PIPESIM PROJECT_2012

PE 7023 Fall 2012

Term Design Project

Reservoir and Production
Management of Hurricane Field

Author: Lecturer:
Sel¸uk Fidan
c Prof.Dr. Holden Zhang

December 10, 2012

Abstract

Brown et al.[1] was stated that many production systems are operating
inefficiently; therefore, most can be improved significantly by careful analy-
sis. It is not unusual to find flow lines that are too small and tubing sizes that
are too large or too small. It was almost 30 years ago Dr. Brown was talk-
ing about this in his famous book. It is still true in some aspects, however
developing technologies and new softwares decrease this improper designs.
One of the most popular software for this purpose is PIPESIM by Schlum-
berger. In our project, PIPESIM is used to apply NODAL analysis under
different conditions to see the performance of the production network system.

In this project we were asked to optimize the Hurricane field which is
located in Tulsa County. It consists of seven different reservoirs and has 11
wells. Four of the wells that PEC-3, PEC5, PEC-6 and PEC-7 are producing
with gas lift and five of them that PEC-1, PEC-2, PEC-4, PEC-8 and PEC-9
have choke installed on the top of the well. The objective of this work is to
optimize the field performance applying NODAL analysis, Well performance
and Artificial Lift Performance, changing tubing size and surface choke siz-
ing. For the gas lift wells we are able to conduct NODAL analysis, Well
performance and Artificial Lift Performance and for the wells have produc-
ing naturally we are able to apply NODAL analysis on the bottom of the well,
on the top of the well and at the separator. We conducted our work mainly
putting the node at the bottom of the well but for the example purpose we
conduct one case for PEC-1 putting the node on the wellhead and put this
into the results section.

Contents

1 Introduction 11

2 Procedure 14
2.1 Under Normal Conditions . . . . . . . . . . . . . . . . . . . . 15
2.2 Changing Tubing Diameters . . . . . . . . . . . . . . . . . . . 15
2.3 Changing Choke Bean Size . . . . . . . . . . . . . . . . . . . . 15
2.4 Gas Lift Optimization and Well Performance . . . . . . . . . . 16
2.4.1 Gas Lift Optimization . . . . . . . . . . . . . . . . . . 16
2.4.2 Well Performance . . . . . . . . . . . . . . . . . . . . . 16
2.5 Changing Static Pressure . . . . . . . . . . . . . . . . . . . . . 17

3 Results 18
3.1 Under Normal Conditions . . . . . . . . . . . . . . . . . . . . 18
3.1.1 Nodal Analysis . . . . . . . . . . . . . . . . . . . . . . 18
3.2 Changing Tubing Diameters . . . . . . . . . . . . . . . . . . . 21
3.3 Changing Choke Bean Size . . . . . . . . . . . . . . . . . . . . 22
3.4 Gas Lift Optimization and Well Performance . . . . . . . . . . 23
3.5 Changing Static Pressure . . . . . . . . . . . . . . . . . . . . . 25
3.6 Possible improvements for the wells . . . . . . . . . . . . . . . 25
3.7 Putting Nodal Point on Wellhead . . . . . . . . . . . . . . . . 26

4 Conclusions 29

Bibliography 30

A Reservoir and Production Management of Hurricane Field 31
A.1 Well Information . . . . . . . . . . . . . . . . . . . . . . . . . 32
A.1.1 PEC-1 . . . . . . . . . . . . . . . . . . . . . . . . . . . 32

2

A.1.2 PEC-2 . . . . . . . . . . . . . . . . . . . . . . . . . . . 32
A.1.3 PEC-3 . . . . . . . . . . . . . . . . . . . . . . . . . . . 32
A.1.4 PEC-4 . . . . . . . . . . . . . . . . . . . . . . . . . . . 33
A.1.5 PEC-5, PEC-6 and PEC-7 . . . . . . . . . . . . . . . . 33
A.1.6 PEC-8 and PEC-9 . . . . . . . . . . . . . . . . . . . . 33
A.1.7 PEC-10 . . . . . . . . . . . . . . . . . . . . . . . . . . 34
A.1.8 PEC-11 . . . . . . . . . . . . . . . . . . . . . . . . . . 34

B Figures 35

C Tables 142

D Matlab Code 146
D.1 Post processing code for changing tubing diameters . . . . . . 146

3

List of Figures

1.1 Complete Producing simple system. [1] . . . . . . . . . . . . . 12
1.2 Pressure losses in complete system. [1] . . . . . . . . . . . . . 12

3.1 Analysing PEC-1 from Nodal Analysis figure. . . . . . . . . . 20
3.2 Tubing diameter (inches) vs. Flow rate sbbl/d. . . . . . . . . . 21
3.3 Schematic view of Well PEC-1, simulation after PIPESIM. . . 27
3.4 IPR and OPR curve with different flowline diameters for PEC-1. 27
3.5 IPR and OPR curve with different tubing and flowline diam-
eters for PEC-1. . . . . . . . . . . . . . . . . . . . . . . . . . . 28

B.1 Actual Gathering System from the project file. . . . . . . . . . 36
B.2 Actual Gathering System after PIPESIM. . . . . . . . . . . . 37
B.3 Flowline for B1. . . . . . . . . . . . . . . . . . . . . . . . . . . 38
B.4 Flowline for B2. . . . . . . . . . . . . . . . . . . . . . . . . . . 38
B.5 Flowline for B3. . . . . . . . . . . . . . . . . . . . . . . . . . . 38
B.6 Flowline for B4. . . . . . . . . . . . . . . . . . . . . . . . . . . 39
B.7 Flowline for B5. . . . . . . . . . . . . . . . . . . . . . . . . . . 39
B.8 Flowline for B6. . . . . . . . . . . . . . . . . . . . . . . . . . . 39
B.9 Schematic view of well PEC-1 from project file. . . . . . . . . 40
B.10 Schematic view of Well PEC-1, simulation after PIPESIM. . . 40
B.11 Production History for PEC-1 from project file. . . . . . . . . 41
B.12 IPR and OPR for PEC-1 under normal conditions. . . . . . . 42
B.13 Pressure vs. depth for PEC-1 under normal conditions. . . . . 43
B.14 Temperature vs. depth for PEC-1 under normal conditions. . . 43
B.15 IPR and OPR for PEC-1 with changing tubing diameters. . . 44
B.16 Pressure vs. depth for PEC-1 with changing tubing diameters. 45
B.17 Temperature vs. depth curve for PEC-1 with changing tubing
diameters. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 45
B.18 IPR and OPR for PEC-1 with changing choke bean size. . . . 46

