PIPESIM Fundamentals Workflow/Solutions Training Version...

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PIPESIM Fundamentals

Workflow/Solutions TrainingVersion 2009.1

Schlumberger Information Solutions

July 10, 2009

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Copyright Notice© 2009 Schlumberger. All rights reserved.

No part of this manual may be reproduced, stored in a retrieval system, or translated in any form or by any means, electronic or mechanical, including photocopying and recording, without the prior written permission of Schlumberger Information Solutions, 5599 San Felipe, Suite100, Houston, TX 77056-2722.

DisclaimerUse of this product is governed by the License Agreement. Schlumberger makes no war-ranties, express, implied, or statutory, with respect to the product described herein and dis-claims without limitation any warranties of merchantability or fitness for a particular purpose. Schlumberger reserves the right to revise the information in this manual at any time without notice.

Trademark InformationSoftware application marks, unless otherwise indicated, used in this publication are trade-marks of Schlumberger. Certain other products and product names are trademarks or regis-tered trademarks of their respective companies or organizations.

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Table of Contents

About this ManualLearning Objectives . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1What You Will Need . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1What to Expect . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1Course Conventions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2Icons . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3Workflow Diagram] . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4Summary . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5

Module 1 PIPESIM IntroductionLearning Objectives . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7Lesson 1: Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7Lesson 2: A Tour of the User Interface . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9Lesson 3: The PIPESIM File System and Calculation Engines . . . . . . . . . . . . . . . . . . 12

Output Files . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14Lesson 4: Plots . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15Lesson 5: Single Branch Operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16Review Questions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19Summary . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19

Module 2 Simple Pipeline TutorialsLearning Objectives . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 21Lesson 1: Single-Phase Flow Calculations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 21

Exercise 1: Modeling a Water Pipeline with Hand Calculations . . . . . . . . . . . . . . . 22Exercise 2: Modeling a Water Pipeline with PIPESIM . . . . . . . . . . . . . . . . . . . . . . 25The Primary Output File . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 31The Auxiliary Output File . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 32Exercise 3: Analyzing Multiple Scenarios with Sensitivities . . . . . . . . . . . . . . . . . . 33Exercise 4: Modeling a Single-Phase Gas Pipeline . . . . . . . . . . . . . . . . . . . . . . . . 36Exercise 5: Calculating Gas Pipeline Flow Capacity . . . . . . . . . . . . . . . . . . . . . . . . 38

Lesson 2: Multiphase Flow Calculations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 40Exercise 1: Modeling a Multiphase Pipeline . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 42

Review Questions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 48Summary . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 48

Module 3 Oil Well Performance AnalysisLearning Objectives . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 51Lesson 1: NODAL Analysis . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 51

Exercise 1: Building the Well Model . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 52Exercise 2: Performing NODAL Analysis . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 55Exercise 3: Performing a Pressure/Temperature Profile . . . . . . . . . . . . . . . . . . . . . 57

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Questions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 57Lesson 2: Fluid Calibration . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 58

Exercise 1: Calibrating PVT Data . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 59Lesson 3: Pressure/Temperature Matching . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 63

Exercise 1: Flow Correlation Matching . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 64Exercise 2: Matching Inflow Performance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 66Questions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 67

Lesson 4: Well Performance Analysis . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 68Exercise 1: Conducting a Water Cut Sensitivity Analysis . . . . . . . . . . . . . . . . . . . . 68Exercise 2: Evaluating Gas Lift Performance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 69Exercise 3: Working with Multiple Completions . . . . . . . . . . . . . . . . . . . . . . . . . . . 71Question . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 74

Lesson 5: Flow Control Valve . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 74Exercise 1: Modeling a Flow Control Valve . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 76

Review Questions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 76Summary . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 76

Module 4 Gas Well PerformanceLearning Objectives . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 79Lesson 1: Compositional Fluid Modeling . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 79

Equations of State (EoS) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 79Binary Interaction Parameter (BIP) Set . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 81Exercise 1: Creating a Compositional Fluid Model for a Gas Well . . . . . . . . . . . . . 84Questions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 86

Lesson 2: Gas Well Deliverability . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 86Exercise 1: Calculating Gas Well Deliverability . . . . . . . . . . . . . . . . . . . . . . . . . . . . 87Exercise 2: Calibrating the Inflow Model Using Multipoint Test Data . . . . . . . . . . . 90Questions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 91

Lesson 3: Predicting Erosion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 91API 14 E . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 91Salama . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 92Exercise 1: Selecting a Tubing Size . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 92Questions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 94

Lesson 4: Modeling Chokes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 94Exercise 1: Modeling a Flowline and Choke . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 95Exercise 2: Predicting Future Production Rates . . . . . . . . . . . . . . . . . . . . . . . . . . . 97Questions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 98

Lesson 5: Liquid Loading . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 98Turner Droplet Model . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 98Exercise 1: Determining a Critical Gas Rate to Prevent Well Loading . . . . . . . . . . 99

Review Question . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 100Summary . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 100

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Module 5 Horizontal Well DesignLearning Objectives . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 103Lesson 1: Inflow Performance Relationships for Horizontal Completions . . . . . . . . . 103

Exercise 1: Constructing the Well Model . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 105Exercise 2: Evaluating the Optimal Horizontal Well Length . . . . . . . . . . . . . . . . . 107Exercise 3: Specifying Multiple Horizontal Perforated Intervals . . . . . . . . . . . . . . 108

Review Questions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 108Summary . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 109

Module 6 Subsea Tieback DesignLearning Objectives . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 111Lesson 1: Flow Assurance Considerations for Subsea Tieback Design . . . . . . . . . . . 112

Exercise 1: Developing a Compositional PVT Model . . . . . . . . . . . . . . . . . . . . . . 112Exercise 2: Constructing the Model . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 114Exercise 3: Sizing the Subsea Tieback . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 116

Lesson 2: Hydrates . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 116Hydrate Mitigation Strategies in PIPESIM . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 117Exercise 1: Selecting Tieback Insulation Thickness . . . . . . . . . . . . . . . . . . . . . . 118Exercise 2: Determining the Methanol Requirement . . . . . . . . . . . . . . . . . . . . . . . 119Questions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 120

Lesson 3: Severe Riser Slugging . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 120PI-SS Indicator (Severe-Slugging Group) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 121Exercise 1: Screening for Severe Riser Slugging . . . . . . . . . . . . . . . . . . . . . . . . . 122

Lesson 4: Slug Catcher Sizing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 123Hydrodynamic Slugging . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 123Pigging . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 125Ramp-up . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 126Evaluating Each Scenario . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 126Exercise 2: Sizing a Slug Catcher . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 126


Module 7 Looped Gas Gathering NetworkLearning Objectives . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 131Lesson 1: Model a Gathering Network . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 131

Boundary Conditions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 131Solution Criteria . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 132Exercise 1: Building a Model of a Network . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 132Exercise 2: Performing a Network Simulation . . . . . . . . . . . . . . . . . . . . . . . . . . . . 138Looped Gathering Network Data . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 140


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Module 8 Water Injection NetworkLearning Objectives . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 145Lesson 1: Crossflow in Multilayer Wells . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 145

Exercise 1: Determining Fluid Distribution in a Water Injection Network . . . . . . . 146Review Questions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 149Summary . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 149

Appendix A PIPESIM 2009 Fundamentals – Answer KeyModule 2: Simple Pipeline Tutorials . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 151

Lesson 1 Single-Phase Flow Calculations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 151Module 3: OilWell Performance Analysis . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 151

Lesson 1: Nodal Analysis . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 151Lesson 2: Fluid Calibration . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 152Lesson 3: Pressure/Temperature Matching . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 152Lesson 4: Well Performance Analysis . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 152Question (Optional) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 153Lesson 5: Modelling a Flow Control Valve . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 153

Module 4: Gas Well Performance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 153Lesson 2: Gas Well Deliverability . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 153Lesson 3: Predicting Erosion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 154Lesson 4: Modelling Chokes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 154Lesson 5: Critical Gas Rate . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 155

Module 5: Horizontal Well Design . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 155Lesson 1: Inflow Performance Relationships . . . . . . . . . . . . . . . . . . . . . . . . . . . . 155

Module 6: Subsea Tieback Design . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 155Lesson 1: Flow Assurance Considerations for Subsea Tieback Design . . . . . . . . 155Lesson 2: Hydrates . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 156Lesson 3: Severe Riser Slugging . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 156Lesson 4: Slug Catcher Sizing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 156

Module 7: Looped Gas Gathering Network . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 156Lesson 1: Model a Gathering Network . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 156

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Schlumberger About this Manual

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About this Manual

This training material and guide is designed to give you 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 ObjectivesAfter 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 NeedYou must have the following hardware and software:• Personal computer with minimum 512 MB RAM

• PIPESIM 2009.1

• Training datasets

What to ExpectIn each module within this training material, you will encounter:• Overview of the module

• Prerequisites to the module (if necessary)

• Learning objectives

• A workflow component

• Lessons, explaining a subject or an activity in the workflow

• Procedures, showing the sequence of steps needed to per-form 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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Course Conventions

NOTE: Some of the conventions used in this manual indicate the information to enter, but are not part of the informa-tion 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 below: 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.

