PIPESIM 2010.1 Fundamentals H

PIPESIM Fundamentals Workflow/Solutions Training Version 2010.1

Schlumberger Information Solutions November 3, 2010

Copyright Notice © 2010 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.

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Table of Contents

About this Manual Learning Objectives . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . What You Will Need . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . What to Expect . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Course Conventions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Icons . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Workflow Diagram . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Summary . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

1 1 2 3 4 5 6

Module 1: PIPESIM Introduction Learning Objectives . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9 Lesson 1: Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9 Lesson 2: A Tour of the User Interface . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12 Lesson 3: PIPESIM File System and Calculation Engines . . . . . . . . . . . . . . . . 15 Output Files . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17 Lesson 4: Plots . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19 Lesson 5: Single Branch Operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 21 System Analysis . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 21 Pressure/Temperature Profile . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 22 Flow Correlation Comparison . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 22 Data Matching . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 22 NODAL Analysis . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23 Optimum Horizontal Well Length . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23 Reservoir Tables . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 24 Well Performance Curves . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 24 Gas Lift Rate vs. Casing Head Pressure . . . . . . . . . . . . . . . . . . . . . . . . . . . 24 Artificial Lift Performance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 24 Wax Deposition . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 24 Review Questions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25 Summary . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25

Module 2: Simple Pipeline Tutorials Learning Objectives . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Lesson 1: Single-Phase Flow Calculations . . . . . . . . . . . . . . . . . . . . . . . . . . . . Exercise 1: Modeling a Water Pipeline with Hand Calculations . . . . . . . . . . Exercise 2: Modeling a Water Pipeline with PIPESIM . . . . . . . . . . . . . . . . . Performing Operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

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The Primary Output File . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . The Auxiliary Output File . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Exercise 3: Analyzing Multiple Scenarios with Sensitivities . . . . . . . . . . . . . Exercise 4: Modeling a Single-Phase Gas Pipeline . . . . . . . . . . . . . . . . . . . Exercise 5: Calculating Gas Pipeline Flow Capacity . . . . . . . . . . . . . . . . . . Lesson 2: Multiphase Flow Calculations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Exercise 1: Modeling a Multiphase Pipeline . . . . . . . . . . . . . . . . . . . . . . . . . Review Questions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Summary . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

41 43 45 49 52 54 57 65 65

Module 3: Oil Well Performance Analysis Learning Objectives . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Lesson 1: NODAL Analysis . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Getting Started . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Exercise 1: Building the Well Model . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Exercise 2: Performing NODAL Analysis . . . . . . . . . . . . . . . . . . . . . . . . . . . Exercise 3: Performing a Pressure/Temperature Profile . . . . . . . . . . . . . . . Questions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Lesson 2: Fluid Calibration . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Single Point Calibration . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Multi-Point Calibration . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Exercise 1: Calibrating PVT Data . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . GOR Property Definitions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Lesson 3: Pressure/Temperature Matching . . . . . . . . . . . . . . . . . . . . . . . . . . . Exercise 1: Flow Correlation Matching . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Exercise 2: Matching Inflow Performance . . . . . . . . . . . . . . . . . . . . . . . . . . Questions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Lesson 4: Well Performance Analysis . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Conducting a Water Cut Sensitivity Analysis . . . . . . . . . . . . . . . . . . . . . . . . Exercise 1: Evaluating Gas Lift Performance . . . . . . . . . . . . . . . . . . . . . . . . Exercise 2: Working with Multiple Completions . . . . . . . . . . . . . . . . . . . . . . Question . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Lesson 5: Flow Control Valve . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Exercise 1: Modeling a Flow Control Valve . . . . . . . . . . . . . . . . . . . . . . . . . Review Questions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Summary . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

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Module 4: Gas Well Performance Learning Objectives . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Lesson 1: Compositional Fluid Modeling . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Equations of State (EoS) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Binary Interaction Parameter (BIP) Set . . . . . . . . . . . . . . . . . . . . . . . . . . . Exercise 1: Creating a Compositional Fluid Model for a Gas Well . . . . . . . Questions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Lesson 2: Gas Well Deliverability . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Exercise 1: Calculating Gas Well Deliverability . . . . . . . . . . . . . . . . . . . . . Exercise 2: Calibrating the Inflow Model Using Multipoint Test Data . . . . . Questions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Lesson 3: Erosion Prediction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . API 14 E . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Salama . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Exercise 1: Selecting a Tubing Size . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Questions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Lesson 4: Choke Modeling . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Exercise 1: Modeling a Flowline and Choke . . . . . . . . . . . . . . . . . . . . . . . Exercise 2: Predicting Future Production Rates . . . . . . . . . . . . . . . . . . . . Questions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Lesson 5: Liquid Loading . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Turner Droplet Model . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Exercise 1: Determining a Critical Gas Rate to Prevent Well Loading . . . . Review Question . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Summary . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

101 101 102 104 107 110 111 112 115 117 117 117 118 118 120 121 122 124 125 126 126 128 128 129

Module 5: Horizontal Well Design Learning Objectives . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Lesson 1: Inflow Performance Relationships for Horizontal Completions . . . . Exercise 1: Constructing the Well Model . . . . . . . . . . . . . . . . . . . . . . . . . . Exercise 2: Evaluating the Optimal Horizontal Well Length . . . . . . . . . . . . Exercise 3: Specifying Multiple Horizontal Perforated Intervals . . . . . . . . . Review Questions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Summary . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

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Module 6: Subsea Tieback Design Learning Objectives . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Lesson 1: Flow Assurance Considerations for Subsea Tieback Design . . . . . Exercise 1: Developing a Compositional PVT Model . . . . . . . . . . . . . . . . Exercise 2: Constructing the Model . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Exercise 3: Sizing the Subsea Tieback . . . . . . . . . . . . . . . . . . . . . . . . . . . Lesson 2: Hydrates . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Hydrate Mitigation Strategies in PIPESIM . . . . . . . . . . . . . . . . . . . . . . . . . Exercise 1: Selecting Tieback Insulation Thickness . . . . . . . . . . . . . . . . . Exercise 2: Determining the Methanol Requirement . . . . . . . . . . . . . . . . . Questions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Lesson 3: Severe Riser Slugging . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . PI-SS Indicator (Severe-Slugging Group) . . . . . . . . . . . . . . . . . . . . . . . . . Exercise 1: Screening for Severe Riser Slugging . . . . . . . . . . . . . . . . . . . Lesson 4: Slug Catcher Sizing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Hydrodynamic Slugging . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Pigging . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Ramp-up . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Evaluating Each Scenario . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Exercise 1: Sizing a Slug Catcher . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Review Questions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Summary . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

139 140 140 142 144 145 146 147 148 150 150 152 153 154 154 156 158 158 159 160 161

Module 7: Looped Gas Gathering Network Learning Objectives . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Lesson 1: Model a Gathering Network . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Boundary Conditions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Solution Criteria . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Exercise 1: Building a Model of a Network . . . . . . . . . . . . . . . . . . . . . . . . . Exercise 2: Performing a Network Simulation . . . . . . . . . . . . . . . . . . . . . . Looped Gathering Network Data . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Review Questions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Summary . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

163 163 164 164 165 173 175 179 179

Module 8: Water Injection Network Learning Objectives . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Lesson 1: Crossflow in Multilayer Wells . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Exercise 1: Determining Fluid Distribution in a Water Injection Network . . Review Questions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Summary . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

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Appendix A: PIPESIM 2010.1 Fundamentals Answer Key to Exercises Module 2: Simple Pipeline Tutorials . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Lesson 1: Single-Phase Flow Calculations . . . . . . . . . . . . . . . . . . . . . . . . Module 3: Oil Well Performance Analysis . . . . . . . . . . . . . . . . . . . . . . . . . . . . Lesson 1: Nodal Analysis . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Lesson 2: Fluid Calibration . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Lesson 3: Pressure/Temperature Matching . . . . . . . . . . . . . . . . . . . . . . . . Lesson 4: Well Performance Analysis . . . . . . . . . . . . . . . . . . . . . . . . . . . . Question (Optional) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Lesson 5: Flow Control Valve Modelling . . . . . . . . . . . . . . . . . . . . . . . . . . Module 4: Gas Well Performance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Lesson 2: Gas Well Deliverability . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Lesson 3: Erosion Prediction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Lesson 4: Choke Modelling . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Lesson 5: Critical Gas Rate . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Module 5: Horizontal Well Design . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Lesson 1: Inflow Performance Relationships . . . . . . . . . . . . . . . . . . . . . . . Module 6: Subsea Tieback Design . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Lesson 1: Flow Assurance Considerations for Subsea Tieback Design . . Lesson 2: Hydrates . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Lesson 3: Severe Riser Slugging . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Lesson 4: Slug Catcher Sizing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Module 7: Looped Gas Gathering Network . . . . . . . . . . . . . . . . . . . . . . . . . . Lesson 1: Model a Gathering Network . . . . . . . . . . . . . . . . . . . . . . . . . . . .

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About this Manual

About this Manual This training provides an introduction into the PIPESIM software application. PIPESIM is a production engineer’s tool that covers a wide range of applications relevant to the oil and gas industry. Applications featured in this training manual include well performance, fluid modeling, flow assurance and network simulation.

Learning Objectives After completing this training, you will know how to: •

build a single branch well or pipeline model

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define a black oil or compositional fluid model

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perform single branch simulation operations

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build a network model

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perform a network simulation.

What You Will Need You must have the following hardware and software to complete the training: •

Personal computer with minimum 512 MB RAM

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Training data sets.

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What to Expect In each module within this training material, you will encounter the following: •

Overview of the module

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Prerequisites to the module (if necessary)

•

Learning objectives

•

A workflow component (if applicable)

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Lessons, explaining a subject or an activity in the workflow

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Procedures, showing the steps needed to perform a task

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Exercises, which allow you to practice a task by using the steps in the procedure with a data set

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Scenario-based exercises

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Questions about the module

•

Summary of the module. You will also encounter notes, tips and best practices.

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Course Conventions Characters typed in Bold

Represent references to dialog box names and application areas or commands to be performed. For example, "Open the Open Asset Model dialog." or “Choose Components.” Used to denote keyboard commands. For example, "Type a name and press Enter." Identifies the name of Schlumberger software applications, such as ECLIPSE or Petrel.

Characters inside triangle brackets

Indicate variable values that the user must supply, such as and .

Characters typed in italics

Represent file names or directories, such as "... edit the file sample.dat and..." Represent lists and option areas in a window, such as Attributes list or Experiments area. Identifies the first use of important terms or concepts. For example, "compositional simulation…" or “safe mode operation.”

Characters typed in

fixed-width

Represent code, data, and other literal text the user sees or types. For example, enter 0.7323.

NOTE: Some of the conventions used in this manual indicate the information to enter, but are not part of the information For example: Quotation marks and information between brackets indicate the information you should enter. Do not include the quotation marks or brackets when you type your information. Instructions to make menu selections are also written using bold text and an arrow indicating the selection sequence, as shown: 1. Click File menu > Save (the Save Asset Model File dialog box opens.) OR Click the Save Model

toolbar button.

An ‘OR’ is used to identify an alternate procedure.

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Icons Throughout this manual, you will find icons in the margin representing various kinds of information. These icons serve as at-a-glance reminders of their associated text. See below for descriptions of what each icon means.

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Workflow Diagram Figure 1 illustrates the workflow of the PIPESIM application.

Figure 1

PIPESIM workflow

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Summary In this introduction, we:

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defined the learning objectives

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outlined what tools you will need for this training

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discussed course conventions that you will encounter within this material

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provided a high-level overview of the workflow.

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NOTES

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NOTES

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PIPESIM Introduction

Module 1 PIPESIM Introduction This module introduces PIPESIM 2010.1 and describes the graphical user interface (GUI) in detail to familiarize you with the application environment.

Learning Objectives After completing this module, you will know how to: •

create a new or open an existing project

•

navigate through the user interface

•

understand the structure of the output file

•

display plots in PsPlot.

You will also develop an understanding of PIPESIM toolbars, file system, engines, and operations.

Lesson 1

Introduction

PIPESIM is a steady-state, multiphase flow simulator used for the design and analysis of oil and gas production systems. With its rigorous simulation algorithms, PIPESIM helps you optimize your production and injection operations. As shown in Figure 2, PIPESIM models multiphase flow from the reservoir through to the surface facilities to enable comprehensive production system analysis. PIPESIM is most often used by reservoir, production or facilities engineers as an engineering user type to model well performance, conduct nodal (systems) analysis, design artificial lift systems, model pipeline networks and facilities, and analyze field development plans and optimize production. NOTE: Steady-state flow simulation implies that the mass flow rate is conserved throughout the system. This means there is no accumulation of mass within any component in the system.

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Figure 2

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Total production system

PIPESIM modules are available and licensed separately, depending on your needs: Base System

Production system analysis software for well modeling, NODAL analysis, artificial lift design, pipeline/process facilities modeling and field development planning.

Network Analysis (NET)

Optional add-on to PIPESIM to model complex networks that can include loops, parallel lines and crossovers

Compositional Model

Optional add on to PIPESIM

Multiflash Package

Optional add-on to PIPESIM. Compositional model is not required.

Multiflash Hydrates

Optional add-on to Multiflash package.

Multiflash Wax Thermodynamics

Optional add-on to Multiflash package.

Multiflash Asphaltene Optional add-on to Multiflash package. PIPESIM Linux Used only with Avocet IAM when Computation Engines ECLIPSE Parallel and is run on a Linux Cluster

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Avocet Gas Lift Optimization Module

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

PIPESIM OLGAS Steady State Flow Correlation 2-Phase

Third-party 2-phase mechanistic multiphase flow model

PIPESIM OLGAS Steady State Flow Correlation 3-Phase

Third-party 3-phase mechanistic multiphase flow model

PIPESIM Rod Pump Design / Optimization

Third-party module for designing rod pumps

PIPESIM Rod Pump Diagnostics

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

PIPESIM DBR Wax Deposition

Single-phase wax deposition model embedded in PIPESIM using wax properties characterized with the DBR Solids application

DBR Solids – Wax and Asphaltene Precipitation

Standalone application that predicts the wax and asphaltene precipitation temperature

DBR Solids – Wax Deposition Characterization

Standalone application that characterizes wax properties for use in PIPESIM wax deposition

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Lesson 2

A Tour of the User Interface

The PIPESIM graphical user interface (GUI) allows you to easily construct well and network models within a single environment. To launch PIPESIM from the Start menu, select Program files > Schlumberger > PIPESIM. As shown in Figure 3, the PIPESIM interface consists of one main window, a menu bar, a status bar, a standard toolbar and three specific toolbars related to single branch and network modeling views.

Figure 3

PIPESIM toolbars and menus

The Standard toolbar (Figure 4) contains common commands that are displayed in both the single branch and network views. The Single Branch toolbar (Figure 5) is displayed only in single branch view, while the Network toolbar (Figure 6) and the Net Viewer toolbar are displayed in the Network view. You can hide the toolbars from view using the Menu bar.

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Menu Bar

This has familiar Windows menus including File, Edit, Help, and more. All the tools available in other toolbars, plus all operations in PIPESIM.

Status Bar

The status of running operation. If there is no operation running, it will show the path of model.

Standard Toolbar

Available in both single branch and network model and is comprised of the icons and processes shown in Figure 4.

Figure 4

Single Branch Toolbar

Figure 5

Standard toolbar functionality

These tools (Figure 5) are available only in single branch models or the network model in single branch mode. It consists of all objects required to build the physical model. These tools can also be accessed from the Menu bar.

Single Branch toolbar

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Network Toolbar

This toolbar (Figure 6) is available only in the network model view. It consists of all objects required to build the physical network model. These tools can also be accessed from the menu bar.

Figure 6

Network toolbar

NOTE: Icons in the Network toolbar and the Net Viewer bar are not highlighted in the Single Branch model. Similarly, icons in the Single Branch toolbar are not highlighted in the network model. From the Network model, you must access the Single Branch viewing mode by double-clicking on the object to insert necessary equipment, such as compressors, pumps, chokes, and more.

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Lesson 3

PIPESIM File System and Calculation Engines

PIPESIM generates several input and output files in its working directory when you run a model. The engines and file system are listed here: PIPESIM Engines

PIPESIM File System

•

PIPESIM uses one engine for a Single Branch model and another engine for a Network model.

•

Psimstub.exe is the PIPESIM engine for single branch operations

•

Pnetsub.exe is the PIPESIM engine for a network simulation

•

You can set or change the path of these engines by selecting Setup > Preferences > Choose Paths.

PIPESIM stores data in these formats: •

ASCII files

•

Binary files

•

Microsoft Access database.

The file extensions are processed by the simulation engine to create output files. Extension *.bps

Type of File Single branch model PIPESIM file

Application Files All the data necessary to run a model. Single Branch model file includes data for units, fluid composition, well IPR, system data, and more. The support team requires these files when you make support queries.

*.bpn

Network model PIPESIM file

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Same as above for a Network model.

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Extension *.out

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Type of File Output file

Output Files All output data in ASCII format. The output file is produced from both Single Branch and Network models. Node by node results are reported in output files. The output file is divided into sections. You have the option to show or hide a section by using Setup > Define Output. Mostly, errors are reported in output file. Remember to check this file in case of an error in a PIPESIM model.

*.sum

Summary file

Summary report of PIPESIM output, such as pressures and temperatures at sources and sinks. Plot Files

*.plc

Profile plot

Variables you can plot with distance and elevation in PsPlot. These variables include pressure, temperature and fluid properties, and more. PsPlot is a plotting utility in PIPESIM.

