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SCHOOL OF ENGINEEERING
MSc Oil and Gas Engineering
Investigate the rate of phase re-segregation
in a shut-in multiphase we...
Investigate the rate of phase re-segregation in a
shut-in multiphase well for a range of starting
water-cuts using transie...
Declaration
This thesis is submitted to The Robert Gordon University in accordance
with the requirements of the degree of ...
Abstract
When a multiphase production well is shut-in at surface, the effects of
gravity and density difference cause phas...
i
Acknowledgments
I would like to extend my thanks to both Alastair Baillie, for his guidance
and supervision throughout t...
ii
Table of Contents
Acknowledgments....................................................................... i
Table of Con...
iii
Chapter Three
OLGA MODEL
3.1. OLGA Well Data: Base Case............................................. 22
Chapter Four
R...
iv
OLGA Well Base Case: Input Data ............................................. 61
Appendix D ..............................
v
List of Figures
Figure 1. 1: Wellbore Fluid Distribution............................................ 5
Figure 2. 1: Well...
vi
Figure 4. 4: Plot of THP v Shut-in Time also showing when the tubing
has become 100% oil/gas..............................
vii
Figure 4. 20: Day 1, Oil Saturation ~0.1 (90% WC) ........................ 46
Figure 4. 21: Day 20, Oil Saturation ~0....
viii
Figure F. 1: Well Model OLGA-ROCX.............................................. 73
Figure G. 1: ROCX Grid...............
ix
List of Tables
Table 2. 1: Approximate Fluid Density Gradients ............................... 9
Table 2. 2: Dunlin Fie...
x
Table C. 2: OLGA Input Tubing Data.............................................. 63
Table C. 3: Ambient Temperature .......
xi
Nomenclature
K = Permeability
Kr = Relative Permeability
∆p = Pressure Difference
P = Pressure
Pb = Bubble Point Pressu...
xii
Subscripts and Superscripts
g = Gas
o = Oil
w = Water
xiii
Abbreviations
BBL = Barrel
FVF = Formation Volume Factor
GOR = Gas-Oil Ratio
ID = Inner Diameter
MD = Measured Depth
...
xiv
Conversion Factors
1 inch (“) = 0.0254 m
1 foot (ft) = 0.3048 m
1 cubic foot (scf) = 0.028317 m3
1 barrel = 0.158987 m...
1
Chapter One
INTRODUCTION
1.1. Overview
During production, pressure declines in the reservoir due to fluid
extraction. Pr...
2
The aim of well skimming is to produce the dry oil out the wellbore and
shut-in again before the reintroduction of high ...
3
1.4. Methodology
A literature review will be carried out into the phase re-segregation
phenomenon. Well skimming as a pr...
4
Chapter Two
LITERATURE REVIEW
2.1. Wellbore Storage Effects
When a producing well is shut-in at surface, flow into the w...
5
Figure 1. 1: Wellbore Fluid Distribution
(Adapted from: p295, Bellarby, 2009)
6
2.2. Well Testing
2.2.1. Pressure Build-up Test
A pressure transient test is a fluid-flow test conducted on wells to obt...
7
a “hump” that gradually disappears as reservoir trends become
recognisable. (Ahmed, 2011)
Figure 2. 1: Wellbore storage ...
8
porosity systems and distortion due to phase segregation, demonstrating
how to differentiate between them.
Different met...
9
Table 2. 1: Approximate Fluid Density Gradients
Fluid
Pressure Gradient
(psi/ft.)
Gas <0.15
Oil 0.25 to 0.35
Water 0.40 ...
10
Dashed lines are pressure falloff data from injection wells, dots are PBU
data from producers, assuming a 100% oil colu...
11
Figure 2. 3: Pressure Traverse. P7 & W4, P6 & W1 are Producer (P) and
Injector (W) wells, Psat = Saturation Pressure at...
12
Table 2.3 considers water production and required water injection (WI)
support for continuous production compared to we...
13
Figure 2. 4: Production from ‘skim wells’ in the Dunlin Field, showing the
variation in skim frequency and skim volume ...
14
Figure 2. 5: Skim volume compared to shut-in THP (bars: skim volume,
scatter plot: THP).
(Source: Fairfield Energy, Jun...
15
Figure 2. 6: Well DA-30: Tubing Head Pressure v Time
(Source: Fairfield Energy, June 2014.)
Figure 2. 7: Well DA-36: Tu...
16
THP levelling off indicates the fluids have fully re-distributed in the
wellbore with fluid pressure equalized between ...
17
expectations and the field produced 20 million STB over the next 2 years.
(Manson, 2009) (Reekie, 2010)
2.6. OLGA
OLGA ...
18
coupled mass conservation equations are solved for: the oil droplets, the
water droplets, the oil film, the water film ...
19
such as density, viscosity and specific volume are taken from
experimental correlations at each pressure and temperatur...
20
numerical coupling between the two models is implemented in an implicit
scheme, outlined in Appendix B.
Hu et al. (2007...
21
wellbore area to optimise the bean-up procedure and prevent any sand
production due to a high pressure gradient.
Both c...
22
Chapter Three
OLGA MODEL
3.1. OLGA Well Data: Base Case
The OLGA Well Graphical User Interface (GUI) allows the user to...
23
Well Model
Figure 3. 1: OLGA Well Model: Base Case
Casing
Casing data is important for heat transfer calculations. Prop...
24
Table 3. 1: OLGA Input Casing Data
Tubing
Tubing properties are outlined in Table 3.2. Tubing length is 9317ft and
inne...
25
Table 3. 3: OLGA Input Reservoir Conditions
Fluid
The Black oil approach was used (see 2.6.2. Black Oil Correlation), G...
26
Table 3. 5: Casing Initial Conditions
Table 3. 6: Tubing Initial Conditions
Outputs
Each simulation was run for 7 days;...
27
Chapter Four
RESULTS/DISCUSSION
In order to investigate the rate of phase re-segregation, for each case,
the time taken...
28
Figure 4. 1: Volume of each fluid in tubing changing during shut-in
period
Figure 4.2 shows THP starting to level off o...
29
Figure 4. 2: Base Case: Plot of THP v Shut-in Time also showing the
volume fraction of each phase (gas, oil, water) in ...
30
4.2. Sensitivities
For sensitivity analysis, conditions were kept the same as the base case,
only changing the respecti...
31
Figure 4. 4: Plot of THP v Shut-in Time also showing when the tubing
has become 100% oil/gas
4.2.2. Water-cut 90 – 98%
...
32
Figure 4. 5: WC 94%: Plot of THP v Shut-in Time also showing the
volume fraction of each phase (gas, oil, water) in the...
33
Using the profile plot, the oil-water contact (OWC) can be determined
during the shut-in period (Fig. 4.7). During the ...
34
Figure 4. 8: The effect of changing GOR on Re-segregation Time
A higher GOR results in a faster rate of phase re-segreg...
35
The results show that changing GOR affects the rate of phase re-
segregation. However, in reality, a change in GOR woul...
36
Figure 4. 10: Plot of THP v Shut-in Time for Oil SG 0.75 – 0.95
For volatile oil (SG = 0.75), the gas coming out of sol...
37
For heavy Oil (SG = 0.95), there is no gas coming out of solution, high
density oil means difference in densities betwe...
38
Figure 4. 13: OWC for different WC % at time of shut-in
4.2.5. Tubing Size
Sample cases showed that a smaller tubing ID...
39
= 17598ft, Vertical MD = 12000ft) which will affect the rate of phase re-
segregation.
Additionally, different flow reg...
40
pressure, temperature and fluid properties; whereas, OLGA coupled with
ROCX also considers the reservoir characteristic...
41
Table 4. 4: Reservoir properties
Reservoir Grid (x, y, z) (5x20m) x (5x20m) x (5x10m)
Porosity (Φ) 0.25
Rock Compressib...
42
Simulation results show that after a shut-in period of 2.092 days the
tubing is 100% oil/gas, and after 2.89 days the f...
43
Figure 4. 18: Volumetric Flow Rate, 70 - 80 hours
Figure 4. 19: If the valve is opened for longer (5 hours), high WC is...
44
4.3.2. Re-segregation in the Reservoir
An integrated model was setup, a smaller reservoir grid was used to
maximise sim...
45
Table 4. 8: Well boundary conditions
Pressure
(bara)
Skin PI Temperature
(o
C)
Sw So Sg
344.46 0 50 104.44 0.9 0.1 0
Ta...
46
Figure 4. 20: Day 1, Oil Saturation ~0.1 (90% WC)
Figure 4. 21: Day 20, Oil Saturation ~0.16 at the top of reservoir, n...
47
show that the phenomenon continues into the reservoir during a
prolonged shut-in.
4.4. Evaluation of software
OLGA has ...
48
Chapter Five
CONCLUSIONS AND RECOMMENDATIONS
5.1. Conclusions
Phase re-segregation was successfully simulated using dyn...
49
3. Oil density (SG) was altered as well as GOR and bubble point to
represent typical properties of heavier oil and vola...
50
5.2. Recommendations
1. From the simulations carried out with sample well models, it is
clear that if a model is set up...
51
REFERENCES
AHMED A and MEEHAN N., 2011. Advanced Reservoir Management and
Engineering. Gulf Professional Publishing
ARN...
52
FAIR WB., 1981. Pressure Buildup Analysis with Phase Redistribution.
Society of Petroleum Engineers. USA. [online]. Ava...
53
HU ET AL., 2010. Use of Wellbore-Reservoir Coupled Dynamic Simulation
to Evaluate the Cycling Capability of Liquid-Load...
54
POURAFSHARY P., 2007. A Coupled Wellbore/Reservoir Simulator to
Model Multiphase Flow and Temperature Distribution. [on...
55
SAGEN ET AL., 2011. A Dynamic Model for Simulation of Integrated
Reservoir, Well and Pipeline System. Society of Petrol...
56
https://www.onepetro.org/conference-paper/SPE-127850-MS [Accessed
23 June 2014]
WINTERFELD PH., 1989. Simulation of Pre...
57
BIBLIOGRAPHY
CLUVER C., 2009. Interpreting Pressure Transient Tests. Halliburton.
[online]. Available from: http://www....
58
APPENDICES
59
Appendix A
Stokes Law
( )
(Eq A.1)
Where:
v = velocity of the rising oil droplet, cm/s
gc = gravitational acceleration ...
60
Appendix B
OLGA-ROCX Coupling
The numerical coupling between the integrated models is implemented in
an implicit scheme...
61
Appendix C
OLGA Well Base Case: Input Data
Casing
Table C. 1: OLGA Input Casing Data
Figure C. 1: Casing Visualisation ...
