Physical and Numerical Modeling of SAGD Under New Well ...

University of Calgary

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2013-09-23

Physical and Numerical Modeling of SAGD Under New

Well Configurations

Tavallali Mohammad

Tavallali M (2013) Physical and Numerical Modeling of SAGD Under New Well Configurations

(Unpublished doctoral thesis) University of Calgary Calgary AB doi1011575PRISM27348

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doctoral thesis

University of Calgary graduate students retain copyright ownership and moral rights for their

thesis You may use this material in any way that is permitted by the Copyright Act or through

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UNIVERSITY OF CALGARY

Physical and Numerical Modeling of SAGD Under New Well Configurations

by

Mohammad Tavallali

A THESIS

SUBMITTED TO THE FACULTY OF GRADUATE STUDIES

IN PARTIAL FULFILMENT OF THE REQUIREMENTS FOR THE

DEGREE OF DOCTOR OF PHILOSOPHY

DEPARTMENT OF CHEMICAL amp PETROLEUM ENGINEERING

CALGARY ALBERTA

SEPTEMBER 2013

copy Mohammad Tavallali 2013

ii

ABSTRACT

This research was aimed at investigating the effect of well configuration on SAGD

performance and developing a methodology for optimizing the well configurations for

different reservoir characteristics The role of well configuration in determining the

performance of SAGD operations was investigated with help of numerical and physical

models

Since mid 1980rsquos SAGD process feasibility has been field tested in many successful

pilots and subsequently through several commercial projects in various bitumen and

heavy oil reservoirs Although SAGD has been demonstrated to be technically successful

and economically viable it still remains very energy intensive extremely sensitive to

geological and operational conditions and an expensive oil recovery mechanism Well

configuration is one of the major factors which affects SAGD performance and requires

greater consideration for process optimization

Several well patterns were numerically examined for Athabasca Cold Lake and

Lloydminster type of reservoirs Numerical modeling was carried out using a commercial

fully implicit thermal reservoir simulator Computer Modeling Group (CMG) STARS

For each reservoir one or two promising well patterns were selected for further

evaluations in the 3-D physical model or future field pilots

Three well patterns including the Classic SAGD pattern Reverse Horizontal Injector

and Inclined Injector of which the last two emerged as most promising in the numerical

study were examined in a 3-D physical model for Athabasca and Cold Lake reservoirs

The physical model used in this study was a rectangular model that was designed based

on the available dimensional analysis for a SAGD type of recovery mechanism Two

types of bitumen representing the Athabasca and Cold Lake reservoirs were used in the

experiments A total of seven physical model experiments were conducted four of which

used the classic two parallel horizontal wells configuration which were considered the

base case tests Two experiments used the Reverse Horizontal Injector pattern and the last

experiment tested the Inclined Injector pattern The suggested well patterns provided

operational and economical enhancement to the SAGD process over the standard well

iii

configuration and this research strongly suggests that both of them should be examined

through field pilots in AthabascaCold Lake type of reservoirs

In order to develop further insight into the performance of different well patterns the

production profile of each experiment was history matched using CMG-STARS Only the

relative permeability curves porosity permeability and the production constraint were

changed to get the best match of the experimental results Although it was possible to

history match the production performance of these tests by changing the relative

permeability curves the need for considerable changes in relative permeability shows

that the numerical model was not able capture the true hydrodynamic behavior of the

modified well configurations

iv

ACKNOWLEDGEMENTS

It would not have been possible to complete this doctoral thesis without the help and

support of the kind people around me to only some of whom it is possible to give

particular mention here

First and foremost I wish to express my sincere gratitude to Dr Brij B Maini and Dr

Thomas G Harding for their generous guidance encouragement and support throughout

the course of this study This thesis would not have been possible without their

unsurpassed knowledge and patience I really feel privileged to have Dr Maini as my

supervisor and Dr Harding as my Co-Supervisor during these years of study

I would like to extend my thanks to Mr Paul Stanislav for his helpful technical support

during performing the experiments

I owe my respectful gratitude to the official reviewers of this thesis Dr SA Mehta Dr

M Dong Dr G Achari and Dr K Asghari for their critically constructive comments

which saved me from many errors and definitely helped to improve the final manuscript

I would like to acknowledge all the administrative support of the Department of

Chemical and Petroleum Engineering during this research

Irsquom practically grateful for the support of Computer Modeling Group for providing

unlimited CMGrsquos license and for their technical support

I must express my gratitude to Narges Bagheri my best friend for her continued support

and encouragement during all of the ups and downs of my research

I would like to thank my friends Bashir Busahmin Cheewee Sia Farshid Shayganpour

and Rohollah Hashemi for their support during my research

Finally I wish to thank my dear parents for their patient love and permanent moral

support

v

DEDICATION

To my parents my sisters Marjan Mozhgan and

Mozhdeh and my best friend Narges

vi

TABLE OF CONTENTS

ABSTRACT ii ACKNOWLEDGEMENTS iv DEDICATIONSv TABLE OF CONTENTS vi LIST OF TABLESx LIST OF FIGURES xi LIST OF SYMBOLES ABBREVIATIONS AND NUMENCLATURES xx

CHAPTER 1 INTRODUCTION1 11 Background 2 12 Dimensional Analysis9 13 Factors Affecting SAGD Performance10

131 Reservoir Properties 10 1311 Reservoir Depth 10 1312 Pay Thickness Oil Saturation Grain Size and Porosity11 1313 Permeability (kv kh)11 1314 Bitumen viscosity11 1315 Heterogeneity11 1316 Wettability12 1317 Water Leg13 1318 Gas Cap13

132 Well Design13 1321 Completion13 1322 Well Configuration 14 1323 Well Pair Spacing 14 1324 Horizontal Well Length 14

133 Operational Parameters 14 1331 Pressure 14 1332 Temperature 15 1333 Pressure Difference between Injector and Producer15 1334 Subcool (Steam-trap control)15 1335 Steam Additives 16 1336 Non-Condensable Gas 16 1336 Wind Down16

14 Objectives17 14 Dissertation Structure 19

CHAPTER 2 LITERATURE REVIEW21 21 General Review 22 22 Athabasca 33 23 Cold Lake 35 24 Lloydminster 36

vii

CHAPTER 3 GEOLOGICAL DESCRIPTION 39 31 Introduction 40 32 Athabasca 41 33 Cold Lake 47 34 Lloydminster 53 35 Heterogeneity 59

CHAPTER 4 EXPERIMENTAL EQUIPMENT AND PROCEDURE62 41 Equipmental Apparatus 63

411 3-D Physical Model63 412 Steam Generator 67 413 Temperature Probes68

42 Data Acquisition68 43 RockFluid Property Measurements 68

431 Permeability Measurement Apparatus 68 432 HAAKE Roto Viscometer69 433 Dean Stark Distillation Apparatus71

44 Experimental Procedure 73 441 Model Preparation 73 442 SAGD Experiment 75 443 Analysing Samples 77 444 Cleaning78

CHAPTER 5 NUMERICAL RESERVOIR SIMULATION 79 51 Athabasca 80

511 Reservoir Model 80 512 Fluid Properties 82 513 Rock-Fluid Properties83 514 Initial CondistionGeomechanics 85 515 Wellbore Model85 516 Wellbore Constraint 86 517 Operating Period87 518 Well Configurations 87

5181 Base Case 88 5182 Vertical Inter-well Distance Optimization94 5183 Vertical Injector 98 5184 Reversed Horizontal Injector 101 5185 Inclined Injector Optimization104 5186 Parallel Inclined Injector108 5187 Multi-Lateral Producer111

52 Cold Lake 113 521 Reservoir Model 113 522 Fluid Properties 114 523 Rock-Fluid Properties115

viii

524 Initial CondistionGeomechanics 116 525 Wellbore Model116 526 Wellbore Constraint 116 527 Operating Period116 528 Well Configurations 117

5281 Base Case 117 5282 Vertical Inter-well Distance Optimization121 5283 Offset Horizontal Injector 123 5284 Vertical Injector 126 5285 Reversed Horizontal Injector 129 5286 Parallel Inclined Injector132 5287 Parallel Reversed Upward Injectors135 5288 Multi-Lateral Producer137 5289 C-SAGD140

53 Lloydminster 144 531 Reservoir Model 146 532 Fluid Properties 147 533 Initial CondistionGeomechanics 148 534 Wellbore Constraint 148 535 Operating Period149 536 Well Configurations 149

5361 Offset Producer 151 5362 Vertical Injector 154 5363 C-SAGD157 5364 ZIGZAG Producer 160 5365 Multi-Lateral Producer162

CHAPTER 6 EXPERIMENTAL RESULTS AND DISCUSSIONS166 61 Fluid and Rock Properties 168 62 First Second and Third Experiments 171

621 Production Results171 622 Temperature Profiles 177 623 History Matching the Production Profile with CMGSTARS183

63 Fourth Experiment187 631 Production Results187 632 Temperature Profiles 188 633 History Matching the Production Profile with CMGSTARS196

64 Fifth Experiment200 641 Production Results200 642 Temperature Profiles 201 643 Residual Oil Saturation 209 644 History Matching the Production Profile with CMGSTARS211

65 Sixth Experiment 215 651 Production Results215 652 Temperature Profiles 219

ix

653 Residual Oil Saturation 224 654 History Matching the Production Profile with CMGSTARS226

66 Seventh Experiment 230 661 Production Results230 662 Temperature Profiles 234 663 Residual Oil Saturation 240 664 History Matching the Production Profile with CMGSTARS241

CHAPTER 7 CONCLUSIONS AND RECOMMENDATIONS246 71 Conclusions 247 72 Recommendations 250

REFERENCES 252

x

LIST OF TABLES

Table 1-1 Effective parameters in Scaling Analysis of SAGD process10

Table 4-1 Dimensional analysis parameters field vs physical64

Table 4-2 Cylinder Sensor System in HAAKE viscometer70

Table 5-1 Reservoir properties of model representing Athabasca reservoir82

Table 5-2 Fluid roperties representing Athabasca Bitumen 82

Table 5-3 Rock-Fluid properties85

Table 5-4 Analaytical solution paramters 93

Table 5-5 Inclined Injector case104

Table 5-6 Reservoir and fluid properties for Cold Lake reservoir model115

Table 5-7 Values of dilation-compaction properties for Cold Lake reservoir model141

Table 5-8 Reservoir and fluid properties for Lloydminster reservoir model148

Table 6-1 Summary of the physical model experiments 168

Table 6-2 Summary watergasoil relative permeability end points of 5th 6th and 7th

experiments 241

xi

LIST OF FIGURES

Figure 1-1 μ minusT relationship 2

Figure 1-2 Schematic of SAGD3

Figure 1-3 Vertical cross section of drainage interface 5

Figure 1-4 Steam chamber interface positions 7

Figure 1-5 Interface Curve with TANDRAIN Theory 8

Figure 1-6 Various well configurations19

Figure 2-1 Chung and Butler Well Schemes26

Figure 2-2A Well Placement Schematic by Chan 27

Figure 2-2B Joshirsquos well pattern27

Figure 2-3 Nasrrsquos Proposed Well Patterns28

Figure 2-4 SW-SAGD well configuration 29

Figure 2-5 SAGD and FAST-SAGD well configuration29

Figure 2-6 Well Pattern Schematic by Ehlig-Economides 30

Figure 2-7 The Cross-SAGD (XSAGD) Pattern 30

Figure 2-8 The JAGD Pattern 31

Figure 2-9 U-Shaped horizontal wells pattern32

Figure 2-10 The Schematic of well patterns proposed by Bashbush and Pina 32

Figure 2-11 Athabasca Oil Sandrsquos Projects 33

Figure 3-1 Albertarsquos bitumen resources estimate volume as of December 31 201140

Figure 3-2 Bitumen and Heavy Oil deposit of Canada 41

Figure 3-3 Distribution of pay zone on eastern margin of Athabasca42

Figure 3-4 Pay thickness of McMurray-Wabiskaw in the Athabasca Area43

Figure 3-5 Athabasca cross section44

Figure 3-6 Correlation chart of Lower Cretaceous bitumen deposits at Athabasca Oil Sand45

Figure 3-7 Oil Sands at Cold Lake area48

Figure 3-8 Correlation chart of Lower Cretaceous at Cold Lake area 48

Figure 3-9 Clearwater Formation at Cold Lake area49

Figure 3-10 Lower Grand Rapids Formation at Cold Lake area 50

xii

Figure 3-11 Upper Grand Rapids Formation at Cold Lake area 51

Figure 3-12 McMurray Formation at Cold Lake area52

Figure 3-13 Location of Lloydminster area 54

Figure 3-14 Correlation chart of Lower Cretaceous at Lloydminster area55

Figure 3-15 Distribution of Ribbon-Shaped Manville Group at Lloydminster area57

Figure 3-16 Lloydminster area oil field59

Figure 4-1 Schematic of Experimental Set-up 63

Figure 4-2 Physical model Schematic 65

Figure 4-3 Physical Model66

Figure 4-4 Thermocouple location in Physical Model 67

Figure 4-5 Pressure cooker 68

Figure 4-6 Temperature Probe design 68

Figure 4-7 Permeability measurement apparatus69

Figure 4-8 HAAKE viscometer 70

Figure 4-9 Dean-Stark distillation apparatus 72

Figure 4-10 Sand extraction apparatus72

Figure 4-11 Bitumen saturation step75

Figure 4-12 InjectionProduction and sampling stage 76

Figure 4-13 Bottom layer of the model after SAGD experiment and the sampling points

for sand analysis77

Figure 5-1 3-D schematic of Athabasca reservoir model 81

Figure 5-2 Cross view of Athabasca reservoir model 81

Figure 5-3 Temperature dependency of bitumen modelrsquos Viscosity for Athabasca 83

Figure 5-4 Water-oil relative permeability 84

Figure 5-5 Relative permeability sets for DW well pairs 85

Figure 5-6 Schematic representation of various well configurations for Athabasca Reservoir 87

Figure 5-7 Oil Production Rate Base Case 89

Figure 5-8 Oil Recovery Factor Base Case 89

Figure 5-9 Cumulative Steam Oil Ratio (cSOR) Base Case90

xiii

Figure 5-10 Steam Chamber Volume Base Case 90

Figure 5-11 Cross view of chamber development at 4 specified time frames Base Case 91

Figure 5-12 Steam Quality of DW vs SS during the SAGD life period Base Case 91

Figure 5-13 Pressure Profile between Injector and Producer at the heel and toe Base Case93

Figure 5-14 Comparison of numerical and analytical solutions Base Case 94

Figure 5-15 Oil Production Rate Vertical Inter-well Distance Optimization 96

Figure 5-16 Oil Recovery Factor Vertical Inter-well Distance Optimization96

Figure 5-17 Steam Oil Ratio Vertical Inter-well Distance Optimization 97

Figure 5-18 Steam Chamber Volume Vertical Inter-well Distance Optimization 97

Figure 5-19 Oil Production Rate Vertical Injectors99

Figure 5-20 Oil Recovery Factor Vertical Injectors 99

Figure 5-21 Steam Oil Ratio Vertical Injectors 100

Figure 5-22 Steam Chamber Volume Vertical Injectors100

Figure 5-23 Oil Production Rate Reverse Horizontal Injector102

Figure 5-24 Oil Recovery Factor Reverse Horizontal Injector 102

Figure 5-25 Steam Oil Ratio Reverse Horizontal Injector 103

Figure 5-26 Steam Chamber Volume Reverse Horizontal Injector103

Figure 5-27 3-D View of Chamber Growth Reverse Horizontal Injector 104

Figure 5-28 Oil Recovery Factor Inclined Injector 105

Figure 5-29 Steam Oil Ratio Inclined Injector105

Figure 5-30 Oil Production Rate Inclined Injector Case 07 106

Figure 5-31 Oil Recovery Factor Inclined Injector Case 07 106

Figure 5-32 Steam Oil Ratio Inclined Injector Case 07107

Figure 5-33 Steam Chamber Volume Inclined Injector Case 07 107

Figure 5-34 Oil Production Rate Parallel Inclined Injector 109

Figure 5-35 Oil Recovery Factor Parallel Inclined Injector 109

Figure 5-36 Steam Oil Ratio Parallel Inclined Injector110

Figure 5-37 Steam Chamber Volume Parallel Inclined Injector 110

Figure 5-38 Oil Production Rate Multi-Lateral Producer111

xiv

Figure 5-39 Oil Recovery Factor Multi-Lateral Producer 112

Figure 5-40 Steam Oil Ratio Multi-Lateral Producer 112

Figure 5-41 Steam Chamber Volume Multi-Lateral Producer 113

Figure 5-42 3-D schematic of Cold Lake reservoir model 114

Figure 5-43 Viscosity vs Temperature for Cold Lake bitumen 115

Figure 5-44 Schematic representation of various well configurations for Cold Lake 117



Figure 5-47 Steam Oil Ratio Base Case120






Figure 5-53 Oil Production Rate Offset Horizontal Injector 124

Figure 5-54 Oil Recovery Factor Offset Horizontal Injector125

Figure 5-55 Steam Oil Ratio Offset Horizontal Injector 125

Figure 5-56 Steam Chamber Volume Offset Horizontal Injector 126












xv


Figure 5-69 Oil Production Rate Parallel Reverse Upward Injector 135

Figure 5-70 Oil Recovery Factor Parallel Reverse Upward Injector 136

Figure 5-71 Steam Oil Ratio Parallel Reverse Upward Injector 136

Figure 5-72 Steam Chamber Volume Parallel Reverse Upward Injector137





Figure 5-77 Reservoir deformation model141

Figure 5-78 Oil Production Rate C-SAGD 142

Figure 5-79 Oil Recovery Factor C-SAGD 143

Figure 5-80 Steam Oil Ratio C-SAGD 143

Figure 5-81 Steam Chamber Volume C-SAGD144

Figure 5-82 Schematic of SAGD and Steamflood145

Figure 5-83 3-D schematic of reservoir model for Lloydminster reservoir147

Figure 5-84 Temperature dependency of heavy oil modelrsquos Viscosity 149

Figure 5-85 Schematic of various well configurations for Lloydminster reservoir150

Figure 5-86 Oil Procution Rate Offset Producer152

Figure 5-87 Oil Recovery Factor Offset Producer 152

Figure 5-88 Steam Oil Ratio Offset Producer153

Figure 5-89 Steam Chamber Volume Offset Producer 153

Figure 5-90 Oil Production Rate Vertical Injector 155

Figure 5-91 Oil Recovery Factor Vertical Injector 155

Figure 5-92 Steam Oil Ratio Vertical Injector 156

Figure 5-93 Steam Chamber Volume Vertical Injector 156



xvi



Figure 5-98 Oil Production Rate ZIGZAG160

Figure 5-99 Oil Recovery Factor ZIGZAG161

Figure 5-100 Steam Oil Ratio ZIGZAG 161

Figure 5-101 Steam Chamber Volume ZIGZAG162

Figure 5-102 Oil Production Rate Comparison 163

Figure 5-103 Oil Recovery Factor Comparison 163

Figure 5-104 Steam Oil Ratio Comparison 164

Figure 5-105 Steam Chamber Volume Comparison 164

Figure 6-1 Permeability measurement with AGSCO Sand 169

Figure 6-2 Elk-Point viscosity profile 170

Figure 6-3 JACOS Bitumen viscosity profile 170

Figure 6-4 Oil Rate First and Second Experiment173

Figure 6-5 cSOR First and Second Experiment 173

Figure 6-6 WCUT First and Second Experiment 174

Figure 6-7 RF First and Second Experiment174

Figure 6-8 Oil Rate Second and Third Experiment 175

Figure 6-9 cSOR Second and Third Experiment 176

Figure 6-10 WCUT Second and Third Experiment 176

Figure 6-11 RF Second and Third Experiment 177

Figure 6-12 Temperature profile along the injector at 5 and 20 hours First Experiment178

Figure 6-13 Layers and Cross sections schematic of the physical model 179

Figure 6-14 Chamber Expansion along the well-pair at 01 PVinj180




Figure 6-18 Chamber Expansion along the well-pair at 078 PVinj 182

Figure 6-19 Chamber Expansion Cross View at 078 PVinj Cross-Section 1 183

xvii

Figure 6-20 Water OilGas Relative Permeability First Experiment History Match184

Figure 6-21 Match to Oil Production Profile First Experiment 185

Figure 6-22 Match to Water Production Profile First Experiment 185

Figure 6-23 Match to Steam (CWE) Injection Profile First Experiment 186

Figure 6-24 Match to Steam Chamber Volume First Experiment186

Figure 6-25 Oil Rate First and Fourth Experiment189

Figure 6-26 cSOR First and Fourth Experiment 189

Figure 6-27 WCUT First and Fourth Experiment 190

Figure 6-28 RF First and Fourth Experiment190

Figure 6-29 Temperature profile along the injector at 3 and 16 hours Fourth Experiment191






Figure 6-35 Chamber Expansion Cross View at 05 PVinj Cross Section 1 195

Figure 6-36 Water OilGas Relative Permeability Fourth Experiment History Match197

Figure 6-37 Match to Oil Production Profile Fourth Experiment 198

Figure 6-38 Match to Water Production Profile Fourth Experiment 198

Figure 6-39 Match to Steam (CWE) Injection Profile Fourth Experiment 199

Figure 6-40 Match to Steam Chamber Volume Fourth Experiment199

Figure 6-41 Oil Rate Fifth Experiment 202

Figure 6-42 3-D cSOR Fifth Experiment 202

Figure 6-43 WCUT Fifth Experiment203

Figure 6-44 RF Fifth Experiment 203

Figure 6-45 Temperature profile along the injector at 5 and 20 hours Fifth Experiment 204




xviii




Figure 6-52 Chamber Expansion Cross View at 065 PVinj Cross Section1 208

Figure 6-53 Sampling distributions per each layer of model209

Figure 6-54 φΔSo across the middle layer fifth experiment210

Figure 6-55 φΔSo across the top layer fifth experiment211

Figure 6-56 Water OilGas Relative Permeability Fifth Experiment History Match 212

Figure 6-57 Match to Oil Production Profile Fifth Experiment 213

Figure 6-58 Match to Water Production Profile Fifth Experiment213

Figure 6-59 Match to Steam (CWE) Injection Profile Fifth Experiment 214

Figure 6-60 Match to Steam Chamber Volume Fifth Experiment 214

Figure 6-61 Oil Rate Fifth and Sixth Experiment 216

Figure 6-62 cSOR Fifth and Sixth Experiment 216

Figure 6-63 WCUT Fifth and Sixth Experiment 217

Figure 6-64 RF Fifth and Sixth Experiment 217

Figure 6-65 Temperature profile along the injector at 4 and 14 hours Sixth Experiment220







Figure 6-72 Chamber Expansion Cross View at 05 PVinj 224

Figure 6-73 φΔSo across the middle layer sixth experiment225

Figure 6-74 φΔSo across the top layer sixth experiment226

Figure 6-75 Water OilGas Relative Permeability Sixth Experiment History Match227

Figure 6-76 Match to Oil Production Profile Sixth Experiment 228

Figure 6-77 Match to Water Production Profile Sixth Experiment 228

xix

Figure 6-78 Match to Steam (CWE) Injection Profile Sixth Experiment 229

Figure 6-79 Match to Steam Chamber Volume Sixth Experiment229

Figure 6-80 Schematic representation of inclined injector pattern230





Figure 6-85 Schematic of D5 Location in inclined injector pattern 234

Figure 6-86 Temperature profile in middle of the model at 4 and 10 hours Seventh Exp 235







Figure 6-93 φΔSo across the top layer seventh experiment 240

Figure 6-94 Water OilGas Relative Permeability Seventh Experiment History Match242

Figure 6-95 Match to Oil Production Profile Seventh Experiment 243

Figure 6-96 Match to Water Production Profile Seventh Experiment 243

Figure 6-97 Match to Steam (CWE) Injection Profile Seventh Experiment 244

Figure 6-98 Match to Steam Chamber Volume Seventh Experiment244

xx

LIST OF SYMBOLS ABBREVIATIONS AND NOMENCLATURE

Symbol Definition

C Heat capacity Cp Centipoises cSOR Cumulative Steam Oil Ratio ERCB Energy Recourses and Conservation Board Fo Fourier Number g Acceleration due to gravity h height k Effective permeability to the flow of oil K Thermal conductivity of reservoir krw Water relative permeability krow Oil relative permeability in the Oil-Water System krg Gas relative permeability krog Oil relative permeability in the Gas-Oil System Kv1 First coefficient for Gas-Liquid K-Value correlation Kv4 Fourth coefficient for Gas-Liquid K-Value correlation Kv5 Fifth coefficient for Gas-Liquid K-Value correlation L Length of horizontal well m Viscosity-Temperature relation coefficient nw Exponent for calculating krw now Exponent for calculating krow nog Exponent for calculating krog ng Exponent for calculation krg RF Recovery Factor Sl Liquid Saturation Soi Initial Oil Saturation Soirw Irreducible oil saturation with respect to water Sgr Residual gas saturation Soirg Irreducible oil saturation with respect to gas Sw Water saturation Swcon Connate water saturation TR Reservoir temperature Ts Steam temperature U Interface velocity UTF Underground Test Facility x Horizontal distance from draining point X Dimensionless horizontal distance y Vertical distance from draining point Y Dimensionless vertical distance ΔSo Oil s aturation change

xxi

Greek Symbols

micro Dynamic viscosity νs Kinematic viscosity of bitumen at steam temperature α Thermal diffusivity φ Porosity ρ Density of oil θ Angle of Inclination of interface ζ Normal distance from the interface

CHAPTER 1

INTRODUCTION

2

11 Background Canadarsquos oil sands and heavy oil resources are among the largest known hydrocarbon

deposits in the world Alberta deposits contain more than 80 of the worldrsquos recoverable

reserves of bitumen However the amount of conventional oil reserves in Canada is

limited and these reserves are declining As a result of advances in the Steam Assisted

Gravity Drainage (SAGD) which was introduced by Butler in 1978 some of the bitumen

resources have turned into reserves These resources include the vast oil sands of

Northern Alberta (Athabasca Cold Lake and Peace River) and the more heavy oil that

sits on the border between Alberta and Saskatchewan (Lloydminster) Currently due to

the oil price and SAGDrsquos efficiency the oil sands and heavy oils are attracting a lot of

attentions

Most of the bitumen contains high fraction of asphaltenes which makes it highly

viscous and immobile at reservoir condition (11-15 ordmC) It is their high natural viscosity

that makes the recovery of heavy oils and bitumen difficult However the viscosity is

very sensitive to temperatures as shown in Fig 1-1

10000000

1000000

100000

10000

1000

100

1

Figure 1-1 μ minusT relationship

Visc

osity

cp

Athabasca Cold Lake

0 50 100 150 200 250 Temperature C

10

3

Currently there are two methods to extract the bitumen out of their deposits a) Open

pit mining b) In-Situ Recovery Using strip mining is economical for the deposit close to

surface but only about 8 of oil sands can be exploited by this method The rest of the

deposits are too deep for the shovel and truck access Currently only thermal oil recovery

methods can be used to recover bitumen from oil sands although several non-thermal

technologies are under investigation

Thermal oil recovery either by heat injection or internally generated heat through

combustion introduces heat into the reservoir to reduce the flow resistance by reduction

of the bitumen viscosity with increased temperature Thermal methods include steam

flooding cyclic steam stimulation in-situ combustion electric heating and steam

assisted gravity drainage Among these processes steam assisted gravity drainage

(SAGD) is an effective method of producing heavy oil and bitumen It unlocks billions

barrels of oil that otherwise would have been inaccessible Figure 1-2 displays a vertical

cross-section of the basic SAGD mechanism

Overburden

Underburden

Steam Chamber

Net Pay

Figure 1-2 Schematic of SAGD

In the SAGD process in order to enhance the contact area between the reservoir and

the wellbore two parallel horizontal wellbores are drilled and completed at the base of

the formation The horizontal well offers several advantages such as improved sweep

efficiency increased reserves increased steam injectivity and reduced number of wells

needed for reservoir development In the SAGD well-pair the top well is the steam

injector and the bottom well is the oil producer The vertical distance between the injector

4

and the producer is typically 5 m The producer is generally located a couple of meters

above the base of formation The SAGD process consists of three phases

1) Preheating (Start-up)

2) Steam Injection amp Oil Production

3) Wind down

The purpose of preheating period is to establish fluid communication between

injector and producer The steam is circulated in both wellbores for typically 3-4 months

in order to heat the region between the wells The intervening high viscosity bitumen is

mobilized and starts flowing from the injector to the producer as a result of both gravity

drainage and the small pressure gradient between wellbores

Once the fluid communication between injector and producer is established the

normal SAGD operation can start High quality steam is introduced continuously into the

formation through the injection well and the oil is produced through the producer The

injected steam tends to rise and expand it forms a steam saturated zone (steam chamber)

above the injection well The steam flows through the chamber where it contacts cold

bitumen surrounding the chamber At the chamber boundary the steam condenses and

liberates its latent heat of vaporization which serves to heat the bitumen This heat

exchange occurs by conduction as well as by convection The heated bitumen becomes

mobile drains by gravity together with the steam condensate to the production well along

the steam chamber boundary Within the chamber the pressure remains constant and a

counter current flow between the steam and draining fluids occurs As the bitumen is

being produced the vacated space is left behind for the steam to fill in The chamber

grows upward longitudinally and laterally before it touches the overburden Eventually it

reaches the cap rock and then spreads only laterally During the normal SAGD phase two

sub-stages can be defined Ramp-up and Plateau It is well understood that the initial

upward growth of the steam chamber is much faster than the lateral growth Meanwhile

the injection and production rates appear to increase This stage is called Ramp-Up As

the chamber reaches the formation top the lateral growth becomes dominant This period

of production in which the oil production rate reaches a maximum (and then slowly

declines) while the water cut goes through a minimum is called Plateau

5

As time proceeds the chamber spreads laterally and the interface becomes more

inclined The oil has to travel longer distance to reach the production well and larger area

of the steam chamber is exposed to the cap-rock Consequently the oil rate decreases and

the SOR increases The ultimate recovery factor in SAGD is typically higher than 50

Eventually the SOR becomes unacceptably high and the steam chamber is called

ldquomaturerdquo The Wind-Down stage begins at this point

Butler McNab and Lo derived the amount of oil flow parallel to the interface and via

drainage force through Equation (11) by assuming that the steam pressure remains

constant in the steam chamber [2] only steam flows in the chamber oil saturation in the

chamber is residual [3] drainage is parallel to the interface the effective permeability is

constant and heat transfer ahead of the steam chamber to cold part of the reservoir is

only by conduction The steam zone interface was assumed to move uniformly at a

constant velocity U Based on these assumptions the temperature ahead of the interface

is given by Equation (1 2)

T=Ts

T=TR

θ

dt t x

y ⎟ ⎠ ⎞

⎜ ⎝ ⎛ part

part

Figure 1-3 Vertical cross section of drainage interface [2]

2φΔS kg h αo (11)q = 2L mν s

T Tminus S ⎛ Uξ ⎞ = exp ⎜ minus (12)⎟T minusT αS R ⎝ ⎠

where q rate of drainage of oil along the interface

L Length of horizontal well φ porosity

ΔSo Oil saturation change

6

k Effective permeability to the flow of oil g Gravitational acceleration α Thermal diffusivity h Reservoir net pay

m Viscosity-Temperature relation coefficient υ s Kinematic viscosity of bitumen at steam temperature Ts Steam temperature

TR Reservoir temperature U Interface velocity ξ Normal distance from the interface

The major assumption for flow relation derivation was that the steam chamber was

initially a vertical plane above the production well and the horizontal displacement was

given as a function of time t and height y by

kgαx t= (13a)2φΔS m ( ) minuso ν s h y

kgα ⎛ ⎞t 2

= minus (13b)y h ⎜ ⎟2φΔS m ⎝ ⎠o ν s x

The position of the interface in dimensionless form can be written as

1 tD 2

Y 1 (14) = minus ⎛ ⎞ ⎜ ⎟2 X⎝ ⎠

X = x h (15)

Y = y h (16)

t kg α (17) t = D h S m h φΔ o ν s

where x Horizontal distance from draining point y Vertical distance from draining point

X Dimensionless horizontal distance Y Dimensionless vertical distance

Interface positions described by equation (14) are shown in Figure 1-4

7

0

01

02

03

04

05

06

07

08

09

1

0 05 1 15 2 Horizontal Distance xh

Ver

tical

Dist

ance

yh

02 06

04 08

1 12

14 16

18 2

Figure 1-4 Steam chamber interface positions

The m value is introduced in Equation (18) to account for the effect of temperature

on viscosity It is defined as a function of the viscosity-temperature characteristics of the

oil the steam and the reservoir temperature

⎡ TS ⎛ 1 1 ⎞ dT ⎤minus1

m = ⎢ν minus ⎥ (18) ν ν T T⎣

s intTR ⎜⎝ R

⎟⎠ minus R ⎦

The drainage rate dictated by equation (11) is exaggerated compared with

experiment data Butler and Stephens modified this theory and came up with the

TANDRAIN theory in which the drainage rate is given by Equation 19 [4] This rate is

87 of that calculated by equation (11) and is closer to the experiment data

15φΔS kg h αoq = 2L (19) mν s

The interface in Figure 14 was modified so that the interface will not spread

horizontally to infinity In TANDRAIN theory the interface is connected to the horizontal

well as in Figure 1-5

8

Figure 1-5 Interface Curve with TANDRAIN Theory

Butler analyzed the dimensional similarity of the process in the field and laboratory

scale physical models and found that not only tD must be the same for the model and the

field but also a dimensionless number B3 as given by equation (110) must be the same

[3]

3 o s

kgh B S mαφ ν

= Δ

(110)

B3 is obtained by combining the dimensionless time (tD) and Fourier number

Fourier number is a dimensionless number that is the ratio of heat conduction rate and

thermal energy storage rate Butler expressed the extent of the temperature in a solid that

is heated by conduction can be demonstrated by Fourier number as provided in equation

(111) [1]

αtFo = h2 (111)

For dimensional similarity between a laboratory model and field in addition to tD

Fo needs to be the same for both models Since Butler defined B3 as

B3 = tD (113) Fo

Therefore for dimensional similarity between filed and lab model the B3 of both

models has to be equal

9

12 Dimensional Analysis Dimensional analysis is a practical technique in all experimentally based areas of

engineering research It can be considered as a simplified type of scaling argument for

learning about the dependence of a phenomenon on the dimensions and properties of the

system that exhibits the phenomenon Dimensional analysis is a method for reducing the

number and complexity of experimental variables that affect a given physical

phenomena If it is possible to identify the factors involved in a physical situation

dimensional analysis can form a relationship between them Dimensional analysis

provides some advantages such as reducing number of variables defining dimensionless

equations and establishing dimensional similarity (Scaling law) Out of the listed

advantages the scaling law allows evaluating the full process using a small and simple

model instead of constructing expensive large full scale prototypes Particular type of

similarities is geometric kinematic and dynamic similarity To establish ldquoSimilar

systemsrdquo one should choose identical values of dimensionless combinations between two

systems even though the dimensional quantities may be quite different Usually the

dimensionless combinations are expressed as dimensionless number such as Re Fr and

etc Similarity analyses can proceed without knowledge of the governing equations

However when the governing equations are known then the ldquoscale analysisrdquo term is

more suitable Since this research is dealing with thermal methods therefore the scaling

requirements for thermal models need to be considered These requirements can be

generalized as follows

1 Geometric Similarity field and model must be geometrically similar This implies

the same width-to-length ratio height-to-length ratio dip angle and reservoir

heterogeneities

2 The values of several parameters containing fluid and rock properties as well as

terms related to the transport of heat and mass must be equal in the field and

model

3 Field and model must have the same initial conditions and boundary conditions

Scaled model experiments are one of the more useful tools for study and further

development of the SAGD process Before SAGD is applied in a new field laboratory

physical model experiments and field pilots may investigate its performance under

10

various reservoir conditions and geological characteristics Physical model studies can

investigate the effects of related factors by evaluating various scenarios Such models

can be used to optimize the pattern type size well configurations injection and

production mode and effects of additives By careful scaling the physical model can

produce data to forecast the performance of reservoirs under realistic conditions It

provides a helpful guide for prediction of field applications and for economic evaluation

In order to obtain the scaled analysis in a SAGD process it is essential to set equal

values of B3 in Equation 110 for both the physical model and the field properties The

properties of the scaled model are selected such a way that the dimensionless number B3

is the same for the model as for the field A list of the parameters included in scaling

analysis is provided in Table 11

Table 1-1 Effective parameters in Scaling Analysis of SAGD process

Parameter

Net Pay m

Permeability mD

φΔSo

microR cp

micros cp

m

13 Factors Affecting SAGD Performance The parameters that control the SAGD performance can be categorized as reservoir

properties well design and operating parameters The following provides a brief

discussion of the effects of important parameters

131 Reservoir Properties

1311 Reservoir Depth

One of the important parameters affecting SAGD performance is the reservoir depth

Deep reservoirs have higher operating pressure which means higher steam temperature

Higher pressure steam (to some extend) carries higher enthalpy (but lower latent heat)

11

and has lower specific volume This increases the energy stored in the vapor chamber

Also the heat losses in the well bore and to the overburden increase due to higher

temperature and increased tubing length On the positive side increased temperature

provides lower oil viscosity The net effect of reservoir depth on SOR and RF needs to

be examined in order to determine the optimum range of reservoir depth

1312 Pay Thickness Oil Saturation Grain Size and Porosity

Net pay thickness oil saturation and porosity determine the amount of oil in the

reservoir and higher values yield better oil rate lower steam oil ratio and higher recovery

factor The minimum pay thickness needed for economically viable SAGD operations

appears to be about 15 meters but this needs to be further examined

1313 Permeability (kv kh)

Permeability determines how easily the fluids flow in the reservoir thus it directly

affects the production rate Low vertical permeability especially between injector and

producer will hinder steam chamber development High horizontal permeability helps

the lateral spreading of steam chamber In most laboratory experiments the physical

models are packed with glass beads or sand that give isotropic permeability (kvkh = 1)

1314 Bitumen viscosity

Heavy oils and bitumen contain a higher fraction of asphaltenes are highly viscous

and sometimes immobile at reservoir condition It is their high natural viscosity that

makes the recovery of heavy oils and bitumen difficult The oil drainage rate in SAGD

under pseudo-steady-state conditions depends on the heated oil viscosity However the

time required for establishing the communication between the injector and the producer

depends largely on the original oil viscosity When the original oil viscosity is lower and

the oil is sufficiently mobile the communication between the wells is no longer a hurdle

This opens up the possibility of increasing the distance between the two wells and

introducing elements of steam flooding into the process

1315 Heterogeneity

A significant concern in the development of the SAGD process is that of the possible

effects of barriers to vertical flow within the reservoir These may consist of significant

sized shale layers or may be grain-sized barriers whose effect is reflected by a lower

12

vertical than horizontal permeability In some situations continuous and extensive shale

barriers divide the reservoir and each sub-reservoir has to be drained separately

However it is common to find layers of shale a few centimeters thick but of relatively

limited horizontal length which do not divide the reservoir but make it necessary for

fluids to meander around them if they are to flow vertically It is important to note that

the direction of flow is oblique not vertical It is the permeability in the direction of flow

that determines the rate not the vertical permeability [3] Overall it appears that partial

shale barriers can be tolerated by the process

In addition to the effect of limited extent shale barriers it would be desirable to

evaluate the effect of heterogeneity due to permeability difference in layers In some

cases the reservoir contains horizontal layers of different permeability so there will be

two cases

frac34 Low permeability on top of high permeability

frac34 High permeability on top of low permeability

Beside the effect of shale barriers on vertical flow their presence results in higher

cSOR Due to their presence in forms of non productive rock within the oil bearing zone

they will be heated as well as the oil sand This extra heat which does not yield to any

additional oil production will cause the cSOR to increase

1316 Wettability

Wettability controls the distribution and flow of immiscible fluids in an oil reservoir

and thus plays a key role in any oil-recovery process Once thought to be a fixed property

of each individual reservoir it is now recognized that wettability can vary on both

microscopic and macroscopic scales The potential for asphaltenes to adsorb onto high

energy mineral surfaces and thus to affect reservoir wettability has long been recognized

The effect of wettability on SAGD performance has not been adequately evaluated

However it is apparent that the wettability will affect oil-water relative permeability and

residual oil saturation which in turn would affect the gravity drainage of oil and ultimate

recovery

13

1317 Water Leg

Many heavy oil and oil sand reservoirs are in communication with water sand(s)

Depending on the density (oAPI gravity) of oil the water sand could lie above or below

the oil zone The presence of a bottom water layer has less an impact on recovery than the

case where an overlying water layer is present Steam flooding a heavy oil or oil sand

reservoir with confinedunconfined water sand (water which may lie below or above the

oil-bearing zone) is risky due to the possibility of short circuiting the oil-bearing zone

There is a major concern that the existence of thief zones such as top water will have

detrimental effects on the oil recovery in (SAGD) process [3] For underlying aquifers if

the steam chamber pressure is high enough and stand-off distance of the producer is

selected correctly then intrusion of water may be prevented

1318 Gas Cap

Some of the heavy oil reservoirs have overlying gas caps Some SAGD studies have

suggested that gas-cap production might ldquosterilizerdquo the underlying bitumen [2] Many

such studies however assumed rather thick continuous pays with high permeability and

considered a large gas-cap So considering the case of a small gas-cap on top of the oil

sand formation with different well configurations (including vertical injectors) would

clarify the feasibility of SAGD projects in such reservoirs

132 Well Design

1321 Completion

SAGD wells are completed with a sand control device in the horizontal section Trials

have been run with wire-wrapped screens but most operators use slotted liners Slotted

liners are manufactured by cutting a series of longitudinal slots The slot width is

selected based on the formationrsquos grain-size distribution to restrict sand production and

allow fluid inflow Liner design requirements must balance sand retention open fluid

flow area and structural capacity Larger liner which means larger intermediate casing

and larger holes will reduce pressure drop especially near the heel of injector It must be

decided which liner size would be optimum for the well

14

1322 Well configuration

The most common well configuration for SAGD operation is to place a single

horizontal injector directly above a single horizontal producer The total number of wells

in such a pattern is two with an injector-to-producer ratio of 11 Based on heavy oil

reservoir oil viscosity (either mobile oil or bitumen) at reservoir condition kvkh

heterogeneity and other factors it might be advantageous to place the injector and

producer in other configurations than the base case of 5 m apart horizontal wells in the

same vertical plane

1323 Well Pairs Spacing

In the initial stage of SAGD the upward rate of growth of the steam chamber would

be larger than the rate of sideways growth Eventually the upward growth is limited by

the top of the reservoir and the sideward growth then becomes critical After a period of

time the interfaces of different chambers intermingle and form a single steam layer above

the oil It would be beneficial to optimize the distance between well pairs since smaller

spacing would yield better SOR and recovery factor but the oil production would decline

faster and more wells would be required

1324 Horizontal well length

The main advantage of long horizontal well in thermal oil recovery is to improve

sweep efficiency enhance producible reserves increase steam injectivity and reduce

number of wells needed for reservoir development The longer well length would yield

higher rates but causes higher pressure drop and it may require larger pipes and holes to

accumulate the higher flow rates and to reduce the pressure drop A sensitivity analysis

must be done to determine the optimum length

133 Operational Parameters

1331 Pressure

Operating pressure plays a significant role in the rate of recovery Lower operating

pressure reduces the SOR reduces H2S production may reduce the silica dissolution and

thereby reduce the water treatment issues [5] However lower pressure operation

increases the challenges in lifting the fluid to the surface A low pressure SAGD

operation may end up with a low recovery factor during the economic life of the project

15

the remaining reserve may be lost forever as it will be extremely unlikely that an

additional SAGD project would be undertaken in the future to ldquoreworkrdquo the property On

the other hand a bitumen deposit which is below the current economic threshold may

well become an attractive prospect in the future with advances in technology simply

because it remains intact Higher steam pressure will cause greater dilation of sandstone

thereby increasing effective reservoir porosity which in turn it is predicted will have the

result of significantly improving projected SAGD recoveries It may be beneficial to

accelerate the start-up and initial steam chamber development and provide sufficient

pressure to lift production fluid to surface

1332 Temperature

At the lower steam temperature which is related to the pressure the sand matrix is

heated to a lower temperature and the energy requirement for heating the reservoir goes

down Conceptually this should lead to a lower steam oil ratio However the lower

temperature would increase the heated oil viscosity and reduce the oil drainage rate

thereby increasing the project time span This will increase the time available for heat

loss to the overburden and may partially or totally negate the reduced heat requirements

Although the steam temperature is often determined by the prevailing reservoir

pressure in situations where operating flexibility exists the optimum temperature needs

to be determined When a non-condensable gas is injected with the steam the pressure

can be increased above the saturation pressure of steam by adding more gas

1333 Pressure Difference between Injector and Producer

Once the reservoir between the two wells is sufficiently heated and bitumen mobility

is evident a pressure differential is applied between the wells The risk in applying this

pressure differential is creating a preferential flow path between wells which results in

the inefficient utilization of energy and may damage the production linear Determining

when to induce this pressure differential and how much pressure differential to apply is

critical to overall optimization of the process

1334 Subcool (Steam-trap control)

The steam circulation is aimed at establishment of the connectivity between injector

and producer Once the communication between the wells is achieved the SAGD process

16

is switched into the normal injection-production process Over this period the steam may

break into the producer and by-pass the heated bitumen In order to decrease the risk of

such steam breakthrough a back pressure is imposed on the production well which

creates level of liquid above the production well which is called subcool The subcool can

be either high or low pressure In the high pressure subcool the liquid level decreases

while in the low pressure one it increases In a field project the sucool varies between

high and low pressures at different time periods Optimization of the subcool amount and

implementation time frame requires intensive investigations

1335 Steam Additives

In SAGD process addition of hydrocarbon solvents for mobility control may play an

important role Components of hydrocarbon solvents based on their PVT behavior may

penetrate into immobile bitumen beyond the thermal boundary layer This provides

additional decrease in viscosity due to dilution with lighter hydrocarbons in that zone

Different solvent mixtures with varying compositions can be employed for achieving

enhancement in SAGD recovery

1336 Non-Condensable Gas

In the practical application of SAGD process the steam within the steam chamber can

be expected to contain non-condensable gases methane and carbon dioxide Carbon

dioxide is often found in the produced gas from thermal-recovery projects and its source

is thought to be largely from the rocks within the chamber The small amounts of non-

condensable gas can be beneficial because the gases accumulate at the top edges of the

steam chamber and restrict the rate of the heat loss to the overburden [3] The non-

condensable gases may not increase the ultimate recovery but will decrease the SOR

However presence of too much non-condensable gas can reduce the steam chamber

temperature and interfere in the heat transfer process at the edge of the chamber

1337 Wind down

The last stage for SAGD operation is wind down It can be done by either low quality

steam or some non condensable gases Based on field experiences it was proposed to use

low quality steam In order to find the level of this low quality some sensitivity analysis

17

must be done to find the best time for applying the wind down and also the possibility of

adding some non condensable gases

14 Objectives Since mid 1980rsquos SAGD process feasibility has been field tested in many successful




geological and operational conditions and an expensive oil recovery mechanism A

comprehensive qualitative understanding of the parameters affecting SAGD performance

was provided in the previous section Well configuration is one of the major factors

which require greater consideration for process optimization Over the 20 years of SAGD

experience the only well configuration that has been extensively field tested is the

standard 11 configuration which has a horizontal injector lying approximately 5 meters

above a horizontal producer

The main objective of this study is to evaluate the effect of well configuration on

SAGD performance and develop a methodology for optimizing the well configurations

for different reservoir characteristics The role of well configuration in determining the


models Numerical modeling was carried out using a commercial fully implicit thermal

reservoir simulator Computer Modeling Group (CMG) STARS The wellbore modeling

was utilized to account for frictional pressure drop and heat losses along the wellbore A

3-D physical model was designed based on the available dimensional analysis for a

SAGD type of recovery mechanism Physical model experiments were carried out in the

3-D model With this new model novel well configurations were tested

1 The most common well configuration for SAGD operation is 11 ratio pattern in

which a single horizontal injector is drilled directly above a single horizontal

producer However depending on the reservoir and oil properties it might be

advantageous to drill several horizontalvertical wells at different levels of the

reservoir ie employ other configurations than the base case one to enhance the

drainage efficiency In this study three types of bitumen and heavy oil reservoirs

18

in Alberta Athabasca Cold Lake and Lloydminster were considered for

evaluating the effects of well configuration For example in heavy oil reservoirs

containing mobile oil at the reservoir condition it may be advantageous to use an

offset between injector and producer Figure 1-5 presents some of the modified

well configurations that can be used in SAGD operations These well

configurations need to be matched with specific reservoir characteristics for the

optimum performance None of them would be applicable to all reservoirs The

aim of this research was to investigate the conditions under which one or more of

these well configurations would give improved performance When two parallel

horizontal wells are employed in SAGD the relevant configuration parameters

are (a) height of the producer above the base of the reservoir (b) the vertical

distance between the producer and the injector and (c) the horizontal separation

between the two wells which is zero in the base case configuration (d) well

length of well-pairs The effects of these parameters in different types of

reservoirs were evaluated with numerical simulation and some of the optimized

configurations were tested in the 3-D physical model

2 Hybrids of vertical and horizontal well pairs were also evaluated to see the

potentials of bringing down the cost by using existing vertical wells

3 The most promising well patterns would be experimentally evaluated in the 3-D

physical model

4 The results of physical model experiments will be history matched with reservoir

simulators to validate the simulations and to extend the simulations to the field

scale for performance predictions

19

Basic Well Configuration Reversed Horizontal Injector

Injector InjectorsInjector Produce

Producer Producer

Injectors Multi Lateral Producer Top View

Injector

Injector Producer Producer Producer

C-SAGD Vertical Injector Inclined Injector

Figure 1-6 Various well configurations

15 Dissertation Structure This study comprised seven chapters of which Chapter 1 describes the basic

concepts of SAGD process a review on dimensional analysis for SAGD explanation of

effective parameters on SAGD and eventually the research objectives

Chapter two provides a general review on previous researches on SAGD This

includes both numerical and experimental studies achieved to evaluate SAGD In

addition extensive literature reviews of proposed well configuration in SAGD process

are provided Most of commercial SAGD projects in three reservoirs of Athabasca Cold

Lake and Lloydminster are described in chapter two as well

In Chapter three a simple geological description of Athabasca Cold Lake and

Lloydminster reservoirs is provided The sequence and description of different formation

for each reservoir is explained and their properties such as porosity permeability and oil

saturation are provided The target formations of most commercial projects are referred

In Chapter four the experimental apparatus which comprised several components

such as steam generator data acquisition temperature probes and physical model is well

described The prepost experimental analysis was achieved in series of equipments such

as permeability measurement apparatus viscometer and dean stark distillation Each

equipment was described briefly The experimental methods and procedures are

explained in this chapter as well

Chapter five discusses the numerical simulation studies conducted to optimize the

well configuration for Athabasca Cold Lake and Lloydminster reservoirs The well

20

constraints operating condition and input data such as description of the geological

models and PVT data for each reservoir are presented This chapter outlines the

comparison of different well patterns results with the base case results for each reservoir

Based on the RF and cSOR results some new well patterns are recommended for each

reservoir

Chapter six comprises the presentation and discussion of the experimental results

Three sets of well patterns are examined for Athabasca and Cold Lake type of reservoir

Each well pattern is compared against the basic SAGD pattern The results of each

experiment are analysed and described in detail Eventually each test was history

matched using CMG-STARS

Chapter seven summarizes the contribution and conclusions of this research in

optimizing the SAGD process under new well configuration both numerically and

experimentally Some future recommendations and research areas are provided in this

chapter as well

CHAPTER 2

LITERATURE REVIEW

22

21 General Review Thermal recovery processes involves several mechanisms such as a) reduction of the

fluid viscosity resistance against the flow via introducing heat in the reservoir b)

distillationcracking of heavy components into lighter fractions Since distillation and

cracking requires specific conditions such as high temperature at low pressures or super

high temperature at high pressures therefore the dominant mechanism in thermal

recovery methods is viscosity reduction In thermal techniques steam fire or electricity

are employed to heat the oil and reservoir

Among all fluids water is abundant and has exceptionally high latent heat of

vaporization which makes it the best heat carrier for thermal purposes Therefore within

all thermal methods steam based recovery methods have become the most efficient for

exploiting bitumen and heavy oil At the same time steam mobility is also very high

Consequently combining the gravitational force and mobility difference of bitumen and

steam would cause the steam to easily penetrate rise into and override within the

reservoir These characteristics are taken advantage of in the SAGD process In fact

using horizontal well-pairs in SAGD causes the steam chamber to expand gradually and

drain the heated oil and steam condensate from a very large area even though the well-

pairs are drilled in the vicinity of each other and the chance of steam breakthrough in the

production well is high

SAGDrsquos efficiency has been compared to the prior field-tested thermal methods such

as steam flood or CSS In steam flooding as a result of steam and crude oil density

difference the lighter steam tends to override and it can breakthrough too early in the

process However being a gravity drainage process SAGD overcomes this limitation of

steam flooding SAGD offers specific advantages over the rest of thermal methods

a) Smooth and gradual fluid flow Unlike the steam flood and CSS less oil will be

left behind

b) No steam override or fingering

c) Moderate heat loss which yields higher energy efficiency

d) Possibility of production at shallow depths

e) Stable gravitational flow

f) Production of heated oil at high rates resulting in faster payout time

23

Since the 1980lsquos the use of shovels and trucks have dominated tar sands mining

operations [2] Using strip mining is still economical for the deposits that are close to

surface but the major part of the oil sand deposits is too deep to strip mine As the depth

of deposit increases using thermal and non-thermal in situ recovery methods becomes

vital

SAGD was first developed by Butler et al [2] A mathematical model was proposed to

predict the production of SAGD based on a steady state assumption Through years of

experiments and field pilot applications the understanding of SAGD process has been

greatly broadened and deepened

Butler further estimated the shape of the steam chamber During the early stage of

steam chamber growth the upward motion of the interface is in the form of steam fingers

with oil draining around them while subsequently the lateral and downward movement of

the interface takes a more stable form [6]

Alberta Oil Sands have seen over 30 years of SAGD applications and numerous

numerical and experimental studies have been conducted to evaluate the performance of

SAGD process under different conditions The experimental models used in laboratory

studies were mostly 2-D models

Chung and Butler examined geometrical effect of steam injection on SAGD two

scenarios (spreading steam chamber and rising steam chamber) were established to

elucidate the geometrical effect of steam injection on wateroil emulsion formation in the

SAGD process [7]

Zhou et al conducted different experiments on evaluation of horizontalvertical well

configuration in a scaled model of two vertical wells and four horizontal well for a high

viscosity oil (11000 cp) The main objective was to compare the feasibility of steam

flood and SAGD in a high mobility reservoir The results showed that a horizontal well-

pair steam flood is more suitable than a classic SAGD [8]

Experiments and simulation were also carried out by Nasr and his colleagues [9] A

two-dimensional scaled gravity drainage experiment model was used to calibrate the

simulator The results obtained from simulation promoted insight into the effect of major

parameters such as permeability pressure difference between well pair capillary pressure

and heat losses on the performance of the process [9]

24

Chan [10] numerically modeled SAGD performance in presence of an overlying gas

cap and an underlying aquifer It was pointed out that the recovery in these situations may

be reduced by up to 20-25 depending on the reservoir setting

Nasr and his colleagues ran different high pressure tests with and without naphtha as

an additive Steam circulation was eliminated and two methods to enhance recovery were

proposed as they believed steam circulation causes delay in oil production [11]

Sasaki [12 13] reported an improved strategy to initialize the communication

between the injector and producer An optical-fiber scope with high resolution was used

together with thermocouples to better observe the temperature distribution of the model

It was found that oil production rate increased with increasing vertical spacing however

the initiation time of the start of production was postponed A modified process was

proposed to tackle this problem

Yuan et al [14] investigated the impact of initial gas-to-oil ratio on SAGD

performance A numerical model was validated through history matching experimental

tests and thereafter the numerical model was utilized for further study Based on the

results they could not conclude the exact impact of the gas presence They stated that it

mostly depends on reservoir conditions and operations

Different aspects of improving SAGD performance were discussed by Das He

showed that low pressure has two advantages of lower H2S generation and less silica

production but has a tendency to require artificial lift [5]

