STUDY OF TAPERED INTERNAL DIAMETER TUBING STRING WELL
COMPLETION FOR ENHANCED PRODUCTION
By
BERTRAND O. AFFANAAMBOMO, B.Sc.
A THESIS
IN
PETROLEUM ENGINEERING
Submitted to the Graduate Faculty
Of Texas Tech University in
Partial Fulfillment of
the Requirements for
the Degree of
MASTER OF SCIENCE
IN
PETROLEUM ENGINEERING
Approved
M. Rafiqul Awal
Chairperson of the Committee
Shameem Siddiqui
Lloyd R. Heinze
Accepted
Fred Hartmeister
Dean of the Graduate School
August, 2008
DEDICATION
This thesis is dedicated
To my late uncle, Ndongo Ebode Louis, whose sacrifice and love eased my
accomplishment and made the man that I am today.
Texas Tech University, Bertrand O. Affanaambomo, August 2008
ACKNOWLEDGEMENTS
I would like to start by expressing my heartfelt thanks to Dr. M. Rafiqul Awal
who not only introduced this topic to me but also served as my committee chairperson.
Dr. M. Rafiqul Awal took me as his protégé soon after his arrival at Texas Tech
University, and inspired me into finishing this research and my master’s program. I am
pleased to have him as my mentor.
I also would like to thank Dr. Lloyd R. Heinze and Dr. Shameem Siddiqui, my
committee members, for their advice and motivation throughout this research.
Thanks to Dr. Ralph Ferguson, Associate Dean, for his help and dedication that
made my graduation possible. Special thanks to Simo Stephane, Renee Jones, Waynishet
Hebert, Md Rakibul Sarker, Morteza Akbari, and other colleagues and friends for their
assistance throughout my research and academic era.
I would like to thank my parents, Mr. Affana Ebode Marc and Mrs. Ngondi
Edwige for their unconditional love that always keeps me going. Thanks to my brothers,
sisters and cousins, Christian, Jojo, Germaine la petite, Camille, Clarisse, Lili, Daniel and
Yannick, Marcel, Edwige, Flore, Ebode, Germaine la grande, and Alida, for their
encouragement and love.
Abega Affana Valentin, to whom I also dedicate this thesis, has always been a
blessing and my greatest source of inspiration.
Last but not least, I thank God for my Resiliency and His blessings in my life.
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Texas Tech University, Bertrand O. Affanaambomo, August 2008
TABLE OF CONTENTS
ACKNOWLEDGEMENTS ................................................................................................ ii
ABSTRACT...................................................................................................................... vii
LIST OF TABLES ........................................................................................................... viii
LIST OF FIGURES ........................................................................................................... xi
LIST OF ABBREVIATIONS .......................................................................................... xvi
I. INTRODUCTION ........................................................................................................... 1
1.1
TYPES OF WELL COMPLETIONS .............................................................. 2
1.1.1
Casing completions ....................................................................................................................2
1.1.1.1 Conventional perforated casing completions .....................................................................2
1.1.1.2 Permanent well completions ...............................................................................................2
1.1.1.3 Multiple-zone completions ..................................................................................................2
1.1.1.4 Sand-exclusion completions ................................................................................................3
1.1.1.5 Water- and gas-exclusion completions ...............................................................................3
1.1.2
Open-Hole completions .............................................................................................................3
1.1.3
Drainhole completions ..............................................................................................................4
1.2
MOTIVATION FOR THE PRESENT STUDY .............................................. 8
1.3
STATEMENT OF THE PROBLEM.............................................................. 15
1.4
APPROACH TO THE PROBLEM ................................................................ 15
II. LITERATURE REVIEW............................................................................................. 17
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2.1 NODAL ANALYSIS FOR NATURAL FLOWS................................................ 17
2.2 INFLOW PERFORMANCE RELATIONSHIP (IPR) ..................................... 22
2.2.1 Vogel’s Method ...........................................................................................................................24
2.2.2 Wiggins’ Method .........................................................................................................................25
2.2.3 Standing’s Method .......................................................................................................................26
2.2.4 Fetkovich’s Method .....................................................................................................................27
2.2.5 The Klins-Clark Method ..............................................................................................................30
2.3 TUBING PERFORMANCE RELATIONSHIP (TPR) ..................................... 31
2.4 ERROR ESTIMATION IN CALCULATION ................................................... 34
2.5 WELL PRODUCTION FORECAST .................................................................. 35
2.5.1 Transient Flow Period..................................................................................................................35
2.5.2 Pseudo-Steady State Single Phase Flow Period ...........................................................................36
2.5.3 Pseudo-Steady Two-Phase Flow Period ......................................................................................37
2.6 EFFECT OF TUBING SIZE ................................................................................ 38
2.7 ASSUMPTIONS AND CONSIDERATIONS ..................................................... 40
III. METHODOLOGY ..................................................................................................... 42
3.1 ALGORITHM (Step-by-Step Procedure) ........................................................... 42
3.1.1 Different Scenarios ......................................................................................................................42
3.1.2 Stabilized Flowrate ......................................................................................................................43
3.1.3 Concept of Equivalent Tubing Diameter .....................................................................................44
3.1.4 Economic Analysis ......................................................................................................................44
3.1.4.1 Well Production Forecast Procedure ....................................................................................45
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3.2 INPUT DATA (Case Studies) ............................................................................... 49
IV. RESULTS AND DISCUSSION ................................................................................. 51
4.1 STABILIZED FLOWRATE RESULTS ............................................................. 51
4.2 EQUIVALENT TUBING DIAMETER .............................................................. 60
4.3 WELL PRODUCTION FORECAST RESULTS .............................................. 65
4.4 ECONOMIC ANALYSIS RESULTS ................................................................. 78
V. COMPARISON OF RESULTS ................................................................................... 87
5.1 COST COMPARISONS ....................................................................................... 87
5.2 STABILIZED FLOWRATES COMPARISONS ............................................... 92
5.3 RECOVERY TIME COMPARISONS ............................................................... 96
5.4 PAYOUT TIME COMPARISONS ................................................................... 100
5.5 NET PRESENT VALUE COMPARISONS ..................................................... 104
5.6 RETURN ON INVESTMENT COMPARISONS ............................................ 108
VI. SUMMARY OF RESULTS ..................................................................................... 112
VII. CONCLUSIONS AND RECOMMENDATIONS .................................................. 125
7.1 CONCLUSIONS ................................................................................................. 125
7.2 RECOMMENDATIONS .................................................................................... 126
REFERENCES ............................................................................................................... 127
APPENDIX
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A. WELL PRODUCTION FORECAST INPUT DATA ............................................... 130
B. ADDITIONAL WELL PRODUCTION FORECAST RESULTS ............................ 136
C. COST ASSUMPTIONS ............................................................................................. 158
D. ADITIONAL ECONOMIC ANALYSIS RESULTS ................................................ 159
E. VITA........................................................................................................................... 161
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ABSTRACT
Conventional Well Completion involves usually a single, internal diameter (ID)
tubing for producing oil from the subsurface reservoir.
As the oil flows vertically
upward, the flowing pressure decreases as a function of depth. This reduction in flowing
pressure causes more and more dissolved gases to come out. Consequently, the flow
stream, especially free gas, expands in volume per unit mass flow rate.
The motivation of the present study is to investigate the effect of gradually
increasing the tubing inside diameter (ID) as the fluid moves up the string. We call this
Tapered ID Tubing Well Completion (TTWC), which is expected to give higher flow
rates of oil. Apparently the TTWC involves a slight increase in capital expenditure
(CAPEX) for the additional cost accrued from using a section of larger ID tubing.
Therefore, we performed numerous studies using nodal analysis for various
tubing size combinations, and also economic analysis over the entire producing life of the
well. The study reveals that the higher flow rates possible through TTWC not only offsets
the additional CAPEX, but also gives significant economic benefits compared to the
conventional single tubing completion.
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LIST OF TABLES
1. 1 Comparisons of Various Well Completion Types ....................................................... 5
4. 1 Results Obtained for 1.995 in. tubing ........................................................................ 52
4. 2 Observations and Results for 2.441 in. tubing ........................................................... 53
4.3 Results Obtained for 2.992 in. tubing ......................................................................... 54
4.4 Results Obtained for 3.340 in. tubing ......................................................................... 55
4. 5 Results Obtained for 2.441&1.995 in. tubing ............................................................ 56
4. 6 Results Obtained for 3.340&2.441 in. tubing ............................................................ 57
4. 7 Results Obtained for 3.340, 2.992, & 2.441 in. tubing .............................................. 58
4. 8 Results Obtained for quad tubing .............................................................................. 59
4. 9 ETD for dual tubing ................................................................................................... 61
4. 10 ETD for trio tubing .................................................................................................. 63
4. 11 ETD for quad tubing ................................................................................................ 64
4.12 Economic Analysis for 1.995" Tubing ..................................................................... 80
4.13 Economic Analysis for 2.441" Tubing ..................................................................... 81
4.14 Economic Analysis for dual Tubing (2.441" & 1.995") ........................................... 82
4.15 Economic Analysis for dual Tubing (3.340" & 2.441") ........................................... 83
4.16 Economic Analysis for Trio Tubing ......................................................................... 84
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4.17 Economic Analysis for Quad Tubing ....................................................................... 85
4. 18 Summary of Economic Analysis ............................................................................. 86
A1: Input data for well production forecast .................................................................... 130
B1: Oil Production Forecast for N = 1 ............................................................................ 136
B2: Gas Production Forecast for N = 1........................................................................... 137
B3: Production Schedule Forecast for 1.995” Tubing .................................................... 138
B4: Production Forecast for 1.995" Tubing .................................................................... 139
B5: Production Schedule Forecast for 2.441” Tubing .................................................... 140
B6: Production Forecast for 2.441" Tubing .................................................................... 141
B7: Production Schedule Forecast for 2.992” Tubing .................................................... 142
B8: Production Forecast for 2.992" Tubing .................................................................... 143
B9: Production Schedule Forecast for 3.340” Tubing .................................................... 145
B10: Production Forecast for 3.340" Tubing .................................................................. 146
B11: Production Schedule Forecast for Dual Tubing (2.441" & 1.995") ....................... 148
B12: Production Forecast for Dual Tubing (2.441" & 1.995")....................................... 149
B13: Production Schedule Forecast for Dual Tubing (3.340" & 2.441") ....................... 150
B14: Production Forecast for Dual Tubing (3.340" & 2.441")....................................... 151
B15: Production Schedule Forecast for Trio Tubing ...................................................... 152
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B16: Production Forecast for Trio Tubing...................................................................... 153
B17: Production Schedule Forecast for Quad Tubing .................................................... 154
B18: Production Forecast for Quad Tubing .................................................................... 155
C1: costs Assumptions .................................................................................................... 158
D1: Economic Analysis for 2.992" Tubing .................................................................... 159
D2: Economic Analysis for 3.340" Tubing .................................................................... 160
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LIST OF FIGURES
1. 1 Completed well/ Open-hole completion ...................................................................... 6
1. 2 Two Types of Drainhole completions.......................................................................... 7
1. 3 Conventional Tubing ................................................................................................. 11
1. 4 Duplex Tubing ........................................................................................................... 12
1. 5 Triplex Tubing ........................................................................................................... 13
1. 6 Quad Tubing .............................................................................................................. 14
2. 1 Pressure Losses in Producing Well System ............................................................... 18
2. 2 Most Common Nodal Points Position ....................................................................... 20
2.3 Inflow Performance Relationship Curve .................................................................... 23
2.4 Straight-line IPR ......................................................................................................... 24
2. 5 Pressure Function Regions ......................................................................................... 28
2.6 flow inside Tubing ...................................................................................................... 32
4. 1 Nodal Analysis for 1.995 in. tubing ........................................................................... 52
4. 2 Nodal Analysis for 2.441 in. tubing ........................................................................... 53
4.3 Nodal Analysis for 2.992 in. tubing ............................................................................ 54
4.4 Nodal Analysis for 3.340 in. tubing ............................................................................ 55
4. 5 Nodal Analysis for dual tubing (2.441&1.995 in. tubing) ......................................... 56
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4. 6 Nodal Analysis for dual tubing (3.340&2.441 in. tubing) ......................................... 57
4. 7 Nodal Analysis for trio tubing (3.340, 2.992, & 2.441 in. tubing) ............................ 58
4. 8 Results Obtained for quad tubing .............................................................................. 59
4.9 Single Tubing Plot ...................................................................................................... 60
4.10 Production Forecast for 1.995” Tubing .................................................................... 66
4.11 Nodal Analysis Plot for 1.995” Tubing .................................................................... 67
4.12 Production Forecast for 2.441” Tubing .................................................................... 68
4.13 Nodal Analysis Plot for 2.441" Tubing .................................................................... 69
4.14 Production Forecast for Dual Tubing (2.441" & 1.995") ......................................... 70
4.15 Nodal Analysis Plot for Dual Tubing (2.441" & 1.995") ......................................... 71
4.16 Production Forecast for Dual Tubing (3.340" & 2.441") ......................................... 72
4.17 Nodal Analysis Plot for Dual Tubing (3.340" & 2.441") ......................................... 73
4.18 Production Forecast for Trio Tubing ........................................................................ 74
4.19 Nodal Analysis Plot for Trio Tubing ........................................................................ 75
4.20 Production Forecast for Quad Tubing....................................................................... 76
4.21 Analysis Plot for Quad Tubing ................................................................................. 77
5.1 Dual Tubing (2.441" & 1.995") vs. Single Tubing ..................................................... 88
5. 2 Dual Tubing (3.340” & 2.441”) vs. Single Tubing.................................................... 89
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5. 3 Trio Tubing vs. Single Tubing ................................................................................... 90
5. 4 Quad Tubing vs. Single Tubing ................................................................................. 91
5. 5 Dual Tubing (2.441" & 1.995") vs. Single Tubing .................................................... 92
5. 6 Dual Tubing (3.340" & 2.441") vs. Single Tubing .................................................... 93
5. 7 Trio Tubing vs. Single Tubing ................................................................................... 94
5. 8 Quad Tubing vs. Single Tubing ................................................................................. 95
5.9 Tubing (2.441" & 1.995") vs. Single Tubing (1.995") ............................................... 96
5. 10 Dual Tubing (3.340" & 2.441") vs. Single Tubing (2.441”) ................................... 97
5. 11 Trio Tubing vs. Single Tubing ................................................................................. 98
5. 12 Quad Tubing vs. Single Tubing ............................................................................... 99
5.13 Dual Tubing (2.441" & 1.995") vs. Single Tubing ................................................. 100
5. 14 Dual Tubing (3.340” & 2.441”) vs. Single Tubing................................................ 101
