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____________________________________
Drilling Manager
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COMPLETION
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TABLE OF CONTENTS
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Registration Certificate
Revision Record
Table of Contents
WELL COMPLETIONS
1
2
OVERVIEW OF THE MANUAL
1.1
Purpose
1.2
Scope
1.3
Completion Manual Structure
1.4
Terminology
1.5
Manual Control
1.6
Revision
TYPES OF WELL COMPLETIONS
2.1
Introduction
2.2
Well Configuration
2.3
Open-hole
2.4
Cased-hole
2.5
Single Completions
2.6
Multiple Completions
2.7
Monobore Completions
2.8
Selecting a Completion Type
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COMPLETION DESIGN
3
4
COMPLETION DESIGN CRITERIA
3.1
Introduction
3.2
Basic Decisions in Completion Design
3.3
Factors Affecting Completion Design
3.4
Completion Design Procedure
PRIMARY CEMENTING
4.1
Introduction
4.2
Cement Fundamentals
4.3
Cement Properties
4.4
Factors Affecting Job Design
4.5
Example : Selection of API Cementing Schedule
4.6
Cement Slurry Design
4.7
Example : Density and Yield of 8% Bentonite Slurry
4.8
Cementing Equipment
4.9
Planning A Primary Cement Job
4.10
Primary Cementing Operations
4.11
Annular Fluid Migration
4.12
Special Primary Cementing Considerations
4.13
References
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5
6
WELLHEADS
5.1
Wellhead System
5.2
Christmas Trees
5.3
Suspension Methods
5.4
Special Wellhead Equipment
5.5
Flanges and Seal Connections
5.6
Wellhead Design Considerations
5.7
Equipment Specifications
5.8
Splitter Wellhead Technology
TUBULARS
6.1
Introduction
6.2
Tubular Nomenclature
6.3
Tubular String Components
6.4
Corrosive Wellbore Fluids
6.5
Tubular Materials
6.6
Tubular Performance Properties
6.7
Tubular Connections
6.8
Connection Manufacturers
6.9
Connection Makeup
6.10
Production Tubing String Design Criteria
6.11
Tubing Size Selection
6.12
Tubing Load Analysis
6.13
Tubing Movement Analysis
6.14
Tubing Stability Analysis
6.15
Operational Considerations
6.16
References
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7
8
9
PACKERS
7.1
Introduction
7.2
Packer Fundamentals
7.3
Permanent Packers
7.4
Hook-Wall Retrievable Packers
7.5
Special Packers
7.6
Packer Selection
7.7
Summary
SURFACE AND SUBSURFACE SAFETY VALVES
8.1
Introduction
8.2
Subsurface-Controlled Valves
8.3
Surface-Controlled Valves
8.4
Surface Safety Valves
8.5
Safety Valve Selection
COMPLETION FLUIDS
9.1
Introduction
9.2
Fluid Properties
9.3
Water-Base Fluids
9.4
Clear Brines
9.5
Example-Brine Composition
9.6
Weighted Brines
9.7
Water-Base Mud
9.8
Hydrocarbons
9.9
Oil-Base Mud
9.10
Nitrogen
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COMPLETION FLUIDS (CONT’D)
9.11
Foam
9.12
Circulating Fluids
9.13
Packer Fluids
9.14
Perforating Fluids
9.15
Field Handling Of Fluids
Appendix A - Brine Data
Appendix B - Hydrocarbon Data
10 PERFORATING
10.1
Introduction
10.2
Shaped Charge Fundamentals
10.3
Gun Design and Testing
10.4
Casing Deformation/Damage
10.5
Perforation Productivity
10.6
Retrievable Hollow-Carrier Guns
10.7
Expendable Guns
10.8
Tubing Conveyed Guns
10.9
Perforation Design
10.10
Perforating Operations
10.11
Specialized Equipment and Operations
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11 SAND CONTROL
11.1
Introduction
11.2
Sand Control Methods
11.3
Mechanical Sand Control
11.4
Gravel Pack Design
11.5
Gravel Pack Productivity
11.6
Gravel Pack Well Preparation
11.7
Gravel Placement-Prepacking
11.8
Gravel Placement
11.9
Plastic Consolidation Principles
11.10
Plastic Consolidation Chemicals
11.11
Well Preparation For Plastic Consolidation
11.12
Plastic Placement
11.13
Commercial Plastic Consolidation Systems
11.14
Resin-Coated Sand
11.15
Selecting A Sand Control Method
11.16
Well Bean-up Procedure
STIMULATION
12 FORMATION DAMAGE
12.1
Introduction
12.2
Effect Of Damage
12.3
Indicators Of Damage
12.4
Causes Of Formation Damage
12.5
Damage Removal
12.6
Damage Prevention
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13 SOLVENT AND SURFACTANT TREATMENTS
13.1
Introduction
13.2
Solvents
13.3
Surfactants
13.4
Paraffin Deposition
13.5
Asphaltene Deposition
13.6
Emulsions
13.7
Relative Permeability Effects
13.8
Organic Damage Removal
14 MATRIX ACIDIZING OF CARBONATES
14.1
Introduction
14.2
Carbonate Minerals
14.3
Dissolving Carbonates
14.4
Acid Attack Of Carbonates
14.5
Acids Used To Dissolve Carbonates
14.6
Acid Additives
14.7
Treatment Design
14.8
Treatment Implementation
14.9
References
15 SANDSTONE ACIDIZING
15.1
Introduction
15.2
Sandstone Composition
15.3
Reaction Chemistry
15.4
Mechanism Of Acid Attack
15.5
Treatment Design
15.6
Field Implementation
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16 SCALE TREATMENTS
16.12
Introduction
16.2
Location Of Scale Deposits
16.3
Carbonate Scale
16.4
Sulfate Scales
16.5
Iron Scales
16.6
Silicon Base Scales
16.7
Salt Scale
16.8
Scale Diagnosis
16.9
Treatment Design And Implementation
16.10
Scale Inhibition
16.11
References
17 FRACTURING
17.1
Introduction
17.2
Benefits From Hydraulic Fracture Stimulation
17.3
Essence Of The Hydraulic Fracturing Process
17.4
Productivity Increases From Fractures
17.5
Fundamental Rock Mechanics
17.6
Fundamentals Fluid/Proppant Mechanics
17.7
Proppant Fracture Design
17.8
Acid Fracture Design
17.9
Field Implementation
17.10
Field Diagnostics
17.11
Reference Material
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18 DIVERSION
18.1
Introduction
18.2
Mechanical/Hydraulic Diverting Techniques
18.3
Particulate Diverting Agents
18.4
Viscous Fluid Diverting Agents
18.5
Perforation Ball Sealers
18.6
Ball Sealer Treatment Design
18.7
Perforation Ball Sealers - Field Results
18.8
Treatment Evaluation
18.9
Appendix A : Limited Entry Design
18.10
Appendix B : Rising Or Settling Velocities Of Ball Sealers
WORKOVERS
19 WORKOVER PLANNING
19.1
Introduction
19.2
Well Problems Requiring Workovers
19.3
Well Assessment - Determining The Problem
19.4
Alternative Operations And Techniques
19.5
Evaluating And Selecting A Technique
19.6
Job Execution And Follow-Up
19.7
Well Analysis Checklist
19.8
References
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20 PRODUCTION LOGGING
20.1
Introduction
20.2
Temperature Logs
20.3
Pressure Measurement Logs
20.4
Sonic Logs
20.5
Electrical Logs
20.6
Magnetic Logs
20.7
Nuclear Production Logs
20.8
Spinner Flowmeters
20.9
Mechanical Survey Logs
20.10
Running Production Logs
20.11
Cement Evaluation
20.12
Flow Distribution Inside Casing
20.13
Production From Unperforated Zones
20.14
Evaluating Stimulation Treatments
20.15
Tubular Or Equipment Evaluation
20.16
Reservoir Monitoring
21 REMEDIAL CEMENTING
21.1
Introduction
21.2
Wellbore Fluids
21.3
Bottom-Hole Temperature
21.4
Bottom-Hole Pressure
21.5
Example : Determination Of Fracture Pressure
21.6
Example : BHP During Cementing Operations
21.7
Formation Type
21.8
Bullhead Technique
21.9
Cement Plugs
21.10
Bradenhead Technique
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REMEDIAL CEMENTING (CONT’D)
21.11
Retrievable Packer Technique
21.12
Drillable Packer Technique
21.13
Circulation Technique
21.14
Job Objective
21.15
On-Site Operations
21.16
Example : Calculation Of Balanced Plug
21.17
Job Design Guidelines
21.18
References
22 WIRELINE OPERATIONS
22.1
Introduction
22.2
Wireline Surface Equipment
22.3
Types Of Wirelines
22.4
Wireline Tool String
22.5
Landing Nipples
22.6
Removable Locking Devices
22.7
Communication Equipment
22.8
Production Control Equipment
22.9
Wireline Pulling/Releasing Tools
22.10
Field Procedures
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23 RIG WORKOVER OPERATIONS
23.1
Introduction
23.2
Well Killing And Well Control
23.3
Conventional Workovers
23.4
Concentric Workovers
23.5
Coiled Tubing Workovers
23.6
Snubbing Unit Workovers
23.7
Fishing Operations
23.8
Workover Rig Selection
APPENDIX A
24 GLOSSARY OF TERMS FOR COMPLETION AND WORKOVER OPERATIONS
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CHAPTER 1
OVERVIEW
TABLE OF CONTENTS
1.1
PURPOSE...................................................................................................................... 3
1.2
SCOPE ........................................................................................................................... 3
1.3
COMPLETION MANUAL STRUCTURE ................................................................... 4
1.4
TERMINOLOGY .......................................................................................................... 4
1.5
MANUAL CONTROL .................................................................................................. 5
1.6
REVISION ..................................................................................................................... 5
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OVERVIEW
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PURPOSE
The number of possible completion configurations for oil and gas wells is infinite.
The objective of this manual is to provide a single source of information containing
a collation of significant items on subjects related to well completions and its role in
the overall well project. The information contained was derived from internal
procedures and reports, SPE, JPT, and other industry publications. Information was
also provided by the service companies involved. The purpose of this PCSB
Completion Manual is to ensure that wells are completed in the most efficient, safe
and cost effective manner to achieve each wells optimum production capability.
The aim of this manual is to provide a clear, up to date text covering the principles
of well completions. Because of this, it is necessary to start from first principles in
order to give both trainee and practicing engineer a comprehensive understanding of
the subject. Hence, no prior knowledge of any topic is assumed, and all necessary
equations and calculations required in completion design are presented.
Today, the completion engineer must be an expert in the traditional aspects of well
completion, he must also be familiar with computing, accountancy, risk analysis,
metallurgy, chemistry, and so on-the list is almost endless.
The purpose of this manual is to provide engineers with information that relates to
their job performance. The text are designed to chronologically follow the
development, completion, and maintenance of a well.
1.2
SCOPE
The contents of this manual shall be applied by PCSB personnel working anywhere
in the world. The purpose of this manual is to provide engineers with a working
knowledge of current state-of-the-art technology in matters critical to successful well
completions and workovers. Engineers should find the material in these pages to be
helpful throughout their daily operations.
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OVERVIEW
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COMPLETION MANUAL STRUCTURE
This manual is intended as a reference document for production technology,
production and drilling operations.
The Completion Manual is divided into five main sections:
1)
Well Completions
2)
Completion Design
3)
Stimulations
4)
Workovers
5)
Appendix
Each chapter of the manual was written as more or less a stand alone document
which can be directly accessed if required. The section entitled Well Completions
begins with details of several completion techniques and the considerations involved
in selecting an interval for completion. A discussion of casing and tubular goods
follows which includes information of various types and grades of pipe, plus their
connections, makeup, performance, and design.
The completion process of cementing is outlined next. Primary cementing
operations, together with compositions of oil-well cements, are also examined.
Next follows a discussion of subsurface completion equipment. Packers as well as
other types of tools are discussed. Completion and workover fluids are then
analyzed. The section ends with a review of perforating techniques
A complete list of contents is provided at the beginning of each chapter to aid the
reader to locate specific subjects of interest.
1.4
TERMINOLOGY
Throughout the manual abbreviations and/or terms used are defined within the
subject text, beyond that, please refer to the Appendix.
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MANUAL CONTROL
Controlled copies of the manual shall be distributed to the manual holders listed on
the control page. The manual owner is also responsible for the distribution and
registration of any uncontrolled copies. All Drilling personnel must be familiar with
the contents of this manual. They must apply the contents and ensure that other
stake-holders understand their responsibilities.
1.6
REVISION
It is the intention to update the Completion Manual whenever the need arises. The
Custodian of the manual is DDR. Corrections and comments will be welcome and
should be directed to the Custodian.
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CHAPTER 2
TYPES OF WELL COMPLETION
TABLE OF CONTENTS
2.1 INTRODUCTION ……………………………………………………………….……... 4
2.1.1
2.1.2
2.1.3
2.1.4
2.1.5
Chapter Objective …………………………………………………………..
Definition of Completion …………………………………………………..
Objective of Completion …………………………………………………...
PCSB Completion Strategy ........................................................................
Fluid Flow Considerations …………………………………………………
4
4
5
5
6
2.2 WELL CONFIGURATION …………………………………………………….....…… 8
2.2.1
2.2.2
2.2.3
2.2.4
2.2.5
2.2.6
2.2.7
Wellhead …………………………………………………………………… 8
Conductor Pipe …………………………………………………………….. 9
Surface Casing …………………………………………………….……….. 9
Intermediate Casing ……………………………………………….……….. 10
Production Casing …………………………………………………………. 10
Liners …………………………………………………………………….… 10
Tubing ……………………………………………………………………… 10
2.3 OPEN-HOLE COMPLETIONS ………………………….…………………………… 11
2.3.1
2.3.2
2.3.3
2.3.4
2.3.5
Definition …………………………………………………………………... 11
Advantages ………………………………………………………………… 11
Disadvantages ……………………………………………………………… 12
Methods ………………………………………………………………….… 13
Examples …………………………………………………………………... 13
2.4 CASED-HOLE COMPLETIONS ……………………………………………………. 14
2.4.1
2.4.2
2.4.3
2.4.4
Definition …………………………………………………………………... 14
Advantages ……………………………………………………………….... 14
Disadvantages ……………………………………………………………… 15
Examples …………………………………………………………………... 16
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2.5 SINGLE COMPLETIONS ………………………….……………………………...… 17
2.5.1
2.5.2
2.5.3
2.5.4
Definitions ………………………………………………………………..... 17
Tubing Without Packer ………….....……………………………………… 17
Tubing With Packer ………………….....…………………………………. 17
Tubingless …………………………………………………………………. 18
2.6 MULTIPLE COMPLETIONS …………………………………………….……...….. 20
2.6.1
2.6.2
2.6.3
2.6.4
2.6.5
2.6.6
Definition …………………………………………………………………... 20
Reasons For Use …………………………………………………………… 20
Single String, Single Packer ……………………………………………….. 21
Single String, Multiple Packer …………………………………………….. 22
Multiple String, Multiple Packer …………………………………………... 24
Multiple Tubingless ………………………………………………………... 27
2.7 HORIZONTAL AND MULTILATERAL WELLS ........................................................ 28
2.7.1
2.7.2
2.7.3
Horizontal Wells …....……………………………………………………... 28
Multilateral Wells ........……………………….........……………………… 30
Multilateral Well Classification Matrix ........…………………………….... 31
2.8 MONOBORE COMPLETIONS ................................................................................. 28
2.8.1
2.8.2
2.8.3
2.8.4
2.8.5
2.8.6
Definition …………………………………………………………………... 28
Introduction ..………………………………….........……………………… 30
Monobore Completion ..………………..........…………………………….. 31
Advantages ..……...............................…………………………………….. 31
Disadvantages .……………………………………..............................…... 32
Examples .…………………………………………………….................... 33
2.9 SPLITTER WELLS ..................................................................................................... 34
2.10 SUBSEA COMPLETIONS …....................……………………………………...…… 38
2.11 SMART WELLS ........................................................................................................ 40
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2.11.1
2.11.2
2.11.3
2.11.4
2.11.5
2.11.6
TYPES OF WELL COMPLETION
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Introduction ...............................................................................................
System Components ..................................................................................
Telemetry ..................................................................................................
Downhole Sensors .....................................................................................
Controls .....................................................................................................
Reservoir Management with Smart Wells ..................................................
40
40
40
42
42
43
2.12 SELECTING A COMPLETION TYPE ………………………………………...…… 45
2.12.1
2.12.2
2.12.3
2.12.4
2.12.5
2.12.6
2.12.7
2.12.8
Reservoir Drive Mechanism ……………………………………………….. 45
Reservoir Extent …………………………………………………………… 45
Number Of Reservoirs ……………………………………………………... 45
Well Location ……………………………………………………………… 46
Enhanced Recovery ………………………………………………………... 46
Stimulation Needs …………………………………………………………. 47
Sand Production …………………………………………………………… 47
Permanent Downhole Monitoring Systems ................................................ 47
2.13 SPOLLABLE COMPLETIONS ............………………………….……………...…… 51
2.13.1
2.13.2
Candidate Selection ................…………………………………………….. 51
Coiled Tubing Material ……..……..……………………………………… 52
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2.1
INTRODUCTION
2.1.1
Chapter Objective
The objective of this chapter is to review the different types of well completions, which are
available, and to discuss the important factors that need to be considered when selecting a
completion configuration. By the end of this chapter, the advantages and disadvantages of
a particular completion type in different producing environments should be clear.
2.1.2
Definition of Completion
A well completion is usually defined as the final string of casing, the production tubing and
associated downhole equipment, and the specific arrangement of these components. This
chapter will examine the considerations, which lead to the decision on where and how to set
the final casing string. Chapter 3 - “Completion Design Criteria” will deal with the
decision making process whereby the actual tubing and downhole completion equipment
are designed.
2.1.3
Objective of Completion
The primary objective of the completion process is to develop a well that will yield the
highest productivity over the life of the well. All wells present unique problems depending
on specific operating conditions. A partial list of factors that influence the design of a
completion program include (1) investment required, (2) desired producing rate, (3)
reserves in various zones, (4) reservoir drive mechanism, (5) stimulation needs, (6) sand
control requirements, (7) workover aspects, (8) artificial lift considerations, and (9) the
possibility of future additional recovery projects.
For each individual well there will be a specific completion technique of optimum design
that will yield the maximum productivity. Major decisions that must be reached in this
regard are (1) bottom-hole completion technique (cased or open hole) (2) number of
completions in a single wellbore, and (3) size of the production casing and/or tubing.
2.1.4
PCSB Completion Strategy
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Coincident with the ongoing groundwork of any field development plan (FDP) is the
preparation of a well completion strategy for the field in question. The deliverable is an
extensive documented study on completion options including a recommended completion
method(s) addressing operational requirements and contingency plans. Examples of
operational requirements may include, but not be limited to : using coiled tubing for acid
stimulation of multiple perforated intervals over a long measured interval; using slickline
and plug systems for isolating a perforated interval to permit selective acid stimulation
and/or hydraulic fracturing, selection of gravel packing method, and stimulation techniques
which require the use of a stimulation vessel.
The deliverable is a strategic approach for optimum completion of our wells to contract or
allowable requirements. This is not viewed as a highly detailed technical document, but
will provide us with a solid starting position for field development. The document will be
dynamic and will change as we obtain more information and ideas.
There is a necessity for documenting our general well completion approach as soon as
possible to :
•
assist in planning requirements for equipment, materials, studies and expertise in
advance of commencing rig operations
•
emphasize best practices in completion operations
•
address important completion issues.
for example: perforating gun system, size, shot density, number of runs, conveyance
method (wireline or other)
•
address strategy and contingencies for well completion and evaluation of the first wells
on a platform (“data” wells) or field and for subsequent batch completed wells. For
example : guidelines will be required for stimulation alternatives such as the use of
fracturing technology depending on observed or log inferred reservoir quality. A
related contingency may be testing a specific well prior to batch completions as a
result of inconclusive logging results.
illustrate geometry and configuration of proposed wells.
provide a reference during preparation of detailed design procedures.
•
•
This is a reference document of our collective knowledge, experience and ideas on well
completion alternatives, including other operator experience, with primary emphasis on
cost effective completion techniques and operational practices. Reservoir management
work and objectives will be utilized to guide completion practices. An example is
determining the perforated intervals with consideration for reserves and permeability
distribution.
The focus is on integrating individual factors in well completion including : reservoir
description, simulation results, drilling and completion fluids, cased hole logging,
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perforating and stimulation options, well testing and fluid sampling requirements.
Completion alternatives should be documented with their respective techniques, advantages
and disadvantages.
The study will provide definition of objectives, deliverables, participants, resources,
activities, and schedule. A small team is normally appointed to develop this scope, prepare
a draft table of contents, including a first pass at completion alternatives. Direct input from
Field Development, Field Operations, Drilling, DPE, and DDR parent is required to
complete this study.
Keep in mind that the overall deliverable is strategic in nature and should not become a
length process.
2.1.5
Fluid Flow Considerations
In the analysis of fluid flow from the reservoir to the wellhead (Figure 1), it is convenient to
think of the system as being comprised of four distinct regions, namely :
•
the reservoir (A)
•
the near-wellbore region (B)
•
the perforation tunnel (C)
•
the tubing (D)
These regions are shown in Figure 1. Flow through the reservoir itself (A) is controlled by
such factors as reservoir pressure, permeability, and fluid saturations. Although we can
influence each of these items to varying degrees, they are outside the scope of this Chapter.
Due to the converging flow profiles associated with the radial flow geometry that exists in
the near-wellbore region, the well productivity is strongly influenced by the conditions in
this region. The most productive arrangement exists when flow continues radially into the
wellbore, as occurs in open-hole completions. Productivity is impeded, on the other hand,
when fluid must converge on individual perforations in order to flow into the casing. When
this happens, the velocity increases around the perforations, causing a higher pressure drop
than if it did not converge on the perforations. For this reason, open-hole completions
generally have higher productivity than cased-hole completions.
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Figure 1. Fluid Pathway
An additional factor to be considered is that the open-hole completion has much more flow
area than the cased-hole completion. Therefore, a greater number of pore spaces can
become plugged in an open-hole completion than in a cased-hole completion before a
decline in productivity is noticed. Therefore, open-hole completions generally have longer
lifetimes than their cased-hole counterparts, when factors such as hole stability and
composition of production fluids are unimportant.
The next region is the perforation tunnel. The perforating parameters the completion
engineer has to work with are the number of perforations, their diameter and depth, their
phase relative to one another, and the conditions existing in the wellbore when the
perforations are made. All these factors can influence the well’s productivity and will be
discussed later in Chapter 10 - “Perforating”.
Finally, the fluid flows up the completion string from the perforations to the wellhead. The
tubing string can have a pronounced effect on a well’s deliverability. It also represents a
large fraction of the well’s capital investment. For this reason great care is taken to select
the tubing string which best depletes the reservoir while still being economical. Design of
tubing strings will be covered in Chapter 3 - “ Completion Design Criteria ” and Chapter 6 “ Tubulars ”.
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WELL CONFIGURATION
Before we discuss specific completion configurations we need to review the general
components of a completion, which include the wellhead and the various casing strings.
2.2.1
Wellhead
The wellhead serves a number of functions. First, it suspends all the strings of casing and
tubing that together comprise the well. Second, it provides a means of isolating one string
from another. Third, it provides a place to attach the blowout preventers when drilling the
well. Figure 2 is a diagram of a typical wellhead. More details about the design and
specifications of wellhead equipment can be found in Chapter 5 - “Wellheads”.
Figure 2. Wellhead and Christmas Tree
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Conductor Pipe
The conductor pipe (Figure 3) is a large diameter pipe which is usually set very shallow
(100-300 ft). It provides a means of taking returns and controlling hole washout when
drilling the surface hole.
2.2.3
Surface Casing
The surface casing is the first (i.e., outermost) string of casing that is cemented in place and
has pressure integrity. Most government regulations specify that the surface casing will
completely cover all fresh -water sands encountered while drilling.
Figure 3. Casing/Tubing Configuration
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Intermediate Casing
The intermediate casing string may not be required for all wells, depending on the
intended target depth and the type and pressure of the different strata to be drilled. Some
of the functions of intermediate casing are to isolate zones which will support and/or
require higher hydrostatic pressure from lower pressure ones and to reduce the chance of
the drill pipe getting stuck when drilling long sections of permeable hole.
2.2.6
Liners
Liners are casing strings that are suspended within the wellbore. That is, they do not
extend all the way to the wellhead. Liners may be either intermediate liners or production
liners, and they serve the same functions as their full string counterparts. There are two
main advantages to running a liner in lieu of a full string. First, the liner requires a lower
capital expenditure since it extends for a shorter distance in the wellbore than the full
casing string. Second, in very high rate completions, the use of a liner allows for a larger
flow area for the produced fluids, resulting in increased well deliverability.
The disadvantages of using liners is that they are difficult to cement effectively. Often
money that is saved on the purchase of pipe is spent on remedial cementing operations.
Nonetheless, liners are still used, and are a necessary component of very deep holes.
2.2.7
Tubing
The tubing is the conduit through which fluids flow from the reservoir to the wellhead.
The tubing must be able to withstand tensile, collapse, and burst loads while efficiently
and economically delivering fluids to the surface.
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OPEN HOLE COMPLETIONS
Up until this point we have been discussing the general components of a completion and
some basic concepts in fluid flow from the reservoir to the wellhead. Next we shall
examine some aspects of the basic completion options available. Depending on the
objective and particular completion considerations an endless variety of alternative well
designs are possible. We begin by discussing the open-hole completion.
2.3.1
Definition
An open-hole completion is one in which there is no casing set across the production
interval. This leaves the entire zone open for flow into the wellbore.
2.3.2
Advantages
Open-hole completions, as shown in Figure 4, have the following advantages.
1.
No perforating expense.
2.
Log interpretation is not critical since entire gross interval is open.
3.
Full diameter opposite the pay. In fact, many open-hole completions are underreamed to 13 in. or larger to increase the effective radius of the completion.
4.
Slightly reduced casing cost.
5.
Can be easily deepened.
6.
Can be easily converted to a perforated liner or casing completion.
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Figure 4. Types of Open-Hole Completions
The cost savings associated with item 1 can be significant for long interval lengths. For
example, if 150 ft of pay are available, it would take 5 gun runs of 30 ft each to perforate
the entire interval. The money spent on perforation charges (perhaps 600 charges or more)
as well as the rig time associated with multiple wireline runs can be substantial, especially
offshore.
2.3.3
Disadvantages
Open-hole completions have some disadvantages, however. Several of these are listed
below.
2.3.4
1.
Excessive gas and/or water-oil ratios cannot normally be controlled (except in the
case of bottom water).
2.
Cannot be selectively fractured or acidized.
3.
Normally requires more rotary rig time since rig is tied up waiting on cement before
drilling the production casing shoe.
4.
Will require frequent clean-outs if sands are not completely competent.
Methods
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There are two basic alternatives in setting an open-hole completion; (a) set casing before
drilling the pay zone or (b) drill the pay zone, then set the casing above the pay. Each of
these techniques is discussed below.
The primary reason for setting the production casing prior to drilling the pay is that the
drilling fluid (mud) may be replaced by a low-solids viscosified drilling fluid. This
reduces the chance of damaging the formation due to plugging by bentonite or barite
solids, which might have been in the original drilling mud.
One risk associated with this technique is that casing is run and cemented before the
formation is evaluated. Thus it is important that the pay zone depth and its characteristics
be well known before adopting this procedure.
The other alternative when making an open-hole completion is to drill the entire pay prior
to setting casing. This method allows one to log and/or test the interval before incurring
the expense of running the production casing. It also ensures that casing is set to the
proper depth. The only disadvantage is that the hole cannot easily be drilled with special
“low-solids” drilling fluids.
This is ordinarily not a serious drawback, however, since the hole can be underreamed
with a clear fluid if required.
2.3.5
Examples
A classic example of an open-hole completion can be found in the Middle East, where
many wells are completed open-hole through long, highly productive carbonate formations
with very little water production. All these characteristics (high productivity, competent
formation, low water) make an open-hole completion the most economic choice.
Another example is the North Sea, where open-hole gravel packs have been installed.
Again, these are high rate wells with a water-oil contact away from the completion
interval. The open-hole gravel pack can provide higher productivity with greater longevity
than its cased-hole counterpart because its greater productivity results in less drawdown
and hence, less stress on the sand.
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CASED-HOLE COMPLETIONS
2.4.1
Definition
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A cased-hole completion (Fig .5) is one in which the production casing string (or
production liner) is cemented across the intended completion interval. In this case
communication between the inside of the casing and the reservoir is effected by
“perforating” the casing.
2.4.2
Advantages
The advantages of cased-hole completions relative to open-hole completions are given
below.
1.
Excessive gas and/or water-oil ratios can normally be controlled.
2.
Can be selectively fractured or acidized.
3.
Easier workovers such as retrieving screens or other fishing operations.
4.
Will control many incompetent sands and is adaptable to special techniques to
minimize sand problems.
5.
Rotary rig time is normally minimized.
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Figure 5. Cased-Hole Completion
2.4.3
Disadvantages
Some disadvantages of cased-hole completions follow :
1.
Perforating costs.
2.
Not adaptable to special drilling techniques to minimize formation damage.
3.
Slightly higher casing expense than an open hole completion.
4.
Log interpretation is critical in order not to miss commercial sands while avoiding
sub-marginal sands.
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Although perforated completions will be the proper choice in the vast majority of wells,
the engineer should be alert to recognize areas where another method of completion would
be preferable. In productive zones that are especially susceptible to formation damage
(such as the Austin Chalk), the best approach may be to set the casing above the pay zone,
use a nondamaging fluid to drill the zone, and then complete in the open hole. In long
producing intervals with severe sand problems, open-hole gravel packs yield higher
capacities at less cost than plastic consolidation or gravel packs made inside perforated
casing.
2.4.4
Examples
Cased-hole completions are found throughout the world. A vast majority of offshore
completions are cased hole, perhaps because of the large number of isolated zones that are
often encountered. Injection wells, whether they be for water flooding, steam, or disposal,
are mostly cased-hole.
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2.5
SINGLE COMPLETIONS
2.5.1
Definitions
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A single completion is a completion where only one conductive path to the surface exists.
There are several varieties of single completions, however, as shown in Figure 6. Each of
these is discussed below.
2.5.2
Tubing Without Packer
In this type completion (Fig .6a), a tubing string is normally installed inside the casing for
production purposes. Even in high-productivity wells where production is directly up the
casing, tubing will often be installed to permit circulation of kill fluids, corrosion
inhibitors, and paraffin solvents. For maximum production, the tubing is run open-ended
and the well produced through both the tubing and annulus.
2.5.3
Tubing With Packer
Figure 6b shows a single completion utilizing a packer at the bottom of the tubing string.
Packers are run for a variety of reasons, such as :
2.5.4
•
To keep formation pressure off of the casing.
•
To prevent corrosive fluids from contacting the casing.
•
To improve flow characteristics of some wells.
•
To provide an annulus for gas lift or continuous annular injection of treating
chemicals.
•
To improve safety in event of uphole casing leaks (i.e., external corrosion).
Tubingless
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Figure 6c is an example of a single tubingless completion. Tubingless completions are
distinguished by the fact that the production tubing is cemented in the hole in lieu of a
production casing string. Thus, the tubing becomes the production casing.
Some advantages of tubingless completion are :
•
Reduced cost through the elimination of the large production casing, the need for
packers and wireline completion equipment, and the need for more expensive
servicing and workover techniques.
•
Workover procedures are simplified, and less total time is required. This is
particularly true in the case of squeeze cementing, stimulation, and plug-back
operations.
However, there are limitations to be considered when deciding whether or not to run a
tubingless completion. Some of these limitations are :
•
The tubing is not retrievable should a tubing leak develop.
•
The small diameter precludes the successful application of gravel packing techniques.
•
Small (1-in.) screens have been run, but the success of such attempts has not been
good.
•
Most methods of artificial lift are more difficult in tubingless completions.
For these reasons, most tubingless completions have been limited to routine, low pressure
reservoirs where a considerable amount of information about the reservoir is known.
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Figure 6. Single Completions
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MULTIPLE COMPLETIONS
2.6.1
Definition
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A multiple completion is one where a number of different reservoirs can be produced
through separate flow paths within the same wellbore. As we shall see, this may be
accomplished with tubing/annulus flow, multiple tubing strings, or by cementing a number
of totally independent tubing strings in the same wellbore (a multiple tubingless
completion).
2.6.2
Reasons For Multiple Completions
A multiple completion is one where a number of different reservoirs can be produced
through separate flow paths within the same wellbore. As we shall see, this may be
accomplished with tubing/annulus flow, multiple tubing strings, or by cementing a number
of totally independent tubing strings in the same wellbore (a multiple tubingless
completion).
•
Higher producing rates and faster payouts - This is the most common reason for
multiple completions. Several productive zones in a well may have varying
productivity indices. When these variations are significant, the weakest interval
usually will produce at a higher rate if it is segregated than if it is commingled with
the better zones.
•
Separating different types of reservoirs - It is generally considered undesirable to
commingle oil from a water-drive reservoir with oil from a dissolved-gas-drive
reservoir because the pressure decline curves are different. Similarly, oil and gas
zones should normally not be commingled in a common wellbore.
•
Proper reservoir control - This can be important in both primary and secondary
operations. In gas-cap drive or water-drive reservoirs having several pays, proper
exploitation may require that the different zones be produced at controlled rates to
recover the maximum amount of oil. In secondary recovery projects, it is often
advisable to inject gas or water into the various pays at controlled rates to maximize
oil recovery. It may also be advantageous to multicomplete key wells to monitor
reservoir behavior.
•
Other reasons may include government regulations, the need for accurate production
history from each zone, price differentials between crudes, etc.
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While multiple completions are useful in many situations, they are more costly than single
completions, and in the case of tubing/packer completions, they increase the risk of
equipment failures and the need for fishing jobs. Where all zones have short flowing
lives, it is often more practical to commingle all zones on initial completion or to complete
in only one zone and open the others on later workovers. Therefore, if commingling
production does not violate governmental regulations, result in a substantial reduction in
the producing rate, or adversely affect the ultimate recovery, a commingled single
completion should be preferred to a multiple completion.
2.6.3
Single String, Single Packer
Figure 7 depicts a multiple completion employing only one tubing string and one packer.
Wells completed in this manner can be produced in two different ways. First, the lower
zone may flow up the tubing while the upper zone is produced up the annulus. This is
shown in Figure 7a. The alternative method (Figure 7b) is to set a plug in the tubing string
below a communication device such as a sliding sleeve or side-pocket mandrel, thereby
blanking off the lower zone. Then, by manipulation of the communication device, the
upper zone could be produced up the tubing.
(a)
(b)
Figure 7. Multiple Completions : Single String, Single Packer
As you can see, the distinction between single and multiple completions gets rather hazy at
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this point. If both zones are produced simultaneously, it is a multiple completion.
However, if each zone is sequentially produced through the tubing string, it becomes a
selective single completion.
2.6.4
•
The upper zone cannot be produced through tubing unless the lower zone is blanked
off.
•
The casing is subject to pressure and possible damage by corrosive fluids.
•
Only the lower horizon can be artificially lifted.
•
Sand production from the upper zone may require a washover operation in order to
pull the tubing.
•
Both zones must be killed if it is desired to work-over the upper zone or if a
concentric-type workover is not feasible in the lower interval.
Single String, Multiple Packer
The addition of a second packer can increase the flexibility of dual completions. Figure 8a
illustrates a well with a wireline-retrievable straight-flow choke installed so that the upper
zone is produced through the annulus and the lower zone through the tubing. Crossoverflow chokes, as shown in Figure 8b, permit the upper zone to be produced through the
tubing and the lower zone through the casing-tubing annulus, but will flow through the
tubing owing to the increased fluid velocity at the same producing rate. Crossover chokes
permit this flexibility and also permit artificial lift of the upper zone
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Figure 8. Multiple Completions : Single String, Dual Packer
The arrangement overcomes some of the limitations of the single-packer type of dual
completion; however, it is still not possible to artificially lift both zones simultaneously.
Also, the casing is subject to damage by high pressures or corrosive fluids, and it is still
necessary to kill both zones to work over the upper zone. The installation of crossover
equipment also presupposes that the lower zone will flow on the casing; if it will not, dual
selective crossover equipment serves no purpose.
Figure 8c shows a multiple selective single completion, which allows a number of
different zones to be sequentially produced up the tubing string.
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Multiple String, Multiple Packer
The most popular type of multiple completion is comprised of multiple parallel tubing
strings and multiple packers. An example of such a completion is shown in Figure 9.
Installations employing parallel tubing strings allow each zone to flow up a separate
conduit, which keeps potentially corrosive high-pressure fluids away from the
production casing.
They also permit several zones to be artificially lifted
simultaneously.
Wireline tools provide circulation between the tubing strings and the casing tubing
annulus. Concentric tubing and wireline workovers are also possible with this type of
completion.
In the vast majority of cases, a multiple completion consists of a single permanent
lower packer and a dual retrievable upper packer. If a number of different zones exist
in the lower section of the hole, it is often desirable to set the lower packer above all of
them. Then, each zone can be sequentially depleted using concentric techniques to
perforate, squeeze perforations, reperforate higher, etc.
Figure 9. Completions : Parallel String, Multiple Packers
Multiple concentric completions have also been tried in the past, but they have proved to
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be very complex completions with a high risk of mechanical failure. An example of such a
completion is shown in Figure 10. Although the drawing looks simple enough, there are
numerous difficulties associated with running and servicing such a completion.
Figure 10. Multiple Completions : Multiple Concentric Tubing Strings
For similar reasons, multiple parallel completions with more than two strings of tubing are
also seldom run. Consider, for example, Figure 11. This completion is a mechanical
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nightmare. The opportunities for servicing this type of completion are very limited, and
the chance of having stuck packers is very high. Consequently, dual completions are by
far the predominant type of multiple completion.
Figure 11. Multiple Completions : Multiple Parallel Tubing Strings
2.6.6
Multiple Tubingless
Multiple tubingless completions are characterized as having two or more strings of tubing
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run through different intervals and then cemented in place. In theory this leaves a number
of totally separate strings which simply share a common wellhead and wellbore. Figures
12 (a) and (b) are examples of such completions.
While multiple tubingless completions have most of the advantages associated with their
single tubingless counterparts, they have serious limitations. One major limitation is the
difficulty encountered when attempting to cement multiple strings of tubing. Very often,
behind-pipe communication or “crossflow” occurs. “Crossflow” generally requires
remedial cementing action, and often increases the cost of the completion significantly.
Figure 12. Multiple Completions : Multiple Tubingless
A second disadvantage of multiple tubingless completions is the chance of perforating a
neighboring string when perforating the target sand. Usually, magnetic detectors or
radioactive sources are used to orient the perforating gun away from the other string (s).
However, mistakes happen. This is especially true when perforating long intervals where
the tubing strings tend to wind around one another.
2.7
HORIZONTAL AND MULTILATERAL WELLS
2.7.1
Horizontal Wells
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Most experts agree that horizontal wells have become a preferred method of recovering oil
and gas from reservoirs in which these fluids occupy strata that are horizontal, or nearly
so, because they offer greater contact area with the productive layer than vertical wells.
While the cost factor for a horizontal well may be as much as two or three times that of a
vertical well, the production factor can be enhanced as much as 15 or 20 times, making it
very attractive to PCSB. Despite these facts, it took several decades for the industry to
embrace the technique.
“Some of the earliest development toward horizontal drilling took place during the early
1940’s when John Eastman and John Zublin developed short-radius drilling tools designed
to increase the productivity of oil wells in California,” explains Frank Schuh, a horizontal
drilling consultant.
“The tools were designed to drill 20 to 30 ft (60.96 to 91.44 m) radii and horizontal
distances of 100 to 500 ft (304.8 to 1,524 m) and they permitted the drilling of numerous
laterals in the same formation in various directions around the wellbore. Typical designs
used between four and eight laterals.”
The equipment preceded downhole survey tools and included extraordinary knucklejointed flexible drill collars that could be rotated around the extremely high curvatures.
Also, it allowed for the employment of a drilling technique that was the perfect completion
companion to standard, vertical open-hole completions being used at the time. “Basically,
Eastman and Zublin were instrumental in drilling the first multilaterals,” Schuh states.
“Today’s multilateral wells are simply modern versions of these earlier efforts.”
Unlike a directional well that is drilled to position a reservoir entry point, a horizontal well
is commonly defined as any well in which the lower part of the wellbore parallels the pay
zone. And, the angle of inclination used to drill the well does not have to reach 90° for the
well to be considered a horizontal well.
Applications for horizontal wells include the exploitation of thin oil-rim reservoirs,
avoidance of drawdown-related problems such as water/gas coning, and extension of wells
by means of multiple drainholes.
True development and employment of horizontal-well techniques began in the U.S. During
the mid-1970’s. However, horizontal-drilling experimentation began much earlier.
The U.S. Dept. Of Energy (DOE) marks the starting date as 1929 in Texon, Texas. Here
says the DOE, the first “true horizontal well” was drilled. Additionally, the DOE cites a
well drilled in Yarega, U.S.S.R., in 1937 and a 500 ft (1,524 m) well drilled in 1944 in the
Franklin Heavy Oil field in Venango City, Pennsylvania, as being some of the first wells
to be drilled horizontally.
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During the 1950’s, the Soviet Union drilled 43 horizontal wells, a considerable effort with
respect to the equipment available then. Following their foray into horizontal drilling, the
Soviets concluded that while horizontal wells were technically feasible, they were
economically disappointing or, in other words, not profitable. As a result, they abandoned
the method.
in the mid-1960’s - 10 years after the Soviet experience - the Chinese drilled two
horizontal wells. The first, 500 m (164.04 ft) in length and not cased, collapsed after a
week of production. The second was interrupted by the “Cultural Revolution.” Like the
Russians, the Chinese concluded that horizontal drilling was uneconomical and abandoned
the method for more than 20 years.
From 1979 to 1982, a renaissance of true horizontal-well development work occurred in
North America. It was during this period that Alan Barnes, an engineer for a major oil
company, used a complex reservoir-simulation model to promote the benefits of the
Eastman/Zublin short-radius technique to his superiors.
Following his modelling studies, the company drilled approximately 12 horizontal wells in
the Empire Abo reef in New Mexico. They targeted a thinning oil column in a massive
limestone reservoir with a significant as cap and active water drive. Oil recovery of the
first hole exceeded the production of a comparable vertical well by more than 20 times
before breakthrough of the gas cap. The success of the Empire Abo project led the
company to look for means of a broader application. The company appointed Schuh to
lead the search.
“We developed what is generally referred to now as ‘medium radius’ (20°/100 ft)
horizontal drilling,” Schuh says as he recalls the project. “The development determined
the maximum hole curvatures possible in drilling horizontal wells without damaging
conventional drillstring and drilling tools. We found that the unique application of
horizontal drilling allows hole curvatures that are five to 10 times greater than can be used
in conventional directional drilling. We utilized the latest advancements in downhole
motors and measurement-while-drilling (MWD) equipment to develop methods for
establishing long, low-cost horizontal boreholes.”
Using their technique, Schuh and his colleagues drilled their first medium-radius well in
January 1985. During the 1980’s, more than 300 horizontal wells were drilled in North
America including the first one in Prudhoe Bay, Alaska, in 1985. During this period,
Texas’ Austin Chalk trend also received a great deal of attention from horizontal-well
operators who, at the time, drilled some of the highest-producing-rate wells in the U.S.
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But the decade of the 1990’s most certainly will become known as “the decade of the
horizontal well.” Through 1998, the number of horizontal wells drilled in the U.S. Has
totaled more than 3,000, an increase of 1,000% over the previous 10 year period.
By the late 1990’s, a dramatic shift in corporate philosophy regarding horizontal drilling
occurred when one major operator set a requirement that prior management approval was
necessary for all vertical wells.
The renaissance of horizontal-well drilling techniques in Europe began about the same
time as in North America. In 1977, Elf Aquitaine and L’Institut Francaise du Petrole (IFP)
began work on the FORHOR project, which eventually led to the success of the Rospo
Mare field, the only oil field in the world at that time that produced systematically through
horizontal wells. Drilled in the Adriatic Sea in water depths ranging from 200 to 300 ft
(61 to 91 m), the technical and economic success of this field is credited with triggering
the world’s interest in horizontal drilling.
Jacques Bosio, a former R & D deputy director and Vice President of Elf Acquitaine, was
one of the pioneers in the field of horizontal drilling as a project manager of the Elf/IFP
FORHOR horizontal drilling research study.
“What I remember about that period, when nobody in the world would believe that
horizontal wells could become a new tool for the industry, is that it was more difficult to
change, by 90°, the way people were thinking than it was to do it with the wells,” says
Bosio, recalling those early days in Italy. “We had been raised with the idea that the
maximum possible inclination for a well could not exceed 70°. I don’t know why, that’s
just the way we were taught. But, one of the main reasons the FORHOR project
succeeded was because we had the perseverance to go one step further with a rotary
drilling rig. Remember, we didn’t have downhole motors then.
“When we talked to our drillers [about going beyond 70° inclination] . . . they first laughed
and then turned real mad at those crazy R & D people,” Bosio muses. “Even supposing
that you could drill it, a horizontal well made ‘no economic sense,” they said. It will cost
at least 10 times as much as a nearby vertical well but will never produce 10 times more.
Besides, no coring, logging or testing will be possible and it will collapse on you before a
liner can be run.”
In spite of the ridicule and disbelief of others, Bosio and his colleagues pressed on in May
1980 to drill the Lacq 90 (a total coincidence that this was the name of the well) in
southern France, the first well drilled at 90° inclination.
“We had to swear that we would plug the well if it happened to disturb the drainage of the
reservoir so production could go back to normal,” Bosio says as he stifles a laugh. “Lacq
90 went 275 m (902 ft) within the reservoir with 100 m (328 ft) purely horizontal at a cost
of 3.2 times that of a vertical well,” he continues. “It did produce . . . much more water
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than its neighbors since the reservoir was 90% watered out.” This led to claims that
horizontal wells were only god for producing water, an unfair statement that did not
nothing to advance the technology. Shrugging off such comments, Bosio had much better
luck later on with the well’s successor, the Lacq 91.
With their data in hand, Bosio’s group set out to apply it in the Rospo mare field, a perfect
laboratory for the development of horizontal-drilling techniques. The field is unique
because the nature of its reservoir and the characteristics of its oil prevent it from being
produced through conventional vertical wells. By early 1981, five wells, all vertical, had
been drilled from a platform at the center of the field to appraise, set the field’s limits, and
begin exploitation.
“Our attention now turned to the Rospo Mare field,” states Bosio enthusiastically. “We
drilled the Rospo Mare 6 in January 1982, 370 m (1,214 ft) of which was horizontal at a
cost factor of 2.1 times more than a vertical well. More importantly, it was an immediate
success, producing 20 times more oil than a neighboring vertical well and boosting the
field’s recoverable reserves from near zero to 70 million barrels,” says Bosio proudly.
Bosio believed the Rospo Mare 6 well’s success would jolt the industry into jumping
aboard the horizontal-well bandwagon. Unfortunately, the success was greeted with a big
industry yawn.
Bosio recalls his experience in giving a paper on the well at the 1983 World Petroleum
Congress (WPC) meeting in London. “When I went to the chair to present the first paper
ever presented on horizontal wells, more than half the room, which was full from the
preceding paper, got up and left! They simply weren’t interested,” Bosio explains. “At
the next WPC in 1987 in Houstan, the paper I presented attracted a small crowd. Then, at
the 1991 WPC in Buenos Aires, we had a full session on horizontal wells.”
Finally, producers had begun to realize that horizontal wells can increase production rates
and ultimate recovery, reduce the number of platforms or wells required to develop the
reservoir, reduce stimulation costs, and bypass environmentally sensitive areas.
2.7.2
Multilateral Wells
The acknowledged father of multilateral technology technology is Alexander Grigoryan.
In 1949, Grigoryan became involved in the theoretical work of American scientist L.
Yuren, who maintained that increased production could be achieved by increasing
borehole diameter in the productive zone. Grigoryan took the theory a step further and
proposed branching the borehole in the productive zone to increase surface exposure.
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Grigoryan put his theory into practice in the former U.S.S.R.’s Bashkiria field (today’s
Bashkortostan). There, in 1953, he used downhole turbodrills without rotating drillstrings
to drill Well 66/45 in the Bashkiria Ishimabainefti field. His target was the Akavassky
horizon, and interval that ranged from 10 to 60 m (33 to 197 ft) in thickness. He drilled
the main bore to a total depth of 575 m (1,886 ft), just above the pay zone, and then
drilled nine branches from the open borehole without cement bridges or whipstocks.
When completed, the well had nine producing laterals with a maximum horizontal reach
from kickoff point of 136 m (447 ft). It was the world’s first truly multilateral well,
although rudimentary attempts at multilaterals had been since the 1930’s.
Compared to other wells in the same field, 66/45 was 1.5 times more expensive, but it
penetrated 5.5 times the pay thickness and produced 17 times more oil each day.
Grigoryan’s success with the 66/45 well inspired the Soviets to drill an additional 110
multilaterals wells in their oil fields during the next 27 years, with Grigoryan drilling 30 of
them himself.
Like horizontal wells, multilateral wells justify their existence through their economics.
Defined as a single well with one or more wellbore branches radiating from the main
borehole, they can be an exploration well, an infill development well or a re-entry into an
existing well. But, they all have a common goal of improving production while saving
time and money.
Multilateral-well technology has not yet evolved to the point of horizontal-well
technology. The complexity of multilateral wells ranges from simple to extremely
complex. They may be as simple as a vertical wellbore with one sidetrack or as complex
as a horizontal extended-reach well with multiple lateral and sublateral branches. While
existing techniques are being applied and fresh approaches are being developed,
complications remain and the risks and chances of failure are still high.
As indicated earlier, it took several decades for the industry to endorse the concept of
drilling horizontal and high-angle wells. Producers had to be convinced that the two- or
three-fold cost increase of horizontally drilled wells would be justified. Once producers
got a taste of the 15- to 20-fold production increases, they wholeheartedly jumped on the
bandwagon.
“This initial growth of horizontal drilling has been quite rapid and now represents about
10 to 15% of all drilling activity. The future growth of horizontal wells depends on how
the industry handles the next rounds of technological advancement,” Schuh says.
“The present state-of-the-art is economically attractive in easily drilled formations where
the reservoir can be efficiently produced without the need of mechanical intervention. The
greatest growth potential is in harder-to-drill formations and reservoirs that require
selective completions, selective isolations, and stimulation operations. “Success in these
areas will require new drilling equipment, a great expansion of completion options and
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development of new completion equipment and well-repair techniques,” Schuh concludes.
It seems that the future of multilateral technology will follow that same course. According
to Jim Longbottom, a service/supply company engineer in multilateral technology and a
highly published author, multilateral completions have a bright future but it will be some
time before that future is realized. “Drilling and completion of multilateral wells is at the
same development state as horizontal drilling and completion was 10 years ago,” he says.
“Acceptance and expansion of multilateral drilling indicate that within a decade,
multilaterally completed wells will be as commonplace throughout the industry as
horizontal wells are now.
“Asset managers have at their disposal the tools and technology to extract more value than
ever before from their holdings,” he continues. “Horizontal and re-entry multilateral
drilling has increased 50% during the past 5 years and will likely grow at more than 15% a
year through 2000.”
However, if Longbottom’s predictions are to come true, multilateral technology will have
to win over the Gulf of Mexico (GOM) operators who seem to possess a mysterious lack
of enthusiasm. Apparently these producers, who by nature are conservative, differ with
their more risk-oriented counterparts operating in other parts of the world. GOM operators
have a long tradition of resisting innovation, opting instead for systems that are dominated
by near-term profit. They tend to shun new, exotic solutions to their daily problems.
Some believe the future of multilateral well development is tied to advances in the
methods for drilling these wells - directional and horizontal drilling techniques, advanced
drilling equipment and coiled tubing drilling. This may be true. However, it is also
important to note that the industry’s ability to analyze the production and reservoir
performance of multilaterals, particularly in a cost-effective manner, has fallen behind.
Currently, drilling technology has temporarily outstripped the industry’s capabilities in
production and reservoir engineering analysis. It will catch up, but these factors are also a
major impediment to more widespread application of multilaterals, particularly where
improved-recovery methods are expected to be used.
Perhaps the biggest push on operators to install multilaterals in the future will come from
the technology’s economics. Historically, when operators have found themselves in
extended periods of depressed oil prices about which they could do nothing, they have
reduced operating and capital expenditures to help the bottom line. Then to help squeeze
more oil from every drilling and completion dollar spent, they have turned to new
technologies, even if they hadn’t endorsed them before. Most recently that technology has
included geosteering, improved seismic data, and horizontal wells.
Also, multilateral technology offers an attractive package of economic incentives to
producers looking for bottom-line help. Multilaterals allow multiple wells to be drilled
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from a single main wellbore, eliminating costly rig days for drilling an upper hole section
for each well. And, the ability to tap several zones from branches off a single wellbore,
rather than a number of vertical ones drilled through the same section, holds the added
attraction of risk reduction.
But, the biggest economic driver will be deepwater offshore wells where risks are high and
the huge cost of deepwater installations can be reduced by multilaterals that shrink the
number of wells and the amount of ancillary drilling and completion work needed to
access high-production-rate fields.
As for horizontal wells, their future is assured. For multilateral wells, the pendulum is
beginning to swing in their favor as operators steadily realize that the advantages of these
systems are increasingly out-weighting their risks. This is making their future look a low
more secure.
2.7.3
Multilateral Well Classification Matrix
TAML, a group of companies with ML experience, held its kick-off meeting in Aberdeen,
Scotland, on March 13 & 14, 1997. The objective of the forum was for participants to
share their worldwide ML experiences, with a view to providing a more unified direction
for the development of multi-lateral technology. Advice was also solicited from several
additional operators and service companies providing multi-lateral equipment and
services, including a discussion on the topic at the 1997 SPE Forum Series on MultiLateral Completions in Breckenridge, Colorado, USA.
Delegates unanimously agreed that, with the wide range of ML well complexities being
drilled, development of a common classification system would have considerable added
value during the planning phase of a ML well. The main benefits from this were seen to
be:
•
Determination of functional requirements - It was agreed that determination of
functional requirements of a proposed ML well is one of the key success factors in
delivering a well that meets its objectives. A classification system would provide a
“road map” which would allow well and petroleum engineers to efficiently achieve
this.
•
Utilization of the most appropriate system - With functional requirements
determined, a classification “code” would be enable the comparison of well
requirements and capabilities of the various systems on the market.
•
Transfer of learning – Albeit, the number of ML wells being drilled worldwide is
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growing rapidly, there is a relatively insignificant amount of pertinent “offset”
information. A classification code would enable relevant and accurate comparison
of case histories and performance indicators.
At present there are several matricies in existence, all with fundamental differences. The
TAML participants agreed that the one proposed here will supercede the others and will be
used by them and their companies in the future.
MATRIX EXPLANATION
The system is made up of two tiers : 1) Complexity Ranking, and 2) Functionality
Classification. The Complexity Ranking consists of a single numeric character while the
Functionality Classification includes a series of alpha and numeric characters that describe
critical functionality characteristics of the well.
Tier 1 - Complexity Ranking. Using a number between 1 and 5, the complexity ranking
gives a “first-pass” indication of the complexity of the well, which is based on junction
complexity. In a well with more than one junction, the most complex one would be
referred to.
Tier 2 – Functionality Classification. Broken down into two sections, Well Description
and Junction Description, the Functionality Classification provides more technical detail
of the well. Its primary use would be that of a “roadmap” in ascertaining critical
requirements during the planning of a ML well or in describing the status of an existing
well. in a well with more than one junction, each is described, from bottom to top.
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Complexity ranking
Well description
Junction description
Example 1 : Level 2; Ranking N-1-PN-S/2-TR-SEL
2-TR-SEL
Level 2
N-1-PN-S
Mother-bore
cased
Mother-bore cased
New Well
cemented;
One Junction
and cemented;
lateral open
lateral open
Producer-Natural lift
Through-tubing re-entry
Single bore completion
(above the production packer) Selective production
&
Example 2 : Level 5; Ranking E-2-IN-D/2-PR-NON/5 (3,000 psi)-TR-SEP
Level 5
E-2-IN-D
2-PR-NON (Lower Junction)
Pressure integrity at
Existing well
Mother-bore
cased
&
the (upper) junction,
Two Junctions
cemented;
achieved with the
Injector
lateral open
completion
Dual bore completion
Re-entry by pulling completion
No flow control
5 (3,000 psi)-TR-SEP
(Upper Junction)
Pressure integrity at the
junction (3,000 psi)
Through-tubing re-entry
Separate production
2.8
MONOBORE COMPLETIONS
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Definition
This type of completion was the original, so called, slim hole or slim well which has been
used in North America for thousands of low rate, non-corrosive wells. In these instances,
2-7/8 inch production tubing served the dual purpose of production casing and tubing.
More recently, slim hole fit-for-purpose or slim well drilling and the monobore completion
emerged independently and it can be agreed that they are synergistic. A monobore
completion is a completion featuring fullbore access across the pay zone/s, without
diameter restrictions (but not necessarily with a constant diameter from top to bottom).
The completion style first designed for wells in the North Sea, utilized primarily 5-1/2”
inch or 5 inch production tubing above 5 inch or 4-1/2” inch (respectively) production
liners. A comparison of a conventional completion and a monobore completion is
illustrated in Figures 13 and 14 that follow:
Figure 13. Conventional versus slimhole monobore
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Figure 14.
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The primary difference is that the monobore completion’s inner diameter tapers downward
with the smallest inner diameter being the production liner (or casing) whereas the
conventional completion tapers down to a minimum inner diameter, usually located at the
base of the packer tailpipe, and the production liner (or casing) is of increased inner
diameter.
The monobore completion is not well suited to wells where zonal selectivity is required.
Where selective completions are required, a conventional completion is likely the
preferred choice. Prior to committing to a well with selectivity, the completion engineers
should challenge whether:
2.8.2
•
Commingling of production with (or without) production logging to allocate
production to reservoirs is an option. The value of conventions/regulations
prohibiting commingled production should be challenged. In the event that
commingling is acceptable, a monobore completion may become the most effective
option.
•
A sequential, bottom up, depletion strategy is appropriate. In this case, a monobore
completion is ideal and the operational advantages of the monobore completion
could be realized.
Introduction
Wells drilled using slim hole techniques are reducing initial drilling costs. The technology
to conduct effective petrophysical evaluation in slim wells is currently available or
emerging rapidly. Thus, slim hole development wells will warrant consideration in many
projects.
This section provides information on the consideration of slim hole development wells.
Although tubular sizes and well designs are specified, these configurations are only of an
illustrative nature and fields (or area) specific optimisation will be required. Slim wells
are not necessarily an optimal solution for general application but they should always be
compared with conventional and horizontal wells on a case by case basis.
A number of currently undeveloped fields could become profitable if the well costs,
including tie-in, were reduced by 30%; an overall saving which is a realistic objective if
the wells, subsea equipment, and tie-ins are down-sized. Wells in many of these fields
will not flow at the rates traditionally required to justify subsea procedures. Thus the
smaller production conduit of the down-sized well may be adequate.
2.8.3
Monobore Completion
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As stated previously, “a ‘monobore’ (MB) completion is a completion featuring fullbore
access across the pay zone, without diameter restrictions (but not necessarily with a
constant diameter from top to bottom)”. This completion style was pioneered by Shell
Expro for use in their North Sea operations for wells utilising primarily 5½” or 5”
production tubing above 5” or 4½” (respectively) production liners. A comparison of a
conventional completion and a monobore completion is illustrated in Figure 13.
2.8.4
Advantages
Monobore completion advantages are as follows:
•
Monobore completions provide maximum flow area and a smooth uniform bore. As
a result, they are the most efficient completions available for maximizing high rate
production.
•
The high rate advantage of monobore completions provides maximum rate
flexibility for peak production swings or periods when wells in a field are off
production.
•
For equivalent production rates between packer type completions, monobores can
reduce the number of wells required for a development thus providing significant
cost savings and increased net present value.
•
The smooth uniform bore minimizes turbulence and reduces the effects of
corrosion/erosion. This is one of the reasons why L-80 material may be run for the
tubing strings in a sour gas environment instead of the much more expensive CRA
stuff.
•
With the full bore internal diameter from the top of the tree to the bottom of the
well, monobore completions readily allow a full range of concentric intervention
activities.
•
The large internal diameter also allows maximum flexibility in tool selection for
intervention operations. Tools that couldn’t be used in packer type completions due
to tubing restrictions can readily be used in monobore completions.
•
The reduced vertical friction losses provided by large bore diameters can be a
significant advantage in delaying compression requirements for a gas project.
•
Since monobore completions don’t utilize a conventional packer, one pipe string can
be eliminated for equivalent tubing size packer completions.
•
With the monobore completion design, packer setting concerns during completion
operations are eliminated while maintaining static tubing seal integrity at the same
time.
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•
Full bore PLT can be used for reservoir monitoring.
•
Thru tubing workover for reservoir intervention. (slickline, e-line, CTU)
•
Less complex in design
•
Compatible with splitter wellhead
•
Ideal for CTU sidetracks. Cheaper infills.
•
Use of a 3-1/2 inch production liner, in conjunction with 3-1/2 inch production
tubing allows cost savings associated with slim wells to be achieved while
maintaining an outflow system suited to a large proportion of wells around the
world.
Disadvantages
•
A drawback to monobore completions is that it is relatively new technology with
limited suppliers in some equipment areas, especially for large diameter, high
pressure gas completions.
•
In many cases, a monobore completion requires more casing/liner flow than in a
conventional completion. This may have two implications:
− Limited ability to circulate a well dead at the top of the productive zone. This is
generally not a concern because most wells can be bullhead dead, and the option
of placing a retrievable bridge plug in the top of the liner section and circulating
the well dead above it is possible.
− Corrosion of the liner may cause irreparable problems. This can generally be
pre-empted by appropriate materials selection for the liner. Also the costs of
sidetracking round mechanical damage, corrosion, and formation impairment
have fallen relative to workover. In many cases a sidetrack round a corroded
liner may be justifiable.
•
If monobore plugs become stuck in the liner, it becomes necessary to mill them out
compared to a conventional completion where it may be possible to hoist tubing and
retrieve a stuck plug or even to ‘shoot off’ or ‘perforate’ a packer tailpipe to restore
production in the event of a stuck plug.
•
Generally, but not necessarily, when a monobore completion is run in larger sizes,
the tubing size selected is one size larger than liner size. For instances, 5” tubing is
set above a 4-1/2” production liner: this completion will tolerate scale build up in
the tubing while still facilitating full bore access to the production liner. In the 3-
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1/2” monobore completion, all scale build up would have to be removed from the
entire production tubing to allow full bore access to the production liner.
2.8.6
•
The limited operating history of 3-1/2” monobore tools is an issue. An extensive
favourable operating history for 4-1/2”, 5” and 5-1/2” monobore operating tools is
available. Indicators are that the 3-1/2” tools will perform favourably but operating
experience is required.
•
Slip damage to the production liner arising from use of monobore tools can act as a
point of initiation for corrosion. The consequence of slip damage initiated corrosion
in and adjacent to the productive interval is probably not an issue but is a concern in
the liner section above the producing interval.
•
In the case of a 3-1/2” liner, flow velocities while producing and subsequent to
perforating underbalanced may inadvertently lift tools. In most cases, it is expected
that this can be managed with appropriate job planning but tool lifting by flow must
be recognised as a potential hazard.
•
In the event of a poor primary cement job, remedial cementing in a 3-1/2”
production liner is expected to be difficult.
Examples
In the Middle East, several high capacity, high pressure gas wells have been completed
using a 7 inch monobore completion. Initial completions were sized to provide 75
MMCFD for the 25 year contract period with a design capacity of 125 MMCFD. The
operator chose the monobore for simplicity, reservoir control and monitoring, stimulation
effectiveness, and high rate capacity.
Shell, in the North Sea, have adopted the 3-1/2 inch monobore completion as their base
case for all new wells. They site the following reasons:
2.9
−
3-1/2 inch production tubing is typically suited for wells with oil production rates of
3000 to 5000 BOPD or gas production rates of 50 MMCFD or less.
−
3-1/2 inch production tubing can be run inside of 5 inch and 5-1/2 inch production
casing. A 3-1/2 inch liner is complementary to the 4-1/8 inch and 4-3/4 inch slim hole.
SPLITTER WELLS
The Twin Wellhead System, also known as Twin Monobore Wellhead System or Surface
Splitter Wellhead System has been pioneered and used by PCSB in East Malaysia. The
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systems allow more than one well to be drilled, cased and completed from a wellbore
while maintaining full access to each well.
Two or three wells can be drilled from one platform slot or surface location using this
design, and it is ideal for multiple horizontal or vertical wells. Once completed, wells can
be independently produced, serviced and worked over.
When an operator decides to develop additional reserves from an existing field
infrastructure there are normally six (6) alternatives to consider. These are as follows :
•
Adding more slots on the platform
•
Downhole splitter systems
•
Surface splitter systems
•
Subsea wells
•
Multi-lateral wells
•
Conductor sharing
Two systems currently exist that we can use to achieve drilling two or more wells in one
slot. In the case of a Surface Splitter System wells are kicked-off immediately below the
conductor pipe. Beyond the 36-in conductors, wells feature 13-3/8-in surface pipe and 95/8-in production casing. Beyond that wells can have an 8-1/2-in diameter horizontal hole
which may be lined or completed openhole. The Downhole Splitter System utilizes a
splitter which can be run on the bottom of the surface or intermediate casing strings. The
dual bore head can suspend two 9-5/8-in casing strings which will accommodate standard
7, 5-1/2, 5 or 3-1/2-in liner systems after being drilled out.
The wellheads are a “major project aspect” for a splitter wells. The close proximity of the
wellheads requires them to be staggered vertically such that larger diameter components
are not at the same level. On occasion, orientation of the trees may have to be changed to
avoid clashing with existing steelwork or impinging on walkways. Valves also have to be
located at a workable height. Stack-up tests prevent difficulty in assembling and testing
the systems onsite.
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Figure 15 Triple Splitter Well at BODP-C, East Malaysia
Figure 16. Plan view of Triple Wellhead at BODP-C, East Malaysia
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Figure 17. Elevation view of Splitter Wellhead and Tree
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Figure 18. Downhole Splitter Configuration
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2.10
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SUBSEA COMPLETIONS
A subsea completion is one which the wellhead and christmas tree are located on the sea
floor. This is in contrast to offshore wells completed on platforms or floating facilities,
where wellheads and trees are above the water. From a completions standpoint, subsea
wells present a number of challenges relating to wellhead accessibility, fluid production,
well maintenance and equipment realiability.
(Statistical information in this section is gathered primarily from R. L. Hansen’s and W. P.
Rickey’s paper SPE 29084, Evolution of Subsea Production Systems : A Worldwide
Overview, (JPT, August 1995).)
More than 750 subsea completions had been installed in various parts of the world by the
end of 1993. While the majority of these wells lie in less than 600 ft (183 m) of water, a
substantial number—more than 60—have been completed in water depths exceeding 1000
ft (305 m). In the Campos Basin of Brazil, maximum water depth has reached 3369 ft
(1027 m).
Subsea wells can be located long distances from a main platform or other host facility,
beyond those attainable by extended-reach drilling. In the North Sea, maximum distances
are 30 miles (48.3 km) for a gas reservoir and 12 miles (19.3 km) for an oil reservoir.
Although most subsea wells have produced by natural flow, artificial lift methods are
becoming more common, along with the use of water injection to maintain reservoir
pressure.
These wells employ a variety of production configurations, including single satellite wells
consisting of wellhead assemblies on individual guide bases; steel template structures with
production manifolds; and clustered well systems (i.e., single satellite wells connected to a
subsea manifold).
Installing subsea completions can be cheaper than drilling highly deviated platform wells,
and more economical than constructing additional surface facilities. They do, however,
have a number of drawbacks and limitations. For example, in long flowlines, substantial
pressure losses can occur between the well and the host facility. Also, the cooling effects
of seawater can result in poor oil flow properties and gas hydrate formation. Most
important, well maintenance and workover costs are high because wells are not easily
accessible—rig work requires moving in a floating drilling unit or jackup. Subsea wells
thus require extensive, careful planning to ensure adequate equipment and operational
reliability in the harsh sea floor environment.
Historically, the main problem in servicing subsea completions has been the subsurface
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safety valve (SSSV). Two developments that considerably ease this problem are the
availability of long-service-life tubing retrievable subsurface safety valves (TRSSSV) and
accessories, and through flow line (TFL) servicing.
TFL servicing involves the modification of wireline tools so that they can be pumped into
the tubing via the flow line. Rather than manipulating the tools via a wireline, operations
of the tool string can be performed by varying the pump pressure on the tools after they are
pumped down the well. The main requirement for this type of well servicing is two
conduits (either two tubing strings or a tubing and annulus). Special tools are required
since they must be able to pass through a 5 ft (1.5 m) radius bend at the well-head.
Surface facilities must also be designed to conform to these specifications.
Although the year-round service capability afforded by TFL completions is obviously
highly attractive for severe environmental conditions, the consequences in terms of rate
restrictions, cost, and operational complexity should not be underestimated. A popular
alternative to TFL is to design a well completion with redundancy (e.g., install two
subsurface safety valves and anticipate frequent servicing). Wireline operations from
workboats have also proven successful in shallow water (100-300 ft, or 30-90 m depth).
2.11
SMART WELLS
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Introduction
During the 1980s, many operators installed pressure and temperature instruments
downhole to gather real-time production data. These data provided valuable information
concerning how to produce the target zones more effectively. More recently, the industry
has favored installations that have remotely operated controls placed in the well. Sensor
requirements have now extended beyond just pressure and temperature to include flow
rates, fluid composition, reservoir characteristics, etc. A well that has a system of
downhole sensors and controls, and that includes a surface system to collect and transmit
the production data to a remote facility for analysis, has been dubbed a “smart” well.
The most significant benefit that a “smart” well will provide is improved economics. The
ability to sense the production processes and react to changing conditions to continuously
optimize production will result in improved production and recoverable reserves. In
addition, properly designed systems should reduce the operating expenses in a typical
installation. Reduced capital expenses may also be realized when, for instance, a system is
fielded that separates and reinjects the produced water downhole.
Imaginative solutions to commonplace production situations are being contemplated, and
the technology to address these issues is under development. Some basic system designs
will be necessary before any systems are used.
2.11.2
System Components
The subsystems that comprise a “smart” well include a telemetry system for conveying
data to and from the surface, downhole sensors for collecting the desired parameters in the
well, controls to reconfigure the downhole tools, and a surface subsystem. The surface
subsystem includes a data collection terminal, software to analyze the data and make
decisions based on the output, and some means of transmitting this data to a remote
facility, if required. These systems are shown in Figure 19.
2.11.3
Telemetry
Most operators equate telemetry with a wireless system, but such systems may not be used
in the earliest of “smart” wells. The technologies that are currently available are limited in
various installations for specific reasons such as conductivity of the formation, variation in
fluid properties, and noise either from surface facilities or from the flow in the well.
Therefore, the proven hardwired telemetry system will most probably be the first
technology deployed in a “smart” well.
The telemetry system may need to transmit some considerable data streams depending on
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the needs of a particular well. For instance, if a well is equipped with 3D reservoir sensors
that visualize the movement of oil, water, and gas near the wellbore, some significant data
rates will be needed in the telemetry system. In the event of a multilateral or multizonal
completion with multiple flow controls installed, the need for operational process data
may exceed all other data. Since the well-control signals will be transmitted from the
surface downhole, the telemetry system plays a very important role in the “smart” well.
Figure 19. Typical “smart well
2.11.4
Downhole Sensors
A “smart” well must control production procedures. Therefore, sensors that provide
information about the flowing conditions downhole will be important. Although the
pressure and temperature instruments that were previously used are now more accurate
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and reliable, sensors will also be needed to determine multiphase flowing conditions and
the rates and volumes of the flowstream constituent.
A major change in data retrieval has recently been introduced with the use of fiber-optic
sensors in wells. These sensors use changes in the properties of the fiber to provide
temperature and pressure profiles downhole. Optical energy is reflected from the point in
the fiber where a temperature or pressure change has altered the optical properties of the
fiber, giving the desired profile information.
Microelectronic technology from the medical and defense industries now allows the oil
industry to assess fluid viscosity, composition, and density reliably and continuously both
inside the wellbore and in the reservoir adjacent to the wellbore.
The “smart” well of the future will contain numerous sensors that will relay information
about the reservoir, the fluids around the wellbore, and the produced fluids in the
wellbore. Sensors will combine with well controls to mitigate or prevent adverse
producing situations. For example, downhole sensors may detect the formation of scale;
there may be controls built into the completion that will remove the scale and change the
flowing conditions that caused it to form initially.
Current geophysical research is determining the interpretation problems associated with
gathering between well seismic data to provide a real-time 3D seismic within the reservoir.
With such a capability, a reservoir management team could image reservoir features such
as channels, faults, and fractures; they could also “listen” to flood front movement within
the reservoir.
2.11.5
Controls
Before the data from wellbore sensors can be used to alter the producing scheme, remotely
controlled downhole flow devices must be developed. A number of flow control devices
exist that are now manipulated by wireline or hydraulic systems. The simplest of these is
the downhole choke, which can be used between packers to regulate flow from a particular
reservoir.
Used in the industry for more than 30 years, downhole chokes are the most direct means of
controlling flow downhole. However, the existing chokes require intervention to extract
and/or insert the flow control. The “smart” choke will be remotely operable, which
represents a major improvement over existing completion methods.
Remote actuation of the controls is an entirely new subject. Hydraulics have dominated
this industry because of the high force capabilities and the robustness of the tools.
However, recent advances in the areas of electromechanical actuation may change the
technology used downhole.
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More sophisticated downhole systems may also be necessary. For example, downhole
separation is already being evaluated in field trials. When used with ESPs, this technology
offers the prospect of avoiding the production of unwanted water or gas to surface with
some method whereby the water or gas is injected either for reservoir pressure
maintenance or into a disposal reservoir. Electronically operated gas-lift valves are
another example of developments being under-taken in this area.
The surface system will typically include a computer that can collect and store production
data, a software package that analyzes this data and helps users decide how the controls
should be configured, and a telemetry system for transmitting this data to a remote
terminal should it be required. Currently, a number of software packages are used for this
task. In some cases, this software will function adequately; however it is currently
considered a growth technology.
2.11.6
Reservoir Management with Smart Wells
Smart well technologies will provide changes in reservoir management. The variety and
type of information available continuously throughout field life will be greatly enhanced.
Both in-well data (pressure, temperature, viscosity, and compositional profiles) and
between well data (seismic, passive listening) will provide greater reservoir
characterization. These enhancements will combine to advance reservoir management
toward precise mapping of fluid fronts and reservoir properties throughout the reservoir.
Most likely, reservoirs will be divided into discrete management intervals in the future.
Systems and technologies will be developed to control that part of the reservoir with which
they are in contact. Therefore, if more reservoir is contacted, greater control can be
achieved, and potentially greater reserves can be accessed.
Horizontal wells will benefit from smart well technology that can penetrate multiple
fractures and isolate reservoir compartments. Reduced drawdown in horizontal wells may
help eliminate unwanted water or gas influx. The capability to control production from
such wells in a series of management intervals further increases their utility.
Multilaterals also offer significant reservoir management potential with smart well
technology. Multilaterals enable a single wellbore to be used (1) for concurrently
producing reserves from low-permeability areas of a heterogeneous reservoir, (2) to access
multiple high-productivity fractures, (3) to access different reservoirs from the same
wellbore, or (4) to better manage injection for pressure maintenance. Flow control in
multilateral wells is critical to their success. Smart well technology will maximize
production from such completions.
Current projections for increased production and recoverable reserves that are directly
attributable to “smart” systems is approximately 10 to 15%, but increases could be greater.
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In addition, this technology may make marginal field developments viable.
The facility to receive continuous in-well and between well data, interpret these data, and
remotely control or reconfigure the completion accordingly, is a fundamental change in
current completion technology. These advances will enable new reservoir management
schemes that can allow engineers to continuously characterize and monitor reservoir
behavior, improve recovery, and enhance field economics.
2.12
SELECTING A COMPLETION TYPE
2.12.1
Reservoir Drive Mechanism
The reservoir drive mechanism and the well’s location within the reservoir can play an
important role in determining the completion type. For example, a primary concern should
be the production of water in a water-drive reservoir. In many wells, which produce with
bottom-water drive, it will be necessary to seal the portion of the well that is making the
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water, and cased-hole completions favor this operation. On the other hand, if the reservoir
has a flank water-drive mechanism, the wells in the central portion of the field may see
little or no water until very late in the life field. Hence these wells might be open-hole
candidates while the wells on the flanks would probably be cased-hole producers.
Similar arguments exist for gas-cap drive reservoirs. In this case, an expanding gas cap
may eventually move into the completion interval. Hence, the cased completion would be
favored because the upper section could be squeezed while production was taken from the
lower perforations. For an open-hole completion this option would not exist.
The reservoir drive mechanism also strongly influences the tubular sizing. The tubular
program must consider the possible production of water and the effects of declining
reservoir pressure. This will in turn affect the need for artificial lift, and the final
completion type. For instance, there is no sense running 3-1/2-in. tubingless completion if
a large diameter downhole pump will eventually be required. This is only one of many
possible considerations.
2.12.2
Reservoir Extent
The amount of recoverable reserves may also affect the completion type. For example,
there is a little incentive to accelerate production with a dual completion if one or more of
the zones has a limited amount of time before it will be depleted. It would probably be
better to complete as a single completion and recomplete as necessary.
As mentioned previously, tubingless completions can have applicability if the reservoir is
expected to be drained in a relatively short period of time (and corrosion problems are not
expected to develop). These are only two of many possible examples of the effect of
reservoir extent.
2.12.3
Number Of Reservoirs
If a large number of separate reservoirs are intersected by the wellbore, then a multiple
completion scheme may be the optimum solution, depending on a number of other factors
such as the estimated reserves in each zone.
However, there are many occasions when a single completion is preferred even though a
number of reservoirs exist. If this is the case, the completion will be cased hole so that
each zone may be produced separately. It is a good idea to design the completion for ease
of concentric workovers so that the well may re-completed as economically as possible.
2.12.4
Well Location
By “well location” we are referring to the physical location of the wellhead (i.e., offshore,
inland waters, onshore, etc.). This is important for two reasons. First, running dual
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completions in preference to singles can result in a large cost saving if less wells need to
be drilled. If an additional platform can be eliminated, then the cost savings are very large
indeed.
The second impact well location has on completion type is the generally higher workover
costs associated with offshore operations. Thus, offshore completions tend to emphasize
reliability, even at the expense of higher capital expenditures. Thus, multiple completions
on the one hand are desirable in an offshore situation because they can reduce the number
of wellbores required, yet at the same time, the higher workover costs of a dual completion
leads in the opposite direction. The final resolution strongly depends on local
circumstances.
2.12.5
Enhanced Recovery
Secondary recovery projects, whether they be CO2 injection, waterflooding, or other
techniques, almost always work best with cased-hole completions, since many secondary
recovery operations periodically require diversion techniques to inject materials which
are intended to move oil to neighboring wells.
With a perforated cased hole completion, diversion can be accomplished with ball
sealers, isolation packers, squeeze cement, etc. With an open hole completion, about the
only choice available is particulate diverting agents, which are not as effective as the
former techniques.
Tertiary recovery projects such as steam stimulation and fireflooding also impose
restrictions on the completion. Again, these are usually cased hole completions, for the
same reasons as outlined above. In addition, the high temperatures involved dictate that
special elastomers and cement formulations be used.
2.12.6
Stimulation Needs
As with enhanced recovery, successful stimulation requires the ability to effectively divert
the stimulating fluids. For this reason, cased hole completions are usually preferred if
stimulation efforts are to be required.
Attempts have been made to stimulate open-hole sections, most notably across prolific
carbonate horizons in Saudi Arabia, by reciprocating coiled tubing across the interval.
While this at least places live acid in front of the formation, it is not known whether the
fluid is effectively diverted into the formation by this technique.
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Sand Production
Both cased-hole and open-hole completions can be gravel packed successfully, so that
sand production does not affect whether a cased-hole or open-hole completion is selected.
However, sand production problems can affect whether a single or dual completion is run.
In general, dual gravel packs are a complicated arrangement. If they are attempted, the
completion is said to be “piggy-backed”. An example of such a completion is shown in
Figure 20. Tubingless wells, because of their small diameter, should not be run if a gravel
pack will be required. For thin intervals, plastic consolidation has been used effectively.
Many wells in the Gulf of Mexico are dual tubingless completions with sand control
effected by plastic consolidation. This has allowed recovery from many zones, which
probably could not have been economically, exploited using a gravel-packed completion.
2.12.8
Permanent Downhole Monitoring Sytems
A total of 952 pressure and temperature monitoring systems have been installed since
1987. For systems installed in the period 1987-88, the five-year survival probability was
40%. This improved to 75% survival for systems installed in the period 1991-92. Beyond
1992, no further improvements have been observed, resulting in a five-year survival
probability of 69% for the period 1993-98. This section contains a description of
permanent downhole gauge (PDG) systems and their components.
PDG systems have been installed in several hundred oil and gas wells. These systems
form an alternative to wireline-conveyed downhole surveys. In comparison, PDG systems
avoid hazardous operations and offer continuous measurements, which enable better
reservoir management and production optimization. Pressure and temperature (p,T)
monitoring systems that use electricity are the most common. Other systems that have
been installed are :
•
Permanent downhole flowmeters for liquid-only mixtures
•
PDG systems in ESP-lifted wells that use ESP power cable for data transmission
•
The Fiber-Optic Well Monitoring system for measuring pressure and temperature
and the Fiber-Optic Distributed Temperature Systems for measuring temperature
profiles
•
The Tucatran system for cableless communication
•
The SCRAMS system
The installation of electric-gaslift valves, all-electric inflow control devices and reservoir
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monitoring systems are planned in the near future. When these systems are available, the
so-called “intelligent well” concept, which can be defined as a modular combination of
downhole monitoring and control systems, will become a reality.
For all these systems, reliability is key. PCSB’s targets are : a 90% probability to survive
five years for monitoring systems and a 90% probability to survive 10 years for actuators.
Figure 20. Dual “Piggyback” Gravel-Pack
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Figure 21. Schematic of a subsea PDG system. The sensing element is an electronic
gauge, mounted in a mandrel that forms part of the tubing string; it measures pressure
and temperature within the tubing. The cablehead forms the top of the gauge and is
connected to the metal-sheathed electrical cable that runs along the tubing to the hanger.
A schematic of an electrical PDG system for pressure and temperature measurement is
depicted in Figure 21. The electric cable is coaxial, comprising an insulated monoconductor encapsulated in a metal sheath. In most cases, the sheath is encapsulated in
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thermoplastic to prevent damage during installation. The cable is supported by protectors
at all tubing joints. These hold the cable in place and protect it across the couplings where
the cable is most vulnerable to crushing.
The wellhead outlet differs on subsea and platform/land wellheads, resulting in different
installations. For a land or platform system, the cable is normally fed through the tubing
hanger, with compression fittings at the top and bottom, and fed out of the tree through a
downhole safety-valve-line port or a flanged outlet. Immediately outside the tree, the
cable is terminated in a connector, from which an instrument cable runs to the surface
acquisition unit.
For subsea installations, wet-connectors are used between the hanger and the tree (Figure
21) and between the hanger and the tree and either the control pod, a control lone in the
umbilical or an acoustic telemetry system.
Data from the PDG are usually fed into a computer system via an interface unit.
2.13
SPOOLABLE COMPLETIONS
When operators in Prudhoe Bay wanted to revive declining production in a well in the
Western Operating Area, they evaluated several completion methods, including traditional
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workover rig completion. Then they installed the world’s first Spoolable CT gas lift
string.
Four Spoolable gas lift valves were spaced over 10,076 feet of 2-3/8” x. 156” CT and hung
from the surface inside existing production tubing. The string was stung into the wirelineset bottom hole assembly located in the original completion’s 4-1/2” tail pipe. Camco’s
Spoolable safety valve was not yet available, so the well was regulated by a wirelineretrievable subsurface-controlled safety valve in a standard “D” type landing nipple at
2,000 feet. Refer to completion schematic, Figure 22.
Prior to the Spoolable completion, the well was not capable of stable flow. Today it is
producing 850 bbl/day of liquid at a gas injection rate of 1.2 MMSCF/day. Actual cost for
the tubing workover was only 40% of the estimated cost of a conventional workover.
2.13.1
Candidate Selection
The best candidate wells for SPOOLABLE completions are operated:
2.13.2
o
In areas where the operating cost of coiled tubing units is much less than that of
traditional rigs (e.g. offshore);
o
Offshore, on platforms with at least 25 ton load bearing capabilities, cranes that
can lift 15 tons and have 1,500 ft2 of deck space. (These figures vary significantly
with tubing size and length). Many more platforms can be serviced, at extra cost,
from jack up barges or service boats;
o
In areas where gas lift equipment or safety valves or both are used;
o
By producers who are already using coiled tubing units for other purposes;
o
By producers who have many marginal wells (and, therefore, a potentially high
payoff for risking a trial and taking the time to learn how to install SPOOLABLE
completions);
o
By producers who are innovators (e.g. have high asperations, have financial
strength, are well educated, and remain alert for new developments).
Coiled Tubing Material
The coiled tubing used in the majority of completions was ASTM A-606 Type 4 Modified
coiled tubing steel. Tensile and yield strength for the steel was 80,000 and 70,000 psi,
minimum, respectively.
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Recent developments of advanced-composite spoolable tubing offers several new solutions
to many challenging oilfield operations. Such attributes as excellent corosion resistance
and low material density and weight, coupled with high working-pressure rating and
extensive fatigue resistance, make these products attractive for a number of oilfield tubular
applications, including well-servicing strings and corrosion-resistant completion strings.
Advanced-composite spoolable pipe can be “engineered” for particular applications to take
advantage of the composite’s attributes while optimizing cost.
Recent activity has focused on gaining a full understanding of performance characteristics
of compositetube technology, particularly under complex loading conditions, and
evolution of standard products and standard qualification tests that provide a wide margin
of safety and cost-effective life under normal operating conditions. Various advancedcomposite-tubular and connector-product designs have been tested extensively to
determine their operating characteristics and to improve their performance. These
extensive tests have led to a line of standardized products developed for the well-servicing
and production-tubing/permanent-installation include 2-3/8-in. CT, 2-in. production
tubing, 1½-in. velocity string, and 1½-in. CT, each with a thermoplastic liner, fiber/epoxy
matrix, and exterior fiber protective layer.
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Figure 22. Spoolable Coiled Tubing Completion
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CHAPTER 3
COMPLETION DESIGN CRITERIA
TABLE OF CONTENTS
3.1
INTRODUCTION ……………………………………………………………….…. 2
3.1.1
3.1.2
3.1.3
3.2
4
4
5
5
Reservoir Properties …………………………………………………
Production Requirements ……………………………………………
Future Operations ……………………………………………………
Intangibles …………………………………………………………...
6
7
8
9
COMPLETION DESIGN PROCEDURE …………………………….…………. 10
3.4.1
3.4.2
3.4.3
3.4.4
3.4.5
3.4.6
3.4.7
3.4.8
3.5
Completion Interval ………………………………………………….
Tubing Diameter …………………………………………………….
Tubing-Casing Configuration ……………………………………….
Completion Equipment ……………………………………………...
FACTORS AFFECTING COMPLETION DESIGN …………………………..... 6
3.3.1
3.3.2
3.3.3
3.3.4
3.4
2
2
2
BASIC DECISIONS IN COMPLETION DESIGN ……………………………… 4
3.2.1
3.2.2
3.2.3
3.2.4
3.3
Purpose ………………………………………………………………
Importance Of Completion Design ………………………………….
Completion Objectives ………………………………………………
Size Tubing …………………………………………………………. 10
Select Packer ………………………………………………………... 10
Calculate Tubing Loads …………………………………………….. 12
Specify Completion Equipment …………………………………….. 12
Select Perforating Technique ……………………………………….. 12
Consider Artificial Lift ……………………………………………… 13
Allow For Stimulation ……………………………………………… 13
Provide Ease Of Workovers ………………………………………… 13
INHOUSE COMPUTER PROGRAM USED TO AID IN WELL DESIGN ..… 10
DRILLING DEPARTMENT
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3.1
INTRODUCTION
3.1.1
Purpose
The purpose of this Chapter is to acquaint the engineer with the basic factors, which need to
be considered when designing the “inner portion” of a well completion. By “inner portion”
we mean the items of the completion, which are run inside the production casing. This is in
contrast to Chapter 2, “Types of Well Completions”, which outlined the considerations for
selecting the broader aspects of completion design, such as whether the well should be
cased or open hole, single or dual completion, etc.
Subsequent chapters will deal with specific aspects of completion design in greater detail.
3.1.2
Importance Of Completion Design
The importance of a good completion design cannot be overstressed. With drilling costs
routinely exceeding several million dollars for many wells, it is imperative that the
completion be sound. In addition, the ability to perform future operations on a well, such as
gas lift, hydraulic fracturing, or water injection, will depend on the care and planning taken
in the initial completion design.
3.1.3
Completion Objectives
A basic well completion has the following objectives :
•
Production - The completion should be designed to handle the anticipated production
rate. In most cases, the production rate is determined by the flow capacity of the
reservoir, although there may be instances where other considerations, such as sales
contracts or pipeline capacity, dictate the production rate.
•
Safety - Paramount in every aspect of completion design is safety. The completion
must be strong enough to withstand all the forces that can occur during the life of the
well since the completion string is the primary mechanism for containing reservoir
pressure.
•
Profit - Without profit there is no incentive to complete the well, so we must ensure
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that the completion design is profitable as well as safe. As a general rule, profitability
is usually enhanced by selecting the simplest completion design possible. Fortunately,
this generally enhances the safety of the completion as well.
•
3.2
Government Regulation - Care must be taken to ensure compliance with any
applicable government regulations. These laws generally pertain to the protection of
the environment, protection of fresh water sands from contamination, and the
“efficient” depletion of the various reservoirs.
BASIC DECISIONS IN COMPLETION DESIGN
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The following discussion summarizes the fundamental decisions to be made when
designing a well completion. These considerations include :
•
Completion Interval : Where is it? What is it near?
•
Tubing Diameter : What size is required for a given production rate?
•
Tubing - Casing Configuration : Is the completion open or cased hole? Single or
multiple? Where is the tubing in relation to the productive zone?
•
Completion Equipment : What are the reasons for running completion equipment?
Design considerations for the actual selection of tubing and hardware will be discussed
later in the section.
3.2.1
Completion Interval
The first question to be addressed in the completion design is the selection of the
completion interval. This is a decision which requires input from a number of sources
including the reservoir engineer, the geologist, a well log specialist, and the completion
engineer. The completion engineer needs to consider such factors as the effect of the
perforation strategy on future stimulation requirements and the effect of interval length on
future workover plans. If the well has a number of zones to be sequentially produced, then
the completion engineer should be consulted to determine the order in which the zones will
be produced, always considering factors to minimize future workover and recompletion
costs.
3.2.2
Tubing Diameter
The required tubing string diameter is the next decision which needs to be made. The
tubing diameter is usually based on deliverability calculations which show the relationship
between reservoir pressure, flowing bottom hole and surface pressures, and flow rate for a
given tubing size. From these calculations, an appropriate tubing size can be determined.
3.2.3
The required tubing diameter can sometimes dictate the type of completion to be used. For
example, if calculations show that 5-1/2 in. or 7-in. tubing is required, it is safe to assume
that a single completion will be run due t space limitations. Likewise, deliverability
calculations may show the need for artificial lift, and the completion can be designed
accordingly.
Tubing-Casing Configuration
Tubing-casing configuration refers to the relationship between the tubing, the casing, and
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the productive zone. One aspect of this relationship is covered in Chapter 2, “Types of
Well Completions”, where open-hole versus cased-hole completions are discussed. In
addition to this, questions such as whether the tubing is to be run open-ended or with a
packer and where the tubing will be set relative to the reservoir need to be answered. This
is particularly important in wells that could be candidates for a PBR (polished bore
receptacle) completion, since the PBR needs to be run with the casing or liner and hence
becomes part of the drilling program.
3.2.4
Completion Equipment
Once the tubing string has been designed and the tubing-casing configuration established, it
is necessary to specify the remaining pieces of completion equipment which will be
required. The downhole completion equipment is run for the following basic reasons :
3.3
•
To improve flow performance (packer, gas-lift mandrels, pump seating nipple)
•
To increase the safety of the completion (packers, subsurface safety valves, flow
couplings)
•
To increase completion flexibility (landing nipples, communication devices)
FACTORS AFFECTING COMPLETION DESIGN
This subject is a review of the primary factors which can affect the completion design. The
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material is broken down into the following categories :
•
Reservoir Properties
•
Production Requirements
•
Future Operations
•
Intangibles
Specific items within each category are discussed below.
3.3.1
Reservoir Properties
One of the major determining factors in completion design is the reservoir itself. The
characteristics of the produced fluids influences the type of completion that will be
necessary for safe and efficient operations. For example, the completion will certainly be
different for a 3,000 ft low pressure oil well than for a 25,000 ft high pressure sour gas
well. Some individual reservoir parameters which affect the completion design are :
•
Pressure - Pressure sets a minimum strength requirement for the tubular goods. Thus,
design of the tubing string is begun by selecting weights and grades of tubing (for a
given size) that will satisfy wellbore pressure requirements.
•
Temperature - The reservoir temperature affects the selection of materials for the
completion. For example, special elastomers for the packer seals are required in very
high temperature wells. Temperature also plays a role in the nature and rate of
corrosion problems.
•
Depth - The depth of the well influences many areas of the completion design. One
influence is the strength of materials (pipe and connections) necessary to withstand the
tensile forces of a long tubular string suspended from the surface. The ability to do
wireline operations also decreases quickly beyond a certain depth. The ability to work
over a well, with coiled tubing in particular, is also limited by depth.
•
Deviation – The wellbore deviation plays a critical role in determining the amount of
downhole manipulation of packers and completion (i.e., wireline) equipment that can
be obtained. Thus, in highly deviated wells, the completion equipment should be
designed to require as little manipulation as possible.
•
kh - The kh of the well, its permeability thickness product, is a partial measure of the
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well’s flow capability. Taken in conjunction with the reservoir pressure, kh can be
used to estimate the volume of fluids that could be produced through different sizes of
tubing. These fluid volume estimates are a primary input to tubing string design.
3.3.2
•
Corrosiveness - The corrosive nature of the fluids impacts both material selection and
the need for chemical corrosion inhibition.
•
Reserves - The expected lifetime of the well is important to the completion design
because it influences the amount of durability and reliability which needs to be built
into the completion. In addition, the amount of money spent on a completion is
sometimes influenced by the amount of recoverable reserves, especially when the
reserves are limited.
Production Requirements
Production requirements are dictated by sales contracts or surface facilities considerations
can sometimes be important to the overall well completion. Some of these considerations
(rate, pressure, temperature) are discussed below.
3.3.3
•
Rate - The required production rate influences the size of the tubulars needed. The
production rate is normally governed by the reservoir deliverability. However,
occasionally a required rate will be dictated by an outside factor such as sales
contracts or processing plant requirements.
•
Flowing Wellhead Pressure (FWHP) - Sometimes a minimum FWHP will be set for
a well. For example, the pressure limit can be the pressure necessary to flow the
produced fluids through the pipeline without compression or it can be the working
pressure of the first stage separator. The tubular program and/or artificial lift program
is then designed to meet such requirements.
•
Flowing Wellhead Temperature (FWHT) -While not usually an important factor in
determining the completion design, FWHT can become important for wells which
have paraffin or asphaltene deposition problems. For these wells, maintenance of a
high FWHT may prevent the deposition from occurring, thereby alleviating the need
for other types of corrective action.
Future Operations
In addition to reservoir and production requirements, a host of future operations need to be
considered. The future operations that are deemed important will strongly depend on local
factors. Presented below are a few of the more universal considerations accounted for in
most producing areas of the world.
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•
Production Trends - The completion may need to account for possible increases in
the gas/oil or water/oil ratio over a period of time. Declining reservoir pressure is
another important consideration. Knowledge of the reservoir drive mechanism and the
well’s location within the structure can sometimes give clues to possible future trends.
•
Secondary Recovery - Wells initially completed for production of warm oil or gas
may be subjected to injection of cool fluids in enhanced recovery operations. In many
cases a standard completion suitable for production will not be acceptable for
injection. However, careful planning can sometimes result in a completion suitable
for both, eliminating the need for a workover to convert from a production to an
injection mode.
•
Stimulation - Consideration must be given to possible stimulation operations and
attendant completion requirements. For example, the following questions should be
asked :
1.
What are the pressure requirements of the job?
2.
Are the various pieces of the downhole assembly compatible with
injection?
3.
Is the perforated interval suitable for stimulation?
The completion must be designed to satisfactorily meet these questions.
•
3.3.4
Sand Control - The need for sand control should be assessed during the initial
completion design. This is particularly true if (a) a tubingless completion is being
considered, or (b) the sand producing zone is the upper zone of a dual completion. In
the former, mechanical sand control efforts have proven to be unsuccessful due to the
very small clearances between tubing and screen. In the latter case, sand production
from the upper zone of a conventional dual completion can result in sand fill around
the tubing, causing it to become stuck In the hole.
Intangibles
Other factors affecting completion design must be taken into account which do not fit into
rigidly defined categories. These include :
•
Safety - The proposed well completion must be safe so that people’s lives are not
endangered. It must also be able to protect the environment from damage in case of
loss of control of the well. Great care must be exercised in completion efforts for
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wells containing H2S, since this gas is extremely poisonous in even small quantities.
The method by which the well is perforated needs to be thoroughly reviewed to ensure
a safe operation throughout.
•
Well Location - The well location can affect the completion design in a number of
ways.
Remote locations often result in high workover costs due to logistical problems of
mobilizing a rig, materials, etc. When this is the case, the completion is usually designed to
minimize future planned workovers.
Populated areas usually dictate that extra safety precautions be taken. This includes
installation of a subsurface safety valve and redundancy in the wellhead master valve
arrangement.
Finally, offshore wells have their own special design considerations. Workover costs tend
to be high and government regulations as well as prudent operating practices require the use
of subsurface safety valves. Equipment reliability therefore becomes an important factor in
offshore well completion design.
•
3.4
Local Personnel – Local experience can sometimes be an important factor in
completion design. The degree to which local service companies are able to perform
certain operations (concentric workovers, complex dual gravel packs) may influence
the completion design.
COMPLETION DESIGN PROCEDURE
A summary of the main tasks which need to be performed when designing a completion
(see completion schematic, Figure 1) is given below. This list is not intended to cover
every detail of completion design but rather to highlight major points which must be
completed.
