Training Course notes.pdf

7/25/2019 Training Course notes.pdf

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Petroleum Experts

Integrated Production Modelling

An Introduction to PROSPER,MBAL & GAP

November 2007

Training Course Notes


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The copyright in this manual and the associated computer program are the property of Petroleum ExpertsLtd. All rights reserved. Both, this manual and the computer program have been provided pursuant to aLicence Agreement containing restriction of use.

No part of this manual may be reproduced, transmitted, transcribed, stored in a retrieval system, ortranslated into any language, in any form or by any means, electronic, mechanical, magnetic, optical orotherwise, or disclose to third parties without prior written consent from Petroleum Experts Ltd., SpectrumHouse, 2 Powderhall Road, Edinburgh, EH7 4GB, Scotland, UK.

Petroleum Experts Ltd. All rights reserved.

IPM Suite, GAP, PROSPER, MBAL, PVTP, REVEAL, RESOLVE, IFM and OpenServer are trademarks ofPetroleum Experts Ltd.

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The software described in this manual is furnished under a licence agreement. The software may be used

or copied only in accordance with the terms of the agreement. It is against the law to copy the software onany medium except as specifically allowed in the license agreement. No part of this documentation may bereproduced or transmitted in any form or by any means, electronic or mechanical, including photocopying,recording, or information storage and retrieval systems for any purpose other than the purchaser's personaluse, unless express written consent has been given by Petroleum Experts Limited.

Address:

Petroleum Experts LimitedPetex House

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Tel : (44 131) 474 7030Fax : (44 131) 474 7031

email: [email protected]: www.petex.com

Copyright Notice

2

2007 Petroleum Experts Ltd.


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IContents

November, 2007

Table of Contents

0

Chapter 1 IPM Course - Introduction 1

................................................................................................................................... 11 Objectives

................................................................................................................................... 22 The IPM Concept

................................................................................................................................... 33 The IPM Modelling Platform

................................................................................................................................... 54 Introduction and Scope of Work

Chapter 2 PROSPER - Wellbore Modelling Exercises 6

................................................................................................................................... 61 Problem 1: System solution using PROSPER

................................................................................................................................... 92 Problem 2: Flow line modelling within PROSPER

................................................................................................................................... 133 Problem 3: Review Exercise

................................................................................................................................... 164 Problem 4: Importance of correct PVT

................................................................................................................................... 185 Problem 5: Effect of oil FVF on production

................................................................................................................................... 206 Problem 6: Flow correlation selection within PROSPER

................................................................................................................................... 227 Problem 7: Well bore modelling review exercise

................................................................................................................................... 268 Problem 8: Running Sensitivities studies in PROSPER for matched well models

Chapter 3 PROSPER - Well Inflow ModellingExercises 28

................................................................................................................................... 281 Problem 9: Building a Darcy well inflow model

................................................................................................................................... 302 Problem 10: Effects of Water cut on IPR

................................................................................................................................... 313 Problem 11: Use PROSPER to build a Karakas and Tariq skin Model

................................................................................................................................... 344 Problem 12: Use PROSPER to build a Gravel Pack design model

................................................................................................................................... 365 Problem 13: Review Exercise

................................................................................................................................... 406 Problem 14: Building IPR Model for Horizontal well with closed boundaries.

................................................................................................................................... 427 Problem 15a: Multilayer IPR models (Case 1).

................................................................................................................................... 458 Problem 15b: Multilayer IPR models (Case 2).

................................................................................................................................... 479 Problem 16: Building Multi-rate C & n inflow model for gas wells

Chapter 4 PROSPER - Artificial Lift Design Exercises 49

................................................................................................................................... 491 Problem 17: Gas Lift Design

................................................................................................................................... 522 Problem 18: Using Quick-look option of PROSPER as a diagnostic tool

................................................................................................................................... 543 Problem 19: ESP Design

Chapter 5 PROSPER - Multi-Lateral Well Exercises 56

................................................................................................................................... 561 Problem 20: Multi-branch completion modelling

................................................................................................................................... 602 Problem 21: Complex Horizontal Well Modelling


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IPM Training Course NotesII

Chapter 6 MBAL - Reservoir Modelling Exercises 63

................................................................................................................................... 631 Problem 22: Building Tank model for a reservoir with a known production history

................................................................................................................................... 662 Problem 23: Review Exercise.

................................................................................................................................... 683 Problem 24: Use of MBAL for oil water contact monitoring

................................................................................................................................... 694 Problem 25: Performing Predictions using MBAL.

................................................................................................................................... 705 Problem 26: Building a Tank Model for a Reservoir with Know Production History by Well

Chapter 7 GAP - Surface Network ModellingExercises 73

................................................................................................................................... 731 Problem 27: Integrated Production Modelling Model Setup

................................................................................................................................... 752 Problem 28: Integrated Production Modelling Solve Network

................................................................................................................................... 763 Problem 29: Integrated Production Modelling Production Forecasting

................................................................................................................................... 784 Problem 30: Gas Lift Optimisation

Chapter 8 OpenServer - OpenServer Tutorial 80

................................................................................................................................... 801 Problem 31a: OpenServer Exercise 1

................................................................................................................................... 812 Problem 31b: OpenServer Exercise 2

Chapter 9 IPM Review - Workshop 82

................................................................................................................................... 821 IPM Review - Workshop

Chapter 10 Appendix A: GAP Constrained NetworkOptimisation 84

................................................................................................................................... 841 GAP Constrained Network Optimisation


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IPM Course - Introduction 1


1 IPM Course - Introduction

1.1 Objectives

Integrated Field Development AnalysisOptimisation and Forecasting

Overall Objectives:

1. Developing the dexterity skills of the programs2. Basic understanding of the physics3. Understanding the limitation of the methods and techniques used

Agenda:Day 1

Introduction to integrated production system and overall approachIntroduction to PROSPERPressure loss in wellboreImportance of PVTVLP correlations theoryBuilding a wellbore model, Matching PVT and flow correlations, and generation oflift curves for output to GAPor simulator.

Day 2Inflow performance models

Gas lift designESP DesignUse of Quick-look for gas lift

Day 3Introduction to MBALRunning and matching prediction, importing VLP's and IPR's from PROSPERIntroduction to Multi-PVT MBAL

Day 4Introduction to GAPBuilding surface network model- linking PROSPERwell models

Generation of surface performance curvesLinking PROSPER, MBALand GAPfor full field optimisation and forecasting

Day 5Workshop


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1.2 The IPM Concept

In its simplest form a production system can be visualised as shown in the sketch below.

The following elements need to be considered when studying the behaviour of such asystem:

For a given reservoir how much of oil / gas is recovered at separator leveldepends on the facilities that connect the two.

Thus any strategy designed to maximise / optimise the oil and gas recovery of thefield requires simultaneous modelling of the reservoir, facilities and the separator.

Decision making process should be based on how these components interactwith each other.

This type of model could be used to fulfil different objectives such as:

Decision making process should be based on how these components interactwith each other.

Production Allocation

Optimally meeting Production Targets

Short-Term to Long-Term Forecasting

Maintenance Planning


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1.3 The IPM Modelling Platform

The Petroleum Experts toolkit is designed to build and study a complete integrated model.

The following tools are used for the different modelling aspect:

PROSPER, Single Wellbore-Modelling Tool

MBAL, Material Balance Reservoir Modelling Tool

GAP, General Allocation ProgramSurface Network Modelling and Optimisation ToolGAPis the total system-modelling tool. It models the surface network internally.For modelling reservoirs it calls MBALtool and uses it.For well modelling it calls PROSPERand uses it.

The following sketch is drawn to explain how these tools interact with each other.

PVTP, Fluid Characterisation ToolPVTPis used to characterise the fluid pressure - volume temperature behaviour andis used to construct models that will be used by other tools.

REVEAL, Specialised Numerical Simulator Reservoir Modelling Tool

RESOLVE, IPM controller, establishing the link between the IPM suite andthird-party tools.

IFM, Integrated Field Management


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IFM is a tool that provides the engineers with the ability to keep these IntegratedModels Valid and perform the various tasks (one of which is rate allocation forinstance) through pre-defined workflows that the engineers can follow.


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1.4 Introduction and Scope of Work

In the overall scheme that we will follow during this course we will build an integrated modelof a very simple field, with two-reservoir block being produced by one well.

Then we will model each component of the system, the wells, the reservoirs and thegathering network in a sequential manner.

At each stage we will be adding more information that may be available to us and see thevalue of the added information.

At the end, we should be capable to use the field scale integrated model, to study theresponse of our total system.

We will start by drawing the simple system we want to model and then proceed in asequential manner. The system sketch is given in below.

Also, in order to keep track of what we will be doing it is better to use the following directorystructure.

