PIPESIM Fundamentals
Workflow/Solutions Training
Version 2010.1
Schlumberger Information Solutions
November 3, 2010
Copyright Notice
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Table of Contents
About this Manual
Learning Objectives . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
What You Will Need . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
What to Expect . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Course Conventions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Icons . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Workflow Diagram . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Summary . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
1
1
2
3
4
5
6
Module 1: PIPESIM Introduction
Learning Objectives . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9
Lesson 1: Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9
Lesson 2: A Tour of the User Interface . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12
Lesson 3: PIPESIM File System and Calculation Engines . . . . . . . . . . . . . . . . 15
Output Files . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17
Lesson 4: Plots . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19
Lesson 5: Single Branch Operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 21
System Analysis . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 21
Pressure/Temperature Profile . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 22
Flow Correlation Comparison . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 22
Data Matching . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 22
NODAL Analysis . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23
Optimum Horizontal Well Length . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23
Reservoir Tables . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 24
Well Performance Curves . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 24
Gas Lift Rate vs. Casing Head Pressure . . . . . . . . . . . . . . . . . . . . . . . . . . . 24
Artificial Lift Performance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 24
Wax Deposition . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 24
Review Questions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25
Summary . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25
Module 2: Simple Pipeline Tutorials
Learning Objectives . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Lesson 1: Single-Phase Flow Calculations . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Exercise 1: Modeling a Water Pipeline with Hand Calculations . . . . . . . . . .
Exercise 2: Modeling a Water Pipeline with PIPESIM . . . . . . . . . . . . . . . . .
Performing Operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
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The Primary Output File . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
The Auxiliary Output File . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Exercise 3: Analyzing Multiple Scenarios with Sensitivities . . . . . . . . . . . . .
Exercise 4: Modeling a Single-Phase Gas Pipeline . . . . . . . . . . . . . . . . . . .
Exercise 5: Calculating Gas Pipeline Flow Capacity . . . . . . . . . . . . . . . . . .
Lesson 2: Multiphase Flow Calculations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Exercise 1: Modeling a Multiphase Pipeline . . . . . . . . . . . . . . . . . . . . . . . . .
Review Questions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Summary . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
41
43
45
49
52
54
57
65
65
Module 3: Oil Well Performance Analysis
Learning Objectives . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Lesson 1: NODAL Analysis . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Getting Started . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Exercise 1: Building the Well Model . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Exercise 2: Performing NODAL Analysis . . . . . . . . . . . . . . . . . . . . . . . . . . .
Exercise 3: Performing a Pressure/Temperature Profile . . . . . . . . . . . . . . .
Questions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Lesson 2: Fluid Calibration . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Single Point Calibration . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Multi-Point Calibration . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Exercise 1: Calibrating PVT Data . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
GOR Property Definitions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Lesson 3: Pressure/Temperature Matching . . . . . . . . . . . . . . . . . . . . . . . . . . .
Exercise 1: Flow Correlation Matching . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Exercise 2: Matching Inflow Performance . . . . . . . . . . . . . . . . . . . . . . . . . .
Questions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Lesson 4: Well Performance Analysis . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Conducting a Water Cut Sensitivity Analysis . . . . . . . . . . . . . . . . . . . . . . . .
Exercise 1: Evaluating Gas Lift Performance . . . . . . . . . . . . . . . . . . . . . . . .
Exercise 2: Working with Multiple Completions . . . . . . . . . . . . . . . . . . . . . .
Question . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Lesson 5: Flow Control Valve . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Exercise 1: Modeling a Flow Control Valve . . . . . . . . . . . . . . . . . . . . . . . . .
Review Questions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Summary . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
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Module 4: Gas Well Performance
Learning Objectives . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Lesson 1: Compositional Fluid Modeling . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Equations of State (EoS) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Binary Interaction Parameter (BIP) Set . . . . . . . . . . . . . . . . . . . . . . . . . . .
Exercise 1: Creating a Compositional Fluid Model for a Gas Well . . . . . . .
Questions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Lesson 2: Gas Well Deliverability . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Exercise 1: Calculating Gas Well Deliverability . . . . . . . . . . . . . . . . . . . . .
Exercise 2: Calibrating the Inflow Model Using Multipoint Test Data . . . . .
Questions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Lesson 3: Erosion Prediction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
API 14 E . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Salama . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Exercise 1: Selecting a Tubing Size . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Questions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Lesson 4: Choke Modeling . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Exercise 1: Modeling a Flowline and Choke . . . . . . . . . . . . . . . . . . . . . . .
Exercise 2: Predicting Future Production Rates . . . . . . . . . . . . . . . . . . . .
Questions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Lesson 5: Liquid Loading . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Turner Droplet Model . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Exercise 1: Determining a Critical Gas Rate to Prevent Well Loading . . . .
Review Question . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Summary . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
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107
110
111
112
115
117
117
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125
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128
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Module 5: Horizontal Well Design
Learning Objectives . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Lesson 1: Inflow Performance Relationships for Horizontal Completions . . . .
Exercise 1: Constructing the Well Model . . . . . . . . . . . . . . . . . . . . . . . . . .
Exercise 2: Evaluating the Optimal Horizontal Well Length . . . . . . . . . . . .
Exercise 3: Specifying Multiple Horizontal Perforated Intervals . . . . . . . . .
Review Questions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Summary . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
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Module 6: Subsea Tieback Design
Learning Objectives . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Lesson 1: Flow Assurance Considerations for Subsea Tieback Design . . . . .
Exercise 1: Developing a Compositional PVT Model . . . . . . . . . . . . . . . .
Exercise 2: Constructing the Model . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Exercise 3: Sizing the Subsea Tieback . . . . . . . . . . . . . . . . . . . . . . . . . . .
Lesson 2: Hydrates . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Hydrate Mitigation Strategies in PIPESIM . . . . . . . . . . . . . . . . . . . . . . . . .
Exercise 1: Selecting Tieback Insulation Thickness . . . . . . . . . . . . . . . . .
Exercise 2: Determining the Methanol Requirement . . . . . . . . . . . . . . . . .
Questions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Lesson 3: Severe Riser Slugging . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
PI-SS Indicator (Severe-Slugging Group) . . . . . . . . . . . . . . . . . . . . . . . . .
Exercise 1: Screening for Severe Riser Slugging . . . . . . . . . . . . . . . . . . .
Lesson 4: Slug Catcher Sizing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Hydrodynamic Slugging . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Pigging . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Ramp-up . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Evaluating Each Scenario . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Exercise 1: Sizing a Slug Catcher . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Review Questions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Summary . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
139
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144
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Module 7: Looped Gas Gathering Network
Learning Objectives . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Lesson 1: Model a Gathering Network . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Boundary Conditions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Solution Criteria . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Exercise 1: Building a Model of a Network . . . . . . . . . . . . . . . . . . . . . . . . .
Exercise 2: Performing a Network Simulation . . . . . . . . . . . . . . . . . . . . . .
Looped Gathering Network Data . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Review Questions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Summary . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
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Module 8: Water Injection Network
Learning Objectives . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Lesson 1: Crossflow in Multilayer Wells . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Exercise 1: Determining Fluid Distribution in a Water Injection Network . .
Review Questions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Summary . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
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Appendix A: PIPESIM 2010.1 Fundamentals Answer Key to Exercises
Module 2: Simple Pipeline Tutorials . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Lesson 1: Single-Phase Flow Calculations . . . . . . . . . . . . . . . . . . . . . . . .
Module 3: Oil Well Performance Analysis . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Lesson 1: Nodal Analysis . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Lesson 2: Fluid Calibration . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Lesson 3: Pressure/Temperature Matching . . . . . . . . . . . . . . . . . . . . . . . .
Lesson 4: Well Performance Analysis . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Question (Optional) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Lesson 5: Flow Control Valve Modelling . . . . . . . . . . . . . . . . . . . . . . . . . .
Module 4: Gas Well Performance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Lesson 2: Gas Well Deliverability . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Lesson 3: Erosion Prediction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Lesson 4: Choke Modelling . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Lesson 5: Critical Gas Rate . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Module 5: Horizontal Well Design . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Lesson 1: Inflow Performance Relationships . . . . . . . . . . . . . . . . . . . . . . .
Module 6: Subsea Tieback Design . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Lesson 1: Flow Assurance Considerations for Subsea Tieback Design . .
Lesson 2: Hydrates . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Lesson 3: Severe Riser Slugging . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Lesson 4: Slug Catcher Sizing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Module 7: Looped Gas Gathering Network . . . . . . . . . . . . . . . . . . . . . . . . . .
Lesson 1: Model a Gathering Network . . . . . . . . . . . . . . . . . . . . . . . . . . . .
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About this Manual
About this Manual
This training provides an introduction into the PIPESIM software
application. PIPESIM is a production engineer’s tool that covers a
wide range of applications relevant to the oil and gas industry.
Applications featured in this training manual include well
performance, fluid modeling, flow assurance and network
simulation.
Learning Objectives
After completing this training, you will know how to:
•
build a single branch well or pipeline model
•
define a black oil or compositional fluid model
•
perform single branch simulation operations
•
build a network model
•
perform a network simulation.
What You Will Need
You must have the following hardware and software to complete
the training:
•
Personal computer with minimum 512 MB RAM
•
PIPESIM 2010.1
•
Training data sets.
PIPESIM Fundamentals, Version 2010.1
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About this Manual
Schlumberger
What to Expect
In each module within this training material, you will encounter the
following:
•
Overview of the module
•
Prerequisites to the module (if necessary)
•
Learning objectives
•
A workflow component (if applicable)
•
Lessons, explaining a subject or an activity in the workflow
•
Procedures, showing the steps needed to perform a task
•
Exercises, which allow you to practice a task by using the
steps in the procedure with a data set
•
Scenario-based exercises
•
Questions about the module
•
Summary of the module.
You will also encounter notes, tips and best practices.
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PIPESIM Fundamentals, Version 2010.1
Schlumberger
About this Manual
Course Conventions
Characters typed in
Bold
Represent references to dialog box names
and application areas or commands to be
performed. For example, "Open the Open
Asset Model dialog." or “Choose
Components.”
Used to denote keyboard commands. For
example, "Type a name and press Enter."
Identifies the name of Schlumberger software
applications, such as ECLIPSE or Petrel.
Characters inside <>
triangle brackets
Indicate variable values that the user must
supply, such as <username> and
<password>.
Characters typed in
italics
Represent file names or directories, such as
"... edit the file sample.dat and..."
Represent lists and option areas in a window,
such as Attributes list or Experiments area.
Identifies the first use of important terms or
concepts. For example, "compositional
simulation…" or “safe mode operation.”
Characters typed in
fixed-width
Represent code, data, and other literal text the
user sees or types. For example, enter
0.7323.
NOTE: Some of the conventions used in this manual indicate
the information to enter, but are not part of the
information For example: Quotation marks and
information between brackets indicate the information
you should enter. Do not include the quotation marks or
brackets when you type your information.
Instructions to make menu selections are also written using bold
text and an arrow indicating the selection sequence, as shown:
1. Click File menu > Save (the Save Asset Model File dialog
box opens.)
OR
Click the Save Model
toolbar button.
An ‘OR’ is used to identify an alternate procedure.
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Icons
Throughout this manual, you will find icons in the margin
representing various kinds of information. These icons serve as
at-a-glance reminders of their associated text. See below for
descriptions of what each icon means.
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About this Manual
Workflow Diagram
Figure 1 illustrates the workflow of the PIPESIM application.
Figure 1
PIPESIM workflow
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Summary
In this introduction, we:
6
•
defined the learning objectives
•
outlined what tools you will need for this training
•
discussed course conventions that you will encounter within
this material
•
provided a high-level overview of the workflow.
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About this Manual
NOTES
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NOTES
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PIPESIM Introduction
Module 1 PIPESIM Introduction
This module introduces PIPESIM 2010.1 and describes the
graphical user interface (GUI) in detail to familiarize you with the
application environment.
Learning Objectives
After completing this module, you will know how to:
•
create a new or open an existing project
•
navigate through the user interface
•
understand the structure of the output file
•
display plots in PsPlot.
You will also develop an understanding of PIPESIM toolbars, file
system, engines, and operations.
Lesson 1
Introduction
PIPESIM is a steady-state, multiphase flow simulator used for the
design and analysis of oil and gas production systems. With its
rigorous simulation algorithms, PIPESIM helps you optimize your
production and injection operations.
As shown in Figure 2, PIPESIM models multiphase flow from the
reservoir through to the surface facilities to enable comprehensive
production system analysis.
PIPESIM is most often used by reservoir, production or facilities
engineers as an engineering user type to model well performance,
conduct nodal (systems) analysis, design artificial lift systems,
model pipeline networks and facilities, and analyze field
development plans and optimize production.
NOTE: Steady-state flow simulation implies that the mass flow
rate is conserved throughout the system. This means
there is no accumulation of mass within any component
in the system.
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Figure 2
Schlumberger
Total production system
PIPESIM modules are available and licensed separately,
depending on your needs:
Base System
Production system analysis software
for well modeling, NODAL analysis,
artificial lift design, pipeline/process
facilities modeling and field
development planning.
Network Analysis
(NET)
Optional add-on to PIPESIM to model
complex networks that can include
loops, parallel lines and crossovers
Compositional Model
Optional add on to PIPESIM
Multiflash Package
Optional add-on to PIPESIM.
Compositional model is not required.
Multiflash Hydrates
Optional add-on to Multiflash package.
Multiflash Wax
Thermodynamics
Optional add-on to Multiflash package.
Multiflash Asphaltene Optional add-on to Multiflash package.
PIPESIM Linux
Used only with Avocet IAM when
Computation Engines ECLIPSE Parallel and is run on a
Linux Cluster
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PIPESIM Introduction
Avocet Gas Lift
Optimization Module
Network Optimization option that
calculates the optimal gas lift
allocation to a network of gas lifted
wells
PIPESIM OLGAS
Steady State Flow
Correlation 2-Phase
Third-party 2-phase mechanistic
multiphase flow model
PIPESIM OLGAS
Steady State Flow
Correlation 3-Phase
Third-party 3-phase mechanistic
multiphase flow model
PIPESIM Rod Pump
Design / Optimization
Third-party module for designing rod
pumps
PIPESIM Rod Pump
Diagnostics
Third-party module for diagnosing rod
pump performance based on digitized
dynocards
PIPESIM DBR Wax
Deposition
Single-phase wax deposition model
embedded in PIPESIM using wax
properties characterized with the DBR
Solids application
DBR Solids – Wax
and Asphaltene
Precipitation
Standalone application that predicts
the wax and asphaltene precipitation
temperature
DBR Solids – Wax
Deposition
Characterization
Standalone application that
characterizes wax properties for use in
PIPESIM wax deposition
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Lesson 2
A Tour of the User Interface
The PIPESIM graphical user interface (GUI) allows you to easily
construct well and network models within a single environment. To
launch PIPESIM from the Start menu, select Program files >
Schlumberger > PIPESIM.
As shown in Figure 3, the PIPESIM interface consists of one main
window, a menu bar, a status bar, a standard toolbar and three
specific toolbars related to single branch and network modeling
views.
Figure 3
PIPESIM toolbars and menus
The Standard toolbar (Figure 4) contains common commands
that are displayed in both the single branch and network views.
The Single Branch toolbar (Figure 5) is displayed only in single
branch view, while the Network toolbar (Figure 6) and the Net
Viewer toolbar are displayed in the Network view.
You can hide the toolbars from view using the Menu bar.
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PIPESIM Introduction
Menu Bar
This has familiar Windows menus including File,
Edit, Help, and more. All the tools available in
other toolbars, plus all operations in PIPESIM.
Status Bar
The status of running operation. If there is no
operation running, it will show the path of model.
Standard
Toolbar
Available in both single branch and network model
and is comprised of the icons and processes
shown in Figure 4.
Figure 4
Single
Branch
Toolbar
Figure 5
Standard toolbar functionality
These tools (Figure 5) are available only in single
branch models or the network model in single
branch mode. It consists of all objects required to
build the physical model. These tools can also be
accessed from the Menu bar.
Single Branch toolbar
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Network
Toolbar
This toolbar (Figure 6) is available only in the
network model view. It consists of all objects
required to build the physical network model.
These tools can also be accessed from the menu
bar.
Figure 6
Network toolbar
NOTE: Icons in the Network toolbar and the Net Viewer bar
are not highlighted in the Single Branch model. Similarly,
icons in the Single Branch toolbar are not highlighted in
the network model.
From the Network model, you must access the Single
Branch viewing mode by double-clicking on the object to
insert necessary equipment, such as compressors,
pumps, chokes, and more.
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PIPESIM Introduction
Lesson 3
PIPESIM File System and
Calculation Engines
PIPESIM generates several input and output files in its working
directory when you run a model. The engines and file system are
listed here:
PIPESIM
Engines
PIPESIM
File System
•
PIPESIM uses one engine for a Single
Branch model and another engine for a
Network model.
•
Psimstub.exe is the PIPESIM engine for
single branch operations
•
Pnetsub.exe is the PIPESIM engine for a
network simulation
•
You can set or change the path of these
engines by selecting Setup > Preferences
> Choose Paths.
PIPESIM stores data in these formats:
•
ASCII files
•
Binary files
•
Microsoft Access database.
The file extensions are processed by the simulation engine to
create output files.
Extension
*.bps
Type of File
Single branch
model
PIPESIM file
Application Files
All the data necessary to run a model. Single
Branch model file includes data for units, fluid
composition, well IPR, system data, and more.
The support team requires these files when you
make support queries.
*.bpn
Network
model
PIPESIM file
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Same as above for a Network model.
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PIPESIM Introduction
Extension
*.out
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Type of File
Output file
Output Files
All output data in ASCII format. The output file is
produced from both Single Branch and Network
models. Node by node results are reported in output
files.
The output file is divided into sections. You have the
option to show or hide a section by using Setup >
Define Output.
Mostly, errors are reported in output file. Remember
to check this file in case of an error in a PIPESIM
model.
*.sum
Summary file
Summary report of PIPESIM output, such as
pressures and temperatures at sources and sinks.
Plot Files
*.plc
Profile plot
Variables you can plot with distance and elevation in
PsPlot. These variables include pressure,
temperature and fluid properties, and more.
PsPlot is a plotting utility in PIPESIM.
*.plt
System plot
Same as the *.plc file, but does not contain
variables such as distance and elevation. This file
is primarily used to see sensitivity of one variable to
another.
For example, you can plot water cut with system
outlet pressure.
Miscellaneous Files
*.psm
This is the keyword input file generated by the user
interface for the PIPESIM single branch engine
named psimstub.exe. In certain situations (mainly
debugging), this file can be manually modified via
expert mode.
*.tnt
All instructions sent to the PIPESIM network engine
- pnetstub.exe. The PIPESIM engine reads this file
for processing – not the *.bpn file.
*.mdb
Access
database file
Black oil fluid data, electric submersible pump (ESP)
performance curves, user-defined pump and
compressor curves, and pressure survey data.
You can access this file by selecting Setup >
Preferences > Choose Paths. You can set the
path of this file in the Data Source box.