62
Figure C. 2: Casing Specifications
63
Tubing
Table C. 2: OLGA Input Tubing Data
Figure C. 3: Tubing Visualisation (depth in metres)
64
Heat Transfer
Table C. 3: Ambient Temperature
Table C. 4: Formation Heat Transfer Properties
Table C. 5: Fluid outside ...
65
Fluid
The Black oil approach was used (see 2.6.2. Black oil Correlation), GOR
and Bubble Point values were taken from a...
66
Table C. 10: Tubing Initial Conditions
67
Appendix D
Tubing Size
Tubing ID 3”: Re-segregation Time (Tubing 100% oil/gas) = 1.171 days
Figure D. 1: Tubing ID 3”: ...
68
Tubing ID 4.02”: Re-segregation Time (Tubing 100% oil/gas) = 1.24
days
Figure D. 2: Tubing ID 4.02”: Plot of THP v Shut...
69
Appendix E
Deviated Well
Profile
Table E. 1: Deviated Well Profile TVD 12000ft, MD 17598ft
70
Figure E. 1: Deviated Well Survey
Casing and Tubing
Casing is the same as the base case (see Appendix C); the 7” liner ...
71
Fluid data and conditions are consistent with the base case, as described
in Appendix C.
Results
WC 90%: Re-segregation...
72
WC 94%: Re-segregation Time (Tubing 100% oil/gas) = 1.029 days
Figure E. 3: Deviated Well WC 94%: Plot of THP v Shut-in...
73
Appendix F
OLGA-ROCX Well Data
Well Model
Figure F. 1: Well Model OLGA-ROCX
74
Casing and Tubing
Table F. 1: OLGA-ROCX Casing Data
The tubing head valve is at 495ft TVD (seabed) and there is a packe...
75
Appendix G
ROCX Input File
Figure G. 1: ROCX Grid
Figure G. 2: ROCX Fluid Properties
76
Figure G. 3: ROCX Reservoir Properties
Figure G. 4: ROCX Kr and Pc
77
Figure G. 5: ROCX Initial Conditions
Figure G. 6: ROCX Boundary Conditions (Well)
78
Figure G. 7: ROCX Boundary Conditions (Reservoir)
Figure G. 8: ROCX Simulation
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MSc Thesis. Jonathan Roche - Investigate the rate of phase re-segregation in a shut-in multiphase well for a range of starting water cuts using transient well modelling. Software; OLGA-ROCX.

  1. 1. SCHOOL OF ENGINEEERING MSc Oil and Gas Engineering Investigate the rate of phase re-segregation in a shut-in multiphase well for a range of starting water-cuts using transient well modelling. Jonathan Roche (1215737) September, 2014
  2. 2. Investigate the rate of phase re-segregation in a shut-in multiphase well for a range of starting water-cuts using transient well modelling. JONATHAN ROCHE (1215737) September 2014 This report is submitted in partial fulfilment of the requirements for the Degree of Master of Science in Oil and Gas Engineering at Robert Gordon University, Aberdeen.
  3. 3. Declaration This thesis is submitted to The Robert Gordon University in accordance with the requirements of the degree of Master of Science in Oil and Gas Engineering, in the School of Engineering. I confirm that the material presented in this report is my own work. Where this is not the case, the source of material has been acknowledged. Student Name Jonathan Roche Signed ................................................ Date 17 September 2014
  4. 4. Abstract When a multiphase production well is shut-in at surface, the effects of gravity and density difference cause phase re-segregation. A dynamic wellbore simulator was used to investigate the rate of phase re-segregation in a shut-in multiphase well for a range of starting water- cuts. Output plots showed that, as water-cut at time of shut-in increases, the time taken for phase re-segregation increases. Simulation results confirmed empirical observations that in 90% water- cut wells, the phases redistribute completely in less than a week. That is, the tubing string fills with 100% oil/gas with all water having gravitated out of the well, being replaced by reservoir oil/gas. Sensitivity analysis of fluid properties and well data showed good agreement with established theories and phenomena. Results show that oil density, which is related to gas-oil ratio and bubble point, affects the rate of phase re-segregation. The rate of phase re-segregation is of particular interest when considering intermittent production. Also termed skimming; this production method utilises the phase re-segregation phenomenon to produce dry oil intermittently from high water-cut wells. To simulate well skimming, a wellbore model was coupled to a near- wellbore reservoir model. Model parameters were varied to optimise skim frequency and skim time to maximise recovery of dry oil. Also investigated, was phase re-segregation occurring in the reservoir during a prolonged shut-in. Onset of phase re-segregation was apparent during a shut-in period of 20 days.
  5. 5. i Acknowledgments I would like to extend my thanks to both Alastair Baillie, for his guidance and supervision throughout this project, and my industry mentor, Tony Peters (Fairfield Energy, UK) for his support and the opportunity to work on this study. Thanks also go to Gareth Herron (Xodus Group) and Luke Boongird (Chevron, UK) for their time and advice.
  6. 6. ii Table of Contents Acknowledgments....................................................................... i Table of Contents ....................................................................... ii List of Figures ............................................................................ v List of Tables............................................................................. ix Nomenclature ........................................................................... xi Abbreviations...........................................................................xiii Conversion Factors...................................................................xiv Chapter One INTRODUCTION 1.1. Overview........................................................................ 1 1.2. Rationale........................................................................ 2 1.3. Aims/Objectives .............................................................. 2 1.4. Methodology ................................................................... 3 1.5. Limitations and Constraints ............................................... 3 Chapter Two LITERATURE REVIEW 2.1. Wellbore Storage Effects................................................... 4 2.2. Well Testing.................................................................... 6 2.2.1. Pressure Build-up Test ................................................ 6 2.2.2. Pressure Transient Analysis.......................................... 6 2.3. Estimating Bottom-hole Pressure........................................ 8 2.3.1. Reservoir Pressure from Shut-in THP ............................. 9 2.4. Skimming/Intermittent Production.................................... 11 2.4.1. Case Study: Fairfield Energy, Dunlin Field (North Sea) ... 12 2.5. Phase Re-segregation in the Reservoir .............................. 16 2.6. OLGA........................................................................... 17 2.6.1. OLGA Overview........................................................ 17 2.6.2. Black oil Correlation.................................................. 18 2.6.3. OLGA-ROCX ............................................................ 19
  7. 7. iii Chapter Three OLGA MODEL 3.1. OLGA Well Data: Base Case............................................. 22 Chapter Four RESULTS/DISCUSSION 4.1. Base Case .................................................................... 27 4.2. Sensitivities .................................................................. 30 4.2.1. Water-cut 60 – 90% ................................................. 30 4.2.2. Water-cut 90 – 98% ................................................. 31 4.2.3. Gas-Oil Ratio (GOR).................................................. 33 4.2.4. Oil Density .............................................................. 35 4.2.5. Tubing Size ............................................................. 38 4.2.6. Deviated Well .......................................................... 38 4.3. OLGA-ROCX.................................................................. 39 4.3.1. Skimming ............................................................... 40 4.3.2. Re-segregation in the Reservoir.................................. 44 4.4. Evaluation of software .................................................... 47 Chapter Five CONCLUSIONS AND RECOMMENDATIONS 5.1. Conclusions .................................................................. 48 5.2. Recommendations ......................................................... 50 REFERENCES ............................................................................ 51 BIBLIOGRAPHY ........................................................................ 56 APPENDICES ............................................................................ 58 Appendix A............................................................................... 59 Stokes Law .............................................................................. 59 Appendix B............................................................................... 59 OLGA-ROCX Coupling................................................................ 60 Appendix C............................................................................... 61
  8. 8. iv OLGA Well Base Case: Input Data ............................................. 61 Appendix D .............................................................................. 67 Tubing Size .............................................................................. 67 Appendix E............................................................................... 69 Deviated Well........................................................................... 69 Appendix F............................................................................... 73 OLGA-ROCX Well Data .............................................................. 73 Appendix G .............................................................................. 75 ROCX Input File........................................................................ 75
  9. 9. v List of Figures Figure 1. 1: Wellbore Fluid Distribution............................................ 5 Figure 2. 1: Wellbore storage on log-log pressure derivative plot ......... 7 Figure 2. 2: Reservoir Pressure - From Shut-in THP Data.................. 10 Figure 2. 3: Pressure Traverse. P7 & W4, P6 & W1 are Producer (P) and Injector (W) wells, Psat = Saturation Pressure at Reservoir Temperature ................................................................................................ 11 Figure 2. 4: Production from ‘skim wells’ in the Dunlin Field, showing the variation in skim frequency and skim volume for each well................. 13 Figure 2. 5: Skim volume compared to shut-in THP (bars: skim volume, scatter plot: THP)........................................................................ 14 Figure 2. 6: Well DA-30: Tubing Head Pressure v Time .................... 15 Figure 2. 7: Well DA-36: Tubing Head Pressure v Time .................... 15 Figure 3. 1: OLGA Well Model: Base Case ...................................... 23 Figure 4. 1: Volume of each fluid in tubing changing during shut-in period ....................................................................................... 28 Figure 4. 2: Base Case: Plot of THP v Shut-in Time also showing the volume fraction of each phase (gas, oil, water) in the tubing during shut- in period.................................................................................... 29 Figure 4. 3: Pressure response during shut-in at 3000ft TVD............. 29
  10. 10. vi Figure 4. 4: Plot of THP v Shut-in Time also showing when the tubing has become 100% oil/gas............................................................. 31 Figure 4. 5: WC 94%: Plot of THP v Shut-in Time also showing the volume fraction of each phase (gas, oil, water) in the tubing during shut- in period.................................................................................... 32 Figure 4. 6: WC 98%: Plot of THP v Shut-in Time also showing the volume fraction of each phase (gas, oil, water) in the tubing during shut- in period.................................................................................... 32 Figure 4. 7: OWC for different WC % at time of shut-in.................... 33 Figure 4. 8: The effect of changing GOR on Re-segregation Time....... 34 Figure 4. 9: Plot of THP v Shut-in Time for GOR 100 – 500 scf/STB.... 34 Figure 4. 10: Plot of THP v Shut-in Time for Oil SG 0.75 – 0.95......... 36 Figure 4. 11: Volume of each fluid in tubing changing during shut-in period ....................................................................................... 36 Figure 4. 12: Volume of each fluid in tubing changing during shut-in period ....................................................................................... 37 Figure 4. 13: OWC for different WC % at time of shut-in.................. 38 Figure 4. 14: Fluid distribution for different well deviations ............... 39 Figure 4. 15: Well Model OLGA-ROCX ........................................... 40 Figure 4. 16: Well Skimming: Plot of THP v Shut-in Time also showing the volume fraction of each phase (gas, oil, water) in the tubing during shut-in period............................................................................. 42 Figure 4. 17: Volumetric Flow Rates during well skimming................ 42 Figure 4. 18: Volumetric Flow Rate, 70 - 80 hours .......................... 43 Figure 4. 19: If the valve is opened for longer (5 hours), high WC is reinstated .................................................................................. 43
