PIPESIM
Training Course
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.
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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.
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
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
Part 1: Single Branch Tutorials
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
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.
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 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.
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
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:
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.
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.
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.
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.
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:
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.
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:
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
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
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
The following pressure profile should be visible by clicking on at the bottom of the screen.
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
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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.
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:
1) Build the Physical Model 2) Create a Fluid Model 3) Choose Flow Correlations 4) Perform Operations 5) View and Analyze Results
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:
Report tool options (same for both Report Tools)
Step 2: Define the Black oil fluid model
Step 3: Choose Flow Correlations:
Step 4: Define and Run a Pressure/Temperature profile operation
From the Operations| Pressure Temperature Profile menu, enter the following:
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
Run the model by clicking on in the user form.
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
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:
Single Branch Tutorial 3 - Oil Well Performance
In this tutorial we will model well performance, following the same general workflow as before: 1) Build the Physical Model
2) Create a Fluid Model 3) Choose Flow Correlations 4) Perform Operations 5) View and Analyze Results
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:
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.
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
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
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.
Step 5: Run the Model
Run the model by clicking on in the user form.
Step 6: Observe the Output Plot
The following pressure profile should be visible by clicking on at the bottom of the screen.
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
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.
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 mixtu 9. The elevational Pres
10. The Frictional Pressure drop 11. The Actual Liquid Flow rate at th 12. The Actual Free gas rate at the
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 Liqu 6. The Superficial Gas veloc 7. The liquid mass flow rat 8. The gas Mas
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
16. The number of Temperature iteratio ues of the Reynolds
osity of the liquid increases as the pre
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
Run the model by clicking on in the user form.
Step 3: Observe the Output Plot
e should be visible by clicking on
The following pressure profil at the bottom of the screen.
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.
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:
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
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.
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.
TIP:
Right button-drag on plot to position data points.
To zoom in, left button-drag a window across the data points towards the lower right. To zoom out, left button-drag a window towards 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.
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2. Select OK to exit dialogExcersise 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/STB
Gas SG 0.83
Water SG 1.02
Oil API 36.83 °
Bubble Point Properties:
Pressure 2647 psia
Temperature 210 °F
Solution Gas 892 scf/STB
Blackoil Calibration Data:
OFVF (above bubble point pressure) 1.49 @ 4,269 psia and 210 °F OFVF (below bubble point pressure) 1.38 @ 2,000 psia and 210 °F
Dead oil viscosities 0.31 cP @ 200 °F and 0.92 cP @ 60 °F Live oil viscosity 0.29 cP @ 2,000 psia and 210 °F Gas viscosity 0.019 cP @ 2,000 psia and 210 °F Gas 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:
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:
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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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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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
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/d
0 0 13,000 1 0 13,000 2 0 13,000 3 0 13,000 4 12 11,600 5 20 9,800 6 35 7,800 7 40 6,700 8 47 5,800 9 54 4,500 10 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:
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 4,269 1 4,190 2 4,113 3 4,020 4 3,950 5 3,893 6 3,840 7 3,800 8 3,762 9 3,730 10 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:
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.
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.
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.
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
Wellhead Pressure
300 psia
Production Rate ?
Flowing BHP ?
Flowing WHT ?
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.
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.
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:
• Go to Operations > System Analysis.
• Enter Outlet Pressure (calculate Liquid Rate).
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.
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).
• Go to Operations > System Analysis.
• Enter Outlet Pressure (calculate Liquid Rate).
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.
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
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
Wellhead Pressure
250 psia
Production Rate ?
Flowing BHP ?
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.
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.
Outlet Pressure = 250 psia.
Oil Production Rates (STBD)– Mukherjee & Brill:
Gas Lift (mmscf/d) Completion 0 (base) 0.5 1.0 2.0 base (skin = 3) acidized (skin = 0) fractured (skin = -2) Method :
• Change the vertical flow correlation to Mukherjee & Brill. • Run Operations > Nodal Analysis
o Enter Given Outlet Pressure.
o Leave “Max Rate” empty (PIPESIM will calculate rates upto the AOFP) o For “Inflow Sensitivity”, enter skin values of 3,0,and -2.
o For “Outflow Sensitivity”, enter gas lift rate values of 0,0.5,1.0and 2.0 mmscf/d. • Generate Nodal Analysis plot.
• Inspect plot to determine answers.
The discrepancy between Beggs & Brill and Mukherjee & Brill, ranges from 1-15%. However, both cases agree fairly well in terms of relative added benefit shown by sensitivity cases. Notice that in changing the flow correlation, the inflow curves remain unchanged. This is because Nodal Analysis
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:
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
QGas (MMSCFD) P (psia) wf
9.728 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:
x-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).
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
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
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
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
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 P
suction <P
bubble 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%..
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.
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:
