PIPESIM Fundamentals Training and Exercise Guide

PIPESIM Fundamentals Training and Exercise Guide Version 2006.1

Schlumberger Information Solutions 25 January 2007

PIPESIM 2006.1 Fundamentals

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Module 1

Introduction ....................................................................................... 1

Prerequisites ....................................................................................................................... 1 Learning Objectives ............................................................................................................ 1 What You Will Need............................................................................................................ 1 What To Expect .................................................................................................................. 2 Summary............................................................................................................................. 2

Module 2

Single Phase Introductory Tutorials............................................... 3

Learning Objectives ............................................................................................................ 3 Water Pipeline Tutorial........................................................................................................ 3 Getting Started ............................................................................................................................ 3 Exercise 1 – Build the Physical Model (a Water Pipeline Model)............................................. 4 Exercise 2 – Water Pipeline Sensitivity Study .........................................................................15 Exercise 3 – Gas Pipeline Sensitivity Study ............................................................................18 Exercise 4 – Calculate the gas flow rate for a given pressure drop .......................................20

Multiphase Pipeline Tutorial.............................................................................................. 23 Learning Objectives .......................................................................................................... 23 Getting Started .................................................................................................................. 23 Exercise 1 – Build a Multiphase pipeline model ......................................................................24

Oil Well Performance Tutorial........................................................................................... 30 Learning Objectives .......................................................................................................... 30 Getting Started .................................................................................................................. 30 Exercise 1 – Build a Physical Model ........................................................................................31 Exercise 2 – Sensitivity Analysis ..............................................................................................38

Black Oil Calibration and Performance Forecasting Tutorial .......................................... 40 Learning Objectives .......................................................................................................... 40 Getting Started .................................................................................................................. 40 Exercise 1 – Insert Completion and Develop a Well Inflow Performance Model ..................41 Exercise 2 – Develop a Calibrated Black Oil Model................................................................44 Exercise 3 – Select a Tubing Size for the Production String ..................................................52 PIPESIM 2006.1 Fundamentals

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Exercise 4 – Gas Lift Feasibility Study.....................................................................................54

Module 3

Well Performance............................................................................ 57

Oil Well Performance Analysis ......................................................................................... 57 Learning Objectives ..................................................................................................................57 Exercise 1 – Estimate bottom-hole flowing conditions............................................................58 Exercise 2 – Perform Nodal Analysis.......................................................................................60 Exercise 3 – Calibrate PVT Data..............................................................................................61 Exercise 4 – Perform Flow Correlation Matching....................................................................62 Exercise 5 – Perform IPR Matching.........................................................................................63 Exercise 6 – Conduct Water Cut Sensitivity Analysis ............................................................64 Exercise 7 – Evaluate Gas Lift Performance...........................................................................65

Enhancing Oil Well Production Using Nodal Analysis..................................................... 66 Learning Objectives ..................................................................................................................66 Exercise 1 – Well Model / Nodal Analysis................................................................................67 Exercise 2 – Nodal Analysis – Sensitivity to Stimulation and Gas Lift ...................................69 Exercise 3 – Nodal Analysis – Sensitivity to Flow Correlation................................................70

Gas Well Performance using a Compositional Fluid Model............................................ 71 Learning Objectives ..................................................................................................................71 Exercise 1 – Build a Simple Well Model ..................................................................................72 Exercise 2 – Calibrate the Inflow Model...................................................................................75 Exercise 3 – Perform Nodal Analysis at Bottom-Hole.............................................................76 Exercise 4 – Perform System Analysis....................................................................................77 Exercise 5 – Model Flow-line and Choke Performance..........................................................78 Exercise 6 – Evaluate Higher Liquid Loading / Flow Correlation Matching ...........................79 Exercise 7 – Calculate Liquid Hold-up Fraction and Flow Regime Map................................81 Exercise 8 – Pressure/Temperature Path from Reservoir......................................................82 Exercise 9 – Pressure Drop due to Increased Condensate Production ................................83 Challenge Exercise 10 – Rigorous Flashing............................................................................84

Module 4

Artificial Lift Design ........................................................................ 84

ESP Design....................................................................................................................... 84 Learning Objectives ..................................................................................................................84 Exercise 1 – Well Model / Nodal Analysis................................................................................86 Exercise 2 – Pump Selection / Design.....................................................................................88 Exercise 3 – Pump Performance with Varying Well Conditions.............................................90

Gas Lift Design – New Mandrel Spacing ......................................................................... 91 Learning Objectives ..................................................................................................................91 PIPESIM 2006.1 Fundamentals

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Exercise 1 – Well Model / Nodal Analysis................................................................................92 Exercise 2 – Evaluate the Lift Gas Response .........................................................................94 Exercise 3 – Perform Gas Lift Design (using the “IPO Surface Close” method)...................95

Gas Lift Design – Current Mandrel Spacing .................................................................... 97 Learning Objectives ..................................................................................................................97 Exercise 1 – Install a Gas Lift Valve System, Deepest Injection Point Operation .................98 Exercise 2 – Generate the Gas Lift Response Curves .........................................................100 Exercise 3 – Design the Gas Lift Valve System using the Current Mandrel Spacing .........101 Exercise 4 – Gas Lift Diagnostics...........................................................................................103

Module 5

Single Branch Pipeline and Facilities......................................... 105

Subsea Tieback Design.................................................................................................. 105 Learning Objectives ................................................................................................................105 Exercise 1 – Develop a Compositional PVT Model ..............................................................106 Exercise 2 – Size the Subsea Tieback ..................................................................................107 Exercise 3 – Check For Severe Slugging..............................................................................109 Exercise 4 – Select Tieback Insulation Thickness ................................................................110 Exercise 4b – Methanol requirement .....................................................................................110 Exercise 5 – Size Slug Catcher..............................................................................................111

Module 6

Network Modeling......................................................................... 113

Looped Gathering Network............................................................................................. 113 Learning Objectives ................................................................................................................113 Getting Started ........................................................................................................................113 Build a model of a network .....................................................................................................113 Specify the Network Boundary Condition ..............................................................................118 Solve the Network and Establish the Deliverability ...............................................................119 Network Tutorial 1: Data Summary........................................................................................121

Gas Transmission Network ............................................................................................ 124 Water Injection System................................................................................................... 129

Module 7

Answers ......................................................................................... 133

Well Performance Case Studies .................................................................................... 133 Oil Well Performance Analysis ...............................................................................................133 Enhanced Oil Well Production Using Nodal Analysis ...........................................................135 Gas Well Performance using a Compositional Fluid Model .................................................136

Artificial Lift Design.......................................................................................................... 138 ESP Design .............................................................................................................................138 PIPESIM 2006.1 Fundamentals

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Single Branch Pipeline and Facilities ............................................................................. 139


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Introduction

Module 1

Introduction

This training material and guide is designed to give you an introduction into the PIPESIM software application. PIPESIM is a production engineer’s tool that covers a wide range of applications relevant to the oil and gas industry. Applications featured in this training manual include Nodal Analysis, Gas Lift Design and Network Modeling.

Prerequisites In the PIPESIM course, you must have knowledge of the following: •

English Proficiency

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Basic Windows and practical computing skills

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Basic Microsoft Office skills

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Basic Production and Reservoir Engineering Fundamentals

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Basic Nodal Analysis (Inflow and Outflow Performance)

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Basic Artificial Lift Concepts

Learning Objectives In this module, you will successfully learn how to use PIPESIM by performing the following tutorials and case studies: •

Single Phase Introductory Tutorials

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Well Performance Case Studies

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Artificial Lift Design Case Studies

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Single Branch Pipeline and Facilities Case Studies

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Network Modeling Case Studies

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FPT Tutorials

What You Will Need In this training, you will need the following hardware and application software: •

A personal computer with minimum 512 MB RAM

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PIPESIM 2004 should be installed

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Training datasets


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What To Expect The training material is structured as follows •

Introduction to the module

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Learning Objectives

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Tutorial and Exercises

Summary of the Module

Summary At the end of this training you will be reasonably proficient with using PIPESIM to perform a wide variety of production engineering tasks to evaluate and predict well performance.


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The purpose of this tutorial is to familiarize you with the PIPESIM Single Branch interface by building and running simple examples. You will construct a simple pipeline model and then calculate the pressure drop along a horizontal pipeline for a given inlet pressure and flow-rate. You will then run some sensitivity studies on the model.

Learning Objectives In this module, you will successfully learn how to perform the following procedures within this workflow: •

Build the Physical Model

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Create a Fluid Model

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Choose Flow Correlations

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Perform Operations

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View and Analyze Results

Water Pipeline Tutorial Getting Started In this section, you will learn how to build a water pipeline. 1. Start PIPESIM from the Start menu (Start > Program Files > Schlumberger > PIPESIM) 2. Choose a New Single Branch Model from the “Select a PIPESIM option” screen.

3. From the Setup > Units menu, select the Eng(ineering) units.


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Single Phase Introductory Tutorial

Exercise 1 – Build the Physical Model (a Water Pipeline Model) Step 1 - Define the Physical Components of the Model The PIPESIM single branch model toolbar

contains the following physical components: Node

Choke

Boundary Node

Injection Point

Source

Equipment Point

Vertical Completion

Multiplier / Adder

Horizontal Completion

Report

Pump

Engine Keyword Tool

Multiphase Booster

Nodal Analysis Point

Separator

Connector

Compressor

Flowline

Expander

Tubing

Heat Exchanger

Riser

1. Select the Source button

and place it in the window by clicking inside the single

branch window. Select the Boundary Node button shown below.

and place it in the window as

2. Select the Flowline button and link Source_1 to the End Node S1 by clicking and dragging from Source_1 to the End Node S1: PIPESIM 2006.1 Fundamentals

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Note: The red outlines on Source_1 and Flowline_1 indicate that essential input data is missing. 3. Double-click on Source_1 and the source input data user form displays. Fill in the form as shown below.

4. Click OK to exit the user form. 5. Double-click on Flowline_1 and the input data user form will appear. Fill the form as shown below ensuring that the rate of undulations = 0 (no terrain effects).


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6. Click on the Heat Transfer tab and fill in the form for an adiabatic process (i.e., no heat gained or lost between the system and its environment) as shown below:

7. Click OK to exit the user form, i.e., accept the internal energy (U value) defaults.

Step 2 - Create the Fluid Model (water) 1. Go to Setup > Black Oil to open the Black Oil Fluid menu. Fill in the Black Oil user form as shown below and click OK when finished: PIPESIM 2006.1 Fundamentals

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2. Go to File > SaveAs and save the Model as “CaseStudy1_WaterPipe.bps”

Step 3 - Choose Flow Correlations From the Setup > Flow Correlations menu select the Moody single phase flow correlation.


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Step 4 - Perform Operations 1. From the Operations menu select the Pressure/Temperature Profile operation and enter the known flowing conditions as shown below.


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2. Run the model by clicking on the Run Model button. The pressure calculation will be done using the Moody correlation (Default single phase correlation).

Step 5 - View and Analyze the Results 1. Graphical Output The following pressure profile should be visible upon completion of the run.


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Click on the Data tab to display a tabular output of the Pressure/Temperature Profile. Notice that the outlet pressure is 935 psia.


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Note: Computed pressures may vary slightly from previous PIPESIM versions. Also, to copy this data into Excel, highlight the cells of interest, hit Ctrl+C, then select a cell in Excel and hit Ctrl+V. 2. Summary File An abbreviated form of the full output file is presented in the summary results file. To open this file, from the Reports menu, select the Summary File option. The following output can be observed:

The Liquid holdup value displayed (2273 bbl) is the total liquid volume for the entire pipe.


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3. Output File In the Reports menu select the Output File option. The Output File is divided by default in 5 sections: •

Input Data Echo (Input data and Input units summary)

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Fluid Property Data (Input data of the fluid model)

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Profile and Flow Correlations (Profile and selected correlations summary)

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Primary Output

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Auxiliary Output

The Primary Output is shown below.

Note that if the units reported in the output file are not the desired ones, the user should change units (Setup > Units and pick the preferred unit system) and re-run the simulation. The Primary Output contains 16 columns: 1. Node number: node at which all the measures on the row have been recorded. (The nodes have by default been spaced with a 1 km interval) 2. Horizontal Distance (cumulative horizontal component of length) 3. Elevation (absolute) 4. Angle of inclination (from the horizontal) 5. Angle of inclination (from the vertical) 6. Pressure 7. Temperature 8. Mean mixture velocity 9. Elevational pressure drop


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10. Frictional pressure drop 11. Actual Liquid Flow rate at the P,T conditions of the node 12. Actual Free gas rate at the P,T conditions of the node 13. Actual Liquid density at the P,T conditions of the node 14. Actual Free gas density at the P,T conditions of the node 15. Slug Number 16. Flow Pattern Notice that as the pressure decreases the liquid density decreases, therefore the velocity must increase to maintain a constant mass flow rate. The Auxiliary Output is shown below:

The auxiliary output also consists of 17 columns: 1. Node Number 2. Horizontal Distance (cumulative) 3. Elevation (absolute) 4. Superficial Liquid Velocity 5. Superficial Gas velocity 6. Liquid mass flow rate 7. Gas Mass flow rate 8. Liquid viscosity 9. Gas viscosity 10. Reynolds Number 11. Liquid Volume Fraction


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12. Liquid hold-up Fraction 13. Liquid Water cut 14. Fluid Enthalpy 15. Erosional Velocity 16. Number of Temperature Iterations 17. Number of Pressure Iterations The values of the Reynolds number indicate that the flow regime is turbulent (Nre > 2000). Modify the graphical output using the Series… option on the PsPlot window to show that the viscosity decreases as the pressure decreases`.


