81059988 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 User’s 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 º API). Repeat the nodal analysis using Mukherjee & Brill vertical flow correlation.


Oil Production Rates (STBD)– Mukherjee & Brill:


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 editor’s 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 ½”), 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 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. 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 <setup/compositional...> 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 ºF 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 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 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 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

Method:

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 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 10ºF 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”.


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 well’s 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 it’s 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 ½) 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 <file/new> 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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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 <edit/copy> <edit/paste> 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 <setup/compositional...> 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 <setup/compositional...> 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: 10/1000 Horizontal distance: 30,000 ft Elevation difference: 0 ft Inner diameter: 6" Wall thickness: 0.5" Roughness: 0.001" Ambient temperature: 60 °F Close the "B1" window to return to the network view. As the looped gathering lines are all identical, the data for branch "B1" should be propagated to the other looped gathering lines. Select "B1" by clicking on the arrow in the middle of the branch and using the commands <edit/copy> <edit/paste> copy "B1" to "B2", "B3", and "B4". Position the new branches as shown below:

In order to reconnect a pasted branch, first pick 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

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highlight box, and you will see that the mouse pointer changes to an "up arrow" shape (↑). This end of the branch can then be dragged and dropped onto a junction node. Now connect the wells to the adjacent junction node and connect "J_4" to the sink as shown below:

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 aftercooler with an outlet temperature of 120 °F and a delta P of 15 psi, and a flowline with the following properties:- Rate of undulations: 10/1000 Horizontal distance: 10,000 ft Elevation difference: 0 ft Inner diameter: 8" Wall thickness: 0.5" Roughness: 0.001" Ambient temperature: 60 °F The equipment is located at "J_4" as shown below:-

Note that you should use the connector tool to join the equipment together.

Task 2. Specify the Network Boundary Conditions First it is necessary to summarise the rules for specification of network boundary conditions. The network module solves the fluid pressures, temperatures, and flowrates 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.

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Boundary conditions: The fluid pressure, temperature, and flowrate 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 sinks and injection wells is always calculated by the network module. Rules for Pressures and Flowrates: There are two rules for specification of pressure and flowrate boundary conditions:- Rule 1 - Degrees of Freedom. The total number of flowrates, pressures and PQ curves specified must equal the total number of lone nodes. Rule 2 - At Least one Pressure. A least one pressure must be specified at one of the lone nodes. All unspecified pressures and flowrates are calculated by the network module. In this case study, the above rules will be satisfied by doing the following - Specify all the fluid inlet temperatures - Specify all the fluid inlet pressures and the delivery pressure. Use the <Setup/boundary conditions> menu to specify the boundary conditions below:-

Node Pressure Temperature Well_1 2900 psia 130 °F Well_2 2900 psia 130 °F Well_3 3100 psia 140 °F Sink_1 800 psia (calculated variable)

Note that all of the flowrates will be calculated by the network module. It is also necessary to enter these values via the well view.

Task 3. 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 = I(P - Pave.)/Pave. x 100%I

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 flowrate into and the total mass flowrate out of a node are averaged. The tolerance is calculated from the equation:-

Ftol = I(Tot. mass flowrate in - Tot. mass flowrate ave.)/Tot. mass flowrate ave. x 100%I

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. Use the <setup/options/network iterations> menu to set the network tolerance to 1%.

Save the model, and then press the run button . When the network has solved you should get the message "pn01 - Finished OK". Press the "OK" button.

Press the report tool button and you will see that the sink gas flowrate is 41.55 mmscf/d.

More comprehensive tabular reporting is available using the summary file button . Select the flow route from "Well_3", branch "B3" and branch "B5". Hold the "Shift" key down in order to

effect a multiple selection. Then press the profile plot button . The following pressure profile for these three branches should be obtained. The effect of the compressor at "J_4" on the system pressure can be seen:-

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Data Available Layout:- The network is laid out as shown below:-

Completion and Tubing Data:-

Wells 1 & 2 Well 3 Gas PI 0.0004 mmscf/d/psi2 0.0005 mmscf/d/psi2

Wellhead TVD 0 0 Mid Perforations TVD 4500 ft 4900 ft Mid Perforations MD 4500 ft 4900 ft

Tubing I.D. 2.4" 2.4" Wellhead Ambient Temperature 60 °F 60 °F

Mid Perforations Ambient Temperature 130 °F 140 °F Pure Hydrocarbon Components (Wells 1 & 2):-

Component Moles Methane 75 Ethane 6

Propane 3 Isobutane 1

Butane 1 Isopentane 1


Petroleum Fraction (Wells 1 & 2):-


Molecular Weight Specific Gravity Moles

C7+ 214 115 0.683 12 Aqueous Component (Wells 1 & 2):-

Component Volume ratio (%bbl/bbl) Water 10

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Pure Hydrocarbon Components (Well 3):- Component Moles

Methane 73 Ethane 7

Propane 4 Isobutane 1.5

Butane 1.5 Isopentane 1.5


Petroleum Fraction (Wells 3):-


Molecular Weight Specific Gravity Moles

C7+ 214 115 0.683 10.5 Aqueous Component (Well 3):-

Component Volume ratio (%bbl/bbl) Water 5

Data for Looped Gathering Lines (B1, B2, B3, and B4):-

Rate of undulations 10/1000 Horizontal distance 30,000 ft Elevation difference 0 ft

Inner diameter 6" Wall thickness 0.5"

Roughness 0.001" Ambient temperature 60 °F

Overall heat transfer coefficient 0.2 Btu/hr/ft2/°F Data for Deliver Line (B5):-

Separator type Liquid Separator efficiency 100%

Compressor differential pressure 400 psi Compressor efficiency 70%

Aftercooler outlet temperature 120 °F Aftercooler delta P 15 psi

Flowline Rate of undulations 10/1000 Flowline Horizontal distance 10,000 ft Flowline Elevation difference 0 ft

Flowline Inner diameter 8" Flowline Wall thickness 0.5"

Flowline Roughness 0.001" Flowline Ambient temperature 60 °F

Flowline Overall heat transfer coefficient 0.2 Btu/hr/ft2/°F Boundary Conditions:-

Node Pressure Temperature Well_1 2900 psia 130 °F Well_2 2900 psia 130 °F Well_3 3100 psia 140 °F Sink_1 800 psia (calculated variable)

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Network Tutorial 2: Gas Transmission Network Features Illustrated • Gas Transmission Network • Two phase, compositional fluid modelling • 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 flowrate and each produces a gas. Fluid properties are modelled using a compositional fluid model.

General Data Different compositional fluids are produced by the sources. The delivery pressure is fixed at 855 psia. 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 (Line4) to the main trunk line has a 960 mm inner diameter with no elevation difference. The parallel, 256,000 m flowline (Line5) to the main trunk line has a 1024 mm inner diameter with no elevation difference.

Flowline (Line2) 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 855 psia. 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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Figure 1 Case 2 Network Graphic

Fluid Data Laboratory analysis has shown the fluids from the two supplies to have different compositions. Right click on each Supply and select Fluid Model. Ensure that the Local Compositional button is checked and Select Edit Composition. Enter the fluids as specified below:

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 Env. button will plot the phase envelope of the fluid. Question 1 Determine the direction of flow in Line2, and the flowrate and fluid temperature at the delivery point. The objective is to determine the direction of flow in Line2 and the flowrate and temperature at the delivery point. Select Summary File from the Reports menu and scroll down to system summary section. This is shown below and you will see that Line2 is flowing in a forward direction (based on the initial flow direction - indicated by the arrow on the line) and that the flowrate and fluid temperature at the delivery point are 52 mmsm3/d and 20.2 oC respectively.

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Figure 3 Summary output

Question 2 Plot the pressure profiles for the 250 km parallel pipelines.

Holding the Shift key, select Line 4 and 5 and click on the Profile Plot Icon: This plot is shown in figure 2

Figure 2: Pressure profiles for the 250 km parallel lines. Question 3 Plot the temperature profiles for the 250 km parallel pipelines.

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In the Plot Window, Select Series and change Pressure to Temperature for the Y-axis This plot is shown in figure 3

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

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Network Tutorial 3: Water Injection System Features Illustrated: • Injection network • Single phase • 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 1 schematically presents the layout of the studied water injection system. A Global black oil model with 100% watercut and DOD of 62.43 lb/ft3 is used in this case study.