Characters typed in Bold Represents references to dialog box names and application areas or com-mands to be performed. For exam-ple, "Open the Open Asset Model dialog box."

Used to denote keyboard commands. For example, "Type a name and press Enter."

Identifies the name of Schlumberger software applications, such as Petrel or GeoFrame.

Characters inside <> triangle brackets

Indicate values that the user must supply. sqlplus <username>/<password>, usually with a sentence that defines the values.

Characters typed in italics Represent file names or directories.

"... edit the file lease.dat and..."

Represent lists and option areas in a window, such as Attributes list or Select Options area.

Identifies the first use of important terms or concepts. For example, "Stacking of data…"

Characters typed in fixed-width

Represent code, sql, and other literal text that the user sees or types. For example: sqlplus <username>/<password> .

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IconsThroughout 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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Workflow Diagram

Figure 1 PIPESIM workflow



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SummaryIn this introduction, we have:• 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.

In the following modules, you will learn how PIPESIM deals with oil and gas well performance, horizontal well design, and gathering and injection networks.



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NOTES


Schlumberger PIPESIM Introduction

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Module 1 PIPESIM Introduction

This module introduces PIPESIM 2009.1 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 on the following page, 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 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 may 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

Multiflash Wax Thermodynamics

Optional add-on to Multiflash

Multiflash Asphaltene Optional add-on to Multiflash

PIPESIM Linux Compoutation Engines

Used only with Avocet IAM when ECLIPSE Parallel, and is run on a Linux Cluster

Avocet Gas Lift Optimization Module

Network Optimization option caclulates the optimal gas lift allocation to a network of gas lifted wells



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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 2 on the preceding page, 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. The standard toolbar (Figure 3 PIPESIM toolbars and menus3) contains common commands that are displayed in both the single branch and network views.The Single Branch toolbar (Figure 4 on the following page) is displayed only in single branch view, while the Network toolbar Figure 5 on page 11) and the Net Viewer toolbar are displayed in the Network view.

PIPESIM OLGAS Steady State Flow Correlation – Two Phase

3rd-party 2-phase mechanistic multiphase flow model

PIPESIM OLGAS Steady State Flow Correlation – Three Phase

3rd-party 3-phase mechanistic multiphase flow model

PIPESIM Rod Pump Design and Optimization

3rd-party module for designing rod pumps

PIPESIM Rod Pump Diagnostics

3rd-party module for diagnosing rod pump performance based on digitized dynocards

PIPESIM DBR Wax Deposition

Single-phase wax deposition model embedded in PIPESIM that uses 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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You may also hide the toolbars from view using the Menu bar.

Figure 3 PIPESIM toolbars and menus

Menu Bar Consists of some of the familiar Windows menus, including File, Edit, Help, and more. All the tools available in other toolbars, plus all operations in PIPESIM.

Status Bar Shows 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 below.

Figure 4 Standard toolbar functionality



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NOTE: Icons in the Network toolbar and the Net Viewer bar are not highlighted in the Single Branch model. Simi-larly, icons in the Single Branch toolbar are not high-lighted 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 equip-ment, such as compressors, pumps, chokes, and more.

Single Branch Toolbar

This is 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.

Figure 5 The Single Branch toolbar

Network Toolbar

This toolbar 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 The Network toolbar



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Lesson 3 The PIPESIM File System and Calculation Engines

PIPESIM generates several input and output files in its working directory when you run a model. The input files are processed by the simulation engine to create output files.

PIPESIM EnginesPIPESIM uses one engine for a Single Branch model and another engine for a Network model. • Psimstub.exe is the PIPESIM engine for single branch oper-

ations

• 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 File SystemPIPESIM stores data in these formats: • ASCII files

• Binary files

• Microsoft Access database

Table 1: PIPESIM File Extensions and their Use

Ext. Type of File Application

*.bps Single branch model PIPESIM file

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

Same as above for a Network model

Output Files

*.out Output File All output data in ASCII format. The output file is produced from both Sin-gle 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 Out-put.

Mostly, errors are reported in output file. Remember to check this file in case of an error in a PIPESIM model.



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*.sum Summary file Summary report of PIPESIM output, i.e., pressures and temperatures at sources and sinks.

Plot Files

*.plc Profile Plot Variables you can plot with distance and elevation in PsPlot. These vari-ables 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 gener-ated by the user interface for the PIPESIM single branch engine - psim-stub.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 submers-ible 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.

*.pvt PVT file 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 oth-ers, or via 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

Table 1: PIPESIM File Extensions and their Use



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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 Define Output tab

Figure 8 Sample output file (primary output section)



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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, e.g., C:\Program Files\Schlumberger\ 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 by clicking on the Data tab.

Figure 9 Tabular view of PsPlot data

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 Advanced Plot Setup dialog



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Lesson 5 Single Branch Operations

There are many single branch operations available in PIPESIM.

NOTE: The system analysis operation also generates Pressure/Temperature profile plots for each case.

System analysis

Enables you to determine the performance of a given system for varying operating conditions on a case-by-case basis. Results of the analysis 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 (e.g., watercut) 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. A typical plot resulting from a system analysis is shown in Figure 11.

Figure 11 Typical System Analysis plot

Pressure/temperature profile

Generate pressure and temperature profiles of the system as a function of distance along the system. Both temperature and pressure profiles are generated on a node-by-node basis for the system.

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.



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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).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 12.

Figure 12 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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NOTE: The artificial lift operation is essentially a specific imple-mentation of the system analysis operation.

Review Questions

• What is the basic premise of steady-state flow modeling?

• What single branch operations are available?

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 bottom hole flowing pressures as a function of tubing head pressure, flow rate, GOR, watercut 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 utilize 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, watercut, tubing and flowline diameters.



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Summary

In the module, you gained an understanding of PIPESIM toolbars, file system and engines, and operations, and learned how to: • start PIPESIM with a new or existing project

• navigate and learn the user interface

• view results in output file

• display plots in PsPlot• select single branch options

• identify PIPESIM computer executables and data files.

In the next module, you learn how to build and run simple models.



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NOTES


Schlumberger Simple Pipeline Tutorials

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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 ObjectivesAfter 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, illustrated below, of a pipeline transporting water.

Figure 13 Pipeline transporting water

The pressure change per distance L for single phase flow is given by Bernoulli’s equation:

onalacceleratilelevationafrictionaltotal dLdp

dLdp

dLdp

dLdp

⎟⎠⎞

⎜⎝⎛+⎟

⎠⎞

⎜⎝⎛+⎟

⎠⎞

⎜⎝⎛=⎟

⎠⎞

⎜⎝⎛


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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:

= (frictional) - (elevational)

where,

ρ = fluid density (lbm/ft3)

g = gravitational constant

f = moody friction factor

v = fluid velocity (ft/s)

d = pipe inside diameter (ft)

Exercise 1 Modeling a Water Pipeline with Hand Calculations

In this exercise, using the data in the table 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

totaldLdp

⎟⎠⎞

⎜⎝⎛

gdvf

2

2ρθρ sing

Table 2: Water Pipeline Data

Pipeline Data

Diameter d 3 in (= 0.25 ft)

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 (=.05002 radians)

Roughness e 0.0015 in

Relative Roughness ε/d 0.0005 in

Fluid Data

Water viscosity μw 1.2 cp (= 8.06e-4 lb/ft-s)

Water density ρw 63.7 lbm/ft3



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1. Calculate the water velocity:

= _____________ ft/s

2. Calculate the Reynold’s number:

= ______________

• Is the flow laminar or turbulent? (See the Moody Diagram on the following page.)