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Exercise 2 – Water Pipeline Sensitivity Study Continuing with the previous example, you will now explore how our model responds to different inlet temperatures.

Step 1 - Modify the P/T Profile operation user 1. From the Operations menu select the Pressure/Temperature Profile Operation. Select Source_1 as the Object and Temperature as the Variable. 2. In the Pressure/Temperature Profile user form click on the An input form appears and must be filled as follows:

button.

3. Click on the Apply button. The filled user form is shown below:

4. Close the Set Range window.

Step 2 – Run the Model Click the Run Model button. The pressure calculation will be done using the Moody correlation (Default single phase correlation).


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Step 3 - Observe the PSPLOT Output The following 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, therefore the Reynolds number increases, the corresponding friction factor decreases and the frictional pressure gradient is lower. In the case of water the effect of the temperature on the density is negligible. Select the Data tab in the plot window to observe all the data for each temperature in a tabular format.

Step 4 - Observe the Output file (.out) 1. The output file can be opened by selecting the Output File button from within the Operations (Pressure/Temperature Profiles) dialog or by going to the Reports menu and selecting Output File option. Note that the Output file contains by default the information for the first case only. (T = 10 deg C). To report all sensitivity cases, from the Setup menu, select the Define Output option and set the number of cases to print to 7.


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2. Re-run the operation. Note: If you do not change the Operation or alter any of the parameters within the Operations menu, you can run the simulation by pressing the Run button

.

3. Open the output report and you will see the results of the seven sensitivity cases. 4. Return to the Setup > Define Output menu. Check the Segment Data in Primary Output option and re-run the operation. Open the Output file and observe that additional segments have been inserted on each side of the nodes (placed by default 30 cm each side of each node).

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


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Exercise 3 – Gas Pipeline Sensitivity Study Without changing any of the physical components of our previous example, you will now investigate the flow of a single phase gas.

Step 1 - Redefine the Fluid Model From Setup > Black Oil, modify the user form as shown below to represent 100 % gas:

Step 2 - Modify the Pressure/Temperature Profile Operation and Run the Model 1. Modify the Pressure/Temperature Profile user form as shown below:


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2. Uncheck the box labeled “Segment Data in Primary Output” under the Setup > Define Output menu.

Step 3 - Run the Model Click the Run model button. As for the case of a single-phase liquid, the pressure calculation will be done using the Moody correlation.

Step 4 - Observe the Output Plot Inspect the pressure profile plot upon completion of the run. Notice that the highest inlet temperatures yield the highest pressure drop. This is because as the temperature increases the density decreases therefore the Reynolds number decreases. Correspondingly, the friction factor increases and thus the frictional pressure gradient is higher.


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Exercise 4 – Calculate the gas flow rate for a given pressure drop In the previous exercises, you calculated the outlet pressure given a known inlet pressure and flow rate. You will now specify known inlet and outlet pressures and calculate the corresponding gas flow rate.

Step 1 - Modify the Pressure/Temperature Profile User Form Specify 1000 psia for the outlet pressure and clear the temperature sensitivity values as shown below (highlight cells and hit ctrl X). The simulation calculates the standard gas flow rate for a given pressure drop.

Step 2 – Run the Model Click the

button on the user form.

The pressure calculation will again be calculated using the Moody correlation.

Step 3 - 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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Observe the output files (.out) The iteration routine for this operation can be seen in the output file as shown below.


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Save your file as exer4.bps. Close the model.


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Multiphase Pipeline Tutorial The previous examples explored single phase flow of water and gas through a pipeline. We will now create a new model and explore multiphase flow through a pipeline.

Learning Objectives In this tutorial, as you did in the previous one, you will successfully learn how to perform the following procedures within this workflow: •


•


•


•

Perform Operations

•


Getting Started In this section, you will learn how to build a multi-phase pipeline. Select File > New > Pipeline and Facilities.


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Exercise 1 – Build a Multiphase pipeline model Step 1 - Build the Physical Model Using the toolbar, construct the model shown below:

Source_1 Data:

Flowline Data: (Keep all default heat transfer options)


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Report tool options (same for both Report Tools)

Step 2 - Create a Black Oil Fluid Model Select the black oil fluid properties from the Setup > Black Oil menu.


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Step 3 - Choose Flow Correlations From the Setup > Flow Correlations menu, select Beggs and Brill for both the horizontal and vertical flow correlations.

Step 4 - Perform a Pressure/Temperature Profile Operation From the Operations > Pressure Temperature Profile menu, enter the following:

Note: If the Inlet Pressure text box is left empty, the value will be taken from the Source_1 user form. The pressure drop will be calculated using the Moody correlation (Default single phase correlation) and the Beggs and Brill Correlation.

Step 5 - Run the model Run the Model.


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Step 6 - View and Analyze Results

The following display can be seen in the Primary output section of the Output file.

The flow pattern, shown below, can be seen by scrolling to the right:.


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Notice that the flow is initially single-phase liquid until the pressure falls below the bubblepoint upon which two-phases oil-gas flow is present. The single-phase moody correlation is used in the first part of the pipe, and the Beggs and Brill correlation is used in the second part of the pipe once liquid condenses. (The holdup for each of the segment can be seen in the auxiliary output.) The number 1.7 is the Erosional Velocity Ratio (EVR = actual velocity/API 14e limit) and is only displayed when higher than 1. The spot reports output is shown below:


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Note: To view the graphics and output in SI or Custom units, you will first need to specify the units via the Setup > Units… option, and re-run the model.


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Oil Well Performance Tutorial In this tutorial we will model well performance using the same general workflow as before.

Learning Objectives In this module, as you did in the previous module, you will successfully learn how to perform the following procedures within this workflow: •


•


•


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Perform Operations

•


Getting Started In this section, you will learn how to model well performance. 1. Select File > New > Well Performance Analysis. 2. From Setup > Units, set engineering units.


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Exercise 1 – Build a Physical Model Step 1 - Define the Physical Components of the Model The PIPESIM single branch model toolbar is shown below:

1. Select the Vertical Completion button Select the End Node button

and place it in the single branch window.

and place it in the window:

2. Select the Select the Tubing button and link VertWell_1 to the End Node S1 by clicking and dragging from VertWell_1 completion to the End Node S1:


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Note: The red outlines on VertWell_1 and Tubing_1 indicate that essential input data is missing 3. Double-click on VertWell_1 and the source input data user form displays. Fill in the form as shown below.

4. Click OK to exit the user form. 5. Double-click on Tubing_1 and the input data user form will appear. 6. Select Simple Model as the Preferred tubing Model as shown below:


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7. Enter the tubing data as shown below:

8. Click OK to exit the user form.

Step 2 - Choose the Black Oil Model 1. Select Setup > Black Oil and enter the fluid properties as shown below:


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2. Save the Model as “CaseStudy1_Oil Well.bps”.

Step 3 - Choose the Multiphase Flow Correlations From the Setup > Flow Correlation menu, ensure that the Beggs Brill Revised correlation is selected for both Vertical and Horizontal Flow.

Step 4 - Perform a Pressure/Temperature Profile Operation Select Operations > Pressure Temperature Profile. Enter a liquid rate of 3000 stb/d and select outlet pressure as the calculated variable. PIPESIM automatically assumes that the inlet pressure is the static reservoir pressure specified in the completion.


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Step 5 - Run the Model Run the model.

Step 6 - View and Analyze the Output The following pressure profile should be visible upon completion of the run.

Notice that the outlet pressure is approximately 695 psia. Click on the Data tab to display a tabular output of the Pressure Temperature Profile.


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Note: To copy this data into Excel, highlight the cells of interest, hit Ctrl+C, then select a cell in Excel and hit Ctrl+V. To observe the Summary Text output, go to Reports > Summary File.

The Liquid Hold-up value displayed (101 bbl) is the liquid content of the entire pipe. For a more detailed text output, go to Reports > Output File. The Primary output section of the Output file is shown below.


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Notice that as the Pressure decreases, the liquid holdup decreases. Therefore, the liquid flow rate decreases to maintain the mass flow rate constant. Also, as the pressure decreases, the gas density decreases. Therefore, the gas hold-up increases and the gas velocity has to increase to maintain a constant mass flow rate. The gas volumetric flow rate increases with decreasing pressure due to gas expansion. The Auxiliary Output section of the Output file is shown below.

Save the model as “tut3ex1.bps”.


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Exercise 2 – Sensitivity Analysis Notice as the Pressure decreases, the liquid holdup decreases. Therefore, the liquid flow rate decreases to maintain the mass flow rate constant.

Step 1 - Modify the Pressure/Temperature Profile Operation User Form From the Operations > Pressure Temperature Profile menu, perform a sensitivity analysis with VertWell_1 as the Component and Static Pressure as the Variable. Enter values shown below:

Step 2 - Run the Model Run the model by clicking on

in the user form.

Step 3 - Observe the Output Plot The following pressure profile should be visible by clicking on of the screen.


at the bottom

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The pressure drop across the reservoir is identical for all cases due to the PI and flow rate being constant. For the case Pws = 1000 psia the reservoir pressure is not sufficient to lift the column of fluid to the surface (the tubing pressure reaches zero at –4000 ft). 1. Select the Data tab in the plot window to observe the plot data in tabular format. 2. Open the Output File. The Output file contains by default the information for the first case only. (Pws = 3600 psia). From Setup > Define Output, set the number of cases to print to 4. Re-run the operation. You will see the output of the 4 sensitivity cases displayed in the Output file. 3. Return to the Define Output user form. Check the Segment Data in Primary Output option and re-run the operation. You will see the additional segments on each side of the nodes (placed by default 30 cm each side of each node).

PIPESIM performs the pressure drop calculation for each of those additional segments by default in order to obtain precise averaged values of properties such as liquid hold-up or velocities at the main nodes.


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Black Oil Calibration and Performance Forecasting Tutorial An oil reservoir has been discovered in the North Sea. A vertical well has been drilled, a test string run and flow characteristics measured. Fluid properties at stock tank and laboratory conditions have been obtained. Reservoir simulations have been performed to predict the change in water cut over the field life. The reservoir pressure will be maintained by water injection and the preference is to avoid the use of artificial lift methods.

Learning Objectives In this tutorial you will: •

Develop a well inflow performance model applicable throughout field life. This provides a relationship between the reservoir pressure, the flowing bottomhole pressure and flow rate in the formation.

•

Develop a Black Oil fluid model to match the laboratory data. It is necessary to develop an accurate method of predicting the fluid physical properties so that the pressure losses and heat transfer characteristics can be calculated.

•

Select a suitable tubing size for the production string.

•

Review the feasibility of using gas lift as an alternative to water injection.

Getting Started In this section, you will learn how to calibrate a black oil model and evaluate performance forecasting. 1. Select File > New > Well Performance Analysis. 2. From Setup > Units, set engineering units.


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Exercise 1 – Insert Completion and Develop a Well Inflow Performance Model A straight line, productivity index (PI) method is considered adequate in this case because the fluid flows into the completion at a pressure considerably above the bubblepoint and no gas comes out of solution at this stage. This method applies throughout field life, and the productivity index is not expected to change. The PI will not be affected by changes to the reservoir pressure because the reservoir pressure is to be maintained by water injection. The PI will not be affected by changes to the water-cut through field life because the oil and water have similar mobilities in this reservoir structure.

Add Completion Add a vertical completion to the model.

1. Double-click on the vertical completion in the work area to enter the following data.

2. Click on the Calculate/Graph… button. Enter the drill string test data, as shown below, and click on the Plot IPR button. This will calculate a productivity index of 25 stb/d/psi to be used throughout the analysis work.


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TIP: Right click-and-drag on a plot to position data points. To zoom in, left click-and-drag a window across the data points towards the lower right.

3. Select OK twice to exit dialogs.

To zoom out, left click-and-drag a window towards the upper-left.

Add Tubing 1. Add a boundary node to the model and insert tubing to connect the completion to the boundary node.


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Completed Model 2. Double-click on the tubing and select Simple Model as the preferred tubing model. Enter the data as shown below. Set the tubing ID in the base case model to 3.83”, this will become a sensitivity variable later.