4

B.19 Pressure vs. depth for PEC-1 with changing choke bean size. . 47
B.20 Temperature vs. depth curve for PEC-1 with changing choke
bean size. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 47
B.21 Nodal Analysis curves for PEC-1 with changing static pressures. 48
B.24 Schematic view of Topographical Survey for PEC-2. . . . . . . 50
diameters. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 54
bean size. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 56
diameters. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 62
B.43 IPR and OPR for PEC-3 at different static pressures. . . . . . 63
B.44 IPR and OPR for for PEC-3 at different static pressures and
gas lift at 2918 ft. . . . . . . . . . . . . . . . . . . . . . . . . . 64
B.45 IPR and OPR for for PEC-3 at different static pressures and
gas lift at 8811 ft. . . . . . . . . . . . . . . . . . . . . . . . . . 64
B.46 Well Performance curves under normal conditions. . . . . . . . 65
B.47 Well Performance curves when gas lift at 2918 ft. . . . . . . . 66
B.48 Well Performance curves when gas lift at 8811 ft. . . . . . . . 66
B.49 Artificial lift performance curves under normal conditions. . . 67
B.50 Artificial lift performance curves when gas lift at 2918 ft. . . . 68

5

B.51 Artificial lift performance curves when gas lift at 8811 ft. . . . 68
diameters. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 74
bean size. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 76
B.67 IPR and OPR curves for PEC-5 under normal conditions. . . . 79
B.68 Pressure vs. depth curve for PEC-5 under normal conditions. . 80
B.69 Temperature vs. depth curve for PEC-5 under normal condi-
tions. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 80
diameters. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 82
B.73 IPR and OPR for PEC-5 at different tubing diameters. . . . . 83
B.74 IPR and OPR for for PEC-5 at different tubing diameters and
gas lift at 1500 ft. . . . . . . . . . . . . . . . . . . . . . . . . . 84
gas lift at 3000 ft. . . . . . . . . . . . . . . . . . . . . . . . . . 84
B.76 Well Performance curves for PEC-5 under normal conditions. . 85
B.77 Well Performance curves for PEC-5 when gas lift at 1500 ft. . 86
B.79 Artificial lift performance curves for PEC-5 under normal con-
ditions. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 87
B.80 Artificial lift performance curves for PEC-5 when gas lift at
1500 ft. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 88

6

3000 ft. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 88
B.85 IPR and OPR curves for PEC-6 under normal conditions. . . . 91
B.86 Pressure vs. depth curve for PEC-6 under normal conditions. . 92
B.87 Temperature vs. depth curve for PEC-6 under normal condi-
tions. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 92
diameters. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 94
B.91 IPR and OPR for PEC-6 at different tubing diameters. . . . . 95
gas lift at 1550 ft. . . . . . . . . . . . . . . . . . . . . . . . . . 96
gas lift at 3050 ft. . . . . . . . . . . . . . . . . . . . . . . . . . 96
B.94 Well Performance curves for PEC-6 under normal conditions. . 97
B.97 Artificial lift performance curves for PEC-6 under normal con-
ditions. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 99
1550 ft. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 100
3050 ft. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 100
B.100Nodal Analysis curves for PEC-6 with changing static pressures.101
B.101Schematic view of well PEC-7 from project file. . . . . . . . . 102
B.102Schematic view of Well PEC-7, simulation after PIPESIM. . . 102
B.103IPR and OPR curves for PEC-7 under normal conditions. . . . 103
B.104Pressure vs. depth curve for PEC-7 under normal conditions. . 104
B.105Temperature vs. depth curve for PEC-7 under normal condi-
tions. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 104
B.106IPR and OPR for PEC-7 with changing tubing diameters. . . 105
B.107Pressure vs. depth for PEC-7 with changing tubing diameters. 106
B.108Temperature vs. depth curve for PEC-7 with changing tubing
diameters. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 106

7

B.109IPR and OPR for PEC-7 at different tubing diameters. . . . . 107
B.110IPR and OPR for for PEC-7 at different tubing diameters and
gas lift at 1540 ft. . . . . . . . . . . . . . . . . . . . . . . . . . 108
B.111IPR and OPR for for PEC-7 at different tubing diameters and
gas lift at 3050 ft. . . . . . . . . . . . . . . . . . . . . . . . . . 108
B.112Well Performance curves for PEC-7 under normal conditions. . 109
B.113Well Performance curves for PEC-7 when gas lift at 1540 ft. . 110
B.114Well Performance curves for PEC-7 when gas lift at 3050 ft. . 110
B.115Artificial lift performance curves for PEC-7 under normal con-
ditions. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 111
B.116Artificial lift performance curves for PEC-7 when gas lift at
1540 ft. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 112
B.117Artificial lift performance curves for PEC-7 when gas lift at
3050 ft. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 112
tions. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 116
diameters. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 118
B.127IPR and OPR for PEC-8 with changing choke bean size. . . . 119
B.128Pressure vs. depth for PEC-8 with changing choke bean size. . 120
B.129Temperature vs. depth curve for PEC-8 with changing choke
bean size. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 120
tions. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 124

8

diameters. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 126
B.139IPR and OPR for PEC-9 with changing choke bean size. . . . 127
B.140Pressure vs. depth for PEC-9 with changing choke bean size. . 128
B.141Temperature vs. depth curve for PEC-9 with changing choke
bean size. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 128
B.144Schematic view of Well PEC-10, simulation after PIPESIM. . 130
B.145IPR and OPR curves for PEC-10 under normal conditions. . . 131
B.146Pressure vs. depth curve for PEC-10 under normal conditions. 132
B.147Temperature vs. depth curve for PEC-10 under normal con-
ditions. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 132
B.149Pressure vs. depth for PEC-10 with changing tubing diameters.134
B.150Temperature vs. depth curve for PEC-10 with changing tub-
ing diameters. . . . . . . . . . . . . . . . . . . . . . . . . . . . 134
B.151Nodal Analysis with Changing Static pressure and tubing di-
ameters. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 135
B.152Nodal Analysis with Changing Outlet pressure. . . . . . . . . 135
B.154Schematic view of Well PEC-11, simulation after PIPESIM. . 136
B.155IPR and OPR curves for PEC-11 under normal conditions. . . 137
B.156Pressure vs. depth curve for PEC-11 under normal conditions. 138
B.157Temperature vs. depth curve for PEC-11 under normal con-
ditions. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 138
B.159Pressure vs. depth for PEC-11 with changing tubing diameters.140
B.160Temperature vs. depth curve for PEC-11 with changing tub-
ing diameters. . . . . . . . . . . . . . . . . . . . . . . . . . . . 140
B.161Nodal Analysis with Changing Static pressure and tubing di-
ameters. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 141
B.162Nodal Analysis with Changing Outlet pressure. . . . . . . . . 141

9

List of Tables

C.1 Well- manifold information for Hurricane field. . . . . . . . . . 143
C.2 The manifolds, the processing center and flow line conditions. 143
C.3 Different diameters Nominal and ID values from user guide. . 144
C.4 Flow rate comparison for given data set and at Nodal Analysis
point. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 144
C.5 Actual Conditions for 11 wells in Hurricane field. . . . . . . . 145

10

Chapter 1

Introduction

What does Nodal Systems Analysis mean? Based on the Brown et al.[1] it
is a procedure for determining that flow rate at which an oil or gas well will
produce and then for evaluating the effect of various components, such as
the tubing-string size, flow-line size, separator pressure, choke sites, safety
valves, downhole restrictions, and well completion techniques including gravel
packs and standard perforated wells. These components are then combined
to optimize the entire system to obtain the most efficient objective flow rate.
Each component evaluated separately; then the entire system is combined to
optimize the system effectively. In PIPESIM, Nodal(or system) analysis is
defined as solving the total producing system by placing nodes at the reser-
voir sand-face, the well tubing, the flowline and the separator.

A node is classified as functional when a pressure differential exists across
it. In nodal analysis, the producing system is divided into two halves at the
solution node. The solution node is defined as the location where the pres-
sure differential upstream (inflow) and downstream (outflow) of the node is
zero. This is represented graphically as the intersection points of the inflow
and outflow performance curves. Solution nodes can be judiciously selected
to show the effect of certain variables such as inflow performance, perfora-
tion density, tubing IDs, flowline IDs and separator pressures. The solution
node can be placed between any two objects, that is bottom hole (between
completion and tubing), and wellhead (between tubing and choke) and so
on.

11

Figure 1.1: Complete Producing simple system. [1]

Figure 1.2: Pressure losses in complete system. [1]

In Figure 1.1, and Figure 1.2 show that above explanation schemati-
cally.
In this work, we try to optimize the Hurrican ﬁeld based on the infor-
mation is provided and tabulated on Table C.5 the reservoir, ﬂuids, well

12

and pipeline actual conditions. For detailed describtion please check the
Appendix A.

13

Chapter 2

Procedure

In this chapter, we will describe the procedure that has been followed for this
section. PIPESIM case studies [2] helped us to build aour model to assign
default values for each and different part of this work. Before that I would
like to mention that for each case building wells are followed putting the
information from Table C.5 into the PIPESIM. If there was no information
default values were used from the PIPESIM user guide. Besides this for
having GREEN reservoirs give us another unknown of the well information
such Temperature of the reservoir and it is assumed that 130 o F . After
putting fluid, reservoir, boundary and limitations informations for production
for each single cases in this work we also followed case studies whether we
missed or put wrongly the input parameters just for verifying purposes.
First of all, we need to build the network system. After constructing the
network system, NODAL analysis is applied without considering sensitivity
analysis to see how system looks like. Having understanding of the system
gives an idea of which part of the well should be considered. First thing is
considerd to change tubing sizes for Outflow performance curve (OPR) or
Tubing performance curve (TPC). For example, wells have artificial lift are
considered to apply Well Performance and Artificial Lift Performance, and
wells have chokes that are considered to changing the choke Bean size. For
this reason, one example is going to give for each of the optimized section
and rest of it is going to be referred in to the Appendix B for figures and
Appendix C for tables.

14

2.1 Under Normal Conditions
The procedure for running PIPESIM under Normal conditions as follows;

• Build network model without modification using PIPESIM.

• Run Nodal analysis and get results and save them to check whether we
can produce or not.

• Obtain pressure and temperature profiles.

• Put the results into the Appendix B each well has following orders as
Nodal Anlaysis, Pressure and Temperature profiles for normal condi-
tons. This is diagnostic place after that different optimization applied
to different part of the system to enhance the production system.

2.2 Changing Tubing Diameters
The procedure for running PIPESIM Changing Tubing Diameters as follows;

• Choose tubing ID Table C.3 based on the PIPESIM User guide pg.
536.

• Keep everything constant from normal conditions except for the outflow
sensitivity part tubing diameters.

• Obtain IPR and OPR and pressure and temperature profiles.

• Put the results into the Appendix B after the results are obtained
from previous section.

• Obtain diameter vs. rate plot for each case and put them into the
result section.

2.3 Changing Choke Bean Size
The procedure for running PIPESIM Changing Choke Bean Size as follows;

• Choose wells that have choke installed in this work we have PEC-1,
PEC-2, PEC-4, PEC-8 and PEC-9.

15

• Keep everything constant from normal conditions except for the outflow
sensitivity part tubing diameters.


from previous section.


from previous section for specific wells.

2.4 Gas Lift Optimization and Well Perfor-
mance
2.4.1 Gas Lift Optimization
In this section I followed the similar case study (Gas Lift Optimization) from
PIPESIM case studies and procedure for Gas Lift Optimization as follows;

• Choose wells that have gas lift in this work we have PEC-3, PEC-5,
PEC-6 and PEC-7.

• From the classwork and coursework material [3] we learned that when
we have the gas lift we should play with the gas lift position. And Prof.
Zhang mentioned in the class putting gas lift at the deeper point we
have in the system in order to get more effective results for most of
the cases. Therefore, I tried three different cases, first I run the system
without changing any placement and get the results for Artificial Lift
Performance. And repeated the work placing the gas lift on top point
and closing the other valves, and continue to only open the deepest
point gas lift and closing the all other valves.

2.4.2 Well Performance
In this section I followed the similar case stud (Gas Lift Design) from PIPESIM
case studies and procedure for Well Performance for gas lift as follows;

16

• Choose wells that have gas lift installed in this work we have PEC-3,
PEC-5, PEC-6 and PEC-7.

• Similar procedure for gas lift optimization is followed with changing
gas lift deoth and ﬁgures are obtained and put into the Appendix B
with order.

2.5 Changing Static Pressure
In this section procedure for Changing Static Pressure as follows;

• Changing tubing diameters and static pressure curves were obtained
using Nodal Analysis. This is important for PEC-10 and PEC-11.

• Results put into the order for each cases into the Appendix B.

17

Chapter 3

Results

In this section of the report we present the results for each case and refer
the figures for each wells from Appendix B. We put all the figures into the
Appendix B, in the first part of the figures we try to represent each well
as possible as we can based on the figures in the Design project. For this
reason I put first original figure then simulated ones. Actual conditions can
be seen from figures B.1 and B.2 and then for the flow line part I put the
six different flowline that we have in this network system in figures B.3,
B.4, B.5, B.6, B.7 and B.8.

3.1 Under Normal Conditions
In this chapter we will explain the each of the wells from Nodal Analysis to
Gas lift performance mainly putting the node bottom of the well and give
one example for the putting the node on the wellhead. After applying pro-
cedures from Chapter 2, we have an idea about the wells diagnostics. Next
proceeding sections are all about the diagnostics and finding the solutions.