Figure 1 Water Injection System

The ESP can be added into the production well by selecting the ESP button (in Artificial Lift section) from the Tubing Details dialog that appears after double-clicking on the tubing in the Producer window.

General Data The fluid produced from the well (Producer) is a single phase black-oil with a watercut of 100%. The delivery pressures to each individual injection point are different. The ambient temperature for the entire network is 50°F.

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. Water is lifted from the production well by an ESP (Type: Centrilift, Model: IB700) with number of stages of 30 and at a speed of 3,600 rpm. The type of ESP can be specified by clicking on the Select ESP button in the Tubing Details dialog window.

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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.

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. Flowline 2 is 15000 ft in length with an ID of 6” and no elevation difference. It joins N2 to N3. Flowline 3 is 10000 ft in length with an ID of 6” and no elevation difference. It joins N2 to N4. Flowline 4 is 7000 ft in length with an ID of 4” and no elevation difference. It joins N2 to N5. All the flowlines are coated (heat transfer coefficient = 2 BTU/hr/ft2/F)

Delivery Sinks/Injection Wells All the delivery sinks are single injection wells with 1.995” ID tubing. Well_1 has a static pressure at 4400 psig and a temperature at 210°F. The injection well is at 7800 ft TVD and at 7800 ft MD. It delivers a total liquid flowrate of 2 STB/d/psi. Well_2 has a static pressure at 4500 psig and a temperature at 220°F. The injection well is at 7900 ft TVD and at 7900 ft MD. It delivers a total liquid flowrate of 4 STB/d/psi. Well_3 has a static pressure at 4400 psig and a temperature at 210°F. The injection well is at 7800 ft TVD and at 7800 ft MD. It delivers a total liquid flowrate of 6 STB/d/psi. Well_4 has a static pressure at 4500 psig and a temperature at 220°F. The injection well is at 7900 ft TVD and at 7900 ft MD. It delivers a total liquid flowrate of 8 STB/d/psi. Well_5 has a static pressure at 4400 psig and a temperature at 210°F. The injection well is at 7800 ft TVD and at 7800 ft MD. It delivers a total liquid flowrate of 3 STB/d/psi. Well_6 has a static pressure at 4500 psig and a temperature at 220°F. The injection well is at 7900 ft TVD and at 7900 ft MD. It delivers a total liquid flowrate of 5 STB/d/psi.

Fluid Data The fluid produced from the production well is a single phase blackoil (with 100% watercut) flow. Select Fluid Model under Setup and then Black Oil, click on the button of “Edit Black Oil Data” to specify the watercut and the dead oil density (DOD), the GOR is 0.0 scf/STB.

Local flow correlations are used to model the wells (both production and injection ones) and flowlines. All the local flow correlations have used Duns & Ros correlation for both vertical and horizontal multiphase flow calculations.

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.

Question 1: Use the Report Tool to summarize the results of interest

• Click on the Report Tool Icon • Select Clear • Click on the Producing Well and each of the injector wells • Select Config and remove all columns except Temperature, Pressure and Liquid Flow This is show in Table 1

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Table 1: Summary of Results

Question 2: Plot the pressure profiles for all injection wells. This is shown in figure 2.

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Figure 2 Pressure profiles for all injection wells

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Part 4 – FPT Tutorials

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FPT Tutorial 1: Compositional Tank & Look Up Tables Objectives: The objective of exercise 1 is to familiarize the user with the FPT interface by building and running a simple case study where the reservoir depletion model is a compositional tank. Exercise 1 is divided into 8 subsections as detailed below:

1. Build a simple surface network. (3 producers, 1 sink). 2. Build a compositional tank model. 3. Link the network model to the FPT model. 4. Map the wells from the reservoir to the network. 5. Enter some simple field planning events. 6. Solve the model. 7. Format and view a graphical output. 8. Format and view a Tabular output.

Build a Simple Surface Network:

• Use PIPESIM to create Network1.bpn in your training directory. The network is shown below:

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• Three wells are connected to this reservoir. One of the well as modeled in PIPESIM is shown

below:

• Well Data (use the Simple Model option in PIPESIM to model each well):

Mid Perfs Depth (Ft below sea bed)

Tubing ID (in)

Ambient T (F)

Gas PI (mmscf/d/psi2)

Res T (F)

Res P (psia)

Well 1: 3000 2 60 1e-5 250 4000 Well 2: 3000 2 60 1e-4 250 4000 Well 3: 3000 2 60 1e-3 250 4000

Note that all the wells in the PIPESIM network model should have no flow directional blocks. This is done by right clicking on the well in the network interface and selecting BLOCK: None.

• Main Flow line Data: These three wells connect to a single wellhead manifold on the seabed, which is at a depth of 1000 ft Subsea S.S. From this a horizontal flow line of 150000 ft length and 4 inch ID runs to the base of a riser of 5 inch ID that goes up 1000 ft to the sink.

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The Sink requires a minimum production pressure of 500 psia and should be able to handle the production from this reservoir. The surface ambient temperature is 60°F. The Flow line and riser system is modelled in PIPESIM as shown below:

• The initial composition of the reservoir can be taken as 88% methane, 10% ethane, and 2% propane.

• Create a compositional file called comp1.pvt in your training directory.

• Check that the model solves successfully by running it. (Gas rate at sink: 26.824 mmscf/d with

a network tolerance of 0.01 %)

• Use the FPT button within the PIPESIM network model to generate the necessary interface files.

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Build a Compositional Tank Model:

• Start FPT.

• Use Save-As to save the model as Exer1.fpt in your training directory.

• Select the Mode menu and choose Compositional Tank Models.

• Select the Reservoir button . The compositional tank model user form will appear.

• Enter the tank name: “tank1” and enter the following tank data:

• Link the reservoir composition to the file comp1.pvt created above.

OGIIP: 50,000 mmscf. Reservoir Pressure (datum): 4000 Psia. Reservoir Temp (datum): 250 F. Reservoir Top (Datum depth: sea bed) 2800 ft Initial OWC (Datum depth: sea bed) 3300 ft Datum depth of perforation: 3000 ft Aquifer Replacement: 30%

• The filled user form for “tank 1” is shown below:

Link the network

model to the FPT model.

• Use the Select Network Model(s) button to attach the network model Network1.bpn to the FPT model Exer1.FPT.

Map the wells to the tank model.

• Use the Well mapping button to map wells 1, 2, and 3 to tank 1. The user form is shown below:

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Enter some simple Field Planning Events.

Events Description:

• The simulation is to be run for 720 days in 60-day steps for the first 360 days and in 180 steps for the second 360 days.

• Initially wells 1 and 3 are on, well 2 being turned on 60 days later.

Coding the events with FPT:

• Input the field logic using the field planning events button .

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• Modify the initial timestep to 60 days. • Note that it is necessary to switch wells 1 and 3 on at time=0 because the default initial

condition of all wells is off.

Run the Model:

• Under build, advanced settings, tick Use NET restart file.

• Run the model by selecting the run button .

Format and view a Graphical Output:

Objectives:

• The objective is to produce a graph of the gas flow rate from each source and at the delivery for each time step.

Method:

• Once the simulation has finished, select the results viewer button .

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• Select plotting and plot for all wells and sinks. The graph is shown below.

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Format and View a Tabular output:

• Select the results viewer button . • Click on the ‘Tanks’ radio-button. • Select Tank 1 from the list box. • Click on Customise to access the customise output dialog. Select Tanks and a custom

summary number 1.

• Remove any existing output from the right hand list box. Select HCIP gas and pressure from the first window. Click on OK and go back to the main window.

• Click on Tank1 again and you should see two columns of data, HCIP gas vs. pressure. This

table is shown below.