3. Click on OK to exit dialog.


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Exercise 2 – Develop a Calibrated Black Oil Model No analysis work can be carried out until a black oil fluid model has been developed. This allows all of the fluid physical properties to be estimated over the range of pressures and temperatures encountered by the fluid. These physical properties are subsequently used to determine the phases present, the flow regime, the pressure losses in single and multiphase flow regions, and the heat transferred to or from the surroundings. The following table contains data from a laboratory analysis of our fluid. Fluid Analysis Stock Tank Oil Properties Watercut GOR Gas SG Water SG Oil API

0% 892 scf/stb 0.83 1.02 36.83 °API

Bubble Point Properties Pressure Temperature Solution Gas

2647 psia 210 °F 892 scf/stb

Black Oil Calibration Data OFVF (above bubble point pressure) OFVF (below bubble point pressure) Dead oil viscosities Live oil viscosity Gas viscosity Gas compressibility (Z)

1.49 @ 4,269 psia and 210 °F 1.38 @ 2,000 psia and 210 °F 0.31 cP @ 200 °F and 0.92 cP @ 60 °F 0.29 cP @ 2,000 psia and 210 °F 0.019 cP @ 2,000 psia and 210 °F 0.85 @ 2,000 psia and 210 °F

Note: The bubblepoint calibration for saturation GOR is used to normalize (calibrate) the Solution GOR correlation. By specifying a higher stock tank GOR than a calibration saturation GOR, you are effectively increasing the bubblepoint. (i.e., a plot of flowing solution GOR vs. pressure will intersect this calibration point, but the bubblepoint is no longer that with which the calibration saturation GOR is specified). Conversely, if the stock tank GOR is less than the calibration saturation GOR, then the stock tank GOR is used (takes precedence) with the calibration GOR ignored. 1. From the Setup > Black Oil menu, enter the stock tank oil properties and the bubblepoint properties as shown below:


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Note: You can find help on the definitions and valid ranges of these stock tank properties by clicking the “Help” button at the bottom of this dialog.


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2. Go to the Advanced Calibration Data (Optional) tab. Select the Single Point Calibration option and enter the data as shown below.

3. Select Plot PVT data (Laboratory Conditions…) On the resulting plot, use the Series menu to plot the oil formation volume factor on the yaxis. The following plot should be obtained: Observe that the un-calibrated curve for a temperature of 210 °F shows that the predicted OFVF is higher than the measured value both above and below the bubblepoint pressure: •

At 4,269 psia the predicted value is 1.52 compared to the measured value of 1.49.

•

At 2,000 psia the predicted value is 1.41 compared to the measured value of 1.38.


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Calibrating the OFVF To calibrate the OFVF above the bubblepoint pressure: 1. Select the Advanced Calibration Data (Optional) tab and enter the measured value of 1.49 @ 4,269 psia and 210 °F. 2. Again, select Plot PVT Data (Laboratory Conditions) and the following plot should be obtained:


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3. Apply OFVF calibration below the bubblepoint pressure. The measured value is 1.38 @ 2,000 psia and 210 °F. Replot. The following plot should be obtained:

Calibrating the Oil Viscosity Calibration of the oil viscosity requires two dead oil viscosity measurements. The uncalibrated (default) approach is to use the Beggs and Robinson correlation, which gives values of 1.562 cP @ 200 °F and about 23 cP @ 70 °F. The Beggs and Robinson correlation uses the oil API gravity to predict two dead oil data points based upon data PIPESIM 2006.1 Fundamentals

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obtained from around 2,000 data points from 600 oil systems. Plot the un-calibrated oil viscosity by changing the previous plot Series. The following plot should be obtained:

In this case notice that the predicted oil viscosity value at a temperature of 60 °F and 14.7 psia is about 23 cP, as specified by the Beggs and Robinson correlation. This value is significantly different from the measured dead oil data and would lead to errors in the prediction of pressure loss. Select the Viscosity Data (Optional) tab and select User’s Data from the pull-down menu for the Dead Oil Viscosity Correlation. Enter the two measured values of 0.31 cP @ 200 °F and 0.92 cP @ 60 °F. The following plot should be obtained:


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Notice that the predicted oil viscosity value at a temperature of 60 °F and 14.7 psia is 0.92 cP, consistent with the laboratory dead oil data. Return to the Advanced Calibration Data (Optional) tab and enter the live oil viscosity calibration data of 0.29 cP @ 2,000 psia and 210 °F. The following plot should be obtained:


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Notice that the predicted oil viscosity value at a temperature of 210 °F and 2000 psia is 0.29 cp, consistent with the laboratory live oil data. Proceed to calibrate the gas viscosity and the gas compressibility using the following calibration data: •

Gas viscosity:

0.019 cP @ 2,000 psia and 210 °F

•

Gas compressibility (Z-factor):

0.85 @ 2,000 psia and 210 °F


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Exercise 3 – Select a Tubing Size for the Production String Find the smallest tubing size that will allow this production plan to be met on the basis that the production string will not be replaced during field life. The sizes available are 3.34”, 3.83”, and 4.28”. Production plan obtained from reservoir simulation Year 0 1 2 3 4 5 6 7 8 9 10

Watercut (%) 0 0 0 0 12 20 35 40 47 54 60

Oil Flowrate, sbbl/d 13,000 13,000 13,000 13,000 11,600 9,800 7,800 6,700 5,800 4,500 3,600

1. From the Setup > Flow Correlations menu, select “Hagedorn & Brown” as the vertical multiphase flow correlation. This correlation performs well for vertical oil wells. 2. From the Operations > Systems Analysis menu, choose liquid rate as the calculated variable. The minimum pressure allowed at the wellhead (outlet pressure) is 600 psia. Enter the x-axis and sensitivity data as shown below:

3. Click on Run Model. Select Stock Tank Oil as the y-axis series to give the following plot:


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Notice that 3.83” ID tubing is the smallest size that will permit forecasted production rates.


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Exercise 4 – Gas Lift Feasibility Study Review the feasibility of using gas lift as an alternative to water injection to support oil production rates in later field life. The predicted decline in reservoir pressure, without water injection, is given below:

Predicted reservoir pressure decline (without water injection) Year

Pws (psia)

0 1 2 3 4 5 6 7 8 9 10

4,269 4,190 4,113 4,020 3,950 3,893 3,840 3,800 3,762 3,730 3,700

Use the Artificial Lift Performance operation to identify how much lift gas would be needed in Year 10 to achieve the desired oil production rate of 3,600 STBD with the reduced reservoir pressure of 3,700 psia. 1. From within the completion, change the static reservoir pressure to 3,700 psia. 2. Double-click on the tubing and ensure that the tubing ID is 3.83”. Add a gas lift depth of 8,000 ft. Click the Properties button and enter the gas lift surface temperature of 100 °F and specific gravity of 0.6. 3. From the Operations > Artificial Lift Performance menu, choose the sensitivity variable System Data > Watercut with one value of 60% (representing year 10). The outlet pressure is 600 psia. Enter gas lift rates of: 0.0, 0.5, 1.0, 1.5, 2.0, 2.5, and 3.0 mmscf/d as shown below:


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4. Run the model and select Stock tank Oil at Outlet as the y-axis series. The following plot should be obtained:

Notice that it would be necessary to inject 2.0 mmscf/d of lift gas at a depth of 8,000 ft in order to achieve the target oil production of 3,600 sbbl/d in Year 10.


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Module 3

Well Performance

Oil Well Performance Analysis Learning Objectives In this case study, you learn to analyze well performance as follows: •

Estimate bottomhole flowing conditions

•

Perform Nodal Analysis

•

Calibrate PVT Data

•

Perform Flow Correlation Matching

•

Perform IPR Matching

•

Conduct Water Cut Sensitivity Analysis

•

Evaluate Gas Lift Performance


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Exercise 1 – Estimate bottom-hole flowing conditions Given the following basic data, construct a well model (vertical completion, tubing and boundary node) and find the flowing bottom hole pressure, flowing wellhead temperature and production rate for a given wellhead pressure. Black Oil PVT Data Water Cut GOR Gas SG Water SG Oil API

10 % 500 scf/stb 0.8 1.05 36 ºAPI

Stock Tank Properties Assume default PVT correlations and no calibration data. Wellbore Data (select “detailed” tubing model) Deviation Data Measured Depth (ft) 0 1000 2500 5000 7500 9000

True Vertical Depth (ft) 0 1000 2450 4850 7200 8550

Geothermal Gradient Measured Depth (ft) 0 9000

Ambient Temp. (oF) 50 200

Overall Heat Transfer Coefficient = 5 btu/hr/ft2/F (override default value) Tubing Data Bottom MD (ft) 8600 9000

Internal Diameter (inches) 3.958 6.184

Reservoir and Inflow Data Completion Model = Well PI Select “Use Vogel Below Bubble Point” Reservoir Pressure Reservoir Temperature


3600 psia 200 oF

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Liq. Productivity Index

8 stb/d/psi

From the Setup > Flow Correlations menu, select Beggs-Brill Revised as the vertical multiphase flow correlation. Steps: 1. Construct the model and enter above data. 2. Run Operations > Pressure / Temperature Profile a. Enter Given Outlet Pressure (Calculate Liquid Rate). b. Leave “Sensitivity Variable” empty. 3. Inspect plot and summary output to determine answers. Results:

Wellhead Pressure

300 psia

Production Rate Flowing BHP Flowing WHT


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Exercise 2 – Perform Nodal Analysis Using the model from Exercise 1, add a Nodal Analysis point at the bottomhole. To do this, insert a nodal analysis object near the completion, single left-mouse click on the tubing and drag the bottom tip of the tubing over to the nodal analysis point. Insert a connector to link the completion with the nodal analysis point.

N.A. Point

Perform a Nodal Analysis operation for a given outlet (wellhead) pressure to determine the operating point (bottomhole pressure and flow rate) and the AOFP (absolute open flow potential) of the well. Steps: 1. Insert the Nodal Analysis point between the completion and the tubing 2. Select Operations > Nodal Analysis. a. Enter given Outlet Pressure. b. Leave Inflow Sensitivity and Outflow Sensitivity empty. c. Run the mode. 3. Inspect plot to determine answers. Result: (Outlet) Wellhead Pressure

300 psia

Operating Point Flow rate Operating Point BHP AOFP


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Exercise 3 – Calibrate PVT Data Measured PVT data is available to calibrate and improve the fluid model. From Setup > Black Oil, select the Advanced Calibration Data tab, and click the Single Point Calibration button. Use the measured data to calibrate the PVT model and re-run Exercise 1. Determine the flowing bottomhole pressure, flowing wellhead temperature and production rate for a given wellhead pressure. PVT Calibration Data Range

Property

P > Pb

OFVF

P = Pb

Sat. Gas

P < Pb

OFVF

Value

Pressure (psia)

Temp (°F)

1.16

3000

200

500 scf/stb

2100

200

1.22

2100

200

Oil Viscosity

1.1 cp

2100

200

Gas viscosity

0.029 cp

2100

200

0.8

2100

200

Gas Z factor

Dead Oil Viscosity Measurements Property Viscosity

Value

Temperature (F)

1.5 cp 10 cp

200 60

PVT Correlations Property Solution gas OFVF at / below bubblepoint Live oil viscosity Under-saturated oil viscosity Gas Z

Correlation Lasater Standing Chew and Connally Vasquez and Beggs Standing

Steps: 1. Enter the calibration data above into the Black Oil fluid model. 2. Run Operations > Pressure / Temperature Profile. Enter Given Outlet Pressure (Calculate Liquid Rate). 3. Inspect plot and summary output to determine answers. Result: Wellhead Pressure

300 psia

Production Rate Flowing BHP Flowing WHT


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Exercise 4 – Perform Flow Correlation Matching An FGS survey (Flowing Gradient Survey) is available for the well. Use the measured data to select the most appropriate vertical flow correlation. Using the selected flow correlation, determine the flowing bottomhole pressure. Well test and FGS Data Welltest Data – Jan 06, 2004 Property

Value

Wellhead pressure

300 psia

Wellhead temperature

130 °F

Liquid Production Rate

6,500 stb/d

GOR

500 scf/stb

Water cut

10 %

Flowing Pressure Survey Depth MD (ft) 0 1500 2500 4500 6500 7500 8500

Pressure (psia) 300 560 690 1200 1760 2070 2360

Steps: 1. Select the Data > Load/ Add Measured Data menu. Select New, enter the flowing pressure survey data and save. 2. Go to Operations > Flow Correlation Matching. Specify the given Outlet Pressure (Wellhead) and Liquid Rate, and select the Inlet Pressure as the calculated variable. 3. Select several vertical flow Correlations (e.g., Beggs and Brill Revised, Duns and Ros, Hagedorn and Brown) and run the model. 4. Inspect the resulting plot to determine which flow correlation most closely agrees with the measured data. 5. Select Setup > Flow Correlations and ensure that the best matching flow correlation is selected for future calculations. Result: Wellhead Pressure Vertical Correlation Flowing BHP


300 psia

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Exercise 5 – Perform IPR Matching Having selected the correct flow correlation chosen in Exercise 4, find the PI (Productivity Index) that matches the test data from Exercise 4, given the reservoir pressure is known to be 3600 psia. What is the AOFP of the well with the new PI? The Productivity Index is expected to be in the range from 5 to 10 stb/d/psi. There are 2 ways to go about determining the matching PI: Steps (Method A): 1. Go to Operations > System Analysis. 2. Enter Outlet Pressure (calculate Liquid Rate). a. For “X-axis variable”, select the Vertical Completion as the Object and Liq. PI as the Variable with values of 5, 6, 7,8, 9 and 10. b. Leave “Sensitivity Variable 1” empty. 3. Run model to generate a plot of calculated liquid rate vs. PI. 4. Inspect the plot to identify the PI, which gives match to the measured production rate. Steps (Method B): 1. Go to Operations > Nodal Analysis. 2. Enter Outlet Pressure. a. For “Inflow Sensitivity”, select the Vertical Completion as the Object and Liq. PI as the Variable with values of 5, 6, 7 and 8. b. Leave Outflow Sensitivity empty. 3. Generate the Nodal Analysis plot. 4. Identify the PI, which gives the correct solution point. 5. Determine AOFP from the Inflow (Nodal Analysis) plot. Results: Wellhead Pressure

300 psia

PI AOFP

Update the PI for the completion with the matched value.