3. Determine the friction factor using the Colebrook-White equa-tion for turbulent flow.

NOTE: This equation is implicit for f and requires an iterative procedure (e.g., Goalseek function in Excel). Alternatively, you may lookup the friction factor using the Moody diagram shown below.

Table 2: Water Pipeline Data

Operating Data

Source Temperature Tinlet 60 degF

Inlet Pressure Pin 1,200 psia

Water Flowrate Qw 6,000 BPD (= 0.39 ft3/s)

Constants

Gravitational g 32.2 ft/s2

⎟⎟⎠

⎞⎜⎜⎝

⎛=

4

2dQv w

π

μρvd

=Re

2

10 Re7.182274.1

1

⎟⎟⎠

⎞⎜⎜⎝

⎛⎟⎠⎞

⎜⎝⎛ +−

=

fDLog

fε



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f = __________________________

4. Evaluate the frictional pressure term, :

= __________ psf/ft /144 = _______ psi/ft

For the given length of pipe, L,

dp friction = _____________ psi

5. Evaluate the elevational pressure term,

NOTE: If using Excel, be sure the angle is in radians.

= __________ psf/ft /144 = ________ psi/ft


dp elevation = _____________ psi

6. Add the frictional and elevational terms to determine the total pressure term:

= __________ psf/ft /144 = ________ psi/ft


dp total = _____________ psi

7. Calculate the outlet pressure given the inlet pressure:

gdvf

2

2ρ

frictiondLdp

⎟⎠⎞

⎜⎝⎛

θρ sin

frictiondLdp

⎟⎠⎞

⎜⎝⎛

totaldLdp

⎟⎠⎞

⎜⎝⎛



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Pout = Pin - dp total = __________ psia



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Exercise 2 Modeling a Water Pipeline with PIPESIM

In this exercise, you use PIPESIM to build the water pipeline analyzed in the previous hand calculation and compare the results.

Getting Started1. Start PIPESIM from the Start menu 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.

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 and place it in the window, as shown below.



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3. Click Flowline , and 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.

4. Double-click Source_1 and the source input data user form displays.

a. Fill in the form, as shown in the figure.

b. Click OK to exit the user form.

5. Double-click Flowline_1 and the input data user form is dis-played.

6. Fill the form as shown below, ensuring that the rate of undula-tions = 0 (no terrain effects).



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7. Click the Heat Transfer tab and fill in the form for an adiabatic process, i.e., no heat gained or lost between the system and its environment.

8. 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 Correlations1. Select Setup > Black Oil to open the Black Oil Fluid menu.

2. Fill in the Black Oil user form, as shown below, and click OK when you are finished.

3. Go to File > Save As and save the model as <Excercise1_WaterPipe.bps>.



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4. From the Setup > Flow Correlations menu, select the Moody single-phase flow correlation.

Performing Operations1. From the Operations menu, select the Pressure/Tempera-

ture Profile operation.

2. Enter the known flowing conditions, as shown below.

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. Click the Data tab to display a tabular output of the Pressure/Temperature profile. 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.



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7. An abbreviated form of the full output file is presented in the Summary results file.

To open this file, go to the Reports menu and select Summary File. You can observe the output:

The Liquid holdup value displayed (175 bbl) is the total liquid volume for the entire pipe.

8. The Summary file reports the frictional and elevational com-ponents 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.

9. 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 correla-tions 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.

Result Hand Calculation PIPESIM

Liquid Velocity (ft/s)

ΔPfrictional (psi)

ΔPelevational (psi)

ΔPtotal (psi)

Outlet Pressure (psia)



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The primary output is shown below:

The Primary Output File

The primary output contains 16 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 P,T conditions 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



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Notice that, as the pressure decreases the liquid density decreases, which means the velocity must increase to maintain a constant mass flow rate.

The Auxiliary Output File

The auxiliary output is shown below:

The auxiliary output consists of 20 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

• Liquid volume fraction

• Liquid hold-up fraction

• Liquid water cut

• Fluid enthalpy

• Erosional velocity ratio

• Erosion rate (if applicable)

• Corrosion rate (if applicable)



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• Hydrate temperature subcooling (if applicable)

• Number of temperature Iterations

• Number of pressure iterations

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.

Exercise 3 Analyzing Multiple Scenarios with Sensitivities

Continuing with the previous example, you now explore how your model responds to different inlet temperatures.To modify the P/T profile operation:1. From the Operations menu, select the Pressure/Tempera-

ture Profile Operation.

a. Select Source_1 as the Object and Temperature as the Variable.

b. In the Pressure/Temperature Profile user form, click

Range .

c. Fill in the input form, as shown.

d. Click Apply and close the Set Range window. The com-pleted form is shown below.



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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 ↑ » μ ↓ » ↑ » f ↓ » ↓

NOTE: In the case of water, the effect of the tempera-ture on the density is negligible, as water is essentially an incompressible fluid.

4. Select the Data tab in the Plot window to see all the data for each temperature in a tabular format.

μρvd

=RefrictiondL

dp⎟⎠⎞

⎜⎝⎛



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5. Observe 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. Choose an option.

c. Set the number of cases to print to <4>.

7. Re-run 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 sensitiv-ity cases.

9. Return to the Setup > Define Output menu and check the Segment Data in Primary Output option.

10. Re-run the operation.



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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.

Exercise 4 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 below, to represent 100% gas (change GOR to LGR).

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 as shown below.

4. Click Run Model. As for the case of a single-phase liquid, the pressure calculation will be done using the Moody correla-tion.

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:

where,ρg = 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 thus, the frictional pressure gradient is higher. In other words,

T ↑ » ρg ↓ » ↓ » f ↑ » ↑

Also, because

=

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 increas-

ing temperature, but this effect is small and does little to offset the effects of decreasing density.

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

zRTpM

g =ρ

μρvd

=RefrictiondL

dp⎟⎠⎞

⎜⎝⎛

frictiondLdp

⎟⎠⎞

⎜⎝⎛

gdvf

2

2ρ



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• Flow rate

Two of these variables must be specified and 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.

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.



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The gas flow rate corresponding to the specified pressure drop is shown in the legend beneath the profile plot.

6. Observe the output files (*.out). The iteration routine for this operation can be seen in the output file, as shown below.

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 two-phase 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, as shown in Figure 14 andFigure 15 on the following page. 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 14 Multiphase flow regimes for horizontal flow

Figure 15 Multiphase flow regimes for vertical flow

Many empirical correlations and mechanistic models have been proposed to predict liquid holdup and pressure loss. (Refer to the PIPESIM help system for details).



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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 16, below. 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 two-phase friction factor from which a pressure gradient is calculated.

Figure 16 Liquid Holdup

Exercise 1 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 at the beginning and end of the flow-line, as shown.

2. Click on the flowline to highlight the object, and drag the tip connected to the source to the first Report icon.



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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 and connect the first Report Tool to the Source icon.

6. Select the Boundary node and press the Delete key. Your model should now appear 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, as shown below.



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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.

12. Double-click on Source_1 and change the pressure to <4800 psia>.



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13. Select Operations > Pressure Temperature Profiles and enter the information shown in the figure.

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 pres-sure 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.

14. Run the model.

15. Observe the pressure profile plot.



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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 bubble point.

NOTE: The holdup for each of the segment may be seen in the auxiliary output.

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 below.

NOTE: To view the graphics and output in SI or Cus-tom units, specify the units via the Setup > Units… option, and rerun the model.



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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?

SummaryIn this module, you learned how to:• build the physical model

• create a fluid model

• choose flow correlations

• perform operations

• view and analyze results.

In the next module, you learn about oil well performance analysis.



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NOTES


Schlumberger Oil Well Performance Analysis

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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 ObjectivesAfter completing this module, you will know how to:

• perform 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 is used to evaluate the performance of an oil well. It involves specifying a nodal point, usually at the bottom-hole or wellhead, and dividing the producing system into two parts - the inflow and the outflow. This is represented graphically in Figure 17, on the following page.