  11. 11. vii Figure 4. 20: Day 1, Oil Saturation ~0.1 (90% WC) ........................ 46 Figure 4. 21: Day 20, Oil Saturation ~0.16 at the top of reservoir, near- wellbore area. ............................................................................ 46 Figure C. 1: Casing Visualisation (depth in metres).......................... 61 Figure C. 2: Casing Specifications ................................................. 62 Figure C. 3: Tubing Visualisation (depth in metres) ......................... 63 Figure D. 1: Tubing ID 3”: Plot of THP v Shut-in Time also showing the volume fraction of each phase (gas, oil, water) in the tubing during shut- in period.................................................................................... 67 Figure D. 2: Tubing ID 4.02”: Plot of THP v Shut-in Time also showing the volume fraction of each phase (gas, oil, water) in the tubing during shut-in period............................................................................. 68 Figure D. 3: Tubing ID 5”: Plot of THP v Shut-in Time also showing the volume fraction of each phase (gas, oil, water) in the tubing during shut- in period.................................................................................... 68 Figure E. 1: Deviated Well Survey ................................................ 70 Figure E. 2: Deviated Well WC 90%: Plot of THP v Shut-in Time also showing the volume fraction of each phase (gas, oil, water) in the tubing during shut-in period ................................................................... 71 Figure E. 3: Deviated Well WC 94%: Plot of THP v Shut-in Time also showing the volume fraction of each phase (gas, oil, water) in the tubing during shut-in period ................................................................... 72
  12. 12. viii Figure F. 1: Well Model OLGA-ROCX.............................................. 73 Figure G. 1: ROCX Grid............................................................... 75 Figure G. 2: ROCX Fluid Properties................................................ 75 Figure G. 3: ROCX Reservoir Properties ......................................... 76 Figure G. 4: ROCX Kr and Pc........................................................ 76 Figure G. 5: ROCX Initial Conditions.............................................. 77 Figure G. 6: ROCX Boundary Conditions (Well) ............................... 77 Figure G. 7: ROCX Boundary Conditions (Reservoir) ........................ 78 Figure G. 8: ROCX Simulation ...................................................... 78
  13. 13. ix List of Tables Table 2. 1: Approximate Fluid Density Gradients ............................... 9 Table 2. 2: Dunlin Field fluid density gradients.................................. 9 Table 2. 3: Voidage efficiency, skimming operation compared to continuous production.................................................................. 12 Table 3. 1: OLGA Input Casing Data.............................................. 24 Table 3. 2: OLGA Input Tubing Data.............................................. 24 Table 3. 3: OLGA Input Reservoir Conditions .................................. 25 Table 3. 4: Fluid Properties Base Case ........................................... 25 Table 3. 5: Casing Initial Conditions .............................................. 26 Table 3. 6: Tubing Initial Conditions .............................................. 26 Table 4. 1: Simulation Results...................................................... 30 Table 4. 2: Water-cut 90 – 98% Simulation Results ......................... 31 Table 4. 3: Oil Properties and Simulation Results............................. 35 Table 4. 4: Reservoir properties ................................................... 41 Table 4. 5: Well boundary conditions............................................. 41 Table 4. 6: Reservoir boundary conditions...................................... 41 Table 4. 7: Reservoir properties ................................................... 44 Table 4. 8: Well boundary conditions............................................. 45 Table 4. 9: Reservoir boundary conditions...................................... 45 Table C. 1: OLGA Input Casing Data.............................................. 61
  14. 14. x Table C. 2: OLGA Input Tubing Data.............................................. 63 Table C. 3: Ambient Temperature ................................................. 64 Table C. 4: Formation Heat Transfer Properties ............................... 64 Table C. 5: Fluid outside production tubing..................................... 64 Table C. 6: Each inflow has conditions set ...................................... 64 Table C. 7: Fluid Properties Base Case........................................... 65 Table C. 8: Production Top Boundary Conditions.............................. 65 Table C. 9: Casing Initial Conditions .............................................. 65 Table C. 10: Tubing Initial Conditions ............................................ 66 Table E. 1: Deviated Well Profile TVD 12000ft, MD 17598ft ............... 69 Table F. 1: OLGA-ROCX Casing Data ............................................. 74 Table F. 2: OLGA-ROCX Tubing Data ............................................. 74
  15. 15. xi Nomenclature K = Permeability Kr = Relative Permeability ∆p = Pressure Difference P = Pressure Pb = Bubble Point Pressure Pc = Capillary Pressure PI = Productivity Index PR = Reservoir Pressure Pref = Reference Pressure Psat = Saturation Pressure Pwf = Bottom-hole Well Flowing Pressure q = Production Rate S = Saturation scf = Standard Cubic Foot SG = Specific Gravity SGR = Residual Gas Saturation SOR = Residual Oil Saturation STB = Stock-tank Barrel SWC = Connate Water Saturation T = Temperature TR = Reservoir Temperature V = Volume
  16. 16. xii Subscripts and Superscripts g = Gas o = Oil w = Water
  17. 17. xiii Abbreviations BBL = Barrel FVF = Formation Volume Factor GOR = Gas-Oil Ratio ID = Inner Diameter MD = Measured Depth OWC = Oil-Water Contact SPE = Society of Petroleum Engineers THP = Tubing Head Pressure TVD = True Vertical Depth TVDSS = True Vertical Depth Subsea WC = Water-cut WI = Water Injection WIF = Well Index Factor WOR = Water-Oil Ratio
  18. 18. xiv Conversion Factors 1 inch (“) = 0.0254 m 1 foot (ft) = 0.3048 m 1 cubic foot (scf) = 0.028317 m3 1 barrel = 0.158987 m3 1 pound (lb) = 453.592 g 1 bar = 105 Pa 1 psia = 6894.76 Pa 1 cP = 0.001 mPa.s API Gravity =
  19. 19. 1 Chapter One INTRODUCTION 1.1. Overview During production, pressure declines in the reservoir due to fluid extraction. Pressure also drops in the wellbore as fluid moves from bottom-hole to the wellhead. Typically, gas liberates from the liquid phase if the pressure drops below the bubble point in the reservoir or wellbore. Water is often produced with hydrocarbons either from natural aquifer encroachment or due to water injection. Due to increasing need for water injection to maintain reservoir pressure, mature fields typically have high water-cuts. Operators are always seeking ways to improve production efficiency, whilst minimising costs. The efficiency of a mature field is often associated with its capacity to process produced water. Initial topside design often doesn’t account for increasing water rate. As the water-cut increases, the topside fluid handling systems can become overloaded. Whether in separation, transmission or disposal, a high water rate reduces oil processing capacity and can threaten the economic viability of a field. (Arnold, 2004) As the water-oil ratio (WOR) increases, eventually, the cost of handling water approaches the value of the oil being produced. This is known as the WOR “economic limit”. Once this limit is reached wells are routinely shut-in and abandoned. (Bailey, 2000) Intermittent production, also termed skimming, is one way to continue production after the WOR economic limit has been reached. By periodically shutting in the well, accounting for the phase re-segregation phenomenon, water will gravitate out of the well, being replaced by reservoir oil/gas.
  20. 20. 2 The aim of well skimming is to produce the dry oil out the wellbore and shut-in again before the reintroduction of high water-cut. 1.2. Rationale Well skimming produces dry oil, which is the goal of all oil producers. Knowing the rate of phase re-segregation and being able to predict when the tubing is 100% oil/gas would enable the operator to optimise the frequency of well skimming. To approximate reservoir pressure from tubing head pressure (THP) data, engineers routinely use water cut prior to shut-in and THP, which has high error. Knowledge of the phase distribution in the wellbore during a shut-in would mean an accurate fluid density gradient could be determined and a better estimation of reservoir pressure. Accurate information about the phase distribution in the wellbore would also give engineers confidence during well intervention activities. Well jewellery such as oil swellable packers need to be covered in the oil phase to be set. 1.3. Aims/Objectives The aim of this project is to run simulations using dynamic wellbore software to estimate the time taken for phase re-segregation in a shut-in multiphase well for a range of starting water cuts. Sensitivity analysis will determine what parameters and conditions affect the rate of phase re-segregation. Additional objectives are to simulate well skimming and demonstrate phase re-segregation occurring in the reservoir during a prolonged shut- in.
  21. 21. 3 1.4. Methodology A literature review will be carried out into the phase re-segregation phenomenon. Well skimming as a production method will be explored and production data from the Dunlin Field’s skim wells will be analysed. The solving mechanisms of the software and its current applications will be reviewed. A sample well model will be set up and simulations run. Sensitivities will be investigated and results calibrated with data and empirical observations. The wellbore model will then be coupled to a near-wellbore reservoir model in order to simulate well skimming and demonstrate phase re- segregation occurring in the reservoir during a prolonged shut-in. Finally, conclusions will be made and recommendations given for further work. 1.5. Limitations and Constraints i.) An integrated dynamic wellbore/reservoir model has not been used to investigate the phase re-segregation phenomenon before. ii.) OLGA-ROCX is a recent software development and not yet widely used in the industry.
  22. 22. 4 Chapter Two LITERATURE REVIEW 2.1. Wellbore Storage Effects When a producing well is shut-in at surface, flow into the wellbore at sand-face continues for some time. The duration of this “after flow” is primarily dependent on three factors; the formation permeability, the wellbore volume and the compressibility of the fluids (Redman, 2008). If the fluid is highly compressible and the well flow rate is low, the influx period can be long. On the contrary, high flow rate wells with little gas have negligible periods of after-flow. (Speight, 2011) In a multiphase well, the second wellbore storage phenomenon is phase re-segregation. As reservoir influx ceases and the fluids in the wellbore stall, the effects of gravity and density difference will allow phase segregation. Depending on shut-in conditions and fluid properties, gas will separate from liquid, forming a gas cap at the top of the tubing, and oil will rise to the top of water due to buoyancy (Vai Yee, 2010). Stokes’ Law, defined in Appendix A, is valid for the buoyant rise velocity of oil dispersed in water. The greater the difference in density between the oil and water phases, the greater the vertical velocity. (Malhorta, 2009) When a well with a high gas/oil ratio is shut in, anomalous pressure build-up behaviour may occur due to phase segregation. If the wellbore pressure builds up to a value greater than reservoir pressure, back flow from the wellbore into producing zones can occur. Figure 1.1 illustrates the fluid dynamics of a multiphase well before and during a shut-in.