Save this GAPfile as day1/Simple.GAP.


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2 PROSPER - Wellbore Modelling Exercises

2.1 Problem 1: System solution using PROSPER

Objective:

This problem is designed to:

- Introduce PROSPER to the student,

- Help the user to familiarise with PROSPER,

- Show how to enter PVT data, IPR and VLP data

- Show how to perform a system (VLP + IPR) using PROSPER and

- Show where to find the desired results

Given PVT, IPR and well completion data, calculate the flow rate for this naturally

flowing oil well if the flowing well head pressure is 450 psig.

Dataset:

BLACK OIL PVT DATA

Reservoir Flu id Oil and Water

Separator Single-Stage

Solution GOR 800 (SCF/STB)

Oil Gravity 35 (API)

Gas Gravity 0.78

Water Sal ini ty 80000 (ppm)

EQUIPMENT DATA

DEVIATION SURVEY


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PROSPER - Wellbore Modelling Exercises 7


Meas ured Dep th (feet) True Vertic al Dep th (feet)

0 0

1000 10001500 1500

1954 1950

2262 2250

3077 3000

8993 8000

12672 11000

12960 11200

13435 11500

DOWNHOLE EQUIPMENT

Label Equ ipment Type

MD (feet) ID (inches) Roughness (inches)

Wellhead Xmas Tree 0 N/A N/A

Tubing Tubing 1100 3.992 0.0006

Safety Valve SSSV 1100 3.6 N/A

Tubing Tubing 13000 3.992 0.0006

Casing Casing 13400 6.13 0.0006

GEOTHERMAL GRADIENT

Measured depth(feet)

TemperatureoF

0 60

1000 50

13400 250

Overal l Heat Transfer Coeff ic ient 8 (BTU/h/ft2/F)

INFLOW PERFORMANCE DATA

Over twenty inf lo w op tions are avai lable.

The choice depends upo n the avai lable information and the type of sensit iv i t ies thatyou wish to run


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Method PI Entry

Reservoir Pressur e 5200 psig

Reservoir Temperature 250.0 oF

Water Cut 0 %

Total GOR 800.0 SCF/STB

Product iv i ty Index 10 STB/day/psi

Compaction Permeabi l i ty

Reduct ion

No

Relative Permeabi l i ty No

RESULTS

Well Head Pressu re 450 psig

Oil Rate 8699.0 STB/day

Flowing BH Pressure 3316.8 Psig

Flowing Wellhead Temperature degF

Save this PROSPERfile as prob1.out.


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2.2 Problem 2: Flow line modelling within PROSPER

Objective:


- Show how to include pipeline into a PROSPER model,

- Show how to describe pipelines,

- Show the impact of pipeline on a well bore model

- Reinforce how to perform a system (VLP + IPR) using PROSPER and

- Review where to find the desired results

Given PVT, IPR, well completion data and surface pipeline, calculate the flow rate for

this naturally flowing oil well if the downstream pressure at the delivery point (herecalled Manifold, NOT well head) is 450 psig.

START WITH THE prob 1.out FILE

Dataset:

BLACK OIL PVT DATA

The PVT Data is similar to that of Problem 1.

Reservoir Flu id Oil and Water




Gas Gravity 0.78


EQUIPMENT DATA

DEVIATION SURVEY


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Meas ured Dep th (feet) True Vertic al Dep th (feet)

0 0

1000 10001500 1500

1954 1950

2262 2250

3077 3000

8993 8000

12672 11000

12960 11200

13435 11500

Note: The zero depth o f the deviat ion sur vey refers to the MSL /rig depth.

SURFACE EQUIPMENT SKETCH

PIPELINE DATA

Pipel ine ID 4

Ambient Temp. 55 F

Overal l Heat Transfer Coefficient 8.5 BTU/h/ft2/F

DOWNHOLE EQUIPMENT


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Label Equ ipment Type

MD (feet) ID (inches) Roughness (inches)

Wellhead Xmas Tree 1000 N/A N/A

Tubing Tubing 1100 3.992 0.0006

Safety Valve SSSV N/A 3.6 N/A

Tubing Tubing 13000 3.992 0.0006

Casing Casing 13400 6.13 0.0006

GEOTHERMAL GRADIENT


TemperatureoF

0 60

1000 50

13400 250

PROSPERrequires the us er to enter the temp erature at the w ell head

Overall Heat Transfer Co efficient : 8 (BTU/h/ft2/F)


Method PI Entry



Water Cut 3.3 %


Product iv i ty Index 10 STB/day/psi

Compaction Permeabi l i ty

Reduct ion

No

Relative Permeabi l i ty No

RESULTS


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Manifold Pressure 450 psig

Oil Rate 8699.0 STB/day

Flowing BH Pressure 3316.8 Psig

Flowing Wellhead Pressu re Psig

Flowing Wellhead Temperature degF



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2.3 Problem 3: Review Exercise

Objective:

This is a review exercise of how to build well bore models. The input data is given

below. It is required to calculate the Oil Rate, FWHP, FWHT and FBHP for two cases,one case considering the flow line and a second case without considering the flowline.

START WITH AN ENTIRELY NEW FILE

Dataset:

BLACK OIL PVT DATA

Reservoir Fluid Water and Oil


Solution GOR 700.0 (SCF/STB)

Oil Gravity 42.00 (API)

Gas Gravity 0.80 (sp. Gravity)


EQUIPMENT DATA

DEVIATION SURVEY

Measured Depth (feet) True Vertical Depth (feet)

0 0

100.0 100.0

2500.0 2480.0

6500.0 6300.0

15000.0 14000.0

Note: The zero depth o f the deviat ion surv ey refers to the mean sea level depth.

PIPELINE SKETCH


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DOWNHOLE EQUIPMENT

Label Measured Depth

Feet

Inside

Diameter (inches)

Roughness

(inches)

Xmas Tree 100.0

Tubing 14000.0 3.96 0.0006

Casing 15000.0 6.00 0.0006

GEOTHERMAL GRADIENT


TemperatureoF

0 60

100 50

15000.0 200

Overal l Heat T rans fer Coef fi ci en t 8.0 (BTU /h /f t2/F)

PIPELINE DATA

Pipel ine ID 4

Ambient Temp. 50 F

Overall Heat Transfer Coefficient 8.5



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Method PI Entry

Reservoir Pressure 5000.0 psig


Water Cut 20 %


Productivity Index 15.0 STB/day/psi

RESULTS

Case With Flowline Without Flowline

Top Node Pressure 200 (Psig)

Water Cut 20 (%)

Oil Rate 5446.6 STB/day 7903.9 STB/day

Flowing Well Head Pressur e 435.9 Psig 200 Psig

Flowing Well Head Temperature 110.3 F 127.9 F

Flowing BH Pressure 4546.1 Psig 4341.3 Psig



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2.4 Problem 4: Importance of correct PVT

Objective:


Demonstrate how to enter PVT lab data into PROSPER,

Match black oil correlation to lab data,

Show the impact of PVT parameters on well response

The following procedure can be used to go through this example:

Start from the saved file prob2.out

Enter the PVT data, match the black oil correlation to the PVT lab data and

recompute the flow rate for this naturally flowing oil well if the flowing wellhead pressure is 450 psig.

Compare the results with Problem 2 (un-matched PVT case).


Dataset:

PVT MATCH DATA

The PVT calculat ion method is identical for al l reservoir f lu id types (i .e. oi l and water,cond ensate or gas). The choice of f lu id type affects the choice of IPR and VLP mod elsas well as the range o f avai lable sensit iv i ty variables.

Temp.F

PressurePsig

Bubble Point(psig)

Gas Oil Ratio(SCF/STB)

Oil FVFRB/STB

Oil ViscositycP

250 3600 3600 800 1.25 0.31

RESULT


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Manifold Pressu re 450 psig

Black Oil Correlation fo r Pb, Rs, Bo

Black Oil Correlation for o

Oil Rate STB/day

Flowing Well Head Pressur e Psig

Flowing Well Head Temperature F

Flowing BH Pressure Psig



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2.5 Problem 5: Effect of oil FVF on production

Objective:




Show the impact of PVT parameters on well response


Enter the PVT data, match the black oil correlation to the PVT lab data and

recompute the flow rate for this naturally flowing oil well if the flowing well

head pressure is 450 psig.

Compare the results with Problem 2 (un-matched PVT case) and Problem 4

(matched with erroneous oil FVF).


Dataset:

PVT MATCH DATA

Temp.F

PressurePsig

Bubble Point(psig)


Oil FVFRB/STB

Oil ViscositycP

250 3600 3600 800 1.456 0.31

RESULT


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Manifold Pressu re 450 psig

Black Oil Correlation fo r Pb, Rs, Bo

Black Oil Correlation for o

Oil Rate STB/day

Flowing Well Head Pressur e Psig

Flowing Well Head Temperature F

Flowing BH Pressure Psig



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2.6 Problem 6: Flow correlation selection within PROSPER

Objective:




Match well test VLP correlation

Use the calibrated correlation to predict the well rate for future operating


Recall the PROSPER file generated while solving the problem 1.