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. For example, if the node is taken at the bottom-hole, factors that affect the inflow performance, such as skin fac-tor, can be analyzed independently of variables that affect the outflow, such as tubing diameter or separator pressure.


Oil Well Performance Analysis Schlumberger

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Figure 17 Intersection points of the inflow and outflow perfor-mance 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.

Exercise 1 Building the Well Model

To build the well model:

1. Select a Vertical Completion object from the single branch toolbar, and place it in the Single Branch flow diagram.

2. Select a Boundary Node and place it in the flow diagram.

17

Outflow

Inflow

PR

PR

Psep

PsepPwf

Pwf

Flow rate

Nodal Analysis



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3. Select a Tubing object and connect VertWell_1 to the End Node S1 by clicking and dragging from VertWell_1 com-pletion to the End Node S1.

NOTE: The red outlines on VertWell_1 and Tubing_1 indicate that essential input data is missing.

4. Double-click on the completion and enter the properties listed in the table.

5. Double-click on the tubing object, and enter the tubing prop-erties based on data listed in the table.

Reservoir and Inflow Data

Completion model Well PI

Use Vogel? Yes

Reservoir Pressure 3,600 psia

Reservoir Temperature 200 degF

Liq. Productivity Index 8 stb/d/psi

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



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6. Specify an Overall Heat Transfer Coefficient = 5 btu/hr/ft2/F (override the default value).

NOTE: You can use the overall heat transfer coeffi-cient 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. Select the Summary table button to observe the configura-tion summary.

8. Set the Distance between nodes to <100 ft>.

9. Select Setup > Black Oil.10. Enter the fluid properties, as shown in the table. Assume

default PVT correlations and no calibration data.

NOTE: The fluid physical properties are calculated over the range of pressures and temperatures encountered by the fluid. These physical prop-erties are subsequently used by multiphase flow correlations to determine the phases pres-ent, the flow regime, and the pressure losses in single and multiphase flow regions. The heat transfer calculations use the fluid thermal properties.

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

Black Oil PVT Data

Water Cut 10 %

GOR 500 scf/stb

Gas SG 0.8

Water SG 1.05

Oil API 36 ºAPI



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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.

NOTE: Select the correlation that is best suited for the fluid and operating conditions of interest. There is no universal rule for selecting a multi-phase flow correlation that is good for all oper-ating scenarios.

See the PIPESIM help stystem for information on the applicability of flow correlations.

12. Save the model as <CaseStudy1_Oil_Well.bps>.

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



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4. Select Operations > NODAL analysis.

5. Enter an Outlet Pressure (Boundary Condition) of <300 psia>.

6. Leave Inflow Sensitivity and Outflow Sensitivity empty.

TIP: Increasing the number of points in inflow and out-flow curves provides more detailed curves from which a more accurate intersection can be read.

Click Limits on the Nodal Analysis window to change the number of points in inflow and out-flow curves.

7. Run the model.

8. Inspect the plot to determine the answers.

Results

(Outlet) Wellhead Pressure 300 psia

Operating Point Flow rate

Operating Point BHP

AOFP



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Exercise 3 Performing a Pressure/Temperature Profile

The Pressure/Temperature profile calculates pressure and tem-perature on a node-by-node basis for the system. The results are plotted for pressure or temperature as a function of distance/ele-vation along the flow path.

To estimate bottom-hole 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.

6. Inspect the plot and summary output to determine answers.

Results

BEST PRACTICE: NODAL analysis and the Pressure/Tempera-ture profile would give you the same results, but it is lot easier to get results from the Pres-sure/Temperature profile because the solution is explicitly reported, rather than visualized in the plot.

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?

Wellhead Pressure 300 psia

Production Rate

Flowing BHP

Flowing WHT

Depth at which gas appears



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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 datasets 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 cor-relations 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 labora-tory 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 bubble point pressure may 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 differ-ent elevational pressure gradient. Likewise, calibration of the fluid viscosity may drastically improve the calculation of the fric-tional 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.

Once the calibration is performed, a calibration factor calculated as ratio of measured value to the value calculated by selected correlation.

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 calcu-lations of the property in question, that is:

Calibrated value = Kc (Predicted value)



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Multi-Point Calibration

In multi-point calibration, black oil correlations are tuned so that the correlation honors all data points (Figure 18).

Figure 18 Correlation running through all data points

A calibration factor is calculated for every measurement point, and a plot is generated for the Pressure vs. Calibration factor, as shown in Figure 19, below.

Figure 19 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 (Optional) tab.

2. Enter the following calibration data:



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3. Under Dead Oil Viscosity, select User’s 2 Data points as the correlation.

a. Enter the following measurements:

b. For Live Oil Viscosity, ensure that the Chew and Con-nally correlation is selected.

c. For the Emulsion Viscosity Method, select the Brinkman 1952 correlation.

d. For the Undersaturated Oil Viscosity, select the Berg-man-Sutton correlation.

4. Select the Advanced Calibration Data tab and click Single-Point Calibration.

5. Enter the measured data to calibrate the PVT model.

6. Select the following PVT correlations:

Dead Oil Viscosity Measurements

Property Temperature (degF) Value

Viscosity 200 1.5 cp

60 10 cp

PVT Calibration DataRange 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

Property CorrelationSaturated gas Lasater

OFVF at / below bubblepoint Standing

Live oil viscosity Chew and Connally

Gas Z Standing



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7. 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 tempera-tures.

8. Select Series and change the y-axis to Oil Formation Vol-ume Factor.

9. Verify that the predicted values match the calibration points.

10. Repeat step 6 through step 8 for Oil viscosity and Gas vis-cosity 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 labora-tory dead oil data.

11. Now that the fluid model is calibrated, re-run the Pressure-Temperature Profile.

12. Determine the flowing bottomhole pressure, flowing wellhead temperature, and production rate for the given wellhead pres-sure.



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13. Compare your answers to the uncalibrated model results in Exercise 3 of the previous lesson.


Results

NOTE: 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 may 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 bubble point based on the specified produced GOR will be higher than that defined by the solution GOR calibra-tion point.

Wellhead Pressure Calibrated Uncalibrated

Production Rate

Flowing BHP

Flowing WHT

Depth where gas appears



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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 select-ing tubing sizes, forecasting well productivity, and designing artifi-cial lift installations.

Pressure distribution along particular tubing may 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), shown below.

Figure 20 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 may 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 matching is performed by tuning parameters, such as friction and hold-up factor multiplier for pressure matching, and a U-fac-tor multiplier for temperature matching. After the model is tuned, you should validate it against test data measured at different con-ditions.

WARNING: Avoid using large tuning factors. The recommended tuning range of friction and holdup factor multipliers are +/- 15% (i.e., 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 char-acterizations.



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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 corre-lation.

To perform a flow correlation match:

1. Select Data > Load/Add Measured Data.

2. Select New.

3. Enter the test data, as shown in the figure.

4. Click Save Changes.



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5. Go to Operations > Data Matching and, enter the range of calibration factors, as shown in the figure.

NOTE: You may uncheck the calibration factor for hor-izontal flow as there is no horizontal flow in this model.

6. Click the Flow Correlation tab and select some of the verti-cal 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 val-ues for the friction factor, holdup factor, and U-Value multipli-ers.

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

Exercise 2 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.

Best Vertical Correlation

Flowing BHP

Head Factor Multiplier

Friction Factor Multiplier

U Factor Multiplier



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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 Other variable and click Define.

4. Select Object VertWell_1 and the Variable Productivity Index.

5. Enter the expected range of PI and click OK.

6. Run the model and review the PsPlot for calculated Liquid PI.

NOTE: Update the PI for the completion with the matched value.

Results

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 correla-tions?

Matched PI STB/d/psi



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• Which data should you use in black oil calibration, i.e., flash or differential?

• What components of the pressure drop are reported by PIPESIM?

• What is the recommended way of selecting a multiphase cor-relation 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 may be performed to evaluate a variety of operating scenarios.

Exercise 1 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.

Using the wellhead pressure and reservoir pressure from the pre-vious 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.



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7. Interpolate to identify the water cut at which the calculated production rate drops to zero.