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Exercise 6 – Conduct Water Cut Sensitivity Analysis Given the current wellhead pressure and reservoir pressure, determine the highest possible water cut for which the well will produce. Note: Make sure you have changed the completion PI in the well model after Exercise 5. Again, there are 2 ways to solve this problem: Steps (Method A): 1. Go to Operations > System Analysis. 2. Enter Outlet Pressure (calculate Liquid Rate). a. For “X-axis variable”, select Fluid Data and enter water cut values of 30%, 40%, 50%, 60%, 70%. b. Leave “Sensitivity Variable 1” empty. 3. Generate a plot of calculated liquid rate vs. water cut. 4. Interpolate to Identify the water cut at which the calculated production rate drops to zero. Steps (Method B): 1. Go to Operations > Nodal Analysis. 2. Enter Outlet Pressure. a. Leave “Inflow Sensitivity” empty. b. For “Outflow Sensitivity”, enter water cut values of 30%, 40%, 50%, 60%, 70%. 3. Generate the Nodal Analysis plot. 4. Identify the lowest water cut for which there is no solution point. Result: Wellhead Pressure Water Cut


300 psia

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Exercise 7 – Evaluate Gas Lift Performance In this exercise we will examine how this well responds to Gas Lift by introducing a Gas Lift Injection point at 8000 ft MD in the tubing equipment. Tasks: 1. Determine how the well responds to gas lift when the water cut is at 10 % and at 60 %. 2. Determine the liquid production rates as a function of gas lift rate and water cut. Assume: wellhead pressure = 300 psia. Injection gas SG = 0.6 Injection gas surface temperature = 100 oF. Steps: 1. Add a Gas Lift Injection point to the tubing description. On the Downhole Equipment tab, select the Properties button and enter a default gas lift rate of 1mmscf/d. 2. Go to Operations > System Analysis. 3. Enter Outlet Pressure (calculate Liquid Rate). a. For “X-axis variable”, enter gas lift rates of 0, 0.2, 0.5, 1, 1.5, 2 (mmscf/d). b. For “Sensitivity Variable 1,” enter water cut values of 10% and 60%. 4. Generate a plot of calculated liquid rate vs. gas lift rate for different water cuts. 5. Inspect plot and summary output to determine answers. Result: Gas Lift Rate (mmscf/d) 0.5 1.0 1.5 2.0


Liq. Prod. Rate (stb/d)


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Enhancing Oil Well Production Using Nodal Analysis An oil well is currently producing below capacity. Options for increasing production include stimulation (acidizing and/or hydraulic fracture) and gas lift.

Learning Objectives An oil well is currently producing below capacity. In this case study, you will learn how to use Nodal Analysis to evaluate well performance and to determine the relative benefits of stimulation (acidizing and/or hydraulic fracture) and gas lift using the following procedures: •

Well Model / Nodal Analysis

•

Nodal Analysis / Sensitivity to Stimulation and Gas Lift

•

Nodal Analysis / Sensitivity to Flow Correlation


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Exercise 1 – Well Model / Nodal Analysis Given the following basic data, construct a well model and perform a Nodal Analysis operation to find the flowing bottomhole pressure and production rate for a wellhead pressure of 250 psia. Use Beggs and Brill Revised multiphase flow correction for both vertical and horizontal flow.

Black Oil PVT Data

Value

Water cut

40 %

GOR

500 scf/stb

Gas SG

0.71

Water SG

1.1

API

26 °API

Bubble Point Calibration Data Pressure

2000 psia

Temperature

170 °F

Saturated Gas

500 scf/stb


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Assume default PVT correlations and no calibration data. Wellbore Data Surface Temperature Kick-off M Perf MD Perf TVD

Simple Model 60 F 2000 ft 7500 ft 7000 ft

Reservoir Temp. Tubing ID

170 oF 2.992 in

Completion Data Pressure Temperature Permeability Thickness Wellbore diameter Drainage radius Skin (mechanical)

o

Open-Hole 3700 psia 170 oF 50 mD 30 ft 6 in 2000 ft 3

Use calculated rate dependent skin

Steps: 1. Construct Model and enter above data. Place Nodal Analysis icon at bottomhole. 2. Select a Pseudo Steady State completion model. Plot the IPR curves. 3. Run Operations > Nodal Analysis. a. Enter Given Outlet Pressure. b. Leave “Inflow Sensitivity” and “Outflow Sensitivity” empty. 4. Inspect plot to determine answers Result: Wellhead Pressure Production Rate Flowing BHP


250 psia

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Exercise 2 – Nodal Analysis – Sensitivity to Stimulation and Gas Lift Investigate the increase in production through stimulation and gas lift using nodal analysis. 1. Assume that the current skin of 3 can be reduced to 0 if the well is acidized and –2 if hydraulically fractured. 2. Insert a gas lift injection point at 4500’ (with lift gas gravity of 0.6 and a surface gas temperature of 90F). What increase in production can be achieved by each approach assuming an outlet Pressure = 250 psia? Steps: 1. Add a Gas Lift Injection point at 4500’. (Assume default gas lift rate = 0). 2. Run Operations > Nodal Analysis a. Enter the Given Outlet Pressure. b. For “Inflow Sensitivity”, enter skin values of 3, 0, and -2. c. For “Outflow Sensitivity”, enter gas lift rate values of 0, 0.5, 1.0 and 2.0 mmscf/d. 3. Generate a Nodal Analysis plot. 4. Inspect the plot to determine answers. The Intersection points are also provided in the formatted Nodal Analysis Report. Open Reports > User Report (Nodal Analysis). Oil Production Rates (stb/d) – Beggs-Brill Revised Gas Lift Rates (mmscf/d) Completion

0.0

0.5

1.0

2.0

base (skin = 3) acidized (skin = 0) fractured (skin = -2)


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Exercise 3 – Nodal Analysis – Sensitivity to Flow Correlation While the Beggs and Brill correlation is widely used and is the default correlation for PIPESIM, it is useful to see the results when using alternative correlations. The Mukherjee and Brill better accounts for viscosity effects, which for this case may be significant because the oil is relatively heavy (26 º API). Repeat the nodal analysis using Mukherjee and Brill vertical flow correlation again using an Outlet Pressure of 250 psia. Steps: 1. Change the vertical flow correlation to Mukherjee and Brill. 2. Run Operations > Nodal Analysis. a. Enter the Given Outlet Pressure. b. For “Inflow Sensitivity”, enter skin values of 3, 0, and -2. c. For “Outflow Sensitivity”, enter gas lift rate values of 0, 0.5, 1.0 and 2.0 mmscf/d. 3. Generate a Nodal Analysis plot. 4. Inspect the plot to determine answers. The Intersection points are also provided in the formatted Nodal Analysis Report. Open Reports > User Report (Nodal Analysis). Result: Oil Production Rates (stb/d)– Mukherjee and Brill: Gas Lift Rates (mmscf/d) Completion

0.0

0.5

1.0

2.0

base (skin = 3) acidized (skin = 0) fractured (skin = -2)

Observe that the discrepancy between Beggs and Brill and Mukherjee and Brill, ranges from 1-15%. However, both cases agree fairly well in terms of relative added benefit shown by sensitivity cases. Notice that in changing the flow correlation, the inflow curves remain unchanged. This is because Nodal Analysis “decouples” the system, creating two independent parts. Ultimately, project economics and future production potential based on reservoir conditions will weigh heavily in the final decision.


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Gas Well Performance using a Compositional Fluid Model Learning Objectives A gas well has been drilled. DST data is available as well as Fluid Gradient Survey (FGS) data from a well completed in the same zone. In this case study, the following procedures will be used to evaluate the gas well performance: •

Build a Simple Well Model

•

Calibrate the Inflow Model

•

Perform Nodal Analysis at Bottomhole

•

Perform System Analysis

•

Model Flowline and Choke Performance

•

Evaluate Higher Liquid Loading / Flow Correlation Matching

•

Calculate Liquid Hold-up Fraction and Flow Regime Mapping

•

Pressure/Temperature Path from Reservoir

•

Pressure Drop due to increased Condensate Production

•

Rigorous Flashing


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Exercise 1 – Build a Simple Well Model 1. Construct the physical well model using the data below:

Reservoir Data Static Pres 4,600 psia Reservoir Temp. 280oF Gas PI 2 x 10-6 mmscf/d/psi2 Mid perf TVD Mid perf MD Ambient temp EOT MD Tubing ID Casing ID

Tubing Data 11,000 ft 11,000 ft 30 oF 10,950 ft 3.476 in 8.681 in

2. Define a compositional fluid model by selecting Setup > Compositional and entering the composition given in the table below. Select the Options tab and ensure that Multiflash is selected. To add library components, select the desired components from the list and click on Add >>. To add the C7+ pseudo-component, select the Petroleum Fractions tab, enter the pseudo-component name and data, highlight the row number for the pseudo-component, and select Add to Composition. a. Determine the water content at saturation at reservoir conditions. To determine the water content at saturation, add an arbitrary amount of water (i.e., 20 moles) to the composition. Select the Flash/Separation tab, click the PT button, enter the given reservoir pressure and temperature, perform a flash and read the water content for the vapor fraction from the screen. The PIPESIM 2006.1 Fundamentals

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hydrocarbon vapor components will be normalized to include the mole fraction of water. Enter the water and renormalized hydrocarbon composition back into the compositional editor’s main screen. b. Generate a phase envelope using the water-saturated composition. To generate a phase envelope, click on the Phase Envelope button in the main compositional editor screen (where the composition was entered). Do this for the composition with the aqueous fraction.

C1 C2 C3 iC4 nC4 iC5 nC5 C6 C7+

Composition (%) 78 8 3.5 1.2 1.5 0.8 0.5 0.5 6

C7+ C7+ C7+

Stock tank Properties 214 oF 115 0.683

BP MW SG

3. Determine the flow-rate, bottomhole flowing pressure, bottomhole flowing temperature and well-head temperature, given a well-head pressure of 800 psia. 4. Build a simple completion using the completion icon, tubing icon and an outlet node. Enter the given gas PI and reservoir pressure and temperature in the completion object, and the given tubing information in the tubing object. Select Duns and Ros as the vertical flow correlation. 5. Run a Pressure/Temperature Profile Operation using an outlet pressure of 800 psia. The flow-rate, pressures and temperatures can be found in the Summary File, accessible from the Reports menu. Results: Pres = 4,600 psia, Tres = 280oF % H2O @ saturation Po = 800 psia QG Pwf BHT


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Po = 800 psia WHT


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Exercise 2 – Calibrate the Inflow Model In this exercise, you will use the Backpressure equation for inflow performance relationship for a gas well producing at pseudo-steady state. The backpressure equation is as follows: Qsc = C(pR2 – pWF2)n where, Qsc = gas rate (mmscf/d) pR = average reservoir pressure (psia) pWF = flowing bottomhole pressure C

= flow coefficient

n = non-darcy exponent Tasks: 1. Using the below DST data, calculate the C and n parameters. 2. Determine the flow-rate, bottomhole flowing pressure, bottomhole flowing temperature and wellhead temperature using the new inflow model. Steps: 1. Double-click on the completion icon then select the Back Pressure Equation from the drop-down menu. Click on Calculate/Graph; then enter the test data in the dialogue box. 2. Re-run the Pressure/Temperature Profile operation. Inspect the resulting plot and summary file to determine the results. DST Data for Back Pressure Equation QGas (mmscf/d) 9.728 11.928 14.336

Pwf (psia) 3000 2500 1800

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


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Exercise 3 – Perform Nodal Analysis at Bottom-Hole Nodal analysis can be used to determine the optimum tubing size. The available tubing sizes have IDs of 2.992”, 3.958”, 4.892” and 6.184”. Tasks: 1. Perform nodal analysis using the available tubing sizes. 2. Plot the elevation vs. Erosional Velocity Ratio from the profile plot for all tubing sizes. 3. Determine the flow rate, bottomhole flowing pressure, bottomhole flowing temperature and wellhead temperature for 3.958” ID tubing at an outlet pressure of 800 psia. Determine the EVR for this tubing at the wellhead. Continue using this tubing size in all subsequent exercises. Steps: 1. Ensure that the model includes a Nodal Analysis object located between the tubing and the completion. Use the Nodal Analysis option from the Operations drop-down menu. Enter the tubing IDs as the Outflow sensitivity. 2. Run a Pressure/Temperature profile using the tubing size as the sensitivity (remember to activate the sensitivity). 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 to determine the maximum erosional velocity ratio. 3. Look in the Summary File for the flow-rate, bottomhole flowing pressure, bottomhole flowing temperature and wellhead temperature for the 3.958” tubing. Results: Po = 800 psia QG Pwf BHT WHT Well-head, 3.958” tubing Max. Erosional velocity ratio


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Exercise 4 – Perform System Analysis The System Analysis Operation can be used to investigate the gas rate as a function of reservoir pressure for the different tubing sizes. Steps: 1. Select System Analysis from the Operations drop-down menu. Use a wellhead pressure of 800 psia. Use the Reservoir (Static) Pressure as the x-axis variable with values of 4600, 4200, 3800 and 3400 psia. Select tubing ID as the sensitivity variable with values of 2.992”, 3.958”, 4.892” and 6.184”. 2. Run the model and view the resultant plot.