The major tasks to be performed are to :
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•
Size Tubing
•
Select Packer
•
Calculate Tubing Loads
•
Select Completion Equipment
•
Specify Perforating Technique
•
Allow for Artificial Lift, if required
•
Provide Ability to Perform Future Workovers
Size Tubing
The first task is to size the tubing string for its production requirements. Tubing is sized by
calculating possible production rates and wellhead pressures for different sized tubing
strings and then selecting the size that best meets the production requirements. This step
must be done first because the rest of the well, from the casing program down to the size of
the landing nipples, will be affected by the tubing size chosen.
3.4.2
Select Packer
The next step is to decide whether to use a packer and, if so, what type. Basically, there are
three broad choices for a packer :
•
Permanent -set on wireline and removed from the hole by milling operations
•
Retrievable – set on tubing and designed to be retrieved with the tubing string
•
Polished Bore Receptable (PBR) – a specially honed sealing nipple run as part of the
casing string or liner
In general, permanent packers are typically run in deep wells, wells which produce
corrosive fluids, and wells with very high pressure. Retrievable packers have been used in
shallow wells, gas lift wells, and in injection wells such as water flooding and steam
injection.
The PBR eliminates the need for a permanent packer but permanently fixes the sealing
location for the tubing within the wellbore.
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Figure 1. Typical Completion Schematic
3.4.3
Calculate Tubing Loads
After the tubing size is determined and a packer tentatively selected, the forces acting on
the proposed completion are calculated. In general, the static loads existing during initial
completion are calculated first. Then the loads created by production and/or stimulation are
calculated. If the calculated loads are excessive, the completion design is modified to
reduce the loads to acceptable levels. Tubing loads and movements are covered in detail in
Chapter 6, “Tubulars”.
3.4.4
Specify Completion Equipment
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The completion equipment for the well should be specified early in the design process,
especially if special materials are to be used. A standard completion usually includes, in
addition to a packer, one or more landing nipples, a wireline re-entry guide, and possibly a
sliding sleeve or side-pocket mandrel. Chapter 22, “Wireline Operations” will explain
completion equipment in greater detail.
3.4.5
Select Perforating Technique
The completion design should be compatible with the perforating method selected. In
general there are three basic perforating options available, namely :
•
With through-tubing guns, underbalanced
•
With casing sized guns, overbalanced
•
With tubing-conveyed guns, underbalanced.
With the first choice, the completion must be designed with sufficient dimensions to allow
passage of the perforating gun.
No special completion arrangements are required for the second choice, perforating with
casing guns. Caution must be taken, however, to ensure an adequate fluid density in the
hole during the perforating process.
Tubing-conveyed perforating guns (the third option) are a relatively new development
which attempt to combine the advantages of perforating with differential pressure into the
wellbore (“underbalanced”) while using large perforating guns (as in overbalanced
perforating).
This is accomplished by connecting large perforating guns to the bottom of the tubing
string, below the packer. Then, the guns are fired by a detonating bar or by some other
means. Because production commences as soon as the well is perforated, the bottom-hole
perforating assembly must not interfere with planned future workovers. It is the
responsibility of the completion engineer to ensure compatibility between this perforating
method and future operations.
3.4.6
Consider Artificial Lift
If artificial lift is deemed necessary, either upon initial completion or at some future date,
then the completion needs to be designed accordingly. Check to see that :
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•
The tubing string provides optimum deliverability,
•
The tubing/casing configuration is suitable for the chosen artificial lift method, and
•
The artificial lift operation will not interfere with other planned operations in the well.
Allow For Stimulation
When stimulation treatments are possible, the completion engineer must :
3.4.8
•
Check pressure limitations of completion equipment and tubular goods and compare
with proposed treating pressures,
•
Minimize fluid diversion problems by careful selection of the perforated interval and
the perforation shot density,
•
Check tubular movement during stimulation treatment.
Provide Ease of Workovers
Finally, the completion needs to be designed with an eye towards simplifying future
workover operations. This can be done by :
•
Providing as large a through-tubing bore as possible,
•
Using packers with simple, straight pick-up releasing mechanisms,
•
Careful attention to the number of holes shot while perforating,
•
Using quality equipment throughout.
It is a good idea to design the completion so that as many types of workovers as possible
may be accomplished using concentric techniques. For example, in a well with many zones
that are to be sequentially squeezed and reperforated by using concentric methods only.
This saves the cost of a full workover rig and eliminates the risks associated with
conventional workovers.
The completion should be designed to facilitate well killing operations, should a
conventional workover be required. For high pressure gas wells this can be a problem,
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especially if large tubular goods are involved. One way to improve the well killing
operation, especially for gas wells, is to set the packer close to the perforations. Another
possibility is to provide a means for setting a plug in the packer before pulling the tubing.
3.5
INHOUSE COMPUTER PROGRAM USED TO AID IN WELL DESIGN
PCSB has purchased a suite of programs called Flosytem which was developed by
Edinburgh Petroleum Services Limited to aid the petroleum engineer in the optimisation,
design and diagnosis of oil wells and production systems.
This software, which consists of three programs : WellFlo (including an optional gas lift
section), WellFlo-ESP and FieldFlo. WellFlo is a single well Nodal Analysis program
which models natural producers, injectors and, optionally, gas-lifted wells; WellFlo-ESP
adds the option to model Electric Submersible Pump (ESP) lifted wells. FieldFlo is a
network model specifically written to optimise the allocation of gas to gas lifted oil wells in
complex networks.
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WellFlo supports a range of PVT, IPR, Vertical Lift, Temperature and Choke correlations
and models. It can be used in two main modes:
(i)
to find the operating point (i.e. production rate) of a well or system,
or
(ii)
to find the pressure drop along a well or pipeline
In both modes of operation, a wide range of sensitivity variables can be used to study
different “what-if” cases. Graphs can be made of results of these calculations. A gas lift
option is available which includes a design facility for the positioning of unloading and
orifice valves.
FieldFlo takes as a starting point the individual well performance curves generated by
WellFlo. You define the network of wells and manifolds, and used WellFlo again, to
describe the pipelines connecting them. Then, a series o f calculations can be made in order
to calculate the optimum lift gas distribution for your field, and to predict its production.
The calculation takes into account the pressure drop along pipelines, and the mixture of
wells: non-lifted, naturally flowing but gas lifted, wells required minimum gas, electrically
pumped wells and gas wells.
Both WellFlo and FieldFlo operate under the Microsoft Windows, Windows 95, Windows
NT and UNIX environments. The custodian for the package of programs is DPE.
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CHAPTER 4
PRIMARY CEMENTING
TABLE OF CONTENTS
4.1
INTRODUCTION …………………………………………………………………. 4
4.1.1
4.1.2
4.1.3
4.2
History of Portland Cement …………………………………………
Manufacture of Portland Cement ……………………………………
Components of Portland Cement ...………………………………….
API Cement Classes ……………………………………...………….
Cement Setting Process ……………………………………………...
Effect of Temperature
………………………………………………..
Effect of Pressure ……………………………………………………
6
6
6
7
7
8
8
CEMENT PROPERTIES …………...……………………………………………. 10
4.3.1
4.3.2
4.3.3
4.3.4
4.3.5
4.3.6
4.4
4
4
4
CEMENT FUNDAMENTALS ……………………………………………………. 6
4.2.1
4.2.2
4.2.3
4.2.4
4.2.5
4.2.6
4.2.7
4.3
Purpose of Chapter …………………………………………………...
Functions of Primary Cementing ……………………………...…….
Problems Caused By Inadequate Primary Cementing ………………
Thickening Time ………………………...………………………….. 10
Fluid-Loss Rate ……………………………………………...……… 11
Density ……………………………………………………………… 12
Free Water …………………………………………………………... 12
Rheology ……………………………………………………………. 12
Compressive Strength ………………………………………………. 13
FACTORS AFFECTING JOB DESIGN ………….…………………………….. 15
4.4.1
4.4.2
4.4.3
4.4.4
4.4.5
4.4.6
4.4.7
Chemical Environment ………………………………...……………. 15
Bottom Hole Static Temperature ……………………………………. 15
Bottom Hole Circulating Temperature ……………………………… 16
Formation Integrity …………………………………………………. 17
Pore Pressures ……………...……………………………………….. 17
Formation Permeability ……………………………...……………… 17
Hole Geometry ……………………………………………………… 18
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4.5
EXAMPLE : SELECTION OF API CEMENTING SCHEDULE …....………... 19
4.6
CEMENT SLURRY DESIGN ……………………………………………………. 20
4.6.1
4.6.2
4.6.3
4.6.4
4.6.5
4.6.6
4.6.7
4.6.8
4.6.9
4.6.10
4.6.11
4.6.12
4.6.13
4.6.14
Introduction ………………………………...……………………….. 20
Neat Cement Slurries ……………………………………………….. 20
Cement Additives …………………………………………………… 20
Water Requirements ………………………………………………… 21
Accelerators …………………………………………………………. 21
Retarders …………………………………………………………….. 23
Fluid-Loss Additives ………………………………………………... 23
Additives To Decrease Density ……………………………………... 24
Additives To Increase Density ……………………………………… 25
Dispersants ………………………………………………………….. 25
Silica ………………………………………………………………… 26
27
Defoamers
27
……………………………………………………………
Sodium Chloride ……………………………………………………. 27
Lost Circulation Materials …………………………………………...
4.7
EXAMPLE : DENSITY AND YIELD OF 8% BENTONITE SLURRY ..……... 28
4.8
CEMENTING EQUIPMENT …………………………………………..……….... 30
4.8.1
4.8.2
4.8.3
4.8.4
4.8.5
4.8.6
4.8.7
4.8.8
4.8.9
4.8.10
4.9
Guide Shoe ………………………………………...………………... 30
Float Equipment …………………………………………………….. 30
Wiper Plugs …………………………………………………………. 31
Centralizers ………………………………………………………….. 32
Scratchers …………………………………………………………… 33
Bulk Units …………………………………………………………... 34
Mixers ………………………………………………………………. 34
Pumping Units ………………………………………………………. 36
Densitometers ……………………………………………………….. 36
Cementing Heads …………………………………………………… 36
PLANNING A PRIMARY CEMENT JOB ………………………………..……. 38
4.9.1
4.9.2
4.9.3
4.9.4
4.9.5
4.9.6
Government Regulations ……………………………………………. 38
Cement Volume Requirements ……………………………………... 38
Specifying A Slurry …………………………………………………. 38
Cement Testing ……………………………………………………... 39
Spacer Fluids ………………………………………………………... 39
Displacing Fluids ..…………………………………………………. 40
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Preparing The Casing Surface ………………………………………. 41
Mud Conditioning ………………………...………………………… 41
Running Casing ……………………………………………..……… 41
Mud Displacement ………………………………………………….. 41
Casing Movement …………………………………………………... 42
Pumping Rate ……………………………………………………….. 42
Pressure Considerations …………………………………………….. 42
Displacement Volume ………………………………………………. 43
After-Cementing Considerations ……………………………………. 43
Waiting-On-Cement Time ………………………………………….. 43
Problems Caused By AFM …………………………………...…….. 44
Pressure Reduction In Cement …………………………………...…. 44
Conducive Conditions ………………………………………………. 45
Prevention Procedures ………………………………………………. 46
Repair Technique …………………………………………………… 46
SPECIAL PRIMARY CEMENTING CONSIDERATIONS ….…………...…… 47
4.12.1
4.12.2
4.12.3
4.12.4
4.1
PROPRIETARY INFORMATION -For Authorised Company Use Only
ANNULAR FLUID MIGRATION ………...………………………………...…… 44
4.11.1
4.11.2
4.11.3
4.11.4
4.11.5
4.12
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PRIMARY CEMENTING OPERATIONS .………………………………...…… 41
4.10.1
4.10.2
4.10.3
4.10.4
4.10.5
4.10.6
4.10.7
4.10.8
4.10.9
4.10.10
4.11
PRIMARY CEMENTING
Cementing Liners …………………………………………………… 47
Cementing Deviated Wells ………………………………………….. 47
Stage Cementing ……………………………………………………. 48
Cementing Multiple Strings ………………………………………… 48
INTRODUCTION
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PRIMARY CEMENTING
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Purpose of Chapter
The purpose of this section is to provide an overview of
•
the properties and behavior of well cements and
•
the primary cementing process
An understanding of the properties and behavior of well cements is important because
cement is used in a number of well completion and workover operations. These operations
include primary cementing of the production casing, repairing channels behind casing,
plugging perforations, fixing casing leaks and plugging the well for abandonment. This
section reviews cement fundamentals, cement properties, factors that affect cement
properties, and basic cement slurry design.
An understanding of the primary cementing process is also important for
completion/workover personnel. For most wells, communication with the pay zone is
through perforations that penetrate the cement sheath. By studying the primary cementing
process, production personnel can better understand how the cement sheath affects
completion, stimulation, and workover operations. The subjects covered include cementing
equipment, planning, primary cementing operations, annular fluid migration, and special
primary cementing considerations.
4.1.2
Functions of Primary Cementing
Primary cementing is the process of placing cement in the annulus between the casing and
the formation. This cement sheath serves a number of functions :
4.1.3
•
It seals the annulus isolating the different fluid bearing zones the borehole has
penetrated.
•
It mechanically supports the casing and helps prevent the casing from buckling.
•
It helps protect the casing from external corrosion.
Problems Caused By Inadequate Primary Cementing
There are a number of problems that are associated with inadequate primary cementing.
These include :
•
Production of unwanted fluid
•
Interzonal flow through the annulus
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•
Annular flow to surface
•
Formation damage
•
Casing buckling
•
Casing leaks
CEMENT FUNDAMENTALS
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History of Portland Cement
Although cementitious materials have been used since ancient times, the invention of
modern Portland cement is usually attributed to Joseph Aspdin, an Englishman, who filed a
patent for Portland cement in 1824. He called it “Portland” cement because it resembled
the limestone quarried in Portland, England.
4.2.2
Manufacture of Portland Cement
Portland cement is manufactured with materials and methods that have changed little since
Aspdin’s time. The material is prepared by sintering fixed proportions of calcium
containing materials (limestone, chalk, seashells) with aluminosilicates clays) in a kiln at
2600-2800°F (1425-1535°C). The resulting material, clinker, is then cooled and
interground with gypsum, a commonly occurring mineral, to form a powder called Portland
cement. Small percentages of other substances, such as sand, bauxite or iron ore are
sometimes used in the kiln feed to adjust the properties of the clinker.
4.2.3
Components of Portland Cement
Portland cement consists primarily of the four chemical compounds shown in Table 1. All
grades or classes of Portland cement contain these four compounds. However, the relative
percentages of the compounds can vary, depending on the feed materials in the
manufacturing process. The relative percentages of these compounds along with the grind
of the cement have been found to strongly affect the cement performance.
Table I
Principal Components of Portland Cement
Compound
Tricalcium Silicate
Dicalcium Silicate
Tricalcium Aluminate
Tetracalcium Aluminoferrite
Other Oxides
4.2.4
Formula
Standard
Designation
Typical % (Wt)
C3S
C2S
C3A
C4AF
50%
25%
10%
10%
5%
3CaO•SiO2
2CaO•SiO2
3CaO•Al2O3
4CaO•Al2O3•Fe2O3
API Cement Classes
Specifications for cements used in oil-well applications have been written by the American
Petroleum Institute (API). These specifications are found in “API Specifications for
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Materials and Testing for Well Cements”, (API Spec 10).
There are nine API cement classes. Table II provided a summary of the chemical
composition, grind and special properties of some of these API cements. (Class J is a
special non-Portland cement). Most oil-field operations use Class A, C, G, or H. A
description of the intended use of these different cements can be found in API Spec 10.
Table II
API Cement Classes
API
Class
Compounds,
C2S
C3S
Typical %
C3S
C3S
Fineness
Sq m/kg
Special
Properties
A
B
53
47
24
32
8
3
8
12
150-190
150-190
C
70
10
3
13
200-240
D
G
26
50
54
30
2
5
12
12
110-15140-160
H
50
30
5
12
120-140
J
-
-
-
-
-
Common Portland
Common Portland
Sulfate Resistant
High Early Strength
Lighter Weight
Retarded
Basic Oil Well
West Coast/Outside USA
Basic Oil Well
Gulf Coast/Mid Continent
High Temperature
4.2.5
Cement Setting Process
When water is added to Portland cement, a chemical reaction (hydration) takes place that
eventually causes the cement particles to bond together to form an impermeable, hard, rocklike material. The strength and impermeability of the cement is due to the formation of a
dense network of interlocking fibers (see Figure 1).
Two of the byproducts of the cement hydration reaction are calcium hydroxide [Ca(OH)2]
crystals and heat. The Ca(OH)2 crystals cause the cement to be very basic (high pH).
Because of this a cement sheath will provide corrosion protection for the steel casing.
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PASTES OF PORTLAND CEMENT appear in scanning electron micrographs made at various stages of hydration, that is, at various
times after water was mixed with the cement. After two hours (1) the initial gel coatings are visible around the cement grains. After
a month (2) the fibrils are evident, as are large platelike crystals of calcium hydroxide. Detail of same sample (3) shows the
interlocking fibers.
Figure 1. Setting of Portland Cement
The heat given off during the hydration reaction is sometimes used to detect the top of
cement by temperature logging. The time at which the slurry achieves its maximum
temperature depends on the particular slurry and its curing conditions, but generally is
between 3 and 12 hours.
4.2.6
Effect of Temperature
Temperature is perhaps the most important factor that affects the performance of cement in
a well. As with most chemical reactions, the hydration of cement is accelerated by
increasing temperature. This effect is illustrated in Figure 2, which shows the effect of
temperature on the thickening time of the cement. The thickening time is the length of time
necessary for the cement to reach a certain viscosity in a standard measuring device and is a
measure of the rate of hydration. Figure 2 shows that, as the temperature increases, the
thickening time decreases, indicating that the hydration reaction rate has increased.
4.2.7
Effect of Pressure
The effect of pressure on the thickening time of a Class H slurry is shown in Figure 3.
Generally above 5000 psi, increasing pressure increases the rate of reaction and thus
decreases the thickening time. The effect of pressure, however, is not as significant as the
effect of temperature.
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Figure 2. Effect of temperature thickening time of various API cements
4
at atmospheric pressure
Figure 3. Effect of pressure on thickening time
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CEMENT PROPERTIES
Cement has a number of measurable properties that can be used to predict its performance
in a well.
4.3.1
Thickening Time
Perhaps the most important property of a cement slurry for well applications is its
thickening time. The thickening time provides an indication of the length of time the slurry
will remain pumpable. A thickening time that is too short can result in the cement setting
inside the casing, tubing or drill pipe with severe economic consequences. A thickening
time that is too long, on the other hand, can necessitate an unduly long and costly delay
waiting for the cement to set.
The API defines the thickening time of a cement slurry to be the time required for the slurry
to reach 100 Bearden units of consistency (Bc), using the methods of API Spec 10. One
hundred Bearden units of consistency is roughly equivalent to a viscosity of 100 poise.
Cement is considered to be unpumpable at this viscosity.
The thickening time is measured in a device called a consistometer. Consistometers are
designed so that the consistency of the cement slurry can be continually monitored while
the cement is subjected to a temperature, shear, and pressure history that simulates what the
cement will see as it is pumped downhole.
Since the thickening time depends not only on the slurry being tested, but also on the
simulated downhole conditions, it is important to simulate these conditions as accurately as
possible. The API has published a series of cementing schedules, based on field
measurements that can be used to simulate the downhole conditions for many wells. There
are different API scheduled, depending on the type of job (casing, liner or squeeze), well
depth, and the bottom hole static temperature.
The API schedules have proven to be accurate and reliable over many years. However,
there are certain situations where the API cementing schedules may not be appropriate. If
unusual temperature conditions are encountered, such as geothermal gradients outside the
0.9-1.9°F/100 ft API range, highly deviated wells or offshore cementing through long risers,
it may be necessary to develop a cement-testing schedule using computer simulation.
The thickening time of a cement slurry is generally selected to be equal to the job time plus
a safety factor. The job time is the estimated time required to mix the slurry and pump it
into place. Usual practice is to employ a 50-100% safety factor, depending on the type of
job and the experience in the area. Through the use of the appropriate additives (see
Subject 4.6), well cement slurries have been designed with thickening times as short as 60
minutes or as long as 12 hours.
4.3.2
Fluid-Loss Rate
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The rate at which a cement slurry loses water through a permeable barrier when a
differential pressure is imposed is referred to as filtration rate fluid-loss rate. The water lost
is the water that does not take part in the chemical reaction, that is, the water required for
slurry fluidity.
When this water is lost, the slurry viscosity increases, and the slurry loses its fluidity. In
addition, as water is lost, the concentration of the cement particles increases. This may
result in the formation of cement bridges in areas of narrow clearance.
Thus, control of the fluid-loss rate of a slurry is necessary when :
•
Cementing past very permeable intervals
•
Cementing through narrow clearances (for example, liners)
•
Squeeze cementing perforations or channels
Because the water lost is that used to maintain slurry fluidity, there is still sufficient water
to complete the hydration reaction. In fact, because the cement particles are closer together,
the strength of a slurry that has lost water is greater than the strength of the parent slurry
(that is, the slurry that did not lose any water).
Testing procedures for fluid loss rates are given in API Spec 10. There are two types of
tests: (1) low temperature/low pressure (LT/LP) and (2) the well-simulation or high
temperature/high pressure (HT/HP). While the LT/LP test is more convenient than the
HT/HP test, research has shown that the LT/LP test may give misleading results. Therefore
the HT/HP tests should be used to determine fluid-loss rates for cement slurries.
The HT/HP fluid-loss rate of a neat cement slurry (i.e. just cement and water) is on the
order of 1000-2000 cc/30 min. However, through the use of certain additives (see Subject
4.6), the fluid-loss rate can be adjusted to lower values. Table III presents some general
fluid loss guidelines for different cementing operations. Additional discussion of fluid loss
rate can be found in the Remedial Cementing Chapter (Section 21.2).
Table III
Guidelines for Cement Slurry Fluid-Loss Rates
Operation
HT/HP Fluid-Loss Rate
(cc/30 min.)
Casing Cementing
(past high permeability formations)
4.3.3
300-450
Liner Cementing
100
Squeeze Perforations, Repair Channels
50
Density
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The density of a cement slurry is important for well control and the prevention of lost
circulation while cementing. Density is also a useful field monitor of whether or not the
slurry has been mixed with the designed water requirement. With the appropriate additives
(see Section 4.6), cement slurries can be designed with densities ranging from about 8 ppg
to about 20 ppg.
Procedures and equipment for density measurement are described in API Spec 10. Methods
using both a pressurized and unpressurized mud balance are presented. Because cement
slurries often contain entrapped air, the pressurized mud balance provides a more accurate
measurement. Errors of 1-2 ppg may occur using the unpressurized balance.
In the field, in-line radioactive densitometers are often used to monitor density as the job is
pumped. These are discussed in Section 4.8.
4.3.4
Free Water
The water added to the dry bulk cement is used both as a reactant in the hydration reaction
and to provide fluidity to the slurry. When properly mixed, about 2/3 of the water is
involved in the chemical reaction while 1/3 provides fluidity. All of the water in a properly
mixed slurry, however, is either bound to the cement particles by chemical bonds or loosely
attracted to the cement particles to form a stable suspension. If excess water is added, the
cement particles will settle, leaving a layer of free water above the suspension.
Excessive cement free water may lead to the formation of water pockets in a well,
especially on the high side of deviated wells. Also, since excessive free water indicates
solids settling, it may result in difficulty in mixing and displacing the slurry.
Procedures for determining the free water content of a cement slurry have been specified by
the API. There are two types of tests : a specification test conducted at 80°F and a new
(tentative) operating free water test conducted under downhole conditions. Under the API
specification procedure, the maximum allowable free water is 1.4% (3.5 ml water from 250
ml of cement). For critical wells PCSB guidelines recommend a free water content less
than 1%. Guidelines for the operating test have not yet been established.
4.3.5
Rheology
The rheology of cement is complicated because the hydration reaction causes the structure
of the material to change with time. In addition, the correct interpretation of laboratory
rheological data is complicated by wall slip phenomenon and difficulty in simulating
downhole temperature and pressures. Furthermore, because fluid loss can drastically alter
cement rheology, predictions based on laboratory - measured cement rheology may be
inaccurate.
The API has specified a procedure for the determination of cement rheological properties
using a rotational viscometer. However, because of the limitations cited above, predictions
based on cement slurry viscometric data should be used with care.
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Perhaps the best general indication of the rheological behavior of a cement slurry can be
obtained from the consistency readings during the free water test. The API has designated
11 Bc as the normal water content and 30 Bc as the minimum water content at the end of a
20-min. stirring period in an atmospheric consistometer. For critical wells PCSB
recommends 11± 2 Bc.
4.3.6
Compressive Strength
The compressive strength of set cement is the stress required to cause failure of the cement
under a uniaxial compressive load. Figure 4 shows the compressive strength development
for a class A cement. The rate of strength development depends on the type of cement, the
type and concentration of additives and the curing temperature. However, 75-80% of the
ultimate compressive strength is generally achieved within 3 days.
Figure 4. Compressive Strength Development
Compressive strength data are used for
•
Establishing waiting-on-cement time,
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•
Determining optimum time to perforate, and
•
Monitoring the stability of the set cement.
After cement has been pumped into the annulus, it must obtain sufficient strength so that
further operations will not damage the cement sheath. Although the loadings placed on the
cement downhole are not necessarily uniaxial compressive loads, the compressive strength
has been found to be a convenient indirect measure of the ability of the cement to withstand
these loads.
The industry has generally accepted a value of 500 psi as the minimum required
compressive strength before further drilling operations can commence. Tests have shown
that a cement sheath with 500 psi can easily support the weight of the casing, even under
rather poor bonding conditions4.
Similarly, laboratory experiments indicate that a well should not be perforated until the
cement has achieved at least 2000 psi compressive strength. Above this value, the tests
indicate that perforating does not damage the cement bond.
Compressive strength data are also used, in some cases, to monitor the long-term
performance of the cement. This is especially important when the cement will be exposed
to temperature above 250°F, thermal cycling or other unusual downhole conditions (e.g.
acid gases).
The API testing procedures for determining compressive strength are given in API Spec 10.
These tests use conventional compressive strength testing equipment. An Ultrasonic
Cement Analyzer (UCA) is also available for making non-destructive compressive strength
measurements. The UCA is based on measurement of the travel time of ultrasonic waves
pulsed through a cement sample. While the UCA provides a useful time history of strength
development, the actual values of compressive strength predicted by the UCA may not
agree with conventional crush tests, especially for non-standard slurries. Therefore
compressive strength values obtained from the UCA should be used with caution.
4.4
FACTORS AFFECTING JOB DESIGN
A number of factors influence the design of a primary or remedial cement job. The
chemical environment and physical parameters such as bottom-hole temperature, formation
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integrity, pore pressures, formation permeability, and hole geometry all influence the
behavior of the cement as it is pumped into place and as it solidifies.
4.4.1
Chemical Environment
The parameters which make up the chemical environment of the cement include :
•
Mix water
•
Wellbore Fluids
•
Formation Types
•
Formation Fluids
Since the cement setting process is a chemical reaction, these factors may affect the
behavior of the cement slurry and will sometimes even affect the properties of the cured
cement. For example, inorganic salts in the mix water or formation may accelerate the
cement set. The chemical composition of substances that will contact the cement should be
kept in mind when designing the cement slurry and when planning the cementing operation.
4.4.2
Bottom-hole Static Temperature
The bottom-hole static temperature (BHST) is one of the most important parameters to
establish when designing a cement job. It is important for two reasons :
•
The bottom-hole static temperature is often used to help estimate the temperature
history that the cement will see as it is pumped into place. The temperature history
strongly affects the thickening time of the cement.
•
The bottom-hole static temperature is usually the maximum temperature the cement
will see during its lifetime. This temperature affects the rate at which the cement
gains compressive strength. Also, if this temperature exceeds 250°F, silica should be
added to the slurry to prevent long term strength retrogression (see Section 4.6).
The bottom-hole static temperature can be determined by :
•
Direct measurement in offset wells
•
Estimation from logging temperatures
•
Knowledge of the local geothermal gradient
The direct measurement of BHST from nearby offset wells is probably the most accurate
method.
If direct measurements are not available, the BHST can be estimated by using an empirical
correlation of static temperature with logging temperatures. Tables are available from
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cementing companies for converting logging temperatures to static temperatures. This
method is generally most accurate for logging temperatures taken 3-4 hours after circulation
is stopped.
Another, perhaps more accurate method for estimating BHST is to use a Horner-plot-type
method in which temperature is plotted in a manner similar to a pressure buildup analysis.
This method, however, requires at least two separate logging temperatures.
4.4.3
Bottom-hole Circulating Temperature
When designing a cement slurry, the bottom-hole circulating temperature (BHCT) is
considered to be the temperature of an element of cement as it reaches the bottom of the
hole. The BHCT will usually be less than the BHST because the inlet temperature of the
cement at the surface is usually less than the BHST. For testing, the BHCT is taken to
represent the highest temperature the slurry will see as it is pumped into place. The API
thickening time testing procedure calls for holding the slurry at the BHCT after it has been
brought up to temperature according to the appropriate schedule.
There are two methods for determining the slurry temperature history :
•
API Cementing Schedules and
•
Computer Simulation
To use the API Cementing Schedules, it is necessary to know only the type of job (casing,
liner or squeeze), the well depth, and the BHST. The job type and well depth are used to
select the appropriate schedule type. The BHST is used to calculate the temperature
gradient from
T. Grad.
=
=
(BHST-80) ÷ (Depth/100 ft) (Eng.)
(BHST-27) ÷ (Depth/100 m) (Metric)
Once the temperature gradient is known, the particular schedule for that gradient can be
identified (See 4.6 for an example). The BHCT is the highest (final) temperature for that
gradient.
As mentioned earlier, for unusual conditions such as highly deviated wells or offshore
cementing through long risers, it may be necessary to use computer simulation to develop a
cement testing schedule.
To determine the BHCT using computer simulation, significantly more information is
required than for the API method.
4.4.4
Formation Integrity
Another fundamental consideration is designing a cement job is formation integrity. The
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breakdown fracture pressure (often expressed as a fracture pressure gradient) will limit the
density of the cement and/or the surface pumping pressure that can be used without losing
returns. Losing returns while cementing is generally undersirable because
•
Since some cement is lost to the formation, the top-of-cement may not be high
enough to cover all necessary zones.
•
Fracturing may cause undersired interzonal flow.
•
Fracturing could expose the cement to high permeability and lead to a costly bridgeoff in the annulus.
•
Cement may plug up a naturally-fractured pay zone.
Information on formation integrity can often be obtained from the Daily Drilling Reports
for the well. If returns were lost while drilling, the mud weight being used at the time
provides some indication of the formation integrity. More direct information may be
available from pressure integrity tests (PITs). In addition, formation integrity can be
estimated from offset wells or empirical formulas. For additional information see the
Fracturing Chapter (Section 17.3).
4.4.5
Pore Pressures
The pore pressures of the fluid-bearing formations also affect the design of the cement job.
The density of the cement should be such that the hydrostatic pressure exceeds the pore
pressure at all depths in the well. Generally this will be the case if the cement density
exceeds the drilling fluid density used to drill the well. However, because of the possibility
of annular fluid migration (see Section 4.11), special consideration may be necessary if
there are large differences in pore pressure between nearby zones.
4.4.6
Formation Permeability
Another factor to consider when designing a cement job is the formation permeability that
the cement may see. Long intervals of high permeability formation increase the potential
for fluid loss from the cement. This may cause high slurry viscosities leading to increased
pumping pressures and lost circulation or perhaps total loss of slurry mobility.
It should be recognized, however, that the drilling fluid filter cake or particle plugging from
the drilling fluid may reduce the permeability that the cement sees. However, any broach in
this shield (e.g. by fracturing or erosion) could lead to disaster without the appropriate
cement fluid-loss control.
4.4.7
Hole Geometry
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Hole geometry is another important factor in designing a cement job. The hole geometry
can influence the cement job in a number of ways. For example :
•
The hole size, casing size, and desired top of cement will affect the volume of cement
to be pumped.
•
The amount of annular clearance may affect the amount of fluid loss control required
to prevent bridging. It may also limit the pumping rate to prevent excessive friction
pressures.
•
The angle of deviation may necessitate reducing the free water content of the slurry
to prevent high-side water pockets. The deviation angle may also affect the
placement of centralizers.
For many wells the hole geometry is obtained from caliper logs. In those wells where
caliper logs are not run, the size of the annulus can be roughly estimated from a fluid
caliper. In this method, the volume required to pump a marker pill (e.g. oats, carbide) down
the casing and up the annulus is monitored. The annular volume is then obtained by
subtracting the casing volume.
4.5
EXAMPLE : SELECTION OF API CEMENTING SCHEDULE
For an 8000 ft well with a BHST of 168°F :
a)
What is the correct API Casing Cementing Schedule?
b)
What is the BHCT?
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For an 8000 ft well, the Casing Cementing Schedule to use is Schedule 5g.
(API Spec 10, Appendix E).
b)
The temperature gradient is :
(168-80)/8000/100 = 1.1°F/100 ft
The maximum temperature on this schedule is 129°F. This is the BHCT.
4.6
CEMENT SLURRY DESIGN
4.6.1
Introduction
While there are a number of different API cement classes, the properties of these cements
are fairly limited. For example, when mixed with the specified percentage water, the API
cements span a density range of only 14.8 to 16.4 ppg (see Table IV).
To achieve desired slurry properties for cements used in wells, additives are usually
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required. Additives are substances added to alter the properties of the cement.
Table IV
Neat Cement Slurries
4.6.2
API Cement
Type
Recommended
Water/Cement Ratio
(gal/sack)
Slurry Density
(lb/gal)
A&B
C
D&E
G
H
J
5.2
6.3
4.3
5.0
4.3
4.9
15.6
14.8
16.4
15.8
16.4
15.4
Neat Cement Slurries
Neat cements are mixtures of cement in water containing no other component. Table IV
presents the water requirement and densities for neat API cement slurries.
4.6.3
Cement Additives
There is a wide variety of cement additives. Most cement additives are powders or granular
materials that are dry blended with the cement at the cementing service company bulk plant.
By convention, the concentration of all additives, except sodium chloride, is expressed as a
percentage of the weight of the dry cement used in mixing up the slurry. Thus, a cement
containing 0.75% Additive A contains 0.75 lbs of Additive A for every 100 lbs of dry
cement used. The concentration of sodium chloride is usually expressed as a percent by
weight of the mix water.
In remote areas, liquid additives are sometimes used. This facilitates formulating different
slurries without dry blending. Liquid additive concentration is usually expressed in gal per
sacks of cement. (A sack of cement weighs 94 lbs). Density control is very important when
using liquid additives, since variations in density can cause significant changes in the
cement to additive ratio.
4.6.4
Water Requirements
All of the API cement classes have a recommended water requirement (see Table IV). This
water requirement is based on the cement composition and grind. Too much water in a neat
cement may lead to free water break out and mixing problems. Too little water may cause
excessive viscosity and increase the rate of set.
Some cement additives also have water requirements. Table V lists the water requirements
for some common additives. More extensive information on additive water requirements is
usually available in cementing company literature.
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The water requirements of additives are in addition to the water requirement of the basic
cement. Thus a Class H slurry with 4% bentonite would require 6.9 gal of water per sack of
cement : 4.3 gal for the cement and 2.6 gal for the bentonite.
Table V
Water Requirements of Some Common Cement Additives
Additives
Bentonite
Hematite
Silica Flour
Gilsonite
4.6.5
Water Requirement
1.3 gal/2% in cement
0.36 gal/100 lb sk
1.6 gal/35% in cement
2.0 gal/50 lb
Accelerators
The additive most commonly used to accelerate the set of cement is calcium chloride
(CaCl2). This compound is used in the concentration range 1 to 4%. Figure 5 shows the
effect of CaCl2 concentration on thickening time for class A cement tested with a 4000 ft
thickening time schedule (Schedule 3g).
Since CaCl2 is effective at relatively low concentrations, it is an economical additive. In
addition, the accelerating effect of CaCl2 is predictable, and it has few adverse side effects.
The presence of CaCl2 , however, will decrease the effectiveness of some fluid loss
additives.
Another additive sometimes used as an accelerator is sodium chloride (NaCl). At
concentrations below 18% (by weight of mix water), NaCl accelerates the set of cement.
At greater concentrations, however, NaCl acts as a retarder. Sodium chloride is not
compatible with most fluid loss additives. In addition it increases the tendency for slurry
foaming.
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Figure 5. Effect of CaCl2 on thickening time7
Table VI
Cement Retarders
Application
BHCT
Range, °F
HB
Service Company Equivalents
D-S
BJ-T
WN
Low Temperature
< 200
HR4
-
R1
WR2
-
Low Temperature/
Dispersing
< 200
HR5
D13
R5
WR15
-
Notes
HR7
Moderate
Temperature
150-250
-
D120
-
-
-
Moderate
Temperature
180-225
Dicel
LWL
D8
R6
Diacel
LWL
CMHEC : Also acts as
a fluid-loss additive,
viscosifies slurry
High Temperature
225-400
HR12
HR15
HR20
D28
D99
R11
R17
WR6
-
High Temperature
> 300
Borax
D93
MHR9
WR7
Borax : Added to
enhance behavior of
high temp. retarders.
Not to be used alone.
4.6.6
Retarders
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Retarders are additives that delay the set of cement. Most commercially available retarders
are organic materials. Table VI presents a summary of the generic types of organic
retarders. Retarders are generally used in the concentration range of 0.1 to 1.0%. Since
retarders are generally composed of heat-sensitive organic molecules, particular attention
should be paid to the recommended temperature range for using the retarder. Information
on specific retarders is available from cementing company literature.
Another additive that will retard the set of cement at certain concentrations is sodium
chloride (NaCl). At concentrations greater than about 18% (by weight of mix water), NaCl
acts as a retarder. For example, the thickening time of a Class G cement increases from
about 2-1/3 hours to 3 hours as the NaCl concentration increases from 18 to 30% for an
8000 ft API casing schedule. While sodium chloride can sometimes be used as a retarder, it
has certain drawbacks. These include incompatibility with most fluid loss additives, an
increased tendency for slurry foaming, and a limited extent of retardation.
4.6.7
Fluid-Loss Additives
Fluid-loss additives are used to reduce the rate of fluid loss from the cement. There are two
basic types of fluid loss additives : polymers and bentonite.
Polymers function primarily by plugging the pore space in the cement filter cake.
Polymeric fluid loss additives
•
are sensitive to temperature,
•
seem to have a threshold concentration of about 0.8%,
•
generally retard the slurry and
•
tend to increase the viscosity of the slurry.
Bentonite functions as a fluid loss additive by decreasing the permeability of the cement
filter cake. As a fluid loss agent bentonite generally
•
will result in a lower density slurry,
•
will increase thickening time,
•
will decrease compressive strength and
•
is sensitive to mix-water salinity.
Attapulgite clay is sometimes used as a fluid-loss additive in salt-containing slurries
because it is not sensitive to the salts. Attapulgite, however, does not have the same waterabsorbing power as bentonite.
4.6.8
Additives To Decrease Density
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There are a number of additives available to lower slurry density. Table VII presents a
summary of additives to lower slurry density. These additives lower the density of the
slurry because they have a lower specific gravity than the cement, and in most cases, have a
higher water requirement than the cement.
Perhaps the most widely used additive to decrease slurry density is bentonite. Bentonite in
cement lowers density chiefly because of its high water requirement. Whereas each pound
of Class G cement requires 0.05 gal water, each pound of bentonite requires 0.69 gal water.
Thus, for example, the density of a Class G cement can be lowered from 15.8 ppg (neat) to
12.8 ppg by the addition of 12% bentonite. Because of loss of compressive strength,
bentonite is generally not used at concentrations greater than 12%.
Table VII
Additives to Lower Density
Additives
Specific Gravity
Water Requirement
Bentonite
Attapulgite
Diatomaceous Earth
Gilsonite
Pozzolan
Ceramic Spheres
Glass Bubbles
Sodium Meta-silicate
Foam
2.65
2.89
2.10
1.07
2.50
0.72
0.39
2.40
Pressure-dependent
1.3 gal/2%/sk cmt.
1.3 gal/2%/sk cmt.
3.3-7.4 gal/10%/sk cmt.
2 gal/50 lb
3.6-3.9 gal/74 lb
0.31 gal/2 lb
0.36 gal/2 lb
3.2-12.3 gal/2-3%/sk cmt.
-
When bentonite is dry blended with the cement, the high Ca+2 content of the cement
prevents full hydration of the bentonite. If bentonite is prehydrated, i.e. allowed to hydrate
in fresh water before being added to the cement, it will have a greater capacity for water.
One part by weight of bentonite prehydrated in the mix water has an effect that is
essentially equivalent to 3.6 parts by weight of bentonite dry blended with the slurry. In
other words, if the bentonite is to be prehydrated (usually 2-12 hours is sufficient) the
amount of bentonite can be reduced by the factor 3.6.
To obtain ultra lightweight slurries, ceramic spheres, glass bubbles, or foam can be used.
Although ceramic spheres and glass bubbles are relatively expensive, slurry densities as
low as 8.3 ppg can be achieved while maintaining good compressive strength properties.
However, because the spheres will crush at sufficiently high hydrostatic pressure (generally
around 4000 psi), there are density and depth limitations associated with their use.
Ultra lightweight slurries can also be achieved by incorporating air or nitrogen into the
cement as a foam. Using foam, slurry densities as low as 9 ppg can be achieved while
maintaining good strength properties in the cured cement.
4.6.9
Additives To Increase Density
For purposes of well control, it is sometimes necessary to use additives that increase slurry
density. Table VIII presents a summary of the additives commonly used to increase slurry
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density.
Table VIII
Additives to Increase Density
Additive
Specific Gravity
Class G Cement
Barite
Hematite
Okla. # 1 Glass Sand
3.14
4.23
5.02
2.63
Water Requirement
5.0 gal/94 lb
2.64 gal/100 lb
0.36 gal/100 lb
0
These additives generally increase the slurry density because they have a high specific
gravity and/or a low water requirement in comparison to the cement. Hematite is more
commonly used than barite because it has a higher specific gravity and a lower water
requirement. A pumpable slurry with a density as high as 20 ppg can be achieved with
hematite.
Although Oklahoma #1 sand has a lower specific gravity than cement, it can increase slurry
density (up to 17.5 ppg) because of its zero water requirement.
Since these weighting additives “dilute: the cement particles, the final strength of the set
cement will be lower than that of a neat cement. Reductions in compressive strength can be
minimized by using a reduced water content in conjunction with a dispersant. This method
is discussed further below.
4.6.10
Dispersants
Dispersants (also called thinners or turbulence inducers) are used to reduce slurry viscosity
or increase slurry density.
A reduction in slurry viscosity may sometimes be desirable to reduce friction pressures.
This may occasionally be necessary when the cement column is long, the annulus is narrow
or when the annulus might be partially obstructed. However, dispersants to thin a slurry
should be used with care. Their misuse can lead to high free water breakout and they can
affect the behavior of other additives.
Dispersants are also useful for increasing slurry density. Because dispersants thin the
slurry, when a dispersant is present a pumpable slurry can be formulated with a lower water
requirement than normally recommended for the neat cement. By adding a dispersant and
reducing the water content, slurry densities as high as 17.5 ppg can be achieved (see Table
IX) without the addition of barite or hematite.
Table IX
Use of Dispersants to Increase Class G Slurry Density
CFR-2 % (bwc)
Mix Water (gal/sack)
Density (lb/gal)
0
5.0
15.8
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0.75
0.75
0.75
4.0
3.78
3.38
16.7
17.0
17.5
An advantage of using this technique for increasing slurry density is that the cement
particles are not diluted. In fact, since the concentration of cement particles is increased,
the strength of the set cement will be higher than that of a neat cement.
4.6.11
Silica
On being cured at temperatures in excess of 250°F, one of the components of Portland
cement (C2S) undergoes a change in structure that results in a significant loss in
compressive strength and a significant increase in permeability. This phenomenon is called
strength retrogression.
Figure 6. Effect of silica concentration on strength retrogression8
Class A cement cured at 320°F
It has been found that the addition of 35% or more of silica can prevent this degradation
(see Fig. 6). Any silica sand finer than 100 mesh can be used. Note that the use of less than
20% silica will intensify the problem, whereas the maximum benefit is obtained at around
40%.
4.6.12
Defoamers
Excessive foam makes it difficult to maintain slurry density control and can cause other
problems, such as “air locking” of the pumps. This is often a problem in salt-containing
slurries. Chemical foam inhibitors, which minimize air entrainment and foaming, are
available. These materials can be obtained in liquid or solid form.
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With the exception of foam cements, these compounds have no known detrimental effects
on other cement properties.
4.6.13
Sodium Chloride
The use of high concentrations of sodium chloride (NaCl) in cement serves a useful purpose
in some primary cementing operations. Salt can function as a freezing point depressant for
cements to be used in permafrost or opposite ice lenses. In some locations salt-containing
mix water is used for reasons of logistical convenience. If salt-containing cement is used, it
should be remembered that :
4.6.14
•
The effect of NaCl on the rate of set of cement varies according to NaCl
concentration.
•
NaCl is not compatible with some fluid-loss additives.
•
NaCl causes slurry foaming.
•
NaCl reduces the durability of set cement.
Lost Circulation Materials
Additives commonly used to control lost circulation while cementing include : gilsonite,
walnut shells, coal, and cellophane flakes.
In selecting and using materials to control lost circulation, two factors should be considered :
•
The material must be small enough that it can be handled by the pumping equipment.
•
The formation opening must be small enough to allow the material to bridge and seal.
When lost circulation occurs in formations with large openings, e.g. vugular carbonates,
lost circulation materials are not effective. In these cases, it may be necessary to use a
thixotropic cement to seal the formation. Thixotropic cements are special cements that
develop gel strength very rapidly. Additional information can be obtained from cementing
service companies.
4.7
EXAMPLE: DENSITY AND YIELD OF 8% BENTONITE SLURRY
The following problem was selected to illustrate the principles involved in calculating
density, water requirement, and yield for a cement slurry.
For a slurry composed of Class A cement and 8% bentonite :
a.
What is the water requirement?
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Calculate the slurry density and yield.
This problem was worked using the Halliburton Red Book. The “Water Requirement”
Table is found in Section 230, pg.18. (1995 Edition).
Water Requirements
Class A Cement
Bentonite
Water Requirement
5.2 gal/sk. cement
1.3 gal/2% bentonite/sk.cmt.
5.2 gal
+ 5.2 gal = 8% / 2% x 1.3 gal
10.4 gal
To determine the slurry density, we use
Density =
Weight
=
Volume
Wcement + Wadditives + Wwater
Vcement + Vadditives + Vwater
It is simplest to do all calculations based on 94 lb (1 sack) of cement.
The volume of an additive refers to its absolute volume, i.e., the volume taken up by the
additive itself (no air spaces). This number can be obtained by multiplying the absolute
volume in gal/lb times the number of pounds of the additive/sk. cmt. Values of absolute
volume can be found in the Halliburton Red Book, Section 230, pgs. 14-15.
It is sometimes easier to set this up as a table :
For our problem :
Component
Class A Cement
8% Bentonite :
8 x 94/100 =
Water
Weight
Conversion
Factor
Absolute
Volume
94.00 lb
0.0382 gal/lb
3.59 gal
7.52 lb
86.63 lb
0.0453 gal/lb
8.33 lb/gal
0.34 gal
10.40 gal
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Totals :
188.15 lb
14.33 gal
Density = 188.15/14.33 = 13.1 lb/gal
Sl. Yield = 14.23 gal/sk/7.48 gal/cu.ft.
= 1.92 cu.ft./sk.
4.8
CEMENTING EQUIPMENT
The equipment used to execute a primary cement job can be categorized into downhole
equipment and surface equipment. The downhole equipment facilitates cement placement
and can affect later completion or workover operations. The surface equipment is generally
supplied by a cementing service company. Much of the surface equipment used for primary
cementing is also used in remedial cementing operations.
4.8.1
Guide Shoe
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The guide shoe (Figure 7) is a special collar that is placed on the first joint of casing to help
direct the pipe through the hole. Cement pumped down the casing flows out of the guide
shoe and then up the annulus. The standard shoe is designed so that all the fluid flows
through the bottom of the tool, though shoes that contain additional side ports are also
available.
Figure 7. Cement Guide Shoe
4.8.2
Float Equipment
Float equipment refers to check valves that are incorporated into the casing string to prevent
U-tubing of the cement back up the casing after the job is completed. It is called float
equipment because it also allows the casing to be run into the hole partially empty, thus
increasing the buoyant force acting on the casing.
There are generally two types of check valve mechanisms used in cementing float
equipment : ball valves and flapper valves (Figure 8). Often more than one piece of float
equipment will be run in a casing string to enhance reliability through redundancy.
Sometimes a float valve will be placed in the casing shoe. It is better practice, however, to
place the float valve in a collar 1-3 joints (called float joints) above the shoe. This allows a
margin of safety to protect from over-displacement and also containment for the last portion
of cement (which tends to be contaminated from the wiping action of the top wiper plug).
If several float joints are used, sufficient rat hole must be drilled so that the float collar is
below the deepest pay zone.
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Figure 8. Cement Float Equipment
While float equipment is generally beneficial for cementing, care must be taken in running
casing containing float equipment because of the pressure surges created as the casing is
lowered. The running speed should be slow enough so that the fracture pressure of the
formation is not exceeded.
4.8.3
Wiper Plugs
Bottom and top wiper plugs (Figure 9) help prevent cement contamination by separating the
cement from the drilling and displacing fluids. The bottom plug precedes the cement slurry
down the pipe and displaces the drilling fluid. When the plug reaches the float collar or
landing collar, a diaphragm in the center of the plug ruptures and allows the slurry to pass
through. After all the cement is in the pipe, the top plug is released and is pumped down by
a displacing fluid. As it follows the slurry, it wipes any adhering mud or cement from the
casing wall. Be sure that the bottom plug with the rupturable diaphragm is used ahead of
the cement slurry. If the plugs are reversed, the cement cannot be displaced from the
casing.
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Figure 9. Wiper Plugs
4.8.4
Centralizers
A centralizer (Figure 10) is a mechanical device attached to the outside of the casing to
hold it off the wall. Laboratory experiments by a number of researchers have confirmed
that centralization is important to good mud displacement. Because fluid flow is
preferentially established along the path of least resistance, mud located on the narrow side
of an eccentric annulus is less likely to be displaced than mud on the wide side of the
annulus.
Figure 10. Casing Centralizer
Centralizer placement depends on a number of factors including the deviation angle of the
well, the location of producing zones, and the location of washouts. A typical centralizer
program for vertical wells might consist of two centralizers per joint on the bottom two
joints, two centralizers per joint through the pay zone (s), and one centralizer per every
third joint in the remainder of the well.
For deviated wells additional centralizers are usually required. Many centralizer suppliers
have computer programs for calculating centralizer placement.
While centralizers aid cement placement, they can affect perforating. Although the annular
geometry is perhaps most uniform near a centralizer, it is generally inadvisable to perforate
directly through a centralizer.
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Scratchers
Scratchers (Figure 11) are devices placed on the outside of the casing to aid mud
displacement by shearing the drilling mud during pipe movement.
While scratchers may help break the gel structure of the mud, they probably do not have
much effect in removing mud filter cake, especially in washed-out portions of the hole.
Although scratchers can be of benefit, centralization and pipe movement are more
important.
RECIPROCATING
Figure 11. Scratchers
ROTATING
A variety of surface equipment is used to mix the cement slurry and pup it down the hole.
4.8.6
Bulk Units
On most jobs, the dry cement is transported to the well site in bulk, preblended with
additives. The bulk unit, shown in Figure 12 in a land configuration, is generally equipped
with solids storage tanks with a capacity of about 200 sacks each. Pressurized air is used to
convey the cement from the tanks to the mixing unit.
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Figure 12. Land Bulk Unit
4.8.7
Mixers
Figure 13 illustrates the three basic types of mixers used to mix the dry cement and water :
continuous, recirculating, and batch. In the continuous (or jet) mixer, dry cement is
dropped through a hopper into a jet of water. When the cement contacts the jet of water, it
forms a cement slurry, which is then transferred to the pumping unit.
A circulating mixer can produce a higher quality, more uniform slurry than the jet mixer. A
recirculating mixer is shown in Figure 13. Recirculating mixers increase the slurry
residence time between mixing and pumping, thereby providing better density control.
A batch mixer is simply a holding tank equipped with a mechanical agitator. The dry
cement, water, and additives are initially mixed by a jet mixer or recirculating mixer, and
are then transferred into the batch unit. There, final adjustments in slurry properties can be
made before the slurry is pumped into the well. Batch mixing can provide a highly uniform
slurry. Because of the longer holding time, however, batch mixing may not be feasible
where volumes are large or surface temperatures are high.
CONTINUOUS
RECIRCULATION
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Figure 13. Types of Mixers
4.8.8
Pumping Units
A cement pumping unit (Figure 14), accommodates the pumps used to mix the slurry and to
pump it down the well. Positive displacement pumps are always used for pumping the
cement downhole. The mixing pumps are of either centrifugal or positive displacement
design, depending on the pressure requirements. The pumps are arranged in a controllable
configuration so that adjustments in pressure and output rate can be made as conditions
demand.
BATCH
Figure 14. Cementing Pumping Unit
4.8.9
Densitometers
Slurry density is monitored and recorded with a radioactive densitometer.
The
densitometer has three basic components : radioactive source, detector, and recorder. The
densitometer measures the slurry density by emitting a radioactive beam through the slurry
to the detector.
Since this instrument is the only routinely available method to monitor cement properties
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continuously during a primary cement job, the densitometer should be properly calibrated
and correctly operated. The densitometer should always be placed where the slurry is under
pressure. Air bubbles present in the unpressured slurry can significantly affect the
measured density. A pressurized mud balance may be used to spot-check the density of the
slurry and the densitometer calibration.
4.8.10
Cementing Heads
Cementing lines are attached to the casing by a cementing head, which also holds the wiper
plugs before release. The widely used single-plug, quick-change cementing head is shown
in Figure 15. If two plugs are employed, loading the second, top plug requires that pumping
be stopped and the head reopened. This change should be executed as quickly as possible
to minimize the time the slurry is not being pumped. Double-plug, continuous pumping
heads do not require reloading.
However, because of their large size and greater complexity, these heads are not in common
use. Special cementing heads are also available that greatly facilitate pipe rotation while
cementing. This has proven to be beneficial to primary cementing, as discussed later (see
Section 4.12).
Figure 15. Single Plug, Quick Change Cementing Head
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4.9
PRIMARY CEMENTING
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PLANNING A PRIMARY CEMENT JOB
Planning a primary cement job should begin weeks in advance. Generally the steps
involved in planning the cement job involve reviewing government regulations, estimating
the volume of cement to be pumped, specifying the slurry, testing the slurry, and selecting
the spacer and displacing fluids to be used.
4.9.1
Government Regulations
In many areas there are government regulations for primary and remedial cementing. These
regulations are generally motivated by the desire to protect fresh water aquifers, to protect
the environment, or to prevent interzonal flow that could inadvertently charge low-pressure
zones or commingle reservoirs. These regulations should be observed in all cementing
operations.
4.9.2
Cement Volume Requirements
The volume of cement to be pumped is determined by coverage requirements, hole
geometry and excess volume percentages. Coverage requirements are usually specified by
government regulation, company policy or field rules. For production strings, cement is
usually required to be brought 500-1000 ft above the highest fluid-bearing zone.
For planning purposes, the hole geometry is usually estimated based on bit size or past
experience. Final volume adjustments are made after the results from caliper logs are
known.
In many areas, the volume of cement is often increased by an excess volume percentage (or
factor) due to uncertainty in knowing the exact geometry. Typically 25% is used. Care
should be taken, however, in using too much cement because of the possibility of lost
returns induced by a long cement column.
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4.9.3
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Specifying A Slurry
After the anticipated annular cement column height has been established, the cement slurry
can be specified. This is often done with the cooperation of cementing service company
representatives. However, the engineer has the responsibility for accurately portraying the
well conditions and assessing any proposed cement slurry formulation. The considerations
involved in cement slurry formulation have been discussed previously (See 4.6).
4.9.4
Cement Testing
Perhaps the most important phase in planning a cement job is cement testing. There are
generally two types of cement samples that can be tested : (1) lab blend and (2) field blend.
A lab blend is a laboratory-size sample that is used to test a proposed slurry formulation.
Often, testing a number of different lab blends is required until an acceptable slurry
formulation is achieved. Lab blends may not use cement and additives from the same stock
as is used for the actual job.
A field blend sample is a sample drawn from the actal blend of dry cement and additives
that is to be used for the job. The field mix water should be used, whenever possible, for
field blend testing.
For critical wells, both lab blend and field blend testing should be performed. On routine
jobs, where there is sufficient field experience with a successful slurry formulation,
laboratory blend testing may not be necessary. However, field blend testing should be
conducted periodically to verify that cement performance is consistent with design
assumptions.
4.9.5
Spacer Fluids
A spacer or preflush is a fluid pumped ahead of the cement to separate the cement from the
drilling fluid and to improve the displacement of the drilling fluid.
Separation of the cement from the drilling mud is sometimes required because of
incompatibility. For example, a drilling mud that contains CaCl2 could cause premature set
when mixed with the cement.
Even if the mud and cement are compatible, a spacer or preflush fluid should be used to
enhance mud displacement. Research has shown that, for water-base muds, fresh water can
significantly improve mud displacement. For oil-base muds, diesel has been reported to be
effective.
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Other spacer/preflush products are sold by the cementing service companies If these
products are used, their compatibility with the fluids to be contacted should be considered.
For displacement purposes, generally the more spacer pumped the better. However,
hydrostatic pressure conditions or economic constraints often limit the spacer volume.
Typically 10-50 bbls of spacer are pumped.
When using a spacer fluid that is lighter than the cement and drilling mud (e.g. water or
diesel), it is generally advisable to pump the spacer ahead of the bottom plug. This helps
prevent mixing of the lightweight spacer with the heavy cement above it on the trip down
the casing.
4.9.6
Displacing Fluid
The choice of the fluid used to displace the top plug depends on the next operation to be
carried out. If additional drilling is required, drilling fluids is often the displacement fluid.
If the next operation is to complete the well, the displacing fluid generally should be a
formation-compatible completion fluid.
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4.10
PRIMARY CEMENTING
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PRIMARY CEMENTING OPERATIONS
After the cementing equipment and cementing materials have been selected, careful
consideration should be given to the operations involved in executing a primary cement job.
4.10.1
Preparing The Casing Surface
Research has shown that cement bonds best to rough or slightly rusty casing surfaces.
Smooth, oily finishes result in the poorest bond. Therefore, if the casing is new, any mill
varnish should be removed. Sandblasting is an effective removal technique. Special
coatings to roughen the surface are not usually required.
4.10.2
Mud Conditioning
Before running the casing a final bit trip should be made to circulate and condition the mud.
This circulation breaks the gel structure of the mud that develops while the mud is static.
Solids control equipment should be operated and the mud circulated until the in and out
mud properties have stabilized at values conducive to good displacement. For vertical
wells, a 10-min. gel strength less than 10 lb/100 ft2 at 120°F is often specified.
The mud should also be circulated and conditioned after the casing is run. Generally the
rate should be as fast as possible without losing returns to promote good hole cleaning. The
mud again should be conditioned to the predetermined properties. At a minimum, one
casing volume should be pumped to ensure that nothing blocks the float equipment.
4.10.3
Running Casing
The casing should be run slow enough so that the surge pressure does not exceed the
formation fracture pressure. This is particularly important in areas having relatively fragile
formations. Calculation methods are available for determining the maximum safe running
speed. Typical values are 30-150 sec/joint.
The casing should be spaced so that the last coupling is below the casinghead and that the
cementing head, if possible, is located at a convenient height above the rig floor.
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4.10.4
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Mud Displacement
Perhaps the most important factor for achieving a successful primary cement job is
obtaining good mud displacement. Failure to displace all of the mud from the annulus will
leave a mud channel within the cement sheath. In some cases the mud channel may occupy
a significant portion of the annulus. The mud channel can greatly reduce the integrity of
the cement sheath. For example, if perforations penetrate such a channel, unwanted fluid
may flow along the channel to the perforations.
Research and field experience have identified a number of factors to enhance mud
displacement while cementing. These include
•
Casing centralization
•
Mud conditioning
•
Using spacer fluids
•
Pipe movement
•
High pumping rates
Casing centralization, mud conditioning, and spacer fluids have been discussed previously.
Casing movement and pumping rate are discussed below.
4.10.5
Casing Movement
Research and field experience have clearly shown that casing movement while cementing
improves cementing success. Two types of movement are possible : reciprocation and
rotation.
Reciprocation is usually accomplished using the rig drawworks. Typically the casing is
reciprocated in 20 ft strokes at speeds not exceeding the last running speed.
Rotation requires the use of a swivel type cementing head. The rotation is often imparted
by a special hydraulic motor incorporated into the cementing head. Typically the casing is
rotated at 15-25 rpm. The applied torque, should not exceed the makeup torque of the
casing.
4.10.6
Pumping Rate
Laboratory studies have demonstrated that for best mud displacement the best pumping rate
is the fastest rate possible. The experiments indicate that mud displacement improves with
increasing flow rate whether or not the cement is in turbulent flow. Therefore the best
practice is to pump as fast as possible without losing returns. (Of course the rate should be
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slowed as the top plug approaches its landing collar).
4.10.7
Pressure Considerations
The major limitation to pumping at high rates is the risk of exceeding the formation fracture
pressure at some point. Lost returns while cementing can lead to cement bridge offs, too
low a top-of-cement and possible formation damage.
To avoid lost returns while cementing, the surface pumping pressure should be low enough
so that the bottom hole pressure is below the fracture pressure of the well. The bottom hole
pressure is approximately equal to the surface pressure plus the hydrostatic pressure of the
liquids in the casing, since the friction pressure in the casing is usually negligible.
4.10.8
Displacement Volume
The volume of displacement fluid to be pumped is the volume from the float or landing
collar to the surface. The volume should be carefully monitored using the calibrated
cementing company displacement tanks. If the rig pumps are used for displacement,
volume can be monitored from the pump stroke count. However, the rig pumps should be
calibrated beforehand.
If the top plug does not bump when the calculated displacement volume has been pumped,
it is generally inadvisable to overdisplace (i.e. pump additional fluid). This is because of
the risk of leaving the critical lower portion of the annulus uncemented by-passing a hungup top plug.
4.10.9
After-Cementing Considerations
After all the fluids have been pumped, the remaining steps to complete the cementing
operation include :
•
Suspend the casing from a set of slips
•
Check that the float equipment check valves are holding
•
Release the internal casing pressure
•
Rig down the cementing equipment
•
Wait on the cement
•
Run an optional temperature log as the cement sets
•
Drop the casing hanger and land the casing in the casinghead
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Waiting-On-Cement Time
The required waiting-on-cement (WOC) time varies, depending on well conditions, cement
slurry, and local regulations. WOC time should be long enough to provide a minimum
compressive strength of 500 psi before the well is drilled out and 2000 psi before it is
perforated.
4.11
ANNULAR FLUID MIGRATION
4.11.1
Problems Caused By AFM
In some areas operators have encountered evidence of fluid flow through the cement sheath
shortly after cementing. This phenomenon is often called annular fluid migration (AFM),
annular gas flow (AGF), or flow induced by loss in annular pressure (FILAP). The problem
is often manifested by pressure on the annulus at the surface several hours after the cement
job. The problem may also be indicated by noise or temperature logs suggesting interzonal
flow prior to perforating. The severity of the problem can vary from simply being a
nuisance to causing a blowout.
4.11.2
Pressure Reduction In Cement
Laboratory measurements have demonstrated that the pressure in a stationary vertical
column of cement decreases with time. By monitoring the pressure in the annulus through
sensors attached to casing at several depths, Cooke et al. showed that the pressure reduction
also occurs in the field (Figure 16). Cooke et al. showed that the pressure can even fall
below the pressure that would be exerted by the cement mix water. The pressure loss in a
cement column before the cement cures is believed to be frequently responsible for vertical
fluid flow through the cement sheath in the casing/borehole annulus.
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Figure 16. Field measurement of pressure decline in cement columns
(from Reference 23)
It is likely that annular gas flow occurs when the pressure in the cement across a gasbearing zone falls below the pore pressure of the zone and the cement has not attained
sufficient strength/impermeability to prevent flow (Figure 17).
Figure 17. Annular Gas Flow that may occur when the pressure in the cement
falls below the formation pore pressure
Annular fluid migration is generally distinguished from poor mud displacement by its
occurrence prior to perforating. Neither problem, however, precludes the other as a source
of fluid flow in the annulus.
4.11.3
Conducive Conditions
Based on current knowledge, Cooke et.al. identified conditions that are believed to be
conducive to AFM. These include :
•
High pore pressures. A smaller reduction of pressure in the cement then allows fluid
to enter the wellbore.
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•
Large difference in pore pressure in nearby permeable zones. Fluid loss in the
pressure-depleted zones decreases the cement column pressure and allows higher
pressure fluids to enter.
•
High fluid loss from cement. This contributes to volume reduction of the cement,
which results in pressure reduction.
•
High gel strength in the cement before curing. This factor decreases the likelihood
that the column will move to compensate for volume reduction.
•
Log cement columns. A long cement column increases the length of the annular
interval that is likely to undergo a pressure reduction.
•
A long period of time before the cement develops strength and impermeability.
Prevention Procedures
No completely successful technique to prevent AFM has yet been found. However, a
number of procedures have been reported that apparently work in some cases.
•
Applying pressure to the annulus immediately after cement placement.
•
Minimize the height of the cement column.
•
Use low-fluid-loss cements.
•
Do not over-retard the cement.
A number of other techniques have been proposed to prevent annular fluid migration.
These techniques include in situ gas generation in the cement slurry, additives to
immobilize the water in the pore space of the cement, and external casing packers. Though
some of these techniques may have merit in certain situations, there has not been sufficient
field or independent laboratory data taken to fully evaluate them.
4.11.5
Repair Techniques
The mechanism of AFM suggests that the unwanted annular flow may be caused by
relatively small and numerous channels cut through the cement. For this reason, repair of
AFM is very difficult.
Repair often requires numerous squeeze attempts. In some cases a non-Portland epoxy-type
cement has been used with success.
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Channel repair techniques are discussed further in the Remedial Cementing Chapter
(Sections 21.7 and 21.13).
4.12
SPECIAL PRIMARY CEMENTING CONSIDERATIONS
There are a number of primary cementing jobs that warrant special consideration. These
include cementing liners, cementing deviated wells, stage cementing, and cementing
multiple strings.
4.12.1
Cementing Liners
A liner is a string of casing that does not extend up to the wellhead. Liners are generally
run into the hole on drill pipe and are suspended from a previous casing string. Cement is
then pumped through the drill pipe, down the liner, and into the annular space.
Some of the common problems that should be considered when cementing a liner are small
annular flow areas, cement contamination at the liner top, and temperature differential
between the top and bottom of the liner.
Careful attention should be paid to slurry design. In general a low-fluid-loss slurry should
be used. However the viscosity may also need to be kept low. (Recall that many fluid-loss
agents also viscosify). In addition, the compressive strength of the slurry should be tested
at both the BHST and the static temperature at the liner top.
Field experience has also suggested that liner cementing success is greatly enhanced by
moving the liner while cementing and by pumping a sufficient volume of cement past the
liner top. However, care must be taken if cement above the liner top is reverse-circulated
out. This is because high pressures may be exerted on the liner top during this operation.
4.12.2
Cementing Deviated Wells
Cementing a deviated or directional well is generally more difficult than cementing a
vertical well because the problems of good cement placement are move severe. Research
and experience have shown that cementing a deviated well requires particular attention to
pipe centralization, hole cleaning, cement free water, and pipe movement.
Because of the difficulty in displacing settled solids from the low side of the hole and also
the probability that the casing will be decentralized toward the low side of the hole, it is
likely that a coherent mud channel remains along the low side of the cemented annulus in
many deviated wells.
Also, free water breakout from the cement may result in water pockets along the high side
of the annulus.
In some deviated wells the possibility of these channels in the cement sheath may have
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implications for completion and workover operations. For example in some high-angle
wells, it may be desirable to perforate away from the low side on initial completion.
4.12.3
Stage Cementing
Stage cementing is the sequential placement of cement into different intervals of the
wellbore. Usually stage cementing consists of a conventional placement of cement slurry
around the lower portion of the casing (first stage) followed by placement of cement across
an upper interval by the pumping of a slurry through ports in a stage collar higher up in the
casing string (second stage). The ports in the stage collar are opened by special opening
plugs or mechanical movement of a work string.
Stage cementing is most commonly used when long casing strings are cemented. Some of
the reasons to use stage cementing are :
•
To place cement across weaker portions of the wellbore that would break down if
subjected to the pressure of a full column of cement.
•
To avoid excessive cement setting times at the lower temperatures higher up in the
annulus.
•
To place cement selectively across widely separated formations.
•
To limit the height of the setting cement column to help mitigate AFM.
•
To reduce the pump pressure required to displace the cement at a desired flow rate.
One disadvantage of stage cementing is that the pipe cannot be removed to enhance mud
displacement after the first stage has set. Other disadvantages are that stage cementing
increases the mechanical complexity of the cement job and that leaks at the stage collar may
occur. Also multiple-stage cementing generally requires more time than a single-stage job.
4.12.4
Cementing Multiple Strings
Some types of completions, such as multiple tubingless completions, require more than one
string to be run and cemented in the same borehole. Often these strings serve as both
casing and tubing and may be more economical than a conventional completion.
Perhaps the most significant problem in the cementing of multiple strings is to obtain
effective mud displacement. Obtaining good displacement during the cementing of
multiple strings is difficult because the annular areas are usually large and irregular.
Many of the factors for good displacement in the cementing of a single string also apply in
the cementing of multiple strings. In particular, pipe reciprocation may help.
Another technique to improve displacement is to pump down more than one string. For a
given surface pressure limit, this increases the flow rate achieved. Also, a string that could
be landed at a shallower depth can be run to the bottom to increase the annular velocity by
decreasing the annular area.
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WELLHEADS
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CHAPTER 5
WELLHEADS
TABLE OF CONTENTS
5.1
WELLHEAD SYSTEM …………………………………………………………...... 3
5.1.1
5.1.2
5.1.3
5.1.4
5.1.5
5.1.6
5.1.7
5.1.8
5.2
CHRISTMAS TREE …………………………………………………………...…. 16
5.2.1
5.2.2
5.2.3
5.2.4
5.2.5
5.2.6
5.2.7
5.2.8
5.3
Master Valves ……………………………………………………….. 17
Flow Tree …………………………………………………………… 17
Wing Valve …………………………………………………………. 17
Choke ……………………………………………………………….. 17
Crown Valve ………………………………………………………… 19
Valve Operation …………………………………………………….. 20
Testing The Tree ……………………………………………………. 20
Fire Resistant Trees …………………………………………………. 20
SUSPENSION METHODS ………………………………………………………. 22
5.3.1
5.3.2
5.3.3
5.3.4
5.3.5
5.3.6
5.3.7
5.3.8
5.3.9
5.4
Wellhead Function ………………………………………………….. 3
Christmas Tree Function ……………………………………………. 4
Tubulars …………………………………………………………….. 4
Typical Wellheads …………………………………………………... 6
Casing Head ………………………………………………………… 8
Intermediate Casing Head …………………………………………... 9
Tubing Head ………………………………………………………… 11
Christmas Tree Assembly …………………………………………... 14
Casing Suspension ………………………………………………….. 22
Automatic-Type …………………………………………………….. 22
Non-Automatic-Type ……………………………………………….. 23
Mandrel-Type ……………………………………………………….. 23
Tubing Suspension ………………………………………………….. 24
Double-Box Method ………………………………………………… 24
Adapter Flange Method …………………………………………….. 26
Mandrel Method …………………………………………………….. 27
Slip Suspension Method ……………………………………………. 29
SPECIAL WELLHEAD EQUIPMENT …………………………………………. 30
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5.4.1
5.4.2
5.4.3
5.4.4
5.4.5
5.5
5.1
January 1998
Tubingless Wellheads ………………………………………………. 30
Multiple Completion Wellheads ……………………………………. 33
Ground Subsidence Wellheads ……………………………………… 35
Injection Wellheads …………………………………………………. 38
Artificial Lift Wellheads ……………………………………………. 39
Flanges ……………………………………………………………… 40
Oval Ring Seal ……………………………………………………… 40
Octagonal Ring Seal ………………………………………………… 40
RX Ring Gasket Seal ……………………………………………….. 40
Grayloc Connection …………………………………………………. 42
Flex-Float Connection ………………………………………………. 42
Resilient Seals ………………………………………………………. 43
44
Pressure-Temperature Ratings
……………………………………….
Casing Program …………………………………………………….. 45
Metalluragical Requirements ……………………………………….. 45
Special Applications ………………………………………………… 45
Pressure Requirements ……………………………………………… 46
Crossover/Pack-off Flanges ………………………………………… 49
EQUIPMENT SPECIFICATIONS ………………………………………………. 51
5.7.1
5.7.2
5.7.3
5.7.4
5.7.5
5.7.6
5.7.7
5.8
PROPRIETARY INFORMATION -For Authorised Company Use Only
WELLHEAD DESIGN CONSIDERATIONS …………………………………... 45
5.6.1
5.6.2
5.6.3
5.6.4
5.6.5
5.7
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FLANGES AND SEAL CONNECTIONS ………………………………………. 40
5.5.1
5.5.2
5.5.3
5.5.4
5.5.5
5.5.6
5.5.7
5.5.8
5.6
WELLHEADS
Industry (API) Specifications ……………………………………….. 51
PCSB Company Specifications …………………………………….. 51
Service Environments ………………………………………………. 52
Sweet Oil ……………………………………………………………. 52
Sweet Gas …………………………………………………………… 52
Hydrogen Sulfide …………………………………………………… 53
Special Temperatures ……………………………………………….. 53
SPLITTER WELLHEAD TECHNOLOGY .....…………………………………. 54
WELLHEAD SYSTEM
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Every oil or gas well has some type of wellhead. Conventional wellhead assemblies
include the casing head, casing hangers, spool sections, tubing head, tubing hanger, valves,
and fittings. (See Figure 1).
Figure 1. The Wellhead System
5.1.1
Wellhead Functions
The wellhead performs three important functions :
5.1.2
•
It provides connection and support for BOP’s and other well control equipment;
•
It provides a sealed connection and support for each tubular string; and
•
It provides a connection and support for the Christmas tree.
Christmas Tree Function
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The Christmas tree, in turn, performs several important functions :
5.1.3
•
It controls the flow of fluids from the wellbore;
•
It provides a means of shutting in the well; and
•
It provides a means of entering the well for servicing and workover.
Tubulars
The wellhead is divided into sections. Each section of the wellhead will be used to suspend
and/or seal off a separate string of casing or tubing.
Therefore, the number of wellhead sections will vary with the number of tubular strings.
The tubular strings in a well are the conductor pipe, the surface casing, the protective
(intermediate) casing, the production casing, and the production tubing (see Figure 2). In
some wells, where formation conditions do not place extreme loads on the surface casing,
the protective string may not be required. In other wells, usually where abnormally
pressured formations are encountered, additional strings of protective casing may be
necessary. In a tubingless well, the production tubing is omitted.
A common wellbore configuration, sometimes called a three-string well, will make use of
each of the above strings. The three strings referred to are the surface casing, protective
casing, and the production casing. Each of these strings will be effectively sealed to
contain pressures within each string.
The conductor pipe, which may be set or driven, maintains the integrity of the walls of
shallow, unconsolidated formations. It is not normally attached to the wellhead, because it
is exposed to minimal pressures. However, in some cases, a base plate may be welded onto
the A-section and placed on top of the conductor pipe in order to distribute the weight of
the casing and wellhead (Figure 3). When extreme loading conditions are expected, the
plate provides additional support and stability.
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Figure 2. The Tubular Strings
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Figure 3. The Base Plate
5.1.4
Typical Wellhead
The typical wellhead for a three-string well will consist of (Figure 4) :
•
The A-section Casing head (sometimes referred to as the Bradenhead);
•
•
The B-section Casing head (or Intermediate Head);
;
The C-section (or Tubing Head); and
•
The Christmas Tree.
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Figure 4. A Three-String Wellhead
NOTE : The sections of the wellhead may be divided into separate parts at times such as A1, A2, A3,
etc.....
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5.1.5
WELLHEADS
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Casing Head
The A-section casing head is attached to the top of the surface casing (Figure 5). Since the
other tubular strings are tied to the A-section, the surface casing must support the weight of
all subsequent strings, the tubing, and the entire wellhead system.
Figure 5. The A-Section Casing Head
The A-section is screwed or welded onto the surface casing. This casing head accepts the
next string of casing - either a protective string, or the production casing, depending on the
needs of the well.
The space between any two strings of pipe is called an annulus. The space between the
surface casing and the wall of the hole is designated as the ‘surface casing-by-hole-annulus’
(Figure 5). It may also be referred to as the casing-hole annulus. When the surface casing
is set, the surface casing-by-hole annulus is filled with cement, which (1) eliminates
potential contamination of fresh water zones behind the surface casing, (2) prevents flow
between pressured formations behind the surface casing, and (3) provides additional
stability of the casing string.
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5.1.6
WELLHEADS
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Intermediate Casing Head
The intermediate casing head, or B-section, is bolted onto the A-section (Figure 6). It can
be used to suspend either the production casing string, as shown, or an additional string of
protective casing, if required. For each additional protective string, an additional
intermediate section is required.
Figure 6. The Intermediate Casing Head
The intermediate casing head consists of a lower flange, for connection to the A-section,
and an upper flange, for connection to the subsequent wellhead section. A cylindrical bore
with shoulders, essentially the same as that of the A-Section, is milled into the upper half of
the head to receive the casing hanger. The intermediate casing head will contain a primary
seal, located inside the top flange, which seals the production-protective casing annulus and
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a secondary seal, located in the lower flange, that seals the protective-surface casing
annulus (Figure 7).
Figure 7. The Intermediate Casing Head with Secondary Seal
The secondary seal performs essentially the same function as the primary seal of the Asection. That is, it contains pressures from the production-protective casing annulus within
the B-section. It also works in conjunction with the A-section primary seal to prevent
communication between the protective casing and the protective-surface casing annulus.
A ring gasket, made of a special metal alloy, is placed between all flanged connections.
The ring gasket fits into specially machined grooves in the upper flange of the A-section
and the lower flange of the B-section.
The gasket serves to contain pressures in the wellhead in the event that either or both the
primary and secondary seals should fail. Each ring gasket is designed to withstand a
maximum pressure that the tubulars will be exposed to during the life of the well. A further
explanation of ring gaskets and pressure ratings is discussed later.
The side outlets on the intermediate casing head are used to check and relieve pressures
inside the production casing by protective casing annulus.
5.1.7
Tubing Head
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The tubing head suspends the production tubing and seals off the tubing-casing annulus
(Figure 8). Like the intermediate casing head, the tubing head includes a secondary seal
and side outlets. The top flange of the tubing head is used to connect blowout preventers
during conventional workover operations; that is, workovers that require pulling the tubing.
The lower flange connects to the top flange intermediate section. A ring gasket is also used
between these flanged connections.
Figure 8. The Tubinghead
The tubing hanger assembly (Figure 9) performs essentially the same function as the casing
hangers; i.e., it suspends the tubing and seals off the tubing-production casing annulus.
Virtually the full weight of the tubing string is supported by the tubing hanger. However, in
some cases, the tubing is attached to the tubing head adapter by one of several possible
methods. In such a situation, the weight of the tubing rests on the adapter flange which, in
turn, rests on the upper flange of the tubing head. In this situation, the tubing hanger only
serves to seal the tubing-casing annulus.
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Figure 9. The Tubing Hanger Assembly
The side outlets of the tubing head can be accessed to (1) inject a fluid into the tubingcasing annulus, as in a gas lift operation (Figure 10); (2) confirm that there is no annulus
pressure; (3) test for leaks; and (4) relieve pressure in the tubing-casing annulus.
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Figure 10. Gas Lift Operation
5.1.8
Christmas Tree Assembly
The Christmas tree is a system of gate valves and a choke that regulates the flow of fluids
from the well, opens or shuts production from the well, and provides entry into the well for
servicing. The tree is connected to the uppermost flange of the wellhead, which typically is
the upper tubing head flange.
A typical tree for a three-string wellhead includes a tubing head adapter, several gate
valves, a flow tee, and a choke (Figure 11). This system routes well production into the
flowline. The flowline then conducts the fluids from the choke to surface treating or
processing facilities.
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The gate valves normally include three types: the master valves, the wing valve or valves,
and the crown valve. Each valve has only two operating positions - fully open and fully
closed (Figure 12). They are used to open or shut the flow from the well. The choke
performs the function of regulating the flow rate.
Figure 11. The Christmas Tree
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Figure 12. Operation of a Gate Valve
5.2
CHRISTMAS TREE
The Christmas tree is a system of gate valves that regulates the flow of fluids from the
well, opens or shuts production from the well, and provides entry into the well for
servicing. They are available in either composite (Figure 11) or block-type (Figure 13)
construction. Composite trees indicate that they are a composite of valves and flow tees
that are bolted together. On the other hand, a block-type tree is machined out of a single
piece of metal.
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Figure 13. Christmas Tree Assembly – Block Type
5.2.1
Master Valve
The master valves are used to close in the well to allow servicing of the wing valve, crown
valve or choke, or to allow connection of treatment lines, lubricators, and wireline BOP’s.
Two master valves are installed in high pressure (5,000 psi and above) wells. The lower
master valve is a backup for the upper master valve.
Valves used on Christmas trees and wellheads are subject to special requirements. Master
valves and other valves in the vertical flow path of the tree must have full bore, round
openings to allow passage. of tools. As a result, wellhead master-type valves are the gate
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type as shown in (Figure 12). Round opening steel, or gate valves are specified for this
service with API flanged end connections or threads. Valves used on multiple-completion
trees have center distance between bores established and limited by the casing size and
hanger spacing.
Directional orientation of the multiple completion valves and tree equipment is determined
by the direction of slots in the wellhead which accommodates the hanger bowl. The desired
direction should be determined prior to installing the wellhead for proper location of the
valves.
Various types of valve operating mechanisms are available and individual well
requirements will determine this need. Location, regulatory requirements, and safety
aspects of well operation should be considered when selecting valve operators.
5.2.2
Flow Tree
The flow tee connects immediately above the upper master valve. It is used to connect the
upper master valve to the crown and wing valves.
5.2.3
Wing Valve
The wing valve, like the master valves, is used to close in the well. Located between the tee
and the choke, it is the first valve that is closed when shutting off the well, and the last one
opened when opening the well.
5.2.4
Choke
Connected to the wing valve, the choke regulates the flow of fluids from the wellhead. A
choke functions by increasing or decreasing the diameter of the fluid path. The nonadjustable choke includes removable inserts that can be used to alter the rate of flow by
means of larger or smaller choke beans (Figure 14). An adjustable choke can be used to
alter the flow rate without having to shut in the well to replace an insert (Figure 15).
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Figure 14. The Non-Adjustable Choke
Figure 15. The Adjustable Choke
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5.2.5
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Crown Valve
The crown valve (also a gate valve), connected to the top of the flow tee, is also referred to
as the swab or wireline valve. In wireline or swabbing operations, a wireline lubricator is
flanged to the top of the crown valve. The lubricator provides a hydraulic seal around the
wireline, which prevents the escape of pressure while the wireline is in the well (Figure 16).
The crown valve should be closed while installing the lubricator, and then opened to allow
wireline entry into the well.
Figure 16. Wireline Lubricator
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Frequently, a pressure gauge will be attached to the top of the Christmas tree (the upper
flange of the crown valve). This pressure gauge is used to monitor either the flowing
wellhead pressure, or the static wellhead pressure with the wing valve closed.
5.2.6
Valve Operation
The tree is operated by operating or closing the valves in a specific order. When shutting in
the well, the first valve that should be closed is the wing valve. The upper master valve is
then closed, and is followed by the lower master valve. The lower master valve is closed
last to ensure that is not closed against a differential pressure; thus saving the valve seats
from excessive wear. In a well control situation, this valve may be the last available valve
to shut in the well so its integrity should be preserved until the valve is needed.
For reopening the flow stream, the procedure is reserved, starting from the lower most
master valve, and ending with the wing valve.
The choke is used to adjust the rate of flow, but cannot be used to shut in the well.
5.2.7
Testing The Tree
The tree is pressure tested for leaks after it has been flanged onto the tubing head or casing
head.
The Christmas tree components individually bolt together. The tree is normally assembled
and pressure tested as a complete unit prior to being flanged onto the wellhead, and
pressure tested again after installation.
Each connection is tested to the specified rating of the tree. In the field, a small hydraulic
pump is used to test the connection between the tubing head and the tubing head adapter.
A light oil is injected into a port on the upper flange of the tubing head. The pressure is
increased until the desired maximum is reached. If the pressure does not hold steady after
waiting a few minutes, the lock screws are retightened and the test repeated.
5.2.8
Fire Resistant Trees
Fire-resistant trees are sometimes required and are of the block type. However, they differ
from the normal block type tree in that clamps are used instead of stud bolts to secure the
tree and wellhead and the seals are metal-to-metal to prevent deterioration in the event of a
fire. An example is shown in Figure 17.
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Figure 17. Fire Resistant Wellhead
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5.3
WELLHEADS
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SUSPENSION METHODS
Suspension or hanger assemblies are used to suspend the casing or tubing in a particular
casing or tubing head as is shown in Figures 6, 8, and 9.
5.3.1
Casing Suspension
The casing hangers most generally used in PCSB operations are the slip-pack type of which
there are two general categories : (1) those that may be set and sealed without removing
blowout preventers (the automatic type), and (2) those that may be set through preventers
but require removal of preventers to establish a seal. The type chosen depends upon
operating conditions and economics since the automatic type is more expensive than the
others but can save on rig time costs. Either of these categories of hangers will permit
setting casing at desired depths without use of space nipples. Examples of the two types are
shown in Figures 18 and 19.
5.3.2
Automatic Type
The automatic seal wrap-around controlled suspension hanger is hinged and may be
installed on the casing landing joint by wrapping around the pipe and lowering or dropping
through the blowout preventers into the casing head. When the weight of the suspended
casing is transferred to the hanger slips and to the casing head, the seal is expanded. The
controlled suspension feature, or the dulled teeth on the back of the slips, prevents the
hanger slips from moving far enough to wedge the casing detrimentally. These hangers are
designed for heavy casing loads and are therefore recommended for long strings where the
automatic sealing feature is also required.
Figure 18. Automatic-Type Hanger
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Figure 19. Non-Automatic-Type Hanger
5.3.3
Non-Automatic Type
With the non-automatic seal with wrap-around slips, the slips are lowered through the
preventers to suspend the pipe, but then a “doughnut type” seal is made only after removing
the preventers and cutting the casing off. The seal, depending upon the make, is either
expanded by set screws on top of the packing or by external lock screws. This type, which
is generally the lowest cost slip-pack hanger, is recommended for shallow or medium depth
wells automatic sealing is not considered necessary. Generally speaking, the longer the
slips, the greater the safe load carrying capacity.
5.3.4
Mandrel Type
The threaded mandrel hanger is commonly called a “boll weevil” hanger. It can be used on
casing although it is more frequently used with tubing1, particularly in tubingless
completions for hanging the production casing. An example is shown in Figure 20. If close
tolerances on setting depths are necessary, its use requires space nipples and pup joints
which are more costly per foot than casing or tubing. This additional cost may more than
offset the lower cost of the threaded hanger and additional rig time required to use space
nipples.
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Figure 20. Mandrel-Type Hanger
5.3.5
Tubing Suspension
Tubing, like casing, is run through blowout preventers and suspended in a head section.
There are four tubing suspension methods. In the double-box and adapter flange methods,
the tubing is hung from the tubinghead adapter. In the mandrel-type and slip-type
suspension method, the tubing is hung from the tubing head.
5.3.6
Double-box Method
In the double-box method, an adapter nipple is threaded onto the end of the tubing (Figure
21). This nipple has an internally machined profile designed to accept a back pressure
valve (or BPV).
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Figure 21. The Double-Box Method of Tubing Suspension
The BPV is used as a well control backup on wells that have been killed prior to workover
or completion. In this method, the use of the BPV assures that pressures in the tubing are
safely contained while nippling-up or nippling-down the Christmas tree and workover
BOP’s. The BPV may be installed or removed on wireline, through a lubricator.
The tubing hanger is wrapped around the last joint of tubing. With this double-box method,
the tubing hanger will only serve to seal the tubing annulus, not to suspend the tubing. A
temporary spacing element called a slip protector is then placed immediately above the
hanger which will keep the nipple threads safely away from the lateral lock screws in the
tubing head when the lock screws are tightened.
A short piece of tubing called a landing joint is used to lower the hanging assembly into the
BOP’s. The hanger passes through the BOP’s and lands in the tubing head.
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Once the hanger has been properly seated, the lock screws on the upper flange of the tubing
head are tightened to activate the hanger seal, and secure the hanger in place. The landing
joint is backed off of the adapter nipple, and the BOP’s are nippled down.
A set of O-rings, which provide the pressure seal between the adapter nipple and the
Christmas tree, are slipped into position on the adapter nipple. The adapter nipple is
properly doped. The assembled Christmas tree, including the tubing head adapter, is then
lowered onto the adapter nipple, and J-latched or screwed into place. Once the adapter
nipple is secured, the weight of the tubing rests on the adapter flange, and the temporary
slips are removed. The ring gasket groove on the tubing head and in the base of the adapter
flange are carefully cleaned. The ring gasket, which had been placed above the temporary
slips, is then placed in the groove. A light grade of oil is used to fill the space between the
gasket and the tubing. The Christmas tree assembly is lowered onto the tubing head and
ring gasket, then flanged-up.
The lock screws of the tubing head are retightened to further secure the tubing hanger seal.
Once the tree assembly has been flanged-up and pressure tested, the back-pressure valve is
removed through the lubricator on wireline. The well is shut-in using the gate valves of the
tree.
5.3.7
Adapter Flange Method
The second type of tubing suspension is called the adapter flange method (Figure 22). This
technique is the same as the double-box method, with the exception that the adapter nipple
is not used. Instead, the Christmas tree and tubing adapter are screwed directly onto the last
joint of tubing.
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Figure 22. The Adapter Flange Method of Tubing Suspension
5.3.8
Mandrel Method
The third common tubing suspension method is called the mandrel, or “bowl weevil,”
method. In this method, the tubing hanger is screwed directly onto the end of the tubing
and hung off in the tubing head (Figure 23). Since the weight of the tubing bears down on
the hanger seals, they are automatically actuated. Lock crews, however, are still tightened
to secure the seal.
After the tubing is suspended and sealed off, the landing joint is backed off, and the tubing
head adapter and tree are bolted on. Since the tubing is not tied into the adapter flange, the
ring gasket will be subjected to the production fluids and pressures. Therefore, this
technique is normally used only on low pressure, sweet service applications.
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Figure 23. The Mandrel (Boll Weevil) Method of Tubing Suspension
5.3.9
Slip Suspension Method
The slip-type hanger is used for tubingless completions. It resembles a standard casing
hanger used to suspend other casing strings (Figure 24). Set screws passing through the
packing are tightened to effect the seal. Lock screws are tightened to secure the seal.
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Figure 24. The Slip-Type Method of Tubing Suspension
5.4
SPECIAL WELLHEAD EQUIPMENT
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Special wellhead equipment is required for certain types of wells and applications. These
special applications include :
5.4.1
•
Tubingless wells
•
Multiple completion wells
•
Ground subsidence wells
•
Injection wells
•
Artificial lift wells
Tubingless Wellheads
In a tubingless well, the oil or gas is produced through the production casing; a separate
string of production tubing is not installed. The production casing, in these wells, is
essentially a string of tubing has been cemented in place (Figure 25).
Normally, intermediate strings of casing are not used in a tubingless well. As a result, a
tubingless well will have only one casing head - the A-section. The tubing, or production
casing, will be suspended from this same casing head (Figure 26).
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Figure 25. A Tubingless Well
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Figure 26. A Tubingless Wellhead
5.4.2
Multiple Completion Wellheads
A well may have more than one producing zone. Multiple-completions reduce the number
of wellbores required (Figure 27). Regulations may require that the production from each
zone is kept separate.
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Figure 27. Multiple Completion
In this cases, the completion may require the installation of two or more strings of
production tubing. Special wellhead equipment is required to suspend these multiple tubing
strings, and to keep the flow streams separate (Figure 28).
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Figure 28. A Multiple Completion Wellhead
5.4.3
Ground Subsidence Wellheads
In some areas, large volumes of fresh water are produced from shallow formations, causing
the ground and surface casing to sink. As the ground subsides, the wellhead also subsides.
As a result, the tension stress originally placed in the casing strings tends to decrease
(Figure 29). Proper tension is important for maintaining casing stability. A ground
subsidence wellhead allows the production casing to be retensioned as the ground subsides.
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Figure 29. Effects of Subsidence
With a ground subsidence wellhead, the tubing head is not bolted to the casing head.
Instead, it is screwed onto the top joint of casing (Figure 30). The casing string is easily
retensioned by releasing the lockdown screws, then lifting up on the tubing head. When the
correct tension is achieved, the lock screws are retightened (Figure 31).
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Figure 30. A Subsidence Wellhead
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Figure 31. Retensioning the Casing in a Subsidence Wellhead
5.4.4
Injection Wellheads
Injection wellheads are commonly used for secondary and tertiary recovery processes, or
for the disposal of field saltwater.
Typically, an injection wellhead requires an injection flow loop which consists of a casing
head, tubing head, flow tee, wing valve, crown valve, and elevated flow loop (Figure 32).
The flow loop often incorporates a check valve, ball valve, screen, and flow meter. Some
injection wells, however, require full Christmas trees.
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Figure 32. An Injection Wellhead
5.4.5
Artificial Lift Wellheads
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Two artificial lift techniques require some modification of the standard wellhead equipment
- rod pumping and electrical submersible pumping.
In a rod pumping installation, the wellhead incorporates a stuffing box, which seals the rod
by tubing annulus. This stuffing box is made up onto the flow tee, which is screwed onto
the top joint of tubing (Figure 33). A submersible pump wellhead contains a passageway
which allows the electrical cable to be run through it.
A wellhead outfitted for gas lift is illustrated in Figure 10.
Figure 33. A Rod Pumping Unit
5.5
FLANGES AND SEAL CONNECTIONS
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5.5.1
WELLHEADS
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Flanges
The most common end connections used in the oil industry aside from welds and threads
are flanges. API has standardized flanges and so has the ASA. Because we use both ASA
and API flanges, it is necessary that we know the differences between them.
Only API flanges are used on wellheads, Christmas trees, and drilling through equipment
such as blowout preventers, rotating heads, and valves connected to them. ASA flanges,
fittings, and valves are used in gas plants and lease equipment such as headers, separator
heaters, dehydration units, etc. Occasionally, API flanges are used in high pressure gas
gathering lines where the working pressure of an API valve fits the pressure requirements
better than an ASA valve and there is an economic advantage to be gained.
5.5.2
Oval Ring Seal
The oval ring shown in the oval groove in Figure 34 also fits the flat bottom groove;
however, the octagonal ring will not fit the oval groove. The oval groove was discontinued
about 1945. The oval ring obtains a seal by deforming into the shape of the groove. If
additional weight is added to the upper half of a flange, such as in a wellhead assembly, it
may crush the ring additionally which has the same effect as loosening the flange bolts.
The oval ring has been used more extensively than the others because it would fit both
shapes of grooves and a little less susceptible to damage from handling.
5.5.3
Octagonal Ring Seal
The octagonal ring seal is not as susceptible to crushing as the oval ring. Until the
development of the RX and BX rings (Figure 34), it was the only acceptable ring for use in
the 10,000 psi flanges.
5.5.4
RX Ring Gasket Seal
The RX gasket is a pressure energized ring which fits the standard API flange ring groove
and has been accepted by API as an alternate form of oval ring gasket. The RX ring
evolved during the department of 15,000 psi working pressure flanges. It was determined
that when the ratio of the height of the ring to the height of the sealing surfaces was 3 to 1
greater, the seal was energized by pressure.
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Figure 34. API Ring Gaskets
Specifically, the internal pressure tended to expand the ring against the outer sides of the
ring groove with sufficient force to form a seal. To insure that initial contact is made
between the sealing surfaces of the ring and the outer surfaces of the ring groove, the pitch
diameter of the ring is made slightly larger than the groove. Also, the ring height is
generally greater in proportion than the conventional octagonal ring.
The advantages of the RX ring are (1) less bolt load is required since the ring does not have
to be crushed to effect the seal, and (2) it is pressure energized. The fact that the ring does
not crush while tightening permits faster tightening of flanges as only one round of bolt
tightening is required. This is especially helpful when working with large flanges in a
limited working space. A specific example where RX rings are helpful occurs when
blowout preventers and drilling through equipment need to be worked on underneath the
derrick floor. It is pointed out that care should be taken to insure that the bolts are
tightened securely to prevent breathing of the flange and subsequent galling of the flange
seals.
5.5.4
Grayloc Connection
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The Grayloc connection, Figure 35, is also pressure energized and is used in certain
wellhead connection applications. The lips of the seal ring have a slightly different taper
than the hub to insure a seal when the hubs are drawn together by means of a two-piece,
two-bolt clamp. Once the ends of the clamps are brought together, the bolts are only to
prevent the clamps from spreading. This is a proprietary connection and is available only
from the manufacturer or licensees. The advantages of this type of connection are (1)
reduced area exposed to pressure, thus reducing end thrust, (2) quick connecting, thus time
saving, and (3) lighter weight. Disadvantages are (1) seal on bore are is subject to damage
from tools and direct washing action of fluids, and (2) it is a proprietary connection that is
only available from Grayloc.
Figure 35. Gray Tool Co. Grayloc Connection
5.5.5
Flex-Float Connection
The Laurent or Flex-Float pressure energized connection, Figure 36, utilizes a soft steel
ring wedged by pressure between two surfaces. Adaptations of this seal were originally
used in the bonnets of WKM gate valves and subsequently by National Supply Company to
seal in multiple bores on wellheads and Christmas trees. This is a good sealing principle,
but due to the strict control of parents, its use has been limited.
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Figure 36. Flex-Float Connector
5.5.6
Resilient Seals
Resilient seals used with wellheads in hangers and auxiliary seals are good to about 300º F.
For temperatures above 300º F, special packings containing asbestos and soft metals are
used.
Furthermore it is well to consult the wellhead manufacturer for their
recommendation. Use of O-ring seals to seal against the OD of casing and tubing is not
acceptable because the tolerances of tubular goods OD’s are too great to permit
dependability of seal. Also, if a leak should develop, no outside means is available for
additional make-up.