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. Select the Limits button and change the number of outflow points to display to 50.

6. Run the model to generate the NODAL analysis plot.

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

Exercise 2 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 tub-ing 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.

Critical Water Cut



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To evaluate gas lift performance:

1. Double-click on Tubing and select the Downhole Equipment tab.

1. Under Equipment, select Gas Lift Injection.2. Click Properties.

3. Enter a default gas lift rate of <1 mmscf/d>.

4. Go to Operations > Artificial Lift Performance and enter the Outlet Pressure.

5. For Sensitivity Data, enter water cut values of <10%> and <60%>.

6. 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>.

7. Run the model to generate a plot of calculated liquid rate vs. gas lift rate for different water cuts.


Results

Table 2: Gas Lift Data

Wellhead Pressure (psia) 300

Injection Gas SG 0.6

Injection Gas Surface Temp (degF)

100

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 3 Working with Multiple Completions

Log analysis shows that a shallow gas zone exists at a TVD of 7,500 feet (Figure 21). As an alternative to gas lift injection, you can investigate the benefits of perforating this zone and self lifting the well.

Figure 21 Shallow zone at 7,500 feet

Defining a Second Completion

To define a second completion:

1. Insert a second vertical completion below the NODAL analy-sis 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, as shown in the figure.

b. Modify the Geothermal survey such that the ambient tem-perature 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.

4. Double-click on the lower tubing string to define its proper-ties,

a. In the Deviation Survey tab, define the lower tubing string profile, as shown in the figure.



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b. In the Geothermal Survey tab, specify temperatures of 180 degF at 7,500 feet and 200 degF at 9,000 feet.

c. 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.

d. Click OK to close the menu.

5. With no test data at hand, model the reservoir performance of the upper zone using the pseudo-steady state Darcy equa-tion. Specify the upper completion using the following data:

6. Select the Fluid model tab within the completion dialog and enter the following:

a. Use a locally-defined fluid model with an LGR of 0 STB/mmscfd, and a water cut 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 watercut 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 (com-pared with gas lift injection), run a Pressure/Temperature Pro-file 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.

Reservoir Properties - Upper Gas Zone

Model Pseudo-steady state

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



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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

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 so-called 'intelligent' or 'smart' wells. The methodology implemented provides a simple way of modeling single branch (non-multilat-eral) intelligent wells in which FCVs are located close to the res-ervoir.

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 mod-eled 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 speci-fied. This is applied to the completion and, if necessary, the choke bean diameter is reduced to honor the limit. The choke diameter and flow rate limit can be applied separately or together. If they are both supplied, they are treated as maximum limits.


Liquid Rate (stb/d)

Gas Rate (upper zone) (mmscfd)



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As shown in Figure 22, the Flow Control Valve dialog uses radio buttons to present a choice between a Generic valve and a Specific valve.

Figure 22 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.

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 effec-tive 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 can-not be calculated to match the limit exactly, this usually results in the flow rate being lower than the limit.

The valve position may 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 diam-eter of zero to allow the valve to be shut. An FCV may have as many as 30 positions.



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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. Run the model and view the output file for Bean Size.

Required Bean Size: _______________

5. (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 Sys-tem 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?

SummaryIn this module, you learned how to:

• perform a NODAL analysis

• estimate bottomhole flowing conditions

• calibrate PVT data

• perform flow correlation matching

• perform IPR matching

• conduct a Water Cut Sensitivity analysis

• evaluate gas lift performance.

• install a flow control valve.

In the next module, you learn about evaluating gas well perfor-mance.



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Schlumberger Gas Well Performance

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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 produc-tion.

Lesson 1 Compositional Fluid Modeling

PIPESIM offers fully compositional fluid modeling as an alternative to the Black 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 packages:• SIS Flash, developed by Schlumberger. This is the same

Equation of State package used by other GeoQuest prod-ucts, such as ECLIPSE Compositional, PVTi, VFPi, and others.

• Multiflash, a 3rd-party compositional package (InfoChem).

Equations of State

Equations of State (EoS) 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, and are a function of pressure and temperature.


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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 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, Multiflash, and Viscosity EoS.

SIS Flash• 2-Parameter Peng-Robinson.

• 3-Parameter Peng-Robinson

Multiflash• Standard Peng-Robinson

• Standard SRK

• Soave-Redlich-Kwong (SRK) (default)

• Peng-Robinson

• Benedict-Webb-Rubin-Starling (BWRS)

Viscosity

Compositional fluid models also use Viscosity models based on corresponding state theory. Available Viscosity models include:• Pederson (default)

• Lohrenz-Bray-Clark (LBC)

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.



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The choice you make of the Equation of State has a large effect on the viscosities predicted by both methods. The LBC method is more sensitive to the Equation of State effects than the Pedersen method.

Figure 23 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 may be based on both binary and multi-component phase equilibrium information.

Figure 24 Selecting a BIP in the Compositional Properties window

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.



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As water cut is increased, there comes a point at which phase inversion occurs, and water becomes the continuous phase. This is the Critical Watercut 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: • Set to oil viscosity

• Volume ratio of oil and water viscosities

• Woelflin, which uses Woelflin correlation at watercut less than, or equal to, CUTOFF, and water viscosity at watercut greater than CUTOFF.

Figure 25 Mixing options

Flashing Options

Flash calculations are an integral part of all reservoir and process engineering calculations. They are required whenever it is desirable 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



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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 – Interpolation, Interpolation when close to phase boundary, and Rigorous.

Interpolation 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 will improve accuracy, but at the cost of speed.

Rigorous A full flash is always performed. Very accurate, but slow!

Figure 26 Flashing options



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Exercise 1 Creating a Compositional Fluid Model for a Gas Well

To create a compositional fluid model:1. Open the Compositional Fluid menu by selecting Setup >

Compositional.2. Choose the Options tab and ensure that Multiflash is

selected.

NOTE: Schlumberger employees select SIS Flash. Your results will be slightly different.

3. Click the Component Selection tab.

4. Add library components by selecting the desired components from the list and clicking Add >>.

5. Specify the mole fractions.

6. Add the C7+ pseudo-component:

a. Select the Petroleum Fractions tab.

b. Enter the pseudo-component name and data.

c. Highlight the row number for the pseudo-component and click Add to Composition.

7. Return to the Component Selection tab and specify a C7+ mol fraction of <6>.

Composition (%)

Methane 78

Ethane 8

Propane 3.5

Isobutane 1.2

Butane 1.5

Isopentane 0.8

Pentane 0.5

Hexane 0.5

Pseudo-Component Stock Tank Properties

C7+ BP 214 degF

C7+ MW 115

C7+ SG 0.683



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8. To determine the water content at saturation at reservoir con-ditions:

a. Add an arbitrary amount of water, such as 20 moles, to the composition.

b. Select the Flash/Separation tab.

c. Click the PT button and enter the reservoir pressure and temperature, <4,600 psia> and <280 degF>, respec-tively.

d. 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.

e. Copy and paste (Ctrl + C and Ctrl + V) the water and the normalized hydrocarbon composition back into the com-positional editor main screen.

NOTE: Water may 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 con-dense 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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9. Click Phase Envelope to generate a phase envelope using the water-saturated composition.

10. From the main Component Selection tab, click Export, name the composition <sat_gas> and click Save.

11. Select Setup > Flow Correlations and choose Gray Modi-fied for the vertical flow correlation.

12. Select File > Save As and save the model as <GasWell.bps>.

Questions

These questions are for discussion and review.• What are the differences between SIS Flash and Multiflash?

• 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?

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 – pWF

2)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, i.e., turbulence. Depending on the flowing conditions, the exponent n may 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



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This equation is commonly called the deliverability or back-pressure 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

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.

The vertical completion properties for Well_1 are shown in the figure below, followed by an example of tubing properties for a simple model.

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



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3. Select Operations > Pressure/Temperature Profile Opera-tion.

a. Select the Gas Rate as the calculated variable.

b. Specify an Outlet Pressure of <800 psia> and click Run.

4. The flow rate appears below the plot. You can read the bot-tomhole flowing pressure on the plot.

5. On the Plot menu, select Series.

6. Change the Y-axis to Temperature. You can read the bottom-hole and wellhead temperatures on the plot.

Results

Pres = 4,600 psia, Tres = 280 degF

% H2O @ saturation

Po = 800 psia

QG

Pwf

BHT

WHT



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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 pseudo-steady state. Using a multipoint well test, the C and n parameters are calculated.1. Double-click Completion.