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Exercise 5 – Model Flow-line and Choke Performance Add a horizontal flow-line and a choke to the model using the below data.

Note: Enter any will be overridden variable.

Flow-line Details Flow-line length 300 ft Flow-line ID 6 in Pipe Roughness 0.001 in Wall thickness 0.5 in Ambient Temp 60 °F

choke size as it by the sensitivity

Task: Using the mechanistic choke model, determine the choke bean size that results in a manifold pressure of 710 psia (manifold is at end of flow-line) using the gas rate as calculated in Exercise 3, Task 3. Use a tubing ID is 3.958”. Steps: 1. The System Analysis operation can be used for this task. Select choke size (a good estimate would be from 1” to 3” in increments of ½”) as the x-axis variable and outlet pressure as the calculated variable. 2. Inspect the plot to determine the choke size that gives the correct outlet pressure (710 psia). Use the wellhead pressure of 800 psia. Results: Po = 710 psia Choke size

Continue using that choke size in model (double-click on the choke and enter that choke size).


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Exercise 6 – Evaluate Higher Liquid Loading / Flow Correlation Matching In the future it is expected that there will be a higher liquid loading due to increased condensate production as the reservoir pressure declines to 4300 psia. Tasks: 1. Save the model with a new name. Enter the heavier composition given in the table below. Determine the water content at saturation at the lower reservoir pressure by performing a single point flash calculation within the Compositional dialog as done previously. 2. Using the FGS data determine the best vertical multi-phase flow correlation for use in this well. Choose from Ansari, Beggs and Brill Revised, Duns and Ros, and Hagedorn and Brown. Find the mean arithmetic and absolute differences for the chosen correlation. Continue using that correlation. Use an outlet pressure of 800 psia for this operation (deactivate choke and flowline) 3. Using the heavier composition and chosen vertical multi-phase flow correlation, determine the new gas flow-rate, bottom hole flowing pressure and actual liquid flow at the perforations and outlet for a manifold pressure of 710 psia. Steps: 1. Determine the water content at saturation for the new composition as per the same method in Exercise 1 using the compositional editor. 2. De-activate choke and flow-line for this operation (hence the outlet pressure of 800 psia will be the well-head pressure). From the Data menu, select Load/Add Measured Data to add the FGS data. From the Operations menu, select “Flow Correlation Matching”. Check the correlations to be used, and then click on the Run Model button. Look in the Output File for the mean arithmetic and absolute differences. 3. Reactivate the choke and flowline and ensure the choke bean size has been updated with the size determined in the previous exercise. Run a Pressure/Temperature Profile Operation using an inlet pressure of 4300 psia, then look in Output File for actual liquid flows 4. Inspect the bottom of the output file to determine the mean arithmetic and absolute differences. Compositional PVT Data (higher condensate fraction) C1 C2 C3 iC4 nC4 iC5 nC5 C6 C7+

Composition (%) 75 6 3 1 1 1 0.5 0.5 12

FGS Data PIPESIM 2006.1 Fundamentals

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Depth (ft) 3000 6000 9000 11000

Pressure (psia) 950 1095 1250 1365

Producing gas rate during FGS = 13.4 mmscf/d Wellhead Pressure during FGS = 800 psia Results: Pres = 4,300 psia, Tres = 280oF % H2O @ saturation Po = 800 psia Best Correlation Mean arithmetic difference (%) Mean absolute difference (%) Po = 710 psia QG Pwf QL @ mid-perfs (act) QL @ outlet (act)


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Exercise 7 – Calculate Liquid Hold-up Fraction and Flow Regime Map Tasks: 1. Determine the following at the bottom of the well, at the top of the well, and at the end of the flow-line: a. xVL : the liquid volume fraction (no-slip liquid holdup) b. xHL : the liquid holdup fraction 2. Generate a flow regime map for the end of the flow-line. Look at the flow-map and determine the flow regime at the end of the flow-line. Steps: 1. Add the report icon at the end of the flow-line. Double-click on the report icon and select the Flow Map. 2. Re-run the Pressure / Temperature Profile Operation. 3. The flow regime at the end of the flow-line can be determined from both the Summary File and Output file. The flow map can be viewed at the bottom of the Output File. Results: Liquid Volume Fraction, Po = 710 psia xVL @ bottomhole xVL @ WH xVL @ end flow-line Flow regime end FL Liquid Hold-up Fraction, Po = 710 psia xHL @ bottomhole xHL @ WH xHL @ end flow-line


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Exercise 8 – Pressure/Temperature Path from Reservoir Tasks: 1. Plot the PT path from the reservoir to the end of the flow-line on the phase diagram. 2. Will hydrate formation be a problem? Steps: 1. Ensure that Phase Envelope is checked in the report tool object. 2. Run the Pressure/Temperature Profile and configure the resulting plot to display Pressure on the y-axis and Temperature on the x-axis. 3. From the generated plot, if the operating line crosses the hydrate formation line, hydrate formation may occur. Results: Ambient Temp = 30oF Hydrate formation?


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Exercise 9 – Pressure Drop due to Increased Condensate Production The increased liquid loading is expected to cause a higher pressure drop through the production system. Task: Calculate the wellbore pressure drop across the formation, tubing, choke and flow-line for a gas flow-rate of 13 mmscf/d. Step: Run a Pressure/Temperature Profile operation using a gas rate of 13 mmscf/d and outlet pressure as the calculated variable. Results: Heavier composition ΔP Reservoir ΔP Tubing ΔP Choke ΔP Flow-line


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Challenge Exercise 10 – Rigorous Flashing To reduce solution time, the calculation engine does not perform a flash at every pipe segment to determine the average fluid properties across the given segment. Instead, it interpolates the properties at each segment based on the results of an initial series of flashes performed prior to iterating. By selecting the Rigorous Flash option from the Setup > Flashing menu, the fluid will be flashed and the properties averaged at every pipe segment. This method is more accurate, and can occasionally cause significantly different results, particularly when operating near a phase boundary. The trade-off with using the more accurate Rigorous Flash option is the increased solution time. Task: Repeat Exercises 6 (Task 3) and 8 (tasks 1 and 2) using the rigorous flash option. Compare the results and comment on the differences.

Po = 710 psia QG Pwf QL @ mid-perfs (act) QL @ outlet (act) Ambient Temp = 30oF Hydrate formation?

Note that the results are similar to when the interpolation option is used, except the rigorous flash predicts more of the retrograde condensation to occur prior to the fluid reaching the sand-face, as determined from the actual liquid flow-rate at the mid-perfs (compare to the results from Exercise 6). The calculated rate is a little less using the interpolation option, and the other results are quite similar. The difference described above illustrates a situation where the rigorous flash option is appropriate, especially when operating near the phase envelope.

Module 4

Artificial Lift Design

ESP Design Learning Objectives This case study will demonstrate the following workflow: 1. Analyze a well’s requirement for artificial lift. 2. Select an appropriate ESP pump. 3. Calculate the number of stages required for design conditions. 4. Evaluate the variable speed performance of the pump. PIPESIM 2006.1 Fundamentals

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5. Evaluate the pump performance with varying well conditions.


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Exercise 1 – Well Model / Nodal Analysis Given the following basic data, construct a well model and perform a Nodal Analysis at bottomhole. Assume no pump in the well at this stage.

Fluid Data Property (Stock Tank)

Value

Water cut

90 %

GOR

449 scf/stb

Gas Gravity

0.984

Water Specific Gravity

1.026

Oil API

30

PVT Calibration Data Range

Property

Value

Pressure (psia)

Temperature (°F)

P = Pb

Sat. Gas

449 scf/stb

2216

288

P = Pb

OFVF

1.33

2216

288

P = Pb

Live Oil Viscosity

0.54 cp

2216

288

Wellbore Data Vertical Well Perforation depth: Flow is in : 41/2 “ (3.958” ID) tubing from surface to 8200 ft. 95/8 “ (8.681” ID) casing from 8200 ft to 9393 ft.

9393

* (note the pump setting depth in the next exercise will be at 8300 ft.) PIPESIM 2006.1 Fundamentals

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Vertical Well Surface Ambient Temperature = 68 oF

Reservoir and Inflow Data Vertical Completion Pressure

3625 psia

Temperature

288 °F

Productivity Index

12.4 stb/d/psi

Task: Using the Hagedorn and Brown vertical flow correlation, confirm that the well will not flow naturally. Steps: 1. Construct Well Model and enter above data. Place the Nodal Analysis icon at bottomhole. 2. Run Operations > Nodal Analysis. a. Enter an Outlet Pressure of 1 atmosphere as a worst case scenario. b. Leave “Max Rate” empty (PIPESIM will calculate rates up to the AOFP). c. Leave “Inflow Sensitivity” and “Outflow Sensitivity” empty. 3. Inspect the plot.


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Exercise 2 – Pump Selection / Design Task: Given the design conditions below, determine the following: 1. The number of stages required using a Reda HN13000 pump. 2. The motor HP required. 3. Generate a Pump Performance Plot showing the potential operating (flow rate) range for variable frequency between 50 to 70 Hz. 4. From the Pump Performance Plot, determine at what flow rate the pump suction pressure falls below the bubblepoint. ESP Design Conditions: Design Production Rate

10,060 stb/d

Design Wellhead (Outlet) Pressure

130 psia

Pump setting depth

8300 ft (within 9 5/8” (8.681” ID) casing))

Design Frequency

60 Hz

(assume no gas separator present, no viscosity correction and a head factor of 1).

Steps: 1. From the Artificial Lift menu select ESP > ESP Design. 2. Enter the Pump Design Data given above. 3. Click the Select Pump button. (This will filter the pump database for all the pumps that meet the design criteria). 4. Set Manufacturer to Reda. 5. Highlight and select the Reda HN13000 pump. Click OK. 6. Click on the Calculate button in the Pump Parameters section. (This will calculate the pump parameters). 7. Read the No. of Stages required. 8. Read the motor pump HP (i.e., Pump Power) required. 9. Click on the Pump Performance Plot button at the bottom of the Pump Parameters section. 10. Read off the flow rate at the intersection of the Well System Curve and the 50Hz and 70 Hz pump curves. 11. Read off the intersection of the pump suction pressure curve and the bubblepoint curve.


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A = Pump operating point (flow rate and pump discharge pressure) at 50 Hz. B = Pump operating point (flow rate and pump discharge pressure) at 70 Hz. C = Pump suction pressure falls below bubblepoint. Result: No. of stages (HN13000) Motor HP required Flow rate range for 50 – 70 Hz. Flow rate for Psuction <= Pbubblepoint


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Exercise 3 – Pump Performance with Varying Well Conditions Install the selected pump in your well model by clicking on the Install Pump button at the bottom of the Pump Parameters section. Task: Determine the flow rate of the well when the water cut increases to 95% (assuming the same number of stages and design speed). Steps: 1. Install the pump in your well model by clicking on the Install Pump button at the bottom of the section. 2. Go to Operations > System Analysis. 3. Enter Outlet Pressure (i.e., select calculated variable = Liquid Rate). a. For “X-axis variable”, enter water cut values of 90 and 95%. b. Leave “Sensitivity Variable 1” empty. 4. Generate a plot of calculated Stock Tank Liquid Rate vs. Water Cut. 5. Read off the oil production rate for water cut 95%. Result: Production Rate (95% water cut)


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Gas Lift Design – New Mandrel Spacing Learning Objectives This case study will demonstrate the following workflow: •

Perform Well Model / Nodal Analysis to analyze a well’s requirement for artificial lift

•

Evaluate the Gas Lift Response

•

Perform a Gas Lift Design (using the “IPO Surface Close” method)


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Exercise 1 – Well Model / Nodal Analysis Given the following basic data, construct a well model and perform a Nodal Analysis at bottomhole. Assume no gas lift valves in the well at this stage.