Small clearances and dimensions between bores of valves and center lines of multiple
completion Christmas trees, wellheads and hangers have necessitated the development of
lip type resilient seals that can be expanded or re-energized by injection of plastic packing.
In all designs, however, these resilient seals should be backed up or contained by metal-tometal seals to the outside, because of susceptibility to damage during installation and to
deterioration with age.
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5.5.6
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Pressure Temperature Ratings
Maximum equipment working pressure ratings for seals and flanges are applicable to the
steel parts of the assemblies for metal temperatures between - 20º F and 250º F. For metal
temperatures below - 20º F, steels which have adequate notch toughness and are suitable for
low temperature service should be used.
Investigations for arctic environments indicate that materials with adequate mechanical
properties exist for these conditions.
The comparatively recent introduction of steam injection for well stimulation necessitated
the need for pressure ratings of wellheads and associated equipment at temperatures in
excess of 250º F. In recognition of these requirements, the API established pressuretemperature ratings for metallic parts in wellheads, valves, and fittings as shown in the
following table.
PRESSURE-TEMPERATURE RATINGS OF METALLIC PARTS OF API WELLHEADS, VALVES
AND FLANGES
Metal Temperature F
-20 to 250º F
300º F
350º F
400º F
450º F
500º F
550º F
600º F
650º F
2000
1995
1905
1860
1810
1735
1635
1540
1430
3000
2930
2860
2785
2715
2605
2455
2310
2145
5000
* 4880
5765
4645
4525
4340
4090
3850
3575
* Does not apply to 5000 psi 6BX API flanges.
5.6
WELLHEAD DESIGN CONSIDERATIONS
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Selecting the appropriate size, type, and pressure rating for each wellhead flange and seal
is a critical task performed in planning the well completion. The design specifications for
a particular wellhead will vary widely from area to area and from well to well, depending
on the specifications and guidelines to cover the particular characteristics of a given field
or geographical location.
The weight, size, number, and metallurgy of the wellhead components will depend upon
the following considerations.
5.6.1
Casing Program
The number of wellhead sections required is dependent upon the number of casing strings
in the well. As already stated, the A-section accommodates the surface and protective
casing string. Also, each casing string diameter will influence the size of the casing hanger
and casing head required.
5.6.2
Metallurgical Requirements
Corrosive conditions such as with hydrogen sulfide (H2S) or in offshore environments will
require special metal alloys.
5.6.3
Special Applications
The installation of artificial lift equipment, or the conversion of a producing well into an
injection well may require special equipment or connections to be installed in the
wellhead. A gas lift system, for example, requires the injection of gas into the tubingcasing annulus, typically, the injection is through the tubing head side-entry port. For a
submersible pump system, the power cable passes through a special conduit in the
wellhead to the downhole motor of the pump (Figure 37). Installation of a surface
controlled, downhole subsurface safety valve (SSSV) usually requires a hydraulic line that
is run from the surface to the downhole valve. Like the submersible pump, the SSSV will
require a special conduit to allow passage of the hydraulic line through the wellhead.
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Figure 37. A Submersible Pump Tubinghead
5.6.4
Pressure Requirements
The pressure rating of each section of the wellhead must be sufficient to control the
maximum working pressure that it is expected to encounter (that is, the maximum shut-in,
injection, or treating pressure that the equipment will be subjected to).
Formation pressures often increase with increases in drilled depth, and each subsequent
casing string is subjected to higher bottom-hole pressures. To match these pressure
increases, the pressure ratings of the wellhead components must also be sure that it is
expected to see during the life of the well.
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Figure 38. Wellhead Working Pressure Ratings
Standard working pressures for flanged wellhead equipment are : 2000, 3000, 5000,
10,000, 15,000 and 20,000 psi. Each flange, however, is tested to twice its working
pressure up to 10,000 psi and 1.5 times the working pressure rating above 10,000 psi (see
Table 1). Essentially, then, each wellhead section has its own built-in safety factor. In all
wells, the pressure rating of the uppermost section of the wellhead is used to categorize the
wellhead. A-sections are normally rated at 3,000 psi because surface casing strings are
normally set to shallow depths and are exposed to minimal pressures. A 2,000psi Asection was commonly installed on low-pressure wells at one time, and they are found in
many older fields, but are not commonly installed within PCSB today. Wellhead sections
rated at 10,000 psi or higher are normally associated with deep or abnormally pressured
wells.
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As noted previously, each casing head contains casing hanger assembly (Figure 39). The
casing hanger assembly consists of a set of slips with built-in seals. The primary seal is
contained in the assembly and seals off the annulus of the string suspended in it. These
seals may be automatically compressed by the weight of the string, or they may be
compressed by tightening lock screws that pass laterally through the casing head upper
flange.
Figure 39. Primary and Secondary Seals
Secondary seals contained in the lower flange of intermediate casing heads and tubing
heads serve as a pack-off. They fit around the end of the casing joint suspended in the
hanger immediately below. As such, the secondary seal performs essentially the same
function as the primary seal located in the flange below.
When possible, the pressure rating of flanges that are bolted together should be the same.
For example, if a top flange on a B-section is rated at 3,000 psi, the lower flange on the
tubing head must also be rated at 3,000 psi. However, one pressure jump is permitted, i.e.,
3,000 - 5,000 psi or 5,000 - 10,000 psi.
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If the upper flange of the tubing head will be potentially exposed to pressures greater than
5,000 psi, it should be rated at 10,000 psi. The jump from a 3,000 psi B-section upper
flange to the 10,000 psi tubing head upper flange constitutes a double-jump. A doublejump is unsafe because the B-section upper flange would be exposed to pressures well in
excess of its rated maximum, should the tubing head’s secondary seals fail.
5.6.5
Crossover/Pack off Flanges
This situation can be remedied be means of a crossover, or pack-off flange (Figure 40).
The crossover is interposed between the casing head and the tubing head. It consists of a
flange with two seals. To satisfy the case described above, the crossover flange would be
rated at 5,000 psi. Consequently there is now only one pressure jump per flange. The
crossover flange is also a double-studded adapter, with bolts extending from its centerline
outward in both directions to match the particular flanges, that allows connection of the
3,000 psi casing head flange to the 5,000 psi tubing head flange. Flanges rated for
different pressures have different API standard bolt patterns and differently sized seal ring
gasket grooves, so that without a double-studded adapter it is not possible to connect two
differently rated flanges.
Figure 40. The Crossover/Pack-off Flange
Table 1 : API Working Pressure Ratings *
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Working Pressure Rating (Psi)
Test Pressure (Psi)
(For flanges 14 in. and smaller)
2,000
3,000
5,000
10,000
15,000
20,000
4,000
6,000
10,000
15,000
22,500
30,000
* Derived from “Table 1.6A - Test Pressure” in API Spec 6A, for Wellhead Equipment, American
Petroleum Institute, January 1981, p.17
5.7
EQUIPMENT SPECIFICATIONS
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Two wellhead specifications are often referenced within PCSB in the design of wellhead
and Christmas tree components. They are API Spec 6A and NACE Standard MR-01-75.
5.7.1
Industry (API) Specifications
The American Petroleum Institute has published standardized specifications for oil
industry wellhead equipment. This publication is called API Spec 6A, Specifications for
Wellhead Equipment, and specifies material and physical properties for wellheads. It also
specifies test requirements for equipment components. The API Spec 6A is accepted
worldwide, and is routinely followed by all major wellhead manufacturers.
API designates wellhead equipment by the following working pressures: 2,000, 3,000,
5,000, 10,000, 15,000 and 20,000 psi (also 30,000 psi as covered in API Spec 6AB).
Generally speaking, the rating of any unit of wellhead equipment is governed by the
working pressure ratings of its flanged connections.
For units having end and outlet connections with different pressure ratings, the lowest
rating determines the test pressure to be applied to the head.
For hydrogen sulfide environments, the National Association of Corrosion Engineers
(NACE) has developed the NACE Standard MR-01-75 specification. It is compatible with
the API Spec 6A and is intended to aid oil companies and wellhead manufacturers in the
selection of materials resistant to sulfide stress cracking. It specifies the materials, heat
treatments, and metal property requirements for components that are exposed to hydrogen
sulfide service.
5.7.2
PCSB Company Specifications
PCSB standards specify that wellheads and trees shall be manufactured and made of
materials in accordance with API Spec 6A. By standardizing wellhead assemblies, PCSB
encourages reuse and interchangeability of salvaged equipment that results in large savings
to the Company.
In addition to API Spec 6A, each office may provide additional provisions to cover the
particular needs of a given field or geographical location. These specifications may include
the following :
1.
Purchasing Procedures - including recommended vendors, bidding procedures, and
requisition exceptions for special equipment.
2.
Wellhead Assemblies - including the number of side outlets, number and type of
valves of plugs, types of casing heads and tubing heads, and special hanger
assemblies.
3.
Christmas Tree Assemblies - including the size of tubing, number and size of valves,
type of tubing suspension, types of metallurgy, types of chokes, types of ring gaskets,
and types and number of pressure gauges.
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4.
5.7.3
WELLHEADS
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Testing Specifications - including specifications for Non-Destructive Evaluation
(NDE).
Service Environments
The type of service environment is of paramount importance in equipment selection since it
directly affects the choice of materials. The four major service environments are sweet oil,
sweet gas, sour oil and gas (hydrogen sulfide), and special temperature service. The
equipment for each environment must be tailored for the specific conditions in which it will
serve.
5.7.4
Sweet Oil
PCSB specifies low alloy steel materials for use in sweet (non H2S) oil wells with up to
5,000 psi pressure. Several steel grades are considered to be low alloy steel and hence are
used in PCSB wellheads. A typical grade is AISI (American Iron and Steel Institute) 4130.
Other alloy steel sometimes used for sweet oil wellheads are AISI 4140 and AISI 8620-30
grades. The code indicates the material composition of the steel, specifying the inherent
percentages of iron, carbon, chromium, molybdenum, nickel, copper, and other included
metals. At pressures above 5,000 psi, the material for sweet oil wellheads should follow
the specifications for sweet gas.
5.7.5
Sweet Gas
PCSB’s standard for sweet gas wells and for oil wells of over 5,000 psi requires the use of
12-14 percent chromium stainless steel in the (1) tubing head adapter flange, (2) lower
master valve, and (3) choke. The typical grade of steel used in PCSB for these components
is AISI 410. The remaining wellhead and tree components are of alloy steel and designed
to withstand specified design pressures by specification, the ring gaskets are made of 18
percent chromium - 8 percent nickel (AISI 316) stainless steel.
5.7.6
Hydrogen Sulfide
The PCSB Material Specification for Wellhead and Christmas Tree Assemblies Used in
H2S Service requires the use of similar materials as are used in sweet wells; however,
additional requirements must be met. A sour service well is identified according to NACE
MR-01-75. In general, if the partial pressure of H2S is greater than or equal to 0.05 psi, the
material is susceptible to sulfide stress cracking. All parts used under these conditions must
be heat treated as recommended in NACE Standard MR-01-75 to have not more than a
specified maximum material hardness. Material hardness is defined as the resistance of
metal to plastic deformation, usually by indention. In H2S tests, the common unit for
material hardness is Rockwell C hardness, which is obtained by applying a cone-shaped
diamond indentor with a load of 150 kilograms to the material and measuring the depth of
indention. NACE Standard MR-01-75 specifies that all wellhead and tree components
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subjected to H2S must have a controlled hardness. The hardness maximum depends on the
materials used for the components. Rockwell C-22 is the maximum for AISI 410 stainless
and low alloy steel. (Rockwell hardness numbers may be converted to other units of
material hardness by referencing appropriate tables in two other documents - ASTM E140,
and Federal Standard No. 151 Method 241.1).
5.8
SPLITTER WELLHEAD TECHNOLOGY
Splitter wellhead technology permits drilling and completion of three independent wells
through one shared conductor slot. In addition to the advantage of being able to drill,
complete and workover each of the three wells independently, the system uses standard
compact internal wellhead component. The only change required over the conventional
wellhead system is the compact housing external shape to allow spacing of the three
housings. The system is flexible, which allows implementation of standard drilling and
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completion procedures.
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MATERIAL AND TUBULAR SELECTION
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CHAPTER 6
MATERIAL AND TUBULAR SELECTION
TABLE OF CONTENTS
6.1
INTRODUCTION …………………….……………………………………………. 5
6.1.1
6.2
6
7
7
7
7
9
Nipples and Mandrels …..…………….…………………………...... 10
Flow Couplings ….……...…..…….......................…...………….…. 10
Blast Joints ……………………...…...............……………………... 10
Pup Joints …………….……………………………………………... 11
CORROSIVE WELLBORE FLUIDS ……………..……………..……………… 12
6.4.1
6.4.2
6.4.3
6.5
API Standards and Specifications ..………..………………………...
Non-API Standards ………………………………………………….
Tubing and Casing ...………………..……………………………….
Outside Diameter ………...………………………………………….
Length Range …………….………………………………………….
Weight Per Foot …..………………………………………………...
TUBULAR STRING COMPONENTS ……………………….……….….……… 10
6.3.1
6.3.2
6.3.3
6.3.4
6.4
5
TUBULAR NOMENCLATURE ………………...………………………………… 6
6.2.1
6.2.2
6.2.3
6.2.4
6.2.5
6.2.6
6.3
Chapter Objectives ………….……………………………………….
Hydrogen Sulfide – Sour Service ….…...…………………………… 12
Carbon Dioxide – Sweet Service …….…………..…………..……... 13
Corrosion Prevention ……...…………….………..………………… 13
TUBULAR MATERIALS ………………...………………………......….……….. 16
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6.5.1
6.5.2
6.5.3
6.5.4
6.5.5
6.5.6
6.5.7
6.5.8
6.6
PROPRIETARY INFORMATION -For Authorised Company Use Only
January 1998
Yield Strength …………...…..…….……………….……………..… 16
Hardness ……………..……………….…………………...………… 17
Heat Treatments ………..…………..……………………………...... 18
Chemical Composition ……………………………………………… 18
Grade Specification ………….……………………………………… 19
API Grades ………………...………………………………………... 21
Non-API High Strength Grades …………………….……………..... 22
High-Alloy Steels …………....…….……………….……………..… 22
Axial Yield Strength …….…..…….…………….……………..…… 25
Compression ………………...……………………………….……… 26
Burst Resistance ……….…………..………………………………... 26
Collapse Resistance ………….…….……………….……………..… 28
Bending ...………….…….…..…….……………….……………..… 30
TUBULAR CONNECTIONS …...……………………………………....….......… 31
6.7.1
6.7.2
6.7.3
6.7.4
6.7.5
6.7.6
6.7.7
6.7.8
6.7.9
6.7.10
6.7.11
6.7.12
6.7.13
6.7.14
6.7.15
6.7.16
6.8
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TUBULAR PERFORMANCE PROPERTIES ..……………..……..….………... 25
6.6.1
6.6.2
6.6.3
6.6.4
6.6.5
6.7
MATERIAL AND TUBULAR SELECTION
Purpose of Connections ……….…...……………….……………..... 31
API Specifications ………………………………………...………… 31
Non-API Connections ……………..………………………………... 32
Thread Profiles ……….……………………………………………... 32
Tubular End Finishes ………….……………………………………. 33
Threaded and Coupled Design ……………………………………… 35
Integral Joint Design ……….…...………….……….…………….... 36
Connection Axial Yield Strength …….…………….……………..… 37
Connection Pressure Seal Mechanisms …………….……………..… 38
Tapered Thread Seals ……….….….……………….……………..… 39
Metal-To-Metal Seals ..……….…...……………….……………..… 41
Elastomer Ring Seals ………….…...……………….……………..... 41
Thread Compounds ……….…...……………….……………..…….. 43
Connection For Sour Service ……...……………….……………..… 44
Erosion Resistant Connections …....……………….……………..… 44
Thread Protectors ……….…...……………….……………..………. 45
CONNECTION MANUFACTURERS ……………….....…………………......… 46
6.8.1
API Connections …….…..............................................................…
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6.8.2
6.8.3
6.8.4
6.8.5
6.8.6
6.9
January 1998
U.S. Steel Buttress Tubing …...………………................................. 48
Hydril …...….….………..……………………..............................… 49
Atlas Bradford ………….………………………………………….... 50
Vallourec ……………………………………………………………. 51
Other Manufacturers ……….…...……………….……………..…… 52
Makeup Torque …….……............................................................… 53
API Makeup Recommendations ….……….…..............................…. 55
Torque-Turn Makeup …..………….………..................................… 55
Non-API Connection Makeup ……..……………………………..… 57
Mill End Couplings …………………………………………………. 57
Galling …….………………………………………………………… 57
Thread Preparation ..….……….…...……………….……………..… 58
Tong Notches ……….…...……………….……………..…………... 59
Design Parameters …….….…......................................................… 60
Design Flowchart .…………………………................................….. 60
Example Tubing String Design ……………………………………... 62
TUBING SIZE SELECTION …..……….....…………....……………………...… 63
6.11.1
6.11.2
6.11.3
6.11.4
6.11.5
6.12
PROPRIETARY INFORMATION -For Authorised Company Use Only
PRODUCTION TUBING STRING DESIGN CRITERIA …..…….……….….. 60
6.10.1
6.10.2
6.10.3
6.11
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CONNECTION MAKEUP ……………………...……………………………...… 53
6.9.1
6.9.2
6.9.3
6.9.4
6.9.5
6.9.6
6.9.7
6.9.8
6.10
MATERIAL AND TUBULAR SELECTION
Tubing Flowing Pressure Gradients ……….….….....................……
Tubing Size Effects ……………...….………...............................….
Erosional Velocity …….…….………...........................................…
Well Deliverability …….…..……………..…………………………
Tubing Size Selection ..……….…...……………….……………..…
63
66
68
70
70
TUBING LOAD ANALYSIS …………….....……………....………..………..…. 73
6.12.1
6.12.2
Phases of Well Life …....…..........................................................….
Design Factors ….……...……………………...................................
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73
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6.12.3
6.12.4
6.12.5
6.12.6
6.12.7
6.12.8
6.12.9
6.12.10
6.12.11
6.12.12
6.13
January 1998
Hydrostatic Pressure ..…..………………..…………………………. 74
Axial Loads ………...……………………………………………….. 75
Air Weight …………………………………………………………... 75
Buoyant Weight …………….………………………………………. 76
Neutral Point ………………………………………………………... 77
Burst Load …………………………………………………………... 78
Collapse Load ……….…...……………….……………..………….. 80
Collapse Strength Reduction Under Axial Tension ………………… 81
Bending ……….…...……………….……………..………………… 82
Deviated Wells ……….…...……………….……………..…………. 83
Temperature Effects ………..….…...............................................… 84
Ballooning ...……..………………..………………………………… 85
Piston Length Changes ………………………………………………. 87
Total Tubing Movement ……………………………………………. 92
Deviated Wells …..………………………………………………….. 93
95
General Concepts ...….............................................................……
Buckling Load ….……...………...………..............................……. 96
98
Stability Neutral Point …….…………….......................................
Length Changes …...…………………..…………………………… 99
Helical Curvature ……….…...………..…….……………..………. 101
Deviated Wells ……….…...……………….…………....…………. 102
OPERATIONAL CONSIDERATIONS .....……………………....…….………. 103
6.15.1
6.15.2
6.15.3
6.15.4
6.15.5
6.16
PROPRIETARY INFORMATION -For Authorised Company Use Only
TUBING STABILITY ANALYSIS ……………….…………………………...… 95
6.14.1
6.14.2
6.14.3
6.14.4
6.14.5
6.14.6
6.15
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TUBING MOVEMENT ANALYSIS ……………....……..………………….…... 84
6.13.1
6.13.2
6.13.3
6.13.4
6.13.5
6.14
MATERIAL AND TUBULAR SELECTION
103
Radial Clearance …..….….............................................................
Rod Pumping .…………..………………..………………………… 103
Hydraulic Pumping …………………….…………………………... 103
Submersible Pumps ……….……………………………………….. 104
Washover Operations ………….…………………………………… 104
REFERENCES ………………...…………………………...…………………...... 105
6.1
INTRODUCTION
6.1.1
Chapter Objectives
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The cost of tubulars for a well can often comprise a large portion of the total well cost, up
to 20% in some cases. Of course failure of a tubing or casing string can result in major
expenditures and even injuries or loss of life. Therefore, an understanding of oil well
tubulars is necessary. With this in mind, the objectives of this chapter are to :
•
Introduce the fundamental nomenclature of oil well tubing and casing,
•
Describe tubular steel properties and the effects of wellbore fluids on them,
•
Define and describe the threaded connections used to join production tubing,
•
Present guidelines and methods for the design of a tubing string,
•
Review basic operational considerations for efficient and safe maintenance of the
tubing.
After reading this chapter, the reader should be able to design a typical conventional tubing
string.
6.2
TUBULAR NOMENCLATURE
6.2.1
API Standards and Specifications
The American Petroleum Institute (API) publishes a number of specifications, standards,
and recommended practices containing minimal requirements that the industry should
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follow in the manufacture, performance, and use of oil well tubular goods. Table 1 lists the
presently available API publications that contain information on tubing, casing, and other
oil field tubulars. A manufacturer wishing to sell or manufacture products which conform
to API standards must obtain a license which authorizes the use of the official API
Monogram.
The Monogram indicates that the manufacturer has followed API
specifications and that the product should perform to API minimum standards.
Table 1
API Tubing and Casing Specifications and Standards
Publication
6.2.2
Title
1.
Specification 5A
Specification for Casing, Tubing, and Drill Pipe
2.
Specification 5AC
Specification for Restricted Yield Strength Casing and Tubing
3.
Specification 5AX
Specification for High Strength Casing, Tubing, and Drill Pipe
4.
Standard 5B
Specification for Threading, Gaging, and Thread Inspection of
Casing, Tubing, and Line Pipe Threads
5.
Bulletin 5A2
Bulletin on Thread Compounds for Casing, Tubing, and Line
Pipe
6.
Bulletin 5C2
Bulletin on Performance Properties of Casing, Tubing, and
Drill Pipe
7.
Bulletin 5C3
Bulletin on Formulas and Calculations for Casing, Tubing,
and Line Pipe Properties
8.
Bulletin 5C4
Bulletin on Round Thread Casing Joint Strength with
Combined Internal Pressure and Bending
9.
Bulletin 5T1
Bulletin on Nondestructive Testing Terminology
10. Recommended Practice 5A5
Recommended Practice for Field Inspection of New Casing,
Tubing, and Plain-End Drill Pipe
11. Recommended Practice 5B1
Recommended Practice for Gaging and Inspection of Casing,
Tubing, and Line Pipe Threads
12. Recommended Practice 5C1
Recommended Practice for Care and Use of Casing and
Tubing
13. Recommended Practice 37
Recommended Practice Proof-Test Procedure for Evaluation
of High-Pressure Casing and Tubing Connection Design
Non-API Tubulars
Non-API tubulars are products designed and manufactured outside the scope of API
specifications and are generally claimed to meet or exceed the minimum performance
standards (burst, tensile, and collapse strength) of API tubulars. Non-API products are
commonly referred to as “proprietary” products denoting that to sell or manufacture a
product of proprietary design requires a licensing or royalty agreement in accordance with
patent rights.
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Tubing and Casing
Two general classifications of oil well pipe are casing and tubing.
Casing is most often used to seal off geologic formations from the wellbore and to prohibit
communication between different formations. After drilling to a predetermined depth,
casing is “run-in” the borehole and the annular space between the casing and the borehole
wall is filled with cement. The cement is used to seal the annulus and to increase the
stability and structural integrity of the casing.
Tubing provides a conduit for the flow of production fluids from the reservoir to the
wellhead, or for the injection of fluids from the surface to a subsurface formation.
Although the tubing is the last string of pipe run in the well, its size is determined first,
before the casing sizes. It is generally not cemented in place. Instead, brine is placed in the
tubing-by-casing annulus. The annular fluid is often called a “packer fluid”. Figure 1
shows a wellbore sketch of typical casing and tubing design for a conventional completion.
6.2.4
Outside Diameter
The API defines tubing to be of outside diameter 1-1/20 inches through 4-1/2 inches and
casing to be of outside diameter 4-1/2 inches and greater. This classification is generally
followed throughout the industry.
6.2.5
Length Range
Oil well tubulars are manufactured in lengths called “joints” (see Figure 2). The API has
specified that tubing joints be manufactured in only two length ranges :
Range 1: 20-24 feet
Range 2: 28-32 feet
The API permits that Range 1 tubing may be specified as 20-28 feet if both the user
manufacturer agree to do so.
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Figure 1. Conventional completion design
Figure 2. Joints of tubing or casing are threaded end-to-end to build a string of pipe
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There are three API standard casing length ranges:
Range 1: 16-25 feet
Range 2: 25-34 feet
Range 3: 34-38 feet
6.2.6
Weight Per Foot
The strength of a tubular - its ability to resist failure under wellbore pressure and axial
loads - can be increased by increasing its wall thickness. But since the API standardizes
tubulars by outside diameter, increasing the wall thickness decreases the inside diameter
and increases the weight. The weight of a tubular is generally expressed as the weight of
the pipe per linear foot, or “weight per foot”, in lb/ft denoted “ppf”. The weight per foot
includes the tubular end finish such as upsets or integral joint finishes. For example, API 31/2 inch, 9.3 ppf EUE tubing has an OD of 3-1/2 inches, an ID of 2.992 inches, wall
thickness of 0.254 inches, and a weight of 9.3 lb per linear foot.
The API publishes standards for only a limited number of weights for a particular size
tubular. For instance, the API only has standards for 3-1/2 inch OD tubing in weights of
7.7, 9.2, 9.3, 10.2, 12.7, and 12.95 ppf. To meet the need for greater strength tubing for
very deep or high pressure wells, several manufactures can supply tubulars in higher
weights. For example 3-1/2 inch tubing is available in non-API weights of 15.8, 16.7, and
17.05 ppf. Non-API weights are available in all sizes of casing and tubing.
6.3
TUBULAR STRING COMPONENTS
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Integral to the tubing string are a number of short tubulars designed as receptacles for
downhole tools or flow control devices. These short tubulars are called “nipples”.
Generally, nipples have specially machined inner and outer profiles to facilitate receiving a
locking device or seal assembly. Figure 3 is an example tubing string design showing
where such equipment is usually placed. A brief description of the most common nipples
and related equipment follows.
6.3.1
Nipples and Mandrels
A landing nipple is a short tubular with threaded connections that is run in the well on the
tubing string string to a predetermined depth. Landing nipples are internally machined to
receive a locking device; and they are internally honed to receive packing for sealing.
Landing nipples are manufactured in all nominal tubing sizes, weights, and threads.
Side pocket mandrels (SPM’s) are devices used to receive injection valves (gas lift valves,
chemical injection valves). They function similarly to landing nipples. SPM’s allow nearly
full tubing flow through its ID while the injection valve is placed in a “side pocket” landing
nipple. This makes the SPM have a large, irregular OD which must be considered in
tubing-casing annular clearance. Landing nipples and side pocket mandrels are discussed in
greater detail in Chapter 22 - Wireline Operations.
6.3.2
Flow Couplings
A flow couplings is a thick wall tubular used as protection against internal erosion. It is
machined with coupling-size outside dimensions and a full-tubing inside diameter. Flow
couplings are positioned immediately above and, in some instances, below a landing nipple
designed to receive a production control device such as a subsurface safety valve, bottomhole regulator, or bottom-hole choke.
6.3.3
Blast Joints
Blast joints give added protection against erosion caused by the jetting action of producing
perforations. They are usually manufactured in lengths of 10, 20, and 30 ft and they are run
on the tubing string. They are usually positioned opposite perforated intervals in multiple
completions. Blast joints can be constructed of a variety of very hard, high strength
materials including stainless steel and carbide.
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Figure 3. Typical placement of subsurface tools
6.3.4
Pup Joints
Pup joints are short tubulars of varying length that are used to space downhole equipment.
They are used to fit the tubing string to the specific length requirement of a given well. The
process of exactly fitting the tubing string length into the well at the wellhead is termed
“space-out”.
6.4
CORROSIVE WELLBORE FLUIDS
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Downhole environment factors can affect the design of tubing strings. Specifically, the
corrosive tendencies of hydrogen sulfide, carbon dioxide, oxygen, and brines may alter
choices with regard to materials, sizes, and overall completion equipment. A discussion of
these factors follows.
6.4.1
Hydrogen Sulfide – Sour Services
Hydrogen sulfide (H2S) can cause brittle failure of tubulars by a mechanism called sulfide
stress cracking (SSC). Figure 4 illustrates the brittle failure of tubing due to sulfide stress
cracking.
The National Association of Corrosive Engineers (NACE) publishes the NACE Standard
MR-01-75 “Material Requirement : Sulfide Stress Cracking Resistant Metallic material for
Oil Field Equipment”.1 The standard describes and defines materials which have been
used successfully in well environments containing water and hydrogen sulfide. According
to MR-01-75, SSC is affected by the following parameters :
Figure 4.
•
Chemical composition of the tubing steel,
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•
Tubing steel heat treatment and resulting steel microstructure,
•
Tubing steel yield strength,
•
pH of the wellbore fluid,
•
H2S concentration and total pressure of the environment
•
Total tensile stress (applied and residual in the metal structure),
•
Temperature,
•
Time.
It is known that the hardness of materials in sour environments should not exceed HRC22
(Rockwell C hardness scale) for carbon and low-alloy steels. Failures due to hardness of
material exceeding HRC2 are numerous. Upset tubing which is to be used in sour service
should be fully quenched and tempered or normalized after upsetting to lower hardness
below HRC22. It is best to use pipe that has been quenched and tempered after upsetting.
Some high-alloy steels can be used in H2S environments up to a hardness of HRC35.
However, the selection of these alloys must be done with great care since some alloys can
be susceptible to failure under certain environmental conditions.
One of the requirements for H2S to cause sulfide stress cracking is a state of tensile stress in
the material. If it is known that the well is sour, a stress analysis of the tubing string should
be done to determine if any stresses are near the yield strength. The total tensile stress,
including any residual stresses, should always be considered.
6.4.2
Carbon Dioxide – Sweet Service
In the presence of water, carbon dioxide (CO2) can cause corrosion of tubulars. CO2
generally causes weight loss corrosion, or corrosion pitting. An example of CO2 pitting is
shown in Figure 5. Severe pitting can also be caused by oxygen or H2S dissolved in water.
However, oxygen contacts wellbore water only after it reaches the surface.
6.4.3
Corrosion Prevention
There are three methods used to prevent corrosion of tubulars :
1. Inhibitors
2. Corrosion Resistant Alloys
3. Plastic Coating
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Figure 5. An example of severe pitting on the ID of tubing due to exposure to CO2 and water
Each method may be applicable to a particular corrosion problem. Most often, a
combination of the method is employed. When a corrosion problem appears to be evident,
a materials specialist should be consulted to determine an effective inhibitor program.
Chemical inhibitors are often used to control weight-loss corrosion. These inhibitors can
be oil-soluble, water-dispersible, or water-soluble to suit the needs of the well. Inhibitors
prevent corrosion by forming a thin film on the surface of the tubing which prevents
corrosive fluid from contacting the tube wall. There are in general two methods of treating
a wellbore with inhibitor: batch treatment and continuous treatment. In a batch treatment, a
predetermined volume of inhibitor is injected into the wellbore. The well is then shut in so
that the inhibitor forms the film on the tubing ID. In a continuous treatment, inhibitor is
“continuously” injected into the tubing string through a chemical injection valve (CIV)
placed in a side pocket mandrel or it is pumped through a “kill string” to the packer depth
where it is injected into the production stream. In any case, it is important that production
flow velocity be determined and controlled so that the thin film of inhibitor is not “washed”
away from the tube wall by turbulent fluid flow.
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Corrosion resistant alloys (CRA’s) are stainless or high-alloy steels which have proved to
be particularly resistant to many types of severely corrosive environments. However,
CRA’s are very expensive. Selection of a CRA for tubing or casing must be done with care
and a materials specialist should be consulted as one CRA may be suitable to a certain
corrosive fluid while it may not be suitable for another.
Plastic coating of the tubing inner walls is often used to protect tubing from corrosion.
Although plastic coated tubing is used in many corrosive environments, it is mainly used to
prevent weight loss corrosion. In a sour (H2S) environement, hydrogen can diffuse through
the plastic coating to cause embrittlement cracking. Due to the brittleness of the coating,
various types of coating damage such as scratches or chips can expose tubing materials to
corrosive fluids. Wireline operations through plastic coated tubing should either be
eliminated or else done with great care.
6.5
TUBULAR MATERIALS
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Yield Strength
Casing, tubing, and drill pipe are manufactured from ductile steels. Ductility is the ability
of material to withstand significant (plastic) deformation prior to fracture. A brittle steel
may fracture without appreciable deformation. The strength of a steel is generally indicated
by its yield stress or ultimate tensile strength. Figure 6 is a stress-strain diagram for a
particular ductile steel. A stress-strain diagram is obtained by pulling tension on a small
cylindrical sample of steel. If the tensile load applied is F and the cross-sectional area of
the sample is As, then the axial or tensile stress is given by
σa =
F
(5.1)
As
Figure 6. Stress-strain diagram for a typical ductile steel
Axial strain is defined as the ratio of sample axial elongation due to the applied tensile
loads to the original length of the sample, or
ε =
∆L
(5.2)
L
These concepts are illustrated in Figure 7.
In Figure 6, Point A represents the yield strength (elastic limit) of the steel. If the steel is
stressed below the elastic limit, it returns to its original shape (or zero strain) upon
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unstressing or unloading the specimen. Below the elastic limit, the stress-strain curve is
linear. The API specifies that the yield stress is the tensile stress required to produce a total
elongation of 0.5 percent of the tensile test specimen (or “gage”) length. This is shown as
point A’ in Figure 6. Stresses greater than the elastic limit cause permanent deformation of
the steel which will not diminish after the load is taken away. In most situations, it is
undersirable to exceed the yield stress of a material.
Figure 7. Schematic of a simple tension test specimen
Point B in Figure 6 is the point at which the steel reaches its ultimate tensile strength. The
ultimate tensile strength is the maximum stress that the steel can sustain.
6.5.2
Hardness
Another important property of steel is its hardness. Hardness generally increases with
increasing material ultimate tensile strength. When a material is selected to resist wear,
corrosion, erosion, or plastic deformation, it may be important to specify a high hardness.
Very hard materials are brittle and will tens to crack or fracture easily. Hardness is
determined by a test in which a standard load is applied with a small ball or pointed object.
Hardness is then expressed by the depth of indentation caused by the object. Generally, oilwater tubular hardness is expressed on the “Rockwell C” hardness scale or the “Brinell”
scale.
6.5.3
Heat Treatments
Producing a steel of desired mechanical properties such as yield stress, ultimate tensile
strength, ductility, or hardness, can be achieved by controlling the heat treating portion of
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the manufacturing process and the chemical composition of the steel. Heat treating affects
changes in the microstructure (or gain structure) of the steel which directly affects its
mechanical properties.
Heat treating is an operation involving heating and/or cooling the solid steel tubular to
develop desired steel microstructures. There are generally five different heat treatments
employed in the production of oil well tubulars:
Quenched and Tempered – The steel is heated to 1500°F – 1600°F. The steel is then
rapidly cooled, or quenched, in water or oil to produce a desired microstructure. It is then
reheated, or tempered, at 1000°F – 1300°F to affect a desired combination of strength and
ductility. Quenched and tempered (Q&T) is the preferred method of producing high
strength casing and tubing.
Normalizing – The steel is heated to 1600°F – 1700°F and then cooled in still air to produce
a uniform microstructure and to alter mechanical properties.
Normalized and Tempered - The steel is first normalized, as above, and then tempered and
air cooled. This tempering process slightly lowers the strength from the normalized
condition but improves ductility. It will also help to relieve residual stresses.
Hot Rolled - The tubular is reduced, or shaped to the desired OD, at a very high
temperature. Hot rolling does not cause the changes in microstructure that cold rolling does
(see below). Hot rolling produces a steel similar to the normalized condition.
Cold Drawn and Tempered - The tubular size is reduced to the desired OD at room
temperature, a process which causes high residual stress in the tube and increases hardness
due to plastic deformation. The tubular is then tempered to reform the microstructure from
the cold drawn state. Tempering reduces the hardness and relieves residual stress.
Tubulars manufactures by this process are undersirable.
6.5.4
Chemical Composition
The chemical composition of a steel directly affects all of its mechanical properties and
corrosion resistance. Steels can be classified according to chemical composition as
follows:
Carbon steel is generally considered to be a mixture of iron and carbon with up to 2%
carbon. Actually, carbon steels can contain more than just iron and carbon. Other
elements, such as manganese or silicon, are added for various reasons. Carbon content
varies from 2% (high carbon steel) to 0.25% (low carbon steel). Carbon steels exhibit less
ductility than alloy steels.
Alloy steels are steels containing significant quantities of alloying elements other than
carbon. Steel is generally considered to be an alloy steel when the maximum of the range
given for the content of the alloying elements exceeds one or more of the following limits:
1.65% manganese, 0.6% silicon, 0.6% copper; when a definite range or a minimum quantity
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of any of the following elements is specified or required: aluminum, boron, cobalt,
chromium, niobium, molybdenum, nickel; or when any other alloying elements is added to
obtain a desired or specific effect.
Low-alloy steels contain less than 5% metallic alloying elements. High-alloy steels contain
more than 5% alloy elements; in particular, high concentrations of chromium, molybdenum,
and nickel are used for high-alloy tubulars. High-alloy steels are often called “stainless”
steels (usually containing greater than 12% chromium). High-alloy steels are now being
frequently used in hostile wellbore environments.
6.5.5
Grade Specification
Grade of steel is a classification of the steel according to its yield stress and ultimate tensile
strength, chemical composition, heat treatment or other characteristics. There are many
grades of steel from which tubing and casing are manufactured. In the oil industry, the
grade of of steel is denoted by a letter of the alphabet followed by the minimum yield stress
of the particular steel. For instance, the API standard grade N-80 has a minimum yield
stress of 80,000 psi. The N is merely a distinguishing prefix to avoid confusion between
different steel grades. The various grades of steel from which oil field tubing and casing
are manufactured are summarized in Table 2 and Table 3.
Generally, steel mills manufacture a particular grade having a range of yield stress; that is,
tubulars of the same grade will not have identical yield stress (i.e., the API 0.5 percent
elongation specification will not give identical values of yield stress for a large number of
tubes). Tubulars will be specified to have a specific minimum and maximum yield stress.
The API permits standard ranges of yield strength for each grade. Figure 8 is bar graph
showing the yield stress range (minimum to maximum) of standard API casing and tubing
grade materials.
Table 2
Physical Properties of Casing and Tubing Grades
Nominal
Designation
Yield Strength
-ksi
Tensile Strength
-ksi
Rockwell
Hardness Range
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Min.
F-25
H-40
J-55
K-55
S-80
C-75
L-80
N-80
C-95
P-105
P-110
V-150
25
40
55
55
55
75
80
80
95
105
110
150
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Max.
Min.
Ultimate
B
C
40
60
75
95
95
95
95
100
105
120
125
160
80
80
90
95
110
110
135
140
180
7
13
7
13
15
15
17
-16
-24
-16
-24
-23
-29
-28
28
35
-35
-39
5A
5A
5A
5AC
5AC
5A
5AC
5AX
5AX
Csg
Tbg
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
Table 3
Composition of alloy stainless steels used for oil well tubulars and other equipment
Composition, &
Type
Stainless steels
Martensitic………
Precipitation hardened
Austenitic…….....
Duplex (austenitic
ferritic)…………..
Nickel alloys
Cold reduced…….
Precipitation hardened
Materials
Fe
Ni
Cr
Mo
Cb+Ta
Ti
Al
Cu
Others
12-13% Cr
CA6NM
17-4 PH1 (martensitic)
Custom 4502
(martensic)
A-286 (austenitic)
20Cb-e2
904 L7
Al 6X9
Sanicro 283
bal
bal
bal
bal
4
4
6
12
12
17
15
0.70
0.75
-
-
-
4
1.5
-
bal
bal
bal
bal
bal
26
33
25
24
31
15
20
20
20
27
1.3
2.5
4.5
6.0
3.5
1.0 max
-
2.0
-
0.2
-
-
0.015B
-
Af-224 SAF-22053
Uranus 50
Ferralium5
DP-38
bal
bal
bal
bal
5.5
7
5.5
6
22
21
26
25
3
2.5
3
1.5
-
-
-
0.14N
0.1 N min
0.1 N min
Hastelloy C-2765
Hastelloy G5
Inconel 6256
Incoloy 8256
Incoloy 8006
Inconel 7186
Pyromet 312
6
20
25
30
45
19
15
bal
bal
bal
42
32
bal
bal
15
22
21
22
21
19
23
16
6
9
3
3
2
2
3.5
5.0
0.85
0.2
0.9
0.4
0.9
2.3
0.2
0.4
0.5
-
2.5 Co max, 4.0 W
2.5 Co max, 1.0 W max
0.005 B
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Figure 8. Minimum to maximum yield stress ranges and ultimate tensile
strengths of API casing and tubing grades
6.5.6
API Grades
API H-40, J-55, K-55, and N-80: These are carbon, very ductile, low-yield strength steels
standardized in “API Specification 5A: Specification for Casing, Tubing, and Drill Pipe”.
K-55 steel has an ultimate strength of 95,000 psi and J-55 steel has an ultimate strength of
75,000 psi. K-55 grade steel is generally used for casing since a higher ultimate tensile
strength is normally desired for casing. H-40, J-55, and K-55 are satisfactory for use in
hydrogen sulfide environments because of their low yield stress.
N-80 is the strength steel covered in API Spec. 5A. N-80 tubing is commonly ordered
quenched and tempered since this heat treatment results in better quality tubulars for oil
well use. PCSB guidelines restrict the use of N-80 tubulars in sour service to service to
service temperature above 200°F for production casing.
API C-75, L-80, and C-95: These low-alloy grades of steel are covered in “API
Specification 5AC: Restricted Yield Strength Casing and Tubing”. C-75 and L-80 grade
have been used successfully in sour service. Their ultimate tensile strength, yield stress
ranges, hardness, and chemistry are specified. The difference between L-80 and N-80
grades is the maximum yield stress. L-80 has a maximum yield stress of 95,000 psi, while
the maximum yield stress for N-80 is 110,000 psi. The maximum hardness of L-80 is also
restricted to HRC23. Numerous SSC failures have been experienced with C-95; therefore,
PCSB guidelines restrict the use of C-95 grades in sour wells to temperatures above 150°F
(for production casing).
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The API has recently developed a specification for C-90 grade tubulars which will be
acceptable for sour service. This new specification is expected to be included in API Spec
5AC.
API P-105 and P-110: These grades are covered in “API Specification 5AX: High Strength
Casing, Tubing, and Drill Pipe” and are the highest strength casing and tubing grades
standardized by the API. P-110 material is normally manufactured for casing and P-105 for
tubing. The API specifies that these grades be either quenched and tempered or normalized
and tempered. Most P-110 tubulars are ordered quenched and tempered. These grades are
normally restricted from use in sour environments. In very deep wells where temperatures
exceed 250°F, PCSB guidelines permit the use of P-105 and P-110 tubulars as they are not
as susceptible to stress cracking at such high temperatures.
6.5.7
Non-API High Strength Grades
Some companies have manufactured 95,000 psi yield strength tubing as “high collapse”
tubulars. This means that the tubulars can withstand higher external pressures (that would
cause collapse of the pipe as predicted by API formulas) because of manufacturing
processes that increases its collapse strength. However, full scale testing has shown that in
some cases, such “high collapse” tubulars fail at external pressures equal to the API
collapse resistance pressures (the tubulars may not exhibit higher collapse strength).
Therefore, such “high collapse” tubulars should be regarded as having standard API
collapse strength.
There are also 125,000 psi, 140,000 psi, 150,000 psi, and 155,000 psi yield strength grades.
These are generally used for casing only. Due to the high risk of sulfide stress cracking and
other corrosive/erosive problems associated with such high yield strength materials, these
grades are normally not allowed for use in sour service or are restricted to high temperature
environments.
6.5.8
High-Alloy Steels
The above API and non-API tubular materials are all carbon steels or low-alloy steels.
Table 3 is listing of the basic chemical components of the high-alloy materials (or corrosion
resistant alloys, CRA’s) used in completion tubing and casing.
The use of high-alloy materials has become popular due to their resistance to the corrosive
environments. These materials are metallurgically complex and must be selected on a caseby-case basis, depending upon the specific environment. A specialist in materials
engineering should be consulted before using high-alloy tubulars.
Several suppliers of CRA materials provide guidelines to help the engineer choose
materials for service in our wells. Two methods, one from Sumitomo and the other from
Kawasaki are provided here in Figures 9 and 10.
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(Note) * Cι– content is less than 50,000 ppm for SM 9CR and SM 13CR
Figure 9. Concept of Material Selection according to Gas
(CO2 and H2S) Partial Pressure (Sumitomo)
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Figure 10. General Guideline For Material Selection For OCTG (Kawasaki)
6.6
TUBULAR PERFORMANCE PROPERTIES
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Performance property values are load limits which when applied to a tubular will cause
yielding or failure of the tubular. The performance properties give the strength of a tubular
under certain loading conditions such as axial tension and internal or external pressure.
“API Bulletin 5C2: Performance Properties of Casing, Tubing, and Drill Pipe” contains the
joint strengths and burst and collapse resistance values for API standard casing, tubing, and
drill pipe”. API Bulletin 5C3: Formulas and Calculations for Casing, Tubing, and Line
Pipe Properties” contains the equations used to calculate the performance properties given
in Bul. 5C2. It is important to recognize that tubing performance properties are the loads
(axial, burst, or collapse) required to yield the tubular. Performance properties for tubing
do not predict actual failure loads or permit stress in excess of the minimum yield stress of
the steel. Some performance properties for casing, the axial strength, are based on the
ultimate tensile strength of the steel allowing stress in excess of minimum yield.
6.6.1
Axial Yield Strength
The axial yield strength of the pipe body of a tubular is the axial load necessary to cause the
axial stress to equal the minimum yield stress of the pipe steel. The load is given by the
formula :
Py = Sy
π
4
(OD2 – ID2)
(6.1)
where:
Py
= axial yield strength of the pipe body, lbs.
OD
= outside diameter of pipe body, in.
ID
= inside diamter of pipe body, in.
Sy
= minimum yield strength of pipe body material, psi
For example, the axial yield strength of 3-1/2 in., 9.3 ppf (ID = 2.992 in.), N-80 tubing is :
Py = (80,000 psi)
6.6.2
π
4
(3.5 in.)2 – (2.992 in)2
= 207,200 lb.
Tubular threaded connections must also be considered when determining the axial yield
strength of a tubular. Because of the mechanical properties of threads, the connection may
be weaker than the pipe body. These concepts are addressed in this section under the
subject TUBULAR CONNECTIONS.
Compression
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For most oilfield tubular steels, the compressive strength is taken to be equal to the yield
strength in tension. Therefore, compressive strength of the pipe body is equal to its axial
tensile strength.
The compressive strength of tubing threaded connections is also important. Compressive
strength of a connection depends upon thread geometry.
6.6.3
Burst Resistance
Burst resistance of the tubing and casing pipe body is the internal pressure necessary to
cause the tangential (or hoop) stress in the pipe to reach the minimum yield strength of the
pipe steel. There are two formulas used to calculate the burst resistance of oil well tubing
and casing, the Barlow formula and the Lame’ formula.
The Barlow formula is an approximation of the hoop stress in thick walled cylinders under
internal pressure. Burst resistance using the Barlow formula is determined by calculating
the internal pressure required to cause the hoop stress at the ID of the tubular to equal the
minimum yield stress. The Barlow formula is presently used by the API and is given by :
PB = 0.875
2Syt
OD
(6.2)
where:
PB
= axial yield strength of the pipe body, lbs.
Sy
= minimum yield stress of pipe steel, psi,
t
= tube wall thickness, in.
OD
= Tube outside diameter.
The 0.875 coefficient assumes that the pipe wall meets the API minimum pipe thickness
specification of 8.7% of nominal thickness. For example, the burst resistance of API 3-1/2
in., 9.3 ppf (t = 0.254 in.), N-80 tubing is :
PB = 0.875
2(80,000 psi)(0.254 in.) = 10,160 psi
(3.5 in.)
The Lame’ formula is based on more rigorous theory than the Barlow formula and is given
by :
PL = SY
[OD2 – (OD – 1.75 t)2]
[OD2 + (OD – 1.75 t)2]
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The terms are defined in equation 6.1. The coefficient of 1.75 assumes the API minimum
allowable wall thickness (87.5% of nominal). For example, PL is 10,800 psi using the
above example data. The Lame’ pipe body burst resistance value is slightly higher than the
Barlow value.
Figure 9 graphically illustrates the difference between the Barlow and Lame’ burst
resistance values. Note that the plot is for various values of outside diameter to wall
thickness ratio, D/t. API tubulars have D/t ratios in the range of approximately 6 to 45. As
D/t increases the Barlow and lame’ formulas provide approximately equal results. It should
be cautioned that burst design factors used in tubing string design depend upon which
formulas, Barlow or Lame’, are used to compute the hoop stress at the ID of the tubular.
In addition, the API considers connection couplings and thread sealability in determining
internal pressure, or burst resistance. These concepts are addressed later in the discussion
of connections.
Figure 9. Plots of the Barlow and Lame’ burst resistance formulas showing that the Barlow formula
predicts yield at the tube ID at lower pressure than the Lame’ foemula.
6.6.4
Collapse Resistance
Collapse of tubulars is a mode of pipe failure in which the wall cross section becomes
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structurally unstable at a critical external pressure. Since collapse is a stability failure, it
can occur at pipe wall stress values which are greater than or less than the minimum yield
stress of the tube steel. However, the equations used by the API to calculate collapse
strength do not allow for stresses in the tubing wall greater than the minimum yield stress.
Tube wall thickness is a critical parameter. If the tube wall is thin, the tube wall collapse
easily. If the wall is thick, the tube wall can undergo plastic deformation before the wall
collapse.
Pipe collapse formulas are normally expressed as a function of D/t. The API specifies four
different collapse formulas corresponding to different D/t values : (1) yield strength
collapse, (2) plastic collapse, (3) transition collapse, and (4) elastic collapse. Collapse
resistance is determined by first calculating the value of D/t for the given size tubular. API
Bul 5C3 gives the D/t range for each collapse formula. The appropriate formula for the D/t
value is then used to calculate the collapse resistance. Figure 10 is a plot of API collapse
formulas as a function of D/t for N-80 grade tubulars.
Figure 10. API collapse formulas plotted for N-80 grade tubulars.
Yield strength collapse is valid for very thick-walled tubulars (small values of D/t). The
plastic collapse formulas can predict external pressures which can cause hoop stress equal
to or exceeding the tube minimum yield stress. Since it is undesirable to allow stress which
exceeds the minimum yield stress the API uses the external pressure that would cause the
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hoop stress at the inside diameter of the tube wall to equal the minimum yield stress of the
pipe steel.
This formula is given by:
PYp = 2YP
(D/t) – 1
(D/t)2
(6.6)
Plastic collapse takes place in slightly thinner walled tubes (when D/t ratios are slightly
larger). There have been many attempts to analytically model this mode of collapse with
varying success. At present, the API uses an empirically derived formula based on a
statistical analysis of full scale external pressure tests on different sizes, grades, and
weights of pipe. This formula is given as :
Pp = YP
A -B
(D/t)
-C
(6.7)
where A, B, and C were determined by a statistical analysis as a function of D/t and pipe
grade.
Transition collapse is due to an anomaly in the statistical analysis used to analyze plastic
collapse data. The plastic collapse equation, when plotted, does not intersect the elastic
collapse equation (given below). So that a smooth transition occurs between plastic and
elastic collapse, the transition collapse formula was statistically derived. It is given as :
PT = YP
F
-B
(D/t)
(6.8)
when F and G were determined statistically as functions of D/t and steel grade.
Elastic collapse is valid for very thin wall tubes and is analytically derived by considering
the external pressure necessary to cross-sectionally buckle a very slightly eccentric or outof-round cylinder. However, this formula is not meant for cylinders of elliptical cross
section. The formula is given as :
46.95 x 106
(6.9)
(D/t)[(D/t) – 1]2
It is well known that axial tension can lower collapse resistance. This is a result of a
combined stress state arising from hoop, radial, and axial tensile stresses. Methods to
derate collapse resistance due to axial tension are discussed under the subject TUBING
LOAD ANALYSIS.
PE =
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Bending
Bending is usually considered as an axial stress. Bending of a tubular causes the axial
stress in the outer fiber of a bend to increase and the axial stress on the inner fiber of the
bend to decrease. That is, the inner fiber bending stress is compressive and the outer fiber
bending stress is tensile. Figure 11 illustrates the stresses induced by bending. Axial stress
due to axial tensile or compressive loading and bending stress are algebraically added to
give total axial stress at the fiber. Bending of a threaded connection causes loss of thread
contact that can lead to loss of pressure integrity. However, analysis of the bending of
threaded connections is considerably more complicated.
Figure 11. The effects of bending on a connection and on the axial stress in the tube body
6.7
TUBULAR CONNECTIONS
6.7.1
Purpose Of Connections
Threads are machined onto the ends of a tubing joint (see Figure 12) so that two joints can
be connected end-to-end to build a string.
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The function of the threaded connection is to provide a mechanism for joining oil well
tubular joints which :
•
Hold the string together under axial design loads, and
•
Provides internal and external pressure seal integrity.
The most desirable connection design would enable the connection to withstand the same
loads as the pipe body.
Figure 12. A typical threaded and coupled tubular connection
6.7.2
API Specifications
The API standards and specifications apply only to API tubing and casing connections. The
standard dimensions and tolerances of API thread forms are contained in “API Standard 5B:
Specification for Threading, Gaging, and Thread Inspection of Casing, Tubing, and Line
Pipe Threads” and “API Recommended Practice 5B1 : Recommended Practice for Gaging
and Inspection of Casing, Tubing, and Line Pipe Threads”.
6.7.3
Non-API Connections
Non-API connections have performance properties, manufacturing tolerances, and
operational guidelines determined by the manufacturer. Usually, some of the non-API
connection information is proprietary. The designs of non-API connections enable them to
provide greater axial strength, a smaller connection OD, and in some cases improved
sealability at higher pressures. Industry criteria concerning when (i.e., at what depth,
Pp =toYuse
- B connections
-C
P
pressure, etc.)
non-API
rather than API connections varies widely.
Pp = YP
-B -C
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However, most major operators indicate that non-API connections are considered for use
when differential pressure across the tubing exceeds 3000 psi to 5000 psi and well depth
exceeds about 10,000 to 12,000 feet.
There are four basic differences between API and non-API connections :
•
axial load strength,
•
additional downhole radial clearance,
•
performance in severely corrosive or erosive environments,
•
price.
To increase the joint yield strength of a connection while keeping the outside diameter of
the connection close to the tubing outside diameter requires a structurally stronger thread
form than the API threads. Greater axial strength without increasing the outside diameter is
also needed when clearance problems arise between tubing and casing. Certain non-API
connections are claimed to minimize connection stresses. Generally, the less expensive
API connections are used unless downhole conditions dictate otherwise.
6.7.4
Thread Profiles
Shown in Figure 13 are the four most basic thread profiles used on oil field casing and
tubing threaded connections. Figure 13a is the API round-thread profile standardized in
API Standard 5B. This thread profile is cut onto API casing, tubing and line pipe. As
shown, the threads are symmetrical, both thread flanks are 30° and the total thread angle is
60°.
The Acme thread profile is shown in Figure 13b. It is also symmetric and is used on only a
few non-API connections.
The API buttress casing thread profile is shown in Figure 13c. The buttress thread flank
angles are not equal. The steeper flank of the profile shown is often called the load flank as
it transfers axial load when the connection is in tension. The opposite flank is usually
called the lead or stab flank as this flank is in contact with the coupling flank when the pin
is stabbed or lowered into the box during makeup. Buttress threads are used on API casing
only, the API does not publish standards for tubing connections with buttress threads.
Many non-API connections employ buttress type threads on tubing and casing with
variations in the flank angles.
Hook threads, shown in figure 13d, are buttress type threads in which the load flank is cut
at a negative angle. When the connection is loaded in axial tension the threads tend to grip.
This is claimed to produce greater axial strength and reduce the possibility of jumpout
under high axial loading. Hook type threads have been used primarily on casing
connections where axial strength is a primary concern.
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Tubular End Finishes
There are two basic tubing end-finishes upon which threads are machined: non-upset-end
and upset-end. Non-upset-end tubing, illustrated in Figure 14a, is simply tubing
manufactured with threads machined on the outer surface of the tubing end. When threads
are cut onto the surface of the tubing end, the cross-sectional area of the tubing underneath
the threads is decreased. The smaller cross section results in higher axial stress in the
threaded end.
To keep the threaded end at least as strong as the tubing body, material must be added to
the tubing end to increase the cross-sectional area below the threads. This is called
upsetting the end of the tubing. Upset tubing is shown in Figure 14b.
Tubing can be upset either externally, internally, or both. Although upsetting increases the
strength of the connection, it also increases the outside diameter and/or decreases the inside
diameter of the connection. In completions where radial clearance is limited, external
upsetting can be a problem. Excessive internal upsetting can cause problems running
downhole tools.
Upsetting of tubing is a manufacturing process that may change the microstructure of the
tubing steel in the neighborhood of the upset. If upset tubing is not properly heat-treated,
changes in microstructure can enhance corrosion/erosion problems. Upset tubing should
always be ordered heat treated quenched and tempered or normalized to assure a
homogeneous microstructure in the tube body-upset transition area.
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Figure 13. Four basic thread profiles used for oil well casing and tubing connections
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Figure 14. Tubular end finishes
6.7.6
Threaded And Coupled Design
Threaded and coupled tubing is shown in Figure 12. It consists of tubing joints with
threads cut on either upset or non-upset ends and a short piece of tubing approximately 3 to
6 inches in length called a coupling, or collar. The coupling, named for the fact that it
“couples” the joints, has a cylindrical outer diameter with threads cut into the inner
diameter. The threaded tubing end is commonly referred to as the pin. The coupling is
sometimes referred to as the box.
As seen in Figure 12, the diameter of the coupling is larger than the tubing body. In tight
fitting completions (such as multiple completions) it is possible for the coupling shoulder to
get hung-up or stuck on the internal profile of the casing connection or on the coupling of
another tubing string. Hang-up is illustrated in Figure 15. Similarly, logging tools could
hang-up in the tubing on the inside shoulder of the coupling.
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Figure 15. An example of couplings hanging-up during tubing manipulation in a dual completion
6.7.7
Integral Joint Design
Integral connections, shown in Figure 16, do not employ couplings. Instead, each joint has
a pin and box. Figure 16 shows an integral connection using a torque shoulder on the
external diameter. A torque shoulder is a machined surface at the end of the threads whose
main purpose is to halt makeup; that is, once the tube end hits the shoulder while screwing
the joints together, makeup cannot continue.
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Figure 16. Example of a typical integral joint connection design
6.7.8
Connection Axial Yield Strength
Tubing body axial yield strength is calculated as the force required to yield the tubing with
respect to the cross-sectional area of the tubing body. The axial yield strength of a threaded
connection is similarly calculated. However, the cross-sectional area of the threaded
connection must be considered. Figure 14a shows the detail of a non-upset API threaded
and coupled tubing connection pin end. Note the position of the last complete thread. This
section is the weakest of a non-upset connection. Hence, the yield strength of this
connection is taken at that point.
Upset tubing, as shown in Figure 14b, has at least the same cross-sectional area under its
last fully engaged thread as the tubing body, so that the connection has the same strength as
the tube body.
Sometimes, the axial yield strength of the connection is referred to as the joint yield load.
The cross section at which this yield load is calculated is the critical cross section shown in
Figure 14. The axial strength, or yield load, is given by
P = AcrSy
(7.1)
where:
P
= the axial load required to yield the critical cross section,
Acr
= critical cross-sectional area, in2 and
Sy
= yield stress of tubing or coupling steel, psi.
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An alternate means of expressing the axial strength of a tubular connection is joint
efficiency. The connection strength may be larger, smaller, or equal to the tubing body
depending on the connection cross-sectional area and the coupling steel (if different from
the joint steel). The ratio of the connection strength to the body strength expressed as a
percentage is defined as the joint efficiency, or
ej =
connection axial strength
X 100%
pipe body axial strength
(7.2)
Since the connection and the pipe body are generally made of the same steel, the yield
strength or ultimate tensile strength of the coupling (or box) and pin will be the same.
Since pipe body or connection strength is the product of critical area and material strength,
the joint efficiency can bee written as
ej =
Acrit
Apipe
X 100%
(7.3)
where Acrit is the connection critical cross-sectional area and Apipe is the pipe body crosssectional area.
Most connections do not have a joint efficiency of 100%. There are some connections with
a joint efficiency in excess of 100%. For example, most upset and integral joint
connections have at least 100% joint efficiency due to the increased wall thickness in the
upset ends.
Joint strength also depends upon thread profile. Generally, the coarser the thread profile,
the greater the axial strength of the joint. Round-threads may have a tendency to slip apart
under very high tensile loads due to thread deformation during axial loading. The
combined effects of the hoop, axial, and bending stresses in the threads produce radial
displacement. If radial displacement is large enough, the threads will slip apart until
insufficient joint tensile strength is left and the connection fails. This mode of failure is
commonly called jumpout, pullout, or unzippering. To prevent jumpout, square threads
with a steeper load-flank angle (greater than the round-thread 30°) such as buttress or hooktype forms are often used in very deep wells where axial tension is large.
6.7.9
Connection Pressure Seal Mechanisms
To prevent gas or liquid from leaking through the threading of a tubing connection four
basic sealing mechanisms are utilized:
•
Tapered thread interference fit
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•
Metal to metal seals (shoulder and lip seals)
•
Elastomers (ring seals)
•
Thread compound
All tubing connections presently available use one or a combination of the above four
mechanisms.
6.7.10
Tapered Thread Seals
All API tubing connections utilize tapered threads which function as the primary sealing
mechanism (along with thread compound). Many non-API connections also employ
tapered threads, but the threads usually do not function as the primary seal. The tapered
threads of non-API connections serve as a secondary seal and to prevent downhole breakout by the development of thread interference. This fact is sometimes used to denote the
difference between API and non-API connections.
Threads which are cut on an angle to the tube axis, on a taper, generate interference
between the threads. Interference produces a bearing pressure between the pin and box
thread flank surfaces. The further the pin is screwed into the box, the greater the
interference and the greater the bearing pressure produced. This bearing pressure caused by
the contact between pin and box thread flanks is the sealing mechanism. This mechanism is
illustrated in Figure 17.
The bearing pressure discussed above is generated solely by making up the connection.
However, it can be seen from Figure 18 that internal and external pressures have an effect
on the contact pressure between pin and box threads. The maximum sealable internal
pressure is theoretically equal to the bearing pressure caused by make-up and internal
pressure combined. Maximum sealable external pressure is found in a similar fashion.
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•
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THE PIN HAS ADVANCES INTO THE BOX N TURNS.
THE PIN TRAVELS DISTANCE PN.
BECAUSE OF TAPER, THE DIAMETER OF PIN AT HAND
TIGHT POINT IS STRAINED TO SMALLER DIAMETER WHEN
PIN IS SCREWED INTO COUPLING.
THE INTERFERENCE IS THE DIFFERENCE IN THE DIAMETER
OF THE PIN AT THE HAND TIGHT PLANE AND THE
DIAMETER OF THE PIN AT THE HAND TIGHT POINT IN
POWER IN POSITION.
E1 = DIAMETER OF PIN AT THE HAND TIGHT PLANE
Figure 17. The principal behind pressure sealibility of tapered threads
Figure 18. Internal and external fluid pressure can affect the magnitude
of the taper-induced thread bearing pressure
In April 1983, the API published a supplement to “API Bulletin 5C3: Formulas and
Calculations for Casing, Tubing, Drill Pipe, and Line Pipe Properties”. This supplement
presents a formula for determining the internal leak resistance of API casing and tubing
round-thread and Buttress connections. The formula gives the maximum sealable pressure
considering bearing pressure due to make-up and internal pressure. The API has adopted
use of the formula not to determine sealability of API threads, but to derate tubular burst
resistance based on the assumption that the thread may leak before the ID of the tube body
reaches the yield stress. Additionally, the API considers burst resistance of the coupling.
The coupling is considered as a short piece of tube and the coupling dimensions are
substituted into the API tube body burst resistance (Barlow) equation.
The minimum of the three calculations of burst resistance (tube body, coupling, and thread
sealability) is the internal pressure resistance given in API Bul 5C2.
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Metal-To-Metal Seals
The sealing mechanism of metal-to-metal seals is similar to the tapered connection. Two
smooth metal surfaces mate during makeup to produce a bearing pressure as a result of
metal-interference between the surfaces. However, whereas the seal is formed along the
entire helical length of the thread flanks on a tapered-thread interference fit seal, metal-tometal seals are usually placed at the beginning or end of the thread length. Metal-to-metal
seals are generally considered to be of two types: lip seals and torque-shoulder seals.
Figure 19 shows a connection with metal-to-metal seals.
Figure 19. Tubing connection employing metal-to-metal torque shoulder and lip seals.
6.7.12
Elastomer Ring Seals
Many non-API connection manufactures use an elastomeric ring seal as additional sealing
protection.
Most manufactures use a combination of 75% Teflon and 25% fiberglass. Some
connections employ the seal ring at the end of the pin against an internal shoulder. Other
connections have the ring seal placed in a machined groove in the threaded profile. Figure
20 shows a connection using a Teflon seal ring.
The distortion temperature of Teflon is about 260° and at higher temperatures the ring may
permanently deform. At temperatures close to 400°F Teflon becomes extremely soft and
will flow. Therefore most connection manufactures place an upper limit of about 300°F for
the reliable operation of Teflon seal rings.
It has frequently been reported that Teflon seal rings can get shredded and torn during
makeup. This is primarily due to improper preparation during seal ring placement prior to
makeup. The ring groove should be thoroughly cleaned and dried before inserting the seal.
Careful attention to thread cleanliness and ring placement are essential to error free running
of connections with Teflon ring seals.
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Figure 20. Tubing connection employing an elastomer seal ring in the thread region.
6.7.13
Thread Compounds
Thread compounds serve three basic functions:
•
to seal gaps and thread clearances on and around the threads
•
to lubricate the threads during make-up
•
to assist in the prevention of galling due to metal-to-metal contact.
To accomplish these functions, thread compounds are composed of fine ductile metal
particles dispersed in a grease base.
In any thread profile there are helical passageways at the crests and roots or along the flanks
of the threads due to design tolerances (see Figure 13). There may also be nicks, cuts, or
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scratches in the thread surface caused by careless handling. To keep gases or liquids from
seeping through these clearances, thread compounds are used.
As the connection is made up, the gaps between the threads are gradually reduced forcing
the metal particles into the thread clearances. The powdered metals deform and compact
tightly together to fill the voids. In the most desirable circumstances, the powdered metallic
particles flatten out. Flattening out of the metallic particles allows grease and gases (air
bubbles) to be squeezed away from the metal particles so that the particles are compressed
into a solid mass which completely fills the thread clearances.3
“API Bulletin 5A2: Thread Compounds for Casing, Tubing, and Line Pipe” gives
specifications for the amount of metallic and non-metallic components, and performance
test procedures for two standard thread compounds. The two compounds are: silicone
thread compound and modified thread compound. Silicone thread compound contains
silicone and modified thread compound does not. Section 1 of Bul. 5A2 lists the metallic
composition of the compounds as:
Table 4
Metallic Constituents of API Thread Compounds
(Percent by Weight)
Constituent
Metallic Solids
Compound
Powdered graphite
Lead powder
Zinc dust
Copper flake
28.0
47.5
19.3
5.2
18.0 ± 1.0
30.5 ± 0.6
12.2 ± 0.6
3.3 ± 0.3
Total
100.0%
64.0%
The applicable temperature range of a thread compound is also a very important
consideration. API Bul. 5A2 specifies that the modified and silicone thread compounds
should function adequately up to 300°F. That is, the compound should be able to hold a
seal on connections up to 10,000 psi pressure at 300°F. However, these thread compound
specifications should not be interpreted as threaded connection seability requirements. The
thread compound standards are to be used for lab tests to determine if a particular
compound meets API specification.
Thread compound is not an antigalling agent in itself. The prevention of galling is mainly
accomplished by thread surface treatments such as electroplating the threads with tin or
zinc or phosphatizing the threads. However, thread compounds help lubricate threads so
that excessive friction does not cause galling.
6.7.14
Connection For Sour Service
Tensile stresses in connections are the result of the combined effects of makeup, tensile
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load in the string, and internal/external pressure effects. Control of connection stresses is a
function mainly of connection design and amount makeup. These two parameters are not
independent of one another. Generally, makeup causes certain radial and, more
importantly, hoop tension stresses to develop in a connection.
Connections with little or no taper generate less interference which results in lower makeup
hoop stresses. Therefore, joint design can be effective in controlling stress corrosion
cracking (SSC) by H2S. Results of experimental investigation have indicated that a twostep non-tapered connection design generates low overall hoop stress.4
Due to the limited knowledge of the stress characteristics of API connections, use of API
connections on tubing strings in sour wells should be avoided.
6.7.15
Erosion Resistant Connections
Abrupt changes in flow area can cause turbulence in high velocity/high productivity wells.
Such turbulence can cause erosion of the pipe wall near the pin ends, especially if the well
also produces sand. This problem is further aggravated by the presence of a corrosive fluid
such as carbon dioxide. Therefore, connections with flush or smooth internal profiles
should be used in high velocity hostile production wells. These connections use an internal
shoulder at the box or coupling center to create a continuous inner diameter. An example is
shown in Figure 21.
Figure 21. A tubing connection employing a flush internal profile to prevent turbulent flow
6.7.16
Thread Protectors
Of the entire tubular, the threaded ends are perhaps the most vulnerable to damage and
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defects. Even small scratches on the threads can cause leaks or failure. Therefore,
adequate protection of the threads is very important. Thread protectors are threaded caps
and plugs which are screwed onto the pin and box ends of the tubulars to protect the threads
from damage. They should be on all tubulars during shipping, in storage and on the rack
while the tubing is awaiting running-in. Figure 22 shows several different thread
protectors.
Traditionally, thread protectors have been made of steel to afford durability while
maintaining low cost. However, high impact plastic protectors with metal reinforcement
are now considered desirable. These are referred to as composite protectors.
Figure 22. Typical thread protectors used for casing or tubing connections
6.8
CONNECTION MANUFACTURERS
This subject contains brief descriptions of the most commonly used production tubing
connections presently available. Since most non-API manufacturers offer several
connections based on the same design principle, only the design philosophy of non-API
connection manufacturers will be given.
6.8.1
API Connections
API NON-UPSET - This is threaded and coupled connection and is probably the oldest,
most basic design for a tubing connection (see Figure 23). It has a low joint efficiency and
is therefore primarily used in shallow to moderate depth wells. Sealing is accomplished
with a tapered round-thread interference seal mechanism.
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Figure 23. API Non-upset tubing connection
API EXTERNAL-UPSET-END (EUE) - The API EUE connection, shown in Figure 24, is
threaded and coupled and is the strongest in axial yield strength of all the API tubing
connections. It exhibits an externally upset pin end to increase joint strength. It has 100%
joint efficiency in all sizes, hence it can be used in moderate to deep wells. Sealing is a
tapered round-thread interference fit seal mechanism.
Figure 24. API External-upset-end tubing connection
API INTEGRAL JOINT (IJ) - The API integral joint tubing connection, Figure 25, was
designed in an effort to develop a non-threaded and coupled, high tensile strength tubing
connection to be used in tight clearance completions where non-upset did not provide
sufficient joint strength and EUE couplings were too large. Additionally, it was intended
that such a connection be suitable for use as a work string. The connection is stronger than
non-upset tubing but not quite as strong as EUE tubing. This connection is most often used
as a work string.
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Figure 25. API Integral joint tubing connection
API LONG-THREAD CASING (LTC) - The API LTC connection is a threaded and coupled,
non-upset casing connection. It employs API round threads identical to the tubing round
threads. The seal mechanism is the thread interference fit. The joint efficiency varies
between 62% and 68% depending upon sizes, weight and grade. Figure 26 shows the API
LTC profile.
Figure 26. API Long-thread casing connection
API SHORT-THREAD CASING (STC) - The API short-thread casing connection is almost
identical to the LTC connection. The STC connection is used on thin wall casing where the
long thread length of the LTC connection would result in a sharp chamfer at the pin end.
The STC connection has the lowest axial strength capacity of all API casing connections.
The joint efficiency of the STC connection varies from 46% to 54% depending on the
outside diameter and weight per foot of the tube body.
API Buttress-Thread Casing (BTC) - Figure 27 is an illustration of the Buttress casing
connection. The API lists specifications for Buttress threads for casing only. Complete
thread run-out, threads are in full contact at the tube body outer diameter, and the square
thread profile enable this connection to attain nearly 100% joint efficiency without
upsetting. The connection seal mechanism is the tapered thread interference fit.
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Figure 27. API Buttress-thread casing connection
The Buttress thread profile has larger thread clearance than API round thread casing and
tubing. It is difficult to seal high pressure gas with Buttress threads due to the large thread
clearance. It has been a practice to heavily tin plate Buttress threads to help fill thread
clearances.
6.8.2
U. S. Steel Buttress Tubing
U.S. Steel manufactures a Buttress-thread tubing connection, the “Improved Buttress
Threaded” connection, shown in Figure 28. The thread form is slightly different than the
API BTC thread (the load flank is 0°). The pin and box threads run out completely. The
joint efficiency is nearly 100% with no external-upsetting. The sealing mechanism is
identical to the API tapered connection sealing.
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Figure 28. U.S. Steel Improved Buttress-thread tubing connection and thread profile
6.8.3
Hydril
Hydril offers several integral joint and threaded and coupled designs. Hydril was the first
to use a “two-step straight thread” connection. A schematic of a typical Hydril two-step
thread profile connection is shown in Figure 29.
Most Hydril tubing connections have modified buttress threads. There is no thread
interference since there is no thread taper. Therefore, the threads do not function as a seal.
Rather, threads are used to provide axial strength and mechanical advantage to load torque
shoulders and metal-to-metal seals. Hydril also offers an optional Teflon-fiberglass seal
ring to prevent corrosive fluids from entering the thread path. Since the threads are nontapered with no interference, little hoop stress in the connection is generated by makeup.
Some patents on the Hydril “two-steps” thread profile design have expired. There are now
many service companies which offer a variety of connections based on Hydril “two-step”
designs. Otis Premium Thread Service (PTS), which used to be a principal licensee to cut
Hydril threads, now offers a complete line of “two-step” threaded connections. Otis PTS
guarantees interchangability of their connections with Hydril’s.
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Figure 29. Hydril CS-CB tubing connection
6.8.4
Atlas Bradford
Atlas Bradford’s connection designs utilize multiple sealing mechanisms and Atlas
Bradford’s proprietary modified Buttress thread profile. Atlas Bradford offers both integral
joint and T&C designs. The sealing elements will be two or more of the following
depending on the connection design: (1) shoulder seal at the pin nose, (2) a metal-to-metal
lip seal just above the pin nose, (3) a Teflon-fiberglass ring seal, and (4) interference-fit
tapered modified buttress thread seal.
Although the threads are tapered, the interference between the box and pin is not usually as
great as the API connections. The primary use of the taper-induced interference is to
prevent down-hole breakout. Figure 30a shows the Atlas Bradford DSS-HTC “Dual Seal”
tubing connection.
Atlas Bradford also manufacturers a threaded and coupled connection, the TC-4S
“Quadraseal”, which has been used on large diameter producting tubing. The TC-4S is
shown in Figure 30b. Atlas Bradford and some other companies manufacturer a modified
API coupling. The coupling has a groove machined into its ID into which a Teflonfiberglass seal ring is installed as an additional seal mechanism. This is shown in Figure
31.
Figure 30. Two of Atlas Bradford’s tubing connections
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Figure 31. Modified API coupling in which a Teflon-fiberglass seal ring is used
to improve pressure sealability
6.8.5
Vallourec
Vallourec is a French based company whose tubing and casing connections have been used
widely in North Sea completions. There are 3 Vallourec tubing connections, each designed
for different for different service environments: VAM, (shown in Figure 32), VAM-AF,
and VAM-AG. The thread profile is of the buttress type. All of the designs share the same
basic characteristics, differing mainly in certain coupling dimensions.
The basic seal mechanism of VAM tubing connections is 30° tapered seal, as shown in
Figure 32. The pin end mates against the coupling shoulder and make-up theoretically
wedges the 30° seal surface on the pin nose against a similar surface on the coupling. The
casing size VAM connection seals in a slightly different manner. The metal-to-metal seal is
a 2.5° seal surface located between the pin threads and the 30° chamfer.
Otis Engineering Corporation (OTS-PTS) obtained permission, as a principal licensee, to
cut VAM threading in the United States.
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Figure 32. Vallourec VAM connection design
6.8.6
Other Manufacturers
There are many other companies that offer non-API connection designs. Most of these
designs employ multiple-to-metal seal, modified buttress or hook-type thread profiles, and
usually include a Teflon-fiberglass type secondary seal.
6.9
CONNECTION MAKEUP
6.9.1
Makeup Torque
Making up tubular connections by applying torque with rig tongs has been the prevalent
method of makeup for many years (see Figure 33). Loss of pressure integrity or failure of a
string can be caused by improper make up practices. Threads should always be thoroughly
cleaned with a solvent such as Varsol and a bristle brush before applying thread compound
or putting on thread protectors. The threads should always be visually inspected for
damage or defects before makeup.
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To screw together any threaded connection, torque is required to overcome friction and
interference between the pin and box threads. However, tubing and casing require careful
consideration of the torque necessary for makeup to provide a strong connection and assure
a leak tight seal against pressured production fluids, especially gas. The amount of torque
necessary to provide a leakproof connection is dependent mainly upon the following
parameters:
•
Thread compound,
•
Surface preparation of the thread (plating or phosphatizing), and
•
Thread profile (type of connection or sealing mechanism).
To form a reliable seal, torque is applied by tongs and makeup of the connection continues
until sufficient pin-to-box interference is developed. The pin thread surfaces conform to
the box thread surface so that the voids above the threads are filled with thread dope
metallic filler and optimum bearing pressure is achieved. Similarly, sufficient torque must
be applied to connections using metal-to-metal seals to develop the necessary bearing
pressure between the seal surfaces.
The torque applied during makeup with the tongs is dependent upon the coefficient of
friction of the thread compound. If the coefficient of friction is high, the torque must work
mainly to overcome the friction and makeup is slow. If the coefficient of friction is low,
applied torque causes faster rotation of the pin into the box and a lower torque can be used
for makeup. Thus the lubricity of the compound, or the coefficient of friction, can control
the makeup. Either over-makeup or under-makeup can cause many problems; for instance,
insufficient joint strength, leaking, and overstressing.
The tool joints used on drilling tubulars employ large torque shoulders which function as a
seal. Because of its design, tool joints require a thread compound with a high coefficient of
friction. Tubing and casing thread compounds can cause damaging over-makeup of tool
joints due to their lower coefficient of friction; tubing and casing thread compounds should
never be used on tool-joint threads.
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A.
STABBING THE PIN INTO THE BOX
B.
APPLYING TORQUE WITH TONGS
Figure 33.
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API Makeup Recommendations
Optimum recommended makeup torques for API connections are given in API RP 5C1.
These recommendations apply to API Standard 5B connections only. Tables of makeup
torque values are supplied by all manufacturers of connections and these values are usually
determined by experiment or general oil field experience.
“API RP 5C1 : Care and Use of Casing and Tubing” also contains recommended makeup
procedures. The API recommends that the connection should be made up approximately
two turns beyond the hand-tight position. To prevent galling, the connections should not be
made up at speeds in excess of 25 rpm.
6.9.3
Torque-Turn Makeup
In a effort to reduce leaks by placing makeup of API connections upon a more operationally
reliable foundation, Humble (Exxon) developed a method of makeup based not only on
torque but also on the axial distance the pin is screwed into the box, he turns. This method
of makeup is called torque-turn6. An illustration of torque-turn makeup in the field is
shown in Figure 34. It should be understood that the torque-turn theory was developed in
an effort to increase the seal reliability of API threaded-and-coupled connections which
employ interference-fit tapered threads and no metal-to-metal seals. Therefore torque-turn
is best applied to API connections. This does not imply that API connections that are
torque-turned are hence superior to other connections; it means that torque-turned API
connections may provide a more reliable seal than API connections which are not torqueturned.
The seal of API threaded-and-coupled tubing and casing connections is controlled by the
bearing pressure between the pin and coupling threads generated during makeup. During
initial makeup, the pin rotates into the coupling with ease until the hand-tight position is
reached. After the hand-tight position, metal-interference generates bearing pressure.
Thus, the sealability is a function of the number of rotations, the “turns”, of the pin into the
box after the hand-tight position is reached. Since connections are also made up by using
torque only, a relation exists between torque and turns to makeup. The relationship is the
basis for torque-turn.
The torque-turn method of makeup should be specified for production casing and tubing
with API connections in order to reduce the incidence of leaking strings. Specifically,
torque-turn should be used when the differential pressure across the connection is over
3000 psi. The higher the well pressure, the more important this recommendation becomes.
A.
TORQUE INDICATOR ON TOP OF TONG WITH HORN WHICH INDICATES OVERTORQUE
OR OVERTURNS. A LOAD CELL IS ATTACHED TO THE TONGS TO INDICATE TORQUE.
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B.
SCHEMATIC AND ACTUAL TORQUE-TURN
COUNTERS
Figure 34. Torque-turn operations and equipment
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Non-API Connection Makeup
Non-API connection makeup procedures are governed by the recommendations of the
manufacturer. These guidelines are usually contained in manufacturer’s bulletins on
running and pulling procedures. Generally, the manufacturer will provide a representative
to oversee the running of the first string equipped with their connection.
6.9.5
Mill End Couplings
Sometimes, tubing is shipped from a mill with the coupling made up on one end of the
tubing. This end of the tubing is called the “mill-end”. It has been reported that the millends of couplings are subject to excessive leaks7. It is thought that this is due to the
redistribution of thread compound in the mill-end threads during transportation from the
mill to the field. Also, drying up or sublimation of the thread compound grease base will
leave only the solidly compacted metal powder on the threads. This can cause damage
during breakout of connections and could even render breakout impossible. Therefore, it is
often suggested for high pressure, critical wells that couplings be boxed separately from the
tubing and floated on in the field so that the user can apply the compound as required.
6.9.6
Galling
Galling is a common problem occurring during makeup of any threaded connections.
Threads can become so severely deformed during makeup that breakout of the connection is
impossible and threads may have to be recut. Galling is the result of very high bearing
stress induced by interference between metal surfaces causing the surfaces to bond. The
two surfaces are severely deformed (galled) when one surface is moved relative to the
other. This galling is caused by excessive friction and interference between the pin and the
box thread surfaces during connection makeup. An example of thread galling is shown in
Figure 35.
Excessive friction can be caused by dirty threads, improper makeup speed, excessive thread
tolerance or improper thread compound. As mentioned previously, pin and box threads
should be thoroughly cleaned. Adequate thread cleanliness and control of makeup speed
can prevent most galling problems.
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Figure 35. Extreme galling of API round-threads
6.9.7
Thread Preparations
Galling and friction between surfaces of similar materials is greater than between dissimilar
materials. Therefore electroplating the threads of a tubular connection with a thin layer of
a malleable metal different from the thread metal is widely practiced to prevent galling
caused by friction and surface irregularities. The two most commonly used metals for
electroplating the thread surfaces are zinc and tin. Zinc and tin are most usually plated onto
the coupling thread - that is, upon the entire internal surface of the box. This is done to
protect the plating from chipping and additional damage by dragging a plated pin end on the
rig floor.
Zinc is by far the most commonly electroplated metal. Tin, being more malleable than zinc,
has generally been used on those threads with large spacing in the profiles such as Buttress
or Acme threading and on high yield strength grades of pipe (material above P-110).
Another method used to reduce galling of threads is phosphatizing (or parkerizing).
Phosphatizing is most commonly used for non-API metal-to-metal seal connections.
Phosphatizing is not an electroplating process; it is based on chemical reactions. A
phospate crylstalline structure or etching is formed which tends to hold the thread
compound in place so that the compound will not be wiped away under the action of
bearing stress during makeup and cause metal-to-metal contact.
Tubing and casing connections made of high-alloy steels have been known to experience
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severe thread galling problems during makeup. Galling of high alloy casing threads is
much more a problem than galling of smaller tubing size connections. Glass bead peening
or sand blasting of tubular threads is often practiced during manufacture to harden and
texture the immediate surface of the threads for prevention of galling. Copper
electroplating of coupling threads has been used as an anti-galling practice for high-alloy
connections.
6.9.8
Tong Notches
Tong notches in high-strength tubular goods have caused both tubing and casing failures.
Properly designed and maintained hydraulic-powered tongs with special contoured tong
dies will minimize notching.
Instances in which tong marks should be carefully guarded against are:
•
High strength tubulars (P-110 and above),
•
High-alloy tubulars, and
•
Any tubulars to be used in H2S environments.
Tong dies and slip teeth should be inspected frequently to assure that they are sharp.
6.10
PRODUCTION TUBING STRING DESIGN CRITERIA
6.10.1
Design Parameters
The design of a production tubing string that will safely and efficiently bring hydrocarbons
to the surface over the life of the well requires the consideration of a variety of parameters.
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The parameters that are most important in production tubing string design are :
•
Tubing ID (production rates)
•
Tubing manufacturing process and steel composition (corrosion resistance)
•
Tubing grade (yield strength)
•
Wall thickness (body yield strength)
•
Threaded connection selection (joint yield strength)
•
Tubing string landing procedures (stability)
•
Future enhanced recovery options and operational considerations
When selecting the tubing for a well completion, the tubing should consist of a single
weight and grade (in tapered strings each section of string should consist of one weight and
grade). This is very important in order to prevent mixing various weights and grades in a
string when tubing is pulled and rerun during a workover. Additionally, some tubing
strings may eventually be used as worksrings.
6.10.2
Design Flowchart
A flowchart which is helpful in designing a production tubing string is given in Figure 36.
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Figure 36. Flowchart for conventional production tubing string design
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Example Tubing String Design
To best illustrate the calculations involved in designing a production tubing string, an
example string will be designed step-by-step during the remainder of this chapter. The well
data for this example is given below in Table 5.
Table 5
Example Tubing String Design Data
Well type : Standard, non-corrosive (no CO2 or H2S)
Reservoir fluid : oil with gas
Gas-to-liquid ratio (GLR) :1000 scf/bbl
Produced water : 0%
Reservoir depth : 12,500 ft
Packer depth : 12,000 ft
Reservoir pressure (BHP) : 6000 psi (9.2 ppg equivalent)
Reservoir temperature (BHST) : 235°F
Surface ambient temperature : 80°F
Oil density : 7.260 ppg (30°API)
Gas gravity : 0.80 (rel. To air)
Packer fluid (completion fluid) density = 9.5 ppg
6.11
TUBING SIZE SELECTION
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Selecting the optimum size for a production tubing string requires a study of single and
two-phase flow of oil and/or gas through the pipe. Knowledge of the relationships between
flowing pressures through the reservoir and through the tubing are required. Generally, the
following steps are taken to determine optimum tubing size:
•
Develop pressure gradients for various size tubing
•
Develop flowrate versus pressure drop, flowing wellhead pressure, or flowing
bottomhole pressure plots for various tubing sizes
•
Consider effects such as erosional velocity, possible future artificial lift requirements,
and other operational constraints.
It may be desirable to select a tubing size to
•
Maintain a specific wellhead pressure,
•
Produce at a specific flowrate,
•
Maintain a specific bottomhole pressure.
Cost and availability of tubulars must also be considered. Well economics may be a
limiting factor.
6.11.1
Tubing Flowing Pressure Gradients
Hydrocarbons are delivered to the wellbore under pressure from a reservoir. Due to flow
restrictions through the reservoir rock and the perforations,, the flowing bottomhole
pressure (FBHP) will be less than the reservoir pressure. Thus, there is a fluid pressure
drop from the reservoir to the wellbore (below the tubing string).
To transport reservoir fluids through the tubing vertically against gravity causes a change in
potential energy. The flow of fluids through the tubing also causes losses in energy due to
flowing friction effects. These energy changes and losses manifest themselves in the form
of pressure losses as the fluid flows from the bottom of the well to the surface. Figure 37
illustrates pressure losses from the reservoir to the surface in a flowing well.
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Figure 37. Pressure losses in a flowing production well
The flowing pressure drop per increment of tubing length from bottom hole to the wellhead,
the pressure gradient, can be generally written as the sum of two pressure losses:
∆p
∆L
=
gρ
4f
gc + ( d)
pv2
2gc
where:
∆p/∆L
f
g
gc
ρ
v
d
=
=
=
=
=
=
=
pressure loss per increment of pipe length, (lbf/ft2)/ft
Fanning friction factor
acceleration due to gravity, 32.17 ft/sec2
dimensional constant, 32.17 lbm-ft/lbf-sec2
density of fluid, lbm/ft3
fluid velocity, ft/sec
inside diameter of pipe or tubing, ft
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The first term on the right hand side of equation (11.1) describes the pressure loss due to
the change in potential energy of lifting the fluid of density ρ. This term is also known as
the static head loss. The second term gives the friction pressure drop of flowing liquid.
Since fluid velocity can be put in terms of the flowrate, Q, (see the following topic) the
friction term can be seen to be a function of flowrate, tubing ID, and a friction factor
(usually empirically derived). In practice, if the density is constant with depth, then
equation (11.1) can be solved exactly. However, for true multiphase flow or compressible
fluids, the density is a function of depth and the equation will have to be approximated
using numerical integration methods.
Flowing pressure gradients for the flow of the example well fluid through various tubing
string sizes are shown in Figure 38. Such gradients are generated using computer programs
which use one of many available pressure gradient correlations. For each of the plots in
Figure 38 flow rate, tubing ID, and basic fluid properties such as viscosity, gas and oil
densities, gas-liquid ratio (GLR), and water cut, plus either the FWHP or FBHP must be
given initially as known, or input, data. Given FBHP, the FWHP is calculated by the
program, or vice versa.
Figure 38. Flowing pressure plots for the example well data.
The FWHP was held constant at 1000 psi.
6.11.2
Tubing Size Effects
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Figure 39 shows plots of the following friction pressure drop for increasing flowrate
through various size tubing strings using the example well data. Frictional pressure losses
increase with decreasing tubing size. The pressure drop due to friction as given in equation
(11.1) can be written as a function of fluid velocity or flowrate :
∆pf = ( 4f)
d
ρv2
∆L
2gc
=
32fρQ2
πgcd5
(11.2)
where
∆pf/∆L
f
v
Q
d
ρ
=
=
=
=
=
=
pressure drop due to friction, (lbf/ft2)/ft
Fanning friction factor
fluid velocity,ft/sec
fluid flowrate, ft3/sec
Inside diameter of tubing, ft
Fluid density, lbm/ft3
For a given flowrate, as the tubing ID decreases, the fluid velocity increases and friction
pressure drop increases.
Figure 39. Flowing friction pressure drop for increasing oil flowrate for different size tubing strings
Shown in Figure 40 are plots of total pressure drop (i.e. static head and frictional pressure
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losses) versus flowrate for various tubing sizes using the example well data. As the
pressure in the formation or the tubing declines below the bubble point, gas and liquid can
physically separate, that is, gas can break out of the mixture.
As gas breaks out, it rises faster than the liquid due to its lower density. If enough gas
breaks out and the velocity is sufficiently low, the heavier liquid may fall back in the string.
This phenomenon is also referred to as liquid hold-up. The pressure drop associated with
the increased fluid head may be high enough to kill a low BHP well. Liquid hold-up is the
reason the pressure drop for 4-1/2-in. tubing in Figure 40 is greater at 500 bbl/d than at
3000 bbl/d.
Figure 40. Total pressure drop (flowing friction plus head) with increasing oil
flowrate for different size tubing strings
It is also important to consider pressure drop when injecting through tubing. The principles
of analysis are the same for injection as they are for production, since pressure loss
increases with increasing flow rate and decreasing tubing ID. In injection operations such
as fracturing, acid stimulation, or any other fluid injection process, it is sometimes
important that a specific bottom hole pressure be maintained. Therefore, flowing pressure
gradients for injection through different tubing sizes need to be considered.
6.11.3
Erosional Velocity
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High velocity, two-phase flow of gas and liquid can cause tubing wall erosion. Wall loss
can be accelerated if the flow contains sand. Erosion can also be accelerated if a corrosive
agent such as CO2 is present. For sand-free production the API recommends that the fluid
velocity through the tubing be kept below a maximum velocity called the erosional velocity.
It is extremely important to understand that the API recommendation is for sand-free
production. There are at present no specific API guidelines for production fluids with
solids. Fluid velocity can be reduced by increasing the tubing ID. “API Recommended
Practice 14E : Design and Installation of Offshore Production Platform Piping Systems”
contains an equation for the erosional velocity:
ve =
C
⊕ρm
(11.3)
where
ve
c
ρm
= fluid erosional velicity, ft/sec
= an empirical constant
= 125 for sand free intermittent flow
= 100 for sand free continuous flow
= gas/liquid mixture density at flowing pressure and temperature,
lbm/ft3
The mixture density is given by:
ρm =
12409SlP + 2.7RSgP
198.7P + RT z
P
Sl
= operating pressure, psi
= liquid specific gravity (water = 1; use average gravity for
R
T
Sg
z
= gas/liquid ratio, ft3/bbl
= operating temperature, °R
= gas specific gravity (air = 1)
= gas compressibility factor, dimensionless
(11.3)
hydrocarbon-water mixtures)
The value of c in equation (11.3) is of particular importance. The value for c given above is
a standard API value. Some investigators have suggested changing c to account for sand
production.8 If the following fluid contains sand or a corrosive gas, it is generally
recommended that c should be reduced by 20-40%.
Once ve is calculated, the minimum flow area can be calculated from the API equation
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Ae
R
T
P
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9.35 + RT
21.25P
ve
(11.4)
= minimum flow area, in2/1000 bbl liquid per day
= gas/liquid ratio, ft3/bbl
= operating temperature, °R
= operating pressure, psi
Then the minimum ID to prevent the fluid from exceeding the erosional velocity is derived
from the simple equation for area:
Ae
= π (IDe)2/4
(11.5)
Figure 41 shows an example of a high productivity gas well where erosion velocity limits
tubing size.
Figure 41. An example of how the API erosional velocity limit is used to determine the minimum FWHP.
Above the minimum FWHP, the API erosion velocity is exceeded.
6.11.4
Well Deliverability
The reservoir delivers hydrocarbons to the wellbore by means of a pressure drop from the
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formation to the wellbore. The relationship between the flowrate delivered by the reservoir
and the FBHP is called an inflow performance relationship (IPR).
The IPR for a given reservoir is unique and depends on the reservoir pressure, formation
rock properties, fluid viscosity, near wellbore damage, and turbulence. The IPR for the
example well is shown in Figure 42. The FBHP necessary for a particular rate on the IPR
curve is then used to determine the tubing deliverability. Tubing deliverability concerns the
flow rate available from a particular tubing size. This was addressed in the Tubing Size
Effects topic. It should be understood that the FBHP, tubing size, FWHP, and flowrate, Q,
are somewhat interdependent. This is why it is usually necessary to consider parametric
studies if FBHP, FWHP, flowrate, and tubing size to select an optimum tubing diameter.
6.11.5
Tubing Size Selection
Several considerations must be made in selecting the optimum tubing ID: FWHP
requirements for the pipeline or for the pipeline or for efficient separator operation, future
water production or artificial lift requirements, operational or drilling limitations, and
tubular cost and availability.
Required FWHP - Using an IPR curve to determine FBHP, a plot of FWHP versus flow
rate can be developed for various tubing sizes. Figure 43 shows such a plot for the example
well.
The friction pressure loss in the small ID tubing results in low FWHP at high rates. Thus, if
a higher FWHP pressure was required, larger ID tubing would be needed.
Future artificial lift - Figure 44 shows FBHP for increasing flowrate with an increasing
percentage of liquid being produced. The increasing liquid content increases the density of
the production fluid and increases the FBHP. This in turn decreases the drawdown
reducing the feed-in-rate. Lower rate implies lower velocity which aggravates the fall-back
problem. The well kills itself. Injecting gas into the tubing (for example through a gas lift
valve in a side pocket mandrel) lowers the mixture density and the FBHP. This increases
the drawdown and permits higher feed-in-rates from the formation. Higher rate implies
higher velocity mitigating fall-back. Smaller ID tubing could also reduce liquid fall back,
but at the expense of initial oil production rate.
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Figure 42. Inflow performance relationship (IPR) for the example well reservoir data
Figure 43. Deliverability curve for the example well data
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Figure 44. A plot of the FBHP for increasing flowrate at different water cuts shows
that gas lift may be required to produce the well.
Operational and Drilling Limitations - In some areas, particularly offshore, there may be
government regulations on the size or type of casing and tubing strings. There are often
cases where limitations exist on downhole equipment availability, such as the size and
rating of subsurface safety valves. In other instances, overall well development may require
consideration. For instance, it may be very difficult to drill a large diameter hole in some
areas and this may require that smaller tubing and casing sizes be utilized despite the desire
for optimum production hydraulics.
Cost and Availability - In some instances, local tubular stocks may have an oversupply of a
particular size or grade of tubing. For economic efficiency it may be desirable to use such
tubulars even if they are not optimum for the given application, but do meet most needs. As
mentioned previously, it may be so expensive to use large tubing and casing to drill and
complete a well that tubular sizes are dictated by well development cost, not optimum flow
rate.
Example:
As discussed above, there are many factors affecting the selection of tubing size. Certain
local guidelines and tubular availability restrictions may apply which cannot be considered.
It is assumed that 3-1/2-in. OD tubing has been selected for the example well. It should be
noted that although there are many weights of 3-1/2-in. available, the change in ID from one
weight to another does not appreciably affect flowing pressure gradients.
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TUBING LOAD ANALYSIS
The purpose of this section is to define and quantity the different loads that can act on a
tubing string during well operations. Generally, the tubing is subjected to the following
loads:
(1)
Axial tension and compression
(2)
Burst
(3)
Collapse
(4)
Bending
The sign convention followed in this text is that tension forces and stresses are considered
positive (+) and compressed forced and stresses are considered negative (-).
Also covered are the design factors used to ensure that the tubing string design is
structurally sound and will not fail (or yield) under expected or unexpected wellbore
conditions.
6.12.1
Phases Of Well Life
In general, a well will pass through four operational phases during its life (not necessarily
in this order):
(1)
Setting or landing - The packer and tubing are run in the hole and set. An initial
stress (tension or compression) may be applied to the tubing before it is hung in the
wellhead.