3.1.1 Nodal Analysis
Under normal conditions IPR and OPR curves were obtained and put into
the Appendix B for figures. In Table C.4, it is clearly seen that only
several wells field data is matching with the simulation results for flow rate
comparison. For the gas lift injection wells we have problems because simula-
tion results and actual data are way off values from each other. For PEC-1

18

we get good IPR and OPR curve in figure B.12 shows that initial reservoir
pressure good enough to produce from the well. Because Pi is bigger than
Po . And Productivity index is low because of the angle θ is high. Changing
tubing sizes will improve the performance. When we look at the PEC-2 from
the simulation in figure B.25, angle θ is small so the productivity index is
high so we can increase the tubing diameters, however in field data it says
we do not produce from PEC-2 and it is usually under shut in condition. It
has GREEN reservoir next to it and they have same manifold to the process
center. For PEC-3 in figure B.37, is the one of the gas lift well and in NA
it shows there is no operating points. And IPR and OPR curve has strange
behavior. For PEC-4 in figure B.55, Pi is smaller than Po , production is
not possible under this conditions. Looking at the PEC-5 in figure B.67
and PEC-6 in figure B.85 IPR and OPR has no intersection and operating
points. We can not produce from this wells. For PEC-7 in figure B.103,
OPR has high pressure ant zero production rate which means we have to
increase reservoir pressure in order to produce, but still gas lift wells under
normal condition no way to produce. For PEC-8 in figure B.121, it has
similar behavior with PEC-2 angle θ is small so the productivity index is
high so we can increase the tubing diameters. PEC-9 in figure B.133 shows
good IPR and OPR behavior. PEC-10 in figure B.145 and PEC-11 in
figure B.155 have similar problem initially Po is bigger than Pi , so this
condition also need to be optimized.

19

20

Figure 3.1: Analysing PEC-1 from Nodal Analysis ﬁgure.

3.2 Changing Tubing Diameters
In this section using PIPESIM guide, we choose several tubing diameters
from Table C.3 and applied the change into the outflow sensitivity. Results
are tabulated after each section results in orderly, can be found at Appendix
B. IPR and OPR curves can be found for different tubing diameters for PEC-
1 in figure B.15, PEC-2 in figure B.28, PEC-3 in figure B.40, PEC-4
in figure B.58, PEC-5 in figure B.73, PEC-6 in figure B.88, PEC-7 in
figure B.106, PEC-8 in figure B.124, PEC-9 in figure B.136, PEC-10 in
figure B.148 and PEC-11 in figure B.158.

Figure 3.2: Tubing diameter (inches) vs. Flow rate sbbl/d.

In Figure 3.2, we can see that almost every well shown in the figure ex-
cept PEC-5 due to the no operating points available on IPR and OPR curve.
Based on the course materials we say that when the tubing diameter vs. flow
rate relationship shows that after increasing diameters flow rate reaches max-
imum value and with increasing diameter flow rate becomes smaller(indicates

21

that unstable region). Gas wells (PEC-3, PEC-6 and PEC-7) do not have
stable points, wells that show stable behaviors are PEC-1, PEC-2, PEC-8
and PEC-9.

3.3 Changing Choke Bean Size
In this section we examined the effect of the changing Choke Bean Size and
put the results as in order in to the Appendix B. Using choke gives system a
restriction. It can be modeled as a fixed-size orifice, in which form it presents
a restriction to flow resulting in a pressure drop that increases as flow rate
increases. In our field we have five wells which PEC-1, PEC-2 , PEC-
4, PEC-8 and PEC-9 have choke installed with different sizes. When we
change the choke size we increase the production rate and decrease the OPR
Po . This gives us to find the optimum bean size for the wells. For PEC-1
changing choke sizes gives till 1.25 inches of choke bean after that all the
values are goes to the same values. More difference between 0.5 and 0.75
inches as it can be seen from figure B.18. For PEC-2 in figure B.31
biggest difference can be seen between choke size 0.5 to 0.75 inches. PEC-4
in figure B.61 when the bean size goes to 0.75, we can see that Po becomes
smaller than Pi , so we can produce from this well when we change the choke
size. For the PEC-8 in figure B.127, although it seems when the choke size
increase we have better OPR curve, but for choke size 0.5 inches we have the
closest production rate 2933 BBPD for the real one is 2900 BBPD. Therefore
choosing choke bean as 0.5 inches instead of 1.0 inches gives close to the field
case. For PEC-9 in figure B.139, choosing choke size between 0.25 and 0.5
gives the optimum value for production rate for this well.

22

3.4 Gas Lift Optimization and Well Perfor-
mance

In this section of project we present both Gas Lift Optimization and Gas
Lift Well Performance putting the valve and injecting the gas at different
depth. In this case we have 4 wells that are PEC-3,PEC-5,PEC-6 and
PEC-7. Each of them certain amount of valves installed at different places.
Each wells figures first one shows result for Well Performance curves and
second figure shows that Artificial Lift Performance curve. First we get
results for without changing conditons for PEC-3 in figure B.46, in this
figure it is shown that with increasing gas injection rate, stock tank liquid
rate is increasing till 1 MMSCFD after that higher the injection rate goes
lower stock tank liquid flowrate at outlet. When we look at the figure B.49
with increasing water cut have reverse effect on stock tank liquid flow rate
at outlet, higher the water cut lower the stock tank flow rate at outlet with
increasing gas injection. For PEC-5, in figure B.76 and figure B.79,
interestingly enough at normal conditions there is no information available.
For PEC-6, in figure B.94 it has some trend in terms of increasing gas
injection rate and system outlet pressure and at outlet we can say that all
the curves almost converges the same values on stock tank liquid flowrate
at outlet except the case injection rate is 1 and 1.2 MMSCFPD, and figure
B.97 with increasing water cut has stock tank liquid level increment, in
addition to this with discontinued values for watercut is 20 % and 30 %. In
PEC-7, figure B.112, gas injection rate smaller than 0.6 MMSCFPD does
not have any impact on the stock tank liquid flowrate at outlet. Moreover,
gas injection rate greater than 1.2 have tendency to converge on the similar
values at outlet stock tank flow rate, means that no need to inject more than
1.2 MMSCFPD. In figure B.115, shows that increasing water cut values
have some good trend on the stock tank flowrate at outlet when the gas
injection rate is more than 1.2 MMSCFPD. Secondly without having any
expense of the changing valves just tried to get one valve which is for this
case top one leave open and get the results for PEC-3 in figure B.47, curves
have good trend except injection gas rate smaller than 1 MMSCFPD, it gives
an idea that injecting gas on the shortest part does not have much impact
on stock tank flow rate at outlet. For the artificial lift performance curve
in figure B.50 does not show good trend for the performance. For PEC-5
figure B.77 this well performace curve shows good trend for gas injection