Confirm that the well will not flow naturally assuming a wellhead pressure of 110 psig. Black Oil PVT Data Water Cut

55 %

GOR

300 scf/stb

Oil Gravity

32 oAPI

Gas Gravity

0.64

Water SG

1.05

Flow Correlation Select the Hagedorn and Brown vertical flow correlation. Wellbore Data MD (ft) 0 7550 mid-perf depth = 7550 ft


TVD (ft) 0 7550

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Geothermal Survey MD (ft) 0 7550

Ambient Temp (F) 50 175

U Value (Btu/hr/ft2/F) 2 2

Tubing/Casing Dimensions 2 7/8 “ (2.441” ID) tubing from surface to 7500 ft 7 “ (6.184” ID) casing from 7500 ft to 7550ft

Reservoir and Inflow Data Reservoir Pressure

2800 psig

Reservoir Temperature

175 oF

Productivity Index

2.5 stb/d/psi

Use Vogel below the bubblepoint.

Steps: 1. Construct a Well Model and enter the above data. Place the Nodal Analysis icon at bottomhole. 2. Run Operations > Nodal Analysis. a. Enter the Given Outlet Pressure (110 psig). b. Leave “Max Rate” empty (PIPESIM will calculate rates up to the AOFP). c. Leave “Inflow Sensitivity” and “Outflow Sensitivity” empty. 3. Inspect the plot.


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Exercise 2 – Evaluate the Lift Gas Response Using the Lift Gas Response operation, determine the gas lift rate that will be used for the design. Steps: 1. Select the Lift Gas Response operation from the Artificial lift > Gas Lift submenu. 2. Enter gas lift rate sensitivity values of 0 to 5 mmscf/d in increments of: a. 0.1 mmscf/d up to 1.0 mmscf/d b. 0.5 mmscf/d up to 5.0 mmscf/d 3. Enter sensitivity values of 150 and 250 psi for the Minimum injection gas ΔP. 4. Use an injection gas surface pressure of 1000 psig and assume an injection gas surface temperature of 80 ºF. 5. Ensure that the gas injection depth is set as Optimum Depth of Injection.

Note that the deepest injection point at the optimum rate is about 4840 ft. This will be discussed in a later exercise.


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Exercise 3 – Perform Gas Lift Design (using the “IPO Surface Close” method) Given the design conditions below, determine the following: 1. Determine the required Mandrel spacing to unload the well. 2. The test rack pressure of each of the unloading valves. Design Conditions Design Control Parameters Design Spacing: Design Method: Top Valve Location: Manufacturer: Type: Size: Series: Min Port Diameter: Unloading Temperature: Production Pressure Curve:

New Spacing IPO-Surface Close Assume Liquid to Surface SLB (Camco) IPO 1’’ (Tubing size 2 7/8 < 3 ½) BK-1 None Default (Unloading) Production Pressure Model

Design Parameters Kickoff Pressure: Operating Injection Pressure: Unloading Prod. Pressure: Operating Prod. Pressure Target Injection Gas Flow rate: Injection gas Surface Temp: Inj Gas Specific Gravity: Unloading Gradient: Minimum Valve Spacing: Minimum Valve Inj DP: Bracketing Options:

1000 psig 1000 psig 110 psig 110 psig 1.25 mmscf/d 80 °F 0.64 0.465 psi/ft Calculated 150 psi Not selected

Safety Factors Surface Close Pressure Drop Between Valves: Locating DP at Valve Location: Transfer Factor: Place Orifice at operating valve location: Discharge Coefficient for Orifice:


15 psi 50 psi 0 Yes 0.865

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Steps: 1. Go to Artificial Lift > Gas Lift > Gas Lift Design in the top menu. 2. Enter the Gas Lift Design Data given above. 3. Click on Perform Design. 4. Select Graph to plot the gas lift design response.


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Gas Lift Design – Current Mandrel Spacing Learning Objectives In this case study you will learn how to design a gas lift system with a current mandrel spacing using the following workflow: •

Install a Gas Lift Valve system in the tubing

•

Perform a Deepest Injection Point operation to find the maximum depth that could be achieved. (Using Pinj = 1000 psig and Lift gas rate = 1.25 mmscf/d)

•

Perform a Gas Lift response operation to produce a graph of oil rate vs. lift gas rate

•

Design the gas lift system using the current mandrel spacing


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Exercise 1 – Install a Gas Lift Valve System, Deepest Injection Point Operation Using the model created during the previous case study, insert the following Gas lift valve system into the tubing: Equipment Gas Lift Valve Gas Lift Valve Gas Lift Valve Gas Lift Valve Gas Lift Valve Gas Lift Valve

MD 1500 2700 3600 4200 4700 5100

Properties IPO-1/8 IPO-1/4 IPO-5/1 IPO-5/16 IPO-5/16 IPO-5/16

Label BK-1 BK-1 BK-1 BK-1 BK-1 BK-1

Steps: 1. In the Downhole Equipment tab (located in the detailed tubing dialog), select the G/L Valve System button and check the “Edit Valve Details” (only used for Gas Lift Diagnostics) box. Specify the spacing shown above in the tubing user form. 2. Select the first row in the user form, click on the Add…[Valve Lookup] button. The Gas Lift Valve Selection user form displays. 3. Select SLB (Camco) as the manufacturer, IPO as the type, 1” as the size and BK-1 as the series. Select Refresh. 4. Click on Add valve to add the required valve. 5. Add the depth of the first valve in the gas lift valve system user form. 6. Repeat the above steps for all the valves. 7. From the Artificial Lift > Gas Lift menu, perform a Deepest Injection Point operation as shown below. Use a lift gas rate of 1.25 mmscf/d and an injection pressure or 1000psig. Then click on the Calculate button.


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The maximum depth of injection is 4770 ft; therefore, you should be able to inject at the mandrel located at 4700 ft. The corresponding oil rate should be 1882 STBD. This shows that a gas lift valve cannot be set below the DIP.


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Exercise 2 – Generate the Gas Lift Response Curves Perform a Gas Lift Response operation to produce a graph of oil rate vs. lift gas rate (Use Minimum gas injection Delta P of 150 psi and 250 psi as the sensitivity and lift gas rates ranging from 0 to 5 mmscf/d in increments of 0.5 mmscf/d. Ensure that the Injection at valve depth only option is selected and run the operation.


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Exercise 3 – Design the Gas Lift Valve System using the Current Mandrel Spacing Given the design conditions (Identical to the previous case study) and the current mandrel spacing, perform the gas lift design. Select current spacing in the design control tab prior to performing the design. Use 1.25 mmscf/d as the lift gas rate.


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It is important to note that we are not injecting at the mandrel located at 4700 ft, but at the mandrel located at 4200 ft. The rate is not 1871 stb/d, but 1708 stb/d. This is due to the fact that the Deepest Injection Point operation does not take into account the 15-psi pressure drop in casing pressure for each unloading valve. It is also important to notice that when designing for a current mandrel spacing, the depth between valves is fixed. It is the transfer pressure that is calculated at each valve. When the transfer pressures lie to the left of the production pressure curve or the equilibrium curve, it may not be possible to transfer to the next valve.


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Exercise 4 – Gas Lift Diagnostics Assuming that the system has been in operation for a while, and that the producing conditions have changed. The separator pressure is now 200 psia and the measured gas lift injection rate is 1.5 mmscf/d. Perform a gas lift diagnosis to ensure that the valves are operating under these conditions. Steps: 1. Go to Artificial Lift > Gas Lift > Gas Lift Diagnosis. 2. Enter the current producing conditions and run the diagnostics. 3. Open the Data Sheet to determine which valves are open, closed or throttling, and the gas rates observed across each valve.


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Single Branch Pipeline and Facilities

Module 5

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Subsea Tieback Design Learning Objectives In this case study, a client plans on producing five condensate wells into a subsea manifold, through a subsea tieback and up a riser to a platform. The oil and gas are then to be separated, with the oil pumped to shore and the gas compressed to shore. 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. You will perform the following procedures to design a subsea tieback: •

Develop a compositional model of the hydrocarbon phases

•

Size the subsea tieback line and riser

•

Screen the results for severe slugging at the riser base

•

Determine the pipeline insulation requirements

•

Size a slug catcher


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Exercise 1 – Develop a Compositional PVT Model Develop a Compositional PVT Model based on the following data: Pure Hydrocarbon Components Component Methane Ethane Propane Isobutane Butane Isopentane Pentane Hexane

Moles 75 6 3 1 1 1 0.5 0.5

Petroleum Fractions Name C7+

Boiling Point (°F) 214

Molecular Weight 115

Specific Gravity 0.683

Moles 12

Aqueous Component Component Water

Volume ratio(%bbl/bbl) 10

Steps: 1. Open the Setup > Compositional menu to enter the pure components given above. Select the pure hydrocarbon components from the component database. Multiple selection is possible by holding down the control key. When all pure hydrocarbon components have been selected, press the Add>> button. 2. Select the Petroleum Fractions tab and characterize the petroleum fraction C7+ by entering the petroleum fraction name, the BP, MW, and SG in row 1. Highlight the row by pressing on the row 1 button and then click on the Add to composition>> button. 3. Return to the Component Selection tab and enter the number of moles for C7+. 4. Select the Options tab and select Multi-flash. Select the SRK equation of state and the Pedersen viscosity model. 5. Generate the hydrocarbon phase envelope by clicking on the Phase Envelope button.


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Exercise 2 – Size the Subsea Tieback 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 riser must be the same ID as the tieback. In addition, ensure that the erosional velocity is not exceeded. From the Setup > Flow Correlations menu, select Beggs-Brill Revised as the vertical and horizontal multiphase flow correlations. From the flowline/tubing screen, select the Heat Transfer Tab and click on the Calculate U value button.

Manifold Pressure Temperature

1500 psia 176 ºF Subsea Tieback 0'/1000' (not hilly) 6 miles 0' (horizontal) 9,10,11 in

Rate of undulations Horizontal Distance Elevational difference Available ID's Heat Transfer: Ambient temperature Pipe thermal conductivity Insulation thermal conductivity Insulation thicknesses available Ambient fluid Ambient fluid velocity Burial depth Ground conductivity


38 º F 35 Btu/hr/ft/°F 0.15 Btu/hr/ft/°F 0.75" + 0.25" increments water 1.5 ft/sec -5.5 " (not buried) 1.5 Btu/hr/ft/°F

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Riser (use detailed profile) Horizontal Distance 0' (vertical pipe) Elevational difference 1600' Available ID's 9,10,11 in Heat Transfer: Ambient temperature @ riser base 38 º F Ambient temperature @ 1200' 42 º F Ambient temperature @ 800' 48 º F Ambient temperature @ 400' 56 º F Ambient temperature @ topsides 68 º F Pipe thermal conductivity 35 Btu/hr/ft/°F Insulation thermal conductivity 0.15 Btu/hr/ft/°F Insulation thicknesses available 0.75" + 0.25" increments Ambient fluid water Ambient fluid velocity 1.5 ft/sec

Steps: 1. Perform a System Analysis with the minimum, maximum and expected flow rates as the x-axis variable, and the available ID’s for the flowline and riser as Change in Step sensitivity variables. 2. Determine the minimum flowline ID that satisfies the separator pressure requirement for the maximum flow rate. 3. Change the y-axis to display Erosional Velocity Ratio and check to ensure that the selected flowline ID does not exceed an erosional velocity ratio of 1.0. 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


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Exercise 3 – Check For Severe Slugging Task: Based on the ID selected above, determine the likelihood of severe slugging occurring at the riser base. Severe riser slugging is likely in a pipeline system followed by a riser under the following conditions: •

The presence of a long slightly downward inclined pipeline prior to the riser.

•

Fluid flowing in the "stratified" or "segregated" flow regime (as opposed to the usual "slug" or "intermittent" flow regime).

•

A slug number (PI-SS) of lower than 1.0.

Steps: 1. 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. 2. View the Summary Report Reports > Summary File, to determine the prevalent flow regime at the riser base for the different rates. Result: 8000 stb/d

14000 stb/d

16000 stb/d

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


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Exercise 4 – Select Tieback Insulation Thickness Task: Using the tieback/riser ID selected above, determine the thickness of the insulation required for both the flowline and riser, such that the temperature of the fluid does not come within 10ºF of the Hydrate curve for all possible flow rates. Steps: 1. Start with an insulation thickness of 0.75”. Ensure that “phase envelope” is checked in the Report Tool (located upstream of separator) and perform a Pressure/Temperature Profile with Separator (outlet) pressure as the calculated variable and with flow-rates as the sensitivity variables. 2. Use the Series menu on the resulting plot to change the x-axis to Temperature and the y-axis to Pressure to display the phase envelope. 3. Observe the production path on the phase envelope and its proximity to the Hydrate curve. 4. If required, perform successive runs while increasing the thickness by 0.25” each time until sufficient. Result: Property Req. Insulation thickness

Value

Exercise 4b – Methanol requirement Assume that the flowline is under insulated with only 0.25” of insulation. Determine the required injection volume of methanol to ensure that hydrates do not form using a compositional model with multi-flash. Insert an injection tool just after the manifold and define a local composition consisting of methanol only. Result: Property Req. Methanol Injection Volume (b/d)


Value

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Exercise 5 – Size Slug Catcher Task: Determine the required size of the slug catcher based on the largest of the following criteria multiplied by a safety factor of 1.2. •

The requirement to handle the largest slugs envisaged (chosen to be statistically the 1/1000 population slug size).