Enter the PVT data, match the black oil correlation to the new PVT lab data,

Select the most appropriate black oil correlation

Quality-check the well test data,

Match the well test data with the most suitable VLP correlation

Use the calibrated model to predict the oil rate if the water cut increases to

35% while everything else remains unchanged.

START WITH THE pro b1.out FILE

Dataset:

PVT MATCH DATA

Temp.F

PressurePsig

Bubble Point(psig)


Oil FVFRB/STB

Oil ViscositycP

250 3600 3600 800 1.456 0.31

WELL TEST DATA


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Well head pressure 375 psig

Well head temperature 157 F

Total GOR 600 SCF/STB

Free GOR 0 SCF/STB

Water Cut 0.5 %

Gauge Depth 12500 feet

Gauge Pressure 3257 psig

Liquid Rate 11350 STB/day

Static Reservoir Pressure at test time 5200 psig

RESULT

Parameters Value

Calibrated U-value (Btu/h/ft2/F):

VLP correlation selected:

Gravity correction for VLP correlation (Parameter 1):

Friction correction for VLP correlation (Parameter 2):

Well Productivity Index (STB/d/psi):

Liquid rate if water cut = 35% (STB/d):

Save this PROSPERfile as well1.out.


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2.7 Problem 7: Well bore modelling review exercise

Objective:

The fol lowin g d ataset is avai lable:

PVT data measured from the laboratory.

A well test with a down-hole gauge measurement

Downhole equipment descr ip t ion

Bu i ld a PROSPERwel l m odel . Then, bui ld a PVT model that reproduces the m easured

data using PROSPER.

Use PROSPER t o q ual i ty c hec k th e d own-h ole p res su re d ata an d th en s elec t a

pressure drop corre la tion based on i t . Use th is ca l ibra ted wel l bore m odel to f ind the

flowin g BHP, WHT and pro ductio n rates.

START FROM AN ENTIRELY NEW FILE

Dataset:

PVT DATA


Separator Two-Stage

Separator Pressur e 200(psig)

Separator Temperature 90 (F)

Separator GOR 2650 (SCF/STB)

Tank GOR 150 (SCF/STB)


Separator Gas Gravity 0.737

Tank Gas Gravity 1.35


Reservoir Temperature 313 (degree F)

Bubble point pressure atreservoir temperature

7785.3 (psig)

Av. Gas Gravity: 0.769839 / GOR: 2800 scf/stb

EQUIPMENT DATA


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DEVIATION SURVEY

Measur ed Dep th (f eet ) Tr ue Ver ti cal Dep th (f eet )

0 0

1856.96 1843.83

11358.30 8307.09

20544.60 12322.80

22385.20 12821.50

23845.10 13566.30

DOWNHOLE EQUIPMENT

Label Measured Depth Feet

InsideDiameter (inches)

Roughness(inches)

Xmas Tree 85.3

Tubing 1857 4.13 6 E-5

SSSV 3.81

Tubing 11423.9 4.13 6 E-5

Restriction 3.75

Tubing 20600.4 4.13 6 E-5

Restriction 3.75

Tubing 22319.6 3.18 6 E-5

Casing 23218.5 3.81 6 E-5

GEOTHERMAL GRADIENT


TemperatureoF

85.3 68

23218.5 313

Overal l Heat Transfer Coeff ic ient 1 to 10 (BTU/h/ft2/F)



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Method Vogel



Water Cut 0 %


TEST DATA

Well head pressure 3235.3 psig

Well head temperature 183 F


Free GOR 0 SCF/STB

Water Cut 0 %

Gauge Depth 15251 feet

Gauge Pressure 5796.8 psig


Static Reservoir Pressure at test time 7785.3 psig

RESULT

Parameters Value

Calibrated U-value (Btu/h/ft2/F):

VLP correlation selected:

Gravity correction for VLP correlation (Parameter 1):

Friction correction for VLP correlation (Parameter 2):

Test BHP (psig):

Liquid rate if WHP = 450 psig and water cut = 35%

(STB/d):


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Save this PROSPERfile as well2.out.


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2.8 Problem 8: Running Sensitivities studies in PROSPER formatched well models

Objective:

Use one of the well mod els generated previously, run a set of sensit iv i t ies on it and

com pare the results obtained.

START FROM THE "well1.ou t" FILE.

Dataset:

Part I

At what water cut will the well die (WHP = 450 psig) at the following reservoirpressures?

5200 psig

4000 psig

Sensitivity variables to use:

Water cut :0, 10, 20, 30, 40, 50, 60, 70, 80, 90%

Reservoir Pressure :5200, 4000 psig

RESULT

Reservoir Pressure (psig) 5200 4000

Water cut (%) 30 45

Part II

Find the production rate at the two specific cases below (WHP=450 psig)

RESULT


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Case 1 Case 2

Reservoir Pressure (psig) 4000 5200

Water cut (%) 15 40

Liquid Rate (STB/day) 3198.7 (aut. geom.) 3237.1 (aut. geom.)

Save this PROSPERfile as Prob8.out.


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3 PROSPER - Well Inflow Modelling Exercises

3.1 Problem 9: Building a Darcy well inflow model

Objective:Use the Darcy inf low mo del of PROSPER to estimate the Well Inf low Performanc e..

START FROM THE "well1.ou t" FILE.

Dataset:


Method Darcy

Reservoir Pressure 5000 psig

Reservoir Temperature 250 F

Water Cut 25 %


Reservoir Permeability 65 md

Reservoir Thickness 100 feet

Drainage Area 390 acres

Dietz Shape Factor 31.6Well-Bore Radius 0.354 feet

Skin 0

RESULT

AOF for Skin = 0 38497.6 STB/day

If Q = 10000 stb/d and BHFP = 3665 psig

was a test point, what skin would berequired to match this test point?

Equivalent PI 13.4 STB/day/psi

AOF STB/day


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PROSPER - Well Inflow Modelling Exercises 29




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3.2 Problem 10: Effects of Water cut on IPR

Objective:Investigate the effects of w ater cut o n the well inf low perfomance.

START FROM THE "p rob09.out" FILE.

Dataset:

VARIABLES

Run sensitivity on water cut using the Inflow Calculation section.

The water cut values used are the following:

0, 20, 40, 60 and 80%

RESULT

Compare the results - Discuss.Save this PROSPERfile as prob10.out.


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3.3 Problem 11: Use PROSPER to build a Karakas and Tariq skinModel

Objective:

A slanted well is going to be drilled to perforate the same pay as Well1.Use the Karakas and Tariq model in PROSPERto model various components of skin

and analyse their contribution to total skin.


Dataset:

INFLOW SKIN DATA

Method Darcy

Perforation Diameter 0.25 inches

Shots Per foot 8

Perforation Length 12 inches

Damaged Zone Thickn ess 8 inches

Damaged Zone Permeabi l i ty 32 md

Crushed Zone Thickn ess 0.2 inches

Crushed Zon e Permeabi l i ty 16 md

Deviation 53 deg

Penetration 0.5

Vertical Permeabi l i ty 6.5 md

Wellbore Radius 0.354 feet

Shot Phasing 120 deg

Skin due to Perforat ion Model

Karakas and Tariqhas been found to give good results in many field applications and isexplained here.

A sketch outlining the main geometric variables is shown below


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The following input data is required:

Reservoir permeability (Effective permeability at connate water saturation)

Perforation diameter (Entry hole diameter)

Shots per foot

Perforation length (Effective perf. length in formation)

Damaged zone thickness (Thickness of invasion)

Damaged zone permeability (Permeability in invaded zone)

Crushed zone thickness (Crushing associated with perforation)

Crushed zone permeability (Reduced permeability near perf. tunnel)

Shot phasing

Vertical permeability

Wellbore radius (Enter the open hole radius, not casing I.D.)

Deviation /Partial Penetration Skin

Two models of this type are provided in PROSPER:

Cinco / Martin Bronz

Wong Clifford

For this exercise, the first model is going to be used.It requires the following data:

Deviation angle of well

Partial penetration fraction

Formation vertical permeability

Penetrat ion is the proport ion o f the total reservoir thickness that is com pleted. (e.g. a


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200 ft thick reservoir with 100 ft of perforat ions wou ld have a Penetrat ion of 0.5)

Dev ia tion sk in is ca lcu lated us ing Cinco-Ley 's method, and is therefore val id up to 75

degrees d eviat ion.