*.plt

System plot

Same as the *.plc file, but does not contain variables such as distance and elevation. This file is primarily used to see sensitivity of one variable to another. For example, you can plot water cut with system outlet pressure. Miscellaneous Files

*.psm

This is the keyword input file generated by the user interface for the PIPESIM single branch engine named psimstub.exe. In certain situations (mainly debugging), this file can be manually modified via expert mode.

*.tnt

All instructions sent to the PIPESIM network engine - pnetstub.exe. The PIPESIM engine reads this file for processing – not the *.bpn file.

*.mdb

Access database file

Black oil fluid data, electric submersible pump (ESP) performance curves, user-defined pump and compressor curves, and pressure survey data. You can access this file by selecting Setup > Preferences > Choose Paths. You can set the path of this file in the Data Source box.

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Extension *.pvt

PIPESIM Introduction

Type of File PVT file

Miscellaneous Files A single stream composition and a table of fluid properties for a given set of pressure and temperature values. If needed, this file can be created by a commercial PVT package, such as Multiflash, Hysys, DBRSolids or others, or using the Compositional module in PIPESIM.

*.unf

Unit file

Stores user-defined unit sets, which can be passed from user-to-user.

*.env

Phase envelope file

*.map

Flow regime map

Output Files The PIPESIM output file is an ACSII format file, generated by either a Single Branch or a Network model. This is a very large file divided into many sections. You can customize the output report by selecting Setup > Define output (Figure 7). Figure 8 is a sample of the output from the primary output section.

Figure 7

Define Output tab

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Figure 8

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Sample output file (primary output section)

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Lesson 4

Plots

Plots in PIPESIM are displayed with a plotting utility called PsPlot. The path to the PsPlot executable is normally located in the PIPESIM installation directory, such as C:\Program Files\Schlumb erger\PIPESIM\Programs\PSPlotX.exe. You can set the path of PsPlotX.exe by selecting Setup > Preferences > Choose Paths. You can use PsPlot to open both *.plc and *.plt files. Optionally, you can view data in tabular mode (Figure 9) by clicking on the Data tab.

Figure 9

Tabular view of PsPlot data

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You can change display settings of PsPlot, such as title, minimum or maximum axis, color, legends and more, by selecting Edit > Advanced Plot Setup (Figure 10).

Figure 10

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Advanced Plot Setup dialog

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Lesson 5

Single Branch Operations

There are many single branch operations available in PIPESIM (Figure 11).

Figure 11

List of single branch operations

System Analysis The systems analysis operation enables you to determine the performance of a given system for varying operating conditions on a case-by-case basis. Results of the system analysis operation are provided in the form of plots of a dependent variable, such as outlet pressure, versus an independent variable, such as flow rate. You can generate families of X-Y curves for the system by varying either a single sensitivity variable (such as water cut) or by applying permutations of a group of sensitivity values. The ability to perform analysis by combining sensitivity variables in different ways makes the system analysis operation a very flexible tool for plotting data on a case-by-case basis.

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A typical plot resulting from a system analysis operation is shown in Figure 12.

Figure 12

Typical System Analysis plot

Pressure/Temperature Profile You can generate pressure and temperature profiles of the system as a function of distance/elevation along the system. Both temperature and pressure profiles are generated on a nodeby-node basis for the system. NOTE: The system analysis operation also generates Pressure/ Temperature profile plots for each case. Likewise, Pressure/Temperature Profile operations generate a system plot.

Flow Correlation Comparison Quickly compare various multiphase flow correlations against measured data. The Data Matching operation introduced in PIPESIM 2009.1 is recommended for regression of friction and holdup multipliers to tune multiphase flow correlations to match well test data.

Data Matching Select parameters that will be automatically adjusted to match measured pressure and temperature data for a particular system. These parameters include multipliers for heat transfer coefficient (to match temperature measurements), as well as friction factor and holdup factor multipliers (to match pressure measurements).

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This operation allows you to select and rank multiple flow correlations, and to simultaneously match pressure and temperature measurements.

NODAL Analysis A common way to analyze well performance is through a NODAL analysis plot to visually assess the impact of various system components. This is done by splitting the system at the point of interest known as the NODAL analysis point and graphically presenting the system response upstream (Inflow) and downstream (Outflow) of the nodal point. The point at which the inflow and outflow curves intersect is the operating point for the given system, as shown in Figure 13.

Figure 13

NODAL analysis Inflow/Outflow curves

Optimum Horizontal Well Length Predicts hydraulic well bore performance in the completion. The multiple source concept leads to a pressure gradient from the blind-end (toe) to the producing-end (heel) which, if neglected, results in over-predicting deliverability. The reduced drawdown at the toe results in the production leveling off as a function of well length, and it can be shown that drilling beyond an optimum length would yield no significant additional production.

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Reservoir Tables For the purposes of reservoir simulation, it is often necessary to generate VFP curves for input to a reservoir simulation program. The VFP curves allow the reservoir simulator to determine bottomhole flowing pressures as a function of tubing head pressure, flow rate, GOR, water cut and the artificial lift quantity. The reservoir simulator interface allows you to write tabular performance data to a file for input into a reservoir simulation model. Currently, the following reservoir simulators are supported: •

ECLIPSE

•

PORES

•

VIP

•

COMP4

•

MoReS (Shell’s in-house reservoir simulator).

Well Performance Curves These can be created in the network solver to produce faster solution times. A curve is created that represents the performance of the well under specified conditions. The network solver will then use this curve instead of modeling the well directly.

Gas Lift Rate vs. Casing Head Pressure Determines the gas lift injection rate possible based on the casing head pressure for a well.

Artificial Lift Performance Analyzes the effects of artificial lift of a production well using either gas lift or an electric submersible pump (ESP). The performance curves allow for sensitivities on various parameters, including wellhead pressure, water cut, tubing and flowline diameters.

Wax Deposition With various deposition model/methods, generates wax deposition profile (Distance vs. Wax deposition thickness) and system (Wax Volume against time) plots.

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Depending on selected methods, you must enter wax properties or provide a properties file. NOTE: The artificial lift operation is essentially a specific implementation of the system analysis operation.

Review Questions •

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

•

What single branch operations are available?

Summary In the module, you gained an understanding of PIPESIM toolbars, file system and engines, and operations. You also learned about: •

starting PIPESIM with a new or existing project

•

navigating and learn the user interface

•

viewing results in output file

•

displaying plots in PsPlot

•

selecting single branch options

•

identifying PIPESIM executables and data files.

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NOTES

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Simple Pipeline Tutorials

Module 2 Simple Pipeline Tutorials The purpose of these tutorials is to familiarize you with the PIPESIM Single Branch interface by building and running simple examples. You begin by performing a simple hand calculation to determine the pressure drop in a water pipeline, and then construct a simple pipeline model to validate pressure drop along a horizontal pipeline for a given inlet pressure and flow rate. You will also run some sensitivity studies on the model.

Learning Objectives After completing this module, you will know how to: •

build the physical model

•

create a fluid model

•

choose flow correlations

•

perform operations

•

view and analyze results.

Lesson 1

Single-Phase Flow Calculations

Consider the case of a pipeline transporting water (Figure 14).

Figure 14

Pipeline transporting water

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

 dp     dL  total =

 dp     dL  frictional +

 dp     dL  elevational +

 dp     dL  accelerational

The accelerational term is normally negligible except for low pressure and high velocity gas flow, although PIPESIM will always calculate this term. Assuming the accelerational term to be zero for your hand calculation, the pressure gradient equation becomes:

fv 2  dp     dL  total = 2 gd (frictional) - g sin  (elevational) Where:

 = fluid density (lbm/ft3) g = gravitational constant f = moody friction factor v = fluid velocity (ft/s) d = pipe inside diameter (ft)

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Exercise 1

Modeling a Water Pipeline with Hand Calculations

In this exercise, using the data in Table 1 and assuming the flow is isothermal, you perform a hand calculation to determine the delivery pressure of the pipeline using single-phase flow theory. NOTE: You will need a hand calculator or MS Excel to complete this exercise. Table 1: Water Pipeline Modelling Data Pipeline Data Diameter

d

3

in

Length

L

20,025

ft

Elevation Change

Z

1,000

ft

Horizontal Distance

X

20,000

ft

Ambient Temperature

Tamb

60

degF

Inclination Angle

q

2.866

º

Roughness

e

0.0015

in

Relative Roughness

/d

0.0005

in

(= 0.25 ft)

(=.05002 radians)

Fluid Data Water viscosity

w

1.2

cp

Water density

w

63.7

lbm/ft3

(= 8.06e-4 lb/ft-s)

Operating Data Source Temperature

Tinlet

60

degF

Inlet Pressure

Pin

1,200

psia

Water Flow rate

Qw

6,000

BPD

(= 0.39 ft3/s)

Constants Gravitational

g

32.2

ft/s2

TIP: To ensure unit consistency when performing hand calculations, refer to the converted unit in the far right column of the table.

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1. Calculate the water velocity:

v

Qw 2  d     4  = _____________ ft/s

2. Calculate the Reynold’s number:

Re 

vd 

= ______________

Is the flow laminar or turbulent? (See the Moody diagram, Figure 15.) 3. Determine the friction factor using the Churchill equation for turbulent flow. NOTE: Alternatively, you can look up the friction factor using the Moody diagram in Figure 15.

f = __________________________

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Figure 15

Simple Pipeline Tutorials

Moody diagram

4. Evaluate the frictional pressure term,

 dp     dL  friction

fv 2 2 gd

:

= __________ psf/ft

divide this by 144 to get_______ psi/ft 5. Multiply by the given length of pipe, L, to get the total frictional pressure drop:

dp friction

= _____________ psi

6. Evaluate the elevational pressure term,  sin  NOTE: If using Excel, be sure the angle is in radians.

dp friction

= __________ psf/ft

divide this by 144 to get________ psi/ft

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7. Multiply by the given length of pipe, L, to get the total elevational pressure drop

dpelevation

= _____________ psi

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

 dp   dp   dp        9.  dL  total =  dL  frictional +  dL  elevational  dp     dL  total = ________ psi/ft 10. Multiply by the given length of pipe, L, to get the total pressure drop

dptotal

= _____________ psi

11. Calculate the outlet pressure given the inlet pressure: Pout = Pin -

Exercise 2

dptotal

= __________ psia

Modeling a Water Pipeline with PIPESIM

In this exercise, you use PIPESIM to build the water pipeline you hand calculated in . You will define parameters for each component in the model, perform operations, view and analyze the results, and compare PIPESIM results to your hand calculations. There are three parts to this exercise: 1. Starting the application 2. Creating the fluid model (water) and selecting flow correlations 3. Building the physical model.

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Getting Started To start the application: 1. Start PIPESIM by selecting Start > Program Files > Schlumberger > PIPESIM. 2. Click NEW Single Branch Model….

3. From the Setup > Units menu, select the Eng(ineering) units. 4. From the Setup > Define Output tab, uncheck all report options except Primary Output and Auxiliary Output.

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Building the Physical Model (a Water Pipeline Model) You begin by defining the physical components of the model. 1. Click Source and place it in the window by clicking inside the Single Branch window. 2. Click Boundary Node

3. Click Flowline

and place it in the window.

.

4. Link Source_1 to the End Node S1 by clicking and dragging from Source_1 to the End Node S1. NOTE: The red outlines on Source_1 and Flowline_1 indicate that essential input data is missing.

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5. Double-click Source_1 and the source input data user form displays. a. Fill in the form.

b. Click OK to exit the user form. 6. Double-click Flowline_1 and the input data user form is displayed. 7. Fill the form as shown below, ensuring that the rate of undulations = 0 (no terrain effects).

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

9. Click OK to exit the user form and accept the overall heat transfer coefficient (U value) defaults.

Creating the Fluid Model (Water) and Selecting Flow Correlations To create the fluid model and select flow correlations: 1. Select Setup > Black Oil to open the Black Oil Fluid menu. 2.

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Fill in the Black Oil user form and click OK when you are finished.

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3. Select File > Save As and save the model as Exercise1_WaterPipe.bps. 4. From the Setup > Flow Correlations menu, select the Moody single-phase flow correlation.

5.

Click OK.

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Performing Operations PIPESIM Single Branch mode offers several simulation operations, depending on the intended workflow. Many of these operations are explained in the exercises that follow. The Pressure/Temperature Profile operation is used to acquire the distribution of pressure, temperature and many other parameters across the flow path. To perform these operations: 1. In the Operations menu, select the Pressure/Temperature Profile operation. NOTE: The Pressure Temperature Profile operation requires that you designate a calculated variable and specify all other variables. Generally, two specifications are provided for use with the rate, inlet pressure and outlet pressure, while the third is calculated. However, all three can be specified and a forth variable will be calculated, for example choke size. 2. Enter the known flowing conditions.

3. Click Run Model. The pressure calculation uses the Moody correlation (default single-phase correlation).

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4. View and analyze the results. The pressure profile below should be visible upon completion of the run.

5. To display a tabular output of the Pressure/Temperature profile, click the Data tab at the top of your graph. Notice that the outlet pressure is 89 psia. 6. (Optional) Copy this data into Excel: a. Highlight the cells of interest. b. Press Ctrl + C. c. Select a cell in Excel and press Ctrl + V. d. To view an abbreviated form of the full output file, select Reports > Summary File. You can observe the output:

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

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7. The Summary file reports the frictional and elevational components of the total pressure change in the pipeline. Compare the results of PIPESIM to your hand calculations by entering the appropriate values in the table. Result

Hand Calculation

PIPESIM

Liquid Velocity (ft/s)

∆Pfrictional (psi) ∆Pelevational (psi) ∆Ptotal (psi) Outlet Pressure (psia)

8. View the output file by selecting Reports > Output File. By default, the output file is divided into five sections: • Input Data Echo (Input data and Input units summary) • Fluid Property Data (Input data of the fluid model) • Profile and Flow Correlations (Profile and selected correlations summary) • Primary Output • Auxiliary Output. NOTE: If the units reported in the output file are not the desired ones, you should change the units (Setup > Units), pick the preferred unit system, and rerun the simulation.

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The Primary Output File The primary output is shown in Figure 16.

Figure 16

Example of the primary output file

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The primary output contains 17 columns: •

Node number: node at which all the measures on the row have been recorded. (The nodes have been spaced by default with a 1,000 foot interval)

•

Horizontal Distance (cumulative horizontal component of length)

•

Elevation (absolute)

•

Angle of inclination (from the horizontal)

•

Angle of inclination (from the vertical)

•

Pressure

•

Temperature

•

Mean mixture velocity

•

Elevational pressure drop

•

Frictional pressure drop

•

Actual Liquid flow rate at the P,T conditions of the node

•

Actual Free gas rate at the standard P,T conditions of the node

•

Total Mass flow rate of the node

•

Actual Liquid density at the P,T conditions of the node

•

Actual Free gas density at the P,T conditions of the node

•

Slug Number

•

Flow Pattern.

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

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The Auxiliary Output File The auxiliary output is shown in Figure 17.

Figure 17

Example of the auxiliary output file

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The auxiliary output consists of 19 columns: •

Node number

•

Horizontal distance (cumulative)

•

Elevation (absolute)

•

Superficial liquid velocity

•

Superficial gas velocity

•

Liquid mass flow rate

•

Gas mass flow rate

•

Liquid viscosity

•

Gas viscosity

•

Reynolds number

•

No-slip Liquid Holdup Fraction

•

Slip Liquid Holdup Fraction

•

Liquid Water cut

•

Fluid Enthalpy

•

Erosional Velocity ratio

•

Erosion rate (if applicable)

•

Corrosion rate (if applicable)

•

Hydrate temperature sub-cooling (if applicable)

•

Liquid Loading Velocity Ratio (if Applicable).

TIP: The values of the Reynolds number indicate that the flow regime is turbulent (NRE > 2000) and are consistent with the results of the hand calculations.

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Exercise 3

Simple Pipeline Tutorials

Analyzing Multiple Scenarios with Sensitivities

In this exercise, you will continue using the previous example to explore how your model responds to different inlet temperatures. You will set a range of temperatures, perform operations, and view and analyze your results. To modify the P/T profile operation and view the output: 1. From the Operations menu, select the Pressure/Temperature Profile Operation. a. Select Source_1 as the Object and Temperature as the Variable. In the Pressure/Temperature Profile user form, click

.

b. Fill in the input form, as shown.

c. Click Apply and close the Set Range window. The completed form is shown in the figure.

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2. Click Run Model. The pressure calculation uses the Moody correlation (Default single phase correlation). 3. Observe the PsPlot output. This pressure profile should be visible upon completion of the run.

Notice that the highest inlet temperature generates the lowest pressure drop. As the temperature increases: • the viscosity decreases • the Reynolds number increases • the corresponding friction factor decreases • the frictional pressure gradient is lower. In other words,

T ↑ »  ↓ »

Re 

vd  ↑ »f↓»

 dp     dL  friction ↓

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

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4. Select the Data tab in the Plot window to see all the data for each temperature in a tabular format. 5. Open the output file (*.out). The output file can be opened in one of two ways: Click the Output File button from within the Operations (Pressure/Temperature Profiles) dialog:

OR Select Reports > Output File. By default, the output file contains the information for the first case only. (T = 20 degF). 6. To report all sensitivity cases: a. Select Setup > Define Output. b. Ensure that options are selected as shown in the figure. c. Set the number of cases to print to 4.

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7. Rerun the operation. TIP: If you do not change the operation or alter any of the parameters within the Operations menu, you can run the simulation by clicking Run

.

8. Open the output report to view the results of the four sensitivity cases. 9. To add segment data to your report, select Setup > Define Output and check the Segment Data in the Primary Output option. 10. Re-run the operation. 11. Open the output file and observe that additional segments have been inserted.