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Extension
*.pvt
PIPESIM Introduction
Type of File
PVT file
Miscellaneous Files
A single stream composition and a table of fluid
properties for a given set of pressure and
temperature values.
If needed, this file can be created by a commercial
PVT package, such as Multiflash, Hysys,
DBRSolids or others, or using the Compositional
module in PIPESIM.
*.unf
Unit file
Stores user-defined unit sets, which can be passed
from user-to-user.
*.env
Phase envelope file
*.map
Flow regime map
Output Files
The PIPESIM output file is an ACSII format file, generated by
either a Single Branch or a Network model. This is a very large file
divided into many sections. You can customize the output report
by selecting Setup > Define output (Figure 7).
Figure 8 is a sample of the output from the primary output section.
Figure 7
Define Output tab
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Figure 8
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Sample output file (primary output section)
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PIPESIM Introduction
Lesson 4
Plots
Plots in PIPESIM are displayed with a plotting utility called PsPlot.
The path to the PsPlot executable is normally located in the
PIPESIM installation directory, such as C:\Program Files\Schlumb
erger\PIPESIM\Programs\PSPlotX.exe.
You can set the path of PsPlotX.exe by selecting Setup >
Preferences > Choose Paths. You can use PsPlot to open both
*.plc and *.plt files.
Optionally, you can view data in tabular mode (Figure 9) by
clicking on the Data tab.
Figure 9
Tabular view of PsPlot data
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You can change display settings of PsPlot, such as title, minimum
or maximum axis, color, legends and more, by selecting Edit >
Advanced Plot Setup (Figure 10).
Figure 10
20
Advanced Plot Setup dialog
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PIPESIM Introduction
Lesson 5
Single Branch Operations
There are many single branch operations available in PIPESIM
(Figure 11).
Figure 11
List of single branch operations
System Analysis
The systems analysis operation enables you to determine the
performance of a given system for varying operating conditions on
a case-by-case basis. Results of the system analysis operation
are provided in the form of plots of a dependent variable, such as
outlet pressure, versus an independent variable, such as flow
rate.
You can generate families of X-Y curves for the system by varying
either a single sensitivity variable (such as water cut) or by
applying permutations of a group of sensitivity values.
The ability to perform analysis by combining sensitivity variables
in different ways makes the system analysis operation a very
flexible tool for plotting data on a case-by-case basis.
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A typical plot resulting from a system analysis operation is shown
in Figure 12.
Figure 12
Typical System Analysis plot
Pressure/Temperature Profile
You can generate pressure and temperature profiles of the
system as a function of distance/elevation along the system.
Both temperature and pressure profiles are generated on a nodeby-node basis for the system.
NOTE: The system analysis operation also generates Pressure/
Temperature profile plots for each case. Likewise,
Pressure/Temperature Profile operations generate a
system plot.
Flow Correlation Comparison
Quickly compare various multiphase flow correlations against
measured data. The Data Matching operation introduced in
PIPESIM 2009.1 is recommended for regression of friction and
holdup multipliers to tune multiphase flow correlations to match
well test data.
Data Matching
Select parameters that will be automatically adjusted to match
measured pressure and temperature data for a particular system.
These parameters include multipliers for heat transfer coefficient
(to match temperature measurements), as well as friction factor
and holdup factor multipliers (to match pressure measurements).
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PIPESIM Introduction
This operation allows you to select and rank multiple flow
correlations, and to simultaneously match pressure and
temperature measurements.
NODAL Analysis
A common way to analyze well performance is through a NODAL
analysis plot to visually assess the impact of various system
components.
This is done by splitting the system at the point of interest known
as the NODAL analysis point and graphically presenting the
system response upstream (Inflow) and downstream (Outflow) of
the nodal point.
The point at which the inflow and outflow curves intersect is the
operating point for the given system, as shown in Figure 13.
Figure 13
NODAL analysis Inflow/Outflow curves
Optimum Horizontal Well Length
Predicts hydraulic well bore performance in the completion. The
multiple source concept leads to a pressure gradient from the
blind-end (toe) to the producing-end (heel) which, if neglected,
results in over-predicting deliverability.
The reduced drawdown at the toe results in the production
leveling off as a function of well length, and it can be shown that
drilling beyond an optimum length would yield no significant
additional production.
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Reservoir Tables
For the purposes of reservoir simulation, it is often necessary to
generate VFP curves for input to a reservoir simulation program.
The VFP curves allow the reservoir simulator to determine
bottomhole flowing pressures as a function of tubing head
pressure, flow rate, GOR, water cut and the artificial lift quantity.
The reservoir simulator interface allows you to write tabular
performance data to a file for input into a reservoir simulation
model. Currently, the following reservoir simulators are supported:
•
ECLIPSE
•
PORES
•
VIP
•
COMP4
•
MoReS (Shell’s in-house reservoir simulator).
Well Performance Curves
These can be created in the network solver to produce faster
solution times. A curve is created that represents the performance
of the well under specified conditions. The network solver will then
use this curve instead of modeling the well directly.
Gas Lift Rate vs. Casing Head Pressure
Determines the gas lift injection rate possible based on the casing
head pressure for a well.
Artificial Lift Performance
Analyzes the effects of artificial lift of a production well using either
gas lift or an electric submersible pump (ESP). The performance
curves allow for sensitivities on various parameters, including
wellhead pressure, water cut, tubing and flowline diameters.
Wax Deposition
With various deposition model/methods, generates wax
deposition profile (Distance vs. Wax deposition thickness) and
system (Wax Volume against time) plots.
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PIPESIM Introduction
Depending on selected methods, you must enter wax properties
or provide a properties file.
NOTE: The artificial lift operation is essentially a specific
implementation of the system analysis operation.
Review Questions
•
What is the basic premise of steady-state flow modeling?
•
What single branch operations are available?
Summary
In the module, you gained an understanding of PIPESIM toolbars,
file system and engines, and operations. You also learned about:
•
starting PIPESIM with a new or existing project
•
navigating and learn the user interface
•
viewing results in output file
•
displaying plots in PsPlot
•
selecting single branch options
•
identifying PIPESIM executables and data files.
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NOTES
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Simple Pipeline Tutorials
Module 2 Simple Pipeline Tutorials
The purpose of these tutorials is to familiarize you with the
PIPESIM Single Branch interface by building and running simple
examples. You begin by performing a simple hand calculation to
determine the pressure drop in a water pipeline, and then
construct a simple pipeline model to validate pressure drop along
a horizontal pipeline for a given inlet pressure and flow rate.
You will also run some sensitivity studies on the model.
Learning Objectives
After completing this module, you will know how to:
•
build the physical model
•
create a fluid model
•
choose flow correlations
•
perform operations
•
view and analyze results.
Lesson 1
Single-Phase Flow Calculations
Consider the case of a pipeline transporting water (Figure 14).
Figure 14
Pipeline transporting water
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The pressure change per distance L for single phase flow is given
by Bernoulli’s equation:
 dp 
 
 dL  total =
 dp 
 
 dL  frictional +
 dp 
 
 dL  elevational +
 dp 
 
 dL  accelerational
The accelerational term is normally negligible except for low
pressure and high velocity gas flow, although PIPESIM will always
calculate this term.
Assuming the accelerational term to be zero for your hand
calculation, the pressure gradient equation becomes:
fv 2
 dp 
 
 dL  total = 2 gd (frictional) - g sin  (elevational)
Where:
 = fluid density (lbm/ft3)
g = gravitational constant
f = moody friction factor
v = fluid velocity (ft/s)
d = pipe inside diameter (ft)
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Simple Pipeline Tutorials
Exercise 1
Modeling a Water Pipeline with
Hand Calculations
In this exercise, using the data in Table 1 and assuming the flow is
isothermal, you perform a hand calculation to determine the
delivery pressure of the pipeline using single-phase flow theory.
NOTE: You will need a hand calculator or MS Excel to complete
this exercise.
Table 1: Water Pipeline Modelling Data
Pipeline Data
Diameter
d
3
in
Length
L
20,025
ft
Elevation Change
Z
1,000
ft
Horizontal Distance
X
20,000
ft
Ambient Temperature
Tamb
60
degF
Inclination Angle
q
2.866
º
Roughness
e
0.0015
in
Relative Roughness
/d
0.0005
in
(= 0.25 ft)
(=.05002 radians)
Fluid Data
Water viscosity
w
1.2
cp
Water density
w
63.7
lbm/ft3
(= 8.06e-4 lb/ft-s)
Operating Data
Source Temperature
Tinlet
60
degF
Inlet Pressure
Pin
1,200
psia
Water Flow rate
Qw
6,000
BPD
(= 0.39 ft3/s)
Constants
Gravitational
g
32.2
ft/s2
TIP: To ensure unit consistency when performing hand
calculations, refer to the converted unit in the far right
column of the table.
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1. Calculate the water velocity:
v
Qw
2
 d 


 4  = _____________ ft/s
2. Calculate the Reynold’s number:
Re 
vd

= ______________
Is the flow laminar or turbulent? (See the Moody diagram,
Figure 15.)
3. Determine the friction factor using the Churchill equation for
turbulent flow.
NOTE: Alternatively, you can look up the friction factor using
the Moody diagram in Figure 15.
f = __________________________
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Figure 15
Simple Pipeline Tutorials
Moody diagram
4. Evaluate the frictional pressure term,
 dp 
 
 dL  friction
fv 2
2 gd
:
= __________ psf/ft
divide this by 144 to get_______ psi/ft
5. Multiply by the given length of pipe, L, to get the total
frictional pressure drop:
dp friction
= _____________ psi
6. Evaluate the elevational pressure term,  sin 
NOTE: If using Excel, be sure the angle is in radians.
dp friction
= __________ psf/ft
divide this by 144 to get________ psi/ft
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7. Multiply by the given length of pipe, L, to get the total
elevational pressure drop
dpelevation
= _____________ psi
8. Add the frictional and elevational terms to determine the total
pressure term:
 dp 
 dp 
 dp 
 
 
 
9.  dL  total =  dL  frictional +  dL  elevational
 dp 
 
 dL  total = ________ psi/ft
10. Multiply by the given length of pipe, L, to get the total
pressure drop
dptotal
= _____________ psi
11. Calculate the outlet pressure given the inlet pressure:
Pout = Pin -
Exercise 2
dptotal
= __________ psia
Modeling a Water Pipeline with
PIPESIM
In this exercise, you use PIPESIM to build the water pipeline you
hand calculated in . You will define parameters for each
component in the model, perform operations, view and analyze
the results, and compare PIPESIM results to your hand
calculations.
There are three parts to this exercise:
1. Starting the application
2. Creating the fluid model (water) and selecting flow
correlations
3. Building the physical model.
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Getting Started
To start the application:
1. Start PIPESIM by selecting Start > Program Files >
Schlumberger > PIPESIM.
2. Click NEW Single Branch Model….
3. From the Setup > Units menu, select the Eng(ineering)
units.
4. From the Setup > Define Output tab, uncheck all report
options except Primary Output and Auxiliary Output.
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Building the Physical Model (a Water Pipeline Model)
You begin by defining the physical components of the model.
1. Click Source
and place it in the window by clicking
inside the Single Branch window.
2. Click Boundary Node
3. Click Flowline
and place it in the window.
.
4. Link Source_1 to the End Node S1 by clicking and dragging
from Source_1 to the End Node S1.
NOTE: The red outlines on Source_1 and Flowline_1
indicate that essential input data is missing.
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5. Double-click Source_1 and the source input data user form
displays.
a. Fill in the form.
b. Click OK to exit the user form.
6. Double-click Flowline_1 and the input data user form is
displayed.
7. Fill the form as shown below, ensuring that the rate of
undulations = 0 (no terrain effects).
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8. Click the Heat Transfer tab and fill in the form for an
adiabatic process, as no heat was gained or lost between the
system and its environment.
9. Click OK to exit the user form and accept the overall heat
transfer coefficient (U value) defaults.
Creating the Fluid Model (Water) and Selecting Flow
Correlations
To create the fluid model and select flow correlations:
1. Select Setup > Black Oil to open the Black Oil Fluid menu.
2.
36
Fill in the Black Oil user form and click OK when you are
finished.
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Simple Pipeline Tutorials
3. Select File > Save As and save the model as
Exercise1_WaterPipe.bps.
4. From the Setup > Flow Correlations menu, select the Moody
single-phase flow correlation.
5.
Click OK.
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Performing Operations
PIPESIM Single Branch mode offers several simulation
operations, depending on the intended workflow. Many of these
operations are explained in the exercises that follow.
The Pressure/Temperature Profile operation is used to acquire
the distribution of pressure, temperature and many other
parameters across the flow path.
To perform these operations:
1. In the Operations menu, select the Pressure/Temperature
Profile operation.
NOTE: The Pressure Temperature Profile operation requires
that you designate a calculated variable and specify
all other variables. Generally, two specifications are
provided for use with the rate, inlet pressure and
outlet pressure, while the third is calculated.
However, all three can be specified and a forth
variable will be calculated, for example choke size.
2. Enter the known flowing conditions.
3. Click Run Model. The pressure calculation uses the Moody
correlation (default single-phase correlation).
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4. View and analyze the results. The pressure profile below
should be visible upon completion of the run.
5. To display a tabular output of the Pressure/Temperature
profile, click the Data tab at the top of your graph. Notice that
the outlet pressure is 89 psia.
6. (Optional) Copy this data into Excel:
a. Highlight the cells of interest.
b. Press Ctrl + C.
c. Select a cell in Excel and press Ctrl + V.
d. To view an abbreviated form of the full output file, select
Reports > Summary File.
You can observe the output:
The Liquid holdup value displayed (175 bbl) is the total liquid
volume for the entire pipe.
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7. The Summary file reports the frictional and elevational
components of the total pressure change in the pipeline.
Compare the results of PIPESIM to your hand calculations by
entering the appropriate values in the table.
Result
Hand
Calculation
PIPESIM
Liquid Velocity (ft/s)
∆Pfrictional (psi)
∆Pelevational (psi)
∆Ptotal (psi)
Outlet Pressure (psia)
8. View the output file by selecting Reports > Output File. By
default, the output file is divided into five sections:
• Input Data Echo (Input data and Input units summary)
• Fluid Property Data (Input data of the fluid model)
• Profile and Flow Correlations (Profile and selected
correlations summary)
• Primary Output
• Auxiliary Output.
NOTE: If the units reported in the output file are not the
desired ones, you should change the units (Setup >
Units), pick the preferred unit system, and rerun the
simulation.
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The Primary Output File
The primary output is shown in Figure 16.
Figure 16
Example of the primary output file
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The primary output contains 17 columns:
•
Node number: node at which all the measures on the row
have been recorded. (The nodes have been spaced by
default with a 1,000 foot interval)
•
Horizontal Distance (cumulative horizontal component of
length)
•
Elevation (absolute)
•
Angle of inclination (from the horizontal)
•
Angle of inclination (from the vertical)
•
Pressure
•
Temperature
•
Mean mixture velocity
•
Elevational pressure drop
•
Frictional pressure drop
•
Actual Liquid flow rate at the P,T conditions of the node
•
Actual Free gas rate at the standard P,T conditions of the
node
•
Total Mass flow rate of the node
•
Actual Liquid density at the P,T conditions of the node
•
Actual Free gas density at the P,T conditions of the node
•
Slug Number
•
Flow Pattern.
Notice that, as the pressure decreases, the liquid density
decreases, therefore the velocity must increase to maintain a
constant mass flow rate.
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The Auxiliary Output File
The auxiliary output is shown in Figure 17.
Figure 17
Example of the auxiliary output file
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The auxiliary output consists of 19 columns:
•
Node number
•
Horizontal distance (cumulative)
•
Elevation (absolute)
•
Superficial liquid velocity
•
Superficial gas velocity
•
Liquid mass flow rate
•
Gas mass flow rate
•
Liquid viscosity
•
Gas viscosity
•
Reynolds number
•
No-slip Liquid Holdup Fraction
•
Slip Liquid Holdup Fraction
•
Liquid Water cut
•
Fluid Enthalpy
•
Erosional Velocity ratio
•
Erosion rate (if applicable)
•
Corrosion rate (if applicable)
•
Hydrate temperature sub-cooling (if applicable)
•
Liquid Loading Velocity Ratio (if Applicable).
TIP: The values of the Reynolds number indicate that the flow
regime is turbulent (NRE > 2000) and are consistent with
the results of the hand calculations.
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Exercise 3
Simple Pipeline Tutorials
Analyzing Multiple Scenarios with
Sensitivities
In this exercise, you will continue using the previous example to
explore how your model responds to different inlet temperatures.
You will set a range of temperatures, perform operations, and
view and analyze your results.
To modify the P/T profile operation and view the output:
1. From the Operations menu, select the Pressure/Temperature
Profile Operation.
a. Select Source_1 as the Object and Temperature as the
Variable. In the Pressure/Temperature Profile user form,
click
.
b. Fill in the input form, as shown.
c. Click Apply and close the Set Range window. The
completed form is shown in the figure.
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2. Click Run Model.
The pressure calculation uses the Moody correlation (Default
single phase correlation).
3. Observe the PsPlot output. This pressure profile should be
visible upon completion of the run.
Notice that the highest inlet temperature generates the
lowest pressure drop. As the temperature increases:
• the viscosity decreases
• the Reynolds number increases
• the corresponding friction factor decreases
• the frictional pressure gradient is lower.
In other words,
T ↑ »  ↓ »
Re 
vd
 ↑ »f↓»
 dp 
 
 dL  friction ↓
NOTE: In the case of water, the effect of the temperature on
the density is negligible, as water is essentially an
incompressible fluid.
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4. Select the Data tab in the Plot window to see all the data for
each temperature in a tabular format.
5. Open the output file (*.out). The output file can be opened in
one of two ways:
Click the Output File button from within the Operations
(Pressure/Temperature Profiles) dialog:
OR
Select Reports > Output File.
By default, the output file contains the information for the first
case only. (T = 20 degF).
6. To report all sensitivity cases:
a. Select Setup > Define Output.
b. Ensure that options are selected as shown in the figure.
c. Set the number of cases to print to 4.
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7. Rerun the operation.
TIP: If you do not change the operation or alter any of the
parameters within the Operations menu, you can run
the simulation by clicking Run
.
8. Open the output report to view the results of the four
sensitivity cases.
9. To add segment data to your report, select Setup > Define
Output and check the Segment Data in the Primary Output
option.
10. Re-run the operation.
11. Open the output file and observe that additional segments
have been inserted.
NOTE: By default, PIPESIM performs the pressure drop
calculation for each of those additional segments to
obtain precise averaged values of properties, such
as liquid holdup or velocities at the main nodes.
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Exercise 4
Simple Pipeline Tutorials
Modeling a Single-Phase Gas
Pipeline
In this exercise, you investigate the flow of a single phase gas
without changing the physical components of our previous
example.
To investigate the flow of a single phase gas:
1. Select Setup > Black Oil and modify the user form, as
shown in the figure. This represents 100% gas
a. Change Water Cut to WGR and GOR to OGR.
b. Set values for WGR and OGR as 0.
c. Rename the fluid as gas.
2. Under the Setup > Define Output menu, uncheck the box
labeled Segment Data in Primary Output.