  23. 23. 5 Figure 1. 1: Wellbore Fluid Distribution (Adapted from: p295, Bellarby, 2009)
  24. 24. 6 2.2. Well Testing 2.2.1. Pressure Build-up Test A pressure transient test is a fluid-flow test conducted on wells to obtain well completion and reservoir data. During the test, flow rate is changed and the pressure response as a function of time is recorded. A pressure build-up test is performed on a well which has been producing at a constant rate and is then shut in. A pressure recorder is lowered into the well to record the pressure in the wellbore for several hours. Typically, soon after the well is shut-in, the fluids in the wellbore reach a quiescent state and bottom-hole pressure rises smoothly. This allows interpretable test results. Semi-log methods and type curve matching can be used for analysis. (Halliburton, 2000) 2.2.2. Pressure Transient Analysis During the period of wellbore storage, reservoir effects can be masked or distorted. If the wellbore storage effects are not properly recognised, they could be misinterpreted as reservoir characteristics, leading to errors in the identification of the reservoir model and calculations of parameters. Hence, the measured data must be critically evaluated before the pressure transient analysis. (Qasem et al, 2001) Wellbore storage effects last until pressure is equalized between the wellbore and formation (Qasem et al, 2001). In most circumstances, masking due to wellbore storage effects end after the early-time "hump" on a pressure derivative plot (Fig 2.1). Wellbore storage shows up as a unit slope at the start of the pressure test. ∆p and its derivative ∆p’ are proportional to the elapsed time and produce a 45o straight line on the log-log plot. On the derivative plot, the transition from wellbore storage effects to infinite acting radial flow gives
  25. 25. 7 a “hump” that gradually disappears as reservoir trends become recognisable. (Ahmed, 2011) Figure 2. 1: Wellbore storage on log-log pressure derivative plot (Redman, 2008) Wellbore phase re-segregation can result in a more complex transient trend. Phase segregation yields a net increase in the wellbore pressure due to the relative incompressibility of the liquid and the inability of the gas to expand in a closed system (Qasem et al, 2002). Bottom-hole pressure may temporarily build up to a value greater than reservoir pressure, resulting in an anomalous hump in the pressure response. Stegemeier and Matthews (1958) attributed this behaviour to rising bubbles of gas and the re-segregating of the phases in the wellbore. Different models have been developed to distinguish phase redistribution during well testing. Stegemeier and Matthews (1958) documented the relation of phase re-segregation to the pressure build-up hump and its size. The size of the hump was correlated with the volume of the gaseous phase in the tubing. Olarewaju (1989) discusses the similarity between pressure build-up behaviour in the transitional flow regime of dual
  26. 26. 8 porosity systems and distortion due to phase segregation, demonstrating how to differentiate between them. Different methods have been used to analyse phase redistribution during a build-up test. Fair (1981), Thompson et al. (1986) and Hageman et al. (1993) proposed mathematical models for phase re-segregation. In their models dimensionless pressure solutions were presented for type-curve matching. Fair (1981) used a simple exponential function to describe the pressure change resulting from the oil and gas segregation. Hageman et al. (1993) modified Fair’s method by using an error function to represent the pressure change when Fair’s model did not give a good fit of field data influenced by wellbore phase redistribution. Several authors, such as Winterfeld (1989), Hasan et al. (1994) and Xiao et al. (1995) developed numerical simulators to simulate counter-current flow during phase re-segregation. 2.3. Estimating Bottom-hole Pressure Due to operational and completion difficulties, it is generally not possible to record pressure data opposite the perforation zone. Hence, in many cases, pressure data is recorded at a depth above the sand-face and then converted to the pressure at the point of interest. For instance, using Equation 2.1, reservoir pressure can be estimated from THP. Knowledge of the fluid density gradient is required. Typical fluid density gradients are shown in Table 2.1. PR= THP + (depth * fluid density gradient) (Eq 2.1)
  27. 27. 9 Table 2. 1: Approximate Fluid Density Gradients Fluid Pressure Gradient (psi/ft.) Gas <0.15 Oil 0.25 to 0.35 Water 0.40 to 0.55 When there is more than one phase present in the wellbore, the conversion requires knowledge of the gradient of the fluid between the pressure gauge and the formation. Due to phase re-segregation, the fluid distribution can be constantly changing during shut-in. 2.3.1. Reservoir Pressure from Shut-in THP To approximate reservoir pressure from tubing head pressure data, engineers routinely use water cut prior to shut-in to calculate the fluid density gradient. This disregards the phase re-segregation phenomenon and can lead to erroneous, misleading results. During annual shutdowns, Fairfield Energy compare pressure build-up (PBU) data from producing wells with pressure falloff data from injection wells to estimate reservoir pressure at their Dunlin Field (Fig. 2.2). For production wells, after sufficient time to let the phases redistribute, the oil gradient can be used with confidence. For injection wells the water gradient is used. Pressures are calculated using Equation 2.1, with the fluid density gradients from Table 2.2. The datum depth is 9000ft TVDSS. Table 2. 2: Dunlin Field fluid density gradients Water Gradient 0.445psi/ft Oil Gradient 0.35psi/ft
  28. 28. 10 Dashed lines are pressure falloff data from injection wells, dots are PBU data from producers, assuming a 100% oil column during PBU. Figure 2. 2: Reservoir Pressure - From Shut-in THP Data (Source: Fairfield Energy, September 2014) Falloff and build-up data from 06/05/2013 to 22/11/2013 converge at around 4400psi. If the water-cut prior to shut-in was used instead of the oil gradient, given water-cuts are around 90%, the calculated pressure around producers would increase by 400 to 500psi resulting in pressures greater than around the injectors. In the pressure traverse plot (Fig 2.3), production wells P6 and P7 were at water-cuts above 90% whilst producing. Although producers have higher THPs than the injectors, the reservoir pressures are in fact lower using oil gradients during the closure.
  29. 29. 11 Figure 2. 3: Pressure Traverse. P7 & W4, P6 & W1 are Producer (P) and Injector (W) wells, Psat = Saturation Pressure at Reservoir Temperature (Source: Fairfield Energy, September 2014) The Dunlin Field produces from an under-saturated reservoir and THP remains above bubble point, however, for a producing well where THP drops below bubble point, the gas content in the tubing will need to be considered for calculating the fluid density gradient. 2.4. Skimming/Intermittent Production Many oil fields in the North Sea are reaching the end of their economic lifetime and effective reservoir management and application of new technologies are required to maximise recovery factors. Well skimming is one way to prolong the lifetime of high water-cut wells and increase recovery. By periodically shutting in the well for re- saturation and producing for a short time it is possible to produce oil with 0% water-cut.
  30. 30. 12 Table 2.3 considers water production and required water injection (WI) support for continuous production compared to well skimming for high water-cut wells. Table 2. 3: Voidage efficiency, skimming operation compared to continuous production Production Water Production Required WI Support Voidage Efficiency Oil Volume Water-cut Continuous Production Skimming Operation Continuous Production Skimming Operation Skimming Operation Compared to Continuous Production 10 90% 90 0 100 10 1000% 10 95% 190 0 200 10 2000% 10 99% 990 0 1000 10 10000% Without accounting for formation volume factors, the table above demonstrates the exponential benefits of well skimming as a mode of operation. 2.4.1. Case Study: Fairfield Energy, Dunlin Field (North Sea) Fairfield Energy have 6 oil producing wells that they produce by skimming in their Dunlin Field, North Sea. Production from skimming 6 wells is 4350 barrels in one month. Wells are normally skimmed every 5- 7 days. (Fig 2.4)
  31. 31. 13 Figure 2. 4: Production from ‘skim wells’ in the Dunlin Field, showing the variation in skim frequency and skim volume for each well. (Source: Fairfield Energy, June 2014.) One of the important factors is THP of the skim well; normally high shut- in THP gives a higher amount of flush oil. THP is therefore one of the main factors when considering skim frequency. Figure 2.5 compares skim volume to shut-in THP.
  32. 32. 14 Figure 2. 5: Skim volume compared to shut-in THP (bars: skim volume, scatter plot: THP). (Source: Fairfield Energy, June 2014.) THP charge can be correlated to the rate of phase re-segregation. As discussed in 2.2.2. Pressure Transient Analysis, phase re-segregation results in a net increase in wellbore pressure due to the inability of the volatile fluid to expand. During shut-in, the THP of well DA-30 charges slowly, hence it is skimmed every 7-11 days (Fig 2.6). For well DA-36, THP charges rapidly, therefore, it is skimmed every 4-5 days (Fig. 2.7).
  33. 33. 15 Figure 2. 6: Well DA-30: Tubing Head Pressure v Time (Source: Fairfield Energy, June 2014.) Figure 2. 7: Well DA-36: Tubing Head Pressure v Time (Source: Fairfield Energy, June 2014.)