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Reservoir Pressure Vs Cumulative Gas Production:

0500

10001500200025003000350040004500

0 5000 10000 15000 20000

Cumulative Gas Production(mmscf):

Pre

ssur

e (p

sia)


Exercise 2 Use of a Depletion table to model the reservoir: Objectives: The objective of exercise 2 is to modify the model developed in exercise 1 using a depletion table as an alternative to the tank method for modelling the reservoir. Exercise 2 is divided into 7 subsections as detailed below:

1. Save the FPT model with a different name. 2. Create a depletion table. 3. Set up the table as the reservoir depletion model. 4. Map the 3 wells to the table. 5. Solve the model. (Using the same field planning events as in Exercise 1) 6. Format and view a graphical output. 7. Format and view a Tabular output.

Save the FPT model with a different name.

• Open exer1.fpt and save this as exer2.fpt Create a depletion table:

• Select the Mode menu and choose Look-up tables:

• Select the Reservoir button . The look-up table user form will appear.

• Select the Cum. gas as the Independent Properties and Pressure as the Dependant Properties, the user form should look as follow:

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• Select Save table and save the table as bja1.tbl in your training directory.

• Click on Edit table and the following text editor should appear.

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• Enter the following data in the table. (These data could be pasted directly from an excel spreadsheet for example).

• Save the table clicking on the menu file submenu save in the text editor.

• Close the text editor. Set up the table as the reservoir depletion model.

• Click on load table in the look-up table user form the table should appear in the user form as shown below.

Map the Reservoir to the wells:

• Map this reservoir to the wells in the same way as you did for the tanks

Run the simulation

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• Run the simulation again.

Format and view the graphical output • The graphical results for exercise 2 are shown below.


Exercise 3: Field planning events logic and flow rate constrained wells:

Objectives: The objective of exercise 3 is to enter more complex conditional logic and adding flow rate constraints on the wells.

• The wells are going to be choked back if necessary so that they produce up to a maximum flow rate.

Exercise 3 is divided into 7 subsections as detailed below:

1. Save the FPT model with a different name.

• Well 2 is only going to be turned on if the production at the FPSO drops below a given value.

2. Input the flow rate constraint. 3. Modify the conditional logic. 4. Run the model. (Using the same field planning events as in Exercise 1) 5. Format and view a graphical output. 6. Format and view a Tabular output.

Save the FPT model with a different name:

• Open exer2.fpt and save this as exer3.fpt. Input the flow rate constraint:

• The PIPESIM network model controls the maximum flow rate from the well by choking the well back. It therefore must contain a choke to operate in the well description in the PIPESIM network model.

• Select the ‘PIPESIM-Net models’ dialog and edit the PIPESIM network model.

• Add a choke to each of the wells at the wellhead. Supply a temporary bean size of 3” for each

choke (this will be overwritten by the field planning events logic). One of the wells as modified in PIPESIM is shown below:

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• Exit the Network graphical interface.

• Select the Flowrate Constraints button and select all of the wells (highlighting them), but not the sink.

• Now choose gas rate as the Limit type, and type in a rate of 11 mmscf/d in the Value text box.

• Click on apply and this flow rate constraint will be imposed upon all of the wells. The flow rate

Click on OK to leave this User Form.

constraints user form is shown below:

•

Modify the conditional logic:

• Use the field planning events editor to delete the event that currently

Now add an Event that effectively says ‘turn on well 2 when the gas production rate at the

turns on the well after 60 days.

•sink drops below 21.8 mmscf/day’.

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Run the model:

• Run the model by selecting the run button . Format and view a graphical output:

• Once the simulation has finished, select the results viewer button . • Select plotting and plot for all wells and sinks. The graph is shown below. • The graphical results are shown below.

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Exercise 4: Use of a bean list to design a drilling schedule Objectives: The objective of exercise 4 is to design a simple drilling schedule to maintain the combined production of the three wells at or above at 19 mmscf/d/ for as long as possible. Exercise 4 is divided into 7 subsections as detailed below:

1. Save the FPT model with a different name. 2. Delete the flow rate constraint. 3. Modify the conditional logic so that only one well is active at timestep = 0 day. 4. Create a “bean list” so that remaining wells get activated sequentially as production drops. 5. Run the model. (Using the same field planning events as in Exercise 1) 6. Format and view a graphical output. 7. Observe that at time 900 the wells are “closed due to link with dead look up table”. 8. Modify the look-up table. 9. Restart the model at 840 days. 10. Format and view a graphical output.

Save the FPT model with a different name: Open exer3.fpt and save this as exer4.fpt. Delete the Flow rate constraints:

Select the Flow rate Constraints button and select all of the wells (highlighting them), but not the sink.

Select limit type = gas rate.

Click on the remove button and the flow rate constraints will be deleted. Click on OK to leave this User Form. Modify the conditional logic:

• Input the field logic using the field planning events button . • Enter the following logic under schedule = NONE. (Note that the timestep has been

changed to 960.)

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Create a bean list: -Down list schedule, highlight BEAN 01 and insert the following logic.

h they have

Run the Model:

• In the Drop• Bean list events will be triggered only once and once at a time in the order in whic

been entered in the user form.

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• Run the model by selecting the run button . Format and view a graphical output:

• Once the simulation has finished, select the results viewer button . • Select plotting and plot for all wells. The graph is shown below.

bserve that the wells are “closed due to link with dead look up table”.

• It can be seen that all the wells are closed from the time step 840 days.

• Open the Field Planning Event window and the following should be seen at the end of the

O

file.

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• The wells have been shut due to the fact that the cumulative production of the wells at the timestep 900 days is above the maximum value of cumulative production in the reservoir table.

Modify the look-up table:

• To fix this, let’s add one more data points to our table as shown below (Click on the edit table

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button, modify the table, save the table from the text editor, exit the text editor, click on load table to load the modified table):

Reservoir Pressure Vs Cumulative Gas Production:

0500

10001500200025003000350040004500

0 20000 40000 60000 80000

Cumulative Gas Production(mmscf):

Pre

ssur

e (p

sia)

Series1

Restart the model at 840 days:

• Select the Restart button , the Restart simulation user form will appear as shown below:

• Highlight the timestep 840 and click on the restart button. Format and view a graphical output:

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• The following graphical output should be obtained this time:


Exercise 5: Design a drilling schedule to produce at a constant rate Objectives: The objective of exercise 5 is to design a simple drilling schedule to maintain the combined production of the three wells at EXACTLY 19 mmscf/d/psi^2 for as long as possible. Exercise 5 is divided into 7 subsections as detailed below:

1. Save the FPT model with a different name. 2. Add a field wide flow rate constraint. 3. Run the model (Using the same field planning events as in Exercise 4) 4. Format and view a graphical output. 5. Format and view a Tabular output.

Save the PPT model with a different name: Open exer4.fpt and save as exer5.fpt. Add a Field wide Flow rate constraint:

• The PIPESIM network model controls the maximum flow rate from the field by choking back the sink. It therefore must have a choke to operate in the main flow line description in the PIPESIM network model.

• Click on the Select network models button

• In the Select network models user form click on the edit button and modify the PIPESIM network model as shown below.

• Select the Flowrate Constraints button • Highlight the sink. • Choose gas rate from the list box, and type in a rate of 19.1 mmscf/d in the box below.

• Click on apply and this flow rate constraint will be imposed upon the sink.

• Click on OK to leave this User Form.

Run the Model:

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• Run the model. Format and view a graphical output:

• Once the simulation has finished, select the results viewer button . • Select plotting and plot for all wells and sinks. The graph is shown below.

Exercise 6: Record some auxiliary properties: Objectives: The objective of exercise 6 is to record some auxiliary properties (Pressure drop across the choke and erosional velocity) while running FPT. In effect not all properties recorded by PIPESIM Net each run are stored in the FPT output files. These Auxiliary (non-recorded) properties can be selected prior to an FPT run so that they are recorded in the FPT output file. Exercise 6 is divided into 7 subsections as detailed below:

1. Save the FPT model with a different name. 2. Define auxiliary output. 3. Run the model. (Using the same field planning events as in Exercise 4) 4. Format and view a Tabular output.

Save the FPT model with a different name:

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• Open exer5.fpt and save as exer6.fpt. Define auxiliary output:

• Select the auxiliary properties button and the following user form will appear:

• The user form is divided into 4 windows the “branch list window” lists all the branches in the network; the “branches selected ” window displays the branch on which the user wishes to record auxiliary properties; the “auxiliary property” window lists all the auxiliary property that are available for the user to record, the “selected property window” display the chosen auxiliary properties to be recorded for the selected branches.