The calculation is based upon the paper by Cinco-Ley, H., Ramey, Jr., H.J. and Miller, F.G.:

"Pseudo-Skin Factors for Partially-Penetrating Directionally-Drilled Wells", SPE 5589presented at 50th Annual Fall Meeting of SPE of AIME, Dallas, TX, September 28 -October 1, 1975

RESULT

Absolute Open Flow 307.5 STB/day

Total Skin 4.77

Perforation Skin 0.178

Partial Penetration Sk in 6.693

Deviation Skin -2.104

Equivalent PI 10.61 STB/day/psi



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3.4 Problem 12: Use PROSPER to build a Gravel Pack design model

Objective:Calculate the IPR for the slanted well in problem 11 if a gravel pack is to be included.Open the PROSPERfile prob11.out, then from the main screen (Options) select well

completion with Gravel Pack.


Dataset:

INFLOW GRAVEL PACK DATA

PROSPER models gravel packed completions as a concentric cylinder having a userspecified permeability connected to the wellbore via perforations of specified diameter. By

sensitising on perforation spacing and diameter, the effect pressure drop due to flowconcentration on well performance can be investigated. Likewise, the effect of varyinggravel length (i.e. the thickness of gravel between the OD of the screen and the ID of theoriginal open hole) on skin can be evaluated.

Gravel pack permeability (Enter the in-situ permeability for the gravel)Perforation diameter (Diameter of perforation tunnel)Shots per footGravel pack length (Distance from the screen O.D. to the sand face)Perforation interval (This affects the flow velocity in the perforations only)Perforation efficiency (Proportion of perforations that are open and effective)

INPUT DATA


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Method Darcy

Gravel Pack Permeability 90000 md

Perforation Diameter 0.25 inchesShots per foot 8

Gravel Pack Length 1.8 inches

Perforation Interval 74 feet

Perforation Efficiency 1

Beta Factor Calculated

Method Multiphase

RESULT

What is the Absolute Open Flow (AOF) of this well in STB/d:

What was the AOF in stb/d prior to the gravel pack installation?

With gravel pack, how much gravel pack dP is lost across the gravel if

the well produces 10,000 STB/d?

With gravel pack, what is the velocity in ft/second of the fluid at the

casing for a WHP of 350 psig:



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36

November, 2007

3.5 Problem 13: Review Exercise

Objective:

This example is designed to go through the following subjects:

How to set up a PROSPERwell model for a dry gas well How to customise the set of unit used

How to predict the production rate of a well using a well model

How to select the right tubing size for various conditions

START FROM AN ENTIRELY NEW FILE.

Dataset:

1. Statement of the problem:

A new gas field has been discovered offshore.The top of the reservoir is 3460 m TVD below the mean sea level.The water depth is 330 m. A sub-sea well head completion is foreseen.

The dataset available is as follows:

1.1. PVTFrom the discovery well, a gas sample was taken and analysed. The gas composition is:

Component Mol. Percent Molecular Weightlbm/lbmol

Nitrogen 2 28

Carbon Dioxide 0.5 44

Methane 95 16

Ethane 2 30

Propane 0.5 44

(Mwair=28.96)

Separator pressure: 1000 psigCondensate Gas Ratio: 1 stb/MMscfCondensate Gravity: 50 API

Water Salinity: 100 000 ppm

1.2. Reservoir parameters


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Initial Reservoir pressure 5300 psig

Reservoir Temperature 230 deg F

Average Reservoir permeability 25 mD

Porosity 15 %Connate Water Saturation 25 %

Gross Pay 300 feet

N/G Ratio 40 %

Drainage Area 500 acres

Dietz shape factor 31.6

Skin factor (initial assumption) 0

Time from start production 100 days

Drill bit size 12 1/4 (0.51 ft Wellbore Radius)

1.3. Downhole Equipment

According to the original design, the well should be completed as follows:

Well orientation Straight hole

Tubing size 2.9ID down to 3400 m

Casing 8.5 ID down to top perforation

SSSV (ID = 2.5) 1000 m below mean sea level

Formation Temperature at well head depth 40 degF

Average Sea Temperature 60 deg

Overall Heat Transfer Coefficient (downhole) 3 Btu/h/ft2/F

2. Questions

Question No.1:Assuming a well head flowing pressure of 3000 psig, calculate the gas rate to be expectedwith the fluid and reservoir parameters given above.

Answer:MMscft/day

Question No.2:Is it possible to increase the performance of the well by selecting a different tubing size?Which tubing size can be recommended?

Tubing Size (ID) available are: 2.9, 3.5, 3.9, 4.8, 5.5

Answer:..MMscft/day with in tubing.

Modify the model to take into account the tubing size that has been selected.


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November, 2007

Question No.3:If we take into account the skin caused by the perforations, how much would the wellproductivity be affected assuming the WHP of ?

Skin Calculation:

Perforation Diameter 0.5

Shots per foot 6

Perforation length 12

Damage Zone Thickness 8

Damage Zone Permeability K*50% = 12.5 mD

Crushed Zone Thickness 0.2 in

Crushed Zone Permeability K*25%= 6.25 mD

Deviation 0 deg

Vertical Permeability K*10% = 2.5mD

Shot Phasing 120 deg

Answer:.MMscft/day.

Question No.4:If a gravel pack screen is used, by how much will the productivity of the well be affectedassuming the same WHP as Question 1?

Gravel Pack Permeability (mD) 10000 (5), 20000 (10), 35000 (15) *

Gravel Pack Length 2

Perforation Efficiency 80%

(* The number in brackets corresponds to the R value for the gravel pack)

Which Gravel Pack Permeability has to be selected in order to maximise the productivity ofthe well?

Answer:.. mD will give .MMscft/day.

Question Nr.5:

After drilling and completing this well (with the gravel pack selected), a test was made andthe following test data are available:


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THP 2350 psig

THT 174 deg F

Gas Rate 70 MMscft/day

WGR 0CGR 1

Gauge Depth 3400 m

Gauge Pressure 3038 psig

Select the Correlation which best represents pressure losses in the well and match it to thetest data. Then determine if the IPR model used is representative of the well and determinethe most likely cause of the deviation.

Answer:The . Flow Correlation was selected.

Most likely cause of the deviation in the IPR: .......................



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November, 2007

3.6 Problem 14: Building IPR Model for Horizontal well with closedboundaries.

Objective:

Use PROSPERto bu i ld Hor izon tal Wel l in f low in c lose boundary rec tangu lar sys tem

and find the AOF. Find the effect of vert ical permeabil i ty on inf low .


Dataset:


This model is based on the work of Kuchuk and Goode. The inflow model used hereassumes that the horizontal well is draining a closed rectangular drainage volume withsealing upper and lower boundaries. The well can be placed anywhere in the drainageregion. Pressure drops along the well bore itself are not taken into account.

Reservoir permeability (Total permeability at prevailing water cut)

Reservoir thickness (Thickness of producing reservoir rock)

Wellbore radius

Horizontal anisotropy (Ratio of Ky/Kx where Kx is permeability in thedirection of the horizontal well and Ky is thepermeability perpendicular to the horizontal well)

Vertical anisotropy (Ratio of Kz/Ky where Kz is the verticalpermeability)

Length of well L

Length of drainage area Lx

Width of drainage area Ly


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Distance along length edge (Xw)

Distance along width edge (Yw)

Distance from bottom (Zw)

Method Hor izon tal Well No f low B oundar ies


Reservoir Temperature 250.0 degrees F

Water Cut 25 %

Total GOR 800 scf/stb

Reservoir Permeability 65 mD

Wellbore Radius 0.354 feet

Reservoir Thickness 100 feet

Horizontal anisotropy 1 fraction

Vertical anisotropy 0.1 fraction

Length of well 1500 feet

Reservoir Width 6000 feet

Reservoir Length 6000 feet

Distance from length Edge to centre of the well 3000 feet

Distance from Width Edge to centre of the well 3000 feet

Distance from Bottom to centre of the well 50 feet

Skin 3

RESULTS

Vertical Anisotropy AOF (STB/day)

0.0083 165500

0.015 199400

0.030 242100

0.100 316700

Save this file as Prob14.out


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November, 2007

3.7 Problem 15a: Multilayer IPR models (Case 1).

Objective:

Use PROSPERto bu i ld a Gas Mult i layer well .

In th is case one layer on top o f the o ther wi thou t any pressure drop in the we llbo rebetween them.