The start-up phase of the SAGD process was optimized using a fully coupled

wellborereservoir simulator by Vanegas Prada et al [15] They conducted a series of

sensitivity runs for evaluating the effects of steam circulation rate tubing diameter

tubing insulation and bottom hole pressure for three different bitumen reservoirs

Athabasca Cold Lake and Peace River

The production profile in SAGD process consists of different steps such as

Circulation Ramp-up Plateau and Wind-down Li et al [16] studied and attempted to

optimize the ramp-up stage The effect of steam injection pressure on ramp-up time and

the associated geo-mechanical effect were investigated as well The results demonstrated

that the higher injection pressure would reduce the ramp-up period and consequently the

contribution of the geo-mechanical effect in the ramp-up period would be greater [16]

25

Barillas et al [17] studied the performance of the SAGD for a reservoir containing a

zone of bottom water (aquifer) The effect of permeability barriers and vertical

permeability on the cumulative oil was investigated Their result was a bit unusual since

they concluded that the lower kvkh would increase the oil recovery factor [17]

Albahlani and Babadagli [18] provided an extensive literature review of the major

studies including experimental and numerical as well as field experience of the SAGD

process They reviewed the SAGD steps and explained the role of geo-mechanical and

operational effects [18]

The effects of various operational parameters on SAGD performance were discussed

in the previous chapter However the geological (reservoir) characteristics and

heterogeneities play the most significant role in recovery process performance While

every single reservoir property has a specific impact on SAGD process heterogeneity is

the most critical aspect of the reservoir which has a direct effect on both injection and

production behavior Heterogeneity may consist of significant sized shale layers or may

be grain-sized barriers whose effect is reflected by a lower vertical than horizontal

permeability A significant concern in the development of the SAGD process is that of

the possible effects of barriers to vertical flow within the reservoir

Yang and Butler [19] conducted several experiments using heterogeneity in their

physical model Various scenarios such as two layered reservoir high permeability

above low permeability and low permeability above high permeability long horizontal

barrier short horizontal barrier and tilted barrier The results demonstrated that in the two

layered reservoir a faster production rate would be achieved when the high permeability

layer is located above the low permeability zone In addition they showed that the short

horizontal barrier does not affect the process [19]

Chen and Kovscek [20] numerically studied the effect of heterogeneity on SAGD A

stochastic model in which the reservoir heterogeneity in the form of thin shale lenses was

randomly distributed throughout the reservoir Besides shale heterogeneity effect of

natural and hydraulic fractures was studied as well [20]

Several studies were conducted to evaluate the contribution of various parameters in

the SAGD process One of the parameters that control the SAGD performance is the well

configurations Over the life of SAGD the only well configuration that has been field

26

tested is the standard 11 configuration which has a horizontal injector lying

approximately 5 meters above a horizontal producer in the same vertical plane On the

course of well configuration some 2-D experimental and 3-D numerical simulations were

conducted which mostly compared the efficiency of vertical vs horizontal injectors It

seems that well configuration is an area that has not received enough attention

Chung and Butler tested two different well configurations the first scheme used

parallel wellbores while the second one used a vertical injector which was perforated near

the top of the model Figure 2-1 displays both schemes [6]

Figure 2-1 Chung and Butler Well Schemes [6]

Chan conducted a set of numerical simulations including the standard SAGD well

configuration as displayed in Figure 2-2A He captured additional recovery up to 10-15

in offsetting the producer from injector The staggered well pattern provided the best

results within all the proposed configurations in terms of RF Increasing drawdown or

fluid withdrawal rate could also enhance oil recovery of SAGD process under those

conditions [9]

Joshi studied the thermally aided gravity drainage process by laboratory experiments

He investigated SAGD performance for three different well configurations 1) a

horizontal well pair 2) a vertical injector and a horizontal producer and 3) a vertical well

pair Figure 2-2B presents the schematic of the well patterns The maximum oil recovery

27

was observed in the horizontal well pair It was also shown that certain vertical fracture

may help the gravity drainage process especially at the initial stage as the fracture gave

a higher OSR than the uniform pack [21]

Top of Formation

Conventional Offset Staggered

Injector

Producer

Base of Formation

Figure 2-2A Well Placement Schematic by Chan [9]

Figure 2-2B Joshirsquos well pattern [20]

Leibe and Butler applied vertical injectors for three types of production wells

vertical horizontal and planar horizontal Effect of well type steam pressure and oil

properties were studied [22]

Nasr et al [10] conducted a series of experimental well configuration optimization

Figure 2-3 displays a summary of their studied patterns Their objective was to combine

an existingnewly drilled vertical well with the new SAGD well-pairs The experiments

were conducted in a 2-D scaled visual model and total of 5 tests were achieved The

combined paired horizontal plus vertical well was able to sweep the entire model in fact

chamber was growing vertically and horizontally The vertical injector accelerated the

communication between injector and producer The RF was improved from 40 up to

28

60 In addition they showed that for a fixed length of horizontal injector the longer

producer would show better performance [10]

Figure 2-3 Nasrrsquos Proposed Well Patterns [10]

The main goal of the industry has been to reduce the cost of SAGD operations which

drives the need to create and test new well patterns The Single well SAGD was

introduced to use a single horizontal well for both injection and production Figure 2-4

display the SW-SAGD well pattern It was field tested primarily at Cold Lake area Later

on several studies were conducted to investigate and optimize SW-SAGD [23] Luft et al

[24] improved the process by introducing insulated concentric coiled tubing (ICCT)

inside the well which would reduce the heat losses and was able to deliver high quality

steam at the toe of the well Falk et al [25] reviewed the success and feasibility of SW-

SAGD and confirmed ICCT development They reported the key pilot parameters and

reviewed the early production data

Polikar et al [26] proposed a new theoretical configuration called Fast-SAGD An

offset well with the depth and length as the producer was horizontally drilled 50 meters

away from the producer The offset single well is operated under Cyclic Steam

Stimulation mode They found that the offset well would precipitate the chamber growth

and increases the ultimate recovery factor

Shin and Polikar [27] focused on FAST-SAGD process and examined several more

patterns as displayed in Figure 2-5 They confirmed the enhancement of SAGD via

FAST-SAGD process In addition they demonstrated that addition of two offset wells on

29

either sides of a SAGD well-pair would enhance the total performance by increasing the

RF and decreasing the cSOR

Figure 2-4 SW-SAGD well configuration [23]

Figure 2-5 SAGD and FAST-SAGD well configuration [27]

Further investigation of the effects of well pattern was done by Ehlig-Economides

[28] Inverted multilevel and sandwiched SAGD were simulated for the Bachaquero

field in Venezuela (Figure 2-6) She included an extra producer in the new well schemes

of multilevel and sandwiched The idea was to utilize and optimize the heat transfer to the

reservoir The results showed that a large spacing between injector and producer is

beneficial and the available excess heat in the reservoir can be captured through extra

producer

30

Figure 2-6 Well Pattern Schematic by Ehlig-Economides [28]

Stalder introduced a well configuration called Cross-SAGD (XSAGD) for low

pressure SAGD The proposed pattern is displayed in Figure 2-7 The main idea is to

solve the limitation in oil drawdown due to steam trap control which originates from the

small spacing between injector and producer The injectors are located several meters

above the producers but they are perpendicular to each other The main concept behind

this well configuration is to move the injection and production point laterally once the

communication between injector and producer has been established In order to improve

the oil rate and obtain thermal efficiency the section of the wells close to the crossing

points requires to be either restricted from the beginning or needs to be plugged later on

The XSAGD results were much more promising at lower pressures [29]

Figure 2-7 The Cross-SAGD (XSAGD) Pattern [29]

31

Gates et al [30] proposed JAGD scheme for the reservoirs with vertical viscosity

variation The injector is a simple horizontal wellbore located at the top of the formation

but the producer is designed to be J-shaped to access all the reservoir heterogeneity They

proposed that the heel of the producer needs to be in vicinity of the base of the net pay

while the toe has to be several meters below the injectorrsquos toe Figure 2-8 displays the

JAGD well configuration schematic Initially the injector would be used for just cold

production thereafter it is converted to the thermal process while the cold production has

no more economical benefits Gates et al conducted a series of numerical simulations

and believed that the thermal efficiency of JAGD is beneficially higher than the normal

SAGD for the selected reservoirs

Figure 2-8 The JAGD Pattern [30]

In 2006 a SAGD pilot was started in Russia introducing a new well configuration

called U-shaped horizontal wells which is displayed in Figure 2-9 The pilot contained

three well pairs with the length of 200-400m The well pairs were drilled into the

formation primarily vertically down to the heel then followed the horizontal section and

eventually drilled up to the surface at the toe The vertical distance between the well pairs

is 5m It was shown that the U-Shaped wellbores will effectively displace the oil for the

complex reservoir with the SOR of 32 tt [31]

32

Figure 2-9 U-Shaped horizontal wells pattern [31]

Bashbush and Pina [32] designed Non-Parallel SAGD well pairs for the warm heavy

oil reservoirs Two cases with azimuth variation were compared against the basic SAGD

well configuration The first case named as Farthest Azimuthal in which the injector was

drilled upward from heel to toe The second case was called as Cross Azimuth in which

the heels of producer and injector are 6rsquo apart in one direction and the toes are 14rsquo apart

in the other direction Both cases are presented in Figure 2-10 Based on the presented

results none of the new patterns were able to improve the SAGD performance and the

recovery of basic SAGD was more impressive and successful

Figure 2-10 The Schematic of well patterns proposed by Bashbush and Pina [32]

Since the main objective of this study is to evaluate the effect of well configuration

on SAGD performance for three bitumen and heavy oil reserved of Alberta Athabasca

Cold Lake and Lloydminster it would be beneficial to review the existing pilot and

commercial SAGD projects in these reservoirs

33

22 Athabasca SAGD has been field tested in many successful pilots and subsequently through

several commercial projects in Athabasca-McMurray Formation Currently the number of

active SAGD pilot and commercial projects in Athabasca is quite large Figure 2-11

presents an overview of SAGD projects in Athabasca

The Underground Test Facility (UTF) was the first successful SAGD field test project

which was initiated by AOSTRA at 40 km northwest of Fort Mc-Murray [34 35] The

test consisted of multiple phases ldquoPhase Ardquo was meant to be just a case study to validate

the SAGD physical process ldquoPhase Brdquo was aimed at the commercial feasibility of

SAGD process ldquoPhase Drdquo tested horizontal drilling from surface which was not

completely successful The pilot was operated until 2004 with the ultimate recovery of

approximately 65 and cSOR of 24 m3m3 Since then SAGD has been applied in

various pilot and commercial projects in Athabasca

CENOVUS (Encana) is currently running the largest commercial SAGD project in

Canada The Foster Creek project started as a pilot with 4 well pairs in 1997 and then

expanded to 28 well-pairs in 2001 Currently it consists of more than 160 well pairs and

is producing over 100000 bbld The pay zone is located at 450 m depth and the target

formation is Wabiskaw-McMurray [36]

JACOS started its own SAGD project in Hangingstone using 2 well pairs in 1999 [37

38] Due to the success of primary pilot the project was expanded to 17 well pairs in

2008 Currently they are producing 10000 bbld The project is producing from

Wabiskaw-MacMurray which has 280-310 m depth [39]

One of the best existing SAGD project with respect to its cSOR appears to be the

MacKay River (currently owned by Suncor) with the average cumulative SOR of 25

m3m3 This project was started with 25 well pairs in 2002 steam circulation started in

September 2002 thereafter the production commenced in November 2002 Later 16

additional well pairs were added in 20052006 This project is also producing from

Wabiskaw-McMurray formation which is located 150m below the surface [40 41]

Encana (now CENOVUS) started a 6 well-pairs pilot SAGD at Phase-1 Christina

Lake in 20022003 Christina Lake has the lowest cSOR which is equal to 21 m3m3

34

Currently MEG Energy is also running SAGD at Christina Lake The net pay which is

Wabiskaw-McMurray is located at ~ 400m depth [42 43 and 44]

ConocoPhilips started their SAGD operation with a 3-well-pairs pilot project at

Surmont in 2004 Two of these well pairs contain 350 m long slotted liners while the

third well contains a 700 m long slotted liner The commercial SAGD at Surmont started

steam injection in June 2007 and oil production later on in Ocotber Currently Surmont is

operated by ConcoPhilips Canada on behalf of its 50 partner Total EampP Canada The

reservoir depth is ~400 m and the formation is Wabiskaw-McMurray [45 46 and 47]

Figure 2-11 Athabasca Oil Sandrsquos Projects [33]

Suncor is also a leader in SAGD operations currently running the Firebag with 40

well-pairs and the MacKay River project mentioned earlier The first steam injection in

the Firebag project commenced in September 2003 and the first oil production was in

January 2004 [48] The average daily bitumen production rate is 48400 bblday with the

cSOR of 314 m3m3 However the current capacity is 95000 bbld

The shallowest SAGD operation started in North Athabasca which had 90-100m

depth The Joslyn pilot project started with a well-pair and steam circulation in April

2004 While the Phase II of the project was ongoing a well blowout occurred in May

2006 Currently there is no injection-production in that area [49]

35

A 6535 joint venture of Nexen and OPTI Canada (now CNOOC Canada) phase 1 of

the Long Lake Project is the most unique SAGD project in Athabasca area The Long

Lake project is connected to an on-site upgrader The project involved three horizontal

well pairs at varied length from 800-1000 m 150 m well spacing Phase 1 of the project

is currently operational with a full capacity of 70000 bd operation that will extract crude

oil from 81 SAGD well-pairs and covert it into premium synthetic crude oil [50 51]

Devon started its Jackfish SAGD project in Athabasca drilling 24 well-pairs in 4 pads

in 2006 at a depth of 350m The target formation was Wabiskaw-McMurray First steam

injection commenced in 2007 The project capacity was designed for 35000 bbld

Currenlty the average cSOR is 24 m3m3 The second phase of Jackfish project

construction was started in 2008 and it is identical to the first phase of Jackfish 1 [52 53]

23 Cold Lake Cyclic Steam Stimulation (CSS) is the main commercial thermal recovery method

employed in the Cold Lake area Currently the largest thermal project across Canada is

the CSS operated by Imperial Oil However CSS has its own limitations which point to

application of SAGD at Cold Lake More recently Steam-Assisted Gravity Drainage

(SAGD) has been field tested in number of pilot projects at Cold Lake

The first SAGD pilot at Cold Lake area was Wolf Lake project Amoco started the

project in 1993 by introducing one 825 m horizontal well-pair in Clearwater Formation

The high cSOR and low RF of first three years operation forced Amoco to change the

project into a CSS process [54 55]

Suncor proposed Burnt Lake SAGD project with the target zone of Clearwater

Formation in 1990 and the operation was started in 1996 Later Canadian Natural

Resources Limited (CNRL) acquired the operation of Burnt Lake in 2000 It consists of

three well-pairs of 700 -1000m well length The reported cSOR and RF till end of 2009

were 39 m3m3 and 479 respectively [55 56]

The Hilda Lake pilot SAGD project was commenced by BlackRock in 1997 Two

1000 m well-pairs were drilled in the Clearwater Formation The operation was acquired

by Shell in 2007 The cSOR and RF at the end of 2009 were 35 m3m3 and 35 [57]

36

Amoco started its second SAGD pilot project in 1998 in Cold Lake area The pilot

included just one well pair of 600 m length which was drilled in Clearwater Formation

The Pilot was on operation for two years and due to high cSOR and low RF of the project

was turned into a CSS process [54]

Orion is a commercial project located in Cold Lake area producing from Clearwater

Formations Shell has drilled total of 22 well pairs with the average well length of 750m

However only 21 of them are on steam The first steam injection commenced in 2008

The cSOR is high due to early time of the project and the reported RF is 6-7 [54]

Husky established its own commercial SAGD at Cold Lake where the drilling of 32

well-pairs was completed in second half of 2006 The well-pairs have approximately

700m length The Tucker project aimed at producing from Clearwater formation with a

depth of ~400m First steam injection was initiated in November 2006 Eight more well-

pairs were appended to the project in 2010 The cSOR to end of May 2010 was above 10

m3m3 while the RF is below 5 [58]

Although SAGD has been demonstrated to be technically successful and

economically viable questions remain regarding SAGD performance compared to CSS

A more comprehensive understanding of the parameters affecting SAGD performance in

the Cold Lake area is required Well configuration is one of the major factors which

require greater consideration for process optimization Nevertheless the only well

configuration that has been field tested is the standard 11 configuration

24 Lloydminster The Lloydminster area which is located in east-central Alberta and west-central

Saskatchewan contains huge quantities of heavy oil The reservoirs are mostly complex

and thin and comprise vast viscosity range The peculiar characteristics of the

Lloydminster deposits containing heavy oil make almost every single production

techniques such as primary waterflood CSS and steam-flood uneconomic and

inefficient In fact the highly viscous oil coupled with the fine-grained unconsolidated

sandstone reservoirs result in huge rates of sand production with oil Although these

techniques may work to some extend the recovery factors remain low (5 to 15) and

large volumes of oil are left unrecovered when these methods have been exhausted

37

Because of the large quantities of sand production many of these reservoirs end up with a

network of wormholes that makes most of the displacement type enhanced oil recovery

techniques unsuitable Among the applicable methods in Lloydminster area SAGD has

not received adequate attention

Huskys Aberfeldy steam drive pilot started in February 1981 with 43 well drills out

of which 7 wells were for steam injection The pilot was on primary production for a

couple of years and the target zone was the Sparky Sands at 520m depth [59]

CSS thermal recovery at Lloydminster began in 1981 when Husky started the Pikes

Peak project It developed the Waseka sand at the depth of 500 meters which is a fairly

thick sand of higher than 10m pay The project initially consisted of 11 producing wells

In 1984 the project was altered into steamflood since the inter-well communication was

established Later on up to 2007 the project was expanded to 239 wells including 5

SAGD well-pairs The project has become mature with the recovery factor of around 70

percent [59 60]

The North Tangleflags reservoir contains fairly thick Lloydminster channel sand

(about 30 meters thick) The reservoir quality including porosity permeability and oil

saturation can be considered as superior Despite the encouraging initial oil rate primary

production failed due to the high viscosity oil of 10000 cp and water encroachment from

the underlying bottom water While the aquifer is only 5 metres compared to the oil zone

thickness of 30 metres the aquifer is quite strong and dominates primary production

performance limiting primary recovery to only a few percent In 1987 the operator

Sceptre Resources constructed a SAGD pilot which included four vertical injectors and a

horizontal producer The steam injection inhibits water encroachment as well as reducing

oil viscosity and this resulted in high recovery factor and low steam oil ratio In 1990 a

new horizontal well was added and performed the same manner as the existing one The

production well-pairs established an oil rate of as high as 200 m3d [61]

The Senlac SAGD project was initiated in 1996 with Phase A which consisted of

three 500m well pairs It is located 100 kilometers south of Lloydminster Alberta

Canada The target zone is the highly permeable channel sand of DinaCummings

formation buried 750 m deep Like other formations in the Lloydminster area the pay

zone is located above a layer of water In 1997 an extra 450 m well-pair was added to the

38

pilot Phase B was started in 1999 using three 500m well-pairs The vertical and

horizontal distance of the well-pairs is 5m and 135m respectively Later on Phase C

including two 750m of well-pairs was started up [62]

CHAPTER 3

GEOLOGICAL DESCRIPTION

40

31 Introduction Canada has the third largest hydrocarbon reserves after Venezuela and Saudi Arabia

containing 175 billion barrels of bitumenheavy oilcrude oil Currently the industry

extracts around 149 million barrels of bitumen per day [63] Figure 3-1 displays a review

of the bitumen resources and their basic reservoir properties

Figure 3-1 Albertarsquos bitumen resources estimate volume as of December 31 2011 [64]

The huge reserves of bitumen and heavy oil in Alberta are found in variety of

complex reservoirs The proper selection of an in-situ recovery method which would be

suitable for a specific reservoir requires an accurate reservoir description and

understanding of the geological setting of the reservoir In fact a good understanding of

the geology is essential for overcoming the challenges and technological difficulties

associated with in-situ oil sands development

Alberta has several types of hydrocarbon reserves but the major bitumen and heavy

oil deposits are Athabasca Cold Lake Peace River and Lloydminster Figure 3-2

displays the location of the extensive bitumen and heavy oil reservoirs across Alberta and

41

Saskatchewan The main deposits are in the Lower Cretaceous Mannville Group which is

found running from Northeastern Alberta to Southwest Saskatchewan

Figure 3-2 Bitumen and Heavy Oil deposit of Canada [65]

In this chapter a brief review of the geological description associated with the three

major oil sand and heavy oil reservoirs of Athabasca Cold Lake and Lloydminster is

presented

32 Athabasca This section of the geology study covers the Athabasca Wabiskaw-McMurray oil

sands deposit

Athabasca oil sands deposit is the largest petroleum accumulation in the world

covering an area of about 46000 km2 [66] In the Athabasca oil sand most of the

bitumen deposits are found within a single contiguous reservoir the lower cretaceous

McMurray-Wabiskaw interval Albertarsquos oil sands are early Cretaceous in age which

means that the sands that contain the bitumen were originally laid down about 100

million years ago [67] The McMurray-Wabiskaw stratigraphic interval contains a

significant quantity (up to 55) of the provincersquos oil sands resources Extensively drilled

studied and undergoing multi-billion dollar development the geology of this reservoir is

well understood in general but still delivers geological surprises

42

Both stratigraphic and structural elements are engaged in the trapping mechanisms of

Athabasca deposit The McMurray formation was deposited on the Devonian limestone

surface in a north-south depression trend along the eastern margin of the Athabasca oil-

sands area There is a structural dome in the Athabasca area which resulted from the

regional dip of the formation to the west and the salt collapse in the east [68] As

displayed in Figure 3-3 most of the reserves in Athabasca area are located east of this

anticline feature

Figure 3-3 Distribution of pay zone on eastern margin of Athabasca [69]

The thickest bitumen within the Athabasca McMurray-Wabiskaw deposit is generally

located in a northndashsouth trending channel complex along the eastern portion of the

Athabasca area Figure 3-4 displays the pay thickness of McMurray-Wabiskaw in

Athabasca area This bitumen trend contains all existing and proposed SAGD projects in

the Athabasca Oil Sands Area Outside the area the McMurray-Wabiskaw deposit

43

typically becomes thinner channel sequences are less predominant and the bitumen is

generally not believed to be exploitable using SAGD or reasonably predictable thermal

technologies Within the area of concern there is approximately 500 billion barrels of

bitumen in-place in the McMurray-Wabiskaw

Figure 3-4 Pay thickness of McMurray-Wabiskaw in the Athabasca Area [64]

As mentioned earlier currently there are two available commercial production

methods for the exploitation of bitumen out of McMurray-Wabiskaw Formations either

open-pit mining or in-situ methods The surface mining is able to extract approximately

10 percent of the reserves and mostly from the reserves situated along the valley of the

Athabasca River north of Fort McMurray The Cretaceous Formation in Athabasca River

has been eroded in a way that the oil sands are exposed in vicinity of the surface and

provide access for the shovel and trucks Figure 3-5 displays the cross view of the

Cretaceous Formation in Athabasca River The rest of the reserves are situated too deep

44

to provide access for the surface mining facilities and their recovery requires in-situ

methods However there are some deposits with a buried depth of 80-150m that are too

deep for surface mining and too shallow for steam injection

Figure 3-5 Athabasca cross section [69]

There is no official and formal classification for the stratigraphic nomenclature of the

Athabasca deposit however it has been developed based on experience Generally the

geologists divide the McMurray formation into three categories of Lower Middle and

Upper members This simple scheme may be valid on a small scale but when extended to

a broader scale may no longer apply [70] This historical nomenclature fails in some part

of the McMurray Formation In some areas McMurray Formation just includes lower

and upper members while in other parts of McMurray only middle and upper members

exist

The McMurray Formation is overlain by the Wabiskaw member of the Clearwater

Formation which is dominantly marine shale and sandstone The Clearwater itself is

located underneath the Grand Rapids Formation which is dominated by sandstone

Clearwater Formation acts as the cap rock for the McMurray reservoirs which prevents

45

any fluid flow from McMurray formation to its overlaying formation or ground surface

The thickness of Clearwater formation varies between 15 to 150m [71] The thickness

and integrity of Clearwater formation is essential since it must be able to hold the steam

pressure during the in-situ recovery operations However for the part of Athabasca where

the oil sand is shallow or the cap rock has low thickness special operating design such as

pressure and steam temperature is required

Figure 3-3 displays a summarized description of the facies characteristics through the

McMurray-Wabiskaw interval The McMurray Formation is located on top of the

Devonian Formation which is mostly shale and limestone

Age Group Wabasca Athabasca

Grand Rapids Grand Rapids

Clearwater ClearwaterU

pperM

annville Wabiskaw Wabiskaw

Lower C

retaceous

Lower

Mannville

McMurray McMurray

Mainly Sand Bitumen Saturated Sand

Figure 3-6 Correlation chart of Lower Cretaceous bitumen deposits at Athabasca Oil Sand

The Lower McMurray has good petro-physical properties it has high porosity and

permeability It mostly contains the bottom water in Athabasca area but in some specific

regions it comprises sand-dominated channel-and-bar complexes [69] The maximum

thickness of this member is up to 75m which is composed of mostly water-bearing sand

and is located above a layer of shale and coal The grain size in the lower member is

coarser than the other two members [68 72]

46

The Middle Member may have 15-30 m of rich oil-bearing sand and in some specific

areas it can even be up to 35 m Thin shale breaks are present while coal zone is absent in

the Middle McMurray The interface of Lower and Middle member is somewhere sharp

but it can be gradual as well In some specific areas of Athabasca the Middle member

channels penetrated into the Lower McMurray sediments deeply The upward-fining in

the Middle Member is typical [68 72]

The richest bitumen reserve among Athabasca deposit belongs to the Upper

McMurray member The Upper McMurrayrsquos channel sand thickness may be as high as 60

m with no lateral widespread shale discontinuity [69] This member is overlain by

Wabiskaw member of the Clearwater Formation Thin coal bioturbated sediments very

fine-grained and small upward coarsening sequences are typical in the Upper Member

[68] The Upper McMurray has somewhat lower porosity reduced permeability

compared to Lower McMurray The successful pilot and commercial schemes within the

Upper McMurray include the Dover UTF MacKay River Hangingstone and Christina

Lake

The Athabasca sands is comprise of approximately 95 quartz grains 2 to 3

feldspar grains and the rest is mostly clay and other minerals [67] The Athabasca sands

are very fine to fine-grained and moderately well sorted Shale beds within the oil sands

consist of silt and clay-sized material and only rarely contain significant amounts of oil

Less than 10 percent of the fines fraction is clay minerals [69] Low clay content and lack

of swelling clays differentiates it from other deposits in Alberta [68]

The McMurray Formation mostly occurs at the depths of 0 to 500 m The Athabasca

oil sands deposit is extremely heterogeneous with respect to physical reservoir

characteristics such as geometry component distribution porosity permeability etc

Several factors affect the petro-physical properties in Athabasca area and are attributed to

high porosity and permeability of McMurray Formation compared to the other sandstones

deposits minimum sediment burial early oil migration lack of mineral cement in the oil

sands which occupies the void space in porous media The petro-physical properties of

Athabasca are thought to have resulted from the depositional history of the sediments

However the bitumen properties are strongly affected by post depositional factors [71]

The reservoir and bitumen properties have a distinctive lateral and vertical variation It is

47

believed that the microbial degradations had a major effect on bitumen heterogeneity

across the Athabasca which resulted in heavier petroleum with accompanying methane as

a side product At reservoir temperature (11 degC) bitumen is highly viscous and immobile

The bitumen density varies from 6 to 11ordm API with a viscosity higher than 1000000 cP

Viscosity can vary by an order of magnitude over 50 m vertical span and 1 km lateral

distance

The single most fortunate characteristic feature of the Alberta oil sands is that the

grains are strongly water-wet However lack of this characteristic would not allow the

hot watersteam extraction process to work well

There are areas where basal aquifer with thickness of greater than 1 m are expected

however due to existence of an impermeable layer the oil-bearing zone is not always in

direct contact with bottom water [69]

33 Cold Lake The Cold Lake oil-sands deposit has been recognized as a highly petroliferous region

covering approximately 23800 km2 in east-central Alberta and containing over 250

billion barrels of bitumen in place it has the second highest rank for volume of reservesshy

in-place among the major oil sand areas in Canada [64] The bitumen and heavy oil

reserves at the Cold Lake area are contained in various sands of the Mannville Group of

Lower Cretaceous age Figure 3-7 and 3-8 present the correlation chart for Lower

Cretaceous bitumen and heavy oil deposits at Cold Lake area

As displayed on Figure 3-7 Cold Lake is inimitable in comparison with Athabasca

deposit all the formations in Mannville Group are oil bearing zones For this reason the

Cold Lake area provides an ideal condition for various recovery method applications

At Cold Lake the Mannville Group comprises the Grand Rapids Clearwater and

McMurray Formations Unlike the Athabasca Oil Sands more reserves belong to the

Grand Rapids and Clearwater Formations than the McMurray Currently the main target

of industry at Cold Lake area is Clearwater Formation Although the Grand Rapids has

higher saturation it is considered a future prospective target zone The Mannville Group

is overlain by the marine shale of the Colorado Group [73] At Cold Lake area the

48

Mannville sands are unconsolidated and the reservoir properties vary significantly over

the areal extension

Figure 3-7 Oil Sands at Cold Lake area [73]

Age Group Cold Lake Athabasca


Clearwater

Upper M

annville Clearwater Wabiskaw

Lower C

retaceous

Lower M

annville

McMurray McMurray

Mainly Sand Bitumen Saturated Sand Shale

Figure 3-8 Correlation chart of Lower Cretaceous at Cold Lake area

49

The Clearwater is an unconsolidated and oil-bearing formation It is located on top of

the McMurray section The Clearwater is overlain by the Lower and Upper Grand Rapids

Formation which extends to the top of the Manville Group The Formation quality is

moderate and the thickness can be as high as 50 m [73] At Clearwater Formation only

about 20 of the sand is quatz The rest is feldspar (~28) volcanics (23) chert

(~20) and the rest is other minerologies [74 75 and 76] The reservoir continuity in

horizontal direction is considered excellent but on the other hand there is vertical

discontinuity in the forms of shale and tight cemented sands and siltstones which occurs

irregularly There are also many calcite concretions present The petro-physical properties

are considered excellent with the average porosity being 30 to 35 and the average

permeability in the order of multiple Darcies [75 77] Figure 3-9 displays the cross

section of Clearwater Formation at Cold Lake area and the extension trend of the reserves

in Alberta

In contrast to the massive sands of the Clearwater Formation the oil bearing zone in

the upper and lower members of the Grand Rapids Formation are thin and poorly

developed [75] In the Grand Rapids heavy oil can be associated with both gas and

water The gas can exist in forms of solution gas and gas cap Mostly the Upper Grand

Rapids has high gas saturations and acts as the overlaying gas cap formation

Fig 3-9 Clearwater Formation at Cold Lake area [75]

50

In the lower member of the Grand Rapids Formation reservoirs contain thin sands

with the interbedded shale the sands thickness ranges from 4-7 m but at some specific

zones the formation can be as thick as 15m The bed continuity is in sheet form and

considered as good but existence of occasional shale leads to poor reservoir continuity

The Lower Grand Rapid Formation has a fairly good continuity in both vertical and

horizontal directions Reservoir sands are fine to medium-grained and well sorted

Porosity can be as high as 35 while the permeability is in multi-Darcy range [78]

Figure 3-10 demonstrates the extension and cross plot of Lower Grand Rapids Formation

in Cold Lake area The lower Grand Rapids Formation is saturated with higher viscosity

bitumen and the solution gas is much lower than the Clearwater Formation [76] This

makes the Lower Grand Rapids a less desirable target zone for thermal applications

Another critical issue is that the formation is in contact with the water bearing sands The

Lower Grand Rapids formation has had a history of sand production problems due to its

highly unconsolidated nature

Fig 3-10 Lower Grand Rapids Formation at Cold Lake area [74]

In the upper member of the Grand Rapids Formation reservoirs consist of mostly gas

but in some regions the formation has oil bearing zone with the interbedded shale layers

The reservoirs are discontinuous with the average thickness of 6m Shale layer interbeds

are typical The sands are poorly to well sorted with a fine to medium grain size Porosity

51

is less than 35 and permeability is generally poor due to high silt and clay content

[75] Figure 3-11 displays the cross section of the Upper Grand Rapids Formation

The McMurray Formation at Cold Lake area has basal sand section upper zone of

thinner sand and interbedded shale layers The upper zone is generally oil-bearing sands

while the basal sand is mostly water saturated zone [74] Therefore the formation is

formed of couple of single pay zones which offers the possibility of multi-zone

completion The McMurray Formation at Cold Lake area is over a layer of aquifer The

deposit is fairly thin with the maximum thickness of 9m The lateral continuity of the

formation is fairly good but the vertical communication suffers from interbedded shale

layers The sands are fine to medium grain size and moderately well sorted The average

porosity is 35 which implies good permeability [75] Figure 3-12 presents the cross

view of the McMurray Formation at Cold Lake area

Fig 3-11 Upper Grand Rapids Formation at Cold Lake area [75]

52

Fig 3-12 McMurray Formation at Cold Lake area [75]

Most of Cold Lake thermal commercial operational target is Clearwater Formation

which is mostly at the depth of about 450 m The minimum depth to the first oil sand in

Cold Lake area is ~300m Grand Rapids Formation is a secondary thermal reservoir At

Clearwater the sands are thick often greater than 40m with a high netgross thickness

ratio Porosity ranges from 30 to 35 with oil saturations that average 70 PV At the

initial reservoir temperature of 13 degC the oil viscosity is about 100000 cp It is ordinary

to find layers of mud interbeds shale and clasts in Clearwater Formation Existence of

any clays or mud interbeds tends to significantly reduce the porosity of sediments and

consequently reducing permeability [77] The major issue in SAGD application in Cold

Lake area is the presence of heterogeneities of various forms

Generally the net pay at Cold Lake area is higher than the one in Athabasca On the

other hand Cold Lake reservoirs contain lower viscosity lower permeability higher

shale percentage lower oil saturation and extensive gas over bitumen layers

The main production mechanism in Cold Lake area is Cyclic Steam Stimulation

which has been the proven commercial recovery method since 1980rsquos Steam is injected

above formation fracture pressure and fractures are normally vertical oriented in a northshy

east to southwest direction However the CSS process has various geological and

operational limitations which make its applications so limited Unlike the CSS process

this area is in its in infancy for the SAGD applications Due to specific Cold Lake

53

reservoir properties SAGD method was less attractive here than in Athabasca A limited

number of SAGD projects have been field tested in the Lower Grand Rapids and

Clearwater Formations at Cold Lake area The Burnt Lake (Shell) and Hilda Lake

(Husky) were designed to produce bitumen from the Clearwater formation via the SAGD

process Later on since CSS had discouraging results at Lower Grand Rapids in the Wolf

Lake area due to extensive sand production BP and CNRL replaced CSS with the

SAGD The results demonstrated promising behaviour

34 Lloydminster Large quantity of heavy oil resources are present in variety of complex thin reservoirs

in Lloydminster area which are situated in east-central Alberta and west-central

Saskatchewan The area has long been the focal point of heavy oil development Figure

3-13 displays the latitude of Lloydminster area The whole area covers about 324

townships or 29 860 km2 [80] The Lloydminster heavy oil sands are contained in the

Mannville Group sediments which are early Cretaceous in age The Lower Cretaceous

contains both bitumen and heavy oil and has a discontinuous north-south trend which

starts from Athabasca in the north passes through Cold Lake and ends up in the

Lloydminster area [81]

At Lloydminster the entire Mannville Group is considered a target zone Which is

completely different from that which was characterized in Central Alberta In the

Lloydminster area interbedded sandstones with layers of shale and mudstones are

overlain by coals which occur repeatedly throughout the entire Mannvile Group [82 83]

Thus the Mannville Group is a complex amalgamation sandstone siltstone shale and

coal which are overlain by the marine shale sands of Colorado Group [80] The

sandstones are mostly unconsolidated with porous cross-beddings The shale is generally

bioturbated with a gray color which has acted as a hydrocarbon source rock [83]

In the Lloydminster area the Mannville Group can be subdivided into groups of the

Lower Middle and Upper members Each member informally comprises a number of

formations Different stratigraphic nomenclatures have been used in the Lloydminster

heavy oil area A summary of different subdivisions for the Mannville Group is presented

in Figure 3-14

54

Figure 3-13 Location of Lloydminster area [80]

There are some discrepancies in subdivision of the Mannville Group members

because of drastic lateral changes in facies Some geologists assign only Dina formation

to the lower Mannville while others include Lloydminster and Cummings Formations as

well In this research the stratigraphic nomenclature which is presented on Figure 3-14

has been considered As displayed on Figure 3-14 the Mannville group at Lloydminster

area is subdivided into nine stratigraphic units

The Lower Mannville contains Dina Formation which is formed of thick and blocky

sandstone Its thickness can reach as high as 67 m A layer of thick coal is located on top

of Dina This is the thickest coal in Manville Group at Lloydminster area which can be up

to 4m thick

55

Age Group Cold Lake Lloydminster

Colony

McLaren

Waseca U

pperGrand Rapids

Clearwater

Sparky

GP

RL-Rex

Lloydminster

Cummings

Middle

Lower C

retaceous

Mannville G

roup

McMurray Dina

Low

er

Mainly Sand

Heavy Oil Saturated Sand

Shale

Figure 3-14 Correlation chart of Lower Cretaceous at Lloydminster area

The Dina Formation is corresponding to the McMurray Formation in the Lower

Mannville Group of the Northern and Central Alberta basin [81] It is both oil and a gas

bearing zone but due to small reserve is not considered as a productive zone [84] The

sandstones are fine to medium-grained size and mainly well-sorted with some layers of

coal and shale

The Middle Mannville consists of five distinct members Cummings Lloydminster

RL-Rex General Petroleum (GP) and the Sparky This member is comprised of narrow

Ribbon-Shaped sandstone and shale layers [80] The associated thickness for each single

formation is approximately 6-9m and their range in width is about 16-64 km and in

length is 15-32 km [85]

The Sparky sandstone is very fine to fine-grained well sorted coarsening upward

with cycles of interbedded shale A thin coaly unit or highly carbonaceous mudstone is

usually present right at the top of Sparky unit [82] The Sparky Member might have a

thickness of up to 30m and usually with a 1m to 2m of mudstone The length of the

56

channel sand could extend in order of tens of kilometers while its width would be in

range of 03-2 km The water saturation in higher part of the Sparky is about 20 percent

whilst due to a transition zone in the lower part of Sparky the water saturation increases

as high as 60 percent [85] The permeability of the Sparky formation ranges between 500

to 2000 mD

GP Member with the maximum thickness of up to 18m thick (Average net pay of 6m)

is located beneath the Sparky member and has a fairly constant recognizable thickness

[86] The sands of GP are mostly oil saturated very fine-grained and well sorted A layer

of shale is situated beneath the oil stained sands of GP The clean sand porosity of the GP

usually exceeds 30 GP is less productive than Sparky

Rex Member can not be counted as a good pay among the Middle Mannvile Group It

included series of shale layers near the base of the formation and coal at the top Its

thickness may vary from 15-24m [87]

The Lloydminster is the most similar to the GP in terms of thickness and distribution

It consists of shale layers which are mostly gray with the very fine to fine grained sands

Thin layer of coal exists near the top of Lloydminster Formation The sands are mostly

oil stained but have high water saturation as well

The Cummings Member has a thickness of 12-48m containing highly interbedded

light gray shale Like the other members at Middle Mannville the sandstone is ribbon

shaped and mostly sheet sand stone (several tens of km2) [80] It has both oil and gas

saturations but it is not considered as commercially productive

Figure 3-15 clearly presents the distribution of Ribbon-Shaped Mannville group

57

Figure 3-15 Distribution of Ribbon-Shaped Manville Group at Lloydminster area [80]

The Upper Mannville comprises Colony McLaren and Waseca Formation This zone

has the same sandstone distribution as in the Middle Mannville The sandstones are

discontinuous and sheet-like which have variable thickness and width but mostly in the

range of 35 m and 300 m respectively [80] Variable successions of coal layers are

present throughout the Upper Member The Upper Mannville has both oil and gas zones

but the gas zone is situated in Alberta while the oil bearing horizons are mostly in the

Saskatchewan side [87]

The Colony and McLaren are usually difficult to differentiate Both are comprised of

fine to very fine grained sandstone with the interbedded light gray shale and variable coal

sequences [86 88] Their thickness can be as high as 61m while 6 m of that could be

shale or coal The oil and gas saturations are not commonly distributed over the entire

area but these formations are mostly gas stained However some local oil or gas stained

deposits can be found as well

Waseca Formation follows the same trend as the members of Middle Mannville

Group It consists of two pays with the thickness of 3-6m which is separated by 1m thick

58

interbedded shale layer [87] The lower part of Waseca Formation is oil saturated zone

and has high quality with porosity of ranging from 30-35 and permeability of 5-10

Darcyrsquos

In the Lloydminster area the target formations have quite a range and unlike the

Athabasca and Cold Lake area there is no specific and single pay for the current and

future developments However most of the Mannville Group formations are situated at

depth of about 450-500 m

The conventional oil ranges from heavy (lt15deg API) to medium gravity (up to 38deg

API) at reservoir temperature The Mannville Group sands in general have quite a large

range of the viscosity the crude oil viscosity ranges from 500 to 20000 cp at reservoir

temperature of 22 degC Water saturation varies between 10 to 20 percent The porosity and

permeability of most formations in Mannville Groups are 22-32 percent and 500-5000

mD respectively The rocks are mostly water wet but in some specific areas they can be

oil wet as well

The recovery mechanism in the study area is mostly primary depletion which is

principally by solution gas drive and gas cap expansion The primary recovery has a low

efficiency of about 8 due to high crude oil viscosity low solution GOR and low initial

reservoir pressure At the same time due to bottom water encroaching high water cuts

can be observed as well However numerous primary and secondary (mostly water-

flood) projects are being implemented in the area Figure 3-16 presents various active

projects in the Lloydminster area

The reservoirs are mostly complex and thin with a wide range of oil viscosity These

characteristics of the Lloydminster reservoirs make most production techniques such as

primary depletion waterflood CSS and steamflood relatively inefficient The highly

viscous oil coupled with the fine-grained unconsolidated sandstone reservoir often

result in huge rates of sand production with oil during primary depletion Although these

techniques may work to some extent the recovery factors remain low (5 to 15) and


Because of the large quantities of sand production many of these reservoirs end up

with a network of wormholes which make most of the displacement type enhanced oil

recovery techniques inapplicable

59

For heavy oil reservoirs containing oil with the viscosity smaller than 5000 cp both

SAGD and steam-flooding can be considered applicable for extraction of the heavy oil

Minimum reservoir thickness of at least 15 meters is likely required for SAGD to be

applicable In fact this type of reservoir provides more flexibility in designing the thermal

recovery techniques as a result of their higher mobility and steam injectivity Steam can

be pushed and forced into the reservoir displacing the heavy oil and creating more space

for the chamber to grow There is considerable field experience available for developing

such techniques Aberfeldy steam drive pilot CSS thermal recovery at Pikes Peak North

Tangleflags SAGD pilot project and Senlac SAGD project

Figure 3-16 Lloydminster area oil field [89]

35 Heterogeneity The Albertarsquos oil sands deposits are extremely heterogeneous with respect to physical

reservoir characteristics and fluid properties Therefore the recovery methods which

depend on inter-well communication will suffer in Alberta deposits since the horizontal

continuity is commonly poor The reservoir heterogeneities have a deep impact in steam

chamber development and the ultimate recovery of SAGD In high quality reservoirs

60

which encounter no shale barrier or thief zones the classic SAGD chamber would be in

the form of inverted triangle pointing to the producer while for the poor quality reservoirs

the form of steam chamber is more elliptical than triangle and will be driven by

heterogeneities

The feasibility of SAGD field implementation depends on various reservoir

parameters such as reservoir geometry horizontal and vertical permeability depth net-

pay thickness bottom water overlaying gas cap existence of shale barriers component

distribution cap rock thickness viscosity of bitumen etc Detailed characterization of

above aspects is required to better understand the reservoir behaviour and reactivity at

production conditions SAGD performance depends directly on the presence or absence

of these factors

In controlling SAGD performance the following factors play critical roles

frac34 Horizontal continuity of cap rock

frac34 Ease of establishing an efficient communication between Injector and Producer

frac34 Presence of any heterogeneity across the net pay and their laterallongitudinal

extension

frac34 Extent of shale along the wellbore

frac34 Existence of bottom water or gas cap

frac34 Presence of lean zones (thief zones)

Both Lloydminster and Cold lake area have quite a thick and continuous cap rock laid

over the pay zones The horizontal continuity of cap rock within the McMurray

Formation is relatively poor and in some regions there is no cap rock at all and if shallow

enough the bitumen is extracted by surface mining

The shale heterogeneity is a minor issue at Athabasca while it creates serious

concerns at Cold Lake and Lloydminster area McMurray formation almost exhibits

analogous characteristics over the Athabasca region but some local heterogeneity also

exists There is no specific way to determine the extension of shale barriers in the oil

sands deposits The effect of shale presence on SAGD performance needs to be evaluated

through numerical simulations

In addition to the shale barriers and cap rock continuity water and gas zones have a

deep impact in steam chamber development and the ultimate recovery The bottom water

61

and gas cap thickness varies over few meters over the entire area of Alberta Their impact

on SAGD is variable and really depends on their thickness and extension over the entire

net pay In the McMurray less gas cap and bottom water exists while at Cold Lake and

Lloydminster and specifically at Lloydminster there are few formations which are not in

contact with gas or water zones

CHAPTER 4

EXPERIMENTAL EQUIPMENT AND

PROCEDURE

63

This chapter describes first the experimental equipment and second the experimental

procedures used to collect and analyse the data presented A consistent experimental

procedure was kept throughout the tests

The equipment description is presented in three sections a) viscosity and

permeability measurement equipment b) the equipment which comprised the physical

model setup and c) sample analysis apparatus

41 Experimental Apparatus The schematic of the SAGD physical model is presented in Figure 4-1

Steam

Water

Load Cell

Steam

Model Temperature

Figure 4-1 Schematic of Experimental Set-up

The model comprised several components including a) Steam Generator b) Data Acquisition

System c) Temperature Probes and d) Physical Model

411 3-D Physical Model

Physical models have been assisting the development of improved understanding of

complex processes where analytical and numerical solutions require numerous

simplifications During the past decades physical models have become a well-established

64

aid for improving the thermal recovery methods The physical models for studying

thermal recovery can be either in the form of partial (elemental) or fully scaled models

Due to the issues with respect to the handling operating and sampling of the thermal

projects usually elemental models have been incorporated to study the thermal processes

For the SAGD process the scaling criteria proposed by Butler were used in this study to

scale down the target reservoirs to the physical model size Butler analysed the

dimensional similarity problem in SAGD and found that a dimensionless number B3 as

given by the equation below must be the same in the field and the physical model [1]

kghB3 = αφΔSomυs

The dimensional analysis includes some approximations and simplifications as well

Some parameters were excluded from the above dimensional analysis and consequently

would be un-scaled between reservoir and physical model These parameters are rock-

fluid properties such as relative permeability and capillary pressure and thermal

expansion-compression emulsification effect and wellbore completion properties such

as skin and perforation zones

There are several additional discrepancies such as operating condition initial

bitumen viscosity and rock properties between the physical model and the field

Therefore to conduct a reasonable dimensional analysis a few assumptions concerning

the properties of the reservoir were considered which are listed in Table 4-1

Table 4-1 Dimensional analysis parameters field vs physical

Parameter Physical Model Athabasca Cold Lake m 19 39 39 Permeability D 300 3-5 3-5 Net pay m 025 20 20 micros cp ρ kgm3

70 987

30 1000

40 1000

φΔSo 04 02 02 Wellbore length m 05 500 500 Well-pair spacing m 05 200 200

According to economicalsimulation study conducted by Edmunds the minimum net

pay which can make a SAGD project feasible is 15m [90] So a thickness of 20m was

selected for both Cold Lake and Athabasca reservoirs The viscosity of saturating

65

bitumen at injecting steam temperature is different between the physical model and field

condition The thermal diffusivity α was assumed to be equal in physical model and the

field The permeability of the packing sand for the physical model is selected to make the

physical model dimensionally similar to the field As per Table 4-1 in order to establish

the dimensional similarity it is necessary to select high permeable packing sand for the

physical model comparing to the packing medium in field

The well length and well-pair spacing has no effect on B3 value but they impact the

physical model dimensions

The physical model designed for this study was a rectangular model which was

fabricated from a fiber reinforced phenolic resin with dimensions of 50macr50macr25 cm in i

j k directions The physical model is schematically shown in Figure 4-2 50 cm

Physical Model Cavity

25 cm

50 cm

Figure 4-2 Physical model Schematic

As a role of thumb the minimum well spacing is twice the net pay In designing the

current physical model the same rule was employed and the model width was selected as

50 cm The 50 cm well length is a minimal arbitrary value that was selected so that the

effect of well length on SAGD performance can be observed and at the same time the

total weight of model (the box 110 kg of sand and 25 liter of oil) would be reasonable

As shown in Figure 4-3 the model was mounted on a 15 m stand to facilitate its

handling Two mounting shafts were incorporated at the side of the model to enable

rotating the model by full 360 degrees

Most SAGD physical models described in the literature use one transparent side

which is usually made of Plexiglas Since this model is designed to account for the

longitudinal and lateral extension of chamber along a horizontal wellbore no visual side

66

was incorporated A total of 31 multi-point thermocouple probes each providing 5 point

measurements were installed to track the steam chamber within the model Figure 4-4

displays the location of the thermocouple probes in the model Thermocouples were

entered into the model from its back side and in 8 rows (A to G rows in Figure 4-4) Their

location was selected in a staggered pattern to cover the entire model The odd rows (A

C E and G) comprised 4 columns of thermocouples while the even rows (B D and F)

have 5 columns of thermocouples The thermocouples were connected to the Data

Acquisition instrument which provided the inputs for the LabView program to record

and display the temperature profile within the model

The pressure of the model is somewhat arbitrary It has an effect on the fluid

viscosity via its effect on the steam temperature but the scaling does not dictate any

pressure on the production side The model used in this work was designed for low

pressure operation and its rated maximum operating pressure was 100 kPa (gauge) The

maximum steam injection pressure used in the experiments was about 40 kPag

Figure 4-3 Physical Model

67

4

3 A B C D E F G

Figure 4-4 Thermocouple location in Physical Model

There are numerous reported studies of SAGD process using physical models but

most of them use two-dimensional models which ignore the effect of wellbore length in

the chamber development However since this model can be considered a semi-scaled 3shy

D model it is expected to provide more realistic and field representative results on the

effects of well configuration

412 Steam Generator

A large pressure cooker was modified to serve as the steam generator The pressure

cooker was made of heavy cast aluminum with the internal capacity of approximately 28

litres The vessels inside diameter was 126 inches the inside height was 14 inches and

its empty weight was 29 lbs

A frac12 inch line was connected to the opening for automatic pressure control which

eliminated the weight based pressure control During the experiments this outlet line was

connected to the injector well of the physical model Electrical heaters were installed in

the pressure cooker to heat the water and convert it to steam These electrical heaters

were controlled by a temperature controller that maintained the desired steam

temperature in the vessel In addition a pressure switch was installed in the power line

that would cut off the power to the heaters if the pressure became higher than the safe

limit Finally the pressure cooker also contained a rupture disc that would have relieved

the pressure if the internal pressure had become unsafe The selective pressure regulator

was designed to release excess steam at 18 lb of pressure The steam generator was

placed on top of a load cell to record the weight of the vessel and its contents The

decline in the weight provided a direct measure of the amount of steam injected into the

physical model

68

Figure 4-5 Pressure cooker

413 Temperature Probes

The temperature measurements inside the physical model were made with 31 multishy

point (5 points per probe) 18 inch diameter 23 inch length type-T thermocouples

Figure 4-5 presents the specification of the multi-point thermocouples

23rdquo

85rdquo

PTB

PTE

215rdquo

PTD

175rdquo

PTC

130rdquo

PTA40rdquo

Figure 4-6 Temperature Probe design

42 Data Acquisition A National Instruments data acquisition system was used to monitor and record the

experimental data These data included the temperatures sensed by a large number of

thermocouples in the experimental set-up as well as the weight of the steam generator A

LabVIEW program was used to coordinate the timing and recording of the data

43 RockFluid Property Measurements

431 Permeability measurement apparatus

A simple sand-pack apparatus was assembled to measure the permeability of the sand

used in the physical model experiments The apparatus comprised a low rate pump a

69

differential pressure transducer and a Plexiglass sand-pack holder (for high rates a

stainless steel holder was used) The schematic of the apparatus is displayed in Figure 4shy

7 The main objective was to inject water at specific rates and measure the corresponding

pressure difference across the sand pack The permeability was determined using Darcyrsquos

law since the length and diameter of the sand pack was known

24 cm 25 cm

Figure 4-7 Permeability measurement apparatus

432 HAAKE Roto Viscometer

The HAAKE RotoVisco 1 is a controlled rate (rotational) viscometer rheometer

which is specifically designed for quality control and viscosity measurements of fluids

such as liquid hydrocarbons It measures viscosity at defined shear rate or shear stress

The possible range of temperature that the HAAKE viscometer can handle is 5-85 ordmC

Figure 4-8 displays the front view of the HAAKE viscometer

The viscometer used in this work offered a choice of 3 sensor rotors Z31 Z38 and

Z41 which are designed for high middle and low viscosity fluids respectively The

amount of sample required for each sensor is different and the choice of sensor depends

primarily on the viscosity of the fluid The table 4-2 presents the specification for each

sensor

70

Figure 4-8 HAAKE viscometer

Table 4-2 Cylinder Sensor System in HAAKE viscometer

Senor Z31 Z38 Z41

Rotor

Material Titanium Titanium Titanium

Radius Ri mm 1572 1901 2071

+- ΔRi mm 0002 0004 0004

Length mm 55 55 55

+- L mm 003 003 003

Cup

Material Steel Steel Steel

Radius Ra mm 217 217 217

+- ΔRa mm 0004 0004 0004

Sample Volume cm3 520 330 140

71

433 Dean-Stark distillation apparatus

Two types of samples were obtained from each experiment 1) the samples which

were in the form of water in oil emulsions and 2) the water-oil-sand samples in the form

of core sample from the model For separation of water from oil and water and oil from

sand the extraction method which uses the Dean-Stark distillation method was

incorporated The Dean-Stark apparatus consists of a heating mantle round bottom flask

trap and condenser as shown in Figure 49

The sample was mixed with toluene with the proportion of 21 and was poured in the

flask The sample was heated with the heating mantle for 24 hours During the heating

vapors containing the water and toluene rise into the condenser where they condense on

the walls of the condenser Thereafter the liquid droplets drip into the distilling trap

Since toluene and water are immiscible they separate into two phases When the top

layer (which is toluene being less dense than water) reaches the level of the side-arm it

can flow back to the flask while the bottom layer (which is water) remains in the trap

After 24 hours no more water exists in the form of emulsion in oil It is important to drain

the water layer from the Dean-Stark apparatus as needed to maintain room for trapping

additional water

Since during each test up to 60 samples were collected a rack containing six units of

Dean-Stark distillation set-ups were employed to speed up the analysis These units were

located in a fume hood

Extraction of water and oil from oil-water-sand mixture was conducted in the same