23

rate greater than 1.2 MMSCFPD and all the curves converge to the similar
stock tank liquid flow rate at outlet. In figure B.80, have stock tank liquid
rate maximum 8 SBBPD and increasing water cut does not have any effect on
stock tank liquid flow rate at outlet . For PEC-6, figure B.95, seems have
good trend but it is not stable, flow rate is 11 STBPD for the maximum
gas injection rate. In figure B.98, increasing water cut value till 60 %
does not have any effect on outlet stock tank flow rate except 70%, it gives
maximum flow rate at outlet when the gas injection rate 0.8 MMSCFPD,
after that it is decreasing. For PEC-7 figure B.113, has interesting trend
injection gas flow rate smaller than 2 MMSCFPD does not give production
on the surface. In figure B.116 has discontinued for the increasing water
cut values have reverse effect on the stock tank flow rate on surface. Lastly,
I got the results for putting the gas injection into the deepest valve opening
depth and got the results shown in each case. For PEC-3, in figure B.48,
for well performance at the deepest point gives very good trend and with
increasing gas injection rate stock tank outlet flow rate is increasing which
is the indication of the chooseing the deepest point gives reasonable match
with the flow rate for actual conditions.In figure B.51, with increasing water
cut, stock tank liquid flow rate is decreasing and at the same time there is
nice continuous trend with incresing gas injection rate. This is also another
indication of choosing the right or close to right point. For PEC-5, in figure
B.78, we get the almost the same flow rate for the actual conditons when
we use injection gas rate between 0.6-0.8 MMSCFPD. With figure B.81,
increasing water cut gives increase at the outlet flow rate with increasing gas
injection rate. For PEC-6, figure B.96, well performance curves for both
PEC-5 and PEC-6 have similar trend and similar injection rate range 0.6-0.8
MMSCFPD, the reason is this because both of them producing at the same
reservoir and most of the properties they have the same. In figure B.99, it is
obvious that both PEC-5 and PEC-6 have the similar trend in performance
of artificial lift. For PEC-7, in figure B.114, shows again similar trend
from previous two cases, for the PEC-7 actual flow rate is 280 BBPD in
order to get this we should increase the injection rate to 0.6 MMSCFPD and
only inject gas at the deepest point we have on teh system. In figure B.117,
from the artificial lift performance curves, PEC-7 shows similar trends that
PEC-5 and PEC-6 showed.

24

3.5 Changing Static Pressure
In this part we increased the static pressure to get several IPR curves and try
to enhance PEC-10 and PEC-11. For PEC-10, in figure B.151, when
we increase the static pressure to minimum 3800 psi, we have production
otherwise Pi is smaller than Po and there is no production and at the same
time increasing tubing diameters to 3.548 gives optimum point. Changing
only tubing diameters did not work for this case. In figure B.152, I changed
the outlet pressure from 300 to 70 psi and got the operating point and bigger
Pi than Po . For PEC-11 figure B.161, with increasing static pressure we
overcome Pi smaller than Po , and able to produce, at the same time increasing
tubing diameter to 4 inches going to give us optimum IPR and OPR curves,
but it is going to cost a lot because the depth of the well is 12000 ft. In this
figure B.162, changing outlet pressure gives liquid loading problem, so the
only way to produce from this well is increase static pressure and increase
the tubing diameter.

3.6 Possible improvements for the wells
1. For PEC-1, it seems there is no need to be improvement. Actual pro-
duction rate and simulated one almost same values. And Pi is greater
than Po we are able to produce from the well.
2. For PEC-2, although given information shows that this well does not
produce, however in simulation it gives production rate. It may because
having GREEN field gives confusion to the program.
3. For PEC-3, PEC-5,PEC-6 and PEC-7 are the gas lift wells and after
conducting both Well Performance and Artificial Lift Performance show
that injecting gas at the deepest point is going to give better results.
And also we saw that increasing gas injection rate does not necessarily
be the right thing after some point.
4. For PEC-4, this is one of the well has choke installed. After diagnostic,
increasing choke bean size minimum to 0.75 inches gives Po smaller than
Pi , so we are able to produce from this well.
5. For PEC-8, adjust the choke size to the 0.5 inches going to provide
optimum flow rate with the actual data.

25

6. For PEC-9, adjusting choke sizes between 0.25 and 0.5 gives optimum
flow rate with actual data.

7. For PEC-10, and PEC-11 as mentioned in the generic document, they
have very similar wells and after conducting changing static pressure
for this wells and increasing tubing size are going to give improvement
for those two wells. However, it is going to be expensive operationa
and it has to be considered in economical way.

3.7 Putting Nodal Point on Wellhead
This section is special place in terms of putting the NODAL Analysis point on
top of the well and get the IPR and OPR with changing flowline diameters
and tubing diameters. This is just an example how the system looks like
when we have NODAL point on top of the well for PEC-1 figure 3.3. It
is clear thatfrom figure 3.4 changing flowline diameter has impact on the
OPR curve, but after 4 inches curves are overlapping on themself and not
much effect seen that is the indication of 4 inches is the optimum point for
flow line diameters.

26

Figure 3.3: Schematic view of Well PEC-1, simulation after PIPESIM.

Figure 3.4: IPR and OPR curve with diﬀerent ﬂowline diameters for PEC-1.

27

28

Figure 3.5: IPR and OPR curve with diﬀerent tubing and ﬂowline diameters for PEC-1.

Chapter 4

Conclusions

1. Hurricane field network system is built successfully, and for each well
is diagnosted for different conditions. Suc as, under normal conditions,
changing tubing size, changing chkesize, applying gas lift design and op-
timization to get well performance and artificial lift performace for gas
lift wells and lastly static pressure change applied in order to optimize
the whole system.

2. In the chapter two, procedures are described and chapter thre explained
the results and give suggestion for the possible improvement for the
wells.

3. We found that although we have data from the field does not necessearily
match the simulated data. But still simulation gives some idea and pos-
sible improvement without trying and error.

4. Almost all the cases I run for this project I put the node at the bottom
of the well and did the analysis. For one case I put the NODAL ANAL-
YSIS point on to the top and got IPR and OPR curve with changing
flowline and tubing diameters.

29

Bibliography

[1] K. E. Brown. The Technology of Artiﬁcial Lift Methods. PennWell Books,
ﬁrst edition, 1984.

[2] Schlumberger. PIPESIM Version 2011.1 User’s Guide.

[3] Holden Zhang. Modeling and Optimization of Oil and Gas Production
Systems. PE 7023 FALL 2012 Advanced Production Design Course Notes,
2012.

30

Appendix A

Reservoir and Production
Management of Hurricane Field

In the appendix A, all the information is based on the project description
from Prof. Holden Zhang’s Generic Project document1 . The Hurricane field
is located in Tulsa County. It consists of seven different reservoirs. There
are 11 existing wells. The objective of this project is to optimize the field
performance.
Currently, the field is totally producing 7915 STB/D oil from all the wells
but Well PEC-5. All of the wells connected to a central processing center
in figure B.142. The production of another field called Green Field, 21681
STB/D of oil and 44 MMSCF/D natural gas, is transported to the same
processing center.
The reservoirs in Hurricane fields have different characteristics. The
well depth varies between 3000 ft and 12500 ft. Formations are sandstone,
dolomites, limestone with varying porosities and permeabilities. Four of the
wells are on artificial lift while six of them produce naturally and one well is
shut in. The production of the wells is sent to different manifolds based on
their geographic location in figure B.1 and after PIPESIM B.2.

1
Generic Project Design is well planned and aimed to teach how to use PIPESIM and
use the course materials effectively in order to accomplish this work.