  34. 34. 16 THP levelling off indicates the fluids have fully re-distributed in the wellbore with fluid pressure equalized between the wellbore and the formation. From Figure 2.7 it can be seen that DA-36 is skimmed once THP has peaked and levelled off at 89-90 barg. For the next skim (14/05) shut-in time has been reduced; as soon as THP has exceeded previous THP shut-in peak (89.57barg) the well is skimmed. Analysis of the data highlights the importance of shut-in THP charge for skimming wells. Tracking shut-in THP gives operators a good idea of when best to skim well in order to optimise skim frequency. Ideally, the skim frequency would be optimised so the well is produced as soon as the tubing string has become 100% oil/gas. 2.5. Phase Re-segregation in the Reservoir During long periods of shut-in it is possible for the phenomenon of phase re-segregation to occur in the reservoir. North Sea fields that have experienced such re-saturation include Dunlin, Piper and Donan/Dumbarton. Block 10 Area of the Dunlin Field that had been shut-in for 9 years, when re-developed, produced with a lower water-cut than when it was initially shut-in (Peters, 2011). In the Piper field, fluid redistribution and natural aquifer re-pressurisation occurred during the 4.5 years of shutdown. When Piper Bravo was redeveloped and came back on-stream, the production rate had significantly increased over the anticipated 1988 decline and a lower water-cut was achieved. (Harker, 1998) The Donan Field reached economic limit and was subsequently abandoned in 1997 at 71% water-cut, after producing 15.3 million STB. The field was redeveloped as the Dumbarton Field and ‘second oil’ was achieved in 2007. Early production performance was in line with
  35. 35. 17 expectations and the field produced 20 million STB over the next 2 years. (Manson, 2009) (Reekie, 2010) 2.6. OLGA OLGA is the industry standard software for transient simulation of multiphase flow. (Schlumberger, 2014) Society of Petroleum Engineers (SPE) publications by Hu et al. (2007) and Sagen et al. (2011) provide reviews of the software, describing its applications and solving mechanisms. With reference to these publications a brief overview is given in 2.6.1 OLGA Overview. 2.6.1. OLGA Overview Dynamic simulation is used extensively in both offshore and onshore developments to investigate transient behaviour in pipelines and wells. Transient modelling is vital for feasibility studies and field development design. Flow modelling and simulation provides valuable insights into flow behaviour, including the physics describing flow from reservoir to processing facilities. Transient simulation with OLGA provides an added dimension to steady- state analyses by predicting system dynamics such as time-varying changes in flow rates, temperature, pressure, fluid compositions and operational changes. The software uses an extensive collection of lab and field data to validate the multiphase flow models. Results are continuously implemented in the OLGA simulator to continually upgrade the technology to better match realities of operations. The simulation outputs provide an accurate prediction of key operational conditions involving transient flow. At each time step, a set of five
  36. 36. 18 coupled mass conservation equations are solved for: the oil droplets, the water droplets, the oil film, the water film and the gas phase. Three momentum equations are solved for the oil bulk, the water bulk and the gas/droplet field. The model is closed by a suitable set of closure laws describing the friction at the fluid interfaces and at the wall, the droplet deposition, and the droplet and bubble entrainment. One energy balance equation is solved for the fluid mixture, which assumes thermal equilibrium between all the phases at a specific location. When applied to simulate well flow transients, the OLGA model is capable of modelling complex well trajectories, advanced well completions, and the features of equipment such as valves and pumps. A heat transfer calculation function accounts for transient heat transfer between the formation and the annulus, and the annulus and tubing. (Hu et al. 2007) (Sagen et al. 2011) The dynamic well model is able to simulate the fluid redistribution during well shut-in by determining an accurate volume of each fluid phase at any position in the tubing over time. (Vai Yee, 2010) 2.6.2. Black Oil Correlation OLGA requires fluid properties to be entered either as a PVT fluid table or by using a black oil correlation. Separate software is required to construct a PVT fluid table. The black oil approach assumes three distinct phases: gas, oil and water. The oil and gas phases are recognised by their specific gravity, which are assumed constant. In the black oil model, the gas is considered to be dissolved in the oil phase, defined by the gas-oil ratio (GOR). The model typically treats PVT properties of the oil and gas phases as single functions of pressure and temperature. Therefore, oil and gas properties
  37. 37. 19 such as density, viscosity and specific volume are taken from experimental correlations at each pressure and temperature. (Pourafshary, 2007) 2.6.3. OLGA-ROCX Most reservoir simulations use vertical flow performance (VFP) tables to represent flow in the wellbore. This approach ignores the flow dynamics in wells, and the downstream processing and transportation. On the other hand, most dynamic wellbore models use pressure-rate equations to describe the inflow from the reservoir, which ignores the flow and pressure transients in the near-wellbore regions. Neither of the two types of modelling account for the transient reservoir- wellbore flow interactions. To bridge this modelling gap ROCX was developed. ROCX is a near- wellbore reservoir model that can be coupled to the OLGA simulator to perform integrated wellbore-reservoir transient simulations. ROCX is a three-dimensional model, capable of simulating three-phase flow in porous media. (Sagen et al, 2011) Flow and temperature equations are solved in three dimensions for saturations, temperatures and pressures in space and time. Flow rates of each phase are calculated at the well boundary at each time step. Input data required for the model include permeability and porosity of the formation, thermal properties of the rock and fluids, and fluid transport properties. Well and reservoir boundary conditions must be given. Initial conditions including pressure and saturation for each phase must also be defined. Outputs are in the standard industry formats, suitable for plotting with Microsoft Excel or reservoir simulator, Eclipse. The reservoir model is considered a plug-in to the wellbore model, with the integrated simulation fully controlled by the wellbore model. The
  38. 38. 20 numerical coupling between the two models is implemented in an implicit scheme, outlined in Appendix B. Hu et al. (2007) tested the integrated models with hypothetic cases. The dynamic phenomena of the selected cases was known, and therefore used to qualitatively verify the performance of the integrated model. Test results showed that the integrated model can more accurately predict well flow transients during shut-in/start-up and gas lift casing heading compared to the Inflow Performance Relationship (IPR) approach. Dynamic coning and cross-flow were also simulated successfully. The integrated model was also used to simulate a pressure build-up and drawdown test on an appraisal gas well. Results confirmed that the model can accurately match well testing data by tuning the skin factor. Thus, indicating the integrated model’s suitability for well testing design and estimating BHP when down-hole measurements are not possible. Chupin (2007) applied the integrated wellbore/reservoir model to examine liquid loading in a gas well. The integrated model provided more realistic results compared to methods where the reservoir and the wellbore were modelled separately. Hu et al (2010) tested the use of the integrated model to evaluate the cycling capability of liquid-loaded gas wells. The coupled model successfully simulated the well cycling. The results confirmed that the selected well can be cycled for a long period if the operator starts the cycling before the well becomes loaded with liquid. Outputs also showed that the average gas production can be more than doubled compared with the stable production rate if the choke was open permanently. Sagen et al. (2011) investigated two further applications for the OLGA- ROCX coupling. The first case aimed to simulate chemical squeeze of a low pressure layer in order to determine the most suitable operation procedure for chemical placement and start-up after the treatment. The second case aimed to calculate the pressure gradient at the near-
  39. 39. 21 wellbore area to optimise the bean-up procedure and prevent any sand production due to a high pressure gradient. Both cases were successfully simulated with results confirming that the integrated reservoir-wellbore model can easily find practical applications for well operations and interventions.
  40. 40. 22 Chapter Three OLGA MODEL 3.1. OLGA Well Data: Base Case The OLGA Well Graphical User Interface (GUI) allows the user to model a complete well from reservoir inflow to tubing head. Initially, a number of wells were modelled and simulated; well data and conditions were varied, and outputs recorded. As discussed in 2.6.1 OLGA Overview, the software takes into account all conditions and parameters affecting the fluids. For a simulation to run conditions must satisfy the governing equations and limitations of OLGA; any inaccuracies or unrealistic data result in simulation failure. Therefore, it was necessary to create a model similar to a real well. With reference to data from the Dunlin DA-36 well, a model was constructed (Fig. 3.1). Data and conditions of the real well were used; although the well model was made vertical, whereas DA-36 is deviated. Complete OLGA input data can be found in Appendix C.
  41. 41. 23 Well Model Figure 3. 1: OLGA Well Model: Base Case Casing Casing data is important for heat transfer calculations. Properties and depths were adapted from Well DA-36 to fit the vertical well. (Tab. 3.1)
  42. 42. 24 Table 3. 1: OLGA Input Casing Data Tubing Tubing properties are outlined in Table 3.2. Tubing length is 9317ft and inner diameter (ID) is 4.02in. The tubing head valve is at 495ft TVD (seabed) and there is a packer at 8089ft TVD. Table 3. 2: OLGA Input Tubing Data Reservoir The reservoir was modelled as under-saturated, where: ( ) (Eq 3.1) The top of the reservoir is at 11000ft TVD. Reservoir inflows are spread between 11000 and 12000ft TVD, each with Productivity Index (PI) = 10 STB/psi/day, making total PI = 50 STB/psi/day which is the estimated PI of Dunlin DA-36 well. Each inflow has conditions described in Table 3.3.
  43. 43. 25 Table 3. 3: OLGA Input Reservoir Conditions Fluid The Black oil approach was used (see 2.6.2. Black Oil Correlation), Gas- oil Ratio (GOR) and Bubble Point (BP) values were taken from a sample Dunlin fluid. Table 3. 4: Fluid Properties Base Case SG Oil 0.85 SG Gas 1 SG Water* 1 GOR 300 scf/STB Water-cut at Time of Shut-in 90% Bubble Point Pressure at Reservoir Temperature 66.33 bara *Dunlin produced water, SG = 1.028 (approx.). Value of 1 used for ease of calculation. Initial Conditions The simulation starts from shut-in conditions; pressures and temperatures correspond with DA-36 skim well data. (Table 3.5, 3.6)
  44. 44. 26 Table 3. 5: Casing Initial Conditions Table 3. 6: Tubing Initial Conditions Outputs Each simulation was run for 7 days; minimum time step 0.1s and maximum time Step 1s. Any larger time-step caused instabilities during simulation. For each simulation, outputs were requested to determine the rate of phase re-segregation. This was achieved using a profile plot of Phase Volume Fraction v Tubing Length. Therefore, at any time during the shut- in and at any position in the tubing the volume fraction of each phase was known. The THP response during shut-in is significant as discussed in 2.4. Skimming/Intermittent Production. A trend plot of Tubing Head Pressure v Shut-in Time was used.
  45. 45. 27 Chapter Four RESULTS/DISCUSSION In order to investigate the rate of phase re-segregation, for each case, the time taken for the tubing string to become 100% oil/gas was recorded. After running sensitivities on the well model; the near-wellbore simulator, ROCX, was coupled to the wellbore model to simulate well skimming and determine phase re-segregation occurring in the reservoir. 4.1. Base Case Starting from an initial shut-in water-cut of 90%, all of the water has gravitated out of the tubing and is replaced by oil/gas after 1.24 days. The rate of phase re-segregation in the tubing is constant throughout the shut-in period. (Fig. 4.1) Due to the initial shut-in THP being below bubble point pressure, some gas bubbles out of solution to form a gas cap at top of tubing. As THP charges above bubble point the gas re-dissolves.
  46. 46. 28 Figure 4. 1: Volume of each fluid in tubing changing during shut-in period Figure 4.2 shows THP starting to level off once the phases have fully re- distributed in the tubing at Time = 1.24 days. THP continues to rise at a steadier rate until it levels off completely at a peak of 92 bara at Time = 1.6 days. This continued THP charge after re-segregation in the tubing is due to phase re-segregation continuing in the wellbore (7” liner). The THP charge is steadier due to the increase in wellbore volume; Tubing ID 4.02”, Liner ID 6.185”. 0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 100% 0 0.2 0.4 0.6 0.8 1 1.2 1.4 FluidinTubing(vol%) Shut-in Time (Days) gas oil water
  47. 47. 29 Figure 4. 2: Base Case: Plot of THP v Shut-in Time also showing the volume fraction of each phase (gas, oil, water) in the tubing during shut- in period Figure 4.3 shows pressure response during the shut-in at a specified position in the tubing string, 3000ft TVD. As the oil/water contact level drops below the position of interest there is a sharp increase in pressure response due to the higher compressibility of the oil phase. Figure 4. 3: Pressure response during shut-in at 3000ft TVD
  48. 48. 30 4.2. Sensitivities For sensitivity analysis, conditions were kept the same as the base case, only changing the respective sensitivity. 4.2.1. Water-cut 60 – 90% Water-cut % at time of shut-in was varied from 60% to 90%. Table 4. 1: Simulation Results Water-cut (%) Re-segregation Time - Tubing 100% oil/gas (Days) 60 0.79 70 0.919 80 1.047 90 1.24 A lower initial water-cut results in a higher initial THP due to the higher volume of compressible fluid (oil/gas) in the wellbore. THP charges and peaks quicker, corresponding with a faster rate of phase re-segregation. For water-cuts 60-80%, THP charges rapidly to a value greater than bubble point pressure so practically no gas is released (Fig. 4.4).