Dean-Stark distillation apparatus with implementation of some minor changes A Soxhlet

was inserted on top of the flask The mixture of water-oil-sand was placed inside a

thimble which itself is placed inside the Soxhlet chamber The rest of process is the same

as the one expressed on Dean-Stark distillation process The sand extraction apparatus is

displayed on Figure 4-10

72

Figure 4-9 Dean-Stark distillation apparatus

Figure 4-10 Sand extraction apparatus

73

44 Experimental procedure Each experiment consisted of four major steps model preparation running the

experiment analysis of the produced samples cleaning

Prior to each experiment the load cell was calibrated to decrease the errors with

respect to weight measurement of the steam generator

441 Model Preparation

The model preparation was achieved in a step-wise manner as follows

bull Cleaning the physical model

bull Pressure testing the model

bull Packing the model

bull Evacuating the pore space of packed model

bull Saturating the model with water

bull Displacing the water with bitumen

Prior to each experiment the physical model was opened the thermocouples were

taken out and the whole set was cleaned Thereafter the model was assembled the

thermocouples were placed back into the model and the pressure test was conducted to

make sure there was no leak in the model Usually the model was left pressurized with

gas for 12 hrs to make sure there was no pressure leak

Various fittings were incorporated in the model for the purpose of packing bitumen

saturation and future well placement The ones for bitumen saturation had mesh on them

while the other ones were fully open

At the next stage the physical model was packed using clean silica sand During

packing the model was vibrated using a pneumatic shaker During the vibration the model

was held at several different angles to make sure that the packing was successful and no

gap would be left behind and a homogenous packing was created The packing and

shaking process typically took 48 hours of work and about 120 kg of sand was required to

fill the model

The next step was to evacuate the model to remove air from the pore space The

model was connected to a vacuum pump and evacuated for 12 hours The model was

disconnected from the vacuum pump and kept on vacuum for couple of hours to make

74

sure that it held the vacuum If high vacuum was maintained it was ready for saturating

with water

The model was saturated with de-ionized water using a transfer vessel The water

vessel was filled with water placed on a balance and was connected to the bottom of the

model Since the transfer vessel was placed at a higher level than the model both

pressure difference and gravity head forced the water to imbibe into the packed model

Approximately 21-22 kg water was required to fully saturate the model with water which

was equal to the total pore volume of the model The last stage is the drainage

displacement of water with the bitumen Two different bitumen samples were available

and both of them were practically immobile at room temperature The oil was placed in a

transfer vessel which was wrapped with the heating tapes and was connected to a

nitrogen vessel The oil was warmed up to 50-60 ordmC and was pushed into the model by

gravity and pressurized nitrogen The selected temperature was high enough that made

the bitumen mobile and was low enough to prevent evaporation of the residual water

Figure 4-11 displays bitumen saturation arrangement

A three point injection scheme was used with injection points at the top of the model

During the oil flood the injection points started at the far end and were moved to the

middle of the model after about 60 of the expected water production had occurred and

finally were directly on top of the production ports near the end of drainage The

displaced water was produced via three different valves and the relative amount of water

produced from the two outer valves was monitored and kept close to each other by

manipulating the openings of these TWO valves This ensured uniform bitumen

saturation throughout the model and specifically at the corners of the model The

displaced water was collected and the connate water and initial oil saturation were

calculated Approximately 18 kg of bitumen was placed in the model which took between

two to three weeks of bitumen injection

75

1

2

3

1 Pressure vessel wrapped with heating tapes

2 Isolated transfer line

3 Connection valves

Bitumen flow direction

Figure 4-11 Bitumen saturation step

442 SAGD Experiment

Each experiment was initiated by calibration of the load cell A few hours before

steam injection the steam generator was filled with de-ionized water step by step (by

adding weighed quantities of water) and the load cell reading was recorded

The steam generator was set to a desired temperature between 107-110 ordmC The steam

transfer line which connected the steam generator to the model was wrapped with heating

tape The purpose was to ensure that high quality steam would be injected into the model

and eliminate any steam condensation prior to the inlet point of the injector The weight

of the steam generator was recorded every minute

After the steam generator had reached the set point temperature the injection valve

was opened to let the steam flow into the model The production valve was opened

simultaneously The produced oil and water samples were collected in glass jars

76

Figure 4-12 InjectionProduction and sampling stage

The temperatures above the injection and production wells in the model were

continuously monitored via LabView program Once steam break-through occurred in the

production well steam trap control was achieved using back pressure via the production

valve This was confirmed by monitoring the temperature of the zone between producer

and injector and ensuring that an adequate sub-cool (approximately 10 ordmC) was present

The produced fluid sampling bottle was changed every 20-30 minutes and each

experiment took between 12 to 30 continuous hours to complete Figure 4-12 shows the

injectionproduction and sampling stage

At end of the test the steam injection was stopped but the production was continued

to get the amount of oil which could be produced from the stored heat energy in the

model Then the steam generator was shut off and the physical model was cooled down

After the model had completely cooled down the thermocouples were taken out in 3

steps and 27 samples of sands were taken from the model from three different layers in

the model Figure 4-13 displays the bottom view of the mature SAGD model and the

location of the sand samples in that layer

77

1 2 3

4 5 6

7 8 9

Figure 4-13 Bottom layer of the model after SAGD experiment and the sampling points for sand analysis

443 Analysing samples

Each sample bottle was weighed to obtain the weight of the produced sample The

sample analysis started with separation of water from oil in the Dean Stark set up Each

jarrsquos content was mixed with toluene and the whole mixture was placed in one single

flask 6 samples were analysed simultaneously using the six available Dean-Stark set ups

Each analysis took at least 12 hours During the extraction the collected water in the trap

part of the set up was drained as needed to allow more water to be collected in the trap

Once the separation was completed the total amount of water produced from the sample

was weighed and recorded The amount of oil produced was determined from the

difference between the total sample weight and the weight of water This procedure was

repeated for the all samples and eventually the cumulative oil and water production

profile could be determined This water-oil separation took about 10-15 days for each

experiment

The next step was separation of water and oil from the collected sand samples Since

only 4 Soxhlet units were available only four sets of separation could be run

78

simultaneously The mixture was placed in the thimble and weighed The thimble

containing the sand sample was placed in the Soxhlet chamber The evaporation and

condensation of toluene washes the water and oil from the sand and eventually they will

be condensed and the water collected in the trap Once the thimble and sand were clean

it was taken out and dried The amount of collected water was recorded and consequently

the residual oil and water saturations could be determined

444 Cleaning

At the end of each run the entire set up including the physical model the injector and

producer all fittings and valves and connection lines were disassembled The valves and

fittings were soaked in a bucket of toluene while the wells and the physical model were

washed with toluene

CHAPTER 5

NUMERICAL RESERVOIR SIMULATION

80

This chapter discusses the numerical simulation studies conducted to optimize the

well configuration in a SAGD process These numerical studies were focused on three

major reservoirs in Alberta as Athabasca Cold Lake and Lloydminster The description

of the simplified geological models associated with each reservoir is presented first

followed by the PVT data for each reservoir The results of simulation studies are then

presented and discussed

51 Athabasca

The McMurray formation mostly occurs at the depths of 0 to 500 m The total

McMurray formation gross thickness varies between 30-100 meters with an average of 30

m total pay The important petro-physical properties of McMurray formation are porosity

of 25ndash35 and 6-12 D permeability The bitumen density varies from 8 to 11ordm API with a

viscosity of larger than 1000000 cp at reservoir temperature of 11 degC

511 Reservoir Model

Numerical modeling was carried out using a commercial fully implicit thermal

reservoir simulator Computer Modeling Group (CMG) STARS 200913 A simplified

single well pair 3-D model was created for this study The model was set to be

homogenous with average reservoir and fluid properties of the McMurray formation

sands in Athabasca deposit Since the model is homogenous and the SAGD mechanism is

a symmetrical process only half of the SAGD pattern was simulated The model size was

30macr500macr20 m and it was represented with the Cartesian grid blocks of size 1macr50macr1 m

in imacrjmacrk directions respectively The total number of grid blocks equals 6000 Figure

5-1 displays a 3-D view of the reservoir model

Figure 5-2 shows that across the well pairs the size of the grid blocks are minimized

which allows capturing a reasonable shape of steam chamber across the well pairs In

addition since most of the sudden changes in reservoir and fluid temperature saturation

and pressure occurs in vicinity of the well-pairs using homogenized grid blocks across

the well-pairs allows the model to better simulate them

81

Figure 5-1 3-D schematic of Athabasca reservoir model

30 500

20

Figure 5-2 Cross view of the Athabasca reservoir model

Injector

Producer

The horizontal permeability and porosity was 5 D and 34 respectively and the

KvKh was set equal to 08 for all grid blocks The selected reservoir properties for the

representative Athabasca model are tabulated in table 5-1 The initial oil saturation was

assumed to be 85 with no gas cap above the oil bearing zone The thermal properties of

rock are provided in table 5-1 as well [91] The heat losses to over-burden and under-

burden are taken into account CMG-STARS calculate the heat losses to the cap rock and

base rock analytically

The capillary pressure was set to zero since at reservoir temperature the fluids are

immobile due to high viscosity and at steam temperature the interfacial tension between

82

oil and water becomes small Moreover the capillary pressure is expected to be very

small in high permeability sand

Table 5-1 Reservoir properties of model representing Athabasca reservoir

Net Pay 20 m Depth 250 m Permeability Kh 5000 md KvKh 08 Porosity 34 Initial Pressure PR 2000 kPa Initial Temperature TR 11 degC Oil Saturation So 85 mole fraction Gas in Oil 6 Oil Viscosity TR 16E+6 cp Formation Compressibility 14E-5 1kPa Rock Heat Capacity 26E+6 Jm3degC Thermal Rock Conductivity 66E+5 JmddegC OverburdenUnderburden Heat Capacity 26E+6 Jm3degC

512 Fluid Properties

Only three fluid components were included in the reservoir model as Bitumen water

and methane Three phases of oleic aqueous and gas exist in the model The oleic phase

can contain both bitumen and methane the aqueous phase contains only water while the

gas phase may consists of both steam and methane

The thermal properties of the fluid and rock were obtained from the published

literature The properties of the water in both aqueous and gas phase were set as the

default values of the CMG-STARS The properties of the fluid (Bitumen and methane)

model are provided in Table 5-2

Table 5-2 Fluid properties representing Athabasca Bitumen

Oil Viscosity TR 16E+6 cp Bitumen Density TR 9993 Kgm3

Bitumen Molecular Mass 5700 gmole Kv1 545 E+5 kPa Kv4 -87984 degC Kv5 -26599 degC

To represent the phase behavior of methane a compatible K-Value relationship was

implemented with the CMG software [92] The corresponding K-value for methane is

provided in table 5-2 [91] It is assumed that no evaporation occurs for the bitumen

component

83

Kv4Kv T + KvK minus Value = 1 exp 5

P

To estimate a full range of viscosity vs temperature the Mehrotra and Svercek

viscosity correlation was used [93]

ln ln (μ) = A + B ln (T) Figure 5-3 shows the viscosity-temperature variation for bitumen model

10

100

1000

10000

100000

1000000

10000000

100000000

Visc

osity

cp

00 500 1000 1500 2000 2500 3000

Temperature C

Figure 5-3 Temperature dependency of bitumen modelrsquos Viscosity for Athabasca

513 Rock-Fluid Properties

Since there was no available experimental data for the rock fluid properties the three

phase relative permeability defined by Stonersquos Model was used to combine water-oil and

liquid-gas relative permeability curves Two types of rock were defined in most of the

numerical models rock type 1 which applied to entire reservoir and rock type 2 which

was imposed on the wellbore but in both rock types the rock was considered water-wet

Straight line relative permeability was defined for the rock fluid interaction in the well

pairs

Some typical values of residual saturates were selected [91 47] and since this part of

study does not include any history matching procedure therefore all the end points are

84

equal to one Table 5-3 summarizes the rock-fluid properties The water-oil and gas-oil

relative permeability curves are displayed on Figure 5-4 Figure 5-5 presents the relative

permeability sets for the grid blocks containing the well pairs

Figure 5-4 Water-oil relative permeability

85

Figure 5-5 Relative permeability sets for DW well pairs

Table 5-3 Rock-fluid properties

SWCON Connate Water 015 SWCRIT Critical Water 015 SOIRW Irreducible Oil for Water-Oil Table 02 SORW Residual Oil for Water-Oil Table 02 SGCON Connate Gas 005 SGCRIT Critical Gas 005 KROCW - Kro at Connate Water 1 KRWIRO - Krw at Irreducible Oil 1 KRGCL - Krg at Connate Liquid 1 nw 3 now 3 nog 3 ng 2

514 Initial ConditionGeo-mechanics

The reservoir model top layer is located at a depth of 250 m and at initial temperature

of 11 ordmC The water saturation is at its critical value of 15 and the initial mole fraction

of gas in bitumen is 6 The total pore volume and oil phase volume are 128 and 109

E+5m3 Geo-mechanical effect was ignored in the entire study

515 Wellbore Model

CMG-STARS 200913 provides two different formulations for horizontal wellbore

modeling SourceSink (SS) approach and Discretized Wellbore (DW) model SS

modeling has some limitations such as a) the friction and heat loss along the horizontal

section is not taken into account b) it does not allow modeling of fluid circulation in

wellbores c) liquid hold-up in wellbore is neglected [94] In fact to heat up the

intervening bitumen between the well pairs during the preheating period of SAGD

process a line heater with specific constraint has to be assigned for the wellbore This

86

would affect the cumulative SOR The DW model provides the means to simulate the

circulation period and it considers both heat and friction loss along the horizontal section

of the wellbore

CMG-STARS models a DW the same as the reservoir Hence each wellbore segment

is treated as a grid block in which the fluid flow and heat transfer equations are solved at

each time step The flow in tubing and annulus is assumed as laminar The flow equations

through tubing and annulus are based on Hagen-Poiseuille equation If the flow became

turbulent then the permeability of tubing and annulus would be modified

However DW has its own limitations as well One of the most significant restrictions

of DW is that it does not model non-horizontal (deviated) wellbores For this study a

combination of both SS and DW models were used

Most of the rock fluid properties were also used for the grid blocks containing the

DW except the thermal conductivities and relative permeability The thermal

conductivity of stainless steel and cement were set for tubing and casing respectively

Straight line relative permeability presented in Figure 5-5 was imposed for the grid

blocks containing DW

All of the wells were modeled as DW except the non-horizontal ones The non-

horizontal injectors are modeled as line sourcesink combined with a line heater The line

heaters were shut in after the circulation period ended The DW consists of a tubing and

annulus which were defined as injector and producer respectively This would provide

the possibility of steam circulation during the preheating period

516 Wellbore Constraint

The injection well is constrained to operate at a maximum bottom hole pressure It

operates at 500 kPa above the reservoir pressure The steam quality is equal to 09 at the

sand-face The corresponding steam saturation temperature at the bottom-hole pressure is

224 degC

The production well is assumed to produce under two major constraints minimum

bottom-hole pressure of 2000 kPa and steam trap of 10 degC The specified steam trap

constraints for producer will not allow any live steam to be produced via the producer

87

517 Operating Period

SAGD process consists of three phases of a) Preheating (Start-up) b) Steam Injection

amp Oil Production and c) Wind down

Each numerical case was run for total of 6 years The preheating is variable between

1-4 months depending on the well configuration For the base case the circulation period

is 4 months which is similar to the current industrial operations The main production

periods is approximately 5 years while the wind down takes only 1 year The SAGD

process stops when the oil rate declines below 10 m3d

518 Well Configurations

Numerous simulations were conducted for well configuration cases in search for an

improved well configuration for the McMurray formation in Athabasca type of reservoir

To start with a base case which has the classic well pattern (11 ratio with 5 m vertical

inter-well spacing) was modeled The base case was compared with available analytical

solutions and performance criteria Furthermore the performance of the examined well

patterns was compared against the base case results

Figure 56 presents some of the modified well configurations that can be used in

SAGD operations These well configurations need to be matched with specific reservoir

characteristics for the optimum performance None of them would be applicable to all

reservoirs

5m

Injector

Producer

Injectors

Producer 5m

Injector

Producer

Basic Well Configuration Vertical Injectors Reversed Horizontal Injector Injectors

Producer

Injector

Producer

Inclined Injector Parallel Inclined Injectors Multi Lateral Producer

Figure 5-6 Schematic representation of various well configurations for Athabasca Reservoir

88

5181 Base Case

This configuration is the classic configuration as recommended by Butler It follows

the same schedule of preheating normal SAGD and wind down The vertical inter-well

distance was 5 m and the producer was placed 15 m above the base of the pay zone Two

distinct base cases were defined for comparison a) both injector and producer wellbores

were modeled based on DW approach b) the injector was modeled with SS wellbore

approach and the producer was simulated with DW Since in some of the future well

patterns the injectors is modeled as a Source well then for the sake of comparison case b

can be used as the base case

The circulation period is 4 month and the total production period is approximately 6

years The results of both cases are reasonable and close to each other Figures 5-7 and 5shy

8 present the oil rate and recovery factor vs time for both cases Figure 5-9 and 5-10

display the cSOR and chamber volume vs time

Both cases provided similar results except for the cSOR The recovery factor for both

DW and SS models are close to each other being 662 and 650 respectively As per

Figure 5-9 there is a small difference in cSOR values for the two base cases The final

cSOR for the Base Case-DW and Base Case-SS are 254 and 223 m3m3 respectively

On Figure 5-7 the total production period is divided into four distinct regions as 1)

circulation period 2) ramp-up 3) plateau and 4) wind down Figure 5-11 displays the

cross section of the chamber development across the well pairs during the four regions

By the time the ramp-up period is completed the chamber reaches the top of reservoir

The maximum oil rate occurs at the end of ramp-up period During this period the

chamber has the largest bitumen head and smallest chamber inclination

In the Base Case-SS model a line heater was introduced above the injector The

heater with the modified constraint injected sufficient heat into the zone between the

injector and producer This supplied amount of energy is not included in cSOR

calculations Also the SS wellbore does not include the frictional pressure drop along the

wellbore These conditions make the base case with the line source to operate at a lower

cSOR

89

Oil

Prod

Rat

e SC

TR (m

3da

y)

0

20

40

60

80

100 Base Case-DW Base Case-SS

1 2 3 4

SCTR stands for Sector

2009 2010 2011 2012 2013 2014

Time (Date)

Figure 5-7 Oil Production Rate Base Case

Oil

Rec

over

y Fa

ctor

SC

TR

0

10

20

30

40

50

60

70


2009 2010 2011 2012 2013 2014

Time (Date)

Figure 5-8 Oil Recovery Factor Base Case

90

Stea

m O

il R

atio

Cum

SC

TR (m

3m

3)

00

05

10

15

20

25

30

35

40

45


2009 2010 2011 2012 2013 2014

Time (Date)

Figure 5-9 Cumulative Steam Oil Ratio (cSOR) Base Case

Stea

m C

ham

ber V

olum

e S

CTR

(m3)

0

10000

20000

30000

40000

50000


2009 2010 2011 2012 2013 2014 Time (Date)

Figure 5-10 Steam Chamber Volume Base Case

91

1 2

3 4

Figure 5-11 Cross view of chamber development at 4 specified time frames Base Case

Stea

m Q

ualit

y D

ownh

ole

00

01

02

03

04

05

06

07

08

09

10

Base Case-DW Base Case-SS

2009 2010 2011 2012 2013 2014

Time (Date)

Figure 5-12 Steam Quality of DW vs SS during the SAGD life period Base Case

92

Figure 5-12 displays the steam quality of DW vs SS injector for the base cases In the

model containing discretized wellbore there is some loss in steam quality due to the heat

loss and friction while in the SourceSink model the steam quality profile is completely

flat no change along the injector

Figure 5-13 displays the pressure profile along the vertical distance between the toe

of injector and producer and also the pressure profile at the heel of injector and producer

There is a small pressure drop along the injector andor producer It seems that the way

STARS treats producers and injectors is somewhat idealistic The producer drawdown

does not change from heel to the toe which in real field operation is not true Most of the

SAGD operators have problems in conveying the live steam to the toe of the injector to

form a uniform steam chamber Das reported that a disproportionate amount of steam

over 80 is injected near the heel of the injector and the remaining goes to the toe if live

steam conquers the heat loss and friction along the tubing [14] As a result the steam

chamber grows primarily at the heel and has a dome shape along the well pairs This

situation may lead to steam breakthrough around the heel area and reduce the final

recovery factor Since these effects are not captured in the model the simulated base-case

performance is better than what can be achieved in the field Therefore when the new

well configurations are compared against the base cases and show even marginally better

performance they are considered promising configurations

The base case model was validated against Butlerrsquos analytical model The analytical

model includes the solution for oil rates during the rising chamber and depletion period

[1] The parameters of the numerical model were incorporated into the analytical solution

and the obtained oil production rate was compared against the numerical base case result

Table 5-4 presents the list of parameters incorporated in the analytical solution of Base

Case results The oil production rate for numerical and analytical results is presented in

Figure 5-14 There is a reasonable consistency between both results Both models

forecast quite similar ramp up and maximum oil rate However after two years of

production the results deviate from each other which is due to the boundary effects and

the simplifying assumptions (single phase flow ignoring formation compressibility

constant viscosity etc) in the analytical solution In fact the numerical model is able to

93

simulate the wind down step as well while the analytical solution only predicts the

depletion period

Table 5-4 Analytical solution parameters

Typical Athabasca Base Case Reservoir Temperature 11

Oil Kinematic Viscosity TR 158728457 Bitumen Kinematic Viscosity 100degC 2039

Reservoir Thickness 20 Thermal Diffusivity 007

Porosity 034 Initial Oil Saturation 085

Residual Oil Saturation 025 Effective Permeability for Oil Flow 16

Well Spacing 60 Vertical Space From Bottom 15

Steam Pressure 25 Parameter m 3

Bitumen Kinematic Viscosity Ts 710E-06

degC cS cS m m2D

D m m Mpa

cS

Pres

sure

(kPa

)

2480

2482

2484

2486

2488

2490

2492

2494

2496

2498

2500

Injector Heel Injector Toe Producer Heel ProducerToe

2009 2010 2011 2012 2013 2014 Time (Date)

Figure 5-13 Pressure Profile between Injector and Producer at the heel and toe Base Case

94

0

20

40

60

80

100

120

140

160

0 1 2 3 4 5 6 Time Year

Oil

Prod

uctio

n R

ate

m3 d

Butlers Analytical Method

CMG Simulation Results Base Case

Figure 5-14 Comparison of numerical and analytical solutions Base Case

Aherne and Maini introduced the Total Fluid to Steam Ratio (TFSR) which is an

indicator for evaluation of the balance between fluid withdrawal and steam injection

pressure [35] In fact the TFSR indicates the water leak off from the steam chamber The

TFSR was expressed as

H2O Prd + Oil Prd - Steam in ChamberTFSR = Steam Inj

They stated that if the TFSR is less than 138 m3m3 then the pressure of the reservoir

will increase or there will be some leak off from the chamber The current numerical base

case model has a TFSR of 14 m3m3 which demonstrates that the injection and

production is balanced

The base case was evaluated using these validation criteria Since its performance is

acceptable the performance of future well patterns will be compared against the base

case

5182 Vertical Inter-well Distance Optimization

The optimum vertical inter-well distance between the injector and producer depends

on reservoir permeability bitumen viscosity and preheating period Locating the injector

95

close enough to the producer would shorten the circulation period but on the other hand

the steam trap control becomes an issue To obtain the best RF and cSOR the vertical

distance needs to be optimized To study the effect of vertical inter-well distance on

SAGD performance five distances were considered 3 4 6 7 and 8m The idea was to

investigate if changing the vertical distance will improve the recovery factor and cSOR

The oil rate RF cSOR and the chamber volume are presented on Figures 5-15 5-16

5-17 and 5-18 respectively It is observed that the performance decreases as the vertical

distance increases above 6m Increasing the inter-well spacing between injector and

producer delays the thermal communication between producer and injector which

imposes longer circulation period and consequently higher cSOR Since for the large

vertical distance between the well pairs the injector is placed close to the overburden the

steam is exposed to the cap rock for a longer period of time and therefore the heat loss

increases which results to higher cSOR and less recovery factor When the inter-well

distance is smaller than the base case the preheating period is shortened but the effect on

subsequent performance is not dramatic The optimum vertical distance between the

injector and producer is assumed to be 5m in most of reservoir simulations and field

projects Figures 5-16 and 5-17 show that the vertical distance can be varied from 3 to 6m

and 4m appears to be the optimal distance The 4m vertical spacing has the highest

recovery factor and same cSOR as 3 5 and 6m vertical spacing cases

96

Oil

Prod

Rat

e SC

TR (m

3da

y)

0

20

40

60

80

100 Base Case-DW Vertical Space=3m Vertical Space=4m Vertical Space=6m Vertical Space=7m Vertical Space=8m

2009 2010 2011 2012 2013 2014

Time (Date)

Figure 5-15 Oil Production Rate Vertical Inter-well Distance Optimization

Oil

Rec

over

y Fa

ctor

SC

TR

0

10

20

30

40

50

60


2009 2010 2011 2012 2013 2014

Time (Date)

Figure 5-16 Oil Recovery Factor Vertical Inter-well Distance Optimization

97

Stea

m O

il R

atio

Cum

SC

TR (m

3m

3)

00

05

10

15

20

25

30

35

40

45


2009 2010 2011 2012 2013 2014

Time (Date)

Figure 5-17 Steam Oil Ratio Vertical Inter-well Distance Optimization

Stea

m C

ham

ber V

olum

e SC

TR (m

3)

0

10000

20000

30000

40000

50000


2009 2010 2011 2012 2013 2014

Time (Date)

Figure 5-18 Steam Chamber Volume Vertical Inter-well Distance Optimization

98

5183 Vertical Injector

Vertical wellbores are cheaper and simpler to drill than the horizontal wellbores An

advantage of vertical wells with respect to horizontal well is that it is possible to change

the injection point as the SAGD project becomes mature Their disadvantage is that to

cover a horizontal wellbore several vertical wells are required Typically for every 150shy

200 m of horizontal well length a vertical well is needed Therefore for this study with

500 m long horizontal wells a well configuration with threetwo vertical injectors and a

horizontal producer was evaluated

The possibility of replacing the horizontal injector with sets of vertical injectors was

studied and the results are presented in this section Comparisons with the base case are

presented in Figures 5-19 5-20 5-21 and 5-22 The circulation of the vertical injectors

was achieved by introducing line heater on the injectors The heating period was the same

as base case preheating period Once the heating stage was terminated the injectors were

set on injection The model encountered some numerical instability during the first few

month of production but it stabled down for the rest of production period The results

demonstrate that using only two vertical injectors is not sufficient to deplete the reservoir

in 6 years of production window Its recovery factor is only 50 after 6 years of

production while its cSOR is close to 30 m3m3 However 3 vertical injectors case has

comparable RF results with the base case model which is about 65 after 6 years of

production but it requires larger amount of steam The steam chamber volume of the 3

vertical injectors is larger than the base case which demonstrates that the steam is

delivered more efficient than the base case Vertical injectors cause some instability in

numerical modeling once the steam zone of each vertical well merges to the adjacent

steam zone This issue was resolved using more refined grid blocks along the producer

99

Oil

Rat

e SC

(m3

day)

0

30

60

90

120

150 Base Case-SS 2 Vertical Injectors 3 Vertical Injectors

2009 2010 2011 2012 2013 2014 2015 2016 2017

Time (Date)

Figure 5-19 Oil Production Rate Vertical Injectors

Oil

Rec

over

y Fa

ctor

SC

TR

0

10

20

30

40

50

60


2009 2010 2011 2012 2013 2014 2015 2016 2017

Time (Date)

Figure 5-20 Oil Recovery Factor Vertical Injectors

100

Stea

m O

il R

atio

Cum

SC

TR (m

3m

3)

00

10

20

30

40

50

60

70

80

90


2009 2010 2011 2012 2013 2014 2015 2016 2017

Time (Date)

Figure 5-21 Steam Oil Ratio Vertical Injectors

Stea

m C

ham

ber V

olum

e SC

TR (m

3)

0

10000

20000

30000

40000

50000

60000


2009 2010 2011 2012 2013 2014 2015 2016 2017

Time (Date)

Figure 5-22 Steam Chamber Volume Vertical Injectors

101

5184 Reversed Horizontal Injector

It has been suggested that most of the injected steam in a basic SAGD pattern is

injected near the heel of the injector where the pressure difference between the injector

and producer is high Thus basic SAGD would yield an uneven and slanted chamber

along the well pair The Reversed Injector is introduced to solve the no uniformity of

steam chamber growth via a uniform pressure difference along the well pair This well

configuration is able to provide live steam along almost the whole length of the injector

and producer The vertical distance between the injector and producer is 5 m The

injectorrsquos heel is placed above the producerrsquos toe and its toe right above the producerrsquos

heel This well configuration creates an even pressure drop between the injector and

producer The steam chamber growth would be more uniform in all directions This

configuration uses the concept of countercurrent heat transfer and fluid flow

Figures 5-23 5-24 5-25 and 5-26 compare the technical performance of Reverse

Horizontal Injector and Base Case-SS

In both Base Case-SS and Reversed Horizontal Injector models a source-sink

wellbore type was used as Injector A line heater was introduced above the injector The

oil recovery factor increased by 4 with reversed injector while cSOR remained the

same as in the Base Case-SS while chamber volume increased by 89 As discussed in

the base case section currently the numerical simulators does not effectively model the

steam distribution (including pressure drop and injectivity) along the injectors and

therefore the results of Reversed Horizontal injector is close to the base case

Figure 5-26 displays a 3-D view of depleted reservoir using the Reversed Horizontal

Injector The chamber grows laterally longitudinally and vertically in a uniform manner

The results suggest that there is potential benefit for reversing the injector This

pattern provides the possibility of higher and uniform pressure operation This strongly

suggests that this pattern should be examined through a pilot project in Athabasca type of

reservoir

102

Oil

Prod

Rat

e SC

TR (m

3da

y)

0

20

40

60

80

100 Base Case-SS Reversed Horizontal Injector

2009 2010 2011 2012 2013 2014 Time (Date)

Figure 5-23 Oil Production Rate Reverse Horizontal Injector

Oil

Rec

over

y Fa

ctor

SC

TR

0

10

20

30

40

50

60

70 Base Case-SS Reverse Horizontal Injector

2009 2010 2011 2012 2013 2014 Time (Date)

Figure 5-24 Oil Recovery Factor Reverse Horizontal Injector

103

Stea

m O

il R

atio

Cum

SC

TR (m

3m

3)

00

05

10

15

20

25

30

35

40

45


2009 2010 2011 2012 2013 2014 Time (Date)

Figure 5-25 Steam Oil Ratio Reverse Horizontal Injector

Stea

m C

ham

ber V

olum

e SC

TR (m

3)

0

10000

20000

30000

40000

50000


2009 2010 2011 2012 2013 2014 Time (Date)

Figure 5-26 Steam Chamber Volume Reverse Horizontal Injector

104

One Year Five Years

Figure 5-27 3-D View of Chamber Growth Reverse Horizontal Injector

5185 Inclined Injector Optimization

Mojarab et al introduced a dipping injector above the producer It was shown that the

well configuration will provide a small improvement in the SAGD performance [95] For

simulating the inclined well the size of grid blocks in vertical direction was reduced to

appropriately capture the interferences at different angles The optimum distance at the

heel and toe was explored Table 5-5 presents the eight different cases that were

investigated

Table 5-5 Inclined Injector Case

Distance to Producer Heel m Distance to Producer Toe m Case 1 75 25 Case 2 8 3 Case 3 85 35 Case 4 9 4 Case 5 95 45 Case 6 10 5 Case 7 85 25 Case 8 95 25

The angle of injector inclination was varied to determine the optimum angle The

production results are compared against the basic pattern RF and cSOR results for all

inclined injector cases are presented in Figure 5-28 and 5-29 The injector was modeled

based on the SS wellbore modeling so the base case is the Base Case-SS model Figure

5-28 and 5-29 demonstrate that the Inclined Injector Case7 provides promising

performance It has increased the recovery factor by 31 while the cSOR was about the

same as in the Base Case-SS This configuration requires less than 3 months of steam

circulation

50

105

70

Oil

Rec

over

y Fa

ctor

SC

TR

Ste

am O

il R

atio

Cum

SC

TR (m

3m

3)

60

50

40

30

20

10

0

Time (Date) 2009 2010 2011 2012 2013 2014

Base Case-SS Inclined Inj Case 01 Inclined Inj Case 02 Inclined Inj Case 03 Inclined Inj Case 04 Inclined Inj Case 05 Inclined Inj Case 06 Inclined Inj Case 07 Inclined Inj Case 08

Figure 5-28 Oil Recovery Factor Inclined Injector

45

40

35

30

25

20

15

10

05

00

Time (Date) 2008-1-1 2009-5-15 2010-9-27 2012-2-9 2013-6-23 2014-11-5


Figure 5-29 Steam Oil Ratio Inclined Injector

106

Oil

Rat

e SC

(m3

day)

0

20

40

60

80

100 Base Case-SS Inclined Inj Case 07

2009 2010 2011 2012 2013 2014 Time (Date)

Figure 5-30 Oil Production Rate Inclined Injector Case 07

Oil

Rec

over

y Fa

ctor

SC

TR

0

10

20

30

40

50

60


2009 2010 2011 2012 2013 2014 Time (Date)

Figure 5-31 Oil Recovery Factor Inclined Injector Case 07

107

Ste

am O

il R

atio

Cum

SC

TR (m

3m

3)

00

05

10

15

20

25

30

35

40

45


2008-1-1 2009-5-15 2010-9-27 2012-2-9 2013-6-23 2014-11-5 Time (Date)


Stea

m C

ham

ber V

olum

e SC

TR (m

3)

0

10000

20000

30000

40000

50000

60000

Base Case-SS Inclined Inj Case 07

2009 2010 2011 2012 2013 2014 Time (Date)

Figure 5-33 Steam Chamber Volume Inclined Injector Case 07

108

The results show that optimum distance at the heel and the toe can varies from 7-9 m

and 2-3 m respectively Figures 5-30 through 5-33 compare the results for optimum

Inclined Injector and the base case

5186 Parallel Inclined Injectors

In this pattern two 250 m long inclined injectors were placed above the producer

This well configuration is aimed at solving the nonuniformity of steam chamber along the

producer for long horizontal wellbores Nowadays the commercial projects are running

SAGD with well lengths of 1000 m or higher Consequently the degree of inclination in

the Inclined Injector pattern becomes small through 1000 meters of wellbore Since in the

current study the base case is defaulted as 500m therefore for this pattern two sets of

inclined injector are suggested Each injector has about 250 m length and their heels are

connected to the surface The heel to toe direction of both injectors is the same as

producer Both injectors are sourcesink type of wellbore and two line heaters were

introduced on the injectors to warm up the bitumen around them The heating period was

less than 3 months

The results obtained with dual inclined injectors above the producer are compared

with the Base Case-SS pattern in Figures 5-34 5-35 5-36 and 5-37 The parallel inclined

injector pattern provides higher RF but at the expense of larger cSOR The RF is

increased by 46 but on the other hand the cSOR increases by 44 as well

As the economic evaluation was not part of this project the conclusions are based on

the production performance only However it is obvious that an economic analysis would

be necessary for the final decision The main advantage of this well configuration is that

it has the flexibility of the vertical injector and deliverability of horizontal wellbores

109

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Figure 5-34 Oil Production Rate Parallel Inclined Injector

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Figure 5-35 Oil Recovery Factor Parallel Inclined Injector

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Figure 5-36 Steam Oil Ratio Parallel Inclined Injector

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Figure 5-37 Steam Chamber Volume Parallel Inclined Injector

111

5187 Multi-Lateral Producer

Unnecessary steam production is often associated with mature SAGD Large amount

of bitumen would be left behind in the area between the adjoining chambers It is

believed that a multi-lateral well could maximize overall oil production in a mature

SAGD Multi lateral wells are expected to provide better horizontal coverage than

horizontal wells and could extend the life of projects In order to increase the productivity

of a well the productive interval of the wellbore can be increased via well completion in

the form of multi-lateral wells A case study on the evaluation of multilateral well

performance is presented Multiple 30 m legs are connected to the producer

Figures 5-38 5-39 5-40 and 5-41 display the results for the Mutli-Lateral pattern

against the Base Case-SS The results are not dramatic The Multi-Lateral provides a

small benefit in recovery factor but not in cSOR Considering the cost involved in drilling

multilaterals this configuration does not appear promising This pattern may be a good

candidate for thin reservoirs which vertical access is limited and it would be more

beneficial to enlarge the horizontal distance between wellpairs

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Figure 5-38 Oil Production Rate Multi-Lateral Producer

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Figure 5-39 Oil Recovery Factor Multi-Lateral Producer

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Figure 5-40 Steam Oil Ratio Multi-Lateral Producer

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Figure 5-41 Steam Chamber Volume Multi-Lateral Producer

52 Cold Lake

The minimum depth to the first oil sand in Cold Lake area is ~300m while most

commercial thermal projects have occurred at the depth of about 450 m In Clearwater

formation the sands are often greater than 40m thick with a netgross ratio of greater than

05 Porosity ranges from 30 to 35 with oil saturations that average 70 PV At the

initial reservoir temperature of 13 degC the oil viscosity is about 100000 cp

521 Reservoir Model

Same as the numerical step in Athabasca reservoir section the (CMG) STARS

200913 software was used to numerically model the most optimum well configuration A

3-D symmetrical Cartesian model was created for this study The model is set to be

homogenous with averaged reservoir and fluid property to honor the properties in Cold

Lake area The model corresponds to a reservoir with the size of 30mtimes500mtimes20 m It

was covered with the Cartesian grid block size of 1times50times1 m in itimes jtimesk directions

respectively Figure 5-42 displays a 3-D view of the reservoir model

114

20

500

30

Figure 5-42 3-D schematic of Cold Lake reservoir model

The absolute permeability in horizontal direction is 5 D and the KvKh is set equal to

be 08 The porosity of sand is 34 The model is assumed to contain three phases with

bitumen water and methane as solution gas in bitumen

The initial oil saturation was assumed to be 85 with no gas cap above the oil

bearing zone The thermal properties of rock are provided in table 5-6 The heat losses to

over-burden and under-burden are taken into account as well CMG-STARS calculate the

heat losses to the cap rock and base rock analytically

The capillary pressure is set to zero as in the case of Athabasca reservoir


The fluid definition for Cold Lake reservoir (including K-Value definition and

values) followed the same steps as the one described in section 512 except the fact that

Cold Lake viscosity is different



ln ln (μ) = A + B ln (T)

Figure 5-43 shows the viscosity-temperature variation for bitumen at cold lake area

115

1000000

100000

10000

1000

100

10

1

Visc

osity

cp

0 50 100 150 200 250 Temperature C

Figure 5-43 Viscosity vs Temperature for Cold Lake bitumen


The relative permeability data set is exactly the same as in the Athabasca model

Table 5-3 summarizes the rock-fluid properties The thermal properties of reservoir and

cap rock are the same as the ones were presented in Table 5-1 The water-oil and gas-oil

relative permeability curves are displayed in Figure 5-4 Figure 5-5 presents the relative


Table 5-6 Reservoir and fluid properties for Cold Lake reservoir model

Net Pay 20 m Depth 475 m Permeability Kh 5000 md KvKh 08 Porosity 34 Initial Pressure PR 2670 kPa Initial Temperature TR 15 degC Oil Saturation So 85 mole fraction Gas in Oil 6 Bitumen Density TR 949 Kgm3

300

116

524 Initial ConditionGeomechanics




E+5m3 respectively Geo-mechanical effects were ignored in the entire study except in

the C-SAGD well configuration

525 Wellbore Model

All the wells were modeled as DW except the non horizontal ones The non









237 degC The production well is assumed to produce under two major constraints

minimum bottom-hole pressure of 2670 kPa and steam trap of 10 degC The specified

steam trap constraints for producer will not allow any live steam to be produced via the

producer




is 50 days which is approximately similar to the current industrial operations The main

production periods is approximately 3 years while the wind down takes only 1 year The

SAGD process stops when the oil rate declines below 10 m3d

117


A series of comprehensive simulations were completed to explore the most promising

well configuration for the Clearwater formation in Cold Lake area First a base case

which has the classic well pattern (11 ratio with 5 m vertical inter-well spacing) was

modeled Then the performance of the other well patterns was compared against the base

case results The horizontal well length for both injector and producer was set at 500 m

Figure 5-44 displays the schematics of different well configurations These well

configurations need to be matched with specific reservoir characteristics for the optimum

performance None of them would be applicable to all reservoirs

5m

Injector

Producer

Injectors

Producer XY

Injector

Producer

Offset Horizontal InjectorBasic Well Configuration Vertical Injector

InjectorsInjectorsInjector

5m Producer Producer Producer

Reversed Horizontal Injector Parallel Inclined Injectors Parallel Reversed Upward Injectors

Injector Producer X

Multi Lateral Producer C-SAGD

Figure 5-44 Schematic representation of various well configurations for Cold Lake

5281 Base Case

This configuration introduces a wellpair consisting of injector and producer with the

vertical interwell distance of 5 m The producer is placed 15 m above the base of the net

pay Two distinct base cases were defined for future comparison a) both injector and

producer wellbores are modeled based on DW approach b) the injector is modeled with

SS wellbore approach and the producer is simulated with DW

The circulation period is 50 days and the reservoir is depleted in 4 years A close

examination of the chamber growth in both DW and SS models will show that that

STARS treats wellbores too idealistically The temperature profile along the wellpairs is

118

completely uniform during circulation as well as during the main SAGD stage However

in most of the field cases operators have difficulties in conveying the live steam to the

toe of injector for creating uniform steam chamber As a result the steam chamber will

have its maximum height at the heel of wellpairs and would become slanted along length

of the wellpairs This situation may create a potential for steam to breakthrough into the

producer resulting in difficulties in steam trap control and ultimately reduces the final

recovery factor

Therefore the new well configurations that have significantly higher chances of

activating the full well length will be considered successful configurations even when

their simulated performance is only slightly better than the base case

Figure 5-45 5-46 5-47 and 5-48 display the progression of the production for both

base cases during depletion of the reservoir

Both cases provided consistent results except for the cSOR The recovery factor for

both DW and SS models are pretty close to each other As per Figure 5-47 there is a

small difference in cSOR of DW and SS models with the respective values of 247 and

217 m3m3 In the Base Case-SS model a line heater was introduced above the injector

The heater with the modified constraint would provide sufficient heat into the intervening

zone between the injector and producer This supplied amount of energy is not included

in cSOR calculations which results in lower cSOR Therefore the difference in cSOR can

be ignored as well and both cases can be assumed to behave similarly

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Figure 5-47 Steam Oil Ratio Base Case

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121


As discussed previously the optimum vertical inter-well distance between the

injector and producer depends on reservoir permeability bitumen viscosity and

preheating period To obtain the best RF and cSOR the vertical distance needs to be

optimized To study the effect of vertical inter-well distance on SAGD performance five

distances were considered 3 4 6 7 and 8m The idea was to investigate if changing the

vertical distance will improve the recovery factor and cSOR The oil rate RF cSOR and

the chamber volume are presented on Figures 5-49 5-50 5-51 and 5-52 It is observed

that the performance decreases with increasing the vertical distance When the distance is

smaller than the base case the preheating period is shortened but the effect on subsequent

performance is not dramatic The optimum vertical distance between the injector and

producer is assumed to be 5m in most of reservoir simulations and field projects Figures

5-50 and 5-51 show that the vertical distance can be varied from 3 to 6m and 4m appears

to be the optimal distance

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5283 Offset Horizontal Injector

The interwell distance between the injector and producer depends on reservoir

permeability bitumen viscosity and preheating period Cold Lake contains bitumen with

the average viscosity of about 100000 cp which can be ranked as a lower viscosity

reservoir among the bitumen saturated sands Cold Lake bitumen offers a tempting option

of offsetting injector from producer The idea behind offsetting the injector is to increase

the drainage area available for the SAGD draw-down despite the fact that both recovery

factor and cSOR would be comparable to the Base Case pattern Therefore it is appealing

to consider a configuration when the injector is positioned at an offset of certain distance

from the producer In order to operate a SAGD project with offset injector the vertical

interwell distance needs to be small The vertical distance is assumed to be either 2m or

3m while the offset distances are set to be 5m and 10m

Four cases were simulated to investigate the possibility of offsetting the injector for a

SAGD process a) Vertical distance of 2m with the horizontal offset of 5m b) Vertical

124

distance of 2m with the horizontal offset of 10m c) Vertical distance of 3m with the

horizontal offset of 5m and d) Vertical distance of 3m with the horizontal offset of 10m

Figures 5-53 5-54 5-55 and 5-56 show that there is some benefit in providing extra

horizontal spacing According to the oil production profile and recovery factor 10m

offset does not offer any advantage to a SAGD process in Cold Lake it decreases the RF

and dramatically increases the cSOR The 10m horizontal offset requires long preheating

period which results in high cSOR Once the communication between injector and

producer established due to high viscosity of the bitumen and large horizontal spacing

between injector and producer the steam chamber does not get stable and the oil rate

fluctuates during the course of production The steam chamber does not grow uniformly

along the injector and major amount of bitumen is left unheated When the horizontal

offset is around 5m there is some improvement in RF but at the expense of higher cSOR

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Base Case-DW Offset Horizontal Injector VD=2m-Off=5m Offset Horizontal Injector VD=2m-Off=10m Offset Horizontal Injector VD=3m-Off=5m Offset Horizontal Injector VD=3m-Off=10m

Time (Date)

Figure 5-53 Oil Production Rate Offset Horizontal Injector

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70 Base Case-DW Offset Horizontal Injector VD=2m-Off=5m Offset Horizontal Injector VD=2m-Off=10m Offset Horizontal Injector VD=3m-Off=5m Offset Horizontal Injector VD=3m-Off=10m

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Figure 5-54 Oil Recovery Factor Offset Horizontal Injector

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Figure 5-55 Steam Oil Ratio Offset Horizontal Injector

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Figure 5-56 Steam Chamber Volume Offset Horizontal Injector


As discussed previously the vertical wellbores are included in each part of the current

study because of their advantages over the horizontal ones such as drilling price ease of

operation flexibility of operation Typically for every 150-200 m of horizontal well

length a vertical well is needed Therefore for this study with 500 m long horizontal

wells a well configuration with threetwo vertical injectors and a horizontal producer was

evaluated



presented in Figures 5-57 5-58 5-59 and 5-60

As was seen in Athabasca section the results demonstrate that two vertical injectors

are not sufficient to deplete a 500m long reservoir since its recovery factor reaches 55

after four years of production with a steam oil ratio of 30 m3m3 On the other hand the

three vertical injectors case provides comparable RF with respect to base case RF but at

larger amount of injected steam The RF and cSOR of three vertical injectors is 63 and

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127

32 m3m3 respectively The steam chamber volume of the 3 vertical injectors is larger

than the base case which demonstrates that the steam is delivered more efficient than the

base case

The line heater was used to establish the thermal communication between the vertical

injectors and producer The heating period was the same as base case preheating period

Once the intervening bitumen between injector and producer is warmed up the injectors

were set on injection Vertical injectors caused some instability in numerical modeling

once the steam zone of each vertical well merges to the adjacent steam zone This issue

was resolved using more refined grid blocks along the producer

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Base Case-SS 2 Vertical Injectors 3 Vertical Injectors

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This pattern was well described previously and its aim was defined to establish a

uniform steam chamber along the well-pairs by imposing a uniform pressure difference

along the injectorproducer vertical interwell distance This well configuration is able to

provide live steam almost along the whole length of the injector and producer The

vertical distance between the injector and producer is 5 m The injectorrsquos heel is placed

above the producerrsquos toe and its toe right above the producerrsquos heel The steam chamber

growth is uniform in three main directions vertically laterally and longitudinally

The oil rate RF cSOR and the chamber volume are plotted on Figures 5-61 5-62 5shy

63 and 5-64 The technical performance of Reverse Horizontal Injector and Base Case-

DW are compared In both Base Case-DW and Reversed Horizontal Injector models a

discretized wellbore formulation was used as Injector Oil recovery factor increased by

2 but the cSOR was the same as Basic Case-DW

The results suggest that there is a potential benefit for reversing the injector in Cold

Lake type of reservoir This pattern provides the possibility of higher and uniform

130

pressure operation This strongly suggests that this pattern be examined through a pilot

project in Cold Lake type of reservoir

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Vertical horizontal and inclined injectors provide some advantages for the SAGD

process namely flexibility of injection point extensive access to the reservoir and short

circulation period The parallel Inclined Injector was designed to combine all these

benefits together In this pattern two 250 m inclined injectors were located above the

producer

The pattern is shown in Figure 5-44 The injectors were defined using the SS

wellbore formulation therefore the results are compared against the Base Case-SS

pattern Figures 5-65 5-66 5-67 and 5-68 present the ultimate production results for the

Parallel Inclined Injectors The recovery factor increased by 36 but the cSOR also

increased by 138

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5287 Parallel Reversed Upward Injectors

Parallel inclined injector and reversed horizontal showed encouraging performance in

comparison with the Base case Combining the advantages gained via these two well

configurations the Parallel Reversed Upward Injectors was proposed Two upward

inclined injectors were introduced above the producer The main thought behind this

special design is to provide a uniform pressure profile along the injector and producer

and resolve the unconformity of steam chamber associated with the Base Case pattern

Each injector has about 250 m length and their heels are connected to the surface The

first injector has its heel above the toe of producer

Figure 5-69 5-70 5-71 and 5-72 compare the technical performance of Parallel

Reversed Inclined Injectors and Base Case-SS The recovery factor and cSOR increased

by 55

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Figure 5-69 Oil Production Rate Parallel Reverse Upward Injector

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70 Base Case-SS Parallel Reverse Upward Injectors

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Figure 5-70 Oil Recovery Factor Parallel Reverse Upward Injector

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Figure 5-71 Steam Oil Ratio Parallel Reverse Upward Injector

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Figure 5-72 Steam Chamber Volume Parallel Reverse Upward Injector


Economic studies show that SAGD mechanism is not feasible in thin reservoirs due

to enormous heat loss and consequently high cSOR [90] Therefore the low RF

production mechanisms such as cold production will continue to be used for extraction of

heavy oil On the other hand in Cold Lake type of reservoir unnecessary steam

production is often associated with mature SAGD and large amount of bitumen would be

left behind in the area between the chambers In order to access more of the heated

mobilized bitumen and increase the productivity of a well the productive interval of the

wellbore can be increased via well completion in the form of multi-lateral wells Multishy

lateral wells are expected to provide better horizontal coverage than horizontal wells and

they can extend the life of projects A simulation study on the evaluation of multilateral

well performance is presented Multiple 30 m legs are connected to the producer

Figure 5-73 5-74 5-75 and 5-76 show the results for Mutli-Lateral pattern against

the Base Case-SS The Multi-Lateral depletes the reservoir significantly faster than the

138

basic pattern The plotted results demonstrate that the Multi-Lateral is not able to provide

any other significant benefits over the performance of base case SAGD

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5289 C-SAGD

At Cold Lake Cyclic Steam Stimulation has been successfully used as the main

recovery mechanism because there are often heterogeneities in form of shale barriers that

are believed to limit the vertical growth of steam chamber and consequently decrease the

efficiency of thermal methods In CSS process the steam is injected at high pressure

(usually higher than the fracture pressure) into the reservoir its high pressure creates

some fractures in the reservoir and its high temperature causes a significant drop in

bitumen viscosity As a result a high mobility zone will be created around the wellbore

which the fluids (melted bitumen and condensate) can flow back into the wellbore The

fracturing stage is known as deformation which includes dilation and re-compaction

Beatle et al defined a deformation model which is presented in Figure 5-77 [96]

During the steam injection into the reservoir the reservoir pressure increases and the

rock behaves elastically The rock pore volume at the new pressure will be obtained

based on the rock compressibility initial reservoir pressure and initial porosity If the

reservoir pressure increases above the so called pdila then the reservoir pore volume

141

follows the dilation curve which is irreversible It may reach the maximum porosity If

the pressure decreases from any point on the dilation curve then the reservoir pore

volume follows the elastic compaction curve If the pressure drops below the re-

compaction pressure ppact re-compaction occurs and the slop of the curve is calculated

by the residual dilation fraction fr

Figure 5-77 Reservoir deformation model [96]

Every single cycle of a CSS process follows the entire deformation envelope The

deformation properties of the cold lake reservoir are provided in Table 5-7 [97]

Table 5-7 Values of dilation-compaction properties for Cold Lake reservoir model

pdila 7300 kPa ppact 5000 kPa φmax 125 φi Residual Dilation Fraction fr 045 Dilation Compressibility 10 E-4 1kPa

The C-SAGD pattern is aimed at combining the benefits of CSS and SAGD together

This configuration starts with one cycle of CSS at both injector and producer locations to

create sufficient mobility in vicinity of both wellbores The one cycle comprises the

steam injection soaking and production stage The CSS cycle starts with 20 days of

steam injection at a maximum pressure of 10000 kPa on both injector and producer 7

142

days of soaking and approximately two months of production Thereafter it switches

into normal SAGD process by injection of steam from injector and producing via

producer The constraints of injector and producer are the same as values are presented in

section 526 The objective of the C-SAGD well pattern is to decrease the preheating

period without affecting the ultimate recovery factor and cumulative steam oil ratio The

injector and producer are placed at the same depth with two set of offsets 10m and 15m

Their results are compared against the Base Case It has to be noted that both injector and

producer in the C-SAGD patter are modeled using the SS wellbore As a result some

marginal value (due to higher pressure and injection rate approximately larger than 02shy

03 m3m3) has to be added to their ultimate cSOR value Figure 5-78 5-79 5-60 and 5shy

61 presents the oil rate RF cSOR and the chamber volume of the two C-SAGD cases in

comparison with the base case results

Oil

Prod

Rat

e SC

TR (m

3da

y)

300

270

240

210

180

150

120

90

60

30

0

Base Case-DW C-SAGD-Offset=10m C-SAGD-Offset=15m

2008-7 2009-1 2009-7 2010-1 2010-7 2011-1 2011-7 2012-1 Time (Date)

Figure 5-78 Oil Production Rate C-SAGD

143

Oil

Rec

over

y Fa

ctor

SC

TR

0

10

20

30

40

50

60

70

80 Base Case-DW C-SAGD-Offset=10m C-SAGD-Offset=15m

2008-7 2009-1 2009-7 2010-1 2010-7 2011-1 2011-7 2012-1

Time (Date)

Figure 5-79 Oil Recovery Factor C-SAGD

Stea

m O

il R

atio

Cum

SC

TR (m

3m

3)

00

10

20

30

40

50

60

70

80

90


2008-7 2009-1 2009-7 2010-1 2010-7 2011-1 2011-7 2012-1

Time (Date)

Figure 5-80 Steam Oil Ratio C-SAGD

144

Stea

m C

ham

ber

Volu

me

SCTR

(m3)

90000

80000

70000

60000

50000

40000

30000

20000

10000

0


2008-7 2009-1 2009-7 2010-1 2010-7 2011-1 2011-7 2012-1 Time (Date)

Figure 5-81 Steam Chamber Volume C-SAGD

The C-SAGD pattern with the offset of 10m is able to deplete the reservoir in 3 years

at ~70 RF and cSOR of 22 m3m3 (needs to add ~02-03 m3m3 due to SS injector and

producer) The pattern enhances the RF of SAGD process significantly The only

limitation with this pattern for the current research scope is the requirement for super

high injection pressure for a short period of time

53 Lloydminster

Steam-flooding has been practiced extensively in North America Generally speaking

steam is introduced into the reservoir via a horizontalvertical injector while the heated

oil is being pushed towards the producer Several types of repeated patterns are known to

provide the most efficient recovery factor The major issues with the steam flooding

process are (1) steam tends to override the heavy oil and breaks through to the

production well and (2) the steam has to displace the cold heavy oil into the production

well These concerns make steam flooding inefficient in reservoirs containing heavy oil

with reservoir condition viscosities higher than 1000 cp However in SAGD type of

Net

145

process the heated oil remains hot as it flows into the production well Figure 5-82 shows

both steam flooding and SAGD processes

At Lloydminster area the reservoirs are mostly complex and thin with a wide range

oil viscosity These characteristics of the Lloydminster reservoirs make most production

techniques such as primary depletion waterflood CSS and steamflood relatively

inefficient The highly viscous oil coupled with the fine-grained unconsolidated

sandstone reservoir often result in huge rates of sand production with oil during primary

depletion Although these techniques may work to some extent the recovery factor

remains low (5 to 15) and large volumes of oil are left unrecovered when these

methods have been exhausted Because of the large quantities of sand production many

of these reservoirs end up with a network of wormholes which make most of the

displacement type enhanced oil recovery techniques inapplicable Steam Oil amp Water