5. 15 Trio Tubing vs. Single Tubing ............................................................................... 102
5. 16 Quad Tubing vs. Single Tubing ............................................................................. 103
5.17 Dual Tubing (2.441" & 1.995") vs. Single Tubing ................................................. 104
5. 18 Dual Tubing (3.340" & 2.441") vs. Single Tubing ................................................ 105
5. 19 Trio Tubing vs. Single Tubing ............................................................................... 106
5. 20 Quad Tubing vs. Single Tubing ............................................................................. 107
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5.21 Dual Tubing (2.441" & 1.995") vs. Single Tubing ................................................. 108
5. 22 Dual Tubing (3.340" & 2.441") vs. Single Tubing ................................................ 109
5. 23 Trio Tubing vs. Single Tubing ............................................................................... 110
5.24 Quad Tubing vs. Single Tubing .............................................................................. 111
6. 1 Production Forecast for dual Tubing (2.441" & 1.995") & Single Tubing (1.995") 112
6. 2 Production Forecast for dual Tubing (3.340" & 2.441") & Single Tubing (2.441") 113
6. 3 Production Forecast for Trio Tubing & Single Tubing (2.441") ............................. 114
6. 4 Production Forecast for Quad Tubing & Single Tubing (2.441") ........................... 115
6. 5 Cost Results for Different Scenarios........................................................................ 116
6. 6 Recovery Time Results for Different Scenarios ...................................................... 117
6. 7 Cashflow: Dual Tubing (2.441" & 1.995") & Single Tubing (1.995").................... 118
6. 8 Cashflow: Dual Tubing (3.340" & 2.441") & Single Tubing (2.441").................... 119
6. 9 Cashflow: Trio Tubing & Single Tubing (2.441") .................................................. 120
6. 10 Cashflow: Quad Tubing & Single Tubing (2.441") ............................................... 121
6. 11 Payout Time Results for Different Scenarios ........................................................ 122
6. 12 Net Present Value Results for Different Scenarios ................................................ 123
6. 13 Return on Investment Results for Different Scenarios .......................................... 124
A1 Thermodynamic Properties for Fluid ........................................................................ 131
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A2 Thermodynamic Properties for Fluid ........................................................................ 132
A3 Relative Permeabilities for Fluid .............................................................................. 133
B1: Production Forecast for 2.992” Tubing.................................................................... 144
B2: Production Forecast for 3.340” Tubing.................................................................... 147
B3: Nodal Analysis Plot for 2.992" Tubing .................................................................... 156
B4: Nodal Analysis Plot for 3.340" Tubing .................................................................... 157
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LIST OF ABBREVIATIONS
Symbol
Definition
A
Cross-sectional Area
Bo
Oil formation volume factor
Bg
Gas formation volume factor
Ct
Total reservoir compressibility
D
Tubing inner diameter
fF
Fanning friction factor
g
Gravitational acceleration
gc
Unit conversion factor
h
Reservoir thickness
J
Productivity index
K
Permeability
kr
Relative permeability
L
Tubing length
Np
Cumulative produced oil
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ΔNp
Cumulative produced change
P
Pressure
Pe
Pressure drainage
Pnode
Pressure of the chosen nodal
point
PR
Reservoir pressure
PR
Average reservoir pressure
Psep
Separator pressure
Pwf
Well flowing pressure
ΔP
Pressure drop
PWFS
Pressure through perforations
q
Production rate
rd
Reservoir drainage radius
re
Drainage radius
Rs
Solution gas-oil ratio
rw
Well bore radius
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R
Average gas-oil ratio
S
Skin factor
So
Oil saturation
t
Time
T
Temperature
Δt
Production time change
u
Fluid velocity
Δz
Elevation increase
Greek Letter
β
Formation volume factor
ρ
Fluid density
μ
Viscosity
Φ
Porosity
γ
Specific gravity
Subscript
i
initial
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o
Oil
g
Gas
sc
Standard conditions
w
Water
wf
Bottom hole
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Conversion of Units Factors
Quantity
U.S. Field unit
To SI unit
To U.S. Field unit
SI unit
Length (L)
feet (ft)
0.3084
3.2808
meter (m)
sq. ft (ft2)
9.29 × 102
10.764
meter2 (m2)
4.0469 × 10^3
2.471 × 104
meter2 (m2)
sq. mile
2.59
0.386
gallon (gal)
0.003785
264.172
meter3(m3)
ounce (oz)
28.3495
0.03527
gram (g)
pound (lb)
0.4536
2.205
kilogram (kg)
lbm
0.0311
32.17
Slug
lb/in2 (psi)
6.8948
0.145
kPa (1000 Pa)
psi
0.0680
14.696
Atm
psi/ft
22.62
inch Hg
3.3864 × 10
Area (A)
Volume (V)
Mass (M)
Pressure (P)
acre
(km)2
0.0442
3
kPa/m
0.2953 × 10
3
Pa
o
F
0.5556(F+32)
1.8C+32
Rankine (8R)
0.5556
1.8
Kelvin (K)
cp
0.001
1,000
Pa-s
lb/ft-sec
1.4882
0.672
kg/(m-sec) or
(Pa-s)
lbf-s/ft2
479
0.0021
dyne-s/cm2
(poise)
Density (P)
lbm/ft3
16.02
0.0624
kg/m3
Permeability
(k)
md
0.9862
1.0133
mD ( =10-15m2)
md ( = 10-3darcy)
9.8692 × 10-16
1.0133 × 1015
m2
Temperature
(t)
Viscosity
(m)
xx
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Texas Tech University, Bertrand O. Affanaambomo, August 2008
CHAPTER I
INTRODUCTION
Well completion is a set of operations meant to ease production from a well.
Based on the definition, this means that well completion is not only one of the most
important aspects of a well, but also it constitutes the connection between the borehole
and the pay zone, the pay zone treatment (if any), equipment, and etc. of the same well.
Completion therefore, can be defined as the interval that goes from well locating to well
abandonment. Completion furthermore makes possible well operations using a logical
and inexpensive way. As a result, it should not be “off the rack,” but “tailor made”
20
.
Figure 1.1 shows an appropriate illustration of a completed well.
To decide on the type of completion, some specific basis of conduct and
expectation must be meant20:
o Completion and maintenance vs. profits; evidently the larger the field with
excellence oil production at fast flowrate, the greater the expenses.
o Money-saving vs. possible risks; a risk taken should always consider
predictable spending and chances of erroneous hazards.
o Supposed change in production of the field vs. supposed change in production
of the specified well; the selected type of completion must be met from the
beginning of production or must allow a trouble-free adjustment for a future
workover.
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1.1
TYPES OF WELL COMPLETIONS
There are three categories of well completions18:
1.1.1 Casing completions
The casing completion is the most used (90% of the time) of the three types.
There are five types of casing completions.
1.1.1.1 Conventional perforated casing completions
It is a completion technique in which a casing string is run from the surface to the
producing zone, followed by its cementing in place. This technique involves the
perforation of the casing string. Oil is produced through the casing string.
1.1.1.2 Permanent well completions
In this completion, the tubing and wellhead are placed permanently. All other
activities (completion or corrective operations) are executed with a small diameter tool
through the tubing.
1.1.1.3 Multiple-zone completions
It is a completion used when there is more than one producing zone. The
technique permits a synchronized production of two or more producing zones. This
technique is complex and pricey due to the downhole equipment and tools used to
complete the job.
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1.1.1.4 Sand-exclusion completions
It is a complicated completion used when a well is drilled in unconsolidated sand.
Sand-exclusion completion is usually used during completion time or sometimes during
the life of a well. The risk is that sand production can wear down the equipment, wellbore
and flowlines, thus it can ruin your investment.
1.1.1.5 Water- and gas-exclusion completions
Water-and gas-exclusion completions are used when free gas conservation and
lesser water productions are needed. Thus to achieve it, appropriate zones inside the
producing zone are chosen.
1.1.2 Open-Hole completions
Open-hole completions are wells completed with the oil tubing string placed
above the productive zone, or in which the productive zone is left open without
protection. This technique is merely employed in steady rock formations. It is used since
it allows the zone of interest to be tested while drilling, there is no formation damaged
from drilling mud or cement, the production is greater than other completions, and it is
cheaper. Figure 1.1 shows an illustration of open-hole completion.
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1.1.3 Drainhole completions
Drainhole completions are methods used to complete horizontal wells or slant
wells. The main advantage of the technique is to elongate the production zone in order to
boost the productivity. Figure 1.2 shows two types of drainhole completions.
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Table 1. 1 Comparisons of Various Well Completion Types18
Well Completion Types
Advantages
•
Casing completions Types
•
Conventional perforated
casing completions
• Permanent well
completions
• Multiple-zone
completions
• Sand-exclusion
completions
• Water- and gasexclusion completions
Open-Hole Completions
•
•
Water-bearing rocks from
above or below the productive
formation are sealed off.
Better economy
•
•
•
•
•
Speed up the rate of flow from
the productive interval.
More productive than a
conventional perforated-casing
completion.
Less expensive
Less cement contamination
•
Increase in productivity
•
Drainhole completions
Disadvantages
Required
casing
swabbing.
Tools are tiny
and
ineffective.
More
complex and
pricey.
•
Less degree
of control
over the
desired
productive
interval.
•
Cost more
than other
completion
types.
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Figure 1.1: Completed well/Open-hole completion24
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Figure 1.2: Two Types of Drainhole completions18
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1.2
MOTIVATION FOR THE PRESENT STUDY
In general, a completion design must be capable to resolve the following
problems successfully20:
o preserve borehole wall stability, if required
o guarantee selective fluid production from specific formation, if required
o reduce confine in the flow path
o guarantee well safety
o permit well flow control
o permit well operations with minimum workover
o facilitate workover, if required
Well completion is therefore essential to the performance of a well during its
entire life, but it has, for a long time, been expensive to the oil industry. Moreover, with
its advanced options of today’s technology, it has made an impact in capital expenditure
(CAPEX) increase, thus should allow a faster and better investment return.
Conventional well completion employs in general a single inside-diameter (ID)
tubing string (fig. 1.3). Sometimes a smaller or larger ID tubing string section(s) is used
due to workover and borehole constraint necessities.
We note that as the oil flows vertically upward, the flowing pressure decreases as
a function of depth. This reduction in flowing pressure causes more and more dissolved
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Texas Tech University, Bertrand O. Affanaambomo, August 2008
gases to come out. Consequently, the flow stream, especially free gas, expands in volume
per unit mass flowrate.
If the capacity of the flow string does not increase as the fluid moves up, more
and more flow restriction is experienced, causing higher flowing pressure gradient. This
will cause an increase in flowing bottomhole pressure (FBHP), which will decrease the
reservoir pressure abandonment, and hence the oil production rate.
Therefore, the motivation of the present study is to investigate the effect of
gradually increasing the tubing ID as the fluid moves up the string.
This is conceptualized as Tapered inside diameter Tubing string Well Completion
(TTWC).
To make TTWC a practical engineering design, from both technical and
economical aspects, we envisage two, three, and four ID’s in the production string.
Comparisons between single and tapered completion string will be made using the
following criteria:
1.
Effect on production rate, and cumulative production;
2.
Effect on capital expenditure (CAPEX);
3.
Economic analysis over full life cycle of a well.
The TTWC design, used for this study, includes a combination, tapered tubing
strings with the smallest size tubing at the bottom and the largest size at the top up. The
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study will be limited to the duplex, triplex and quad strings. An illustration of a duplex
tubing, triplex tubing, and quad tubing is shown in Figures 1.4, 1.5, and 1.6, respectively.
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Texas Tech University, Bertrand O. Affanaambomo, August 2008
Figure 1.3 Conventional Completion
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Texas Tech University, Bertrand O. Affanaambomo, August 2008
Figure 1. 4 Duplex Tubing
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Texas Tech University, Bertrand O. Affanaambomo, August 2008
Figure 1. 5 Triplex Tubing
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Texas Tech University, Bertrand O. Affanaambomo, August 2008
Figure 1. 6 Quad Tubing
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Texas Tech University, Bertrand O. Affanaambomo, August 2008
1.3
STATEMENT OF THE PROBLEM
This study is important for the following reasons:
o Well inflow-outflow analysis over the full life cycle of an oil well shows
that the proposed completion is suitable for a new as well as an old well.
o Production Optimization
o Accelerated Recovery
o Better economy performance
The study does not focus on factors affecting the proposed TTWC such as: the
mechanical challenge and design of the TTWC. To calculate the well production forecast,
we used real field data and the units used are field units. In this study, the terms dual
tubing, trio tubing and quad tubing will be used for duplex tubing, triplex tubing and
quadruple tubing, respectively.
1.4
APPROACH TO THE PROBLEM
To examine the effectiveness of the proposed TTWC well completion, the following
objectives are set for this study:
o Conduct a focused review of literature on IPR and TPR construction
methods, and well performance forecast method.
o Collect pertinent reservoir, well, fluid, and production data
o Determine stabilized flowrates for the single, dual, triple and quad strings,
using nodal analysis software.
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Texas Tech University, Bertrand O. Affanaambomo, August 2008
o Run economic analysis (using NPV) for variation strings.
o Compare results of a single string vs. dual, triple, and quad strings.
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Texas Tech University, Bertrand O. Affanaambomo, August 2008
CHAPTER II
LITERATURE REVIEW
2.1 NODAL ANALYSIS FOR NATURAL FLOWS
Natural flow is one of the mechanisms that some producing wells exploit to
transport produced fluids from the bottom to the surface. Gas wells usually flow
naturally. Oil wells, on the other hand, sometimes will flow naturally because of constraint
energy gained in their premature phases of their productive life.
Typical produced fluids go through many constraints (friction losses) during their
transportation from the reservoir to the surface. They must go through reservoir rock
matrix, perforations and probable gravel pack, probably a bottomhole standing valve, the
tubing, probably a subsurface safety valve, the surface flowline, and flowline choke to the
separator. Figure 2.1 shows potential pressure losses in producing well system.
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Texas Tech University, Bertrand O. Affanaambomo, August 2008
Figure 2. 1 Pressure Losses in Producing Well System1
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Texas Tech University, Bertrand O. Affanaambomo, August 2008
Where
1. ∆P1 = PR – Pwfs = pressure drop in porous medium
2. ∆P2 = Pwfs – Pwf = pressure drop across completion
3. ∆P3 = PUR – PDR = pressure drop across restriction
4. ∆P4 = PUSV – PDSV = pressure drop across safety valve
5. ∆P5 = Pwh – PDSC = pressure drop across surface choke
6. ∆P6 = PDSC – Psep = pressure drop in flowline
7. ∆P7 = Pwf – Pwh = total pressure drop in tubing
8. ∆P8 = Pwf – Psep = total pressure drop in flowline
First introduced by Gilbert3 in 1954 then debated by Nind4 in 1964 and Brown16
in 1978, nodal analysis has been one of the most used instruments for well analysis. It is
based on choosing a point in a producing well system called “nodal point” or “node”
which separates the producing well system into two sections (inflow/outflow). Inflow
section includes upstream components (from the nodal point to the separator). Outflow
section includes downstream components (from the nodal point to the reservoir). Figure
2.2 shows the most common nodal points employed:
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Texas Tech University, Bertrand O. Affanaambomo, August 2008
Figure 2. 2 Most Common Nodal Points Position1
Where
1. Separator
7. PWFS = pressure through perforations
2. Surface Choke
8. PR = reservoir pressure
3. Wellhead
1A. Gas Sales
4. Safety Valve
1B. Stock Tank
5. Restriction
6. PWF = flowing bottomhole Pressure
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Texas Tech University, Bertrand O. Affanaambomo, August 2008
The average reservoir pressure and the separator well are two pressures that stay
unchanged, since they are independent of the flowrate, at a specific time of the well life.
In order to calculate the flowrate in the system, after the nodal point has been chosen, the
subsequent conditions have to be met:
o The node inflow must be equivalent to the node outflow.
o There must be just one pressure at a particular node.
Inflow to the nodal point:
P R– ΔP (upstream components) = pnode
(2.1)
Outflow from the nodal point:
Psep + ΔP (downstream components) = pnode
(2.2)
Where
p R = average reservoir pressure, psia
Psep = separator pressure, psia
ΔP = pressure drop of any component in the system, psia
Pnode = pressure of the chosen nodal point, psia
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Texas Tech University, Bertrand O. Affanaambomo, August 2008
2.2 INFLOW PERFORMANCE RELATIONSHIP (IPR)
An inflow performance relationship (IPR) is a graphical method used in
production engineering to estimate the relationship between the flowrate and the
bottomhole flowing pressure. IPR is a most common way in production engineering to
estimate reservoir deliverability.
It is generally used to estimate various operating
conditions such as determining the optimum production scheme and designing production
equipment of a particular well. It is a Cartesian plot (IPR plot) of various bottomhole
flowing pressure test data versus the flowrate test data of a particular well.
The IPR graph (inflow performance relationship) curve or an IPR curve is shown
in Figure 2.3. The magnitude of the slope of the IPR is called the “productivity index” (PI
or J),
J = q (Pe − Pwf
)
(2.3)
Where
J = productivity index, STB/D/psi
q = flowrate, STB/D
pe = pressure at the external boundary of the drainage area, psia
pwf = bottomhole pressure, psia
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Texas Tech University, Bertrand O. Affanaambomo, August 2008
Figure 2.3 Inflow Performance Relationship Curve5
Reservoir inflow models used to construct the well IPR curves have either a
theoretical basis or an empirical basis. These models are generally verified during test
points in the field application.
The most common and broadly used IPR equation is a Productivity Index or
straight-line IPR. The assumption used is that the flowrate is proportional to the pressure
drawdown in the reservoir. Figure 2.4 shows a plot of the straight-line IPR.
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Texas Tech University, Bertrand O. Affanaambomo, August 2008
Figure 2.4 Straight-line IPR
6
IPR is used to describe reservoir deliverability. However, it is not enough for a
production engineer to comprehend wellbore flow performance to recommend oil well
equipment and optimize well production situation.
2.2.1 Vogel’s Method
In 1968 Vogel, with the help of a computer model, constructed IPRs for a number
of suppositional saturated oil reservoirs which were under a wide range of conditions.
This method not only helps to regularize IPR but also generates IPR without any physical
units. The following equation is used to generate IPRs curves for different reservoir
pressure conditions:
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Texas Tech University, Bertrand O. Affanaambomo, August 2008
P
Qo
= 1 − 0.2 wf
(Qo ) max
 Pr