  49. 49. 31 Figure 4. 4: Plot of THP v Shut-in Time also showing when the tubing has become 100% oil/gas 4.2.2. Water-cut 90 – 98% Water-cut % at time of shut-in was varied from 90% to 98%. As water-cut % is increased above the base case, THP charges slower and the fluids take longer to segregate. Table 4. 2: Water-cut 90 – 98% Simulation Results Water-cut (%) Re-segregation Time - Tubing 100% oil/gas (Days) 90 1.24 94 2.029 98 6.01 The slower rate of THP charge results in some gas coming out of solution, for water-cut 94% and 98%. This is evident as a small hump in the THP response between Day 0 and Day 2 on Figure 4.6.
  50. 50. 32 Figure 4. 5: WC 94%: Plot of THP v Shut-in Time also showing the volume fraction of each phase (gas, oil, water) in the tubing during shut- in period Figure 4. 6: WC 98%: Plot of THP v Shut-in Time also showing the volume fraction of each phase (gas, oil, water) in the tubing during shut- in period
  51. 51. 33 Using the profile plot, the oil-water contact (OWC) can be determined during the shut-in period (Fig. 4.7). During the early period of shut-in (<0.5 days) fluids are unstable and OWC is not distinguishable. Tubing Depth is from the top of tubing, which is at seabed level. Tubing length is 9317ft, the data labels show when tubing becomes 100% oil/gas. Figure 4. 7: OWC for different WC % at time of shut-in 4.2.3. Gas-Oil Ratio (GOR) The effect of GOR on rate of re-segregation was investigated. Results showed that as GOR increases the time taken for phase re- segregation decreases. (Fig. 4.8) 1.24, -9317 2.03, -9317 6.01, -9317 -10000 -9000 -8000 -7000 -6000 -5000 -4000 -3000 -2000 -1000 0 0 1 2 3 4 5 6 7 TubingDepth(ft) Shut-in Time (Days) Oil-Water Contact Level During Shut-in WC = 90% WC = 94% WC = 98%
  52. 52. 34 Figure 4. 8: The effect of changing GOR on Re-segregation Time A higher GOR results in a faster rate of phase re-segregation. This correlates with a steeper rise in THP, and higher THP peak. Figure 4. 9: Plot of THP v Shut-in Time for GOR 100 – 500 scf/STB 1.05 1.1 1.15 1.2 1.25 1.3 1.35 100 200 300 400 500 Re-SegregationTime(Days) GOR (scf/STB) Re-segregation Time v GOR
  53. 53. 35 The results show that changing GOR affects the rate of phase re- segregation. However, in reality, a change in GOR would also change the oil density and bubble point pressure. 4.2.4. Oil Density In order to compare the effects of different densities of oil, sample cases for heavier oil and a more volatile oil were created. Oil specific gravity (SG) was altered as well as GOR and Bubble Point Pressure to represent typical properties of heavier oil and a volatile oil. Oil properties were taken from McCain (1990) and bubble points estimated based on the GLASO correlation for the North Sea. Table 4.3 shows the oil properties and the simulation results. Table 4. 3: Oil Properties and Simulation Results SG 0.75 (Volatile Oil) SG 0.85 (Base Case) SG 0.95 (Heavy Oil) APIo 57.5 35 17.5 GOR (scf/STB) 800 300 100 Bubble Point Pressure (bara) 150 66.3 30 Re-segregation Time (Tubing 100% oil/gas) 1.18 days 1.24 days 1.52 days
  54. 54. 36 Figure 4. 10: Plot of THP v Shut-in Time for Oil SG 0.75 – 0.95 For volatile oil (SG = 0.75), the gas coming out of solution results in rapid THP charge, and fast phase re-segregation. Figure 4. 11: Volume of each fluid in tubing changing during shut-in period 0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 100% 0 0.2 0.4 0.6 0.8 1 1.2 FluidinTubing(vol%) Shut-in Time (Days) gas oil water
  55. 55. 37 For heavy Oil (SG = 0.95), there is no gas coming out of solution, high density oil means difference in densities between oil and water is small resulting in slow THP charge and longer time for re-segregation. Figure 4. 12: Volume of each fluid in tubing changing during shut-in period Fig. 4.13 compares the OWC level during shut-in for the different sample cases. Data labels show when the tubing becomes 100% oil/gas. 0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 100% 0 0.2 0.4 0.6 0.8 1 1.2 1.4 1.6 FluidinTubing(vol%) Shut-in Time (Days) gas oil water
  56. 56. 38 Figure 4. 13: OWC for different WC % at time of shut-in 4.2.5. Tubing Size Sample cases showed that a smaller tubing ID results in faster THP charge and a faster rate of phase re-segregation (see plots in Appendix D). This can be attributed to the reduced volume of the tubing string; less space for oil/gas expansion and less fluids in the tubing to segregate. 4.2.6. Deviated Well A deviated well was constructed, with inclination increasing 7.5o for every 1000ft TVD, well data and simulation results are in Appendix E. Simulation results show that for wells with shut-in water-cut of 90% and 94%, phases segregated quicker in a deviated well compared to a vertical well. The deviated well has larger wellbore volume (Deviated MD 1.18, -9317 1.24, -9317 1.52, -9317 -10000 -9000 -8000 -7000 -6000 -5000 -4000 -3000 -2000 -1000 0 0.4 0.6 0.8 1 1.2 1.4 1.6 TubingDepth(ft) Shut-in Time (Days) Oil-Water Contact Level During Shut-in Oil SG = 0.75 Oil SG = 0.85 Oil SG = 0.95
  57. 57. 39 = 17598ft, Vertical MD = 12000ft) which will affect the rate of phase re- segregation. Additionally, different flow regimes could explain the faster rate of phase re-segregation. For a high water-cut production well the likely flow regime is bubble flow – droplets of oil evenly dispersed in water. However, in deviated wells, there could be stratified or wavy stratified flow. As pipe deviation is increased; gravity ensures there is a higher concentration of oil in the upper section (Fig 4.14). (Catala, 1996) Figure 4. 14: Fluid distribution for different well deviations (Adapted from Catala, 1996) Further investigation would be required to determine flow regimes during production and how this affects the rate of phase re-segregation during shut-in conditions. 4.3. OLGA-ROCX The dynamic wellbore model (OLGA) was coupled to a near wellbore reservoir model (ROCX) to simulate well skimming and investigate fluid behaviour in the near wellbore area during a prolonged shut-in. The coupled model creates a more accurate representation of fluid dynamics in the wellbore and near wellbore by taking into account reservoir effects. The OLGA wellbore reservoir inflow considers PI,
  58. 58. 40 pressure, temperature and fluid properties; whereas, OLGA coupled with ROCX also considers the reservoir characteristics and properties. 4.3.1. Skimming A vertical well model was setup with TVD 11300ft (Fig 4.15), for complete well data see Appendix F. The near-wellbore model was coupled to the wellbore at 11250ft. The wellbore penetrates vertically through the centre block of the reservoir grid. Figure 4. 15: Well Model OLGA-ROCX The near-wellbore reservoir data is summarized in Tables 4.4 - 4.6. For full ROCX input data, see Appendix G. Reservoir conditions are constant throughout the simulation.
  59. 59. 41 Table 4. 4: Reservoir properties Reservoir Grid (x, y, z) (5x20m) x (5x20m) x (5x10m) Porosity (Φ) 0.25 Rock Compressibility 6.525 x 10-5 1/bar (Pref 413.8 bara) Permeability (x, y, z) 1000 mD SWC 0.15 SOR 0.18 SGR 0 Initial Pressure 344.46 bara Temperature 104.44 o C There are two boundaries of the coupled model, the wellbore/well interface and the reservoir outer boundary. Table 4. 5: Well boundary conditions Pressure (bara) Skin PI Temperature (o C) Sw So Sg 344.46 0 50 104.44 0.9 0.1 0 Table 4. 6: Reservoir boundary conditions Pressure (bara) Temperature (o C) Sw So Sg 344.46 104.44 0.9 0.1 0 Results Parameters such as shut-in period, skim time and valve opening (%) were varied to optimise skimming frequency and skim time.
  60. 60. 42 Simulation results show that after a shut-in period of 2.092 days the tubing is 100% oil/gas, and after 2.89 days the full wellbore is 100% oil/gas (Fig 4.16). Figure 4. 16: Well Skimming: Plot of THP v Shut-in Time also showing the volume fraction of each phase (gas, oil, water) in the tubing during shut-in period Therefore, the well is shut-in for 3 days (72 hours) and then opened for 4 hours to get flush oil out before re-introduction of high water-cut (Fig 4.17 – 4.19). Figure 4. 17: Volumetric Flow Rates during well skimming
  61. 61. 43 Figure 4. 18: Volumetric Flow Rate, 70 - 80 hours Figure 4. 19: If the valve is opened for longer (5 hours), high WC is reinstated The results show that well skimming can be effectively simulated and frequency of skimming and skim time can be optimised to maximise recovery of dry oil.
  62. 62. 44 4.3.2. Re-segregation in the Reservoir An integrated model was setup, a smaller reservoir grid was used to maximise simulation duration. A vertical well model was setup with TVD 11300ft, for well data see appendix F. The near-wellbore model was coupled to the wellbore at 11250ft. The wellbore penetrates vertically through the centre block of the reservoir grid. The near-wellbore reservoir data is summarized in Tables 4.7 - 4.9. Apart from the reservoir grid model, input data is the same as detailed in Appendix G. Reservoir conditions are constant throughout the simulation. Table 4. 7: Reservoir properties Reservoir Grid (x, y, z) (5x5m) x (5x5m) x (5x5m) Porosity (Φ) 0.25 Rock Compressibility 6.525 x 10-5 1/bar (Pref 413.8 bara) Permeability (x, y, z) 1000 md SWC 0.15 SOR 0.18 SGR 0 Initial Pressure 344.46 bara Temperature 104.44 o C There are two boundaries of the coupled model, the wellbore/well interface and the reservoir outer boundary.