2. Select the Back Pressure Equation from the drop-down menu.

3. Click Calculate/Graph and enter the test data listed in the table..

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.

4. Rerun the Pressure/Temperature Profile operation to deter-mine the following:

• Gas flow rate

• Bottomhole flowing pressure

• Bottomhole flowing temperature

• Wellhead temperature

Multipoint Test Data

QGas (mmscf/d) Pwf (psia)

9.7 3,000

11.9 2,500

14.3 1,800



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5. Inspect the profile plot and summary file to determine results.

Results

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 Predicting Erosion

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 in PIPESIM – API 14 E and Salama.

Figure 27 Selecting erosion options

Back Pressure Equation

Parameter C

Parameter n

Po = 800 psia

QG

Pwf

Tbh (degF)

Twh (degF)



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API 14 E

The API 14 E model comes from the American Petroleum Institute, Recommended Practice, number 14 E. This is a solids-free model which calculates only an erosion velocity (no erosion rate). The erosion velocity Ve is calculated with the formula:

Where ρm is the fluid mean density and C is an empirical constant. 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 - 2650 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 per-form 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 calcu-lations, which tubing size would you select? ____________

4. Record the results below for the selected tubing size, and specify this tubing size in the tubing object in subsequent exercises and procedures.

Results

Po = 800 psia

QG

Pwf

BHT

WHT

Well-head, Selected Tubing

Max. Erosional velocity ratio



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Questions

These questions are for discussion and review.• What are the criteria for optimum tubing selection?

• What is the basic difference between the API 14 E and the Salama correlation?

Lesson 4 Modeling Chokes

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 28).

Figure 28 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.

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.



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Whether a sonic flow exists at a choke depends on a downstream-to-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 may 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.

3. Select the mechanistic model for both critical and sub-critical flow.

TIP: You may 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.



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5. Specify the flowline using the data in the table.

6. Select Operations > Pressure Temperature Profile.

a. Select Other Variable as calculated, and input a choke size. A good estimate is a size between 1 inch and 3 inches.

b. Set the Outlet Pressure to 710 psia.

c. Specify the gas flow rate calculated in the previous exer-cise.

d. Run the model and see the PsPlot for the choke size.

7. Enter the resulting choke size into the choke model.

8. Re-run the Pressure/Temperature profile with outlet pressure as the calculated variable to verify that the calculated well-head pressure is 800 psia.

9. Inspect the output file to determine individual pressure drops for the reservoir, tubing, choke and flow line.

Flow-line length 300 feet

Flow-line ID 6 inches

Pipe Roughness 0.001 inches

Wall thickness 0.5 inches

Ambient Temp 60 degF



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Results

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 indi-cate they are inactive.

2. Select Operations > System Analysis.

3. Choose Gas Rate as the calculated variable.

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

Po = 710 psia

Choke size

Pressure losses across system

ΔP Reservoir

ΔP Tubing

ΔP Choke

ΔP Flow-line

Reservoir Pressure (psia) Gas Rate (mmscfd)

4,600

4,300

3,800

3,400



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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 down-hole chokes instead of wellhead chokes?

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. This is illustrated in Figure 29.

Figure 29 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 out-

flow 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.

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.



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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 out-flow curve, which you can validate by perform-ing a Pressure/Temperature Profile operation at the same conditions (flow rate and outlet pressure).

5. Perform a Pressure/Temperature Profile operation to calcu-late 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?

Summary

In this module, you learned how to: • build a simple well model

• calibrate the inflow model

• perform a NODAL analysis at bottomhole

• perform system analysis

• select optimum tubing size

• model flowline and choke performance

• calculate the pressure drop due to increased condensate pro-duction.

In the next module, you learn about using PIPESIM to design and evaluate horizontal well performance.



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Schlumberger Horizontal Well Design

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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 may 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.

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 may produce more economically than a vertical well.


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These 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 pseudo-steady state results to be quite straight-forward.

• 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.

Pseudo-Steady State Production

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 recommended that you 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.



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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-to-surface 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 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.

Exercise 1 Constructing the Well Model

To construct the well model:1. Construct the physical horizontal well model shown in the fig-

ure, using the tubing data in the tables that follow.

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 - Pwf

2)L for gas reservoirs, where J = distributed productivity index.



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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 Ambient Temp. (degF) U Value (Btu/hr/ft2)

0 50 2

9000 200 2

Tubing Configuration

Bottom MD (ft) ID (in) Pipe Roughness (in)

9500 2.992 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



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2. Select Setup > Compositional.a. Enter the following composition:

b. Enter the water content of <2 BBL/mmscf>.

3. Select Setup > Flow Correlations and 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 horizon-tal well.

Optimal horizontal well length: ____________________.

Component Mol %

Methane 0.846

Ethane 0.087

Propane 0.038

Isobutane 0.013

Butane 0.016



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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 in the figure below.

2. Run a Pressure Temperature profile with the Gas Rate as the calculated variable and 200 psia as the Outlet Pressure.

Results

Review Questions

• What are the advantages of a horizontal well over a vertical well?

• What are the basic completion models in PIPESIM for hori-zontal wells?

• Explain the shape of the horizontal well length versus produc-tion rate curve

Po = 200 psia

QG

Bhp



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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.

In the next module, you learn how to design a subsea tieback.



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Schlumberger Subsea Tieback Design

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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 30 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 Moles

Carbon Dioxide 3

Methane 72

Ethane 6

Propane 3

Isobutane 1

Butane 1

Isopentane 1

Pentane 0.5

Hexane 0.5



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To develop a Compositional PVT model:1. Open the Setup > Compositional menu to enter the pure

components noted in the preceding tables.

2. Select the pure hydrocarbon components from the compo-nent database.

TIP: Make multiple selections by holding down the Ctrl key.

3. After selecting all pure hydrocarbon components, click Add >>.

4. Select the Petroleum Fractions tab and characterize the petroleum fraction C7+ by entering these parameters:

• petroleum fraction name

• BP

• MW

• SG in Row 1

5. Highlight the row by clicking Row 1, and click Add to compo-sition >>.

6. Return to the Component Selection tab and enter the num-ber of moles for C7+.

7. Select the Options tab and select Multiflash.

8. Select the SRK equation of state.

9. Select the Pedersen viscosity model.

10. Generate the hydrocarbon phase envelope by clicking Phase Envelope.

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



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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 in

the figure below.

2. Specify each object based on the data provided in the tables that follow.

NOTE: To enter the detailed heat transfer data in the flow-line and riser, select the Heat Transfer tab and click Calculate U value. Ensure that your Riser Elevation survey matches that shown below.

Manifold Data

Pressure 1,500 psia


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 0.25 in + 0.25 in increments

Ambient fluid water



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Ambient fluid velocity 1.5 ft/sec

Burial depth Leave it 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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Exercise 3 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. To size the subsea tieback:1. From the Setup > Flow Correlations menu, make the follow-

ing 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 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 Maxi-mum.

5. Verify that the selected flowline ID does not exceed an ero-sional velocity ratio of 1.0 for the expected flow rate.

Results

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.

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



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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 31, below, 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 Multi-

flash Hydrate Package and cannot be used with SIS Flash.

Figure 31 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.

Thermal insulationHeat 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



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• Ambient fluid (Air or Water)

• Ambient Fluid Velocity

• Pipe burial Depth

• Ground conductivity (for flowlines only)

Chemical InhibitorsThermodynamic 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.

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 vari-able, and the three design flow rates as the sensitivity vari-ables.

4. Use the Series menu on the resulting plot to change the X-axis 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



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Exercise 2 Determining the Methanol Requirement

Assume the flowline has been installed but it is 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. To determine the methanol requirement:1. Insert an injector just downstream of the source, as shown in

the figure below.

2. Double-click on the Injector (Use temp. = 68 degF) and select Edit Composition.

a. Specify a composition of <100% Methanol>.

b. Click OK to accept the composition.