(2)
Shut-in - The wing valve is closed and the well is prevented from flowing.
(3)
Production - Production fluid flows due to pressure.
(4)
Stimulation or injection - Fluid is injected under pressure into the tubing string
during fracturing jobs, acid jobs, or when killing the well.
Each particular operation causes changes in well temperature and pressure which results in
changing tubing loads.
6.12.2
Design Factors
Design factors are used to ensure that the tubular strength ratings are sufficient to withstand
expected wellbore loads and an additional amount of unexpected loading. The tubular
axial, burst, or collapse rating is divided by the design factor to give a reduced rating or
working load for the tubular. Tubular maximum loads should not exceed the working load.
The design factors given below are primarily a result of industry experience.
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Tension Design Factor - The tension design factor ranges from 1.5-1.8. The axial rating
selected is the minimum of the pipe body strength and the connection strength. The tubular
load is calculated on the basis of the string hanging freely in air; buoyancy is generally
neglected in production tubing design. If there is reasonable confidence in the prediction of
downhole forces or if the completion is being designed for a well developed area, lower
design factors, 1.5 to 1.6, are used. If the completion is for an exploratory or step-out well,
or if the downhole environment is known to be hostile, larger design factors, 1.7 to 1.8, are
suggested. If predicted wellbore temperature and pressure changes increase tubing loads so
that the design factor is exceeded, stronger tubing is required or alternate completion
operations should be considered (e.g., initial tubing stress when landed, annulus pressure
during stimulation, etc.).
Burst Design Factor - The recommended burst design factor ranges from 1.125 to 1.312
with lower factors for low pressure, well developed wells and higher factors for high
pressure corrosive wells. If the Lame’ formula is used to develop tubular burst strength
ratings, then the following design factors are recommended:
•
1.125 for standard well-developed fields
•
1.312 for hostile or high pressure or exploratory wells
Different design factors may be appropriate if the burst design is based on the Barlow
Formula.
Collapse Design Factor - The collapse design factor for production tubing is 1.125.
6.12.3
Hydrostatic Pressure
Due to its density, a column of fluid exerts pressure beneath its surface. The pressure at
any depth is due to the weight of the fluid above it. This pressure is referred to as the
hydrostatic pressure or hydrostatic head and is given by the density of the fluid times the
depth:
PH = 0.052 Hρ
(12.1)
where :
PH
ρ
H
= hydrostatic pressure at depth H, psi
= fluid density, ppg (lbm/gal)
= depth, ft
The coefficient 0.052 psi/ft/lbm/gal is a conversion factor.
If pressure is applied at the surface of the well, the total static pressure at depth H will be
given by the sum of the applied surface pressure and hydrostatic head of fluid:
P = Psurf + 0.052 Hρ
(12.2)
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where : Psurf = surface pressure, psi
6.12.4
Axial Loads
Axial or longitudinal tubing loads are the most difficult of all loads to accurately predict
due to the many different forces acting on the string in the well. Initial axial tensile or
compressive loads are generated by the buoyant weight of the tubing during initial landing
operations. After landing, the well is shut-in, brought onto production, or injected with
fluid. These operations cause changes in well pressures and temperatures with
corresponding changes in axial loads. Temperature changes cause changes in axial loads if
the tubing is prevented from elongating or contracting by the packer. Buckling also causes
axial and lateral loads.
6.12.5
Air Weight
The air weight, or weight in air, of a tubing string is simply the product of the weight per
foot of the tubing and the length of the tubing string:
Wair = wL
Wair
w
L
(12.3)
= air weight of tubing, lb,
= nominal weight per foot of tubing, ppf, and
= total length of tubing string, ft
The air weight is used to initially determine the required tubing weight and grade. Air
weight is used because the tubing will sometimes be anchored to a packer and often
additional axial tension load above the buoyant weight of the string will be pulled at the
surface. Additionally, the air weight can be an actual tubing load which occurs when
perforations become plugged and the tubing is evacuated or when a well is swabbed tot he
perforations.
Example:
As previously stated, 3-1/2-in. OD tubing was selected for the example well design. Using
tables of tubing performance properties such as given in API Bul 5C2 or the Halliburton
Cementing Tables, the lowest weight and grade (and therefore the cheapest) 3-1/2-in.
Tubing is 7.70 ppf, J-55 non-upset tubing with an axial yield strength of 89,470 lb.
Since this is a standard, non-corrosive well, apply a design factor of 1.5 so the working load
is
89,470 lb
59,647 lb
=
1.5
The air weight is
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Wair = (7.70 ppf)(12,000 ft) = 92,400 lb
7.70 ppf, J-55, NU tubing is inadequate since its working load of 59,700 lb is much less
than its air weight. However, checking the performance property tables again, it is found
that 9.3 ppf, N-80, EUE tubing has a joint yield load of 207,220 lb.
Applying the design factor to the axial yield strength:
207,220 lb =
1.5
138,146 lb
The air weight of the 9.3 ppf tubing string is
(9.3 ppf)(12,000 ft) = 111,600 lb
The 3-1/2-in. OD, 9.3 ppf, N-80 EUE tubing is adequate based on air weight. The initial
choice is therefore to use 9.3 ppf, N-80 tubing with EUE connections. Note also that this
well has differential tubing pressure greater than 3000 psi and that it is 12,000 ft deep. This
may require that torque-turn makeup of the EUE connections is required or that a non-API
connection with greater than 100% joint efficiency is required.
6.12.6
Buoyant Weight
It is important to consider the effects of fluid buoyancy on tubing or casing when
determining the reduction in collapse resistance due to axial tension or when considering
fishing operations. Buoyancy is also important when considering tubing or casing string
stability. When a tubing or casing string (or any object) is totally submerged in a fluid, its
weight is reduced by an amount equal to the weight of fluid displaced by the string. This
effect of reduced weight is buoyancy. By subtracting the weight of the fluid displaced by
the string from the air weight of the string the following equation can be derived for the
buoyant weight of the string:
WB
(12.4)
=
(B.F.)Wair
where :
WB
Wair
B.F.
ρ
65.5
= Buoyant weight, lb
= air weight of tubing, lb,
= (65.5-ρ) / 65.5 = buoyance factor, and
= Wellbore fluid density, ppg
= An average velue for the density of steel (some high-alloy
materials may have a slightly different density), ppg
Example:
The completion fluid (in which the tubing will set in the packer) is a 9.5 ppg brine.
Therefore, the buoyancy factor is
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65.5 - 9.5
65.5
= 0.85
and the buoyant weight for the 3-1/2-in. OD, 9.3 ppf, N-80 tubing is
WB = (0.85)(111,600 lb) = 94,860 lb
6.12.7
Neutral Point
Figure 45 shows a plot of the axial load in a tubing string hanging in air. Note that the axial
load is always a tensile load and varies from the air weight at the surface to zero at the
bottom of the string. This is due to the fact that each joint from the surface down must hold
the weight of the remaining tubing below it and there is no load or support acting upward
against the string.
A buoyant force can be considered to act upward against the end of the string to cause a
compressive axial load in the tubing string. The compression decreases with distance from
the bottom of the string as tension in the string increases due to the weight of all the tubing
below the depth of interest. This is also shown in Figure 45 which shows a plot of axial
load versus depth of a tubing string is zero, that is, changes from tension to compression, is
called the neutral point. The neutral point is used to determine the depth at which collapse
rating should be derated for axial tension (discussed later). The neutral point of a tubing
string in a fluid filled wellbore is given by:
n = (B.F.)L
(12.5)
where :
n
B.F.
L
= neutral point, ft
= buoyancy factor
= tubing depth, ft
Example:
Using the previously calculated buoyancy factor, 0.85, n = (0.85)(12,000 ft) = 10,200 ft
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Figure 45. Plots of axial load versus depth for a tubing string in air and in a fluid
6.12.8
Burst Load
After selecting the tubing weight and grade based on tubing string tension (air weight), the
burst strength of the tubing must be checked to ensure that the tube wall thickness (given by
the weight per foot) is adequate to prevent burst failure due to internal pressure. In some
areas, abnormal pressure zones may exist at shallow depths. While the wellbore may not be
considered deep (less 8000-10,000 ft), extremely high internal pressure may be possible.
Thus, some districts or divisions may require that maximum burst load be considered before
tension in the string design process. However, in most cases, tension will cause the greatest
load on a tubing string.
The differential pressure acting across the tubing wall due to an internal pressure greater
than the external pressure is known as the burst load. The maximum burst load will
normally occur at the depth at which there is no external pressure, or back up. This
normally occurs at the surface just below the wellhead where there is often little or no
annular surface pressure. This is illustrated in Figure 46.
The worst case tubing burst load will normally occur during shut-in or during stimulation
(injection) operations when high tubing surface pressure exists.
After determining the worst case burst load, the burst resistance of the tubing is checked.
The burst resistance rating is divided by the appropriate burst design factor to determine the
maximum allowable burst load for the tubing. If the allowable load is less than the
calculated maximum burst load, a higher weight tubing (greater wall thickness) or higher
steel grade (greater yield strength) is required.
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Figure 46. Plot tubing and annulus pressure with depth. The maximum differential pressure, the
burst load, occurs at the surface.
Example:
As a worst case, the production fluid is assumed to be gas (this may not be a bad
assumption as many wells which initially produce oil and gas may begin to produce more
gas at a later time). The maximum shut-in tubing pressure (SITP) for a 2.0 ppg gas is found
by equation (12.2).
SITP = 6000 psi - 0.052 psi/ft/lbm/gal (2.0 ppg)(12,500 ft) = 4700 psi
The burst rating of 3-1/2-in. OD, 9.3 ppf, N-80 tubing is 10,160 psi (this value is found
from API Bul. 5C2 or the Halliburton Cementing Tables). Applying a 1.125 burst design
factor for a standard, non-critical well,
10,160 psi
1.125
6.12.9
= 9031 psi > 4700 psi
The tubing weight and grade is adequate under maximum burst load.
Collapse Load
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The differential pressure acting across the tubing wall due to external (annulus) pressure
greater than tubing pressure is the collapse load. In designing the string for maximum
structural integrity, the maximum collapse load is assumed to be the pressure differential
occurring when the tubing is empty and external pressure is a maximum. This can be an
actual wellbore occurrence when the tubing is swabbed to the packer depth or below.
Maximum external pressure occurs at the bottom of the tubing string just above the packer
where the pressure is equal to the surface pressure plus the hydrostatic head of the annular
fluid. This is illustrated in Figure 47.
Collapse resistance tables are checked to determine if the tubing wall thickness and grade
selected under the assumed maximum burst load condition is adequate to withstand the
maximum collapse load without failure. The collapse resistance rating is divided by the
appropriate collapse design factor. If the collapse load is less than the collapse resistance
value (with the collapse factor applied), then the tubing is sufficient. If not, a greater wall
thickness is required.
Figure 47. Plot of external (annulus) pressure versus depth witht the tubing assumed to be empty.
The maximum collapse load generally occurs at packer depth.
Example:
The maximum external pressure occurs at the packer depth due to the packer fluid
hydrostatic head with no tubing presure:
0.052 psi/ft/lbm/gal (9.5 ppg) (12,000 ft) = 5928 psi
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The collapse rating of 3-1/2-in OD, 9.3 ppf, N-80 tubing is 10,530 psi. Applying the
collapse design factor of 1.125,
10,530 psi = 9360 psi > 5928 psi
1.125
The tubing is adequate to withstand external pressure.
6.12.10
Collapse Resistance Reduction Under Axial Tension
The collapse resistance of a tubular is reduced under the combined loading of external
pressure and axial tension. This concept is illustrated in Figure 48. In single OD (nontapered), tubing strings these effects are usually negligible since the maximum collapse
load generally occurs at the packer, but near the packer the tubing is in compression or very
little tension. Compression does not reduce collapse strength. However, the reduction in
collapse strength may be considerable in the bottom joints of the upper sections of a tapered
tubing string (just above a crossover) where tension may be large and a collapse pressure
differential may exists. Collapse derating is a more important consideration in casing
design where multitapered strings are frequently required.
Figure 48. Schematic showing changes in tubing dimensions when axial tension is applied.
The combined state of stress resulting from the tensions and pressures result in reducing
the collapse resistance of the tube.
A method for derating collapse resistance values is given in “API Bulletin 5C3: Formulas
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and Calculations for Casing, Tubing, and Line Pipe Properties”. The method is based on
the Huber-von Mises-Hencky energy of distortion yield strength theory. The equation is
used to derate the yield strength of the tubular due to a triaxial state of stress. The reduced
yield strength is then used in the API collapse resistance formulas (given earlier) to
determine the derated collapse resistance. Additionally, tables of derated collapse
resistance for various axial tension loads for each API tubular grade are contained in the
most recent edition of “API Bulletin 5C2: Performance Properties of Casing Tubing and
Drill Pipe”.
6.12.11
Bending
Wellbore dog legs or tubing instability (buckling) cause bending stresses. Bending stress is
evaluated as a fiber stress (a compressive or tensile stress). The maximum tensile fiber
stress and maximum compressive fiber stress is then added to the pipe axial stress at the
corresponding inner and outer diameters. Bending stress is assumed to contribute to
tension stress.
Figure 49 is a schematic of a simple deviated wellbore. An approximate equation for the
bending load due to the rate of deviation angle, in degrees per 100 ft, is
BI ϕ 63 (OD) θ ‘ w
(12.6)
where :
BI
OD
θ‘
w
= maximum bending force in pipe, lb
= outside diameter of pipe, in.
= rate of change of angle, degree per 100 ft
= weight per foot of tubing or casing, ppf
Equation (12.9) is applicable to in-plane bending which takes place in kick-off points or
key-seats. The equation is not applicable to the evaluation of bending stress due to
helically buckled tubing strings (this is considered in the Tubing Stability Analysis subject).
Example:
The example well given earlier is not deviated. However, for illustration assume the well
has a 1.5°/100 ft dog leg at 2500 ft. The bending load would be
BI = 63(3.5 in) (1.5°/100 ft) (9.3 ppf) = 3076 lb
This is taken as an axial load and would be added to the total axial load to see if the joint
tensile load is too high.
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Figure 49. Simple deviated wellbore showing bending load at the kickoff point.
6.12.12
Deviated Wells
Wellbore deviation can appreciably effect wellbore loads. Aside from the bending effect
discussed immediately above, the following should be done in selecting tubulars or
designing tubing strings for a deviated well.
Tension - The measured depth (MD) of tubing should be used in equation (12.3). Also, the
effect of tubing-casing friction due to tubing laying on the low side of the hole or in contact
with casing in a dog leg may cause trouble in attempting to release from a packer and
pulling the tubing. Therefore, an additional tension, overpull, of between 15,000 lb to
25,000 lb may be added to the result of equation (12.3) to approximate friction effects.
Burst - The true vertical depth (TVD) is used to calculate wellbore pressures as hydrostatic
effects depend on gravity.
Collapse - Use TVD for the same reasons as addressed in burst.
In determining the effect of wellbore inclination on burst and collapse loads, the equation
for wellbore static pressure is modified as follows
p = psurf + 0.052 LTVD ρ
where
6.13
LTVD = true vertical depth, ft
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This section presents the equations needed to calculate the length changes, or tubing
movements, due to changes in wellbore temperature and pressure during different well
operations. For instance, during the change from initial landing of the tubing in the packer
to bringing the well on production, the tubing temperature and pressure increase. The
tubing will elongate and the axial loads will change due to pressure changes. In this text,
elongation of a tubular is considered positive (+) and contraction of a tubular is negative (-).
Burst and collapse loads will also change due to pressure changes, but these loads were
already checked on a worst case basis.
All examples in this section are based on the example well data given previously. Example
calculations of each tubing movement will be given. Tubing movements will be based on
the well being stimulated to increase productivity. The tubing is assumed to be free to
move up or down within the packer, axial load changes for anchored tubing will not be
calculated.
6.13.1
Temperature Effects
Consider that the tubing string has initial wellhead and bottomhole temperatures of WHTi
and BHTi, respectively. Then, the tubing fluid is changed or the fluid heats or cools to the
final wellhead and bottomhole temperatures WHTf and BHTf, respectively. The change in
average tubing string temperature from the initial to final conditions is given by:
∆Τ =
WHTf + BHTf
2
−
WHTi
+ BHTi
2
(13.1)
Hooke’s law is then used to derive the change in tubing string length due to the change in
average string temperature, or:
LT = αL ∆Τ
(13.2)
where :
∆LT
α
L
∆Τ
= change in tubing length, ft
= 6.9 X 10-6/°F = coefficient of thermal expansion of tubing steel
= length of tubing string, ft, and
= change in average tubing temperature, °F
Equations (13.1) and (13.2) are only approximate. They are only truly valid if the
temperature gradient is linear. In reality, the temperature of the wellbore fluid varies
nonlinearly with depth. Therefore, equations (13.1) and (13.2) are usually applied over
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small segments (or increments) of tubing and the results of equation (13.2) summed to
provide the total tubing movement.
There are many computer programs available within PCSB which calculate temperature and
pressure gradients. It is important to note that gases (which are compressible) behave very
differently than liquids (incompressible) and care must be taken in generating reliable
temperature data from computer programs.
Example:
The well is to be stimulated by injecting a 9.5 ppg 28% HCl solution at 5 barrels per minute
under 3000 psi wellhead pressure. Using one of the many available thermal simulator
computer programs, it is found that the bottomhole temperature (BHT) after injecting the
acid is 107°F. The decrease in average tubing temperature is
∆Τ =
80 + 107
−
2
80 + 235
= − 64°F
2
The corresponding length change (contraction) is
∆LΤ = (6.9 X 10-6/°F) (12,000 ft) (-64°F) = -5.30 ft
If the tubing is latched at the packer, the tubing axial load is increased (tension) or
decreased (compression) according to the sign of ∆T. This change in load can be derived
from Hooke’s law as:
∆F = -207 As ∆T
where As is the tubing cross-sectional area.
6.13.2
Ballooning
Hooke’s law in the generalized, three-dimensional form implies that when a solid is subject
to tensile forces acting in two perpendicular directions, the contraction in the third
(perpendicular) direction will be proportional to the stresses. This is known as the Poisson
effect and when applied to long pipes is called ballooning or pipe squeeze. Figure 50
illustrates ballooning. Internal and external pressure applied to tubing causes radial and
hoop stresses in the tubing. These radial and hoop stresses are used in Hooke’s law to give
the following equation for change in the length of tubing due to ballooning or pipe squeeze:
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Figure 50. Increasing the internal pressure, pi, within the tubing causes an axial shorting of the
tubing called the ballooning effects.
∆LP =
0.052µL2
E
∆ρi γ2 ∆ρo
γ2 – 1
2µL ∆ρi - γ2 ∆ρo
E
γ2 – 1
(13.4)
where :
∆LP
µ
E
γ
∆ρo , ∆ρi
∆ρo , ∆ρi
= contraction or elongation, ft
= 0.3 = Poisson’s ratio for steel,
= 30 x 106 psi = Young’s modulus for steel
= ratio of tubing OD to ID = OD/ID
= change in annulus and tubing fluid densities,
= change in annular and tubing surface pressures, psi
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Example:
The wellhead pressure (WHP) during stimulation is 3000 psi. There is no surface pressure
applied on the annulus during this operation. First,
γ2 = (3.500 in/2.992 in)2 = 1.368
(0.052 psi/ft/lbm/gal) (0.3) (12,000 ft)2
(30 x 106 psi)
∆LP = −
X
(9.5 ppg – 9.5 ppg) – 1.368 (9.5 ppg – 9.5 ppg)
(1.368 – 1)
−
2(0.3) (12,000 ft)
(30 x 106 psi)
(3000 psi – 0) – 1.368(0-0)
(1.368 – 1)
= − 1.96 ft
The tubing shortens due to ballooning.
If the tubing is latched at the packer, Hooke’s law provides the change in axial load due to
tubing elongation or contraction as:
∆F =
6.13.3
EAS∆LP
(13.5)
L
Piston Length Changes
When pressure changes in the wellbore, a change in length of the tubing string is also
caused by the pressure forces acting on the stinger-seal assembly and at the cross-over in a
tapered string. These changes in length are calculated by using Hooke’s law which relates
the change in force to the change in length:
∆L
=
L∆F
ASE
(13.6)
where :
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= Change in length, ft
= Length of tubing, ft
= Change in force, lb
= Tubing cross-sectional area, in2
= 30 X 106 = Young’s modulus
Piston Force on Stinger-Seal Assembly and Resulting Length Change - The change in
outside and inside tubing diameter at the packer due to the seal assembly that stings into the
packer bore results in a change in area on which internal and external pressure act. Such a
stinger-seal assembly arrangement is shown in Figure 51. It can be shown that the load in
the tubing string due to pressure is given by:
Figure 51. Pressure forces acting on the stinger-seal assembly which results in
piston type length changes.
FPIST = (Ap - Ao)po – (Ap – Ai)pi
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where :
Fp
Ap
Ao
Ai
po
pi
= load on stringer-seal assembly, lb
= area of packer bore, in.2
= area of tubing OD, in.2
= area of tubing ID, in.2
= pos + 0.052ρoL = annular pressure at packer depth, psi
= pis + 0.052ρiL = tubing pressure at packer depth, psi
Note that for flowing fluids, pi will be changed due to friction pressure drop.
A change in pressure occurs during a change in the operational phase of the well, for
instance, from shut-in to production. This change in pressure causes a change in the
pressure force. The change in force is called the piston force and is given by:
FPIST = (Ap - Ao)∆po – (Ap – Ai)∆pi
(13.8)
where :
∆po
=
=
[pos + 0.052ρoL]f − [pos + 0.052ρoL]i
change in annular pressure at the packer, psi
∆pi
=
=
[pis + 0.052ρiL]f − [pis + 0.052ρiL]i
change in annular pressure at the packer, psi
Using equation (13.8) for ∆F, the piston length change at the packer due to the stinger-seal
assembly is:
∆LPIST =
L
AsE (Ap− Ao)∆po − (Ap – Ai) ∆pi
Example:
The packer bore diameter, IDp, is 3.25 in
Then
Ap = (π/4)(3.250 in)2 = 8.296 in2 .
Also,
As = Ao - Ai
=
π (3.500 in) 2− π (2.992 in)2
4
4
= 2.59 in2
The change in hydrostatic pressure inside and outside the tubing is
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∆pi = [3000 psi + (0.052 psi/ft/lbm/gal) (9.5 ppg) (12,000 ft)]
- [0 + (0.052 psi/ft/lbm/gal) (9.5 ppg) (12,000 ft)]
= 3000 psi
∆po = [0 + (0.052 psi/ft/lbm/gal (9.5 ppg) (12,000 ft)]
- [0 + (0.052 psi/ft/lbm/gal) (9.5 ppg) (12,000 ft)]
= 0 psi
So the piston length change at the packer is:
∆LPIST
=
(12,000 ft)
(8.296 in2 − 9.621 in2) (0 psi)
(2.59 in2) (30 X 102 psi)
− (8.296 in2 − 7.031 in2) (3000 psi)
=
− 0.59 ft
Piston Force on a Taper and Resulting length Change - Similar to the pressure force on the
stinger-seal assembly at the packer, there is an exposed area at any crossover of a tapered
string. See Figure 52.
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Figure 52. Pressure forces acting on a crossover in a tapered string
result piston type tubing movements
The force at the crossover caused by fluid pressures acting on the shoulder is:
Fco
=
(Ai1
Ai2)pi
(Ao1
(13.10)
Ao2)po
where :
Ao1, Ai1 = areas computed with outer and inner diameters, respectively, of upper
tubing section, in.2
Ao2, Ai2 = areas computed with outer and inner diameters, respectively, of lower
tubing section, in.2
pi, po = tubing and annular pressures at crossover depth, respectively, psi
If a change in pressure occurs during a change in well operation, then the change in
pressure force at the crossover is:
∆Fco
=
(Ai1
Ai2)
∆pi
(Ao1
Ao2)
∆po
(13.11)
where : ∆pi = [pis + 0.052iLco]f - [pis + 0.052iLco]i
= change in tubing pressure, at crossover depth, psi
∆po = [pos + 0.052oLco]f - [pos + 0.052oLco]i
= change in tubing pressure, at crossover depth, psi
Lco = crossover depth, ft
Using equation (13.11) for F, the length change due to the tapered string crossover is:
∆Lco =
L
AsE (Ai1 − Ai2)∆pi − (Ao1 – Ao2)∆po
(13.12)
Latched Tubing - If the tubing is latched to the packer to restrict tubing movement, equation
(13.8) is used to determine the change in load at the packer. If there is a crossover in the
string, Hooke’s law is used to give the change in load at the crossover. However, when a
crossover is used, the load change due to temperature and ballooning can also become more
complicated than given by equation (13.10). Analysis of tapered tubing strings is best done
using a computer program.
6.13.4
Total Tubing Movement
The total movement of the end of the tubing string determines the required length of the
tubing-to-packer seal assembly. For this reason tubing movement calculations should be
made for all phases of the well since production generally causes elongation and
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stimulation jobs will generally cause tubing contraction. The total tubing movement for a
certain phase of well operation is the sum of the individual tubing movements.
∆LTOT = ∆LT + ∆LP + ∆LPIST + ∆LCO + ∆LB
where: ∆LTOT
∆LT
∆LP
∆LPIST
∆LCO
∆LB
= total tubing movement, ft
= temperature effect, ft
= ballooning effect, ft
= piston movement due to tubing-to-packer seal assembly, ft
= tubing movement caused by crossover shoulder, ft
= buckling tubing movement (see the next subject), ft
Example :
Using the previously calculated tubing movements, the total length change when the well is
stimulated is:
∆LTOT = -5.30 ft - 1.96 ft - 0.59 ft - 0 ft - 0.053 ft
= -7.90 ft
The length change, ∆LB, due to buckling is calculated in the subject “Tubing Stability
Analysis”.
6.13.5
Deviated Wells
The effects of wellbore inclination on tubing movement can be significant. However,
friction caused by contact between the tubing and casing will alter the analysis.
Consideration of friction effects is beyond the scope of the text.
Hooke’s Law - Hooke’s Law relates stress in the tubing cross section to strain in the tubing.
These quantities are not affected by borehole inclination, only the force in the tubing may
be. Hence, Hooke’s law is given by
F = EAS (
∆L )
LMD
(13.14)
Temperature effect - The wellbore temperature gradient depends upon the depth below the
earth’s surface so deviation should be considered when determining the wellbore
temperature profile. However, since Hooke’s law is used to calculate the change in length,
the total measured length of tubing is used. Equation (13.2) becomes
∆LT = α (LMD) (∆T)
(13.15)
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Ballooning - The ballooning or pipe squeeze equation (13.4) is the result of the generalized
Hooke’s law and wellbore pressure. Therefore, it can be shown that both measured depth
and true vertical depth terms are involved in the modified equation.
∆Lp = −
−
0.052µ (LMD) (LTVD)
E
2µ (LMD)
E
∆ρi − γ2∆ρo
γ2 − 1
∆ρi − γ2∆ρo
γ2 − 1
(13.16)
Piston effects - Both the force on the stinger-seal assembly and on the crossover are the
results of pressure loads. Therefore, the pressure loads reflect wellbore deviation:
po = psurf + 0.052 ρo LTVD
and
pi = psurf + 0.052 ρi LTVD
However, when using Hooke’s law to determine the length change due to wellbore
inclination, LMD should be used in equations (13.9) and (13.13).
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6.14
TUBING STABILITY ANALYSIS
6.14.1
General Concepts
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A string of tubing is so long in comparison with its diameter that it lacks the rigidity to
withstand compressive loads. Hence, a very small compressive load will cause the tubing
to buckle as a column. Due to the fact that the tubing is constrained by the inside diameter
of the production casing, the tubing buckles into the shape of a helix. Although the tubing
is said to “buckle”, this does not always mean a failure. Actually, the tubing is in an
unstable equilibrium configuration and the instability can be obviated by increasing tubing
tension or decreasing tubing pressure. Figure 53 illustrates the concept of helically buckled
tubing. Helically buckled tubing can cause problems when logging a well or running other
wireline tools. Instability can become severe enough to cause the pipe steel to yield and the
tubing to become permanently cork-screwed. Therefore, tubing stability must be analyzed
as part of the tubing string design.
There are two ways in which a compressive load can be generated at the end of the tubing
string to cause instability: (1) a physically applied force such as slacking off tubing weight
on the packer and (2) an “effective” compressive force generated by internal and external
pressures acting on the tubing.
This section gives the equations necessary to calculate the stability of a tubing string based
on the analysis presented by A. Lubinski, W.S. Althouse, and J.L. Logan in their paper
“Buckling of Tubing Strings Sealed in Packers”.
Figure 53. Helically buckled tubing. Note that the helix is greatly exaggerated for clarity.
6.14.2
Buckling Load
The load that causes tubing instability is sometimes called the buckling load.
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Physically Applied Force - A tubing string is so long compared to its diameter that virtually
any compressive force acting on its end will cause it to buckle. Thus, any amount of tubing
weight slacked off during landing operations will cause some amount of instability. In
other words, the buckling load is taken to be any compressive load.
Internal Pressure - Internal pressure can cause helical buckling. This effect is caused by
the tubing being initially very slightly bent resulting in slightly different areas on the inside
and outside of the tubing bend. Internal pressure acts on the tubing internal surface area in
such a way that more bending results if the pressure is large enough. In a similar way,
external pressure tends to keep the tubing from bending.
The bending effect of internal and external pressure is equivalent to an effective force
acting on the end of the tubing string. This is illustrated in Figure 54. This effective force
due to tubing pressure causes the string to buckle (or bend) into a helix.
Figure 54. Internal pressure can result in bending moments applied to the tubing which
results in a helical configuration.
When any tubular (tubing, casing, drillpipe, or riser pipe) is immersed in fluid, pressure
acting on the inner and outer surfaces cause forces which affect the straightness or
curvature of the string. This is often referred to as a “buoyancy” effect, but it is actually the
effect of fluid pressure on the equilibrium configuration of the tubular. By carefully
analyzing the equilibrium of forces and moments acting on a submerged tubular string, it
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can be seen that the geometry (i.e., the straightness or curvature) of the string is governed
by the effective tension:
Fe = Fa - (piAi - poAo)
where :
(14.1)
Fe = effective tension, lb
Fa = actual axial load in the tubing, lb
pi, po = hydrostatic internal and external pressure, respectively, psi
Since the effective tension controls the lateral defection of the string when submerged in a
fluid filled wellbore, it can be shown that it governs buckling. That is, the effective tension,
Fe, is the buckling load. It can be seen from equation (14.1) that since Fa, pi and po all vary
with wellbore depth, so does Fe. The effective tension is a maximum at the packer and
decreases with distance from packer to the surface.
In equation (14.1), the effective tension, Fe, is an effect of unequal internal and external
static pressure (i.e. different fluid densities or surface pressures). The actual axial force int
he string, Fa, is the axial load acting acting over cross section of the tubing. That is, Fa is
used to compute the axial stress, σa.
By substituting equation (13.7), the axial force acting on the stinger-seal assembly in the
packer bore,
FPIST = (Ap - Ao)po - (Ap - Ai)pi,
into equation (14.1) for Fa, the following equation results
(Fe)pkr = -Ap (pi - po)
where:
(14.2)
(Fe)pkr = effective buckling force at the packer, lb
pi = [pis + 0.052ρiL] = tubing static pressure at packer depth, psi
po = [pos + 0.052ρoL] = tubing-by-casing annulus static pressure at
packer depth, psi
Ap = π/4 (IDp)2 = area of the packer seal bore, in2
Equation (14.2) gives the maximum effective, or buckling, load in the tubing that occurs at
packer depth. The equation is valid only for a tubing string which is allowed to move up or
down within the packer. Restricted movement of the stinger-seal assembly is addressed
later in the text. If (Fe)pkr is negative (pi > po), the tubing will buckle.
Inspection of equation (14.1 shows that increasing annulus surface pressure or decreasing
tubing pressure will decrease (Fe)pkr and reduce or alleviate instability. It can also be seen
from the above equation that not only does buckling depend on tubing pressure, but
buckling severity also depends on packer seal bore diameter. As such, buckling can be
controlled by the packer bore size.
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Example:
Using the example well stimulation data, the tubing can be checked for stability during
stimulation. The tubing is assumed free to move up or down within the packer.
(Fe)pkr = - (8.296 in2){[3000 psi + .052 psi/ft/lbm/gal (9.5 ppg) (12,000 ft)]
- [0 + .052 psi/ft/lbm/gal (9.5 ppg) (12,000 ft)]}
= - (8.296 in2) (3000 psi) = - 24,888 lb
The tubing has buckled into a helix.
Tubing tension can alleviate buckling. The effect of tubing tension on buckling can be seen
if the effective force is written in the form of equation (14.1). Increasing tubing actual
tension, that is, making Fa (make Fe less compressive), and decrease the severity of
buckling. This is most commonly done by anchoring, or latching, the tubing to the packer
and pulling tension, generally known as landing in tension.
If the tubing is anchored tot he packer and tension is initially pulled, thermal elongation of
the string during production will cause increased compression (Fa < 0) at the packer which
can result in buckling of the string. This is one reason why it is important to consider
tubing movement calculations in the overall design procedure for tubing strings.
6.14.3
Stability Neutral Point
Static pressure and tubing axial load both vary will wellbore depth. Tension increases and
pressure decreases with distance from the packer tot he surface. Due to this fact, the
effective tension diminishes with distance from the packer until a depth is reached at which
the actual axial load, Fa, in the string equals the effect of pressure; that is, when Fa = piAi poAo, Fe = 0. The depth at which this occurs is called the stability neutral point. Above the
neutral point there is no buckling. Below the neutral point the tubing is buckled into a
helix. The equation for the stability neutral point is
ns = −
(Fe)pkr
Wf
(14.3)
where :
ns
(Fe)pkr
wf
=
=
=
ws
ρi, ρo
=
=
= stability neutral point, ft
effective tension at the packer
ws + 0.052(ρiAi - Ao)
buoyed weight-per-foot of tubing, ppf
weight-per-foot of tubing in air, ppf
tubing and annular fluid densities, ppg
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inner and outer diameter areas of tubing cross section, in2
Example:
The buoyed weight-per-foot of the tubing when the 9.5 ppg stimulation fluid is flowing and
the 9.5 ppg packer fluid is used is
= 9.3 ppf + (0.052 psi/ft/lbm/gal) [(9.5 ppg) (7.031 in2)
-(99.5 ppg) (9.621 in2)]
= 8.02 ppf
wf
From the previous example
ns =
24888 lb
8.02 ppf
= 3103 ft
or, bottom 3105 ft of tubing is helically buckled.
6.14.4
Length Changes
The lateral (or radial) movement of the tubing as it buckles into a helix causes a
corresponding shortening of the tubing. The length change depends upon the position of
the buckling neutral point.
Tubing Free to Move Up or Down Within the Packer - The equations for length change are
given as follows, depending upon the neutral point position:
ns < 0 : ∆LB = 0
0
(14.4)
r2 Fe2
8Elwf
< ns < L : ∆LB = −
2
2
ns ƒ L : ∆LB = _ r Fe
8Elwf
where:
Lwf (2 − Lw)f
Fe
Fe
∆LB = length change due to buckling, ft
Fe = effective tension at the packer, lb
r = (IDc - ODt)/2 = radial clearance between casing ID and tubing OD, in
IDc = inside diameter of casing, in
ODt = outside of tubing or coupling, in
E = 30 x 10 psi = modulus of elasticity of steel
l = π x (OD4 - ID4)/64 = moment of inertia of tubing, in4
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wf = buoyed weight per foot of tubing ppf
Equation (14.4) is used if o buckling occurs; (14.5) is used if the neutral point is within the
tubing string; and (14.6) is used if the entire string is buckled.
Example:
For the stimulation example data ns 3103 ft and the string is 12000 ft long, so equation
(14.5) is used. Assuming that 7-in OD, 35 ppf (ID = 6.004) casing is used for the
production casing, the radial clearance between the casing and tubing coupling (for 3.5-in
OD, 9.3 ppf, ODC = 4.500 in) is
r =
6.004 in − 4.500 in
= 0.752 in
2
and
l
π
= 64
(3.5 in)4 − (2.992 in)4
=
3.432 in4
So the tubing contraction due to helical buckling is:
∆LB = −
=
(0.752 in)2 (24888 lb)2
8(30 X 106 psi) (3.432 in4) (8.02 ppf)
− 0.053 ft
As is generally the case, the tubing contraction due to helical buckling is very small. Of
more concern is the curvature of the helix, for it affects the length of a tool which can pass
through the buckled tubing. This is discussed later.
Tubing Restricted From Moving - The above tubing movement equations are only
applicable to tubing which is free to move up or down within the packer seal bore. If the
tubing is anchored to the packer, the tubing actual load, Fa, and effective load, Fe, can
become nonlinearly related. Therefore, the solution for tubing loads and stability is more
complicated. With combination tubing strings (tapered strings or strings with more than
one packer) a numerical iteration technique may be required.
6.14.5
Helical Curvature
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As shown in Figures (53) and (54), the radial constraint of the casing causes the tubing to
buckle into a helical shape. This helix has curvature which varies with depth (due to
hydrostatic pressure and axial loads). An approximate relation for the curvature at any
depth below the neutral point is
Ct =
34,380 r Fe
El
(14.13)
where :
Ct
r
Fe
E
l
= helix curvature, deg. per 1000 ft
= radial clearance between casing and tubing, in
= effective tension, lb
= 30 x 106 psi = modulus of elasticity
= tubing cross-sectional moment of inertia, in
Equation (14.13) should not be confused with the rate of angle change at a kickoff point in
a deviated wellbore. It is entirely different. The helix curvature is related to the rate of
change of the tangent to the helix.
A maximum helical curvature due to tubing string instability (helical buckling) of 5°/100 ft
to 7°/100 ft is suggested if wireline operations are planned. However, the curvatures can be
higher if wireline operations are not planned. The design factor is based on experience.
Operational experience has indicated that if tubing strings are designed with the helical
curvature below 5° - 7°/100 ft, minimal problems in running wireline tools will result.
Example:
for the example production data
Ct =
34380 (0.752 in) (24888 lb)
(30 X 106 psi) (3.432 in4)
= 6.25°/100 ft
During stimulation, the helical curve is great enough to cause some concern if logging tools
are to be run immediately following injection. However, since the buckling is due mostly
to the high pumping pressure, the curvature should decrease somewhat when pumping
ceases.
6.14.6
Deviated Wells
At present there is no generally accepted method of analysis of tubing or casing stability for
inclined boreholes. Although there are analytical methods available in the literature, these
have been rarely applied and are still under study.
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MATERIAL AND TUBULAR SELECTION
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OPERATIONAL CONSIDERATIONS
When operational requirements are considered, the advantages and disadvantages of a
particular tubing design will depend almost entirely on the producing characteristics of the
reservoir and the method of production that will be employed. For this reason, it is
impractical to establish rules governing tubing designs that would be applicable to all types
of operation. However, certain major considerations have sufficient impact on tubing and
casing programs to warrant a brief discussion of general guidelines. The guidelines
discussed below exemplify that the tubing string should be designed before a production
casing size is selected. Common to all of the operational considerations given below is the
fact that the annular space between the tubing and casing can be an important design
parameter.
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Radial Clearance
To avoid sticking a tubing string inside casing, a minimum radial clearance between the
tubing connection OD and casing ID of 5/8 in. is required. The dimensions of other means
of production.
6.15.2
Rod Pumping
Much larger pipe sizes will be required for a given production rate with rod pumping than
for any other means of production. When maximum producing rates using rod pumps are
required, provision for maximum tubing and casing sizes should be made. Generally
speaking, this would be 4½-inch tubing inside 7-inch casing and 2-7/8-inchtubing inside 5½inch casing. Deep lift of large volumes with a rod pump is generally impractical because of
excessive rod stretch and rod strength limitations although new developments in fiberglass
rods may change this. Rod sizes limitations will also seriously hamper pumping from great
depth (over 5000 feet) through small tubing.
6.15.3
Hydraulic Pumping
Hydraulic pumping installations will generally require larger casing sizes for a given
production rate than gas-lift or flowing wells because they usually need a parallel string for
power oil supply. However, this is not always the case, since in some instances the casingtubing annulus is used for production and the tubing serves as the power oil supply. These
casing-type installations are necessarily limited in application to low GOR reservoirs or
reservoirs in which the bottomhole pressure is above the bubble-point pressure because all
produced gas must pass through the pump.
6.15.4
Submersible Pumps
Submersible pumps can be run on 2-3/8-inch OD or 2-7/8-inch tubing and are particularly
applicable in deviated or very deep holes where rod pumping would be undersirable.
6.15.5
Sand Control
Modern advances in sand-control equipment and techniques have eliminated the
requirement for large pipe sizes in which to install sand control equipment. Successful
gravel packs are routinely made inside 51/2-inch casing, although these are more difficult to
place than in larger size casing. If the sand production rate is not great enough to damage
surface equipment, then smaller pipe size give the advantage of greater sand-carrying
capacity at lower producing rates which may eliminate or reduce the need for sand control
measures.
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Washover Operations
The ability to wash over a tubing string is also an important consideration, but it should not
be a limiting factor in casing design. Washover requirements will be based almost entirely
on local considerations such as sand production, available wash pipe, risk involved, and
local policy.
6.16
REFERENCES
1.
Material Requirement : Sulfide Stress Cracking Resistant Metallic Material for
Oil Field Equipment, NACE Standard MR-01-75, National Association of
Corrosion Engineers, 1980 Revision.
2.
Kane, R. D. (January 1983): High-Alloy Tubulars Hold Promise for Sour
Service Tolerance, Petroleum Engineer International, vol. 55, no. 1, p. 98-112.
3.
Prengaman, R. D. (October 1981): Thread Compounds – How Do They Work,
Petroleum Engineer International, vol. 53, no. 12, p. 93-106.
4.
Noerager, J. A., and Greer, J. B. (1977): An Investigation of Coupled Tubing
Joints for Sour Service, Materials Performance, vol. 16, no. 2, p. 37-45.
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5.
Weiner, P. D., and Sewell, F. D., Jr. (March 1967): New Technology for
Improved Tubular Connection Performance, Journal of Petroleum Technology,
vol. 19, no. 3, p. 337-342.
6.
Salama, M. M and Ven Katesh, E. S. (1983): Evaluation of API RP 14E
Erosional Velocity Limitation for Offshore Gas Wells, Presented at 1983
Offshore Technology Conference and Exhibition, Houston, TX.
7.
Lubinski, A., Althouse, W. S., and Logan, J. E. (June 1964): Helical Buckling
of Tubing Sealed in Packers, Journal of Petroleum Technology, vol. 16, no. 6,
p. 655-670.
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CHAPTER 7
PACKERS
TABLE OF CONTENTS
7.1
INTRODUCTION ……………………………………………………………...…... 3
7.1.1
7.1.2
7.2
Construction ………………………………………………………… 15
Applications ………………………………………………………… 15
Objections …………………………………………………………… 15
HOOK-WALL RETRIEVABLE PACKERS ………………………………...…. 17
7.4.1
7.4.2
7.4.3
7.5
Basic Components ………………………………………………….. 5
Sealing Elements ……………………………………………………. 9
Seal Extrusion Prevention …………………………………………... 10
Slips …………………………………………………………………. 11
Setting And Releasing Elements ……………………………………. 11
Friction Devices …………………………………………………….. 12
Hydraulic Hold-Downs ……………………………………………... 13
PERMANENT PACKERS ……………………………………………………….. 15
7.3.1
7.3.2
7.3.3
7.4
3
3
PACKER FUNDAMENTALS ………………………………………………….….. 5
7.2.1
7.2.2
7.2.3
7.2.4
7.2.5
7.2.6
7.2.7
7.3
Packer Definition …………………………………………………….
Types Of Packers ……………………………………………………
Compression Packers ……………………………………………….. 17
Tension Packers …………………………………………………….. 18
Tension-Compression Packers ……………………………………… 19
SPECIAL PACKERS ……………………………………………………………... 20
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7.5.2
7.5.3
7.5.4
7.5.5
7.5.6
7.5.7
7.6
7.1
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Polished Bore Receptacles ………………………………………….. 20
Cup Packers …………………………………………………………. 22
Inflatable Packers …………………………………………………… 22
Permanent-Retrievable Packers ……………………………………... 24
Thermal Packers …………………………………………………….. 25
Dual Packers ………………………………………………………… 27
28
Liner Hangers ..................................................................................
PACKER SELECTION ………………………………………………………..…. 34
7.6.1
7.6.2
7.6.3
7.7
PACKERS
Factors To Be Considered in Choosing A Packer ............................. 34
Setting Packers ……………………………………………………… 35
Retrieving Packers …………………………………………………... 35
SUMMARY ……………………………………………………………………..…. 37
INTRODUCTION
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7.1.1
PACKERS
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Packer Definition
A production packer can be defined as a subsurface tool used to provide a seal between the
tubing and casing to prevent vertical movement of fluids past the sealing point. Packers
serve a vital role in well completions and have a marked effect on subsequent operations
performed in a well. As its major functions, a packer should :
7.1.2
•
Protect casing from bursting under conditions of high production or injection pressures
•
Protect casing from corrosive fluids
•
Provide better well control
•
Prevent fluid movement between productive zones
Types Of Packers
Production packers are generally classified as either retrievable or permanent. By
definition, a retrievable packer is one that can be removed from a well by tubing
manipulation or some other means not involving destruction of the packer. A permanent
packer, on the other hand, must be destroyed for removal. For this reason, permanent
packers are often referred to as drillable packers. A classification outline of production
packers is shown in Table 1.
Table 1
Classification Outline of Production Packers
I.
Permanent
II.
Hook Wall Retrievable
a. Compression
b.
III.
1.
Mechanically set
2.
Hydraulically set
Tension-mechanically set
c. Tension and compression
Special Retrievable
a. Cup
b. Inflatable
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c.
Permanent-retrievable
The primary function of any packer is to provide a seal - the crucial prerequisite to be met
in selecting any packer. All other considerations are of secondary importance, and quite
rightly so. The functions expected of the packer, the environmental conditions under which
it will be used, and its mechanical design must be known before selection is made for a
particular application.
7.2
PACKER FUNDAMENTALS
7.2.1
Basic Components
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As illustrated in Figure 1, there are certain basic components of construction that are
common to practically all makes of production packers. A permanent packer is shown in
Figure 2, and in Figure 3, a retrievable compression packer. They all have the following
components in common :
•
seal assembly - usually of rubber, some with metal back-up rings
•
slips to engage the casing wall and hold the packer against applied forces
•
cone assembly to force the slips out to engage the casing
•
friction element to allow motion of the inner mandrel relative to the packer body (not
on hydraulic or permanent packers)
•
setting and releasing mechanism
•
mandrel assembly to hold parts together
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Figure 1. Typical Production Packer
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Figure 2. Permanent Packer
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Figure 3. Mechanically Set Compression Packer
In addition, some offer the option of a hydraulic hold-town assembly (Figure 4) to facilitate
high-pressure work below the packer. In the following paragraphs, some of these basic
components are discussed in greater detail.
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Figure 4. Hydraulically Set Compression Packer (with hydraulic hold-down)
7.2.2
Sealing Elements
Sealing elements are normally constructed of nitrile-rubber, except in such special
applications as thermal-injection or sour-service operations. Nitrile-rubber seals have
proved superior for use in moderate temperatures under normal service conditions.
The compound characteristics required for a particular job can be achieved through control
of the constituents in the compound and the degree of vulcanization. When a packer is set,
the sealing elements is compressed to form a seal against the casing. During compression
the rubber element will normally extrude between the packer body and the casing wall.
This extrusion, along with the inability of the sealing element to return to its original shape
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when the compression forces are removed, can cause the packer to become stuck.
7.2.3
Seal Extrusion Prevention
Many techniques are used to lessen the unwanted extrusion. In some packers, back-up rings
are used to reduce the unsupported cross section of the rubber seal. In others, multiple
sealing elements of varying hardness are used to reduce the deformation of the rubber itself.
For example, in a three-element packer (Figure 5), the upper and lower elements are usually
harder than the middle one.
Figure 5. Three Element Packer
All three are compressed when the packer is set. The lower hardness center elements seals
off against imperfections in the casing wall. The higher hardness end elements, on the
other hand, aid in restricting extrusion and effecting a seal when high temperature and
pressure differentials are encountered. This degree of hardness is related to the seal
element’s ability to withstand deformation, and thus bears a general relationship to its
ability to hold pressure without failing.
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Slips
Slips can be of any of a variety of shapes, provided that they are sharp and have an adequate
surface for holding the packer in position under the anticipated pressure differentials and
tension/compression due to tubing movement.
Theoretically a packer can be seated and unseated a number of times without requiring the
replacement of slip elements. The cost, however, of slip replacement in comparison with
rig cost very insignificant. Complete service and repair of a packer should therefore be
performed whenever the packer is removed from the wellbore.
7.2.5
Setting And Releasing Elements
The setting mechanism on retrievable packers generally consists of a J-latch, a shear pin, or
some other clutch arrangement to allow the packer to be engaged. The various mechanisms
employed are actuated by a number of different methods, including upward or downward
movement, placing weight on the packer, pulling tension in the tubing, or rotating to the
right or left. Hydraulically actuated retrievable packers are set with pressure inside the
tubing using pump-out plugs, wireline plugs, or flow-out balls. The releasing mechanisms
on a retrievable packer involve another wide range of actuation methods - straight pickup,
rotating to the right or left, slacking off and then picking up, or picking up to shear pins. To
select a particular type of setting or releasing mechanism, it is necessary to know the
conditions existing in the particular wellbore when the packer is set and the operations
anticipated during its stay in the hole.
The simplest setting and releasing mechanism is the J-slot and pin arrangement (Figure 6),
which requires, for setting, only a slight rotation of the tubing at the packer, and can usually
be released by simply pulling on the packer. This rotational requirement is often difficult to
achieve in highly holes. A typical choice for deviated wellbores is therefore a hydraulically
set packer with straight pickup release mechanisms. As discussed in the Tubular Goods
Chapter, tubing effects - or the changes in tubing length with pressure and temperature
changes - must always be evaluated in order to make the proper selection for a setting or
releasing mechanism.
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Figure 6. Right-hand (a) and left hand (b) J-slot Mechanism
8.2.6
Friction Devices
Friction elements are an essential part of mechanically set packers, as seen on the packer in
Figure 7. Ordinarily, friction devices are either bow springs or friction blocks. If properly
designed, either one will provide the holding force needed to allow independent rotation of
the inner mandrel. Friction blocks are quite popular today, but packers with bow springs
are also prominent on the market. The preference for friction blocks is not strong enough to
bring about a redesign of the old packers in order to accommodate them.
8.2.7
Hydraulic Hold-Downs
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Hydraulic anchors, or hold-downs, provide a reasonably reliable method of preventing
upward movement of a packer when differential pressures are applied across the sealing
elements. A single-slip, weight-set packer, for example, may move up the hole when high
pressure is applied, unless the packer is equipped with some type of hydraulic hold-down.
This device extends to engage the casing wall and to firmly anchor the packer against
upward movement, as seen in Figure 7.
The hydraulic hold-down is a useful device, but it does have certain limitations and
disadvantages. For example, if the pressure differential across it reverses direction, as often
occurs during normal oilfield operations, the anchor will eventually fail because of repeated
releasing and resetting of the slip teeth into the casing. This situation can lead to anchor
failure, in which the packer may move up the hole; or it may cause the slips to wear a hole
in the casing. Furthermore, trash (e.g., sand or corrosion material) can collect behind the
anchor pistons, often preventing the retraction of the slips, thus perhaps requiring an
extensive fishing operation to remove the packer from the wellbore.
Modern lock-set-type packers with dual opposing slips, which hold in both an upward and
downward direction, have almost totally replaced hydraulic hold-downs. These new packer
designs are much more reliable in retrieving and, furthermore, do not allow slip movement
during normal production operations.
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Figure 7. Packer Components (Courtesy of Baker Packers)
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7.3
PERMANENT PACKERS
7.3.1
Construction
Permanent packers consist of opposed slips with a rubber sealing element located between
them. Figure 2 shows a simplified schematic of one type, a Baker Model D. This type
packer has a sealing element that is compressed between cones which are locked into
position by opposing slips to prevent packer movement in either direction. Expanding
metal rings help contain the sealing element and prevent extrusion of the rubber. A flapper
valve prevents flow from below the packer while the tubing and stinger are removed.
Permanent packers can be run on tubing, but most are set by wireline. If run on tubing,
setting is accomplished by seating a ball or plug and applying pressure. If run on wireline,
setting is accomplished by firing a small explosive charge to create the necessary pressure.
Wireline setting is a valuable asset when precise packer location is required. The opposedslip principle of this packer makes it highly useful in containing high-pressure differentials
or when large temperature variations are involved, such as during hydraulic fracturing
operations.
The seal between packer and tubing is accomplished by a packing on the tubing that seals
against the polished internal bore of the packer. These seals can be allowed to move within
the packer or a threaded connection can be included in the top of the packer to prevent
tubing movement.
7.3.2
Applications
The permanent packer finds application where high pressure differentials and/or large
tubing/load variations require a maximum reliability with a long sealing life. A permanent
packer can be used under these conditions where the expected loading would not cause
tubing yielding. However, in deep wells, especially when injection is planned, floating
seals must be used. These floating seals should be long enough to accommodate the
maximum tubing movement anticipated at the packer. Figure 8 shows a floating seal
assembly being used in conjunction with a permanent packer.
7.3.3
Objections
The primary objection to the permanent packer is the necessity of drilling or milling up the
packer for removal. A permanent packer can generally be removed in two or three hours if
the special “packer picker” fishing tool is used to retrieve it. This special retrieving tool
consists of a collect that extends through the packer mandrel and a mill that removes the top
slips.
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Once the top slips have been milled away, picking up on the tubing will engage the collect
in the bottom of the packer and retrieval can normally be achieved. Drilling up permanent
packers with a rock bit is not normally recommended, since field experience with this
technique has been poor.
Figure 8. Packer and Sliding Seal Assembly with Close-up of Tubing Seal Unit
(Courtesy of Baker Packers)
7.4
HOOK-WALL RETRIEVABLE PACKERS
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Many types and variations of retrievable packers are available, primarily because of the
latitude possible in the design of their activation and releasing mechanisms. Similarly,
there are many means of classifying retrievable packers. One of the simplest (and the one
used in this discussion) is to categorize them according to the manner in which force is
applied to activate the sealing element - namely, as compression packers, tension packers,
or combination tension and compression packers. Packers can further be classified by their
setting mechanism, whether mechanically or hydraulic.
7.4.1
Compression Packers
The compression or weight-set packer is one of the oldest and simplest packers available. It
is economical and is ideally suited to low-pressure situations, such as gas lift installations,
or circumstances in which pressure in the casing-tubing annulus at the packer always
exceeds the tubing pressure there. Compression packers are less satisfactory when squeeze
cementing or stimulation work is required, because they are not designed to hold pressure
differential from below, unless a hydraulic hold-down device is used or extra tubing weight
is set on the packer. As previously discussed, however, hydraulic hold-downs are not
completely reliable and generally have been replaced by the dual opposing slip-type
compression packers.
In a mechanically set compression packer (Figure 3) the packer sealing element is
compressed between the mandrel cone after the slips lock into the casing. After the desired
setting depth is reached, the slips are generally activated by rotational manipulation of the
tubing. As indicated before, pressure from above to seal the packer tighter whereas
pressure from below can cause it to lose its seal. To retrieve this type packer, tension is
pulled in the tubing to release the sealing element and retract the slips.
A hydraulically set compression packer is used when tubing manipulation is undesirable.
In this type packer (shown in Figure 4) the sealing element is compressed between the cone
and piston when tubing pressure is applied. Pressure applied in the setting chamber forces
the piston downward and slips outward, while the hydraulic slips hold the mandrel in place
and small slips lock the packer in a set position. Notice that no tubing manipulation is
required to set this packer, in contrast to the mechanically set packer. Hydraulically set
compression packers are retrieved either by straight pickup or by rotation and pickup.
7.4.2
Tension Packers
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These packers are essentially weight-set packers that are run upside down and are set by
pulling tension on the tubing. After a tension packer is set, differential pressure from the
bottom or formation side increases the setting force and holds it in place automatically.
Figure 9 shows a simplified schematic of a Baker Model A packer. As in the compression
packer, the sealing element is compressed between the mandrel and the cone after the slips
have hooked into the casing. The exception is that in this case the compressive force is
applied by pulling tension in the tubing. Pressure from below will cause the packer to seal
tighter, whereas pressure from above can cause it to lose its seal.
Tension packers are suitable for injection or stimulation, but are seldom used. The reason
is that for most wells, the weight of the packer fluid is such that the pressure differential
across the packer is downward. Tension packers are also unsuitable for use in deep wells
where high tubing strains are expected.
Figure 9. Mechanically Set Tension Packer
7.4.3
Tension-Compression Packers
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A more sophisticated packer now on the market utilizes a slip-and cone arrangement that
prevents packer movement in either direction, thus eliminating the need for hydraulic holddowns. These packers are designed to compete with permanent packers and can be used
when the tubing is in tension, compression, or neutral, or when pressure differentials from
either direction exist. Retrievable tension-compression packers are run in the hole on the
tubing string.
The mechanically set tension-compression packer, the Baker Lock Set, is shown in Figure
10. In this design, the packer sealing element is compressed between the mandrel and the
cone by a segmented nut moving upward and locking the left-hand directional threads.
Opposing slips lock the packer against movement from either tubing tension or
compression, and maintain the packer seal against pressure differential from either
direction. Setting and releasing the packer is accomplished by rotation.
Generally a packer of this type will also have secondary emergency release mechanism
which requires only straight pickup to release.
Figure 10. Mechanically Set Tension Compression Packer
7.5
SPECIAL PACKERS
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There are also designs available for packers other than the more common ones discussed
above. Six such packers are discussed in the following paragraphs.
Figure 11. PBR and Seal Assembly (Courtesy of Baker Packers)
7.5.1
Polished Bore Receptacles
A polished bore receptacle (PBR) is another type of packer system that can be used in place
of a permanent packer. The PBR accepts an inner seal assembly that seals off between the
tubing and the PBR (Figure 11). The PBR is commonly used in a liner completion, where it
is installed as an integral part of the liner hanger. When the completion string is run, the
seal assembly, similar to that used on a permanent packer, or left floating to allow tubing
movement (Figure 12).
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Figure 12. PBR Installed in Liner Completion
(Courtesy of Baker Packers)
Normally, the PBR diameter is larger than the diameter of the liner below it.
workover tools and procedures can be run through the PBR with ease.
Most
In a PBR completion, the sealing characteristics and capabilities between the tubing and
PBR are the same as between the tubing and packer body of a permanent packer
completion.
The PBR has a disadvantage that the permanent packer does not. The position of the PBR
is fixed in the hole, generally in the liner hanger, which may be several thousand feet above
the zone of interest. As stated previously, one of the functions of the packer system is to
protect the casing string from the corrosiveness of wellbore fluids by sealing off the tubing
annulus.
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Since the PBR is set at the top of the liner, the entire length of the liner is exposed to
potentially corrosive fluids when the well is produced. For example, in a well with a 500 ft
liner and a producing interval 50 ft in length, the entire liner is exposed to the effect of the
production fluids, as opposed to a typical installation in which the packer would be located
just above the pay.
When the PBR completion method is selected, instructions for installing it must be included
in the drilling program, since it will be an integral part of the liner top and therefore part of
the casing program.
7.5.2
Cup Packers
This is a special-type packer that has no slips. In this case, a seal is effected by reinforcing
metal springs in the cups and by increases in pressure from the concave side of the cup.
Figure 13 illustrates a Guiberson-type GW cup packer. In this arrangement, the steelreinforced rubber cups attain a seal against the casing. Each cup holds pressure from only
one direction; increasing the pressure differential tends to increase the seal between the cup
and the casing. The rubber cups contact the casing during running and pulling and need no
manipulation for setting.
The cup packer finds application in moderate-depth wells where moderate pressure
differentials are expected and where pressure can be balanced and the tubing anchored
against movement. Its main advantage is that it is inexpensive and simple to use.
7.5.3
Inflatable Packers
This special retrievable production packer is manufactured by Lynes, Inc., or Tam
International, Inc. This packer may have slips, and the seal is effected by the injection of
fluid into an inflatable, balloon-type rubber sealing element. A schematic of this packer is
shown in Fig. 14. In operation, an expandable steel-reinforced sealing element is forced
against the casing or open hole by pressure applied to the tubing. A check valve prevents
backflow, thus keeping the packer inflated. To unseat the packer, a passage is opened by
tubing manipulation and the packer element is allowed to deflate.
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Figure 13. Guiberson-Type GW Cup Packer
Figure 14. Inflatable Packer
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The main application for the inflatable packer is in open-hole settings, especially when
irregular hole conditions have been encountered. Because of its balloon like nature, it can
be set in a large hole below restricted sections of casing.
In application, the packers are used for water and gas shut-off, selective stimulation, and
testing. In a very special application, specially treated elements are incorporated into the
packer’s exterior for taking impressions of fractures, open hole irregularities, or casing
failures.
7.5.4
Permanent Retrievable Packers
Permanent-retrievable packers combine all the production features of permanent packers in
one that is retrievable. They are designed to be run and set on electric wireline or on
tubing, with either hydraulic or rotation setting. Additionally, these packers are designed to
be retrieved by various means with a straight pull. As with the permanent-type is especially
useful in lieu of a permanent drillable type packer in those such as lost circulation.
A permanent-retrievable packer is especially useful for hydraulic fracturing treatments that
involve multiple stages utilizing packer movements and bridge plugs. One can often
successfully move the packer four or five times to distribute (divert) treatment stages
without removing it from the wellbore for service.
A wireline set permanent-retrievable packer, the Halliburton Perma-Trieve, is shown in Fig.
15. The wireline setting tool is attached at point C with the outer sleeves of the setting tool
over top portions of the packer mandrel. Movement of packer parts are as follows: setting
the tool shears screws at point A moving slip carrier (1) down-ward so upper slips contact
casing wall. Assembly (2) remains stationary as assemblies (3) and (4) are moved upward
to compress the sealing elements and set the lower slips. Shear screws C are sheared and
the setting tool is removed from the packer and the wellbore. This packer has mechanisms,
which allow for release with a straight upward pull.
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Figure 15. Wireline Set Permanent-Retrievable Packer
(Courtesy of Halliburton)
7.5.5
Thermal Packers
Special thermal packers must be used for high-temperature applications such as steam
injection. The use of thermal packers will reduce the wellbore heat losses and deliver more
heat to the interval of interest. Reduction of wellbore heat losses will also limit the
temperature-induced compressive stresses in the casing string. Thermal packers have
sealing elements made from materials designed to withstand very high temperatures. These
packers often have integral expansion joints to accommodate thermal expansion and
contraction of the tubing. These packers are available in both permanent and retrievable
models. Figure 16 shows a permanent thermal packer with expansion joint for use in steam
injection operations.
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Figure 16. Permanent Thermal Packer with Expansion Joint
7.5.6
Dual Packers
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A conventional dual completion is shown in Fig. 17. This type of completion requires a
special dual packer. The packer is made up and run in on the long string with the lower
retrievable packer or seal assembly attached to the tailpipe. Upon reaching setting depth,
the lower packer is set or the seal assembly is stung into the seal bore of the packer. The
short string is then run and landed into the dual packer, which is then set.
Figure 17. Conventional Dual Completion
7.5.7
Liner Hangers
A liner hanger is a device usually used to position and suspend, with or without packoff, a
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string of tubing or casing commonly known as a “liner”. The “liner” is placed within an
existing larger string of casing in an oil, gas or water well. The various types of liner
hangers can be used to accomplish a wide variety of production operations. Typical
applications may include :
•
To shut off water and protect producing zones against water encroachment.
•
To protect casing and seal off casing leaks for scabbing operations.
•
To separate producing zones.
•
To inject gas or water into secondary recovery programs.
•
To reinforce casing in repressuring, recycling, pressure maintenance and underground
storage in single or multiple-zone completions.
•
To eliminate the need for setting the full casing string when a well is deepened through
the bottom of the original completion string.
•
To eliminate the need for setting a full string when a well is redrilled through a window
of the present string.
Plain type liner hangers (Figure 18) are used to suspend a liner but do not provide a means
of sealing the annulus between the liner and the casing in which it is suspended. Single or
dual cone hangers are available to suit liner weight needs.
Delayed action liners (Figure 19) with sealing units are designed so that the seals expand
after the slips on the hanger are set and cementing is complete. This gives the operator the
opportunity to perform such operations as cementing and casing repair. Also, delayed
action packers allow operators to perform other completion jobs that require circulating in
the casing/liner annulus before packing off and sealing the annulus. An example of this is a
completion job that uses a liner hanger as a production packer.
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Figure 18.
Figure 19.
Mechanical-set liner hangers will usually perform well in straight, shallow wells where pipe
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rotation is easily achieved. However, a hydraulic-set hanger (Figure 20) is more ideal for
down-hole conditions where rotating pipe is difficult. Such conditions include crooked
holes and deep directional wells from offshore platforms or floating vessels. Manufacturers
make the hydraulic-set hanger to adapt to H2S, CO2, and high temperature conditions.
Figure 20.
Hydraulic hangers are set by dropping a setting ball that seats on a latch collar (Figure 21A). The hanger is set by applying pump pressure that will vary from 1,500 psi to 2,000 psi.
Once the hanger is set, internal pressure shears pins to eject the setting ball and the seat
onto a ball catcher (Figure 21-B) located one joint below. Circulation can be established
after the setting ball and the seat are ejected. After circulation and cementing are
completed, the setting tool and work string are lifted to the surface. Figure 3.34 illustrates a
liner hanger installed and cemented in place.
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Figure 21.
Typical uses of liner hangers are to :
•
suspend a liner from the well casing to protect against liner spiralling or shifting of its
own weight
•
minimize the possibility that the liner could sink in soft formation at the bottom of the
well
•
protect the liner from falling into a cavity and becoming misaligned with the hole
above.
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Figure 22 also shows the possibility of using a tapered string installation to reduce the size
of the production string and to reduce tubing cost. Liner hangers also have the versatility of
being used as production packers in extreme conditions such as H2S, CO2, high
temperatures, or where tubing string movement may be anticipated.
Figure 23 illustrates a liner hanger used in a production packer.
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receptacle may be used where tubing elongation and an environment of H2S are
encountered. The nipples above the hanger are used to set subsurface flow control above
the hanger. The added length of the sealing bore from the polished bore receptacle will
contain the seal units. The sealing bore exposes only the lower seal to corrosive well
production. The production packer and tail pipe extension with nipple allow the well to be
plugged and the tubing pulled.
Figure 24 illustrates a liner hanger used as a production packer. The tail pipe and packer
used as a production packer. The tail pipe and packer bore extension are equipped with
landing of bottom hole pressure equipment. The polished bore receptacle is below the liner
hanger and allows the seals to keep H2S environment off of the liner hanger. In Figure 3.35
and 3.36, normal production is through the tubing. This allows movement of the tubing
within the polished bore receptacle as the tubing is affected by high temperatures.
7.6
PACKER SELECTION
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7.6.1
PACKERS
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Factors To Be Considered In Choosing A Packer
Well pressure must be considered since a packer must be selected with the proper pressure
capabilities for that well. It is necessary to know if pressure differentials will be from the
top or the bottom of the packer and if the differential will change from one side to the other
during the life of the well. Some packers will withstand only a limited pressure from one
side.
Pressure change is also one of the factors involved in tubing movement, elongation, or
contraction. Temperature is a consideration since some packers can perform at higher
temperatures than others. Retrievable packers normally should be limited to temperatures
of 275°F maximum. Sealing compounds used on sealing units for permanent packers or on
packer bore receptacles should be selected for best performance in a given temperature
range.
Longevity of a producing zone is a prime consideration in the selection of packers. If a
zone is expected to produce for many years without remedial work, it may be desirable to
use a permanent type packer or hydraulic-set retrievable packer. However, if it is
anticipated that remedial work to the well will be necessary within a short period of time, it
may be more desirable to use mechanical set packers.
Corrosive agents in the well fluids must be considered. Usually retrievable packers perform
poorly in wells with high H2S concentration. Many times, alloy used in the manufacture of
a packer must be selected to withstand the corrosive agents that they may encounter.
If the well is to be treated with acid or fracturing materials or pumped into at high rates and
pressures for any reasons, the proper packer must be selected. Packer failures most often
occur in treating operations. Tubing contraction may be retrievable packers to release or
can cause the seal element to move out of the seal bore in a permanent packer or packer
bore receptacle.
Often packers are selected to be compatible with other downhole equipment. For example,
when hanger systems are used with surface controlled subsurface safety systems, it is
desirable to use hydraulic-set packers. Hydraulic-set packers allow the operator to install
and set the complete safety system and the tree before setting the packers. Well fluids may
then be displaced with lighter fluids while the well is under complete control. The packers
can be set after displacement of the fluids is complete.
If wireline equipment is to be serviced in the tubing or through tubing perforation is to be
accomplished, it is desirable to use packers that do not require tubing weight to keep them
set. Wireline operations can be more successfully completed if tubing is kept straight by
landing it in tension or neutral. This is increasingly important in deeper wells. In many
instances, packers are selected for use with gas lift valves to keep pressure off the
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producing formation and prevent gas from passing around the end of the tubing. If a packer
is to be used with a rod pumping unit, it usually is desirable that the tubing be placed in
tension. A tension-set retrievable packer must be selected to allow this.
Economics may become a factor in packer selection. In some instances, the operator must
complete the well as inexpensively as possible and will select a packer because of its low
cost.
Sometimes producing intervals are close together, making it necessary to place the packer
accurately in the hole. If a packer is set by electric conductor line, it is possible to place the
packer in the casing with a high degree of accuracy.
7.6.2
Setting Packers
Setting a packer is often considered an extremely simple job, one requiring little expertise.
The number of packer failures in the industry, however, is testimony that packer installation
instructions, it usually requires a person experienced with the particular equipment to
ensure a good job. Therefore, if the company representative on a job is not completely
familiar with the packer being run, it is advisable to have a manufacturer’s operator present
when the packer is set and tested.
Before running a packer, it may be wise to run either a gauge ring and junk basket on
wireline, or a rock bit and casing scraper on tubing. This precaution is particularly
important if earlier operations-such as fishing, milling, or packer removal-might reasonably
be expected to have left steel cuttings, packer rubber, or miscellaneous debris in the
wellbore. Normally it is not prudent to set a packer at the same point in the casing that
milling operations have taken place.
7.6.3
Retrieving Packers
Releasing a packer with a rotational release mechanism should normally be easy. In some
cases, however, the condition of the well may be such that torque cannot be transmitted to
the packer as easily as tension is (for example, a deviated well). In these cases, a straight
pickup release-type packer should be run. If a torque-release packer fails to release when
torque is applied with the tubing in the slips, then torque should be applied while the tubing
is worked up and down.
This action allows torque to be worked down the hole to the packer. By applying rotation
on the order of 1/2 turn/200 ft of tubing and jarring downward, a rotational release
mechanism may be operated if it has previously failed to function.
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This procedure is just one of several possible in pulling a packer that is reluctant to release.
The same technique can be used with latching mechanisms on permanent packers. When
pulling a packer with a hydraulic hold-down, it may be advisable to place pressure on the
casing annulus to pump in the buttons before getting rough with the packer. After releasing
and before pulling on a packer, it is good practice to allow several minutes to elapse so that
the seals may retract, thereby preventing them from tearing off.
The use of safety joints to minimize fishing time is sometimes justified. Safety joints
normally release with right-hand rotation of the tubing. They are usually installed
immediately above (or one joint above) the packer in single-string wells and between
packers in multiple-string wells. Safety joints merit consideration particularly in dual
completions and/or below a crossover gravel-pack packer.
7.7
SUMMARY
Overall packer cost, in the final analysis, is directly related to retrievability and failure rate.
Packer mechanics and the method by which the seal with the casing is maintained are major
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factors. Retrievability will be greatly enhanced when oil or saltwater, rather than mud, is
used for the packer fluid. Frequency of packer failures can be minimized by selecting the
proper packer for each set of well conditions. The permanent packer is by far the most
reliable. Compression and tension models of retrievable packers will perform satisfactorily
when the pressure is from one direction only and is not excessive. Fishing characteristics
must also be considered in packer selection. Although it is necessary to drill out a
permanent packer to remove it, the procedure is uncomplicated because all packer material
is drillable. Conversely, removal of stuck retrievable packers, which have hardened steel
components, usually results in extensive fishing operations.
In summary, the selection of packers is a complicated process which must be carefully
planned for optimum effectiveness and efficiency. Further, the selection must be made by
someone completely familiar not only with the packer mechanics, but also with the overall
completion and workover techniques used, including any future anticipated workovers.
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SURFACE AND SUBSURFACE SAFETY VALVES
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CHAPTER 8
SURFACE AND SUBSURFACE SAFETY VALVES
TABLE OF CONTENTS
8.1
INTRODUCTION ………………………………………………………………………….. 3
8.1.1
8.1.2
8.1.3
8.1.4
8.1.5
8.2
3
3
3
4
4
SUBSURFACE-CONTROLLED VALVES ……………………………………………… 5
8.2.1
8.2.2
8.2.3
8.2.4
8.2.5
8.2.6
8.2.7
8.2.8
8.2.9
8.3
Subsurface Safety Valve …………………………………………….
Surface Safety Valve ………………………………………………...
Safety Valve Status ………………………………………………….
Government Regulations …………………………………………….
Operator Responsibility ……………………………………………..
Type Of Closure Mechanism ……………………………………….. 5
Poppet Closure ……………………………………………………… 5
Rotating Ball Closure ……………………………………………….. 6
Flapper Valves ………………………………………………………. 6
7
Pressure Differential Valves
8
…………………………………………
Ambient Pressure Valves …………………………………………… 9
Limitations/Advantages …………………………………………….. 10
Installation ………………………………………………………….. 12
Manufacturers ……………………………………………………….
SURFACE-CONTROLLED VALVES ………………………………………………….. 13
8.3.1
8.3.2
8.3.3
8.3.4
8.3.5
8.3.6
8.3.7
8.3.8
8.3.9
8.3.10
Control Lines ……………………………………………………….. 13
Control Manifolds …………………………………………………... 14
Valve Operation …………………………………………………….. 18
Fail Safe Closure (Single Control Line) Valves ……………………. 18
Balanced Valves (Dual Control Lines) ……………………………... 19
Ratio Balanced Valves ……………………………………………… 20
Equalizing Feature ………………………………………………….. 21
Control Line Fluid ………………………………………………….. 22
Control Pressure Characteristics ……………………………………. 22
Manufacturers ………………………………………………………. 24
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Intended Function …………………………………………………… 25
Control Line ………………………………………………………… 25
Monitor Pilots ………………………………………………………. 26
Three Way Block And Bleed Valves ……………………………….. 27
Gate Valve And Cylinder Assembly ……………………………….. 29
Other Types Of Valves ……………………………………………… 32
SAFETY VALVE SELECTION …………………………………………………………. 34
8.5.1
8.5.2
8.5.3
8.5.4
8.5.5
8.1
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SURFACE SAFETY VALVES …………………………………………………………... 25
8.4.1
8.4.2
8.4.3
8.4.4
8.4.5
8.4.6
8.5
SURFACE AND SUBSURFACE SAFETY VALVES
Tubing Information …………………………………………………. 34
Valve Model Or Type ………………………………………………. 34
Service Class Or Working Environment ……………………………. 34
Size And Working Pressure ………………………………………… 34
Setting Depth ……………………………………………………….. 35
INTRODUCTION
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8.1.1
SURFACE AND SUBSURFACE SAFETY VALVES
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Subsurface Safety Valve
A subsurface safety valve is a device installed in a well below the wellhead that can be
actuated to prevent uncontrolled well flow. This device can be installed and retrieved by
either wireline (wireline retrievable) or pump down methods, or can be an integral part of
the tubing string (tubing retrievable).
8.1.2
Surface Safety Valve
The surface safety valve is an integral part of the wellhead. It is an automatic wellhead
valve that will close during loss of power supply. The valve actually consists of three parts:
the surface safety valve, an actuator, and a lock open device.
8.1.3
Safety Valve Status
The surface safety valve is geared to trip when a production facility malfunction or well
condition is sensed and indicates a problem at or down-stream of the wellhead such as high
separator level, high or low flow-line pressure, or fire. Table 1 depicts the status of either
valve under various conditions.
Table 1
Safety Valve Status
8.1.4
Alarm
Surface
Safety Valve
Subsurface
Safety Valve
High Flow-line Pressure
Closed
Open
Low Flow-line Pressure
Closed
Open
High Separator Level
Closed
Open
Low Separator Level
Closed
Open
Fire
Closed
Open
Wellead Damage
Inoperable
Closed
Emergency Shutdown
Closed
Closed
Government Regulations
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Government regulations require the use of safety valves. The United States Geological
Survey has primary responsibility for enforcing regulations offshore. On inland waters and
land, responsibility is vested in the environmental protection agency. Sometimes the state’s
petroleum industry regulatory body, such as the Texas Railroad Commission, also exercises
controls and regulations.
Outer Continental Shelf (OCS) orders are published by the United States Geological Survey
(USGS) and are regulations which producing companies must follow concerning the use
and testing of safety valves. The regulation pertaining to subsurface safety valves is OCS
Order 5. It requires that a subsurface controlled subsurface safety valve be installed at least
30 meters (98 feet) below the ocean floor 2 days after production has stabilized. It also
requires that the valves be tested at intervals not exceeding 6 months for tubing retrievable
and 12 months for wireline retrievable valves. Valve leak-age rates of 400 cc/min liquid or
15 ft3/min gas are permitted.
The OCS orders reference several American Petroleum Institute (API) standards. Those
referenced in OCS-5 are: API-14A which covers the design and performance requirements,
certification and documentation requirements for downhole valves (pertains mainly to
manufacturers); API-RP-14B which covers the use of the valves described in 14A. API-RP14C covers the subsurface safety valves. API-14D is the counterpart of 14A for surface
safety valves.
8.1.5
Operator Responsibility
Section 2 of OCS Order 5 states that the operator must use valves that are manufactured
under the quality assurance standards of ANSI/ASME-SPPE-1. In addition, all valves
employed shall conform to the design and performance requirements of API-14A and 14D.
Regulations also require that the operator maintains records for period of five years, two of
which have to be retained in the nearest offshore field office, while the remaining three
years can be retained in an onshore field office. These records must contain verification of
compliance to the various API specifications and the ANSI/ASME-SPPE-1, all valve data,
setting requirements, and the identity of personnel qualified to install and remove the
valves.
8.2
SUBSURFACE CONTROLLED VALVES
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8.2.1
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Type Of Closure Mechanism
Subsurface safety valves can have three different closing mechanisms, poppet, ball or
flapper. The ball and flapper mechanisms are the most popular.
8.2.2
Poppet Closure
Probably, the oldest design in use today, the poppet valve, is one of the most reliable
valves. It simply pops up to seat against a metal seat. A spring holds the valve open during
normal flow. When the flow reaches a specified rate, the tension in a retention spring is
overcome and the valve closes. The poppet closure is shown on Figure 1.
Figure 1. Poppet Closure
8.2.3
Rotating Ball Closure
This closure mechanism uses a spring and piston to keep the valve normally open. When a
pressure differential exists across the ball, a piston moves up, causing the ball to rotate
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about a mechanical linkage to the closed position (Figure 2). Since the sealing surfaces are
not exposed to moving well fluids, flow cutting is negligible, making this valve very
reliable.
Figure 2. Ball Type Closure
8.2.4
Flapper Valves
The closing mechanism of the flapper operates similarly to the ball and poppet. The valve
closes when the piston is forced upward as a result of excessive fluid flow. A flapper
closure is shown in Figure 3.
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Figure 3. Flapper Type Closure
8.2.5
Pressure Differential Valves
Pressure differential valves have an orifice that causes a pressure differential across it as a
result of fluid flow. All these valves are normally open (Figure. 1, 2, and 3) by the spring
force that keeps the piston in the down position, holding the flapper, ball, or poppet open.
However, when the flow rate through the valve exceeds a critical rate and corresponding
pressure differential, the valve is forced to close. An example of events which might result
in excessive flow rates could be the destruction of the wellhead or flowline.
8.2.6
Ambient Pressure Valves
These valves have a deliberately charged preset pressure chamber that is opposed by the
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surrounding pressure in the wellbore. The charged pressure in these valves is just as
important as the size of the orifice in a differential valve. Although the charged pressure
holds the valve in the normally closed position, the well pressure at the installed valve will
be greater than the charged pressure inside the valve, and therefore the valve will open.
Assume that a wellhead catastrophe has occurred and as a result wellbore fluid is being
vented to the atmosphere. If the decrease in wellbore pressure is reflected at the valve and
is less than the pressure in the chamber of the valve, the valve will close (Figure. 4 and 5).
Figure 4. Ambient Valve-Open
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Figure 5. Ambient Valve-Closed
8.2.7
Limitations / Advantages
Ambient pressure valves are used primarily on low-velocity wells with flow rates incapable
of closing a differential valve. Ambient valves have a larger unrestricted flow area, which
makes them ideal for low-pressure wells. Leakage of the charged pressure would cause the
ambient valve to close. Leakage from the tubing to the charged chamber will equalize
pressure working on the valve and cause it to malfunction in the open position. Because of
this possibility, the ambient valve includes a spring to assist in closing. Just as paraffin
buildup or sand cutting could adversely affect the closing action of differently operated
valves, the same holds true with ambient valves.
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Therefore, a good well maintenance program is important. It should be noted that both
ambient and pressure differential valves are available only in wireline retrievable form. An
important limitation on closing the differential pressure valves is that the differential must
exist at the setting depth in tubing. Also, as well conditions change, the setting of the safety
valve must be monitored so that function properly.
8.2.8
Installation
A basic requirement for installing wire-line retrievable subsurface controlled safety valves
is the initial installation of landing nipples as part of the tubing string, Landing nipples
should be located as shallow as possible below the depth at which paraffin begins to form
for the following reasons.
•
If the valve closes in a well producing significant quantities of sand, less sand is
available to fall back on the valve.
•
If a catastrophe occurs, less well fluid will be lost.
•
A shallow valve is easier to service.
The safety valve is attached to a locking mandrel selected to set in the nipple that has been
installed. Also attached to this assembly is an equalizing sub installed between the locking
mandrel and the safety valve. Equalizing subs are important because they provide a way to
equalize differential pressures across the safety valve before the valve is reopened or
retrieved from the tubing string. The safety valve assembly is then run in the well by wireline or pump down techniques and is locked in the appropriate nipple. Figure 6 shows a
safety valve assembly.
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Figure 6. Safety Valve Assembly
The valve can be opened in two ways. The first is by the application of
pressure to the tubing above the valve, and the second is by wire-line
methods with the equalizing sub. When pressure applied to the tubing
above the safety valve becomes equal to the pressure below the valve, the
mechanical force of the spring will reopen the valve. When wire-line
methods to reopen the safety valve are used, an equalizing prong is run on
wire-line tools until it makes contact with the equalizing sub. When
contact is made, the prong pushes the equalizing valve off its seat, allowing
the pressure from below to move through the equalizing valve and into the
tubing above. After pressure has been equalized across the safety valve,
the mechanical force of the spring will cause it to reopen. Figure 7 shows
an example of this procedure.
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Figure 7. Wireline Methods
8.2.9
Manufacturers
There are only three API/OCS certified manufacturers of subsurface controlled subsurface
safety valves, and these are :
Halliburton Center
5151 San Felipe
Houston, Texas
77056
Macco/Schlumberger
100 Macco Blvd.
Sugar Land, Texas 77478
Baker Packers
P.O. Box 3048
Houston, Texas
77001
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8.3
SURFACE CONTROLLED VALVES
8.3.1
Control Lines
Surface-controlled subsurface safety valves (SCSSV) are normally closed and are held open
by an externally applied pressure source. Most offshore regulations require these remotely
controlled valves due to their higher reliability and safety records as opposed to subsurface
controlled safety valves. Upon loss of this control pressure, the valve closes due to the
force of the spring acting on the closure mechanism. Opposing this force is the hydrostatic
pressure of the control fluid. Consequently, there is a depth limit to which these valves can
be set since at some point the spring force is balanced by the hydrostatic pressure.
Commands are sent down to SCSSVs by either hydraulic pressure, wire line, or acoustic
signal, but by far the most common is hydraulic pressure. The control conduit is usually
0.25-inch (6.2-mm) outside diameter (OD) tubing that is run from the wellhead to the valve.
However, an annular flow path or a separate tubing string can also be used as a conduit.
The surface controlled safety valves are usually set shallow so that the control line does not
have to be long.
Figure 8. Surface-downhole control line schematic
The most popular control line is the continuous type. It has no threaded joints and comes
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already filled with hydraulic fluid. The control line is usually banded to the tubing and
connected to a lug on the landing nipple. The control line and tubing are then run in the
hole together. The control line at the surface is connected to a hydraulic control manifold
(Figure 8).
Figure 9. Single Well Control Manifold-valve open
8.3.2
Control Manifolds
On a single well system, hydraulic manifolds are small and pneumatic/hydraulic. On
multiwell systems, the manifolds are often electrohydraulic and can be the size of a small
room. Figure 9 shows how a single well manifold functions. Supply gas is fed to the
control manifold and operates a hydraulic pump. This gas is also regulated down to feed
fusible plugs (plugs that melt when heated), manual shutdown stations, or other controls
used to monitor the system. The hydraulic pressure created by the pump is applied
downhole to the safety valve and keeps it open. If for any reason the control pressure is
released, the hydraulic pump in the manifold is by passed by a control valve. At this point
hydraulic pressure is released back into the reservoir, allowing the safety valve downhole to
close (Figure 10). If gas pressure is lost or unavailable, the safety valve can be operated
manually by a hand pump on the control manifold.
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Figure 10. Single Well Control Manifold-valve closed
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Figure 11. Wireline Retrievable Ball Valve
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Figure 12. Wireline Retrievable Flapper Valve
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8.3.3
SURFACE AND SUBSURFACE SAFETY VALVES
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Valve Operation
The operational characteristics of a surface controlled safety valve (SCSSV) are similar to
the mechanics of a subsurface controlled safety valve (SSCSSV). The two main types of
closure mechanisms are the ball and the flapper. The main difference is that the spring
keeps the SSCSSV valve open, while the spring force in the SCSSV causes it to close in the
absence of control line pressure. Figure 11 illustrates these functions. At the top right,
hydraulic fluid enters the valve and forces the piston down against the spring. As stated
earlier, surface-controlled valves are normally closed. The action of the piston moving
down mechanically moves the ball off its seat and rotates it to the open position. When
hydraulic pressure is released, the large closing spring forces the piston back up and closes
the valve. Well pressure at the valve also assists the closing. The flapper closure performs
in a similar manner. The piston physically pushes the flapper back out of the flow path to
open (Figure 12).
8.3.4
Fail Safe Closure (Single Control Line Valves)
As mentioned previously, an inherent limitation to single control line SCSSVs is the depth
to which these valves may be set before the hydrostatic head of the control line fluid
overrides the counteracting spring force of the closure mechanism. This maximum setting
depth is called the fail-safe depth and the valve will not close at greater depths. For a
particular SCSSV, the piston area and the spring force are constant. The pressure gradient
of the control line fluid is then the determining factor for the fail-safe depth. Although not
an all- inclusive number, the fail-safe depth should be determined for each particular
installation.
The fail safe depth of a single line surface controlled subsurface safety valve is defined as
the maximum setting depth at which the valve will close while opposing the hydrostatic
pressure in the control line. This theoretical fail-safe depth may be calculated by dividing
the force of the spring when the valve is closed by the piston area and the gradient of the
control line fluid.
This relationship is shown in the following equation :
F
D =
Ap
Ge
where :
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D
=
fail safe closure depth, ft
F
=
spring force with valve closed, lb
Ap
=
piston area of valve, in
Ge
=
effective fluid gradient, psi/ft
Ge
=
Gc or Gw , whichever is greater
Gc
=
gradient of control line fluid, psi/ft
Gw
=
gradient of wellbore fluid, psi/ft
2
where :
It is usually assumed that there is no wellfluid above the valve or well pressure below the
piston. In actual well conditions, an effective gradient, Ge ,would be determined at the
piston of the valve. This theoretical depth may be modified by a safety factor of 1.2 to 1.5
to compensate for mechanical and seal friction in order to arrive at a working fail safe
depth.
8.3.5
Balanced Valves (Dual Control Lines)
In a balanced valve, a second control line is run to the valve and filled with the same
control line fluid. The hydrostatic pressure applied to the underside of the piston balances
the hydrostatic pressure on top of the piston regardless of the valve setting depth. A
balanced valve is shown in Figure 13.
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Figure 13. Dual Control Line-balanced valve
Theoretically, a balanced valve has an unlimited setting depth; however, the closing times
required to displace the control line fluid to the surface limit the depths to which the valve
should be set. An advantage (besides extreme setting depths) to a balanced valve is that the
control pressure required to hold the valve open need not be greater than well pressure. The
control pressure is required simply to compress the spring to hold the valve open, although
for fail-safe considerations control pressure should be higher than well pressure.
8.3.6
Ratio Balanced Valves
Ratio-balanced surface controlled subsurface safety valves are those where the balance area
is less than the piston area (Figure 14). Consequently the valve has a particular fail-safe
depth.
Because of the difference in areas, the valve is assisted in closing by the well pressure
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acting on the balance piston. This feature helps decrease the closure time when the valve is
set at extreme depths.
Figure 14. Ratio Balanced Dual Control Line Valve
8.3.7
Equalizing Feature
Many surface controlled valves have an equalizing feature in which the shut-in well
pressure is equalized across the valve by the application of control line pressure to the
piston. This pressure causes an equalizing seat to open so that the pressures above and
below the valve are equalized before the primary valve mechanism is opened fully. Lowpressure wells are not usually equipped with an equalizing feature. In all cases, the
pressure differential across a closed valve should be equalized to prevent damage to the
closure mechanism during opening.
8.3.8
Control Line Fluid
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The two basic factors to be considered in the selection of a liquid for controlling subsurface
safety valves are density and viscosity. Density is important because of the effect of the
hydrostatic head pressure exerted at the valve. Viscosity is important because of the
increase in bleed down time of most systems as ambient temperature falls. Diesel is
commonly used as a control fluid because of its low density. Treated water, that is, fresh
water with miscible oils and possibly glycol, is also used. For viscosity control, light oils,
for example, SAE 10 weight or lighter, can be used in systems when the minimum
operating temperature is 50° F (10° C) or greater. Below that temperature, viscosity
increases to an unacceptable level. In arctic service this factor is critical. In this application
a mixture of two parts light diesel and one part isopropanol by volume often is used to
maintain a low viscosity at temperatures from 20° F (-7° C) to 180° F (82° C) at the
downhole. Note that the alcohol tends to vaporize at producing temperatures with this latter
control fluid.
8.3.9
Control Pressure
Safety valve problems vary with each individual application and valve. However, since
these valves are linked to the surface by the control line, the operation and condition of the
valve can be determined by observation of the control pressure characteristics (Figure 15).
To determine if the valve piston is moving down, hand pump the control manifold at a
constant rate. By observing the control line pressure, an increase in opening pressure (A)
should be noticed as illustrated in Figure 15. The pressure should then increase more
slowly than before, indicating that the piston is traveling. At time B (Figure 15) the
pressure should increase sharply, indicating that the valve is fully open.
Figure 15. Control Pressure Characteristics-opening cycle
To determine if the valve is closing (the valve piston is moving up), exhaust the control line
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fluid at a constant rate and observe the pressure. It should decrease to pressure A (Figure
16), after which the rate of pressure decrease is much less than before. At this point the
valve spring pressure exceeds the control line hydraulic pressure and initiates upward
piston motion. The lower rate of pressure decline in control line pressure will continue
until the pistonn bottoms out or ceases motion (pressure B on Figure 16). The decrease in
pressure should continue at the same rate as when the fluid was first bled to the atmosphere.
Figure 16. Control Pressure Characteristics-closing cycle
8.3.10
Manufacturers
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There are several API/OCS certified manufacturers of surface controlled subsurface safety
valves. These include :
Halliburton Center
5151 San Felipe
Houston, Texas
77056
Macco/Schlumberger
100 Macco Blvd.
Sugar Land, Texas 77478
Baker Packers
P.O. Box 3048
Houston, Texas
77001
Hydrill Downhole Tool Division
16770 Imperial Valley Drive
Suite 149
Houston, Texas
77060
Camco Incorporated
7010 Ardmore Blvd.
Houston, Texas
77054
Flopetrol
Americana Building
Room 1433
811 Dallas Street
Houston, Texas
77002
8.4
SURFACE SAFETY VALVES
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Intended Function
The surface safety valves are an integral part of the Christmas tree and are designed to shut
in the well when a problem occurs downstream of the wellhead itself. This design
eliminates the repeated use of the subsurface safety valve, and improves its reliability
should an emergency occur at the wellhead.
8.4.2
Control Line
The automatic SSVs close upon loss of pressure. The pressure source is either pressurized
air or gas (Fig. 17) and is used to hold the valve in the open position. Control line pressure
is normally about 100 psi, but the pressure required to hold the valve open may vary,
depending on the size of the safety valve, the operating ratio of the valve piston, and the
wellhead pressure. In some cases pressures as low as 30 psi is sufficient.
Figure 17. Surface Safety Valve Control Line
8.4.3
Monitor Pilots
The control line is routed to monitor pilots at strategic points downstream of the well head
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choke (Figure 18). These pilots sense decreases or increases in pressure along the flow
line at the heater, the separator, or any point where critical pressure changes should be
monitored. Each pilot is adjustable in the field and can be set within operating limits.
Figure 19 demonstrates how this monitor functions. On the right, control pressure is
brought into a toggle valve. The sensing plunger runs vertically through the center of the
pilot and is free to move up with an increase or decrease in flow-line pressure. The toggle
valve fits in a groove around the sensing plunger. Any motion of the plunger will trip the
toggle valve. If the toggle valve is tripped off seat, the control pressure can exhaust
through the port on the left.
Figure 18. Surface Control Line Type ‘P’ Pilot
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Figure 19. High/low Flowline Pressure Monitor
8.4.4
Three-Way Block And Bleed Valves
Routed through monitor pilots, control line pressure is also channeled to a three-way valve.
This valve shifts and blocks incoming control pressure and bleeds pressure from the safety
valve cylinder. This action allows the safety valve cylinder to close. In service, the handle
is up (Figure 20). Control line pressure feeds in from the left and completely fills the
valve. The pressure is routed out the top right to the safety valve and out the lower right
outlet to the monitor pilot.
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Figure 20. Three-Way Block and Bleed Valve-in service
Figure 21 shows the actuated condition of the same three-way valve. At step 1, the
monitor pilot has been actuated, and control line pressure has been bled off the lower side
of the diagram. At step 2, the stem and handle have moved down and are blocking
incoming control pressure. Step 3 shows where the control pressure that was holding the
safety valve open is now bleeding out the top of the three-way valve by the stem, allowing
the safety valve to close.
The handle must be pulled up and held momentarily until the safety valve is completely
open to place the three-way valve back in service and to reopen the safety valve after the
problem is solved.
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Figure 21. Three-Way Block and Bleed Valve-activated
8.4.5
Gate Valve And Cylinder Assembly
The SSV comprises the gate valve and a cylinder assembly. The cylinder assembly may be
installed by the manufacturer on almost any reverse-acting gate valve or may be installed in
the field on existing gate valves. Figure 22 shows a cutaway of a complete surface safety
valve. Figure 23 shows the actuated valve. Control pressure entering the valve cylinder
forces the piston, stem, and gate down to the open position. Notice that the stem is almost
flush with the top of the cylinder, indicating the position of the gate. The valve may be
mechanically locked open by a screw-on lockout cap. Fusible caps are available that will
melt in the event of a fire and will allow the valve to close if the valve inadvertently is left
locked open. This is a fail-close valve since in the absence of control line pressure, the
valve will close. The valve body pressure is the closing force. Pressure acting on the area
of the stem (Figure 24) forces the piston, stem, and gate to the closed position.
The closing spring comes into effect only if a 100-psi pressure or less is in the gate valve
body (Figure 25). This condition could occur if the flow line ruptures near the valve on the
downstream side.
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Figure 22. Sectional View of Surface Safety Valve
Figure 23. Activated Surface Safety Valve
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Figure 24. Surface Safety Valve-pressure on stem
Figure 25. Surface Safety Valve-closing spring
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Figure 26. Flowline Pressure Activated Surface Safety Valve
8.4.6
Other Types Of Valves
Some SSV valves do not require external control pressure. These operate by flow-line
pressure (Figure 26) diverted into the valve cylinder. A monitor actuator pilot adapts
directly into the cylinder, which senses high or low pressure only or a combination of both.
The valve operates similar to those illustrated in Figures 22 through 25, and can be adapted
to any reverse-acting gate valve.
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Another surface safety valve is the hydraulic type (Figure 27). It also is adaptable to any
reverse-acting gate valve. Because of its small size, it is ideal for close quarters on
offshore platforms. Also, because it is hydraulically operated, it is often tied into the
control system for surface-controlled subsurface safety valves.
Figure 27. Hydraulically Operated Surface Safety Valve
8.5
SAFETY VALVE SELECTION
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8.5.1
SURFACE AND SUBSURFACE SAFETY VALVES
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Tubing Information
One of the most important items necessary when ordering a subsurface safety valve is the
tubing size, weight and grade so that the proper landing nipples, tubing connections,
material specs, etc. are the same. This is true whether the valve is actuated remotely from
the surface or from downhole.
8.5.2
Valve Model Or Type
Valve model refers to the method employed to shut off the flow of hydrocarbons to the
surface. These are either flapper, ball or poppet. Flapper and ball is used on both surface
and subsurface controlled valves, whereas the poppet is used strictly on the latter.
The type refers mainly to the remote control feature of surface controlled valves, i.e., dual
control lines or single control lines. As mentioned earlier, the dual control line type
usually selected when extreme setting depths are anticipated.
8.5.3
Service Class Or Working Environment
There are three types of service class environments as defined by the American Petroleum
Institute (API), and these are Class 1 - Standard Service; Class 2 - Sandy Service; Class 3 Stress Corrosion Cracking Service. Within this last class there are two sub-classes : 3S for sulfide stress cracking and 3C - for chloride stress cracking service. Details concerning
the working environment and material specs can be found in API Spec 14A “Specification
for Subsurface Safety Valves”.
8.5.4
Size And Working Pressure
Although size is important from a standpoint of tubing compatibility, it is also necessary
information regarding any special accessories such as pup joints, flow couplings or
equalizing valves that may be desired. OCS Order 5 requires that flow couplings be
installed immediately before and after the subsurface safety valve in order to protect
against erosion from turbulence in the flow stream.
