Pipesim Course

PIPESIM Training Course

June 2003

2 PIPESIM Training Manual

Copyright notice June, 2003, Schlumberger. All Rights Reserved. No part of this manual may be reproduced, stored in a retrieval system, or translated in any form or by any means, electronic or mechanical, including photocopying and recording, without the prior written permission of Schlumberger Information Solutions, 5599 San Felipe, Suite 1700, Houston, TX 77056-2722. Disclaimer Use of this product is governed by the License Agreement. Schlumberger makes no warranties, expressed, implied or statutory, with respect to the product described herein and disclaims without limitation any warranties of merchantability or fitness for a particular purpose. Schlumberger reserves the right to revise the information in this manual at any time without notice. Trademark Information PIPESIM, GOAL, NODAL Analysis, OFM, HoSim and ECLIPSE are trademarks of Schlumberger. All other products and product names are trademarks or registered trademarks of their respective companies or organizations.

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PIPESIM Training Manual 3

PART 1: SINGLE BRANCH TUTORIALS 5 Single Branch Tutorial 1 - Single Phase Pipeline 6

Single Branch Tutorial 2 Multiphase Pipeline 26

Single Branch Tutorial 3 - Oil Well Performance 33

Single Branch Tutorial 4 Black Oil Calibration and Performance Forecasting 46

PART 2: SINGLE BRANCH CASE STUDIES 64 Case Study 1 - Oil Well/ Black Oil Fluid 65

Case Study 2 - Well Performance Modelling - Nodal Analysis 73

Case Study 3 - Gas well Performance using a Compositional Fluid Model 77

Case Study 4 ESP Selection / Design 86

Case Study 5 Pipeline and Facilities (Compositional Fluid model) 89

Case Study 6 Gas Lift Design, New Mandrel spacing: 95

Case Study 7 Gas Lift Design, Current Mandrel spacing: 98

PART 3: NETWORK MODELING TUTORIALS 99 Network Tutorial 1: Looped Gathering Network 100

Network Tutorial 2: Gas Transmission Network 108

Network Tutorial 3: Water Injection System 112

PART 4 FPT TUTORIALS 116 FPT Tutorial 1: Compositional Tank & Look Up Tables 117

FPT Tutorial 2: Black Oil Tank. 145

FPT Tutorial 3: Look Up Tables 157

FPT Tutorial 4: Daily Contract Quotas (DCQ) 163

PART 5 SINGLE BRANCH CASE STUDIES WORKED ANSWERS 174 Worked Answers: Case Study 1 Oil Well Design 175

Worked Answers: Case Study 2 Well Performance Analysis Nodal Analysis 194

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Worked Answers: Case Study 3 Gas Well Performance 203

Worked Answers: Case Study 4 ESP Selection / Design 220

Worked Answers: Case Study 5 Pipeline and Facilities 222

Worked Answers: Case Study 6 Gas Lift Design New Mandrel Spacing 228

Worked Answers: Case Study 7 Gas Lift Design Current Mandrel Spacing 230

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Part 1: Single Branch Tutorials

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Single Branch Tutorial 1 - Single Phase Pipeline The purpose of this tutorial is to familiarize the user with the PIPESIM Single Branch interface by building and running simple examples. The user will construct a simple pipeline model then calculate the pressure drop along a horizontal pipeline for a given inlet pressure and Flowrate. The user will then run some sensitivity studies on the model. Each example will follow the standard workflow for single branch modelling:

1) Build the Physical Model 2) Create a Fluid Model 3) Choose Flow Correlations 4) Perform Operations 5) View and Analyze Results

Exercise 1: Water Pipeline Getting Started: Launch PIPESIM from the Start menu (Start -> Program Files -> Schlumberger -> PIPESIM) 1) Choose New Single Branch Model from the startup screen

2) From the Setup|Units menu, select SI Units

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Step 1: Define the physical components of the model: The PIPESIM single branch model toolbox is shown below:

Select the source button and place it in the window by clicking on the single branch window:

Select the End Node button and place it in the window:

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:

Note that the red outlines on Source_1 and Flowline_1 indicate that essential input data is missing.

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Double Click on Source_1 and the source input data user form will appear. Fill the form as shown below.

Click on to exit the user form. Double Click on Flowline_1 and the source input data user form will appear. Fill the form as shown below:

Click on the Heat transfer tab and fill the form as shown below (adiabatic process):


Click on to exit the user form.

Step 2: Define the fluid model (water): In the Setup menu select Black Oil; the Black Oil user form will appear.

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Fill in the Black Oil user form as shown below: Go to the File Menu and save the Model as CaseStudy1_WaterPipe.bps. Step 3: Select Flow Correlations: From the Setup menu, Select Flow Correlations and ensure that the Moody single phase flow correlation is selected

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Step 3: Define the operation: In the Operations menu select the Operation Pressure/Temperature

Fill in the Pressure/Temperature Profile User form as shown below:

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Step 4: Run the Model:

Run the model by clicking on in the user form. The pressure calculation will be done using the Moody correlation (Default single phase correlation)

Step 5: Observe the PSPlot output:

The following pressure profile should be visible by clicking on at the bottom of the screen.

It can be seen that the outlet pressure is 58 bars.

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Click on the Data tab to display a tabular output of the Pressure/Temperature Profile

To copy this data into Excel, highlight the cells of interest, hit Ctrl+C, then select a cell in Excel and hit Ctrl+V.

Step 6: Observe the Summary File ( .sum):

In the Reports menu select the Summary File option:

The following output can be observed: The Liquid Hold-up value displayed 353.4 m3 is the liquid hold up for the entire pipe.

Step 7: Observe the Output file (.out): In the Reports menu select the Output File option.

The Output File is divided by default in 5 sections:

1. The INPUT DATA ECHO. (Input data and Input units summary) 2. The Fluid Property Data. (Input data of the fluid model) 3. The Profile & Flow Correlations. (Profile and selected correlations summary) 4. The Primary Output. 5. The Auxiliary Output.

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The Primary output is shown below.

It is divided into 16 sections:

1. The 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. The Horizontal Distance. (This is different from the Measured distance along the Flowline) 3. The Elevation. (Elevation from the horizontal). 4. The Horizontal Angle 5. The Vertical Angle 6. The Pressure 7. The Temperature 8. The mean mixture velocity 9. The elevational Pressure drop. 10. The Frictional Pressure drop. 11. The Actual Liquid Flow rate at the P,T conditions of the node. 12. The Actual Fre gas rate at the P,T conditions of the node. 13. The Actual Liquid density at the P,T conditions of the node. 14. The Actual Free gas density at the P,T conditions of the node. 15. The Slug Number. 16. The Flow Pattern.

It can be seen that as the Pressure decreases the Liquid density decreases therefore the Flowrate has to increase to maintain the mass flow rate constant.

The auxiliary output is shown below:

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It is also divided into 16 sections:

1. The node Number. 2. The Horizontal Distance. 3. The vertical Elevation. 4. The Pipe ID 5. The Superficial Liquid Velocity 6. The Superficial Gas velocity 7. The liquid mass flow rate. 8. The gas Mass flow rate. 9. The liquid viscosity. 10. The Gas viscosity. 11. The Reynolds Number. 12. The No-slip liquid hold-up. 13. The Liquid hold-up. 14. The Enthalpy 15. The number of Pressure iteration 16. The number of Temperature iteration.