P
 − 0.8 wf

 Pr



2
(2.4)
Where
Qo= oil rate at Pwf, bbl/day
(Qo )max
= maximum oil flow rate when wellbore pressure is zero, bbl/day
Pwf = bottomhole pressure, psig
Pr = reservoir pressure, psig
Other methods used to generate IPR are Wiggins’ method, Standing’s method,
Fetkovich’s method, and Klins-Clark method.
2.2.2 Wiggins’ Method
In 1993 Wiggin derived equations to calculate inflow performance using four sets
of relative permeability and fluid property input data for a computer model. The
assumption used for this method is that the initial reservoir pressure is at its bubble
pressure. The followings are the two equations derived:
P
Qo
= 1 − 0.52 wf
(Qo ) max
 Pr

P
 − 0.48 wf

 Pr



2
(2.5)
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Texas Tech University, Bertrand O. Affanaambomo, August 2008
P
Qo
= 1 − 0.72 wf
(Qo ) max
 Pr

P
 − 0.28 wf

 Pr



2
(2.6)
Where
Qo= oil rate at Pwf, bbl/day
(Qo )max
= maximum oil flow rate when wellbore pressure is zero, bbl/day
Pwf = bottomhole pressure, psig
Pr = reservoir pressure, psig
2.2.3 Standing’s Method
In 1970 Standing rearranged Vogel’s equation to calculate future inflow
performance relationship of a well as a function of reservoir pressure. The rearranged
equation is:
 P
Qo
= 1 − wf
(Qo ) max  Pr

P
 1 − 0.8 wf

 Pr



(2.7)
Where
Qo= oil rate at Pwf, bbl/day
(Qo )max
= maximum oil flow rate when wellbore pressure is zero, bbl/day
Pwf = bottomhole pressure, psig
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Texas Tech University, Bertrand O. Affanaambomo, August 2008
Pr = reservoir pressure, psig
2.2.4 Fetkovich’s Method
In 1942, Muskat and Evinger derived a theoretical productivity index equation
from the pseudosteady-state flow equation for non-linear flow wells.
P
Qo =
r
0.00708kh
f ( p )dp
 re
 P∫wf
ln − 0.75 + S 
 rw

(2.8)
Where
f ( p) =
k ro
µo β o
is the pressure function
(2.9)
kro = oil relative permeability
k = absolute permeability, md
βo = oil formation volume factor
µo = oil viscosity, cp
In 1973 Fetkovich proposed that the pressure function can exist in two regions as shown
in figure 3.1:
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Texas Tech University, Bertrand O. Affanaambomo, August 2008
Figure 2. 5 Pressure Function Regions
23
1. For p>pb, the pressure function exists at the right in figure 2.5 above in the
undersaturated region, thus:
 1 

f ( p ) = 
µ
β
o
o
p

(2.10)
2. For p<pb, the pressure function is at the left in figure 2.5 above in the saturated region,
thus:
 1  P
  
f ( p ) = 
 µo β o  Pb  Pb 
(2.11)
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Texas Tech University, Bertrand O. Affanaambomo, August 2008
µo and βo are estimated at the bubble-point pressure.
Three cases are to be taken into account in a straight-line function pressure application:
•
For
and Pwf > Pb, the production is from an undersaturated reservoir, therefore
equation 2.10 will be substituted into equation 2.8, thus:
P
•
Qo =
r
0.00708kh
 re
 P∫wf
ln
0
.
75
S
−
+


 rw

 1 
dp
f 
µ
β
 o o
(2.12)
 1 
= constant therefore equation 2.12 becomes:

 µo β o 
Qo =
(
0.00708kh
P r − Pwf
 re

µ o β o ln − 0.75 + S 
 rw

)
(2.13)
• For and Pwf < Pb, the pressure function is a straight line, therefore equation 2.11 will
be substituted into equation 2.8, thus:
P
Qo =
r
0.00708kh
 re
 P∫wf
ln
0
.
75
S
−
+


 rw

 1   P 
   dp
f  
 µo β o   Pb  
 Pb   

(2.14)
 1  P

   is constant therefore equation 2.14 becomes:
µ
β
 o o  Pb  Pb 
Qo =
 1  −2
0.00708kh
 Pr − Pwf2


 2P
(µo β o )Pb ln re − 0.75 + S   b 
 rw

(
)
29
(2.15)
Texas Tech University, Bertrand O. Affanaambomo, August 2008
•
For Pwf < Pb and > Pb, at this condition, equation 2.8 becomes:
P
Pr

0.00708kh  b
 ∫ f ( p )dp + ∫ f ( p )dp 
Qo =
 re
  Pwf

Pb
ln − 0.75 + S  
 rw

(2.16)
Combining equation 2.10 and 2.13 with 3.1, we have:
P
Pr

0.00708kh  b  1   P 
1
  dp + ∫
 ∫ 
Qo =
dp 
µβ 
 re
  Pwf  µo β o  Pb  Pb 
Pb o o

ln − 0.75 + S  
r
 w

(2.17)
µo and βo are estimated at the bubble-point pressure Pb, therefore the integration of
equation 2.17 gives:
Qo =
 1  −2

0.00708kh
 Pr − Pwf2 + P r − Pwf 


 2P

(µo β o )Pb ln re − 0.75 + S   b 
r
 w

) (
(
)
(2.18)
2.2.5 The Klins-Clark Method
In 1993, Klins and Clark introduced an equation comparable to Vogel’s equation
with an exponent d:
P
Qo
= 1 − 0.295 wf
(Qo ) max
 Pr

P
 − 0.705 wf

 Pr



d
(2.19)
Where
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Texas Tech University, Bertrand O. Affanaambomo, August 2008

 P r 
d = 0.28 + 0.72 (1.24 + 0.001Pb )

 Pb 
(2.20)
We selected Vogel’s method to construct IPR because it was better than the other
ones for this particular well.
2.3 TUBING PERFORMANCE RELATIONSHIP (TPR)
Tubing performance relationship (TPR) is the relationship between bottomhole
pressure and the flowrate. TPR is used to observe the connection between the total tubing
pressure drop and a surface flowing pressure value as a function of flowrate, GOR
(GLR), tubing ID, density, surface pressure, and average temperature.
A well deliverability is mostly dependent of the pressure drop required to raise a
fluid through the production tubing at a certain flowrate. The tubing pressure drop is the
sum of the surface pressure, the hydrostatic pressure of the fluid, and the frictional
pressure loss due to the flow.
A fluid inside the tubing string of length L and height Δz goes from position 1 to
position 2 (see figure 2.5). Using the first law of thermodynamics, the pressure drop is:
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Texas Tech University, Bertrand O. Affanaambomo, August 2008
Figure 2.6 flow inside Tubing 22
∆P = p1 − p2 =
2 f ρu 2 L
ρ
g
∆u 2 + F
ρ∆z +
gc D
2 gc
gc
(2.21)
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Texas Tech University, Bertrand O. Affanaambomo, August 2008
Where
ΔP = pressure drop, lbf/ft2
P1 = pressure at position 1, lbf/ft2
P2 = pressure at position 2, lbf/ft2
g = gravitational acceleration, 32.17 ft/s2
gc = unit conversion factor, 32.17 lbm-ft/ibf-s2
ρ = fluid density lbm/ft3
Δz = elevation increase, ft
u = fluid velocity, ft/s
fF = Fanning friction factor
L = tubing length, ft
D = tubing inner diameter, ft
As stated in section 2.2, IPR is not enough for a production engineer to
comprehend wellbore flow performance and to recommend oil well equipment and
optimize well production situation. TPR and IPR intersection is used to find the stabilized
flowrate and the corresponding bottomhole pressure which consequently allows a full
understanding of the wellbore flow performance to recommend oil well equipment and
optimize well production situation.
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Texas Tech University, Bertrand O. Affanaambomo, August 2008
2.4 ERROR ESTIMATION IN CALCULATION
Hagedorn & Brown correlation used to construct TPR in this study, was made
using data from a 1500-ft vertical well, tubing sizes ID ranging from 1-2 in, and 5
different fluid types (water and four types of oil and viscosity ranging between 10 and
110 cp at 80oF),
were used to develop the correlation. This correlation is independent
of flow patterns.
•
Tubing Size: The correlation has an accurate prediction on the pressure losses for
tubing sizes ranging from 1-2 in. For tubing sizes over the above range will result on an
over prediction.
•
Oil Gravity: Heavier oils (13-25 oAPI) result to an over calculation the pressure
losses. On the other hand, lighter oils (40-56 oAPI) result to an under calculation of the
pressure losses.
•
Gas-Liquid Ratio (GLR): GLR greater than 5000 result to an over calculation of
the pressure drop.
•
Water-Cut: The correlation has an accurate calculation for a large range of water-
cut25.
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Texas Tech University, Bertrand O. Affanaambomo, August 2008
2.5 WELL PRODUCTION FORECAST
Well production forecasting is a method used in production engineering, based on
the basis of principle of material balance, flow regimes, and drive mechanisms, to find
future production rate and cumulative production of oil and gas using nodal analysis. It is
mostly used in field economics analyses by combining production forecast results with
oil and gas prices. IPR and TPR are used to find future production rates.
The flow periods for a volumetric oil reservoir are:
2.5.1 Transient Flow Period
With the use of Nodal analysis in transient IPR and steady flow TPR, the production
rate during transient flow period can be calculated by the following equation:
q=
kh( pi − pwf )
k
162.6 B0 µ o (log t + log
− 3.23 + 0.87 S )
φµo ct rw2
Where
k = effective horizontal permeability, percentage
h = pay zone thickness, feet
pi is the reservoir pressure in psia
pwf = bottomhole pressure, psia
Bo = oil formation volume factor, bbl/stb
35
(2.22)
Texas Tech University, Bertrand O. Affanaambomo, August 2008
μo = oil viscosity, cp
t = time, day
Ф = reservoir porosity, percentage
ct = total reservoir compressibility, psi-1
rw = wellbore radius, feet
S = skin factor
2.5.2 Pseudo-Steady State Single Phase Flow Period
During pseudo-steady state single phase flow period, the IPR varies with time due
to the reservoir pressure decline and the TPR remains stable due to the stability of the
fluid properties above the bubble-point pressure. The production rate during pseudosteady one phase flow period is calculated using the following equation:
q=
kh( p − p wf )
1
4A
141.2 Bo µ o ( ln
+ S)
2 γC A rw2
(2.23)
Where
k = effective horizontal permeability, percentage
h = pay zone thickness, feet
pwf = bottomhole pressure, psia
Bo = oil formation volume factor, bbl/stb
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Texas Tech University, Bertrand O. Affanaambomo, August 2008
μo = oil viscosity, cp
P R = average reservoir pressure, psia
A = drainage area, feet scare
γ = Euler’s constant = 1.78
CA = drainage area shape factor, 31.6 for a circular boundary
rw = wellbore radius, feet
S = skin factor
S = skin factor
2.5.3 Pseudo-Steady Two-Phase Flow Period
During pseudo-steady two-phase flow period, IPR and TPR both vary with time
due to the unsteadiness of fluid properties such as relative permeability and gas-liquid
ratio (GLR). The production rate during pseudo-steady two-phase flow period is
calculated using the following equation:
p
J*p 
1 − 0.2 wf
q=
1.8 
 p

p = pe −
p

 − 0.8 wf
 p




2
(2.24)