  63. 63. 45 Table 4. 8: Well boundary conditions Pressure (bara) Skin PI Temperature (o C) Sw So Sg 344.46 0 50 104.44 0.9 0.1 0 Table 4. 9: Reservoir boundary conditions Pressure (bara) Temperature (o C) Sw So Sg 344.46 104.44 0.9 0.1 0 Results ROCX outputs are produced as text files and can be plotted with Eclipse plotting tool, Floviz. From the simulation, commencement of re- segregation is clear at Day 20. (Fig. 4.19, 4.20)
  64. 64. 46 Figure 4. 20: Day 1, Oil Saturation ~0.1 (90% WC) Figure 4. 21: Day 20, Oil Saturation ~0.16 at the top of reservoir, near- wellbore area. In the wellbore during shut-in, the phase re-segregation phenomenon sees oil rise above water with the OWC level dropping. Simulation results
  65. 65. 47 show that the phenomenon continues into the reservoir during a prolonged shut-in. 4.4. Evaluation of software OLGA has been proven to be an effective tool and has many potential applications for production operations and well intervention activities. Due to the level of accuracy of the outputs, there is a lot of data input required, if sufficient data is not available this can be problematic. When coupling the reservoir model to the wellbore model; the time step to avoid instabilities has to be 0.1s-1s, whereas the ROCX time-step can be set to 1 hour. As the models run together, the OLGA time step limits the speed and produces large files as outputs are calculated at every time step. Consequently, for the coupled model the maximum simulation duration was 20 days. In the version of ROCX used, sources could not be used in combination with the black-oil mode. Therefore, it was not possible to include a water injection well in the reservoir model. This is only possible when a PVT fluid table used, which requires separate software.
  66. 66. 48 Chapter Five CONCLUSIONS AND RECOMMENDATIONS 5.1. Conclusions Phase re-segregation was successfully simulated using dynamic wellbore modelling and well skimming was effectively simulated with an integrated wellbore-reservoir model. It was also possible to demonstrate the onset of phase re-segregation in the reservoir during a prolonged shut-in. Rate of phase re-segregation 1. Simulation results show that as the water-cut at time of shut-in is increased the time taken for phase re-segregation increases. Results confirmed empirical observations that in 90% water-cut wells, the phases redistribute completely in less than a week with the tubing becoming 100% oil/gas; all the water gravitated out of the well, being replaced by reservoir oil. For the sample well model, for a shut-in water-cut of 90% the tubing is 100% oil after 1.24 days. If shut-in water-cut set at 98% the tubing string is 100% oil/gas after 6.01 days. 2. Simulation output plots confirmed that the rate of phase re- segregation is linked to THP charge. THP is expected to increase initially for a period after shut in and eventually stabilise after the well has been shut in long enough for fluids to come to equilibrium. Results showed that a rapid THP charge correlates with a faster rate of phase re-segregation. This is consistent with data analysed from the North Sea, Dunlin Field. It is evident from simulation results that any gas coming out of solution during shut-in period results in rapid THP charge, this agrees with theory based on the inability of the gas to expand in a closed system.
  67. 67. 49 3. Oil density (SG) was altered as well as GOR and bubble point to represent typical properties of heavier oil and volatile oil. Results show that for the heavier oil phase re-segregation takes longer. This is attributed to the smaller difference in densities between oil and water and no release of gas due to the lower bubble point pressure. For the volatile oil, gas coming out of solution results in rapid THP charge, and the larger difference in densities results in a faster rate of phase re-segregation. Skimming 4. Well skimming was successfully simulated with OLGA-ROCX. For a well with water-cut 90% at time of shut-in, it was possible to optimise skim time and frequency of skimming to maximise recovery of dry oil. Simulation results show dry oil can be produced for 4 hours once every 3 days. 5. The THP character was the same as Fairfield skimming data, charging at a constant rate during phase re-segregation and levelling off once fluids have fully redistributed. Re-segregation in the Reservoir 6. From the Eclipse simulation it is evident that phase re-segregation will occur in the reservoir during a prolonged shut-in. There is potential for re-saturation to occur in any reservoir during a prolonged period of closure for any well with water-cut less than 100% at time of shut-in. This suggests vast opportunity for the redevelopment of abandoned fields.
  68. 68. 50 5.2. Recommendations 1. From the simulations carried out with sample well models, it is clear that if a model is set up to match a producing well it is possible to determine the rate of phase re-segregation. For this, an exact model would need to be set up with accurate well, production and reservoir data. The input data requirements and limitations of OLGA make this a complex undertaking. Model inputs can be manipulated to match flowing conditions of a well. Once the model is correlated with real data it is then possible to save the case at a specific time during the simulation as a restart case. This means separate identical models can be duplicated and initial conditions set to the restart case. Thus, allowing the user to investigate different cases and varying parameters for the same initial conditions. 2. Potential to produce dry oil from redundant wells is very appealing. Well skimming allows production of dry oil from mature fields where water-cut is too high to produce continually. This method of production is worth consideration to maximise economic recovery from mature North Sea oil fields. 3. As software advances, in the future we can expect to accurately simulate phase re-segregation in the reservoir using wellbore- reservoir modelling. 4. A potential application of OLGA-ROCX is the modelling of cross- flow in long term shut-in wells. Particularly in abandoned fields where different zones in wells are left open, leaving fluids free to use them as pathways for reservoir fluid distribution.
  69. 69. 51 REFERENCES AHMED A and MEEHAN N., 2011. Advanced Reservoir Management and Engineering. Gulf Professional Publishing ARNOLD ET AL., 2004. Managing Water—From Waste to Resource. Oilfield Review: Summer 2004. [online]. Available from: https://www.slb.com/~/media/Files/resources/oilfield_review/ors04/sum 04/04_managing_water.pdf [Accessed 13 August 2014] BAILEY ET AL., 2000. Water Control. Oilfield Review: Spring 2000. [online]. Available from: http://water.slb.com/~/media/Files/resources/oilfield_review/ors00/spr0 0/p30_51.pdf [Accessed 12 August 2014] BELLARBY J., 2009. Well Completion Design. Elsevier CATALA G ET AL., 1996. Fluid Flow Fundamentals. Oil Field Review Winter 1996. [online]. Available from: http://scholar.google.co.uk/scholar_url?hl=en&q=http://www.onesubsea .com/~/media/Files/resources/oilfield_review/ors96/win96/12966164.pdf &sa=X&scisig=AAGBfm1wFp0G6nltAX-gYQyHE4x0gOTV- g&oi=scholarr&ei=2H8VVP-qHoTSaOHKgJgM&ved=0CB8QgAMoADAA [Accessed 27 August 2014] CHUPIN ET AL., 2007. Integrated Wellbore/Reservoir Model Predicts Flow Transients in Liquid-Loaded Gas Wells. Society of Petroleum Engineers. [online]. Available from: https://www.onepetro.org/conference- paper/SPE-110461-MS [Accessed 28 August 2014]
  70. 70. 52 FAIR WB., 1981. Pressure Buildup Analysis with Phase Redistribution. Society of Petroleum Engineers. USA. [online]. Available from: https://www-onepetro-org.ezproxy.rgu.ac.uk/journal-paper/SPE-8206- PA [Accessed 28 August 2014] HAGEMAN PS and JOSEPH JA., 1993. Well Test Analysis With Changing Wellbore Storage. Society of Petroleum Engineers. USA. [online]. Available from: https://www-onepetro-org.ezproxy.rgu.ac.uk/journal- paper/SPE-21829-PA [Accessed 06 August 2014] HALLIBURTON., 2000. Well Test Analysis. Halliburton. [online]. Available from: http://www.scribd.com/doc/228494176/16/blank [Accessed 30 June 2014] HARKER SD., 1998. The palingenesy of the Piper oil field, UK North Sea. Petroleum Geoscience Vol 4, No 3, August 1998 pp. 271 – 286. HASAN AR and KABIR CS., 1994. Modeling Changing Storage During a Shut-in Test. Society of Petroleum Engineers. USA. [online]. Available from: https://www-onepetro-org.ezproxy.rgu.ac.uk/journal-paper/SPE- 24717-PA [Accessed 28 August 2014] HU ET AL., 2007. Integrated Wellbore-Reservoir Dynamic Simulation. Society of Petroleum Engineers. [online]. Available from: https://www- onepetro-org.ezproxy.rgu.ac.uk/conference-paper/SPE-109162-MS [Accessed 20 August 2014]
  71. 71. 53 HU ET AL., 2010. Use of Wellbore-Reservoir Coupled Dynamic Simulation to Evaluate the Cycling Capability of Liquid-Loaded Gas Wells. Society of Petroleum Engineers. [online]. Available from: https://www-onepetro- org.ezproxy.rgu.ac.uk/conference-paper/SPE-134948-MS [Accessed 20 August 2014] MALHORTA ET AL., 2009. Recent Advances in Mineral Processing Plant Design. Society for Mining, Metallurgy and Exploration. MANSON ET AL. 2009. Field Redevelopment Accomplished Using Advanced RSS. World Oil May 2009, Vol. 230 No. 5 p51 – 53. [online]. Available from: http://www.worldoil.com/May-2009-Field- redevelopment-accomplished-using-advanced-RSS.html [Accessed 25 August 2014] MCCAIN WD., 1990. The Properties of Petroleum Fluids. Pennwell Books OLAREWAJU JS and LEE WJ., 1989. Effects of Phase Segregation on Buildup Test Data From Gas Wells. Society of Petroleum Engineers. USA. [online]. Available from: https://www-onepetro- org.ezproxy.rgu.ac.uk/conference-paper/SPE-19100-MS [Accessed 20 August 2014] PETERS T., 2011. Dunlin Field - Recovery of Stranded Oil From the Block 10 Area. DEVEX 2011. [online]. Available from: http://www.devex- conference.org/pdf/Presentations_2011/Dunlin%20Field%20- %20Recovery%20of%20Stranded%20Oil%20From%20the%20Block%20 10%20Area.pdf [Accessed 01 August 2014]