The values of the Reynolds number indicate that the flow regime is turbulent.

The viscosity decreases as the pressure decreases.

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

Step 1: Modify the Pressure/Temperature Profile operation user form In the Operations menu select the Operation Pressure/Temperature Profile. Select Source_1 as the Component and Temperature as the Variable.

In the Pressure/Temperature Profile user form press on the button, an input form appears and must be filled as follows:

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

Step 2: Run the Model:

Run the model by clicking on in the user form. The pressure calculation will be done using the Moody correlation (Default single phase correlation)

Step 3: Observe the PSPlot output:


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It can be seen that the highest inlet temperature generates the lowest pressure drop. This is because 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 are negligible. Select the Data tab in the PS plot to observe all the data for each temperature in a tabular format.

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Step 4: Observe the output file (.out): In the Reports menu select the Output File option. The Output file contains by default the information for the first case only. (T = 10 deg C). In the Setup Menu, select the Define Output option as shown below:

In the Define Output user form set the No of cases to print to 7.

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Re-run the operation, open the output report and you will see the results of the seven sensitivity cases.

Return to the Define Output user form. 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 hold-up 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, we will now model single phase gas through our flowline. Step 1: Redefine the Fluid Model: From Setup|Black Oil, modify the user form as shown below (100 % gas):

Step 2: Modify the Pressure/Temperature Profile Operation Modify the Pressure/Temperature Profile user form as shown below:

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Step 3: Run the model

Run the model by clicking on in the user form

The pressure calculation will be done using the Moody correlation (Default single phase correlation)

Step 4: Observe the Output Plot


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It can be seen that the highest inlet temperatures generate the highest pressure drops. 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.

In the case of gas the effect of the temperature on the viscosity are negligible. In PS-Plot click on the Series menu:

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Change the Y axis from pressure to temperature and press on OK the following temperature profile will be seen.


The temperature decrease along the pipeline is due to the Joule -Thompson effect.

Exercise 4: Calculate the gas Flowrate for a given pressure drop In the previous exercises, we calculated the Outlet Pressure given a known Inlet Pressure and Flowrate. We will now specify known Inlet and Outlet Pressures and calculate the corresponding gas flowrate.

Step 1: Modify the Pressure/Temperature profile user form Modify the Pressure/Temperature user form as shown below in order to calculate the standard gas flow rate for a given pressure drop.

Step 2: Run the Operation

Run the model by clicking on in the user form.

The pressure calculation will be done using the Moody correlation (Default single phase correlation)

Step 3: Observe the PSPlot output The Gas Flowrate corresponding to the specified pressure drop is shown in the legend beneath the profile plot

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Step 4: Observe the output files (.out):

The iteration routine for this operation can be seen in the output file as shown below.

Save your file as exer4.bps and File|Close.


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Single Branch Tutorial 2 Multiphase Pipeline 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, following the same general workflow as before:


Getting Started: 1) Select File|New|Pipeline and Facilities 2) From Setup|Units, set to SI Step 1: Build the Physical model: Using the toolbar, contruct the model shown below:

Source_1 Data:


Flowline Data: (Keep all default heat transfer options)

Report tool options (same for both Report Tools)

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Step 2: Define the Black oil fluid model

Step 3: Choose Flow Correlations: From the Setup| Flow Correlations menu, Select the following Flow Correlations:


Step 4: Define and Run a Pressure/Temperature profile operation

From the Operations| Pressure Temperature Profile menu, enter the following:

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As the Inlet Pressure text box is left empty the value will be taken from the Source_1 user form.

Step 5: Run the model


The pressure drop will be calculated using the Moody correlation (Default single phase correlation) and the Beggs and Brill Correlation.

Step 6: Observe the output file

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

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The flow pattern can be seen by scrolling to the right:

It can be seen that the flow is initially single-phase liquid until the pressure falls below the bubble point 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. (The hold-up for each of the segment can be seen in the auxiliary output.) The number 1.8 is the erosional velocity ratioand is only displayed when higher than 1.

The spot reports output is shown below:

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Single Branch Tutorial 3 - Oil Well Performance In this tutorial we will model well performance, following the same general workflow as before:


Getting Started: 1) Select File|New| Well Performance Analysis 2) From Setup|Units, set to English Exercise 1: Pressure Temperature Profile

Step 1: Define the physical components of the Model The PIPESIM single branch model toolbar is shown below:

Select the Vertical Completion button and place it in the single branch window:

Select the End Node button and place it in the window:

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Select the Tubing button and link Completion_1 to the End Node S1 by clicking and dragging from Completion_1 to the End Node S1:

Note that the red outlines on Completion_1 and Tubing_1 indicate that essential input data is missing.

Double Click on Completion_1 and the source input data user form will appear. Fill the form as shown below.

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Click on to exit the user form. Double Click on Tubing_1 and the source input data user form will appear.

Select Simple Model as the Preferred tubing Model as shown below:

Fill the form as shown below:

Click on to exit the user form.

Step 2: Define the black oil model Select Setup| Black Oil

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Enter the fluid properties as shown below:

Go to the File Menu and save the Model as CaseStudy1_Oil Well.bps. Step 3: Select Multiphase Flow Correlations From the Setup| Flow Correlation menu, ensure that the Beggs Brill Revised correlation is selected for both Vertical and Horizontal Flow

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Step 4: Define and Run a Pressure/Temperature Profile Operation

Select Operations | Pressure Temperature Profile

Enter a liquid rate of 3000 STBD and select outlet pressure as the calculated variable. PIPESIM will automatically assume that the inlet pressure is the static reservoir pressure specified in the completion.

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Step 5: Run the Model




It can be seen that the outlet pressure is 730 Psia.

Click on the Data tab to display a tabular output of the Pressure-Temperature Profile

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To copy this data into Excel, highlight the cells of interest, hit Ctrl+C, then select a cell in Excel and hit Ctrl+V.

Step 7: Observe the Summary File (.sum):

In the Reports menu select the Summary File option:

The following output can be observed:

and Input units summary)

elations summary) 4) The Primary Output

The Liquid Hold-up value displayed 101 m3 is the liquid content of the entire pipe (linepack).

Step 8: Observe the output file (.out):

the Reports menu select the Output File option.

The Output File is divided by default in 5 sections:

In

1) The INPUT DATA ECHO (Input data 2) The Fluid Property Data (Input data of the fluid model) 3) The Profile & Flow Correlations (Profile and selected corr

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5) The Auxiliary Output

The Prim w.

It is divided into 16 sections: 1. The node number: node at which all the measures on the row have been recorded.

by default been spaced with a 1000 ft interval)

3.

re velocity sure drop.

. e P,T conditions of the node.

P,T conditions of the node.

e.

It can b sure decreases, the liquid holdup decreases. Therefore, the liquid flowrate decreases to maintain the mass flow rate constant.

Therefore, the gas hold-up increases nd the gas velocity has to increase to maintain a constant mass flowrate. The gas volumetric

flowrate increases with decreasing pressure due to gas expansion.

ary output is shown belo

(The nodes have 2. The Horizontal Distance.

The Elevation. (Elevation from the horizontal). 4. The Horizontal Angle 5. The Vertical Angle 6. The Pressure 7. The Temperature 8. The mean mixtu9. The elevational Pres10. The Frictional Pressure drop11. The Actual Liquid Flow rate at th12. The Actual Free gas rate at the13. The Actual Liquid density at the P,T conditions of the node. 14. The Actual Free gas density at the P,T conditions of the nod15. The Slug Number. 16. The Flow Pattern.

e seen that as the Pres

Also, as the pressure decreases the gas density decreases. a

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The Auxiliary Output is shown below:

It is also divided into 16 sections:

1. The node Number. 2. The Horizontal Distance. 3. The vertical Elevation.

id Velocity ity

e. s flow rate.

.

iteration n.

The val number (~ 50,000) indicates turbulent flow The visc ssure decreases due to gas coming out of solution. Save the model as exer4.bps

Exercise 2: Sensitivity Analysis

Using the model from the previous exercise, we will now perform sensitivity analysis on the reservoir pressure.

Step 1: Modify the Pressure Temperature Profile Operation user form:

4. The Pipe ID 5. The Superficial Liqu6. The Superficial Gas veloc7. The liquid mass flow rat8. The gas Mas9. The liquid viscosity. 10. The Gas viscosity. 11. The Reynolds Number. 12. The No-slip liquid hold-up13. The Liquid hold-up. 14. The Enthalpy 15. The number of Pressure16. The number of Temperature iteratio

ues of the Reynoldsosity of the liquid increases as the pre

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From the Operations | Pressure Temperature Profile menu, select as a sensitivity VertWell_1 as the Component and Static Pressure as the Variable. Enter values shown below:

Step 2: Run the Model



e should be visible by clicking on

The following pressure profil at the bottom of the screen.

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The pressure drop across the reservoir is identical for all case due to the PI and flowrate being constant. For the case Pws = 1000 psia the pressure is not sufficient to lift the column of fluid to the surface. The pressure reaches zero at 4000 ft. Select the Data tab in the PS plot to observe all the data for each temperature in a tabular format.

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Step 4: Observe the output file (.out):

In the Reports menu select the Output File option.

The Output file contains by default the information for the first case only. (Pws = 3600 psia). In the Setup Menu, select the Define Output option as shown below:

In the Define Output user form set the No of cases to print to 4.

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Re-run the operation you will see the output of the 4 sensitivity cases displayed in the Output file.

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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Single Branch Tutorial 4 Black Oil Calibration and Performance Forecasting

Overview An oil reservoir has been discovered in the North Sea. A vertical well has been drilled, a test string inserted 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 watercut 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. The engineer is asked to perform the following tasks:

1) Develop a well inflow performance model applicable throughout field life. This provides a relationship between the reservoir pressure, the flowing bottom hole pressure and flowrate through the formation.

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

3) Select a suitable tubing size for the production string. 4) Review the feasibility of using gas lift as an alternative to water injection.

The engineering data available is given at the end of this case study. Getting Started 1) Select File| New| Well Performance Analysis 2) From Setup|Units, set to English

Excercise1: 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 bubble point and no gas comes out of solution at this stage. This 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 watercut through field life because the oil and water have similar mobilities in this reservoir structure. 1. Add a vertical completion to the model. This is done by pointing and clicking on the vertical completion button at the top of the screen and then pointing and clicking in the work area. A vertical completion appears as shown below.

vertical completion button vertical completion

2. Double click on the vertical completion in the work area to enter the following data:

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3. Press the "calculate/graph button and enter the drill string test data as shown below and select 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 button-drag on plot to position datapoints.

To zoom in, left button-drag a window acrossthe data points towards the lower right.

To zoom out, left button-drag a windowtowards the upper-left.

1. Select OK and OK to exit dialogs Add Tubing 1. Add a boundary node to the model by pointing and clicking on the boundary node button at the top of the screen and then pointing and clicking in the work area:-

boundary node button boundary node

2. Click on the tubing button, and drag from the completion to the boundary node.

Completed Model

Note that the red outline indicates that essential data is missing for that component. 3. 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.

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2. Select OK to exit dialog


Excersise 2: Develop a Calibrated Blackoil Model No analysis work can be carried out until a blackoil fluid model has been developed. This allows all of the fluid physical properties to 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 0 %GOR 892 scf/STBGas SG 0.83Water SG 1.02Oil API 36.83

Bubble Point Properties:Pressure 2647 psiaTemperature 210 FSolution Gas 892 scf/STB

Blackoil Calibration Data:OFVF (above bubble point pressure) 1.49 @ 4,269 psia and 210 FOFVF (below bubble point pressure) 1.38 @ 2,000 psia and 210 FDead oil viscosities 0.31 cP @ 200 F and 0.92 cP @ 60 FLive oil viscosity 0.29 cP @ 2,000 psia and 210 FGas viscosity 0.019 cP @ 2,000 psia and 210 FGas compressibility (Z) 0.85@ 2,000 psia and 210 F

Note: The bubble point calibration for sat GOR is used to normalize (calibrate) the Soln GOR correlation . By specifying a higher stock tank GOR than acalibration sat. GOR, you are effectively increasing the bubble point. (ie.a plot of flowing soln. GOR vs. pressure will intersect this calibration point, but the bubble point is no longer that with which the calibrationsat. GOR is specified). Conversely, if the stock tank GOR is less than the calibration sat. GOR, then the stock tank GOR is used (takes precendence)with the calibration GOR ignored.

1. From the Setup | Black Oil menu to enter the stock tank oil properties and the bubble point properties as shown below:

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Note: Help on the definitions and valid ranges of these stock tank properties can be obtained by selecting the Help at the bottom of this dialog

2. Select the Advanced Calibration Data menu, Single Point Calibration and enter the Gas

Saturation at the Bubble Point pressure and temperature as shown below:

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3. press the "Plot PVT data (Laboratory Conditions) button.

4. On the resulting plot, use the Series menu to plot the oil formation volume factor on the y-axis.

The following plot should be obtained:

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Observe that the uncalibrated curve for a temperature of 210 F shows that the predicted OFVF is higher than the measured value both above and below the bubble point 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.

To calibrate the OFVF above the bubble point pressure, select the Advanced Calibration Data tab and enter the measured value of 1.49 @ 4,269 psia and 210 F as shown below:


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Again, click on the Plor PVT Data (Laboratory Conditions) and the following plot should be obtained:


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Apply OFVF calibration below the bubble point pressure. The measured value is 1.38 @ 2,000 psia and 210 F and replot. The following plot should be obtained:


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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 @ 60 F. The Beggs and Robinson correlation uses the oil API gravity to predict two dead oil data points based upon data obtained from around 2,000 data points from 600 oil systems. Plot the uncalibrated oil viscosity by changing the previous plot Series. The following plot should be obtained: In this case it can be seen that the predicted oil viscosity value at a temperature of 70 F and 14.7 psia is about 23 cP as specified by the Beggs & Robinson correlation. This is significantly different from the measured dead oil data and would lead to errors in the prediction of pressure loss. Select the Viscosity Data tab and select Users Data 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:


It can be seen 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 tab and enter the live oil calibration data of 0.29 cP @ 2,000 psia and 210 F. The following plot should be obtained:

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It can be seen 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


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. I.D. as described in at the end of the case study.

Year Watercut (%) Oil Flowrate, sbbl/d0 0 13,0001 0 13,0002 0 13,0003 0 13,0004 12 11,6005 20 9,8006 35 7,8007 40 6,7008 47 5,8009 54 4,50010 60 3,600

Production plan obtained from reservoir simulation

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 menu, select Systems Analysis menu and 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. Select Run Model, and select Stock Tank Oil as the y-axis series to give the following plot:

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It can be seen that 3.83 ID tubing is the smallest size that will satisfy all of the production plan conditions.

