Fundamentals of Sustainable
Drilling Engineering
Scrivener Publishing
100 Cummings Center, Suite 541J
Beverly, MA 01915-6106
Publishers at Scrivener
Martin Scrivener (martin@scrivenerpublishing.com)
Phillip Carmical (pcarmical@scrivenerpublishing.com)
Fundamentals of Sustainable
Drilling Engineering
M. Enamul Hossain, PhD
Abdulaziz Abdullah Al-Majed, PhD
Copyright © 2015 by Scrivener Publishing LLC. All rights reserved.
Co-published by John Wiley & Sons, Inc. Hoboken, New Jersey, and Scrivener Publishing LLC, Salem,
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Published simultaneously in Canada.
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Cover design by Kris Hackerott
Library of Congress Cataloging-in-Publication Data:
ISBN 978-0-470-87817-0
Printed in the United States of America
10 9 8 7 6 5 4 3 2 1
Dedicated with love to the blessed soul of the irst author’s
Late mother, Azizun Nesa (1951 – 1981)
Late grandmother, Hazera Khatun (1922 – 1992)
whose devotion and afection never ceases and whose beautiful memories are ever
lasting.
and
dedicated to the second author’s wife and children for their understanding and
support.
Contents
Foreword
Preface
Acknowledgements
Summary
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Introduction
1.1 Introduction
1.2 Introduction of Drilling Engineering
1.3 Importance of Drilling Engineering
1.4 Application of Drilling Engineering
1.5 History of Oil Discovery
1.6 An Overview of Drilling Engineering
1.6.1 Licensing, Exploration and Development
1.6.2 Role of Drilling during Field Development
1.6.3 Types of Drilling Wells
1.6.4 Sequences of Drilling Operations
1.7 Organization Chart and Manpower Requirements during
Drilling Operations
1.8 Aspect of Sustainability in Drilling Operations
1.9 Summary
References
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Drilling Methods
2.1 Introduction
2.2 Types of Drilling Methods
2.2.1 Cable Tool Drilling
2.2.2 Rotary Drilling
2.3 Rotary Drilling Rig and its Components
2.4 Drilling Process
2.4.1 Power System
2.4.2 Hoisting System
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2.4.3 Circulation System
2.4.4 Rotary System
2.5 Types of Rotary Drilling Rigs
2.6 Nature and Need for Sustainable Drilling Operations
2.7 Current Practice in the Industries
2.7.1 Derrick and Substructure
2.7.2 Hoisting System
2.7.3 Pressure Control System
2.8 Future Trend in Drilling Methods
2.9 Summary
2.10 Nomenclature
2.11 Exercise
Appendix 2A
Rig Floor (Conventional Rotary Rig)
Rig Floor (Top Drive)
Blowout Preventer Stack And Wellhead
Drilling Fluid Equipment
References
3 Drilling Fluids
3.1 Introduction
3.2 Drilling Fluid Circulating System
3.3 Classiication of Drilling Fluids
3.3.1 Water-base Mud
3.3.2 Oil-based Mud
3.3.3 Air or Gas-base Mud
3.3.4 Foam
3.3.5 Special Types of Muds
3.4 Composition of Drilling Fluids
3.5 Mud Additives
3.5.1 Chemical Additives
3.5.2 Additives for Water-based Mud
3.5.3 Additives for Oil-based Mud
3.6 Measurement of Drilling Fluids Properties
3.6.1 Mud Density
3.6.2 Mud Viscosity
3.6.3 Gel Strength
3.6.4 pH Determination
3.6.5 Filtration Tests
3.6.6 Sand Content
3.6.7 Determination of Liquid and Solids Content
3.6.8 Alkalinity
3.6.9 Water Hardness
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3.6.10 Water Analysis
3.6.11 Chemical Analysis
3.6.12 Chloride Concentration
3.6.13 Cation Exchange Capacity of Clays
3.6.14 Electrical Properties
3.7 New Drilling Mud Calculations
3.8 Design of Mud Weight
3.9 Current Developments in Drilling Fluids
3.9.1 Formulation of WBM
3.9.2 Formulation of OBM
3.9.3 Formulation of Gas-based Mud
3.9.4 Development of Environment-Friendly Mud System
3.9.5 Application of Nanotechnology
3.9.6 Application of Biomass
3.10 Future Trend on Drilling Fluids
3.10.1 Cost Analysis
3.10.2 Development of Environment Friendly Mud Additives
3.10.3 Sustainability
3.10.4 Development of Mud and/or Additives for HTHP Applications
3.11 Summary
3.12 Nomenclature
3.13 Exercises
References
4 Drilling Hydraulics
4.1 Introduction
4.2 Types of Fluids
4.2.1 Newtonian Fluid
4.2.2 Non-Newtonian Fluid
4.3 Flow Regimes
4.3.1 Laminar Flow
4.3.2 Turbulent Flow
4.3.3 Transitional Flow
4.4 Hydrostatic Pressure Calculation
4.4.1 Liquid Columns
4.4.2 Gas Columns
4.5 Fluid Flow through Pipes
4.6 Fluid Flow through Drill Bits
4.7 Pressure Loss Calculation of the Rig System
4.7.1 Pipe Flow
4.7.2 Annular Flow
4.7.3 Bit Flow
4.7.4 Pump Calculations
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4.8
Current Development on Drilling Hydraulics
4.8.1 Drilling Hydraulics Optimization
4.8.2 Down-hole Motor Technology
4.8.3 Drilling Hydraulics for the Aerated “Foam” Fluids
4.8.4 Drilling Hydraulics of Aerated luids for Vertical Wells
4.8.5 Drilling Hydraulics of Aerated luids for Deviated, Horizontal
and ERD Wells
4.8.6 Drilling Hydraulics for Coiled Tubing Drilling
4.9 Future Trend on Drilling Hydraulics
4.9.1 Hydraulics of Dual Gradient Drilling
4.9.2 Enlargement of Hydraulics Operating Window
4.9.3 Introducing New Hole Cleaning Devices
4.10 Summary
4.11 Nomenclature
4.12 Exercise
References
5 Well Control and Monitoring Program
5.1 Introduction
5.2 Well Control System
5.2.1 Well Control Principles
5.3 Warning Signals of Kicks
5.3.1 Primary Indicators
5.3.2 Secondary Indicators
5.4 Control of Inlux and Kill Mud
5.4.1 Analysis of Shut-in-Pressure
5.4.2 Type of Inlux and Gradient Calculation
5.4.3 Kill Mud Weight Calculation
5.4.4 Kick Analysis
5.4.5 Shut-in Surface Pressure
5.5 BOP Equipment for Well Control System
5.5.1 Kick Detection Equipment
5.5.2 Kick Management Equipment
5.6 Well Monitoring System
5.7 Current Practice in Well Control and Monitoring
5.7.1 Managed Pressure Drilling
5.7.2 Real Time Data Analysis with Dynamic Neural Network
5.8 Future Trend on Well Control and Monitoring System
5.8.1 Real Time Vibration Measurement
5.9 Summary
5.10 Nomenclature
5.11 Exercise
References
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6 Formation Pore and Fracture Pressure Estimation
6.1 Introduction
6.2 Geological Aspects of Rock Mechanics in Drilling
6.2.1 Rock Mechanical Properties
6.2.2 Underground Stresses
6.2.3 Formation Pressure
6.2.4 Overburden Pressures
6.2.5 Pore Pressure Estimation
6.2.6 Fracture Pressure
6.2.7 Methods for Estimating Fracture Pressure
6.3 Current Development on Formation Pore
and Fracture Pressure
6.4 Future Trend on Formation Pore
and Fracture Pressure
6.5 Summary
6.6 Nomenclature
6.7 Exercise
References
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7 Basics of Drill String Design
7.1 Introduction
7.2 Drill String Components
7.2.1 Kelly
7.2.2 Drill Pipe
7.2.3 Tool Joint
7.2.4 Heavy Wall Drill Pipe
7.2.5 Bottomhole Assembly
7.3 Drilling Bit
7.3.1 Types of Drilling Bits
7.4 Drill String Design
7.4.1 Collapse Load
7.4.2 Tension Load
7.4.3 Other Design Factors
7.5 Bit Design
7.5.1 Roller Cone Bits
7.5.2 PDC Bits
7.6 Drilling Bit Selection
7.6.1 Situation-1: When Bit Records are Not Available
7.6.2 Situation-2: When Bit Records are Available
7.7 Drilling Bit Performance
7.7.1 Roller Cone Bits
7.7.2 PDC Bit
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7.8
Drilling Optimization Techniques
7.8.1 History of Drilling Optimization
7.8.2 Parameters for Drilling Optimization
7.8.3 Factors Afecting the Drilling Operations
7.8.4 How to Optimize the Drilling Operations
7.8.5 Traditional Optimization Process
7.9 Factors Afecting Rate of Penetration
7.10 Rate of Penetration Modelling
7.10.1 Established Models for Rate of Penetration
7.10.2 Optimization of the Penetration Rate
7.11 Current Development on Drill String and Bottomhole Assembly Design
7.12 Future Trend on Drill String and Bottomhole Assembly Design
7.13 Summary
7.14 Nomenclature
7.15 Exercise
References
8 Casing Design
8.1 Introduction
8.2 Importance of Casing String
8.3 Types of Casing String
8.3.1 Stove Pipe and Riser
8.3.2 Conductor Pipe
8.3.3 Surface Casing
8.3.4 Intermediate Casing
8.3.5 Production Casing
8.3.6 Liners
8.4 Components of Casing String
8.5 Classiication and Properties of Casing
8.5.1 Casing Size
8.5.2 Range of Length
8.5.3 Casing Grade
8.5.4 Casing Weight
8.5.5 Casing Connections
8.6 Manufacturing of Casing
8.6.1 Seamless Process
8.6.2 Electric-resistance Welding
8.6.3 Electric-lash Welding
8.7 Rig-site Operation
8.7.1 Handling Procedures
8.7.2 Running Procedures
8.7.3 Landing Procedures
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8.8
Casing Design and Selection Criteria
8.8.1 Factors Inluencing Casing Design
8.8.2 Design Criteria
8.8.3 Approaches of Casing Design
8.9 Current Development in Casing Technology
8.9.1 Casing Material Development to Protect the Corrosion
8.9.2 Development in Casing Connections
8.10 Discussions on Some Case Studies
8.11 Future Trend on Casing Design Development
8.12 Summary
8.13 Nomenclature
8.14 Exercises
References
9 Cementing
9.1 Introduction
9.2 Applications of Oil Well Cements
9.2.1 Cement Applications
9.2.2 Variables Afecting Zonal Isolation
9.3 Cement Production
9.3.1 Production Process
9.3.2 Cement Components
9.4 Classiications of Oil Well Cements
9.5 Cement Properties
9.5.1 Density
9.5.2 Fluid Loss
9.5.3 hickening Time
9.5.4 Viscosity and Yield Point
9.5.5 Permeability
9.5.6 Compressive Strength
9.5.7 Soundness
9.5.8 Fineness
9.5.9 Hydration of Cement Slurries
9.6 Types of Cementing
9.6.1 Primary Cementing
9.6.2 Squeeze Cementing
9.6.3 Plug Cementing
9.6.4 Liner Cementing
9.7 Oil Well Cement Additives
9.7.1 Accelerators
9.7.2 Retarders
9.7.3 Fluid Loss Agent
9.7.4 Extenders
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9.8
9.9
9.10
9.11
9.12
9.13
9.14
9.15
9.16
9.7.5 Anti-foaming Agent
9.7.6 Free Water Control Additives
9.7.7 Lost Circulation Control Agents
9.7.8 Weighing Agent
9.7.9 Dispersants
9.7.10 Strength Retrogression Agents
Cementing Design Process
9.8.1 Planning Cement Job
9.8.2 Factors Afecting Cement Job Design
Laboratory Tests on Cements Slurry
9.9.1 Well Speciications
9.9.2 Cement Slurry Design
9.9.3 Materials
9.9.4 Cement Slurry Preparation
9.9.5 hickening Time Test
9.9.6 Density of OWC Slurries
9.9.7 Free Water Contents
9.9.8 Fluid Loss Test
9.9.9 Rheological Properties
9.9.10 Compressive Strength of Cement
9.9.11 Particles Settling Test
9.9.12 Permeability and Porosity Tests
9.9.13 Micro Structural Analysis
Mechanics of Cementing
9.10.1 Cementing Equipment
9.10.2 Cementing Processes
Cement Job Evaluation
Cement Volume Calculation
9.12.1 Slurry Requirement
9.12.2 Number of Sacks
9.12.3 Mixwater Needed
9.12.4 Additives Needed
9.12.5 Displacement Volume Required
9.12.6 Duration of Pumping
Practical Calculations
Recommendations for Successful Cementing
Current Development on Cementing
Future Trend on Cementing
9.16.1 Depleted Reservoirs
9.16.2 HTHP Reservoirs
9.16.3 Corrosive Environment
9.16.4 Deep Waters
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9.17 Summary
9.18 Nomenclature
9.19 Exercises
References
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10 Horizontal and Directional Drilling
10.1 Introduction
10.2 Functions
10.3 Basic Terminologies
10.4 Types of Directional Drilling
10.4.1 Horizontal Drilling
10.4.2 Multilateral Drilling
10.4.3 Extended Reach Drilling (ERD)
10.4.4 Coiled Tubing Drilling (CTD)
10.5 Well Planning Trajectory
10.5.1 Directional Patterns
10.6 Directional Drilling Tools
10.6.1 Drill Collars (DC)
10.6.2 Heavy Weight Drill Pipe (HWDP)
10.6.3 Stabilizer
10.6.4 Roller Reamers
10.6.5 Key-Seat Wiper
10.6.6 Cross-over Sub
10.6.7 Drilling Jars
10.6.8 Deviating Tools
10.7 Well Survey
10.7.1 Survey Tools
10.7.2 Survey Calculation
10.8 Geo-steering
10.9 Current Trends in Directional Drilling
10.10 Future Trends in Directional Drilling
10.11 Summary
10.12 Nomenclature
10.13 Exercise
References
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11 Well Drilling Cost Analysis
11.1 Introduction
11.2 Variables Related to Drilling Costs
11.3 Types of Well Drilling Costs
11.3.1 Rig Costs
11.3.2 Tangible Costs
11.3.3 Service Costs
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11.4 Brake Down of Total Well Drilling Cost
11.5 Authorisation for Expenditure
11.6 Drilling Cost Estimation
11.7 Well Drilling Time Estimation
11.7.1 Drilling Time Estimation
11.7.2 Trip Time Estimation
11.7.3 Number of Bit Estimation
11.7.4 Connection Time Estimation
11.7.5 Coring Cost Estimation
11.8 Time Value of Investment
11.8.1 Future Value Estimation
11.9 Price Elasticity
11.10 Current Trend on Drilling Cost Analysis
11.11 Future Trend on Drilling Cost Analysis
11.12 Summary
11.13 Nomenclature
11.14 Exercise
References
12 Well Completion
12.1 Introduction
12.2 History of Well Completion
12.3 Requirements for Well Completion
12.4 Types of Well Completion
12.4.1 Open-hole Completion
12.4.2 Uncemented Liner Completions
12.4.3 Cased and Cemented Completions
12.4.4 Perforated Completion
12.4.5 Multi-Zone Completions
12.5 Factors Inluencing Well Completion Design
12.6 Completion Equipment and Materials
12.6.1 Casing
12.6.2 Cement
12.6.3 Perforating and Sand or Gravel Packs
12.6.4 Production Equipment
12.6.5 Landing Nipple
12.6.6 Downhole Gauges
12.6.7 Perforated Joint
12.6.8 Formation Isolation Valve
12.6.9 Centralizer
12.6.10 Wireline Entry Guide
12.6.11 Tubing Hanger
12.6.12 Electrical Submersible Pump
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12.6.13 Wellhead Equipment and Completion
12.6.14 Downhole Safety Valve
12.6.15 Subsurface Safety Valves
12.6.16 Completion Fluids
12.6.17 Casing Perforation
12.6.18 Filters and Drains for Solid Transport Control
12.6.19 Well Stimulation
12.6.20 Tubing String and Accessories
12.7 Sand Control
12.8 Remedial Cementing
12.9 Corrosion and Corrosion Prevention
12.10 Current Development on Well Completion
12.11 Future Trend on Well Completion
12.12 Summary
References
Index
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Foreword
Albert Einstein famously said, “I was originally supposed to become an engineer but the
thought of having to expend my creative energy on things that make practical everyday
life even more reined, with a loathsome capital gain as the goal, was unbearable to me.”
Engineers are faced with solving problems that few dare approaching. hey do so for a
“loathsome capital gain” yet they remain responsible for making things practical and eicient. Drilling into a formation that is thousands of meters underground is a daunting task.
To make that process sustainable is nothing short of a miracle. Promises of such miracles
are an act of a magician unless backed by a solid scientiic foundation. his book addresses
a problem that only a few years ago was deemed to be an impossible task, and it does so with
a solid scientiic foundation, yet with utmost clarity.
Engineering is an art that needs conscious participation and skillful mentoring. he best
way to learn how to handle an engineering problem is to sit down next to a friendly, patient,
experienced practitioner and work through problems together, step-by-step. his book will
give the readers similar learning experience. he chapters are organized in a very logical
fashion. he book is easy to understand even though it is a product of extensive research in
fundamentals of drilling engineering and is enhanced with new knowledge and the most
up-to-date information. Such a hands-on approach cannot be found in any other textbook
in engineering. his textbook promotes the concept of true paradigm shit in the topic of
drilling engineering that remains one of the most complex yet least understood subjects of
the modern era.
It is no secret that no single current drilling engineering book is adequate in explaining natural phenomena. When it comes to challenging tasks, such as environmental sustainability, the inadequacy becomes even more pronounced and has caused tremendous
frustration in the current energy management schemes. While everyone seems to have a
solution, it is increasingly becoming clear that these options are not moving our environment to any cleaner state. Few have ventured into proposing a solution that would question
the foundation of conventional thinking. his book takes that necessary step and ofers
something that can only be characterized as groundbreaking. his textbook ofers some of
the advanced and recent achievements related to drilling operations in addition to fundamentals of diferent drilling areas and sustainable operations. It breaks out of conventional
practices of using prior knowledge as a basis. It takes a bold step of going to the root of
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xx Foreword
the current practices and challenges in the area. By doing so, this textbook creates a true
knowledge for undergraduate students to strengthen their basics of drilling engineering
and researchers who need guidelines for further improvement in the area. One application
is the use of basics of drilling engineering along with more workout examples and exercises
at the end of each chapter. his book puts forward a guideline how to handle the inherent
complexity of recent challenges that are being faced by the industry. Many people feel the
petroleum industry has not been as good as others in propagating sustainable activities for
enterprise applications. Even researchers simplify and oten marginalize the inherent complexity of drilling operations, especially the drilling luid properties toward sustainability
considering assumptions in an unjustiied way. As the technology becomes more capable
and sophisticated, it becomes more important to understand how to use it well. his unique
book is a valuable step in advancing that understanding. In my view, this book is a must for
any student, practicing engineer, expert, researcher, and academic who aspires to understand the complex process involved in drilling engineering.
Professor M. R. Islam
Former Killam Chair in Petroleum Engineering, Dalhousie University, Canada
President, Emertec Research and Development Ltd., Halifax, NS, Canada
Preface
Sustainable Drilling Engineering? I have heard sustainable used in conjunction with “green”
energy sources such as wind or solar. I have heard sustainable with respect to agriculture. But
using sustainable with respect to drilling? Isn’t that an oxymoron such as “jumbo shrimp”
or “accurate rumors?” Doesn’t drilling have to do with oil and gas, a inite resource?
Yes, it does. But it is more than that. Drilling is the process of accessing resources below
the surface of a planet such as Earth. hese resources include oil and gas, naturally. But
consider one of the most critical resources mankind needs: water. In many places, the only
source of that precious resource is underground. How about various minerals? Gold and
silver come to mind; but more important to us are iron, aluminum, and the many rare
earths needed by our electronic devices. he initial discovery of these resources is oten at
the end of a drill bit. How about geothermal energy? hat is a potential source of energy
that is limitless, and it takes a borehole drilled into the ground to access it. How about
learning science? We study the geology of the Earth. We look at the past climates with ice
cores in Antarctica. We determine the low of contaminates underground. We look for life
on other worlds. Drilling is not only for oil and gas; it is needed for any access to the natural
resources and knowledge found below the surface of our (or any other) planet.
Sustainable means to be able to be maintained at a certain rate or level or to be upheld or
defended. In the case of this book, I consider both deinitions to be an accurate description
of the text. Drilling operations are expensive, time consuming, and potentially dangerous to people and the environment. One must maintain a high level of engineering and
operational skill that mitigates any potential harm to anyone or anything. It is the drilling
engineering and the process of drilling that is sustainable. herefore, the title of this book is
accurate. It is drilling engineering that is sustainable.
Drs. Hossain and Al-Majed have written a book on sustainable drilling engineering. In it,
they describe the many aspects of the drilling engineer’s practice. In some work I did with
the United States’ National Aeronautics and Space Administration some years ago, the Jet
Propulsion Laboratory engineers and my Colorado School of Mines team reduced drilling
wellbores into three categories: penetrate the rock, remove the rock, and keep the wellbore
open. his book explains it all.
hey start with an introduction to the profession of drilling engineering and the people
that are involved in making drilling sustainable. he authors then go on to describe and
explain the machinery of the drilling rig that enables people to drill wells. Towards the end
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Preface
of the book, they discuss how to inish a well, called well completions and detail how to
determine the economics of drilling and completing wellbores in a chapter on cost analysis.
You have to penetrate the rock. he authors launch into drill string design from the top
drive/kelly through the drill pipe and bottom hole assembly to the drill bit. hey explain
how to choose the bit and operate the rig at peak capability. hey also discuss in another
chapter how to direct the wellbore trajectory in the process called directional drilling. his
includes the process of horizontal drilling that is a remarkable process for opening up oil
and gas resources that were never considered a resource just a decade ago.
You have to remove the rock. he authors describe drilling luids and the hydraulics
derived from their low. hey continue in logical sequence to well control issues and methods; and, on to the prediction processes not only for the source of well control problems,
pore pressures; but also to the bane of well control, fracture gradients and the loss of luids.
You have to support the borehole. One way to stop wellbores from collapsing or to control pressures is to run steel pipe. his is called casing and its design is the subject of a chapter in the book. his is followed by the illing of the ring shaped area (called the annulus)
between the rock walls and the casing with cement, the most common way to prevent the
migration of luids from one formation to another. he casing and cement helps to maintain the borehole.
All of this knowledge goes into making drilling and the engineering required be sustainable. his book is the start in learning how to make drilling engineering sustainable.
Dr. Alfred William Eustes III, Ph.D., P.E.
Colorado School of Mines
Petroleum Engineering Department
Golden, Colorado 80401, USA
Acknowledgements
he authors would like to acknowledge the inancial support provided by the Deanship of
Scientiic Research (DSR) at King Fahd University of Petroleum & Minerals (KFUPM) for
funding this book writing grant through project number IN101017. he authors are also
grateful for the support received from the department of Petroleum Engineering at KFUPM.
he irst author acknowledges the support of his family members that provided him with
full support during the book writing. he dedication of Dr. Hossain’s wife gave him the
feelings of heavenly environment and continuous mental support under all circumstances.
During this long journey, the sacriice of the children, Ijlal Hossain, Ryyan Hossain, Omar
Mohammed Ali-Hossain and Noor Hossain remained the most important source of inspiration. he second author acknowledges the support of his family members and friends
whose understanding and support made it possible for him to accomplish the demanding
undertaking of writing a book.
he authors would like to thank Dr. Abdullah Sultan for his support to assign graduate
students to work in this project. he authors would like also to thank Dr. Kalim Urahman
for his support during writing the cementing chapter. It is also acknowledged the contributions of our graduate students, Mr. Abdul Rauf Adebayo, Murtaza Mobeen, and Waqas
Ahmed Khan who assisted in the literature survey of some chapters. Appreciation goes to
Mr. Mohammad Hussain Khan Niazi for his support in drawing igures as a dratsman. In
addition, there are many more friends, colleagues, stafs and secretaries who have dedicated
time for this book.
xxiii
Summary
Drilling Engineering is one of the oldest technologies on earth and the technological advancement in this area is well recognized by the scientists, engineers, researchers, and the petroleum industry. However, the hydrocarbon extraction industry is still unmoved by attempts
of alternative energy sources to displace it as the primary source of energy for the foreseeable
future. In this information era, the key to success in the drilling industry has been the results
of utilization of technological advancement. Knowledge gaps have been created in drilling
technologies because of the challenges that face the oil companies in the exploration for oil and
gas in areas which is remote, deep and diicult to reach, whether on land or ofshore areas. he
scientiic and technological advancement could not reduce the level of risks and data uncertainties in the drilling operations to the desired level since performing drilling operations in
a sustainable fashion does not have the priority in an era of continuously increasing demand
for oil and gas, and increasing costs of projects. Unfortunately, the petroleum industry is still
perceived as one of the expensive branches of modern industries. To date there are very few
textbooks that explain the sustainable drilling operations with fundamentals of drilling engineering. As the irst and only complete guide for petroleum engineers on basic drilling
engineering and a milestone book for environmentalist and researchers, this is a best choice
to have for the drilling community. his textbook explains how the drilling technology can be
operated in a sustainable fashion. However, the main focus is given on drilling luid because
lot more researches are needed to green the mud technology for a stainable drilling operation. he book also covers the fundamental issues for the beginners who are interested in
learning drilling engineering. he textbook explains the concepts of the basic subject matter
clearly and presents the existing knowledge ranges from history of drilling technology to well
completion. he book presents the engineering terminologies in a clear manner so that the
beginner of the drilling engineering would be able to understand the drilling concepts with
minimum eforts. In addition, each chapter contains some workout examples and exercises for
a comprehensive understanding of the subject. his will make the reader interested in reading the book. For the potential researchers, the book outlines related issues and covers gaps
in knowledge. It also outlines how the industry can plan the rig operations in a sustainable
manner. he book explains the concepts in a readable fashion very clearly. It includes all the
basic aspects of drilling engineering including rig operations, drilling hydraulics, cementing
jobs, drilling luids, drillstring, bit and casing design, and horizontal and directional drilling.
In addition, the book talks about the sustainable petroleum operations and points out topics
that deserve further research. However, we believe that each chapter deserves to be a short
xxv
xxvi
Summary
book and we tried to focus the most important concepts and main topics of the subject matter.
he textbook is a foundation and resourceful guide, and an excellent resource for petroleum
engineering students, drilling engineers, supervisors and managers, researchers, and environmental scientists. he speciic topics of the drilling engineering that are covered in this
book include the following chapters:
Chapter 1 – Introduction: his chapter introduces the fundamental features of the drilling. It discusses some of the core issues related to drilling engineering, activities need to be
completed before starting drilling operations, etc. Finally, the concepts of sustainable drilling operations are introduced.
Chapter 2 – Drilling Methods: his chapter discusses all characteristics related to drilling rig and its components. he chapter focuses on the drilling methods used for hydrocarbon exploitation and covers the cable tool drilling rig, rotary drilling rig and its components,
rotary rig systems, types of rigs, current advancement of rig systems, and the knowledge
gap that needs to be illed in drilling.
Chapter 3 – Drilling Fluids: he chapter covers almost all the fundamental and basic
ideas of mud engineering including an extensive literature survey on the drilling luid. he
chapter presents the current trend and the future challenges of the technology and also
identiies where the R&D personals need to focus their attention toward the sustainable
mud engineering.
Chapter 4 – Drilling Hydraulics: Drilling hydraulics plays an essential role while drilling activities continue to operate. To understand and properly design the hydraulic system, it is important to discuss hydrostatic pressure, types of luid low, criteria for type of
low, and types of luids commonly used in the various operations at the drilling industry.
In addition, it covers the type of luids; pressure losses in the surface connections, pipes,
annulus, and the bit; jet bit nozzle size selection; surge pressures due to vertical pipe movement; optimization of bit hydraulics, and carrying capacity of drilling luid. he current and
future trends of the hydraulic system are also discussed in the last sections of the chapter.
Chapter 5 – Well Control and Monitoring Program: he chapter discusses well control
and monitoring system in general. It covers how a well can be controlled in a sequential and
safe way in addition to its diferent control devices used in any well control and monitoring
system. his chapter covers the whole range of real-time monitoring system and discusses
the current practices in the industry and the future trend of the well control and monitoring
system in general.
Chapter 6 – Formation Pore and Fractures Pressure Estimation: his chapter deals
with the formation luid pressure and fracture pressure, understanding of the variation
of these two parameters with depth, and rock mechanical properties including geological aspects of rock mechanics. he development of underground stresses and the related
formation pressure, fracture pressure are also outlined in this chapter. he diferent causes
of abnormal pressure with detailed detection and prediction techniques are the main focus
of the chapter. Finally, the current state-of-the-art on formation pore pressure and fracture
pressure along with the fracture gradient are elaborated in this chapter.
Chapter 7 – Basics of Drillstring Design: he chapter covers the basic drillstring and
bottom-hole assembly (BHA) design including drill bit. he diferent types of drill bit
and their applications are outlined in detail. he ROP optimization and the factors that
inluence the ROP are discussed and the existing ROP models are explained. he current
Summary
xxvii
development in the area and the future trend of drill string and BHA are also presented in
the chapter.
Chapter 8 – Casing Design: his chapter focuses the types of casing, diferent components of casing and landing procedures including the manufacturing of casing, rig side
operations, handling procedure, casing design, and selection criteria. Finally, the current
practice and the future trend of the casing for the oil industry are discussed.
Chapter 9 – Cementing: his chapter discusses how the well cementing plays a vital role
by providing the diferent functions throughout the life of a well. It explains the cement
slurry design process which covers the parameters those afect the cementing process during and ater placement of cement slurry in the annulus. he chapter also discusses lab testing and the rheological properties of cement slurry. he current developments and future
challenges faced by oil well cementing industry are outlined at the end of the chapter.
Chapter 10 – Horizontal and Directional Drilling: his important chapter discusses
the fundamental concepts related to horizontal and directional drilling including well
survey, other forms of directional drilling technologies such as horizontal wells, extended
reach wells, multilateral wells, slim hole drilling, and coiled tubing drilling. Future trends
in directional drilling are also discussed on a separate subsection in addition to the current
trend of the directional drilling technology.
Chapter 11 – Well Drilling Costs Analysis: his chapter focuses the factors afecting
the drilling costs, types of costs, and variables that inluence the well drilling costs. Some
typical examples are set to enhance the drilling costs estimation. he purpose of the chapter
is to review the primary methods used to assess drilling cost and complexity. he foundational basis of each approach is described and a critical assessment of model assumptions
is provided.
Chapter 12 – Well Completion: his chapter addresses the needs for well completion
and focuses on building the current foundation of engineers on completion techniques. It
further provides practical exercises and industrial applications on the key decisions needed
to be made during the completion processes. In addition, an in-depth discussion on the
emerging technologies and methodologies on well completion is covered. he current trend
and practices of the well completion along with its future trend are also identiied in the
chapter.
Dr. M. Enamul Hossain
and
Dr. Abdulaziz Al-Majed
1
Introduction
1.1 Introduction
his chapter introduces the fundamental aspects of the drilling. It covers the basic
deinitions related to drilling engineering, importance and the procedure for drilling
operations. he applications and history of drilling are also outlined. he systematic
approach and the introduction to casing sets are discussed. Finally, the aspects of sustainable drilling operations will be introduced.
1.2 Introduction of Drilling Engineering
Some scholars consider petroleum hydrocarbons to be the lifeblood of modern civilization. he life cycle of petroleum operations includes exploration and development,
production, reining, marketing, transportation/distribution to the end user, and inal
utilization. he drilling technology has been developed through the eforts of many
individuals, professionals, companies, and organizations. his technology is a necessary step for petroleum exploration and production. Drilling is one of the oldest technologies in the world. Drilling engineering is a branch of knowledge where the design,
analysis, and implement procedure are completed to drill a well as sustainably as possible. In a word, it is the technology used to utilize crude oil and natural gas reserves.
he responsibilities of a drilling engineer are to facilitate the eicient penetration of
1
2
Fundamentals of Sustainable Drilling Engineering
the earth by wellbore and to facilitate cementing operations from the surface to an
optimum target depth that prevents any situation that may jeopardize the environment.
1.3 Importance of Drilling Engineering
It is well known that the petroleum industry drives the energy sector, which in turn
drives the modern civilization. It is not unlikely that every day human beings are getting beneits out of the petroleum industry. he present modern civilization is based on
energy and hydrocarbon resources. he growth of human civilization and necessities of
livelihood with time inspired human beings to bore a hole for diferent reasons (such
as drinking water, agriculture, hydrocarbon extraction for lighting, power generation,
to assemble diferent mechanical parts, etc.). here is no surface hydrocarbon resource;
rather, all resources are underground on this globe. To keep serving the whole civilization, drilling engineering has a signiicant role in this issue. Moreover, the world’s
energy sector is dependent on the drilling engineering. Without drilling a hole, how
are we going to extract the hydrocarbon from underground to the surface of the earth?
To the best of our knowledge, right now, there is no alternative technology available to
extract hydrocarbon without drilling a hole. If the petroleum industry falls down, the
whole civilization will probably collapse. herefore, for the survival of our existence,
we need to know and keep updating our knowledge, especially on the technology, of
drilling engineering. Based on this motivation, human necessities of drilling a hole by
excavation on earth have motivated the researchers to develop diferent sophisticated
technologies for drilling engineering. In a word, we can say, drilling engineering has
a vital role in our daily life, economy, society, and even in national and international
politics.
1.4 Application of Drilling Engineering
By the development of human civilization with time, human beings have needed to
make a hole in diferent objects for diferent purposes. It ranges from just a childhood
playing game/toy, to modern drilling of a hole for the purpose of any scientiic and
technological usage. Humans have been using this technology for underground water
withdrawal since ancient times. Drilling technology is a widely used expertise in the
applied sciences and engineering, such as manufacturing industries, pharmaceutical
industries, aerospace, military defense, research laboratories, and any small-scale laboratory to a heavy industry like petroleum. Modern cities and urban areas use the drilling
technology to get the underground water for drinking and household use. he underground water extraction by boring a hole is also used agricultural irrigation purposes.
herefore, there is no speciic ield of application for this technology. It has been used
for a widespread ield based on its necessity. As this textbook is only focusing on drilling a hole with the hope of hydrocarbon discovery, here, the drilling engineering application means a shat-like tool (i.e., drilling rig) with two or more cutting edges (i.e., drill
bit) for making holes toward the underground hydrocarbon formation through the
Introduction 3
earth layers, especially by rotation. Hence, the major application of drilling engineering
is to discover and produce redundant hydrocarbon from a potential oil ield.
1.5 History of Oil Discovery
Geology and time have created large deposits of crude oil in various parts of the
earth. Until the mid-1800s, this vast untapped wealth lay mostly hidden below the
surface of the earth. Some oil seeped naturally to the earth’s surface, and formed
shallow pools. hese oil seeps had long been known and were used for medicinal
purposes, to caulk boats and buildings, and to lubricate machinery. Ancient people
were using oil mainly as medicine. So, the use of oil is not new in human history.
he irst oil discovery in human life was in Babylon (Current Iraq) as oil pits in 450
BC. hen, the second discovery was in Macedonia in 325 BC, and this oil was being
used by Alexander the Great. he third discovery of oil was in Kirkuk, Iraq. However,
according to Wikipedia, the earliest known oil wells were drilled in China in 347.
he Chinese were using bamboo as modern drill pipe to extract oil. hey were able
to drill at a depth of about 800 feet using bits attached with bamboo poles. he use
of oil was limited to evaporating brine, producing salt, and for lighting and heating.
he petroleum industry in Middle East was established by the eighth century. his
was due to the use of tar at the street lights in Baghdad. However, some people believe
that in the ninth century, oil ields were developed in Baku, Azerbaijan to produce
naphtha. he Persian alchemist, Mohammad ibn Zakariya Razi, produced kerosene
from petroleum using the distillation process in the ninth century. Kerosene was
used mainly as kerosene lamps. he distillation process of crude oil was also carried out by Arab and Persian chemist to produce lammable products for military
purposes. By the twelth century, distillation process became available in Western
Europe through Islamic Spain. History says Baku was the place where shallow pits
were dug to facilitate collecting oil. he hand-dug holes, which were up to 115 feet
deep, were in use by 1594. In fact, these holes were essentially oil wells and produced
about 28,000 barrels of oil so far. he irst break through in the oil industry’s drilling
history was the year 1849, when Russian engineer F.N. Semyenov used a cable tool
to drill an oil well on the Apsheron Peninsula. In the west, Canada was the irst place
of commercial oil production, when James Williams drilled the irst oil well in North
America in 1857. Later, in 1859, the irst well in the USA was drilled near Titusville,
Pennsylvania under the supervision of Colonel Edwin L. Drake, and it was about
69 feet deep. Table 1.1 shows the oil discovery in the diferent places around the world
as an example case.
he irst commercial oil well was situated in the southwestern Ontario town of Oil
Springs. Williams acquired some property that was known to have oil gum beds. He
dug through the gum beds in search of the source of the oily deposits, and discovered
crude oil. his irst oil well was simply a hole in the ground, with oil rising up close to
the surface. With the use of hand pumps, the oil was extracted at a rate of 37 barrels of
oil per day. Williams built and operated a local distillery from which he reined and sold
kerosene. Ontario’s irst oil boom—relected in town names such as Petrolia—paralleled
4
Fundamentals of Sustainable Drilling Engineering
Table 1.1 First discovery of oil in diferent places in the world for commercial production.
Serial
No.
Name of the Country
First Discovery of Oil
01
Oil pits near Babylon
450BC
02
Macedonia
325BC
03
Kirkuk (Iraq)
100
04
China (used bamboo for extract oil)
347
05
Azerbaijan (For medicine)
1264
06
Poland
1500
07
Russia
1597
08
Australia
1800
09
Romania
1857
10
Ontario, Canada
1858 (First Commercial use)
11
Pennsylvania, USA
1859
12
Lake Maracaibo, Venezuela
1878
13
Sumatra, Indonesia
1885
14
Norway/Netherland
1885
15
Nigeria
1907
16
Iran
1908
17
Tampico, Mexico
1910
18
Bahrain
1932
19
Saudi Arabia
1933
20
Kuwait
1938
21
Qatar
1939
22
Brazil
1939
23
Algeria
1956
24
United Arab Emirates
1960
25
Oman
1967
26
United Kingdom
1969
27
Sudan
1979
a larger oil boom in northern Pennsylvania, where energy dynasties were beginning
to emerge. Oil was not being used widely in commercial basis before middle of the
nineteenth century. Oil had been used as medicine, laming torches, and for lighting
purposes before that. Now a day’s oil is the backbone of nation’s economy and the heart
of modern civilization.
Introduction 5
1.6 An Overview of Drilling Engineering
A multitude of issues are needed to be resolved even before the consultants or engineers ever see the prospect of the project. Most importantly, these phases of works are
being completed before any drilling operation. Here, the principal party is called the
operator. his operator is normally the “Oil Company,” who is a well-known major
company or an independent. he operator employs the drilling consultant to protect
and negotiate the operator’s interest. Meanwhile, the operator also engages geologists
to locate the area where s/he feels to have a good prospect for hydrocarbon reserve.
he geologists may recommend drilling a wildcat well (a small exploratory oil well
drilled in land not known to be an oil field to get the geological information ) into
an untested ield, or s/he may recommend a development well (a well drilled in a
proved production fi eld or area to extract natural gas or crude oil) to get the desired
information about the formation. he operator’s next objective is to hire a landman to
acquire drilling rights. he oil companies normally have a paid staf of geologists and
landmen. he main responsibility of landman is to determine who is going to own the
minerals rights in the area to be drilled. He also tries to acquire lease rights from the
landowner through a document which is called an “oil and gas lease.” So, the landman
is the representative of the operator who takes care of all of the negotiation parts with
landowner so that the terms and conditions would be acceptable for the operator.
Ater getting the lease and approval of license, the operator then hires the drilling contractor (a contractor who owns the drilling rig and employs the crew to drill the well ).
At this stage, operator hires the specialist consultants (normally service companies)
to conduct other rig side jobs, such as casing, cementing, logging, perforating, fracturing, acidizing, lost tool recovery, drilling luid preparations, etc. he geologists and
reservoir engineers are again engaged to analyze the drilling results and to determine
which zones, if any, are worth producing. If there are one or more potential zones, the
well would be completed for production. On the other hand, if there are no formation
zones, the well would be plugged and abandoned in accordance with the regulations
that protect the water zones drilled through. he operator cannot just pick up the rig
and leave the hole open. Finally, the operator is responsible for producing and selling
the hydrocarbons from its proven zones.
1.6.1 Licensing, Exploration and Development
Petroleum and mineral resources are usually owned of by the government of the host
country. Normally, the ministry of petroleum/oil and gas (diferent names in diferent
countries) is empowered on behalf of the government to invite companies to apply
for exploration and production licenses within the country. Exploration licenses may
be awarded at any time based on company’s reputation and terms and conditions.
Exploration licenses do not allow a company to drill any deeper than certain depth
and are used primarily to enable a company to acquire seismic data from a given area.
Production licenses allow licensees to drill for, develop and produce hydrocarbons
from whatever depth is necessary. Costs of ield development are so huge that major oil
companies normally form partnerships to share the expenses. Typically, oil companies
6
Fundamentals of Sustainable Drilling Engineering
operate in joint ventures to reduce their individual risk as well. One of the companies
within the joint venture is designated and empowered to act as an operator that actually
supervises the work.
As long as the governments of most nations issue licenses to explore, develop, and
produce its oil and gas resources, the company needs to obtain a production license
even before drilling an exploration well. Prior to applying for a production license,
however, they will conduct an “investigation” exercise, in which they will analyze any
seismic data they have acquired, analyze the regional geology of the area, and inally
take into account any available information on producing ields or well tests performed
in the vicinity of the prospect they are considering. Based on the above, and a general
look at the exploration and development costs, the pricing, and tax regimes, the company will decide whether it would be worth developing the ield (if a discovery were
made)or not. If the project is considered worth exploring further, the company will try
to acquire a production license and continue with the “exploration” phase of the ield.
his will allow the company to drill wells in the area of interest. It will in fact commit
the company to drill one or more wells in the area. he exploration phase of the ield
development may begin with the company shooting extra seismic lines in a closer grid
pattern than it had done previously. his will provide more detailed information about
the prospect and will assist in the deinition of an optimum drilling target. Despite
improvements in seismic techniques the only way of conirming the presence of hydrocarbons is to drill an exploration well (the well that helps to determine the presence of
hydrocarbons ).
Drilling is very expensive, and if hydrocarbons are not found, there is no return on
the investment, although valuable geological information may be obtained. With only
limited information available, a large risk is involved (on average, only one in eight
North Sea exploration wells are successful). If the company decides to go ahead for
hydrocarbon presence, an exploration well proposal is drawn up to drill in the most
likely position on the reservoir. he length of the exploration phase will depend on the
success. here may be a single well or many wells drilled on a prospect in the exploration phase. If a viable discovery is made on the prospect then the company enters
the “Appraisal” phase of the ield. During this phase more seismic lines may be shot
and more wells will be drilled to establish the extent of the reservoir. hese appraisal
wells (a well that is drilled to establish the extent (size) of reservoir ) will yield further
information, on which future plans will be based. he information provided by the
appraisal wells will be combined with all of the previously collected data. Engineers will
investigate the most cost-efective manner through which they can develop the ield.
If the prospect is deemed to be economically attractive, this development design will
culminate in the production of a ield development plan. his plan will be submitted for
approval. If approval of the development is received, then the company will commence
drilling development wells (a well that is drilled in a proved production fi eld or area to
extract natural gas or crude oil ) and construction of production facilities according to
the development plan. Once the ield is “on-stream,” the companies’ commitment continues in the form of maintenance of both the wells and all of the production facilities.
Ater many years of production, it may be found that the ield is yielding more or
possibly less hydrocarbons than initially anticipated at the development planning stage,
and the company may undertake further appraisal and subsequent drilling in the ield.
Introduction 7
Once the ield is no longer producing economically, the company will be required to
abandon the ield in a sustainable (i.e., safe and environmentally acceptable) fashion.
1.6.2 Role of Drilling during Field Development
he role of drilling during, or even before, the ield development is enormous. here are
some step-by-step works that are normally followed by the operators during the development phase of an oil ield. Figure 1.1 shows a complete loop for diferent phases of
the development works related to drilling engineering. In addition, to understand the
process well, the following steps are mentioned while drilling an oil/gas well continued:
1.
2.
3.
4.
5.
6.
7.
8.
9.
10.
11.
12.
Complete or obtain seismic, log, scouting information, or other data
Lease the land or obtain concession
Calculate reserves or estimate from best data available
If reserve estimates show payout, proceed with well
Obtain permits from various government authorities
Prepare drilling and completion program
Ask for bids on footage, day work, or combination from selected drilling
contractors based on drilling program
If necessary, modify program to it selected contractor equipment
Construct road, location/platforms and other marine equipment necessary for access to site
Gather all personnel concerned for meeting prior to commencing
drilling (pre-spud meeting)
If necessary, further modify program
Drill well for production
Once a decision is made to drill a well, then the drilling engineer’s role comes into
play. In this long process, a drilling engineer plays a vital role during drilling operations,
including planning, design, and supervision. he following are some of the important
responsibilities that are accomplished by the drilling engineer:
•
•
•
•
•
•
1.6.3
Well planning before drilling
Monitor drilling operations including mud luid
Managing rig side people (i.e., management job)
Ater drilling, review drilling results and recommend future improvements
Prepare report
General duties
Types of Drilling Wells
If the subsurface hydrocarbon formations are identiied from primary seismic survey,
a decision is made to either develop the ield to get more information from exploration, or to declare the ield as abandoned. If the ield is decided as a potential area of
hydrocarbon production, actual drilling of one or more wells is necessary to determine
whether or not suicient accumulations of hydrocarbon exist as commercial quantities.
8
Fundamentals of Sustainable Drilling Engineering
Geological and Geophysical Analysis
Seismic Survey
Drill Exploration Well
Drill Appraisal
Well
Mud Logging
(Lithological and textural description of formation from drill
cutting, hydrocarbon shows)
Coring
(Lithological and textural description from massive sample. Samples
used for lab analysis – porosity, permeability, capillary pressure etc.)
Well Logging
(Electrical, Radioactive and Sonic tools provide quantitative
assessment of luid types and distribution)
Well Testing
(Following the well allows large representative samples of the reservoir
luid to be recovered. Pressure response of reservoir allows extent,
producibility and drive mechanisms of the reservoir to be evaluated.)
Evaluated Information Gathered Above
From exploration and appraisal well information, compile
geological model
Compile Economic Model
Drill Development Wells
Figure 1.1 Role of drilling during ield development.
Based on these strategic decisions and primary outcomes, drilling wells can be categorized into four types, such as exploration well, appraisal well, development well, and
abandonment well.
An exploration drilling well is oten called a Wildcat well. It is drilled during the
initial phases of exploration. he drilling is completed with the hope of getting the
information whether the reservoir rocks contain any oil or gas. he main objectives
of this drilling well are to determine the presence of hydrocarbons, to provide a geological data (such as cores, logs) for evaluation, conduct low test through the well
to determine its production potential, and to obtain the luid samples for laboratory
Introduction 9
analysis. Once hydrocarbons are discovered, more drilling is done to test if the i eld
is commercially viable or not. So, appraisal wells are those wells that are used to
establish the extent (size) of the reservoir. his well helps in gathering information
such as whether there is a suicient amount of oil and gas to justify investing money
in infrastructure to recover oil/gas to scales. he development wells are sometime
called production wells . his well is drilled in a proved production ield/area to
extract hydrocarbons (i.e., natural gas/crude oil). h is drilling well is done to create
a low path from the reservoir to the surface, and then through the production facility. Finally, if no hydrocarbon discovery is found, the well that was drilled to gather
the information needs to be closed to prevent possible environmental disaster. he
well that is sealed and closed is called an abandonment well. his well can be an
exploration or appraisal well.
1.6.4 Sequences of Drilling Operations
he sequences of drilling operations can be categorized into three major steps. he irst
step is to initiate and accelerate the drilling of a hole on the earth’s surface for hydrocarbon extraction, the second step is the casing operations, and the third step is the
completion of well. However, the second and third steps are basically needed to support drilling operations in a sustainable manner. When drilling operations continue,
the second step needs to be accomplished simultaneously with drilling. he third step
comes once drilling operations reach their target level.
In general, several casing steps are completed to avoid blowout or any other consequences during drilling operations. However, when a well is drilled in high pressured zones, weak and fractured formations, unconsolidated formations, or sloughing
shales, the second step must be completed without any excuse to avoid substantial
destruction at the rig-side. Diferent casing sizes are required for diferent depths. In
general, ive diferent casing sizes are used to complete a well. Figure 1.2 shows the
diferent casings, such as outmost casing (or conductor pipe), surface casing, intermediate casing, production casing, and liner. As shown in Figure 1.2, these pipes are
run to diferent depths, and one or two of them may be omitted, depending on the
drilling condition. However, they may also be used as liners, or in combination with
liners. Based on the above casing concept, the sequences of the drilling operations are
outlined, considering an onshore oil ield.
Once the location is inalized, depending on primary seismic survey, a large diameter hole (normally 36 ) is drilled using a truck mounted mobile rig. his hole is only
drilled to a shallow depth. It varies from 40 – 500 in length at onshore, and up to 1000
at ofshore. However, the conventional depth is 100 and normal range is 50 – 150 . he
hole must be lined with steel pipe or casing (usually called conductor pipe). his is the
outmost casing string. he main purpose of this casing is to hold back the unconsolidated surface formations and prevent them from falling into the hole. he conductor
pipe is cemented back to the surface, and it is either used to support subsequent casing
and wellhead equipment, or the pipe is cut of at the surface ater setting the surface
casing. Once the conductor is in place, the drilling rig is brought on to the site and set
up for the next stage. A 30 casing shoe is used in this example (Figure 1.2).
10
Fundamentals of Sustainable Drilling Engineering
36"
4 12
Production
Tubing
Cement
Surface
casing
30" Casing shoe
(Conductor pipe)
Production
casing
6000'
2000'
100'
Outmost casing
string or
Conductor pipe
20" Casing shoe
(Surface casing)
Intermediate
casing
13 38 " Casing shoe
(Intermediate casing)
12.25" Casing shoe
(Liner)
Liner
Production
tubing
Reservoir
formation
Packer
9 58 " Production
casing
Figure 1.2 Typical casing program showing diferent casing sizes and their setting depths.
A smaller diameter bit must be used to drill the next section below the conductor. If
the conductor is 30 diameter, a 26 bit may be used. his 26 hole may be drilled down
to 2000 (normal range: 300 – 5000 ) through unconsolidated formations, which may
cave in. he hole must be lined with another string of casing (surface casing) which
may be up to 20 diameter as an example (Figure 1.2). he size of the surface casing
normally varies from 7 – 16 in diameter and the most common sizes are 103⁄4 and
133⁄8 . he main functions of the surface casing string are to hold back unconsolidated
shallow formations that can slough into the hole and cause problems, isolate freshwater
formations, and to serve as a base on which to set the blowout preventers. he casing is
lowered into the hole joint by joint, and then cemented in place.
he intermediate or protective casing is set at a depth between the surface and production casings. he main reason for setting intermediate
casing is to case of the formations that prevent the well from being drilled to the total
depth. It is also used to counter balancing the formation pressure. It varies in length
Introduction 11
from 5000 – 15,000 and 7 and 113⁄4 in outside diameter. In such case, a 171⁄2 bit
is used to drill the hole down to 6000 . In case some of the formations in this section
prove troublesome (e.g., sloughing shales), another string of casing (133⁄8 intermediate
casing) must be run and cemented in place.
he next bit size is 121⁄4 and drilling proceeds as before. By this time, we may be
approaching the oil bearing formation zone. Any hydrocarbons can be detected by
examining the rock cuttings, and if this proves favorable, we may want to evaluate
the formation more fully. he drill string is pulled out, and electric logs run on wire
line are lowered into the hole. We may also want to take core samples, using a special bit which will allow recovery of a section of rock. A DST (drill-stem test) may
be carried out to gain further data. Once all of the test data indicates the positive
results, suspended pipes are run from the bottom of the next largest casing string,
which is called a liner. Liners are the pipes that do not usually reach the surface.
here are several types of liners, such as drilling liner, production liner, tie-back
liner, scab liner, and scab tie-back liner. he major advantages of liners are that the
reduced length and smaller diameter of the casing results in a more economical
casing design than would otherwise be possible, and that they reduce the necessary suspending capacity of the drilling rig. However, possible leaks across the liner
hanger, and the diiculty in obtaining a good primary cement job due to the narrow
annulus, must be taken into consideration in a combination string with an intermediate casing and a liner.
Before production casing or liner, if all the indications from the above tests are negative or show only slight indications of oil, the well will be abandoned. However, if positive results come, production casing is set through the prospective productive zones,
except in the case of open-hole completions. It is usually designed to hold the maximal
shut-in pressure of the producing formations. It is also designed to withstand stimulating pressures during completion and workover operations. Production casing provides
protection for the environment in the event of failure of the tubing string during production operations, and allows for the production tubing to be repaired and replaced.
Production casing varies from 41⁄2 and 95⁄8 in diameter, and is cemented far enough
above the producing formations to provide additional support for subsurface equipment and to prevent casing buckling. Production casing goes up to the formation zone.
So, there is no speciic length for this casing. It varies well to well, depending on the
depth of formation zones. Finally, production tubing is place for hydrocarbon production (Figure 1.2).
he third or inal stage of the drilling sequences is the completion phase. As
mentioned earlier, the completion of the well involves running the production casing (95⁄8 ) at total depth (TD) to seal of the oil producing zone (temporarily).
Another string of pipe known as tubing (41⁄2 diameter) is now run with a packer on the
outside. When packer is positioned just above the pay zone (Figure 1.2), its rubber seals
are expanded to seal of the annulus between tubing and 95⁄8 casing. A set of valves is
initiated on the top of the casing to control the low of oil once it reaches the surface.
To initiate the production, a perforating gun is run down the tubing on wireline, and
is positioned adjacent to the pay zone. Holes are shot through the casing and cement
into the formation. he hydrocarbons low into the wellbore and up the tubing to the
surface.
12
Fundamentals of Sustainable Drilling Engineering
1.7 Organization Chart and Manpower Requirements during
Drilling Operations
Drilling requires many diferent skills and involves many diferent companies. he manpower needed to complete the drilling operations is normally engaged from three separate
organizations. he organizations, such as drilling contractor, well operator, and drilling
services companies, work together and provide manpower as required and requested.
A typical drilling organization chart is shown in Figure 1.3. he oil company seeking to
exploit the petroleum reserves is known as the “Well Operator.” he operator bears overall responsibility for drilling operations. he company representative makes the rig-side
spot decisions based on the well plan for drilling operations and other services if necessary. he planning of the well is usually done by the operator’s staf engineers working
at headquarters/control oice in town. hey draw up a drilling program that must be
followed as the well is being drilled. Usually the operator will have a representative
on the rig (sometimes called the “company man”). His job is to ensure that drilling
operations go ahead as planned, to make decisions afecting progress of the well, and
to organize supplies of equipment. Any consumable items (i.e., drilling bit, drill pipe,
Oil Company
(Well Operator)
Geology
Department
Drilling
Engineering
Formation
Evaluation
Company
Representative
Operators
Accounting
Department
Drilling
Superintendent
Reservoir
Engineering
Other Wells
in Progress
Production
Engineering
Land
Department
Drillng Contractor
Accounting
Department
Drilling
Superintendent
Drilling Services Companies
Rig Design &
Maintenance
Mud Engineering
Cementing
Other Rigs
Tool Pusher
Drilling Bits
Driller
Drilling Fluid
Rig Crew
Blowout
Prevention
Field
Representatives
Surveying
Well Monitoring
Well Casing
Formation Evaluation
Directional
Drilling
Well Completion
Equipment’s
Miscellaneous
Figure 1.3 Drilling rig organizational chart.
Introduction 13
cement, etc.) must be provided by the operator. He will be in daily contact with his
drilling superintendent in the main control oice in town. here may also be a drilling
engineer and/or a geologist on the rig employed by the operator.
he oil company usually employs a “Drilling Contractor” to actually drill the well.
he contractor provides the rig and the crew to operate it. he drilling contractor is
responsible for maintaining the rig and the associated equipment. he rig operation
and rig personnel supervision are the responsibilities of drilling contractor. he drilling
contractor will have a tool pusher in overall charge of the rig. He is responsible for all
rig loor activities, and coordinates with the company man to ensure progress is satisfactory. Since drilling continues twenty-four hour a day, there are usually two drilling
crews. Each crew works under the direction of the driller (or tool pusher). he crew will
generally consists of a derrick man (who will also be liable for the pump while drilling
continues), three roughnecks (working on the rig loor), plus a mechanic, an electrician, a crane operator, and roustabouts (general laborers).
During the course of the well, certain specialized skills or equipment may be necessary
(i.e., logging, surveying, etc.). he jobs are done by the appointed service companies. he
service companies are employed by the operator. hey provide all the specialized logistic
supports and rig-side services. he service company’s personnel work on the rig as and
when required. Sometimes they are employed on a long-term basis (e.g., mud engineer),
or only for a few days (e.g., casing crews), based on demand at rig-side.
1.8 Aspect of Sustainability in Drilling Operations
Drilling is a necessary step for petroleum exploration and production. he conventional
rotary drilling technique falls short, since it is costly and contaminates surrounding
rock and water due to the use of toxic components in the drilling luids. Conventional
rotary drilling has been the main technique used for drilling in the oil and gas industry.
However, this method has showed its limits regarding the depth of the wells drilled,
in addition to the use of toxic components in drilling luids. he success of a high risk
hydrocarbon exploration and production depends on the use of appropriate technologies. herefore, to overcome the limitations of conventional rotary drilling technique, we
need to look for other environmentally friendly drilling technologies which may lead to
a sustainable drilling operation.
Generally, a technology is selected based on criteria such as technical feasibility, cost
efectiveness, regulatory requirements, and environmental impacts. Recently, Khan
and Islam (2006) introduced a new approach in technology evaluation based on the
novel sustainability criterion. In their study, they not only considered the environmental, economic, and regulatory criteria, but investigated sustainability of a technology.
‘Sustainability’ or ‘sustainable technology’ has been using in many publications, company brochures, research reports, and government documents which do not necessarily
gives a clear direction. Sometimes, these conventional approaches/deinitions mislead
to achieve true sustainability. Figure 1.4 shows the directions of true sustainability in
technology devolvement. It shows the direction of nature-based, inherently sustainable
technology, as contrasted with an unsustainable technology. he path of sustainable
technology is its long-term durability and environmentally wholesome impact, while
14
Fundamentals of Sustainable Drilling Engineering
Beneicial
Inherently Sustainable
Technology privileges
the long-term.
)
Beneit
( t
t
Unsustainable
Technology privileges
the very short-term.
( t 0)
Harmful
Figure 1.4 Direction of sustainable and unsustainable technology (Khan and Islam, 2006;
Hossain et al., 2009).
unsustainable technology is marked by Δt approaching 0. Presently, the most commonly used theme in technology development is to select technologies that are good
for t = right now , or Δt = 0. In reality, such models are devoid of any real basis (termed
“aphenomenal” by Khan et al., 2005), and should not be applied in technology development if we seek sustainability for economic, social, and environmental purposes.
In addition to technological details of an appropriate drilling technology, the sustainability of this technology is evaluated based on the model proposed by Khan and
Islam. Figure 1.5 shows the detailed steps for its evaluation. he irst step of this method
is to evaluate a sustainable technology based on time criterion (Figure 1.5). If the technology passes this stage, it would be evaluated based on criteria such as environmental,
economic, and social variants. According to Khan and Islam’s method, any technology
is considered sustainable if it fulills the environmental, economic, and social conditions (Cn + Ce + Cs) ≥ constant for any time, t, provided that, dCnt ⁄ dt ≥ 0, dCet ⁄ dt ≥
0, dCst ⁄ dt ≥ 0.
To evaluate the environmental sustainability, a proposed drilling technique is compared with the conventional technology. he current drilling technologies are considered
to be the most environmentally concerning activities in the whole petroleum operations.
he current practices produce numerous gaseous, liquid, and solid wastes and pollutants, none of which have been completely remedied. herefore, it is believed that conventional drilling has negative impacts on habitat, wildlife, isheries, and biodiversity.
For analyzing the environmental consequences of drilling, conventional drilling
practices need to be analyzed, which will be continued, chapter by chapter, in this book
on sustainability. In conventional drilling, diferent types of rigs are used. However, the
drilling operations are similar. he main tasks of a drill rig are completed by the hosting,
circulating, and rotary system, backed up by the pressure-control equipment. A drill bit
is attached at the end portion of a drill pipe. Motorized equipment rotates the drill pipe
to make it cut into rocks. During drilling, many pumps and prime movers circulate
drilling luids from tanks through a standpipe into the drill pipe and drill collar to the
Introduction 15
New Technology
Is
Yes
Accepted
for EES test
No
t
Yes
Is there scope
to improve?
Yes
Yes
d
Cnt ≥ 0?
dt
No
Improve the step...
No
No
Improve the step...
No
No
Improve the step...
No
Yes
d
Cet ≥ 0?
dt
Yes
d
Cst ≥ 0?
dt
Yes
Technology
Unsustainable
Technology Sustainable
Figure 1.5 Flowchart of sustainability analysis of a drilling technology (redrawn from
Khan and Islam, 2008; Hossain et al., 2009).
bit. he muds low out of the annulus above the blowout preventer over the shale shaker
(a screen to remove formation cutting), and back into the mud tanks. Drilling muds are
composed of numerous chemicals, some of which are toxic, and which are harmful to
the environment and its lora and fauna. hese issues will be discussed in the drilling
mud chapter. he conventional practice in the oil industry is to use diferent drilling
techniques, where huge capital is involved, and which create huge environmental negative impacts. he technology is also more complicated to handle. herefore, sustainable
petroleum operation is one of the important keys for our future existence in this planet.
1.9 Summary
his chapter discusses some of the core issues related to drilling engineering. Even before
starting drilling operations, many activities need to be completed to fulill the diferent
16
Fundamentals of Sustainable Drilling Engineering
parties’ requirements, which are well-covered here. Moreover, this chapter addresses
issues such as the deinition of drilling engineering, diferent terminologies related to
drilling operations, licensing, development plan, work sequences, and responsibilities
of drilling engineers and diferent companies. his chapter covers almost all aspects of
drilling management. Finally, the benchmark of sustainability is also discussed in the
chapter.
References
Appleton, A.F., 2006. “Sustainability: A practitioner’s relection,” Technology in Society: in press.
Canada Nova Scotia Ofshore Petroleum Board, 2002. Environmental Protection Board. White
Page. http://www.cnsopb.ns.ca/Environment/evironment.html (Cited: April 21, 2002).
EPA, 2000. “Development document for inal eluent limitations guidelines and standards for
synthetic-based drilling luids and other non-aqueous drilling luids in the oil and gas extraction point source category.” United States Environmental Protection Agency. Oice of Water,
Washington DC 20460, EPA-821-B-00-013, December 2000.
Holdway, D.A., 2002. “he Acute and Chronic Efects of Wastes Associated with Ofshore
Oil and Gas Production on Temperature and Tropical Marine Ecological Process.” Marine
Pollution Bulletin , Vol. 44: 185–203.
Hossain, M.E., Khan, M.I., Ketata, C. and Islam, M.R., 2009. “Sustainable Waterjet Drilling.”
Journal of Nature Science and Sustainable Technology, article in press.
Khan, M.I, and Islam, M.R., 2003a. “Ecosystem-based approaches to ofshore oil and gas operation: An alternative environmental management technique.” SPE Conference, Denver, USA.
October 6–8, 2003.
Khan, M.I, and Islam, M.R., 2003b. “Wastes management in ofshore oil and gas: A major
Challenge in Integrated Coastal Zone Management.” ICZM, Santiago du Cuba, May 5–7,
2003.
Khan, M.I., and Islam, M.R. 2005. “Assessing Sustainability of Technological Developments:
An Alternative Approach of Selecting Indicators in the Case of Ofshore Operations.” ASME
Congress, 2005, Orlando, Florida, Nov 5–11, 2005, Paper no.: IMECE2005-82999.
Khan, M.I., and Islam, M.R., 2006. Achieving True Sustainability in Technological Development
and Natural Resources Management. Nova Science Publishers, New York, USA, pp. 381.
Khan, M.I., and Islam, M.R., 2008. Petroleum Engineering Handbook: Sustainable Operations.
Gulf Publishing Company, Texas, USA, pp. 461.
Khan, M.I, Zatzman, G., and Islam, M.R., 2005. “New sustainability criterion: development of
single sustainability criterion as applied in developing technologies.” Jordan International
Chemical Engineering Conference V, Paper No.: JICEC05-BMC-3-12, Amman, Jordan,
12–14 September 2005.
Patin, S., 1999. Environmental impact of the offshore oil and gas industry . EcoMonitor
Publishing, East Northport, New York. 425 pp.
Veil, J.A., 2002. “Drilling Waste Management: past, present and future.” SPE paper no. 77388.
Annual Technical Conference and Exhibition, San Antonio, Texas, 29 September–2 October.
“Waste Management Practices in the United States,” prepared for the American Petroleum
Institute, May 2002.
2
Drilling Methods
2.1 Introduction
Drilling is one of the oldest technologies. Man used to dig a hole for diferent purposes.
Until internal combustion engines were developed in the late 19th century, the main
method for drilling rock was a muscle power of man or animal. Rods were turned by
hand, using clamps attached to the rod. he rope and drop method was invented in
Zigong, China where they used a steel rod or piston raised and dropped vertically via
a bamboo rope. hese Chinese wells were drilled using bamboo derricks and reached
depths of up to 4800 t. he irst rotary drilling rig was developed in France in the
1860’s. However, it was seldom used because it was erroneously believed that most
hydrocarbons were under hard-rock formations that could be easily drilled with cabletool rigs. he rotary drilling system that circulates luid to remove the rock cuttings
were successfully used in Corsicana, Texas in 1880’s where drillers searching for water,
and fortunately they discovered oil. Since then, drilling rigs underwent a revolution
of improvement in terms of drilling a well in good, safe and economic manner. here
are four main procedures on how to select the appropriate drilling: i) wells design for
the same ield, ii) the expected loads during drilling, iii) testing and any other related
operations, and iv) compare the expected loads with the existing rigs and select the best
rig and its appropriate components.
Now days, there are a lot of types of drilling rigs classiied into two major types
based on the drilling area environment which will be discussed in this chapter. his
17
18
Fundamentals of Sustainable Drilling Engineering
chapter focuses on the drilling methods used for hydrocarbon exploitation. his chapter covers the cable tool drilling rig, rotary drilling rig and its components, diferent
rotary rig systems, types of rigs, current advancement of rig systems, and the knowledge gap that needs to be illed in this area. In all drilling methods a downward force
has to be applied on the tool that breaks the rock, and therefore it is an important
parameter for an efective drilling operation. In rotary drilling the cutting tool is the
bit and the downward force is the weight of the drill string assembly applied on the bit.
he conventional practice in the oil industry is to use heavy drill string assembly for
which large capital expenses are required.
2.2 Types of Drilling Methods
here are two basic methods to drill a hole for hydrocarbon withdrawal from an underground system. hese are: i) cable tool drilling, and ii) rotary drilling.
2.2.1 Cable Tool Drilling
Cable tool drilling is deined as a drilling procedure in which a sharply pointed bit
attached to a cable and is repeatedly lited and dropped into the borehole. In cable-tool
drilling, a heavy carbide tipped drill bit (i.e. along with drill string) is suspended in the
hole by a rope or cable. A powered walking beam is operated by a steam engine through
which the cable and attached bit assembly are lowered and raised. his upward and
downward motion is repeated again and again. he drill bit chisels through the rock
by inely pulverizing the subsurface materials. Each time the bit drops it and hits the
bottom of the hole and thus cuts the rock. However, the basic principles employed in
all cable tool drilling operations virtually have been unchanged since the Chinese irst
drilled shallow wells for salt water in the ancient days. he irst oil well in the United
States was drilled with cable tools in 1859 to a depth of 65 feet located near Titusville,
Pennsylvania. hen, it was widely used from about 1870 onward. he cable-tool drilling
method was in common use until the 1920’s. Now days, cable tool is a traditional way
of drilling water wells in diferent places on earth. he majority of the large diameter
water supply wells are completed using this technique. While this drilling method has
been replaced in recent years by modern rotary drilling, it is still the most practicable
drilling method for large diameter, deep bedrock wells, and in widespread use for small
rural water supply wells.
A schematic diagram of cable tool rig is shown in Figure 2.1. he basic components
of the cable tool rigs consist of the engine and boiler, the derrick and crown block,
the bull wheel and drilling cable, the sand wheel and sanding line for the bailer, the
vertical band wheel with a center crank, drill string and the walking beam supported
by the Samson post. Band wheels are basically large pulleys (usually 8–10 t in diameter) driven by a belt from the engine, which reduces the engine RPMs and increases
power. A crank on the band wheel’s axle imparts up-and-down motion (via a pitman)
to the walking beam. he other end of the band wheel is connected to the drilling
cable by the temper screw. he walking beam alternately raises and loweres the drilling
Drilling Methods 19
Crown Block
Derrick
Drilling Cable
Bailer
Bull Wheel
Engine
Sand Reel
Calf Reel
Stem
Bit
Figure 2.1 A conventional cable tool rig.
tools. Walking beams is typically 26' 12" 24 " in size. Bull wheels and sand wheels are
spools for the drilling cable and sanding (or bailing) line, respectively. Additionally,
ishing tools, various hand tools, wrenches, and forge tools are required for the drilling
process. he drill string consists of the upper drill rods, a set of jars, and the drill bit.
During the drill process, the drill string is periodically removed from the borehole and
a bailer is lowered to collect the drill cuttings. Since the drill string must be lowered and
raised to advance the boring, casing is typically used to hold back upper soil materials
and stabilize the borehole.
his technology has achieved vast improvements in rig mechanisms and labor-saving devices. Some of the examples are modern rotary drilling rigs, powered with an
internal combustion engine, electric motor, or steam engine and most sophisticated rig
related equipment/tools. However, there are two major disadvantageous of the cabletool method; irst, the drilling has to be stopped oten and the bit pulled up so that cuttings of chipped rock could be removed; second, this system has a hard time in drilling
sot rock formations. he other disadvantages are: it is very slow, it does not efectively
control subsurface pressures, and blowouts are common in cable tool operations.
2.2.2 Rotary Drilling
Rotary drilling is a complex mechanical technique in which a drill bit is attached to the
bottomhole assembly where rotational motion is applied to cut the rock in a forward
direction. Rotary drilling is new as compared to cable tool drilling. he irst rotary
drilling rig was developed in France in the 1860’s. At the time, it was believed that most
hydrocarbons were under hard-rock formations that could be easily produced by the
cable-tool rigs. he irst rotary drilling rigs were introduced in 1890 to cut sot formations where cable-tool drilling was extremely ineicient due to caving. However, the
rotary drilling system that circulates luid to remove the rock cuttings was irst successfully used in Corsicana, Texas in the early 1900 to get water. he irst major success for
rotary drilling was at Spindletop, Texas in 1901 where oil was discovered at a depth of
1020 t and produced about 100,000 bbl/day. With time, the improvement of design of
20
Fundamentals of Sustainable Drilling Engineering
(a) A picture of an onshore rotary rig
(b) A picture of an onshore rotary rig
Figure 2.2 A conventional rotary drilling rig.
rotary drilling system made it easy to bore a hole up to a depth of 30,000 t. he conventional rotary drilling rigs for an onshore (Figure 2.2a) and an ofshore (Figure 2.2b)
are shown in Figure 2.2.
In the rotary drilling method, a large, heavy drill bit is attached to the tip of the bottomhole assembly where a downward force is applied. he bit is rotated by a drill string
composed of high quality drill pipe and drill collar. New sections of drill pipe assembly
are added at the top of the hole as drilling progresses. he taller the rig structure, the
longer the drill pipe sections that can be strung together. When it is time to replace the
drill bit, the whole drill string must be pulled out of the hole. Each pipe is unscrewed
and stacked on the rig loor. he cuttings are lited from the bore hole by injecting
drilling luids (drilling mud) through drill pipe and bit nozzles. he drilling luid is collected at the surface and passes through diferent tanks and separators to treat the mud
properly. Once the mud is ready, the cycle repeats again.
2.3 Rotary Drilling Rig and its Components
A drilling rig is a complex assembly of large heavy anchored to a mechanical structure
(Figure 2.3). he igure shows the diferent components of the rig above the ground
level. Its basic function is relatively simple. he rig structure is a giant crane for liting
and lowering drill pipe, with a rotary table to rotate the drill pipe. he function of rig
is to rotate a string of drill pipe and drill a hole in the ground. It must also pull the drill
pipe out of the hole for drill bit changes and run the pipe back into the hole. he drilling
rig must be able to perform some other functions such as circulating drilling luid to
clean the well bore and support the weight of the drill string so that the weight on the
bit can be controlled (Figure 2.4a and b). he igure shows the diferent components
that are underneath the rotary table along with other components above the rotary
Drilling Methods 21
Crown Block
Runaround
Gin Pole
Monkey Board
Jack Knife
Derrick
Traveling Block
Hook
Swivel Bail
Gooseneck
Rotary Hose
Stand Pipe
Swivel
Drilling Line
Kelly
A-Frame
Cat Head
Rotary Table
Rotary Drive
Derrick Floor
Hydromatic
Brake
Compound
Draw Works
Dog House
Draw Works Drive
Diesel Engine
Pump Drive
Substructure
Mud Pump
Shale Shaker
Mud Tanks
Figure 2.3 A conventional rotary drilling rig with diferent components.
Crown Block
Crown Block
Derrick
Safety Platform
Drilling Line
Block & Tackle
Monkey Board
Stand Pipe
Traveling Block
Hook
Swivel
Mud Hose
Suction
Pipe
Vibrating
Screen
Mud
Returns
Mud Ditch
Mud
Pump
Draw
Works
Stand Pipe
Kelly
Weight Recorder
Bell Nipple
Rotary Table
Blowout
Derrick Floor
Blow-Out Prevent Preventer
Cellar
Emergency
Flow Line
Conductor
Cement
Engine
House
Suction
Pit
Rotary Hose
Swivel
Bore Hole
Mud Pump
Drill Pipe
Conductor
Casing
Annulus
Downward Mudstream
Drilling Pipe
Drill Collars
Rising
Mudstream
Bit
(a)
Earth Pit
Bit
(b)
Figure 2.4 A conventional rotary drilling rig showing diferent components under rotary table.
22
Fundamentals of Sustainable Drilling Engineering
1.
2.
3.
4.
5.
6.
7.
8.
9.
10.
11.
12.
13.
14.
15.
16.
17.
Crown Block Assembly
Catline Boom and Hoist Line
Drilling Line
Monkey Board
Traveling Block
Top Drive (Power Swivel)
Mast
Drill Pipe
Doghouse
Blowout Preventer Control
Unit (Accumulator)
Water Tank
Electric Cable Tray
Engine-Generator Sets
Fuel Tank
10
Mud Pump
Mud Tank Pit
Reserve Pit
18.
19.
1
2
4
3
5
6
13
9
12
8
20
19
46
46.
47.
48.
49.
50.
22
17
48
49
Degasser
Desander
Desilter
Centrifugal Pumps
Mud Agitators
16
21
26
47
18
15
11
23
50
14
7
25
24
20.
21.
22.
23.
24.
25.
26.
Electrical Control (SCR)
House
Bulk Mud component
Tanks (P-Tanks)
Mud-Gas Separator
Shale Shakers
Choke Manifold
Pipe Ramp
Catwalk
Pipe Rack
Pipe on Rack
32
31
33 27
28
27.
28.
29.
30.
31.
32.
33.
Hook
Swivel
Kelly
Rotary Table Assembly
Drawworks
Stand pipe
Rotary (Kelly) House
29
30
Figure 2.5 A modern rotary drilling rig and its components.
table. In general, the equipment that are used to drill and complete a hydrocarbon well
are usually quite simple. Whether the drilling rig is ofshore or onshore, they all have
the same basic structure and use the same equipment.
A detail rotary rig devices and its diferent components are illustrated in Figure 2.5.
Almost all the parts of a modern rig are leveled in Figure 2.5. A detail rig components
names and their description are shown in this igure separately. he deinitions and
their descriptions are illustrated in Appendix 2A at the end of this chapter.
2.4
Drilling Process
When all the necessary equipment and the drilling rig are in place, the drilling processes start on for drilling activities. he drilling process entails several diferent systems which are interconnected and drives the whole drilling operations. he process
can be categorized as i) power system, ii) hoisting system, iii) circulation system,
Drilling Methods 23
and iv) rotary system. Sometime these systems are called drilling process subsystem. Most of rig components are engaged with one or more of these systems that are
shown in Figure 2.5. his igure show the conventional rotary drilling process along
with associated rig components related to the diferent systems.
2.4.1 Power System
he major components of the power system are the drawworks, mud pumps and rotary
table are shown in the rig system (Figure 2.6). he individual components of the circulating system are shown in Figure 2.7. he diesel engine set is shown in Figure 2.8
which transmits power to the three major systems of the rig. Most of the rig power is
consumed by the hoisting and circulating system. he other rig systems (such as rotary
rig etc.) have much less power consumptions. he hoisting and circulating systems do
not generally work at the same time. Power is supplied by large internal combustion
engines (prime over) fueled by diesel. Depending on its size and capacity, the rig may
Block & Tackle
Traveling Block
Hook
Swivel
Kelly
Engine
House
Rotary Table
Mud
Pump
Drawworks
Drilling Pipe
Bit
Figure 2.6 Major components of power system shown in the rig system.
Drawworks
Rotary table
Mud Pump
Figure 2.7 Major components of power system.
24
Fundamentals of Sustainable Drilling Engineering
Diesel Engines Provide
Power for the Rig
Diesel
Engines
Figure 2.8 he generator set for power system.
have up to 4 prime movers which deliver more than 3,000 hp. A typical prime mover
with generating set is shown in Figure 2.8. he diesel engines drive large electric generators. Electricity is then supplied to electric motors connected to the Drawworks,
rotary table and mud pumps. Steam power and mechanical transmission systems were
used on the early drilling rigs. Steam power and mechanical transmission systems were
being used by the older rigs. Nowadays, modern rigs are powered by internal combustion diesel engines and the modern electric transmission enables the driller to apply
power more smoothly and hence it avoids shock and vibration of the rigs.
Total power requirements for most of the modern rigs are from 1,000 to 3,000 hp.
Generally, the characteristics of power system performance are stated in terms of output horsepower, torque, and fuel consumption for various engine speeds. he heating
values of various fuels for internal combustion engines are shown in Table 2.1.
A typical arrangement of an engine with lywheel and pulley system is shown in
Figure 2.9. he shat power developed by an engine can be obtained by the following
equation:
Ps
T
(2.1)
where;
Ps = Shat power developed by an IC engine, hp
T = Output torque, ft lb f
= Angular velocity of the shat, rad/min
Equation (2.1) can be written in terms of revolution per minute, weight on pulley and
distance travel by the weight with velocity vector. In terms of revolution per minute, Eq.
(2.1) can be written as:
Ps
T
2 N
WrFW
2 rFW NW
(2.2)
In terms of velocity vector and if we consider frictionless pulley system, Eq. (2.1) can
be written as:
v
2 rFW N
(2.3)
Drilling Methods 25
Table 2.1 Heating values of various fuels.
Fuel Type
Density
lbmgal
Heating value
(btu/lbm)
Natural gas
1.07
1,030 btu/t3
Propane
4.22
2,500 btu/t3
Methane
3.54
24,000 (or 1,000 btu/t3)
Landill gas
–
500 btu/t3
Butane
4.7
21,000 (or 3,200 btu/t3)
Methanol
6.63
57,000 btu/gal
Ethanol
6.61
76,000 btu/gal
Kerosene
6.68
135,000 btu/gal
Diesel
7.2
19,000 (or 138,500 btu/gal)
Gasoline
6.6
20,000 (or 125,000 btu/gal)
Frictionless
Pulley
Fly wheel
I C Engine
r
Engine Stand
W
Weight
Figure 2.9 A typical IC engine power output.
We know that power is the product of force and velocity. So, power of shat can again
be written as:
Ps
Wd
t
W.v
where;
d = distance travel by the weight on pulley, t
N = revolution per minute, rpm
t = time required to travel the distance, d, min
W = Weight on pulley, lb f
(2.4)
26
Fundamentals of Sustainable Drilling Engineering
v = velocity vector, t/min
rFW = Radius of ly wheel, t
If we use the Eq. (2.3) into Eq. (2.4), the resultant equation turns to Eq. (2.2). he
overall engine power eiciency is determined as the power output by power input.
Mathematically, it can be written as:
ps
Power output
Power input
Ps
Qi
Ps
wf Hf
(2.5)
where;
ps = Overall engine eiciency of the power system
Qi = power input to the IC engine, hp
w f = the rate of fuel consumption by the engine, lbm / min
H f = heating value of fuel used in the engine, Btu / lbm
Example 2.1: An internal combustion engine is run by diesel fuel in a rig side to generate power for the system. It gives an output torque of 1,600 ft lb f at an engine speed of
1,150 rpm. he engine consumes fuel at a rate of 30 gal/hr. Calculate the wheel angular
velocity, power output, overall eiciency of the IC engine.
Solution:
Given data:
T = Output torque = 1,600 ft lb f
N = revolution per minute = 1,150 rpm
w f = the rate of fuel consumption by the engine = 30 gal/hr
Required data:
= Angular velocity of the shat i.e. wheel angular velocity, rad/min
Ps = Shat power developed by an IC engine i.e. power output, hp
ps = Overall engine eiciency of the power system i.e. IC engine, %
he angular velocity can be calculated by using the given equation:
2 N =2
1,150 = 7,225.68 rad/min
he power output can be calculated using Eq. (2.1) as:
Ps
T
7,225.68 rad / min
1,600 ft lb f
33,000 ft lb f / min
350.34 hp
hp
(Note: 1hp 33,000 ft lb f / min)
is 7.2
Since the engine is run by diesel fuel, therefore from Table 2.1, the density
lbm / gal and the heating value H f is 19,000 Btu / lbm. herefore the fuel consumption
rate w f can be obtained by unit conversion as:
Drilling Methods 27
wf
30 gal / hr
1hr
60 minute
7.2 lbm / gal
3.6 lbm / min
herefore, the total heat energy consumed by the IC engine i.e. input power can be
calculated by using input power part of Eq. (2.5) as:
Qi
3.6 lbm / min
wf Hf
19,000 Btu / lbm
779 ft lb f / Btu
33,000 ft lb f / min
hp
= 1,614.65 hp
(Note: 1 Btu 779 ft lb f )
hus, the overall eiciency of the IC engine is obtained by using the Eq. (2.5) as:
ps
Power output
Power input
Ps
Qi
350.34
1,614.65
0.2168 or 21.68%
Example 2.2: A diesel engine was running at a speed of 1250 rpm at the drilling operations side. he driller noticed that the engine shat output is 360 hp. He was trying to
pull a drillstring of 600,000 lb f . he engine was running for one hour. Calculate the
wheel angular velocity, torque developed by the engine, the drillstring velocity, distance
travelled by the drillstring.
Solution:
Given data:
N = revolution per minute = 1,250 rpm
W = Weight on pulley = 600,000 lb f
Ps = Shat power developed by an IC engine i.e. power output = 360 hp
t = time required to travel the distance, d = 1 week
Required data:
= Angular velocity of the shat i.e. wheel angular velocity, rad/min
T = Output torque, ft lb f
v = the drillstring velocity i.e. velocity vector, t/min
d = distance travel by the weight on pulley, t
he angular velocity can be calculated by using the given equation:
2 N =2
1,250 = 7,854 rad/min
he torque output is obtained using Eq. (2.1) as:
T
Ps
360 hp
33,000 ft lb f / min / hp
7,854 rad / min
1,512.61 ft lb f
28
Fundamentals of Sustainable Drilling Engineering
(Note: we know that 1hp 33,000 ft lb f / min)
he drillstring velocity can be calculated using the Eq. (2.4) as:
v
360 hp
Ps
W
33,000 ft lb f / min / hp
600,000 lb f
= 19.8 t/min
As the engine was running for one hour, so the total distance traveled by the drill string
within one hour is obtained by using Eq. (2.4) as:
Wd
t
W.v ;
d
t
vt
19.8 ft / min
v
So,
d
1 hr 60 min
1188 t
2.4.2 Hoisting System
Hoisting system is deined as a system which works as a complex pulley system to raise
the travelling block and remove the drill pipe and allows adding an extra length of
pipe or a new drill bit. he main function of the hoisting system is to lower or lit the
drillstring, casing string, and other subsurface equipment into or out of the hole. In
addition, making a connection (i.e. the periodic process of adding a new joint of drill
pipe as the hole deepens), and making a trip (i.e. the process of removing the drillstring
from the hole to change a portion of the downhole assembly and then lowering the
drillstring back to the hole bottom) are the two regular tasks that need to be done by
hoisting system. he main components of hoisting system are derrick (i.e. steel tower/
mast) and substructure, drawworks, and block & tackle. he assembly and components
of a hoisting system are shown in Figure 2.10.
Derrick
Crown Block
Drum
Drilling Line
(8 lines are
Strung
Dead Line
Fast Line
Traveling Block
Drawworks
Dead Line Anchor
Hook
Drum Break
Load Indicator
Figure 2.10 Diferent components of hoisting system.
Storage
Reel
Drilling Methods 29
Derrick:
Derrick is the steel structure part of a rig. It provides vertical height required to raise
pipe sections (Figure 2.11). It must have suicient height and strength to perform its
functions. Derrick is rated according to its ability to withstand compressive loads &
wind loads. he compressive load of a derrick is calculated as the sum of the strengths
of the four legs. Each leg is considered as a separate column and its strength is calculated at the weakest section. he wind load is speciied in two ways, namely with or
without pipe setback based on API derricks.
he wind load can be calculated as:
Ww
0.004 V 2
(2.6)
where;
2
Ww = wind load, lb f / ft
V = wind velocity, mph
he total compressive load on derrick can be calculated using the block and tackle
arrangement as shown in Figure 2.12. If the system has frictionless pulley, the following
relationship is evident:
WD
n 2
Whl
n
(2.7)
Crown Block
Drilling Line
Fast Line
Derrick
Deadline
Traveling Block
Hook
Drawworks
Deadline Anchor
Storage Reel
Figure 2.11 Derrick load system using block and tackle.
30
Fundamentals of Sustainable Drilling Engineering
Derrick
Leg
Tf
Fast
Line
Td
Tf
Draw
Works
Dead
Line
Anchor
D
whl
A
C
B
Figure 2.12 Derrick/mast of the hoisting system.
where;
WD = total compressive load on the derrick, lb f
n = number of drilling lines through the travelling block
Whl = hook load, lb f
Example 2.3: During a drilling rig structure fatigue test, the operator measured the wind
load of 0.5 psi. he rig has ten lines which are strung through the travelling block. A hook
load of 250,000 lbf is being hoisted. According to the API standard, calculate the wind
velocity, and the total compressive load.
Solution:
Given data:
Ww = wind load = 0.5 psi
Whl = hook load = 250,000 lb f
n = number of drilling lines through the travelling block = 10
Required data:
V = wind velocity, mph
T = total compressive load on the derrick, lb f
he wind velocity can be obtained using Eq. (2.6) as:
V
2
Ww
0.004
0.5 lb f / in2
144 in2 /1 ft 2
0.004
Drilling Methods 31
(Note: we know that 1 ft 2 144 in2 )
herefore,
V
134 mph
he total compressive load on the derrick is obtained using the Eq. (2.4) is:
WD
n 2
Whl
n
10 2
250,000
10
= 300,000 lb f
he load imposed on the derrick i.e. the total compressive load on derrick is greater
than the hook load due to the arrangement of lines on the block and tackle (Figure
2.12). herefore, using the fast line and dead line tension, the derrick load can also be
calculated by:
Derrick load = hook load + Fast line load + dead line load
WD
Whl T f
(2.8)
Td
where;
T f = tension (i.e. load) in the fast line, lb f
Td = tension (i.e. load) in the dead line, lb f
In practical situation, the total derrick load is not distributed equally over all four derrick legs due to the placement of drawworks. Figure 2.12 shows that the tension in the
fast line is distributed over only two of the derrick legs (i.e. legs A and C) and the dead
line afects only Leg D due to its attachment with this leg only. Table 2.2 shows the load
distribution for each leg where it is assumed that the four legs of the derrick are in equal
distance.
Table 2.2 Derrick leg load distribution.
Load on each derrick leg
Load
source
Total
load
Leg A
Leg B
Leg C
Leg D
Hook load
Whl
Whl /4
Whl /4
Whl /4
Whl /4
Fast line
Tf
T f /2
–
T f /2
–
Dead line
Td
–
–
–
Td
Total load
on each
derrick leg
Whl /4
T f /2
Whl /4
Whl /4
T f /2
Whl /4 Td
32
Fundamentals of Sustainable Drilling Engineering
he distribution of total load on each leg shows that leg D has more load as compared to the other three legs. It is evident that if one leg fails, the entire derrick also fails,
therefore, it is necessary to deine a maximum equivalent derrick load WDmax as the
load which is equal to four times the maximum leg load. So, the maximum equivalent
derrick load can be written as:
WDmax
Whl / 4 Td
4
(2.9)
Sometimes, a parameters named as derrick eiciency, is used to evaluate various drilling
line arrangements. Derrick eiciency is deined as the ratio of the actual derrick load to
the maximum equivalent load given by Eq. (2.9) which is written as:
D
WD
WDmax
WD
Whl / 4 Td
4
(2.10)
Drawworks:
A powerful drawworks and a pulley system attached to the derrick are used to continue its smooth operations. It is essentially a large winch that spools of or takes in
the drilling line. he main function of the drawworks is to provide the hoisting and
braking power required to raise or lower the heavy strings of pipe (drill pipe, casing
pipe etc.). he main components of drawworks are drum, break, transmission, and
cathead (Figure 2.13). he large revolving drum transmits torque required for hoisting
and breaking. It also rolls the drill line (a wire rope). It has a catshat where the catheads
Figure 2.13 Drawworks assembly
Drilling Methods 33
Derrick
Drilling Line
(8 lines are
Strung)
Fast Line
Crown Block
Dead Line
nTf
n=4
Drum
Traveling Block
Dead Line
Anchor
Storage
Reel
Hook Whl
Drum Break
Drawworks
Load Indicator
Figure 2.14 Block & tackle arrangement for the hoisting system.
are mounted. he driller controls the drawworks by applying a main brake as well as
auxiliary brakes to assist during drilling operations.
Block & tackle:
Components of block & tackle are crown block, traveling block, and drilling Line
(Figure 2.14). he crown block is a large set of pulleys (sheaves) ixed to the top of
the derrick (Figure 2.15a). he drilling line is threaded over the crown block down to
another set of pulleys that are known as the travelling block (Figure 2.15b). Travelling
block suspends a large hook with a snap shut locking device (Figure 2.14). his hook
accepts the bail of the swivel when the rig is in drilling operations. In addition, it takes
the weight of the drill string. he elevators are also attached to the travelling block.
hese synchronizing components are used when drill string is running in or pulling out
of the hole. A set of clamps are fastened around the drill pipe below a tool joint. Once
the elevators are latched, the drill string can be raised by pulling three joints of drill
pipe at a time. One end of the drilling line is secured to an anchorage point somewhere
below the rig loor (Figure 2.14). his drilling line is called deadline since it does not
move. he other end of the drilling line is wound on to the drawworks and is called the
fast line (Figure 2.14).
he drilling line is usually rolled several times around the blocks to take heavy
loads (eight or ten lines are in common). he wire rope does not wear uniformly over
its entire length. he most severe wear occurs at the pickup points, where the rope
passes over the top of the crown block sheaves during trips. To maintain the drilling
line in good condition a slip and cut program is regularly carried out. his is done by
unclamping the deadline anchor, removing some line from the drawworks, replacing
it with some line led through from the reserve drum. To assess the amount of wear on
the drilling line a Ton-miles calculation is made. he stands must be racked by the derrick man standing on the monkey board about 95 t above the rotary table. he selection of suitable rig generally involves matching derrick strength and the capacity of the
34
Fundamentals of Sustainable Drilling Engineering
(a) Crown block
(b) Travelling block
Figure 2.15 Crown block and travelling block for the hoisting system.
n Tf
Drilling line
n=4
Travelling block
Hook
Whl
Figure 2.16 Travelling block diagram for force analysis.
hoisting gear. Consideration must also be given to mobility and climate conditions. he
standard derrick measures 140 t high, 30 t square base, and is capable of supporting
1,000,000 lbs of weight.
he main function of block & tackle is to provide the mechanical advantage which
allows drillers to handle a large amount of loads easily. It is deined as the load supported by the travelling block to the load imposed on the drawworks. As Figure 2.16
shows the hook load is completely carried over by the travelling block, and the load
imposed on the drawworks is equal to the tension in the fast line, therefore mathematically the mechanical advantage can be written as:
Madv
Whl
Tf
(2.11)
where;
Madv = mechanical advantage
he ideal mechanical advantage that assumes no friction in the block and tackle can be
determined from a force analysis of the travelling block (Figure 2.16). If it is assumed
that there is no friction in the system, the tension in the drilling line would remain
same all through block – pulley – drawworks. hus the forces acting on the travelling
block can be written as:
forces
Tf
0 or, Whl nTf
Whl
n
0
(2.12)
Drilling Methods 35
where;
n
= number of lines strung through the travelling block
Now, the ideal mechanical advantage can be derived using the Eq. (2.12) into Eq. (2.11)
yielding:
Whl
Whl / n
Miadv
(2.13)
n
Equation (2.13) shows that ideal mechanical advantage is equal to the number of drilling lines strung to the travelling block and crown block. he use of six, eight, ten and
twelve lines is common, depending on the loading condition.
he power of the block and tackle can be deined as the work done per unit time.
hus, the input power of the block and tackle is measured as the drawworks load (i.e.
fast line tension) multiplied by the fast line velocity, mathematically:
Pibt
(2.14)
Tf v f
where;
Pibt = input power of the block and tackle, hp
v f = velocity of the fast line, ft / min
Accordingly, the output power or hook power can be measured as the traveling block
load (i.e. hook load) times the velocity of the traveling block.
Poutbt
(2.15)
Whl vbt
Where;
Poutbt = output power of the block and tackle, hp
vbt = velocity of the traveling block, ft / min
Equation (2.12) shows that Whl T f n for a frictionless block and tackle. Since the unit
distance movement of the fast line tends to shorten each of the lines strung between the
crown block and traveling block only by 1/ n times the unit distance, then the traveling
block velocity can be calculated using the following relation:
vbt
vf
(2.16)
n
Now the eiciency of the frictionless block and tackle can be obtained as the ratio of
output power to input power. hus, dividing Eq. (2.15) by Eq. (2.14) and substituting
Eq. (2.16) and hook load, the following unity of eiciency is obtained:
Poutbt
bt
Pibt
Whl vbt
Tf v f
Tf n
Tf v f
vf
n
1
(2.17)
36
Fundamentals of Sustainable Drilling Engineering
However, in practical situation, there is no such frictionless system and there is always
some loss of power due to friction. he approximate block and tackle eiciency can be
characterized by a relationship, bt e n 0.98n. herefore, the actual block and tackle
eiciency can be obtained using the actual tension in the fast line for a given hook load.
As a result, the following mathematical relationship is obtained:
Poutbt
bt
Whl
Whl vbt
Tf v f
Pibt
vf
n
Whl
Tf n
Tf v f
(2.18)
Equation (2.18) lead to ind out the fast line tension in terms of hook load and block
and tackle eiciency as:
Whl
bt n
Tf
(2.19)
Equation (2.19) can be used to select drilling line size. Since there is a line wear and shock
loading condition, a safety factor is needed to be considered. he tension in the deadline
can be obtained by Td Whl / n because the friction in the stacks will not afect the deadline. Substituting Eq. (2.19) and Td in Eq. (2.8), the following relationship is obtained:
WD
Whl
1
Whl Whl
n
bt n
bt
bt
bt
n
(2.20)
Whl
n
Again the maximum derrick load can be obtained by substituting Td Whl / n in Eq.
(2.9) yield:
WDmax
Whl
4
Whl
n
4
n 4
Whl
n
(2.21)
Again substituting Eq. (2.20) and Eq. (2.21) in Eq. (2.10), the derrick eiciency becomes:
1
D
WD
WDmax
bt
bt
bt
n
n
n 4
Whl
n
Whl
n 1
bt
bt
n 4
1
(2.22)
Example 2.4: he total weight of 9,000 t of 9 5/8-inch casing for a deep well is determined to be 400,000 lbs. Since this will be the heaviest casing string run, the maximum
mast load must be calculated. Assuming that 10 lines run between the crown and the
traveling blocks and neglecting buoyancy efects, calculate the maximum load.
Solution:
Given data:
Whl = hook load = 400,000 lb f
Drilling Methods 37
Lc = length of casing = 9,000 t
ODc = outer diameter of casing = 9 5/8 in
n
= number of drilling lines through the travelling block = 10
Required data:
WDmax = Maximum derrick load, lb f
If frictionless pulley and block and tackle system is used, the fast line tension can be
calculated using Eq. (2.12) as:
Tf
400,000 lb f
10
40,000 lb f
If we consider that the deadline has also the same tension, the maximum derrick load
can be obtained using the Eq. (2.9) or Eq. (2.21) as:
Eq. (2.9): WD
max
Eq. (2.9): WDmax
Whl / 4 Td
n 4
Whl
n
4
400,000
40,000
4
10 4
10
4
560,000 lbf
400,000 lb f = 560,000 lbf
his example demonstrates two additional points – the marginal decrease in mast load
decreases with additional lines, and the total mast load is always greater than the load
being lited.
Example 2.5: he hoisting system of a rig derrick has a load of 350,000 lb f . he input power
of the drawworks for the rig can be a maximum of 530 hp. Eight drilling lines are strung
between the crown block and traveling block. Assume that the rig loor is arranged as
shown in Fig. 2.9. Consider there is some loss of power due to friction within the hoisting
system. Compute (1) the static tension in the fast line when upward motion is impending
(2) the mechanical advantage of the block and tackle (3) the maximum hook horsepower available (4) the maximum hoisting speed (5) if a 90 t stand is required to be
pulled, what should be the required time (6) the actual derrick load (7) the maximum
equivalent derrick load (8) the derrick eiciency factor.
Solution:
Given data:
Whl = hook load = 350,000 lb f
Pibt = input power of the block and tackle = 530 hp
n = number of drilling lines through the travelling block = 8
Ls = length of stand = 90 t
Required data:
Tf
= tension (i.e. load) in the fast line, lb f
Madv = mechanical advantage
Poutbt = output power of the block and tackle, hp
38
Fundamentals of Sustainable Drilling Engineering
vbt
t
WD
WDmax
D
= velocity of the traveling block, ft / min
= time, min
= actual load on the derrick, lb f
= Maximum derrick load, lb f
= derrick eiciency, %
(1). As the system is not frictionless, then irst we need to calculate the hoisting eiciency for eight numbers of drilling lines. he approximate block and tackle eiciency
can be characterized by the following relationship:
0.98n 0.988
en
bt
0.851
herefore, the static tension in the fast line can be obtained using Eq. (2.19):
Whl
bt n
Tf
350,000 lb f
0.851 8
51,410 lbf
(2). he mechanical advantage of the block and tackle is given by Eq. (2.11) as:
Madv
350,000 lb f
Whl
Tf
51, 410 lb f
6.81
(3). he maximum hook horsepower available can be obtained applying Eq. (2.17) as:
Poutbt
bt
Pibt
0.851 530 = 451.03 hp
(4). he maximum hoisting speed is the maximum velocity of the block and tackle that
can be attained by the available hook power. herefore the maximum velocity can be
obtained by using Eq. (2.15) as:
vbt
33,000 ft lb f / min
451.03 hp
Poutbt
hp
350,000 lb f
Whl
= 42.53 ft /min
(5). To pull a 90 t long stand, the time required can be estimated using the deinition
of speed as:
t
Ls
vbt
90 ft
= 2.12 min
42.53 ft / min
(6). he actual derrick load is given by Eq. (2.20):
WD
1
bt
bt
bt
n
n
Whl
1 0.851 0.851 8
0.851 8
350,000 lb f
Drilling Methods 39
= 445,160.1 lb f
(7). he maximum derrick load can be obtained by using Eq. (2.21) as:
n 4
Whl
n
WDmax
8 4
8
350,000 lb f = 525,000 lbf
(8). he derrick eiciency is given by Eq. (2.22):
D
WD
WDmax
445,160.1 lb f
525,000 lb f
= 0.8479 = 84.8%
Example 2.6: A diesel engine is run to generate power for the rig system. It gives an
output torque rating of 1,500 ft lb f at an engine speed of 1,170 rpm. Consider that
there is a friction loss in the pulley and block and tackle system. he hook load of the
rig is 580,000 lb f and there are ten drilling lines strung on the system. Find the output
power of the engine, velocity of the fast line, tension of the fast line, velocity of the travelling block, power output of the block and tackle, eiciency of block and tackle.
Solution:
Given data:
T
= Output torque = 1,500 ft lb f
N = revolution per minute = 1,170 rpm
Whl = hook load = 580,000 lb f
n
= number of drilling lines through the travelling block = 10
Required data:
Ps
= Shat power developed by an IC engine i.e. power output, hp
T f = tension (i.e. load) in the fast line, lb f
v f = velocity of the fast line, ft / min
vbt = velocity of the traveling block, ft / min
Poutbt = output power of the block and tackle, hp
= eiciency of the block and tackle, %
bt
he angular velocity can be calculated by using the given equation:
2 N =2
1,170 = 7,351.34 rad/min
he power output can be calculated using Eq. (2.1) as:
Ps
T
7,351.34 rad / min
1,500 ft lb f
33,000 ft lb f / min
334.15 hp
hp
(Note: 1hp 33,000 ft
lb f /min)
If we consider that this engine power output will be only engaged by the hoisting system and there is no friction loss on the pulley, this engine power output would be
40
Fundamentals of Sustainable Drilling Engineering
considered as the power input for the block and tackle (Pibt ). So, Pibt = 334.15 hp. Tension
in the fast line can be obtained using Eq. (2.12) as:
Tf
580,000 lb f
Whl
n
= 58,000 lb f
10
Using Eq. (2.14), the velocity of the fast line can be obtained as:
vf
Pibt
334.15 hp
33,000 ft lb f /min
hp
= 190.12 ft /min
58,000 lb f
Tf
Equation (2.16) is used to calculate the velocity of travelling block as;
vf
vbt
190.12 ft / min
= 19.0 ft /min
10
n
he output power or hook power can be measured as the traveling block load (i.e. hook
load) times the velocity of the traveling block i.e. using Eq. (2.15) as:
Poutbt
580,000 lb f
Whl vbt =
19.0 ft / min
33,000 ft lb f / min
= 333.94 hp
hp
he eiciency of the block and tackle can be given by Eq. (2.18) as:
Poutbt
bt
Pibt
333.94 hp
= 0.99 = 99%
334.15 hp
Just to cross check, if we use the relationship
as bt en 0.98n 0.9810 0.817 81.7%
bt
en
0.98n for the eiciency, it becomes
2.4.3 Circulation System
he circulating system is like a close loop electric circuit through which drilling luid
(i.e. mud) can travel from surface to all the way down hole and back to its initial point
(i.e. mud pit). It goes from the mud pits to main rig pumps (i.e. mud pump), and then
major components including surface piping, standpipe, kelly hose, swivel, kelly, drill
pipe, drill collar, bit nozzles, the various annular geometries (annulus means space
between drill pipe and hole) of the open hole and casing strings, low line, mud cleaning equipment, mud tanks, and again the mud pit/mud pump (Figure 2.17). It is obvious that the rock cuttings must be removed from the borehole to allow drilling to
proceed. his is done by pumping drilling luid down the drillstring, through the bit
and up the annulus. he cuttings are then separated from the mud, which is then
recycled. he circulating system (i.e. drilling luid) also enables to clean the hole of
cuttings made by the bit; to exert a hydrostatic pressure suicient to prevent formation
luids entering the borehole; and to maintain the stability of the hole by depositing a
Drilling Methods 41
thin mud-cake on the sides of the hole. he main components related to the circulating system are mud pumps, mud pits, mud mixing equipment and contaminantremoval equipment (Figure 2.18). he detail equipment list for this system is shown in
Figure 2.17 and Figure 2.18. Drilling luid is usually a mixture of water, clay, weighting
material (barite) and chemicals. A variety of mud are now widely used (i.e. oil base,
invert oil emulsion). he mud must be mixed and conditioned in the mud pits, and
then circulated by large pumps i.e. sludge pumps (Figure 2.19). A schematic diagram
illustrating a typical rig circulating system along with its low direction is depicted in
Figure 2.20. he mud is pumped through whole cycle as mentioned in the Figure 2.20.
Once the mud comes back to the surface again, the solids must be removed and the
mud is conditioned prior to being re-circulated. hese solids and some other contaminants are removed using shale shaker, desander, desilter, and degasser (Figure 2.21).
he mud pit is usually a series of large steel tanks, all interconnected and itted with
agitators to maintain solids in suspension (Figure 2.22). Some pits are used for circulating (i.e. suction pit) and others for mixing and storing fresh mud. Most modern rigs
have equipment for storing and mixing bulk additives (i.e. barite) as well as chemicals
(both granular and liquid). he mixing pumps are generally high volume, low discharge centrifugal pumps (Figure 2.18). At least two sludge pumps are installed on the
rig. At shallow depths they are usually connected in parallel to deliver high low rates.
Swivel
CIRCULATION
SYSTEM
Rotary
House
Stand
Pipe
Discharge
Line
Mud
Tank
Kelly
Suction
Line
Drill
Pipe
Degasser
Mud
Pump
Desilter
Return
Line
Desander
Annulus
Shale
Shaker
Steel
Tank
Drill
Collar
Drill Bit
Figure 2.17 Diferent components showing rig circulating system.
42
Fundamentals of Sustainable Drilling Engineering
Bulk Storage
Mixing Hopper
Mud Pump
Centrifugal Pump
Desilter
Desander
Standpipe
Degasser
Chemical Tank
Swivel
Earthen
Pits
Drill String
Shale Shaker
Steel Tank
Annulus
Bit
Figure 2.18 Diferent components showing rig circulating system with cleaning
equipment.
Figure 2.19 A typical mud pump.
Positive displacement pumps are used (reciprocating pistons) to deliver high volumes at high discharge pressures. he discharge line from the mud pumps is connected to the standpipe, a steel pipe mounted vertically on one leg of the derrick. A
lexible rubber hose (i.e. kelly hose) connects the top of the stand pipe to the swivel
via the gooseneck (Figure 2.3). Once the mud has been circulated round the system it
will contain suspended solids, perhaps some gas and other contaminants. hese must
be removed before the mud is recycled. he mud passes over a shale shaker, which
Drilling Methods 43
Mud Pump
Mud Tank
Degasser
Rotary
Hose
Desilter
Stand
Pipe
Desander
Earthen Pit
Bell Nipple
Blowout
Preventer
Emergency
Flow Line
Shale Shaker
Conductor Casing
Annulus
Drill Pipe
Drill
Collars
Figure 2.20 A complete rig circulating system with rig itself.
Desander
Shale Shaker
Desilter
Degasser
Figure 2.21 A typical photograph of shale shaker, desander, desilter, and degasser.
44
Fundamentals of Sustainable Drilling Engineering
Figure 2.22 A typical photograph of mud tank.
is basically a vibrating screen. his removes the larger particles, while allow the residue (underlow) to pass into settling tanks. he iner material can be removed using
desanders, degassers, and centrifuges. If the mud contains gas from the formation it
can be passed through a degasser which operates a vacuum, thereby separating the
gas from the liquid mud. Having passed through all the mud processing equipment
the mud is pumped to settling traps prior to being returned to the mud tanks for recycling. Another tank which is useful for well monitoring is the possum belly tank. his is
calibrated to measure the luid displaced from hole while running in. If the level varies
signiicantly from the expected level a pressure control problem can be identiied and
necessary actions take place.
Mud pumps:
As mentioned above, mud circulating pumps are used to circulate drilling luid at the
desired pressure and volume. With some exception, mud pumps always have reciprocating positive–displacement pistons. Figure 2.19 depicts the conventional mud pumps
used in the oil ield application. Two types of pumps are commonly used during rig
operations based on site are duplex (two cylinder) and triplex (three cylinder) pumps.
he duplex pumps are normally double action that pump on both forward and backward piston strokes and are generally used in onshore rigs. he triplex pumps are generally single action that pump only on forward piston strokes and are usually used in
ofshore rig operations. A comparison of both duplex and triples pumps is shown in
Table 2.3. he table shows that triplex pumps are more suitable than duplex pump.
herefore majority of pumps used are in triplex type.
he choice of reciprocating positive displacement pistons gives some additional
advantages – it has ability to move high solids-content luids; ability to pump large particles; ease of operation and maintenance; reliability; ability to operate over wide range
of pressures and low rates by changing diameters of the pump liners (compression cylinders) and diameter of pistons. However, the main disadvantage of these pumps is that
the discharge low is pulsating, which causes periodic impact loads on discharge lines.
his efect is minimized by air illed surge chambers located on the discharge line. Mud
Drilling Methods 45
Table 2.3 A comparison between duplex and triplex pumps.
Duplex pump
Triplex pump
Heavy
Light
Bulky
More compact
High output pressure
Lower output pressure
More o/p pulsation
Less o/p pulsation
More maintenance
Less maintenance
Costlier to operate
Cheaper to operate
1"
18"
2 1"
mud pump means that the pump has a piston diameter of (i.e. liner size) of 6 and
2
a stroke length of 18". In general, two circulating pumps are installed on the rig. For
pumps are commonly categorized by bore and stroke. As an example, an 6
the large hole sizes used on the shallow portion of most wells, both pumps can be used
operated in parallel to deliver the large low rates required. On the deeper portions of
the well, only one pump is required, and the second pump serves as a standby for use
when pump maintenance is required.
he overall eiciency of a mud-circulating pump can be calculated as the product of
the mechanical eiciency and the volumetric eiciency. Mechanical eiciency Pmech is
usually assumed as 90% which is related to the eiciency of the prime over itself and
the linkage to the pump drive system. On the other hand, volumetric eiciency Pvol is
usually as high as 100% if the suction of the pump is adequately charged. Most manufacturer speciications show that Pmech is 90% and Pvol is 100%.
Figure 2.23 depicts the valve and cylinder arrangement of a double acting (Figure 2.23a)
and a single acting (Figure 2.23b) pumps. he development of the theoretical performance of pumps is extremely important because proper pump selection and utilization is
imperative to the over-all eiciency of drilling operations. he circulation requirements
in the area of use should be carefully analyzed before the inal selection is made. Typical
hydraulic calculations which emphasize this point will be discussed in Chapter 4.
he theoretical displacement from a double-acting pump is a function of the piston
diameter, the liner diameter, and the stroke length. herefore, on the forward stroke of
each piston and liner system, the volume of liquid displaced is obtained by (Figure 2.23a):
VF 1
4
dl2 Ls
where,
VF 1 = volumetric displacement of liquid for a forward stroke with one piston,
dl = liner diameter, inch
(2.23)
in3
stroke
Fundamentals of Sustainable Drilling Engineering
Discharge
P2
Discharge
P2
Piston
Discharge
P2
Piston Rod
dl
Piston
46
Piston Rod
dl
dpr
Ls
Ls
P1
P1
Suction
P1
Suction
Suction
(a) Double acting pump
(b) Single acting pump
Figure 2.23 Valve and liner arrangement of mud circulating pumps
Ls = stroke length, inch
Similarly, on the backward stroke of each piston and liner system (Figure 2.23a), the
volume of liquid displaced is calculated by the following formula where the piston
diameter circumferential volume is subtracted.
VB1
4
dl2 Ls
d 2pr Ls
4
4
dl2 d 2pr Ls
(2.24)
where,
VB1 = volumetric displacement of liquid for a backward stroke with one piston,
in3
stroke
d pr
= piston diameter, inch
herefore, for a double acting (duplex) pump having two cylinders, the total volumetric
displacement of liquid per complete pump cycle is given by combining Eq. (2.23) and
Eq. (2.24) as:
qD
VF 1 VB1
2
4
dl2 Ls
4
dl2 d 2pr Ls
Ls
2
2dl2 d 2pr
(2.25)
If the volumetric eiciency of pump ( p ) is considered, the total volumetric displacement per cycle can be written using Eq. (2.25) as:
qD
Ls
2
2dl2 d 2pr
p
(2.26)
Sometimes, the volumetric displacement per cycle is called pump factor. For N number
of pump cycle, Eq. (2.26) can be written as:
qDN
where,
Ls
2
p
2dl2 d 2pr
N
(2.27)
Drilling Methods 47
N = number of pump cycle i.e. revolutions per minute of crank =
piston strokes / min
4
Since both pistons make a stroke in each direction for each revolution of the crank,
there are four individual piston strokes per crank revolution. herefore, for N revolution, Eq. (2.27) can be obtained as:
Ls
qDN
p
2dl2 d 2pr
2
4N
(2.28)
Now, pumps are commonly rated by hydraulic horsepower. If we assume that suction
pressure is atmospheric, then work done per piston stroke can be calculated as:
WP
Pd
4
dl2 d 2pr
where,
WP = work done per piston stroke, lb f
Pd = discharge pressure, psig
Ls
12
(2.29)
ft
Since both pistons make a stroke in each direction for each revolution of the crank,
there are four individual piston strokes per crank revolution. herefore, for N revolution, Eq. (2.29) can be obtained as:
WPN
Pd
4
Ls
12
dl2 d pr2
Where,
WPN = work done per complete stroke, lb f
4N
(2.30)
ft
he power output for pump then can be obtained as:
Pd
Pout p
4
dl2 d pr2
Ls
12
4N
Pd dl2 d pr2 Ls N
126050.4
33,000 ft lb f / min
hp
(2.31)
mp
mp
Where,
WPN = work done per complete stroke, lb f ft
Pout p = output power for the duplex pump, hp
mp = mechanical eiciency of the duplex pump, %
For a mechanical eiciency of 85%, Eq. (2.31) can be reduced to the following equation:
Pout p
Pd dl2 d pr2 Ls N
107143
(2.32)
In general, pumps are rated for hydraulic horse power, maximum pressure, and maximum low rate. he following equation is used to calculate the pump horse power.
48
Fundamentals of Sustainable Drilling Engineering
Php
pq
1714
(2.33)
Where,
Php = pump horse power, hp
p = increase in pressure, psi, which cannot be more than 3,500 psi.
q = low rate, gal/min
As shown in Figure (2.23b) for a single acting pump (triplex), there is only one suction and delivery valve which means there is no backward displacement. herefore, the
volumetric displacement by each piston stroke during one complete cycle is given by
qS
4
dl2 Ls
(2.34)
hus the volumetric displacement per cycle for a single-acting pump having three cylinders with volumetric eiciency becomes as:
qST
3 2
d L
3 l s
(2.35)
p
For N number of pump cycle, Eq. (2.35) can be written as:
qSTN
3 2
dL
3 l s
p
(2.36)
N
Example 2.6: Calculate the liner size required for a double-acting duplex pump where
rod diameter is 2.5 in, stroke length is 22 in stroke, pump speed is 70 strokes/min. In
addition the maximum available pump hydraulic horsepower is 1200 hp. For optimum
hydraulics, the pump recommended delivery pressure is 3,000 psi. Assume the volumetric eiciency of pump is 98%.