141.2qBo µ o
4kh
(2.25)
Where
P R= average reservoir pressure, psia
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Texas Tech University, Bertrand O. Affanaambomo, August 2008
pwf = bottomhole pressure, psia
J = productivity index, STB/D/psi
Bo = oil formation volume factor, bbl/stb
μo = oil viscosity, cp
k = effective horizontal permeability, percentage
h = pay zone thickness, feet
Pe = reservoir pressure, psia
2.6 EFFECT OF TUBING SIZE
Tubing size generally has an essential function in well production. Wells with
larger tubing sizes have less pressure drops due to friction and lesser gas velocities than
wells with smaller tubing sizes which have high pressure drops due to friction, but have
higher gas velocities. Nodal analyses for oil and gas wells usually reveal that certain large
size tubing (ID), well flowrate decreases. The indispensable notion of tubing design will
be to install an adequate tubing diameter to allow less friction and have a high velocity.
The concepts used to size tubing are nodal analysis and critical velocity.
An extensive search in public literature domain revealed any tapered ID string concepts
for optimizing production.
However, there are reported cases of two sizes (ID) of tubing because of well
construction problems;
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Texas Tech University, Bertrand O. Affanaambomo, August 2008
Trenchard & Whisenant27 (1935) reported probably the earliest case of tapered
tubing string completion. The purpose was putting wells back on production after
shutting them in. Three methods were generally used: pumping, flowing with the aid of
valves, and tapered tubing. The tapered tubing string method was found to be quite
satisfactory. It usually consisted of a string of pipe, half of which is 3/4-inch, and the
other half, i-inch. The use of the tapered tubing afforded a more continuous flow and
probably a smaller amount of injected gas at the start.
Frederick & DeWeese (1967) reported a tapered tubing string used in a well, "Kaplan
Caper," in South Louisiana. In order to flow the well after initial completion, a tapered
macaroni string was installed inside the production tubing (ID). The macaroni string
consisted of (top to bottom):
1-1/2-in, 2.9-lb N-80 tubing to 7,000-ft, and
1-1/4-in, 2.4-lb/ft N-80 tubing from 7,000-ft to 9,000-ft.
The production tubing itself was tapered (top to bottom) as follows:
3-1/2-in, 17.05-lb/ft N-80
0-ft -- 7,100-ft;
2-7/8-in, 8.7-lb/ft N-80
7,000-ft to 9,000-ft;
2-3/8-in, 7.7-lb/ft N-80
9,000-ft -- 15,500-ft
2-3/8-in, 7.7-lb/ft P-105
15,500-FT -- 21,230-ft
Golan and Whitson6 (1986) reported using smaller size (ID) of tubing in the
liner section of well.
Schlumberger28 (2001) reported using a tapered tubing string of 5.5 to 7 in. in a
condensate well with a high GOR. The well was producing 5500 BOPD with a gas/oil
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Texas Tech University, Bertrand O. Affanaambomo, August 2008
ratio of 9600 scf/STB through a monobore completion consisting of a 7-in.liner and a
tapered tubing string of 5.5 to 7 in. Velocities exceeded 8 m/s, and the flowing wellhead
pressure was 1430 psi. Tibbles, R., Ezzat, A., Mahmoud, K.H., Ali, A.H.A., and Hosein,
P. (2004). "Hydraulic fracturing the best producer: A myth?" presented at New Zealand
Petroleum Conference, Auckland from 7-10 March. Slide #9-10. Tibbles et al. (2004)
reported the use of a tapered tubing string as follows:
4-1/2-in 0-ft to 5,000-ft
3-1/2-in 5,000-ft to 5,892-ft
The well produced at 2,147 stbo/d before hydraulic fracturing was considered. Prefracturing nodal analysis indicated a high AOFP. The tapered tubing string indicated a
production rise to 3,145 stbo/d. After fracturing, the measured flow rate was 3,101 stbo/d.
Other instances of tapered tubing are usually for increase outer diameter (OD)
necessitated by mechanical performance.
2.7 ASSUMPTIONS AND CONSIDERATIONS
The present study is conducted with the following assumptions and
considerations.
1. Well is vertical.
2. Reservoir drive is depletion type, i.e. oil and gas are produced by expansion in
volume caused by reservoir pressure depletion.
3. Initial average reservoir pressure is at or below bubble point pressure (Pb) of 4350
psia.
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Texas Tech University, Bertrand O. Affanaambomo, August 2008
4. A single well is considered in a 640 acre spacing.
5. The well is produced till an assumed abandonment pressure (Pa) of 3350 psia.
6. Wellbore skin is considered via the IPR equation, but is put equal to zero in this
study.
7. We consider only naturally flowing oil well. However, the methodology can be
extended to wells on artificial lift methods.
8. The design calculations for various sizes of tubing considered in this study do not
include mechanical performance (e.g. tensile collapse, burst, and torsion failure).
It is implicitly assumed that the selected tubing sizes satisfy the various
mechanical performance requirements.
9. Average reservoir pressure declines from 4350psia to 3350 psia in 100 psia steps.
10. Reservoir is solution gas drive at the bubble point with no initial gas cap and
rapidly goes below the bubble point pressure after production starts.
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Texas Tech University, Bertrand O. Affanaambomo, August 2008
CHAPTER III
METHODOLOGY
3.1 ALGORITHM (Step-by-Step Procedure)
The objective of this thesis, as stated in section 1.4, is to determine stabilized
flowrates for the single, dual, triple and quad strings, run economic analysis (using NPV)
for combination strings, and compare results of a single string vs. dual, triple, and quad
strings.
3.1.1 Different Scenarios
The innovation about TTWC is its design. It is a combination of tapered tubing
strings with the smallest size tubing at the bottom and the largest size at the top. Most
production tubings in the oil industry are made considering outside diameter (OD) for
strength. TTWC in the other hand is mainly about inside diameter (ID). The different
scenarios below will be used while conducting experiments.
Scenario 1:
Single tubing
1.995, 2.441, 2.992, and 3.340 in. tubing sizes were used.
Scenario 2:
Dual tubing
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Texas Tech University, Bertrand O. Affanaambomo, August 2008
Two different sub-scenarios with different tubing inside diameter sizes, 1.995, 2.441, and
3.340 in., were conducted and their design will be as shown in figure 1.4:
1.
d1 = 2.441 in. and d2 = 1.995 in.
2.
d1= 3.340 in. and d2= 2.441 in.
Scenario 3:
Trio tubing
One sub-scenario with different tubing sizes, 2.992, 2.441, and 3.340 in., was conducted
and its design will be as shown in figure 1.5:
1.
d1= 3.340 in., d2= 2.992 in., and d3 = 2.441 in.
Scenario 4:
Quad tubing
One sub-scenario with different tubing sizes, 1.995, 2.441, 2.992, and 3.340 in., was
conducted and its design will be as shown in figure 1.6:
1.
d1= 3.340 in., d2= 2.441 in., d3= 2.992 in., and d4= 1.995 in.
3.1.2 Stabilized Flowrate
As mentioned in section 2.3, TPR and IPR intersection is used to find the
stabilized flowrate and the corresponding bottomhole pressure. Stabilized flowrate is
achieved when there is a continuous flow between the reservoir and the tubing string.
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Texas Tech University, Bertrand O. Affanaambomo, August 2008
The empirical method used in this study to generate IPR is the Vogel’s method7,
and the empirical method used to generate TPR is Hagedorn & Brown correlation25. Both
methods are incorporated in the following software used:
1.
VirtuWellTM by Fekete30 and
2.
Well performance forecast program (in MS ExcelTM) developed by Guo et al22.
3.1.3 Concept of Equivalent Tubing Diameter
Based on stabilized flowrates obtained for different scenarios, a graph of different
single tubing diameter sizes vs. their correspondent flowrates will be plotted. A
streamline equation will then be derived from the plot. This equation obtained will serve
as the equivalent tubing diameter equation in which we will substitute each TTWC
stabilized flowrates to find their corresponding single tubing diameter.
The objective of this study is to investigate what equivalent single tubing diameter
corresponds to each one of TTWC tubing diameter, i.e. dual, trio, and quad tubing. Thus
each TTWC will be compared with its equivalent single tubing diameter obtained.
3.1.4 Economic Analysis
In order to carry out the economic analysis, well production forecast must first be
calculated. Economic analysis, as stated in section 2.4, will then be conducted based on
the results obtained from well production forecast and gas and oil prices.
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Texas Tech University, Bertrand O. Affanaambomo, August 2008
3.1.4.1 Well Production Forecast Procedure
Well production forecast calculation for a solution-gas drive reservoir requires the
use of material balance models to create the cumulative production and time relationship.
The most frequently used material balance model is found in Craft & Terry Hawkins
(1991)12 which was from Tarner’s earlier work in 1944.
The following steps are used in order to calculate the production forecast during the twophase period:
1.
Assume average-reservoir pressure (between the bubble pressure Pb and the
abandonment reservoir pressure pa).
2.
Calculate fluid properties at each average reservoir pressure, and compute
incremental cumulative production ΔNp and cumulative production Np inside each
average reservoir pressure gap.
Compute Фn and Фg using the two pressure values within the interval pressure,
a.
and then find their average in the interval.
Φn =
Bo − R s B g
(3.1)
(Bo − Boi ) + (Rsi − Rs )B g
Where
Фn = coefficient
Bo = oil formation volume factor, bbl/stb
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Texas Tech University, Bertrand O. Affanaambomo, August 2008
Bg = gas formation volume factor, bbl/stb
Rs = solution gas-oil ratio, scf/stb
Rsi = solution gas-oil ratio at initial reservoir pressure, scf/stb
Boi = oil formation volume factor at initial reservoir pressure, bbl/stb
Φg =
Bg
(3.2)
(Bo − Boi ) + (Rsi − Rs )Bg
Where
Фg = coefficient
Bo = oil formation volume factor, bbl/stb
Bg = gas formation volume factor, bbl/stb
Rs = solution gas-oil ratio, scf/stb
Rsi = solution gas-oil ratio at initial reservoir pressure, scf/stb
b.
Estimate incremental oil and gas production per stb of oil in place by presuming
an average gas-oil ratio in interval.
∆N =
1
p
1 − Φn N 1p − Φ g G1p
(3.3)
Φn + R Φ g
(3.4)
∆G p = ∆N p R
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Texas Tech University, Bertrand O. Affanaambomo, August 2008
Where
Φ g = average coefficient
Φ n = average coefficient
ΔNp1 = change in cumulative produced oil at the beginning of the interval, stb
Np1 = cumulative produced oil at the beginning of the interval, stb
Gp1 = reservoir gas volume at the beginning of the interval, scf
R = average gas-oil ratio in interval, scf/stb
ΔGp1 = incremental oil and gas production per stb of oil, place
Add ΔNp1 and ΔGp1 to Np1 and Gp1, in that order to estimate cumulative oil
c.
and gas production of each end of the interval.
d.
Determine oil saturation
So =
(
Bo
(1 − S w ) 1 − N 1p
Boi
)
(3.5)
Where
So = oil saturation, fraction
Bo = oil formation volume factor, bbl/stb
Boi = oil formation volume factor at initial reservoir pressure, bbl/stb
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Texas Tech University, Bertrand O. Affanaambomo, August 2008
Sw = water saturation, fraction
Np1 is the cumulative produced oil at the beginning of the interval in stb
e.
Using So, find the relative permeabilities krg and kro from the relative
permeability curves.
f.
Determine the average gas-oil ratio
R = Rs +
k rg µ o Bo
k ro µ g Bg
(3.6)
Where
R = average gas-oil ratio in interval, scf/stb
Rs = solution gas-oil ratio, scf/stb
krg = relative permeability to gas phase, fraction
kro = relative permeability to oil phase, fraction
Bo = oil formation volume factor, bbl/stb
Bg = gas formation volume factor, bbl/stb
μo = oil viscosity, cp
μg = gas viscosity, cp
g.
Contrast in 2f with the assume value in 2b. Repeat 2b through 2f until converges.
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Texas Tech University, Bertrand O. Affanaambomo, August 2008
3.
Calculate production rate q at each average reservoir pressure using Nodal
analyses.
4.
∆t =
Determine production time for each average reservoir pressure interval:
∆N P
q
(3.7)
t = ∑ ∆t
(3.8)
Where
t = cumulative production time, day
Δt = production time for each average reservoir pressure interval, day
ΔNp = change in cumulative produced oil, stb
q = production rate, stb/day
3.2 INPUT DATA (Case Studies)
The most important concern for the choice of the typical production test data is to
be capable to run a simulation and obtain the producing capacity of the well using
different scenarios described in section 3.1. To accomplish this, the following data inputs
were used: GLR and gas gravity are equal to 400 Scf/STB and 0.65, respectively. Pb will
be at 3600 psia. The reservoir pressure is equal 3482 psia; this means the reservoir is
saturated. The well head pressure is equal 400 psig; the water cut is 50%, and 35 oAPI.
The well depth is 10,000 feet. The test data is as follow: qL = 320 STB/day and well head
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Texas Tech University, Bertrand O. Affanaambomo, August 2008
pressure is 3445 psig. Input data used for well production forecast and all economic
analysis assumptions are listed in Appendix B and Appendix C, respectively.
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Texas Tech University, Bertrand O. Affanaambomo, August 2008
CHAPTER IV
RESULTS AND DISCUSSIONS
The first part of the experience involves the nodal analysis of different scenarios
for the single, dual, trio, and quad strings. Their experimental observations and results
can be seen below from Table 4.1 to Table 4.6. The outflow values are then obtained
from the nodal analysis plots from Figure 4.1 to Figure 4.6 for various production
scenarios for the single, dual, trio and quad strings.
4.1 STABILIZED FLOWRATE RESULTS
Scenario 1
Single Tubing
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Texas Tech University, Bertrand O. Affanaambomo, August 2008
Figure 4. 1 Nodal Analysis for 1.995 in. tubing
Table 4. 1 Results Obtained for 1.995 in. tubing
Outflow
Reservoir Pressure
(psia)
Flowrate
(Bbl/d)
Pressure
(Psia)
3482
1870.2
3260.5
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Texas Tech University, Bertrand O. Affanaambomo, August 2008
Figure 4. 2 Nodal Analysis for 2.441 in. tubing
Table 4. 2 Observations and Results for 2.441 in. tubing
Outflow
Reservoir Pressure
(psia)
Flowrate
(Bbl/d)
Pressure
(psia)
3482
2867.5
3136.7
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Texas Tech University, Bertrand O. Affanaambomo, August 2008
Figure 4.3 Nodal Analysis for 2.992 in. tubing
Table 4.3 Results Obtained for 2.992 in. tubing
Outflow
Reservoir Pressure
Flowrate
Pressure
(psia)
(Bbl/d)
(psia)
3482
4131.1
2973.5
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Texas Tech University, Bertrand O. Affanaambomo, August 2008
Figure 4.4 Nodal Analysis for 3.340 in. tubing
Table 4.4 Results Obtained for 3.340 in. tubing
Outflow
Reservoir Pressure
Flowrate
Pressure
(psia)
(Bbl/d)
(psia)
3482
4857.8
2876.1
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Texas Tech University, Bertrand O. Affanaambomo, August 2008
Scenario 2
Dual Tubing
Figure 4. 5 Nodal Analysis for dual tubing (2.441&1.995 in. tubing)
Table 4. 5 Results Obtained for 2.441&1.995 in. tubing
Outflow
Reservoir Pressure.
Flowrate
Pressure
(psia)
(Bbl/d)
(psia)
3482
2348.7
3201.7
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Texas Tech University, Bertrand O. Affanaambomo, August 2008
Figure 4. 6 Nodal Analysis for dual tubing (3.340&2.441 in. tubing)
Table 4. 6 Results Obtained for 3.340&2.441 in. tubing
Outflow
Reservoir Pressure
Flowrate
Pressure
(psia)
(Bbl/d)
(psia)
3482
3844.6
3011.2
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Texas Tech University, Bertrand O. Affanaambomo, August 2008
Scenario 3
Trio Tubing
Figure 4. 7 Nodal Analysis for trio tubing (3.340, 2.992, & 2.441 in. tubing)
Table 4. 7 Results Obtained for 3.340, 2.992, & 2.441 in. tubing
Outflow
Reservoir Pressure
Flowrate
Pressure
(psia)
(Bbl/d)
(psia)
3482
3978.2
2993.7
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Texas Tech University, Bertrand O. Affanaambomo, August 2008
Scenario 4
Quad Tubing
Figure 4. 8 Nodal Analysis for Quad tubing
Table 4. 8 Results Obtained for quad tubing
Outflow
Reservoir Pressure
Flowrate
Pressure
(psia)
(Bbl/d)
(psia)
3482
3255.6
3087.4
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Texas Tech University, Bertrand O. Affanaambomo, August 2008
4.2 EQUIVALENT TUBING DIAMETER
In order to compare results of a single string vs. dual, triple, and quad strings, an
“Equivalent Tubing Diameter” (ETD), deq, was defined for different TTWC. ETD is
derived from the streamline equation obtained from the plot of the different single tubing
diameter sizes vs. their correspondent flowrates, see figure 4.7.
Single Tubing
6000
q = 5813.ln(deq) - 2214.
R² = 0.996
Flowrate, Bbl/d
5000
4000
3000
2000
1000
0
1
1.5
2
2.5
3
3.5
Tubing dia (di), inches
Figure 4.9 Single Tubing Plot
Therefore after derivation, ETD equation obtained is:
q = 5813 ln(d eq ) − 2214
(4.1)
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Texas Tech University, Bertrand O. Affanaambomo, August 2008
q + 2214
= ln (d eq )
5813
(4.2)
 (q + 2214)
d eq = EXP 