• Select B1, well1, well2, and well3 by highlighting them in the “branch list window” and clicking

on the Add button.

• Highlight the 3 selected wells in the “selected branches window” and click on Erosional velocity Ratio in the “auxiliary properties window”.

• Highlight the selected B1 branch in the “selected branches window” and click on Pressure

drop across choke and Bottom hole pressure in the “auxiliary property window”.

• Click on OK to exit the user form.

n the model:

un the model by selecting the run button

Ru

R .

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Format and view a tabular output:

• Click the customise button to produce the following tabular outputs.

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FPT Tutorial 2: Black Oil Tank.

Exercise 1: Objectives: The objective of exercise 1 is to familiarize the user with the FPT interface by building and running a simple case study where the reservoir depletion model is a Black Oil tank. Exercise 1 is divided into 8 subsections as detailed below: Build a Network model. Build a Black oil tank model. Link the network model to the FPT model. Map the wells from the reservoir to the network. Enter some simple field planning events. Run the model. Format and View a Graphical output. Format and View a Tabular output. Build a Simple Surface Network: Use PIPESIM network module to create BOTank.bpn in your training directory. The network model is shown below:

Six identical wells are connected to this reservoir. One of the wells as modeled in PIPESIM is shown elow:

b

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Well Data: Reservoir Pressure = 3000 psi Reservoir Temperature = 200 F Completion Model – Well PI, choose Liquid PI of 10 STB/day/psi. Tubing Details – (use Detailed Model) MD ft TVD ft Temperature F U value Tubing ID inch 0 0 60 2 2.992 1000 1000 2.992 2250 2000 2.992 3500 3000 200 2 2.992 Rename this well Well_A1 and then copy and paste it to create wells Well_A2, Well_A3, Well_B1, Well_B2 and Well_B3. Link the wells to form the network. Enter the pipeline data: Name Length, ft Pipeline ID, inches Conn 1 2500 6 Conn 2 2000 6 Conn 3 100 8 Ambient temperature for all surface conditions is 60 F. PumpBranch is made of two flow lines each of 1000 ft length and 6 inches ID. It also contains an adiabatic pump of 100% Efficiency and 100 HP and a Gas separator of 100 % efficiency between the two flow lines as shown below:

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Sink delivery pressure is 500 psi. The Global Black Oil composition for the network is Water Cut = 20%, GOR = 500 SCF/STB. Calibration data at Bubble point is Pressure = 3000 psi, Temperature =200 F, Saturation Gas = 500 SCF/STB. Note that all the wells in the PIPESIM network model should have no flow directional blocks. This is done by right clicking on the well in the network interface and selecting BLOCK: None. Check that the model solves successfully by running it. The following output is obtained at the sink (Tolerance: 0.2 %):

Use the FPT button within the PIPESIM network model to generate the necessary interface files. Build a Black Oil Tank Model: Start FPT. Use Save-As to save the model as BOTank.fpt in your training directory. Select the Mode menu and choose Black Oil Tank Models.

Select the Reservoir button . The compositional tank model user form will appear. Create a new reservoir named PoolA with the following data:

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Create another new reservoir PoolB and input the following data:

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Link the network model to the FPT model.

Use the Net Models button to attach the network model BOtank.bpn to the FPT model BOtank.FPT. Map the wells to the tank model.

Use the well mapping button to map well_A1, Well_A2, Well_A3 to PoolA and Well_B1, Well_B2, Well_B3 to PoolB. The user form is shown below:

Select the Reservoir button once more. The compositional tank model user form will appear. Select the Well completion details tab. Input the completion depths of the six wells as shown below:

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Click on edit to create the Water cut table (Watercut1) and GLR table (GLR1):

Select WellA1, WellA2, WellA3 and apply the Water Cut and GLR tables:

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Enter some simple field planning events: Events description: The simulation is to be run for 600 days in 60 days step. Initially Well_A1, Well_A2, Well_A3 are on Well_B1, Well_B2, Well_B3 are turned on 120 days later. The pump Horsepower is set to 600 Hp after 300 days. Coding the events with FPT:

Input the field logic using the field planning events button . Set the initial timestep to 60 days. Note that it is necessary to switch well_A1, well_A2, well_A3 at time=0 because the default initial condition of all wells is off. The timestep is set to 1 day just before an event happens in order for the graph to represent accurately the surge in production that happens when: WellB1, WellB2, WellB3 are turned on. The pump power is stepped up from 100 Hp to 600 Hp.

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Run the Model

Run the model by selecting the run button . View the Graphical Output

Once the simulation has finished, select the results viewer button . Select plotting and plot for all wells and sinks. The graph is shown below.

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FPT Tutorial 3: Look Up Tables

Exercise 1: Objectives: The objective of exercise 1 is to build and run a simple set of case studies where the boundary conditions are provided to the network for a given number of simulations. (I.e. no reservoir depletion model is used) Exercise 1 is divided into 6 subsections as detailed below: Build 2 look up tables (PoolA and PoolB). Link the network model to the FPT model. Map the wells from the reservoir to the network. Enter some simple field planning events. Run the model. Format and View a Graphical output. Create 2 look up tables (PoolA and PoolB): Select the Mode menu and choose Case Studies:

Select the Reservoir button . The look-up table user form will appear. Select Case as the Independent Properties and Pressure as the Dependant Properties, the user form should look as follows:

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Select Save table and save the table as PoolA.tbl in your training directory. Click on Edit table and the following text editor should appear. Enter the following data in the table. (These data could be pasted directly from an excel spreadsheet for example). The date must lie between the 2 keywords “LOOKUPTABLEDATA” and “ENDOFTABLEDATA”

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Save the table clicking on the menu file submenu save in the text editor. Close the text editor. Select Unused2 in the case studies user form. Select Case as the Independent Properties and Pressure as the Dependant Properties, the user form should look as follow:

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Create the following table (Pool_B.tbl): Map the Table to the wells: Map this table to the wells in the same way as you did in the black oil tank case study:

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Enter some simple field planning events: Wells A1, A2, A3 are on for cases 1-2; all wells are on for cases 3-5. Enter the following field planning events:

Run the simulation Run the simulation again. View the Graphical Output

Once the simulation has finished, select the results viewer button . Select plotting and plot for all wells and sinks. The graph is shown below.

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The x-Axis is “Time” but for the case study mode “time” and “case” are treated the same.


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FPT Tutorial 4: Daily Contract Quotas (DCQ) Exercise 1: Objectives: The objective of exercise 1 is to familiarize the user with the FPT_DCQ interface by building and running a simple case study where the reservoir depletion model is a Compositional Tank. Exercise 1 is divided into 8 subsections as detailed below: Build a Network model (containing 5 identical wells). Build a Compositional tank model. Link the network model to the FPT model. Map the wells from the reservoir to the network. Enter some simple field planning events. Run the model. Format and View a Graphical output. Fill in the DCQ user form. Build a simple surface Network: Use PIPESIM network module to create DCQ.bpn in your training directory. The network model is shown below:

Six identical wells are connected to this reservoir. One of the wells as modeled in PIPESIM is shown below:


Well Data:

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Link the wells to form the network. Enter the pipeline data:

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Sink delivery pressure is 2000 psi. The Global composition for the network is shown below: Nitrogen: 3.15 Carbon Dioxide: 1.34 Methane: 85.05 Ethane: 5.14 Propane: 2.19 Isobutane: 0.35 Butane: 0.7 Isopentane: 0.24 Pentane: 0.24 Hexane: 0.19 C7+: 1.41 Name BP (F) MW SG TC (F) PC (psia) Omega C7+ 188 90 0.75 520 512 0.29 Note that all the wells in the PIPESIM network model should have no flow directional blocks. This is done by right clicking on the well in the network interface and selecting BLOCK: None. Create a PVT file DCQ.pvt. Check that the model solves successfully by running it. The following output is obtained at the sink (Tolerance: 1 %):

Use the FPT button within the PIPESIM network model to generate the necessary interface files. Build a Compositional Tank Model: Start FPT. Use Save-As to save the model as DCQ.fpt in your training directory. Select the Mode menu and choose Compositional Tank Models.