When dealing with subsurface controlled valves, the two most important parameters to be
specified are the orifice size and the working pressure. The orifice size dictates the amount
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of pressure drop that will be available to close the valve during a catastrophe. The working
pressure establishes the amount of dome charge that is necessary to close the valve if an
ambient pressure valve is used.
If a remote-controlled valve is used, the working pressure is necessary in order to size up
the surface hydraulic system.
8.5.5
Setting Depth
Setting depths are especially important when surface controlled (remote) valves are
employed because of the importance of the hydraulic control line fluid’s hydrostatic head.
If the valve is set too deep, the closing springs acting on the valve mandrel may be
incapable of exerting sufficient force to counteract the control line’s fluid pressure. This
situation would result in a permanently open valve. The fail-safe depth must therefore be
calculated for each installation.
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COMPLETION FLUIDS
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CHAPTER 9
COMPLETION FLUIDS
TABLE OF CONTENTS
9.1
INTRODUCTION …………………….……………………………………………. 5
9.1.1
9.1.2
9.1.3
9.2
Fluid Density ..………..……………………………………………... 8
Subsurface Density ………………………………………………….. 10
Density of Blends ...…………………………………………………. 12
Viscosity …………………………………………………………….. 12
Gel Strength …………………………………………………………. 15
Corrosivity …………………………………………………………... 15
Solids Content ………………………………………………………. 16
Formation Compatibility ……………………………………………. 16
Fluid Loss …………………………………………………………… 17
Cost …………………………………………………………………. 17
WATER-BASE FLUIDS ……………………….……….………………………… 18
9.3.1
9.3.2
9.3.3
9.3.4
9.3.5
9.3.6
9.3.7
9.3.8
9.3.9
9.4
5
5
7
FLUID PROPERTIES ………………...…………………………………………… 8
9.2.1
9.2.2
9.2.3
9.2.4
9.2.5
9.2.6
9.2.7
9.2.8
9.2.9
9.2.10
9.3
Definitions ……………..…………………………………………….
Fluid Functions ……………..……...………………………………..
Fluid Types …………………….…………………………………….
Source of Water …..……………..……………………………….….. 18
Formation Damage ……...…..…….......................….....……….….. 18
Fluid Loss Agents ……………...…...............………………………. 19
Polymer Viscosifiers ………………………………………………... 20
Polymer Applications ……...............……………………………….. 21
Mixing Polymers ……...............……………………………………. 21
Polymer Breakers ……...............……………………………………. 22
Polymer Degradation ……...............………………………………... 23
Polymer Residue ……………………………………………………. 23
CLEAR BRINES ……………..…………………………………………………… 24
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9.4.1
9.4.2
9.4.3
9.4.4
9.4.5
9.4.6
9.4.7
9.4.8
9.4.9
9.4.10
9.5
Density Ranges ….…...……………………………………………… 24
Freezing and Crystallization …….…………..……………………… 24
Potassium Chloride ……...………………………..………………… 24
Sodium Chloride …………………………………………….……… 25
Sodium Chloride/Calcium Chloride ………………………………… 25
Calcium Chloride …………………………………………………… 26
Calcium Chloride/Calcium Bromide ……………………………….. 26
Calcium Chloride/Calcium Bromide/Zinc Bromide ………………... 27
Sodium Bromide ……………………………………………………. 27
Brines To Avoid …………………………………………………….. 28
Problem 1 ………….…….…..…….……………….……………..… 29
Average Fluid Density ……………….…………………...………… 29
Fluid Type ………..………………..………………………………... 30
Required Surface Density …………………………………………… 30
Problem 2 …………………………………………………………… 30
Freezing and Crystallization ………………………………………... 30
Weighting Agents …….…..…….……………….……………..…… 31
Amount of Weighting Agents ……………………………….……… 31
Application ……….………………..………………………………... 32
Composition ……….…….…..…….……………….……………..… 33
Economics ………………………………………………...………… 33
Damage …………..………………..………………………………... 33
Stability ……………………………………………………………... 34
Corrosion ……………………………………………………………. 35
Applications ………………………………………………………… 36
HYDROCARBON FLUIDS ……………….....………………………………...… 37
9.8.1
9.8.2
9.8.3
9.8.4
9.8.5
9.9
January 1998
WATER-BASE MUD …...……………………………………………....….......… 33
9.7.1
9.7.2
9.7.3
9.7.4
9.7.5
9.7.6
9.8
PROPRIETARY INFORMATION -For Authorised Company Use Only
WEIGHTENED BRINES ……………………………………..……..….………... 31
9.6.1
9.6.2
9.6.3
9.7
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EXAMPLE : BRINE COMPOSITION …………………………......….……….. 29
9.5.1
9.5.2
9.5.3
9.5.4
9.5.5
9.5.6
9.6
COMPLETION FLUIDS
Applications …….…....................................................................… 37
Density …...……………..……………………..............................… 37
Viscosity ..….….………..……………………..............................… 37
Crude Oil ………….……………………………………………….... 37
Diesel ……..…………………………………………………………. 38
OIL-BASE AND INVERT-EMULSION MUDS ……………………………...… 39
DRILLING DEPARTMENT
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9.9.1
9.9.2
9.9.3
9.9.4
9.9.5
9.9.6
9.10
Composition …….…….................................................................... 39
Economics ….……….….……………………..............................…. 39
Damage…………….……………….………..................................… 39
Stability ……..……………………………………………………..... 40
Corrosion ……………………………………………………………. 40
Applications ………………………………………………………… 40
Applications …….….…...............................................................…
Equipment .……………...…………………................................…
41
41
Definition ……….….…...............................................................… 42
Advantages/Uses ……………...…..…………...............................… 42
Properties …….…….………………….........................................… 42
Foam Generation …….…..………………..………………………… 42
Solids Transport …....…...............................................................… 44
Solids Suspension ……...…………………….................................. 46
Breaking Circulation ..…..………………..…………………………. 47
Fluid Loss Control ………………………………………………….. 47
Treatment Displacement ……………………………………………. 50
Selecting A Circulating Fluid ………………………………………. 50
PACKER FLUIDS ……………....……………………....…………………….…... 51
9.13.1
9.13.2
9.13.3
9.13.4
9.13.5
9.13.6
9.13.7
9.13.8
9.14
January 1998
CIRCULATING FLUIDS …………….....……………....……………………..…. 44
9.12.1
9.12.2
9.12.3
9.12.4
9.12.5
9.12.6
9.13
PROPRIETARY INFORMATION -For Authorised Company Use Only
FOAM …………………………………….....…………....……………………...… 42
9.11.1
9.11.2
9.11.3
9.11.4
9.12
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Issue 1
NITROGEN ……………………..……………………....…………….……….….. 41
9.10.1
9.10.2
9.11
COMPLETION FLUIDS
Functions ………..….…...............................................................… 51
Hydrostatic Head ………..………………..………………………… 51
Solids Settling ………………………………………………………. 51
Corrosion ……………………………………………………………. 52
Corrosion Inhibitor ………………………………………………….. 53
Biocides ……………………………………………………………... 53
Packer Fluid Selection ……………………………………………… 53
Insulating Fluids ……………………………………………………. 55
PERFORATING FLUIDS ……………….……………………...……………...… 57
9.14.1
9.14.2
Perforation Plugging ...….............................................................…
Salt Water and Oil ….……...………...………..............................…
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57
57
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9.14.3
9.14.4
9.15
COMPLETION FLUIDS
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Acids ……………..…….………………......................................…. 57
Nitrogen ….……….…..………………..…………………………… 58
FIELD HANDLING OF FLUIDS ………...……………………....…….………... 59
9.15.1
9.15.2
9.15.3
9.15.4
9.15.5
9.15.6
9.15.7
9.15.8
9.15.9
9.15.10
9.15.11
59
Mixing Brines …..….…...............................................................…
Safety ……….…………..………………..…………………………. 60
Properties Control …………………………………………………... 60
Freezing and Crystallization ………………………………………… 61
Corrosion ……………………………………………………………. 61
Environmental ………………………………………………………. 63
Resale ……………………………………………………………….. 63
Surface Equipment ………………………………………………….. 64
Solids Control ………………………………………………………. 64
Allowable Solids ……………………………………………………. 66
Filtration …………………………………………………………….. 68
9.16
APPENDIX A – BRINE DATA …………………………...…………………...… 72
9.17
APPENDIX B – HYDROCARBON DATA …………....……………………...… 113
9.1
INTRODUCTION
9.1.1
Definitions
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Following the drilling of a well with drilling fluids, various other fluids are used in the well
during the well completion steps and subsequent workover operations. We will call these
other fluids completion or workover fluids interchangeably since no useful distinction can
be made between these terms from the point of view of fluid requirements.
Completion fluids may be subdivided according to function into working fluids, packer
fluids, and treating fluids.
Working fluids are the general purpose fluids which serve to control the well while it is
open, transport solids out of and into the well, displace well treatments, bring the well in,
augment perforating, and protect the producing formation during perforating and
subsequent exposure. Circulating fluids and perforating fluids are important subclasses of
working fluids.
Packer fluids are fluids which are left in the tubing-casing annulus when the annulus is
isolated from the tubing with a packer. They must meet many of the same requirements as
working fluids and are often the same fluid. Packer fluids serve to reduce differential
pressure across the packer, protect annular steel surfaces from corrosion, help control the
well while the packer is being set or retrieved, make up part of the kill fluid should a packer
failure occur, and may thermally insulate the tubing during production or injection.
Treating fluids are fluids used to actively treat the formation or wellbore to solve a specific
problem. Treating fluids comprise formation matrix acidizing fluids, wellbore cleanout
acids and solvents, formation matrix solvent and surfactant treatments, paraffin and asphalt
removal and inhibiting fluids, fracturing fluids, cements, and sand consolidation fluids.
These fluids and their use are highly specialized. Treating fluids will not be covered in this
chapter.
9.1.2
Fluid Functions
The various workover and completion operations require fluids which will serve one or
more of the following basic functions :
1.
Well control
2.
Solids transport
3.
Treatment displacement
4.
Formation protection
5.
Corrosion protection
6.
Solids suspension
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Well control is a primary function of completion and workover fluids. In a conventional
completion or workover, the fluid must be able to kill a flowing well; that is, the fluid must
be heavy enough to produce a hydrostatic pressure sufficient to stop the well from flowing.
The fluid properties that are important for the well control function are density, viscosity,
and fluid loss characteristics. The fluid density determines whether the hydrostatic head
will be sufficient to control the well. Fluid viscosity determines the rate at which fluid is
lost to the formation in the absence of fluid loss additives. Fluid loss may be reduced by
the incorporation of filter cake forming fluid loss agents.
Solids transport is another major function of workover/completion fluid. Often clay fines,
sand, and larger debris must be removed from the well. The effectiveness of any fluid in
well cleanout operations depends on its carrying capacity, which is largely a function of
fluid viscosity.
Treatment displacement is a fluid function which is often taken for granted. When a
treating fluid is used in a well, a workover/completion fluid is usually employed to displace
the treatment through the well and into the formation. It may also be used to establish
injectivity into the wellbore to cool down the zone, and/or breakdown the initial resistance
of the formation to fluid entry. The most important property required of a treatment
displacement fluid is that it be chemically compatible with the treating fluid. It should also
be non-damaging to the formation.
Formation protection is an important function of any fluid that will come into contact with
the productive formation. The fluid allowed to leak off to the formation should not contain
damaging solids, such as clays, silt, barite, paraffins, asphalt, and insoluble corrosion byproducts. Surfactants used in the fluid should be compatible with the formation and
formation fluids.
Corrosion protection is an easily important function of a fluid which will remain in the well
for an extended period of time. Fluids which are inherently corrosive must sometimes be
used in the well. The time duration of their use should be minimized and corrosion
inhibitors should be added to control corrosion damage to acceptable levels.
Solids suspension is a function primarily desired in fluids where suspended solids are
necessary to impart a required fluid property. Most commonly, suspended solids are
required to increase fluid density or to provide fluid loss control.
9.1.3
Fluid Types
Many kinds of fluids are used in completions and workovers. The most common fluid is a
clear brine of kill weight or slightly greater. Common fluid types are muds, treated fresh
water, field saltwater, clear dense brines, solids-weighted brines, hydrocarbons, oil-base
muds, nitrogen, and foams.
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In the following sections we will examine each of these. Table 1 lists the various workover
fluids, their practical density ranges and typical applications.
Table 1 : Fluid Types and Applications
Type of Fluid
Density Range
Fresh water
9.2
Applications
8.33 ppg
1)
2)
3)
base for brines & slurries
spacer for treatments or sluries
solids transport (when gelled)
Saltwater/weighted brines
8.3-18.0 ppg
1)
2)
3)
4)
5)
6)
well control
perforating
sand control
treatment displacement
solids transport (when gelled)
packer fluid
Conventional water-based muds
8.3-19.0 ppg
1)
2)
well control
solids transport
Oils & oil-base muds
7.0-8.3 ppg
1)
2)
3)
4)
5)
perforating (oils only)
treatment displacement
packer fluids
well control (when gelled &weighted)
solids transport (when gelled & weighted)
Foam
0.2 ppg
1)
washing out sand, small cuttings,and
wellbore liquids (usually in low pressure
reservoirs
Nitrogen gas
0.1 ppg
1)
2)
3)
treatment displacement
well unloading
circulating out sand or small cuttings
(usually in low pressure reservoirs)
FLUID PROPERTIES
The fluid properties that most often must be considered when selecting a fluid are density,
viscosity, corrosivity, solids content, compatibility with the formation, fluid-loss
characteristics, mechanical requirements, and cost. The importance of these properties in
the choice of fluids will be discussed in this section.
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9.2.1
COMPLETION FLUIDS
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Fluid Density
Fluid density is defined as the weight per unit volume of fluid. Fluid gradient is defined as
the pressure exerted by a column of fluid of unit depth. Table 2 shows the relation between
fluid gradient and fluid density for a variety of common units. The fluid gradient, FG, in
psi/foot is related to the average fluid density, ρ, in pounds per gallon by:
FG(psi/ft) = 0.052ρ(ppg)
(1)
Thus, the pressure exerted by a column of fluid at a particular depth can be calculated as
follows:
Pressure(psi)= 0.052ρ (ppg) Depth(ft)
(2)
where ρ is the average fluid density in ppg, and depth is the true vertical depth of the fluid
column.
Fluid density is used to control a well that must be open during a period of work. Fluid
density should be no higher than needed to control formation pressure in order to minimize
potentially damaging fluid loss, extended unloading times, and avoid formation fracturing.
With reasonable precautions a hydrostatic bottom hole pressure (BHP) of 100 to 400 psi
over formation pressure should be adequate. The excess of the hydrostatic BHP exerted by
the workover fluid over the formation BHP (pore pressure) is called overbalance. This
overbalance is chosen by the engineer to provide a safety margin intended to insure well
control throughout the workover. If the hydrostatic BHP is less than the formation BHP,
then the well is said to be underbalanced.
Table 2
Density and FluidGradient
∆P (psi/ft) = 0.051948 ρ (ppg)
L
∆P (psi/ft) = 0.433527 ρ (g/cm3)
L
∆P (MPa/m) = 1.175096 x 10-3 ρ (ppg)
DRILLING
DEPARTMENT
L
∆P
PETRONAS
CARIGALI SDN BHD
(bar/m) = 0.098067
0.011751 ρ (g/cm
(ppg) 3)
∆P
L (Mpa/m) = 9.80665 x 10-3 ρ (g/cm3)
CM 9
COMPLETION
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COMPLETION FLUIDS
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The average fluid density required to control a well can be calculated using the following
equation :
ρ (ppg) =
BHP + Overbalance (psi)
(3)
0.052 Depth (ft)
The formation bottomhole pressure (BHP) or formation pore pressure can be estimated
from the reservoir data, or by adding the shut-in surface pressure and the hydrostatic head
of the fluid in the wellbore (if the liquid is known), or measured in other ways.
It must be emphasized that the required density calculated using the above relation is the
average density of fluid in the well not the surface density. Fluid density is a function of
temperature and pressure. In general, fluid density decreases with increasing temperature
and increases with increasing pressure so that to some extent the effects of temperature and
pressure tend to compensate each other. In general, the temperature effect is the greater of
the two.
9.2.2
Subsurface Density
Table 3 illustrates how subsurface temperatures and pressures affect the density of a CaBr2
workover fluid with a 14.2 ppg surface density. This 9000 foot well has a 250°F static
bottomhole temperature and a 6532 psig static bottomhole pressure. In this example the
fluid column exactly balances the well. Using Eqn. (3) we can calculate the average fluid
density required to balance this well as
ρ AV =
6531.7 + 0
= 13.970 ppg
(0.05195) (9000)
Column 4 shows how the fluid density changes with depth. Notice that the average value of
the fluid densities in column 4 is also 13.970 ppg. Computation of fluid densities at various
temperature-pressure combinations, as was done to generate column 4, requires detailed
knowledge of the PVT properties of each brine concentration. Since this is not usually
available and since great precision is not necessary, a simpler yet adequate method is
desirable.
If we neglect the effects of both temperature and pressure, thus assuming that the fluid has
the same density at all depths, then the resulting actual distribution of densities with depth
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is as illustrated in column 5. In column 5 we see that a fluid with a surface density of
13.970 ppg will have an actual average density of 13.744 ppg. This is 0.226 ppg less than
the required average density and will result in the well being underbalanced by 105.6 psi.
The usual prescription of adding 200 to 400 psi “overbalance” to the required fluid head
would prevent an underbalanced well in this case. The poor accuracy of this method of
fluid head estimation is compensated for by the application of what has historically
appeared to be an arbitrary “overbalance” requirement.
A more accurate, yet still simple, method of estimating the required fluid density is the
temperature compensated mid-depth method. It is based upon (1) the assumption that the
mid-depth geothermal temperature is a suitable average well temperature and (2) the simple
observation that the effect of temperature on fluid density is generally (at typical well
depths) greater than the effect of pressure. Until accurate P-V-T-composition data for
workover fluid is developed, this method is the most suitable method available. The
method is applied as follows :
(1)
Accurately determine the mid-depth geothermal temperature.
(2)
Determine the required average fluid density from formation pore pressure and the
desired overbalance using Eqn. (3).
(3)
Select a fluid type.
(4)
Set the chosen fluid’s density at the mid-depth temperature equal to the required
average fluid density.
(5)
Locate the required surface density using density versus temperature charts such as
those in Appendix A. enter the chart at the required average density and mid-depth
temperature. Then, follow a line of constant composition back to the surface
temperature.
Column 6 of Table 3 illustrates this process for the case where the desired overbalance is
zero. Column 7 shows the actual density distribution of the chosen fluid. Notice that the
actual mid-depth density is 14.080 ppg not 13.970 ppg and that the actual average density
of the fluid is 14.089 ppg not 13.970 ppg. Thus, use of the temperature compensated middepth method results in overbalance pressure. Note, that in this case, temperature effect
accounts for 161.2 psi bottomhole pressure difference and pressure effect accounts for a
55.4 psi bottomhole pressure difference.
Table 3
Wellbore Fluid Density
(1)
Depth
(2)
Temp.
(3)
Pressure
(4)
(5)
(6)
(7)
ρ (T, P)
ρ (T, P)
ρ (T)
ρ (T, P)
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ft
°F
psig
ppg
ppg
ppg
ppg
0
900
1800
2700
3600
4500
5400
6300
7200
8100
9000
70
88
106
124
142
160
178
196
214
232
250
0
653.2
1306.3
1959.5
2612.7
3265.8
3919.0
4572.2
5225.4
5878.5
6531.7
14.200
14.125
14.084
14.043
14.002
13.961
13.922
13.884
13.849
13.815
13.785
13.970
13.896
13.856
13.815
13.775
13.735
13.697
13.660
13.624
13.592
13.561
14.320
14.320
14.245
14.204
14.162
14.120
14.080
14.040
14.002
13.966
13.933
13.902
13.970
13.744
ρ av
9.2.3
=
13.970
14.089
Density of Blends
Sometimes it is necessary or desirable to blend two miscible fluids to obtain a fluid of
intermediate density. The following relationship may be used to calculate the proportions
of light and heavy fluid which should be combined to produce a desired density :
a =
where :
ρH - ρF
(4)
ρH - ρL
ρF
=
final density
ρL
=
density of lighter fluid
ρH
=
density of heavy fluid
a
=
volume fraction of lighter fluid
1-a
=
volume fraction of heavy fluid
Example : To obtain 100 bbl of 10.3 ppg CaCl2 brine by diluting 11.5 ppg CaCl2 brine with
brine weighing 8.5 ppg :
11.5 – 10.3
a =
11.5 – 8.5
= 0.4
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Thus 40 bbl (0.4 x 100) of 8.5 ppg brine plus 60 bbl (0.6 x 100) of 11.5 ppg brine will
provide 100 bbl of 10.3 brine.
9.2.4
Viscosity
Viscosity is a measure of the drag force that a fluid exerts upon a surface past which it
flows. More precisely, viscosity is the viscosity coefficient, which is the ratio of the
tangential frictional force per unit area to the velocity gradient perpendicular to the
direction of fluid flow. The velocity gradient perpendicular to the fluid flow direction is
called the rate of shear strain, or more commonly, simply the shear rate. When the
tangential force is porportional to the fluid velocity, the fluid is said to be Newtonian and
when it is not the fluid is said to be non-Newtonian.
Viscosity is strongly dependent upon the temperature of a fluid, its composition variables,
and to a lesser extent upon surrounding pressure. When the fluid is non-Newtonian its
viscosity is also dependent upon the velocity and the shape of the conduit through which
the fluid is flowing. The flow behavior of completion fluids is often not simple. NonNewtonian flow behavior is exhibited by polymer solutions, emulsions, foams, and muds.
Brines without gel, and hydrocarbons are Newtonian.
The viscosity of a workover fluid decreases exponentially with increasing well temperature
and well temperature normally increases with depth. Therefore, the viscosity of a fluid at
the bottom of the well may be substantially less than at the surface. The graphs of
Appendix A and Appendix B show the effect of temperature on the viscosity for common
workover fluids. A rough estimate of the effect of temperature for any fluid may be
sufficient.
Pressure can also have an effect on fluid viscosity. Directionally, viscosity increases with
increasing pressure. The viscosity increase is proportional to pressure. For brines the
effect is small, on the order of 0.5%/1000 psi. For hydrocarbons it is on the order of
13%/1000 psi.
Viscosity is commonly measured in the oil field using one of two devices. The viscosity of
a fluid may be measured by using either a Marsh funnel or a Fann viscometer.
The Marsh funnel consists of cone terminating in short tube. For an indication of fluid
viscosity, one measures the time it takes for 1500 ml of fluid to drain through the tube at the
bottom (Figure 1). Fresh water will drain in 26 seconds. More viscous fluids will take a
longer time. The Marsh funnel measure of viscosity is only approximate for a number of
reasons. First, the efflux time is also dependent on the fluid density since the fluid head
provides the driving force for efflux. Second, since the head changes over the measurement
time, the flow rate and hence the shear rate also change uncontrollably during the
measurement. Since all polymer containing fluids are non-Newtonian (muds are too), the
viscosity indicated by the Marsh funnel efflux time is some kind of an average “viscosity”
over the shear rate range of the measurement which may or may not be in the shear rate
range of the application. Because of its simplicity, the Marsh funnel nevertheless provides
a useful index of relative fluid viscosity.
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Figure 1. Marsh Funnel. NL Baroid, Manual of Drilling Fluids Technology,
“Mud Testing”, p.5
Figure 2. Fann Rheometer. NL Baroid, manual of Drilling Fluids Technology,
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“Mud Testing,” p.5
The Fann viscometer (Figure 2) provides a more precise measure of fluid viscosity. It
consists of a motor or hand-crank driven pair of concentric cylinders. The outer cylinder
rotates at various constant speeds around the stationary inner cylinder. The space between
the two cylinders is filled with the workover fluid. The torque applied to the inner cylinder
is measured at various speeds and thus at various known rates of shear. From the torques
and speeds with a given gap one may calculate and plot viscosity in centipoise (cp) as a
function of shear rate. Thus, the Fann viscometer not only gives viscosity in accepted units
of viscosity, but also provides the fluid’s viscosity response to shear. The shear rates in
tubing and annuli may be estimated for expected flow rates and then the Fann viscometer
generated plots may be used to provide more precise estimation of the fluid’s effective
viscosity in the downhole application.
9.2.5
Gel Strength
Sometimes a fluid will have a true yield stress which must be exceeded in order for the
fluid to flow. A true yield stress will often be called a gel strength to distinguish it from the
yield point of the Bingham rheological model. Gel strength is properly measured by
applying shear stress infinitely slowly until the rigid structure of the gelled fluid fails. The
shear stress at which the failure occurs is a gel strength or true yield stress. Ideally the
failure occurs at a shearing rate of zero. In practice, gel strengths are only approximated by
observing the peak stress occurring on the sudden application of shear strain at low shear
rates using a Fann viscometer. Muds are the most common oilfield fluids which develop
gel strength on standing. Some high concentration or cross-linked polymer fluids also
develop gel strength.
Gel strength is important for three reasons. First, gel strength must be present if solids are
required to remain suspended in a fluid that is not flowing. High viscosity alone will
simple delay the settling process, but will not prevent it. Second, gel strength determines
the pressure required to reinitiate flow following a no-flow period. Thirdly, gel strength is
desirable if a fluid is intended to thermally insulate an annulus.
A gel strength of 2 to 4 lbgf/100 ft2 is necessary to prevent settling of the barite added to
weight drilling fluids. More gel strength may be required to suspend larger or denser
particles. A gel strength of about 25 lbf/100 ft2 at the application temperature will suppress
thermal convection in packer fluids designed to thermally insulate the tubing-casing annular
space in the most difficult producing or injection situation. Gel strengths of 20 to 40
lbf/100 ft2 are common in muds. In general, a fluid should be chosen to have the minimum
gel strength necessary to solve any given problem requiring gel strength.
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Corrosivity
A completion fluid should not be unduly corrosive to the tubular goods. Corrosion
inhibitors are used to control the corrosion rate. A suitable upper limit of allowable
corrosivity for a completion or workover fluid is 0.05 lb/ft2 (~ 1 mil) per workover.
Preferably, corrosivity should be less than 0.02 lb/ft2 (~ 0.5 mil) per workover. A suitable
upper limit of corrosivity for a packer fluid is 5 mil/yr, but 1 mil/yr is the preferred target.
Corrosivity generally increases with increasing temperature. Corrosion destroys well
tubular goods and insoluble corrosion reaction products can damage the producing
formation if corrosive fluids are allowed to enter the formation.
9.2.7
Solids Content
To avoid formation and perforation plugging, workover fluids ideally should contain no
solids. However, even with the best efforts at cleanliness, fine particles often appear in the
fluids that enter the formation. Particles larger than 5 microns in diameter will bridge on
the “typical” producing formation. Particles up to 5 microns in diameter may cause
plugging deep within the formation’s pore channels. Significantly less plugging results
from particles of less than 1 micron diameter. The use of filters to remove avoidable solids
is encouraged where practical. Perforation damage by solid particles during perforating can
be avoided by perforating with the pressure differential into the wellbore.
9.2.8
Formation Compatibility
Characteristics of the fluid should be tailored to minimize formation damage. Formation
damage may result from interaction or chemical reaction with the formation or connate
fluids. When possible, brine concentrations should be balanced to prevent swelling or
dispersion of clay minerals. Surfactants and other chemicals that can permanently and
adversely change formation wettability should be avoided. Thus, for example, anionic
surfactants should not be used in carbonate formations and cationic surfactants should not
be used in sandstone formations.
A workover fluid should not cause scale precipitation when mixed with formation brine.
Formation of stable emulsions of the fluid and resident crude can be prevented by proper
choice of pH, brine concentration, mutual solvent, or emulsion preventing surfactant.
Chemical additives should be used when required for these purposes. However, one should
attempt to hold the use of additives to a minimum. Indiscriminate use of additives can
cause more problems than they solve.
9.2.9
Fluid Loss
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Fluid-loss additives may be required to prevent loss of excessive quantities of fluid to the
formation. One method of preventing excessive fluid loss to the formation is to include
properly sized acid-soluble particles such as calcium carbonate (CaCO3) in the workover
fluid. These particles bridge at the formation face and form a filter cake that prevents
damaging particles from entering the formation. An acid wash can thereafter dissolve the
filter cake. In many cases oil-soluble resin particles may be substituted for CaCO3. In
either case, polymer viscosifiers are usually also required for an effective fluid-loss control.
9.2.10
Cost
The most economical fluid consistent with the workover objectives and formation
protection should be used. Cost should not, however, outweigh the goals set in a given
workover or completion. For very high-density fluids, which tend to be expensive, fluid
recovery and re-use is an additional consideration.
9.3
WATER-BASE FLUIDS
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Source Of Water
When water-base fluids are to be used, the first consideration is the source of water. Two
factors are important when selecting a source of water. The water must contain a minimum
of particulate matter and its chemistry must be compatible with that of the formation and
connate water. It must have a high enough salinity to prevent clay swelling and dispersion.
And, precipitates should not form when the water mixes with formation water. The most
common sources of water are field or lease saltwater, seawater, bay water, or fresh water
(such as from a municipal water supply).
Field or lease saltwater is the most common workover fluid in use today owing to its low
cost, availability, and solids-free nature. If it is clean, formation saltwater is ideal from the
standpoint of minimizing formation damage caused by swelling or dispersion of clays in
sandstone formations.
Although saltwater from settling tanks or heater treaters is frequently considered to be
natural water from the formation, it often contains treating chemicals and fine particles of
oil, clay, silt, paraffin, asphalt, or scale. Filtered formation saltwater may still contain oiltreating surfactants (emulsion breakers), which can cause wettability or emulsion problems.
Seawater or bay water is often used in coastal areas because it is readily available. But it
frequently contains clays, other fines, and marine microorganisms that cause plugging.
Water from such a source should therefore always be filtered before use. If used as a
packer fluid, an appropriate biocide should be added. Depending on the salinity of bay
water, it may be necessary to add NaCl or KCl to prevent clay disturbance.
Fresh water is often desirable as a basic fluid because of the difficulty of obtaining
sufficiently clean sea or formation water. However, it is not sufficient that the fresh water
be clean at its source. Care must also be taken to ensure that the tanks transporting and
storing it are clean as well. Salt can be added to obtain the required density and clay
stabilization. When clean brine is available at low cost, purchasing it prepared may be
preferable to mixing it on location.
9.3.2
Formation Damage
One concern with water-base fluids is the formation damage that can result from contact
with swelling clays, such as montmorillonite. Laboratory investigations have shown that
contacting these clays with water fresher than connate can severely reduce formation
permeability. This damage is especially severe when the water is very fresh. Laboratory
tests have also demonstrated that this type of formation damage can generally be prevented
by adding 1% by weight of calcium chloride (CaCl2), 3-5% by weight of sodium chloride
(NaCl), or 2-3% of potassium chloride (KCl) to the water.
Emulsion and formation wettability problems may result either from activation of natural
surfactants in the crude by pH changes or particular cations (e.g., calcium), or from
contamination of the workover fluid by surfactants from another source. When the water
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comes from a field source, the contaminating surfactants are usually treating chemicals
such as surfactants, corrosion inhibitors, and emulsion breakers (frequently formation oil
wetters). It is far better to prevent emulsion and wettability problems than to correct them
after the fact. An unsatisfactory emulsifying or wettability situation can usually be
corrected by the addition of a small amount (0.1%) of the proper surfactant.
9.3.3
Fluid Loss Agent
Fluid loss agents are often necessary to prevent excessive loss of an expensive or difficultto-unload fluid to the formation. They may also serve to prevent formation damage by
particulate debris, polymer viscosifiers, and salts that may be present in the workover fluid.
The rate of fluid loss to a formation is usually controlled by the fluid’s viscosity and by a
filter cake of solid additives in perforation tunnels or on the formation face. Reliance on
viscosifiers alone is usually not preferred since the effectiveness of this measure relies upon
relatively deep invasion of the formation by the polymer. Permeability damage can result.
Although this damage can be reduced by back-flowing and the use of breakers, polymer
removal is often incomplete so that some formation damage remains.
Ideally, fluid loss should be controlled at the formation face. This can be accomplished by
adding particulate matter of the proper size, shape, concentration, and particle-size
distribution to the workover fluid. Properly chosen solids will form an effective filter cake
on the formation face without invading the pore space. Polymers can be used to plug the
filter cake and obtain a thin, impermeable filter cake on the formation face.
A filter cake should form quickly so that the movement of fluids and polymer into the pore
space is minimized. A filter cake so formed should be removable primarily by backflowing. The particulate matter chosen should be degradable by acid or solvent, and the
polymer should likewise be degradable by an incorporated breaker or overflush.
A technique often used effectively to control lost circulation or to kill a well is the
circulation of a pill. A pill is a slug of 10 to 15 bbl of fluid containing a high concentration
of polymer and fluid loss solids. Successively coarser grades of fluid loss solids are added
until fluid loss ceases. This establishes an initial bridge. The polymer and particle
concentrations and fluid loss particle size can then be reduced. When and if additional
cleaning or chip lifting capacity is needed, another pill can be circulated.
Fluid-loss solids are available individually and as various packages supplied by service
companies. They are usually composed of calcium carbonate, which is decomposed by
acids. Various oil-soluble resin particulates are also common in present-day operations.
Calcium carbonate is available in several size ranges designated as Micro (400 mesh), Fine
(200 fresh) and Medium (70 mesh). For most formation pore sizes, the 200-mesh particle
size should be used. CaCO3 is completely soluble in hydrochloric acid (HCl). When used
in conjunction with HEC to provide carrying capacity and to further reduce the
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permeability of the bridge, excellent fluid-loss control is provided. Almost perfect
permeability recovery then occurs following contact with HCl. In a field situation,
however, acid contact with the bridged CaCO3 cannot always be assured and some
permeability loss may remain.
A satisfactory CaCO3 fluid can be prepared by adding 5 to 15 lb/bbl of 200 mesh CaCO3 to
a solids-free salt solution containing 0.25 to 0.50 lb/bbl biopolymer. This mixture should
provide effective fluid loss control and sufficient viscosity to circulate out sand or silt.
Higher concentrations of polymer may be required to lift large cuttings or shale if
circulating capacity is limited.
Oil-soluble resins are available in the graded sizes most often needed for effective bridging
action. Although quite effective brines, they are quickly removed by low concentrations
(2%) of oil if they can be effectively contacted by it. If difficulty is encountered in
recovering permeability after the use of resins, a wash or overflush of an aromatic solvent
(such as xylene or toluene) can be used rather than diesel or crude, since the dissolution rate
in these solvents is many times faster. Temperature stability is of concern because some
resins tend to soften and melt even at relatively low temperature. Softening and melting
temperatures are sometimes drastically lowered by the presence of small amounts of
hydrocarbon, corrosion inhibitor, surfactants, and solvents. If the softening and melting
temperatures are reduced below the treating temperature, the oil-soluble solids will not
effectively control fluid loss.
9.3.4
Polymer Viscosifiers
A number if additives are available to provide viscosity, thereby increasing the lifting,
carrying, and suspending capacity of water-base workover fluids. Some also function to
help reduce fluid loss. Both natural and synthetic polymer additives have been used in
completion fluid formulations. Among them are : guar gum, starch, XC-biopolymer
(Xanthan gum), hydroxyethyl cellulose (HEC), carboxymethyl cellulose(CMC), and
polyacrylamides. The appropriate concentration of any of these depends on the desired
viscosity, the type and concentration of the salts present, and the temperature. The
possibilities are numerous, and service company and vendor literature should be consulted
for details. Each type of polymer may be made with different molecular weights, different
derivatization, different degrees of substitution, and different types and degrees of
crosslinking. No standards exist and the properties of polymer of the same generic type
vary considerably depending on their source. Nevertheless, generalizations are possible.
Table 4 compares typical properties of polymer viscosifiers which have been used in
completion fluid formulations. Not all of them are currently recommended.
Table 4
Characteristics of Water Soluble Polymers used in Completion Fluids
Polymer
Type
Viscosity
Filtration
Low Shear
Acid
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HEC
XC-Polymer
Guar
CMC
Starch
9.3.5
Nonionic
Anionic
Nonionic
Anionic
Nonionic
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Development
Control
Suspension
Properties
Solubility
Stab.
Tolerance
Recommendation
Excellent
Fair
Excellent
Good
Poor
Poor
Poor
Poor
Good
Good
Poor
Excellent
Poor
Fair
Poor
Excellent
Good
Fair
Poor
Poor
250°F
250°F
250°F
250°F
250°F
Excellent
Fair
Good
Poor
Good
Yes
Yes
Some
No
No
Polymer Applications
In most applications, polymer solutions are prepared to provide viscosity in some desirable
range at certain shear and temperature conditions dependent upon the particular application.
The polymer solution must retain the required viscosity for the working time of the
application. Thereafter, it is often desirable that the polymer degrade so that the solution
viscosity breaks back to the brine viscosity at some time after the work is finished. Thus,
considerations of concern to the engineer are (1) estimation of the viscosity required for the
application, (2) estimation of the shear conditions prevailing in the application, (3)
estimation of temperatures relevant to the application, (4) selection of the polymer, (5)
specification of the polymer concentration to be used accounting for the effects of
temperature, shear rate, brine type and brine density, (6) estimation of the working time,
and (7) providing breaker chemical at a concentration which will allow sufficient working
time and still break the polymer in a reasonable length of time at time at well conditions.
9.3.6
Mixing Polymers
A consideration of operational importance is the rate at which polymer can be put into
solution. When solid polymer particles are added to a solution they first imbibe water,
swell, and finally disperse into molecular solution. In high density brines this process can
take many hours. This process proceeds most quickly if the solid particles are quite fine
and remain dispersed without agglomerating while dissolution proceeds. If agglomeration
occurs, the “fish eyes” or “gel balls” that result may not dissolve at all and may pose a real
threat to the perforations.
There are a number of product and handling tricks that can be used to avoid this problem.
First, some polymers are prepared with surface treatments that prevent the perimeter of
individual polymer particles from rapidly swelling and becoming tacky until the whole
particle has imbibed water to its core. These preparations are a distinct improvement over
plain polymers.
Second, increasingly polymers are being supplied in highly concentrated, prehydrated
solutions emulsified into a thin oil to make them manageable. These dispersions hydrate
rapidly when added to brines under high shear conditions. Of course, they cost a little more
in this form.
Third, solid polymer may be first dispersed into and wet with a water soluble solvent in
which it is not soluble. The slurry formed in this way may then be added continuously to
brine tanks as they are rolled without fish eye formation. A good solvent for this purpose is
often ethylene glycol (antifreeze). It is sufficiently viscous to suspend polymer particles
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well and wets most polymers without dissolving them. Use of ethylene glycol slurries has
been observed to reduce hydration times from several hours to fifteen minutes in some
instances. The small quantity of ethylene glycol has very little effect on other solution
properties.
Fourth, in field operation, it has been found that slow addition of the polymer with
simultaneous vigorous agitation of the water will greatly increase the surface area per
pound of polymer exposed to water and eliminate fish eye formation in many cases.
Fifth, regardless of the surface preparation and handling, most polymer solutions hydrate
more rapidly at elevated temperature (starch is a notable exception). The use of applied
heat or utilization of the heat of mixing of the salt solutions can accelerate polymer
hydration. Heating is most often required when polymers are added to heavy brines.
Solids salts should be added to polymer solutions. If this is done, polymer will come out of
the solution and coat the salt particles thus halting their dissolution. The resulting mess can
be extremely difficult to handle.
One way of avoiding critical polymer mixing problems during operations is to use and stock
prepared polymer/brine concentrates. The required completion brine is then prepared by
simply diluting the concentrate to the required concentration with clean completion brine.
The mixing is instantaneous and there is no hydration time to delay operations. The
polymer/brine concentrate stock can be purchased prepared or can be made up and
maintained separate from other operations.
9.3.7
Polymer Breakers
Another consideration is the working time and breakback characteristics of the workover
polymer system. Generally, these characteristics will be determined by the type and
amount of breaker chemical added to the polymer solution. However, most polymers in
common use will degrade by hydrolysis at some finite rate of their own accord. The
degradation rate is, of course, greater at higher temperatures.
Chemicals added to destroy completion fluid polymers in a timely fashion are acids,
enzymes, peroxides, or other oxidizing agents. When an acid is used, it is most frequently
hydrochloric acid although other acids may be used.
Small amounts of various enzymes may be used to accelerate hydrolysis also. Enzyme
breakers are effective for many natural polymers up to temperatures of about 140°F.
Peroxides, very typically ammonium persulfate, are effective in degrading a variety of
polymers.
When all else fails strong oxidizing agents can be added to degrade most polymers.
Common oxidizing agents used to degrade completion fluid polymers include hydrogen
peroxide, ammonium persulfate, and sodium hypochlorite (bleach).
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Finally, when it is necessary to prepare polymer solutions in high density brines, it is often
necessary to heat the solutions to get the polymer to hydrate in a reasonable length of time.
When heat must be applied or when the solution is still hot from preparing the original
brine, the addition of breaker chemicals should be delayed until the solution has cooled to
prevent premature break-back of the polymer.
9.3.8
Polymer Degradation
Many of the natural polymers are susceptible to degradation by microorganisms with which
they may inadvertently become inoculated. Sources of degrading bacteria may be polymer
processing, make up waters, tanks, transport tankage, and the air. When solutions of
natural polymers must be held for more than 24 hours prior to use, biocides should be
added to prevent bacterial growth which may cause loss of viscosity and generate formation
plugging by-products.
Atmospheric oxygen can significantly degrade polymer solutions. When polymer solutions
must be rolled for a long time to dissolve the polymer, a large quantity of air becomes
entrained in the solution. The entrained air rapidly replaces dissolved oxygen allowing
further degradation of the polymer.
Polymer solution viscosity can be significantly reduced by this air oxidation process.
Oxidation inhibitors are beneficial when mixing times of surface times are long. When
oxidation inhibitors are used, their presence must be taken into account when the type and
amount of breaker chemical is selected.
9.3.4
Polymer Residue
It has been frequently observed that some insoluble residue remains in brines following the
break-back of the common polymers. The amount of residue left is somewhat dependent
upon the break mechanism and the chemicals used, but it is mainly dependent upon the type
of polymer used. Guar polymer has the most residue and HEC has the least.
9.4
CLEAR BRINES
9.4.1
Density Ranges
It is often necessary to prepare a brine of increased density to contain formation pressures.
Table 5 shows the operational density range of salts that may be used to increase the
density of water and can also be adequately inhibited. Appendix A contains data on
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material requirements and physical properties relative to the solutions shown in Table 5.
The upper limits of solution density for each salt listed in Table 5 are established either by
the solution saturation properties for the minimum operating temperature or by the freezing
point.
Table 5
Density Range of Salt Solutions
Density (ppg)
9.4.2
Salt Solutions
8.3 – 9.7
Potassium chloride
8.3 – 9.8
Sodium chloride
9.8 – 11.0
Sodium chloride/calcium chloride
8.3 – 11.7
Calcium chloride
11.7 – 15.1
Calcium chloride/calcium bromide
15.2 – 19.2
Calcium chloride/calcium bromide/zinc bromide
Freezing And Crystallization
Figure 3 (also Figure-A-1) shows the freezing points and crystallization points of common
brine solutions as a function of solution density. As Figure 3 illustrates, brine solutions are
characterized by a minimum freezing composition called the eutectic composition (or here
perhaps “eutectic density”). The minimum obtainable temperature is called the eutectic
temperature. Solutions less dense than the eutectic density freeze to an ice structure on
cooling. Solutions more dense than the eutectic density crystallize on cooling. As
crystallization proceeds salt crystals form and separate from the solution. In Figure 3 note
that CaCl2 solutions crystallize at temperatures above 60°F if their weight exceeds about
11.7 ppg. When operations are conducted at less than 60°F, the upper weight shown in
Table 5 may be unattainable.
9.4.3
Potassium Chloride
Potassium chloride can be mixed to provide densities up to about 9.7 ppg at 85°F. Figures
A-2, A-3, A-4, and Table A-1 of Appendix A give material requirements, physical
properties, density vs. temperature, and viscosity vs. temperature for KCl solutions.
9.4.4
Sodium Chloride
Sodium chloride can be mixed to provide densities up to about 9.8 ppg. Figures A-5, A-6,
A-7, and Table A-II of Appendix A give material requirements, physical properties, density
vs. temperature, and viscosity vs. temperature for NaCl solutions.
9.4.5
Sodium Chloride/CalciumChloride
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A combination of sodium chloride and calcium chloride can be utilized for weights ranging
from 9.8 to 11.0 ppg. Although CaCl2 might be used alone, the use of less expensive NaCl
as a companion weight additive reduces the cost of the fluid.
Figure A-8 shows material requirements for preparing NaCl/CaCl2 compositions. It should
be realized that further addition of either salt reduces the solubility of the other, so that the
addition of CaCl2 to a saturated NaCl water mixture will cause NaCl to precipitate out of
solution. Figure A-8 gives the actual composition of all mixtures of sodium chloride and
calcium chloride that freeze at 60°F. In this way the maximum amount of NaCl has been
used at minimum cost. Table A-III and Figure A-9 of Appendix A show the various
physical properties and density vs. temperature for NaCl/ CaCl2 solutions.
Figure 3. Freezing and crystallization of brines
9.4.6
Calcium Chloride
Calcium chloride solutions can be prepared with densities as high as 11.7 ppg. Figures A10, A-11, A-12, and Table A-IV show material requirements, physical properties of interest,
density vs. temperature, and viscosity vs temperature for CaCl2 brines. The brine can be
made up on location using dry CaCl2 mixed with fresh water; or previously prepared brines
can be obtained. Dry CaCl2 is available in two grades, 77% minimum and 94% minimum
CaCl2. The substances to be added must be based on the grade being used. The 94%
minimum grade is preferred, since fewer unidentified solid particles are thereby added to
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the fluid. Previously prepared brines are usually less expensive, with a possible saving in
rig time.
Some solutions of CaCl2 have extremely low freezing points (e.g., -60°F at 10.7 ppg). But
at very high densities the crystallization point is quite high (e.g., +52°F at 11.7 ppg).
Lowering the temperature below the saturation temperature for the particular weight of
saltwater being used will cause CaCl2 to precipitate out of solution. This problem can be
eliminated by never exceeding the density limit for the minimum temperature to be
encountered.
When CaCl2 brine is prepared, precautions should be taken to keep the dry chemical dust
out of eyes and lungs. Rubber protective clothing should be worn to prevent skin damage.
When mixing high concentrations of CaCl2 considerable heat is generated, and precautions
should be taken to prevent burns from hot equipment.
9.4.7
Calcium Chloride/Calcium Bromide
Calcium chloride/calcium bromide (CaCl2/CaBr2) solutions can be prepared to give
solution densities between 11.7 and 15.1 ppg. These are solids-free fluids and have low
corrosion rates, which can be inhibited even lower. The toxicity is low enough to allow use
of these solutions in marine waters. Tables A-V and A-VI, together with Figures A-13
through A-16, show material requirements, density vs. temperature, and viscosity vs.
temperature for CaCl2/CaBr2 solutions at minimum cost. The compositions given contain
the maximum amount of CaCl2 consistent with the density required.
One limitation in the use of these various combinations, as Figure 3 illustrates, is their high
crystallization points. The crystallization point can be reduces below the current ambient
temperature by increasing the CaBr2 concentration and also the cost. These solutions are
very expensive. A 15.1-ppg CaCl2/CaBr2 brine costs about 25 times more than 10.0 ppg
CaCl2 brine does. If such brines are used, provision for their recovery and release is a
consideration.
When CaCl2/CaBr2 brine is prepared, precautions should be taken to keep dry chemical dust
out of eyes and lungs. Rubber protective clothing should be worn to prevent skin damage.
Because mixing high concentrations of CaCl2/CaBr2 generates considerable heat,
precautions should also be taken to prevent burns from hot equipment.
9.4.7
Calcium Chloride/Calcium Bromide/Zinc Bromide
Calcium chloride/calcium bromide/zinc bromide (CaCl2/CaBr2Znbr2) brines with densities
between 15.2 and 19.2 ppg can be prepared. Mixing requirements for CaBr2/ZnBr2 brine
mixtures having low freezing temperatures are given in Tables A-VII and A-VIII. Mixing
requirements for minimum cost, nearly constant-freezing brine mixtures containing
CaCl2/CaBr2/ZnBr2 are given in Tables A-IX and A-X. These mixtures crystallize between
16°F and 64°F. Density dependence on temperature is given in Figure A-17. Solution
viscosities are presented in Figure A-18. Corrosion behavior is illustrated in Figure A-19.
The engineer must tailor the solutions to the individual well given due consideration to
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environmental conditions, economy, density, crystallization point, and corrosivity.
Crystallization point is lowered by increasing concentrations ZnBr2 and CaBr2, so that the
highest crystallization point of a maximum-density composition is about 16°F. Conversely,
increasing the percentage of CaCl2 to achieve lower densities with the most economical
composition raises the crystallization point toward the 65°F limit.
Previously, there was considerable concern for the corrosivity of zinc containing brines
based on the behavior of zinc chloride solutions which are quite acidic. The fear of high
corrosiveness was subsequently found to be exaggerated. As the data of Figure A-19
demonstrates CaCl2/CaBr2/ZnBr2 brines are not unacceptably corrosive at temperatures
below 250°F. The fluid is slightly acidic and requires inhibition to control corrosion at
elevated temperatures and high ZnBr2 loadings. The corrosion rate dramatically increases
when the brine density exceeds 18 ppg. However, these fluids are significantly less
corrosive than CaCl2/ZnCl2 brines, and effective corrosion inhibitors are available to
control corrosion rates for most applications. Nevertheless, zinc-rich brines should not be
used as packer fluids.
The major drawback to the use of these fluids is their cost. An 18-ppg CaCl2/CaBr2/ZnBr2
brine is about 81 times the cost of a 10-ppg CaCl2 brine. However, these solutions provide
the only known way of obtaining solids-free fluid densities of the aforementioned
magnitudes while simultaneously holding corrosion rate, economics, and crystallization
point at low values. Fluid recovery, reuse, and resale should certainly be considered.
These fluids can be toxic to fish and certain shellfish. Prolonged exposure of human skin to
them can cause irritation or chemical burns. Eye contact can cause serious damage and loss
of sight. Protective rubber clothing, chemical goggles, and other precautions for keeping
dry chemical dust out of eyes and lungs are necessary.
9.4.8
Sodium Bromide
In some cases it is found that a brine containing divalent cations such as Ca++ or Zn ++ can
react with formation water anions such as bicarbonate to produce a precipitate when
workover fluid and formation water mix. When this occurs the workover fluid may damage
the well. This is characterized by an abnormal production decline curve following the
workover. Sodium bromide solutions can be prepared with densities up to 12.4 ppg to
produce clear brine solutions that avoid this problem. Table A-XI gives the material
requirements and freezing data for sodium bromide solutions. The freezing temperature of
sodium bromide solutions can be depressed to as low as – 40°F for arctic service by the
addition of ethylene glycol. Composition and properties of crush a low freezing mixture is
given in Table A-XII. When ethylene glycol is added, it is advantageous to use a ratio of
sodium chloride of 3:1 ore greater in order to avoid sodium chloride solubility problems.
Figure A-20 gives the density versus temperature relationship for NaBr brines. NaBr brines
of all densities are characterized by low corrosivity comparable with NaCl brines at the
same temperature. These brines are quite expensive and winterizing with ethylene glycol
makes them even more so. The cost of their use must be justified by prolific production
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and a lack of viable non-damaging alternatives.
9.4.9
Brines To Avoid
Calcium nitrate (Ca (NO3) 2) and calcium chloride/zinc chloride brines are two additional
solutions worthy of mention, although their use is not recommended.
(Ca (NO3)2)/CaCl2 solutions can be prepared with densities as high as 14.3 ppg. However,
Ca (NO3)2 is expensive, corrosive, and a potentially dangerous oxidizing agent. If Ca
(NO3)2 is used in a workover fluid, it should be thoroughly rinsed from the tubular goods
after use, and any spilled salt solution should be thoroughly rinsed away from the surface
facilities. Contact of petroleum liquids with the dry salt can produce a fire. It should
certainly not be used in packer fluid formulations.
Calcium chloride/zinc chloride solutions can provide fluid densities as high as 17 ppg.
However, these solutions are expensive, unacceptably corrosive, and sometimes
unacceptably toxic as well. Solutions containing ZnCl2 are inherently acidic at higher
densities. This pH cannot be lowered by the addition of caustic, without precipitating zinc
hydroxide. Currently there are no corrosion inhibitors capable of satisfactorily inhibiting
these solutions. Under no circumstances should CaCl2/ZnCl2 brines be used as packer
fluids. If they are used at all, they should be completely circulated out of the wellbore prior
to final completion.
9.5
EXAMPLE : BRINE COMPOSITION
9.5.1
Problem 1
A workover is planned with the following objectives :
(1) pull a failed packer,
(2) wash large formation and cement debris from wellbore,
(3) replace failed packer
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Choose a brine workover fluid and specify the required surface density.
Relevant well data is as follows:
Depth = 10,000 ft
Geothermal Surface Temperature = 80°F
Static Bottom Hole Temperature = 270°F
Measured Static Bottom Hole Temperature = 5635 psi
Fracture Gradient = 0.72 psi/ft
The supervisor likes 300 psi overbalance.
9.5.2
Average Fluid Density
Part A. Calculate the average fluid density required to balance the formation with 300 psi
overbalance.
Using Equation 3,
ρ (ppg) =
BHP + Overbalance (psi)
0.052 Depth (ft)
find the average fluid density required.
ρ =
9.5.3
5635 + 300
= 11.4 ppg
(0.052)(10,000)
Fluid Type
Part B. Select the fluid type.
Examination of Table 5 and Figure A-1 leads to the conclusion that calcium chloride brine
can be prepared with densities in the 11.4 ppg range.
9.5.4
Required Surface Density
Part C. Find the surface density of the chosen brine that gives the required average
density.
Using the mid-depth method, estimate the fluid surface density required to provide an
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average density sufficient to overbalance the well by a design value of 300 psi.
To correct the 11.4 ppg required average density back to surface conditions, enter Figure
A-11 for CaCl2 brines with the mid depth well temperature of 175°F and interpolate using a
ruler o estimate the required 60°Fdensity. Doing so, find that the required surface density is
about 11.7 ppg. To the nearest 0.1 ppg one may now chosen to use an 11.7 ppg CaCl2 brine
for the workover.
Since the small correction for the compression of the brine under well pressures has been
neglected, the choice is conservative.
9.5.5
Problem 2
If in the above problem the ambient temperature is a cool 35°F, what brine should be
chosen?
9.5.6
Freezing And Crystallization
Referring to Figure A-1, note that 35°F is well below the crystallization temperature of an
11.7 ppg CaCl2 brine. It is clear that either a CaBr2 brine or a less costly CaCl2/CaBr2 brine
mixture can be prepared which will not crystallize at 35°F. Referring to Figure A-13
CaCl2/CaBr2 brines we can confirm that our required average density of 11.41 ppg will be
provided by an 11.7 ppg CaCl2/CaBr2 brine also.
9.6
WEIGHTED BRINES
Sometimes economics precludes the use of expensive clear brines when fluid density in
excess of 11 lb/gal is required. One approach to overcoming this problem is to suspend
particulate solids (inherently high density) in a liquid of relatively low density to produce a
net high-density fluid. With proper fluid-loss control measures these fluids may sometimes
be used without severe formation damage. Any solids used must be removable by an
inexpensive treatment following the use of such a fluid.
9.6.1
Weighting Agents
Typically, 200-mesh calcium carbonate, iron carbonate, barium carbonate, or ferric oxide
(all acid soluble) is used as weighting solids. Viscosifiers of the types discussed earlier
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provide the suspending power. The most common system used is CaCO3 with HEC or
biopolymer.
9.6.2
Amount Of Weighting Agents
The following equations estimate the weight of solids needed to obtain a certain fluid
density and the resulting increase in fluid volume.
The amount of weighting material required is given by Equation (5).
ρf - ρj
W = K
C - ρf
(5)
The increase in volume is given by Equation (6)
V = W/K
(6)
In these equations
W
= weighting material needed, lb/bbl of initial fluid
ρf
= fluid density desired, lb/gal
ρj
= density of available brine, lb/gal
∆V
= volume increase, bbl/bbl initial fluid
K, C
= constants for weighting material from Table 6. They are the
density of the weighting material in bbl/and lb/gal respectively.
Table 6
Specific
Gravity
Density Increase
Obtainable
(ppg)
Calcium carbonate
2.7
Iron carbonate
Weighting
Material
Equation Constants
K
C
3.5
945
22.5
3.85
65
1348
32.1
Barium carbonate
4.43
8.0
1551
37.0
Ferric oxide
5.24
10.0
1834
43.7
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Application
Based on the above relations, 11.5 ppg CaCl2 brine would require 150 lb/bbl of CaCO3 to
prepare a 13.0 ppg fluid. The volume increase would be 16 bbl/100 bbl of initial brine.
Adequate suspension qualities would probably require 0.5 to 1.0 lb/bbl of XC-biopolymer.
Settling should be checked before putting the fluid in the hole. If settling occurs, more
polymer is required.
For effective fluid-loss control, some of the CaCO3 should be larger than 200 mesh.
Suspension improves, however, as particulate size decreases. In the preferred approach,
initial fluid-loss control should be established with a pill of graded CaCO3 , after which 200
mesh particles can be used for density requirements.
9.7
WATER-BASE MUD
Economics and availability sometimes suggest the use of conventional water-base mud
rather than weighted brines when completion fluid weights greater than 11.0 ppg are
required. Indeed, until fairly recently water-base muds were used extensively as completion
and workover fluids. The use of mud is not recommended, however. Clear fluids are
always preferred to mud if at all possible. Mud filtrate contains clay thinners and
dispersants, plus a high concentration of fine solids known to cause irreparable formation
damage, both within and on the face of the formation. Mud solids form tough filter cakes
within perforation tunnels which are difficult to remove. Long time exposure to well
conditions often results in chemical and colloidal decomposition of the mud, and corrosion
of well tubulars. Nevertheless, occasions arise when a water-base mud must be used in a
completion or workover operation. Some consideration of the likely consequences is
desirable.
9.7.1
Composition
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Workover and completion muds have basically the same composition as drilling muds.
Water-base muds can be formulated with densities ranging from 9.0 to 21.0 ppg. There are
many kinds of water-base muds, but all water-base muds are composed of aqueous fluids
and weighting solids, with clays as the major suspension material. The clays function to
increase viscosity and in forming impermeable filter cakes on exposed formations. When
densities under 10.0 ppg are required, bentonite clay is used to provide both viscosity and
weight. Bentonite is sodium montmorillonite. It gives higher viscosities than other clays
when mixed with fresh water. When higher densities are required, barite, a commercial
grade of barium sulfate, is usually the solid weighting material chosen. Bentonite can
provide the gel strength to suspend the barite in fresh waters and the clay attapulgite may be
chosen to provide viscosity and gel strength when salt waters are used in the mud. Mud
formulations contain thinners and dispersants to control mud properties, as working
conditions require.
9.7.2
Economics
From strictly an economic standpoint water-base mud would appear to be an ideal
completion/workover and packer fluid. They are much less costly than high density clear
brines and they are nearly always present at completion time. For example, the cost of a
14.0 ppg calcium bromide brine is about five times the cost of a 14.0 ppg barite mud.
9.7.3
Damage
Plugged perforations and formation damage are two reasons for the fall of water-base muds
from favor as completion fluids. Muds are designed to have low fluid loss. This is
accomplished by the mud solids which form tough filter cakes. The fluid loss properties of
mud that are desirable during drilling have been shown to be most undesirable following
perforating. Mud solids are not entirely acid soluble and often cannot be backflowed from
perforation tunnels. Considerable pressure drop is required to remove mud from
perforation tunnels and all mud is not removed even then. In some lab tests thousands of
pounds per square inch of reverse pressure differential is unable to remove tough
dehydrated mud plugs. When one or two perforations in a completion do break down, the
pressure drop required to break down remaining plugged perforations is frequently no
longer attainable.
If muds or potentially damaging fluids must be used as the completion fluid, an effort
should be made to hold exposure times and filtration pressure to a minimum. Perforating
should be done in brine or oil if possible. If muds must be used, perforating should be done
through tubing with differential pressure into the wellbore.
In new wells contact of mud with newly exposed formation can be avoided by pumping the
primary cement plug down with saltwater, oil, or acid. Mud residue can be circulated out
of the casing with the production tubing string before perforating. Through tubing
perforating with differential pressure into the wellbore can then be done in a cleaner fluid.
However, once mud solids are inside the production casing, complete removal may be
difficult.
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If the well is already perforated and mud has been used as a workover fluid, the mud may
be removed by circulating out with a light oil while the production string is in place. The
light oil serves to reduce the hydrostatic head inducing the well to flow and thereby
hastening the removal of mud from plugged perforations. The main objectives of this
procedure are to avoid the use of mud as a packer fluid and to initiate production without
the necessity of swabbing. If some perforations remain plugged following light oil
circulation, then swabbing, surging, or a nitrogen blow down may be used to increase the
perforation pressure differential to dislodge the perforation plugs. Hydrofluoric acid can
dissolve mud components in plugged perforations. A hydrofluoric acid wash or injected
volume can be used to unplug perforations.
One should keep in mind that when mud is used as a packer fluid, future contact of mud
with productive perforations has been built into the well. If the packer is unseated or a
tubing leak occurs at a future time, perforations will be damaged and a stimulation
treatment will be required.
9.7.4
Stability
The long term stability of a mud is important when the mud will be used as a packer fluid or
as an external casing pack above the top of cement. When long term installation is planned,
the mud should be cleaned up and conditioned. Adjusting the pH to a 48-hour stabilized
value between 10.5 and 11.5 will increase the chance of long term stability. Unconditioned
mud pH tends to drop below the protective level of 9.5 fairly rapidly. As temperature rises
above about 200°F, the pH change becomes quite rapid. The pH change causes loss of mud
properties and increased incidence of corrosion phenomena. Reactions of the free alkali
with clay and other siliceous minerals in the mud tend to cause excessive gelation or may
cause the solids to settle. Excessive gelation may prevent future circulation of the fluid rom
the tubing-casing annulus or even prevent future movement of the tubing and packer.
Settled solids prevent unseating of the packer at a future time.
9.7.5
Corrosion
Water-base muds are highly conductive and contain components that can be decomposed to
corrosive agents. Many drilling mud additives thermally degrade upon prolonged exposure
to high temperatures to form carbon dioxide and hydrogen sulfide, both of which are
corrosive. Bacterial activity in water-base mud can cause breakdown of organic additives
to form corrosive organic acids, carbon dioxide, and soluble sulfide. Lignosulfonate, and
sulfate containing solutions can react electrochemically at metal surfaces to form sulfide
even at moderate temperatures. Corrosion is a special concern when water-base mud is to
be used as a packer fluid. The same acid/base reactions that tend to destabilize water-base
mud with time and temperature also tend to enhance the rate of corrosion. Even when an
effort is made to remove mud from the well some portion of the mud will remain in contact
with tubular components. Some will commingle with subsequent packer fluids. Unless
corrosion inhibition is 100% effective, corrosion reactions will proceed.
Serious thermal degradation of drilling mud chemicals will normally not occur at
temperatures below 300°F. Earlier recommendations for packer fluids were based on
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avoiding these conditions. Drilling mud chemicals known to degrade at low temperatures
should not be used in packer fluids.
Certain mud additives are susceptible to attack by sulfate reducing bacteria.
Lignosulfonates, soluble sulfates, and even barite can be reduced by the bacteria under the
proper conditions to form hydrogen sulfide. The acidity formed by the bacterial action
increases the corrosion rate and causes gelation and settling. Metal sulfides are formed by
the combination of the reaction of hydrogen ion with exposed metal and the reaction of
sulfide ion with the metal ions released during the corrosion reaction. The hydrogen
molecules formed enter the metal matrix causing hydrogen embrittlement in high strength
steels. Hydrogen embrittlement in combination with sulfide scale formation is also known
as sulfide stress cracking.
Laboratory evidence shows that sulfide can be formed electrochemically when small
amounts of sulfur containing organic additives are present. Serious corrosion and
embrittlement of high strength tubulars can result. If a corrosion cell can form on tubing or
casing walls with enough potential to release hydrogen (about 0.4 volt), then sulfur
containing organic mud additives can be reduced to sulfide even at room temperature.
These conditions can exist downhole, since the potential between mill scale and pipe wall is
reported to be on the order of 0.5 volt. Electrochemical reaction is the suspected cause for
failures of N-80 and higher strength casing strings.
Corrosion inhibitors are sometimes used with water-base muds.
However, their
effectiveness is doubtful because the corrosion inhibitor tends to adsorb on the very great
surface area of the mud solids making it unavailable for adsorbtion on tubular goods.
9.7.6
Applications
Water-base mud can be used to advantage in certain working fluid applications. Mud can
be used as an emergency well kill fluid. A wide range of densities are possible and mud has
excellent fluid loss characteristics. Its fine viscosity characteristics make mud an excellent
choice for removing large cuttings and debris from the well during well clean-out, milling,
drilling in, and other completion and recompletion operations. Needless to say, mud is the
cheapest and most satisfactory fluid to use in a well that will be abandoned following the
workover.
The use of a water-base mud as a packer fluid, while not recommended, is acceptable in
shallow wells with normal pressures and low temperatures. No high strength steel should
be involved and formation temperature should not exceed 300°F. The mud should be
sterilized by treatment with biocide and a stabilized pH between 10.5 and 11.0 should be
attained. The mud should be tested to determine that it contains no significant amount of
sulfide at the same time of placement. Water-base mud is not acceptable as a packer fluid
elsewhere. Water-base muds cannot be relied upon for protection of external casing
because corrosive formation waters may be miscible with the casing pack. A water-base
casing pack cannot be expected to remain sterile or highly alkaline.
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Water-base muds are not recommended as perforating fluids.
9.8
HYDROCARBON FLUIDS
9.8.1
Applications
Hydrocarbon fluids are non-corrosive, do not damage clay-bearing formations, have a low
density, and carry sand as well as brines do. The low density of hydrocarbon fluids restricts
their use to low-pressure reservoirs. They are used to advantage as packer fluids and as
working fluids in low pressure horizons where the use of brines cause high fluid loss and
result in reduced productivity and extended swabbing times. Hydrocarbons may be placed
in the workstring annulus during concentric workovers to isolate the upper tubing and
casing strings from treating fluids (on which they float) being injected into the formation.
This is commonly done in sand consolidation treatments. The hydrocarbon fluid used may
be crude oil or a refined oil. A clean hydrocarbon fluid is always preferred.
9.8.2
Density
Appendix B contains the information necessary to estimate the density and viscosity of
common hydrocarbon fluids as a function of temperature and pressure. Figures B-1, B-2,
and B-3 may be used to estimate the density of petroleum products at various temperatures
and pressures.
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9.8.3
COMPLETION FLUIDS
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Viscosity
The viscosity of petroleum fractions or hydrocarbon products may be estimated at any
temperature and pressure with the aid of Figures B-4, B-5, B-6, B-7, and B-8 of
Appendix B.
9.8.4
Crude Oil
Availability makes crude oil a logical choice when its density meets the need at hand.
Lease crude obtained from a tank battery has usually weathered sufficiently to minimize
(but not eliminate) the hazard of fire. Its low density makes it particularly desirable for
low-pressure formations. A low-viscosity crude has limited carrying capacity and no gel
strength. Thus, it should drop out non hydrocarbon solids in surface pits. Crude oil is an
excellent packer fluid from the standpoint of minimizing corrosion, and gel strength can be
provided to limit the settling of solids if required.
Loss of crude oil to the formation is usually not harmful from the standpoint of clay
disturbance or saturation effects, as might be the case with saltwater in a low-pressure
formation. Fluid loss may be great, however. Thus, any entrained fine solids might be
carried into the formation pore structure.
Crude oil should always be checked for the presence of asphaltenes or paraffins that could
plug the formation. This check can be made in the field with API fluid-loss test equipment
to observe the quantity of solids collected on the filter paper.
Crude oil should also be checked for any tendency to form an emulsion with the formation
water. Techniques of the API RP 42 tests are suitable for field use. If stable emulsions are
formed, a suitable surfactant should be added.
9.8.5
Diesel
Diesel oil is often ideal when an especially clean fluid is required for operations such as
sand consolidation. Its use may even be advantageous for work under pressure at the
surface where its density is insufficient to overcome formation pressure.
Diesel oil is a particularly clean, solids-free material when proper handling and hauling
practices are employed. It may contain motor-fuel additives when obtained from some
sources. These can cause emulsions. These additives can cause formation problems.
Lease crudes and refined oils are petroleum products, as such, will burn under the right
conditions. Caution must be exercised in the use of any of the oil-based fluids.
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9.9
COMPLETION FLUIDS
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OIL-BASE AND INVERT-EMULSION MUDS
Oil-base and invert-emulsion muds can be formulated with densities over the range of 7.8 to
22.0 ppg. They are particularly useful where high densities are required at high
temperatures. They are suitable for use at temperatures in excess of 400°F. Because they
are non-conductive, they are generally non corrosive. These muds typically have extremely
low filtration rates so that fluid loss during their use should not be a problem. Because oilbase are non-aqueous, they can prevent clay hydration. Reactions between formation solids
and mud additives are generally thought to be minimal.
9.9.1
Composition
Oil-base and invert-emulsion muds are the two common forms of oil-base muds in use. In a
strict sense, oil-base muds are those that incorporate a minimum amount of water (usually
less than 5%) along with certain alkali metal soaps, other salts, and asphalt materials as the
main continuous phase. On the other hand, invert-emulsion muds (water-in-oil) consist of
relatively large percentages of water (over 40%). For fluid loss control these muds depend
on a high degree of emulsification and certain suspended solids. In both cases, the
continuous phase is oil.
9.9.2
Economics
Oil-base and invert-emulsion muds are somewhat more expensive than water-base muds,
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but they are less expensive than many high density brines.
9.9.3
Damage
Oil-base and invert-emulsion muds have been generally considered to be less damaging
than conventional water-base muds because the filtrate is oil rather than water. However,
most oil-base systems contain strong emulsifiers, which may oil-wet the formation, and
blown asphalt, which can plug perforations and the formation.
Laboratory tests and recent field experience have shown that some invert-emulsion muds
can damage formation rock severely. The damage mechanism was not determined, but
severe shallow damage was demonstrated. Since the problem occurred in formations with
very fresh connate water, invert-emulsion muds should not be used against formations
bearing very fresh water if such use is avoidable.
Laboratory tests have shown that perforating in weighted oil muds can result in the
formation of mud plugs that cannot be removed by back-flowing. Mud plugs reduce
productivity, restrict the uniform production of the reservoir, and reduce the success of
subsequent squeeze cementing and sand consolidation procedures. Thus, oil-base or invertemulsion muds are less desirable than solids-free fluids, such as brines or oil.
9.9.4
Stability
Oil-base and invert-emulsion muds do not solidify due to internal reactions at high
temperatures like some water-base muds do. However, there are some instances where gel
strength fails with time and temperature and mud solids settle out. This is a concern in
packer fluid applications. Mud solids settled on top of a packer can prevent subsequent
movement of the packer. The separated fluid no longer has the required density. If these
muds are to be used as packer fluids, extra effort must be taken to condition them and to
add the appropriate oil dispersible clays to obtain sufficient long term gel strength.
9.9.5
Corrosion
Oil-base and invert-emulsion muds provide corrosion protection by their lack of
conductivity, their tendency to oil-wet tubulars, and also by the ability of the surfactants in
them to emulsify any water that they contact. When properly formulated and conditioned
the quantity of water in the mud is not so important. Corrosion protection is provided by oil
mud containing 5 to 10% water and by invert emulsion muds containing 20 to 30% water.
Corrosion inhibitors are generally not required.
9.9.6
Applications
During drilling operations the uses of oil muds include (1) protecting the producing
formation, (2) drilling water soluble formations, (3) drilling deep/hot holes, (4) preventing
differential pressure sticking, (5) coring, (6) mitigating severe drill string corrosion, and (7)
drilling troublesome shale.
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Completions fluid applications of oil-base and invert-emulsion muds include use as (1) a
packer fluid, (2) a casing packer fluid, and as (3) a working fluid against sensitive
formations and in high temperature, high pressure oil wells.
The use of oil-base and invert-emulsion muds is justified in cases where a mud must be
used and formation clays would be seriously damaged by conventional water-base mud.
Oil-base or invert-emulsion muds are better packer fluids than water-base muds from the
standpoint of both corrosion and the settling of solids. Temperature stability is very good.
Solids do tend to settle over long periods of time unless the mud is properly treated with
extra gelling agent.
9.10
NITROGEN
9.10.1
Applications
In areas in which bottomhole pressures are low and a local source of nitrogen is available,
N2 can be used as a workover fluid. A typical density in a well application is about 0.1 ppg.
Nitrogen requires a fairly high injection rate and its lifting power is limited. However, the
dangers inherent in using air are eliminated by the use of inert N2, and lost circulation
problems in low-pressure zones are avoided by using a low density fluid. Nitrogen can also
be used for perforating. It will not cause formation damage and is especially suitable for
gas wells.
Nitrogen may be used in conjunction with coiled tubing units for workover and service
jobs. It can be used as a temporary gas-lift system to unload water-logged gas wells and to
bring in wells after workover or completion. It has been used to form foam to clean out
sand and to drill cement with a downhole motor.
Well-stimulation jobs may be performed by using the N2 to form a foam carrier for either
sand or acids. Nitrogen may be used to charge the fluid of a stimulation treatment. The use
of N2 in these jobs permits cleanup when the well is placed on production.
9.10.2
Equipment
One draw back to N2 is the extra equipment and space requirements its use entails.
Nitrogen is usually delivered to the well site in a liquid form. Typically the service
company supplies equipment to gasify the nitrogen on a skid or truck along with the liquid
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nitrogen.
9.11
FOAM
9.11.1
Definition
Foam is a mechanical mixture of air or gas dispersed in water or brine containing a small
amount of surfactant. Surfactant type and concentration should be selected to develop a
stable foam with the specific well fluids encountered. These fluids have been applied
widely in shallow, low-pressure, reservoirs. In wells with low fluid levels in which
circulation of solids-free oil or water-base fluids is not possible, foams have used for
workover operations such as washing out sand, gravel packing, drilling in, liner removal,
tool recovery, and deepening.
9.11.2
Advantages/Uses
The advantages of a stable-foam circulating fluid include :
•
Low hydrostatic head to minimize formation damage by lost circulation
•
Excellent carrying capacity for sand and cuttings removal or gravel packing
•
Rapid identification of formation fluids in returns
•
Low circulation pressures
The greatest advantage of foam is the combination of low density and high lifting capacity
at moderate flow velocities. Bottom-hole pressures as low as 50 psi have been measured at
2900 ft while circulating foam.
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COMPLETION FLUIDS
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Properties
Depending on the ratio of air to foam water circulated, foams can be prepared with
densities as low as 0.3 ppg (2 lb/ft3). The gas-to-liquid ratio ranges from 3-50 ft3/gal,
depending on downhole requirements. Viscosity can be varied to provide high lifting
capacity at the 300 + ft/min annular rising velocity. BHP measurements have indicated
actual pressures of 15 psi at 1000 ft, and 50 psi at 2900 ft while circulating.
9.11.4
Foam Generation
The foam is prepared at the surface to a consistency similar to that of aerosal shaving
cream. It then is circulated only once so that materials recovered from the well are not
reinjected. The water-detergent solution that is mixed with gas to form the foam can
employ a wide range of organic foaming agents. Surface injection pressures have ranged
from 5 to 200 psi above BHP. Pressures to 2000 psi can be attained, and foam has been
circulated through macaroni strings at 600 to 800 psi.
Foam generated with natural gas or nitrogen has been used in connection with smalldiameter reelable tubing or snubbing equipment to clean out higher pressure wells without
killing them. Foam returns in these cases are directed through the normal flowline system
to production separation facilities.
Equipment requirements include an air compressor or source of measured gas, mixing tanks
for foamer solution, a liquid pump, metering facilities for air and liquid volumes, and a
foam generator to provide good dispersion of air in the foam solution. The equipment
needed to handle foam returns includes a tubing rotating head or stripper assembly at the
wellhead to divert the foam returns into a blooey line and to a disposal pit. At the pit, a
water spray system may be required to break the foam. Aluminum stearate is a good
defoamer.
Typical air compressor requirements are 500 to 1000 ft3/min at a pressure of about 500 psi.
Water and foaming agents are mixed and injected into the air stream at a rate of 10 to 20
gal/min. Foaming agent concentrations of 0.5 to 1.0% are typical. Bentonite or polymers
are added to the water to produce a stiff foam with greater carrying capacity.
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9.12
COMPLETION FLUIDS
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CIRCULATING FLUIDS
Circulating fluids are those working fluids used to move things around within a well. These
fluids may be required to transport solids into or, more typically, out of the well. They may
be required to suspend solids for various lengths of time when circulation ceases. They
may also be required to displace treating fluids to the formation and in some cases to
overdisplace the treatment fluids out into the formation. Excessive loss of the circulating
fluid to the formation often can not be tolerated.
9.12.1
Solids Transport
In a workover involving a solids transport or washing operation, the workover fluid should
be able to carry solids to the surface. In this application, viscosity is the most important
fluid property. As the viscosity of the fluid increases, the carrying capacity increases.
Brines with viscosifiers added, muds, foam, and gas are the most common fluids used for
these clean-up operations. Foam or gas may be used to provide lifting capability for
workover or completion fluids, sand, and small cuttings.
There are three main factors which determine the magnitude of effective viscosity required
for solids transport in washing operations. These factors are well temperature, the size and
weight of solids to be transported, and the shear conditions (flow rates and tubular
dimensions) in the tubing or annulus in which the solids are to be transported.
The first factor, well temperature, has been discussed previously. As noted, viscosity
decreases more-or-less exponentially as temperature increases. To be conservative it is
appropriate to design using the maximum expected circulating temperature thereby
providing more than sufficient viscosity for transport at all other temperatures. The fluid
temperature profile in a well depends upon wellbore geometry, flow rate, flow direction,
elapsed time and geothermal gradient. Accurate estimation of the flowing temperature
profile requires a computer simulator. On the basis of such simulations we can generalize
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as follows. During circulation the maximum temperature occurs somewhere between 2/3
TD and TD. The maximum temperature is lower at high flow rates and higher at low flow
rates approaching the geothermal profile as flow ceases. The maximum temperature is
lower at high flow rates and higher at low flow rates approaching the geothermal profile as
flow ceases. The maximum temperature is always less than the static bottomhole
temperature and always greater than the return fluid temperature. Most conservatively, one
may use the static bottomhole temperature for design.
The second factor affecting the desired viscosity of a fluid is the nature of the solids to be
transported. As a rule, a higher viscosity is required to transport larger and heavier
particles. For example, removing cuttings from milling out a packer will require a viscosity
greater than that required to wash sand from the well.
The third factor effecting the desired viscosity is the shear conditions to which the fluid is
exposed. The shear rate is determined by the fluid flow rate and wellbore geometry at the
point of interest.
Shear conditions have an effect similar to the effect of temperature on the fluid viscosity.
Most polymer viscosifiers, which are added to brines to increase viscosity, are shear
thinning; that is, their viscosity drops as shear increases. The shear rate through the tubing
is significantly greater than shear rate through the tubing casing annulus. Depending on the
type of operation, method of fluid circulation, and other well conditions, the shear rate may
be lesser or greater. Typical shear rate ranges are given in Table 7.
Table 7
Typical Shear Rates
Tanks, Pit
Annulus
Tubing, Wokstring
0 – 5 sec-1
10 – 500 sec-1
100 – 3000 sec-1
The relationship between these three factors will determine the range of viscosities that may
be achieved with a particular fluid, and the desired concentration of polymer required to
achieve a particular viscosity.
The effect of particle size on required viscosity is illustrated in Table 8. Forty mesh sand
may be circulated or reverse circulated using a fluid with a viscosity of 0.7 cps or 0.2 cps
respectively. This viscosity is less than equal to the viscosity of water at well temperatures.
On the other hand, viscosity somewhat greater than the viscosity of water at well
temperatures is required to wash twenty mesh sand. Typically, in this case the viscosity
would be raised to 10 cps as a safety margin to compensate for temperature effects and
possible shut downs. Ten mesh sand requires still greater viscosity and large cuttings
require a substantial increase in viscosity.
The effect of flow rate on the required viscosity is illustrated in Table 9. Larger sand
articles (10 mesh = 2 mm) may be reverse circulated from the well at 1 BPM with a 20 cps
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fluid than circulated from the well with an 80 cps fluid. At the same flow rate particles of 5
times the diameter require 750 cps and 2000 cps viscosity fluids to be removed by reverse
and direct circulation respectively. Increasing the circulation rate decreases the required
viscosity proportionately.
In practice, the completion/workover engineer may indicate in the program that a viscosifier
will be required. If the operation involves washing out sand or small cuttings, field
personnel who are familiar with local well conditions and field practices will use a common
starting point. If local experience is lacking, the engineer must provide an estimate of the
required viscosity given the conditions and procedure requirements. In general a viscosity
of approximately 40 Marsh-seconds (approx. 20 cp) may be used to begin washing out
small debris, cuttings, or sand. If necessary, the field personnel will increase the viscosity
of the fluid using the viscosifier specified in the program.
Table 8
Required Viscosity Effect of Particle Size
For Tubing and Annular Transport
Particle
Size
40 mesh
40 mesh
20 mesh
20 mesh
10 mesh
10 mesh
1 cm
1 cm
Circul. Rate
(BPM)
Fluid Density
(ppg)
Tubing
(in)
Casing
(in)
Viscosity
Required (cps)
5
5
5
5
5
5
5
5
9
9
9
9
9
9
9
9
3.5
3.5
3.5
3.5
3.5
3.5
3.5
3.5
7
7
7
7
0.25
0.7
1.0
2.8
5.8
16
150
400
Table 9
Required Viscosity Effect of Flow Rate
For Tubing and Annular Transport
Particle
Size
10 mesh
(2 mm)
10 mesh
(2 mm)
1 cm
1 cm
1 cm
1 cm
1 cm
Circul. Rate
(BPM)
Fluid Density
(ppg)
Tubing
(in)
Casing
(in)
Viscosity
Required (cps)
1
9
3.5
-
29
1
9
3.5
7.0
80
1
1
5
5
10
9
9
9
9
9
3.5
3.5
3.5
3.5
3.5
7.0
7.0
-
750
2000
150
400
75
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1 cm
9.12.2
10
9
3.5
7.0
200
Solids Suspension
Often it is necessary to assure that solids entrained or suspended in a fluid do not rapidly
separate from the fluid when circulation is stopped. Or, we may desire that suspended
solids remain suspended in surface tankage for some period of time. If the solids are fine
enough they may be suspended with surface active dispersing agents indefinitely.
Generally, for dispersing agents to work the solids must be of colloid dimensions, i.e., less
than 0.1 micron. Indefinite suspension of typical well solids is usually accomplished by
imparting gel strength to the well fluid.
In drilling fluids, gel strength is derived from the interaction of clay particles. In workover
fluids gel strength is usually provided by polymer gels. Polymer solutions may be gelled
with various crosslinkers or labile bridging agents. A gel strength of only 2 to 4 lbf/100 ft2
is sufficient to suspend the barite weighting solids used in drilling muds. More gel strength
is required to suspend larger particles or denser particles. Excessive gel strengths should
generally be avoided in order to facilitate fluid movement.
If the suspending fluid has no gel strength and suspended particles are above colloid
dimensions, then the particles will settle out with time. Particle settling can be drastically
slowed, but not eliminated by providing the fluid with increased viscosity. This is usually
accomplished in well fluids by adding polymers to the fluid. The rate of particle settling in
a viscous fluid may be estimated using standard engineering methods.
9.12.3
Breaking Circulation
When gel strength is used to give particle suspending properties to a fluid, one must be
concerned not only with the ability of the resulting gel to suspend solids, but also with the
pressure required to reinitiate fluid flow. Depending on the location of gelled fluid within
the tubulars, undersirable pressure may develop at the surface or bottomhole before the gel
breaks and flow is reinitiated. The gel strength determines the pressure required to break
circulation.
For example, consider the removal of a gelled packer fluid from an annulus. A concern in
this case might be whether or not exposed formation will be fractured before circulation is
broken and packer fluid removal begun. In this case, if a 0.57 psi/ft packer fluid with a gel
strength of 50 lbf/100ft2 were to be circulated from a 3½ inch x 7 inch annulus with a 0.54
psi/ft workover fluid in a 10,000 ft well, the pressure required to break circulation would be
840 psi.
The 840 psi increase in the surface pressure will be reflected by a similar increase in the
overbalance at the perforations. Such an increase may not be tolerable.
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Fluid Loss Control
Frequently, it is necessary to reduce fluid loss during the use of a circulating fluid.
Normally this is accomplished by spotting a viscous fluid loss pill as required. Fluid loss
pills typically are dispersions of fine degradable solids in highly viscous solutions of
polymer in a workover brine. The dispersed solids/polymer combination is designed to
form a relatively impermeable filter cake in perforations or on the formation face. This
fluid loss control mechanism is preferred in order to reduce intrusion of potentially
damaging additives and fluid into the formation matrix.
It is, however, possible to control fluid loss in some instances with very high fluid viscosity
alone. Increased viscosity alone cannot stop fluid loss completely. If fractures and
channels are absent and fluid loss is into permeable formation matrix only, it is possible to
increase fluid viscosity at formation temperature sufficiently to reduce fluid loss to an
almost undetectable amount. The upper limit on allowable viscosity is determined by the
ability to place the viscous fluid across the perforations. The effective use of this “viscosity
pill” technique requires invasion of the formation matrix to some radius with viscous
polymer solution. In this case, the solution must contain breaker chemicals if the pill is to
be removed later since post treatment contact of the polymer solution with breaker
chemicals may become essentially impossible.
The rate of the fluid loss to a formation when a viscous volume of fluid is spotted is a
function of time. Initially, as polymer solution invades the formation the fluid loss rate
drops. Thereafter, it will approach a constant rate which continues as long as viscous
solution fills the wellbore at the perforations. After the whole pill is lost to the formation,
the fluid loss rate will again rise towards the original rate as low viscosity fluid displaces
polymer solution outwards.
Figure 4 illustrates the fall of relative injectivity (or fluid loss) with invasion radius as a pill
of viscous Newtonian fluid invades the formation around a wellbore for various ratios of
pill to formation fluid viscosity.
Figure 4 shows that fluid loss will quickly fall to 10 times the ratio of formation fluid
viscosity to pill viscosity after about one foot of pill penetration and thereafter will change
only slowly with further penetration. This means that for a 0.25 porosity formation J/J0 <
10 µf/µp after about 11 gal/ft of pill is lost to the formation. Thus, for example, the fluid
loss rate will be reduced to <0.01% of the original fluid loss rate after 11 gal/ft of 100,000
cps pill fluid is lost to the formation (µf = 1 cps). If the original loss rate was 1 BPD/ft,
then after pill placement the fluid loss rate would fall to 0.0042 gal/day/ft. For a hundredfoot interval, 100 BPD of fluid loss would be reduced to 0.42 gal/day. If the pill viscosity
were 10,000 cps, fluid loss would be reduced to 4.2 gal/day, etc.
In general, viscosity pills should be designed for about 0.5 bbl/ft of loss using a fluid with
10,000 cps, to 100,000 cps viscosity at 1 sec-1 shear rate at formation temperatures. This
will require 100 lb/1000 gal to 120 lb/1000 gal of HEC. For 100 ft of interval this will
amount to 50 bbl of pill containing 210 lb to 252 lb of HEC.
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A viscosity pill absolutely must contain a breaker chemical. Breaker chemicals are
ordinarily acids or oxidizing agents added in a concentration that is dependent upon the
formation temperature and the desired working time.
Figure 4. Relative injectivity of a viscous pill
Solids fluid loss agents are usually used in a fluid loss pill in place of the high viscosifier
loadings used in viscosity pills. The filter cake formed by the solids is designed to have a
very low permeability which becomes the major flow restriction in series with the
formation permeability. Thus, lower viscosity fluids are able to exhibit low fluid loss.
Fluid loss solids may also be required if fluid loss is into fractures, channels, or vugular
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porosity. In this case the normally fine grade fluid loss solids will have to be augmented
with the addition of progressively coarser grinds of solids until a filter cake is able to form
and fluid loss is reduced. Fluid loss solids should not be used if it appears that they will
end up in locations that cannot be subsequently contacted with acid or solvent as needed by
the particular type of solid for removal. This might be the case in some gravel packing
applications for example. When solids removal is a concern then viscosity pills are
indicated. Be aware that certain fluid loss solids, e.g., siderite react with acids 30 times
slower than calcium carbonate. Because of this low reaction rate, acid breakthrough in
some perforations may prevent all solids from being dissolved in other perforations.
9.12.5
Treatment Displacement
Circulating fluids are invariably used to displace well treatments to the formation. In some
instances they may be required to overdisplace the treatments to some distance out into the
formation. Fluids used for this purpose must be compatible with the fluids they are
displacing. In the case of overdisplacement they must also be compatible with solutions of
the reaction by-products from the treatment being displaced. For example, it would be
inappropriate to overdisplace mud acid with a sodium or potassium containing brine since
the reaction by-products, fluosilicates, will react with these cations to form damaging
precipitates. Diesel, ammonium chloride solution, or hydrochloric acid are more
appropriate in this case. Secondly, fluids used for displacement should be clean and solids
free since they will contact the formation and pass through perforations either by design or
by error. Thirdly, effective displacement of one fluid from a portion of formation by
another depends on a favorably high mobility ratio. Viscosity ratio is the most easily
influenced component of the mobility ratio. Thus, effective overdisplacement is effected by
assuring that the viscosity of the displacing fluid is greater than that of the fluid being
displaced.
9.12.6
Selecting A Circulating Fluid
Selection of the type of fluid required for a particular application is basically a five step
process. These steps are as follows.
1.
Calculate the fluid density required to counteract the expected bottomhole pressure.
2.
If well control is an important criterion, select fluids that have a density range slightly
greater than the required fluid density. Use the mid-depth method.
3.
If viscosity is an important criterion (e.g., washing operation), select those types of
fluids that are sufficiently viscous, or whose viscosity can be increased by the addition
of viscosifiers.
4.
Review the workover fluids that meet the criteria above, and eliminate those fluids that
are unacceptable due to the potential of formation damage resulting from their use.
Avoid drastic drops (e.g., 50%) in the salinity as compared to the connate (native)
brine. Among the most significant considerations, the corrosiveness of the fluids and
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their compatibility with other fluids are the most important.
5.
Choose the fluid which meets all of the above criteria, and is the most economical.
If the fluid selected in step five is very expensive, it may be necessary to review the
selection process and reconsider some of the fluid that were eliminated along the way.
9.13
PACKER FLUIDS
9.13.1
Functions
In a conventional completion, the primary function of a packer is to seal off the tubingcasing annulus, and allow production from below the packer, through the tubing. The
primary function of a packer fluid, in turn, is to prevent packer/tubular failures that would
allow communication to develop between the annulus and the formation or produced fluids.
The packer fluid performs these functions mainly by protecting the steel in the tubingcasing annulus from corrosion. Since the packer may remain in the annulus for an extended
period of time, it is necessary to properly inhibit the fluid to prevent or minimize annular
corrosion.
In addition to performing the above functions, the packer fluid may provide the benefits of
backing up the packer functions by reducing the tubing burst load, and reducing the
differential pressure across the packer. In some situations, the packer fluid may help to
prevent tubing buckling or burst by providing additional pressure on the tubing annulus.
When differential pressure across the packer approaches or exceeds the packer rating, the
packer fluid may reduce the differential pressure, thereby increasing the safe operating
limits of the packer.
The fluid properties which are necessary to provide the packer fluid functions are described
below.
9.13.2
Hydrostatic Head
It is accepted practice to use a packer fluid with kill weight density. The packer fluid must
contribute to well control during the seating and unseating of the packer.
9.13.3
Solids Settling
A packer fluid should ideally be solids-free. If a packer fluid must be weighted with solid
materials, they should not settle out over the period of fluid use. Solids weighted packer
fluids must have gel strength to prevent the solids from settling. The gel strength should
not be so great as to prevent initiation of circulation or tubing movement should a workover
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become necessary. If solids do segregate out and fall to the bottom, a retrievable packer or
the tubing may get stuck, resulting in a long and expensive fishing job.
Water/clay based muds with a high solids content are not desirable packer fluids. Mud
properties usually deteriorate in one of two ways when left quiet at well conditions for a
long period of time. The gel strength may become too high or mud solids may settle out
around the packer. However, it has often been found that the clear brine required by a high
pressure well is not available at sufficient low cost and low corrosivity so that mud must,
nevertheless, be used.
9.13.4
Corrosion
In contrast to a fluid that is strictly for a workover/completion operation, a packer fluid is
typically in place for a long period of time. The packer fluid must, therefore, be noncorrosive to both tubing and casing. Corrosion is the most important problem to be solved
in packer fluid selection. Corrosion in wells may result from the generation of corrosive
chemicals as a fluid or its additives deteriorate, from electrochemical cells of spontaneous
origin in various parts of the well, and from bacterial action. The overall corrosion rate
should be kept low, pitting corrosion should be minimized, and embrittlement must be
completely avoided.
Three methods are commonly used to control corrosion. Fluids of inherently low
corrosivity may be used. Or, corrosion may be minimized in more corrosive fluids by
controlling pH and the use of corrosion inhibitors.
Fluids of low inherent corrosivity are generally hydrocarbon based. The low electrical
conductivity of these fluids suppresses corrosion currents. In low pressure wells the
hydrocarbon may be diesel or lease crude. Oil-base or invert-emulsion mud may be used in
higher pressure wells. The clay dispersants and emulsifiers in oil muds keep water
emulsified and metal surfaces oil wetted, thus, further minimizing conductivity and
corrosivity. Both oil soluble and brine dispersible corrosion inhibitors are sometimes added
to hydrocarbons to insure corrosion protection when inefficient displacement of water-base
mud or brine anticipated.
Corrosion inhibitors may be added to electrically conductive fluids to reduce the corrosion
rate. Typically, corrosion inhibiting agents function by scavenging oxygen, electrostatically
passivating the metal surface, or, more commonly by forming a hydrophobic film on the
metal surface that prevents the entrance of corrosion currents into the surface. Corrosion
inhibitors function well in brines. Film forming corrosion inhibitors do not provide much
protection in water-base muds since they tend to adsorb strongly on the mud solids.
Bactericides act as corrosion inhibitors by killing bacteria that generate corrosive byproducts.
Control of pH is the primary method of reducing corrosion in water-base muds. When a
brine can tolerate a high pH, elevated pH can also control corrosion in brines. High pH
controls sweet and sour corrosion by preventing the oxidation of iron by hydrogen ions and
by preventing the growth of sulfate reducing bacteria. A pH greater than 9.5 significantly
reduces corrosion of iron. Water-base mud pH should be adjusted to a stable value between
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10.5 and 11.5 prior to installation of the mud as a packer fluid. The pH of the mud should
remain unchanged following circulation for 48 hours before it is considered stabilized.
This is necessary because mud components tend to reduce the mud pH with time.
9.13.5
Corrosion Inhibitor
A water soluble corrosion inhibitor, such as Conqor 303 or Conqor 404, can provide
excellent protection under subsurface conditions. A concentration of 5000 ppm (20 gal/100
bbl) is generally recommended when saltwater is used as a packer fluid or will be left in the
wellbore for extended periods of time. Corrosion inhibitor is not usually necessary for
saltwaters that will be circulated out of the well after completion or workover operations
are finished. Most corrosion failures attributable to packer fluids are observed to occur
below circulating valves and between packers in multiple completions and in other areas
from which mud and fluids are not removed by normal circulating methods. When such
possibilities exist, only inhibited fluids should be used.
Contamination of a clear liquid to be used or left in a well can be lessened by displacing the
drilling fluid with clear untreated fluid, discarding the returned interface between the fluids,
and then circulating the clear fluid again after the addition of required corrosion inhibitor
and biocide additives. Wastage of corrosion inhibiting chemicals is avoided by delaying
their addition until after the first purge of the well with clear fluid.
9.13.6
Biocides
Packer fluids which contain water can support the growth of bacteria. Bacterial life
processes often generate corrosive by-products and bacterial bodies can plug and damage
formation rock. A bactericide should be added to packer fluids to prevent the growth of
bacteria. Two common bactericides used for packer fluid systems are Xcide 102 and 207.
Bacteria can cause sulfide corrosion in the absence of oxygen (anaerobic conditions).
Anaerobic bacteria are able to use hydrogen formed by electrochemical corrosion to reduce
sulfate ions, forming hydrogen sulfide.
This anaerobic process accelerates the
electrochemical corrosion, and the resulting hydrogen sulfide also attacks the steel, forming
black iron sulfide scale and pitting corrosion. Iron sulfide scale has caused plugging in
injection wells. The hydrogen sulfide formed can cause tubular goods to fail through
sulfide-stress-cracking/hydrogen-embrittlement under certain conditions.
If untreated packer fluids come in contact with the formation, the bacteria may damage the
formation. This can occur following a period of bacterial colony growth if the packer fluid
is subsequently used as a workover fluid, or if the packer fails and the fluid leaks into the
producing zone.
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9.13.7
COMPLETION FLUIDS
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Packer Fluid Selection
Various guidelines for selecting packer fluids have been published from time to time. They
are generally similar. The following conditions and recommendations pertinent to them are
a modification of those suggested by Baroid.
Condition A
No high-strength pipe involved in the completion (N-80 is borderline case). Packer fluid
density of less than 11.5 ppg is required.
Recommendation :
•
Use diesel oil or sweet crude treated with an inhibitor if density requirements permit.
•
Use clear water or brine with an inhibitor and a biocide. Inhibitor and biocide must be
compatible.
Condition B
No high-strength pipe involved in the completion. Fluid density greater than 11.5 ppg
required. Bottomhole temperature does not exceed 300°F.
•
Economics of the workover must be considered. Where workovers are inexpensive, a
water-base mud treated with a biocide might be practical. Tests should be made to
ascertain that mud does not contain soluble sulfide. The pH should be maintained at
11.5 for a few days prior to completion, if possible. Solids should be kept to a
minimum to avoid gelation with high pH.
•
In remote locations where workovers are expensive, or where workover frequency has
been high with water-base muds, use a properly formulated oil mud.
•
Use CaCl2/CaBr2 brine with an inhibitor.
Condition C
No high-strength pipe involved in the completion. Density of more than 11.5 ppg required.
Bottomhole temperature exceeds 300°F.
•
Use properly formulated oil mud.
•
Use CaCl2/CaBr2 brine with an inhibitor.
Condition D
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High-strength pipe to be used under any condition of fluid density or bottomhole
temperature.