•

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

•

Ramp-up surge

Steps: 1. Ensure that “slugging values” and “sphere generated liquid volume” are selected in the report tool. 2. Under Setup > Define Output, select 3 cases to print. 3. Re-run pressure-temperature profile open output report. This report provides the full output of each sensitivity value with the Report Tool selections appended to the bottom of each sensitivity output. For each sensitivity value, scroll down to this section and read the reported “1/1000 slug volume” and “Total Sphere Generated Liquid Volume So Far”. 4. For the ramp-up case, perform a system analysis with inlet pressure calculated and liquid rates from 8000 to 14000 BPD in increments of 1000 BPD. Note the difference in total liquid holdup as this will be the surge volume. Notes on SGLV Calculation: When a sphere is introduced into the line, it will gather in front of itself a liquid slug made from "all the liquid that is flowing slower than the mean fluid flowrate in the pipeline at any given point". Thus, the crucial value that determines Sphere Generated Liquid Volume (SGLV) is the Slip Ratio(SR), which is the average speed of the fluid divided by the speed of the liquid. If the liquid and gas move at the same speed, the slip ratio will be 1 (i.e., there is 'no slip' between the phases). In this situation the sphere will not collect any liquid, so the SGLV will be zero. Normally the liquid flows slower than the gas (i.e., the slip ratio is greater than 1), so "some" of the liquid in the pipeline will collect in front of the sphere to form the SGLV. The only way that "all" of the liquid in the pipeline will collect to form the SGLV, is if the liquid velocity is zero (i.e., the slip ratio is infinite). This cannot happen in a steady-state reality, so the SGLV is always smaller than the total liquid holdup.


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Results: Property 1/1000 slug volume (bbl)

8000 stb/d

14000 stb/d

16000 stb/d

Sphere generated liquid volume (bbl) Design volume for slug catcher (bbl)


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Network Modeling

Module 6

Network Modeling

Looped Gathering Network Learning Objectives In this case study, a national oil and gas client is interested in establishing 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. You will perform the following procedures of the network modeling workflow: •

Build a model of the network

•

Specify the network boundary condition

•

Solve the network and establish the deliverability

Getting Started In this section, you will learn how to build a looped gathering network. 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 (e.g., as file c:\training\pn01.bpn).

Build a model of a network You will use the engineering data available at the end of this case study. You will perform the following steps: 1. Enter the engineering data for the first well. 2. Copy the data to wells 2 and 3. 3. Modify the data for well 3. 4. Specify the composition at each production well. 5. Connect the network together. 6. Define the engineering data for each branch.


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Step 1 – Enter the Engineering Data for the First Well 1. Use the production well button to place Well 1 in the work area as shown below.

production well button

production well

2. Double-click on Well_1 to reveal the components as shown below:

3. Double-click on the vertical completion to enter the inflow performance data. Enter a gas PI of 0.0004 mmscf/d/psi2, and the reservoir temperature. The reservoir pressure will be entered later when the network boundary conditions are specified. 4. Double-click on the tubing and select Simple Model as the preferred tubing model. Define a vertical tubing with a wellhead datum MD of 0 ft. and mid perforations TVD and MD of 4500 ft. The ambient temperatures are 130 °F at mid perforations and 60 °F at the wellhead. The tubing has an I.D. of 2.4". Note: essential data fields are shown in red outline (if the fields are not outlined, then data entry in these fields is optional). 5. Close the view of Well 1 by clicking at the right upper corner of the window or by selecting File > Close to return to the network view.

Step 2 – Copy the data to well 2 and well 3 Select Well_1. Using the commands Edit > Copy and Edit > Paste, create 2 copies of the well. By default, the names of the copied wells will be Well_2 and Well_3. Position the new wells as shown below:


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You will see that Wells 2 and 3 contain the same input data as Well 1.

Step 3 – Modify the Data of Well 3 Double-click on Well_3 and modify the completion and tubing data. For the vertical completion enter a gas PI of 0.0005 mmscf/d/psi2. Define vertical tubing with a wellhead TVD of 0 and mid perforations TVD and MD of 4900 ft. The ambient temperatures are 140 °F at the mid-perforation depth and 60 °F at the surface. The tubing has an I.D. of 2.4". Close the view of Well 3 to return to the network view.

Step 4 – Specify the Composition of Each Production Well The next step is to define the compositions at the production wells. Wells 1 and 2 are producing from the same zone and thus are assumed to have the same composition. Well 3 has a different composition as 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 (i.e., that for Wells 1 and 2) as the global composition and then to specify the composition of Well 3 as a local variant. The composition of Wells 1 and 2 is the same as that for the Subsea Tieback Design Case Study in Part 4 of this manual. This composition can be imported to save time. Otherwise, refer to the end of this case study for the compositional data. 1. First save the current network model. Open the Subsea Tieback Case Study (e.g., c:\training\tieback.bps). Open the Setup > Compositional menu and select the Export button to export the composition to a file called "comp1.pvt". You may now close the Subsea Tieback model. 2. In the network model, go to Setup > Compositional and select Import to import comp1.pvt as the global composition. 3. To define the local composition for well 3, select Setup > Fluid Models and edit the local composition. You may wish to import the composition used for wells 1 and 2 and modify the composition as given at the end of this case study.


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Network Modeling

Step 5 – Connect the Network Together 1. Now insert a sink and some junction nodes. Note that 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:

2. Using the branch button connect J_1 to J_2. To do this, click on the branch button, then hold down the left mouse button over J_1 and drag the mouse pointer to J_2 before releasing the left mouse button.

branch button

branch connected

3. Double-click on the arrow in the center of B1 to enter data for that branch. Now double-click on the flowline to enter the following data:

Rate of Undulations Horizontal distance Elevation difference Inner Diameter Wall Thickness Roughness Ambient Temperature

10/1000 30,000 ft 0 ft 6” 0.5” 0.001” 60 oF

4. Close the B1 window to return to the network view. As the looped gathering lines are all identical, the data for branch B1 can be used to define the other looped gathering lines. Select B1 by clicking on the arrow in the middle of the branch and using the Edit > Copy and Edit > Paste commands, copy B1 to create B2, B3, and B4. 5. In order to connect a pasted branch, first click the arrow in the middle of the new branch. You will see that highlight boxes appear at either end of the branch. Move the mouse pointer over the right hand highlight box, and you will see that the mouse PIPESIM 2006.1 Fundamentals

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Network Modeling

pointer changes to an "up arrow" shape (↑), as shown below. This end of the branch can then be dragged and dropped onto a junction node.

6. Position the new branches as shown below:

7. Now connect the wells to the adjacent junction node and connect J_4 to the sink as shown below:

8. Enter the engineering data for each branch. 9. Now enter the components and data for branch B5. Branch B5 comprises a liquid separator with an efficiency of 100%, a compressor with a pressure differential of +400 psi and an efficiency of 70%, an after-cooler (heat exchanger) with an outlet temperature of 120 °F and a delta P of 15 psi, and a flowline with the following properties:

Rate of Undulations Horizontal distance


10/1000 10,000 ft

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Network Modeling

Elevation difference Inner Diameter Wall Thickness Roughness Ambient Temperature

0 ft 8” 0.5” 0.001” 60 oF

The equipment is located at J_4 as shown below:

10. Use the connector tool

to join the equipment together.

Note: A reciprocating compressor must not be connected directly to another piece of equipment, i.e., you will need to use a separate branch. 11. You may now close the single branch window. Flow Correlations From the Setup > Flow Correlations menu, select Beggs-Brill Revised as the global vertical and horizontal multiphase flow correlations.

Specify the Network Boundary Condition First let us summarize the rules for specification of network boundary conditions. The network solver determines the fluid pressures, temperatures, and flow rates around a network for a user-specified set of boundary conditions. The following definitions are used: Lone Node

A lone node is a node with only one branch connected, i.e., a production well, an injection well, a source or a sink.

Boundary conditions

The fluid pressure, temperature, and flow rate at each lone node in the network.

The following rules apply: Rule for Temperatures: The fluid temperature at all sources and the static reservoir temperature at all production wells must be specified by the user. The fluid temperature at all the sinks and injection wells is always calculated by the network module.


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Rules for Pressures and Flow Rates: There are two rules for specification of pressure and flow rate boundary conditions: •

To satisfy the Degrees of Freedom, the total number of flow rates, pressures and PQ curves specified must equal the total number of lone nodes.

•

At least one pressure must be specified at one of the lone nodes.

•

All unspecified pressures and flow rates are calculated by the network module.

In this case study, the above rules will be satisfied by doing the following: 1. Specify all the fluid inlet temperatures. 2. Specify all the fluid inlet pressures and the delivery pressure. 3. Go to Setup > Boundary Conditions and specify the following boundary conditions:

Node Well_1 Well_2 Well_3 Sink_1

Pressure 2900 psia 2900 psia 3100 psia 800 psia

Temperature 130 °F 130 °F 140 °F (calculated variable)

All flow rates will be calculated by the network solver. Note: Any temperature/pressure specification defined in the single branch model must be re-specified in the network model. Likewise, the boundary pressures specified in the Network view will not change the pressures defined in the single branch model for use in single branch operations.

Solve the Network and Establish the Deliverability First, it is necessary to explain the network tolerance. A network has converged when the pressure balance and mass balance at each node is within the specified tolerance. The calculated pressure at each branch entering and leaving a node is averaged. The tolerance of each pressure is calculated from the equation: Ptol = (P - Pave.)/Pave. x 100% If all Ptol values are within the specified network tolerance then that node has passed the pressure convergence test. This is repeated for each node. The total mass flow rate into and the total mass flow rate out of a node are averaged. The tolerance is calculated from the equation: = (Tot. mass flow rate in - Tot. mass flow rate avg.) / Ftol Tot. mass flow rate avg. x 100% If the Ftol value is within the specified network tolerance then that node has passed the mass convergence test. This is repeated for each node. When all of the above conditions are satisfied, the network has converged. In this case study, the following steps are required:


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•

Set the network tolerance

•

Run the model

•

View the tabular reports

•

View the graphical reports

Steps: 1. Open the Setup > Iterations menu to set the network tolerance to 1%. 2. Save the model, and then press the run button

.

3. When the network has solved you should get the message "pn01 – Finished OK". Click on the OK button. 4. Select the Report Tool button approximately 42 mmscf/d.

and you will see that the sink gas flow rate is

5. More comprehensive reporting is available via the summary file button

.

6. Holding the shift key down, select the flow route from Well_3, branch B3 and branch . The following pressure profile for these three B5. Select the profile plot button branches should be obtained. The effect of the compressor at J_4 on the system pressure can be seen:

Note: Edit the legend and title on PsPlot to improve the graphical presentation.


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Network Tutorial 1: Data Summary Layout:

Completion and Tubing Data: Gas PI Wellhead TVD Mid Perforations TVD Mid Perforations MD Tubing I.D. Wellhead Ambient Temperature Mid Perforations Ambient Temperature

Wells 1 and 2 0.0004 mmscf/d/psi2 0 4500 ft 4500 ft 2.4" 60 °F 130 °F

Well 3 0.0005 mmscf/d/psi2 0 4900 ft 4900 ft 2.4" 60 °F 140 °F

Pure Hydrocarbon Components (Wells 1 and 2): Component Methane Ethane Propane Isobutane Butane Isopentane Pentane Hexane

Moles 75 6 3 1 1 1 0.5 0.5

Petroleum Fraction (Wells 1 and 2): PIPESIM 2006.1 Fundamentals

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Name


C7+

Molecular Weight

Specific Gravity

115

0.683

Moles 12

Aqueous Component (Wells 1 and 2): Component

Volume ratio (%bbl/bbl)

Water

10

Pure Hydrocarbon Components (Well 3): Component

Moles

Methane Ethane Propane Isobutane Butane Isopentane Pentane Hexane

73 7 4 1.5 1.5 1.5 0.5 0.5

Petroleum Fraction (Wells 3): Name C7+


Molecular Weight

Specific Gravity

115

0.683

Moles 10.5

Aqueous Component (Well 3): Component Water

Volume ratio (%bbl/bbl) 5

Data for Looped Gathering Lines (B1, B2, B3, and B4): Rate of undulations Horizontal distance Elevation difference Inner diameter Wall thickness Roughness Ambient temperature Overall heat transfer coefficient

10/1000 30,000 ft 0 ft 6" 0.5" 0.001" 60 °F 0.2 Btu/hr/ft2/°F

Data for Deliver Line (B5): Separator type Separator efficiency Compressor differential pressure Compressor efficiency After cooler outlet temperature After cooler delta P Flowline Rate of undulations Flowline Horizontal distance


Liquid 100% 400 psi 70% 120 °F 15 psi 10/1000 10,000 ft

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Flowline Elevation difference Flowline Inner diameter Flowline Wall thickness Flowline Roughness Flowline Ambient temperature Flowline Overall heat transfer coefficient

0 ft 8" 0.5" 0.001" 60 °F 0.2 Btu/hr/ft2/°F

Boundary Conditions: Node Well_1 Well_2 Well_3 Sink_1


Pressure 2900 psia 2900 psia 3100 psia 800 psia

Temperature 130 °F 130 °F 140 °F (calculated variable)

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Gas Transmission Network Features Illustrated •

Gas Transmission Network

•

Two phase, compositional fluid modeling

•

Sources and a sink

•

Parallel flowlines

•

Pressure/Flow boundary conditions

Problem Outline Two sources, Supply_1 and Supply_2, are connected through a parallel pipeline system to a delivery station some 250km away. Each source has a fixed flow rate and each produces a gas. Fluid properties are modeled using a compositional fluid model. From the Setup > Units menu, select the SI system of units for this exercise. General Data Different compositional fluids are produced by the sources. The delivery pressure is fixed at 58.95 bars. The ambient temperature for the field is 20 oC. Sources •

Supply_1 is flowing 15 mmsm3/d of gas at a temperature of 70 oC. The 1000 m flowline to the main trunk line has a 600 mm inner diameter, ID, with no elevation difference.