3. Select Setup > Heat Transfer Options, and verify that Enable Hydrate Sub-Cooling Calculation is selected.

4. Select Operations > System Analysis.

a. Specify a liquid rate of <8,000 BPD> and select calcu-lated 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 <50 to 500 BPD> in increments of 50 BPD.

d. Uncheck the active status on all sensitivity variables with defined values.

e. Run the model.

5. On the resulting plot, change the Y-axis to display Maximum Hydrate Subcooling Temperature.



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6. 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 Subcooling in the output file indicates the fluid temperature is below the hydrate stability temperature.

Results

Questions

These questions are for discussion and review.• What are the advantages and disadvantages of thermal insu-

lation versus chemical inhibition for prevention of hydrates?

• What is the basic difference between thermodynamic inhibi-tors and low-dosage hydrate inhibitors?

Lesson 3 Severe Riser Slugging

Severe slugging in risers may 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 32 on the following page

Property Value

Req. Methanol Injection Volume (bbl/d)

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.

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.



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Figure 32 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 proceeds 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. 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)



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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 holdupSevere 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.

Exercise 1 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 sensi-tivity 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 in 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 (e.g., larger pipe ID) is not common practice. Because hydrodynamic slugs grow as they progress through the pipe, long pipelines may 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:• 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

The preceding probabilities represent various levels of confidence regarding the maximum slug size. For example, a 1 in thousand slug length of 50 meters indicates there is only 0.1% probability of the maximum slug length exceeding 50 meters.Symbols that may appear 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.



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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 33 Define Output menu options

Alternatively, you can insert the Report tool and check Slugging values and Sphere-generated Liquid Volume values, as shown in Figure 34, below.

Figure 34 Selecting report properties



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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 35, below.

Figure 35 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 36), 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 (i.e., 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 36 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 (ramp-up) occurs, the liquid volume in the pipeline is accelerated resulting in a surge. A ramp-up operation is illustrated in Figure 37. 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 37 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).

Exercise 2 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.



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• 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, i.e., Ramp-up surge.

NOTE: For the purposes of sizing a slug-catcher, it is assumed that severe riser slugging may be mitigated with top-sides 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 exer-cise.

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 dura-tion of the ramp-up. See “Cunliffe’s Method” in the PIPESIM help system for information on how to calculate the ramp-up duration.

5. Inspect the output file and observe the flow regimes along the profile for each case.

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)



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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 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.

In the next module, you learn about looped gas gathering networks.



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NOTES



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Schlumberger Looped Gas Gathering Network

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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, thus, 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.

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, determined as follows:

Degrees of Freedom = number of wells (production and injection) + number of sources + number of sinks

For example, a 3 production 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.


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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.

• At least 1 pressure must be specified.

• All each source (production well & source) the fluid tempera-ture must be set.

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:

Ptol = (P - Pave.)/Pave. x 100%

If all Ptol values are within the specified network tolerance, that node has passed the pressure convergence test. This is repeated for each node.The total mass flow rate into and the total mass flow rate out of a node are averaged. The tolerance is calculated from the equation:

Ftol = (Tot. mass flow rate in - Tot. mass flow rate avg.) / Tot. mass flow rate avg. x 100%

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 Started1. 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 direc-tory, e.g., c:\training\pn01.bpn.

Using the engineering data available at the end of this case study, build a model of a network.



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3. Click Production Well to place Well_1 in the work area, as shown.

4. Double-click on Well_1 to reveal the components, as shown below.

5. Double-click on the vertical completion to enter the inflow performance data.

6. Enter a gas PI of <0.0004 mmscf/d/psi2> and a reservoir temperature of <130 F>.

NOTE: You will enter the reservoir pressure later when the network boundary conditions are specified.

7. Double-click on the tubing and select Simple Model as the preferred tubing model.

8. Define vertical tubing with a wellhead datum MD of <0 feet> and mid perforations TVD and MD of <4,500 feet>.

9. 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 out-line; if the fields are not outlined, data entry is optional.

10. 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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11. 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.

12. Position the new wells, as shown in the figure below.

13. 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 reservoir temperature of <140 F>.

c. Define vertical tubing with a wellhead TVD of <0> and mid-perforations TVD and MD of <4,900 feet>.

d. The ambient temperatures are 140 degF at the mid-perfo-ration 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.

14. 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, and then specify the composition of Well_3 as a local composition.



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The composition data of all wells is given at the end of this exercise in Summary data.

a. Save the current network model.

b. On the Setup > Compositional menu, and enter the global composition (Well_1 and Well_2).

c. To define the local composition for Well_3, right-click on Well_3 and select Fluid Model.

d. Select Use locally defined fluid model and click Edit. e. Enter the composition of Well_3.

15. Connect the network together.

a. Insert a sink and some junction nodes.

NOTE: Holding down the Shift key while placing junc-tion 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. To do this:

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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16. 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:

b. Close the B1 window to return to the network view.

14. As the looped gathering lines are all identical, the data for branch B1 can be used to define the other looped gathering lines. a. Select B1 by clicking 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 that highlight boxes appear at either end of the branch.

ii. Move the cursor over the right-hand, highlight box. The cursor changes to an up arrow (↑), as shown below. Use this end of the branch to drag and drop onto a junction node.

c. Position the new branches, as shown in the figure.

Rate of Undulations 10/1000

Horizontal distance 30,000 feet

Elevation difference 0 feet

Inner Diameter 6 inches

Wall Thickness 0.5 inches

Roughness 0.001inches

Ambient Temperature degF



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d. Connect the wells to the adjacent junction node and con-nect J_4 to the sink, as shown.

15. Double-click on branch B5 and insert the following objects in the order shown in the figure below:

• 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:

a. Click Connector to join the equipment together.

b. Close the Single Branch window.

Rate of undulations 10/1000



Inner Diameter 8 inches

Wall Thickness 0.5 inches

Roughness 0.001 inches

Ambient Temperature degF



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16. Select Setup > Flow Correlations menu, and choose Beggs-Brill Revised as the global vertical and horizontal multiphase flow correlations.

17. In the Options Control tab of the Flow Correlations menu:

a. Select use network options.

b. Click Apply network options to all branches.

18. Select Setup > Erosion and Corrosion Options and choose the deWaard Corrosion model.

NOTE: 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). The corrosion rate will be zero if CO2 or the liquid water phase is absent from the fluid.

19. 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.

20. Save the model as <gas_network>.

Exercise 2 Performing a Network Simulation

To perform a network simulation:1. Select Setup > Boundary Conditions and specify these

boundary conditions:

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 net-work 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 toler-ance to <1%>.

Node Pressure

Well_1 2,900 psia

Well_2 2,900 psia

Well_3 3,100 psia

Sink_1 800 psia



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3. Save the model.

4. Click Run .

5. When the network has solved, you should get the message:

pn01 – Finished OK.

When this message is displayed, 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.

8. Click Profile Plot .

9. You should obtain the pressure profile for these three branches, and the effect of the compressor at J_4 on the sys-tem pressure should look similar to the figure below.

10. Select Series and change the Y-axis to Corrosion Rate to observe the calculated corrosion rate.

Maximum Corrosion Rate in network = ______ mm/year11. Determine the field production rate in the event of a compres-

sor 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

Figure 38 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 Temper-ature

130 degF 140 degF

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



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Table 8: Petroleum Fraction (Well_1 and Well_2)

NameBoiling Point (degF)

Molecular Weight


C7+ 214 115 0.683 12

Table 9: Aqueous Component (Well_1 and Well_2)


Water 10

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)

NameBoiling Point (degF)

Molecular Weight


C7+ 214 115 0.683 10.5

Table 12: Aqueous Component (Well_3)


Water 5



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Table 13: Data for Looped Gathering Lines (B1, B2, B3, and B4

Rate of undulations 10/1000



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)

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 coeffi-cient

0.2 Btu/hr/ft2/degF

Table 15: Boundary Conditions

Node Pressure Temperature

Well_1 2,900 psia 130 degF



Sink_1 800 psia (calculated variable)



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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 how to:• build a model of the network

• specify the network boundary condition

• solve the network and establish the deliverability.

In the next module, you learn about water injection networks.



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Schlumberger Water Injection Network

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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 39 shows how crossflow may occur when production from one zone is injected into another zone of lower pressure. This may occur in either production or injection systems.