9.13.8
•
Where fluid density requirements permit, use oil treated with both an oil-soluble and a
brine-dispersable corrosion inhibitor.
•
Use oil mud formulated to meet density and temperature requirements.
•
Use CaCl2/CaBr2 brine with an inhibitor.
Insulating Fluids
Sometimes it is desirable to thermally insulate the tubing string. This might be necessary in
arctic completions in order to prevent permafrost melting during production. It might be
necessary in order to bring asphalt and paraffin in the tubing. In thermal completions,
insulation increases the efficiency of the steam injection process. The use of an insulating
packer fluid can be the most economic way of installing insulation around the tubing.
Generally, this means that the insulating fluid must have a low thermal conductivity. The
thermal conductivity of the insulating medium will control the heat transfer if transport by
fluid convection and radiation are suppressed. It is most important to suppress the free
convection of fluid that tends to occur in the annular temperature gradient. Free convection
is suppressed if a packer fluid has sufficient gel strength. A gel strength of 25 lbf/100 ft2 at
well conditions is sufficient to eliminate heat transfer by convection in almost all well
situations.
Table 10
Packer Fluid Thermal Insulation
Depth = 17,250 ft
GTG
= 1.75°F/100 ft
SBHT = 372°F
31/2 inch tubing, 7 inch casing
Annular Fluid Properties
Brine
Diesel
Water-Base Mud
Oil-Base Mud
Gelled Diesel
HEATSAVER Tubing
Flowing Tubing Head Temp.
C
Btu/lb/
°F
k
Btu/ft/
Day/°F
Gel
Strength
lbf/100ft2
@
1000 BPD
°F
@
2000 BPD
@
3000 BPD
1.00
0.49
0.83
0.50
0.49
0.50
3.99
1.51
14.02
3.36
1.51
3.36
0
0
30.0
25.0
25.0
25.0
128
137
143
192
237
319
177
190
199
253
290
344
213
225
235
284
313
353
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and Oil Base Mud
Table 10 compares the effectiveness of packer fluids in a well with asphaltene deposition
problems. It was desirable in this well to bring the produced fluids to the surface at a
temperature greater than 185°F in order to prevent the deposition of asphaltenes in the
tubing string. Note that without gel strength the packer fluid cannot accomplish its
insulating objective as the flow rate drops below around 1500 BPD. For comparison
HEATSAVER brand insulated tubing is also included in the table. In thermal completions
where high temperatures occur, the expense of running this very effective insulated tubing
may be justified. It costs more than twice the cost of a normal tubing string. Gelled oil
packer “fluids” are clearly more economic where they are applicable. Wellbore thermal
computer simulators can be used to gauge the effectiveness of an insulating fluid in a given
situation.
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9.14
COMPLETION FLUIDS
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PERFORATING FLUIDS
Although perforating fluids are not necessarily a distinct type of workover fluid, they are
distinguished here to emphasize again the importance of using a fluid that does not contain
suspended solids and is otherwise nondamaging to newly exposed formation.
Until recent years, mud was extensively used as a well-completion fluid. A well was
usually perforated with the wellbore full of mud; tubing was then installed, the mud
displaced from the tubing with water or oil, and production initiated. This method of
completion was considered satisfactory until laboratory tests, conducted under simulated
well conditions with cores, showed that perforations are filled with mud solids and charge
debris when mud is used as a perforating fluid. Back-flowing of the cores also revealed that
mud plugs are not easily removed by production.
9.14.1
Perforation Plugging
Plugged perforations have several undersirable effects. Mud plugged perforations may
require appreciable pressure differentials to initiate production. Flow through those
perforations that break down first can be expected to restrict, or prevent the higher pressure
differentials required to initiate flow across the more tightly plugged perforations, thus
impairing complete reservoir drainage. Mud plugged perforations can also increase like
likelihood of coning water or gas into a completion interval. Coning can happen if the top
perforations only are open in an interval near the gas-oil contact, or if the bottom
perforations only are open in an interval close to the water-oil contact.
Plugged perforations also hinder subsequent squeeze cementing or plastic consolidation
treatments. Mud plugs prohibit cement from reaching all perforations and result in
repetitious squeeze cementing to seal all holes. Mud plugs prevent placement of
consolidating plastics through each individual perforation increasing the likelihood of a
sand control failure.
9.14.2
Salt Water and Oil
Mud plugged perforations may be eliminated by using a clean fluid such as saltwater or oil
during completion and perforating operations. However, when perforating in water or oil,
formation damage can be expected if the perforating is done with a differential pressure
into the formation. The degree of near wellbore formation permeability reduction that
occurs is largely dependent upon the length of time that the well fluid is allowed to flow
into the formation after perforating and upon the formation’s clay content. Saltwater has a
high filtration rate and may carry entrained fine particles and charge debris short distance
into the formation. Back-flowing does not completely remove these materials.
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COMPLETION FLUIDS
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Acids
Acetic acid merits special mention because of its application as a perforating fluid and its
wide use. In the absence of hydrogen sulfide, acetic acid can be effectively inhibited
against almost all types of corrosion at elevated temperatures for extended periods of time.
Hydrochloric acid has a tendency to pit-corrode. This pitting becomes more pronounced
with increasing temperatures. Film forming acid corrosion inhibitors which must be used
with hydrochloric acids may oil wet newly exposed formation rock. Acetic acid, on the
other hand, causes only modest, uniform corrosion of the pipe.
Without the pronounced pitting corrosion, serious damage will not occur even if the acid is
allowed to become completely spent. This characteristic renders acetic acid particularly
suited for use in perforating operations in which the acid often must remain in contact with
the steel tubulars for a considerable period of time. However, acetic acid in combination
with hydrogen sulfide is very difficult to inhibit against embrittlement.
Acetic acid is normally available from service companies in a 10% by weight solution in
water. Acetic acid can be weighted with various salt mixtures to about 16 ppg. When
perforating in an acid medium, it is reasonable to assume that acid enters each perforation
as the formation is penetrated. On contact, acid reacts with carbonates, cement fines,
hydrated clays (such as those found in drilling muds), and formation components that have
been hydrated by filtrate from either the drilling mud or the cement slurry.
In tubingless completions, the usual procedure is to pump down the plug with acetic acid.
In conventional wells, acetic acid is spotted in place with the production tubing before the
Christmas tree is installed. In either case, the well may be perforated with differential
pressure into the wellbore and the perforations may be immediately unloaded if the well
flows. If it does not flow, acid is already in place with which to wash the perforations
without first displacing large volumes of wellbore fluids into the formation.
9.14.4
Nitrogen
A recent technique involves perforating with little or no liquid in the wellbore and using
nitrogen under pressure to control formation fluids. Welex, the foremost advocate of this
technique, claims gas-well productivities are higher when perforating is done in a gaseous
medium than when it is done in oil or saltwater. It is claimed that this is true even with
differentials into the wellbore. Results indicate that consideration should be given to this
technique when :
•
Very low pressure exists in the formation.
•
It is not desirable to contaminate formation fluids with workover fluids during special
testing programs.
•
Extended periods of rig time would be required to initiate flow by swabbing in highcost locales, such as offshore platforms.
Nitrogen is more expensive than over typical perforating fluids, however, and the added
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cost must be warranted.
9.15
FIELD HANDLING OF FLUIDS
In the foregoing we have considered the properties of completion fluids and how they relate
to the various applications of the fluids. Here we consider the operations and factors
involved in handling completion fluids. Because they are the most common, and for
simplicity, the focus is on brine completion fluids.
They handling of brines entails the mixing and maintaining of a fluid composed of water,
salts, polymers, and other additives in quantities and at rates compatible with ongoing well
operations. Since a major objective in using a fluid other than drilling fluid for completing
the well is the protection of the productive formation, a major consideration is maintaining
the cleanliness of the completion brine. When high brine densities are required and more
expensive brines must be used, the handling of a completion brine can become considerably
more complicated. High density brines may cost hundreds of dollars per barrel. Thus,
minimizing fluid loss, reconditioning, and resale become important. Not only the expense,
but also certain physical properties of the higher density brines necessitate handling
considerations that are unnecessary for low density brines. In the following we will survey
the operations of mixing and maintaining completion brines, their safe handling and
disposal, and the equipment their use entails.
9.15.1
Mixing Brines
For the sake of cleanliness and accuracy of mixing, dense brines should be mixed initially
to the engineer’s specification in service company mixing facilities whenever possible. The
dense brines are normally supplied to a specific density at 70°F in 0.1 ppg increments.
Service company facilities will not be contaminated with well fluids and experienced
personnel ought to be in control of the mixing process. Care should be taken that tankage
in which the brine is transported is clean. It should be inspected before fill-out to insure
this. Hoses and lines used to transfer the fluid should be inspected and cleaned.
Segregated tankage and pumps should be provided at the well for brine make-up and brine
altering operations. Sealed storage for hydroscopic solids salts may be required. Although
mixing is sometimes done with compressed air jets, this is to be discouraged since the
extensive aeration accelerates oxygen corrosion of all equipment and generates ferric iron
by-products that complicate filtration and can plug the formation and perforations if
generated downstream of the filters. Mixing with mechanical mixers and by rolling tanks
with the pumps is preferred.
Service company data or the composition tables of Appendix A can be used to figure the
quantities required to readjust the density of a returned fluid. Accurate density
measurements and any composition tests required to assure that no adverse precipitation
reactions will occur should be made. Blending of brines was discussed under the subject of
Clear Brines. As a general rule of thumb, for dense brines based on CaBr2, when a required
density increase is greater than 0.2-0.3 ppg, the addition of a denser liquid is more
economical than the addition of solid salts to achieve additional weight. When using a
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brine mixture it is best to make density adjustments with the basic system rather than with a
solution of one of the single salts. It is possible to saturate a brine system with a higher
concentration of one of the single salts then the combined system can tolerate thus possibly
causing unexpected crystallization and corrosion. Using the same basic system will also
help assure that costs are minimized.
As noted1 previously considerable heat is often generated during the mixing of dense
brines. This can be a hazard. The generated heat can also be used to advantage during
subsequent polymer addition to speed the rate of polymer hydration.
Remember, polymer should be added to already prepared brines either in dry form or as a
previously prepared concentrate. Solid salts should never be added to a brine already
containing dissolved polymer. Polymer will come out of solution on the salt crystals if this
is done causing the loss of useful fluid and various plugging and fluid separation problems.
Higher density liquid brines may be blended with already prepared polymer solutions
without problems.
9.15.2
Safety
The handling of concentrated high density brines poses some safety problems. First, when
brines are mixed there is often a great amount of heat generated. There is considerable
potential for scalds and burns from contact with solution or equipment. Second, high
density brines are severely irritating to the skin. Contact with the solutions should be
minimized and work in the dust of the solid salts should be avoided. Third, eye contact
especially with bromide and zinc containing brines can be extremely serious. Permanent
loss of sight is possible. Eyes should be continuously flushed with fresh water for 15
minutes following such contact and medical examination should follow immediately. Rig
personnel should be equipped with steel toe rubber boots, slicker suits, full gauntlet rubber
gloves, and chemical goggles when working close to these brines. Leather articles are
destroyed by brine contact.
9.15.3
Properties Control
Various factors may cause the loss of expensive fluid or loss of the properties of that fluid.
First, fluid may be lost by a number of mechanisms. Fluid may be lost to the formation as a
result of excessive overbalance, inadequate fluid viscosity, or inadequate fluid loss
additives. Fluid may be lost due to spillage and contamination. Formation losses may be
minimized by reducing the density, adding polymer, and/or adding fluid loss solids.
Spillage and contamination can be minimized by properly instructing the rig personnel in
the value of the fluid and proper handling. Second, the fluid may lose some of its
properties with use, notably density. The density of concentrated brine fluids may decrease
with time for a number of reasons. The brine may be diluted with formation fluids. Or,
because of the very hygroscopic nature of dense brines, dilution may result from the
adsorption of moisture from the atmosphere. Rain may dilute the brine. Attention to the
amount of overbalance and minimization of swabbing actions will prevent dilution with
formation water. Covered tankage will prevent adsorption of atmospheric humidity and the
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influx of rain into the fluid. Covered tankage is recommended when using expensive high
density brines. Third, density may be reduced by mixing the completion fluid with
immiscible fluids such as air (from mixing perhaps with polymers present), gas, or liquid
hydrocarbons. Emulsions with oil products and crude oil seems to form easily with high
density zinc containing brines. If mixing with immiscible fluids is a problem or is expected
to be, gas and oil-water separation facilities may be required in the working fluid handling
circuit. Air entrainment can be minimized by proper mixing equipment. Gas entrainment
can be minimized by proper attention to the overbalance requirements and minimization of
swabbing actions.
9.15.4
Freezing And Crystallization
As noted previously, high density brines have a tendency to freeze or crystallize at
relatively high temperatures. Figure A-1 gives these data for the various brines. In the
summer months or in areas where daily temperature variations are slight this might not be a
problem. However, when daily temperature variations are large and during winter, freezing
and crystallization can cause difficulties. The heavy brines do not expand on freezing, so
broken pipes will not result if freezing occurs. However, solid salts in hard to reach places
are difficult to redissolve. Loss of flow area can increase circulating pressures. And
settling of solids from the fluid during a temperature cycle can significantly reduce the
circulating brine density. Completely frozen brines require heat to be refluidized. The use
of heaters and heated tankage during the winter months will allow the use of the less
expensive, higher freezing brines.
9.15.5
Corrosion
Brines are strong electrolytes and as such tend to be corrosive to steel. Corrosion is the
result of electrochemical reactions and the high conductivity of brines allow those
reactions to proceed. If allowed to occur, corrosion can be severe in the surface equipment
used to handle brines. This corrosion not only destroys the equipment, but also adds
damaging corrosion by-products to their circulating brine. If not controlled, corrodents
carried downhole destroy downhole tubular goods as well.
Corrosion occurs due to the reaction of oxygen with the steel or by the reaction of salt
generated acid with the steel. For nonzinc-containing brines the primary corrodent is
oxygen. Corrosion by these brines can be controlled to acceptable levels by excluding
oxygen and using film forming corrosion inhibitors. Oxygen is excluded by eliminating
aeration and using oxygen scavengers.
Zinc containing brines generate additional corrosion because the zinc ions produce acidity
in reaction with water. Acid corrosion predominates over oxygen corrosion in high density
zinc brines because very little oxygen can dissolve in fluids containing such large amounts
of dissolved salts. Heavy aeration, however, can maintain oxygen corrosion in these brines
in addition to the acid type corrosion. Zinc bromide brines are somewhat acidic and must
be maintained acidic in order to prevent precipitation of zinc hydroxide. Zinc bromide
solution corrosivity is controlled to acceptable levels in most applications by the use of
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proprietary corrosion inhibitors supplied by service company and brine vendors. As
illustrated in Figure 5, corrosion in zinc bromide brines is unacceptably high in the absence
of corrosion inhibitors. When the brine density exceeds 18 ppg the corrosion rate increases
dramatically. Figure 6 shows the typically observed behavior of corrosion rate with time.
As Figure 6 illustrates corrosion appears to mitigate with time. The correct interpretation
of test results must take into consideration the time duration of the test and the shape of this
curve.
Zinc bromide containing brines have been observed to be “corrosive” in another sense. The
high density solutions are sometimes good solvents for certain plastics. In one report, zinc
bromide solutions dissolved the Orlon fabric and components of a filter system.
Figure 5. Brine corrosion rates on N-80 steel as a function of temperature. Curves 1-5 are 30-day
tests. Curves A and B are 14-day tests with and without a new water soluble
inhibitor (data from Dowell).
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Figure 6. Dependence of measured corrosion rate on length of test for N-80 steel,
15.0 lb/gal CaCl2/CaBr2/ZnBr2, 400°F, 1000 psi, unhibited.
9.15.6
Environmental
The salts of most completion brines are common in nature and as such are not especially
toxic. However, high brine concentrations are destructive to various life forms. The less
commonly occurring salts, such as those containing bromide and zinc, are considerably
more toxic. Hydrocarbon contamination is a concern. And, additives such as corrosion
inhibitors and biocides are often very toxic. Thus, care should be taken to avoid spillage
and to dispose of completion brines in strict compliance with local laws. In general, these
laws are designed to protect drinking water supplies, water which may be used in
agriculture, the environment of aqua-culture, and wildlife.
9.15.7
Resale
High density brines have some value at the end of workover or completion operations. The
value of the fluid should be determined and steps taken to recover as much of that value as
possible. One should keep in mind upcoming projects which may require a similar fluid. If
the fluid has a density greater than 12 ppg, resale or storage and reuse should be considered.
Most service companies offer a 50% buy-back policy less cost if fluid losses are minimized.
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If future operations will require use of the fluid within the coming 12 months then very
likely storage and reuse will be a more economical option.
9.15.8
Surface Equipment
For efficient fluid processing and especially when high density brines are to be handled,
provision should be made for dual circuit fluid containment and handling. One circuit, the
working system, should be designed to handle fluid cleanup during the performance of well
operations. Another circuit should be provided for storing and filtering contaminated well
fluids separately from the working system. Fresh, clean fluid reserve storage be available
also.
The working system may contain, as required, a shale shaker with a 120 to 325 mesh
screen, a combination cyclone/shaker unit, cyclones, a settling tank, two filter units in
series, and another settling tank. The upstream filter unit will be designed to remove
intermediate fine particles and it should have a fairly large capacity. This unit might be a
pair of dual pot filters in series using 5 to 50 micron elements. The downstream filter unit
will be a polishing filter designed to remove the fine particles discharged from the upstream
filter unit.
This unit might be a large single pot unit using 2 to 10 micron elements. While the finer
filters are desirable from a particle removal point of view, frequently the viscosity of the
heavy brine fluids forces the use of coarser filters. A schematic of such a filtration system
is provided in Figure 7. A well trained filter operator is a necessity if the filters are
expected to function correctly for any length of time.
The contaminated fluids circuit will have similar fine filtration equipment, but need not
have the coarse solids removal components or be designed for high volume through-put.
More emphasis can be placed on settling as a separation mechanism for this inactive fluid.
Thus, appropriate tankage with baffles may replace the shakers and cyclones in this circuit.
9.15.9
Solids Control
There are a number of considerations relevant to keeping a brine clean and serviceable.
The fluid should be prepared with components of good purity and transported and stored in
clean tanks. Continuing attention should be given to maintaining cleanliness throughout the
useful life of the fluid. There are a many sources of the damaging debris that often collects
in a workover fluid during its use. Dirty mixing tanks and storage tanks, and dirty vacuum
trucks are common sources of contamination to a clean workover fluid system. Tanks
should be thoroughly cleaned before use. Workover rig tanks should be equipped with
sumps and bottom baffles to contain settlings. Suction should be taken about 18 in. off
bottom. Tanks should have easily accessible clean-out plates. Rounded corners aid
cleaning.
Settlings in workover tanks should be checked hourly and cleaned as needed. Samples
from the pump discharge are helpful in checking for undersirable solids. Dirty tubing
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strings and transfer piping are often sources of rust, scale, and pipe dope. Tubing strings
can be cleaned in the well by setting a wireline plug at the bottom, running a string of 1 in.,
and circulating HCl, isoproply alcohol, or simply water with about 1 ppg frac sand for
scouring. In new completions a diligent effort should be made to purge the well of drilling
fluid and drilling fluid residue prior to the introduction of the completion fluid.
Devices in the fluid cleaning circuit are used to maintain fluid cleanliness. Settling tanks
can remove the larger and more dense solids. A-4 in. cone desilter can take out a high
percentage of solids down to the 10 to 20 micron range. When it is necessary to remove
still finer particles, filters must be used. They key to effective filtration is filter operator
training and supervision.
Surface filtration alone may not be enough to ensure a no-solids fluid at the bottom of the
hole. This was demonstrated in a well experiment. Fluid previously filtered to 2 microns
was circulated through a tubing string having filters at the top and bottom. The top tubing
filter remained clean, but the bottom filter consistently plugged with solution formed iron
oxide, pipe dope, scale, and rust. Iron oxide is formed by the action of dissolve oxygen on
ferrous iron, which comes from the pipe wall as corrosion proceeds. When first formed,
iron oxide exists as gelatinous ferric hydroxide which readily plugs formation pores. The
reaction between oxygen and iron can be prevented by using an oxygen scavenger such as
sodium sulfite and cobalt sulfate catalyst. Ferric iron in solution can be deactivated by
sequestering with EDTA or sodium citrate.
There are two basic strategies for minimizing formation damage due to solids entrained in a
completion fluid. Solids can be prevented from reaching the completion interval altogether,
or they can be prevented from invading the formation pore space, even though they arrive at
the formation face. In either case the objective is to minimize the quantity of undersirable
solids which enter the formation pore structure or filter out on the formation face. Both
approaches can be used simultaneously.
Damage may be minimized by thorough removal of solids from the circulating fluid. Fluid
in contact with the formation should ideally not contain any solids larger than 2 micron.
This goal is usually not entirely realizable. One can attempt to eliminate all solids through
use of surface filters and take steps to minimize the pickup of solids downstream from the
filters. Nevertheless, some fluid loss will occur and some small fines will be lost to the
formation. The use of polymers must be minimized in order to maximize filterability.
Carrying capacity must be sacrificed to achieve filterability. In many, instances velocity
can be substituted for viscosity in lifting particles.
Damage may also be minimized by efficient fluid-loss-control. The quantity of fines lost to
the formation may be reduced by minimizing differential pressure into the formation. The
removal of fines from the pore system may be returning the well to production gradually.
Temporary fluid-loss additives can be used to control fluid loss and form a filter on the
formation face. The filter cake prevents particles from moving past the face of the
formation into the pore system and the quantity of undersirable solids deposited on the
formation face is minimized by the reduction in fluid volume filtered into the formation.
The best method of minimizing formation damage by workover fluids will vary from well
to well. It may involve the use of one of these strategies or the other, or some combination
of the two. In any case, the base workover fluid should be thoroughly cleaned initially by
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settling, filtering, etc., while circulating. Fluid loss material might then be used in pills in
order to avoid general distribution of them in the fluid thereby leaving the bulk of the fluid
filterable. In this way work can be done in a clean fluid that is further filtered at the sand
face. Other schemes employing these principles are possible.
Figure 7. Filtration system layout
9.15.10
Allowable Solids
We normally say a fluid is clean if it contains no undissolved solids. Cleanliness is
characterized by the size distribution and the total volume of undissolved solids dispersed
in the fluid. When the particles present are large enough, a sieve analysis of the solids may
be used to determine the size distribution. When significant amounts of the total solids
present are too small to be collected on sieves, more sophisticated particle counters may be
required to determine the size distribution. An operational measure of cleanliness is
provided by the process of filtration. One needs only (1) the total undissolved solids
(usually on a volume basis stated in parts per million or ppm) and (2) the total undissolved
solids (similar units) that pass through a filter designed to remove all solids above a certain
size. For example, a fluid might be characterized as containing 130 ppm of suspended
solids with 4% greater than 2 micron. An allowable suspended solids specification might
be similarly stated.
The specification of allowable solids for a given application and filter performance are
somewhat entertwined. A filtration ratio, β, is often defined using filter performance data
as
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Influent Concentration
Effluent Concentration
=
β (Βετα)
(7)
Figure 8. Beta curves for two absolute rated filters.
The A curve represents 2 µm absolute and the B curve 10 µm absolute.
The value of β depends on filter medium characteristics and suspended particle size. The
concentrations and size distributions of influent and effluent particles may be analyzed to
generate values of β over a range of particle sizes. The value of β plotted against particle
size can be used to characterize the filter’s performance. When these plots are continued
until a β of 10,000 is reached, the corresponding particle size can be used as a statement of
the filter’s absolute rating. Essentially, no particles above an absolute rating are allowed to
pass.
This procedure is illustrated in Figure 8 for two different filters. Percent removal efficiency
is simply computed from β as
β-1
X 100
=
Percent Removal Efficiency
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β
The test conditions are chosen to be similar to the conditions that the filter will be subjected
to in service. However, low solids loadings are used to insure that the filter medium is
characterized rather then the solids filter cake.
There is considerable dispute over what level of undissolved solids is allowable in a given
situation. What is allowable is often determined by economic and operational criteria
rather than by physical laws. For example, a 5 micron filter will allow particles smaller
than 5 micron to enter or deposit on the formation, and these particles may cause a
reduction in permeability. But frequently, 10 microns is used as a minimum allowable
particle size because it is more certain that this level of filtration can actually be
maintained, it is less expensive, it allows higher filtration rates, and because it is judged
that the risk of plugging the formation with the reduced volume of remaining smaller
particles is “acceptable”. Note that the 10 micron filter of Figure 8 still has a filtration ratio
around 20 (95% efficient) for particles on the order of 1 micron diameter. In applications,
filter efficiency increases with time as filtered solids form a filter cake that is more
effective than the filter media. Filter performance curves should be examined for each
application in order to gauge the risks of using larger size filters.
9.15.11
Filtration
There are various types of filters and filter systems available. Table 11 presents
comparative data on the different types of filters. Four types of filtration systems are
ordinarily seen in the oilfield for use with workover and completion fluids. They are
cartridge filters, bag filters, multimedia filters, and diatomaceous earth filters.
Cartridge filters are metal or plastic tubes that are perforated and wrapped with filament or
layered with a permeable material to form a permeable matrix. The permeable matrix may
be made from materials such as cotton, paper, fiberglass, polyester fiber, and rayon. Large
particles are blocked at the outer surface of the cartridge. The smaller particles are trapped
within the permeable matrix.
The cartridges are normally enclosed in a stainless steel pressure vessel called a pod. Pods
may contain as few as 6 or as many as 110 cartridges. Filter pods are commonly operated
in pairs. Valving allows the filters to be replaced in one pod while the other is in operation.
Figure 9 is a schematic of such a filter. When the pressure drop across a pod rises to a
predetermined level, such as 25 to 40 psi, the operating filter pod must be shut down and
the cartridge elements changed. If the fluid is very dirty and the pod contains only a few
cartridges, this may happen in minutes. Many such devices have by-pass valves which
activate if the pressure drop becomes too high. When the by-pass valve is activated, dirty
fluid is allowed to pass the filter and may enter the well.
Cartridge filters can be cleaned and reused with 80-85% of capacity performance.
Cartridge life can be extended significantly by using settling tanks to remove the bulk of the
solids upstream of the cartridge filters.
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Obtainable flow rates range from 1 to 6 bbl/min, depending on the system. Higher flow
rates may be obtained by using multiple systems, operated in parallel.
Cartridge filters are either absolute or normally rated. An absolute cartridge will obtain a
sharp cutoff of solids at its rated size. A nominally rates cartridge may allow some particles
larger than its rating to pass through. Generally, cartridge filters are available in 1, 2, 5, 10,
and 25 micron ratings.
Figure 9. Dual pod filter
Table 11
Filtration Methods **
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Micron Size
Limitation
Flow
Capability
Operating
Cost *
Cartridge
(nominal)
1 (nominal)
1-2 bbl/min
cartridge bank
$5-10/bbl
Cartridges may last less than 15 min.
Cartridges must be discarded. Timeconsuming to change cartridges.
Requires large inventory.
Cartridge
(absolute)
1 (absolute)
1-2 bbl/min
cartridge bank
$15-50/bbl
Cartridges may last a short time if
pretreatment is not done. Bypassing
can occur if pressure is not watched
closely.
Bag
2 (nominal)
1-2 bbl/min pod
$7-16/bbl
Can develop leaks and tears. Quicker
to change than cartridges. Short life.
Multimedia
High-Rate
Filter
1 (nominal)
As high as 25
bbl/min
5 /bbl
Requires significant amounts of clean
fluid for filling and backwashing.
Large vessel. Used with injection
wells.
Tubular filter
(Backwashable)
1-3
(nominal)
0.25-1 bbl/min
tube
-
Plate and
frame press
with D.E.
<1
6-10 bbl/min
20 /bbl
Needs guard filter to protect against
accidental D.E. discharge. Large
physical system.
Vertical
pressure leaf
filter with
D.E.
<1
1-6 bbl/min
20 /bbl
Needs guard filter. Vibration can
cause loss of precoat. Over
pressurization can damage leaves.
Small size.
Tubular filter
with D.E.
<1
1-3 bbl/min
20 /bbl
Needs guard filter. Short cycle length.
Filter Type
*
**
Comments
Requires backwash recovery unit.
Valves can wear quickly.
Expendable materials only.
Arthur E.Hall, “How to Filter Workover and Completion Fluids-Part 2 : Tubular and Press Filters,”
Petroleum Engineering International, August, 1982, p. 130.
Bag filters, often called sock-type filters, are mesh fabric bags of controlled sizes mounted
in a filter housing. Fluids are injected at the center of the bag from above. Fluid flows
through the bags and into the housing, trapping the solids in the bag. The pressure will rise
as the bag fills with solids. At a predetermined pressure drop, flow is stopped and the bag
is removed from the filter housing for cleaning.
Filter bags can be made of wool, silk, rayon, polytetrapropylene, polyester, felt, and
polytetrafluorethylene (PTFE). Some bags may be washed and reused, depending on the
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type of material. Some types of material are most resistant to tears than others. Bag filter
life may be extended by using prefiltering methods, such as settling tanks.
Bag filters are available over the full range of ratings, down to 2 microns. Flow rates
ranging from 1 to 2 bbl/min, per pod, may be obtained. As with the cartridge systems, this
rate may be increased by operating several pods in parallel.
Multimedia filters consist of layers of granular materials of reasonably uniform sizes. The
most commonly used materials are sand, gravel, walnut hulls, and garnet. Normally,
several of these media are used in a single system. The media layers are packed into a
pressure vessel in one of several configurations. The layers may be horizontal, vertical, or
radial. Finer media bridges on successively coarser media in the direction of fluid flow.
In principal, the filter operation is similar to a gravel pack. The fluid flows through the
filter, trapping particles which are larger than a specified diameter. When the filter begins
to plug up, the differential pressure across the filter will build rapidly. The system will then
need to be periodically backwashed. Backwashing is accomplished by simply switching
valves. The length of time between backwashings can be increased by using a precleaning
method, before filtering, to remove larger solids.
Multimedia filters, in general, can provide higher flow rates than cartridge or bag-type
filters. These filters are available in vertical, horizontal, and radial configurations. Vertical
filters are more often used for workover and completion operations. A vertical filter can
provide a flow rate as high as 25 bbl/min. Normally, a system consists of two filters
operated in tandem, so that one filter may be used to backwash the other. An important
advantage of multimedia system over the cartridge and bag type filters is that it may be
operated unattended, except for periodic maintenance. Multimedia filters are used in large
volume operations, such as in injection water preparation.
Diatomaceous earth is the fossil-like remains of microscopic water plants, called diatoms.
Packed diatoms are highly permeable and virtually insoluble. They are often used as a filter
media. Diatomaceous earth is used frequently as a filter aid with many types of filtration
systems.
Filtration systems which use D.E. as a filter aid are: tubular filters, plate and frame press
filters, and vertical pressure and leaf filters. These filters are designed for large filtering
capacities and long-term operations. The median pore size of diatomaceous earth ranges
from 1.5 micron to 22 micron. D.E. filtration methods are as effective as cartridge, bag, and
multimedia filters. D.E. filters can filter at high flow rates and they are more economical
than cartridge or bag filters.
9.16
APPENDIX A – BRINE DATA
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Figure A-1. Freezing and crystallization of brines
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Figure A-2. Material requirements for preparing potassium chloride solutions
Table A - I
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Physical Properties of Potassium Chloride Solutions.
Data at 68°F
Potassium
Chloride
(% by weight)
Specific
Gravity
Weight
(lb/gal)
Chloride
(mg/λ
λ)
Freezing
Point (°F)
Hydrostatic
Head (psi/100ft)
0.0
1.0
2.0
3.0
4.0
5.0
6.0
7.0
8.0
9.0
10.0
11.0
12.0
13.0
14.0
15.0
16.0
17.0
18.0
19.0
20.0
22.0
24.0
0.9982
1.0046
1.0110
1.0174
1.0239
1.0304
1.0369
1.0434
1.0500
1.0566
1.0633
1.0700
1.0768
1.0836
1.0905
1.0974
1.1043
1.1114
1.1185
1.1256
1.1328
1.1474
1.1623
8.33
8.38
8.44
8.49
8.54
8.60
8.65
8.71
8.76
8.82
8.87
8.93
8.99
9.04
9.10
9.16
9.22
9.28
9.33
9.39
9.45
9.58
9.70
0
4,756
9,606
14,505
19,498
24,491
29,580
34,716
39,947
45,226
50,552
55,973
61,442
67,006
72,618
78,277
84,031
89,833
95,730
101,722
107,762
120,031
132,634
32.0
31.2
30.3
29.5
28.7
27.8
26.9
26.1
25.2
24.3
23.4
22.4
21.4
20.4
43.28
43.55
43.83
44.11
44.39
44.67
44.95
45.23
45.52
45.81
46.10
46.39
46.68
46.98
47.28
47.58
47.87
48.18
48.49
48.80
49.11
49.74
50.39
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Figure A-3. Decrease in density of potassium chloride brines with increasing temperature
Figure A-4. Potassium chloride solution viscosities
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Figure A-5. Material requirements for preparing sodium chloride solutions
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Table A - II
Physical Properties of Sodium Chloride Solutions.
Data at 60°F
% Sodium
Chloride By
Weight
Specific
Gravity
Weight Lbs.
Per Gal
mg/l*
Sodium
Chloride
mg/l*
Chloride
Freezing
point °F
Hydrostatic
Head PSI per
100 ft.
1.0
2.0
3.0
4.0
5.0
6.0
7.0
8.0
9.0
10.0
11.0
12.0
13.0
14.0
15.0
16.0
17.0
18.0
19.0
20.0
21.0
22.0
23.0
24.0
25.0
26.0
1.007
1.014
1.021
1.029
1.036
1.043
1.051
1.059
1.067
1.074
1.082
1.089
1.097
1.104
1.112
1.119
1.127
1.135
1.143
1.151
1.159
1.168
1.176
1.184
1.193
1.201
8.40
8.46
8.52
8.59
8.65
8.70
8.77
8.84
8.90
8.96
9.03
9.09
9.15
9.21
9.28
9.34
9.41
9.47
9.54
9.61
9.67
9.75
9.81
9.88
9.96
10.02
10,070
20,280
30,630
41,160
51,800
62,580
73,570
84,720
96,030
107,400
119,020
130,680
142,610
154,560
166,800
179,040
191,590
204,300
217,170
230,200
243,390
256,960
270,480
284,160
298,250
312,260
6,110
12,300
18,580
24,970
31,420
37,960
44,630
51,390
58,250
65,150
72,200
79,270
86,510
93,760
101,180
108,610
116,220
123,930
131,740
139,640
147,650
155,880
164,080
172,380
180,920
189,420
31.0
30.0
28.9
27.8
26.7
25.5
24.2
22.9
21.6
20.2
18.8
17.3
15.7
14.1
12.4
10.6
8.7
6.7
4.6
2.4
0.0
-2.5
-5.2
+1.4
+13.3
+27.9
43.68
43.99
44.30
44.67
44.98
45.24
45.60
45.97
46.28
46.59
46.96
47.27
47.58
47.89
48.26
48.57
48.93
49.24
49.61
49.97
50.28
50.70
51.01
51.38
51.79
52.10
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Figure A-6. Decrease in densities of sodium chloride brines with increasing temperature
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Figure A-7. Sodium chloride solution viscosities
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Figure A-8. Material requirements for preparing calcium chloride/sodium chloride solutions
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Table A - III
Physical Properties of Constant – Freezing
Calcium Chloride – Sodium Chloride Brines.
Data at 60°F
Sodium
Chloride
(% by weight
Calcium Chloride
(95%)
(% by weight)
Specific
Gravity
Weight
(lb/gal)
Chloride
(mg/λ
λ)
Hydrostatic
Head
(psi/100 ft.
26.7
21.2
16.3
12.7
9.7
7.5
5.6
4.4
3.4
2.6
2.1
1.6
1.3
0.9
0.6
0.5
0.4
0.3
0.0
6.1
12.4
16.8
20.8
23.7
26.3
28.5
30.3
32.1
33.5
35.0
36.6
37.7
39.1
40.2
41.4
42.3
1.1983
1.2102
1.2222
1.2342
1.2462
1.2582
1.2702
1.2821
1.2941
1.3061
1.3181
1.3301
1.3421
1.3540
1.3660
1.3780
1.3900
1.4020
10.0
10.1
10.2
10.3
10.4
10.5
10.6
10.7
10.8
10.9
11.0
11.1
11.2
11.3
11.4
11.5
11.6
11.7
194,111
189,482
190,307
190,102
192,109
193,883
196,223
201,651
206,360
212,707
219,118
226,220
235,657
241,285
249,700
258,003
267,049
274,285
51.95
52.47
52.99
53.51
54.03
54.55
55.07
55.58
56.10
56.62
57.14
57.66
58.18
58.70
59.22
59.74
60.26
60.78
All of these mixtures freeze very slightly below 60°F
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Figure A-9. Decrease in densities of calcium chloride/sodium chloride brines with increasing temperatures
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Figure A-10. Material requirements for preparing calcium chloride solutions
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Table A - IV
Physical Properties of Calcium Chloride Solutions
All Data Based on Readings at 60°F
Weight of Solution
Freezing Data
Lbs. Calcium Chloride Type 1
(77% min.)
Lbs. Calcium Chloride Type 2
(94% min.)
Specific
Gravity
‘Baume at
60°F
(Am. Std)
Lbs. per
gallon
Lbs. per
Cu.Ft
Per Cent
CaCl2
Actual
Crystallisa
tion Starts
°F
Apparent
Solidificat
ion °F
Per Gal.
Solut
ion
≅ Per
Gal.
Water
Α Final
Vol.
Gals.
Per Gal.
Solut
ion
≅ Per
Gal.
Water
Α Final
Vol.
Gals.
1.000
1.010
1.020
1.030
1.040
1.050
1.060
1.070
1.080
1.090
1.100
1.110
1.120
1.130
1.140
1.150
1.160
1.170
1.180
1.190
1.200
1.210
1.220
1.230
1.240
1.250
1.260
1.270
1.280
1.290
1.300
1.310
1.320
1.330
1.340
1.350
1.360
1.370
1.380
1.390
1.400
1.410
0.0
1.4
2.8
4.2
5.6
6.9
8.2
9.5
10.7
12.0
13.2
14.3
15.5
16.7
17.8
18.9
20.0
21.1
22.1
23.2
24.2
25.2
26.2
27.1
28.1
29.0
29.9
30.8
31.7
32.6
33.5
34.3
35.1
36.0
36.8
37.6
38.4
39.0
39.9
40.7
41.4
42.2
8.34
8.42
8.50
8.59
8.67
8.75
8.84
8.92
9.00
9.09
9.17
9.25
9.34
9.42
9.50
9.59
9.67
9.75
9.84
9.92
10.00
10.09
10.17
10.25
10.34
10.42
10.50
10.59
10.67
10.75
10.84
10.92
11.01
11.09
11.17
11.26
11.34
11.42
11.51
11.59
11.67
11.76
62.37
62.99
63.61
64.24
64.86
65.48
66.11
66.73
67.36
67.98
68.60
69.23
69.85
70.47
71.10
71.72
72.35
72.97
73.59
74.22
74.84
75.46
76.09
76.71
77.33
77.96
78.58
79.21
79.83
80.45
81.08
81.70
82.32
82.95
83.57
84.19
84.82
85.44
86.07
86.69
87.31
87.94
0
1.2
2.3
3.5
4.6
5.9
7.0
8.1
9.2
10.3
11.4
12.4
13.5
14.5
15.6
16.6
17.6
18.6
19.5
20.6
21.5
22.4
23.3
24.2
25.1
26.0
27.0
27.8
28.7
29.6
30.5
31.3
32.2
33.2
34.0
34.9
35.8
36.4
37.4
38.3
39.2
40.0
+32.0
+31.0
+30.2
+29.1
+28.0
+27.0
+25.9
+24.5
+23.2
+21.9
+20.3
+18.7
+16.5
+14.5
+12.2
+ 9.7
+ 7.0
+ 4.1
+ 1.2
- 2.0
- 5.8
- 9.4
- 13.2
- 17.1
- 21.5
- 25.8
- 31.2
- 37.1
- 44.3
- 59.8
- 41.8
- 29.2
- 17.0
- 4.7
- 4.3
+14.3
+21.7
+30.0
+37.0
+44.4
+50.9
+55.9
+32.0
+29.5
+26.6
+22.8
+19.0
+14.3
+10.3
+ 6.0
+ 1.7
- 2.7
- 7.2
- 11.5
- 16.2
- 20.7
- 25.7
- 30.2
- 34.4
- 38.4
- 41.7
- 45.2
- 47.9
- 50.2
- 52.4
- 54.4
- 56.2
- 57.8
- 59.5
- 60.6
- 61.8
….
….
….
….
….
….
….
….
….
….
….
….
….
….
0.13
0.25
0.39
0.51
0.66
0.79
0.92
1.06
1.20
1.34
1.47
1.62
1.75
1.90
2.04
2.19
2.33
2.46
2.62
2.76
2.90
3.03
3.18
3.33
3.48
3.64
3.79
3.93
4.08
4.24
4.38
4.54
4.72
4.87
5.04
5.20
5.33
5.52
5.69
5.86
6.03
….
0.13
0.25
0.40
0.52
0.68
0.82
0.96
1.11
1.28
1.43
1.57
1.75
1.90
2.08
2.25
2.44
2.02
2.78
2.99
3.18
3.36
3.54
3.75
3.96
4.18
4.42
4.65
4.86
5.10
5.36
5.58
5.86
6.18
6.45
6.76
7.07
7.30
7.69
8.05
8.41
8.79
1.000
1.006
1.011
1.017
1.022
1.030
1.036
1.043
1.050
1.058
1.065
1.071
1.080
1.087
1.096
1.104
1.113
1.122
1.131
1.142
1.152
1.160
1.170
1.180
1.190
1.202
1.215
1.227
1.237
1.250
1.264
1.278
1.293
1.309
1.324
1.341
1.359
1.375
1.393
1.414
1.435
1.457
….
0.11
0.21
0.32
0.42
0.54
0.65
0.76
0.87
0.99
1.10
1.21
1.33
1.44
1.56
1.68
1.79
….
0.11
0.21
0.32
0.42
0.55
0.66
0.77
0.89
1.01
1.13
1.24
1.37
1.49
1.62
1.75
1.88
1.000
1.004
1.006
1.008
1.011
1.016
1.019
1.022
1.026
1.029
1.033
1.036
1.040
1.044
1.049
1.052
1.057
1.062
1.064
1.071
1.075
1.078
1.083
1.088
1.092
1.097
1.104
1.107
1.113
1.120
1.125
1.130
1.137
1.146
1.152
1.159
1.168
1.171
1.181
1.190
1.200
1.207
1.91
2.01
2.02
2.15
2.26
2.38
2.49
2.61
2.73
2.85
2.98
3.10
3.22
3.35
3.48
3.60
3.73
3.88
4.00
4.14
4.27
4.38
4.53
4.67
4.82
4.95
2.13
2.28
2.40
2.53
2.67
2.80
2.94
3.08
3.25
3.38
3.53
3.69
3.85
4.00
4.17
4.36
4.52
4.71
4.90
5.02
5.24
5.45
5.66
5.85
≅
Pounds of calcium chloride per cubic foot of water at 60°F may be obtained by multiplying the quantity in pounds per gallon by 7.481
Α
Final volume in gallons at 60°F when quantity of calcium chloride shown in previous column is added to one gallon of water.
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Figure A-11. Decrease in densities of calcium chloride brines with increasing temperature
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Figure A-12. Calcium chloride solution viscosities
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Table A - V
Minimum Cost Calcium Chloride – Calcium Bromide Brines
Mixing Tables
CaCl2 – CaBr2
Density Desired
Barrels 14.2 lb/gal
CaBr2
Barrels 11.6 lb/gal
CaCl2
Pounds 94-97%
Calcium Chloride
Flake or Pellet
11.7
11.8
11.9
12.0
12.1
12.2
12.3
12.4
12.5
12.6
12.7
12.8
12.9
13.0
13.1
13.2
13.3
13.4
13.5
13.6
13.7
13.8
13.9
14.0
14.1
14.2
14.3
14.4
14.5
14.6
14.7
14.8
14.9
15.0
15.1
.0254
.0507
.0762
.1016
.1269
.1524
.1778
.2032
.2285
.2540
.2794
.3048
.3302
.3556
.3810
.4084
.4318
.4572
.4826
.5080
.5334
.5589
.5842
.6069
.6351
.6604
.6858
.7113
.7366
.7620
.7875
.8128
.8382
.8637
.8891
.9714
.9429
.9143
.8857
.8572
.8286
.8000
.7715
.7429
.7143
.6857
.6572
.6286
.6000
.5714
.5429
.5143
.4857
.4572
.4286
.4000
.3714
.3429
.3143
.2857
.2572
.2286
.2000
.1715
.1429
.1143
.0858
.0572
.0286
.0000
2.86
6.06
9.09
12.13
15.15
18.18
21.22
24.24
27.28
30.31
33.34
36.37
39.41
42.44
45.47
48.49
51.53
54.56
57.59
60.62
63.65
66.69
69.72
72.75
75.78
78.81
81.84
84.88
87.90
90.94
93.97
96.99
100.03
103.06
106.10
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Table A - VI
Minimum - Cost Calcium Chloride – Calcium Bromide Brines
Table of Chemicals for the Preparation of 1 bbl of
DENSITY
DESIRED
BARRELS
WATER
POUNDS
CaCl2
POUNDS
CaBr2 (91%)
11.7
11.8
11.9
12.0
12.1
12.2
12.3
12.4
12.5
12.6
12.7
12.8
12.9
13.0
13.1
13.2
13.3
13.4
13.5
13.6
13.7
13.8
13.9
14.0
14.1
14.2
14.3
14.4
14.5
14.6
14.7
14.8
14.9
15.0
15.1
.8493
.8421
.8349
.8277
.8205
.8133
.8061
.7989
.7917
.7845
.7773
.7701
.7629
.7557
.7485
.7415
.7343
.7271
.7199
.7127
.7055
.6983
.6911
.6839
.6767
.6695
.6623
.6551
.6479
.6407
.6335
.6263
.6191
.6119
.6047
195.39
193.09
190.79
188.49
186.10
183.89
181.59
179.29
176.99
174.69
172.39
170.09
167.79
165.49
163.19
160.89
158.59
156.29
153.99
151.69
149.39
147.09
144.80
142.51
140.21
137.91
135.61
133.31
131.01
128.71
126.41
124.11
121.81
119.51
117.21
6.24
14.96
23.68
32.40
41.12
49.84
58.56
67.28
76.00
84.72
93.44
102.16
110.88
119.60
128.32
137.04
145.76
154.48
163.20
171.92
180.64
189.36
198.08
206.81
215.53
224.25
232.97
241.69
250.41
259.13
267.85
276.57
285.29
294.01
302.73
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Figure A-13. Decrease in density of minimum-cost calcium chloride/
calcium bromide brines with increased temperature
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Figure A-14. Minimum-cost calcium chloride/calcium bromide brines : Temperature vs. apparent viscosity
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Figure A-15. Apparent viscosity of minimum-cost calcium chloride/
calcium bromide solutions containing HEC
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Figure A-16. Viscosities of calcium bromide solutions
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Table A - VII
Calcium Bromide/Zinc Bromide Solution Requirements Using
14.2 lb/gal ZnBr2/CaBr2 Brine and 19.2 lb/gal ZnBr2/CaBr2 Brine
To Make 1 bbl (42 gal)
Brine density at
60°F lb/gal
14.2 lb/gal
CaBr2 bbl
19.2 lb/gal
CaBr2/ZnBr2 bbl
Crystallization Point
60°F
15.0
15.1
15.2
15.3
15.4
15.5
15.6
15.7
15.8
15.9
16.0
16.1
16.2
16.3
16.4
16.5
16.6
16.7
16.8
16.9
17.0
17.1
17.2
17.3
17.4
17.5
17.6
17.7
17.8
17.9
18.0
18.1
18.2
18.3
18.4
18.5
18.6
18.7
18.8
18.9
19.0
19.1
19.2
.840
.820
.800
.780
.760
740
.720
.700
.680
.660
.640
.620
.600
.580
.560
.540
.520
.500
.480
.460
.440
.420
.400
.380
.360
.340
.320
.300
.280
.260
.240
.220
.200
.180
.160
.140
.120
.100
.080
.060
.040
.020
.000
.160
.180
.200
.220
.240
.260
.280
.300
.320
.340
.360
.380
.400
.420
.440
.460
.480
.500
.520
.540
.560
.580
.600
.620
.640
.660
.680
.700
.720
.740
.760
.780
.800
.820
.840
.860
.880
.900
.920
.940
.960
.980
1.000
- 22
- 25
- 27
- 29
- 32
- 34
- 35
- 38
- 40
- 37
- 33
- 30
- 26
- 23
- 20
- 16
- 11
- 8
- 6
- 4
- 4
- 2
0
+ 2
+ 4
+ 5
+ 5
+ 6
+ 7
+ 7
+ 9
+ 10
+ 11
+ 13
+ 15
+ 17
+ 19
+ 21
+ 23
+ 20
+ 21
+ 18
+ 16
Table A - VIII
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Calcium Bromide/Zinc Bromide Solution Requirements Using
14.2 lb/gal CaBr2 Brine, 14.5 lb/gal ZnBr2 Brine, and Dry 91% Pure CaBr2
To Make 1 bbl (42 gal)
Brine density at
60°F lb/gal
14.2 lb/gal
CaBr2 bbl
14.5 lb/gal
ZnBr2 bbl
91%
CaBr2 lb
14.5
14.6
14.7
14.8
14.9
15.0
15.1
15.2
15.3
15.4
15.5
15.6
15.7
15.8
15.9
16.0
16.1
16.2
16.3
16.4
16.5
16.6
16.7
16.8
16.9
17.0
17.1
17.2
17.3
17.4
17.5
17.6
17.7
17.8
17.9
18.0
.8833
.8565
.8223
.7859
.7555
.7109
.6859
.6530
.6239
.5921
.5632
.5287
.4964
.4651
.4268
.3944
.3515
3205
.2893
.2610
.2254
.2034
.1776
.1467
.0928
.0587
.0229
.0060
.0000
-
.0900
.1067
.1318
.1531
.1788
.2079
.2322
.2547
.2722
.2995
.3228
.3413
.3627
.3912
.4233
.4513
.4852
.5083
.5250
.5496
.5690
.5862
.6058
.6372
.6842
.7093
.7241
.7449
.7552
.7548
.7447
.7356
.7263
.7181
.7098
.6890
27.41
37.41
58.65
59.67
66.33
73.08
83.71
93.84
104.74
111.25
118.48
132.43
142.43
147.98
156.27
161.95
171.08
179.63
192.37
198.37
212.06
218.92
226.56
230.03
238.49
247.04
263.58
265.12
266.66
271.13
281.51
291.24
301.08
310.25
319.52
336.42
Blending Procedure: Add 14.2 lb/gal Calcium bromide and 14.5 lb/gal zinc bromide, followed by the
91% calcium bromide. The desired density should be measured at 60°F.
Table A - IX
Calcium Chloride/Calcium Bromide/Zinc Bromide Solution Requirements Using
15.0 lb/gal CaCl2/CaBr2 Brine, 19.2 lb/gal ZnBr2/CaBr2
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To Make 1 bbl (42 gal)
Brine Density at
60°F lb/gal
15.0 lb/gal
CaCl2/ CaBr2 bbl
19.2 lb/gal
CaBr2/ZnBr2 bbl
Crystallization Point
°F
15.0
15.1
15.2
15.3
15.4
15.5
15.6
15.7
15.8
15.9
16.0
16.1
16.2
16.3
16.4
16.5
16.6
16.7
16.8
16.9
17.0
17.1
17.2
17.3
17.4
17.5
17.6
17.7
17.8
17.9
18.0
18.1
18.2
18.3
18.4
18.5
18.6
18.7
18.8
18.9
19.0
19.1
19.2
1.000
.976
.952
.929
.905
.881
.857
.833
.810
.786
.762
.738
.714
690
.667
.643
.619
.592
.571
.548
.524
.500
.476
.452
.429
.405
.381
.357
.333
.310
.286
.262
.238
.214
.190
.167
.143
.119
.095
.071
.048
.024
.000
.000
.024
.048
.071
.095
.119
.143
.167
.190
.214
.238
.262
.286
.310
.333
.357
.381
.405
.429
.452
.476
.500
.524
.548
.571
.592
.619
.643
.667
.690
.714
.738
.762
.786
.810
.833
.857
.881
.905
.929
.952
.976
1.000
+ 64
62
61
59
59
59
58
57
55
54
53
52
50
50
49
47
46
43
40
36
32
28
31
35
37
41
45
44
44
43
43
42
41
37
35
32
28
25
23
18
18
17
16
Table A - X
Calcium Chloride/Calcium Bromide/Zinc Bromide Solution Requirements Using
14.2 lb/gal CaBr2 Brine, 14.5 lb/gal ZnBr2 Brine, Dry 94% Pure CaCl2 ,
and Dry 91% Pure CaBr2
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To Make 1 bbl (42 gal)
Brine Density
at 60°F lb/gal
14.2 lb/gal
CaBr2 bbl
14.5 lb/gal
ZnBr2 bbl
94%
CaCl2 lb
91%
CaBr2 lb
15.1
15.2
15.3
15.4
15.5
15.6
15.7
15.8
15.9
16.0
16.1
16.2
16.3
16.4
16.5
16.6
16.7
16.8
16.9
17.0
17.1
17.2
17.3
17.4
17.5
17.6
17.7
17.8
17.9
18.0
.8647
.8348
.8050
.7752
.7454
.7156
.6858
.6560
.6261
.5963
.5665
.5367
.5069
.4770
.4472
.4174
.3876
.3578
.3280
.2982
.2683
.2385
.2087
.1789
.1491
.1193
.0895
.0596
.0298
.0000
.0000
.0226
.0452
.0678
.904
.1130
.1357
.1583
.1809
.2035
.2261
.2487
.2713
.2939
.3166
.3392
.3618
.3844
.4070
.4296
.4522
.4748
.4974
.5200
.5427
.5653
.5879
.6105
.6331
.6559
113.40
111.13
108.86
106.59
104.32
102.05
99.78
97.51
95.24
92.97
90.70
88.43
86.16
83.89
81.62
79.35
77.08
74.81
72.54
70.27
68.00
65.73
63.46
61.19
58.92
56.65
54.38
52.11
49.84
47.57
5.13
15.60
26.08
36.55
47.02
57.50
67.97
78.44
88.91
99.12
109.86
120.33
130.81
141.28
151.75
162.23
172.70
183.17
193.65
204.12
214.59
225.07
235.54
246.01
256.48
266.96
277.43
287.90
298.38
308.97
Blending Procedure : Add 14.2 lb/gal calcium bromide and 14.5 lb/gal zinc bromide followed by the
94% calcium chloride. Allow about thirty minutes for the majority of the chloride to dissolve.
Then add the 91% calcium bromide. The desired density should be measured at 60°F.
The crystallization point for each of these fluids is between 45 and 50°F.
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Figure A-17. Decrease in density of minimum cost calcium chloride/
calcium bromide/zinc bromide brines with increasing temperature
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Figure A-18. Viscosity of CaBr2-ZnBr2 at various temperatures
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Figure A-19. Corrosivity of CaCl2/CaBr2/ZnBr2 brines at 250°F
Table A - XI
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Sodium Bromide Solution Requirements Using Sacked NaBr (95%)
To Make 1 bbl (42 gal)
Brine Density at
70°F lb/gal
Water bbl
95%
NaBr bbl
Crystallization
Point, °F
9.5
9.6
9.7
9.8
9.9
10.0
10.1
10.2
10.3
10.4
10.5
10.6
10.7
10.8
10.9
11.0
11.1
11.2
11.3
11.4
11.5
11.6
11.7
11.8
11.9
12.0
12.1
12.2
12.3
12.4
12.5
12.6
12.7
.950
.946
.941
.937
.933
.927
.923
.918
.914
.910
.905
.900
.895
.891
.886
.882
.877
.872
.867
.862
.857
.853
.847
.844
.839
.834
.831
.825
.823
.816
.812
.807
.804
66.4
72.0
77.9
83.6
89.2
95.4
101.1
107.1
112.6
118.2
124.1
130.2
136.0
141.7
147.6
153.3
159.2
165.1
171.1
177.0
183.0
188.6
194.8
200.2
206.0
212.0
217.3
223.6
228.5
235.1
240.7
246.7
252.0
20
19
18
16
15
14
12
11
10
8
6
5
4
2
0
-2
-3
-5
-7
-9
-11
-14
-16
-19
-10
6
14
27
34
43
50
57
63
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Figure A-20. Decrease in density of sodium chloride/sodium bromide brines with increasing temperature
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Table A - XII
Low Freezing Point Workover Fluids
(10.4 and 10.6 lb/gal)
Ethylene Glycol-Water
9.17
1
2
3
4
5
6
Ratio H2O : Et(OH) 2, v:v
Ratio NaBr:NaCl2, w:w
Total Solids, wt%
80:20
50:50
27
80:20
50:50
29
80:20
75:25
25
80:20
75:25
27.5
70:30
75:25
24
70:30
75:25
26.5
Ingredients to make 1 barrel:
- H2O, gal
- Et(OH) 2, gal
- NaBr, lb
- NaCl, lb
29.8
7.6
59.1
59.1
29.5
7.5
64.7
64.7
30.6
7.7
81.8
27.2
30.4
7.7
91.9
30.6
26:8
11.5
78.7
26.2
26.6
11.5
88.6
29.5
Density at 72°F, lb/gal
Density at Freeze Pt., lb/gal
Freeze Point, °F
Flash Point (Closed Cup), °F
Raw Material Cost, $/bbl
10.4
10.3
- 29
> 250
37
10.6
10.4
- 30
> 250
39
10.4
10.4
- 25
> 250
43
10.6
10.6
- 32
>250
46
10.4
10.4
- 39
> 250
51
10.6
10.6
- 40
> 250
54
APPENDIX B – HYDROCARBON DATA
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Table B - I
Typical Compositions of Petroleum Products
Summary of Product Types Produced From Petroleum
Number of Carbon Atoms
Boiling Point of Normal
°C
Paraffin at 760 mm
°F
C1
-161
-259
C2
- 89
-127
C3
-42
-44
C4
-0.5
+31
C5
+36
97
C6
69
156
C7
98
209
C8
126
258
C9
151
303
C10
174
345
C11
196
384
C12
216
421
C13
235
456
C14
253
488
Liquefied Petroleum Gas
Precipitation Naphtha
VM&P Naphtha
Mineral Spirits
Reformate
Gasoline
Kerosene, Diesel Fuel
Aviation Turbine Fuel
Gas Oil, Fuel Oil
Transformer Oil
Lubricating Oil
Asphalt, Pitch
Wax
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C15
270
519
C16
287
548
C17
302
575
C18
316
601
C19
329
625
C20
343
649
>
C20
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Figure B-1. Approximate specific gravity of petroleum fractions: Effect of temperature
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Figure B-2. Effect of pressure on hydrocarbon fluid densities
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Figure B-3. Specific gravity of petroleum fractions
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Figure B-4. Viscosity of petroleum fractions and hydrocarbon liquids
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Figure B-5. Viscosity of gas-free crude oil at oil-field temperature
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Figure B-6. Effect of pressure on viscosity of gas-saturated crude oils
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Figure B-7. Viscosity of gas-saturated crude oil at reservoir temperature and pressure.
Dead oil viscosity from laboratory data after Chew and Connally.
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Figure B-8. Effect of temperature and pressure on viscosity of diesel oil
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CHAPTER 10
PERFORATING
TABLE OF CONTENTS
10.1
INTRODUCTION………………………………………………………………...... 4
10.1.1
10.1.2
10.1.3
10.1.4
10.2
5
6
7
8
Gun Size …………………………………………………………… 9
Explosive Load …………………………………………………….. 9
9
Gun Clearance
11
………………………………………………………
API RP 43 …………………………………………………………. 12
Surface Test ………………………………………………………... 12
Laboratory Flow Test ………………………………………………
CASING DEFORMATION/DAMAGE………………………………........…….. 15
10.4.1
10.4.2
10.4.3
10.4.4
10.4.5
10.5
Shaped Charge Components ………………………………………..
Detonation ………………………………………………………….
Jet-Impingement Pressure …………………………………………..
Penetration ………………………………………………………….
GUN DESIGN AND TESTING…………………………………………………… 9
10.3.1
10.3.2
10.3.3
10.3.4
10.3.5
10.3.6
10.4
4
4
SHAPED CHARGE FUNDAMENTALS...………………………………………. 5
10.2.1
10.2.2
10.2.3
10.2.4
10.3
Purpose ……………………………………………………………..
The Objective of Perforating………………………………………...
Gun Type …………………………………………………………... 15
Casing Support …………………………………………………….. 16
Explosive Load …………………………………………………….. 18
Hydrostatic Pressure ……………………………………………….. 18
Guidelines ………………………………………………………….. 19
PERFORATION PRODUCTIVITY…….……………………………………….. 19
10.5.1
10.5.2
Clean-Up Characteristics …..………………………………………. 19
Core Flow Efficiency ………………………………………………. 21
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10.5.3
10.5.4
10.5.5
10.5.6
10.5.7
10.5.8
10.5.9
10.6
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Differential Pressure ……………………………………………….. 23
Type Of Wellbore Fluid …………………………………………… 24
Depth Of Penetration ……………………………….……..…….…. 24
Diameter Of Perforation …………………………….….….…….… 25
Type And Quality Of Charge ..……………………..…..……...…... 25
Shot Density And Pattern ………………………..………………… 26
Type And Size Of Gun …………………………..………………... 28
RETRIEVABLE HOLLOW-CARRIER GUNS………………………………… 29
10.6.1
10.6.2
10.6.3
Description …………………………………………………………. 29
Operations ………………………………………………………….. 29
Applications ………………………………………………………... 29
10.7EXPENDABLE GUNS………………………………………………..…………… 32
10.7.1
10.7.2
10.7.3
10.7.4
Description …………………………………………………………. 32
Operations ………………………………………………………….. 32
Applications ………………………………………………………... 33
Pirot Guns ......................................................................................
10.8TUBING CONVEYED GUNS…………………………………………………….. 34
10.8.1
10.8.2
10.8.3
Description …………………………………………………………. 34
Operations ………………………………………………………….. 34
Applications …………………………………………………….….. 34
10.9PERFORATION DESIGN………………………………………………………… 36
10.9.1
10.9.2
10.9.3
10.9.4
Matrix Acidizing …………………………………………………… 36
Diversion …………………………………………………………… 36
Gravel Packing …………………………………………………….. 36
Fracturing …………………………………………….…….………. 37
10.10 PERFORATING OPERATIONS………………………………………………... 39
10.10.1
10.10.2
10.10.3
10.10.4
10.10.5
10.10.6
10.10.7
Selecting Firing ……………………………………………………. 39
Depth Correlation ………………………………………………….. 40
Gun Orientation ……………………………………………………. 40
Perforating Fluid …………………………………………………… 42
Overbalanced Perforating ………………………………………….. 42
Underbalanced Perforating ………………………………………… 44
45
TCP Firing Systems ......................................................................
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10.10.9
10.10.10
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High-Temperature Perforating …………………………………….. 52
Wellhead Pressure Control ...………………………………………. 53
Safety .............................................................................................
10.11 SPECIALIZED EQUIPMENT AND OPERATIONS…………………………... 54
10.11.1
10.11.2
10.11.3
10.11.4
Limited Penetration Devices ………………………………………. 54
Tubing-Casing Cutters …………………………………………….. 55
Hydraulic Jet Perforator ……………………………………………. 56
Well Cleaning Before Perforating ................................................... 56
10.12 REFERENCES…………………………………………………………….………. 58
10.1
INTRODUCTION
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Purpose
Perforating is one of the most important and widely applied of the various cased-hole
operations. Perforating provides a path for flow communication between the wellbore and
reservoir.
The efficient completion of production and injection wells plays a crucial role in the
profitable development of oil and gas accumulations. The perforation operation is clearly a
critical activity in the completion process, as the first requirement of any perforated
completion is unimpaired communication through the production casing, cement sheath and
zone damaged by drilling operations.
Perforating is a complex process greatly influenced by many geological and mechanical
uncertainties such as reservoir characteristics and explosive charge performance. Although
perforating technology is viewed as being relatively mature, our inadequate understanding
of perforating fundamentals and our intrinsic inability to assess perforator performance
(perforation geometry, effective shot density) downhole make it virtually impossible to
offer definitive recommendations. Rather than attempt to provide a list of ‘rules of thumb’,
this chapter discusses the principles of perforating and the likely effect various parameters
have on performance. Local field tests under controlled conditions may assist in
substantiating the often conflicting, and at times unclear conclusions drawn by different
sources within the industry. Nevertheless, there are a number of principle design criteria
which should always be considered when designing a perforated completion: depth of
penetration, shot density, shot phasing, entrance hole diameter and clean up requirements.
The relative importance of each is clearly related to the completion type. However,
regardless of completion type, penetration and effective shot density are normally important
design parameters as they also directly relate to other perforating and completion
considerations (formation damage, inflow performance and reservoir heterogeneity).
Perhaps the single most important factor is perforation clean up - perforating underbalance
and producing the well is recommended.
10.1.2
The Objective of Perforating
The objective of perforating a well is to provide a flow path between the productive
formation and the wellbore. This is achieved by the creation of passages which penetrate
the casing, cement and formation to a depth which bypasses formation damage and
permeability impairment caused by the drilling and cementing processes. The crosssectional area, wall area and permeability of the passages created must allow the production
or injection of the required fluid volumes.
10.1.3
The History of Perforating
Explosives were first invented by the Chinese in the 10th Century, and later by the Arabs,
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in the 13th century. These were low explosives made from mixtures of sodium or
potassium nitrate, powdered charcoal and sulphur, and are referred to as black powder.
These explosives have a relatively slow reaction rate of about 500-1500 m/s and the
combustion pressures generated are low. Detonation of low explosives does not occur
unless the combustion products are confined, generating high pressures.
The first high explosive was discovered by an Italian, Ascano Sobreto, in 1846, who found
that reacting nitric acid with glycerol produced an oily liquid. Small quantities of this oily
liquid, nitroglycerine, exploded violently even when unconfined. Due to the sensitivity to
shock of nitroglycerine, it was of little commercial use until Alfred Nobel combined it with
kieselguhr, a clay soil, to make dynamite, which was the first commercial high explosive.
Nobel developed and patented the detonator which initiated detonation by “percussion or
sudden pressure”. High explosives detonate at rates of 5000-9000 m/s generating very high
combustion pressures.
The use of explosives to increase the productivity of wells was first reported in the United
States in 1866, when a dry well was stimulated by lowering two torpedoes of gunpowder
into the well. The torpedoes were detonated opposite the formation with a drop bar, and the
well produced at a rate of 80 barrels of oil per day.
Within the industry today low explosives are used in core guns, bullet guns, and as power
charges in pressure setting assemblies. High explosives are used as a signal source in
seismic work, and in shaped-charge perforating guns. They are also present in the igniters
used to initiate the power charge in pressure setting assemblies, and are used for cutting and
severing of tubulars.
10.1.4
Shaped Charge Development
The first observation of the effects of a shaped explosive charge was reported by Charles E.
Monroe in Scribner’s Magazine in May 1888. Monroe observed that the explosion of gun
cotton indented with the letters USN 1884 left an impression when detonated on a steel
plate. Although the indentations were not lined, an impression approximately half the
diameter of the indentation was made in the steel plate. In the late 1930’s, a Swiss, H.
Mohaupt, and an American, Dr. R. W. Wood observed that a large increase in penetration
could be obtained if the cavity in the explosive was lined with metal. This technique was
then developed and used in anti-tank weapons such as the bazooka. The effects of lined
unlined cavities when detonated on a steel target are compared with the effect of bulk
explosive in Figure 1 [16].
In 1948 the shaped charge technique was applied commercially for the first time in the
perforation of oil wells by the Welex Jet Perforating Company, which is now a subsidiary
of Halliburton Industries. Although the performance of the shaped charge was superior to
the bullet gun in terms of hole size and penetration, the productivity of the perforations was
in some cases found to be inferior to those of bullet guns. Investigation of the operation of
shaped charges indicated that the perforation could get plugged by the material used to line
the shaped charge, and that the crushing and compaction of the formation around the
formation around the perforation tunnel created a localised reduction in permeability.
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Plugging has been reduced by the use of powdered metal liners, and the permeability
reduction is now measured and used to assess and compare charges. Many improvements
have been made in the design and operation of perforating guns, and a variety of methods is
available by which they can be positioned and fired.
Figure 1. The effects of lined and unlined cavities compared with bulk explosive
10.2
METHODS OF PERFORATING
10.2.1
Bullets Perforators
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With the advent of completions lined with cemented casing, mechanical cutters were
employed to cut through the casing and cement to allow production to take place. The first
patent for perforating with a bullet gun was granted in 1926, but was not tested until 1932,
when the Lane-Wells Company (later acquired by Dresser Industries) began offering bullet
perforating services to the oil industry. The bullet gun was similar in operation to the guns
used today for sample taking. Hardened steel bullets were fired from a short barrel using a
black powder charge to penetrate the casing, cement sheath, and formation.
Penetration in harder rocks was poor, and it was not uncommon to recover bullets from the
well after perforating, implying that the casing had not been penetrated. Bullet perforators
continued to be used until the 1960’s but from the mid-1950’s were increasingly replaced
by the use of explosive shaped charges. The use of bullet perforators is now confined to
special applications, such as the perforation of certain soft formations, the placing of radioactive marker bullets for compaction monitoring or where circular, burr free holes are
needed.
10.2.2
Shaped Charge Perforators
The first shaped charge guns consisted of large diameter tubular steel carriers in which the
charges were mounted. These guns were run on wireline and fired electrically in a manner
similar to that employed today. The large diameter and heavy weight of the guns combined
with the problems of pressure control generally precluded their use in completed wells, or
with significant underbalance pressures in the borehole. These guns were normally run in
overbalanced, mud filled holes, and the casing was perforated prior to running the
completion. These guns were followed by the development of smaller diameter,
lightweight guns which could be run on a 4.76 mm (3/16”) or 5.56 mm (7/32”) diameter
cable. These guns were small enough to be run through the completion, and the use of a
small diameter cable with pressure control equipment allowed the well to be perforated
safely underbalanced. The performance of these guns was however limited by the size of
the charges which could be accommodated in the small diameter carriers. During the past
decade the advantages of both large diameter carriers and underbalanced perforating have
been realised with tubing conveyed perforating, in which the gun is run into the well
suspended from the completion.
10.2.3
Hydraulic Jet Perforating
This technique uses a jet of fluid at high pressure containing abrasive particles to erode the
casing and formation. In the past it was carried out using a conventional workstring, which
required the use of hoist and was therefore prohibitively expensive due to the time required.
The process is slower than jet perforating, requiring 5-10 minutes per perforation, and is
therefore not widely used. Renewed interest has been expressed in the technique in recent
years taking advantage of the possibilities of reduced cost using coiled tubing, and it is
currently a subject of research. Recent abrasive jetting experiments have demonstrated that
jetted holes are far more stable and clean than perforated holes. After gravel packing, the
jetted perforations also showed no impairment while tunnel plugging was observed for the
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gravel packed perforated tunnel.
The theoretical well inflow performance of a gravel packed cased hole perforated and a
gravel packed cased hole slot cut well have been compared [67]. It has been calculated that
replacement of the actual perforation configuration by a multiple slot configuration would
lead to a large increase in productivity of the well. This is based on the presumption that a
perforated well has a reduced inflow area due to tunnel plugging and, as suggested from the
PI data analysis from the actual wells, a reduced gravel permeability possible caused by
invasion of fines created during the perforation process. The slotting technique using
abrasives is thought to be sufficiently mature for implementation in the field.
10.2.4
Chemical Perforators
These devices employ a jet of corrosive fluid to etch a hole in the casing. They are used
primarily to establish communication between the wellbore and the annulus, in a similar
manner to a tubing punch, but are not used for production perforating. The holes produced
are clean and burr-free, and multiple perforations can be made at the same depth.
10.2.5
Cutting and Severing
Shaped charges can be designed to penetrate a specific thickness of steel, and can be used
to cut the inner of two tubular strings without causing damage to the outer string. These
cutters have an outside diameter only slightly smaller than the size of tubular that they are
designed to cut, and can not be used below restrictions.
Cutters and severing tools for drillpipe and drill collars must only be used in open hole or
damage to the casing will result. When using shaped charge cutters the pipe to be cut
should be placed under tension and the cutter fired in the body of the pipe where the
thickness of steel to be cut is least.
Severing tools are not shaped charges but are tubes filled with up to 4 kg of explosive
segments which produce an unfocussed blast. When using a severing tool the pipe to be cut
is placed under tension and the shot positioned inside a tool joint. The blast deforms and
spilts the tool joint allowing the string to part. Severing tools are available for tool joints
and drill collars up to 12” in diameter.
10.2.6
Mechanical Punches
Wireline conveyed mechanical perforating tools (punches) are presently available from a
number of industry service companies including J. C. Kinley and Otis Engineering. These
tools are primarily intended for punching holes in both standard and heavy-weight tubing.
Typically, mechanical punches are lowered (on wire or slick line) into the well and set on
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depth. Jars in the tool are used to set off a power charge, this forces a piston downwards
which forces a wedge to drive an orifice insert through the tubing.
The main benefits of mechanical punches are :
•
the risk of inadvertently perforating the production casing is negligible;
•
they are less costly compared to shaped charge punches although, as with other
techniques which use explosive charges, radio silence is required during mechanical
punch operations.
Mechanical tubing punches have been employed by a number of Opcos to:
•
provide access to the tubing/casing annulus to facilitate well kill operations;
•
avoid pulling a wet string;
•
lower the gas injection point in a gaslift well. Check valves, and pack off gaslift can
also be installed;
•
permit production through a completion tailpipe that has become plugged.
When consulting service companies for additional information, engineers are advised to
specify the following: application, grade of steel, tubing size, weight, and ID restrictions.
10.3
GUN DESIGN AND TESTING
Many design parameters govern charge performance. Charge configuration is of
significance, including standoff and distance from liner apex to primer. Explosive
distribution and density (which determine detonation velocity) may be more important than
the overall amount of explosive.
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Gun Size
If penetration and entrance-hole data are compared with gun diameter, as is done in Figure
2, it becomes evident that the physical parameters of interest increase with gun size.
Penetration and entrance-hole size increase because charge liners are larger and contain
more material to be converted to the jet.
10.3.2
Explosive Load
Some charges with less explosive load outperform others with much more load. It is further
evident that a large gun does not necessarily require a large explosive load. The size of
charge components is the important factor, given equal design features and production
quality. As will be discussed in a later section, explosive load is an important factor in the
degree of casing deformation produced when expendable-type perforators are fired.
10.3.3
Gun Clearance
Considering other conditions in the well, gun clearance can have an important effect.
Clearance is defined as the distance from gun to casing along the axis of the jet (Figure 3).
Varying clearances are common, since most guns tend to become eccentric in casing
because of well deviation. Further, most guns are designed to fire in several directions
(multiphased). Penetration and entrance-hole values vary, the optimum ones occurring at
lower clearances. Variations can be expected among perforators of the same type and size.
The problem of gun clearance becomes more acute when small-diameter guns must go
through tubing and then perforate large casing. Consider a 1-11/16 in., 90° phased gun
firing in 7-in. casing. Note in Figure 4 the significant change in penetration and entrancehole values.
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GUN DIAMETER (INCHES)
Figure 2. Effect of gun diameter on penetration and entrance-hole size
3-3/8"
Figure 3. Gun clearance effects
Centralizing the gun has often been suggested as a solution to variable clearance. Although
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this approach is sometimes practical for large-diameter guns, it is considered impractical for
small ones, with which the problem is quite severe. Centralizing the gun shown in Figure 7
would result in high clearance on all shots fired. Also, the incidence of poor-quality
perforations, such as irregularly shaped or “keyed” holes, increases at higher clearances in
comparison with those of lower values.
A better solution to the severe clearance problem presented by through-tubing guns is that
of gun positioning. The gun is held against the wall of the casing by means of a magnetic
or mechanical device. Shaped charges are arranged so that jets will fire at a fixed low
clearance value (usually 0-in.). Since clearance is constant, penetration and entrance-hole
size size should prove reasonably constant as well.
Figure 4. Perforating pattern – conventional 1-11/16”, 90° phased gun
10.3.4
API RP 43
Standard industry test procedures for evaluating well perforators are set forth in API
Recommended Practice 43 (2nd Ed.), and test specifications are fully detailed. API RP 43,
included in the addendum, consists of two different types of tests, referred to as Section I
(Surface Test) and Section II (Laboratory Flow Test).
10.3.5
Surface Test
Section I test data are developed in the simple concrete drum-type target shown
schematically in Figure 5. A regular field gun containing six to eight shots is placed in the
casing and eccentrically placed to check clearance effects. Several shots are fired to assure
that charges being fired in close proximity do not interfere with one another. Before firing
commences, the concrete target must be cured for a minimum of 28 days and must have a
minimum tensile strength of 400 psi, which corresponds to about 4000 psi compressive
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strength.
The Section I test provides data on penetration and entrance-hole size. Burr height (or the
lip of metal around the periphery of the perforated hole) is also included. This test is not
intended to throw light on cleanliness aspects of the perforation. That is left to the Section
II Flow Test.
The API RP 43 tests are conducted by a service or manufacturing company. The data are
certified to be representative of the charges being fired in the field.
Figure 5. Test target of API RP 43 Section 1
10.3.6
Laboratory Flow Test
The flow test is a laboratory measurement of flow from a perforation in a Berea sandstone
target after shooting under specified pressure conditions at a temperature of 180°F. It is
intended to show whether the perforation will liberate debris resulting from the penetration
process and then clean up under the stimulus of fluid flow. The method of testing is shown
schematically in Figure 6 and 7. Here it will be seen that perforators can be tested under
simulated positive and reverse pressure conditions.
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Figure 6. Positive-pressure flow test procedure
Figure 7. Reverse-pressure flow test procedure
The flow test utilizes a 3-9/16-in.-OD Berea sandstone core target cemented into a special
steel canister. The core must have a porosity of between 17% and 22%, and its effective
permeability must fall within the range of 150 to 300 millidarcys. Compressive strength of
the target will average approximately 6000 psi. Test specifications require that the target
must be of such length that 5-in. of unpenetrated stone remains beyond the farthest extent of
the penetration.
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After the test target is perforated, it is flowed with kerosene at a differential pressure of 200
psi until a stable flow rate is achieved. Following the procedures outlined in the API RP 43
(2nd Ed.), core flow efficiency (CFE) is then calculated, as is shown in Figure 8. CFE is a
measure of the perforation’ s flow capability compared with that of an ideal hole of the
same diameter and depth in an identical sample.
Because of the liner character of flow in this target system, the CFE value would apply not
to downhole radial flow conditions but to this specific laboratory regime only. CFE
nevertheless represents an improvement over older testing procedures. CFE is a valuable
parameter for measuring the relative performance of several guns.
Since CFE is a ration of actual-to-ideal perforations, the depth sensitivity problem is
avoided. Further, the modified API procedure requires that the target length vary so that a
minimum of 5-in. of unpenetrated stone remains, regardless of penetration depth. Thus the
possible influence of depth of penetration on perforation cleanup characteristics is
minimized. Short and long shooting charges should show approximately the same CFE if
equally clean – about 0.70 to 0.80.
Figure 8. Core flow efficiency (CFE) vs. permeability
10.4
CASING DEFORMATION/DAMAGE
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As mentioned before, the pressure attending detonation of a shaped charge can be several
million psi. One might imagine such pressure destroying the casing each time a well is
perforated. Fortunately, the explosive reaction is so highly transient that the peak pressures
generated last only a short time (20 microseconds). Thus, the inertia of the casing can
provide a significant amount of protection, that is, detonation pressures decay before the
casing can fully respond.
What is meant by casing damage? Character of damage produced by the expendable
shaped charge is shown in Figure 9. It consists of actual splits or casing rupture. Hairline
cracks extending vertically above and below the perforation are also considered to be
damage, since they may adversely affect ball sealer operations in treating or fracturing
procedures.
Figure 9. Typical casing deformation caused by expandable shaped charge
10.4.1
Gun Type
Damage or deformation of casing relates closely to the type used and well conditions.
Damage or deformation can be caused by the expandable-type guns, but none is produced
by the retrievable hollow-carrier guns. Explosive energy from the expandable gun is borne
by the casing. That from the hollow-carrier version is absorbed by the carrier, protecting
the casing.
10.4.2
Casing Support
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Figure 10 shows casing deformation as measured in the lab with a common 20.5-g, 2-1/8-in.
–capsule aluminum charge. The test sample was placed in a well with water pressure inside
and outside the pipe equalized. Semi-supported refers to 0.75-in. of 3500 psi cement
behind the pipe retained by a thin-walled metal sheath. Well supported is the same, except
that a heavy thick-walled steel cylinder is used to support the cement.
Deformation is plotted against a strength factor that is the product of the tensile strength of
the casing and its wall thickness. Note the significant influence of support behind the pipe,
and how deformation increases in the lighter weight and/or lower tensile strength casings.
With this charge there will always be a minimum of about 0.1-in. deformation, even with
infinite support. Finally, a 4-in. hollow-carrier gun of about the same 20.5-g explosive load
produces no deformation.
Figure 10. Effect of casing strength and support on casing
damage with expendable and hollow-carrier guns
Cement strength apparently has little effect on casing deformation (Figure 11). However,
waiting for the cement to attain a compressive strength of 2000 psi before perforating is still
recommended to prevent damage to the cement sheath. The curve shown applies to the
semi-supported target described earlier, perforated with the 20.5-g expendable charge inside
5-1/2-in. casing. As shown in Figure 12, however, thickness of cement behind the casing is
indeed significant, with deformation decreasing as sheath thickness increases.
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Figure 11. Casing deformation vs. cement compressive strength
Figure 12. Casing deformation vs. cement thickness
10.4.3
Explosive Load
Expendable-charge explosive load is an important consideration in casing deformation.
Figure 13 shows that as explosive load increases, danger of splitting occurs at about 25 g
with non-supported J-55, 5-1/2-in., 17-lb/ft pipe and at about 28 g with semi-supported
pipe. These data, along with other data concerning casing deformation, apply only to pipe
in new condition.
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Figure 13. Casing deformation vs. explosive load (at 1000 psi and 180°F)
10.4.4
Hydrostatic Pressure
Hydrostatic pressure tends to minimize deformation, as shown in Figure 14. The difference
between 1000 psi and 5000 psi about 30%. Splitting was experienced at atmosphere
pressure but did not occur above a few hundred psi. Consequently, observations of splitting
in surface target tests may not be significant in terms of response in the well.
Figure 14. Casing deformation vs. pressure
(Semi-supported 5.5-in. 17-lb/ft J-55 casing)
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Guidelines
Regarding the significance of the data on casing damage, as it relates to proper choice of a
gun for a field operation, the following considerations are suggested :
10.5
•
To avoid casing deformation or damage, use a retrievable hollow-carrier gun
•
In the use of expendable versions, keep explosive load as low as possible consistent
with performance required.
•
Avoid use of expendable guns in older wells in which casing may have been weakened
by corrosion.
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Flow properties of the perforation are fully as important as penetration depth, entrance-hole
size, and other mechanical aspects previously discussed.
The capability of the perforation to flow depends on two things :
•
Flow properties of the perforation
•
Well completion conditions under which the perforator is fired
For the best results, both of these factors must be considered in completing a well.
Indeed, it must be recognized that the perforator needs “assistance” if it is to produce a
perforation of optimum effectiveness-assistance in the form of a suitable completion
fluid and/or the proper level and direction of differential pressure during firing.
10.5.1
Clean-up Characteristics
As the high-velocity jet penetrates or punches its way through the target, formation material
is forced laterally or radially outward from the axis of the perforation. The X-rays shown in
Figure 15 demonstrate the process. A sandstone material is in the process of being
penetrated, after 30-and 40-microsecond time intervals. The light region around the jet
suggests that formation material has been forced away from the jet. The darker adjacent
region indicates increased density, resulting from passage of the shock waves from the jet.
Much of this zone will be permanently compacted.
Figure 15. X-rays of jet penetrating composite target
Although the photographs indicate that the formation material is being displaced and
compressed lateral to the jet, the perforation is found to be largely filled with debris
immediately after penetration. This is shown schematically in Figure 16, which represents
a typical Berea sandstone target fired when well pressure is greater than core pressure.
Debris in the perforation is largely pulverized formation material.
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Figure16. Character of perforated hole made in Berea sandstone
The energy stored in the compressed or compacted zone causes material to “spring back”
into the perforation once jet pressures have subsided. At this point, the perforation is a very
poor conductor of fluid. It is only after a certain amount of fluid has been flowed from the
perforation that it will liberate its debris and appear clean, as shown in Figure 16B.
Even when clean, a damaged or compacted zone remains as illustrated. It is characterized
by substantially reduced permeability in comparison with the undamaged Berea. Estimates
based on flow calculations suggest that the permeability of the compacted zone is about
20% of the original target permeability. The lateral extent of the zone varies from about
0.5-in at the tip of the perforation to 1.5-in at the face plate for a typically large hollowcarrier gun charge. Zones are smaller for smaller, shallow penetrating charges.
10.5.2
Core Flow Efficiency
The compacted zone reduces the flow efficiency of the perforation in comparison to, for
example, an ideal hole of the same depth and diameter. As shown by the typical CFE buildup curve of Figure 17, the stabilized CFE of a Berea perforation is about 75% when
subjected to a differential pressure of 200 psi in the API RP 43 system.
The CFE of a typical perforation is initially very low. The first impression is that the debris
shown in Figure 16A is being flushed out. Most of the crushed solids are expelled in the
first 300-500 cc of flow in an API RP 43 test, leaving the perforation open but not yet
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cleaned. Substantial additional flow is required to reach the stabilized flow level shown.
During this period, permeability is being partially restored in the compacted zone.
The flow of a certain quantity of fluid is apparently required to effect maximum restoration
of permeability.
Clearly, the perforation must be flowed and cleaned for maximum flow capacity. Consider
the more dramatic case of response to injection with kerosene (before any back flow or
cleanup) in Figure 18. Note the trend toward reduced flow and/or permeability with
increasing injection. It is assumed that the finely pulverized particles present are further
plugging the interstices in the attempted. Once cleaned, they should be subjected only to
injection with clean fluids.
Figure 17. Influence of differential pressure on CFE (or WF) values
(3-3/8-in. retrievable hollow-carrier charge)
Figure 18. Response of perforation to injection flow at 200 psi differential pressure
The type of formation being penetrated will undoubtedly have a strong bearing on
perforation response to cleanup and flow. Materials other than Berea sandstone have not
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been extensively evaluated in the flow lab. Many test firings have been made into other
sandstones and limestones, which show physical variations in the character of the
perforated hole. Though not conclusive, this finding would support the contention that
formation materials might very well respond differently than Berea.
10.5.3
Differential Pressure
Differential pressure level sharply affects degree of perforation cleanup and efficiency.
Perforations respond better to higher differential P’s, as shown in Figure 19. Apparently
the higher driving force is more effective in expelling debris and in restoring permeability
of the compacted zone. The data shown apply only to liquid flow in the API RP 43 target.
However, the same general remarks apply to gas flow, except that even higher differential
P’s may be required to effect good cleanup.13
One possible observation is that perforations tend to respond more quickly to flow when
liquid is not injected into the perforation before the flow phase. Injection liquids apparently
tend to consolidate debris in the perforation, perhaps conveying fine particles deeper into
the compacted zone, making cleanup somewhat more difficult. Injection also presents the
risk of producing blocks or emulsions that may prove difficult to flow back.
According to White et al. , 13 invasions of even clean liquid into a gas core greatly increase
the probability of plugging problems, even when the formation is subjected to high
differential pressures during flow.
It is for these reasons that the use of through-tubing perforators in a solids-free fluid has
increased. Perforating with a differential pressure of 500-1000 psi into the wellbore
produces perforations that are relatively free of compaction debris.
10.5.4
Type of Wellbore Fluid
Type of fluid in the wellbore was also singled out by Allen and Worzel2 as being highly
influential in perforation cleanup. Fluids with high counts of particulates, such as drilling
muds, and fluids which may cause clay swelling, such as fresh water, should not be used. A
severe reduction in effective permeability of the core because of particulate plugging can
occur. Also, high differential P’s are required to initiate flow – another measure of the
plugging capability of these fluids. Clean brine is the best-recommended perforating fluid.
In essence, experimental data strongly suggest that maximum perforation effectiveness can
be accomplished only when fluids are not permitted to invade the perforation. It would
seem logical, therefore, to perforate in clean fluid and with a pressure differential toward
the wellbore. This topic will be discussed in greater detail later in this section.
10.5.5
Depth of Penetration
Depth of penetration has received inordinate emphasis over the years as the most important
factor in well deliverability. Yet field results often contradict this contention; reports
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indicate that small through-tubing guns promote better production than large ones when the
small guns (shooting one-third to one-half as deep) are fired with differential pressure
toward the wellbore. These observations suggest that well completion conditions, as
discussed in the foregoing paragraphs, are of equal or even greater importance than
penetration in terms of achieving best well deliverability.
In terms of a well’s capacity to produce, shot density would appear to be of greater
importance than penetration depth. Note in Figure 22 that four perforations/ft, 2-in. deep,
offer a productivity ratio significantly greater than one perforation/ft with a perforation
depth of 12 in!14.
10.5.6
Notice also that the productivity ratio, which is the ratio of flow through perforations to
ideal flow, can be greater than 1.0 at higher shot densities. A deep perforation of 8-in. or
more acts as a small fracture. This alters the flow geometry from radial to linear, and thus
improves flow capabilities. In actual practice, the deeper perforation will also penetrate the
damaged zone surrounding the wellbore.
Diameter of Penetration
Diameter of perforation along its length has an insignificant effect on flow capacity, except
where penetration is very shallow.15
As shown in the example of Figure 23, the difference in flow rates between ideal 14-in.
perforations of 0.25-in. and 0.75-in. diameter is only about 20% - yet the ratio of hole size
to surface area is 3 to 1. The flow is shown to be fairly uniform along the length of the
perforation.16,17
10.5.7
Type and Quality of Charge
Type and quality of charge will also influence cleanup and flow. There appears to be no
specific relation between charge cleanup characteristics and depth of penetration. A charge
can shoot very deeply and have poor cleanup quality. Perforation cleanup seems to be
related more to the character of the jet than to depth of penetration (assuming, of course,
that plugging does not stem from slug or charge-case debris).
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Figure 22. Productivity ratio vs. penetration depth for various shot densities
Figure 23. Flow rates for linear and downhole models
– ideal perforations (CFE=1.0)
Although much work remains to be done, there have been some laboratory indications that
charges with higher quality jets produce perforations that release their debris more easily
and cleanup more quickly. Here, higher quality jet refers to one having greater coherency,
uniform mass, and velocity distribution. The difference between the jets appears to stem
from aspects of charge design, conditions of loading, and quality control.
10.5.8
Shot Density and Pattern
Perforating guns are usually designed with up to four shots/ft (SPF), perforating with shots
phased at 0°, 60°, 90°, 120°, or 180°. Note in Figure 24 that phase angle does not
significantly affect the productivity ratio. Perforating guns can be loaded at any shot
density desired and are manufactured in various lengths, from those containing only a few
shots to those containing hundreds of shots.
Typically, wells without sand control problems are shot with 2-4 SPF or more and wells
with sand control problems are shot with 8-12 SPF. Research indicates that increases in
productivity can be achieved by increasing the shot density. However, there are potential
disadvantages to higher shot densities also :
•
Additional holes make diversion more difficult.
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•
Higher SPF makes squeeze cementing in later workover operations more difficult.
•
Costs are higher.
Figure 24. Effect of phase angle on productivity
A very low number of shots are placed in wells with scheduled limited-entry well
stimulation treatments. With this technique the shot density varies based upon diversion
requirements but can range from 0.1 to SPF.
10.5.9
Type and Size of Gun
To achieve maximum performance, the largest gun size that can be safely run is usually
employed. Table 1 may be used as a guideline for selecting a perforating gun size based on
the size of the tubing. A detailed discussion of the various types of perforating guns
available for different situations follows.
Table 1
Tubing Size (OD)
Maximum Gun OD*
2-3/8″
2-7/8″
4-1/2″
5-1/2″
1-11/16″
2-1/8″
3-5/8″
4″
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* After-detonation OD
10.6
RETRIEVABLE HOLLOW-CARRIER GUNS
The myriad of shaped-charge guns and charges commercially available today can
generally be classified into three categories relative to their operational characteristics and
applications :
10.6.1
•
Retrievable hollow-carrier gun
•
Non-retrievable or expandable gun
•
Tubing conveyed gun
Description
As indicated by Figure 25, the retrievable hollow-carrier gun of (A) consists of a steel tube
into which the explosive shaped charge is suitably secured. The gun tube is sealed against
hydrostatic pressure. When the charge fires, the explosive forces slightly expand the carrier
wall, but the gun and debris within are fully retrieved from the well.
10.6.2
Operations
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The retrievable hollow-carrier type gun is lowered into the wellbore and positioned by
wireline. Guns are provided in diameters ranging from 3-1/8-in. up to 5-in. for general
casing operations. However, hollow-carrier guns are made in correspondingly smaller
diameter versions for through-tubing (or slim casing) operations.18 Guns are available in
diameters that will permit easy passage through tubing seating nipples after the gun has
been fired and has swelled – for example, 1-9/16-in. guns for passage through 1-25/32-in.
nipples and 2-in. guns for 2-1/4-in. nipples.
10.6.3
Applications
Today the retrievable hollow-carrier (steel) shaped charge guns perform more than 70% of
all perforating done throughout the world, for those reasons :
•
High reliability; minimum misfires since blasting cap, detonating cord, and charge are
protected within gun.
•
Mechanical strength and ruggedness; adaptable to rough treatment, including
movement through wellbore debris. These factors, combined with greater gun weight,
make getting to perforating depth easier.
Fast running for minimum rig time.
•
•
High pressure and temperature resistance. Standard guns and charges are rated to 340°
at 15,000 to 20,000 psi; high-temperature guns are rated for 25,000 psi at 470°F,
although their performance is decreased.
•
Easy adaptability to desired shot density.
•
Minimal casing deformation upon firing.
•
High charge performance.
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Figure 25. Guns used in general casing operations
Basically the same remarks as those above apply to the through-tubing retrievable guns,
except that on occasion they will fail to go down because of doglegged production tubing.
In these cases, expendable guns should be used because they are generally quite flexible.
Also, the expendable versions have larger charge components (e.g., liner); they therefore
permit somewhat more penetration than a comparable retrievable steel gun. A major
disadvantage of the retrievable steel gun is its rigidity and/or weight, which limits the
length of assembly that can be run.
10.7
EXPENDABLE GUNS
10.7.1
Description
The non-retrievable or expendable gun and the semi-expendable gun consist of individual
pressure-sealed cases, usually made of aluminum, ceramic, glass, or cast iron. A charge is
contained within each case and, when detonated, blasts the case into small pieces. There is
no carrier to contain the blast. Case debris remains in the well.
Fully expendable guns (Figure 25B), usually made of aluminum, can claim none of the
advantages for the retrievable models cited above. Their remain feature is that they are
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more economical and can be easily loaded or assembled at the well. Another significant
advantage is that they can be loaded or “hooked together” in much greater lengths than steel
guns. They are lightweight and flexible (usually they have a bending radius of about 5 ft),
which facilitates feeding a long gun into the well. Guns of 200 ft have reportedly been shot
on a single trip into the well.
Semi-expendable guns (Figure 25C), although equipped with a retrievable carrier strip, wire
and better cases, also fall short of the steel retrievable guns in terms of desirable operational
specifications and features. But they represent improvements over the fully expendable
guns in some respects.
10.7.2
Operations
Important factors to be considered in the use of fully expendable guns are:
•
Their flexibility permits handling long lengths and facilitates feed-in at wellhead.
•
They leave debris in the well, which can produce bridging in the casing particularly
when shooting in mud or smaller diameter casing) or which can be blown up the well
on certain reverse-pressure operations, thus causing tool sticking and fishing.
•
Aluminum cases are not adequately resistant to commonly used HCl acid. Cases can
be operated in acid for a few minutes at lower temperatures without failure. However,
this is not recommended. HCl acid is often used to dissolve debris left in the well.
•
Aluminum cases are prone to excessive casing or production tubing wear if run too
fast into the well. Speed should not exceed 10,000 ft/hr or 168 ft/min. Particular
attention should be paid to these specifications when operating in deep wells.
•
Occasionally an operator is uncertain whether all charges in the gun have been fired.
There is no telltale feature as in the case of the retrievable or semi-retrievable
versions.
Size for size, these guns usually offer more penetration than corresponding steel
hollow-carrier guns. The difference ranges from 10% to 25%, the higher value being
noted in guns of very small diameter.
•
Semi-expendable guns provide the following advantages over the fully expendable type :
•
Minimize amounts of debris, particularly on reduced shot-density operations, by
elimination of expendable extension members through use of steel strips or wires that
are retrievable.
•
Improve character of debris; that is, use of ceramic or glass cases produces debris that
is more nearly like sand or gravel and that is less likely to cause bridging.
•
Improve pressure capability, wear resistance, ruggedness, gas integrity, and chemical
resistance through use of ceramic cases.
•
Facilitate 0° phasing for the positioned guns used on through-tubing operations.
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10.7.3
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Applications
Some important factors concerning the applications of expendable guns are :
•
Pressure and temperature ratings are usually substantially less than those of steel guns.
Some are rated as high as 15,000 psi at 300°F and others at 5000 psi at 200°F.
•
Because of their design, expendable guns are not as mechanically competent as
retrievable steel ones. No attempt should be made to push an expendable gun through
a wellbore which is blocked by debris. This can cause gun breakage and separation,
which in turn usually results in a fishing operation.
•
They can deform or damage casing when fired, depending on explosive load and well
conditions (to be discussed subsequently). Consequently, they are not recommended
for use in wells in which casing is old or has been exposed to excessive corrosion.
In summary, the use of fully expendable guns should ordinarily be confined to shallower
holes in which conditions do not tax their mechanical and operational capability. Semiexpendable guns, like the fully expendable versions, are generally confined to shallower
operations. With ceramic cases, however, they are often used in deeper wells on throughtubing operations when gas is a problem.
10.7.4
Pivot Guns
At the end of 1992, Schlumberger introduced a new though tubing perforating system called
the Pivot Gun. The system has a performance comparable to casing guns and can pass
restrictions with diameters as small as 45 mm (17/8”) by using large charges that are
assembled in the gun parallel to its axis. When the gun is on depth, the charges are rotated
90° and then fired (Figure 30).