•

Supply_2 is flowing 37 mmsm3/d of gas at a temperature of 55 oC. The 35000 m flowline to the main trunk line has a 900 mm inner diameter with no elevation difference.

Parallel Flowlines The 250,000 m flowline (Line 4) to the main trunk line has a 960 mm inner diameter with no elevation difference. The parallel, 256,000 m flowline (Line 5) to the main trunk line has a 1024 mm inner diameter with no elevation difference. Flowline (Line 2) The 2000 m flowline joining the two parallel lines at their start has a 949.9 mm inner diameter with no elevation difference. Flowline To Delivery The flowline from the end of the parallel line to the delivery has a 970 mm ID and continues for 2000 m to the delivery point. The required pressure for delivery is 59 bars. Note: All other parameters, including the heat transfer, have been left as the default. The gas transmission network for is shown below.


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Fluid Data

Laboratory analysis has shown the fluids from the two supplies to have different compositions. Ensure that the Compositional Fluid model is defaulted by selecting Setup > Compositional and select OK. Select Setup > Fluid Models, select the supply source and click Edit to enter the compositions given below for each supply source. Component

Supply_1 Mol %

Supply_2 Mol %

Nitrogen

0.1

0.2

H2S

0.1

0.0

Carbon Dioxide

5.2

3.0

Methane

77.9

79.8

Ethane

6.9

8.4

Propane

4.5

4.2

Isobutane

1.0

2.1

Butane

1.3

1.0

Isopentane

0.4

0.7

Pentane

1.0

0.4

Hexane

0.8

0.2

Heptane

0.8

0.0

Clicking the Phase Envelope button will plot the phase envelope of each fluid. Flow Correlations: From the Setup > Flow Correlation menu, ensure that the Beggs Brill Revised correlation is selected for both Vertical and Horizontal Flow. Question 1 Run the model to determine the direction of flow in Line 2, and the flow rate and fluid temperature at the delivery point. The objective is to determine the direction of flow in Line 2 and the flow rate and temperature at the delivery point. Select Summary File from the Reports menu and scroll down to system summary section. Determine the flow direction of Line 2 by noting the referenced From and To objects and checking whether the fluid is flowing in a Forward or Reverse direction relative to these points. Note the direction of the arrow appearing on the branch refers to the direction of the directional survey data, not the direction of flow.


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Observe that the flow rate and fluid temperature at the delivery point are 51 mmsm3/d and 24.4 oC respectively.

Figure 1: Summary output


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Question 2 Plot the pressure profiles for the 250 km parallel pipelines. Holding the Shift key, select Line 4 and 5, and then click on the Profile Plot icon pressure profile plot is shown in Figure 2.

. The

Figure 2: Pressure profiles for the 250 km parallel lines.


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Question 3 Plot the temperature profiles for the 250 km parallel pipelines. In the Plot Window, Select Series and change the y-axis to Temperature variable. The temperature plot is shown in Figure 3.

Figure 3: Temperature profiles for the 250 km parallel lines.


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Water Injection System Features Illustrated: •

Injection network

•

Single phase (water)

•

ESP lifted production well

Problem Outline A water production well feeds water into an injection system that consists of 6 injection points. The water is lifted from the production well by an ESP. Figure 4 schematically presents the layout of the studied water injection system. A Global black oil model with 100% water cut is used in this case study.

Figure 4: Water Injection System

General Data The fluid produced from the well (Producer) is a single phase black-oil with a water cut of 100%. The delivery pressures to each individual injection point are different. The ambient temperature for the entire network is 50°F. Use Beggs-Brill Revised as the vertical and horizontal multiphase flow correlations. Well Data The water production rate of the well is 15,000 stb/d and the temperature of the well is 200 °F and reservoir pressure is 4000 psia. The well has a liquid productivity index (PI) of 100 stb/d/psi. The ESP can be added into the production well by selecting the Simple Tubing model in the Production well and selecting the ESP option in Artificial Lift section.


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The ESP is located at a depth of 2,000 ft TVD and the water production well is at 6,000 ft TVD. The total measured depth along the tubing is 6,000 ft MD and the well has a 7” ID. To specify the ESP parameters, click on the Properties button on the Artificial Lift section of the Tubing window. Set the ESP manufacturer and model to Centrilift Model: IB700. Set the number of stages to 30 and the speed to 3,600 rpm. Flowlines to Injection Wells •

Flowline 1 is 150 ft in length with an ID of 8” and no elevation difference. It joins N1 to N2.

•


•


•


All the flowlines are insulated (heat transfer coefficient = 0.2 BTU/hr/ft2/F). Delivery Sinks/Injection Wells All the delivery sinks are single injection wells with 1.995” ID tubing and properties as follows:

Well 1 Well 2 Well 3 Well 4 Well 5 Well 6

Static Pressure (psia) 4400 4500 4400 4500 4400 4500

Reservoir Temp (°F) 210 220 210 220 210 220

MD/TVD (ft) 7800 7900 7800 7900 7800 7900

Injection PI (stb/d/psi) 2 4 6 8 3 5

Fluid Data The fluid produced from the production well is a single-phase, black oil (with 100% water cut) flow. Select Fluid Models under Setup, highlight the production well and select Edit to insert the Black oil data. Task: The objective of the case study is to determine the fluid (i.e., water in this case) distribution in an injection system from a single production well. Note: All other parameters should be left as the default. Run the Model and View the Results 1. Select the Run Model icon

to start the simulation.

2. Use the Report Tool to summarize the results of interest. 3. Click on the Report Tool icon

.

4. Select Clear.


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5. Click on the Producing well and each of the injectors.

Plot the pressure profiles for the entire network by selecting all objects in the network and then selecting the profile plot icon.

Note: Click on the Summary Table button on the Tubing dialog to increase the number of points along the tubing strings. Re-run the model and plot the results.


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Module 7

Answers

In this module, you can find the answers to the Well Performance Case Studies, Artificial Lift Design and Single Branch Case Studies.

Well Performance Case Studies Oil Well Performance Analysis Exercise 2 – Pressure / Temperature Profile Wellhead Pressure Production Rate Flowing BHP Flowing WHT

300 psia 7454 bbl/d 2668 psia 133 oF

Exercise 2 – Nodal Analysis (Outlet) Wellhead Pressure Operating Point Flow rate Operating Point BHP AOFP

300 psia 7454 bbl/d 2668 psia 28535 bbl/d

Exercise 3 – PVT Analysis Wellhead Pressure Production Rate Flowing BHP Flowing WHT

300 psia 6812 bbl/d 2744 psia 129 °F

Exercise 4 – Flow Correlation Matching Wellhead Pressure Vertical Correlation Flowing BHP

300 psia Hagedorn Brown 2522 psia

Exercise 5 – IPR Matching Wellhead Pressure PI AOFP

300 psia 6 16000 bbl/d

Exercise 6 – Water Cut Sensitivity Wellhead Pressure Water Cut

300 psia 64%

Exercise 7 – Gas Lift Water cut = 10% Gas Lift Rate (mmscf/d)


Water cut = 60% Liq. Prod. Rate (stb/d)


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0.5

7227

4755

1

7707

5796

1.5

8048

6443

2

8306

6898


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Enhanced Oil Well Production Using Nodal Analysis Exercise 1 – Well Model Wellhead Pressure Production Rate Flowing BHP

250 psia 775 stb/d 2417 psia

Exercise 2 – Nodal Analysis – Sensitivity to Stimulation and Gas Lift Oil Production Rates (stb/d) – Beggs-Brill Gas Lift Rates (mmscf/d) Completion

0.0

0.5

1.0

2.0

base (skin = 3)

779

1097

1188.2

1240.5

acidized (skin = 0)

1084.5

1432.1

1535.2

1598.9

fractured (skin = -2)

1438.4

1798.9

1916.8

1981.9

Exercise 3 – Nodal Analysis – Sensitivity to Flow Correlation Oil Production Rates (stb/d) – Mukherjee and Brill Gas Lift (mmscf/d) Completion

0.0

0.5

1.0

2.0

base (skin = 3)

697.7

1011.5

1125.1

1221.3

acidized (skin = 0)

981

1332.2

1468.6

1578

fractured (skin = -2)

1325.4

1695.4

1846.2

1964.5


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Gas Well Performance using a Compositional Fluid Model Exercise 1 – Simple Well Model Pres = 4,600 psia, Tres = 280oF % H2O @ saturation 1.85%

QG Pwf BHT WHT

Po = 800 psia 33 mmscf/d 2160 psia 248 oF 182 oF

Exercise 2 – Calibrate Inflow Model Back Pressure Equation Parameter C 8*10-7 Parameter n 1

QG Pwf Tbh (ºF) Twh (ºF)

Po = 800 psia 15.6 mmscf/d 1292 psia 227 oF 168 oF

Exercise 3 – Perform Nodal Analysis at bottom hole QG Pwf BHT WHT

Po = 800 psia 15.7 mmscf/d 1254 psia 227 oF 165 oF

Well-head, 3.958” tubing Max. Erosional velocity ratio 0.78

Exercise 4 – Flow-line and Choke Choke size

Po = 710 psia 1.5

Exercise 5 – Higher liquid loading / Flow Correlation Matching Pres = 4300 psia, Tres = 280 °F % H2O @ saturation 1.91 Po = 800 psia Best Correlation Mean arithmetic difference (%)


Duns-Ros 0.27

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Po = 800 psia Mean absolute difference (%)

0.27

Exercise 6 – Higher liquid loading / Flow Correlation Matching Po = 710 psia QG Pwf QL @ mid-perfs (act) QL @ outlet (act)

13.3 mmscf/d 1361.3 psia 2062 bbl/d 2650 bbl/d

Exercise 7 – Liquid Hold-up fraction and Flow Regime Map Liquid Volume Fraction, Po = 710 psia xVL @ bottom-hole 0.07 xVL @ WH 0.08 xVL @ end flow-line 0.05 Flow regime end FL Intermittent Liquid Hold-up Fraction, Po = 710 psia xHL @ bottom-hole 0.38 xHL @ WH 0.08 xHL @ end flow-line 0.15

Exercise 8 – Pressure / Temperature path from Reservoir Ambient Temp = 30 °F Hydrate formation? No

Exercise 9 – Pressure Drop due to increase condensate production Heavier composition 2803 psia (Pwf = 1497 psia) ΔP Reservoir ΔP Tubing

630 psia (Pwh = 869 psia)

ΔP Choke

84 psia

ΔP Flow-line

2 psia

Exercise 10 – Rigorous Flashing Po = 710 psia QG 13.3 mmcfd Pwf 1360.4 psia QL @ mid-perfs (act) 2094 bbl/d QL @ outlet (act) 2654 bbl/d Ambient Temp = 30 °F Hydrate formation? No


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Artificial Lift Design ESP Design Exercise 1 – Nodal Analysis Well will not flow naturally. Exercise 2 – Pump Selection / Design No. of stages (HN13000) Motor HP required Flowrate range for 50 – 70 Hz. Flowrate for Psuction < Pbubblepoint

57 316 7606-12830 bbl/d 11926 bbl/d

Exercise 3 – Pump performance with varying well conditions Production Rate (95% water cut)


600 stb/d

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Single Branch Pipeline and Facilities Exercise 1 – Size Subsea Tieback 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

10’’ 0.88 900 psia 1234 psia

Exercise 2 – Check for Severe slugging

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

8000 (stb/d) 0.99 Intermittent



Exercise 3 – Select Tieback Insulation Thickness Property Req. Insulation thickness

Value 1”

Exercise 5 – Size Slug Catcher Property 1/1000 slug volume (bbl) Sphere generated liquid volume (bbl) Design volume for slug catcher (bbl)


8000 (stb/d) 166.3 485.7 485.7*1.2 = 582.8

14000 (stb/d) 186.7 448.2

16000 (stb/d) 226.5 435.9

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