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3. Select Operations > Pressure/Temperature Profile and
modify the Pressure/Temperature profile operation.
4. Click Run Model. As for the case of a single-phase liquid,
the pressure calculation will be done using the Moody
correlation.
5. Inspect the pressure profile plot upon completion of the run.
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In the previous example using water, the density remained
constant because water is essentially incompressible. However,
gas is a compressible fluid with a density described by the ideal
gas law, rearranged into the following expression:
g 
pM
zRT
Where:
g = gas density
p = pressure
M = Molecular Weight
z = gas compressibility factor
R = ideal gas constant
T = Temperature
Notice that the highest inlet temperatures yield the highest
pressure drop. This is because, as the temperature increases the
density decreases, which results in a decrease in the Reynolds
number.
Correspondingly, the friction factor increases and, as a result, the
frictional pressure gradient is higher. In other words,
T ↑ » g ↓ »
Re 
 dp 
 vd
 
 ↓ » f ↑ »  dL  frictiona↑
Also, because
fv 2
 dp 


 dL  friction = 2gd
the velocity increase due to gas expansion has an exponential
effect on the frictional pressure term. This accounts for the
increase in the frictional gradient along the flowline and the
curvature in the pressure profile plot.
NOTE: The viscosity of the gas increases slightly with
increasing temperature, but this effect is small and does
little to offset the effects of decreasing density.
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Exercise 5
Calculating Gas Pipeline Flow
Capacity
In the previous exercises, you calculated the outlet pressure given
a known inlet pressure and flow rate. In this exercise, you specify
known inlet and outlet pressures and calculate the corresponding
gas flow rate.
There are three key variables involved in Single Branch
operations:
•
Inlet pressure
•
Outlet pressure
•
Flow rate.
Two of these variables must be specified but the third is
calculated. Some operations allow you to specify all three
variables, in which case a matching variable, such as pump speed
or choke setting, must be specified.
PIPESIM generally performs calculations in the direction of flow.
Therefore, when the outlet pressure is calculated, as in the
previous examples, the solution is non-iterative in that the outlet
pressure is calculated during the first and only pressure traverse
calculation.
However, when outlet pressure is specified and either the inlet
rate or the flow rate is calculated, the process becomes iterative,
and successive estimates of the calculated variable are supplied
until the calculated outlet pressure agrees with the specified
pressure.
To calculate gas deliverability:
1. Open the Pressure/Temperature Profiles user form and
select Gas Rate as the calculated variable.
2. Specify 600 psia for the outlet pressure.
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3. Clear the temperature sensitivity values, shown in the figure,
by highlighting the cells and pressing Ctrl + X.
4. Click Run Model on the user form.
5. Observe the PsPlot output.
The gas flow rate corresponding to the specified pressure drop
is shown in the legend beneath the profile plot.
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6. Observe the output files (*.out). The iteration routine for this
operation can be seen in the output file, as shown below.
NOTE: To view this report, you must check Iteration
Progress Log under Setup/Define Output)
7. Save your file as exer5.bps.
Lesson 2
Multiphase Flow Calculations
While pressure losses in single-phase flow in pipes have long
been accurately modeled with familiar expressions such as the
Bernoulli equation, accurate predictions of pressure loss in twophase flow have proved to be more challenging because of added
complexities.
The lower density and viscosity of the gas phase causes it to flow
at a higher velocity relative to the liquid phase, a characteristic
known as slippage. Consequently, the associated frictional
pressure losses result from shear stresses encountered at the
gas/liquid interface as well as along the pipe wall. Additionally, the
highly compressible gas phase expands as the pressure
decreases along the flow path.
Further complicating matters are the variety of physical phase
distributions that are characterized by flow regimes or flow
patterns (Figure 18 and Figure 19). The prevailing flow pattern for
a specific set of conditions depends on the relative magnitude of
the forces acting on the fluids.
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Buoyancy, turbulence, inertia, and surface-tension forces are
greatly affected by the relative flow rates, viscosities, and
densities of a fluid, as well as the pipe diameter and inclination
angle. The complex dynamics of the flow pattern govern slippage
effects and, therefore, variations in liquid holdup and pressure
gradient.
Figure 18
Multiphase flow regimes for horizontal flow
Figure 19
Multiphase flow regimes for vertical flow
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Many empirical correlations and mechanistic models have been
proposed to predict liquid holdup and pressure loss. (Refer to the
PIPESIM help system for details). Some are very general, while
others apply only to a narrow range of conditions.
Many of these approaches begin with a prediction of the flow
pattern, with each flow pattern having an associated method of
predicting liquid holdup.
Because the gas travels faster in steady-state flow, it will occupy
less pipe volume. The fraction of pipe volume occupied by the
liquid is called the liquid holdup and is illustrated in Figure 20.
Liquid holdup is generally the most important parameter in
calculating pressure loss. Liquid holdup is also necessary to
predict hydrate formation and wax deposition and to estimate the
liquid volume expelled during pigging operations for sizing slug
catchers. The liquid holdup prediction is used to determine a twophase friction factor from which a pressure gradient is calculated.
Figure 20
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Liquid Holdup
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Exercise 1
Simple Pipeline Tutorials
Modeling a Multiphase Pipeline
The previous exercises explored single-phase flow of water and
gas through a pipeline. In this exercise, you modify the existing
pipeline model and explore multiphase flow.
1. Insert Report Tool
flowline, as shown.
at the beginning and end of the
2. Click on the flowline to highlight the object and drag the tip
connected to the source to the first Report icon.
3. Release the mouse button when the arrow is on top of the
Report Tool icon and the flowline turns yellow.
4. Repeat the previous step for the second Report Tool icon.
5. Select Connector
the Source icon.
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6. Select the Boundary node and press the Delete key. Your
model should now displays as shown below:
7. Double-click on each of the Report Tool icons and enter the
data shown in the figure.
8. Double-click on the Flowline and select the Heat Transfer
tab.
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9. Choose the typical Heat Transfer Coefficient value for bare
pipe exposed to air, as shown below.
10. Select Setup > Black Oil and specify the fluid properties.
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11. From the Setup > Flow Correlations menu, select Beggs
and Brill Revised (Taitel-Dukler map) for the horizontal flow
correlation and Hagedorn and Brown for the vertical flow
correlation.
NOTE: Observe that the Swap angle is set to 45º. This is the
angle that corresponds to the switch between use of
the vertical and horizontal flow correlation. In this
example, the pipeline inclination angle is about 3º,
which means that only the horizontal flow correlation is
used.
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12. Double-click on Source_1 and change the pressure to 4800
psia.
13. Select Operations > Pressure Temperature Profiles and
enter the information.
NOTE: The pressure drop is calculated using the Moody
correlation (default single-phase correlation) and the
Beggs and Brill Revised correlation.
The results from the Taitel-Dukler Flow Regime map
will be reported and will influence the pressure drop
calculations performed by the Beggs and Brill
Revised correlation if the flow regime is different from
that predicted by the Beggs and Brill correlation.
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14. Run the model.
15. Observe the pressure profile plot.
16. From the Reports menu, open the output file. The following
display can be seen in the primary output section of the
output file.
Notice that the flow is initially single-phase liquid until the
pressure falls below the bubblepoint upon which two-phase
oil-gas flow is present. The single-phase Moody correlation is
used in the first part of the pipe, and the Beggs and Brill
multiphase correlation is used in the second part of the pipe
after the pressure falls below the bubblepoint.
TIP: The holdup for each of the segment can be seen in the
auxiliary output.
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The number in the far right column is the Erosional Velocity
Ratio (EVR = actual velocity/API 14e limit) and is displayed
only when it is higher than 1.
The spot reports output is shown in Figure 21.
NOTE: To view the graphics and output in SI or Custom units,
specify the units via the Setup > Units… option and
rerun the model.
Figure 21
Sample spot report output
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The flow regime map (Figure 22) can also be viewed in PsPlot by
selecting Reports > Flow Regime Map.
Figure 22
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Flow regime map
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Review Questions
•
Which types of pressure drop contributions are reported by
PIPESIM in output file (by default)?
•
What is the default single-phase flow correlation in
PIPESIM?
•
How do you describe a Black Oil fluid model for water or dry
gas?
•
Did you get any difference in pressure drop between hand
calculation and PIPESIM reported results? If yes, why?
Summary
In this module, you learned about:
•
building the physical model
•
creating a fluid model
•
choosing flow correlations
•
performing operations
•
viewing and analyzing results.
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NOTES
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Oil Well Performance Analysis
Module 3 Oil Well Performance
Analysis
This module examines a producing oil well located in the North
Sea. You analyze the performance of this well using NODAL
analysis, calibrate black oil fluid (low GOR) using laboratory data,
and match flow correlations with pressure survey data.
You will also analyze the behavior of the well with increased water
cut and find an opportunity to inject gas at a later stage when the
well is unable to flow naturally.
Learning Objectives
After completing this module, you will know how to:
•
perform a NODAL analysis
•
estimate bottomhole flowing conditions
•
calibrate pressure, volume and temperature (PVT) data
•
perform flow correlation matching
•
perform inflow performance relationship (IPR) matching
•
conduct water cut sensitivity analysis
•
evaluate gas lift performance
•
install a flow control valve.
Lesson 1
NODAL Analysis
NODAL analysis evaluates the performance of an oil well. You
specify a nodal point, usually at the bottomhole or wellhead, and
divide the producing system into two parts: the inflow and the
outflow. This is represented graphically in Figure 23.
The solution node is defined as the location where the pressure
differential upstream (inflow) and downstream (outflow) of the
node is zero. Solution nodes can be judiciously selected to isolate
the effect of certain variables.
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For example, if the node is taken at the bottomhole, factors that
affect the inflow performance, such as skin factor, can be
analyzed independently of variables that affect the outflow, such
as tubing diameter or separator pressure.
Nodal Analysis
Psep
PR
Inflow
Outflow
Pwf
Pwf
PR
Psep
17
Figure 23
Flow rate
Intersection points of the inflow and outflow
performance curves
Getting Started
Before beginning an oil well performance analysis:
1. Select File > New > Well Performance Analysis.
2. From Setup > Units, set the engineering units.
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Exercise 1
Oil Well Performance Analysis
Building the Well Model
Model building refers to setting up all objects, from the source to
the sink, and defining the properties of these objects. You can
select PIPESIM single branch objects using either the Tool menu
or the toolbar at the top of PIPESIM window.
To build the well model:
1. Click Vertical Completion
on the single branch toolbar
to choose a vertical completion object and place it in the
Single Branch flow diagram.
2. Click Boundary Node
the flow diagram.
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3. Click Tubing object
and connect VertWell_1 to the End
Node S1 by clicking and dragging from VertWell_1
completion to the End Node S1.
NOTE: The red outlines on VertWell_1 and Tubing_1 indicate
that essential input data are missing.
4. Double-click on the completion and enter the properties
listed in the table.
Reservoir and Inflow Data
70
Completion model
Well PI
Use Vogel?
Yes
Reservoir Pressure
3,600 psia
Reservoir Temperature
200 degF
Liq. Productivity Index
8 stb/d/psi
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Oil Well Performance Analysis
5. Double-click on the tubing object and enter the tubing
properties based on data listed in the tables.
Deviation Data
Measured Depth (ft)
True Vertical Depth (ft)
0
0
1,000
1,000
2,500
2,450
5,000
4,850
7,500
7,200
9,000
8,550
Geothermal Gradient
Measured Depth (ft)
Ambient Temp. (degF)
0
50
9,000
200
Tubing Data
Bottom MD (ft)
Internal Diameter (inches)
8,600
3.958
9,000
6.184
6. Specify an Overall Heat Transfer Coefficient = 5 btu/hr/ft 2/F
(override the default value).
NOTE: Use the overall heat transfer coefficient to calculate
total heat transfer through the pipe wall. The overall
heat transfer coefficient depends on the fluids and their
properties on both sides of the wall, as well as the
properties of the wall and the transmission surface.
7. Click the Summary table button to observe the configuration
summary.
8. Set the Distance between nodes to 100 ft.
9. Select Setup > Black Oil.
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10. Enter the fluid properties, as shown in the table. Assume
default PVT correlations and no calibration data.
Black Oil PVT Data
Water Cut
10 %
GOR
500 scf/stb
Gas SG
0.8
Water SG
1.05
Oil API
36 ºAPI
The fluid physical properties are calculated over the range of
pressures and temperatures encountered by the fluid and
used by multiphase flow correlations to determine the phases
present, the flow regime, and the pressure losses in single and
multiphase flow regions.
NOTE: The heat transfer calculations use the fluid thermal
properties.
11. From the Setup > Flow Correlation menu, ensure that the
Hagedorn-Brown correlation is selected for vertical flow and
the Beggs-Brill Revised correlation is selected for horizontal
flow.
Select the correlation that is best suited for the fluid and
operating conditions of interest.
NOTE: There is no universal rule for selecting a multiphase
flow correlation that is good for all operating scenarios.
See the PIPESIM help system for information on the
applicability of flow correlations.
12. Save the model as CaseStudy1_Oil_Well.bps.
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Oil Well Performance Analysis
Exercise 2
Performing NODAL Analysis
In this exercise, you perform a NODAL analysis operation for a
given outlet (wellhead) pressure to determine the operating point
(intersection) and the absolute open flow potential (AOFP) of the
well.
To do this, add a NODAL analysis point at the bottomhole to
divide the system into two parts. Part A extends from reservoir to
the bottomhole, while Part B runs from the bottomhole to the
wellhead.
To perform a NODAL analysis:
1. Select a NODAL analysis point from the toolbar and drop it
near the completion.
2. Click on the tubing and drag its bottom tip over to the NODAL
analysis point.
3. Insert a connector to link the completion with the NODAL
analysis point.
N.A. Point
4. Select Operations > NODAL analysis.
5. Enter an Outlet Pressure (Boundary Condition) of 300 psia.
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6. Leave Inflow Sensitivity and Outflow Sensitivity empty.
TIP: For users having PIPESIM 2009.1 or older versions:
Increasing the number of points in inflow and outflow
curves provides more detailed curves from which a
more accurate intersection can be read. Click Limits in
the Nodal Analysis window to change the number of
points in inflow and outflow curves.
PIPESIM 2010.1 has implemented several modifications in
Nodal Analysis calculation. The most significant is displaying
the intersection point on the nodal plot. As a result, you do
not depend on reading from the plot and the solution points
are calculated with the values presented in Data tab.
TIP: There is no need to specify/change number of points for
inflow and outflow curve unless you wish to use those
data for further processing. The PIPESIM engine
automatically determines the number of points and their
spacing for both inflow and outflow curves.
7. Run the model.
8. Inspect the plot and select the Data tab to determine the
answers.
Results
(Outlet) Wellhead Pressure
300 psia
Operating Point Flow rate
Operating Point BHP
AOFP
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Exercise 3
Oil Well Performance Analysis
Performing a Pressure/
Temperature Profile
The Pressure/Temperature profile calculates pressure and
temperature on a node-by-node basis for the system. The results
are plotted for pressure or temperature as a function of distance/
elevation along the flow path.
To estimate bottomhole flowing conditions:
1. Run Operations > Pressure / Temperature Profile.
2. Enter the Outlet (Tubing head) pressure of 300 psia.
3. Specify the liquid rate as the calculated variable.
4. Leave Sensitivity Data empty.
NOTE: Inlet and outlet pressure always reference the
boundaries of the system. In this particular case, inlet
pressure is the reservoir pressure, while the outlet
pressure corresponds to wellhead pressure. The inlet
pressure is specified at the completion or source
level, whereas the outlet pressure is always specified
manually within the operation.
5. Run the model.
NOTE: PIPESIM 2010.1 generates a Profile plot for every
valid combination of inflow-outflow cases. Because
of this, there is no need to run a separate Pressure
Temperature Profile operation.
6. Inspect the plot and summary output report to determine
answers.
Results
Wellhead Pressure
300 psia
Production Rate
Flowing BHP
Flowing WHT
Depth at which gas appears
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Questions
These questions are for discussion and review.
•
What is the significance of intersection between the inflow
and outflow curves?
•
What are the advantages/disadvantages of performing a
Pressure/Temperature Profile versus a NODAL analysis?
Lesson 2
Fluid Calibration
Fluid properties (also known as PVT properties) are predicted by
correlations developed by fitting experimental fluid data with
mathematical models. Various correlations have been developed
over the years based on experimental data sets covering a range
of fluid properties.
The PIPESIM help system describes the range of fluid properties
used to develop each correlation, which helps you select the most
appropriate correlation for the fluid at hand. The default
correlations in PIPESIM are based on the overall accuracy of the
correlations as applied to a broad range of fluids.
To increase the accuracy of fluid property calculations, PIPESIM
provides functionality to match PVT fluid properties with laboratory
data. Calibration of these properties can greatly increase the
accuracy of the correlations over the range of pressures and
temperatures for the system being modeled.
For example, calibration of the bubblepoint pressure can result in
the initial appearance of gas at a depth of perhaps a thousand feet
higher or lower than an uncalibrated model. This results in a
significantly different mixture fluid density and, thus, a much
different elevational pressure gradient.
Likewise, calibration of the fluid viscosity can drastically improve
the calculation of the frictional pressure gradient, especially in
heavy oils and emulsions.
If the calibration data is omitted, PIPESIM calibrates on the basis
of oil and gas gravity alone, resulting in a loss of accuracy.
After the calibration is performed, a calibration factor calculated as
ratio of measured value to the value calculated by selected
correlation.
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Oil Well Performance Analysis
There are two calibration options available in PIPESIM:
•
Single Point calibration
•
Multi-Point calibration.
Single Point Calibration
In many cases, actual measured values for some properties show
a slight variance from calculated values. When this occurs, it is
useful to calibrate the property using the measured point.
PIPESIM can use the known data for the property to calculate a
calibration constant Kc;
Kc = Measured Property @(P,T)/Calculated Property @(P,T)
This calibration constant is used to modify all subsequent
calculations of the property in question, that is:
Calibrated value = Kc (Predicted value)
Multi-Point Calibration
In multi-point calibration, black oil correlations are tuned so that
the correlation honors all data points (Figure 24).
Figure 24
Correlation running through all data points
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A calibration factor is calculated for every measurement point, and
a plot is generated for the Pressure vs. Calibration factor, as
shown in Figure 25.
Figure 25
Pressure vs. Calibration factor
NOTE: This is not a best fit method, as all points are fitted
exactly. Any outlying data should be smoothed before
entering it into PIPESIM.
Exercise 1
Calibrating PVT Data
To calibrate PVT data:
1. From Setup > Black Oil, select the Viscosity Data tab.
2. Enter the following calibration data:
3. Under Dead Oil Viscosity, select User’s 2 Data points as the
correlation.
4. Enter the following measurements:
Dead Oil Viscosity Measurements
Property
Viscosity
Temperature
(degF)
Value
200
1.5 cp
60
10 cp
5. For Live Oil Viscosity, ensure that the Chew and Connally
correlation is selected.
6. For the Emulsion Viscosity Method, select the Brinkman
1952 correlation.