Solution:
Given data:
d pr = piston rod diameter, inch = 2.5 in
Ls = stroke length, inch = 22 in
4N = revolutions per minute of crank = piston strokes / min =
70 strokes/min
Pout p = output power for the duplex pump, hp = 1200 hp
Pd = discharge pressure, psig = 3,000 psi (here it is p for the pump)
= volumetric eiciency of pump = 0.98
p
Required data:
dl
= liner diameter, inch
Using Eq. (2.26), the pump displacement for a duplex pump is given by
qD
Ls
2
2dl2 d 2pr
p
(22 in)
2
2dl2
2.5 in
2
0.98,
in3
stroke
Drilling Methods 49
33.85
2dl2
2.5 in
2
in3
stroke
1 gal
231in3
2dl2
2.5 in
6.82
2
,
gal
stroke
(Note: 1 gal 231 in3 )
Using Eq. (2.28), the pump displacement for a duplex pump operating at 60 strokes/
min is given by
qDN
Ls
p
2dl2 d 2pr
2
17.6 dl2 55 gpm
2dl2
4N
2.5 in
2
,
6.82
gal
stroke
60
stroke
min
Equation (2.33) gives the pump displacement as
Php
pq
1714
1,200 hp
3,000 psi q
1714
q
685.6 gpm
heoretically, these two pump displacement is equal therefore,
qDN
q
17.6 dl2 55
685.6
d l = 6.49 in
2.4.4 Rotary System
A rotary system is designed to give the continuous rotation from the surface to the drill
string assembly to achieve bit rotation. his system includes all of the equipment used
to attain bit rotation. here is a rotating machine (rotary table) on the rig loor, through
which drillpipe is run. he drilling bit is screwed on (or made up) to the end of the
drillpipe and lowered into the hole. As the hole gets deeper more sections of drillpipe
are added to the drill string on surface. When the rotary table is engaged it rotates the
pipe and the bit, which cuts away the rock at the bottom of the hole. A schematic diagram of diferent components of rotary system is shown in the Figure 2.24. he main
components of rotary system include 1) swivel, 2) kelly, 3) rotary table 4) rotary drive,
5) drill pipe, and 6) drill collars. here are some other related components such as kelly
bushing, kelly hose and bit etc.
A set of slips is used to suspend pipe in the rotary table when making or breaking
a connection. Slips are usually designed to have three hinged segments, which have
a tapered inish outside. he inside has an uneven surface which grips the pipe. Two
large wrenches (tongs) are used to break a connection. A stand of pipe is raised up into
the derrick until the lowermost tool joint appears. he roughnecks drop in the slip to
wedge and support the rest of the string. he breakout tongs are latched above the connection, the makeup tongs below the connection. Both tongs are usually connected
by a chain to their respective catheads (the makeup cathead is usually on the driller’s
side of the drawworks). With the makeup tong held in position, the driller operates the
breakout tong and breaks the connection.
To make a connection the makeup tong is put above, and the breakout tong below
the connection. his time the breakout tong is ixed, and the driller pulls on the makeup
50
Fundamentals of Sustainable Drilling Engineering
Drilling Line
Traveling Block
Hook
Hose
Elevator
Goose Neck
Swivel
Kelly
Kelly Bushing
Master Bushing
Figure 2.24 Diferent components of rotary system.
cathead until the connection is tight. Although the tongs are used to break or tighten
up a connection to the required torque, other means are available to screw up the two
joints prior to torquing up:
• For making up the kelly the lower tool joint is ixed by a tong while kelly
is rotated by a kelly spinner, using compressed air.
• A tong may be clamped around the top tool joint while the table is rotated
clockwise to unscrew the connection.
• A drillpipe spinner (power tong) may be used to make up or backof a
connection (powered by compressed air).
• For making up some subs or special tools (i.e. MWD subs) a chain tong
is oten used.
2.5 Types of Rotary Drilling Rigs
A drilling rig is a steel structure with other equipment and rig components. here are
many types and designs of drilling rigs based on equipment usages, geographical location of well, position and height of derrick, type of pipe used, and method of rotation.
Drilling rigs can be classiied using any of the features. Broadly, it can be categorized
as cable tool rig and rotary drill rig based on geographical location uses (Figure 2.25).
Rotary drilling rigs can be further classiied into two broad categories as ofshore (i.e.
marine) and onshore (i.e. land) rigs. Figure 2.25 depicts a more detailed classiication
of the rigs that are used currently in drilling operations based on site.
A schematic view of marine and land rigs are shown in Figure 2.26 and Figure 2.27.
he primary purpose of ofshore rig is to set a well in the ofshore area. he key design
features of ofshore rigs are portability and maximum water depth of operation. For an
ofshore rig, the structure upon which wells produce is called as production platform.
Drilling Methods 51
Drilling rigs
Cable tool rigs
Rotary drilling rigs
Onshore
Ofshore
Fixed platforms/
Bottom support
Floating
Conventional rigs
Mobile rigs
Jacknife
Barge
Jackup
Selfcontained
Platform
Semi-submersible
Tendered
Figure 2.25 Diferent types of rotary drilling rigs.
Figure 2.26 Ofshore rigs.
Figure 2.27 Onshore rigs.
Drillship
Portable mast
52
Fundamentals of Sustainable Drilling Engineering
Figure 2.28 Structure rigs.
A ixed platform or structured rig is an immobile of shore structure from which development wells are drilled and produced (Figure 2.28). It is mounted on ixed platform
where drilling equipment are secured on the deck. Platform rigs may be built of steel
or concrete and may be either rigid or compliant. Rigid platform rigs, which rest on
the sealoor, are the caisson-type platform, the concrete gravity platform, and the steeljacket platform. hese are capable of being set in water depths of 10' 850'. hese types
of ixed platforms are used to drill development (directional) wells from one location.
he loating type rig is a loating vessel upon which a drilling rig sits where sometime
a semi-submersible rig or drillships take the place for ofshore drilling. he jack-up rig
is a type of mobile platform for ofshore drilling which is capable of standing on sea
loor (Figure 2.29). It is also supported by the mat and provides a stable base for drilling
of oil and gas exploration and production wells. It can have several supporting legs such
as three, four or more. In general, four suction piles are located at corners of the mat to
restrict the movement of the rig and maintain positioning during strong current lows
and wave impacts. It can be towed on location and few are self-propelled. It is capable
of working in water depths of 30' 350' with a drilling depth of up to 9500'.
A Tension Leg Platform (TLP) or Extended Tension Leg Platform (ETLP) is a vertically moored loating platform held in place by an anchor system (Figure 2.30). he
TLP’s are similar to conventional ixed platforms except that the platform is maintained
on location through the use of moorings held in tension by the buoyancy of the hull.
TLP is used where water depths DW are within the range of 1000' DW 4,900' . he
anchor system is a set of tension legs (also called set of tethers) or tendons attached
to the platform of TLP. hese legs are connected to a template or foundation on the
sealoor. he template is held in place by piles driven into the sealoor. his method
restricts the vertical motion of the platform. On the other hand, it allows for horizontal
movements. he topside facilities (processing facilities, pipelines, and surface trees) of
Drilling Methods 53
Figure 2.29 Jackup rigs.
the TLP and most of the daily operations are the same as for a conventional platform.
TLPs have been used since the early 1980s. he irst TLP was built for Conoco’s Hutton
ield in the North Sea in the early 1980s.
Semisubmersible drilling rig is a loating ofshore drilling unit (Figure 2.31). It
has pontoons and columns that help to lood which causes the unit to submerge in
'
water to a predetermined depth. It is capable of drilling in water depths of 20 7000'
or more. he necessary oice space, limited residential space and storage etc. are
reassembled on the deck. his rig is either self-propelled or towed to a drilling site
and either anchored or dynamically positioned over the sea. However, the rig itself
remains stationary at well location by a series of anchors. Drillship is a self-propelled
loating ofshore drilling vessel (Figure 2.32). he vessel is constructed in such a way
so that it can drill from its base. Drillship is capable of drilling in water depths more
than 10,000 t. However, it is not as stable as semisubmersible. here are two basic
types of drill ships – positions itself with anchors, and uses dynamic positioning
(GPS-Global Positioning System).
Land rigs are primarily used in land. In the early stage of rotary drilling operations,
drilling rigs were semi-permanent in nature which were built on site and let in place
ater the completion of the well. hese days, the drilling rigs are becoming more and
more expensive due to the addition of numerous automatic and advanced technologies
on the rig components. Most land rigs have to be transported to location in sections,
some are self-contained, permanently mounted on trucks. herefore, now there is an
option to carry the rigs from well to well. Land rigs are capable of drilling holes to a
depth of more than 30,000 feet. Some light-duty drilling rigs are similar in nature to a
mobile crane. Larger land rigs are dismantled into multiple sections and loads in order
to move to a new location. Jackknife rig is a drilling rig that has jack-knife mast instead
of a standard derrick (Figure 2.33). he jackknife rigs are assembled on the ground with
54
Fundamentals of Sustainable Drilling Engineering
SUBSEA
FIXED
COMPLETIONS PLATFORMS
(SS)
(FP)
FP
CT
COMPLIANT
TOWERS
(CT)
FPS
FLOATING TENSION LEO
PRODUCTION PLATFORMS
(TLP)
SYSTEM (FPS)
TLP
SS
1000 2000 3000 4000 5000 6000 7000
Water Depth - Feet
Skiddable
Platform Rig
Production
Facilities
Mooring
Systems
Hull
3,275”
Tendons
(Steel Pipe)
Production
Riser / Wells
1,454”
555’
Washington
Monument
1,615”
697’
One Shell
Square
Sears
tower
Bullwinkle
1,353’ WD
Anger
2,860’ WD
Direct
Tendon / Pile
Connection
Piles
Wells
Tension leg Platform
Figure 2.30 Floating Production Systems (FPS) & Tension Leg Platforms (TLPs).
pins and then raised as a unit using the rig-hoisting equipment. When the rig is needed
to move some other places, it is lowered or laid down intact and transported by truck.
he portable mast rig is supported by legs like conventional derrick and hinged at the
base (Figure 2.34). his rig is suitable for moderate-depth wells, usually is mounted on
wheeled trucks or trailers that incorporate the hoisting machinery, engines, and derrick
as a signal unit.
Beyond the above classiication, rigs can also be classiied based on:
i)
Power used
• electric - rig is connected to a power grid usually produced by its own
generators
• mechanic - rig produces power with its own (diesel) engines
Drilling Methods 55
Figure 2.31 Semisubmersible rigs.
Figure 2.32 Drillship rigs.
56
Fundamentals of Sustainable Drilling Engineering
Figure 2.33 Jack-knife mast rig.
Figure 2.34 Portable mast rig.
ii)
• hydraulic - most movements are done with hydraulic power
• pneumatic - pressured air is used to generate small scale movements
Pipe used
• cable - a cable is used to slam the bit on the rock (used for small geotechnical wells)
Drilling Methods 57
• conventional - uses drill pipes
• coil tubing - uses a giant coil of tube and a downhole drilling motor
iii) Height
• single - can drill only single drill pipes, has no vertical pipe racks (most
small drilling rigs)
• double - can store double pipe stands in the pipe rack
• triple - can store stands composed of three pipes in the pipe rack (most
large drilling rigs)
• quad - can store stands composed of four pipes in the pipe rack
iv) Method of rotation
• no rotation (most service rigs)
• rotary table - rotation is achieved by turning a square pipe (i.e. kelly) at
drill loor level.
• top-drive - rotation and circulation is done at the top of the drillstring,
on a motor that moves along the derrick.
v) Position of derrick
• conventional – derrick is vertical
• slant - derrick is at an angle (this is used to achieve deviation without an
expensive downhole motor)
2.6 Nature and Need for Sustainable Drilling Operations
According to the World Petroleum Congress, and the World Summit on sustainable
development, sustainable development can be deined as the “development that meets
the needs of the present without compromising the needs of future generations”. hen
the questions come such as: “Will the world let us produce oil and gas? Will we be
allowed to play? Can we change?” he answer yielded has been: “If we don’t, we won’t be
allowed to operate. here is no alternative. We are going into a new century of corporate
social responsibility. In order to be able to expand business, one needs to have a license
to operate, not one given by the government, but which lies in the public’s willingness
to accept us”.
he petroleum industry must pay their attention in inding solutions to environmental problems and try to get the answers of the above. Otherwise the environmental organization and summit will not allow exploring and producing in undeveloped
areas worldwide in the near future. he industry is facing external pressure to reduce
emissions of carbon dioxide and other greenhouse gases. It is also hoped to work collectively on global climate change. Recently, the concept and practice of environmental management and sustainable development have changed quickly within industrial
organizations. To some extent, this has been a reaction to public concerns and to the
obligations of increasingly stringent environmental regulations. In general, the government is gradually strengthening its environmental laws, not only in response to public
opinion, but also as a result of the Country’s obligations as a member of the United
Nations (UN).
he long-term commitment to sustainability and ethical behavior should be the core
where the industry has to stand for as an organization. In general, most of the giant
58
Fundamentals of Sustainable Drilling Engineering
oil companies are operating as global companies where they should act in a socially
responsible manner. he values start with sustainability where it is believed that any
organization will be successful when they put health and safety irst and subsequently
are environmentally responsible, and support the communities in which they should
operate for stakeholders. he overarching goal for environmental management is to
minimize, and where possible eliminate, any impact of the operations on the environment. he experts recognize that the eicient and responsible use of natural resources
is critical to the sustainability of the environment. Sustainable development should be
the core to petroleum business strategy where it needs to be integrated health, safety,
environmental, social and economic factors into the decision-making. Any sustainable
business will be successful when the industry provides lasting social, environmental
and economic beneits to society.
It is well-known fact that the oil & gas exploration pose long and short-term environmental risks. hese risks are primarily associated with (a) contamination due to drilling wastes
(muds, produced waters, byproducts, etc.); emissions from drilling sites and potential runofs, (b) natural gas/oil leaks and spills, and (c) direct efects on human health. he drilling
luids circulated through the circulating system which contains toxic materials (including
oil/grease, arsenic, chromium, cadmium, lead, mercury, & naturally occurring radioactive
materials). he composition of drilling muds and produced waters varies widely depending on location and depth of well; and type of drilling luid. Produced waters potentially
impacting the surface or groundwater are typically disposed of in a deep aquifer, but there
is still the threat of accidental release from temporary storage. Contributing to air pollution
are also the potential emissions of hydrogen sulide present in natural gas deposits. Its short
and long-term direct efect on human health could be severe, from unconsciousness to
death within a few breaths. Statistically, 0.5–1% of exploratory wells result in blowout, causing harmful emissions. Additionally, pressurized contents of a geologic formation literally
explode out of the new well, severely impacting environment and the project economics.
Some researchers present guidelines and economically feasible options to minimize risks
to environment and human health (see references). hey also provide an overview of the
environmental concerns, project economics and sustainability issues.
As a result, the current industrial trend is toward the development of sustainable
technologies, and environmentally-friendly chemicals that might be used to enhance
the drilling activities. his is due to the fact that petroleum industry is regarded as one
of the hazardous and risky industries. he current research trend is deeply involved
toward inding and developing a mud system which will satisfy both technical and
environmental requirements and thus bridging the gap between WBMs and OBMs.
2.7 Current Practice in the Industries
Most of the development and improvement in the rig equipment and component are
occurred for the ofshore drilling where the operator are moving forward to the deep
water environment. Now ofshore operations are exeeding the depth of 10,000 feet for
the water level which required the drilling contractors to follow the rapid demand for
new improvement and technology. he most important development are the rig capacity to sustain drilling and casing string while run in and pull from the hole. he other
Drilling Methods 59
Rig
Maersk Developer
Type
Semisubmersible
Design
DSS21
Year Built
Class
Station Keeping
Water Depth Cap., ft
Drilling Depth. ft
Quarters
Diamentions
Drawworks
Derrick Activity
Derrick #1 Cap.
Derrick #2 Cap.
Top Drive system
Pipe handling system
2009
ABS
Dynamic position
10,000 ft
40,000 ft
180
259 ft X 258 ft
6000 hp (main)
Dual
2500 klbs
1500 klbs
2,000 klbs (main)
2 X Hydroracker
Figure 2.35 Maersk developer semisubmersible speciication.
important development is the strong well control equipment that can work at such
harsh environment. Most of the conventional and current practices are already outlined
in the previous sections. he current trend in deveeloping rig component to suit the
above situation and what have been achieved till now are mentioned in this section.
2.7.1 Derrick and Substructure
Based on the current demand, Maersk Drilling company designed a large and most
sophisticated built-for-Purpose rig that can work in water depth up to 10,000 feet and
can drill up to 40,000 feet. he rig is dynamically positioned and povides living quarter
of 180 workers. his rig has dual derricks, 6000 hp drawworks and hydraulic pipe handling to handle the tubulars easily and safely. he derrick and drawworks are capable to
lit and run loads up to 2,000,000 pounds of tubulars which is the heaviest load recoreded currently. Figure 2.35 shows the detailded speciication.
2.7.2 Hoisting System
Due to the heaviest load in drilling operations, this load is coming from the casing
string speacially if the depth is deep. As a result, the hoisting system was based mainly
on the maximum expected casing string load. Modiications of the hoisting system that
used to support 2,000,000 pound was consist of the following:
a Casing system comprised of a 1.5 million pound casing handling seal
assembly running tool “CHSART” and dual subsea release “SSR”.
b Landing string comprised of 6 5/8 OD 0.938 wall V-150 6 5/8 FH landing string with a heavy-wall slip section “HWSS” and dual diameter tool
joints, a multi-opening diverter tool, a single joint of landing string pipe,
and pup joint.
c Top drive system consists of a 1000 MT top drive, a spacer sub, an upper
IBOP, a lower IBOP, and a saver sub.
60
Fundamentals of Sustainable Drilling Engineering
• 1,000 ton Hydraulically Actuated
Slip Assembly
• 1,000 ton Hydraulically Actuated
Elevator
Figure 2.36 Slip and elevator systems.
Reduced tool joint diameter for
reduced make-up torque
requirements
Extended length, thicker wall slip section for
increased slip crushing capacity
Internal and external upset (IEU)
Double
diameter box
tool joint
Tungsten carbide free
hardbanding to protect
riser/casing
Increased elevator
diameter for increased
hoisting requirements
High strength grade
tube of reduced wall
thickness
Pin wall thickness to provide
connection tensile capacity
Figure 2.37 6-5/8 OD 0.9338 Wall Slip-Proof® landing string.
On top of the above, the hoisting system and casing handling equipment also included
1000 ton hydraulic actuated elevators, 1000 ton hydraulic actuated slips, and bails
(Figure 2.36). In addition, special drill pipes were manufactured to withstand these
heavy loads (Figure 2.37). he speciications for the tubulars consist of the following:
a) Pipe body of higest speciied minimum yield strength (SMYS) of 150 ksi and even
165 ksi grades which can be produced with minimum toughnes greater than API S-135,
b) heavy wall slip section to protec the pipe from crushing efect when suspend the
string at the rotary. c) Dual tool joint to provide a sacriicial wear pad for the installation of casing-friendly hardband material. his speciications is mainly to maximize the
fatigue resistance, torsional balance and the elevator capacity. d) Extra long tool joints
with extended tong space which provide additional repair or rethreading. e) internal
plastic coating which mitigates corrosion of internal pipe from drilling luid and will
also facilitate reduced friction low. In addition, the top drive system that has an upper
& lower IBPO, and saver sub is manufactured. his hoisting and handling TDS can
handle up to one thousand tons (Figure 2.38).
Drilling Methods 61
Traveling
Block
Becket
Integrated Swivel
Running and building stan
• Run singles
• Run stands
Top Drive
• Build stands and run single
Pipe Handler
Figure 2.38 Travelling block and Top drive section components.
2.7.3 Pressure Control System
Due to widening the ofshore drilling operations to reach 10,000 t deep water environment, the need to have an eicient and strong pressure control equipment (PCE)
became a reality. he irst 10,000 t deep PCE was deployed in Brazil in 2004 with
a surface activation equipment. he system consits of surface BOP, a 13 3/8” casing
riser and subsea disconnecting system “SDS”. he surface BOP is connected to the
riser tensioner system which transmits the riser tension to the BOP stack. Riser
tensioner rods are coupled to a split load ring via 6 shakles. An anti-recoil system
is also incorporated with shut-of valves on each cylinder. his enabled the surface
BOP and the 13 3/8 riser load to be landed into the existing rig tension ring by the
insertion of a simple adapter. he SDS consists of 5 pipe rams and shear ram. In this
respect, the SDS gives shear and disconnect functionality equivelent to a ive cavity
conventional subsea BOP stack. he system has a stand-alone control system connected subsea equipment and surface BOP to the surface accumulated banks.
2.8 Future Trend in Drilling Methods
here are lots of components that can be further developed and improved to insure
achieving the drilling goals. As drilling is going deeper and deeper, the need for the
powerful rig in terms of hoisting system is required to support the heaviest loads of the
tubulars. Also the hydraulic circulating system needs to be iproved to meet the required
circulating parameters. As the operators are now focusing on deep seas, the subsea
equipment also needs to be modiied to suit the new water depths.
Currently the manufacturers are looking to use a strong drill pipes but at the same
time lighter weight such as titanium drill pipe. Titaium drill pipes are proved to decrease
the hook load by 40% as compared with the steel drill pipes using drilling program simulator. his type of drill pipe will be very helpful for the extended reach drilling operations where the well TMD is large. Another future development is reelwell drilling
62
Fundamentals of Sustainable Drilling Engineering
methods (RDM) which can solve a lot of cleaning and weight-on bit control for coiled
tubing drilling applications. his methods consists of two concentric tubular string,
rotating control device (RCD) and dual loat valve. he annular of the outer string is
used to pump the mud down the well while the inner string is used to pump the mud
with cuttings out the well. By doing this, the well annulus will be isolated. In general,
solving a lot of hydraulic problems while drilling will also be a challenge. It may also
be a challenge to have the automation of all drilling operations. Currently there are lots
of rigs that have automation in most of their operating system that can ease the drilling. But the future envelope for development is still open for more active research and
development.
2.9 Summary
his chapter discusses the all aspects related to drilling rig and its components. he
diferent drilling rig systems are explained in addition to classiications of rig. he different components or devices names with complete igures are shown in this chapter.
he pump rating, capacity and design of pumps are also stated here.
2.10 Nomenclature
d
dl
d pr
Hf
Ls
Madv
n
= distance travel by the weight on pulley, t
= liner diameter, inch
= piston diameter, inch
= heating value of fuel used in the engine, Btu / lbm
= stroke length, inch
= mechanical advantage
= number of lines strung through the travelling block
N
= number of pump cycle i.e. revolutions per minute of crank,
piston strokes / min
rpm =
4
= number of drilling lines through the travelling block
= discharge pressure, psig
= pump horse power, hp
= input power of the block and tackle, hp
= output power of the block and tackle, hp
= Shat power developed by an IC engine, hp
= output power for the duplex pump, hp
= low rate, gal/min
= power input to the IC engine, hp
= Radius of ly wheel, t
= Output torque, ft lb f
= time required to travel the distance, d, min
n
Pd
Php
Pibt
Poutbt
Ps
Pout p
q
Qi
rFW
T
t
Drilling Methods 63
Tf
Td
V
= tension (i.e. load) in the fast line, lb f
= tension (i.e. load) in the dead line, lb f
= wind velocity, mph
VB1
= volumetric displacement of liquid for a backward stroke with one piston,
in3
stroke
= velocity of the traveling block, ft /min
= volumetric displacement of liquid for a forward stroke with one piston,
in3
stroke
= velocity vector, t/min
= velocity of the fast line, ft / min
= Weight on pulley, lb f
= the rate of fuel consumption by the engine, lbm / min
= wind load, lb f / ft 2
= total compressive load on the derrick, lb f
= hook load, lb f
= work done per piston stroke, lb f ft
= work done per complete stroke, lb f ft
= increase in pressure, psi, which cannot be more than 3,500 psi.
= Angular velocity of the shat, rad/min
= mechanical eiciency of the duplex pump, %
= Overall engine eiciency of the power system
vbt
VF 1
v
vf
W
wf
Ww
WD
Whl
WP
WPN
p
mp
ps
2.11 Exercise
E2.1: A diesel engine gives an output torque of 1,740 t-lbf at an engine speed of 1,200
rpm. If the fuel consumption rate was 31.5 gal/hr, what is the output power and overall
eiciency of the engine? Ans. 397.5 hp; 23.4%
E2.2: An internal combustion engine is run by diesel fuel which gives an output
torque of 1,300 ft lb f at an engine speed of 1,000 rpm. he engine consumes fuel at a
rate of 25 gal/hr. Calculate the wheel angular velocity, power output, overall eiciency
of the IC engine. Ans.
E2.3: A diesel engine runs at a speed of 1,100 rpm and its engine power output 300
hp. If the system uses frictionless pulley, the drawworks can handle to lower a drillstring of 500,000 lb f . he drilling operations engine was continuing for three days.
Calculate the wheel angular velocity, torque developed by the engine, the drillstring
velocity, distance travel by the drillstring, power input, and overall eiciency of the
engine. Ans.
E2.4: For a series of engine operations, the following data were obtained. he fuel
used for running the engine was gasoline. Compute power output or break horsepower,
overall engine eiciency for each engine speed, fuel consumptions in gal/day for 1,000
rpm and 850 rpm considering 8 hrs a day. Ans.
64
Fundamentals of Sustainable Drilling Engineering
Engine speed (rpm)
Torque ft - lbf
Fuel consumption (gal/hr)
1,350
1,500
27.0
1,150
1,650
20.0
1,000
1,700
18.0
850
1,750
15.5
700
1,800
13.0
E2.5: A drilling rig has a hook load of 300,000 lbf , which has eight number of drilling lines. A wind velocity of 100 mph is felt by the derrick. he rig has ten lines which
are strung through the travelling block. A hook load of is being hoisted. According to
the API standard, calculate the wind load and total compressive load. Assume that the
block and tackle has the frictionless pulley. Ans.
E2.6: he total weight of 8,000 t of 9 5/8-inch casing for a deep well is determined to
be 344,000 lbs. Since this will be the heaviest casing string run, the maximum derrick load
must be calculated. Assuming that 12 lines run between the block and tackle and neglecting buoyancy efects and friction, calculate the maximum derrick load. Also calculate each
derrick leg load. Ans.
E2.7: he total casing weight is determined 440,000 lbf for a 11,000 t of 8 5/8-inch
casing during a deep well casing operation. Assume that 14 lines are run with the hoisting system. As this casing string operation is the heaviest run, the maximum derrick
load is needed to be calculated. Assume that there is a friction loss with the hoisting
system and neglecting buoyancy efect, calculate the maximum derrick load. Also calculate each derrick leg load. Ans.
E2.8: he hoisting system of a rig derrick has a load of 440,000 lb f . he input power
of the drawworks for the rig can be a maximum of 560 hp. Fourteen drilling lines
are strung between the crown block and traveling block. Assume that the rig loor is
arranged as shown in Fig. 2.9. Consider there is some loss of power due to friction
within the hoisting system. Compute (1) the static tension in the fast line when upward
motion is impending (2) the mechanical advantage of the block and tackle (3) the maximum hook horsepower available (4) the maximum hoisting speed (5) if a 60 t stand
would require to pull, what should be required time (6) the actual derrick load (7) the
maximum equivalent derrick load (8) the derrick eiciency factor.
E2.9: Calculate the liner size required for a triplex pump where rod diameter is 2.0
in, stroke length is 20 in stroke, pump speed is 80 strokes/min. In addition the maximum available pump hydraulic horsepower is 1000 hp and the delivery pressure is
3,000 psi. Assume the volumetric eiciency of pump is 98%.
E2.10: Calculate the liner size required for a double-acting duplex pump where rod
diameter is 2.2 in, stroke length is 24 in stroke, pump speed is 75 strokes/min. In addition the maximum available pump hydraulic horsepower is 1300 hp. For optimum
hydraulics, the pump recommended delivery pressure is 2,500 psi. Use the formula for
calculating the volumetric eiciency of pump.
Drilling Methods 65
APPENDIX 2A
1. Shale shakers
2. Choke manifold
3. Pipe ramp
4. Catwalk
5. Pipe rack
6. Pipe on rack
7. Crown block assembly
8. Catline boom and hoist line
9. Drilling line
10. Monkey board
11. Travelling block
12. Top drive (power swivel)
13. Mast
14. Drill pipe
15. Doghouse
16. Blowout preventer control unit (Accumulator)
17. Water tank
18. Electric cable tray
19. Engine-generator set
20. Fuel tank
21. Electrical control (SCR house)
22. Mud pumps
23. Bulk mud component tanks (P-tanks)
24. Mud tanks (Pits)
25. Reserve pits
26. Mud-gas separator
RIG FLOOR (CONVENTIONAL ROTARY RIG)
27. Hook
28. Swivel
29. Kelly
30. Rotary table assembly
31. Drawworks
32. Standpipe
33. Rotary (Kelly) hose
RIG FLOOR (TOP DRIVE)
34. Driller’s console
35. Iron roughneck
66
Fundamentals of Sustainable Drilling Engineering
36. Tongs
37. Slips
38. Air hoist
BLOWOUT PREVENTER STACK AND WELLHEAD
39. Annular blowout preventer
40. Ram blowout preventer
41. Substructure
42. Cellar
43. Conductor casing
44. Drill string
45. Bit
DRILLING FLUID EQUIPMENT
46. Degasser
47. Desander
48. Desilter
49. Centrifugal pumps
50. Mud agitators
Accumulator is a storage device for nitrogen pressurized hydraulic luid, which is used
in operating the blowout preventers.
Air hoist is a hoisting device of a liting tackle which is constructed by a cylinder,
piston, and piston-rod for a reciprocating motion. It is operated by compressed air to
complete the heavy duty works in the rig site.
Annulus is the space around a pipe in a well bore between the outer wall of the drill
pipe and the wall of either the bore hole or the casing. It is also called as annular space.
Blowout preventer control unit (Accumulator) is a large valve usually installed
above the ram preventers. It forms a seal in the annular space between the pipe and well
bore. If there is no pipe existence, it is installed on the wellbore itself.
Bulk mud component tanks (P-tanks) are hopper type tanks for storage of drilling
luid components.
he BHA is made up of a drill bit, drill collar and stabilizer.
A blowout preventer (BOP) is a large valve installed at the wellhead to control the
rig pressures in the annular space between the casing and drill pipe during drilling,
cementing and completions. It is also called an annular blowout preventer. Ram-type
preventers have interchangeable ram blocks to accommodate diferent O.D. drill pipe,
casing, or tubing.
Cellar is a pit in the ground to provide additional height between the rig loor and
the well head. he space allows to install the blowout preventers, ratholes, mouseholes,
and so forth. It also collects drainage water and other luids for disposal.
Catwalk is a ramp at the side of the drilling rig where pipe is laid to be lited to the
derrick loor by the catline or by an air hoist.
Drilling Methods 67
Crown block assembly is a stationary steel beam joined to the top of the derrick
posts of an oil well to support the pulleys or sheaves through which the drill line (i.e.
wire rope) passes. It helps to raise and lower the drill string, bottomhole assembly, etc.
(item 1 of Figure 2.3).
Catline boom and hoist line is a structural framework upright near the top of the
derrick for liting material.
Choke manifold is an arrangement of piping and special valves which is called
chokes. Drilling mud is circulated through this arrangement when the blowout preventers are closed. Choke manifold is used to control the pressures encountered during a
kick.
Conductor casing is the irst casing needed to be run in a well. his is done ater
spudding-in so a blowout preventer can be installed before drilling is started. It is
the largest diameter casing and the topmost length of casing. It is relatively short and
encases the topmost string of casing.
Drill string is an assembly (i.e. column or string) of drill pipe, drill bit, drill collars
that transmits drilling mud and give the rotational power to the drill bit. he drill string
is hollow so that drilling luid can be pumped down through it and can be circulated
back through the annulus. he drill string is typically made up of four sections such as
bottom hole assembly (BHA), transition pipe (i.e. heavyweight drill pipe), drill pipe and
drill stem subs. Each section of drill string is made up of several components. hey are
joined together using special threaded connections known as tool joints.
Drilling mud agitator is an equipment for oilield drilling mud tanks and is usually driven by electric power. It is used to agitate drilling mud in the mud tanks and is
widely used in oilield mud puriication system.
Drill stem subs are used to connect drill string elements.
Degasser is an equipment used to remove unwanted gas from drilling luid.
Desander is a centrifugal device used in drilling rig to remove sand from drilling
luid. his action prevents pump abrasion. It may be operated mechanically or by a fastmoving stream of luid inside a special cone-shaped vessel, in which case it is sometimes called a hydrocyclone.
Desilter is a centrifugal device, similar to a desander, used to remove very ine particles, or silt, from drilling luid. his keeps the amount of solids in the luid to the lowest possible level.
Drill bit is the cutting or boring element used to break up the rock formation in
drilling oil and gas wells. Most bits used in rotary drilling are roller-cone bits. he bit
consists of the cutting elements and the circulating element. he circulating element
permits the passage of drilling luid and uses the hydraulic force of the luid stream to
improve drilling rates.
Drill collar is a heavy, thick-walled tubular usually made up of steel. It is used to
apply weight to the drill bit so that the bit can drill the rock formation. It places between
the drill pipe and the bit in the drill stem.
Drill pipe is heavy seamless tubing used to rotate the drill bit and through which
drilling luid is circulated. hirty feet long drill pipes are coupled together with tool
joints. he Purpose of the drill pipe is to rotate the bit and provide downward passage
for drilling luid.
68
Fundamentals of Sustainable Drilling Engineering
Figure 2.3 A modern rotary drilling rig and its components.
Drawworks or hoist is the key piece of equipment and is the hoisting mechanism
on a rotary drilling rig. It is essentially a large winch that spools of or takes in the
drilling line and thus raises or lowers the drill stem and bit. he principal parts of the
drawworks are the drum, breaks, transmission, and clutches. It has also some other
parts such as chains, sprockets, engine throttles, and other controls which enable the rig
power to be diverted to the particular operation at hand.
Driller’s console is the control panel, located on the platform, where the driller controls drilling operations.
Doghouse is a small enclosed space (room) on the rig loor used as an oice for the
driller or as a storehouse for small objects.
Drilling line is a wire rope hoisting line, reeved on sheaves of the crown block and
traveling block (in efect a block and tackle). he functions of drilling line are to hoist or
lower drill pipe or casing from or into a well. It is also used to support the drilling tools.
Electric cable tray is a steel structure which supports the heavy electrical cables.
his cable supplies the power from the control panel to the rig motors.
Engine-generator set produces power for the drilling rig. It has an engine driven by
diesel, Liqueied Petroleum Gas (LPG), natural gas, or gasoline along with a mechanical
transmission and generator.
Electrical control (SCR house) is a panel that controls the power supply. In the rig
site, the generator produces electricity that lows through cables to electric switches and
control equipment enclosed in a control cabinet or panel.
Fuel tanks are used to store fuel for the power generating system.
Drilling Methods 69
Hook is a large, hook-shaped device from which the elevator bails or the swivel is
suspended. It is designed to carry maximum loads ranging from 100 to 650 tons and
turns on bearings in its supporting housing.
Iron roughneck is a mechanical device that is used to make and break the connections. his machine can be easily set away when it is not in use. Its mobility allows
it to carry out mousehole connections when the roads are correctly positioned. he
device consists of a spinning wrench and torque wrench which are both hydraulically
operated. he advantages of this device include controlled torque, minimal damage to
threads (thereby increasing the service life of drill pipe) and reducing crew fatigue.
Kelly is the heavy square or hexagonal steel member suspended from the swivel
through the rotary table. It is the irst section of a heavy steel pipe below the Swivel, normally about 40’ long, with an outside hexagonal cross section. It is suspended from the
swivel. It is connected to the topmost joint of drill pipe to turn the drill stem as the rotary
table turns. It must have this hexagonal (or sometimes square) shape to transmit rotation from the rotary table to the drillstring. he kelly has the right hand thread connection on the lower [pin] end, and a let hand thread connection on the upper [box] end.
Kelly-saver-sub is a short connection between the kelly and the irst joint of drillpipe. his inexpensive short section of pipe is used to prevent wear on the kelly threads.
It can be easily replaced.
Kelly cocks are valves installed at either end of the kelly to isolate high pressures and
prevent backlow from the well. he purpose of the Kelly is to transmit torque through
kelly bushings.
Monkey board is a platform where derrickman works. It is located at a height in the
derrick equal to two, three or four lengths of drill pipe respectively.
Mast is a portable derrick capable of being vertical as a unit. It is notable from a standard derrick, which cannot be raised to a working position as a unit.
Mud pumps are the large reciprocating pumps used to circulate the mud (drilling
luid) on a pumps drilling rig.
Mud tanks (Pits) are a series of open tanks, usually made of steel plates, through
which the drilling mud is cycled to allow sand and sediments to settle out. Additives
are mixed with the mud in the pit, and the luid is temporarily stored there before being
pumped back into the well. Mud pit compartments are also called shaker pits, settling
pits, and suction pits, depending on their main purpose.
Mousehole is a shallow bore under the rig loor. It is usually wrinkled with pipe in
which joints of drill pipe are temporarily suspended for later connection to the drill
string.
Mud pump is a large reciprocating pump used to circulate the mud (drilling luid)
on a drilling rig.
Mud-gas separator is a device that removes gas from the mud coming out of a well
when a kick is being circulated out.
Pipe ramp is an angled ramp for dragging drill pipe up to the drilling platform or
bringing pipe down of the drill platform.
Pipe rack is a horizontal support where drill pipes are stacked.
Reserve pit is a mud pit in which a supply of drilling luid is stored. It is also called
waste pit, usually an excavated, earthen-walled pit. It may be lined with plastic to prevent soil contamination.
70
Fundamentals of Sustainable Drilling Engineering
Rotary table assembly is the principal component of a rotary or rotary machine. It
is used to turn the drill stem and support the drilling assembly. It has a beveled gear
arrangement to create the rotational motion and an opening into which bushings are
itted to drive and support the drilling assembly. he purpose of the rotary drive is to
provide the power to turn the rotary table and power sub can be used to connect casing.
Rotary table is located on the drill loor and can be turned in both clockwise and
anti-clockwise directions, controlled from the driller’s console. he rotating top has a
square recess into which its the master bushing having a circular recess into which its
the Kelly bushing. he Kelly bushing has four pins to it into the rotary table. When the
rotary is engaged, the torque is transmitted from the rotating table on the Kelly via the
Kelly bushing.
Rotary hose is the hose on a rotary drilling rig that conducts the drilling luid from
the mud pump and standpipe to the swivel and Kelly. It is also called the mud hose or
the kelly hose.
Rathole is a hole in the rig loor 30 to 35 feet deep, lined with casing that projects above the loor. he kelly is placed in the rathole when hoisting operations are in
progress.
Shale shaker is a series of trays with sieves or screens. he vibrating motion of the
shale shaker helps to remove cuttings from drilling mud. Sieve size of the tray is selected
based on formation cuttings.
Swivel is a mechanical device that suspends the weight of the drill pipe, provides for
the rotation of the drill pipe beneath it while keeping the upper portion stationary, and
permits the low of drilling mud from the standpipe without leaking. It is a tool that is
hung from the rotary hook to suspend and permit free rotation of the drill stem. Swivel
also provides a connection for the hose and a passage for the low of drilling luid into
the drill stem. he bail of the swivel is attached to the hook of the travelling block, and
the gooseneck of the swivel provides a connection for the kelly hose.
Standpipe is a vertical pipe rising along the side of the derrick or mast. It joins the
discharge line leading from the mud pump to the rotary hose and through which mud
is pumped going into the hole.
Slips are a pipe gripping devices, with wedge-shaped pieces of metal with teeth or
other gripping elements. hese are used to prevent drill string from slipping down into
the hole or to hold pipe in place. heir purpose is to prevent the drill string from falling down in the well and provide link to hang drill string from the rotary table. Rotary
slips it around the drill pipe and wedge against the master bushing to support the pipe.
Power slips are pneumatically or hydraulically actuated devices that allow the crew to
dispense with the manual handling of slips when making a connection. Packers and
other down hole equipment are secured in position by slips that engage the pipe by
action directed at the surface.
Stabilizer is a device which keeps the drilling assembly centered in the hole.
Substructure is the foundation on which the derrick or mast and usually the drawworks sit. It has space for storage and well control equipment.
Travelling block is an arrangement of pulleys or sheaves through which drilling
cable is reeved. It moves up and/or down in the derrick or mast.
Top drive (power swivel) rotates the drill bit without the use of a kelly and rotary
table. he top drive is operated from a control console on the rig loor.
Drilling Methods 71
Transition pipe is the heavyweight drill pipe (HWDP) normally used to make the
transition between the drill collars and drill pipe. he function of the HWDP is to provide a lexible transition between the drill collars and the drill pipe. his helps to reduce
the number of fatigue failures seen directly above the BHA. HWDP is also used to add
additional weight to the drill bit. Drill pipe makes up the majority of a drill string.
Tongs are the large wrenches used for turning when making up or breaking out
drill pipe, casing, tubing, or other pipe; variously called casing tongs, rotary tongs, and
so forth according to the speciic use. Power tongs are pneumatically or hydraulically
operated tools that spin the pipe up and, in some instances, apply the inal makeup
torque.
Water tank is a container used to store water. his water is used for mixing mud,
cement and cleaning the rig.
References
J.N. Brock, R. Brett Chandler, NOV Grant Pridco; C. Maersk Drilling USA; J. Dugas, W.
White, Quail Tools; M. Vasquez, A. Johnalagadda, Statoil. Innovative Tubular, Hoisting, and
Deepwater Rig Design Extend Hook Load Envelope to 2,000,000 Pounds. Paper IADC/SPE
151140 presented in San Diego, California, USA, 6–8 March 2012.
R. Brett Chandler, SPE/IADC, Grant Pridco; Michael J. Jellison, SPE/IADC, Grant pridco;
Michael L. Payne, SPE, BP America; Jef S. Shepard, IADC, GlobalSantaFe. Performance
Driven Drilling Tubular Technologies. Paper SPE/IADC 79872 presented in Amsterdam, he
Netherlands, 19–21 Feb 2003.
T.S Burns, R&B Falcon Corporation, and W.T Bennett, Bennett & Associates LLC. Rapid
Evolution of Ultra-Deep Water Drilling Rig Designs. Paper OTC 8749 presented on Ofshore
Technology Conference in Houston, Texas, USA, 4–7 May 1998.
Jackie E. Smith, SPE, Grant Prideco; R. Brett Chandler, SPE, Grant Prideco; Patric L. Boster,
SPE, RTI Energy Systems. Titanium Drill Pipe for ultra-Deep Directional Drilling. SPE/
IADC 67722 paper presented at the drilling conference held in Amsterdam, he Netherlands,
27th Feb–1st Mar 2001.
Graham Brunt; Stena Drilling, Scott Elson, Nautronix, Tim Newman; Shell international E.P.
Inc., Paul Toudouze; Cameron project management. Surface BOP: Equipment Development
for Extending the Water Depth Capability of a D.P. Semisubmersible to 10,000 t and beyond.
SPE/IADC 87109 paper presented at the drilling conference held in Dallas, Texas, 2–4 March
2004.
M.D. Dunn, Phoenix Alaska Technology; P.J. Archey, BP; E.A. opstad, Phoenix Alaska
Technology; M.E. Miller, BP; T. Otake, NI Energy Development Inc. (Subsidary of Nisso
Iwai). Design, Speciication, and Construction of a Light, Automated Drilling System (LADS).
SPE/IADC 74451 paper presented at the drilling conference in Dallas, Texas, 26–28 Feb 2002.
P. Girde, Maharashtra Inst. Of Technology. Advanced Drilling using a Spiral Kelly. SPE 99284
STU (Student3) paper presented at the international student paper context in Dallas, Texas,
9–12 Oct 2005.
M. Mir Rajibi, SPE, A.I. Nergard, SPE, University of Stavanger; O. Hole, SPE,
O. M. Vestavik, SPE, Reelwell AS. A New Riserless Method Enable Us to Apply Managed
pressure Drilling in Deepwater Environment. SPE/IADC 125556 paper presented at the
Drilling technology Conference in Manama, Bahrain, 26–28 Oct 2009.
72
Fundamentals of Sustainable Drilling Engineering
Zengxuan Yan, Hongwei Xu, Guanghui Liu, Qinghong Li, Jianhong Wang, Xianping Ma, Feng
Zhao, Qingyu Li, Shinguan Yang and Lin Sun, Qinghai Drilling Company of CNPC Xibo
Drilling Engineering Company Limited. Design and Application of 735 hp (4000m) Plateau
Mountain Rig. SPE/IADC 155886 paper presented at the Asia Paciic Drilling conference in
Tianjin, China, 9–11 July 2012. http://homepage.ntlworld.com/leslie.foster/drilling_history.
htm, accessed on November, 18, 2009
Oil tools: http://www.welong-oiltools.com/technical/29.htm, accessed on November 19, 2009.
http://www.osha.gov/SLTC/etools/oilandgas/drilling/maintenance_activities.html#mud_circulating_system, accessed on January 23, 2010
Brighenti, G., Macini, P. and Mesini, E. Environment and Sustainable Management of Oil
and Gas Reservoirs in Italy, SPE 80608-MS, SPE/EPA/DOE Exploration and Production
Environmental Conference, 10–12 March 2003, San Antonio, Texas, USA.
Rana, S. Facts and Data On Environmental Risks - Oil & Gas Drilling Operations. SPE 114993MS. SPE Asia Paciic Oil and Gas Conference and Exhibition, 20–22 October 2008, Perth,
Australia.
Arthur, J.D., Coughlin, B.J. and Bohm, B.K. Summary of Environmental Issues, Mitigation
Strategies, and Regulatory Challenges Associated With Shale Gas Development in the United
States and Applicability to Development and Operations in Canada. SPE 138977-MS, presented at the Canadian Unconventional Resources and International Petroleum Conference,
19–21 October 2010, Calgary, Alberta, Canada.
Rana, M.S., Environmental Risks - Oil & Gas Operations Compliance and Cost Control Using
Smart Technology. SPE 121595-MS. Asia Paciic Health, Safety, Security and Environment
Conference, 4–6 August 2009, Jakarta, Indonesia.
Al-Majed, A.A., Adebayo, A.R. and Hossain, M.E., “A Novel Sustainable Oil Spill Control
Technology”, Environmental Engineering and Management Journal, accepted for publication on May 16, 2012, Tracking No. 201_Aziz_11, (2012), in press.
Hossain, M.E. and Apaleke, A.S., “An Overview of Mud Technology and Challenges Toward
Greening of Drilling Fluid”, Environmental Engineering and Management Journal, accepted
for publication on November 19, 2012, Tracking No. 314_Hossain_11, (2012), in press.
Apaleke, A.S., Al-Majed, A. and Hossain, M.E., “Drilling Fluid: State of the Art and Future
Trend”, Paper ID: SPE- 149555, presented at 2012 SPE North Africa Technology Conference
and Exhibition (NATC), 20–22 February 2012 in Cairo, Egypt, 2012.
Apaleke, A.S., Al-Majed, A. and Hossain, M.E., “State of the Art and Future Trend of Drilling
Fluid: An Experimental Study”, Paper ID: SPE- 153676, presented at the 2012 SPE Latin
America and Caribbean Petroleum Engineering Conference, 16–18 April 2012 in Mexico
City, Mexico, 2012.
3
Drilling Fluids
3.1 Introduction
Drilling luid (also called drilling mud) is an essential part of the rotary drilling system.
Most of the problems encountered during the drilling of a well are directly or indirectly related to the mud. he successful completions of a hydrocarbon well and its cost
depend on the properties of the drilling luid to some extent. he cost of the drilling
mud itself is not very high. However, the cost increases abruptly for the right choice,
and to keep the proper quantity and quality of luid during the drilling operations.
he correct selection, properties and quality of mud is directly related to some of the
most common drilling problems such as rate of penetration, caving shales, stuck pipe
and loss circulation etc. In addition, the mud afects the formation evaluation and the
subsequent eiciency of the well. More importantly, some toxic materials are used to
improve the particular quality of the drilling luid, which is a major concern of the environmentalist. his addition of toxic materials contaminates the underground system as
well as the surface of the earth.
herefore, the selection of a suitable drilling luid and routine control of its properties
are the concern of the drilling operations related individuals. he drilling and production
personnel do not need a detailed knowledge of drilling luids, but they should understand
the basic principles governing their behavior, and the relation of these principles to drilling and production performance. hey should have a clear vision about the objectives of
any mud program, which are: 1) to allow the target depth to be reached, 2) minimize well
73
74
Fundamentals of Sustainable Drilling Engineering
costs, 3) maximize production from the pay zone. In mud program, factors that need to
be considered are the location of well, expected lithology, equipment required, and mud
properties. Hence, this chapter deals with the basic components of mud, its functions,
diferent measuring techniques, mud design and calculations, the updated knowledge in
the development of drilling luid and future trend of the drilling luid.
3.2 Drilling Fluid Circulating System
In rotary drilling process, luid circulation system plays a vital role where drilling luid
is very important as a major part. In reality, without circulating the drilling luid, no
one could successfully drill most wells with the rotary method. What’s more, the success or failure of the mud program can largely determine whether the drilling contractor can drill the well to the operator’s speciications in a safe and economical way.
Diferent parts of rig are involved to complete the luid low channel. Figure 3.1
shows a complete lowchart of diferent components that are involved with circulating
system. he mud, water and other necessary chemicals, and solids are mixed through
the mud-mixing tank. hen mud goes to the fresh mud pit from where it is pumped to
the bottomhole assembly. Mud passes through the standpipe, hose and swivel, kelly and
then the drill pipe, drill collar to drilling bit. On the return, mud with cuttings passes
through the annulus, BOP, channel, shale shaker, desander to desilter to again at the
mud pit in surface. he use of mud during the drilling operations is very crucial. As a
result, water was used as the irst drilling luid in France in 1845. he purpose of this
use was to bring the cuttings from the borehole to the surface. However, the diverse
applications of drilling luid make it prime requirement for the rotary drilling. he
primary functions of the drilling luid are to:
i.
i.
ii.
iii.
iv.
v.
vi.
vii.
Remove and transport cuttings from bottom of the hole to the surface
through the annulus (i.e. clean the borehole from cuttings and removal
of cuttings).
Exert suicient hydrostatic pressures to reduce the probability of having
a kick (i.e. control of formation pressure)
Cool and lubricate the rotating drill string and drilling bit
Transmit hydraulic horsepower to the bit
Form a thin, low permeable ilter cake to seal and maintain the walls of
the borehole and prevent formation damage (i.e. seal the thief zones)
Suspend drill cuttings in the event of rig shutdown so that the cuttings do
not fall to the bottom of hole and stick the drill pipe
Support the wall of the borehole
Maintain wellbore stability (i.e. keep new borehole open until cased)
In addition to the above functions, there are some other secondary functions such
as suspending the cuttings in the hole and dropping them in surface disposal areas,
improving sample recovery, controlling formation pressures, minimizing drilling luid
losses into the formation, protecting the soil strata of interest (i.e. should not damage
formation), facilitating the freedom of movement of the drill string and casing, and
Drilling Fluids 75
BULK
STORAGE
Mud
Details of Mud Mixing System
Clay & other
solid additives
Water
Mixing Hopper
Channel
Shale
Shaker
BOP
Standpipe
Hose &
Swivel
Annulus
Kelly
Drill Pipe
Degasser
Mud
Pump
Bit
Desander
Mud
Mixing
Mud
Pit
Desilter
Figure 3.1 A block diagram for drilling luid circulating system.
Swivel
p
Mud Pum
Drill Pipe
Mud Tank/Pit
(Suction)
Cuttings
Drill Stem
Drill Collar
Rotary Hose
Mud Tank/Pit
(Settling)
Reserve Pit
Kelly
Annulus
BIT
Figure 3.2 Diferent functions of drilling luid.
reducing wear and corrosion of the drilling equipment, and provide logging medium. It
is noted that the follwing side efects must be minimized to achieve the above functions.
i.
i.
ii.
iii.
Damage to subsurface formation, especially those that may be productive
Loss of circulation
Wash and circulation pressure problems
Reduction of penetration rate
76
Fundamentals of Sustainable Drilling Engineering
iv.
v.
vi.
vii.
viii.
Swelling of the sidewalls of the borehole creating tight spots and/or hole
swelling shut
Erosion of the borehole
Attaching of the drill pipe against the walls of the hole
Retention of undesirable solids in the drilling luid
Wear on the pump parts
Figure 3.1 depicts some of the functions of drilling luid with a complete circle of the
mud circulating system.
3.3 Classiication of Drilling Fluids
Drilling luids are generally classiied according to their base composition. It may be
broadly classiied as liquid, gases, and liquid-gas mixtures. Although pure gas or gasliquid mixtures are used, they are not as common as the liquid based systems. A detailed
classiication of drilling mud is shown in Figure 3.3. Drilling luids can also be broadly
categorized as compressed air, foam, clear water, water-based mud and oil-in-water
emulsion or oil-based mud. In addition to the above, additives must oten be added to
these luids to overcome speciic downhole problems. A freshwater or saltwater based
drilling luid with additives is commonly called drilling mud. Based on some speciic
requirements and functions, some special types of drilling luids are made which will
be discussed as a separate subsection below.
Air and water generally satisfy the primary functions of a drilling luid. In addition,
chemical additives are used for speciic purposes. he main factors that govern the
selection of drilling luids are 1) formation type to be drilled, 2) the range of formation
data i.e. pressure, temperature, permeability, saturation and strength, 3) the formation
evaluation procedure used, 4) the water quality available i.e. fresh or saline water and 5)
ecological and environmental considerations i.e. sustainability analysis. However, the
drilling luid that yields the lowest drilling cost in an area must be determined by trial
and error. he following sections describe the diferent drilling luids in detail.
Liquids
Gases
Liquid & Gases Mixtures
Water base
Fresh water
Oil base mud
Inhibited
Low Solids
Foam mostly
Full Oil
Aerated Water
Invert Emulsions
less than 5%
5 - 50% Water Content
Water content
Figure 3.3 Classiication of diferent drilling luids.
Air
Natural Gas
Pseudo oil-based mud
Drilling Fluids 77
3.3.1
Water-based Mud
Water is the most common luid. When the solids are entrained in the water it makes
it a natural mud. Water-based mud (WBM) is deined as a drilling mud in which the
continuous phase is water. WBM is the most commonly used drilling luids worldwide;
although in the North Sea oil based muds are the most widely used type of mud. WBM
are those drilling luids in which the continuous phase of the system is water. WBM has
some advantages: 1) Some clays hydrate readily in water and due to clay hydrating in
water, the viscosity of the mud greatly increases, which helps carry the rock cuttings to
the surface 2) clay particles form mud cake which reduces water loss (less lost circulation), and prevents the wall from caving into the hole (by forming a mud cake i.e. less
formation damage, and 3) less mud cost (mud cost = 10% of well cost). However, there
are some disadvantages as well: 1) reduction in penetration rate 2) increase in pressure
loss due to friction. In small holes, the disadvantages may be more than the advantages.
herefore, equipment to remove inely divided solids must be used to prevent the formation of natural clays. here are two types of water, saltwater and freshwater, that are
used as base compositions for WBM. A freshwater mud is one in which the continuous
liquid phase of the system is freshwater.
Saltwater drilling luids are prepared from brine water, seawater and dry sodium
chloride or other salts such as potassium chloride. hese luids have a chloride content
of 6,000 mg/lt to less than 189,000 mg/lt. he commonly used products are attapulgite, PAC, CMC and starch to increase viscosity and FCLS, caustic lignite to control gel
strength and iltrate loss. An inhibited mud is a mud with salt or calcium to reduce
active clays hydration. An inhibited mud is one where the reactivity of the water phase
within the mud system with active clays within the formation is greatly reduced.
he distinction between fresh-water and inhibited muds is based on salt concentration. Inhibited muds are used when a problem arises during drilling with fresh mud
(sloughing clays). Freshwater muds are those having less than 3000 ppm Na+ ions. It is
used to drill shale and clay formations. Low solids muds are those where solid contents
are less than 5%.
3.3.2
Oil-based Mud
Oil-based mud (OBM) is deined as the drilling mud made with oil as the solvent carrier for the solids content. OBM is a drilling luid in which oil is the continuous phase
and where water content is less than 2% to up to 5%. his water is spread out, or dispersed, in the oil as small droplets. In general, diesel, kerosene and fuel oils are used as
base luid. OBMs are used for a variety of applications where luid stability and inhibition are necessary such as high-temperature (> 2000F), and deep (> 16,000 t) wells, salt
and unconsolidated formation and sot shale formation where sticking and hole stabilization is a problem. Using OBM results in fewer drilling problems and causes less formation damage than WBMs and they are therefore very popular in certain areas. OBM
is normally used in extremely hot formations and when water-based muds adversely
afect formation. In general, OBMs are applied in directional wells and horizontal wells.
It is also used to drill and core (i.e. collection of samples for analysis) pay zones, to drill
troublesome formations (i.e. shale) and to reduce corrosion.
78
Fundamentals of Sustainable Drilling Engineering
OBMs consist of three types – i) invert emulsion oil-based mud, ii) pseudo oil-based
mud and iii) full oil mud. he ratio of oil to water or brine is 50:50 to 80:20. Various
chemicals, such as surfactants, organic clay and asphalt are used to control rheological, iltration and emulsion stability. OBMs are formulated with only oil as the liquid
phase and water content is less than 5%. hese types are used as coring luid or for a
hostile environment. OBMs require higher additional gelling agents for viscosity, such
as emulsiiers and wetting agents. OBMs are however more expensive and require more
careful handling (i.e. pollution and toxicity control) than WBMs. hey are useful in
drilling certain formations that may be diicult or costly to drill with water-based mud.
OBMs have some advantages and disadvantages that are as follows:
Advantages:
1.
1.
2.
3.
2.
Good rheological properties at temperatures as high as 500 °F
More inhibitive than inhibitive water-based muds
Efective against all types of corrosion
Superior lubricating characteristics
Permits mud densities as low as 7.5 lbm/gal
Disadvantages:
1.
1.
2.
3.
2.
Generally more expensive and higher initial cost
Require more stringent pollution-control procedures
Reduced efectiveness of some logging tools
Remedial treatment for lost circulation is more diicult
Detection of gas kicks is more diicult because of gas solubility in diesel oil
i) Invert emulsion oil-based mud: Invert emulsion drilling luids are water in oil emulsion, typically with CaCl2 brine as the emulsiied phase and mineral oil as the continuous phase. he basic components of a typical low toxicity invert emulsion luid are base
oil, water, emulsiier, wetting agents, organophillic clay, and lime. Only low toxic base
oil should be used within the range as mentioned earlier. his is the external emulsion phase. Water is used as an internal emulsion phase, which gives the oil/water ratio
(OWR). OWR gives the percentage of each part as a total of the liquid phase. Generally,
a higher OWR is used for drilling troublesome formations. he salinity of the water
phase can be controlled by the use of dissolved salts, usually calcium chloride. Control
of salinity in invert oil muds is necessary to tie up free water molecules and prevents
any water migration between the mud and the open formation such as shale.
ii) Pseudo oil-based mud: A biodegradable synthetic based oil mud. he developments such mud has been made to help the environmental problem of low toxicity oil
based muds and their low biodegradability. A system that uses synthetic base oil is called
a pseudo oil-based mud (SOB). Synthetic oil-based mud is deined as a mud with the oil
component replaced by lower toxicity oil such as mineral oil. It is designed to behave as
close as possible to low toxic oil based mud (LTOBM). It is built in a way similar to normal
oil-based luids using modiied emulsiiers. SOB muds are expensive systems and should
only be considered in drilling hole sections that cannot be drilled using water-based muds
Drilling Fluids 79
without the risk of compromising the well objectives. he base oils that are being used in
this type of mud are the Detergent Alkalates, Synthetic Hydrocarbon, Ether and Ester.
Synthetic base luids include Linear Alpha Oleins (LAO), Isomerised Oleins (IO), and
normal alkanes. Other synthetic base luids have been developed and discarded such as
ethers and benzene based formulations. Esters are non-petroleum oils and are derived
from vegetable oils. hey contain no aromatics or petroleum-derived hydrocarbons. he
primary advantage of an ester-based luid is that it biodegrades readily, either aerobically
or, more importantly, from a mud cuttings disposal viewpoint, anaerobically.
iii) Full-oil mud: his mud has very low water content (<5%) whereas invert oil
emulsions may have 5 – 50% water content.
3.3.3 Air or Gas-based Mud
Compressed air is very efective as a drilling luid for drilling in a competent (i.e. the
borehole will not collapse) consolidated rock, or in frozen ground. Only minor modiications to a conventional drilling rig and drill bits are required to drill with compressed
air as compared to drilling with mud. Gases are used when the formation is competent
and impermeable (i.e. gas will not leak into). herefore, the use of gas or air as a drilling luid is limited to areas where the formations are competent and impermeable, for
example in West Virginia. Air, or foam drilling luids are included in two types. Air or
natural gas drilling luid is included by injecting air or natural gas into the wellbore at a
rate capable of achieving annular velocities that will remove drill cuttings. Foam drilling luid is formed by injecting a foaming agent into the air stream or may be mixed
with produced water. Surfactants and possibly clays or polymers are used to form high
carrying capacity foam. hese drilling luids can prevent the formation of damage especially for low pressure, low permeability reservoirs.
During drilling with air/gas, a compressor along with its diferent parts such as pressure gauges, safety valves, storage tank, etc., are required. A delivery hose is required to
attach the air supply to the kelly of the drilling rig. A delector should be placed over the
borehole to delect the cuttings, which are brought to the surface by the compressed air.
When drilling frozen formations, refrigeration equipment may be required to chill the
compressed air before it is pumped into the borehole, especially if the ambient temperature is cooler than about –5°C (23°F). If the relative humidity is high, provisions should
also be made for defrosting the chiller. here are some advantages and disadvantages of
drilling with air in the circulating system that are stated below:
Advantages:
1. High penetration rate
1. Better hole cleaning
2. Less formation damage
Disadvantages:
1. Gases/air cannot support the sides of the borehole
2. Air cannot exert enough pressure to prevent formation luids entering
the borehole
80
Fundamentals of Sustainable Drilling Engineering
3.3.4 Foam
Air with additives is referred to as foam. Gas-liquid mixtures can be used only some
limited formations where water production is at signiicant rates. he gas-liquid mixtures sometimes form foam. Foam or mist is normally added to compressed air to
enhance its performance, especially when too much water is encountered during the
drilling of clay and shale formations. Foam helps to keep the cuttings separated, reduce
the efects of balling and sticking, assist in removing water from the drill hole, and
allow larger cuttings to be removed from the hole with the same volume of air. As the
removal of larger cuttings from the bottom of the hole is improved, foam helps to assure
better cleaning of the hole, faster bit penetration due to less grinding of cuttings. hus
longer bit life results. Foam is also used as a dust suppressant and reduces air loss, which
allows drilling through lost circulation zones. Foaming agents are generally biodegradable mixtures of surfactants.
he foam mist is generally adequate to suppress dust, combat small water inlow, and
remove sticky clay, wet sand, and ine gravel in holes with few hole problems. Stifer
foam is required as the hole diameter and depth increase, gravel or cuttings become
larger, water inlows become signiicant, or unstable hole conditions are encountered.
he injection of mist or foam may require an increased return velocity of 30% or more as
compared to strictly air drilling. When foam drilling continues, use 1 to 2 pints per 100
gallons of makeup water. his should be added to the foam-mixing tank. he foam/water
mixture is injected into the air stream from the compressor through the mixing nozzle.
he resulting foam is piped through the parts in the bit where it expands and lows back
up the hole to the surface bringing with it suspended cuttings. If stif foam is desired, the
addition of Insta Pac- 425 in small quantities will help stifen the foam. Insta-Pac 425 can
also be used as a stiing agent. In general, foam drilling is not commonly used in engineering activities; it is recommended that anyone planning to use foam drilling should
investigate available products and manufacturer’s recommendations.
3.3.5
Special Types of Muds
i) Bentonite muds: Bentonite is the most commonly used drilling luid additive. It
consists of inely ground sodium bentonite clay. When bentonite is mixed with water,
the resulting slurry has a viscosity greater than water, acquires the ability to suspend
relatively coarse and heavy particles. his mixture then tends to form a thin, very low
permeability cake on the walls of the borehole. Due to these features, bentonite drilling
mud is superior to water as a drilling luid for many applications. Bentonite for drilling
is generally available in a standard grade which complies with the American Petroleum
Institute (API) Speciication 13A (American Petroleum Institute 1983). A high yield
grade, which contains organic polymers, generally produces approximately the same
viscosity as the standard grade with one-half the amount of bentonite. It should be
noted, however, that the standard grade bentonite may contain peptizing agents and
organic additives. For environmental drilling where additives are unacceptable, pure
sodium bentonite is available from several suppliers.
ii) Inhibited muds: he hydration of clays is severely reduced if water contains a high
salt concentration. If a shale zone is being drilled with a freshwater mud the formation
Drilling Fluids 81
clays will tend to expand and the wellbore becomes unstable (sloughing shale). By using
a mud containing salt or calcium there will be fewer tendencies for this problem to
occur. An inhibitive mud is deined as one where the ability of active clays to hydrate
has been greatly reduced. Another advantage is that the water normally used in hydration is available to carry more solids. Inhibitive muds are principally used to drill shale
and clay formations, and are characterized by low viscosity, low gel strength, greater
solids tolerance, and greater resistance to contaminate.
iii) Calcium treated muds: When Ca2+ ions are added to a clay-water mud, the mud
begins to thicken due to locculation. At the same time a cation exchange reaction
begins whereby Ca2+ replaces Na2+ on the clay plates. Calcium montmorillonite does
not hydrate as extensively as sodium montmorillonite and the plates begin to aggregate
(stack closer together). As the reaction proceeds the mud begins to thin and viscosity
reduces. he conversion of a freshwater mud to an inhibited mud usually takes place in
wellbore. he conversion should not be done at a shallow depth where large volumes
of cuttings are being lited, as this might cause a viscous plastic mass around the bit.
Lime, caustic soda and a delocculant (quebrancho, lignosulphanates etc) are added. A
pilot test may be run to determine the amounts required for each chemical. he conversion may be done in one circulation (pressure and temperature help the reaction to
proceed). Gypsum, CaSO4.2H2O or calcium chloride CaCl2 can be used in place of lime
to supply the Ca2+ ions.
iv) Lignosulphanate treated muds: An inhibited mud can also be formed by adding
large amounts (12 lb/bbl) of lignosulphanate to a clay-water system. Chrome lignosulphanates is commonly used since it is relatively cheap and has a high tolerance for salt
and calcium.
v) Saltwater muds: Inhibitive muds having a salt concentration (NaCl) in excess of
1% by weight are called saltwater muds. hese are oten used in marine areas where
freshwater is not readily available. As stated earlier commercial clays (i.e. bentonite)
will not readily hydrate in water containing salt concentration (i.e. bentonite behaves
like an inert solid). To build viscosity the clay must be pre-hydrated in freshwater, then
treated with a delocculant before increasing salinity. he Ca2+ and Mg2+ ions can be
removed by adding NaOH to form insoluble precipitates which can be removed before
building viscosity. Ater conversion saltwater muds are not greatly afected by subsequent contamination. However the increased salt content may make it more diicult to
maintain other mud properties. (Alkalinity is controlled by adding NaOH and iltration by adding bentonite). Corrosion may be a major problem in saltwater muds unless
alkalinity is controlled.
vi) Polymer mud: Both natural and synthetic organic polymers are available that will
produce drilling muds with desirable properties. Although the cost of most polymer
additives is greater than the cost of bentonite, the lubricating quality of many polymer
muds is excellent and can noticeably reduce bit and rod wear. As compared to bentonite
muds, polymer muds oten contain lower solids contents. Although polymer muds may
lack the gel strength that is required to suspend particles or to form a satisfactory ilter
cake as compared to bentonite muds, polymer muds can be pumped at much higher
viscosities. Consequently, the water loss due to poorer ilter cake properties is partially
mitigated by reduced seepage of the very viscous mud into the formation. A natural
polymer, which has been used for drilling wells and piezometers, is made from the
82
Fundamentals of Sustainable Drilling Engineering
Guar bean. It degrades naturally because of the action of enzymes and returns to the
viscosity of water within a few days.
vii) Bentonite and polymer mud: It is sometimes advantageous to prepare drilling
muds composed of both bentonite and polymer with water. he low solids viscosity
properties of organic polymers when combined with the iltration properties of a bentonite mud yield a mud with excellent characteristics for many applications. When the
combination mud is prepared, the bentonite should be added to the water before the
polymer is added.
3.4 Composition of Drilling Fluids
he composition of drilling luid ranges from a simple clay-water mixture to a complex blend of materials chemically suspended in water or oil. he composition of mud
depends on the type of mud whether it is water-based, oil-based or synthetic-based, and
functions of mud. Table 3.1 shows the diferent compositions of drilling muds (Zwicker
et al. 1983; Patin, 1999; Wenger et al. 2004; Khan and Islam, 2007). In addition, Table 3.2
Table 3.1 Composition of drilling muds which are used in oil and gas exploration.
Product
Composition
Concentration (kg/bbl)
Base luid
Water, Bentonite clay (Sodium
montmorillonite), Caustic soda (sodium
hydroxide)
As needed
Additives
Ligno sulfonate, Phosphates (sodium
acid pyrophosphate and tetra sodium
pyrophosphate), Plant tains (predominant
usage of quebracho), Lignite
1–2.7 kg/bbl
Density control
Barite (natural barium sulfate ore),
Ferrophosphate ore, Calcite, Siderite
0 – 317.5 kg/bbl
Fluid-loss
control
Starch (corn and potato), Polyanionic
cellulose polymer, Xanthum gum, Sodium
carboxymethyle-cellulose, lignite.
< 0.45–4.5 kg/bbl
Lost Circulation
Ground nut shells, Micas, Ground cellophane,
Diatomacheous earth, Cottonseed hulls,
Ground or shredded paper
0.9–13.6 kg/bbl
Corrosion and
scale control
Sodium sulite, Zinch chromate, Tall oil,
Amines, Sodium hydroxide, Phosphates,
Bactericides
0.11–2.7 kg/bbl
Solvents
Isoprophanol, Glycerol, Isobutanol, Ester
alcohols, Diesel oil
Lubricant
Asphalts, Diesel oil, Fatty soaps, gilsonite,
Glass beads, Rosin soap
0.09–2.7 kg/bbl
Drilling Fluids 83
Table 3.2 Composition of water–based, oil–based and synthetic–based drilling muds.
Water–Based Mud
Oil–Based Mud
Synthetic–Based Mud
–
–
–
–
–
–
–
–
–
–
–
–
–
– A drilling luids whose
continuous phase is
composed of one or more
luids produced by the
reaction of speciic puriied
chemical feedstock, rather
than through physical
separations such as cracking
and hydro processing
Bentonite (0 to 50)
Barite (0 to 500)
Caustic Soda (0 to 5)
Soda Ash (0 to 3)
Sodium bicarbonate (0 to 3)
Seawater (any portion)
Freshwater (any portion)
Drill solids (0 to 100)
(Source: GESAMP, 1993)
Barite (60.8%)
Base oil (31.3 %)
CaCl2 (3.3%)
Emulsiier (2.2 %)
Filtrate control/
wetting agent (1.8%)
– Lime (0.2%)
– Viscosiier (0.2%)
(Source: Patin, 1999)
(Source: OWTG, 2002)
Water-base Mud
Barite 6%
Drilling solids
(i.e. sand, limestone
etc) 5%
Clay 3%
Water
80%
Solids for
density
control 6%
Figure 3.4 Diferent compositions of water-based mud.
outlines the various chemical additives and heavy metals that may be added to the drilling muds to stabilize the drilling luids during use, and to reduce corrosion and bacterial activity (Khan and Islam, 2007). Water-based muds consist of a mixture of water,
solids, liquids and chemicals (Figure 3.4). Some emulsiied diesel oil or lease crudes
are used to lubricate and ilter control. Some solids (i.e. clay) react with the water and
chemicals in the mud and are called “active solids”. he activity of these solids must be
controlled in order to allow the mud to function properly. he solids that do not react
within the mud are called “inactive” or inert solids (ex. Barite). Freshwater is used as
the base for most of these muds. However in ofshore drilling, saltwater is more readily
available. Oil-based muds are similar in composition with water-based mud. he only
exception is the continuous phase of the oil (Figure 3.5), which has almost 50 – 80% oil.
In an invert oil emulsion, mud water makes up a large percentage of the volume, but oil
is still the continuous phase. he water is dispersed throughout the system as droplets.
WBMs are complex blends composed of water and bentonite. On the other hand
OBMs are composed of mineral oils, barite, mineral oil, and chemical additives
(Table 3.1). SBMs are characterized by the replacement of mineral oil with oil like
substance, and are free of inherent contaminants such as radioactive components and
84
Fundamentals of Sustainable Drilling Engineering
Oil-based Mud
Clay, sand, limestone, chert,
mud additives etc 3%
Water
30%
Oil
54%
Others
12%
Solids for
density control
9%
CaCl2 or NaCl 4%
Figure 3.5 Diferent compositions of oil-base mud.
toxic heavy metals (Table 3.2). SBMs are considered benign environmentally, and have
the potential to biodegrade under aerobic conditions (OWTG, 2002). herefore their
use is preferred over WBMs and OBMs. To minimize the quantity of oil discharged
into the marine environment, use of water-based or synthetic-based mud is encouraged (OWTG, 2002). Oil-based muds may be required in exceptional circumstances for
deeper well sections and where well is needed to drill at vertical angle.
3.5 Mud Additives
As discussed in the previous section, there are many types of drilling luids that are used
in industry. Each has many subcategories based on purposes, additives, or clay states.
here are fundamental aspects that have to be controlled in order to have an efectively
and successfully purposing drilling luid. Mud additives control these aspects. here
are many drilling luid additives that are used to develop the key properties of the mud.
he varieties of luid additives relect the complexity of mud systems that are currently
in use to improve the drilling performance in general. Nowadays, the complexity is
also increasing in a daily basis because the drilling personals face new, more diicult
and challenging drilling conditions. However, the use of additives can be categorized
mainly under i) chemical additives, ii) additives for WBM, and iii) additives for OBM.
We shall limit ourselves to the most common types of additives used in these categories
of mud.
3.5.1 Chemical Additives
he following chemicals are used in drilling luid for maintaining diferent functional
properties.
i) Sodium Carbonate (NaCO3 ): Soda ash is used to precipitate soluble calcium from
water-based mud to control pH. When the soda ash enters hard water, it ionizes as Na+
and CO32- in the continuous phase. he carbonate ions combine with the calcium ions,
forming calcium carbonate (CaCO3), and inert precipitate. Treating hard water with
soda ash prior to using the water to make a bentonite or polymer drilling luid will
Drilling Fluids 85
result in a higher yield and more stable drilling luid. Make up water should be treated
with soda ash if 500-ppm calcium is present. Formula for soda ash addition is 0.001 x
ppm Ca = lb. soda ash plus 42 gallons make up water. Excessive treatment with soda
ash can cause high viscosity and gel strengths. If a mud has pH less than 11, soda ash
additions will raise it.
ii) Sodium Hydroxide (NaOH): Caustic Soda is used in this case. A chemical is
primarily used to impart a higher pH. Cautions are taken when using caustic soda
because it can cause severe burns due to its high corrosiveness. To raise pH, use ¼ to
1 lbs caustic soda per 50 gallons of water. Use of caustic soda is not recommended for
groundwater drilling.
iii) Sodium Acid Pyrophosphate (SAPP): SAPP has a 4.5 pH in 10% solution. It
is used as a thinning agent, to disperse sticky clays and clean up and develop waterbearing formations. A very small amount of phosphate is required to thin clay-drilling
luids. Normally, ¼ to ½ pound per 50 gallons is suicient. To develop water well, use
4 to 10 pounds per 50 gallons of water, jetting and circulating product at the targeted
water-bearing formation. Sodium Hexametaphosphate (6.8 pH) and Sodium Tetra
phosphate (8.0 pH) are used as SAPP. Care should be taken when using phosphate to
develop water well. Development should start and be completed at the time the phosphate is introduced to the system. Introducing phosphate into a system and letting it
sit for 6 to 12 hours prior to well development can damage water-bearing formation
inhibiting proper well development.
iv) Lime [Ca(OH)2 ]: Lime has the same detrimental efect as cement has on drilling
mud. Lime increases viscosity, gel strength and luid loss in the formation. he reaction
is very severe. Lime hinders the ability to develop a water-bearing formation properly.
v) Borax (Sodium Borate): Borax is used as a viscosiier and gelling agent in conjunction with guar gum (VariFlo).
vi) Chlorine (Sodium Hypo chlorite-Liquid or Dry): Chlorine is primarily used
to destroy bacteria once the well is completed. It is also used to destroy bacteria and
enzymes in the mix water prior to using a guar gum (VariFlo) polymer.
3.5.2 Additives for Water-based Mud
WBM is prepared as a mixture of solids, liquids, and chemicals where water is the
continuous face. A wide range of WBM additives are used to control and upgrade the
performance and quality of WBM. he most commonly used additives are classiied as
i) weighting materials, ii) lost circulation control materials, iii) thinners or dispersants,
iv) surfactants or surface-active agents, v) luid loss control additives, vi) viscosiiers,
vii) iltration control materials, viii) alkalinity and pH control materials, ix) rheology
control materials, x) lubricating materials, xi) shale stabilizing materials, xii) removal
of contaminants and xiii) other additives.
i) Weighting agents: Weighting agents are also called density control additives. Barite
(BaSO4) is the most commonly used weighting agent. Density of mud can be achieved
in the range of 9 ppg – 19 ppg by mixing water, clay, and barite. he API speciication
for barite is shown in Table 3.3. Hematite (Fe2O3) and ilmenite (FeTiO3) can also be
used. Hematite may be superior because it has the potential to enrich iron-deicient
86
Fundamentals of Sustainable Drilling Engineering
Table 3.3 API speciication for Barite
Speciic gravity
4.2 (minimum)
Soluble metals or calcium
250 ppm (maximum)
Wet screen analysis
Residue on No.
200 sieve: 3% (maximum)
Residue on No.
325 sieve: 5% (minimum)
Table 3.4 Materials used as density control additives
Material
Principal
components
Speciic gravity
% Acid soluble
Galena
PbS
7.4 – 7.7
0
Hematite
Fe2O3
4.9 – 5.3
50+
Magnetite
Fe3O4
5.0 – 5.2
0
Illmenite
FeO.TiO2
4.5 – 5.1
20
Barite
BaSO4
4.2 – 4.6
0
Siderite
FeCO3
3.7 – 3.9
95+
soils. Table 3.4 gives a list of the most commonly used weighting agents. Barite is typically ground according to API speciications: less than 3% w/w of particles should be
greater than 75μm and less than 30% w/w of particles should be less than 6-μm diameter in order to be used in oilield applications. Hematite and ilmenite are typically
ground iner than barite due to abrasion problems seen with this material. Abrasion
similar to barite is achieved if these materials are ground to a particle size less than
45μm, and this is the speciication typically used.
ii) Lost circulation control materials: Lost circulation is the loss of mud or cement
to the formation while drilling. his may happen in highly permeable sandstones, natural fractures, cavernous formations, and induced fractures. While drilling, mud loss
also happens due to natural losses, or due to excessive overbalance. It causes increased
well costs due to non-operating rig time and the loss of expensive drilling luid, loss
of accurate hole monitoring and well control problems. herefore, it is important to
control the lost circulation. he additives that are used to control such loses is called
lost circulation material (LCM). Table 3.5 shows loss circulation additives that are commonly used in the industry.
iii) Fluid loss control additives: Loss of luid from the mud occurs when the mud
comes into contact with a permeable zone. If the pores are large enough the irst efect
will be a spurt loss, followed by the buildup of solids to form a mud cake. he rate at
which luid is lost is a function of diferential pressure, thickness of ilter cake and viscosity of the iltrate. Clays, dispersants, and polymers such as starch are widely used
as luid-loss-control additives. Sodium montmorillonite (bentonite) is the primary
luid-loss-control additives in most water-based drilling luids. he colloidal-sized
Drilling Fluids 87
Table 3.5 Commonly used lost circulation additives (Bourgoyne et al., 1986)
Material
Nut shell
Type
granular
Description
50% – 3/16-10 mesh
Concentration
Largest
Fracture sealed
lbm/bbl
in.
20
0.25
50% – 10-100 mesh
Plastic
granular
50% – 10-100 mesh
20
0.25
Limestone
granular
50% – 10-100 mesh
40
0.12
Sulfur
granular
50% – 10-100 mesh
120
0.12
Nut shell
granular
50% – 10-16 mesh
20
0.12
60
0.10
50% – 10-100 mesh
Expanded
granular
Perlite
50% – 3/16-10 mesh
50% – 10-100 mesh
Cellophane
lamellated
3/4-in. lakes
8
0.10
Sawdust
ibrous
¼” particles
10
0.10
Prairie hay
ibrous
½” ibers
10
0.10
Bark
ibrous
3/8” ibers
10
0.07
Cotton seed hulls
granular
ine
10
0.06
Prairie hay
ibrous
3/8” particles
12
0.05
Cellophane
lamellated
½” lakes
8
0.05
Shredded wood
ibrous
¼” ibers
8
0.04
Sawdust
ibrous
1/16” particles
20
0.02
sodium-bentonite particles are very thin and sheetlike or platelike with a large surface area, and they form a compressible ilter cake. Inhibitive mud systems inhibit
the hydration of bentonite and greatly diminish its efectiveness. herefore, bentonite
should be prehydrated in freshwater before being added to these systems. he larger
and thicker particles of sodium montmorillonite do not exhibit the same luid-losscontrol additives.
iv) Filtration control materials: Filtration control materials are compounds that
reduce the amount of luid that will be lost from the drilling luid into a subsurface
formation. his is due to the diferential pressure between the hydrostatic pressure
of the luid and the formation pressure. he common iltration control additives are
i) starch, ii) polymers (i.e. Sodium Carboxymethylcellulose (CMC), sodium polyacraylate etc.), iii) polyanionic cellulose (PAC), iv) bentonite, v) thinners or delocculants.
Starches form very compressible particles that plug the small openings in the ilter cake.
Polymers such as PAC and CMC reduce iltrate mainly when the hydrated polymer
88
Fundamentals of Sustainable Drilling Engineering
chains absorb onto the clay solids and plug the pore spaces of the ilter cake. Polymers
prevent luid seeping through the ilter cake and formation. Polymers reduce water loss
by increasing the efective water viscosity. When clay cannot be used efectively, watersoluble polymers are substituted. he free water is absorbed by the sponge like material, which aids in the reduction of luid loss. Bentonite is efective to control viscosity
and suspension as well as iltration control. he lat, “plate like” structure of bentonite
packs tightly together under pressure and forms a irm compressible ilter cake. It prevents luid from entering the formation. hinners and delocculants function as iltrate
reducers by separating the clay locks or groups enabling them to pack tightly to form
a thin, lat ilter cake.
v) hinners or dispersants: Originally, thinner was used to reduce low resistance
and gel development. However, the modern use of dispersant or thinner is to improve
the luid-loss control. hinners are also used to reduce iltration and cake thickness to
counteract the efects of salts, to minimize the efect of water on the formations drilled,
to emulsify oil in water, and to stabilize mud properties at elevated temperatures. he
term dispersant is frequently used incorrectly to refer delocculants, Dispersants are
chemical materials that reduce the tendency of the mud to coagulate into a mass of
particles or loc cells. In addition, some dispersants contribute to luid-loss control by
plugging or bridging tiny openings in the ilter cake. As a result, some dispersants such
as lignosulfonate are more efective than others as luid-loss reducers. Materials commonly used as thinners in clay-based drilling luids are classiied as: i) plant tannins,
ii) lignitic materials, iii) lignosulfonates, and iv) low molecular weight, synthetic, water
soluble polymers.
vi) Surfactants or surface-active agents: A surface-active agent is a soluble organic
compound. It concentrates on the surface boundary between two dissimilar substances
and diminishes the surface tension between them. he molecular structure of surfactants is made of dissimilar groups having opposing solubility tendencies such as hydrophobic and hydrophilic. hey are commonly used in the oil industry as additives to
WBMs to change the colloidal state of the clay from that of complete dispersion to one
of the controlled locculation. hey may be cationic, anionic, or non-ionic. Surfactants
are used in muds as emulsiiers, dispersants, wetting agents, foamers and defoamers,
and to decrease the hydration of the clay surface. he type of surfactant behaviour
depends on the structural groups of the molecules.
vii) Viscosiiers: here are many diferent products that can be classiied as viscosiiers. Bentonite, attapulgite clays, sub-bentonites and polymers are most widely used
viscosity builders. hese viscosiiers form colloidal suspensions in water. hey increase
viscosity, yield point and gel-strength by inter surface friction and by chemically
binding-water. Polymers are multi-purpose additives that may simultaneously modify
viscosity, control iltration properties, stabilize shales and create or prevent clay locculation. Table 3.6 shows a list of commonly used materials to provide viscosity to drilling
luids.
viii) Alkalinity and pH control materials: he pH afects several mud properties
including i) detection and treatment of contaminants such as cement and soluble carbonates, ii) solubility of many thinners and divalent metal ions such as calcium and
magnesium. pH control is desirable to prevent corrosion, and hydrogen embrittlement
is important. he pH of most muds lies between 9.5 and 10.5. here are some common
Drilling Fluids 89
Table 3.6 Chemical additives used as viscosiiers used in WBM (Rabia, 2006)
Material
Principal components
Bentonite
Sodium/calcium aluminosilicate
CMC
Sodium carboxy-methyle cellulose
PAC
Poly anionic cellulose
Xanthan gum
Extracellullar microbial polysaccharide
HEC
Hyroxy-ethyl cellulose
Guar gum
Hydrophilic polysassharide gum
Resigns
Hydrocarbon co-polymers
Silicates
Mixed metal silicates
Synthetic polymers
High molecular weight polyacrylamides/polyacrylates
Table 3.7 pH of 10% aqueous solutions (by weight) of chemicals additives commonly used in
WBM (Bourgoyne et al., 1986)
Material
Commercial name
Description
pH of solution
Calcium hydroxide
Slaked lime
Ca(OH)2
12.0
Calcium sulfate
gypsum
CaSO4.2H2O
6.0
Sodium carbonate
Soda ash
Na2CO3
11.1
Sodium hydroxide
Caustic soda
NaOH
12.9
additives such as NaOH, KOH, Ca(OH)2, NaHCO3 and Mg(OH)2 that are used to control alkalinity and pH. However, caustic soda (NaOH) is the main additives used to
keep the pH of the drilling luid. hese additives are compounds used to attain a speciic pH, and to maintain optimum pH and alkalinity in water base luids. Table 3.7
shows the pH of aqueous solutions of commonly used additives.
ix) Rheology control materials: When eicient control of viscosity and gel development cannot be achieved by controlling viscosiier concentration, materials called thinners, dispersants, and delocculants are added. hese materials cause a change in the
physical and chemical interactions between solids and/or dissolved salts such that the
viscous and structure forming properties of the drilling luid are reduced.
x) Lubricating materials: While drilling, lubricating materials are used with the
mud system because the reduction of friction between the wellbore and the drill string
is an important issue. his reduction of friction will in turn reduce torque and drag.
his is essential in highly deviated and horizontal wells. he commonly used lubricating materials include oil (diesel, mineral, animal, or vegetable oils), surfactants, graphite, asphalt, gilsonite, polymer and glass beads.
xi) Shale stabilizing materials: Shale problems are commonly encountered while
drilling sensitive highly hydratable shale sections. herefore, shale stabilization needs
90
Fundamentals of Sustainable Drilling Engineering
to be achieved by preventing the water contact with the open shale section. his can
happen when the additive captures the shale or when a speciic ion such as potassium
actually enters the exposed shale section. As a result, it neutralises the charge on it. he
commonly used shale stabilisers are high molecular weight polymers, hydrocarbons,
potassium and calcium salts (e.g. KCl) and glycols. Field experience indicates that complete shale stabilisation cannot be obtained from polymers only. So, soluble salts must
also be present in the aqueous phase to stabilize hydratable shales.
xii) Removal of contaminants: Various substances may enter the mud and cause
an adverse efect on the quality of the mud and reduce its eiciency. hese contaminants must be removed. he most common contaminants are calcium, carbon dioxide, hydrogen sulphide, and oxygen. Calcium (Ca+) may enter from cement, gypsum,
lime or saltwater. It reduces the viscosity building properties of bentonite. It is usually
removed from freshwater muds by adding soda ash Na2CO3, which forms insoluble
CaCO3. If calcium is present in the mud, the pH will normally be too high.
Carbon dioxide (CO2 ) presence in the formations can cause adverse iltration and
gelation characteristics of the mud. To remove CO2, calcium hydroxide can be added
to precipitate CaCO3.
Hydrogen sulphide (H2S) presence in formations creates highly toxic gas, which also
causes hydrogen embrittlement of steel pipe.
Oxygen (O2) entrained in mud in surface pits, causes corrosion and pitting of steel
pipe. Sodium sulphite (Na2SO3) is added at the surface to remove the oxygen
xiii) Other additives: As mentioned above, various additives are present in the drilling luid to control the physical properties such as emulsion stabilizers, pH adjusters,
wetting agents, viscosiiers and luid-loss-reducing agents. However, the speciic chemicals used oten vary between locations. It is assumed that in most cases their environmental impact is negligible compared to the efects of hydrocarbons, salts and heavy
metals. Furthermore, diferent mud additives have diferent efects on the environment,
from their impact on marine organisms to their efects on rig workers coming into
close contact with them.
3.5.3 Additives for Oil-based Mud
here are some common types of additives used in oil-based mud as explained for
water-based mud system. However, there are some special types of additives also used
in oil-based mud. he followings are some of the examples.
i) Emulsiier: Calcium or magnesium fatty acid soap is frequently used as an emulsiier
for oil-based mud. Fatty acids are organic acids that are available in naturally occurring
fats. Emulsiiers are oten divided into primary and secondary emulsiiers. he emulsiier acts at the interface between the oil and the water droplets. Emulsiier levels are
held in excess to act against possible water and solid contamination.
ii) Wetting agents or wettability control: Most of the natural minerals are preferentially wet by water. When water-wet solids are introduced to a water-in-oil emulsion, the solids tend to attach with the water. his action results in high viscosities
and settling down the phase. Water-wet solids also tend to cause the formation of an
oil-in-water emulsion rather than a water-in-oil emulsion. To overcome these problems,
Drilling Fluids 91
wetting agents are added to the oil phase of the mud. he wetting agents are surfactants
similar to the emulsiiers. his is a high concentration emulsiier used especially in
high-density luids to oil-wet all the solids. If solids become water-wet they will not be
suspended in the luid, and would settle out of the system. Soaps are added to serve as
emulsiiers, which have similar functions, are as wetting agents. However, they usually
do not act fast enough to handle a large inlux of water-wet solids during fast drilling or
mud weighting operations. Several special surfactants are available for more efective
oil wetting.
iii) Organophillic clay: hese are clays treated to react and hydrate in the presence of
oil. hey react with oil to give both suspension and viscosity characteristics.
iv) Lime: Lime is the primary ingredient necessary for reaction with the emulsiiers
to develop the oil water interface. It is also useful in combating acidic gases such as CO2
and H2S. he concentration of lime is usually held in excess of 2 to 6 lbm/bbl, depending
on conditions.
v) Viscosity control: Excessive viscosity in an oil-based mud may be encountered
due to i) too much water content, and/or ii) drilled solids. When water is properly
emulsiied in the mud, it works like a solid. If the water fraction increases, the viscosity will also increase. However, the solids content afects viscosity in oil-based mud in
the same way as discussed for water-based muds. If we use diamond bits for drilling,
the accumulation of ine solids may produce high plastic viscosity, yield point, and
gel strengths. Finer shale shaker screens (120 mesh size) should be used to reduce the
solid content efect. Water wet solids may also cause problems with high yield point.
herefore, it is suggested to go for pilot tests to measure the efects of adding chemicals
to the mud to control viscosity. Emulsiiers and wetting agents may be added to reduce
viscosity. Water and special viscosiiers (organically treated bentonite) may be added to
the mud to increase viscosity.
vi) Filtration control: Since oil is the continuous phase in an oil-based mud, only
the oil phase is free to form a iltrate. herefore, this property makes the oil-based mud
suitable for formations easily damaged by water invasion, which must not be allowed
to damage. In general, oil-based mud has excellent iltration properties and barely
required iltration control additives. As a result, the luid loss is generally very small
with oil-based muds (< 3cc at 500 psi and 300°F). However, when additional luid loss
is anticipated, asphalt, polymers, manganese oxide, and amine-treated lignite can be
used. Water presence in the iltrate is not allowed during the test, which shows poor
emulsion. If water is present more emulsifying agent should be added.
vii) Density control: To control density of an oil-based mud, API barite is used as
control additive. It is also used for water-based muds. Sometimes calcium carbonate
(CaCO3) is also used if a relatively low mud density is necessary. Barite has lower gel
strengths, which creates a severe problem of settling down the oil-based mud quickly.
In addition, if the API barite is not converted completely to an oil-wet condition, the
barite particles will aggregate and will greatly be increasing their tendency to settle.
viii) Alkalinity control: In general, lime is used to sustain the alkalinity of oil-based
muds at an acceptable level. A high pH (8.5 to 10.0) is needed to control corrosion and
to obtain the best performance from the emulsiiers. If corrosive formations of gases
(such as CO2 or H2S) that form acids upon ionization are expected, an even higher alkalinity is recommended. he ability to contain a large reserve of undissolved lime makes
92
Fundamentals of Sustainable Drilling Engineering
an oil mud superior to a water mud when drilling CO2 or H2S bearing zones. he usual
range of the methyl orange alkalinity of the mud is 0.5 to 1.0 cm3. However, a value of
2.0 cm3 may be desirable when H2S or CO2 in anticipated.
ix) Water content: he water content of the oil-based muds must be maintained
within certain limits. When the mud temperature is high, water evaporation will take
place and sometimes this evaporation will be signiicant. Evaporation losses must be
replaced to prevent excessive viscosity of the OBM. his is accomplished by dilution
with oil. It is usually more economical to remove a portion of the oil mud when diluting
rather than continually increasing total mud volume.
In addition to temperature, water in oil emulsions is an important issue. he water
in reverse emulsion muds is dispersed as small droplets throughout the oil. Emulsiiers
coat the droplets and prevent the droplets from coalescence. his mechanism makes
the mud unstable (i.e. larger water droplets will settle out and break down the emulsion). Calcium or magnesium fatty acid soap is oten used as an emulsiier in an oilbased mud. he long hydrocarbon chain of the soap molecule tends to be soluble in oil
while the ionic portion tends to be soluble in water. When soap is added to a mixture of
oil and water, the molecule takes up the position as shown in Figure 3.6.
his mechanism reduces the surface energy of the interface and keeps the water droplets
in the emulsion. Other types of emulsiiers such as naphthenic acid soaps and soaps from
tree sap can also be used. he efectiveness of an emulsiier depends on the temperature
of the mud. he small and uniform water droplets should be maintained to increase the
stability. Shearing the mud by agitators does this. When oil is added the stability increases,
since the distance between droplets becomes greater. his causes a decrease in viscosity.
For good mud properties there must be a balance between oil and water. he water droplets help to support the barite, reduce ilter loss, and build viscosity and gel strength.
x) Control of solids: We know that drilling mud is a mixture of luids such as water,
oil or gases and solids (i.e. bentonite, barite etc.). he solids such as sand, silt, and
limestone do not hydrate or react with other compounds within the mud and are being
generated as cuttings from the formation while drilling. hese solids are called inert
and must be removed to allow eicient drilling to continue. herefore, solids control
is deined as the control of the quantity and quality of suspended solids in the drilling
luid so as to reduce the total well cost. However, some particles in the mud (i.e. barite,
bentonite) should be retained since they are required to maintain the properties of the
mud. he Rheological and iltration properties can become diicult to control when the
concentration of drilled solids (low-gravity solids) becomes excessive. If the concentration of drill solids increases, penetration rates and bit life decrease. On the other hand,
hole problems increase with the increase of drill solids concentration.
Oil
Water
Droplet
Oil
Figure 3.6 Water droplets dispersed in a continuous oil phase (Redrawn from Ford, 2005)
Drilling Fluids 93
During drilling operation, huge amounts of rock chips are generated due to the cutting
of earth rock. herefore, it is very important to know the solid volume of rock fragments that comes to the surface with the drilling mud. In an ideal situation, all drill
solids are removed from a drilling luid. Under typical drilling conditions, low-gravity
solids should be maintained below 6% by volume. Drill cuttings are the volume of rock
fragments generated by the bit per hour of drilling. he following equation (Eq. 3.1)
can be used to estimate the volume of solids entering to the mud system while drilling.
Vs
1
A
d B2
4
RROP
(3.1)
Here
dB = bit diameter
Vs = solid volume of rock fragments entering the mud i.e. volume of cuttings
RROP = rate of penetration of the bit
= average formation porosity
A
In ield unit, Eq. (3.1) can be written as
Vs
1
A
d B2
1029
RROP
(3.2a)
Here
dB = bit diameter, in
Vs = solid volume of rock fragments entering the mud i.e. volume of cuttings, bbl/hr
RROP = rate of penetration of the bit, t/hr
= average formation porosity, vol. fraction
A
If, Vs is in tons/hr, dB is in inch and RROP is in t/hr, Eq. (3.1) can be obtained as:
Vs
1
A
2262
d B2
RROP
(3.2b)
All of these solids (except barite) are considered undesirable because i) they increase
frictional resistance without improving liting capacity, ii) they cause damage to the
mud pumps, leading to higher maintenance costs, and iii) the ilter cake formed by
these solids tends to be thick and permeable. his leads to drilling problems (stuck
pipe, increased drag) and possible formation damage.
Example 3.1: A 15-in bit is used to drill a hole at a rate of 80 t/hr where the porosity of the formation is 20%. Calculate the solid volume generated by this drilling
operation. If the density of the solid is 910 lbm/bbl, calculate the solid generation in
tons/hr also.
Solution:
Given data:
dB = bit diameter = 15 in
RROP = rate of penetration = 80 t/hr
= average porosity of the formation = 0.20
A
94
Fundamentals of Sustainable Drilling Engineering
Required data:
Vs = solid volume generated by the bit in bbl/hr
he solid volume generated by the bit in bbl/hr can be calculated by using the Eq. (3.1)
as:
1
Vs
A
d B2
4
RROP
1 0.20 152 in2
4
3
231 in / gal
42 gal / bbl
80 ft
12 in / hr
hr
13.986 bbl / hr
he same result can be obtained if we use Eq. (3.2a).
In tons/hr: 910
lbm
bbl
13.986
bbl
hr
1ton
2000 lbm
6.36 tons / hr
he same result can be obtained if we use Eq. (3.2b).
Example 3.2: For a typical North Sea well, it is given that the diameter of the bit is 26
in, rate of penetration is 62 t/hr, and the average porosity is 25%. Find out the volume
of cuttings.
Solution:
Given data:
dB = bit diameter = 26 in
RROP = rate of penetration of the bit = 62 t/hr
= average formation porosity = 0.25
A
Required data:
Vs = volume of cuttings
he volume of cuttings can be calculated by using the Eq. (3.1) as:
Vs
1
A
4
dB2
1 0.25
RROP
4
26
ft
12
2
62 ft / hr
171.45
ft 3
hr
If we consider that the speciic gravity of drilled solids is approximately 2.6, then the
lb
lb
ft 3
tons
density of the solid is 171.45
62.4 m3 10,698.5 m . So, the cuttings in
will
hr
hr
hr
ft
lb
1ton
tons
be 10,698.5 m
.
5.35
hr 2000 lbm
hr
In the above examples, it shows that huge amount of solids have to be removed by
the solids control equipment every hour. Solids control is the most expensive part of the
mud system because it is operating continuously to remove unwanted solids. It is generally cheaper to use mechanical devices to reduce the solids content rather than treat
the mud with chemicals. However, the aim of any eicient solids removal system is to
Drilling Fluids 95
retain the desirable components of the mud system by separating out and discharging
the unwanted drilled solids and contaminants.
Solids in drilling luids may be classiied in two separate categories based on a) speciic gravity or density, and b) particle size.
a) Speciic gravity: For most practical purposes the solids can be classiied into two
groups according to their speciic gravity: i) high gravity solids, Sgh = 4.2, and ii) low
gravity solids, Sgl = 1.6 to 2.9. For example, barite has the high gravity solids and formation cuttings have low gravity solids. So, the solids content of a drilling luid will
be made up of a mixture of high and low gravity solids. High gravity solids are added
to luids to increase the density, e.g. barites, whilst low gravity solids enter the mud
through drilled cuttings and should be removed by the solids control equipment.
b) Particle size: he drill cuttings or mud solids are also classiied according to their
size. he unit of the particle size is called microns (μ). One micron is equal to 0.0000394
in or 0.001 mm. he analyses of particle sizes are important in drilling muds because
of two main reasons: i) the smaller the particle size, the more distinct the efect on
luid properties, and ii) the smaller the particle size, the more diicult it is to remove
or controlling its efects on the luid. he API classiication of particle sizes is shown
in Table 3.8. he various solids-particle sizes and the range of sizes are also shown in
Figure 3.7.
3.5.3.1
Solid Control Equipment
here is solids-control equipment that is used to remove solid contaminants and gas
entrapped in mud. A typical solids-removal system is shown in Figure 3.8, which
depicts a layout for solids control equipment for a weighed mud system. Solids can be
removed from mud in four stages: i) screen separation – shale shakers, scalper screens
and mud cleaner screens, ii) settling separation in non-stirred compartments – sand
traps and settling pits, iii) removal of gaseous contaminants by vacuum degassers or
similar equipment, and iv) forced settling by the action of centrifugal devices including
hydrocyclones (i.e. desanders, desilters and micro-cones) and centrifuges.
i) Screen separation: he shale shaker is the most common screen device as shown in
Figure 3.9. It contains one or more vibrating screens through which mud passes. Mud
Table 3.8 API classiication of particle sizes (Bourgoyne et al., 1986).
Particle size (μ)
Classiication
Sieve size (mesh)
> 2000
Coarse
10
2000 – 250
Intermediate
60
250 – 74
Medium
200
74 – 44
Fine
325
44 – 2
Ultra-ine
–
2–0
Colloidal
–
96
Fundamentals of Sustainable Drilling Engineering
0.01
2
0.1
4 68
2
1
4 68
10
2
Dispersed
Bentonite
4 68
100
4 68
2
2
1 mm
1,000
4 68
2
1cm
10,000
4 68
Barite
Drilled
Solids
Desilter
Underlow
Centrifuge
Overlow
200 mesh
discard
100 mesh
60 mesh
20 mesh
Fine
Sand
Silt
Tobacco
Smoke
Milled
Flour
Setting velocity in water Barite
at 68° F ft/min
Drilled
Solids
Gravel
Course
Sand
Beach
Sand
0.01
0.1
0.01
1
0.1
10
1
100
10
30
50 90
Figure 3.7 Particle size for solids-control devices (Redrawn form Mitchell and Miska, 2011).
Degasser
Stand Trap
Overlow
Shale
shakers
Mud
Cleaner
suction
Pump
Under low
Degasser
Suction
Under low
Discard
Pump Suction
Under low
Flow Line
Hopper
Centrifuge
suction
Centrifuge
Mud cleaner
Liquid
returns
Pump
Screen
Pump
Screened liquid
returned
Coarse solids discarded
Figure 3.8 Complete solid control system with mud cleaner and centrifuge.
Dry solids discarded
Drilling Fluids 97
Figure 3.9 Typical shale shaker (Source: http://www.slb.com/services/miswaco).
loaded with solids passes over the vibrating shaker where the liquid part of mud and
small solids pass through the shaker screens. he drill cuttings are then collected at
the bottom of the shaker. If the correct type of shaker is used and runs in an eicient
manner, the shale shaker and scalper screens (Gumbo shakers) can efectively remove
up to 80% of all solids from a drilling luid. Shale shakers are classiied into two types
based on its motion: a) circular or elliptical motion, and b) linear motion. Circular or
elliptical motion shakers are also known as rumba shakers. Elliptical rollers are used to
generate a circular rocking motion to provide better solids removal through the screen.
A linear-motion shaker uses a straight back-and-forth rocking motion to keep the luid
circulating through the screens. Field experience indicates that elliptical shakers work
better with water-based muds and linear-motion shakers are more suitable for oilbased muds. An absolute minimum of three shale shakers is recommended to have an
eicient separation of solids.
ii) Settling separation: A low-cost solids control method is to allow time for the
drilling luid to settle down. In this case, the contaminated mud needs to circulate
through a settling pit. hese settling control pits work on an overlow principle. he
sand trap is the irst one (Figure 3.8), which is fed by the screened mud from the shale
shakers. here should not be any agitation from suction discharge lines or paddles.
Any large heavy solids will settle out here and will not be carried on into the other pits.
Particles above colloidal size will eventually settle out in a slow condition. However,
the smaller the particle, the longer it will take to settle. In some cases, for silt-sized
particles, it may take days. Basically the solids will settle out more readily when a) the
solid particles are large and heavy, b) the mud is light and has a low viscosity, and c) the
gravitational force can be increased by mechanical means. Particle-settling velocities
are given in Figure 3.7.
iii) Gas removal: he trapped gas in mud must be removed in order to maintain the
desired density to a level needed to control downhole formation pressures. Figure 3.10
shows a typical degasser, which is used to remove gases from mud. here are also some
simple equipment such as a vacuum pump and a loat assembly. he vacuum pump creates
98
Fundamentals of Sustainable Drilling Engineering
Figure 3.10 A typical vacuum degasser (Source: http://www.udpf.com/).
a low internal pressure that allows gas-cut mud to be drawn into the degasser vessel. It is
then allowed to low in a thin layer over an internal bale plate. he combination of low
internal pressure and thin liquid ilm causes gas bubbles to expand in size, which rise to
the surface of the mud inside the vessel. As a result, the gas breaks down from the mud.
As the gas moves toward the top of the degasser it is removed by the vacuum pump. he
removed gas is routed away from the rig and is then either vented to atmosphere or lared.
iv) Forced settling: Desanders and desilters are similar devices, which are called
hydrocyclones. hey work on the principle of separating solids from a liquid by creating centrifugal forces inside the hydrocyclone. Mud is injected tangentially into the
hydrocyclone and the resulting centrifugal forces drive the solids to the walls of the
hydrocyclone. Finally hydrocyclone discharges the solids from the apex with a small
volume of mud (Figure 7.11). he luid portion of mud leaves the top of the hydrocyclone as an overlow and is then sent to the active pit to be pumped downhole again.
Hydrocyclones come in various sizes and shapes and usually speciied by the particle
sizes they are designed to remove. In general, there are four types of hydrocyclones:
a) desanders, b) desilters, c) mud cleaners, and d) centrifuges.
(a) Desanders: Desanders are hydrocyclones with 6-inch inner diameters or larger
(Figure 3.12). he primary use of desanders is in the top-hole sections when drilling
with water-based mud to help maintain low mud weights. Use of desanders prevents
overload of the desilter cones and increases their eiciency by reducing the mud weight
and solids content of the feed inlet. Desanders should be used if the sand content of the
mud rises above 0.5% to prevent abrasion of pump liners. Desanders should never be
used with oil-based muds because of its very wet solids discharge. he desander makes
a cut in the 40 to 45 micron size range. With a spray discharge, the underlow weight
should be between 2.5 to 5.0 ppg heavier than the input mud.
Drilling Fluids 99
Overlow opening (Liquid discharge)
Vertex inder
Hydrocyclone
Liquids and ine solids
Feed chamber
(actual hydro cyclone size is inside
diameter of cone at this point)
Pressurized mud
mixture enters
tangentially here
Whole mud in
Slurry rotation develops
centrifugal forces in cyclone.
Feed
inlet
Liquid moves inward
and upward as a
spiraling vortex
Solid are driven to the wall
and are moved downward in
an accelarating spiral
Apex
Underlow opening (solid discharge)
Coarse solids
Figure 3.11 Principle of hydrocyclones (redrawn from Mitchell and Miska, 2011).
Figure 3.12 A typical desander (http://www.pyzyrsd.com).
(b) Desilters: Desilters are the hydrocyclones made up of large number of small
diameter cones (i.e. < 6 in inner diameter). Figure 3.13 shows a typical desilter arrangement. Desilters along with desanders should be used to process low mud weights that
are used to drill top-hole sections (Figure 3.14). If the mud weight needs to rise, adding the barites must do this. Low gravity solids should not be allowed in such case.
Desilters are designed to remove silt-sized particles.
(c) Mud Cleaners: Mud cleaners are the combination of a ine-screened (roughly 320
mesh) shale shaker under a desilter and are placed above a high energy vibrating screen
(Figure 3.15). hey are used for weighed muds because barite tends to be removed with
silt-sized particles. By using a mud cleaner, barite can be recovered and reused. Mud
100 Fundamentals of Sustainable Drilling Engineering
Figure 3.13 A typical desilter.
Figure 3.14 A typical desander and desilter.
(Source: http://www.pyzyrsd.com)
Fine mesh screen
Overlow
(clean mud)
Desilting
hydrocyclone
Discard
(sand, some silt
and some barite)
Feed
Return
to pit
Liquid, ines,
most barite
Figure 3.15 A mud cleaner.
Drilling Fluids 101
Bowl rotation
Drying zone
Liquid zone
Feed
Whole
mud feed
Pool
Liquid return to active
Overlow
liquid
discharge
Beach
Solids discharge
(a) Decanting centrifuge with a horizontal
slender conical steel bowl
Under low
coarse solids
discharge
(b) Decanting centrifuge with cylinder
(Mitchell and Miska, 2011)
Figure 3.16 A typical decanting centrifuge.
cleaners must be used when it becomes impossible to maintain low mud weights by
use of the shale shakers alone. It is far more eicient to use desilters and process the
underlow with a centrifuge than to use the screens of a mud cleaner. he use of mud
cleaners with oil-based muds should be minimised because experience has shown that
mud losses of 3 to 5 bbls/hr being discharged are not uncommon.
(d) Centrifuges: Centrifuges use centrifugal forces to remove heavy solids from the
liquid and lighter components of the mud. Figure 3.16a shows a decanting centrifuge,
which consists of a horizontal conical steel bowl rotating at a high speed. he bowl contains a double-screw type conveyor that rotates in the same direction as the steel bowl at
a slightly lower speed (Figure 3.16a). Normally, the decanter centrifuge involves slender
cylindrical- or conical-bowl sections with a relatively large aspect ratio (Figure 3.16b).
Typical bowl speeds are 1,800 to 4,000 rev/min. When mud enters the centrifuge, the
centrifugal force developed by the bowl holds the mud in a pond against the walls of the
pond. In this pond the silt and sand particle settle against the walls and the conveyor blade
scrapes and pushes the settled solids towards the narrow end of the bowl where they are
collected as damp particles with no free liquid. he liquid and clay particles are collected
as overlow from ports at the large end of the bowl. Centrifuge eiciency is afected predominantly by the feed low rate. However, it is also afected by the operating parameters
such as bowl speed (rpm), bowl conveyer diferential speed (rpm), and pool depth.
3.6 Measurement of Drilling Fluids Properties
he API has recommended a drilling luid testing practice. hese are routine tests that are
needed to ensure the quality of drilling luids. Certain tests can be carried out by the mud
engineer to determine the properties of the drilling luid and ensure that it will fulill the
functions described earlier. By carrying out these tests at regular intervals any deterioration in mud quality can be identiied before it causes any problems in the downhole. he
following tests are normally conducted to check the quality of the drilling luids.
i.
ii.
iii.
iv.
Mud density
Mud viscosity
Gel strength
pH determination
v. Filtration test
vi. Sand content
vii. Determination of liquid and solids
content (mud retort)
102 Fundamentals of Sustainable Drilling Engineering
viii.
ix.
x.
xi.
Alkalinity
Water hardness
Water analysis
Chemical analysis
xii. Chloride concentration
xiii. Cation exchange capacity of clays
xiv. Electrical properties
3.6.1 Mud Density
he density of mud weight is an important parameter which determines the hydrostatic
pressure exerted by the mud column. It is determined by weighing a precise volume of
mud and dividing the weight by the volume and is expressed as m. A sample of mud is
weighed in a measuring tool called a mud balance (Figure 3.17). It is a device that is used
to measure the density (weight) of mud. Sometimes mud balance is used to measure
cement or other liquid or slurry. A mud balance consists of a ixed-volume mud cup with
a cap on one end of a graduated beam and a counterweight on the other end. A sliderweight can be moved along the beam. here is a bubble that indicates neutral level of
the beam. Density is read at the point where the slider-weight sits on the beam at a neutral level. he accuracy of mud weight is normally tried to keep within +/- 0.1lbm / gal
3
(+/- 0.01 g / cm ). he mud balance provides the most suitable means of inding an accurate volume. herefore, the density of drilling muds is normally measured with a mud
balance in the rig side area. However, densities of the lowing slurries can be measured
by a gamma ray densitometer (Guest and Zimmerman, 1973). he procedure for the
mud balance is to ill the cup with mud, put on the lid, wipe of excess of mud from the
lid, move the rider along the arm till a balance is obtained, and read the density at the
side of the rider toward the knife edge. hese instruments are rugged, easily calibrated,
and lend themselves to ield use.
A mud balance is calibrated with water or another liquid of known density by adjusting the counter weight. Normally, calibration is performed by
using freshwater, having a known density in pounds per gallon i.e. lbm / gal (also
known as ppg). he reading of the mud balance should be 8.33 lbm / gal, 62.3
lbm / ft 3, or 1.0 SG for freshwater mud. Weight is reported in other units such as
lbm / ft 3 ; kg / m3 ; lbm / in2 / ft or psi / ft ; pptf or psi /1000 ft , kg / L, and kg / cm3 (also
called speciic gravity or SG) are commonly used.
Mud Density is the key to control the formation kick. High mud weight is needed
i) to avoid an inlux of formation luids that can cause mud contamination, corrosion
and kicks or blowouts and ii) to support the walls of the hole for borehole stability.
balance arm
Lid
Rider
Level glass
Knife edge
Fulcrum
Base
(a) Description of mud balance
(b) Mud balance
(c) Pressurized density balance
Figure 3.17 A typical mud balance (courtesy from KFUPM PETE laboratory).