NOTE: By default, PIPESIM performs the pressure drop calculation for each of those additional segments to obtain precise averaged values of properties, such as liquid holdup or velocities at the main nodes.

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Exercise 4

Simple Pipeline Tutorials

Modeling a Single-Phase Gas Pipeline

In this exercise, you investigate the flow of a single phase gas without changing the physical components of our previous example. To investigate the flow of a single phase gas: 1. Select Setup > Black Oil and modify the user form, as shown in the figure. This represents 100% gas a. Change Water Cut to WGR and GOR to OGR. b. Set values for WGR and OGR as 0. c. Rename the fluid as gas.

2. Under the Setup > Define Output menu, uncheck the box labeled Segment Data in Primary Output.

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3. Select Operations > Pressure/Temperature Profile and modify the Pressure/Temperature profile operation.

4. Click Run Model. As for the case of a single-phase liquid, the pressure calculation will be done using the Moody correlation. 5. Inspect the pressure profile plot upon completion of the run.

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In the previous example using water, the density remained constant because water is essentially incompressible. However, gas is a compressible fluid with a density described by the ideal gas law, rearranged into the following expression: g 

pM zRT

Where:

g = gas density p = pressure M = Molecular Weight z = gas compressibility factor R = ideal gas constant T = Temperature Notice that the highest inlet temperatures yield the highest pressure drop. This is because, as the temperature increases the density decreases, which results in a decrease in the Reynolds number. Correspondingly, the friction factor increases and, as a result, the frictional pressure gradient is higher. In other words,

T ↑ » g ↓ »

Re 

 dp   vd    ↓ » f ↑ »  dL  frictiona↑

Also, because

fv 2  dp     dL  friction = 2gd the velocity increase due to gas expansion has an exponential effect on the frictional pressure term. This accounts for the increase in the frictional gradient along the flowline and the curvature in the pressure profile plot. NOTE: The viscosity of the gas increases slightly with increasing temperature, but this effect is small and does little to offset the effects of decreasing density.

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Exercise 5

Calculating Gas Pipeline Flow Capacity

In the previous exercises, you calculated the outlet pressure given a known inlet pressure and flow rate. In this exercise, you specify known inlet and outlet pressures and calculate the corresponding gas flow rate. There are three key variables involved in Single Branch operations: •

Inlet pressure

•

Outlet pressure

•

Flow rate.

Two of these variables must be specified but the third is calculated. Some operations allow you to specify all three variables, in which case a matching variable, such as pump speed or choke setting, must be specified. PIPESIM generally performs calculations in the direction of flow. Therefore, when the outlet pressure is calculated, as in the previous examples, the solution is non-iterative in that the outlet pressure is calculated during the first and only pressure traverse calculation. However, when outlet pressure is specified and either the inlet rate or the flow rate is calculated, the process becomes iterative, and successive estimates of the calculated variable are supplied until the calculated outlet pressure agrees with the specified pressure. To calculate gas deliverability: 1. Open the Pressure/Temperature Profiles user form and select Gas Rate as the calculated variable. 2. Specify 600 psia for the outlet pressure.

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3. Clear the temperature sensitivity values, shown in the figure, by highlighting the cells and pressing Ctrl + X.

4. Click Run Model on the user form. 5. Observe the PsPlot output. The gas flow rate corresponding to the specified pressure drop is shown in the legend beneath the profile plot.

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6. Observe the output files (*.out). The iteration routine for this operation can be seen in the output file, as shown below. NOTE: To view this report, you must check Iteration Progress Log under Setup/Define Output)

7. Save your file as exer5.bps.

Lesson 2

Multiphase Flow Calculations

While pressure losses in single-phase flow in pipes have long been accurately modeled with familiar expressions such as the Bernoulli equation, accurate predictions of pressure loss in twophase flow have proved to be more challenging because of added complexities. The lower density and viscosity of the gas phase causes it to flow at a higher velocity relative to the liquid phase, a characteristic known as slippage. Consequently, the associated frictional pressure losses result from shear stresses encountered at the gas/liquid interface as well as along the pipe wall. Additionally, the highly compressible gas phase expands as the pressure decreases along the flow path. Further complicating matters are the variety of physical phase distributions that are characterized by flow regimes or flow patterns (Figure 18 and Figure 19). The prevailing flow pattern for a specific set of conditions depends on the relative magnitude of the forces acting on the fluids.

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Buoyancy, turbulence, inertia, and surface-tension forces are greatly affected by the relative flow rates, viscosities, and densities of a fluid, as well as the pipe diameter and inclination angle. The complex dynamics of the flow pattern govern slippage effects and, therefore, variations in liquid holdup and pressure gradient.

Figure 18

Multiphase flow regimes for horizontal flow

Figure 19

Multiphase flow regimes for vertical flow

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Many empirical correlations and mechanistic models have been proposed to predict liquid holdup and pressure loss. (Refer to the PIPESIM help system for details). Some are very general, while others apply only to a narrow range of conditions. Many of these approaches begin with a prediction of the flow pattern, with each flow pattern having an associated method of predicting liquid holdup. Because the gas travels faster in steady-state flow, it will occupy less pipe volume. The fraction of pipe volume occupied by the liquid is called the liquid holdup and is illustrated in Figure 20. Liquid holdup is generally the most important parameter in calculating pressure loss. Liquid holdup is also necessary to predict hydrate formation and wax deposition and to estimate the liquid volume expelled during pigging operations for sizing slug catchers. The liquid holdup prediction is used to determine a twophase friction factor from which a pressure gradient is calculated.

Figure 20

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Liquid Holdup

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Exercise 1

Simple Pipeline Tutorials

Modeling a Multiphase Pipeline

The previous exercises explored single-phase flow of water and gas through a pipeline. In this exercise, you modify the existing pipeline model and explore multiphase flow. 1. Insert Report Tool flowline, as shown.

at the beginning and end of the

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

3. Release the mouse button when the arrow is on top of the Report Tool icon and the flowline turns yellow.

4. Repeat the previous step for the second Report Tool icon. 5. Select Connector the Source icon.

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and connect the first Report Tool to

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

7. Double-click on each of the Report Tool icons and enter the data shown in the figure.

8. Double-click on the Flowline and select the Heat Transfer tab.

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9. Choose the typical Heat Transfer Coefficient value for bare pipe exposed to air, as shown below.

10. Select Setup > Black Oil and specify the fluid properties.

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11. From the Setup > Flow Correlations menu, select Beggs and Brill Revised (Taitel-Dukler map) for the horizontal flow correlation and Hagedorn and Brown for the vertical flow correlation. NOTE: Observe that the Swap angle is set to 45º. This is the angle that corresponds to the switch between use of the vertical and horizontal flow correlation. In this example, the pipeline inclination angle is about 3º, which means that only the horizontal flow correlation is used.

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

13. Select Operations > Pressure Temperature Profiles and enter the information. NOTE: The pressure drop is calculated using the Moody correlation (default single-phase correlation) and the Beggs and Brill Revised correlation. The results from the Taitel-Dukler Flow Regime map will be reported and will influence the pressure drop calculations performed by the Beggs and Brill Revised correlation if the flow regime is different from that predicted by the Beggs and Brill correlation.

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14. Run the model. 15. Observe the pressure profile plot.

16. From the Reports menu, open the output file. The following display can be seen in the primary output section of the output file.

Notice that the flow is initially single-phase liquid until the pressure falls below the bubblepoint upon which two-phase oil-gas flow is present. The single-phase Moody correlation is used in the first part of the pipe, and the Beggs and Brill multiphase correlation is used in the second part of the pipe after the pressure falls below the bubblepoint. TIP: The holdup for each of the segment can be seen in the auxiliary output.

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The number in the far right column is the Erosional Velocity Ratio (EVR = actual velocity/API 14e limit) and is displayed only when it is higher than 1. The spot reports output is shown in Figure 21. NOTE: To view the graphics and output in SI or Custom units, specify the units via the Setup > Units… option and rerun the model.

Figure 21

Sample spot report output

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The flow regime map (Figure 22) can also be viewed in PsPlot by selecting Reports > Flow Regime Map.

Figure 22

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Flow regime map

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Review Questions •

Which types of pressure drop contributions are reported by PIPESIM in output file (by default)?

•

What is the default single-phase flow correlation in PIPESIM?

•

How do you describe a Black Oil fluid model for water or dry gas?

•

Did you get any difference in pressure drop between hand calculation and PIPESIM reported results? If yes, why?

Summary In this module, you learned about: •

building the physical model

•

creating a fluid model

•

choosing flow correlations

•

performing operations

•

viewing and analyzing results.

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NOTES

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Oil Well Performance Analysis

Module 3 Oil Well Performance Analysis This module examines a producing oil well located in the North Sea. You analyze the performance of this well using NODAL analysis, calibrate black oil fluid (low GOR) using laboratory data, and match flow correlations with pressure survey data. You will also analyze the behavior of the well with increased water cut and find an opportunity to inject gas at a later stage when the well is unable to flow naturally.

Learning Objectives After completing this module, you will know how to: •

perform a NODAL analysis

•

estimate bottomhole flowing conditions

•

calibrate pressure, volume and temperature (PVT) data

•

perform flow correlation matching

•

perform inflow performance relationship (IPR) matching

•

conduct water cut sensitivity analysis

•

evaluate gas lift performance

•

install a flow control valve.

Lesson 1

NODAL Analysis

NODAL analysis evaluates the performance of an oil well. You specify a nodal point, usually at the bottomhole or wellhead, and divide the producing system into two parts: the inflow and the outflow. This is represented graphically in Figure 23. The solution node is defined as the location where the pressure differential upstream (inflow) and downstream (outflow) of the node is zero. Solution nodes can be judiciously selected to isolate the effect of certain variables.

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

Nodal Analysis Psep

PR

Inflow Outflow

Pwf

Pwf

PR

Psep 17

Figure 23

Flow rate

Intersection points of the inflow and outflow performance curves

Getting Started Before beginning an oil well performance analysis: 1. Select File > New > Well Performance Analysis. 2. From Setup > Units, set the engineering units.

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Exercise 1

Oil Well Performance Analysis

Building the Well Model

Model building refers to setting up all objects, from the source to the sink, and defining the properties of these objects. You can select PIPESIM single branch objects using either the Tool menu or the toolbar at the top of PIPESIM window. To build the well model: 1. Click Vertical Completion on the single branch toolbar to choose a vertical completion object and place it in the Single Branch flow diagram. 2. Click Boundary Node the flow diagram.

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3. Click Tubing object and connect VertWell_1 to the End Node S1 by clicking and dragging from VertWell_1 completion to the End Node S1. NOTE: The red outlines on VertWell_1 and Tubing_1 indicate that essential input data are missing.

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

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Completion model

Well PI

Use Vogel?

Yes

Reservoir Pressure

3,600 psia

Reservoir Temperature

200 degF

Liq. Productivity Index

8 stb/d/psi

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5. Double-click on the tubing object and enter the tubing properties based on data listed in the tables. Deviation Data Measured Depth (ft)

True Vertical Depth (ft)

0

0

1,000

1,000

2,500

2,450

5,000

4,850

7,500

7,200

9,000

8,550 Geothermal Gradient

Measured Depth (ft)

Ambient Temp. (degF)

0

50

9,000

200 Tubing Data

Bottom MD (ft)

Internal Diameter (inches)

8,600

3.958

9,000

6.184

6. Specify an Overall Heat Transfer Coefficient = 5 btu/hr/ft 2/F (override the default value). NOTE: Use the overall heat transfer coefficient to calculate total heat transfer through the pipe wall. The overall heat transfer coefficient depends on the fluids and their properties on both sides of the wall, as well as the properties of the wall and the transmission surface. 7. Click the Summary table button to observe the configuration summary. 8. Set the Distance between nodes to 100 ft. 9. Select Setup > Black Oil.

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10. Enter the fluid properties, as shown in the table. Assume default PVT correlations and no calibration data. Black Oil PVT Data Water Cut

10 %

GOR

500 scf/stb

Gas SG

0.8

Water SG

1.05

Oil API

36 ºAPI

The fluid physical properties are calculated over the range of pressures and temperatures encountered by the fluid and used by multiphase flow correlations to determine the phases present, the flow regime, and the pressure losses in single and multiphase flow regions. NOTE: The heat transfer calculations use the fluid thermal properties. 11. From the Setup > Flow Correlation menu, ensure that the Hagedorn-Brown correlation is selected for vertical flow and the Beggs-Brill Revised correlation is selected for horizontal flow. Select the correlation that is best suited for the fluid and operating conditions of interest. NOTE: There is no universal rule for selecting a multiphase flow correlation that is good for all operating scenarios. See the PIPESIM help system for information on the applicability of flow correlations. 12. Save the model as CaseStudy1_Oil_Well.bps.

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Exercise 2

Performing NODAL Analysis

In this exercise, you perform a NODAL analysis operation for a given outlet (wellhead) pressure to determine the operating point (intersection) and the absolute open flow potential (AOFP) of the well. To do this, add a NODAL analysis point at the bottomhole to divide the system into two parts. Part A extends from reservoir to the bottomhole, while Part B runs from the bottomhole to the wellhead. To perform a NODAL analysis: 1. Select a NODAL analysis point from the toolbar and drop it near the completion. 2. Click on the tubing and drag its bottom tip over to the NODAL analysis point. 3. Insert a connector to link the completion with the NODAL analysis point.

N.A. Point

4. Select Operations > NODAL analysis. 5. Enter an Outlet Pressure (Boundary Condition) of 300 psia.

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6. Leave Inflow Sensitivity and Outflow Sensitivity empty. TIP: For users having PIPESIM 2009.1 or older versions: Increasing the number of points in inflow and outflow curves provides more detailed curves from which a more accurate intersection can be read. Click Limits in the Nodal Analysis window to change the number of points in inflow and outflow curves. PIPESIM 2010.1 has implemented several modifications in Nodal Analysis calculation. The most significant is displaying the intersection point on the nodal plot. As a result, you do not depend on reading from the plot and the solution points are calculated with the values presented in Data tab. TIP: There is no need to specify/change number of points for inflow and outflow curve unless you wish to use those data for further processing. The PIPESIM engine automatically determines the number of points and their spacing for both inflow and outflow curves. 7. Run the model. 8. Inspect the plot and select the Data tab to determine the answers.

Results (Outlet) Wellhead Pressure

300 psia

Operating Point Flow rate Operating Point BHP AOFP

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Exercise 3

Oil Well Performance Analysis

Performing a Pressure/ Temperature Profile

The Pressure/Temperature profile calculates pressure and temperature on a node-by-node basis for the system. The results are plotted for pressure or temperature as a function of distance/ elevation along the flow path. To estimate bottomhole flowing conditions: 1. Run Operations > Pressure / Temperature Profile. 2. Enter the Outlet (Tubing head) pressure of 300 psia. 3. Specify the liquid rate as the calculated variable. 4. Leave Sensitivity Data empty. NOTE: Inlet and outlet pressure always reference the boundaries of the system. In this particular case, inlet pressure is the reservoir pressure, while the outlet pressure corresponds to wellhead pressure. The inlet pressure is specified at the completion or source level, whereas the outlet pressure is always specified manually within the operation. 5. Run the model. NOTE: PIPESIM 2010.1 generates a Profile plot for every valid combination of inflow-outflow cases. Because of this, there is no need to run a separate Pressure Temperature Profile operation. 6. Inspect the plot and summary output report to determine answers.

Results Wellhead Pressure

300 psia

Production Rate Flowing BHP Flowing WHT Depth at which gas appears

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Questions These questions are for discussion and review. •

What is the significance of intersection between the inflow and outflow curves?

•

What are the advantages/disadvantages of performing a Pressure/Temperature Profile versus a NODAL analysis?

Lesson 2

Fluid Calibration

Fluid properties (also known as PVT properties) are predicted by correlations developed by fitting experimental fluid data with mathematical models. Various correlations have been developed over the years based on experimental data sets covering a range of fluid properties. The PIPESIM help system describes the range of fluid properties used to develop each correlation, which helps you select the most appropriate correlation for the fluid at hand. The default correlations in PIPESIM are based on the overall accuracy of the correlations as applied to a broad range of fluids. To increase the accuracy of fluid property calculations, PIPESIM provides functionality to match PVT fluid properties with laboratory data. Calibration of these properties can greatly increase the accuracy of the correlations over the range of pressures and temperatures for the system being modeled. For example, calibration of the bubblepoint pressure can result in the initial appearance of gas at a depth of perhaps a thousand feet higher or lower than an uncalibrated model. This results in a significantly different mixture fluid density and, thus, a much different elevational pressure gradient. Likewise, calibration of the fluid viscosity can drastically improve the calculation of the frictional pressure gradient, especially in heavy oils and emulsions. If the calibration data is omitted, PIPESIM calibrates on the basis of oil and gas gravity alone, resulting in a loss of accuracy. After the calibration is performed, a calibration factor calculated as ratio of measured value to the value calculated by selected correlation.

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There are two calibration options available in PIPESIM: •

Single Point calibration

•

Multi-Point calibration.

Single Point Calibration In many cases, actual measured values for some properties show a slight variance from calculated values. When this occurs, it is useful to calibrate the property using the measured point. PIPESIM can use the known data for the property to calculate a calibration constant Kc; Kc = Measured Property @(P,T)/Calculated Property @(P,T) This calibration constant is used to modify all subsequent calculations of the property in question, that is: Calibrated value = Kc (Predicted value)

Multi-Point Calibration In multi-point calibration, black oil correlations are tuned so that the correlation honors all data points (Figure 24).