Overburden

Underburden

Steam Chamber

Underburden

Overburden

Vertical Cross Section of SAGD Vertical Cross Section of Steamflood

Figure 5-82 Schematic of SAGD and Steamflood


SAGD and steamflooding can be considered applicable for extraction of the heavy oil In

fact this type of reservoir provides more flexibility in designing the thermal recovery

techniques as a result of their higher mobility and steam injectivity Steam can be pushed

and forced into the reservoir displacing the heavy oil and creating more space for the

chamber to grow On the other hand due to small thickness of the net pay the heat loss

could make the process uneconomical for both methods However steamflood faces its

own additional problems as well no matter where it is applied For the SAGD case

146

although drainage by the SAGD mechanism from the steam chamber to the production

well is conceivable due to the small pay thickness the gravity forces may not be large

enough to provide economical drainage rates

Unfortunately SAGD has not received adequate attention in Lloydminster area

mostly due to the notion that lower drainage rate and higher heat loss in thin reservoirs

would make the process uneconomical While this may be true the limiting reservoir

thickness and inter-well horizontal distance for SAGD under varying conditions has not

been established These reservoirs contain oil with sufficient mobility Therefore the

communication between the SAGD well pairs is no longer a hurdle This opens up the

possibility of increasing the distance between the two wells and introducing elements of

steamflooding into the process in order to compensate for the small thickness of the

reservoir In fact a new application of SAGD mechanism for the reservoir with the

conventional heavy oil could be the combination of an early lateral steam drive with

SAGD afterwards In this scheme steam would be injected from an offset horizontal

injector pushing the oil towards the producer Once the communication between injector

and producer is established the recovery mechanism will be changed to a SAGD process

by applying steam trap control to the production well

Among the whole Mannville group the formations that have potential to be

considered as oil bearing zone are Waseca Sparky GP and Lloydminster These

sandstone channels thicknesses may rarely go up to 20m and the oil saturation up to 80

Their porosity ranges from 30-35 percent and permeability from 5 to 10 Darcyrsquos

Mannville group contains both conventional and heavy oil with the API ranging from 15shy

38 degAPI and viscosity of 800-20000 cp at 15 degC

531 Reservoir Model

The optimization of the well configuration study was carried out via a series of

numerical simulations using CMGrsquos STARS 2010 A 3-D symmetrical-Cartesianshy

homogenous reservoir model was used to conduct the comparison analysis between

different well configurations The reservoir and fluid properties were simply averaged to

present the best representative of Lloydminster deposit The model corresponds to a

reservoir with the size of 90mtimes500mtimes10 m using the Cartesian grid block sizes of

147

1times50times1 in itimes jtimesk directions respectively Figure 5-83 displays a 3-D view of the

reservoir model

10

500

90

Figure 5-83 3-D schematic of reservoir model for Lloydminster reservoir

The reservoir and fluid properties are summarized in Table 5-8 The rock properties

are the same as Athabasca and Cold Lake


As in simulations of Athabasca and Cold Lake reservoirs three components were

included in the reservoir model as Oil water and methane The thermal properties of the

fluid and rock were obtained from the published literature The properties of the water in

both aqueous and gas phase were set as the default values of the CMG-STARS The

properties of the fluid (oil and methane) model are provided in Table 5-8

The K-Values of methane are the same as the numbers presented for Athabasca and Cold

Lake reservoirs



ln ln (μ) = A + B ln (T) Figure 5-84 shows the viscosity-temperature variation for the heavy oil model

Rock fluid properties are the same as the relative permeability sets presented for

Athabasca and Cold Lake reservoirs

148

Table 5-8 Reservoir and Fluid Properties for Lloydminster reservoir model

Net Pay 10 m Depth 450 m Permeability Kh 5000 md KvKh 08 Porosity 34 Initial Pressure PR 4100 kPa Initial Temperature TR 20 degC Oil Saturation So 80 mFrac Gas in Oil 10 Oil Viscosity TR 5000 cp

533 Initial ConditionsGeomechanics



of gas in heavy oil is 10 The total pore volume and oil phase volume are 192 and 154

E+5m3

Geo-mechanical effects were ignored in the entire study except the C-SAGD pattern


The well length was kept constant at a value of 500m The injection well was

constrained to operate at a maximum bottom hole pressure It operated at 500 kPa above

the reservoir pressure The steam quality was equal to 09 at the sand-face The

corresponding steam saturation temperature at the bottom-hole pressure is 2588 degC


bottom-hole pressure of 1000-2000 kPa and steam trap of 10 degC (The 1000 kPa is for

the offset of larger than 30 m) The specified steam trap constraints for producer will not

allow any live steam to be produced via the producer

149

10000

Visc

osity

cp

1000

100

10

1 0 50 100 150 200 250

TemperatureC

Figure 5-84 Temperature dependency of heavy oil modelrsquos Viscosity


Each numerical case was run for total of 7 years The preheating is variable for

Lloydminster area and it really depends on the well configuration and wellbore offset


The basic well pattern is practical for the reservoirs with the thickness of higher than

20 m as the vertical inter-well distance is 5 m and the producer is placed at least 15 m

above the base of the pay zone However depending on the reservoir thickness and oil

properties it might be advantageous to drill several horizontalvertical wells at different

levels of the reservoir ie employ other configurations than the classic one to enhance the

drainage and heat loss efficiency These well configurations need to be matched with

specific reservoir characteristics for the optimum performance

When two parallel horizontal wells are employed in SAGD the relevant

configuration parameters are (a) height of the producer above the base of the reservoir

(b) the vertical distance between the producer and the injector and (c) the horizontal

300

150

separation between the two wells which is zero in the base case configuration Although

the assumed net pay for the Lloydminster reservoir is 10 m but just for sake of

comparison the base case is the same pattern was defined before ie an injector located

5m above the producer which is the case under the name of VD=5m_Offset=0m




Injectors Produce Injectors

Injector

5m Producer Producer

Basic Well Configuration Offset Producer Top View Vertical Injector

Injectors Produce Injectors Produce

Injector Producer X

C-SAGD ZIGZAG Producer Top View Multi Lateral Producer Top View

Figure 5-85 Schematic of various well configurations for Lloydminster reservoir

The SS wellbore type is used in all the defined well configurations for Lloydminster

In fact due to some of the special patterns such as C-SAGD some high differential

pressure and consequently high fluid rates are required which the DW modeling is not

able to model properly As a result some marginal value has to be added to their ultimate

cSOR value in order to compensate for replacing DW by SS wellbore

Two types of start-up are used in initializing the proposed patterns in Figure 5-85 a)

routine SAGD steam circulation b) one CSS cycle Due to the nature of fluid and

reservoir in Lloydminster area initial oil viscosity of 5000 cp at reservoir temperature

the initial mobility is high but not sufficient for a cold production start The primary

production leads to a small recovery factor and would create worm holes in the net pay

Therefore some heat is required to be injected into the reservoir to mobilize the heavy oil

Among the six proposed well patterns only C-SAGD initializes the production by

one cycle of CSS In C-SAGD pattern the steam at high pressure of 10000 kPa is

151

injected in both injector and producer thereafter both wells were shut-in for a week

(soaking period) The heated mobilized heavy oil around the injector and producer were

produced for approximately 4 months Eventually the steam was injected via injector and

pushed the heavy oil towards the producer which was set at a minimum bottom-hole

pressure of 1000 kPa The start-up stage in the rest of the patterns follows the same

routing steps of a regular SAGD process steam circulation which followed by

injectionproduction via injector and producer The steam circulation is achieved by

defining a line heater above the injector and producer The period of steam circulation

really depends on the well pair horizontal spacing and is variable among each pattern

5361 Offset Producer

The lower viscosity of the Lloydminster deposit comparing to Cold Lake and

Athabasca reservoirs opens up the possibility of increasing the distance between the two

wells and introducing elements of steam flooding into the process in order to compensate

for the small thickness of the reservoir Due to the low viscosity and sufficient mobility

the communication between the SAGD well pairs may be no longer a hurdle Therefore

the horizontal separation between the two well is more flexible in Lloydminster type of

reservoir and due to the small thickness of the net pay the vertical distance needs to be as

small as possible

The objective of the offset producer pattern is to increase the horizontal spacing

between wells as much as possible To establish the chamber on top of the well pairs

which are separated horizontally the fact that any increase in the well spacing may

require more circulation period needs to be considered Horizontal well spacing of 6 12

24 30 36 and 42 m were tested to obtain the optimum performance The circulation

period was varied between 20 and 80 days which occurred at 6m and 42m offset

producer Figure 5-86 5-87 5-88 and 5-89 shows the results for the offset injector

against the Base Case-DW

152

Oil

Rat

e SC

(m3

day)

0

20

40

60

80

100

120

140

160

180

200 VD=5m-Offset=0m VD=0m-Offset=6m VD=0m-Offset=12m VD=0m-Offset=18m VD=0m-Offset=24m VD=0m-Offset=30m VD=0m-Offset=36m VD=0m-Offset=42m

2009 2010 2011 2012 2013 2014 2015 2016

Time (Date)

Figure 5-86 Oil Production Rate Offset Producer

Oil

Rec

over

y Fa

ctor

SC

TR

0

15

30

45

60


2009 2010 2011 2012 2013 2014 2015 2016

Time (Date)

Figure 5-87 Oil Recovery Factor Offset Producer

153

Cum

Ste

am O

il R

atio

(m3

m3)

00

10

20

30

40

50


2009 2010 2011 2012 2013 2014 2015 2016

Time (Date)

Figure 5-88 Steam Oil Ratio Offset Producer

Stea

m C

ham

ber V

olum

e SC

TR (m

3)

00e+0

20e+4

40e+4

60e+4

80e+4

10e+5 VD=5m-Offset=0m VD=0m-Offset=6m VD=0m-Offset=12m VD=0m-Offset=18m VD=0m-Offset=24m VD=0m-Offset=30m VD=0m-Offset=36m VD=0m-Offset=42m

2009 2010 2011 2012 2013 2014 2015 2016

Time (Date)

Figure 5-89 Steam Chamber Volume Offset Producer

154

The minimum RF is 66 which belongs to the base case 42m offset producer pattern

and the maximum obtained RF is 71 which obtained by the 30m offset On the other

hand the 42m and 36m offset producer provide the minimum steam oil ratio of 46 m3m3

Among all the offset patterns the 30m offset producer provides the most optimum

performance Therefore it can be concluded that if any offset horizontal well is decided

to be drilled in Lloydminster type of reservoir the horizontal inter-well distance can not

be larger than 30m


According to early experience of SAGD in Lloydminster area vertical wells were

considered as successful with the steam oil ratio of 3-6 m3m3 [98] Generally 3-4 vertical

injection wells with an offset of 50m have been used for a 500m long horizontal

producer There is an unanswered question of how much of horizontal offset should be

considered between vertical injectors and horizontal producers so that the SAGD would

achieve optimum performance Vertical injector well configuration was tested using 3

vertical wells combined with a horizontal producer using the offsetting values of 0 6 12

18 24 30 36 and 42 horizontal wells The zero offset case locates the three vertical

injectors above the producer imposing 4 m of vertical inter-well distance In the rest of

offset cases the injectorrsquos completed down to the producerrsquos depth The comparison

between the base case results and the vertical well scenarios are presented in Figure 5-90

5-91 5-92 and 5-93

The pattern which has 3 vertical injectors 5m above the producer exhibits the best

performance regarding the RF and cSOR It RF equals to 70 while its cSOR is 52

m3m3 However the 42m offset vertical injectors pattern has a promising performance

with an extra benefit This pattern allows to enlarge the drainage area by 42m which will

affect the number of required well to develop a full section much less than the no offset

vertical injectors

155

Oil

Rat

e SC

(m3

day)

0

30

60

90

120

150

180

210 VD=5m-Offset=0m 3VW-VD=5m-Offset=0m 3VW-VD=0m-Offset=6m 3VW-VD=0m-Offset=12m 3VW-VD=0m-Offset=18m 3VW-VD=0m-Offset=24m 3VW-VD=0m-Offset=30m 3VW-VD=0m-Offset=36m 3VW-VD=0m-Offset=42m

2009 2010 2011 2012 2013 2014 2015 2016

Time (Date)

Figure 5-90 Oil Production Rate Vertical Injector

Oil

Rec

over

y Fa

ctor

SC

TR

0

12

24

36

48

60

72

VD=5m-Offset=0m 3VW-VD=5m-Offset=0m 3VW-VD=0m-Offset=6m 3VW-VD=0m-Offset=12m 3VW-VD=0m-Offset=18m 3VW-VD=0m-Offset=24m 3VW-VD=0m-Offset=30m 3VW-VD=0m-Offset=36m 3VW-VD=0m-Offset=42m

2009 2010 2011 2012 2013 2014 2015 2016

Time (Date)

Figure 5-91 Oil Recovery Factor Vertical Injector

156

Stea

m O

il R

atio

Cum

SC

TR (m

3m

3)

00

10

20

30

40

50


2009 2010 2011 2012 2013 2014 2015 2016

Time (Date)

Figure 5-92 Steam Oil Ratio Vertical Injector

Stea

m C

ham

ber V

olum

e SC

TR (m

3)

00e+0

20e+4

40e+4

60e+4

80e+4

10e+5 VD=5m-Offset=0m 3VW-VD=5m-Offset=0m 3VW-VD=0m-Offset=6m 3VW-VD=0m-Offset=12m 3VW-VD=0m-Offset=18m 3VW-VD=0m-Offset=24m 3VW-VD=0m-Offset=30m 3VW-VD=0m-Offset=36m 3VW-VD=0m-Offset=42m

2009 2010 2011 2012 2013 2014 2015 2016

Time (Date)

Figure 5-93 Steam Chamber Volume Vertical Injector

157

5363 C-SAGD

The C-SAGD pattern was simulated in Cold Lake reservoir and its results were

promising Due to low oil viscosity and thickness at Lloydminster reservoir it is desired

to shorten the circulation period as much as possible The C-SAGD provides the

possibility to establish the communication between injector and producer in minimal time

period As explained earlier in Cold Lake section this pattern comprises of one CSS

cycle at both injector and producer locations and thereafter it switches to regular SAGD

process The CSS cycle starts with 15 days of steam injection at a maximum pressure of

10000 kPa on both injector and producer 7 days of soaking and approximately three

months of production Thereafter it switches into normal SAGD process by injection of

steam from injector and producing via producer During the normal SAGD the

constraints of injector and producer are the same as values are presented in section 544

The injector and producer are placed at the same depth with the offsetting spacing of 6

12 18 24 30 36 and 42 m Figures 5-94 5-95 5-96 5-97 present the C-SAGD results

According to RF results the offset of 6 and 12m is small for a C-SAGD process But

since the horizontal inter-well distance between the injector and producer gets larger the

RF will be somewhere around 80 which sounds quite efficient The patterns with an

offset value of larger than 12m are able to deplete the reservoir with a cSOR in the range

of 6-65 m3m3 According to the results the most optimum horizontal inter-well spacing

is 42m since it has the highest RF the lowest cSOR and provides the opportunity to

enlarge the drainage area

158

Oil

Rat

e SC

(m3

day)

0

30

60

90

120

150

180

210 VD=5m-Offset=0m C-SAGD-Offset=6m C-SAGD-Offset=12m C-SAGD-Offset=18m C-SAGD-Offset=24m C-SAGD-Offset=30m C-SAGD-Offset=36m C-SAGD-Offset=42m

2009 2010 2011 2012 2013 2014 2015 2016

Time (Date)


Oil

Rec

over

y Fa

ctor

SC

TR

0

10

20

30

40

50

60

70

80


2009 2010 2011 2012 2013 2014 2015 2016

Time (Date)


159

Stea

m O

il R

atio

Cum

SC

TR (m

3m

3)

00

10

20

30

40

50

60

70

VD=5m-Offset=0m C-SAGD-Offset=6m C-SAGD-Offset=12m C-SAGD-Offset=18m C-SAGD-Offset=24m C-SAGD-Offset=30m C-SAGD-Offset=36m C-SAGD-Offset=42m

2009 2010 2011 2012 2013 2014 2015 2016

Time (Date)


Stea

m C

ham

ber V

olum

e SC

TR (m

3)

00e+0

20e+4

40e+4

60e+4

80e+4

10e+5

12e+5 VD=5m-Offset=0m C-SAGD-Offset=6m C-SAGD-Offset=12m C-SAGD-Offset=18m C-SAGD-Offset=24m C-SAGD-Offset=30m C-SAGD-Offset=36m C-SAGD-Offset=42m

2009 2010 2011 2012 2013 2014 2015 2016

Time (Date)


160

5364 ZIGZAG Producer

A new pattern called ldquoZIGZAGrdquo was designed and compared against the horizontal

offsets The objective for this well pattern was to shorten the circulation period without

affecting the ultimate performance The horizontal inter-well distance between the

injector and producer are assumed as 12 18 24 30 36 and 42 m The producer enters

into the formation at X meters offset of the injector but it approaches toward the injector

up to X2 meters away from injector and it bounce back to its primary location of X

meters from injector This move repeatedly occurs throughout the length of injector The

results of ZIGZAG pattern are provided in Figures 5-98 5-99 5-100 and 5-101

Increasing the offset between injector and producer enhance the performance which has

the same trend in other configurations The 42m offset depletes the reservoir much faster

while it exhibits the highest RF of 78 and lowest cSOR of 5 m3m3

Oil

Rat

e SC

(m3

day)

180

160

140

120

100

80

60

40

20

0

VD=5m-Offset=0m ZIGZAG-Offset=12m ZIGZAG-Offset=18m ZIGZAG-Offset=24m ZIGZAG-Offset=30m ZIGZAG-Offset=36m ZIGZAG-Offset=42m

2009 2010 2011 2012 2013 2014 2015 2016 Time (Date)

Figure 5-98 Oil Production Rate ZIGZAG

161

Oil

Rec

over

y Fa

ctor

SC

TR

0

10

20

30

40

50

60

70

80 VD=5m-Offset=0m ZIGZAG-Offset=12m ZIGZAG-Offset=18m ZIGZAG-Offset=24m ZIGZAG-Offset=30m ZIGZAG-Offset=36m ZIGZAG-Offset=42m

2009 2010 2011 2012 2013 2014 2015 2016

Time (Date)

Figure 5-99 Oil Recovery Factor ZIGZAG

Stea

m O

il R

atio

Cum

SC

TR (m

3m

3)

00

10

20

30

40

50


2009 2010 2011 2012 2013 2014 2015 2016

Time (Date)

Figure 5-100 Steam Oil Ratio ZIGZAG

162

Stea

m C

ham

ber V

olum

e SC

TR (m

3)

10e+5

80e+4

60e+4

40e+4

20e+4

00e+0


2009 2010 2011 2012 2013 2014 2015 2016 Time (Date)

Figure 5-101 Steam Chamber Volume ZIGZAG


For the thin reservoirs of Lloydminster type due to its potential for much higher heat

loss and consequently high cSOR the conventional SAGD is considered uneconomical

In order to access more of the heated mobilized bitumen and increase the productivity of

a well the productive interval of the wellbore can be increased via well completion in the

form of multi-lateral wells Multi lateral wells are expected to provide better reservoir

coverage than horizontal wells and they can extend the life of projects The multi-lateral

producer was numerically simulated and compared against the base case The multishy

lateral producer has 10 legs each has 50m length The producer is located at the same

depth of the injector and with an offset of 6m The results of the Multi-Lateral producer

are presented in Figure 5-102 5-103 5-104 and 5-105 Itrsquos performance is compared

against the most promising well pattern that was explored in earlier sections

163

Oil

Rat

e SC

(m3

day)

0

20

40

60

80

100

120

140

160

180 Multi-Lateral-Offset=6m VD=0m-Offset=30m 3VW-VD=0m-Offset=42m C-SAGD-Offset=42m ZIGZAG-Offset=42m

2009 2010 2011 2012 2013 2014 2015 2016

Time (Date)

Figure 5-102 Oil Production Rate Comparison

Oil

Rec

over

y Fa

ctor

SC

TR

0

15

30

45

60

75


2009 2010 2011 2012 2013 2014 2015 2016

Time (Date)

Figure 5-103 Oil Recovery Factor Comparison

164

Stea

m O

il R

atio

Cum

SC

TR (m

3m

3)

00

10

20

30

40

50

60


2009 2010 2011 2012 2013 2014 2015 2016

Time (Date)

Figure 5-104 Steam Oil Ratio Comparison

Stea

m C

ham

ber V

olum

e SC

TR (m

3)

00e+0

20e+4

40e+4

60e+4

80e+4

10e+5

12e+5 Multi-Lateral-Offset=6m VD=0m-Offset=30m 3VW-VD=0m-Offset=42m C-SAGD-Offset=42m ZIGZAG-Offset=42m

2009 2010 2011 2012 2013 2014 2015 2016

Time (Date)

Figure 5-105 Steam Chamber Volume Comparison

165

The Multi-Lateral producer is able to sweep off the heavy oil in 4 years at a RF of

67 and cSOR of 56 m3m3 Its performance with respect to ultimate recovery factor and

steam oil ratio is weaker than the rest of optimum patterns The C-SAGD pattern exhibits

the highest RF (81) and at the same time highest cSOR (64 m3m3) Among these

patterns the vertical injectors seems to provide reasonable performance since its recovery

factor is 70 but at a low cSOR value of 52 In addition to the vertical injector

performance the drilling and operation benefits of vertical injector over the horizontal

injector this 3-vertical injector is recommended for future development in Lloydminster

reservoirs

CHAPTER 6

EXPERIMENTAL RESULTS AND

DISUCSSIONS

167

This chapter presents the results and discussions of the physical model experiments

conducted for evaluating SAGD performance in two of Albertarsquos bitumen reservoirs a)

Cold Lake b) Athabasca

The objective of these experiments was to confirm the results of numerical

simulations for the optimum well configuration in a 3-D physical model Two type of

bitumen were used in experiments 1) Elk-Point oil which represents the Cold Lake

reservoir and 2) JACOS bitumen which represents the Athabasca reservoir

Three different well configurations were tested using the two oils I) Classic SAGD

Pattern II) Reverse Horizontal Injector and III) Inclined Injector Each experiment was

history matched using a commercial simulator CMG-STARS to further understand the

performance and behaviour of each experiment A total of seven physical model

experiments were conducted Four experiments used the classic two parallel horizontal

wells configuration which were considered base case tests

The first experiment was used as the base case for the Cold Lake reservoir When the

physical model was designed there were some concerns regarding the initially assumed

reservoir parameters which were applied in the dimensional analysis In the second

experiment the assumed permeability of the model was increased while the same fluids

were used for saturating the model In fact the second experiment was conducted to

examine the scaling criteria discussed in chapter 4

Since a large volume of sand was required in each experiment and re-packing the

model was time consuming there was a thought that perhaps the model can be re-

saturated after each run by oil flooding the depleted model without any cleaning and

opening of the model Therefore the third experiment was run aiming at reducing the

turn-around time for experiments by re-saturating the model The last classic SAGD

pattern was the fifth experiment which uses the same sand as the first experiment but was

saturated using the Athabasca bitumen

Two sets of experiments used the Reverse Horizontal Injector pattern Each test used a

different bitumen while they both were packed with the same AGSCO silica sand Finally

the last experiment used the Inclined Injector pattern using the Athabasca bitumen and

AGSCO sand

168

Table 6-1 presents a summary of all experiments and their relevant initial properties

Table 6-1 Summary of the physical model experiments

Experiment Permeability D

Porosity

Soi

Swi

Viso Ti cp

Well Spacing cm

First 270 3600 8602 1398 29800 5 Second 650 3625 9680 320 29800 5 Third 650 3625 9680 320 29800 5 Fourth 265 3160 8730 1270 29800 10 Fifth 260 3460 8690 1310 440668 10 Sixth 260 3100 8750 1250 440668 10 Seventh 260 3290 8700 1300 440668 5-18

The performance of each experiment was examined based on the injection

production and temperature (steam chamber) data Performance analysis included oil

rate water cut steam injection rate (CWE) cumulative Steam Oil Ratio (cSOR)

recovery factor Water Cut (WCUT) and steam chamber contour maps The contour

maps were plotted to observe the shape and size of steam chamber at various times of

each test The chamber volume profile for each experiment was calculated using

SURFER 90 software which is powerful software for contouring and 3D surface

mapping To obtain a representative chamber volume every single temperature reading

of the thermocouples was imported into the SURFER at specific pore volumes injected

(PVinj) time thereafter the chamber volume which was enclosed by steam temperature

was calculated The final step in the analysis was matching the production profile of each

experiment using a numerical simulation model CMG-STARS

61 Fluid and Rock Properties Two types of packing material either glass beads or sand were used to create a

porous medium inside the model The glass beads were of A-130 size and provided a

permeability of 600-650 D The sand was the AGSCO 12-20 mesh sand with a

permeability of 250-290 D and a porosity of 31-34 The porosity and permeability of

AGSCO 12-20 was measured in the apparatus displayed in Figure 4-2 The sand-pack

was prepared in a 68 cm long stainless steel tube to conduct the permeability

measurements at higher rates The measured points are shown in Figure 6-1 in forms of

the flow rate versus pressure drop and the slope of the fitted straight line is the

permeability According to the slope of the best fit line to the experimental data the

169

permeability of the AGSCO 12-20 was 262 D with the associated porosity of 33 The

AGSCO 12-20 was used in the last five experiments The porosity associated with the

AGSCO 12-20 sand was measured at the start of each run in the 3-D physical model and

it varied between 31-34 Table 6-1 lists the measured values of porosities for each

physical model run It is assumed that the permeability would be similar when the same

sand is packed into the physical model and the resulting porosity in the model is not too

different from that in the linear sand-pack

The objective of this study was aimed at experimental evaluation of the optimum well

configurations on Cold Lake and Athabasca type of reservoirs Hence two heavy oils

were obtained Elk Point heavy oil provided by Husky Energy and the Athabasca

bitumen provided by JACOS The viscosity of both heavy oils was measured using the

HAAKE viscometer described in chapter 4 The viscosity was measured at temperatures

of 25-70 ordmC To estimate a full range of viscosity vs temperature the Mehrotra and

Svercek viscosity correlation [93] was used to honor the measured viscosities of both

oils Figure 6-2 and 6-3 show the viscosity-temperature variation for Elk-Point and

Athabasca bitumen respectively The oil density at room temperature of 21 ordmC was 987

and 1000 kgm3 for Elk Point and JACOS oil respectively

y = 26222x

R2 = 09891

0

10

20

30

40

50

60

70

80

0 005 01 015 02 025 03

∆PL psicm

QA

ccmincm

2

Measured

Linear Regression

Figure 6-1 Permeability measurement with AGSCO Sand

170

1

10

100

1000

10000

100000

0 50 100 150 200 250 300

Measured Data

Mehrotras Corelation

Temperature degC

Viscosity

cp

Figure 6-2 Elk-Point viscosity profile

1

10

100

1000

10000

100000

1000000

0 50 100 150 200 250 300

Temperature C

Visco

cp

Measured Date

Mehrotra Correlation

Figure 6-3 JACOS Bitumen viscosity profile

171

62 First Second and Third Experiments 621 Production Results

The first experiment was conducted to attest the base case performance in Cold Lake

type of reservoir Its well configuration was the classic 11 ratio which is a horizontal

injector located above a horizontal producer The vertical distance between the horizontal

well-pair was 5 cm This vertical distance was an arbitrary number but it is geometrically

similar to the 5 m inter-well distance in 25 m thick formation The model was packed

using AGSCO 12-20 mesh sand and saturated with the Elk-Point oil (at irreducible water

saturation) using the procedure described in Chapter 4 In order to fully saturate the

model ~195 kg of heavy oil was consumed which lead to initial oil saturation of ~86

The saturation step took 12 days to complete

The second experiment used the same configuration and vertical inter-well distance

However instead of AGSCO 12-20 mesh sand A-130 size glass beads were used to pack

the model These glass beads provided a permeability of 600-650 D

The third experiment was a repeat of second one and it was intended to test the

feasibility of re-saturating the model using the Elk-Point oil Unfortunately the re-

saturating idea was not successful and the results were rather discouraging The third

experimentrsquos results were compared against the second experiment The first and second

experiments are compared using the oil production rate cSOR WCUT and recovery

factor in Figures 6-4 6-5 6-6 and 6-7

The oil rate in the first experiment remains mostly in a plateau between 3 to 5 ccmin

following a short-lived peak of 11 ccmin It shows another peak near the end that is

related to blow-down Compared to this the maximum oil rate in the second experiment

is much higher and the rate stays in vicinity of 15 ccmin for most of the run As shown in

Figure 6-4 the oil rate in the second experiment is about 3 times the rate in the first

experiment

The first experiment was run continuously for 27 hours The oil rate reached a peak at

~1 hr which was due to accumulation of heated oil above the producer as a result of

initial attempt for steam trap control The first steam breakthrough happened after 10 min

of steam injection During the run we attempted to keep 10 ordmC of steam trap over the

production well by tracking the temperature profile of the closest thermocouple However

172

controlling the steam trap by manually adjusting the production line valve was a tricky

process which contributed to production rate fluctuations

The water-cut (WCUT) in first experiment stabilized at 65-70 during the first 10

hours of the test The chamber at this time was expanding in the lateral directions and

along the wells but it had already reached to the top of the model In fact at 02 PVinj (5

hours) the steam had touched the top of the model and it had started transferring heat to

the environment through the top wall which increased the heat loss and caused more

steam condensation At 02 PVinj the WCUT displays a small increase but the major

change occurs at 10 hours when the chamber is fully developed at the top and the heat

loss increases It caused the WCUT to stabilize at a higher level of ~80

After 25 hours of steam injection first experiment was stopped and the production

well was fully opened The objective was to utilize the amount of heat that was

transferred to the model and the rock

The comparison of the cSOR for both experiments is shown in Figure 6-5 The cSOR

of the second experiment increased up to 15 cccc at about 01 PVinj and dropped

sharply down to 05 at 02 PVinj while the oil rate increases during this period The cSOR

remained then remained at ~07 cccc up to end of second experiment The explanation

for the sharp increase in oil rate is the production of collected oil above the production

well as the back pressure on the production well was reduced in controlling the sub-cool

temperature

The cSOR in the first experiment is roughly three times higher than the cSOR in the

second experiment Figure 6-7 shows a comparison of the recovery factor for both

experiments Again the second experiment shows vastly superior performance

Figure 6-4 6-5 6-6 and 6-7 show that the formation permeability is a critically

important parameter In fact the only difference between the two results is the impact of

the higher permeability which was about 250 times higher in the second run

173

0

5

10

15

20

25

0 5 10 15 20 25 30 Time hr

Oil

Rat

e c

cm

in

First Experiment Second Experiment

Figure 6-4 Oil Rate First and Second Experiment

0

1

2

3

4

5

6

7

8

0 5 10 15 20 25 30 Time hr

cSO

R c

ccc


Figure 6-5 cSOR First and Second Experiment

174

0

10

20

30

40

50

60

70

80

90

100

0 5 10 15 20 25 30 Time hr

WC

UT


Figure 6-6 WCUT First and Second Experiment

0

5

10

15

20

25

30

35

40

45

0 5 10 15 20 25 30 Time hr

RF


Figure 6-7 RF First and Second Experiment

175

The second and third experiments are compared using oil rate cSOR WCUT and

recovery factor in Figures 6-8 6-9 6-10 and 6-11 The production profile of second and

third experiments is totally different The maximum oil rate oil rate plateau cSOR

WCUT and RF of both experiments are not equal and do not even follow the same trend

These results lead to the conclusion that it is not possible to re-generate the initial

conditions by oil-flooding the post SAGD run model It is possible that due to the heating

and cooling steps in SAGD and the blow-down period in which some of the water

flashes to steam the wettability of sand may have changed and it caused a totally

different production profile The first experiment is considered as the base case for the

well configuration study

0

5

10

15

20

25

30

35

40

45

50

0 2 4 6 8 10 12 14 16 18 20 Time hr

Oil

Rat

e c

cm

in

Second Experiment Third Experiment

Figure 6-8 Oil Rate Second and Third Experiment

176

00

05

10

15

20

25

30

35

0 2 4 6 8 10 12 14 16 18 20 Time hr

cSO

R c

ccc


Figure 6-9 cSOR Second and Third Experiment

0

10

20

30

40

50

60

70

80

0 2 4 6 8 10 12 14 16 18 20 Time hr

WC

UT


Figure 6-10 WCUT Second and Third Experiment

177

0

5

10

15

20

25

30

35

40

45

0 2 4 6 8 10 12 14 16 18 20 Time hr

RF


Figure 6-11 RF Second and Third Experiment

622 Temperature Profiles

Figure 6-12 displays the temperature change with time at different locations along the

injector during the first run D15-D55 thermocouples (See Figure 4-5 for temperature

probe design) are located on top of the injector in a row starting from the heel up to toe of

the injector The chamber grows along the length of the injector but D55 the

thermocouples closet to the toe never reaches the steam temperature D45 which is 6

inches upstream of the toe initially reaches the steam temperature but subsequently cools

down At ~40 min of the injection the increased drainage of cold heavy oil from the heel

zone suppresses the passage of steam to the toe of the injector As a result a sharp

decrease in temperature at D55 is observed which resulted in a drop in the oil

production rate During the entire run the shape of chamber remains inclined towards the

toe of the injector

178

0

20

40

60

80

100

120

0 1 2 3 4 5 Time hr

Tem

pera

ture

C

D15 D25 D35 D45 D55

0

20

40

60

80

100

120

0 4 8 12 16 20 Time hr

Tem

pera

ture

C

D15 D25 D35 D45 D55

Figure 6-12 Temperature profile along the injector at 5 and 20 hours First Experiment

179

The shape of steam chamber within the model using the recorded temperatures in the

first experiment was determined at 01 02 05 06 and 078 PVinj The model was

examined in 5 vertical cross-sections perpendicular the wellbore and in 7 horizontal

layers parallel to the wellbore(A B D D E F and G where G and A layers are located

at the top and bottom of model respectively) The 7th layer (Layer A) is located

somewhere below the production well it does not contribute any interesting result and

therefore is not shown in the plots Figure 6-13 presents the schematic of the 7 layers and

5 cross sections of the physical model

Layer A Layer B

Layer C

Layer D

Layer E Layer F Layer G

Cross Section 1 Cross Section 2


Cross Section 5

Figure 6-13 Layers and Cross sections schematic of the physical model

The cartoons in Figures 6-14 15 16 17 and 18 represent the chamber extension

across the top six layers Figure 6-19 represents the vertical cross-section which is located

at the inlet of the injector (cross section 1) at 078 PVinj

As the injection starts the injector attempts to deliver high quality steam into the

entire length of the wellbore According to Figure 6-14 the injector fails to provide live

steam at the toe At 2 hours of steam injection which is 01 PVinj the chamber tends to

rise vertically and grow laterally and along the well pairs At 02 PVinj the chamber

above the injector heel has reached the top of the model but it is non-uniform along the

length of well pair After 16 hours of steam injection the chamber is in slanted shape and

the injectors tip has still not warmed up to steam temperature When the steam injection

is about to be stopped (078 PVinj) the chamber growth is continuing in all directions but

it keeps its slanted shape and the injector fails in delivering the steam to the toe Thus the

classic well pattern was not able to provide high quality steam uniformly along the wellshy

180

pair length and consequently created a slanted chamber along the length of the wells with

maximum growth near the heel of the injector Large amount of oil was left behind and

the SAGD process ran at high cSOR Continuing steam injection up to 078 PV did not

make the chamber grow more along the wells

This configuration has been practiced in the industry since SAGD was introduced

however it resulted in high cSOR and a slanted steam chamber with very little reservoir

heating near the toe The question then is whether this problem can be mitigated by using

a modified well configuration

Injector

Producer

Figure 6-14 Chamber Expansion along the well-pair at 01 PVinj

181

Injector

Producer

Injector

Producer



182

Injector

Producer

Injector

Producer



183

Injector

Producer

Figure 6-19 Chamber Expansion Cross View at 078 PVinj Cross-Section 1

623 History Matching the Production Profile with CMGSTARS

The performance of the first experiment was history matched using the CMGshy

STARS It was attempted to honor the production profile just by changing few reasonable

parameters The thermal conductivity and heat capacity of the model frame (made of

Phenolic resin) for the heat loss purpose was taken as wood thermal properties which was

465E-1 J(cmminoC) and 765 J(cm3oC) respectively These thermal properties

control the heat loss from overburden and under-burden The permeability and porosity

of the model were 240 D and 034 respectively The viscosity profile was the same as the

one presented on Figure 6-2 The relative permeability to oil gas and water which lead

to final history match are provided in Figure 6-20 The end points to water gas and oil

were assumed to be 1 The results of match to oil water and steam injection profile are

presented in Figure 6-21 22 and 23 respectively It should be noted that the initial

constraint on the producer was the oil rate while the second constraint was steam trap

The Injector constraint was set as injection temperature with the associated saturation

pressure

184

It is evident that the numerical model match of the experimental data is reasonable

However another result that needs to be looked into is the chamber volume As discussed

earlier the chamber volume was calculated using thermocouple readings The results were

compared against the chamber volume reported by STARS in Figure 6-24 The match is

reasonable during most the experiment except the last point of water production profile at

078 PVinj At 22 hours when the oil rate has a sharp increase the numerical model is

not able to honor the production profile which leads to a mismatch in chamber volume as

well

Figure 6-20 Water OilGas Relative Permeability First Experiment History Match

185

140 6000

120

100

80

60

40

20

00

Experimental Result-Oil Rate History Match-Oil Rate Experimental Result-Cum Oil History Match-Cum Oil

5000

4000

3000

2000

1000

0

Wat

er R

ate

SC (c

m3

min

)O

il R

ate

SC (c

m3

min

)

Cum

ulat

ive

Wat

er S

C (c

m3)

C

umul

ativ

e O

il SC

(cm

3)

0 4 8 12 16 20 24 28 Time (hr)

Figure 6-21 Match to Oil Production Profile First Experiment

28 14000

24

20

16

12

8

4

0

Experimental Result-Water Rate History Match-Water Rate Experimental Result-Cum Water History Match-Cum Water

12000

10000

8000

6000

4000

2000

0 0 4 8 12 16 20 24 28

Time (hr)

Figure 6-22 Match to Water Production Profile First Experiment

186

Wat

er R

ate

SC (c

m3

min

)

Cum

ulat

ive

Wat

er S

C (c

m3)

0

5

10

15

20

25

30

0

3000

6000

9000

12000

15000

18000

Experimental Result-Steam (CWE) Rate History Match-Steam (CWE) Rate Experimental Result-Cum Steam (CWE) History Match-Cum Steam (CWE)

0 4 8 12 16 20 24 28 Time (hr)

Figure 6-23 Match to Steam (CWE) Injection Profile First Experiment

Stea

m C

ham

ber V

olum

e SC

TR (c

m3)

0 4 8 12 16 20 24 28 0

500

1000

1500

2000

2500

3000

3500

4000 Experimental Result History Match

Time (hr)

Figure 6-24 Match to Steam Chamber Volume First Experiment

187

63 Fourth Experiment 631 Production Results

The classic SAGD pattern in previous experiments was not able to provide high

quality steam at the toe of the injector and create a uniform chamber Therefore the test

ended up with low RF and high cSOR Numerical simulations of Cold-Lake reservoir in

chapter 5 showed that using the Reversed Horizontal Injector may improve the SAGD

process performance As a result the fourth experiment was designed to test the Reversed

Horizontal Injector pattern using the same sand and bitumen as in the first experiment

The vertical distance between the horizontal well-pair was set at 10 cm This vertical

distance was chosen to improve the manual steam trap control by choking the production

with a valve The model was packed using AGSCO 12-20 mesh sand and a total of ~120

kg sand was carefully packed into the model which was gently vibrated during the

packing process The permeability of the packed model was ~260 D The model was then

evacuated and water was imbibed into the model using both pressure difference and

gravity head The water was then displaced by injecting the Elk-Point heavy oil

Approximately 180 kg of heavy oil was consumed which lead to initial oil saturation of

~90

Using the new well pattern the model was depleted in 17 hours with low cSOR The

results of fourth experiments are compared against the first experiment and presented on

Figure 6-25 26 27 and 28

The oil rate fluctuated during the first 3 hours (01 PVinj) of production but then it

started to steadily increase and peaked at 15 ccmin The oil rate then fell to a high

plateau at 11 ccmin which lasted for almost 5 hours Subsequently the oil rate dropped

down to 6 ccmin at 11 hours (03 PVinj) which is nearing the wind down stage The

fluctuation of oil rate before 01 PVinj is mostly due to the upward chamber growth

which creates counter current steam vapor and condensate-heated oil flow After 02

PVinj the chamber is almost stable and it has reached the top and is growing sideways

This results in increasing and stable oil rate As shown in Figure 6-25 changing the well

configuration increases the oil rate almost 3 times higher than the base case (first

experiment) oil rate In addition the fourth experiment depletes the reservoir at higher

cumulative oil volumes much faster (18 hours comparing to 27 hours) than the first

188

experiment It should be kept in mind that this improvement is due to the well

configuration only the permeability and oil viscosity were kept constant in both

experiments

The first steam breakthrough happened after 20 min of steam injection During the

run time we tried to keep 10 ordmC of steam trap over the production well by tracking the

temperature profile of the closest thermocouple The steam trap control was a difficult

task during the chamberrsquos upward growth however once the chamber reach to the top of

the model it was really smooth and easy

The cSOR in the fourth experiment stabilized at ~1 cccc after a sharp rise at early

time of production Comparing the cSOR profile of the first and fourth experiments it

can be concluded that not only the oil rate is 3 times higher in fourth experiment but also

the cSOR is nearly 3 times lower which makes the Reversed Horizontal Injector pattern

doubly successful and a very promising option for future SAGD projects

In the fourth experiment only half of the total produced liquid was water The WCUT

of fourth experiment remained at 40-60 during the entire test period

Figure 6-28 compares the RF of the first and fourth experiments Fourth experiment

was able to produce slightly higher than 50 of OOIP in 17 hours which demonstrate

that the Reversed Horizontal Injector is able to deplete the reservoir much faster than the

classic SAGD pattern and its final RF at the same time is much higher


The temperature profile along the injector well is presented in Figure 6-29 Five

thermocouple points of D31-D35 which are located on the injector were chosen to

validate the steam injection homogeneity along the injector It can be seen that steam has

been successfully delivered throughout the entire length of injector after 6 hours all

thermocouples show temperatures at or above 100 oC At 05 hrs a sharp temperature

decrease occurred at the toe of the injector which resulted from the steam trap control

procedure and imposing some extra back pressure on the production well Figure 6-29

brings out a clear message Reverse Horizontal Injector successfully delivers live steam

throughout the entire length of injector

189

0

2

4

6

8

10

12

14

16

0 5 10 15 20 25 30 Time hr

Oil

Rat

e c

cm

in

First Experiment Fourth Experiment

Figure 6-25 Oil Rate First and Fourth Experiment

0

1

2

3

4

5

6

7

8

0 5 10 15 20 25 30 Time hr

cSO

R c

ccc


Figure 6-26 cSOR First and Fourth Experiment

190

0

10

20

30

40

50

60

70

80

90

100

0 5 10 15 20 25 30 Time hr

WC

UT


Figure 6-27 WCUT First and Fourth Experiment

0

10

20

30

40

50

60

0 5 10 15 20 25 30 Time hr

RF


Figure 6-28 RF First and Fourth Experiment

191

0

20

40

60

80

100

120

0 1 2 3 Time hr

Tem

pera

ture

C

D31 D33 D35 D37 D39

0

20

40

60

80

100

120

0 2 4 6 8 10 12 14 16 Time hr

Tem

pera

ture

C

D31 D33 D35 D37 D39

Figure 6-29 Temperature profile along the injector at 3 and 16 hours Fourth Experiment

192

In order to analyse the 3-D growth of the chamber along and across the well-pair the

chamber expansions along the well-pair were determined at 01 02 03 04 and 05

PVinj in different layers As before the model was partitioned into 5 vertical cross-

sections along the wellbore and 7 horizontal layers (A B D D E F and G where G and

A layers are located at the top and bottom of model respectively) Figures 6-30 31 32

33 and 34 present the chamber extension across each layer Figure 6-35 presents the

vertical cross-section which is located at the inlet of the injector at 05 PVinj

Injector Producer


193

Injector Producer


Injector Producer


194

Injector Producer


Injector Producer


195

According to Figures 6-30-34 the Reversed Horizontal Injector is able to introduce

steam along the entire well length Even at early steam injection period (01 PVinj) the

entire injector length is warmed up close to the injection temperature At this point the

steam chamber just needs to grow laterally and vertically After 02 PVinj the steam

chamber almost approached the side walls leading to the maximum oil rate and

minimum WCUT Sometimes after 03 PVinj when the chamber hits the side walls the

oil rate started to decrease which leads to higher WCUT As per Figures 6-31 and 6-32

the chamber grows somewhat faster at the heel of producer where the steam broke

through initially but it was controlled by steam trap later on

In chapter 5 it was mentioned that the new pattern is able to create homogenous steam

chamber along the well pairs The plotted temperature contours using the recorded

temperatures confirm that a uniform chamber was created on top of the well pairs This

fact also confirms that a uniform pressure drop existed between the injector and producer

throughout the experiment period which improves the SAGD process efficiency and

leads to higher RF and lower cSOR as shown earlier

Injector

Producer

Figure 6-35 Chamber Expansion Cross View at 05 PVinj Cross Section 1

196


The performance of the fourth experiment was history matched using the CMGshy

STARS As in the first experiment few parameters were changed to get the best match of

the experimental results The thermal conductivity and volume capacity of the model

frame (made of Phenolic resin) was the same as in the first experiment The permeability

and porosity of the model were 260 mD and 031 respectively The viscosity profile is the

same as the one presented on Figure 6-2 The relative permeability to oil gas and water

which lead to final history match are provided on Figure 6-36 The end point to water

gas and oil were 075 035 and 1 respectively The results of match to oil water and

steam injection profile are presented on Figure 6-37 38 and 39 It has to be noted that

the initial constraint on producer was the oil rate while the second constraint was steam

trap The Injector constraint was set as injection temperature with the associated

saturation pressure

It seems that the numerical model matches the experimental data reasonably well

The last result that needs to be looked into is the chamber volume As discussed earlier

the chamber volume was calculated using thermocouple readings The results were


reasonable during the entire experiment except for the last point which is 05 PVinj The

difference can be due to possible error in simulation of the heat loss from the side walls

of the model which becomes a larger factor near the end

197

Figure 6-36 Water OilGas Relative Permeability Fourth Experiment History Match

198

Oil

Rat

e SC

(cm

3m

in)

Cum

ulat

ive

Oil

SC (c

m3)

0

4

8

12

16

20

0

2000

4000

6000

8000

10000 Experimental Result-Oil RateHistory Match-Oil Rate Experimental Result-Cum OilHistory Match-Cum Oil

0 4 8 12 16 20

Time (hr)

Figure 6-37 Match to Oil Production Profile Fourth Experiment

Wat

er R

ate

SC (c

m3

min

)

Cum

ulat

ive

Wat

er S

C (c

m3)

0

3

6

9

12

15

0

2000

4000

6000

8000

10000 Experimental Result-Water Rate History Match-Water RateExperimental Result-Cum Water History Match-Cum Water

0 4 8 12 16 20

Time (hr)

Figure 6-38 Match to Water Production Profile Fourth Experiment

199

Wat

er R

ate

SC (c

m3

min

)

Cum

ulat

ive

Wat

er S

C (c

m3)

0

3

6

9

12

15

18

0

2000

4000

6000

8000

10000

12000 Experimental Result-Steam (CWE) Rate History Match-Steam (CWE) Rate Experimental Result-Cum Steam (CWE)History Match-Cum Steam (CWE)

0 4 8 12 16 20

Time (hr)

Figure 6-39 Match to Steam (CWE) Injection Profile Fourth Experiment

Stea

m C

ham

ber V

olum

e SC

TR (c

m3)

0

1000

2000

3000

4000

5000

6000

7000


0 4 8 12 16 20

Time (hr)

Figure 6-40 Match to Steam Chamber Volume Fourth Experiment

200

64 Fifth Experiment 641 Production Results

Part of current study was aimed at optimizing the well configuration for Athabasca

reservoir Numerical simulations were conducted and promising well configurations were

identified It was considered desirable to test some of those configurations in the 3-D

physical model

To start with a simple 11 pattern was needed to establish an experimental base case

for the Athabasca study Hence the fifth experiment was conducted to build the base case

for further comparisons The pattern includes only 2 horizontal wells one located near

the bottom of the physical model and the second well which operates as an injector was

located 10 cm above the producer The larger inter-well distance of 10 cm was used to

overcome difficulties encountered in the manual steam trap control by manipulating the

production line valve

The model was packed and saturated using the procedure described earlier A total of

~120 kg sand was packed into the model and the permeability of the porous packed

model was ~260 D The bitumen used for saturating the model was provided by JACOS

from Athabasca reservoir In order to fully saturate the model ~216 kg of bitumen was

consumed which gave the initial oil saturation of ~87 The saturation step took 20 days

to be completed The fifth experiment was completed by injection of steam into the

model via injector for 20 hrs The oil rate cSOR WCUT and RF are presented in

Figures 6-41 42 43 and 44

The first steam break-through occurred approximately after one hour of steam

injection Controlling the steam break-through was really difficult throughout the entire

experiment once the back pressure on the production valve was reduced in order to let

more oil come out the steam jumped into the production well As a result the back

pressure had to be increased which caused the liquid level to raise in vicinity of the

production well The steam trap control never became fully stable throughout the

experiment and was one of the biggest challenges during the test Most of the fluctuations

in oil production rate were due to steam trap control process

The cSOR in this experiment had a sharp rise similar to the previous SAGD tests

and thereafter it stabilized at ~2 cccc The sharp rise is due to vertical chamber growth

201

At 05 PVinj (~15 hours) when the entire injector starts getting live steam the cSOR

drops sharply which explains the sharp increase in oil rate and high slope WCUT

reduction At 055 PVinj (163 hours) the steam broke through and to control the live

steam production higher back pressure was imposed on the producer which caused a

sharp decrease in oil rate and a pulse in cSOR and WCUT profile However after a while

it was stabilized and the oil rate went back on the track again and the cSOR became

stable

Water production in the fifth experiment was similar to the first test According to

Figure 6-43 almost 60 of the total produced liquid was water which is the expected

behavior in SAGD The RF profile is presented in Figure 6-44 Almost 50 of the

bitumen was produced after 20 hours

642 Temperature Profile

Figure 6-45 displays the temperature profile along the injector D15-D55

thermocouples (Figure 4-5) are located in a row starting from the heel up to toe of

injector At about 20 min of production the chamber was collapsing down and the

temperature was decreasing due to low injectivity the steam was not able to penetrate

into the bitumen saturated model Consequently a sharp drop in the temperature profile

was created which resulted in reduced oil production rate as well The back pressure was

removed completely to facilitate steam flow and this allowed the steam to move again

However the chamber along the producer and injector was unstable for the first 3 hours

of production The Chamber formed at the heel (about 25 of the injector length) in one

hour and the temperature near the heel was stable to the end of this test but the rest of the

wellbore had difficulties in delivering steam into the model After 10 hours the middle of

the injector reached the steam temperatures while the rest of the wellbore (the 25th of

injector length covering D45 and D55) got warmed up to steam temperature only after 16

hours had passed from the beginning the test It can be seen that these temperature and

chamber volume fluctuations result in oil production scatter

202

0

2

4

6

8

10

12

14

16

18

20

0 4 8 12 16 20 Time hr

Oil

Rat

e c

cm

in

Fifth Experiment

Figure 6-41 Oil Rate Fifth Experiment

00

05

10

15

20

25

30

0 4 8 12 16 20 Time hr

cSO

R c

ccc

Fifth Experiment

Figure 6-42 cSOR Fifth Experiment

203

0

10

20

30

40

50

60

70

80

90

0 4 8 12 16 20 Time hr

WC

UT

Fifth Experiment

Figure 6-43 WCUT Fifth Experiment

0

10

20

30

40

50

60

0 4 8 12 16 20 Time hr

RF

Fifth Experiment

Figure 6-44 RF Fifth Experiment

204

0

20

40

60

80

100

120

0 1 2 3 4 5 Time hr

Tem

pera

ture

C

D15 D25 D35 D45 D55

0

20

40

60

80

100

120

0 4 8 12 16 20 Time hr

Tem

pera

ture

C

D15 D25 D35 D45 D55

Figure 6-45 Temperature profile along the injector at 5 and 20 hours Fifth Experiment

205


chamber expanse along the well-pair were determined at 01 02 03 04 05 and 065

PVinj for different layers As in the previous experiments the model was partitioned into

5 vertical cross-sections along the well-pairs and 7 horizontal layers (A B D D E F

and G where G and A layers are located at the top and bottom of model respectively)

Figures 6-46 47 48 49 50 and 51 present the chamber extension across each layer

(only 6 layers are shown) Figure 6-51 represents the cross-section which is located at the

heel of the injector at 05 PVinj

Injector

Producer


206

Injector

Producer

Injector

Producer



207

Injector

Producer

Injector

Producer



208

Injector

Producer


Injector

Producer

Figure 6-52 Chamber Expansion Cross View at 065 PVinj Cross Section1

209

Figures 6-46 to 6-51 show that a major shortcoming of the classic pattern is uneven

injection of steam along the injector length which results in a slanted steam chamber

The injector is not able to supply live steam at the toe most of the steam gets injected

near the heel which causes an issue in steam trap control and lower productivity because

the zone near the toe does not get heated At the end of the physical model experiment

the process produced a slanted chamber which gave a reasonable RF but at higher cSOR

643 Residual Oil Saturation

The model was partitioned into three layers each had a thickness of approximately 8

cm and each layer comprised 9 sample locations Figure 6-53 presents the schematic of

the sample locations on each layer

1 2 3

4 5 6

7 8 9

50 cm

8 cm 50 cm

Figure 6-53 Sampling distributions per each layer of model

The sand samples taken from these locations were analyzed in the Dean Stark

apparatus The volumetric balance on the taken samples extracted oil and water and the

cleaned dried sand was used to calculate the residual oil and water saturations Using the

porosity initial oil saturation and residual oil saturation the φΔSo parameter can be

calculated In section 444 a range of 02-03 was assumed for the model while in a real

reservoir this number would typically be 015-02 Figure 6-54 presents the φΔSo of the

middle layer where the injector is located and the chamber has grown throughout the

entire layer

The injector is located at X=255 cm and enters into the model at Y=0 cm At X=255

cm the maximum value of φΔSo is 233 which is located at the heel of the injector where

most of steam was injected and resulted in the minimum residual oil saturation Along the

length of the injector the residual oil saturation increases which cause a decreasing trend

in φΔSo value

210

85 255

425

425

255

85

222 233

220

239

223

267

217

200

251

10

12

14

16

18

20

22

24

26

28

φΔS

o

X cm

Y cm

Mid Layer

Figure 6-54 φΔSo across the middle layer fifth experiment

The average φΔSo of the middle layer stays in the range of 02-03 which was

assumed in the dimensional analysis section The variations in the values of φΔSo are

partly due to the process performance and partly due to the experimental errors There

can be some unevenness in the porosity due to the packing inhomogeneity and the

calculation of residual saturation by extraction has some associated error There are two

higher values of residual oil saturations on the two corners close to the heel of injector

which may be interpreted as the error associated with the measurement technique The

same plot was generated for the top layer in Figure 6-55 In figure 6-55 the residual oil

saturation keeps the expected trend parallel to the injector at 85 and 255 cm on X-axis

however the trend fails on 425 cm location on X-axis Again in one corner close to the

injectorrsquos heel the residual oil saturation is unexpectedly high The average residual

saturation of the top layer still falls in the expected range listed the dimensional analysis

section

211

85 255

425

425

255

85

220 224

210 211 212

228

197 200

244

10

12

14

16

18

20

22

24

26

φΔS

o

X cm

Y cm

Top Layer

Figure 6-55 φΔSo across the top layer fifth experiment


In order to analyze and study the performance of the fifth experiment under numerical

simulation its production profile was history matched using the CMG-STARS Only the


changed to get the best match of the experimental results The thermal conductivity and

heat capacity of the model frame (made of Phenolic resin) was the same as in the

previous experiment The permeability and porosity of the model were 260 mD and 034

respectively The viscosity profile was the same as the one presented on Figure 6-3 which

is the measured and modeled viscosity profile for Athabasca bitumen The relative

permeability to oil gas and water which gave the final history match is provided in

Figure 6-56 The end points to water gas and oil were assumed to be 03 014 and 1

respectively The results of the match to oil water and steam production profile are

presented in Figure 6-57 58 and 59 It should be noted that the initial constraint on

producer was the oil rate while the second constraint was steam trap The Injector

constraint was set as injection temperature with the associated saturation pressure

212

It seems that the numerical model matches the experimental data quite well However

one last result that needs to be looked into is the chamber volume As discussed earlier


compared against the chamber volume reported by STARS in Figure 6-60 This match is

a bit off during the entire experiment Since there were too many issues in steam trap

control and the chamber was expanding erratically during the experiment it was not

surprising that the chamber volume history was not well-matched

Figure 6-56 Water OilGas Relative Permeability Fifth Experiment History Match

213

Oil

Rat

e SC

(cm

3m

in)

Cum

ulat

ive

Oil

SC (c

m3)

00

50

100

150

200

0

2000

4000

6000

8000

10000 Experimental Result Oil RateHistory Match Oil Rate Experimental Result Cum OilHistory Match Cum Oil

0 200 400 600 800 1000 1200 Time (min)

Figure 6-57 Match to Oil Production Profile Fifth Experiment

Wat

er R

ate

SC (c

m3

min

)

Cum

ulat

ive

Wat

er S

C (c

m3)

0

6

12

18

24

30

0

3000

6000

9000

12000

15000 Experimental Result Water Rate History Match Water Rate Experimental Result Cum WaterHistory Match Cum Water

0 200 400 600 800 1000 1200 Time (min)

Figure 6-58 Match to Water Production Profile Fifth Experiment

214

Wat

er R

ate

SC (c

m3

min

)

Cum

ulat

ive

Wat

er S

C (c

m3)

0

7

14

21

28

35

42

0

3000

6000

9000

12000

15000

18000 Experimental Result Steam (CWE) RateHistory Match Steam (CWE) Rate Experimental Result Cum Steam (CWE)History Match Cum Steam (CWE)

0 200 400 600 800 1000 1200 Time (min)

Figure 6-59 Match to Steam (CWE) Injection Profile Fifth Experiment

Stea

m C

ham

ber V

olum

e SC

TR (c

m3)

0

2000

4000

6000

8000 History MatchExperimental Result

0 200 400 600 800 1000 1200 Time (min)

Figure 6-60 Match to Steam Chamber Volume Fifth Experiment

215

65 Sixth Experiment 651 Production Results

The classic SAGD pattern in fifth experiment showed the expected performance of a

11 ratio SAGD well pattern Although it provides commercially viable performance in

the field some of the issues with it are low oil rate not very high RF high WCUT high

cSOR In the physical model experiments it gives very long run time due to slow

drainage rate In addition to these difficulties if the temperature contour maps were

studied carefully the steam chamber is not homogenous and it is slanted along the well

pairs

Several numerical simulations that were run on Athabasca reservoir and were

presented in Chapter 5 showed the Reversed Horizontal Injector pattern to be superior to

the classic pattern It was shown that the new pattern is able to improve the performance

of the SAGD process The new well configuration was tested in Cold Lake type of

reservoir in the fourth experiment and it showed large improvement that was

considerably more pronounced than the numerical simulation result Therefore it would

be desirable to test the new well configuration under the Athabasca type of reservoir

conditions as well Hence the sixth experiment was designed to test the Reversed

Horizontal Injector pattern under Athabasca conditions

As in the preceding base case experiment 10 cm vertical inter-well distance was

used The same AGSCO 12-20 mesh sand used to create the porous medium in the

model The permeability and porosity of the porous packed model were ~260 D and 031

respectively In order to fully saturate the model ~180 kg of JACOS bitumen was

consumed which lead to initial oil saturation of ~90 Using the new well pattern the

model was depleted in 13 hours with relatively low cSOR The results of this experiment

is compared against the fifth experiment and presented in Figures 6-61 62 63 and 64

216

0

5

10

15

20

25

0 4 8 12 16 20

Time hr

Oil

Rat

e c

cm

in

Fifth Experiment Sixth Experiment

Figure 6-61 Oil Rate Fifth and Sixth Experiment

00

05

10

15

20

25

30

35

0 4 8 12 16 20 Time hr

cSO

R c

ccc


Figure 6-62 cSOR Fifth and Sixth Experiment

217

0

10

20

30

40

50

60

70

80

90

0 4 8 12 16 20 Time hr

WC

UT


Figure 6-63 WCUT Fifth and Sixth Experiment

0

10

20

30

40

50

60

0 4 8 12 16 20 Time hr

RF


Figure 6-64 RF Fifth and Sixth Experiment

218

The oil production profile of the sixth experiment is compared against the fifth

experiment in Figure 6-61 The oil rate profile has some fluctuations throughout the

experiment Before 01 PVinj (~3 hours) the steam chamber is growing upward and

laterally which makes the chamber to be somewhat unstable due to the counter current

flow Consequently the liquid production shows fluctuations which can be observed in

Figure 6-61 The oil rate fluctuates between 5 and 10 ccmin The steam chamber reaches

to top of the model somewhere between 01 and 02 PVinj (~45 hours) which leads to a

sharp increase in the oil rate Then the average oil rate somewhat stabilized at 15 ccmin

with a maximum and minimum of 20 and 10 ccmin respectively At 04 PVinj where the

chamber hits the adjacent sides the oil rate gets another jump but since the chamber

cannot spread anymore and extra heat loss occurs from the sidewalls the oil rate drops

down at 05 PVinj (11 hours) A part of the oil rate fluctuation originated from the

manual control of the steam trap using the valve adjustments The Reverse Horizontal

Injector displays a dramatic improvement where the oil rate of this experiment is nearly

twice that of the fifth experiment (which used the classic pattern)


run we tried to keep 10 ordmC of steam trap over the production well by tracking the

temperature profile of the closest thermocouple Since the pressure drop along the well-

pair was almost uniform the steam trap control was relatively simple In this experiment

the cSOR increased sharply during the rising chamber phase of the process It then

decreases smoothly to ~15 cccc A comparison of the cSOR profiles of the fifth and the

sixth experiments is provided in Figure 6-62 The sixth experiment displays lower cSOR

almost half of the fifth experiment The WCUT in sixth experiment is 50-60 and is

compared against the fifth experiment in Figure 6-63 It can be seen that the well

configuration in sixth experiment yields less heat loss which caused the WCUT to be

lower compared to the fifth experiment Figure 6-64 demonstrates the RF of these two

experiments According to Figure 6-64 the Reversed Horizontal Injector can provide

higher RF in shorter period compared to the classic well pattern In the sixth experiment

after 13 hours 55 of the OOIP had been produced while at the same time only 25 of

OOIP had been produced by the classic pattern in the fifth experiment The combination

of oil rate cSOR WCUT and RF profile makes the Reversed Horizontal Injector a very

219

promising replacement for the classic pattern in SAGD process in Athabasca type of

reservoir


Figure 6-65 displays the temperature profiles at the injector for the first 4 and first 14

hours of steam injection D31-D39 thermocouples (Figure 4-5) are located in a row

starting from the heel up to toe of the injector The first four points get to steam

temperature in less than one hour The last point which is located at the toe of the injector

warmed up to steam temperature after 2 hours This made the steam trap control very

easy since the steam broke through to the production well at the producerrsquos toe instead of

its heel

The chamber growth in the model was studied by determining the chamber

expansions in different layers at 01 02 03 04 05 and 06 PVinj Out of the 7 layers

(A B D D E F and G where G and A layers are located at the top and bottom of model

respectively) only 6 layers are included in the plots since the 7th layer (Layer A) is

located somewhere below the production well and does not show any interesting result

Figures 6-66 67 68 69 70 and 71 represent the chamber extension across each layer

Figure 6-72 represent the cross-section which is located at the inlet of the injector at 06

PVinj

At 01 PVinj the chamber has just formed around the injector in the E layer which is

located above the injector At 02 PVinj the chamber hit the top of the model and it

started growing only laterally At 03 PVinj it approached the vicinity of the side walls

but it is at 04 PVinj when the steam chamber reaches the side walls From 04 PVinj till

06 PVinj the steam chamber grows downward on the side walls which is reflected in

the chamber development on C and B layers

According to Figures 6-66 to 6-71 the Reversed Horizontal Injector pattern delivers

high quality steam throughout the injector soon after the steam injection starts It

successfully develops a uniform chamber laterally while it continuously supplies the live

steam at the toe of the injector This results in low cSOR and WCUT while the oil rate

and RF are dramatically higher

220

0

20

40

60

80

100

120

0 1 2 3 4 Time hr

Tem

pera

ture

C

D31 D33 D35 D37 D39

0

20

40

60

80

100

120

0 2 4 6 8 10 12 14 Time hr

Tem

pera

ture

C

D31 D33 D35 D37 D39

Figure 6-65 Temperature profile along the injector at 4 and 14 hours Sixth Experiment

221

Injector Producer


Injector Producer


222

Injector Producer


Injector Producer


223

Injector Producer


Injector Producer


224

Injector

Producer

Figure 6-72 Chamber Expansion Cross View at 05 PVinj


As in the fifth experiment the model was partitioned into three layers each has a

thickness of approximately 8 cm and each layer comprised 9 sample locations Figure 6shy

52 presents the schematic of the sample locations on each layer The same methodology

presented in section 643 was followed to calculate φΔSo over each layer of the model

Figure 6-73 presents the φΔSo of the middle layer where the injector is located and

the chamber has grown throughout the entire layer

The injector is located at Y=255 cm and enters into the model at X=50 cm The

average φΔSo over the middle layer is in the range of 12-14 The run time of sixth

experiment was short and compared to the rest of tests and it lead to higher residual oil

saturation over the middle layer At Y=255 cm which is along the length of the injector

the residual oil saturation has a fairly constant values showing a flat trend in φΔSo value

The maximum oil saturation is located on top of the injectorrsquos heel which is right above

the producerrsquos toe in the reversed horizontal injector pattern There are two high values of

residual oil saturations on the two corners close to the toe of injector which may be due to

less depletion near the two corners The same plot was generated for the top layer in

225

Figure 6-74 The distribution of the residual oil saturation over the top layer is more

uniform than the middle layer which means steam was able to sweep out more oil and the

chamber was spread uniformly throughout the entire layer The average residual

saturation of the top layer still falls in the expected range of the dimensional analysis

section

Mid Layer

14

13

12

11

85

255 10

425

136

132

129

126 127

121

131

123

122

Y cm 425 85

255

X cm

φΔS

o

Figure 6-73 φΔSo across the middle layer sixth experiment

226

85 255

425

425

255

85

229 223

253

235

225 237 235

225 222

10

12

14

16

18

20

22

24

26

φΔS

o

X cm

Y cm

Top Layer

Figure 6-74 φΔSo across the top layer sixth experiment


The results of sixth experiment were history matched using CMG-STARS It was

tried to keep the consistency between the sixth and previous numerical models

Therefore the thermal conductivity and heat capacity of the model frame (made of

Phenolic resin) were kept the same as in first fourth and fifth experiments The

permeability and porosity of the model were 260 mD and 031 respectively The viscosity

profile was the same as the one presented on Figure 6-3 The relative permeability to oil

gas and water which lead to final history match are shown in Figure 6-75 The end point

to water gas and oil were assumed to be 017 008 and 1 respectively The results of

match to oil water and steam production profile are presented on Figure 6-76 to 6-78 As

in the previous simulations the initial constraint on producer was the oil rate while the

second constraint was steam trap The Injector constraint was set as injection temperature

with the associated saturation pressure In this case also the numerical model matched

the experimental data reasonably well The match of the chamber volume whose

227

experimental values were calculated using thermocouple readings while the simulated

values were as reported by STARS is shown in Figure 6-79 The match turned out to be

nearly perfect

Figure 6-75 Water OilGas Relative Permeability Sixth Experiment History Match

228

24 12000

20

16

12

8

4

0

Experimental Result Oil RateHistory Match Oil Rate Experimental Result Cum OilHistory Match Cum Oil

10000

8000

6000

4000

2000

0

Wat

er R

ate

SC (c

m3

min

)O

il R

ate

SC (c

m3

min

)

Cum

ulat

ive

Wat

er S

C (c

m3)

C

umul

ativ

e O

il SC

(cm

3)

0 2 4 6 8 10 12 14 Time (hr)

Figure 6-76 Match to Oil Production Profile Sixth Experiment

30 12000

25

20

15

10

5

0

Experimental Result Water Rate History Match Water Rate Experimental Result Cum Water History Match Cum Water

10000

8000

6000

4000

2000

0 0 2 4 6 8 10 12 14

Time (hr)

Figure 6-77 Match to Water Production Profile Sixth Experiment

229

28 14000

Wat

er R

ate

SC (c

m3

min

)

24

20

16

12

8

4

0

Experimental Result Steam (CWE) Rate History Match Steam (CWE) RateExperimental Result Cum Steam (CWE) History Match Cum Steam (CWE) 12000

10000

8000

6000

4000

2000

0

Cum

ulat

ive

Wat

er S

C (c

m3)

0 2 4 6 8 10 12 14 Time (hr)

Figure 6-78 Match to Steam (CWE) Injection Profile Sixth Experiment

Stea

m C

ham

ber V

olum

e SC

TR (c

m3)

0

1000

2000

3000

4000

5000

6000

7000

8000 Experimental Result History match

0 2 4 6 8 10 12 14 Time (hr)

Figure 6-79 Match to Steam Chamber Volume Sixth Experiment

230

66 Seventh Experiment 661 Production Results

The simulation study presented in Chapter 5 showed that the inclined injector may

provide some advantages over the classic pattern This pattern was able to supply high

quality steam to the toes of injector and producer because it has higher pressure gradient

near the toes Note that the producer was horizontal while the injector was dipping down

with smaller vertical inter well distance at the toe of injector and producer than the

vertical distance between the well pairs at the heel The chamber was developed initially

near the toe and grew backward towards the injectorrsquos heel This pattern demonstrated

some improvement in SAGD process which was persuasive enough to warrant its testing

in the physical model The inclined injector pattern was tested in Athabasca type of

reservoir in the seventh experiment The performance of the inclined injector well was

compared against the results of the fifth and the sixth experiments both of which also

represented Athabasca reservoir

The schematic of the inclined injector pattern is displayed in figure 6-80 The vertical

inter well distance at the heel and toe of injector were 18 and 5 cm respectively

Injector

18 cm

5 cm Producer

Figure 6-80 Schematic representation of inclined injector pattern

The model was packed using the same AGSCO 12-20 mesh sand which was used in

the previous experiments The initial porosity of the porous packed model was 033 The

model was initially evacuated and thereafter was saturated with water Unfortunately

although a pressure leak test was conducted before water imbibition the water penetrated

into the edges of the model and started leaking The model was drained out of water

However fixing this leak took 6 months while the model was still full of sand The water

saturation was repeated four times after the model leak was fixed and gave consistent

results Eventually the water was displaced out of porous media using injection of

JACOS bitumen from Athabasca reservoir Approximately 198 kg of bitumen was

231

consumed which lead to initial oil saturation of ~96 This number was higher than

previous tests The saturation step took 7 days to be completed

The performance of the inclined injector is compared against the classic pattern and

reversed horizontal injector in Figures 6-81 82 83 and 84

Similar to the previous experiments the oil rate profile has some fluctuations

throughout the experiment it goes as high as 35 ccmin and as low as 7 ccmin with the

average of 20-25 ccmin After 8 hours (04 PVinj) the oil rate dropped down to 15

ccmin and thereafter to 10 ccmin at 05 PVinj The oil rate produced by the inclined

injector is higher than the classic pattern and surprisingly even higher than the Reversed

Horizontal Injector The improved performance can also be observed in the cSOR profile

in Figure 6-82 where its cSOR stabilizes at 10 cccc

Figure 6-83 compares the WCUT of the three well patterns The portion of oil in total

fluid in inclined injector has a small improvement with respect to the Reversed

Horizontal Injector but it shows quite impressive improvement in comparison with the

classic pattern

The final RF shown in Figure 6-84 was similar to that in the sixth experiment but in

considerably shorter period which makes its performance even better It depleted 53 of

the OOIP in 10 hours

During the seventh experiment run time it was observed that the chamber growth was

not the same as was seen in numerical modeling Based on the simulation results the

chamber was supposed to start from the injector and producer toes and grow back

towards the injector and producer heels However it grew from middle of injector and

was expanding laterally and towards the toe and heel of injector To further analyse the

performance the temperature contours in different layers of the model and the

temperature profile between the injector and producer need to be examined There was a

row of thermocouples parallel to the producer but 5 cm above it The temperatures

recorded at these points (their location is displayed in Figure 6-85) are presented in

Figure 6-86

232

cSO

R c

ccc

O

il R

ate

cc

min

35

40 Fifth Experiment Sixth Experiment Seventh Experiment

30

25

20

15

10

5

0 0

30

35

4 8 12

Time hr


16 20

Fifth Experiment Sixth Experiment Seventh Experiment

25

20

15

10

05

00 0 4 8 12

Time hr


16 20

233

RF

WC

UT

70

80

90 Fifth Experiment

Sixth Experiment Seventh Experiment

60

50

40

30

20

10

0 0 4 8

Time hr 12 16 20

50

60



40

30

20

10

0 0 4 8 12 16 20

Time hr


234


Figure 6-85 displays the location of D15-55 thermocouples with respect to injector

and producer locations D15-D55 thermocouples (Figure 4-5) are located in a row

starting from the location 5 cm above the heel of producer up to toe of the injector (which

is 5 cm above the toe of producer)

Injector

Producer 5 cm

18 cm

D15 D35 D55

D45D25

Figure 6-85 Schematic of D5 Location in inclined injector pattern

As per numerical simulation results it was expected that the chamber grows from the

injectors toe The minimum resistance against the steam flow is at the injector and

producer toes where the distance is shortest between the well pairs Hence it should lead

to chamber growth at the injectors toe which was confirmed by the simulation study

Therefore within the five thermocouples the D55 should show an early rise in its

temperature profile and while as the chamber grows backward the rest of thermocouples

on the chamber path ie D45 D35 D25 and D15 will subsequently warm up to steam

temperature Figure 6-86 shows that the order of temperature increase at D55

thermocouple is not consistent with the numerical results and the pattern concept The

green and blue lines represent D35 and D45 respectively The D35 shows the earliest

increase on temperature profile followed by the D45 which had the second highest

temperature at early time of injection period It seems that the chamber growth started

near the middle of the physical model One of the contributing reasons for this

discrepancy appears to be the high heat loss near the toe of the injector since it was very

close to the wall of the model

235

0

20

40

60

80

100

120

0 2 4 6 8 10 Time hr

Tem

pera

ture

C

D15 D25 D35 D45 D55

0

20

40

60

80

100

120

0 1 2 3 4 Time hr

Tem

pera

ture

C

D15 D25 D35 D45 D55

Figure 6-86 Temperature profile in middle of the model at 4 and 10 hours Seventh Experiment

236

In order to better understand the chamber shape and growth within the model the

temperature contours were generated in different layers at 01 02 03 04 05 and 06

PVinj Figures 6-87 88 89 90 and 91 represent the chamber extensions in six different

layers Figure 6-86 represents the vertical cross-section which is located at the inlet of the

injector at 05 PVinj The unusual chamber growth mentioned earlier occurred before 2

hours of injection ie at PVinj of less than 01 However the unusual chamber growth left

its mark on the temperature contours at 01 02 and 03 PVinj

At 01 PVinj the chamber is above the heel of the injector in the top layer (Layer-G)

but near the toe of the producer in the layer containing the producer (Layer-B) The

temperature contours representing the chamber in G F and E layers are a bit unusual and

appear to follow the inclination of the inclined injector At this early time in the run the

chamber already covers nearly the full length of the model in D layer The D layer

represents the D55 thermocouple presented in Figure 6-85 In the classic well

configuration the injector would be located in this layer

At 02 PVinj the chamber is well developed at the top of the model and it covers half

of the top layer (Layer-G) The temperature contours in Figure 6-88 shows that the

hottest spot in all layers is located on the heel side of the wells which is at mark 10 on the

y-axis scale The temperature contours in G F and E layers in Figures 6-89 and 6-90

show that the chamber growth is from the heel towards the toe In fact some unheated

spots can be noticed on the toe side in some layers while the heel side is heated up to

steam temperature in all layers It is also apparent that at this point in the run the chamber

covers a large fraction of the total volume Compared to the volume of chamber in the

classic pattern at 02 PVinj shown in Figure 6-47 the chamber is substantially larger

The production profile confirmed that the inclined injector may have significant

advantage over the classic pattern but the experimental temperature profiles leave some

unanswered question concerning why the chamber grows in the manner observed in this

experiment The expected result from the numerical simulation model was a systematic

growth starting from the toe region and progressing toward the heels of the wells The

experiment showed a more uniform development of the chamber Actually the

experiment showed better than expected performance and if this can be confirmed in a

field trial the inclined injector would become the well configuration of choice

237



238



239


Injector

Producer


240


As in the previous experiment the model was partitioned into three layers each

having a thickness of approximately 8 cm and each layer comprised 9 sampling

locations Figure 6-53 presents the schematic of the sample locations on each layer The

same methodology presented in section 643 was followed to calculate φΔSo over each

layer of the model

Figure 6-93 presents the φΔSo of the top layer where the chamber has grown

throughout the entire layer The injector is located at X=255 cm and enters into the

model at Y=0 cm The average φΔSo in the top layer is in the range of 21-26 At

Y=255 and 425 cm where the injector approaches the producer the residual oil

saturation is low However at the heel of injector Y=85 cm due to large spacing

between injector and producer higher residual oil saturation was observed According to

Figure 6-93 chamber was fairly homogenous throughout the top layer The average

residual saturation of the top layer falls in the expected range of the dimensional analysis

section

85 255

425

425

255

85

257

216 228

267

259 262 265

254 251

10

12

14

16

18

20

22

24

26

28

φΔS

o

X cm

Y cm

Top Layer

Figure 6-93 φΔSo across the top layer seventh experiment

241


The production and chamber volume profile of the seventh experiment was history

matched using CMG-STARS Since the sand type and the model was the same as in the

previous tests the thermal conductivity and heat capacity of the model frame (made of

Phenolic resin) was kept the same as in previous tests The permeability and porosity of

the model were 260 mD and 033 respectively The viscosity profile was the same as the


to final history match are presented in Figure 6-94 The end point to water gas and oil

were assumed to be 015 0005 and 1 respectively The relative permeability to the gas

was really low without which matching the steam injection and water production rate

was impossible Table 6-2 compares the end point of water gas and oil which have been

used in history matching of fifth sixth and seventh experiments According to this table

the end point to the gas relative permeability in seventh experiment is artificially low It

was attempted to match the production profile with higher gas relative permeability but it

was simply not possible Eventually it was decided to keep the end point value of the gas

relative permeability as low as 0005 and add this to the surprising behavior of the

seventh experiment Physically there is no valid reason why the gas relative permeability

should be so low

Table 6-2 Summary watergasoil relative permeability end points of 5th 6th and 7th experiments

Experiment End Point gas Rel Perm

End Point water Rel Perm

End Point Oil Rel Perm

Fifth 030 014 100 Sixth 0075 017 100 Seventh 0005 015 100

The results of history match to oil water and steam production profile are presented

in Figure 6-95 96 and 97 As in previous tests the initial constraint on the producer was

the oil rate while the second constraint was steam trap The Injector constraint was set as

injection temperature with the associated saturation pressure

It is apparent that the numerical modelrsquos match to experimental results is reasonable

but it is based on using unrealistically low gas relative permeability As discussed earlier

for previous experiments the chamber volume was calculated using the thermocouple

242

readings The results were compared against the chamber volume reported by STARS in

Figure 6-98 The match was not very good in spite of the low gas relative permeability

Table 6-2 also shows that the gas relative permeability was considerably smaller in

history match of the sixth experiment compared to the fifth experiment This too is an

artificial adjustment since the gas relative permeability would be expected to be similar

in experiments using the same rock-fluid system It is partly due to the weakness of the

simulator in modeling two-phase flow in the wellbore

Figure 6-94 Water OilGas Relative Permeability Seventh Experiment History Match

243

12000 42

35

28

21

14

7

0

Experimental Result Oil Rate History Match Oil Rate Experimental Result Cum Oil History Match Cum Oil

10000

8000

6000

4000

2000

0

Wat

er R

ate

SC (c

m3

min

)O

il R

ate

SC (c

m3

min

)

Cum

ulat

ive

Wat

er S

C (c

m3)

C

umul

ativ

e O

il SC

(cm

3)

0 2 4 6 8 10 12 Time (hr)

Figure 6-95 Match to Oil Production Profile Seventh Experiment

25

20

15

10

5

Experimental Result Water RateHistory Match Water Rate Experimental Result Cum WaterHistory Match Cum Water

00 20 40 60 80 100 120

10000

8000

6000

4000

2000

0

Time (hr)

Figure 6-96 Match to Water Production Profile Seventh Experiment

0

244

30 12000

25

20

15

10

5

0

Experimental Result Steam (CWE) Rate History Match Steam (CWE) RateExperimental Result Cum Steam (CWE) History Match Cum Steam (CWE)

10000

8000

6000

4000

2000

0

Stea

m C

ham

ber V

olum

e SC

TR (c

m3)

W

ater

Rat

e SC

(cm

3m

in)

Cum

ulat

ive

Wat

er S

C (c

m3)

0 2 4 6 8 10 12 Time (hr)

Figure 6-97 Match to Steam (CWE) Injection Profile Seventh Experiment


0 2 4 6 8 10 12

8000

6000

4000

2000

0

Time (hr)

Figure 6-96 Match to Steam Chamber Volume Seventh Experiment

245

The last two physical model tests show that both new well configurations (Reversed

Horizontal Injector and Inclined Injector) are very promising for Athabasca reservoir

Their performance in the physical model tests is vastly superior to that of the classic

pattern The field scale numerical simulation presented in Chapter 5 was not able to

capture this dramatic improvement in the performance It is difficult to say with certainty

whether the physical model results or the numerical simulation results would be closer to

the field performance of these well configurations This question can be answered

directly by a field trial of the modified well configurations Therefore it is strongly

recommended that both of these well configurations should be evaluated in field pilots

CHAPTER 7

COCLUSIONS AND RECOMMENDATIONS

247

71 Conclusions

In this research homogenous reservoir models with averaged properties typical of

Athabasca Cold Lake and Lloydminster reservoirs were constructed for each reservoir

to investigate the impact of well configuration on the ultimate recovery obtained by the

SAGD process The following conclusions are based on the results of the numerical

simulation study

bull Six well patterns were studied for Athabasca reservoir including Basic Pattern

Vertical Injectors Reversed Horizontal Injector Inclined Injector Parallel

Inclined Injector and Multi-Lateral Producer The Vertical Injectors pattern

performed poorly in Athabasca reservoir since the pattern with 3 vertical injectors

provided the same recovery factor as the base case but its steam oil ratio was

much higher The Reversed Horizontal Injector pattern and the inclined injector

provided higher recovery factor but same steam oil ratio in comparison with the

base case pattern Their results suggest that there is potential benefit for reversing

or inclining the injector These two cases were considered candidates for further

evaluations in the physical model set-up The Parallel Inclined Injectors

configuration provided higher recovery factor but the cSOR was increased The

Multi-Lateral provided a small benefit in recovery factor but not in cSOR

Therefore out of the six patterns only the Reserved Horizontal Injector and

Inclined Injector were selected for further study in Athabasca reservoir

bull In the Cold Lake reservoir eight patterns were examined Basic Pattern Offset

Horizontal Injector Vertical Injectors Reversed Horizontal Injector Parallel

Inclined Injector Parallel Reversed Upward Injector Multi-Lateral Producer

and C-SAGD Offsetting the injector provided some benefit in improving the RF

but at the expense of higher cSOR The results of vertical injectors were the same

as in Athabasca The three vertical injectors pattern was able to deplete the

reservoir as fast and as much as the base case but at higher cSOR values

Reversed Horizontal Injector somewhat improved the RF while its cSOR was the

same as base case pattern This well configuration was included in the list of

patterns to be examined in the 3-D physical model The Parallel Inclined Injector

and the Parallel Reversed Upward Injector patterns were not able to improve the

248

performance of SAGD The Multi-Lateral Producer was able to deplete the

reservoir much faster than the base case but at the expense of higher cSOR The

C-SAGD pattern with the offset of 10m was able to deplete the reservoir much

faster than the base case pattern Itrsquos cSOR was larger than the base case cSOR

(including addition of ~02-03 m3m3 to the final cSOR value of 25 m3m3 due to

SourceSink injector and producer) The pattern enhanced the RF of SAGD

process significantly As a result the Reverse Horizontal Injector and C-SAGD are

assumed the most optimal well patterns at Cold Lake The only limitation with C-

SAGD pattern is the requirement of very high injection pressure for a short period

of time which was not possible in our low pressure physical model Therefore

only the Reversed Horizontal Injector was selected for testing in the 3-D physical

model

bull At Lloydminster due to the particular reservoir and fluid properties such as low

initial viscosity and net pay itrsquos more practical to offset the injector from

producer and introduce the elements of steam flooding into the process in order to

compensate for the small thickness of the reservoir Total of six main well

configurations were tested for Lloydminster Basic Pattern Offset Producer

Vertical Injector C-SAGD ZIZAG Producer and Multi-Lateral Producer For

each pattern except the Multi-lateral pattern several horizontal inter-well spacing

values such as 6 12 18 24 30 36 and 42m were examined Among all the

patterns the 30m Offset producer 42m offset vertical injectors 42m Offset C-

SAGD and 42m Offset ZIGZAG provided the most promising performance

Among these best patterns the 42m offset vertical injectors provided the most

reasonable performance since their recovery factor was 70 but at a minimum

cSOR value of 52 In addition to the vertical injector performance the drilling

and operational benefits of vertical injectors over the horizontal injector this 3-

vertical injector is recommended for future development in Lloydminster

reservoirs

Further on to confirm the results of numerical simulations for the optimum well

configuration a 3-D physical model was designed based on the dimensional analysis

proposed by Butler Two types of bitumen were used in experiments 1) Elk-Point oil

249

which represents the Cold Lake reservoir and 2) JACOS bitumen which represents the

Athabasca reservoir Three different well configurations were tested using the two oils I)

Classic SAGD Pattern II) Reverse Horizontal Injector and III) Inclined Injector A total

of seven physical model experiments were conducted Four experiments (using

Athabasca and Cold Lake bitumen) used the classic pattern which was considered as base

case tests Two experiments used the Reverse Horizontal Injector pattern for Cold Lake

and Athabasca bitumen and the last experiment used the Inclined Injector pattern with the

Athabasca bitumen The Main conclusions from the experimental study conducted in this

research are as follows

bull Out of four basic pattern experiments two tests were conducted using two

different permeabilities of 600 and 260 mD The results were consistent and their

rate and cSOR were nearly proportional to the permeability

bull The classic SAGD well configuration was tested for both Athabasca and Cold

Lake reservoirs This pattern is not able to sweep the entire model due to non-

homogeneity of the chamber growth along the well-pair A slanted chamber was

formed above the producer and it was necessary to increase the steam injection

rate to keep the chamber growing

bull The Reversed Horizontal Injector well configuration that was identified as

promising by the numerical simulation study was examined in the 3-D physical

model and its results were compared against the classic pattern This pattern was

tested for both Athabasca and Cold Lake reservoirs The Reversed Horizontal

Injector provided significantly improved performance with respect to RF cSOR

and chamber volume The associated chamber growth was uniform in all

directions

bull The Inclined Injector pattern was examined experimentally for Athabasca type

bitumen Its results were compared with basic pattern and Reverse Horizontal

Injector and it provided very promising performance with respect to RF cSOR

and chamber volume

bull The results of each experiment were history matched using CMG-STARS All the

numerical models were able to honor the experimental results reasonably well

However different relative permeability curves were needed to history match the

250

performance of different well patterns This was attributed to problems in

accurately modeling the wellbore hydraulics in the simulator

bull The results of the Reverse Horizontal Injector and the Inclined Injector patterns

strongly suggest that these patterns should be examined through a pilot project in

AthabascaCold Lake type of reservoir

72 Recommendations

The performance of Reversed Horizontal Injector and Inclined Injector in the physical

model tests is vastly superior to that of the classic pattern The field scale numerical

simulation presented in Chapter 5 was not able to capture this dramatic improvement in

the performance It is difficult to say with certainty whether the physical model results or

the numerical simulation results would be closer to the field performance of these well

configurations This question can be answered directly by a field trial of the modified

well configurations Therefore it is strongly recommended that both of these well

configurations should be evaluated in field pilots

In this research a homogenous reservoir with averaged properties was constructed for

Athabasca Cold Lake and Lloydminster reservoirs to investigate the impact of well

configuration on the ultimate recovery obtained by SAGD process However reservoir

characterization plays an important role in all thermal recovery mechanisms Therefore it

is essential to numerically examine the robustness of the new patterns in a more realistic

geological model in order to validate the optimized well patterns in a heterogeneous

reservoir

In this study the high pressure patterns such as C-SAGD were not examined through

the experimental study Therefore the laboratory verification of the high pressure patterns

in a 3-D physical model will be beneficial

Most experimental studies including this thesis study SAGD process using single

well pair models Therefore once the chamber reaches to the sides of the model it

encounters no flow boundaries during the depletion period In the commercial SAGD

projects the chambers will eventually merge with each other and create a series of

instabilities Modeling the chamber to chamber process at the time that oil rate starts to

decline will be an interesting area of research

251

This research was more focused on the recovery performance of SAGD therefore the

process was terminated at the end of each test by stopping steam injection and producing

the mobilized heated bitumen around the producer Most of the experimental studies

ignore the last SAGD step which is Wind-Down Once a high pressure model is designed

some study can be conducted on optimizing the best approach for shutting the injector

down

Optimization of wind-down strategy at the time when one chamber merges into

another can improve SAGD performance and create more stability for a commercial

project operation

The impact of solvent injection can be evaluated for the new well configurations

However the solvent recovery needs to be optimized for each well pattern so that the

economics of the project may be optimized

An economical study including the cost of surface and subsurface facilities is required

for each recommended well pattern so that a logical decision can be made in selecting the

best pattern

252

REFERENCES 1) Butler RM ldquoThermal Recovery of Oil and Bitumenrdquo 3rd edition Gravdrain Inc

2000

2) Butler RM McNab GS AND Lo HY ldquoTheoretical Studies on the Gravity

Drainage of Heavy Oil During Steam Heatingrdquo Can J Chem Eng 59 455-460

August 1981

3) Cardwell WT Parsons RL ldquoGravity Drainage Theoryrdquo Trans AIME 146 28-

53 1942

4) Butler RM Stephens DJ ldquoThe Gravity Drainage of Steam-heated Heavy Oil to

Parallel Horizontal Wellsrdquo JCPT 90-96 April-June 1981

5) Das S ldquoImproving the Performance of SAGDrdquo SPE 97921 presented at the SPE

International Thermal Operations and Heavy Oil Symposium held in Calgary

Alberta Canada 1-3 November 2005

6) Butler RM ldquoRising of Interfering Steam Chamberrdquo JCPT 70-75 May-June

1987

7) Chung KH Butler RM ldquoGeometric Effect of Steam Injection on the Formation

of Emulsions in the Steam-Assisted Gravity Drainage Processrdquo JCPT 36-41 Jan-

Feb 1988

8) Zhou G Zhang R ldquoHorizontal Well Application in a High Viscous Oil

Reservoirrdquo SPE 30281 presented at the SPE International Thermal Operations and

Heavy Oil Symposium held in Calgary Alberta Canada 19-20 June 1995

9) Nasr T N Golbeck H Lorimer S ldquoAnalysis of the Steam Assisted Gravity

Drainage (SAGD) Process Using Experimental Numerical Toolsrdquo SPE 37116

presented at the SPE International Conference on Horizontal Well Technology

Calgary Canada November 18-20 1996

10) Chan MYS Fong J Leshchyshyn T ldquoEffects of Well Placement and Critical

Operating Conditions on the Performance of Dual Well SAGD Well Pair in Heavy

Oil Reservoirrdquo SPE 39082 presented at the 5th Latin American and Caribbean

Petroleum Engineering Conference and Exhibition Rio de Janeiro Brazil Aug

30- Sept 3 1997

11) Nasr T N Golbeck H Korpany G Pierce G ldquoSAGD Operating Strategiesrdquo

253

SPE 50411 presented at the SPE International Conference on Horizontal Well

Technology Calgary Alberta Canada November 1-4 1998

12) Sasaki K Akibayashi S Yazawa N Doan Q Farouq Ali SM ldquoExperimental

Modeling of the SAGD Process-Enhancing SAGD Performance with Periodic

Stimulation of the Horizontal Producerrdquo SPE 56544 presented at the SPE Annual

Technical Conference and Exhibition Houston Texas October 3-6 1999

13) Sasaki K Akibayashi S Yazawa N Doan Q Farouq Ali S M ldquoNumerical

and Experimental Modelling of the Steam Assisted Gravity Drainage (SAGD)rdquo

JCPT Vol 40 No1 January 2001

14) Yuan JY Nasr TN Law DHS ldquoImpact of Initial Gas-to-Oil Ratio (GOR) on

SAGD Operationsrdquo JCPT Vol42 No1 January 2003

15) Vanegas Prada JW Cunha LB Alhanati FJS ldquoImpact of Operational

Parameters and Reservoir Variables During the Startup Phase of a SAGD

Processrdquo SPEPS-CIMCHOA 97918 SPE International Thermal Operations and

Heavy Oil Symposium Calgary Alberta Canada November 1-3 2005

16) Li P Chan M Froehlich W ldquoSteam Injection Pressure and the SAGD Ramp-

Up Processrdquo JCPT Vol48 No1 January 2009

17) Barillas JLM Dutra TV Mata W ldquoReservoir and Operational Parameters

Influence in SAGD Processrdquo Journal of Petroleum Science and Engineering

Vol54 2006

18) Albahlani AM Babadagli T ldquoA Critical Review of the Status of SAGD Where

Are We and What is Nextrdquo SPE 113283 SPE Western Regional and Pacific

Section AAPG Bakersfield California USA March 31-April 02 2008

19) Yang G Butler RM ldquoEffects of Reservoir Heterogeneities on Heavy Oil

Recovery by Steam Assisted Greavity Drainagerdquo JCPT Vol31 No8 1992

20) Chen Q Kovscek AR ldquoEffects of Reservoir Heterogeneity on the Steam

Assisted Gravity Drainage Processrdquo SPE 109873 SPE Reservoir Evaluation and

Engineering October 2008

21) Joshi S D ldquoLaboratory Studies of Thermally Aided Gravity Drainage Using

Horizontal Wellsrdquo AOSTRA Journal of Research vol 2 No 1 1985

22) Liebe HR Butler R ldquoA Study of the Use of Vertical Steam Injectors in the

254

Steam Assisted Gravity Drainage Processrdquo Presented at the CIMAOSTRA Banff

Canada April 21-24 1991

23) Shen C ldquoNumerical Investigation of SAGD Process Using a Single Horizontal

Wellrdquo SPE 50412 SPE International Conference on Horizontal Well Technology

Calgary Alberta Canada November 1-4 1998

24) Luft HB Pelensky PJ George GE ldquoDevelopment and Operation of a New

Insulated Concentric Coiled Tubing String for Continuous Steam Injection in

Heavy Oil Productionrdquo SPE30322 SPE International Heavy Oil Symposium

Heavy Oil Oil Sands Thermal Operations Calgary Alberta Canada June 19-21

1995

25) FalkK NzekwuB Karpuk B PelenskyP ldquoA Review of Insulated Concentric

Coiled Tubing Installations for Single Well Steam Assisted Gravity Drainagerdquo

SPEICoTA North American Coiled Tubing Roundtable Montgomery Texas

February 26-28 1996

26) Polikar M Cyr TJ Coates RM ldquoFast-SAGD Half the Wells and 30 Less

Steamrdquo SPEPetroleum Society of CIM 65509 SPEPetroleum Society of CIM

International Conference on Horizontal Well Technology Calgary Alberta

Canada November 6-8 2000

27) Shin H Polikar M ldquoReview of Reservoir Parameters to Optimize SAGD and

FAST-SAGD Operating Conditionsrdquo JCPT Vol46 No1 January 2007

28) Ehlig-Economides CA Fernandez B Economides MJ ldquoMultibranch

InjectorProducer Wells in Thick Heavy-Crude Reservoirsrdquo SPE 71868 June 2001

29) Stalder J L ldquoCross-SAGD (XSAGD)-An Accelerated Bitumen Recovery

Alternativerdquo SPEPS-CIMCHOA International Thermal Operations and Heavy

Oil Sumposium Calgary AB Canada November 2005

30) Gates ID Adams JJ Larter SR ldquoThe impact of oil viscosity heterogeneity on

the production characteristics of tar sand and heavy oil reservoirs Part II

Intelligent geotailored recovery processes in compositionally graded reservoirsrdquo

Journal of Canadian Petroleum Technology 47(9)40-49 2008

31) Ibatullin R R Ibragimov N G Khisamov R S Zaripov A T Amekhanov

M I ldquoA Novel Thermal Technology of Formation Treatment Involves Bi-

255

Wellhead Horizontal Wellsrdquo SPE 120413 presented at the SPE Middle East Oil amp

Gas Show and Conference Bahrain 15-18 March 2009

32) Bashbush J L Pina J A ldquoInfluence of Non-Parallel SAGD Well Pairs and

Permeability Hetroheneities on Recovery Factors from Warm Heavy Oil

Reservoirsrdquo SPE 139366 presented at the SPE Latin American amp Caribian

Petroleum Engineering Conference Lima Peru 1-3 December 2010

33) httpwwwenergygovabca

34) Edmunds NR ldquoReview of the Phase A Steam-Assisted Gravity Drainage Test

An Underground Test Facilityrdquo SPE 21529 presented at the SPE International

Thermal Operation Symposium Bakersfield California February 7-8 1991

35) Aherne A L Maini B ldquoFluid Movement in the SAGD Process A Review of the

Dover Projectrdquo JCPT Vol 47 No 1 January 2008

36) Encana 2006 Fostre Creek Development httpwwwercbca May 30 2006

37) Ito Y Suzuki S ldquoNumerical Simulation of the SAGD Process in the

Hangingstone Oil Sand Reservoirrdquo JCPT 27-35 September 1999 Vol 38 No9

38) Ito Y Hirata T Ichikawa I ldquoThe Effect of Operating Pressure on the Growth

of the Steam Chamber Detected at the Hangingstone SAGD Projectrdquo Petroleum

Societyrsquos Canadian International Petroleum Conferenece Calgary Alberta

Canada June 11-13 2002

39) Jimenez J ldquoThe Field Performance of SAGD Projects in Canadardquo IPTC 12860

International Petroleum Technology Conference Kuala Lumpur Malaysia 3-5

December 2008

40) Petro-Canada 2007 MacKay River Performance Presentation Approval No 8668

httpwwwercbca October 26 2007

41) Miller H Osmak G M ldquoMacKay River SAGD Project Benefits from New Slant

Rig Designrdquo SPE 84583 presented at SPE Annual Technical Conference and

Exhibition Denver Colorado USA 5-8 October 2003

42) Suggett J Gittins S Youn S ldquoChristina Lake Thermal Projectrdquo SPECIM

65520 presented at the 2000 SPEPetroleum Society of CIM International

Conference on Horizontal Well Technology Calgary Alberta Canada 6-8

November 2000

256

43) Encana Christina Lake In Situ Oil Sands Sheme 2006 Update Approval No

10441 and 9634 httpwwwercbca May 25 2006

44) MEG Energy Corp Christina Lake Regional Project 2007 Performance

Presentation Approval No 10159 and 10773 httpwwwercbca June 18 2007

45) ConocoPhilips Surmont SAGD Pilot Project Resource Management Report

httpwwwercbca December 2004

46) Bao X Chen Z Wei Y Dong C Sun J Deng H Yu S ldquoNumerical

Simulation and Optimization of the SAGD Process in Surmont Oil Sands Leaserdquo

SPE 137579 presented at the SPE Abu Dhabi International Petroelum Exhibition

and Conference Abu Dhabi UAE 1-4 November 2010

47) Gates ID Kenny J Hernandez-Hdez IL and Bunio GL ldquoSteam-Injection

Strategy and Energetics of Steam-Assisted Gravity Drainagerdquo SPE Res Eval

amp Eng 10 (1) 19-34 SPE-97742-PA

48) Suncor Firebag Project Commercial In-Situ Oil Sands Project Approval No

8870 httpwwwercbca April 19 2006

49) Total Joslyn Project Joslyn Creek Performance Presentation Approval No

9272C httpwwwercbca September 19 2006

50) Nexen Long Lake Pilot Performance Review httpwwwercbca June 20 2006

51) OPTI Canada Inc httpwwwopticanadacomprojectsoil_sands_overview

Retrieved May 4 2010

52) Devon Jackfish SAGD Project 2006 Resource Management Performance

Presentation Approval No10097A httpwwwercbca 2006

53) httpwwwdevonenergycom

54) Scott GR ldquoComparison of CSS and SAGD Performance in the Clearwater

Formation at Cold Lakerdquo SPEPetroleum Society of CIMCHOA 79020 presented

at the SPEPS-CIMCHOA International Thrmal Operation and Heavy Oil

Symposium and International Horizontal Well Technology Calgary Alberta


55) Canadian Natural Resources Limited 2010 Annual Presentation to ERCB on

Primoros Wolf Lake and Burnt Lake httpwwwercbca January 26 2010

56) Kisman KE Yeung KC ldquoNumerical Study of the SAGD Process in the Burnt

257

Lake Oil Sands Leaserdquo SPE 30276 presented at the SPE International Heavy Oil

Symposium Calgary Alberta Canada June19-21 1995

57) Shell Exploration and Production In-Sity Oil Sands Progress Presentation Hilda

Lake Pilot Approval No 8093 httpwwwercbca April 6 2010

58) Husky Oil Operation Limited Annual Performance Presentation Tuker Thermal

Project Approval No9835 httpwwwercbca July 21 2010

59) httpwwwlloydminsterheavyoilcom

60) Wong F Y Anderson D B OrsquoRouke J C Rea H Q Scheidt K A

ldquoMeeting the Challenge To Extend Success at the Pikes Peak Steam Project to

Areas With Bottomwaterrdquo SPE 84776 March 31 2003

61) Jespersen P J Fontaine T J ldquoThe Tangleflages North Pilot a Horizontal Well

Steamfloodrdquo Fourth Petroleum Conference South Saskatchewan Regina October

7-9 1991

62) Boyle TB Gittins SD Chakrabarty C ldquoThe Evolution of SAGD Technology

at East Senlacrdquo JCPT January 2003 Volume 42 No 1

63) httpwwwercbca

64) Albertarsquos Energy Reserves 2007 and SupplyDemand Outlook 2008-2017

httpwwwercbca

65) Nasr TN Ayodele OR ldquoThermal Techniques for the Recovery of Heavy Oil

and Bitumenrdquo SPE-97488-MS-P SPE International Improved Oil Recovery

Conference in Asia Pacific Kuala Lumpur Malaysia December 5-6 2005

66) Conly FM Crosley RW Headley JV ldquoCharacterization Sediment Sources

and Natural Hydrocarbon Inputs in the Lower Athabasca River Canadardquo J

Environ Eng Sci 1187-199 2002

67) Mossop GD ldquoGeology of the Athabasca Oil Sandsrdquo Science Vol207 January

11 1980

68) Flach PD ldquoOil Sands Geology-Athabasca Deposit Northrdquo Geological Survey

Department Alberta Research Council Edmonton Alberta Canada 1984

69) Athabasca Wabiskaw-McMurray Regional Geological Study December 31 2003

httpwwwercbca

70) Hein FJ Cotterill DK ldquoThe Athabasca Oil Sands-A Regional Geological

258

Perspective Fort McMurray Area Alberta Canadardquo Natural Resources Research

Vol15 No2 June 2006

71) Bachu S undershults JR Hitchon B Cotteril D ldquoRegional-Scale Subsurface

Hydrogeology in Northeast Albertardquo Bulletin No 61 Alberta Research Council

1993

72) Flach P Mossop GD ldquoDepositional Environmens of Lower Cretaceous

McMurray Formation Athabasca Oil Sands Albertardquo The American Association

of Petroleum Geologists Bulleting Vol 69 No8 August 1985

73) Fustic M Ahmed K Brogh S Bennett B Bloom L Asgar-Deen M

Jokanola O Spencer R Larter S ldquoReservoir and Bitumen Heterogeneity in

Athabasca Oil Sandsrdquo CSPG-CSEG-CWLS Convention pp640-652 2006

74) Harrison DB Glaister RP Nelson HW ldquoReservoir Description of the

Clearwater Oil Sand Cold Lake Alberta Canadardquo in The Future of Heavy Crude

and Tar Sands RFMeyer and CTSteele McGraw-Hill New York P264-279

75) Kendall GH ldquoImprtance of Reservoir Description in Evaluating IN SITU

Recovery Methods for Cold Lake Heavy Oil Part 1-Reservoir Descriptionrdquo

Bulletin of Canadian Petroleum Geology Vol25 No2 May 02 1977

76) Jiang Q Thornton B Houston JR Spence S ldquoReview of Thermal Recovery

Technologies for the Clearwater and Lower Grand Rapids Formation in the Cold

Lake Area in Albertardquo Presented at Canadian International Petroleum Conference

(CIPC) Calgary Alberta Canada 16-18 June 2009

77) McCrimmon GG Arnott RWC ldquoThe Clearwater Formation Cold Lake

Alberta A Worldclass Hydrocarbon Reservoir Hosted in a Complex Succession of

Tide-Dominated Deltaic Depositrdquo Bulletin of Canadian Petroleum Geology

Vol50 No3 September 2002

78) Hutcheon I Abercrombie HJ Putnam P Gradner R Krouse HR

ldquoDiagnesis and sedimentology of the Clearwater Formation at Tucker Lakerdquo

Bulletin of Canadian Petroleum Geology Vol37 No1 March 1989

79) Cold Lake Oil Sands Area Formation Picks and Correlation of Associated

Stratigraphy January 2007 httpwwwercbca

80) Putnam PE ldquoAspects of the Petroleum Geology of the Lloydminster Heavy Oil

259

Fields Alberta and Saskatchewanrdquo Bulletin of Canadian Petroleum Geology

Vol30 No2 June 1982

81) Orr RD Johnston JR Manko EM ldquoLower Cretaceous Geology and Heavy

Oil Potential of the Lloydminster Areardquo Bulletin of Canadian Petroleum Geology

Vol25 No6 December 1977

82) VanHulten FFN Smith SR ldquoThe Lower Cretaceous Sparky Formation

Lloydminster Area Stratigraphy and Paleoenvironmentrdquo Canadian Society of

Petroleum Geologists Memoir 9 p431-440 1984

83) White WI Von Osinski WP ldquoGeology and Heavy Oil Reserves of the

Mannville Group-Lloydminster-North Battleford Area-Saskatchewanrdquo Petroleum

Society of CIM Edmonton May30-June03 1977

84) Brown JS ldquoFormation Evaluation in Heavy Oil Sandsrdquo 15th Annual Technical

Meeting P amp NG Division CIM Calgary May 1964

85) Burnett A Adams KC ldquoA Geological Engineering and Economical Study of a

Portion of the Lloydminster Sparky Pool Lloydminster Albertardquo Bulletin of

Canadian Petroleum Geology Vol25 No2 May 1977

86) Vigrass LW ldquoTrapping of Oil at Intra-Mannville (Lower Cretaceous)

Disconformity in Lloydminster Area Alberta and Saskatchewanrdquo American

Association of Petroleum Geologists Bulletin Vol61 No7 July 1977

87) VanHulten FFN ldquo Petroleum Geology of Pikes Peak Heavy Oil Field Waseca

Formation Lower Cretaceous Saskatchewanrdquo Canadian Society of Petroleum

Geologists Memoir 9 p4431-454 1984

88) Reidiger CL Fowler MG Snowdn LR MacDonald R Sherwin MD

ldquoOrigin and Alteration of Lower Cretaceous Mannville Group Oils from the

Provost Oil Field East Central Alberta Canadardquo Bulletin of Canadian Petroleum

Geology Vol47 No1 March 1999

89) Adams DM ldquoExperience With Waterflooding Lloydminster Heavy-Oil

Reservoirsrdquo Journal of Petroleum Technology August 1982

90) Edmunds N Chhina H ldquoEconomic Optimum Operating Pressure for SAGD

Projects in Albertardquo JCPT VOL40 No12 December 2001

91) Gates ID Chakrabarty N ldquoOptimization of Steam-Assisted Gravity Drainage in

260

McMurray Reservoirrdquo Canadian International Petroleum Conference Calgary

Alberta Canada June 7-9 2005

92) CMG STARS 200913 Usersrsquos Guide

93) Mehrotra AK and Svercek WY ldquoViscosity of Compressed Athabasca

Bitumenrdquo Canadian Journal of Chemical Engineering Vol 64 pp844-847 1986

94) Oballa V Coombe D A Buchanan l ldquoAspects of Discretized Wellbore

Modelling Coupled to Compositional Thermal Simulationrdquo Journal of Canadian

Petroleum Technology Vol36 pp45-51 1997

95) Mojarab M Harding T Maini B ldquoImproving the SAGD Performance by

Introducing a New Well Configurationrdquo Canadian International Petroleum

Conference (CIPC) 2009 Calgary AB Canada 16-18 June 2009

96) Beattie CI Boberg TC McNab GS ldquoReservoir Simulation of Cyclic Steam

Stimulation in the Cold Lake Oil Sandsrdquo SPE-18752-PA SPE Reservoir

Engineering May 1991

97) CokarM Kallos M S Gates I S ldquoReservoir Simulation of Steam Fracturing

in Early Cycle Cyclic Steam Stimulationrdquo presented at the SPE Improved Oil

Recovery Symposium Tulsa Oklahama USA 24-28 April 2010

98) Kasraie M Singhal AK Ito Y ldquoScreening and Design Criteria for Tangleflags

Type Reservoirsrdquo International Thermal Operations and Heavy Oil Symposium

Bakesfield California USA February 10-12 1997

Cover Page-Acknowledement-Table of Tables and Figures

Pages from Full Thesis

UNIVERSITY OF CALGARY

Physical and Numerical Modeling of SAGD Under New Well Configurations

by

Mohammad Tavallali

A THESIS

SUBMITTED TO THE FACULTY OF GRADUATE STUDIES

IN PARTIAL FULFILMENT OF THE REQUIREMENTS FOR THE

DEGREE OF DOCTOR OF PHILOSOPHY

DEPARTMENT OF CHEMICAL amp PETROLEUM ENGINEERING

CALGARY ALBERTA

SEPTEMBER 2013

copy Mohammad Tavallali 2013

ii

ABSTRACT





models
























iii











iv

ACKNOWLEDGEMENTS























support

v

DEDICATION



vi

TABLE OF CONTENTS








vii











viii










ix




REFERENCES 252

x

LIST OF TABLES














experiments 241

xi

LIST OF FIGURES





























xii




















for sand analysis77










xiii






























xiv






























xv





























xvi






























xvii






























xviii






























xix






















xx


Symbol Definition


xxi

Greek Symbols


CHAPTER 1

INTRODUCTION

2










attentions





10000000

1000000

100000

10000

1000

100

1


Visc

osity

cp

Athabasca Cold Lake

0 50 100 150 200 250 Temperature C

10

3















Overburden

Underburden

Steam Chamber

Net Pay








4





3) Wind down


























5















T=Ts

T=TR

θ

dt t x

y ⎟ ⎠ ⎞

⎜ ⎝ ⎛ part

part







6








kgα ⎛ ⎞t 2



1 tD 2

Y 1 (14) = minus ⎛ ⎞ ⎜ ⎟2 X⎝ ⎠

X = x h (15)

Y = y h (16)





7

0

01

02

03

04

05

06

07

08

09

1


Ver

tical

Dist

ance

yh

02 06

04 08

1 12

14 16

18 2





⎡ TS ⎛ 1 1 ⎞ dT ⎤minus1

m = ⎢ν minus ⎥ (18) ν ν T T⎣

s intTR ⎜⎝ R

⎟⎠ minus R ⎦









8





[3]

3 o s

kgh B S mαφ ν

= Δ

(110)





(111) [1]

αtFo = h2 (111)