31

A.1 Well Information
A.1.1 PEC-1
This well was completed in 1986 at an interval of 12467-12523 ft. in a forma-
tion composed by dolomites from medium Cretaceous of the reservoir SEC-1.
The static pressure has been kept around 3900 psi due to the water injection.
The flowing pressure and oil production started to decline at the end of 1994
and the well started to produce water. From 1995 to 1998, the flowing pres-
sure and oil production have declines notable, and the water cut increased.
This behavior is shown in figure figure B.9 and after PIPESIM figure B.10.
The additional information on production history: At the beginning of
1987, the production was increased from 993 STB/D to 2327 STB/D through
stimulation indicating that formation was originally damaged. The produc-
tion was held constant until April 1991 when it was increased by changing
the choke settings. In 1995, the oil production started to decline and well
started to cut water with salinity of 65,000 ppm. According to laboratory
tests, the salinity of the formation water is 150,000 ppm, which indicates that
the injection water is present in the well. Increase in the water saturation
around the near wellbore may result in additional damage. The most of the
information of this well is given in Table C.5.

A.1.2 PEC-2
This well was completed in 1997 at an interval of 6371-6476 ft. (figure
B.22 and figure B.23) in a formation composed by dolomites from medium
Cretaceous of the reservoir SITEC. This is the only well in the reservoir. The
general characteristics of the system rock-fluids are given in the Table C.5.
The topography of the flow line from PEC-2 to P2 is given in figure B.24.
This well is shut in most of time.

A.1.3 PEC-3
This well produces from a sand stone reservoir which has static pressure of
3400 psi, 12 % of porosity and 40 md of permeability. It was completed with
2 7/8 in. tubing and 8 conventional gas lift valves (figure B.35 and figure
B.36). These valves cannot be changed unless the tubing is replaced since

32

they are part of the tubing. There has been a severe communication between
gas-lift valves. The communication was detected at 4091 ft (third valve).
The well has 6890 ft of 3 in. flow line and has reported a productivity
index of 3 bbls/psi. The general characteristics of the system rock-fluids are
given in Table C.5.

A.1.4 PEC-4
This well has two pay zones from sandstone reservoir; one was abandoned
because of high water cut, and the other has been producing at a rate of 420
STB/D with 15 % water. The reservoir has a static pressure of 2198 psi, 15
% porosity and 44 md of permeability. The well was completed with a 3 1/2
in. tubing (See figure B.53 and figure B.54). Water coning is expected
to be a problem. Therefore, the well is choked with a choke of 0.5 in. to
prevent the well from watering out. The general characteristics of the system
are given in Table C.5.

A.1.5 PEC-5, PEC-6 and PEC-7
These wells are producing from reservoir called VSU, which is a consolidated
sandstone, with a pressure of 600 psi at 3750 ft and a temperature of 140◦ F.
The sand has been producing for more than 20 years, leaving 15,398,438 bbl
of oil in place. The general characteristics of the system are given in Table
C.5. These wells are gas lifted and their characteristics, physical parameters
and the completions are given in Table C.5. For PEC-5, in figure B.65
and figure B.66. For PEC-6, in figure B.83 and figure B.84 and for
PEC-7, in figure B.101 and figure B.102.

A.1.6 PEC-8 and PEC-9
These wells are producing from reservoir called CAR, which is a highly frac-
tures with a high permeability of 500 md. The general characteristics of the
system are given in Table C.5. The schematics of these wells are given in
For PEC-8, in figure B.119 and figure B.120 and for PEC-9, in figure
B.131 and figure B.132. The pressure loss through perforations is reported
to be 1,415 psi. The perforation shot density is reported as 4 shots per feet.

33

A.1.7 PEC-10
This well is producing from a reservoir called SJ-1. This sand has a thickness
of 30 ft with 30 % of porosity and 30 md of permeability. The actual static
pressure of the reservoir is 2,800 psi and the bubble pressure of the oil is
3,500 psi. The general characteristics of the system are given in Table C.5.
The schematic of the well is given in figure B.143 and figure B.144.

A.1.8 PEC-11
This well is producing from a reservoir called SJ-1. This sand has a thickness
of 30 ft with 30 % of porosity and 30 md of permeability. The actual static
pressure of the reservoir is 2,800 psi and the bubble pressure of the oil is
3,500 psi. The general characteristics of the system are given in Table C.5.
The schematic of the well is given in figure B.153 and figure B.154. This
well is very similar to PEC-10. The difference is that this well is susceptible
to water coning. Therefore, the maximum flow rate should be 800 bbl/d.

34

Appendix B

Figures

Appendix B gives and extensive information about the application that has
been done in terms of figures. All the figures are well organized and showed
here starting from Normal Conditions, Changing tubing diameters, Changing
choke Bean size, Applying artificial lift performance and well performance
and ended up changing static pressure values.

35

36

Figure B.1: Actual Gathering System from the project ﬁle.

37

Figure B.2: Actual Gathering System after PIPESIM.

Figure B.3: Flowline for B1.



38




39

Figure B.9: Schematic view of well PEC-1 from project ﬁle.

Figure B.10: Schematic view of Well PEC-1, simulation after PIPESIM.

40

Figure B.11: Production History for PEC-1 from project ﬁle.

41

42

Figure B.12: IPR and OPR for PEC-1 under normal conditions.

Figure B.13: Pressure vs. depth for PEC-1 under normal conditions.

Figure B.14: Temperature vs. depth for PEC-1 under normal conditions.

43

44

Figure B.15: IPR and OPR for PEC-1 with changing tubing diameters.

Figure B.16: Pressure vs. depth for PEC-1 with changing tubing diameters.

Figure B.17: Temperature vs. depth curve for PEC-1 with changing tubing
diameters.

45

46

Figure B.18: IPR and OPR for PEC-1 with changing choke bean size.

Figure B.19: Pressure vs. depth for PEC-1 with changing choke bean size.

Figure B.20: Temperature vs. depth curve for PEC-1 with changing choke
bean size.

47

48

Figure B.21: Nodal Analysis curves for PEC-1 with changing static pressures.



49

Figure B.24: Schematic view of Topographical Survey for PEC-2.

50

51




52

53



diameters.

54

55



bean size.

56

57




58

59




60

61



diameters.

62

63

Figure B.43: IPR and OPR for PEC-3 at diﬀerent static pressures.

Figure B.44: IPR and OPR for for PEC-3 at diﬀerent static pressures and
gas lift at 2918 ft.

Figure B.45: IPR and OPR for for PEC-3 at diﬀerent static pressures and

64

65

Figure B.46: Well Performance curves under normal conditions.

Figure B.47: Well Performance curves when gas lift at 2918 ft.

Figure B.48: Well Performance curves when gas lift at 8811 ft.

66

67

Figure B.49: Artiﬁcial lift performance curves under normal conditions.

Figure B.50: Artiﬁcial lift performance curves when gas lift at 2918 ft.

Figure B.51: Artiﬁcial lift performance curves when gas lift at 8811 ft.