Select the Reservoir button . Fill in the compositional tank model user form as shown below (Composition file: DCQ.pvt).

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Link the network model to the FPT model.

Use the Net Models button to attach the network model DCQ.bpn to the FPT model DCQ.FPT Map the wells to the tank model.

Use the well mapping button to map a1, a2, a3, b1, b2, and b3 to res01. The user form is shown below:

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Enter some simple field planning events: All wells are turned on at the start of the simulation.

Run the model:

Run the model by selecting the run button . Format and View a Graphical output:

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Fill in the DCQ user form: Click on the menu MODE submenu DCQ and the DCQ user form will appear:

Enter the following data in the user form (The date can be entered under the following format 01/01/2000 – the Time column will then be filled automatically):


The typical contract is defined by the following:

The obligation, which is the average production rate (DCQ in mmscf/d) that will be purchased by the transmission company (or consumer) over the nomination period.

The take factors that are the fractions of the DCQ that will be bought in any given period. The following equation must be respected:

∑=

=⋅n

i

i DCQnDCQ

1

α

Where: n = Number of time period considered. αi = Take fraction for the period i.

Minimum specified delivery pressure.

The swing factors: Factors, which multiplied by the DCQ volume, gives the peak daily demand rate expected by the purchaser in any given period. The peak daily demand rate can be much higher than the average daily take.

The swing and take patterns are drawn by linking all the swing and take factors together against time. A typical swing and take pattern over a period of one year can be seen below:

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0

0.2

0.4

0.6

0.8

1

1.2

1.4

1.6

0 100 200 300 400

SwingTake

Time (Days).

DCQ calculation procedure:

Start of Iteration: The engine takes the initial DCQ value (mmscf/d) as the boundary condition of the sink. The production allocation from each well is calculated in a PIPESIM-net simulation determined. The corresponding outlet pressure is also calculated. Deliverability check for the month:

Using the “% take” value for the month, FPT calculates the cumulative flow taken from each source for the 1st month of the contract. Well Name:

Flow rate produced by each source when producing DCQ:

% Take value for August:

Flow rate produced by each source in August:

Cumulative flow rate taken in August:

Well A: 5 mmscf/d. 0.5 2.5 mmscf/d 75 mmscf Well B: 8 mmscf/d. 0.5 4 mmscf/d 120 mmscf Well C: 12 mmscf/d. 0.5 6 mmscf/d 180 mmscf

12.5 mmscf/d Total: DCQ = 25 mmscf/d. 0.5 375 mmscf Using the cumulative flow rate taken from each well calculate the pressure of the reservoir(s) at the end of the period. The deliverability at the end of the month Q2 is calculated using the reservoir pressure (s) at the end of the period at each of the well and Pout at the sink (minimum specified delivery pressure). If the deliverability is less than the DCQ multiplied by the swing factor abort the iteration and repeat step 1 with a more suitable initial DCQ guess (Lower DCQ). If the deliverability is more than the DCQ multiplied by the swing factor do a deliverability check for the following period. If no Pinch point has been encountered over the length of the nomination period choose a higher DCQ and return to point one.

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Run the DCQ operation:

Run the operation by pressing the button in the DCQ user form. The Messages window will look as shown below during the run:

Observe the results:

The Calculated DCQ that the asset can guarantee and the corresponding pinch point can be seen on the DCQ Calculation user form.

FPT converges on a solution after four iterations.

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Click on the results tab to display the results (Calculated DCQ value of 98.818 mmscf/d, Pinch point in December)


Part 5 – Single Branch Case Studies – Worked Answers

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Worked Answers: Case Study 1 – Oil Well Design Exercise 1 Open PIPESIM and Open a new Well Performance Analysis module from the File menu. Save the model as Case Study 1. The first step is to create the black-oil model. From the Setup Menu, select “Black Oil…”. Using the given Black Oil PVT data, enter the data into the dialogue box as shown below:

Click on the Export button. This will add the fluid model to the data-base. Note that if any changes are made to the fluid, you must click on the Export button. Now that the basic black oil model has been defined, the next step is to create the well model. Click and drag the objects to create a well model as shown below:

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To enter the tubing data, double click on the tubing and select “detailed model”. Enter the given deviation data into the model as per the below screen:

Click on the “Geothermal Survey” tab and enter in the given information as per the below screen:

Now click on the “Tubing Configurations” tab and enter the data as per the below table:

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Now that all the required tubing information has been entered, the next step is to enter the reservoir and inflow data into the model. Double click on the completion icon and enter the data as shown below. Note that inflow model used is a Well PI, this can be selected from the drop-down menu. Also click on the radio button to “use non-linear correction below the bubble point”.

The basic oil well model has been defined. It is now possible to run some PIPESIM operations. To answer the questions, a Pressure/Temperature profile operation will

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be run. From the Operations menu, select “Pressure/Temperature Profile…” To calculate the production rate for a well-head pressure of 300 psia, enter the information into the dialogue box as shown below:

Hit the “Run Model” button, and the following plot will be generated:

The above shown screen shows the pressure profile down the length of the tubing. You can plot other variables on the chart by using the “Series” drop down tab.

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To obtain the production rate, flowing BHP and flowing WHT, close the plot then from the main PIPESIM page, then select Summary File from the Reports menu. The below shown screen will be generated:

From the above shown ASCII file, the results below can be obtained:

Result

Wellhead Pressure 300 psia Production Rate ? 7438 bbl/d

Flowing BHP ? 132 oF

2670 psia Flowing WHT ?

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Exercise 2 Nodal analysis will now be performed to determine the operating point and AOFP of the well. A nodal analysis icon will need to be inserted into the model. Enter a NA point as shown below:

From the Operations menu select “Nodal Analysis…”. Enter the data as shown in the below dialogue box.

Click on the “Run Model” button and the below shown Nodal Analysis plot will be generated:

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To determine the operating point flowrate and BHP, and the AOFP, click on those points on the chart and read the results from the bottom right hand corner of the screen. The results are as follows:

Result

(Outlet) Wellhead Pressure 300 psia Operating Point Flowrate ? 7438 stb/d

Operating Point BHP ? 2670 psia AOFP ? 20400 stb/d

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Exercise 3 The black oil model used so far only contains the minimum information required for fluid model definition. In this exercise the black oil model will be calibrated using more detailed data. From the Setup menu select “Black Oil…”. Now click on the “Viscosity Data (Optional)” tab at the top of the dialogue box. In the Dead Oil Vicosity section, select “User’s Data” from the drop-down menu. Enter the given data as shown below:

Now go to the Advanced Calibration Data (Optional) tab from the top of the dialogue box and enter the data as shown below:

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Go back to the Black Oil Properties tab and click the Export button. This will update the fluid into the database. Click OK. From the Operations menu select “Pressure/Temperature Profile…”. Repeat the previous operation and inspect the depth vs pressure chart. As shown in Exercise 1, from the Summary file you can find the following results:

Result

Wellhead Pressure Production Rate ? 6826 stb/d

Flowing BHP ? 2747 psia Flowing WHT ? 129

300 psia

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Exercise 4 An FGS survey and well test data are available for this well. In this exercise we will use the FGS data to select the most suitable vertical multiphase flow correlation. From the Operations menu select “Flow Correlation Matching..”. Enter the given information as per the below dialogue box (we will use only Beggs & Brill Revised, Duns & Ros, and Hagedorn & Brown).

Click on the “Run Model” button and the following plot will be generated:

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From the above plot, it appears that the best correlation is Hagedorn & Brown. Close the plot then from the Setup menu, select “Flow Correlations..”. As shown below, change the vertical multiphase flow correlation to Hagedorn & Brown:

The BHP using the Hagedorn & Brown can be approximated from the profile plot generated earlier, or for the exact calculation you can run another “Pressure/Temperature Profile…” as done in the earlier exercises. The BHP can be read from the Summary File (Reports menu). Using the Hagedorn & Brown correlation, the results are as follows:

Result

Wellhead Pressure 300 psia Hagedorn & Brown

2532 psia Vertical Correlation ?

Flowing BHP ?