B3 = tD (113) Fo



9























heterogeneities



model





10













Parameter

Net Pay m

Permeability mD

φΔSo

microR cp

micros cp

m









11



























1315 Heterogeneity




12












two cases







1316 Wettability









recovery

13

1317 Water Leg











1318 Gas Cap







132 Well Design

1321 Completion









14








same vertical plane

















1331 Pressure






15










1332 Temperature





















16


























1337 Wind down




17






























18




















physical model




19



Producer Producer


Injector
























20





reservoir









chapter as well

CHAPTER 2

LITERATURE REVIEW

22

























left behind






23





vital
















SAGD process [7]











24
































25
































26















conditions [9]





27




Top of Formation


Injector

Producer

Base of Formation













28






















29











producer

30













31



















32















33






























34



















35





























36






























37














percent [59 60]


















38




CHAPTER 3


40















41






presented


sands deposit










42







anticline feature







43














44












exist





45













pperM


Lower C

retaceous

Lower

Mannville

McMurray McMurray









46















Lake

















47






distance























48


the areal extension




Clearwater

Upper M


Lower C

retaceous

Lower M

annville

McMurray McMurray



49













in Alberta







50




















51














52





















53





























in Figure 3-14

54











to 4m thick

55


Colony

McLaren

Waseca U

pperGrand Rapids

Clearwater

Sparky

GP

RL-Rex

Lloydminster

Cummings

Middle

Lower C

retaceous

Mannville G

roup

McMurray Dina

Low

er

Mainly Sand


Shale






coal and shale










56





to 2000 mD


















57

















58



Darcyrsquos











oil wet as well


















59
















60




heterogeneities







of these factors





extension
















61






CHAPTER 4


PROCEDURE

63








Steam

Water

Load Cell

Steam

Model Temperature








64






















70 987

30 1000

40 1000





65













25 cm

50 cm













66
















67

4

3 A B C D E F G







412 Steam Generator

















physical model

68






23rdquo

85rdquo

PTB

PTE

215rdquo

PTD

175rdquo

PTC

130rdquo

PTA40rdquo










69






24 cm 25 cm












sensor

70



Senor Z31 Z38 Z41

Rotor


Radius Ri mm 1572 1901 2071

+- ΔRi mm 0002 0004 0004

Length mm 55 55 55

+- L mm 003 003 003

Cup



+- ΔRa mm 0004 0004 0004


71

















additional water










72



73


























fill the model




74


with water

























75

1

2

3



3 Connection valves



442 SAGD Experiment












76

















77

1 2 3

4 5 6

7 8 9














experiment



78







444 Cleaning




washed with toluene

CHAPTER 5


80







51 Athabasca






511 Reservoir Model















81


30 500

20


Injector

Producer










82




















component

83


P




10

100

1000

10000

100000

1000000

10000000

100000000

Visc

osity

cp

00 500 1000 1500 2000 2500 3000

Temperature C









pairs



84





85









515 Wellbore Model








86



of the wellbore























224 degC




87



















reservoirs

5m

Injector

Producer

Injectors

Producer 5m

Injector

Producer


Producer

Injector

Producer



88

5181 Base Case




























cSOR

89

Oil

Prod

Rat

e SC

TR (m

3da

y)

0

20

40

60

80


1 2 3 4


2009 2010 2011 2012 2013 2014

Time (Date)


Oil

Rec

over

y Fa

ctor

SC

TR

0

10

20

30

40

50

60

70


2009 2010 2011 2012 2013 2014

Time (Date)


90

Stea

m O

il R

atio

Cum

SC

TR (m

3m

3)

00

05

10

15

20

25

30

35

40

45


2009 2010 2011 2012 2013 2014

Time (Date)


Stea

m C

ham

ber V

olum

e S

CTR

(m3)

0

10000

20000

30000

40000

50000


2009 2010 2011 2012 2013 2014 Time (Date)


91

1 2

3 4


Stea

m Q

ualit

y D

ownh

ole

00

01

02

03

04

05

06

07

08

09

10


2009 2010 2011 2012 2013 2014

Time (Date)


92































93


depletion period










degC cS cS m m2D

D m m Mpa

cS

Pres

sure

(kPa

)

2480

2482

2484

2486

2488

2490

2492

2494

2496

2498

2500


2009 2010 2011 2012 2013 2014 Time (Date)


94

0

20

40

60

80

100

120

140

160

0 1 2 3 4 5 6 Time Year

Oil

Prod

uctio

n R

ate

m3 d















case




95




















96

Oil

Prod

Rat

e SC

TR (m

3da

y)

0

20

40

60

80


2009 2010 2011 2012 2013 2014

Time (Date)


Oil

Rec

over

y Fa

ctor

SC

TR

0

10

20

30

40

50

60


2009 2010 2011 2012 2013 2014

Time (Date)


97

Stea

m O

il R

atio

Cum

SC

TR (m

3m

3)

00

05

10

15

20

25

30

35

40

45


2009 2010 2011 2012 2013 2014

Time (Date)


Stea

m C

ham

ber V

olum

e SC

TR (m

3)

0

10000

20000

30000

40000

50000


2009 2010 2011 2012 2013 2014

Time (Date)


98

























99

Oil

Rat

e SC

(m3

day)

0

30

60

90

120


2009 2010 2011 2012 2013 2014 2015 2016 2017

Time (Date)


Oil

Rec

over

y Fa

ctor

SC

TR

0

10

20

30

40

50

60


2009 2010 2011 2012 2013 2014 2015 2016 2017

Time (Date)


100

Stea

m O

il R

atio

Cum

SC

TR (m

3m

3)

00

10

20

30

40

50

60

70

80

90


2009 2010 2011 2012 2013 2014 2015 2016 2017

Time (Date)


Stea

m C

ham

ber V

olum

e SC

TR (m

3)

0

10000

20000

30000

40000

50000

60000


2009 2010 2011 2012 2013 2014 2015 2016 2017

Time (Date)


101



























reservoir

102

Oil

Prod

Rat

e SC

TR (m

3da

y)

0

20

40

60

80


2009 2010 2011 2012 2013 2014 Time (Date)


Oil

Rec

over

y Fa

ctor

SC

TR

0

10

20

30

40

50

60


2009 2010 2011 2012 2013 2014 Time (Date)


103

Stea

m O

il R

atio

Cum

SC

TR (m

3m

3)

00

05

10

15

20

25

30

35

40

45


2009 2010 2011 2012 2013 2014 Time (Date)


Stea

m C

ham

ber V

olum

e SC

TR (m

3)

0

10000

20000

30000

40000

50000


2009 2010 2011 2012 2013 2014 Time (Date)


104

One Year Five Years








investigated










circulation

50

105

70

Oil

Rec

over

y Fa

ctor

SC

TR

Ste

am O

il R

atio

Cum

SC

TR (m

3m

3)

60

50

40

30

20

10

0

Time (Date) 2009 2010 2011 2012 2013 2014



45

40

35

30

25

20

15

10

05

00

Time (Date) 2008-1-1 2009-5-15 2010-9-27 2012-2-9 2013-6-23 2014-11-5



106

Oil

Rat

e SC

(m3

day)

0

20

40

60

80


2009 2010 2011 2012 2013 2014 Time (Date)


Oil

Rec

over

y Fa

ctor

SC

TR

0

10

20

30

40

50

60


2009 2010 2011 2012 2013 2014 Time (Date)


107

Ste

am O

il R

atio

Cum

SC

TR (m

3m

3)

00

05

10

15

20

25

30

35

40

45


2008-1-1 2009-5-15 2010-9-27 2012-2-9 2013-6-23 2014-11-5 Time (Date)


Stea

m C

ham

ber V

olum

e SC

TR (m

3)

0

10000

20000

30000

40000

50000

60000


2009 2010 2011 2012 2013 2014 Time (Date)


108















less than 3 months









109

Oil

Prod

Rat

e SC

TR (m

3da

y)

0

20

40

60

80


2009 2010 2011 2012 2013 2014

Time (Date)


Oil

Rec

over

y Fa

ctor

SC

TR

0

10

20

30

40

50

60


2009 2010 2011 2012 2013 2014

Time (Date)


110

Stea

m O

il R

atio

Cum

SC

TR (m

3m

3)

00

05

10

15

20

25

30

35

40

45


2009 2010 2011 2012 2013 2014

Time (Date)


Stea

m C

ham

ber V

olum

e SC

TR (m

3)

0

10000

20000

30000

40000

50000


2009 2010 2011 2012 2013 2014

Time (Date)


111
















100

80

60

40

20

0

Oil

Prod

Rat

e SC

TR (m

3da

y)


2009 2010 2011 2012 2013 2014 Time (Date)


112

Oil

Rec

over

y Fa

ctor

SC

TR

0

10

20

30

40

50

60


2009 2010 2011 2012 2013 2014

Time (Date)


Stea

m O

il R

atio

Cum

SC

TR (m

3m

3)

00

05

10

15

20

25

30

35

40

45


2009 2010 2011 2012 2013 2014

Time (Date)


113

Stea

m C

ham

ber

Volu

me

SCTR

(m3)

70000

60000

50000

40000

30000

20000

10000

0


2009 2010 2011 2012 2013 2014 Time (Date)


52 Cold Lake






521 Reservoir Model








114

20

500

30


















115

1000000

100000

10000

1000

100

10

1

Visc

osity

cp

0 50 100 150 200 250 Temperature C










300

116







525 Wellbore Model













producer







117










5m

Injector

Producer

Injectors

Producer XY

Injector

Producer





Injector Producer X



5281 Base Case









118







recovery factor














119

Oil

Prod

Rat

e SC

TR (m

3da

y)

0

20

40

60

80

100

120


2008-7 2009-1 2009-7 2010-1 2010-7 2011-1 2011-7 2012-1

Time (Date)


Oil

Reco

very

Fac

tor

SCTR

0

10

20

30

40

50

60


2008-7 2009-1 2009-7 2010-1 2010-7 2011-1 2011-7 2012-1

Time (Date)


120

Stea

m O

il R

atio

Cum

SC

TR (m

3m

3)

00

05

10

15

20

25

30

35

40

45


2008-7 2009-1 2009-7 2010-1 2010-7 2011-1 2011-7 2012-1

Time (Date)


Stea

m C

ham

ber

Volu

me

SCTR

(m3)

0

10000

20000

30000

40000

50000


2008-7 2009-1 2009-7 2010-1 2010-7 2011-1 2011-7 2012-1

Time (Date)


121















Oil

Prod

Rat

e SC

TR (m

3da

y)

160

140

120

100

80

60

40

20

0


2008-7 2009-1 2009-7 2010-1 2010-7 2011-1 2011-7 2012-1 Time (Date)


122

Oil

Rec

over

y Fa

ctor

SC

TR

0

10

20

30

40

50

60


2008-7 2009-1 2009-7 2010-1 2010-7 2011-1 2011-7 2012-1

Time (Date)


Stea

m O

il R

atio

Cum

SC

TR (m

3m

3)

00

05

10

15

20

25

30

35

40

45


2008-7 2009-1 2009-7 2010-1 2010-7 2011-1 2011-7 2012-1

Time (Date)


123

Stea

m C

ham

ber

Volu

me

SCTR

(m3)

60000

50000

40000

30000

20000

10000

0


2008-7 2009-1 2009-7 2010-1 2010-7 2011-1 2011-7 2012-1 Time (Date)
















124













Oil

Prod

Rat

e SC

TR (m

3da

y)

160

140

120

100

80

60

40

20

0 2008-7 2009-1 2009-7 2010-1 2010-7 2011-1 2011-7 2012-1


Time (Date)


125

Oil

Rec

over

y Fa

ctor

SC

TR

0

10

20

30

40

50

60


2008-7 2009-1 2009-7 2010-1 2010-7 2011-1 2011-7 2012-1

Time (Date)


Stea

m O

il R

atio

Cum

SC

TR (m

3m

3)

00

10

20

30

40

50

60

70

80

90

100


2008-7 2009-1 2009-7 2010-1 2010-7 2011-1 2011-7 2012-1

Time (Date)


126

60000

50000

40000

30000

20000

10000

0

Time (Date)








evaluated









Stea

m C

ham

ber

Volu

me

SCTR

(m3)


2008-7 2009-1 2009-7 2010-1 2010-7 2011-1 2011-7 2012-1

127



base case







Oil

Prod

Rat

e SC

TR (m

3da

y)

180

160

140

120

100

80

60

40

20

0


2008-7 2009-1 2009-7 2010-1 2010-7 2011-1 2011-7 2012-1 Time (Date)


128

Oil

Rec

over

y Fa

ctor

SC

TR

0

10

20

30

40

50

60


2008-7 2009-1 2009-7 2010-1 2010-7 2011-1 2011-7 2012-1

Time (Date)


Stea

m O

il R

atio

Cum

SC

TR (m

3m

3)

00

05

10

15

20

25

30

35

40

45


2008-7 2009-1 2009-7 2010-1 2010-7 2011-1 2011-7 2012-1

Time (Date)


129

Stea

m C

ham

ber

Volu

me

SCTR

(m3)

60000

50000

40000

30000

20000

10000

0


2008-7 2009-1 2009-7 2010-1 2010-7 2011-1 2011-7 2012-1 Time (Date)

















130



Oil

Prod

Rat

e SC

TR (m

3da

y)

140

120

100

80

60

40

20

0


2008-7 2009-1 2009-7 2010-1 2010-7 2011-1 2011-7 2012-1

Time (Date)


131

Oil

Rec

over

y Fa

ctor

SC

TR

0

10

20

30

40

50

60


2008-7 2009-1 2009-7 2010-1 2010-7 2011-1 2011-7 2012-1

Time (Date)


Stea

m O

il R

atio

Cum

SC

TR (m

3m

3)

00

05

10

15

20

25

30

35

40

45


2008-7 2009-1 2009-7 2010-1 2010-7 2011-1 2011-7 2012-1

Time (Date)


132

Stea

m C

ham

ber V

olum

e SC

TR (m

3)

60000

50000

40000

30000

20000

10000

0


2008-7 2009-1 2009-7 2010-1 2010-7 2011-1 2011-7 2012-1 Time (Date)







producer





increased by 138

133

Oil

Prod

Rat

e SC

TR (m

3da

y)

0

20

40

60

80

100

120


2008-7 2009-1 2009-7 2010-1 2010-7 2011-1 2011-7 2012-1

Time (Date)


Oil

Reco

very

Fac

tor

SCTR

0

10

20

30

40

50

60


2008-7 2009-1 2009-7 2010-1 2010-7 2011-1 2011-7 2012-1

Time (Date)


134

50

45

40

35

30

25

20

15

10

05

00


2008-7 2009-1 2009-7 2010-1 2010-7 2011-1 2011-7 2012-1

Time (Date)


Stea

m C

ham

ber

Volu

me

SCTR

(m3)

0

10000

20000

30000

40000

50000


2008-7 2009-1 2009-7 2010-1 2010-7 2011-1 2011-7 2012-1

Time (Date)

Stea

m O

il R

atio

Cum

SC

TR (m

3m

3)


135












by 55

Oil

Prod

Rat

e SC

TR (m

3da

y)

140

120

100

80

60

40

20

0


2008-7 2009-1 2009-7 2010-1 2010-7 2011-1 2011-7 2012-1 Time (Date)


136

Oil

Rec

over

y Fa

ctor

SC

TR

0

10

20

30

40

50

60


2008-7 2009-1 2009-7 2010-1 2010-7 2011-1 2011-7 2012-1

Time (Date)


Stea

m O

il R

atio

Cum

SC

TR (m

3m

3)

00

05

10

15

20

25

30

35

40

45


2008-7 2009-1 2009-7 2010-1 2010-7 2011-1 2011-7 2012-1

Time (Date)


137

Stea

m C

ham

ber

Volu

me

SCTR

(m3)

60000

50000

40000

30000

20000

10000

0


2008-7 2009-1 2009-7 2010-1 2010-7 2011-1 2011-7 2012-1 Time (Date)
















138



Oil

Prod

Rat

e SC

TR (m

3da

y)

140

120

100

80

60

40

20

0


2008-7 2009-1 2009-7 2010-1 2010-7 2011-1 2011-7 2012-1

Time (Date)


139

Oil

Rec

over

y Fa

ctor

SC

TR

0

10

20

30

40

50

60


2008-7 2009-1 2009-7 2010-1 2010-7 2011-1 2011-7 2012-1

Time (Date)


Stea

m O

il R

atio

Cum

SC

TR (m

3m

3)

00

05

10

15

20

25

30

35

40

45


2008-7 2009-1 2009-7 2010-1 2010-7 2011-1 2011-7 2012-1

Time (Date)


140

Stea

m C

ham

ber

Volu

me

SCTR

(m3)

70000

60000

50000

40000

30000

20000

10000

0


2008-7 2009-1 2009-7 2010-1 2010-7 2011-1 2011-7 2012-1 Time (Date)


5289 C-SAGD















141
















142













Oil

Prod

Rat

e SC

TR (m

3da

y)

300

270

240

210

180

150

120

90

60

30

0


2008-7 2009-1 2009-7 2010-1 2010-7 2011-1 2011-7 2012-1 Time (Date)


143

Oil

Rec

over

y Fa

ctor

SC

TR

0

10

20

30

40

50

60

70


2008-7 2009-1 2009-7 2010-1 2010-7 2011-1 2011-7 2012-1

Time (Date)


Stea

m O

il R

atio

Cum

SC

TR (m

3m

3)

00

10

20

30

40

50

60

70

80

90


2008-7 2009-1 2009-7 2010-1 2010-7 2011-1 2011-7 2012-1

Time (Date)


144

Stea

m C

ham

ber

Volu

me

SCTR

(m3)

90000

80000

70000

60000

50000

40000

30000

20000

10000

0


2008-7 2009-1 2009-7 2010-1 2010-7 2011-1 2011-7 2012-1 Time (Date)







53 Lloydminster









Net

145













Overburden

Underburden

Steam Chamber

Underburden

Overburden











146
























531 Reservoir Model







147


reservoir model

10

500

90











Lake reservoirs






148







E+5m3











149

10000

Visc

osity

cp

1000

100

10

1 0 50 100 150 200 250

TemperatureC
















300

150









Injector




Injector Producer X
















151


















small as possible









152

Oil

Rat

e SC

(m3

day)

0

20

40

60

80

100

120

140

160

180


2009 2010 2011 2012 2013 2014 2015 2016

Time (Date)


Oil

Rec

over

y Fa

ctor

SC

TR

0

15

30

45

60


2009 2010 2011 2012 2013 2014 2015 2016

Time (Date)


153

Cum

Ste

am O

il R

atio

(m3

m3)

00

10

20

30

40

50


2009 2010 2011 2012 2013 2014 2015 2016

Time (Date)


Stea

m C

ham

ber V

olum

e SC

TR (m

3)

00e+0

20e+4

40e+4

60e+4

80e+4


2009 2010 2011 2012 2013 2014 2015 2016

Time (Date)


154







be larger than 30m













5-91 5-92 and 5-93






vertical injectors

155

Oil

Rat

e SC

(m3

day)

0

30

60

90

120

150

180


2009 2010 2011 2012 2013 2014 2015 2016

Time (Date)


Oil

Rec

over

y Fa

ctor

SC

TR

0

12

24

36

48

60

72


2009 2010 2011 2012 2013 2014 2015 2016

Time (Date)


156

Stea

m O

il R

atio

Cum

SC

TR (m

3m

3)

00

10

20

30

40

50


2009 2010 2011 2012 2013 2014 2015 2016

Time (Date)


Stea

m C

ham

ber V

olum

e SC

TR (m

3)

00e+0

20e+4

40e+4

60e+4

80e+4


2009 2010 2011 2012 2013 2014 2015 2016

Time (Date)


157

5363 C-SAGD





















158

Oil

Rat

e SC

(m3

day)

0

30

60

90

120

150

180


2009 2010 2011 2012 2013 2014 2015 2016

Time (Date)


Oil

Rec

over

y Fa

ctor

SC

TR

0

10

20

30

40

50

60

70

80


2009 2010 2011 2012 2013 2014 2015 2016

Time (Date)


159

Stea

m O

il R

atio

Cum

SC

TR (m

3m

3)

00

10

20

30

40

50

60

70


2009 2010 2011 2012 2013 2014 2015 2016

Time (Date)


Stea

m C

ham

ber V

olum

e SC

TR (m

3)

00e+0

20e+4

40e+4

60e+4

80e+4

10e+5


2009 2010 2011 2012 2013 2014 2015 2016

Time (Date)


160













Oil

Rat

e SC

(m3

day)

180

160

140

120

100

80

60

40

20

0


2009 2010 2011 2012 2013 2014 2015 2016 Time (Date)


161

Oil

Rec

over

y Fa

ctor

SC

TR

0

10

20

30

40

50

60

70


2009 2010 2011 2012 2013 2014 2015 2016

Time (Date)


Stea

m O

il R

atio

Cum

SC

TR (m

3m

3)

00

10

20

30

40

50


2009 2010 2011 2012 2013 2014 2015 2016

Time (Date)


162

Stea

m C

ham

ber V

olum

e SC

TR (m

3)

10e+5

80e+4

60e+4

40e+4

20e+4

00e+0


2009 2010 2011 2012 2013 2014 2015 2016 Time (Date)














163

Oil

Rat

e SC

(m3

day)

0

20

40

60

80

100

120

140

160


2009 2010 2011 2012 2013 2014 2015 2016

Time (Date)


Oil

Rec

over

y Fa

ctor

SC

TR

0

15

30

45

60

75


2009 2010 2011 2012 2013 2014 2015 2016

Time (Date)


164

Stea

m O

il R

atio

Cum

SC

TR (m

3m

3)

00

10

20

30

40

50

60


2009 2010 2011 2012 2013 2014 2015 2016

Time (Date)


Stea

m C

ham

ber V

olum

e SC

TR (m

3)

00e+0

20e+4

40e+4

60e+4

80e+4

10e+5


2009 2010 2011 2012 2013 2014 2015 2016

Time (Date)


165









reservoirs

CHAPTER 6


DISUCSSIONS

167






























AGSCO sand

168




Porosity

Soi

Swi

Viso Ti cp

Well Spacing cm























169


















y = 26222x

R2 = 09891

0

10

20

30

40

50

60

70

80

0 005 01 015 02 025 03

∆PL psicm

QA

ccmincm

2

Measured

Linear Regression


170

1

10

100

1000

10000

100000

0 50 100 150 200 250 300

Measured Data


Temperature degC

Viscosity

cp


1

10

100

1000

10000

100000

1000000

0 50 100 150 200 250 300

Temperature C

Visco

cp

Measured Date



171

























experiment






172




















temperature







173

0

5

10

15

20

25

0 5 10 15 20 25 30 Time hr

Oil

Rat

e c

cm

in



0

1

2

3

4

5

6

7

8

0 5 10 15 20 25 30 Time hr

cSO

R c

ccc



174

0

10

20

30

40

50

60

70

80

90

100

0 5 10 15 20 25 30 Time hr

WC

UT



0

5

10

15

20

25

30

35

40

45

0 5 10 15 20 25 30 Time hr

RF



175











0

5

10

15

20

25

30

35

40

45

50

0 2 4 6 8 10 12 14 16 18 20 Time hr

Oil

Rat

e c

cm

in



176

00

05

10

15

20

25

30

35

0 2 4 6 8 10 12 14 16 18 20 Time hr

cSO

R c

ccc



0

10

20

30

40

50

60

70

80

0 2 4 6 8 10 12 14 16 18 20 Time hr

WC

UT



177

0

5

10

15

20

25

30

35

40

45

0 2 4 6 8 10 12 14 16 18 20 Time hr

RF














toe of the injector

178

0

20

40

60

80

100

120

0 1 2 3 4 5 Time hr

Tem

pera

ture

C

D15 D25 D35 D45 D55

0

20

40

60

80

100

120

0 4 8 12 16 20 Time hr

Tem

pera

ture

C

D15 D25 D35 D45 D55


179









Layer A Layer B

Layer C

Layer D




Cross Section 5















180









Injector

Producer


181

Injector

Producer

Injector

Producer



182

Injector

Producer

Injector

Producer



183

Injector

Producer
















pressure

184








well


185

140 6000

120

100

80

60

40

20

00


5000

4000

3000

2000

1000

0

Wat

er R

ate

SC (c

m3

min

)O

il R

ate

SC (c

m3

min

)

Cum

ulat

ive

Wat

er S

C (c

m3)

C

umul

ativ

e O

il SC

(cm

3)

0 4 8 12 16 20 24 28 Time (hr)


28 14000

24

20

16

12

8

4

0


12000

10000

8000

6000

4000

2000

0 0 4 8 12 16 20 24 28

Time (hr)


186

Wat

er R

ate

SC (c

m3

min

)

Cum

ulat

ive

Wat

er S

C (c

m3)

0

5

10

15

20

25

30

0

3000

6000

9000

12000

15000

18000


0 4 8 12 16 20 24 28 Time (hr)


Stea

m C

ham

ber V

olum

e SC

TR (c

m3)

0 4 8 12 16 20 24 28 0

500

1000

1500

2000

2500

3000

3500


Time (hr)


187
















~90



Figure 6-25 26 27 and 28












188



experiments



























189

0

2

4

6

8

10

12

14

16

0 5 10 15 20 25 30 Time hr

Oil

Rat

e c

cm

in



0

1

2

3

4

5

6

7

8

0 5 10 15 20 25 30 Time hr

cSO

R c

ccc



190

0

10

20

30

40

50

60

70

80

90

100

0 5 10 15 20 25 30 Time hr

WC

UT



0

10

20

30

40

50

60

0 5 10 15 20 25 30 Time hr

RF



191

0

20

40

60

80

100

120

0 1 2 3 Time hr

Tem

pera

ture

C

D31 D33 D35 D37 D39

0

20

40

60

80

100

120

0 2 4 6 8 10 12 14 16 Time hr

Tem

pera

ture

C

D31 D33 D35 D37 D39


192








Injector Producer


193

Injector Producer


Injector Producer


194

Injector Producer


Injector Producer


195
















Injector

Producer


196













saturation pressure








197


198

Oil

Rat

e SC

(cm

3m

in)

Cum

ulat

ive

Oil

SC (c

m3)

0

4

8

12

16

20

0

2000

4000

6000

8000


0 4 8 12 16 20

Time (hr)


Wat

er R

ate

SC (c

m3

min

)

Cum

ulat

ive

Wat

er S

C (c

m3)

0

3

6

9

12

15

0

2000

4000

6000

8000


0 4 8 12 16 20

Time (hr)


199

Wat

er R

ate

SC (c

m3

min

)

Cum

ulat

ive

Wat

er S

C (c

m3)

0

3

6

9

12

15

18

0

2000

4000

6000

8000

10000


0 4 8 12 16 20

Time (hr)


Stea

m C

ham

ber V

olum

e SC

TR (c

m3)

0

1000

2000

3000

4000

5000

6000

7000


0 4 8 12 16 20

Time (hr)


200





physical model


























201







stable





















202

0

2

4

6

8

10

12

14

16

18

20

0 4 8 12 16 20 Time hr

Oil

Rat

e c

cm

in

Fifth Experiment


00

05

10

15

20

25

30

0 4 8 12 16 20 Time hr

cSO

R c

ccc

Fifth Experiment


203

0

10

20

30

40

50

60

70

80

90

0 4 8 12 16 20 Time hr

WC

UT

Fifth Experiment


0

10

20

30

40

50

60

0 4 8 12 16 20 Time hr

RF

Fifth Experiment


204

0

20

40

60

80

100

120

0 1 2 3 4 5 Time hr

Tem

pera

ture

C

D15 D25 D35 D45 D55

0

20

40

60

80

100

120

0 4 8 12 16 20 Time hr

Tem

pera

ture

C

D15 D25 D35 D45 D55


205









Injector

Producer


206

Injector

Producer

Injector

Producer



207

Injector

Producer

Injector

Producer



208

Injector

Producer


Injector

Producer


209











1 2 3

4 5 6

7 8 9

50 cm

8 cm 50 cm









entire layer





in φΔSo value

210

85 255

425

425

255

85

222 233

220

239

223

267

217

200

251

10

12

14

16

18

20

22

24

26

28

φΔS

o

X cm

Y cm

Mid Layer














section

211

85 255

425

425

255

85

220 224

210 211 212

228

197 200

244

10

12

14

16

18

20

22

24

26

φΔS

o

X cm

Y cm

Top Layer

















212









213

Oil

Rat

e SC

(cm

3m

in)

Cum

ulat

ive

Oil

SC (c

m3)

00

50

100

150

200

0

2000

4000

6000

8000


0 200 400 600 800 1000 1200 Time (min)


Wat

er R

ate

SC (c

m3

min

)

Cum

ulat

ive

Wat

er S

C (c

m3)

0

6

12

18

24

30

0

3000

6000

9000

12000


0 200 400 600 800 1000 1200 Time (min)


214

Wat

er R

ate

SC (c

m3

min

)

Cum

ulat

ive

Wat

er S

C (c

m3)

0

7

14

21

28

35

42

0

3000

6000

9000

12000

15000


0 200 400 600 800 1000 1200 Time (min)


Stea

m C

ham

ber V

olum

e SC

TR (c

m3)

0

2000

4000

6000


0 200 400 600 800 1000 1200 Time (min)


215








pairs

















216

0

5

10

15

20

25

0 4 8 12 16 20

Time hr

Oil

Rat

e c

cm

in



00

05

10

15

20

25

30

35

0 4 8 12 16 20 Time hr

cSO

R c

ccc



217

0

10

20

30

40

50

60

70

80

90

0 4 8 12 16 20 Time hr

WC

UT



0

10

20

30

40

50

60

0 4 8 12 16 20 Time hr

RF



218
































219


reservoir








its heel








PVinj












220

0

20

40

60

80

100

120

0 1 2 3 4 Time hr

Tem

pera

ture

C

D31 D33 D35 D37 D39

0

20

40

60

80

100

120

0 2 4 6 8 10 12 14 Time hr

Tem

pera

ture

C

D31 D33 D35 D37 D39


221

Injector Producer


Injector Producer


222

Injector Producer


Injector Producer


223

Injector Producer


Injector Producer


224

Injector

Producer


















225





section

Mid Layer

14

13

12

11

85

255 10

425

136

132

129

126 127

121

131

123

122

Y cm 425 85

255

X cm

φΔS

o


226

85 255

425

425

255

85

229 223

253

235

225 237 235

225 222

10

12

14

16

18

20

22

24

26

φΔS

o

X cm

Y cm

Top Layer
















227



nearly perfect


228

24 12000

20

16

12

8

4

0


10000

8000

6000

4000

2000

0

Wat

er R

ate

SC (c

m3

min

)O

il R

ate

SC (c

m3

min

)

Cum

ulat

ive

Wat

er S

C (c

m3)

C

umul

ativ

e O

il SC

(cm

3)

0 2 4 6 8 10 12 14 Time (hr)


30 12000

25

20

15

10

5

0


10000

8000

6000

4000

2000

0 0 2 4 6 8 10 12 14

Time (hr)


229

28 14000

Wat

er R

ate

SC (c

m3

min

)

24

20

16

12

8

4

0


10000

8000

6000

4000

2000

0

Cum

ulat

ive

Wat

er S

C (c

m3)

0 2 4 6 8 10 12 14 Time (hr)


Stea

m C

ham

ber V

olum

e SC

TR (c

m3)

0

1000

2000

3000

4000

5000

6000

7000


0 2 4 6 8 10 12 14 Time (hr)


230
















Injector

18 cm

5 cm Producer











231















classic pattern













Figure 6-86

232

cSO

R c

ccc

O

il R

ate

cc

min

35


30

25

20

15

10

5

0 0

30

35

4 8 12

Time hr


16 20


25

20

15

10

05

00 0 4 8 12

Time hr


16 20

233

RF

WC

UT

70

80

90 Fifth Experiment


60

50

40

30

20

10

0 0 4 8

Time hr 12 16 20

50

60



40

30

20

10

0 0 4 8 12 16 20

Time hr


234






Injector

Producer 5 cm

18 cm

D15 D35 D55

D45D25

















235

0

20

40

60

80

100

120

0 2 4 6 8 10 Time hr

Tem

pera

ture

C

D15 D25 D35 D45 D55

0

20

40

60

80

100

120

0 1 2 3 4 Time hr

Tem

pera

ture

C

D15 D25 D35 D45 D55


236
































237



238



239


Injector

Producer


240






layer of the model









section

85 255

425

425

255

85

257

216 228

267

259 262 265

254 251

10

12

14

16

18

20

22

24

26

28

φΔS

o

X cm

Y cm

Top Layer


241


















should be so low













242









243

12000 42

35

28

21

14

7

0


10000

8000

6000

4000

2000

0

Wat

er R

ate

SC (c

m3

min

)O

il R

ate

SC (c

m3

min

)

Cum

ulat

ive

Wat

er S

C (c

m3)

C

umul

ativ

e O

il SC

(cm

3)

0 2 4 6 8 10 12 Time (hr)


25

20

15

10

5


00 20 40 60 80 100 120

10000

8000

6000

4000

2000

0

Time (hr)


0

244

30 12000

25

20

15

10

5

0


10000

8000

6000

4000

2000

0

Stea

m C

ham

ber V

olum

e SC

TR (c

m3)

W

ater

Rat

e SC

(cm

3m

in)

Cum

ulat

ive

Wat

er S

C (c

m3)

0 2 4 6 8 10 12 Time (hr)



0 2 4 6 8 10 12

8000

6000

4000

2000

0

Time (hr)


245










CHAPTER 7


247

71 Conclusions





simulation study


























248












model
















reservoirs




249
























directions




and chamber volume




250






72 Recommendations















reservoir










251






down



project operation






best pattern

252


2000



August 1981


53 1942







1987



Feb 1988












30- Sept 3 1997


253




















Vol54 2006












254










1995




February 26-28 1996


















255






















December 2008









November 2000

256













amp Eng 10 (1) 19-34 SPE-97742-PA



















257













7-9 1991



63) httpwwwercbca


httpwwwercbca








11 1980




httpwwwercbca


258


Vol15 No2 June 2006



1993



























259


Vol30 No2 June 1982






























260























ii

ABSTRACT





models
























iii











iv

ACKNOWLEDGEMENTS























support

v

DEDICATION



vi

TABLE OF CONTENTS








vii











viii










ix




REFERENCES 252

x

LIST OF TABLES














experiments 241

xi

LIST OF FIGURES





























xii




















for sand analysis77










xiii






























xiv






























xv





























xvi






























xvii






























xviii






























xix






















xx


Symbol Definition


xxi

Greek Symbols


CHAPTER 1

INTRODUCTION

2










attentions





10000000

1000000

100000

10000

1000

100

1


Visc

osity

cp

Athabasca Cold Lake

0 50 100 150 200 250 Temperature C

10

3















Overburden

Underburden

Steam Chamber

Net Pay








4





3) Wind down


























5















T=Ts

T=TR

θ

dt t x

y ⎟ ⎠ ⎞

⎜ ⎝ ⎛ part

part







6








kgα ⎛ ⎞t 2



1 tD 2

Y 1 (14) = minus ⎛ ⎞ ⎜ ⎟2 X⎝ ⎠

X = x h (15)

Y = y h (16)





7

0

01

02

03

04

05

06

07

08

09

1


Ver

tical

Dist

ance

yh

02 06

04 08

1 12

14 16

18 2





⎡ TS ⎛ 1 1 ⎞ dT ⎤minus1

m = ⎢ν minus ⎥ (18) ν ν T T⎣

s intTR ⎜⎝ R

⎟⎠ minus R ⎦









8





[3]

3 o s

kgh B S mαφ ν

= Δ

(110)





(111) [1]

αtFo = h2 (111)



B3 = tD (113) Fo



9























heterogeneities



model





10













Parameter

Net Pay m

Permeability mD

φΔSo

microR cp

micros cp

m









11



























1315 Heterogeneity




12












two cases







1316 Wettability









recovery

13

1317 Water Leg











1318 Gas Cap







132 Well Design

1321 Completion









14








same vertical plane

















1331 Pressure






15










1332 Temperature





















16


























1337 Wind down




17






























18




















physical model




19



Producer Producer


Injector
























20





reservoir









chapter as well

CHAPTER 2

LITERATURE REVIEW

22

























left behind






23





vital
















SAGD process [7]











24
































25
































26















conditions [9]





27




Top of Formation


Injector

Producer

Base of Formation













28






















29











producer

30













31



















32















33






























34



















35





























36






























37














percent [59 60]


















38




CHAPTER 3


40















41






presented


sands deposit










42







anticline feature







43














44












exist





45













pperM


Lower C

retaceous

Lower

Mannville

McMurray McMurray









46















Lake

















47






distance























48


the areal extension




Clearwater

Upper M


Lower C

retaceous

Lower M

annville

McMurray McMurray



49













in Alberta







50




















51














52





















53





























in Figure 3-14

54











to 4m thick

55


Colony

McLaren

Waseca U

pperGrand Rapids

Clearwater

Sparky

GP

RL-Rex

Lloydminster

Cummings

Middle

Lower C

retaceous

Mannville G

roup

McMurray Dina

Low

er

Mainly Sand


Shale






coal and shale










56





to 2000 mD


















57

















58



Darcyrsquos











oil wet as well


















59
















60




heterogeneities







of these factors





extension
















61






CHAPTER 4


PROCEDURE

63








Steam

Water

Load Cell

Steam

Model Temperature








64






















70 987

30 1000

40 1000





65













25 cm

50 cm













66
















67

4

3 A B C D E F G







412 Steam Generator

















physical model

68






23rdquo

85rdquo

PTB

PTE

215rdquo

PTD

175rdquo

PTC

130rdquo

PTA40rdquo










69






24 cm 25 cm












sensor

70



Senor Z31 Z38 Z41

Rotor


Radius Ri mm 1572 1901 2071

+- ΔRi mm 0002 0004 0004

Length mm 55 55 55

+- L mm 003 003 003

Cup



+- ΔRa mm 0004 0004 0004


71

















additional water










72



73


























fill the model




74


with water

























75

1

2

3



3 Connection valves



442 SAGD Experiment












76

















77

1 2 3

4 5 6

7 8 9














experiment



78







444 Cleaning




washed with toluene

CHAPTER 5


80







51 Athabasca






511 Reservoir Model















81


30 500

20


Injector

Producer










82




















component

83


P




10

100

1000

10000

100000

1000000

10000000

100000000

Visc

osity

cp

00 500 1000 1500 2000 2500 3000

Temperature C









pairs



84





85









515 Wellbore Model








86



of the wellbore























224 degC




87



















reservoirs

5m

Injector

Producer

Injectors

Producer 5m

Injector

Producer


Producer

Injector

Producer



88

5181 Base Case




























cSOR

89

Oil

Prod

Rat

e SC

TR (m

3da

y)

0

20

40

60

80


1 2 3 4


2009 2010 2011 2012 2013 2014

Time (Date)


Oil

Rec

over

y Fa

ctor

SC

TR

0

10

20

30

40

50

60

70


2009 2010 2011 2012 2013 2014

Time (Date)


90

Stea

m O

il R

atio

Cum

SC

TR (m

3m

3)

00

05

10

15

20

25

30

35

40

45


2009 2010 2011 2012 2013 2014

Time (Date)


Stea

m C

ham

ber V

olum

e S

CTR

(m3)

0

10000

20000

30000

40000

50000


2009 2010 2011 2012 2013 2014 Time (Date)


91

1 2

3 4


Stea

m Q

ualit

y D

ownh

ole

00

01

02

03

04

05

06

07

08

09

10


2009 2010 2011 2012 2013 2014

Time (Date)


92































93


depletion period










degC cS cS m m2D

D m m Mpa

cS

Pres

sure

(kPa

)

2480

2482

2484

2486

2488

2490

2492

2494

2496

2498

2500


2009 2010 2011 2012 2013 2014 Time (Date)


94

0

20

40

60

80

100

120

140

160

0 1 2 3 4 5 6 Time Year

Oil

Prod

uctio

n R

ate

m3 d















case




95




















96

Oil

Prod

Rat

e SC

TR (m

3da

y)

0

20

40

60

80


2009 2010 2011 2012 2013 2014

Time (Date)


Oil

Rec

over

y Fa

ctor

SC

TR

0

10

20

30

40

50

60


2009 2010 2011 2012 2013 2014

Time (Date)


97

Stea

m O

il R

atio

Cum

SC

TR (m

3m

3)

00

05

10

15

20

25

30

35

40

45


2009 2010 2011 2012 2013 2014

Time (Date)


Stea

m C

ham

ber V

olum

e SC

TR (m

3)

0

10000

20000

30000

40000

50000


2009 2010 2011 2012 2013 2014

Time (Date)


98

























99

Oil

Rat

e SC

(m3

day)

0

30

60

90

120


2009 2010 2011 2012 2013 2014 2015 2016 2017

Time (Date)


Oil

Rec

over

y Fa

ctor

SC

TR

0

10

20

30

40

50

60


2009 2010 2011 2012 2013 2014 2015 2016 2017

Time (Date)


100

Stea

m O

il R

atio

Cum

SC

TR (m

3m

3)

00

10

20

30

40

50

60

70

80

90


2009 2010 2011 2012 2013 2014 2015 2016 2017

Time (Date)


Stea

m C

ham

ber V

olum

e SC

TR (m

3)

0

10000

20000

30000

40000

50000

60000


2009 2010 2011 2012 2013 2014 2015 2016 2017

Time (Date)


101



























reservoir

102

Oil

Prod

Rat

e SC

TR (m

3da

y)

0

20

40

60

80


2009 2010 2011 2012 2013 2014 Time (Date)


Oil

Rec

over

y Fa

ctor

SC

TR

0

10

20

30

40

50

60


2009 2010 2011 2012 2013 2014 Time (Date)


103

Stea

m O

il R

atio

Cum

SC

TR (m

3m

3)

00

05

10

15

20

25

30

35

40

45


2009 2010 2011 2012 2013 2014 Time (Date)


Stea

m C

ham

ber V

olum

e SC

TR (m

3)

0

10000

20000

30000

40000

50000


2009 2010 2011 2012 2013 2014 Time (Date)


104

One Year Five Years








investigated










circulation

50

105

70

Oil

Rec

over

y Fa

ctor

SC

TR

Ste

am O

il R

atio

Cum

SC

TR (m

3m

3)

60

50

40

30

20

10

0

Time (Date) 2009 2010 2011 2012 2013 2014



45

40

35

30

25

20

15

10

05

00

Time (Date) 2008-1-1 2009-5-15 2010-9-27 2012-2-9 2013-6-23 2014-11-5



106

Oil

Rat

e SC

(m3

day)

0

20

40

60

80


2009 2010 2011 2012 2013 2014 Time (Date)


Oil

Rec

over

y Fa

ctor

SC

TR

0

10

20

30

40

50

60


2009 2010 2011 2012 2013 2014 Time (Date)


107

Ste

am O

il R

atio

Cum

SC

TR (m

3m

3)

00

05

10

15

20

25

30

35

40

45


2008-1-1 2009-5-15 2010-9-27 2012-2-9 2013-6-23 2014-11-5 Time (Date)


Stea

m C

ham

ber V

olum

e SC

TR (m

3)

0

10000

20000

30000

40000

50000

60000


2009 2010 2011 2012 2013 2014 Time (Date)


108















less than 3 months









109

Oil

Prod

Rat

e SC

TR (m

3da

y)

0

20

40

60

80


2009 2010 2011 2012 2013 2014

Time (Date)


Oil

Rec

over

y Fa

ctor

SC

TR

0

10

20

30

40

50

60


2009 2010 2011 2012 2013 2014

Time (Date)


110

Stea

m O

il R

atio

Cum

SC

TR (m

3m

3)

00

05

10

15

20

25

30

35

40

45


2009 2010 2011 2012 2013 2014

Time (Date)


Stea

m C

ham

ber V

olum

e SC

TR (m

3)

0

10000

20000

30000

40000

50000


2009 2010 2011 2012 2013 2014

Time (Date)


111
















100

80

60

40

20

0

Oil

Prod

Rat

e SC

TR (m

3da

y)


2009 2010 2011 2012 2013 2014 Time (Date)


112

Oil

Rec

over

y Fa

ctor

SC

TR

0

10

20

30

40

50

60


2009 2010 2011 2012 2013 2014

Time (Date)


Stea

m O

il R

atio

Cum

SC

TR (m

3m

3)

00

05

10

15

20

25

30

35

40

45


2009 2010 2011 2012 2013 2014

Time (Date)


113

Stea

m C

ham

ber

Volu

me

SCTR

(m3)

70000

60000

50000

40000

30000

20000

10000

0


2009 2010 2011 2012 2013 2014 Time (Date)


52 Cold Lake






521 Reservoir Model








114

20

500

30


















115

1000000

100000

10000

1000

100

10

1

Visc

osity

cp

0 50 100 150 200 250 Temperature C










300

116







525 Wellbore Model













producer







117










5m

Injector

Producer

Injectors

Producer XY

Injector

Producer





Injector Producer X



5281 Base Case









118







recovery factor














119

Oil

Prod

Rat

e SC

TR (m

3da

y)

0

20

40

60

80

100

120


2008-7 2009-1 2009-7 2010-1 2010-7 2011-1 2011-7 2012-1

Time (Date)


Oil

Reco

very

Fac

tor

SCTR

0

10

20

30

40

50

60


2008-7 2009-1 2009-7 2010-1 2010-7 2011-1 2011-7 2012-1

Time (Date)


120

Stea

m O

il R

atio

Cum

SC

TR (m

3m

3)

00

05

10

15

20

25

30

35

40

45


2008-7 2009-1 2009-7 2010-1 2010-7 2011-1 2011-7 2012-1

Time (Date)


Stea

m C

ham

ber

Volu

me

SCTR

(m3)

0

10000

20000

30000

40000

50000


2008-7 2009-1 2009-7 2010-1 2010-7 2011-1 2011-7 2012-1

Time (Date)


121















Oil

Prod

Rat

e SC

TR (m

3da

y)

160

140

120

100

80

60

40

20

0


2008-7 2009-1 2009-7 2010-1 2010-7 2011-1 2011-7 2012-1 Time (Date)


122

Oil

Rec

over

y Fa

ctor

SC

TR

0

10

20

30

40

50

60


2008-7 2009-1 2009-7 2010-1 2010-7 2011-1 2011-7 2012-1

Time (Date)


Stea

m O

il R

atio

Cum

SC

TR (m

3m

3)

00

05

10

15

20

25

30

35

40

45


2008-7 2009-1 2009-7 2010-1 2010-7 2011-1 2011-7 2012-1

Time (Date)


123

Stea

m C

ham

ber

Volu

me

SCTR

(m3)

60000

50000

40000

30000

20000

10000

0


2008-7 2009-1 2009-7 2010-1 2010-7 2011-1 2011-7 2012-1 Time (Date)
















124













Oil

Prod

Rat

e SC

TR (m

3da

y)

160

140

120

100

80

60

40

20

0 2008-7 2009-1 2009-7 2010-1 2010-7 2011-1 2011-7 2012-1


Time (Date)


125

Oil

Rec

over

y Fa

ctor

SC

TR

0

10

20

30

40

50

60


2008-7 2009-1 2009-7 2010-1 2010-7 2011-1 2011-7 2012-1

Time (Date)


Stea

m O

il R

atio

Cum

SC

TR (m

3m

3)

00

10

20

30

40

50

60

70

80

90

100


2008-7 2009-1 2009-7 2010-1 2010-7 2011-1 2011-7 2012-1

Time (Date)


126

60000

50000

40000

30000

20000

10000

0

Time (Date)








evaluated









Stea

m C

ham

ber

Volu

me

SCTR

(m3)


2008-7 2009-1 2009-7 2010-1 2010-7 2011-1 2011-7 2012-1

127



base case







Oil

Prod

Rat

e SC

TR (m

3da

y)

180

160

140

120

100

80

60

40

20

0


2008-7 2009-1 2009-7 2010-1 2010-7 2011-1 2011-7 2012-1 Time (Date)


128

Oil

Rec

over

y Fa

ctor

SC

TR

0

10

20

30

40

50

60


2008-7 2009-1 2009-7 2010-1 2010-7 2011-1 2011-7 2012-1

Time (Date)


Stea

m O

il R

atio

Cum

SC

TR (m

3m

3)

00

05

10

15

20

25

30

35

40

45


2008-7 2009-1 2009-7 2010-1 2010-7 2011-1 2011-7 2012-1

Time (Date)


129

Stea

m C

ham

ber

Volu

me

SCTR

(m3)

60000

50000

40000

30000

20000

10000

0


2008-7 2009-1 2009-7 2010-1 2010-7 2011-1 2011-7 2012-1 Time (Date)

















130



Oil

Prod

Rat

e SC

TR (m

3da

y)

140

120

100

80

60

40

20

0


2008-7 2009-1 2009-7 2010-1 2010-7 2011-1 2011-7 2012-1

Time (Date)


131

Oil

Rec

over

y Fa

ctor

SC

TR

0

10

20

30

40

50

60


2008-7 2009-1 2009-7 2010-1 2010-7 2011-1 2011-7 2012-1

Time (Date)


Stea

m O

il R

atio

Cum

SC

TR (m

3m

3)

00

05

10

15

20

25

30

35

40

45


2008-7 2009-1 2009-7 2010-1 2010-7 2011-1 2011-7 2012-1

Time (Date)


132

Stea

m C

ham

ber V

olum

e SC

TR (m

3)

60000

50000

40000

30000

20000

10000

0


2008-7 2009-1 2009-7 2010-1 2010-7 2011-1 2011-7 2012-1 Time (Date)







producer





increased by 138

133

Oil

Prod

Rat

e SC

TR (m

3da

y)

0

20

40

60

80

100

120


2008-7 2009-1 2009-7 2010-1 2010-7 2011-1 2011-7 2012-1

Time (Date)


Oil

Reco

very

Fac

tor

SCTR

0

10

20

30

40

50

60


2008-7 2009-1 2009-7 2010-1 2010-7 2011-1 2011-7 2012-1

Time (Date)


134

50

45

40

35

30

25

20

15

10

05

00


2008-7 2009-1 2009-7 2010-1 2010-7 2011-1 2011-7 2012-1

Time (Date)


Stea

m C

ham

ber

Volu

me

SCTR

(m3)

0

10000

20000

30000

40000

50000


2008-7 2009-1 2009-7 2010-1 2010-7 2011-1 2011-7 2012-1

Time (Date)

Stea

m O

il R

atio

Cum

SC

TR (m

3m

3)


135












by 55

Oil

Prod

Rat

e SC

TR (m

3da

y)

140

120

100

80

60

40

20

0


2008-7 2009-1 2009-7 2010-1 2010-7 2011-1 2011-7 2012-1 Time (Date)


136

Oil

Rec

over

y Fa

ctor

SC

TR

0

10

20

30

40

50

60


2008-7 2009-1 2009-7 2010-1 2010-7 2011-1 2011-7 2012-1

Time (Date)


Stea

m O

il R

atio

Cum

SC

TR (m

3m

3)

00

05

10

15

20

25

30

35

40

45


2008-7 2009-1 2009-7 2010-1 2010-7 2011-1 2011-7 2012-1

Time (Date)


137

Stea

m C

ham

ber

Volu

me

SCTR

(m3)

60000

50000

40000

30000

20000

10000

0


2008-7 2009-1 2009-7 2010-1 2010-7 2011-1 2011-7 2012-1 Time (Date)
















138



Oil

Prod

Rat

e SC

TR (m

3da

y)

140

120

100

80

60

40

20

0


2008-7 2009-1 2009-7 2010-1 2010-7 2011-1 2011-7 2012-1

Time (Date)


139

Oil

Rec

over

y Fa

ctor

SC

TR

0

10

20

30

40

50

60


2008-7 2009-1 2009-7 2010-1 2010-7 2011-1 2011-7 2012-1

Time (Date)


Stea

m O

il R

atio

Cum

SC

TR (m

3m

3)

00

05

10

15

20

25

30

35

40

45


2008-7 2009-1 2009-7 2010-1 2010-7 2011-1 2011-7 2012-1

Time (Date)


140

Stea

m C

ham

ber

Volu

me

SCTR

(m3)

70000

60000

50000

40000

30000

20000

10000

0


2008-7 2009-1 2009-7 2010-1 2010-7 2011-1 2011-7 2012-1 Time (Date)


5289 C-SAGD















141
















142













Oil

Prod

Rat

e SC

TR (m

3da

y)

300

270

240

210

180

150

120

90

60

30

0


2008-7 2009-1 2009-7 2010-1 2010-7 2011-1 2011-7 2012-1 Time (Date)


143

Oil

Rec

over

y Fa

ctor

SC

TR

0

10

20

30

40

50

60

70


2008-7 2009-1 2009-7 2010-1 2010-7 2011-1 2011-7 2012-1

Time (Date)


Stea

m O

il R

atio

Cum

SC

TR (m

3m

3)

00

10

20

30

40

50

60

70

80

90


2008-7 2009-1 2009-7 2010-1 2010-7 2011-1 2011-7 2012-1

Time (Date)


144

Stea

m C

ham

ber

Volu

me

SCTR

(m3)

90000

80000

70000

60000

50000

40000

30000

20000

10000

0


2008-7 2009-1 2009-7 2010-1 2010-7 2011-1 2011-7 2012-1 Time (Date)







53 Lloydminster









Net

145













Overburden

Underburden

Steam Chamber

Underburden

Overburden











146
























531 Reservoir Model







147


reservoir model

10

500

90











Lake reservoirs






148







E+5m3











149

10000

Visc

osity

cp

1000

100

10

1 0 50 100 150 200 250

TemperatureC
















300

150









Injector




Injector Producer X
















151


















small as possible









152

Oil

Rat

e SC

(m3

day)

0

20

40

60

80

100

120

140

160

180


2009 2010 2011 2012 2013 2014 2015 2016

Time (Date)


Oil

Rec

over

y Fa

ctor

SC

TR

0

15

30

45

60


2009 2010 2011 2012 2013 2014 2015 2016

Time (Date)


153

Cum

Ste

am O

il R

atio

(m3

m3)

00

10

20

30

40

50


2009 2010 2011 2012 2013 2014 2015 2016

Time (Date)


Stea

m C

ham

ber V

olum

e SC

TR (m

3)

00e+0

20e+4

40e+4

60e+4

80e+4


2009 2010 2011 2012 2013 2014 2015 2016

Time (Date)


154







be larger than 30m













5-91 5-92 and 5-93






vertical injectors

155

Oil

Rat

e SC

(m3

day)

0

30

60

90

120

150

180


2009 2010 2011 2012 2013 2014 2015 2016

Time (Date)


Oil

Rec

over

y Fa

ctor

SC

TR

0

12

24

36

48

60

72


2009 2010 2011 2012 2013 2014 2015 2016

Time (Date)


156

Stea

m O

il R

atio

Cum

SC

TR (m

3m

3)

00

10

20

30

40

50


2009 2010 2011 2012 2013 2014 2015 2016

Time (Date)


Stea

m C

ham

ber V

olum

e SC

TR (m

3)

00e+0

20e+4

40e+4

60e+4

80e+4


2009 2010 2011 2012 2013 2014 2015 2016

Time (Date)


157

5363 C-SAGD





















158

Oil

Rat

e SC

(m3

day)

0

30

60

90

120

150

180


2009 2010 2011 2012 2013 2014 2015 2016

Time (Date)


Oil

Rec

over

y Fa

ctor

SC

TR

0

10

20

30

40

50

60

70

80


2009 2010 2011 2012 2013 2014 2015 2016

Time (Date)


159

Stea

m O

il R

atio

Cum

SC

TR (m

3m

3)

00

10

20

30

40

50

60

70


2009 2010 2011 2012 2013 2014 2015 2016

Time (Date)


Stea

m C

ham

ber V

olum

e SC

TR (m

3)

00e+0

20e+4

40e+4

60e+4

80e+4

10e+5


2009 2010 2011 2012 2013 2014 2015 2016

Time (Date)


160













Oil

Rat

e SC

(m3

day)

180

160

140

120

100

80

60

40

20

0


2009 2010 2011 2012 2013 2014 2015 2016 Time (Date)


161

Oil

Rec

over

y Fa

ctor

SC

TR

0

10

20

30

40

50

60

70


2009 2010 2011 2012 2013 2014 2015 2016

Time (Date)


Stea

m O

il R

atio

Cum

SC

TR (m

3m

3)

00

10

20

30

40

50


2009 2010 2011 2012 2013 2014 2015 2016

Time (Date)


162

Stea

m C

ham

ber V

olum

e SC

TR (m

3)