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:

Year Pws (psia)

0 4,2691 4,1902 4,1133 4,0204 3,9505 3,8936 3,8407 3,8008 3,7629 3,73010 3,700

Predicted reservoir pressure decline (without water injection)

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 sbbl/d with the reduced reservoir pressure of 3,700 psia.

1. Double click on the completion, and change the static reservoir pressure to 3,700 psia.

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2. Double click on the tubing, ensure that the tubing ID is 3.83, and add a gaslift depth of 8,000 ft. Press the properties button and enter the gas lift surface temperature of 100 F and specific gravity of 0.6.

3. From the Operations menu, select Artificial Lift Performance menu and 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 mmscfd as shown below:

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

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It can be seen that it would be necessary to inject 2.0 mmscfd 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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Part 2: Single Branch Case Studies

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Case Study 1 - Oil Well/ Black Oil Fluid

Exercise 1. Well Model - System Solution Given the following basic data, construct a well model and find the flowing bottom hole pressure, flowing wellhead temperature and production rate for a given wellhead pressure. Black Oil PVT Data Stock Tank Properties

Water Cut 10 % GOR 500 scf/stb Gas SG 0.8 Water SG 1.05 Oil API 36 (API)

Assume default PVT correlations and no calibration data Wellbore Data Deviation Data

Measured Depth (ft) True Vertical Depth (ft) 0 0

1000 1000 2500 2450 5000 4850 7500 7200 9000 8550

Geothermal Gradient

Measured Depth (ft) Ambient Temp. (oF) 0 50

9000 200 Overall Heat Transfer Coefficient = 5 btu/hr/ft2/F Tubing Data

Bottom MD (ft) Internal Diameter (inches) 8600 3.958 9000 6.184

Reservoir & Inflow Data

Completion Model = Well PI Select Use Vogel Below Bubble Point

Reservoir Pressure 3600 psia

Reservoir Temperature 200 oF Productivity Index 8 stb/d/psi

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Result

Wellhead Pressure 300 psia Production Rate ?

Flowing BHP ? Flowing WHT ?

Method :

Construct Model and enter above data. Run Operations > Pressure / Temperature Profile

o Enter Given Outlet Pressure (Calculate Liquid Rate). o Leave Sensitivity Variable empty.

Inspect plot and text output to determine answers.

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Exercise 2. Well Model Nodal Analysis Using the model from Exercise 1. Add (insert) a Nodal Analysis icon at bottom hole location.

N.A. Point

Perform a Nodal Analysis operation for a given outlet (wellhead) pressure to determine the operating point (bottom hole pressure and flowrate) and the AOFP (absolute open flow potential) of the well ?.

Result

(Outlet) Wellhead Pressure 300 psia Operating Point Flowrate ?

Operating Point BHP ? AOFP ?

Method :

Insert the Nodal Analysis icon at bottom hole location (between the completion and the tubing).

Run Operations Nodal Analysis o Enter Given Outlet Pressure. o Leave Inflow Sensitivity and Outflow Sensitivity empty.

Inspect plot to determine answers.

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Exercise 3. Well Model PVT Calibration The following measured PVT data is available to calibrate and improve the fluid model. Use the measured data to calibrate the PVT model and re-run Exercise 1. (find the flowing bottom hole pressure, flowing wellhead temperature and production rate for a given wellhead pressure) ?. PVT Calibration Data

OFVF above bubble point = 1.16 @ 3000psia and 200 oF. Bubble Point Properties Pressure = 2100 psia, Temperature = 200, Solution Gas = 500 scf/stb Data Measured at the bubble point.

OFVF = 1.22 @ 2100 psia and 200 oF Live Oil Viscosity = 1.1 cp @ 2100 psia and 200 oF

Gas viscosity = 0.029 cp @ 2100 psia and 200 oF Gas Z factor = 0.8 @ 2100 psia and 200 oF Dead Oil Viscosity Measurements Viscosity = 1.5 cp @ 200 oF and 10 cp @ 60 oF. Use the following PVT Correlations :

Property Correlation Solution gas Lasater

OFVF at / below bubble point Standing Live oil viscosity Chew & Connally

Undersaturated oil viscosity Vasquez & Beggs Gas Z Standing

Result


Flowing BHP ? Flowing WHT ?

Method :

Enter the calibration data above into the Black Oil fluid model Run Operations > Pressure / Temperature Profile

o Enter Given Outlet Pressure (Calculate Liquid Rate). Inspect plot and text output to determine answers.

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Exercise 4. Well Model Flow Correlation Matching The following FGS survey (flowing pressure 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 bottom hole pressure ?. Well test & FGS Data Wellhead pressure 300 psia Wellhead temperature 130 oF Liquid Production Rate 6500 stb/d GOR 500 scf/stb Water cut 10 %

Flowing Pressure Survey Depth MD (ft) Pressure (psia)

0 300 1500 560 2500 690 4500 1200 6500 1760 7500 2070 8500 2360

Result

Wellhead Pressure 300 psia

Vertical Correlation ? Flowing BHP ?

Method :

Go to Operations > Flow Correlation Matching. Enter the measured depth and pressure data.

o Enter Given Outlet Pressure (Wellhead) and Liquid Rate, and select the Inlet Pressure as the calculated variable.

Select Flow Correlations (eg. Beggs & Brill Revised, Duns & Ros, Hagedorn & Brown). Note : Now change the selected model vertical flow correlation in the Setup > Flow Correlations menu.

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Exercise 5. Well Model IPR Matching Given the correct flow correlation chosen in Exercise 4, find the correct IPR (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. Note : Make sure you have changed the selected model vertical flow correlation in the Setup > Flow Correlations menu after Exercise 4.

Result

Wellhead Pressure 300 psia PI ?

AOFP ?

Method A:

Go to Operations > System Analysis. Enter Outlet Pressure (calculate Liquid Rate).

o For X-axis variable, enter PI values of 5,6,7,8,9and 10. o Leave Sensitivity Variable 1 empty.

Generate a plot of calculated liquid rate vs. PI. Identify the PI which gives match to the measured production rate.

Method B:

Go to Operations > Nodal Analysis. Enter Outlet Pressure.

o For Inflow Sensitivity, enter PI values of 5,6,7and 8. o Leave Outflow Sensitivity empty.

Generate Nodal Analysis plot. Identify the PI which gives correct solution point. Determine AOFP from Inflow (Nodal Analysis) plot.

Note : Now change the completion PI in the well model.

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Exercise 6. Well Model Sensitivity Analysis

Given the current wellhead pressure and reservoir pressure, determine at what water cut will the well die ?.

Note : Make sure you have changed the completion PI in the well model after

Exercise 5.

Result

Wellhead Pressure 300 psia

Water Cut ?

Method A:


o For X-axis variable, enter water cut values of 30%, 40%, 50%, 60%, 70%. o Leave Sensitivity Variable 1 empty.

Generate a plot of calculated liquid rate vs. water cut. Identify the water cut at which the calculated production rate drops to zero.

Method B:

Go to Operations > Nodal Analysis. Enter Outlet Pressure.

o Leave Inflow Sensitivity empty. o For Outflow Sensitivity, enter water cut values of 30%, 40%, 50%, 60%, 70%.