The increased performance of this fully expendable 43 mm (111/16”) gun makes it
applicable for certain through tubing applications where the inside diameter of the
production tubing is considerably less than that of the production casing and where
effective shot perforation is an important design criterion.
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Figure 30. The Schlumberger Pivot Gun
10.8
TUBING CONVEYED GUNS
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10.8.1
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Description
The tubing conveyed gun consists of a large casing gun attached to the end of the tubing
string, as seen in Figure 26. This is a relatively new type of perforating gun which has been
gaining popularity in recent years.
10.8.2
Operations
Tubing conveyed guns are run in the well on the end of the tubing string and are positioned
through the use of a locator collar. The collar is radioactively tagged and can be easily
distinguished on a collar log. The locator collar is a premeasured distance above the gun.
A collar log is then used for depth control, plotting tubing collars against natural formation
gamma ray radiation. The gun is usually fired mechanically with a sinker bar through
tubing. It can also be fired by sufficiently high differential pressure across the packer or by
wireline. After firing, the gun can be left on the tubing string, retrieved by pulling the
string, or simply released into the rathole.
10.8.3
Applications
The advantages of tubing conveyed guns include :
•
Maximum formation energy can be utilized to expel debris from the perforation. Also,
the differential pressure attained may be sufficient to increase the permeability
through the compacted zone around the perforation. Simultaneously, the potential
hazard of the gun blowing uphole, sometimes associated with reverse differential
pressure wireline perforating, is eliminated.
•
Formation contact with completion fluids is minimized.
•
The larger perforating capacity of a casing gun is utilized.
•
Does not require a lubricator.
However, the tubing-conveyed gun also has these disadvantages :
•
The only way to confirm that all the charges have fired is to pull the gun (and tubing)
out of the hole.
•
In deviated, mud-filled, or debris-filled tubing, the detonation bar may have difficulty
detonating the gun.
•
Once the perforation step is completed, the gun assembly becomes extraneous
material, and may hinder future workover operations.
Higher cost – cost may exceed through-tubing costs by 40%.
•
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Figure 26.
10.9
PERFORATION DESIGN
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The foregoing discussion suggests that certain specific considerations are involved in
achieving maximum deliverability from perforations. First of all, steps should be taken to
avoid wellbore damage from completion fluids. Secondly, perforators should be used that
not only produce good penetration but also provide good cleanup characteristics.
During the completion operation, attention should be directed toward establishing
conditions conducive to rendering the entire perforated system effective. Basically, the
objective is to maximize well deliverability and achieve more efficient reservoir drainage
without jeopardizing subsequent operations.
10.9.1
Matrix Acidizing
The only major consideration in designing a perforation job for matrix acidizing is to limit
the number of holes per foot so that effective diversion can be carried out.
10.9.2
Diversion
For proper diversion, in general 2-4 shots per foot should be used with perforation
diameters of approximately 0.2-0.4 inches.
Another consideration of special importance is reperforation. Extensive reperforation,
especially when the gun has lain repeatedly on the same side of the hole (in deviated holes,
for example), can lead to overlapping or interfering perforations that cannot be sealed by
balls. For example, it is virtually impossible for a spherical ball to seal a hole of figureeight shape formed by two adjacent, overlapping perforations. Diversion away from such
intervals will be difficult once injectivity is established.
10.9.3
Gravel Packing
Special attention must be paid to perforation design when gravel packing is planned. First,
large diameter (0.5 inches) perforations should be used to avoid bridging. Second, high
shot densities should be used since the gravel blocks approximately 60% of the flow area of
the perforations. Also, higher shot density lowers the pressure drop across each perforation
during both injection and production, thus increasing the stability of the gravel pack. In
general, 8-12 shots per foot should be used, with the lower density for longer intervals.
10.9.4
Fracturing
An interval of 200-250 feet or less can usually be perforated and fractured with a single
stage. Larger intervals, which will require fracturing, should be perforated in multiple
stages with the same number of holes in each stage for uniform injection. In a multi-stage
job, each perforated interval should be less than 250 feet with 100-200 foor gaps between
the perforated zones to allow for fracture height growth without establishing
communication between zones.
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Zones to be hydraulically fractured or treated should not be “blanket” – perforated, as
illustrated in Figure 27A. In too many cases only a single zone is fractured with this
technique, leaving other reservoirs unexploited. The emphasis is currently on selectivity in
fracturing and treating. It is desirable to have all potential zones fractured or treated, as
shown schematically in Figure 27B.
Several techniques are used to achieve the fracturing or treating selectivity illustrated. A
wellbore with broader perforating requirements is handled as follows :
•
A calculated number of shots of given hole size are placed in the zones of interest.
•
Typically, one of the zones will break down when pressure is applied. It will be
treated and ball sealers injected into the fluid stream. The balls will seal off the zone
taking fluid, permitting pressure to be applied to the other zones. The process is
repeated with the objective of fracturing all zones.
Figure 27. Perforating methods for fracturing and treating
10.10
PERFORATING OPERATIONS
Clearly the operation can be performed by perforating each zone in turn with conventional
perforating equipment, packers, etc. More time would be required, and the cost would be
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significantly higher.
10.10.1
Selective Firing
Perforators provided for limited entry and treating operations frequently require selective
firing provisions and a specific entrance-hole size in the casing. They are also required to
cause only minimum damage to casing or cement.
Selectivity in the gun perforator is required for reasons of economy. The ability to
selectively fire many shots from the same gun assembly on a single trip in the well saves rig
time. Entrance holes must usually be controlled to a specific range of sizes, which involves
gun positioning to control clearance.
In Figure 28 are shown some of the selective guns operating in the field today. A switching
system between the retrievable carrier in (A) permits any number of gun carriers in the
common sizes to be run, positioned or non-positioned. The number of shots per carrier may
be varied. Length of assembly that can be run into the well depends on surface handling
facilities. Firing is carrier-by-carrier from the bottom upward.
Figure 28. Selective firing perforators
Shot-by-shot selective equipment capable of firing up to 48 individual shots on a single trip
is depicted in Figure 28B. Note the spring positioner for clearance and thus entrance-hole
size control.
The expendable selective version shown in Figure 28C are used very little. Although
considerably more economical than other approaches, they lack the mechanical ruggedness
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needed to withstand shock from firing of an adjacent bank of charges. Furthermore, oil
operators have become increasingly concerned over potential casing-cement damage from
the expendable charges.
10.10.2
Depth Correlation
There are several methods available for locating the perforating gun at the proper depth in
the well. One way is to attach a density logging tool to the gun assembly to detect casing
connections downhole. Greater accuracy can be obtained if several short lengths of casing
are used in the area of interest. Another way of detecting proper depth is to put radioactive
tape in the casing connections at the key points and use a radioactive tracer logging tool in
conjunction with the perforating gun assembly.
10.10.3
Gun Orientation
Sometimes it becomes necessary to perforate the upper zone of a dual completed well, as
shown in Figure 29. In these cases it is not considered desirable to pull tubing strings and
packer, either because of anticipated mechanical problems or reluctance to kill the lower
zone.
As set out in Fig. 29, the requirement is to perforate the upper reservoir without damaging
or deforming the adjacent string, and without leaving debris on top of the lower packer.
This is accomplished by means of the simple mechanical orienting device18 shown in Figure
30. In operation, the arm is released mechanically or electrically on arriving at perforating
depth. Movement of the arm is mechanically interlocked with an electrical switch so that if
the arm moves through distance d1, or more, the tool can be fired by the operator and the
jets should not damage the adjacent string. If the arm has not moved through distance d1,
the gun cannot be fired.19 The arm simultaneously serves the function of clearance control
and gun positioning for optimum charge performance. Again, a retrievable hollow-carrier
gun is used to assure that no shock damages the adjacent string and no debris is left on the
lower packer. Gun length is usually limited to 10 ft to avoid shooting into “drifting” tubing.
In this operation, the gun and cable sometimes wrap around the adjacent string and cannot
be recovered. There is about a five percent chance that this problem will occur, and it is
aggravated by tool designs that do not provide for release of the arm at perforating depth.
(Cable torque is thereby allowed to build up going in the well). Also, fishing jobs occur
more frequently when the perforated interval is located a great distance beneath the upper
packer.
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Figure 29. Between-packer perforating of conventional dual completion
Figure 30. Mechanical orienting device for perforating dual completions
10.10.4
Perforating Fluid
Perforating fluids can have a very significant effect on the performance of a well. Until
recently, mud was used extensively as a perforating fluid. Mud was considered satisfactory
until laboratory tests, conducted under simulated well conditions with cores, showed that
perforations are filled with mud solids and charge debris when mud is used as a perforating
fluid. Back-flowing of the cores also showed that mud plugs are nor easily removed by
production. Mud plugging of perforations may be eliminated by using a clean fluid such as
saltwater or oil during perforating operations.
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A downhole choke or trigger technique is sometimes used with fluid sensitive formations
and in other applications. With this technique a selectively-fired, through-tubing gun first
shoots one or two holes at the base of the completion interval. The gun is then lowered
below the perforations and the well allowed to produce. The wellbore completion fluids
are unloaded as the well flows, leaving a compatible formation fluid opposite the remainder
of the interval. To perforate the remaining interval, the differential pressure can be
controlled by varying the surface flow rate and formation drawdown. The selective-firing
gun still in the hole can then be raised to perforate the remaining interval.
10.10.5
Overbalanced Perforating
Wells are basically completed in one of two ways, as illustrated in Figure 31. Perforating is
done with a casing perforator under overbalanced conditions or through tubing under
underbalanced conditions. Casing perforation is done under positive pressure because there
is no easy way to control wellhead pressure.
Perforating in drilling mud overbalanced, that is, with higher pressure in the wellbore than
the formation, results in the plugging of some of the perforations, as illustrated in Figure
32.
Figure 31. Comparison between standard and through-tubing completion methods
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Figure 32. Adverse effects of perforating in mud
10.10.6
Underbalanced Perforating
As discussed above, perforating in oil or saltwater rather than mud is generally less
damaging to perforations.
Perforating underbalanced, that is, with lower pressure in the wellbore than in the
formation, 20 is most conducive to obtaining an effective perforated system. Perforations
are not exposed to foreign fluids. The initial surge results in production from a maximum
number of perforations, as depicted in Figure 33.
Recently, a ∆P of 500 psi has been considered standard. The optimum value will
undoubtedly depend on the particular reservoir being completed.
Even higher differential pressures are established for some gas well completions : ∆P’s as
high as 4000 psi have been reported. The reason is that perforations made into gas
reservoirs are more difficult to clean up. Sometimes operators are reluctant to perforate
under very high ∆P’s because they fear blowing the gun up the well and causing a fishing
job. However, the judicious use of weights or tubing-conveyed guns obviates the problem.
Most underbalanced perforating is conducted through tubing with small-diameter
perforators. Positioned guns are recommended to assure optimum performance. Such guns
are usually designed for inline firing, which sometimes evokes a question regarding the
effect on productivity ratio. As reported by Harris14, the productivity ratio is reduced by
about 10%, as shown in Figure 34. However, in view of the strikingly good field results
obtained when reperforating behind the larger casing guns, one can assume that the
reduction is often more than balanced by the higher effective shot density being achieved.
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Figure 33. Underbalanced perforating
A variation of the downhole choke technique can provide an underbalanced perforating
condition in wells with extended intervals that require more than on e perforating run.
After the first interval is perforated, the shut-in BHP will approach the reservoir pressure;
however, additional reverse pressure perforating may be achieved by flowing the well
(keeping the BHP low) concurrent with the perforating operation. Local management
approval is always required when perforating a flowing well.
Figure 34. Productivity ratio vs. perforation pattern
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10.10.7
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TCP Firing Systems
Various methods for firing the detonator of a TCP gun have been developed to enable
reliable firing of guns in wells with differing geometry, mechanical configuration, and
borehole conditions. These can be grouped into four main types, which are
•
drop bar actuated systems, in which a metal bar is dropped from surface and free falls
under gravity to mechanically initiate the firing head;
•
hydraulically fired systems, in which fluid pressure is applied from surface to the
tubing or annulus to fire the gun;
•
electrically actuated systems, in which current is sent from surface via an electrical
cable to fire the gun;
•
electrically actuated systems, in which a detonator and shaped charge are lowered
from surface on wireline to fire the gun
The operation of mechanically or electrically actuated systems is dependent on well
geometry and mechanical restrictions in the completion, whereas the use of hydraulically
fired systems requires a detailed analysis of the operating pressures or pressure ratings of
other completion items.
Although Figure 35 indicates the use of lead azide, it should be stressed that lead azide
boosters are almost obsolete within the industry due to its intrinsic sensitivity to thermal
and shock loading.
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Figure 35. Mechanical initiator (detonator)
10.10.7.1
Drop Bar Systems
Drop bar systems can be employed in wells with deviation up to 65°. In dry
tubing the rate of descent may be controlled by running the bar on slickline or
providing a fluid cushion to reduce the velocity through tubing accessories and
the packer. The presence of scale or debris in the well may prevent a drop bar
from initiating the firing head. The bar can be fished using slickline if the guns
fail to fire, reducing the risk of unintentional firing if a misfire occurs and a gun
must be recovered. Overall reliability of drop systems is estimated to be in
excess of 99%.
10.10.7.2
Hydraulically Fired Systems
In an hydraulically fired system the firing pin is actuated by a piston driven by
hydraulic pressure. The piston is mechanically restrained while the gun is run
into the hole, and is released to fire the gun. The piston may be released by
applying excess pressure from surface to the tubing or annulus or by the use of
a drop bar. Hydraulically actuated systems can be used in highly deviated
wells, and can be less susceptible to problems caused by scale or debris than
electrical or mechanical systems. Overall system reliability is estimated to be
greater than 95%.
The presence in the string of setting tools or pressure actuated valves or shear
disks must be considered when designing an hydraulically fired system. To
operate each item of equipment sequentially while allowing for operating
pressure tolerances, the burst and collapse pressures of the tubing and casing
must be considered. The range of differential pressures between annulus and
tubing to which the assembly will be subjected while running in the hole or
creating drawdown must be calculated to prevent unintentional firing of the
gun. Pressure differentials created by a failure to maintain the fluid level in the
tubing while running in may be sufficient to actuate the firing head.
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Figure 36. Electrical initiation of TCP gun using a wet connector
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10.10.7.3
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Electrically Fired Systems
Electrically fired systems are similar to those used in wireline guns. A wet
connector is fitted above the gun allowing an electrical connection to be made
with a wireline cable run through the completion (Figure 36). Current sent
down the cable actuates the detonator initiating the gun. Alternatively a shaped
charge may be run through the completion on wireline and fired into a booster
to trigger the gun (Figure 37). Production logging sensors can be run on the
wireline cable to allow pressure, temperature and flow to be monitored as the
gun is fired. Limited information is available on the reliability of electrical
firing systems for TCP applications.
10.10.7.4
Shot Indicators
When the guns are fired there is no way of knowing whether all charges in the
string have fired correctly until the guns are removed from the hole. Service
companies offering TCP have developed tools which trigger a delayed second
detonation when the detonation reaches the bottom of the gun string (‘Bottom
Shot Indicator’), but low order detonation of sections of the gun may remain
undetected. A ‘bottom shot indicator’ is illustrated schematically in Figure 38.
The detonation can generally be monitored from surface using a microphone
attached to the wellhead. In some cases, particularly in deep wells or with high
ambient noise levels, indications of firing at surface are inconclusive, and if the
well fails to produce as expected re-perforation with wireline guns may be
attempted. This will require dropping the TCP guns from the completion string
into the well.
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Figure 37. Initiation of TCP gun using a wireline conveyed detonator
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Figure 38. Bottom shot indicator
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10.10.8
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High-Temperature Perforating
Most shaped-charge perforating equipment today uses an RDX (Cyclonite) explosive that is
rated at 340°F. When the temperature of the wellbore exceeds that level, special equipment
should be used23. Failure to do so may result in premature gun detonation, with perforation
or damage to the well. Existing expendable-type guns should never be operated at
temperature exceeding 300 °F.
Special versions of the retrievable-type perforators are rated at 25,000 psi and 470°-500° F
for one hour. They contain special explosive for the charge, special detonating cord, and
blasting cap. The system is essentially fail-safe. The blasting cap rating is higher than that
of the cord and charge. If temperature limits are inadvertently exceeded, the explosive in
the charge will usually sublimate without detonation.
The blasting cap is the weak link in standard RDX packages today. It will spontaneously
detonate at 360°F to 365°F. When it does, there is a fifty percent chance that the cord will
ignite and the charge detonate, producing holes in the casing (usually off depth!).
Accordingly, operating-temperature ratings of equipment should never be exceeded. This
implies that bottom-hole temperature should be known within reasonable accuracy. If in
doubt, make measurements!.
Remember that thermal gradients vary widely from one area to another. The operator
should not use calculated temperature values unless he is reasonably certain of the validity
of the gradient.
In perforating high-temperature wells, consideration must be given to accessory equipment.
Radiation tools, casing collar locators, heads, seals, electric cable, and downhole
electronics must be adequately rated for the job.
Because of the air cushion in the gun’s steel hollow carrier, operators will sometimes
attempt to take advantage of a thermal lag within the carrier by running into the well very
rapidly. Their idea is to operate standard equipment at levels in excess of the temperature
rating. This is not recommended because the gain is insignificant, as shown in Figure 39.
Running into the well at about 20,000 ft/hr, or at a 340°F/hr rate of temperature increase,
temperature inside the gun lags only about 1.6°F for five minutes – scarcely enough time to
assure proper depth control before firing.
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Figure 39. Thermal lag – well to carrier
10.10.9
Wellhead Pressure Control
In order to run a wireline tool into a live well pressure control equipment is used to provide
a pressure tight seal around the logging cable, while leaving the cable free to move. The
equipment used for this is illustrated in Figure 56. The pressure control equipment consists
of two ‘flow tubes’ or ‘grease tubes’ 1 m in length with an inside diameter approximately
0.1 mm larger than the outside diameter of the cable, connected together by a coupling.
The cable enters the well through the flow tubes. Viscous grease is injected into a port in
the coupling between the flow tubes at a higher pressure than the well pressure and flows
very slowly downwards around the cable into the well, and upwards to atmosphere pressure
at the to of the upper flow tube. For high pressure work a second flow tube can be added
above the grease injection point to further reduce the flow of grease.
A seal must be established by filling the space between the cable and the flow tubes with
grease prior to applying well pressure to the system. If the grease seal is lost for any reason
the space will be filled with non-viscous gas or oil from the well which will flow rapidly
past the cable and may prevent the reestablishment of the seal. Two sets of blow out
preventer (BOP) rams provide an alternative means of sealing around the cable. The lower
BOP rams are inverted and cannot be used to seal against well pressure: the upper BOP
rams have a limited capacity to seal against the cable but may leak if exposed to gas at high
pressures. To achieve a seal both sets of rams must be closed and grease injected between
the two BOPs at a pressure higher than that present in the well.
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Figure 56. Wireline Pressure Control Equipment
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•
The riser, flow tubes and wireline blow out preventers should be tested to their
maximum test pressure is generally either 150% or 200% of the maximum safe
working pressure. A metal band indicating the test date, safe working pressure,
and the service (H2S or not H2S) should be attached to each item of pressure
control equipment and should be checked by the wellsite supervisor.
•
Only twin ram BOPs equipped with a grease injection manifold between the rams
should be used on gas wells.
•
Sufficient riser must be available for the longest gun to be run together with the
required ancillary equipment such as the cable head, collar locator and
positioning device and sufficient weights to prevent the tool being blown from
the hole by the well pressure or fluid flow after perforating.
•
The pressure control equipment should be tested to the maximum expected
pressure before commencing operations on a well. Retesting should only be
carried out if the equipment is disassembled. Pressure testing should be carried
out using glycol. This avoids filling the flow tubes with water which can prevent
the grease from sealing, and reduces the risk of hydrate formation.
•
Pressure testing should never be carried out with an armed gun in the lubricator.
Sufficient weights should be used to prevent the cable head being forced into the
tool catcher by the well pressure.
Safety
There are several additional safety considerations for perforating operations. Rig floor
personnel should be extremely cautious when removing a perforating gun from the well
since some or all of the charges may not have fired downhole. Before overbalanced
perforating, the engineer should check to ensure that the density of the perforating fluid is
adequate to maintain control of the well. Before underbalanced perforating, the engineer
should check to ensure that the packer has been properly set and all well control equipment
has been installed and tested. Also, before loading or running a perforating gun, temporary
signs should be placed on roads entering the location prohibiting operation of radio
transmitters.
10.11
SPECIALIZED EQUIPMENT AND OPERATIONS
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Apart from the broader applications discussed in the foregoing section, perforators have
been designed for special types of operations or to solve specific problems. They are
classified here as specialized because they are not widely used as yet or are not frequently
required.
10.11.1
Limited Penetration Devices
To perforate a string of tubing or drill pipe without damaging the casing, or to perforate an
inner string of casing without damaging an outer one, limited penetration shaped charges
are employed (Figure 40). These are usually used to establish circulation or to squeeze
cement between strings.
Figure 40. Tubing and casing punchers
Those used to perforate the relatively thin wall of tubings are sometimes referred to as
tubing punchers and those used to perforate drill pipe or casing, casing punchers. They
differ only in terms of depth of penetration in steel and should be selected according to the
penetrating requirements.
Guns are usually of small diameter (1-3/8-in. or 1-11/16-in.) and of the retrievable hollowcarrier type, positioned to assure clearance/performance control.
10.11.2
Tubing-Casing Cutters
Circular shaped-charge devices such as those shown in Figure 41 are designed to cut or
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sever tubing and casing to permit retrieval from the well. Note the characteristics flare at
the cut, which is usually not objectionable. Various sizes are available to match the
common sizes of tubing and casing. The major portion of a tubing cutter is retrieved after
shooting, whereas casing cutters are fully expendable. The devices perform best at low
clearances; the proper size should be chosen for the tubing/casing. Best results are
achieved when centralizers are used. Another commonly used wireline device for cutting
tubing is the chemical cutter. It produces no flare at the cut, in contrast to the shapedcharge cutter.
Figure 41. Shaped-charge cutters
10.11.3
Hydraulic Jet Perforator
The hydraulic perforator, introduced in 1960, operates on tubing instead of wireline.
Penetration is effected by pumping sand-laden fluid down the tubing and horizontally out
through a jet nozzle26. Early reports claimed outstanding performances by the hydraulic
perforator. As pointed out by Thompson,27 however, penetration into the API Berea
sandstone target is less than that made by most 4-in. shaped-charge guns when testing under
more simulative pressure conditions. He further reported that it took 10 minutes to
penetrate 3.7-in of Berea with a typical 3-19-in. diameter nozzle and 2500 psi differential
pressure across the nozzle. Jetting an additional 20 minutes extended the perforation to
only 5.2-in.
Configuration of the perforation made differs from that made by jet or bullet perforators.
Holes were reported to be larger in diameter and more bulbous in shape. Flow capability
was reported to be good.
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Very little perforating is done in the industry today with the hydraulic perforator because of
the time and cost involved. Compared with the wireline shaped charge, it has the
disadvantage of less positive depth control (unless, of course, an electric line and
instrument are used to position the nozzle).
10.11.4
Well Cleaning Before Perforating
Wellbore cleaning before completion fluids can contact the formation is a critical aspect to
minimise formation damage. Any source of damage that can be avoided should be
avoided.
Wellbore cleaning is usually carried out by displacement of the drilling mud in the well by
seawater or clean completion fluid and using a variety of pills in between. The casing
should be scraped prior to perforating or underreaming. A suitable wellbore cleaning
procedure is given:
Cleaning the wellbore is often difficult and because all wellbores seem to be unique in this
respect, it is difficult to programme a set procedure. Decisions have to be made at the
wellsite to obtain the desired degree of cleanliness in the shortest time.
1.
M/U bit and Rotavert Scraper, P/U 31/2” DP and RIH to float collar. Use thread
compound sparingly.
2.
With bit at float collar circulate well to drillwater and observe well stable.
3.
Scrape three times casing from float collar to 50m above top packer setting depth
while circulating viscous pills. Repeat scraping until returns are clean (refer to sec.)
4.
With bit at float collar pump the following cleaning pills:
5.
•
20 bbl viscous pill, 20 bbl sand pill and 20 bbl viscous pill. Chase at maximum
rate with drillwater using rig pumps.
•
20 bbls viscous pill, 25 pill citric acid pill and 20 bbl viscous pill. Circulate
slowly to give ten minutes contact time with the casing.
•
Circulate with clean brine at maximum rate until the turbidity of the returns is
some 25 NTU. Plot turbidity as function of circulating time.
Displace well to completion brine with density to give 50 psi overbalance at top
packer setting depth. Observe well stable. POOH
NOTE : Cleaning recipe may be required to be changed depending on the fluid in the hole.
10.12
WELLSITE OPERATIONS
10.12.1
Achieving Drawdown
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To lower the pressure in the wellbore before perforating, a number of techniques have been
developed. Selection of the appropriate technique will depend on the underbalance
pressure to be used and the well configuration, and should be considered in the completion
design.
All techniques for lowering the wellbore pressure involve filling the well with a fluid or
combination of fluids whose hydrostatic head is lower by a specified amount than the
reservoir pore pressure. The means by which this is achieved will depend on the well and
completion design, which may allow the use of a sliding side door or side pocket mandrel to
provide a means of circulating a low density fluid or gas. For the high drawdown pressures,
required for low permeability formations, the well may need to be partially or completely
gas filled. Commonly a coiled tubing unit is used to replace part of the tubing contents with
a low density fluid such as nitrogen.
If the well is perforated for the first time, the underbalance can be established by running
the tubing into the well empty or partially empty with a plug or valve preventing the entry
of well fluid, although this preclude internal pressure testing of the completion assembly
and may restrict the choice of other completion accessories.
If the well has already been perforated, the required underbalance cannot be achieved using
an air cushion unless flow into the tubing is prevented until immediately before the guns are
fired. This can be achieved using TCP equipment run with a glass disk or production valve
just above the gun. The valve is opened or the disk shattered by the drop bar immediately
before the gun is fired, causing fluid to surge into the tubing. This creates the required
reduction in wellbore pressure as the gun is fired.
When considering through tubing perforating techniques, drawdown can also be achieved
by perforating so called ‘trigger’ intervals. This principally applies to gas wells, and
involves firstly perforating (through tubing) a trigger interval to allow the well to be
evacuated to gas. This enables subsequent perforation runs to be carried out underbalance
in a gas filled wellbore. This method can also be used to perforate zones exhibiting
significant permeability contrasts. Low permeability (trigger) intervals are perforated first
to ensure effective clean-up, followed by the more prolific higher permeability zones.
Where operationally possible, perforating underbalanced using a partially evacuated string
is recommended.
10.12.2
Through Tubing Underbalance Perforating
With through tubing underbalance perforating the level of drawdown may have to be
limited as the resulting inflow of fluids creates a friction force on the wireline and tool.
This can cause the tool to be lifted up the well causing cable tangle which can result in
costly retrieval operations.
To avoid this the drawdown applied when perforating must be limited so that :
Fg > Ff + Fp
where:
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Fg
=
weight of logging tool and cable;
Ff
=
friction forces due to flow;
Fp
=
force due to bottom pressure acting on the cross sectional area of the cable.
The above equation can be expanded to:
MG cos α b >
πDL
2
fρv2 + PAc
where :
M
G
α
b
f
ρ
v
d
l
P
Ac
=
=
=
=
=
=
=
=
=
=
=
mass of tool and cable
gravitational constant
average hole angle
buoyancy factor
friction factor
fluid density
fluid velocity
diameter of the cable
length of cable
flowing bottom hole pressure
cross-sectional area of cable
(kg)
(9.81 ms-2)
(°)
(kg/m3)
(ms)
(m)
(m)
(Pa)
(m2)
In single-phase flowing wells it is possible, using the equation mentioned above, to predict,
with some accuracy, the total upward force. By matching predicted and observed forces,
friction coefficient can be found. Clearly, if the predicted force approaches the weight of
the cable and tool either extra weights have to be added, or the well should be beaned back
to reduce the risk of the tool being forced up the hole. The SIPM Production Handbook,
Volume 5, should be consulted for more detailed information. It should be noted that above
treatment is only valid for a flowing well.
The weight required to overcome well pressure can be calculated by multiplying the cross
section area of the cable by the maximum tubing head pressure expected after perforating,
or by using the chart shown in Figure 52. The chart also makes allowance for friction
between cable and flow tubes.
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Figure 52. Chart for calculating tool weight required to overcome well pressure
Extreme care must be exercised when establishing drawdown levels for through tubing
operations in high rate gas wells which are not flowing, as the system friction and inflow
performance are major sources of uncertainty. Morever, in such cases it is vital to know
whether a liquid level is above or below the zone to be perforated. If a liquid slug is forced
up the wellbore it will create significantly higher forces. Attempts [29, 79] have been made
to quantify lifting forces in such cases, but no simple correlations are available. In view of
the inherent doubt it is recommended to restrict drawdown levels. One Opco has
successfully operated with the following guidelines :
•
maximum drawdown 50 bar (700 psi)
•
the total tool weight should be at least twice that required to overcome well
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pressure acting on the cross sectional area of the cable.
•
the top of the tool should be at least 10 m (30 feet) below the packer tail.
•
largest guns sizes are 21/8” and 111/16” for 7” and 41/2” casing respectively.
The major wireline companies offering perforation services have computer based tools
which can also be used to help establish area specific guidelines.
10.12.3
Operational Aspects
Underbalanced perforating implies that the hydrostatic head of the well fluid prior to
perforating is insufficient to control the flow of fluid from the formation into the well, and
should therefore only be conducted with surface pressure control equipment, even if the
well is not expected to produce fluid to surface. The underbalanced perforation of
reservoirs containing H2S may require additional precautions to ensure that the completion
is adequately internally pressure tested prior to perforating.
10.13
REFERENCES
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1.
Allen, T.O., and Attebury, J.H., Jr. :Effectiveness of Gun Perforating, Trans.,
AIME (1954) 201, 8-14.
2.
Allen, T.O., and Worzel, H.C. : Productivity Method of Evaluating Gun
Perforating, Drilling and Production Practice (1956) 112-125.
3.
Birkhoff, G., MacDougal, D.P., Pugh, E.M., and Taylor, G. : Exxplosive with
Lined Cavities, J. Appl. Phys. (1948) 563.
4.
Pugh, E.M., Eichelberger, R.J., and Rostaker, N.: Theory of Jet Formation by
Charges with Lined Conical Cavities, J. Appl. Phys. (1952) 537.
5.
Delacour, J., Lebourg, M.P., and Bell, W.T.: A New Approach Toward
Elimination of Slug in Shaped Charge Perforating, J. Pet. Tech. (March, 1958)
15-18.
6.
Robinson, R.L. : Temperature Effect on Formations during Jet Perforating, SPE
681-G (Oct., 1956).
7.
Bell, W.T., Lebourg, M.P., and Bricaud, J.: Perforating Today – A Science,
Drilling and Production Practice (1959) 249-260.
8.
Wade, R.T., Pohoriles, E.M., and Bell, W.T. : Well Tests Indicate New
Perforating Devices Improved Efficiency in Casing Completion Operation, J. Pet.
Tech. (Oct., 1962) 1069-1073.
9.
API Recommended Practice Standard Procedure for Evaluation of Well
Perforators, API RP 43, 2nd Ed. (July, 1971).
10.
Bell, W.T., and Shore, J.B., Casing Damage with Gun Perforators, Drilling and
Production Practice (1964) 7-14.
11.
Godfrey, W.K. : Effect of Jet Perforating on Bond Strength of Cement, SPE
2300, presented at 43rd Annual SPE Fall Meeting, Houston (1968).
12.
Rike, J.L. : Review of Sand Consolidation Field Experience in South Louisiana,
J. Pet. Tech. (May, 1966) 545-550.
13.
White, W., Walker, T., and Diebold, J. : A Proven Gas Well Completion
Technique for Higher Deliverability, J. Pet. Tech. (June, 1965) 647-656.
14.
Harris, M.H. : The Effect of Perforating on Well Productivity, J. Pet. Tech.
(April, 1966) 518-528.
McDowell, J.M., and Muskat, M. : The Effect on Well Productivity of Formation
Penetration Beyond Perforated Casing, Trans. AIME (1950) 189, 309-312.
15.
16.
Klotz, J.A., Krueger, R.F., and Pye, D.S. : Effect of Perforation Damage on Well
Productivity, SPE 4654, presented at 48th Annual Fall Meeting, Las Vegas,
Nevada (1973), J. Pet. Tech., November 1974.
17.
Bell, W.T., Brieger, E.F., and Harrigan, J.W., Jr. : Laboratory Flow
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Characteristics of Gun Perforations, SPE 3043, presented at 46th Annual Fall
Meeting, New Orleans (1971).
18.
Bell, W.T. : Recent Developments in Gun Perforating Techniques, Proceedings,
Seventh World Petroleum Congress (1967).
19.
Lebourg, M.P., and Bell, W.T. : Perforating of Multiple Tubingless Completions,
J. Pet. Tech. (May, 1960) 88-93.
20.
Tausch, G.H., and Kenneday, J.W. : Permanent-Type Dual Completions, Pet.
Engr. (March, 1956) 24-31.
21.
Huber, T.A., and Tausch, G.H. : Permanent-Type Well Completions, Trans.,
AIME (1953) 198, 11-16.
22.
Lebourg, M.P., and Hodgson, G.R. : A Method of Perforating Casing Below
Tubing, trans., AIME (1952) 195, 303-310.
23.
Bell, W.T., and Auberlinder, G.A., Perforating High Temperature Wells, J. Pet.
Tech. (march, 1961) 211-216.
24.
McEntree, J.R., Greer, R.L., and Collipp, P.B. : Underwater Drilling and
Completion Methods, Proceedings, Sixth World Petroleum Congress (June,
1963), Sec. 2, Paper 31, 39-59.
25.
Rigg, W.A., Childress, T.W., Jr., and Corley, C.B., Jr. : A Subsea Completion
System for Deep Water, SPE 1404, presented at the Symposium on Offshore
Technology and Operations (May 23-24, 1966).
26.
Huitt, J.L. : Hydraulic Fracturing with the Single Point Entry Technique, J. Pet.
Tech. (March, 1960) 11-13.
Thompson, G.D. : Effects of Formation Compressive Strength on Perforator
Performance, Drilling and Production Practice (1962) 191-197.
27.
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CHAPTER 11
SAND CONTROL
TABLE OF CONTENTS
11.1
INTRODUCTION ………………………………………………………………...... 5
11.1.1
11.1.2
11.1.3
11.1.4
11.1.5
11.2
SAND CONTROL METHODS ……………………………………………….….. 12
11.2.1
11.2.2
11.2.3
11.2.4
11.3
Background …………………………………………………………. 16
Formation Sampling ………………………………………………… 16
Sieving ………………………………………………………………. 17
Liner/Screen Completion …………………………………………… 20
Open-Hole Gravel Packs ……………………………………………. 21
Cased-Hole Gravel Packs …………………………………………… 22
Gravel Pack Screens ………………………………………………… 22
GRAVEL PACK DESIGN ……………………………………………………….. 25
11.4.1
11.4.2
11.4.3
11.4.4
11.4.5
11.4.6
11.4.7
11.5
Production Practices ………………………………………………… 12
Completion Practices ……………………………………………….. 13
Mechanical Retention ……………………………………………….. 13
Chemical Consolidation …………………………………………….. 15
MECHANICAL SAND CONTROL ……………………………………………... 16
11.3.1
11.3.2
11.3.3
11.3.4
11.3.5
11.3.6
11.3.7
11.4
Sand Problems ………………………………………………………. 5
Causes Of Sand Production …………………………………………. 6
Consequences Of Sand Production …………………………………. 7
Sand Detection ………………………………………………….…... 8
Sand Production Predictions ………………………………………... 10
Formation Sand Characterization …………………………………… 25
Design Point ………………………………………………………… 27
Gravel-Sand Ratio …………………………………………………... 27
Screen Slot Width …………………………………………………… 28
Example Design …………………………………………………….. 29
Gravel Pack Thickness ……………………………………………… 29
Summary ……………………………………………………………. 30
GRAVEL PACK PRODUCTIVITY ……………………………………........….. 31
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11.5.1
11.5.2
11.5.3
11.5.4
11.5.5
11.6
January 1998
Open-Hole Gravel Packs ……………………………………………. 31
Cased-Hole Gravel Packs …………………………………………… 32
Prepacking …………………………………………………………... 33
Producing Rate ……………………………………………………… 34
Summary ……………………………………………………………. 36
Cleaning The Casing ………………………………………………... 37
Workover Fluids ……………………………………………………. 37
Underreaming ……………………………………………………….. 38
Perforating …………………………………………………………... 38
Perforation Washing ………………………………………………… 39
Perforation Surging …………………………………………………. 41
Acidizing ……………………………………………………………. 42
Advantages ………………………………………………………….. 44
Transport Through Perforations …………………………………….. 44
Bridging In Perforations ……………………………………………. 45
Wellbore Angle ……………………………………………………... 46
Fluid Viscosity And Rate …………………………………………… 48
Recommendations …………………………………………………... 49
GRAVEL PLACEMENT …………………………………………...……............. 51
11.8.1
11.8.2
11.8.3
11.8.4
11.8.5
11.8.6
11.8.7
11.8.8
11.8.9
11.8.10
11.9
PROPRIETARY INFORMATION -For Authorised Company Use Only
GRAVEL PLACEMENT – PREPACKING …………………………........……. 44
11.7.1
11.7.2
11.7.3
11.7.4
11.7.5
11.7.6
11.8
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GRAVEL PACK PREPARATION ………………………………………….…... 37
11.6.1
11.6.2
11.6.3
11.6.4
11.6.5
11.6.6
11.6.7
11.7
SAND CONTROL
Choice Of Fluids ……………………………………………………. 51
Slurry Packing ………………………………………………………. 51
Circulation Packing …………………………………………………. 53
Deviated Wells ……………………………………………………… 55
Wash Down …………………………………………………………. 57
Reverse Circulation …………………………………………………. 58
Crossover ……………………………………………………………. 59
Filtration …………………………………………………………….. 62
Sand Injection ………………………………………………………. 64
Summary ……………………………………………………………. 65
PLASTIC CONSOLIDATION PRINCIPLES …………………………………... 66
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11.9.1
11.9.2
11.9.3
SAND CONTROL
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Macroscopic Objectives …………………………………………….. 66
Microscopic Objectives ……………………………………………... 68
Sand Coating Methods ……………………………………………… 68
11.10 PLASTIC CONSOLIDATION CHEMICALS ……………………………......... 71
11.10.1
11.10.2
11.10.3
11.10.4
11.10.5
Preflush ……………………………………………………………… 71
Resin ………………………………………………………………… 72
Diluent ………………………………………………………………. 74
Coupling Agent ……………………………………………………... 74
Overflush ……………………………………………………………. 75
11.11 WELL PREPARATION FOR PLASTIC CONSOLIDATION ……………...... 76
11.11.1
11.11.2
11.11.3
11.11.4
11.11.5
11.11.6
Wellbore Equipment ………………………………………………… 76
Perforating …………………………………………………………... 77
Prepacking …………………………………………………………... 78
Injectivity Testing ………………………………………………….. 79
Acidizing ……………………………………………………………. 79
Neutralizer ………………………………………………………….. 79
11.12 PLASTIC PLACEMENT ……………………………………………………….… 81
11.12.1
11.12.2
11.12.3
11.12.4
11.12.5
11.12.6
11.12.7
Objective …………………………………………………………….
Rathole Fluid ………………………………………………………...
Annulus Fluid ………………………………………………………..
Concentric Workstring ………………………………………………
Conventional Workstring ……………………………………………
Bullhead ……………………………………………………………..
Restoring Production ………………………………………………..
81
81
82
82
84
84
85
11.13 COMMERCIAL PLASTIC CONSOLIDATION SYSTEMS …………………... 86
11.13.1
11.13.2
11.13.3
11.13.4
11.13.5
11.13.6
Evaluation Criteria …………………………………………………..
Data Sources …………………………………………………………
Evaluation Summary ………………………………………………...
Epoxy II ……………………………………………………………...
Sanfix ………………………………………………………………..
Field Results …………………………………………………………
86
86
88
89
92
93
11.14 RESIN-COATED SAND …………………………………………………………... 95
11.14.1
11.14.2
Objective ……………………………………………………………. 95
Sand Coating Methods ……………………………………………… 95
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11.14.3
11.14.4
11.14.5
SAND CONTROL
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Placement Procedures ………………………………………………. 96
Commercial Systems ……………………………………………….. 97
Field Results ………………………………………………………… 98
11.15 SELECTING A SAND CONTROL METHOD ……………………………….… 100
11.15.1
11.15.2
11.15.3
11.15.4
11.15.5
11.15.6
11.15.7
11.15.8
11.15.9
Plastic Consolidation ……………………………………………….. 100
Resin-Coated Sand ………………………………………………….. 101
Gravel Packing ……………………………………………………… 101
Conventional Completions ………………………………………….. 102
Tubingless Completions …………………………………………….. 103
Well Deviation ……………………………………………………… 104
Interval Length ……………………………………………………… 104
Sand Quality ………………………………………………………… 105
Reservoir Conditions ……………………………………………….. 106
11.16 WELL BEAN-UP PROCEDURE .....................……………………………….… 107
11.1
INTRODUCTION
11.1.1
Sand Problems
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The production of formation sand into a well is one of the problems in the oil and gas
industry. Not only does formations sand plug wells, but it also can erode equipment and
settle in surface vessels. It is estimated that PCSB spends millions of dollars each year to
prevent the production of formation sand and to deal with other sand-related problems.
In considering sand control, or formation solids control, it is necessary to differentiate
between load-bearing solids and the fine particles. Fines are not usually considered to be a
part of the mechanical structure of the formation. Sand control actually refers to the control
of the load-bearing particles - those that support the overburden. The problem then lies in
deciding what is excessive sand production. As a practical limit, any sand production
higher than 0.1% (volumetric) can usually be considered excessive.
Sand production has been experienced in essentially every area in the world where oil or
gas production occurs from sandstone reservoirs (see Figure 1). Sand production is the
most common in Tertiary age sand reservoirs. Since these reservoirs are geologically
young and are usually located at relatively shallow depths, they are no more than
moderately consolidated (~ 1000 psi compressive strength).
Figure 1. Sand problem areas worldwide
11.1.2
Causes Of Sand Production
When fluids are produced from sandstone reservoirs, stresses are imposed on the sand
grains that tend to move them into the wellbore along with the produced fluids (Figure 2).
These stresses are caused by pressure differences in the formation, fluid frictional forces,
and the weight of the overburden. When the combined magnitude of these stresses exceeds
the strength of the formation, sand will be produced. The implication is that for many
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wells, there is a critical production rate below which sand will not be produced and above
which the formation will fail. Unfortunately, this critical rate is often below the economical
producing rate. Some means of sand control must therefore be employed as an initial or
remedial part of the well completion.
Figure 2. Movement of sand grains caused by fluid flow stress
Opposing fluid forces are the restraining forces that act to hold sand grains in place. These
forces arise from intergranular bonds (natural consolidation), intergranular friction, gravity
forces, and capillary forces. Internal pore pressure (reservoir pressure) helps support the
weight of the overburden, thereby acting to relieve some of the stress on the sand grains.
Of these forces, the intergranular bonds are the most important factor in preventing sand
production. The compressive strength of a formation sand is measure of the intergranular
bond. Provided that good completion and production practices are followed, formations
with a compressive strength greater than 1000 psi will generally produce sand-free. The
exception is the instance in which the pressure drawdown around the well is high.
Predicting the sand-producing tendency of a formation is complicated, not only because
data on the various factors to be considered are limited, but also because many of these
factors change with time. Some examples of time-related changes follow:
•
Decreasing reservoir pressure increases the overburden stress on the sand grains.
•
Water production may dissolve natural cementing materials and weaken intergranular
bonds.
•
Permeability reductions resulting form water production, fines invasion, and the like
increase the stresses induced on the sand grains by fluid flow.
Because the problem is complex, the most meaningful prediction of potential sand problems
is usually a correlation based on the performance of offset wells producing from the same
reservoir.
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11.1.3
SAND CONTROL
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Consequences Of Sand Production
Removal of sand from surface equipment, such as manifolds and separators, is a common
occurrence in sand-producing regions. Perhaps only troublesome in land-based operations,
sand disposal can become an acute problem offshore. Special treating facilities are required
to remove the oil from the sand prior to offshore disposal. The problems arising from
produced sand become more severe when the entrained sand is carried at high enough
velocities to erode surface equipment, such as valves and chokes, necessitating periodic
replacement of these items. By far the worst complication growing out of sand production
is the erosion of surface equipment to the point that it fails, allowing high-pressure gas
and/or oil to escape. This situation obviously constitutes a severe safety and pollution
hazard.
Productivity loss occurs when a sand bridge forms in the production tubulars. This sandedup condition occurs when the fluid velocity is not sufficient to suspend the produced sand
completely and flow it from the well. In settling out of the produced fluids, sand can then
fill the production tubing and block the flow. The amount of sand fill sufficient to plug the
tubing can range from a few to several hundred feet. These bridges must be removed either
by bailing or washing before production can be restored.
Casing failure may accompany the production of formation sand in the producing interval,
meaning the loss of a well. As sand is produced, slumping of the overlying casing-bearing
formations can subject the entire casing string to abnormal loads. Such loads can lead to
severe buckling when the lateral restraint provided by the surrounding sand is lost during
sand production. In an example from offshore Louisiana, 7-in. casing was deflected 8 in.
within a vertical distance of 5 to 10 ft (see Figure 3).
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Figure 3. Casing buckling caused by sand production in well in offshore Louisiana.
The 7-in. casing was deflected 8-in. within vertical distance of from 5to 10 ft.
11.1.4
Sand Detection
Devices to detect the presence of sand in produced fluids can substantially improve the
safety and productivity of wells in sand- producing areas. Two currently available devices
detect sand produced to the surface - the Exxon sand probe and the Mobil sonic sand probe
(marketed by OIC). These devices enable the engineer to take remedial action in advance
of sand damage to tubular goods thus lowering workover costs. They can also be used to
establish the maximum sand-free production rate for each well.
The Exxon sand probe (Figure 4) is a hollow stainless steel cylinder, plugged at one end,
which is inserted into a flow stream with the open end protruding from the wall of the pipe.
The probe was developed by Exxon and is manufactured by AMCO Equipment Co. and
Otis Engineering Co. When produced sand erodes the wall of the probe, flow stream
pressure is transmitted to a pilot valve, which closes the surface safety valve and shuts in
the well.
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Figure 4. Exxon’s sand probe installed in a flow stream
The sand probe has been extensively tested by Exxon USA and is currently in use on all of
their offshore Louisiana wells. It has three principal applications. It serves as a safety
device, as an aid in optimizing production rates, and as a tool in the selection of workover
candidates. By using sand probes, one USA Offshore operator was able to reduce by 78%
the number of production units eroded and to reduce costs associated with equipment
failure related to sand erosion by more than 75%. Fire and pollution hazards were also
reduced. Production increased, furthermore, because the number of sand-ups had
decreased.
The sonic sand probe detects the impact of sand as an acoustical signal. It was developed
and field-tested by Mobil Oil Corporation, and a commercial unit is currently marketed by
Oceanography International and by the Johnston Division of Schlumberger. Reports have it
that there are over 200 of these units currently in service in the industry. The principal
advantage is that the probe provides an immediate indication of sand production. Its
disadvantages lie in the expense involved and the fact that the signal is not currently related
to the erosiveness of the sand being produced. Figure 5 is a photograph of the sonic sand
probe and instrument package.
Figure 5. Sonic Sand Probe
The probe is mounted in a surface flow line. Acoustical “pinging” of impinging sand is
converted in the probe to an electrical signal. The signal can be calibrated to determine the
concentration of solids in terms of pounds per day, or grams per second, as a function of
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fluid velocity. Both the mass concentration of solids in the flow stream and the rate of sand
production are provided. If fluid or gas production rates are known, the rate of sand
production and solids concentration can be determined within a factor of two.
11.1.5
Sand Production Predictions
Research has shown that sand production is proportional to the pressure drop and flow rate
across the formation sand. An investigation, designed to determine the magnitude of the
pressure drops that core samples can withstand without producing sand, demonstrated the
following relationship :
Onset of ∆P at sand production ~ 1.7 x sand compressive strength, psi
This correlation indicates that even though compressive strength is exceeded, sand
production does not occur until a rock’s compressive strength is substantially exceeded.
The relationship applies only to consolidated sands; no correlation exists for unconsolidated
sands. Here it should be assumed that in most cases sand production will occur when fluid
is produced.
Schlumberger’s Mechanical Properties Prediction is claimed to be a method of determining
if a formation will produce sand. The technique is based on calculations made from data
taken from sonic, density, and neutron logs. Although such predictions probably can point
out those zones that are more (or less) consolidated than others, no information exists to
show that the technique has been used successfully to predict sand production in PCSB
wells. It may, however, be an effective tool in those circumstances in which its results can
be correlated with field observations.
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11.2
SAND CONTROL
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SAND CONTROL METHODS
Several techniques can be used to combat sand problems, and they can be grouped into four
general categories :
•
Production practices
•
Completion practices
•
Mechanical retention
•
Chemical consolidation
Each of these methods, using singly or in combination, has been used to alleviate and/or
control sand-production problems. No one technique, however, can be used to control sand
effectively under all circumstances. Thus, it is important that the advantages and
limitations of each technique be recognized so that the best procedure can be followed.
11.2.1
Production Practices
Sand production is the natural consequences of the flow of fluids into a well; therefore,
reducing the production rate will normally diminish sand production as well. The flow of
formation sand into a well is proportional to the velocity-viscosity product (V x µ), which is
related to the drag force created by the flowing fluid. Laboratory and field tests have
shown that sand production can be reduced by lowering the production rate (drag force) to
the point that the natural cohesive forces within the sand hold it in place. Sand control
therefore becomes possible through a step-by-step reduction in the production rate to a level
at which the sand cut is acceptable. If the flow rate is sufficiently high, no further sand
control may be necessary.
Since sand production occurs when the stresses associated with fluid withdrawal exceed
some critical value, the probability of formation failure in any given well can be reduced by
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minimizing such stresses. Recognizing this fact, the oil industry in its early history
controlled sand almost exclusively by limiting fluid production rates. Today the production
from many wells is still held below some assumed “critical rate” thought to cause formation
failure. Unfortunately, the critical rate is difficult to predict accurately and to associate
with incipient failure.
Unless the critical rate for a particular well remains high, any voluntary restriction on flow
rate to prevent sanding represents a lost opportunity for maximizing revenue. Often in the
past, production from sand-prone wells has been curtailed without a loss of profit. But the
current surge in demand for energy means that reduced production rates are equivalent to
smaller profits. Engineers in many areas that in the past have required no means of sand
exclusion other than a reduction in rate should now consider new techniques.
11.2.2
Completion Practices
If a well is to be completed in an unconsolidated formation without a sand-control
treatment, several completion practices should be followed to minimize the possibility of
formation failure and subsequent loss of production. In general, these practices are
intended to reduce the stresses caused per unit of production by enhancing the ability of the
formation to produce fluid. They include the use of :
•
Clean completion fluids
•
High perforation densities
•
Perforation of long intervals
•
Perforation of clean sands
The desirability of clean workover and completion fluids has long been recognized by the
oil industry. Fluids that are free of solids and compatible with formation material are
essential to successful sand control. Partially plugged perforations and/or formation
damage caused by incompatible or solids-laden wellbore fluids can require excessive
pressure drawdowns in order to produce desired fluid rates.
In 1969 a study of the effect of perforation density on consolidated formation failure was
undertaken. This study, and others that followed, revealed that sand problems in untreated
intervals could be minimized by increasing perforation density. Also, the frequency of sand
problems in wells completed without sand-control measures decreased significantly with
increasing length of perforated interval.
It has long been noted that sand problems are more severe in dirty, fine-grained formations
than in relatively clean, well-developed sands. The success of producing the more
permeable segments reflects the effect of limiting wellbore stresses by reducing drawdown.
Also aiding production success is the fact that segments containing a high percentage of
non-silica particles (indicated by a poorly developed SP curve) generally exhibit low
permeability and poor natural cohesion. If possible, these intervals should be avoided.
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11.2.3
SAND CONTROL
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Mechanical Retention
One obvious method of preventing formation sand from being produced is to physically
restrain its entry into the wellbore flow stream. To accomplish this goal, many types of
mechanical devices have been used in both the water-well and oil industries. Spherical
particles will not flow continuously through rectangular slots even twice as wide as the
diameter of the particles, or through circular holes three times their size.
The particles tend to “bridge” across such openings, thereby preventing further particle
movement. If the size of the particles varies, retention of the larger particles causes the
smaller particles to bridge behind them.
All methods of mechanical retention are based upon the principle of retaining a certain
portion of the formation material to prevent the rest of it from entering the well. Devices
used by themselves to restrict sand movement are usually referred to as screens or slotted
liners. The placement of large clean sand (actually referred to as gravel, because it is much
larger than formation sand) between the screening device and the formation is referred to as
gravel packing. Figure 6 shows a gravel packed completion.
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Figure 6. Gravel Pack Schematic
11.2.4
Chemical Consolidation
Chemical consolidation has primarily involved the use of plastics to artificially cement the
formation sand grains together so that formation fluids can be produced sand free. To be
effective, the plastics must (1) wet the sand surfaces and adhere to the sand grains, (2) yield
a high compressive strength upon curing, and (3) maintain high well productivity. Figure 7
indicates the region surrounding the wellbore that is cemented by plastic consolidation.
Another chemical sand control method involves a resin- coated sand, which is mixed at the
surface and pumped into the well. The gravel-plastic slurry is then allowed to settle and
cure. After curing, the residue is drilled out of the well, which is then placed on
production. Figure 7 illustrates a resin-coated sand treatment.
Figure 7. Chemical Consolidation Methods
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11.3
MECHANICAL SAND CONTROL
11.3.1
Background
Mechanical sand control in wells originated with the water-well industry, because early
water-well completions in shallow formations commonly produced sand. A mechanical
device inserted in these wells excluded sand but allowed fluids to enter the well. In these
early completions the mechanical devices included torch-cut slots, perforated casing,
louvre-type screen, and machine-slotted pipe. More recently, several varieties of wirewrapped screen have been used.
Mechanical sand-control methods are based on bridging theory. That is, the formation sand
bridges against some sort of filtering medium, which allows the passage of fluid but
prevents the production of formation sand. Water wells were normally completed by
developing, which involved the alternate surging and producing of the formation. The finer
particles were thereby produced from the well, leaving the uniformly graded sand or gravel
with higher porosity and permeability surrounding the screen or slotted liner.
Figure 8. Schematic of a natural gravel pack after developing
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11.3.2
SAND CONTROL
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Formation Sampling
The size and distribution of the formation sand, as determined from a sieved sample, is
important to the optimal design of gravel packs. Rubber sleeve cores are the preferred
formation material. If none are available, produced sand or sidewall cores can be
substituted. It should be remembered, however, that produced solids may be too fine and
bailed solids too coarse to be representative. Also, sidewall cores may contain crushed
grains or significant amounts of drilling mud contamination.
11.3.3
Sieving
In practice, sieving is simple. The disaggregated material to be sized is placed in a sieve
and shaken until those particles smaller than the sieve openings fall through. Separation
into any number of size groups is possible if a progression of sieve sizes is used, from
larger to smaller, downward from the top screen. Shaking should be done on an automatic
machine for about 20 minutes. This length of time represents a compromise between the
provision of complete separation of grain sizes and the avoidance of sediment-particle and
screen erosion. After shaking, the material retained on each sieve and that which fell
through the finest sieve into the pan are weighed and recorded.
The theory of sieving is not quite as simple as the practice. Most grains are not spherical,
hence separation is not based solely on grain diameter - grain shape also plays a part. A
long, lath-shaped grain theoretically could pass a given sieve if its two smaller dimensions
are less than those of the sieve opening. Despite these shortcomings, sieving is an
established technique in the mechanical analysis of sediments.
The Tyler Standard Screen Series, as well as the U.S. Mesh Series, is commonly used in
sieving. The openings of each successively larger screen are increased by a factor of two.
The diameter of grains retained on these openings thus increases geometrically be a factor
of √2, or 1.414. Closer grading can be achieved by including screens with openings with a
progression of 4√2, or 1.189. By themselves they provide an offset scale also increasing by
the √2 progression. Table I compares the Tyler and U.S. Mesh series.
The weight data from a sieve analysis are arranged according to the weight percent retained
on a given screen. The cumulative weight percent retained is obtained by summing the
percentages on successive screens. The tubular classification of data does not lend itself to
visual comparison of grain-size distributions. Comparisons are easier when a graph of
grain size (horizontal scale) is used.
Comparison and interpretation of the cumulative size-frequency distribution are fairly
simple. If a curve maintains its form, a translation along the abscissa reflects a change in
grain size (Figure 9). A change in slope or stepness in the cumulative curve represents a
change in the sorting of grain sizes (Figure 10). Skewed distributions are asymmetrical, as
shown in Figure 11.
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Figure 9. Sand grain distribution showing grain size change
Figure 10. Sand train distribution showing changes in sorting
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Table I
Sand Sieve Sizes
Standard Sieve Openings (1)
Mesh
Sieve Opening
U.S. (2)
Tyler
Inches
Millimeters
Series
Series
21/2
21/2
3
3
31/2
31/2
4
4
5
5
6
6
7
7
8
8
10
9
12
10
14
12
16
14
18
16
20
20
(1)
(2)
0.315
0.312
0.265
0.263
0.223
0.221
0.187
0.185
0.157
0.156
0.132
0.131
0.111
0.110
0.0937
0.093
0.0787
0.0078
0.0061
0.065
0.0555
0.05
0.0469
0.046
0.0394
0.0390
0.0331
0.0328
8.00
7.925
6.73
6.68
5.66
5.613
4.76
4.699
4.00
3.962
3.36
3.327
2.83
2.794
2.38
2.362
2.00
1.981
1.68
1.651
1.41
1.397
1.19
1.168
1.00
0.991
0.84
0.833
Standard Sieve Openings (1)
Mesh
Sieve Opening
(2)
Tyler
Inches
Millimeters
U.S.
Series
Series
25
30
35
24
28
32
40
45
50
35
42
48
60
60
70
65
80
80
100
120
140
170
200
230
270
325
400
Chemical Engineers’ Handbook, 3rd Edition, McGraw Hill.
Hydraulic Fracturing Proppant screens used in U.S.
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100
115
150
170
200
250
270
325
400
0.0280
0.0276
0.0232
0.0197
0.0195
0.0165
0.0164
0.0138
0.0117
0.0116
0.0098
0.0097
0.0083
0.0082
0.0070
0.0069
0.0059
0.0058
0.0049
0.0041
0.0035
0.0029
0.0024
0.0021
0.0017
0.0015
0.71
0.701
0.589
0.50
0.495
0.42
0.417
0.351
0.297
0.295
0.250
0.246
0.210
0.208
0.177
0.175
0.149
0.147
0.124
0.104
0.088
0.074
0.062
0.053
0.044
0.037
CM 11
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Figure 11. Sand grain distribution showing skewing
11.3.4
Liner/Screen Completions
A screen or slotted liner can be simply run into position and the produced sand allowed to
bridge around it. Since no back-surging or pump-in treatments are normally used, the finer
particles are not removed effectively from the near-wellbore sand mass, and lower
productivity is usually the result. Completions in which only a screen or slotted liner is run
in a well have been unsuccessful in controlling sand and/or maintaining a well’s
productivity for long periods of time.
Probably the reason this technique is less successful in oil and gas wells than in water wells
is that most hydrocarbon-bearing rock formations are more consolidated than are shallow
aquifers. The liner/screen-only completion typically decreases in productivity with time
because of plugging around the screen/slot openings. For this reason, the technique is not
preferred.
11.3.5
Open-Hole Gravel Packs
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Gravel packing is the recommended method for mechanically controlling formation sand
production in oil and gas wells. This technique, as noted earlier, entails using accurately
sized gravel to exclude formation sand. A screen or slotted liner retains the gravel, but
allows the entry of fluids into the well.
Open-hole gravel packs are completions in which there is no perforated casing between the
gravel pack and the screen or slotted liner (see Figure 12). This completion has the highest
productivity of all gravel packed completions. As far as well completions in general are
concerned, its productivity is surpassed only by an open-hole completion.
Figure 12. Schematic of gravel packing techniques
The primary disadvantage of the open-hole gravel pack is the inability to isolate extraneous
fluids, such as gas or water at the sand face.
A second limitation is that not all sand formations are physically structured to
accommodate this type of completion because of hole instability. In these cases the sand
formations are usually cased off prior to completion.
Other than these two limitations, the open-hole gravel pack is the preferred mechanical
sand-control technique when there is no contraindication to its use. As a general statement,
it is used to greatest effectiveness in long-life completions in which the production of water
and/or gas will not present a problem.
11.3.6
Cased-Hole Gravel Packs
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The cased-hole gravel pack consists of a screen or slotted liner that is gravel packed inside a
perforated casing (see Figure 12). This completion is the most widely used gravel pack
today in oil and gas wells. It is chosen primarily because, upon the initial completion, it is
not always certain if wells will produce formation sand. Consequently, many wells are
perforated and then produced. If no sand appears, a gravel pack is not necessary; but a
cased-hole gravel pack can be performed later if sand control becomes necessary.
Furthermore, this completion is better adapted to exclude water and/or gas if the need
arises.
The primary disadvantages of the cased-hole gravel are that (1) they are not as well suited
as the open-hole packs for high flow rates, and (2) they are much more difficult to perform
correctly. Both of these limitations arise from the greatly limited cross-sectional area of
flow in the sand-filled perforations of cased-hole packs compared with that of the open
hole. It is therefore extremely important that all perforations, as well as the region outside
them, contain gravel of the highest permeability able to control formation sand production
effectively.
To perform cased-hole packing properly requires that all perforations be open and free of
formation sand when the well is completed. If at all possible, the region outside the
perforation should be prepacked with gravel - that is, filled with gravel of the highest
permeability able to control sand production. The procedure usually includes washing or
surging the perforations to ensure that they are open to accept the gravel.
11.3.7
Gravel Pack Screens
Gravel packing entails the use of accurately sized gravel as the filtering medium. The
gravel is retained in an annular region around the well by some mechanical device that also
allows the entry of fluids into the well. In most present-day oil and gas well completions
requiring gravel packing, either a slotted liner or a wire-wrapped screen is used.
A slotted liner usually consists of vertical slots spaced uniform about the pipe. The width
of the slots can vary from 0.020 in. to as large as desired, depending on the gravel size.
Figure 13 illustrates the various combinations of slots for slotted liners. The liners are
much less expensive than the wire-wrapped screens, but they are not as effective. Their use
is confined to those situations in which wire-wrapped screens cannot be used economically.
In wire-wrapped screens the wire is wrapped directly on the pipe base, which may be
drilled, slotted, or slotted and grooved. Longitudinal rods are also used between the screen
and the pipe in some cases. The screen-slot openings are controlled by lugs, which are
crimped into the wire during screen fabrication. After the wire is wrapped on the pipe base,
it is welded at each end of the screen joint and is held in place by two longitudinal welds
that extend the length of the screen. Figure 14a is a photograph of a wire-wrapped screen.
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Figure 13. Slotted-liner slot geometry
Figure 14. Wire Screens
Rod-base screens are similar to the jackets on all-welded construction screens, but they
contain no pipe base. In their manufacture the wire is resistance-welded to longitudinal
rods. The final step in their construction is to weld connections on the ends of each screen.
Figure 14c is an example of a rod-base screen.
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Wire-wrapped and all-welded screens have the advantage of offering much more open area
per liner foot than slotted liners. Consequently, they are less susceptible to plugging. They
are used in most completions instead of slotted liners if the additional cost can be justified.
The wire on all-welded, wire-wrapped, and rod-base screens is keystone in shape, that is, it
tapers toward the center. This design avoids the liability of plugging as particulates pass
through the screen slots. The keystone-shaped wire can be seen in Figure 14. Unless
otherwise specified, all wire is grade 304 stainless steel.
Tests were made of the wire screens available to the industry in order to determine their
strength and flow characteristics. The results of the study were compared with the results
of the same tests performed with slotted pipe.
Tensile Strength
•
Pipe-base screens are about twice as strong as rod-base screens under tensile loading
conditions.
Collapse Strength
•
Collapse failures of all-welded screens is related primarily to the excessive standoff of
the screen from the pipe base. To avoid low collapse resistance, close tolerance
should be observed by manufactures.
Flow Capacity
11.4
•
The flow capacity of screens, slotted liners, and gravel packs does not pose a
significant restriction to flow unless they become plugged.
•
Rod-base screens offer no significant advantage over pipe-base screens in flow
capacity.
GRAVEL PACK DESIGN
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The basic problem is how to control formation sand without an excessive reduction in well
productivity. To achieve effective control implies a good gravel pack design, the essential
elements of which include :
11.4.1
•
Analysis of formation grain-size distribution
•
Selection of an optimum gravel size in relation to formation sand size in order to
control formation sand movement
•
Use of the optimum screen slot width to retain the gravel
Formation Sand Characterization
The first step in the design process is to obtain representative samples of the specific
formation’s sand. The distribution of grain size often varies through a particular sand body,
and certainly from one zone to another. To assure representative measurements, therefore,
a number of samples are needed.
In gravel packing, formation sand is controlled by properly sized gravel. For correct gravel
sizing, the producing formation’s grain size must be determined accurately. The most
widely used methods for assessing grain size are based on the Tyler Standard or U.S. Series
screen scales, which grade the screen or sieve sizes in mesh numbers. In this technique,
representative formation sand samples are extracted, dried, weighed, and passed through
screens of varying sizes.
The slope of this sieve analysis curve indicates the sand’s uniformity. In Figure 15, curve
A which is almost vertical, represents a highly uniform sand. Curve D, which leans toward
the horizontal, suggests a non-uniform sand. A specific value of uniformity is useful in
providing an approximate description of the distribution curve.
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Figure 15. Sieve analysis curve
The convention has been to describe the distribution curve by the grain size at two specific
percentile points, 40 and 90.
The dimension of the grain size at the 40 percentile divided by that at the 90 percentile is
called the uniformity coefficient, Cµ.
d40
Uniformity coefficient
= Cµ =
d90
Although this relationship has become the accepted method for expressing a sand’s
uniformity, it is somewhat confusing in that highly uniform sands have low uniformity
coefficients, whereas non-uniform sands have high coefficients. As a general guideline,
11.4.2
Cµ < 3
- Sand usually considered uniform
3 < Cµ < 5
- Sand considered non-uniform
Cµ > 5
- Sand highly non-uniform (sand with a uniformity coefficient of this
magnitude is rare)
Design Point
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A gravel pack is designed to restrain the load-bearing grains of the formation sand from
passing into the wellbore. These larger grains will bridge the smaller ones, controlling the
entry of formation sand into the well while permitting the passage of fluids. This size is
used as the design point for sizing gravel, because gravel size is a multiple of the formation
sand size at the design point.
For uniform sands the design point is not particularly important, since there is very little
difference in grain size between the 10 or 50 percentile points. For non-uniform sands,
however, a considerable difference in the grain size exists, and the selection of the
appropriate value becomes more critical. Work performed at Exxon and also by Shell*
suggests that designing a gravel pack on the 50 percentile point is probably the best for all
conditions. It will yield about the same design for a uniform sand that the 10 percentile
would, and it will also provide the optimum design for non-uniform sands.
Data indicate that a gravel pack should not be designed so that it blocks all formation
particles, which occurs when high design points are used. If high design points are chosen,
well productivity can be severely limited by a total plugging of the gravel pack by fine
particles - material that is normally produced through the gravel pack if it is designed to
retain only the load-bearing particles.
*Saucier, R.J., “Gravel Pack Design Considerations,” Paper SPE4030, 47th Annual Fall Meeting SPE of AIME, San Antonio,
Texas, Oct. 8-11, 1972.
Use of the 50-percentile design point produces a simpler and more straightforward design.
For highly uniform sands it yields the same design that the 10-percentile design point does.
For non-uniform sands, it avoids a gravel size so small that sand control measures predicted
on it will seriously affect well productivity.
11.4.3
Gravel-Sand Ratio
The gravel-to-sand (G-S) ratio - defined as the ratio of the gravel grain size to the formation
sand grain size at equal percentile points - is one of the most important parameters in the
design of a gravel pack. When the G-S ratio is too high, the oversized gravel is invaded by
formation sand, which reduces the overall permeability of the packed zone (often to less
than the native reservoir permeability) and impairs productivity. Oversizing the gravel is a
common error in designing oil field gravel packs. On the other hand, undersizing results in
excellent sand control; however, it is at the expense of productivity.
The theoretically optimum range for the G-S ratio is about 5 to 6, as illustrated in Figure 16,
for highly uniform sands. At a ratio of 6, productivity is at maximum and sand control is
also achieved. With a ratio of 15, pack permeability is good but sand control is poor,
because the formation sand can move easily through the pack. With a ratio of 10, formation
sand can move into the gravel pack but has difficulty moving through it. The result is a
severe loss in gravel pack productivity.
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Figure 16. Effect of sand control on productivity
To compensate for possible optimism and to adjust for an erroneous choice of design pont
(caused, perhaps, by improper sampling), a G-S ratio of 5 to 6 is recommended. That is, the
diameter of the gravel to be used for packing should be 5 to 6 times the diameter of the
formation sand at the 50-percentile design point selected from the grain-size analysis curve
of the formation sand.
The use of close, accurately sized gravel is important. Recommendations are that 96% of
the gravel should be within the specified size range and that fines compose no more than
2%. Further, a roundness and sphericity of 0.6 is recommended, and the acid solubility
should not exceed 3.0% when the sand is exposed to 12-3 hydrochloric/hydrofluoric acid
for 30 min.
11.4.4
Screen Slot Width
Ideally, slot widths should be as large as possible while retaining sand grains and not
restricting the flow of fluids and interstitial fines. Because it is imperative that all the
gravel be tightly packed and retained, screen slot width for a gravel pack should be about
one-half the smallest gravel diameter. Under no conditions should the slot be wider than
70% of the smallest gravel-size diameter.
11.4.5
Example Design
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An example of a typical gravel pack design is shown graphically in Figure 17 for a sieve
analysis whose 50 percentile point is about 0.004 inches. Six times this quantity is 0.024
inches. The gravel line is constructed through this point with a uniformity coefficient of
1.5. The gravel size for this sand is taken from the zero and 100 percentile points, 0.035
and 0.018 inches. Consequently the nearest standard gravel size is 20/40 U.S. mesh. The
slot width is taken as 1/2 the smallest gravel, which is 1/2 x 0.0165 = 0.00825 inches.
Figure 17. Gravel pack design
11.4.6
Gravel Pack Thickness
Many opinions have been expressed regarding the optimum thickness of gravel packs.
Carefully controlled laboratory experiments have shown that a thickness of only 3 to 5
grain diameters is required to create a stable bridge. This conclusion is based on the
assumption, however, that the bridge will be permanent and completely effective.
Occasional adjustments of sand particles with changes in differential pressures and flow
velocities will no doubt occur. With each failure of a sand bridge, individual grains particularly the finer grains - may encroach further into the gravel envelope. It follows that
the thicker the gravel bed, the greater the assurance that the pore spaces between gravel
particles will remain unclogged with sand. Gravel pack design should therefore place more
emphasis on pack thickness than on screen diameter.
Recommended screen diameters for various casing sizes are listed below :
Screen Size (in.)
Casing Size (in.)
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5
3-1/2
2-7/8 to 3-1/2
2-3/8
1-1/4 to 1-1/2
9-5/8
7-5/8
7
5-1/2
4
Since screen flow capacities are extremely high, the screen diameter recommendation is
based on a diameter that allows it to be washed over.
11.4.7
Summary
To achieve optimum results from gravel packing the operator should :
•
Obtain a representative sample of formation sand. Rubber-sleeve cores are best;
sidewall cores are acceptable; bailed or produced sand should be used only as a last
resort.
•
Sieve the formation sand and plot a cumulative weight distribution. Calculating the
coefficient of uniformity may be useful, i.e.,
diameter at 40-percentile point
Cµ =
11.5
diameter at 90-percentile point
•
Select a gravel diameter that is five to six times the design point size, i.e., five to six
times the 50-percentile size of the formation sand.
•
Specify the narrowest range of sieve sizes that would successfully contain the selected
gravel diameter.
•
Use a screen slot size that is one-half the smallest gravel size. In any case, slot size
should never exceed 70% of the smallest gravel diameter.
GRAVEL PACK PRODUCTIVITY
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Within the past several years, new emphasis has been placed on gravel packing, particularly
when cased-hole packs are required. This interest has evolved because of the new high-rate
fields under development that will require some sort of sand control. Examples are fields in
the North Sea, the Middle East, and Southeast Asia. Some of the wells in these areas are
capable of producing at rates in the 400 BFPD/ft range. Research on cased-hole gravel
pack performance has also accelerated because of higher water and gas cuts associated with
producing oil in older fields, a circumstance tending to have adverse effects on productivity
and sand production.
11.5.1
Open Hole Gravel Packs
Research was conducted to determine the magnitude of productivity losses associated
primarily with screens and slotted liners. The equipment used in this study is shown in
Figure 18. Here the model simulated flow conditions in the immediate vicinity of the well.
Note that the screen was placed in the model with sand around it, an arrangement actually
analogous to an open-hole gravel pack. Tests were then made to assess pressure losses as a
function of flow rate.
Figure 18. Schematic of and equipment used in flow capacity test
with screens and slotted liners
The results of these tests are shown in Figure 19. Note here that the flow rates were
extremely high, yet pressure losses were quite low. Wire-wrapped screens were shown to
have higher flow capacities than slotted liners; however, at realistic field rates the pressure
drop through either was only a few psi.
The implications of these tests are that the screen/slotted liner and gravel pack offer no
significant restriction to well productivity, unless they become plugged. We observed that
slotted liners become plugged more easily than do wire-wrapped screens. To avoid
plugging with gravel, screen/slot openings equal to half the smallest gravel size are
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preferred.
Figure 19. Flow capacities of 2-7/8 inch screens and slotted liners
Figure 20. Schematic and results of flow capacity tests of
cased-hole gravel packs
11.5.2
Cased Hole Gravel Packs
Results obtained from the model that simulated cased-hole packs are shown in Figure 20.
They demonstrate that well productivity is significantly reduced in this type of completion,
but by increasing the number and size of perforations, productivity can be significantly
increased. In comparison Figure 19, which reveals pressure drops of only a few psi, these
results show that a perforated gravel pack is productivity-limited by virtue of the flow
through the sand-or gravel-filled perforations.
11.5.3
Prepacking
It is apparent that the perforation tunnel is the most critical region in a cased-hole gravel
pack. Research has been conducted to determine the effects on well productivity and sand
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control of gravel size, different gravel/sand geometries, flow rate, and multiphase flow.
The model used here is shown in Figure 21.
Figure 21. Full scale gravel pack model and schematic
Gravel was placed around the screen and through the perforation of the model. A prepack
could also be simulated. Brazos River sand was primarily used for the formation sand since
it closely resembles the Miocene sands present in the Gulf Coast of Texas and Louisiana.
Flow test results with a uniform 5-darcy Brazos River sand with no prepack but with the
perforation filled with gravel (Figure 22) revealed a high pressure drop across the
perforation. The data also indicate that packing the perforation reduces the pressure drop at
low flow rates. The plugging observed at high flow rates was due to viscous forces causing
the formation sand to migrate into the entrance of the perforation. When a prepack was
used, however, the pressure drop across the perforation was substantially lower.
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Figure 22. Gravel pack productivity, prepacked, perforation only prepacked and
perforation filled with formation sand
11.5.4
Producing Rate
Subsequent testing in which no prepack was used has shown that such completions are
more rate sensitive than prepacked completions, and that permanent damage can result if
the critical rate is exceeded. This liability is demonstrated in Figure 23. Plugging or
damage occurred when the viscous forces were high enough to move the formation sand
into the perforation.
Figure 23. Permanent formation damage caused by
high flow rates and lack of prepacking
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Figure 24. Test results demonstrating the importance of prepacking in
Preventing perforation damage
On the other hand, as Figure 24 shows, cased-hole prepacked gravel packs are not as
severely affected by rate, from the standpoint of permanent damage, as when no prepack
was used. They are affected by turbulent or nondarcy flow effects, as this figure shows.
Here the apparent perforation-tunnel permeability decreases as the flow rate was increased.
The apparent loss in permeability was the result of turbulent flow effects. Note that when
the flow rate was decreased to the initial level, no permanent damage was evident. In fact,
a slight improvement was observed in this test; it has been noted in several others, as well.
Apparently the improvement was due to a slight cleaning action by the produced fluids,
which caused the permeability improvement.
11.5.5
Summary
Based on the data presented here, the following conclusions concerning gravel-packed
completions can be made :
•
The screen/slotted liner and gravel pack do not create a significant restriction to well
productivity unless they become plugged with formation sand.
•
For cased-hole gravel packs, maximizing the size and number of perforations increases
productivity.
•
Packing only the perforation may suffice for low-rate wells. This technique is rate
sensitive and should be avoided.
•
Turbulence is a major factor in decreasing the productivity in high-rate, cased-hole
gravel packs.
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SAND CONTROL
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GRAVEL PACK WELL PREPARATION
Attention to details when performing a gravel pack can mean the difference between
completion success and failure. Consequently a logical and well executed completion
procedure offers the best chance for a well to be placed on production in an undamaged
condition. To achieve this goal, attention should be given to the following items :
11.6.1
•
Cleaning the casing
•
Workover fluids
•
Underreaming
•
Perforating
•
Perforation washing
•
Perforation surging
•
Acidizing
Cleaning The Casing
Casing cleaning usually consists of performing bit and scraper runs to remove cement, rust
and other foreign material from inside the casing. It is important to prevent this material
from being mixed with the gravel and thereby reducing the pack permeability. In some
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cases the casing is even acidized to remove this material. Normally, weak 5-10%
hydrochloric acids are used for this purpose. Regardless of what technique is used,
obtaining the cleanest conditions possible will aid in achieving completion success.
11.6.2
Workover Fluids
Clear brines are the preferred workover fluids for gravel packing operations. Insoluble
materials should not be present. Gravel packing requires that the fluids be filtered at least
20 microns prior to use. Viscosity control is normally achieved by adding polymers such as
hydroxyethyl cellulose (HEC). However, viscosified fluids should normally contain a
viscosity breaker which will reduce the viscosity to about that of water several hours after
the completion has been conducted. This step allows the well to “clean up” rapidly rather
than having to produce the high viscosity fluid that has leaked-off into the formation.
Foams have received quite a bit of usage in situations where low reservoir pressure exists
and where lost returns cannot be tolerated. Their use requires special equipment and highly
trained personnel to properly mix and handle them.
11.6.3
Underreaming
Once the decision has been made to open-hole gravel pack a well, the other decisions to be
made relate to the casing point, total depth, and whether or not to underream.
Selecting the casing point is straightforward; it can usually be determined by running and
correlating well logs or by analyzing sample cuttings at the surface. If at all possible, the
casing point should always be selected so that the overlying shales are cased off. The
reason for this recommendation is that shales sometimes heave or slough to the point that
the completion is adversely affected by contamination from the shales. Consequently, if
shales can be cased off, they will create no problem.
In most open-hole completions underreaming is recommended. Underreamers, or hole
enlargers, operate by the application of hydraulic pressure to the device, which is attached
at the end of the drill string. This pressure forces arms out against the borehole as the drill
string is rotated, thus expanding the hole to a predetermined radius. When the hydraulic
pressure is released, the arms return to their original position, allowing the underreamer to
be removed from the well.
Where feasible, brines make excellent underreaming fluids. Because of their low viscosity
and high fluid loss, however, the capability of brine to clean and remove cuttings from the
hole are limited unless high fluid velocities can be achieved in the well’s annulus.
Additives to the underreaming fluid have consisted of calcium carbonate and lignosulfonate
for fluid loss control and potassium chloride to prevent clay swelling.
11.6.4
Perforating
Cased-hole gravel packs differ from open-hole gravel packs in that the well screen is run
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inside perforated casing. The primary difficulty with this type of completion is that it
reduces the well productivity of high rate wells. Sand-filled perforations are the chief
restriction to flow. Consequently, increasing the size of perforations, as Figure 25
illustrates, is recommended. In most gravel packed wells, a minimum of four shots per foot
of 0.5-in. diamter should be used. Greater shot density and diameter should be considered
if excessive casing damage can be avoided. And, it is important to remember that
perforating operations should always be performed with a clean fluid in the well.
Because perforations are the main limitation to flow, the selection of perforating equipment
is critical to completion success. The perforation charges selected should yield the largest
diameter and the deepest penetration possible. Diameter, however, is more critical to the
flow capacity of cased-hole gravel packs than is perforation length, as long as penetration
extends beyond the cement sheath. Consequently, the recommendation is to perforate with
guns providing the largest hole diameter as well as adequate length. In most cases the
cased-gun perforator yields the best results in comparison with expendable guns, although
the cost is greater and the rig time longer.
Now available are new 7-in. diameter casing guns that shoot an 0.7-in. hole with an average
penetration of about 18-in. These guns have been used quite successfully in gravel packs in
which large-diameter casing has been run. In BDO, the guns have frequently been run.
Shot densities average about 8 to 12 per foot.
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Figure 25. Pressure drop in gravel-packed perforation tunnels as a function
Of hole size and flow rate (after Saucier)
11.6.5
Perforation Washing
Well preparation procedures are further complicated by the fact that for maximum
productivity, the perforations should be filled with the gravel used in the completion. In
addition, the region outside the perforations should be prepacked with gravel. If the
perforations are plugged with the formation sand or other debris, filling them with gravel
during the gravel pack is difficult, if not impossible. Consequently, prior to the gravel pack
or prepacking operation, steps should be taken to ensure that the perforations are open and
free of plugging material.
Perforation washing is the preferred method of cleaning perforations. The term generally
refers to any one of several techniques in which a wash fluid can be pumped through
opposed swab cups. The washing takes place across the cups by injecting down the tubing
and taking returns through the casing-tubing annulus to remove formation sand and other
debris capable of plugging the perforations.
An illustration of a conventional circulation wash tool is shown in Figure 26. The tool
configuration in the figure is simply two opposed swab cups with a narrow space between
them. Wash fluid is injected between the cups. Returns are taken by forcing the fluid to
enter perforations between the cups and to flow behind the cement to other perforations
where the fluid may enter the casing-workstring annulus. The tool configuration can also
be reversed so that the cups are unopposed. In this case, wash fluid is injected into
perforations above or below the cups, and returns are taken through perforations between
the cups.
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Figure 26. Perforation wash tool schematic, conventional-circulation type
The primary advantage of the basic tool design shown in Figure 26 is its simplicity. One
disadvantage is that all fluid injected between the swab cups must be returned up the
annulus, which can cause the tools to stick. To avoid this problem, a slide valve is usually
located on top of the tool to permit reversing debris from the annulus.
Baker and Dowell supply disposable wash tools. Since in certain situations well control has
been a problem when wash tools are removed, pump-off subs have been installed to
separate the tool from the workstring. This separation is accomplished by dropping a ball
in the tubing and allowing it to seat in the pump-off sub. Pressure is then applied until the
retaining pins are sheared to separate from the tubing. Once this has been done, the tool is
pushed to the rat hole (below the perforations). The workstring can now be removed from
the well without the swabbing action that would occur if the wash tool were removed
rapidly from the well.
Procedures used for washing perforations tend to be arbitrary and dependent on the
particular situation being encountered. Normally, perforations are washed from the bottom
up with conventional wash tools. The flow rate during washing operations usually averages
about 2 bbl/min, but up to 5-8 bbl/min is beneficial if these rates are attainable. A fluid
volume of about 10 bbl/ft is normally recommended. The material commonly recovered in
perforation washing operations is formation sand and miscellaneous debris.
11.6.6
Perforation Surging
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Perforation surging is another way of cleaning perforations and removing plugging material
from them. The tool used is in itself no more than a cylindrical chamber that can be sealed
at the surface so that the air inside the chamber is at atmospheric pressure. The tool is run
to the desired depth and opened in the well to expose the perforations to atmospheric
pressure (see Figure 27). The pressure change thereby forces a limited volume of
perforation debris, mud, formation sand, and reservoir fluid from the perforations.
Figure 27. Schematic of a typical perforation surge tool
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Although the surge tool has been effective in opening perforations, there are several
disadvantages to its use, namely :
•
A trip of the tubing is required for each surge run.
•
The tool is not well suited for long perforated intervals.
•
There is a limited amount of flow through the perforation when the tool is opened.
Most of these disadvantages are not inherent in perforation washing tools. Consequently,
perforation washing is preferred to surging in most situations.
11.6.7
Acidizing
Acidizing can be used in several different ways to enhance gravel pack completion success.
Acid treatments can be performed either before or after the gravel pack.
In those instances where acidizing is performed before the gravel pack, the acid treatment is
run in the same manner that it would be run in a perforated well. Should acidizing be
considered necessary to completion success, it should be performed prior to gravel packing.
In the event that a post gravel pack acid treatment is considered, the reason is almost always
prompted by the well’s inability to produce at an acceptable rate. There is a high risk of
damaging the gravel pack with a post gravel pack acid treatment. Damage can result from
pumping the treatment at rates sufficiently high to fluidize the gravel pack. In this case well
productivity increase is usually temporary and may be achieved at the expense of sand
control.
In order to avoid this condition, post gravel pack acid jobs should be pumped at low rates.
They should not exceed 0.5 bbl/min for a well completed over 10 ft of interval and
perforated 8 shots/ft. In any event the acid pump rate should not exceed 2 bbl/min at a
surface pressure that will not exceed the fracture gradient.
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11.7
GRAVEL PLACEMENT - PREPACKING
11.7.1
Advantages
Cased and perforated well completions are usually less productive than are open-hole
completions. They are nevertheless widely used when the exclusion of interbedded water,
gas, or undersirable shale streaks is required. The productivity and lifetime of cased-hole
completions can be increased significantly by (1) creating an operating or cavity into the
formation beyond the perforation tunnel with properly sized gravel before placing a gravel
pack in the casing annulus. Cased-hole gravel packs, in which no attempt is made to
prepack the perforations, are not recommended for wells with high production rates,
because low-permeability formation sand can enter the perforation tunnel and restrict the
well’s productivity.
11.7.2
Transport Through Perforations
When particles are transported from the casing through the perforations during gravel
prepacking, inertial and gravity force cause particles in the sand slurry to separate from the
stream lines of the fluid entering the perforations. This separation causes greater
concentration of particle slurries with increasing distance from the perforated casing. This
process is further illustrated by the data in Figure 28. Here the particle concentration in
each perforation was sampled and compared with the injected concentration in a casing
with three perforations. The increase in concentration is more pronounced for the larger
gravel particles. Note that increasing the fluid viscosity from 1 to 10 cp leads to nearly
uniform distribution of particle concentration into the perforations. This uniformity is a
result of increased drag forces on the gravel caused by the more viscous fluid.
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A nearly uniform distribution of particles into the perforations is desirable because it
prevents buildup of high concentrations in the lower part of the casing. This is important
because, if gravel concentrations become too high opposite any of the perforations,
particles can bridge in the entrance of perforations. The result may well be incomplete
packing of the region immediately behind the casing.
It is recommended that the prepack gravel be pumped in a viscous slurry. The minimum
viscosity for 20/40 and 40/60 U.S. mesh gravel should be 100 and 30 cp, respectively.
Initial gravel concentration should be 2 to 4 lb/gal. However, concentration should be
increased to 8 to 10 lb/gal until a sand-out occurs. After the well has been cleaned out, the
prepacking operation can be repeated to ensure that all perforations are filled.
Figure 28. Uniform fluid flow through 3-inch casing
11.7.3
Bridging In Perforations
The maximum particle concentration transportable through perforations is shown by the
data in Figure 29. Bridging inside a perforation occurs even at the low gravel concentration
of 0.5 to 1 lb/gal (0.022 - 0.043 vol. fraction) if the perforation diameter is two to three
times the average particle diameter. However, when the perforation diameter is greater than
six times the diameter of the average particle, bridging does not occur even at gravel
concentrations of 30 lb/gal (0.58 vol. fraction).
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The ratio of perforation diameter to the average particle diameter at which bridging occurs
is not affected by the viscosity of the carrier fluid. The ratios are virtually the same
whether tap water or a 100-cp hydroxyethyl cellulose fluid is used. However, the size of
the particle node that forms in the casing around a bridged perforation increases with
increasing viscosity. If large enough particle nodes form on opposite sides of the casing, a
particle bridge can form, thus preventing particles from being transported downstream of
the bridged casing.
Figure 29. Bridging of particles in perforations
11.7.4
Wellbore Angle
Wellbore angle dramatically affects the transportation of gravel through the perforations.
When low-viscosity fluids are used to transport gravel, the result may be an incomplete
prepacking of the perforations in the upper part of the casing. When the gravel slurry enters
a non-vertical perforated casing, the gravel particles are distributed unevenly throughout the
cross section of the casing. Here the particles separate from the fluid and accumulate on the
bottom part of the casing. Here the particles separate from the fluid and accumulate on the
bottom part of the casing (see Figure 30). Gravel particles are then transported through the
perforations only on the lower side of the casing. They are not transported out from the
upper part of the casing, because the fluid exiting those perforations does not contain an
appreciable number of particles.
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Figure 30. Gravel prepacking in deviated wells. (A) Gravel particles transported
Out bottom perforations; (B) Upper perforations filled
Fluid transportation continues until all the perforations in the lower side of the casing are
filled with gravel. At this point, the gravel slurry fills the rathole up to the bottom
perforation. If the carrying fluid exerts sufficient drag forces on the gravel particles, the
gravel will then be transported into the upper perforations, starting at the bottom of the
wellbore and proceeding upward.
Low-viscosity fluids may not have sufficient drag force to carry the gravel slurry to the
perforations in the upper side of the casing. As injection continues, therefore, the gravel
fills the casing past some upper perforation until an equilibrium height is eventually
established. Above this equilibrium height the fluid has sufficient drag force, owing to the
increased velocity through the remaining perforations, to continue transporting the particles
into the upper perforations.
Any voids and perforation tunnels not filled with gravel can allow invasion of formation
sand. Or they may allow gravel in the wellbore to settle after the well is returned to
production, possibly leaving part of the screen uncovered with gravel.
Complete prepacking of the entire perforated zone is more likely if high-viscosity fluids are
used, since they exert greater drag forces on the gravel particles. The particles tend to
follow the trajectory of this fluid into the perforations more readily than if a low-viscosity
fluid is chosen.
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Fluid Viscosity And Flow Rate
The final number of particles transported through the perforations depends ultimately on
three factors : (1) presence of a void space outside the casing that can accept the particles
transported through the perforation; (2) size of the perforation relative to the particle size;
and (3) the transport efficiency of the carrier fluid.
The transport efficiency of particles - i.e., the fraction of particles transported through the
perforations - can be calculated if the critical trajectory of a particle just entering the bottom
perforation is known. The importance of this critical trajectory is illustrated in Figure 31.
All particles inside the envelope (or surface of revolution) generated by the trajectory will
enter the perforations, whereas all particles outside will sink into the rathole. The particle
transport efficiency can thus be defined as the ratio of the area inside the critical trajectory
to the total cross-sectional area of the casing.
Figure 31. Mathematical model used to determine prepacking efficiency
Figure 32 illustrates some theoretical results obtained for several gravel-fluid combinations
in a 6.2-in. ID casing with 100 perforations. These results demonstrate that significant
increases in particle transport efficiency can be achieved by increasing either the fluid
viscosity or the total fluid rate.
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Figure 32. Effect of flow rate on calculated transport efficiency
11.7.6
Recommendations
•
Wash the perforations.
•
Circulate the prepack slurry to the top of the perforations and squeeze.
•
The minimum fluid viscosity during placement should be at least 30 cp when 40/60
mesh gravel is pumped. A minimum of 100 cp is required when 20/40 mesh gravel is
pumped. By raising the viscosity to about 300 cp, gravel concentrations in excess of
10 lb/gal are possible without significant settling.
•
Do not exceed fracturing pressure during placement.
Figure 33 is a schematic of the prepack process.
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Figure 33. Schematic of the prepack process
11.8
GRAVEL PLACEMENT
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11.8.1
SAND CONTROL
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Choice Of Fluids
When gravel packing, the Engineer has a choice of using either low or high viscosity fluids.
Each system has its particular advantages and disadvantages. However, if performed
properly, either can result in an excellent completion. As a general guideline, low viscosity
fluids should be used to squeeze the gravel around the screen by taking no fluid returns to
the surface. Low viscosity gravel pack fluids are normally referred to as circulation-type
gravel placement fluids while the high viscosity fluids are commonly known as slurry pack
fluids.
Circulation packing involves pumping the gravel and the carrier fluid down the tubing, then
through a crossover into the screen-casing annulus. There the gravel settles to the bottom
of the interval while the fluid returns to the surface through the tail pipe and well’s annulus.
Slurry packing has been used as a gravel packing technique since the mid-1970s. The
major differentiation between slurry pack fluids and circulation-type fluids is the fluid
viscosity. Slurry pack fluids range in viscosity from about 20 cp up to as high as 1000 cp;
however, the viscosity is commonly 200-300 cp. Because of the high fluid viscosity, the
gravel-transport efficiency is improved and much higher higher gravel concentrations are
possible. Gravel concentrations of 15 lb/gal are common when slurries are used to gravel
pack. In contrast circulation-type gravel packs normally do not use gravel concentrations in
excess of 1-1/2 lb/gal because the low viscosity fluids (ordinary brine) do not have
sufficient transport capabilities to handle the higher concentration.
11.8.2
Slurry Packing
In slurry packing, the gravel is squeezed into place around the screen after being circulated
down the well’s tubing. Consequently, the carrier fluid is lost is to the formation rather
than being circulated back to the surface. This causes the slurry to dehydrate around the
screen to facilitate packing. Slurry pack downhole equipment commonly consists of the tail
pipe being packed off in the lower portion of the screen assembly. As shown in Figure 34,
this assembly also commonly consists of a bottom rather than a top telltale screen. The
purpose of the lower telltale screen is to insure that the gravel is packed from the bottom of
the screen section upwards.
Since the slurry pack completion equipment does not have an upper telltale screen and
because the gravel is squeezed into place, it is difficult to determine when and if sufficient
gravel is packed around the screen. The gravel volume is usually calculated based on the
theoretical volume plus about 0.5 sacks/ft outside the casing. In order to avoid placing an
insufficient amount of gravel, practice is to run a blank pipe section at least equal to the
length of screen section. Where conditions allow, the blank or reserve gravel volume may
be 2-3 times that of gravel volume around the screen.
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Figure 34. Slurry pack equipment
Some of the advantages and disadvantages of slurry packing are listed in the following :
Advantages
•
Lower fluid volume requirements
•
High gravel concentration may reduce mixing with formation sand
•
Prepack and gravel pack can be performed simultaneously
•
Usually requires less time to place gravel
•
Minimum returns taken through screen which minimizes potential screen damage from
erosion.
Disadvantages
•
No positive indication of gravel level around the screen when packed
•
Gravel volume for pack must be predetermined.
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•
Several joints of blank pipe are desirable for gravel reserve
•
Should be run with minimum rathole (sump packer is preferred)
•
Fluid break and settling required for a good pack
•
Probably not well suited for high angle wells greater than 45°
Probably the most attractive features of slurry packing is that it can be performed very
quickly as compared to circulation packing. One of its main advantages is that it can
simultaneously prepack as well as gravel pack the completion interval. This can save
thousands of dollars when high rig costs are involved. However, slurry packing has its
limitations. At this writing its use should be limited to completions intervals less than 75ft
and well deviations of less than 50 degrees. Further work is needed to define the precise
limits of gravel placement in deviated wellbores using this technique.
11.8.3
Circulation Packing
Circulation gravel packing involves the use of low viscosity carrier fluids and low gravel
concentrations. Unlike slurry pack fluids, the gravel settles very rapidly in the low
viscosity, circulation-type fluids. As shown in Figure 35, gravel placement with these
fluids employs slightly different gravel pack equipment. With this type of fluid placement,
upper telltale screens are used. Their purpose is to indicate when the gravel has reached
this location during gravel placement. A signal of this event is the rapid rise in pump
pressure when the gravel covers the telltale screen.
Gravel achieves its highest initial density when it is circulated in the wellbore with lowviscosity fluids, such as brines, and a tailpipe or stinger is used inside a slotted screen to
return the fluid to the surface. With this method, the gravel settling velocity is sufficiently
great that the material falls to the bottom of the wellbore. The pack then forms from the
bottom upward, creating a high-density mass.
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Figure 35. Circulation pack equipment
One might ask why high viscosity fluids are not used as an alternative for placing gravel in
the circulation mode. This practice is not recommended because the high viscosity fluids
will tend to drag the gravel into the screen and cause the pack to extend radially outward
rather than settling to the bottom of the screen section. The results in incomplete gravel
placement and premature cessation of pumping due to high pressures. However, once the
pumping is stopped, the gravel will settle so that the upper portion of the screen may not be
covered. In this event the gravel pack will probably be ineffective. As a result low
viscosity fluids are recommended when circulation packing operations are conducted.
To be performed properly circulation gravel packing should be conducted in two stages.
The first stage involves prepacking the perforations using high viscosity fluids while the
second stage is actually the gravel pack portion using the low viscosity fluid.
The advantages and disadvantages of circulation-type gravel placement are shown in the
following :
Advantages
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•
Positive indication of gravel level at job completion
•
No mixing of viscous fluids required
•
Low gravel concentrations
•
Probably better suited for high-angle holes - greater than 45°
•
Less crushing (pots normally used)
Disadvantages
•
Clean fluids are essential - especially when 40/60 mesh used
•
Long circulation time may erode screen
•
Can require a long time placement time
Requires a prepack prior to gravel pack for proper completion - this is critical in high rate
wells.
The single most important advantage in placing gravel in two stages is the greater
probability of completely filling both the void space behind the casing (including
perforation tunnels) and the annular space between the casing and the screen. During twostage gravel packing, the operator can measure how much gravel is placed behind the casing
(prepacking), and also how much gravel is placed in the casing annulus (gravel packing),
because the operations are performed separately.
11.8.4
Deviated Wells
The gravel packing of deviated wells with low-viscosity fluids is relatively effective if the
wellbore angle is less than 45°. Beyond 45°, incomplete gravel packing can occur if
precautions are not taken. During gravel placement in high-angle wellbores, a gravel dune
forms near the inlet of the wellbore, as shown in Figure 36.
The height of the gravel dune increases until fluid velocity in the open channel above the
dune is sufficiently high to transport gravel over the dune and deposit it further toward the
bottom of the wellbore. As the dune’s height becomes stabilized, and the dune continues to
descend the wellbore, the pressure drop of the gravel slurry over the stabilized bank
becomes sufficiently high to force the gravel-carrying fluid into the screen.