 5813 
(4.3)
Where
deq is the equivalent tubing diameter in inches
q is the stabilized flowrate in bbl/d
Calculations of different ETDs were done based on each scenario stabilized
flowrate and results can be seen from tables 4.7 to table 4.9:
Scenario 2
Table 4. 9 ETD for dual tubing
Dual tubing
deq, in.
2.441” & 1.995” tubing diameters
2.19
3.340” & 2.441” tubing diameters
2.84
For the first sub-scenario (2.441” & 1.995” tubing ID), the nearest tubing size
available is 2.441 in. on the upside, and 1.995 in. on the downside.
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Texas Tech University, Bertrand O. Affanaambomo, August 2008
From what it is seen in table 4.3, the Dual (2.441” & 1.995” tubing ID) completion
will be compared with 1.995 in. tubing Completion, for the following reasons:
1.
The Dual completion gives q = 2348.7 STB/d, which is approx. 25% more than
flowrate from 1.995-in single tubing completion.
2.
But the Dual completion involves 50% length of higher tubing. Diameter, i.e.,
2.441 in., which will increase capital expenditure (CAPEX) by certain amount.
For the second sub-scenario (3.340” & 2.441” tubing ID), the nearest tubing size
available is 2.992 in. on the upside, and 2.441 in. on the downside.
From the table 4.4, the Dual (3.340” & 2.441” tubing ID) completion will be
compared with 2.441 in. tubing Completion, for the following reasons:
1.
The Dual completion gives q = 3844.6 STB/d, which is approx. 34% more than
flowrate from 2.441 in. single tubing completion.
2.
But the Dual completion involves 50% length of higher tubing. Diameter, i.e.,
3.340 in., which will increase capital expenditure (CAPEX) by certain amount.
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Texas Tech University, Bertrand O. Affanaambomo, August 2008
Scenario 3
Table 4. 10 ETD for trio tubing
Trio tubing
deq, in.
3.340”, 2.992”, and 2.441” tubing diameters
2.90
The nearest tubing size available is 2.992 in. on the upside, and 2.441 in. on the
downside.
From figure 4.5, to make economic comparisons, it makes sense to compare the
trio completion with 2.441 in. tubing Completion, for the following reasons:
1.
The trio completion gives q = 3978.2 STB/d, which is approx. 39% more than
flowrate from 1.995-in single tubing completion.
2.
But the trio completion involves more than one 50% length of higher tubing.
Diameter, i.e., 3.340 in., which will increase capital expenditure (CAPEX) by certain
amount.
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Texas Tech University, Bertrand O. Affanaambomo, August 2008
Scenario 4
Quad Tubing
Table 4. 11 ETD for quad tubing
Quad tubing
3.340”, 2.992”, 2.441”, &1.995” tubing diameters
deq, in.
2.56
The nearest tubing size available is 2.992 in. on the upside, and 2.441in. on the
downside.
From table 4.6, to make economic comparisons, the quad completion will be compared
with 2.441 in. tubing Completion, for the following reasons:
1.
The quad completion gives q = 3255.6 STB/d, which is approx. 13.5% more than
flowrate from 2.441in single tubing completion.
2.
But the quad completion involves more than one 50% length of higher tubing.
Diameter, i.e., 3.340 in., which will increase capital expenditure (CAPEX) by certain
amount.
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Texas Tech University, Bertrand O. Affanaambomo, August 2008
4.3 WELL PRODUCTION FORECAST RESULTS
In the following, the forecast of the well performance is computed with a twophase hydrocarbon reservoir. This is done with the help of Nodal analysis, the principle
of material balance, and Tarner’s method. The procedure used in doing so is as stated in
section 3.1.4.1. The object is to illustrate both recovery and time of the well.
Figures 4.8, 4.10, 4.12, 4.14, 4.16, and 4.18 are graphical representation of table C4, C6,
C12, C14, C16, and C18 of APENDIX C.
IPR results seen in figures 4.9, 4.11, 4.13, 4.15, 4.17, and 4.19 were calculated using
Vogel’s correlation for two- phase reservoir.
Scenario 1
Single Tubing
65
1,200
3,000,000
1,000
2,500,000
800
2,000,000
600
1,500,000
400
Production Rate
1,000,000
200
Cumulative
Production
500,000
0
0
0
20
40
60
80
100
Time, month
Figure 4.10 Production Forecast for 1.995” Tubing
66
120
Cumulative Production, STB
Production Rate, STB/d
Texas Tech University, Bertrand O. Affanaambomo, August 2008
Texas Tech University, Bertrand O. Affanaambomo, August 2008
4500
IPR for Pr = 4250 psia
4000
IPR for Pr = 4150 psia
IPR for Pr = 4050 psia
3500
IPR for Pr = 3950 psia
IPR for Pr = 3850 psia
3000
Pwf, psia
IPR for Pr = 3750 psia
2500
IPR for Pr = 3650 psia
IPR for Pr = 3550 psia
2000
IPR for Pr = 3450 psia
IPR for Pr = 3350 psia
1500
TPR for pr = 4250 psia
1000
TPR for pr = 4150 psia
TPR for pr = 4050 psia
500
TPR for pr = 3950 psia
TPR for pr = 3850 psia
0
0
500
1000
Production Rate, STB/d
1500
TPR for pr = 3750 psia
TPR for pr = 3650 psia
Figure 4.11 Nodal Analysis Plot for 1.995” Tubing
67
1,200
3,000,000
1,000
2,500,000
800
2,000,000
600
1,500,000
400
1,000,000
Production Rate
Cumulative Production
200
500,000
0
0
0
20
40
60
80
100
Time, month
Figure 4.12 Production Forecast for 2.441” Tubing
68
120
Cumulative Production, STB
Production Rate, STB/d
Texas Tech University, Bertrand O. Affanaambomo, August 2008
Texas Tech University, Bertrand O. Affanaambomo, August 2008
4500
IPR for Pr = 4250 psia
4000
IPR for Pr = 4150 psia
IPR for Pr = 4050 psia
3500
IPR for Pr = 3950 psia
IPR for Pr = 3850 psia
3000
Pwf, psia
IPR for Pr = 3750 psia
2500
IPR for Pr = 3650 psia
IPR for Pr = 3550 psia
2000
IPR for Pr = 3450 psia
IPR for Pr = 3350 psia
1500
TPR for pr = 4250 psia
1000
TPR for pr = 4150 psia
TPR for pr = 4050 psia
500
TPR for pr = 3950 psia
TPR for pr = 3850 psia
0
0
500
1000
Production Rate, STB/d
1500
TPR for pr = 3750 psia
TPR for pr = 3650 psia
Figure 4.13 Nodal Analysis Plot for 2.441" Tubing
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Texas Tech University, Bertrand O. Affanaambomo, August 2008
Scenario 2
1200
3000000
1000
2500000
800
2000000
600
1500000
400
1000000
Production Rate
200
500000
Cumulative Production
0
0
0
20
40
60
80
100
120
Time, month
Figure 4.14 Production Forecast for Dual Tubing (2.441" & 1.995")
70
Cumulative Production, STB
Production Rate, STB/d
Dual Tubing
Texas Tech University, Bertrand O. Affanaambomo, August 2008
4500
IPR for pr = 4250 psia
4000
IPR for pr = 4150 psia
IPR for pr = 4050 psia
3500
IPR for pr = 3950 psia
IPR for pr = 3850 psia
Pwf, psia
3000
IPR for pr = 3750 psia
2500
IPR for pr = 3650 psia
IPR for pr = 3550 psia
2000
IPR for pr = 3450 psia
1500
IPR for pr = 3350 psia
TPR for pr = 4250 psia
1000
TPR for pr = 4150 psia
TPR for pr = 4050 psia
500
TPR for pr = 3950 psia
0
TPR for pr = 3850 psia
0
500
1000
Production Rate, STB/d
1500
TPR for pr = 3750 psia
TPR for pr = 3650 psia
Figure 4.15 Nodal Analysis Plot for Dual Tubing (2.441" & 1.995")
71
1200
3000000
1000
2500000
800
2000000
600
1500000
400
Production Rate
1000000
200
Cumulative Production
500000
0
0
0
20
40
60
80
100
120
Time, month
Figure 4.16 Production Forecast for Dual Tubing (3.340" & 2.441")
72
Cumulative Production, STB
Production Rate, STB/d
Texas Tech University, Bertrand O. Affanaambomo, August 2008
Texas Tech University, Bertrand O. Affanaambomo, August 2008
IPR for pr = 4250 psia
4500
IPR for pr = 4150 psia
4000
IPR for pr = 4050 psia
IPR for pr = 3950 psia
3500
IPR for pr = 3850 psia
Pwf, psia
3000
IPR for pr = 3750 psia
IPR for pr =3650 psia
2500
IPR for pr = 3550 psia
IPR for pr = 3450 psia
2000
IPR for pr = 3350 psia
1500
TPR for pr = 4250 psia
TPR for pr = 4150 psia
1000
TPR for pr = 4050 psia
TPR for pr = 3950 psia
500
TPR for pr = 3850 psia
0
0
200
400
600
800
1000
1200
Production Rate, STB/d
TPR for pr = 3750 psia
1400
TPR for pr = 3650 psia
Figure 4.17 Nodal Analysis Plot for Dual Tubing (3.340" & 2.441")
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Scenario 3
1400
3000000
1200
2500000
1000
2000000
800
1500000
600
1000000
400
Production Rate
200
Cumulative Production
500000
0
0
0
20
40
60
80
Time, month
Figure 4.18 Production Forecast for Trio Tubing
74
100
Cumulative Production, STB
Production Rate, STB/d
Trio Tubing
Texas Tech University, Bertrand O. Affanaambomo, August 2008
4500
IPR for pr = 4250 psia
4000
IPR for pr = 4150 psia
IPR for pr = 4050 psia
3500
IPR for pr = 3950 psia
Pwf, psia
3000
IPR for pr = 3850 psia
IPR for pr = 3750 psia
2500
IPR for pr = 3650 psia
IPR for pr = 3550 psia
2000
IPR for pr = 3450 psia
1500
IPR for pr = 3350 psia
TPR for pr = 4250 psia
1000
TPR for pr = 4150 psia
500
TPR for pr = 4050 psia
TPR for pr = 3950 psia
0
0
200
400
600
800
1000
1200
Production Rate, STB/d
TPR for pr = 3850 psia
1400
TPR for pr = 3750 psia
TPR for pr = 3650 psia
Figure 4.19 Nodal Analysis Plot for Trio Tubing
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Scenario 4
1400
3000000
1200
2500000
1000
2000000
800
1500000
600
400
200
Production Rate
1000000
Cumulative Production
500000
0
0
0
20
40
60
80
100
120
Time, month
Figure 4.20 Production Forecast for Quad Tubing
76
Cumulative Production, STB
Production Rate, STB/d
Quad Tubing
Texas Tech University, Bertrand O. Affanaambomo, August 2008
4500
IPR for pr = 4250 psia
4000
IPR for pr = 4150 psia
IPR for pr = 4050 psia
3500
IPR for pr = 3950 psia
IPR for pr = 3850 psia
Pwf, psia
3000
IPR for pr = 3750 psia
2500
IPR for pr = 3650 psia
IPR for pr = 3550 psia
2000
IPR for pr = 3450 psia
1500
IPR for pr = 3350 psia
TPR for pr = 4250 psia
1000
TPR for pr = 4150 psia
TPR for pr = 4050 psia
500
TPR for pr = 3950 psia
0
TPR for pr = 3850 psia
0
500
1000
1500
Production Rate, STB/d
Figure 4.21 Analysis Plot for Quad Tubing
77
TPR for pr = 3750 psia
TPR for pr = 3650 psia
Texas Tech University, Bertrand O. Affanaambomo, August 2008
4.4 ECONOMIC ANALYSIS RESULTS
The main motivation of this study is not only to optimize production and lower
the recovery time, but it is also to expect a better economic performance of TTWC
compare to the conventional tubing completion. Thus the economic analysis of different
scenarios was conducted using payout time, net present value (NPV), and return on
investment.
NPV of cash flows over n (days, months, or years) is the subtraction of the present value
and the initial investment, I17:
n
NPV = ∑
t =1
Ct
−I
r t
(1 +
)
100
(7.1)
Where
t = time of the cash flow, days
n = total time of the project, days
r = discount rate, %
Ct = net cash flow at time t, $
I = initial investment, $
For NPV > 0, the project may be accepted
For NPV < = 0, the project should be rejected
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Texas Tech University, Bertrand O. Affanaambomo, August 2008
The return on investment (ROI) is the percentage of money gained or lost on an
investment to the money invested:
For ROI = + 100%, the final value is twice the initial value
For ROI > 0, the investment is profitable
For ROI < 0, the investment is at a loss
For ROI = − 100%, investment can no longer be recovered
NPV will be conducted at 10% interest rate. Prices of oil and gas used are
126.2$/bbl and 11.537$/Mmbtu as of May, 2008, respectively26. Tubing outside
diameters 2.378 in., 2.875 in., 3.5 in., and 4.0 in. will be 4.02, 5.44, 7.76, and 9.48 $/ft as
of May, 2008 respectively. Because the well is presumed to be in natural flow, operation
expenditure (OPEX), development cost, and abandonment cost will not be considered.
In the economic analysis, we only consider one cost element, tubing cost, and
consider all other cost components equal.
In reality, however, TTWC will entail additional costs, such as, cost due to
increased rig time in handling multiple tubing sizes, additional workover time in pulling
out/ running in (if workover is required before reaching the assumed abandonment
pressure, Pa), etc.
The following are the results obtained for various completion types:
79
Texas Tech University, Bertrand O. Affanaambomo, August 2008
Scenario 1
Single tubing
Table 4.12 Economic Analysis for 1.995" Tubing
Time,
day
Oil
Produced,
bbl/day
Gas
Produced,
MMbtu/day
Gross
REVENUE,
$/day
Cost, $
Cashflow, $
0
0
0
0
262910
-262910
169
1,017
878.86
138484.82
262910
-124425.18
319
891
792.00
121581.52
262910
-2843.67
718
863
901.33
119309.30
262910
116465.63
1088
835
1002.82
116946.51
262910
233412.14
1463
807
1136.26
114952.48
262910
348364.62
1855
781
1355.46
114200.19
262910
462564.82
2223
754
1613.82
113773.40
262910
576338.22
2554
726
1827.57
112705.92
262910
689044.14
2872
698
2049.70
111734.97
262910
800779.11
3177
669
2273.93
110662.14
262910
911441.25
NPV, $
ROI
Payout Time, days
1,654,170
14.26
329
80
Texas Tech University, Bertrand O. Affanaambomo, August 2008
Table 4.13 Economic Analysis for 2.441" Tubing
Time,
day
Oil
Produced,
bbl/day
Gas
Produced,
MMbtu/day
Gross
REVENUE,
$/day
Cost, $
Cashflow, $
0
0
0
0
274270
-274270
160
1,075
928.98
146382.67
274270
-127887.33
303
938
833.78
127994.91
274270
107.58
681
909
949.38
125668.77
274270
125776.35
1033
879
1055.66
123108.97
274270
248885.32
1389
849
1195.40
120935.14
274270
369820.45
1761
822
1426.62
120195.34
274270
490015.79
2111
794
1699.43
119809.12
274270
609824.92
2425
765
1925.75
118760.38
274270
728585.29
2727
735
2158.35
117657.88
274270
846243.17
3016
706
2399.69
116782.47
274270
963025.64
NPV, $
ROI
Payout Time, days
1,763,282
14.51
303
81
Texas Tech University, Bertrand O. Affanaambomo, August 2008
Scenario 2
Dual Tubing
Table 4.14 Economic Analysis for dual Tubing (2.441" & 1.995")
Time,
day
Oil
Produced,
bbl/day
Gas
Produced,
MMbtu/day
Gross
REVENUE,
$/day
Cost, $
Cashflow, $
0
0
0
0
268590
-268590
158
1,091
943
148561
268590
-120028.61
298
953
847
130042
268590
10013.13
671
922
963
127466
268590
137479.14
1018
891
1070
124790
268590
262268.77
1370
860
1211
122502
268590
384770.80
1738
831
1442
121511
268590
506282.14
2084
802
1717
121016
268590
627298.41
2396
771
1941
119692
268590
746990.24
2695
741
2176
118618
268590
865608.59
2982
711
2417
117610
268590
983218.13
NPV, $
ROI
Payout Time, days
1,854,242
15.40
287
82