Generate Nodal Analysis plot. Identify the water cut for which there is no solution point.

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Exercise 7. Well Model System Analysis, Artificial Lift.

Examine how this well responds to Gas Lift. Introduce a Gas Lift Injection point at 8000 ft MD in the tubing equipment. How does the well respond to gas lift when the water cut is at 10 % and at 60 % ?. Determine the following liquid production rates for the following gas lift rates and water cut values ?. Assume wellhead pressure = 300 psia. Injection gas SG = 0.6 Injection gas surface temperature = 100 oF.

Result

Water cut = 10% Water cut = 60% Gas Lift Rate

(mmscf/d) Liq. Prod. Rate

(stb/d) Liq. Prod. Rate

(stb/d) 0.5 1

1.5 2

Method :

Add a Gas Lift Injection point in the tubing description (enter a default gas lift rate of 1mmscf/d).


o For X-axis variable, enter gas lift rates of 0, 0.2, 0.5, 1, 1.5, 2 (mmscf/d). o For Sensitivity Variable 1 enter water cut values of 10% and 60%.

Generate a plot of calculated liquid rate vs. gas lift rate for different water cuts. Inspect plot and text output to determine answers.

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Case Study 2 - Well Performance Modelling - Nodal Analysis

Problem Outline :

An oil well is currently producing below capacity. Options for increasing production include stimulation (acidizing and/or hydraulic fracture) and gas lift. Nodal Analysis will be performed to determine the relative benefits of these courses of action.

Exercise 1. Well Model Given the following basic data, construct a well model and perform a Nodal Analysis operation to find the flowing bottom hole pressure and production rate for the given wellhead pressure. Assume default flow correlations (Beggs & Brill Revised).

Assume default PVT correlations and no calibration data.

Black Oil PVT Data Watercut 40 % GOR 500 scf/STB Gas SG 0.71 Water SG 1.1 API 26 Bubble Point Calibration Data: Pressure 2000 psia Temperature 170 F Saturated Gas 500 scf/STB

Wellbore Data Surface Temperature 60 F Kick-off MD 2000 ft Perf MD 7500 ft Perf TD 7000 ft Reservoir Temp 170 F Tubing ID 2.992 in

Completion Data Completion Type : Pseudo steady state.

o Basis of IPR : Liquid. Use Vogel correction below the bubble point.

Pressure 3700 psia Temperature 170 F Permeability 50 md Thickness 30 ft Wellbore diameter 6 in Drainage radius 2000 ft Skin (mechanical) 3 Use calculated rate dependent skin Schlumberger


Method :

Construct Model and enter above data. Place Nodal Analysis icon at bottom hole. Run Operations > Nodal Analysis

o Enter Given Outlet Pressure. o Leave Max Rate empty (PIPESIM will calculate rates upto the AOFP) o Leave Inflow Sensitivity and Outflow Sensitivity empty.

Inspect plot to determine answers.

Result


Flowing BHP ?

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Exercise 2. Nodal Analysis Sensitivity to Stimulation & Gas Lift. Investigate the increase in production through stimulation and gas lift using nodal analysis.

a) Assume that the current skin of 3 can be reduced to 0 if the well is acidized and 2 if hydraulically fractured.

b) 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?

Outlet Pressure = 250 psia.

Oil Production Rates (STBD) Beggs-Brill:

Gas Lift (mmscf/d) Completion 0 (base) 0.5 1.0 2.0

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

Method :

Add a Gas Lift Injection point at 4500. (Assume default gas lit rate = 0). Run Operations > Nodal Analysis

o Enter Given Outlet Pressure. o Leave Max Rate empty (PIPESIM will calculate rates upto the AOFP) o For Inflow Sensitivity, enter skin values of 3,0,and -2. o For Outflow Sensitivity, enter gas lift rate values of 0,0.5,1.0and 2.0 mmscf/d.

Generate Nodal Analysis plot. Inspect plot to determine answers.

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Exercise 3. Nodal Analysis Sensitivity to Flow Correlation. While the Beggs & Brill correlation is widely used and is the default correlation for PIPESIM, it is useful to see the results when using alternative correlations. Unlike the Beggs & Brill correlation, Mukherjee & Brill accounts for effects of viscosity, which for this case may be significant because the oil is relatively heavy (26 API). Repeat the nodal analysis using Mukherjee & Brill vertical flow correlation.

Outlet Pressure = 250 psia.

Oil Production Rates (STBD) Mukherjee & Brill:

Gas Lift (mmscf/d) Completion 0 (base) 0.5 1.0 2.0

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

Method :

Change the vertical flow correlation to Mukherjee & Brill. Run Operations > Nodal Analysis

o Enter Given Outlet Pressure. o Leave Max Rate empty (PIPESIM will calculate rates upto the AOFP) o For Inflow Sensitivity, enter skin values of 3,0,and -2. o For Outflow Sensitivity, enter gas lift rate values of 0,0.5,1.0and 2.0 mmscf/d.

Generate Nodal Analysis plot. Inspect plot to determine answers.

The discrepancy between Beggs & Brill and Mukherjee & 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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Case Study 3 - Gas well Performance using a Compositional Fluid Model

A gas well has been drilled. DST data is available as well as FGS data from a completed neighbouring identical well. The objective here is to construct a model of the well using the compositional editor, and then perform various PIPESIM operations on the well to determine certain characteristics.

Exercise 1: Simple Well Model The first exercise is to construct a gas well model.

Use the following data for the reservoir and completion:

Reservoir Data

Static Pres 4,600 psia Reservoir Temp. 280oF Gas PI 2 x 10-6 MMSCFD/d/psi2

Completion Data Mid perf TVD 11,000 ft Mid perf MD 11,000ft Ambient temp 30oF EOT MD 10,950 ft Tubing ID 3.476 Casing ID 8.681

Fluid Model: Enter the PVT data as per the tables below.

Tasks:

1. Determine the water content at saturation at reservoir conditions.

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2. Generate a phase envelope using the water saturated composition.

3. Determine the flow-rate, bottom-hole flowing pressure, bottom-hole flowing temperature and well-head temperature given a well-head pressure of 800 psia.

Method:

1. To determine the water content at saturation, enter the given data into the compositional table in the composition editor, from the Setup Menu. Add some water (ie 20 moles). Go to the Single point flash tab, click the PT radio button, enter the given reservoir P/T, and read the water content for the vapour fraction from the screen. Enter this value and the re-normalised hydrocarbon composition back into the compositional editors main screen.

2. 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.

3. 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 inflow section, and the given tubing information in the tubing section.

Run a Pressure/Temperature Profile from the Operations drop-down menu using an outlet pressure of 800 psia. The flow-rate, pressures and temperatures can be found in the Summary File, from the Reports drop-down menu.

Compositional PVT Data (no water)

Composition (%) C1 78 C2 8 C3 3.5 iC4 1.2 nC4 1.5 iC5 .8 nC5 .5 C6 .5 C7+ 6

Stock tank Properties

C7+ BP 214oF C7+ MW 115 C7+ SG 0.683

Flow Correlation Select Duns & Ros vertical flow correlation Results:

Pres = 4,600 psia, Tres = 280oF % H2O @ saturation

Po = 800 psia

QG Pwf BHT WHT

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Exercise 2: Calibrate Inflow Model The Back Pressure equation can be used to determine the IPR of a Pseudo Steady State gas well using test data. In this exercise, we will use the Back Pressure Inflow model to represent the inflow relationship.