Dataset:

PVT DATA

Reservoir Fluid Dry and Wet Gas


Gas Gravity 0.801

Separator Pressu re 200 (psi)


CGR 5 (STB/MMSCF)

WGR 0 (STB/MMSCF)


EQUIPMENT DATA

DEVIATION SURVEY

Measur ed Dep th (f eet ) Tr ue Ver ti cal Dep th (f eet )

0 0

1856.96 1843.83

11358.30 8307.09

20544.60 12322.80

22385.20 12821.50

23845.10 13566.30

DOWNHOLE EQUIPMENT


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Label Measured Depth Feet

InsideDiameter (inches)

Roughness(inches)

Xmas Tree 0

Tubing 1857 4.13 6 E-5

SSSV 3.81

Tubing 11423.9 4.13 6 E-5

Restriction 3.75

Tubing 20600.4 4.13 6 E-5

Restriction 3.75

Tubing 22319.6 3.18 6 E-5

Casing 23218.5 3.81 6 E-5

GEOTHERMAL GRADIENTMeasured depth

(feet)Temperature

oF

0 68

23218.5 313

Overal l Heat Transfer Coeff ic ient 1 to 10 (BTU/h/ft2/F)



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November, 2007

Model Mu lt i layer Reservo ir

Layer 1 Layer 2

Layer Pressure (psi) 7785.3 7800.2Layer Height (ft) 100 150

Layer Skin 0 1

Gas Gravity 0.798 0.803

Oil Gravity (API) 39 39

CGR (STB/MMSCF) 5 6

WGR (STB/MMSCF) 0 0

Layer Permeability (mD) 12 35

Drainage Area (acre) 500 500

Dietz Shape factor 31.6 31.6

Wellbore Radius (ft) 0.354 0.354

Once the model is bui l t , determine what is the well overal l produ ction and th e

contr ib ut ion from each layer when the wellhead pressure is 3000 psi.

RESULTS

Wellhead Pressure 3000 psi

Overal l Gas Rate (mm scfd )

Layer 1 Gas Rate (mm scfd )


Save this file as Prob15a.out


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3.8 Problem 15b: Multilayer IPR models (Case 2).

Objective:

Use PROSPERto bu i ld a Gas Mult i layer well .

In th is case there is a s ign i f icant d is tance between layer so we w ould l ike to take in toaccount th e pressure drop in th e wellbore between the layers

START FROM THE "Prob lem15a.out" FILE.

Dataset:



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November, 2007

Model Mu lt i layer dP loss in Wellbore

Layer 1 Layer 2

Layer Pressure (psi) 7785.3 7800.2Layer Height (ft) 100 150

Layer Skin 0 1

Gas Gravity 0.798 0.803

CGR (STB/MMSCF) 5 6

WGR (STB/MMSCF) 0 0

Layer Permeability (mD) 12 45

Drainage Area (acre) 500 500

Dietz Shape factor 31.6 31.6

Wellbore Radius (ft) 0.354 0.354

Perforation Interval (ft) 100 150

Once the model is bui l t , determine what the well overal l produ ction and the

contr ib ut ion from each layer when the wellhead pressure is 3000 psi.

RESULTS

Wellhead Pressure 3000 psi

Overal l Gas Rate (mm scfd )



Save this file as Prob15b.out


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3.9 Problem 16: Building Multi-rate C & n inflow model for gas wells

Objective:

Use the multi-rate C and n IPR method to construct an IPR.Based on this find the well AOF and reservoir pressure.


Dataset:

The C and n IPR Model is based on the following relationship:

Q = C.(Pr2- Pwf

2)n

C and n values are determined from a plot of Q vs (Pr2 - Pwf2) on log-log paper and directlyinput by the user.n is usually found in the range 0.5 (complete turbulence) to 1.

The multi-rate C and n determines the coefficients of the back pressure equation that best fitmeasured flowing bottom-hole pressures.

PVT DATA

Reservoir Fluid Dry Gas

Separator Single Stage

Separator Pressu re 1000 psig

CGR 10 STB/MMscf

Oil Gravity 44.00 API

Gas Gravity 0.77

WGR 0 STB/MMscf

Water Sal ini ty 100000 ppm



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November, 2007

Method Multi -rate C & n

Reservoir Pressu re ?

Reservoir Temperature 302 (degree F)

WGR 0 STB/MMscf

TEST DATA

FBHP (psig) Rate (MMscf/day)

3600 250

3000 500

RESULTS

AOF 1036.8 mmscfd

Reservoir Pressur e 4060.26 psig



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PROSPER - Artificial Lift Design Exercises 49


4 PROSPER - Artificial Lift Design Exercises

4.1 Problem 17: Gas Lift Design

Objective:


Illustrate how to design a gas lifted well with PROSPER

Transfer the design results to the input section

Sensitize on gas lift injection rate during the system (VLP + IPR) calculation

The reservoir pressure is supposed to have decreased down to 4500 psig.


Load the PROSPER file Well1.OUT

Set the Reservoir Pressure to 4500 psig

Under |Options|Options, select |Artificial Lift: GAS LIFT

Select |Design |Gas Lift and enter the gas lift gas gravity of 0.7

Design a gas lift system for the given well configuration

Assuming a single point of injection (orifice only) perform a system calculation with:

o WHFP = 350 psig

o Water Cut = 80%

o GOR = 800 scf/st

o Gas lift injection rates: 0, 0.5, 1,2,3,5,7,8,10 and 15 MMscf/d.

START FROM THE well1.out FILE.

Dataset:

LIFT GAS DATA


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November, 2007

Artif ic ial L if t Method Gas L if t

Gas-l if t Gas Gravity 0.7 sg

Mole Percent H2S 0 %

Mole Percent CO2 0 %

Mole Percent N2 0 %

GAS LIFT DESIGN ( NEW WELL)

Arti f ic ial L ift Method Gas L ift

Valve Type Casing Sensitive

Design Rate Method Calculated from Max Production

Maximum L iquid Rate 35000 STB/day

Maximum Gas Avai lable 6 MMscf/day

Maximum Gas dur ing Unloading 6 MMscf/day

Flowing Top Node Pressure 350 psig

Unloading Top Node Pressure 350 psig

Operating Injection Pressur e 2000 psig

Kickoff In ject ion Pressure 2000 psig

Desired dP Across Valve 100 psi

Packer Depth 13000 feet

Design Water Cut 80 %

Static Gradient Of Load Fluid 0.450 psi/ft

Minimum CHP decrease/valve 50 psi

Minimum Spacing 250 feet

VALVE DETAILS

Valve Type Casing Sens it ive

Manufacturer Camco

Type R-20

Specif ication Normal


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RESULTS

What is the depth of the orifice in ft MD:

Save this PROSPERfile as day2/well1gl.out.


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4.2 Problem 18: Using Quick-look option of PROSPER as adiagnostic tool

Objective:

Using the fi le PROB18_start.out perform a diagnostic usin g Quick loo k in PROSPER.

Calculate the total gas inject ion rate.

START FROM THE PROB18_start.out FILE.

Dataset:

In the file considered:

PVT has been matched to lab data

PI entry has been used as IPR model

Existing Mandrel Valves Information given

WELL TEST RESULTS

Tubing Head Pressur e 113 psig

Tubing Head Temperature 185 F


Water Cut 73.3 %

Total Gas Rate 1.368 MMscf/day

Injection Gas Rate 0.4 MMscf/day

Casing Head Pressur e 1740 psig

Valve Depths and Port sizes

Valve Depth (m) Port size (1/64thinches)

Valve 1 1337 16

Valve 2 1744 20

Valve 3 2098 24

Orif ice 2362 32

DIAGNOSTIC RESULTS


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Likely depth of injection 1744 m

Port size 8.7 1/64th inches


Save this PROSPERfile as prob18_final.out.


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November, 2007

4.3 Problem 19: ESP Design

Objective:

Use the well1.outfi le. Use this f i le perform an ESP design u sing PROSPER.

Then use the ESP selected to stud y various chang ed condit io ns by d oing a sensit iv i tyanalysis.

Use the sensit iv i ty analysis to s ee if the selected ESP is appropriate for al l the flo wingcond it ions the well is potentia l ly going to encounter during its l i fe.

START FROM THE well1.out" FILE.

Dataset:

ESP DESIGN ( NEW WELL)

Arti f ic ial L ift Method ESP

Pump Depth 12000 ft

Operating Frequency 60 Hertz

Maximum OD 6 inches

Design Rate 12000 STB/day

Water Cut 80 %

Top Node Pressure 350 psig

Gas Separation 0 %

Motor Pow er Safety Margin 0 %

Pump Wear Factor 0 %

SENSITIVITY PARAMETERS

Top node pressure: 400 psig

Water Cut: 60, 70, 80, 90 & 95%

Frequency: 50, 55, 60 Hertz

DESIGN RESULTS


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Pump Centrilift KC12000

Motor Centrilift - 562

Cable Cooper

Gas Separation 0 %

Save this PROSPERfile as well1esp.out.