  72. 72. 54 POURAFSHARY P., 2007. A Coupled Wellbore/Reservoir Simulator to Model Multiphase Flow and Temperature Distribution. [online]. Available from: http://repositories.lib.utexas.edu/bitstream/handle/2152/3638/pourafsha ryd52151.pdf?sequence=2 [Accessed 23 June 2014] QASEM FH, NASHAWI IS and MIR MI., 2001. SPE 67239: A New Method for the Detection of Wellbore Phase Redistribution Effects During Pressure Transient Analysis. Society of Petroleum Engineers. USA. [online]. Available from: https://www.onepetro.org/conference- paper/SPE-67239-MS [Accessed 24 June 2014] QASEM FH, NASHAWI IS and MIR MI., 2002. Detection of Pressure Buildup Data Dominated by Wellbore Phase Redistribution Effects. Journal of Petroleum Science and Engineering, 2002, 34, 109-122. KUWAIT. [online]. Available from: http://www.sciencedirect.com/science/article/pii/S0920410502001584# [Accessed 24 June 2014] REDMAN M., 2008. The Effect of Wellbore Storage on Surface Data. Halliburton. [online]. Available from: http://www.spidr.com/oil-and- gas/The-Effect-of-Wellbore-Storage-on-Surface-Data/subpage53.html [Accessed 26 July 2014] REEKIE ET Al., 2010. An old field in a new landscape: the renaissance of Donan. Geological Society, London, Petroleum Geology Conference series 2010, v. 7, p. 431-450. UK. [online]. Available from: http://pgc.lyellcollection.org/content/7/431.abstract [Accessed 23 July 2014]
  73. 73. 55 SAGEN ET AL., 2011. A Dynamic Model for Simulation of Integrated Reservoir, Well and Pipeline System. Society of Petroleum Engineers. USA. [online]. Available from: https://www-onepetro- org.ezproxy.rgu.ac.uk/conference-paper/SPE-147053-MS [Accessed 23 June 2014] SCHLUMBERGER 2014. OLGA Dynamic Multiphase Flow Simulator. www.software.slb.com. [online]. Available from: http://www.software.slb.com/products/foundation/Pages/olga.aspx [Accessed 23 June 2014] SPEIGHT JG., 2011. An Introduction to Petroleum Technology, Economics, and Politics. John Wiley and Sons STEGEMEIER GL and MATTHEWS CS., 1958. A Study of Anomalous Pressure Build-Up Behavior. Petroleum Transactions, AIME. Society of Petroleum Engineers. USA. [online]. Available from: https://www- onepetro-org.ezproxy.rgu.ac.uk/general/SPE-927-G [Accessed 23 June 2014] THOMPSON ET AL. 1986. Analysis of Pressure Buildup Data Influenced by Wellbore Phase Redistribution. Society of Petroleum Engineers. USA. [online]. Available from: https://www-onepetro- org.ezproxy.rgu.ac.uk/journal-paper/SPE-12782-PA [Accessed 23 June 2014] VAI YEE H, ZAINAL S and SAAID I., 2010. SPE 127850: Transient Well Performance Modeling for Reservoir Pressure Determination. Society of Petroleum Engineers. EGYPT. [online]. Available from:
  74. 74. 56 https://www.onepetro.org/conference-paper/SPE-127850-MS [Accessed 23 June 2014] WINTERFELD PH., 1989. Simulation of Pressure Buildup in a Multiphase Wellbore/Reservoir System. Society of Petroleum Engineers. [online]. Available from: https://www-onepetro-org.ezproxy.rgu.ac.uk/journal- paper/SPE-15534-PA [Accessed 23 June 2014] XIAO JJ, FUENTES-N FA and REYNOLDS AC., 1995. SPE 26965: Modeling and Analyzing Pressure Buildup Data Affected by Phase Redistribution in the Wellbore. Society of Petroleum Engineers. USA. [online]. Available from: https://www.onepetro.org/journal-paper/SPE-26965-PA [Accessed 23 June 2014]
  75. 75. 57 BIBLIOGRAPHY CLUVER C., 2009. Interpreting Pressure Transient Tests. Halliburton. [online]. Available from: http://www.spidr.com/oil-and-gas/Interpreting- Pressure-Transient-Tests/subpage82.html&upd=qqyes [Accessed 12 August 2014] DAKE LP., 1978. Fundamentals of Reservoir Engineering, Elsevier Science KING GE., 2009. Well Testing. GEK Engineering. [online]. Available from: http://gekengineering.com/Downloads/Free_Downloads/Well_Testing.pdf # [Accessed 12 August 2014] MATTAR L and SANTO M., 1992. How Wellbore Dynamics Affect Pressure Transient Analysis. Journal of Canadian Petroleum Technology, April 1992, 9, 63-70. CANADA. [online]. Available from: https://www.onepetro.org/download/journal-paper/PETSOC-92-02- 03?id=journal-paper%2FPETSOC-92-02-03 [Accessed 24 June 2014] MCCAIN WD., 1990. The Properties of Petroleum Fluids. Pennwell Books POURAFSHARY P., 2007. A Coupled Wellbore/Reservoir Simulator to Model Multiphase Flow and Temperature Distribution. [online]. Available from: http://repositories.lib.utexas.edu/bitstream/handle/2152/3638/pourafsha ryd52151.pdf?sequence=2 [Accessed 23 June 2014]
  76. 76. 58 APPENDICES
  77. 77. 59 Appendix A Stokes Law ( ) (Eq A.1) Where: v = velocity of the rising oil droplet, cm/s gc = gravitational acceleration constant, cm/s2 Δρ = difference in density between the oil and water phases, g/cm3 dp = oil droplet diameter, cm μL = viscosity of the water, g/cm.s (Malhorta, 2009)
  78. 78. 60 Appendix B OLGA-ROCX Coupling The numerical coupling between the integrated models is implemented in an implicit scheme described by Hu et al (2007) and Sagen et al (2011). The notion is that the reservoir model calculates a sensitivity coefficient for the production rate with respect to the wellbore pressure at each time step and makes it available for the wellbore flow model. At the next time step, the wellbore model uses this sensitivity coefficient to solve the new wellbore pressure. The principle of the model coupling is summarised below: 1. Assuming the models have been integrated up to time step n, the wellbore model begins integration to time step n+1 by requesting the reservoir model to calculate the sensitivity coefficients and , which are used in Equation B.1: (Eq B.1) Where is the pressure in the wellbore, is the mass flow rate with the subscript referring to the phase, ie. gas, oil or water. 2. The wellbore model uses the above relationship as a boundary condition and solves for the complete model. The wellbore model has now completed time step n+1 and sends and to the reservoir model. 3. The reservoir model completes its time step n+1 calculation by using the wellbore model supplied boundary condition. The sensitivity coefficient is calculated by: (Eq B.2) And is given by: (Eq B.3)
  79. 79. 61 Appendix C OLGA Well Base Case: Input Data Casing Table C. 1: OLGA Input Casing Data Figure C. 1: Casing Visualisation (depth in metres)
  80. 80. 62 Figure C. 2: Casing Specifications
  81. 81. 63 Tubing Table C. 2: OLGA Input Tubing Data Figure C. 3: Tubing Visualisation (depth in metres)
  82. 82. 64 Heat Transfer Table C. 3: Ambient Temperature Table C. 4: Formation Heat Transfer Properties Table C. 5: Fluid outside production tubing Reservoir The reservoir was modelled as under-saturated, where: ( ) (Eq 3.1) The top of the reservoir is at a depth of 11000ft TVD. Reservoir inflows are spread between 11000 and 12000ft TVD. 5 inflows, each PI = 10 making total PI of 50 STB/psi/day which is the estimated PI of Dunlin DA-36 well. Table C. 6: Each inflow has conditions set
  83. 83. 65 Fluid The Black oil approach was used (see 2.6.2. Black oil Correlation), GOR and Bubble Point values were taken from a sample Dunlin fluid. Table C. 7: Fluid Properties Base Case SG Oil 0.85 SG Gas 1 SG Water* 1 GOR 300 scf/STB Water-cut at Time of Shut-in 90% Bubble Point Pressure at Reservoir Temperature 66.33 bara *Dunlin produced water, SG = 1.028 approx. Value of 1 used for ease of calculation. Table C. 8: Production Top Boundary Conditions Initial Conditions Table C. 9: Casing Initial Conditions
  84. 84. 66 Table C. 10: Tubing Initial Conditions
  85. 85. 67 Appendix D Tubing Size Tubing ID 3”: Re-segregation Time (Tubing 100% oil/gas) = 1.171 days Figure D. 1: Tubing ID 3”: Plot of THP v Shut-in Time also showing the volume fraction of each phase (gas, oil, water) in the tubing during shut- in period
  86. 86. 68 Tubing ID 4.02”: Re-segregation Time (Tubing 100% oil/gas) = 1.24 days Figure D. 2: Tubing ID 4.02”: Plot of THP v Shut-in Time also showing the volume fraction of each phase (gas, oil, water) in the tubing during shut-in period Tubing ID 5”: Re-segregation Time (Tubing 100% oil/gas) = 1.898 days Figure D. 3: Tubing ID 5”: Plot of THP v Shut-in Time also showing the volume fraction of each phase (gas, oil, water) in the tubing during shut- in period
  87. 87. 69 Appendix E Deviated Well Profile Table E. 1: Deviated Well Profile TVD 12000ft, MD 17598ft
  88. 88. 70 Figure E. 1: Deviated Well Survey Casing and Tubing Casing is the same as the base case (see Appendix C); the 7” liner is extended to MD 17598ft. Tubing string is same length as vertical well, 9317ft. The tubing head valve is at 495ft TVD (seabed) and there is a packer at 8089ft TVD. Reservoir Reservoir inflows are located between 11000 and 12000 TVD, consistent with the base case.
  89. 89. 71 Fluid data and conditions are consistent with the base case, as described in Appendix C. Results WC 90%: Re-segregation Time (Tubing 100% oil/gas) = 0.858 days Figure E. 2: Deviated Well WC 90%: Plot of THP v Shut-in Time also showing the volume fraction of each phase (gas, oil, water) in the tubing during shut-in period
  90. 90. 72 WC 94%: Re-segregation Time (Tubing 100% oil/gas) = 1.029 days Figure E. 3: Deviated Well WC 94%: Plot of THP v Shut-in Time also showing the volume fraction of each phase (gas, oil, water) in the tubing during shut-in period
  91. 91. 73 Appendix F OLGA-ROCX Well Data Well Model Figure F. 1: Well Model OLGA-ROCX
  92. 92. 74 Casing and Tubing Table F. 1: OLGA-ROCX Casing Data The tubing head valve is at 495ft TVD (seabed) and there is a packer at 8089ft TVD. Table F. 2: OLGA-ROCX Tubing Data Near-wellbore The near-wellbore model is coupled to the wellbore model at 11250ft TVD. Fluid data and conditions are consistent with the base case, as described in Appendix C.
  93. 93. 75 Appendix G ROCX Input File Figure G. 1: ROCX Grid Figure G. 2: ROCX Fluid Properties
  94. 94. 76 Figure G. 3: ROCX Reservoir Properties Figure G. 4: ROCX Kr and Pc
  95. 95. 77 Figure G. 5: ROCX Initial Conditions Figure G. 6: ROCX Boundary Conditions (Well)
  96. 96. 78 Figure G. 7: ROCX Boundary Conditions (Reservoir) Figure G. 8: ROCX Simulation
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