Texas Tech University, Bertrand O. Affanaambomo, August 2008
Table 4.15 Economic Analysis for dual Tubing (3.340" & 2.441")
Time,
day
Oil
Produced,
bbl/day
Gas
Produced,
MMbtu/day
Gross
REVENUE,
$/day
Cost, $
Cashflow, $
0
0
0
0
290430
-290430
151
1,136
982
154689
290430
-135740.96
287
989
879
134954
290430
-786.84
646
956
998
132166
290430
131379.65
981
923
1109
129271
290430
260651.07
1321
891
1255
126918
290430
387568.86
1676
861
1494
125898
290430
513466.90
2011
830
1776
125241
290430
638708.18
2312
799
2011
124039
290430
762746.79
2601
768
2255
122940
290430
885687.27
2878
735
2498
121579
290430
1007266.75
NPV, $
ROI
Payout Time, days
1,840,291
14.33
287
83
Texas Tech University, Bertrand O. Affanaambomo, August 2008
Scenario 3
Trio Tubing
Table 4.16 Economic Analysis for Trio Tubing
Time,
day
Oil
Produced,
bbl/day
Gas
Produced,
MMbtu/day
Gross
REVENUE,
$/day
Cost, $
Cashflow, $
0
0
0
0
291229.9264
-291229.93
149
1,154
997
157140
291229.9264
-134089.83
282
1,005
893
137137
291229.9264
3047.57
636
971
1014
134240
291229.9264
137287.81
966
937
1125
131232
291229.9264
268520.01
1301
904
1273
128770
291229.9264
397289.57
1651
873
1515
127653
291229.9264
524942.29
1982
841
1800
126901
291229.9264
651843.39
2279
809
2037
125591
291229.9264
777434.43
2565
776
2279
124221
291229.9264
901655.53
2838
746
2536
123399
291229.9264
1025054.57
NPV, $
ROI
Payout Time, days
1893710.33
14.63
279
84
Texas Tech University, Bertrand O. Affanaambomo, August 2008
Scenario 4
Quad Tubing
Table 4.17 Economic Analysis for Quad Tubing
Time,
day
Oil
Produced,
bbl/day
Gas
Produced,
MMbtu/day
Gross
REVENUE,
$/day
Cost, $
Cashflow, $
0
0
0
0
284150
-284150.00
150
1,143
988
155642
284150
-128507.7708
285
995
884
135773
284150
7265.08
642
962
1005
132996
284150
140261.07
975
929
1116
130112
284150
270372.82
1313
896
1262
127630
284150
398002.84
1667
865
1501
126483
284150
524485.77
2000
833
1783
125694
284150
650179.72
2300
801
2016
124349
284150
774528.82
2588
770
2261
123261
284150
897789.45
2864
739
2512
122241
284150
1020030.594
NPV, $
ROI
Payout Time, days
1,907,249
15.03
278
85
Texas Tech University, Bertrand O. Affanaambomo, August 2008
Table 4.18 below is the economic analysis summary. We observe that the quad
completion has a better economic performance.
Table 4. 18 Summary of Economic Analysis
Completion Types
Conventional Completion
1
Conventional Completion
2
Payout Time (d)
329
NPV ($)
1,654,170
ROI (%)
14.26
303
1,763,282
14.51
Dual Completion 1
287
1,854,242
15.40
Dual Completion 2
287
1,840,291
14.33
Trio Completion
279
1,893,710
14.63
Quad Completion
278
1,907,249
15.03
86
Texas Tech University, Bertrand O. Affanaambomo, August 2008
CHAPTER V
COMPARISON OF RESULTS
5.1 COST COMPARISONS
Figures 5.1, 5.2, and 5.3, and 5.4 show the cost comparisons of dual tubing
(3.340” & 2.441”) vs. single tubing, trio tubing vs. single tubing, and quad tubing vs.
single tubing, respectively.
As mentioned in section 4.3, calculations were done with the well that is
presumed to be in natural flow. Therefore, OPEX, development cost, and abandonment
cost will not be considered. As a result, tubing costs will only be considered.
With the assumptions made below, we observe the following cost comparisons:
87
Texas Tech University, Bertrand O. Affanaambomo, August 2008
300,000
Costs, dollars
290,000
280,000
270,000
268,590
262,910
260,000
250,000
240,000
Duplex Tubing (2.441" & 1.995")
Single Tubing (1.995")
Figure 5.1 Dual Tubing (2.441" & 1.995") vs. Single Tubing
88
Texas Tech University, Bertrand O. Affanaambomo, August 2008
300,000
295,000
290,430
Costs, dollars
290,000
285,000
280,000
274,270
275,000
270,000
265,000
260,000
Duplex Tubing (3.340" & 2.441")
Single Tubing (2.441")
Figure 5. 2 Dual Tubing (3.340” & 2.441”) vs. Single Tubing
89
Texas Tech University, Bertrand O. Affanaambomo, August 2008
300,000
295,000
291,230
Costs, dollars
290,000
285,000
280,000
274,270
275,000
270,000
265,000
260,000
Triplex Tubing
Single Tubing (2.441")
Figure 5. 3 Trio Tubing vs. Single Tubing
90
Texas Tech University, Bertrand O. Affanaambomo, August 2008
300,000
295,000
Costs, dollars
290,000
285,000
284,150
280,000
274,270
275,000
270,000
265,000
260,000
Quad Tubing
Single Tubing (2.441")
Figure 5. 4 Quad Tubing vs. Single Tubing
91
Texas Tech University, Bertrand O. Affanaambomo, August 2008
5.2 STABILIZED FLOWRATES COMPARISONS
Figures 5.5, 5.6, 5.7, and 5.8 show stabilized flowrates comparison of dual tubing
(2.441” & 1.995”) vs. single tubing (1.995”), dual tubing (3.340” & 2.441”) vs. single
tubing (2.441”), trio tubing vs. single tubing (2.441”), and quad tubing vs. single tubing
(2.441”), respectively. As expected, we have a better production rate when using TTWC.
This is because TTWC allows the flow stream expansion, in volume per unit mass
flowrate, as it moves up.
Production Rate, Bbl/d
4500
4000
3500
3000
2500
2,348.7
1,870.2
2000
1500
1000
500
0
Duplex Tubing (2.441"&1.995")
Sigle Tubing (1.995")
Figure 5. 5 Dual Tubing (2.441" & 1.995") vs. Single Tubing
92
Texas Tech University, Bertrand O. Affanaambomo, August 2008
Production Rate, Bbl/d
4500
4000
3,844.6
3500
2,867.5
3000
2500
2000
1500
1000
500
0
Dual Tubing (3.340" & 2.441")
Single Tubing (2.441")
Figure 5. 6 Dual Tubing (3.340" & 2.441") vs. Single Tubing
93
Texas Tech University, Bertrand O. Affanaambomo, August 2008
4500
Production Rate, Bbl/d
4000
3,978.2
3500
2,867.5
3000
2500
2000
1500
1000
500
0
Trio Tubing
Single Tubing (2.441")
Figure 5. 7 Trio Tubing vs. Single Tubing
94
Texas Tech University, Bertrand O. Affanaambomo, August 2008
4500
Production Rate, Bbl/d
4000
3500
3,255.6
2,867.5
3000
2500
2000
1500
1000
500
0
Quad Tubing
Single Tubing (2.441")
Figure 5. 8 Quad Tubing vs. Single Tubing
95
Texas Tech University, Bertrand O. Affanaambomo, August 2008
5.3 RECOVERY TIME COMPARISONS
By calculating well production forecast, we were able to obtain the recovery time
in days of different scenarios. Figures 5.9, 5.10, 5.11, and 5.12 show the recovery time
comparisons of dual tubing (3.340” & 2.441”) vs. single tubing, trio tubing vs. single
tubing, and quad tubing vs. single tubing, respectively. As we can see, the recovery time
using TTWC is faster than conventional completion.
3,500
Recovery Time, days
3,400
3,300
3,177
3,200
3,100
3,000
2,982
2,900
2,800
2,700
2,600
2,500
Duplex Tubing (2.441" & 1.995")
Single Tubing (1.995")
Figure 5.9 Tubing (2.441" & 1.995") vs. Single Tubing (1.995")
96
Texas Tech University, Bertrand O. Affanaambomo, August 2008
3500
Recovery Time, days
3400
3300
3200
3100
3,016
3000
2900
2,878
2800
2700
2600
2500
Duplex Tubing (3.340" & 2.441")
Single Tubing (2.441")
Figure 5. 10 Dual Tubing (3.340" & 2.441") vs. Single Tubing (2.441”)
97
Texas Tech University, Bertrand O. Affanaambomo, August 2008
3500
Recovery Time, days
3400
3300
3200
3100
3,016
3000
2900
2,838
2800
2700
2600
2500
Triplex Tubing
Single Tubing (2.441")
Figure 5. 11 Trio Tubing vs. Single Tubing
98
Texas Tech University, Bertrand O. Affanaambomo, August 2008
3500
Recovery Time, days
3400
3300
3200
3100
3,016
3000
2900
2,864
2800
2700
2600
2500
Quad Tubing
Single Tubing (2.441")
Figure 5. 12 Quad Tubing vs. Single Tubing
99
Texas Tech University, Bertrand O. Affanaambomo, August 2008
5.4 PAYOUT TIME COMPARISONS
Figures 5.13, 5.14, 5.15, and 5.16 show the payout comparison of dual tubing
(3.340” & 2.441”) vs. single tubing, trio tubing vs. single tubing, and quad tubing vs.
single tubing, respectively. We observe a better payout time using TTWC completion than
single tubing completion.
350
340
329
Payout Time, days
330
320
310
300
290
287
280
270
260
250
Duplex Tubing (2.441" & 1.995")
Single Tubing (1.995")
Figure 5.13 Dual Tubing (2.441" & 1.995") vs. Single Tubing
100
Texas Tech University, Bertrand O. Affanaambomo, August 2008
350
340
Payout Time, days
330
320
310
303
300
290
287
280
270
260
250
Duplex Tubing (3.340" & 2.441")
Single Tubing (2.441")
Figure 5. 14 Dual Tubing (3.340” & 2.441”) vs. Single Tubing
101
Texas Tech University, Bertrand O. Affanaambomo, August 2008
350
340
Payout Time, days
330
320
310
303
300
290
280
279
270
260
250
Triplex Tubing
Single Tubing (2.441")
Figure 5. 15 Trio Tubing vs. Single Tubing
102
Texas Tech University, Bertrand O. Affanaambomo, August 2008
350
340
Payout Time, days
330
320
310
303
300
290
280
278
270
260
250
Quad Tubing
Single Tubing (2.441")
Figure 5. 16 Quad Tubing vs. Single Tubing
103
Texas Tech University, Bertrand O. Affanaambomo, August 2008
5.5 NET PRESENT VALUE COMPARISONS
Figures 5.17, 5.18, 5.19, and 5.20 show NPV comparisons of dual tubing (3.340”
& 2.441”) vs. single tubing, trio tubing vs. single tubing, and quad vs. single tubing,
respectively. NPV was calculated at the interest rate of 10%. TTWC completions show
better NPV than the conventional tubing completion.
1,950,000
Net Present Value, $
1,900,000
1,854,242
1,850,000
1,800,000
1,750,000
1,700,000
1,654,170
1,650,000
1,600,000
1,550,000
Duplex Tubing (2.441" & 1.995")
Single Tubing (1.995")
Figure 5.17 Dual Tubing (2.441" & 1.995") vs. Single Tubing
104
Texas Tech University, Bertrand O. Affanaambomo, August 2008
1,950,000
Net Present Value, $
1,900,000
1,850,000
1,840,291
1,800,000
1,763,283
1,750,000
1,700,000
1,650,000
1,600,000
1,550,000
Duplex Tubing (3.340" & 2.441")
Single Tubing (2.441")
Figure 5. 18 Dual Tubing (3.340" & 2.441") vs. Single Tubing
105
Texas Tech University, Bertrand O. Affanaambomo, August 2008
1,950,000
Net Present Value, $
1,900,000
1,893,710
1,850,000
1,800,000
1,763,282
1,750,000
1,700,000
1,650,000
1,600,000
1,550,000
Triplex Tubing
Single Tubing (2.441")
Figure 5. 19 Trio Tubing vs. Single Tubing
106
Texas Tech University, Bertrand O. Affanaambomo, August 2008
1,950,000
1,907,249
Net Present Value, $
1,900,000
1,850,000
1,800,000
1,763,282
1,750,000
1,700,000
1,650,000
1,600,000
1,550,000
Quad Tubing
Single Tubing (2.441")
Figure 5. 20 Quad Tubing vs. Single Tubing
107
Texas Tech University, Bertrand O. Affanaambomo, August 2008
5.6 RETURN ON INVESTMENT COMPARISONS
Figure 5.21, 5.22, 5.23, and 5.24 show a ROI comparison graphic representative
of dual tubing (3.340” & 2.441”) vs. single tubing, trio tubing vs. single tubing, quad
tubing vs. single tubing. The observation that we can derive these figures is that TTWC has
a better rate of return than the conventional completion.
15.60
Return on Investment, %
15.40
15.40
15.20
15.00
14.80
14.60
14.40
14.26
14.20
14.00
13.80
13.60
Dual Tubing (2.441" & 1.995")
Single Tubing (1.995")
Figure 5.21 Dual Tubing (2.441" & 1.995") vs. Single Tubing
108
Texas Tech University, Bertrand O. Affanaambomo, August 2008
15.60
Return on Investment, %
15.40
15.20
15.00
14.94
14.80
14.60
14.51
14.40
14.20
14.00
13.80
13.60
Duplex Tubing (3.340" & 2.441")
Single Tubing (2.441")
Figure 5. 22 Dual Tubing (3.340" & 2.441") vs. Single Tubing
109
Texas Tech University, Bertrand O. Affanaambomo, August 2008
15.60
15.40
Return on Investment, %
15.20
15.00
14.80
14.63
14.60
14.51
14.40
14.20
14.00
13.80
13.60
Triplex Tubing
Single Tubing (2.441")
Figure 5. 23 Trio Tubing vs. Single Tubing
110
Texas Tech University, Bertrand O. Affanaambomo, August 2008
15.60
Return on Investment, %
15.40
15.20
15.03
15.00
14.80
14.60
14.51
14.40
14.20
14.00
13.80
13.60
Quad Tubing
Single Tubing (2.441")
Figure 5.24 Quad Tubing vs. Single Tubing
111
Texas Tech University, Bertrand O. Affanaambomo, August 2008
CHAPTER VI
SUMMARY OF RESULTS
Figures 6.1 through 6.13 below show the summary results of both the
1200
3000000
1000
2500000
800
2000000
600
1500000
Dual Tubing (2.441" &
1.995")
Single Tubing (1.995")
400
200
1000000
500000
Cum. Prod. For dual Tubing
0
Cumulative Production, STB
Production Rate, STB/day
conventional completion and TTWC:
0
0
20
40
60
80
100
120
Time, months
Figure 6. 1 Production Forecast for dual Tubing (2.441" & 1.995") & Single Tubing (1.995")
112
1200
3000000
1000
2500000
800
2000000
600
1500000
Dual Tubing (3.340" & 2.441")
400
Cumulative Production, STB
Production Rate, STB/day
Texas Tech University, Bertrand O. Affanaambomo, August 2008
1000000
Single Tubing (2.441")
Cum. Prod. For dual Tubing
200
500000
Cum. Prod. For Single Tubing
0
0
0
20
40
60
80
100
120
Time, months
Figure 6. 2 Production Forecast for dual Tubing (3.340" & 2.441") & Single Tubing (2.441")
113
1200
3000000
1000
2500000
800
2000000
600
1500000
Triplex Tubing
Single Tubing (2.441")
400
1000000
Cum. Prod. For Triplex
Tubing
Cum. Prod. For Single
Tubing
200
0
0
20
40
60
80
100
500000
0
120
Time, months
Figure 6. 3 Production Forecast for Trio Tubing & Single Tubing (2.441")
114
Cumulative Production, STB
Production Rate, STB/day
Texas Tech University, Bertrand O. Affanaambomo, August 2008
1200
3000000
1000
2500000
800
2000000
600
1500000
Quad Tubing
400
1000000
Single Tubing (2.441")
Cum. Prod. For Quad Tubing
200
500000
Cum. Prod. For Single Tubing
0
0
0
20
40
60
80
100
120
Time, months
Figure 6. 4 Production Forecast for Quad Tubing & Single Tubing (2.441")
115
Cumulative Production, STB
Production Rate, STB/day
Texas Tech University, Bertrand O. Affanaambomo, August 2008
Texas Tech University, Bertrand O. Affanaambomo, August 2008
295,000
290,000
285,000
Costs, dollars
280,000
275,000
270,000
265,000
260,000
255,000
250,000
245,000
Single Tubing (1.995")
Dual Tubing (2.441" & 1.995")
Single Tubing (2.441")
Quad Tubing
Dual Tubing (3.340" & 2.441")
Trio Tubing
Figure 6. 5 Cost Results for Different Scenarios
116
Texas Tech University, Bertrand O. Affanaambomo, August 2008
3,300
Recovery Time, days
3,200
3,100
3,000
2,900
2,800
2,700
2,600
Trio Tubing
Quad Tubing
Dual Tubing (3.340" & 2.441")
Dual Tubing (2.441" & 1.995")
Single Tubing (2.441")
Single Tubing (1.995")
Figure 6. 6 Recovery Time Results for Different Scenarios
117
Texas Tech University, Bertrand O. Affanaambomo, August 2008
1,200,000
Cashflow, dollars
1,000,000
800,000
600,000
400,000
200,000
0
-200,000
-400,000
0
151
287
646
981
1,321 1,676 2,011 2,312 2,601 2,878
Time, days
Dual Tubing (2.441" & 1.995")