Figure 24

Correlation running through all data points

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A calibration factor is calculated for every measurement point, and a plot is generated for the Pressure vs. Calibration factor, as shown in Figure 25.

Figure 25

Pressure vs. Calibration factor

NOTE: This is not a best fit method, as all points are fitted exactly. Any outlying data should be smoothed before entering it into PIPESIM.

Exercise 1

Calibrating PVT Data

To calibrate PVT data: 1. From Setup > Black Oil, select the Viscosity Data tab. 2. Enter the following calibration data: 3. Under Dead Oil Viscosity, select User’s 2 Data points as the correlation. 4. Enter the following measurements: Dead Oil Viscosity Measurements Property

Viscosity

Temperature (degF)

Value

200

1.5 cp

60

10 cp

5. For Live Oil Viscosity, ensure that the Chew and Connally correlation is selected. 6. For the Emulsion Viscosity Method, select the Brinkman 1952 correlation. 7. For the Undersaturated Oil Viscosity, select the BergmanSutton correlation.

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8. Select the Advanced Calibration Data tab and click SinglePoint Calibration. 9. Enter the measured data to calibrate the PVT model. PVT Calibration Data Range

Property

Value

Pressure (psia)

Temp (degF)

P > Pb

OFVF

1.18

3,000

200

P = Pb

Sat. Gas

500 scf/stb

2,100

200

P -/+ 15% to match the actual measured data, you should review the data again. Large adjustments in friction and holdup factors could also be due to poor fluid characterizations.

Exercise 1

Flow Correlation Matching

An FGS is available for this well. In this exercise, you use the measured data to select the most appropriate vertical flow correlation. To perform a flow correlation match: 1. Select Data > Load/Add Measured Data. 2. Click New. 3. Enter the test data, as shown.

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4. Click Save Changes. 5. Go to Operations > Data Matching and enter the range of calibration factors, as shown in the figure. NOTE: You can uncheck the calibration factor for horizontal flow as there is no horizontal flow in this model.

6. Click the Flow Correlation tab and select some of the vertical multiphase flow correlations, as shown below.

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7. Go to the Run tab and specify the given Outlet Pressure (Wellhead) and Liquid Rate. 8. Select the Inlet Pressure as the calculated variable and click Run model.

9. View the results in Data Matching window to determine which flow correlation agrees most closely with the measured data. 10. Select the best correlation and click Save Selected Results to update the model with this correlation and the matched values for the friction factor, holdup factor, and U-Value multipliers. NOTE: Weighting factors are used to set the relative importance of the pressure and temperature error terms if both pressure and temperature data have been specified.

Results Best Vertical Correlation Flowing BHP Head Factor Multiplier Friction Factor Multiplier U Factor Multiplier

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Exercise 2

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Matching Inflow Performance

It is known from a pressure gradient survey that this particular well can flow 6,500 bbl/d of liquid against 300 psia of wellhead pressure. Using the correct flow correlation from the previous exercise, run the Pressure/Temperature profile to determine how much this well can produce for the same boundary conditions. If the calculated flow rate is different from measured flow rate (6,500 bbl/d), it is time to determine the Productivity Index (PI) that matches the test data. In this exercise, you also determine the absolute open flow potential (AOFP) of the well with the new PI, given a reservoir pressure known to be 3,600 psia. TIP: The Productivity Index (PI) is expected to be in the range from 5 to10 stb/d/psi. To perform the IPR matching: 1. Select Operations > Pressure/Temperature Profile. 2. Enter the Outlet Pressure and the Liquid Rate. 3. Select the User variable as the calculated variable and click Define. 4. Select Object VertWell_1 and the Variable Productivity Index. 5. Enter the expected range of PI and click OK.

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6. Run the model and review the PsPlot for calculated Liquid PI. WARNING: Update the PI for the completion with the matched value.

Results Matched PI

STB/d/psi

Questions These questions are for discussion and review. •

What is the minimum data requirement for black oil fluid model in PIPESIM?

•

How can you use lab PVT data to improve black oil correlations?

•

Which data should you use in black oil calibration, - flash or differential?

•

What components of the pressure drop are reported by PIPESIM?

•

What is the recommended way of selecting a multiphase correlation in PIPESIM?

•

What is the role of the pressure loss in the completion during flow correlation matching?

Lesson 4

Well Performance Analysis

After you define the well and fluids descriptions and match them to generate an accurate model for the well, several simulation operations can be performed to evaluate a variety of operating scenarios.

Conducting a Water Cut Sensitivity Analysis After an initial design has been made, it is important to evaluate how the system will respond to changing operating conditions. Increase in water production in the late life of oil and gas fields is inevitable, whether because of water injection or water coning.

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Using the wellhead pressure and reservoir pressure from the previous exercise, determine the highest possible water cut this well will produce. NOTE: Change the completion PI in the well model from the previous exercise. There are two methods available to solve this problem - Method A: System analysis and Method B: NODAL analysis.

Method A – System Analysis To run a System analysis: 1. Select Operations > System Analysis and enter the Outlet Pressure. 2. Calculate the liquid rate. 3. For the X-axis variable, select Fluid Data. 4. Enter the water cut values of 30 to 70% in increments of 5%. 5. Leave Sensitivity Variable 1 empty. 6. Run the model to generate a plot of calculated liquid rate vs. water cut. 7. Interpolate to identify the limiting water cut at which the production rate continues to be calculated. NOTE: You may need to rerun the model using finer sensitivity values for the water cut.

Method B – NODAL Analysis To run a NODAL analysis: 1. Go to Operations > NODAL analysis. 2. Enter the Outlet Pressure. 3. Leave Inflow Sensitivity empty. 4. Enter the water cut values of 30 to 70% in increments of 5%. 5.

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

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

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7. Identify the lowest water cut for which there is no solution point. NOTE: You may need to rerun the model using finer sensitivity values for the water cut.

Results Critical Water Cut

Exercise 1

Evaluating Gas Lift Performance

The basic principle behind gas lift injection in oil wells is to lower the density of the produced fluid in the tubing. This results in a reduction of the elevational component of the pressure gradient above the point of injection and a lower bottomhole pressure. Lowering the bottomhole pressure increases reservoir drawdown and, thus, production rate. In this exercise, you examine how this well responds to gas lift by introducing a Gas Lift Injection point at 8,000 feet MD in the tubing equipment. You have two tasks to accomplish: •

Determine how the well responds to gas lift when the water cut is 10% and 60%.

•

Determine the liquid production rates as a function of the gas lift rate and water cut. Refer to Table 2 for specific values. Table 2: Gas Lift Data Wellhead Pressure (psia)

300

Injection Gas SG

0.6

Injection Gas Surface Temp (degF)

100

To evaluate gas lift performance: 1. Double-click on Tubing and select the Downhole Equipment tab. 2. Under Equipment, select Gas Lift Injection and specify a depth of 8000 ft. MD. 3. Click Properties.

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4. Enter a default gas lift rate of 1 mmscf/d. 5. Go to Operations > Artificial Lift Performance and enter the Outlet Pressure. 6. For Sensitivity Data, enter water cut values of 10% and 60%. 7. For the Gas Lift Injection rate: a. Select Range. b. Enter a start value of 1.0. c. Enter an end value of 10.0. d. Enter increments of 0.5. 8. Run the model to generate a plot of calculated liquid rate vs. gas lift rate for different water cuts. 9. Inspect the plot and summary output to determine answers.

Results Gas Lift Rate (mmscf/d)

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

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

1 2 4 6 10

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Exercise 2

Working with Multiple Completions

Log analysis shows that a shallow gas zone exists at a TVD of 7,500 feet (Figure 27). As an alternative to gas lift injection, you can investigate the benefits of perforating this zone and self lifting the well.

Figure 27

Shallow zone at 7,500 feet

Defining a Second Completion To define a second completion: 1. Insert a second vertical completion below the NODAL analysis point. 2. Connect to the original completion using a separate tubing model, as shown below.

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3. Modify the upper tubing string to extend only to the top of the upper perforations. a. Modify the Deviation survey such that it will extend to only 7,200 feet TVD.

b. Modify the Geothermal survey such that the ambient temperature at an MD of 7,500 feet is 180 degF. c. In the Tubing Configurations tab, specify a bottom MD of 7,500 feet and a tubing ID of 3.958 inches. d. In the Downhole Equipment tab, remove the gas lift injection. e. Click OK to close the menu.

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4. Double-click on the lower tubing string to define its properties, a. In the Deviation Survey tab, define the lower tubing string profile, as shown.

b. In the Geothermal Survey tab, specify temperatures of 180 degF at 7,500 feet and 200 degF at 9,000 feet. c. Specify the U value as 5 Btu/hr/ft2/F. d. In the Tubing Configuration tab, specify a tubing ID of 3.958 inches to a depth of 8,600 feet MD and 6.184 inches to a depth of 9,000 feet. e. Click OK to close the menu.

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5. With no test data at hand, model the reservoir performance of the upper zone using the pseudo-steady state Darcy equation. Specify the upper completion using the following data: Reservoir Properties - Upper Gas Zone Model

Pseudo-steady state

Basis of IPR Calculation

Gas

Use Pseudo-pressures?

yes

Reservoir pressure

3,000 psia

Reservoir Temperature

180 degF

Thickness

5 feet

Permeability

20 md

Mechanical Skin

0

Rate Dependant Skin

0

6. Select the Fluid model tab within the completion dialog and enter the following: a. Use a locally-defined fluid model with an OGR of 0 STB/ mmscfd and a WGR of 0 (all gas). b. Specify a gas gravity of 0.67. c. Leave all other properties and correlations at their default settings. NOTE: The fluid data used for a well/source is defined by a default, local data set or an override value [for water cut and/or GOR/GLR/OGR/LGR]. If there are multiple fluids present in the system with different intrinsic properties, define the main fluid as the default and all others as local fluids. 7. To analyze the effect of perforating the upper zone (compared with gas lift injection), run a Pressure/Temperature Profile for the 60% water cut case. a. From Setup > Black Oil, set the water cut to 60%. NOTE: This water cut affects only the lower zone because the lower zone uses the default fluid model, while the upper zone is defined with a local fluid model.

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b. Select Operations > Pressure/Temperature Profile. c. Specify the Outlet Pressure as 300 psia. d. Specify the Mass Rate as the Calculated Variable. e. Run the model. f. Inspect the output file to determine the results.

Results Wellhead Pressure

300 psia

Liquid Rate (stb/d) Gas Rate (upper zone) (mmscfd)

Question Comparing the results of gas lift injection versus perforating the upper zone, roughly how much gas lift injection would result in the same liquid rate achievable through perforating the upper zone? Equivalent gas lift injection rate: ______________

Lesson 5

Flow Control Valve

A downhole flow control valve (FCV) allows you to model socalled 'intelligent' or 'smart' wells. The methodology implemented provides a simple way of modeling single branch (non-multilateral) intelligent wells in which FCVs are located close to the reservoir. An FCV can restrict the completion flow rate through the system; however, they are available only for vertical completions. The purpose of an FCV is to provide a restriction to fluid flow, thereby reducing the productivity (or injectivity) of a given completion. They are useful in a model containing multiple completions. An FCV is very similar to a choke. Like a choke, it can be modeled as a fixed-size orifice, in which form it presents a restriction to flow resulting in a pressure drop that increases as flow rate increases. Unlike a choke however, a maximum flow rate can also be specified. This is applied to the completion and, if necessary, the choke bean diameter is reduced to honor the limit.

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The choke diameter and flow rate limit can be applied separately or together. If they are both supplied, they are treated as maximum limits. As shown in Figure 28, the Flow Control Valve dialog uses radio buttons to present a choice between a Generic Valve and a Specific Valve.

Figure 28

Flow Control Valve properties

A generic valve is specified with its Equivalent Choke Area, Gas and Liquid Flow Coefficients, and choice of Gas Choke Equation method. The choke area can be omitted if a Maximum Rate Through Valve is specified. If it is present, the FCV is modeled with that choke area but, if the resulting flow rate exceeds the limit, the area is reduced to honor the limit.

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You must choose a specific valve from the list of available valves provided in the PIPESIM database. Many of the specific valves are multi-position devices, as they allow you to select the effective choke area from a range of pre-installed fixed chokes. If a flow rate limit is supplied, the simulation selects the choke position required to honor the limit. Because the choke area cannot be calculated to match the limit exactly, this usually results in the flow rate being lower than the limit. The valve position can be specified or omitted. If specified, the FCV is modeled with the corresponding choke area, but if the resulting flow rate exceeds the limit, a lower position number is used. Valve positions are numbered in order of increasing choke size, starting with position zero. This position usually specifies a diameter of zero to allow the valve to be shut. An FCV can have as many as 30 positions.

Exercise 1

Modeling a Flow Control Valve

A formation integrity test indicates you should not flow more than 2 mmscfd of gas from the upper formation. To make sure, install the FCV in the upper completion. To model a flow control valve: 1. Double-click on the upper completion and check Flow Control Valve. 2. In the FCV Properties window, set the Maximum Rate through Valve to 2 mmscfd. 3. Leave Equivalent Choke Area empty. 4. Select Operations > Pressure Temperature Profile. 5. Ensure that the Liquid Rate is the calculated variable and the outlet pressure is set to 300 psia. 6. Run the model and view the output file for Bean Size. Required Bean Size: _______________

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7. (Optional) Select any Specific Valve to sensitize on FCV and generate a plot liquid flow rate vs. FCV position. TIP: Select SLB : TRFC-HN-AIS value and use System Analysis and mass flow rate.

Review Questions •

What is the effect on tubing performance curve of increasing the water cut?

•

What is the difference between a standard choke and an FCV?

•

What is the difference between a generic valve and a specific valve?

Summary In this module, you learned about:

98

•

performing a NODAL analysis

•

estimating bottomhole flowing conditions

•

calibrating PVT data

•

performing flow correlation matching

•

performing IPR matching

•

conducting a Water Cut Sensitivity analysis

•

evaluating gas lift performance

•

installing a flow control valve.

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NOTES

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Gas Well Performance

Module 4 Gas Well Performance A gas well has been drilled for which Drill Stem Test (DST) and compositional fluid data are available. In this module, you will model the performance of this well.

Learning Objectives After completing this module, you will know how to: •

model compositional fluid

•

calibrate the Inflow model

•

perform a NODAL analysis at bottomhole

•

perform a System analysis

•

select the optimum tubing size

•

model flowline and choke performance

•

calculate pressure drop due to increased condensate production.

Lesson 1

Compositional Fluid Modeling

PIPESIM offers fully compositional fluid modeling as an alternative to theBlack Oil model. Compositional fluid modeling is generally regarded as more accurate, especially for wet gas, condensate and volatile oil systems. However, detailed compositional data is less frequently available to the production engineer. PIPESIM currently has access to two compositional PVT Frameworks that provide several PVT flash packages. Original PIPESIM PVT Framework: •

SIS Flash, developed by Schlumberger. This is the same Equation of State package used by other GeoQuest products, such as ECLIPSE Compositional, PVTi, VFPi, and others.

•

Multiflash, a third-party compositional package (InfoChem).

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New PVT Toolbox Framework (available in PIPESIM 2010.1): •

Eclipse 300 Flash, a new interface to ECLIPSE two-phase flash, allowing additional Equation of States.

•

DBR Flash, two-phase flash developed by the Schlumberger DBR Technology Center. It has a more extensive component library than ECLIPSE Flash.

•

NIST Refprop Flash, two-phase flash using HelmHoltz Equation of State.

Equations of State (EoS) Equations of State describe the pressure, volume and temperature (PVT) behavior of pure components and mixtures. Most thermodynamic and transport properties are derived from the Equation of State. They are a function of pressure and temperature. One of the simplest Equations of State for this purpose is the ideal gas law, PV=nRT, which is roughly accurate for gases at low pressures and high temperatures. NOTE: The Black Oil model uses this equation along with a compressibility factor (z) to account for non-ideal behavior. However, this equation becomes increasingly inaccurate at higher pressures and temperatures, and it fails to predict condensation from a gas to a liquid. As a result, much more accurate Equations of State have been developed for gases and liquids. The Equations of State available in PIPESIM include: SIS Flash

2-Parameter Peng-Robinson 3-Parameter Peng-Robinson 2-Parameter Peng-Robinson (advanced) 3-Parameter Peng-Robinson (advanced).

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Multiflash

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Standard Peng-Robinson Advanced Peng-Robinson Standard Soave-Redlich-Kwong (SRK) Advanced Soave-Redlich-Kwong (SRK) Benedict-Webb-Rubin-Starling (BWRS) Association (CPA).

DBR Flash

Peng-Robinson (with/without Volume Shift) Soave-Redlich-Kwong (with/without Volume Shift Correction).

ECLIPSE 300 Flash

Peng-Robinson (with/without Volume Shift + Accentric Factor Correction) Soave-Redlich-Kwong (with/without Volume Shift Correction).

NIST Refprop Flash

HelmHoltz Equation of State

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

Pederson (default)

•

Lohrenz-Bray-Clark (LBC)

•

Aasberg-Petersen

Comparative testing has shown the Pedersen method to be the most widely applicable and accurate for oil and gas viscosity predictions. Multiflash uses the Pedersen method as the default viscosity model, though an option is available to choose the LBC model for backward compatibility. The choice you make of the Equation of State has a large effect on the viscosities predicted by these methods. The LBC method is more sensitive to the Equation of State effects than the Pedersen method.