10e+5

80e+4

60e+4

40e+4

20e+4

00e+0


2009 2010 2011 2012 2013 2014 2015 2016 Time (Date)














163

Oil

Rat

e SC

(m3

day)

0

20

40

60

80

100

120

140

160


2009 2010 2011 2012 2013 2014 2015 2016

Time (Date)


Oil

Rec

over

y Fa

ctor

SC

TR

0

15

30

45

60

75


2009 2010 2011 2012 2013 2014 2015 2016

Time (Date)


164

Stea

m O

il R

atio

Cum

SC

TR (m

3m

3)

00

10

20

30

40

50

60


2009 2010 2011 2012 2013 2014 2015 2016

Time (Date)


Stea

m C

ham

ber V

olum

e SC

TR (m

3)

00e+0

20e+4

40e+4

60e+4

80e+4

10e+5


2009 2010 2011 2012 2013 2014 2015 2016

Time (Date)


165









reservoirs

CHAPTER 6


DISUCSSIONS

167






























AGSCO sand

168




Porosity

Soi

Swi

Viso Ti cp

Well Spacing cm























169


















y = 26222x

R2 = 09891

0

10

20

30

40

50

60

70

80

0 005 01 015 02 025 03

∆PL psicm

QA

ccmincm

2

Measured

Linear Regression


170

1

10

100

1000

10000

100000

0 50 100 150 200 250 300

Measured Data


Temperature degC

Viscosity

cp


1

10

100

1000

10000

100000

1000000

0 50 100 150 200 250 300

Temperature C

Visco

cp

Measured Date



171

























experiment






172




















temperature







173

0

5

10

15

20

25

0 5 10 15 20 25 30 Time hr

Oil

Rat

e c

cm

in



0

1

2

3

4

5

6

7

8

0 5 10 15 20 25 30 Time hr

cSO

R c

ccc



174

0

10

20

30

40

50

60

70

80

90

100

0 5 10 15 20 25 30 Time hr

WC

UT



0

5

10

15

20

25

30

35

40

45

0 5 10 15 20 25 30 Time hr

RF



175











0

5

10

15

20

25

30

35

40

45

50

0 2 4 6 8 10 12 14 16 18 20 Time hr

Oil

Rat

e c

cm

in



176

00

05

10

15

20

25

30

35

0 2 4 6 8 10 12 14 16 18 20 Time hr

cSO

R c

ccc



0

10

20

30

40

50

60

70

80

0 2 4 6 8 10 12 14 16 18 20 Time hr

WC

UT



177

0

5

10

15

20

25

30

35

40

45

0 2 4 6 8 10 12 14 16 18 20 Time hr

RF














toe of the injector

178

0

20

40

60

80

100

120

0 1 2 3 4 5 Time hr

Tem

pera

ture

C

D15 D25 D35 D45 D55

0

20

40

60

80

100

120

0 4 8 12 16 20 Time hr

Tem

pera

ture

C

D15 D25 D35 D45 D55


179









Layer A Layer B

Layer C

Layer D




Cross Section 5















180









Injector

Producer


181

Injector

Producer

Injector

Producer



182

Injector

Producer

Injector

Producer



183

Injector

Producer
















pressure

184








well


185

140 6000

120

100

80

60

40

20

00


5000

4000

3000

2000

1000

0

Wat

er R

ate

SC (c

m3

min

)O

il R

ate

SC (c

m3

min

)

Cum

ulat

ive

Wat

er S

C (c

m3)

C

umul

ativ

e O

il SC

(cm

3)

0 4 8 12 16 20 24 28 Time (hr)


28 14000

24

20

16

12

8

4

0


12000

10000

8000

6000

4000

2000

0 0 4 8 12 16 20 24 28

Time (hr)


186

Wat

er R

ate

SC (c

m3

min

)

Cum

ulat

ive

Wat

er S

C (c

m3)

0

5

10

15

20

25

30

0

3000

6000

9000

12000

15000

18000


0 4 8 12 16 20 24 28 Time (hr)


Stea

m C

ham

ber V

olum

e SC

TR (c

m3)

0 4 8 12 16 20 24 28 0

500

1000

1500

2000

2500

3000

3500


Time (hr)


187
















~90



Figure 6-25 26 27 and 28












188



experiments



























189

0

2

4

6

8

10

12

14

16

0 5 10 15 20 25 30 Time hr

Oil

Rat

e c

cm

in



0

1

2

3

4

5

6

7

8

0 5 10 15 20 25 30 Time hr

cSO

R c

ccc



190

0

10

20

30

40

50

60

70

80

90

100

0 5 10 15 20 25 30 Time hr

WC

UT



0

10

20

30

40

50

60

0 5 10 15 20 25 30 Time hr

RF



191

0

20

40

60

80

100

120

0 1 2 3 Time hr

Tem

pera

ture

C

D31 D33 D35 D37 D39

0

20

40

60

80

100

120

0 2 4 6 8 10 12 14 16 Time hr

Tem

pera

ture

C

D31 D33 D35 D37 D39


192








Injector Producer


193

Injector Producer


Injector Producer


194

Injector Producer


Injector Producer


195
















Injector

Producer


196













saturation pressure








197


198

Oil

Rat

e SC

(cm

3m

in)

Cum

ulat

ive

Oil

SC (c

m3)

0

4

8

12

16

20

0

2000

4000

6000

8000


0 4 8 12 16 20

Time (hr)


Wat

er R

ate

SC (c

m3

min

)

Cum

ulat

ive

Wat

er S

C (c

m3)

0

3

6

9

12

15

0

2000

4000

6000

8000


0 4 8 12 16 20

Time (hr)


199

Wat

er R

ate

SC (c

m3

min

)

Cum

ulat

ive

Wat

er S

C (c

m3)

0

3

6

9

12

15

18

0

2000

4000

6000

8000

10000


0 4 8 12 16 20

Time (hr)


Stea

m C

ham

ber V

olum

e SC

TR (c

m3)

0

1000

2000

3000

4000

5000

6000

7000


0 4 8 12 16 20

Time (hr)


200





physical model


























201







stable





















202

0

2

4

6

8

10

12

14

16

18

20

0 4 8 12 16 20 Time hr

Oil

Rat

e c

cm

in

Fifth Experiment


00

05

10

15

20

25

30

0 4 8 12 16 20 Time hr

cSO

R c

ccc

Fifth Experiment


203

0

10

20

30

40

50

60

70

80

90

0 4 8 12 16 20 Time hr

WC

UT

Fifth Experiment


0

10

20

30

40

50

60

0 4 8 12 16 20 Time hr

RF

Fifth Experiment


204

0

20

40

60

80

100

120

0 1 2 3 4 5 Time hr

Tem

pera

ture

C

D15 D25 D35 D45 D55

0

20

40

60

80

100

120

0 4 8 12 16 20 Time hr

Tem

pera

ture

C

D15 D25 D35 D45 D55


205









Injector

Producer


206

Injector

Producer

Injector

Producer



207

Injector

Producer

Injector

Producer



208

Injector

Producer


Injector

Producer


209











1 2 3

4 5 6

7 8 9

50 cm

8 cm 50 cm









entire layer





in φΔSo value

210

85 255

425

425

255

85

222 233

220

239

223

267

217

200

251

10

12

14

16

18

20

22

24

26

28

φΔS

o

X cm

Y cm

Mid Layer














section

211

85 255

425

425

255

85

220 224

210 211 212

228

197 200

244

10

12

14

16

18

20

22

24

26

φΔS

o

X cm

Y cm

Top Layer

















212









213

Oil

Rat

e SC

(cm

3m

in)

Cum

ulat

ive

Oil

SC (c

m3)

00

50

100

150

200

0

2000

4000

6000

8000


0 200 400 600 800 1000 1200 Time (min)


Wat

er R

ate

SC (c

m3

min

)

Cum

ulat

ive

Wat

er S

C (c

m3)

0

6

12

18

24

30

0

3000

6000

9000

12000


0 200 400 600 800 1000 1200 Time (min)


214

Wat

er R

ate

SC (c

m3

min

)

Cum

ulat

ive

Wat

er S

C (c

m3)

0

7

14

21

28

35

42

0

3000

6000

9000

12000

15000


0 200 400 600 800 1000 1200 Time (min)


Stea

m C

ham

ber V

olum

e SC

TR (c

m3)

0

2000

4000

6000


0 200 400 600 800 1000 1200 Time (min)


215








pairs

















216

0

5

10

15

20

25

0 4 8 12 16 20

Time hr

Oil

Rat

e c

cm

in



00

05

10

15

20

25

30

35

0 4 8 12 16 20 Time hr

cSO

R c

ccc



217

0

10

20

30

40

50

60

70

80

90

0 4 8 12 16 20 Time hr

WC

UT



0

10

20

30

40

50

60

0 4 8 12 16 20 Time hr

RF



218
































219


reservoir








its heel








PVinj












220

0

20

40

60

80

100

120

0 1 2 3 4 Time hr

Tem

pera

ture

C

D31 D33 D35 D37 D39

0

20

40

60

80

100

120

0 2 4 6 8 10 12 14 Time hr

Tem

pera

ture

C

D31 D33 D35 D37 D39


221

Injector Producer


Injector Producer


222

Injector Producer


Injector Producer


223

Injector Producer


Injector Producer


224

Injector

Producer


















225





section

Mid Layer

14

13

12

11

85

255 10

425

136

132

129

126 127

121

131

123

122

Y cm 425 85

255

X cm

φΔS

o


226

85 255

425

425

255

85

229 223

253

235

225 237 235

225 222

10

12

14

16

18

20

22

24

26

φΔS

o

X cm

Y cm

Top Layer
















227



nearly perfect


228

24 12000

20

16

12

8

4

0


10000

8000

6000

4000

2000

0

Wat

er R

ate

SC (c

m3

min

)O

il R

ate

SC (c

m3

min

)

Cum

ulat

ive

Wat

er S

C (c

m3)

C

umul

ativ

e O

il SC

(cm

3)

0 2 4 6 8 10 12 14 Time (hr)


30 12000

25

20

15

10

5

0


10000

8000

6000

4000

2000

0 0 2 4 6 8 10 12 14

Time (hr)


229

28 14000

Wat

er R

ate

SC (c

m3

min

)

24

20

16

12

8

4

0


10000

8000

6000

4000

2000

0

Cum

ulat

ive

Wat

er S

C (c

m3)

0 2 4 6 8 10 12 14 Time (hr)


Stea

m C

ham

ber V

olum

e SC

TR (c

m3)

0

1000

2000

3000

4000

5000

6000

7000


0 2 4 6 8 10 12 14 Time (hr)


230
















Injector

18 cm

5 cm Producer











231















classic pattern













Figure 6-86

232

cSO

R c

ccc

O

il R

ate

cc

min

35


30

25

20

15

10

5

0 0

30

35

4 8 12

Time hr


16 20


25

20

15

10

05

00 0 4 8 12

Time hr


16 20

233

RF

WC

UT

70

80

90 Fifth Experiment


60

50

40

30

20

10

0 0 4 8

Time hr 12 16 20

50

60



40

30

20

10

0 0 4 8 12 16 20

Time hr


234






Injector

Producer 5 cm

18 cm

D15 D35 D55

D45D25

















235

0

20

40

60

80

100

120

0 2 4 6 8 10 Time hr

Tem

pera

ture

C

D15 D25 D35 D45 D55

0

20

40

60

80

100

120

0 1 2 3 4 Time hr

Tem

pera

ture

C

D15 D25 D35 D45 D55


236
































237



238



239


Injector

Producer


240






layer of the model









section

85 255

425

425

255

85

257

216 228

267

259 262 265

254 251

10

12

14

16

18

20

22

24

26

28

φΔS

o

X cm

Y cm

Top Layer


241


















should be so low













242









243

12000 42

35

28

21

14

7

0


10000

8000

6000

4000

2000

0

Wat

er R

ate

SC (c

m3

min

)O

il R

ate

SC (c

m3

min

)

Cum

ulat

ive

Wat

er S

C (c

m3)

C

umul

ativ

e O

il SC

(cm

3)

0 2 4 6 8 10 12 Time (hr)


25

20

15

10

5


00 20 40 60 80 100 120

10000

8000

6000

4000

2000

0

Time (hr)


0

244

30 12000

25

20

15

10

5

0


10000

8000

6000

4000

2000

0

Stea

m C

ham

ber V

olum

e SC

TR (c

m3)

W

ater

Rat

e SC

(cm

3m

in)

Cum

ulat

ive

Wat

er S

C (c

m3)

0 2 4 6 8 10 12 Time (hr)



0 2 4 6 8 10 12

8000

6000

4000

2000

0

Time (hr)


245










CHAPTER 7


247

71 Conclusions





simulation study


























248












model
















reservoirs




249
























directions




and chamber volume




250






72 Recommendations















reservoir










251






down



project operation






best pattern

252


2000



August 1981


53 1942







1987



Feb 1988












30- Sept 3 1997


253




















Vol54 2006












254










1995




February 26-28 1996


















255






















December 2008









November 2000

256













amp Eng 10 (1) 19-34 SPE-97742-PA



















257













7-9 1991



63) httpwwwercbca


httpwwwercbca








11 1980




httpwwwercbca


258


Vol15 No2 June 2006



1993



























259


Vol30 No2 June 1982






























260























iii











iv

ACKNOWLEDGEMENTS























support

v

DEDICATION



vi

TABLE OF CONTENTS








vii











viii










ix




REFERENCES 252

x

LIST OF TABLES














experiments 241

xi

LIST OF FIGURES





























xii




















for sand analysis77










xiii






























xiv






























xv





























xvi






























xvii






























xviii






























xix






















xx


Symbol Definition


xxi

Greek Symbols


CHAPTER 1

INTRODUCTION

2










attentions





10000000

1000000

100000

10000

1000

100

1


Visc

osity

cp

Athabasca Cold Lake

0 50 100 150 200 250 Temperature C

10

3















Overburden

Underburden

Steam Chamber

Net Pay








4





3) Wind down


























5















T=Ts

T=TR

θ

dt t x

y ⎟ ⎠ ⎞

⎜ ⎝ ⎛ part

part







6








kgα ⎛ ⎞t 2



1 tD 2

Y 1 (14) = minus ⎛ ⎞ ⎜ ⎟2 X⎝ ⎠

X = x h (15)

Y = y h (16)





7

0

01

02

03

04

05

06

07

08

09

1


Ver

tical

Dist

ance

yh

02 06

04 08

1 12

14 16

18 2





⎡ TS ⎛ 1 1 ⎞ dT ⎤minus1

m = ⎢ν minus ⎥ (18) ν ν T T⎣

s intTR ⎜⎝ R

⎟⎠ minus R ⎦









8





[3]

3 o s

kgh B S mαφ ν

= Δ

(110)





(111) [1]

αtFo = h2 (111)



B3 = tD (113) Fo



9























heterogeneities



model





10













Parameter

Net Pay m

Permeability mD

φΔSo

microR cp

micros cp

m









11



























1315 Heterogeneity




12












two cases







1316 Wettability









recovery

13

1317 Water Leg











1318 Gas Cap







132 Well Design

1321 Completion









14








same vertical plane

















1331 Pressure






15










1332 Temperature





















16


























1337 Wind down




17






























18




















physical model




19



Producer Producer


Injector
























20





reservoir









chapter as well

CHAPTER 2

LITERATURE REVIEW

22

























left behind






23





vital
















SAGD process [7]











24
































25
































26















conditions [9]





27




Top of Formation


Injector

Producer

Base of Formation













28






















29











producer

30













31



















32















33






























34



















35





























36






























37














percent [59 60]


















38




CHAPTER 3


40















41






presented


sands deposit










42







anticline feature







43














44












exist





45













pperM


Lower C

retaceous

Lower

Mannville

McMurray McMurray









46















Lake

















47






distance























48


the areal extension




Clearwater

Upper M


Lower C

retaceous

Lower M

annville

McMurray McMurray



49













in Alberta







50




















51














52





















53





























in Figure 3-14

54











to 4m thick

55


Colony

McLaren

Waseca U

pperGrand Rapids

Clearwater

Sparky

GP

RL-Rex

Lloydminster

Cummings

Middle

Lower C

retaceous

Mannville G

roup

McMurray Dina

Low

er

Mainly Sand


Shale






coal and shale










56





to 2000 mD


















57

















58



Darcyrsquos











oil wet as well


















59
















60




heterogeneities







of these factors





extension
















61






CHAPTER 4


PROCEDURE

63








Steam

Water

Load Cell

Steam

Model Temperature








64






















70 987

30 1000

40 1000





65













25 cm

50 cm













66
















67

4

3 A B C D E F G







412 Steam Generator

















physical model

68






23rdquo

85rdquo

PTB

PTE

215rdquo

PTD

175rdquo

PTC

130rdquo

PTA40rdquo










69






24 cm 25 cm












sensor

70



Senor Z31 Z38 Z41

Rotor


Radius Ri mm 1572 1901 2071

+- ΔRi mm 0002 0004 0004

Length mm 55 55 55

+- L mm 003 003 003

Cup



+- ΔRa mm 0004 0004 0004


71

















additional water










72



73


























fill the model




74


with water

























75

1

2

3



3 Connection valves



442 SAGD Experiment












76

















77

1 2 3

4 5 6

7 8 9














experiment



78







444 Cleaning




washed with toluene

CHAPTER 5


80







51 Athabasca






511 Reservoir Model















81


30 500

20


Injector

Producer










82




















component

83


P




10

100

1000

10000

100000

1000000

10000000

100000000

Visc

osity

cp

00 500 1000 1500 2000 2500 3000

Temperature C









pairs



84





85









515 Wellbore Model








86



of the wellbore























224 degC




87



















reservoirs

5m

Injector

Producer

Injectors

Producer 5m

Injector

Producer


Producer

Injector

Producer



88

5181 Base Case




























cSOR

89

Oil

Prod

Rat

e SC

TR (m

3da

y)

0

20

40

60

80


1 2 3 4


2009 2010 2011 2012 2013 2014

Time (Date)


Oil

Rec

over

y Fa

ctor

SC

TR

0

10

20

30

40

50

60

70


2009 2010 2011 2012 2013 2014

Time (Date)


90

Stea

m O

il R

atio

Cum

SC

TR (m

3m

3)

00

05

10

15

20

25

30

35

40

45


2009 2010 2011 2012 2013 2014

Time (Date)


Stea

m C

ham

ber V

olum

e S

CTR

(m3)

0

10000

20000

30000

40000

50000


2009 2010 2011 2012 2013 2014 Time (Date)


91

1 2

3 4


Stea

m Q

ualit

y D

ownh

ole

00

01

02

03

04

05

06

07

08

09

10


2009 2010 2011 2012 2013 2014

Time (Date)


92































93


depletion period










degC cS cS m m2D

D m m Mpa

cS

Pres

sure

(kPa

)

2480

2482

2484

2486

2488

2490

2492

2494

2496

2498

2500


2009 2010 2011 2012 2013 2014 Time (Date)


94

0

20

40

60

80

100

120

140

160

0 1 2 3 4 5 6 Time Year

Oil

Prod

uctio

n R

ate

m3 d















case




95




















96

Oil

Prod

Rat

e SC

TR (m

3da

y)

0

20

40

60

80


2009 2010 2011 2012 2013 2014

Time (Date)


Oil

Rec

over

y Fa

ctor

SC

TR

0

10

20

30

40

50

60


2009 2010 2011 2012 2013 2014

Time (Date)


97

Stea

m O

il R

atio

Cum

SC

TR (m

3m

3)

00

05

10

15

20

25

30

35

40

45


2009 2010 2011 2012 2013 2014

Time (Date)


Stea

m C

ham

ber V

olum

e SC

TR (m

3)

0

10000

20000

30000

40000

50000


2009 2010 2011 2012 2013 2014

Time (Date)


98

























99

Oil

Rat

e SC

(m3

day)

0

30

60

90

120


2009 2010 2011 2012 2013 2014 2015 2016 2017

Time (Date)


Oil

Rec

over

y Fa

ctor

SC

TR

0

10

20

30

40

50

60


2009 2010 2011 2012 2013 2014 2015 2016 2017

Time (Date)


100

Stea

m O

il R

atio

Cum

SC

TR (m

3m

3)

00

10

20

30

40

50

60

70

80

90


2009 2010 2011 2012 2013 2014 2015 2016 2017

Time (Date)


Stea

m C

ham

ber V

olum

e SC

TR (m

3)

0

10000

20000

30000

40000

50000

60000


2009 2010 2011 2012 2013 2014 2015 2016 2017

Time (Date)


101



























reservoir

102

Oil

Prod

Rat

e SC

TR (m

3da

y)

0

20

40

60

80


2009 2010 2011 2012 2013 2014 Time (Date)


Oil

Rec

over

y Fa

ctor

SC

TR

0

10

20

30

40

50

60


2009 2010 2011 2012 2013 2014 Time (Date)


103

Stea

m O

il R

atio

Cum

SC

TR (m

3m

3)

00

05

10

15

20

25

30

35

40

45


2009 2010 2011 2012 2013 2014 Time (Date)


Stea

m C

ham

ber V

olum

e SC

TR (m

3)

0

10000

20000

30000

40000

50000


2009 2010 2011 2012 2013 2014 Time (Date)


104

One Year Five Years








investigated










circulation

50

105

70

Oil

Rec

over

y Fa

ctor

SC

TR

Ste

am O

il R

atio

Cum

SC

TR (m

3m

3)

60

50

40

30

20

10

0

Time (Date) 2009 2010 2011 2012 2013 2014



45

40

35

30

25

20

15

10

05

00

Time (Date) 2008-1-1 2009-5-15 2010-9-27 2012-2-9 2013-6-23 2014-11-5



106

Oil

Rat

e SC

(m3

day)

0

20

40

60

80


2009 2010 2011 2012 2013 2014 Time (Date)


Oil

Rec

over

y Fa

ctor

SC

TR

0

10

20

30

40

50

60


2009 2010 2011 2012 2013 2014 Time (Date)


107

Ste

am O

il R

atio

Cum

SC

TR (m

3m

3)

00

05

10

15

20

25

30

35

40

45


2008-1-1 2009-5-15 2010-9-27 2012-2-9 2013-6-23 2014-11-5 Time (Date)


Stea

m C

ham

ber V

olum

e SC

TR (m

3)

0

10000

20000

30000

40000

50000

60000


2009 2010 2011 2012 2013 2014 Time (Date)


108















less than 3 months









109

Oil

Prod

Rat

e SC

TR (m

3da

y)

0

20

40

60

80


2009 2010 2011 2012 2013 2014

Time (Date)


Oil

Rec

over

y Fa

ctor

SC

TR

0

10

20

30

40

50

60


2009 2010 2011 2012 2013 2014

Time (Date)


110

Stea

m O

il R

atio

Cum

SC

TR (m

3m

3)

00

05

10

15

20

25

30

35

40

45


2009 2010 2011 2012 2013 2014

Time (Date)


Stea

m C

ham

ber V

olum

e SC

TR (m

3)

0

10000

20000

30000

40000

50000


2009 2010 2011 2012 2013 2014

Time (Date)


111
















100

80

60

40

20

0

Oil

Prod

Rat

e SC

TR (m

3da

y)


2009 2010 2011 2012 2013 2014 Time (Date)


112

Oil

Rec

over

y Fa

ctor

SC

TR

0

10

20

30

40

50

60


2009 2010 2011 2012 2013 2014

Time (Date)


Stea

m O

il R

atio

Cum

SC

TR (m

3m

3)

00

05

10

15

20

25

30

35

40

45


2009 2010 2011 2012 2013 2014

Time (Date)


113

Stea

m C

ham

ber

Volu

me

SCTR

(m3)

70000

60000

50000

40000

30000

20000

10000

0


2009 2010 2011 2012 2013 2014 Time (Date)


52 Cold Lake






521 Reservoir Model








114

20

500

30


















115

1000000

100000

10000

1000

100

10

1

Visc

osity

cp

0 50 100 150 200 250 Temperature C










300

116







525 Wellbore Model













producer







117










5m

Injector

Producer

Injectors

Producer XY

Injector

Producer





Injector Producer X



5281 Base Case









118







recovery factor














119

Oil

Prod

Rat

e SC

TR (m

3da

y)

0

20

40

60

80

100

120


2008-7 2009-1 2009-7 2010-1 2010-7 2011-1 2011-7 2012-1

Time (Date)


Oil

Reco

very

Fac

tor

SCTR

0

10

20

30

40

50

60


2008-7 2009-1 2009-7 2010-1 2010-7 2011-1 2011-7 2012-1

Time (Date)


120

Stea

m O

il R

atio

Cum

SC

TR (m

3m

3)

00

05

10

15

20

25

30

35

40

45


2008-7 2009-1 2009-7 2010-1 2010-7 2011-1 2011-7 2012-1

Time (Date)


Stea

m C

ham

ber

Volu

me

SCTR

(m3)

0

10000

20000

30000

40000

50000


2008-7 2009-1 2009-7 2010-1 2010-7 2011-1 2011-7 2012-1

Time (Date)


121















Oil

Prod

Rat

e SC

TR (m

3da

y)

160

140

120

100

80

60

40

20

0


2008-7 2009-1 2009-7 2010-1 2010-7 2011-1 2011-7 2012-1 Time (Date)


122

Oil

Rec

over

y Fa

ctor

SC

TR

0

10

20

30

40

50

60


2008-7 2009-1 2009-7 2010-1 2010-7 2011-1 2011-7 2012-1

Time (Date)


Stea

m O

il R

atio

Cum

SC

TR (m

3m

3)

00

05

10

15

20

25

30

35

40

45


2008-7 2009-1 2009-7 2010-1 2010-7 2011-1 2011-7 2012-1

Time (Date)


123

Stea

m C

ham

ber

Volu

me

SCTR

(m3)

60000

50000

40000

30000

20000

10000

0


2008-7 2009-1 2009-7 2010-1 2010-7 2011-1 2011-7 2012-1 Time (Date)
















124













Oil

Prod

Rat

e SC

TR (m

3da

y)

160

140

120

100

80

60

40

20

0 2008-7 2009-1 2009-7 2010-1 2010-7 2011-1 2011-7 2012-1


Time (Date)


125

Oil

Rec

over

y Fa

ctor

SC

TR

0

10

20

30

40

50

60


2008-7 2009-1 2009-7 2010-1 2010-7 2011-1 2011-7 2012-1

Time (Date)


Stea

m O

il R

atio

Cum

SC

TR (m

3m

3)

00

10

20

30

40

50

60

70

80

90

100


2008-7 2009-1 2009-7 2010-1 2010-7 2011-1 2011-7 2012-1

Time (Date)


126

60000

50000

40000

30000

20000

10000

0

Time (Date)








evaluated









Stea

m C

ham

ber

Volu

me

SCTR

(m3)


2008-7 2009-1 2009-7 2010-1 2010-7 2011-1 2011-7 2012-1

127



base case







Oil

Prod

Rat

e SC

TR (m

3da

y)

180

160

140

120

100

80

60

40

20

0


2008-7 2009-1 2009-7 2010-1 2010-7 2011-1 2011-7 2012-1 Time (Date)


128

Oil

Rec

over

y Fa

ctor

SC

TR

0

10

20

30

40

50

60


2008-7 2009-1 2009-7 2010-1 2010-7 2011-1 2011-7 2012-1

Time (Date)


Stea

m O

il R

atio

Cum

SC

TR (m

3m

3)

00

05

10

15

20

25

30

35

40

45


2008-7 2009-1 2009-7 2010-1 2010-7 2011-1 2011-7 2012-1

Time (Date)


129

Stea

m C

ham

ber

Volu

me

SCTR

(m3)

60000

50000

40000

30000

20000

10000

0


2008-7 2009-1 2009-7 2010-1 2010-7 2011-1 2011-7 2012-1 Time (Date)

















130



Oil

Prod

Rat

e SC

TR (m

3da

y)

140

120

100

80

60

40

20

0


2008-7 2009-1 2009-7 2010-1 2010-7 2011-1 2011-7 2012-1

Time (Date)


131

Oil

Rec

over

y Fa

ctor

SC

TR

0

10

20

30

40

50

60


2008-7 2009-1 2009-7 2010-1 2010-7 2011-1 2011-7 2012-1

Time (Date)


Stea

m O

il R

atio

Cum

SC

TR (m

3m

3)

00

05

10

15

20

25

30

35

40

45


2008-7 2009-1 2009-7 2010-1 2010-7 2011-1 2011-7 2012-1

Time (Date)


132

Stea

m C

ham

ber V

olum

e SC

TR (m

3)

60000

50000

40000

30000

20000

10000

0


2008-7 2009-1 2009-7 2010-1 2010-7 2011-1 2011-7 2012-1 Time (Date)







producer





increased by 138

133

Oil

Prod

Rat

e SC

TR (m

3da

y)

0

20

40

60

80

100

120


2008-7 2009-1 2009-7 2010-1 2010-7 2011-1 2011-7 2012-1

Time (Date)


Oil

Reco

very

Fac

tor

SCTR

0

10

20

30

40

50

60


2008-7 2009-1 2009-7 2010-1 2010-7 2011-1 2011-7 2012-1

Time (Date)


134

50

45

40

35

30

25

20

15

10

05

00


2008-7 2009-1 2009-7 2010-1 2010-7 2011-1 2011-7 2012-1

Time (Date)


Stea

m C

ham

ber

Volu

me

SCTR

(m3)

0

10000

20000

30000

40000

50000


2008-7 2009-1 2009-7 2010-1 2010-7 2011-1 2011-7 2012-1

Time (Date)

Stea

m O

il R

atio

Cum

SC

TR (m

3m

3)


135












by 55

Oil

Prod

Rat

e SC

TR (m

3da

y)

140

120

100

80

60

40

20

0


2008-7 2009-1 2009-7 2010-1 2010-7 2011-1 2011-7 2012-1 Time (Date)


136

Oil

Rec

over

y Fa

ctor

SC

TR

0

10

20

30

40

50

60


2008-7 2009-1 2009-7 2010-1 2010-7 2011-1 2011-7 2012-1

Time (Date)


Stea

m O

il R

atio

Cum

SC

TR (m

3m

3)

00

05

10

15

20

25

30

35

40

45


2008-7 2009-1 2009-7 2010-1 2010-7 2011-1 2011-7 2012-1

Time (Date)


137

Stea

m C

ham

ber

Volu

me

SCTR

(m3)

60000

50000

40000

30000

20000

10000

0


2008-7 2009-1 2009-7 2010-1 2010-7 2011-1 2011-7 2012-1 Time (Date)
















138



Oil

Prod

Rat

e SC

TR (m

3da

y)

140

120

100

80

60

40

20

0


2008-7 2009-1 2009-7 2010-1 2010-7 2011-1 2011-7 2012-1

Time (Date)


139

Oil

Rec

over

y Fa

ctor

SC

TR

0

10

20

30

40

50

60


2008-7 2009-1 2009-7 2010-1 2010-7 2011-1 2011-7 2012-1

Time (Date)


Stea

m O

il R

atio

Cum

SC

TR (m

3m

3)

00

05

10

15

20

25

30

35

40

45


2008-7 2009-1 2009-7 2010-1 2010-7 2011-1 2011-7 2012-1

Time (Date)


140

Stea

m C

ham

ber

Volu

me

SCTR

(m3)

70000

60000

50000

40000

30000

20000

10000

0


2008-7 2009-1 2009-7 2010-1 2010-7 2011-1 2011-7 2012-1 Time (Date)


5289 C-SAGD















141
















142













Oil

Prod

Rat

e SC

TR (m

3da

y)

300

270

240

210

180

150

120

90

60

30

0


2008-7 2009-1 2009-7 2010-1 2010-7 2011-1 2011-7 2012-1 Time (Date)


143

Oil

Rec

over

y Fa

ctor

SC

TR

0

10

20

30

40

50

60

70


2008-7 2009-1 2009-7 2010-1 2010-7 2011-1 2011-7 2012-1

Time (Date)


Stea

m O

il R

atio

Cum

SC

TR (m

3m

3)

00

10

20

30

40

50

60

70

80

90


2008-7 2009-1 2009-7 2010-1 2010-7 2011-1 2011-7 2012-1

Time (Date)


144

Stea

m C

ham

ber

Volu

me

SCTR

(m3)

90000

80000

70000

60000

50000

40000

30000

20000

10000

0


2008-7 2009-1 2009-7 2010-1 2010-7 2011-1 2011-7 2012-1 Time (Date)







53 Lloydminster









Net

145













Overburden

Underburden

Steam Chamber

Underburden

Overburden











146
























531 Reservoir Model







147


reservoir model

10

500

90











Lake reservoirs






148







E+5m3











149

10000

Visc

osity

cp

1000

100

10

1 0 50 100 150 200 250

TemperatureC
















300

150









Injector




Injector Producer X
















151


















small as possible









152

Oil

Rat

e SC

(m3

day)

0

20

40

60

80

100

120

140

160

180


2009 2010 2011 2012 2013 2014 2015 2016

Time (Date)


Oil

Rec

over

y Fa

ctor

SC

TR

0

15

30

45

60


2009 2010 2011 2012 2013 2014 2015 2016

Time (Date)


153

Cum

Ste

am O

il R

atio

(m3

m3)

00

10

20

30

40

50


2009 2010 2011 2012 2013 2014 2015 2016

Time (Date)


Stea

m C

ham

ber V

olum

e SC

TR (m

3)

00e+0

20e+4

40e+4

60e+4

80e+4


2009 2010 2011 2012 2013 2014 2015 2016

Time (Date)


154







be larger than 30m













5-91 5-92 and 5-93






vertical injectors

155

Oil

Rat

e SC

(m3

day)

0

30

60

90

120

150

180


2009 2010 2011 2012 2013 2014 2015 2016

Time (Date)


Oil

Rec

over

y Fa

ctor

SC

TR

0

12

24

36

48

60

72


2009 2010 2011 2012 2013 2014 2015 2016

Time (Date)


156

Stea

m O

il R

atio

Cum

SC

TR (m

3m

3)

00

10

20

30

40

50


2009 2010 2011 2012 2013 2014 2015 2016

Time (Date)


Stea

m C

ham

ber V

olum

e SC

TR (m

3)

00e+0

20e+4

40e+4

60e+4

80e+4


2009 2010 2011 2012 2013 2014 2015 2016

Time (Date)


157

5363 C-SAGD





















158

Oil

Rat

e SC

(m3

day)

0

30

60

90

120

150

180


2009 2010 2011 2012 2013 2014 2015 2016

Time (Date)


Oil

Rec

over

y Fa

ctor

SC

TR

0

10

20

30

40

50

60

70

80


2009 2010 2011 2012 2013 2014 2015 2016

Time (Date)


159

Stea

m O

il R

atio

Cum

SC

TR (m

3m

3)

00

10

20

30

40

50

60

70


2009 2010 2011 2012 2013 2014 2015 2016

Time (Date)


Stea

m C

ham

ber V

olum

e SC

TR (m

3)

00e+0

20e+4

40e+4

60e+4

80e+4

10e+5


2009 2010 2011 2012 2013 2014 2015 2016

Time (Date)


160













Oil

Rat

e SC

(m3

day)

180

160

140

120

100

80

60

40

20

0


2009 2010 2011 2012 2013 2014 2015 2016 Time (Date)


161

Oil

Rec

over

y Fa

ctor

SC

TR

0

10

20

30

40

50

60

70


2009 2010 2011 2012 2013 2014 2015 2016

Time (Date)


Stea

m O

il R

atio

Cum

SC

TR (m

3m

3)

00

10

20

30

40

50


2009 2010 2011 2012 2013 2014 2015 2016

Time (Date)


162

Stea

m C

ham

ber V

olum

e SC

TR (m

3)

10e+5

80e+4

60e+4

40e+4

20e+4

00e+0


2009 2010 2011 2012 2013 2014 2015 2016 Time (Date)














163

Oil

Rat

e SC

(m3

day)

0

20

40

60

80

100

120

140

160


2009 2010 2011 2012 2013 2014 2015 2016

Time (Date)


Oil

Rec

over

y Fa

ctor

SC

TR

0

15

30

45

60

75


2009 2010 2011 2012 2013 2014 2015 2016

Time (Date)


164

Stea

m O

il R

atio

Cum

SC

TR (m

3m

3)

00

10

20

30

40

50

60


2009 2010 2011 2012 2013 2014 2015 2016

Time (Date)


Stea

m C

ham

ber V

olum

e SC

TR (m

3)

00e+0

20e+4

40e+4

60e+4

80e+4

10e+5


2009 2010 2011 2012 2013 2014 2015 2016

Time (Date)


165









reservoirs

CHAPTER 6


DISUCSSIONS

167






























AGSCO sand

168




Porosity

Soi

Swi

Viso Ti cp

Well Spacing cm























169


















y = 26222x

R2 = 09891

0

10

20

30

40

50

60

70

80

0 005 01 015 02 025 03

∆PL psicm

QA

ccmincm

2

Measured

Linear Regression


170

1

10

100

1000

10000

100000

0 50 100 150 200 250 300

Measured Data


Temperature degC

Viscosity

cp


1

10

100

1000

10000

100000

1000000

0 50 100 150 200 250 300

Temperature C

Visco

cp

Measured Date



171

























experiment






172




















temperature







173

0

5

10

15

20

25

0 5 10 15 20 25 30 Time hr

Oil

Rat

e c

cm

in



0

1

2

3

4

5

6

7

8

0 5 10 15 20 25 30 Time hr

cSO

R c

ccc



174

0

10

20

30

40

50

60

70

80

90

100

0 5 10 15 20 25 30 Time hr

WC

UT



0

5

10

15

20

25

30

35

40

45

0 5 10 15 20 25 30 Time hr

RF



175











0

5

10

15

20

25

30

35

40

45

50

0 2 4 6 8 10 12 14 16 18 20 Time hr

Oil

Rat

e c

cm

in



176

00

05

10

15

20

25

30

35

0 2 4 6 8 10 12 14 16 18 20 Time hr

cSO

R c

ccc



0

10

20

30

40

50

60

70

80

0 2 4 6 8 10 12 14 16 18 20 Time hr

WC

UT



177

0

5

10

15

20

25

30

35

40

45

0 2 4 6 8 10 12 14 16 18 20 Time hr

RF














toe of the injector

178

0

20

40

60

80

100

120

0 1 2 3 4 5 Time hr

Tem

pera

ture

C

D15 D25 D35 D45 D55

0

20

40

60

80

100

120

0 4 8 12 16 20 Time hr

Tem

pera

ture

C

D15 D25 D35 D45 D55


179









Layer A Layer B

Layer C

Layer D




Cross Section 5















180









Injector

Producer


181

Injector

Producer

Injector

Producer



182

Injector

Producer

Injector

Producer



183

Injector

Producer
















pressure

184








well


185

140 6000

120

100

80

60

40

20

00


5000

4000

3000

2000

1000

0

Wat

er R

ate

SC (c

m3

min

)O

il R

ate

SC (c

m3

min

)

Cum

ulat

ive

Wat

er S

C (c

m3)

C

umul

ativ

e O

il SC

(cm

3)

0 4 8 12 16 20 24 28 Time (hr)


28 14000

24

20

16

12

8

4

0


12000

10000

8000

6000

4000

2000

0 0 4 8 12 16 20 24 28

Time (hr)


186

Wat

er R

ate

SC (c

m3

min

)

Cum

ulat

ive

Wat

er S

C (c

m3)

0

5

10

15

20

25

30

0

3000

6000

9000

12000

15000

18000


0 4 8 12 16 20 24 28 Time (hr)


Stea

m C

ham

ber V

olum

e SC

TR (c

m3)

0 4 8 12 16 20 24 28 0

500

1000

1500

2000

2500

3000

3500


Time (hr)


187
















~90



Figure 6-25 26 27 and 28












188



experiments



























189

0

2

4

6

8

10

12

14

16

0 5 10 15 20 25 30 Time hr

Oil

Rat

e c

cm

in



0

1

2

3

4

5

6

7

8

0 5 10 15 20 25 30 Time hr

cSO

R c

ccc



190

0

10

20

30

40

50

60

70

80

90

100

0 5 10 15 20 25 30 Time hr

WC

UT



0

10

20

30

40

50

60

0 5 10 15 20 25 30 Time hr

RF



191

0

20

40

60

80

100

120

0 1 2 3 Time hr

Tem

pera

ture

C

D31 D33 D35 D37 D39

0

20

40

60

80

100

120

0 2 4 6 8 10 12 14 16 Time hr

Tem

pera

ture

C

D31 D33 D35 D37 D39


192








Injector Producer


193

Injector Producer


Injector Producer


194

Injector Producer


Injector Producer


195
















Injector

Producer


196













saturation pressure








197


198

Oil

Rat

e SC

(cm

3m

in)

Cum

ulat

ive

Oil

SC (c

m3)

0

4

8

12

16

20

0

2000

4000

6000

8000


0 4 8 12 16 20

Time (hr)


Wat

er R

ate

SC (c

m3

min

)

Cum

ulat

ive

Wat

er S

C (c

m3)

0

3

6

9

12

15

0

2000

4000

6000

8000


0 4 8 12 16 20

Time (hr)


199

Wat

er R

ate

SC (c

m3

min

)

Cum

ulat

ive

Wat

er S

C (c

m3)

0

3

6

9

12

15

18

0

2000

4000

6000

8000

10000


0 4 8 12 16 20

Time (hr)


Stea

m C

ham

ber V

olum

e SC

TR (c

m3)

0

1000

2000

3000

4000

5000

6000

7000


0 4 8 12 16 20

Time (hr)


200





physical model


























201







stable





















202

0

2

4

6

8

10

12

14

16

18

20

0 4 8 12 16 20 Time hr

Oil

Rat

e c

cm

in

Fifth Experiment


00

05

10

15

20

25

30

0 4 8 12 16 20 Time hr

cSO

R c

ccc

Fifth Experiment


203

0

10

20

30

40

50

60

70

80

90

0 4 8 12 16 20 Time hr

WC

UT

Fifth Experiment


0

10

20

30

40

50

60

0 4 8 12 16 20 Time hr

RF

Fifth Experiment


204

0

20

40

60

80

100

120

0 1 2 3 4 5 Time hr

Tem

pera

ture

C

D15 D25 D35 D45 D55

0

20

40

60

80

100

120

0 4 8 12 16 20 Time hr

Tem

pera

ture

C

D15 D25 D35 D45 D55


205









Injector

Producer


206

Injector

Producer

Injector

Producer



207

Injector

Producer

Injector

Producer



208

Injector

Producer


Injector

Producer


209











1 2 3

4 5 6

7 8 9

50 cm

8 cm 50 cm









entire layer





in φΔSo value

210

85 255

425

425

255

85

222 233

220

239

223

267

217

200

251

10

12

14

16

18

20

22

24

26

28

φΔS

o

X cm

Y cm

Mid Layer














section

211

85 255

425

425

255

85

220 224

210 211 212

228

197 200

244

10

12

14

16

18

20

22

24

26

φΔS

o

X cm

Y cm

Top Layer

















212









213

Oil

Rat

e SC

(cm

3m

in)

Cum

ulat

ive

Oil

SC (c

m3)

00

50

100

150

200

0

2000

4000

6000

8000


0 200 400 600 800 1000 1200 Time (min)


Wat

er R

ate

SC (c

m3

min

)

Cum

ulat

ive

Wat

er S

C (c

m3)

0

6

12

18

24

30

0

3000

6000

9000

12000


0 200 400 600 800 1000 1200 Time (min)


214

Wat

er R

ate

SC (c

m3

min

)

Cum

ulat

ive

Wat

er S

C (c

m3)

0

7

14

21

28

35

42

0

3000

6000

9000

12000

15000


0 200 400 600 800 1000 1200 Time (min)


Stea

m C

ham

ber V

olum

e SC

TR (c

m3)

0

2000

4000

6000


0 200 400 600 800 1000 1200 Time (min)


215








pairs

















216

0

5

10

15

20

25

0 4 8 12 16 20

Time hr

Oil

Rat

e c

cm

in



00

05

10

15

20

25

30

35

0 4 8 12 16 20 Time hr

cSO

R c

ccc



217

0

10

20

30

40

50

60

70

80

90

0 4 8 12 16 20 Time hr

WC

UT



0

10

20

30

40

50

60

0 4 8 12 16 20 Time hr

RF



218
































219


reservoir








its heel








PVinj












220

0

20

40

60

80

100

120

0 1 2 3 4 Time hr

Tem

pera

ture

C

D31 D33 D35 D37 D39

0

20

40

60

80

100

120

0 2 4 6 8 10 12 14 Time hr

Tem

pera

ture

C

D31 D33 D35 D37 D39


221

Injector Producer


Injector Producer


222

Injector Producer


Injector Producer


223

Injector Producer


Injector Producer


224

Injector

Producer


















225





section

Mid Layer

14

13

12

11

85

255 10

425

136

132

129

126 127

121

131

123

122

Y cm 425 85

255

X cm

φΔS

o


226

85 255

425

425

255

85

229 223

253

235

225 237 235

225 222

10

12

14

16

18

20

22

24

26

φΔS

o

X cm

Y cm

Top Layer
















227



nearly perfect


228

24 12000

20

16

12

8

4

0


10000

8000

6000

4000

2000

0

Wat

er R

ate

SC (c

m3

min

)O

il R

ate

SC (c

m3

min

)

Cum

ulat

ive

Wat

er S

C (c

m3)

C

umul

ativ

e O

il SC

(cm

3)

0 2 4 6 8 10 12 14 Time (hr)


30 12000

25

20

15

10

5

0


10000

8000

6000

4000

2000

0 0 2 4 6 8 10 12 14

Time (hr)


229

28 14000

Wat

er R

ate

SC (c

m3

min

)

24

20

16

12

8

4

0


10000

8000

6000

4000

2000

0

Cum

ulat

ive

Wat

er S

C (c

m3)

0 2 4 6 8 10 12 14 Time (hr)


Stea

m C

ham

ber V

olum

e SC

TR (c

m3)

0

1000

2000

3000

4000

5000

6000

7000


0 2 4 6 8 10 12 14 Time (hr)


230
















Injector

18 cm

5 cm Producer











231















classic pattern













Figure 6-86

232

cSO

R c

ccc

O

il R

ate

cc

min

35


30

25

20

15

10

5

0 0

30

35

4 8 12

Time hr


16 20


25

20

15

10

05

00 0 4 8 12

Time hr


16 20

233

RF

WC

UT

70

80

90 Fifth Experiment


60

50

40

30

20

10

0 0 4 8

Time hr 12 16 20

50

60



40

30

20

10

0 0 4 8 12 16 20

Time hr


234






Injector

Producer 5 cm

18 cm

D15 D35 D55

D45D25

















235

0

20

40

60

80

100

120

0 2 4 6 8 10 Time hr

Tem

pera

ture

C

D15 D25 D35 D45 D55

0

20

40

60

80

100

120

0 1 2 3 4 Time hr

Tem

pera

ture

C

D15 D25 D35 D45 D55


236
































237



238



239


Injector

Producer


240






layer of the model









section

85 255

425

425

255

85

257

216 228

267

259 262 265

254 251

10

12

14

16

18

20

22

24

26

28

φΔS

o

X cm

Y cm

Top Layer


241


















should be so low













242









243

12000 42

35

28

21

14

7

0


10000

8000

6000

4000

2000

0

Wat

er R

ate

SC (c

m3

min

)O

il R

ate

SC (c

m3

min

)

Cum

ulat

ive

Wat

er S

C (c

m3)

C

umul

ativ

e O

il SC

(cm

3)

0 2 4 6 8 10 12 Time (hr)


25

20

15

10

5


00 20 40 60 80 100 120

10000

8000

6000

4000

2000

0

Time (hr)


0

244

30 12000

25

20

15

10

5

0


10000

8000

6000

4000

2000

0

Stea

m C

ham

ber V

olum

e SC

TR (c

m3)

W

ater

Rat

e SC

(cm

3m

in)

Cum

ulat

ive

Wat

er S

C (c

m3)

0 2 4 6 8 10 12 Time (hr)



0 2 4 6 8 10 12

8000

6000

4000

2000

0

Time (hr)


245










CHAPTER 7


247

71 Conclusions





simulation study


























248












model
















reservoirs




249
























directions




and chamber volume




250






72 Recommendations















reservoir










251






down



project operation






best pattern

252


2000



August 1981


53 1942







1987



Feb 1988












30- Sept 3 1997


253




















Vol54 2006












254










1995




February 26-28 1996


















255






















December 2008









November 2000

256













amp Eng 10 (1) 19-34 SPE-97742-PA



















257













7-9 1991



63) httpwwwercbca


httpwwwercbca








11 1980




httpwwwercbca


258


Vol15 No2 June 2006



1993



























259


Vol30 No2 June 1982






























260























iv

ACKNOWLEDGEMENTS























support

v

DEDICATION



vi

TABLE OF CONTENTS








vii











viii










ix




REFERENCES 252

x

LIST OF TABLES














experiments 241

xi

LIST OF FIGURES





























xii




















for sand analysis77










xiii






























xiv






























xv





























xvi






























xvii






























xviii






























xix






















xx


Symbol Definition


xxi

Greek Symbols


CHAPTER 1

INTRODUCTION

2










attentions





10000000

1000000

100000

10000

1000

100

1


Visc

osity

cp

Athabasca Cold Lake

0 50 100 150 200 250 Temperature C

10

3















Overburden

Underburden

Steam Chamber

Net Pay








4





3) Wind down


























5















T=Ts

T=TR

θ

dt t x

y ⎟ ⎠ ⎞

⎜ ⎝ ⎛ part

part







6








kgα ⎛ ⎞t 2



1 tD 2

Y 1 (14) = minus ⎛ ⎞ ⎜ ⎟2 X⎝ ⎠

X = x h (15)

Y = y h (16)





7

0

01

02

03

04

05

06

07

08

09

1


Ver

tical

Dist

ance

yh

02 06

04 08

1 12

14 16

18 2





⎡ TS ⎛ 1 1 ⎞ dT ⎤minus1

m = ⎢ν minus ⎥ (18) ν ν T T⎣

s intTR ⎜⎝ R

⎟⎠ minus R ⎦









8





[3]

3 o s

kgh B S mαφ ν

= Δ

(110)





(111) [1]

αtFo = h2 (111)



B3 = tD (113) Fo



9























heterogeneities



model





10













Parameter

Net Pay m

Permeability mD

φΔSo

microR cp

micros cp

m









11



























1315 Heterogeneity




12












two cases







1316 Wettability









recovery

13

1317 Water Leg











1318 Gas Cap







132 Well Design

1321 Completion









14








same vertical plane

















1331 Pressure






15










1332 Temperature





















16


























1337 Wind down




17






























18




















physical model




19



Producer Producer


Injector
























20





reservoir









chapter as well

CHAPTER 2

LITERATURE REVIEW

22

























left behind






23





vital
















SAGD process [7]











24
































25
































26















conditions [9]





27




Top of Formation


Injector

Producer

Base of Formation













28






















29











producer

30













31



















32















33






























34



















35





























36






























37














percent [59 60]


















38




CHAPTER 3


40















41






presented


sands deposit










42







anticline feature







43














44












exist





45













pperM


Lower C

retaceous

Lower

Mannville

McMurray McMurray









46















Lake

















47






distance























48


the areal extension




Clearwater

Upper M


Lower C

retaceous

Lower M

annville

McMurray McMurray



49













in Alberta







50




















51














52





















53





























in Figure 3-14

54











to 4m thick

55


Colony

McLaren

Waseca U

pperGrand Rapids

Clearwater

Sparky

GP

RL-Rex

Lloydminster

Cummings

Middle

Lower C

retaceous

Mannville G

roup

McMurray Dina

Low

er

Mainly Sand


Shale






coal and shale










56





to 2000 mD


















57

















58



Darcyrsquos











oil wet as well


















59
















60




heterogeneities







of these factors





extension
















61






CHAPTER 4


PROCEDURE

63








Steam

Water

Load Cell

Steam

Model Temperature








64






















70 987

30 1000

40 1000





65













25 cm

50 cm













66
















67

4

3 A B C D E F G







412 Steam Generator

















physical model

68






23rdquo

85rdquo

PTB

PTE

215rdquo

PTD

175rdquo

PTC

130rdquo

PTA40rdquo










69






24 cm 25 cm












sensor

70



Senor Z31 Z38 Z41

Rotor


Radius Ri mm 1572 1901 2071

+- ΔRi mm 0002 0004 0004

Length mm 55 55 55

+- L mm 003 003 003

Cup



+- ΔRa mm 0004 0004 0004


71

















additional water










72



73


























fill the model




74


with water

























75

1

2

3



3 Connection valves



442 SAGD Experiment












76

















77

1 2 3

4 5 6

7 8 9














experiment



78







444 Cleaning




washed with toluene

CHAPTER 5


80







51 Athabasca






511 Reservoir Model















81


30 500

20


Injector

Producer










82




















component

83


P




10

100

1000

10000

100000

1000000

10000000

100000000

Visc

osity

cp

00 500 1000 1500 2000 2500 3000

Temperature C









pairs



84





85









515 Wellbore Model








86



of the wellbore























224 degC




87



















reservoirs

5m

Injector

Producer

Injectors

Producer 5m

Injector

Producer


Producer

Injector

Producer



88

5181 Base Case




























cSOR

89

Oil

Prod

Rat

e SC

TR (m

3da

y)

0

20

40

60

80


1 2 3 4


2009 2010 2011 2012 2013 2014

Time (Date)


Oil

Rec

over

y Fa

ctor

SC

TR

0

10

20

30

40

50

60

70


2009 2010 2011 2012 2013 2014

Time (Date)


90

Stea

m O

il R

atio

Cum

SC

TR (m

3m

3)

00

05

10

15

20

25

30

35

40

45


2009 2010 2011 2012 2013 2014

Time (Date)


Stea

m C

ham

ber V

olum

e S

CTR

(m3)

0

10000

20000

30000

40000

50000


2009 2010 2011 2012 2013 2014 Time (Date)


91

1 2

3 4


Stea

m Q

ualit

y D

ownh

ole

00

01

02

03

04

05

06

07

08

09

10


2009 2010 2011 2012 2013 2014

Time (Date)


92































93


depletion period










degC cS cS m m2D

D m m Mpa

cS

Pres

sure

(kPa

)

2480

2482

2484

2486

2488

2490

2492

2494

2496

2498

2500


2009 2010 2011 2012 2013 2014 Time (Date)


94

0

20

40

60

80

100

120

140

160

0 1 2 3 4 5 6 Time Year

Oil

Prod

uctio

n R

ate

m3 d















case




95




















96

Oil

Prod

Rat

e SC

TR (m

3da

y)

0

20

40

60

80


2009 2010 2011 2012 2013 2014

Time (Date)


Oil

Rec

over

y Fa

ctor

SC

TR

0

10

20

30

40

50

60


2009 2010 2011 2012 2013 2014

Time (Date)


97

Stea

m O

il R

atio

Cum

SC

TR (m

3m

3)

00

05

10

15

20

25

30

35

40

45


2009 2010 2011 2012 2013 2014

Time (Date)


Stea

m C

ham

ber V

olum

e SC

TR (m

3)

0

10000

20000

30000

40000

50000


2009 2010 2011 2012 2013 2014

Time (Date)


98

























99

Oil

Rat

e SC

(m3

day)

0

30

60

90

120


2009 2010 2011 2012 2013 2014 2015 2016 2017

Time (Date)


Oil

Rec

over

y Fa

ctor

SC

TR

0

10

20

30

40

50

60


2009 2010 2011 2012 2013 2014 2015 2016 2017

Time (Date)


100

Stea

m O

il R

atio

Cum

SC

TR (m

3m

3)

00

10

20

30

40

50

60

70

80

90


2009 2010 2011 2012 2013 2014 2015 2016 2017

Time (Date)


Stea

m C

ham

ber V

olum

e SC

TR (m

3)

0

10000

20000

30000

40000

50000

60000


2009 2010 2011 2012 2013 2014 2015 2016 2017

Time (Date)


101



























reservoir

102

Oil

Prod

Rat

e SC

TR (m

3da

y)

0

20

40

60

80


2009 2010 2011 2012 2013 2014 Time (Date)


Oil

Rec

over

y Fa

ctor

SC

TR

0

10

20

30

40

50

60


2009 2010 2011 2012 2013 2014 Time (Date)


103

Stea

m O

il R

atio

Cum

SC

TR (m

3m

3)

00

05

10

15

20

25

30

35

40

45


2009 2010 2011 2012 2013 2014 Time (Date)