Tasks:

1. Using the below DST data, calculate the C and n parameters.

2. Determine the flow-rate, bottom-hole flowing pressure, bottom-hole flowing temperature and well-head temperature using the new inflow model.

Method:

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 as in Exercise 1 Task 3. DST data for Back Pressure Equation

Q (MMSCFD) Gas P (psia) wf9.728 3000

11.928 2500 14.336 1800

Results:

Back Pressure Equation Parameter C Parameter n

Po = 800 psia

QG Pwf BHT WHT

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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 depth versus erosional velocity ratio from the profile plot for all tubing sizes.

3. Determine the flow-rate, bottom-hole flowing pressure, bottom-hole flowing temperature and well-head temperature for 3.958 ID tubing at an outlet pressure of 800 psia. What is the erosional velocity ratio for this tubing at the wellhead. Continue using this tubing size in all subsequent exercises.

Method:

1. Use the Nodal Analysis option from the Operations drop-down menu. You will need to enter a Nodal Analysis icon if you have not done so already. Enter in 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 by selecting the Series option from the toolbar.

3. Look in the Summary File for the flow-rate, bottom-hole flowing pressure, bottom-hole flowing temperature and well-head temperature for the 3.958 tubing.

Results:

Po = 800 psia QG Pwf BHT WHT

Well-head, 3.958 tubing

Erosional velocity ratio

Exercise 4: System Analysis System Analysis can be used to model the gas rate vs reservoir pressure for the different tubing sizes (amongst other things).

Task:

Generate a chart to show the variation of gas rate with the reservoir pressure for the different tubing sizes. Use a wellhead pressure of 800 psia. Use reservoir pressures of 4600, 4200, 3800, 3400 psia.

Method:

Select System Analysis from the Operations drop-down menu. Use the Reservoir Pressure as the x-axis variable and tubing ID as the sensitivity variable. Run the model and view the resultant plot.

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Exercise 5: Flow-line and Choke Add a flow-line and a choke to the model using the below data.

Flow-line Details

Flow-line length (ft) 300 Flow-line ID 6 Pipe Roughness (in) 0.001 Wall thickness (in) Ambient Temp (F)

0.5 60

Note: enter any choke size you wish as this will be overridden by the sensitivity variable

Task:

Using the mechanistic choke model, determine the choke size (mechanistic choke model) 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. Ensure that the tubing ID is 3.958.

Method:

The operation Pressure/Temperature Profiles can be used for this task. Using choke size as the sensitivity (a good estimate would be from 1 to 3 in increments of ), look in the Summary File to find the choke size that gives the correct outlet pressure (710 psia). Note that the wellhead pressure will remain at 800 psia. Use a flow-rate of 15.7 MMSCFD if unable to get results for Exercise 3. 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: 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. Reactivate flowline and choke. Ensure choke bean size is 2.

Tasks:

1. Save the model under a new name, then enter the heavier composition with higher liquid fraction. Determine the water content at saturation at the lower reservoir pressure, then proceed with the following tasks and exercises.

2. Using the FGS data determine the best vertical multi-phase flow correlation for use in this well. Choose from Beggs & Brill Revised, Duns & Ros, and Hagedorn & 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.

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.

Method:

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 Operations menu, select Flow Correlation Matching. Enter in the FGS data, check the correlations to be used, then click on the Run Model button. Look in the Output File for the mean arithmetic and absolute differences.

3. Run a Pressure/Temperature Profile Operation using an inlet pressure of 4300 psia, then look in Output File for actual liquid flows

Compositional PVT Data (higher condensate fraction)

Composition (%) C1 75 C2 6 C3 3 iC4 1 nC4 1 iC5 1 nC5 .5 C6 .5 C7+ 12

FGS Data

Depth (ft) Pressure (psia)

3,000 950 6,000 1,095 9,000 1,250 11,000 1,365

Producing gas rate during FGS = 13.4 MMSCFD Wellhead Pressure during FGS = 800 psia

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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)

Exercise 7: Liquid Hold-up fraction and Flow Regime Map Tasks:

1. Determine the liquid volume fraction and hold-up fraction at the bottom of the well, at the top of the well, and at the end of the flow-line.

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.

Method:

1. Re-run the Pressure/Temperature Profile Operation as performed in Exercise 6, Task 3. Look in Auxiliary Output Page at the bottom of the Output File.

2. Add the report icon at the end of the flow-line and select Flow Map. Re-run the model. 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 @ bottom-hole xVL @ WH xVL @ end flow-line Flow regime end FL

Liquid Hold-up Fraction, Po = 710 psia

xHL @ bottom-hole xHL @ WH xHL @ end flow-line

Note: xVL = liquid volume fraction xHL = liquid hold-up fraction

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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?

Method:

1. Select phase envelope in the report icon, run the Pressure/Temperature Profile from Exercise 7, Task 2, then change the axes on profile plot to Pressure vs Temperature.

2. From the generated plot, if the operating line crosses the hydrate formation line, hydrate formation will occur.

Results:

Ambient Temp = 30oF Hydrate formation?

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.

Tasks:

1. Calculate the well-bore pressure drop across the formation, tubing, choke and flow-line for a gas flow-rate of 13 MMSCFD

Method:

1. Run a Pressure/Temperature Profile operation using a gas rate of 13 MMSCFD. Check the appropriate check-box so that it calculates the outlet pressure for the given gas rate.

Results:

Heavier composition P Reservoir P Tubing P Choke P Flow-line

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Exercise 10: Rigorous Flashing To reduce solving 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 Flashing section of the Setup 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 solving time, which is significantly longer. Task:

Repeat Exercises 6 (Task 3) and 8 (tasks 1 and 2) using the rigorous flash option. Compare the results. Why are there any differences?

Po = 710 psia QG Pwf QL @ mid-perfs (act) QL @ outlet (act)

Ambient Temp = 30oF

Hydrate formation?

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Case Study 4 ESP Selection / Design This case study will demonstrate the following workflow :

1. Analyse a wells 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. 5. Evaluate the pump performance with varying well conditions.

Exercise 1. Well Model Nodal Analysis Given the following basic data, construct a well model and perform a Nodal Analysis at bottom hole. Assume no pump in the well at this stage. Confirm that the well will not flow naturally. Black Oil PVT Data Water Cut = 90% GOR = 80 m3/m3 (449scf/stb) Oil Gravity = 876 kg/m3 (30o API) Gas Gravity = 0.984 Water SG = 1.026 Bubble Point = 152.8 bara (2216 psia) at 142.2 oC (288 oF) Formation Volume Factor = 1.33 rb/stb at bubble point. Oil Viscosity = 0.54 cp at bubble point Wellbore Data Vertical well Perforation depth 2863m (9393 ft) Flow is in : 41/2 (3.958 ID) tubing from surface to 2500 m 95/8 (8.681 ID) casing from 2500m to 2863 m * * (note the pump setting depth in the next exercise will be at 2500 m) Surface Ambient Temperature = 20 oC (68 oF) Reservoir & Inflow Data Reservoir Pressure = 250 bara (3625 psia) Reservoir Temperature = 142.2 oC (288 oF) Productivity Index = 28.5 m3/d/bar (12.4 stb/d/psi) Use nonlinear correction below bubble point Use Hagedorn & Brown Vertical Flow Correlation. Method :

Construct Well Model and enter above data. Place Nodal Analysis icon at bottom hole. Run Operations > Nodal Analysis

o Enter Given Outlet Pressure. o Leave Max Rate empty (PIPESIM will calculate rates upto the AOFP) o Leave Inflow Sensitivity and Outflow Sensitivity empty.