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Exercise 5 Given the correct flow correlation chosen in Exercise 4, Exercise 5 involves finding the correct IPR that matches the test data used in Exercise 4. The known reservoir pressure is 4600 psia. We will determine the new PI and the AOFP. To determine the PI, System Analysis will be performed. In this exercise, a plot of production rate vs PI will be generated given the known reservoir pressure of 3600 psia and the known wellhead pressure of 300 psia. From the Operations menu, select “System Analysis…”. Enter the given information into the dialogue box as shown below:

Click on the “Run Model” button and the below system plot will be generated:

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From the above chart, the PI can be read from the plot at a liquid flow-rate of 6500 STB/d. The correct PI is 6.059 STB/d/psi. To determine the AOFP, Nodal Analysis can be performed using the PI as calculated above (to do this, the new calculated would need to be entered into the completion model prior to performing Nodal Analysis). Nodal Analysis can also be used to determine the correct PI. As per Exercise 2, from the Operations menu select “Nodal Analysis…”. Enter the information into the dialogue box as shown below:

The below Nodal Analysis plot will be generated:

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From the above Nodal Analysis plot the PI that corresponds to a liquid flowrate of 6500 STB/d can be approximated as 6 STB/d/psi. At this PI, the AOFP is 15224 STB/d.

Result

Wellhead Pressure 300 psia PI ? 6 STB/d/psi

15224 AOFP ? As mentioned above, note that in the case when the PI is calculated using System Analysis, if the user wishes to use Nodal Analysis to determine the AOFP, then the calculated PI from the System Analysis would need to be entered into the completion (as per Exercise 1) prior to performing the Nodal Analysis. The PI of 6 will be used in the remaining exercises, ensure that it is changed in the completion.

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Exercise 6 Given the current wellhead pressure, we will determine the watercut at which the well will die. This will be performed using System Analysis. From the Operations Menu, select “System Analysis..”. Enter the given data into the dialogue box as shown below:

Click on the “Run Model” button and the below System Plot will be generated:

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As can be seen from the above plot, the last converged solution is at 60% watercut. This is because for a watercut of 70%, the well will not flow. For our purposes, we will take the answer to be 60%. To determine the exact watercut at which the well will die, the operation could be repeated using watercut values from 60% to 70% as the sensitivity.

Result

Wellhead Pressure

Water Cut ? 60 % 300 psia

Note that Nodal Analysis could also be used to determine the watercut at which the well will die. To do this, select the Nodal Analysis operation from the Operations menu as done previously, and perform nodal analysis by selecting the watercut as the outflow sensitivity and entering watercut values into the table. From the Nodal Analysis plot, the watercut at which the well dies can be determined by identifying the first outflow curve that does not cross the IPR curve at any point (as determined above, this will be a water cut between 60% and 70%).

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Exercise 7 In this exercise we will examine how this well responds to Gas Lift. We will introduce a gas lift injection point at 8000 ft MD in the tubing. Using watercuts of 10% and 60%, we will determine the liquid production rate for a range of gas lift injection rates. Double click on the tubing, and select the “Downhole Equipment” tab. Enter the data as per below:

Click on the “Properties” button and enter the given data as shown below (note: default injection rate must be given - use 1 MMSCFD):

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Click OK and from the main PIPESIM menu select the System Analysis operation from the Operations menu. To see the effect of the gas lift rate at various watercuts, select the “X-axis variable” to be the lift gas rate and the “Sensitivity Variable” to be the watercut. Enter the given data as shown below:

Click on the “Run Model” button. The below shown System Plot will be generated.

From the above generated plot, the below answers can be determined:

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Result Water cut = 10% Water cut = 60%

Gas Lift Rate (mmscf/d)

Liq. Prod. Rate (stb/d)

Liq. Prod. Rate (stb/d)

0.5 7163 4708 7661 5771

1.5 8002 6411 8257 6870

1

2

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Worked Answers: Case Study 2 – Well Performance Analysis – Nodal Analysis Exercise 1 In this exercise we will build a single branch model and perform Nodal Analysis. The first step is to create a new single branch model by selecting “Well Performance Analysis” from the “New” option from the File menu. The first step is to define and characterize the fluid model. From the Setup menu select “Black Oil…”. Enter the given information as shown below.

Click on the “Export” button then click OK. This new fluid model is now in the fluid model database. Now build a simple model as per the below shown screen-shot:

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Double click on the completion icon and select Pseudo Steady State as the inflow model and then select “Liquid” as the basis for the IPR. Check the box “Use Vogel below bubble point”. Enter the given information as per the below table:

Now that the completion has been defined, click OK then double click on the tubing. Select “Simple model” from the drop-down list then enter the information into the model as shown below (when entering the Perforation information into the dialogue box, enter the TVD first then the MD and allow PIPESIM to calculate the angle from the kick-off point).

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Now all the required data has been entered into the model. Using Nodal Analysis, we will now determine the flowing bottom hole pressure and the production rate given a well-head pressure (250 psia). From the Operations menu, select “Nodal Analysis…”. Enter the data and fill in the dialogue box as shown below (leave the sensitivity fields blank).

Click on the “Run Model” button. The following plot should be generated.

From the plot, the flowing bottom hole pressure and production rate can be determined by clicking on the operating point and viewing the results in the bottom right hand corner of the chart.

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The results are as follows:

Result

Wellhead Pressure Production Rate ? 780

Flowing BHP ? 2420

250 psia

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Exercise 2 In this exercise we will investigate the increase in production through stimulation and gas lift using Nodal Analysis. Firstly, a gas lift injection point must be entered into the model. Double click on the tubing, then in the “Artificial Lift (Optional)” field, click on the “Gas Lift” button and enter a depth of 4500 ft into the field as shown below.

Now click on the “Properties” button, and enter the data as follows (we will set a default gas lift rate of 0 MMSCFD here).

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From the Operations menu, select “Nodal Analysis…”. Enter the data as shown below:

Click on the “Run Model” button and the following plot should be generated:

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From the above plot, the following results can be determined: Outlet Pressure = 250 psia.


base (skin = 3) 780 1090 1180 1240 1430 1530 1590

fractured (skin = -2) 1430 1790 1910 1980

acidized (skin = 0) 1070

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Exercise 3 In this exercise the different flow correlations will be investigated. The Beggs and Brill correlation has been used so far. The Mukherjee and Brill correlation accounts for the effects of viscosity, which for this case may be significant because the oil is relatively heavy. We will repeat the Nodal Analysis from Exercise 2 using the Mukherjee and Brill vertical flow correlation. From the Setup menu, select “Flow Correlations…”. In the Vertical Flow (Multiphase) section, select Mukherjee and Brill from the “Correlation” drop down menu, as per the below screen.

We will now repeat the Nodal Analysis as performed in Exercise 2. From the Operations menu, select “Nodal Analysis…”. The inflow and outflow sensitivity definitions should still remain from Exercise 2 (if not, re-enter them as per Exercise 2). Click on the “Run Model” button. The below chart should be generated:

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From the above generated chart, the following results can be determined.


Oil Production Rates (STBD)– Mukherjee & Brill:


base (skin = 3) 690 1010 1120 1220 acidized (skin = 0) 980 1320 1460 1570 fractured (skin = -2) 1320 1690 1840 1960

The above results can be compared to the results from Exercise 2. The discrepancy between the Beggs and Brill correlation and the Mukherjee and Brill correlation ranges from 1 – 15%. However, both cases agree fairly well in terms of the relative added benefit shown by sensitivity cases. Notice that in changing the flow correlation, the inflow curves remain unchanged. This is because Nodal Analysis “de-couples” the system, creating two independent components. Ultimately, project economics and future production potential based on reservoir conditions will weigh heavily in the final decision.

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Worked Answers: Case Study 3 – Gas Well Performance Task 1: Water content at saturation (Reservoir conditions) Open a new PIPESIM single branch model. Firstly the PVT information will be entered. From the Setup drop-down menu select “Compositional”. This opens the compositional PVT editor. You can enter in the gas well fluid composition as per the given composition. For the purposes of the first task, you must enter an amount of water; use a value of 20 moles. The compositional editor is shown below.