Single Tubing (1.995")
Figure 6. 7 Cashflow: Dual Tubing (2.441" & 1.995") & Single Tubing (1.995")
118
Texas Tech University, Bertrand O. Affanaambomo, August 2008
1,200,000
1,000,000
Cashflow, dollars
800,000
600,000
400,000
200,000
0
-200,000
-400,000
0
151
287
646
981
1,321 1,676 2,011 2,312 2,601 2,878
Time, days
Dual Tubing (3.340" & 2.441")
Single Tubing (2.441")
Figure 6. 8 Cashflow: Dual Tubing (3.340" & 2.441") & Single Tubing (2.441")
119
Texas Tech University, Bertrand O. Affanaambomo, August 2008
1,200,000
1,000,000
Cashflow, dollars
800,000
600,000
400,000
200,000
0
-200,000
-400,000
0
149
282
636
966
1,301 1,651 1,982 2,279 2,565 2,838
Time, days
Trio Tubing
Single Tubing (2.441")
Figure 6. 9 Cashflow: Trio Tubing & Single Tubing (2.441")
120
Texas Tech University, Bertrand O. Affanaambomo, August 2008
1,200,000
1,000,000
Cashflow, dollars
800,000
600,000
400,000
200,000
0
-200,000
-400,000
0
150
285
642
975
1,313 1,667 2,000 2,300 2,588 2,864
Time, days
Quad Tubing
Single Tubing (2.441")
Figure 6. 10 Cashflow: Quad Tubing & Single Tubing (2.441")
121
Texas Tech University, Bertrand O. Affanaambomo, August 2008
340
330
Payout Time, days
320
310
300
290
280
270
260
250
Quad Tubing
Trio Tubing
Dual Tubing (3.340" & 2.441")
Dual Tubing (2.441" & 1.995")
Single Tubing (2.441")
Single Tubing (1.995")
Figure 6. 11 Payout Time Results for Different Scenarios
122
Texas Tech University, Bertrand O. Affanaambomo, August 2008
1,950,000
Net Present Value, $
1,900,000
1,850,000
1,800,000
1,750,000
1,700,000
1,650,000
1,600,000
1,550,000
1,500,000
Single Tubing (1.995")
Single Tubing (2.441")
Dual Tubing (3.340" & 2.441")
Dual Tubing (2.441" & 1.995")
Trio Tubing
Quad Tubing
Figure 6. 12 Net Present Value Results for Different Scenarios
123
Texas Tech University, Bertrand O. Affanaambomo, August 2008
15.60
Return on Investment, %
15.40
15.20
15.00
14.80
14.60
14.40
14.20
14.00
13.80
13.60
Single Tubing (1.995")
Single Tubing (2.441")
Tri Tubing
Dual Tubing (3.340" & 2.441")
Quad Tubing
Dual Tubing (2.441" & 1.995")
Figure 6. 13 Return on Investment Results for Different Scenarios
124
Texas Tech University, Bertrand O. Affanaambomo, August 2008
CHAPTER VII
CONCLUSIONS AND RECOMMENDATIONS
7.1 CONCLUSIONS
The following conclusions are drawn from the results obtained:
1.
In this study, we have developed a new concept of well completion for enhanced
production: Tapered ID Tubing Well Completion (TTWC)
2.
Well inflow-outflow analysis over the full life cycle of an oil well shows that
TTWC gives high well flowrates and cumulative production.
3.
Based on well production forecast results, TTWC showed shorter recovery time.
4.
Based on the economy analysis results, TTWC demonstrated a most favorable
payout time than the conventional well completion.
5.
It also demonstrated a better net present value (NPV) and return on investment
(ROI) than the conventional well completion.
125
Texas Tech University, Bertrand O. Affanaambomo, August 2008
7.2 RECOMMENDATIONS
1.
A study should be carried out to compare the natural flow period till liquid
loading takes place for each completion described in the present work, and the economic
ramifications.
2.
Apply the TTWC method using data for various fields in the Permian basin and
Gulf of Mexico for old/existing wells, additional economic analysis should be performed
to account for workover cost and downtime.
3.
Optimize the section lengths in TTWC for maximum flowrate or maximum NPV.
A good starting case is the duplex completion.
126
Texas Tech University, Bertrand O. Affanaambomo, August 2008
REFERENCES
1. Beggs Dale H., “Production Optimization Using NODALTM Analysis,” OGCI,
OK, 1991.
2. Szilas A. P., “Production and Transport of Oil and Gas, Second completely
revised edition,” Elsevier, New York-Tokyo, 1985.
3. Gilbert, W. E., “Flowing and Gas-Lift Well Performance,” API Drill. Prod.
Practice, NY, 1954.
4. Nind, T. E. W., “Principles of Oil Well Production,” McGraw-Hill, TX, 1964,
1981.
5. James Lea, Nickens Henry V., Well Michael, “Gas Well Deliquification
Solutions to Gas Well Liquid Loading Problem,” Elsevier, Gulf Drilling
Guides, MA, 2003.
6. Golan, Michael, and Whitson, Curtis H., “Well Performance, 2nd ed.
Englewood Cliffs,” Prentice-Hall, New Jersey, 1986.
7. Vogel, J. V., “Inflow Performance Relationships for Solution-Gas Drive
Wells,” JPT, Jan. 1968, pp. 86–92; Trans. AIME, p. 243.
8. Standing, M. B., “Inflow Performance Relationships for Damaged Wells
Producing by Solution-Gas Drive,” JPT, Nov. 1970, pp. 1399–1400.
9. Wiggins, M. L., “Generalized Inflow Performance Relationships for ThreePhase Flow,” SPE Paper 25458, presented at the SPE Production Operations
Symposium, Oklahoma, March 21–23, 1993.
127
Texas Tech University, Bertrand O. Affanaambomo, August 2008
10. Klins, M., and Clark, L., “An Improved Method to Predict Future IPR
Curves,” SPE Reservoir Engineering, November 1993, pp. 243–248.
11. Fetkovich, M. J., “The Isochronal Testing of Oil Wells,” SPE Paper 4529,
presented at the SPE 48th Annual Meeting, Las Vegas, Sept. 30–Oct. 3, 1973.
12. Craft B.C., Hawkins M., “Applied Petroleum Reservoir Engineering, 2nd
edition,” Prentice Hall, New Jersey, 1991.
13. Beggs, Dale H., “Gas Production Operations,” OGCI, Oklahoma, 1984.
14. Muskat, M., and Evinger, H. H., “Calculations of Theoretical Productivity
Factor,” Trans. AIME, 1942, pp. 126–139, 146.
15. Ahmed Terek, McKinney Paul D., “Advanced Reservoir Engineering,”
Elsevier, Jordan Hill, MA, 2005.
16. Brown Kermit E., “The Technology of Artificial Lift Methods, Vol. 1,” PPC,
OK, 1977.
17. Cholet H., “Well Production Practical Handbook,” Editions TECHNIP, 2000.
18. Gray Forest, “Petroleum Production for the Non-technical Person,” PennWell
Book, OK, 1986.
19. Hall Lewis W., Leecraft Jodie, “Petroleum Production Operations,” PETEX,
TX, 1986.
20. Perrin, D., Caron Michel, Gaillot, Georges, “Well Completion and Servicing,”
Editions Tecnip, France and Institut francais du petrole, France, 1999.
21. Economides Michael J., Hill Daniel A., Ehlig-Economides Christine,
“Petroleum Production Systems,” Prentice Hall PTR, New Jersey, 1994.
128
Texas Tech University, Bertrand O. Affanaambomo, August 2008
22. Guo Boyun, Lyons William C., Ghalambor Ali,” Petroleum Production
Engineering a Computer-Assisted Approach,” Elsevier Science & Technology
Books, MA, 2007.
23. Ahmed Tarek, “Reservoir Engineering Handbook, 2nd edition,” GPC, TX,
2001.
24. http://www.geomore.com/Completed%20Well.htm
25. Bharath Rao, “Multiphase Flow Models Range of Applicability,” CTES, L.C,
TX, 1998.
26. http://money.cnn.com/2008/05/16/news/economy/oil_speculator/index.htm?po
stversion=2008051615
27. Trenchard, J. and Whisenant, J. B., "Government Wells Oil Field, Duval
County, Texas," Bulletin of the American Association of Petroleum Geologists
Vol. 19, No. 8 August, 1935. PP. 1131-1147.
28. Frederick, B. and DeWeese, E., "Kaplan Caper," in Drilling, June, 1967. p.38.
29. Schlumberger, “GHOST--Gas Holdup Optical Sensor Tool brochure,” SMP5762, 2001.
30. http://www.fekete.com/software/virtuwell/description.asp
129
Texas Tech University, Bertrand O. Affanaambomo, August 2008
APPENDIX A
WELL PRODUCTION FORECAST INPUT DATA
Table A1: Input data for well production forecast21
kH, md
13
µo, cp
1.7
h, ft
115
γo, oAPI
32
pi, psi
4350
γg, oAPI
0.71
pb, psi
4350
T, oF
180
Co, psi-1
1.20E-05
Tpc, oR
395
Cw, psi-1
3.00E-06
Ppc, psi
667
Cf, psi-1
3.10E-06
Sw , fraction
0.3
Ct, psi-1
1.25E-05
Φ, fraction
0.21
µg, cp
0.023
rw, ft
0.406
re, ft
1490
130
Texas Tech University, Bertrand O. Affanaambomo, August 2008
Figure A1 Thermodynamic Properties for Fluid21
131
Texas Tech University, Bertrand O. Affanaambomo, August 2008
Figure A2 Thermodynamic Properties for Fluid21
132
Texas Tech University, Bertrand O. Affanaambomo, August 2008
Figure A3 Relative Permeabilities for Fluid21
133
Texas Tech University, Bertrand O. Affanaambomo, August 2008
“The Minimum Performance Properties of API Tubing”22
134
Texas Tech University, Bertrand O. Affanaambomo, August 2008
135
Texas Tech University, Bertrand O. Affanaambomo, August 2008
APPENDIX B
ADDITIONAL WELL PRODUCTION FORECAST RESULTS
Table B1: Oil Production Forecast for N = 1
PR
(psia)
4350
Bo
(rb/stb)
Bg (rb/scf)
Rs
(rb/scf)
Φg
Rav
(rb/scf)
Φn
∆N p (stb)
1.430
1.420
6.9E-04
7.1E-04
840
820
199.48
0.169
839
2.93E-03
1.413
7.2E-04
805
111.22
0.095
863
2.28E-03
1.395
7.4E-04
770
49.12
0.044
1,014
5.86E-03
1.388
7.6E-04
750
31.56
0.029
1,166
5.27E-03
1.380
7.8E-04
730
22.64
0.022
1,367
5.16E-03
1.370
8.0E-04
705
17.11
0.017
1,685
5.21E-03
1.360
8.1E-04
680
13.58
0.014
2,078
4.73E-03
1.353
8.3E-04
660
11.19
0.012
2,444
4.09E-03
1.345
8.5E-04
640
9.42
0.010
2,851
3.78E-03
1.338
8.7E-04
620
8.07
0.009
3,300
3.48E-03
1
4250
4150
4050
3950
3850
3750
3650
3550
3450
3350
136
N1p (stb)
2.93E-03
2.93E-03
5.21E-03
5.21E-03
1.11E-02
1.11E-02
1.63E-02
1.63E-02
2.15E-02
2.15E-02
2.67E-02
2.67E-02
3.14E-02
3.14E-02
3.55E-02
3.55E-02
3.93E-02
3.93E-02
4.28E-02
4.28E-02
Texas Tech University, Bertrand O. Affanaambomo, August 2008
Table B2: Gas Production Forecast for N = 1
P R (psia)
∆G1p (scf)
G1p (scf)
2.46E+00
2.46E+00 0.693068
So
Sg
kro
krg
S
0.006932
0.462821
6.01E-05
0
0.012168
0.436554
0.000174
1
0.024689
0.379638
0.000664
1.1
0.0319
0.350292
0.001079
1.2
0.038996
0.323629
0.001577
1.3
0.047278
0.295062
0.002271
1.4
0.055194
0.270121
0.003044
1.5
0.63854
0.06146
0.25188
0.00373
1.6
0.63251
0.06749
0.235494
0.004453
1.7
7.44E+01 0.626707
0.073293
0.220729
0.005205
1.8
4350
4250
2.46E+00
1.97E+00
4150
4.43E+00
5.94E+00
4050
1.04E+01 0.675311
1.04E+01
6.14E+00
3950
1.65E+01
0.6681
1.65E+01
7.05E+00
3850
2.36E+01 0.661004
2.36E+01
8.78E+00
3750
3.23E+01 0.652722
3.23E+01
9.84E+00
3650
4.22E+01 0.644806
4.22E+01
1.00E+01
3550
5.22E+01
5.22E+01
1.08E+01
3450
6.30E+01
6.30E+01
1.15E+01
3350
4.43E+00 0.687832
7.44E+01
137
Texas Tech University, Bertrand O. Affanaambomo, August 2008
Table B3: Production Schedule Forecast for 1.995” Tubing
PR
(psia)
qo
(stb/d)
ΔNp
(stb)
1,017
1.7E+05
Np (stb)
ΔGp (scf)
Gp (scf)
Δt (d)
t
(d)
4350
4250
171,959
891
1.3E+05
4150
1.16E+08
3.4E+05
4050
3950
3850
3750
3650
3550
3450
331
6.33E+08
2.0E+05
2.22E+03
3.06E+09
2,307,321
669
368
5.87E+08
2.2E+05
1.85E+03
2.48E+09
2,085,482
698
391
5.77E+08
2.4E+05
1.46E+03
1.90E+09
1,845,188
726
375
5.15E+08
2.8E+05
1.09E+03
1.38E+09
1,567,356
754
371
4.14E+08
3.1E+05
7.18E+02
9.69E+08
1,261,638
781
398
3.61E+08
3.0E+05
3.19E+02
6.08E+08
958,875
807
150
3.48E+08
3.1E+05
1.69E+02
2.60E+08
649,494
835
169
1.44E+08
305,778
863
3350
1.44E+08
2.55E+03
318
3.70E+09
6.73E+08
2,511,388
305
4.37E+09
138
2.87E+03
3.18E+03
Texas Tech University, Bertrand O. Affanaambomo, August 2008
Table B4: Production Forecast for 1.995" Tubing
(psia)
t
(d)
Production Rate
(bbl/d)
Cumulative
Production (stb)
GLR,
(scf/bbl)
Gas
Produced,
(scf/day)
4350
0
0
0
0
0
4250
169
1,017
171,959
839
853263
4150
319
891
305,778
863
768933
4050
718
863
649,494
1,014
875082
3950
1088
835
958,875
1,166
973610
3850
1463
807
1,261,638
1,367
1103169
3750
1855
781
1,567,356
1,685
1315985
3650
2223
754
1,845,188
2,078
1566812
3550
2554
726
2,085,482
2,444
1774344
3450
2872
698
2,307,321
2,851
1989998
3350
3177
669
2,511,388
3,300
2207700
PR
139
Texas Tech University, Bertrand O. Affanaambomo, August 2008
Table B5: Production Schedule Forecast for 2.441” Tubing
P R (psia)
qo
(stb/d)
ΔNp
(stb)
1,075
1.7E+05
Np
(stb)
ΔGp (scf)
Gp (scf)
Δt
(d)
t
(d)
4350
4250
171,959
938
1.3E+05
4150
1.16E+08
3.4E+05
4050
879
3850
3750
3650
2.4E+05
735
2.2E+05
3550
350
5.87E+08
2.11E+03
314
3.06E+09
6.33E+08
2.0E+05
1.76E+03
2.48E+09
2,307,321
706
372
5.77E+08
2,085,482
3450
1.39E+03
1.90E+09
1,845,188
765
357
5.15E+08
2.8E+05
1.03E+03
1.38E+09
1,567,356
794
352
4.14E+08
3.1E+05
6.81E+02
9.69E+08
1,261,638
822
378
3.61E+08
3.0E+05
3.03E+02
6.08E+08
958,875
849
143
3.48E+08
3.1E+05
1.60E+02
2.60E+08
649,494
3950
160
1.44E+08
305,778
909
3350
1.44E+08
2.43E+03
302
3.70E+09
6.73E+08
2,511,388
289
4.37E+09
140
2.73E+03
3.02E+03
Texas Tech University, Bertrand O. Affanaambomo, August 2008
Table B6: Production Forecast for 2.441" Tubing
PR
Cumulative
Production (stb)
GLR,
(scf/bbl)
Gas
Produced,
(scf/day)
(psia)
t (d)
Production
Rate (bbl/d)
4350
0
0
0
0
0
4250
160
1,075
171,959
839
901925
4150
303
938
305,778
863
809494
4050
681
909
649,494
1,014
921726
3950
1033
879
958,875
1,166
1024914
3850
1389
849
1,261,638
1,367
1160583
3750
1761
822
1,567,356
1,685
1385070
3650
2111
794
1,845,188
2,078
1649932
3550
2425
765
2,085,482
2,444
1869660
3450
2727
735
2,307,321
2,851
2095485
3350
3016
706
2,511,388
3,300
2329800
141
Texas Tech University, Bertrand O. Affanaambomo, August 2008
Table B7: Production Schedule Forecast for 2.992” Tubing
P R (psia)
qo
(stb/d)
ΔNp (stb)
1,117
1.7E+05
Np
(stb)
ΔGp (scf)
Gp
(scf)
Δt
(d)
t
(d)
4350
4250
171,959
974
1.3E+05
4150
1.16E+08
3.4E+05
4050
3950
3850
3750
3650
3550
3450
304
6.33E+08
2.0E+05
142
2.34E+03
292
3.70E+09
6.73E+08
2,511,388
2.04E+03
3.06E+09
2,307,321
730
338
5.87E+08
2.2E+05
1.70E+03
2.48E+09
2,085,482
760
360
5.77E+08
2.4E+05
1.34E+03
1.90E+09
1,845,188
791
344
5.15E+08
2.8E+05
9.96E+02
1.38E+09
1,567,356
821
340
4.14E+08
3.1E+05
6.56E+02
9.69E+08
1,261,638
850
365
3.61E+08
3.0E+05
2.91E+02
6.08E+08
958,875
880
137
3.48E+08
3.1E+05
1.54E+02
2.60E+08
649,494
911
154
1.44E+08
305,778
942
3350
1.44E+08
2.63E+03
280
4.37E+09
2.91E+03
Texas Tech University, Bertrand O. Affanaambomo, August 2008
Table B8: Production Forecast for 2.992" Tubing
P R (psia)
t (d)
Production Rate
(bbl/d)
Cumulative
Production (stb)
GLR,
(scf/bbl)
Gas
Produced,
scf/day
4350
0
0
0
0
0
4250
154
1117
171958.7143
839
937163
4150
291
974
305777.5666
863
840562
4050
656
942
649493.8706
1,014
955188
3950
996
911
958874.9411
1,166
1062226
3850
1340
880
1261638.375
1,367
1202960
3750
1700
850
1567355.847
1,685
1432250
3650
2038
821
1845187.952
2,078
1706038
3550
2342
791
2085481.801
2,444
1933204
3450
2634
760
2307320.773
2,851
2166760
3350
2913
730
2511388.454
3,300
2409000
143