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Inspect plot.

Exercise 2. Pump Selection / Design 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 (flowrate) range for

varaible frequency between 50 to 70 Hz. 4. From the Pump Performance Plot, determine at what flowrate the pump suction pressure falls

below the bubble point. Design Conditions : Design Production Rate = 1600 sm3/d Design Wellhead (Outlet) Pressure = 8 barg Pump setting depth = 2500 m (i.e. within the 95/8 (8.681 ID) casing Design Frequency = 60 Hz (assume no gas separator present, no viscosity correction and a head factor of 1).

Result

1). No. of stages (HN13000) ? 2). Motor HP required ? 3). Flowrate range for 50 70 Hz. ? 4). Flowrate for Psuction < Pbubble point ?

Method :

Go to Design > ESP Design in top menu. Enter the Pump Design Data given. Click the Select Pump button. (This will filter the pump database for all pumps which meet

the design criteria). Select Manufacturer to Reda. Highlight and select the Reda HN13000 pump.

Click on the Calculate button in Pump Parameters section. (This will calculate the pump

parameters). Read the No. of stages required. Read the motor HP required.

Click on the Pump Performance Plot at the bottom of the Pump Parameters section. Read off the flowrate at the intersection of the Well System Curve and the 50Hz and 70 Hz

pump curves. Read off the intersection of the pump suction pressure curve and the bubble point curve.

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Exercise 3. Pump performance with varying well conditions Now install the selected pump in your well model by clicking on the Install Pump button at the bottom of the Pump Parameters section. Determine the flowrate of the well when the water cut increases to to 95% (assuming the same number of stages and design speed).

Result

Production Rate (95% wcut) ? Method :

Install the pump in your well model by clicking on the Install Pump button at the bottom of the Pump Parameters section.

Go to Operations > System Analysis. Enter Outlet Pressure (i.e. select calculated variable = Liquid Rate).

o For X-axis variable, enter watercut values of 90 and 95 % o Leave Sensitivity Variable 1 empty.

Generate a plot of calculated liquid rate vs. watercut. Read off the production rate for water cut 95%..

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Case Study 5 Pipeline and Facilities (Compositional Fluid model) Overview Five condensate wells are to produce 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 and the system will be designed to accommodate between 8,000 STBD (turndown case) and 16,000 STBD should the wells produce more than expected. The engineer is asked to perform the following tasks:

1) Develop a compositional model of the hydrocarbon phases 2) Size the subsea tieback line and riser 3) Screen the for severe slugging at riser base 4) Determine the pipeline insulation requirement 5) Size a slug catcher

Exercise 1: Develop the compositional PVT model based on the following data:

Pure Hydrocarbon Components Component Moles

Methane 75 Ethane 6

Propane 3 Isobutane 1

Butane 1 Isopentane 1

Pentane 0.5 Hexane 0.5

Petroleum Fraction

Name Boiling Point (F)

Molecular Weight

Specific Gravity

Moles

C7+ 214 115 0.683 12 Aqueous Component

Component Volume ratio (%bbl/bbl)

Water 10

Method:

1) Use the menu to enter the pure components given at the end of the case study. 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 characterise 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 press the "Add to composition>>" button.

3) Return to the "Component Selection" tab and enter the number of moles for C7+. 4) Generate the hydrocarbon phase envelope by pressing the "Phase Envelope" button.

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Exercise 2: Size 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 errosional velocity is not exceeded. First, build the physical model as shown below with the following data:

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Manifold

Outlet pressure 1500 psia Temperature 176 F Subsea tieback Rate of undulations 0'/1000' (not hilly) Horizontal Distance 6 miles Elevational difference 0' (horizontal) Available ID's 9,10,11 " Heat Transfer: Ambient temperature 38 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 Burial depth -5.5 " (not burried) Ground conductivity 1.5 Btu/hr/ft/F Riser (use detailed profile) Horizontal Distance 0' (vertical pipe) Elevational difference 1600' Available ID's 9,10,11 " Heat Transfer: Ambient temperature @ riser base 38 F Ambient temperature @ 1200' 42 F Ambient temperature @ 800' 48 F Ambient temperature @ 400' 56 F Ambient temperature @ topsides 68 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

Method:

1) Perform a System Analysis with the minimum, maximum and expected flow rates as the x-axis variable, and the available IDs for the flowline and riser as Change in Step sensitivity variables.

2) Determine the minimum flowline ID that satisfies the separator pressure requirement for the maximum flow rate.

3) Change the y-axis to display Errosional Velocity Ratio and check to ensure that the selected flowline ID does not exceed an errosional velocity ratio of 1.0.

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Result

Pipeline and Riser ID: Max. errosional velocity ratio

for selected ID Min. Separator pressure for

selected ID Max. separator pressure for

selected ID

Exercise 3: Check for Severe Slugging 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: 1. The presence a long slightly downward inclined pipeline prior to the riser. 2. Fluid flowing in the "stratified" or "segregated" flow regime (as opposed to the usual "slug" or

"intermittent" flow regime). 3. A slug number (PI-SS) of lower than 1.0. Method:

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 STBD 14000 STBD 16000 STBD

PI-SS number at riser base

Flow pattern at riser base

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Exercise 4: Select tieback insulation thickness Using the tieback/riser ID selected above, determine the thickness of insulation required for both the flowline and riser such that the temperature of the fluid does not come within 10F of the Hydrate curve for all possible flow rates. Method:

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 flowrates as the sensitivity variables.

2) Use the Series menu on the resulting plot to change the x-axis to Temperature. 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

Req. Insulation thickness Exercise 5: Size Slug Catcher Determine the required size of the slug catcher based on the largest of following criteria multiplied by a safety factor of 1.2. 1. The requirement to handle the largest slugs envisaged (chosen to be statistically the 1/1000

population slug size). 2. The requirement to handle liquid swept in front of a pig. Method:

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 with Report Tool selections appended to the bottom of each sensitivity output. For each sensitivity, scroll down to this section and read the reported 1/1000 slug volume and Total Sphere Generated Liquid Volume So Far.

Result 8000 STBD 14000 STBD 16000 STBD

1/1000 slug volume (ft3)

Sphere generated liquid volume (ft3)

Design volume for slug catcher (ft3)

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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 liquidflows 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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Case Study 6 Gas Lift Design, New Mandrel spacing: This case study will demonstrate the following workflow:

1. Analyse a wells requirement for artificial lift. 2. Perform a Gas Lift Design for the well using the IPO Surface Close method.

Exercise 1. Well Model Nodal Analysis: Given the following basic data, construct a well model and perform a Nodal Analysis at bottom hole. Assume no gas lift valves in the well at this stage. Confirm that the well will not flow naturally. Assume wellhead pressure = 110 psig. Black Oil PVT Data Water Cut = 55% GOR = 300 scf/stb Oil Gravity = 32o API Gas Gravity = 0.64 Water SG = 1.05 Flow Correlation Select Hagedorn and Brown Vertical Flow correlation. Wellbore Data Vertical well: MD (ft) TVD (ft) 0 0 7550 7550 Perforation depth 7550 MD Geothermal Survey: MD (ft) Ambient (F) U Value (Btu/hr/ft2/F) Temp 0 50 2 7550 175 2 Flow is in: 2 7/8 (2.441 ID) tubing from surface to 7500 ft 7 (6.184 ID) casing from 7500 ft to 7550ft Reservoir & Inflow Data Reservoir Pressure = 2800 psig Reservoir Temperature = 175 oF Productivity Index = 2.5 stb/d/psi Use Vogel below bubble point Method:

Construct Well Model and enter above data. Place Nodal Analysis icon at bottom hole.