After entering the water free composition in the lower table (in moles, total excluding water equals 100) and a nominal 20 moles of water in the top table (these numbers will be changed later after determining the saturated water composition), click on the “Single Point Flash” tab across the top of the dialogue box. Check the PT radio button as shown below, and enter in the reservoir pressure and temperature. Press the “Perform Flash” button, and the results water saturated composition will be shown in the vapour stream.

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The water content at the saturation point at reservoir conditions is given below (this is the re-normalised content):

P 0res = 4,600 psia, Tres = 28 oF % Water 1.80%

Now enter this new composition into the composition editor (note that the aqueous fraction should be entered into the top section). Task 2: Phase envelope: It is possible to generate a phase diagram by pressing the “Phase Envelope” button from the “Component Selection” screen. The following phase diagram should be generated:

Task 3: Results To run a case, the first step is to construct a model using the PIPESIM icons as arranged below:

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Prior to running a model, the reservoir, inflow and tubing data must be entered into PIPESIM. Click on the completion icon to enter in the reservoir and inflow information. The below dialogue box should come up. Enter in the reservoir pressure and temperature, then select the inflow model from the drop-down menu. Enter the Gas PI as per the data sheet.

After entering the reservoir and inflow information, you should now enter in the tubing information. Click OK from the on the above screen then double-click on the tubing. Select “Simple Model” from the drop-down menu then enter the information as per the data sheet into the dialogue box, as shown below:

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All required information has now been entered into the model. It is now time to run the model. From the Operations menu select “Pressure/Temperature Profiles”. To calculate the rate for a given outlet (well-head) pressure of 800 psia, click on the radio button next to “Gas Rate”. Now enter in 800 psia into the box next to the “Outlet Pressure” radio button as shown below:

Click on the “Run Model” button. This will run the model and give a profile plot for the flow path. To obtain the results, close the plot and from the Reports drop-down menu, select “Summary File” From the Summary File, the below answers can be obtained:

Po = 800 psia QG 19.4 MMSCFD Pwf 1,318 psia BHT 228oF WHT 172oF

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Worked Answer Exercise 2: Task 1: Calculated inflow parameters for Back-Pressure Equation from DST data:

Instead of using the Gas PI as the inflow model, the Back Pressure equation will be used. The back pressure equation allows generation of a pseudo steady state gas well IPR model using test data. The parameters will be determined by fitting the data to a curve using the following formula:

Q = C(Pws2 - Pwf2)n

To change the inflow model, double click on the completion. This will bring up the dialogue box as shown in Exercise 1. From the drop-down menu next to “Model Type” under “Completion Model”, select BackPressure Equation. To calculate the C and n parameters, click on the button “Calculate/Graph”. Enter in the given DST data into the dialogue box as shown below, and click OK. The calculated values will then be shown.

The calculated parameters are listed below:

Pres = 4,600 psia Parameter C 8 x 10-7 Parameter n 1

Task 2: Results using Back-Pressure Equation and DST data: You can now run the model using “Pressure/Temperature Profiles” in the same way as shown for Exercise 1. The results can again be obtained from the Summary File, and are summarised below:

Results:

Po = 800 psia G 15.7 MMSCFD wf 1,263 psia

226oF oF

QPBHT WHT 167

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Worked Answer Exercise 3: Task 1: Bottom-hole Nodal Analysis with tubing ID set as outflow sensitivity: To perform the Nodal Analysis at the sand-face, a Nodal Analysis icon will need to be installed at the bottom of the tubing (if not already done so). From the Operations Menu, select “Nodal Analysis”. Enter the given data into the dialogue box as shown below then click on the “Run Model” button.

The following bottom-hole Nodal Analysis plot will be shown. The below is a Nodal Analysis plot at bottom-hole for different tubing sizes:

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Task 2: Erosional velocity ratio: Run the model from the “Pressure/Temperature Profiles” option from the Operations menu, using the tubing size as the sensitivity (as shown below). Use an outlet pressure of 800 psia.

The pressure temperature profile plot of the system will be generated. To generate a plot of depth versus the erosional velocity ratio, change the x-axis to Erosional Velocity Ratio by selecting “Series” from the top toolbar and selecting “Erosional Velocity Ratio” from the “Select X Axis” drop-down menu. Click OK and the following chart should be obtained.

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Task 3: Results for 3.958” ID tubing:

The below results can be obtained from the Summary File.

3.958” ID tubing QG 15.7 MMSCFD

wf 1,236 BHT 226oF WHT 164oF

P psia

Use the generated chart to determine the erosional velocity ratio at the wellhead for the 3.958” ID tubing.

Well-head Erosional velocity ratio 0.788

Worked Answer Exercise 4: Task: Gas rate vs Reservoir Pressure for different tubing sizes:

From the Operations Menu select “System Analysis”. Enter the given information into the dialogue box as shown below:

Click on the “Run Model” button and the below chart should appear. From this chart it also appears that the 3.958” ID tubing is likely the optimum tubing size.

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Worked Answer Exercise 5: Task: Calculated choke Size:

A choke and flow-line can be entered into the model by the usual click and drag method. Double click on the flow-line and enter the given data as shown in the below dialogue box:

To determine the choke size to give the desired outlet (ie manifold) pressure of 710 psia, the “Pressure/Temperature Profiles” option can be used. Use the choke size as the sensitivity, and calculate the outlet pressure for the given rate of 15.7 MMSCFD, as per the below dialogue box:

Click on “Run Model” then look in the Summary File (shown below). Look for the choke size that results in an outlet pressure of 710 psia (and check that that wellhead pressure is 800 psia).

From the Summary File, the choke size that will give an outlet pressure of 710 psia is 1.5”. Note that the well-head pressure is still 800 psia upstream of the choke.

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Po = 710 psia 1.5” Choke size

Worked Answer Exercise 6: Task 1: Water content at saturation (Reservoir conditions) at new composition:

Save the model as a new name. Enter the new composition using the composition editor and determine the fraction of water at the saturation point of the gas (as per the same method as Exercise 1 Task 1). The answer is as follows:

Pres = 4,600 psia, Tres = 280oF 1.88% % Water

Task 2: Best Flow Correlation:

The choke and flow-line should be de-activated (so that the outlet pressure of 800 psia represents the well-head pressure). To de-activate an object, right click it and select Active, this will de-activate the object (it will now read “inactive”). From the operations menu, select “Flow Correlation Matching”. Enter the given data in the dialogue box as shown below:

Click on “Run Model”, and the following chart will be generated:

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From the above chart it is clear that the Duns & Ros correlation is the most suitable. To determine the mean arithmetic and mean absolute differences, look at the bottom the Output File

Po = 800 psia Best Correlation D&R Mean arithmetic difference (%) 0.89

0.89

Mean absolute difference (%) Task 3: Results using new correlation and heavier composition:

Using the “Pressure/Temperature Profile” option from the Operations Menu, with an outlet pressure of 710 psia (remember to activate the flow-line and choke) as per the method described previously, the results can be generated. The bottom-hole flowing pressure and gas flow-rate can be read from the Summary File as shown in the previous exercises, and the actual liquid flow-rate at the mid-perfs and outlet can be found in the Output File


Po = 710 psia QG 13.3 MMSCFD Pwf 1,361 psia

2,292 bbl/d L @ outlet (act) 2,690 bbl/d

QL @ mid-perfs (act) Q

Worked Answer Exercise 7:

Task 1: Liquid Volume Fractions and Liquid Hold-up Fractions:

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Re-run the Pressure/Temperature Profile as performed in Exercise 6, Task 3. To determine the liquid volume fraction and liquid hold-up fraction at the specified points, look in the Auxiliary Output Page at the bottom of the output file:

The following results can be obtained:

Liquid Volume Fraction, Po = 710 psia xVL @ bottom-hole 0.0717 xVL @ WH 0.0585 xVL @ end flow-line 0.0500

Liquid Hold-up Fraction, P sia o = 710 p

xHL @ bottom-hole 0.4080 HL @ WH

xHL @ end flow-line x 0.0837

0.1085 Task 2: Flow Regime and Map for end of flow-line: To obtain a flow-map, a report tool needs to be entered into the model at the end of the flow-line.