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November, 2007

5 PROSPER - Multi-Lateral Well Exercises

5.1 Problem 20: Multi-branch completion modelling

Objective:

Model a multi-branch completion by using the multilateral modelling option inPROSPER.


Dataset:

COMPLETION DESCRIPTION

Tie point

Branch 3

Branch 1

Branch 2

Upper Layer

Joint

Lower Layer

Available data for the Upper and Lower layer

Upper layer:Reservoir Pressure 5200 psigReservoir Temperature 225 degrees FOil Gravity 35 APIGas Gravity 0.782 sp. gravityWater Salinity 80000 ppmWater Cut 5 percentTotal GOR 820 scf/STBHorizontal Permeability 50 md


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PROSPER - Multi-Lateral Well Exercises 57


Formation Thickness 40 feetDrainage Area 200 acresDepth of Reservoir Top 7850 feetVertical Permeability 5 md

Lower Layer:Reservoir Pressure 5250 psigReservoir Temperature 225 degrees FOil Gravity 35 APIGas Gravity 0.782 sp. gravityWater Salinity 80000 ppmWater Cut 10 percentTotal GOR 820 scf/STBHorizontal Permeability 40 mdFormation Thickness 65 feetDrainage Area 500 acres

Depth of Reservoir Top 7950 feetVertical Permeability 5 md

Branch 1

Measured Depth

(feet)

True Vertical Depth

(feet)

Az imuth

8800 7700 0

8850 7750 0

Tubing

Type

Measured Depth

(feet)

IDs

(ins)

Roughness

(ins)

Start 8800

Tubing 8850 3.92 0.0006

Well bore radius = 0.43 ft

Branch 2

Measured Depth(feet)

True Vertical Depth(feet)

Az imuth

8850 7750 0

9120 7810 45

9300 7840 55

9400 7855 65

9650 7885 75


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November, 2007

Tubing

Type

Measured Depth

(feet)

IDs

(ins)

Roughness

(ins)

Start 8850

Tubing 9650 3.92 0.0006

Perforation s tart (MD),feet

Perfo rat ion end, (MD), feet Local Sk in

9380 9650 0

Well bore radius = 0.43 ftDietz shape factor = 31.6

Branch 3


True Vertical Depth(feet)

Az imuth

8850 7750 0

9200 7950 220

9400 8010 245

TubingType


IDs(ins)

Roughness(ins)

Start 8850

Tubing 9400 3.92 0.0006

Perforation s tart (MD),feet

Perfo rat ion end, (MD), feet Local Sk in

9200 9400 1

Well bore radius = 0.43 ftDietz shape factor = 31.6

RESULT

Solve for 5 points

Tie point p ressure,psig

Flow rate, STB/day


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These points can be transferred to any multi-rate IPR to represent the overall response ofthe multilateral completion.

Save this file as PROB20.out


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60

November, 2007

5.2 Problem 21: Complex Horizontal Well Modelling

Objective:

Using the Mult i lateral option, bui ld a mo del for a complex Horizontal well


Dataset:

COMPLETION DESCRIPTION

PVT DATA

Reservoir Fluid Oil and Water

Oil Gravity 840 Kg/m3

Gas Gravity 0.7

GOR 300 Sm3/Sm3

H2S 0 %

CO2 0.99 %

N2 2.21 %

Water Sal ini ty 20000 ppm

Layer Prop ert ies

Reservoir Pressure 440 Bar


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Reservoir Temperature 113 degrees COil Gravity 840 Kg/m3Gas Gravity 0.7 sp. gravityWater Salinity 20000 ppmWater Cut 0 percentTotal GOR 300 Sm3/Sm3Horizontal Permeability 100 mdFormation Thickness 200 mDrainage Area 600000 m2sDepth of Reservoir Top 2830 mVertical Permeability 50 md

Top Node

Measured Depth(m )

True Vertical Depth(m )

4711 2824

TubingType

Measured Depth(m )

TVD(m )

Azimut IDs (ins)

Roughness(m )

Start 4711 2824 0

Tubing 4924 2923.7 192.31 4 1.524e-5

Well bore radius = 0.15 m

Branch 1

Measured Depth

(m )

True Vertical Depth

(m )

Az imuth

5128.51 2987.53 196.64

5212.58 3004.23 195.72

5348.10 3010.43 197.39

5453.19 2993.64 200.84

5688.61 2905.92 202.71

5818.43 2869.8 204.41

5948.07 2860.61 204.71

6182.47 2889.55 229.31

6616.00 2974.57 229.90

TubingType

Measured Depth(m )

IDs(ins)

Roughness(m )

Start 4924

Tubing 6616 4.0 1.524e-5


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November, 2007

Perfo ration star t (MD), m Perfo ration end, (MD), m Local Sk in

5130 5380 0

5423 5579 0

5604 5665 05767 5975 0

6124 6246 0

6279 6505 0

Well bore radius = 0.15mDietz shape factor = 30

RESULT

Tie Point Pressure 400 bara

Product iv i ty IndexSm3/day/bar

Sk in Rate (Sm3/day)

536 -2.18 4190

Save this file as PROB21.out


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MBAL - Reservoir Modelling Exercises 63


6 MBAL - Reservoir Modelling Exercises

6.1 Problem 22: Building Tank model for a reservoir with a knownproduction history

Objective:


Show how to set-up an MBAL model

Show how to match PVT in MBAL

How to enter tank and historical data into MBAL

How to perform a history match with MBAL

How to perform fractional flow matching and how to verify the reliability of the

fractional flow


Set-up and MBAL model single tank

Match the PVT

Quality-check the historical data

Perform a history match to:

o Estimate the original oil in place

o Check if there is an aquifer

o Quantify the various drive mechanisms affecting this oil reservoir

o Derive pseudo relative permeabilities for use in forecasting mode

o Verify that the pseudo relative permeabilities can reasonably reproduce the

historical water cut and GOR.


Dataset:


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November, 2007

PVT DATA





Gas Gravity 0.78


PVT MATCH DATA

Temp.F

PressurePsig

Bubble Point(psig)


Oil FVFRB/STB

Oil ViscositycP

250 3600 3600 800 1.456 0.31

RESERVOIR PARAMETERS

Reservoir Properties Water and Oil

Reservoir Temperature 250 FReservoir Pressure 5215 psig

Reservoir Thickness 100 ft

Reservoir Radius 2200 ft

Reservoir Porosity 23 %

Connate Water Saturation 15 %

Initial Gas Cap 0

Estimated Oil In Place 250 MMSTB

Production Start 01/02/2000

Aquifer Hurst-Van Everdingen Modified

Outer / Inner Radius 5

Encroachment Angle 180 deg

Aquifer Permeability 20 mD


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RELATIVE PERMEABILITIES

Phase ResidualSaturation

(Fraction)

End Point(Fraction)

Corey Exponent

Water 0.15 0.6 1

Oil 0.15 0.8 1

Gas 0.02 0.9 1

Water Sweep Efficien cy: 100%

Gas Sweep Efficienc y: 100%

PRODUCTION HISTORY

Open the file in day3/res1h.xls and import the table in to MBAL

Save this MBALfile as Res1.mbi.


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November, 2007

6.2 Problem 23: Review Exercise.

Objective:

We have the prod uction history of a under saturated reservoir.

We want to use this history to find the reservoir OOIP and handle the various drivemechanism s that this reservoir has.


Dataset:

PVT DATA





Gas Gravity 0.77


% H2S 0

% CO2 0

% N2 0

PVT MATCH DATA

Temp.F

PressurePsig

Bubble Point(psig)


313 7785.3 7785.3 2800



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Initial Gas Cap 0.1



Production History res2h.xls

Aquifer Model Hurst-Van Everdingen Modified

Aquifer Type Radial

Reservoir Outer / Inner Radius ?? (5)

Encroachment Angle ?? (180 degres)

Aquifer Permeability ?? (10 mD)


Phase ResidualSaturation(Fraction)

End Point(Fraction)

Corey Exponent

Water 0.15 0.7 1

Oil 0.15 0.8 1

Gas 0.02 1 1



Save this MBALfile as Res2.mbi.


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November, 2007

6.3 Problem 24: Use of MBAL for oil water contact monitoring

Objective:

We have a reservoir m odel already h istory matched.

We know all i ts drive mechanism s. We want to see how the con tact moves w ithproduct ion.

START FROM THE "Res1.mbi"FILE

Dataset:

PORE VOLUME versus DEPTH

Pore Volume

(Fraction)

TVD(ft)

0 11477.9

0.25 11520

0.5 11550

1 11577.9

Run the simulation and save the stream as 100% Sweep

Go to the relative permeability screen and change the water sweep efficiency

to 70%.

Re-run the simulation and save the stream as 70% Sweep

Plot, compare and comment the evolution for the oil-water contact in both cases

Save this MBALfile as Prob24.mbi.