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Run Operations > Nodal Analysis o Enter Given Outlet Pressure. o Leave Max Rate empty (PIPESIM will calculate rates up to the AOFP) o Leave Inflow Sensitivity and Outflow Sensitivity empty.

Inspect plot.

Exercise 2: Lift Gas Response Using the Lift Gas Response operation, determine the gas lift rate that will be used for the design. Use sensitivity values 0, 0.1, 0.2, 0.3, 0.5, 0.7, 1, 2, 3, 5 mmscf/d for the gas lift rate. Use sensitivity values of 150 and 250 psi for the Minimum injection gas P (to investigate its effect on injection depth). Use an injection gas surface pressure of 1000 psig and assume an injection gas surface temperature of 80 F. Method:

Run the Lift Gas Response operation in the Artificial lift menu, Gas lift submenu.

Exercise 3: Gas Lift Design 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: Design Spacing: New Spacing. Design Method: IPO-Surface Close. Top Valve Location: Assume Liquid to Surface. Manufacturer: SLB (Camco) Type: IPO Size: 1 (Tubing size 2 7/8 < 3 ) Series: BK-1. Min Port Diameter: None. Unloading Temperature: Default (Unloading) Production Pressure Curve: Production Pressure Model. Design Parameters: Kickoff Pressure: 1000 psig. Available Injection Pressure: 1000 psig. Unloading Prod. Pressure: 110 psig. Operating Prod. Pressure 110 psig. Target Injection Gas Flowrate: 1.25 mmscf/d. Injection gas Surface Temp: 80 F. Inj Gas Specific Gravity: 0.64. Unloading Gradient: 0.465 psi/ft. Minimum Valve Spacing: Calculated.

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Minimum Valve Inj DP: 150 psi Bracketing Options: Not selected. Safety Factors: Surface Close Pressure Drop Between Valves: 15 psi. Locating DP at Valve Location: 50 psi. Transfer Factor: 0. Place Orifice at operating valve location: Yes. Discharge Coefficient for Orifice: 0.865

Result

Valve Depth

Valve Series

Port Size

Ptro Open Pres @ Surface

Close Pres @ Surface

Gas Rate (Unloading)

Unloading Liq Rate

Max Valve Throughput

Valve Temp

Injection Pressure Drop

Cd

Method:

Go to Design > Gas Lift Design in top menu. Enter the Gas Lift Design Data given.

Click on Perform Design.

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Case Study 7 Gas Lift Design, Current Mandrel spacing: This case study will demonstrate the following workflow:

1. Install a Gas Lift Valve system in the tubing. 2. 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) 3. Perform a Gas Lift response operation to produce a graph of oil rate vs. lift gas rate. 4. Design the gas lift system using the current mandrel spacing.

Exercise 1: Installing a Gas Lift valve system, Deepest Injection Point Operation: Open the model created during the previous case study. Insert the following Gas lift valve system into the tubing user form. Equipment MD Properties Label Gas Lift Valve 1500 IPO-1/8 BK-1 Gas Lift Valve 2700 IPO-1/4 BK-1 Gas Lift Valve 3600 IPO-5/16 BK-1 Gas Lift Valve 4200 IPO-5/16 BK-1 Gas Lift Valve 4700 IPO-5/16 BK-1 Gas Lift Valve 5100 IPO-5/16 BK-1 Method: -Insert the spacing shown above in the tubing user form (in the down hole equipment tab). -Perform a Deepest Injection Point operation using a lift gas rate of 1.25 mmscf/d and an injection pressure or 1000psig.

Exercise 2: Generate Gas lift response curves

Perform a Lift Gas 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 of 0-0,1-0,2-0,3-0,5-0,7-1-2-3-5 mmscf/d. Method: -In the Lift Gas Response user form select injection at valve depth only.

Exercise 3: Design the gas lift system using the current mandrel spacing Given the design conditions (Identical to case study 5), and the current mandrel spacing perform the gas lift design. Method: -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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Part 3: Network Modeling Tutorials

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Network Tutorial 1: Looped Gathering Network Overview The deliverability of a production network is to be established. The network connects three producing gas wells in a looped gathering system and delivers commingled product to a single delivery point. The engineer is asked to perform the following tasks:- - Build a model of the network. - Specify the network boundary conditions. - Solve the network and establish the deliverability. The engineering data available is given at the end of this case study.

Step 1. Build a Model of the Network The following steps are to be carried out: - Enter the engineering data for the first well. - Copy the data to wells 2 and 3. - Modify the data for well 3. - Specify the composition at each production well. - Connect the network together. - Define the engineering data for each branch. Open PIPESIM and go to to open a new Network model and save this in your training directory (e.g. as file c:\training\pn01.bpn). Use the production well button to place Well 1 in the work area as shown below.

production well button production well Double click on Well_1 to reveal the components as shown below:-

Double click on the vertical completion to enter the inflow performance data. Enter a gas PI of 0.0004 mmscf/d/psi2. The reservoir temperature and pressure will be entered later when the network boundary conditions are specified (see page 2-5). Double click on the tubing and select Simple Model as the preferred tubing model. Define a vertical tubing with a wellhead MD of 0 and mid

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Mack Edward ShippenAdded to clarify remove when bug is fixed

Mack Edward Shippenchanged from TVD


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 that the essential data fields are shown in red outline (if the fields are not outlined, then data entry in these fields is optional). Close the view of Well 1 to return to the network view. Select "Well_1" and using the commands copy "Well_1" to "Well_2" and "Well_3". Position the new wells as shown below:-

You will see that Wells 2 and 3 have adopted the data of Well 1. Double click on Well 3 and modify the completion and tubing data. Double click on the vertical completion to enter the inflow performance data. Enter a gas PI of 0.0005 mmscf/d/psi2. Double click on the tubing, and define a vertical tubing with a wellhead TVD of 0 and mid perforations TVD and MD of 4900 ft. The ambient temperatures are 140 F at mid perforations and 60 F at the wellhead. The tubing has an I.D. of 2.4". Close the view of Well 3 to return to the network view. The next step is to define the compositions at the production wells. Wells 1 & 2 are producing from the same reservoir and 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 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 single branch model case study 5 and can be imported. First save the current network model. Open the single branch case study 5 (e.g. c:\training\ps05.bps). Use the menu and the export button to export the composition to a file called "comp1.pvt". Now close the single branch model case study 5. In the network model, use the menu and the import button to import comp1.pvt as the global composition. Click the right mouse button over Well 3, select fluid model and modify the composition to be locally defined as given at the end of this case study. The import function can be used again. Now position the sink and some junction nodes. Note that holding down the "Shift" key whilst placing junction nodes allows multiple placement, you should release the "Shift" key before the final placement. The network should now look like this:

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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

Double click on the arrow in the centre of "B1" to enter data for that branch. Now double click on the flowline to enter the following data:- Rate of undulations: 10/100

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