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Figure 29

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Selecting the default Viscosity option

Binary Interaction Parameter (BIP) Set Binary interaction parameters (BIPs) are adjustable factors used to alter the predictions from a model until the predictions match experimental data as closely as possible. BIPs are usually generated by fitting experimental VLE or LLE data to the model in question. BIPs apply between pairs of components, although the fitting procedure can be based on both binary and multi-component phase equilibrium information.

Figure 30

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Selecting a BIP in the Compositional Properties window

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Gas Well Performance

Emulsion Viscosities An emulsion is a mixture of two immiscible liquid phases. One phase (the dispersed phase) is carried as droplets in the other (the continuous phase). In oil/water systems at low water cuts, oil is usually the continuous phase. As water cut is increased, there comes a point at which phase inversion occurs, and water becomes the continuous phase. This is the Critical water cut of Phase Inversion, otherwise called the cutoff, which occurs typically between 55% and 70% water cut. The viscosity of the mixture is usually highest at, and just below, the cutoff. Emulsion viscosities can be many times higher than the viscosity of either phase alone. Three mixing rules have been implemented that are identical to the options currently available in the Black Oil section. You can choose any of these options (Figure 31): •

Set to oil viscosity

•

Volume ratio of oil and water viscosities

•

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

Figure 31

Mixing options

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Flashing Options Flash calculations are an integral part of all reservoir and process engineering calculations. They are required whenever you wish to know the amounts (in moles) of hydrocarbon liquid and gas coexisting in a reservoir or a vessel at a given pressure and temperature. These calculations are also performed to determine the composition of the existing hydrocarbon phases. Given the overall composition of a hydrocarbon system at a specified pressure and temperature, flash calculations can determine four factors: •

Moles of the gas phase

•

Moles of the liquid phase

•

Composition of the liquid phase

•

Composition of the gas phase

The compositional module uses inline flashing (PVT tables built in memory) as the default mode of compositional simulation. For inline flashing, PIPESIM has three options (Figure 32): Interpolation, Interpolation when close to phase boundary, and Rigorous.

Figure 32

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Interpolation

Gas Well Performance

To maximize the speed of the simulation, not all requested P/T points are flashed. A pressure/temperature grid is defined and only these points are created. For points not lying exactly on a grid point, four-point interpolation is used. The default grid points can be changed via the compositional option. This is the fastest, but least accurate, method.

Interpolation when close to a phase boundary

In a case where one or more of the four points used for the interpolation is in a different phase, a full flash is performed and the data point added to the table. This improves accuracy, but sacrifices speed.

Rigorous

Exercise 1

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

Creating a Compositional Fluid Model for a Gas Well

To create a compositional fluid model: 1. Start with a new PIPESIM case – Well Performance Analysis. 2. Open the Compositional Fluid Template menu by selecting Setup > Compositional Template. 3. Choose PVT Framework as PIPESIM and select Multiflash as PVT Package. NOTE: Schlumberger employees select PVT Toolbox Framework, E300 Flash Package. Your results will be slightly different. 4. Click the Component Selection tab.

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5. Add following library components by selecting the desired components from the list and click Add >>. •

Methane

•

Butane

•

Ethane

•

Isopentane

•

Propane

•

Pentane

•

Isobutane

•

Hexane

6. Add the C7+ pseudo-component: a. Select the Petroleum Fractions tab. b. Enter thStep 4e pseudo-component name and data. c. Highlight the row number for the pseudo-component and click Add to Composition. Pseudo-Component Stock Tank Properties C7+ BP

214 degF

C7+ MW

115

C7+ SG

0.683

7. Leave Property Models as default. 8. Open the Compositional (Local Default) menu by selecting Setup > Compositional (local default). 9. Under the Component Selection tab, you will notice all the components predefined in Step 4. Add the mole fraction to these components. Composition (%)

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Methane

78

Ethane

8

Propane

3.5

Isobutane

1.2

Butane

1.5

Isopentane

0.8

Pentane

0.5

Hexane

0.5

C7+

6.0

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10. To determine the water content at saturation at reservoir conditions: a. Go back to the Compositional Template UI and add Water as additional component. b. Now come back to Compositional (Local default) UI and add an arbitrary amount of water, such as 20 moles, to the composition. c. Select the Flash/Separation tab. d. Click the PT button and enter the reservoir pressure and temperature, 4,600 psia and 280 degF, respectively. e. Perform a flash and read the water content for the vapor fraction from the screen. NOTE: The hydrocarbon vapor components will be normalized to include the mole fraction of water. f. Copy and paste (Ctrl + C and Ctrl + V) the water and the normalized hydrocarbon composition back into the compositional editor main screen. NOTE: Water can be carried along with the gas in the vapor phase or entrained in the gas in droplet form. There exists at any temperature and pressure a maximum amount of water vapor that a gas is able to hold. A gas is completely saturated when it contains the maximum amount of water vapor for the given pressure and temperature conditions. Keeping the volume and pressure constant on water vapor-saturated gas, water will condense out at lower temperatures because the capacity of the gas to hold water is less. The same is true if the volume and temperature are kept constant, but the pressure is allowed to increase.

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11. Click Phase Envelope to generate a phase envelope using the water-saturated composition. 12. From the main Component Selection tab, click Export, name the composition sat_gas and click Save. 13. Select Setup > Flow Correlations and choose Gray Modified for the vertical flow correlation. 14. Select File > Save As and save the model as GasWell.bps.

Questions These questions are for discussion and review.

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•

What are the key differences between the various flash packages?

•

What is the tradeoff between the rigorous flash option and the interpolation flash option?

•

What is the likelihood of forming an emulsion when water and gaseous hydrocarbons are the two phases present?

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Lesson 2

Gas Well Deliverability

Based on the analysis for flow data obtained from a large number of gas wells, Rawlins and Schellhardt (1936) presented a relationship between the gas flow rate and pressure drawdown that can be expressed as: Qsc = C(pR2 – pWF2)n Where: Qsc

= gas rate (mmscf/d)

pR

= average reservoir pressure (psia)

pWF

= flowing bottomhole pressure

C

= flow coefficient (mmscf/day/psi2)

n

= non-Darcy exponent

The exponent n is intended to account for the additional pressure drop caused by the high-velocity gas flow, such as turbulence. Depending on the flowing conditions, the exponent n can vary from 1.0 for completely laminar flow to 0.5 for fully turbulent flow. The performance coefficient C in above equation is included to account for: •

Reservoir rock properties

•

Fluid properties

•

Reservoir flow geometry.

This equation is commonly called the deliverability or backpressure equation. If you can determine the coefficients of the equation - n and C - you can calculate the gas flow rate Qsc at any bottomhole flow pressure pWF and construct the IPR curve. Deliverability testing has been used for more than sixty years by the petroleum industry to characterize and determine the flow potential of gas wells. There are essentially three types of deliverability tests: •

Conventional deliverability (back-pressure) test

•

Isochronal test

•

Modified isochronal test.

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Essentially, these tests consist of flowing wells at multiple rates and measuring the bottomhole flowing pressure as a function of time. When the recorded data are properly analyzed, it is possible to determine the flow potential and establish the inflow performance relationships of the gas well.

Exercise 1

Calculating Gas Well Deliverability

In this exercise, you construct the simple physical well model shown below and perform a simulation to calculate deliverability. 1. Using the Single Branch toolbar, insert a vertical completion, tubing, and NODAL analysis point, as shown in the figure.

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2. Edit the reservoir and tubing data according to the data in the table. Reservoir Data Static Pres

4,600 psia

Reservoir Temp.

280 degF

Gas PI

1 x 10-6 mmscf/d/psi2 Tubing Data

Mid perf TVD

11,000 feet

Mid perf MD

11,000 feet

Ambient temp

30 degF

EOT MD

10,950 feet

Tubing ID

3.476 inches

Casing ID

8.681 inches

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

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3. Select Operations > Pressure/Temperature Profile Operation. a. Select the Gas Rate as the calculated variable. b. Specify an Outlet Pressure of 800 psia and click Run. 4. The flow rate displays below the plot. You can read the bottomhole flowing pressure on the plot. 5. On the Plot menu, select Series. 6. Change the Y-axis to Temperature. You can read the bottomhole and wellhead temperatures on the plot.

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Results Pres = 4,600 psia, Tres = 280 degF % H2O @ saturation Po = 800 psia QG Pwf BHT WHT

Exercise 2

Calibrating the Inflow Model Using Multipoint Test Data

In this exercise, you use the back-pressure equation for inflow performance relationship for a gas well producing at a pseudosteady state. Using a multipoint well test, the C and n parameters are calculated. 1. Double-click Completion. 2. Choose the Back Pressure Equation from the drop-down list. 3. Click Calculate/Graph and enter the test data listed in the table. Multipoint Test Data QGas (mmscf/d)

Pwf (psia)

9.7

3,000

11.9

2,500

14.3

1,800

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4. Click Plot IPR.

TIP: To position data points, right-click and drag on a plot. To zoom in, click and drag a window across the data points towards the lower right. To zoom out, click and drag a window towards the upper-left. 5. Rerun the Pressure/Temperature Profile operation to determine the following: • Gas flow rate • Bottomhole flowing pressure • Bottomhole flowing temperature • Wellhead temperature 6. Inspect the profile plot and summary file to determine the results.

Results Back Pressure Equation Parameter C Parameter n Po = 800 psia QG Pwf Tbh (degF) Twh (degF)

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Questions These questions are for discussion and review. •

What IPR methods are available in PIPESIM for gas wells?

•

What are the three types of gas well deliverability tests?

•

Does the C factor in the back pressure equation change over time?

Lesson 3

Erosion Prediction

Erosion has been long recognized as a potential source of problems in oil and gas production systems. Erosion can occur in solids-free fluids but, usually, it is caused by entrained solids (sand). Two erosion models are available: API 14 E and Salama.

Figure 33

Selecting erosion options

API 14 E The API 14 E model comes from the American Petroleum Institute, Recommended Practice, number 14 E. This is a solidsfree model which calculates an erosion velocity but not a rate). The erosion velocity Ve is calculated with the formula:

where m is the fluid mean density and C is an empirical constant.

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C has dimensions of (mass/(length*time2)) 0.5. Its default value in engineering units is 100, which corresponds to 122 in SI units. The current practice for eliminating erosional problems in piping systems is to limit the flow velocity to that calculated by this correlation.

Salama The Salama model was published in Journal of Energy Resources Technology, Vol 122, June 2000, "An Alternative to API 14 E Erosional Velocity Limits for Sand Laden Fluids," by Mamdouh M. Salama. This model calculates erosion rate and erosional velocity. The parameters required for the model are Acceptable Erosion rate, Sand production ratio, Sand Grain Size, Geometry Constant and Efficiency. The equations in Salama's paper use a sand rate in Kg/day. This is obtained from the supplied volume ratio using Salama's 'typical value' for sand density - 2,50 kg/m 3.

Exercise 1

Selecting a Tubing Size

In this exercise, you perform a NODAL analysis to select an optimum tubing size. The available tubing sizes have IDs of 2.992 inches, 3.958 inches, 4.892 inches, and 6.184 inches. Your final decision will be based on these criteria: •

Flow rate (High)

•

Erosional velocity ratio ( NODAL analysis. a. Enter 800 psia as the Outlet Pressure. b. Enter the tubing IDs as the Outflow Sensitivity.

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c. Run the model and observe the outflow curves.

3. Another way to analyze the effect of the tubing ID, is to perform a Pressure/Temperature profile. Select Operations > Pressure/Temperature Profile. a. Enter the tubing size as the sensitivity. b. Specify the flow rate as the calculated variable and run the model. c. From the profile plot, change the X-axis to Erosional Velocity Ratio (EVR = actual velocity / API 14e limit) by selecting the Series option from the toolbar. This lets you determine the maximum erosional velocity ratio. Based on the results of the NODAL analysis and EVR calculations, which tubing size would you select? 4. Record the results for the selected tubing size. Specify this tubing size in the tubing object in subsequent exercises and procedures.

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Results Po = 800 psia QG Pwf BHT WHT Well-head, Selected Tubing Max. Erosional velocity ratio

Questions These questions are for discussion and review.

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•

What are the criteria for optimum tubing selection?

•

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

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Lesson 4

Choke Modeling

Wellhead chokes are used to limit production rates to meet surface constraints, protect surface equipment from slugging, avoid sand problems due to high drawdown, and control flow rate to avoid water or gas coning. Placing a choke at the wellhead increases the wellhead pressure and, thus, the flowing bottomhole pressure which reduces production rate. Pressure drop across wellhead chokes is usually very significant, and various choke flow models are available for critical (sonic) and sub-critical flow (Figure 34).

Figure 34

Gas fraction in the fluid and flow regimes

Sound waves and pressure waves are both mechanical waves. When the fluid flow velocity in a choke reaches the traveling velocity of sound in the fluid under the in situ condition, the flow is called sonic flow.

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Under sonic flow conditions, the pressure wave downstream of the choke cannot go upstream through the choke because the medium (fluid) is traveling in the opposite direction at the same velocity. As a result, a pressure discontinuity exists at the choke, which means that the downstream pressure does not affect the upstream pressure. Because of the pressure discontinuity at the choke, any change in the downstream pressure cannot be detected from the upstream pressure gauge. Any change in the upstream pressure cannot be detected from the downstream pressure gauge either. This sonic flow provides a unique choke feature that stabilizes the well production rate and separation operation conditions. Whether a sonic flow exists at a choke depends on a downstreamto-upstream pressure ratio. If this pressure ratio is less than a critical pressure ratio, sonic (critical) flow exists. If this pressure ratio is greater than, or equal to, the critical pressure ratio, sub-sonic (sub-critical) flow exists. The critical pressure ratio is about 0.55 for natural gas, and a similar constant is used for oil flow. In some wells, chokes are installed in the lower section of tubing strings. This choke arrangement reduces wellhead pressure and enhances oil production rate as a result of gas expansion in the tubing string. For gas wells, a downhole choke can reduce the risk of gas hydrates. A major disadvantage of using downhole chokes is that replacing a choke is costly.

Exercise 1

Modeling a Flowline and Choke

In this exercise, you add a horizontal flow line and a choke to the model. You use the gas rate calculated in the previous exercise to determine the choke bean size that results in a manifold (end of flowline) pressure of 710 psia. To model a flowline and choke: 1. Ensure the tubing ID is set to 3.958 inches. 2. Insert a choke at the wellhead and reconnect the tubing to the choke.

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3. Select the mechanistic model for both critical and sub-critical flow. TIP: You can enter any choke size you wish, but it will be overridden by the sensitivity variable.

4. Insert a flowline downstream of the choke and connect it to a node representing the manifold. 5. Specify the flowline using the data in the table. Flow-line length

300 feet

Flow-line ID

6 inches

Pipe Roughness

0.001 inches

Wall thickness

0.5 inches

Ambient Temp

60 degF

6. Select Operations > Pressure Temperature Profile. 7. Select User Variable as calculated and input a choke size. A good estimate is a size between 1 inch and 3 inches. 8. Set the Outlet Pressure to 710 psia. 9. Specify the gas flow rate calculated in the previous exercise. 10. Run the model and see the PsPlot for the choke size. 11. Enter the resulting choke size into the choke model. 12. Rerun the Pressure/Temperature profile with outlet pressure as the calculated variable to verify that the calculated wellhead pressure is 800 psia.

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

Results Po = 710 psia Choke size Pressure losses across system P Reservoir P Tubing P Choke P Flow-line

Exercise 2

Predicting Future Production Rates

In this exercise, you use System analysis to calculate the gas rate as a function of reservoir pressure. To predict future production rates: 1. Right-click and choose Active to deactivate the choke and flowline. These objects should be highlighted in red to indicate they are inactive. 2. Select Operations > System Analysis. 3. Choose Gas Rate as the calculated variable.

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4. Set the wellhead pressure to 800 psia. 5. Use Reservoir (Static) Pressure as the X-axis variable and set these values: • 4,600 psia • 4,300 psia • 3,800 psia • 3,400 psia. 6. Run the model and view the resultant plot.

Results Reservoir Pressure (psia)

Gas Rate (mmscfd)

4600 4200 3800 3400

Questions These questions are for discussion and review. •

What is the difference between critical and sub-critical flow?

•

What effect does changing the manifold pressure have if the choke is in critical flow?

•

What are the advantages and disadvantages of using downhole chokes instead of wellhead chokes?

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Lesson 5

Liquid Loading

Gas wells usually produce natural gas-carrying liquid water and/or condensate in the form of mist. As the gas flow velocity in the well drops because of reservoir pressure depletion, the carrying capacity of the gas decreases. When the gas velocity drops to a critical level, liquids begin to accumulate in the well (liquid loading). This increases the bottomhole pressure, which reduces the gas production rate. A low gas production rate will cause gas velocity to drop further and, eventually, the well will cease producing.

Turner Droplet Model In predominantly gas wells operating in the annular-mist flow regime, liquids flow as individual particles (droplets) in the gas core and as a liquid film along the tubing wall. By analyzing a large database of producing gas wells, Turner found that a force balance performed on a droplet could predict whether the liquids would flow upwards (drag forces) or downwards (gravitational forces). If the gas velocity is above a critical velocity, the drag force lifts the droplet, otherwise the droplet falls and liquid loading occurs (Figure 35).

Figure 35

Turner Droplet model

When the drag is equal to weight, the gas velocity is at critical. Theoretically, at the critical velocity, the droplet would be suspended in the gas stream, moving neither upward nor downward. Below the critical velocity, the droplet falls and liquids accumulate in the wellbore.