7. For the Undersaturated Oil Viscosity, select the BergmanSutton correlation.
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8. Select the Advanced Calibration Data tab and click SinglePoint Calibration.
9. Enter the measured data to calibrate the PVT model.
PVT Calibration Data
Range
Property
Value
Pressure
(psia)
Temp
(degF)
P > Pb
OFVF
1.18
3,000
200
P = Pb
Sat. Gas
500 scf/stb
2,100
200
P <= Pb
OFVF
1.22
2,100
200
Live Oil Viscosity
1.1 cp
2,100
200
Gas viscosity
0.029 cp
2,100
200
Gas Z factor
0.8
2,100
200
10. Select the following PVT correlations:
Property
Correlation
Saturated gas
Lasater
OFVF at / below bubblepoint
Standing
Live oil viscosity
Chew and Connally
Gas Z
Standing
11. From the Advanced Calibration Data tab, select Plot PVT
Data (Laboratory Conditions GOR = GSAT) to generate a
plot of the PVT properties for various pressures and
temperatures.
12. Select Series and change the y-axis to Oil Formation Volume
Factor.
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13. Verify that the predicted values match the calibration points.
14. Repeat steps 12 and 13 for Oil viscosity and Gas viscosity to
ensure the predicted values are correct.
NOTE: Dead Oil conditions are at 14.7 psia.
Notice that the predicted oil viscosity value at a temperature
of 60 degF and 14.7 psia is 10.0 P, consistent with the
laboratory dead oil data.
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15. Now that the fluid model is calibrated, rerun the PressureTemperature Profile.
16. Determine the flowing bottomhole pressure, flowing wellhead
temperature, and production rate for the given wellhead
pressure.
17. Compare your answers to the uncalibrated model results in .
18. Inspect the plot and summary output to determine answers.
Results
Wellhead Pressure
Calibrated
Uncalibrated
Production Rate
Flowing BHP
Flowing WHT
Depth where gas appears
GOR Property Definitions
The quantity defined by PIPESIM as 'stock tank' GOR is actually
the produced GOR, a dynamic property. The solution gas GOR
calibration, an intrinsic property, is specific to the reservoir oil at
reservoir conditions and is obtained through laboratory
experiments.
The solution gas liberated at standard conditions is called the
associated gas. Produced gas can also include a contribution
from the gas cap, otherwise known as free gas. In other words:
Produced gas = associated (solution) gas + free gas.
If free gas is produced, the produced GOR will be higher than the
solution GOR and, therefore, the calculated bubblepoint based on
the specified produced GOR will be higher than that defined by
the solution GOR calibration point.
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Lesson 3
Pressure/Temperature
Matching
The pressure distribution of the fluid as it flows though the tubing
is very important in production engineering tasks such as
selecting tubing sizes, forecasting well productivity, and designing
artificial lift installations.
Pressure distribution along particular tubing can be obtained from
actual measurements taken with pressure gauges using wireline/
slickline at different depths in the well while it is flowing at a
constant rate. The result of this measurement is a plot of fluid
pressure along tubing versus vertical depth, called a Flowing
Gradient survey (FGS) and shown in Figure 26.
Figure 26
Flowing Gradient survey
When an FGS is available, it is always best to compare different
multiphase flow correlations with the FGS, to determine the one
that best matches the FGS.
Additionally, the correlation can be tuned to more accurately
match the data. Optimization routines in PIPESIM allow the
PIPESIM Single Branch engine to calculate optimal values of
parameters to match measured pressure and/or temperature
data. The match is performed by tuning parameters, such as
friction and hold-up factor multiplier for pressure matching, and a
U-factor multiplier for temperature matching. After the model is
tuned, you should validate it against test data measured at
different conditions.
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WARNING: Avoid using large tuning factors. The recommended
tuning range of friction and holdup factor multipliers
are +/- 15% (such as 0.85 - 1.15). If it needs > -/+
15% to match the actual measured data, you should
review the data again. Large adjustments in friction
and holdup factors could also be due to poor fluid
characterizations.
Exercise 1
Flow Correlation Matching
An FGS is available for this well. In this exercise, you use the
measured data to select the most appropriate vertical flow
correlation.
To perform a flow correlation match:
1. Select Data > Load/Add Measured Data.
2. Click New.
3. Enter the test data, as shown.
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4. Click Save Changes.
5. Go to Operations > Data Matching and enter the range of
calibration factors, as shown in the figure.
NOTE: You can uncheck the calibration factor for horizontal
flow as there is no horizontal flow in this model.
6. Click the Flow Correlation tab and select some of the
vertical multiphase flow correlations, as shown below.
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7. Go to the Run tab and specify the given Outlet Pressure
(Wellhead) and Liquid Rate.
8. Select the Inlet Pressure as the calculated variable and click
Run model.
9. View the results in Data Matching window to determine
which flow correlation agrees most closely with the
measured data.
10. Select the best correlation and click Save Selected Results
to update the model with this correlation and the matched
values for the friction factor, holdup factor, and U-Value
multipliers.
NOTE: Weighting factors are used to set the relative
importance of the pressure and temperature error
terms if both pressure and temperature data have
been specified.
Results
Best Vertical Correlation
Flowing BHP
Head Factor Multiplier
Friction Factor Multiplier
U Factor Multiplier
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Exercise 2
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Matching Inflow Performance
It is known from a pressure gradient survey that this particular well
can flow 6,500 bbl/d of liquid against 300 psia of wellhead
pressure. Using the correct flow correlation from the previous
exercise, run the Pressure/Temperature profile to determine how
much this well can produce for the same boundary conditions.
If the calculated flow rate is different from measured flow rate
(6,500 bbl/d), it is time to determine the Productivity Index (PI) that
matches the test data.
In this exercise, you also determine the absolute open flow
potential (AOFP) of the well with the new PI, given a reservoir
pressure known to be 3,600 psia.
TIP: The Productivity Index (PI) is expected to be in the range
from 5 to10 stb/d/psi.
To perform the IPR matching:
1. Select Operations > Pressure/Temperature Profile.
2. Enter the Outlet Pressure and the Liquid Rate.
3. Select the User variable as the calculated variable and click
Define.
4. Select Object VertWell_1 and the Variable Productivity Index.
5. Enter the expected range of PI and click OK.
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6. Run the model and review the PsPlot for calculated Liquid PI.
WARNING: Update the PI for the completion with the matched
value.
Results
Matched PI
STB/d/psi
Questions
These questions are for discussion and review.
•
What is the minimum data requirement for black oil fluid model
in PIPESIM?
•
How can you use lab PVT data to improve black oil
correlations?
•
Which data should you use in black oil calibration, - flash or
differential?
•
What components of the pressure drop are reported by
PIPESIM?
•
What is the recommended way of selecting a multiphase
correlation in PIPESIM?
•
What is the role of the pressure loss in the completion during
flow correlation matching?
Lesson 4
Well Performance Analysis
After you define the well and fluids descriptions and match them to
generate an accurate model for the well, several simulation
operations can be performed to evaluate a variety of operating
scenarios.
Conducting a Water Cut Sensitivity Analysis
After an initial design has been made, it is important to evaluate
how the system will respond to changing operating conditions.
Increase in water production in the late life of oil and gas fields is
inevitable, whether because of water injection or water coning.
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Using the wellhead pressure and reservoir pressure from the
previous exercise, determine the highest possible water cut this
well will produce.
NOTE: Change the completion PI in the well model from the
previous exercise.
There are two methods available to solve this problem - Method A:
System analysis and Method B: NODAL analysis.
Method A – System Analysis
To run a System analysis:
1. Select Operations > System Analysis and enter the Outlet
Pressure.
2. Calculate the liquid rate.
3. For the X-axis variable, select Fluid Data.
4. Enter the water cut values of 30 to 70% in increments of 5%.
5. Leave Sensitivity Variable 1 empty.
6. Run the model to generate a plot of calculated liquid rate vs.
water cut.
7. Interpolate to identify the limiting water cut at which the
production rate continues to be calculated.
NOTE: You may need to rerun the model using finer
sensitivity values for the water cut.
Method B – NODAL Analysis
To run a NODAL analysis:
1. Go to Operations > NODAL analysis.
2. Enter the Outlet Pressure.
3. Leave Inflow Sensitivity empty.
4. Enter the water cut values of 30 to 70% in increments of
5%.
5.
Click the Limits button and change the number of outflow
points to display to 50.
6. Run the model to generate the NODAL analysis plot.
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7. Identify the lowest water cut for which there is no solution
point.
NOTE: You may need to rerun the model using finer sensitivity
values for the water cut.
Results
Critical Water Cut
Exercise 1
Evaluating Gas Lift Performance
The basic principle behind gas lift injection in oil wells is to lower
the density of the produced fluid in the tubing. This results in a
reduction of the elevational component of the pressure gradient
above the point of injection and a lower bottomhole pressure.
Lowering the bottomhole pressure increases reservoir drawdown
and, thus, production rate.
In this exercise, you examine how this well responds to gas lift by
introducing a Gas Lift Injection point at 8,000 feet MD in the tubing
equipment.
You have two tasks to accomplish:
•
Determine how the well responds to gas lift when the water
cut is 10% and 60%.
•
Determine the liquid production rates as a function of the gas
lift rate and water cut. Refer to Table 2 for specific values.
Table 2: Gas Lift Data
Wellhead Pressure (psia)
300
Injection Gas SG
0.6
Injection Gas Surface Temp (degF)
100
To evaluate gas lift performance:
1. Double-click on Tubing and select the Downhole Equipment
tab.
2. Under Equipment, select Gas Lift Injection and specify a
depth of 8000 ft. MD.
3. Click Properties.
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4. Enter a default gas lift rate of 1 mmscf/d.
5. Go to Operations > Artificial Lift Performance and enter
the Outlet Pressure.
6. For Sensitivity Data, enter water cut values of 10% and 60%.
7. For the Gas Lift Injection rate:
a. Select Range.
b. Enter a start value of 1.0.
c. Enter an end value of 10.0.
d. Enter increments of 0.5.
8. Run the model to generate a plot of calculated liquid rate vs.
gas lift rate for different water cuts.
9. Inspect the plot and summary output to determine answers.
Results
Gas Lift Rate
(mmscf/d)
Liq. Prod. Rate (stb/d)
@ 10% Wcut
Liq. Prod. Rate (stb/d)
@ 60% Wcut
1
2
4
6
10
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Exercise 2
Working with Multiple Completions
Log analysis shows that a shallow gas zone exists at a TVD of
7,500 feet (Figure 27). As an alternative to gas lift injection, you
can investigate the benefits of perforating this zone and self lifting
the well.
Figure 27
Shallow zone at 7,500 feet
Defining a Second Completion
To define a second completion:
1. Insert a second vertical completion below the NODAL
analysis point.
2. Connect to the original completion using a separate tubing
model, as shown below.
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3. Modify the upper tubing string to extend only to the top of the
upper perforations.
a. Modify the Deviation survey such that it will extend to only
7,200 feet TVD.
b. Modify the Geothermal survey such that the ambient
temperature at an MD of 7,500 feet is 180 degF.
c. In the Tubing Configurations tab, specify a bottom MD of
7,500 feet and a tubing ID of 3.958 inches.
d. In the Downhole Equipment tab, remove the gas lift
injection.
e. Click OK to close the menu.
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4. Double-click on the lower tubing string to define its
properties,
a. In the Deviation Survey tab, define the lower tubing string
profile, as shown.
b. In the Geothermal Survey tab, specify temperatures of
180 degF at 7,500 feet and 200 degF at 9,000 feet.
c. Specify the U value as 5 Btu/hr/ft2/F.
d. In the Tubing Configuration tab, specify a tubing ID of
3.958 inches to a depth of 8,600 feet MD and 6.184
inches to a depth of 9,000 feet.
e. Click OK to close the menu.
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5. With no test data at hand, model the reservoir performance of
the upper zone using the pseudo-steady state Darcy equation.
Specify the upper completion using the following data:
Reservoir Properties - Upper Gas Zone
Model
Pseudo-steady state
Basis of IPR Calculation
Gas
Use Pseudo-pressures?
yes
Reservoir pressure
3,000 psia
Reservoir Temperature
180 degF
Thickness
5 feet
Permeability
20 md
Mechanical Skin
0
Rate Dependant Skin
0
6. Select the Fluid model tab within the completion dialog and
enter the following:
a. Use a locally-defined fluid model with an OGR of 0 STB/
mmscfd and a WGR of 0 (all gas).
b. Specify a gas gravity of 0.67.
c. Leave all other properties and correlations at their default
settings.
NOTE: The fluid data used for a well/source is defined by a
default, local data set or an override value [for water
cut and/or GOR/GLR/OGR/LGR]. If there are
multiple fluids present in the system with different
intrinsic properties, define the main fluid as the
default and all others as local fluids.
7. To analyze the effect of perforating the upper zone (compared
with gas lift injection), run a Pressure/Temperature Profile for
the 60% water cut case.
a. From Setup > Black Oil, set the water cut to 60%.
NOTE: This water cut affects only the lower zone because
the lower zone uses the default fluid model, while the
upper zone is defined with a local fluid model.
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b. Select Operations > Pressure/Temperature Profile.
c. Specify the Outlet Pressure as 300 psia.
d. Specify the Mass Rate as the Calculated Variable.
e. Run the model.
f. Inspect the output file to determine the results.
Results
Wellhead Pressure
300 psia
Liquid Rate (stb/d)
Gas Rate (upper zone) (mmscfd)
Question
Comparing the results of gas lift injection versus perforating the
upper zone, roughly how much gas lift injection would result in the
same liquid rate achievable through perforating the upper zone?
Equivalent gas lift injection rate: ______________
Lesson 5
Flow Control Valve
A downhole flow control valve (FCV) allows you to model socalled 'intelligent' or 'smart' wells. The methodology implemented
provides a simple way of modeling single branch (non-multilateral)
intelligent wells in which FCVs are located close to the reservoir.
An FCV can restrict the completion flow rate through the system;
however, they are available only for vertical completions. The
purpose of an FCV is to provide a restriction to fluid flow, thereby
reducing the productivity (or injectivity) of a given completion.
They are useful in a model containing multiple completions.
An FCV is very similar to a choke. Like a choke, it can be modeled
as a fixed-size orifice, in which form it presents a restriction to flow
resulting in a pressure drop that increases as flow rate increases.
Unlike a choke however, a maximum flow rate can also be
specified. This is applied to the completion and, if necessary, the
choke bean diameter is reduced to honor the limit.
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The choke diameter and flow rate limit can be applied separately
or together. If they are both supplied, they are treated as
maximum limits.
As shown in Figure 28, the Flow Control Valve dialog uses radio
buttons to present a choice between a Generic Valve and a
Specific Valve.
Figure 28
Flow Control Valve properties
A generic valve is specified with its Equivalent Choke Area, Gas
and Liquid Flow Coefficients, and choice of Gas Choke Equation
method. The choke area can be omitted if a Maximum Rate
Through Valve is specified. If it is present, the FCV is modeled
with that choke area but, if the resulting flow rate exceeds the
limit, the area is reduced to honor the limit.
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You must choose a specific valve from the list of available valves
provided in the PIPESIM database. Many of the specific valves
are multi-position devices, as they allow you to select the effective
choke area from a range of pre-installed fixed chokes.
If a flow rate limit is supplied, the simulation selects the choke
position required to honor the limit. Because the choke area
cannot be calculated to match the limit exactly, this usually results
in the flow rate being lower than the limit.
The valve position can be specified or omitted. If specified, the
FCV is modeled with the corresponding choke area, but if the
resulting flow rate exceeds the limit, a lower position number is
used.
Valve positions are numbered in order of increasing choke size,
starting with position zero. This position usually specifies a
diameter of zero to allow the valve to be shut. An FCV can have
as many as 30 positions.
Exercise 1
Modeling a Flow Control Valve
A formation integrity test indicates you should not flow more than
2 mmscfd of gas from the upper formation. To make sure, install
the FCV in the upper completion.
To model a flow control valve:
1. Double-click on the upper completion and check Flow
Control Valve.
2. In the FCV Properties window, set the Maximum Rate through
Valve to 2 mmscfd.
3. Leave Equivalent Choke Area empty.
4. Select Operations > Pressure Temperature Profile.
5. Ensure that the Liquid Rate is the calculated variable and the
outlet pressure is set to 300 psia.
6. Run the model and view the output file for Bean Size.
Required Bean Size: _______________
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7. (Optional) Select any Specific Valve to sensitize on FCV and
generate a plot liquid flow rate vs. FCV position.
TIP: Select SLB : TRFC-HN-AIS value and use System
Analysis and mass flow rate.
Review Questions
•
What is the effect on tubing performance curve of increasing
the water cut?
•
What is the difference between a standard choke and an
FCV?
•
What is the difference between a generic valve and a specific
valve?
Summary
In this module, you learned about:
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•
performing a NODAL analysis
•
estimating bottomhole flowing conditions
•
calibrating PVT data
•
performing flow correlation matching
•
performing IPR matching
•
conducting a Water Cut Sensitivity analysis
•
evaluating gas lift performance
•
installing a flow control valve.
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NOTES
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Gas Well Performance
Module 4 Gas Well Performance
A gas well has been drilled for which Drill Stem Test (DST) and
compositional fluid data are available. In this module, you will
model the performance of this well.
Learning Objectives
After completing this module, you will know how to:
•
model compositional fluid
•
calibrate the Inflow model
•
perform a NODAL analysis at bottomhole
•
perform a System analysis
•
select the optimum tubing size
•
model flowline and choke performance
•
calculate pressure drop due to increased condensate
production.
Lesson 1
Compositional Fluid Modeling
PIPESIM offers fully compositional fluid modeling as an
alternative to theBlack Oil model.
Compositional fluid modeling is generally regarded as more
accurate, especially for wet gas, condensate and volatile oil
systems. However, detailed compositional data is less frequently
available to the production engineer.
PIPESIM currently has access to two compositional PVT
Frameworks that provide several PVT flash packages.
Original PIPESIM PVT Framework:
•
SIS Flash, developed by Schlumberger. This is the same
Equation of State package used by other GeoQuest
products, such as ECLIPSE Compositional, PVTi, VFPi,
and others.
•
Multiflash, a third-party compositional package (InfoChem).
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New PVT Toolbox Framework (available in PIPESIM 2010.1):
•
Eclipse 300 Flash, a new interface to ECLIPSE two-phase
flash, allowing additional Equation of States.
•
DBR Flash, two-phase flash developed by the Schlumberger
DBR Technology Center. It has a more extensive component
library than ECLIPSE Flash.
•
NIST Refprop Flash, two-phase flash using HelmHoltz
Equation of State.
Equations of State (EoS)
Equations of State describe the pressure, volume and
temperature (PVT) behavior of pure components and mixtures.
Most thermodynamic and transport properties are derived from
the Equation of State. They are a function of pressure and
temperature.
One of the simplest Equations of State for this purpose is the ideal
gas law, PV=nRT, which is roughly accurate for gases at low
pressures and high temperatures.
NOTE: The Black Oil model uses this equation along with a
compressibility factor (z) to account for non-ideal
behavior.
However, this equation becomes increasingly inaccurate at higher
pressures and temperatures, and it fails to predict condensation
from a gas to a liquid. As a result, much more accurate Equations
of State have been developed for gases and liquids.