Drilling Fluids 103
On the other hand, low mud weight can permit faster drilling, avoid lost circulation
and combat diferential pressure sticking. Mud density is controlled by adding Barite,
Hematite to increase density and water is added to reduce density. he conversion factors for mud density can be written as
3
Speciic Gravity (SG) = gm / cm
Mud gradient (MGFPS) in psi / ft
lbm / gal
8.33
lbm / gal
19.24
lbm / ft 3
62.3
lbm / ft 3
144
SG 0.433
Mud gradient (MGMKS ) in kg / cm2 / m = SG 0.1
(3.3)
(3.4)
(3.5)
Example 3.3: A mud engineer measured the density of the drilling luid as 10 ppg in
the rig side area. Calculate the speciic gravity in gm / cm3, mud gradient in psi / ft and
kg / cm2 / m.
Solution:
Given data:
= mud density = 10 ppg
m
Required data:
SG
= speciic gravity, gm / cm3
MGFPS = mud gradient, psi / ft
MGMKS = mud gradient, kg / cm2 / m
he speciic gravity of the mud in gm / cm3 can be calculated by using the Eq. (3.3) as:
SG =
lbm / gal
8.33
10
8.33
1.2 gm / cm 3
he mud gradient (MGFPS) in psi / ft can be calculated using Eq. (3.4) as:
MGFPS
lbm / gal
19.24
10
19.24
0.5197 psi / ft
OR
MGFPS
SG 0.433 1.2 0.433 0.5196 psi / ft
he mud gradient (MGMKS ) in kg / cm2 / m can be calculated using Eq. (3.5) as:
MGMKS = SG 0.1 = 1.2 0.1 = 0.12 kg / cm 2 / m
3.6.2 Mud Viscosity
he term viscosity is a measure of a liquid’s resistance to low. It is a property of drilling
luids and/or slurries that indicates their resistance to low. Viscosity is deined as the
ratio of shear stress to shear rate. Sometime, it is called dynamic viscosity. Figure 3.18
104 Fundamentals of Sustainable Drilling Engineering
Moving Plate
F
V
V
L
fixed Plate
V=0
Shearing stress or pressure
Figure 3.18 A typical mud balance.
B
, Bingham yield point
Plastic luids
Transition from plug to laminar low
Plug low
Newtonian luids
, true yield point
TB
Rate shear or velocity
Figure 3.19 Flow behavior of luids.
shows the conventional explanation of the stress-strain relationship for viscosity.
Mathematically viscosity can be expressed as:
Shearing stress
rate of shearing strain
Here,
A
l
F
v
s
dv
dl
s
F/A
dv / dl
(3.6)
= cross-sectional area
= layer thickness
= force
= velocity
= dynamic viscosity of the luid between the plate
= shear stress
= shear rate
= velocity gradient along l-direction
he dimensions of dynamic viscosity are obtained using the Eq. (3.6), which is
MLt 2 / L2 M
. he unit of viscosity is poise (dyne-sec/cm2). For a mud viscosity meaL /t / L
Lt
surement, centipoise (cp) is used because one poise is a high viscosity which is hundred
times larger than centipoise. One centipoise equals one millipascal-second. Viscosity
must have a shear rate to be meaningful otherwise it would be indeterminate. A general behavior of plastic and Newtonian luids is shown in Figure 3.19. It is noted that a
Drilling Fluids 105
certain value of stress (true yield point) must be exceeded in order to initiate movement
for plastic low. A transition zone of decreasing slope in which the low pattern changes
from plug to viscous low follows this. he viscosity of a true (Newtonian) liquid is
constant and equal to the slope of the depicting its stress-strain behavior. herefore, if
the viscosity of a plastic luid is measured in a conventional manner, i.e., the ratio of
shearing stress to rate of shearing strain, the value obtained will depend on the rate of
shear at which the measurements were taken.
Example 3.4: A moving plate with a velocity of 20 cm/s having a cross-sectional area of
10 cm2 is placed 2 cm above a ixed plate. A force of 250 dynes is required to move the
upper plate. Calculate the viscosity of the luid.
Solution:
Given data:
v
= velocity = 20 cm/s
= cross-sectional area = 10 cm2
A
= layer thickness = 2 cm
l
=
force = 250 dynes
F
Required data:
= dynamic viscosity of the luid between the plate, cp
he viscosity of the luid can be calculated using Eq. (3.6) as:
F/A
dv / dl
250 dyne / 10 cm2
20 cm / s / 2 cm
2.5
dyne s
cm2
25 cp
It is well known that Newton’s law of viscosity is the most commonly used model for
studying the luid low in various applications including drilling luid. he Newton
model considers the parallel plate concept in luid low. It is based on a linear relationship between the viscous stress and the rate of strain. A luid that satisies this law is
called the Newtonian luid. he coeicient of proportionality is known as the viscosity that depends only on temperature and pressure and also the chemical composition
of the luid if the luid is not a pure substance. For a Newtonian luid, the viscosity
does not depend on the forces acting upon it at all shear strain rate. Water, some lighthydrocarbon oils, air and other gases are Newtonian luids. However, water, the most
abundant luid on earth, has been considered for centuries as an ideal example of a
Newtonian luid. Li et al. (2007) discovered that when water molecules are forced to
move through a small gap (in nanoscale) of two solid surfaces (hydrophilic/wetting),
its viscosity increases by a factor of 1000 to 10,000, resulting in a behavior similar to
molasses. During their experiment on hydrophobic surfaces, they did not observe
such an increase in viscosity. heir indings are in good agreement with the molecular
dynamics simulation results that show a dramatically decreased mobility for sub-nanometer thick water ilms under hydrophilic coninement. hey concluded that water has
viscous and solid-like properties at its molecular level and is organized into layers. At
the nanometer scale, water is a viscous luid and could be a much better lubricant. his
study received much attention from the general scientiic community as well as the
106 Fundamentals of Sustainable Drilling Engineering
general public because of its potential applications to nanotechnology (Mauk, 2007).
However, the fact that any luid behaves diferently under molecular constrains from
larger scale has been known for some time. he slow-moving low of a thin ilm of liquid
is a ubiquitous phenomenon. his low exists in nature such as in lava lows, the linings
of mammalian lungs, tear ilms in the eye, and in artiicial instances such as microchip fabrication, tertiary oil recovery as well as in many coating processes (Perazzo and
Gratton, 2003). herefore, the natural phenomena, for which viscous luid low exists,
are normally non-Newtonian type of low (Perazzo and Gratton, 2003; Arratia et al.,
2005). In general most of the drilling luids are either emulsions or/and colloids that
behaves as plastic or non-Newtonian luids (Hossain et al., 2007 and Hossain and Islam,
2009). hey also mentioned that almost all the underground hydrocarbons behave as
non-Newtonian luids. In response to the above considerations, Hossain et al. (2007)
developed a new stress-strain relationship, which can be written as:
t
sT
T
T D Ma
0
2
t
1
p
d
x
0.5
0.5
6K
0
p
x
e
E
RT
dux
dy
(3.7)
Here
E
K
Ma
p
R
T
t
= activation energy for viscous low, KJ/mol
= operational parameter
= Marangoni number
= pressure of the system, N/m2
= universal gas constant, KJ/mol – k
= temperature, °K
= time, s
= a dummy variable for time i.e. real part in the plane of the integral
ux = luid velocity in porous media in the direction of x axis, m/s
y
= distance from the boundary plan, m
= surface tension, N/m
= fractional order of diferentiation, dimensionless
= thermal difusivity, m2/s
D
T = TT To =temperature diference between a temperature and a reference temperature, °K
= luid dynamic viscosity, Pa-s
= luid dynamic viscosity at reference temperature T0, Pa-s
o
= shear stress at temperature T, Pa
sT
= ratio of the pseudopermeability of the medium with memory to luid
m3 s1
viscosity,
kg
dux
= velocity gradient along y-direction, 1/s
dy
T
= the derivative of surface tension with temperature and can be positive or
negative depending on the substance, N/m-K
Drilling Fluids 107
It should be mentioned here that the irst part of Eq. (3.7) is the efect of surface tension, the second part is the efect of luid memory with time and the pressure gradient,
the third part is the efect of pressure, viscosity, pseudo-permeability, the fourth part
is the efect of temperature on the stress-strain equation and the ith part is the velocity gradient in the y-direction which is called the rate of velocity change i.e. rate of
shear strain. he second part is in a form of convolution integral that shows the efect
of the luid memory during the low process. his integral has two variable functions
and 2 p /
x where the irst one is a continuous changing function and
of t
is an overlapping function
the second one is a ixed function. his means that t
x in the mathematical point of view. hese two funcon the other function, 2 p /
tions depend on the space, time, pressure, and a dummy variable. In the original reference, there is a negative sign with a power of 0.5, which indicates the direction of low.
herefore, it is not shown here. Interested readers might refer to references of the irst
author of the book including Hossain et al. (2009).
3.6.2.1
Measurement of Mud Viscosity
Mud viscosity is diicult to measure. In general several measuring devices are used.
Further complication generally arises due to the diferent value given by diferent methods. here are two common methods used to measure viscosity at drilling rig area –
i) Marsh Funnel, and ii) Rotational viscometer.
i) Marsh Funnel: Marsh Funnel viscometer is a very quick test that only gives as indication of viscosity and not an absolute result. Measuring viscosity by a Marsh Funnel is
useful as a comparative value and is recorded in seconds. It is a conical-shaped funnel
itted with a small bore tube on the bottom end through which mud lows by the action
of gravity force (Figure 3.20). his test is one of the earliest mud viscosity measurements for ield applications. It is a simple device to measure the viscosity and is used by
mud engineers to check the quality of drilling mud. he funnel consists of a cone of 12
in long, and 6 in diameter at the top; and 2 in long tube at the bottom with 3/16 in internal diameter. A 1/8 in mesh screen is ixed near the top across half the cone to block
the solid particles existence of the mud if any. During the measurement of viscosity, a
Marsh Funnel is put vertically and the end of the tube is closed with a inger. A mud
sample is poured through the mesh to the funnel and it ends when the mesh is reached.
his gives a volume inside of about 1.5 liters. To take the measurement, the inger is
6 in.
1
/8-in.
mesh
screen
12 in.
Copper tube
drilled 3/16 in.
Figure 3.20 Viscosity measuring device: Marsh Funnel and mud measuring cup.
2 in.
108 Fundamentals of Sustainable Drilling Engineering
released and a stopwatch is started. As a result, the liquid starts to run into a measuring
container or cup. he time in seconds is recorded for one quart (946 ml) to low out
into a measuring cup as a measure of the viscosity. So, funnel viscosity is reported in
seconds of a quart, which is referred to as MF ignoring the unit “seconds”. he quart
Marsh Funnel time is 34 – 50 seconds for typical drilling muds. However, mud mixtures
may have a time of 100 or more seconds to cope with some geological conditions. he
measuring technique is simple, quick and foolproof. It still serves as a useful indicator
of change in the mud by comparing mud-in and mud-out sample funnel viscosities.
However, since the low rate varies throughout this test it cannot give a true viscosity.
Moreover, the Marsh Funnel is not a rheometer because it only provides one measurement under one low condition. he funnel viscosity may be used for checking any
radial changes in mud viscosity. Further tests must be carried out before any treatment
can be recommended.
Normally most of the drilling luids are non-Newtonian in nature and exhibit different viscosities at diferent low rates. Pitt (2000) introduced a new formula to measure the efective viscosity by Marsh Funnel. He showed the low behavior of a Marsh
Funnel that is numerically simulated to get a general picture of the meaning of the
Marsh Funnel time. He developed a correlation allowing this to be converted into a
value for efective viscosity. For ield use, the following equation is obtained as
e
M
tM
(3.8)
25
Here
e
tM
M
= the efective viscosity, cp
= the Marsh Funnel (quart) time, s
= density of mud, g/cm3
Example 3.5: A Marsh Funnel is used to measure the density of the drilling luid which
is 1.2 g/cm3 in 50 seconds. Calculate the efective viscosity using Marsh Funnel equation.
Solution:
Given data:
= mud density = 1.2 g/cm3
M
= time = 50 sec
Required data:
= efective viscosity, cp
e
he efective viscosity of the mud in cp can be calculated by using the Eq. (3.8) as:
e
M
tM
25
1.2 50 25
30 cp
ii) Rotational Viscometer: A viscometer is an instrument used to measure the viscosity
of a luid, which is also called viscosimeter. It gives a more meaningful measure of viscosity. A typical Stormer Viscometer is shown in Figure 3.21a. Normally a rheometer is
used for those liquids where viscosities vary with low conditions. In general, either the
luid remains stationary and an object moves through it, or the object is stationary and
Drilling Fluids 109
the luid moves through it. he drag caused by relative motion of the luid and a surface
is a measure of the viscosity. he low conditions must have a suiciently small value of
Reynolds number for there to be laminar low. A sample of mud is sheared at a constant
rate between a rotating outer sleeve and an inner bob. he test is conducted at a range
of diferent speeds such as 600 rpm, 300 rpm, and 100 rpm etc. (laboratory models
can operate at 6 diferent speeds). he standard procedure is to lower the instrument
head into the mud sample until the sleeve is immersed up to the scribe line. he rotor
speed is set at 600 rpm and ater waiting for a steady dial reading this value is recorded
(degrees). he weight or driving force in grams is then used with a calibration chart to
obtain the mud viscosity. his value is the apparent viscosity of the mud measured at a
rate of shear corresponding to 600 rpm of the instrument. he speed is then changed
to 300 rpm and again the reading is recorded. his is repeated until all of the required
dial readings have been recorded. he results can be plotted as shown in Figure 3.21b.
Only two standard speeds are possible on most models designed for ield use. During
the measurement of apparent viscosity in centipoise, the dimensions of the bob and
rotor are chosen so that the dial reading is equal to the apparent viscosity at a rotor
speed of 300 rpm. Now, the apparent viscosity at any other speeds, N is given by:
300
N
app
N
(3.9)
Here
N
N
app
= torque reading from the dial at a speed N, rpm
= rotor speed, rpm
= apparent viscosity at a speed N rpm, cp
Example 3.6: A mud sample in a rotational viscometer gives a dial reading of 450 at 600
rpm and a dial reading of 260 at 300 rpm. Compute the apparent viscosity of the mud
at each rotor speed.
Solution:
Given data:
= torque reading from the dial = 450 for 600 rpm
N
= 260 for 300 rpm
N = rotor speed = 600 and 300 rpm
Required data:
app = apparent viscosity at 600 rpm and 300 rpm, cp
he apparent viscosity of the mud in cp can be calculated by using the Eq. (3.9) as:
app
app _ 600
app _ 300
300 N
N
300 45
22.5 cp
600
300 27
27 cp
300
110 Fundamentals of Sustainable Drilling Engineering
CALIBRATION CURVE FOR STORMER VISCOCIMETER
Vicosity in centipoises
120
100
80
60
40
20
0
0
40 80 120 160 200 240 280 320 360 400
Driving force in grams for 600 rpm
(a) Stormer viscosimeter
(b) Calibration chart
Figure 3.21 Viscosity measuring device.
he viscometer can also be used to determine rheological parameters such as plastic
viscosity and yield point that describe non-Newtonian luid behavior. he other kind of
viscometer, a Fann V-G (viscosity-gel) meter is a multispeed measuring device which
measures the rheological parameters (Figure 3.22a). he high pressure and high temperature (HPHT) viscometer is also shown in Figure 3.22b. In principle, a Fann meter
is like the Stormer where the basic measurement is the torque necessary to revolve an
inner rotor in a stationary, mud-illed test-cup. he spindle is driven by a two-speed
synchronous motor. Torque readings are obtained directly from a dial on the instrument. he instrument constants are adjusted so that the slop of the linear portion of
the low curve may be obtained as the diference between the 600 and 300-rpm torque
readings. his slope is deined as plastic viscosity (rigidity) and is given by centipoise
(Figure 3.23). Plastic Viscosity is thought of as that part of the low resistance caused by
mechanical frictions (i.e. solid content). It is due to the friction between solid particles
in the mud and the viscosity of the dispersed phase (base liquid). It is dependent on
solid content. he plastic viscosity is normally computed using the below relationship:
p
600
300
(3.10)
Here
300
600
p
= torque reading from the dial at a speed of 300 rpm, rpm
= torque reading from the dial at a speed of 600 rpm, rpm
= plastic viscosity, cp
he yield point can be computed using the following formula as:
B
Here
B
= the Bingham yield point,
300
lb f
100 ft 2
p
(3.11)
Drilling Fluids 111
(a) Fann V-G meter
(b) HTHP Pressure Viscometer
Figure 3.22 Viscosity measuring device, courtesy from KFUPM PETE laboratory.
600
Dial delection,
Slope proportional
to plastic viscosity
300
Slope proportional
to apparent (600 rpm)
viscosity
B
0
300
Setting, rpm
600
Figure 3.23 Measurement of plastic low properties with the Fann V-G meter.
From Eq. (3.10) and Eq. (3.11), yield point can be calculated as:
600
B
2
(3.12)
p
In Eq. (3.9), using the dial delection for 600 rpm, the apparent viscosity becomes:
300 600
600
app
1
2
600
(3.13)
he use of Eq. (3.13) forms the Eq. (3.12) as:
B
2
app
p
(3.14)
True yield point can be deined using Figure 3.19 for plastic or Bingham luids as:
3
4
TB
Here
TB
= true Bingham yield point,
lb f
100 ft 2
B
(3.15)
112 Fundamentals of Sustainable Drilling Engineering
In summary, diferent viscosity measuring devices give diferent viscosity of the drilling luid. he Marsh Funnel gives the viscosity, which is useful as a comparative value
and is recorded in seconds. Stormer viscosity provides the apparent viscosity that is
expressed in centipoise. However, it has limited value since it is valid at only one rate of
shear. he Fann V-G meter measures the viscosity, which is called the plastic viscosity
and represents the rate of change of shearing stress with respect to shearing strain over
the linear portion of the consistency curve. Finally, yield point is calculated which is
useful in hydraulic calculations.
Example 3.7: Using the data of Example 3.5, compute the plastic viscosity yield point
and true yield point of the mud sample.
Solution:
Given data:
= torque reading from the dial = 450 for 600 rpm
N
= 260 for 300 rpm
N = rotor speed = 600 and 300 rpm
Required data:
= plastic viscosity, cp
p
= Bingham yield point, lb f /100 ft 2
B
= true yield point, lb f /100 ft 2
T
he plastic viscosity of the mud in cp can be calculated by using the Eq. (3.10) as:
600
p
300
45 26 19 cp
he yield point of the mud can be calculated by using the Eq. (3.11) as:
300
B
p
26 19 7 lb /100 ft
he true yield point of the mud can be calculated by using the Eq. (3.15) as:
T
3.6.3
3
4
B
3
7
4
5.25 lb f /100 ft 2
Gel Strength
Most drilling luids are either colloids or emulsions, which behave as plastic or nonNewtonian luids. Some muds are thixotropic too. hey form gelled structures when
stagnant and liquefy when sheared. he low characteristics of these muds difer from
Newtonian luids (i.e. water, light oils, etc.) and their viscosities vary with the rate of
shear, as shown in Figure 3.19. Apart from the two parameters (i.e. plastic viscosity and
yield point) of a Bingham plastic luid as discussed before, a third non-Newtonian rheological parameter is called get strength. he gel strength is a function of the inter-particle
forces. Gel strength can be deined as a measure of the ability of a colloidal dispersion
to develop and retain a gel form based on its resistance to shear. It is a measure of the
shearing stress necessary to initiate a inite rate of shear. In other word, it can be stated as
the gel, or shear strength of a drilling mud, which determines its ability to hold solids in
Drilling Fluids 113
suspension. It is the ability or a measure of its ability to form gels. Sometimes bentonite
and other colloidal clays are added to drilling luid to increase its gel strength. As gel
strength is directly related to shear stress, it is related to the viscosity of luid. herefore,
the viscosities of plastic luids depend on the rate of shear at which the measurements are
normally taken. Hence, these measurements are normally taken and reported as initial
gel strength and inal gel strength. Fundamentally, for Bingham luids initial gel strength
and true yield value should be the same. Figure 3.24 depicts that the speciic gel strength
of a drilling luid is described as low-lat (most desirable), progressive or high-lat (both
undesirable) according to its measured gel strength versus time, as shown on this plot.
Gel strength can be measured using the viscometer. he Baroid Rheometer is also
used to determine the gel strength of a mud in lb f /100 ft 2 . Ater the mud has remained
static for some time (10 sec) the rotor is set at a low speed (3 rpm) and the delection
is noted. his is reported as the “initial 10-second gel”. he same procedure is repeated
ater the mud remains static for 10 minutes, to determine the “10-minute gel”. Both
gels are measured in the same units as yield point. Gel strength measurement gives an
indication of the amount of gelation that will occur ater circulation ceased and the
mud remains static. he more the mud gels during shutdown periods, the more pump
pressure will be required to initiate circulation again. Gel strength usually appears on
the mud report as two igures (example: 18/26). he irst igure indicates the initial gel
and the second one indicates as the 10-minute gel.
3.6.4
pH Determination
he pH of a drilling luid is a measure of the acidity or alkalinity of the mixing water.
he pH of a solution is the logarithm of the reciprocal of the H concentration in
grams moles per liter, which can be mathematically expressed as:
log
pH
1
(3.16)
log H
H
Diferent types of gel strengths in muds
esirable)
High-flat (und
0.80
0.60
Pr
og
(u
nd ress
i
es
ira ve
bl
e)
Gel strength (lb/100 ft2)
0.70
0.50
0.40
0.30
0.20
Low-flat (desirable)
0.10
0
0
10
20
30
40 50 60
Time (min)
70
80
90
Figure 3.24 Variation of gel strength with time for drilling muds (redrawn from oil glossary).
114 Fundamentals of Sustainable Drilling Engineering
pOH
1
log
(3.17)
log OH
OH
Where (H+) and (OH–) are the hydrogen and hydroxyl ion concentration in moles/
liter. he acidity and the alkalinity of the drilling luid can be measured by the concentration of the [H+] ion in the luid. As for instance, if [H+] is large (1 10 1), then the
[OH–] concentration is very low (1 10 13 ), the solution is strongly acidic. If the [OH–]
concentration is (1 10 1) very high then [H+] concentration is very low then the solution is strongly alkaline. For example, for pure water, pH is equal to 7 where both [H+]
and [OH–] concentrations are same. Since the product {[H+][OH–]} must remain constant for any aqueous solution, an increase in [H+] requires a corresponding decrease in
[OH–]. herefore, a solution in which [OH–] > [H+] is said to be alkaline, and a solution
in which [H+] > [OH–] is said to be acidic.
In general, if the pH of a drilling luid drops from 7.0 to 6.0, the number of [H+]
ions increases ten times. In contrary, if the pOH of a drilling luid drops from 7.0 to
6.0, the number of [OH–] ions decreases ten times. he pH of a mud is seldom below
7 and in most cases, falls between 8 and 12.5 depending upon the type of mud. he
unbalanced pH of the muds afects the rate of mud mixing, borehole stability, mud
properties, corrosiveness, viscosity, gel development, and iltration control. pH is also
important because it afects the solubility of certain organic thinners and the dispersion of clays present in the mud. Corrosion rates are suppressed in muds with pH above
10. herefore, the best desired operating pH for drilling mud is generally 8.5 to 9.5.
Sometimes, pH is kept slightly above 11 if hydrogen sulide (H2S), a poisonous gas, is
suspected in the mud. However, very high pH (above 11.5) should be avoided, because
it is detrimental to most organic additives and causes locculation of clay.
Example 3.8: Find out the pH of an aqueous solution where both [H+] and [OH–] ions
are same and equal to 1 10 7. Find out the pOH also.
Solution:
Given data:
= hydrogen ion concentration = 1 10 7m/l
[H+]
[OH–] = hydroxyl ion concentration = 1 10 7m/l
Required data:
pH = pH of drilling mud, m/l
pOH = pOH of drilling mud, m/l
he pH of the mud in m/l can be calculated by using the Eq. (3.16) and Eq. (3.17) as:
pH
log
pOH
log
1
H
log
1
1 10
log 1 10
7
7
7
7.00
and
1
OH
log
1
1 10
7
log 1 10
7
7
7.00
Drilling Fluids 115
Figure 3.25 Methods of measuring pH Hydrion pH Dispensers (let) and Digital pH Meter (center and
right), courtesy from KFUPM PETE laboratory.
he pH test is used to express the concentration of hydrogen ions in an aqueous solution. his can be done either by pH paper (example: hydrion paper) or by a special
meter. pH paper strips have dyes absorbed onto the paper, which display certain colors
in certain pH ranges (Figure 3.25). It is a useful, inexpensive method to determine pH
in freshwater muds. he main disadvantage is that high concentrations of salts (10,000
ppm chloride) will alter the color change and cause inaccuracy.
Figure 3.25 shows a digital pH meter, which is an electrometric device utilizing glass
electrodes to measure pH. It is a controlled microprocessor and provides very accurate
and reliable measurements with a resolution of 0.01 pH over a full range of 0–14 pH.
It also displays temperature and mV readings simultaneously, on an LCD screen. he
device has the Automatic Temperature Control (ATC) probe in the range of 0 to 100°C,
which automatically adjusts the readout to measure temperature variations in the luid.
he pH readings when the ‘READY’ indicator is displayed are recorded. his shows that
the readings are stable within a range of 0.01 pH.
3.6.5 Filtration Tests
he iltration properties of a luid determine its ability to form a controlled ilter cake
on the sidewalls of the borehole. In a drilling mud, the iltration properties afect borehole stability, smooth movement of the drill string, formation damage, and development time. he ilter cake should not exceed a sixteenth of an inch in thickness and
should be easily removable with the back low. he ilter cake, formed from the solid
constituents in the drilling luid, controls the loss of liquid from a mud due to iltration.
he test in the laboratory consists of measuring the volume of liquid forced through the
mud cake into the formation in a 30-minute period under given pressure and temperature conditions using a standard size cell. here are two commonly determined iltration rates used which are as the low-pressure low-temperature and the high-pressure
high-temperature. Controlled high iltrate will minimize chip hold down and provide
for faster drilling. Low iltrate may be desired to combat a tight hole caused by thick
ilter cake, diferential pressure sticking, and the formation of productivity damage. In
terms of rheology, high viscosity and gel strength may be desired to combat high torque
bridging, drag, and ill caused by borehole cleaning, and to provide good suspension
of weight material. Low viscosity and gel strength result in faster drilling and the more
eicient separation of drilled solids. It has been found in early work that the volume of
luid lost is roughly proportional to the square root of the time for iltration, i.e. v
t.
his procedure is based on the observation as well.
116 Fundamentals of Sustainable Drilling Engineering
“T” scrow
Top cap
Top bar
Rubber gasket
Air hose
Pressure inlet
Mud cup
Frame
Center bar
Graduated cylinder
Support rod
Thumb screw
Support
Cell
Rubber gasket
Fillter paper
Screen
Rubber gasket
Base cap with
iltrate tube
Filtrate tube
Figure 3.26 Standard API Filter Press, courtesy from KFUPM PETE laboratory.
Figure 3.27 High Temperature High Pressure Filter Press, courtesy from KFUPM PETE laboratory.
he ilter press instrument consists of a mud cell, pressure assembly and iltering
device etc. (Figure 3.26). he low-pressure test is conducted using a standard cell under
the API speciication of 100 + 5 psi for 30 minutes at room temperature. Filter press
used for iltration tests that consists of four independent ilter cells mounted on a common frame. Each cell has its own valve such that any or all the cells could be operational
at the same time. Toggle valve on the top of each cell could be operated independently
for the supply of air for each individual cell. Figure 3.27 depicts a special cell, which
must be used to measure iltration rate at high pressure and temperature (500 psi,
300°F). Special high pressure and high temperature iltration tests are run in the laboratory simulating formation temperature and formation back- pressure.
he cell is closed at the bottom by a lid that is itted with a screen. On top of the
screen is placed a ilter paper, which is pressed up against an O-ring seal. A graduated
cylinder is placed under the screen to collect the iltrate. he pressure of 100 psi is
applied for a period of 30 minutes and the volume of the iltrate can then be measured
in cm3. When the pressure is bled of the cell can be opened and the ilter paper is examined. he thickness of the ilter cake is measured in 1/32’s of an inch. It is noted that
this type of test does not simulate downhole conditions in that only static iltration is
being measured. In the wellbore, iltration is occurring under dynamic conditions with
the mud lowing past the wall of the hole.
Drilling Fluids 117
3.6.6 Sand Content
he sand content of a drilling luid is deined as any particle larger than 74 microns in
size, which is measured by using a 200-mesh sieve and a sand content kit. For example,
the Baroid sand content set consists of a 200-mesh sieve, funnel, and a glass measuring
tube calibrated from 0 to 20% to read directly the percentage sand by volume. Figure
3.28 shows the sand content test equipment. he test may be performed on low solids muds as well as on weighed muds. Periodic sand content determination of drilling
luid is important. Excessive sand may result in the deposition of a thick ilter cake
on the wall of the hole. It may settle back into the hole when circulation is stopped.
High sand content also may cause excessive abrasion of pump parts and pipe connections and interferes with drilling tools and the setting of casing. Elutriation, settling, or
sieve analysis determines sand content. Of the three methods, sieve analysis is preferred
because of reliability of test and simplicity of equipment. he volume of sand, including
void spaces between grains, is usually measured and expressed as percentage by volume
of the mud.
he glass-measuring tube is illed with mud up to the scribe line. Water is then added
up to the next scribe line. he luids are mixed by shaking and then poured through
the sieve. he sand retained on the sieve should be washed thoroughly to remove the
remaining mud. A funnel is itted to the top of the sieve and the sand is washed into the
glass tube by a ine spray of water. Ater allowing the sand to settle, the sand content can
be read of directly as a percentage.
3.6.7 Determination of Liquid and Solids Content
Knowledge of the liquid and solid content of a drilling luid is necessary for better
control of the mud properties. Such information will oten explain poor performance
of the mud and indicate whether the mud can best be conditioned by the addition of
water or whether treatment with chemical thinner or the removal of the contaminant
is required. Similarly, proper control of an oil-emulsion mud depends upon knowledge
of the oil content. For muds containing only water and solids, the quantity of each can
be determined from the mud density and from the evaporation of a weighed sample
of mud. Oil and water content can also be obtained measuring the liquid fraction. he
latter method is only applicable to oil emulsion muds. Baroid Oil and Water Retort Kit
are used to determine the amount and type of solids and liquids presence in a drilling
mud sample (Figure 3.29).
Sand ilters
Measuring cylinder
Solids scale
Figure 3.28 Sand Content Set.
118 Fundamentals of Sustainable Drilling Engineering
Figure 3.29 Oil/Water Retort Kit.
(Courtesy from KFUPM PETE laboratory)
A carefully measured sample of mud is placed in the steel container and then heated
in a retort until the liquid components are vaporized. he vapor is passed through a
condenser in which it is cooled and then collected in the measuring glass (i.e. graduated
cylinder). he volume of liquids (oil and/or water) is measured as a fraction of the total
mud volume. he volume of solids (suspended and dissolved) is found by subtracting
from 100%. For accurate results a true mud density should be used for calculations. An
accurate air free sample must be used and a volume correction factor should be determined for oil content if it is present in the mud. he solids volume fraction of mud can
be mathematically obtained as
fs
Here
Cf
fo
fs
fw
1 fw C f
fo
(3.18)
= volume increase factor due to the loss of dissolved salt during retorting
= volume fraction of oil phase in the mud system, vol/vol
= volume fraction of solids in the drilling mud, vol/vol
= volume fraction of water phase in the mud system, vol/vol
Example 3.9: A 11 lbm/gal saltwater mud is retorted and found to contain 8% oil and
72% water. If the chloride test shows the mud to have a chloride content of 79,000 mg
Cl / L, Find out the solid fraction of the mud? Assume that the mud is a sodium chloride mud. he solution has 12% salinity and NaCl has a volume increase factor of 1.045.
Solution:
Given data:
fw = water volume fraction of drilling mud = 0.76
fo = oil volume fraction of drilling mud = 0.08
Cf = volume increase factor due to the loss of dissolved salt during retorting = 1.045
Required data:
fs = solids volume fraction of drilling mud, vol/vol
Drilling Fluids 119
he solid volume fraction can be calculated by using the Eq. (3.18) as:
fs
1 fw C f
fo
1
0.76
1.045
0.08 0.1258
3.6.8 Alkalinity
Although pH gives an indication of alkalinity, it has been observed that the characteristics of a high pH mud can vary considerably despite constant pH. A further analysis
of the mud is usually carried out to assess the alkalinity. herefore, an alkalinity test is
essential to keep the quality of drilling mud. Alkalinity is an indication of the acid neutralizing power of a substance. Alkalinity measurements in drilling luid testing may be
made on the whole mud (designated with a subscript m) or on the iltrate (designated
with a subscript f). he data collected can also be used to estimate the concentrations of
hydroxyl (OH–), carbonate (CO3-2) and bicarbonate (HCO3–) ions in the drilling luid.
Knowledge of the mud and iltrate alkalinity is important in many drilling operations.
Mud additives, particularly some organic delocculants, require an alkaline environment in order to function properly. Alkalinity arising from hydroxyl ions is generally
accepted as being beneicial while alkalinities resulting from carbonates or bicarbonates
may be detrimental to mud performance. he ions that are primarily responsible for
iltrate alkalinity are the hydroxyl (OH–), carbonate (CO3-2) and bicarbonate (HCO3–)
ions. he carbonates can change from one form to another by changing the pH of the
solution. Other inorganic ions such as borate’s, silicates, sulides and phosphates may
also contribute to the alkalinity. It is important to realize the following calculations are
only estimates of the concentrations of the reported ionic species based on theoretical chemical equilibrium reactions. he composition of mud iltrates is oten so complex that the interpretation of alkalinities may be misleading. Any particular alkalinity
value represents all of the ions that will react with the acid within the pH range over
which that particular value was tested. Anionic organic thinners and iltrate reducers
contribute to a large portion of the Mf alkalinity value and may also mask the endpoint color change and render the test highly inaccurate in muds treated with organic
thinners. For simple bentonite-based mud systems containing no organic thinners, the
Phenolphthalein (Pf) and the methyl orange (Mf) alkalinities may be used as guidelines
to determine the presence of carbonate/bicarbonate contamination and the treatment
necessary to alleviate the problem. If organic thinners are present in large amounts, the
conventional Pf/Mf test is suspect, and the P1/P2 method should be used instead.
3.6.9
Water Hardness
Water hardness of drilling luid is due principally to the calcium (Ca2+) and magnesium (Mg2+) ions present in the water. So, hard water has a high mineral content (in
contrast with sot water). he minerals of hard water primarily consist of Ca2+, Mg2+,
and sometimes other dissolved compounds such as bicarbonates (HCO3 ) and sulfates
2
(SO4 ). Calcium usually enters the water as either calcium carbonate (CaCO3), in the
form of limestone and chalk, or calcium sulfate (CaSO4), in the form of other mineral
deposits. he predominant source of magnesium is dolomite (CaMg(CO3)2). Water is
an excellent solvent and readily dissolves minerals when it comes in contact with them.
120 Fundamentals of Sustainable Drilling Engineering
Table 3.9 Classical water hardness scale for drilling muds.
Water Hardness Scale
Classiication
mg/l or ppm
Grains/gal (gpg)
0 – 17.1
0 – 1.0
Slightly hard
17.1 – 60.0
1 – 3.5
Moderately hard
60.0 – 120.0
3.5 – 7.0
Hard
120.0 – 180.0
7.0 – 10.5
> 180.0
> 10.5
Sot
Very hard
As water moves through a formation of soil and rock, it dissolves very small amounts of
minerals and holds them in solution. During the circulation of drilling luid while drilling operations continue, calcium and magnesium dissolved in water and thus makes
water “hard”. Table 3.9 shows the diferent level of hardness scale of water based on the
total concentrations of Ca2+ and Mg2+ iron.
Determination of water hardness (i.e. Ca2+ content) involves a titration of a prepared
solution, sometimes called wet titration. he hardness of water can be estimated by
three types of measurements; i) milligrams per liter (mg/l), ii) parts per million (ppm),
and iii) grains per gallon (i.e. one grain of hardness equals 17.1 mg/L). Usually, hardness
is measured in terms of ppm of CaCO3 or Ca2+ and sometimes weight/volume (mg/l)
of Ca2+. It means that total water ‘hardness’ (including both Ca2+ and Mg2+ ions) is read
as ppm or mg/l of CaCO3 in the water. Although water hardness usually measures only
the total concentrations of Ca2+ and Mg2+ iron, aluminium, and manganese may also be
present at elevated levels in some geographical locations. Soda ash (i.e. Na2CO3) is used
in water-based muds as a source of carbonate ions to precipitate calcium, increase pH
or locculate spud muds. It is a weak base that is soluble in water and dissociates into
sodium (Na ) and carbonate (CO3 2 ) ions in solution. he chemical reaction of calcium/
magnesium precipitation can be described as:
Ca 2 or Ma
2
Na2CO3
CaCO3 or (MaCO3 )
Na
(3.19)
3.6.10 Water Analysis
Water analysis of mud is necessary because the existence of chemical content may
afect the selection of the mud type. he invasion of water and soluble salts may change
the properties of the mud in drilled formations. Usually the simple tests for alkalinity,
chloride and hardness serve to identify any objectionable contaminants from water.
Occasionally, a more detailed analysis is needed that are available in literature.
3.6.11 Chemical Analysis
he chemical analysis is an important test to ind out the concentration of diferent
ions that exist in drilling mud. hese analyses may be used for formation identiication,
Drilling Fluids 121
compatibility studies, quality control, or evaluation of pollution problems. he concentration of hydroxyl (OH–), chloride (Cl–), sulides (S–2), potassium (K+), formaldehyde
(CH2O), etc. are required to control for mud quality, which is an API standard. he test
kits contain all chemicals, equipment and glassware for measurement in the ield. For
results of these analyses to be accurate and reliable, care must be exercised in taking
the drilling luid samples. Most chemical analyses are performed on the drilling luid
iltrate rather than the drilling luid. To obtain a sample of drilling luid iltrate, the
drilling luid is iltered using a standard API, 100 psi (690 kPa) ilter press or a high
temperature high pressure ilter press. his operation removes all solids but leaves the
dissolved salts. Some iltrates are so darkly colored the iltration endpoints cannot be
seen. Literature shows that certain chemical analyses are useful in the control of mud
performance. For example, an increase in chloride content may adversely afect mud
properties unless the mud has been designed to withstand contamination by salt. he
detail analysis is available in API RP 13B.
3.6.12 Chloride Concentration
he amount of chloride (Cl–) in the mud is a measure of the salt contamination from
the formation. Chloride concentration increases due to the entrance of salt and subsequently contaminates the mud system. his situation arises when a salt formation is
drilled or saline formation water enters the wellbore. he Cl– concentration is determined by titration with silver nitrate (AgNO3) solution. his procedure results the Cl–
to be removed from the solution as AgCl, a white precipitate. he chemical reaction is
obtained as:
Ag
Cl
AgCl
(3.20)
he endpoint of the titration is identiied using a potassium chromate K 2CrO4 indicator. he excess Ag+ present ater all Cl– has been removed from solution reacts with the
chromate (CrO4 2) to form Ag 2CrO4 which is an orange red precipitate. he chemical
reaction is obtained as:
Ag
CrO4 2
Ag 2CrO4
(3.21)
he above procedure involves taking a small sample of iltrate, adding phenolphthalein
and titrating with acid until the color changes. Add 25 – 50 ml of distilled water and
a small amount of potassium chromate solution. Stir continuously while silver nitrate
is added drop by drop. he end point is reached when the color changes. he chloride
content is calculated from:
Cl content in ppm
ml of AgNO3
ml of filtrate sample
(3.22)
3.6.13 Cation Exchange Capacity of Clays
he clay content of a drilling luid has the ability to exchange free cations located in the
aqueous solution. A well-known application of the ion exchange reaction is the sot ening of water. Ion exchange reactions in the drilling luids are important because the
122 Fundamentals of Sustainable Drilling Engineering
ability of the clay particles to hydrate depends greatly on the presence of free cations.
he ability of one cation to replace another depends on the nature of the cations and
their relative concentrations. he common cations will replace each other when present
in the same concentration in the order as shown by Eq. (3.23):
Al 3
Ba2
Mg 2
Ca2
H
K
(3.23)
Na
However the order, as shown in Eq. (3.23), can be changed by increasing the concentration of the weaker cation presence. Many organic compounds also absorb in clay
structures.
Methylene blue is a dye. If it is allowed to dry on glassware or other laboratory equipment, it will cause a stain that is diicult or impossible to remove. herefore, it is recommended i) to avoid spilling methylene blue, ii) thoroughly wash and dry all laboratory
equipment and glassware immediately ater use, and iii) make sure methylene blue bottles are closed tightly ater use. he methylene blue dye test (MBT) is used to determine
the cation exchange capacity of the solids present in a drilling mud. he methylene
blue capacity gives an estimate of the total cation exchange capacity of the solids in
the drilling luid. he methylene blue capacity of a drilling luid is an indication of the
amount of reactive clays (i.e. bentonite or drilled solids) present as determined by the
methylene blue test. Only the reactive portions of the clays present are involved in the
test. Materials such as barite, carbonates and evaporites do not afect the results of the
test since these materials do not adsorb methylene blue. he methylene blue capacity
and the cation exchange capacity are not necessarily same. It is normally somewhat less
than the actual cation exchange capacity.
Methylene blue solution is added to a sample of drilling luid that has been treated
with hydrogen peroxide and acidiied until saturation is noted by the formation of a
“dye halo” around a drop of solids placed on ilter paper. Drilling luids frequently contain substances in addition to reactive clays that also absorb methylene blue dye. Pretreatment with hydrogen peroxide removes these efects from organic materials such as
lignosulfonates, lignites, cellulosic polymers and polyacrylates, etc. he methylene blue
capacity is measured by Eq. (3.24) as:
Methylene Blue in ml
Drilling Fluid or mud sample in ml
Methylene Blue Capacity
(3.24)
he methylene blue capacity may also be reported as pounds per barrel of equivalent
bentonite, based on bentonite with a cation exchange capacity using Eq. (3.24) and
which is by Eq. (3.25) and Eq. 3(26).
Bentonite equivalent,
Bentonite equivalent,
lbm
bbl
kg
m3
5 Methylene Blue Capacity
2.85 Bentonite equivalent in
lbm
bbl
(3.25)
(3.26)
Figure 3.30 shows the methylene blue test kit model of 425. Fann Instrument Company
ofers a complete methylene blue test kit containing all reagents, glassware and hardware required to perform the methylene blue test according the API recommended
Drilling Fluids 123
(a) Model 425 test kit
(b) Model 168-00/168-00-1(OFI Testing Equipment, Inc.)
Figure 3.30 Methylene blue test kit.
practice. All items are neatly packaged in a rugged stainless steel carrying case. hey
also ofer the replacement parts and reagents including methylene blue solutions in
varying container sizes.
3.6.14 Electrical Properties
Mud resistivity is one of the most important electrical properties of the mud.
i) Mud Resistivity: is the resistance to low of electrical current through mud sysm) . Drilling mud is inluenced by
tem. he resistivity is measured in ohm-m (
the dissolved salts (in ppm or gpg) and the insoluble solid material contained in
the water portion. he resistivity of mud is inversely proportional to the dissolved
salt concentration i.e. the greater the concentration of dissolved salts, the lower
resistivity of the solution. herefore, freshwater muds usually have high resistivity
and saltwater muds have low resistivity. Unlike metals, the resistivity of a solution
decreases as temperature increases. It is necessary to measure resistivity because the
mud, mud cake, mud iltrate resistivity exert a strong efect on the electric logs taken
in that mud. he mud resistivity varies greatly from the actual resistivity values due
to the various factors encountered in the actual operation. A system for measuring
resistivity of the formation is attached at the lower end of a casing string while drilling operations continue. he drilling assembly includes all the necessary equipment
(explained in Chapter 2), where the motor and bit are electrically isolated from the
casing string. Formation resistivity measuring device is provided in the assembly.
A data transmission mechanism is provided for encoding the resistivity data and
transmitting it through the drilling luid to the surface location of the wellbore.
Figure 3.31 shows the analog and digital resistivity meters. his testing equipment is
the Baroid or Fann Resistivity Meter.
124 Fundamentals of Sustainable Drilling Engineering
Figure 3.31 Analog (let) and digital (right) resistivity meters.
(Courtesy from KFUPM PETE laboratory)
3.7 New Drilling Mud Calculations
he most common mud engineering calculations are those concerned with the changes
of mud volume and density caused by the addition of various solids or liquids to the
system. For mud calculations, the irst step is to calculate the system volume, which is
the sum of the mud in the hole and surface pits. While the surface volume is readily
obtained from the pit size, the downhole volume is diicult to determine. Boreholes are
not always cut to gauge (the same size as bit) and unless a caliper log is available, which
is unusual at the time of drilling, the true hole size must be estimated. here are two
basic assumptions during drilling mud calculations: i) the volumes of each material are
additive. his may immediately raise a question concerning bentonite and water mixtures since it is known that bentonite swells when wet. his expansion is due, however,
to the adsorption of water, hence the clay volume increase is at the expense of water
volume, and the total volume (clay plus water) is, for practical purposes, unchanged, ii)
the weights of each material are additives. Solid content of the mud can be calculated
using the following equations.
Vsc Vm1 Vm2
(3.27)
Here
Vm1 = volume of initial mud (or any liquid) in mud calculation, bbl, cc
Vm2 = volume of new mixture in mud calculation, bbl, cc
Vsc = volume of solids in mud calculation, bbl, cc
scVsc
m1Vm1
m2 Vm2
Here
sc
m1
m2
= density of solids, gm/cc
= density of initial mud, gm/cc
= density of new/inal mud (i.e. freshwater and clay), gm/cc
(3.28)
Drilling Fluids 125
Equation (3.27) and (3.28) can be solved for solid volume and product of solid volume
and density as:
Vsc
Vm2
m2
m1
(3.29)
m2
sc
Equation (3.29) is not very useful because the net volume of a powdered solid is not
readily measureable. However, the corresponding weight to add is:
scVm 2
scVsc
m2
m1
(3.30)
m2
sc
In terms of volume percentage, Eq. (3.29) can be written as:
Vsc
Vm2
m2
m1
sc
m1
(3.31)
100
Example 3.10: A 10.0 lbm/gal mud contains clay of speciic gravity of 2.5 and freshwater.
Compute volume percentage and weight percentage of clay in this mud.
Solution:
Given data:
= density of solids (i.e. clay) = 2.5 x 8.33 = 20.825 gm/cc
sc
= density of initial mud (i.e. freshwater) = 8.33 gm/cc
m1
= density of inal mud (i.e. freshwater and clay) = 10.0 gm/cc
m2
Required data:
Vsc
= volume in percentage
Vm2
scVsc
= weight in percentage
scVm2
he solid volume in percentage can be calculated by using the Eq. (3.31) as:
Vsc
Vm2
m2
m1
sc
m1
100
10.0 8.33
20.825 8.33
100 13.37%
he solid weight in percentage can be calculated as:
scVsc
sc
m2Vm2
m2
Vsc
Vm2
sc
m2
m2
sc
m1
m2
100
20.825 10.0 8.33
100 27.83%
10 20.825 8.33
3.8 Design of Mud Weight
In general drilling mud is composed of four major components – i) water or brine
phase, ii) an oil phase, iii) low density solids, and iv) high density solids. hese four
components are immiscible i.e. no component dissolves in any other component to
126 Fundamentals of Sustainable Drilling Engineering
any signiicant degree. his means that the four components form an ideal mixture.
Mathematically, the sum of the four components volumes equals the total volume of
the inal mixture.
Vmix
Here
Vmix
Vw
Vo
Vls
Vhs
(3.32)
Vw Vo Vls Vhs
= volume of inal mixture i.e. mud
= volume of the water phase in the mud system
= volume of oil phase in mud the mud system
= volume of the low density solid in the mud system
= volume of the high density solid in the mud system
Employing Eq. (3.32), the total weight of the luid mixture is simply the sum of the
weights of the components. he conservation of mass ensures that the total weight calculation is always correct.
mixVmix
mmix
wVw
oVo
lsVls
hsVhs
(3.33)
Here
mmix = mass of inal mixture i.e. mud
mix = overall density of luid mixture i.e. mud
= density of water phase in the mud system
w
= density of oil phase in the mud system
o
=
density of the low density solid in the mud system
ls
= density of the high density solid in the mud system
hs
From Eq. (3.33) the overall density of the luid mixture (i.e. mud) can be written as:
mix
w
Vw
Vmix
o
Vo
Vmix
ls
Vls
Vmix
hs
Vhs
Vmix
(3.34)
In terms of volume fraction, Eq. (3.34) can be written as:
mix
w
fw
o
fo
ls
f ls
f hs
f ls
hs
f hs
(3.35)
where,
fw
Here
fw
fo
f ls
f hs
fo
1
(3.36)
= volume fraction of water phase in the mud system
= volume fraction of oil phase in the mud system
= volume fraction of low density solid in the mud system
= volume fraction of high density solid in the mud system
he speciic gravities of typical drilling luid solids are illustrated in Table 3.10. he
density changes in temperature and pressure will change the volumes of the components. Literature shows that mud compositions including solids might have a signiicant change due to the changes of pressure and temperature.
Drilling Fluids 127
Table 3.10 Speciic gravity of solids in drilling luids
Drilling luid
component
Speciic
gravity
Drilling luid
component
Attapulgite
2.89
Cuttings
Barite
4.2
Galena
Bentonite
2.6
Calcium chloride
1.96
Speciic
gravity
Drilling luid
component
Speciic
gravity
Limestone
2.8
7.50
Sand
2.63
Hematite
5.05
Siderite
3.08
Ilmetite
4.6
Sodium chloride
2.16
2.6
Example 3.11: A well is drilled to a depth of 8000 t. he top of the oil formation is at
7600 t. and the bottom is at 8000 t. he pore pressure at 7600 t. is 3600 psi. Calculate
the following:
a.
b.
c.
d.
Calculate the mud weight in pcf to balance the pore pressure at 7600 t.
What mud weight should be used to over balance the pore pressure by 300 psi?
What the over balance pressure if 10.6 ppg mud is used?
If the fracture gradient of the formation at 7600 t.is 0.75 psi/t, what is
the bottomhole pressure that will fracture the formation?
e. What is the surface pressure that will fracture the formation at 7600 t.if
the hole is full of water?
Solution:
Given data:
hTVD = total vertical depth = 8,000 t
hot = top of oil formation at a depth = 7,600 t.
hob = bottom of oil formation at a depth = 8,000 t.
PTVD = pressure at a depth 7,600 t.= 3,600 psi
Required data:
P x 144
a)
L
P x 144
b)
L
c)
Ph
L
144
3600 x 144
73.89 pcf
7600
10.6 x 7.48 7600
4184 psi
144
Overbalance
4184 3600 584 psi
d)
Fracturing pressure
e)
Ps
Ph
Pb
Ps
Pb
Ph
62.4 x 7600
5700
68.21 pcf
7600
3900 x 144
= 7600 x 0.75
= 5700 psi @ 7600
144
5700 3293 2406 psi
128 Fundamentals of Sustainable Drilling Engineering
3.9 Current Developments in Drilling Fluids
In its endeavor to provide a sustainable low of hydrocarbon energy, the petroleum
industry has been recognized by the general public as an industry that has negatively
impacted the environment as a result of using either harmful materials or risky practices. his leads the industry to continuously invest in R&D to develop environmentally
friendly technologies and products. For any new technology or product, the current
R&D trend is toward the development of sustainable practices and expertise. As we
know, drilling luids are necessary for drilling oil and gas wells. Unfortunately, drilling
luids have become increasingly more complex in order to satisfy the various operational demands and challenges. he materials used in the process to improve the quality and functions of the drilling luids, contaminates the subsurface and underground
systems, landills, and surrounding environment. Due to the increasing environmental
awareness and pressure from environmental agencies throughout the world, it is very
important to look back at the drilling luid technology to reassess its progress while it
tries to take steps forward to improve the petroleum industry’s position as an environmentally friendly industry. Recently, Apaleke et al. (2012a and 2012b) conducted an
extensive review on the current development of mud system.
3.9.1
Formulation of WBM
he water-based drilling luids, which simulate the performance of oil-based drilling
luids, are commonly referred to as high-performance water-based muds (HPWBM)
(Morton, 2005; West and Morales, 2006; Dye, 2006; Patel, 2007; Marin et al, 2009). he
main beneits of HPWBM include the reduction of environmental impacts, and lower
down costs associated with cuttings and luids disposal. Reid et al. (1992) evaluated a
novel inhibitive water-based luid for tertiary shale that was formulated primarily from
tetra-potassium pyrophosphate. hey observed that the formulation was considerably
more inhibitive than other mud systems (even approached the level of that observed
with OBM). Kjosnes et al. (2003) designed a water-based mud from a mixture of potassium chloride and polymers such as polyanionic celluoses/xathan gum. When this mud
is applied, they observed that the formulation resulted in improved hole cleaning optimization, and hole stability.
Al-Ansari et al. (2005) formulated a HPWBM comprising of partially hydrolyzed polyacrylamide (PHPA, for cutting encapsulation) and polyamide derivatives
(for suppressing the hydration and dispersion tendency of reactive clays). hey concluded that the formulation which had been used successfully to drill several wells in
the Arabian Gulf is an environmentally friendly and performance driven alternative
to OBM. Young and Ramses (2006) developed a unique water-based luid by blending a hydration suppressant, a dispersion suppressant, a rheology controller (xathan
gum), a iltration controller, and an accretion suppressant. he formulation according
to them delivered an invert emulsion-like drilling performance. Ramirez et al. (2007)
developed an aluminum-based HPWBM that was used successfully to drill an exploratory well in the Magellan Strait, Argentina. hey claimed that the HPWBM not only
replaced the oil-based mud, it was also environmentally friendly. Marin et al. (2009)
formulated a HPWBF from a blend of salt and polymers at diferent mud weights. hey
Drilling Fluids 129
recommended the inclusion of sized calcium carbonate if drilling through high permeability sands.
3.9.2
Formulation of OBM
OBM is the most efective drilling luid when drilling or exploring for oil in frontier areas
where extremely high geothermal gradients are a major challenge. However, recently,
there have been concerns about the restrictions of its use globally due to stifer government regulations, the very high cost of disposal and treatment of cuttings from the use of
OBM. Nowadays, the costs of formulation have received more attention from researchers than improved formulations (Oakley et al., 1991). Miller (1950) reported that muds
containing air blown asphalt were the most efective due in part to their superior plastering properties and lexibility of temperature range. Oakley et al. (1991) designed an oilbased mud based on oil-soluble polymers (amidoamines and imidazolines) that would
reduce the oil on drill cuttings. Based on the results from their laboratory tests, they
concluded that oil on cuttings can be reduced by up to 30% on current 50:50 oil-water
ratio. Herzhet al. (2003) studied the inluence of temperature and clay/emulsion microstructure on oil-based mud of low shear rate rheology. hey concluded that organophilic
clays, in interaction with the emulsion droplets, are responsible for the low shear rate.
Chen et al. (2004) formulated an oil-based mud system using VERSA, LLD, BOO, and
NOVA (emulsifying and oil-wetting agents) to study the efects of OBM invasion on
irreducible water saturation. heir experimental indings show that originally strong
water-wet Berea and limestone cores were altered to become intermediate-wet or oil-wet
by OBM surfactants thus faulting the assumption of water-wetness by the NMR T2 cutof model which generally underestimates the value of irreducible water saturation (Swir).
hey proposed that the magnitude of underestimation depends on the type of OBM surfactants, their concentration in the lushing luid, and the lushing time. hey suggested
that the efects of OBM invasion on the NMR misinterpret the real drilling process when
wettabilty alteration occurs. Controlling the invasion volume and the concentration of
OBM surfactants in the invasion luid can minimize this efect.
3.9.3
Formulation of Gas-based Mud
Most of the technological improvements seen in the drilling of well with air have come
from the mining industry, which is primarily associated with shallow large bore wells.
he oil and gas industry has failed to make the same technological advancement in air
drilling compared to wells drilled with liquid or mud systems (Mellot, 2008). However,
the followings are some of the current trends in the use of air for drilling:
Foam: his involves the injection of a dilute solution of a suitable foaming into the air
stream. Foam efectively removed cuttings at lower annular velocities that was possible
with air alone (Mellot, 2008).
Aerate Mud: his involves the direct injection of compressed air from a 3-stage
compressor through the standpipe into the mud system. A special check valve is placed
in the drill string one joint below the Kelly to prevent the problem of mud spray when
making connections (Kenneth et al., 2007).
130 Fundamentals of Sustainable Drilling Engineering
Gel Foam and Stif Foam: Basically, this is the use of prepared a slurry consisting of
(by weight) 98% water; 0.3% soda ash; 3.5% bentonite; 0.17% guar gum; and 1% volume
of a suitable commercially available foaming agent. In recent formulations, guar gum has
been substituted by other polymers and bentonite by other clays (Crews, 1964).
3.9.4 Development of Environment-Friendly Mud System
he current trend in drilling luid development is to come up with novel environmentally friendly drilling luids that will rival the OBM in terms of low toxicity level, performance, eiciency, and cost. Several researchers have come up with formulations for
drilling luids with minimal but not zero environmental impact. E Van Dort et al. (1996)
formulated an improved water-based drilling luid based on soluble silicates capable of
drilling through heaving shale, which is environmentally friendly. However, this is not
recommended because silicate has the potential to damage the formation. Shake et al.
(1999) suggested the use of micro-sized spherical mono-sized polymer beads as a blend
to WBM to improve lubrication. haemlitz et al. (1999) formulated a new environmentally friendly and chromium-free drilling luid for HPHT drilling based on only two
polymeric components. Brady et al. (1998) came up with a polyglycol enriched waterbased drilling luid that will provide high level of shale inhibition in freshwater and
low salinity water-based drilling luid. However, this formulation has a defect. here
must be a presence of electrolytes in the mud system to get the optimum performance.
Nicora et al. (1998) developed a new generation dispersant for environmentally friendly
drilling luids based on zirconium citrate. he zirconium citrate is used to improve the
rheological stability of conventional water-based luids at high temperature. However,
this formulation has a limitation in that the concentration of zirconium citrate may be
depleted in the drilling luid due to solids absorption.
To avoid some of the above mentioned problems, Sharm et al. (2001) developed an
environmentally friendly drilling luid which can efectively replace oil-based drilling
luid by using eco-friendly polymers derived from tamarind gum and tragacanth gum.
Tamarind gum is derived from tamarin seed while tragacanth gum is from astragalus gummiier. his formulation is also cheaper and has less damaging efect on the
formation. Hector et al. (2002) developed a formulation with a void toxicity based on
a potassium-silicate system. he advantage of this formulation apart from being environmentally friendly is that cuttings from the use of this drilling luid can be used as
fertilizer. Warren et al. (2003) developed a formulation based on water-soluble polymer
amphoteric cellulose ether (ACE), which is cheaper, low in solids content, environmentally friendly but with some potential to damage the formation. Davidson et al. (2004)
developed a drilling luid system that is environmentally friendly. It also removes free
hydrogen sulphide, which may be encountered while drilling based on ferrous iron
complex with a carbohydrate derivative (ferrous gluconate). Ramirez et al. (2005) formulated a biodegradable drilling luid. It maintains hole stability and also enables drilling through sensitive shale based on an aluminum hydroxide complex (AHC). his
formulation contains some blown asphalt and therefore possesses some environmental
problems. Dosunmu et al. (2010) developed an oil-based drilling luid based on vegetable oil derived from palm oil and groundnut oil. he luid did not only satisfy environmental standards, it also improved crop growth when discharged onto farmlands.
Drilling Fluids 131
he eforts of all these researchers brought drilling luid technology to a more
responsible position, which is to some extent environmentally friendly and cost efective. However, these formulations still do not have zero environmental impact. h is
leads to the question, is the development of a zero impact environmentally friendly
drilling luid possible?
3.9.5 Application of Nanotechnology
Nano-Silica, nano-graphene, and other nano-based materials have been proposed for
use as alternative mud additives. A nanomaterial based mud system is deined as that
mud containing at least one additive with particle size in the range of 1–100 nanometers (Amanullah et al., 2009). It is based on the number of nano-sized additives in the
mud system. Mud systems can be classiied as simple nano-mud system or advanced
nano-mud system. Nanomaterials in mud systems are expected to reduce the total solids and/or chemical content of such mud systems and hence reducing the overall cost
of mud system development.
3.9.6 Application of Biomass
Cellulose is the main component on the cell walls of trees and other plants. Its purest
form is called nanocrystalline cellulose (NCC), which is treated as a strengthener and
stifener of materials. Currently, a number of oil companies in Canada have teamed up
to conduct research into the possibility of using NCC as an alternative drilling luid
additive toward the development of a sustainable mud system.
3.10 Future Trend on Drilling Fluids
here are challenges to further improve mud engineering technology. hose challenges
need to be fulilled by the researchers in future. Recently, Apaleke et al. (2012a and
2012b) conducted an extensive review on the future development of drilling luid as
challenges and trend of the mud engineering.
3.10.1 Cost Analysis
he cost of developing environmentally friendly OBM for ield application is a future
challenge because of its high cost. he future of research in drilling luid development should be directed towards the formulation of an environmentally friendly drilling luid with zero impact on the environment. his is pertinent because incidents
of environmental pollution due to the discharge of oil-based drilling wastes into the
environment keep increasing, while the regulations set by the government agencies
and NGOs of diferent countries are restricting the use of OBMs. herefore, the use of
OBM is becoming stricter. To solve the stringent pollutant contents from mud systems,
Ammnullah (2010) proposed the use of waste vegetable oil in the formulation of environmentally friendly OBM. Ogunrinde and Dosunmu (2010) suggested the use of palm
oil. A major multinational oil company for ofshore drilling operations had used highly
132 Fundamentals of Sustainable Drilling Engineering
de-aromatized aliphatic solvents to formulate low toxicity mud system. Although these
formulations have zero environmental impact, they are very expensive. As a result,
bringing their cost of formulation down so that overall cost of drilling becomes cheaper
is deinitely a challenge.
3.10.2 Development of Environment Friendly Mud Additives
he hazardous efects of additives such as defoamers, descalers, thinners, viscosiiers,
lubricants, stabilizers, surfactants and corrosion inhibitors on marine and human life had
been reported. Efects range from minor physiological changes to reduced fertility and
higher mortality rates. For example, Jonathan et al. (2002) reported that ferro-chrome
lignosulfonate (a thinner and delocculant) afected the survival and physiological
responses of ish eggs and fry. he iltration control additive CMC (carboxymethylcellulose) causes the death of ish fry at high concentrations (1000–2000 mg/ml) and physiological changes start the level of at 12–50 mg/ml. On the other hand, corrosion inhibitors
such as phosphoxit-7, EKB-2-2, and EKB-6-2 cause genetic and teratogenic damages
in humans. Another example of the use of toxic additive in OBM formulation was the
dumping of 896 tons of drilling mud containing SOLTEX that damaged the coast of
Great Britain. When questioned, both the company and the government body overseeing the industry provided only the trade name of the active additive in the dumped
drilling mud as SOLTEX with no reference to the fact that SOLTEX contained potentially toxic heavy metals as revealed by Greenpeace in a publication in 1995. Information
provided in the product data sheet of some additives has revealed that these additives
can cause cancer in an individual if he/she is exposed to them. It is well recognized that
toxic additives are the high performers. So, how will they be replaced? Answering this
question obviously is one of the future challenges researchers will have to contend with.
3.10.3 Sustainability
Drilling luid’s position is still in a challenging environment if its status is analyzed
based on sustainability, though there is a tremendous advancement in this technology.
It is due to the complex formulation of the mud system, which is needed to meet the
diferent desired properties for smooth functioning while drilling. In addition, mud
system’s sustainability has to do with two issues: 1) Ensuring the continuous availability of the base oils used in the formulation of environmentally friendly mud systems,
2) Executing a complete drilling program in a safe and environmentally friendly
manner. hese two issues put forward a challenging environment to the researchers.
Recently, Hossain (2011) proposed a sustainable drilling pathway. He also proposed a
diagnostic test procedure toward the greening of the drilling luid system. Following
up on his proposed protocol is a real challenge for the petroleum industry because of
cost, the need for technological advancement, and availability of the innovative sustainable chemical additives. he initial steps should come considering the environmentally
friendly base oils with zero toxicity as opposed to the use of conventional base oil. he
sources are from plants where there is no use of toxic or unhealthy materials during the
entire process. hese objectives provide researchers a challenging situation for achieving their goals. Ensuring resource availability in a timely manner is also a big challenge.
Drilling Fluids 133
3.10.4 Development of Mud and/or Additives for HTHP Applications
In extremely high-temperature and high-pressure (HTHP) situations, mud systems
formulated with macro- and micro-based materials (chemicals and polymers) become
drastically altered (Amanullah et al., 2009). his is due to the breakage or association of
polymer chains and branches by vibration, Brownian motion and thermal stress causing
a drastic reduction in gelling and viscous properties. To solve this problem, nanos with
excellent thermal stability and with extreme pressure consistency should be developed.
3.11 Summary
he chapter covers almost all the fundamental and basic components of mud engineering. However, the industry and laboratory practices are not covered extensively in the
chapter because it is available in any drilling luid manual and scope of the book. A
state-of-the-art literature review on drilling luid has been completed, in order to give
an idea about overall mud engineering. he chapter presents the current trends and
the future challenges of the technology and also identiies where R&D personnel need
to focus their attention. In addition, future research guidelines are presented focusing
on the development of environmentally friendly drilling luids with zero impact on the
environment. Eforts should be intensiied to develop alternatives that will transform
current mud technology into a more sustainable industry. In drilling luid technologies, two main trends are currently being practiced: i) the search for new additives to
increasing the performances of WBM and ii) the development and introduction of new
combinations and ingredients for OBM.
3.12 Nomenclature
A
dB
Cf
E
K
F
f ls
f hs
fo
fs
fw
l
p
Ma
mmix
N
R
= cross-sectional area
= bit diameter
= volume increase factor due to the loss of dissolved salt during retorting
= activation energy for viscous low, KJ/mol
= operational parameter
= force
= volume fraction of low density solid in the mud system, vol/vol
= volume fraction of high density solid in the mud system, vol/vol
= oil volume fraction of drilling mud, vol/vol
= solids volume fraction of drilling mud, vol/vol
= water volume fraction of drilling mud, vol/vol
= layer thickness
= pressure of the system, N/m2
= Marangoni number
= mass of inal mixture i.e. mud
= rotor speed, rpm
= universal gas constant, kj/mole – k
134 Fundamentals of Sustainable Drilling Engineering
= rate of penetration of the bit, t/hr
= temperature, °K
= time, s
= the Marsh Funnel (quart) time, s
= luid velocity in porous media in the direction of x axis, m/s
= velocity
Vls = volume of the low density solid in the mud system, bbl, cc
Vhs = volume of the high density solid in the mud system, bbl, cc
Vmix = volume of inal mixture i.e. mud, bbl, cc
Vm1 = volume of initial mud (or any liquid) in mud calculation, bbl, cc
Vm2 = volume of mixture in mud calculation, bbl, cc
Vs = solid volume of rock fragments entering the mud i.e. volume of cuttings, bbl/hr
Vsc = volume of solids in mud calculation, bbl, cc
Vw = volume of the water phase in the mud system, bbl, cc
Vo = volume of oil phase in mud the mud system, bbl, cc
y
= distance from the boundary plan, m
= fractional order of diferentiation, dimensionless
=
thermal difusivity, m2/s
D
= density of the low density solid in the mud system, g/cm3
ls
= density of the high density solid in the mud system, g/cm3
hs
= density of mud, g/cm3
M
m1 = density of initial mud, gm/cc
m2 = density of inal mud (i.e. freshwater and clay), gm/cc
3
mix = overall density of luid mixture i.e. mud, g/cm
= density of water phase in the mud system, g/cm3
w
= density of oil phase in the mud system, g/cm3
o
= density of solids, gm/cc
sc
= average formation porosity
A
N = torque reading from the dial at a speed N, rpm
300 = torque reading from the dial at a speed of 300 rpm, rpm
600 = torque reading from the dial at a speed of 600 rpm, rpm
= viscosity of the luid between the plate
=
shear stress
s
= shear rate
= a dummy variable for time i.e. real part in the plane of the integral
= surface tension, N/m
T = TT To =temperature diference between a temperature and a reference temperature, °K
= luid dynamic viscosity, Pa-s
app = apparent viscosity at a speed N rpm, cp
= the efective viscosity, cp
e
= luid dynamic viscosity at reference temperature T0, Pa-s
o
= plastic viscosity, cp
p
lb f
= the Bingham yield point,
B
100 ft 2
RROP
T
t
tM
ux
Drilling Fluids 135
TB
sT
= the true Bingham yield point,
lb f
100 ft 2
= shear stress at temperature T, Pa
= ratio of the pseudopermeability of the medium with memory to luid viscosity,
m3 s1
kg
dux
= velocity gradient along y-direction, 1/s
dy
dv
= velocity gradient along l-direction
dl
T
= the derivative of surface tension with temperature and can be positive or negative depending on the substance, N/m-K
3.13 Exercises
E3.1: For a typical US Gulf Coast area, it is given that the diameter of the bit is 15 in,
rate of penetration is 100 t/hr, and the average porosity is 25%. Find out the volume of
cuttings in bbl/hr and tons/hr.
3
E3.2: he density of the drilling mud is measured as 80 lbm / ft in the rig side area.
Calculate the speciic gravity in gm / cm3, mud gradient in psi / ft and kg / cm2 / m. Ans.
3
E3.3: A mud engineer measured the density of the drilling luid as 75 lbm / ft in
3
the rig side area. Calculate the speciic gravity in gm / cm , mud gradient in psi / ft and
kg / cm2 / m. Ans.
E3.4: During the drilling of hazardous formation, the mud engineer was trying to
keep up the quality of drilling luid. At certain time, he measured the density of the
drilling luid as 12 ppg in the rig side area. Calculate the speciic gravity in gm / cm3,
mud gradient in psi / ft and kg / cm2 / m. Ans.
E3.5: A Marsh Funnel is used to measure the density of the drilling luid which is
1.1 g/cm3 in 40 seconds. Calculate the efective viscosity using Marsh Funnel equation. Ans.
E3.6: A Marsh Funnel is used for 45 seconds to to measure the density of the drilling
luid which is 1.3 g/cm3. Calculate the efective viscosity using Marsh Funnel equation.
Ans.
E3.7: A mud sample in a rotational viscometer gives a dial reading of 460 at 600 rpm
and a dial reading of 280 at 300 rpm. Compute the apparent viscosity of the mud at each
rotor speed.
E3.8: Using the data of Exercise 3.6, compute the plastic viscosity and yield point of
the mud sample. Ans.
E3.9: To calculate the diferent viscosity of a mud sample, a Fann V-G meter is used
and the data measurements are 600 250 and 300 180. Calculate i) plastic viscosity,
ii) apparent viscosity, iii) Bingham yield point, and true yield point. Ans.
E3.10: Find out the pH of a aqueous solution where both [H+] and [OH–] ions are
1 10 2 and 1 10 12 respectively. Ans.
E3.10: Find out the pH of both [H+] and [OH–] ions if an aqueous solution has the
concentration of 1 10 9 for [H+] and 1 10 5 for [OH–] ions respectively. Ans.
136 Fundamentals of Sustainable Drilling Engineering
E3.11: A 13 lbm/gal drilling mud is retorted and found to contain 9% oil and 75%
water. If the chloride test shows the mud to have a chloride content of 150,000 mg
Cl / L, Find out the solid fraction of the mud? Assume that the mud is a calcium chloride mud. he solution has 14% salinity and CaCl2 has a volume increase factor of
1.037. Ans.
E3.12: A 10 lbm/gal drilling mud is retorted and found to contain 12% oil and 70%
water. If the chloride test shows the mud need to have chloride content, Find out the
solid fraction of the mud? Assume that the mud is a sodium chloride mud. he solution
has 18% salinity and NaCl has a volume increase factor of 1.075. Ans.
E3.13: A 20-in bit is used to drill a hole at a rate of 70 t/hr where the porosity of the
formation is 25%. Calculate the solid volume generated this drilling operation. If the
density of the solid is 910 lbm/bbl, calculate the solid generation in tons/hr also. Ans.
E3.14: For a typical North Sea well, a 26-in bit is used to drill a hole at a rate of
60 t/hr where the porosity of the formation is 25%. Calculate the solid volume generated this drilling operation. If the density of the solid is 910 lbm/bbl, calculate the solid
generation in tons/hr also. Ans.
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4
Drilling Hydraulics
4.1 Introduction
Hydraulics can be deined as the study of the physical science and technology of the
static and dynamic behavior of luids under the inluence of mechanical forces and/or
pressure, and uses of that knowledge in designing and controlling machines. In drilling
engineering, drilling hydraulics is an essential part of drilling operations where computation of pressure proiles along the wellbore and particularly in the annulus contributing to well safety and well integrity are done to improve the API recommended practice
for drilling luid rheology and drilling hydraulics estimation. Drilling hydraulics plays
a vital role while drilling activities continue to operate which is also referred to as rig
hydraulics.
In the petroleum industry, drilling hydraulics provides a productivity tool which is
helpful in the drilling of hydrocarbon wells for hydraulics calculations, and optimization
of rate of penetration (ROP) to the driller, tool pushers, engineers, chemists, students and
other professionals. It can help on the decision on selection of bit nozzles. In addition,
accurate use of hydraulic energy at i) drill bit, ii) calculations of frictional pressure drops
through the drill pipe and various surface equipment, iii) eicient cleaning ability of the
drilling system, and iv) proper utilization of mud pump horsepower are some of the features necessary to optimize for eicient, safe, and cost efective drilling operations. An
incorrect design resulting in an ineicient hydraulics system can – i) slow down the ROP,
ii) fail to properly clean the hole of drill cuttings, iii) cause lost circulation, and inally
141
142 Fundamentals of Sustainable Drilling Engineering
iv) lead to blowout of the well. As a result, proper design and maintenance of rig hydraulics is crucial. To understand and properly design the hydraulic system, it is important to
discuss hydrostatic pressure, types of luid low, criteria for type of low, and types of luids commonly used in the various operations at the drilling industry. Hence this chapter
deals with the type of luids; pressure losses in the surface connections, pipes, annulus,
and the bit; jet bit nozzle size selection; surge pressures due to vertical pipe movement;
optimization of bit hydraulics; and carrying capacity of drilling luid.
4.2 Types of Fluids
here are diferent types of luids. Almost all the luids follow the following categories:
i)
ii)
Newtonian luid
Non-Newtonian Fluid
4.2.1 Newtonian Fluid
Normally Newtonian luids are those liquids where low molecular weight substances
exist. Examples include water, light crude oil, organic and inorganic liquids, gases, solutions of low molecular weight inorganic salts, molten metals and salts which exhibit
Newtonian low behavior. A Newtonian Fluid can be deined as – “the shear stress is
directly proportional to shear rate at a constant temperature and pressure”. he constant
proportionality is known as dynamic viscosity of luid. he shear stress and the rate of
deformation are normally expressed by Newton’s law of viscosity which can be written
mathematically as:
dux
(4.1)
d
dy
Here:
= shear stress, Pa
= dynamic viscosity, Pa-s
d
dux
or = the velocity gradient perpendicular to the direction of shear, or equivady
lently the strain rate, s−1
In ield unit, viscosity is expressed in centipoises (1 poise = 100 centi poise) and the
ield unit of share stress is in lbf /100 t2. Figure 4.1 shows the linear variation of shear
stress with shear rate. he slop of the line gives the viscosity of the luid. Equation (4.1)
is called the Newtonian luid model. he fundamental concept of the Newtonian luid
behavior is already explained in section 3.6.2 of Chapter 3.
he linear relationship between shear stress and shear rate as illustrated by Eq. (4.1)
is valid only if the luid moves in conined layers or laminae. A luid that lows in this
type of arrangement is said to be laminar low. his phenomenon is true only at relatively low rates of shear. he pipe low and other types of low will be discussed in the
next section of this chapter.
Example 4.1: Calculate the shear stress of a luid which has a viscosity of 55 cp and a
shear rate of 15 s–1.
Drilling Hydraulics 143
Shear Stress ( )
1
2
3
Shear Rate ( )
Figure 4.1 Characteristics of newtonian luid.
Solution:
Given data:
= Mud viscosity = 55 cp = 0.55 Poise = 0.55 dyne.s / cm2 = 0.55 Pa-s
d
dux
= = Shear rate = 15s–1
dy
Required data:
= Shear stress, Pa
he shear stress of the luid can be calculated using Eq. (4.1) as:
d
dux
dy
0.55 Pa.s 15 s
1
8.25 Pa
4.2.2 Non-Newtonian Fluid
A non-Newtonian luid is a luid whose low behavior or properties is not the same
as Newtonian luid i.e. fundamentally the rate of shear is not proportional to the corresponding stress and cannot be described by a single constant value of viscosity.
Most of the drilling luids are non-Newtonian, due to their complex characteristics
in behavior. Some other examples can be illustrated as foams, suspensions, polymer
solutions, and melts. Non-Newtonian luids can be classiied as i) shear-thickening,
ii) shear-thinning, iii) time-dependent (i.e. thixotropic, and rheopectic), visco-plastic,
and visco-elastic luids. In addition to these types of luids, non-Newtonian luids can
also be categorized as i) Bingham plastic, and ii) power-law luids.
A shear-thickening luid is deined as a luid in which apparent viscosity increases
with the increase of shear strain rate. It is also termed ‘dilatant.’ A shear-thinning luid
is the opposite of shear-thickening luid where apparent viscosity decreases with the
increase of the rate of shear strain which is also called as pseudoplastic luid. Examples
of this type of luid are drilling luids and cement slurries in general. here are also
luids that are time-dependent; a luid is called thixotropic if the apparent viscosity
decreases with time ater the shear rate is increased to a new constant value. On the
other hand, if the apparent viscosity increases with time ater the shear rate is increased
144 Fundamentals of Sustainable Drilling Engineering
Viscoplastic
Shear Stress
Bingham
Plastic
Pseudoplastic
Newtonian Fluid
Dilatant Fluid
Shear Rate
Figure 4.2 Characteristics of diferent non-Newtonian luids
to a new constant value, the luid is called rheopectic. Again, drilling luids and cement
slurries are generally thixotropic. A luid that exhibit a viscoelastic property i.e. a blend
of viscous luid behavior and of elastic solid-like behavior is called visco-elastic luid.
Viscoelasticity is the property of materials that exhibit both viscous and elastic characteristics when undergoing deformation, such as honey. Figure 4.2 shows the typical
low curves (rheograms) for the above mentioned categories of luid behavior.
4.2.2.1
Diferent Rheological Models for Non-Newtonian Fluids
For non-Newtonian luids, there are some rheological models that describe the relationship between shear stress and shear rate when a luid lows through a circular
section or an annulus. he rheological models are generally used to approximate the
luid behavior. Among the various rheological models, this chapter considers the most
widely used models and one newly developed model by the irst author of this book.
he models are: i) Bingham plastic model, ii) power-law model, iii) shear-thinning
luid model, and iv) Herschel-Bulkley model. he other model for Newtonian model is
already discussed in the above section.
i) Bingham Plastic Models: Bingham plastic luids can be deined as luids that have a
linear stress-strain relationship and which require a inite yield stress before they start
to low. he linear plot of stress-strain relationship does not pass through the origin,
but rather intersects to a point of stress line. Examples are clay suspensions, toothpaste,
mayonnaise, chocolate, and mustard. Figure 4.3 depicts the relationship between the
shear rate and shear stress.
Bingham plastic models are used to approximate the pseudoplastic behavior (i.e.
decrease of apparent viscosity with increasing shear rate) of drilling luids and cement
slurries. It is deined in terms of the shear stress and shear rate, which are given by the
following mathematical models:
p
=0
Shear Stress ( )
Drilling Hydraulics 145
+
Yield Stress
Yield points
Shear Rate ( )
–
Figure 4.3 Shear rate vs. shear stress relationship for Bingham plastic luid.
p
y
;
if
y
(4.2a)
p
y
;
if
y
(4.2b)
Here:
y
p
= a minimum shear stress that needs to initiate luid low, Pa
= Bingham plastic viscosity, Pa-s
he deinition of Bingham plastic luid says that there will not be any low until there is
a certain minimum shear stress applied to the luid which is called a yield point stress ( y ).
It may also predict a non-physical yield point. Once the yield point has been exceeded,
changes in shear stress are proportional to changes in shear rate. he slop of the curve
(Figure 4.3) or the constant proportionality is called the plastic viscosity ( p ). he plastic
viscosity depends on pressure and temperature. he above two Bingham plastic models
are valid only for laminar low. hese models work well for higher shear rates. However,
the models give a signiicant error at low shear rates.
Example 4.2: A moving plate is set 2 cm above a stationary plate which has a crosssectional area of 25 cm2. If a force of 250 dynes is required to just initiate the upper plate
and a force of 550 dynes is needed to move the plate with a uniform velocity of 8 cm/s,
calculate the yield point and plastic viscosity of the luid.
Solution:
Given data:
L = Gap between the plates = 2 cm
A = Cross-sectional area of the upper plate = 25 cm2
146 Fundamentals of Sustainable Drilling Engineering
Fy = Force needed to initiate the plate movement (i.e.
V = Fluid velocity = 8 cm/s
F = Force needed to move the plate = 550 dynes
0) = 250 dynes
Required data:
= Yield point, Pa
y
= Plastic viscosity, Pa-s
p
he yield point ( y) needed to initialize the luid can be calculated using Eq. (4.2a) as:
p
y
p
0
y
y
Now, the deinition of shear stress can be written using Eq. (3.6) as:
250 dynes
25 cm2
F/A
herefore,
y
10 dyne / cm2
10 dynes / cm 2
he plastic viscosity can be calculated using the force needed to move the plate and
with the luid velocity and by Eq. (4.2a) as:
y
p
F/A
550 / 25 10
8/2
y
V /L
3.0dyne.s / cm2
3 Poise
300 cp
For Bingham luid, plastic viscosity, yield point, and zero-sec-gel can be calculated
using a FannV-G meter (See Chapter 3) reading with the following relationships.
p
2
y
600
300
(4.3a)
300
600
(4.3b)
0
(4.3c)
3
Here:
600
300
3
0
= the Fann dial reading at 600 rpm
= the Fann dial reading at 300 rpm
= the Fann dial reading at 3 rpm
= yield point stress at dial reading at 3 rpm
Alternatively, the dial readings can be reverse calculated by using plastic viscosity, yield
point, and zero-gel by rearranging the Eqs. (4.3a – c). It is noted that these readings give
the corresponding plastic viscosity, and yield point in ield units.
300
600
p
2
p
y
y
(4.4a)
(4.4b)
Drilling Hydraulics 147
3
(4.4c)
0
If the FannV-G meter RPMs are any other readings except 300 and 600 rpm, the following equations can be used:
300
N 2 N1
p
y
Here:
N1 , N 2
N1 , N 2
N2
N1
p
(4.5)
N1
N1
300
(4.6)
= he Fann rpm reading
= he Fann dial reading at N1 and N 2 rpm
Example 4.3: In the drilling luid laboratory, a student was conducting an experiment
for the Bingham luid where he was using the Fann V-G meter to measure the viscosity of the luid and he found the following Fann data: 300 30; 600 55, and 200 27;
49. Calculate the plastic viscosity and yield point of the luid using the Bingham
400
plastic model.
Solution:
Given data:
300 = Dial reading at 300 rpm = 30
600 = Dial reading at 600 rpm = 55
200 = Dial reading at 200 rpm = 27
400 = Dial reading at 400 rpm = 49
Required data:
p = Plastic viscosity, Pa.s
y = Yield point, Pa
For 300 and 600 rpm readings, the plastic viscosity and yield point can be calculated
using the Eqs. (4.3a) and (4.3b) as:
p
y
2
300
600
600
300
55 30 25cp 0.25 Poise
0.25 dyne.s / cm2
0.25 Pa. s
2 30 55 5 lb f /100 ft 2
5 lb f /100 ft 2
1.04 dyne / cm2
dyne / cm2
;
4.79lb f /100 ft 2
(1 Pa 4.79 lb f /100 ft 2 )
1.04 Pa
For the second set of readings, we should use Eqs. (4.5) and (4.6) as:
p
300
N 2 N1
N2
N1
300
49 27
400 200
33 cp
0.33 Pa. s
148 Fundamentals of Sustainable Drilling Engineering
y
N1
N1
300
p
200
300
27 33
5 lb f /100 ft 2 1.04 dyne / cm 2
1.04 Pa
ii) Power-Law Models: A power-law luid can be deined as a luid in which the shear
stress at any point is proportional to the rate of shear at that point with some power on
the shear rate. he rheological equation for the power law model can be given as:
K
np
(4.7)
Here:
K
= low consistency index, Pa. sn
dux
= shear rate or velocity gradient perpendicular the plan of shear, s
dy
= power-law exponent or low behavior index, dimensionless
np
1
he apparent viscosity as a function of shear rate can be written as:
app
K
np 1
(4.8)
Shear Stress ( )
Shear Stress ( )
Power-law luids can be further classiied into three diferent types of luids based
on n p: i) pseudoplastic luids for n p < 1, ii) Newtonian luids for n p = 1, and iii) Dilatant
luids for > 1. he power-law models are also known as Ostwald-de Waele model.
Equations (4.7) and (4.8) are useful because they are simple and require only two
parameters for characterizing luid behavior. hese models are also used to approximate the pseudoplastic behavior of drilling luids and cement slurries. However, these
models can only approximate the behavior of a real non-Newtonian luid. Figure 4.4
shows the graphical representation of the model Eqs. (4.7) and (4.8).
In the power-law model, K is a measure of the thickness of the luid, analogous to
apparent viscosity of the luid. he larger the K value, the thicker the luid is. he value
=K
<1
=K
>1
=K
Shear Rate ( )
n–1
=K
(a)
Shear Rate ( )
n–1
(b)
Figure 4.4 Shear rate vs. shear stress relationship for power-law luid: (a) pseudoplastic
power-law luid, and (b) dilatants power-law luid.
Drilling Hydraulics 149
of n indicates the degree of non-Newtonian behavior of the luid. For example, if n
is less than one, the power-law forecasts the efective viscosity which decreases with
the increase of shear rate indeinitely. It is noted that in Eq. (4.8), 0 n p 1 will yield
d app / d
0 which indicates that shear-thinning behavior of luids is characterized
by a value of n p 1. Lots of polymer melts and solutions have the value of n in the
range of 0.3 – 0.7 based on the concentration, molecular weight of the polymer, and
some other properties. In addition, smaller values of power-law index (n p 0.1 0.15)
are encountered with ine particle suspensions like kaolin-in-water, bentonite-in-water,
etc. Naturally, the smaller the value of n p, the more shear-thinning the material is.
Although, Eq. (4.7) or (4.8) ofers the simplest approximation of shear-thinning
behavior, it predicts neither the upper nor the lower Newtonian plateaus in the limits
. In addition, a luid needs ininite viscosity at rest and zero viscosof
0 or
ity while the shear rate approaches ininity. However, a real luid has a minimum and
maximum efective viscosity which depends on the physical chemistry at the molecular
level. hus, the power law models (Eqs. 4.7 and 4.8) are only a good representation of
the luid behavior within the range of shear rates to which the coeicients are itted.
he shortcoming of the power-law model is that it underestimates the shear stresses at
medium and low shear rate ranges. In the literature, there are a number of other models
that better explain the entire low behavior of shear-dependent luids such as shearthinning luid. he following section presents some models as an example.
Example 4.4: A moving plate is set 2 cm above a stationary plate which has a crosssectional area of 25 cm2. Calculate the consistency index and low-behavior index if a
force of 250 dyne is required to move the upper plate at a constant velocity of 8 cm/s
and a force of 300 dyne is needed to move the plate with a uniform velocity of 10 cm/s.
Solution:
Given data:
L
= Gap between the plates = 2 cm
A
= Cross-sectional area of the upper plate = 25 cm2
F1 = Force needed to move the plate by 8 cm/s = 250 dynes
V1 = First luid velocity = 8 cm/s
F2 = Force needed to move the plate by 10 cm/s = 300 dynes
V2 = Second luid velocity = 10 cm/s
Required data:
K
= Flow consistency index, Pa. sn
n p = Power-law exponent or low behavior index, dimensionless
To calculate K and n p, Eq. (4.7) is used at the two rates of shear observed and Eq. (3.4)
is used for shear stress as:
F/A
250
25
K
8
2
np
K
np
300
and
25
K
10
2
np
150 Fundamentals of Sustainable Drilling Engineering
Now, dividing the second equation by the irst equation as:
300
250
np
10
8
Taking the ln of both sides and solving for n p as:
ln 300 / 250
np
ln 10 / 8
0.817
Substituting the value of n in the irst equation above gives as:
250
25
8
K
2
np
10
(4)0.817
K
322.2 Pa. s 0.817
322.2 eq.cp
For a power-law luid, the low behavior index can be calculated using Fann V-G meter
which is written as:
log10
600
300
np
3.322 log
0.301
600
(4.9)
300
In Eq. (4.9), if we use the modiied power-law, it can be written using Eqs. (4.4a) and
(4.4b) as:
np
3.322 log
2
p
p
y
(4.10)
y
he consistency index, K can be written as:
K
5.11
300
np
(4.11)
511
In Eq. (4.11), K is in eq. poise. It can be expressed in terms of lb f
the conversion factor of 1 Pa 4.79lb f /100 ft 2.
sec
n
/100 ft 2 using
K can also be calculated using the modiied power-law which gives as:
K
2
p
y
n
1022
(4.12)
If the Fann V-G meter RPMs are any other readings except 300 and 600 rpm, the following equations can be used:
log
np
N2
N1
N2
log
N1
(4.13)
Drilling Hydraulics 151
5.11
K
N
(4.14)
np
1.703 N
Example 4.5: In the drilling luid laboratory, a student was conducting an experiment
for the Bingham luid where he was using the Fann V-G meter to measure the viscosity of the luid and he found the following Fann data: 300 30; 600 55, and 200 27
; 400 49. Calculate the consistency index and low-behavior index for the power-law
model.
Solution:
Given data:
300 = Dial reading at 300 rpm = 30
600 = Dial reading at 600 rpm = 55
200 = Dial reading at 200 rpm = 27
400 = Dial reading at 400 rpm = 49
Required data:
np
K
= Flow consistency index, Pa. s
n p = Power-law exponent or low behavior index, dimensionless
For 300 and 600 rpm reading, K and n can be calculated using the Eqs. (4.9) and
(4.11) as:
np
3.322 log
600
3.322 log
300
55
30
0.874
and
5.11
K
5.11 30
5110.874
300
np
511
0.658 eq. poise
In ield units:
K
0.658 4.79 3.152 lb f /100 ft 2 .
[Note: 1 Pa 4.79lb f /100 ft 2]
For the second set of readings, we should use Eqs. (4.13) and (4.14) as:
log
np
K
5.11
1.703
N2
N1
N2
log
N1
5.11
N
N
49
27
400
log
200
log
np
1.703
27
200
0.8598
0.8598
0.9174 eq. cp
152 Fundamentals of Sustainable Drilling Engineering
In ield unit:
K
0.9174 4.79
4.394 lb f / 100 ft 2
iii) Shear-thinning luid models: he majority of complex luids used in oil ield applications are non-Newtonian polymeric solutions demonstrating shear-thinning (pseudoplastic) behavior in solution. he two main polymers used in the oil industry for hydrocarbon
recovery are synthetic polyacrylamide (in its partially hydrolyzed form, HPAM) and
Xanthan biopolymer gum. Bulk property measurement of polymeric solutions is a standard and reliable experimental procedure. herefore, researchers’ eforts have been made
to extend the laws of motion for purely Newtonian luids (Darcy’s law) to rheologically
complex ones using easily measurable properties such as the shear rate/viscosity behavior. A bundle of parallel capillary tubes approach has been used to measure the macroscopic and microscopic properties of porous media. his approach leads to the deinition
of an average radius which is dependent on macroscopic properties of the medium such as
porosity, absolute permeability, and some measure of tortuosity. he available mathematical models (such as power law, Carreau, or Cross models) to describe the luid rheology
have been developed to deine viscosity and apparent shear rate from the use of the Darcy
velocity. Experimental results show that the shape of the apparent viscosity curve is similar
to that of the bulk shear rate. Most experimental works had been performed with Xanthan
biopolymers whose experimental results are available in the literature where they tried to
ind the shape factor, SF . For the porous media, Chauveteru’s form of the deinition of
porous media wall shear strain rate or in-situ shear rate is
.
pm
SF ux
k
(4.15)
Here:
ux = Fluid velocity in porous media in the direction of x axis, m / s
.SF = Shape factor which is medium-dependent
=Apparent shear rate within the porous medium, s 1
pm
k = Reservoir permeability, m2
= porosity of luid media, m3 / m3
In the context of polymer looding (part of enhanced oil recovery schemes), in-situ
rheology depends on polymer type and concentration, residual oil saturation, core
material and other related properties which are addressed in the available literature. A
brief discussion has been outlined by Lopez (2004). he existence of a slip phenomenon
in the Newtonian region at ultra low low rates is conirmed and the degree of shit (the
SF factor) in the non-Newtonian region is quantiied. It is shown that the adoption of
rigorous and reproducible core lood procedures is required to yield unambiguous data
on in-situ polymer viscosity and polymer retention in real systems. Some researchers
pointed out that Eq. (4.15) has a generic form which depends on polymer type, medium
structure and approach. In this area, there have been developed several constitutive
equations in the past that capture the full bulk rheological behavior of pseudoplastic
solutions. To model the bulk rheology of the non-Newtonian luid, the Carreau-Yasuda
model may be written as:
Drilling Hydraulics 153
0
ef
.
1 (
Here:
a
nc
eff
0
a
pm )
(4.16)
nc
a
= Parameter in Carreau–Yasuda model, dimensionless
= Power-law exponent for Carreau–Yasuda model, dimensionless
= Fluid efective viscosity, Pa s
= Fluid dynamic viscosity at zero shear rate, Pa s
= Fluid dynamic viscosity at ininite shear rate, Pa s
= time constant in Carreau–Yasuda model, s
he exact form of the shear stress-shear rate (stress-stain) relationship depends on the
nature of the polymeric solution. herefore, recently, a question is coming out about
the efect of memory on rock/luids in porous media when predicting oil low outcomes. Hossain and Islam (2006) have reviewed the existing complex luid low models with memory available in literature. None of them has focused on shear thinning
luid models which may couple with luid memory. Hossain et al. (2007, and 2008)
have developed a model which represents a more realistic rheological behavior of luid
and media. hey have developed a stress-strain relation coupling the macroscopic
and microscopic properties with memory (see Chapter 3). In that model, they did not
consider the polymeric luid properties in porous media. However, the conventional
practice is to consider the Newtonian luid low equations as ideal models for making
predictions. Even non-Newtonian models focus on what is immediately present and
tangible in regard to luid properties. he bulk macroscopic properties of these solutions, mainly their viscosity/shear rate dependency, are well understood and characterized using established models. Existing theoretical models as well as experimental
indings are well established in the literature. Recently, Hossain et al. (2009) attempted
to model shear rate and viscosity of a polymeric complex luid as a function of time
and other related bulk properties of luid and media itself where memory has been
incorporated to represent macroscopic and microscopic behavior of luid and media
in a more realistic way. hey argue that the intangible dimension of time and other
luid and media properties can be coupled to demonstrate the more complex behavior
of shear thinning luids in porous media. Hossain et al. (2009) proposed the following
model for apparent shear rate:
.
pm
Here:
p
t
t
SF
k
1
2
t
0
p
d
x
(4.17)
= pressure of the system, N / m2
= time, s
= fractional order of diferentiation, dimensionless
= ratio of the pseudopermeability of the medium with memory to luid
viscosity, m3 s1 / kg
= a dummy variable for time i.e. real part in the plane of the integral, s
154 Fundamentals of Sustainable Drilling Engineering
Equation (4.17) provides the efects of the polymer luid and formation properties
in one dimensional luid low with memory. his model may be extended to a more
general case of 3-dimensional low for a heterogeneous and anisotropic formation. It
should be mentioned here that the irst part of the Eq. (4.17) is the apparent core properties; the second part is the efect of luid memory with time and the pressure gradient.
he second part is in a form of convolution integral that shows the efect of the luid
memory during the low process. his integral has two variable functions of t
x where the irst is a continuous changing function and second is a ixed
and 2 p /
is an overlapping function on the other function,
function. his means that t
2
p/
x in the mathematical point of view. hese two functions depend on the space,
time, pressure, and a dummy variable.
To analyze the memory efect in the shear-thinning luid viscosity, Hossain et al.
(2009) proposed the following model for efective viscosity.
0
eff
t
1
SF
0
2
t
p
d
x
a
nc
a
(4.18)
1
k
he solution of Eq. (4.16) and Eq. (4.18) is shown in Figure 4.5 which shows the variation of viscosity verses shear rate of the Hossain et al. (Eq. (4.18)) for diferent values
to compare the Carreau-Yasuda model (Eq. (4.16)) in a log-log plotting. All the data
generated by solving these two models are overlapped with each other, except for the
range of data variation. For the same conditions and input data, the proposed model
gives more information than the Carreau-Yasuda model. he proposed model provides
a wider range of data in both the zero shear and the ininite shear region. he existence
of the Carreau-Yasuda model is only in the power-law region if we compare it with the
proposed model. It is also noted that all values data lie in the transition and powerlaw region which are very diicult to capture and explain. If increases, the data range
extends to reach the other two regions, zero shear and ininite shear. herefore it may
be concluded that the proposed model is more appealing and illustrative in deining the
rheological properties of the shear-thinning luid low in porous media.
iv) Herschel-Bulkley model: he Herschel-Bulkley model is a combination of the
Bingham Plastic and the Power law models. It is also known as the yield power-law
model. his model considers the yield point shear stress which is a shortcoming of
the power-law model. Figure 4.6 shows the stress-strain relationship for the HerschelBulkley model. Mathematically, this model is deined as:
K
n
y
(4.19)
In Eq. (4.19), if y = 0, the Herschel-Bulkley model is reduced to the power-law model.
On the other hand if n = 1, the model reduces to the Bingham plastic model. It is
Drilling Hydraulics 155
102
Carreau-Yasuda model
= 0.2
= 0.4
= 0.6
= 0.8
Efective viscosity (
eff ), pa–s
101
100
10–1
10–2
10–3
10–4
10–2
100
102
Apparent shear rate (
pm), s
104
106
–1
=0
Shear Stress ( )
Figure 4.5 Comparison of Hossain et al viscosity model with Carreau-Yasuda model.
Herschel-Bulkley luid
+
Yield Stress
Yield points
Shear Rate ( )
Figure 4.6 Shear rate vs. shear stress relationship for Herschel-Bulkley luid.
noted that sometimes non-linear regression is needed for solving the resultant mathematical expressions which are not readily solved analytically. his model is preferable
compared to power law or Bingham models because it gives more accurate rheological
behavior when adequate experimental data are available. he yield stress is normally
taken as the 3 rpm reading, with the n and K values then calculated from the 600 or
300 rpm values or graphically. Some drilling luids fall under the Herschel-Bulkley luid
model. It requires a certain minimum stress to initiate low.
156 Fundamentals of Sustainable Drilling Engineering
4.3
Flow Regimes
When a luid is forced to low inside a pipe (example, drill pipe, drill collar etc.), there
are diferent geometrical conigurations or low regimes which prevail. he low regime
can be deined as a range of stream lows that have similar bed forms, low resistance,
and means of transporting sediment. While drilling luids low in a well, the luid
behavior may difer because the regime depends on the luid properties, length and size
of the conduit, and low rate. he low regime also depends on the coniguration of the
inlet. In general, low regimes can be classiied as i) laminar low, ii) transition low, and
iii) turbulent low.
4.3.1 Laminar Flow
he most common annular low regime is laminar which is also known as streamline
low and creates a steady-state low (Figure 3.7a). It is sometimes referred to as sheet
low, or layered low. Laminar low can be deined as the motion of a luid where every
particle in the luid follows the same path of its previous particles. It occurs when a luid
lows in parallel layers, with no disruption between the layers. It exists from very low
pump rates to the rate at which turbulence begins. At low velocities, the luid tends to
low in an organized way. here is no cross low perpendicular to the direction of low,
no eddies, and no spins of luids. In laminar low, the motion of the particles of luid
is very orderly with all particles moving in straight lines parallel to the pipe walls. he
luid moves fastest in the center of the conduit and slowest at the walls (Figure 4.7). It
is also true for pipe and annular low too (Figure 3.7b). his indicates that center layers usually move at rates greater than the layers near the wellbore or pipe. he major
characteristics of this low regime are: i) low pattern is linear i.e. no radial low, ii) luid
velocity at the center of the pipe is maximum and velocity at wall is zero, iii) it produces
minimal hole erosion, iv) as the low velocity increases, the low type changes from
laminar to turbulent. Laminar low can be characterized by Reynolds number, N Re . If
Reynolds number is less than 2100 i.e. N Re 2100 , the low is treated as laminar low.
4.3.2 Turbulent Flow
Turbulent low or turbulence is a low regime characterized by the chaotic nature of the luid
property changes. Turbulent lows are always highly irregular and chaotic but not all chaotic
lows are turbulent (Figure 4.8). Turbulence occurs when increased velocities between the
layers create shear strengths exceeding the ability of the mud to remain in laminar low. he
layered structure becomes chaotic and turbulent (Figure 4.8(c – d)). Turbulent lows are
unsteady by deinition. A constant source of energy supply is necessary to continue turbulent low. Otherwise, turbulence disperses rapidly as the kinetic energy is converted
into internal energy by viscous shear stress. It causes eddies formation of many diferent
length scales. Turbulent low can be characterized by Reynolds number, N Re . Flows with
high Reynolds numbers generally become turbulent. For pipe low, if the Reynolds number is greater than 4000 i.e. N Re 4000 , the low is treated as turbulent low. However,
we oten assume that luid low is turbulent if N Re 2100.
Drilling Hydraulics 157
Max Velocity
V=0
Laminar Flow
(a) Characteristics of laminar low
r
r
r2
r2
r1
v
v
(b) Pipe low
(c) Annular low
Figure 4.7 Characteristics and the velocity proiles for laminar low.
Pipe
Laminar Flow
DYE
TRACERS
(a)
(b)
(c)
Pipe
Turbulent Flow
Fluid Velocity proile
Particle
motion
(d)
(e)
Figure 4.8 Characteristics of turbulent low: (a) laminar low, (b) transition between
laminar and turbulent low and (c – e) turbulent low.
Turbulence usually takes place in the drillstring and seldom around the drill collars.
Much published literature suggests that annular turbulent low increases hole erosion
problems. In summary, the basic characteristics of turbulent low can be written as:
i) low pattern is random (low in all directions), ii) tends to produce hole erosion,
iii) results in higher pressure losses (takes more energy), iv) provides excellent hole
158 Fundamentals of Sustainable Drilling Engineering
cleaning but forms eddies in wall of the drill string. A comparison between laminar and
turbulent low is shown in Table 4.1.
Reynolds number: Reynolds observed that when circulating Newtonian fluids
through pipes the onset of turbulence was dependant on the variables such as i)
pipe diameter (d), ii) density of fluid , iii) viscosity of fluid (μ), iv) average flow
velocity (v). He also found that the onset of turbulence occurred when the above
combination of these variables exceeded a value of 2100. Reynold’s observation
was very significant because it means that the onset of turbulence can be predicted
for pipes of any size, and fluids of any density or viscosity, flowing at any rate
through the pipe. This grouping of variables is generally termed a dimensionless
group which is known as the Reynolds number. Therefore, the onset of turbulence
in pipe flow is characterized by the dimensionless group as:
N Re
vdi
(4.20)
Here:
v
di
d
q
= Fluid density, gm/cc
= Avg. luid velocity, cm/s
= Pipe inner diameter, cm.
= Dynamic viscosity of luid, cp
= Circulating volume, cc/s
In ield units, Reynolds number can be written as:
N Re
928 vdi
(4.21)
Here:
v
di
d
q
= Fluid density, lbm/gal
q
= Avg. luid velocity, t/s =
2.448 di2
= Pipe inner diameter, in.
= Dynamic viscosity of luid, cp
= Circulating volume, gal/min
Reynolds found that as he increased the luid velocity in the tube, the low pattern
changed from laminar to turbulent at a Reynolds number of 2100. However, later investigators have shown that under certain conditions (i.e. non-Newtonian luids and very
smooth conduits), laminar low can exist at very much higher Reynolds numbers. For
Reynolds numbers of between 2,000 and 4,000 the low is actually in a transition region
between laminar low and fully developed turbulent low (Figure 4.8b).
Example 4.6: While drilling, a 10.0 lbm/gal of mud having a viscosity of 1.2 cp was being
circulated through Drillstring at a rate of 650 gal/min. If the internal diameter of the
drillpipe is 5.0 in, determine the type of low in the drillpipe of the circulating system.
Drilling Hydraulics 159
Table 4.1 A comparison between laminar and turbulent low.
Flow
Type
Laminar Flow
Turbulent Flow
01
Flow is smooth
Flow pattern is random in both time
and space
02
Flow is essentially organized
and layered.
Flow is essentially random and
unpredictable and seconds
the well-deined Laminar low
conditions.
03
Velocity increase towards the
middle
Uniform at its inal stage
04
Only longitudinal velocity
Longitudinal and transverse
velocities
05
Same uniform velocity
Final velocity is uniform
06
Plug low is a special case
of laminar low (lat at
center)
No Plug low
07
Plug low occurs at low
velocity and high viscosity
of luid
No plug low
08
Laminar shear resistance
Laminar and turbulent shear
resistance
Laminar boundary layer
Turbulent boundary layer
Solution:
Given data:
= Density of the mud = 10.0 lbm/gal
m
= Viscosity of the mud = 1.2 cp
m
q
= Circulating volume or volume low rate = 650 gal/min
di
= Inner diameter of drillpipe = 5.0 in
Steeper Proile and
energy exchange
Thickness
Thickness
09
160 Fundamentals of Sustainable Drilling Engineering
Required data:
Type of low
he average luid velocity can be calculated as:
v
q
2.448 di2
650 gal / min
2.448
5 in
2
10.62 ft / s
Equation (4.21) is used to determine whether the luid is laminar or turbulent
N Re
928 vdi
928
10 lbm / gal
10.62 ft / s
1.2 cp
5 in
410, 640
Since the Reynolds number is considerably very high comparing with 2,100, the luid
of the drillpipe is in turbulent low.
4.3.3 Transitional Flow
In the case of pipe low, when the luid velocity increases the layers of luid start to
become a little unstable. his type of low is called transitional low (Figure 4.9).
herefore, this low can be deined as a mixture of laminar and turbulent low where turbulence occurs in the center of the pipe, and laminar low near the edges. If the low rate
continues to increase further, the low turns down to turbulent low. In such situations,
it is oten diicult to estimate the low rate at which turbulence may take place. A range
of Reynolds number can lead to inding out the transition zone. If 2100 N Re 4000 ,
low is in transition, and is neither laminar nor turbulent, sometimes called mixed low.
However, during any design, it is chosen as turbulent for being in the safe side.
It is sometimes easy to characterize the transition zone by critical luid velocity. It
is used to deine the velocity at which the low regime changes from laminar to turbulent. his variable is the most important since all other parameters in the Reynolds
number equation (Eq. 4.20 or 4.21) are considered constant. Since no single Reynolds
number deines the transitional zone, it follows that a range of critical velocities may
be necessary to determine the low regime. Based on critical velocity criteria, low
regimes can be characterized by critical velocity Vc , and actual velocity Vac as:
i) if Vc Vac, low is laminar, ii) if Vc Vac, low is turbulent, and iii) if Vc Vac , low is
transition.
he critical velocity can be determined for the Bingham plastic model as:
VcB
Here:
VcB
m
di
1.08
p
1.08
2
p
12.34
2
m di y
mdi
= Critical velocity for the Bingham plastic model, t/s
= Mud density, ppg
= Pipe inner diameter, in
(4.22)
Drilling Hydraulics 161
Velocity Proile
Turbulent Flow
Smooth Pipe
NR=107 , f=0.012
V
Laminar Flow
NR<2,000
Rough Pipe
NR=107, f=0.04
f = friction factor
NR = Reynolds Number
Increasing Velocity
Figure 4.9 Characteristics of transition low.
he critical low rate can be determined for the Bingham plastic model as:
QcB
2.448 VcB di2
(4.23)
Here:
QcB = Critical low rate for the Bingham plastic model, gpm
Example 4.7: While drilling, a 13.0 lbm/gal of mud is used where Fann data was observed
as 300 25; 600 47. he target depth was set at 10,000 t (TVD). If the internal diameter of the drillpipe is 3.75 in, calculate the critical velocity inside the pipe and the critical low rate.
Solution:
Given data:
= Density of the mud = 13.0 lbm/gal
m
=
Dial reading at 300 rpm = 25
300
= Dial reading at 600 rpm = 47
600
TVD = Total vertical depth = 10,000 t
di
= Inner diameter of drillpipe = 3.75 in
Required data:
VcB = Critical velocity inside the pipe, ft / s
QcB = he critical low rate, gpm
For 300 and 600 rpm reading, the plastic viscosity and yield point can be calculated
using the Eqs. (4.3a) and (4.3b) as:
p
y
2
300
600
600
300
47 25 22cp
2 25 47
3 lb f /100 ft 2
he critical velocity can be determined for the Bingham plastic model by using
Eq. (4.22) as:
162 Fundamentals of Sustainable Drilling Engineering
VcB
1.08
p
2
p
1.08
12.34
2
m i y
d
d
m i
1.08 22 1.08 222 12.34 13 3.752 3
13 3.75
2.37 ft / s
he critical low rate can be determined for the Bingham plastic model by Eq. (4.23) as:
QcB
2.448 VcB di2
2.448 2.37 3.752
81.59 gpm
4.4 Hydrostatic Pressure Calculation
he hydrostatic pressure of the drilling luid is an important feature in maintaining
control of a well. he understanding of this feature is also needed to prevent blow-outs.
Hydrostatic pressure is deined as the static pressure of a column of luid. Most of the
luid in the drillstring is mainly drilling mud. However, it can contain air, natural gas,
foam, mist, or aerated mud. herefore, this section is divided into three subsections for
i) liquid column, ii) gas column, and iii) complex luid column.
4.4.1 Liquid Columns
he subsurface well pressures are normally determined easily for static well conditions. he
liquid-based systems such as mud are considered in this section. he hydrostatic pressure
of a mud column is a function of the mud weight, and the true vertical depth of the well. It
is very important to pay attention to the well depth because it should be conirmed that the
measured depth, or total depth, is not used erroneously. Figure 4.10 shows the free-body
diagram from which variation of pressure with depth can be derived mathematically.
he downward force acting on the luid element can be calculated as:
Fdown
Here:
Fdown
p
A
pA
(4.24)
= Downward force on the luid element applied by the luid
column above, lbf
= Pressure on the luid element, psig
= Inner cross-sectional area of the luid column, in2
he upward force acting on the luid element can be calculated as:
Fup
Here:
Fup
Ltvd
Ltvd
p
dp
L
A
dLtvd tvd
(4.25)
= Upward force on the luid element applied by the below luid column, lbf
= Total vertical depth, t
= Diferential total vertical depth, t
Drilling Hydraulics 163
Ltvd = 0
Ltvd
FDown
Area A
Ltvd
Wsp
Fself
FUp
Figure 4.10 Fluid column where distribution of forces acting on the luid element.
dp
dLtvd
= Pressure gradient with respect to total vertical depth, psig/t
Finally the weight of the luid element itself is exerting a downward force which can be
calculated as:
Fself
(4.26)
Wsp A Ltvd
Here:
Fself = Fluid element’s self-weight acting as a downward force, lb
f
Wsp = Speciic weight of luid, lb f / in2 ft
If we consider that luid is at rest, there will not be any shear forces acting on the luid
element and thus all forces acting on the luid element must be in equilibrium i.e.:
Fdown
pA
p
pA pA
Fup
Wsp A Ltvd
(4.27)
0
dp
L
A Wsp A Ltvd
dLtvd tvd
0
(4.28)
dp
A Ltvd Wsp A Ltvd
dLtvd
0
(4.29)
dp Wsp dLtvd
(4.30)
For drilling operations, normally we deal with a liquid such as drilling mud or salt
water where luid compressibility is negligible, and speciic weight can be considered
constant with depth. With these approximations, Eq. (4.30) can be integrated for an
incompressible luid which gives the following inal form:
p Wsp Ltvd
po
(4.31)
164 Fundamentals of Sustainable Drilling Engineering
Here:
po= Surface pressure at Ltvd
0 which is also the constant of the integral.
In general, the static surface pressure, po is zero unless the blowout preventer of the well
is closed and the well is trying to low. he speciic weight of the liquid in ield unit can
be written as:
Wsp
0.052
(4.32)
m
Here:
Wsp = Speciic weight of luid, lb f / in2
ft
herefore, Eq. (4.31) can be written in ield units as:
p 0.052
L
po
m tvd
(4.33)
Since mud weights and well depths are oten measured with diferent units, the constant of Eq. (4.32) will vary. Common forms of the hydrostatic pressure equation are as
follows:
p 0.052
mud weight, lbm / gal
p 0.00695
p 9.81
depth, ft , where p is in psia
mud weight, lbm / ft 3
3
mud weight, g / cm
depth, ft , where p is in psia
depth, m , where p is in kPa
(4.34a)
(4.34b)
(4.34c)
If a column of luid contains several mud weights, the total hydrostatic pressure is the
sum of the individual luid column or section:
pt
Here:
pt
C
i
Li
C i Li
(4.35)
= Total hydrostatic pressure
= Conversion constant
= Mud weight for the section of interest
= Length of the section of interest (which is part of Ltvd )
Equation (4.35) leads to the concept of Equivalent Mud Weight (EMW) which is frequently used in drilling operation. Drilling operations oten involve several luid densities, pressures resulting from luid circulation, and perhaps applied surface pressure
during kick control operations. It is useful in practical applications to discuss this complex pressure and luid density arrangement on a common basis. he approach most
widely used is to convert all pressures to an “EMW” that would provide the same pressures in a static system with no surface pressure. he EMW concept is a convenient
way to compare the pressures at any depth. For example, a 12,000-t well has two mud
weights. It contains 6,000 t of 10.0 lbm/gal mud and 6,000 t of 12.0 lbm/gal mud. Now,
the equivalent mud weight at 12,000 t is 11.0 lbm/gal, even though the well does not
Drilling Hydraulics 165
contain any real 11.0 lbm/gal mud. Mathematically, EMW in lbm/gal (i.e. ppg) can be
calculated as:
pt
EMW
(4.36a)
0.052 Ltvd
If the well is deviated
deg from the vertical, the EMW is given by:
pt
EMW
0.052 Dm cos
(4.36b)
Here:
= Measured depth, t
Another term commonly used to describe the equivalent mud weight concept is equivalent circulating density (ECD). ECD results from the addition of the equivalent mud
weight, due to the annular pressure loss, to the original mud weight. he ECD usually
considers the hydrostatic pressures and the friction pressure resulting from luid movement. For example, a 13.0 lbm/gal mud may act as if it is 13.4 lbm/gal mud (due to the
friction pressure) while it is pumped. Some drilling engineers may refer to the ECD in
this case as 0.4 lbm/gal. Typical ranges for the ECD additive factor are 0.1–0.5 lbm/gal.