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6.4 Problem 25: Performing Predictions using MBAL.

Objective:

We have a reservoir m odel already h istory matched.We know all i ts drive mechanisms.

We want to see run predict io n forecasts using this m odel

START FROM THE "Res1.mbi"FILE

Dataset:

A: Predict Reservoir Pressure only from Production Schedule

We want to know how the Reservoir Pressure / Water Cut and GOR would evolve ifa constant 3500 STB/d of liquid is produced from the end of the Production History

until 1/1/2025

Save this MBALfile as PROB25A.mbi

B: Predict Reservoir Pressure and Production from Manifold Pressure

We plan to produce the reservoir with one well at a constant manifold pressure of360 psi with a maximum liquid production constraint of 3500 STB/d.

We want to know how the Production / Reservoir Pressure/Water Cut and GORwould evolve.

The well lift curves have been already generated using PROSPERand are in the filePROB25.tpd.

The Productivity Index of this well is 16.5 STB/d/psi

Use the file previously saved PROB25A.mbi

Save this MBALfile as PROB25B.mbi


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November, 2007

6.5 Problem 26: Building a Tank Model for a Reservoir with KnowProduction History by Well

Objective:

We have the produc tion histo ry by w ell of a under saturated reservoir.We want to use this histor y to find the reservoir OOIP, understand the various drive

mechanism s that this reservoir has and to match the indiv idu al wells fract ional f low.


Dataset:

PVT DATA





Gas Gravity 0.798


PVT MATCH DATA

Temp.F

PressurePsig

Bubble Point(psig)


Oil FVFRB/STB

Oil ViscositycP

250 2200 2200 500 1.32 0.4



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Initial Gas Cap 0





End Point(Fraction)

Corey Exponent

Water 0.15 0.6 1

Oil 0.15 0.8 1

Gas 0.02 0.9 1



PRODUCTION HISTORY

Open the file in Prob26 - Production History.xls and import the table in to MBAL

PREDICTION WELLS

Well1 PI=15 STB/d/PSIWell2 PI=10 STB/d/PSI

Well1 & Well2 VLPs: PROB26.tpd


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Perform a Prediction using the wells described above using a manifold pressure of 1000 psiuntil 1/1/2015

Save this MBALfile as Prob26.mbi.


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GAP - Surface Network Modelling Exercises 73


7 GAP - Surface Network Modelling Exercises

7.1 Problem 27: Integrated Production Modelling Model Setup

In this section, we will finalize the construction of our Integrated Production Model Simple.

Step 1: Linking all the components

Ensure the reservoirs and wells components in GAPare associated to the correspondingMBALand PROSPERfiles.

Reservoir 1 in GAP: Res1.mbi MBALfileReservoir 2 in GAP: Res1.mbi MBALfileWell 1 in GAP: Well 1.out PROSPERfileWell 2 in GAP: Well 2.out PROSPERfile

Step 2: Generating IPRs and VLPs using PROSPERfiles from GAP

In order to use the VLP/IPR intersection method for our well performance calculations inGAP, we need to generate this data in advance.

Make sure an appropriate range of values (and and spacing) is used when generating LiftCurves (VLPs) as this is key to keep the integrity of the well models.Below there is a suggested range to be used for each well.

Well 1

Variable (OilField Units) Liquid Rate ManifoldPressure

GOR (*) WC

Minimum 100 200 400 0

Maximum 40000 4000 25000 95

Number of values 20 10 10 10

Spacing Geometric Linear Geometric Linear

After generating the values, replace the second value by 800 (solution GOR) as we knowthis exact value will be required while the reservoir pressure remains above the Pb.

Well 2


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Variable (OilField Units) Liquid Rate ManifoldPressure

GOR WC

Minimum 100 200 1500 0

Maximum 40000 6000 25000 95

Number of values 20 10 10 10

Spacing Geometric Linear Geometric Linear

After generating the values, replace the third value by 2800 (solution GOR) as we know thisexact value will be required while the reservoir pressure remains above the Pb.

Step 3: Pipelines Data

WH1 to Manifold WH2 to Manifold Manifold to Sep

Length (ft) 1000 2000 1000

Inside Diamter () 6 8 10

Correlation Beggs & Brill Beggs & Brill Beggs & Brill

Save this as Simple.GAP


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7.2 Problem 28: Integrated Production Modelling Solve Network

a) How much would the field produce if both wells were fully open today (01/07/2005)?

Step 1: Initialise IPRs from tank simulations

When solving the network, the reservoir data used (Reservoir Pressure, WC, GOR, etc)is that of the wells IPR screen.

Initialising the IPRs from tank simulations ensures the Wells IPRs are up to date as perthe reservoir model.MBALwill run a simulation until the date specified (using the production history rates) andupdate the IPRs with the Pr, GOR/CGR and WC/WGR.The IPRs can also be updated manually (ie. no tank models are required for solving thenetwork)

Step 2: Solve Network (No optimisation) with a Separator Pressure of 200 psig

Discuss the results

b) How could we control the field to maximise oil production if we have a maximumliquid constraint at the Separator of 22000 bbl/d?

Step 1: Set the wells controllable (Wellhead choke can be changed by the optimiser)

Step 2: Enter a maximum liquid constraint of 22000 bbl/d at the separator

Step 3: Solve Network (Optimise with all constraints)

Discuss the results


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7.3 Problem 29: Integrated Production Modelling ProductionForecasting

Perform a production prediction (from 01/07/2005 to 01/01/2020 2 months stepsize)for the following different scenarios

a) Both Wells fully open (No optimisation)

Discuss the Results

b) With a maximum liquid rate constraint at the Separator of 22000 bbl/d(Optimisation)

Discuss the Results

c) We are planning to maintain the Reservoir 1 pressure by water injection.

How much water (injection rate) would we need if the pressure is to be maintained at5300 psig? From when?

d) An upgrade of the facilities is being considered for early 2008.

How much more could we produce if the maximum liquid rate handling were increased to35000 bbl/d?

e) Artificial lift for Well 1 is being considered as soon as the facilities are upgraded.

Analyse both Gas lift and ESP artificial lifts methods impact in the overall production.Use previously created Well1GL.out and Well 1ESP.out.VLPs are providedAvailable Gas Lift: 10 mmscfd

f) Water Injection System

ESP is the preferred option.Using this as base case, we want to design the water injection system.

In previous scenarios, the required water injection to maintain Reservoir 1 pressure at5300 psig was automatically injected by GAP. Now we want to analyse the systemrequired to achieve that.

A simple Water Injection System GAP model will be built and then coupled to the existingproduction system

Step 1: Save the Production System Simple.GAP model


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Step 2: Start a new GAP model (Water Injection System)

Step 3: Build the System Layouta) Injection Manifoldb) Flowline (1000 ft long / 4 ID)

c) 1 Water Injector welld) 1 Tanke) Link the componentsf) Save as Simple-Injection.GAP

Step 4: Create the water injector model using PROSPERa) Water Salinity: 100000 ppmb) Vertical Well down to 11500 ftc) Geothermal Gradient as per Well 1d) Completion: Tubing down to 11000 ft (2.9 ID) / Casing (6ID)e) Injectivity Index: 12 STB/d/psif) Save as Wat Injector.out

Step 5: Link PROSPERfile and Res1 MBALmodel to the corresponding componentsin GAP

Step 6: Generate IPR/VLP

Step 7: Set the Well controllable and Save the fileOpen the Production System model and link it to the injection system.

Step 8: Analyse the whole system performance. (Injection Manifold 1000 psi)Is one well enough? How many well do we need?Discuss how the Target pressure feature works when having an Injection

System linked.


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7.4 Problem 30: Gas Lift Optimisation

Objective:

Use the GAPOptimiser to analyse if oil production can be increased by reallocating

the same amount of gas lift gas among the wells


Dataset:

SURFACE NETWORK SETUP

TEST DATA


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Well Gas Injection RateMMscf/d

WHPpsig

Liquid rateSTB /day

Water cut%

GORscf/stb

Well 1 - 198.3 6720 85 1200

Well 2 3 208.3 820 80 300

Well 3 3 208.3 1135 75 300

Well 4 3 208.3 1400 70 300

Well 5 1 208.3 3090 30 300

TASKS

Step 1: Build the Production System Layout in GAP(all components) and link them

Pipeline Data

Pipeline Length (feet) ID (inches) Correlation

From Manifold 1 to Manifold 2 1000 6 Beggs & Brill

From Well 1 to Manifold 2 200 4 Beggs & Brill

From Well 5 to Manifold 2 500 4 Beggs & Brill

From Manifold 2 to Sep Joint 2000 8 Beggs & Brill

Step 2: Link the Well models in GAPto the corresponding PROSPERfiles given

Step 3: Generate IPRs

Step 4: IMPORT the VLPs given. (DO NOT GENERATE THEM)

Step 5: Compare the Well models against test data by using the Model Validation featurein GAP

Step 6: Enter the surrent amount of gas being injected in the wells in the \Edit\EquipmentControl screen

Step 7: Solve the Network (no optimisation) to calculate the total oil production of the field.