The Equations of State available in PIPESIM include:
SIS Flash
2-Parameter Peng-Robinson
3-Parameter Peng-Robinson
2-Parameter Peng-Robinson (advanced)
3-Parameter Peng-Robinson (advanced).
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Gas Well Performance
Standard Peng-Robinson
Advanced Peng-Robinson
Standard Soave-Redlich-Kwong (SRK)
Advanced Soave-Redlich-Kwong (SRK)
Benedict-Webb-Rubin-Starling (BWRS)
Association (CPA).
DBR Flash
Peng-Robinson (with/without Volume Shift)
Soave-Redlich-Kwong (with/without Volume Shift
Correction).
ECLIPSE
300 Flash
Peng-Robinson (with/without Volume Shift +
Accentric Factor Correction)
Soave-Redlich-Kwong (with/without Volume Shift
Correction).
NIST
Refprop
Flash
HelmHoltz Equation of State
Viscosity
Compositional fluid models also use Viscosity models based on
corresponding state theory. Available Viscosity models include:
•
Pederson (default)
•
Lohrenz-Bray-Clark (LBC)
•
Aasberg-Petersen
Comparative testing has shown the Pedersen method to be the
most widely applicable and accurate for oil and gas viscosity
predictions. Multiflash uses the Pedersen method as the default
viscosity model, though an option is available to choose the LBC
model for backward compatibility.
The choice you make of the Equation of State has a large effect
on the viscosities predicted by these methods. The LBC method is
more sensitive to the Equation of State effects than the Pedersen
method.
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Figure 29
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Selecting the default Viscosity option
Binary Interaction Parameter (BIP) Set
Binary interaction parameters (BIPs) are adjustable factors used
to alter the predictions from a model until the predictions match
experimental data as closely as possible.
BIPs are usually generated by fitting experimental VLE or LLE
data to the model in question. BIPs apply between pairs of
components, although the fitting procedure can be based on both
binary and multi-component phase equilibrium information.
Figure 30
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Selecting a BIP in the Compositional Properties
window
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Gas Well Performance
Emulsion Viscosities
An emulsion is a mixture of two immiscible liquid phases. One
phase (the dispersed phase) is carried as droplets in the other
(the continuous phase). In oil/water systems at low water cuts, oil
is usually the continuous phase.
As water cut is increased, there comes a point at which phase
inversion occurs, and water becomes the continuous phase. This
is the Critical water cut of Phase Inversion, otherwise called the
cutoff, which occurs typically between 55% and 70% water cut.
The viscosity of the mixture is usually highest at, and just below,
the cutoff.
Emulsion viscosities can be many times higher than the viscosity
of either phase alone.
Three mixing rules have been implemented that are identical to
the options currently available in the Black Oil section.
You can choose any of these options (Figure 31):
•
Set to oil viscosity
•
Volume ratio of oil and water viscosities
•
Woelflin, which uses Woelflin correlation at water cut less
than, or equal to, CUTOFF, and water viscosity at water cut
greater than CUTOFF.
Figure 31
Mixing options
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Flashing Options
Flash calculations are an integral part of all reservoir and process
engineering calculations. They are required whenever you wish to
know the amounts (in moles) of hydrocarbon liquid and gas
coexisting in a reservoir or a vessel at a given pressure and
temperature.
These calculations are also performed to determine the
composition of the existing hydrocarbon phases.
Given the overall composition of a hydrocarbon system at a
specified pressure and temperature, flash calculations can
determine four factors:
•
Moles of the gas phase
•
Moles of the liquid phase
•
Composition of the liquid phase
•
Composition of the gas phase
The compositional module uses inline flashing (PVT tables built in
memory) as the default mode of compositional simulation. For
inline flashing, PIPESIM has three options (Figure 32):
Interpolation, Interpolation when close to phase boundary, and
Rigorous.
Figure 32
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Flashing options
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Interpolation
Gas Well Performance
To maximize the speed of the simulation, not
all requested P/T points are flashed. A
pressure/temperature grid is defined and only
these points are created.
For points not lying exactly on a grid point,
four-point interpolation is used. The default
grid points can be changed via the
compositional option.
This is the fastest, but least accurate, method.
Interpolation
when close to
a phase
boundary
In a case where one or more of the four points
used for the interpolation is in a different
phase, a full flash is performed and the data
point added to the table.
This improves accuracy, but sacrifices speed.
Rigorous
Exercise 1
A full flash is always performed. Very accurate,
but slow!
Creating a Compositional Fluid
Model for a Gas Well
To create a compositional fluid model:
1. Start with a new PIPESIM case – Well Performance Analysis.
2. Open the Compositional Fluid Template menu by selecting
Setup > Compositional Template.
3. Choose PVT Framework as PIPESIM and select Multiflash
as PVT Package.
NOTE: Schlumberger employees select PVT Toolbox
Framework, E300 Flash Package. Your results will be
slightly different.
4. Click the Component Selection tab.
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5. Add following library components by selecting the desired
components from the list and click Add >>.
•
Methane
•
Butane
•
Ethane
•
Isopentane
•
Propane
•
Pentane
•
Isobutane
•
Hexane
6. Add the C7+ pseudo-component:
a. Select the Petroleum Fractions tab.
b. Enter thStep 4e pseudo-component name and data.
c. Highlight the row number for the pseudo-component and
click Add to Composition.
Pseudo-Component Stock Tank Properties
C7+ BP
214 degF
C7+ MW
115
C7+ SG
0.683
7. Leave Property Models as default.
8. Open the Compositional (Local Default) menu by selecting
Setup > Compositional (local default).
9. Under the Component Selection tab, you will notice all the
components predefined in Step 4. Add the mole fraction to
these components.
Composition (%)
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Methane
78
Ethane
8
Propane
3.5
Isobutane
1.2
Butane
1.5
Isopentane
0.8
Pentane
0.5
Hexane
0.5
C7+
6.0
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10. To determine the water content at saturation at reservoir
conditions:
a. Go back to the Compositional Template UI and add
Water as additional component.
b. Now come back to Compositional (Local default) UI and
add an arbitrary amount of water, such as 20 moles, to the
composition.
c. Select the Flash/Separation tab.
d. Click the PT button and enter the reservoir pressure and
temperature, 4,600 psia and 280 degF, respectively.
e. Perform a flash and read the water content for the vapor
fraction from the screen.
NOTE: The hydrocarbon vapor components will be
normalized to include the mole fraction of water.
f. Copy and paste (Ctrl + C and Ctrl + V) the water and the
normalized hydrocarbon composition back into the
compositional editor main screen.
NOTE: Water can be carried along with the gas in the vapor
phase or entrained in the gas in droplet form. There
exists at any temperature and pressure a maximum
amount of water vapor that a gas is able to hold.
A gas is completely saturated when it contains the
maximum amount of water vapor for the given
pressure and temperature conditions.
Keeping the volume and pressure constant on water
vapor-saturated gas, water will condense out at lower
temperatures because the capacity of the gas to hold
water is less. The same is true if the volume and
temperature are kept constant, but the pressure is
allowed to increase.
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11. Click Phase Envelope to generate a phase envelope using
the water-saturated composition.
12. From the main Component Selection tab, click Export,
name the composition sat_gas and click Save.
13. Select Setup > Flow Correlations and choose Gray
Modified for the vertical flow correlation.
14. Select File > Save As and save the model as
GasWell.bps.
Questions
These questions are for discussion and review.
110
•
What are the key differences between the various flash
packages?
•
What is the tradeoff between the rigorous flash option and
the interpolation flash option?
•
What is the likelihood of forming an emulsion when water
and gaseous hydrocarbons are the two phases present?
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Lesson 2
Gas Well Deliverability
Based on the analysis for flow data obtained from a large number
of gas wells, Rawlins and Schellhardt (1936) presented a
relationship between the gas flow rate and pressure drawdown
that can be expressed as:
Qsc = C(pR2 – pWF2)n
Where:
Qsc
= gas rate (mmscf/d)
pR
= average reservoir pressure (psia)
pWF
= flowing bottomhole pressure
C
= flow coefficient (mmscf/day/psi2)
n
= non-Darcy exponent
The exponent n is intended to account for the additional pressure
drop caused by the high-velocity gas flow, such as turbulence.
Depending on the flowing conditions, the exponent n can vary
from 1.0 for completely laminar flow to 0.5 for fully turbulent flow.
The performance coefficient C in above equation is included to
account for:
•
Reservoir rock properties
•
Fluid properties
•
Reservoir flow geometry.
This equation is commonly called the deliverability or backpressure equation. If you can determine the coefficients of the
equation - n and C - you can calculate the gas flow rate Qsc at any
bottomhole flow pressure pWF and construct the IPR curve.
Deliverability testing has been used for more than sixty years by
the petroleum industry to characterize and determine the flow
potential of gas wells.
There are essentially three types of deliverability tests:
•
Conventional deliverability (back-pressure) test
•
Isochronal test
•
Modified isochronal test.
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Essentially, these tests consist of flowing wells at multiple rates
and measuring the bottomhole flowing pressure as a function of
time. When the recorded data are properly analyzed, it is possible
to determine the flow potential and establish the inflow
performance relationships of the gas well.
Exercise 1
Calculating Gas Well Deliverability
In this exercise, you construct the simple physical well model
shown below and perform a simulation to calculate deliverability.
1. Using the Single Branch toolbar, insert a vertical
completion, tubing, and NODAL analysis point, as shown in
the figure.
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2. Edit the reservoir and tubing data according to the data in the
table.
Reservoir Data
Static Pres
4,600 psia
Reservoir Temp.
280 degF
Gas PI
1 x 10-6 mmscf/d/psi2
Tubing Data
Mid perf TVD
11,000 feet
Mid perf MD
11,000 feet
Ambient temp
30 degF
EOT MD
10,950 feet
Tubing ID
3.476 inches
Casing ID
8.681 inches
The vertical completion properties for Well_1 are shown in
the figure below, followed by an example of tubing properties
for a simple model.
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3. Select Operations > Pressure/Temperature Profile
Operation.
a. Select the Gas Rate as the calculated variable.
b. Specify an Outlet Pressure of 800 psia and click Run.
4. The flow rate displays below the plot. You can read the
bottomhole flowing pressure on the plot.
5. On the Plot menu, select Series.
6. Change the Y-axis to Temperature. You can read the
bottomhole and wellhead temperatures on the plot.
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Results
Pres = 4,600 psia, Tres = 280 degF
% H2O @ saturation
Po = 800 psia
QG
Pwf
BHT
WHT
Exercise 2
Calibrating the Inflow Model Using
Multipoint Test Data
In this exercise, you use the back-pressure equation for inflow
performance relationship for a gas well producing at a pseudosteady state. Using a multipoint well test, the C and n parameters
are calculated.
1. Double-click Completion.
2. Choose the Back Pressure Equation from the drop-down list.
3. Click Calculate/Graph and enter the test data listed in the
table.
Multipoint Test Data
QGas (mmscf/d)
Pwf (psia)
9.7
3,000
11.9
2,500
14.3
1,800
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4. Click Plot IPR.
TIP: To position data points, right-click and drag on a plot.
To zoom in, click and drag a window across the data
points towards the lower right. To zoom out, click and
drag a window towards the upper-left.
5. Rerun the Pressure/Temperature Profile operation to
determine the following:
• Gas flow rate
• Bottomhole flowing pressure
• Bottomhole flowing temperature
• Wellhead temperature
6. Inspect the profile plot and summary file to determine the
results.
Results
Back Pressure Equation
Parameter C
Parameter n
Po = 800 psia
QG
Pwf
Tbh (degF)
Twh (degF)
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Questions
These questions are for discussion and review.
•
What IPR methods are available in PIPESIM for gas wells?
•
What are the three types of gas well deliverability tests?
•
Does the C factor in the back pressure equation change over
time?
Lesson 3
Erosion Prediction
Erosion has been long recognized as a potential source of
problems in oil and gas production systems. Erosion can occur in
solids-free fluids but, usually, it is caused by entrained solids
(sand).
Two erosion models are available: API 14 E and Salama.
Figure 33
Selecting erosion options
API 14 E
The API 14 E model comes from the American Petroleum
Institute, Recommended Practice, number 14 E. This is a solidsfree model which calculates an erosion velocity but not a rate).
The erosion velocity Ve is calculated with the formula:
where m is the fluid mean density and C is an empirical constant.
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C has dimensions of (mass/(length*time2)) 0.5. Its default value in
engineering units is 100, which corresponds to 122 in SI units.
The current practice for eliminating erosional problems in piping
systems is to limit the flow velocity to that calculated by this
correlation.
Salama
The Salama model was published in Journal of Energy Resources
Technology, Vol 122, June 2000, "An Alternative to API 14 E
Erosional Velocity Limits for Sand Laden Fluids," by Mamdouh M.
Salama.
This model calculates erosion rate and erosional velocity. The
parameters required for the model are Acceptable Erosion rate,
Sand production ratio, Sand Grain Size, Geometry Constant and
Efficiency.
The equations in Salama's paper use a sand rate in Kg/day. This
is obtained from the supplied volume ratio using Salama's 'typical
value' for sand density - 2,50 kg/m 3.
Exercise 1
Selecting a Tubing Size
In this exercise, you perform a NODAL analysis to select an
optimum tubing size. The available tubing sizes have IDs of 2.992
inches, 3.958 inches, 4.892 inches, and 6.184 inches.
Your final decision will be based on these criteria:
•
Flow rate (High)
•
Erosional velocity ratio (<1).
•
Cost (Generally increases with size).
To select a tubing size:
1. Ensure that the model includes a NODAL analysis object
located between the tubing and the completion.
2. Select Operations > NODAL analysis.
a. Enter 800 psia as the Outlet Pressure.
b. Enter the tubing IDs as the Outflow Sensitivity.
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c. Run the model and observe the outflow curves.
3. Another way to analyze the effect of the tubing ID, is to
perform a Pressure/Temperature profile.
Select Operations > Pressure/Temperature Profile.
a. Enter the tubing size as the sensitivity.
b. Specify the flow rate as the calculated variable and run the
model.
c. From the profile plot, change the X-axis to Erosional
Velocity Ratio (EVR = actual velocity / API 14e limit) by
selecting the Series option from the toolbar. This lets you
determine the maximum erosional velocity ratio.
Based on the results of the NODAL analysis and EVR
calculations, which tubing size would you select?
4. Record the results for the selected tubing size.
Specify this tubing size in the tubing object in subsequent
exercises and procedures.
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Results
Po = 800 psia
QG
Pwf
BHT
WHT
Well-head, Selected Tubing
Max. Erosional velocity ratio
Questions
These questions are for discussion and review.
120
•
What are the criteria for optimum tubing selection?
•
What is the basic difference between the API 14 E and the
Salama correlation?
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Lesson 4
Choke Modeling
Wellhead chokes are used to limit production rates to meet
surface constraints, protect surface equipment from slugging,
avoid sand problems due to high drawdown, and control flow rate
to avoid water or gas coning. Placing a choke at the wellhead
increases the wellhead pressure and, thus, the flowing bottomhole
pressure which reduces production rate.
Pressure drop across wellhead chokes is usually very significant,
and various choke flow models are available for critical (sonic)
and sub-critical flow (Figure 34).
Figure 34
Gas fraction in the fluid and flow regimes
Sound waves and pressure waves are both mechanical waves.
When the fluid flow velocity in a choke reaches the traveling
velocity of sound in the fluid under the in situ condition, the flow is
called sonic flow.
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Under sonic flow conditions, the pressure wave downstream of
the choke cannot go upstream through the choke because the
medium (fluid) is traveling in the opposite direction at the same
velocity. As a result, a pressure discontinuity exists at the choke,
which means that the downstream pressure does not affect the
upstream pressure.
Because of the pressure discontinuity at the choke, any change in
the downstream pressure cannot be detected from the upstream
pressure gauge. Any change in the upstream pressure cannot be
detected from the downstream pressure gauge either. This sonic
flow provides a unique choke feature that stabilizes the well
production rate and separation operation conditions.
Whether a sonic flow exists at a choke depends on a downstreamto-upstream pressure ratio. If this pressure ratio is less than a
critical pressure ratio, sonic (critical) flow exists.
If this pressure ratio is greater than, or equal to, the critical
pressure ratio, sub-sonic (sub-critical) flow exists.
The critical pressure ratio is about 0.55 for natural gas, and a
similar constant is used for oil flow.
In some wells, chokes are installed in the lower section of tubing
strings. This choke arrangement reduces wellhead pressure and
enhances oil production rate as a result of gas expansion in the
tubing string.
For gas wells, a downhole choke can reduce the risk of gas
hydrates. A major disadvantage of using downhole chokes is that
replacing a choke is costly.
Exercise 1
Modeling a Flowline and Choke
In this exercise, you add a horizontal flow line and a choke to the
model. You use the gas rate calculated in the previous exercise to
determine the choke bean size that results in a manifold (end of
flowline) pressure of 710 psia.
To model a flowline and choke:
1. Ensure the tubing ID is set to 3.958 inches.
2. Insert a choke at the wellhead and reconnect the tubing to
the choke.
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3. Select the mechanistic model for both critical and sub-critical
flow.
TIP: You can enter any choke size you wish, but it will be
overridden by the sensitivity variable.
4. Insert a flowline downstream of the choke and connect it to a
node representing the manifold.
5. Specify the flowline using the data in the table.
Flow-line length
300 feet
Flow-line ID
6 inches
Pipe Roughness
0.001 inches
Wall thickness
0.5 inches
Ambient Temp
60 degF
6. Select Operations > Pressure Temperature Profile.
7. Select User Variable as calculated and input a choke size. A
good estimate is a size between 1 inch and 3 inches.
8. Set the Outlet Pressure to 710 psia.
9. Specify the gas flow rate calculated in the previous exercise.
10. Run the model and see the PsPlot for the choke size.
11. Enter the resulting choke size into the choke model.
12. Rerun the Pressure/Temperature profile with outlet pressure
as the calculated variable to verify that the calculated
wellhead pressure is 800 psia.
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13. Inspect the output file to determine individual pressure drops
for the reservoir, tubing, choke and flow line.
Results
Po = 710 psia
Choke size
Pressure losses across system
P Reservoir
P Tubing
P Choke
P Flow-line
Exercise 2
Predicting Future Production Rates
In this exercise, you use System analysis to calculate the gas rate
as a function of reservoir pressure.
To predict future production rates:
1. Right-click and choose Active to deactivate the choke and
flowline. These objects should be highlighted in red to
indicate they are inactive.
2. Select Operations > System Analysis.
3. Choose Gas Rate as the calculated variable.
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4. Set the wellhead pressure to 800 psia.
5. Use Reservoir (Static) Pressure as the X-axis variable and
set these values:
• 4,600 psia
• 4,300 psia
• 3,800 psia
• 3,400 psia.
6. Run the model and view the resultant plot.
Results
Reservoir Pressure
(psia)
Gas Rate
(mmscfd)
4600
4200
3800
3400
Questions
These questions are for discussion and review.
•
What is the difference between critical and sub-critical flow?