1200
3000000
1000
2500000
800
2000000
600
1500000
400
1000000
Production Rate
200
500000
Cumulative Production
0
0
0
20
40
60
80
100
Time, month
Figure B1: Production Forecast for 2.992” Tubing
144
120
Cumulative Production, STB
Production Rate, stbl/day
Texas Tech University, Bertrand O. Affanaambomo, August 2008
Texas Tech University, Bertrand O. Affanaambomo, August 2008
Table B9: Production Schedule Forecast for 3.340” Tubing
PR
(psia)
4350
qo
(stb/d)
ΔNp
(stb)
1,136
1.7E+05
4250
(stb)
ΔGp (scf)
1.3E+05
4150
957
3.4E+05
3950
3850
862
832
3550
3450
300
6.33E+08
2.0E+05
2.01E+03
3.06E+09
2,307,321
739
334
5.87E+08
2.2E+05
1.67E+03
2.48E+09
2,085,482
770
355
5.77E+08
2.4E+05
1.32E+03
1.90E+09
1,845,188
801
339
5.15E+08
2.8E+05
9.81E+02
1.38E+09
1,567,356
3650
6.46E+02
335
4.14E+08
3.1E+05
3750
359
9.69E+08
1,261,638
2.31E+03
288
3.70E+09
6.73E+08
2,511,388
2.60E+03
276
4.37E+09
145
(d)
2.87E+02
6.08E+08
3.61E+08
3.0E+05
t
1.51E+02
2.60E+08
958,875
893
(d)
135
3.48E+08
3.1E+05
Δt
151
1.16E+08
649,494
924
(scf)
1.44E+08
305,778
4050
Gp
1.44E+08
171,959
989
3350
Np
2.87E+03
Texas Tech University, Bertrand O. Affanaambomo, August 2008
Table B10: Production Forecast for 3.340" Tubing
PR
Cumulative
Production (stb)
GLR,
(scf/bbl)
Gas
Produced,
(scf/day)
(psia)
t (d)
Production
Rate (bbl/d)
4350
0
0
0
0
0
4250
151
1136
171958.7143
839
953104
4150
287
989
305777.5666
863
853507
4050
646
957
649493.8706
1,014
970398
3950
981
924
958874.9411
1,166
1077384
3850
1320
893
1261638.375
1,367
1220731
3750
1674
862
1567355.847
1,685
1452470
3650
2008
832
1845187.952
2,078
1728896
3550
2308
801
2085481.801
2,444
1957644
3450
2596
770
2307320.773
2,851
2195270
3350
2873
739
2511388.454
3,300
2438700
146
1200
3000000
1000
2500000
800
2000000
600
1500000
400
1000000
Production Rate
200
500000
0
0
0
20
40
60
80
100
Time, month
Figure B2: Production Forecast for 3.340” Tubing
147
120
Cumulative Production, STB
Production Rate, STB/d
Texas Tech University, Bertrand O. Affanaambomo, August 2008
Texas Tech University, Bertrand O. Affanaambomo, August 2008
Scenario 2
Dual Tubing
Table B11: Production Schedule Forecast for Dual Tubing (2.441" & 1.995")
PR
(psia)
qo
(stb/d)
ΔNp
(stb)
1091
171958.71
ΔGp
(scf)
Np
(stb)
Gp
(scf)
Δt
(d)
T
(d)
4350
4250
171958.7
953
133818.85
4150
1.16E+08
343716.3
4050
3950
3850
3750
3650
3550
3450
311.6652
6.33E+08
204067.68
2084.423
3.06E+09
2307321
711
346.4241
5.87E+08
221838.97
1737.999
2.48E+09
2085482
741
367.8911
5.77E+08
240293.85
1370.108
1.9E+09
1845188
771
352.0505
5.15E+08
277832.11
1018.058
1.38E+09
1567356
802
347.229
4.14E+08
305717.47
670.8285
9.69E+08
1261638
831
372.7943
3.61E+08
302763.43
298.0342
6.08E+08
958874.9
860
140.4185
3.48E+08
309381.07
157.6157
2.6E+08
649493.9
891
157.6157
1.44E+08
305777.6
922
3350
1.44E+08
2396.088
299.3778
3.7E+09
6.73E+08
2511388
287.015
4.37E+09
148
2695.466
2982.481
Texas Tech University, Bertrand O. Affanaambomo, August 2008
Table B12: Production Forecast for Dual Tubing (2.441" & 1.995")
P R (psia)
t (d)
Production Rate
(bbl/d)
Cumulative
Production (stb)
GLR,
(scf/bbl)
Gas
Produced,
(scf/day)
4350
0
0
0
0
0
4250
158
1091
171958.7143
839
915349
4150
298
953
305777.5666
863
822439
4050
671
922
649493.8706
1,014
934908
3950
1018
891
958874.9411
1,166
1038906
3850
1370
860
1261638.375
1,367
1175620
3750
1738
831
1567355.847
1,685
1400235
3650
2084
802
1845187.952
2,078
1666556
3550
2396
771
2085481.801
2,444
1884324
3450
2695
741
2307320.773
2,851
2112591
3350
2982
711
2511388.454
3,300
2346300
149
Texas Tech University, Bertrand O. Affanaambomo, August 2008
Table B13: Production Schedule Forecast for Dual Tubing (3.340" & 2.441")
PR
(psia)
qo
(stb/d)
ΔNp (stb)
1136
171958.7
Np (stb)
ΔGp (scf)
Gp (scf)
Δt
(d)
t
(d)
4350
4250
171958.7
989
133818.9
4150
115520235
343716.3
4050
3950
3850
3750
3650
3550
3450
300.7432
632573070
204067.7
2011.018
3.06E+09
2307321
735
334.7375
587217145
221839
1676.28
2.48E+09
2085482
768
355.0726
577420272
240293.8
1321.208
1.9E+09
1845188
799
339.8018
515219303
277832.1
981.406
1.38E+09
1567356
830
335.1908
413986592
305717.5
646.2152
9.69E+08
1261638
861
359.5359
360592677
302763.4
286.6793
6.08E+08
958874.9
891
135.3072
348460540
309381.1
151.3721
2.6E+08
649493.9
923
151.3721
1.44E+08
305777.6
956
3350
144304796
2311.761
288.8528
3.7E+09
673326479
2511388
277.6431
4.37E+09
150
2600.614
2878.257
Texas Tech University, Bertrand O. Affanaambomo, August 2008
Table B14: Production Forecast for Dual Tubing (3.340" & 2.441")
PR
Cumulative
Production (stb)
GLR,
(scf/bbl)
Gas
Produced,
(scf/day)
(psia)
t (d)
Production Rate
(bbl/d)
4350
0
0
0
0
0
4250
151
1136
171958.7143
839
953104
4150
287
989
305777.5666
863
853507
4050
646
956
649493.8706
1,014
969384
3950
981
923
958874.9411
1,166
1076218
3850
1321
891
1261638.375
1,367
1217997
3750
1676
861
1567355.847
1,685
1450785
3650
2011
830
1845187.952
2,078
1724740
3550
2312
799
2085481.801
2,444
1952756
3450
2601
768
2307320.773
2,851
2189568
3350
2878
735
2511388.454
3,300
2425500
151
Texas Tech University, Bertrand O. Affanaambomo, August 2008
Scenario 3
Trio Tubing
Table B15: Production Schedule Forecast for Trio Tubing
PR
(psia)
4350
qo
(stb/d)
ΔNp
(stb)
1154
171958.71
4250
ΔGp
(scf)
1005
133818.85
971
343716.3
3950
259825031
904
3.61E+08
302763.43
3750
841
3550
776
297.0258
6.33E+08
204067.68
1981.79481
3.063E+09
2307320.8
746
330.3592
5.87E+08
221838.97
1651.43559
2.476E+09
2085481.8
3450
350.1918
5.77E+08
240293.85
1301.24376
1.898E+09
1845188
809
334.9153
5.15E+08
277832.11
966.328453
1.383E+09
1567355.8
3650
330.1826
4.14E+08
305717.47
636.14588
968878248
1261638.4
873
282.164104
353.9818
608285571
958874.94
3850
149.011018
133.1531
3.48E+08
309381.07
2278.82058
285.875
3.695E+09
6.73E+08
2511388.5
2564.69555
273.5492
4.369E+09
152
t
(d)
149.011
1.16E+08
649493.87
937
Δt
(d)
144304796
305777.57
4050
Gp
(scf)
1.44E+08
171958.71
4150
3350
Np
(stb)
2838.24472
Texas Tech University, Bertrand O. Affanaambomo, August 2008
Table B16: Production Forecast for Trio Tubing
PR
Cumulative
Production (stb)
GLR,
(scf/bbl)
Gas
Produced,
(scf/day)
(psia)
t (d)
Production Rate
(bbl/d)
4350
0
0
0
0
0
4250
149
1154
171958.7143
839
968206
4150
282
1005
305777.5666
863
867315
4050
636
971
649493.8706
1,014
984594
3950
966
937
958874.9411
1,166
1092542
3850
1301
904
1261638.375
1,367
1235768
3750
1651
873
1567355.847
1,685
1471005
3650
1982
841
1845187.952
2,078
1747598
3550
2279
809
2085481.801
2,444
1977196
3450
2565
776
2307320.773
2,851
2212376
3350
2838
746
2511388.454
3,300
2461800
153
Texas Tech University, Bertrand O. Affanaambomo, August 2008
Scenario 4
Quad tubing
Table B17: Production Schedule Forecast for Quad Tubing
P R (psia)
qo (stb/d)
ΔNp (stb)
1143
171958.71
Np (stb)
ΔGp (scf)
Gp (scf)
Δt
(d)
t
(d)
4350
4250
171958.7
995
133818.85
4150
1.16E+08
343716.3
4050
3950
3850
305717.47
833
277832.11
3750
3550
1.9E+09
3450
2.48E+09
299.9923
6.33E+08
204067.68
154
2300.116
288.1026
3.7E+09
6.73E+08
2511388
2000.124
3.06E+09
2307321
739
1666.592
333.5319
5.87E+08
221838.97
1313.161
353.4306
5.77E+08
2085482
770
337.9056
5.15E+08
240293.85
975.2557
1.38E+09
1845188
801
333.0259
4.14E+08
1567356
3650
642.2298
9.69E+08
1261638
865
357.2935
3.61E+08
302763.43
284.9364
6.08E+08
958874.9
896
134.4913
3.48E+08
309381.07
150.4451
2.6E+08
649493.9
929
150.4451
1.44E+08
305777.6
962
3350
1.44E+08
2588.219
276.1403
4.37E+09
2864.359
Texas Tech University, Bertrand O. Affanaambomo, August 2008
Table B18: Production Forecast for Quad Tubing
Cumulative
Production (stb)
GLR,
(scf/bbl)
Gas
Produced,
(scf/day)
P R (psia)
t (d)
Production Rate
(bbl/d)
4350
0
0
0
0
0
4250
150
1143
171958.7143
839
958977
4150
285
995
305777.5666
863
858685
4050
642
962
649493.8706
1,014
975468
3950
975
929
958874.9411
1,166
1083214
3850
1313
896
1261638.375
1,367
1224832
3750
1667
865
1567355.847
1,685
1457525
3650
2000
833
1845187.952
2,078
1730974
3550
2300
801
2085481.801
2,444
1957644
3450
2588
770
2307320.773
2,851
2195270
3350
2864
739
2511388.454
3,300
2438700
155
Texas Tech University, Bertrand O. Affanaambomo, August 2008
4500
IPR for pr = 4250 psia
4000
IPR for pr = 4150 psia
IPR for pr = 4050 psia
3500
IPR for pr = 3950 psia
IPR for pr = 3850 psia
Pwf, psia
3000
IPR for pr = 3750 psia
2500
IPR for pr = 3650 psia
IPR for pr = 3550 psia
2000
IPR for pr = 3450 psia
1500
IPR for pr = 3350 psia
TPR for pr = 4250 psia
1000
TPR for pr = 4150 psia
TPR for pr = 4050 psia
500
TPR for pr = 3950 psia
0
-100
TPR for pr = 3850 psia
400
900
1400
Production Rate, STB/d
TPR for pr = 3750 psia
TPR for pr = 3650 psia
Figure B3: Nodal Analysis Plot for 2.992" Tubing
156
Texas Tech University, Bertrand O. Affanaambomo, August 2008
4500
IPR for pr = 4250 psia
4000
IPR for pr = 4150 psia
IPR for pr = 4050 psia
3500
IPR for pr = 3950 psia
IPR for pr = 3850 psia
Pwf, psia
3000
IPR for pr = 3750 psia
2500
IPR for pr = 3650 psia
IPR for pr = 3550 psia
2000
IPR for pr = 3450 psia
1500
IPR for pr = 3350 psia
TPR for pr = 4250 psia
1000
TPR for pr = 4150 psia
TPR for pr = 4050 psia
500
TPR for pr = 3950 psia
0
TPR for pr = 3850 psia
0
500
1000
1500
Production Rate, STB/d
TPR for pr = 3750 psia
TPR for pr = 3650 psia
Figure B4: Nodal Analysis Plot for 3.340" Tubing
157
Texas Tech University, Bertrand O. Affanaambomo, August 2008
APPENDIX C
COST ASSUMPTIONS
Table C1: costs Assumptions
ACQUISITION
Land and landwork
Wellbore
Geological/Engineering
Seismic data
Seismic reprocessing
Seismic interpretation
ACQUISITION TOTAL
$8,000
$15,000
$ 7,000
$40,850
$14,000
$ 4,500
$89,350
DRILLING
Prepare location
Well preparation
Mill casing section
Drill directional
Drill pipe rental
Drilling mud
Drill bits
Geological/Engineering
Mud logger 6 days x 400
DRILLING TOTAL
$ 1,000
$ 8,000
$15,000
$45,000
$ 9,500
$ 2,500
$ 7,000
$ 5,000
$ 2,400
$95,400
COMPLETION
Completion rig
Tubing
Rods and pump
Size 456 pumping unit
Production facilities
Field Supervision
COMPLETION TOTAL
$ 4,500
varies
$ 8,000
$18,000
$12,500
$ 3,000
$ 56,725
PROJECTED TOTAL COST
158
$241,475 (plus or minus 10%)
Texas Tech University, Bertrand O. Affanaambomo, August 2008
APPENDIX D
ADITIONAL ECONOMIC ANALYSIS RESULTS
Table D1: Economic Analysis for 2.992" Tubing
Time,
day
Oil
Produced,
bbl/day
Gas Produced
MMbtu/day
Gross
REVENUE,
$/day
Cost, $
Cashflow, $
0
0
0
0
292830
-292830
154
1,117
965.28
152101.81
292830
-140728.19
291
974
865.78
132907.29
292830
-7820.90
656
942
983.84
130231.00
292830
122410.11
996
911
1094.09
127590.75
292830
250000.85
1340
880
1239.05
125350.91
292830
375351.76
1700
850
1475.22
124289.58
292830
499641.34
2038
821
1757.22
123883.24
292830
623524.58
2342
791
1991.20
122796.68
292830
746321.26
2634
760
2231.76
121659.85
292830
867981.10
2913
730
2481.27
120752.41
292830
988733.52
NPV, $
1768031.994
ROI, %
13.77
159
Payout Time, days
313
Texas Tech University, Bertrand O. Affanaambomo, August 2008
Table D2: Economic Analysis for 3.340" Tubing
Time,
day
0
151
287
646
981
1320
1674
2008
2308
2596
2873
Oil
Produced,
bbl/day
0
1,136
989
957
924
893
862
832
801
770
739
NPV, $
1728598.835
Gas
Produced,
Mmbtu/day
0
981.70
879.11
999.51
1109.71
1257.35
1496.04
1780.76
2016.37
2261.13
2511.86
Gross
REVENUE,
$/day
0
154689.04
134954.12
132304.75
129411.47
127202.68
126044.26
125543.06
124349.10
123260.63
122241.14
ROI, %
13.02
160
Cost, $
Cashflow, $
306590
-306590
306590
-151900.96
306590
-16946.84
306590
115357.90
306590
244769.38
306590
371972.06
306590
498016.32
306590
623559.38
306590
747908.48
306590
871169.11
306590
993410.25
Payout Time, days
333
Texas Tech University, Bertrand O. Affanaambomo, August 2008
APPENDIX E
VITA
Bertrand O. Affanaambomo (Oliver) was born in Douala, Cameroon and grew up
in Yaoundé, Cameroon. He graduated from Lycee Technique de Nkolbisson with the
degree in electricity and maintenance electro-mechanic. In 2003, he transferred to Texas
Tech University from Georgia Perimeter College where he graduated with a Bachelor of
Science Degree in Petroleum Engineering.
His curriculum at Texas Tech gave him both the base of knowledge for petroleum
engineering and practical opportunities to apply that knowledge. For example, in his
advanced drilling engineering class, he prepared a mud plan, a bit plan, a casing plan, and
a hydraulic plan for a proposed well in Campbell County, Wyoming. Also in his
advanced petrophysics class, he worked on a petrophysical analysis of well #5399 in the
lower Wolfcamp Field located in the Permian Basin.
Oliver worked as a teaching assistant in the advanced production class in which
he assisted students in performing nodal analysis in electric submersible pumps and
Surface Centrifugal Pumps to determine optimum flowrate, production forecast, and
stabilized flowrate using PERFORM v6.0 software and VirtuWellTM.
During his academic year at Texas Tech University, Oliver was involved in
different student organizations. He has been an active member of Texas Tech University
Chapter of the Society of Petroleum Engineers and a member of Pi Epsilon Tau,
161
Texas Tech University, Bertrand O. Affanaambomo, August 2008
Petroleum Engineering's honor society, since 2003 and 2006, respectively. He was the
president of African Student Organization in 2004-2005.
162
PERMISSION TO COPY
In presenting this thesis in partial fulfillment of the requirements for a master’s
degree at Texas Tech University or Texas Tech University Health Sciences Center, I
agree that the Library and my major department shall make it freely available for research
purposes. Permission to copy this thesis for scholarly purposes may be granted by the
Director of the Library or my major professor. It is understood that any copying or
publication of this thesis for financial gain shall not be allowed without my further
written permission and that any user may be liable for copyright infringement.
Agree (Permission is granted.)
Bertrand O. Affanaambomo
Student Signature
07/25/2008
Date
Disagree (Permission is not granted.)
_______________________________________
Student Signature
_________________
Date