Mathematically, ECD in ppg can be determined as:
ECD
om
pan
0.052 Ltvd
(4.37a)
Here:
om
pan
= Original mud density, ppg
= Annular pressure loss, psi
In deviated wells, vertical depth is used. In such case, Eq. (4.37a) can be modiied for
multiple sections as:
nw
ECD
Here:
nw
i 1
om
0.052
pan i
nw
i 1
(4.37b)
Ltvd i
= number of wellbore sections
Example 4.8: An intermediate casing string was cemented using the following muds:
irst section 7,000t was illed by 11.5 lbm/gal mud, second section of 1500t was illed
by 14.3 lbm/gal mud and the last section was illed by 15 lbm/gal mud. Calculate the
total hydrostatic pressure at 11,000 t. Convert the pressure at 11,000 t to an equivalent
mud weight and determine if it will exceed the fracture gradient of 13.2 lbm/gal. Also
calculate the ECD for an annular pressure loss gradient of 0.04 psi/t and an original
mud weight of 12.5 ppg.
Solution:
Given data:
= Mud weight for the section of interest = 11.5, 14.3, and 15 lbm/gal
i
166 Fundamentals of Sustainable Drilling Engineering
Ltvd = Total vertical depth= 11,000 t
Li
= Length for the section of Ltvd = 7,000 , 1,500 and 2,500 respectively
Fracture gradient = 13.2 lbm/gal
Annular pressure loss = 0.04 psi/t
Required data:
pt
= Total hydrostatic pressure, psia
EMW = Equivalent mud weight, lb /gal
m
ECD
= Equivalent circulating Density, lbm/gal (i.e. ppg)
Total hydrostatic pressure can be determined using Eq. (4.35) where C is equal to 0.052.
herefore,
pt
0.052
11.5, lbm / gal
0.052
14.3, lbm / gal
0.052
15, lbm / gal
7000 ft
1500 ft
2500 ft i.e. 11000
7000 1500
= 7,251.4 psia
Equivalent mud weight (EMW) can be calculated using Eq. (4.36)
EMW
7,251.4 psia
0.052 11,000 ft
pt
0.052 Ltvd
12.67 lbm / gal or ppg
herefore, the static hydrostatic pressure with a 12.67 lbm/gal EMW will not exceed the
fracture gradient of 13.2 lbm/gal.
he ECD is calculated for the total depth of 11,000 t so Eq. (4.37a) is used for calculating ECD as:
psi
11,000 ft
ft
0.052 11,000 ft
0.04
ECD 12.5
12.5 0.769 13.27 ppg
4.4.2 Gas Columns
In many cases of drilling and completion operations, gas presence exists in at least a
portion of a well. Sometime gas is injected to the well from the surface or gas may enter
the well from a subsurface formation. It is very important and complicated to calculate
the pressure variation of a static gas column because the density of gas changes with
pressure.
he gas behavior can be described using the real gas equation deined by
paV
Here:
ZnRT
(4.38)
Drilling Hydraulics 167
pa = Absolute pressure
V = Gas volume
Z = Compressibility or gas deviation factor
m
n = mole of gas =
m = mass of gas M
M = Gas molecular weight
R = Universal gas constant
T = Absolute temperature
Gas density can be expressed as a function of pressure using Eq. (4.38) which can be
written as
Mpa
ZRT
m
V
(4.39)
Equation (4.39) can be expressed in ield unit for mud as
Mpa
80.3 ZT
m
Here:
pa
M
T
(4.40)
= Absolute pressure, psia
= Gas molecular weight, fraction
= Absolute temperature, °R
For any long gas column, variation of gas density with depth can be written in terms
of the pressure gradient using Eq. (4.40) in Eq. (4.32) and then applying the product to
Eq. (4.30) yielding:
dp 0.052
Mpa
dL
80.3 ZT tvd
(4.41)
If the gas deviation factor Z is constant, Eq. (4.41) can be rearranged as integrate both
sides as
pa
p0
1
dp
p
M
1,544 ZT
Ltvd
dLtvd
(4.42)
L0
he inal form of Eq. (4.42) gives
M Ltvd L0
pa
p0 e
1,544 ZT
(4.43)
Example 4.9: Consider the tubing of a well illed with methane (CH4) gas to a vertical
depth of 12,000 t. he annular space is illed with a 10.5 lbm/gal mud. Assume that
the gas follows the ideal gas behavior. Calculate the amount by which the exterior
pressure on the tubing exceeds the interior tubing pressure at 12,000 t if the surface tubing pressure is 1,200 psia and the mean temperature is 150°F. If the collapse
168 Fundamentals of Sustainable Drilling Engineering
resistance of the tubing is 8,500 psi, will the tubing collapse due to the high external
pressure?
Solution:
Given data:
M
= Gas molecular weight = 12 + 1 x 4 =16
Ltvd = Total vertical depth = 12,000 t
= mud weight = 10.5 lbm/gal
m
= Surface pressure = 14.7 psia
po
= Surface tubing pressure = 1,200 psia
pst
T
= Absolute temperature in °R = (460 + 150) = 610°R
pcollapse = Collapse tubing pressure = 8,500 psi
Required data:
p
= Pressure diference between exterior and interior tubing, psia
he pressure in the annulus of the well can be calculated using Eq. (4.33) at a depth of
12,000 t as:
0.052
p12,000 A
10.5, lbm / gal
12000 ft
14.7 psia
6566.7 psia
he pressure in the tubing at a depth of 12,000 t can be determined using Eq. (4.43) as:
16 12,000 0
p12,000t
1200 psia
e
1,544
1
610
1, 471.35 psia
hus the pressure diference can be calculated as:
p
p12,000 A
p12,000t
6566.7 1, 471.35 5, 095.35 psia
his pressure diference between exterior and interior tubing is below the collapse tubing pressure, 8,500 psi. So there would not be any collapse of tubing string.
However, let us verify the collapse based on the density concept explained earlier.
In this case, the density of the gas in the tubing string at the surface can be calculated
using Eq. (4.40) as:
16
80.3
1,200
1
610
0.3919 lb /gal
m
It is noted that if we use the Eq. (4.33), the pressure in the tubing of the well can be
calculated at a depth of 12,000 t as:
p12,000t
0.052
0.3919, lbm / gal
12000 ft
1,200 psia 1, 444.55 psia
he above tubing pressure of the well is less by 26.8 psia compared with the other calculation based on Eq. (4.43). herefore the above decision for collapse is ok.
Drilling Hydraulics 169
4.5 Fluid Flow through Pipes
In rotary drilling operation, the hydraulic system consists of stand pipe, rotary hose,
swivel, kelly, drill pipe, drill collar, drill bit, and the annulus (Figure 4.11a and 4.11b).
he mud pump discharges the drilling luid which passes through the surface lines,
and hydraulic system. he mud begins to travel downward through the drill pipe and
drill collars and is expelled through the nozzles of the bit, then returns up to the surface
through the annulus. Since the mud enters the drill string and leaves the annulus at the
same level the only pressure required is to overcome the frictional losses in the system.
When drilling luid circulates, a pressure drop takes place due to friction between the
luid and the surface in contact. he pressure that forces the drilling luid to circulate
through the hydraulic system is supplied by the mud pump. he mud pump pressure
is partly used up in overcoming the friction losses of the hydraulic system including
surface facilities. he remaining pump pressure is consumed as drill bit nozzle pressure
loss, where the high nozzle speed is needed to remove cuttings from the bit and its surroundings. herefore, the total discharge pressure at the pump is deined as:
PP
Here:
ΔPP
ΔPsp
ΔPdp
ΔPdc
ΔPbn
ΔPac
ΔPap
Psp
PdP
Pdc
Pbn
Pac
Pap
(4.44)
= pump discharge pressure, psi
= pressure loss in surface piping, stand pipe and mud hose, psi
= pressure loss inside drill pipe, psi
=pressure loss inside drill collar, psi
= pressure loss across bit nozzle, psi
= pressure loss in annulus in the drill collars, psi
= pressure loss in annulus in the drill pipe, psi
Example 4.10: Calculate the total pressure required to discharge a 10 ppg mud through
the drilling circulating system. Use the following data for the mud pump pressure
requirement:
Pressure loss in surface piping, stand pipe and mud hose = 90 psi
Pressure loss inside drill pipe = 2000 psi
Pressure loss inside drill collar = 300 psi
Pressure loss across bit = 75 psi
Pressure loss in annulus in the drill collars = 350 psi
Pressure loss in annulus in the drill pipe = 2,700 psi
Solution:
Given data:
ΔPsp = pressure loss in surface piping, stand pipe and mud hose = 90 psi
ΔPdp = pressure loss inside drill pipe = 2,000 psi
ΔPdc = pressure loss inside drill collar = 300 psi
ΔPbn = pressure loss across bit = 75 psi
ΔPac = pressure loss in annulus in the drill collars = 350 psi
170 Fundamentals of Sustainable Drilling Engineering
PPUMP
Mud Pump
Suction Pit
CASING &
CEMENT
DRILL PIPE
OPEN HOLE
ANNULUS
PERMEABLE
ZONES
DRILL COLLARS
(a)
(b)
Figure 4.11 Well low system (redrawn from,Bourguyan et al., 1986).
ΔPap = pressure loss in annulus in the drill pipe = 2,700 psi
Required data:
ΔPP = pump discharge pressure
he total pump discharge pressure of the circulating system can be calculated using Eq.
(4.44) as:
Pt
Ps
PP
Pc
Pb
Pac
Pap
= 90 2,000 300 75 350 2,700 5,515 psi
Fluid low through pipes is considered as either laminar or turbulent. We already discussed about the low pattern in section 4.2 and 4.3. Calculation of pressure drop for
pipe low requires a knowledge of which low relates to the speciic case, since diferent equations apply for each situation based on low type. In such cases, deinition of
Reynolds number (Eq. (4.20) and Eq. (4.21)) is important and it is the determining
criterion for pressure drop calculation. here are established equations in the literature.
he detailed explanation can be found in any basic luid dynamics textbook. here are
some equations that can be explained here.
he pressure drop in laminar low is given by the Hagan-Poiseuille law which is
given in ield units as:
Drilling Hydraulics 171
Lv
1500 di2
PLf
(4.45)
Here:
L
PLf = Laminar low pressure drop, psi
= Length of the pipe, t
For turbulent low, Fanning’s equation can be applied as
f L v2
25.8 d i
Ptf
(4.46)
Here:
Ptf = Turbulent low pressure drop, psi
f
= Fanning friction factor
he friction factor f of Eq. (4.46) can be obtained using Figure 4.12.
4.6 Fluid Flow through Drill Bits
A tri-cone bit has three nozzles.
1
2
p
0.1
2
m vn
(4.47)
9
8
7
6
5
4
3
Friction Factor, f
2
0.01
1
9
8
7
6
5
4
n=1
.0
Q8
Q6
3
2
Q4
0.001
1
9
8
7
6
5
4
Q2
3
2
0.0001
2
100
3 4 5 67 891
1000
2
3
4 5 6 78 91
2
3
4
10,000
5 6 7 8 91
100,000
2
3
4 5 6 7 89
1,000,000
Reynolds Number, NRe
Figure 4.12 Friction factor vs. Reynolds number for mud low calculations (Ormsby, 1954).
172 Fundamentals of Sustainable Drilling Engineering
Here:
p
m
vn
= pressure drop or loss at any section, psi
= mud density in ppg
= mud velocity at the nozzle, t/s
vn
Here:
pbit
pbit
33.36
(4.48)
m
= pressure drop at the bit, psi
Nozzle area can be calculated as:
An
Here:
q
An
0.3208
q
vn
(4.49)
= mud low rate, gpm
= total nozzle area at the bit, in2
For tri-cone bit, there are three nozzles with equal sizes, therefore
An
Here:
dn
3 A 3 dn2
4
(4.50)
= equivalent average diameter of individual nozzle at the bit, in
dn
32
4 An
3
(4.51)
Example 4.11: A drilling engineer was assigned to ind out the nozzle sizes of a tri-cone
bit which will be used for an immediate drilling operation. he supervisor asked the
engineer to use 500 gpm of mud circulation at a pressure drop of 1200 psi through the
bit. It is noted that the mud density is 10 ppg.
Solution:
Given data:
q
= mud low rate = 500 gpm
pbit
= pressure drop at the bit = 1,200 psi
= mud density = 10 ppg
m
Required data:
dn
= equivalent average diameter of individual nozzle at the bit, in
To calculate the mud velocity at the nozzle, Eq. (4.48) is used as:
vn
33.36
pbit
33.36
1200
10
365.44 ft / s
Drilling Hydraulics 173
Equivalent nozzle area can be calculated using Eq. (4.49) as:
0.3208
An
q
vn
0.3208
500
365.44
0.4389 in2
Now equivalent average nozzle size at the bit can be calculated using Eq. (4.51) as:
dn
4 An
3
32
4 0.4389
3
32
13.81in
1
13 14
15
Nozzle sizes are normally available in an integer value of , i.e. , , and .
32 32
32
32
13 13
14
So we have to choose the sizes as , , and
32 32
32
Cross-check for size:
13 13
14
, , and
32 32
32
Equivalent nozzle area can be calculated as:
If we use the sizes as
2
13
1
4
32
4
is less than the design area.
AT
2
14
32
2
0.4095 in2. his design is ok because this area
Again:
13 14
14
, , and
32 32
32
Equivalent nozzle area can be calculated as:
If we use the sizes as
AT
1
13
32
4
2
2
4
14
32
2
0.5598 in2. his design is not ok because
this area is greater than the design area.
herefore the nozzle sizes of
13 13
14
, , and
are ok.
32 32
32
4.7 Pressure Loss Calculation of the Rig System
In the rig system, the total pressure loss includes surface pressure losses, connections
pressure losses, pipe pressure losses (i.e. drillstring: drill pipe, drill collar), annular pressure losses, and pressure drop across the bit (Figure 4.13).
he total system pressure losses of the rig system can be calculated by the following
equation which is similar to Eq. (4.44):
Prig
Psp
PdP
Pdc
Pbn
Pac
h
Pac
cas
Padp
h
Padp
cas
(4.52)
174 Fundamentals of Sustainable Drilling Engineering
PSP
Surface
Padp-cas
Surface
facilities
PdP
Padp-h
Drill pipe
Pac-cas
Annulus
Pac-h
Pdc
Pbn
Drill Collar
Drill bit
Figure 4.13 Schematic drawing of the circulating system.
Here:
Prig
Psp
Pdp
Pdc
Pbn
Pac-h
Pac-cas
Padp-h
Padp-cas
= total pressure loss in the rig system, psi
= pressure loss in surface piping, stand pipe and mud hose, psi
= pressure loss inside drill pipe, psi
= pressure loss inside drill collar, psi
= pressure loss across bit nozzle, psi
= pressure loss in annulus and the drill collars inside hole, psi
= pressure loss in annulus and the drill collars inside casing, psi
= pressure loss around the drill pipe inside hole, psi
= pressure loss around the drill pipe inside casing, psi
4.7.1 Pipe Flow
he following equations are used to determine pressure loss while the Bingham model
is used:
he average velocity:
v
Here:
v
q
di
24.5 q
di2
= avg. luid velocity, t/min
= mud pump rate, gpm
= pipe inner diameter, in
Again, the critical velocity can be calculated using imperial units:
(4.53)
Drilling Hydraulics 175
97
VcB _ i
Here:
VcB _ i
m
di
y _i
p_i
97
p _i
2
p _i
8.2
2
m di y _ i
m di
(4.54)
= critical velocity for the Bingham plastic model in imperial units, t/min
lbm
(ppg)
= Mud density,
gal
= Pipe inner diameter, in
lb f
= Yield point in imperial units,
100 ft 2
= Plastic viscosity in imperial units, cp
VcB _ i ), the pressure drop can be calculated as:
If the low is laminar (i.e. v
p _iv
L
300D
Pdp
y _i
(4.55)
5di
Here:
L = length of the drill pipe, t
If the low is turbulent (i.e. v
lated as:
Pdp
VcB _ i ), the pressure drop at the drill pipe can be calcu-
8.91 10
5
0.8 1.8
m q
di4.8
0.2
p_i
L
(4.56)
4.7.2 Annular Flow
he following equations are used to determine pressure loss when the Bingham model
is used:
he average velocity:
v
24.5 q
2
dh2 ddpo
(4.57)
Here:
dh = Hole diameter, in
ddpo = Outside diameter of drillpipe, in
Again, the critical velocity can be calculated using imperial units as:
VcB _ i
97
p _i
97
2
p _i
6.2
2
m de y _ i
m de
Here:
de = Annular distance, in = dh ddpo or dh ddco
ddco = Outside diameter of drill collar, in
(4.58)
176 Fundamentals of Sustainable Drilling Engineering
If the low is laminar (i.e. v VcB _ i ), the pressure drop at the annulus can be calculated
as:
L
Pan
L
60,000De2
If the low is turbulent (i.e. v
be calculated as:
Pdp
p _i v
y _i
(4.59)
200De
VcB _ i ), the pressure drop at the annulus (drill pipe) can
8.91 10
5
dh ddpo
0.8 1.8
m
3
q
0.2
p_i
dh ddpo
L
(4.60)
1.8
Equation (4.60) can be used for drill collar pressure loss with the change of drill pipe
diameter (ddpo ) by drill collar outside diameter (ddco ).
4.7.3 Bit Flow
he pressure drop across the bit nozzle can be calculated using the following equation
which is similar to Eq. (4.52):
Pbn = Pstandpipe
PdP + Pdc + + Pac
hole+
Pac cas+ Padp
+
hole
Padp
cas
(4.61)
Section 4.6 discusses the nozzle velocity, nozzle area, and nozzle size. However the pressure loss across the bit is calculated as:
Pb
Here:
Pb
m
Cd
8.311 10
5
mq
2
Cd2 An2
(4.62)
= pressure drop or loss at drill bit, psi
= mud density in ppg
= discharge coeicient which is usually 0.95
he pressure drop across the bit can also be calculated with a 0.95 discharge coeicient
as:
2
mq
Pb
(4.63)
10858 An2
he pressure drop across the bit is calculated with a nozzle velocity as:
2
m vn
Pb
1120
Bit hydraulic horsepower (BHHP) can be calculated as:
q Pb
HPb
1714
(4.64)
(4.65)
Drilling Hydraulics 177
Here:
HPb = drill bit hydraulic horsepower, hp
Now, bit hydraulic horsepower per square inch of the bit can be calculated as:
HPb
HP
HPsi
1.273 2b
db
db2
4
Here:
HPsi = bit hydraulic horsepower per square inch of the bit, hp/in2
db = diameter of the drill bit, in
(4.66)
Bit hydraulic power per square inch of the hole drilled can also be calculated as:
HPsi _ h
Here:
HPsi _ h
dh
HPb
4
dh2
1.273
HPb
dh2
(4.67)
= bit hydraulic horsepower per square inch of the hole drilled, hp/in2
= diameter of the hole, in
Example 4.12: Calculate the pressure losses across the diferent sections of drill pipe
and annulus. Use the Bingham plastic luid model where the following data are available: he total vertical depth (TVD) is 10,000 t; the shoes of the casing diameter of 20
and 13-3/8 (ID = 12.565 ) are set at 1200 and 4500 , respectively. he hole diameter is
26” and ater the second casing shoe is 12.25 . A 700 of drill collar with O.D. = 9 and
I.D. = 2.875 was set at the bottom of the drillstring while the drill pipe O.D. = 5.5 and
I.D. = 4.276 . he mud weight is 10 ppg with a plastic viscosity of 12 cp and yield point
is 13 lbm/100t2. he pump rate for mud discharge was 750 gpm and the nozzle velocity
is 22,200 t/min.
Solution:
Given data:
Model = Bingham plastic luid model
TVD
= total vertical depth = 10,000 t
Lcas20"
= total casing length of 20 diameter = 1,200 t
Lcas13 3/8 " = total casing length of 13–3/8 diameter = 4,500 t
dh1
= hole diameter = 26
dh 2
= hole diameter ater second casing = 12.25
dcas id = second casing ID diameter ater second casing = 12.565
Ldc
= total drill collar length = 700 t
ddco
= outside diameter of drill collar = 9
ddci
= inside diameter of drill collar = 2.875
Ldp
= total drill pipe length = (10,000 –700) = 9,300 t
Ldp h
= total drill pipe length at the open hole = (10,000 – 4500 –700) = 4,800 t
ddpo
= outside diameter of drill pipe = 5.5
ddpi
= inside diameter of drill pipe = 4.276”
= mud density = 10 ppg
m
178 Fundamentals of Sustainable Drilling Engineering
y _i
p_i
q
vn
lb f
= yield point = 13.0
100 ft 2
= plastic viscosity = 12.0 cp
= mud low rate = 700 gpm
= nozzle velocity = 22200 t/min = 370 t/s
Required data:
= pressure loss inside drill pipe, psi
Pdp
= pressure loss inside drill collar, psi
Pdc
= pressure loss across bit nozzle, psi
Pbn
= pressure loss in annulus and the drill collars inside hole, psi
Pac–h
Padp–h = pressure loss around the drill pipe inside hole, psi
Padp–cas = pressure loss around the drill pipe inside casing, psi
Figure 4.14 presents the schematic view of the example 4.13. To calculate the stepby-step pressure losses, it is needed irst to calculate the average velocity and critical
velocity.
Inside drill pipe:
he average velocity inside the drill pipe can be calculated using Eq. (4.53) as:
v
24.5 q
2
ddpi
24.5 (700 gpm)
4.276 in
937.97 ft / min
2
Again, the critical velocity can be calculated using Eq. (4.54) as:
VcB _ i
97
97
p _i
2
p
8.2
2
m ddpi y _ i
m ddpi
97 (12cp) 97 (12cp)2 8.2 (10 ppg )
(10 ppg )
4.276 in
2
13.0
lb f
100 ft 2
4.276 in
345 ft / min
As v VcB _ i , the low is turbulent. herefore, the pressure drop across the drill pipe (Sec
1 of Figure 4.14) can be calculated using Eq. (4.56) as:
Pdp
8.91 10
5
0.8 1.8
q
m
0.2
p _i
Ldp
4.8
dpi
d
8.91 10
5
1,062.66psi
100.8 7001.8 120.2 9,300
4.2764.8
Drilling Hydraulics 179
26"
Drill pipe
5 12
Outmost casing string
or conductro pipe
1200'
Cement
4500'
Sec 6
Surface casing
20" casing shoe
(Conductor pipe)
10,000
Sec 1
9,300
casing shoe
13 3"
8
(Surface casing)
Sec 5
Hole dia 12.25"
5.5" drill pipe
Sec 2
Reservoir
formation
4,800"
9" drill colar @ 700'
Sec 4
700'
Sec 3
Figure 4.14 Schematic drawing of the casing and cementing system for pressure losses
calculations for Example 4.13.
Inside drill collar:
he average velocity inside the drill collar can be calculated using the same equation,
Eq. (4.53), as the drill pipe:
v
24.5 q
2
ddci
24.5 (700 gpm)
2.875 in
2074.86 ft / min
2
Again, the critical velocity can be calculated using Eq. (4.54):
VcB _ i
97
p _i
97
2
p
8.2
m ddci
2
m Ddci y _ i
180 Fundamentals of Sustainable Drilling Engineering
97 (12cp) 97 (12cp)2 8.2 (10 ppg )
(10 ppg )
2.875 in
2
13.0
lb f
100 ft 2
2.875 in
359.77 ft / min
As v VcB _ i , the low is turbulent. herefore, the pressure drop across the drill collar
(Sec 2 of Figure 4.14) can be calculated using Eq. (4.56) as:
Pdc
8.91 10
5
0.8 1.8
m
0.2
q
p _i
Ldc
5
8.91 10
100.8 7001.8 120.2 700
2.8754.8
4.8
ddci
537.68 psi
Inside drill bit:
Equivalent nozzle area can be calculated using Eq. (4.49) as:
An
q
vn
0.3208
0.3208
700 gpm
370 ft / s
0.6069 in2
Now if we consider Cd = 0.95, Eq. (4.63) is used to calculate the pressure loss across the
bit nozzle (Sec 3 of Figure 4.14) as:
mq
Pbn
2
10 ppg
10858 An2
700 gpm
2
1225.25 psi
10858 0.60692
Around outside of drill collars and annulus:
he average velocity outside of the drill collar and hole (i.e. annulus) can be calculated
using Eq. (4.57) as:
v
24.5 q
2
dh2 ddco
24.5 (700 gpm)
12.25 in
2
9 in
2
248.33 ft / min
Again, the critical velocity can be calculated using Eq. (4.58) as:
VcB _ i
97
p _i
97
2
p _i
m
6.2
313.52 ft / min
dh ddco
2
y _i
dh ddco
97 (12cp) 97 (12cp)2 6.2 (10 ppg )
(10 ppg )
m
12.25 in 9 in
12.25 in 9 in
2
13.0
lb f
100 ft 2
Drilling Hydraulics 181
Here, v VcB _ i , therefore the low is laminar. For this type of low, the pressure drop at
the annulus around the drill collar (Sec 4 of Figure 4.14) can be calculated using Eq.
(4.59):
Pac
Ldc
h
v
p _i
Ldc
60,000De2
200De
700 ft
200
700 ft
y _i
13.0
(12cp)
60,000
248.33 ft / min
12.25 in – 9 in
2
lb f
100 ft 2
17.29psi
12.25 in – 9 in
Around outside drill pipes and annulus:
here are two parts (Sec 5 and Sec 6) for this calculation.
he average velocity for outside drill pipe and hole (i.e. annulus) can be calculated
for Sec 5 using Eq. (4.57):
24.5 q
2
dh2 ddpo
v
24.5 (700 gpm)
12.25 in
2
5.5 in
143.14 ft / min
2
Again, the critical velocity can be calculated using Eq. (4.58):
97
VcB _ i
97
p _i
2
p _i
m
6.2
dh ddpo
2
y _i
dh ddpo
97 (12cp) 97 (12cp)2 6.2 (10 ppg )
(10 ppg )
m
12.25 in 5.5 in
2
13.0
lb f
100 ft 2
12.25 in 5.5 in
292.79 ft / min
Here, v VcB _ i , therefore the low is laminar. For this type of low, the pressure drop
at the open hole annulus around the drill pipe (Sec 5 of Figure 4.14) can be calculated
using Eq. (4.59) as:
Padp
Ldp
h
h
p _i
v
2
e
60,000D
4800 ft
200
Ldp
h y _i
200De
13.0
4800 ft
(12cp)
60,000
143.14 ft / min
12.25 in – 5.5 in
2
lb f
100 ft 2
12.25 in – 5.5 in
49.24 psi
Again, the outside drill pipe and cased hole (i.e. annulus) part (Sec 6) pressure loss
can be calculated in the same fashion. he average velocity outside the drill pipe and
cased hole (i.e. annulus) can be calculated for Sec 6 using Eq. (4.57) as:
182 Fundamentals of Sustainable Drilling Engineering
v
24.5 q
2
ddpo
24.5 (700 gpm)
2
dcas
id
12.565 in
2
5.5 in
134.37 ft / min
2
Again, the critical velocity can be calculated using Eq. (4.58) as:
97
VcB _ i
2
p _i
97
p _i
m
6.2
dcas
h
97 (12cp) 97 (12cp)2 6.2 (10 ppg )
(10 ppg )
m
dcas
h
ddpo
2
y _i
ddpo
12.565 in 5.5 in
2
13.0
lb f
100 ft 2
12.565 in 5.5 in
292.35 ft / min
Here, v VcB _ i , therefore the low is laminar. For this type of low, the pressure drop at
the cased hole annulus around the drill pipe (Sec 6 of Figure 4.14) can be calculated
using Eq. (4.59):
Padp
4500 ft
60,000
Ladp
p_i v
60,000De2
cas
(12cp)
cas
134.37 ft / min
12.565 in – 5.5 in
2
Ladp
cas y _ i
200De
4500 ft
200
13.0
lb f
100 ft 2
12.565 in – 5.5 in
= 43.82 psi
4.7.4 Pump Calculations
he pump pressure is the pressure required to circulate the mud throughout the circulation system. It is the summation of the entire pressure drop in every step of the system.
herefore the pump pressure drop can be given as:
Pp
Here:
Pp
Pfl
Pb
Pfl
(4.68)
= pump pressure drop, psi
= frictional pressure losses at diferent components of the circulating system,
psi
Example 4.13: While drilling a hole of 12 ¼” at a depth of 8,000 t, the pump pressure drop is 4,500 psi, and total pressure loss is 2,200 psi. A 10.5 ppg mud is used to
achieve a bit hydraulic horsepower per square inch of the hole of 1.2. Calculate the
low rate of the mud where it is assumed Cd = 0.95.
Drilling Hydraulics 183
Solution:
Given data:
dh
= diameter of the hole = 12.25 in
TVD = total vertical depth = 8,000 t
Pp
= pump pressure drop = 4,500 psi
Pfl
= frictional pressure losses = 2,200 psi
= mud weight = 10.5 ppg
m
HPsi _ h = bit hydraulic horsepower per square inch of the hole drilled = 1.2hp/in2
Required data:
q
= mud low rate, gpm
he drill bit pressure drop can be calculated using Eq. (4.68) as:
Pb
Pp
Pfl
4500 2200 2,300 psi
Now, bit hydraulic horsepower (BHHP) can be calculated using Eq. (4.65) as:
HPb
q 2300
1714
1.342 q
Bit hydraulic horsepower per square inch of the hole drilled is calculated using Eq.
(4.67) as:
HPsi _ h
1.342 q
dh2
105.34 gpm
1.273
1.2
q
0.702 dh2
0.702
12.25
2
4.8 Current Development on Drilling Hydraulics
4.8.1 Drilling Hydraulics Optimization
Drilling hydraulic optimization with conventional drilling luid is a well-known practice which has been widely practiced in the oil industry. Drilling hydraulics is mainly
discussing the pressure needed during drilling to improve drilling and provide suicient cutting removal capacity and decreasing pressure losses in the circulating system.
here are lots of empirical correlations to optimize hydraulics. For example, Fulletron
charts, Amoco curves, etc., or the use of optimization theory to maximize some arbitrary functions such as maximum bit hydraulic horsepower or jet impact force are
among them. his section discusses the current development in hydraulic optimization
using down-hole motors and its improvement in overall drilling optimization. It also
covers the improvement in the underbalance drilling (UBD) optimization using aerated luids. Swanson et al. (1994) stated that drilling hydraulics optimization involves
manipulation of several independent variables. One can obtain maximum/minimum
for one or more dependent variables within boundaries imposed by the cost, safety
and the physical properties of the analyzed system. Table 4.2 shows a summary of the
variables and constraining parameters that are involved in a typical drilling operation.
184 Fundamentals of Sustainable Drilling Engineering
In addition, accurate quantiication of system losses (we already discussed in the previous sections) enhances the validity of calculated equivalent circulating density (ECD)
and other drilling parameters and indicators. Determination of pressure drop at the
bit is one of the major concerns for establishing proper hydraulic design. heoretically,
most of the hydraulic power should be utilized by the bit. he hydraulic power will
then be helpful in hole cleaning and removal of cuttings from the well. Optimization
of this power will be very critical in the directional and horizontal well where cleaning
is a common and costly problem. Even so, this will be most critical particularly in the
case of extended reach drilling where larger and longer wellbores are drilled. So, lots
of studies were carried out to develop a good procedure in cutting transport. Studies
found that turbulent low regimes performed better at high angles. So a drilling luid
with a well-designed luid rheology should be pumped into the well with high velocity
to improve cutting transport and avoid accumulation of cutting in the horizontal and
deviated section of the well. Field measurements have revealed that the pressure drop
over a slim borehole can also depend signiicantly on the rotation speed of the drillpipe. Studies explain the inluence of drillpipe rotation on the axial frictional pressure
drop for the simplest cases such as laminar low, Newtonian luid etc. For laminar low
inertial forces caused by rotation and eccentricity of the drillpipe give rise to the axial
pressure drop.
4.8.2 Down-hole Motor Technology
In the last decades, use of down-hole motors have increased to meet challenges such
as speedup drilling of vertical wells, optimized drilling of directional and horizontal wells and in particular, extended reach drilling, deep and ultra-deep water wells.
Determination of proper jet nozzle size is important because a signiicant increase in
rate of penetration (ROP) can be achieved through proper choice of nozzle sizes. For
true optimization of jet bit hydraulics, an accurate down-hole motor model must be
incorporated including coniguration, dimension, weight on bit, etc. So the motor horse
power required must be taken as a separate because the pressure drop across the motor
is a function of coniguration of the motor (number of lobes) and weight on bit applied.
Experimental studies showed that ROP increases with a decrease in the number of
lobes of the motor under the same weight on bit. At high weight on bit, all motor types
gave similar results except the two-lobe motor which resulted in less ROP as compared
Table 4.2 Variables and constrained parameters involved in a typical drilling operation.
Variables
Restriction
Drilling rate
Pump capacity
Drilling Fluid rheology
Drilling cost
Drillstring geometry
Minimum cuttings transport velocity
Bit nozzle size
Wellbore stability
Drilling luid low rate
Wellbore geometry
Drilling Hydraulics 185
to other. his is mainly due to the higher WOB used in hard formations which need a
strong motor to be used in such an environment. In addition, ROP increases with the
increase of WOB for the same motor coniguration. Figure 4.15 shows the above relationship as each motor coniguration has the optimum operating condition that gives
better results. Studies showed that for the sot formations, the best motor coniguration
is two loops which can result in a higher ROP, but in the case of hard formations or
of motions in which we need to apply more weight on bit, motors more than 4 loops
will be optimal. Figure 4.16 shows a simple schematic of two loops that is used in sot
formations. Based on that, best motor coniguration that can give better ROP in sot
formations is double-lobes motor as shown in Figure 4.16. Studies also suggested that
analysis of optimum low rate with the down-hole motor gives a more realistic estimation of the optimum low rate. Also sizing of the bit nozzles is dependent on the coniguration of the motor in use.
4.8.3 Drilling Hydraulics for the Aerated “Foam” Fluids
Compared to conventional drilling luids, relatively little is known about the hydraulic
and rheological properties of foamed luids. Now days, foam has been used in various
ields as drilling luids. A typical use of foam luids is in Extended Reach Drilling (ERD)
where Equivalent Circulating Density (ECD) can be reduced with these types of luids. Other useful applications are in the Underbalanced Drilling (UBD). Foam can be
formed by mixing a gas phase (air or similar) with a liquid phase which is either water
(stable foam) or aqueous polymer solution (stif foam) containing 1 – 2% by volume
foaming agent. he major advantage of foam is its lexibility in controlling the efective
mud density which has a direct relation with the bottom-hole pressure. Field experiences have shown that the performance of aerated luids is diicult to predict. here are
60
2/2
50
R O P (ft/hr)
40
2/3
30
3/4
20
MOB (Ibf)
Figure 4.15 ROP vs. WOB for diferent motor conigurations.
100,000
90,000
80,000
70,000
60,000
50,000
40,000
20,000
10,000
0
0
30,000
4/5
5/6
6/7
7/8
10
186 Fundamentals of Sustainable Drilling Engineering
Shaft
Elastomer
da
Cavity
db
Figure 4.16 Motor cross-section.
factors that have a signiicant efect on the hydraulics of the aerated luids such as type
and percentage of gas and liquid forming the foam, foam quality, optimum foam low
velocity, slippage efect, etc. here are diferent hydraulic models that are used generally
to model the drilling hydraulics for the aerated drilling luids:
Blauer et al. Model (1972): it predicts friction losses in laminar, transitional, and
turbulent regimes for foam low assuming that the foam behaves is like a Bingham
plastic type of luid, and can be expressed as below:
Q
Here
D
gc
Q
τw
τy
p
D3 w g c
4
1
32 p
3
y
w
1
3
4
y
(4.69)
w
= pipe diameter, L
= gravitational constant, L/t2
= low rate, L3/t
= shear stress at tubing wall, m/Lt2
= shear stress at y-direction, m/Lt2
= plastic viscosity, m/Lt
Sanghani Model (1982): it is similar to Blauer et al. model. However, the diference
is that Sanghani assumed the foam behaves as a pseudoplastic luid. His model is as
below:
Pf
L
4 K 8 3n 1 Q
D
nD 3
n
(4.70)
Here
n
= low-behavior index, dimensionless
K
= consistency index of power law model, dimensionless
Pf
= Pressure loss due to friction per unit length, (m/Lt2)/L
L
Reidenbach et al. Model (1986): this model is empirical correlations for calculating rheological properties of N2 and CO2 foam. he model is based on laminar low with viscosity
Drilling Hydraulics 187
dependent on foam quality, yield point, base luid consistency index, and low behavior
index; and it is developed as below:
a
'
YP
8v
d
1
8v
k
d
n' 1
'
(4.71)
Here
= apparent viscosity, m/Lt
= geometry dependent yield stress, m/Lt2
v = foam velocity, L/t
d = pipe diameter, L
K ' = geometry dependent consistency index, dimensionless
n' = geometry dependent low behavior index, dimensionless
a
'
YP
Valco and Economides’ Model (1992): this model is proposed by a new constitutive
equation for non-Newtonian compressible luids and the ratio of the liquid density to
the foam density. It also states that if volume-equalized shear stress is plotted against volume-equalized shear rate, points obtained at diferent qualities and diferent geometries
lie on one curve in isothermal conditions. So, using this principle, frictional pressure
losses during isothermal, steady state low can be estimated using the equation below:
1
D
dp
dx
Here
ff
a
b
c
D
g
p
2 f f b2 c 2
D g p3 4 f f abc 2 p2 2 f f a 2c 2 p
bp3 ap2 abc 2 p a 2 p2
(4.72)
= friction factor, dimensionless
= constant coeicient, L2/t2
= constant coeicient, L3/m
= constant coeicient, m/(t.L2)
= pipe diameter, L
= gravitational constant, L/t2
= pressure, m/(Lt2)
Gardiner et al. Model (1998): this model uses the “Volume Equalization Principle” and
assumes the low is isothermal. In addition, the efect of changing axial velocity on radial
low is negligible. He expressed his model as below:
Q
R2 uslip
n
3n 1
n 1 n 1
dp R
dx
2k
1
n
Here
Q
= low rate, L3/t
R
= universal gas constant
uslip = slip velocity, L/t
= speciic volume expansion ratio, dimensionless
n
= low behavior index, dimensionless
k
= consistency index, dimensionless
(4.73)
188 Fundamentals of Sustainable Drilling Engineering
Ater the analysis of many experimental studies, it is concluded that there is no model
out of the above that can best predict the pressure losses of the actual operations.
Drilling hydraulic optimization of aerated luids is mainly focused on determining
optimum foam low rate, back pressure, foam quality and others to have an efective
cutting transport. Hydraulic optimization varies from well to well depending on the
well trajectory and drillstring used for drilling.
4.8.4
Drilling Hydraulics of Aerated luids for Vertical Wells
he great advantages of using aerated muds for vertical wells are the elimination of lost
circulation, and formation damage. So the efective foam drilling practice is the efectiveness of cutting transportation while keeping the circulating bottomhole pressure at
a minimum level. One of the models considers the combined efects of the drilling rate,
the annular back pressure, foam injection rates on the circulating bottomhole pressure,
and eiciency of cuttings transport (Yibing and Ergun 2004). Foam velocity is used as
primary term to control the bottom hole pressure whereas cuttings concentration is
used to evaluate the cutting transport eiciency.
Critical foam velocity is speciied as the minimum velocity required to lit and transport the cutting out. Krug and Mitchell (1972) suggested that it should be 1.5 t/s. Guo
et al. (1995) suggested that it is the minimum velocity to give 4% as maximum cuttings concentration. Based on that, optimum foam velocity (OFV) is the velocity which
yields minimum bottom hole pressure (BHP) while keeping the maximum cuttings
concentration in the annulus as less than 4%. Gas Liquid Ratio (GLR) has a signiicant
efect on the BHP and therefore, it requires the optimization of GLR irst. In contrast,
CLR is a function of annular back pressure (ABP). So, critical GLR is that gives minimum optimum BHP. Determination of the optimum ABP is an essential irst step to
achieve minimum BHP. Efect of drilling rate on ABP is negligible, whereas, borehole
diameter and well depth have signiicant efects on the ABP. ABP increases when hole
diameter decreases. It also increases when true vertical depth increases. In general, for
large hole diameters, the optimum foam rate is always higher than the minimum low
rates required for cuttings transport. Although hydraulic optimization can be achieved
by using these higher injection rates, the overall economics of the well may set a limit
on the volumetric low rates.
4.8.5
Drilling Hydraulics of Aerated luids for Deviated, Horizontal and
ERD Wells
New critical deposition velocity correlation for foam-cuttings low is introduced where
the model is solved numerically to predict cuttings bed height as a function of the drilling rate, the foam injection rates, the rate of luid inlux from the reservoir, and the
borehole geometry. Foam muds are used in UBD to achieve a lot of beneits such as
increased productivity by reducing formation damage, increased rate of penetration,
eliminating loss of circulation, improved formation evaluation while drilling, reduced
stimulation requirements, etc.
For deviated and horizontal wells, a two-layer model is developed to study factors
afecting cuttings transport with foam as shown schematically in Figure 4.17 (Skelland
Drilling Hydraulics 189
and A.H.P 1967). he model also states that foam with cuttings creates a uniform
homogeneous property in an arbitrary cross-sectional area. he foam velocity must be
higher than the critical deposition velocity to convey cutting in suspension.
Another model (Crowe 1998) stated that a cutting bed normally formed when the
annular low rate cannot prevent cutting particles from depositing. As the bed grows,
the velocity and frictional pressure gradient increase until an equilibrium condition is
reached. herefore, the model considers two diferent layers (upper layer and stationary bed) and employs mass and momentum conservation equations. he model has the
following diferential form:
t
AoCs s us
Ao p
Cs
x
x
Ao
AoCs s us2
v
uf
us
1
Cs f s s us2 So
2
(4.74)
Here
Ao = cross-sectional area of the upper layer in the horizontal model, m2
Cs = volumetric concentration of the dispersed phase
3
s = density of the dispersed phase, kg/m
us = velocity of the dispersed phase, m/s
u f = foam velocity, m/s
p = pressure, Pa
3
v = coeicient accounting for drag force, kg/(s.m )
f s = fanning friction coeicient of the dispersed phase, dimensionless
So = source term of oil, kg/(s.m3)
Ford et al. (1990) reported that larger cuttings are more diicult to transport at all
angles of inclination if using low-viscosity luids. Wilson (1978) stated that when cuttings decrease in size to 0.5 mm in a near horizontal condition, it is much more diicult
to move the small particles. Tomren (1979) stated that an increase in the hole angle
greatly decreases the cuttings transport eiciency and reported that a 40° inclination is
the most diicult angle for hole cleaning.
Formation Fluid
Dilute Layer
AO
uf
Mass Transfer
hb
Formation Fluid
Figure 4.17 Schematic view of two-layer model for cuttings transport with foam in
horizontal wells.
uf
190 Fundamentals of Sustainable Drilling Engineering
4.8.6
Drilling Hydraulics for Coiled Tubing Drilling
Due to the fact that coiled tubing is curved in shape, friction losses of low of the drilling luids are greater than that of a straight pipe because of the existence of secondary
low. his low is caused by the efect of centrifugal forces in curved-low geometry.
Numerous eforts have been given to provide a complete set of friction-factor correlations for both Newtonian and non-Newtonian luids under laminar and turbulent low
regimes (Zhou et al., 2005). hese correlations took into account the pipe roughness
and its efects on the pressure losses.
Ito (1969): For Newtonian Fluids, one of the reported correlations in literature is the
Ito correlation for laminar low which can be written as:
fCL
f SL
Here
fCL
f SL
N De
NRe
0.1033 N D0.5e
1
1.729
N De
0.5
3
1.315
N D0.5e
(4.75)
= the friction factors of laminar low in curved pipes, dimensionless
= the friction factors of laminar low in straight pipes, dimensionless
= Dean number, (NRe (a/R))
= Reynolds number, dimensionless
In Eq. (4.75), the Dean number is deined as the product of the Reynolds number and
the square root of the curvature ratio (a/R). his correlation was obtained numerically
using the approach of boundary-layer approximation.
Ito (1959) has also developed a correlation for turbulent low which can be written
as:
fCT
1 a
4 R
0.5
0.029 0.304 N Re
a
R
2
0.25
(4.76)
Here
fCL = the friction factors of turbulent low in curved pipes
2
a
< 300.
Equation (4.76) is valid for 0.034 < N Re
R
Liu and Masliyah (1993): he Liu and Masliyah correlation for laminar low can be
written as:
0.0908 0.0233
fCL
f SL
a
R
0.5
N D0.5e 0.132
49
1
N De
a
R
0.5
0.37
a
R
Here
fCL = the friction factors of laminar low in curved pipes
f SL = the friction factors of laminar low in straight pipes
N De = Dean number
0.2
(4.77)
Drilling Hydraulics 191
For N De 5000. he correlation was developed on the basis of the numerical solution
of the governing Navier-Stokes equations.
Srinivasan et al. (1970): Srinivasan and coauthors developed a correlation for turbulent low which can be written as:
0.084
fCT
Equation
(4.78)
is
a
R
0.2
(4.78)
N D0.2e
valid
for
(N De )cr
N De
14000 and 0.0097
a
R
0.135.
It is noted that Eq. (4.75) to Eq. (4.78) are developed for Newtonian luid.
Zhou and Shah (2002): Zhou and Shah have developed a correlation for non-Newtonian luid and laminar low. he model can be written as:
1
n
a
(2) n 1 N Deon 1 ( )0.5 Y
R
f CL
where Y
Here
Co
C1
N Deo
C2n
C3
N D2 eo
C4n2 C5
3n
n 1
n , and
N Deo
(4.79)
[
'
b ' ln(n)]2.
fCL = the friction factors of laminar low in curved pipes
N Deo = generalized Dean number for Eq. (4.79)
Co , C1, C2 , C3, C4, C5 = correlation constants
In Eq. (4.79), Co through C5 and a and b are the correlation constants given in the
Technical Report for the coiled tubing Consortium (2002). n is the low-behavior index
of luid and the Dean number is deined as:
n
N Deo
Here
vm
k
a
R
2a vm2 n
K
a
R
(4.80)
= mean velocity
= consistency index of power law model
= radius of coiled tubing
= density of luid
= radius of coiled tubing reel
A generalized dean number was introduced as:
N Deg
where
N Reg
a
R
0.5
(4.81)
192 Fundamentals of Sustainable Drilling Engineering
N Reg
d nvm2 n
K p 8n
(4.82)
1
Here
N Deg = generalized Dean number in equation (4.81)
N Reg = generalized Reynolds number
he above correlation [Eq. (4.80)] is derived following the approach of boundary-layer
approximation and assuming a power-law-model luid.
Zhou and Shah (2006): Zhou and Shah again developed a correlation for the nonNewtonian luid in a turbulent low case. his correlation was developed based on
extensive low experiment on diferent sizes of coiled tubing and diferent luids. he
analysis of the turbulent low data showed that the following form of correlation for
friction factor can be applied for guar, HEC, and PHPA luids:
C1 C2 ln n C3
fCT
a
R
C 4 C5
a
R
1.5
(4.83)
N Deg
Here
N Deg = generalized Dean number for Eq. (4.83)
C1, C2 , C3 , C4, C5 and = correlation constants determined separately for each luid
For xanthan luids, the following correlation is obtained.
C1 C2
fCT
a
R
(4.84)
N Deg
A new hydraulic calculation method was presented by Pilehvari and Serth (2005), and
later modiied to incorporate the efective diameter for eccentric annuli that includes
the efect of both conduit geometry and luid rheology. Tests on a variety of drilling
luids indicate that the method is capable of reliably predicting the pressure drop of
most drilling luids in eccentric annuli. Experiments showed that the annulus mixture
velocity plays a signiicant role in cuttings transport, and this can be achieved only if the
low in the annulus is turbulent. Also the eccentric condition of the tubing in the hole
will result in a dramatic decrease in cuttings transport eiciency.
4.9 Future Trend on Drilling Hydraulics
he future of drilling hydraulics will be very challenging because of the nature of
unconventional hydrocarbon resources. Current eforts will lead to newer and more
sophisticated types of technology to tackle high pressure, high temperature drilling.
he following sections discuss some of these aspects.
Drilling Hydraulics 193
4.9.1
Hydraulics of Dual Gradient Drilling
Dual gradient systems are one of the new technologies introduced to address the hydrostatic pressure of the riser drilling luids for deep of-shore operations. In dual gradient,
the well is drilled with two diferent annulus gradients in place, which is a good advantage for deep-water drilling. Utilization of the dual gradient will reduce hydrostatic
pressure against the formation, and will therefore reduce the number of casing strings
required. here are two methods for dual gradient. One is known as subs Mudlit drilling; where the marine riser is eliminated subsea pumping system is introduced to send
the return mud to the drilling rig through the small diameter return line. he other
method is the liquid or gas lit method, where a low density luid is injected into the
bottom of the riser on the sea loor. he low density luid will reduce the density of the
return mud in the riser to become equivalent to a seawater gradient. Later the injected
luid is separate from the mud at the surface. Studies showed that liquid and gas lit
method is better because it does not utilize subsea pump, or in other words, it does not
introduce complications into the system.
here are several hydraulic parameters that need to be considered, including density
and mud rheology, low rate, and annulus coniguration. he low rate should be estimated correctly because if it is less than the minimum rate, there will be hole cleaning
problems. If it is too high, the pressure at the open hole section may exceed the fracture
pressure. To manage the low rate, the operator has to consider pump capacity, cuttings
transport and bit hydraulic optimization.
4.9.2 Enlargement of Hydraulics Operating Window
he need to mechanically control bottomhole pressures for drilling narrow mud weight
windows urges an increase in the use of Managed Pressure Drilling (MPD). Recent studies concentrate on integrating drilling luid design and MPD operations for a speciic
application. MPD has gained widespread acceptance to overcome many of the drilling
related problems associated with the narrow hydraulic operating window between pore
pressure and fracture pressure gradients. It requires a closed and pressurized drilling luid
system using special equipment to apply annular backpressure in order to maintain wellbore in a stable condition as IADC (2006) has deined.
Recent approaches in enlarging the operating window are looking again at the rheological behavior of the current drilling luids used in the oil industry to establish the
compromise between suiciently high rheology and gel strengths to adequately suspend
high-density weighting agents and eventually get better control of down-hole hydraulics. he new material used in this area is a Treated Micronized Barite (TMB) which is
the same as normal API Barite of 97%. However, the particle sizes have been decreased
from 75 microns to less than 5 microns. By using real-time downhole hydraulic information from behind the bit, it becomes easier to navigate through narrow pressure
margins using MPD choke controls. Coupling MPD techniques with the new-treated
drilling luids manages to reduce the equivalent circulating density (ECD) and manage narrow hydraulic operating windows such as extended-reach drilling and deep ofshore drilling. Based on recent experiences, Doug and Lee (2011) managed to lower the
ECD by 50% with low rheology as compared to conventionally weighted system. hey
194 Fundamentals of Sustainable Drilling Engineering
manage also to increase low rates by 15% – 25% for the same pump pressures which
gives lexibility to navigate the wellbore through depleted zones. However, the most
important issue is the pressure-while drilling (PWD) tools response. Recently, PWD
has been improved in TMP luids due to the lower rheological proile providing rapid
and true pressure transmission of downhole near bit conditions. However, there are still
challenges that need to be addressed by the researcher.
4.9.3
Introducing New Hole Cleaning Devices
Hole cleaning is generally considered to be well understood when drilling deviated
and horizontal holes. Less than optimal hole cleaning can lead to non-productive time,
poor bore-hole quality and loss of drillstring or even the well. So hole cleaning was
given proper attention because it afects many drilling parameter and leads at the end to
high ECD. So it is very important to ind a way to improve cutting removal and prevent
cuttings from settling in the low side of the deviated hole sections. he right approach
is to plan and address hole cleaning. One of these approaches is the use of Mechanical
Hole Cleaning Devices (MHCD) which are good in drilling highly deviated sections
with large hole sizes. hese tools gradually reduce cutting bed height by mechanical
erosion of cutting beds buildup where they cannot be avoided under normal drilling
conditions. hese tools use the hydrodynamic and hydromechanical efect.
One type of these tools is HydrocleanTM drill pipes (Figure 4.18) which is developed
by the VAM drilling company. his tool consist of two sections: the irst is the hydrocleaning zone which provides optimum scooping efect while the variable helix angle
accelerates the cuttings and re-circulates them on the high side of the hole. he second
is the hydro-bearing zone which protects the wellbore from the blades and provides
less frictional load and better sliding properties. he optimum string design is to use
Hydroclean
Recirculation zone
High velocity zone
of annular passage
Dynamic
Recirculation
View from bottom
Q
Final cutting
bed height
Two zones of full
scooping and lift
of cuttings
Initial cutting
bed height
Figure 4.18 Features of HydrocleanTM drill pipe.
ROP
Drilling Hydraulics 195
HydrocleanTM drill pipes in deviated hole more than 40° angles, and one HydrocleanTM
drill pipe every three stands of drill pipes.
4.10 Summary
Drilling hydraulics is one of the most important issues in drilling engineering. his
chapter covers almost all aspects of hydraulics. he diferent types of luids, models, and
low regimes are discussed elaborately. he pressure loss calculation shows the losses at
diferent parts of the circulating system. he current and future trends of the hydraulic
system are also discussed in the last sections of the chapter.
4.11 Nomenclature
A
a
C
Cd
di
dh
ddpo
de
ddco
Dm
f
Fdown
Fup
Fself
HPb
K
k
L
Li
Ltvd
m
M
n
N1 , N 2
p
pa
Pb
po
pt
= inner cross-sectional area of the luid column, in2
= parameter in Carreau–Yasuda model, dimensionless
= conversion constant
= discharge coeicient which is usually 0.95
= pipe inner diameter, cm, in.
= hole diameter, in
= outside diameter of drillpipe, in
= annular distance, in = dh ddpo or dh ddco
= outside diameter of drill collar, in
= measured depth, t
= fanning friction factor
= downward force on the luid element applied by the luid
column above, lbf
= upward force on the luid element applied by the below luid column, lbf
= luid element’s self-weight acting as a downward force, lbf
= drill bit hydraulic horse power, hp
n
= low consistency index, Pa. s
2
= reservoir permeability, m
= length of the drillpipe, t
= length for the section of interest (which is part of Ltvd )
= total vertical depth, t
= mass of gas
= gas molecular weight
m
= mole of gas =
M
= the Fann rpm reading
2
= pressure of the system, psig, N / m
= Absolute pressure
= pressure drop or loss at drill bit, psi
= surface pressure at Ltvd 0 which is also the constant of the integral.
= total hydrostatic pressure
196 Fundamentals of Sustainable Drilling Engineering
Pac-h
Pac-cas
Padp-h
Padp-cas
Pbn
Pdc
Pdp
Prig
Psp
v
dp
dLtvd
q
QcB
R
t
T
ux
V
v
v
VcB
VcB _ i
Wsp
Wsp
Z
y
p_i
y _i
m
i
om
d
p
dux
or
dy
0
N1 , N 2
3
300
= pressure loss in annulus and the drill collars inside hole, psi
= pressure loss in annulus and the drill collars inside casing, psi
= pressure loss around the drill pipe inside hole, psi
= pressure loss around the drill pipe inside casing, psi
= pressure loss across bit nozzle, psi
= pressure loss inside drill collar, psi
= pressure loss inside drill pipe, psi
= total pressure loss in the rig system, psi
= pressure loss in surface piping, stand pipe and mud hose, psi
= avg. luid velocity, t/min
= pressure gradient with respect to total vertical depth, psig/t
= circulating volume or mud pump rate, cc/s, gal/min
= critical low rate for the Bingham plastic model, gpm
= universal gas constant
= time, s
= absolute temperature
= luid velocity in porous media in the direction of x axis, m / s
= gas volume
= avg. luid velocity, cm/s
q
= avg. luid velocity, t/s =
2.448 di2
= critical velocity for the Bingham plastic model, t/s
= critical velocity for the Bingham plastic model in imperial unit, t/min
2
= speciic weight of luid, lb f / in ft
2
= speciic weight of luid, lb f / in ft
= universal gas constant
3
3
= porosity of luid media, m / m
= fractional order of diferentiation, dimensionless
= shear stress, Pa
= a minimum shear stress that needs to initiate luid low, Pa
= plastic viscosity in imperial unit, cp
lb f
= yield point in imperial unit,
2
= luid density, gm/cc, lbm/gal 100 ft
= mud density, ppg
= mud weight for the section of interest
= original mud density, ppg
= dynamic viscosity of luid, Pa-s
= Bingham plastic viscosity, Pa-s
= the velocity gradient perpendicular to the direction of shear, or equivalently the strain rate, s−1
= yield point stress at dial reading at 3 rpm
= he Fann dial reading at N1 and N 2 rpm
= the Fann dial reading at 3 rpm
= the Fann dial reading at 300 rpm
Drilling Hydraulics 197
= the Fann dial reading at 600 rpm
600
np
dux
dy
.SF
pm
nc
nw
eff
m
0
Ltvd
ΔPP
ΔPac
pan
ΔPap
ΔPbn
ΔPdc
ΔPdp
PLf
ΔPsp
Ptf
1
= shear rate or velocity gradient perpendicular the plan of shear, s
= power-law exponent or low behaviour index, dimensionless
= shape factor which is medium-dependent
= apparent shear rate within the porous medium,
= power-law exponent for Carreau–Yasuda model, dimensionless
= number of wellbore sections
= luid efective viscosity, Pa s
= mud density, ppg
= luid dynamic viscosity at zero shear rate, Pa s
= luid dynamic viscosity at ininite shear rate, Pa s
= time constant in Carreau–Yasuda model, s
= ratio of the pseudopermeability of the medium with memory to luid vis3 1
cosity, m s / kg
= a dummy variable for time i.e. real part in the plane of the integral, s
= diferential total vertical depth, t
= pump discharge pressure, psi
= pressure loss in annulus in the drill collars, psi
= annular pressure loss, psi
= pressure loss in annulus in the drill pipe, psi
= pressure loss across bit nozzle, psi
= pressure loss inside drill collar, psi
= pressure loss inside drill pipe, psi
= laminar low pressure drop, psi
= pressure loss in surface piping, stand pipe and mud hose, psi
= turbulent low pressure drop, psi
4.12 Exercise
Ex 4.1: Calculate the shear stress of a luid which has a viscosity of 60 cp and a shear
rate of 10 s–1.
Ex 4.2: Calculate the viscosity of a luid if the shear stress is 15 Pa and the shear rate
is 12 s–1.
Ex 4.3: A thin movable plate is set 2.5 cm above a stationary plate having a crosssectional area of 30 cm2. If a force of 300 dynes is required to just initiate the upper plate
and a force of 650 dynes is needed to move the plate with a uniform velocity of 7 cm/s,
calculate the yield point and plastic viscosity of the luid.
Ex 4.4: An engineer used a Fann V-G meter to measure the viscosity of the Bingham luid and found the following Fann data: 300 35; 600 65,
and 200 25; 400 55. Calculate the plastic viscosity, and yield point of the luid using
the Bingham plastic model.
Ex 4.5: A moving plate is set 3 cm above a stationary plate which has a cross-sectional area of 20 cm2. Calculate the consistency index and low-behavior index if a force
198 Fundamentals of Sustainable Drilling Engineering
of 270 dyne is required to move the upper plate at a constant velocity of 9 cm/s and a
force of 350 dyne is needed to move the plate with a uniform velocity of 12 cm/s.
Ex 4.6: In the drilling luid laboratory, a technician was observing the Fann V-G
meter in an experiment for the Bingham luid where he was using the Fann V-G meter
to measure the viscosity of the luid and he found the following Fann data: 300 30;
55, and 200 27; 400 49. Calculate the consistency index and low-behavior
600
index for the power-law model.
Ex 4.7: While drilling, a 12.0 lbm/gal of mud having a viscosity of 1.3cp was being
circulated through the Drillstring at a rate of 600 gal/min. If the internal diameter of the
drillpipe is 5.5 in, determine the type of low in the drillpipe of the circulating system.
Ex 4.8: While drilling, a 13.5 lbm/gal of mud is used where Fann data was observed as
26; 600 48. he target depth was set at 10,500 t (TVD). If the internal diameter
300
of the drillpipe is 4.75 in, calculate the critical velocity inside the pipe and the critical
low rate.
Ex 4.9: An intermediate casing string was cemented using the following muds: irst section 9,000t was illed by 10.5 lbm/gal mud, second section of 1300t was illed by 13.3 lbm/
gal mud and the last section was illed by 15.5 lbm/gal mud. Calculate the total hydrostatic
pressure at 11,500 t. Convert the pressure at 11,500 t to an equivalent mud weight and
determine if it will exceed the fracture gradient of 14.2 lbm/gal. Also calculate the ECD for
an annular pressure loss gradient of 0.046 psi/t and an original mud weight of 12.0 ppg.
Ex 4.10: he tubing of a well illed with sour gas (SO2) gas to a vertical depth of
14,700 t. he annular space is illed with a 11.5 lbm/gal mud. Assume that the gas follows ideal gas behavior. Calculate the amount by which the exterior pressure on the
tubing exceeds the interior tubing pressure at 14,700 t. he surface tubing pressure is
1,000 psia and the mean temperature is 150°F. If the collapse resistance of the tubing is
9,500 psi, will the tubing collapse due to the high external pressure? Justify your answer.
Ex 4.11: Calculate the total pressure required to discharge a 12 ppg mud through the
drilling circulating system. Use the following data for the mud pump pressure requirement. Here:
Pressure loss in surface piping, stand pipe and mud hose = 80 psi
Pressure loss inside drill pipe = 2200 psi
Pressure loss inside drill collar = 350 psi
Pressure loss across bit = 95 psi
Pressure loss in annulus in the drill collars = 460 psi
Pressure loss in annulus in the drill pipe = 3,800 psi
Ex 4.12: You are drilling a 12-1/4 hole at 8,000 t using 5.0 OD x 4.276 ID drill pipe
and 800 t of 8.0 x 2-3/4 drill collars. he well has 13-3/8 , 68 lbs/t casing (ID 12.415 )
set at 6000 t. Mud is pumped down the drill pipe at the rate of 630 gal/min. Mud properties are: density = 12.0 ppg, viscosity = 14 cp, yield point = 20 lb/100 sq-t. he bit has
three 0.50 ID nozzles.
1. Calculate the pressure loss in the drill pipe.
2. Calculate the pressure loss in the drill collars.
3. Calculate the pressure loss across the bit.
Drilling Hydraulics 199
4.
5.
6.
7.
Calculate the pressure loss across the drill collar and open hole annulus.
Calculate the pressure loss across the drill pipe and open hole annulus.
Calculate the pressure loss across the drill pipe and cased hole annulus.
Calculate the horse power of the mud pump required to pump the mud
at 630 gpm.
8. Calculate the pressure at the inlet and the outlet of the pump.
Ex 4.13: You need to ind out the nozzle sizes of a tri-cone bit which will be used for an
immediate drilling operation. he available data needs to be used are 550 gpm of mud
circulation at a pressure drop of 1285 psi through the bit, and the mud density is 11 ppg.
Ex 4.14: Calculate the pressure losses across the diferent sections of drill pipe and
annulus. Use the Bingham plastic luid model where the following data are available.
he total vertical depth (TVD) is 18,350 t; the shoes of the casing diameter of 22 in and
13-3/8 in (ID = 12.565 in) are set at 1,500t and 5,500t respectively. he hole diameter
is 30 in and ater the second casing shoe is 12.25 in. A 900t drill collar with O.D. = 9.5
in and I.D. = 2.875 in was set at the bottom of the drillstring while the drill pipe O.D. =
5.5 in and I.D. = 4.276 in. he mud weight is 10.5 ppg with a plastic viscosity of 11.8cp
and yield point is 13.5 lbm/100t2. he pump rate for mud discharge was 860 gpm and
the nozzle velocity is 21,860 t/min.
Ex 4.15: While drilling a hole of 9 7/8 in at a depth of 8,880 t, the pump pressure drop
is 3,800 psi, and total pressure loss is 2,450 psi. A 12.5 ppg mud is used to achieve a bit
hydraulic horsepower per square inch of the hole of 1.3. Calculate the low rate of the mud
where it was assumed Cd = 0.90.
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5
Well Control and Monitoring
Program
5.1 Introduction
Well control and monitoring systems are an integrated part of drilling operations. Well
control means an assurance of formation luid (oil, gas or water) that does not low in
an uncontrolled way from the formations being drilled, into the borehole and eventually to the surface. It prevents the uncontrolled low of formation luids (‘kick’) from the
wellbore. Hence, a kick can be deined as an unexpected entry of formation luid(s) into
the wellbore, causing a rise of mud-level in the mud pit. herefore controlling the well
is an important issue in any drilling activity.
he well control system can be deined as the technology usages to control the luid
invasion and to maintain a balance between borehole pressure (pressure exerted by the
mud column in the wellbore) and formation pressure (pressure in the pore space of the
formation) for preventing or directing the low of formation luids into the wellbore. he
control system must have the options: i) to detect a kick, ii) to close the well at surface,
iii) to remove formation luid, and iv) to make the well safe. his technology includes the
approximation of formation luid pressures, the strength of the subsurface formations
and the use of casing and mud density to ofset those pressures in an expected fashion.
It also includes the operational procedures to safely stop a well from lowing luid as an
inlux of formation luid. he well-control procedure starts with installing large valves
at the top of the well to enable well-site personnel to close the well if necessary.
205
206 Fundamentals of Sustainable Drilling Engineering
Properly trained personnel are essential for well control activities. Well control consists of two basic components: an active component consisting of drilling luid pressure
monitoring activities, and a passive component consisting of the Blowout Preventers
(BOPs). he irst line of defense in well control is to have suicient drilling luid pressure in the well hole. During drilling, underground luids such as gas, water, or oil
under pressure (the formation pressure) opposes the drilling luid pressure (mud pressure). If the formation pressure is greater than the mud pressure, there is the possibility
to have a kick and ultimately a blowout. his chapter will cover all the aspects of the well
control and monitoring system.
5.2 Well Control System
he control of the formation pressure is normally referred to as keeping the pressures
in the well under control or simply well control. When pressure control over the well is
lost, immediate action must be taken to avoid the severe consequences of the blowout.
he consequences may include: i) loss of human life, ii) loss of rig and equipment, iii)
loss of reservoir luids, iv) damage to the environment, v) loss of capital investment,
and vi) huge cost involvement to bringing back the well under control. herefore, it is
important to understand the principles of well control, procedures and equipment used
to prevent blowouts.
An optimum drilling operation requires close control over a number of parameters.
A modern rig should have devices that will show and at the same time record the
important parameters related to the drilling operation. Some of the most important
parameters that are related to drilling operations, and well control and monitoring
system are: i) well depth, ii) weight on bit (WOB), iii) hook load, iv) rotary speed, v)
rotary torque, vi) mud low rate, vii) pump rate, viii) low return, ix) pump pressure, x)
pit level, xi) rate of penetration (ROP), xii) luid properties (such as density, temperature, viscosity, salinity, gas content, solids content etc.), xiii) hazardous gas content
of air. In addition, there are some parameters such as mud properties that cannot be
determined automatically. hese parameters are measured, recorded, and controlled
constantly as well as through physical experiments. herefore, it is mandatory that
rig personnel (i.e. rig supervisor, driller, crews, drilling and mud engineer) keep track
of the operation development at all times in order to make necessary adjustments
and to quickly detect and correct drilling problems. he rig crews must be alert at all
the times to recognize the signs of a kick and to take immediate action to bring the
well back under control. he kick occurs due to the pressure imbalance (the pressure
inside the wellbore (Pw) is lower than the formation pore pressure (Pf ) in a permeable
formation). he imbalance might happen if the mud density is too low, or luid level is
too low due to the mud-loss, and lost circulation (swabbing i.e. cleaning on trips; and
circulation stopped i.e. ECD is too low). As a result, the severity of the kick depends on
several factors: i) type of formation, ii) formation pressure, and iii) the nature of inlux.
he higher the permeability and porosity of the formation are, the greater the potential for a severe kick is. he greater negative pressure diferential (formation pressure
to wellbore pressure) is, the easier it is for the formation luids to enter the wellbore,
exclusively if this is coupled with high permeability and porosity. Finally, gas will low
Well Control and Monitoring Program
207
into the wellbore much faster than oil or water and therefore, the obvious result is
blowout if a kick is not controlled.
Well control operations are badly needed when formation luids start to low into
the well and displace the mud. Figure 5.1 shows the hydraulic low paths during wellcontrol operations. Formation luids that have entered the wellbore generally must be
removed by circulating the well through an adjustable chock at the surface (Fig 5.1).
he bottomhole pressure of the well at all times must remain above the pore pressure of
the formation to prevent additional inlux of the formation luid.
5.2.1 Well Control Principles
Well control is implemented by basically two principles: i) primary control, and ii) secondary control. hese two controls can restrict the luid low from the formation into
the wellbore, which lead to save the well from the blowout. However, there is another
line of control that is called tertiary control. his control is last control recently developed as blowout prevention. Figure 5.2 shows the diferent levels of well control in
terms of primary, secondary, and tertiary control. he primary control exists for all
Separator
Pump
Adjusttable
Choke
Blowout
Preventer
Casing
Pit
Open Hole
Strata of Minimum Fracture Resistance
Drill Pipe
Drill Collars
Formation Fluid
Permeable High Pressure Strata
Figure 5.1 Schematic of well control operations (redrawn from Bourguyan et al., 1986).
l
Control & Recovery
iar
t
Ter
tro
on
yC
l
BOPs
r
da
S
n
eco
tro
on
yC
Specialists
Mud Wt.
r
ma
Pri
l
tro
on
C
y
Well Control
Hole full
Figure 5.2 Levels of well control (Brekel, 2011).
208 Fundamentals of Sustainable Drilling Engineering
Depth
Mud Pressure
Formation
Pressure
Pressure
Figure 5.3 Primary control – formation pressure control with mud column (redrawn
from Ford, 2005).
drilling activities. he secondary control is more in depth and well managed the drilling activities by taking extra precautionary measures such as installation of BOPs to
safe guard and control the well. he third measure or level of control is the highest level
of security and control. Sometimes, it is a control of the well ater the recovery of a well
from explosion or kick.
5.2.1.1
Primary Control
Primary control is deined as the control by conirming that the borehole pressure is
greater than the formation pressure. It maintains a positive diferential pressure or
overbalance on the formation pressure (Figure 5.3). However, this control may be mislaid (i.e. Pw< Pf ) in two ways: the irst reason is if the formation pressure is not correctly
predicted which is higher than that of prediction by the reservoir engineers or geologists, as a result the drilling engineer would have programmed a mud weight that was
too low. herefore the bottomhole pressure would be less than the formation pressure
(Figure 5.3). he second reason is if the pressure due to the column of mud decreases
for some reason, and the bottomhole pressure drops below the formation pressure.
Since the bottomhole pressures is a product of mud density and the height of the column mud. herefore, the pressure at the bottom of the borehole can only decrease
if either the mud density (Figures 5.4) or the height of the column of mud decreases
(Figures 5.5).
here are diferent reasons for the reduction of mud weight and/or the hydrostatic
pressure of the mud column under normal drilling operations. he followings are few
of those reasons.
i) Low Mud Weight: here are many reasons that inluence the mud weight. It may be
too low due to – i) an overpressured zone which may have been penetrated, requiring
a heavier than normal mud weight, ii) gas cutting of the mud, iii) excessive dilution of
the mud (water contamination), and iv) inaccurate measurement of luid density. he
normal industry practice is to keep the overbalance pressure at around 200 – 300 psi.
Well Control and Monitoring Program
209
Original Mud Pressure
Depth
Mud Pressure Due to
Loss in Density (Mudweight)
Formation
Pressure
Well Under Control
Loss of Well Control
Pressure
Figure 5.4 Loss of primary control due to mud density (redrawn from Ford, 2005).
Mud Pressure When Lossses Occure
Depth
Original Mud Pressure
Formation
Pressure
Pressure
Figure 5.5 Loss of primary control due to reduction in luid level at borehole (redrawn
from Ford, 2005).
If there is a large amount of overbalance, the rate of penetration (ROP) will be reduced
and as a result, cost of ROP/t. will be increased which is an uneconomic situation. If
the mud weight is becoming less, the developed overbalance will be less and hence the
risk of having a kick increases. he following dynamic factors afect the mud weight.
Gas cutting: he seepage of gas from the formation into the circulating mud produces
a dramatic reduction in the mud weight at surface. he gas will expand as it rises up
the annulus and reduce the overall hydrostatic pressure on the formation. Although
the mud weight may be drastically cut at surface, the efect on the bottomhole pressure
is not so high. his is due to the fact that most of the gas expansion occurs near the
surface i.e. a mud cut to 90% of its original weight will produce a decrease in bottomhole pressure of only 10 psi. However, the pressure of gas in the annulus still poses a
problem, which will get worse if the gas is not removed. he mud loggers should monitor the amount of gas in the mud continuously, and any signiicant increase reported
immediately.
Solids removal: he cuttings must be removed from the formation to allow eicient
drilling when the mud returns to the surface. If a very ine screen is used on the shale
shaker, a large amount of the weighting solids (barite) may also be removed. he screen
210 Fundamentals of Sustainable Drilling Engineering
size should be selected so that the shaker removes only the larger particles related to
formation, while the iner material drops out in the sand traps.
Dilution: When the mud is being treated to improve some property (i.e. viscosity) the
irst stage is to water-back in order to lower the percentage of solids. Water may also
be added when drilling deep wells where evaporation may be signiicant. During these
operations mud weight must be monitored carefully.
ii) Reduced Height of Mud Column: Under normal drilling operations, the volume of
mud pumped into the borehole should be equal to the mud returned. In such case, when
mud pump operations are stopped, there should not be any luid low from the well and
thus the level of the mud should not fall below the mud pit level. However, this is not
always the case. Reduction of pit level or mud column height may occur due to the following reasons:
Tripping: When the drill pipe is pulled from the borehole during the tripping operation, the top of the mud column will fall down. his results in a reduction in the height
of the mud column above any point in the wellbore, which creates a decrease in bottomhole pressure. herefore, the openhole must be illed up when pulling out of the
hole, which is done by equivalent volume of drilling luid.
Swabbing: Is a process where the drill pipe acts like a piston. During the upward motion
of drill pipe, it creates a region of low pressure into which formation luids may low.
he opposite efect is known as surging when the pipe is run into the hole. he amount
of swabbing will increase with:
i.
ii.
iii.
iv.
v.
vi.
he adhesion of mud to the drill pipe
he speed at which the pipe is pulled
Use of muds with high gel strength and viscosity
Having small clearances between drill string and wellbore
hick mud cake
Ineicient cleaning of the bit to remove cuttings
Lost Circulation: his occurs when a fractured formation is being drilled. Whole mud
is lost to the cavities in the rock, which reduces the height of mud in the borehole. Lost
circulation can also occur if too high a mud weight is used and the fracture gradient is
exceeded. Whatever the cause of lost circulation is the process by which the drill pipe
acts like a piston. During the upward motion of drill pipe, it creates a region of low
pressure into which formation luids may low. he opposite efect is known as surging when the pipe is run into the hole. he amount of swabbing will increase with the
following.
5.2.1.2
Secondary Control
If there is a pit gain observed at the surface, it means that a kick has been identiied by
the drilling personals. his pit gain indicates that the primary control over the well has
been lost. In such a situation, all normal drilling or tripping operations must be terminated in order to concentrate on bringing the well back to primary control. Secondary
Well Control and Monitoring Program
211
control can be referred to as the shutting of the BOP valves at the surface. his control
is needed once the primary control fails which indicates that an unexpected high-pressure formation luid is entered into the wellbore and starts to low. he purposes of this
control are: i) to stop the low of unexpected luids into the wellbore, ii) to allow the
inlux to be circulated to the surface and safely discharged, and iii) to prevent further
inlux to the downhole.
i) Steps of second control: he irst step is to close the annulus space at the surface
with the help of BOP valve to prevent further inlux of the unexpected formation luid.
Figure 5.6 shows the secondary control system and its pressure rating. he second step
is to circulate the heavy mud through the drill string and annulus to displace the inlux
and original mud. he third step is to allow the drilling mud with a controlled way so
that no further inlux occurs at the bottom of the borehole. In such case, the heavier
mud should prevent a further inlux of formation luid when drilling ahead, which is
now under primary control. Secondary control is only required in drilling exploration
wells where formation pressures may not be known.
5.3 Warning Signals of Kicks
A blowout does not usually happen suddenly. While drilling, the crew must be watchful.
hey should know the warning signs at the surface and be able to understand the inlux
at the bottom of the borehole. An alert crew can see the warning signs and if it is interpreted correctly, the well can be saved by immediate correct actions. Even though these
signs may not be necessarily always positively identify a kick, they do provide a warning
and should be monitored carefully. Sometimes the driller observes several indicators at
the surface, which might be due to events other than an inlux. As a result, the signs are
not always inal. For example, if the drill bit enters in an over pressured zone of a formation, the rate of penetration will increase. It might be happen due to the new formation
encountered by the bit. On the other hand, there are some indicators need to be monitored
Pdp
Depth
Pann
Mud Pressure
Well Under Control
Formation
Pressure
Loss of Well Control
Pressure
Figure 5.6 Secondary control using BOP valve (redrawn from Ford, 2005).
212 Fundamentals of Sustainable Drilling Engineering
continuously to restrict having kick. Normally there are two types of indicators,
i) primary indicators, and ii) secondary indicators.
5.3.1 Primary Indicators
While drilling, there are some indicators that are more obvious than others and are
therefore called primary indicators. he followings are the primary indicators:
i.
ii.
iii.
iv.
Flow rate increase
Pit volume increase
Flowing well with pump shut of
Improper hole ill-up during trips
i) Flow rate increase: While the mud pumps are circulating at a constant rate there
should be a steady low rate of mud returns to the mud tank or pit. If this low rate
increases without changing the pump speed, this is a sign that formation luids are
entering into the wellbore and helping to move the contents of the annulus to the surface. herefore, it very important to monitor low rate into and out of the well continuously using a diferential low meter. he meter measures the diferential rate at which
luid is being pumped into the well and the rate at which it returns from the annulus
along the low line. he practice gives the indication of low rate increase to the drilling
crew.
ii) Pit volume increase: if the mud low rate into and out of the well is constant, the
volume of luid in the mud pit should remain constant. A rise in the level of mud in the
active pits is a sign that some mud has been displaced from the annulus by an inlux of
formation luids. he level of the mud in the mud pits is therefore monitored continuously. he volume of this inlux is equal to the pit gain and should be noted for use in
later calculations.
iii) Flowing well with pump shut of: When the rig pumps are not in operating condition,
there should be no luid returns from the well. If the pumps are in shut down condition and
the well continues to low, then the luid is being pushed out of the annulus by some other
forces. In such case, it is assumed that the formation pressure is higher than the hydrostatic
pressure due to the column of mud. his higher pressure results in an inlux to the wellbore
which ultimately fallouts to have a kick. here are two exceptions to this explanation: i) the
thermal expansion of mud in the borehole and annulus which results in a small amount
of low when the pumps are shut of, ii) U-tubing efect when mud in drill string is heavier
than mud in annulus. A low check is oten carried out to conirm whether the well is kicking or not. he procedure is as follows: i) pick up a kelly until the tool joint clears the rotary
table, ii) shut down pumps, iii) sets slips, iv) observe low line, check for low from annulus,
v) if well is lowing, close BOP. If not lowing, resume drilling.
iv) Improper hole ill-up during trips: he hole should be required to be illed up with
mud when the pipe is tripped out. If the hole is not being illed and does not take the
calculated volume the drill pipe volume, formation luids will replace the empty space.
Well Control and Monitoring Program
5.3.2
213
Secondary Indicators
While drilling, there are some indicators that are not conclusive and may be due to
some other reasons. he followings are the secondary indicators:
i.
ii.
iii.
iv.
Changes in pump pressure
Drilling break
Gas, oil, or water-cut mud
Reduction in drill pipe weight
ii) Changes in pump pressure: An entry of formation luids may cause the mud to
locculate and result in a slight increase in pump pressure. As low continues the lower
density of the inlux will cause a gradual drop in pump pressure. As the luid in the
annulus becomes lighter the mud in the drill pipe will tend to fall and the pump speed
(stokes/min) will increase. Notice, however, that these efects can be caused by other
drilling problems (i.e. washout in drill string, or twist-of ).
ii) Drilling break: A drilling break is an abrupt increase in the rate of penetration. It
should be treated with caution. If the drilling parameters have not been changed, the
increased penetration rate may be attributed to: a) change from shale to sand (i.e. more
porous and permeable and so having a greater kick potential), or b) reduced overbalance
(i.e. increase in pore pressure). he drilling break may indicate that a higher-pressure
formation has been entered and therefore the chip hold down efect has been reduced
and/or that a higher porosity formation (i.e. due to under-compaction and therefore
indicative of high pressure) has been entered. However an increase in drilling rate may
also be simply due to a change from one formation type to another. Experience has
shown that drilling breaks are oten associated with overpressured zones. It is recommended that a low check is carried out ater a drilling break.
iii) Gas, oil, or water cut mud: Gas cut mud can be deined as the mud where an entrance
of gas happens from formations while drilled. In reality it is not possible to prevent any
gas entrance to the mud column. Gas cut mud may be considered an early warning sign.
he mud should be continuously monitored. Any signiicant rise above the background
level should be reported. Gas cutting may occur due to: a) drilling in a gas bearing formation with the correct mud weight, b) swabbing when making a connection or during
trips, and c) inlux due to negative pressure diferential. he detection of gas in the mud
does not necessarily mean the weight should be increased. he cause of the gas cutting
should be investigated before action is taken.
iv) Reduction in drill pipe weight: he reduction in drill string weight happens when
a substantial inlux occurs from a zone of high productivity. However, the other indicators may be displayed prior to or along with a reduction in drill pipe weight.
he operational procedure to deal with a kick while drilling is depicted in Figure 5.7.
During the operation, it is not essential to close valves inside the drill pipe since the drill
pipe is connected to the mud pumps. his allows controlling the pressure to the drill
pipe. Generally it is required to close the uppermost annular preventer (i.e. hydrill).
However, the lower pipe rams can also be used as a backup if required. he surface
214 Fundamentals of Sustainable Drilling Engineering
Active Drilling Operations
Kick Indication
Primary Indicators
Flow Rate
Increase
Pit Volume
Increase
Flowing Well with
Pump Shut Of
Secondary Indicators
Change in
Pump Pressure
Improper Hole
Fill-Up during Trips
Drilling
Break
Gas Cut
Mud
Rasie Kelly above Rotary
Stop Pump
Is Well Flowing?
No
Continue Drilling
Flow Check as needed
Yes
Close Hydrill
Note Pdp and Pann
Note Pit Gain
Calculate Nature of Inlux
Calculate New Mud Weight
to balance from Pressure
Kill Well
Continue to Drill
Figure 5.7 Operational procedure lowing detection of a kick.
and annulus pressure should be monitored carefully. he pressures can also be used to
identify the nature of the inlux and calculate the mud weight required to kill the well
(Figure 5.7).
5.4 Control of Inlux and Kill Mud
Once there is an inlux of the formation luid (i.e. kick) at the borehole, it is necessary
to control the well efectively. Otherwise, the well would be beyond control. herefore,
kill mud calculations are needed to bring back the well under primary control. he following subsections describe how the kill mud can control a well.
5.4.1 Analysis of Shut-in-Pressure
When the formation luid is already in wellbore and as a result the well is in shut-in
condition, the pressures at the drill pipe and the annulus can be used to determine i) the
formation pore pressure, ii) the mud weight required to kill the well, and iii) the type
of inlux. Due to the shut-in condition, the pressure at the top of the drill string will
increase until the sum of drill pipe pressure and the hydrostatic pressure due to the luids in the drill pipe are equal to the pressure in the formation. For the same reason, the
pressure in the annulus would continue to increase until the sum of annulus pressure
and the hydrostatic pressure due to the luids in the annulus are equal to the pressure
in the formation. It is noted that the drill pipe and annulus pressure will be diferent
because of the diferent luids content while shut-in. When the inlux happens and the
Well Control and Monitoring Program
215
well is shut-in, the drill pipe will contain mud. However the annulus will now contain
both mud and the invaded luid (i.e. oil, gas, or water). Hence the hydrostatic pressure of the muds in the drill string and the annulus will be diferent. It is based on the
assumption that no inlux will low through drill string. If the system is in equilibrium,
the drill pipe shut-in pressure can be interpreted as the amount by which bottomhole
pressure exceeds the hydrostatic mud pressure. Mathematically the expression can be
written as:
Psidp Gm H vc
where,
Psidp
Gm
Hvc
Pbh
(5.1)
Pbh
= shut-in drill pipe pressure, psi
= mud pressure gradient, psi/t
= total vertical height of the mud column, t
= bottomhole (i.e. formation) pressure, psi
In terms of mud weight, formation pressure can be calculated as:
Pbh
Psidp 0.052
om
H vc
(5.2)
where,
om
= original mud weight, ppg
Since the mud weight in the drill pipe will be known throughout the well control procedure, Psidp gives an indication of bottomhole pressure (i.e. the drill pipe pressure gauge
acts as a bottomhole pressure gauge). hroughout the well control procedure the further inlux of formation luids must be prevented. In order to do this, (Psidp Gm H vc )
must be kept equal or slightly above Pbh . his is an important concept of well control
on which everything else is based on. Sometimes this technique is referred to as the
constant bottomhole pressure killing methods due to this reason.
Now, if we consider the annulus side, the bottomhole pressure can be calculated as
equal to the surface annulus pressure plus the combined hydrostatic pressure of the
mud and inlux. Mathematically the expression can be written as:
Psiann Gi H i
where,
Psiann
Gi
Hi
Hm
Gm H m
Pbh
(5.3)
= shut-in annulus pressure, psi
= inlux pressure gradient, psi/t
= vertical height of the inlux or kick, t
= vertical height of mud in the annulus ater inlux, t.= Hvc – Hi
Hi can be calculated from the displaced volume of mud measured at surface (i.e. the pit
gain) and the cross-sectional area of the annulus i.e.:
Hi
Vpit
Aann
(5.4)
216 Fundamentals of Sustainable Drilling Engineering
where,
Vpit = pit gain volume, bbls
Aann = cross-sectional area of the annulus, bbls/t
Initial circulating pressure is calculated as:
Pic
Psidp
Pp
(5.5)
Pok
where,
Pic = initial circulating pressure, psi
Pp = slow circulating pump pressure, psi
Pok = overkill pressure, psi
Final circulating pressure is calculated as:
Pfc
Pp
km
(5.6)
om
where,
Pfc = inal circulating pressure, psi
km = kill mud weight, ppg
1"
Example 5.1: A 8 diameter hole is drilled up to 7500 t. with a density of 12.5 ppg. If
2
the formation pore pressure at this point is 4500 psi. Calculate i) mud pressure overbalance above the pore pressure, ii) if the mud density is 10.5 ppg, what would be the overbalance, and iii) if the luid level in the annulus is dropped to 250 t. due to inadequate
hole ill up during tripping, what would be the efect on bottomhole pressure?
Solution:
Given data:
Hvc = total vertical height of the mud column = 7500 t
1"
dh = hole diameter = 8
2
om1 = original mud weight 1 = 12.5 ppg
Pf = formation pore pressure = 4500 psi
om2 = original mud weight 2 = 10.5 ppg
Hann = vertical height of the mud column in the annulus = 250 t
Required data:
i) Pob1 = mud pressure overbalance at 7500 t
ii) Pob2 = mud pressure overbalance at 7500 t. if mud density is 10.5 ppg
iii) Efect on bottomhole pressure?
he overbalance at a depth of 7,500 t.can be calculated by Eq. (4.34a) which can be
modiied for overbalance as:
Pob1 0.052
om1
H vc
Pf
0.052
12.5 ppg
7500 ft
375 psi
he overbalance at a depth of 7500 t. if mud density is 10.5 ppg as:
4500 psi
Well Control and Monitoring Program
Pob 2
0.052
om 2
H vc
0.052
Pf
10.5 ppg
7500 ft
217
4500 psi
405 psi
If the mud density is decreased, the negative sign implies that the well would be underbalanced by 405 psi with the consequent risk of an inlux.
If the luid level in the annulus is dropped by 250 t, the efect would be to reduce the
bottomhole pressure by:
Pbhp
0.052
12.5 ppg
250 ft
162.5 psi
his result indicates that there would still be a net overbalance of 212.5 (i.e. 375 – 162.5)
psi.
5.4.2
Type of Inlux and Gradient Calculation
If we combine Eqs. (5.1) and (5.3), the inlux gradient can be calculated as:
Gi
Gm
Psiann
Psidp
Hi
(5.7)
It is noted that the above expression is given in this form because Pann Pdp ,
due to the lighter luid being in the annulus. he type of luid can be identiied from
the gradient calculated utilizing Eq. (5.7). Diferent references report diferent ranges of
data for identifying the luid types. However, the following are as a guide.
a)
b)
c)
d)
A gas kick is recognized: 0.075 < Gi < 0.25 psi/t.
An oil and gas mixture kick: 0.25 < Gi < 0.3 psi/t
An oil and condensate mixture kick: 0.3 < Gi < 0.4 psi/t
A water kick: 0.4 < Gi psi/t
For example, if Gi is found to be above 0.25, this may indicate a mixture of gas and oil.
If nature of inlux is not known, it is usually assumed to be gas, since this is the most
severe type of kick.
5.4.3 Kill Mud Weight Calculation
he mud weight required to kill the inlux and would provide the overbalance while
drilling ahead can be calculated from Eq. (5.1) as:
Pbh
Psidp Gm H vc
(5.8)
To bring back the well under primary control, the new mud weight must be adequate to
balance or be slightly greater than the bottomhole pressure. One more thing should be
taken care during the design of mud weight. We should keep in mind that the kill mud
weight would not be exceeding the formation fracture gradient. Otherwise, there would
be mud loss in the fracture. If an overbalance is used the equation becomes:
218 Fundamentals of Sustainable Drilling Engineering
Gk H vc
Pbh
(5.9)
Pob
where,
Gk = kill mud pressure gradient, psi/t
Pob = overbalance pressure, psi
Substituting Eq. (5.8) into Eq. (5.9), the inal form of the above equation can be written
as:
Gk
Psidp
Gm
Pob
(5.10)
H vc
It is noted that the pit gain volume (V) and the casing pressure (i.e. Psiann) do not appear
in Eq. (5.10) which indicate that both parameters do not have any role over kill mud
design and calculations.
Formation pressure can be calculated in terms of mud weight as
Pbh
Psidp 0.052
om
H vc
(5.11)
he kill mud weight can be calculated in terms of mud weight as
Psidp
km
(5.12)
om
0.052 H vc
If we consider overkill mud as a safety margin, Eq. (5.12) can be written as:
Psidp
km
om
0.052 H vc
ok
(5.13)
where,
ok
= overkill mud weight for safety margin, ppg
he kill mud gradient can be calculated in terms of mud weight as
Gk
0.052
Psidp
om
H vc
(5.14)
Example 5.2: while drilling ahead at a target of 8,500 t, the hole size was 7 in. he
drilling crew noticed that there was a pit gain of 10 bbls. he well is shut-in and the
drill pipe and annulus pressures were recorded as 650 psi, and 800 psi respectively. he
3"
bottomhole assembly consists of 650 t. of 4 OD collars and 3 drill pipe. he mud
4
weight is 10.2 ppg. Assume a mud pressure gradient. Identify the inlux and calculate
the new mud weight, including an overbalance of 250 psi.
Well Control and Monitoring Program
219
Solution:
Given data:
Hvc = total vertical height of the mud column = 8500 t
dh = hole diameter = 7 in
Vpit = pit gain volume = 10 bbls
Pdp = shut-in drill pipe pressure = 650 psi
Pann = shut-in annulus pressure =800 psi
HBHA = bottomhole assembly length = 650 t
3"
dc = collar outer diameter = 4 = 4.75
"
1 4
ddp = drill pipe diameter = 3 = 3.5
2
= mud weight = 10.2 ppg
m
Pob = overbalance pressure = 250 psi
Required data:
a. Type of inlux
b. m = new mud weight in ppg
Nature of inlux:
he vertical height of the inlux can be calculated using Eq. (5.4) as
Hi
Vpit
10bbls
10 bbls
dh2 dc2 / 4
Aann
72
4.752
4
ft 3
0.178 bbls
in
2
ft 2
144 in2
389.6 ft
(Here, H i is less than bottomhole assembly length, 650 t)
Assuming a mud pressure gradient of 0.53 psi/t, the type of inlux can be calculated
using Eq. (5.7) as:
Gi
Gm
Psiann
Psidp
0.53
Hi
800 650
389.6
0.145 psi / ft
As long as, the inlux pressure gradient is within the range 0.075 – 0.25 psi/t,
the type of inlux is probably gas.
New mud weight:
he new mud weight or kill mud weight can be calculated using Eq. (5.10) as:
Gk
Gm
Pdp
Pob
H vc
0.636 psi / ft
0.53 psi / ft
Hence the new mud weight would be as:
650 psi
250 psi
8500 ft
220 Fundamentals of Sustainable Drilling Engineering
0.636 psi / ft
0.052 1 ft
m
12.23 ppg
Example 5.3: Determine the kill mud density and kill mud gradient for a shut-in drill
pipe pressure of 600 psi at a depth of 12,000 t. If the original mud weight is 14.5 ppg
and the slow circulating pump pressure is 850 psi, ind out also the initial and inal circulating pressure of the system.
Solution:
Given data:
Psidp = shut-in drill pipe pressure = 600 psi
Hvc = total vertical height of the mud column 12,000 t
om = original mud weight = 14.5 ppg
Pp = slow circulating pump pressure = 850 psi
Required data:
km = kill mud weight, ppg
Gk = kill mud gradient, psi/t
Pic = initial circulating pressure, psi
Pfc = inal circulating pressure, psi
he kill mud weight can be calculated using Eq. (5.12) as
600 psi
Psidp
km
om
0.052 H vc
0.052
12,000 ft
14.5 ppg
15.5 ppg
If we consider an overkill mud weight of 0.5 ppg as a safety margin, Kill mud weight can
be calculated using Eq. (5.13) as:
Psidp
km
om
0.052 H vc
ok
15.5 0.5 16.0 ppg
he kill mud gradient can be calculated using Eq. (5.14) as
Gk
0.052
Psidp
om
H vc
0.052
14.5 ppg
600 psi
12,000 ft
0.804 psi / ft
If we consider there is no overkill pressure, the initial circulating pressure is calculated
using Eq. (5.5) as:
Pic
Psidp
Pp
Pok
600 psi
850 psi
0 1450 psi
Final circulating pressure is calculated is calculated using Eq. (5.6) as:
Pfc
Pp
km
om
850 psi
15.5
14.5
908 psi
Well Control and Monitoring Program
221
5.4.4 Kick Analysis
he composition of the kick luids controls the annular pressure proile. his pressure
proile is normally observed during well control operations. In general, a liquid kick has
lower annular pressures than a gas kick. his is true because of the two factors: i) a gas
kick has a lower density than a liquid kick, and ii) a gas kick must be allowed to expand
as it is pumped to the surface. Both of these factors result in a lower hydrostatic pressure
in the annulus. hus it maintains a constant formation pressure. In such cases, a higher
surface annular pressure must be maintained using the adjustable choke.
he kick composition must be identiied for annular pressure calculations, which are
needed for well planning. Generally it is not known during actual well control operations. However, the density of the kick luid can be estimated from the observed drill
pipe pressure, annular casing pressure, and pit gain. he density calculation oten determines whether the kick is mainly gas/liquid or not. he density of the kick luid that
enters the annulus is estimated simply assuming as a slug. Figure 5.8 shows the initial
well conditions ater closing the BOP on a kick. he pit gain is usually recorded by pit
volume monitoring equipment.
he length and density of the kick can be calculated based on annulus capacity
behind the drill collar. If the pit gain volume is smaller than the annulus volume against
the drill collar, the length of the kick zone (i.e. inlux height) can be expressed in terms
of the pit gain volume, and annulus capacity. Mathematically,
If Vpit Vann _ dc , the length of the kick can be calculated as:
Lk
Vpit
(5.15)
Cann _ dc
where,
= kick length (i.e. vertical height of inlux, Hi), t
Lk
Cann _ dc = the annulus capacity behind the drill collar, bbl/t
Vpit
= the pit gain volume, bbl
Pit gain (Vpit)
Pdp
Pc
Lcas
Ldp
Lnoncas
Lk
Hvc
Ldc HBHA
Figure 5.8 Schematic of initial well conditions during well control operations (redrawn
from Borgunay et al., 1986).
222 Fundamentals of Sustainable Drilling Engineering
Vann _ dc = the annulus volume against drill collar, bbl
If Vpit
Vann _ dc , the length of the kick is given by
Lk
Vpit
Ldc
Vann _ dc
(5.16)
Cann _ dp
where,
Ldc = length of the drill collar, t
Cann _ dp = the annulus capacity behind the drill pipe, bbl/t
A pressure balance on the initial well system for a uniform mud density,
Picp 0.052
H vc
om
Lk
k
Lk
m
H vc
Pidp
m,
is given by
(5.17)
where,
Picp = initial stabilized drill collar pressure, psi
Pidp = initial stabilized drill pipe pressure, psi
k = kick luid (i.e. inlux) density, ppg
Solving Eq. (5.17) for kick luid density gives
Pidp Picp
k
om
0.052 Lk
(5.18)
A kick density less than about 4 ppg should indicate that the kick luid is predominantly
gas, and a kick density greater than about 8 ppg should indicate that the kick luid is
predominantly liquid.
Example 5.4: A kick was detected while drilling a high-pressure zone.
he depth of the formation was recorded 10,000 t. with a mud density of
9.0 ppg. he crew shut-in the well and they recorded the pressure for drill pipe and
drill collar as 350 psi and 430 psi respectively. he observed total pit gain was 6.0 bbl.
he annular capacity against 950 t. of drill collar is 0.028 bbl/t. and the overkill safety
margin is 0.50 ppg. Compute the formation pressure, inlux density, the type of luid,
required kill mud weight, and kill mud gradient.
Solution:
Given data:
= total vertical height of the mud column =10,000 t
Hvc
= original mud weight = 9.0 ppg
om
= shut-in drill pipe pressure = 350 psi
Psidp
= shut-in drill collar pressure = 430 psi
Psidc
Vpit
= pit gain volume = 6bbls
= length of drill collar = 950 t
Ldc
Cann _ dc = the annulus capacity behind the drill collar = 0.028 bbl/t.
= overkill mud as a safety margin = 0.5 ppg
ok
Well Control and Monitoring Program
223
Required data:
Pbh = formation pressure, psi
= kick luid or inlux density, ppg
k
Type of luid
km = kill mud weight, ppg
Gk = kill mud gradient, psi/t
Formation pressure can be calculated using Eq. (5.11) as
Pbh
Psidp 0.052
om
350 psi
H vc
0.052
9.0 ppg
10000 ft
5030 psi
Pbh
To calculate the kick density, we irst need to calculate the length of the kick and therefore, the annular volume.
he annular volume against the drill collar,
Vann _ dc
As long as Vpit
Ldc Cann _ dc
950 ft 0.028
bbl
ft
26.6 bbl
Vann _ dc , the length of the kick can be calculated using Eq. 5(15) as:
Lk
Vpit
6.0 bbl
Cann _ dc
0.028 bbl / ft
214.29 ft
he density of the kick luid is calculated using Eq. (5.18) as:
Pidp Picp
k
om
0.052 Lk
9.0 ppg
350 psi 430 psi
0.052
214.29 ft
1.82 ppg
herefore, the kick luid is gas.
Consider overkill mud as a safety margin, the kill mud weight can be calculated
using Eq. (5.13) as:
Psidp
km
om
0.052 H vc
10.17 ppg
ok
9.0 ppg
350 psi
0.052
10,000 ft
0.5 ppg
he kill mud gradient can be calculated using Eq. (5.14) as:
Gk
0.052
Psidp
om
H vc
0.052
9.0 ppg
350 psi
10,000 ft
0.503 psi / ft
Example 5.5: A well was being drilled at a high-pressure zone of 12,000 t. vertical
depth where 9.5 ppg mud was being circulated at a rate of 8.0 bbl/min. A pit gain of 95
bbl was noticed over a 3 minutes period before the pump was stopped and the BOPs
were closed. Ater the pressures stabilized, an initial drill pipe pressure of 500 psi and
an initial casing pressure of 700 psi were recorded by the attendees at the rig side. he
224 Fundamentals of Sustainable Drilling Engineering
annular capacity against 950 t. of drill collar was 0.03 bbl/t. and the annular capacity
against 850 t. of drill pipe was 0.0775 bbl/t. Compute the formation pressure, inlux
density.
Solution:
Given data:
= total vertical height of the mud column =12,000 t
Hvc
= original mud weight = 9.5 ppg
om
qt
= original mud circulation rate = 8.0bbl/min
Vpit
= pit gain volume = 95 bbls
t
= time to stop the pump = 3 min
= shut-in drill pipe pressure = 500 psi
Psidp
= shut-in drill collar pressure = 700 psi
Psidc
= length of drill collar = 950 t
Ldc
Cann _ dc = the annulus capacity behind the drill collar = 0.03 bbl/t
= length of drill pipe = 850 t
Ldp
Cann _ dp = the annulus capacity behind the drill pipe = 0.0775 bbl/t
Required data:
Pbh
= formation pressure, psi
= kick luid or inlux density, ppg
k
A schematic view of the example is shown in Figure 5.9. Formation pressure can be
calculated using Eq. (5.11) as:
Psidp 0.052
Pbh
om
H vc
500 psi
Pbh
0.052
9.5 ppg
12000 ft
6428 psi
To calculate the kick density, we irst need to calculate the length of the kick and therefore, the annular volume.
he total annular volume against the drill pipe and drill collar,
Vann
Vann
Vann _ dp
Vann _ dc
850 ft 0.0775
bbl
ft
Ldp Cann _ dp
Ldc Cann _ dc
950 ft 0.03
bbl
ft
94.37 bbl
However, kick length is determined based on the total annular volume against the drill
collar only. So,
Vann _ dc
Ldc Cann _ dc
950 ft 0.03
bbl
ft
28.5 bbl
If we assume that the kick luids are mixed with the mud pumped while the well was
lowing, so the total pit gain is
Vpit
total
Vpit
qt t
95.0 bbl
8.0 bbl / min 3 min
119.0 bbl
Well Control and Monitoring Program
225
Psidp = 500 psi
3000 ft
Cann_dp = 0.0775 bbl/ft
Cann_dp = 0.0775 bbl/ft
ρom = 9.5 ppg
Hvc = 12,000 ft
Cann_dc = 0.03 bbl/ft
Psidc = 700 psi
2117.7ft
950ft
PBHA = 5,600 psi
Figure 5.9 Illustration for Example 5.5.
As long as Vpit
(5.16) as
Lk
Ldc
total
Vpit
Vann _ dc , the length of the kick can be calculated using Eq.
Vann _ dc
950 ft
Cann _ dp
119 bbl 28.5 bbl
0.0775 bbl / ft
2,117.74 ft
he density of the kick luid is calculated using Eq. (5.18) as
Pidp Picp
k
om
0.052 Lk
9.5 ppg
500 psi 700 psi
0.052
2,117.74 ft
7.68 ppg
5.4.5 Shut-in Surface Pressure
Normally the maximum permissible shut-in-pressure is the lesser of 80–90% of the
casing burst pressure and the surface pressure required to produce fracturing at the
casing shoe. he maximum permissible shut-in surface pressure is given by the following equation:
Psifp
Where,
Psifp
Hcs
Pann _ m
Gf
Pann _ m Gm H cs
= G f H cs = shut-in fracture pressure, psi
= vertical height of the casing shoe or depth to the casing shoe, t
= maximum shut-in annulus pressure, psi
= fracture pressure gradient, psi/t
(5.19)
226 Fundamentals of Sustainable Drilling Engineering
3"
13 −
8
casing set at 2,100 ft
Gf = fracture pressure
gradient = 0.68 psi/ft
ρm = mud weight = 10.6 ppg
Gm = mud pressure gradient
= 0.6 psi/ft
HVC = Vertical height of the
mud column = 12,000 ft.
Figure 5.10 Schematic view of the Example 5.6.
"
3
set at a depth of 2,100 t.
Example 5.6: he surface casing with an OD of 13
8
he fracture gradient was found 0.68 psi/t. he mud density was 10.6 ppg with a
mud gradient of 0.6 psi/t. Total depth of the well was 12,000 t. and the internal yield
was 2,500 psi. Determine the maximum permissible surface pressure on the annulus.
Assume that the casing burst is limited to 85% of design speciication.
Solution:
"
Given data:
3
= depth to the casing shoe = 2,100 t.@ 13
Hcs
8
= fracture pressure gradient = 0.68 psi/t
Gf
= mud weight = 10.6 ppg
m
= mud pressure gradient = 0.6 psi/t
Gm
= vertical height of the mud column 12,000 t
Hvc
= Internal yield = 2,500 psi
Yd
85% burst pressure
Required data:
Pann _ m = maximum shut-in annulus pressure, psi
Figure 5.10 illustrates the wellbore and casing set for the Example 5.6. If the casing burst is
limited to 85% of the yield pressure, permissible pressure is then:
85% burst = 0.85 x Yd = 0.85 x (2500 psi) = 2,125 psi
he maximum permissible annulus pressure can be determined using Eq. (5.19) as:
Pann _ m
0.68 psi / ft
2100 ft
G f H cs Gm H cs
0.6 psi / ft
2100 ft
168.0 psi
herefore, the maximum permissible annular pressure at the surface is 168.0 psi, which
is that pressure which would produce formation fracturing at the casing seat.
Well Control and Monitoring Program
227
5.5 BOP Equipment for Well Control System
he well control system normally allows i) to detect the kick, ii) to close the well at the surface,
iii) to circulate the well under pressure to remove the formation luids and increase the
mud density, iv) to move the drill string under pressure, and v) to divert low away from rig
personnel and equipment. here are two types of equipment used for well control system, i)
kick detection equipment, and ii) kick management equipment. Figure 5.11 shows the different parts of drilling luid circulating system along with blowout prevention equipment.
Figure 5.12 shows only BOP stack with annular preventers and ram systems.
5.5.1 Kick Detection Equipment
Kick detection is very important during drilling operations. It is generally recognized
using a pit volume indicator or a low indicator. Figure 5.13 depicts these devices. An
increase in the low of the mud can be detected by both devices while returning from
the well, which is being circulated by the pump. Pit volume indicators usually employ
loats in each pit that are connected by means of pneumatic or electrical transducers
to a recording device on the rig loor. he recording device indicates the volume of
all active pits. High and low level alarms can be presented to turn on lights and horns
when the pit volume increases or decreases signiicantly. An increase in surface mud
volume indicates that formation luids may be entering the well. A decrease shows that
drilling luid is being lost to an underground formation.
CIRCULATING SYSTEM
BLOWOUT PREVENTION SYSTEM
1.
2.
3.
4.
5.
6.
7.
8.
9.
10.
11.
12.
13.
14.
A.
B.
C.
D.
E.
F.
G.
H.
I.
J.
K.
Pump
Stand pipe
Rotary House
Swivel
Kelly Valve
Kelly Joint
Drill Pipe
Drill Collars
Bit
Bell Nipple
Flowline
Shale Shaker
Mud Tank
Fill Tank
3
Blowout Preventer
Kill Line
Emergency Kill Line
Choke Flowline
Emergency Choice Flowline
Choke Manifold
Choke
Choke Discharge Line
Splash Box
Degasser
Reserve or Slush Pit
Flow
4
2
5
6
11
10
7
14
A
13
G
12
J
A
D
13
B
H
I
F
A
E
H
C
G
K
8
9
Figure 5.11 A composite system showing circulating and blowout prevention systems.
228 Fundamentals of Sustainable Drilling Engineering
Applied Pressure Test
(a)
(b)
(c)
Rotary
Flow Stack
Annular Preventer
RAM Type Preventer
(Pipe RAMS)
Drilling Spool
Choke Flowline
Kill Line
RAM Type Preventer
(Blind RAMS)
RAM Type Preventer
(Pipe RAMS)
Emergency Choke Flowline
Emergency Kill Line
ANNULAR PREVENTER
CLOSED
PIPE RAMS
CLOSED
MASTER (BLIND) RAMS
CLOSED
Figure 5.12 (a) BOP stack with annular preventer closed, (b) BOP stack with pipe rams
closed, and (c) BOP stack with blind rams closed.
Flow
Indicator
0
100%
Pit Volume
Indicator
0
Loss
−50
Gain
+50
Flow In
Flow Out
Gain in Pit
Volume Equal
To Kick Volume
Kick
Flow
High Pressure
Permeable formation
Figure 5.13 Kick detection during drilling operations (Redrawn from Bourgoyne et al.,
1986).
Well Control and Monitoring Program
229
he mud low indicators can do quick kick detection. he more commonly used
devices are somewhat similar in operation to the pit level indicators. A paddle-type
luid level sensor is used in lowline (Fig. 5.12). In addition, a pump stroke counter is
used to sense the low rate into the well. A panel on the rig loor displays the low rate
into the well. If the rates are appreciably diferent, a gain or loss warning will be given.
During tripping operations, mud circulation is stopped. A signiicant portion of the
pipe is removed from the hole. herefore mud must be pumped to keep the hole full
while the pipe is pulled. Kick detection during tripping operations is accomplished
through use of a hole ill-up indicator. he purpose of the hole ill-up indicator is to
measure accurately the mud volume required to ill the hole. If the volume required to
ill the hole is less than the volume of pipe removed, it should be understood that a kick
may be in progress. In this regard, small trip tanks ofer the best means of monitoring
hole ill-up volume. Trip tanks usually hold 10–15 bbl and have 1-bbl gauge markers.
Figure 5.14 shows an arrangement of two alternative trip tanks. With either arrangement, the hole is maintained full as the pipe is withdrawn from the well. Periodically,
the trip tank is reilled using the mud pump. he top of a gravity-feed type trip tank
must be slightly lower than the bell nipple to prevent mud from being lost to the lowline (Figure 5.14). he required ill-up volume is determined by periodically checking
the luid level in the trip tank. When a trip tank is not installed on the rig, hole ill-up
volume should be determined by counting pump strokes each time the hole is illed.
Gravity Feed
Trip Tank
Alternative
Centrifugal Feed
Trip Tank
Alternative
BOP
Stack
Centrifugal
Pump
Figure 5.14 Two alternative trip-tank arrangements for kick detection during tripping
operations.
230 Fundamentals of Sustainable Drilling Engineering
he level in one of the active pits should not be used since the active pits are normally
too large to provide suicient accuracy.
5.5.2 Kick Management Equipment
he low of luid from the well caused by a kick is stopped by use of special pack-of
devices called blowout preventers (BOPs). It can also be deined as a device to control
formation pressures in a well by closing the annulus when pipe is suspended in the well
or by closing the top of the casing at other times. BOP equipment usually refers to the
mechanical devices used to shut a well in at the surface and the auxiliary equipment
required to circulate the kick out. here are two basic types of preventers used for closing a well: i) annular preventers (bag type), ii) ram type preventers. A combination of
both types is commonly used to make up a BOP stack. Depending on the pressure rating there are diferent designs available. When drilling from a loating vessel the BOP
stack design is further complicated and will be dealt with later.
5.5.2.1 Annular Preventers
Sometimes an annular preventer is called a bag-type preventer. It is a device that can
seal around irregularly shaped objects or an openhole. It stops low from the well using
a ring of synthetic rubber that contracts in the luid passage. Most designs of this type
consist of a high tensile strength circular rubber-packing unit. he rubber is molded
around a series of metal ribs. he rubber packing conforms to the shape of the pipe
in the hole. he packing unit can be compressed inwards against drill pipe by a piston
operated by hydraulic power. he packing element will close of around any size or
shape of pipe as well as sealing of openhole. An annular preventer will also allow pipe
to be stripped in and out and rotated, although its service life is much reduced by these
operations. he rubber-packing element should be frequently inspected for wear and
is easily replaced. Most annular preventers also will close an openhole if necessary. A
cross section of one type of annular preventer is shown in Figure 5.15. Annular preventers are available for working pressures of 2,000, 5000, and 10,000 psig. However, the
annular preventer provides an efective low-pressure seal (5000 psi) and is usually the
irst to be used in closing in a well.
5.5.2.2 Ram Type Preventers
Ram preventers have two packing elements on opposite sides. Figure 5.16a shows the
ram type BOP preventers and Figure 5.16b and 5.16c show the detail parts the ram
type BOP. here are three types of ram preventers: i) blind rams, ii) shear rams, and
iii) pipe rams. Blind ram completely closes of the well when there is no pipe in the hole.
However, it does not stop the low from the well. Shear rams are the same as blind rams
except that they can cut through drill pipe for emergency release as a last resort. hey
are designed to shear the drill string when closed. his action will cause the drill string
to drop in the hole. As a result the low from the well will be stopped. Shear rams are
closed on pipe only when all pipe rams and annular preventers have failed. Pipe rams
seal of around a speciic size of pipe and thus sealing of the annulus. hey have semicircular openings, which match the diameter of pipe sizes. herefore the pipe ram must
Well Control and Monitoring Program
WEAR PLATE
PACKING UNIT
HEAD
OPENING
CHAMBER
PISTON
CLOSING
CHAMBER
Figure 5.15 Annular type blowout preventer (Redrawn from Bourgoyne et al., 1986).
Seal Ring Grove
Ram
Rod Seals
Rod Seal
Cylinder
Piston Seals
Manual Lock
Ram Faces
Cover Seal
Seal Seat
Ring Gasket
Body
Control Opening
Ram Guide
Exhaust Line
Fluid Entry
Side Outlet
Ram Rode
(a)
Working Fluid Control
Opening Cover
(b)
Road Seals
Piston Seals
Body
Cylinder Head
Door Seal
Flat Door
Ram
Piston Assembly
Wear
Rings
(c)
Figure 5.16 Ram type blowout preventer.
Secondary
Ram Shaft Seal
231
232 Fundamentals of Sustainable Drilling Engineering
Bell Nipple
Flow Line
Fill Line
Annular
Preventer
A
R-Blind
Rams
R-Pipe
Rams
Drilling
Spool
Kill Line
Choke
Flow Line
S
Casing
Head
Figure 5.17 Typical BOP stack arrangement.
match the size of pipe that is in use. If there are multiple sizes of drill pipe in the hole,
additional ram preventers must be used in the BOP stack. A set of pipe rams may be
installed below the shear rams to suspend the severed drill string. Ram type preventers
can be used for working pressures of 2,000, 5,000, 10,000 and 15,000. he sealing elements are constructed in a high tensile strength rubber. hey are designed to withstand
very high pressures.
5.5.2.3 Blowout Preventer Stack
he BOP stack is the assembly of drilling-control equipment connected to the top of
the casing head. he basic items of the BOP stack are blind ram preventer, pipe ram
preventer, annular preventer, drilling spool, kill line, choke lowline, bell nipple, and
ill line. Figure 5.17 shows a typical BOP stack arrangement with basic equipment.
he stack arrangement (Figure 5.18) depends on the pressures where the BOPs will be
expected to cope with the working pressures. BOP stack can be designed to handle up
to 15,000 psi.
here is an API code for describing the stack arrangement. he code can be designated as:
"
5M – 13
5
RSRdAG
8
Here:
5M " = the working pressure (for this case: 5,000 psi)
5
13
= diameter of the vertical bore
8
RSRdAG = the order of the components from the bottom up
where
Well Control and Monitoring Program
233
G*
A*
A*
A*
R
R
R
R
R
R
S
R
S
R
S
R
Casing
Spool
Casing
Spool
Casing
Spool
Figure 5.18 Drilling spool.