•
What effect does changing the manifold pressure have if the
choke is in critical flow?
•
What are the advantages and disadvantages of using
downhole chokes instead of wellhead chokes?
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Lesson 5
Liquid Loading
Gas wells usually produce natural gas-carrying liquid water and/or
condensate in the form of mist. As the gas flow velocity in the well
drops because of reservoir pressure depletion, the carrying
capacity of the gas decreases. When the gas velocity drops to a
critical level, liquids begin to accumulate in the well (liquid
loading).
This increases the bottomhole pressure, which reduces the gas
production rate. A low gas production rate will cause gas velocity
to drop further and, eventually, the well will cease producing.
Turner Droplet Model
In predominantly gas wells operating in the annular-mist flow
regime, liquids flow as individual particles (droplets) in the gas
core and as a liquid film along the tubing wall.
By analyzing a large database of producing gas wells, Turner
found that a force balance performed on a droplet could predict
whether the liquids would flow upwards (drag forces) or
downwards (gravitational forces). If the gas velocity is above a
critical velocity, the drag force lifts the droplet, otherwise the
droplet falls and liquid loading occurs (Figure 35).
Figure 35
Turner Droplet model
When the drag is equal to weight, the gas velocity is at critical.
Theoretically, at the critical velocity, the droplet would be
suspended in the gas stream, moving neither upward nor
downward.
Below the critical velocity, the droplet falls and liquids accumulate
in the wellbore.
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In practice, the critical gas velocity is generally defined as the
minimum gas velocity in the tubing string required to move
droplets upward.
The general form of Turner's equation is given by:
Where:
ρg = gas phase density (lbm/ft3)
ρl
= liquid phase density (lbm/3)
σ
= interfacial tension (dynes/cm)
vt
= terminal velocity of liquid droplet (ft/sec)
Liquid loading calculations are performed in every operation and
are available for review in output files and plot reports. Review the
output file to determine if the well is under liquid loading.
A value of Liquid Loading Velocity Ratio in excess of 1 indicates
loading.
The NODAL analysis plot will report the Liquid Loading Gas Rate
when the X-axis is configured to display gas rate. For every point
on the outflow curve, the value of Liquid Loading Velocity Ratio is
calculated and the critical gas rate is calculated at a point where
liquid loading velocity ratio is equal to 1.
NOTE: The reported value comes from interpolation of the
outflow curve between two points, one with a velocity
ratio below 1 and another with a velocity ratio above 1.
Therefore, the accuracy of the results depends on the
number of points on the outflow curve.
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Exercise 1
Determining a Critical Gas Rate to
Prevent Well Loading
To determine the Critical Gas rate:
1. Select Operations > NODAL analysis.
2. Select Limits and change these settings:
• Number of points on each inflow curve = 100
• Number of points on each outflow curve = 200
• Inflow curves to extend to the AOFP
• Outflow curves limited to the pressure range of the inflow
curves.
3. Set the outlet pressure to 800 psia and run the model.
4. Plot the Pressure at NA point vs. Stock Tank Gas Rate. Note
the stock tank gas rate on the Data tab.
The reported critical gas rate is _________ mmscfd
NOTE: The reported critical gas rate refers to the outflow
curve, which you can validate by performing a
Pressure/Temperature Profile operation at the same
conditions (flow rate and outlet pressure).
5. Perform a Pressure/Temperature Profile operation to
calculate inlet pressure at the given critical gas rate
corresponding to outflow outlet pressure of 800 psia.
6. View the output file to see if the Maximum Liquid Loading
Velocity Ratio is close to 1, which is consistent with the
results of the NODAL analysis.
Review Question
What actions can be taken to prevent liquid loading?
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Summary
In this module, you learned about:
•
building a simple well model
•
calibrating the inflow model
•
performing a NODAL analysis at bottomhole
•
performing system analysis
•
selecting optimum tubing size
•
modeling flowline and choke performance
•
calculating the pressure drop due to increased condensate
production.
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NOTES
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Horizontal Well Design
Module 5 Horizontal Well Design
This module shows you how to use PIPESIM to design a
horizontal well and evaluate horizontal well performance.
Learning Objectives
After completing this module, you will know how to:
•
optimize horizontal well length
•
perform horizontal well IPR / sensitivity
•
model a horizontal well with multiple perforated intervals.
Lesson 1
Inflow Performance
Relationships for Horizontal
Completions
The main advantage of a horizontal well, as compared to a vertical
well, is to enhance reservoir contact and, thereby, enhance well
productivity. There are also many circumstances that lead to
drilling horizontal wells (Cooper, 1988):
Thin reservoirs
The increased area of contact of the
horizontal well with the reservoir is reflected
by the Productivity Index (PI).
Typically, the PI for a horizontal well can be
increased by a factor of 4 when compared to
a vertical well penetrating the same
reservoir.
Heterogeneous
reservoirs
When irregular reservoirs exist, the
horizontal well can effectively intersect
isolated productive zones which might
otherwise be missed.
A horizontal well can also intersect vertical
natural fractures in a reservoir.
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Reduce water/
gas coning
A horizontal well provides minimum pressure
drawdown, which delays the onset of water/
gas breakthrough. Even though the
production per unit well length is small, the
long well length provides high production
rates.
Vertical
permeability
If the ratio of vertical permeability to
horizontal permeability is a high, a horizontal
well can produce more economically than a
vertical well.
The following IPR methods are available in PIPESIM for designing
horizontal wells.
Steady State
Production
The simplest form of horizontal well
productivity calculations are the steady-state
analytical solutions, which assume that the
pressure at any point in the reservoir does not
change with time.
According to Joshi (1991), even though very
few reservoirs operate under steady-state
conditions, steady state solutions are widely
used because:
•
Analytical derivation is easy.
•
The concepts of expanding drainage
boundary over time, effective wellbore
radius and shape factors allows the
conversion to either transient or pseudosteady state results to be quite
straightforward.
•
Steady-state mathematical results can
be verified experimentally.
The steady-state distributive productivity
index is based upon Joshi's SPE 16868,
"Review of Horizontal and Drainhole
Technology." The equation is based on the
assumption that the horizontal well drains an
ellipsoidal volume around the wellbore of
length L.
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PseudoSteady State
Production
Horizontal Well Design
It is often desirable to calculate productivity
from a reservoir with unique boundary
conditions, such as a gas cap or bottom water
drive, finite drainage area, well location, and
so forth. In these instances, pseudo-steady
state equations are employed.
Pseudo-steady state or depletion state begins
when the pressure disturbance created by the
well is felt at the boundary of the well drainage
area.
The pseudo-steady state productivity index is
based on Babu and Odeh's SPE paper
18298. (It is best to read this reference before
applying the equation.) The equation is based
upon the Pseudo-steady state IPR well model
applied to a rectangular drainage area.
Distributed
Productivity
Index Method
This option uses straight line PI value for
liquid or gas. The distributed productivity
index relationship is:
Q = J(Pws - Pwf)L for liquid reservoirs
OR
Q = J(Pws2 - Pwf2)L for gas reservoirs, where
J = distributed productivity index.
The Optimum Horizontal Completion Analysis module can
accurately predict the hydraulic wellbore performance in the
completion and is an integral part of the PIPESIM reservoir-tosurface analysis.
PIPESIM uses a technique in which the horizontal completion is
subdivided into vertical cross-sections, and flow is treated
independently from other cross-sections. This multiple source
concept leads to a pressure gradient from the blind-end (toe) to
the producing-end (heel) which, if neglected, results in overpredicting deliverability.
The reduced drawdown at the toe results in the production
leveling off as a function of well length, and it can be shown that
drilling beyond an optimum length would yield no significant
additional production.
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Exercise 1
Constructing the Well Model
To construct the well model:
1. Construct the physical horizontal well model shown in the
figure, using the tubing data in the tables that follow.
Wellbore Deviation
Survey Data
MD (ft)
TVD (ft)
0
0
7,000
7,000
7,700
7,600
8,400
8,000
9,000
8,200
9,500
8,300
Geothermal Survey
MD
134
Ambient Temperature
(degF)
U Value
(Btu/hr/ft2)
0
50
2
9500
200
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Horizontal Well Design
Tubing Configuration
Bottom MD (ft)
ID (in)
9500
2.992
Pipe Roughness (in)
0.001
Completion Data
Static Pressure
4,600 psia
Temperature
200 degF
Completion Model
Distributed PI
IPR Model Type
Distributed PI
Distributed PI
1.00E-9 mmscf/d/psi2/ft
Wellbore Data
Length
10,000 feet
ID
2.992 inches
Tambient (degF)
200 degF
2. Select Setup > Compositional Template and add these
Library components:
•
Methane
•
Iso-butane
•
Ethane
•
Butane
•
Propane
•
Water
3. Keep all other options as default.
4. Select Setup > Compositional (Local Default).
a. Enter the following composition:
Component
Mol %
Methane
0.846
Ethane
0.087
Propane
0.038
Isobutane
0.013
Butane
0.016
b. Enter the water content of 2 BBL/mmscf.
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5. Select Setup > Flow Correlations.
6. Specify Beggs-Brill Revised for both horizontal and vertical
flow.
Exercise 2
Evaluating the Optimal Horizontal
Well Length
To evaluate the optimal horizontal well length:
1. Select Operations > Optimum Horizontal Well Length.
2. For an outlet pressure of 200 psia, evaluate the optimal
length of a horizontal well up to approximately 10,000 feet
and the pressure loss from the toe to the heel of the
horizontal well.
Optimal horizontal well length: ____________________.
Exercise 3
Specifying Multiple Horizontal
Perforated Intervals
Additional geological information suggests that the reservoir
consists of four sand intervals that are 500, 400, 400, and 500 feet
in width, with equally spaced impermeable intervals of 400 feet in
width.
To specify multiple intervals:
1. Specify separate horizontal completions for each interval with
flowline objects to connect the completion intervals, as shown.
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2. Run a Pressure Temperature profile with the Gas Rate as the
calculated variable and 200 psia as the Outlet Pressure.
Results
Po = 200 psia
QG
Bhp
Review Questions
•
What are the advantages of a horizontal well over a vertical
well?
•
What are the basic completion models in PIPESIM for
horizontal wells?
•
Explain the shape of the horizontal well length versus
production rate curve
Summary
In this module, you learned how to:
•
construct a horizontal well
•
optimize horizontal well length
•
perform horizontal well IPR / sensitivity
•
model a horizontal well with multiple perforated intervals.
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NOTES
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Subsea Tieback Design
Module 6 Subsea Tieback Design
The offshore frontier poses some of the greatest technical
challenges facing the oil and gas industry, particularly as we
venture into ever deeper waters and more remote locations.
Development costs can be substantial and many new production
systems must be designed to accommodate subsea multiphase
flow across long distances to be economically viable.
Managing costs over extended distances introduces a number of
complex risks and reliability becomes a key concern due to high
intervention costs and potential for downtime.
Characterizing and managing these risks requires detailed
multidisciplinary engineering analysis and has led to the
emergence of a new field called flow assurance.
Design of subsea tiebacks requires multiphase flow simulation to
assure that fluids will be safely and economically transported from
the bottom of the wells all the way to the downstream processing
plant.
Four flow assurance issues are discussed in this module,
including hydrates, heat loss, erosion, and liquid slugging.
Learning Objectives
After completing this module, you will know how to:
•
develop a compositional model of the hydrocarbon phases
•
size the subsea tieback line and riser
•
determine the pipeline insulation requirements
•
screen the results for severe slugging at the riser base
•
size a slug catcher.
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Lesson 1
Flow Assurance
Considerations for Subsea
Tieback Design
In this case study, a client plans to produce four condensate wells
into a subsea manifold through a subsea tieback and up a riser to
a platform. The oil and gas will be separated, with the oil pumped
to shore and the gas compressed to shore.
Figure 36
Subsea Tieback
Exercise 1
Developing a Compositional PVT
Model
In this exercise, you develop a compositional PVT model based
on the data in the tables that follow.
Table 3: Pure Hydrocarbon Components
Component
140
Moles
Component
Moles
Carbon Dioxide
3
Butane
1
Methane
72
Isopentane
1
Ethane
6
Pentane
0.5
Propane
3
Hexane
0.5
Isobutane
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Table 4: Petroleum Fractions
Name
Boiling Point
(degF)
Molecular
Weight
Specific
Gravity
Moles
C7+
214
115
0.683
12
Table 5: Aqueous Component
Component
Volume ratio (%bbl/
bbl)
Water
10
To develop a Compositional PVT model:
1. Open the Setup > Compositional Template menu.
2. Choose PIPESIM as PVT Framework.
3. Choose Multiflash as PVT Package.
4. To enter the pure components noted in the preceding tables,
select the pure hydrocarbon components from the component
database.
TIP: Make multiple selections by holding down the Ctrl key.
5. After selecting all of the pure hydrocarbon components, click
Add >>.
6. Select the Petroleum Fractions tab and characterize the
petroleum fraction C7+ by entering these parameters:
• petroleum fraction name
• BP
• MW
• SG in Row 1.
7. Highlight the row by clicking Row 1 and click Add to
composition >>.
8. Return to the Component Selection tab to see that petroleum
fraction displays in the component list table on the right.
9. Click the Property Model tab and check the radio button
Use Template Models for all fluids.
10. Select SRK Equation of State and Pedersen viscosity model.
Leave all other options as default.
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11. Select Setup > Compositional Local Default and add mole
fractions for all library and pseudo components, as per
Table 3, Table 4, and Table 5.
12. Generate the hydrocarbon phase envelope by clicking Phase
Envelope.
Exercise 2
Constructing the Model
In this exercise, you construct the subsea tieback model.
To construct the model:
1. Using the Single Branch toolbar, insert the objects shown
2. Specify each object based on the data provided in the tables
that follow.
NOTE: To enter the detailed heat transfer data in the flowline
and riser, select the Heat Transfer tab and click
Calculate U value. Ensure that your Riser Elevation
survey matches that shown below.
Manifold Data
142
Temperature
176 degF
Pressure
1,500 psia
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Subsea Tieback Data
Rate of undulations
0'/1000 feet (not hilly)
Horizontal Distance
6 miles
Elevational difference
0 feet (horizontal)
Available IDs
9,10,11 inches
Heat Transfer:
Ambient temperature
38 degF
Pipe thermal conductivity
35 Btu/hr/ft/degF
Insulation thermal conductivity
0.15 Btu/hr/ft/degF
Insulation thicknesses available
0.50 in + 0.25 in increments
Ambient fluid
water
Ambient fluid velocity
1.5 ft/sec
Burial depth
Blank (Elevated above ground)
Ground conductivity
1.5 Btu/hr/ft/degF
Riser (use detailed profile)
Horizontal Distance
0 feet (vertical pipe)
Elevational difference
1,600 feet
Available IDs
9,10,11 inches
Heat Transfer
Ambient temperature @ riser base
38 degF
Ambient temperature @ 1,200 feet
42 degF
Ambient temperature @ 800 feet
48 degF
Ambient temperature @ 400 feet
56 degF
Ambient temperature @ topsides
68 degF
Pipe thermal conductivity
35 Btu/hr/ft/degF
Insulation thermal conductivity
0.15 Btu/hr/ft/degF
Insulation thickness
0.50 in (plus additional 0.25 in
increments if required)
Ambient fluid
water
Ambient fluid velocity
1.5 ft/sec
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Sizing the Subsea Tieback
You will now determine the required ID for the subsea tieback,
such that the separator pressure for the maximum expected rate
is no less than 400 psia.
The expected production rate is 14,000 STBD. The system will be
designed to accommodate between 8,000 STBD (turndown case)
and 16,000 STBD, should the wells produce more than expected.
The riser must be the same ID as the tieback, and you must not
exceed the erosional velocity.
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To size the subsea tieback:
1. From the Setup > Flow Correlations menu, make the
following selections:
• Vertical Flow Correlation = Hagedorn Brown (Duns & Ros
map)
• Horizontal Flow Correlation = Beggs-Brill Revised.
2. Perform a System analysis with the minimum, maximum, and
expected flow rates as the X-axis variable and the available
IDs for the flowline and riser as Change in Step (with
Sensitivity variable 1) sensitivity variables.
3. Determine the minimum flowline ID that satisfies the
separator pressure requirement (400 psia) for the maximum
flow rate.
4. Change the Y-axis to display Erosional Velocity Ratio
Maximum.
5. Verify that the selected flowline ID does not exceed an
erosional velocity ratio of 1.0 for the expected flow rate.
Results
Property
Value
Pipeline and Riser ID
Max. erosional velocity ratio for selected ID
Min. Separator pressure for selected ID
Max. separator pressure for selected ID
Lesson 2
Hydrates
Gas hydrates are crystalline compounds with a snow-like
consistency that occur when small gas molecules come into
contact with water at below a certain temperature. Hydrate
formation temperature increases with increasing pressure,
therefore, hydrates risk increases at higher pressures and lower
temperatures. When hydrates form inside the pipeline, the flow
can be blocked by hydrate plugs.
Hydrate forming molecules most commonly include methane,
ethane, propane, carbon dioxide, and hydrogen sulfide.
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Three hydrate crystal structures have been identified: Structures I,
II, and H. The properties of Structures I and II hydrates are well
defined. Structure H hydrates are relatively new, and their
properties are less well defined.
Hydrates can very easily form downstream of a choke where fluid
temperature can drop into the hydrate formation region due to
Joule-Thompson cooling effects.
Figure 37 shows a typical gas hydrate curve which is very useful
for subsea pipeline design and operations. On the left side of the
curve is the hydrate formation region. When pressure and
temperature are in this region, water and gas will start to form
hydrate.
Many factors impact the hydrate curve, including fluid
composition, water salinity and presence of hydrate inhibitors.
NOTE: Generating Hydrate curves requires the PIPESIM
Multiflash Hydrate Package and cannot be used with
SIS Flash.
Figure 37
Hydrate curve
Hydrate Mitigation Strategies in PIPESIM
Two common strategies available in PIPESIM to mitigate hydrates
formation are thermal insulation and chemical inhibitors. Thermal
insulation carries a higher upfront capital cost whereas chemical
inhibition carries a higher operational cost.
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Thermal insulation
Heat transfer between the fluid and surroundings occurs,
depending upon the temperature gradient. There are two options
for modeling the heat transfer in PIPESIM: Input U value and
Calculate U value.
Input U value is an overall heat transfer coefficient (U value)
based upon the pipe outside diameter is entered.
Calculate U value includes the following information, which can
be entered to compute the overall Heat Transfer coefficient.
•
Pipe coatings
• Thickness of the pipe coat.
• K (Thermal conductivity) of the material.
•
Pipe conductivity
•
Ambient fluid (Air or Water)
•
Ambient Fluid Velocity
•
Pipe burial Depth
•
Ground conductivity (for flowlines only).
Chemical Inhibitors
Thermodynamic inhibitors can be used to shift the hydrate curve
towards the left, thereby lowering the hydrate formation
temperature. Examples of inhibitors include methanol and
ethylene glycol.
Kinetic and anti-agglomerate inhibitors comprise a category
known as Low Dosage Hydrate Inhibitors (LDHIs). These
inhibitors do not lower the hydrate formation temperature; instead,
they help prevent the nucleation and agglomeration of hydrates to
avoid blockage formation. The effects of these types of inhibitors
cannot be modeled with PIPESIM.