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In practice, the critical gas velocity is generally defined as the minimum gas velocity in the tubing string required to move droplets upward. The general form of Turner's equation is given by:

Where: ρg = gas phase density (lbm/ft3) ρl

= liquid phase density (lbm/3)

σ

= interfacial tension (dynes/cm)

vt

= terminal velocity of liquid droplet (ft/sec)

Liquid loading calculations are performed in every operation and are available for review in output files and plot reports. Review the output file to determine if the well is under liquid loading. A value of Liquid Loading Velocity Ratio in excess of 1 indicates loading. The NODAL analysis plot will report the Liquid Loading Gas Rate when the X-axis is configured to display gas rate. For every point on the outflow curve, the value of Liquid Loading Velocity Ratio is calculated and the critical gas rate is calculated at a point where liquid loading velocity ratio is equal to 1. NOTE: The reported value comes from interpolation of the outflow curve between two points, one with a velocity ratio below 1 and another with a velocity ratio above 1. Therefore, the accuracy of the results depends on the number of points on the outflow curve.

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Exercise 1

Determining a Critical Gas Rate to Prevent Well Loading

To determine the Critical Gas rate: 1. Select Operations > NODAL analysis. 2. Select Limits and change these settings: • Number of points on each inflow curve = 100 • Number of points on each outflow curve = 200 • Inflow curves to extend to the AOFP • Outflow curves limited to the pressure range of the inflow curves. 3. Set the outlet pressure to 800 psia and run the model. 4. Plot the Pressure at NA point vs. Stock Tank Gas Rate. Note the stock tank gas rate on the Data tab. The reported critical gas rate is _________ mmscfd NOTE: The reported critical gas rate refers to the outflow curve, which you can validate by performing a Pressure/Temperature Profile operation at the same conditions (flow rate and outlet pressure). 5. Perform a Pressure/Temperature Profile operation to calculate inlet pressure at the given critical gas rate corresponding to outflow outlet pressure of 800 psia. 6. View the output file to see if the Maximum Liquid Loading Velocity Ratio is close to 1, which is consistent with the results of the NODAL analysis.

Review Question What actions can be taken to prevent liquid loading?

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Summary In this module, you learned about: •

building a simple well model

•

calibrating the inflow model

•

performing a NODAL analysis at bottomhole

•

performing system analysis

•

selecting optimum tubing size

•

modeling flowline and choke performance

•

calculating the pressure drop due to increased condensate production.

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Horizontal Well Design

Module 5 Horizontal Well Design This module shows you how to use PIPESIM to design a horizontal well and evaluate horizontal well performance.

Learning Objectives After completing this module, you will know how to: •

optimize horizontal well length

•

perform horizontal well IPR / sensitivity

•

model a horizontal well with multiple perforated intervals.

Lesson 1

Inflow Performance Relationships for Horizontal Completions

The main advantage of a horizontal well, as compared to a vertical well, is to enhance reservoir contact and, thereby, enhance well productivity. There are also many circumstances that lead to drilling horizontal wells (Cooper, 1988): Thin reservoirs

The increased area of contact of the horizontal well with the reservoir is reflected by the Productivity Index (PI). Typically, the PI for a horizontal well can be increased by a factor of 4 when compared to a vertical well penetrating the same reservoir.

Heterogeneous reservoirs

When irregular reservoirs exist, the horizontal well can effectively intersect isolated productive zones which might otherwise be missed. A horizontal well can also intersect vertical natural fractures in a reservoir.

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Reduce water/ gas coning

A horizontal well provides minimum pressure drawdown, which delays the onset of water/ gas breakthrough. Even though the production per unit well length is small, the long well length provides high production rates.

Vertical permeability

If the ratio of vertical permeability to horizontal permeability is a high, a horizontal well can produce more economically than a vertical well.

The following IPR methods are available in PIPESIM for designing horizontal wells. Steady State Production

The simplest form of horizontal well productivity calculations are the steady-state analytical solutions, which assume that the pressure at any point in the reservoir does not change with time. According to Joshi (1991), even though very few reservoirs operate under steady-state conditions, steady state solutions are widely used because: •

Analytical derivation is easy.

•

The concepts of expanding drainage boundary over time, effective wellbore radius and shape factors allows the conversion to either transient or pseudosteady state results to be quite straightforward.

•

Steady-state mathematical results can be verified experimentally.

The steady-state distributive productivity index is based upon Joshi's SPE 16868, "Review of Horizontal and Drainhole Technology." The equation is based on the assumption that the horizontal well drains an ellipsoidal volume around the wellbore of length L.

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Horizontal Well Design

It is often desirable to calculate productivity from a reservoir with unique boundary conditions, such as a gas cap or bottom water drive, finite drainage area, well location, and so forth. In these instances, pseudo-steady state equations are employed. Pseudo-steady state or depletion state begins when the pressure disturbance created by the well is felt at the boundary of the well drainage area. The pseudo-steady state productivity index is based on Babu and Odeh's SPE paper 18298. (It is best to read this reference before applying the equation.) The equation is based upon the Pseudo-steady state IPR well model applied to a rectangular drainage area.

Distributed Productivity Index Method

This option uses straight line PI value for liquid or gas. The distributed productivity index relationship is: Q = J(Pws - Pwf)L for liquid reservoirs OR Q = J(Pws2 - Pwf2)L for gas reservoirs, where J = distributed productivity index.

The Optimum Horizontal Completion Analysis module can accurately predict the hydraulic wellbore performance in the completion and is an integral part of the PIPESIM reservoir-tosurface analysis. PIPESIM uses a technique in which the horizontal completion is subdivided into vertical cross-sections, and flow is treated independently from other cross-sections. This multiple source concept leads to a pressure gradient from the blind-end (toe) to the producing-end (heel) which, if neglected, results in overpredicting deliverability. The reduced drawdown at the toe results in the production leveling off as a function of well length, and it can be shown that drilling beyond an optimum length would yield no significant additional production.

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Exercise 1

Constructing the Well Model

To construct the well model: 1. Construct the physical horizontal well model shown in the figure, using the tubing data in the tables that follow.

Wellbore Deviation Survey Data MD (ft)

TVD (ft)

0

0

7,000

7,000

7,700

7,600

8,400

8,000

9,000

8,200

9,500

8,300 Geothermal Survey

MD

134

Ambient Temperature (degF)

U Value (Btu/hr/ft2)

0

50

2

9500

200

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Tubing Configuration Bottom MD (ft)

ID (in)

9500

2.992

Pipe Roughness (in) 0.001

Completion Data Static Pressure

4,600 psia

Temperature

200 degF

Completion Model

Distributed PI

IPR Model Type

Distributed PI

Distributed PI

1.00E-9 mmscf/d/psi2/ft Wellbore Data

Length

10,000 feet

ID

2.992 inches

Tambient (degF)

200 degF

2. Select Setup > Compositional Template and add these Library components: •

Methane

•

Iso-butane

•

Ethane

•

Butane

•

Propane

•

Water

3. Keep all other options as default. 4. Select Setup > Compositional (Local Default). a. Enter the following composition: Component

Mol %

Methane

0.846

Ethane

0.087

Propane

0.038

Isobutane

0.013

Butane

0.016

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

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5. Select Setup > Flow Correlations. 6. Specify Beggs-Brill Revised for both horizontal and vertical flow.

Exercise 2

Evaluating the Optimal Horizontal Well Length

To evaluate the optimal horizontal well length: 1. Select Operations > Optimum Horizontal Well Length. 2. For an outlet pressure of 200 psia, evaluate the optimal length of a horizontal well up to approximately 10,000 feet and the pressure loss from the toe to the heel of the horizontal well. Optimal horizontal well length: ____________________.

Exercise 3

Specifying Multiple Horizontal Perforated Intervals

Additional geological information suggests that the reservoir consists of four sand intervals that are 500, 400, 400, and 500 feet in width, with equally spaced impermeable intervals of 400 feet in width. To specify multiple intervals: 1. Specify separate horizontal completions for each interval with flowline objects to connect the completion intervals, as shown.

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

Results Po = 200 psia QG Bhp

Review Questions •

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

•

What are the basic completion models in PIPESIM for horizontal wells?

•

Explain the shape of the horizontal well length versus production rate curve

Summary In this module, you learned how to: •

construct a horizontal well

•

optimize horizontal well length

•

perform horizontal well IPR / sensitivity

•

model a horizontal well with multiple perforated intervals.

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Subsea Tieback Design

Module 6 Subsea Tieback Design The offshore frontier poses some of the greatest technical challenges facing the oil and gas industry, particularly as we venture into ever deeper waters and more remote locations. Development costs can be substantial and many new production systems must be designed to accommodate subsea multiphase flow across long distances to be economically viable. Managing costs over extended distances introduces a number of complex risks and reliability becomes a key concern due to high intervention costs and potential for downtime. Characterizing and managing these risks requires detailed multidisciplinary engineering analysis and has led to the emergence of a new field called flow assurance. Design of subsea tiebacks requires multiphase flow simulation to assure that fluids will be safely and economically transported from the bottom of the wells all the way to the downstream processing plant. Four flow assurance issues are discussed in this module, including hydrates, heat loss, erosion, and liquid slugging.

Learning Objectives After completing this module, you will know how to: •

develop a compositional model of the hydrocarbon phases

•

size the subsea tieback line and riser

•

determine the pipeline insulation requirements

•

screen the results for severe slugging at the riser base

•

size a slug catcher.

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Lesson 1

Flow Assurance Considerations for Subsea Tieback Design

In this case study, a client plans to produce four condensate wells into a subsea manifold through a subsea tieback and up a riser to a platform. The oil and gas will be separated, with the oil pumped to shore and the gas compressed to shore.

Figure 36

Subsea Tieback

Exercise 1

Developing a Compositional PVT Model

In this exercise, you develop a compositional PVT model based on the data in the tables that follow. Table 3: Pure Hydrocarbon Components Component

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Moles

Component

Moles

Carbon Dioxide

3

Butane

1

Methane

72

Isopentane

1

Ethane

6

Pentane

0.5

Propane

3

Hexane

0.5

Isobutane

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Table 4: Petroleum Fractions Name

Boiling Point (degF)

Molecular Weight

Specific Gravity

Moles

C7+

214

115

0.683

12

Table 5: Aqueous Component Component

Volume ratio (%bbl/ bbl)

Water

10

To develop a Compositional PVT model: 1. Open the Setup > Compositional Template menu. 2. Choose PIPESIM as PVT Framework. 3. Choose Multiflash as PVT Package. 4. To enter the pure components noted in the preceding tables, select the pure hydrocarbon components from the component database. TIP: Make multiple selections by holding down the Ctrl key. 5. After selecting all of the pure hydrocarbon components, click Add >>. 6. Select the Petroleum Fractions tab and characterize the petroleum fraction C7+ by entering these parameters: • petroleum fraction name • BP • MW • SG in Row 1. 7. Highlight the row by clicking Row 1 and click Add to composition >>. 8. Return to the Component Selection tab to see that petroleum fraction displays in the component list table on the right. 9. Click the Property Model tab and check the radio button Use Template Models for all fluids. 10. Select SRK Equation of State and Pedersen viscosity model. Leave all other options as default.

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11. Select Setup > Compositional Local Default and add mole fractions for all library and pseudo components, as per Table 3, Table 4, and Table 5. 12. Generate the hydrocarbon phase envelope by clicking Phase Envelope.

Exercise 2

Constructing the Model

In this exercise, you construct the subsea tieback model. To construct the model: 1. Using the Single Branch toolbar, insert the objects shown

2. Specify each object based on the data provided in the tables that follow. NOTE: To enter the detailed heat transfer data in the flowline and riser, select the Heat Transfer tab and click Calculate U value. Ensure that your Riser Elevation survey matches that shown below. Manifold Data

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Temperature

176 degF

Pressure

1,500 psia

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Subsea Tieback Data Rate of undulations

0'/1000 feet (not hilly)

Horizontal Distance

6 miles

Elevational difference

0 feet (horizontal)

Available IDs

9,10,11 inches

Heat Transfer: Ambient temperature

38 degF

Pipe thermal conductivity

35 Btu/hr/ft/degF

Insulation thermal conductivity

0.15 Btu/hr/ft/degF

Insulation thicknesses available

0.50 in + 0.25 in increments

Ambient fluid

water

Ambient fluid velocity

1.5 ft/sec

Burial depth

Blank (Elevated above ground)

Ground conductivity

1.5 Btu/hr/ft/degF Riser (use detailed profile)

Horizontal Distance

0 feet (vertical pipe)

Elevational difference

1,600 feet

Available IDs

9,10,11 inches Heat Transfer

Ambient temperature @ riser base

38 degF

Ambient temperature @ 1,200 feet

42 degF

Ambient temperature @ 800 feet

48 degF

Ambient temperature @ 400 feet

56 degF

Ambient temperature @ topsides

68 degF

Pipe thermal conductivity

35 Btu/hr/ft/degF

Insulation thermal conductivity

0.15 Btu/hr/ft/degF

Insulation thickness

0.50 in (plus additional 0.25 in increments if required)

Ambient fluid

water

Ambient fluid velocity

1.5 ft/sec

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Sizing the Subsea Tieback

You will now determine the required ID for the subsea tieback, such that the separator pressure for the maximum expected rate is no less than 400 psia. The expected production rate is 14,000 STBD. The system will be designed to accommodate between 8,000 STBD (turndown case) and 16,000 STBD, should the wells produce more than expected. The riser must be the same ID as the tieback, and you must not exceed the erosional velocity.

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To size the subsea tieback: 1. From the Setup > Flow Correlations menu, make the following selections: • Vertical Flow Correlation = Hagedorn Brown (Duns & Ros map) • Horizontal Flow Correlation = Beggs-Brill Revised. 2. Perform a System analysis with the minimum, maximum, and expected flow rates as the X-axis variable and the available IDs for the flowline and riser as Change in Step (with Sensitivity variable 1) sensitivity variables. 3. Determine the minimum flowline ID that satisfies the separator pressure requirement (400 psia) for the maximum flow rate. 4. Change the Y-axis to display Erosional Velocity Ratio Maximum. 5. Verify that the selected flowline ID does not exceed an erosional velocity ratio of 1.0 for the expected flow rate.

Results Property

Value

Pipeline and Riser ID Max. erosional velocity ratio for selected ID Min. Separator pressure for selected ID Max. separator pressure for selected ID

Lesson 2

Hydrates

Gas hydrates are crystalline compounds with a snow-like consistency that occur when small gas molecules come into contact with water at below a certain temperature. Hydrate formation temperature increases with increasing pressure, therefore, hydrates risk increases at higher pressures and lower temperatures. When hydrates form inside the pipeline, the flow can be blocked by hydrate plugs. Hydrate forming molecules most commonly include methane, ethane, propane, carbon dioxide, and hydrogen sulfide.

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Three hydrate crystal structures have been identified: Structures I, II, and H. The properties of Structures I and II hydrates are well defined. Structure H hydrates are relatively new, and their properties are less well defined. Hydrates can very easily form downstream of a choke where fluid temperature can drop into the hydrate formation region due to Joule-Thompson cooling effects. Figure 37 shows a typical gas hydrate curve which is very useful for subsea pipeline design and operations. On the left side of the curve is the hydrate formation region. When pressure and temperature are in this region, water and gas will start to form hydrate. Many factors impact the hydrate curve, including fluid composition, water salinity and presence of hydrate inhibitors. NOTE: Generating Hydrate curves requires the PIPESIM Multiflash Hydrate Package and cannot be used with SIS Flash.

Figure 37

Hydrate curve

Hydrate Mitigation Strategies in PIPESIM Two common strategies available in PIPESIM to mitigate hydrates formation are thermal insulation and chemical inhibitors. Thermal insulation carries a higher upfront capital cost whereas chemical inhibition carries a higher operational cost.

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Thermal insulation Heat transfer between the fluid and surroundings occurs, depending upon the temperature gradient. There are two options for modeling the heat transfer in PIPESIM: Input U value and Calculate U value. Input U value is an overall heat transfer coefficient (U value) based upon the pipe outside diameter is entered. Calculate U value includes the following information, which can be entered to compute the overall Heat Transfer coefficient. •

Pipe coatings • Thickness of the pipe coat. • K (Thermal conductivity) of the material.

•

Pipe conductivity

•

Ambient fluid (Air or Water)

•

Ambient Fluid Velocity

•

Pipe burial Depth

•

Ground conductivity (for flowlines only).

Chemical Inhibitors Thermodynamic inhibitors can be used to shift the hydrate curve towards the left, thereby lowering the hydrate formation temperature. Examples of inhibitors include methanol and ethylene glycol. Kinetic and anti-agglomerate inhibitors comprise a category known as Low Dosage Hydrate Inhibitors (LDHIs). These inhibitors do not lower the hydrate formation temperature; instead, they help prevent the nucleation and agglomeration of hydrates to avoid blockage formation. The effects of these types of inhibitors cannot be modeled with PIPESIM.

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Exercise 1

Selecting Tieback Insulation Thickness

Using the tieback/riser ID selected above, determine the thickness of the insulation required for both the flowline and the riser, such that the temperature of the fluid does not cross the hydrate curve for all possible flow rates. To select tieback insulation thickness: 1. Double-click on the Report tool and ensure that Phase Envelope is checked. 2. Select Operations > Pressure/Temperature profile. 3. Specify Separator (outlet) pressure as the calculated variable and the three design flow rates as the sensitivity variables. 4. Use the Series menu on the resulting plot to change the Xaxis to Temperature and the Y-axis to Pressure to display the phase envelope. 5. Observe the production path on the phase envelope and its proximity to the hydrate curve. 6. If required, perform successive runs while increasing the insulation thickness of both the flowline and riser by 0.25 inch increments until sufficient.