Figure 39 Crossflow Types in Layered Reservoir

NOTE: To model all crossflow scenarios, you must use this engine keyword from Setup > Engine Options: OPTIONS REVERSEFLOW = ON.


Water Injection Network Schlumberger

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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 40, below, 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 40 Water Injection network by electric submersible pump (ESP)

To determine fluid distribution:1. Create a new Network model by selecting File > New > Net-

work.

2. Layout the network as shown in Figure 40 using the data in the tables below.

Water Production Well

Reservoir Pressure 4,000 psia


Productivity Index (PI) 100 STB/d/psi

Tubing Model simple

Orientation vertical

Tubing depth 6000 ft. TVD

Tubing ID 7 in

ESP depth 2,000 ft. TVD

ESP model Centrilift IB700

ESP stages 30

ESP speed 3,600 rpm



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Both injection wells have 1.995-inch ID tubing and the properties listed in the tables that follow.

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 for the next lower tubing string (e.g., Datum MD for tubing between zone 1_1 and 1_2 should be 7,800 ft). Leave all other parameters at their default settings.

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

Injection Well 1

Zone

Reservoir Pressure

(psia)Res Temp

(degF) MD/TVD (ft)Injection PI (stb/d/psi)

FCV

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

Injection Well 2

Zone

Reservoir Pressure

(psia)Res Temp

(degF) MD/TVD (ft)Injection PI (stb/d/psi)

FCV

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



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3. Create a global fluid model for water by selecting Setup > Black Oil.

4. Specify a watercut of 100%.

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

7. Go to Setup > Boundary Conditions and specify these boundary conditions:

8. Click Run Model to start the simulation.

9. Click Report Tool and select Clear.10. Click on the producing well and each of the injectors.

Node Pressure

Producer 4000 psia

Well_1 4800 psia

Well_2 5000 psia



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11. Plot the pressure profiles for the entire network by selecting all objects in the network, and click Profile Plot.

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 how to:• model a water injection network

• model a multilayer injection well

• model an ESP.



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Schlumberger PIPESIM 2009 Fundamentals – Answer Key

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Appendix A PIPESIM 2009 Fundamentals – Answer Key

Module 2: Simple Pipeline Tutorials

Lesson 1 Single-Phase Flow Calculations

Exercise 1: Hand Calculations1. 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) = 1106 psi

7. Outlet Pressure = 94 psia

Exercise 2: PIPESIM Calculation• Liquid velocity = 7.91-7.94 ft/s

• P(outlet) = 89.3 psia

Exercise 5: Gas Flowline Capacity• Flowrate = 10.47 mmscfd

Module 3: OilWell Performance Analysis

Lesson 1: Nodal Analysis

Exercise 2: Performing Nodal Analysis


Operating Point Flow rate 8,510 stb/d

Operating Point BHP 2,536 psia

AOFP 21,290 stb/d


PIPESIM 2009 Fundamentals – Answer Key Schlumberger

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Exercise 3: Performing a Pressure/Temperature Profile

Lesson 2: Fluid Calibration

Exercise 1:

Lesson 3: Pressure/Temperature Matching

Exercise 1: Flow Correlation Matching

Exercise 2: Matching Inflow Performance


Production Rate 8,518 stb/d

Flowing BHP 2,535 psia

Flowing WHT 137 degF

Depth at which gas appears 7,200 ft


Production Rate 7,834 stb/d


Flowing WHT 134 degF

Depth at which gas appears 7,000 ft


Vertical Correlation Hagedorn Brown


Head Factor 1.1475

Friction Factor 1.0071

U Factor 0.93604


PI 6.728



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Lesson 4: Well Performance Analysis

Exercise 1: Conducting a Water Cut Sensitivity Analysis

Exercise 2: Evaluating Gas Lift Performance

Exercise 3: Working with Multiple Completions

Question (Optional)

• Equivalent gas lift injection rate: 4

Lesson 5: Modelling a Flow Control Valve

Exercise 1: Modeling a Flow Control Valve• Required Bean Size: 0.04734 in2


Water Cut 60%

Gas Lift Rate (mmscf/d)

Liq. Prod. Rate (stb/d) @ 10% Wcut

Liq. Prod. Rate (stb/d) @ 60% wcut

1 7,755 4,942

2 8,398 5,948

4 9,064 6,853

6 9,369 7,267

10 9,528 7,662


Liquid Rate (stb/d) 6,814

Gas Rate (upper zone) (mmscfd) 4



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Module 4: Gas Well Performance

Lesson 2: Gas Well Deliverability

Exercise 1: Calculating Gas Well Deliverability

Exercise 2: Calibrating the Inflow Model Using Multipoint Test Data

Lesson 3: Predicting Erosion

Exercise 1: Selecting a Tubing Size• Based on the results of the Nodal Analysis and EVR calcula-

tions, which tubing size would you select? 3.958 in

Pres = 4,600 psia, Tres = 280 degF

% H2O @ saturation 1.8549

Po = 800 psia

QG 18.22 mmscfd

Pwf 1,713 psia

BHT 236 degF

WHT 169 degF

Back Pressure Equation

Parameter C 7.9793682e-007

Parameter n 1

Po = 800 psia

QG 14.97 mmscfd

Pwf 1547 psia

Tbh (degF) 233 degF

Twh (degF) 164 degF

Po = 800 psia

QG 15.38 mmscfd

Pwf 1370 psia

BHT 229 degF

WHT 163 degF



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Lesson 4: Modelling Chokes

Exercise 1: Modeling a Flowline and Choke

Exercise 2: Predicting Future Production Rates

Lesson 5: Critical Gas Rate

Exercise 1: Determining a Critical Gas Rate to Prevent Well Loading• The reported critical gas rate: 3.57 mmscfd

Module 5: Horizontal Well Design

Lesson 1: Inflow Performance Relationships

Exercise 2: Evaluating the Optimal Horizontal Well LengthOptimal horizontal well length: 10,000 ft

Well-head, Selected Tubing

Max. Erosional velocity ratio 0.7657

Po = 710 psia

Choke size 1.5

Pressure losses across system

ΔP Reservoir 3,227 psia

ΔP Tubing 568 psia

ΔP Choke 90 psia

ΔP Flow-line 1.681 psia

Reservoir Pressure Flow rate

3,400 7.3370

3,800 9.4069

4,200 11.6604

4,600 14.0942



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Exercise 3: Specifying Multiple Horizontal Perforated Intervals

Module 6: Subsea Tieback Design

Lesson 1: Flow Assurance Considerations for Subsea Tieback Design

Exercise 3: Sizing the Subsea Tieback

Lesson 2: Hydrates

Exercise 1: Selecting Tieback Insulation Thickness

Exercise 2: Determining the Methanol Requirement

Lesson 3: Severe Riser Slugging

Exercise 1: Screening for Severe Riser Slugging

Po = 200 psia

QG 25 mmscfd

Bhp 2,727 psia

Property Value

Pipeline and Riser ID 10 inch

Max. erosional velocity ratio for selected ID 0.7651

Min. outlet pressure for selected ID 981 psia

Max. outlet pressure for selected ID 1,262 psia

Property Value

Req. Insulation thickness 1 in

Property Value

Req. Methanol Injection Volume (bbl/d) 500

Property 8,000 stb/d 14,000 stb/d 16,000 stb/d

PI-SS number at riser base

1.01 1.27 1.28

Flow pattern at riser base

Intermittent Intermittent Intermittent



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Lesson 4: Slug Catcher Sizing

Exercise 1: Sizing a Slug Catcher

Module 7: Looped Gas Gathering Network

Lesson 1: Model a Gathering Network

Exercise 2: Performing a Network Simulation• Maximum Corrosion Rate in network: 44 mm/year

• Gas production rate at the Sink: 38.3 mmscfd.

Property 8,000 stb/d 14,000 stb/d 16,000 stb/d

1/1000 slug volume (bbl)

165 181 215

Sphere generated liq-uid volume (bbl)

464 434 426

Ramp-up volume (bbl)

961 – 799 = 162

Design volume for slug catcher (bbl)

464 * 1.2 = 556.8



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PIPESIM Fundamentals Workflow/Solutions Training Version...

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Transcript of PIPESIM Fundamentals Workflow/Solutions Training Version...