Step 8: Set the wells gas lift gas controllable and solve the network this time optimised(using the same total amount of gas lift gas)

Step 9: Compare the total oil rate production now.


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8 OpenServer - OpenServer Tutorial

8.1 Problem 31a: OpenServer Exercise 1

MACRO 1

1. Exercise Objective

Generate Sensitivities on Well Length for a Horizontal Well.The Performance of the Well for different Well Lengths (Liquid Rate vs. Well Length) isrequired.

2. Data Provided

PROSPERFile:HORWELLDP.OUT

OpenServer Template (Excel File): Exercise 1 Template.xls

MACRO 2


Generate Sensitivities on Well Length and Vertical Anisotropy for a Horizontal Well.The Performance of the Well for different Well Lengths and Vertical Anisotropy is required.

2. Data Provided

PROSPER File:HORWELLDP.OUT

OpenServerTemplate (Excel File):Exercise 1 Template.xls


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8.2 Problem 31b: OpenServer Exercise 2


Generating a Production Forecast and determining the time for drilling Well-2

2. Description

The Field is being currently produced with Well-1 at Maximum Rate.

A second Well (Well 2) is planned to be drilled when Well 1 Production falls below 7000 bbl

An automatic way of running the model (and enabling the second well when required) isrequired as there will be plenty of sensitivities run on this model and manually checking forthe drilling date is not practical.

3. Data Provided

IPM Model:GAP Model.GAP (and associated files)

OpenServerTemplate (Excel File): Gap Prediction Template.xls

OpenServer Commands/Variables required

Well 1 Liquid Rate: GAP.MOD[{PROD}].WELL[{W1}].PREDRES[j ].LIQRATEMask Command: GAP.MOD[{PROD}].WELL[{W2}].MASK()Unmask Command: GAP.MOD[{PROD}].WELL[{W2}].UNMASK()

VBA Functions

CStr(Number):Converts the number into a string. This is useful for concatenating stringsand numbers

e.g.: GAP.MOD[{PROD}].WELL[{W1}].PREDRES[ & Cstr(j) &].LIQRATE

with j=3.

This is equivalent to

GAP.MOD[{PROD}].WELL[{W1}].PREDRES[ 3].LIQRATE

Which is the string required to extract the Liquid Rate of well W1 of the 4 th predictiontimestep

Val(String): Converts a string into a number. This is useful when extracting values usingOpenServer (they are extracted as strings) and need to compare in numerical values (e.g. ifRate > 4000..)


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9 IPM Review - Workshop

9.1 IPM Review - Workshop

Objective:

There has been a new disco very and few data avai lable on the disc overy.

On the basis o f the in fo rmat ion ava ilab le, we want to s tudy the best way to manage

the development o f the fie ld.

The Plat fo rm max imum capaci ty is 35000 bb l /d and the target Recovery Fac to r are

22% for Res 1 and 35% fo r Res 2 in 10 years.


Dataset:

FIELD DESCRIPTION

Two subsea reservoirs in 600 feet of water.

Reservoir 1 is 10,000 feet away from reservoir 2.

Separator is 50,000 feet away.

Data: Reservoir 1 Reservoir 2

OOIP 150 85 (MMSTB)Pressure 6500 11000 (psig)GOR 500 1700 (scf/STB)API 35 40Gas gravity 0.7 0.72Res Depth 14000 15000 (feet)Permeability 50 500 (md)Pay height 25 50 (feet)Porosity 0.15 0.25 (fraction)


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IPM Review - Workshop 83


Swc 0.15 0.15 (fraction)Salinity 100,000 10,000 (ppm)Temperature 200 250 (F)Wellbore radius 0.354 0.354 (feet)Drainage Area 100 100 (Acres)


End Point(Fraction)

Corey Exponent

Water 0.15 0.7 0.8

Oil 0.15 0.8 1.5

Gas 0.02 0.9 1


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10 Appendix A: GAP Constrained Network Optimisation

10.1 GAP Constrained Network Optimisation

The constrained optimisation module in GAP alters choke settings on naturally flowing wellsand gaslift amount on gaslifted wells to achieve maximum oil production whilst meetingconstraints usually processing limits placed at various levels in the gathering system.

The Successive Linear Programming AlgorithmFirstly, consider a system (Fig 1) consisting of two wells connected via a manifold and apipework to a separator.

The wells are naturally flowing, and their unchoked production is:

Oil

Production

Water

Production

Gas

ProductionWater Cut GOR

Well 1 5000 1250 5 20 1000

Well 2 4000 3017 2 43 500

Totals 9000 4267 7

Processing limits at the manifold of 2500 STB/d water and 3.8 MMscf/day gas are given,and the task is to choke back the wells to meet these limits in an optimal way, where optimal


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Appendix A: GAP Constrained Network Optimisation 85


in this case is define as maximising oil production.

This reduces to a mixing problem of a type frequently seen in all forms of process industry,since each well supplies oil gas and water in its own particular proportions and we aremixing the wells at the manifold. There are therefore many techniques available for solving

problems of this type.

Before we look at the actual technique used in GAP, let us solve the problem manually. Wetherefore define x1 and x2 as the fraction of unchoked production from each well, o1 and o2as the unchoked oil production, w1 and w2 as the unchoked water production and finally g1and g2 as the unchoked gas production. The problem can be stated with the followingequations:

Maximise oil production = x1.o1+x2.o2

Subject to the constraints water production = x1.w1+x2.w2


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constraints, a point has to lie below or on both lines simultaneously. The region containingall the possible mixtures which satisfy all the constraints is the four sided region OEBG, thefeasible region.

Now consider the oil production. Two lines representing all mixtures of the two wells which

produce 5000 and 4000 (JK and KL) are plotted. The 5000 line lies entirely outside thefeasible region, while the 4000 line divides it. If we visualise moving a production contourfrom 5000 to 4000, it can be seen that the contour will first touch the region at point B. Thistherefore must be the optimal point, since all points in the region below must have lower oilproduction.

At point B, the actual production is 5031, and both the gas and water production are at theirlimits. This corresponds to a fraction x1=0.513728 of unchoked production for Well 1, andx2-0.615679 of unchoked production for Well 2. Note that the combination of constraints hasled a solution where both wells are choked.Since we have performed curves for the wells relating production to WHP, we canimmediately look up the desired WHP for each well. This in turn gives us the choke settings

(as pressure differences), since they must equal the difference between the manifoldoperating pressure and the desired WHP.

To get to this stage, we used the production data and constraints to form a set of linearequations, and solved then simultaneously with a graphical method. It should be clear thatwe can construct a similar set of equations for any system of naturally flowing wells, withconstraints at different levels affecting all of the wells connected below. Since the equationsare linear, this can be classed as a linear programming problem, and GAP solves this usingthe simplex method, since this is reliable and computationally efficient.

The Simplex Method.

A property of linear programming problems is that the solution always occurs on theboundary of the region enclosed by the problem constraints, where two or more constraintsmeet (i.e. a vertex of the region). Let us take a problem with N variables (i.e. N wells) and Mconstraints.

To solve the problem therefore, we need to step through the points at the vertices, endingwith the point whose objective value is the highest. The simplex method is a procedurewhich ensures that the objective increases at each step, and that the optimum point isreached after a number of steps of order N (or M, whichever is larger).

The first step is to express the system of equations in a standard form as follows:

z- 5000.x1 -4000.x2 = 0 :Objective function

1250.x1 +3017.x2+y1 = 2500 :constraint 1

5.x1 +2.x2+y2 = 3.8 :constraint 2

x1 +y3 = 1 :constraint 3

x2 +y4 = 1 :constraint 4

They yis are called slack variables and are introduced to transform the inequality constraintsto equality constraints. All the variables are defined to be non-negative. We now form a


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Appendix A: GAP Constrained Network Optimisation 87


matrix representation of the equation (the tableau):

z x1 x2 y1 y2 y3 y4

Row 0 1 -5000 -4000 0 0 0 0 0

Row 1 0 1250 3017 1 0 0 0 2500

Row 2 0 5 2 0 1 0 0 3.8

Row 3 0 1 0 0 0 1 0 1

Row 4 0 0 1 0 0 0 1 1

As a starting point, take x1 and x2=0. This satisfies all constraints. We now want to take astep which increases the objective. Choose the variable which has the largest negative

coefficient in row 0 in this case x1. Let x2 stay at zero. As we incr

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