Results Property

Value

Req. Insulation thickness

Exercise 2

Determining the Methanol Requirement

Assume the flowline and riser have been insulated but they are under-insulated with only 0.25 inch of insulation. In this exercise, you determine the required injection volume of methanol to ensure that hydrates do not form.

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To determine the methanol requirement: 1. Insert an injector just downstream of the source, as shown.

2. Specify Methanol as Injector Fluid. 3. Use injection temp. = 68 degF. To do this: a. Select Setup > Compositional Template. b. Add Methanol to the listed of added components. c. Double-click on the Injector and choose Edit Composition. d. Specify a composition of 100% Methanol. e. Specify Injection Temperature and any injection rate. 4. Select Setup > Heat Transfer Options and verify that Enable Hydrate Sub-Cooling Calculation is selected. 5. Select Operations > System Analysis. a. Specify a liquid rate of 8,000 BPD and select calculated variable as the outlet pressure. b. For the X-axis variable, select the Injector as the object and Rate as the Variable. c. Select Range and enter a range of 200 to 600 BPD in increments of 50 BPD. d. Uncheck the active status on all sensitivity variables with defined values. e. Run the model.

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6. On the resulting plot, change the Y-axis to display Maximum Hydrate Subcooling Temperature. 7. From the plot, determine the required Methanol injection rate, such that the flowing temperature is always above the stable hydrate temperature. NOTE: A Positive Hydrate Sub-cooling in the output file indicates the fluid temperature is below the hydrate stability temperature.

Results Property

Value

Req. Methanol Injection Volume (bbl/d)

Questions These questions are for discussion and review. •

What are the advantages and disadvantages of thermal insulation versus chemical inhibition for prevention of hydrates?

•

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

Lesson 3

Severe Riser Slugging

Severe slugging in risers can occur in a multiphase transport system consisting of a long flowline followed by a riser. Severe slugging is a transient phenomenon that can be split into four steps, as shown in Figure 38. Step 1:

Slug formation corresponds to an increase of the pressure in bottom of the riser. The liquid level does not reach the top of the riser. During this period, the liquid is no longer supported by the gas and begins to fall, resulting in blockage to the riser entrance and pipeline pressure buildup, until the liquid level in the riser reaches to the top.

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Step 2:

In slug production, the liquid level reaches the riser outlet, and the liquid slug begins to be produced until gas reaches the riser base.

Step 3:

In bubble penetration, gas is again supplied to the riser, so the hydrostatic pressure decreases. As a result, the gas flow rate increases.

Step 4:

This corresponds to gas blowdown. When the gas produced at the riser bottom reaches the top, the pressure is minimal and the liquid is no longer gas-lifted. The liquid level falls and a new cycle begins.

Figure 38

The four slugging steps

PIPESIM does not rigorously model severe slugging associated with risers, as this is a transient phenomena, but it does report a dimensionless indicator of the likelihood of this occurring (PI-SS number in PIPESIM output file). Severe slugging is most prevalent in cases in which a long flowline precedes a riser, especially for cases in which the flowline inclination angle is negative going into the riser. In cases of severe slugging, the slug catcher must be able to receive a volume of liquid at least equal to the volume of the riser.

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However, severe slugging can be mitigated by topsides choking or riser base gas lift including self-lifting mechanisms.

PI-SS Indicator (Severe-Slugging Group) The PI-SS indicator (severe-slugging group) is the ratio between the pressure build-up rates of gas phase and that of liquid phase in a flowline followed by a vertical riser:

where: Z

= Gas compressibility factor

R

= Gas universal constant

T

= Temperature (K)

M

= Molecular weight of gas

WG

= Gas mass flow rate (kg/s)

WL

= Liquid mass flow rate (kg/s)

g

= Acceleration due to gravity (m/s2)

LF

= Flowline length (m) = Average flowline gas holdup

Severe slugging is expected when the Pots number is equal to, or less than, unity. Pots’ model can be used to determine the onset of severe slugging, but the model cannot predict how long the severe slugs will be and how fast severe slugs will be produced into the separator. The PI-SS indicator is available as part of the PRIMARY output in PIPESIM.

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Exercise 1

Subsea Tieback Design

Screening for Severe Riser Slugging

To screen for severe riser slugging: 1. Deactivate the methanol injector and reset the insulation thickness to that determined to prevent hydrate formation. 2. Under Setup > Define Output, select three cases to print. This reports the full output of each sensitivity value with the Report tool selections appended to the bottom of each sensitivity output. 3. Perform a System analysis with an inlet pressure of 1,500, outlet pressure calculated and liquid rates of 8,000; 14,000 and 16,000 BPD. 4. To check for severe slugging: a. Configure the Y-axis of the System Analysis plot to display the PI-SS number. This represents the maximum value of the PI-SS number along the flowline. b. View the Output report by selecting Reports > Output File, to determine the prevalent flow regime at the riser base for the different rates.

Results Severe Slugging

8,000 stb/d

14,000 stb/d

16,000 stb/d

PI-SS number at riser base Flow pattern at riser base

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Lesson 4

Slug Catcher Sizing

PIPESIM is frequently used to estimate the capacity requirements for slug catchers. More detailed analysis is typically performed with transient simulators such as OLGA. For offshore platforms, you must balance the high cost of added weight to the platform with the potential of a large slug overwhelming the liquids handling capacity and shutting down the entire system. There are three typical scenarios to consider in the sizing of slug catchers for this type of system: •

Hydrodynamic slugging

•

Pigging

•

Ramp-up.

Hydrodynamic Slugging Most multiphase production systems will experience hydrodynamic slugging. Designing systems simply to avoid hydrodynamic slugging, such as larger pipe ID, is not a common practice. Because hydrodynamic slugs grow as they progress through the pipe, long pipelines can produce very large hydrodynamic slugs. PIPESIM calculates the mean slug length as a function of distance traveled by using the SSB or Norris Correlations. A continuous intermittent flow regime is required for this to occur. A probabilistic model (again, based on Prudhoe Bay field data) is applied to calculate the largest slug out of 10, 100 and 1,000 occurrences. The 1/1000 slug length is often used to determine slug catcher volume requirement. The slug output from PIPESIM yields the length and frequency for the selected slug size correlation:

154

•

Mean slug length (distribution is assumed skewed log normal)

•

1 in 1,000 slug length and frequency

•

1 in 100 slug length and frequency

•

1 in 10 slug length and frequency.

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The preceding probabilities represent various levels of confidence regarding the maximum slug size. For example, a 1 in one thousand slug length of 50 meters indicates there is only 0.1% probability of the maximum slug length exceeding 50 meters. Symbols that can be included in the slug output have the following meanings: 0.0

Flow is not in a slugging regime (as calculated by the relevant flow map correlation at spot report) and, thus, no hydrodynamic slugs are required.

N/A

The slug length calculated using the chosen slugging correlation is negative and, therefore, slug size is indeterminate at this point in the flowline.

It should be noted that the slug size data output is only printed if SLUG is specified in the Windows menu option Define Output (Figure 39).

Figure 39

Define Output menu options

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Alternatively, you can insert the Report tool and check Slugging values and Sphere-generated Liquid Volume values, as shown in Figure 40.

Figure 40

Selecting report properties

Pigging In multiphase flow in horizontal and upwards inclined pipe, the gas travels faster than the liquid due to lower density and lower viscosity. This is called slippage. Multiphase flow correlations predict the ‘slip-ratio’ which depends on many factors, such as fluid properties, pipe diameter and flow regime. To preserve continuity, recall the definition of liquid holdup discussed in Module 2. In steady-state flow, the gas travels faster, so it will slip past the liquid and occupy less pipe volume. This gives rise to a higher liquid volume fraction than if the gas traveled at the same velocity, resulting in ‘liquid holdup,’ as illustrated in Figure 41.

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Figure 41

Subsea Tieback Design

Liquid Holdup

During a pigging operation, a solid object the diameter of the pipeline is sent through the line to push out liquids and debris. As a pipeline is pigged (Figure 42), a volume of liquid builds up ahead of the pig and is expelled into the slug catcher as the pig approaches the exit. PIPESIM considers that the pig travels at the mean fluid velocity and, thus, the volume of liquid that collects ahead of the pig is a function the degree of slip between the gas and liquid phases (such as magnitude of liquid holdup). PIPESIM reports this volume as the sphere generated liquid volume (SGLV). The slip ratio (SR) is also reported, which is the average speed of the fluid divided by the speed of the liquid. The volume of liquid expelled at the receiving terminal as a result of pigging can be estimated using steady-state analysis as a first order approximation.

Figure 42

Pigging operation

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Ramp-up When the flow rate into a pipeline increases, the overall liquid holdup typically decreases because the gas can more efficiently sweep out the liquid phase. When a sudden rate increase (rampup) occurs, the liquid volume in the pipeline is accelerated resulting in a surge. A ramp-up operation is illustrated in Figure 43. The size of the surge is influenced by the sensitivity of liquid holdup with respect to the overall flow rate. A simple material balance approach can be applied to estimate the volume of the associated surge. For more details, see Cunliffe's method entry in the PIPESIM help system.

Figure 43

Ramp-up operation

Evaluating Each Scenario For a more detailed analysis of slug catcher sizing, you should also consider the drainage rates of the primary separator and slug catcher. Hydrodynamic slugs and pig-generated slugs typically occur over a short duration (minutes), while the surge created by a ramp-up operation can be a long duration (hours/days).

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Exercise 1

Sizing a Slug Catcher

In this exercise, you screen for severe slugging and determine the required size of the slug catcher based on the largest of the following criteria, multiplied by a safety factor of 1.2. Consider these criteria: •

Hydrodynamic slugging, which is the requirement to handle the largest slugs envisaged, chosen to be statistically the 1/ 1000 population slug size. This is determined by using the SSB or Norris Correlations.

•

The requirement to handle liquid swept in front of a pig.

•

Transient effects, such as the requirement to handle the liquid slug generated when the production flow is ramped up from 8,000 to 16,000 STB/D, such as Ramp-up surge. NOTE: For the purposes of sizing a slug-catcher, it is assumed that severe riser slugging can be mitigated with topsides choking or riser-based gas lift.

To size the slug catcher: 1. In the Report tool, verify that slugging values and sphere generated liquid volume are selected. 2. Re-run the System Analysis configured in the previous exercise. 3. For each sensitivity value, scroll down and read the reported 1/1000 slug volume and the Total Sphere Generated Liquid Volume So Far. 4. For the ramp-up case, calculate the difference in total liquid holdup, as this will be the surge volume. You must convert from ft3 > bbl. The conversion factor is 5.615 ft3/bbl. NOTE: The surge associated with ramp-up occurs over a much longer time period than the other cases. The ramp-up volume does not consider the drainage rate of the separator or the duration of the ramp-up.1 5. Inspect the output file and observe the flow regimes along the profile for each case. 1. See Cunliffe’s Method in the PIPESIM help system for information on how to calculate the ramp-up duration.

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6. Based on the results in the table below, select a slug catcher size that will be able to handle the largest slug volume for all conditions.

Results Slug Catcher Sizing

8,000 stb/d

14,000 stb/d

16,000 stb/d

1/1000 slug volume (bbl) Sphere generated liquid volume (bbl) Ramp-up volume (bbl) Design volume for slug catcher (bbl) (use 20% safety factor)

Review Questions •

What types of slugs are reported by PIPESIM?

•

How do you report SGVL at particular location in the system?

•

Why should the SGVL not be greater than the total liquid holdup?

•

Can PIPESIM be used for transient analysis?

Summary In this module, you learned about:

160

•

developing a compositional model of the hydrocarbon phases

•

sizing the subsea tieback line and riser

•

determining the pipeline insulation requirements

•

screening the results for severe slugging at the riser base

•

sizing a slug catcher.

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Looped Gas Gathering Network

Module 7 Looped Gas Gathering Network You must model the network as a complete system to account for the interaction of wells producing in a common gathering system. The wellhead pressure and, by extension, the deliverability of any particular well is influenced by the backpressure imposed by the production system. Modeling the network as a whole allows the engineer to determine the effects of such actions as adding new wells, adding compression, looping flowlines and changing the separator pressure. In this module, you learn how to build a gathering network and perform a network simulation to evaluate the deliverability of the complete system.

Learning Objectives After completing this module, you will know how to: •

build a model of the network

•

specify the network boundary condition

•

solve the network and establish the deliverability.

Lesson 1

Model a Gathering Network

Network models are constructed using the network module and solved using its calculation engine. The basic stages involved in developing a network model are: 1. Build a model of the field, including all wells and flowlines. 2. Specify the boundary conditions. 3. Run the model.

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Boundary Conditions To solve the network model, you must enter the correct number of boundary conditions. Boundary nodes are those that have only one connecting branch, such as a production well, injection well, source or sink. The number of boundary conditions required for a model is determined by the model’s Degrees of Freedom: number of wells (production and injection) + number of sources + number of sinks For example, a three-well system producing fluid to a single delivery point has 4 degrees of freedom (3+1), regardless of the network configuration between the well and the sink. Each boundary can be specified in terms of Pressure OR Flow rate OR Pressure/Flow rate (PQ) curve. Additionally, the following conditions must be satisfied: •

The number of pressure, flow rate or PQ specifications must equal the degrees of freedom of the model.

•

You must specify at least one pressure.

•

You must set the fluid temperature at each source (production well and source).

Solution Criteria A network has converged when the pressure balance and mass balance at each node are within the specified tolerance. The calculated pressure at each branch entering and leaving a node is averaged, and the tolerance of each pressure is calculated from the equation:

If all Ptol values are within the specified network tolerance, that node has passed the pressure convergence test. This is repeated for each node.

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The total mass flow rate into and out of a node are averaged. The tolerance is calculated from the equation: Ftol = If the Ftol value is within the specified network tolerance, that node has passed the mass convergence test. This is repeated for each node. The network has converged when all of the foregoing conditions are satisfied.

Exercise 1

Building a Model of a Network

In this case study, your goal is to establish the deliverability of a production network. The network connects three producing gas wells in a looped gathering system and delivers commingled product to a single delivery point.

Getting Started 1. Open PIPESIM and go to File > New > Network to create a new network model. 2. Go to File > Save As to save the model in your training directory, such as c:\training\pn01.bpn.

Building the Model Using the engineering data available at the end of this case study, build a model of a network. To build the model: 1. Click Production Well

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to place Well_1 in the work area.

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2. Double-click on Well_1 to reveal the components.

3. Double-click on the vertical completion to enter the inflow performance data. 4. Enter a gas PI of 0.0004 mmscf/d/psi2 and a reservoir temperature of 130 degF. NOTE: You will enter the reservoir pressure later when the network boundary conditions are specified. In the meantime put any value against Reservoir Pressure to let GUI dialog close. 5. Double-click on the tubing and select Simple Model as the preferred tubing model. 6. Define vertical tubing with a wellhead datum MD of 0 feet and mid perforations TVD and MD of 4,500 feet. 7. The ambient temperatures are 130 degF at mid-perforations and 60 degF at the wellhead. The tubing has an I.D. of 2.4 inches. NOTE: Essential data fields are shown in a red outline; if the fields are not outlined, data entry is optional. 8. Close the view of Well_1 by clicking at the upper-right corner of the window, or by selecting File > Close to return to the network view.

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9. Copy the data to Well_2 and Well_3. a. Select Well_1. b. Using the commands Edit > Copy and Edit > Paste (or Ctrl + C and Ctrl + V), create two copies of the well. NOTE: By default, the names of the copied wells will be Well_2 and Well_3 and contain the same input data as Well_1. 10. Position the new wells, as shown.

11. Modify the data of Well_3. a. Double-click on Well_3 and modify the completion and tubing data. b. For the vertical completion, enter a gas PI of 0.0005 mmscf/d/psi2 and a reservoir temperature of 140 degF. c. Define vertical tubing with a wellhead TVD of 0 and midperforations TVD and MD of 4,900 feet. d. The ambient temperatures are 140 degF at the midperforation depth and 60 degF at the surface. The tubing has an I.D. of 2.4 inches. e. Close the view of Well_3 to return to the network view.

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12. Specify the composition of each production well. This step defines the compositions at the production wells. Well_1 and Well_2 are producing from the same zone and, thus, are assumed to have the same composition. Well_3 has a composition that is different than that shown in the data section at the end of the case study. The most efficient way to define the compositions is to set the more prevalent composition (that for Wells_1 and Well_2) as the global composition, then specify the composition of Well_3 as a local composition. TIP: Composition data of all wells is provided at the end of this exercise in Summary data. a. Save the current network model. b. Define the global template of all components used in the network model. i. Select Setup > Compositional Template menu. ii. Add all library components (Hydrocarbon as well as aqueous components). c. Under the Petroleum Fraction tab, specify the name and properties of the petroleum fraction and add it to the list of template components. d. Select Setup > Compositional (Network Default). e. Enter the mole fraction for all components to define global composition (Well_1 and Well_2). NOTE: By default, the network global composition applies to all sources/wells in the network model. Check this by viewing the network fluid summary under Setup > Fluid Models. To define a different composition for any particular source/well, you must set it locally. f. Define the local composition for Well_3: i. Right-click on Well_3. ii. Choose Fluid Model. g. Select Use locally defined fluid model and click Edit. h. Choose Local Compositional and click Edit Composition. i. Enter the composition of Well_3.

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13. Connect the network together. a. Insert a sink and some junction nodes. NOTE: Holding down the Shift key while placing junction nodes allows for multiple insertions. Be sure to release the Shift key before the final insertion. The network should now look like this:

b. Use the Branch

button to connect J_1 to J_2.

i. Click the Branch object. ii. Hold down the left mouse button over J_1 and drag the cursor to J_2. iii. Release the mouse button. A connected branch is shown in the figure.