G
A
Rd
S
R
= rotating BOP for gas/air drilling
= annular preventer
= double ram-type preventer
= drilling spool
= single ram-type preventer
5.5.2.4 Drilling Spools
A drilling spool is a BOP stack connection having both ends equipped with flanges
as a connector. Normally it has the same bore diameter as the blowout preventers. It
allows chock and kill lines to be attached to the BOP stack. Figure 5.18 depicts the
drilling spool with a typical surface stack blowout preventer. The symbol S is used
for representing drilling spool. During the stripping operation, a drilling spool provides space between ram preventers. The spool must have a bore at least equal to
the maximum bore of the uppermost casing head. The spool must also be capable
of withstanding the same pressures as the rest of the BOP stack.
5.5.2.5 Casing Spools
he wellhead from which casing strings are suspended is made up of casing spools
(Figure 5.18). A casing spool is installed ater each casing string is being set. he BOP
stack is placed on top of the casing spool and connected to it by langed, welded or
234 Fundamentals of Sustainable Drilling Engineering
Figure 5.19 Casing spool.
Figure 5.20 Casing head.
threaded connections. Once again the casing spool must be rated to the same pressure
as the rest of the BOP stack. he casing spool outlets should only be used for the connections of the chock and/or kill lines in an emergency. A typical casing spool is shown
in Figure 5.19.
5.5.2.6
Casing Head
he casing head is the connection between the blowout preventer stack or casing spool
and the casing (Figure 5.17). It is the lowest part of the wellhead, which is almost always
connected to the surface casing string. It provides a means of suspending and packing
of the next casing string. It provides annular outlets, as well as supporting the BOP
while drilling the remaining stages. he casing head is generally the irst component
to be installed ater the casing has been set. he next element of the BOP stack can be
placed on top of the casing head and connected to it by langed, welded or threaded
connections. Again the casing head must be rated at the same pressure as the rest of
the BOP stack. A typical casing head is shown in the Figure 5.20, which can take up to
10,000 psi working pressure.
Well Control and Monitoring Program
235
Figure 5.21 Kill and choke lines.
5.5.2.7 Kill and Choke Lines
A pipe that is used to pump heavy mud into the annulus is called a kill line (Figure 5.11).
It is a line attached to some point in the blowout preventer assembly through which
drilling luid can be pumped into the hole to subdue well pressure. he main purpose
of the kill lines is to assist the chock line as a backup (Figure 5.21). Conduits used to
release luid from the annulus may include a chock line, a diverter line, or simply a
lowline. To kill a kick the, heavy mud is pumped down through the drill string up the
annulus and out to surface. Since the well is generally closed in at the annular preventer,
another exit must be available below this point to allow the wellbore luids to leave the
annulus. he chock line carries the mud and kick luid from the BOP stack to the chock
manifold. Both chock and kill lines can be used to pump directly into the annulus
(Figure 5.11).
5.5.2.8
Diverter System
he function of a diverter system is to allow the well to blowout safely or bridge itself.
Figure 5.22 shows a typical diverter system through which the kick must be diverted safely
away from the rig. his type of BOP is normally used when surface hole is being drilled.
If the well has a tendency to have a blowout at this shallow depth, there would not be
any beneit of using a proper BOP stack because the formation fracture gradient would
be too low. he pressure is possible to be low (example: 500 psi). However a high volume
of luids can be expected. he discharge line should be as straight as possible and irmly
secured.
236 Fundamentals of Sustainable Drilling Engineering
Bell/Flow nipple
Flow line
Diverter
Vent line should be
correctly oriented
downwind from the
rig and facilities
Full- opening valve
(Automatically opens
when diverter closes)
Diverter
line
Drive pipe or
conductor pipe
Figure 5.22 Diverter system (redrawn from Ford, 2005).
Figure 5.23 Choke Manifold.
5.5.2.9
Choke Manifold
It is a manifold connecting chocks to the choke lowline (Figure 5.11). Chock manifold
is an arrangement of lines, valves, and chokes (Figure 5.23). It is designed to control
the low from the annulus of the well. It must be capable of i) controlling pressures by
using manually operated chokes or operated from a remote location, ii) diverting low
to burning pit, lare or mud pits, iii) having enough back up lines so that failure of the
any part of the manifold can be tackled, and iv) working pressure equal to BOP stack.
Since during a gas kick excessive vibration may occur, it must be well secured. Drill pipe
and annulus pressure gauges should be monitored on the chock manifold.
5.5.2.10
Choke Device
A choke is a device in the well circulating system with either a ixed or variable aperture
used to release the low of well luids under controlled pressure. It applies some low
Well Control and Monitoring Program
237
restriction, which creates a backpressure in the system. his pressure is used to control
formation pressure during a well drilling operation. Two type chocks are available: i)
positive (ixed oriice) chock, and ii) adjustable chock (rubber or steel elements). he
chock opening may be adjusted by the relative position of two tungsten oriices, or
another design uses a rod and cylinder type action. he choke can be operated hydraulically or manually based on design and necessity.
5.5.2.11 Internal Preventers
he internal preventer is also called the “inside blowout preventer”. It is a check valve
placed in the drill string that permits circulation down the hole and prevents any back
low. However, there are diferent types of tools used to prevent formation luids rising
up inside the drill pipe. Float valves, safety valves, check valves, and the kelly cock are
some of them. he function of a loat valve is to prevent upward low. It is installed in the
drill string and allows normal circulation to continue. Float valves are more oten used
to reduce backlow during connections. One disadvantage of using a loat valve is that
drill pipe pressure cannot be read. As a result a manual safety valve should be kept on
the rig loor all times. It should be a full opening ball-type valve so there is no restriction
to low. his valve is used when a kick occurs during a trip, and is installed onto the top
of the drill string.
5.5.2.12 Accumulators
An accumulator is a device which stores liquid under gas pressure to hydraulically
operate blowout preventers. It is also called the hydraulic power package. Figure 5.24
shows an accumulator in which the storage device for nitrogen pressurized hydraulic
luid and is used in operating the blowout preventers. he BOP operation is controlled
from the rig loor through the control panel. he control panel is connected to an accumulator system. his system supplies the energy required to operate all the elements
of the BOP stack. Hydraulic oil is stored under a compressed nitrogen gas. If there is a
need to close the BOPs, hydraulic oil is released. his mechanism is designed in such a
way that it can be operated in less than 5 seconds. Hydraulic pumps reill the accumulator with the same amount of luid used to operate the BOPs. he accumulator must
be equipped with pressure regulators since diferent BOP elements require diferent
Figure 5.24 Accumulator.
238 Fundamentals of Sustainable Drilling Engineering
closing pressures (e.g. annular preventers require 1,500 psi while some pipe rams may
require 3,000 psi). Another function of the accumulator system is to maintain constant
pressure while the pipe is being stripped through the BOPs. he accumulator system
must be tested regularly to ensure that it is working eiciently.
5.6 Well Monitoring System
here are many individual pieces of equipment on a rotary drilling rig as mentioned
in Chapter 2. hese individual pieces of equipment can however be grouped together
into six subsystems. hese systems are i) the power system, ii) the hoisting system, iii)
the circulating system, iv) the rotary system, v) the well control system, and vi) the well
monitoring system. his section only deals with well monitoring system. he other
subsystems are already discussed in Chapter 2, and 3.
he well monitoring system can be deined as a situation in which the well and the reservoir are continuously monitored through diferent devices. Safety, security, environmental protection, and eiciency of the well require a real-time or continuous monitoring
of the well to identify drilling problems quickly. his early detection prevents the blowout of the well and protects the rig side and the environment. A permanent well monitoring system is composed of inlow control valves that enable choking or shutting of
diferent zones according performance such as drawdown, GOR or water cut, downhole
sensors that register pressure, luid low rate and temperature. Diferent monitoring and
control devices are used to record or display the parameter data. he parameters such as
i) depth, ii) ROP, iii) hook load, iv) rotary speed, v) rotary torque, vi) pump rate, vii)
pump pressure, viii) mud temperature, ix) mud density, x) mud salinity, xi) gas content of mud, xii) hazardous gas content of air, xiii) pit level, and xiv) mud low rate are
monitored continuously. Real-time well monitoring ofers the pressure, temperature,
low, luid density, and wellbore stress data. hese data enable a better understanding of
well behavior while minimizing the operational and health, security, and environmental risk and overhead.
he driller must be aware of how drilling parameters are changing (i.e. WOB, RPM,
pump rate, pump pressure, gas content of mud etc.). For this reason there are various
gauges installed on the driller’s console where he can read them easily (Figure 5.25).
hus surface control units are used to handle the monitored data and for remote operation of the downhole inlow control valves (Figure 5.25). In addition, control lines are
used for power transmission and transferring of monitored downhole data captured
by downhole sensors (Figure 5.26). he igure shows the wellhead control panels. It is
designed to control single or multi-wells. hese units are designed as removable drawer
module type or integrated ixed assemblies. he panel consists of supply and subsurface safety valve (SSSV) return reservoirs, dual electrically driven hydraulic pumps,
accumulators, ilters and associated control and instrumentation for both low pressure
hydraulic supply headers and the high-pressure hydraulic supply headers. he wellhead
control panel is designed as a fully enclosed assembly with the hydraulic power unit
providing a common source of hydraulic power for each well control module.
Another useful aid in monitoring the well is mud logging. he mud logger carefully
inspects rock cuttings taken from the shale shaker at regular intervals. By calculating
Well Control and Monitoring Program
(Source: http://www.china-ogpe.com)
239
(Source: http://www.ridgewaterservices.com)
Figure 5.25 Example of control panels for well control system.
Figure 5.26 Wellhead control panel (Source: http://www.specialisedmanagementservices.com).
lag times the cuttings descriptions can be matched with the depth and hence a log of
the formations being drilled can be drawn up. his log is useful to the geologist in correlating this well with others in the vicinity. Mud loggers also monitor the gas present
in the mud by using gas chromatography. he well monitoring system has improved
signiicantly for last few decades. New technologies such as i) intelligent wells, ii) digital
oilield, iii) multiphase pumping, and iv) subsea separation and re9injection are the key
in current days well monitoring system.
Wells with permanent monitoring systems are commonly called intelligent or smart
wells (Figure 5.27). Permanent well monitoring is commonly used in multilateral wells,
where hydraulically independent valves control the low of each lateral and in deepwater
wells, where well-intervention operations are oten prohibitively expensive. Permanent
well monitoring helps improve reservoir management by quickly choking or shutting
of zones, avoiding expensive well intervention. It also helps maximize production and
optimize recovery.
240 Fundamentals of Sustainable Drilling Engineering
Wells Equipped at completion with Downhole Control and Sensors
Horizontal
Producer
Pilot Well
Proactive
Remediation of
Fluid Inlow
• Remote controlled Downhole
zonal control valves
• Implement reservoir decisions
without intervention
• Optical Pressure Gauge
• Optical Distributed Temperature
Gauge
• Data is transmitted up the
wellbore via iber optics
Gas Injector
Continuous data from wells
Pressure
Performance
Inlow
Distribution
Downhole
Seismic
Reservoir
Saturation
Flowing
Phase
Figure 5.27 Example of intelligent well.
Facilities
Data Store
4D / 4C - Permanent
seismic
Real-Time Data
Transmission
high-resoluble data is
A
obtainable by a 4C seismic
survey using 4 components OBS
(marine earthquake cable) with
a hydrophone and 3 geophone
components.
Reservoir
Management
HIVE
Integration for
Decisions
Control,
Optimization &
Intervention
Decision
Facilities
Driven
model Business Analysis
model
Reservoir
model
Market
Drivers &
Intelligence
Export/Transport
Well
Construction
Figure 5.28 Example of digital oilield wells.
Figure 5.28 shows the digital oilield well that is used to monitor the well in a continuous basis in real-time. he ield data are transferred in real-time to the data storage
hub through satellite. he diferent decision models are the used to analyze the data to
get real-time appropriate decision to monitor the well.
5.7 Current Practice in Well Control and Monitoring
Well control is considered one of the most crucial features in drilling hydrocarbon reservoir. Indeed it afects the overall cost of the well completion and sometimes it leads to
facilitating damage to the environment. Human errors and equipment failure are the
major causes for blowout. his situation occurs in many environments such as highpressure high temperature (HPHT) environments when kicks are underestimated and
thus the drilling personnel cannot control the well. Contingency plans should be in
place to handle this unexpected potential blowout. Besides the well control, there is also
Well Control and Monitoring Program
241
one important aspect to take into consideration while drilling is the well monitoring.
Well monitoring provides us the information about the downhole condition. herefore,
the necessity for the early detection and the control of the kick, losses, and the other
abnormal circumstances while drilling are becoming essential as the drilling activities has increased signiicantly. here are areas that have challenging environments
onshore and ofshore as a result of diiculties with respect to pressure regimes, equipment stresses, and monitoring the drill string while drilling. his section discusses the
current trend to control the well in an efective manner. Finally it shows the modern
equipment to be used to monitor the well while drilling.
he BOP component can be organized in many ways depending on the company’s
policy. Each BOP coniguration has beneits and drawbacks depending on pressure
needed and components, which are added or omitted. For example, Figure 5.29 shows
the company policy of Saudi Aramco for operation in the Kingdom of Saudi Arabia and
BOP coniguration the ofered by Halibarton oil company for a well drilled with a hole
size more than 4-in. diameter (Grøttheim, 2005).
In conventional ofshore drilling operations, all the mud that is coming out of the well is
dumped outside the well in the vessel and is open to the atmosphere (Malloy et al., 2009).
As the vessel is open, the low increases with no incremental pressure from the wellbore,
which is oten a sign of an imminent well control incident. In this method, pressures cannot be adequately monitored until the well is shut-in and becomes a closed vessel (Malloy
et al., 2009). In underbalanced drilling operation, the pressure exerted by mud is less than
pore pressure and thus produce while drilling. here is also another concept in drilling
called managed pressure drilling (MPD) which is similar to underbalanced however no
production occurs. he inluxes are allowed to traverse up the hole and are controlled by
three major surface containment devices called i) rotating control device (RCD), ii) drilling choke manifold, and iii) multiple phase separator (Malloy et al., 2009). here are some
modern trends in well control that are discussed below.
Mud Pump
Rotating Head
Weco Union
1622
Annular
Choke
Valve
Injector head
Stripper
Pipe Rams
2.1/191 10M Kill Line
4.1/191 10M Choke Lit
Drilling
Spool
HCR
Drill loor
Shear Blind rams
Manual
Manual
HCR
Mud returns
Annual preventer
Blind rams
Lower Blind rams
Lower Pipe rams
Casing
Spool
HCR Manual
BOP stack 7 1/16 in., 5000 psi
Shear rams
Kill
3.1/161 Emergency Kill Line
Choke
Wellhead, casing
or christmas tree
Connected to
Emergency pump
Figure 5.29 BOP stack coniguration from Saudi Aramco and Halibraton.
Ground
242 Fundamentals of Sustainable Drilling Engineering
5.7.1 Managed Pressure Drilling
MPD is an adaptive drilling process used to precisely control the annular pressure proile throughout the wellbore. he objectives are to establish the downhole pressure environment limits and to manage the annular hydraulic pressure proile accordingly. MPD
is intended to avoid the continuous inlux of formation luids to the surface. Nowadays,
MPD is recognized as one of the modern methods for drilling operation expected to
be the future trend for well control (detecting kicks). his method is used to mitigate
drilling hazards like lost circulation, stuck pipe, wellbore instability, and well control
incidents. MPD is considered a straightforward adaptation of conventional well control such as driller’s method. Santos et al. (2003) and van Riet et al. (2003) explained
the technologies through which MPD operations can be applied. hese technologies
were examined on gas kicks simulated by the use of computer applications and with
gas injected in real facilities to implement the driller’s method (Davoudi et al., 2011).
Santos et al. (2007) describe the use of a computer model to utilize the ingerprint
for measuring well control incidents (Davoudi et al., 2011). Fredericks et al. (2008)
explained kick-detection utilizing accurate low out metering simultaneously with
more accurate control of bottomhole pressure utilizing a pressure while drilling apparatus and wired drill pipe. Saponja et al. (2006) suggested that the same technique can
be utilized for controlling high pressure, low volume gas kicks during tripping operations. Some researchers reviewed devices utilized as a conversion of well control operations to alarm levels of formation luid in the well that requires a response (Saponja et
al. 2006; Vieira et al. 2008; Urbieta et al. 2009). Andreas Sadlier et al. (2011) studied the
use of special sotware, which reduces the potential risk for kicks, lost circulation and
wellbore instability events.
In addition, the use of RCD associated with MPD provides more precisely rolling of
the annular wellbore pressure proiles, detection of inluxes, and losses. As a result, the
safety of rig personnel and equipment during everyday drilling operations is improved.
Rotating control devices for some kinds of MPD operations increase the number of
kicks detection to well control issues. he use of RCD gives the drillers an additional
level of comfort since it creates pressure management, but the need for well control is
an obligation. Well control procedures are relaxed as a result of MPD. It is indeed the
primary well control as the pressure in the well is controlled to avoid an inlux of formation luids into the wellbore. Dropping the mud weights has the potential to introduce
more well control events. Approximately 90% of the wells in Asia Paciic have indeed
encountered kicks where MPD operations with choke manifolds were used.
Setup for MPD operations: Figure 5.30 shows the MPD set up in a closed wellbore. It
is a closed wellbore system with RCD installed at the top of the annular preventer. he
outlet from the RCD is divided between the main return lowline and the MPD choke
manifold. It is installed in parallel with the rig main low line and in parallel with the
choke manifold. Backpressure can be felt at any time to the well. As a result MPD manifold is used and the gas production can safety be removed by gas separator. It is done
when the surface pressure exceed the limit of RCD pressure (i.e. 3000 psi).
here are three circumstances that result in well kick i) formation pressure more
than of the wellbore pressure, ii) suicient permeability to allow low into the wellbore,
Well Control and Monitoring Program
Main low line
MPD Choke Manifold
with Coriolis Meter
Rig Choke
Manifold
Shale
Shakers
Gas to vent
Mud gas
Separator
Triptank ill up
Bleed of
243
Trip
Tank
Trip tank
pump
Figure 5.30 MPD Set up in a closed wellbore.
and iii) low viscosity of the formation luid. As we mentioned earlier, primary well
control is lost because of the insuicient mud density, failure to keep the hole full while
tripping, swabbing while tripping, and lost circulation. So, MPD is a good choice for
controlling the unexpected entry of formation luid.
Kick detection in closed wellbores: here are advanced tools used to detect the kick
that rely on sonic measurements of the annular luid or systems rely on measuring
measurement while drilling (MWD) pulse signal travel times in the annulus. Mass
low meters in combination with very accurate standpipe pressure sensors permit
automated kick measure system as utilized on some of the MPD systems. However,
when tripping or making connections are continued, the low out is usually considered a well control issue. he following devices are some examples of the advanced
detection tools.
i) Flow meters: A low meter is made of a primary device, transducer, and transmitter.
he transducer measures the luid that lows through the apparatus and transmitter
produces a usable signal. hese low measurements are done in three ways: volumetric
low, velocity low, and mass low. Examples of low meter technologies that measure
velocity include magnetic, turbine, ultrasonic, and vortex shedding and luidic low
meters. he Coriolis mass low meters operates by calculating the density.
ii) Coriolis meters: It is likely to adjust the low into the well from the pump strokes
and calculate the discharge of the well with the low meter by using special programs.
Figure 5.31 shows the kick detection using low in and low out concept. Since there are
variations in low, an alarm indicates that there is a kick. In such condition, backpressure is applied for three to four minutes and the well is shut-of. he kick is detected
ater a 1 bbl inlux and closed in ater just a 3 bbl gained.
It is noted that there might be a problem called ballooning due to returned mud
when the mud pumps are turned of (Figure 5.31). his inlux can be handled safely
by stopping circulation and using the choke. However, the increase of mud weight is
the best solution to control ballooning. he precise measurements of low in and out of
the well permits kick detection and detection of losses, and ballooning in a wellbore.
However, a kick can still happen if attention is not paid.
244 Fundamentals of Sustainable Drilling Engineering
Figure 5.31 Kick detection using low in and low out and example of ballooning.
iii) Mass low meter: A kick can be detected in a closed wellbore utilizing the mass low
meter. As the wellbore is already closed, there are now two choices with an MPD system: i) use MPD equipment and choke manifold, ii) use BOP’s and rig choke manifold.
5.7.2
Real Time Data Analysis with Dynamic Neural Network
Over the years the apparatus used to detect the kick has signiicantly advanced in terms
of technology and intelligent tools. he following are some of the recent advances in
well control and monitoring system.
Wave Processing of the Parameters: his tool is designed to measure the propagation
time of pressure pulses that are sent through the mud system. he system can detect
any gas entry in the borehole 15 minutes before the surface warning sensor’s exposure.
his tool works better when drilling operations continue. However, it does not work
properly when we stop the drilling operation due to tripping or connecting pipes. he
limitation of the tool is that it may give wrong warning as a result of the movement of
drill pipe.
Using Flow-out Sensors’ and Delta Flow: he delta low is the diference between
the inlow and outlow rate, which is the major factor for kick detection in much of
the literature. here are inlow devices that are utilized in drill string like conventional
pump stroke counters, rotary pump speed counters, magnetic low meters, and doppler ultrasonic low meter. For outlow, there are standard paddle meter, acoustic level
meter, rolling loat meter. Liquid level monitoring is also one of the important parameters. Schubert and coauthors proposed the use of an acoustic device installed on the
casing valve to the ongoing observed liquid level in the annulus for wells experiencing
complete loss of returns.
5.8 Future Trend on Well Control and Monitoring System
Eiciency in drilling and safety of the crew irst and also the equipment require constant monitoring of the well so that it can detect any drilling problems. he driller’s job
Well Control and Monitoring Program
245
is to monitor the drilling so that the operation succeeds. Devices that are used to record
or display parameters such as i) depth of the well, ii) rate of penetration, iii) rotary
torque, iv) pump rate, v) pump pressure, vi) mud density, vii) mud temperature, viii)
mud salinity, ix) gas content of mud, x) hazardous gas content of air, xi) pit level, and
xii) mud rate are part of the monitoring system (Bourgoyne et al., 1986). Also, one way
to assist the driller in detecting problems is to look at the good records about the drilling operation that they might face. Over the years, these techniques have been improving fast and well monitoring has helped to drill wells while minimizing costs with the
safety of the crew and the equipment in mind. However, most of the drilling failures are
related to the fail of the drill string because of certain occasions. So the future trend in
well monitoring focused in monitoring the drill string specially in deep and trajectory
well where the equipment fatigue due to great stress.
5.8.1 Real Time Vibration Measurement
Since the early 1990s, vibration measurements while drilling have been used in the
oil and gas industry to understand downhole dynamics (Aldred and Sheppard, 1992;
Arevalo et al., 2011). his is one of the methods that quantify the drill string integrity
failure risk using real time vibration measurement. Failures connected with drill string
vibration keep on happening in spite of the complexity of measurement available nowadays. hese failures represent a very major amount of the loss of the time that is aimed
to improve. Operators encountered with an unidentiied quantiication of the risk
severity when trying to diminish vibration, and by quantifying the danger, this work
proves how to stop incidents which are not just limited to twist ofs, back ofs, and bottomhole assembly (BHA) component failures (Arevalo et al., 2011). he solution has
been developed with the use of advanced vibration sensors to classify between diferent
types of vibration. About 80% of drill string integrity failures analyzed can be recognized and prevented using the proposed risk quantiication solution (Arevalo et al.,
2011). However, there are diiculties in using these devices and sometimes gives error.
herefore, it is a challenge to make it more reliable tool to handle risk quantiication.
he measurement device: Is a multi-axis vibration chassis (MVC) that is a four-axis
shock measurement tool (Ashley et al. 2001; Arevalo et al., 2011). he irst axis of the
system comes to the strain gauges and accompanied electronics used for torsion measures. he lasting three axes comes to a system containing the vibration acquisition
board and three of slat accelerometers. he whole system is raised on a particular chassis in the measurements while drilling (MWD) device (Arevalo et al., 2011). he quantiication of the vibration related risks based on the indices are utilized in geotechnical
earthquake engineering to explain the critical potential of seismic movements. his
study aimed to determine which one of the indices or which arrangement of them
can give a better and also remain simple solution to calculate the risk of a vibration
linked drill string integrity failure (Figure 3.32). In the application of vibration severity
indices, the analysis is all from vertical wells. Seventeen and half inches (17 ½ in), or
similar hole sizes are the majority common hole size in the top hole and the maximum
frequency of integrity breakdown. his is also reached to smaller hole sizes, mostly 12
¼-in.
Normalized Vibration Indices
246 Fundamentals of Sustainable Drilling Engineering
2
1.8
1.6
1.4
1.2
1
0.8
0.6
0.4
0.2
0
Vibration Intensity
Characteristic Intensity
Optimise parameters
for maximum drilling
performance
Require formal MOC for
drilling ahead with
increased risk levels.
1.5
Stop operation.
Severe risk of
drillstring failure
0.75
0
10
20
30
Time (h)
40
50
60
Figure 5.32 he risk management process based on integrity failure risk quantiication
As a result of the excellent correlation with real integrity failures, the characteristic intensity as the primary risk symbol has been chosen for real time monitoring.
However, the vibration intensity ought to be watched as an exact measurement of the
vibration energy mounted up by the assembly.
In short, 12 ¼-in. sections noticed to sufer from considerably minor vibration levels. In spite of the discussed limitations of the technique, outcome seems to indicate
that the main donor to the actual integrity failures is the fatigue gathered along the
existing bit run.
Measurement of drill dynamics by using multiple downhole Dynamics Recorders:
As we mentioned above, modern technology trends in drilling have become more interested in monitoring drilling dynamics and vibration as a result of their efect reduced
drilling performance, downhole tool and drill string failures. Historically, vibration data
measured by the MWD tool was associated with a lower BHA. However, the reason for
the extreme surface torque could not be clariied. So, the use of DDRs is to get more
understanding and the cause of the torque. It can also put up to 2500 m from the drill
bit, for two subsequent wells. When we increase the rate up to a threshold RPM, the
drill string starts moving up and down as the drill string hits the borehole that leads to
increased levels of lateral vibration. Severe lateral vibration like a whirl can cause downhole tool failure, damage to the drill bits, and drill string twist ofs. Both torsional and
lateral vibration can cause loss of penetration rates and numerous unwanted BHA or bit
trips. MWD or LWD tools that are historically used capture little vibration data within
the drill pipe. However, DDRs enabled the simultaneous measurement of vibration levels at several positions along the drill string and BHA.
Monitoring using Micro seismic Techniques in Clastic Reservoir: his is one of the
efected methods that are done in monitoring the hydraulic fracture mapping in clastic
gas reservoir. his is done by wire line sensors where recorded micro seismic (MS)
events indicating fracture growth as they are being created by rock failure. here is
great level of detail to which a hydraulic fracture can be imaged using MS data recorded
by arrays placed in a nearby monitoring well. Here I will discuss the pilot test done in
India, which was the irst time this technique used there. Understanding of the fracture geometry from this technique beside the fracture geometry gained from fracture
modeling, well test, would be joined to come up with optimized designs for future
Well Control and Monitoring Program
247
fracturing. In 2009, Cairn Energy India Pte. Ltd. (CEIL) made this test to validate and
prove the values of Micro seismic monitoring technique in evaluating the hydraulic
fracture stimulation. his monitoring was done for distance >1000 t. and companies in
Fatehgarh reservoirs requesting (CEIL) to do the fracture monitoring. he Raageshwari
Horst is one of the larger Central Basin High (CBH) structure important network of
fault terraces in Barmer basin which is divided into four fault-deined diamond shaped
compartments by faults parallel to the western margin and eastern margin faults
Raageshwari ield contains two types of reservoirs, the clastic reservoirs and volcanic
units.
5.9 Summary
he chapter discusses almost all aspects of well control and the monitoring system. How
a well can be controlled in a sequential and safe way is well documented here. Knowing
what the diferent control devices are that are used while drilling is paramount in any
well control and monitoring system. hese devices and their functions are outlined in
this chapter. Well monitoring is an integrated part of the drilling operations. herefore,
parameters that need to be monitored to control the well are identiied through this
chapter. his chapter covers the whole range of real-time monitoring system and discusses the current practices in the industry and the future trend of the well control and
monitoring system in general.
In short, well control is considered one of the most crucial aspects in drilling gas and
oil reservoirs. In fact it afects the overall cost of the well completion and sometimes it
leads to fatalities, and numerous or great damage to the environment. Human errors
and equipment failure are the cause of blowouts, which are not controlled by the formation luids, so well control becomes the most important aspect. Also well monitoring is
the most important aspect in drilling and production. It provides us with a view of what
is happening downwards in the well. hat is to say, the necessity for the early detection and the control of these kicks, losses and also the other abnormal circumstances
while drilling are becoming essential. he drilling industry has increased work in areas
that have challenging environments onshore and ofshore as a result of diiculties with
respect to pressure regimes and equipment stresses. Also, drill string monitoring is an
important aspect in well control.
5.10 Nomenclature
Aann
Cann _ dc
Cann _ dp
Gf
Gi
Gk
Gm
Hi
= cross-sectional area of the annulus, bbls/t
= the annulus capacity behind the drill collar, bbl/t.
= the annulus capacity behind the drill pipe, bbl/t.
= fracture pressure gradient, psi/t
= inlux pressure gradient, psi/t
= kill mud pressure gradient, psi/t
= mud pressure gradient, psi/t
= vertical height of the inlux or kick, t
248 Fundamentals of Sustainable Drilling Engineering
Hm
Hvc
Hcs
Ldc
Lk
Pann _ m
Pbh
Pfc
Pic
Picp
Pidp
Pob
Pok
Pp
Psifp
Psidp
Psiann
Vann _ dc
Vpit
k
km
ok
om
= vertical height of mud in the annulus ater inlux, t.= Hvc – Hi
= total vertical height of the mud column, t
= vertical height of the casing shoe or depth to the casing shoe, t
= length of the drill collar, t
= kick length (i.e. vertical height of inlux, Hi), t
= maximum shut-in annulus pressure, psi
= bottomhole (i.e. formation) pressure, psi
= inal circulating pressure, psi
= initial circulating pressure, psi
= initial stabilized drill collar pressure, psi
= initial stabilized drill pipe pressure, psi
= overbalance pressure, psi
= overkill pressure, psi
= slow circulating pump pressure, psi
= G f H cs = shut-in fracture pressure, psi
= shut-in drill pipe pressure, psi
= shut-in annulus pressure, psi
= the annulus volume against drill collar, bbl
= pit gain volume, bbls
= kick luid (i.e. inlux) density, ppg
= kill mud weight, ppg
= overkill mud weight for safety margin, ppg
= original mud weight, ppg
5.11 Exercise
"
1
E5.1: A 7 diameter hole is drilled up to 9000 t. with a density of 11.5 ppg. If the
2
formation pore pressure at this point is 4800 psi. Calculate i) mud pressure overbalance
above the pore pressure, ii) if the mud density is 10.5 ppg, what would be the overbalance, and iii) if the luid level in the annulus is dropped to 300 t. due to inadequate hole
ill up during tripping, what would be the efect on bottomhole pressure?
"
1
E5.2: A 6 diameter hole is drilled up to 7000 t where it encountered an overbal2
ance of 350 psi. If the formation pore pressure at this point is 4800 psi. Calculate i) mud
density, ii) if the mud density is 9.5 ppg, what would be the overbalance, and iii) if the
luid level in the annulus is dropped to 200 t. due to inadequate hole ill up during tripping, what would be the efect on bottomhole pressure?
E5.3: A target depth was set at 7500 t. with a hole size of 6.5 in. he drilling crew
noticed that there was a pit gain of 14 bbls. he well is shut-in and the drill pipe and
annulus pressures were recorded as 600 psi, and 700" psi respectively. he bottomhole
"
1
3
assembly consists of 550 t. of 4 OD collars and 3 drill pipe. he mud weight is 10.4
2
4
ppg with a mud pressure gradient of 0.5 psi/t. Identify the inlux and calculate the new
mud weight, including an overbalance of 200 psi.
Well Control and Monitoring Program
249
"
5
set at a depth of 2,000 t. he fracture
8
gradient was found 0.76 psi/t. he mud density was 9.6 ppg with a mud gradient of
0.5 psi/t. Total depth of the well was 10,000 t. and the internal yield was 2,470 psi.
Determine the maximum permissible surface pressure on the annulus. Assume that the
casing burst is limited to 80% of design speciication.
E5.5: Determine the kill mud density and kill mud gradient for a shut-in-drill pipe
pressure of 650 psi at a depth of 11,000 t. If the original mud weight is 12.5 ppg and the
slow circulating pump pressure is 800 psi, ind out also the initial and inal circulating
pressure of the system.
E5.6: A kick was detected when drilling a high-pressure zone of a depth of the formation10,000 t. with a mud density of 9 ppg. Ater the well was shut-in, the pressures
recorded were for drill pipe and drill collar as 350 psi and 430 psi respectively. he total
pit gain observed was 5 bbl. he annular capacity against 950 t. of drill collar is 0.0292
bbl/t. the overkill safety margin is 0.50 ppg. Compute the formation pressure, kick
density, the type of luid, and required kill mud weight.
E5.7: A well was being drilled at a high-pressure zone of 9,500 t vertical depth where
10.5 ppg mud was being circulated at a rate of 10.0 bbl/min. A pit gain of 30 bbl was
noticed over a 2.5 minutes period before the pump was stopped and the BOPs were
closed. Ater the pressures stabilized, an initial drill pipe pressure of 550 psi and an initial casing pressure of 750 psi were recorded by the driller. he annular capacity against
750 t. of drill collar was 0.029 bbl/t. and the annular capacity against 800 t. of drill
pipe was 0.072 bbl/t. Compute the formation pressure, inlux density.
E5.4: he surface casing with an OD of 8
References
A. Fadili, P.M.J. Tardy and J.R.A. Pearson, “A 3D iltration law for power-law luids in heterogeneous porous media”. J. of Non-Newtonian Fluid Mech., 106: 121–146, 2002.
Arevalo, Yezid Ignacio, and Ashley Jude Fernandes. “Quantiication of Drillstring Integrity
Failure Risk Using Real-Time Vibration Measurements.” In SPE Asia Paciic Oil and Gas
Conference and Exhibition. Jakarta, Indonesia: Society of Petroleum Engineers, 2011.
Bourgoyne, Jr. Adam T., Keith K. Millheim, Martin E. Chenevert, and Jr. F.S. Young. Applied
Drilling Engineering. First Printing, Society of Petroleum, 1986.
Brekel, Bernd Van Den. “Making Wells Safer, Process Safety & Advanced Well Control Training.”
In International Petroleum Technology Conference. Bangkok, hailand: International
Petroleum Technology Conference, 2011.
Davoudi, Majid, John Rogers Smith, José E. Chirinos, and Bhavin M. Patel. “Evaluation of
Alternative Initial Responses to Kicks Taken During Managed-Pressure Drilling.” SPE
Drilling & Completion, no. 2 (2011): pp. 169–181.
Dutta, Sushant M, Arcady Reiderman, Larry G. Schoonover, and Michael B. Rabinovich.
“Novel Transient Electromagnetic Borehole System for Reservoir Monitoring.” In SPE
Annual Technical Conference and Exhibition. Denver, Colorado, USA: Society of Petroleum
Engineers, 2011.
Final Report on the Investigation of the Macondo Well Blowout. Deepwater Horizon Study
Group. (2011): n. page. Web. 30 Mar. 2012.
Ford, J. (2005). Drilling Engineering. Department of Petroleum Engineering, Heriot-Watt
University, UK.
250 Fundamentals of Sustainable Drilling Engineering
Grøttheim, O.E. “Development and Assessment of Electronic Manual for Well Control and
Blowout Containment”. Texas A&M University, 2005. http://ccrm.berkeley.edu/pdfs_papers/
bea_pdfs/DHSGFinalReport-March2011-tag.pdf.
Jablonowski, Christopher, and Augusto L. Podio. “he Impact of Rotating Control Devices on the
Incidence of Blowouts: A Case Study for Onshore Texas, USA.” SPE Drilling & Completion,
no. 3 (2011): pp. 364–370.
Kamyab, Mohammadreza, Seyed Reza Shadizadeh, HoushangJazayeri-rad, and NavidDinarvand.
“Early Kick Detection Using Real Time Data Analysis with Dynamic Neural Network: A
Case Study in Iranian Oil Fields.” In Nigeria Annual International Conference and Exhibition.
Tinapa - Calabar, Nigeria: Society of Petroleum Engineers, 2010.
Lim, Teck Kean, Satyabrata Mishra, and Anish Gupta. “Hydraulic Fractures Monitoring Using
Microsiesmic Techniques in Volcanic Basalt Reservoir - A Pilot Test Case.” In SPE Asia
Paciic Oil and Gas Conference and Exhibition. Jakarta, Indonesia: Society of Petroleum
Engineers, 2011.
Makvandi, Mehran, Khalil Shahbazi, and HeidarBahmani. “he Great Achievement in Well
Control of One of he Iranian Wells.” In SPE/IADC Middle East Drilling Technology
Conference and Exhibition. Muscat, Oman: SPE/IADC Middle East Drilling Technology
Conference and Exhibition, 2011.
Malloy, Kenneth P., Rick Stone, George Harold Medley, Don M. Hannegan, Oliver D. Coker,
Don Reitsma, Helio Mauricio Santos, et al. “Managed-Pressure Drilling: What It Is and
What It Is Not.” In IADC/SPE Managed Pressure Drilling and Underbalanced Operations
Conference & Exhibition. San Antonio, Texas: 2009, IADC/SPE Managed Pressure Drilling
and Underbalanced Operations Conference and Exhibition, 2009.
Nas, Steve. “Kick Detection and Well Control in a Closed Wellbore.” In IADC/SPE Managed
Pressure Drilling and Underbalanced Operations Conference and Exhibition. Denver,
Colorado, USA: 2011, IADC/SPE Managed Pressure Drilling and Underbalanced
Operations Conference and Exhibition, 2011.
Patel, Bhavin, Todd Douglas Cooper, Simon Nicholas Hughes, and William C. Billings. “he
Application of Advanced Gas Analysis System Complements Early Kick Detection and
Control Capabilities of MPD With Added HSE Value.” In SPE/IADC Managed Pressure
Drilling and Underbalanced Operations Conference and Exhibition. Milan, Italy: SPE/IADC
Managed Pressure Drilling and Underbalanced Operations Conference and Exhibition,
2012.
Raap, Constantijn, Andrew David Craig, and Ryan Basson Graham. “Drill Pipe Dynamic
Measurements Provide Valuable Insight Into Drill String Dysfunctions.” In SPE Annual
Technical Conference and Exhibition. Denver, Colorado, USA: Society of Petroleum
Engineers, 2011.
Sadlier, Andreas G, Christopher Allen Wolfe, Michael M Reese, and Ian Says. “Automated Alarms
for Managing Drilling Pressure and Maintaining Wellbore Stabilityâ” “New Concepts in
While-Drilling Decision Making.” In SPE Annual Technical Conference and Exhibition.
Denver, Colorado, USA: Society of Petroleum Engineers, 2011.
Schlumberger. Blowout preventer, 2012. Web. 1 Mar 2012. http://www.slb.com/about.asp&xgt.
Vargas, A.C. “Use of Rotating Control Devices in High-Pressure/High-Temperature Applications
in Brazil Provides Economic and HSE Beneits.” In Ofshore Technology Conference. Houston,
Texas, 2006.
6
Formation Pore and Fracture
Pressure Estimation
6.1 Introduction
he magnitude of the pressure in the pores of a formation is known as the formation
pore pressure. It is sometimes simply called formation pressure and is also designated
as formation luid pressure, or pressure in luid contained in the pore spaces of the rock.
his formation pressure is an essential consideration in many aspects of well planning
and operations. It afects the casing design and mud design. Formation pore pressure
increases the chances of stuck pipe and well control problems. It is mainly important
due to the prediction and detection of high pressure zones where there is the risk of a
blowout. Besides predicting the pore pressure in a formation, it is also very important
to calculate the pressure at which the rocks will fracture. hese fractures can result in
lost circulation problem. On the other hand, if there is an inlux from a shallow formation, luids will low along the fractures all the way to surface which potentially will
cause a blowout. When the pore and fracture pressure is being predicted for all of the
formations to be penetrated, the well is designed to continue operations. In this case,
pressures in the borehole neither exceed the fracture pressure, nor fall below the pore
pressure in the formations being drilled. his chapter discusses how to determine the
formation luid pressure and fracture pressure. Understanding the variation of these
two parameters with depth is very important in the planning and drilling of a well.
251
252 Fundamentals of Sustainable Drilling Engineering
Rock mechanical properties including geological aspects of rock mechanics in drilling
is covered in this chapter.
6.2 Geological Aspects of Rock Mechanics in Drilling
According to the Rock Mechanics Committee of the American National Academy
of Science, rock mechanics are deined as the theoretical and applied science of the
mechanical behaviour of rock and rock masses. It is that branch of mechanics concerned with the response of rock and rock masses to the force ields of their physical environment. Rock mechanics deal with the mechanical responses of all geological
materials and are applied in mining, petroleum, and other engineering practices. he
principles of engineering mechanics are applied to the design of the rock structures
generated by mining, drilling, reservoir production e.g. mining shats, underground
excavations, open pit mines, oil and gas wells, and other structures built in or of rock.
he rock mechanical behaviour is dependent on the age of the deposition, and
the complicated natural process from an initial state as loose sediment to the present state as a rock. A sedimentary basin may be exposed to sedimentary subsidence,
sea-level changes and tectonic forces. hese parameters create the repeated cycles
of elevation and depression, in addition to erosion, changes in sedimentary environment, changes in sedimentation rate, solution and precipitation of cementing
material etc. All these properties complicate the geological description of the sedimentary basin. hese geological actions and measures will afect not only current
rock mechanical properties, but also current boundary conditions in terms of in
situ stresses and pore pressure. herefore, knowledge of geological processes is very
important in drilling engineering. Even though there is a totally diferent time scale
and length scale, the geological processes are oten analogous with the occasions in
rock mechanics laboratory testing. As a result, such tests may be used to enhance
our understanding of geological phenomena. he purpose of this section is to give
an introduction on geological aspects that are important in petroleum related rock
mechanics for drilling operations.
6.2.1 Rock Mechanical Properties
It is normally assumed that the mechanical properties of a rock are constants. In this
case, a linearly elastic and perfectly brittle isotropic rock can be deined by ive mechanical parameters: a) two elastic parameters – i) Young’s modulus, ii) Poisson’s ratio, and
b) three strength parameters – i) friction angle, ii) the tensile strength, iii) uniaxial
compressive strength. However, transportation, deposition and sediment accumulation
may take place in a variety of depositional environments. hese various environments
will change the diferent distributions of grain size, grain shape. hese grain distributions may afect the mechanical properties of the rock with time even ater millions
of years. he present properties of a sedimentary rock are determined by the entire
process from erosion of rock fragments to transportation, deposition, compaction and
lithiication. herefore the knowledge of these processes is important to evaluate the
mechanical properties of a rock.
Formation Pore and Fracture Pressure Estimation
253
Some deinitions related to grains and granular materials need to be known to have
a strong understanding of the mechanical properties of rock. Grain size is a measure of
the diameter of the grain. Table 6.1 shows the grain sizes for diferent sediments where
-scale is used. In geology, the -scale is deined as
log 2 graindiameter inmm .
According to this classiication scheme, the grain size determines the class of sedimentary rocks. Grain shape involves both the roundness (angularity of corners) and sphericity (proximity to a spherical shape). Finally, grain sorting is a measure of the range
of grain sizes (grain size distribution). A rock containing a wide range of grain sizes
implies to be poorly sorted. On the other hand, well sorted is considered a narrow
distribution.
In the petroleum industry, the common types of rock are dolomite, sandstone, carbonate, chalk, and shale. A basic diference between these rocks is grain or pore size of
the rock. hey range from 0.1–1.0 mm in sands down to the nanometre range in shales.
his diference in grain size afects petrophysical characteristics of the rock. Parameters
such as the porosity and permeability have a profound inluence on mechanical behaviour of the rock.
6.2.2
Underground Stresses
he underground stress can be deined as the resistance of the formation matrix to
compaction. In general, an underground formation has to carry the weight of the overlying formations. herefore, it is the stress arising from the weight of the rock overlying
the zone under consideration. It can be expressed in psi or psi/t. he vertical stress
at the bottom of a homogeneous media can be expressed as v h g , where h is the
height of the media, ρ is the density of the material and g is the gravitational acceleration (assuming constant throughout the reservoir depth). Now for an underground
formation, if the density of the rock varies with depth, the vertical stress at depth D
becomes can be expressed as:
D
(6.1)
g dD
v
0
Table 6.1 Grain size scale for sediments.
Grain Size Diameter (mm)
-scale
> 256
<–8
Boulder
64 – 256
– 6 to – 8
Cobble
4 – 64
– 2 to – 6
Pebble
2–4
– 1 to – 2
Granule
4 to – 1
Sand
8 to 4
Silt
>8
Clay
1/16 – 2
1/256 – 1/16
< 1/256
Term
254 Fundamentals of Sustainable Drilling Engineering
0
Depth (ft)
1000
2000
3000
D
4000
0
2000
4000
6000
8000
10000
Stresses and pore pressure (psi)
Figure 6.1 Normal subsurface pressure with depth.
Figure 6.1 shows the normal subsurface stresses and pore pressure distribution with
depth. Note that the D-axis has the direction vertically downward (i.e. opposite to the
gravitational acceleration) with a reference point at the earth surface (i.e. D = 0). he
vertical stress increases downwards approximately at 0.8 – 1.0 psi/t.
6.2.3 Formation Pressure
Formation pressure (or pore pressure) is the luid pressure found within the pore spaces
of the formation. It can be expressed as an average vertical pressure or equivalent mud
weight. he unit of pore pressure is psi, ppg, g/cc etc. It is an essential parameter in
drilling activities of porous, luid-illed rock systems. he pore luid carries part of
the total stresses of the formation and thus relieves the rock matrix from part of the
load. Knowledge of formation pressure is important in drilling engineering since it
afects the casing design, mud weight, rate of penetration, problems with stuck pipe,
and well control. In addition, knowledge of the pore pressure in the various formations
is extremely important while studying borehole stability during drilling, rock stability
during production, and compaction/subsidence. It is very important because of the
necessities of the prediction and detection of high pressure zones where there is a risk
of blowout. Such zones are usually associated with the thick shale sequences which have
trapped the connate water and normally released during deposition.
If the sedimentation process continues, grains of sediment are continuously building
up on top of each other usually in a water illed environment. As sediments deposit to
form sedimentary layers, the luid (water) is trapped in small pores which form during
the sedimentation process and an increasing portion of the overburden stress is carried
through grain-to-grain contact. he grains of the sediment are packed closer together,
and some of the water is expelled from the pore spaces (Figure 6.2). Under normal
compaction, the pore luid remains in communication with the surface. In this case,
the luid pressure within the pores is normal, meaning that it is approximately equal
to the hydrostatic pressure. his indicates that the pore luid pressure is dependent
on the density of the luid in the pore space and the depth of the pressure. It will be
Formation Pore and Fracture Pressure Estimation
255
Matrix
Pores
Expelled Fluid
Figure 6.2 Water expelled out from the pore space.
Ground surface
Hydrostatic communication
between staked rock layer
D
Interstitial water
Rock grain
Figure 6.3 Normal pore pressure of a water bearing formation system.
independent of the pore size or pore throat geometry. herefore, the pressure of the liquid in the pore space can be measured and plotted against depth as shown in Figure 6.1.
his type of diagram is known as a P-Z diagram. Due to the communication with the
formation and surface, the pore pressure gradient is a straight line as shown in Figure
6.1. he gradient of the line is a representation of the density of the luid. Hence the
density of the luid in the pore space is oten expressed in units of psi/t.
Based on the depositional characteristics of the formation pore space and rock matrix,
pore pressure can be categorized as i) normal pressure, and ii) abnormal pressure
6.2.3.1 Normal Pressure
When formation pore pressure is approximately equal to theoretical hydrostatic pressure for a given vertical depth, the formation pressure is called normal pore pressure.
In terms of pressure gradient, it is deined as the pressure gradient corresponding to
the hydrostatic gradient of a fresh or saline water column. Figure 6.3 shows the normal
pore pressure system in a conventional hydrocarbon formation.
As mentioned above, under normal compaction the pore luid within the pore is
treated as normal pore pressure which can be written at a depth, D as:
D
Pfn
fn
gdD
0
Here
Pfn = normal formation pore pressure
(6.2)
256 Fundamentals of Sustainable Drilling Engineering
fn = formation luid density at normal condition
D = total vertical depth
dD = vertical depth from a reference point (ground surface)
g
= gravitational acceleration
Equation (6.2) is valid based on the assumption that it is given by the weight of a luid
column above, i.e. in analogy to Eq. (6.1). Most of the oilield brines have a dissolved
mineral content which may vary from 0 to over 200,000 ppm. he pore luid density
in case of brine with sea water salinity is in the range 1.03–1.07 g/cm3. So the pore
pressure increase with depth is roughly 0.45 psi/t. However, the hydrostatic gradient
ranges from 0.433 psi/t (pure water) to about 0.50 psi/t. In most geographical areas the
hydrostatic gradient is taken as 0.465 psi/t (assumes 80,000 ppm). In many important
cases, however, the pore pressure deviates from the normal value Pfn . Table 6.2 shows
some typical values of the normal pore pressure gradient for several geographical areas
of world where active drilling operations continue. Note that water densities vary from
region to region. he normal pore pressure must be determined using the proper water
density or pressure gradient.
In ield unit hydrostatic pressure Eq. (6.2) can be written by recalling Eq. (4.34a) as:
Pfn
Here
Pfn
m
D
0.052
m
D
(6.3)
= normal formation pore pressure, psi
= mud weight, ppg
= total vertical depth, t
Table 6.2 Normal formation pressure gradients for several areas of active drilling (Bourgoyne
et al., 1986)
Pressure gradient (psi/t)
Density (g/cm3)
Anadarko Basin
0.433
1.000
California
0.439
1.014
Gulf of Mexico
0.465
1.074
Mackenzie Delta
0.442
1.021
Malaysia
0.442
1.021
North Sea
0.452
1.044
Rocky Mountain
0.436
1.007
West Africa
0.442
1.021
West Texas
0.433
1.000
Formation Pore and Fracture Pressure Estimation
257
Example 6.1: Find out the normal pore pressure at a depth of 5000 t. below sea level.
Assume that the drilling activities will be continued in California area. Also ind out the
mud weight for that area.
Solution:
Given data:
D = total vertical depth = 5,000 t
Gnp = normal pressure gradient for California = 0.439 psi/t (Table 6.2)
Required data:
Pfn = normal pore pressure, psi
m = mud weight, ppg
he normal pore pressure for California area can be estimated as:
Pfn
Gnp D
5000 ft
0.439 psi / ft = 2,195.0 psi
he mud weight can be calculated using Eq. (6.3) as:
Pfn
m
0.052 D
2195 psi
0.052
5000 ft
8.44 ppg
6.2.3.2 Abnormal Pressure
Formation pressure which is smaller or greater than the magnitude of the hydrostatic
pressure of a column of pore luid that reaches from the surface to the vertical depth
of the formation is called abnormal pressure. In short, it is deined as any formation
pressure above or below the hydrostatic gradient, and is called abnormal pressure.
Figure 6.4 shows the development of abnormal pressure in the formation. Due to the
abnormal pressure, the pore luid expels out from the pore space (Figure 6.4).
Figure 6.5 shows the pressure variation with depth of the formation. If the pressure
gradient is higher than the normal pressure gradient, it is called overpressured which
is shown in Figure 6.5a. On the other hand, if the pressure gradient is less than the
normal pressure gradient, it is called underpressured which is shown in Figure 6.5b.
he underpressured formation pressure is also called subnormal pressure. In general,
Matrix
Pores
Figure 6.4 Abnormal pressure development in the formation.
258 Fundamentals of Sustainable Drilling Engineering
Geological
Section
Pore Pressure
Gradient, psi/ft
Depth (ft)
Overpressure (Abnormally
Pressured) Formation
Depth (ft)
Normal Pressure
Gradient = 0.465 psi/ft
Abnormal Pressure
Gradient > 0.465 psi/ft
Normal Pressure
Gradient = 0.465 psi/ft
Pressure
Gauge
Underpressure (Abnormally
Pressured) Formation
Abnormal Pressure
Gradient < 0.465 psi/ft
Underpressure
Overpressure
Pressure (psi)
Pressure (psi)
(a) Overpressure Formation
(b) Underpressure (Subnormal
Pressured) Formation
Figure 6.5 Variation of pressure with showing overpressured and underpressured formation.
Man-made
Undercompacted shale
Massive Shale Section
Isolated Sand Lenses
(a)
Shale
Salt
Diaper
Massive
Shale
Sealing
Fault
(b)
Shale
(c)
DenseCaprock
(d)
Figure 6.6 Diferent formations showing pressure seals.
subnormal pressures are less common and cause fewer problems than overpressures.
Table 6.3 shows the potential reasons for abnormal pressure gradient of the formation.
All abnormal pressures require some means of sealing or trapping the pressure within
the rock body (Figure 6.6). Otherwise, hydrostatic equilibrium back to a normal gradient would eventually be restored. Massive shales provide good pressure seals, however
shales do have some permeability. So, normal pressures will eventually be established
if it is given suicient time. It may take tens of millions of years for a normal pressure
gradient to re-occur. Both types of abnormal pressure as mentioned above are associated with sealing mechanisms. he pressure seal is a zone of low permeability and acts
to trap the pore luids within a formation. It restricts the vertical and lateral movement
of pressure (i.e. evaporation, faults etc.). he seal prevents equalization of the pressures
Formation Pore and Fracture Pressure Estimation
259
Table 6.3 Potential reasons for abnormal
pressure gradient of the formation.
Artesian systems
Structural reasons
Tectonics
Faults
Salt or shale diapirs
Others
Surface erosion
Rock diagenesis
Sulfates
Precipitation
Clays
hermal efects
Osmosis through shale
Biochemical efects
External pressure sources
Natural
Man-made
Undercompacted shale
which occur within the geological sequence. he seal is formed by a permeability barrier resulting from either physical or chemical action. he physical seal may be the
result of a gravity fault during deposition or the deposition of a iner grained material.
he chemical seal may be due to calcium carbonate being deposited, thus restricting
average permeability. Another example might be chemical diagenesis during the compaction of organic material. Both physical and chemical action may occur simultaneously to form a seal (i.e. gypsum-evaporite action).
In normal compaction, water is expelled from the formation pores during the compaction process. If the pore water is trapped, it will be pressurized by the overburden
stress (Figure 6.7). he overburden is now supported by both the grain-to-grain contact
and the luid pressure. his is called under compaction. he pore volume in undercompacted formation also tends to be larger than that in normally compacted formation at
the same depth. As mentioned earlier, when the pore pressure is higher than the normal
hydrostatic pressure, it is referred to as abnormal, and the situation is oten called overpressured. Pore luid may be trapped naturally by the deposition of ine-grained sediment, such as shale on top of the formation.
Like an abnormal pressure gradient, there are many possible causes of abnormal
pressure, which will be discussed later. While drilling in an abnormal pressure zone, the
followings are the signs that indicate this pressure existence in the formation:
•
•
•
•
Normalized drilling rate (Drilling models)
Change in rotary torque
Change in drag
Shale density
260 Fundamentals of Sustainable Drilling Engineering
Overburden stress,
ob = ef + Pp
Efective
stress, ef
Pp
Pore
pressure
Figure 6.7 Relation between overburden stress, pore pressure, and efective stress.
•
•
•
•
Gas analysis
Flow line temperature
Size and shape of cuttings
Open hole logs
From the deinition of abnormal pressure, it can be classiied as underpressured (i.e.
subnormal) or overpressured formation pressures.
1. Underpressured Formation Pressure: Underpressured formation pressure is also
called subnormal formation pressure. As shown in Figure 6.5b, the subnormal pressure is always smaller than the normal formation pore pressure which shows some
very speciic geographical locations on earth. Lost circulation problems and diferential
sticking are common problems in these areas. here are many mechanisms by which
subnormal pressures occur. he major mechanisms such as thermal expansion, formation foreshortening, precipitation, epeirogenic movement, depletion, potentiometric
surface are discussed here.
i) hermal Expansion: As sediment and pore luids are suppressed with the increasing burial depth, the temperature rises. In this case, if the pore luid is allowed to expand,
the density will decrease, which results in a diminution in pressure.
ii) Formation Foreshortening: During a compression process of the formation beds,
there is some bending of strata as shown in Figure 6.8. Due to this action, the upper
bed A will bend upward, while the lower bed C will bend downwards. he intermediate
bed B must expand to ill the void and so create a subnormally pressured zone. his is
assumed to apply to some subnormal formation zones in Indonesia and the USA. It is
noted that this action may also cause overpressures in the top and bottom beds (i.e. Bed
A and Bed C).
iii) Precipitation: In dry areas such as Texas, Middle East, South India, etc., the
water table may be located hundreds of feet below surface. his reduces the hydrostatic
pressure and creates subnormal pressured zones in the formation.
iv) Epeirogenic Movements: A change in elevation can cause abnormal pressures in
formations open to the surface laterally, but otherwise sealed. If the outcrop is raised
Formation Pore and Fracture Pressure Estimation
261
Overpressured
A
Bed A
P
Bed B
Subnormal Pressure
P
P
B
Bed C
C
Overpressure
Figure 6.8 Foreshortening of formation beds (Redrawn from Ford, 1999).
Production
Well
Development
Well
Producing zone
Deeper Prospect
Figure 6.9 Production of oil or gas.
this will cause overpressures (Figure 6.5a), if lowered it will cause subnormal pressures
(Figure 6.5b). However, pressure changes are rarely caused by changes in elevation
alone because associated erosion and deposition are also signiicant. Loss or gain of
water saturated sediments is also important.
v) Depletion: A subnormally pressured zone may occur when hydrocarbons or water
are produced from a capable formation in which no subsidence happens (Figure 6.9).
his is important when drilling development wells through a reservoir where there is a
production for some time. Some pressure gradients in Texas aquifers have been as low
as 0.36 psi/t.
vi) Potentiometric Surface: his mechanism refers to the structural relief of a formation and can result in both subnormal and overpressured zones. he potentiometric
surface is deined by the height to which conined water will rise in wells drilled into
the same aquifer. he potentiometric surface can therefore be thousands of feet above
or below ground level (Figure 6.10).
vii) Faulting: A discontinuity in a rock formation caused by the fracturing of the
earth’s crust can create the fault. here are various causes of fault fractures such as the
movement of “tectonic plates” relative to each other. In oilield terms a fault block is a
compartment of a rock formation surrounded or partly surrounded by faults, which
may have sealed in hydrocarbons separately from the rest of the formation. When there
is a sealing fault that deviates the formation zones downward, subnormal pressured
zones are created (Figure 6.11a and b). Normal faults and thrust faults are the result of
various stress imbalances in the crust and supericial sediments. hey are oten caused
262 Fundamentals of Sustainable Drilling Engineering
Intake Area
Surface
Excess
Pressure
Subnormal
Pressure
Potentiometric Surface
Oil pool A
Reservoir
Rock
ace
Surf
Oil pool B
Discharge
Area
Figure 6.10 Potentiometric surface in connection with the ground surface (Redrawn
from Ford, 1999).
Marker Bed
Marker Bed
PA
PA
Subnormal
Pore
Pressure
PB
A
A
PB
B
Normal
Pore
Pressure
Pressure
may increase
Top of
Transition
Zone
Normal
Pore Pressure
Flow
Abnormal
Gradient
Pore Pressure
B
Sealing Fault
(a) Normal Faulting
(b) Down faulting
Figure 6.11 Subnormal pressures due to faulting.
by, helped by, or linked to overpressure. When moving and dilating, pressures can easily be transferred. his can result in moving luids to a previously lower potential or
bleeding pressure of, returning it back to hydrostatic. Faults are also good lateral seals.
viii) Outcrop Aquifer: Outcrop can be deined as the appearance of a rock formation
at the surface whereas an aquifer is an underground water reservoir contained between
layers of rock, sand or gravel. Figure 6.12 shows a portion of bedrock or other stratum
protruding through the soil level, indicating a fault or some other oil-bearing formation.
In a water-drive ield, the aquifer is the water zone of the reservoir underlying the oil zone.
In reality, the efect of under pressuring is usually very insigniicant. herefore, it
does not have any practical concern. In reality, the largest number of abnormal pressures reported in literature is the overpressures, and not subnormal pressures.
2. Overpressured Formation Pressure: As mentioned earlier, the formations whose
pore pressure is greater than the corresponding normal gradient 0.465 psi/t is called
overpressured. hese pressures can be plotted between the hydrostatic gradient and the
overburden gradient (1 psi/t.) which is also shown in Figure 6.5a. his overpressure
can cause severe drilling problems. Overpressures at diferent geographical locations
worldwide are shown in Table 6.4.
In nature, there are numerous mechanisms that cause such overpressures to develop
in the formation. Some such as formation foreshortening and potentiometric surface
have already been discussed under subnormal pressures in the above section. It is due
Formation Pore and Fracture Pressure Estimation
263
Outcropping aquifer
Outcropping
aquifer
Patm
Patm
(a) Aquifer outcrops below rig
(b) Aquifer
Figure 6.12 Aquifer outcrops below rig.
Table 6.4 Overpressures at diferent geographical locations.
Geographical Location
Pressure Gradient
Gulf Coast
0.8 – 0.9 psi/t.
Iran
0.71 – 0.98 psi/t.
North Sea
0.5 – 0.9 psi/t.
Carpathian Basin
0.8 – 1.1 psi/t.
to the fact that both under and over pressures can occur as a result of these mechanisms. he other mechanisms that cause the overpressured are summarized below.
i) Faulting: It is also called luid charging. In this mechanism, fault may redistribute
sediments, and place permeable zones opposite to impermeable zones. he fault movement is in the upward direction. hus it creates barriers to luid movement (Figure 6.13).
In this case, hydrocarbon from deep or high-pressure reservoir may low into shallower
formation through fractures or other paths. his may also prevent water being expelled
from shale, which will cause high porosity and pressure within that shale under compaction. his is a common cause of abnormal pressure in shallow formations.
ii) Incomplete Sediment Compaction: In the rapid burial of low permeability clays
or shales, there is little time for luids to escape. Under normal conditions the initial
high porosity is decreased as the water is expelled through permeable sand structures
or by slow percolation through the clay/shale itself. If the burial is rapid, however, there
is no time for this process to take place, and the trapped luid will help to support the
overburden.
iii) Massive Rock Salt Deposition: he deposition of salt can occur over wide areas.
Since salt is impermeable to luids, the underlying formations become overpressured.
Abnormal pressures are frequently found in zones directly below a salt layer (Figure
6.6).
iv) Repressuring from Deeper Levels: It is also called luid migration efects. his
is caused by the migration of luid from a high to low pressure zone at shallower depth.
264 Fundamentals of Sustainable Drilling Engineering
Fault or
fracture
Figure 6.13 Fluid charging due to fault or fracture in the formation.
Underground
Blowout
Casing
Leaks
Faulty
Cement Job
(a)
(b)
(c)
Figure 6.14 hree examples of shallow formations being charged with deeper gas.
his may be due to faulting (Figure 6.13), improperly abandoned (Figure 6.14a) or from
a poor casing/cement job (Figure 6.14b and c). When this happens, the shallow formation is said to be charged. As shown in the igures, the low path for this type of luid
migration can be natural or man-made. he danger of repressuring the formation zone
is that the unexpectedly high pressure could cause a kick, since no lithology change
would be apparent. High pressures can occur in shallow sands if they are charged by gas
from lower formations. Sometimes, even if the upward movement of luid is stopped,
considerable time may be required for the pressures in the charged zone to bleed of
and return to normal. his situation is common in old ields.
v) Diferential Density Efects: When the density of the hydrocarbon or other pore
luid in an inclined formation is much lower than the normal luid density, abnormal
pore pressure may develop in the updip region. he common occurrence in inclined
gas reservoirs of this type of abnormal pressure is shown in Figure 6.15. his situation
is encountered frequently when a gas reservoir with a signiicant dip is drilled. Because
of a failure to recognize this potential hazard, blowouts can be occurred in familiar gas
sands previously presented by other wells. However, the magnitude of the abnormal
pressure can be calculated easily by use of the hydrostatic pressure concepts as described
in Chapter 4. A higher mud density is required to drill the gas zone safely near the top
of the structure than is required to drill the zone near the gas/water contact.
vi) Salt Diaperism: his is the upward movement of a low-density salt dome due to
buoyancy, which distributes the normal layering of sediments and produces pressure
Formation Pore and Fracture Pressure Estimation
265
anomalies (Figure 6.16). he salt may also act as an impermeable seal to lateral dewatering of clays. Salt diapirs plastically “low” or extrude into the previously deposited
sediment layers. he resulting compression can result in overpressure.
vii) Phase Changes During Compaction: Sometimes, it is called the diagenesis efect. Minerals may change under increasing pressure i.e. under compaction.
(Example: gypsum + anhydrate + free water). It has been estimated that a 50 t. bed of
gypsum will produce a 24 t. column of water. Conversely anhydrite could be hydrated
at depth to yield gypsum resulting in a 40% increase in rock volume. his diagenesis
is due to the chemical transformation of one rock mineral to another. For example,
at 200 –300°F, montmorillonite can be converted to illite by releasing the interlayer
water (Figure 6.17). he transformation of montmorillonite to illite also releases large
amounts of water (Figure 6.17a). he last water layer in the interlayer space has a much
higher density than that of bulk water. hus, abnormal pore pressure may develop as
this water is released into the pores (Figure 6.17b).
viii) Tectonic Compression: he lateral compression of sediments may result either
in upliting weathered sediments or fracturing/faulting of stronger sediments. hus formations normally compacted at a depth can be raised to a higher level. If the original
pressure is maintained, the uplited formation would be overpressured.
ix) Salt Formation: If there is a salt formation at the underground layer, there would
be normal pressure above the salt formation zone (Figure 6.18). On the other hand, the
pressure at the bottom of the salt layer is oten extremely overpressured.
Gulf of
Mexico
Sea Level
Top of sand structure
GWC
Gas Sand
Figure 6.15 Diferential Density Efects (Redrawn from Bourgoyne et al., 1986).
Isolated san lens
Shaded Sand
Represent Abnormal
Pore Pressure
Far Field Equilibrium
Restored
Salt
Diaper
Figure 6.16 Salt diapirs.
266 Fundamentals of Sustainable Drilling Engineering
Pp
(a) Montmorillonitc – release of
interlayer water at high
temperatures.
(b) lllite – low interlayer water content;
abnormal pressure developed due
to digenesis.
Figure 6.17 Clay diagnosis.
Normally Pressure
Salt
Salt
Pressure at the
bottom of the salt is
often extremely
overpressures
Figure 6.18 Salt formations.
x) Compaction Efects: Compaction is principally a process of mechanical rearrangement. If it applies to shales, which are deposited with a large content of organic
material, they will produce gas as the organic material degrades under compaction
(Figure 6.19). If this gas is not allowed to escape, it will also form salts which will be
precipitated in the pore space, thus helping to reduce porosity and create a seal.
Again pore space is reduced under compaction and pore water expands with the
increasing burial depth and increased temperature. hus, normal formation pressure can
be maintained only if there exists a permeable path to allow the formation water to escape
freely (Figure 16.19). If pore water can escape as quickly as required by the natural compaction rate, the pore pressure will remain at hydrostatic pressure. However, if the water
low path is blocked or severely restricted, the increasing overburden stress will cause
the pressurization of the pore water above hydrostatic pressure. he pore volume also
will remain greater than normal for the given burial depth. herefore, the natural loss of
permeability due to the compaction of ine-grained sediments may create a seal, which
would allow developing abnormal pressures. he compaction rate of the sediments plays
a major role while compaction efects continue. he factors afecting compaction rate
are rate of deposition, tectonic forces, formation permeability, lithology, diagenesis, and
osmosis.
Example 6.2: A gas sand reservoir is shown in Figure 6.15 where the average gas density was measured as 0.65 lbm/gal. Assume that the water-illed portion of the sand is
Formation Pore and Fracture Pressure Estimation
(a) Normal arrangement
267
Expelled luid
(b) Under compaction
Figure 6.19 Rock matrixes and pore spaces arrangement under normal and under compaction.
pressured normally and the gas/water contact is at a depth of 6,000 t. What is the mud
weight that would be required to drill through the top of the sand structure safely at a
depth of 4,500 t.?
Solution:
Given data:
= gas density = 0.65 lbm/gal
g
D gw = total vertical depth of gas/water contact = 6,000 t.
Ds
= total vertical depth of the sand structure = 4,500 t.
Gnp = normal pressure gradient for gulf of Mexico = 0.465 psi/t. (Table 6.2)
Required data:
= mud weight, ppg
m
he normal pressure at a depth of 6,000 t. of gas/water contact can be estimated using
pressure gradient concept as:
Pfn _ GWC
Gnp D
6000 ft
0.465 psi / ft = 2,790.0 psi
Again, the normal pressure at a depth of 4,500 t. where gas sand exists can be estimated
using pressure gradient concept as:
Pfn _ GS
Gnp D
4500 ft
0.465 psi / ft = 2,092.5 psi
However, the pressure in the gas sand at 4,500 t. can also be determined hydrostatic
pressure concept as:
Pfn _ GS
2,790.0 0.052
Pfn _ GWC
0.65 lbm / ft
0.052
g
DGWC DGS
6,000 ft 4,500 ft = 2,739.3 psi
268 Fundamentals of Sustainable Drilling Engineering
his pressure is higher than that calculated based on a normal pressure gradient at
4,500 t. herefore, the minimum mud weight can be calculated using Eq. (6.3) as:
Pfn _ GS
m
0.052 D
2739.3 psi
0.052 4500 ft
11.7 ppg
6.2.4 Overburden Pressures
he pressures discussed in Section 6.2.3 relate entirely to the pressure in the pore space
of the formations. However, it is also important to quantify the vertical stress at any
depth because this pressure will have a signiicant impact on the pressure at which the
borehole will fracture when exposed to high pressures. Vertical stress develops due to
the overburden load (Figure 6.20). It is deined as the combined weight of the formation
matrix and the luids overlying a formation. his vertical stress ultimately introduces
the matrix stress which is deined as the resistance of the formation matrix to compaction expressed in psi or psi/t. he vertical pressure any point in the earth is known
as the overburden pressure or geostatic pressure which is the pressure exerted by the
overburden load upon underlying formations (Figure 6.20). he overburden gradient
is derived from a cross plot of the overburden pressure versus depth which is shown in
Figure 6.21.
Figure 6.22 shows the equilibrium condition of overburden pressure. At equilibrium
condition, the overburden pressure is the sum of vertical matrix stress and the formation pore pressure. Mathematically,
Pob
Here
Pob
v
Pfn
v
Pfn
(6.4)
= overburden pressure
= vertical matrix stress
= normal formation pore pressure
Example 6.3: Calculate the overburden pressure of an underground reservoir if the
matrix stress is 8,500 psi and the formation pore pressure is 5000 psi.
Overburden
Overburden
Pressure
Matrix Stress
Pore Fluid
Pressure
Figure 6.20 Overburden load on formation zone.
Formation Pore and Fracture Pressure Estimation
269
Depth (ft)
Normal pore pressure
Gradient = 0.456 psi/ft
Fracture pressure gradient
Overburden gradient
Pressure (psi)
Figure 6.21 Typical pressure versus depth showing pore pressure gradient, overburden,
and fracture pressure gradient.
Equilibrium
Overburden
Pressure
Matrix Stress
+
Pore Fluid
Pressure
Figure 6.22 Equilibrium condition for rock matrix and formation pore space.
Solution:
Given data:
= vertical matrix stress = 8,500 psi
v
Pfn = normal formation pore pressure = 5,000 psi
Required data:
Pob = overburden pressure = ?
he overburden pressure can be estimated using the Eq. (6.4) as:
Pob
v
Pfn
8,500 psi 5,000 psi 13,000 psi
Due to the compaction efect as mentioned earlier, the overburden pressure depends on
several factors such as rock and luid densities, lithology etc. Table 6.5 shows the typical
matrix and luid densities in general.
he pressure at any point is a function of the mass of the rock and luid above the
point of interest. In order to calculate the overburden pressure at any point, the average
density of the material (rock and luids) above the point of interest must be determined.
he average density of the rock and luid in the pore space is known as the bulk density
of the rock. he bulk density at a given depth can be calculated as:
b
f
r
1
(6.5)
270 Fundamentals of Sustainable Drilling Engineering
Here
b
f
r
= bulk density of porous sediment
= luid density in the pore space
= grain density of rock matrix
= porosity
In an area of signiicant drilling activity, the change in bulk density with depth usually
is determined by conventional well logging methods. Since the lithology and luid content
vary with depth, the bulk density will also vary with depth. he overburden pressure or
gradient is derived from the pressure exerted by the rock above the depth of interest. his
overburden pressure at any point is therefore the integral of the bulk density from surface
down to the point of interest. Table 6.5 shows the typical matrix and luid densities.
In many areas, it is convenient to use the exponential relationship relating change in
average sediment porosity to depth of burial when calculating the overburden stress,
ob , resulting from geostatic load at a given depth. To use this approach, the average
bulk density data are expressed irst in terms of average porosity. hen Eq. (6.5) for
average porosity yields:
r
b
r
f
(6.6)
avg
Equation (6.6) allows average bulk density data read from well logs to be expressed easily in terms of average porosity for any assumed grain density and luid density. If these
average porosity values are plotted against depth on semi-log paper, a good straightline trend usually is obtained (Figure 6.23). he equation of this line is given by:
oe
K Ds
(6.7)
Table 6.5 A list of typical matrix and luid densities.
Type
Substance
Density (gm/cc)
Rock Matrix
Sandstone
2.65
Limestone
2.71
Dolomite
2.87
Anhydrite
2.98
Halite
2.03
Gypsum
2.35
Freshwater
1.0
Fluid
Seawater
1.03 – 1.06
Oil
0.6 – 0.7
Gas
0.15
Formation Pore and Fracture Pressure Estimation
271
0
Sediment depth (D), ft
1000
2000
3000
4000
5000
6000
0.01
1.0
Porosity ( ). %
Figure 6.23 Average porosity variation with sediment depth.
Here
o
K
Ds
= porosity at surface (D = 0)
= porosity decline constant at
= the depth below the surface of the sediments
he constants o and K can be determined graphically or by the least-square method.
he porosity decline constant can be estimated from the Eq. (6.7) by taking ln in
both sides of the equation and solving the same for K as:
ln o
ln
Ds
K
(6.8)
he vertical overburden stress ( ob ) resulting from geostatic load at a depth can be written in terms of bulk density of the system in the same form of Eq. (6.1) as:
D
ob
b
gdD
(6.9)
0
So, the vertical overburden stress resulting from the geostatic load can be expressed in
terms of average sediment porosity at a particular depth. Now substituting Eq. (6.5)
into Eq. (6.9) yields:
D
ob
g
f
r
1
dD
(6.10)
0
Equation (6.10) is valid only for onshore area. However, we can utilize Eq. (6.10) for ofshore area too. In this case the total depth would be in two segments: i) from the surface
to the ocean bottom (i.e. total depth of sea water: 0 to Dsw), and ii) from the mudline
to the depth of interest (i.e. Dsw to D). In this case, Eq. (6.9) can be used for these two
situations. hus b would become seawater density, sw which is equal to 8.5 lbm/gal up
272 Fundamentals of Sustainable Drilling Engineering
to the depth of Dsw and then from sea bed to the depth D would be same as mentioned
in Eq. (6.10). So, Eq. (6.9) can be written as:
D
sw Dsw g
ob
g
r
r
dD
f
(6.11)
Dsw
D
ob
sw
Dsw g g D Dsw
g
r
r
dD
f
(6.12)
Dsw
he variation of with depth D due to overburden stress can be estimated using Eq.
(6.7). herefore, substituting Eq. (6.7) into Eq. (6.12) yields:
D
ob
sw
Dsw g g D Dsw
g
r
r
f
o
e
K D
(6.13)
dD
Dsw
Solving the Eq. (6.13) and applying the limits of the integration, the equation
becomes as:
ob
sw
Dsw g g D Dsw
g
r
r
f
1
e
K
o
K D
e
K Dsw
(6.14)
Let Ds
ob
D Dsw. Substituting this in Eq. (6.14) yields:
gDs
sw Dsw g
gDs
sw Dsw g
ob
ob
g
r
r
o
r
r
f
o
e
K
g
r
r
f
K Dsw
e
K
g
gDs
sw Dsw g
f
o
K
K Dsw
e
K Dsw
e
e
K
K Ds
1 e
e
Ds Dsw
(6.15)
K Dsw
(6.16)
K Ds
(6.17)
In the right hand side of Eq. (6.17), within the range of Dsw, there is no existence of
rock, so r 0 and the porosity becomes 1. herefore, the porosity decline constant will
become zero. As a result, e K Dsw 1. hus, Eq. (6.17) can be written as:
ob
sw
Dsw g
gDs
g
r
r
f
o
K
1 e
K Ds
(6.18)
For onshore area, Eq. (6.18) can be written as:
ob
gDs
g
r
r
f
K
o
1 e
K Ds
(6.19)
Formation Pore and Fracture Pressure Estimation
273
In ield unit, Eqs. (6.18) and (6.19) can be written as:
ob
0.052
sw
Dsw
0.052
ob
r
r
Ds
r
Ds
f
o
K
r
f
o
K
1 e
1 e
K Ds
K Ds
(6.20)
(6.21)
Here
ob
sw
Dsw
r
Ds
f
o
K
= vertical overburden stress, psi
= density of sea water, lbm/gal
= depth from surface to the ocean bottom, t.
= grain density of rock matrix, lbm/gal
= the depth from the sea bed to up to a depth of interest, t.
= density of luid in the pore space, lbm/gal
= porosity at surface (D = 0), fraction
= porosity decline constant at , t.–1
Example 6.4: Determine the porosity decline constant for the North Sea area. It is
noted that an average grain density of 2.55 g/cm3, an average pore luid density of 1.044
g/cm3, and the value for surface porosity of 45% were recorded. Assume the average
bulk density of the sediment is 2.35 g/cm3 at a speciied depth of 9,000 t. Also compute
the vertical overburden stress along the coast line of North Sea at the same depth.
Solution:
Given data:
= average grain density of rock matrix = 2.55 g/cm3
r
= average density of luid in the pore space = 1.044 g/cm3
f
= porosity at surface (D = 0) = 0.45
o
Ds = the depth below the surface of the sediments = 9,000 t.
= bulk density of porous sediment = 2.35 g/cm3
b
Required data:
K
= porosity decline constant at =?
= vertical overburden stress =?
ob
Before calculating the porosity decline constant, we have to calculate the average porosity at the speciied depth by using the Eq. (6.6) as:
r
b
r
f
avg
2.55 2.35
2.55 1.044
0.133
Using Eq. (6.7), K can be calculated as:
o
e
K Ds
0.133 0.45e
K
9000
K
0.000135 ft -1
As long as the vertical overburden stress is along the coast line of North Sea, Eq. (6.19)
can be used if we assume that Dsw = 0. herefore,
274 Fundamentals of Sustainable Drilling Engineering
ob
2.55 gm / cm3
9000 ft
25.4 cm / ft
2.55 gm / cm3 1.044 gm / cm3
0.000135
ft
25.4 cm / ft
1 e
0.000135
ft
25.4 cm/ ft
1
981
981cm / s 2
cm
0.45
s2
1
9000 ft 25.4 cm/ ft
2
= 571854330 gm / cm s – 87971272.6 gm / cm s 2
2
2
= 483,883,057.4 gm / cm s = 483,883,057.4 dynes / cm
= 7,016.3 psi (since 1 dynes/cm2 = 0.0000145 psi)
6.2.5 Pore Pressure Estimation
he estimation of formation pore pressure is an important task in drilling activities.
he formation pore pressure must be estimated during well planning because it afects
directly the mud and casing programs. he accuracy of pore-pressure estimation is
critical to the success of a drilling operation. his pressure is one of the most critical parameters needed by the drilling engineer in planning and drilling a well. In well
planning, the engineer must irst determine whether there is a presence of abnormal
pressures or not (Figure 6.24). If there is an existence of abnormal pressure, it is important to know the depth at which the luid pressure deviates from its normal pressure
or gradient. Finally the magnitude of the pressures must be estimated. However, porepressure prediction and estimation are still an active research area; many diferent
techniques have been proposed to improve the accuracy. here are three general categories applied to detect and/or estimate the abnormal formation pore pressure. he
followings are the categories: i) predictive techniques, ii) detection techniques, and
iii) conirmation techniques.
Normal Pressure Gradients
0'
Depth, ft
West Texas: 0.433 psi/ft
Gulf Coast: 0.465 psi/ft
Abnormal Pressure
Gradients
??
Depth of interest where
abnormal pressure starts
Pore Pressure, psig
Figure 6.24 Presence of abnormal pressure at a certain sediment depth.
Formation Pore and Fracture Pressure Estimation
275
6.2.5.1 Predictive Techniques
he predictive techniques for formation luid pressure estimation are applied before
drilling. he predictive techniques are based on measurements that can be made by
i) geophysical measurements: identify geological conditions which might indicate the
potential for overpressures such as salt domes, ii) analyzing data from wells that have
been drilled in nearby locations (i.e. ofset well data which should be emphasized in
the planning of development wells), iii) seismic data that has been used successfully
to identify transition zones, iv) ofset well histories which may contain information
on mud weights used, problems with stuck pipe, lost circulation or kicks, and v) wire
line logs or mud logging information which is also valuable when attempting to predict overpressures. Geophysical measurements include the shallow and/or deep seismic surveys (i.e. formation velocity), comparison with nearby wells, gravity, magnetic
and electrical prospecting methods. hese geophysical methods are used in the initial
exploration stage. here may also be data from wells drilled in the same area. When
planning development wells, emphasis is placed on data from previous drilling experiences in the area. For wildcat wells, only seismic data may be available.
Most pore pressure prediction techniques rely on measured or inferred porosity. he
shale compaction theory as mentioned earlier is the basis for these predictions. he
procedures for prediction suggest to irst measure the porosity indicator (e.g. density)
in normally pressured, clean shale, to establish a normal trend line. hen if the indicator suggests porosity values that are higher than the trend, then abnormal pressures
are suspected to be present. Finally, the magnitude of the deviation from the normal
trend line is used to quantify the abnormal pressure. he current approach to predicting pore pressure is based on the fact that formations with abnormal pressures tend to
have higher porosities than normally compacted formations. However, the available
literature shows that the prediction techniques are primarily in two folds: i) correlation
of available data from nearby wells, and ii) seismic data.
1. Estimation using Correlations: In 1971, Matthews was the irst person who showed
how to calculate pore pressure from well log data. his strategy utilizes a geologic age
speciic overlay which indicates the normally pressured compaction trendline for the
appropriate geologic age. Ater plotting the observed resistivity/conductivity data on
the geologic age speciic overlay, formation pore pressures can be predicted. A simple
calibration of the data is required to implement this method. he second pore pressure prediction was developed by Ben Eaton. Eaton developed a simple relationship
that predicts the formation pore pressure knowing the normally pressured compaction
trendline, the observed resistivity/conductivity data and a relationship for formation
overburden stress. he two pore pressure prediction techniques require petrophysical
data, speciically formation resistivity or conductivity, to predict pore pressures.
2. Estimation using Seismic Data: Seismic data are more important in the planning
of exploration wells. To estimate formation pore pressure from seismic data, the average acoustic velocity as a function of depth is an important parameter which must be
determined to estimate formation pore pressure using from seismic data. he machine
displays only time which is the reciprocal of velocity. his time is called interval transit
time. he observed interval transit time is a porosity dependent parameter that varies
with porosity according to the following relation:
276 Fundamentals of Sustainable Drilling Engineering
tt
Here
tt
tf
tr
tr 1
tf
(6.22)
= the observed interval transit time, s/t.
= the interval transit time in the pore luid, s/t.
= the interval transit time in rock matrix, s/t.
= porosity
Table 6.6 depicts the interval transit times for common matrix materials and pore
luids. It is noted that pore luid transit times are greater than rock matrices. herefore
the observed transit time in rock increases with increasing porosity.
Sometimes it is useful to use empirical or mathematical models to estimate extrapolated formation pore pressure. hese models are desirable when plotting a porositydependent parameter vs. depth for this purpose specially to extrapolate a normal
pressure trend (observed in shallow sediments) to deeper depths, where the formations are abnormally pressured. Oten a linear, exponential, or power-law relationship
is assumed so that normal pressure trend can be plotted as a straight line on Cartesian,
semilog, or log-log graph paper. However, in some cases, an acceptable straight line
trend is not observed for any of these approaches. As a result a more complex model
must be used. Such complex model can be derived using Eq. (6.7) where normal compaction process exists. Substituting Eq. (6.7) for the into Eq. (6.22) yields:
tt
t f oe
tt
o
K Ds
tr 1
tf
tr e
tt
o
tf
o
e
K Ds
tr
tr
o
tf
K Ds
(6.23)
tr
(6.24)
e
tr
K Ds
(6.25)
Taking ln in both sides of Eq. (6.25) yields:
tr
ln
o
tf
tr
tt
ln
o
tf
tr
K Ds
(6.26)
Equation (6.26) represents the normal pressure relationship of the average observed
sediment travel time and depth. his equation is complicated by the fact that rock matrix
transit time also varies with porosity. his variance is due to the compaction efects on
shale matrix travel time. As shown in Table 6.6, rock matrix transit time for shales can
vary from 167 μs/t. for uncompacted shales to 62 μs/t. for highly compacted shales.
In addition, formation changes with depth also can cause changes in both matrix travel
time and the normal compaction constants o and K . hese problems can be resolved
only if suicient normal pressure data are available.
Formation Pore and Fracture Pressure Estimation
277
Table 6.6 Representative interval transit time times for common matrix materials and pore
luids (Bourgoyne et al., 1986).
Transit Time (10–6, s/t.)
Description
Matrix Material
Dolomite
44
Calcite
46
Limestone
48
Anhydrite
50
Granite
50
Gypsum
53
Quartz
56
Shale
Salt
Sandstone
Pore Fluid
62 – 167
67
53 – 59
Distilled Water
218
100,000 ppm NaCl
208
200,000 ppm NaCl
189
Oil
240
Methane
626*
Air
910*
Note: Valid only near 14.7 psia and 60°F
To describe the prediction method analysis, the following worklow is outlined
below.
i.
ii.
iii.
iv.
v.
Identify, acquire and review ofset well data including:
a. Petrophysical data
b. Drilling records
c. Measured pressure data
Construct pore pressure prediction model using petrophysical data
Include ofset well data in the pore pressure prediction model
Calibrate pore pressure prediction model, if necessary
Analyze the pore pressure prediction model against data obtained from
reviewing drilling records and select or develop an accurate pore pressure prediction model
278 Fundamentals of Sustainable Drilling Engineering
6.2.5.2
Detection Techniques
While drilling a well, the detection techniques are applied to estimate formation luid
pressure. hey are basically used to detect an increase in pressure in the transition zone.
hese are certain drilling response parameters which can be monitored while the well is
being drilled. Any change in these parameters is a signal that a transition zone may have
been penetrated. here are three sources of data which allows the detection of abnormal pressures: i) drilling parameters, ii) drilling mud parameters, iii) drilling cuttings.
Table 6.7 shows the methods for detecting abnormal pressures using these techniques.
1. Drilling Parameters: First drilling parameters as listed in Table 6.7 are observed.
Empirical equations are then applied to produce a term which is dependent on pore
pressure. he theory behind using drilling parameters to detect overpressured zones is
based on facts such as i) compactions of formations increases with depth due to overburden which expedite ROP to decrease with depth provided all other things being
constant, ii) in the transition zone the rock will be more porous (less compacted) than
that in a normally compacted formation. As a result an increase in ROP will occur. In
addition, as drilling proceeds the diferential pressure between the mud hydrostatic and
formation pore pressure in the transition zone will reduce which results a much higher
ROP.
he use of the ROP to detect overpressured zones is a simple concept, but more dificult to apply in practice. his is due to the fact that many other factors afect the ROP
apart from formation pressure. Some additional factors are: i) bit type, ii) bit diameter, iii)
bit nozzle size, iv) bit wear, v) weight on bit, vi) rotary speed, vii) mud type, viii) mud density, ix) efective mud viscosity, x) solids content and size distribution in mud, xi) pump
pressure, and xii) pump rate. Since these other parameters efects cannot be held constant, they must be considered so that a direct relationship between ROP and formation
pressure can be established. his is achieved by applying empirical equations to produce
a “normalized” ROP, which can then be used as a detection tool. he followings correlations are normally used to ind out the formation pressure using detection technique (i.e.
drilling parameters).
i) Bingham Model: Bingham (1964) developed a model to detect overpressures
which is based on a normalised drilling rate equation. He proposed the following generalized equation as a drilling equation.
R
Here
A
db
dexp
E
N
R
W
AN
E
W
db
dexp
= rock matrix strength constant or drillability constant
= bit diameter, in
= bit weight exponent or d-exponent or formation drillability
= rotary speed exponent
= rotary speed, rpm
= rate of penetration or drilling rate, t./hr
= weight on bit, lbf
(6.27)
Formation Pore and Fracture Pressure Estimation
279
Table 6.7 Methods for detecting abnormal pressures by detection techniques (Ford, 1999).
Source of Data
Parameters
Time of Recording
Drilling Parameters
Drilling rate of penetration
While drilling
Delayed by the time
required for mud
return
d, dc exponent
Drilling rate equations
Torque
Drag
Drilling
Drilling Mud Parameter
Gas content
While drilling
Flowline mud weight
Inlux of oil and gas (i.e. kick)
Flowline temperature
Chlorine variation
Drillpipe pressure
Pit volume
Flow rate
Hole ill up
Drill Cuttings
Shale cuttings
Bulk density
Shale factor
While drilling
Delayed by the time
required for sample
return
Electrical resistivity (i.e. Shale
slurry resistivity)
Volume
Shape and size
Novel geochemical
Physical techniques
he model proposed by Bingham [i.e. Eq. (6.27)] is called the “drilling rate” equation.
ii) Jordan and Shirley Model: Jordan and Shirley (1966) reorganised Eq. (6.27) for
dexp . He simpliied this equation by assuming that the rock matrix strength constant
did not change (A = 1) and the rotary speed exponent was equal to one (i.e. E = 1). he
rotary speed exponent has been found experimentally to be very close to one. hese
simpliications helped to remove the variables which were dependent on lithology and
280 Fundamentals of Sustainable Drilling Engineering
rotary speed. his means however that the resulting equation can only be applied to one
type of lithology and theoretically at a single rotary speed. he latter is not too restrictive since the value of E generally close to one. On the basis of these assumptions and
accepting the above mentioned limitations, the following equation is produced using
Eq. (6.27) as:
R
N
W
db
dexp
(6.28)
Taking log into both sides of Eq. (6.28), the equation becomes as:
R
N
W
log
db
log
dexp
(6.29)
A modiied version of Eq. (6.29) can be written as:
log
dexp
R
60 N
12W
log
106 db
(6.30)
he model proposed by Jordan and Shirley [i.e. Eq. (6.30)] is called the “d-exponent”
equation. Since the values of R, N, W, and db are either known or can be measured at
surface the value of the d-exponent can be determined and plotted against depth for the
entire well. However, this equation is not a rigorous solution for the dexp of Eq. (6.27)
because of the above mentioned assumptions suggested by Jordan and Shirley (1966).
Equation (6.30) can be used to detect the transition from normal to abnormal pressure if the drilling luid density is held constant. A detail analysis can be found in their
article. It should be realized that this equation takes into account the variations in the
major drilling parameters. However, to get the accurate results, there are some conditions that should be maintained. hese conditions are: i) no abrupt changes in WOB or
RPM should occur, i.e. keep WOB and RPM as constant as possible, ii) to reduce the
dependence on lithology, the equation should be applied over small depth increments
only, iii) a good thick shale is required to establish a reliable “trend” line.
Example 6.5: Determine the value of the dexp if the drilling rate is 35 t./hr, the rotary
RPM is 100, and the weight on the bit is 60,000 lbf. Assume necessary data. Further
calculate what will happen to dexp if the drilling rate is increased to double of its original
case. Make comments on the result.
Solution:
Given data:
R1 = drilling rate = 35 t./hr
N = rotary speed = 100 rpm
Formation Pore and Fracture Pressure Estimation
W
R2
281
= weight on bit = 60,000 lbf
= drilling rate = 70 t./hr
Assuming:
db = bit diameter = 12.25 in
Required data:
dexp1 = formation drillability = ?
dexp2 = formation drillability = ?
he d-exponent can be calculated by using the Eq. (6.30) as:
R
60 N
12W
log
106 db
log
log
dexp1
35
60 100
12 60,000
log
106 12.25
2.2341
1.2308
1.82
Now, if the rate of penetration is doubled, then d-exponent can also be calculated in the
same fashion as:
R
60 N
12W
log
106 db
log
log
dexp 2
70
60 100
12 60,000
log
106 12.25
1.9330
1.2308
1.57
It is showing that an increase in R resulted in a decrease in dexp . In this case, doubling of
the rate of penetration decreased the modiied d-exponent from 1.82 to 1.57
iii) Rehm and McClendon Model: It can be observed that the mud weight consideration is not taken care by the “d-exponent” Eq. (6.30). Since mud weight determines the
pressure on the bottom of the hole, an increase of the mud weight will increase the chip
hold-down efect which results a decrease in ROP. As a result, Rehm and McClendon
(1971) proposed modifying the d-exponent to correct for the efect of mud density
changes as well as changes in weight on bit, bit diameter, and rotary speed. Ater an
empirical study, they computed a modiied d-exponent correlation as:
dm
dexp
n
(6.31)
e
Here
dm
n
e
= modiied d-exponent
= mud density equivalent to normal pore pressure gradient or normal mud
weight, ppg
= equivalent mud density at the bit while circulating or actual mud weight in
use, ppg
282 Fundamentals of Sustainable Drilling Engineering
Equation (6.31) is oten used for a quantitative estimate of formation pore pressure gradient as well as for the qualitative detection of abnormal formation pressure. Numerous
empirical correlations have been developed in addition to the equivalent matrix stress
concept. Oten these correlations are presented in the form of graphical overlays constructed on a transparent plastic sheet that can be placed directly on dm plot to read the
formation pressure. As recommended by Rehm and McClendon (1971), Figure 6.25
shows the depth vs. dm plot in a Cartesian coordinates for the normal pore pressure,
and abnormal pressure trend line. he procedure for determining pore pressure from
dm can be explained as follows:
•
•
•
•
Calculate dm over 10–30 t. intervals
Plot dm vs depth (use only date from Clean shale sections)
Determine the normal line for the dm vs. depth plot.
Establish where dm deviates from the normal line to determine abnormal
pressure zone
Rehm and McClendon recommend using linear scales for both depth and dm values when constructing a graph to establish formation pore pressure quantitatively
(Figure 6.25). A straight-line normal pressure trend line having intercept with depth
and slope is assumed such that:
dmn
dmo
(6.32)
mD
Here
dmn = value of dm read from the normal pressure trend line at a depth of interest
(Figure 6.26)
dmo = intercept of the normal trend line
m = slop of the normal trend line
D = depth
Abnormal
Pressure
Depth
Normal Pressure
Normal
Compaction
Trend Line
Transition Zone
Overpressure
Zone
dm
Figure 6.25 Depth verses dm plotting in Cartesian coordinates.
Formation Pore and Fracture Pressure Estimation
283
No
Depth (ft)
d
ren
lT
a
rm
Normal
dm
dmn
Abnormal
D
dm
Figure 6.26 Depth verses dm plotting showing dmn on the trendline.
According to the authors, the value of slope m is fairly constant with changes in geologic
age. he modiied “d-exponent” correlation oten is used for estimating the formation
pressure gradient as well as the abnormal formation pressure. Rehm and McClendon
suggested the following empirical equation to calculate the equivalent mud density as:
e
7.56log dmn dm
16.5
(6.33)
Here, e is in lbm/gal
he formation pressure gradient can be written as:
Gf
0.052
e
(6.34)
Here, G f is in psi/t.
he formation pressure can be written as:
Pf
Gf D
(6.35)
Here, Pf is in psi
Example 6.6: For the Malaysian area, determine the value of the dm if the drilling rate
is 30 t./hr, the rotary RPM is 90, and the weight on the bit is 65,000 lbf. In addition, an
equivalent circulating density at the bit was 9.5 lbm/gal. Assume necessary data.
Solution:
Given data:
R
= drilling rate = 30 t./hr
N = rotary speed = 90 rpm
W = weight on bit = 65,000 lb
f
= actual mud weight in use = 9.5 ppg
e
Additional assumption:
db = bit diameter = 12.0 in
Required data:
dm = modiied d-exponent = ?
284 Fundamentals of Sustainable Drilling Engineering
Before inding out the dm, it is necessary to ind out the d-exponent which can be calculated by using the Eq. (6.30) as:
log
R
60 N
log
12W
106 db
dexp
30
60 90
12 65,000
log
106 12.00
log
2.2553
1.9
1.1871
We know that for the Malaysian area, the normal formation pressure gradient is 0.442
psi/t. (Table 6.2). So, the mud density equivalent to normal pore pressure gradient ( n)
can be calculated as:
0.442
0.052
n
8.5 ppg
herefore, the modiied d-exponent can be calculated using Eq. (6.31) as:
dm
n
dexp
1.9
e
8.5
9.5
1.7
iv) Zamora Model: It is noted that Rehm and McClendon mentioned to use linear
scales for plotting depth vs. dm as shown in Figure 6.25. However, Zamora recommends
using a linear scale for the depth but a logarithmic scale for dm values when constructing a graph to estimate formation pore pressure quantitatively (Figure 6.27). A straightline normal pressure trend line having intercept dmo and exponent m is assumed such
that:
dmn
dmoe mD
(6.36)
Zamro reported that the slope of the normal pressure trend line varied only slightly
and without apparent regard to location or geological age. He also introduced another
empirical equation to calculate the formation pressure gradient.
Gf
Gn
dmn
dm
(6.37)
0
lT
d
ren
Depth (ft)
a
rm
No
Normal
10,000
Abnormal
20,000
0.1
1.0
dm
Figure 6.27 Depth verses dm plotting in semi-logarithmic coordinates.
10
Formation Pore and Fracture Pressure Estimation
Here
Gn
285
= normal pressure gradient, lbm/gal
Example 6.7: Figure 6.28 shows the depth vs. d-exponent and modiied d-exponent
plot. Estimate the formation pressure at 13,500 t. using Rehm and McClendon and the
Zamora correlation. Assume that Figure 6.28 is constructed based on gulf of Mexico
data.
Solution:
Given data:
D = depth = 13,500 t.
From Figure 6.28, we can ind out the dmn and dm at a depth of 13,500 t. as:
dm = modiied d-exponent = 1.11
dmn = dm from the normal pressure trend line at a depth of interest = 1.66
Gn = normal pressure gradient = 0.465 lb /gal (Table 6.2)
m
Required data:
Pf = formation pressure = ?
Rehm and McClendon Model:
Before inding out the formation pressure, it is necessary to ind out the equivalent
mud density based on Rehm and McClendon which can be calculated by using the Eq.
(6.33) as:
16.5 7.56log 1.66 1.11
0
0
2000
2000
4000
4000
Normal
Pressure
Trend Line
6000
Depth (ft)
Depth (ft)
6000
8000
10.000
dmod=
1.15+0.0000380
8000
10.000
12,000
12,000
13.500 ft 1.11
14,000
2.0
0.1
Modiied d-Exponent
(d-UNITS)
2.0
1.5
1.0
0.5
0
Modiied d-Exponent
(d-UNITS)
16.5 14.53 ppg
0.4
0.6
0.8
1.0
7.56log dmn dm
0.2
e
1.66
13.500 ft
14,000
16,000
16,000
18,000
18,000
Figure 6.28 Depth verses dexp and dm plotting for Example 6.7.
1.11
1.66
286 Fundamentals of Sustainable Drilling Engineering
he formation pressure gradient can be obtained using Eq. (6.34) as:
0.052
Gf
0.052 14.53 0.756 psi / ft
e
Finally, the formation pressure can be calculated using Eq. (6.35) as:
Pf
0.756 13,500 10,206 psi
Gf D
Zamora Model:
he formation pressure gradient can be obtained directly using Eq. (6.37) as:
Gf
Gn
dmn
dm
1.66
1.11
0.465
0.695 psi / ft
Finally, the formation pressure can be calculated again using Eq. (6.35) as:
Pf
Gf D
0.695 13,500
9,382.5 psi
v) Eaton Model: he d-exponent is generally used to simply identify the top of the
overpressured zone. he value of the formation pressure can however be derived from
the modiied d-exponent, using the method proposed by Eaton (1976) as:
Pf
ob
ob
Pf
D
D
D
D
dmc
dmn
n
1.2
(6.38)
Here
= overburden stress (i.e.
ob
Pf
ob
Ppn), psi
= overburden stress gradient, psi/t.
D
Pf
dmc
dmn
v
= formation pressure gradient, psi/t.
D
D
ob
= normal pressure gradient, psi/t.
n
= calculated modiied d-exponent at a given depth
= modiied d-exponent from normal trend (i.e. extrapolated) at a given
depth (Figure 6.26)
Eaton claims the relationship is applicable worldwide and is accurate to 0.5 ppg.
Example 6.8: What is the pore pressure at the point indicated on the Figure 6.29.
Assume a Gulf Coast area where the depth is 10,000 t. Also assume that the overburden stress gradient is 0.95 psi/t. and normal formation pressure gradient is 0.465 psi/t.
Use the Eaton Equation. Find out the EMW of the formation too.
Solution:
Given data:
D
= depth of the formation = 10,000t.
Depth (ft)
Formation Pore and Fracture Pressure Estimation
0.25
Robs
end
al Tr
10,000'
Norm
Transition
dmc
Rn
0.5
287
1
dmn
2
3
Figure 6.29 Depth verses Robs and Rn plotting for Example 6.8.
= overburden stress gradient = 0.95 psi/t.
ob
D
Pf
D
= normal pressure gradient = 0.456 psi/t.
n
Required data:
= formation pore pressure at a depth of 10,000 t., psi
Pf
From Figure 6.29, we can ind out the Robs and Rn at a depth of 10,000 t. as:
Robs = observed shale resistivity of the formation = 0.8 ohms-m
Rn = resistivity of the formation at a normal trend = 1.55 ohms-m
he Eaton model can be expressed in terms of resistivity of the formation which is
analogous with d-exponent as:
Pf
D
0.95
Pf
ob
ob
Pf
D
D
D
D
0.95 0.456
0.80
1.55
n
1.2
Robs
Rn
1.2
0.726624 psi / ft
herefore,
Pf
0.726624 D 0.726624 10000
7266.24 psi
he equivalent mud weight (EMW) can be calculated as (Eq. 4.36a):
EMW
Pf
0.052 D
7266.24
0.052 10000
13.97 lbm / gal
288 Fundamentals of Sustainable Drilling Engineering
0
Depth (ft)
2000
Surface Casing
4000
2,500'
Mud weight gradient,
0.52 psi/ft
6000
Fracture gradient,
0.73 psi/ft
8000
14000
12000
10000
8000
6000
4000
2000
0
10000
Pressure, psi
Figure 6.30 Casing set and pressure gradient for Example 6.9.
Example 6.9: he mud engineer of an Arabian oil company designed the mud weight
of 10 lbm/gal for a formation that needed to be drilled where the pressure gradient was
found 0.52 psi/t. he surface casing was set at a depth of 2,500 t. It was noticed that
the fracture gradient below the surface casing was 0.73 psi/t. he driller realized that
he was passing a pressure transition zone while drilling at a depth of 10,000 t. his new
situation gave the impression that the designed mud weight might be less than pore
pressure which results a kick. To avoid a kick, determine the maximum safe underbalance between mud weight and pore pressure if the well kicks from formation at a depth
of 10,000 t.
Solution:
Given data:
D
= total vertical depth = 10,000 t.
=
mud weight = 10 ppg
m
= normal pressure gradient = 0.52 psi/t.
Gnp
D
= depth at which surface casing is set = 2,500 t.
= fracture pressure gradient = 0.73 psi/t.
Gfp
Required data:
EMWmax = maximum safe underbalance mud weight, ppg
Figure 6.30 shows the casing seat and pressure gradient where an elaboration is
explained for this example. In general, when a well kicks, the well is shut in and the
wellbore pressure increases until the new BHP equals the new formation pressure.
At that point, the influx of formation fluids into the wellbore ceases. Since the mud
gradient in the wellbore has not changed, the pressure increases uniformly everywhere (Figure 6.31).
Formation Pore and Fracture Pressure Estimation
289
0
2000
Casing seat at 2,500'
525 psi
2,500'
1,825 psi
6000
8000
After kick and
stabilization
1,300 psi
Depth (ft)
4000
Before
kick
5,200 psi
5,725 psi
10000
Kick at 10,000'
14000
12000
10000
8000
6000
4000
2000
0
P, 525
Pressure, psi
Figure 6.31 wellbore pressures at diferent depth for Example 6.9.
At 2,500t.
he initial mud pressure can be estimated as:
Pim
Gnp D
0.52 psi / ft
2,500 ft = 1,300 psi
he fracture pressure can also be estimated as:
Pfp
G fp D
0.73 psi / ft
2,500 ft = 1,825 psi
herefore, the maximum allowable increase in pressure = (1,825 – 1,300) = 525 psi
At 10,000 t.
Since the pressure increases uniformly everywhere as shown in Figure 6.31, the
maximum allowable increase in pressure at a depth of 10,000 t. will be 525 psi. his
increase in pressure corresponds to an increase in mud weight which can be calculated
using Eq. (4.36a) as:
EMWmax
525
0.052 10000
1.01 lbm / gal
his increase in EMW is the maximum which is the kick tolerance for a small kick.
vi) Combs Model: In 1968, Combs presented a general equation for penetration rate.
He attempted to improve on the use of the drilling rate for pore pressure by correcting for hydraulics, diferential pressure, bit wear and in addition to W, db, and N. He
assumed that the penetration rate is proportional to weight on bit, rotary speed, and bit
hydraulics, each released to a ixed power as shown below:
290 Fundamentals of Sustainable Drilling Engineering
R
Here
f
q
R
W
aW
aN
aq
dh
dn
Pd
Rd
tN
f Pd
f tN
Rd
W
3,500 dh
aW
N
200
aN
q
96 dh dn
aq
f Pd f t N
(6.39)
= function of
= luid circulation rate, gpm
= shale drillability or rate of penetration, t./hr
= weight on bit, lbf
= bit weight exponent (= 1.0 for ofshore Louisiana)
= rotating speed exponent (= 0.6 for ofshore Louisiana)
= low rate exponent (= 0.3 for ofshore Louisiana)
= borehole diameter, in
= diameter of one bit nozzle, in
= diferential pressure, lbf/gal/1000t.
= shale drillability at zero diferential pressure, t./hr
= bit wear index (equivalent to rotating hours),
= function related to diferential pressure
= function related to bit wear
vii) Other Drilling Parameters: Torque is one of the other parameters that might be
suitable to identify overpressured zones. An increase in torque may reduce overbalance
which results in the physical breakdown of the borehole wall. his breakdown of the
wall will generate more material, and then the drilled cuttings. hese excess materials
will accumulate in the annulus and thus there is a change in torque. here are also the
propositions that borehole walls may squeeze into the open hole as a result of the reduction in diferential pressure. Drag may also increase as a result of these efects, although
increases in drag are more diicult to identify.
2. Drilling Mud Parameters: An overpressured zone on the mud can be identiied by
monitoring the efect of diferent drilling mud parameters (Table 6.7). he main efects
due to abnormal pressures will be i) increasing gas cutting of mud, ii) decrease in mud
weight, and iii) increase in low-line temperature. Since all these efects can only be
measured when the mud is returned to the surface they involve a time lag of several
hours in the detection of the overpressured zone. As a result, during the time it takes
to circulate bottoms up, the bit could have penetrated quite far into an overpressured
zone.
i) Gas Cutting of Mud: Gas cutting of mud may happen in two ways: i) from shale
cutting – if gas is present in the shale which is being drilled the gas may be released in
the annulus from the cuttings, ii) direct inlux – this can happen if the overbalance is
reduced too much, or due to swabbing when pulling back the drillstring at connections.
Continuous gas monitoring of the mud is done by the mudlogger using gas chromatography. A degasser is usually installed as part of the mud processing equipment so that
entrained gas is not re-cycled downhole or allowed to build up in the mud pits.
ii) Mud Weight: he mud weight measured at the lowline will be inluenced by
an inlux of formation luids. he presence of gas is readily identiied due to the large
Formation Pore and Fracture Pressure Estimation
291
decrease in density, but a water inlux is more diicult to identify and isolate. Continuous
measurement of mud weight may be done by using a radioactive densometer.
iii) Flow-Line Temperature: he clays that are under compaction with relatively
high luid content have higher temperature than other formations. By monitoring
the lowline temperature, a slow increase in temperature will be observed when drilling through normally pressured zones. In this case, if there is an overpressured zone
encountered, temperature will rise rapidly as drilling through the overpressured zone
itself (Figure 6.32). herefore, lowline temperatures should be monitored carefully on
a continuous basis. he normal geothermal gradient is about 1°F/100 t. and has been
detected when drilling overpressured zones. It is also reported that changes in lowline
temperature up to 10°F/100t. have been detected when drilling overpressured zones.
When using this method we should keep in mind that other efects such as circulation
rate, mud mixing, etc. may inluence the mud temperature too.
iv) Pit Level and Total Pit Volume: Figure 5.12 shows the arrangement of a pit volume indicator where it indicates the increase in pit volume due to abnormal pressure.
he functions are discussed in Section 5.3.1. he pit level indicators monitor variations
in the total mud volume. It may show mud-volume reduction due to lost circulation.
he pit level may also increase because of the luid entry into the wellbore as a result of
unexpected high formation pressures. Ultrasonic equipment is used to measure accurately the levels of drilling luid in mud tanks. his method is useful on loating, deepwater ofshore drilling rigs.
v) Mud Flow Rate: Pit level volume indicator takes some time to detect the abnormal pressure zone. herefore, low rate measurements are used to detect abnormality
which is superior to pit level checks. his is due to the fact that even small low scan
be detected before they become suiciently large to show on any pit level measuring
device. herefore more time is available to take proper control measures.
vi) Hole Fill-up: If the drillstring is pulled from the borehole, the mud volume
needed to ill the same should be equal to the displaced pipe volume. It is very critical to
keep the hole full at the time when drill collars are pulled because on pulling the same
length of collars as that of the drillpipe, the level of drilling mud in the borehole will fall
four to ive times faster than the drillpipe. In addition, if there is an unexpected luid
entry (i.e. salt water, oil, or gas) from the formation into the wellbore, the mud volume
required to ill the borehole will be less than the displaced volume of the pipe pulled
out. hus, the irst indication of a pressure kick will be notiied.
Depth (ft)
0’
Normal Trend
Top
Overpressure
Flowline Temperature (°F)
Figure 6.32 Flowline temperature distributions with depth to detect overpressure.
292 Fundamentals of Sustainable Drilling Engineering
3. Drilling Cuttings: his detection method examines the cuttings, trying to identify
cuttings from the sealing zone (Table 6.7). Since overpressured zones are associated
with under-compacted shales with high luid content, these detection methods are
aimed at determining the degree of compaction as measured from the cuttings. he
methods commonly used are: a) density of shale cuttings, b) shale factor, and c) shale
slurry resistivity (Table 6.7). he shape and size of the cuttings may give an indication
(large cuttings due to low pressure diferential). As with the drilling mud parameters,
these tests can only be done ater a lag time of some hours.
i) Density of Shale Cuttings: In normally pressured formations the compaction and
therefore the bulk density of shales should increase uniformly with depth (given constant
lithology). If the bulk density decreases, this may indicate an undercompacted zone which
may be an overpressured zone. he bulk density of shale cuttings can be determined by
using a mud balance (Figure 3.6). A sample of shale cuttings must irst be washed and sieved
to move caving. he cuttings are then placed in the cup of the mud balance so that the density indicated by the balance is equal to the density of water (i.e. 8.3 ppg) which is equivalent
to a full cup of water. hus the mass of the shale cuttings in the balance is equal to the mass
of a volume of water equal to the total cup volume of the balance. At this point, the following
relation can be used:
Vs
bs
Here
Vs
Vt
bs
w
w
Vt
(6.40)
= volume of shale cutting, t.3
= total volume of cup, t.3
= bulk density of shale, lbm/t.3
= density of water, lbm/t.3
When enough shale cuttings is added to obtain a balance with the mud cup on and
when the rider indicated the density of water, fresh water is added to ill the cup. he
mixture is agitated to remove any air existence. he mud cup then is replaced and the
average density ( m) of the cuttings/water mixture is determined. At this point Eq.
(6.40) should be written as:
V
Vs
m t
bs
w
Substituting Vs from Eq. (6.40) into Eq. (6.41) and then solving for
2
w
bs
2
w
(6.41)
Vt Vs
bs
will give as:
(6.42)
m
A number of such samples should be taken at each depth to check the density calculated as above and so improve the accuracy. he density at each depth can then be plotted as shown in Figure 6.33 to detect the overpressured zone.
As we mentioned earlier, the bulk density of porous sediments depends on porosity, shale density is also a porosity dependent parameter, which is oten plotted against
Formation Pore and Fracture Pressure Estimation
293
Depth (ft)
0’
Normal Trend
Top
Overpressure
Bulk density
Figure 6.33 Bulk density variations with depth to detect overpressured zone.
depth to estimate formation pressure. A mathematical model of the normal compaction trend for the bulk density of shale cuttings can be developed by using Eq. (6.5) as:
bsn
r
r
(6.43)
f
Now, substituting Eq. (6.7) into Eq. (6.43) for porosity variation will give:
bsn
r
r
f
o
e
K Ds
(6.44)
Here
bsn
= shale density for normally pressured shales
he grain density of pure shale is 2.65 g/cm3. he average pore luid density can be
obtained from Table 6.2. Constants o , and K can be based on shale-cutting bulk density measurements made in the normally pressured formations.
ii) Shale Formation Factor: his technique measures the reactive clay content in the
cuttings. It uses the “methylene blue” dye test to determine the reactive montmorillonite clay present, and thus indicate the degree of compaction. he higher the montmorillonite, the lighter the density, which indicates under compacted shale. Montmorillonite
will absorb methylene blue and change its color. Shale factor method may be compared
with the cation exchange capacity of solids carried by the drilling luid out of the wellbore. It can be related to the water-holding capacity of drill cuttings or montmorillonite
content. he shale factor also appears to be a supplementary and useful indicator to
detect the cap rocks on top of the overpressured zones.
iii) Shale Slurry Resistivity: As compaction increases with depth, water is expelled
and so conductivity is reduced. A plot of resistivity against depth should show a uniform
increase in resistivity, unless an undercompacted zone occurs where the resistivity will
reduce (Figure 6.34). To measure the resistivity of shale cuttings a known quantity of dried
shale is mixed with a known volume of distilled water. he resistivity can then be measured
and plotted.
iv) Shape and Size of Shale Cuttings: he shape of drill cuttings is round in the
normal hydrostatic pressure environments. On the other hand, the shape is angular and
294 Fundamentals of Sustainable Drilling Engineering
Depth (ft)
0’
Normal Trend
Top
Overpressure
Resistivity
Figure 6.34 Resistivity variations with depth to detect overpressured zone.
sharp while encountering the pressure transition zones. Moreover, cuttings from highpressure formations are unusually large and splintery in appearance.
v) Volume of Shale Cuttings: While drilling, entry into an overpressured zone is
characterized by an increase in the penetration rate. his gives rise to an increase in
volume of cuttings over the shale shaker.