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Exercise 1
Selecting Tieback Insulation
Thickness
Using the tieback/riser ID selected above, determine the thickness
of the insulation required for both the flowline and the riser, such
that the temperature of the fluid does not cross the hydrate curve
for all possible flow rates.
To select tieback insulation thickness:
1. Double-click on the Report tool and ensure that Phase
Envelope is checked.
2. Select Operations > Pressure/Temperature profile.
3. Specify Separator (outlet) pressure as the calculated variable
and the three design flow rates as the sensitivity variables.
4. Use the Series menu on the resulting plot to change the Xaxis to Temperature and the Y-axis to Pressure to display the
phase envelope.
5. Observe the production path on the phase envelope and its
proximity to the hydrate curve.
6. If required, perform successive runs while increasing the
insulation thickness of both the flowline and riser by 0.25 inch
increments until sufficient.
Results
Property
Value
Req. Insulation thickness
Exercise 2
Determining the Methanol
Requirement
Assume the flowline and riser have been insulated but they are
under-insulated with only 0.25 inch of insulation. In this exercise,
you determine the required injection volume of methanol to ensure
that hydrates do not form.
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To determine the methanol requirement:
1. Insert an injector just downstream of the source, as shown.
2. Specify Methanol as Injector Fluid.
3. Use injection temp. = 68 degF. To do this:
a. Select Setup > Compositional Template.
b. Add Methanol to the listed of added components.
c. Double-click on the Injector and choose Edit Composition.
d. Specify a composition of 100% Methanol.
e. Specify Injection Temperature and any injection rate.
4. Select Setup > Heat Transfer Options and verify that
Enable Hydrate Sub-Cooling Calculation is selected.
5. Select Operations > System Analysis.
a. Specify a liquid rate of 8,000 BPD and select calculated
variable as the outlet pressure.
b. For the X-axis variable, select the Injector as the object
and Rate as the Variable.
c. Select Range and enter a range of 200 to 600 BPD in
increments of 50 BPD.
d. Uncheck the active status on all sensitivity variables with
defined values.
e. Run the model.
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6. On the resulting plot, change the Y-axis to display Maximum
Hydrate Subcooling Temperature.
7. From the plot, determine the required Methanol injection
rate, such that the flowing temperature is always above the
stable hydrate temperature.
NOTE: A Positive Hydrate Sub-cooling in the output file
indicates the fluid temperature is below the hydrate
stability temperature.
Results
Property
Value
Req. Methanol Injection Volume (bbl/d)
Questions
These questions are for discussion and review.
•
What are the advantages and disadvantages of thermal
insulation versus chemical inhibition for prevention of
hydrates?
•
What is the basic difference between thermodynamic
inhibitors and low-dosage hydrate inhibitors?
Lesson 3
Severe Riser Slugging
Severe slugging in risers can occur in a multiphase transport
system consisting of a long flowline followed by a riser. Severe
slugging is a transient phenomenon that can be split into four
steps, as shown in Figure 38.
Step 1:
Slug formation corresponds to an increase of the
pressure in bottom of the riser. The liquid level does
not reach the top of the riser.
During this period, the liquid is no longer supported
by the gas and begins to fall, resulting in blockage to
the riser entrance and pipeline pressure buildup, until
the liquid level in the riser reaches to the top.
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Step 2:
In slug production, the liquid level reaches the riser
outlet, and the liquid slug begins to be produced until
gas reaches the riser base.
Step 3:
In bubble penetration, gas is again supplied to the
riser, so the hydrostatic pressure decreases. As a
result, the gas flow rate increases.
Step 4:
This corresponds to gas blowdown.
When the gas produced at the riser bottom reaches
the top, the pressure is minimal and the liquid is no
longer gas-lifted. The liquid level falls and a new
cycle begins.
Figure 38
The four slugging steps
PIPESIM does not rigorously model severe slugging associated
with risers, as this is a transient phenomena, but it does report a
dimensionless indicator of the likelihood of this occurring (PI-SS
number in PIPESIM output file).
Severe slugging is most prevalent in cases in which a long
flowline precedes a riser, especially for cases in which the flowline
inclination angle is negative going into the riser.
In cases of severe slugging, the slug catcher must be able to
receive a volume of liquid at least equal to the volume of the riser.
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However, severe slugging can be mitigated by topsides choking or
riser base gas lift including self-lifting mechanisms.
PI-SS Indicator (Severe-Slugging Group)
The PI-SS indicator (severe-slugging group) is the ratio between
the pressure build-up rates of gas phase and that of liquid phase
in a flowline followed by a vertical riser:
where:
Z
= Gas compressibility factor
R
= Gas universal constant
T
= Temperature (K)
M
= Molecular weight of gas
WG
= Gas mass flow rate (kg/s)
WL
= Liquid mass flow rate (kg/s)
g
= Acceleration due to gravity (m/s2)
LF
= Flowline length (m)
= Average flowline gas holdup
Severe slugging is expected when the Pots number is equal to, or
less than, unity. Pots’ model can be used to determine the onset
of severe slugging, but the model cannot predict how long the
severe slugs will be and how fast severe slugs will be produced
into the separator.
The PI-SS indicator is available as part of the PRIMARY output in
PIPESIM.
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Exercise 1
Subsea Tieback Design
Screening for Severe Riser
Slugging
To screen for severe riser slugging:
1. Deactivate the methanol injector and reset the insulation
thickness to that determined to prevent hydrate formation.
2. Under Setup > Define Output, select three cases to print.
This reports the full output of each sensitivity value with the
Report tool selections appended to the bottom of each
sensitivity output.
3. Perform a System analysis with an inlet pressure of 1,500,
outlet pressure calculated and liquid rates of 8,000;
14,000 and 16,000 BPD.
4. To check for severe slugging:
a. Configure the Y-axis of the System Analysis plot to display
the PI-SS number. This represents the maximum value of
the PI-SS number along the flowline.
b. View the Output report by selecting Reports > Output
File, to determine the prevalent flow regime at the riser
base for the different rates.
Results
Severe Slugging
8,000
stb/d
14,000
stb/d
16,000
stb/d
PI-SS number at riser base
Flow pattern at riser base
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Lesson 4
Slug Catcher Sizing
PIPESIM is frequently used to estimate the capacity requirements
for slug catchers. More detailed analysis is typically performed
with transient simulators such as OLGA. For offshore platforms,
you must balance the high cost of added weight to the platform
with the potential of a large slug overwhelming the liquids handling
capacity and shutting down the entire system.
There are three typical scenarios to consider in the sizing of slug
catchers for this type of system:
•
Hydrodynamic slugging
•
Pigging
•
Ramp-up.
Hydrodynamic Slugging
Most multiphase production systems will experience
hydrodynamic slugging. Designing systems simply to avoid
hydrodynamic slugging, such as larger pipe ID, is not a common
practice. Because hydrodynamic slugs grow as they progress
through the pipe, long pipelines can produce very large
hydrodynamic slugs.
PIPESIM calculates the mean slug length as a function of
distance traveled by using the SSB or Norris Correlations. A
continuous intermittent flow regime is required for this to occur. A
probabilistic model (again, based on Prudhoe Bay field data) is
applied to calculate the largest slug out of 10, 100 and 1,000
occurrences.
The 1/1000 slug length is often used to determine slug catcher
volume requirement.
The slug output from PIPESIM yields the length and frequency for
the selected slug size correlation:
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•
Mean slug length (distribution is assumed skewed log normal)
•
1 in 1,000 slug length and frequency
•
1 in 100 slug length and frequency
•
1 in 10 slug length and frequency.
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The preceding probabilities represent various levels of confidence
regarding the maximum slug size.
For example, a 1 in one thousand slug length of 50 meters
indicates there is only 0.1% probability of the maximum slug
length exceeding 50 meters.
Symbols that can be included in the slug output have the following
meanings:
0.0
Flow is not in a slugging regime (as calculated by the
relevant flow map correlation at spot report) and, thus, no
hydrodynamic slugs are required.
N/A
The slug length calculated using the chosen slugging
correlation is negative and, therefore, slug size is
indeterminate at this point in the flowline.
It should be noted that the slug size data output is only printed if
SLUG is specified in the Windows menu option Define Output
(Figure 39).
Figure 39
Define Output menu options
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Alternatively, you can insert the Report tool and check Slugging
values and Sphere-generated Liquid Volume values, as shown in
Figure 40.
Figure 40
Selecting report properties
Pigging
In multiphase flow in horizontal and upwards inclined pipe, the gas
travels faster than the liquid due to lower density and lower
viscosity. This is called slippage. Multiphase flow correlations
predict the ‘slip-ratio’ which depends on many factors, such as
fluid properties, pipe diameter and flow regime.
To preserve continuity, recall the definition of liquid holdup
discussed in Module 2.
In steady-state flow, the gas travels faster, so it will slip past the
liquid and occupy less pipe volume. This gives rise to a higher
liquid volume fraction than if the gas traveled at the same velocity,
resulting in ‘liquid holdup,’ as illustrated in Figure 41.
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Figure 41
Subsea Tieback Design
Liquid Holdup
During a pigging operation, a solid object the diameter of the
pipeline is sent through the line to push out liquids and debris. As
a pipeline is pigged (Figure 42), a volume of liquid builds up ahead
of the pig and is expelled into the slug catcher as the pig
approaches the exit.
PIPESIM considers that the pig travels at the mean fluid velocity
and, thus, the volume of liquid that collects ahead of the pig is a
function the degree of slip between the gas and liquid phases
(such as magnitude of liquid holdup). PIPESIM reports this
volume as the sphere generated liquid volume (SGLV). The slip
ratio (SR) is also reported, which is the average speed of the fluid
divided by the speed of the liquid.
The volume of liquid expelled at the receiving terminal as a result
of pigging can be estimated using steady-state analysis as a first
order approximation.
Figure 42
Pigging operation
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Ramp-up
When the flow rate into a pipeline increases, the overall liquid
holdup typically decreases because the gas can more efficiently
sweep out the liquid phase. When a sudden rate increase (rampup) occurs, the liquid volume in the pipeline is accelerated
resulting in a surge.
A ramp-up operation is illustrated in Figure 43. The size of the
surge is influenced by the sensitivity of liquid holdup with respect
to the overall flow rate. A simple material balance approach can
be applied to estimate the volume of the associated surge.
For more details, see Cunliffe's method entry in the PIPESIM help
system.
Figure 43
Ramp-up operation
Evaluating Each Scenario
For a more detailed analysis of slug catcher sizing, you should also
consider the drainage rates of the primary separator and slug catcher.
Hydrodynamic slugs and pig-generated slugs typically occur over a
short duration (minutes), while the surge created by a ramp-up
operation can be a long duration (hours/days).
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Exercise 1
Sizing a Slug Catcher
In this exercise, you screen for severe slugging and determine the
required size of the slug catcher based on the largest of the
following criteria, multiplied by a safety factor of 1.2.
Consider these criteria:
•
Hydrodynamic slugging, which is the requirement to handle
the largest slugs envisaged, chosen to be statistically the 1/
1000 population slug size. This is determined by using the
SSB or Norris Correlations.
•
The requirement to handle liquid swept in front of a pig.
•
Transient effects, such as the requirement to handle the
liquid slug generated when the production flow is ramped up
from 8,000 to 16,000 STB/D, such as Ramp-up surge.
NOTE: For the purposes of sizing a slug-catcher, it is
assumed that severe riser slugging can be mitigated
with topsides choking or riser-based gas lift.
To size the slug catcher:
1. In the Report tool, verify that slugging values and sphere
generated liquid volume are selected.
2. Re-run the System Analysis configured in the previous
exercise.
3. For each sensitivity value, scroll down and read the reported
1/1000 slug volume and the Total Sphere Generated Liquid
Volume So Far.
4. For the ramp-up case, calculate the difference in total liquid
holdup, as this will be the surge volume. You must convert
from ft3 > bbl. The conversion factor is 5.615 ft3/bbl.
NOTE: The surge associated with ramp-up occurs over a
much longer time period than the other cases. The
ramp-up volume does not consider the drainage rate
of the separator or the duration of the ramp-up.1
5. Inspect the output file and observe the flow regimes along
the profile for each case.
1. See Cunliffe’s Method in the PIPESIM help system for information on how to calculate the ramp-up duration.
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6. Based on the results in the table below, select a slug catcher
size that will be able to handle the largest slug volume for all
conditions.
Results
Slug Catcher Sizing
8,000
stb/d
14,000
stb/d
16,000
stb/d
1/1000 slug volume (bbl)
Sphere generated liquid volume (bbl)
Ramp-up volume (bbl)
Design volume for slug catcher (bbl)
(use 20% safety factor)
Review Questions
•
What types of slugs are reported by PIPESIM?
•
How do you report SGVL at particular location in the system?
•
Why should the SGVL not be greater than the total liquid
holdup?
•
Can PIPESIM be used for transient analysis?
Summary
In this module, you learned about:
160
•
developing a compositional model of the hydrocarbon
phases
•
sizing the subsea tieback line and riser
•
determining the pipeline insulation requirements
•
screening the results for severe slugging at the riser base
•
sizing a slug catcher.
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Looped Gas Gathering Network
Module 7 Looped Gas Gathering
Network
You must model the network as a complete system to account for
the interaction of wells producing in a common gathering system.
The wellhead pressure and, by extension, the deliverability of any
particular well is influenced by the backpressure imposed by the
production system.
Modeling the network as a whole allows the engineer to determine
the effects of such actions as adding new wells, adding
compression, looping flowlines and changing the separator
pressure.
In this module, you learn how to build a gathering network and
perform a network simulation to evaluate the deliverability of the
complete system.
Learning Objectives
After completing this module, you will know how to:
•
build a model of the network
•
specify the network boundary condition
•
solve the network and establish the deliverability.
Lesson 1
Model a Gathering Network
Network models are constructed using the network module and
solved using its calculation engine. The basic stages involved in
developing a network model are:
1. Build a model of the field, including all wells and flowlines.
2. Specify the boundary conditions.
3. Run the model.
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Boundary Conditions
To solve the network model, you must enter the correct number of
boundary conditions. Boundary nodes are those that have only
one connecting branch, such as a production well, injection well,
source or sink.
The number of boundary conditions required for a model is
determined by the model’s Degrees of Freedom:
number of wells (production and injection) +
number of sources +
number of sinks
For example, a three-well system producing fluid to a single
delivery point has 4 degrees of freedom (3+1), regardless of the
network configuration between the well and the sink.
Each boundary can be specified in terms of Pressure OR Flow
rate OR Pressure/Flow rate (PQ) curve.
Additionally, the following conditions must be satisfied:
•
The number of pressure, flow rate or PQ specifications must
equal the degrees of freedom of the model.
•
You must specify at least one pressure.
•
You must set the fluid temperature at each source (production
well and source).
Solution Criteria
A network has converged when the pressure balance and mass
balance at each node are within the specified tolerance. The
calculated pressure at each branch entering and leaving a node is
averaged, and the tolerance of each pressure is calculated from
the equation:
If all Ptol values are within the specified network tolerance, that
node has passed the pressure convergence test. This is repeated
for each node.
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The total mass flow rate into and out of a node are averaged. The
tolerance is calculated from the equation:
Ftol =
If the Ftol value is within the specified network tolerance, that
node has passed the mass convergence test. This is repeated for
each node.
The network has converged when all of the foregoing conditions
are satisfied.
Exercise 1
Building a Model of a Network
In this case study, your goal is to establish the deliverability of a
production network. The network connects three producing gas
wells in a looped gathering system and delivers commingled
product to a single delivery point.
Getting Started
1. Open PIPESIM and go to File > New > Network to create a
new network model.
2. Go to File > Save As to save the model in your training
directory, such as c:\training\pn01.bpn.
Building the Model
Using the engineering data available at the end of this case study,
build a model of a network.
To build the model:
1. Click Production Well
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2. Double-click on Well_1 to reveal the components.
3. Double-click on the vertical completion to enter the inflow
performance data.
4. Enter a gas PI of 0.0004 mmscf/d/psi2 and a reservoir
temperature of 130 degF.
NOTE: You will enter the reservoir pressure later when the
network boundary conditions are specified. In the
meantime put any value against Reservoir Pressure
to let GUI dialog close.
5. Double-click on the tubing and select Simple Model as the
preferred tubing model.
6. Define vertical tubing with a wellhead datum MD of 0 feet
and mid perforations TVD and MD of 4,500 feet.
7. The ambient temperatures are 130 degF at mid-perforations
and 60 degF at the wellhead. The tubing has an I.D. of 2.4
inches.
NOTE: Essential data fields are shown in a red outline; if the
fields are not outlined, data entry is optional.
8. Close the view of Well_1 by clicking at the upper-right corner
of the window, or by selecting File > Close to return to the
network view.
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9. Copy the data to Well_2 and Well_3.
a. Select Well_1.
b. Using the commands Edit > Copy and Edit > Paste (or
Ctrl + C and Ctrl + V), create two copies of the well.
NOTE: By default, the names of the copied wells will be
Well_2 and Well_3 and contain the same input data
as Well_1.
10. Position the new wells, as shown.
11. Modify the data of Well_3.
a. Double-click on Well_3 and modify the completion and
tubing data.
b. For the vertical completion, enter a gas PI of 0.0005
mmscf/d/psi2 and a reservoir temperature of 140 degF.
c. Define vertical tubing with a wellhead TVD of 0 and midperforations TVD and MD of 4,900 feet.
d. The ambient temperatures are 140 degF at the midperforation depth and 60 degF at the surface. The tubing
has an I.D. of 2.4 inches.
e. Close the view of Well_3 to return to the network view.
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12. Specify the composition of each production well.
This step defines the compositions at the production wells.
Well_1 and Well_2 are producing from the same zone and,
thus, are assumed to have the same composition. Well_3
has a composition that is different than that shown in the data
section at the end of the case study.
The most efficient way to define the compositions is to set
the more prevalent composition (that for Wells_1 and Well_2)
as the global composition, then specify the composition of
Well_3 as a local composition.
TIP: Composition data of all wells is provided at the end of
this exercise in Summary data.
a. Save the current network model.
b. Define the global template of all components used in the
network model.
i. Select Setup > Compositional Template menu.
ii. Add all library components (Hydrocarbon as well as
aqueous components).
c. Under the Petroleum Fraction tab, specify the name and
properties of the petroleum fraction and add it to the list of
template components.
d. Select Setup > Compositional (Network Default).
e. Enter the mole fraction for all components to define global
composition (Well_1 and Well_2).
NOTE: By default, the network global composition applies to
all sources/wells in the network model. Check this by
viewing the network fluid summary under Setup >
Fluid Models. To define a different composition for
any particular source/well, you must set it locally.
f. Define the local composition for Well_3:
i. Right-click on Well_3.
ii. Choose Fluid Model.
g. Select Use locally defined fluid model and click Edit.
h. Choose Local Compositional and click Edit Composition.
i. Enter the composition of Well_3.
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13. Connect the network together.
a. Insert a sink and some junction nodes.