Double click on the report icon and check the “Flow Map” check-box as shown below:

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The model needs to be re-run, this can be done by pressing the “Run” button on the main tool-bar (this will re-run the latest operation, in this case the Pressure/Temperature Profile from Exercise 7, Task 1). Look at the bottom of the Output File to see the flow map as shown below:

From the above flow-map , the flow-regime at the end of the flow-line can be determined (this can also be determined by looking elsewhere in the Output File, as well as the Summary File).

Liquid Volume Fraction, Po = 710 psia Flow regime end FL Intermittent

Worked Answer Exercise 8: Task 1: PT path on phase diagram:

To generate phase diagram with the PT flow path super-imposed on it, first of all double click on the report icon and select “Phase Envelope”. Re-run the model using “Pressure/Temperature Profiles” (this will re-run the model from Exercise 7, Task 2). In the profile plot that is generated, from the Series option in the top toolbar, change the y-axis to pressure and the x-axis to temperature. The below phase diagram with the fluids PT path should be generated:

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Task 2: Hydrate formation? From the above shown phase diagram, it can be seen that the operating line does not cross the hydrate formation line. This means that hydrates will not be produced anywhere in the production system up to the manifold (represented by the outlet).

Ambient Temp = 30oF Hydrate formation No

Worked Answer Exercise 9: Task 1: Pressure drops for heavier composition:

The pressure drop across the reservoir, tubing, choke and flow-line can be determined from the Summary File, as shown below. Use a rate of 13 MMSCFD and run a Pressure/Temperature Profile operation (and select Outlet Pressure as the calculated variable).

The tubing pressure drop is the bottom-hole flowing pressure minus the well-head pressure, as determined from the above shown Summary File output.

Heavier composition (13 MMSCFD) ∆P Reservoir 2,803 psia ∆P Tubing 601 psia

76 psia ∆P Flow-line ∆P Choke

2 psia

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Worked Answer Exercise 10: Task: Results using Rigorous Flash:

To use the “Rigorous Flash” option, from the Setup Menu select “Flashing…”. Check the “Always Rigorous Flash (slow)” for both the Temperature Energy Balance and Physical Properties as per the below shown dialogue box:

Click OK then re-run the model from “Pressure/Temperature Profiles” using an outlet pressure of 710 psia. Compare the results from the Summary and Output files and the phase diagram to the results from the same operation when the Interpolation option was used instead of rigorous flashing (ie Exercise 6 Task 3, and Exercise 8 Tasks 1 and 2). The results are as follows:

Po = 710 psia QG 13.3 MMSCFD Pwf 1,361 psia QL @ mid-perfs (act) 2,291 bbl/d

L @ outlet (act) 2,672 bbl/d Q

PT path from reservoir to end of flow-line plotted on new phase diagram using the Rigorous Flash option:

Hydrate formation?

Ambient Temp = 30oF No Hydrate formation

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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 Task 3). The prediction is 4,112.4 bbl/d vs 3,150.3 bbl/d for the interpolation option. The other results are quite similar, but the difference described above illustrates the how the Rigorous flash can be applicable, especially when operating near the phase envelope. The trade-off is the solving time.

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Worked Answers: Case Study 4 – ESP Selection / Design

Exercise 1.

Exercise 2.

1). No. of stages (HN13000) 58

2). Motor HP required 322 3). Flowrate range for 50 – 70 Hz. 1200 – 2050 sm3/d 4). Flowrate for Psuction < Pbubble point 1800 sm3/d

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A

B

C

A =

Pump operating point (flowrate & pump discharge pressure) at 50 Hz. B = Pump operating point (flowrate & pump discharge pressure) at 70 Hz. C = Pump suction pressure falls below bubble point.

Exercise 3.

Production Rate (95% wcut) 1480 sm3/d

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Worked Answers: Case Study 5 – Pipeline and Facilities Exercise 1: Create PVT Model

Phase Envelope

Baker Jardine

Temperature (F)400350300250200150100500-50

Pres

sure

(PSI

A)

3,400

3,200

3,000

2,800

2,600

2,400

2,200

2,000

1,800

1,600

1,400

1,200

1,000

800

600

400

200

0

Exercise 2: Size Subsea Tieback and Riser

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Separator Pressures for Operating Liquid Rates and ID's

System Outlet Pressure : IDIAMETER=9 ins System Outlet Pressure : IDIAMETER=10 insSystem Outlet Pressure : IDIAMETER=11 ins

System Data-Liquid rate (STB/d)16,00015,00014,00013,00012,00011,00010,0009,0008,000

Syst

em O

utle

t Pre

ssur

e (p

sia)

1,2501,2001,1501,1001,0501,000

950900850800750700650600550500450400350300

Errosional Velocity Ratios for Operating Liquid Rates and ID's

Erosional Velocity Ratio : IDIAMETER=9 ins Erosional Velocity Ratio : IDIAMETER=10 insErosional Velocity Ratio : IDIAMETER=11 ins


Eros

iona

l Vel

ocity

Rat

io (

)

1.9

1.8

1.7

1.6

1.5

1.4

1.3

1.2

1.1

1

0.9

0.8

0.7

0.6

0.5

0.4

0.3

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Result

10” Pipeline and Riser ID: Max. errosional velocity ratio

for selected ID 0.88 Min. Separator pressure for

selected ID 900 psia

Max. separator pressure for selected ID 1230 psia

Exercise 3: Check for Severe Slugging

PI-SS Number for Operating Liquid Rates and ID's

PI-SS : IDIAMETER=9 ins PI-SS : IDIAMETER=10 ins PI-SS : IDIAMETER=11 ins


PI-S

S ( )

1.5

1.4

1.3

1.2

1.1

1


0.98!! 1.2 1.28 PI-SS number at riser base

Intermittent Intermittent Intermittent Flow pattern at riser base

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Exercise 4: Select Insulation Thickness

.75" Insulation Thickness

Created by User on 26/11/02 22:47:46Baker Jardine

Temperature (F)18017016015014013012011010090807060

Pres

sure

(psi

a)

1,800

1,700

1,600

1,500

1,400

1,300

1,200

1,100

1,000

900

800

700

600

∆T < 2ºF Hydrates possible!


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1.00" Insulation Thickness

Created by User on 26/11/02 22:54:36Baker Jardine

Temperature (F)18017016015014013012011010090807060

Pres

sure

(psi

a)1,800

1,700

1,600

1,500

1,400

1,300

1,200

1,100

1,000

900

800

700

600

∆T = 15ºF sufficient insulation


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Exercise 5: Size Slug Catcher

8000 STBD case:


1/1000 slug volume (bbl) 166 187.6 226.8

Sphere generated liquid volume (bbl) 485.1 448.2 436.1 = 485.1 * 1.2 = 582.1

Design volume for slug catcher (bbl)

Result

Req. Insulation thickness 1.00”


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

Exercise 1:

Answer Exercise 2:


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We will choose 1.25 mmscf/d as our lift gas rate and 150 psi as the min injection gas ∆P.

Answer Exercise 3:


Worked Answers: Case Study 7 – Gas Lift Design – Current Mandrel Spacing Exercise 1: -Define the Gas Lift valve system:

• In the tubing user form, in the Downhole Equipment tab, click the

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button. The Gas Lift Valve system user form will appear:

• Select the 1st row in the user form, click on the

button. The Gas Lift Valve Selection user form will appear.

• Select SLB (Camco) as the manufacturer, IPO as the type, 1” as the size and BK-1 as the

series. Click on , the user form is shown below.


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• Click on Add valve to add the required valve. • Add the depth of the first valve in the gas lift valve system user form.

Repeat the above steps for all the valves, the gas lift valve system user form should look as shown below:

Click on OK to exit the user form.

-Perform the Deepest Injection Point operation:


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The maximum depth of injection is 4780 ft therefore we should be able to inject at the mandrel located at 4700 ft and the corresponding oil rate should be 1871 stb/d.


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Exercise 3:


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. And the rate is not 1871 stb/d but 1708 stb/d.

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This is due to the fact that the Deepest Injection Point operation does not take into account the 15-psi

ressure drop in casing pressure for each unloading valve.

t mandrel spacing the depth between alves is fixed, it is the transfer pressure that is calculated at each valve.

e or the equilibrium curve, it ay not be possible to transfer to the next valve.

p It is also important to notice that when designing for a currenv When the transfer pressures lie to the left of the production pressure curvm

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