6.2.5.3
Conirmation Techniques
he conformation techniques for formation luid pressure estimation are applied ater
drilling. Table 6.8 shows diferent parameters that are applied ater drilling to conirm
the abnormal pressure existence in the formation. Once the hole has been successfully
drilled certain electric wireline logs and pressure survey may be run to conirm the
presence of overpressures. he logs that are partially sensitive to under compaction are:
a) sonic log, b) density log, and c) neutron logs. However, there are some other logs
such as resistivity log, and conductivity log are used in this regard.
6.2.6 Fracture Pressure
In the planning of the mud program, it is useful to know the maximum mud weight
which can be used at any particular depth. his maximum weight is deined by the
fracture gradient which can be deined as the minimum total in situ stress divided by
the depth. he mud weight used in the well must lie between the formation pressure
gradient and the fracture gradient. Knowledge of the fracture gradient is vital when
drilling through an overpressured zone. he fracture pressure can be deined as the
pressure required inducing fractures in rock at a given depth. It is the pressure above
which injection of luids will cause the rock formation to fracture hydraulically. he
factor used to determine formation fracturing pressure as a function of well depth is
in units of psi/t. he orientation of the produced fracture depends on the orientation
of the principal stress of the fracture point. At any point in the formation there exists a
stress regime consisting of three perpendicular stresses as shown in Figure 6.35. If we
consider that 1 as maximum, 2 as intermediate, and 3 as minimum, the fracture will
be developed perpendicular to the minimum stress (Figure 6.36). To initiate a fracture in the wall of the borehole, the pressure in the borehole must be greater than the
least principal stress in the formation. To propagate the fracture, the pressure must be
Formation Pore and Fracture Pressure Estimation
295
Table 6.8 Methods for detecting abnormal pressures by conirmation techniques (Ford, 1999).
Source of Data
Parameters
Time of Recording
Electrical survey
Ater drilling
Resistivity
Conductivity
Shale formation factor
Salinity variations
Well Logging
Interval transit time, bulk density,
hydrogen index
hermal neutron cam capture cross
section
Nuclear Magnetic Resonance
Downhole gravity data
Pressure bombs
Direct Pressure
Measuring Devices
When well is tested or
completed
Drillstem test
Wire line formation test
2
1
3
Figure 6.35 Stress regime distributions in three plan of a block.
1
3
2
Figure 6.36 Fracture development perpendiculars to the minimum stress.
296 Fundamentals of Sustainable Drilling Engineering
maintained at a level greater than the least principal stress. Formation fracture gradient
study is important because it – i) helps in selecting the casing seats, ii) helps to prevent the lost circulation, iii) helps in planning the hydraulic fracturing, and iv) helps in
selecting the production/injection areas. he Factors that afect fracture gradient are:
i) type of rock, ii) degree of anisotropy, iii) formation pore pressure, iv) magnitude of
overburden, and v) degree of tectonics action in the area.
6.2.7 Methods for Estimating Fracture Pressure
here are two methods that are available for determining fracture pressure gradient.
hese include i) direct method, and ii) indirect method. he direct method depends
on the determination of the pressure required for fracturing the rock and the pressure
required to propagate the resulting fracture. he indirect method is based on theoretical background and uses stress analysis to predict fracture gradient.
6.2.7.1
Direct Method
Direct method is a technique where mud is used to pressurize the well until the formation fractures. he value of the surface pressure at fracture is noted and is added to the
hydrostatic pressure of mud inside the hole to determine the total pressure required to
fracture the formation. his pressure is commonly called formation breakdown pressure. Formation breakdown pressure is determined by a pressure test that is called the
leak-of test (Figure 6.37). It represents an experimental approach to determine the
fracture gradient.
Ater each casing string is cemented in place, the leak-of test (LOT) or pressure integrity testing (PIT) is used to verify the casing, cement, and formations below the casing
seat. It also tests how these parameters can withstand the wellbore pressure required to
drill safely to the next depth at which casing will be set. he major functions of LOT
are i) estimate the formation fracture gradient just below the casing seat, and ii) check
cement bond. hese tests are normally performed at the start of each new hole section,
just ater drilling out of a casing shoe of the previous hole section. his means that the
test can be made in the open hole section below the surface or intermediate casing. he
general procedure is as follows: i) drill out cement and casing shoe to approximately 10
t. into formation (i.e. 5 – 10 t. below the casing shoe), ii) close the BOP at the surface,
iii) circulate to clean hole and stabilize drilling-luid density, iv) close well and pump in
drilling luid (approximately 0.25 to 1 bbl/min), and v) monitor surface pressure.
Figure 6.38 shows leak-of test results taken ater drilling the irst sand below the casing seat. During the test, there is a constant pressure increase for each incremental drilling luid volume pumped. So the early test results fall on a relatively straight line. he
straight line trend continues until point A, where the formation grains start to move
apart and the formation begins to take a whole mud. he pressure at point A is called
the leak-of pressure and is used to compute the formation fracture gradient. Pumping
is continued during the leak-of test long enough to ensure that fracture pressure has
been reached. At point B, the pump is stopped, and the well let shut in order to observe
the rate of pressure decline. he rate of pressure decline is indicative of the rate at which
mud or mud iltrate is being lost.
Surface Pressure
Formation Pore and Fracture Pressure Estimation
Leak-of
pressure
A
297
Formation
breakdown pressure
B
Propagation pressure
C
D
E
Shut-in pressure
0
0
Time
Increment of mud pumped in
Figure 6.37 Leak-of test.
Pump stopped
3000
Pressure (psi)
B
A
SPfrac
2000
1000
0
2
4
6
Volume pumped
(bbl)
2
4 6
Time
(min)
Figure 6.38 Leak-of test results taken ater drilling the irst sand below the casing seat.
he predicted surface leak-of pressure is based on the formation fracture pressure
predicted by one of the empirical correlations presented in the next section. he predicted surface leak-of pressure is given by:
Plo
Pfp 0.052
m
D
Pf
(6.45)
Here
Plo
Pfp
= surface leak-of pressure, psi
= observed fracture pressure, psi
= mud density, lbm/t.3
m
D = total depth, t.
Pf = friction pressure loss, psi
Frictional pressure loss can be calculated using the gel strength as:
Pf
g
D
300 d
Here
g
D
d
= gel strength, lbm/100t.2
= total depth, t.
= inner diameter of the drill pipe, in
(6.46)
298 Fundamentals of Sustainable Drilling Engineering
6.2.7.2
Indirect Methods
Estimations of formation fracture pressures and gradients are based on theoretical and
empirical correlations. In literature, a number of theoretical and ield-developed correlations are reported to approximate fracture gradients. hese correlations are established
using stress analysis for predicting the fracture gradient. Many of these correlations
are suitable for immediate application in a particular geologic area. However, it is an
observation approach based on density (or other) logging measurements taken ater
the well been drilled. In general, the fracture gradient is a function of pore pressure,
pore pressure gradient, overburden gradient, and stress rate. Calculation procedures
for these areas rely on either a history of the ield or geological structure, or on ield
determinations utilizing leak-of tests or logging methods. he following equations and
correlations are commonly used to determine the fracture pressure theoretically.
i) Hubbert and Willis Model: In 1957, they proposed a method for calculating fracture gradients based on the fact that fracturing occurs when the applied luid pressure exceeds the sum of minimum efective stress and formation pressure. he efective
stress is deined as the diference between the total stress and pore pressure. he fracture plane is assumed to be perpendicular to the minimum principle stress. he below
equation is used to determine the fracture pressure.
Pfp
Pf
min
(6.47)
Here
Pfp = observed fracture pressure at the point of interest, psi
min = minimum efective stress at the point of interest, psi
Pf = formation pore pressure at the point of interest, psi
he failure of the material of porous media is controlled by the magnitude of the efective stress only and not the total stress. In this method, the fracture pressure is controlled by overburden stress gradient, formation pore pressure gradient and Poisson’s
ratio of rocks. Hubbert and Willis method was found not applicable in sot rocks.
In calculating the fracture gradient, Hubbert and Willis explored the variables
involved in initiating a fracture in formation. According to them, the fracture gradient
is a function of overburden stress, formation pressure, and a relationship between the
horizontal and vertical stresses. hey believed this stress relationship to be in the range
of 1/3 to 1/2 of the total overburden. herefore the fracture gradient determination
would be as follows:
G fr _ min
1
3
G fr _ max
1
2
min
D
2 Pf
D
min
Pf
D
D
Here
G fr
Pfp
D
= fracture pressure gradient at the point of interest, psi/t.
(6.48a)
(6.48b)
Formation Pore and Fracture Pressure Estimation
min
D
Gp
D
299
= minimum efective stress gradient at the point of interest, psi/t.
Pf
=
= formation pore pressure gradient at the point of interest, psi/t.
D
= depth, t.
If an overburden stress gradient or minimum efective stress gradient is assumed to be
1 psi/t., Eq. (6.48) becomes as:
G fr _ min
2 Pf
1
1
D
3
Pf
1
1
2
G fr _ max
(6.49a)
(6.49b)
D
he above procedures can be done in a graphical form for a quick solution. Let’s assume
a mud weight (example – 12.0 lb/gal) value required to balance the formation and enter it
to the ordinate (Figure 6.39). Applying this value draws a horizontal line along the pressure gradient up to the limit of the intersection of formation pressure gradient line and
constructs a vertical line from this point to the minimum and maximum fracture gradients. Read the fracture mud weight from the ordinate. It is shown that the fracture mud
weight for a 12.0-lb/gal equivalent formation pressure could range from 14.4 to 15. In
Eqs. (6.48 – 6.49), Hubbert and Willis assumed that the stress relationships and the overburden gradients were constant for all depths. Since this has been proven untrue in most
19
Minimum and maximum
fracture and mud weight,
lb/gal
um
g
fp
t
0.7
M
in
im
Por
um
ep
fp
res
g0
sur
eg
.73
rad
ps
ien
i/
t
Pore and Fracture Pressure, lb/gal
17
i/f
s
3p
ft
18
im
M
16
15
14
13
ax
12
11
Pore pressure
10
9
0.4
0.5
0.6
0.7
0.8
0.9
Pressure Gradient, psi/ft
1.0
Figure 6.39 Graphical determination of fracture gradients as proposed by Hubbert and Willis.
300 Fundamentals of Sustainable Drilling Engineering
cases, subsequent methods have attempted to account for one or both of these variables
more accurately.
ii) Matthews and Kelly Model: Matthews and Kelly (1967) published a fracture gradient relationship which difers from the Hubbert and Willis model. hey noticed based
on drilling experience that the formation fracture gradients increase with depth, even
in normally pressured formations. herefore, the following correlation was introduced.
min
Here
F
z
ob
F
z
(6.50)
= variable matrix stress coeicient for the depth at which the value of
be normal matrix stress, dimensionless
= matrix stress = ob Pf , psi
= overburden pressure, psi
z
would
Substituting the Eq. (6.50) into Eq. (6.47), fracture pressure can be obtained as:
Pfp
F
z
Pf
(6.51)
In Eq. (6.51), the variable matrix stress coeicient is a monotonic function of depth to
represent formation properties. his coeicient relates the actual matrix stress conditions of the formation to the conditions of matrix stress if the formation were compacted normally. For simplicity, the authors assumed an overburden pressure gradient
equal to 1.0 psi/t. and a pore pressure gradient equal to 0.465 psi/t. In their work, the
authors concluded that the fracture pressure was higher than pore pressure due to rock
matrix cohesive force, which can be interpreted as rock stress that changes with the
compaction degree. he cohesiveness of the rock matrix is usually related to the matrix
stress. It varies only with the degree of compaction.
Example 6.10: Calculate the minimum and maximum equivalent mud weights in ppg
that can be used immediately below the casing seat at a depth of 12,000 for the pore
pressure gradient of 0.58 psi/t. and an overburden gradient of 0.95 psi/t. It is assumed
that matrix stress coeicient is 0.712. Use the Mathews and Kelly method.
Solution:
Given data:
D
= total vertical depth = 12,000 t.
=
mud weight = 10 ppg
m
= pore pressure gradient = 0.58psi/t.
Gp
= overburden gradient = 0.95 psi/t.
Go
F
= variable matrix stress coeicient = 0.712
Required data:
EMWmin = maximum equivalent mud weight, ppg
EMWmax = maximum equivalent mud weight, ppg
he overburden pressure at a depth of 12,000 t. = 0.95 12,000 = 11,400 psi
Formation Pore and Fracture Pressure Estimation
301
he pore pressure at a depth of 12,000 t. = 0.58 12,000 = 6,960 psi
Using Mathews and Kelly method, the minimum stress can be calculated by Eq.
(6.50) as:
min
F
z
0.712
11400 6960
4, 440 psi
he fracture pressure can be obtained using Eq. (6.51) as:
Pfp
4440 6960 11, 400 psi
herefore, maximum equivalent mud weight which can be calculated using Eq. (4.36a)
as:
EMWmax
11400
0.052 12000
18.27 lbm / gal
And the minimum equivalent mud weight can be calculated as:
EMWmin
6960
0.052 12000
11.15 lbm / gal
Equation (6.51) can be expressed in terms of fracture gradient. Matthews and Kelly
developed the following equation for calculating fracture gradients in the sedimentary
formations as:
G fr
F z
D
Pf
D
(6.52)
hey believed that the conditions necessary for fracturing the formation would be
similar to those for the normally compacted formation. hey also believed that the
coeicient would vary with diferent geological conditions. F can be obtained by substituting actual ield data of breakdown pressures into the above equation and solving
the same for F . Matthews and Kelly have developed the variation of stress coeicient
with depth for south Texas gulf coast and Louisiana gulf coast (Figure 6.40). he igure
shows a nonlinear trend for the stress coeicient vs. depth correlation. he procedure
for calculating fracture gradients using the Matthews and Kelly technique can be summarized as follows:
1. Obtain formation luid pressure (Pf ). his can be measured by drill stem
tests, kick data, logs, or another satisfactory method.
Pf for the depth, D
2. Obtain the matrix stress ( z) by using z
ob
and assuming a gradient of 1.0 psi/t. for the overburden.
3. Determine the depth, Di , for which the matrix stress, z, would be the
normal value. Assume that the overburden pressure gradient is 1.0 psi/t.
and 0.465 psi/t. as pore pressure gradient, i.e. 0.535 Di
z . From the
relationship, the value of Di can be found.
4. Use the value of Di , apply it to Figure 6.40 to obtain the corresponding
value of F .
5. Finally calculate the formation fracture gradient (G f ) by using Eq. (6.52).
302 Fundamentals of Sustainable Drilling Engineering
0
Matrix stress coeicient
Versus D1 for
South Texas Gulf Coast
and
Louisiana Gulf Coast
2
4
South Texas
Gulf Coast
Depth × 1,000 ft
6
8
Louisiana
Gulf Coast
10
12
14
16
18
20
0.3
0.4
0.5
0.6
0.7
0.8
0.9
1.0
F
Figure 6.40 variations of matrix stress coeicients with depth for Matthews and Kelly
model.
Example 6.11: A well of 12,500 t. was drilled at Louisiana Gulf Coast area where the
pore pressure gradient was found 0.695 psi/t. Calculate the fracture gradient in units
of psi/t. and lbm/gal using Matthews and Kelly model.
Solution:
Given data:
D = total vertical depth = 12,500 t.
Pf
Gp =
= pore pressure gradient = 0.695 psi/t.
D
Required data:
Pfp
= fracture pressure gradient in psi/t.
Gfr =
D
Pfp
= fracture pressure gradient in ppg
Gfr =
D
In this case Pf and D are known i.e. pore pressure gradient is known. he matrix stress,
Pf where overburden gradient is considered as
z may be calculated using z
ob
1 psi/t. Finally F is determined graphically using Figure 6.40. We will use the above
procedure to calculate the fracture gradient.
1. First, determine the pore pressure gradient.
Pf
Gp =
D
= 0.695 psi/t.
Formation Pore and Fracture Pressure Estimation
2. Next, calculate the matrix stress.
z
ob
D Pf
1 0.695
D
12500 0.305 12500 3,812.5 psi
3. Now determine the depth, Di under normally pressured conditions. In
this case, the rock matrix stress z would be 3,812.5 psi and normal pore
pressure gradient is 0.46 psi/t.
obn
Di
Pfn Di
1.0 0.46
Di
3,812.5
zn
Di
7,060.19 ft
4. Using Di 7060 ft, Matthews and Kelly plot (Figure 6.40) is applied to
construct Figure 6.41 and obtained the corresponding value of Fz 0.65.
5. Finally to calculate the formation fracture gradient (G f ), Eq. (6.52) is
applied.
F
G fr
z
D
Pf
D
0.65
3,812.5
0.695 0.893 psi / ft
12,500
In terms of ppg, the formation fracture gradient is
0
Matrix stress coeicient
Versus D1 for
South Texas Gulf Coast
and
Louisiana Gulf Coast
2
4
South Texas
Gulf Coast
Depth × 1,000 ft
6
8
Louisiana
Gulf Coast
10
12
14
16
18
20
0.3
0.4
0.5
0.6
0.7
0.8
0.9
1.0
F
Figure 6.41 matrix stress coeicients for Example 6.11 using Matthews and Kelly model.
303
304 Fundamentals of Sustainable Drilling Engineering
0.893 psi / ft
0.052
G fr
17.18 ppg
iii) Pennebaker Model: he Pennebaker (1968) correlation is similar to the Mathews
and Kelly method as shown by Eq. (6.50). He correlated the stress rate coeicient with
depth regardless of the pore pressure gradient. Pennebaker did not assume a constant
overburden pressure gradient. Instead he used a variable overburden pressure gradient
taking into account the depth and formation type.
iv) Eaton Model: In 1969, Ben Eaton modified the Hubbert and Willis method.
He assumed that both overburden stress and Poisson’s ratio are assumed to be variables with depth. Eaton also assumed an elastic rock behavior and a lateral strain
that could be related to the vertical stress ratio as a function of Poisson’s ratio. The
horizontal and vertical stress ratio and the matrix stress coefficient are dependent
on the Poisson’s ratio of the formation. Mathematically the model can be written as:
x
y
h
1
(6.53)
z
Here
x
y
= matrix stress in x-direction, psi
= matrix stress in y-direction, psi
= Poisson’s ratio
Equation (6.53) is analogous with Eq. (6.51). Substituting
the analogy, the fracture pressure can be obtained as:
Pfp
1
Pf
ob
z
=
Pf
ob
Pf and applying
(6.54)
he fracture gradient for any depth of interest can be written as:
G fr
Pf
ob
1
D
Pf
D
(6.55)
Eaton prepared several graphs and monographs both for overburden stress and Poisson’s
ratio variables by utilizing actual ield fracture data and log-derived values (Figure 6.42
– 6.45). Using a suitable choice for each variable, the monograph can be used to calculate a fracture gradient (Figure 6.42). A graphical presentation for the Eaton approach
provides a quick solution. he graphs and monographs are used in the same manner as
the Matthews and Kelly graph shown in Figure 6.41.
v) Christmen Model: Christmen (1973) proposed a method to predict fracture gradient for ofshore ield application. he determination of fracture gradient procedures
assumes that overburden stress consists of rock matrix stress and formation luid stress.
he Christmen model is a modiied version of Eaton method. In shallow water, the
reduction in fracture gradient is almost insigniicant because as water depth increases,
fracture gradient declines. he efective stress ratio has been correlated to the bulk density of the sediments. Christmen concluded that the bulk density of the sediments tends
Formation Pore and Fracture Pressure Estimation
305
DEPTH, ft
Variable Overburden Stress by Eaton
0
2000
4000
6000
8000
10,000
12,000
14,000
16,000
18,000
20,000
0.70
0.75
0.80
0.85
0.90
0.95
1.00
1.05
Overburden Stress Gradient, psi/ft
Figure 6.42 Variation of overburden stress with depth as proposed by Eaton.
0
2
Extreme upper limit
Depth × 1,000 ft
Overburden 4
equals 1.0 psi/ft 6
shale
8
10
12
14
16
Gulf Coast
variable
overburden
West Texas
overburden
equals 1.0 psi/ft
producing
formations
18
20
0
0.1 0.2 0.3 0.4 0.5 0.6
Poisson’s ratio
Figure 6.43 Variation of Poisson’s ratio with depth as proposed by Eaton.
to increase with increases in depth, overburden stress, and geological age. he water has
no rock matrix for ofshore area. Since rock is denser than water, the fracture gradient
at a given depth is lower for an ofshore well than for onshore well at the same depth.
he efect of the water depth in calculating the overburden gradient can be shown by
the model proposed by Christmen which is shown below:
Gob
1
D
w
Dw
Here
Gob = overburden gradient, psi/t.
= density of seawater, lbm / ft 3
w
= average bulk density, lbm / ft 3
b
b
Dml
(6.56)
306 Fundamentals of Sustainable Drilling Engineering
PD
1.00
0.90
0.8
0.85
0.80
0.7
0.5
0.4
Example:
Determine fracture gradient at 12,000’ with
formation pressure of 0.67 psi/ft at 12,000’.
Overburden load is 0.96 and Poisson’s Ratio
is 0.46 from monograph fracture gradient is
0.91 psi/ft or 17.5 ppg.
19.0
18.0
17.0
16.0
15.0
14.0
13.0
12.0
11.0
10.0
0.75
1.0
0.9
0.8
0.7
0.6
Fracture Gradient (psi/ft)
0
0.5
5
0.4
0
4
.
0
5
0.3
0
.
03
0.6
PWD
Fracture Gradient (lb/gal)
0.8
Formation Pressure (psi/ft)
0.9
0.9
o
Rati
son
Pois
Overburden (psi/ft)
1.0
PD
0.5
0.70
0.65
0.60
Formation Pressure (psi/ft)
0.95
SC
0.55
0.50
0.45
0.40
Figure 6.44 Monograph determinations of fracture gradients as proposed by Eaton.
Dw = seawater depth, t.
Dml = depth below mud line, t.
If we assume the seawater density of 1.02 g/cc, Eq. (6.56) becomes:
Pfp
D
1
0.44 Dw
D
b
Dml
(6.57)
vi) Anderson et al., Model: Anderson et al. (1973) developed a model based on Biot’s
stress/strain relationships for elastic porous media. All the previous eforts were based on
the assumed that the formation properties coeicient is a function of depth. However, the
proposed model was not based on this assumption. he authors derived an expression for
the fracture pressure gradient that is a function of well depth, overburden pressure, pore
pressure, Poisson’s ratio, and the ratio of the compressibility of the porous rock matrix to the
intrinsic compressibility of rock (α). he model can be written in form as:
Pfp
Here
Pob
cr
cb
Pf
2
1
Pob
Pf
(6.58)
= overburden pressure, psi
= ratio of the compressibility of the porous rock matrix to the intrinsic comc
pressibility of rock = 1 r
cb
= compressibility of the porous rock matrix, 1/psi
= bulk compressibility of the rock matrix, 1/psi
Formation Pore and Fracture Pressure Estimation
307
0
1,000
9
10
11
12
13
14
15
1,000
3,000
4,000
5,000
6,000
16
17
18
19
7,000
Depth (ft)
8,000
9,000
10,000
11,000
12,000
13,000
14,000
15,000
16,000
17,000
18,000
19,000
20,000
9
10 11 12 13 14 15 16 17 18 19 20
Fracture Gradient (Ib/gal)
Figure 6.45 Graphical determinations of fracture gradients with depth using the Eaton approach.
Anderson et al. (1973) used ield data to evaluate empirically some of the parameters
involved in terms of quantities available from the well log. hey concluded that, the
ratio of the compressibility of the porous rock matrix to the intrinsic compressibility
of the rock is found to be empirically related to formation porosity. Poisson’s ratio,
according to the derived relationship is found to be empirically related to the shaliness
of the sand as estimated by the use of sonic and density logs. hen, the fracture pressure, which is dependent upon Poisson’s ratio (i.e., by shaliness) as well as by porosity,
is assumed to have a uniform behavior with depth.
vii) Belloti and Giacca Model: Another formula that was used to calculate fracture
pressure gradient was based on the Terzaghi equation and presented by Belloti and
Giacca (1978). his technique classiied the formations according to their elasticity and
other properties such as permeability, shaliness, etc. he following equations can be
used to calculate the fracture pressure gradient.
G fr
Gp
2
1
Gob G p
(6.59)
308 Fundamentals of Sustainable Drilling Engineering
Here
G fr = fracture gradient, psi/t.
Gob = overburden gradient, psi/t.
G p = pore pressure gradient, psi/t.
Equation (6.59) is used when the pressure is totally employed at the well bore, as in case
of iltration controlled by wall-building luids. For the case of free formation invasion
by drilling luids where the pressure distribution creates a gradient inside the rock, the
following equation is can be used:
G fr
Gp 2
Gob G p
(6.60)
he authors used a constant value of ( ) according to rock lithology.
Example 6.12: A well of 14,750 t. was drilled at South Texas Gulf Coast area where the
pore pressure gradient was found at 0.74 psi/t. Calculate the fracture gradient in units
of psi/t and lbm/gal using the Hubbert and Willis model, Matthews and Kelly model,
Eaton model, and the Belloti and Giacca model. Summarize the results in tabular form,
showing answers, in units of lb/gal and also in psi/t.
Solution:
Given data:
D = total vertical depth = 14,750 t.
Pf
Gp =
= pore pressure gradient = 0.74 psi/t.
D
Required data:
Pfp
= fracture pressure gradient in psi/t.
Gfr =
D
Pfp
Gfr =
= fracture pressure gradient in ppg
D
Hubbert and Willis model:
G fr _ min
2 Pf
1
1
D
3
G fr _ max
1
1
2
1
1 2 0.74
3
Pf
D
1
1 0.74
2
0.827 psi / ft
0.87 psi / ft
In terms of ppg, the formation fracture gradient is
G fr _ min
0.827 psi / ft
psi / ft
0.052
lbm / gal
15.90 ppg and
Formation Pore and Fracture Pressure Estimation
0.87 psi / ft
psi / ft
0.052
lbm / gal
G fr _ max
309
16.73 ppg
Matthews and Kelly model:
1. First, determine the pore pressure gradient.
Pf
Gp =
= 0.74 psi/t.
D
2. Next, calculate the matrix stress.
z
ob
D Pf
1 0.74
D
14,750 0.26 14,750 3,835.0 psi
3. Now determine the depth, Di under normally pressured conditions. In
this case, the rock matrix stress z would be 3,812.5 psi and normal pore
pressure gradient is 0.46 psi/t.
obn
Di
Pfn Di
1.0 0.46
Di
3,835.0
zn
Di
7,101.85 ft
4. Using Di 7101.85 ft , Matthews and Kelly plot (Figure 6.40) is applied to
construct Figure 6.46 and obtained the corresponding value of Fz 0.74.
5. Finally to calculate the formation fracture gradient (G f ), Eq. (6.52) is
applied.
G fr
F
Pf
z
D
D
0.74
3,835.0
0.74
14,750
0.9324 psi / ft
In terms of ppg, the formation fracture gradient is
G fr
0.9324 psi / ft
0.052
17.93 ppg
Eaton model:
Equation (6.55) shows that the overburden stress gradient and Poisson’s ratio should be
found out irst from the graphs in Figure 6.42 and Figure 6.43 as proposed by Eaton.
Figure 6.47 and Figure 6.48 show the overburden stress gradient and Poisson’s ratio
respectively as:
ob
D
0.98 psi / ft and
0.48
Now applying Eq. (6.55), the fracture gradient can be calculated as:
G fr
0.48
0.98 0.74
1 – 0.48
0.74
0.962
psi
ft
310 Fundamentals of Sustainable Drilling Engineering
In terms of ppg, the formation fracture gradient is:
G fr
0.962 psi / ft
0.052
18.49 ppg
Belloti and Giacca model:
Applying Eq. (6.60), the fracture gradient can be calculated as:
G fr
Gp 2
0.74 2 0.48 0.98 0.74
Gob G p
0.9704 psi / ft
In terms of ppg, the formation fracture gradient is:
G fr
0.9704 psi / ft
0.052
18.662 ppg
he summaries of the fracture gradients by diferent models are shown in Table 6.9.
In the above example, it is noted that all the methods applied here take into consideration the pore pressure gradient. As the pore pressure increases, the fracture gradient
0
Matrix stress coeicient
Versus D1 for
South Texas Gulf Coast
and
Louisiana Gulf Coast
2
4
South Texas
Gulf Coast
Depth × 1,000 ft
6
8
Louisiana
Gulf Coast
10
12
14
16
18
20
0.3
0.4
0.5
0.6
0.7
0.8
0.9
1.0
F
Figure 6.46 matrix stress coeicients for Example 6.12 using Matthews and Kelly model.
Formation Pore and Fracture Pressure Estimation
311
DEPTH, ft
Variable Overburden Stress by Eaton
0
2000
4000
6000
8000
10,000
12,000
14,000
16,000
18,000
20,000
0.70
0.75
0.80
0.85
0.90
0.95
1.00
1.05
Overburden Stress Gradient, psi/ft
Figure 6.47 Variation of overburden stresses with depth for Example 6.12.
0
2
4
Extreme upper limit
Depth × 1,000 ft
Overburden
equals 1.0 psi/ft
shale
6
8
10
12
14
Gulf Coast
variable
overburden
West Texas
overburden
equals 1.0 psi/ft
producing
formations
16
18
20
0
0.1 0.2 0.3 0.4 0.5 0.6
Poisson’s ratio
Figure 6.48 Variation of Poisson’s ratio with depth for Example 6.12.
also increases. While calculating the fracture gradient by Hubbert and Willis, it is
apparently considered only the variation in pore pressure gradient. On the other hand,
Matthews and Kelly consider the changes in rock matrix stress coeicient, and in the
matrix stress along with pore pressure. Ben Eaton considers variation in pore pressure
gradient, overburden stress and Poisson’s ratio to calculate the fracture gradient. Belloti
and Giacca also consider similar parameters. he last two methods are probably the
most accurate of the four methods. If we know Poisson’s ratio, the last two methods are
actually quite similar, and usually yield similar results.
312 Fundamentals of Sustainable Drilling Engineering
6.3 Current Development on Formation Pore
and Fracture Pressure
Daines (1980) proposed a technique for predicting fracture pressure for wildcat wells;
he described a theoretical model in order to demonstrate the principle stress system
within a basin of simple topography and structure. In this model, if a well is drilled
nearly vertically, then it should be approximately parallel to one of the principle stresses,
which is equal to the efective weight of the overlying strata. he horizontal stresses are
a combination of the stresses caused by gravity and a superposed horizontal stress. he
latter may be nonexistent or may reach a maximum of two or three times the vertical
stress. he minimum horizontal stress is measured by the irst fracture test in compact formation. As the vertical stress increases approximately linearly with depth, then
the tectonic horizontal stress will increase linearly with depth and is also deined by a
constant stress ratio G fr G p / Gob G p . Since this ratio is obtained from the irst
fracture test, then at any subsequent depths the fracture pressures may be calculated
providing pore pressures, overburden pressures and formation lithology as an indicate
for Poisson’s ratio.
Breckels and Eekelen (1982) proposed correlations for fracture gradient and depth.
hey plotted hydraulic fracturing and leak-of test data versus depth and drew lower
bound curves, which were assumed as representing the minimum horizontal stress for
particular areas. hen a relationship between minimum horizontal stress and depth
was derived to estimate fracture pressures.
Another attempt to study the relationship between formation properties coeicients
and depth was made by Brennan and Annis (1984). heir work is based on shallow soil
boring density and density log to estimate overburden pressure gradient. A correlation
between horizontal to vertical efective stress ratio and depth had been developed. But
soon it was concluded that this procedure generated very poor correlations, which can
be attributed to variation in the depth of the top of the abnormal pore pressure zone
and the rate of change of the pore pressure. To minimize these factors, efective horizontal stress gradient versus efective vertical stress gradient (Gob G p ) was plotted. By
this plot, the depth problem was eliminated and pore pressure efects minimized. he
relationship described by the empirical correlation deined efective horizontal stress
gradient as a function of efective vertical stress gradient. An equation is obtained from
the above relationship, which is then solved for pressure gradient. So, given the overburden pressure gradient and pore pressure gradient, a direct solution can be made for
the fracture pressure gradient.
Constant and Bourgoyne (1988) used the data published by Eaton to introduce the
stress ratio, which was obtained by itting an exponential function using the data.
Aadnoy and Soteland (1989) stated that at a shallow depth, the rocks are not fully
compacted or consolidated. herefore, lithology may not play the same role as for
deeper depths. he authors gave a good analysis of the factors that afect leak-of tests.
hese factors include the absence of exact measurement, lithology, faults, intact versus
non-intact boreholes, and mud properties.
Lesage et al., (1991) elucidated that the horizontal stresses are signiicantly larger
than the pore pressure, so a suitable safe range of mud weight usually can be found;
Formation Pore and Fracture Pressure Estimation
313
even throught potential shear failure of the wellbore provides other constraints on mud
weight, especially in highly deviated wells. Clearly, abnormally high pore pressure or
weak formations present potential problems for drillers. Abnormally high or low earth
stresses also can lead to unexpected diiculties.
Rocha et al., (1994) proposed a method to estimate fracture pressure gradient
using only the leak-of test data and being independent of the pore pressure. he
method is based on a new concept called “pseudo overburden pressure”, which is
deined as the overburden pressure a formation would exhibit if it was plastic. In this
method it was assumed that fracture pressure is a strong function of depth. hese
can be seen by the relationship, which was introduced by plotting leak-of test data
collected from diferent areas with depth. hen high correlation coeicients were
obtained, which indicate that depth is one of the most important factors afecting
fracture pressure. As a conclusion of their work, the authors stated that for the case
of plastic formations such as shales the value of the stress ratio should be very close
to 1.0 implying that fracture pressure would be a function only of the overburden
pressure. In other word, in the presented method overburden pressure function is
chosen and correlated directly to fracture pressure data represented by leak-of test
data.
Yasser (1995) used the concept that, in normal fault regime basins, fracture propagation pressure which was calculated accurately from porosity, vertical stress, and pore
pressure, is not based on rock mechanics laws but on the relationship given below
H
1
v
(6.61)
Here
H
= horizontal efective stress, psi
= porosity, dimensionless
Equation (6.61) means that the higher the porosity, the smaller the ratio between
the horizontal and vertical efective stresses, which in fact, is the opposite of what is
observed in nature. he author stated that the relationship between pore pressure and
fracture pressure will vary with diferent overpressure mechanisms and local boundary
conditions, so that prediction of one from the other, even using established techniques,
can lead to signiicant errors.
Rodney et al., (2002) stated that pre-drill pore pressure and fracture gradient determination from seismic data is available as a means of drilling risk reduction in deep
water classic basins. Based on the work of several investigators, pore and fracture gradient can be computed using seismic data.
6.4 Future Trend on Formation Pore
and Fracture Pressure
he future trend toward solving the challenges related to formation pore and fracture
pressures are in the direction of the application of artiicial intelligent techniques. A
314 Fundamentals of Sustainable Drilling Engineering
new development in pore pressure prediction is the artiicial neural network (ANN).
An ANN has the capability of intelligent analyzing with simple mathematical method
and dealing with non-linear, fuzzy, and complex relationship. Feed-forward with
back-propagation neural network (FFBPANN) is the most wildly used ANN due to its
powerful adaptability for diferent problem and excellent performance when dealing
with complex relationship. he output of the ANN is pore pressure.
his ANN has three layers such as two hidden and one as the output layer. he irst
set of inputs includes gamma ray; formation density is the input of the irst layer. he
second set of inputs, which includes interval transit time, formation density, depth and
the results of the irst layer, are the inputs of the second layer. Compared with the ANNs
used in the literature, the novel design of this ANN is the fact that it has two sets of
inputs and a diferent structure. he ANN can generate a more accurate pore pressure
prediction with logging data because it can simulate the process and predict the pore
pressure more precisely. he ANN modeling proved that it is more accurate than the
conventional pore pressure prediction methods since it is not based on the theory of
shale compaction and since it precisely simulates the prediction process. he better
the ANN constructed, the more accurate the prediction results of formation pore and
fracture pressures.
6.5 Summary
he chapter discusses the issues related to the formation of pore pressure and fracture
gradients. he diferent rock mechanical properties are discussed in detail. he development of underground stresses and the related formation pressure, fracture pressure
is also outlined in this chapter. he importance of diferent types of pore pressures
and their detail impacts on the formation of pore and fracture gradients are discussed
thoroughly. he diferent causes of abnormal pressures with detailed detection and prediction techniques are the main focus of the chapter. Pore pressure estimation and prediction techniques and correlations are well explained to understand the techniques.
he same procedure is applied for fracture pressure and gradient calculation. Finally
the current state-of-the-art on the formation pore pressure and fracture pressure along
with the fracture gradient are elaborated in this chapter.
6.6 Nomenclature
A
D
d
E
f
g
m
N
q
= rock matrix strength constant or drillability constant
= total vertical depth, t.
= inner diameter of the drill pipe, in
= rotary speed exponent
= function of
= gravitational acceleration, t./sec2
= slop of the normal trend line
= rotary speed, rpm
= luid circulation rate, gpm
Formation Pore and Fracture Pressure Estimation
R
W
aN
aq
aW
cr
cb
db
dh
dm
dn
Ds
Dw
dmc
dmn
dmo
Dml
Dsw
dexp
dD
F
f Pd
f tN
Gf
Gn
Gp
G fr
Gob
Pd
Pfp
Pf
Pfn
Plo
Pob
Rd
tN
tt
tf
tr
Vs
Vt
K
315
= shale drillability or rate of penetration, t./hr
= weight on bit, lbf
= rotating speed exponent (= 0.6 for ofshore Louisiana)
= low rate exponent (= 0.3 for ofshore Louisiana)
= bit weight exponent (= 1.0 for ofshore Louisiana)
= compressibility of the porous rock matrix, 1/psi
= bulk compressibility of the rock matrix, 1/psi
= bit diameter, in
= borehole diameter, in
= modiied d-exponent
= diameter of one bit nozzle, in
= the depth from the sea bed to up to a depth of interest, t.
= seawater depth, t.
= calculated modiied d-exponent at a given depth
= modiied d-exponent from normal pressure trend line (i.e. extrapolated) at a
given depth (Figure 6.26)
= intercept of the normal trend line
= depth below mud line, t.
= depth from surface to the ocean bottom, t.
= bit weight exponent or d-exponent or formation drillability
= vertical depth from a reference point (ground surface)
= variable matrix stress coeicient for the depth at which the value of z would
be normal matrix stress, dimensionless
= function related to diferential pressure
= function related to bit wear
= formation pressure gradient
= normal pressure gradient, lbm/gal
Pf
=
= formation pore pressure gradient at the point of interest, psi/t.
D
Pfp
=
= fracture pressure gradient at the point of interest, psi/t.
D
= overburden gradient, psi/t.
= diferential pressure, lbf/gal/1000t.
= observed fracture pressure at the point of interest, psi
= formation pore pressure at the point of interest, psi
= normal formation pore pressure
= surface leak-of pressure, psi
= overburden pressure, psi
= shale drillability at zero diferential pressure, t./hr
= bit wear index (equivalent to rotating hours),
= the observed interval transit time, s/t.
= the interval transit time in the pore luid, s/t.
= the interval transit time in rock matrix, s/t.
= volume of shale cutting, t.3
= total volume of cup, t.3
= porosity decline constant at , t.–1
316 Fundamentals of Sustainable Drilling Engineering
Pf
= formation pressure gradient, psi/t.
D
Pf
D
b
w
b
e
f
m
n
r
f
fn
sw
bs
w
avg
o
H
v
z
ob
x
y
v
ob
ob
min
min
D
ob
D
Pf
g
= normal pressure gradient, psi/t.
n
= ratio of the compressibility of the porous rock matrix to the intrinsic comcr
pressibility of rock = 1
cb
= density of the rock
= bulk density of porous sediment
= density of seawater, lbm / ft 3
= average bulk density, lbm / ft 3
= equivalent mud density at the bit while circulating or actual mud weight in
use, ppg
= luid density in the pore space
= mud density, lbm/t.3
= mud density equivalent to normal pore pressure gradient or normal mud
weight, ppg
= grain density of rock matrix, lbm/gal
= density of luid in the pore space, lbm/gal
= formation luid density at normal condition
= density of sea water, lbm/gal
= bulk density of shale, lbm/t.3
= density of water, lbm/t.3
= porosity, dimensionless
= average porosity
= porosity at surface (D = 0), fraction
= horizontal efective stress, psi
= vertical matrix stress
= matrix stress = ob Pf , psi
= overburden pressure, psi
= matrix stress in x-direction, psi
= matrix stress in y-direction, psi
= vertical stress
= vertical overburden stress, psi
Ppn), psi
= overburden stress (i.e. ob
v
= minimum efective stress at the point of interest, psi
= minimum efective stress gradient at the point of interest, psi/t.
= overburden stress gradient, psi/t.
= friction pressure loss, psi
= gel strength, lbm/100t.2
= Poisson’s ratio
Formation Pore and Fracture Pressure Estimation
317
6.7 Exercise
E6.1: Find out the normal pore pressure at a depth of 7000 t. below the sea level.
Assume that the drilling activities will be continued in Malaysia. Also ind out the mud
weight for that area.
E6.2: Consider a gas sand reservoir as shown in Figure 6.15. If the water-illed portion of the sand is pressured normally and the gas/water contact occurred at a depth of
5,300 t., what mud weight would be required to drill through the top of the sand structure safely at a depth of 4,100 t.? Assume the gas has an average density of 0.78 lbm/gal.
E6.3: Determine the pore pressure of a normally pressured formation in the Gulf of
Mexico at 9,000t. depth.
E6.4: Calculate the matrix stress of an underground reservoir if the overburden pressure is 6,300 psi and the formation pore pressure is 4000 psi.
E6.5: Determine values for surface porosity of an area where an average grain density of 2.55 g/cm3, an average pore luid density of 1.02 g/cm3, and the value for porosity decline constant is 0.00009 t.–1. Assume the average bulk density of the sediment is
2.52 g/cm3 at an speciied depth of 8,500 t.
E6.6: Determine porosity decline constant for West Texas area. It is noted that an
average grain density of 2.50 g/cm3, an average pore luid density of 1.00 g/cm3, and the
value for surface porosity of 38% were recorded. Assume the average bulk density of
the sediment is 2.25 g/cm3 at an speciied depth of 10,000 t. Also compute the vertical
overburden stress at the same depth.
E6.7: A penetration rate of 25t./hr was observed while drilling in shale at a depth of
10,500t. using a 9.875-in bit in the gulf of Mexico. he WOB was 26,000 lbf and the rotary
speed was 110rpm. he equivalent circulating density at the bit was 10.0 lbm/gal. Compute
the dexp and the dm. Assume the normal pressure gradient for the area as 0.465 psi/t.
E6.8: Figure 6.28 shows the depth vs. d-exponent and modiied d-exponent plot.
Estimate the formation pressure at 14,000 t. using the Rehm and McClendon and the
Zamora correlation. Assume that Figure 6.28 is constructed based on North sea data.
E6.9: What is the pore pressure at a depth of 12,500 t. if the formation is in Gulf
Coast area? Assume that overburden stress gradient is 0.85 psi/t., and normal formation pressure gradient is 0.465 psi/t. Use Eaton Equation. Use Figure 6.29. Also
ind out the EMW of the formation.
E6.10: he mud engineer of Schlumberger calculated the mud weight of 12 lbm/gal
for the North Sea area where the pressure gradient was found 0.452 psi/t. he surface
casing was set at a depth of 2,000 t. he fracture gradient was calculated as 0.73 psi/
t. and the transition zone was detected at a depth of 8,000 t., which results a kick. To
avoid kick, determine the maximum safe underbalance between mud weight and pore
pressure if well kicks from formation at a depth of 8,000 t.
E6.11: Calculate the minimum and maximum equivalent mud weight in ppg that
can be used immediately below the casing seat at a depth of 10,000 for the pore pressure gradient of 0.57 psi/t. and an overburden gradient of 0.90 psi/t. It is assumed that
matrix stress coeicient is 0.70. Use Mathews and Kelly method.
E6.12: A well of 13,000 t. was drilled at a Texas Gulf Coast area where the pore pressure gradient was found 0.735 psi/t. Calculate the fracture gradient in units of psi/t.
and lbm/gal using Matthews and Kelly model.
318 Fundamentals of Sustainable Drilling Engineering
E6.13: A well of 15,000 t. was drilled at a South Louisiana Gulf Coast area where the
pore pressure gradient was found 0.689 psi/t. Calculate the fracture gradient in units
of psi/t. and lbm/gal using the Hubbert and Willis model, Matthews and Kelly model,
Eaton model, and Belloti and Giacca model. Summarize the results in tabular form,
showing answers, in units of lb/gal and also in psi/t.
References
Aadnoy, B.S, Soteland, T. Rogaland, U., and Ellingsen, B. Casing Point Selection at Shallow
Depth. SPE/IADC 18718 presented in New Orleans, Louisiana, Feb–March 1989.
Alixant, J.L. and Desbrandes, R.: “Explicit Pore-Pressure Evaluation: Concept and Application,”
SPEDE (September 1991) p. 182.
Anderson, R.A., Ingram, D.S., and Zanier, A.M. SPE-AIME. Determining Fracture Pressure
Gradients Drom Well Logs. SPE 4135 paper presented in 1973.
Bassiouni, Z.: “heory, Measurement, and Interpretation of Well Logs,” SPE, Richardson, TX,
1994, pp. 1–19.
Bennan, R.M and Annis, M.R. A New Fracture Gradient Prediction Technique hat Shows
Results in Gulf of Mexico Abnormal Pressure. SPE 13210 paper presented in Houston,
Texas, Sept 1984.
Bourgoyne A.T. Jr, et al.: “Applied Drilling Engineering,” SPE, Richardson, TX, 1991, pp.
246–252.
Bourgoyne, A.T. Jr, and Rocha, A.L. Jr.: “A New, Simple Way to Estimate Fracture Pressure
Gradient,” SPEDC, September 1996, pp. 153–159.
Breckels, I.M., and van Eekelen, H.A.M, Relationship Between Horizontal Stress and Depth in
Sedimentary Basins. SPE 10336 paper presented in 1982.
Carothers, J.W.: “A Statistical Study of the Formation Factor Relationship,” he Log Analyst,
September–October 1948, pp. 14–20.
Chilingar, G.V. and Knight, L., “Relationship Between Pressure and Moisture Content of
Kaolinite, Illite and Montmorillonite Clays,” AAPG Bulletin, 1960, V. 44, No. 1, pp. 100–106.
Christman, S. “Ofshore Fracture Gradients, J. Pet. Tech., (Aug. 1973), 910–914.
Combs, G.E, 1968. “Prediction of Pore Pressure from Penetration Rate”. 43rd Annu. Fall Meet.,
Soc. Pet. Eng., AIME, Houston, TX, SPE 2162, 16 pp.
Constant, W.D. and Bourgoyne, A.T., Fracture Gradient Prediction for Of-shore Wells. SPE
15105 paper presented in Jun 1988.
Daine, S.R. Exploration Logging Inc. he Prediction of Fracture Pressures. SPE paper 9081 presented in 1980.
Eaton, B.A. (1969). Fracture Gradient Prediction and Its Application in Oilield Operations. J.
Per. Tech., Oct. 1969, 1353–1360; Tram, AIME, 246.
Eaton, B.A., and Eaton, L.E.: “Fracture Gradient Prediction for the New Generation,” World Oil,
October 1997, p. 93.
Eaton, B.A.: “Fracture Gradient Prediction and Its Application in Oilield Operations,” JPT,
October 1969, p. 246.
Eaton, B.A.: “he Equation for Geopressure Prediction from Well Logs,” paper SPE 5544, presented at the 1975 SPE Annual Technical Conference and Exhibition, Dallas, TX, September
28–October 1.
Economides, M.J., and Martin, T.: “Modern Fracturing – Enhancing Natural Gas Production,”
ET Publishing, Houston, TX, 1997, pp. 116–124.
Formation Pore and Fracture Pressure Estimation
319
Fricke, H.: “A Mathematical Treatment of the Electrical Conductivity and Capacity of Disperse
Systems,” Physical Review, 1924, 24, pp. 525–587.
Gardner, G.H.F., et al.: “Formation Velocity and Density – he Diagnostic Basis for
Stratigraphic Traps,” Geophysics, Vol. 39, No. 6, December 1974, pp. 2085–2095.
Hottman, C.E., and Johnson, R.K.: “Estimation of Formation Pressures from Log-derived Shale
Properties,” JPT, June 1965, p. 717.
Hubbert, M.K. and Willis, D.G. (1957). Mechanics of Hydraulic Fracturing. Trans., AIME 210,
153–166.
Hubbert, M.K. and Willis, D.G., “mechanics of Hydraulic Fracturing”, Trans., AIME (1957), 210,
153–160.
Lesage, M., Hall, P., Pearson, J.R.A and hiercelin, M.J., Cambrige Research. Pore-Pressure and
Fracture Gradient Predictions. SPE 21607 paper presented in Jun 1991.
Littleton, R., Cody, R., Landreth J., Irving, T. and Greve, J., Pre-drill Seismic Predictions Platform
(Pore Pressure, Fracture Gradient, Lithology, and Pore Fluids) Efectively Used as a Well
Planning Tool by a Multi-Discipline Deepwater Operations Team. IADC/SPE 74487 paper
presented in Dallas, Texas, Feb 2002.
Matthews, W.R. and Kelly, J., “How to predict formation pressure and fracture gradient from
electric and sonic logs”, OGJ, February 20, 1967.
Matthews, W.R.: “Here is How to Calculate Pore Pressure from Logs,” OGJ, November 15, 1971–
January 24, 1972.
Matthews,W. R. and Kelly, J. (1967). How to Predict Formation Pressure and Fracture Gradient
from Electric and Sonic logs. Oil and Gas Journal, February 20.
MI Drilling Fluids, Inc.: “Plotting Pressures From Electric Logs,” 1999. 110.
Pennebaker, E.S., “An Engineering Interpretation of Seismic Data”, SPE 2165, presented at the SPE
43rd Annual Fall Meeting, Houston, September 29–October 02, 1968.
Perez-Rosales, C.: “Generalization of Maxwell Equation for Formation Factor,” paper SPE
5502, presented at the 1975 SPE Annual Technical Conference and Exhibition, Dallas, TX,
September 18–October 1.
Porter, C.R., and Carothers, J.W.: “Formation Factor-Porosity Relation Derived from Well Log
Data,” SPWLA, 1970, Paper A.
Rocha, L.A., Petrobras, S.A, and Bourgoyne, A.T., A New Simple Method to Estimate Fracture
Pressure Gradient. SPE 28710, paper presented in 1994.
Roegiers, J-C.: “Rock Mechanics,” Chapter 3 or Reservoir Stimulation, ed. Economides, M.J. and
Nolte, K.G., Schlumberger Educational Services, 1987.
Schlumberger: “Log Interpretation Charts,” Houston, Tx, 1979.
Schlumberger: “Oilield Glossary – Where the Oilield Meets the Dictionary,” http://www.glossary.oilield.slb.com.
Terzaghi, K.: “heoretical Soil Mechanics,” John Wiley and Sons, New York City, NY, 1943.
Timur. A., et al.: “Porosity and Pressure Dependence on Formation Resistivity Factor for
Sandstones,” Cdn. Well Logging Soc., 1972, 4, paper D.
Winsauer, H.M., et al.: “Resistivity of Brine-Saturated Sands in Relation to Pore Geometry,”
AAPB Bulletin 36, No. 2, February 1952, pp. 253–277.
Yoshida, C., et al.: “An Investigative Study of Recent Technologies Used For Prediction,
Detection, and Evaluation of Abnormal Formation Pressure and Fracture Pressure in
North and South America,” IADC/SPE 36381 presented at the 1996 IADC/SPE Asia Paciic
Drilling Technology Conference, Kuala Lumpur, Malaysia, September 9–11.
7
Basics of Drill String Design
7.1 Introduction
he drill string is an important part and a major component of the rotary drilling system. he drill string is a pervasive term that is sometimes also called a drillstem. It is
the connection between the rig and the drill bit. A typical drill string consists of kelly,
drill pipe, drill collars, tools and drill bit. he drill string has two primary objectives:
i) it provides a conduit for the drilling luid to be pumped down through it, and circulates back up the annulus, ii) it provides torque to the drill bit for cutting the rock. he
major functions of drill string are: i) to suspend the bit, ii) to transmit rotary torque
from kelly to the drill bit (i.e. impart rotary motion to the bit), iii) to provide a conduit
for circulating drilling luid to the bit (i.e. provide luid conduit from rig to bit), iv) to
provide weight on bit (WOB), and v) to lower and raise bit in the well. In addition, the
drill string may serve some of the following specialized services such as i) it allows the
formation evaluation and testing when logging tools cannot be run in the openhole,
ii) it provides some stability to the bottomhole assembly to minimize vibration and bit
jumping, and iii) it allows formation luid and pressure testing through the drill string.
It must be remembered that in deep holes the drill string may be 8–10 km long.
Trying to control the bit on the end of such long string is a diicult task. herefore
the drill string must be carefully chosen to meet the requirements. Although the drill
string is oten a source of problems such as washouts, twist-ofs, and collapse failures,
it is rarely designed to prevent these problems from occurring. In many cases, a few
minutes of drill string design work could prevent most of the problems.
321
322 Fundamentals of Sustainable Drilling Engineering
7.2 Drill String Components
he drill string assembly consists primarily of the kelly, drill pipe, bottomhole assembly
(BHA), and drill bit. he drilling luid and rotational power are transmitted from the
surface to the bit through the drill string. Figure 7.1 shows the usual arrangement of
drill string components and bit. he drill pipe section contains conventional drill pipe,
and heavy weight pipe. he drill pipe is attached with a square or hexagonal pipe called
kelly at the upper end of the drill string. he BHA may contain the following items such
as: i) drill collars, ii) stabilizers, iii) jars, iv) reamers, v) shock subs, and vi) bit sub. In
addition, the drill string may include shock absorbers, junk baskets, drilling jars, reamers, and other equipment. here are some special tools in the BHA or drill pipe, which
may include monitor-while-drilling (MWD) tools, and drill stem-testing tools. Finally
there exists drill bit at the lower end of the drill string. Heavy walled large-diameter
drill collars furnish bit load.
he drill bit is attached to the drill collars by means of a bit sub. For an efective rock
cutting, the lower part of the drill collar is stacked onto the drill bit to provide the WOB.
he drill cuttings generated by the rock bit are removed from the bottom of the hole
by the drilling luid, which is circulated inside the drill string and through the drill bit
into the annular space between the drill string and the bottomhole wall. Stabilizers are
placed above the bit to control the direction in which the drill bit penetrates the formation. Downhole motors with bent subs and rotary-steerable tools are also used for
controlling the direction in which the bit drills.
7.2.1
Kelly
A description of a kelly is already covered in Chapter 2. It is a special section of pipe
that is attached to the bottom of the swivel by threading. Figure 7.2a shows the arrangement, which is not round. It has a hexagonal (6 sides) or square shape (4 sides) of pipe
(Figure 7.2b). hey come in 40t.. and 54t. lengths. Table 7.1 shows the diferent available size of the kelly. It is attached to the swivel and its in a matching slot in the rotary
table. he kelly it into a device called kelly bushing. he kelly bushing then its into the
master bushing which is mounted on the rotary table (Figure 7.3). As the rotary table
turns, kelly is also turned which rotates the drill string and the drill bit. he functions of
the kelly are i) to transmit rotation and weight to the drill bit, and ii) to carry the total
weight of the drill string.
7.2.2
Drill Pipe
Drill pipe is the major component of the drill string, which forms the upper part of
the drill string. It has a seamless pipe with threaded joints at either end known as tool
joints (Figure 7.4). Each section of pipe is called a joint with a box (female) and pin
(male) located on the ends. At the one end of the pipe there is the box, which has the
female thread. Drill pipe is threaded together or assembled in sections and put into
the hole as the bit turns. he other end is the male thread known as the pin. hese
tool joints provide a shoulder that suspends the drill pipe in the slips or elevators.
It consists of a tube body and tool joint. he drill pipe is hollow and allows luid or
Basics of Drill String Design 323
mud
Kelly
Drill String
Kelly Joint
mud
DP
Mud
To pits
Tool joint
Bottom Hole Assembly
mud
HWDP
Drill Collar
Shock Tool
Near Bit Pressure
or Stabilizer
Drill collars
Bit
BIT
(a)
Rotary box
Connection L.H.
mud
Stabilizer
Drill pipe
mud
Jar
(b)
Swivel
Rotary box
connection
Swivel stem
spec. BA
Tool joint
box member
Drill pipe
Rotary pin
Connection L.H.
Rotary box
Connection L.H.
Spec 7
swivel sub
Kelly cock
(optional)
Rotary pin
connection
Upper upset
Rotary box
connection
Rotary pin
connection
Rotary pin
Connection L.H.
Rotary box
Connection L.H.
Rotary box
Kelly
(square or hexagon) connection
(square illustrated)
Note:
All connections
between “lower
upset” of Kelly
and bit are R.H.
Rotary pin
Connection
Rotary box
Connection
Lower upset
Tool joint
pin member
Crossover sub
Drill collar
Rotary pin
connection
Kelly cock or
Kelly saver sub
Protector rubber
(optional)
Rotary pin
Connection
Rotary box
connection
Rotary pin
connection
Bit sub
Bit
(c)
Figure 7.1 Components of the drill string.
transmitting wires to pass through it. he drill pipe is used in lengths known as singles,
which are available in three ranges (Table 7.2). he most common range is 27 t. – 30 t.
in length. he exact length of each single must be measured on the rig since lengths
are not uniform.
324 Fundamentals of Sustainable Drilling Engineering
Table 7.1 Diferent size of kelly.
Square
Hexagonal
1
2
3
3
3
1
2
3
1
2
4
1
4
4
1
4
5
1
4
5
1
4
2
6”
6
SQUARE KELLY
Top Upset with
Left Hand
Connection
HEXAGONAL KELLY
Top Upset with
Left Hand
Connection
E
E
F
G
B
A
G
F
Bottom Upset
with Right Hand
Connection
Bottom Upset
with Right Hand
Connection
(a)
(b)
Figure 7.2 Components of a kelly.
Table 7.2 Drill pipe lengths (Ford, 2005).
Range
Length (t.)
1
18 – 22
2
27 – 30
1
38 – 45
B
A
Basics of Drill String Design 325
Kelly
Kelly
bushing
Rotary
table
Bowl Lock Assy.
API Insert Bowl
Hinge Pin Stationary
Drive Hole Bush
Hole for Lifting Sing
APS-Insert Bowl
Hinge Pin Stationary
Drive Hole Bushing for
Pin Type Kelly Bushing
Lock for Bowl
Label to lock
in Rotary Table
Body Segment
Holes for Lifting
Sling Hock
Hinge Pin Removable
Body Segment
Figure 7.3 Components of kelly bushing.
Figure 7.4 Drill pipe arrangement.
Various diameters of drill pipe are available, together with diferent wall thickness
(Table 7.3). However, the most commonly used diameters of drill pipe are 4, 4½, and
5 inches OD. he wall thickness dimension relates to the weight per foot of the drill
pipe and allows a selection of the pipe to meet speciic drilling requirements. A drill
pipe is normally purchased in large batches and a record should be kept to monitor the
wear and use each batch sustains. he physical properties of a drill pipe can be found
326 Fundamentals of Sustainable Drilling Engineering
Table 7.3 Dimensions of drill pipe (Ford, 2005).
Size (OD, inches)
Weight (lb/t)
ID (inches)
5.65
1.815
10.40
2.151
9.50
2.992
13.3
2.764
15.50
2.602
5
16.25
4.408
5
19.50
4.276
5
25.60
4.000
21.90
4.776
24.70
4.670
3
8
7
2
8
1
3
2
1
3
2
1
3
2
2
1
2
1
5
2
5
in any available handbook or manual. However, for identiication purposes, a drill pipe
can be classiied according to the size (nominal OD), wall thickness (or nominal wall
thickness), steel grade, and length ranges. he steel grades used and the corresponding
minimum tensile yield strength for each are given in Table 7.4.
7.2.3 Tool Joint
Tool joints are positioned at each end of a length of drill pipe, which are shown in
Figure 7.5. It provides the screw thread for connecting together the joints of drill pipe
and the only seal is the shoulder-to-shoulder connection between box and pin. Initially
tool joints are screwed at the end of drill pipe, and then reinforced by welding. A new
development is to have shrunk-on tool joints. his process involves heating the tool
joint, then screwing it on to the pipe. As the joint cools, it contracts and forms a very high
close seal. One advantage of this method is that a worn joint could be heated, removed
and replaced by a new joint. he modern method is to lash-weld the tool joints onto
the pipe. Hard facing material is used for the tool joints, and so replacements are not
required. When a connection is made, the rig tongs must be engaged around the tool
joints, whose greater wall thickness can sustain the torque required. he strength of the
Basics of Drill String Design 327
Table 7.4 Minimum tensile yield strength for new drill pipe (Mitchell and Miska, 2011).
Steel Grade
Minimum Yield Strength, psi
D
55,000
E
75,000
X-95
95,000
G-105
105,000
S-135
135,000
V-150
150,000
Internal
Upset
External
Upset
Internal-External
Upset
Figure 7.5 Tool joint.
tool joint depends on the cross sectional area of the box and pin. With continual use
the threads become worn, and there is a decrease in the tensile strength. Various sizes
of tool joints are available and can be found in the data handbook. Tool joint boxes usually have 18 degree tapered shoulders, and pins have 35 degree tapered shoulders. Tool
joints are subjected to the same stresses as the drill pipe, and also have to face additional
problems such as: i) when pipe is being tripped out the hole, the elevator supports the
string weight underneath the shoulder of the tool joint, ii) frequent engagement of pins
and boxes, if done harshly, can damage threads, and iii) the threaded pin end of the
pipe is oten let exposed. Tool joint life can be substantially extended if connections
are greased properly (dope) and a steady torque applied. Rubber thread protectors are
also used.
7.2.4
Heavy Wall Drill Pipe
he use of a heavy weight drill pipe (HWDP) in the drilling industry has become a
widely accepted practice. It has a greater wall thickness than ordinary drill pipe. he
pipe is available in conventional drill pipe outer diameters. However, its increased wall
thickness gives a body weight of 2–3 times greater than regular drill pipe (Figure 7.6).
HWDP provides three major beneits to the user – i) it reduces drilling cost by virtually
eliminating drill pipe failures in the transition zone, ii) it signiicantly increases performance and depth capabilities of small rigs in shallow drilling areas through the case of
handling and the replacement of some of the drill collars, and iii) it provides substantial
savings in directional drilling costs by replacing the largest part of the drill-collar string,
reducing down hole drilling torque, and decreasing tendencies to change direction. he
328 Fundamentals of Sustainable Drilling Engineering
HWDP
DC
Figure 7.6 Heavy weight drill pipe.
major functions of HWDP are to reduce failures at transition zone, to reduce downhole
torque and drag in directional drilling, and to reduce diferential sticking.
Most HWDP have an integral center upset acting as a centralizer and wear pad. It
helps prevent excessive tube wear when run in compression. his pipe has less wall
contact than drill collars and therefore reduces the chances of diferential pipe sticking.
HWDP is oten used at the base of the drill pipe where stress concentration is greatest.
he stress concentration is due to i) the diference in cross section and therefore stifness between the drill pipe and drill collars, and ii) the rotation and cutting action of
the bit can frequently result in a vertical bouncing efect.
7.2.5 Bottomhole Assembly
he bottomhole assembly (BHA) is the component of the drill string located directly
above the drill bit and below the drill pipe. he primary component of the BHA is
the drill collar. herefore, it has a signiicant efect on drill bit performance. he other
components of BHA are stabilizers, jars, reamers, crossovers, shocks, hole-openers,
and various subs such as bit subs, shock subs (Figure 7.7). In addition to these main
components, the BHA typically consists of a down hole motor, rotary steerable system
(RSS), and measurement and logging while drilling tools (MWD and LWD respectively. However, some classify the drill bit as a part of the BHA. It hangs below the drill
pipe and provides weight to the drill bit to induce the teeth to penetrate the formation.
he functions of BHA are i) to protect the drill pipe in the drill string from excessive
bending and torsional loads, ii) to control direction and inclination in directional holes,
iii) to drill more vertical and straighter holes, iv) to reduce severities of doglegs, key
seats, and ledges, v) to assure that casing can be run into a hole, vi) to reduce rough
drilling (rig and drill string vibrations), and xi) as a tool in ishing, testing, and work
over operations.
1. Drill Collars: Drill collars (DC) are heavy, stif steel tubulars, which have a much
larger outer diameter and generally smaller inner diameter than a drill pipe. hey are
used at the bottom of a BHA to provide weight on bit and rigidity. he primary function of the drill collar is to provide suicient weight on bit. he weight of the collar also
ensures that the drill pipe is kept in tension to prevent buckling. Figure 7.8 shows a
typical short drill collar and non-magnetic drill collar. It is a pipe with thick walls that
are attached to the bottom of the drill string. herefore it has a signiicantly thicker wall
Basics of Drill String Design 329
BHA for
holdup and
horizontal sections
BHA
Straight hole
Head sub
Coiled
tubing
Connector
Check valve
assembly
Inner tube
landing ring
Long top sub
Pressure
disconnect
Drill collars
Inner tube
stabilizer
Orienting tool
Drill collar sub
Mud motor
SUM 1 MWD
in nonmagnetic
drill collar
Stabilizer sub
Mud motor
Adjustable
best housing
Inner tube
stabilizer
ixed diamond bit
Figure 7.7 Schematics of bottomhole assembly [hese bottomhole assemblies are designed for drilling a
straight hole (let) and a directional hole (right)].
Short Drill Collar
Non-Magnetic Drill Collar
Figure 7.8 Drill Collar.
than a drill pipe. Since the drill collars have such a large wall thickness, tool joints are
not necessary and the connection threads can be machined directly onto the body of
the collar. Drill collars add weight to the bit and make the bit cutters bite into the rock.
Normally multiple drill collars are used to add weight. he purposes of drill collars
are i) to put extra weight on bit, so they are usually larger in diameter than drill pipe
and have thicker walls, ii) to keep the drill string in tension, thereby reducing bending
stresses and failures due to fatigue, iii) to provide stifness in the BHA for directional
control, iv) to stabilize the bit. he weakest point in the drill collar is the joint, therefore
the correct make up torque must be applied to prevent failure. he external surface of
a regular collar is round (slick), although other proiles are available. he drill collars
330 Fundamentals of Sustainable Drilling Engineering
Spiral Drill Collar
Square Drill Collar
Figure 7.9 Spiral drill collar.
are normally supplied in ranges two lengths (30–32 t.). Drill pipe and drill collar come
in sections, or joints, about 30 feet long. here are several types of drill collars that are
explained below.
Square Drill Collars: Square drill collars provide the ability to maximize the available weight on the bit when drilling in challenging formations (Figure 7.9). he square
design has a larger cross sectional area than round drill collars, which increases its
stifness and rigidity to prevent deviation while drilling. he square shape also provides
four point stabilization to prevent buckling. Square geometry makes for a stable and
stif BHA ideal for drilling in hard formations requiring all available weight on the bit.
he square drill collar achieves four objectives – i) it provides continuous centralization over their length, ii) it maximizes bending resistance (stifness), iii) it maximizes
torsional damping, and iv) it minimizes axial vibrations. hese collars are usually 1/16
less than bit size, and are run to provide maximum stabilization of the BHA.
Spiral Drill Collars: Spiral drill collars decrease the risk of diferential pressure
sticking of the BHA (Figure 7.9). he spiral drill collars usually have slip and elevator
recesses. Stress-relief groove pins and bore back boxes are optional. In directional drilling, spiral drill collars are preferable. he spiral grooves machined in the collar reduce
the wall contact area by 40% for a reduction in weight of only 4%, thus reducing the
chances of diferential sticking. his is likely to happen when the formation is highly
porous, a large overbalance of mud pressure is being used and the well is highly deviated. he problem can be overcome by reducing the contact area of the collar against
the wellbore.
Non-Magnetic Drill Collar: his type of collar is also called a monel drill collars.
Non-magnetic drill collars are usually non-spiral. hey are made of a special nonmagnetic steel alloy (Figure 7.8). hey are manufactured from high-quality, corrosionresistant, austenitic stainless steel. Magnetic survey instruments (MWD/Magnetic
Single Shots/Multi Shots) run in the hole and need to be located in a non-magnetic
drill collar of suicient length to allow the measurement of the earth’s magnetic ield
without magnetic interference. Survey instruments are isolated from magnetic disturbance caused by steel components in the BHA and drill pipe. he primary purpose of
non-magnetic drill collars is to reduce the interference of the magnetic ields associated
with those sections of the BHA, which are both above and below the magnetic compass
contained in the survey tool with the earth’s magnetic ield. Four critical factors play an
important role in selecting non-magnetic collars. hese factors are their total length,
Basics of Drill String Design 331
the location of the survey compass with the non-magnetic collars, the type of material
of which the collars are composed, and distinguishing hot spots.
Medium and Large Round Collars: he purposes of large round collars are to provide stifness next to the drill bit and to add weight to the BHA. he medium collars
add weight to the BHA and reduce ever-present lexure stresses between large collars
and drill pipe or other tools of less rigidity than the large collars. Both may be used for
jarring weight.
Short Drill Collars: Short drill collars (SDC’s) are also called pony collars. hey are
simply shortened versions of a steel drill collar. Short drill collars may be manufactured
or a steel drill collar may be cut to make two or more short collars. For a directional
driller, the SDC and the short non-magnetic drill collar have their widest application
in the make-up of locked BHAs. SDCs of various lengths (e.g. 5’, 10’, 15’) are normally
provided by the manufacturers.
Short Non-Magnetic Drill Collars: It is a short version of the non-magnetic collars.
Cutting a full-length non-magnetic collar oten makes them. he short non-magnetic
collars may be used between a mud motor and an MWD collar to counteract magnetic
interference from below. It is used in locked BHAs, particularly where the borehole’s
inclination and direction give rise to high magnetic interference. It is also used for
BHAs of horizontal wells.
2. Stabilizers: A stabilizer consists of a length of pipe with blades on the external surface and located above the bit. hese blades may be either straight or spiral and there
are numerous designs of stabilizers (Figure 7.10). he blades can either be ixed on to
the body of the pipe, or mounted on a rubber sleeve (sleeve stabilizer), which allows the
drill string to rotate within it. According to the blades, stabilizers can be categorized. he
function of the stabilizer depends on the type of hole being drilled. However, the functions of stabilizers are i) to control hole deviation, ii) to reduce buckling and bending
stresses on the drill collars, iii) to prevent wall thickening, iv) to improve performance of
the bit, v) to allow higher WOB since the string remains concentric even in compression,
vi) to centralize drill collars in hole and increase stifness, vi) increase ability of drill collars to drill smooth straight hole, and vii) to wipe wall of hole to ensure full gage.
3. Jars: his type of tool is used to generate upward or downward loads to free stuck
pipes or release ish (Figure 7.11). here are two types of drilling jars based in its operation: i) hydraulic, and ii) mechanical. Hydraulic jars are stimulated by a straight pull
and give an upword blow. Mechanical jars are present at surface to operate when a given
compression load is applied and given a downward blow. Jars are usually positioned at
the top of the drill collars. Jars are needed when there are sloughing formations, there
are sensitive shales, the mud system does not have good suspension properties, and
there is expensive equipment in BHA.
4. Roller Reamers: Roller reamers are also called drilling reamers. hey consist of
stabilizer blades with rollers embedded into surface of the blade. he rollers may be
made from high grade carburized steel or have tungsten carbide inserts (Figure 7.12).
he reamer acts as a stabilizer and is especially useful in maintaining gauge hole. It is
used to drill a bigger hole. It is also used for any potential hole problems such as doglegs, ledges, and key seats. A roller reamer is a very useful tool for drilling operation,
especially used for the function of stabilization in drilling of the abrasive formation.
332 Fundamentals of Sustainable Drilling Engineering
Figure 7.10 Stabilizers.
Figure 7.11 Jars.
Sleeve dressed
with type ”W”
gth
31”
Nominal
Length
n
Total Le
24”
D
Pin Tool
Joint
11”
21’4”
C
Spiral
Upset
A
Nominal
size
Sleeve Length
42”
D
Box Tool
Joint
B
Elevator
Upset
Diameter
24”
Sleeve
body dia
Basics of Drill String Design 333
DIferent roller
Figure 7.12 Roller reamers.
Crossover
Shock sub
Figure 7.13 Images of various subs.
5. Various Subs: here are various subs used at BHA for diferent purposes. he word
“sub” refers to any short length of pipe, collar, casing, etc., with a deinite function for
drilling operations. he following are some of the subs used during drilling string design.
Crossovers: A crossover sub is used between the drill string and drill collars. Short
joints of pipe to connect two pipes of diferent sizes or thread types are called crossovers
(Figure 7.13).
Shock Subs: Shock subs are also called vibration dampeners (Figure 7.13). hey are
normally located above the bit to reduce the stress due to bouncing when the bit passes
through hard rock. he shock sub absorbs the vertical vibration either by using a strong
steel spring, or a resilient rubber element. he purpose of shock subs is to dampen the
vibration produced by the drill bit and the drill string. It is reasonable to surmise that
shock subs prolong the life of drill bits and drill strings and in some cases the rig. hey
are not as stif (resistance to axial bending) as drill collars and, because of this, oten
have limited application in straight hole drilling. In addition, large drill collars may be
more efective in reducing bottomhole vibrations. Sometimes we use shock absorbers
based on application. he functions of shock absorbers are almost same as shock subs,
which are to: i) reduce or eliminate vertical oscillations, ii) maintain uniform bit load,
iii) increase bit life, iv) increase ROP, and iv) reduce drill collar failures.
334 Fundamentals of Sustainable Drilling Engineering
7.3
Drilling Bit
Technically, the drill bit is not a component of the BHA. However, it does generate and
send axial and torsional loads to the BHA. It is located at the bottom end of the drill
string and makes contact with the subsurface layers, and drills through them. A drilling bit is deined as the cutting or boring tool, which is made up on the end of the drill
string (Figure 7.14). Its basic function is to cut rock at the bottom of the hole. he bit
consists of a cutting element (cutters) and a luid circulation element (nozzles). he
drill bit is rotated mechanically to crush and penetrate new formations. he broken
and loosened rocks are known as cuttings, which are removed from the wellbore by
circulating drilling luid down the drill pipe and through nozzles in the drill bit. he
bit drills through the rock by scraping, chipping, gouging or grinding the rock at the
bottom of the hole. Drilling luid applies hydraulic power to improve penetration rates.
he penetration rate of a bit is a function of several parameters including WOB, RPM,
mud properties and hydraulic eiciency. here are several bit sizes ranges from 3¾
inches to 26 inches in diameters. he most commonly used sizes are 17½, 12¼, 77⁄8, and
6 ¼ inches.
7.3.1
Types of Drilling Bits
here are several types of drill bits manufactured for diferent situations and conditions
encountered during drilling operations. Basically there are two types of drill bits; these
are the ixed-cutter bits, and roller-cone bits. Figure 7.15 shows the detail classiications
Blade Drag Bit
Rolling Cutter Bit
Figure 7.14 Images of typical drilling bits.
Diamond Bit
Basics of Drill String Design 335
Rotary Drilling Bits
Fixed-Cutter Bits
Roller-Cone Bits
Hybrid Bits
Insert Bits
Steel-Cutter Bits
Diamond Bits
Impregnated Bits
MIlled-tooth or
Steel-tooth Bits
Natural Diamond Bit
PDC Bit
TSP Bit
Tungsten-Carbide-Insert
(Tci) Bit
Figure 7.15 Classiication of rotary drilling bits.
Figure 7.16 Examples of drag bit.
of rotary drilling bits. he most common types are the roller-cone bits and diamond
bits. he diamond bit is commonly used in hard formations. Roller-cone bits usually
have three cone-shaped steel cutting devices that are free to turn as the bit rotates.
herefore it is sometimes called as rolling-cutter bit.
1. Fixed-Cutter Bits
A ixed-cutter bit is also called a drag bit. It is deined as a drill bit that has ixed blades,
which are integral with the body of the bit and rotate as a single unit. It is usually
designed for using in sot formations such as sand, clay, or some sot rock. Fixed-cutter
bits have steel wings extending from the central shat of the bit instead of roller cones
(Figure 7.16). In a two-blade bit, the body and blades are stamped as a single unit
(Figure 7.16). hese were the irst bits used in rotary drilling but are no longer in common use. A drag bit is used in drilling water wells that consist of a drill pipe connector
attached to blades on the end. hese wings consist of rigid steel blades shaped like a
ishtail which rotate as a single unit with the drill string since the beginning of rotary
drilling in early 19th century. Due to the dragging/scraping action of this type of bit high
RPM and low WOB are applied.
he main advantages of drag bits are – i) no rolling parts which require strong clean
bearing surfaces, ii) because it is made from one solid piece of steel there is less chance
336 Fundamentals of Sustainable Drilling Engineering
of bit breakage, which would leave junk in the bottom of the hole. he main disadvantages in using drag bits are: i) the introduction of roller cone bits which could drill sot
formations more eiciently, ii) if too much WOB is applied, excessive torque led to
bit failure or drill pipe failure, iii) drag bits tend to drill crooked hole, therefore some
means of controlling deviation is required, iv) drag bits are limited to drilling through
uniformly, sot, unconsolidated formations where there were no hard abrasive layers.
Fixed-cutter bits can be classiied as – i) steel-cutter bits, ii) diamond bits, and
iii) impregnated bits.
i) Steel-Cutter Bits: Drag bits with steel cutter elements are called steel-cutter bits
which look like ishtails (Figure 7.17). It works better relative to other bit types in uniformly sot, unconsolidated formations. As the formation becomes harder and more
abrasive, the bit wear increases rapidly and drilling rate decreases rapidly. his type of
bit is best for sot, uniform, and unconsolidated formations. Now, it is replaced by other
types in all areas.
ii) Diamond Bits: Due to the hardness of diamond, it has been used as a material
for cutting rock for many years. In general, the term “diamond bit” refers to a bit where
diamonds are used as a cutter set at the surface of the contact area. he cutting action
is developed by scraping away the rock and drills by a high-speed ploughing action
that breaks the cementation between rock grains. his type of bit is used in abrasive
formations and is best for hard non-brittle formations. Diamond bits can be classiied
as natural diamond bits, polycrystalline diamond compact (PDC) bits, and thermally
stable polycrystalline (TSP) bits.
Natural Diamond Bits: he hardness and wear resistance of diamond prepared it as a
necessary material for a drilling bit. he natural diamond bit is truly a type of drag bit
since it has no moving cones and operates as a single unit (Figure 7.18). he cutting
action is achieved by scraping away the rock using high RPM. h e face or crown of the
Figure 7.17 Examples of steel cutter bit.
Basics of Drill String Design 337
Figure 7.18 Examples of natural diamond bit.
bit consists of many diamonds set in matrix body. he diamonds are set in a specially
designed pattern and bonded into a matrix on a steel body. Regardless of its high wear
resistance, diamond is sensitive to shock and vibration. herefore great care must be
taken when running a diamond bit. Efective luid circulation across the face of the bit
is also very important to prevent overheating of the diamonds and matrix material. It is
also necessary to prevent the face of the bit becoming grimy with rock cuttings, which
is called bit balling.
he higher cost of diamond bits is the major disadvantage, which is sometimes 10
times more expensive than a similar sized rock bit. In addition, if a roller cutter bit is
selected correctly, a diamond bit will not guarantee higher ROP for the same formation. hey are however cost efective when drilling formations are for long rotating
hours (200 – 300 hours per bit). Since diamond bits have no moving parts they tend
to last longer than roller cone bits. Once the cutting elements have worn down, no
further cutting structure is available. hey can be used for extremely long bit runs.
Longer life of bit reduces the number of round trips, which decreases the capital costs
of the bit. his is essential in ofshore drilling. In addition, the diamonds of the bit can
be extracted which have some salvage value. Natural diamond bit diamonds are set in
a pre-designed pattern that ensures suicient overlap to prevent excessive wear to the
matrix. hese can include both natural diamonds and shaped TSPs. Natural diamond
bits are most suitable when drilling in sot to medium hard formations. As a general
rule, the soter the formation, the bigger the size of diamonds should be set in the bit.
PDC Bits: PDC bits are the new generation of diamond bits known as polycrystalline
diamond compact (PDC) bits (Figure 7.19). PDC bits are also called polycrystalline
diamond (PCD) bits. A new family of drag bits has been made possible by introducing
a sintered polycrystalline diamond drill blank as a bit cutter element since the mid1970s. he drill blanks consist of a layer of a synthetic polycrystalline diamond about
(1/64)-inch thick that is bonded to a cemented tungsten carbide substrate in a highpressure high-temperature (HPHT) process. It contains many small diamond crystals
bonded together. he PDC is bonded either to a tungsten carbide bit-body matrix or to
a tungsten carbide stud that is mounted in a steel bit body. hey perform best in sot,
338 Fundamentals of Sustainable Drilling Engineering
Figure 7.19 Examples of polycrystalline diamond compact bits.
Figure 7.20 Examples of TSP bits.
irm, and medium-hard, non-abrasive formations that are not gummy to avoid bitballing. Good results are obtained in carbonates or evaporates that are not broken up
with hard shale stringers. It is also good in a sandstone, siltstone, and shale. h e design
of the crown proile is important. Double-cone and lat proiles are also used which are
called dual-diameter bits.
TSP Bits: A further development of the PDC bit concept was the introduction in the
late 1980s of TSP diamond bits (Figure 7.20). hese bits are manufactured in a similar
fashion to PDC bits but are tolerant of much higher temperatures than PDC bits. TSP
bits are manufactured similarly to PDC bits except TSP bits can resist much higher
operating temperatures than PDC bits.
iii). Impregnated Bits: Impregnated-bit bodies are PDC matrix materials that are similar to those used in cutters. he working portions of impregnated bits are unique, such
that they contain matrix impregnated with diamond (Figure 7.21). Both natural and
synthetic diamonds are prone to breakage from impact. When embedded in a bit body,
they are supported to the greatest extent possible and are less susceptible to breakage. However, because the largest diamonds are relatively small, cutting depth must be
smaller and ROP must be achieved through increased rotational speed. hey are most
frequently run in conjunction with turbo drills and high-speed positive displacement
motors that operate at several times the normal rotational velocity for rotary drilling
(500 – 1,500 rpm). Diamond impregnated bits are also used in full-size conventional
drilling (Figure 7.21) when a turbine is used to provide high rotary speed. Turbines
Basics of Drill String Design 339
Figure 7.21 Examples of Impregnated bits.
are available that have no rotating elastomeric seals, so they can withstand high temperatures, but their high rotary speed is not compatible with rotary bits, so diamond
impregnated bits are used. During drilling, individual diamonds in a bit are exposed
at diferent rates. Better bit performance and reduction in the number of required bits
have been reported in abrasive and heterogeneous formations when impregnated bits
with turbines are used instead of roller cone bits and PDCs (Botelho et al., 2006). hese
bits are generally only used when nothing else will work—the rate of penetration is low,
they are extremely expensive, and they cannot be repaired when worn.
2. Roller-Cone Bits
he most common type of bit used worldwide is the roller cone bit. It is also called a
rolling cutter bit or simply a rock bit (Figure 7.22). he cutting action is provided by
cones having either steel teeth or tungsten carbide inserts that drill holes predominantly with a grinding and chipping action. he irst successful rock bit was designed
by Hughes in 1909 which was a major innovation since it allowed rotary drilling to be
extended to hard formations. he irst design was two or more cones containing the
cutting elements, which rotate about the axis of the cone as the bit is rotated at the bottom of the hole. However, the three-cone rolling cutter bit is by far the most common
bit. hese bits are mounted on bearing pins, or arm journals, which extend from the bit
body. Figure 7.23 shows the roller cone bearing used in rolling cutter bits.
Rolling cutter bits have improved a lot over time. In the early stages, the bit did not
have self-cleaning option. Proper bottomhole cleaning is very important where luid
low through jets in the bit (i.e. nozzles) is responsible for the cleaning (Figure 7.24a).
herefore, the three-cone bit is developed where a straight hole exists and intermeshing teeth for better cleaning are introduced (Figure 7.24). Other improvements include
hard-facing on the teeth and body, steel and milled tooth, carbide tooth (tungsten
carbide insert), change from water courses to jets (Figure 7.24b), sealed bearings, and
340 Fundamentals of Sustainable Drilling Engineering
(a) For soft formation
(b) For hard formation
Figure 7.22 Roller cone bits.
Figure 7.23 Roller cone bearing.
journal bearings. Roller cone bits are available with a large variety of tooth design and
bearing types. he major disadvantages include the limited space, cone ofset to stop
rotating periodically to scrape the hole like PCD bits, and faster tooth wear. he major
advantages of the roller cone bits are jet bits through which drilling luid exits from the
Basics of Drill String Design 341
Figure 7.24 Roller cone bits with straight hole nozzle.
Figure 7.25 Insert roller cone bit (photo courtesy of Reed-Hycalog NOV.)
bit through nozzles between the cones. hus it creates high velocity jets of mud. his
will help lit cuttings away from the bit. Other advantages include:
1.
2.
3.
4.
5.
6.
7.
For any type of formation, there is a suitable design of rock bit
It is available with a large variety of tooth design and bearing types
It can handle changes in formation
It has an acceptable life and drilling rate
It has a reasonable cost
he use of tungsten carbide for hard-facing and gauge protection
he introduction of sealed bearings to prevent mud causing premature
failure due to abrasion and corrosion of the bearings
Rock bits are classiied as “milled tooth” or “insert” depending on the cutting surface of
the cones. As mentioned in Figure 7.15, the roller-cone bit can further be classiied as
insert bit, milled-tooth or steel-tooth bit, and tungsten-carbide-insert (TCI) bit.
i) Insert Bit: In insert bits, the cutting structure is a series of inserts pressed into the
cones (Figure 7.25). Insert bits are used in medium to hard formations, with the size,
shape, bearings, and number of inserts. hese parameters are varied to it the speciic drilling conditions. he bits are available with either roller or journal bearings
depending on the operating conditions. he bearings, seals, and lubricants should all
342 Fundamentals of Sustainable Drilling Engineering
be speciied to withstand high temperatures if the bits are to be used in geothermal
drilling.
ii). Milled-tooth Bit: In milled-tooth bit, the cutting structure is milled from the
steel making up the cone (Figure 7.26). he cutters have inner rows of teeth that are
intermeshing. So, uses of inner rows are advantageous. On the other hand, the outerrow of teeth (i.e. heel teeth) has no intermeshing which creates very diicult job. It
wears and leads to out of gauge bit (i.e. hole). Normally long teeth arrangements are
used for sot formations and shorter teeth for harder formations. Cone ofset of bit
results in scraping, gouging action in sot-formation. It also provides high drilling rates
especially in soter rocks.
iii). TCI Bit: he TCI bits are manufactured by pressing a tungsten carbide cylinder
into accurately machined holes in the cone (Figure 7.27). he tungsten carbide teeth
designed for drilling sot formations are long and have a chisel-shaped end. he various
types of insert bit tooth designs are shown in Figure 7.28. TCI bit has long life cutting
structure in hard rocks and has hemispherical inserts for very hard rocks. It has larger
and more pointed inserts for soter rock and can handle high bit weights and high
RPM. he inserts of TIC fail through breakage rather than wear because the tungsten
carbides are very hard and brittle material.
3. Hybrid Bits
he research on developing hybrid bits was done in the early 1930s. However, it was
deemed impractical and even unreasonable. Due to the technological advancement in
21st century, it has become a reality. Over the last 100 years, many technologies have had
signiicant impact on the drilling industry. Advancement on the rotary rig, rolling bits,
top drive, and PDC bits are some of the revolutionary technologies that have changed
the way operators drill wells. he everyday demands and challenges faced by the industry have become even more diicult. For example, complex well proiles, hard and
inter-bedded formations, and rig or equipment limitations increase the potential for
shorter runs. However, these shorter run cause expensive tool damage, and ultimately
reduce operator proitability. While PDC performance has improved signiicantly, it
still is subject to dynamic ineiciencies in terms of higher torque luctuations and overall level of torque generated. Similarly, enhancements in roller cone technology could
provide improvements in ROP or overall footage, but continue to be burdened with the
Figure 7.26 Milled-tooth bit.
Basics of Drill String Design 343
Figure 7.27 Tungsten carbide insert bit.
Soft Formation Inserts
Gage compact
Ovoid
Ogive
Conical
90° Chisel
Wedge Crested Chisel
Soft to Medium Formation Inserts
Medium to Hard Formation Inserts
Hard Formation Inserts
Scoop Chisel
Blunt Chisel
Sharp Chisel
Figure 7.28 Example tungsten carbide insert cutter used in rolling cutter bits (Bourgoyne et al., 1986).
inherent limitations of the technology. As a result, in the same spirit, Hybrid bit development came into picture through Baker Hughes Inc (Figure 7.29).
Hybrid drilling technology is a paradigm shit in innovation, a coalescence of
roller cone and PDC bits into a single design. he result is a technology designed to
exploit the best attributes of each bit type, bridging the gap between them. With the
cutting superiority and continuous scraping of diamond bits and the rock-crushing
strength of roller cones, this repairable bit has proven to survive highly inter-bedded
formations with smooth drilling and excellent tool face control. In the most complex
applications, hybrid drill bit technology combines roller cones and PDC ixed cutters
into a single bit to reduce drilling time, to create smoother drilling, remarkable torque
management, and precise steerability. Leveraging the cutting superiority of PDCs in
344 Fundamentals of Sustainable Drilling Engineering
Figure 7.29 Example of Hybrid Bit.
sot formations and the rock-crushing strength and stability of roller cones in hard or
inter bedded formations, the hybrid bit has the potential to maintain higher overall
ROP for more footage than a roller cone or PDC could individually. A superior directional bit for motor and rotary applications, the hybrid bit provides increased buildup
rate capabilities, dampened torque response, and precise steerability on a variety of
bottomhole assemblies. he hybrid bit is improving drilling rates in tough applications worldwide. Laboratory tests and ield performances conirm beneits of the
combined technology. Compared to PDC bits, the hybrids have – i) lower and more
consistent drilling torque, ii) better dynamics and directional control, iii) improved
durability and reliability in inter bedded formations, and iv) less torsional vibration
(stick/slip). Compared to traditional roller cone bits, they have – i) increased rate of
penetration (ROP) potential, ii) less axial vibration (bit bounce), and iii) lower weight
on bit requirement.
7.4 Drill String Design
he objective of designing the drill string is to obtain the optimum size and length
of diferent drill string components in terms of durability and cost efectiveness. An
iterative approach is usually applied due to the inherent complexity of the problem.
In general a design model is initially assumed. Based on the initial consideration,
the components of the drill string are selected, and then incorporating factors that
were overlooked during the irst step reines the design. During the design, a good
knowledge of drill string performance properties (available sizes, grades, etc.), previous history of drilling in similar conditions, and also costs associated with drill string
Basics of Drill String Design 345
components. he following design criteria should be considered while designing the
drill string.
1. Design involves the determination of:
a. Length
b. Weight
c. Grades
2. Factors afecting the design:
a. Hole or depth size
b. Mud weight
c. Safety factor
d. Length/weight of DC
e. DC sizes
3. Design should be tested for the following criteria:
a. Tension
b. Collapse
c. Critical speed
d. Shock loading
e. Torsion
f. Stretch
4. Design should follow the following procedure
a. Tension
b. Collapse
c. Others (if necessarily)
However, there are some other major standards that need to be satisied at the inal
stage of the design. hese criteria are: i) the load capacity divided by a SF of any drill
string component should be greater than or equal to the maximum permissible load,
ii) the neighbouring elements must be well-suited which is accomplished by selecting
elements with an appropriate bending-stress ratio, iii) the drill string geometric properties should be selected in conjunction with an optimal hydraulic and casing program,
iv) in deviated wells, drill string rotation should not produce excessive wall and casing
damage, and v) a minimum level of the cost of the string should be maintained. In
summary design of drill string means determination of length, weight, grades of drill
pipe to be used during drilling, coring or any other operation which depends on hole
depth, hole size, mud weight, safety factor and/or margin of pull (MOP), length and
weight of DCs, and drill pipe size. he design factors such as tension, collapse, and
other factors – shock loading, torsion, stretch of pipe, and critical rotating speed need
to be considered.
he main factors considered in the selection of drill strings are i) the collapse load,
and ii) the tensile load on the drill pipe. Burst pressures are not generally considered
since these only occur when pressuring up the string on a plugged bit nozzle or during
a DST. However, it is very unlikely that the burst resistance of the pipe will be exceeded.
Torsion is not needed to be considered except in a highly deviated well. Once the
collapse and tension loads have been quantiied, the appropriated weight and grade of
the drill pipe can be selected.
346 Fundamentals of Sustainable Drilling Engineering
In general, a graphical approach to drill string design is recommended. If one section of the string does not meet requirements, it must be upgraded. he procedure can
be listed as – i) choose a weight and grade of pipe to satisfy the collapse conditions, ii)
using the pipe chosen in (i), calculate the tension loading, including buoyancy efects,
iii) draw the tension loading line and also the maximum allowable load line, iv) modify
the tension load as given in (ii) by applying a design factor, MOP etc., v) generate three
design lines, vi) if any of these design lines exceed the maximum allowable load, a
higher rated drill pipe must be used for that section of pipe, vii) calculate the new tension loading line for the new drill string and repeat steps (v) and (vi).
7.4.1
Collapse Load
Collapse pressure can be deined as a required external pressure that causes yielding of
the drill pipe or casing. It can also be deined as the diference between external and
internal pressure (Figure 7.30). he collapse pressure will occur if the drill pipe is empty
(i.e. no mud). It develops due to the diference in pressure inside and outside of drill
pipe (Figure 7.31a). In normal operation the mud column inside and outside the drill
pipe are both equal in height and in density (Figure 7.31b). herefore zero diferential
pressure across pipe body exists and thus no collapse happens. Normally, collapse pressure will happen during DST test.
Pc = 0
D
X
(a)
(b)
(c)
Figure 7.31 Collapse pressure at diferent situations for a typical drill pipe.
outside
inside
outside
inside
D-X
Figure 7.30 Collapse pressure.
Basics of Drill String Design 347
he highest external pressure tending to collapse the drill string will occur at the
bottom when the drill string is run empty into the hole. If a non-return valve is run, it is
normally standard practice to i ll up the pipe at regular intervals when running in. he
highest anticipated external pressure on the pipe can be written as:
0.052
PC
(7.1a)
LTVD
f
where,
PC = collapse pressure, psi
= density of luid outside the drill pipe, ppg
f
LTVD = total true vertical depth of the well at which PC acts, t.
Equation (7.1a) can also be expressed as:
PC
LTVD
f
(7.1b)
144
where,
PC = collapse pressure, psi
= density of luid outside the drill pipe, lb f / ft 3
f
LTVD = true vertical depth at which PC acts, t.
Equation (7.1) is based on the assumption that there is no luid inside the pipe to resist
the external pressure. he collapse resistance of the drill pipe is given in Tables 7.4. he
collapse resistance of the drill pipe is generally derated by a design factor (i.e. divide
the collapse rating by 1.125). A suitable grade and weight of drill pipe must be selected
whose derated collapse resistance is greater than Pc. his string must then be checked
for tension.
If there are diferent luids inside and outside the drill pipe, the diferential collapse
pressures across the drill pipe prior to opening of the DST tool (Figure 7.31a) can be
obtained as:
pc
where,
D
X
inside
outside
0.052 D
outside
0.052 D X
inside
(7.2)
= total depth of luid column or drill pipe, t.
= depth of the empty drill pipe, t.
= density of luid inside the drill pipe, ppg
= density of luid outside the drill pipe, ppg
When luid density inside and outside the drill pipe is the same (Figure 7.31b), i.e.
outside
inside
pc
0.052 D
(7.3)
When the drill pipe is completely empty, X = 0, and inside 0, the diferential collapse
pressures across the drill pipe would be the maximum collapse pressure (Figure 7.31c)
and hence Eq. (7.2) can be reformed as:
pc
max
0.052 D
outside
(7.4)
348 Fundamentals of Sustainable Drilling Engineering
A safety factor in collapse can be determined by
SF
Collapse resistance
Collapse pressure pc
(7.5)
Normally a safety factor of 1.125 is considered for the collapse rating. In general the
drill pipe is subjected to biaxial loading due to the combined loading of tension and
collapse. Due to the biaxial loading, the drill pipe is stretched resulting in a decrease in
its collapse resistance.
Burst pressure develops when the internal pressure is higher than that of the external
pressure. It can be rated as:
pb
Internal pressure External pressure
(7.6)
where,
pb = burst load or pressure, psi
A safety factor in burst can be determined by
SF
Burst rating
Allowable burst
(7.7)
7.4.2 Tension Load
he tensile strength of the drill pipe is shown in Table 7.4. he tension loading can be
calculated from the known weights of the drill collars and drill pipe below the point
of interest. he efect of buoyancy on the drill string weight, and therefore the tension,
must also be considered. Buoyancy forces are exerted on exposed horizontal surfaces
and may act upwards or downwards. hese exposed surfaces occur where there is a
change in cross-sectional area between diferent sections (Figure 7.32). he load calculation can be started at the bottom of the drill string and worked up to the top. he
tension loading can be determined for each depth. his is represented graphically by
the tension loading line (Figure 7.32).
If the drill pipe is to remain in tension throughout the drilling process, drill collars
need to be added to the bottom of the drill string. he buoyant weight of the drill collars
must exceed the buoyant force on the drill pipe. In addition, the neutral point shown
in Figure 7.32 must be within the length of the drill collars. Drill collars are required to
maintain the drill string in tension because the function of the drill collars is to provide
WOB. When selecting the drill pipe, the maximum tensile loads that the string could be
subjected to need to be considered. In addition to the design load calculated on the basis
of the string hanging freely in the wellbore, some other safety factors and margins are
generally added: i) design factor - it is generally added to the loading line calculated above
(in general, multiply by 1.3) which allows for extra loads due to rapid acceleration of the
pipe, ii) margin of overpull (MOP) - it is generally added to the loading line because this
allows for the extra forces applied to the drill string when pulling on stuck pipe.
Tabulated API properties should be considered for designing tension. he magnitude
depends on mud density and steel density where submerged weight should be considered. In general steel density is considered 489.5 lbm/t.3 or 65.5 lbm/ gal or 7850 kg/m3.
Basics of Drill String Design 349
To provide an added safety factor, only 80–90% of the yield strength tabulated is generally used for the drill pipe. herefore, the weight and length of the drill pipe can be
calculated using the load balance of the drill string as:
0.9 × drill pipe yield strength = weight of DP + weight of DC
+ weight of HWDP + MOP
(7.8)
where,
MOP = margin of overpull or maximum overpull on the drill string by the drawworks, lbf
MOP is the minimum tension force above expected working load to account for any
drag or stuck pipe. he typical MOP value ranges from 50,000 – 100,000 lbs. Maximum
overpull should not exceed 80% of tensile strength of weakest drill pipe section in the
drill string.
Mathematically, Eq. (7.8) can be written as:
0.9 Pd
LdpWdp LdcWdc LHdpWHdp B f
(7.9)
MOP
Here,
Pd = drill pipe yield strength or design weight, lbf
Ldp = length of drill pipe, t.
Ldc = length of drill collar, t.
LHdp = length of heavy weight drill pipe, t.
Wdp = nominal weight of the drill pipe, lbf/t.
Wdc = nominal weight of the drill collar, lbf/t.
WHdp = nominal weight of the heavy weight drill pipe, lbf/t.
B f = buoyancy factor, fraction = 1 m / s
= mud density, lbm/gal
m
=
density of steel, lbm/ t.3
s
Compression(-)
Tension (+)
D
Drill Pipe
D
w2
f2
C
A
f1
B
Drill Collars
B
w1
C
A
f1
Figure 7.32 Axial Load distributions on the Drill String.
** Not API standard: shown for information only.
Collapse Pressure
Internal Yield Pressure
Tensile Strength
Internal Internal
weight
Size of
per foot Diameter Diameter
outer
D
E
G** S.135**
at Full
(in.)
with
Diameter
D
E
G**
S.135**
D
E
G**
S.135
1,000
1,000
1,000
1,000
Upset
Coupling
(in.)
(psi)
(psi)
(psi)
(psi)
(psi)
(psi)
(psi)
(psi)
(lbf)
(lbf)
(lbf)
(lbf)
(in.)
(lbf)
2 3⁄8
4.85
1.995
1.437
6,850** 11,040 13,250 16,560 7,110** 10,500 14,700 18,900
70
98
137
176
6.65
1.815
1.125
11,440 15,600 18,720 23,400 11,350 15,470 21,660 27,850
101
138
194
249
2 3⁄8
6.85
2.441
1.875
–
10,470 12,560 15,700
–
9,910 13,870 17,830
–
136
190
245
2 7⁄8
2 7⁄8
10.40
2.151
1.187
12,770 16,510 19,810 24,760 12,120 16,530 23,140 29,750
157
214
300
386
1
9.50
2.992
2.250
–
10,040 12,110 15,140
–
9,520 13,340 17,140
–
194
272
350
3 ⁄2
3 1⁄2
13.30
2.764
1.875
10,350 14,110 16,840 21,170 10,120 13,800 19,320 24,840
199
272
380
489
15.50
2.602
1.750
12,300 16,770 20,130 25,160 12,350 16,840 23,570 30,310
237
323
452
581
3 1⁄2
4
11.85
3.476
2.937
–
8,410 10,310 12,820
–
8,600 12,040 15,470
–
231
323
415
4
14.00
3.340
2.375
8,330
11,350 14,630 17,030
7,940
10,830 15,160 19,500
209
285
400
514
13.75
3.958
3.156
–
7,200
8,920
10,910
–
7,900 11,070 14,230
–
270
378
486
4 1⁄2
4 1⁄2
16.60
3.826
2.812
7,620
10,390 12,470 15,590
7,210
9,830 13,760 17,690
242
331
463
595
1
20.00
3.640
2.812
9,510
12,960 15,560 19,450
9,200
12,540 17,560 22,580
302
412
577
742
4 ⁄2
5
16.25
4.408
3.750
–
6,970
8,640
10,550
–
7,770 10,880 13,960
–
328
459
591
5
19.50
4.276
3.667
7,390
10,000 12,090 15,110
6,970
9,500 13,300 17,100
9
396
554
712
5 1⁄2
21.90
4.778
3.912
6,610
8,440 10,350 12,870
6,320
8,610 12,060 15,500
321
437
612
787
24.70
4.670
3.500
7,670
10,460 12,560 15,700
7,260
9.900 13,860 17,820
365
497
696
895
5 1⁄2
19.00**
4.975
4.125
4,580
5,640
–
–
5,090
6,950
–
–
267
365
–
–
5 9⁄16
5 9⁄16
22.20**
4.859
3.812
5,480
6,740
–
–
6,090
8,300
–
–
317
432
–
–
9
25.25**
4.733
3.500
6,730
8,290
–
–
7,180
9,790
–
–
369
503
–
–
5 ⁄16
6 5⁄8
22.20**
6.065
5.187
3,260
4,020
–
–
4,160
5,530
–
–
307
418
–
–
25.20
5.965
5.000
4,010
4,810
6,160
6,430
4,790
6,540
9,150 11,770
359
489
685
881
6 5⁄8
6 5⁄8
31.90**
5.761
4.625
5,020
6,170
–
–
6,275
8,540
–
–
463
631
–
–
* Collapse, internal yield and tensile strengths are minimum values with no safety factor. D.F.G.S–135 are standard steel grades used in drillpipe.5
Table 7.4 Dimensions and Strength of API Seamless Internal Upset Drill Pipe.
350 Fundamentals of Sustainable Drilling Engineering
Basics of Drill String Design 351
From Eq. (7.9), the total weight carried by the top joint of drill pipe is given by
Pa
(7.10a)
LdpWdp LdcWdc LHdpWHdp B f
If we use safety factor, Eq. (7.10a) can be written as:
Pa
LdpWdp LdcWdc LHdpWHdp B f
(7.10b)
SF
Here,
Pa = actual weight or total weight carried by the top joint, lbf
To provide an added safety factor of 90%, the theoretical yield strength can be calculated as:
Pt
0.9 Pd
(7.11)
Here,
Pt = theoretical yield strength, psi
If Pa < Pd, then pipe is ok for tension. In general, the diference between Pt and Pa gives
the MOP.
he ratio of Eq. (7.11) and Eq. (7.10) gives the safety factor (SF) as:
SF
Pt
Pa
0.9 Pd
(7.12)
LdpWdp LdcWdc B f
Safety factor is normally in the range of 1.1–1.3. It is noted that SF is not applied for
heavy weight drill pipe. In such case, Eq. (7.9) can be written in terms of SF as:
0.9 Pd
LdpWdp LdcWdc B f
SF LHdpWHdp B f
MOP
(7.13)
hus length of the drill pipe can be found by rearranging Eq. (7.13) as:
Ldp
0.9 Pd MOP
SF Wdp B f
Wdc
L
Wdp dc
WHdp LHdp
Wdp SF
(7.14a)
If we do not consider SF, length of the drill pipe can be found by rearranging Eq. (7.9) as:
Ldp
0.9 Pd MOP
Wdp B f
Wdc
L
Wdp dc
WHdp
Wdp
LHdp
(7.14b)
If dual-grade drill pipe is used at diferent section of drill string, the length of drill pipe
is calculated as:
Ldp2
0.9 Pd MOP
SF Wdp2 B f
Wdp1
Wdp2
Here,
Ldp1 = length of drill pipe grade 1, t.
Ldp2 = length of drill pipe grade 2, t.
Ldp1
Wdc
L
Wdp2 dc
WHdp LHdp
Wdp2 SF
(7.15)
352 Fundamentals of Sustainable Drilling Engineering
Wdp1 = nominal weight of the drill pipe grade 1, lbf/t.
Wdp2 = nominal weight of the drill pipe grade 2, lbf/t.
A tapered string is designed by irst considering the lightest available grade and selecting its maximum useable length as a bottom section. Successive heavy grades and their
usable lengths are selected in turn.
Example 7.1: A drill string needs to be designed based on the information given here. It
is noted that the outer diameter of the drill pipe is 5 , total vertical depth is 12,000 and
mud weight is 75 lbf/t.3 (i.e. 10 ppg). Total MOP is 100,000 lbs and the design factor,
SF = 1.3 (tension); SF = 1.125 (collapse). he bottomhole assembly consists of 20 drill
collars with an outer diameter of 6.25 and an inner diameter of 2.8125 where the
weight of drill collar is 83 lbf/t. and each collar is 30 t. long. In addition, you need to
consider the length of slips is 12”.
Solution:
Given data:
dodp
= outer diameter of drill pipe = 5 in
LTVD = total vertical depth = 12,000 t.
= mud weight = 75 lbf/t.3 (10 ppg)
m
MOP = margin of pull = 100,000 lbs
= design factor of safety for tension = 1.3
SFT
= design factor of safety for collapse = 1.125
SFc
= number of drill collar = 20
Ndc
dodc
= outer diameter of drill collar = 6.25 in
didc
= inner diameter of drill collar = 2.8125 in
Wdc
= weight of the drill collar = 83 lbf/t.
= length of drill collar = 30 t.
Ldc
= length of slips = 12 in
Lslips
Required data:
Design the drill string
For Collapse loading:
If the total vertical depth is 12,000 t., and the mud density is 10 ppg, then collapse pressure can be calculated using Eq. (7.1a) as:
PC
0.052 LTVD
m
0.052 12,000 ft 10 ppg
6,240 psi
If we use 75 lb f / ft 3 mud, collapse pressure can be calculated using Eq. (7.1b) as:
PC
LTVD m
144
12,000 ft 75 lb f / ft 3
144 in2 / ft 2
6,250 psi
Applying SF for collapse, PC 6,250 psi 1.125 7,031 psi
Now from Table 7.4, choose 19.50 lbf/t. for 5” and we select Grade D for which
ID = 4.276”.
Basics of Drill String Design 353
For Tension loading:
f
BF 1
75 lb f / ft 3
1
490 lb f / ft 3
s
0.847
Now if we apply Eq. (7.10b) to calculate actual weight or total weight carried by the top
joint, it becomes as:
Pa
MOP
LdpWdp LdcWdc
BF SFT
100,000
12,000 20 30
400,000 lb f
19.5
20 30
83
0.847 1.3
From Table 7.4, for 5” and 19.5 lbf/t. drill pipe, Pt = 396,000 lbf for Grade E and
= 290,000 lbf for Grade D
Decision: We need to select Grade E instead of Grade D because of the huge diference
in tensile strength. However, as long as the actual weight is greater than the theoretical yield strength (i.e. P >Pt), the selected design of Grade E is not OK and needs to be
veriied again.
As the chosen grade is not ok, let us choose the next grade which is 5 ½ outer diameters. For this grade, let us choose the weight of the drill pipe as 21.90 lbf/t. and grade
E for which the tensile yield strength is 437,000 lbf. Now, apply the chosen grade for the
entire pipe.
For Tension and Compression loading (Figure 7.33):
At 12,000 t. i.e. the bottom of DC:
0.052 LTVD
PdC _ bottom
m
0.052 12,000 ft 10 ppg
6,240 psi
Cross sectional area of DC:
Referring to Figure 7.33,
AdC _ bottom
F1_ bottom
4
2
dOd
did2
4
6.252 2.8122
24.47 in2
PdC _ bottom AdC _ bottom 6,240 24.47 152,692.8 lbs
W1_ dc LdC
20 30 83 49,800 lbs
dc
So, tension at the bottom of the collar at point 1 = F1_ bottom = 152,692.8 lbs (Tension)
At 11,400 t. i.e. the top of DC:
AdC _ top
2
dOd
did2
6.252 5.02
4
PdC _ top
4
0.052 LTVD
F2 _ top
PdC _ top
m
outer
2
dOd
did2
4.2762 2.81252
inner
19.19 in2
0.052 11, 400 ft 10 ppg
AdC _ top
5,928 psi
5,928 19.19 113,758 lbs
354 Fundamentals of Sustainable Drilling Engineering
W2 _ dc
Ldp
dp
11, 400 ft 19.5
222,300 lbs
So, tension at the top of the collar at point 2 = F1_ bottom W1_ dc = (–152,692.8 + 49,800) lbs
= 102,892.8 lbs (Compression)
At 11,400 t. i.e. the bottom of the DP (Point 3):
2
d2 d2
dOd
did2
19.19 in2
inner
4 Od id outer
0.052 LTVD m 0.052 11, 400 ft 10 ppg 5,928 psi
Adp _ bottom
Pdp _ bottom
F3 _ bottom
Pdp _ bottom
W3 _ dp
Ldp
Adp _ bottom
dp
5,928 19.119 113,758.0 lbs
11, 400 ft 19.5
222,300 lbs
So, tension at the bottom of the drill pipe at point 3 = T2dp dc
F3_ bottom
= ( 102,892.8 + 113,758) lbs
= 10,865.2 lbs (Tension)
At the top of the DP (Point 4):
W4 _ dp
F4 _ top
Ldp
dp
11, 400 ft 19.5
222,300 lbs
tension at the bottom of the drill pipe at point 3 T3
10,865.2 lbs
So, tension at the top of the drill pipe at point 4 = W4 _ dp F4 _ top
= 222,300 lbs 10,865.2 lbs
= 233,165.2 lbs (Tension)
Total weight carried
by top joint
4
400,000
Compression(-)
200,000
0
Tension(+)
200,000
Drill pipe = 11,400 ft
0
6,000
1
Drill Collar
= 20 x 30 ft
=600 ft
2
3
12,000
Figure 7.33 Axial Load distributions on the Drill String for Example 7.1.
400,000
Basics of Drill String Design 355
Maximum allowable load:
If we assume that 85% of theoretical load can be allowed to carry by the drill string,
then the maximum allowable load is:
W4 _ dp
0.85 Pt
0.85 396,000 lbs
335,750 lbs
he total weight carried by the top joint, 400,000 lbs and as the maximum allowable
load is 335,750 lbs, therefore a diferent size of the drill pipe need to be selected for
at least 1,200 t. (Figure 7.34). From Table 7.4, for 5.5” and 21.90 lbf/t. drill pipe, Pt =
437,000 lbf for Grade E. this grade can be selected up to 1,200 t.
Decision:
We may choose the next grade for only the irst 1,200’
0 – 1,200 t.
: Grade E, 21.90 lbf/t.
200 – 12,000 t. : Grade E, 19.5 lbf/t.
Check the new Grade:
Now if we apply again Eq. (7.10b) to calculate actual weight or total weight carried by
the top joint, it becomes:
Pa
Pa
100,000
MOP
1,200 21.5
LdpWdp LdcWdc
10,800 20 30
BF SFT
19.5
20 30
83
0.847 1.3
402,251.95 lb f
Table 7.4 shows, Pt = 437,000 lbf/t, and inally it shows that Pa < Pt. herefore, the
design is ok and this is the inal design decision.
Total weight carried
by top joint
400,000
4
Compression(–)
200,000
0
Tension(+)
200,000 400,000
0
6,000
3
1
Drill Collar
= 20 x 30 ft
= 600 ft
2
335,750 lbs
Maximum allowable load
Drill pipe = 11,400 ft
1,200
12,000
Figure 7.34 Axial Load and maximum load distributions on the Drill String for Example 7.1.
356 Fundamentals of Sustainable Drilling Engineering
7.4.3 Other Design Factors
Shock Load: It arises between slip area set and the moving drill pipe. When a moving
drill pipe is suddenly stopped by setting slips, shock load develops. he additional tensile force generated due to this shock load can be obtained as
(7.16)
3,200 Wdp
Fs
Here,
Wdp = weight of drill pipe per unit length, lbf/t.
Torsion: Torsion in a drill string is produced by a twisting moment. his moment is
called torque which results in a shear or torsional stress and an angle. he shear stress
and the diferential angle of twist can be calculated as:
d t
dz
Here
T
r
di
do
Ip
Es
E
t
Tr
Ip
(7.17)
T
Es I p
(7.18)
= shear or torsional stress, psi
= torque, in-lbf
= distance from the center of the drill pipe to a point under consideration
di 2r do , in
= inside diameter of drill pipe, in
= outside diameter of drill pipe, in
do4 di4 , in4
= polar moment of inertia =
32
E
= shear modulus of elasticity =
21
= Young’s modulus of elasticity, psi
= Poisson’s ratio, (the ratio of transverse contraction strain to longitudinal extension strain in the direction of stretching force.