68

69




70

71




72

73



diameters.

74

75



bean size.

76

77




78

79

Figure B.67: IPR and OPR curves for PEC-5 under normal conditions.

Figure B.68: Pressure vs. depth curve for PEC-5 under normal conditions.

Figure B.69: Temperature vs. depth curve for PEC-5 under normal condi-
tions.

80

81



diameters.

82

83

Figure B.73: IPR and OPR for PEC-5 at diﬀerent tubing diameters.

Figure B.74: IPR and OPR for for PEC-5 at diﬀerent tubing diameters and


84

85

Figure B.76: Well Performance curves for PEC-5 under normal conditions.

Figure B.77: Well Performance curves for PEC-5 when gas lift at 1500 ft.


86

87

Figure B.79: Artiﬁcial lift performance curves for PEC-5 under normal conditions.

Figure B.80: Artiﬁcial lift performance curves for PEC-5 when gas lift at
1500 ft.

3000 ft.

88

89




90

91



tions.

92

93



diameters.

94

95




96

97




98

99


1550 ft.

3050 ft.

100

101




102

103



tions.

104

105



diameters.

106

107




108

109




110

111


1540 ft.

3050 ft.

112

113




114

115



tions.

116

117



diameters.

118

119



bean size.

120

121




122

123



tions.

124

125



diameters.

126

127



bean size.

128

129




130

131



Figure B.147: Temperature vs. depth curve for PEC-10 under normal con-
ditions.

132

133


Figure B.149: Pressure vs. depth for PEC-10 with changing tubing diame-
ters.

diameters.

134

Figure B.151: Nodal Analysis with Changing Static pressure and tubing
diameters.

Figure B.152: Nodal Analysis with Changing Outlet pressure.

135



136

137



Figure B.157: Temperature vs. depth curve for PEC-11 under normal con-
ditions.

138

139


Figure B.159: Pressure vs. depth for PEC-11 with changing tubing diame-
ters.

diameters.

140

Figure B.161: Nodal Analysis with Changing Static pressure and tubing
diameters.

Figure B.162: Nodal Analysis with Changing Outlet pressure.

141

Appendix C

Tables

142

The following table C.1 gives the well-manifold information.

Table C.1 Well- manifold information for Hurricane field.
W ell Condition Manifold Destination
PEC-3 Gas Lift P1 P2
PEC-1 Natural Flow P4 P2

The manifolds, the processing center and flow line conditions are given
in the following table C.2.

Table C.2 The manifolds, the processing center and flow line conditions.
M − P1 M − P 3 M − P 4 M − P 5 PC
Pressure (psi) 70 300 70 667 60
Oil Flow Rate (STB/D) 1160 1363 5392 21681 29596
Water Flow Rate (STB/D) 175 269 291 0 735
Gas Flow Rate (MMSCF/D) 0.51 5.92 6.13 43.36 55.92
Length (ft) 3300 1000 1300 40000
Diameter (in.) 8 10 12 15
API 30

143

Table C.3 Diﬀerent diameters Nominal and ID values from user guide.
Nominal Bore ID in
238
2.041
7
28 2.259
312
2.75
4.0 3.548
1
42 4.0
5.0 4.276
5.0 4.560
6.0 5.24
7.0 5.75
7.0 6.276

Table C.4 Flow rate comparison for given data set and at Nodal Analysis
point.
Wells After Nodal Analysis, BBPD Given actual Conditions, BBPD
PEC-1 1259.2171 1136
PEC-2 3232.7249 0
PEC-3 0 712
PEC-4 690.9286 420
PEC-5 1.4592 156
PEC-6 1.4666 180
PEC-7 1.4707 280
PEC-8 9568.8 2900
PEC-9 9825.716 1260
PEC-10 709.8362 780
PEC-11 880.636 1000

144

Table C.5 Actual Conditions for 11 wells in Hurricane field.
PEC-1 PEC-2 PEC-3 PEC-4 PEC-5 PEC-6 PEC-7 PEC-8 PEC-9 PEC-10 PEC-11
RESERVOIR SEC-1 SITEC NS620 RG194 VSU VSU VSU CAR CAR SJ-1 SJ-1
Model Type PSS Fetkovich. Vogel Vogel Vogel Vogel Vogel PSS PSS Vogel Vogel
Static Pressure [psi] 3982 3982 3400 2198 600 650 650 4000 4000 2800 2800
Reservoir Temp. [F] 284 128.3 278 298 140 140 140 180 180 298 298
Permeability [mD] 40 460 40 44 15 15 15 500 500 30 30
Porosity [%] 4 4.9 12 15 30 30 30 8 8 30 30
Rock Dolomite Dolomite Sand Sand CS CS CS Limestone Limestone Sand Sand
Drainage radius [ft] 300 - - - - - - 1600 1600 - -
Wellbore diameter [ft] 6.5 6.5 - - - - - 9 9 - -
Pay thickness [ft] 56 79 15 30 350 350 350 120 60 30 30
Skin factor 40 0 0 7 0 0 0 0 0 0 0
Total Recovery factor [%] 30 35 30 32 40 20 40 35 35 35 35
Actual Recovery factor [%] 1 30 20 15 20 20 20 15 15 28 28
Oil in place [bbl] 10,568,000 365,500,000 37,568,000 35,000,000 30,796,875 30,796,875 30,796,875 50,010,000 50,010,000 14,563,804 14,563,804
Bubble Pressure [psi] 3210 3210 3600 3821 1250 1250 1250 4000 4000 3500 3500
FLUIDS
Fluid Model Black Oil Black Oil Black Oil Black Oil Black Oil Black Oil Black Oil Black Oil Black Oil Black Oil Black Oil
Oil gravity [API] 35 30.5 25 38.2 26 26 26 30 30 25 25
Gas gravity [rel.to air] 0.861 0.793 0.7 0.7 0.7 0.7 0.7 0.65 0.65 0.65 0.65
Water gravity [rel.to water] 1.02 1.02 1.02 1.02 1.02 1.02 1.02 1.02 1.02 1.02 1.02
GOR [ft3/bbl] 1500 440 400 4214 444 474 500 800 800 4706 4000
Water cut [%] 23 10 20 15 10 5 0 0 0 15 30
WELL
145

Production method NF NF GL NF GL GL GL NF NF NF NF
Gas lift flow rate [MMSCFD] - - 0.5 - 0.4 0.4 0.4 - - - -
Vertical flow correlation HB BB Ansari HB MB MB MB Ansari Ansari HB HB
Inclination Angle [deg] 0 0 0 0 0 0 0 26 0 0 0
Depth of Perforation [ft] 12495 6424 12132.5 10428 3750 3802 3810 9000 9400 12110 12165
Pwf [psi] 1830 3258 3200 2066 486 500 560 2435 2350 2081 1840
Pwh [psi] 300 1095 260 1095 80 80 80 500 430 670 1000
Production Rate [BBPD] 1136 0 712 420 156 180 280 2900 1260 780 1000
Open Flow Potential 22474 - - 500 450 1200 - -
Choke [inch] 0.875 0.5 - 0.5 0 0 0 1 1 - -
PIPELINE
Horizontal Flow Correlation BBR D,A,F BBR Xiao Xiao Xiao Xiao Xiao Xiao BBR BBR
Length [ft] 8202 17585 6890 4921 3000 3000 3200 5000 4501 9950 11000
Diameter [inc.] 4 10 3 3 4 4 4 6 6 3 6
Inclination [deg] 0 0 0 0 0 0 0 0 0 0 0