NOTE: Holding down the Shift key while placing junction
nodes allows for multiple insertions. Be sure to release
the Shift key before the final insertion.
The network should now look like this:
b. Use the Branch
button to connect J_1 to J_2.
i. Click the Branch object.
ii. Hold down the left mouse button over J_1 and drag the
cursor to J_2.
iii. Release the mouse button. A connected branch is
shown in the figure.
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14. Double-click on the arrow in the center of B1 to enter data for
that branch.
a. Double-click on the flowline to enter the following data:
Rate of Undulations
10/1000
Horizontal distance
30,000 feet
Elevation difference
0 feet
Inner diameter
6 inches
Wall thickness
0.5 inches
Roughness
0.001 inches
Ambient temperature
degF
b. Close the B1 window to return to the network view.
15. The looped gathering lines are all identical, so the data for
branch B1 can be used to define other looped gathering lines.
a. Select B1. Click on the arrow in the middle of the branch
and copy/paste B1 to create B2, B3, and B4.
b. To connect a pasted branch:
i. Click the arrow in the middle of the new branch. You will
see highlight boxes display at either end of the branch.
ii. Move the cursor over the right-hand, highlight box. The
cursor changes to an up arrow (). Use this end of the
branch to drag and drop onto a junction node.
c. Position the new branches.
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d. Connect the wells to the adjacent junction node and
connect J_4 to the sink.
16. Double-click on branch B5 and insert the following objects in
the left-to-right order shown in the figure:
• Liquid separator with an efficiency of 100%
• Compressor with a pressure differential of +400 psi and an
efficiency of 70%
• After-cooler (heat exchanger) with an outlet temperature of
120 degF and ∆P of 15 psi
• Flowline with the following properties:
Rate of undulations
10/1000
Horizontal distance
10,000 feet
Elevation difference
0 feet
Inner Diameter
8 inches
Wall Thickness
0.5 inches
Roughness
0.001 inches
Ambient Temperature
60 degF
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a. Click Connector
Schlumberger
to join the equipment together.
b. Close the Single Branch window.
17. Select Setup > Flow Correlations menu and choose
Beggs-Brill Revised as the global vertical and horizontal
multiphase flow correlations.
18. In the Options Control tab of the Flow Correlations menu:
a. Select use network options.
b. Click Apply network options to all branches.
19. Select Setup > Erosion and Corrosion Options and
choose the deWaard Corrosion model.
This model calculates a corrosion rate caused by the
presence of CO2 dissolved in water. Concentrations of CO2
and water are obtained from the fluid property definitions,
(black oil or compositional).
NOTE: The corrosion rate will be zero if CO2 or the liquid
water phase is absent from the fluid.
20. In the Options Control tab of the Erosion and Corrosion
Options menu:
a. Select Use network options.
b. Click Apply network options to all branches.
21. Save the model as gas_network.
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Exercise 2
Performing a Network Simulation
To perform a network simulation:
1. Select Setup > Boundary Conditions and specify these
boundary conditions:
Node
Pressure
Well_1
2,900 psia
Well_2
2,900 psia
Well_3
3,100 psia
Sink_1
800 psia
All flow rates are calculated by the network solver.
NOTE: Any pressure specification defined in the single
branch model must be re-specified in the network
model.
However, the boundary pressures specified in the
Network view will update the pressures defined in
the single branch model for use in single branch
operations.
2. Open the Setup > Iterations menu to set the network
tolerance to 1%.
3. Save the model.
4. Click Run
.
5. When the network has solved, you should see the message:
Gas_networkbpn01 – Finished OK.
When this message displays, click OK.
6. Click Report Tool
.
What is the gas production rate at the sink? _____ mmscfd?
TIP: More comprehensive reporting is available by clicking
Summary File
.
7. Hold down the Shift key and select the flow route from Well_3,
branch B3 and branch B5.
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8. Click Profile Plot
. You should obtain the pressure
profile for these three branches.
The effect of the compressor at J_4 on the system pressure
should look similar to the figure.
9. Select Series and change the Y-axis to Corrosion Rate to
observe the calculated corrosion rate.
Maximum Corrosion Rate in network = ______ mm/year
10. Determine the field production rate in the event of a
compressor shutdown. Assuming a bypass line exists around
the compressor, deactivate the compressor object and rerun.
Gas production rate at the Sink:______mmscfd
NOTE: Edit the legend and title on PsPlot to improve the
graphical presentation.
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Looped Gathering Network Data
The tables that follow contain the data for exercises in this
module.
Figure 44
Network layout
Table 6: Completion and Tubing Data
Well_1 and Well_2
Well_3
Gas PI
0.0004 mmscf/d/psi2
0.0005 mmscf/d/psi2
Wellhead TVD
0
0
Mid perforations TVD
4,500 feet
4,900 feet
Mid perforations MD
4,500 feet
4,900 feet
Tubing I.D.
2.4 inch
2.4 inch
Wellhead ambient temperature
60 degF
60 degF
Mid perforations ambient
temperature
130 degF
140 degF
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Table 7: Pure Hydrocarbon Components
(Well_1 and Well_2)
Component
Moles
Carbon Dioxide
3
Methane
72
Ethane
6
Propane
3
Isobutane
1
Butane
1
Isopentane
1
Pentane
0.5
Hexane
0.5
Table 8: Petroleum Fraction (Well_1 and Well_2)
Name
Boiling Point
(degF)
Molecular
Weight
Specific
Gravity
Moles
C7+
214
115
0.683
12
Table 9: Aqueous Component
(Well_1 and Well_2)
176
Component
Volume ratio
(%bbl/bbl)
Water
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Table 10: Pure Hydrocarbon Components
(Well_3)
Component
Moles
Carbon Dioxide
2
Methane
71
Ethane
7
Propane
4
Isobutane
1.5
Butane
1.5
Isopentane
1.5
Pentane
0.5
Hexane
0.5
Table 11: Petroleum Fraction (Well_3)
Name
Boiling Point
(degF)
Molecular
Weight
Specific
Gravity
Moles
C7+
214
115
0.683
10.5
Table 12: Aqueous Component
(Well_3)
Component
Volume ratio
(%bbl/bbl)
Water
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Table 13: Data for Looped Gathering Lines
(B1, B2, B3, and B4)
Rate of undulations
10/1000
Horizontal distance
30,000 feet
Elevation difference
0 feet
Inner diameter
6 inch
Wall thickness
0.5 inch
Roughness
0.001 inch
Ambient temperature
60 degF
Overall heat transfer coefficient
0.2 Btu/hr/ft2/degF
Table 14: Data for Deliver Line (B5)
178
Separator type
Liquid
Separator efficiency
100%
Compressor differential pressure
400 psi
Compressor efficiency
70%
After cooler outlet temperature
120 degF
After cooler delta P
15 psi
Flowline Rate of undulations
10/1,000
Flowline Horizontal distance
10,000 feet
Flowline Elevation difference
0 feet
Flowline Inner diameter
8 inch
Flowline Wall thickness
0.5 inch
Flowline Roughness
0.001 inch
Flowline Ambient temperature
60 degF
Flowline Overall heat transfer coefficient
0.2 Btu/hr/ft2/degF
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Table 15: Boundary Conditions
Node
Pressure
Temperature
Well_1
2,900 psia
130 degF
Well_2
2,900 psia
130 degF
Well_3
3,100 psia
140 degF
Sink_1
800 psia
(calculated variable)
Review Questions
•
How do you change tolerance in PIPESIM Network model?
•
What are the rules for pressure and flow rates in PIPESIM
Net?
•
Where do you see corrosion rate in the PIPESIM output?
Summary
In this module, you learned about:
•
building a model of the network
•
specifying the network boundary condition
•
solving the network and establish the deliverability.
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Water Injection Network
Module 8 Water Injection Network
In this module, you learn how to build and simulate a water
injection network. Other features illustrated in this module include
crossflow, single-phase (water), and electric submersible pump
(ESP) lifted production well.
Learning Objectives
After completing this module, you will know how to:
•
build an injection network
•
insert an ESP into a well
•
model multilayer reservoir with and without crossflow.
Lesson 1
Crossflow in Multilayer Wells
Figure 45 shows how crossflow can occur when production from
one zone is injected into another zone of lower pressure. This can
occur in either production or injection systems.
Figure 45
Crossflow types in a layered reservoir
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NOTE: To model all crossflow scenarios, you must use this
engine keyword from Setup > Engine Options:
OPTIONS REVERSEFLOW = ON.
Exercise 1
Determining Fluid Distribution in a
Water Injection Network
A water production well feeds water into an injection system
consisting of two injection wells with multiple completions. The
water is lifted from the production well by an ESP. Figure 46
schematically represents the layout of the studied water injection
system.
The objective of the exercise is to determine the fluid distribution
(the water, in this instance) in an injection system from a single
production well.
Figure 46
182
Water Injection network by electric submersible
pump (ESP)
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Water Injection Network
To determine fluid distribution:
1. Create a new network model by selecting File > New >
Network.
2. Layout the network shown in Figure 46 using the data in the
tables that follow.
Water Production Well
Reservoir Pressure
4,000
psia
Temperature
200
degF
Productivity Index (PI)
100
STB/d/psi
Tubing Model
simple
Orientation
vertical
Tubing depth
6,000
ft. TVD
Surface ambient temp
50
degF
Tubing ID
7
in
ESP depth
2,000
ft. TVD
ESP model
Centrilift IB700
ESP stages
30
ESP speed
3,600
rpm
Surface Flowlines (all)
Ambient Temperature
50
degF
HTC
0.2
BTU/hr/ft2/degF
Flowline Data
Flowline
Distance
(ft)
Elevation
Difference
(ft)
Diameter
(in)
B1
150
0
8
B2
15,000
0
6
B3
10,000
0
6
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Both injection wells have 1.995-inch ID tubing and the properties
listed in the table.
Injection Well 1
Zone
Reservoir
Pressure
(psia)
Res
Temp
(degF)
Zone 1_1
4,400
210
7,800
2
No FCV
Zone 1_2
4,600
220
7,900
3
Maximum Liquid
= 1,500 STB/d
Zone 1_3
4,800
235
8,200
5
Equivalent Choke Area
= 0.25 in2
MD/TVD Injection PI
(ft)
(stb/d/psi)
FCV
Injection Well 2
Zone
Reservoir
Pressure
(psia)
Res
Temp
(degF)
Zone 2_1
4,500
220
7,900
4
No FCV
Zone 2_2
4,800
250
8,500
5
Maximum Liquid =
1,000 STB/d
Zone 2_3
5,000
270
8,800
4
FCV Closed
MD/TVD Injection PI
(ft)
(stb/d/psi)
FCV
NOTE: For each of the lower two multi-layer tubing objects, be
sure to use the bottom MD of the upper tubing string for
the datum MD of the next lower tubing string.
For example, Datum MD for tubing between zone 1_1
and 1_2 should be 7,800 ft. Leave all other parameters at
their default settings.
3. Create a global fluid model for water by selecting Setup >
Black Oil.
4. Specify water as fluid (set water cut as 100% and GLR = 0).
5. Select Beggs-Brill Revised as the vertical and horizontal
multiphase flow correlations.
6. Select Setup > Engine Options and enter the following in
the additional Engine Keywords field (TOP of network file):
OPTIONS REVERSEFLOW = ON
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7. Go to Setup > Boundary Conditions and specify these
boundary conditions:
Node
Pressure
Producer
4000 psia
Well_1
4800 psia
Well_2
5000 psia
8. Click Run Model
9. Click Report Tool
to start the simulation.
and select Clear.
10. Click on the producing well and each of the injectors.
11. Plot the pressure profiles for the entire network by selecting
all objects in the network and click Profile Plot.
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Review Questions
•
Which crossflow scenario occurs in your model?
•
What is the effect of installing FCV in your model.
•
Remove the FCVs from completions and compare the
results. Which crossflow scenarios now occur?
•
What other way can a water fluid model be defined?
Summary
In this module, you learned about modeling:
186
•
a water injection network
•
a multilayer injection well
•
an ESP.
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NOTES
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PIPESIM 2010.1 Fundamentals Answer Key to Exercises
Appendix A PIPESIM 2010.1
Fundamentals Answer
Key to Exercises
Module 2: Simple Pipeline Tutorials
Lesson 1: Single-Phase Flow Calculations
Exercise 1: Hand Calculations
1. Water Velocity
= 7.9ft/s
2. Reynold’s number = ~157,000; turbulent flow
3. Friction Factor
= ~ 0.0193
4. dP(friction)
= 662 psi
5. dP(elevation)
= 442 psi
6. dP(Total)
= 1,106 psi
7. Outlet Pressure
= 94 psia
Exercise 2: PIPESIM Calculation
•
Liquid velocity
= 7.91-7.94 ft/s
•
dP (frictional)
= 667.6 psi
•
dP (elevational)
= 443.1 psi
•
dP (total)
= 1,111 psi
•
P(outlet)
= 89.33 psia
Exercise 5: Gas Flowline Capacity
•
Flow rate
= 10.47 mmscfd
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Module 3: Oil Well Performance Analysis
Lesson 1: Nodal Analysis
Exercise 2: Performing Nodal Analysis
(Outlet) Wellhead Pressure
= 300 psia
Operating Point Flow rate
= 8,510 stb/d
Operating Point BHP
= 2,536 psia
AOFP
= 21,290 stb/d
Exercise 3: Performing a Pressure/Temperature Profile
(Outlet) Wellhead Pressure
= 300 psia
Production Rate
= 8,518 stb/d
Flowing BHP
= 2,535 psia
Flowing WHT
= 134 degF
Depth at which gas appears
= 7,200 ft
Lesson 2: Fluid Calibration
Exercise 1:
Wellhead Pressure
= 300 psia
Production Rate
= 7,808 stb/d
Flowing BHP
= 2,624 psia
Flowing WHT
= 129 degF
Depth at which gas appears
= 6,730 ft
Lesson 3: Pressure/Temperature Matching
Exercise 1: Flow Correlation Matching
190
Wellhead Pressure
= 300 psia
Vertical Correlation
= TUFFP-2Phase
Flowing BHP
= 2,681 psia
Head Factor
= 1.0059
Friction Factor
= 0.93035
U Factor
= 0.7907
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PIPESIM 2010.1 Fundamentals Answer Key to Exercises
Exercise 2: Matching Inflow Performance
Wellhead Pressure
= 300 psia
PI
= 6.669126
Lesson 4: Well Performance Analysis
Exercise 1: Conducting a Water Cut Sensitivity Analysis
Wellhead Pressure
= 300 psia
Water Cut
= 53.4%
Exercise 2: Evaluating Gas Lift Performance
Gas Lift Rate
(mmscf/d)
Liq. Prod. Rate
(stb/d) @ 10% Wcut
Liq. Prod. Rate
(stb/d) @ 60% Wcut
1
7,918
5,364
2
8,800
6,349
4
9,649
7,122
6
10,101
7,400
10
10,485
6,846
Exercise 3: Working with Multiple Completions
Wellhead Pressure
= 300 psia
Liquid Rate (stb/d)
= 6,885
Gas Rate (upper zone) (mmscfd)
= 4.161
Question (Optional)
•
Equivalent gas lift injection rate = 3.38
Lesson 5: Flow Control Valve Modelling
Exercise 1: Modelling a Flow Control Valve
•
Required Bean Size = 0.046 in2
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Module 4: Gas Well Performance
Lesson 2: Gas Well Deliverability
Exercise 1: Calculating Gas Well Deliverability
Pres = 4,600 psia, Tres = 280 degF
% H2O @ saturation
1.8549
Po = 800 psia
QG
18.21 mmscfd
Pwf
1,716 psia
BHT
237 degF
WHT
169 degF
Exercise 2: Calibrating the Inflow Model Using Multipoint
Test Data
Back Pressure Equation
Parameter C
7.9793682e-007
Parameter n
1
Po = 800 psia
192
QG
14.97 mmscfd
Pwf
1,548 psia
Tbh (degF)
233 degF
Twh (degF)
165 degF
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PIPESIM 2010.1 Fundamentals Answer Key to Exercises
Lesson 3: Erosion Prediction
Exercise 1: Selecting a Tubing Size
Based on the results of the Nodal Analysis and EVR calculations,
which tubing size would you select? 3.958 in.
Po = 800 psia
QG
15.39 mmscfd
Pwf
1,370 psia
BHT
229 degF
WHT
163 degF
Wellhead, Selected Tubing
Max. Erosional velocity ratio
0.7657
Lesson 4: Choke Modelling
Exercise 1: Modelling a Flowline and Choke
Po = 710 psia
Choke size
1.5145 ins
Pressure losses across system
P Reservoir
3,231.5 psia
P Tubing
569.55 psia
P Choke
86.75 psia
P Flow-line
1.79 psia
Exercise 2: Predicting Future Production Rates
Reservoir Pressure
Flow rate
3,400
8.051
3,800
10.272
4,200
12.723
4,600
15.387
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Lesson 5: Critical Gas Rate
Exercise 1: Determining a Critical Gas Rate to Prevent
Well Loading
The reported critical gas rate = 2.099 mmscfd.
Module 5: Horizontal Well Design
Lesson 1: Inflow Performance Relationships
Exercise 2: Evaluating the Optimal Horizontal Well
Length
Optimal horizontal well length = 10,000 ft
Exercise 3: Specifying Multiple Horizontal Perforated
Intervals
Po = 200 psia
QG
24.40 mmscfd
Bhp
2,683 psia
Module 6: Subsea Tieback Design
Lesson 1: Flow Assurance Considerations for
Subsea Tieback Design
Exercise 3: Sizing the Subsea Tieback
Pipeline and Riser ID
= 10 inch
Max. erosional velocity ratio for selected ID
= 0.825
Min. outlet pressure for selected ID
= 947 psia
Max. outlet pressure for selected ID
= 1,265 psia
Lesson 2: Hydrates
Exercise 1: Selecting Tieback Insulation Thickness
Req. Insulation thickness = 1 in
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PIPESIM 2010.1 Fundamentals Answer Key to Exercises
Exercise 2: Determining the Methanol Requirement
Req. Methanol Injection Volume (bbl/d) = 523
Lesson 3: Severe Riser Slugging
Exercise 1: Screening for Severe Riser Slugging
PI-SS number at riser
base
Flow pattern at riser base
8,000
stb/d
14,000
stb/d
16,000
stb/d
1.01
1.266
1.332
Intermittent
Intermittent
Intermittent
Lesson 4: Slug Catcher Sizing
Exercise 1: Sizing a Slug Catcher
8,000
stb/d
14,000
stb/d
16,000
stb/d
1/1000 slug volume (bbl)
165
181
215
Sphere generated liquid volume (bbl)
465
435
427
Property
Ramp-up volume (bbl)
962 – 799 = 163
Design volume for slug catcher (bbl)
465 * 1.2 = 558
Module 7: Looped Gas Gathering Network
Lesson 1: Model a Gathering Network
Exercise 2: Performing a Network Simulation
•
Gas production rate at the Sink
= 42.28 mmscfd.
•
Maximum Corrosion Rate in network
= 44.902 mm/year
•
Gas production rate at the Sink
= 38.26 mmscfd.
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NOTES
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