= angle of twist, radian
trans
)
longitudinal
d t
= diferential angle of twist, in–1
dz
he maximum shear stress occurs at the outer ibre of the pipe, and for this case
Eq. (7.17) can be written as:
16 doT
max
where
Z p = polar sectional modulus, psi
do4
di4
T
Zp
(7.19)
Example 7.2: A drill string has 3000 t. long, and 5.5 in outer diameter drill pipe. While
the pipe was moving, it was suddenly stopped. A torque of 200 lbf-in is applied which
Basics of Drill String Design 357
develops torsional stress and angle at a distance of 5.124 from the center of the pipe.
Assume that the Young’s modulus of elasticity for steel is 29 106 psi and Poisson’s ratio
is 0.44. Find out the shock load, torsional stress, maximum shear stress and diferential
angle of twist.
Solution:
Given data:
dodp = outer diameter of drill pipe = 5.5 in
Ldp = total drill pipe length = 3,000 t.
T
= torque = 200 in-lbf
r
= distance from the center of the drill pipe to the point = 5.124 in
E
= Young’s modulus of elasticity = 29,000000 psi
= Poisson’s ratio = 0.44
wdp = weight per feet = 21.9 lbf/t.
From Table 7.4,
didp = inner diameter of drill pipe = 4.778 in
wdp = weight per feet = 21.9 lbf/t.
Required data:
= shear or torsional stress in psi
Fs
= shock load in lbf
d t
= diferential angle of twist, in–1
dz
Applying Eq. (7.16), shock load can be calculated as:
Fs
3,200 Wdp
3,200
210.24 ×106 psi
3,000 21.9
he shear stress can be calculated using Eq. (7.17) as:
Tr
Ip
200 lb f
32
in
do4
5.124 in
di4
200 lb f
32
5.5
4
in
5.124 in
4.778
4
in
26.5
4
lb f
in2
26.5 psi
he diferential angle of twist can be calculated applying Eq. (7.18) as:
d t
dz
T
Es I p
200 lb f
T
E
21
7
32
5.14 ×10 in
do4 di4
in
29,000000 psi
5.54 4.7784
2 1 0.44
32
1
he maximum shear stress is calculated by Eq. (7.19) as:
16 doT
max
do4 di4
16 5.5 in
200 lb f
5.54 4.7784
in
in4
17, 600 psi
in4
358 Fundamentals of Sustainable Drilling Engineering
he torque developed in the drill string can be calculated if the horsepower required to
rotate the string is obtained by recalling Eq. (2.1) for a given rpm as:
T
5252 HPds
N
(7.20)
where
HPds = horsepower required to turn the rock bit and drill string, hp
N = drill string rotary speed, rev/min
T
= torque, t.-lbf
he horsepower required to rotate the drill pipe is given as:
HPdp
Cd do2 NLdp
(7.21)
m
Here
HPp = horsepower required to rotate the drill pipe, hp
Cd = an empirical factor that depends on hole inclination angle (0.000048 –
0.00000665 for hole angles ranging from 3 to 5°)
=
specii
c gravity of mud
m
Example 7.3: While drilling, 250 hp was applied to rotate the drill string and bit where
500 rpm was recorded from the rotary speed machine. In addition, 175 hp was applied
to rotate 3,500 t. of drill pipe of 5 in OD with the same speed as drill string. Assume
that Cd = 0.000005. Calculate the required torque for drilling string and the speciic
gravity of mud.
Solution:
Given data:
HPds = horsepower required to turn the rock bit and drill string = 250 hp
N = drill string rotary speed = 500 rev/min
HPp = horsepower required to rotate the drill pipe = 175 hp
Cd = an empirical factor that depends on hole inclination angle = 0.000005
Ldp = length of drill pipe = 3,500 t.
Cd = outer diameter of drill pipe = 5 in
Required data:
T
= torque in t.-lbf
= speciic gravity of mud
m
Applying Eq. (7.20), the torque developed in the drill string can be calculated as:
T
5252 HPds
N
5252
250 hp
500 rpm
2626 lb f
in
he speciic gravity of mud is calculated using Eq. (7.21) as:
HPdp
m
Cd do2 NLdp
175 hp
2
0.000005 5 in2 500 3,500 ft
0.8
Basics of Drill String Design 359
he following two equations can be used to calculate the maximum allowable makeup
torque before the minimum torsional yield strength of the drill pipe body is exceeded.
In such case, Eq. (7.19) can be rearranged and written for torsional yield strength due
to pure tension as:
Qmin
0.096167 I pYmin
(7.22)
do
Here,
Qmin = minimum torsional yield strength, t.-lbf
Ymin = minimum unit yield strength, psi
It is well established that during normal drilling operations, the drill pipe is subjected
to both torsion and tension. hus Eq. (7.22) becomes:
Qmin _ t
0.096167 I p
do
2
Ymin
Wtj2
A2
(7.23)
Here,
Qmin _t = minimum torsional yield strength under tension, lbf-t.
Wtj
= total load in tension or total weight carried by the top joint, lbf
A
= cross-sectional area, in2
Example 7.4: Find out the minimum torsional yield strength and torsional yield
strength under tension for the following data: OD = 4.5 in, top joint load is 400,000 lbf.
Assume that the ID of the pipe is 3.958 in. Use an E-grade pipe.
Solution:
Given data:
Ip
= horsepower required to rotate the drill pipe = 175 hp
do
= outer diameter of drill pipe = 4.5 in
Wtj
= total load in tension carried by the top joint = 400,000 lbf
di
= inner diameter of drill pipe = 3.958 in
It is assumed that, Ymin = yield strength of drill pipe = 150,000 psi
Required data:
Qmin = minimum torsional yield strength in t.-lbf
Qmin _t = minimum torsional yield strength under tension in lbf-t.
he polar moment of inertia is calculated as:
Ip
32
do4 di4
32
4.54 3.958 4
16.16 in4
he cross sectional area, A can be calculated as:
A
4
do2 di2
4
4.52 3.9582
3.6 in2
360 Fundamentals of Sustainable Drilling Engineering
Now, the minimum torsional yield strength is given applying Eq. (7.22) as:
Qmin
0.096167 I pYmin
0.096167
16.16 in4
7,900 psi
4.5 in
do
2728.24 psi
he minimum torsional yield strength under tension is also given by Eq. (7.23):
0.096167 I p
Qmin _ t
do
2
Ymin
Wtj2
0.096167
16.16 in4
4.5 in
A2
= 3506.76 lb f ft
1500002
400,0002
3.62
Note that the drill pipe weights given in tabular form are nominal weights used mainly
for drill pipe classiication. hese tables are available in any petroleum engineering
handbook or the book of Mitchell and Miska (2011). he calculation of the approximate weight of a drill pipe includes the approximate weight of the tool joint assembly.
he following equations can be used to calculate the adjusted weight as:
Wdp
Here,
Wdp
Wdp
Wdp
adj
Wdp
Wdp
plain
upset
(7.24)
29.4
= approx. adjusted weight of drill pipe, lbf/t.
plain = plain end weight, lbf/t.
upset = upset weight, lbf/t.
adj
Now the approximate adjusted weight of the tool joint can be calculated as:
Wtool joint
Here,
Wtool joint
L
do
di
dTE
0.222 L do2 di2
3
0.167 do3 dTE
0.501di2 do dTE
(7.25)
= approximate adjusted weight of the tool joint, lbf/t.
= combined length of pin and box, in
= outside diameter of pin, in
= inside diameter of pin, in
= diameter of box at elevator upset, in
Equation (7.24) can also be represented in terms of approximate adjusted weight of the
tool joint and tool joint adjusted length as:
Wdp
adj
Ltool joint
29.4
Wtool joint
29.4 Ltool joint
L 2.253 do dTE
12
(7.26)
(7.27)
Here,
Ltool joint = tool joint adjusted length, t.
Stretch of Pipe: he stretch of drill pipe develops due to the action of drill collars and
its own weight carried out by the hook. So, the drill pipe stretches under the action of
Basics of Drill String Design 361
drill collars and its own weight can be calculated separately as the elongation due to i)
its own weight, and ii) drill collar’s weight
Due to its own weight:
In FPS system:
L2dp 65.44 1.44
o
m
(7.28)
9.625 107
Here:
o
Ldp
m
= stretch due to own weight, in
= total length of drill pipe, t.
= mud density, ppg
In MKS system, Eq. (7.28) can be written as:
2.346 10 8 L2dp 65.44 1.44
o
m
(7.29)
Here:
o
Ldp
m
= stretch due to own weight, m
= total length of drill pipe, m
= mud density, kg/lt
Due to weight of drill collars:
In FPS system:
Ldc Ldp
dc
735444 Wdp
Here:
dc
Ldp
Ldc
Wdp
Wdc
Wdc
(7.30)
= stretch due to drill collar, in
= total length of drill pipe, t.
= total length of drill collar, t.
= weight of the drill pipe, lbf/t.
= weight of the drill collar, lbf/t.
In MKS system, Eq. (7.30) can be written as::
dc
373.8 10
Here:
dc
Ldp
Ldc
Wdp
Wdc
10
Wdc
L
Ldp
Wdp dc
(7.31)
= elongation due to drill collar, m
= total length of drill pipe, m
= total length of drill collar, m
= weight of the drill pipe, kg/m
= weight of the drill collar, kg/m
If tension is applied,
Ldp Pdi
t
p
735294 Wdp
(7.32)
362 Fundamentals of Sustainable Drilling Engineering
Here:
= stretch due to tension, t.
t
Pdi p = diferential pull, lbf
Wdp = weight of the drill pipe, lbf/t.
Example 7.5: A 10 ppg mud is circulated through a 5 in. drill pipe assembly of 8,000 t.
If 50 drill collars of 30 t. long each are also used, calculate stretch for drill pipe and collar due to their own weight. Assume the OD and ID of drill collar as 6.25 in and 2.8125
in respectively and weight of drill collar is 93 lbf/t. In addition assume that a diferential
pull of 1,000 lbf is applied on the drill pipe. Also, ind out the stretch due to tension.
Solution:
Given data:
Ldp = total length of drill pipe = 8,000 t.
dodp = outer diameter of drill pipe = 5 in
didp = outer diameter of drill pipe = 4.408 in (Table 7.4)
Wdp = weight of the drill pipe = 16.25 lbf/t. (Table 7.4)
= mud density = 10 ppg
m
Ldc = total length of drill collar = 30 t. x 50 = 1,500 t.
dodc = outer diameter of drill collar = 6.25 in
didc = outer diameter of drill collar = 2.8125 in
Wdc = weight of the drill collar = 93.0 lbf/t.
Pdi p = diferential pull = 1,000 lbf
Required data:
= stretch due to own weight in inch
o
=
stretch due to drill collar in inch
dc
=
stretch
due to tension in t.
t
he stretch due to drill pipe own weight can be given using Eq. (7.28) as:
L2dp 65.44 1.44
o
m
9.625 107
80002 65.44 1.44 10
9.625 107
33.93 in
he stretch due to drill collar weight can be given using Eq. (7.30) as:
Ldc Ldp
dc
Wdc
735444 Wdp
1500 8000
93
735444 16.25
0.074 in
he stretch due to tension can be given using Eq. (7.32) as:
Ldp Pdi
t
p
735294 Wdp
8000 1000
735294 16.25
0.67 ft
Critical Rotating Speed: he components of a drill string can vibrate in three modes –
axial or longitudinal, transverse or lateral, and torsional. Figure 7.35 shows these three
types of vibration experienced during drilling. Axial action can be recognized at surface
(Figure 7.35a) and transverse method is possible only with drill pipe (Figure 7.35b).
Basics of Drill String Design 363
Axial
Vibration
(a)
lateral
Vibration
(b)
Torsional
Vibration
(c)
Figure 7.35 Triaxial shock and vibration.
Torsional mode cannot be seen due to rotary table which controls of angular motion
(Figure 7.35c). he vibration causes resonance and hence wears and fatigue. he pipe
vibration should coincide with bit rotation. It is calculated based on drill string length
and drill pipe dimensions or drill collar length. It is important therefore to review each
element of vibration, their efects, methods of detection and actions to control the speciic vibration when encountered.
Axial vibration occurs when it causes the bit and therefore the drill string to
vibrate or bounce on the formation. It can be due to several things including variation on the WOB, changes in mud pressure and the interaction of the bit cutting
structure on the formation i.e. interaction with stringers, ledges, hard rock formations etc. Bit bounce is typically encountered with roller cone bits, which exhibit
an unstable bottomhole pattern. Lateral vibrations are experienced at right angles
to the drill string and are commonly referenced as ‘bit whirl’ or ‘BHA whirl’ where
the lateral vibration causes a bending vibration in the BHA. Whirl can manifest
itself in both forward and backward directions. Torsional vibrations (stick slip)
describe the situation where the drill string stops or slows down rotation to a point
where the drill string torques up and rapid releases energy once the BHA and bit
free up and begin rotation again. Due to the built up torque the string rotates signiicantly faster than the nominal rpm during the slip phase. Stick slip is caused largely
by interaction with the formation and frictional forces between the drill string, BHA
and the wellbore, environments that become increasingly common in highly deviated
and deep wells.
he longitudinal vibration based on total length and drill pipe dimensions can be
calculated as:
rpmLc
Here:
rpmLc
258,000
Ldp
= critical rpm for longitudinal vibration, rev/min
(7.33)
364 Fundamentals of Sustainable Drilling Engineering
he transverse vibration can be calculated as:
rpmTc
Here:
rpmTc
4760,000 2
do di2
Ldp
(7.34)
= critical rpm for transverse vibration, rev/min
Example 7.6: Find out the critical rpm for both longitudinal and transverse vibration if
5 in of 16.25 lbf/t., and 7,500 t. drill pipe.
Solution:
Given data:
Ldp = total length of drill pipe = 7,500 t.
dodp = outer diameter of drill pipe = 5 in
didp = outer diameter of drill pipe = 4.408 in (Table 7.4)
Wdp = weight of the drill pipe = 16.25 lbf/t.
Required data:
rpmLc
= critical rpm for longitudinal vibration in rev/min
rpmTc
= critical rpm for transverse vibration in rev/min
he critical rpm for longitudinal vibration can be given by Eq. (7.33) as:
rpmLc
258,000
Ldp
258,000
7,500
34.4 rpm
he critical rpm for transverse vibration can be given by Eq. (7.34) as:
rpmTc
4760,000 2
do di2
Ldp
4760,000 2
5 4.4082
7,500
1498 rpm
7.5 Bit Design
he design features of the most widely used bits are the roller cone bits, and PDC bits.
herefore, these two bits will be discussed here only.
7.5.1 Roller Cone Bits
he design of roller cone bits can be described in terms of the four principle elements of
the design. he following aspects of the design will be dealt with in detail.
i.
ii.
iii.
iv.
Cutting structure
Fluid circulation
Types of cones
Bearing assemblies
Cutting Structure: he selection of a bit is mainly dependent on the hardness of the formation to be drilled. herefore, the design of the cutting structure will be based on the
Basics of Drill String Design 365
hardness of the formation. he main considerations in the design of the cutting structure are the height and spacing of the teeth or inserts. For sot formations, bits require
deep penetration into the rock so the teeth are long, thin and widely spaced to prevent
bit balling. Bit balling occurs when sot formations are drilled and the sot material accumulates on the surface of the bit preventing the teeth from penetrating the rock. For
moderately hard formations, it needs a heavier load so teeth height is decreased and
teeth width increased. he spacing of the teeth must be suicient to allow good cleaning. While drilling hard formations, bits rely on the chipping action and not on tooth
penetration to drill. herefore, teeth are shorter and stubbier than comparing with sot
formations. he teeth must be strong enough to withstand the crushing/chipping action
and suicient numbers of teeth should be used to reduce the unit load. Here spacing is
not critical sine ROP is reduced and the cuttings tend to be smaller.
Fluid Circulation: Drilling luid passes from the drill string and out through nozzles in
the bit. As it passes across the face of the bit, it carries the drilled cutting from the cones and
into the annulus. he original design for rock bits only allow the drilling mud to be ejected
from the middle of the bit (Figure 7.36). here are three jet nozzles used for eicient cleaning. Jet nozzles are small rings of standard outer diameter and various inner diameters.
hey are made of tungsten carbide and diameters less than 7/32 are not recommended.
Types of Cones: One of the basic factors that needs to be considered in the design of
the cone is the journal or pin angle. Since all three cones it together, the journal angle
speciies the outside contour of the bit.
Bearing Assemblies: While designing the bearing assembly, the most important factor is space availability. Preferably the bearings should be large enough to support the
applied loading. he inal design ensures that the bearings will not wear out before the
cutting structure.
7.5.2 PDC Bits
here are ive major components of a PDC bit that need to be considered during the
design:
i.
ii.
Cutting materials
Bit body materials
Fluid
Fluid
Jet
Nozzle
Open
Bearing
Jet
Nozzle
Sealed
Bearing
Figure 7.36 Fluid circulation through bit nozzle (courtesy, uralbmt).
Fluid
Open
Bearing
366 Fundamentals of Sustainable Drilling Engineering
iii.
iv.
v.
vi.
vii.
Bit proile
Fluid circulation
Cutting rake
Cutting density
Cutting exposure
i) Cutting materials: Normally polycrystalline diamond material has 90 – 95% pure
diamond that is set into the body of the bit. he PCD is formed by high temperatures
(i.e. more than 1400°C) and pressures (i.e. more than 600,000 psi).
ii) Bit body materials: he cutters of a PDC bit are mounted on a bit body. Normally
two types of bit body are used for the PDC bit – steel body, and tungsten carbide matrix
body. Steel body bit is cheaper but faces erosion problems.
iii) Bit proile: Normally three basic types of crown proiles exist – lat or shallow
cone, tapered or double cone, and parabolic. he lat cone proile evenly distributes with
WOB between each of the cutters on the bit (Figure 7.37a). he taper cone proile allows
increased distribution of the cutters toward the outer diameter of the bit (Figure 7.37b).
As a result it achieves greater rotational and directional stability, which ultimately gives
even wear. he parabolic proile gives a smooth loading over the bit proile and the largest surface contact area (Figure 7.37c). As a result, this type of bit gives even more rotational and directional stability and even wears compared to the taper cone proile.
iv) Fluid Circulation: One of the most important design criteria is to have the ability
to remove the cuttings and to cool the bit eiciently. his option is the same as the roller
cone bit. In general, more than three jets are used on a PDC bit.
v). Cutting Rake: he PDC cutter can be set at various rack angles. hese rack angles
include back rake and side rake. he back rake angle determines the size of cutting that
is produced and the side rake is used to direct the formation cuttings towards the lank
of the bit and into the annulus.
vi). Cutting Density: Is the number of cutters per unit area on the face of the bit. he
cutter density is used to control the amount of load per cutter.
vii). Cutting Exposure: Is the amount by which cutters protrude from bit body. It is
necessary to ensure good cleaning of the bit face and mechanical strength.
7.6 Drilling Bit Selection
he selection of a bit means a thorough examination of bit records from ofset well
data. he best selection is by the trial-and-error method. he data and the bit design
(a)
(b)
Figure 7.37 PDC bit proiles (redrawn from Ford, 2005).
(c)
Basics of Drill String Design 367
should be examined, analysed and this information needs to be used to determine the
characteristics of the best performing drill bits. Special care must be given to the details
such as the premature failure of bits, reasons to pull bits, and dull characteristics of
inserts (i.e. whether the inserts were worn or broken) etc. For example, a drill bit that
had broken inserts clearly indicates that the formation should have been drilled with
a much harder drill bit. here are some data required to select the correct bit such as
projected lithology column with detailed description of each formation, drilling luid
details, and well proile.
When drilling directional wells, special attention should be given. he directional
contractor should provide an assessment on required BHA changes, motor requirements and any limitations on bit operating parameters, which may efect the bit selection. In addition bit characteristics in terms of walk, build and drop tendencies need to
be evaluated for their inluence on the well trajectory.
Formation characteristics (drillability, and abrasiveness) and cost per foot analyses
can help greatly in bit selection. he drillability of a formation is a measure of how easily
the formation is to drill. It is inversely proportional to the compressive strength of the
rock formation. Drillability generally decreases with depth in a given area. Abrasiveness
of a formation is a measure of how rapidly the teeth of the milled-tooth-bit will wear
when drilling the formation. Abrasiveness generally increases as drillability decreases.
In summary, bit selection criteria depend on the following two situations: i) Situation-1:
bit records for a formation are not available, and ii) Situation-2: bit records for a formation are available.
7.6.1 Situation-1: When Bit Records are Not Available
Several Rules of humb are oten used for initial bit selection:
Rules of humb #1: If the formation hardness is known, then use the IADC Charts
(available in any handbook of IADC), or Bourgoyne et al., (1986). Table 7.5 shows the
bit types oten used in various formation types.
Rules of humb #2: Bit cost consideration plays a vital role for selecting initial bit
type and features.
Rules of humb #3: Selection of tri-cone roller bits. his is a good choice for an
initial bit type, which is used for the shallow portion of the well. TCR bits are most
versatile. In addition, use the longest tooth size possible.
Rules of humb #4: Selection of diamond bits which perform best in non-brittle
formations (having a plastic mode of failure) and bottom portion of well (due to longer
bit life, minimizes high-cost tripping operations).
Rules of humb #5: Selection of PCD drag bits, which perform best in uniform
sections of carbonate formations (without thin stringers of brittle rocks or hard
shales).
Rules of humb #6: PCD drag bits should not be used in gummy formations (gluey
shales, tending to cause bit balling.
Rules of humb #7: Carefully evaluate a dull bit when it is removed from the well.
Maintain carefully well-written records of the performance of used bits for future
references.
368 Fundamentals of Sustainable Drilling Engineering
Table 7.5 Bit types oten used in various formation types (Bourgoyne et al., 1986).
IADC bit
classiication
Formation
1–1
1–2
5–1
6–2
Sot formations having low compressive strength and high drillability
(sot shales, clays, red beds, salt, sot limestone, unconsolidated
formations, etc.)
1–3
6–1
Sot to medium formations or sot interspersed with harder streaks
(irm, unconsolidated or sandy shales, red beds, salt, anhydrite, sot
limestone, etc.)
2–1
6–2
Medium to medium hard formations (harder shales, sandy shales,
shales altering with streaks of sand and limestone, etc.)
2–3
6–2
Medium hard abrasive to hard formations (high compressive strength
rock, dolomite, hard limestone, hard slaty shale, etc.)
3–1
7–2
Hard semiabrasive formations (hard sandy or chert bearing limestone, dolomite, granite, chert, etc.)
3–2
3–4
8–1
Hard abrasive formations (chert, quartzite, pyrite, granite, hard sand
rock, etc.)
7.6.2 Situation-2: When Bit Records are Available
Bit selection and evaluation is easier when bit performance records in a formation
are available. he most valid criterion for comparing the performance of various drill
bits is the drilling cost per foot drilled. he drilling cost per foot formula presented in
Chapter-11 can be used for this purpose. Since no amount of arithmetic allows us to
drill the same section of hole more than once, we must compare between succeeding
bits in a given well, or, between bits used to drill the same formation in a diferent well.
7.7 Drilling Bit Performance
he performance of the bit can be evaluated based on the criteria such as how far it
drilled, how fast it drilled (ROP), how much it costs to run per foot of the hole drilled.
he drilling cost analysis will be presented in Chapter 11. Since ROP is one of the most
signiicant factors in the assessment of bit performance, it is discussed in detail only for
two bit types, roller cone bit and PDC bit.
7.7.1 Roller Cone Bits
To evaluate the bit performance of a roller cone bit, ROP plays a vital role, which
depends on 1) weight on bit (WOB), 2) rotary speed (RPM), 3) mud properties, and 4)
hydraulic eiciency.
Rate of penetration (ROP), ft/hr
Basics of Drill String Design 369
Threshold WOB
Weight on bit (WOB), lbs
Rate of penetration
(ROP), ft/hr
Figure 7.38 Linear variation of rate of penetration over weight on bit in a log-log plot.
High HPH at bit
Medium HPH at bit
Threshold WOB
Low HPH at bit
Weight on bit (WOB), lbs
Figure 7.39 Nonlinear variation of rate of penetration due to hole cleaning over weight on bit in a loglog plot.
1. Weight on Bit
A certain minimum WOB is required to overcome the compressibility of the formation (Figure 7.38). Experimental study shows that once this threshold is exceeded, ROP
increases linearly with WOB. However there are certain limitations to the WOB which
can be applied to hydraulic horsepower (HPH) at the bit, type of formation, hole deviation, bearing life, tooth life etc.
i) Hydraulic Horsepower: If the hydraulic horsepower is not suicient to ensure good
bit cleaning, the ROP is reduced either by bit balling, or by bottomhole balling. If this
condition arises, there would not be any increase in ROP due to an increase in WOB.
herefore, it is necessary to improve the HPH by other means. Figure 7.39 shows an
increased ROP with WOB where the HPH generated by the luid lowing through the
bit is improved. he HPH at the bit is given by:
HPH
PbnQbn
1714
(7.35)
Here,
Pbn = pressure drop across the nozzles of the bit, psi
Qbn = low rate through the bit, gpm
Practically, HPH can be improved by increasing Pbn , which is done by designing smaller
nozzles. Hydraulic horsepower can also be increased by increasing bn, which means
370 Fundamentals of Sustainable Drilling Engineering
faster pump speed or larger liner. his may cause a radical change to other drilling factors
such as annular velocity, which may not be beneicial. Hole cleaning may be improved by
using extended nozzles to bring the luid stream nearer to the bottom of the hole.
ii) Type of Formation: Sometimes WOB cannot be increased in sot formations.
he excessive weight will only bury the teeth into the rock and result increased torque.
Ultimately it will not improve ROP increment.
iii) Hole Deviation: In some areas, WOB will produce bending in the drill string, leading to a curved hole. he drill string should be properly stabilized to prevent this happening.
iv) Bearing Life: An increase in WOB reduces the operational life of the bearing.
herefore, optimizing ROP will depend on a compromise between WOB and bearing wear.
v) Tooth Life: WOB is oten limited in sot formations, where excessive weight will
only bury the teeth into the rock and cause increased torque, with no increase in ROP.
2. Rotary Speed
An optimum speed must be determined because ROP is afected by the rotary speed
of the bit. he RPM inluences the ROP since the teeth must have time to penetrate
and sweep the cuttings into the hole. Figure 3.40 shows how ROP varies with RPM for
diferent formations. he non-linearity in hard formations is due to the time required
to break down rocks of higher compressive strength. Experience is very important in
selecting the correct rotary speed in any given situation. RPM is the function of type of
bit and type of formation.
i) Type of Bit: In general, lower RPMs are used for insert bits comparing with milled
tooth bits. his is due to the allowance of more time to penetrate the formation by the
inserts. he insert crushes a piece of rock and then forms a crack, which loosens the
fragment of rock.
ii) Type of Formation: Harder formations are diicult to penetrate which leads to
maintain low RPM. A high RPM may cause damage to the bit or the drill string.
3. Mud Properties
Mud properties play a vital role while drilling. hey create a hydrostatic balance around
the cutting area to restrict an inlux of formation luids into the wellbore. In addition,
due to the slide overburden pressure from the mud, they form the ilter cake on the wall
of the borehole. his ilter cake prevents any further entry of mud into the formation.
he overbalance and ilter cake also exists at the bottom of the hole where it afects the
Rate of penetration
(ROP), ft/hr
Soft formation
Hard formation
Rotary speed (RPM)
Figure 7.40 Variation in the rate of penetration over rotary speed in a log-log plot.
Basics of Drill String Design 371
removal of cuttings. In addition, the ilter cake covers up the cracks and prevents mud
pressure being exerted below the chip. he diferential pressure on the chip tends to
keep the chip against the formation. his is known as the static chip hold down efect,
which leads to lower down the penetration rates. Sometimes a dynamic chip hold down
may occur because cracks form around the chip where mud enters the cracks to equalise the pressure. As a result, a pressure drop is created which tends to ix the chip against
the bottom of the hole. Both static and dynamic hold down efects cause bit balling and
bottomhole balling which can be prevented by ensuring correct mud properties.
4. Hydraulic Efficiency
he efects of increased hydraulic horsepower at the bit are already explained earlier
in section 7.7.1. Hydraulic eiciency is directly related to HPH. So it is recommended
to allow a minimum low rate to ensure that the bit face is kept clean and the cutting
temperature is kept to a minimum. his requirement for low rate may poorly afect the
optimization of HPH.
7.7.2 PDC Bit
To estimate the bit performance of a PDC bit, WOB, RPM, mud properties, and hydraulic eiciency are important.
1. Weight on Bit and Rotary Speed
PDC bits tend to drill faster with low WOB and high RPM. hese bits require higher
torque than roller cone bits. he general recommendation is to use the highest RPM
that might be achieved. Although the torque is fairly constant in shale sections the
bit will tend to dig in and torque up in sandy sections. When drilling in these sandy
sections, or when the bit drills into hard sections and ROP drops, the WOB should
be reduced. However, a constant bit weight should be maintained to produce a rotary
torque at least equal to that of a roller cone bit. If there is a too low WOB, it will cause
premature cutter wear, possible diamond chipping, and a slow ROP.
2. Mud Properties
PDC bit works better in terms of best ROP when we use oil-based muds. However, a
good deal of success has been achieved with water-based muds. he improved performance in oil-based muds is due to increased lubricity, decreased cutter wear temperature and preferential oil wetting of the bit body. he performance of PDC bits with
respect to other mud properties is consistent comparing with roller cone bits.
3. Hydraulic Efficiency
his is same as roller cone bits as stated earlier.
7.8 Drilling Optimization Techniques
he fundamental concept of drilling needs to be understood before undergoing any
optimization of parameters related drilling operations. In order to drill a well, three
372 Fundamentals of Sustainable Drilling Engineering
factors have to be established simultaneously – i) a certain load has to be applied on
the bit, ii) the bit has to be rotated, and iii) a drilling luid has to be circulated within
the wellbore. So, making a hole for the recovery of underground oil and gas is a process
that requires two major constituents – i) Man-power, and ii) Hardware systems. he
manpower includes a drilling engineering group and a rig operator group. hey irst
provides engineering support for optimum drilling operations, including rig selection,
design of mud program, casing and cement programs, hydraulic program, drill bit program, drill string program and well control program. A rig operator group is responsible for the daily operations ater drilling begins. his group consists of a tool pusher
and several drilling crews. On the other hand, the hardware systems which make up a
rotary drilling rig are i) power generation system, ii) hoisting system, iii) drilling luid
circulation system, iv) rotary system, v) well blowout control system, and vi) drilling
data acquisition system and monitoring system. Managing all these ingredients in a
cost efective way is very challenging. herefore, drilling optimization is widely used to
maximize the drilling eiciency of oil and gas wells in a cost efect manner. Diferent
computer sot wares, tools and equipment are used in the optimization process, such
as, measurements while drilling (MWD), surface sensors, and computer sotware. In
addition, experienced expert personnel play a vital role in the optimization process.
In the recent years, drilling optimization techniques have been used to reduce drilling
operation costs. Reducing the operation time, since time is always money in drilling
operations would do this. he researchers in the drilling engineering ields are always
looking for the prediction of unexpected events and optimizing the related parameters.
he philosophy of optimization in drilling operation is using the record of the irst
drilled wells as a basis and applying optimization techniques to reduce drilling costs
for the next wells being drilled. Drilling optimization can be deined as a process
that employs downhole and surface sensors, computer sotware, MWD, and experienced expert personnel – all dedicated to reduce trouble time and increase drilling eiciency (Paes et. al, 2005). It can also be deined as the provision of real-time
data to expedite decision-making based on information transmitted from downhole
(Bharadwaj and Vinayaka, 2013). he disadvantage of using conventional drilling
optimization processes is the independence of real time data, which makes the optimization process ineicient. Real time and rig-site data should be used to make the
optimization more accurate and eicient. he main parameter that should be looked
into in the optimization process is the drilling time that can be optimized by increasing the penetration rate.
he objective of optimizing drilling parameters in real time is to arrive to a methodology that considers past drilling data and predicts drilling trend advising optimum
drilling parameters in order to save drilling cost and reduce the probability of encountering problems. Figure 7.50 provides the timeline of some important achievements in
drilling optimization history. In the 1950s the scientiic period took place with expansion in drilling research. he optimization technique was irst applied in 1967, which
has considerably reduced drilling costs. Ater the 1970s, rigs with full automation systems started to operate in oil and gas ields. Operator companies developed techniques
of drilling optimization in the mid of 1980s. In the 1990s diferent drilling planning
approaches were brought to identify the best possible well construction performance.
Ater the 2000s real time operations support centers were built. In recent years drilling
Basics of Drill String Design 373
parameters are easily acquired, stored and transferred in real time and thus currently
have become an important aspect of drilling technology.
7.8.1 History of Drilling Optimization
A historical time line for drilling optimization is shown in Figure 7.41. One of the
irst attempts for the drilling optimization purpose was presented in the study of
Graham and Muench in 1959. hey analytically evaluated the weight on bit and
rotary speed combinations to derive empirical mathematical expressions for bit life
expectancy and for drilling rate as a function of depth, rotary speed, and bit weight.
Galle and Woods (1963) produced graphs and procedures for ield applications to
determine the best combination of drilling parameters. One of the most important
drilling optimization studies was performed by Bourgoyne and Young (1974). hey
proposed the use of a linear drilling penetration rate model and performed multiple
regression analysis to select the optimized drilling parameters. hey used minimum
cost formula, showing that maximum rate of penetration may coincide with minimum cost approach if the technical limitations were ignored. In the mid 1980s operator companies developed techniques of drilling optimization in which their ield
personnel could perform optimization at the site referring to the graph templates
and equations. In the 1990s diferent drilling planning approaches were brought to
surface (Bond et al., 1996, Carden et al., 2006). New techniques identiied the best
possible well construction performances. Later on “Drilling the Limit” optimization
techniques were also introduced (Schreuder and Sharpe, 1999). Towards the end
of the millennium real-time monitoring techniques started to take place, e.g. drilling parameters started to be monitored from of locations. A few years later realtime operations/support centres started to be constructed. Some operators proposed
advanced techniques in monitoring of drilling parameters at the rig site. Following
the early developments in rotary drilling system, groundbreaking developments in
the latter years of the century took place. Highly inclined wells were drilled using
rotary steerable; pressure controlled drilling techniques with acquisition of drilling
parameters.
1952
Introduction of
Jet type roller
Cone bits
1963
Best Constant Weight
and RPM,
Galle & Woods
1959
First Drilling Optimization,
by Graham and Muench
1950
Scientiic Period
Expansion of Drilling Research
Optimization of drilling start
1970
Rig
Automation
Period
1986
Real-Time Drilling
Optimization (Manual),
at the Rig Site
Chevron
1974
Multiple Regression
Spproach,
by Bourgoyne
1991
Field Veriication of
Drilling Models,
by maidla and Ohara
2009
1950
Drilling Optimization Timeline
1999
Real-Time Data
Monitoring in
Ofshore Norway
2003
Real-Time Operating
Centers, Shell &
Halliburton
2008
Real-Time Data
Transfer to
Support Centers,
by Stateoil
Mitter et al.
2005
Real-Time Monitoring
of Parameters, at the
Site ExxonMobil
Dupriest et al.
Figure 7.41 Time line for drilling optimization (Eren and Ozbayoglu, 2010).
2009
Real-Time Drilling
Optimization by
means of Mult. Regs.
374 Fundamentals of Sustainable Drilling Engineering
7.8.2 Parameters for Drilling Optimization
Actual data is the only source of information to make a recommendation to optimize
drilling operations. he parameters those of which could be collected from a drilling
activity are as listed in Table 7.6. Each parameter to be collected from the rig site is going
to have an impact on the overall optimization process. Data reliability and accuracy is
very important, all of the data collecting sensors should be accurately calibrated and be
signalling the correct magnitude of measurement. he success of drilling optimization
is closely related with the quality of the recorded drilling parameters. he parameters
recorded for drilling optimization are critically important to be representative of data
they are meant to relect. he brief description of the drilling parameters is deemed
necessary to be explained.
Whenever the cost of drilling activity is reduced, the whole process is considered
optimized. Optimization could be performed by means of adjusting the magnitude of
two or more independent parameters. his could be achieved mainly by means of i)
minimized cost per foot, and ii) minimizing problems. he cost of a drilling process
could be minimized by means of working with optimized combination of controllable
drilling parameters. Hole problems those of which are being generated due to ineficient parameter usage generally occurring at the rig sites could be avoided. Drilling
optimization is considered that the rig equipment, BHA, and the bit to be used are
already in the optimum selections. In order to achieve the objective of minimum cost
drilling the bit should be prevented from damages when run into the hole.
7.8.3
Factors Afecting the Drilling Operations
here are parameters that signiicantly afect drilling operations. hese parameters
are normally used for drilling optimization. herefore, it is important to know about
those parameters. In general, drilling parameters may be broadly classiied under
two types – i) rig and bit related parameters, and ii) formation parameters. he rig
and bit related parameters can be controlled but the formation parameters have to be
dealt with. he formation parameters recorded for drilling optimization are critically
important to be representative of data they are meant to relect. Many drilling parameters afect the performance of the drilling operation. If they are not adjusted properly,
Table 7.6 Parameters from a drilling activity.
WOB
Drill string Properties
RPM
Casing details
Pump parameters
Drilling luid properties
Depth
Torque
Inclination
Hook-load
Azimuth
LWD
ROP
MWD
Basics of Drill String Design 375
they will make the operation less economical. Rig and bit type parameters are broadly
categorized as weight on bit or hook load, rotational speed (RPM), torque, and hydraulic parameters (i.e. Bit hydraulics) – low rates, density of drilling luid etc. However,
WOB, RPM, low rate, bit hydraulics, and more importantly the type of bit are the most
important drilling parameters afecting drilling operations because they are afecting
rate of penetration (drilling speed) and the economics of drilling. he parameters that
come under the formation type are local stresses, mineralogy, formation luids, rock
compaction and abrasivity of formation. Beyond the above stated parameters, determining the rate of penetration is among the most sought ater parameters in drilling
industry. his is due to the fact that it allows for optimization of drilling parameters to
decrease drilling costs and enhance drilling process safety. Among the above factors,
some of the parameters are discussed below.
Weight on Bit: Represents the amount of weight applied onto the bit. It is the abbreviation for “Weight on Bit”. his load is then transferred to the formation which in turn is
the energy created together with string speed that advances drill string. It is measured
through the drilling line, usually by means of having attached a strain gauge, which
measures the magnitude of the tension in the line itself, and gives the weight reading based on the calibration. his sensor measures a unique value, which is the overall weight (Hook-load) of the string including the weight of the block and Top Drive
System (TDS). For all of these circumstances correct calibration is required in order
to have proper reading for this drilling parameter. Field study shows through testing
that doubling the bit RPM in 6,000-psi rock while keeping WOB constant resulted in
70% increase in ROP. However, doubling WOB, with RPM constant, resulted in 300%
increase in ROP. Bit condition is very important as there is blunting while drilling progresses, which depends on the formation being drilled.
RPM: his parameter stands for “revolutions per minute”. It represents the rotational
speed of the drill string. With the invention of TDS, the reading is directly linked to the
electronics of the unit itself. It is considered that the measurements for this parameter
are accurate as long as the acquisition system set-up has been thoroughly made up.
Torque: his parameter is the torque of the drill string while it is rotating. It is
measured by means of TDS systems. Previously the readings for this parameter were
relative. his parameter is going to be signiicantly important for inclined and highly
deviated wellbores, which is also related with the wellbore cleaning issues.
Pump Parameters: he pump parameters are composed of the liner size in use,
pump strokes, and the pump pressure. In case there are two pumps working simultaneously all of the data for two of the pumps should be acquired. With the electric pumps
the stroke is transmitted in the same way as RPM. he pressure at the pump in case of
having been acquired could be compared with the reliability of the standpipe pressure.
Pump pressure should always be greater than the standpipe pressure. he use of low
meters could also be adapted for accurate low rate measurements.
Depth: he value of depth, in other means the bit position is input in the mudlogging unit (MLU). he operator is the responsible for that. Usually it is linked to the
position of the block, by means of the sensors located at the crown block.
Inclination – Azimuth: hese two parameters are the responsibility of the directional driller. An eicient communication between the MLU and the measurements
376 Fundamentals of Sustainable Drilling Engineering
while drilling (MWD) unit is to the beneit of these two parameters, which may be very
important for wellbore stability considerations.
ROP: his parameter is the most important parameter, since all of the calculations in
this study are based on estimations of ROP. It is measured through the relative change
of the position of the block in time. Accurate calibrations are very important in order
to have a representative ROP parameter.
String–Casing Properties: he string and casing properties are very important
when the frictional pressure losses are to be calculated.
Fluid Properties: Rheological properties and the density of the drilling luids are
also among the very important parameters to be recorded for optimization purposes.
Usually the drilling luid density is measured through calibrated mud weight (MW)
sensors. Rheological properties on the other hand are still measured manually. Recent
developments in regards to real-time pipe viscometers dictate alternative solutions.
here are experimental studies performed in the laboratory using pipe-viscometers.
Continuous real-time viscometer probes placed on the low line could facilitate data
acquisition over the rheological properties of drilling luids in real-time.
Logging While Drilling (LWD): Formation related parameters could be captured
during drilling and be used in the optimization process. LWD consideration needs to
be applied to enhance the optimization process.
7.8.4
How to Optimize the Drilling Operations
he optimization of the drilling performance, even more in a ield development context
requires i) data acquisition, and ii) data processing. Data acquisition has the relevant
measurement of drilling data such as WOB, RPM, torque, ROP and low rate. Some of
these data are time dependent. Data processing is based upon relevant drilling data, the
processing leads to drill bit response follow up with mechanical speciic energy (MSE),
HMSE logs, and E/S Diagram, events identiication (steady drilling, vibrations, cleaning issue, wear development, and drilling response optimization (drilling parameters
adaptation). he surface data allows tracking of the drilling behaviour. his is especially
possible when the full bit design is known. In other cases, detailed information on the
design needs to be provided (cutter distribution, orientation and position). Using the bit
signature together with the GeoScan lithology, we can then assess on a real time basis the
drilling performance. he wear phenomena can be tracked and a wear logs is created.
he vibrations are also monitored using surface data, bit signature and predicted ROP.
Two main services are provided in this regard i) real time service (RTS), and ii) next
well service (NWS). he RTS provides the decision maker with the information needed
to modify and optimize the drilling parameters in order to increase ROP, bit life and
decrease vibrations. Pull out decisions can also be supported by this RTS. NWS uses
the parameters logs recorded during drilling operation and electric logs. he lithology
can also be reviewed and the ield mapped, well ater well. Lessons learned are gathered.
his leads to the construction of a reference knowledge database (RKD). BHA components and bit design can then be adapted to improve performance for the next well.
Guidelines are given to the drillers.
Figure 7.42 summarizes the algorithmic steps, which should be followed consecutively to optimize drilling parameters of a hydrocarbon ield using mathematical
Basics of Drill String Design 377
Data preparation and validation
Comparative
optimization method
Modeling
penetration rate
Optimum drilling
mud properties
Hydraulic
optimization
Optimum
bit selection
Modelling wear
rate of selected bits
Determining maximum allowable
mechanical horsepower
Specifying optimum bit
weight/rotary speed to
minimize cost per foot
Figure 7.42 Algorithm of the mathematical optimization procedure.
solutions. As shown in this igure, some of the comparative optimization results such
as selection of optimal bit and mud properties will be employed in the numerical technique. Each step of this algorithm can be achieved by using the proper mathematical
model for each parameter optimization.
7.8.5 Traditional Optimization Process
he traditional optimization process consists of (i) pre-run modeling, (ii) real-time
data measurement and monitoring, and (iii) post-run analyses and knowledge management. At the center of this process, the team members are the personnel who are
expert in these technologies and who can make recommendations to avoid trouble
and improve drilling performance. Generally, a comprehensive drilling optimization
should include solutions for: i) drill string integrity, ii) hydraulics management, and iii)
wellbore integrity. However, new drilling optimization technologies emphasize information management and real-time decision making. On the other hand, the traditional
three-step optimization process will not it the real time process and has had to be
changed. First pre-run modeling needs to be changed to “real-time modeling”. his
change is required because the input parameters for pre-run models have typically been
out-dated and incorrect. herefore, modeling results were oten of little use for real-time
decision making. Second, integrated real-time modeling and data are required to allow
378 Fundamentals of Sustainable Drilling Engineering
detailed diagnoses on the downhole environment. hird, a rig-to-oice integration is
best so the optimization process can be monitored 24/7 by an asset team. hese three
new technologies have been summarized by (Chen, 2004) as i) real-time modeling, ii)
integrated real-time modeling and data, and iii) a real time operation center (RTOC).
i) Real Time Modeling: he objective of optimizing drilling parameters in real time is
to arrive to a methodology that considers – i) past drilling data, and ii) predicts drilling
trend advising optimum drilling parameters. Real time optimization is needed in order
to save drilling cost and reduce the probability of encountering problems. Conventional
modeling is usually run during well planning to avoid a set of predicted data. As drilling processes, the input parameters may change intentionally or unintentionally. As a
result, conventional, stand-alone computer sotware requires constant manual updating to produce pertinent results. Such a procedure, however, has proven to be impractical. In contrast, real-time modeling is automatically updated using “correct” input
data, which is no doubt more accurate. In addition, real-time modeling is always “on”
allowing continuous monitoring to prevent drilling accidents. Real time modeling also
allows integration with real time data to enable real time decision making. To date,
several real-time drilling optimization-related modeling programs are being developed
as BHA dynamics, torque and drag, pore pressure/fracture gradient prediction, hydraulics, hole cleaning, and wellbore stability.
ii) Integrated Real Time Modeling and Data: Although real-time modeling produces better results than the conventional, stand-alone modeling, the delivery of useful information in a useful form and diagnosis of a problem requires an integration of
modeling with downhole data. For example, the integration of the following models
and data is always beneicial:
• Bottomhole Assembly (BHA) dynamics model with downhole vibration
data
• Pore pressure model with Pressure While Drilling (PWD) and Formation
Testing While Drilling (FTWD) data
• Hydraulic model with PWD data
• Hole cleaning model with PWD and solids in mud
• Wellbore stability model with Logging While Drilling (LWD) imaging
data
iii) RTOC: he irst Real-Time Operation Center (RTOC) was set-up by Shell E&P
in New Orleans in early 2002. Since then, several other RTOCs for diferent operators
have been developed particularly for ofshore rigs. here are many reasons to setup
RTOCs. First, wells drilled ofshore are very expensive. hey clearly require full attention by the best staf available. Second, critical decisions are always multidisciplinary;
and multidisciplinary decision making with expert staf is impractical to arrange at
a rig. hird, a permanent, common ground needs to be identiied for oice and ofshore staf throughout planning and execution; and RTOCs readily satisfy this element.
Lastly, full time (24/7) real-time drilling optimization monitoring and information
management is required to avoid hazards; and 24/7 monitoring available to key personnel is best done an RTOC.
Basics of Drill String Design 379
7.9
Factors Afecting Rate of Penetration
he factors which afect the rate of penetration (ROP) are very numerous and perhaps
important variables exist which are unrecognized up to this time. A rigorous analysis of
drilling rate is complicated by the diiculty of completely isolating the variable under
study. For example, the interpretation of ield data may involve uncertainties due to
the possibility of undetected changes in rock properties. Studies of drilling luid efects
are always plagued by diiculty of preparing two muds having all properties identical
except one that is under observation. While it is generally desirable to increase penetration rate, such gains must not be made at the expense of overcompensating, detrimental
efects. he fastest on-bottom drilling rate does not necessarily result in the lowest cost
per foot of drilled hole. Other factors such as accelerated bit wear, equipment failure
etc. may raise the cost. hese restrictions should be kept in mind during the following
discussion.
he factors that have an efect on ROP are listed under two general classiications
such as environmental and controllable. Table 7.7 shows the list of parameters based
these two categories. Environmental factors are not controllable such as formation
properties and drilling luids requirements. Controllable factors on the other hand are
the factors that can be instantly changed such as weight on bit, bit rotary speed, hydraulics. he reason that drilling luid is considered to be an environmental factor is due to
the fact that a certain amount of density is required in order to obtain certain objectives
such as having enough overpressure to avoid low of formation luids. Another important factor is the efect of the overall hydraulics to the whole drilling operation which
is under the efect of many factors such as lithology, type of the bit, downhole pressure
and temperature conditions, drilling parameters and mainly the rheological properties
of the drilling luid. Rate of penetration performance depends and is a function of the
controllable and environmental factors. It has been observed that the drilling rate of
penetration generally increases with decreased Equivalent Circulating Density (ECD).
Another important term controlling the rate of penetration is the cuttings transport.
Ozbayoglu et al. (2004) conducted extensive sensitivity analysis on cuttings transport
Table 7.7 Variables that afect ROP.
Environmental Factors
Controllable Factors (Alterable)
Depth
Bit Wear State
Formation properties
Bit design
Mud type
Weight on bit
Mud density
Rotary speed
Other mud properties
Flow rate
Overbalance mud pressure
Bit hydraulic
Bottomhole mud pressure
Bit nozzle size
Bit size
Motor/turbine geometry
380 Fundamentals of Sustainable Drilling Engineering
for the efects of major drilling parameters, while drilling for horizontal and highly
inclined wells. It was concluded that the average annular luid velocity is the dominating parameter on cuttings transport, the higher the low rate the less the cuttings bed
development. Drilling penetration rate and wellbore inclinations beyond 70° did not
have any efect on the thickness of the cuttings bed development. Drilling luid density did have moderate efects on cuttings bed development with a reduction in bed
removal with increased viscosities. Increased eccentricity positively afected cuttings
bed removal. he smaller the cuttings the more diicult it is to remove the cuttings bed.
It is clear that turbulent low is better for bed development prevention. One of the most
important considerations in order to have an eiciently cuttings transported hole is to
take into account the factors given in Table 7.6.
However, in any engineering study of rotary drilling it is convenient to divide the
factors that afect the ROP into the following list:
1. Personal eiciency
2. Rig eiciency
3. Formation characteristics (e.g. strength, hardness and/or abrasiveness,
state of underground formations stress, elasticity, stickiness or balling
tendency, luid content and interstitial pressure, porosity and permeability etc.)
4. Mechanical factors i.e. bit operating conditions – a) bit type, and b)
rotary speed, and c) weight on bit
5. Hydraulic factor (e.g. jet velocity, bottom- hole cleaning )
6. Drilling luid properties (e.g. mud weight, viscosity, iltrate loss and solid
content)
7. Bit tooth wear
he most important variables that afect the ROP are:
1. Bit type
2. Formation characteristics
3. Bit operating conditions (i.e. bit type, bit weight, and rotary speed)
Table 7.8 Factors for eicient hole cleaning.
Hole angle
Fluid velocity
Fluid properties (rheological properties and density)
Cutting size, shape, and concentration
Annular size
Rate of pipe rotation and pipe eccentricity
Fluid low regime (laminar and turbulent)
Bit size
Basics of Drill String Design 381
4. Bit hydraulics
5. Drilling luid properties
6. Bit toot wear
1) Personal Efficiency
he manpower skill and experience is referred to as personal eiciency. Given equal
conditions during drilling/completion operations, personnel are the key to have success or failure of those operations and ROP is one of them. Overall well costs as a result
of any drilling/completion problem can be extremely high; therefore, continuing education and training for personnel directly or indirectly involved is essential to successful desired ROP and drilling/completion practices.
2) Rig Efficiency
he integrity of drilling rig and its equipment, and maintenance are major factors in
ROP and to minimizing drilling problems. Proper rig hydraulics (pump power) for
eicient bottom and annular hole cleaning, proper hoisting power for eicient tripping
out, proper derrick design loads, drilling line tension load to allow safe overpull in case
of a sticking problem, and well-control systems (ram preventers, annular preventers,
internal preventers) that allow kick control under any kick situation are all necessary for
reducing drilling problems and optimization of ROP. Proper monitoring and recording systems that monitor trend changes in all drilling parameters are very important
to rig eiciency. hese systems can retrieve drilling data at a later date. Proper tubular
hardware speciically suited to accommodate all anticipated drilling conditions, and
efective mud-handling and maintenance equipment will ensure that the mud properties are designed for their intended functions.
3). Formation Characteristics
he formation characteristics are some of the most important parameters that inluence
the rate of penetration. he following formation characteristics afect the ROP – i) elasticity
i.e. elastic limit, ii) ultimate strength, iii) hardness and/or abrasiveness, iv) state of underground formations stress, v) stickiness or balling tendency, vi) luid content and interstitial
pressure, and vii) porosity and permeability. Among these parameters, the most important
formation characteristics that afect the ROP are the elastic limit and ultimate strength of
the formation. he shear strength predicted by the Mohr failure criteria sometimes is used
to characterize the strength of the formation. To determine the shear strength from a single
compression test, an average angle of internal friction varies from about 30 to 40° from the
most rock. he following model has been used for a standard compression test:
1
0
Here,
0
1
2
cos
(7.36)
= shear stress at failure, psi
= compressive stress, psi
= angle of internal friction
W
required to initiate drilling was obtained by
d t
plotting drilling rate as a function of bit weight per bit diameter and then extrapolating
he threshold force or bit weight
382 Fundamentals of Sustainable Drilling Engineering
20
Atmospheric pressure
18
Shear Strength , 1,000 psi
16
Pink quartzite
Knippa basalt
14
Virginia
limestone
12
10
Rush Springs sandstone
8
Anhydrite
6
Berea sandstone
4
Carthage marble
2
0
0
40 80 120 160 200 240 280 320
W
db
t
W
db
,lbf / ft
t
Figure 7.43 Relationship between rock shear strength and threshold bit weight at atmospheric pressure
(Mitchell and Miska, 2011).
back to a zero drilling rate. he laboratory correlation obtained in this manner is shown
in Figure 7.43.
he other factors such as permeability of the formation have a signiicant efect on the
ROP. In permeable rocks, the drilling luid iltrate can move into the rock ahead of the
bit and equalize the pressure diferential acting on the chips formed beneath each tooth.
Formation as nearly an independent or uncontrollable variable is inluenced to a certain
extent by hydrostatic pressure. Laboratory experiments indicate that in some formations
increased hydrostatic pressure increases the formation hardness or reduces its drill-ability. he mineral composition of the rock also has some efect on ROP. Rocks containing hard, abrasive minerals can cause rapid dulling of the bit teeth. Rocks containing
gummy clay minerals can cause the bit to ball up and drill in a very ineicient manner.
4) Mechanical Factors
he mechanical factors are also sometimes called as bit operating conditions. he following mechanical factors afect the ROP – i) bit type, ii) rotary speed, and iii) weight
on bit.
i) Bit Type: he bit type selection has a signiicant efect on rate of penetration. For
rolling cutter bits, the initial penetration rates for shallow depths are oten highest when
using bits with long teeth and a large cone ofset angle. However, these bits are practical
only in sot formations because of rapid tooth wear and sudden decline in penetration
rate in harder formations. he lowest cost per foot drilled usually is obtained when
using the longest tooth bit that will give a tooth life consistent with the bearing life
at optimum bit operating conditions. he diamond and PDC bits are designed for a
given penetration per revolution by the selection of the size and number of diamonds
or PDC blanks. he width and number of cutters can be used to compute the efective
Basics of Drill String Design 383
number of blades. he length of the cutters projecting from the face of the bit (less the
bottom clearance) can limit the depth of the cut. he PDC bits perform best in sot,
irm, and medium-hard, nonabrasive formations that are not gummy. herefore, the bit
type selection i.e., whether a drag bit, diamond bit, or roller cutter bit must be used and
the various tooth structures afect to some extent the drilling rate obtainable in a given
formation must be considered.
Figure 7.44 shows the characteristic shape of a typical plot of ROP vs. WOB obtained
experimentally where all other drilling variables remain constant. No signiicant penetration rate is obtained until the threshold bit weight is exceeded (point a). ROP
increases gradually and linearly with increasing values of bit weight for low-to-moderate values of bit weight (segment ab). A linear sharp increase curve is again observed
at the high bit weight (segment bc). Although the ROP vs. WOB correlations for the
discussed segments (ab and bc) are both positive, segment bc has a much steeper slope,
representing increased drilling eiciency. Point b is the transition point where the rock
failure mode changes from scraping or grinding to shearing. Beyond point c, subsequent increases in bit weight cause only slight improvements in ROP (segment cd).
In some cases, a decrease in ROP is observed at extremely high values of bit weight
(segment de). his type of behaviour sometimes is called bit loundering (point d – bit
loundering point). he poor response of ROP at high WOB values is usually attributed
to less-eicient hole cleaning because of a higher rate of cuttings generation, or because
of a complete penetration of a bit’s cutting elements into the formation being drilling,
without room or clearance for luid bypass.
ii) Rotary Speed: Figure 7.45 shows a characteristic shape typical response of ROP
vs. rotary speed obtained experimentally where all other drilling variables remain constant. Penetration rate usually increases linearly with increasing values of rotary speed
(N) at low values of rotary speed (segment ab). At higher values of rotary speed (ater
point b, segment b to c), the rate of increase in ROP diminishes. he poor response of
penetration rate at high values of rotary speed usually is also attributed to less eicient
bottomhole cleaning. Here, the bit loundering is due to less eicient bottomhole cleaning of the drill cuttings.
Combined Efect of Bit Weight and Rotary Speed on ROP
Maurer (1962) developed a theoretical equation for rolling cutter bits relating ROP to
bit weight, rotary speed, bit size, and rock strength. he equation was derived from the
Bit Floundering Point
ROP
d
c
e
b
a
Weight on bit
Figure 7.44 Typical response of ROP to increasing bit weight (Mitchell and Miska, 2011).
384 Fundamentals of Sustainable Drilling Engineering
ROP
Bit Floundering Point
c
b
Rotary Speed
a
Figure 7.45 Typical response of ROP to increasing rotary speed (Mitchell and Miska, 2011).
following observations made in single-insert impact experiments – i) the crater volume
is proportional to the square of the depth of cutter penetration, ii) the depth of cutter
penetration is inversely proportional to the rock strength. For these conditions, the
equation can be written as:
2
ROP
Here,
ROP
K
Sc
Wb
Wtb
db
N
Wo
db
K Wb
Sc2 db
Wtb
db
N
(7.37)
t
= rate of penetration, t./min
= constant of proportionality
= compressive strength of the rock
= bit weight
= threshold bit weight
= bit diameter
= rotary speed
= threshold bit weight per inch of bit diameter
t
his theoretical relation assumes perfect borehole cleaning and incomplete bit tooth
penetration. Bingham (1965) suggested the following drilling equation on the basis of
considerable laboratory and ield data. he equation can be written as:
ROP
Here,
K
a5
K
W
db
a5
N
(7.38)
= constant of proportionality that includes the efect of rock strength
= bit weight exponent
In this equation, the threshold bit weight was assumed to be negligible and bit weight
exponent must be determined experimentally for the prevailing conditions.
iii) Weight on Bit: he signiicance of WOB can be shown as explained by
Figure 7.46. he igure shows that no signiicant penetration rate is obtained until the
threshold bit weight (Wt ) is applied (Segment oa, i.e. up to point a). he penetration rate
Rate of Penetration
Basics of Drill String Design 385
d
c
Threshold
Bit Weight
e
b
a
Weight on bit
Figure 7.46 Typical bit weight response with ROP.
then increases rapidly with increasing values of bit weight (Segment ab). hen a constant rate in increase (linear) in ROP is observed at moderate bit weight (Segment bc).
Beyond this point (c), only a slight improvement in the ROP (segment cd) is observed.
In some cases, a decrease in penetration rate is observed at extremely high values of bit
weight (Segment de). his behavior is called bit loundering. It is due to less eicient
bottomhole cleaning (because the rate of cutting generation has increased).
5) Hydraulic Factor
Hydraulic factor is also called bit hydraulics. he two hydraulic factors afect the ROP
greatly – i) jet velocity, and ii) bottomhole cleaning. he mechanical factors of weight on the
bit and rotary speed are then linearly related to the drilling rate, provided the hydraulic factors are in proper balance to insure proper cleaning of the hole. he hydraulic factors afect
drilling rate only when they inluence the rate of penetration or the eiciency of the drilling.
i) Jet Velocity: Signiicant improvements in penetration rate could be achieved by
a proper jetting action at the bit. he improved jetting action promoted better cleaning of the bit face as well as the hole bottom. here exists an uncertainty on selection
of the best proper hydraulic objective function to be used in characterizing the efect
of hydraulics on penetration rate. Bit hydraulic horsepower, jet impact force, Reynolds
number, etc, are commonly used objective functions for describing the inluence of
bit hydraulics on ROP. Eckel (1968) studied with micro bits in a laboratory drilling
machine. He made the most extensive laboratory study to date of the relation between
penetration rate and the level of hydraulics. His study was at constant bit weight and
rotary speed. Eckel proposed the following model based on Reynolds number:
N Re
Here,
Ks
f
v
dnz
a
Ks
f
v dnz
a
= a scaling constant
= drilling luid density
= low rate
= nozzle diameter
= apparent viscosity of drilling luid at 10,000 s–1
(7.39)
386 Fundamentals of Sustainable Drilling Engineering
Penetration Rate, ft/hr
100
Indiana lime
Pbh – Pt =500 psi
N = 75 rev/min
db = 1.25 in.
W
10
1
1
10
Reynolds - Number Function,
1,500 lbf
1,000 lbf
500 lbf
100
1
1,976
f
dnz
Figure 7.47 Efect of Reynolds number and WOB on ROP (Eckel, 1968).
In Eq. (7.39), the shear rate of 10000 s–1 was chosen as representative of shear rates
present in the bit nozzle. he scaling constant, K s , is somewhat arbitrary, but a constant
value of 1/1,976 was used by Eckel to yield a convenient range of Reynolds-number
group. Figure 7.47 shows the experimental results of Eckel’s inding. It is noted that
increasing the Reynolds number function for the full range of the Reynolds number
studied increased ROP. He found that when the bit weight was increased, the correlation curve simply was shited upward as shown in the igure.
ii) Bottomhole Cleaning: It is one of the most important mechanisms for cutting
transport in rotary drilling. However, proper bottomhole cleaning is very diicult to
achieve in practice. he jetting action of the mud crossing through the bit nozzles has to
provide suicient velocity and cross low across the rock face to efectively remove cuttings from around the bit as rock is newly penetrated. his would prevent cuttings from
building up around the bit and teeth (bit balling), prevent excessive grinding of the cuttings and clear them on their way up the annulus, and maximize the drilling eiciency.
here are many variables that play a part in the eiciency of bottomhole cleaning. hese
variables include bit weight and rotation speed, bit type, low rate, jet velocity, diferential
pressure, nozzle size, location and distance from rock face, solids volume, and cutting
characteristics etc. Proper bottomhole cleaning will eliminate excessive regrinding of
drilled solids, and will result in improved penetration rates. he eiciency of bottomhole
cleaning can be achieved through proper selection of bit nozzle sizes. he maximum
hydraulic horsepower and the maximum impact force are the two requirements to get
the best hydraulic cleaning at the bit. Both these items increase when the circulation rate
increases. However, when the circulation rate increases, so does the frictional pressure
drop. Inadequate hole cleaning can lead to costly drilling problems, such as: mechanical
pipe sticking, premature bit wear, slow drilling, formation fracturing, excessive torque
and drag on drill string, diiculties in logging and cementing, and diiculties in casings
landing. he most prevalent problem is excessive torque and drag, which oten leads to
the inability of reaching the target in high-angle/extended-reach drilling.
6) Drilling Fluid Properties
here are functions of drilling luids that can have unique challenging inluences. For
example, the two mud properties that have direct impact on hole cleaning are viscosity
Basics of Drill String Design 387
and density. he main functions of density are mechanical borehole stabilization and the
prevention of formation-luid intrusion into the annulus. Any unnecessary increase in
mud density beyond fulilling these functions will have an adverse efect on the ROP. his
density increase may cause fracturing of the formation under the given in-situ stresses.
So, mud density should not be used as a criterion to enhance hole cleaning. In contrast,
viscosity has the primary function of the suspension of added desired weighting materials, such as barite. he following drilling luid properties afect the ROP – i) density (i.e.
mud weight), ii) rheological low properties (i.e. viscosity), iii) iltration characteristics
(i.e. iltrate loss), iv) solid content and size distribution, and v) chemical composition.
i) Density: An increase in drilling luid density causes a decrease in penetration rate
for rolling cutter bit. he density of the mud controls the pressure diferential across the
zone of crushed rock beneath the bit. If the density increases, it causes an increase in
the bottomhole pressure beneath the bit. hus, there is an increase in the pressure differential between the borehole pressure and the formation luid pressure. Cunningham
and Eenink (1959) conducted experiments on Berea sandstone and clay/water mud.
Figure 7.48 shows the efect of mud density (i.e. mud weight) on ROP based on the
experimental data. It shows a wider range of borehole and formation luid pressure.
Note that a good correlation is obtained when the data are replotted with drilling rate
as a function of overbalance (right side of Figure 7.48). Paiaman et al. (2009) reported
that ROP decreases with the increase of mud weight as shown in Figure 7.49.
14
12
12
P f= 4
psig
psig
psig
,000
,000
P =3
psig
4
,000
,000
6
f
8
P f= 2
10
Drilling Rate, ft/hr
14
P f= 1
Drilling Rate, ft/hr
Efect of Mud Density (Overbalance) on Penetration Rate:
Bourgoyne and Young (1974) observed that the relation between overpressure and penetration rate could be represented approximately by a straight line on semilog paper for
the range of overbalance commonly used in ield practice. In addition, they suggested
normalizing the penetration rate data by dividing by penetration rate corresponding to zero overbalance (borehole pressure equal to formation pressure). Figure 7.50
shows the normalized ROP and overbalance for the data as suggested by Bourgoyne
and Young. Note that a reasonably accurate straight-line representation of the data is
possible for moderate values of overbalance.
10
8
6
4
2
2
0
0
0
1000 2000 3000 4000 5000 6000 7000
Pm – Mud Column Pressure, PSI
0 2000 4000 6000 8000
(Pm – Pf ) Diferential Pressure,
PSI
Figure 7.48 Efect of Mud Weight on Rate of Penetration (Bourgoyne, 1986).
388 Fundamentals of Sustainable Drilling Engineering
ROP (ft/hr)
40
y = −14.784
+ 158.96
R2 = 0.7315
30
20
10
0
8.0
8.5
9.0
9.5
10.0
Mud Weight (ppg)
10.5
11.0
Figure 7.49 Efect of Mud Weight on Penetration Rate (Paiaman et al., 2009).
Drag bit
Diamond bit
Rolling cutter bit
Rolling cutter bit
Rolling cutter bit
Rolling cutter bit
Rolling cutter bit
0
log
R
Ro
-1
-2
0
500
1,000
1,500
2,000
2,500
Overbalance, psi
Figure 7.50 Exponential relation between penetration rate and overbalance for roller-cone bits (Mitchell
and Miska, 2011).
From Figure 7.50, we see that the equation for the straight line is given by:
log10
Here,
Pbh
Pf
R
Ro
m
R
Ro
m Pbh
Pf
(7.40)
= circulating bottomhole pressure, psi
= formation luid pressure, psi
= rate of penetration (ROP), t./hr
= ROP at zero overbalance, Pbh Pf
0, t./hr
= slope of the straight line in the plot, psi–1
he circulating bottomhole pressure (Pbh ) can be expressed in terms of ECD (equivalent
circulation density, c ) as follows:
Pbh
0.052 c D
(7.41)
Basics of Drill String Design 389
Here,
D
= total depth, t.
Also the Formation luid pressure Pf can be represented bypore pressure gradient, G p
as follows:
(7.42)
0.052 G p D
Pf
herefore, applying Eqs. (7.41) and (7.42), Eq. (7.40) can be re-written as follows:
log10
R
Ro
0.052 mD
c
Gp
(7.43)
Equation (7.43) can be written as:
log10
Here,
a4
R
Ro
a4 D
Gp
c
(7.44)
= overbalance exponent
his equation is useful for studying the efect of mud density changes on ROP. So, Eq.
(7.44) can be re-arranged as follows:
R2
R1
Here
R1
R2
1
2
e
2.304 a4 D
1
2
(7.45)
= rate of penetration (ROP) corresponding to 1, t./hr
= rate of penetration (ROP) corresponding to 2, t./hr
= old mud weight, lbf/gal
= new mud weight, lbf/gal
Example 7.7: Estimate the change in penetration rate ater the mud-weight is increased
from 25 t./hr to a certain rate using the following data: a4 = 3.56 x10–05, D = 12,500 t.,
12.5 lb f / gal, 2 13.5 lb f / gal.
1
Solution:
Given data:
R1 = old rate of penetration = 25 t./hr
a4 = overbalance exponent = 3.56 x 10–05 t.
D = total depth = 12,500 t.
= old mud weight = 12.5 lbf/gal
1
= new mud weight =13.5 lbf/gal
2
Required data:
R2 = new rate of penetration in t./hr
390 Fundamentals of Sustainable Drilling Engineering
he new ROP can be given by Eq. (7.45) as:
So,
R2
R1
e
2.304 a4 D
R2
1
2
R1 e
e
05
2.304 3.56 10
1.02528
25
12,500 12.5 –13.5
ft
hr
0.424 10.6
e
1.02528
ft
hr
ft
. If the mud weight is increased by
hr
8.33%, ROP m is increased by 8%, ROP decreases by 57.6%.
ii) Viscosity: Penetration rates tend to decrease with increasing viscosity (Figure
7.51). he luid viscosity controls the parasitic frictional losses in the drill string and
thus the hydraulic energy available at the bit jets for cleaning. here is also experimental
evidence that increasing plastic viscosity reduces penetration rates even when the bit is
perfectly clean (Figure 7.52). Plastic viscosity is that part of the resistance to low caused
by mechanical friction. he friction is caused by viscosity of the luid phase of the drilling mud. In addition, viscosity acts on the mobility of cuttings. With a high viscosity,
cuttings tend to remain stuck on the bottom involving their re-drilling and thus a reduction in the performances of the bit. he best rates of penetration will be obtained with a
luid having a viscosity as low as possible at the exit of the nozzles of the bit (Figure 7.52).
iii) Filtration Characteristics: Penetration rate increases with increasing iltration
rate. he iltration characteristics of the mud control the pressure diferential across the
bit nozzle and formation rock.
10.6
Rate of Penetration
herefore, new rate of penetration, R2
Viscosity
ROP (ft/hr)
Figure 7.51 ROP vs. viscosity plot (Alum and Egbon, 2011).
40
35
30
25
20
15
10
5
0
y =-4.3912 × +36.562
2
R = 0.6087
0
1
2
6
3
4
5
Plastic Viscosity (cP)
Figure 7.52 ROP vs. plastic viscosity plot (Paiaman et al., 2009).
7
8
Basics of Drill String Design 391
iv) Solid Content and Size Distribution: Drilling muds are usually composed of
a continuous luid phase in which solids are dispersed. Plastic viscosity is that part of
the resistance to low caused by mechanical friction. he friction is caused by solid
concentration, size and shape of solids, and viscosity of the luid phase. Penetration
rate decreases with increasing solids content (Figure 7.53a and 7.53b). Figure 7.53a
shows the variation of solid content rate of penetration and on the other hand, Figure
7.53b shows the efect of solid content on ROP at constant plastic viscosity. he solids
content also controls the pressure diferential across the bit nozzle and formation rock.
For practical ield applications, plastic viscosity is regarded as a guide to solids control.
Plastic viscosity increases if the volume percent remains constant, and the size of the
particle decreases. Decreasing particle size increases surface area, which increases frictional drag.
v) Chemical Composition: he chemical composition of the luid has an efect on
penetration rate, such that the hydration rate and bit-balling tendency of some clays are
afected by the chemical composition of the luid.
7) Bit Toot Wear
Most bits tend to drill slower as the drilling time elapses because of tooth wear. he
tooth length of milled tooth rolling cutter bits is reduced continually by abrasion and
chipping. he teeth are altered by a hard facing or case-hardening process to promote a
self-sharpening type of tooth wear. However, while this tends to keep the tooth pointed,
it does not compensate for the reduced tooth length. he teeth of tungsten carbide
insert-type rolling cutter bits and PDC bits fail by breaking rather than by abrasion.
Oten, the entire tooth is lost when breakage occurs. Reductions in penetration rare due
to bit wear usually are not as severe for insert bits as for milled tooth bits unless a large
number of teeth are broken during the bit run.
Several authors have published mathematical models for computing the efect of
cutting-element wear on penetration rate for roller-cone bits. Galle and Woods (1963)
published the following model:
(7.46)
= the fractional tooth height that has been worn away, in
= tooth wear exponent
y = –2.0454 × +33.767
40
35
30
25
20
15
10
5
0
y = –2.8264 × +36.071
40
R2 = 0.6186
2
R = 0.6181
ROP (ft/hr)
ROP (ft/hr)
Here,
h
a7
a7
1
0.928125 h2 6h 1
ROP
30
20
10
2
4
6
8
10
12
14
16
2
4
6
8
Solid Content (%)
Solid Content (%)
(a)
(b)
Figure 7.53 ROP vs. solid content plot (Paiaman et al., 2009).
10
12
392 Fundamentals of Sustainable Drilling Engineering
A value of 0.5 was recommended for the exponent a7 for self-sharpening wear of milledtooth bits, the primary bit type discussed in Galle and Woods (1963). Bourgoyne and
Young (1974) suggested a similar but less complex relationship:
ROP
exp
(7.47)
a7 h
Bourgoyne and Young suggested that the exponent a7 be determined on the basis of the
observed decline of penetration rate with tooth wear for previous bit runs under similar
conditions.
Example 7.8: he initial penetration rate of 30 t./hr was recorded in shale at the beginning of a bit run. he previous bit was identical to the present bit and was operated
under the same operating conditions (such as bit weight, rotary speed, mud density,
and other factors). However, a drilling rate of 10 t./hr was observed in the same shale
formation just before pulling the bit. In addition, the previous bit was graded as T-6.
Calculate the approximate value of a7.
Solution:
Given data:
ROP1 = initial rate of penetration = 30 t./hr
ROP2 = inal rate of penetration = 10 t./hr
h1
= 0 in
6
h2
= T-6 =
0.75 in
8
Required data:
a7
= exponent constant
he new ROP can be given by Eq. (7.47) as:
ROP1
Ke
a7 h1
Ke
a7 0
K
and
ROP2
a7 h2
Ke
Ke
a7 0.75
Ke
0.75a7
Now, dividing the irst equation by the second equation as:
ROP1
ROP2
K
Ke
0.75a7
e 0.75a7
Taking the natural logarithm of both sides and solving for a7 gives:
ROP1
ROP2
0.75
ln
a7
30
10
0.75
ln
1.46
7.10 Rate of Penetration Modelling
he main characteristic of rotary drilling penetration performance is not only the
fracture of the rock on the bottom, but also the removal of the fractured cuttings
Basics of Drill String Design 393
from the rock face in an instant and eicient manner to provide further fracturing
and drilling progress. Due to the complexity of understanding the rate of penetration mechanism of drilling operations, industry pioneers have adopted empirical
approaches by quantifying the efects of the controllable parameters on ROP performance, more than the analytical model implementation for the understanding
of rate of penetration in the industry of drilling. It is reportedly known that time
spent for the drilling of wells is composed by up to 30% “rotating time” of the total
well construction time. Penetration rate optimization is consequently an important
cost reduction consideration. It is assumed that all of the properties of the formations afecting rate of penetration, that is subject to optimization are macroscopically homogeneous and are with unique physical properties throughout the entire
interval.
he development of an ROP model is a challenging job due to the known and
unknown variables. As a result, numerous investigations have been done in this
area. In considering which variables to choose for developing an ROP model, experience and research suggest the eight variables as mentioned earlier. hese variables
are mainly – i) mud properties, ii) hydraulics, iii) bit type, iv) weight on bit, v) drill
string rotation speed, vi) depth, vii) bit tooth wear, and viii) formation properties.
However, for horizontal and inclined wellbores, hole cleaning is also a major factor
that inluences the ROP. he basic interactive efects between these variables were
determined by design experiments. Variable interaction exists when the simultaneous increase of two or more variables does not produce an additive efect as compared with the individual efects. he meaning of variable interaction is illustrated
in Figure 7.54.
In addition, the mathematical model for the penetration rate could be written as
a function of drilling parameters such as WOB/db, RPM, as given in below section.
Also the bit tooth wear has been considered in the same equation for the optimization
purposes.
Increasing Variables
Relative Drilling Rate
WOB
N
WOB+N
Negative
Interaction
Actual WOB + N
WOB
Hydraulic
WOB + Hydraulic
Actual WOB + Hydraulic
Figure 7.54 Positive and negative interaction.
Positive
Interaction
394 Fundamentals of Sustainable Drilling Engineering
7.10.1 Established Models for Rate of Penetration
1) ROP Models:
Graham and Muench (1959) are some of the irst researchers who conducted evaluations on drilling data to determine optimum weight on bit and rotary speed combination. hey used a mathematical analysis method for drilling related costs to drill
under optimum circumstances. Empirical mathematical expressions were derived
for bit life expectancy and the drilling rate as a function of depth, rotary speed and
bit weight. he proposed mathematical relations contained constants representative
of the respective formations existing in the area. heir study resulted in being able
to propose optimum weight on bit and rotary speed by means of calculations under
any drilling conditions in order to minimize total drilling costs. here are three most
widely used models for estimating rate of penetration; i) Maurer, ii) Galle and Woods,
and iii) Bourgoyne and Young.
Maurer’s Method: Maurer (1962) derived ROP equation for roller-cone type of bits
considering the rock cratering mechanisms. His method was developed based on
a theoretical penetration equation as a function of WOB, RPM, bit size and rock
strength. he developed equation was based on observations such as the amount
the crater cutter can create, rock strength related considerations. In addition, it was
based on ‘perfect cleaning’ condition where all of the rock debris is considered to be
removed between tooth impacts. A working relation between drilling rate, weight
on bit and string speed was achieved. It was also mentioned that the obtained relationships were a function of the drilling depth. Maurer rate of drilling equation is
expressed as:
dFD
dt
Here
FD
t
V
db
4 dV
db2 dt
(7.48)
= distance drilled by bit, t.
= time, hr
= volume of rock removed,
= bit diameter
Galle and Woods’ Method: Galle and Woods (1963) were some of the irst researchers to investigate the efect of best constant bit weight and rotary speed for lowest cost
and developed semi-empirical equations. hey investigated the efects of weight on bit,
rotary speed, and cutting structure dullness on drilling rate, rate of tooth wear and
bearing life. hey presented graphs and procedures for ield applications to determine
the best combinations of constant weight and rotary speed. hey assumed a relation for
the wear rate as a function of time in relation to inverse ratio of bit weight to bit diameter. he given equation was limited with a load application of 10,000 lbf/in of bit diameter. hey also published an equation showing a relationship between the tooth wear
rate and the rotary speed for only milled tooth bits designed for sot formations. In their
graphs, the drilling cost, footage, drilling hours and condition of teeth and bearing of
the dull bit may be calculated. he drilling costs were demonstrated to be reduced using
Basics of Drill String Design 395
the recommended combinations of the drilling parameters. hey presented the drilling
rate equation as given in (7.49) as a function of WOB and RPM.
dFD
dt
C fd
Wk
r
ap
(7.49)
Here
C fd = formation drillability parameter
a
= 0.028125h2 + 6.0h + 1
h
= bit tooth dullness, fractional tooth height worn away, in
p
= 0.5 (for self-sharpening or chipping type bit tooth wear)
k
= 1.0 (for most formations except very sot formations), 0.6 (for very sot
formations)
r
= function of N which can be expressed as Eq. (7.50) and Eq. (7.51)
7.88WOB
W = function of WOB and db, such that W
db
Now, r can be expressed for two types of formations.
For hard formation:
100
r
e
N2
r
e
N2
100
N 0.428 0.2 N 1 e
N2
N 0.750 0.5 N 1 e
N2
(7.50)
For sot formation:
100
Here
N
100
(7.51)
= rotational speed
Galle and Woods (1963) also deined rate of dulling and bearing life equation respectively as shown in Eq. (7.52) and Eq. (7.53).
Rate of dulling equation:
dh
dt
1 i
Af a m
(7.52)
L
N
(7.53)
where:
i
= N 4.348 10 5 N 3
m = 1359.1 714.19 log10 W
Bearing life equation:
B
S
where:
S
= drilling luid parameter
L
= tabulated function of W used in bearing life equation
396 Fundamentals of Sustainable Drilling Engineering
Bingham Model: Bingham (1965) proposed a rate of penetration equation based on
laboratory data as stated in Eq. (7.54). In his equation, the threshold bit weight was
assumed to be negligible and rate of penetration was a function of applied weight on the
bit and rotary speed of the string. he bit weight exponent, a5 was set to be determined
experimentally through the prevailing conditions.
ROP
a5
WOB
K
db
N
(7.54)
Here
ROP = rate of penetration
K
= proportionality constant for rock strength efect
a5 = bit weight exponent
Bourgoyne and Young’s Method: Bourgoyne and Young’s (1973 and 1974) method is
the most important drilling optimization method since it is based on statistical synthesis of the past drilling parameters. A linear penetration model is being introduced and
multiple regression analysis over the introduced rate of penetration equation is being
conducted. For that reason this method is considered to be the most suitable method
for the real-time drilling optimization. hey developed a mathematical model and a
summary of the equations is given below.
he rate of penetration is expressed as:
8
d
ROP
dt
Here
a1
i
ai
xi
a1
e
ai xi
i
2
(7.55)
= formation strength parameter
= index number for ith drilling rate of penetration equation coeicient or summation index for ith data point
= set of constants that relates with each of the drilling parameters considered
= set of dimensionless drilling parameters calculated from the actual collected
drilling data
he normalization constants given in the general ROP Eq. (7.55) are modiied accordingly as a function of the data property when used as an input to the regression cycle.
When modiied normalization constants are used, the coeicients should give accurate predictions for ROP. So, the dimensionless drilling parameters in Eq. (7.55) are
described as following:
Formation Resistance:
1.0
(7.56)
10,000 TVD
(7.57)
x1
Consolidation Efects:
x2
Basics of Drill String Design 397
Overpressure Efects:
TVD 0.69 g p 9.0
x3
(7.58)
Diferential Pressure:
x4
TVD g p
(7.59)
ec
Bit diameter and WOB:
x5
ln
WOB
db
WOB
db
WOB
db
4.0
t
(7.60)
t
Rotary Speed:
ln
x6
N
100
(7.61)
h
(7.62)
Tooth Wear:
x7
Bit Hydraulic:
x8
Here
TVD
gp
h
m
Q
dn
mQ
350 dn
(7.63)
= total vertical depth, t.
= pore pressure gradient of the formation, lbf/gal
= equivalent circulating mud density at the bottomhole, lbf/gal
ec
WOB
db
WOB
db
ln
= weight on bit per inch of bit diameter, 1000 lbf/in
= threshold weight on bit per inch of bit diameter, 1000 lbf/in
t
= bit tooth dullness, fraction of original tooth height worn away
= mud density, lbf /gal
= low rate, gal/min
= Viscosity
= bit nozzle diameter, in
he constants given in Eq. (7.55), a1 through a8 should be determined through the multiple regression analysis using the drilling data. hey represent the efects of formation
strength [Eq. (7.56)], compaction efect [Eq. (7.57)], over pressure [Eq. (7.58)], pressure
diferential [Eq. (7.59)], bit weight [Eq. (7.60)], rotary speed [Eq. (7.61)], tooth wear
[Eq. (7.62)] and hydraulic exponent [Eq. (7.63)]. he threshold weight on bit and bit
398 Fundamentals of Sustainable Drilling Engineering
diameter value is not a constant, signiicantly, it may have varying magnitudes based
on formation characteristics, and for this reason whole data trend is observed when
this threshold value is determined as an input. he same value could easily be obtained
from a drill-of test. he fractional tooth height calculation methodology is a function
of reference abrasiveness constants in the same ield, and is related to the time bit in
use have operated. herefore, combining the Eqs. (7.56 – 7.63), the open form of the
general ROP Eq. (7.55) for roller cone bit types is given as:
a1 a2 10000 TVD
d
ROP
dt
a3TVD 0.69 g p 9.0
a4 TVD g p
ec
a5 ln
WOB
db
4.0
e
WOB
db
WOB
db
t
a6 ln
N
100
a7
h
a8 ln
mQ
350 dn
t
(7.64)
Here
al
a2
a3
a4
a5
a6
a7
a8
= formation strength parameter
= exponent of the normal compaction trend
= under compaction exponent
= pressure diferential exponent
= bit weight exponent
= rotary speed exponent
= tooth wear exponent
= hydraulic exponent
he considered efects of the controllable and uncontrollable drilling variables on ROP
are individually described below for each item. Figure 7.55 gives the schematically represented general rate of penetration equation for roller-cone bit types.
a3
Under Compaction
X3 = D0.69 (gp – 9)
a2
Normal
Compaction
a4
Pressure
Diferential
X4 = D(gp – )
X2 = (10000 – D)
a5
ROP
a1
WOB
dF
— = f(1)f(2)......f(8)
dt
Formation
Strength
X5 =
W
W
–
da
da
4–
a8
Hydraulic
pq
X6 =
350 da
a6
RPM
a7
Tooth wear
X7 = –h
Figure 7.55 General rate of penetration equation.
X6 = Lx
N
135
W
da
Basics of Drill String Design 399
Bourgoyne and Young (1973) also expressed bit wear by using certain assumptions.
Tooth wear model is deined as:
dh
dt
Here
H1 , H 2 , H 3
H
WOB
db
max
H3
H
N
100
WOB
db
H1
WOB
db
H2
2
1 H2 h
4
1
max
WOB
db
max
(7.65)
= Constants that depend on bit type
= formation abrasiveness constant, hrs
= Bit weight per inch of bit diameter at which the bit teeth would fail
instantaneously, 1000 lbf/in
Bearing wear model:
dBbw
dt
1
B
N
100
WOB
4 db
b
(7.66)
Here
Bbw = bearing wear fraction of the total life
= life of teeth at standard conditions, hrs
B
b
= constant
Reza and Alcocer Method: Reza and Alcocer (1986a) developed a dynamic non-linear,
multidimensional, dimensionless drilling model for deep drilling applications using
theorem. Buckingham
theorem is a dimensional analysis theorem
Buckingham
used to generate equations in dimensionless forms. he model is based on three equations – rate of penetration, rate of bit dulling and rate of bearing wear. heir study
relected the efects of the following variables on three given equations: weight on bit,
rotary speed, bit diameter, bit nozzle diameter, bit bearing diameter, drilling luid characteristics (density and viscosity), drilling luid circulation rate, diferential pressure,
rock hardness, temperature and heat transfer coeicient. hey deined the rate of penetration as given in Eq. (7.67) in a form of non-linear, multivariable equation.
ROP
N dbd
C1
2
Ndbd
a
3
Ndbd
Q
b
Edbd
WOB
c
pdbd
WOB
Here
ROP = rate of penetration, t./min
C1 = proportionality constant in penetration rate equation
dbd = bearing diameter, in
= drilling luid kinematic viscosity, cp
Q
= volumetric low rate, gpm
E
= rock hardness, psi
d
(7.67)
400 Fundamentals of Sustainable Drilling Engineering
In Eq. (7.67), C1, a, b, c, and d are unknown parameters. In order to ind the coeficients using the available data a linear regression analysis methodology was applied
ater taking the natural logarithm of both sides of the equation above. When the solution of the ROP equation was written the following relation was reported to investigate
the deep well drilling problems, equation (7.68).
ROP
N dbd
0.33
2
Ndbd
0.43
3
Ndbd
Q
0.68
0.91
Edbd
WOB
pdbd
WOB
0.15
(7.68)
he general equation for the rate of bit dulling was obtained as in equation (7.69).
dbt
N db
Q
0.001
N db3
0.56
WOB
E db2
0.26
db
Q
0.03
(7.69)
Here
dbt = bit tooth dullness, fraction of original tooth
db = bit diameter
he general equation for the bit bearing life was obtained as in equation (7.70).
Bbw
N
T ht dbd
0.05
N WOB
0.4
0.51
2
N dbd
Q
3
N dbd
0.5
(7.70)
Here
Bbw = bearing wear fraction of the total life
T
= temperature at the bottom of the hole, °F
ht
= heat transfer coeicient, BTU /
ft 2 hr
dbd = bearing diameter, in
In the second part of their study Reza and Alcocer (1986b) mentioned that the exponents of the derived models are sensitive to unknowns, and there would be luctuations
from region to region and well to well. For that particular reason their inding was a
generalization of the model speciically for a region and in deep ield/wells.
Warren’s Model: Warren derived a model of the drilling process for tri-con bits
called perfect-cleaning model in 1987 and later modiied by Hareland (Hareland and
Hoberock, 1993). he basic idea is that under steady-state drilling conditions, the rate
of cutting removal from the bit is equal to the rate at which new chips are formed. h is
implies that the cutting-generation process, the cutting removal, or a combination of
the two processes controls the ROP. he perfect-cleaning model, which is shown in the
following equation, is reviewed as a starting point for development of an imperfectcleaning model.
ROP
a S 2 db2
N bWOB 2
Here
a, b, c = bit constant for Warren’s constant
S
= conined rock strength, psi
c
N db
1
(7.71)
Basics of Drill String Design 401
Unfortunately, ROP in most ield cases is signiicantly inhibited by the rate of cuttings
removal from under the bit. hus Eq. (7.71) is not efective for predicting ield ROP
without modiication to account for imperfect cleaning. herefore, it is necessary to
modify the ROP model for imperfect cleaning conditions, which happen because of
real situations. hus the resultant expression for ROP is:
a S 2 db2
ROP
N WOB 2
b
N db
1
c db
f
(7.72)
Fjm
Here
f
Fjm
= luid speciic gravity
= mud plastic viscosity, cp
= modiied jet impact force, klbf
he modiied impact force is calculated from the following equation:
Fjm
Here
Av
Fj
1 Av 0.122 Fj
(7.73)
= ratio of jet velocity to return velocity
= jet impact force, klbf
If Av is the ratio of the jet velocity to the luid return velocity, the Av (for three jets) is
given by:
Av
vn
vf
0.15 db2
(7.74)
3 dn2
Modiied Warren’s Model: Neither Winters (Winters et al., 1987) nor Warren (Warren,
1987) addresses Chip’s hold down efects on penetration rate modeling, but it is known
that this efect is important. It is an estimation of the resultant forces on a chip when the
bit generates it. To establish the best relationship for chip hold down, data from laboratory full scale drilling tests was used in which bottomhole pressure varied and other
conditions remained constant. A reasonable it to these diferent lithologies is given by:
f c Pe
cc ac Pe 120
bc
(7.74)
Here
Pe
= diferential pressure
f c Pe = chip hold down function
ac , bc , cc = lithology-dependent constant
Units of ac , bc , cc are chosen such that f c Pe is dimensionless. Equation (7.71) can now
be modiied to include chip hold down efect and becomes:
ROP
f c Pe
a S 2 db2
N b WOB 2
b
N db
c db
1
f
Fjm
(7.75)
402 Fundamentals of Sustainable Drilling Engineering
Hareland (Hareland et al., 1993) modiied this ROP model for the efect of bit wear on
ROP by introducing a wear function, W f into the model:
ROP W f fc Pe
a S 2 db2
N b WOB2
Here
BG
1
f
Fjm
BG
8
1
Wf
c db
b
N db
(7.76)
(7.77)
= change in bit tooth wear
It can be calculated based on the WOB, ROP, relative rock abrasiveness and conined
rock strength.
n
BG Wc
WOBi N i Arabr Si
i
i 1
(7.78)
Here
Wc = bit wear coeicient
Arabr = relative abrasiveness
Rock compressive strength is a function of pressure and lithology:
S So 1 as Pebs
(7.79)
Here
S
= conined rock strength
So = unconined rock strength
as , bs = coeicient depends on formation permeability
Pessier and Fear Method: Pessier and Fear (1992) elaborated the mechanical speciic
energy methodology which was developed by Teale (1962). hey performed simulator
tests in the computer and conducted laboratory tests to quantify and develop an energybalanced model for drilling of boreholes under hydrostatically pressurized conditions.
hey derived an equation for mechanical speciic energy, Eq. (7.80). hey found better
identiication methodologies (than WOB and ROP concentrated evaluation) for bearing problems of the drill bits, which are more quick and reliable by continuously monitoring Es and μ, Eq. (7.81).
Es
WOB
1
AB
36
Here
Es
AB
= bit speciic energy, psi
= borehole area, in2
13.33 s N
db ROP
T
db WOB
(7.80)
(7.81)
Basics of Drill String Design 403
s
= bit speciic coeicient of sliding friction,
= apparent viscosity at 10,000 sec–1, cp
Osgouei Model: Osgouei (2007) developed a drilling model for predicting the ROP
by considering the efect of the various drilling parameters. In his study, Bourgoyne
& Young’s model is improved and enhanced for both PDC and insert-tooth – roller
bits as well as for horizontal and directional wells. he major improvements are the
consideration of additional drilling parameters occurring due to inclination as well as
re-deinition of same drilling parameters due to PDC’s. He initiated the model as:
ROP
f1
f2
f3
f4
f5
f6
f7
f8
fn
(7.82)
fn represent the functional relations between penwhere f1 , f 2 , f 3 , f 4 , f 5 , f 6 , f 7 , f 8 ,
etration rate and various drilling variables. Each of these functions contains constants
which are shown as a1 through an . Determination of these constants is accomplished by
using a multiple regression analysis of collected drilling data.
he general form of the proposed model for roller-cone bits is
ROP
f1
f2
f3
f4
f5
f6
f7
f8
f9
f10
f11
(7.83a)
ROP
f1'
f 2'
f 3'
f 4'
f 5'
f 6'
f 7'
f 8'
f 9'
f10'
f11'
(7.83b)
For PDC bits
In the upcoming sections, the functions (f1, f2, f3 . . . . . , fn) are deined and presented for
both type of bits.
Efect of formation strength (f1) is deined by
f1'
f1 e a1
(7.84)
he functions of f1 & f1' primarily represent the efects of formation strength and bit
type on the penetration rate. hey also contain the efects of other parameters, which
are not included into consideration. he term f1 & f1' are expressed in the same units
as penetration rate and commonly is called the drillability of the formation. he drillability is numerically equal to the penetration rate that would be observed in the given
formation type (under normal compaction) when operating with a new bit at zero
overbalance, a bit weight, a rotary speed, and a depth of the “normalization” values.
he drillability of the various formations can be computed using drilling data obtained
from previous wells in the area.
Efect of compaction (f2) and (f3) are deined by:
f 2'
f 3'
f2
f3 e
e
a2 8800 TVD
a3TVD
0.69
g p 9.0
(7.85)
(7.86)
As seen from Eq. (7.85), normalization depth was used in his study is 8800 t. he functions f2 and f2' account for the rock strength increase due to the normal compaction with
depth, and f3 and f 3' model the efect of pore pressure gradient on penetration rate.
404 Fundamentals of Sustainable Drilling Engineering
Efect of diferential pressure (f4) and ( f 4' ) is deined by
f 4'
f4
e
a4 TVD g p
ec
(7.87)
Where measured depth is considered with determining ECD. he functions f4 & f 4'
model the efect of overbalance on penetration rate, and, thus assume an exponential
decrease in penetration rate with excessive bottomhole pressure.
he Efect of the Bit Diameter and Bit Weight (f5) & ( f 5') is deined by:
a5
WOB
db
f5
WOB
db
WOB
db
f 5'
WOB
db
(7.88)
c
a5
mech
(7.89)
c
Here
WOB
db
WOB
db
= critical weight on bit per inch of bit diameter, 1000 lbf/in
c
= mechanical weight on bit per inch of bit diameter, 1000 lbf/in
mech
It is noted that the penetration rate is directly proportional to (WOB/db) as mentioned
by several authors. he critical bit weight (WOB/db)c must be estimated by considering
drill string properties, bit type and ield data. he mechanical weight on bit (WOB/db)mech
is a concept usually observed when using PDC’s and is deined as the diference between
the applied weight on bit and pump-of force acting on the face of bit divided by the bit
diameter. According to Duklet and Bates (1980), the mechanical weight on bit is given by:
WOB
db
WOBapplied 0.942 Pb db 1
db
mech
Pb
Here
An
Q2
12031 An2
(7.90)
(7.91)
= the total nozzle area
he pump-of force is approximated by an empirical expression developed using previous Christensen tests. he pump-of force can be a substantial hydraulic force created
by the diferential pressures on the bit, due to the bit face pressure drop. his force tends
Basics of Drill String Design 405
to unload the cutting and is subtracted from the measured load to obtain the actual
weight on bit.
Efect of Rotary Speed (f6) and ( f 6') is deined by
f 6'
Here
Nc
a6
N
Nc
f6
(7.92)
= the critical rotary speed
Several authors assumed that penetration rate is directly proportional to N. Note that
the critical rotary speed (Nc) must be estimated by considering drill string properties,
bit type and ield data.
Efect of Tooth Wear (f7) and ( f 7' ) is deined by:
f 7'
f7
e
a7
h
(7.93)
Efect of Bit Hydraulic (f8) and ( f 8') is deined by:
f 8'
f8
Fj
a8
(7.94)
Fjc
he value depends on bit type, drilling mud property and pump pressure.
he Efect of Hole Cleaning (f9), (f10), (f11) and ( f 9'), ( f10' ), ( f11' ) is deined by:
f 9'
f10'
f11'
f9
f10
f11
Abed
Awell
0.2
Vactual
Vcritical
Cc
100
a9
(7.95)
a10
(7.96)
a11
(7.97)
Today, one of the most common applications in the petroleum industry is to drill on
inclined and horizontal wells. One of the major problems in drilling a horizontal and
inclined well is hole cleaning. he technology applied successfully in cleaning vertical
wells oten does not apply directly in horizontal and inclined wells. So, hole cleaning
plays an important role on developing the realistic functions to predict penetration
rate. he functions ( f9), ( f10), ( f11) and ( f 9'), ( f10' ), ( f11' ) deine the efect of hole cleaning
in horizontal, inclined and vertical sections of wells where roller cone bits as well as
PDC bits are used. Note that the equation (7.94) is a dimensionless function considering for horizontal section, equation (7.95) is simulating the inclined section and equation (7.96) is represented vertical section for proper hole cleaning for both PDC and
roller cone bits.
406 Fundamentals of Sustainable Drilling Engineering
If we apply Eqs. (7.84) – (7.97) to Eq. (7.83), the resultant equation will represent the
ROP equations for Osgouei Model.
ROP e a1 e
a2 8800 TVD
e
a3TVD 0.69 g p 9.0
e
a4 TVD g p
a5
WOB
db
a6
N
Nc
WOB
db
e
a7
a8
Fj
h
Fjc
Abed
Awell
0.2
ec
a9
Vactual
Vcritical
a10
Cc
100
a11
(7.98)
c
For PDC bits
ROP
e a1 e
WOB
db
WOB
db
a2 8800 TVD
e
a3TVD0.69 g p 9.0
e
a4 TVD g p
a5
mech
N
Nc
a6
e
a7
h
a8
Fj
Fjc
ec
Abed
Awell
0.2
a9
Vactual
Vcritical
a10
Cc
100
a11
(7.99)
c
2). Tooth Wear Model
As indicated in Bourgoyne & Young’s drilling model, ( f 7 ) & ( f 7' ) have a value of 1.0
when totally new tungsten carbide insert bits (IADC code: 517 & 523) and PDC bits are
used. Osgouei (2007) assumed that bit cone ofset selection is proper. So bearing wear is
negligible. he developed model for estimating frictional tooth dullness, h, is given by:
dh
dt
g1 g 2 g 3 g 4
(7.100)
he function g1 describes the efect of formation abrasiveness on tooth wear and deined
by:
g1
H3
(7.101)
H
In equation (7.100), the value of H3 for tungsten carbide insert bits (IADC code: 517
& 523) and PDC bits is 0.02 according to Bourgoyne and Young and the value of τH
depend on formation properties and it must be estimated using drill-of tests or previously drilled well data. he function g2 considers the efect of weight on bit on tooth
wear. his function is diferent for tungsten carbide insert bits (IADC code: 517 & 523)
and PDC’s. For tungsten carbide insert bits (IADC code: 517 & 523) it is deined by:
g2
WOB
db
WOB
db
2.9
max
max
WOB
db
(7.102a)
Basics of Drill String Design 407
Here
WOB
db
max
= bit weight per inch of bit diameter at which the bit teeth would fail
instantaneously, 1000 lbf/in
Estes (1971) has pointed out that the rate of bit wear will be excessive if a very high bit
weight is used. For PDC bits, the efect of weight on bit on tooth wear is deined by:
WOB
db
g2
WOB
db
cir
(7.102b)
mech
Note that the normalized bit weight (WOB/db )cir must be estimated by considering drill
string properties, bit type and ield data.
he function g3 describes the efect of pipe rotation on tooth wear and deined by:
N
Nc
g3
H1
(7.103)
he value of H1 for tungsten carbide insert bits (IADC code: 517 & 523) and PDC bits is
1.50 according to Bourgoyne & Young and the value of Nc depend on drill string properties and bit type.
he function g4 is used to emphasize the efect of tooth geometry on tooth wear.
For all types of bits, tooth wear is proportional to the inverse of the contact area (A) if
failing by fracturing of brittle tungsten carbide is ignored. Generally the shape of bits
should be classiied into three main shapes: cylindrical, triangular and spherical. For
cylindrical shape, since there is no change in contact area, the efect of tooth geometry
on tooth wear is given by:
1
g4
(7.104)
For triangular shape, the efect of tooth geometry on tooth wear is given by:
H2
2
1 H2 h
1
g4
(7.105a)
he value of H2 is 1.0 according to Bourgoyne & Young. Finally, for spherical shape, the
efect of tooth geometry on tooth wear is given by:
g4
1
dc h 2 h
(7.105b)
By substituting Eqs. (7.101 through 7.105) into Eq. (7.100) and integrating for h, the
value of frictional tooth dullness, h, can be calculated as:
408 Fundamentals of Sustainable Drilling Engineering
For tungsten carbide bit:
i) Tooth geometry on tooth wear for cylindrical shape:
WOB
db
H3
dh
dt
WOB
db
H
2.9
WOB
db
max
H1
N
Nc
max
(7.106a)
ii) Tooth geometry on tooth wear for triangular shape:
WOB
db
H3
dh
dt
WOB
db
H
2.9
N
Nc
max
WOB
db
max
H2
2
1 H2 h
1
H1
(7.106b)
iii) Tooth geometry on tooth wear for spherical shape:
dh
dt
WOB
db
H3
H
WOB
db
2.9
N
Nc
max
WOB
db
max
H1
1
dc h 2 h
(7.106c)
For PDC bit:
i) Tooth geometry on tooth wear for cylindrical shape:
dh
dt
WOB
db
H3
H
WOB
db
H1
N
Nc
cir
(7.107a)
mech
ii) Tooth geometry on tooth wear for triangular shape:
dh
dt
H3
H
WOB
db
WOB
db
cir
N
Nc
H1
H2
2
1 H2 h
1
(7.107b)
mech
iii) Tooth geometry on tooth wear for spherical shape:
dh
dt
H3
H
WOB
db
WOB
db
cir
mech
N
Nc
H1
1
dc h 2 h
(7.107c)
Basics of Drill String Design 409
3) Mechanical Speciic Energy:
he concept of mechanical speciic energy (MSE) has been used efectively in lab environments to evaluate the drilling eiciency of bits. MSE analysis has also been used in
a limited manner to investigate speciic ineiciencies in ields operations (Dupriest et.
al., 2005). he MSE surveillance process provides the ability to detect changes in the
eiciency of the drilling systems, more or less continuously. In early 2004, an operator
initiated a pilot to determine whether rig-site personnel might use the concept more
broadly as a real-time tool to maximize the rate of penetration (ROP). h e results have
exceeded expectations. he average ROP on the six rigs selected for the three-month
pilot was increased by 133% and new ield records were established on 10 of 11 wells.
Real time MSE surveillance is used to ind the lounder or founder point for the current
system and in some cases the cause of founder. MSE is a ratio and quantiies the relationship between input energy and ROP. his ratio should be constant for a given rock,
which is to say that a given volume of rock requires a given amount of energy to destroy.
he relationship between energy and ROP derived by Teale (1965) is presented here as
InputEnergy
OutputROP
MSE
MSE
Here
Tor
480Tor RPM
db2
ROP
4WOB
db2
(7.108)
(7.109)
= torque, lbf-t.
Figure 7.56 shows the relationship between ROP and WOB to relate the MSE and the
drill of curve. In region II, the linear slope means that the ratio of input energy WOB
to ROP is constant. Since MSE equals to this ratio, it must also be a constant value, but
only if the bit is operating within the linear portion of the curve. When the bit is in
region I or III, a disproportionate amount of energy is being used for the given ROP.
his provides a useful diagnostic. If MSE is constant the bit is eicient and operating in
region II. If MSE rises, the system is foundering. By plotting MSE continuously at the
rig site, the driller can see whether it moves in or out of founder as various parameters
are tested.
he energy required to destroy a given volume of rock is determined by its compressive strength. Teale (1965) derived the speciic energy equation by calculating the
Region lll: Founder
Bit Balling
Bottom Hole Balling
Vibrations
Potential Performance
Performance is
enhanced by
redesigning to extend
the founder point
ROP
Region ll: Eicient
Region l: Inadequate Depth of Cut (DOC)
WOB
Figure 7.56 Relationships between ROP and WOB (Dupriest et al., 2005).
410 Fundamentals of Sustainable Drilling Engineering
torsional and axial work performed by the bit and dividing this by the volume of rock
drilled. his concept is also reported by Dupriest (Dupriest, 2005). Although there is
a clear connection between rock strength and energy required for destroying it, Teale
was surprised when lab-drilling data showed the MSE value to be numerically equal to
rock compressive strength in psi. his is useful from an operations standpoint because
it provides a reference point for eiciency. If the observed MSE is closed to the known
conined rock strength, the bit is eicient. If not, energy is being lost. he value should
change as the lithology changes. However, ield experience shows the occurrence of
energy losses when the bit founder is very large. In such situations, they cannot be confused with the small changes that occur with rock compressive strength.
Drilling Speciic Energy: Armenta (Armenta, 2008) modiied the concept of MSE
and its original mathematical equation developed by Teale (Teale, 1965). In the modiication, he included a bit hydraulic-related term on the original MSE correlation and
presented the equation in the below form:
DSE
WOB 120 RPM Tor
AB
AB ROP
1,980,000
HPB
AB ROP
(7.110)
Here
DSE =drilling speciic energy, psi
AB = borehole area, in2
= bit hydraulic factor, dimensionless
HPB = bit hydraulic horse power, psi
he irst two terms on the right hand side of Eq. (7.110) are similar to those on Teale’s
original equation. However, the third term represents the bit hydraulic related term.
he number 1,898,000 is a unit conversion factor. he parameter Lambda (λ) is a
dimensionless bit hydraulic factor depending on the bit diameter (Figure 7.57). he
ratio of bit hydraulic power HPB and bit area (HPB/AB) is the bit hydraulic power per
square inch, HSI (hp/in2). he DSE concept was evaluated by applying Eq. (7.110) and
the relationship of DSE and ROP was investigated for diferent drilling parameters (i.e.
WOB, and HSI). DSE vs. ROP for diferent WOB values for all the experiments show
grouping of curves according to the WOB (Figure 7.58). Field data was used to calculate DSE using Eq. (7.110) to identify ineicient drilling condition. he ROP and DSE
both were plotted irst against depth to identify any particular pattern (Figure 7.55).
A good agreement between the experimental data and the DSE model was observed.
All the curves have similar pattern showing three main regions: i) High DSE and low
ROP indicating ineicient drilling; ii) low DSE and high ROP which indicate eicient
drilling; iii) A transition zone from region 1 to region 2 in between these two regions
(Armenta, 2008).
In order to show the efect of the hydraulic term (i.e. HSI) again DSE, Figure 7.59 was
plotted to show the efect of DSE on ROP where the data was grouped according to the
HSI. During the experimental work, WOB was kept constant and diferent WOB curves
are shown on the plot to make a connection between DSE and ROP as shown in Figure
7.59. It was shown in Figure 7.60 that all the data with HSI between 0.5 hp/in2 and 1.7 hp/
in2 are located on the ineicient drilling region (Region 1: high DSE and low ROP) for
Basics of Drill String Design 411
Hydraulic Factor (Lambda),
dimensionless
0.060
0.050
0.040
0.030
0.020
0.010
0.000
4
5 6
7 8
9 10 11 12 13 14 15 16 17 18 19 20
Bit dia-meter, in
Figure 7.57 Hydraulic Factor (λ) (Armenta, 2008).
ROP, ft/hr
2,000
0
50
DSE , psi
100
150 0
100,000 200,000 300,000
2,500
3,000
Depth, ft
3,500
4,000
4,500
5,000
5,500
6,000
Figure 7.58 ROP and DSE vs. depth for ield data (Armenta, 2008).
120,000
DSE, psi
100,000
80,000
60,000
WOB=50,000lb
40,000
WOB=40,000lb
20,000
0
0.0
WOB=30,000lb
WOB=20,000lb
5.0
10.0
15.0 20.0
ROP, ft/hr
25.0
30.0
Figure 7.59 DSE vs. ROP with experimental data grouped according to the WOB (Armenta, 2008).
412 Fundamentals of Sustainable Drilling Engineering
120,000
100,000
DSE, psi
80,000
0.5 hp/in2 < HIS < 1.7 hp/in2
60,000
1.8 hp/in2 < HIS
< 5.7 hp/in2
40,000
5.8 hp/in2 < HIS
< 7.9 hp/in2
20,000
0
0.0
5.0
10.0
15.0
ROP, ft/hr
20.0
25.0
30.0
Figure 7.60 DSE vs. ROP with experimental data grouped according to the HSI (Armenta, 2008).
their particular WOB. On the other hand all the data with HSI between 5.8 hp/in2 and 7.9
hp/in2 are on the eicient drilling region (Region 2: low DSE and high ROP). It is revealed
from Figure 7.60 that the bit hydraulic is the driver to move from ineicient drilling when
the WOB is constant. When increasing HSI not only is the cutting removed faster underneath the bit, the bit cutting structure is kept clean to break new rock more efectively.
Khamis (2013) modiied the DSE equation [Eq. (7.109)] by using the area of the
1.2651
Db 2 ) and modifying hydraulic factor
as:
drilling bit (AB
4
Db2
DSE
4 WOB
Db2
480 RPM Tor
2
Db ROP
3,189,335 HPB
Db 4 ROP
(7.111)
he input parameters of the DSE Eq. (7.110) can be used to estimate the DSE and therefore the drilling parameters can be optimized in order to maximize the ROP by minimizing the DSE.
7.10.2 Optimization of the Penetration Rate
he drilling rate of the penetration model should be deined in order to conduct the
real-time data analysis for ROP optimization. he model described below aims to optimize WOB and RPM where multiple linear regression technique is used as an optimization methodology. Multiple regressions are used to ind the parameters of an
equation, which make that equation to be best representation of the data. Codes are
designed to ind the coeicients of the model; mathematically correlating rate of penetration with the controllable and uncontrollable drilling parameters. he mission is to
obtain drilling data at a rig site network, pipe the collected data to the operation center,
and run the analysis and send feed back to the rig-site as shown in Figure 7.61. he
data process technique is performed to the drilling data set to achieve general equation to predict ROP as a function of input drilling parameters. he multiple regression
Basics of Drill String Design 413
Rig-n
Rig-n+1
Sensors
D/A
Converter
Rig Site Network
Sensors
D/A
Converter
Operation
Center Network
Rig Site Network
Optimization
Figure 7.61 Drilling optimization data transmission process (Eren and Ozbayoglu, 2010).
technique is based on regression model that contains more than one regressor variable
(Montgomery and Runger, 2003). Multivariable data analysis is characterization of an
observation unit by several variables (Davis, 2002). Multivariable analysis method gets
afected for the changes in magnitude if several properties simultaneously act on it.
Multiple regressions consider all possible interactions within combination of variable
as well as the variables themselves.
A standard plan for ROP is 700 – 1000 t./day. It is well known that too fast drilling
(i.e. ROP: +100 t./hr) can result in poor borehole cleaning, cuttings can fall in when
pumps are tuned of during connection and tripping operations which cause diferential
sticking. On the other hand, slow drilling (i.e. ROP: 10 t./ hr) can usually be improved
by adding more weight on a bit. Typically only 30–40% of the total drilling time is spent
rotating the bit on bottom of the hole. Recently, ROP is optimized using drilling speciic energy (DSE) based on real time and rig-site data. he work involves adequately
deining the problems to be solved, formulating the objectives of drilling optimization
tasks into mathematical equations and solving the formulated optimization problems.
Introducing bit hydraulics improves the ROP signiicantly. Drilling parameters need to
be considered during the development of a correlation between ROP and the related
factors such as Weight on Bit (WOB), Revolution per Minute (RPM), Torque (T), drilling luid circulation rate (Qm), and bit hydraulics (HPb).
414 Fundamentals of Sustainable Drilling Engineering
here are mainly two optimization methodologies; using analytical models such as
the method of Galle and Woods, drill-of tests, and the use of the numerical (statistical) models such as multiple regression analysis. he drilling optimization procedure
considered by Osgouei (2007) is based on two objective functions i) maximizing the
rate of penetration, and ii) minimizing cost per foot. In order to derive the optimum
drilling parameters analytically, two separate diferential equations are deined: i) rate
of penetration [Eq. (7.112)] and ii) teeth wear as a function of time [Eq. (7.113)]. In a
general form, they can be written as:
he general form of the optimized model for roller-cone bits is:
ROP
WOB
, N, h
db
f1
dh
dt
f2
(7.112)
WOB
, N, h
db
(7.113)
As seen in equations (7.112) & (7.113), only the operable parameters can be considered.
So, it can be concluded that drilling optimization can be conducted to select the proper
weight on bit and rotary speed. During analytical derivation of optimum value for weight
on bit and rotary speed, some constraints due to practical application are introduced.
WOBmin
WOB
N min
0
WOBmax
(7.114)
N N max
(7.115)
1.0
(7.116)
h
Where for totally worn out teeth, the value of h is zero and for new teeth, it equal to one.