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14. Double-click on the arrow in the center of B1 to enter data for that branch. a. Double-click on the flowline to enter the following data: Rate of Undulations

10/1000

Horizontal distance

30,000 feet

Elevation difference

0 feet

Inner diameter

6 inches

Wall thickness

0.5 inches

Roughness

0.001 inches

Ambient temperature

degF

b. Close the B1 window to return to the network view. 15. The looped gathering lines are all identical, so the data for branch B1 can be used to define other looped gathering lines. a. Select B1. Click on the arrow in the middle of the branch and copy/paste B1 to create B2, B3, and B4. b. To connect a pasted branch: i. Click the arrow in the middle of the new branch. You will see highlight boxes display at either end of the branch. ii. Move the cursor over the right-hand, highlight box. The cursor changes to an up arrow (). Use this end of the branch to drag and drop onto a junction node.

c. Position the new branches.

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d. Connect the wells to the adjacent junction node and connect J_4 to the sink.

16. Double-click on branch B5 and insert the following objects in the left-to-right order shown in the figure:

• Liquid separator with an efficiency of 100% • Compressor with a pressure differential of +400 psi and an efficiency of 70% • After-cooler (heat exchanger) with an outlet temperature of 120 degF and ∆P of 15 psi • Flowline with the following properties: Rate of undulations

10/1000

Horizontal distance

10,000 feet

Elevation difference

0 feet

Inner Diameter

8 inches

Wall Thickness

0.5 inches

Roughness

0.001 inches

Ambient Temperature

60 degF

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a. Click Connector

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to join the equipment together.

b. Close the Single Branch window. 17. Select Setup > Flow Correlations menu and choose Beggs-Brill Revised as the global vertical and horizontal multiphase flow correlations. 18. In the Options Control tab of the Flow Correlations menu: a. Select use network options. b. Click Apply network options to all branches. 19. Select Setup > Erosion and Corrosion Options and choose the deWaard Corrosion model. This model calculates a corrosion rate caused by the presence of CO2 dissolved in water. Concentrations of CO2 and water are obtained from the fluid property definitions, (black oil or compositional). NOTE: The corrosion rate will be zero if CO2 or the liquid water phase is absent from the fluid. 20. In the Options Control tab of the Erosion and Corrosion Options menu: a. Select Use network options. b. Click Apply network options to all branches. 21. Save the model as gas_network.

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Exercise 2

Performing a Network Simulation

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

Pressure

Well_1

2,900 psia

Well_2

2,900 psia

Well_3

3,100 psia

Sink_1

800 psia

All flow rates are calculated by the network solver. NOTE: Any pressure specification defined in the single branch model must be re-specified in the network model. However, the boundary pressures specified in the Network view will update the pressures defined in the single branch model for use in single branch operations. 2. Open the Setup > Iterations menu to set the network tolerance to 1%. 3. Save the model. 4. Click Run

.

5. When the network has solved, you should see the message: Gas_networkbpn01 – Finished OK. When this message displays, click OK. 6. Click Report Tool

.

What is the gas production rate at the sink? _____ mmscfd? TIP: More comprehensive reporting is available by clicking Summary File

.

7. Hold down the Shift key and select the flow route from Well_3, branch B3 and branch B5.

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8. Click Profile Plot . You should obtain the pressure profile for these three branches. The effect of the compressor at J_4 on the system pressure should look similar to the figure.

9. Select Series and change the Y-axis to Corrosion Rate to observe the calculated corrosion rate. Maximum Corrosion Rate in network = ______ mm/year 10. Determine the field production rate in the event of a compressor shutdown. Assuming a bypass line exists around the compressor, deactivate the compressor object and rerun. Gas production rate at the Sink:______mmscfd NOTE: Edit the legend and title on PsPlot to improve the graphical presentation.

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Looped Gathering Network Data The tables that follow contain the data for exercises in this module.

Figure 44

Network layout Table 6: Completion and Tubing Data Well_1 and Well_2

Well_3

Gas PI

0.0004 mmscf/d/psi2

0.0005 mmscf/d/psi2

Wellhead TVD

0

0

Mid perforations TVD

4,500 feet

4,900 feet

Mid perforations MD

4,500 feet

4,900 feet

Tubing I.D.

2.4 inch

2.4 inch

Wellhead ambient temperature

60 degF

60 degF

Mid perforations ambient temperature

130 degF

140 degF

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Table 7: Pure Hydrocarbon Components (Well_1 and Well_2) Component

Moles

Carbon Dioxide

3

Methane

72

Ethane

6

Propane

3

Isobutane

1

Butane

1

Isopentane

1

Pentane

0.5

Hexane

0.5

Table 8: Petroleum Fraction (Well_1 and Well_2) Name

Boiling Point (degF)

Molecular Weight

Specific Gravity

Moles

C7+

214

115

0.683

12

Table 9: Aqueous Component (Well_1 and Well_2)

176

Component

Volume ratio (%bbl/bbl)

Water

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Table 10: Pure Hydrocarbon Components (Well_3) Component

Moles

Carbon Dioxide

2

Methane

71

Ethane

7

Propane

4

Isobutane

1.5

Butane

1.5

Isopentane

1.5

Pentane

0.5

Hexane

0.5

Table 11: Petroleum Fraction (Well_3) Name

Boiling Point (degF)

Molecular Weight

Specific Gravity

Moles

C7+

214

115

0.683

10.5

Table 12: Aqueous Component (Well_3) Component

Volume ratio (%bbl/bbl)

Water

5

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Table 13: Data for Looped Gathering Lines (B1, B2, B3, and B4) Rate of undulations

10/1000

Horizontal distance

30,000 feet

Elevation difference

0 feet

Inner diameter

6 inch

Wall thickness

0.5 inch

Roughness

0.001 inch

Ambient temperature

60 degF

Overall heat transfer coefficient

0.2 Btu/hr/ft2/degF

Table 14: Data for Deliver Line (B5)

178

Separator type

Liquid

Separator efficiency

100%

Compressor differential pressure

400 psi

Compressor efficiency

70%

After cooler outlet temperature

120 degF

After cooler delta P

15 psi

Flowline Rate of undulations

10/1,000

Flowline Horizontal distance

10,000 feet

Flowline Elevation difference

0 feet

Flowline Inner diameter

8 inch

Flowline Wall thickness

0.5 inch

Flowline Roughness

0.001 inch

Flowline Ambient temperature

60 degF

Flowline Overall heat transfer coefficient

0.2 Btu/hr/ft2/degF

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Table 15: Boundary Conditions Node

Pressure

Temperature

Well_1

2,900 psia

130 degF

Well_2

2,900 psia

130 degF

Well_3

3,100 psia

140 degF

Sink_1

800 psia

(calculated variable)

Review Questions •

How do you change tolerance in PIPESIM Network model?

•

What are the rules for pressure and flow rates in PIPESIM Net?

•

Where do you see corrosion rate in the PIPESIM output?

Summary In this module, you learned about: •

building a model of the network

•

specifying the network boundary condition

•

solving the network and establish the deliverability.

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Water Injection Network

Module 8 Water Injection Network In this module, you learn how to build and simulate a water injection network. Other features illustrated in this module include crossflow, single-phase (water), and electric submersible pump (ESP) lifted production well.

Learning Objectives After completing this module, you will know how to: •

build an injection network

•

insert an ESP into a well

•

model multilayer reservoir with and without crossflow.

Lesson 1

Crossflow in Multilayer Wells

Figure 45 shows how crossflow can occur when production from one zone is injected into another zone of lower pressure. This can occur in either production or injection systems.

Figure 45

Crossflow types in a layered reservoir

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

Exercise 1

Determining Fluid Distribution in a Water Injection Network

A water production well feeds water into an injection system consisting of two injection wells with multiple completions. The water is lifted from the production well by an ESP. Figure 46 schematically represents the layout of the studied water injection system. The objective of the exercise is to determine the fluid distribution (the water, in this instance) in an injection system from a single production well.

Figure 46

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Water Injection network by electric submersible pump (ESP)

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To determine fluid distribution: 1. Create a new network model by selecting File > New > Network. 2. Layout the network shown in Figure 46 using the data in the tables that follow. Water Production Well Reservoir Pressure

4,000

psia

Temperature

200

degF

Productivity Index (PI)

100

STB/d/psi

Tubing Model

simple

Orientation

vertical

Tubing depth

6,000

ft. TVD

Surface ambient temp

50

degF

Tubing ID

7

in

ESP depth

2,000

ft. TVD

ESP model

Centrilift IB700

ESP stages

30

ESP speed

3,600

rpm

Surface Flowlines (all) Ambient Temperature

50

degF

HTC

0.2

BTU/hr/ft2/degF

Flowline Data

Flowline

Distance (ft)

Elevation Difference (ft)

Diameter (in)

B1

150

0

8

B2

15,000

0

6

B3

10,000

0

6

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Both injection wells have 1.995-inch ID tubing and the properties listed in the table. Injection Well 1

Zone

Reservoir Pressure (psia)

Res Temp (degF)

Zone 1_1

4,400

210

7,800

2

No FCV

Zone 1_2

4,600

220

7,900

3

Maximum Liquid = 1,500 STB/d

Zone 1_3

4,800

235

8,200

5

Equivalent Choke Area = 0.25 in2

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

FCV

Injection Well 2

Zone

Reservoir Pressure (psia)

Res Temp (degF)

Zone 2_1

4,500

220

7,900

4

No FCV

Zone 2_2

4,800

250

8,500

5

Maximum Liquid = 1,000 STB/d

Zone 2_3

5,000

270

8,800

4

FCV Closed

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

FCV

NOTE: For each of the lower two multi-layer tubing objects, be sure to use the bottom MD of the upper tubing string for the datum MD of the next lower tubing string. For example, Datum MD for tubing between zone 1_1 and 1_2 should be 7,800 ft. Leave all other parameters at their default settings. 3. Create a global fluid model for water by selecting Setup > Black Oil. 4. Specify water as fluid (set water cut as 100% and GLR = 0). 5. Select Beggs-Brill Revised as the vertical and horizontal multiphase flow correlations. 6. Select Setup > Engine Options and enter the following in the additional Engine Keywords field (TOP of network file): OPTIONS REVERSEFLOW = ON

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

Pressure

Producer

4000 psia

Well_1

4800 psia

Well_2

5000 psia

8. Click Run Model 9. Click Report Tool

to start the simulation. and select Clear.

10. Click on the producing well and each of the injectors.

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

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Review Questions •

Which crossflow scenario occurs in your model?

•

What is the effect of installing FCV in your model.

•

Remove the FCVs from completions and compare the results. Which crossflow scenarios now occur?

•

What other way can a water fluid model be defined?

Summary In this module, you learned about modeling:

186

•

a water injection network

•

a multilayer injection well

•

an ESP.

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PIPESIM 2010.1 Fundamentals Answer Key to Exercises

Appendix A PIPESIM 2010.1 Fundamentals Answer Key to Exercises Module 2: Simple Pipeline Tutorials Lesson 1: Single-Phase Flow Calculations Exercise 1: Hand Calculations 1. Water Velocity

= 7.9ft/s

2. Reynold’s number = ~157,000; turbulent flow 3. Friction Factor

= ~ 0.0193

4. dP(friction)

= 662 psi

5. dP(elevation)

= 442 psi

6. dP(Total)

= 1,106 psi

7. Outlet Pressure

= 94 psia

Exercise 2: PIPESIM Calculation •

Liquid velocity

= 7.91-7.94 ft/s

•

dP (frictional)

= 667.6 psi

•

dP (elevational)

= 443.1 psi

•

dP (total)

= 1,111 psi

•

P(outlet)

= 89.33 psia

Exercise 5: Gas Flowline Capacity •

Flow rate

= 10.47 mmscfd

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Module 3: Oil Well Performance Analysis Lesson 1: Nodal Analysis Exercise 2: Performing Nodal Analysis (Outlet) Wellhead Pressure

= 300 psia

Operating Point Flow rate

= 8,510 stb/d

Operating Point BHP

= 2,536 psia

AOFP

= 21,290 stb/d

Exercise 3: Performing a Pressure/Temperature Profile (Outlet) Wellhead Pressure

= 300 psia

Production Rate

= 8,518 stb/d

Flowing BHP

= 2,535 psia

Flowing WHT

= 134 degF

Depth at which gas appears

= 7,200 ft

Lesson 2: Fluid Calibration Exercise 1: Wellhead Pressure

= 300 psia

Production Rate

= 7,808 stb/d

Flowing BHP

= 2,624 psia

Flowing WHT

= 129 degF

Depth at which gas appears

= 6,730 ft

Lesson 3: Pressure/Temperature Matching Exercise 1: Flow Correlation Matching

190

Wellhead Pressure

= 300 psia

Vertical Correlation

= TUFFP-2Phase

Flowing BHP

= 2,681 psia

Head Factor

= 1.0059

Friction Factor

= 0.93035

U Factor

= 0.7907

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PIPESIM 2010.1 Fundamentals Answer Key to Exercises

Exercise 2: Matching Inflow Performance Wellhead Pressure

= 300 psia

PI

= 6.669126

Lesson 4: Well Performance Analysis Exercise 1: Conducting a Water Cut Sensitivity Analysis Wellhead Pressure

= 300 psia

Water Cut

= 53.4%

Exercise 2: Evaluating Gas Lift Performance Gas Lift Rate (mmscf/d)

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

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

1

7,918

5,364

2

8,800

6,349

4

9,649

7,122

6

10,101

7,400

10

10,485

6,846

Exercise 3: Working with Multiple Completions Wellhead Pressure

= 300 psia

Liquid Rate (stb/d)

= 6,885

Gas Rate (upper zone) (mmscfd)

= 4.161

Question (Optional) •

Equivalent gas lift injection rate = 3.38

Lesson 5: Flow Control Valve Modelling Exercise 1: Modelling a Flow Control Valve •

Required Bean Size = 0.046 in2

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Module 4: Gas Well Performance Lesson 2: Gas Well Deliverability Exercise 1: Calculating Gas Well Deliverability Pres = 4,600 psia, Tres = 280 degF % H2O @ saturation

1.8549

Po = 800 psia QG

18.21 mmscfd

Pwf

1,716 psia

BHT

237 degF

WHT

169 degF

Exercise 2: Calibrating the Inflow Model Using Multipoint Test Data Back Pressure Equation Parameter C

7.9793682e-007

Parameter n

1 Po = 800 psia

192

QG

14.97 mmscfd

Pwf

1,548 psia

Tbh (degF)

233 degF

Twh (degF)

165 degF

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PIPESIM 2010.1 Fundamentals Answer Key to Exercises

Lesson 3: Erosion Prediction Exercise 1: Selecting a Tubing Size Based on the results of the Nodal Analysis and EVR calculations, which tubing size would you select? 3.958 in. Po = 800 psia QG

15.39 mmscfd

Pwf

1,370 psia

BHT

229 degF

WHT

163 degF Wellhead, Selected Tubing

Max. Erosional velocity ratio

0.7657

Lesson 4: Choke Modelling Exercise 1: Modelling a Flowline and Choke Po = 710 psia Choke size

1.5145 ins

Pressure losses across system P Reservoir

3,231.5 psia

P Tubing

569.55 psia

P Choke

86.75 psia

P Flow-line

1.79 psia

Exercise 2: Predicting Future Production Rates Reservoir Pressure

Flow rate

3,400

8.051

3,800

10.272

4,200

12.723

4,600

15.387

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Lesson 5: Critical Gas Rate Exercise 1: Determining a Critical Gas Rate to Prevent Well Loading The reported critical gas rate = 2.099 mmscfd.

Module 5: Horizontal Well Design Lesson 1: Inflow Performance Relationships Exercise 2: Evaluating the Optimal Horizontal Well Length Optimal horizontal well length = 10,000 ft

Exercise 3: Specifying Multiple Horizontal Perforated Intervals Po = 200 psia QG

24.40 mmscfd

Bhp

2,683 psia

Module 6: Subsea Tieback Design Lesson 1: Flow Assurance Considerations for Subsea Tieback Design Exercise 3: Sizing the Subsea Tieback Pipeline and Riser ID

= 10 inch

Max. erosional velocity ratio for selected ID

= 0.825

Min. outlet pressure for selected ID

= 947 psia

Max. outlet pressure for selected ID

= 1,265 psia

Lesson 2: Hydrates Exercise 1: Selecting Tieback Insulation Thickness Req. Insulation thickness = 1 in

194

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PIPESIM 2010.1 Fundamentals Answer Key to Exercises

Exercise 2: Determining the Methanol Requirement Req. Methanol Injection Volume (bbl/d) = 523

Lesson 3: Severe Riser Slugging Exercise 1: Screening for Severe Riser Slugging

PI-SS number at riser base Flow pattern at riser base

8,000 stb/d

14,000 stb/d

16,000 stb/d

1.01

1.266

1.332

Intermittent

Intermittent

Intermittent

Lesson 4: Slug Catcher Sizing Exercise 1: Sizing a Slug Catcher 8,000 stb/d

14,000 stb/d

16,000 stb/d

1/1000 slug volume (bbl)

165

181

215

Sphere generated liquid volume (bbl)

465

435

427

Property

Ramp-up volume (bbl)

962 – 799 = 163

Design volume for slug catcher (bbl)

465 * 1.2 = 558

Module 7: Looped Gas Gathering Network Lesson 1: Model a Gathering Network Exercise 2: Performing a Network Simulation •

Gas production rate at the Sink

= 42.28 mmscfd.

•

Maximum Corrosion Rate in network

= 44.902 mm/year

•

Gas production rate at the Sink

= 38.26 mmscfd.

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NOTES

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