Appendix D

Matlab Code

D.1 Post processing code for changing tubing
diameters
% Post P r o c e s s i n g f o r P r o d u c t i o n Design P r o j e c t
%
% S e l c u k Fidan
clc ; clear a l l ; close a l l ;

% Steam q u a l i t y
%
DataFromWells = x l s r e a d ( ’ TubingSize . x l s x ’ ) ; % pascal

% Pec−1
subplot ( 2 , 5 , 1 )
plot ( DataFromWells ( : , 2 ) , DataFromWells ( : , 1 ) , ’ b− ’ , . . .
’ linewidth ’ ,3);

ylabel ( ’Q, Flow r a t e , s b b l /d ’ , ’ Fontname ’ , . . .
’ C a l i b r i ’ , ’ FontSize ’ , 18)
xlabel ( ’ Tubing d i a m e t e r ( i n c h e s ) ’ , ’ Fontname ’ , . . .
legend ( ’PEC−1 ’ , ’ Fontname ’ , ’ C a l i b r i ’ , . . .
’ F o n t S i z e ’ , 1 4 , ’ L o c a t i o n ’ , ’ SouthEast ’ )
set ( gca , ’ XAxisLocation ’ , ’ top ’ )
set ( gca , ’ FontSize ’ , 1 2 , . . .
’ XMinorTick ’ , ’ on ’ , . . .
’ YMinorTick ’ , ’ on ’ , . . .
’ Tic kDi r ’ , ’ out ’ ) ;
box ( ’ on ’ ) ;
grid on

146

% Pec−2
subplot ( 2 , 5 , 2 )
plot ( DataFromWells ( : , 2 ) , DataFromWells ( : , 3 ) , . . .
’ b− ’ , ’ l i n e w i d t h ’ , 3 ) ;
legend ( ’PEC−2 ’ , ’ Fontname ’ , ’ C a l i b r i ’ , ’ F o n t S i z e ’ , . . .
1 4 , ’ L o c a t i o n ’ , ’ SouthEast ’ )
set ( gca , ’ FontSize ’ , 1 2 , . . .
’ XMinorTick ’ , ’ on ’ , . . .
’ YMinorTick ’ , ’ on ’ , . . .
’ Tic kDi r ’ , ’ out ’ ) ;
box ( ’ on ’ ) ;
grid on

% Pec−3
subplot ( 2 , 5 , 3 )
’ b− ’ , ’ l i n e w i d t h ’ , 3 ) ;
set ( gca , ’ FontSize ’ , 1 2 , . . .
’ XMinorTick ’ , ’ on ’ , . . .
’ YMinorTick ’ , ’ on ’ , . . .
’ Tic kDi r ’ , ’ out ’ ) ;
box ( ’ on ’ ) ;
grid on

% Pec−4
subplot ( 2 , 5 , 4 )
’ b− ’ , ’ l i n e w i d t h ’ , 3 ) ;

147

set ( gca , ’ FontSize ’ , 1 2 , . . .
’ XMinorTick ’ , ’ on ’ , . . .
’ YMinorTick ’ , ’ on ’ , . . .
’ Tic kDi r ’ , ’ out ’ ) ;
box ( ’ on ’ ) ;
grid on
% Pec−6
subplot ( 2 , 5 , 5 )
’ b− ’ , ’ l i n e w i d t h ’ , 3 ) ;
set ( gca , ’ FontSize ’ , 1 2 , . . .
’ XMinorTick ’ , ’ on ’ , . . .
’ YMinorTick ’ , ’ on ’ , . . .
’ Tic kDi r ’ , ’ out ’ ) ;
box ( ’ on ’ ) ;
grid on
% Pec−7
subplot ( 2 , 5 , 6 )
’ b− ’ , ’ l i n e w i d t h ’ , 3 ) ;
set ( gca , ’ FontSize ’ , 1 2 , . . .
’ XMinorTick ’ , ’ on ’ , . . .
’ YMinorTick ’ , ’ on ’ , . . .
’ Tic kDi r ’ , ’ out ’ ) ;
box ( ’ on ’ ) ;
grid on
% Pec−8
subplot ( 2 , 5 , 7 )

148

’ b− ’ , ’ l i n e w i d t h ’ , 3 ) ;
set ( gca , ’ FontSize ’ , 1 2 , . . .
’ XMinorTick ’ , ’ on ’ , . . .
’ YMinorTick ’ , ’ on ’ , . . .
’ Tic kDi r ’ , ’ out ’ ) ;
box ( ’ on ’ ) ;
grid on
% Pec−9
subplot ( 2 , 5 , 8 )
’ b− ’ , ’ l i n e w i d t h ’ , 3 ) ;
set ( gca , ’ FontSize ’ , 1 2 , . . .
’ XMinorTick ’ , ’ on ’ , . . .
’ YMinorTick ’ , ’ on ’ , . . .
’ Tic kDi r ’ , ’ out ’ ) ;
box ( ’ on ’ ) ;
grid on
% Pec−10
subplot ( 2 , 5 , 9 )
plot ( DataFromWells ( : , 2 ) , DataFromWells ( : , 1 0 ) , ’ b− ’ , . . .
’ linewidth ’ ,3);
ylabel ( ’Q, Flow r a t e , s b b l /d ’ , ’ Fontname ’ , ’ C a l i b r i ’ , . . .
’ FontSize ’ , 18)
xlabel ( ’ Tubing d i a m e t e r ( i n c h e s ) ’ , ’ Fontname ’ , ’ C a l i b r i ’ , . . .
’ FontSize ’ , 18)
set ( gca , ’ FontSize ’ , 1 2 , . . .
’ XMinorTick ’ , ’ on ’ , . . .
’ YMinorTick ’ , ’ on ’ , . . .

149

’ Tic kDi r ’ , ’ out ’ ) ;
box ( ’ on ’ ) ;
grid on
% Pec−11
subplot ( 2 , 5 , 1 0 )
plot ( DataFromWells ( : , 2 ) , DataFromWells ( : , 1 1 ) , . . .
’ b− ’ , ’ l i n e w i d t h ’ , 3 ) ;
set ( gca , ’ FontSize ’ , 1 2 , . . .
’ XMinorTick ’ , ’ on ’ , . . .
’ YMinorTick ’ , ’ on ’ , . . .
’ Tic kDi r ’ , ’ out ’ ) ;
box ( ’ on ’ ) ;
grid on

150

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