In general, the optimized WOB and RPM should lie within the operation window
of their respective applicable range and mathematically, it can be represented by the
following equation:
dF
dt
Here
dF
dt
Wv
db
N
h
f
Wv
, N,h
db
(7.117)
= rate of penetration (ROP), t./hr
= vertical weight on bit component
= bit diameter
= rpm
= bit tooth dullness, fractional tooth height worn away
For roller cone and tungsten carbide insert bits:
WOB
db
a5 H1
opt
WOB
db
a5 H1 a6
max
(7.118a)
Basics of Drill String Design 415
For PDC bit:
WOB
db
H1 a5
WOB
db
WOB
db
c
cir
(7.118b)
H1 a6
opt
Ater determining the optimum weight on bit and bit life (tb), the corresponding rotary
speed can be calculated for roller cone bits and PDC bits, assuming complete tooth
wear, which is given as:
For tungsten carbide insert bits:
N opt 100
H
WOB
db
tb H 3
max
WOB
db
WOB
db
1
H1
opt
(7.119a)
2.9
max
For PDC bits:
100
N opt
tb H 3
H
(7.119b)
1
H1
WOB
db
cir
WOB
db
opt
Ater the necessary calculus the optimized equation for the vertical weight component
for each diameter of bit size, the optimum bit weight can be expressed as (Bourgoyne
et al. 1986):
Wv
db
Here
Wv
db
a5
a6
H1
a5 H1
opt
w
db
a6
max
W
db
t
a5 H1 a6
(7.120)
= optimum weight on bit and drill bit diameter
opt
= bit weight exponent
= rotary speed exponent
= tooth geometry constant used to predict bit tooth wear
In a parallel routine the optimum bit speed (N Opt ) can be expressed as (Bourgoyne et
al. 1986):
416 Fundamentals of Sustainable Drilling Engineering
N Opt
60
H
W
db
tb
Wv
db
max
W
db
Opt
(7.121)
4
max
Here
N Opt = optimum rotary speed
= formation abrasiveness constant
H
tb
= bit drilling time
W = weight on bit
In ROP optimization, drilling cost per foot can be deined to account for daily rig rate,
bit cost, and timings required in the course of bit runs, which is discussed in Chapter 11.
7.11 Current Development on Drill String and Bottomhole
Assembly Design
New developments involve using the drill string as a vehicle for sending downhole
information to the top of the hole. High-speed-telemetry drill pipe can provide highquality downhole dynamic data along with logging information (gamma scans, density images, etc) that can be efectively used for real-time drilling optimization. Many
researchers have been performed for drilling real-time data. Most of these researches
focused on the application of real-time data in the optimization of the drilling parameters. A large amount of sotware was built in order to be able to handle the tremendous
amount of data that can be easily visualized and analyzed.
Onoe et al. (1991) described the concept, design and capabilities of an advanced
real-time information system for drilling. he objectives of this system are to provide
signiicant increases in drilling eiciency and engineering accuracy while at the same
time to enhance operational safety and optimize the data management associated with
drilling operations. hree important attributes distinguish this system from other “realtime” systems either existing or under development. First, the system provides “realtime” engineering models for decision support augmented by a “real time” expert
system. Second, the system can be interfaced with any data acquisition hardware. hird,
it addresses a wider range of data analysis and engineering functionality. Additionally,
scenarios for its utilization in the ield to optimize drilling operations are provided. It
was also recognized that this system would need to grow and adapt to accommodate
new technology and changing requirements during the 1990’s and beyond. honhauser
(2004) investigated the use of process related data measured in real time for performance
analysis while and ater drilling. his process showed that it is possible to automatically
derive activities and events from real-time data, just as it is possible to accomplish an
understanding of various events, which results in non-optimal performance or trouble
time through visual inspection of data plots. Quality problems with existing real-time
data, revealed during post analysis were discussed as well as their origin in the historically developed pattern of geology-driven, depth-based view of all the drilling process.
Basics of Drill String Design 417
High-resolution operation analysis can be performed with existing data, which showed
a very high potential for automated process optimization and early problem recognition.
Mathis and honhauser (2007) addressed the problem related to the real-time data and
developed essential steps criteria to measure and evaluate data quality. Quality control
and improvement, data quality benchmarking, and accessibility of controlled data are
management strategy proposed in their paper and therefore signiicant time saving was
achieved compared to a manual quality control. A visual concept has been introduced,
which allows the suring of time and depth based data with unique navigation concept.
Vogel and Asker (2010) presented certain scenarios to inform operators and other
drilling organizations about the cost-efectiveness and importance of real time data
management techniques and information transfer for complimenting technology in
drilling operation. his technique can save the oil and gas industry operator money
in the current drilling operations and even in future operations. It also ills some of
the knowledge gap in the industry and saves money for the environmental and safety
sector of this industry, which can be very expensive when incidents occur. Following
the real time data management and information transfer technique will allow for safe
and eicient drilling with maximum ROI and reduced risks. Staveley and how (2010)
illustrated techniques for improving collaboration and analysis of real-time and historical drilling data, increasing the cost of efectiveness of drilling eforts. hey presented a
case study highlighting the achievable beneits. A drilling knowledge base makes it possible to unlock the value of all the drilling data a company has paid to collect but rarely
uses due to its disparate nature. Earth model sotware makes it possible to perform
multi-well analysis and implement the collaborative worklows to facilitate the type of
drilling analysis and planning that the industry has known for years can reduce NPT,
increase drilling eiciency, and ultimately reduce costs. hese worklows can be used
for completely green exploration wells, where you have no data and can create a drilling
knowledge base during drilling; for ields where some ofset data is available; and for
established ields where many wells have already been drilled. Each well added to the
knowledge base efectively decreases drilling uncertainty. Eren and Ozbayoglu (2010)
developed a model to optimize drilling parameters during drilling operations such as
weight on the bit, bit rotation speed in order to obtain maximum drilling rate and hence
minimize the cost per foot and the overall drilling cost. he model that was developed
used actual ield data collected through modern well monitoring and data recording
systems, which will be used in predicting the rate of drilling penetration as a function of
available parameters. he study demonstrated that drilling rate of penetration could be
predicted at relatively accurate levels, based on past drilling trend. he optimum weight
on bit and bit rotation speed could be determined in order to achieve minimum cost
drilling. It is believed that by means of efective communication infrastructures and
thorough team eforts having eicient real-time drilling optimizations based on statistical syntheses are not too distant. Sharma et al. (2010) included six case histories where
the use of downhole drilling data increases drilling eiciency. hese cases described
four diferent applications where a downhole optimization sub’s (DHOS) real-time data
was used to improve drilling operations. he case studies are proof that having optimization sensors that provide information like bending moments, DWOB, etc. are essential to answer such questions and are key tools in the benchmarking process. Armed
with these tools, even the most diicult of wells will have an engineered solution.
418 Fundamentals of Sustainable Drilling Engineering
Maidla and William (2005) showed how MSE was implemented in a drilling information system in real time on the rig and at remote monitoring locations. he study
showed that the use of MSE in real time is a useful tool for both drillers and drilling
engineers. Conducting MSE tests in real time is an efective way to develop an understanding of MSE behaviour and contributes to acceptance by rig personnel. he general
practice of adjusting drilling parameters to minimize the value of MSE is a good rule of
thumb. Rashidi et al. (2008) presented a new method to combine Mechanical Speciic
Energy (MSE) and Rate of penetration (ROP) models to calculate real time bit wear
which takes into consideration the fundamental diferences between MSE and ROP
models and that the latter only takes into account the efect of bit wear. Encouraging
results have been obtained which shows a linear relationship between MSE (Rock
Energy) and rock drillability (Drilling Strength) equations with the use of K1 as a constant of proportionality. Change in mud weight and bit wear are the two most dominant
factors, which cause an irregularity in normal decreasing trend of the inverse of coeicient K1 versus depth. he developed model is correlative using diferent sliding coeicient of friction to account for variations in bit parameters like bit diameter, number of
cutters, cutter diameter, back rake and side rake, etc. which are not accounted for in the
ROP equation presented and the MSE calculation. his approach has been veriied with
a small dataset, and by analyzing more bit runs the authors believe this can become a
valuable tool in real time analysis of bit wear.
Rashidi et al. (2010a) described the real-time application of a developed model
for bit wear analysis. he model was developed based on the diference between rock
energy model, MSE, and rock drillability from rate of penetration model. It has been
modiied and implemented as an engineering module in the newly developed sotware,
Intelligent Drilling Advisory system (IDA’s), and used to estimate real-time bit wear for
both roller cone and PDC bits. Sotware from a remote server for the analysis retrieves
the drilling data. he data is subsequently quality controlled before calculating instantaneous bit wear while the bit is in the hole. In this research, bit runs for two ofset wells
in Alberta, Canada, will be analyzed in detail using the sotware module. Similarities
between the recorded bit wear outs reported in the ield and the simulation results indicate that the procedure can be used for bit wear estimation with good accuracy. Depth
for normalization of constant K1 and multiplication factor are set manually for each bit
run section to get a smother bit wear trend. he automatic calibration and setting of
these factors will be integrated into the future development of the sotware. Calculated
inal bit wear out values show good matches compared to the ield data. his engineering sotware module could be used to identify unnecessary tripping which will result
in time and cost reduction as well as an additional tool to aid in the estimation of bit
wear status while drilling. Mohan et al. (2009) presented a new correlation to identify
ineicient drilling conditions using MSE. Hydro Mechanical Speciic Energy (HMSE)
was introduced encompasses hydraulic as well as mechanical energy. he HMSE equation will be of value during both planning and operational phases of selecting drilling
parameters and also optimize them. However, Armenta (2008) presented a novel correlation to identify ineicient drilling conditions using experimental and ield data.
Results showed that drilling speciic energy (DSE) can be used to identify ineicient
drilling conditions. Experimental results illuminated the importance of including bit
hydraulics into Speciic Energy analysis for drilling optimization. he new hydraulic
Basics of Drill String Design 419
term included on the speciic energy correlation is the key to correctly matching the
amount of energy used to drill and the rock compressive strength. Also, this term illuminates how much hydraulic energy is needed to drill faster and eiciently when the
mechanical energy (axial and torsional) is increased.
Rashidi et al. (2010b) conducted a study to demonstrate the efects of changing the
drilling parameters bit wear and bit designs on ROP for both approaches. Optimum
bit types and designs with corresponding drilling parameters can be globally recommended for entire bit runs using ROP model. he MSE model can be used to adjust
the operating parameters to reach a maximum ROP value “locally”, or in real-time
with no efect of bit design or bit wear integrated. he lexibility of using an ROP
model as opposed to the MSE equation transformed into an ROP equation is also
investigated. he MSE model is easier to use in terms of inding the ineiciencies and
reaching the instantaneous optimization level. he MSE model has its limitation in
planning and post analysis of the drilling phases. MSE is useful as a tool to detect possible drilling problems while drilling without addressing the exact causes. he ROP
model is more comprehensive compared to the MSE model. It includes bit wear, bit
hydraulics and bit design, which gives the user the capability to optimize bit runs and
hole sections for lowest $/t. he ROP models can be used in all phases of the drilling
cycle including pre-planning, real-time drilling and post analysis. he big advantage
of ROP models over the MSE model is that it can recommend drilling parameters
that maximize the ROP over the entire bit run and not just instantaneously, meaning
that ROP models can be used as a global optimization tool while MSE models are
only local.
Voss et al. (2010) described the drilling of a sidetrack from a well that was originally
drilled in 2005 and makes comparisons between two projects proposed with respect to
equipment used and planning techniques implemented. he original 2005 wellbore was
drilled directionally through approximately 5000 t. of salt. his caused several drilling
related issues, including severe vibration and downhole tool failures. With the objective of improving drilling performance on the sidetrack well while avoiding disastrous
failure, the operator and Service Company jointly used a structure engineering optimization process. As a result of the total system optimization program, ROP was doubled
from 15.5 to 30.6 t./hr while comparing the target well with the ofset well. his action
saved the operators cost $2.1 million in this hole section which resulted in 76% reduction in drilling removable time (DRT). In addition, it exhibited minimum vibration
throughout the entire run. A total systems approach and proper pre-well planning were
shown to be the key to success including: service company’s teams and conditions, risks
and contingencies taken by operator, eicient planning and ield execution, improved
bit selection proper bit and reamer synchronization, well-trained service company rig
and oice engineering services. Zoellner et al. (2011) studied several cases to monitor drilling hydraulics by analyzing luid low in relation to pump pressure and other
relevant sensor channels. He tried to recognize early the onset of hydraulics related
problems in order to take preventive action. he concept is based on recognition variations in expected behaviour of rig sensor responses using hybrid algorithms, which
link analytic, static and knowledge bases concepts. he outlined concept to display
previous start-up sequences and corresponding parameters to provide a reference for
the driller should result in a minimization of start-up time and pressure surge of the
420 Fundamentals of Sustainable Drilling Engineering
current sequence in the sense of an on-going optimization process within one BHA run
and therefore lost and hidden lost time can be avoided.
Tagir et al. (2010) proposed an expert system which ofers an eicient way of combining some basic measurements provided by the surface sensors for early diagnosis
and prevention of possible damage of downhole drilling equipment, primarily the drill
bit itself. he fundamental theory behind the proposed approach is based on certain
elements of fractal analysis as well as artiicial neural networks. Some real iled data
examples are used for training the model and assessing the current drill bit conditions by using the proposed methodology. For extending this experience to a real ield
application, one should apply the results of the studies obtained in the experimental
borehole (i.e. a determined optimal combination of the diagnostic criteria and the sampling frequency) to subsequent boreholes drilled in the same general area, so that the
input-output data will be somewhat clustered to reduce uncertainties in problematic
scenarios. Authors believe that this methodology opens new opportunities for realtime drilling optimization that can be eiciently implemented within the scope of the
existing drilling practice. It should be noted that neural networks-based expert systems
usually perform satisfactory interpolation, while it may generate erroneous results in
case of extrapolation. Because of this, the more representative and diverse database
from the previous experience that is available, the higher the probability of accurate
diagnosis that can be potentially achieved.
Sawaryn et al. (2010) discussed how data quality inluences worklows and decisionmaking in drilling and completions and examines the use of semi-automated processes
for quality assurance. With poor data, additional steps are required and worklows
must be repeated. In even relatively simple situations, controlled tests suggest that small
changes or omissions may have a signiicant inluence on the work eiciency or outcome. In earlier work, the quality of any data stream has been described in terms of
identity, presence, measurement frequency, accuracy, continuity, units and associated
metadata. For some of these, a degree of self-checking is possible, applying simple algorithms to the data stream to detect presence and bounds, with alarms to alert the operator if these are transgressed. In other cases, such as the change in drag and torque with
depth, the stream must be checked against a trend, called a pseudo-log determined
from the physics. hese calculations are performed by “smart agents” directly in real
time on the WITSML data feed from the rig. he paper describes the early work developing smart agents to address data quality and structure of the associated toolkit that
can be used to construct more complex agents from a wider selection of data sources,
including system generated ones. he computational resources required are also discussed. he increase in digital data and the skills shortage makes the manual assurance
of all the data streams neither practical nor cost efective. Since current applications are
not tolerant of errors and omissions, a step change in data quality will be needed if more
automated worklows are to be achieved. Greater assurance of the data at source and
an improved understanding of the worklows will help. Mostoi et al. (2010) developed
rock strength log of Asmary formation from backward simulation of drilling operation.
his log is critical for analysis such as drilling optimization, sand production evaluation and wellbore stability. According to the bit constants estimated from the ield and
other bit constants that have been previously calculated from laboratory tests, the drilling operation is simulated and the drilling optimization to minimize the cost per foot
Basics of Drill String Design 421
value is carried out. Based on cost equation, the best bit runs are introduced which can
reduce the drilling operation up to 38%. Drilling simulation can improve the drilling
schedule estimation. On the other hand, drilling project can be analyzed more accurately from economical view before drilling operation starts.
Maidla and William (2010) addressed the measuring techniques that involved data
quality control (QC) and automatic drilling operations detections of routine drilling
operations. hese are available today in modern drilling programs, and goes through
examples of how implementation was carried out in the onshore area in drilling a series
of similar wells. Measurement accuracy, training, and the development of new work
processes were successfully implemented, which led to key performance indicator
(KPI) time savings between 31% and 43%. You cannot improve what you don’t measure. And in this case you cannot measure without a proper data quality control procedure in place. he automatic operations detection technology, preceded by a rigorous
data QC process was a means to help prepare meaningful reports to lag opportunities to improve safety and performance. Spoerker et al. (2011) presented a technology, which explains how automatic operations detection was carried out to address
the proposed challenges, and the necessary reporting and user interaction needed. he
theory and one case history on this was presented and covered the start-up phase of
such initiative, and all of its push backs, and lead the readers through the implementation and inal results that were successfully archived. Performance target selection
should aim at consistent operation around a best practice rather than operational time
only. Based on the deinition of a target value it is possible to calculate the diference in
performance for crews, rigs, or complete rig leets as a savings potential. his process
can be highly automated and translated to instant performance reports e.g. to be used
on the rig as well as trend monitoring on a management level, for example by means
of a management score board. Continues monitoring of performance trends will lead
to continuous improvement with higher operational consistency and safety. Barbato
and Cenberlitas (2011) presented a description and features of the Micro-Flux Control
(MFC) system, beneits of standard application, and case studies with real ield data.
MFC technology is virtually applicable to any conventional well without compromising existing rig components in order to authorize and optimize data analysis during
drilling operations. he overview of the diferent regions has shown that appropriate
real time micro-lux analysis of naturally occurring or intentionally induced events
combined with Dynamic Mud Weight Management (DMWM) has provided a signiicant advantage in Non-Productive Time (NPT) reduction and an obvious advantage
in overall safety. Alum and Egbon (2011) developed a semi-analytical model for ROP
based on the original Bourgoyne and Young Model using real time bit records obtained
from wells drilled in the Niger Delta reservoirs. Simple regression analysis was applied
on the equation on the parameter that contains diferential pressure to obtain regression constants, which were then used to generate mathematical relationship between
ROP and drilling luid properties.
Gidh et al. (2011) developed an Artiicial Neural Network (ANN) based sotware
system to replace the human factor of applying operating parameters such as WOB and
RPM. By following the real-time ANN recommendations, changes can be implemented
to increase overall ROP while maximizing bit life by managing the dull condition. As
a result of applying the model developed here the operator completed the 8–1/2 hole
422 Fundamentals of Sustainable Drilling Engineering
section almost three days ahead of plan even with the unplanned trip to retrieve the
lost cone. he reduction in drilling days saved the operator approximately $150,000.
Van Oort et al. (2011) discussed the job of the optimization center at Shell Upstream
Americas. he team of that center is highly efective improvement team capable to help
drive performance optimization and the delivery of top quartile performance on its
wells in North America and beyond. Using the optimization approaches, it has been
possible to help accelerate well delivery times and associated learning curves by as much
as factor of three, oten in a minimum amount of time. his approach is a highly efective way to bring performance optimization focus to ield operations. he worklow and
organizational structure was applied to well delivery optimization with projects ranging from shale gas drilling in the Continental US and Canada as well as hard rock drilling in the Middle East. Koederitz and Johnson (2011) described the development and
ield-testing of an autonomous drilling system. his system sotware uses a test process
to evaluate and quantify the drilling performance for a given set of target set points. he
research method is used to identify these set points. Its development was based on early
work in the application of real-time MSE display. Overall, the ield testing results were
favorable, displaying that the potential for autonomous drilling optimization without
drilling knowledge is practical, lexible, and economical, exhibiting promise in a range
of cost-efective applications. Bataee and Mohseni (2011) predicted the proper penetration rate, optimizing the drilling parameters, estimating the drilling time of a well and
therefore reducing the drilling cost for future wells using ANNs. hey got some valuable observations, which were based on their model. Increasing WOB or rotary speed
does not always increases ROP. his study shows in some parts which the driller exerts
high WOB and rotary speed (N), the ROP value decreases due to cleaning problem and
bit loundering. his is the ability of ANN analysis whether no equation can ind the
actual amounts of parameters that maximize penetration rate. As results show always
less mud weight used leads in higher ROP value, which is a correct concept. Greater
range for N and WOB is used and observed that best one was neither the maximum
nor the minimum value. An appropriate ROP was selected based on the previous ROP
to be achieved by using the modeled function and applying the corresponding drilling
bit parameters.
Dykstra et al. (2011) focused on the technical challenges faced when drilling the
Haynesville shale play in North Louisiana. One of the most daunting is penetrating
the hard, abrasive Hosst on sandstone-shale sequence and hard Knowles limestone in
the intermediate section of the overburden. he operator applied a systematic drilling
eiciency optimization (DEO) approach encompassing well planning, well execution
and post-well analysis to drive performance improvement through these formations.
Optimization eforts focused on polycrystalline diamond compact (PDC) bit design,
bit hydraulic, positive displacement motor (ODM) selection, sot torque rotary system (STRS) utilization, bottomhole assembly (BHA) design and active management of
drilling parameters. Combined, these eforts reduced cost per foot and days per thousand feet by over 50% while drilling approximately 70 well over a two-year period.
Signiicant technical lessons were as follows: i) PDC cutter selection, cutter placement,
blade layout and nozzle placement and orientation can be reined to yield longer, faster
bit runs in the Hosst on and Knowles formations, ii) higher hydraulic horsepower contributed to improved bit performance in both hard and sot formations, iii) low speed,
Basics of Drill String Design 423
high torque downhole motors helped protect PDC bits from damage caused by torsional stick-slip, iv) STRS allowed wider ranges of WOB and RPM to be used without
stick-slip and improved bit performance on both rotary and motor assemblies, v) he
number and placement of stabilizers in BHAs could be adjusted to make them less
prone to buckling and lateral vibration over desired range of WOB and RPM and vi)
Active monitoring of drilling parameters, Stick-Slip Alarm (SSA) and MSE by rig site
and remote personnel improved recognition and mitigation of drilling dysfunctions
and improved average ROP and run length.
7.12 Future Trend on Drill String and Bottomhole Assembly
Design
here are still challenges related to drill string and bottomhole assembly design. he
following are some of them.
Hole Deviation: In the process of drilling a borehole, geosteering is the process of
directing the borehole position (inclination and azimuth angles) on the run to achieve
the optimum well placement. hese changes are based on geological information gathered while drilling. here are many companies provide real time geosteering services.
However, there are still challenges that need to be addressed.
Corrosive Environments: As a result of failure in drill pipe due to corrosion, more
focus is being paid to geochemistry. he understanding of geochemistry of the drilling
luids and the formation luids is vital in minimizing the failure due to corrosion. It can
be mitigated by corrosive scavengers and by controlling the mud pH in the presence of
H2S. he corrosion of tubulars may occur because of oxygen, acid gases (CO2 or H2S)
that may also be toxic, and/or other chemicals that create a spontaneous electromotive potential. Oxygen is always present in drilling luids. It enters the system during
mixing and routine maintenance operations. A few parts per million is suicient to
cause signiicant corrosion. Pitting, caused by the formation of oxygen-corrosion cells
under patches of rust or scale or at holidays in inhibitor ilms on treated surfaces, is
characteristic of oxygen corrosion. he best method for preventing oxygen corrosion is
to minimize the entrainment of air at the surface by using only submerged guns in the
pits and arranging for returns from desanders, desilters, etc. to be discharged below the
pit luid level. he mixing hopper is a prime source of air entrainment, and it should be
open only when mud-conditioning materials are being added.
When oxygen must be scavenged because of unacceptable corrosion rates, the
usual method is to use easily oxidized materials that have minimal efect on drilling
luid properties. he most common oxygen scavengers are the soluble sulphite salts.
Chromate salts and a few organic materials are used occasionally. When it is not practical to remove oxygen, chemicals may be added that coat or passivate the steel tubulars
to minimize the attack by oxygen. he coating materials frequently are oily organic surfactants. Passive elements include certain inorganic and metal organic salts. Removal of
H2S is accomplished with iron or zinc materials. hese combine with H2S to form insoluble sulides, which are not easily decomposed to reform into toxic H2S. As a result,
removal of H2S is still a challenge.
424 Fundamentals of Sustainable Drilling Engineering
Gas Hydrate Inhibitors: Gas hydration inhibitors utilize low molecular weight
organic compounds for gas hydrate inhibition. hey have important applications in
deepwater drilling. Gas hydrates are clathrates that are formed under the appropriate
conditions of temperature and pressure. Clathrates are complexes formed between two
chemicals in which one type of molecule completely encloses the other molecule in a
crystal lattice. In the case of gas hydrates, hydrogen-bonded water molecules form a
cage-like structure that surrounds gas molecules forming a solid substance with a high
gas density. An agglomeration of these cage structures can result in blockage of lines
and valves in drilling equipment. he hydrates of interest to the petroleum industry are
formed with natural gas components, the major component of which is methane, but
other components (ethane, propane, isobutane, carbon dioxide, nitrogen, and hydrogen sulide) also form water clathrates and create a real challenge for drill string and
BHA design.
Shale Inhibitors: Reactive shale tends to adsorb water, which can result in the
swelling or disintegration of the shale and lead to problems such as bit balling, high
torque and drag, and stuck pipe. Using oil-base mud may solve this problem. If using
oil-base mud is not possible due to environmental issues or government regulations,
water-based mud should be used with various chemical inhibitors such as organic cationic materials (OCMS), KCl and glycol to control reactive shale. KCl additives work
by changing places with sodium atoms in the clay structure since potassium ions are
smaller than sodium ions. his causes the clay structure to shrink rather than expand.
Soluble silicates have also been used as shale inhibitors. hese materials are soluble at
high pH, but precipitate out of solution if the pH drops. Tiny amounts of these silicates
enter the pore space between shale structures, and form a barrier to prevent further
water penetration and creates problem for BHA. Researchers need to address these
issues while designing the drill string and BHA. Some oil companies such as Saudi
Aramco have its own laboratories to run studies on how to prevent failures of drill
string. With high-tech labs, they were able to develop geochemical studies on all different luids to be encountered during drilling operations. his helps to minimize drill
string failures, which results in saving costs.
7.13 Summary
he chapter discusses almost all aspects of basic drill string and BHA design including
drill bit. he diferent types of drill bit and their applications are outlined in detail. h e
ROP optimization and the factors that inluence the ROP are also discussed. he existing ROP models are explained here. he current development in the area and the future
trend of drill string and BHA are also presented in the chapter.
7.14 Nomenclature
A
AB
a4
= cross-sectional area, in2
= borehole area, in2
= overbalance exponent
Basics of Drill String Design 425
E
h
HPB
HPds
HPp
H1
= bit weight exponent
= rotary speed exponent
= tooth wear exponent
= buoyancy factor, fraction = 1 m / s
= an empirical factor that depends on hole inclination angle (0.000048 –
0.00000665 for hole angles ranging from 3 to 50)
= total depth of luid column or drill pipe, t.
= bit diameter
= inside diameter of drill pipe, in
= outside diameter of drill pipe, in
= nozzle diameter
= diameter of box at elevator upset, in
= drilling speciic energy, psi
E
= shear modulus of elasticity =
21
= Young’s modulus of elasticity, psi
= the fractional tooth height that has been worn away, in
= bit hydraulic horse power, psi
= horsepower required to turn the rock bit and drill string, hp
= horsepower required to rotate the drill pipe, hp
= tooth geometry constant used to predict bit tooth wear
Ip
= polar moment of inertia =
a5
a6
a7
Bf
Cd
D
db
di
do
dnz
dTE
DSE
Es
K
Ks
L
Ldc
Ldp
Ldp1
Ldp2
LHdp
Ltdp
Ltool joint
m
N
N Opt
P
Pbh
Pd
Pf
Pt
Qbn
Qmin
Qmin _t
R
do4 di4 , in4
32
= constant of proportionality that includes the efect of rock strength
= a scaling constant
= combined length of pin and box, in
= total length of drill collar, t., m
= total length of drill pipe, t., m
= length of drill pipe grade 1, t.
= length of drill pipe grade 2, t.
= length of heavy weight drill pipe, t.
= total length of drill pipe, t.
L 2.253 do dTE
= tool joint adjusted length =
, t.
12
= slope of the straight line in the plot, psi-1
= drill string rotary speed, rev/min
= optimum rotary speed
= actual weight or total weight carried by the top joint, lbf
= circulating bottomhole pressure, psi
= drill pipe yield strength or design weight, lbf
= formation luid pressure, psi
= theoretical yield strength, psi
= low rate through the bit, gpm
= minimum torsional yield strength, t.-lbf
= minimum torsional yield strength under tension, lbf-t
= rate of penetration (ROP), t./hr, t./min
426 Fundamentals of Sustainable Drilling Engineering
= distance from the center of the drill pipe to a point under consideration
di 2r do , in
= ROP at zero overbalance, Pbh Pf
0, t./hr
= rate of penetration (ROP) corresponding to 1, t./hr
= rate of penetration (ROP) corresponding to 2, t./hr
= critical rpm, rev/min
= compressive strength of the rock
= torque, in-lbf
= bit drilling time
= torque, lbf-t.
= total vertical depth of well, t.
= low rate
= weight on bit or bit weight, lbf
= weight of the drill collar, lbf/t., kg/m
= nominal weight of the drill pipe, lbf/t., kg/m
= approx. adjusted weight of drill pipe, lbf/t.
= plain end weight, lbf/t.
= upset weight, lbf/t.
= nominal weight of the heavy weight drill pipe, lbf/t.
= threshold bit weight
= approximate adjusted weight of the tool joint, lbf/t.
= vertical weight on bit component
= nominal weight of the drill pipe grade 1, lbf/t.
= nominal weight of the drill pipe grade 2, lbf/t.
= depth of the empty drill pipe, t.
= minimum unit yield strength, psi
= polar sectional modulus, psi
r
Ro
R1
R2
rpmc
S
T
tb
Tor
TVD
v
W
Wdc
Wdp
Wdp adj
Wdp plain
Wdp upset
WHdp
Wo
Wtool joint
Wv
Wdp1
Wdp2
X
Ymin
Zp
dF
= rate of penetration (ROP), t./hr
dt
Wv
= optimum weight on bit and drill bit diameter
db opt
Wo
db
f
inside
m
outside
s
1
2
= threshold bit weight per inch of bit diameter
t
= density of luid outside the drill pipe, ppg
= density of luid inside the drill pipe, ppg
= mud density, lbm/gal, kg/lt
= density of luid outside the drill pipe, ppg
= density of steel, lbm/ t.3
= old mud weight, lbf/gal
= new mud weight, lbf/gal
= shear or torsional stress, psi
= Poisson’s ratio, (the ratio of transverse contraction strain to longitudinal
extension strain in the direction of stretching force.
o
= stretch due to own weight, in, m
trans
longitudinal
)
Basics of Drill String Design 427
dc
t
0
1
t
a
H
m
pb
Pbn
d t
dz
= stretch due to drill collar, in, m
= stretch due to tension, t.
= shear stress at failure, psi
= compressive stress, psi
= angle of internal friction
= angle of twist, radian
= apparent viscosity of drilling luid at 10,000 s–1
= formation abrasiveness constant
= bit hydraulic factor, dimensionless
= speciic gravity of mud
= burst load or pressure, psi
= pressure drop across the nozzles of the bit, psi
= diferential angle of twist, in–1
7.15 Exercise
E7.1: A drill string needs to be design based on the information given here. It is noted
that the outer diameter of the drill pipe is 5.5 , total vertical depth is 10,000’, mud weight
is 12 ppg. Total MOP is 150,000 lbs and the design factor, SF = 1.2 (tension); SF = 1.1
(collapse). he bottomhole assembly consists of 30 drill collars with an outer diameter
of 6.625” where the weight of drill collar is 93 lbf/t. and each collar is 30 t. long. In
addition, you need to consider the length of slips is 10 .
E7.2: Design a 5.5 and 24.7 lbf/t. drill string using a new pipe to reach a TVD of
12,500 t. in a vertical hole. he bottomhole assembly consists of 25 drill collars with
an outer diameter of 6.625 and inner diameter of 2.929 . he weight of drill collar is
93 lbf/t. and each collar is 22 t. long. For design purpose, the additional information
are: MW is 10.5 ppg, MOP is 140,000 lbs and the design factors are 80% for tension and
1.125 for collapse. You need to consider the length of slips is 12 .
E7.3: A drill string has 5000 t. long, and 5.0 in outer diameter drill pipe. While the
pipe was moving, it was suddenly stopped. A torque of 270 lbf-in is applied which develops torsional stress and angle at a distance of 4.15 from the center of the pipe. Assume
that the Young’s modulus of elasticity for steel is 29 106 psi and Poisson’s ratio is 0.64.
Find out the shock load, torsional stress, maximum shear stress and diferential angle
of twist.
E7.4: During the drilling operation, 150 hp was applied to rotate the drill string and
bit where 800 rpm was recorded from the rotary speed machine. In addition, 105 hp
was applied to rotate 2,900 t. of drill pipe, 5.5 in OD with the same speed as drill string.
Assume that Cd = 0.0000043. Calculate the required torque for drilling string and the
speciic gravity of mud.
E7.5: Find out the minimum torsional yield strength and torsional yield strength
under tension for the following data: OD = 5.5 in, top joint load is 500,000 lbf. Assume
that the ID of the pipe is 4.67 in.
E7.6: A 12 ppg mud is circulated through a 5.5 in drill pipe assembly of 4,000 t.
If 30 drill collars of 32 t. long each are also used, calculate stretch for drill pipe and
428 Fundamentals of Sustainable Drilling Engineering
collar due to their own weight. Assume the OD and ID of drill collar as 6.25 in and
2.8125 in respectively and weight of drill collar is 93 lbf/t. In addition assume that a
diferential pull of 800 lbf is applied on the drill pipe. Also ind out the stretch due to
tension .
E7.7: Estimate the change in penetration rate ater the mud-weight is increased
from 20 t./hr to a certain rate using the following data: a4 = 3.46 x10–05, D = 13,500 t.,
10.5 lb f / gal, 2 11.0 lb f / gal.
1
E7.8: An initial penetration rate of 20 t./hr is observed in shale at the beginning
of a bit run. he previous bit was identical to the current bit and was operated under
the same conditions of the bit weight, rotary speed, mud density, and other factors.
However, a drilling rate of 12 t./hr was observed in the same shale formation just before
pulling the bit. If the previous bit was graded T-6, compute the approximate value of a7.
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8
Casing Design
8.1 Introduction
Drilling a hole for extracting hydrocarbon is not an easy job. It is always a challenge
due to the highly diversiied geological structure and petro physical properties of earth
deposition and age. In addition while drilling, the well is drilled in sections from surface (for onshore) or the seabed (for ofshore) through all of the formations to the target depth because of the technological limitations. During drilling operations, the well
encounters diferent formation zones with enormous challenges such as faults, highpressure formations, toxic materials, and thief zones etc. Lining the inside of the borehole with steel pipe to ensure a hydraulic and mechanical seal seals of the well. Once a
certain length of hole is drilled it has to be cased with steel pipe, which is called casing
and is joined together by threaded sleeves. herefore, casing is deined as a heavy large
diameter steel pipe, which can be lowered into the well for some speciic functions.
Casing is using a strong steel pipe used in an oil or gas well to ensure a pressure-tight
connection from the surface to the oil or gas reservoir. It is a steel pipe of approximately
40 t. in length that starts from the surface and goes down to the bottom of the borehole.
It is rigidly connected to the rocky formation using cement slurry, which also guarantees hydraulic insulation. he space between the casing string and the borehole is then
illed with cement slurry before drilling the subsequent hole section. he inal depth
of the well is completed by drilling holes of decreasing diameter and uses the same
diameter protective casings in order to guarantee the borehole stability. According to
API standards, the dimensions of the tubes, types of thread and joints are standardized.
433
434 Fundamentals of Sustainable Drilling Engineering
However, special direct-coupling casings without a sleeve joint also exist. he selection
of casing sizes, weights, grades, and types of threaded connections for a given situation
presents engineering and economic challenge of considerable importance. he costs of
the casing can constitute 20–30% of the total cost of the well. Sometimes, it is the greatest single item of expense for the well. Since the cost of the casing can represent up to
30% of the total cost of the well, the number of casing strings run into the well should
be minimized.
his chapter discusses the types of casings, diferent components of casing and landing procedures. It also discusses the manufacturing of casings, rig side operations, handling procedures, casing design, and selection criteria. Finally, the current practice and
future trends in casing for the oil industry are discussed.
8.2 Importance of Casing String
Casing the borehole is one of the most important parts of drilling operations. However,
casing is normally set to serve a speciic purpose and is neither arbitrary nor compulsory for any hole condition. he casing transforms the well into a stable, permanent
structure able to contain the tools for producing luids from underground reservoirs.
It supports the walls of the borehole and prevents the migration of luids from layers at
high pressure to ones at low pressure. Moreover, the casing enables circulation losses to
be eliminated, protects the hole against damage caused by impacts and friction of the
drill string, and acts as an anchorage for the safety equipment such as BOPs. Failure of
casing or tubing results in expensive reworking and may lead to loss of the well, or loss
of life. Casing serves the following important functions in the well.
1) It helps to keep the hole open and provides support for weak, vulnerable
or fractured formations. hus it prevents the collapse of the borehole
during drilling, and the hole from caving in or washing out.
2) It is used to isolate the porous media with diferent luids, and pressure
regimes from contaminating the pay zone. his is basically achieved
through the combined presence of cement and casing. hus production
from a speciic zone can be achieved.
3) It prevents cross channeling between two or more subsurface luidbearing layers.
4) It prevents the contamination of near-surface freshwater zones and protects freshwater sands from contamination by luids from lower zones.
It keeps water out of the producing formation.
5) It protects drilling luids from subsurface formations (prevents lost circulation) and from invasion by formation luids (i.e. saltwater, gas, etc.).
6) It provides a passage for hydrocarbon luids and most production operations are carried out through special tubing, which is run inside the casing.
7) It provides a suitable connection for the wellhead equipment and serves
as a structure to install the BOP for well control during drilling.
8) It minimizes the formation of damage by drilling mud (i.e. water-sensitive shale, hydrocarbon-bearing zones).
Casing Design 435
9) It provides a hole of known diameter and depth to facilitate the running
of testing and completion equipment.
10) It is used to complete and produce the well eiciently.
8.3 Types of Casing String
he functions, and types or names of the various casings vary according to the depth
where they are placed. A typical stack of casing showing its threads is shown in Figure
8.1. In reality it is not possible to drill a hole to total depth (TD) with a small diameter drill bit, and then case the hole from surface to TD. his is due to the presence of
high-pressured zones at diferent depths along the wellbore, and the presence of weak,
unconsolidated formations or sloughing, shaly zones. hese troublesome zones need to
be sealed of by running casing and subsequently allow drilling up to TD. As a result,
diferent sizes (i.e. continuously decreasing diameter) of casing are used which gives
a tapered shape to the inished well. Apart from the diiculties of drilling the rocks
encountered, the number and size of casings also depend on the depth of the well and
on the reason for drilling. Starting from the uppermost and largest casing, the irst one
comes as the conductor pipe, then the surface casing and the intermediate casing, and
inally the production casing. In addition, there is a special type of pipe used in ofshore
drilling called marine riser. he diferent types of casings are discussed as follows:
8.3.1 Stove Pipe and Riser
A stovepipe is used as a marine conductor, drive pipe or structural pile or foundation pile for ofshore drilling only (Figure 8.2a). It is run to prevent washouts of nearsurface unconsolidated formations. It also provides a circulation system for the drilling
mud and ensures the stability of the ground surface upon which the rig is placed. For
example, Figure 8.2b shows that the circulation is maintained through the conductor
pipe attached to the sea loor. In general, stovepipe does not carry any weight from the
wellhead equipment and can be driven into the ground or seabed with a pile driver.
A typical size for a stovepipe ranges from 26–42 in. However, it may vary from 16 to
60 in diameter and the range of the length is 150 to 300 based the depth of the water
depth from the sea level.
Figure 8.1 Casing with threaded joints.
436 Fundamentals of Sustainable Drilling Engineering
with riser
mud
Stove pipe
(a) Stove pipe in an ofshore platform
(b) A conductor pipe with riser
in the sea bed
Figure 8.2 A typical example of a riser.
A drilling riser is a conduit that provides a temporary extension of a subsea oil
well to a surface drilling facility. In general, there are two diferent types of risers such
as marine riser, and tieback riser. A marine riser is the pipe which connects the subsea BOP stack with the loating drilling rig and generally deployed from ixed platforms or very stable loating platforms like a spar or tension leg platform (TLP). A
marine drilling riser consists of a large diameter, low pressure main tube with external
auxiliary lines that include high pressure choke and kill lines for circulating luids to
the subsea blowout preventer (BOP), and usually power and control lines for the BOP.
he riser allows mud to be circulated back to surface, and provides guidance for tools
being lowered into the wellbore. he international standard ISO 13624-1:2009 covers
the design, selection, operation and maintenance of marine riser systems for loating
drilling operations. Its purpose is to serve as a reference for designers, for those who
select system components, and for those who use and maintain this equipment. It relies
on basic engineering principles and the accumulated experience of ofshore operators,
contractors, and manufacturers.
A tieback riser can be either a single large-diameter high-pressure pipe, or a set of
concentric pipes extending the casing strings in the well up to a surface BOP. here are
some risers that have joints with buoyancy modules (Figure 8.3). Riser tensioner is a
pneumatic or hydraulic device used to provide a constant strain in the cables, which
support the marine riser. A telescopic joint is a component installed at the top of the
marine riser to accommodate vertical movement of the loating drilling rig.
Casing Design 437
Figure 8.3 Drilling riser joints with buoyancy modules.
8.3.2 Conductor Pipe
he conductor is the irst casing string that needs to be run and thus has the largest
diameter. he conductor pipe is run from the surface to a shallow depth to protect
near surface unconsolidated formations, seal of shallow-water zones (Figure 8.4). It
permits the circulation of the mud during the irst drilling phase. It protects the surface
of unconsolidated formations against erosion due to the mud circulation, which could
compromise the stability of the rig foundations. Conductor pipe protects subsequent
Conduction
Pipe
Surface
Casing
Production
Casing
Production
Tubing
Protect "V"
Casing
N. P.
(a) Normally pressured
(b) Abnormally pressured
Figure 8.4 A typical diferent types of casing seats at diferent well depth.
438 Fundamentals of Sustainable Drilling Engineering
casing strings from corrosion. It provides protection against shallow gas lows and protects the foundation of the platform in ofshore operations. his casing allows one or
more BOPs to be mounted on it or a diverter system if the setting depth of the conductor pipe is shallow. he size of the conductor pipe varies according to the geographical
locations. For example, atypical size for a conductor pipe is either 18⅝ or 20 in the
Middle East. In North Sea exploration wells, the size of the conductor pipe is usually
26” or 30”. However it might vary from 16” to 48” in diameter and the length of the
conductor pipe is normally 40’–300’ (Figure 8.3). In general it is set at approximately
100 t. below the ground level or seabed. Conductor pipe is always cemented to surface.
It is used to support subsequent casing strings and wellhead equipment or alternatively
the pipe is cut of at the surface ater setting the surface casing. In ofshore operations,
conductor pipes are either driven by a hammer or run in a drilled hole or run by a
combination of drilling and driving especially where hard boulders are encountered
near seabed.
8.3.3
Surface Casing
Surface casing is run ater the conductor casing and is set at approximately 1,000–1,500
t. below the ground level or seabed. It is used to prevent caving of weak formations that
are encountered at shallow depths and washing out of poorly consolidated surface beds.
his casing should be set in competent rocks such as hard limestone. his will ensure
that formations at the casing shoe will not fracture at the high hydrostatic pressures,
which may be encountered later. he surface casing is cemented up to the surface to
increase its stifness and makes it capable of bearing the compressive loads resulting
from the positioning of the subsequent casings. It protects freshwater sands from possible contamination caused by drilling luid mud, oil or gas and or saltwater from lower
zone. It is used to provide anchorage for the subsequent casing, and to support the wellhead. he surface casing also serves to provide protection against shallow blowouts and
hence BOPs are connected to the top of this string. he setting depth of this casing string
is chosen in such as way so that it may protect the troublesome formations, thief zones,
water sands, shallow hydrocarbon zones and build-up sections of deviated wells. A typical size of this casing is l3⅜ (Figure 8.5) in the Middle East and 18⅝ or 20 in North
Sea operations. However it might vary from 8⅝ to 20 in diameter and the length of the
surface casing is normally 300 –5,000 (Figure 8.5). Its length depends on the depth of
the aquifers and on the calculated wellhead pressure following the entry of luids from
the bottomhole into the casing. In fact, as the surface casing is the irst casing on which
the BOPs are mounted, it has to be positioned at a depth where the formation fracturing
pressure is suiciently high to allow the BOPs to be closed without any risk.
8.3.4
Intermediate Casing
Intermediate casing is also called protection casing. It depends on well depth and geology in a speciic area. It is usually set in the transition zone below or above an overpressured zone (Figure 8.5). It is used to protect against problem formations such as
mobile salt zones, caving shales, thief zones etc. he primary functions of intermediate zones is to seal of troublesome zones which contaminate drilling luid; jeopardize
Casing Design 439
36” Hole
30” Conductor Casing
13? Surface Casing
9? Intermediate
Casing
5½ Production Casing
Cement
36”
Casing shoe
(Conductor Pipe)
Surface Casing
20” Casing shoe
(Surface Casing)
Intermediate Casing
6000’
Outmost casing
String or Conductor
Pipe
2000’
100’
7” Production
Casing
Production Casing
Liner
13? ” Casing shoe
(Intermediate Casing)
Production Tubing
12.25” Casing shoe (Liner)
Reservoir
Formation
Packer
Figure 8.5 A detail casing placement at diferent well depth with diferent casings.
drilling progress with possible pipe sticking, excessive hole enlargement; contain
abnormal pressure luids; protect formation below the surface casing from higher pressure credited by mud. he casing depth of the intermediate columns depends on the
pore pressure proile of the underground luids. As the hole goes deeper, the well has
to be cased because the hydrostatic pressure of the mud equals the fracturing pressure
of the weakest formation present in the openhole. he weakest formation is usually
the one nearest the surface, immediately under the last pipe of cemented casing. In
this way it is possible to drill every phase of the well with drilling luids of diferent
densities. he intermediate casings are cemented along the entire length of openhole,
up to about a hundred metres in the preceding casing. Good cementation of this casing must be ensured to prevent communication behind the casing between the lower
440 Fundamentals of Sustainable Drilling Engineering
hydrocarbon zones and upper water formations. Multistage cementing may be used to
cement this string of casing in order to prevent weak formations from being subjected
to high hydrostatic pressure from a continuous, long column of cement. he most common size of this casing is 9⅝ or 10¾ . However it ranges from 7⅝ to 13⅜ in diameter
and no speciic range in length.
8.3.5 Production Casing
Production casing is the last casing string placed in the hole and it reaches the top of
the pay formation. It is set through a productive interval to segregate pay zones, and
can be used to produce luid instead of tubing. If the completion is open-hole, or it goes
right through all of it, the completion has a cased borehole. he completion equipment
is set inside this casing, which enables the underground luids to reach the surface. he
primary functions are to isolate producing zones, to provide reservoir luid control
and to permit selective production in multi zone production. his is the string through
which the well is completed and perforations are made to allow hydrocarbon production (Figure 8.5). he usual sizes of this string are 4½ , 5 and 7 . However it ranges
from 4½ to 9⅝ in diameter and no speciic range in length. his is the most important
casing and must not collapse since it has to remain eicient for the entire productive life
of the well. he design of this casing must ensure its resistance to the maximum pressure exerted by the luids to be produced, and guarantee its resistance to any corrosion
that might be induced by the chemical composition of the luids.
8.3.6 Liners
A liner is a string of casing that is run in a particular depth of interest within the TD and
does not reach up to the surface (Figure 8.5). Liners are hung on the intermediate casing
by using a liner-hanger and ensure the hydraulic and mechanical seal (Figure 8.6). In liner
completions, both the liner and the intermediate casing perform as the production string
because a liner is set at the bottom and hung from the intermediate casing. he major
advantages of using the production linear are: i) total costs of the production string are
reduced, ii) running and cementing times are reduced, iii) the length of reduced diameter
is reduced which allows completing the well with optimum sizes of production tubings.
In general, liner is used to reduce the cost of casing which works as an intermediate casing. he choice of a liner rather than a casing depends on economic and technical considerations. It decreases the weight on the hook during the running of the liner into the well.
his factor is important especially in deep wells, or when the rig has a limited hook load
capacity. Moreover, the liner also leads to improved borehole hydraulics, as the decrease
in length of the small-diameter annulus reduces circulation head losses. If necessary, the
liners may be backed up to the surface with a casing run downhole in a special seating in
the head of the hanger. he liner and its hanger are lowered into the well with a drill string,
and its length is such that when the operation is completed the hanger is about 330 t.
inside the preceding casing. Typically the major design criterion for a liner is the ability to
withstand the maximum expected collapse pressure.
he basic types of liner systems are shown in Figure 8.6. For example, drilling liners are used to isolate lost circulation or abnormally pressured zones to permit deeper
Casing Design 441
Intermediate
Casing
Packer
Liner Hanger
Casing Shoe
Scab liner
Liner
Tie back liner
Scab tie
back liner
Figure 8.6 Diferent types of liners attached with casings.
drilling. Production liners are run instead of a full casing to provide isolation across
the production or injection zones. he tieback liner is a section of casing extending
upwards from the top of an existing liner to the surface. It may or may not be cemented
in place. he scab liner is a section of casing that does not reach the surface and is used
to repair existing damaged casing. It is normally sealed with packers at top and bottom.
In some cases, it is also cemented. he scab tieback liner is a section of casing extending from the top of an existing liner but does reach the surface. he scab tieback liner is
normally cemented in place.
However, there are some other advantages of using liners that include i) complete
wells with less weight landed on wellheads and surface pipes, ii) a scab liner tieback
provides heavy wall cemented section through salt sections, iii) permits drilling with
a tapered drill string, iv) where rig capacity cannot handle full string; when running
heavy 9 5/8” casing, v) to provide a polished bore receptacle (PBR) completion. his
type of completion is recognised to be the best casing to tubing seal system, vi) improved
completion lexibility, vii) to provide an upper section of casing (tieback liner) which
had seen no drilling, viii) for testing in critical areas where openhole testing is not
practised. he disadvantages of a liner are i) possible leak across a liner hanger, and ii)
diiculty in obtaining a good primary cementation due to the narrow annulus between
the liner and the hole.
8.4 Components of Casing String
A casing string is made of individual joints of steel pipes of diferent sizes (Figure 8.7).
he chart in Figure 8.7 depicts the most common casing size and hole size conigurations. Solid lines indicate commonly used bits for that size pipe and can be considered
adequate clearance to run and cement the casing or liner. he dotted lines represent
less commonly used conigurations. he selection of one of these broken paths requires
that special attention be given to the connection, mud weight, cementing, and doglegs
(Economides et al., 1998). Casings are connected together by threaded connections
(Figure 8.1). In general, the joints of casing in a string have the same outer diameter
and are approximately 40 t. long. A bull-nose shaped device, known as a guide shoe or
casing shoe, is attached to the bottom of the casing string (Figure 8.6).
442 Fundamentals of Sustainable Drilling Engineering
Casing and liner
size (inches)
4
Bit and hole
size (inches)
4¾
Casing and liner
size (inches)
57 3
5½
5
61 2
61 3
77 3
75 3
Casing and liner
size (inches)
Bit and hole
size (inches)
4½
65 3
77 3
753 3
7 4
7
8½
8¾
9573
9 3
85 3
95 3
85 3
9½
105 3
121 4
103 4
1137 4
11 3
13x x
14
Bit and hole
size (inches)
105 3
121 4
Casing and liner
size (inches)
113 4
117 3
13x x
14
16
20
Bit and hole
size (inches)
143 4
12½
20
26
16
20
24
30
Casing and liner
size (inches)
14¾ 17½
Figure 8.7 Diferent sizes of casing string (Mitchell and Miska, 2011).
A casing hanger is a mechanism that locks into the casing head, responsible for
hanging the casing pipe (Figure 8.8). It is attached to the top of the casing, which allows
the casing to be suspended from the wellhead. Slip hangers seal automatically or manually, depending on the types of seals integral to their installation. here are some other
items of equipment such as loat collar, centralizers and scratchers associated with the
cementing operation (Chapter 9). hese items may be included in the casing string or
attached to the outside of the casing.
8.5 Classiication and Properties of Casing
Casing is manufactured in a wide variety of sizes, lengths, grades and weights. Casing
can be specially made for diicult environments such as highly corrosive, toxic, and
high-pressure zones. A number of diferent coupling types are also available. he
detailed speciication of the sizes, weight and grades of casing that are most commonly
used has been standardized by the API. he various types of casing and their properties such as sizes, weights and grades that are available can be found in manufacturer catalogues and cementing company handbooks. Casing is generally classiied in
manufacturer catalogues and handbooks in terms of i) size (i.e. outside diameter, OD),
Casing Design 443
Figure 8.8 Casing hanger (FMC Technologies, http://www.fmctechnologies.com).
ii) range of length, iii) casing grade, iv) casing weight in wt/t, and v) type of coupling
i.e. connections. American Petroleum Institute (API) declared the standardization of
casing based on these standards.
8.5.1 Casing Size
he outside diameter of a casing is recognized as the casing size. It is the main body of
the tubular. he sizes vary from 4.5 to 36 in diameter. hese can be found in manufacturer’s catalogues or the ield book tables. Tubulars with an OD of less than 4.5 are
called tubing. Figure 8.7 shows the sizes of casing used for a speciic well, which are
generally limited to those standard sizes. he igure also shows the hole sizes required
to accommodate these casing sizes. he choice of OD may be limited by the availability
of certain sizes.
8.5.2
Range of Length
Casing is normally available in three length ranges as shown in Table 8.1. he joint
length of the casing has been standardized and classiied by the API recommendation.
In reality it is not possible to manufacture the casing to a speciic length. herefore,
when the casing is delivered to the rig side, the length of each joint should be measured
Table 8.1 API casing length ranges
Ranges
Ranges of Length (t.)
Average length (t.)
R-1
16–25
22
R-2
25–34
31
R-3
>34
42
444 Fundamentals of Sustainable Drilling Engineering
and recorded on the tally sheet. he length is measured from the top of the collar to the
uppermost thread. Lengths are recorded to the nearest 100th of a foot. he most common range of lengths is 25–34 t. However, the shorter lengths are useful as pup joints
when spacing out the hanger.
8.5.3 Casing Grade
Casing grades are very much dependent on the chemical composition and the mechanical properties of steel. hese properties of casing difer extensively. A variety of compositions and treatment processes are used during the manufacturing process to develop
desired properties. he steel materials manufactured through the process have been
classiied by the API into a series of grades (Table 8.2). he table shows the maximum
and minimum yield strength in addition to minimum ultimate tensile strength. he
minimum elongation is also shown to the corresponding grades. A letter, and a number designate each grade. he letter refers to the chemical composition of the material
and the number refers to the minimum yield strength of the material (i.e. N-80 casing
means a minimum yield strength of 80,000 psi and K55 has a minimum yield strength
of 55,000 psi). herefore, the grade of the casing provides an indication of the strength
of casing and the higher the grade is, the higher the strength of the casing shows up. In
Table 8.2 API Recommended Casing Grades and Properties
Yield Strength
Minimum Ultimate
Tensile Strength
Minimum
Elongation
API
Grade
Minimum
Maximum
psi
%
H-40
40,000
80,000
60,000
29.5
J-55
55,000
80,000
75,000
24.0
K-55
55,000
80,000
95,000
19.5
C-75
75,000
90,000
95,000
19.5
L-80
80,000
95,000
95,000
19.5
N-80
80,000
110,000
100,000
18.5
C-90
90,000
105,000
100,000
18.5
C-95
95,000
110,000
105,000
18.0
S-95
95,000
110,000
110,000
18.0
T-95
95,000
110,000
105,000
18.0
P-110
110,000
140,000
125,000
15.0
Q-125
125,000
150,000
135,000
18.0
V-150
150,000
180,000
160,000
18.0
Casing Design 445
addition to the API grades, certain manufacturers produce their own grades of material. Both seamless and welded tubulars are used as casing although seamless casing is
the most common type of casing and only H and J grades are welded.
8.5.4 Casing Weight
Within each grade of casing various wall thicknesses are available for a given OD. he
wall thickness is indicated by the weight per foot, which can be obtained from ield
book tables. However, as an example, Table 8.3 shows the four diferent weights of 9⅝
casing.
API sets the dimensions of casings, where very strict provisions exist for tolerances.
As a result, the actual ID of the casing varies slightly in the manufacturing process and
thus the drit diameter of casing is mentioned in the speciications for all casing. he
drit diameter is the minimum ID of the casing. his diameter would be important
when a decision needs to be made for certain drilling or completion tools which will be
able to pass through the casing. For example, the drit diameter of 9⅝ and 53.4 lbf/t.
casing is less than 8½ bit and therefore an 8½ bit cannot be used below this casing setting depth. If the 47 lbf/t. casing is too weak for the particular application then a higher
grade of casing would be used (Section 8.5.3). he volumetric capacity of the casing is
calculated using the nominal ID of the casing.
8.5.5 Casing Connections
As already mentioned in the length ranges of casing in Table 8.1, sections of piece wise
casing are delivered to the rig side. herefore, it must be joined with threaded connectors as each length is run in the well. A threaded connection is used to connect individual joints of casing. It consists of a pin and box. Connections can be of three types–i)
threaded and coupled, ii) integral-joint, and iii) lush joints (Figure 8.9). hreaded and
coupled connections have pins on both ends of the pipe that screw into a common
coupling. For most threaded and coupled casings, the threads are cut into the unaltered
diameter of the tubes. Integral-joint casing connections oten have the ends of the casing tube thickened (swaged) on either the tube OD or ID (or both). his provides more
metal into which threads can be cut. hese connections are classiied into four types
such as API, premium, gastight, and metal-to-metal seals.
Table 8.3 API Recommended 9 5/8” Casing Weight
Weight
Outer diameter
Inner diameter
Wall thickness
Drit diameter
lbf/t
in
in
in
in
53.5
9.625
8.535
0.545
8.379
47
9.625
8.681
0.472
8.525
43.5
9.625
8.755
0.435
8.599
40
9.625
8.835
0.395
8.679
446 Fundamentals of Sustainable Drilling Engineering
Pin
Pin
Field
end
Coupling
Box OD
same as
pipe OD
Box
Mill end
Box OD
expanded
Pin
Threaded and coupled
Integral joint
Flush joint
Figure 8.9 Diferent types of joints.
he coupling must be leak resistant and should have the same or greater physical
properties as the casing itself. Various types of connections may be used. he standard types of API threaded and coupled connections are i) short thread connection
(STC), ii) long thread connections (LTC), iii) buttress thread connection (BTC), and
iv) extreme line connection (ELC). he STC thread proile is rounded with 8 threads
per inch and LTC is similar. However, it has a longer coupling, which provides better
strength and sealing properties than the STC. he BTC proile has lat crests with the
front and back cut at diferent angles. ELC also have lat crests and have 5 or 6 threads
per inch. he ELC connection is the only API connection that has a metal-to-metal seal
at the end of the pin and at the external shoulder of the connection, whereas all of the
other API connections rely upon the thread compound, used to make the connection,
to seal of the leak path between the threads of the connection.
8.6 Manufacturing of Casing
he three basic processes used in the manufacturing of casing:
i) Seamless process
ii) Electric-resistance welding, and
iii) Electric-lash welding
8.6.1 Seamless Process
In the seamless process, a billet is irst pierced by a mandrel in a rotary piercing mill
(Figure 8.10). he heated billet is introduced into the mill, where it is gripped by two
obliquely oriented rolls that rotate and advance the billet into a central piercing plug.
8.6.2 Electric-resistance Welding
In the electric welding processes, lat sheet stock is cut and formed and the two edges
are welded together without the addition of extraneous metal to form the desired tube.
Casing Design 447
(a) Rotary Piercing Mills
(c) Reelers
(b) Plug Mills
(d) Sizing Mills
Figure 8.10 Manufacturing of seamless casing (Mitchell and Miska, 2011).
PINCH
BUTT-END ROLL
WELDER
LOOPER
LEVELING & FORMING
UNCOILING
SIZING
WELD BEAD TRIMMER
CUTTING
HIGH FREQUENCY
WELDING
COOLING
BLOWER
END-FACING
HYDROSTATIC TEST
GALVANIZING
STRAIGHTENING
THREADING & SOCKETING
MARKING
PACKING
Figure 8.11 Manufacturing process for steel pipes and tubes at TST pipes.
8.6.3 Electric-lash Welding
In electric-lash welding technique processes a sheet by cutting it to the desired dimensions, simultaneously forming the entire length to a tube, and lashing and pressing
the two edges together to make the weld. Figure 8.11 shows the steps of manufacturing
process for steel pipes and tubes in detail.
8.7 Rig-site Operation
Rig-site operations are one of the heavy works in the whole drilling operation. here are
three types of rig-site operations: i) handling procedure, ii) running procedures, and
iii) landing procedures. When handling and running the casing on the rig, there might
have damage of the threads, which cause the casing leaks. It is also known for a joint of
448 Fundamentals of Sustainable Drilling Engineering
CASING
COUPLING
Casing
Coupling
Figure 8.12 Installing conductor casing.
the wrong weight or grade of casing to be run in the wrong place. As a result, a weak
spot would be creating in the drill string. Such mistakes are usually very expensive to
repair, both in terms of rig time and materials. herefore, it is important to use the correct procedures when running the casing.
8.7.1
Handling Procedures
As was deined earlier, casing is a pipe usually larger in diameter and longer than drill pipe
and is used to line the hole. Casing operations occur periodically throughout the drilling process starting with the conductor casing, surface casing, intermediate casing, and
ending with production string which takes place during well completion (Figure 8.12).
here is special equipment that is normally used during the handling process (Figure
8.13, and Figure 8.14). his equipment is heavy. he activities involved in casing operations can vary according to the type of casing being installed, but generally fall into
these steps: i) installing casing tools, ii) running casing into the hole, iii) installing casing
accessories, iv) circulating and cementing. hese steps are discussed below.
i) Stacking: When the casing arrives at the rig site, the casing should be
carefully stacked in the correct running order. his is especially important when the string contains sections of diferent casing grades and
weights. On ofshore rigs, where deck space is limited, do not stack the
casing too high or else. It will create excessive lateral loads on the lowermost row. Casing is of-loaded from the supply boat in reverse order,
so that it is stacked in the correct running order.
Casing Design 449
Figure 8.13 Special casing elevators.
Elevators
Monkeyboard
Pipe
Fig. 8.14 Derrickman latching elevators.
ii) Proper Checking: he length, grade, weight and connection of each
joint should be checked thoroughly. Each joint should be clearly numbered with paint. he length of each joint of casing is recorded on a tally
sheet. If any joint is found to have damaged threads it can be crossed of
the tally sheet. he tally sheet is used by the drilling engineer to select
those joints that must be run so that the casing shoe ends up at the correct depth when the casing hanger is landed in the wellhead.
iii) Coupling Check: While the casing is on the racks the threads and couplings should be thoroughly checked and cleaned. Any loose couplings
should be tightened.
iv) Proper Protection: Casing should always be handled with thread protectors in place. hese need not be removed until the joint is ready to be
stabbed into the string.
450 Fundamentals of Sustainable Drilling Engineering
8.7.2
Running Procedures
Liners are run on a drill pipe with special tools which allow the liner to be run, set
and cemented all in one trip (Figure 8.15). he liner hanger is installed at the top of
the liner. he hanger has wedge slips. hese slips can be set against the inside of the
previous string and can be set mechanically (rotating the drill pipe) or hydraulically
(diferential pressure). A liner packer may be used at the top of the liner to seal of
the annulus ater the liner has been cemented. he basic liner running procedure is
as follows:
1. Visually check each joint of casing/liner to ensure all joints are clear of
foreign matter, measured and drited.
2. Reduce the annular preventer closing pressure to less than the collapse
rating of the casing/liner, if necessary.
3. Make up a full opening safety valve (in the open position) on the casing circulating swage and position it in a readily accessible drill loor
location.
4. Make up the shoe loats and shoe track as per the running list.
5. Check loat equipment ater the shoe track is run in ensure the loat is
holding and that circulation is possible.
6. Install centralizers as per the centralizer programme.
7. Partially ill each joint and completely ill every ive joints.
8. Make up the connections in accordance with API Speciication 5CT.
9. Run the casing/liner smoothly, avoiding high acceleration and deceleration, which could cause unnecessary surge/swab pressures.
10. Limit the casing/liner lowering speed to 45 sec/joint or to the optimum
speed from surge/swab calculations.
11. Monitor returns constantly by using the trip tank and inform the driller
of any potential loss circulation zones.
12. Monitor drags.
13. Count the joints of casing/liner remaining on deck before landing the
casing/liner at the settling depth and compare this number against the
amount in the hole and amount received at the well site. his should
conirm that the casing/liner is set at the proper depth.
14. Minimize the time between landing the casing/liner and breaking circulation to avoid plugging the loat equipment.
15. Land the casing such that it is at a safe height for installing the cementing head, i.e., 4 feet–5 feet above the rig loor if possible.
16. Circulate a minimum volume of 150% of the annulus/casing/liner contents, once circulation has been established.
In short, the running procedure can be summarized as run the liner on drill pipe to
the required depth, set the liner hanger, circulate drilling luid to clean out the liner,
back of (disconnect) the liner hanger setting tool, pump down and displace the cement,
set the liner packer, pick up the setting tool, and reverse circulate to clean out cement
and pull out of hole.
Casing Design 451
Plug Dropping
Head
Setting Tool
Hanger
Slick Joint
Cementing
Manifold
Liner Tie-Back Sleeve
Pack-of Bushing
(Retrieval-Optional)
Wiper Plug
(Shear type)
Stand-Of Devices
Landing Collar
Float Collar
Float Shoe
Figure 8.15 Casing liner equipment.
8.7.3
Landing Procedures
Casing landing practices vary signiicantly throughout the industry. In some cases, considerable additional axial stress will be placed in the casing when it is landed in the
wellhead. Ater the casing is run to the required depth, it is cemented in place while
suspended in the wellhead. he method used for landing the casing will vary from
area to area, depending on the forces exerted on the casing string ater the well is completed. hese forces may be due to changes in formation pressure, temperature, luid
density and earth movements (compaction). Landing procedures follow the following
four common methods and the axial stress must be considered in the casing design. An
API committee identiied these four common methods for landing casing:
1) Landing the casing with the same tension that was present when cement
displacement was completed.
2) Landing the casing in tension at the freeze point, which is generally considered to be at the top of the cement.
3) Landing the casing with the neutral point of axial stress (σz = 0) at the
freeze point.
4) Landing the casing in compression at the freeze point.
8.8 Casing Design and Selection Criteria
Based on the commercial hydrocarbon quantities discovery, the design of a casing program starts with specifying the surface and bottomhole well locations and the size of
452 Fundamentals of Sustainable Drilling Engineering
the production casing. he number and sizes of tubing strings and the type of subsurface artiicial lit equipment may ultimately be placed in the well and determine
the minimum ID of the production casing. In general, these speciications are determined for the drilling engineer by other members of the engineering staf. In some
cases, consideration must also be given to the possibility of exploratory drilling below
an anticipated productive interval. he drilling engineer then must design a program
of bit sizes, casing sizes, grades, and setting depths that will allow the well to be drilled
and completed safely in the desired producing coniguration. To obtain the most economical design, casing strings oten consist of multiple sections of diferent steel grade,
wall thickness, and coupling types. Such a casing string is called a combination string.
Additional cost savings sometimes can be achieved by the use of liner-tieback combination strings instead of full strings running from the surface to the bottom of the hole.
he casing design process involves three distinct operations: i) the selection of the
casing sizes and setting depths; ii) the deinition of the operational scenarios which will
result in burst, collapse and axial loads being applied to the casing; and inally iii) the
calculation of the magnitude of these loads and selection of an appropriate weight and
grade of casing. Before embarking on a casing design exercise, the essential data must
be obtained from various sources including: geologists, petrophysicists, reservoir engineers etc. he format given in Table 8.4 shows from where the data may be obtained.
Once the above data is obtained, it may be organised in the format given in Table 8.5,
which would greatly help in casing design calculations. It should be noted that the
accuracy of the casing programme is dependent on the accuracy of data used.
8.8.1
Factors Inluencing Casing Design
Casing design involves the determination of factors that inluence the failure of casing
and the selection of the most suitable casing grades and weights for a speciic operation,
both safely and economically. he casing programme should also relect the completion
Table 8.4 Sources of data for casing design
Data
Source
1. Formation pressure, psi
Ofset wells, well logs, log analyst
2. Casing setting depths, t.
Ofset wells, kick tolerance calculations
3. Fracture gradient in psi/t. or fracture pressure at the casing seat, ppg or psi
Ofset wells, well logs, calculation of
fracture gradient
4. Mud density, ppg
As above
5. Mean sea water level, t.
Geographical data
6. Available casing grades and weights
Stock status report
7. Strength properties (i.e. burst, collapse, yield)
API manufacturer’s catalogues
8. Geothermal temperatures, °F, °C
Ofset wells
Casing Design 453
Table 8.5 Essential Data
Essential Data
Casing OD, in
18⅝
13⅜
9⅝
7
Casing setting depth (TVD), t.
Casing grade and weight (lb/t.)
I.D., in
Drit diameter, in
Coupling type
Collapse strength, psi
Burst strength, psi
Body yield strength (lbf x 1000)
Connection parting load (lbf x 1000)
Mud density to drill hole for this casing, ppg
Expected formation pressure at next TD, psi
Fracture gradient at casing seat, psi/t.
Mudline depth, t.
Geothermal gradient,
and production requirements. he following are some of the factors inluencing casing
design.
1. A good knowledge of stress analysis and the ability to apply it are necessary for the design of casing strings. he end product of such a design
is a ‘pressure vessel’ capable of withstanding the expected internal and
external pressures and axial loading. Hole irregularities further subject
the casing to bending forces, which must be considered during the selection of casing grades.
2. A safety margin is always included in casing design, to allow for future
deterioration of the casing and for other unknown forces, which may be
encountered, including corrosion, wear and thermal efects.
3. Loading conditions during drilling and production.
4. he strength properties of the casing seat (i.e. formation strength at casing shoe).
5. he degree of deterioration the pipe will be subjected to during the entire
life of the well.
6. he availability of casing.
454 Fundamentals of Sustainable Drilling Engineering
8.8.2 Design Criteria
here are three basic forces where the casing is subjected to collapse, burst and tension.
hese are the actual forces that exist in the wellbore. hey must irst be calculated and
must be maintained below the casing strength properties. In other words, the collapse
pressure must be less than the collapse strength of the casing and so on. Casing should
initially be designed for collapse, burst and tension. Reinements to the selected grades
and weights should only be attempted ater the initial selection is made. he suitability
of selected casing depends on the accuracy of data collected in Table 8.5. For directional
wells a correct well proile is required to determine the true vertical depth (TVD). All
wellbore pressures and tensile forces should be calculated using true vertical depth
only. he casing lengths are irst calculated as if the well is a vertical well and then these
lengths are corrected for the appropriate hole angle.
8.8.3 Approaches of Casing Design
he designer must consider all the anticipated loadings on the casing string at the time
when the casing is run and throughout the life of the well. he design must meet the
conlicting requirements of collapse and burst, while ensuring the tensile properties of
the casing are never exceeded. he most economical design should be selected, consistent with good engineering practice. his usually results in a “combination” string
(or tapered string), where the OD remains the same throughout but certain sections of
difering grade and weight of casing are included to reduce costs. he below steps are
followed in casing design considerations. he following loads should be considered in
the approach during casing design:
1. Design Process
a) Selection of casing sizes
b) Selection of setting depths
c) Deinition of design properties
d) Calculation of magnitude of properties
2. Design Properties
a) Collapse strength or loading (i.e. pressure)
b) Burst strength or loading (i.e. pressure)
c) Yield strength–tensile and compressive
d) Biaxial loading considerations
e) Efect of bending
3. Design Procedure
a) Collapse pressure calculation
b) Burst pressure calculation
c) Tensile/compressive strength calculation
4. Safety Factor
8.8.3.1 Design Process
he design process includes i) selection of casing sizes, ii) selection of setting depths,
iii) deinition of design properties, and iv) calculation of magnitude of properties.
Casing Design 455
1. Selection of Casing Sizes: As mentioned earlier, Figure 8.7 shows the common hole
and bit sizes, and casing and liner sizes. he size of the casing strings is controlled by the
inner diameter of the production string and the number of intermediate casing strings
required reaching the desired depth. To enable the production casing to be placed in
the well, the bit size used to drill the last interval of the well must be slightly larger than
the OD of the casing connectors. he selected bit size should provide suicient clearance and beyond the OD of the coupling to allow for mud cake on the borehole wall and
for casing appliances, such as centralizers and scratchers. he bit used to drill the lower
portion of the well also must it inside the casing string above. his, in turn, determines
the minimum size of the second-deepest casing string. With similar considerations,
the bit size and casing size of successively more shallow well segments are selected.
Selection of casing sizes that permit the use of commonly used bits is advantageous
because the bit manufacturers make readily available a much larger variety of bit types
and features in these common sizes. However, additional bit sizes are available that can
be used in special circumstances.
2. Selection of Setting Depths: he selection of the number of casing strings and their
respective setting depths generally is based on a consideration of the pore-pressure
gradients and fracture gradients of the formations to be penetrated. he pore pressure gradient and fracture gradient data are obtained by the methods presented in
Chapter 6. hey are expressed as an equivalent density, and are plotted against depth
(Figure 8.16). A line representing the planned-mud-density program is also plotted.
he mud densities are chosen to provide an acceptable trip margin above the anticipated formation pore pressures to allow for reductions in efective mud weight caused
by upward pipe movement during tripping operations. In summary, when planning a
well the formation pore pressures and fracture pressures can be predicted from the following procedure:
Fracture
gradient
Pore
pressure
gradient
Low
mud-weight
proile
Medium-line
mud-weight
proile
Alternative mud-weight schedule
Figure 8.16 Alternative mud-weight schedules.
High
mud-weight
proile
456 Fundamentals of Sustainable Drilling Engineering
Fracture
gradient
d
Pore
pressure
gradient
Conductor
Surface
Depth
Normal pressure
Equivalent Mud Density
Fracture
gradient less
kick margin
c
Intermediate
b
Mud density
(pore pressure
plus trip margin)
a
Production
Depth Objective
Figure 8.17 Casing setting depths (Bourgoyne et al., 1991).
1) Analyze and plot log data or d-exponent data from an ofset (nearby) well.
2) Draw in the normal trend line, and extrapolate below the transition zone.
3) Calculate a typical overburden gradient using density logs from ofset
wells.
4) Calculate formation pore pressure gradients from equations (e.g. Eaton).
5) Use known formation and fracture gradients and overburden data to calculate a typical Poisson’s ratio plot.
6) Calculate the fracture gradient at any depth.
As mentioned above, equivalent mud density in lbm/gal is an important parameter
for setting casing depth. Figure 8.16 shows three mud weight selection principles: low
mud weight, median-line mud weight, and high mud weight. he median-line principle is a simple tool to establish an optimal mud weight schedule. he oil industry has
commonly used a mud weight barely exceeding the pore pressure, as shown in the let
stepped curve in the igure. When borehole stability analysis became invoked, a high
mud weight like the right stepped curve was oten recommended to reduce the tangential stress and, hence, the collapse potential of the well. he middle stepped curve gave
better results because it is based on the idea of minimum disturbance of the stresses
acting on the borehole. Once the formation pore pressure and fracture pressure are set,
the casing setting depth is inalized.
Figure 8.17 shows the relationship between casing-setting depth and these gradients.
A commonly used trip margin is 0.5 lbm/gal or one that will provide 200 to 500 psi
of excess bottomhole pressure (BHP) over the formation pore pressure. To reach the
depth objective, the efective drilling luid density shown at Point a is chosen to prevent
the low of formation luid into the well (i.e., to prevent a kick). However, to carry this
drilling luid density without exceeding the fracture gradient of the weakest formation
exposed within the borehole, the protective intermediate casing must extend at least to
the depth at Point b, where the fracture gradient is equal to the mud density needed to
drill to Point a. Similarly, to drill to Point b and to set intermediate casing, the drilling
Casing Design 457
luid density shown at Point c will be needed and will require surface casing to be set
at least to the depth at Point d. When possible, a kick margin is subtracted from the
true fracture-gradient line to obtain a design fracture-gradient line. If no kick margin
is provided, it is impossible to take a kick at the casing-setting depth without causing
hydrofracture and a possible underground blowout.
Other factors-such as the protection of freshwater aquifers, the presence of vugular
lost-circulation zones, depleted low-pressure zones that tend to cause stuck pipe, salt
beds that tend to low plastically and to close the borehole, and government regulations-also can afect casing depth requirements. In addition, experience in an area may
show that it is easier to get a good casing-seat cement job in some formation types
or that fracture gradients are generally higher in some formation types. When such
conditions are present, a design must be found that simultaneously will meet these special requirements and the pore-pressure and fracture-gradient requirements outlined
above. he conductor casing-setting depth is based on the amount required to prevent
washout of the shallow borehole when drilling to the depth of the surface casing and to
support the weight of the surface casing. he conductor casing must be able to sustain
pressures expected during diverter operations without washing around the outside of
the conductor. he conductor casing oten is driven into the ground, and the resistance
of the soil governs the length. he casing-driving operation is stopped when the number of blows per foot exceeds some speciied upper limit.
Example 8.1: A well is being planned to drill where well completion requires the use of
7-in. production casing set at 15,000 t. Determine the number of casing strings needed
to reach this depth safely, and select the casing setting depth of each string. Pore pressure, fracture gradient, and lithology data from logs of nearby wells are given in Figure
8.18. Allow a 0.5 lbm/gal trip margin, and a 0.5 lbm/gal kick margin when making the
casing-seat selections. he minimum length of surface casing required to protect the
freshwater aquifers is 2,000 t. Approximately 180 t. of conductor casing generally is
required to prevent washout on the outside of the conductor. It is general practice in
this area to cement the casing in shale rather than in sandstone.
Solution:
he planned-mud-density program irst is plotted to maintain a 0.5 lbm/gal trip margin at
every depth. he design fracture line is then plotted to permit a 0.5 lbm/gal kick margin at
every depth. hese two lines are shown in Figure 8.18 by dashed lines. To drill to a depth
of 15,000 t, a 17.6 lbm/gal mud will be required (Point a). his, in turn, requires intermediate casing to be set at 11,400 t. (Point b) to prevent fracture of the formations above
l1,400 t. Similarly, to drill safely to a depth of 11,400 t. to set intermediate casing, a mud
density of 13.6 lbm/gal is required (Point c). his, in turn, requires surface casing to be set
at 4,000 t. (Point d). Because the formation at 4,000 t. is normally pressured, the usual
conductor-casing depth of 180 t. is appropriate. Only 2,000 t. of surface casing is needed
to protect the freshwater aquifers. However, if this minimum casing length is used, intermediate casing would have to be set higher in the transition zone. An additional liner also
would have to be set before the total depth is reached to maintain a 0.5 lbm/gal kick margin. Because shale is the predominant formation type, only minor variations in casingsetting depth are required to maintain the casing seat in shale.
458 Fundamentals of Sustainable Drilling Engineering
Equivalent Mud Density, lbm/gal
8
10
12
14
16
2,000
20
Fracture
gradient
4,000
d
Fracture
gradient less
0.5 lbm/gal
kick margin
6,000
Depth, ft
18
8,000
10,000
c
12,000
14,000
Pore
pressure
gradient
b
Mud density
0.5 lbm/gal
trip margin
a
16,000
Figure 8.18 Setting depth example (Mitchell and Miska, 2011).
Example 8.2: A well is being planned to drill where well completion requires the use
of 7-in. production casing set at 15,000 t. Determine the casing size (i.e. OD) for each
casing string needed to reach this depth safely. Pore pressure, fracture gradient, and
lithology data from logs of nearby wells are given in Figure 8.18. Allow a 0.5 lbm/gal
trip margin, and a 0.5 lbm/gal kick margin when making the casing-seat selections. he
minimum length of surface casing required to protect the freshwater aquifers is 2,000
t. Approximately 180 t. of conductor casing generally is required to prevent washout
on the outside of the conductor. It is general practice in this area to cement the casing
in shale rather than in sandstone.
Solution:
A 7 in. production casing string is desired. An 8.625-in. bit is needed to drill the bottom section of the borehole (Table 8.6). An 8.625 in. bit will pass through most of the
available 9.625 in. casings (Table 8.7). However, a inal check will have to be made ater
the required maximum weight per foot is determined. According to the data presented
in Table 8.6, a 12.25 in. bit is needed to drill to the depth of the intermediate casing.
As shown in Table 8.7, a 12.25 in. bit will pass through 13.375 in. casing. A 17.5 in.
bit is needed to drill to the depth of the surface casing (Table 8.6). Finally, as shown
in Table 8.7, a 17.5 in. bit will pass through 18.625 in. conductor casing, which will be
driven into the ground.
3. Deinition of Design Properties: the deinitions of design properties are important for proper calculation. Collapse pressure, burst pressure, yield strength, tensile
strength, and compressive strength are the design properties.
Collapse pressure: it can be deined as the diference between external and internal
pressure. Mathematically, it can be expressed as given by Eq. (8.1):
pb
External pressure Internal pressure
(8.1)
Casing Design 459
Table 8.6 Commonly used bit sizes for running API casing (Burgoyne et al., 1986)
Casing Size (OD)
(in)
Coupling Size (OD)
(in)
Common Bit Sizes Used
(in)
5.0
6, 6.125, 6.25
5
5.563
6.5, 6.75
5.5
6.050
7.875, 8.375
6
6.625
7.875, 8.375, 8.5
6.625
7.390
7.875, 8.375, 8.5
7.0
7.656
8.625, 8.75, 9.5
7.625
8.500
9.875, 10.625, 11.0
8.625
9.625
11.0, 12.25
9.625
10.625
12.25, 14.75
10.75
11.750
15.0
13.375
14.375
17.5
16.0
17.0
20.0
20.0
21.0
24.0, 26.0
4.5
p
p
EXTERNAL
PRESSURE
Figure 8.19 Collapse failure from external pressure.
A detailed description about the collapse pressure is given in Section 7.4.1 of
Chapter 7. Here we will discuss some detail of collapse pressure related to casing
design. Collapse requirements are mandatory for designing collapse. Collapse pressure
is afected by axial stress and if external pressure exerts, collapse failure will happen as
shown in Figure 8.19. here are two important factors that afect the collapse pressure:
i) the collapse pressure resistance of a pipe depends on the axial stress, and ii) the API
design factor. Table 8.8 shows a typical API design factor.
460 Fundamentals of Sustainable Drilling Engineering
Table 8.7 Commonly used bit sizes that will pass through API casing (Burgoyne et al., 1986)
Casing Size
(O.D., in.)
4½
5
5½
6⅝
7
7⅝
8⅝
Weight per Foot
(IBM/t)
9.5
10.5
11.6
13.5
11.5
13.0
15.0
18.0
13.0
14.0
15.5
17.0
20.0
23.0
17.0
20.0
24.0
28.0
32.0
17.00
20.00
23.00
26.00
29.00
32.00
35.00
38.00
20.00
24.00
26.40
29.70
33.70
39.00
24.00
28.00
32.00
36.00
40.00
44.00
49.00
Internal
Diameter (in.)
4.09
4.052
4.000
3.920
4.560
4.494
4.408
4.276
5.044
5.012
4.950
4.892
4.778
4.670
6.135
6.049
5.921
5.791
5.675
6.538
6.456
6.366
6.276
6.184
6.094
6.006
5.920
7.125
7.025
6.969
6.875
6.765
6.625
8.097
8.017
7.921
7.825
7.725
7.625
7.511
Drit
Diameter (in.)
3.965
3.927
3.875
3.795
4.435
4.369
4.283
4.151
4.919
4.887
4.825
4.764
4.653
4.545
6.010
5.924
5.796
5.666
5.550
6.413
6.331
6.241
6.151
6.059
5.969
5.879
5.795
7.000
6.900
6.844
6.750
6.640
6.500
7.972
7.892
7.796
7.700
7.600
7.500
7.386
Commonly Used
Bit Sizes (in.)
3⅞
3¾
4¼
3⅞
4¾
4⅝
4¼
6
5⅝
4¾
6¼
6⅛
6
5⅝
6⅜
6½
7⅞
6¾
Casing Design 461
Table 8.7 Commonly used bit sizes that will pass through API casing (Burgoyne et al., 1986)
Casing Size
(O.D., in.)
9⅝
10¾
11¾
13⅜
16
18⅝
20
Weight per Foot
(IBM/t)
29.30
32.30
36.00
40.00
43.50
47.00
53.50
32.75
40.50
45.50
51.00
55.00
60.70
65.37
38.00
42.00
47.00
54.00
60.00
48.00
54.50
61.00
68.00
72.00
55.00
65.00
75.00
84.00
109.00
87.50
94.00
Internal
Diameter (in.)
9.063
9.001
8.921
8.835
8.755
8.681
8.535
10.192
10.050
9.950
9.850
9.760
9.660
9.560
11.154
11.084
11.000
10.880
10.772
12.715
12.615
12.515
12.415
12.347
15.375
15.250
15.125
15.010
14.688
17.755
19.124
Drit
Diameter (in.)
8.907
8.845
8.765
8.679
8.599
8.525
8.379
10.036
9.894
9.794
9.694
9.604
9.504
9.404
10.994
10.928
10.844
10.724
10.616
12.599
12.459
12.359
12.259
12.191
15.188
15.062
14.939
14.822
14.500
17.567
18.936
Commonly Used
Bit Sizes (in.)
8¾, 8½
8⅝, 8½
8½
7⅞
9⅞
9⅝
8¾, 8½
8¾, 8½
11
10⅝
12¼
11
15
14¾
17½
17½
Burst pressure: it develops when internal pressure is higher than that of external
pressure. It can be rated as
pb
Internal pressure External pressure
(8.2)
Yield strength: the yield strength or yield point of a material is deined in engineering and materials science as the stress at which a material begins to deform plastically.
462 Fundamentals of Sustainable Drilling Engineering
Table 8.8 Typical API design factors
Required
Forces
Design factor
Design
10,000 psi
Collapse
1.125
11,250 psi
100,000 lbf
Tension
1.8
180,000 lbf
10,000 psi
Burst
1.1
11,000 psi
Prior to the yield point the material will deform elastically and will return to its original
shape when the applied stress is removed. Once the yield point is passed, some fraction
of the deformation will be permanent and non-reversible.
Tensile strength: Tensile strength is a measure of the ability of material to resist a force
that tends to pull it apart. It is expressed as the minimum tensile stress (force per unit
area) needed to split the material apart. It is also called ultimate tensile strength (UTS),
or ultimate strength.
Compressive strength: Compressive strength is the resistance of a material to breaking
under compression. It can be measured by plotting applied force against deformation in a
testing machine. Compressive strength is oten measured on a universal testing machine.
4. Calculation of Magnitude of Properties: he casing string must be designed to
stand up to the expected conditions in burst, collapse and tension. For collapse it is
considered that hydrostatic pressure increases with depth. For burst, assume full reservoir pressure all along the wellbore. In tension, the tensile stress due to weight of
string is highest at top. In addition, casing design is done based on the worst possible
conditions. he worst possible cases are i) For collapse design, assume that the casing is
empty on the inside (Pinside = 0 psig), ii) For burst design, assume no “backup” luid on
the outside of the casing (Poutside = 0 psig), iii) For tension design, assume no buoyancy
efect, and iv) For collapse design, assume no buoyancy efect. he above conditions are
quite conservative. hey are also simpliied for easier understanding of the basic concepts. During the calculation of the magnitude of properties, the above considerations
should be taken care. hese calculations are discussed in the next section.
8.8.3.2 Design Properties and Procedure
he design of the casing is based on the i) collapse strength (radial load), ii) burst
strength (radial load), iii) yield strength–tensile and compressive, iv) biaxial and triaxial loading, and v) efect of bending.
i) Collapse Strength
Collapse strength is one of the most important considerations while designing casing
string. he following assumptions are made during the design of collapse.
1) he most severe lost circulation problem ater cementing and continuing
to drill the next section
2) he most severe collapse loading anticipated when the casing is run
3) For both cases, the maximum possible external pressure results from the
drilling luid in the hole when the casing is placed and cemented
4) he beneicial efect of cement is ignored
Casing Design 463
5) he detrimental efect of axial tension on collapse pressure rating is
considered
6) he beneicial efect of pressure inside the casing can also be taken into
account
7) A safety factor is applied (1.1)
he collapse of a steel pipe tube from external pressure is very complex phenomenon
and much more diicult to calculate than bursting of pipe from internal pressure. he
reason for this is that collapse is an instability type of failure in many cases and is sensitive to many factors such as ovality, the ratio of tube diameter to wall thickness, yield
strength, type of steel heat treatment, and localized wall reduction. here is no simple
method of calculating the collapse of a tube because collapse strength continues to be
proposed and studied (Tamano et al., 1983; Issa and Crawford, 1993; Ju et al., 1998).
Formulas for calculating collapse-performance properties were irst introduced in the
late 1960s by API. here are four collapse pressure formulas proposed by API as shown
in Figure 18.1. hese four collapse pressure formulas are i) yield strength collapse, ii)
plastic collapse, iii) transition collapse, and iv) elastic collapse. Figure 8.20 shows the
variation of collapse resistance with dn/t for the above four collapse.
Five factors (F1, F2, F3, F4, and F5) are used with the tube’s dn/t ratio to determine
which of the four collapse-pressure formulas is applied. he factors are dependent on
the yield strength of the tube. hey are deined by the following equations:
F1
c0 c1
F2
F3
F4
c6 c7
c2
2
yield
c 4 c5
yield
c8
2
yield
yield
yield
3 RF
2 RF
c10
yield
3 RF
2 RF
F5
Here
c0 = 2.8762
c2 = 2.1302 10 11
c4 = 0.026233
c6 = –465.93
c8 = –1.0483 10 8
c10 = 46.95
106
c1 = 1.0679
c3 = –5.3132
c5 = 5.0609
c7 = 3.0867
c9 = 3.6989
F2
RF
F1
RF
F4 RF
10 6
10 17
10 7
10 2
10 14
c3
3
yield
(8.3)
(8.4)
c9
3
yield
(8.5)
3
1
3 RF
2 RF
2
(8.6)
(8.7)
464 Fundamentals of Sustainable Drilling Engineering
25,000
Plastic
Elastic
7 in. P-110 casing
Yield
15,000
Plastic
API Collapse Resistance, psi
20,000
10,000
5,000
Transition
Yield
Transition
Elastic
0
5
10
15
20
25
30
35
dn/t
Figure 8.20 Collapse modes.
he dn/t ranges where the four collapse-pressure equations applicable are separated by
three changeover points, which are dependent on casing grade and the values of the factors. he equations used to determine these three changeover points are discussed below.
Yield-Strength Collapse Pressure Formula: he yield-strength collapse-pressure
formula calculates the external pressure that generates the minimum yield stress on
the inside wall of a tube and can be derived theoretically using the Lamé equation. He
formulated this equation for the thickest-walled tubulars used in oil wells. he equation
can be written as:
2
Pcr
dn
1
t
yield
(8.8)
2
dn
t
dn
d
values up to the value of the n ratio where the
t
t
dn
ratio for this changeover point can
plastic collapse formula becomes applicable. he
t
his equation is applicable for
be calculated as:
F1 2
dn
t
2
8 F2
F3
F1 2
yield
2 F2
F3
yield
(8.9)
Casing Design 465
Here
dn = nominal OD of pipe, in
t
= thickness, in
Pcr = collapse pressure rating, psi
= the minimum yield stress, psi
yield
Plastic-Collapse Pressure Formula: the equation is based on 2,488 physicalcollapse tests of K-55, N-80, and P-110 casings (API TR 5C3 2800). Statistical
methods were used to analyze the results of the physical tests, and a plastic-collapse
formula was developed to calculate a collapse value with a 95% probability that the
actual collapse pressure will exceed the minimum stated with no more than a 0.5%
failure rate:
Pcr
he
yield
F1
F
dn 2
t
F3
(8.10)
dn
ratio where the changeover from the plastic collapse formula to the transit
tion formula can be calculated as:
dn
t
2
F2
F1
3 F2
F1
(8.11)
Transition-Collapse Pressure Formula: the transition-collapse formula was developed to provide a transition from the plastic-collapse formula to the elastic-collapse
formula:
Pcr
he
F4
dn
t
yield
F5
(8.12)
dn
ratio where the changeover from the transition collapse formula to the
t
elastic-collapse equation can be calculated as:
dn
t
yield
F3
F1 F4
yield
F2 F5
(8.13)
466 Fundamentals of Sustainable Drilling Engineering
Elastic-Collapse Pressure Formula: this equation was theoretically derived and was
found to be an adequate upper bound for collapse pressures as determined by testing.
API adopted this equation in 1968.
Pcr
46.95 106
dn
t
dn
1
t
(8.14)
2
Collapse Resistance of Casing with Combined Loading Formula: API ofers an
equation to calculate the external pressure equivalent when both external and internal
pressures are applied to a tubular:
Peq
Pe
2
dn
t
1
(8.15)
Pi
Here
Peq = external pressure equivalent in collapse due to external and internal pressure
Pe = external pressure, and Pi = Internal pressure
Collapse Pressure with Axial Stress: the current API formula accounts for the combined inluence of tension and collapse loading on a casing by modifying the minimum
yield strength to the yield strength of an axial-stress-equivalent grade. he equivalent
yield-strength formula is:
2
pa
1 0.75
a
yield
0.5
a
yield
(8.16)
yield
Here
pa
a
yield
= equivalent yield strength, psi
= total axial stress, not included bending due to hole deviation, doglegs, or
buckling
= minimum yield strength of pipe, psi
Example 8.3: Compute the API collapse-pressure rating for 20-in, K-55 casing with a
nominal wall thickness of 0.64 in. and a nominal weight per foot of 135 lbf/t.
Solution:
Given data:
dn = nominal diameter of the casing pipe = 20 in
t
= thickness of the casing pipe = 0.64 in
Wn = nominal weight per foot of the pipe = 135 lbf/t
Casing Design 467
Required data:
Pcr = Collapse pressure rating, psi
he
dn
ratio can be calculated as:
t
dn
= 20/0.64 = 31.25.
t
Now ind
dn
using Eq. (8.13)
t
dn
t
yield
F3
F1 F4
yield
F2 F5
Compare the two results. It is found that it falls in the range of transition collapse.
Compute F1–F5 using the following Equations.
F1
c0 c1
yield
F2
c 4 c5
yield
F3
c6 c7
yield
F4
Here
c0 = 2.8762
c2 = 2.1302 10 11
c4 = 0.026233
c6 = –465.93
c8 = –1.0483 10 8
c10 = 46.95
106
2
yield
c3
3
yield
c8
2
yield
c9
3
yield
3 RF
(2 RF )
c10
yield
F5
c2
3 RF
RF
(2 RF )
3
3RF
1
(2 RF )
2
F4 RF
c1 = 1.0679
c3 = –5.3132
c5 = 5.0609
c7 = 3.0867
c9 = 3.6989
F2
RF
F1
10 6
10 17
10 7
10 2
10 14
Eq. 18.5 is used to calculate collapse pressure rating.
Pcr
Pcr
yield
F4
dn
t
55,000
F5
1.989
0.036
31.25
1,520.64 psi
468 Fundamentals of Sustainable Drilling Engineering
ii) Burst Loading
Burst pressure is also called internal yield pressure for pipe. In general, the casing
experiences a net burst loading if the internal radial load exceeds the external radial
load (Figure 8.21). he burst load, ΔPb at any point along the casing can be calculated
using Eq. (8.2). In designing the casing to resist burst loading the pressure rating of the
wellhead and BOP stack should be considered since the casing is part of the well control system. he following assumptions need to be considered while designing burst
pressure.
Assumptions
1) Based on well-control condition assumed to occur while circulating out
a large kick
2) he burst design should ensure that formation fracture pressure should
be exceeded before the burst pressure of the casing is reached
3) he formation fracture pressure is used as a safety pressure release
mechanism.
4) he design pressure at the casing seat is equal to the fracture pressure
plus a safety margin.
5) he pressure inside the casing is calculated assuming that all of the drilling luid in the casing is lost to the fractured formation leaving only formation gas in the casing
6) he external pressure (backup pressure) outside the casing is assumed to
be equal to the normal formation pore pressure
7) A safety factor is assumed (1.1-1.2)
Barlow Model: API uses the Barlow model to determine the minimum internal
yield pressure for tubular (API TR 5C3). he Barlow equation, which is sometimes
called an “API” Burst is:
Pbr
f
2
yield
dn
t
(8.17)
Here
f = wall-thickness correction factor = 0.875 for standard API tubulars when a
12.5% wall- thickness tolerance is speciied.
Pbr = burst pressure rating, psi
Casing Design 469
API recommends the use of Eq. (8.17) with wall thickness rounded to the nearest
0.001 in and the results rounded to the nearest 10 psi.
According to Lame equations, the burst loading can be estimated as:
Pbr
dn2 dm2
yield
(8.18)
dn2 dm2
Here
dn = nominal OD of pipe, in
dm = maximum pipe body ID based on minimum speciic wall thickness, in
Example 8.4: Compute the burst requirement if the pore pressure is 6000 psi if the factor of safety is assumed as 1.1.
Solution:
Given data:
Pp = pore pressure = 6,000 psi
Required data:
Pbr = burst pressure in psi
he burst requirement based on the expected pore pressure can be calculated as:
Pbr
Pp SF
6,000 psi
1.1 6,600 psi
he whole casing string must be capable of withstanding this internal pressure without failing in burst.
Example 8.5: Compute the API burst resistance for 20-in, 133-lbf/t, K-55 casing with
a nominal wall thickness of 0.64 in. Use Barlow model.
Solution:
Given data:
dn = nominal OD of pipe = 20 in
= minimum yield strength of pipe (k-55) = 55,000 psi
yield
t
= nominal wall thickness of pipe = 0.64 in
Required data:
Pbr = burst pressure in psi
Pbr
f
2
yield
dn
t
0.875
2 55,000 psi 0.65 in
20 in
3,128.13 psi
iii) Yield Strength
Yield strength can be expressed as the ability of a metal to tolerate gradual progressive force without permanent deformation. It can be classiied as tensile loading (i.e.
470 Fundamentals of Sustainable Drilling Engineering
pressure) and compressive loading. Axial tension loading results primarily from the
weight of the casing string suspended below the joint of interest. Pipe body yield
strength is the tension force that causes the pipe body to exceed its elastic limit. API
deines the pipe body yield strength as the axial load in the tube, which results in the
stress being equal to the material’s minimum speciic yield strength (Figure 8.22). To
calculate the stress in the tube, the speciic or nominal OD and the ID are used for
API casing. For Tension design, assume no buoyancy efect and thus pipe-body tensile
strength can be expressed as:
Ften
yield
4
2
dno
dni2
(8.19)
Here
Ften = pipe-body tensile strength, psi
dno = nominal OD of pipe, in
dni = nominal ID of pipe, in
Equation (8.19) can be written in terms of cross-sectional area as
Ften
yield
As
(8.20)
2
dno
dni2 .
4
he efect of compressive forces need only be considered for surface casing, due
to the weight transferred from later casing strings. It is not usually a critical factor.
So, yield strength in compression is typically assumed to be the same as in tension.
However, when a casing is loaded in compression, axial buckling may occur, and the
casing may fail before reaching the pipe-body yield strength. Use Paslay and Cernocky
(1991) and Mitchell (2003) models.
where, As
Ften
dno
dnini
As
Figure 8.22 Pipe-body tensile stress.
Casing Design 471
Example 8.6: Compute the body-yield strength for 20-in., K-55 casing with a nominal
wall thickness of 0.64 in. and a nominal weight per foot of 133 lbf/t.
Solution:
Given data:
dn = nominal OD of pipe = 20 in
σyield = minimum yield strength of pipe (k-55) = 55,000 psi
t
= nominal wall thickness of pipe = 0.64 in
Wn = nominal weight of pipe = 133 lbf/t.
Required data:
Ften = body-yield strength in psi
his pipe has a minimum yield strength of 55,000 psi and an ID of (K55)
d
20.00 2 0.64
18.72 in
hus, the cross-sectional area of steel can be calculated using the sub-equation of
Eq. (8.20) as
As
4
202 18.722
38.93 in2
Now, Eq. 8.20 predicts a minimum pipe-body yield at an axial force of:
Ften
yield
As
55,000 38.93
2,140,907.43 lb f
iv) Biaxial and Triaxial Loading
It can be established both theoretically and experimentally that the axial load on a casing can afect the burst and collapse ratings of that casing which is shown in Figure
8.23. It noted that as the tensile load imposed on a tubular increases, the collapse rating
decreases and the burst rating increases. his igure also shows that as the compressive
loading increases the burst rating decreases and the collapse rating increases. he burst
and collapse ratings for casing quoted by the API assume that the casing is experiencing
zero axial load. However, since casing strings are very oten subjected to a combination
of tension and collapse loading simultaneously, the API has established a relationship
between these loadings. he casing will in reality experience a combination of three
loads (Triaxial loading). hese are Radial, Axial and Tangential loads (Figure 8.23). he
latter being a resultant of the other two. Triaxial loading and failure of the casing due
to the combination of these loads is very uncommon and therefore the computations
of the triaxial loads on the casing are not frequently conducted. In the case of casing
strings being run in extreme environment (>12,000 psi wells, high H2S) triaxial analysis
should be conducted.
he current API model accounts for the combined inluence of tension and collapse
loading on a casing by modifying the minimum yield strength to the yield strength of
472 Fundamentals of Sustainable Drilling Engineering
Axial Load
Tangential
(Hoop) Load
Radial Load
r
a
t
Figure 8.23 Tri-axial loading on casing.
an axial-stress-equivalent grade. he reduced equivalent yield strength is based on von
Mises theory. he equivalent yield-strength formula is give as:
Bouyant weight carried by weakest grade
a
d
4
2
0
(8.21)
2
i
d
2
pa
a
1 0.75
0.5
yield
a
yield
(8.22)
yield
Here:
σa = the axial stress due to tension, psi
σpa = the equivalent yield strength, psi
d0 = the outer casing diameter, in
di = the inner casing diameter, in
Biaxial efect is calculated using the following set of equations:
46.95 10
6
F
Ypa
3B / A
2 B/A
3B / A B
2 B/A A
G
F B
A
3
3B / A
1
2 B/A
2
(8.23)
Casing Design 473
where A, B, C, F and G are empirical constants
5
A 2.8762 0.10679 10
B 0.026233 0.50609 10
C
465.93 0.030867
pa
10
2
pa
2
pa
0.36989 10
0.21301 10
pa
0.53132 10
16
3
pa
6
pa
0.10483 10
7
13
3
pa
Example 8.7: Determine the collapse strength for a 5 1/2” O.D., 14.00 lbf/t, J-55 casing
under axial load of 100,000 lbf.
Solution:
Given data:
Fab = equivalent axial force, lbf = 100,000 lbf
do = the outer casing diameter = 5.5 in
di = the inner casing diameter = 5.012 in
= the minimum yield strength of the grade = 55,000 psi (Grade J-55)
yield
Required data:
= the equivalent yield strength, psi
pa
he axial tension will reduce the collapse pressure using Eq. (8.21) and Eq. (8.22) as:
Bouyant weight carried by weakest grade
a
4
do2 di2
100,000 lb f
2
4
5.5
24,820 psi
2
5.012 in
2
2
pa
1 0.75
a
0.5
yield
24,820
1 0.75
55,000
2
0.5
a
yield
yield
24,820
55,000
55,000 38,216 psi
Here the axial load decreased the J-55 rating to an equivalent “J-38.2” rating
v) Efect of Bending
In directional drilling, the efect of wellbore curvature and vertical deviation angle on
axial stress in the casing and coupling must be considered during the casing string
design. When a casing is forced to bend, the axial tension on the convex side of the
bend can increase signiicantly. In sections of the hole where there are severe dog-legs
474 Fundamentals of Sustainable Drilling Engineering
(sharp bends) the bending stresses should be checked. he most critical sections are
where dog-leg severity exceeds 10° per 100’. So, stress can be expressed as:
1
E dn K ds
2
b
(8.24)
Here
= bending stress
b
E = Young modulus of elasticity
dn = normal OD of pipe
Kds = dogleg severity
In oilield units where the dog-leg severity, Kds, is expressed as the change in angle in
degrees per 100 t. of borehole length, and the pipe is assumed to be steel, the simpliied
form of Eq. (8.24) can be written as:
218 dn K ds
b
(8.25)
In terms of an equivalent axial force, Fcr, Eq. (8.25) can be expressed as:
Fab
b
As
218 dn K ds As
(8.26)
he area of steel, As can be expressed as the weight per feet of pipe divided by the
density of steel. If we apply ield unit, Eq. (8.26) becomes as:
Fab
64 dn K dsWdp
(8.27)
Here
Fab = equivalent axial force, lbf
dn = normal OD of pipe, in
Kds = dogleg severity, degrees/100t
Wdp = weight per foot of drill pipe in air, lbf/t
When the axial tension strength (Fcr) divided by the cross-sectional area of the pipe
wall under last perfect thread is greater than the minimum yield strength, the joint
strength is given by:
5
Fcr
0.95 A jp
140 K ds dn
ult
(8.28)
0.8
ult
yield
Here
σult = ultimate strength, psi
Fcr
A jp
yield
, K ds is in degrees/100ft, and A jp
4
dn 0.1425
2
dn 2 t
2
Casing Design 475
When the axial tension strength divided by the cross-sectional area of the pipe wall
under last perfect thread is less than the minimum yield strength, the joint strength is
given by:
ult
0.95 A jp
Fcr
yield
218.15 K ds dn
yield
0.644
(8.29)
It was developed from the experimental tests conducted with 5.5˝, 17- lbf/t, K-55
casing with short round-thread coupling (STC)
Example 8.8: Determine the maximum axial stress for a 5 1/2˝ O.D., 14.00 lbf/t, J-55
casing under axial load of 100,000 lbf axial-tension load in a portion of a directional
wellbore having a dogleg severity of 4°/100ʹ. Compute the maximum axial stress assuming uniform contact between the casing and the borehole wall.
Solution:
Given data:
Fab = equivalent axial force, lbf = 100,000 lbf
dno = the nominal outer casing diameter = 5.5 in
dni = the nominal inner casing diameter = 5.012 in
= the minimum yield strength of the grade = 55,000 psi (Grade J-55)
yield
Required data:
= the maximum axial stress, psi
pa–max
he axial stress without bending can be calculated using Eq. (8.21):
100,000 lb f
Bouyant weight carried by weakest grade
a
2
no
d
4
2
ni
2
d
4
5.5
2
5.012 in
24,820 psi
2
he additional stress level on the convex side of the pipe caused by bending can be
computed using Eq. (8.25) as:
218 dn K ds
b
218 5.5 4
4,796 psi
So, the total maximum axial stress will be:
pa max
a
b
24,820 psi 4,796 psi
29,616 psi
vi) Torsion
For most casing strings, torque is seldom applied, and when it must be applied, it is
limited to the connection makeup torque Mt. he torsional shear stress acting in the
circumferential direction at a radius at some point in the pipe-body wall thickness is
Mt r
Jp
(8.30)
476 Fundamentals of Sustainable Drilling Engineering
t 4 dn
2
t
Jp
dn
t
1
2
1
1
(8.31)
Here
τ
= shear stress, psi
Mt = makeup torque,
= polar moment of inertia
Jp
If we include internal and external pressures, axial force, bending, and torsion, the
von Mises equivalent stress equation for torsion can be written as:
2
2
r
t
vm
t
a
b
2
a
2
b
r
6
2
(8.32)
Here
σvm = von Mises triaxial equivalent stress, psi
σa = total axial stress, not including bending due to hole deviation, doglegs, or
buckling, psi
σb = bending stress, psi
σr = radial stress, psi
σt = tangential stress, psi
8.8.3.3 Design Procedure
he inal casing design procedure can be shown at a glance in Figure 8.24 where the
steps of casing design process are explained. he casing design process involves three
distinct operations: i) the selection of the casing sizes and setting depths, ii) the deinition of the operational scenarios which will result in burst, collapse and axial loads
being applied to the casing; and inally iii) the calculation of the magnitude of these
loads and selection of an appropriate weight and grade of the casing.
8.8.3.4
Safety Factor
The uncertainty associated with the conditions used in the calculation of the external, internal, compressive and tensile loads described above is accommodated by
increasing the burst collapse and axial loads by a design factor (Table 8.8). These
factors are applied to increase the actual loading figures to obtain the design loadings. Design factors are determined largely through experience, and are influenced
by the consequences of a casing failure. The degree of uncertainty must also be
considered (i.e. an exploration well may require higher design factors than a development well). Table 8.9 shows the ranges of factors that are commonly used in
addition to Table 8.8.
Casing Design 477
Design Casing Coniguration
Select casing setting depth
Formation, strength, pore pressure,
mud weights, geological
considerations, directional wellplan,
drilling luid selection etc.
Deine load cases for each string
Select casing sizes
Calculation of Internal/External,
and axial loads on each string
Well objectives, logging tools,
testing equipment, production
equipment contingency
Calculation of net collapse,
and burst loads
Select casing weight and grade
Calculation of net axial loads
API ratings of casing
and design factors
Derate collapse rating of
casing based on axial loads
Conirm casing selection
Figure 8.24 Casing design process (Ford, 2005).
Table 8.9 Ranges of typical API design factors
Forces
Ranges of design factor
Collapse
1.0–1.125
Tension
1.0–2.0
Burst
1.0–1.33
Triaxial
1.25
8.9 Current Development in Casing Technology
With the evolution of casing drilling technology, the need to re-look into the casing
design has become one of the essential issues; especially when we consider the deep
wells with abnormal conditions. Also exploring in a high sour gas environments leads
to improve bodies of the casing from H2S and CO2 attacks. In this part, the recent developments in the casing manufacturing are discussed.
478 Fundamentals of Sustainable Drilling Engineering
8.9.1 Casing Material Development to Protect the Corrosion
104
103
DSS
22Cr-5Ni-3Mo
CW 2205
15Cr-60Ni-16Mo
21Cr-61Ni-9Mo
25Cr-50Ni-6Mo
Quench
Annealed
27Cr-31Ni-3.5Mo
22Cr-42Ni-3Mo
13Cr
2
10
10
20Cr-25Ni-4Mo
%Cr
API L-80
C-75-2
SS85
SS90
d
API J-55
N-80
an
10–1
M
o
1
Ni
Partial Pressure of CO2, psia
Sour gases such as H2S and CO2 have greater impact on the life of the well. hey
mainly attack the steel of the tubulars, and eventually corrosion will occur to their
bodies. Tubular manufacturers continued to igure out this issue and ind the permanent solution for it. Unfortunately, the situation cannot be generalized for all
environments. Based on this challenging scenario, researchers started to look for
each case separately.
In the industry, there has been a trend towards the development of increasing
severe oil and gas production environments in terms of pressure, temperature, and
aggressive luids. his trend is expected to continue into the future. Such severe conditions necessitate the use of Corrosion Resistant Alloys (CRA’s). At present, materials speciications for CRA’s are based on a combination of standard tests (e.g., NACE
TM-01-77), it for purpose testing, and experience. Figure 8.25 shows an example of
empirically estimated boundaries of CRA performance based on the partial pressures
of the H2S & CO2.
Production casing and liners are exposed to the produced luids, and in the event
of any connection or packer leak, the upper strings of the casings or tie back strings
could also be exposed for a long period of time to the sour faces. hese strings must
therefore be resistant to Sulide Stress Cracking (SSC) and Stress Corrosion Cracking
(SCC). he liners below the packers are exposed to the produced luids, which raise
the possibility of the corrosion of steel grades such as Q-125 and SS-110 liners. To
counter this, manufacturers start to think if CRAs can be considered in the selection because SCC is a potential problem for certain grades. Severe SSC is addressed
well by using the grades T-95 or SS-110, which have reasonable resistance to SSC.
In deep wells, it is standard that you must have competent production liners in
order to maintain the well integrity for the life of the well. For example, the Kuwait
Oil Company (KOC) led the initiative to start using CRAs in their deep wells. he
%
10–2
10–3
10–2
10–1
1
10
102
103
104
Partial Pressure of H2S, psia
Figure 8.25 Empirically Estimated Boundaries of CRA Performance (Al-Saeedi et. al., 2013).
Casing Design 479
following factors were considered when selecting the material for production casings
and liners (Al-Saeedi et. al., 2013):
• he sour severity with respect to SSC was evaluated reference to new
NACE MR-0175/ISO 15156 severity diagram (Figure 8.26), with all operating conditions being in the most severe area for sour service. he Major
Manufacturer Material Selection Guide is also shown in Figure 8.27.
• he use of C-110 grade is recommended in sour conditions for only
intermediate casing because it cannot be considered fully sour grade over
the whole range of pH and H2S partial pressure.
• T-95 propriety grade is fully resistant to any sour conditions.
• Presence of oxygen may have a dramatic corrosion impact on carbon
steel equipment in presence of wet luid.
• he use of oil-based mud instead of water-based mud strongly minimizes
the SSC likelihood for intermediate casing, because of no or low water
wetting combined with a limited duration of exposure to a wet sour luid.
he CRA grade selected was a 28% Chrome high-alloy austenitic stainless, equivalent strength 125 Ksi, suitable for highly corrosive oil and gas environments. his proprietary grade is characterized by:
• Very good corrosion resistance in H2S, CO2, and chloride-containing
environments
• Very good resistance to pitting owing to its high Pitting Resistance
Equivalent (PRE) value of 38 minimum
• General corrosion comparable to or better than Alloy 825
• Tensile strength equivalent to ASTM 316
• Very good performance in elevated temperature (geothermal wells)
• Entirely non-magnetic properties
0.05psi, 0.3kPa
Historical sweet/sour demarcation
6.5
1
5.5
pH
0
2
4.5
3
3.5
2.5
0.1
1
10
100
1000
H2S Partial Pressure, kPa
Figure 8.26 NACE MR 0175/ISO 15156 Sour Service Deinition Diagram (Al-Saeedi et. al., 2013).
480 Fundamentals of Sustainable Drilling Engineering
> 0.1 bar
H2S
> 0.2 bar
232 C
SMC276 (15%Mo)
204 C
SM2050 (11%Mo)
177 C
SM2550 (6%Mo)
149 C
SM2535 (3%Mo)
SM2242 (3%Mo)
250 C
SM25CRW
SM25CR
200 C
SM22CR
200 C
SM17CRS
180 C
SM13CRS
180 C
SM13CRM
150 C
SM13CR
0.1 bar
0.03 bar
CO2
Nickel Alloy
Duplex Stainless
Steel
MartenslticFerritic Stainless
Steel
MartenslticStainless Steel
0.003 bar
0.2 bar
Sour Service
> 0.003 bar
Sour Service &
High Collapse
H2S
High Collapse
High Strength
0.003 bar
Sour Service
Carbon Steel
Non Sour
Carbon Steel
Arctic
Figure 8.27 Major Manufacturer Material Selection Guide (Al-Saeid et. al., 2013).
KOC has run the irst 5˝, 21.4 ppf, 28% Chrome Alloy, 125 Ksi, CRA with premium
connection as production in well SA-437. he well was a deviated well with inal angle
of 40 degrees. he liner was run at the well TD of 16,504 t, and had a length of 1,740 t,
with TOL at 14,764 t.
Based on the KOC experience, recommendations are listed below:
• Use T-95 and C-110 high quality sour service grades, which provide
more than suicient SSC resistance for both the deep oil and gas wells.
• For the cemented production liners, the selection of CRA was recommended in order to ensure the long-term mechanical integrity.
• he selection between carbon steel and CRA for the irst string of production tubing was dependent on the expected timing of irst production
of reservoir water.
• Success of well SA-437 encouraged the KOC to extensively use the CRA
in all North Kuwait Jurassic wells with high percentages of H2S and CO2.
8.9.2 Development in Casing Connectio