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Figure 36. Formation of gravel dune during gravel
packing of inclined wells
When fluid escapes from the open channel to the screen, fluid velocity in the open channel
decreases, the gravel is deposited, and the channel bridges off completely. Gravel can then
be deposited only upstream of the bridge, resulting in an incomplete gravel pack.
Figure 37 shows the effect of wellbore angle on gravel packing efficiency (percent of full
pack). In the tests cited, tap water and a 100-cp fluid were used to carry the gravel. The
effects of gravel concentration, fluid properties, flow rates, and resistance to fluid flow
inside the screen on circulation-type packing efficiency were evaluated. Packing efficiency
was observed to increase with:
•
Lower gravel concentration
•
Higher flow rates
•
Higher fluid density
•
Increasing resistance to fluid flow inside the screen
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Figure 37 Effect of wellbore angle on gravel packing efficiency
The most important variable in the gravel-packing of inclined wellbores with circulationtype techniques is the resistance to fluid flow in the tailpipe/screen annulus. During gravel
placement, a high flow resistance inside the tailpipe annulus prevents all the fluid from
escaping into the screen until the gravel is transported to the bottom of the wellbore.
A convenient way to increase the resistance to fluid flow inside the screen is either (1) to
increase the flow rate of the carrying fluid, or (2) to use a larger diameter tailpipe inside the
screen. Tests have shown that even horizontal wellbores can be efficiently gravel-packed
by following either of these two simple measures.
11.8.5
Wash Down
The wash-down method (Figure 38), is a very simple completion technique, but one that is
performed quite differently from the circulation techniques described earlier. As in all
cased-hole gravel pack operations, it is necessary to clean the wellbore, open the
perforations in some manner, and prepack the perforations. This sequence is then as
follows :
1.
Once the perforation pack is completed, gravel is left inside the casing at some
predetermined height.
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2.
The screen is run to the top of the gravel and conventional circulation begun through
the bottom of the screen. (Several devices are available that allow sufficient
circulation to fluidize the gravel).
3.
The screen is washed into place, circulation stopped, and gravel allowed to fall back
around the top of the blank liner section.
4.
The working string is released from the screen through the use of a back-off sub and is
picked up a few feet.
5.
Reverse circulation is initiated up the washpipe to ensure that the inside of the screen
is clean.
6.
When necessary, a second trip is made to put a packer device on top of the screen
assembly.
The major disadvantage in this method is the limitation on the length of screen that can be
successfully washed down. Stopping circulation to make an additional connection can
cause gravel to fall around the screen, thus preventing any further circulation or movement
of the screen. As a result, the maximum screen setting should be nor more than one joint of
tubing, or about 30 ft.
With this technique, either low-or high-viscosity fluids can be used. The only requirement
is that the gravel be sufficiently fluidized so that the screen can be washed into position.
11.8.6
Reverse Circulation
Figure 39 shows the reverse circulation method of gravel placement. It requires wellbore
preparation similar to that of the wash-down method, except that all gravel is washed from
the wellbore after the perforation prepack operation is complete. The screen is then run and
set in position and the sand/water slurry circulated in a reverse manner to deposit the gravel
around the outside of the screen. This method should be used in conjunction with lowviscosity fluids in order to avoid a premature gravel bridge caused by the slurry’s being
drawn into the screen rather than being allowed to fall to the bottom of the completion
interval.
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Figure 38. Wash-down method
11.8.7
Crossover
The crossover gravel pack technique, shown in Figure 40, consists of a workstring designed
to pump gravel slurry around the screen. With this equipment the slurry is crossed over
between the screen and the casing at the top of the screen section. Crossover gravel-pack
equipment can be used with either circulation or slurry pack placement.
This technique is preferred in those situations where its higher cost can be justified. This
form of gravel placement has several advantages over wash-down and reverse circulation
techniques.
•
Mud, rust, pipe dope, and scale will not be scoured from the casing by the gravel
slurry. Thus there is less risk of depositing debris in the perforations or on the screen.
•
The volume of the workstring is smaller than that of the workstring casing annulus. At
equal pumping rates, the higher fluid velocity inside the drill pipe reduces placement
time as well as the possibility of bridging or gravel segregation.
•
Control of both fluid and gravel location within the workstring is more precise.
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Figure 39. Reverse circulation method
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Figure 40. Crossover gravel pack method
Crossover-type gravel placement can be accomplished with either a cup-type crossover tool
or with a crossover-type gravel-pack packer. With the cup-type, the crossover tool is part of
the workstring. The tool consists of a dual swab-cup assembly and crossover device. Upon
completion of the gravel pack. therefore, a second trip is required to set a packer or seal on
top of the screen assembly.
The crossover can also be included as part of the gravel-pack packer. A port collar and a
crossover assembly are incorporated into the service seal unit. Additional equipment - such
as wash pipe inside the screen and a circulating valve above the packer - may also be added.
See Figure 40.
As its major functions, the crossover assembly must provide :
•
Means for setting and testing the packer
•
Flow path for the sand slurry to be pumped down the workstring and out through the
ports in the port collar below the packer
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•
Capability either to circulate fluids through the screen and out the workstring casing
annulus or to squeeze the fluids into the formation
•
Means to release the crossover tool assembly from the packer
•
Capability to reverse-circulate and clean out the screen and workstring after being
released from the packer
A crossover gravel-pack packer can be used with either circulation or slurry packs. When
slurry packs are performed, a bottom rather than a top telltale should be used. Also, the
tailpipe should be packed off on bottom so that returns are circulated through the lower
telltale.
Before selecting a supplier of such tools and services, an operator should consider the
following features, which have a bearing on the success of gravel pack placement :
11.8.8
•
Wellbore fluids should not be allowed to flow through the screen while tripping in the
hole, since screen plugging can easily occur (especially in old wells).
•
The ports on the crossover-tool outlet and port collar should overlap and should be
large. This features is especially important in high sand-concentration slurries and
when large gravel sizes are used.
•
Some means must be provided to close or pack-off across the port collar after
completion of the pack.
•
A positive indication of the tool position, such as squeeze (bullhead) or circulation,
should be available.
•
The squeeze position should be maintained without the necessity of excessive tubing
weight.
•
The tool should have an emergency release mechanism in case the primary releasing
device cannot be actuated.
Filtration
The first important consideration in gravel packing a well is the use of clean workover
fluids. Yet workover fluids vary in availability and quality. In some areas produced
formation fluids may be available; but even these fluids contain fines and possibly other byproducts of the production system, such as scale and hydrocarbons. The use of produced
fluids does offer one major advantage, however. Their chemical compatibility with the
formation being packed is usually greater than that of surface waters.
Where possible, fluids should be filtered to at least 20µ. Special caution must be exercised
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in filtering very dirty fluids, as the filtering devices tend to plug rapidly in the 20µ fliter
stage. When extremely clean fluids are required, filtering with devices down to 2µ may be
necessary.
Figure 41 is a schematic of the internal operation of a typical filtering system. The device
shown is a cartridge-type filter and is available from most service companies in the gravel
pack industry. This system is very effective, its filters are easily changed, and the cost is
reasonable.
In addition to the cartridge or sock-type filters, in certain areas several other filtering
systems are available, such as graded sand beds and diatomaceous-earth filter systems. The
major disadvantage of the graded bed filter is the extensive process required to exchange or
clean the filter media, which generally necessitates the presence of more than one cell on
location.
Figure 42 shows typical piping for a single-stage filtering unit. This unit may be used
where clean produced fluids are available. The filter cells are individually manifolded so
that one cell is used at a time. As the pressure differential across the system increases,
which will be noted on the inlet pressure gauge, that filter cell can be shut off and the
alternate cell opened for flow. The plugged filter cell can then be drained and the filtering
devices changed.
Figure 41. Typical filtering system
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Figure 42. Typical piping for single-stage filtering unit
11.8.9
Sand Injection
Figure 43 is a schematic of a typical downstream sand injector. Productivity testing
performed by Shell on its large-scale radial model has indicated that dirty gravel-pack
gravel can be a major source of productivity impairment. Because of the potential problems
of productivity decline and initial productivity impairment as a result of “crushed” sand, it
is recommended that sand be injected downstream of the high-pressure injection pumps
with a system comparable to the one illustrated.
Figure 43. Downstream sand injector
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This type injector also offers adjustable concentration control. It generally contains a choke
just upstream of the sand injection point and a by-pass control valve to drive the sand from
the pot. Opening the control valve will increase the flow rate through the sand, thereby
increasing the sand-fluid ratio. Similarly, closure of the valve will decrease the ratio. Such
a system will generally supply from 1/2 lb to as much as 1-1/2 lb of sand per gallon of fluid
pumped, which is sufficient for most ranges of desired sand-fluid concentration when lowviscosity fluids such as water are used.
Blenders are normally used for mixing and handling high-gravel-concentration slurries.
They are available in a variety of shapes, sizes, and methods of operation. Blenders are no
more tanks in which the slurry is mixed and agitated (either mechanically or hydraulically)
before being pumped into the well.
11.8.10
Summary
Whether a well is gravel packed by either slurry or circulation fluids or whether wash
down, reverse circulation, or crossover placement techniques are selected, packing
technique is in many cases not the important issue. What is important is that the gravel is
placed properly around the screen and, in the case of cased-hole gravel packs, that the
perforations are prepacked. Several processes are capable of achieving excellent gravel
packed completions, but as has been mentioned earlier each has its particular advantages
and disadvantages. The choice of placement technique depends solely on the particular
well, reservoir, rig, and operating conditions.
11.9
PLASTIC CONSOLIDATION PRINCIPLES
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Plastic consolidation is a method of stopping sand production by artificially bonding the
formation sand grains together into a consolidated mass. Liquid chemicals are pumped
through the perforations and into the pore spaces of the formation sand. These chemicals
subsequently solidify to form the bonding material that holds the sand in place.
To successfully control sand, several important objectives must be reached in the
consolidation process. These objectives exist on both a macroscopic and microscopic scale.
A schematic representation of consolidation objectives is presented in Figure 44.
Figure 44. Plastic consolidation objectives
11.9.1
Macroscopic Objectives
The primary macroscopic, or large-scale, objective in a consolidation treatment is to bond
together the formation sand adjacent to every perforation. Because the treatment is
designed to function on formation sand, a zone several feet in radius around the wellbore
can be consolidated. A picture of a laboratory wellbore model after consolidation is shown
in Figure 45.
In Figure 45 a 1-in. pipe with two 0.5-in. perforations spaced one foot apart was surrounded
with formation-type sand. Consolidating fluid was pumped through the pipe and
perforations into the sand. It can be seen that the consolidation extends a full 360° around
the well; the consolidated radius is about one foot. It is important to recognize that the
consolidating fluid spreads around the entire wellbore circumference and also flows
vertically to enclose the well completely.
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Figure 45. Plastic distribution around a wellbore
The figure shows two distinct lobes consolidated sand, which seem to meet at a point half
way between the perforations. Had there been a plugged perforation between the two
perforations. Had there been a plugged perforation between the two open ones, it would
have been treated by consolidating fluids pumped through the open perforations. It is
important to treat every perforation, even though some of them may not permit fluid
injection. The necessity of covering every perforation cannot be overemphasized. The fact
that a perforation does not accept injected fluid during consolidation is no guarantee that it
will not permit fluid (and sand) flow during production.
The question often arises about how large a consolidated radius is necessary for a
successful treatment. Covering every perforation (to obtain high initial success) with a
sufficient amount of resin to allow for some deterioration (to achieve long lifetime) requires
an average consolidated radius of 2-3 ft.
11.9.2
Microscopic Objectives
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The three microscopic objectives, identified in Figure 1, are to : (1) coat the entire sand
grain with resin, (2) concentrate the resin at the contact points to bond the grains together,
and (3) leave the bulk of the pore space open for flow. A photograph from the scanning
electron microscope (Figure 46) illustrates the achievement of these objectives in an actual
consolidation of formation sand.
Coating the grains with resin indicates that the resin is wetting the sand surface and will
therefore form a good adhesive bond. Concentration of the wetting phase (resin) at the
grain contact points is a natural occurrence in all porous media when two phases are
present.
Before the resin hardens, the pore space is partially displaced with a non-reactive fluid.
Ordinarily, oil is used for this displacement, but water may also be used. Approximately
35% of the pore volume is filled with resin leaving the remainder open for flow.
Figure 46. Plastic coating on sand grains
11.9.3
Sand Coating Methods
Although there are many commercial consolidation processes, there are still only three
basic means of achieving the desired resin coating. These are described in the following
sections without specifically referring to the type of resin used.
Individual variations of these methods are described in the discussion of commercial
processes. The name given to each coating method refers, first, to the mechanism of mixing
the hardening agent with resin and, second, to the means of opening the pore space for fluid
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flow.
The Internally Catalyzed Phase Separation method employs the direct mixing of the resin
and hardening agent (catalyst) prior to contacting the sans; hence the description internally
catalyzed. Phase separation refers to the precipitation of the polymerized plastic from the
initial resin solution. At the end of the polymerization, there are two phases in the pore
space : polymerized plastic, which coats the sand, and solvent from the original resin
solution, which fills the bulk of the pore space and provides permeability.
A step-by-step representation of the pore space fluid saturations for an internally catalyzed
phase-separation plastic is shown in Figure 47A. Initially, the pore space is filled with
brine and oil, which are miscibly displaced with a mutual solvent preflush. The resin
solution then displaces the preflush to fill the pore space completely. The resin solution
then displaces the preflush to fill the pore space completely. At this point, fluid injection
ceases and the cure period begins. As the resin polymerizes, it becomes insoluble in the
carrier solvent and precipitates (phase separates) onto the sand grains. This leaves the
carrier solvent in the center of the pore space and a hardened resin film on the sand.
All the resin ingredients used in the Internally Catalyzed Overflush technique - including
the catalyst (or hardener) - are blended prior to injection. Permeability is achieved by
immiscible displacement of the excess resin by an inert fluid (usually an oil). A schematic
representation of this process is shown in Figure 47B. The oil and brine are displaced by
preflush, which in turn is displaced by resin. At this point, an oil is used to immiscibly
displace excess resin and to establish permeability. The resin is left as a coating on the
sand grains which then hardens without phase separating to cement the grains together.
The overflush process may be likened to the flushing of a water-saturated sand to residual
water with oil. With the consolidation process, a “residual resin” saturation is established
by the overflushing procedure. Typical “residual resin” saturations are 30-55% of the pore
volume.
Unlike the catalysts of the techniques described above, the catalyst in the In Situ Catalyzed
Overflush procedure is not included in the resin solution. Instead. it is dissolved in the
overflushing fluid and diffuses into the resin phase once the pore space has been
overflushed. A schematic representation of an in situ catalyzed overflush resin is given in
Figure 47C.
Separating the resin and catalyst during plastic placement overcomes the risks of limited
pumping time associated with internally catalyzed processes. In situ catalyzed resins retain
their original fluid state indefinitely, unless contacted with an overflush fluid containing
catalyst.
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Figure 47. Sand coating methods
11.10
PLASTIC CONSOLIDATION CHEMICALS
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Many chemicals are used during the plastic consolidation process. These chemicals can be
grouped into five functional categories : preflushes, resins/catalysts, diluents, coupling
agents and overflush fluids. The function of each chemical category as well as specific
chemical constituents are discussed in this section.
11.10.1
Preflush
A preflush is injected ahead of the consolidation resin to change either the fluid saturation
or the coating (wettability) of the formation sand. Surface preparation is vitally important
in any “gluing” operation. To be effective, there must be sufficient resin coating (wetting)
of the sand grains to provide adhesive strength. Achieving the desired “resin wet”
condition requires proper preparation of the formation prior to introducing the resin.
Probably the earliest uses of preflushes involved changing the fluid saturation near the
wellbore by injection of either Water or Oil. While these treatments cannot alter the
wetting of the sand surface, they can affect the resin saturation in the pore space.
By adding a Surfactant to an oil or water preflush, the sand wettability as well as the fluid
saturations can be changed. Fluid saturations other than residual water or residual oil can
be achieved with the aid of surfactants.
The term Mutual Solvent refers to a fluid that can simultaneously dissolve substatial
amounts of both brine and oil. This type of preflush is therefore useful in removing both
water and oil from the pore space. Two distinct types of phase behavior are exhibited by
these mutual solvents; they can be preferentially water-miscible or preferentially oilmiscible.
If a preferentially water-miscible mutual solvent is added to equal volumes of brine and
crude, the volume of the aqueous phase will increase but the oil phase will show little
change in volume. As shown in Figure 48A, adding additional solvent eventually dissolves
both the oil and aqueous phase.
The type of mutual solvency illustrated in this example would be very effective in
mobilizing water in the formation pore space.
Adding a preferentially oil miscible mutual solvent to equal amounts of oil and brine will
primarily enlarge the oil phase, as shown in Figure 48B. Once again, if enough solvent is
added, both the aqueous and oil phases are totally dissolved. This type of phase behavior
would be effective in removing oil from a porous medium.
Laboratory experience has shown that most resins perform better if water is removed from
the pore space. This is not surprising since, in most sands, water is the wetting phase and
therefore the one that the resin must displace to achieve wetting. For this reason, a
preferentially water-miscible mutual solvent is often used as a preflush.
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Figure 48. Mutual solvent preflushes
11.10.2
Resin
Although there are many commercial plastic consolidation processes available, they are all
based on the polymerization reactions of either an epoxy, a furan, or a phenolic resin. The
basic resin reaction chemistry and physical properties are summarized in Figure 49 and
Table II.
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Figure 49. Consolidation chemistry
Table II
Summary of resin Properties
Resin
Cured By
Reaction
By-Products
Epoxy
Furan
Phenolic
Amines
Strong Acid
Strong Base
None
H2O
H2O
Softening
Temperature
Wet Sands in
Presence of
Water
Chemical
Resistance
250°F
300°F
300°F
No
Yes
Yes
Excellent
Excellent
Good
Epoxy resins are well known for their adhesive and surface-coating capabilities. The
hardening mechanism depends on the reaction of apoxide rings attached to each end of the
resin molecule. Two hardening reactions commonly encountered in sand consolidation
processes are illustrated in Figure 49A. The first reaction is the joining of two epoxide
rings which is promoted by a tertiary amine catalyst that does not take part in the reaction
itself. The second reaction is between an epoxide ring and a primary amine-curing agent.
Because there are no reaction by-products and there is little shrinkage during cure, epoxy
coatings are smooth, uniform, and highly resistant to chemical attack. Above 250°F,
ordinary epoxy formulations become soft and yield when placed under stress. This upper
temperature limit does not place any significant restrictions on usage for sand control, since
unconsolidated sands are rarely above 250°F.
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Furan consolidation systems are based on the polymerization of furfuryl alcohol with an
acid catalyst. The furfuryl alcohol molecules join together by forming a methylene bridge
(-CH2-) and releasing water as a by-product. This process is shown in Figure 49B. The
catalyst is usually a strong acid such as trichloroacetic acid (oil soluble) or hydrochloric
acid (water-soluble). Ordinarily, a mixture of furfuryl alcohol and furan resin is used. The
furan resin is prepared by partially polymerizing some furfuryl alcohol and then removing
the produced water. Furan polymerization reactions occur at a very rapid rate. Some
spontaneous polymerization occurs even at room temperature, which can limit the shelf life
of some resin formulations.
Phenolic resins are of great historical importance in consolidation because some of the
earliest processes, developed during the 1940’s, involved the use of a phenolic resin. The
resin is formed by the reaction between a phenol and an aldehyde. As seen in Figure 49C,
the result is a methylene bridge (-CH2-) linking two phenol molecules. Because there are
many sites on each phenol molecule to which the aldehyde may attach, the final structure is
always highly cross-linked.
11.10.3
Diluent
Almost every resin suitable for sand consolidation is too viscous to be pumped in the
undiluted state. Starting with undiluted resins having a viscosity of 100-10,000 cp, diluent
levels of 10-50% by weight are commonly required to each the desired 10-20 cp diluted
viscosity. Two types of diluents, reactive and non-reactive, are available for resin dilution.
A reactive diluent is able to polymerize with the resin while a non-reactive diluent is not.
Furfuryl alcohol is the most widely used Reactive diluent. It is used to dilute both furan
and phenolic resins. Furfuryl alcohol has two reactive sites; it therefore does not cause
chain termination during polymerization.
A Nonreactive diluent is an inert solvent that does not react chemically during the curing
process. Because it does not react, solvent left in the cured plastic serves only to weaken it.
It is of paramount importance that a non-reactive diluent be removed from the resin after
the resin solution has been injected into the formation.
11.10.4
Coupling Agent
Coupling agents in the plastic consolidation process serve the specific purpose of
chemically bonding resin to the silica surface. These chemical bonds are much stronger
than the usual attractive forces between the resin and the sand. The coupling-agent
molecule is chosen so that one end can react with the silica while the other end reacts with
the resin during polymerization. Dow-Corning Z-6020 is a typical organo-silane-coupling
agent. The organic end group (amine in this case) reacts with the resin whereas the silane
end group reacts with the sand.
H2NCH2CH2NH(CH2)3Si(OCH3)3
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reacts with resin
11.10.5
reacts with silica
Overflush
The fluid used to overflush a plastic consolidation resin performs three important functions.
First, it must open a fluid pathway through the resin, filling the pore space so that the
consolidated sand will be permeable. Second, it usually must carry the catalyst into the
pore spaces to harden the resin coating. Third, the overflushing fluid is sometimes required
to extract the diluent from the resin.
To displace the excess resin efficiently from the pore space, the overflush fluid should be
more viscous than the resin. A favorable mobility (viscosity) ratio is necessary to prevent
the fluid from fingering or channeling through the resin.
By far the most common overflush fluid is diesel. Price and availability considerations
make diesel an attractive candidate. However, diesel viscosity is only 3 to 5 cp as opposed
to 10 to 20 cp for the typical resin. This difference makes the mobility ratio unfavorable for
displacing resin with diesel.
Several systems employ more highly refined oils than diesel. These include motor oil
brightstock, white oil, and process oil. The overflush-resin mobility ratio can be controlled
with these more viscous oil grades.
Recently, water brine has been used as an overflush fluid. It can compete economically
with diesel and offers a decreased pollution risk from a spill. The mobility ratio problem is
compounded by using a water overflush, since its viscosity is even less than diesel.
11.11
WELL PREPARATION FOR PLASTIC CONSOLIDATION
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11.11.1
SAND CONTROL
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Objective
Proper preparation of the well prior to consolidation can have a significant impact on job
success. One goal of the well preparation sequence is to ensure that all resin is displaced
from the wellbore tubulars and equipment into the formation. Serious production problems
can arise if even a portion of the resin hardens inside the wellbore. The second important
goal of the well preparation procedure is to achieve a uniform distribution of resin around
the well.
11.11.2
Wellbore Equipment
Sound wellbore equipment is absolutely essential if sand consolidation treatments are to be
successful. Any conditions allowing consolidation chemicals to enter areas of the wellbore
other than the interval to be treated will not only result in an unsuccessful job, but also can
cause the hole to be junked.
An unrepaired leak in the wellbore tubular goods is the surest way to glue a workstring in
the well. Damage that allows fluid to leak from the workstring/tubing annulus will permit
fluids to exit the wellbore at some point other than the perforations. Resin (and
subsequently catalyst) will flow up the annulus, causing the bottom portion of the
workstring to be glued into the well. The current record is 3000 ft of workstring glued into
a well.
A wide variety of conditions can cause leaks. Obviously, conditions such as split casing,
split tubing, or a failed squeeze cement treatment are major sources. If the well is on gas
lift, the valves are usually replaced with dummies to prevent damage. Each gas-lift mandrel
is therefore a potential leak site. At the very least, the gas-lift annulus should be killed and
a gauge used to monitor its pressure during the treatment. Preferably, the tubing string
should be pulled and the gauge-lift mandrels removed.
The surface-controlled subsurface safety valve is another potential leak source. This too
must be pulled and replaced by a dummy to prevent resin from entering the control lines.
The pressure of any annular space associated with the safety valve should be monitored to
detect leaks.
If a well has sanded up, it is frequently convenient to test the integrity of the wellbore
tubulars at this time. Since no fluid can be injected through the perforations in the sandedup condition, pressure testing of the casing or tubing can be easily performed.
11.11.3
Perforating
The relationship between perforating practices and sand control success has been the topic
of many studies during the past few years. The results of these studies can be used to
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define clearly the goals of a perforating technique used in conjunction with plastic
consolidation.
Every study of plastic consolidation has conclusively demonstrated that increasing the shot
density also increases the chances for sand control. The results of such a study are shown
in Figure 50. Long-term consolidation success is clearly improved by 20% when 4 shots/ft
are used as opposed to 1 or 2 shots/ft. Not every well can be perforated at 4 shots/ft
because of mechanical considerations, especially multiple tubingless wells. The goal of a
perforating operation should be to achieve the maximum number of perforations possible
under the circumstances. Shot densities in excess of 4 shots/ft are not generally used with
plastic consolidation systems. The perforations are left open after consolidation so they are
not a restriction to fluid production.
Figure 50. Effect of perforation density on consolidation success
Perforation size is not nearly as important in plastic consolidation as is the number of holes.
Ideally, however, one would like as big a hole as possible to increase the flow area and to
reduce the local drawdown stress. In gravel packing, large perforations are required
because they are always filled with gravel. In consolidation, the perforation tunnels are left
open, so their diameter is of less importance.
11.11.4
Prepacking
Prepacking a formation prior to consolidation involves filling the formation’s void spaces
with sand. Void spaces in the near-wellbore region can lead to resin channeling with a
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resulting uneven plastic distribution. If void spaces become large enough, segregation of
resin and catalyst will occur. The less dense catalyst oil will float over the resin, leaving a
significant portion of the resin uncured.
The correlation between prepacking and consolidation success has been firmly established
by several field lifetime studies. The results of the most recent study are shown in Figure
51. To eliminate as many variables as possible, the scope of this particular study was
limited to intervals perforated with 2 shots/ft and consolidated with base catalyzed phenolic
(BCP) resin. All were “old intervals” that had produced sand prior to treatment. The
results clearly show that a significant benefit accrues when “old intervals” are prepacked
prior to consolidation.
Figure 51. Effect of prepacking on consolidation success
Sand control success for “old intervals” after prepacking is seen in Figure 51 to be
equivalent to success in “new intervals” that have not produced sand.
11.11.5
The procedure used for prepacking the formation is uncomplicated and easily performed.
Sand is suspended at low concentration in a low-viscosity carrier fluid and pumped into the
formation until a sand-out occurs. Ordinarily, the well is reversed clean and the procedure
repeated until a second sand-out occurs.
A 40/60 U.S. mesh sand is used for most sandpacking operations. This sand size is easily
suspended in the carrier fluid and is readily consolidated by resin. Larger sand grains do
not have a sufficient number of contact points to be strongly consolidated. The 40/60 sand
is at least 10 times more permeable than any formation sand; therefore, no production
impairment will result from prepacking.
Injectivity Testing
The ultimate goal of any injectivity testing procedure is to ensure that the consolidation
chemicals may all be pumped without exceeding the fracture pressure of the formation.
The injectivity response must be determined in advance because, once pumped,
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consolidation chemicals cannot be recovered and reused.
Exceeding the formation fracture pressure is not permissible on a matrix-type treatment. In
such treatments (of which consolidation is an example), the goal is to have fluid reach every
pore space in the near-wellbore region. Exceeding the fracture pressure allows a channel to
develop, leading the treating fluids away from the area immediately surrounding the
perforations. No consolidation treatment will succeed if the fracture pressure is exceeded.
Most consolidation fluids are four to five times more viscous than diesel. A pressure
increase of 300-500 psi recorded during injectivity testing with diesel will therefore lead to
a 1200-2500 psi increase at the formation face when consolidation fluids are pumped at the
same rate. Under most circumstances, this would be sufficient injectivity to allow pumping
of the consolidation chemicals. However, a check should always be made to see that the
static pressure plus the injection pressure during consolidation does not exceed the fracture
pressure.
11.11.6
Acidizing
Acidizing is a method for removing clay, scale, and other particulate material from the
formation sand. Plugging of perforations by particles suspended in the workover fluid or by
particles loosened from the walls of the casing or tubing is a common occurrence during
workover operations. The particles impair injectivity (and subsequent productivity) and
must be removed prior to consolidation. The presence of these damaging solids can usually
be identified during an injectivity test.
In addition to improving injectivity, mud acid benefits a consolidation treatment by
cleaning the sand grain surfaces. Fresh silica is exposed by removing clay, feldspar and
other minerals from the pore space. Maximum bond strength is developed between the
consolidation resin and a freshly etched silica surface. Thus, even when no injectivity
problem exists, an acid treatment is frequently recommended to improve the strength of the
consolidated sand.
11.11.7
Neutralizer
An acid treatment must be followed by a neutralizing solution to remove residual acidity
from the sand. Residual acidity can be responsible for poor consolidation in one of two
ways. When an acid-catalyzed consolidation plastic is used, residual acidity will cause
premature hardening of the resin with subsequent loss in permeability. On the other hand,
when a base-catalyzed plastic is used, residual acid reacts with the catalyst and prevents
hardening of the resin.
Neutralizer capacity can be provided by using either ammonium bicarbonate (NH4HCO3) or
ammonium hydroxide (NH4OH). These bases may be used interchangeably to provide a
neutralization capacity of 0.25 mole/liter.
The volume of neutralizer must be sufficiently large to displace residual acid from the pore
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space. To be effective, a minimum volume of 100 gal/ft of neutralizer is needed.
Ordinarily, however, a volume of 150 gal/ft is recommended to ensure effectiveness. The
cost of the neutralizer is typically low and is therefore not a major treatment expense item.
Two typical neutralizer formulas are shown below :
I
H2O
NH4Cl
NH4HCO3
II
150 gal
50 lb
25 lb
11.12
PLASTIC PLACEMENT
11.12.1
Objective
H2O
NH4Cl
NH4OH
150 gal
50 lb
12.5 lb
The procedure used to place (or inject) consolidation fluids has a large impact on job
success. Consolidation involves a chemical reaction between several of the injected fluids.
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For the results of this reaction to be predictable, the reactants must arrive at the formation
face in an uncontaminated condition.
Several unique injection procedures have been developed to deal with the placement
problem. Although each is different, all of them were designed with three common
objectives :
11.12.2
•
To control fluid flow in the wellbore
•
To segregate reactive components
•
To protect wellbore tubular goods against excessive plastic buildup
Rathole Fluid
Because of its density (9.0 - 9.2 lb/gal), resin tends to sink into the rathole below the
perforations, displacing the original contents of the rathole (usually brine) into the
formation. This displacement process has two detrimental consequences. First, the rathole
is left full of resin which can become partially catalyzed during consolidation. The second
and possibly more detrimental consequence of rathole fluid movement is the contamination
of the formation sand with brine displaced from the rathole by resin. Simultaneous
injection of resin and brine causes brine to wet some of the sand surfaces, and in so doing
prevents wetting and adhesion by the resin. The remedy for this problem is to fill the
rathole with a fluid that is more dense than the resin.
A dense brine (9.5 - 9.8 lb/gal) can be circulated into the rathole with a workstring. Dense
bring has been used successfully many times in the field, but its use is somewhat time
consuming and is easily omitted from the procedure. Dense brine is satisfactory in noncritical applications, but is not sufficiently reliable for use with epoxy resins that are
sensitive to the presence of water.
In the case of an epoxy consolidation process, introduction of water from the rathole during
resin injection reduces the strength of the final consolidation. In this situation, the use of
the more reliable o-nitrotoluene rathole filling method is essential. O-nitrotoluene, a dense
(9.66 lb/gal) organic liquid, is pumped to the perforated interval. As illustrated in Figure
52, a portion of the o-nitrotoluene sinks into the rathole due to gravitational forces, while
the excess is injected out the perforations into the formation. Brine displaced from the
rathole is similarly injected into the formation. To minimize the amount of o-nitrotoluene
needed, the rathole depth should be limited to 25 ft. Based on current safety information, onitrotoluene should not be used with organic acid chloride catalysts (such as Halliburton’s
Sanfix).
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Figure 52. Rathole filling with 0-nitrotoluene
11.12.3
Annulus Fluid
Fluid movement must be prevented in the annulus between the workstring and casing for
the region above the perforations. If the annulus will not stand full of fluid, then injection
down the workstring into the formation will cause the fluid level in the annulus to rise.
This condition can allow some of the resin to flow up the annulus after leaving the
workstring. Any catalyst that flows up into the annulus will harden the resin on the
workstring. This invariable glues several joints of pipe into the well.
To prevent this situation, the annulus should be filled with diesel. When the bottomhole
pressure is low that the annulus will not stand full of diesel, a packer should be run on a
workstring. A Halliburton “RTSS” packer (or equivalent) is commonly used for this
application. Customarily, about 30 ft of tailpipe is used below the packer. With either a
diesel-filled annulus or a packer, fluid movement in the annulus will be eliminated.
11.12.4
Concentric Workstring
Perhaps the most versatile means of placing consolidation fluids is with a concentric
workstring. One advantage is the small volume of fluid needed to fill the workstring. This
allows precise injection of the small chemical volumes usually encountered in consolidation
treatments. Figure 53 shows the equipment layout for a typical 1-inch workstring
consolidation treatment.
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Figure 53. Concentric workstring placement technique
After completing the well preparation, it is time to begin the actual consolidation treatment.
If the rathole is to be filled with dense brine, it should be done now. Next, the workstring is
pulled to the top of the perforations and the well reversed full of diesel. An injectivity test
should be run to decide whether an acid treatment will be required. If needed, the well
should be acidized and neutralized. Finally, the workstring should be pressure tested before
pumping the consolidation chemicals.
The workstring should be positioned 10-15 ft above the perforated interval. Most
consolidation procedures are straightforward, requiring only that the chemicals be pumped
in the correct sequence. Tanks with the proper amount of each chemical ingredient should
be on location and clearly identified. The pump suction hose is moved sequentially to each
tank.
Workstring movement during the treatment is very limited. Once all the resin has exited the
bottom of the workstring, and spacer fluid begins to enter the perforations, the workstring is
usually picked up 5 ft. This ensures that the end of the workstring is not in contact with the
resin that has coated the casing wall. After all the consolidating fluids have been injected,
the workstring is picked up an additional 20-30 ft. At no time after beginning to pump the
consolidation resin should the workstring be lowered.
Because it is the most effective method for completely segregating consolidation fluids, the
concentric workstring method is probably the best injection technique. For this reason, it
should be used any time that a rig is on location.
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SAND CONTROL
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Conventional Workstring
The placement procedure for conventional and concentric workstrings is essentially
identical. However, the large internal volume of a conventional workstring - approximately
30 bbl or 1200 gal - necessitates a slight change in job approach. The preflush, resin,
spacer and a portion of the catalyst oil are pumped into the workstring before the preflush
ever reaches the formation sand. Because all the chemicals are in the tubing
simultaneously, a greater opportunity exists for adjacent chemicals to mix.
This mixing is primarily dependent on time spent in the tubing and not on flow rate. For
this reason, it is recommended that a pumping rate of 0.5 - 1.0 bpm be used to minimize the
time required to pump the chemicals to bottom. Because of fluid mixing, small chemical
volumes cannot be successfully pumped through a conventional workstring. For most
applications, the volume required to consolidate a 6 ft interval is the minimum amount of
fluid to pump. A shorter interval can be treated, but the chemical volume for a 6 ft interval
should be used.
11.12.6
Bullhead
The term bullheading refers to pumping the consolidation chemicals directly down the
permanent production tubing or casing. The wells can be either tubingless or conventional
completions with 2-3/8, 2-7/8, or 3-1/2 in. tubing. The chemicals are pumped through the
Christmas tree, since there is no workstring or rig. The same volume consideration as in
conventional workstrings also applies to bullhead placement.
The equipment requirements for the bullhead placement method are shown in Figure 54.
Since it is not possible to circulate the rathole full of brine without a rig, o-nitrotoluene
injection is the preferred rathole-filling technique. In conventional completions, the
annulus between the tailpipe below the packer and the casing must be filled with diesel.
Since there is no rig to circulate this fluid into place, it can be positioned only by pumping
the diesel to bottom and letting gravity direct it to the proper location.
Bullheading is the preferred technique when a rig is not needed on location. Such instances
include initial completions and recompletions in which the zone is to be perforated and then
consolidated. If, however, a well is sanded up and requires a rig for cleanout, a workstring
placement method would be preferred.
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Figure 54. Bullhead placement technique
11.12.7
Restoring Production
After consolidation, most wells will return to the productivity observed prior to treatment,
and some wells will produce at a higher rate. Significant productivity loss due to
consolidation can be treated by either HCL acidizing or reperforating. However, if the
problem is caused by poor reservoir quality, then little can be done to improve the
production rate.
If productivity loss is severe, acidizing with HCL after the consolidation resin cures has
been found to be an effective method for improving well productivity. Hydrochloric acid
will not harm the consolidation strength once the resin has cured.
If attempts to restore productivity with HCL have been unsuccessful, reperforation of the
consolidated interval can be attempted. The exact same interval that was consolidated must
be reperforated to avoid reaching sand that was not treated by resin injection. This
requirement calls for good depth control and close attention by service company personnel.
11.13
COMMERCIAL PLASTIC CONSOLIDATION SYSTEMS
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Through the years, many plastic consolidation processes have been developed and
commercialized. Claims abound regarding the advantages and virtues of each chemical
system. The discussion presented in the following pages will attempt to establish the
important criteria for evaluating consolidation processes, and then to measure the
performance of each commercial system using these criteria. Treatment design information
will be presented for a few systems offered commercially.
11.13.1
Evaluation Criteria
Selecting the best plastic consolidation process requires a comparison of strength,
permeability, and aging characteristics. Other considerations such as cost and method of
application are also usually important.
Uniaxial compressive strength is used as a laboratory test to measure how well the sand
grains are cemented together. Consolidation processes that yield compressive strengths of
1000-2000 psi are capable of withstanding drawdown forces of 2000-3000 psi. This is
considerably above the drawdown pressure drop encountered in most wells. Thus, any
plastic system capable of developing 1000-2000 psi in initial compressive strength is fully
capable of controlling sand initially.
Evaluating the permeability retention of a consolidation process involves measuring the
absolute (single phase) permeability of the sand before and after treatment. This
permeability ratio (after consolidation/before consolidation) is defined as the permeability
retention. Permeability retentions on the order of 70-80% are the best that can be achieved
without sacrificing compressive strength.
Almost any commercial consolidation process generating 1000-2000 psi in initial
compressive strength would be acceptable if the properties did not change with time.
Unfortunately, all consolidation plastics show deterioration when exposed to reservoir
fluids for an extended period of time. When the strength drops below that necessary to
withstand the drawdown forces, the plastic fails and the well begins to produce sand.
Knowledge of the plastic’s aging characteristics is an important criterion in evaluating a
consolidation process.
11.13.2
Data Sources
Most of the useful commercial consolidation processes have been tested in the laboratory.
The current laboratory testing procedure employs a 4-ft linear model. A drawing of the test
equipment is shown in Figure 55. In addition to data on strength and permeability of the
consolidation process, this apparatus yields information about how deeply resin can
penetrate into the sand.
Another important consolidation testing apparatus, shown in Figure 56, is the large 5-ft
radial model. In this model, the sandpack is 1-ft thick, covers one-fifth of a circle (70° arc),
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and extends up to 5-ft from the wellbore. Tests conducted in this model give information
about the size and properties of the consolidated sand mass under radial flow conditions.
Actual field results are the most valuable of the data used to evaluate a sand consolidation
process. Because the conditions vary so widely between wells, however, a statistical
approach must be used to evaluate job success. To be valid, this approach requires that a
large number of treatments be performed. It is obviously impractical to generate field
lifetime results for every consolidation process. But it is possible to correlate the initial
laboratory properties of the systems for which there are field results.
Figure 55. Linear model schematic
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Figure 56. Radial model schematic
11.13.3
Evaluation Summary
A broad overview of the number and types of commercial plastic consolidation systems
may be obtained by examining Table III. The systems are listed by resin type along with
the trade name and developer. Next, there appears information on the method of catalysis
and the manner in which permeability is obtained. The values for resin viscosity are
measured at room temperature and may be used as a guide for comparing the ease with
which the resins can be pumped.
Table III
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Commercial Plastic Consolidation Systems Evaluated
Resin
Epoxy
Furan
PhenolicFuran
Trade Name
Developer
Catalysis
Obtain
Permeability
Resin
Viscosity
(cp@70°°F)
Initial
Strength *
(psi)
Permeability
Retention *
Placement
Technique
Field
Experience
Epoxy II+
Exxon
In Situ
Overflush
16
6000
60%
Bullhead
Good
EPR Epoxy
Eposand 112
Eposand 9
Chevron
Epoxy
Santrol
Exxon
Shell
Shell
Chevron
In Situ
Internal
Internal
In Situ
Overflush
Overflush
Phase sep
Overflush
80
15
10
100+
6000
5800
3500
4500
60%
53%
70%
65%
1-inch
Bullhead
Bullhead
1-inch
Good
Fair
None
None
BJ Hughes
Internal
Overflush
15
-
-
Bullhead
None
Sanfix +
Enriched
Sanfix
Hydrofix +
Halliburton
Halliburton
In Situ
In Situ
Overflush
Overflush
15
26
3500
2000
55%
50%
Bullhead
Bullhead
Good
None
Halliburton
In Situ
Overflush
22
4200
27%
Bullhead
Good
Sandbond V
In Situ
Overflush
35
5100
21%
Bullhead
Fair
In Situ
Overflush
35
-
-
Bullhead
Fair
K200
Compl.Svcs
.
Compl.Svcs
.
Dowell
In Situ
Overflush
35
2800
60%
Bullhead
Limited
BCP+
K86-87
K90
Exxon
Dowell
Dowell
Internal
Internal
Internal
Phase sep
Overflush
Overflush
10
22
16
1800
1000
4000
65%
60%
60%
1-inch
Bullhead
Bullhead
Good
None
None
Sandbond VI+
Phenolic
* 48-inch linear core test on mud-acidized Brazos River sand
+ systems used widely by Exxon
The next two columns show data on the initial compressive strength and permeability
retention of each system. Under placement technique, when the term bullhead appears, it
implies that placement may be made with any of the methods. When the term 1-inch
appears, it means that only a concentric workstring should be used to place resin. Finally,
operator’s field experience with each system is listed. Systems listed as having limited
experience have had fewer than 10 jobs performed and evaluated.
Based on the data presented in Table III, it appears that epoxy resins consistently provide
the highest compressive strengths while maintaining good permeability retention. Furan
and phenolic-furan resins are nearly equal in performance and as a class provide the next
best compressive strength. Finally, phenolic resins provide the least compressive strength,
although their strength are above or equal to the 1000 psi minimum recommended
compressive strength.
11.13.4
Epoxy II
The Epoxy II process was developed by Exxon to have a low viscosity (15 cp) thus
allowing considerable flexibility in the placement procedure. A job design is given in
Table IV that can be used with either the concentric workstring or bullhead placement
technique.
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As with all epoxy resins, water must be excluded from the formation during plastic
placement. O-Nitrotoluene has been included in the job procedure to displace brine from
the rathole, which thereby ensures that the resin will not become contaminated with water.
The 300 gal listed on the job design is sufficient to fill a 25-ft rathole depth.
The preflush is composed of Exxon Chemical’s Corexit 8626, a brine-miscible mutual
solvent. A viscosifier (PVP) and a coupling agent (Z-6020) have been included in the
preflush solution. The resin is a mixture of an epoxy resin and two diluents.
Although the actual formation temperature after pumping the consolidation fluids is not
needed for the job design, the possibility of excessive formation cooling must still be kept
in mind. The system is designed for a 20-40°F cooling by the injected fluids. For this
reason, pumping rates should be 1/4-3/8 bpm in 1-in. workstrings and 1/2 bpm in
production size tubing.
Radial model test results for Epoxy II are shown in Figure 57. The consolidated radius was
measured to be 32 inches from the wellbore. A series of cores were taken from the
consolidated mass at increasing radial distances. These cores were analyzed for porosity,
resin content, permeability and compressive strength. The average compressive strength
was 6500 psi and the composite permeability retention was 77%.
Table IV
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Epoxy II Job Design*
Fluid
Ingredients
Volume
Standard acid/Mutual
solvent treatment
Comments
Recommended for increasing
consolidation effectiveness.
Neutralizer
Water
NH4Cl
NH4HCO3
150 gal
50 lb
25 lb
150 gal/ft
Use only if acid treatment was
performed. Can substitute 12.5 lb
NH4OH for NH4HCO3.
Wellbore conditioner
o-Nitrotoluene
300 gal
300 gal
Limit rathole depth to 25 ft. oNitrotoluene is available from DuPont.
Preflush
Corexit 8626
PVP (Type K-90)
Z-6020
100 gal
4.0 lb
0.5 gal
100 gal/ft
PVP is available from GAF. Z-6020
coupling agent is sold by DOwCorning. Corexit 8626 is a product of
Exxon Chemical.
Resin
Epoxy II resin
55 gal
55 gal/ft
Epoxy II will be mixed at the service
company yard.
Spacer oil
Mentor 28
Flexon 766
20 gal
10 gal
30 gal/ft
Wiper balls are not required with this
low viscosity formulation.
Catalyst oil
Mentor 28
Flexon 766
DMP-30
167 gal
83 gal
7.5 gal
257 gal/ft
Mentor 28 and Flexon 766 are Exxon
USA products. DMP-30 is available
from Rohm and Haas and epoxy resin
suppliers.
Diesel
Diesel
100 gal
100 gal/ft
Displacement
Diesel
Tubing volume
After displacement, allow curing time
of 12 hr.
* Temperature Range : 140-200°F static BHT
Placement Technique : Bullhead or concentric workstring
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Figure 57. Epoxy II radial model results
11.13.5
Sanfix
Halliburton’s Sanfix was one of the first furan-based consolidation systems. A job design
for Sanfix is shown in Table V. The resin is in situ catalyzed and requires overflushing to
develop permeability. The primary ingredient is a partially polymerized furfuryl alcohol
resin diluted with unpolymerized furfuryl alcohol.
It is recommended that a mud acid treatment precede the consolidation. As with any
consolidation treatment, neutrlization of the residual acid is essential prior to injection of
resin. In the case of an acid-catalyzed resin, residual acid can cause premature hardening.
Preflushing ahead of Sanfix resin is best accomplished with plain diesel. In the laboratory,
mutual solvents did not benefit the strength of Sanfix consolidations. Following the
preflush are resin and spacer fluid (without surfactant). Finally, there is the catalyst oil,
which is diesel containing just 0.8% of the catalyst (Sanfix C2).
Ease of application in the field has always been an attractive feature of the Sanfix process.
Because furan resin will wet sand in the presence of water, special procedures to exclude
water are not necessary. The Sanfix resin is routinely placed with either a workstring or
bullhead technique. Because of the rapid resin cure, pumping rates, formation cooling, and
other placement variables do not affect the cure of the resin.
11.13.6
Field Results
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Through the years, many studies of plastic consolidation field results have been performed.
Schroeder and Tucker summarized 20 years’ experience in the Grande Isle Block 16 field
through 1968, and analyzed sand control methods in terms of both initial success and
longevity. The report of Carr analyzes plastic consolidation results between January 1970
and May 1974. Powell compared and analyzed sand consolidation and gravel packs
performed on offshore formations between January 1970 and June 1975.
During 1970-76 the two consolidation systems used most often were BCP (483 Jobs) and
Halliburton’s Sanfix (156 Jobs). The success curves calculated according to standard
success curve methods are shown in Figure 59. The results are expressed as sand control
success versus cumulative fluid production (oil and water). To cause a decrease in job
success, a well must start producing sand. Wells removed from production due to reservoir
depletion or mechanical failure do not directly affect the success curves.
The initial success rate at zero production was 80-90%. Success slowly declined as the first
400-500 kbbl were produced, and then held steady for the next 500 kbbl. The average longterm success for all systems was about 50%.
Figure 59. Plastic consolidation field results 1970-76
Since 1976 several new plastic systems have become available. A survey of USA
Operators showed that six different systems were being used during 1978-1982. These
systems and their frequency of use are shown in Figure 60. Halliburton’s Sanfix was the
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most frequently used system with 30% usage. Epoxy II (22%), BCP (17%), and Sandbond
VI (15%) were also used extensively. The aqueous catalyzed systems Hydrofix and
Sandbond V were used only to a limited extent. The bar labeled “Other” in Figure 60
represents systems that were used only once or twice.
Figure 60. Plastic consolidation systems used 1978-82
11.14
RESIN-COATED SAND
Controlling sand with a resin-coated sand pack is based on principles derived from both
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gravel packing and consolidation.
11.14.1
Objective
Like a gravel pack. a resin-coated sand pack is sized to hold back the formation sand;
however, a resin coating, rather than a screen, holds the pack sand in position. The pack
sand is pumped into the void spaces outside the casing as well as into the perforation
tunnels. The pack sand is sized according to standard gravel packing techniques to retain
the formation sand.
The resin coating is applied to the pack sand at the surface before pumping. After pumping,
this resin hardens to bond the sand grains together. Once bonded in position, the pack sand
will then retain the loose formation sand. No screen or liner is needed to keep the pack
sand in position. A schematic is illustrated in Figure 61.
Figure 61. Resin-coated sand pack
11.14.2
Sand Coating Methods
Two methods are available for initially coating sand with resin. In one case, the uncured
resin forms a liquid coating on the sand, while a second technique produces a solid coating
of uncured resin.
To produce a liquid resin coating, sand is first mixed with the carrier fluid to form a slurry.
A silane coupling agent can be added at this time to promote wetting and adhesion by the
resin. Finally, the liquid resin is added to form a coating on the sand.
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Because some of the resin diluent is extracted by the carrier fluid, the resin coating on the
sand becomes very viscous. Increased viscosity helps prevent resin removal during the
placement operation.
Liquid resin systems employ chemicals similar to conventional plastic consolidation
processes. Epoxy resins internally catalyzed with amines are in widespread use. Because
they react very rapidly, liquid furan resin coatings are usually in situ catalyzed by acids.
Solid resin coatings may be applied to sand in two ways. A solid resin can be melted,
mixed with the sand, and allowed to cool. Alternatively, the solid resin can be dissolved in
a solvent, mixed with the sand, and then the solvent evaporated. Both of these methods
require specialized processing equipment; hence, the resin is applied at a factory before
shipment to the well site.
Solid-resin coated sand is dry, free flowing and capable of being bagged and handled as
ordinary sand. The resin softens somewhat on exposure to water or diesel, so that when
immersed in liquid and compressed, the grains will adhere to one another. Elevated
temperatures (> 140°F) cause the resin to cure into a hard plastic that binds the sand into a
hard porous matrix.
11.14.3
Placement Procedures
Although each individual resin-coated sand process has recommended mixing and pumping
procedure, most techniques employ the same placement fundamentals. Initially, the pack
sand is sized on the basis of the formation sand sieve analysis. This procedure usually
results in the selection of 20/40 or 40/60 U.S. mesh sand.
The amount of slurry to be mixed depends on the length of the perforated interval.
Generally, one or two sacks of sand per foot of perforated interval will be needed. In
addition, sufficient sand must be available to fill the rathole and a portion of the casing
above the perforations.
Once mixed, the slurry is injected into the well through a conventional workstring. A
bullhead technique cannot be used, since excess sand must be removed from the well prior
to production. To minimize the mixing of slurry with other fluids in the casing, the end of
the workstring is positioned 40-60 ft above the perforations. The preflush chemicals (if
any) are pumped into the well followed by the slurry. The slurry pumping rate is kept low
to avoid fracturing the formation.
Slurry pumping continues until a “sand-out” occurs. At this point, there are two possible
procedures. Internally catalyzed systems are usually allowed to cure in the “sand-out”
condition. The sand in the casing is later removed with a mill. In situ catalyzed systems
may be reversed out of the wellbore and the sandpacking procedure repeated. After the
final washout, a catalyst solution is injected to harden the resin.
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To overcome the problems associated with uneven sand distribution, system formulators
have incorporated extra resin to consolidate some of the formation sand along with the pack
sand. The extra resin may be added to the initial resin-sand slurry, or it may be pumped as
a separate step after the pack sand is in place. If resin in excess of the amount needed to
coat the pack sand is incorporated into the initial slurry, resin leak-off from the slurry to the
formation sand will occur. This procedure will increase the radius of the consolidation
around the well, leading (one hopes) to an improved lifetime.
11.14.4
Commercial Systems
Table VI is a compilation of the significant features of current commercial resin-coated
sand. They are listed according to resin type along with the trade name and developer.
Next appears information on the method of catalysis and whether additional resin can be
used to consolidate some of the formation sand. The strength of the resin coating on 20/40
U.S. mesh sand is reported in the next column.
Resin-coated sand packs are routinely evaluated on the same basis as a sand consolidation
resin. Initial strength and permeability retention of the sand are determined. Unfortunately,
these tests represent the status of the resin-coated sand before injection into the formation.
There are no data available to evaluate the sand pack after placement.
Table VI
Commercial Resin-Coated Sand Systems
Resin
Trade Name
Developer
Catalysis
Additional
Resin
Stage
Strength
on 20/40
(psi)
Well
Cleanout
Field
Experience
Epoxy
Sandlock IV
Dowell
Internal
No
2500
Drill
Limited
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Sandlock V
Aqua-Epon
Hydrocon-E
Comp-Perm
Dowell
Shell
Halliburton
Completion
Service
Internal
Internal
Internal
Internal
No
No
No
No
1000
-
Drill
Drill
Drill
Drill
Limited
None
None
None
San-Stop
BJ Hughes
Internal
No
-
Drill
Limited
Furan
(Liquid)
Conpac
Conpac II-H
Hydrocon
Halliburton
Halliburton
Halliburton
In Situ
Internal
In Situ
Yes
No
Yes
2500
2500
2500
Wash
Wash or Drill
Wash
Limited
None
Limited
Phenolic
(Solid)
Super Sand
Baker Bond
Ac Frac CR
Santrol
Baker
Acme
Internal
Internal
Internal
No
No
No
2500
-
Wash or Drill
Wash or Drill
Wash or Drill
Limited
None
None
Because the sand is resin-coated under controlled conditions at the surface, there is a wider
choice of chemical ingredients than in a conventional consolidation process. For this
reason, a high-strength resin may be formulated with little difficulty. However, because
there are fewer grain-to-grain contact points with 20/40 U.S. mesh sand than with formation
sand, the consolidated strength of the 20/40 resin-coated sand is lower than comparable
sand consolidation processes. The initial strength of most commercial resin-coated sand is
well above the 1000-2000 psi compressive strength needed to prevent sand production.
The permeability of either 20/40 or 40/60 U.S. mesh sand is so much higher than typical
formation sand that no productivity impairment should occur. However, if there is
sufficient mixing between the resin-coated and formation sands during or after placement,
well productivity will be affected. Data to evaluate the permeability after placement are not
available for the various commercial resin-coated sands.
11.14.5
Field Results
Field experience with resin-coated sand has been fairly limited. Over the past 20 years only
two systems, Conpac and Super Sand, have been evaluated on more than 10 wells.
During the late 1960’s, a series of 26 jobs were done in the USA with Halliburton’s Conpac
I system. The results, however, were disappointing from a lifetime standpoint. A similar
study of Conpac in USA’s Harvey District revealed a success rate of only 39%.
A total of 35 jobs have been performed and evaluated with Super Sand. Job experience has
been good with 32 of the 35 jobs judged to be successful. The most successful applications
has been by Oil Company G in a shallow-steam flood. After placement, the Super Sand is
heated to above 250°F with steam. This high cure temperature promotes good resin
strength, and job success has been excellent. The number of actual applications have been
too few to draw a firm conclusion about the merits of the process.
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11.15
SAND CONTROL
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SELECTING A SAND CONTROL METHOD
Once the decision has been made to perform a sand control treatment on a well, the
question of which method to use still remains. Generally the choice must be made from
among plastic consolidation, resin-coated sand pack, or gravel pack. This decision is made
on the basis of wellbore and completion requirements, as well as economics. The three
sand control options are illustrated in Figure 62.
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Figure 62. Sand control techniques
11.15.1
Plastic Consolidation
The objective of a plastic consolidation technique is to treat the formation in the immediate
vicinity of the wellbore with a material that will bond the sand grains together at their
points of contact. This is accomplished by injecting liquid chemicals through the
perforations and into the formation. These chemicals subsequently harden to form the
bonding material (usually a plastic). For these treatments to be effective, two requirements
must be met. First, the formation must be treated (consolidated) outside all perforations.
Second, the consolidated sand mass must remain permeable to well fluids. As a sand
control method, consolidation offers many advantages. First, future workovers are
simplified because no mechanical equipment is left in the wellbore. An expensive fishing
job is thus avoided in case of a sand control failure. Second, because all of the formation
material is cemented together for several feet surrounding the wellbore, the productivity
decline associated with the migration of fine particles toward the wellbore is absent.
Third, on wells that have not sanded up, consolidation can be performed without a rig. This
can be of special benefit in initial completions and recompletions.
Offsetting these benefits are the two primary disadvantages of a consolidation technique:
cost and coverage. The cost of a treatment is currently $ 2500-4000 per foot of perforated
interval. At this price, the cost of consolidating a long interval (50 ft) becomes
prohibitively expensive. For shorter intervals (10 ft or less), however, the technique is
competitive with other sand-control methods. The problems associated with coverage arise
from the injection of insufficient resin into low-permeability zones of highly stratified
reservoirs. Because stratification is generally more pronounced in longer intervals,
consolidation success has been lower for perforated intervals longer than 15 ft.
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SAND CONTROL
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Resin-Coated Sand
Like consolidation, the resin-coated sand technique relies on bonding sand grains together
to control sand. Instead of bonding formation sand, however, only a special pack-sand,
placed inside and immediately surrounding the perforations, is consolidated. The pack sand
(usually 40/60 or 20/40 U.S. mesh) is coated with a resin at the surface and then pumped
into the well as a slurry. This slurry is then squeezed through the perforations to fill a
region behind the casing. After hardening, this consolidated pack sand will prevent the
formation sand from entering the wellbore. Excess resin-coated sand is removed from
inside the casing either by drilling or washing.
The primary advantage offered by this technique is reduced cost. Because of the limited
amount of sand that is actually consolidated, the volume of resin needed is only 1-2 gallons
per foot of perforated interval. A resin-coated sand treatment can be done for one-fourth to
one-half the cost of a conventional consolidation treatment, making it economically
attractive in longer intervals. Because PCSB’s experience with resin-coated sand has been
very limited, it is difficult to evaluate this type of treatment fully.
The one potential disadvantage to resin-coated sand may be a short lifetime. To be
effective, a sand control method must stop sand production from every perforation. In the
case of resin-coated sand, this means forcing a significant amount of sand through every
perforation. The coverage problems appear to be even more severe than with a
consolidation treatment. Even with poor coverage, the initial job success may be high
because of the resin-coated sand packed into perforation tunnels. But because of the high
state of stress imposed on sand in or near a perforation, the job lifetime may be very short.
Whether this disadvantageous aspect actually materializes can only be determined by
monitoring future job success.
11.15.3
Gravel Packing
Perhaps the most widely used method of preventing formation sand from being produced is
to physically restrain its entry into the wellbore flow stream. This is the mechanism of sand
control used in gravel packing.
Because of its versatility and low initial cost, gravel packing has been used widely to
control sand. Since the screen is a mechanical device, the size of its openings and its length
may be chosen to control many different sand sizes over any perforated interval length.
Gravel packing interval lengths of 20 to 200 ft is common and treatments covering 500 ft or
more of interval have been done.
Although gravel packing offers an economical method of controlling sand, there are several
disadvantages to consider. First, whereas initial installation is economical, a remedial
treatment to replace a failed screen may involve an expensive fishing job. Second, in
overpressured reservoirs that cannot be controlled with a calcium chloride brine, the use of
a special gravel-packing fluid is required. In these cases, the cost of the workover fluid
could be large in comparison to the screen and gravel costs, thereby changing the
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economics. Third, productivity impairment caused by filling the perforation tunnels with
sand and/or invasion of the gravel pack by formation fines is an important consideration.
This problem is especially severe in small casing where a 1-in. OD screen must be used.
11.15.4
Conventional Completions
Initial sand-control success in a conventional completion generally runs 90% or better,
whereas the long-term success is 50% or better. Wells included in this category have 5-1/2
or 7-in. casing (or larger) with 2-7/8-in tubing (or larger). They may be completed either
open hole or cased hole.
Figure 63 shows the success of three sand control methods : open-hole gravel packing,
cased-hole gravel packing, and plastic consolidation. These data represents experience
during the period 1970-1975. In this figure, success refers to the permeability of a well
achieving a certain cumulative productive provided that there are sufficient reserves.
obviously, not every cased-hole gravel pack in the study reached 800,000 bbl of fluid
(sufficient reserves), only 25% had failed and 75% were still controlling sand.
The implications of Figure 63 are fairly clear; open-hole gravel packing is the most
successful of the sand control techniques. Unfortunately, only a few wells typically meet
the long-life productivity and minimum-recompletion requirements necessary for successful
open-hole production.
Frequently, however, a choice must be made between a cased-hole gravel pack or a plastic
consolidation. Both of these methods have a initial success rate, with most of the failures
occurring early in the production life of the wells. In the long run, gravel packing turns out
to be more successful than plastic consolidation in conventional completions.
Figure 63. Sand control success in conventional completions
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SAND CONTROL
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Tubingless Completions
With respect to multiple tubingless completions, the success data reported by various
Operators on plastic consolidation and cased-hole gravel packs are shown in Figure 64.
The percentage success is definitely lower in tubingless completions than in conventional
completions, especially for cased-hole gravel packs. No tubingless wells were completed
open hole.
There are several reasons why gravel packing success is reduced in tubingless completions.
First, the size of screen that can be placed inside 2-7/8 in. or 3-1/2 in. tubing is 1 to 1-1/4 in.
in diameter. The slot area of such a screen is small and therefore easily plugged by even a
small amount of fine material from the formation. Second, there is less than one inch of
gravel separating the screen from the perforations even if the screen is perfectly centralized.
This greatly increases the chances that formation sand will reach the screen. A sandcontrol failure is the typical result, since the screens are not designed to bridge formation
sand.
Third, tubingless wells are ordinarily perforated at 2 shots/ft instead of 4 to 8 shots/ft for a
conventional completion. Filling this reduced perforations area with sand can dramatically
reduce well productivity. In fact, many of the wells produced no fluid at all after gravel
packing.
Figure 64. Sand control success in tubingless completions
11.15.6
Well Deviation
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In gravel packing deviated wells, there is the basic problem of completely filling the
annulus between the casing and screen with gravel. For wells inclined more than 45° with
the vertical, as little as 20-30% of the annulus may be filled with gravel. Recently, special
tools and placement techniques designed to overcome this problem have been developed.
There is no indication from either field or laboratory results that well deviation significantly
affects plastic consolidation results. However, no success study has specifically isolated
well deviation angle as a parameter.
11.15.6
Interval Length
Economic considerations often require that long intervals be gravel packed. However, with
interval lengths less than 20 ft, economic decisions must also include success and
productivity considerations. Previously presented sand-control success curves did not
differentiate between long and short interval lengths. In fact, the gravel-packing data were
collected primarily on wells with long production intervals, whereas the consolidation data
were almost exclusively from short zones. Long intervals have the advantage in a lifetime
study concerned only with cumulative production, because the total flow rates are usually
higher than in short intervals. At the same time, the specific production rate, bbl/day/ft, of
a long interval is typically less than of a short one.
To eliminate any distortion is results that might be related differing interval lengths, sandcontrol success comparisons have been made for intervals of similar length. The success
rate for gravel packing and consolidation in intervals of less than 12 ft is shown in Figure
65. Gravel-packing success is about 10% lower for this range than it is when all lengths are
assessed. On the other hand, consolidation results do not differ when intervals of all
lengths are evaluated because very few treatments have been done when lengths exceeded
12 ft.
Conventional gravel packing still has the highest success rate in the control of formation
sand, followed by plastic consolidation, and finally, by tubingless gravel packing.
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Figure 65. Sand control success in intervals less than 12 ft
11.15.8
Sand Quality
Sand quality refers to the nonsilica content and grain-size distribution of the sand. In
general, formation sands are composed of sand and shale. Sand is mostly quartz (SiO2).
Shales contain various proportions of clay minerals (illite, montmorillonite, kaolinite), as
well as silt, carbonate, and other nonclay materials. Silt is a very fine-grained material that
is predominantly quartz, but it may include feldspar, calcite, and other minerals.
A good quality sand has a narrow grain size distribution and a low nonsilica content (i.e., 515%). The permeability of such sand will generally be high - one darcy or greater. A poor
quality sand, on the other hand, generally has a wide particle-size distribution, an
appreciable fraction of which will pass a No. 400 U.S. mesh screen. The nonsilica content
of these sands can be as high as 50%, whereas the permeability may be under 100
millidarcies.
There are many sources of data on sand quality. Direct evidence includes rubber-sleeve
cores, sidewall cores, and the completion log constructed by the geologist from cuttings as
the well is drilled. Indirect evidence of formation strength can be obtained from the drilling
time log, the caliper log, and a recent combination (sonic density) logging tool called the
mechanical properties log. Clay content/shaliness can be estimated with increasing
precision from some single logs, dual log cross-plots, and multiple tool computed logs.
In general, as sand quality deteriorates, the success of all sand control techniques also
declines. Sand consolidating materials exhibit poorer wetting and adhesion when nonsilica
material is present. This can lead to a low-strength consolidation that is incapable of
withstanding the stresses of production. Gravel packs are usually too coarse to successfully
bridge off the very fine formation particles. These particles soon invade the pack and either
plug or erode the screen.
As the sand quality deteriorates, sand consolidation success tends to decline more rapidly
than does gravel packing. Hence, gravel packing tends to be the more prevalent technique
in poor quality sands.
11.15.9
Reservoir Conditions
As a rule, reservoir temperature does not play an important role in the selection of a sandcontrol technique. With few exceptions, all sand-control techniques (consolidation, resincoated sand, gravel packing) may be applied to reservoirs with static bottom-hole
temperature between 120° and 200°F. This temperature range probably encompasses 95%
of all sand-producing wells. Being a mechanical technique, gravel packing is applicable at
temperatures both above and below 120-200°F, but many consolidation and resin-coated
sand systems are not.
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Like reservoir temperature, the reservoir pressure is not usually an important parameter to
consider. Workover fluids are commonly available to control formation gradients from
0.30-0.60 psi/ft, but in certain abnormally pressured reservoirs, special completion fluids
costing up to $ 200/bbl may be required.
The type of fluid (oil, gas, or water) produced from the reservoir should be considered
during technique selection. Erosion of mechanical equipment by fine particles entrained in
a high-velocity gas stream may be severe. The problem is even worse when the gas is in
turbulent flow, which it may well be (depending on rate) as it moves through the gravel
pack and screen. A recent analysis of several failed screens from offshore gas completion
reveals screen erosion as a primary failure mode.
11.16
WELL BEAN-UP PROCEDURE
The objective of a bean-up policy is to reach well potential within the shortest period of
time without jeopardising ultimate well integrity and productivity.
During sand control workshops, bean-up procedures were found to vary greatly between
operators and were not always clearly justified. some operators have however established
that rapid bean-up times are detrimental to the long term performance of their wells e.g:
Shell
BSP
Bean-up time resulting in impairment
Acceptable bean-up time
1 day
2 weeks
5 days
3 months
One impairment mechanism during bean-up is thought to be migration of fines in the
reservoir. In formations susceptible to this type of damage, restricted production rates at
the bean-up phase may keep the concentration of moving fines low and hence prevent
blockage of pore throats. Also by gradually increasing the drawdown, movable fines
beyond this radius cannot be mobilised and are therefore no cause for worry. It should be
noted that the subject of fines migration is somewhat controversial and that no specific
guidelines to prevent impairment can be given. Core flow tests could be considered as a
means of assessing critical flowrates required for fines migration.
Restricted initial production rates may also allow a stable gravel/sand interface to build-up
with minimal invasion of sand into the gravel pack. This effect is however difficult to
quantify.
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Bean-up policies should be developed for each field and for their specific reservoirs. Beanup times will vary according to reservoir permeability, clay content, etc. Operators who
have not experienced impairment during bean-up should consider conducting trials at faster
bean-up rates.
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CHAPTER 12
FORMATION DAMAGE
TABLE OF CONTENTS
12.1
INTRODUCTION ……………….…...……………....………….….….…..….…
3
Chapter Goals ……………………………………………………….
Poor Productivity …………………………………………………...
Formation Damage …………………………………………………
Wellbore Deposits ………………………………………………….
Ineffective Perforating ……………………………………………...
Treating Approaches ……………………………………………….
3
3
3
4
5
5
EFFECT OF DAMAGE ………………………………………………………….
6
Radial Flow …………………………………………………………
Darcy’s Law ………………………………………………………...
Radial Reservoir Flow ……………………………………………...
Productivity Index ………………………………………………….
Inflow Performance ………………………………………………...
Effect Of Damage Zone Thickness …………………………………
Effect Of Damage Location ………………………………………..
Matrix Treating Benefits
……………………………………………
Matrix Treating Undamaged Wells ………………………………...
6
6
7
10
10
12
14
15
15
12.1.1
12.1.2
12.1.3
12.1.4
12.1.5
12.1.6
12.2
12.2.1
12.2.2
12.2.3
12.2.4
12.2.5
12.2.6
12.2.7
12.2.8
12.2.9
12.3
INDICATORS OF DAMAGE ……………………………………………...……. 17
12.3.1
12.3.2
12.3.3
12.3.4
12.3.5
12.3.6
Introduction …………………………………………………………
Offset Production …………………………………………………...
Production History ………………………………………………….
Reservoir Predictions ……………………………………………….
Darcy’s Law Calculations …………………………………………..
Well Testing ………………………………………………………..
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17
17
18
18
18
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12.4
January 1998
Introduction …………………………………………………………
Clay Disturbance …………………………………………………...
Clay Swelling ………………………………………………………
Clay Dispersion And Migration ……………………………………
Low Salinity Clay Dispersion ……………………………………...
Flow Induced Fines Migration ……………………………………..
Effect Of Mobile Water …………………………………………….
Scale Deposition ……………………………………………………
Asphalt And Paraffin Deposition …………………………………..
Emulsions …………………………………………………………..
Water Blocking …………………………………………………….
Wettability Changes ………………………………………………..
Acid Precipitates ……………………………………………………
21
22
23
23
23
24
24
26
27
27
29
30
30
Introduction …………………………………………………………
Matrix Treatments ………………………………………………….
Acidizing ……………………………………………………………
Solvents And Surfactants …………………………………………..
Hydraulic Fracturing ………………………………………………..
Tubing Treatments ………………………………………………….
31
31
31
31
32
32
DAMAGE PREVENTION ….....…………………………………………………. 33
12.6.1
12.6.2
12.6.3
12.6.4
12.6.5
12.6.6
12.6.7
12.6.8
12.6.9
12.1
PROPRIETARY INFORMATION -For Authorised Company Use Only
DAMAGE REMOVAL ………………………………………………………...… 31
12.5.1
12.5.2
12.5.3
12.5.4
12.5.5
12.5.6
12.6
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CAUSES OF FORMATION DAMAGE …………………....…...……………… 21
12.4.1
12.4.2
12.4.3
12.4.4
12.4.5
12.4.6
12.4.7
12.4.8
12.4.9
12.4.10
12.4.11
12.4.12
12.4.13
12.5
FORMATION DAMAGE
Drilling Fluid Selection …………………………………………….
Workover Fluid Salinity ……………………………………………
Brines To Stabilize Clays …………………………………………..
Clay Stabilizers ……………………………………………………..
Avoid Incompatible Brines …………………………………………
Surfactant Selection ………………………………………………...
Drawdown …………………………………………………………..
Fluid Loss Control ………………………………………………….
Injection Water Quality …………………………………………….
INTRODUCTION
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33
34
35
35
36
36
36
36
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12.1.1
FORMATION DAMAGE
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Chapter Goals
The purpose of this chapter is to introduce the engineer to the common causes of poor
productivity which can be remedied by workover treatments. Special emphasis is given to
poor productivity attributable to permeability reduction of the formation near the wellbore,
commonly referred to as damage. Upon completing this section, the engineer should be
able to recognize well productivity impairment, review information to identify its likely
source, and avoid causing formation damage when possible.
The radial flow theory necessary to understand the effects of damage and estimate
unimpaired production is presented first. This is followed by a discussion of indicators of
damage, causes of damage and damage prevention. Finally, a brief introduction to damage
treatments serves to bridge the gap between this and subsequent sections.
12.1.2
Poor Productivity
There are two major categories of poor productivity : (1) poor productivity attributable to
reservoir characteristics, and (2) poor productivity caused by alterations in the formation
near the wellbore or deposits in the production tubulars. Reservoir factors such as low
pressure, low permeability, and high viscosity may be overcome through methods involving
flooding, thermal methods and large hydraulic fracturing treatments. These approaches
have in common that they are designed to affect large reservoir areas. However, for the
purpose of this section, we are interested in causes of poor productivity that can be
remedied by workover treatments localized to a particular well. Included in this category
are formation damage and well deposits.
12.1.3
Formation Damage
Poor productivity caused by flow restrictions in the reservoir rock is called formation
damage. Formation damage is usually caused by disturbances to the formation or its native
fluids during drilling, workover, and producing operations. Formation damage is generally
limited to the reservoir rock lying within a couple of radial feet of the wellbore as
illustrated in Figure 1.
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Figure 1. Damaged Zone Around A Wellbore Restricts Production
In contrast to reservoir limitations, formation damage can often be removed with relatively
small treatments designed to treat the wellbore or penetrate only a limited distance into the
formation.
12.1.4
Wellbore Deposits
Material deposited in the production tubing and casing also is a common cause of
productivity declines. Such deposits can consist of organic material such as paraffin, or
mineral material such as calcite and barite, known as scale. These and similar solids often
precipitate from produced fluids as they re-equilibrate with wellbore conditions. Removing
wellbore deposits often involves a different approach than removing formation damage.
12.1.5
Ineffective Perforating
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Optimal flow rate from a particular well is also dependent upon establishing good
communication between the wellbore and the reservoir. This is the goal of perforating. For
various reasons however, perforations may not provide the necessary good communication.
Charges may fail to ignite, or ignite below their design force, or the cement sheath may be
thicker than the limited penetration depth of the gun. These limitations are associated with
gun capabilities and may require re-perforation to achieve satisfactory flow.
The perforating technique is also important for attaining perforating objectives.
Specifically, it is widely recognized that perforations shot underbalanced in a clear fluid
perform better than those shot overbalanced in mud. Overbalancing causes perforation
debris and mud to become compacted in the tunnels, often necessitating an acid job to
attain maximum deliverability. These are but a few examples of how the perforating
process can effect well performance. For a more complete discussion refer to the section
on Perforating.
12.1.6
Treating Approaches
The type of treatment chosen is determined by the cause of the productivity impairment.
Formation damage is often treated with acids and solvents which are injected into the rock
matrix, so that flow restrictions will be dissolved. Material deposited in the wellbore may
also be remove with solvents, usually with less volume than required for matrix treatment.
In some cases, mechanical methods may be necessary to remove wellbore restrictions.
Hydraulically fracturing a formation will often be successful at by passing a zone of
damage. While such treatments are frequently designed to stimulate reservoirs by
overcoming naturally low permeability, added benefit often is realized from by passing
damage. In fact, smaller volume fracturing treatments are often designed only to penetrate
a damage zone immediately around the wellbore. However, fracturing treatments in general
tend to be more involved and costly, and there are added risks. Therefore, it is usually
desirable to remove damage with matrix treatments whenever possible.
12.2
EFFECT OF DAMAGE
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Radial Flow
The severity of formation damage is a consequence of the radial flow pattern of reservoir
fluids. Flow in an unfractured reservoir proceeds via radial geometry, in which fluids
traverse progressively smaller volumes of rock as they approach the wellbore.
Consequently, the greatest pressure drop occurs in the formation adjacent to the wellbore,
making overall production very sensitive to permeability reductions there.
12.2.2
Darcy’s Law
Henry D’Arcy, while studying the operation of sand filters for municipal water treatment in
France during the mid-1800’s, deduced the basic law for the flow of a single liquid through
a porous medium. Darcy (his name has long since been Anglicized) observed that the
velocity of flow is directly proportional to the pressure gradient, dp/ds, and inversely
proportional to fluid viscosity, µ. This proportionality is expressed in the following
equation;
v = - k dp
µ ds
(1)
where k, the constant of proportionality is a characteristic of the porous medium called the
permeability. The velocity referred to in this equation is the apparent velocity and is equal
to volumetric flow rate divided by the area through which this flow occurs, i.e., v = q/A. In
cgs units, v is expressed in centimeters per second, viscosity in centipoise and pressure
gradient in atmospheres per centimeter. Similarly, volumetric flow rate is expressed in
cubic centimeters per second and area in square centimeters. In these units the
proportionality constant, k, is expressed in darcies.
Darcy’s Law applies to the laminar flow region only. Turbulent flow may occur in porous
media provided that flow rate is high enough, fluid viscosity low enough, or the
characteristic pore dimension large enough. In non-Darcy flow the pressure gradient
increases at a rate greater than flow rate. However, non-Darcy flow seldom occurs with
liquids flowing through porous media except in the case where very high injection or
production rates are encountered, and then only in the region nearest the wellbore. For gas
wells, however, non-Darcy flow is by no means uncommon. Calculations based on Darcy’s
Law on gas wells producing at high rates can be seriously in error.
12.2.3
Radial Reservoir Flow
Although flow very near the wellbore probably occurs via a complex combination of
geometries, most near-wellbore flow problems are analyzed by assuming a radial flow
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model throughout the reservoir. Radial flow actually occurs only in an open hole
completion from a formation of uniform permeability, as idealized in Figure 2.
Figure 2. Radial Flow
As a practical matter, however, flow from densely perforated completions can be
successfully analyzed by employing the radial flow model. When Darcy’s equation is
modified for radial geometry and converted from cgs units to customary field engineering
units of psi, barrels per day, millidarcies and centipoise, the final equation relates surface
production rate to pressure drop, formation permeability and fluid viscosity :
Q
-3
= 7.08 x 10 kh (Pe
re
µ Bo ln rw
Pw)
Q
=
flow rate, stock tank barrels/day
k
=
average formation permeability, millidarcies
h
=
interval thickness, feet
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Pe
=
formation pressure at external drainage radius, psi
Pw
=
flowing wellbore pressure at perforations, psi
µ
=
oil viscosity at formation temperature, centipoise
Bo
=
reservoir fluid volume factor,
re
=
drainage radius of well, feet
rw
=
wellbore radius, feet
reservoir barrels
stock tank barrels
Notice that the factor Bo appears in the equation. This factor is used to account for the
volume change of crude oil from the time it flows into the wellbore to the time it is
measured in a stock tank. This factor is determined from an analysis of a crude sample
taken at a particular point in a well’s production history. This equation can be used to
estimate an oil well’s flowing potential, if the required reservoir and wellbore factors are
known or can be estimated.
A slightly different equation exists for gas wells, and includes terms to account for gas
compressibility. This equation takes the form
Q(MScf/D)
-4
2
= 7.03 x 10 kh (P e
re
µ T z ln rw
P2w)
(3)
where the additional term T is Rankine temperature, and z is a dimensionless factor
accounting for gas deviation from ideality.
The drainage radius is inferred from well spacing. For example, the drainage radius for a
well spacing of 40 acres is 660 feet. This can be verified by noting that a circle with radius
of 660 ft can be inscribed within a square 40-acre unit. Similarly, for 160 acre spacing, the
drainage radius is 1320 ft, and for 640 acre spacing, the drainage radius is 2640 feet. Thus,
quadrupling the spacing doubles the drainage radius.
Common well spacings and corresponding drainage radii are summarized in Table 1 :
TABLE 1
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Well Spacing
Acres
Drainage Radius
Ft
10
20
40
80
160
320
640
330
467
660
933
1320
1867
2640
While the concept of a drainage radius and wellbore radius is precise, neither quantity is
known with great precision. In the case of the wellbore radius, for example, this radius is
clearly not the inside radius of the casing, nor even the outside radius of the casing, but
rather the radius of permeable formation beyond the cement sheath at the cement-formation
interface. This radius is not always precisely definable because of hole enlargement or
filter cake deposition. Additionally, flow is through a perforation at this point and hence,
departs markedly from radial flow in the immediate vicinity of the perforation.
Nonetheless, these imprecisions on the determination of rw have less effect than might be
anticipated because of the logarithmic term in which re and rw appear. For example, in an
8” diameter wellbore (rw = 4 in or 333 ft) for a well on 40-acre spacing (re = 660 ft) the ratio
of re over rw is 1980 and the logarithm of 1980 is 7.59. An increase in the internal radius
from 4 in to 6 in, i.e., 50 percent increase in the value of rw yields a value of 7.18 for the
logarithmic term which is a decrease of less than 6 percent in the value of this quantity.
Thus, the effect of the uncertainty is greatly reduced in the final calculation.
In the practical application of this equation Pw is generally determined by measurements
with a bottomhole pressure bomb positioned adjacent to the sand face near the middle of
the perforated interval during the period when the well is flowing. Pe’ the pressure at the
drainage radius is generally estimated from a shut-in pressure buildup test. For relatively
permeable formations, this can be determined within a reasonably short shut-in period (say
24 hours) provided bottomhole pressures have substantially stabilized during this period.
More involved methods, however, must be employed on formations of low permeability to
obtain a suitable Pe.
The viscosity of the crude at reservoir temperature can be obtained from a hydrocarbon
report if available, or estimated from correlations of oil gravity and viscosity. Viscosity is
measured in centipoise, and can be compared to water at 1 cp.
Using the above equation, the average permeability of the formation may be estimated from
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a given flow rate at known pressure drawdown (Pe - Pw). This calculated permeability will
represent an average, which will include the effects of any damage zone that is present. As
discussed further in the text, comparing this average permeability with independently
measured formation permeability from core data or a buildup test often serves as an
indicator of well damage. Alternatively, this equation can be used to estimate flow rate
from a knowledge of formation permeability. In this case, permeability may be inferred
from buildup test data or core permeability measurements, when available.
12.2.4
Productivity Index
For field applications in which comparisons among wells in the same formation are often
relied upon as an indicator of damage, many of the terms in Darcy’s equation will cancel
out to give a simplified, convenient measure of productive capacity, called productivity
index, J :
J=
q
Pe - Pw
(4)
The productivity index can be used to compare well performance within a given formation,
where formation properties are constant. The Specific Productivity Index, J per foot of
interval, is a way of accounting for differences in formation thickness from one well to the
next.
12.2.5
Inflow Performance
The productivity index is a limited concept in that it assumes that there is no relative
permeability during production; i.e., no other reservoir fluids are being produced with the
primary production fluid. Since the production rate is directly proportional to the pressure
drawdown, both will decrease proportionally as the well is depleted, and the productivity
index should remain relatively constant. The only reservoir characteristic that will alter the
productivity index is the presence of relative permeability.
In particular, the productivity index will decline in a well with a solution-gas drive reservoir
when the reservoir pressure falls below the bubble point of the formation’s crude oil. The
bubble point is the pressure at which gas begins to evolve from the crude. As gas is
released from the oil, it begins to fill the pore spaces, making it more difficult for oil to
flow. An inflow performance curve which is more applicable to a well producing below its
bubble point is shown in Figure 3. This curve demonstrates that a greater drawdown is
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required to obtain a given production rate as reservoir pressure declines below the bubble
point (when the straight-line relationship does not hold). When producing at reservoir
pressures below the bubble point, the productivity index will decline with time.
Figure 3. Typical Inflow Performance Relationship for Solution Gas Drive Reservoirs
When evaluating the productivity of a well by comparing its specific productivity index to
that of other wells, it will be necessary to first determine if a given well is producing above
or below its bubble point pressure. If the specific productivity index of a well is lower than
the specific productivity index of offset wells, it may not be damaged but simply producing
below its bubble point. The bubble point for various crudes will differ from one field to
another, depending on the fluid properties and temperatures of a given formation.
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FORMATION DAMAGE
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Effect Of Damage Zone Thickness
As a natural consequence of radial flow, formation damage that is located closest to the
wellbore exerts the greatest adverse influence on production. Of course, the thicker or
deeper the damage zone is, the greater the reduction of productivity. However, once
damage to the near wellbore region occurs, deepening of the damage adds a progressively
smaller contribution to production loss. This is mathematically shown by manipulating
Darcy’s equation to include a zone of damaged permeability, kd, of thickness rd. The
resulting equation relates the productivity index of the damaged formation to the native
formation (J/Jo) and the depth and magnitude of damage :
αlog
J/Jo =
re
rw
log re + αlog re
rw
rw
(5)
where α is the ratio of damage zone permeability to virgin permeability. These dimensions
are illustrated in Figure 4 for an idealized damage zone. Plotting the above equation for
various amounts of damage, α, as a function of depth of damage radius shows that the
greatest effect of damage is within the first two inches of the wellbore (Figure 4), with
diminishing influence as depth of damage invasion increases.
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Figure 5. Effect of Moving a Zone of Damage of Constant Thickness
Outward from the Wellbore
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Effect Of Damage Location
The fact that damage is most harmful near the well also implies that a damage removal
treatment will be effective even though it may not penetrate deeply enough to remove all
damage. This is also mathematically founded in Darcy’s equation, which, when rearranged
to describe a residual zone of damage around the wellbore gives :
ln
J/Jo =
ln
re
rw
re
k
r
+ o − 1 ln d
rw
kd
ru
(6)
Figure 5. Effect of Moving a Zone of Damage of Constant Thickness
Outward from the Wellbore
As shown in Figure 5, a hypothetical zone of damage 6 inches thick exerts less influences
as it is placed further from the wellbore. This demonstrates that, although deep damage
removal may be desirable for complete recovery in some cases, it is not essential. Benefits
can be derived from removing damage near the wellbore even if the deeper portion can’t be
removed.
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Matrix Treating Benefits
Removing damage with solvents can result in productivity many times the damaged
productivity, depending on the extent of initial damage. For example, Figure 4 indicates
that a well which contains a 90% reduction in permeability in the first foot around the
wellbore has a flow efficiency near 35%. Therefore, a properly designed damage-removal
treatment has the potential to increase the production rate by a factor of three. Such
damage removal benefits are estimated on the assumption of uniform, radial removal of
damage from within the matrix of the rock, hence such treatments are often referred to as
matrix treatments. Hydraulic fracturing, as discussed later, can also yield these benefits, by
a mechanism which causes the damage to be bypassed. However, a fracture treatment must
be intentionally designed in order to be effective. Fracturing a treatment intended for
matrix injection will generally yield disappointing results.
12.2.9
Matrix Treating Undamaged Wells
Matrix treating only offers the potential for significant productivity improvement in
damaged wells. Little benefit can be expected if no damage is present. The negligible
benefits of undamaged well treating can be dramatized with the aid of Equation 5, this time
by approaching the limit of α = ∞ for the hypothetical case of a treatment which infinitely
increases near wellbore permeability of a 6-in. well completed on 40 acre spacing.
Physically, this would require underreaming the formation with a drill bit, thereby
removing all rock.
As shown in Figure 6, very little benefit can be expected from even such an extreme
operation as removing all rock radially out to 10 feet. A productivity index increase of two
fold is about the best to expect. In reality, such permeability increases are not possible with
matrix treatments, and production increases would be negligible. Furthermore, some
damage removal treatments may create damage if not performed properly. For these
reasons, there should be evidence of formation damage before a matrix treatment is
implemented.
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Figure 6. Stimulation of an Undamaged Well
12.3
INDICATORS OF DAMAGE
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12.3.1
FORMATION DAMAGE
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Introduction
There is a large incentive for being able to identify the presence of treatable formation
damage, since the economic return of a field often depends on maintaining maximum
productivity from each well. Treatments performed on undamaged wells are wasted at best,
and may actually lead to increased damage. We can avoid many problems associated with
incorrect diagnosis by exploiting the evaluation tools available, including productivity
comparisons, calculated production estimates, and well testing.
12.3.2
Offset Production
A common indicator of well damage is low productivity relative to offset wells in the same
formation. The specific productivity index, J/ft of interval, provides a means for
quantifying this comparison. A substantially lower specific productivity index relative to
other wells in the field suggests that damage is present. However, although this is a useful
approach for initial screening, this concept is limited by the heterogeneous makeup of many
formations. Therefore, additional diagnostics and data should be gathered prior to deciding
a course of remedial action.
12.3.3
Production History
Comparison of present production with past production history is a good indicator of
problem wells, providing that normal reservoir decline is accounted for. Productivity
index, J, is especially useful for comparing production from the same well at different
times, since formation factors are likely to remain constant.
After an abnormally high production decline has been verified, the well’s history can give
important clues as to the type of damage present. Low productivity may be traceable to a
specific completion, workover or production practice. For example, formation damage is
often common after well killing operations, especially if drilling mud is used as a workover
fluid. Injection of unfiltered brines into disposal or injection wells is a common cause of
reduced injectivity. Instances such as these should be looked for in well files when damage
is suspected.
12.3.4
Reservoir Predictions
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Reservoir engineering calculations which predict production history are important guides to
a well’s potential, against which actual performance can be measured. A decline in
productivity which is inconsistent with reservoir predictions is reason to suspect damage.
12.3.5
Darcy’s Law Calculations
The previous subject detailed the use of the radial flow equation to estimate production, and
the use of this approach is an important part of diagnosing possible problems. If rock
permeability and hydrocarbon properties are known, a rough estimate of productivity index
can be calculated using Darcy’s equation and compared to the actual value. Although
limitations on our knowledge of the true rock permeability will make accurate predictions
difficult, large discrepancies imply formation damage.
12.3.6
Well Testing
Well testing is generally understood to encompass flow testing and pressure buildup testing.
Flow testing can provide productivity index, fluid ratios, and a measure of average
permeability. Changes in flow rate or relative fluid production from one test period to
another are often signs that the well is damaged.
Pressure buildup testing is a relatively sophisticated approach to measuring reservoir
permeability and obtaining an indication of formation damage. A buildup test involves
flowing the well at constant rate buildup of pressure in the formation is monitored. The
rate at which this pressure re-establishes itself after being drawn down is a measure of the
native formation permeability, and the presence of a damage zone.
The ideal system is a single well in an infinite, homogeneous reservoir containing a fluid
with constant properties but with no altered zone around the well. If this well is shut in at
the sand face after producing at a rate q for Horner time, th, the sandface pressure at time ∆t
after shut-in given by :
Pw - Pi = 162.6
qµ Bo log
kh
th + ∆t
∆t
(7)
This equation suggests that a plot of Pw vs log (th + ∆t/∆t) will be a straight line for
circumstances adequately described by the ideal reservoir model. Bulk formation
permeability can be obtained from the slope, m, of this straight line by :
K=
162.6 qµBo
mh
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Original reservoir pressure, Pj, is obtained by extrapolating the straight line to infinite shutin time; i.e., where (th + ∆t)/∆t = 1 (See Figure 7).
In actual buildup or fall of test, it is rare for straight line to be observed over all shut-in
times. Instead, field curves have various shapes, which can be explained with the depth-ofinvestigation concept. Field curves can logically be divided into three regions, as shown in
Figure 8. At early times, the depth of investigation is near the wellbore. Accordingly,
conditions in the altered zone (such as formation damage) determine the character of the
curve. In addition, continued production into the well (afterflow) because of surface shut-in
influences the curve in this region. “Afterflow” occurs because the compressibility of fluid
in the wellbore will permit residual feed in, even after shut in. This effect, which interferes
with early time data analysis, can be eliminated or reduced by using bottomhole shut-in
equipment.
Formation damage is often indicated by the shape of the curve in region I. A steeply rising
slope suggests a high pressure drop caused by formation damage. A numerical estimate of
damage, called the skin factor, “s”, is obtainable from this region. Although its calculation
is beyond the scope of this text, it is worthwile to gain an appreciation of typical skin factor
magnitude. A skin factor of 0 indicates that no damage is present, while positive skin
factors are typical of damaged formations. Typically, a skin factor of 5 - 10 may indicate
moderate levels of damage, while factors above 10 indicate severe damage. Very high skin
factors, say 30 and above, may sometimes be attributable to ineffective perforation
penetration or incomplete perforation of an entire interval. These possibilities should be
investigated in cases of high skin factors. Negative skin factors often are indicative of
stimulated wells.
In the middle time region, the depth of investigation has moved beyond the region of
influence of the altered zone and is not yet affected by conditions at the drainage boundary.
Bulk formation properties are the dominant influence. A straight line with slope m usually
occurs, from which bulk-formation permeability can be obtained just as if the reservoir
were infinite. Permeability can be obtained from the slope of the MTR using equation 8.
The flow rate q, is the maintained prior to the shut-in period. If they are not accurately
known from hydrocarbon analyses, the viscosity and formation volume factors can be
estimated from correlations using API gravity and gas/oil ratio obtained at the wellsite.
The buildup measurement of kh gives us a value to compare with average kh obtained from
production testing. If kh (buildup) is significantly greater than kh (flow), formation damage
is indicated.
At late times, the depth of investigation has reached the well’s drainage boundaries.
Pressure behavior is accordingly influenced by conditions at these boundaries
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Figure 7. Ideal Build-up
Figure 8. Actual Build-up
12.4
CAUSES OF FORMATION DAMAGE
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12.4.1
FORMATION DAMAGE
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Introduction
Formation damage implies that hydrocarbon flow through reservoir rock has been impaired.
Solids plugging probably is the major cause of damage problems. As a category, solids
include native clays and fines, materials precipitated from reservoir fluids (mineral scale,
asphalt, paraffin) and solids introduced by drilling mud (barite, bentonite, drilled rock).
They can range in size from sub-micron clay particles to perforation and wellbore-filling
scale deposits. Some clay solids are illustrated in Figure 9.
Figure 9 Examples of Native Formation Clays
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Figure 10. Osmotic Swelling of Clays
Other established causes of damage are emulsion blocking, water blocking, and wettability
changes. These conditions adversely affect production through different mechanisms but
nevertheless the end result can be as harmful as solids damage. A more recently recognized
form of damage occurs as a result of reprecipitation of dissolved material during sandstone
acidizing.
12.4.2
Clay Disturbance
Clays are probably the fine particles most often responsible for damage. They can impair
permeability several ways. First, all clays are prone to dispersion and migration when
disturbed.
Foreign fluid invasion and fluid flow forces are common disturbance which are often
blamed for causing clay migration subsequent plugging. The second widely accepted
damage mechanism involves swelling. There is a variety of clay known as smectite
(montmorillonite) which can expand to several times its size upon water absorption. This
expansion is believed capable of causing blocking of pore spaces, especially if the clays are
located at critical pore throats. These clays are also more prone to disperse and migrate
when they expand. Consequently, they can restrict pores by a dual mechanism of
expansion and migration if disturbed. A scanning electron microscope photo of smectite is
included in Figure 9.
In actuality, attributing damage to either of these mechanisms exclusively is overly
simplistic. Clay damage probably proceeds via a combination of these and other
mechanisms in most cases.
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Clay Swelling
Swelling is believed to occur because of an osmotic pressure difference between the bulk
fluid and the interlayer region of the clay particle. This theory explains the sensitivity of
clays towards brines with salinity sharply lower than the connate brine. Water molecules
from a less-saline brine will enter a clay structure containing higher salinity brine. This
occurs because osmotic forces tend to equilibrate the lower bulk salinity with the higher
salinity in the vicinity of the clay layers, as conceptualized in Figure 10.
Divalent cations such as Ca ++ and Mg ++ limit clay swelling by holding the clay layers
together more tightly. This is also true of K + and NH4+, monovalent cations which are
effective at reducing swelling because they fit well into the clay structure. Regardless of
which cation is responsible for stabilizing clays, the effect is reversible. Stabilizing cations
can be replaced by re-exposure of clays to sodium, after which the clays are prone to low
salinity damage.
12.4.4
Clay Dispersion and Migration
Clays also reduce permeability by dispersing and migrating. In this case, they can lodge in
pore throats, causing blockage. Although this pore blockage occurs on a microscopic scale,
the result is a reduction of the bulk rock permeability. Migration can be caused by salinity
incompatibility with introduced brine and mechanical forces on particles during fluid flow.
Either or both of these causes may be operative at the same time.
12.4.5
Low Salinity Clay Dispersion
Abrupt salinity reductions of the clay environment will often cause clay particles to detach
from each other and the sand grain surfaces, as shown in Figure 11. Clays in this detached
state are free to migrate until they bridge at pore constrictions and reduce fluid flow.
The charge characteristics of clays explain their tendency to disperse upon exposure to low
salinity brines. Clays are characterized by a negative surface charge which attracts a
diffuse layer of cations such as Na+ and Ca++. This layer of cations experiences two
opposing forces which counteract each other. A diffusional force away from the clay
surface. The tendency for diffusion increases if the salinity is reduced, causing the layer of
ions to expand and exert repulsive forces on nearby particles, as shown in Figure 11.
This mechanism believed to be responsible for dispersing clays, especially if salinity
reduction is abrupt. However, evidence has shown that reduction in salinity sometimes will
be completely non-damaging if introduced gradually. This suggests that the repulsive
forces causing dispersion can be rendered less damaging if they are taken in a stepwise
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fashion. This observation has important practical implications for workover fluids. If low
salinity brine must be used, severe damage can be avoided by exposing the formation to
progressively lower salinity brine until the desired strength is attained.
Figure 11. Low Salinity Causes Clay Dispersion
12.4.6
Flow Induced Fines Migration
The foregoing discussion suggests that dispersion damage can be avoided by the proper
choice of fluids introduced to the formation. This is true, up to a point. Clays, as well as
other fine particles, can be mobilized by fluid forces exerted by fluid flow, and this problem
is more difficult to avoid. As shown in Figure 12, fluid flow velocities increase
dramatically towards the near wellbore region, and it is possible to entrain particles from a
few feet into the reservoir, particularly in a high rate well.
12.4.7
Effect of Mobile Water
Entrainment of fines by fluid flow has been shown to be related to the mobility of the water
phase. Clays and silica fines, being generally water-wet will experience greater fluid forces
if the water phase flows. This concept is illustrated in Figure 13, which portrays physical
laboratory observations made under a microscope.
Field observations tend to support this concept, since it is generally true that the onset of
water production marks the onset of sand production in poorly consolidated fields. Coning,
flood breakthrough, and workover fluid leakoff are a few mechanisms by which an
irreducible water phase, and hence fines, may become mobilized.
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Figure 12. High Fluid Velocity near Wellbore Can Cause Fines Migration
Figure 13.
12.4.8
Scale Deposition
Scale deposition occurs because produced fluids seek to regain equilibrium with the new
environment in the wellbore. As a result, solid mineral material, called scale, is often
d