Stea

m C

ham

ber V

olum

e SC

TR (m

3)

0

10000

20000

30000

40000

50000


2009 2010 2011 2012 2013 2014 Time (Date)


104

One Year Five Years








investigated










circulation

50

105

70

Oil

Rec

over

y Fa

ctor

SC

TR

Ste

am O

il R

atio

Cum

SC

TR (m

3m

3)

60

50

40

30

20

10

0

Time (Date) 2009 2010 2011 2012 2013 2014



45

40

35

30

25

20

15

10

05

00

Time (Date) 2008-1-1 2009-5-15 2010-9-27 2012-2-9 2013-6-23 2014-11-5



106

Oil

Rat

e SC

(m3

day)

0

20

40

60

80


2009 2010 2011 2012 2013 2014 Time (Date)


Oil

Rec

over

y Fa

ctor

SC

TR

0

10

20

30

40

50

60


2009 2010 2011 2012 2013 2014 Time (Date)


107

Ste

am O

il R

atio

Cum

SC

TR (m

3m

3)

00

05

10

15

20

25

30

35

40

45


2008-1-1 2009-5-15 2010-9-27 2012-2-9 2013-6-23 2014-11-5 Time (Date)


Stea

m C

ham

ber V

olum

e SC

TR (m

3)

0

10000

20000

30000

40000

50000

60000


2009 2010 2011 2012 2013 2014 Time (Date)


108















less than 3 months









109

Oil

Prod

Rat

e SC

TR (m

3da

y)

0

20

40

60

80


2009 2010 2011 2012 2013 2014

Time (Date)


Oil

Rec

over

y Fa

ctor

SC

TR

0

10

20

30

40

50

60


2009 2010 2011 2012 2013 2014

Time (Date)


110

Stea

m O

il R

atio

Cum

SC

TR (m

3m

3)

00

05

10

15

20

25

30

35

40

45


2009 2010 2011 2012 2013 2014

Time (Date)


Stea

m C

ham

ber V

olum

e SC

TR (m

3)

0

10000

20000

30000

40000

50000


2009 2010 2011 2012 2013 2014

Time (Date)


111
















100

80

60

40

20

0

Oil

Prod

Rat

e SC

TR (m

3da

y)


2009 2010 2011 2012 2013 2014 Time (Date)


112

Oil

Rec

over

y Fa

ctor

SC

TR

0

10

20

30

40

50

60


2009 2010 2011 2012 2013 2014

Time (Date)


Stea

m O

il R

atio

Cum

SC

TR (m

3m

3)

00

05

10

15

20

25

30

35

40

45


2009 2010 2011 2012 2013 2014

Time (Date)


113

Stea

m C

ham

ber

Volu

me

SCTR

(m3)

70000

60000

50000

40000

30000

20000

10000

0


2009 2010 2011 2012 2013 2014 Time (Date)


52 Cold Lake






521 Reservoir Model








114

20

500

30


















115

1000000

100000

10000

1000

100

10

1

Visc

osity

cp

0 50 100 150 200 250 Temperature C










300

116







525 Wellbore Model













producer







117










5m

Injector

Producer

Injectors

Producer XY

Injector

Producer





Injector Producer X



5281 Base Case









118







recovery factor














119

Oil

Prod

Rat

e SC

TR (m

3da

y)

0

20

40

60

80

100

120


2008-7 2009-1 2009-7 2010-1 2010-7 2011-1 2011-7 2012-1

Time (Date)


Oil

Reco

very

Fac

tor

SCTR

0

10

20

30

40

50

60


2008-7 2009-1 2009-7 2010-1 2010-7 2011-1 2011-7 2012-1

Time (Date)


120

Stea

m O

il R

atio

Cum

SC

TR (m

3m

3)

00

05

10

15

20

25

30

35

40

45


2008-7 2009-1 2009-7 2010-1 2010-7 2011-1 2011-7 2012-1

Time (Date)


Stea

m C

ham

ber

Volu

me

SCTR

(m3)

0

10000

20000

30000

40000

50000


2008-7 2009-1 2009-7 2010-1 2010-7 2011-1 2011-7 2012-1

Time (Date)


121















Oil

Prod

Rat

e SC

TR (m

3da

y)

160

140

120

100

80

60

40

20

0


2008-7 2009-1 2009-7 2010-1 2010-7 2011-1 2011-7 2012-1 Time (Date)


122

Oil

Rec

over

y Fa

ctor

SC

TR

0

10

20

30

40

50

60


2008-7 2009-1 2009-7 2010-1 2010-7 2011-1 2011-7 2012-1

Time (Date)


Stea

m O

il R

atio

Cum

SC

TR (m

3m

3)

00

05

10

15

20

25

30

35

40

45


2008-7 2009-1 2009-7 2010-1 2010-7 2011-1 2011-7 2012-1

Time (Date)


123

Stea

m C

ham

ber

Volu

me

SCTR

(m3)

60000

50000

40000

30000

20000

10000

0


2008-7 2009-1 2009-7 2010-1 2010-7 2011-1 2011-7 2012-1 Time (Date)
















124













Oil

Prod

Rat

e SC

TR (m

3da

y)

160

140

120

100

80

60

40

20

0 2008-7 2009-1 2009-7 2010-1 2010-7 2011-1 2011-7 2012-1


Time (Date)


125

Oil

Rec

over

y Fa

ctor

SC

TR

0

10

20

30

40

50

60


2008-7 2009-1 2009-7 2010-1 2010-7 2011-1 2011-7 2012-1

Time (Date)


Stea

m O

il R

atio

Cum

SC

TR (m

3m

3)

00

10

20

30

40

50

60

70

80

90

100


2008-7 2009-1 2009-7 2010-1 2010-7 2011-1 2011-7 2012-1

Time (Date)


126

60000

50000

40000

30000

20000

10000

0

Time (Date)








evaluated









Stea

m C

ham

ber

Volu

me

SCTR

(m3)


2008-7 2009-1 2009-7 2010-1 2010-7 2011-1 2011-7 2012-1

127



base case







Oil

Prod

Rat

e SC

TR (m

3da

y)

180

160

140

120

100

80

60

40

20

0


2008-7 2009-1 2009-7 2010-1 2010-7 2011-1 2011-7 2012-1 Time (Date)


128

Oil

Rec

over

y Fa

ctor

SC

TR

0

10

20

30

40

50

60


2008-7 2009-1 2009-7 2010-1 2010-7 2011-1 2011-7 2012-1

Time (Date)


Stea

m O

il R

atio

Cum

SC

TR (m

3m

3)

00

05

10

15

20

25

30

35

40

45


2008-7 2009-1 2009-7 2010-1 2010-7 2011-1 2011-7 2012-1

Time (Date)


129

Stea

m C

ham

ber

Volu

me

SCTR

(m3)

60000

50000

40000

30000

20000

10000

0


2008-7 2009-1 2009-7 2010-1 2010-7 2011-1 2011-7 2012-1 Time (Date)

















130



Oil

Prod

Rat

e SC

TR (m

3da

y)

140

120

100

80

60

40

20

0


2008-7 2009-1 2009-7 2010-1 2010-7 2011-1 2011-7 2012-1

Time (Date)


131

Oil

Rec

over

y Fa

ctor

SC

TR

0

10

20

30

40

50

60


2008-7 2009-1 2009-7 2010-1 2010-7 2011-1 2011-7 2012-1

Time (Date)


Stea

m O

il R

atio

Cum

SC

TR (m

3m

3)

00

05

10

15

20

25

30

35

40

45


2008-7 2009-1 2009-7 2010-1 2010-7 2011-1 2011-7 2012-1

Time (Date)


132

Stea

m C

ham

ber V

olum

e SC

TR (m

3)

60000

50000

40000

30000

20000

10000

0


2008-7 2009-1 2009-7 2010-1 2010-7 2011-1 2011-7 2012-1 Time (Date)







producer





increased by 138

133

Oil

Prod

Rat

e SC

TR (m

3da

y)

0

20

40

60

80

100

120


2008-7 2009-1 2009-7 2010-1 2010-7 2011-1 2011-7 2012-1

Time (Date)


Oil

Reco

very

Fac

tor

SCTR

0

10

20

30

40

50

60


2008-7 2009-1 2009-7 2010-1 2010-7 2011-1 2011-7 2012-1

Time (Date)


134

50

45

40

35

30

25

20

15

10

05

00


2008-7 2009-1 2009-7 2010-1 2010-7 2011-1 2011-7 2012-1

Time (Date)


Stea

m C

ham

ber

Volu

me

SCTR

(m3)

0

10000

20000

30000

40000

50000


2008-7 2009-1 2009-7 2010-1 2010-7 2011-1 2011-7 2012-1

Time (Date)

Stea

m O

il R

atio

Cum

SC

TR (m

3m

3)


135












by 55

Oil

Prod

Rat

e SC

TR (m

3da

y)

140

120

100

80

60

40

20

0


2008-7 2009-1 2009-7 2010-1 2010-7 2011-1 2011-7 2012-1 Time (Date)


136

Oil

Rec

over

y Fa

ctor

SC

TR

0

10

20

30

40

50

60


2008-7 2009-1 2009-7 2010-1 2010-7 2011-1 2011-7 2012-1

Time (Date)


Stea

m O

il R

atio

Cum

SC

TR (m

3m

3)

00

05

10

15

20

25

30

35

40

45


2008-7 2009-1 2009-7 2010-1 2010-7 2011-1 2011-7 2012-1

Time (Date)


137

Stea

m C

ham

ber

Volu

me

SCTR

(m3)

60000

50000

40000

30000

20000

10000

0


2008-7 2009-1 2009-7 2010-1 2010-7 2011-1 2011-7 2012-1 Time (Date)
















138



Oil

Prod

Rat

e SC

TR (m

3da

y)

140

120

100

80

60

40

20

0


2008-7 2009-1 2009-7 2010-1 2010-7 2011-1 2011-7 2012-1

Time (Date)


139

Oil

Rec

over

y Fa

ctor

SC

TR

0

10

20

30

40

50

60


2008-7 2009-1 2009-7 2010-1 2010-7 2011-1 2011-7 2012-1

Time (Date)


Stea

m O

il R

atio

Cum

SC

TR (m

3m

3)

00

05

10

15

20

25

30

35

40

45


2008-7 2009-1 2009-7 2010-1 2010-7 2011-1 2011-7 2012-1

Time (Date)


140

Stea

m C

ham

ber

Volu

me

SCTR

(m3)

70000

60000

50000

40000

30000

20000

10000

0


2008-7 2009-1 2009-7 2010-1 2010-7 2011-1 2011-7 2012-1 Time (Date)


5289 C-SAGD















141
















142













Oil

Prod

Rat

e SC

TR (m

3da

y)

300

270

240

210

180

150

120

90

60

30

0


2008-7 2009-1 2009-7 2010-1 2010-7 2011-1 2011-7 2012-1 Time (Date)


143

Oil

Rec

over

y Fa

ctor

SC

TR

0

10

20

30

40

50

60

70


2008-7 2009-1 2009-7 2010-1 2010-7 2011-1 2011-7 2012-1

Time (Date)


Stea

m O

il R

atio

Cum

SC

TR (m

3m

3)

00

10

20

30

40

50

60

70

80

90


2008-7 2009-1 2009-7 2010-1 2010-7 2011-1 2011-7 2012-1

Time (Date)


144

Stea

m C

ham

ber

Volu

me

SCTR

(m3)

90000

80000

70000

60000

50000

40000

30000

20000

10000

0


2008-7 2009-1 2009-7 2010-1 2010-7 2011-1 2011-7 2012-1 Time (Date)







53 Lloydminster









Net

145













Overburden

Underburden

Steam Chamber

Underburden

Overburden











146
























531 Reservoir Model







147


reservoir model

10

500

90











Lake reservoirs






148







E+5m3











149

10000

Visc

osity

cp

1000

100

10

1 0 50 100 150 200 250

TemperatureC
















300

150









Injector




Injector Producer X
















151


















small as possible









152

Oil

Rat

e SC

(m3

day)

0

20

40

60

80

100

120

140

160

180


2009 2010 2011 2012 2013 2014 2015 2016

Time (Date)


Oil

Rec

over

y Fa

ctor

SC

TR

0

15

30

45

60


2009 2010 2011 2012 2013 2014 2015 2016

Time (Date)


153

Cum

Ste

am O

il R

atio

(m3

m3)

00

10

20

30

40

50


2009 2010 2011 2012 2013 2014 2015 2016

Time (Date)


Stea

m C

ham

ber V

olum

e SC

TR (m

3)

00e+0

20e+4

40e+4

60e+4

80e+4


2009 2010 2011 2012 2013 2014 2015 2016

Time (Date)


154







be larger than 30m













5-91 5-92 and 5-93






vertical injectors

155

Oil

Rat

e SC

(m3

day)

0

30

60

90

120

150

180


2009 2010 2011 2012 2013 2014 2015 2016

Time (Date)


Oil

Rec

over

y Fa

ctor

SC

TR

0

12

24

36

48

60

72


2009 2010 2011 2012 2013 2014 2015 2016

Time (Date)


156

Stea

m O

il R

atio

Cum

SC

TR (m

3m

3)

00

10

20

30

40

50


2009 2010 2011 2012 2013 2014 2015 2016

Time (Date)


Stea

m C

ham

ber V

olum

e SC

TR (m

3)

00e+0

20e+4

40e+4

60e+4

80e+4


2009 2010 2011 2012 2013 2014 2015 2016

Time (Date)


157

5363 C-SAGD





















158

Oil

Rat

e SC

(m3

day)

0

30

60

90

120

150

180


2009 2010 2011 2012 2013 2014 2015 2016

Time (Date)


Oil

Rec

over

y Fa

ctor

SC

TR

0

10

20

30

40

50

60

70

80


2009 2010 2011 2012 2013 2014 2015 2016

Time (Date)


159

Stea

m O

il R

atio

Cum

SC

TR (m

3m

3)

00

10

20

30

40

50

60

70


2009 2010 2011 2012 2013 2014 2015 2016

Time (Date)


Stea

m C

ham

ber V

olum

e SC

TR (m

3)

00e+0

20e+4

40e+4

60e+4

80e+4

10e+5


2009 2010 2011 2012 2013 2014 2015 2016

Time (Date)


160













Oil

Rat

e SC

(m3

day)

180

160

140

120

100

80

60

40

20

0


2009 2010 2011 2012 2013 2014 2015 2016 Time (Date)


161

Oil

Rec

over

y Fa

ctor

SC

TR

0

10

20

30

40

50

60

70


2009 2010 2011 2012 2013 2014 2015 2016

Time (Date)


Stea

m O

il R

atio

Cum

SC

TR (m

3m

3)

00

10

20

30

40

50


2009 2010 2011 2012 2013 2014 2015 2016

Time (Date)


162

Stea

m C

ham

ber V

olum

e SC

TR (m

3)

10e+5

80e+4

60e+4

40e+4

20e+4

00e+0


2009 2010 2011 2012 2013 2014 2015 2016 Time (Date)














163

Oil

Rat

e SC

(m3

day)

0

20

40

60

80

100

120

140

160


2009 2010 2011 2012 2013 2014 2015 2016

Time (Date)


Oil

Rec

over

y Fa

ctor

SC

TR

0

15

30

45

60

75


2009 2010 2011 2012 2013 2014 2015 2016

Time (Date)


164

Stea

m O

il R

atio

Cum

SC

TR (m

3m

3)

00

10

20

30

40

50

60


2009 2010 2011 2012 2013 2014 2015 2016

Time (Date)


Stea

m C

ham

ber V

olum

e SC

TR (m

3)

00e+0

20e+4

40e+4

60e+4

80e+4

10e+5


2009 2010 2011 2012 2013 2014 2015 2016

Time (Date)


165









reservoirs

CHAPTER 6


DISUCSSIONS

167






























AGSCO sand

168




Porosity

Soi

Swi

Viso Ti cp

Well Spacing cm























169


















y = 26222x

R2 = 09891

0

10

20

30

40

50

60

70

80

0 005 01 015 02 025 03

∆PL psicm

QA

ccmincm

2

Measured

Linear Regression


170

1

10

100

1000

10000

100000

0 50 100 150 200 250 300

Measured Data


Temperature degC

Viscosity

cp


1

10

100

1000

10000

100000

1000000

0 50 100 150 200 250 300

Temperature C

Visco

cp

Measured Date



171

























experiment






172




















temperature







173

0

5

10

15

20

25

0 5 10 15 20 25 30 Time hr

Oil

Rat

e c

cm

in



0

1

2

3

4

5

6

7

8

0 5 10 15 20 25 30 Time hr

cSO

R c

ccc



174

0

10

20

30

40

50

60

70

80

90

100

0 5 10 15 20 25 30 Time hr

WC

UT



0

5

10

15

20

25

30

35

40

45

0 5 10 15 20 25 30 Time hr

RF



175











0

5

10

15

20

25

30

35

40

45

50

0 2 4 6 8 10 12 14 16 18 20 Time hr

Oil

Rat

e c

cm

in



176

00

05

10

15

20

25

30

35

0 2 4 6 8 10 12 14 16 18 20 Time hr

cSO

R c

ccc



0

10

20

30

40

50

60

70

80

0 2 4 6 8 10 12 14 16 18 20 Time hr

WC

UT



177

0

5

10

15

20

25

30

35

40

45

0 2 4 6 8 10 12 14 16 18 20 Time hr

RF














toe of the injector

178

0

20

40

60

80

100

120

0 1 2 3 4 5 Time hr

Tem

pera

ture

C

D15 D25 D35 D45 D55

0

20

40

60

80

100

120

0 4 8 12 16 20 Time hr

Tem

pera

ture

C

D15 D25 D35 D45 D55


179









Layer A Layer B

Layer C

Layer D




Cross Section 5















180









Injector

Producer


181

Injector

Producer

Injector

Producer



182

Injector

Producer

Injector

Producer



183

Injector

Producer
















pressure

184








well


185

140 6000

120

100

80

60

40

20

00


5000

4000

3000

2000

1000

0

Wat

er R

ate

SC (c

m3

min

)O

il R

ate

SC (c

m3

min

)

Cum

ulat

ive

Wat

er S

C (c

m3)

C

umul

ativ

e O

il SC

(cm

3)

0 4 8 12 16 20 24 28 Time (hr)


28 14000

24

20

16

12

8

4

0


12000

10000

8000

6000

4000

2000

0 0 4 8 12 16 20 24 28

Time (hr)


186

Wat

er R

ate

SC (c

m3

min

)

Cum

ulat

ive

Wat

er S

C (c

m3)

0

5

10

15

20

25

30

0

3000

6000

9000

12000

15000

18000


0 4 8 12 16 20 24 28 Time (hr)


Stea

m C

ham

ber V

olum

e SC

TR (c

m3)

0 4 8 12 16 20 24 28 0

500

1000

1500

2000

2500

3000

3500


Time (hr)


187
















~90



Figure 6-25 26 27 and 28












188



experiments



























189

0

2

4

6

8

10

12

14

16

0 5 10 15 20 25 30 Time hr

Oil

Rat

e c

cm

in



0

1

2

3

4

5

6

7

8

0 5 10 15 20 25 30 Time hr

cSO

R c

ccc



190

0

10

20

30

40

50

60

70

80

90

100

0 5 10 15 20 25 30 Time hr

WC

UT



0

10

20

30

40

50

60

0 5 10 15 20 25 30 Time hr

RF



191

0

20

40

60

80

100

120

0 1 2 3 Time hr

Tem

pera

ture

C

D31 D33 D35 D37 D39

0

20

40

60

80

100

120

0 2 4 6 8 10 12 14 16 Time hr

Tem

pera

ture

C

D31 D33 D35 D37 D39


192








Injector Producer


193

Injector Producer


Injector Producer


194

Injector Producer


Injector Producer


195
















Injector

Producer


196













saturation pressure








197


198

Oil

Rat

e SC

(cm

3m

in)

Cum

ulat

ive

Oil

SC (c

m3)

0

4

8

12

16

20

0

2000

4000

6000

8000


0 4 8 12 16 20

Time (hr)


Wat

er R

ate

SC (c

m3

min

)

Cum

ulat

ive

Wat

er S

C (c

m3)

0

3

6

9

12

15

0

2000

4000

6000

8000


0 4 8 12 16 20

Time (hr)


199

Wat

er R

ate

SC (c

m3

min

)

Cum

ulat

ive

Wat

er S

C (c

m3)

0

3

6

9

12

15

18

0

2000

4000

6000

8000

10000


0 4 8 12 16 20

Time (hr)


Stea

m C

ham

ber V

olum

e SC

TR (c

m3)

0

1000

2000

3000

4000

5000

6000

7000


0 4 8 12 16 20

Time (hr)


200





physical model


























201







stable





















202

0

2

4

6

8

10

12

14

16

18

20

0 4 8 12 16 20 Time hr

Oil

Rat

e c

cm

in

Fifth Experiment


00

05

10

15

20

25

30

0 4 8 12 16 20 Time hr

cSO

R c

ccc

Fifth Experiment


203

0

10

20

30

40

50

60

70

80

90

0 4 8 12 16 20 Time hr

WC

UT

Fifth Experiment


0

10

20

30

40

50

60

0 4 8 12 16 20 Time hr

RF

Fifth Experiment


204

0

20

40

60

80

100

120

0 1 2 3 4 5 Time hr

Tem

pera

ture

C

D15 D25 D35 D45 D55

0

20

40

60

80

100

120

0 4 8 12 16 20 Time hr

Tem

pera

ture

C

D15 D25 D35 D45 D55


205









Injector

Producer


206

Injector

Producer

Injector

Producer



207

Injector

Producer

Injector

Producer



208

Injector

Producer


Injector

Producer


209











1 2 3

4 5 6

7 8 9

50 cm

8 cm 50 cm









entire layer





in φΔSo value

210

85 255

425

425

255

85

222 233

220

239

223

267

217

200

251

10

12

14

16

18

20

22

24

26

28

φΔS

o

X cm

Y cm

Mid Layer














section

211

85 255

425

425

255

85

220 224

210 211 212

228

197 200

244

10

12

14

16

18

20

22

24

26

φΔS

o

X cm

Y cm

Top Layer

















212









213

Oil

Rat

e SC

(cm

3m

in)

Cum

ulat

ive

Oil

SC (c

m3)

00

50

100

150

200

0

2000

4000

6000

8000


0 200 400 600 800 1000 1200 Time (min)


Wat

er R

ate

SC (c

m3

min

)

Cum

ulat

ive

Wat

er S

C (c

m3)

0

6

12

18

24

30

0

3000

6000

9000

12000


0 200 400 600 800 1000 1200 Time (min)


214

Wat

er R

ate

SC (c

m3

min

)

Cum

ulat

ive

Wat

er S

C (c

m3)

0

7

14

21

28

35

42

0

3000

6000

9000

12000

15000


0 200 400 600 800 1000 1200 Time (min)


Stea

m C

ham

ber V

olum

e SC

TR (c

m3)

0

2000

4000

6000


0 200 400 600 800 1000 1200 Time (min)


215








pairs

















216

0

5

10

15

20

25

0 4 8 12 16 20

Time hr

Oil

Rat

e c

cm

in



00

05

10

15

20

25

30

35

0 4 8 12 16 20 Time hr

cSO

R c

ccc



217

0

10

20

30

40

50

60

70

80

90

0 4 8 12 16 20 Time hr

WC

UT



0

10

20

30

40

50

60

0 4 8 12 16 20 Time hr

RF



218
































219


reservoir








its heel








PVinj












220

0

20

40

60

80

100

120

0 1 2 3 4 Time hr

Tem

pera

ture

C

D31 D33 D35 D37 D39

0

20

40

60

80

100

120

0 2 4 6 8 10 12 14 Time hr

Tem

pera

ture

C

D31 D33 D35 D37 D39


221

Injector Producer


Injector Producer


222

Injector Producer


Injector Producer


223

Injector Producer


Injector Producer


224

Injector

Producer


















225





section

Mid Layer

14

13

12

11

85

255 10

425

136

132

129

126 127

121

131

123

122

Y cm 425 85

255

X cm

φΔS

o


226

85 255

425

425

255

85

229 223

253

235

225 237 235

225 222

10

12

14

16

18

20

22

24

26

φΔS

o

X cm

Y cm

Top Layer
















227



nearly perfect


228

24 12000

20

16

12

8

4

0


10000

8000

6000

4000

2000

0

Wat

er R

ate

SC (c

m3

min

)O

il R

ate

SC (c

m3

min

)

Cum

ulat

ive

Wat

er S

C (c

m3)

C

umul

ativ

e O

il SC

(cm

3)

0 2 4 6 8 10 12 14 Time (hr)


30 12000

25

20

15

10

5

0


10000

8000

6000

4000

2000

0 0 2 4 6 8 10 12 14

Time (hr)


229

28 14000

Wat

er R

ate

SC (c

m3

min

)

24

20

16

12

8

4

0


10000

8000

6000

4000

2000

0

Cum

ulat

ive

Wat

er S

C (c

m3)

0 2 4 6 8 10 12 14 Time (hr)


Stea

m C

ham

ber V

olum

e SC

TR (c

m3)

0

1000

2000

3000

4000

5000

6000

7000


0 2 4 6 8 10 12 14 Time (hr)


230
















Injector

18 cm

5 cm Producer











231















classic pattern













Figure 6-86

232

cSO

R c

ccc

O

il R

ate

cc

min

35


30

25

20

15

10

5

0 0

30

35

4 8 12

Time hr


16 20


25

20

15

10

05

00 0 4 8 12

Time hr


16 20

233

RF

WC

UT

70

80

90 Fifth Experiment


60

50

40

30

20

10

0 0 4 8

Time hr 12 16 20

50

60



40

30

20

10

0 0 4 8 12 16 20

Time hr


234






Injector

Producer 5 cm

18 cm

D15 D35 D55

D45D25

















235

0

20

40

60

80

100

120

0 2 4 6 8 10 Time hr

Tem

pera

ture

C

D15 D25 D35 D45 D55

0

20

40

60

80

100

120

0 1 2 3 4 Time hr

Tem

pera

ture

C

D15 D25 D35 D45 D55


236
































237



238



239


Injector

Producer


240






layer of the model









section

85 255

425

425

255

85

257

216 228

267

259 262 265

254 251

10

12

14

16

18

20

22

24

26

28

φΔS

o

X cm

Y cm

Top Layer


241


















should be so low













242









243

12000 42

35

28

21

14

7

0


10000

8000

6000

4000

2000

0

Wat

er R

ate

SC (c

m3

min

)O

il R

ate

SC (c

m3

min

)

Cum

ulat

ive

Wat

er S

C (c

m3)

C

umul

ativ

e O

il SC

(cm

3)

0 2 4 6 8 10 12 Time (hr)


25

20

15

10

5


00 20 40 60 80 100 120

10000

8000

6000

4000

2000

0

Time (hr)


0

244

30 12000

25

20

15

10

5

0


10000

8000

6000

4000

2000

0

Stea

m C

ham

ber V

olum

e SC

TR (c

m3)

W

ater

Rat

e SC

(cm

3m

in)

Cum

ulat

ive

Wat

er S

C (c

m3)

0 2 4 6 8 10 12 Time (hr)



0 2 4 6 8 10 12

8000

6000

4000

2000

0

Time (hr)


245










CHAPTER 7


247

71 Conclusions





simulation study


























248












model
















reservoirs




249
























directions




and chamber volume




250






72 Recommendations















reservoir










251






down



project operation






best pattern

252


2000



August 1981


53 1942







1987



Feb 1988












30- Sept 3 1997


253




















Vol54 2006












254










1995




February 26-28 1996


















255






















December 2008









November 2000

256













amp Eng 10 (1) 19-34 SPE-97742-PA



















257













7-9 1991



63) httpwwwercbca


httpwwwercbca








11 1980




httpwwwercbca


258


Vol15 No2 June 2006



1993



























259


Vol30 No2 June 1982






























260























v

DEDICATION



vi

TABLE OF CONTENTS








vii











viii










ix




REFERENCES 252

x

LIST OF TABLES














experiments 241

xi

LIST OF FIGURES





























xii




















for sand analysis77










xiii






























xiv






























xv





























xvi






























xvii






























xviii






























xix






















xx


Symbol Definition


xxi

Greek Symbols


CHAPTER 1

INTRODUCTION

2










attentions





10000000

1000000

100000

10000

1000

100

1


Visc

osity

cp

Athabasca Cold Lake

0 50 100 150 200 250 Temperature C

10

3















Overburden

Underburden

Steam Chamber

Net Pay








4





3) Wind down


























5















T=Ts

T=TR

θ

dt t x

y ⎟ ⎠ ⎞

⎜ ⎝ ⎛ part

part







6








kgα ⎛ ⎞t 2



1 tD 2

Y 1 (14) = minus ⎛ ⎞ ⎜ ⎟2 X⎝ ⎠

X = x h (15)

Y = y h (16)





7

0

01

02

03

04

05

06

07

08

09

1


Ver

tical

Dist

ance

yh

02 06

04 08

1 12

14 16

18 2





⎡ TS ⎛ 1 1 ⎞ dT ⎤minus1

m = ⎢ν minus ⎥ (18) ν ν T T⎣

s intTR ⎜⎝ R

⎟⎠ minus R ⎦









8





[3]

3 o s

kgh B S mαφ ν

= Δ

(110)





(111) [1]

αtFo = h2 (111)



B3 = tD (113) Fo



9























heterogeneities



model





10













Parameter

Net Pay m

Permeability mD

φΔSo

microR cp

micros cp

m









11



























1315 Heterogeneity




12












two cases







1316 Wettability









recovery

13

1317 Water Leg











1318 Gas Cap







132 Well Design

1321 Completion









14








same vertical plane

















1331 Pressure






15










1332 Temperature





















16


























1337 Wind down




17






























18




















physical model




19



Producer Producer


Injector
























20





reservoir









chapter as well

CHAPTER 2

LITERATURE REVIEW

22

























left behind






23





vital
















SAGD process [7]











24
































25
































26















conditions [9]





27




Top of Formation


Injector

Producer

Base of Formation













28






















29











producer

30













31



















32















33






























34



















35





























36






























37














percent [59 60]


















38




CHAPTER 3


40















41






presented


sands deposit










42







anticline feature







43














44












exist





45













pperM


Lower C

retaceous

Lower

Mannville

McMurray McMurray









46















Lake

















47






distance























48


the areal extension




Clearwater

Upper M


Lower C

retaceous

Lower M

annville

McMurray McMurray



49













in Alberta







50




















51














52





















53





























in Figure 3-14

54











to 4m thick

55


Colony

McLaren

Waseca U

pperGrand Rapids

Clearwater

Sparky

GP

RL-Rex

Lloydminster

Cummings

Middle

Lower C

retaceous

Mannville G

roup

McMurray Dina

Low

er

Mainly Sand


Shale






coal and shale










56





to 2000 mD


















57

















58



Darcyrsquos











oil wet as well


















59
















60




heterogeneities







of these factors





extension
















61






CHAPTER 4


PROCEDURE

63








Steam

Water

Load Cell

Steam

Model Temperature








64






















70 987

30 1000

40 1000





65













25 cm

50 cm













66
















67

4

3 A B C D E F G







412 Steam Generator

















physical model

68






23rdquo

85rdquo

PTB

PTE

215rdquo

PTD

175rdquo

PTC

130rdquo

PTA40rdquo










69






24 cm 25 cm












sensor

70



Senor Z31 Z38 Z41

Rotor


Radius Ri mm 1572 1901 2071

+- ΔRi mm 0002 0004 0004

Length mm 55 55 55

+- L mm 003 003 003

Cup



+- ΔRa mm 0004 0004 0004


71

















additional water










72



73


























fill the model




74


with water

























75

1

2

3



3 Connection valves



442 SAGD Experiment












76

















77

1 2 3

4 5 6

7 8 9














experiment



78







444 Cleaning




washed with toluene

CHAPTER 5


80







51 Athabasca






511 Reservoir Model















81


30 500

20


Injector

Producer










82




















component

83


P




10

100

1000

10000

100000

1000000

10000000

100000000

Visc

osity

cp

00 500 1000 1500 2000 2500 3000

Temperature C









pairs



84





85









515 Wellbore Model








86



of the wellbore























224 degC




87



















reservoirs

5m

Injector

Producer

Injectors

Producer 5m

Injector

Producer


Producer

Injector

Producer



88

5181 Base Case




























cSOR

89

Oil

Prod

Rat

e SC

TR (m

3da

y)

0

20

40

60

80


1 2 3 4


2009 2010 2011 2012 2013 2014

Time (Date)


Oil

Rec

over

y Fa

ctor

SC

TR

0

10

20

30

40

50

60

70


2009 2010 2011 2012 2013 2014

Time (Date)


90

Stea

m O

il R

atio

Cum

SC

TR (m

3m

3)

00

05

10

15

20

25

30

35

40

45


2009 2010 2011 2012 2013 2014

Time (Date)


Stea

m C

ham

ber V

olum

e S

CTR

(m3)

0

10000

20000

30000

40000

50000


2009 2010 2011 2012 2013 2014 Time (Date)


91

1 2

3 4


Stea

m Q

ualit

y D

ownh

ole

00

01

02

03

04

05

06

07

08

09

10


2009 2010 2011 2012 2013 2014

Time (Date)


92































93


depletion period










degC cS cS m m2D

D m m Mpa

cS

Pres

sure

(kPa

)

2480

2482

2484

2486

2488

2490

2492

2494

2496

2498

2500


2009 2010 2011 2012 2013 2014 Time (Date)


94

0

20

40

60

80

100

120

140

160

0 1 2 3 4 5 6 Time Year

Oil

Prod

uctio

n R

ate

m3 d















case




95




















96

Oil

Prod

Rat

e SC

TR (m

3da

y)

0

20

40

60

80


2009 2010 2011 2012 2013 2014

Time (Date)


Oil

Rec

over

y Fa

ctor

SC

TR

0

10

20

30

40

50

60


2009 2010 2011 2012 2013 2014

Time (Date)


97

Stea

m O

il R

atio

Cum

SC

TR (m

3m

3)

00

05

10

15

20

25

30

35

40

45


2009 2010 2011 2012 2013 2014

Time (Date)


Stea

m C

ham

ber V

olum

e SC

TR (m

3)

0

10000

20000

30000

40000

50000


2009 2010 2011 2012 2013 2014

Time (Date)


98

























99

Oil

Rat

e SC

(m3

day)

0

30

60

90

120


2009 2010 2011 2012 2013 2014 2015 2016 2017

Time (Date)


Oil

Rec

over

y Fa

ctor

SC

TR

0

10

20

30

40

50

60


2009 2010 2011 2012 2013 2014 2015 2016 2017

Time (Date)


100

Stea

m O

il R

atio

Cum

SC

TR (m

3m

3)

00

10

20

30

40

50

60

70

80

90


2009 2010 2011 2012 2013 2014 2015 2016 2017

Time (Date)


Stea

m C

ham

ber V

olum

e SC

TR (m

3)

0

10000

20000

30000

40000

50000

60000


2009 2010 2011 2012 2013 2014 2015 2016 2017

Time (Date)


101



























reservoir

102

Oil

Prod

Rat

e SC

TR (m

3da

y)

0

20

40

60

80


2009 2010 2011 2012 2013 2014 Time (Date)


Oil

Rec

over

y Fa

ctor

SC

TR

0

10

20

30

40

50

60


2009 2010 2011 2012 2013 2014 Time (Date)


103

Stea

m O

il R

atio

Cum

SC

TR (m

3m

3)

00

05

10

15

20

25

30

35

40

45


2009 2010 2011 2012 2013 2014 Time (Date)


Stea

m C

ham

ber V

olum

e SC

TR (m

3)

0

10000

20000

30000

40000

50000


2009 2010 2011 2012 2013 2014 Time (Date)


104

One Year Five Years








investigated










circulation

50

105

70

Oil

Rec

over

y Fa

ctor

SC

TR

Ste

am O

il R

atio

Cum

SC

TR (m

3m

3)

60

50

40

30

20

10

0

Time (Date) 2009 2010 2011 2012 2013 2014



45

40

35

30

25

20

15

10

05

00

Time (Date) 2008-1-1 2009-5-15 2010-9-27 2012-2-9 2013-6-23 2014-11-5



106

Oil

Rat

e SC

(m3

day)

0

20

40

60

80


2009 2010 2011 2012 2013 2014 Time (Date)


Oil

Rec

over

y Fa

ctor

SC

TR

0

10

20

30

40

50

60


2009 2010 2011 2012 2013 2014 Time (Date)


107

Ste

am O

il R

atio

Cum

SC

TR (m

3m

3)

00

05

10

15

20

25

30

35

40

45


2008-1-1 2009-5-15 2010-9-27 2012-2-9 2013-6-23 2014-11-5 Time (Date)


Stea

m C

ham

ber V

olum

e SC

TR (m

3)

0

10000

20000

30000

40000

50000

60000


2009 2010 2011 2012 2013 2014 Time (Date)


108















less than 3 months









109

Oil

Prod

Rat

e SC

TR (m

3da

y)

0

20

40

60

80


2009 2010 2011 2012 2013 2014

Time (Date)


Oil

Rec

over

y Fa

ctor

SC

TR

0

10

20

30

40

50

60


2009 2010 2011 2012 2013 2014

Time (Date)


110

Stea

m O

il R

atio

Cum

SC

TR (m

3m

3)

00

05

10

15

20

25

30

35

40

45


2009 2010 2011 2012 2013 2014

Time (Date)


Stea

m C

ham

ber V

olum

e SC

TR (m

3)

0

10000

20000

30000

40000

50000


2009 2010 2011 2012 2013 2014

Time (Date)


111
















100

80

60

40

20

0

Oil

Prod

Rat

e SC

TR (m

3da

y)


2009 2010 2011 2012 2013 2014 Time (Date)


112

Oil

Rec

over

y Fa

ctor

SC

TR

0

10

20

30

40

50

60


2009 2010 2011 2012 2013 2014

Time (Date)


Stea

m O

il R

atio

Cum

SC

TR (m

3m

3)

00

05

10

15

20

25

30

35

40

45


2009 2010 2011 2012 2013 2014

Time (Date)


113

Stea

m C

ham

ber

Volu

me

SCTR

(m3)

70000

60000

50000

40000

30000

20000

10000

0


2009 2010 2011 2012 2013 2014 Time (Date)


52 Cold Lake






521 Reservoir Model








114

20

500

30


















115

1000000

100000

10000

1000

100

10

1

Visc

osity

cp

0 50 100 150 200 250 Temperature C










300

116







525 Wellbore Model













producer







117










5m

Injector

Producer

Injectors

Producer XY

Injector

Producer





Injector Producer X



5281 Base Case









118







recovery factor














119

Oil

Prod

Rat

e SC

TR (m

3da

y)

0

20

40

60

80

100

120


2008-7 2009-1 2009-7 2010-1 2010-7 2011-1 2011-7 2012-1

Time (Date)


Oil

Reco

very

Fac

tor

SCTR

0

10

20

30

40

50

60


2008-7 2009-1 2009-7 2010-1 2010-7 2011-1 2011-7 2012-1

Time (Date)


120

Stea

m O

il R

atio

Cum

SC

TR (m

3m

3)

00

05

10

15

20

25

30

35

40

45


2008-7 2009-1 2009-7 2010-1 2010-7 2011-1 2011-7 2012-1

Time (Date)


Stea

m C

ham

ber

Volu

me

SCTR

(m3)

0

10000

20000

30000

40000

50000


2008-7 2009-1 2009-7 2010-1 2010-7 2011-1 2011-7 2012-1

Time (Date)


121















Oil

Prod

Rat

e SC

TR (m

3da

y)

160

140

120

100

80

60

40

20

0


2008-7 2009-1 2009-7 2010-1 2010-7 2011-1 2011-7 2012-1 Time (Date)


122

Oil

Rec

over

y Fa

ctor

SC

TR

0

10

20

30

40

50

60


2008-7 2009-1 2009-7 2010-1 2010-7 2011-1 2011-7 2012-1

Time (Date)


Stea

m O

il R

atio

Cum

SC

TR (m

3m

3)

00

05

10

15

20

25

30

35

40

45


2008-7 2009-1 2009-7 2010-1 2010-7 2011-1 2011-7 2012-1

Time (Date)


123

Stea

m C

ham

ber

Volu

me

SCTR

(m3)

60000

50000

40000

30000

20000

10000

0


2008-7 2009-1 2009-7 2010-1 2010-7 2011-1 2011-7 2012-1 Time (Date)
















124













Oil

Prod

Rat

e SC

TR (m

3da

y)

160

140

120

100

80

60

40

20

0 2008-7 2009-1 2009-7 2010-1 2010-7 2011-1 2011-7 2012-1


Time (Date)


125

Oil

Rec

over

y Fa

ctor

SC

TR

0

10

20

30

40

50

60


2008-7 2009-1 2009-7 2010-1 2010-7 2011-1 2011-7 2012-1

Time (Date)


Stea

m O

il R

atio

Cum

SC

TR (m

3m

3)

00

10

20

30

40

50

60

70

80

90

100


2008-7 2009-1 2009-7 2010-1 2010-7 2011-1 2011-7 2012-1

Time (Date)


126

60000

50000

40000

30000

20000

10000

0

Time (Date)








evaluated









Stea

m C

ham

ber

Volu

me

SCTR

(m3)


2008-7 2009-1 2009-7 2010-1 2010-7 2011-1 2011-7 2012-1

127



base case







Oil

Prod

Rat

e SC

TR (m

3da

y)

180

160

140

120

100

80

60

40

20

0


2008-7 2009-1 2009-7 2010-1 2010-7 2011-1 2011-7 2012-1 Time (Date)


128

Oil

Rec

over

y Fa

ctor

SC

TR

0

10

20

30

40

50

60


2008-7 2009-1 2009-7 2010-1 2010-7 2011-1 2011-7 2012-1

Time (Date)


Stea

m O

il R

atio

Cum

SC

TR (m

3m

3)

00

05

10

15

20

25

30

35

40

45


2008-7 2009-1 2009-7 2010-1 2010-7 2011-1 2011-7 2012-1

Time (Date)


129

Stea

m C

ham

ber

Volu

me

SCTR

(m3)

60000

50000

40000

30000

20000

10000

0


2008-7 2009-1 2009-7 2010-1 2010-7 2011-1 2011-7 2012-1 Time (Date)

















130



Oil

Prod

Rat

e SC

TR (m

3da

y)

140

120

100

80

60

40

20

0


2008-7 2009-1 2009-7 2010-1 2010-7 2011-1 2011-7 2012-1

Time (Date)


131

Oil

Rec

over

y Fa

ctor

SC

TR

0

10

20

30

40

50

60


2008-7 2009-1 2009-7 2010-1 2010-7 2011-1 2011-7 2012-1

Time (Date)


Stea

m O

il R

atio

Cum

SC

TR (m

3m

3)

00

05

10

15

20

25

30

35

40

45


2008-7 2009-1 2009-7 2010-1 2010-7 2011-1 2011-7 2012-1

Time (Date)


132

Stea

m C

ham

ber V

olum

e SC

TR (m

3)

60000

50000

40000

30000

20000

10000

0


2008-7 2009-1 2009-7 2010-1 2010-7 2011-1 2011-7 2012-1 Time (Date)







producer





increased by 138

133

Oil

Prod

Rat

e SC

TR (m

3da

y)

0

20

40

60

80

100

120


2008-7 2009-1 2009-7 2010-1 2010-7 2011-1 2011-7 2012-1

Time (Date)


Oil

Reco

very

Fac

tor

SCTR

0

10

20

30

40

50

60


2008-7 2009-1 2009-7 2010-1 2010-7 2011-1 2011-7 2012-1

Time (Date)


134

50

45

40

35

30

25

20

15

10

05

00


2008-7 2009-1 2009-7 2010-1 2010-7 2011-1 2011-7 2012-1

Time (Date)


Stea

m C

ham

ber

Volu

me

SCTR

(m3)

0

10000

20000

30000

40000

50000


2008-7 2009-1 2009-7 2010-1 2010-7 2011-1 2011-7 2012-1

Time (Date)

Stea

m O

il R

atio

Cum

SC

TR (m

3m

3)


135












by 55

Oil

Prod

Rat

e SC

TR (m

3da

y)

140

120

100

80

60

40

20

0


2008-7 2009-1 2009-7 2010-1 2010-7 2011-1 2011-7 2012-1 Time (Date)


136

Oil

Rec

over

y Fa

ctor

SC

TR

0

10

20

30

40

50

60


2008-7 2009-1 2009-7 2010-1 2010-7 2011-1 2011-7 2012-1

Time (Date)


Stea

m O

il R

atio

Cum

SC

TR (m

3m

3)

00

05

10

15

20

25

30

35

40

45


2008-7 2009-1 2009-7 2010-1 2010-7 2011-1 2011-7 2012-1

Time (Date)


137

Stea

m C

ham

ber

Volu

me

SCTR

(m3)

60000

50000

40000

30000

20000

10000

0


2008-7 2009-1 2009-7 2010-1 2010-7 2011-1 2011-7 2012-1 Time (Date)
















138



Oil

Prod

Rat

e SC

TR (m

3da

y)

140

120

100

80

60

40

20

0


2008-7 2009-1 2009-7 2010-1 2010-7 2011-1 2011-7 2012-1

Time (Date)


139

Oil

Rec

over

y Fa

ctor

SC

TR

0

10

20

30

40

50

60


2008-7 2009-1 2009-7 2010-1 2010-7 2011-1 2011-7 2012-1

Time (Date)


Stea

m O

il R

atio

Cum

SC

TR (m

3m

3)

00

05

10

15

20

25

30

35

40

45


2008-7 2009-1 2009-7 2010-1 2010-7 2011-1 2011-7 2012-1

Time (Date)


140

Stea

m C

ham

ber

Volu

me

SCTR

(m3)

70000

60000

50000

40000

30000

20000

10000

0


2008-7 2009-1 2009-7 2010-1 2010-7 2011-1 2011-7 2012-1 Time (Date)


5289 C-SAGD















141
















142













Oil

Prod

Rat

e SC

TR (m

3da

y)

300

270

240

210

180

150

120

90

60

30

0


2008-7 2009-1 2009-7 2010-1 2010-7 2011-1 2011-7 2012-1 Time (Date)


143

Oil

Rec

over

y Fa

ctor

SC

TR

0

10

20

30

40

50

60

70


2008-7 2009-1 2009-7 2010-1 2010-7 2011-1 2011-7 2012-1

Time (Date)


Stea

m O

il R

atio

Cum

SC

TR (m

3m

3)

00

10

20

30

40

50

60

70

80

90


2008-7 2009-1 2009-7 2010-1 2010-7 2011-1 2011-7 2012-1

Time (Date)


144

Stea

m C

ham

ber

Volu

me

SCTR

(m3)

90000

80000

70000

60000

50000

40000

30000

20000

10000

0


2008-7 2009-1 2009-7 2010-1 2010-7 2011-1 2011-7 2012-1 Time (Date)







53 Lloydminster









Net

145













Overburden

Underburden

Steam Chamber

Underburden

Overburden











146
























531 Reservoir Model







147


reservoir model

10

500

90











Lake reservoirs






148







E+5m3











149

10000

Visc

osity

cp

1000

100

10

1 0 50 100 150 200 250

TemperatureC
















300

150









Injector




Injector Producer X
















151


















small as possible









152

Oil

Rat

e SC

(m3

day)

0

20

40

60

80

100

120

140

160

180


2009 2010 2011 2012 2013 2014 2015 2016

Time (Date)


Oil

Rec

over

y Fa

ctor

SC

TR

0

15

30

45

60


2009 2010 2011 2012 2013 2014 2015 2016

Time (Date)


153

Cum

Ste

am O

il R

atio

(m3

m3)

00

10

20

30

40

50


2009 2010 2011 2012 2013 2014 2015 2016

Time (Date)


Stea

m C

ham

ber V

olum

e SC

TR (m

3)

00e+0

20e+4

40e+4

60e+4

80e+4


2009 2010 2011 2012 2013 2014 2015 2016

Time (Date)


154







be larger than 30m













5-91 5-92 and 5-93






vertical injectors

155

Oil

Rat

e SC

(m3

day)

0

30

60

90

120

150

180


2009 2010 2011 2012 2013 2014 2015 2016

Time (Date)


Oil

Rec

over

y Fa

ctor

SC

TR

0

12

24

36

48

60

72


2009 2010 2011 2012 2013 2014 2015 2016

Time (Date)


156

Stea

m O

il R

atio

Cum

SC

TR (m

3m

3)

00

10

20

30

40

50


2009 2010 2011 2012 2013 2014 2015 2016

Time (Date)


Stea

m C

ham

ber V

olum

e SC

TR (m

3)

00e+0

20e+4

40e+4

60e+4

80e+4


2009 2010 2011 2012 2013 2014 2015 2016

Time (Date)


157

5363 C-SAGD





















158

Oil

Rat

e SC

(m3

day)

0

30

60

90

120

150

180


2009 2010 2011 2012 2013 2014 2015 2016

Time (Date)


Oil

Rec

over

y Fa

ctor

SC

TR

0

10

20

30

40

50

60

70

80


2009 2010 2011 2012 2013 2014 2015 2016

Time (Date)


159

Stea

m O

il R

atio

Cum

SC

TR (m

3m

3)

00

10

20

30

40

50

60

70


2009 2010 2011 2012 2013 2014 2015 2016

Time (Date)


Stea

m C

ham

ber V

olum

e SC

TR (m

3)

00e+0

20e+4

40e+4

60e+4

80e+4

10e+5


2009 2010 2011 2012 2013 2014 2015 2016

Time (Date)


160













Oil

Rat

e SC

(m3

day)

180

160

140

120

100

80

60

40

20

0


2009 2010 2011 2012 2013 2014 2015 2016 Time (Date)


161

Oil

Rec

over

y Fa

ctor

SC

TR

0

10

20

30

40

50

60

70


2009 2010 2011 2012 2013 2014 2015 2016

Time (Date)


Stea

m O

il R

atio

Cum

SC

TR (m

3m

3)

00

10

20

30

40

50


2009 2010 2011 2012 2013 2014 2015 2016

Time (Date)


162

Stea

m C

ham

ber V

olum

e SC

TR (m

3)

10e+5

80e+4

60e+4

40e+4

20e+4

00e+0


2009 2010 2011 2012 2013 2014 2015 2016 Time (Date)














163

Oil

Rat

e SC

(m3

day)

0

20

40

60

80

100

120

140

160


2009 2010 2011 2012 2013 2014 2015 2016

Time (Date)


Oil

Rec

over

y Fa

ctor

SC

TR

0

15

30

45

60

75


2009 2010 2011 2012 2013 2014 2015 2016

Time (Date)


164

Stea

m O

il R

atio

Cum

SC

TR (m

3m

3)

00

10

20

30

40

50

60


2009 2010 2011 2012 2013 2014 2015 2016

Time (Date)


Stea

m C

ham

ber V

olum

e SC

TR (m

3)

00e+0

20e+4

40e+4

60e+4

80e+4

10e+5


2009 2010 2011 2012 2013 2014 2015 2016

Time (Date)


165









reservoirs

CHAPTER 6


DISUCSSIONS

167






























AGSCO sand

168




Porosity

Soi

Swi

Viso Ti cp

Well Spacing cm























169


















y = 26222x

R2 = 09891

0

10

20

30

40

50

60

70

80

0 005 01 015 02 025 03

∆PL psicm

QA

ccmincm

2

Measured

Linear Regression


170

1

10

100

1000

10000

100000

0 50 100 150 200 250 300

Measured Data


Temperature degC

Viscosity

cp


1

10

100

1000

10000

100000

1000000

0 50 100 150 200 250 300

Temperature C

Visco

cp

Measured Date



171

























experiment






172




















temperature







173

0

5

10

15

20

25

0 5 10 15 20 25 30 Time hr

Oil

Rat

e c

cm

in



0

1

2

3

4

5

6

7

8

0 5 10 15 20 25 30 Time hr

cSO

R c

ccc



174

0

10

20

30

40

50

60

70

80

90

100

0 5 10 15 20 25 30 Time hr

WC

UT



0

5

10

15

20

25

30

35

40

45

0 5 10 15 20 25 30 Time hr

RF



175











0

5

10

15

20

25

30

35

40

45

50

0 2 4 6 8 10 12 14 16 18 20 Time hr

Oil

Rat

e c

cm

in



176

00

05

10

15

20

25

30

35

0 2 4 6 8 10 12 14 16 18 20 Time hr

cSO

R c

ccc



0

10

20

30

40

50

60

70

80

0 2 4 6 8 10 12 14 16 18 20 Time hr

WC

UT



177

0

5

10

15

20

25

30

35

40

45

0 2 4 6 8 10 12 14 16 18 20 Time hr

RF














toe of the injector

178

0

20

40

60

80

100

120

0 1 2 3 4 5 Time hr

Tem

pera

ture

C

D15 D25 D35 D45 D55

0

20

40

60

80

100

120

0 4 8 12 16 20 Time hr

Tem

pera

ture

C

D15 D25 D35 D45 D55


179









Layer A Layer B

Layer C

Layer D




Cross Section 5















180









Injector

Producer


181

Injector

Producer

Injector

Producer



182

Injector

Producer

Injector

Producer



183

Injector

Producer
















pressure

184








well


185

140 6000

120

100

80

60

40

20

00


5000

4000

3000

2000

1000

0

Wat

er R

ate

SC (c

m3

min

)O

il R

ate

SC (c

m3

min

)

Cum

ulat

ive

Wat

er S

C (c

m3)

C

umul

ativ

e O

il SC

(cm

3)

0 4 8 12 16 20 24 28 Time (hr)


28 14000

24

20

16

12

8

4

0


12000

10000

8000

6000

4000

2000

0 0 4 8 12 16 20 24 28

Time (hr)


186

Wat

er R

ate

SC (c

m3

min

)

Cum

ulat

ive

Wat

er S

C (c

m3)

0

5

10

15

20

25

30

0

3000

6000

9000

12000

15000

18000


0 4 8 12 16 20 24 28 Time (hr)


Stea

m C

ham

ber V

olum

e SC

TR (c

m3)

0 4 8 12 16 20 24 28 0

500

1000

1500

2000

2500

3000

3500


Time (hr)


187
















~90



Figure 6-25 26 27 and 28












188



experiments



























189

0

2

4

6

8

10

12

14

16

0 5 10 15 20 25 30 Time hr

Oil

Rat

e c

cm

in



0

1

2

3

4

5

6

7

8

0 5 10 15 20 25 30 Time hr

cSO

R c

ccc



190

0

10

20

30

40

50

60

70

80

90

100

0 5 10 15 20 25 30 Time hr

WC

UT



0

10

20

30

40

50

60

0 5 10 15 20 25 30 Time hr

RF



191

0

20

40

60

80

100

120

0 1 2 3 Time hr

Tem

pera

ture

C

D31 D33 D35 D37 D39

0

20

40

60

80

100

120

0 2 4 6 8 10 12 14 16 Time hr

Tem

pera

ture

C

D31 D33 D35 D37 D39


192








Injector Producer


193

Injector Producer


Injector Producer


194

Injector Producer


Injector Producer


195
















Injector

Producer


196













saturation pressure








197


198

Oil

Rat

e SC

(cm

3m

in)

Cum

ulat

ive

Oil

SC (c

m3)

0

4

8

12

16

20

0

2000

4000

6000

8000


0 4 8 12 16 20

Time (hr)


Wat

er R

ate

SC (c

m3

min

)

Cum

ulat

ive

Wat

er S

C (c

m3)

0

3

6

9

12

15

0

2000

4000

6000

8000


0 4 8 12 16 20

Time (hr)


199

Wat

er R

ate

SC (c

m3

min

)

Cum

ulat

ive

Wat

er S

C (c

m3)

0

3

6

9

12

15

18

0

2000

4000

6000

8000

10000


0 4 8 12 16 20

Time (hr)


Stea

m C

ham

ber V

olum

e SC

TR (c

m3)

0

1000

2000

3000

4000

5000

6000

7000


0 4 8 12 16 20

Time (hr)


200





physical model


























201







stable





















202

0

2

4

6

8

10

12

14

16

18

20

0 4 8 12 16 20 Time hr

Oil

Rat

e c

cm

in

Fifth Experiment


00

05

10

15

20

25

30

0 4 8 12 16 20 Time hr

cSO

R c

ccc

Fifth Experiment


203

0

10

20

30

40

50

60

70

80

90

0 4 8 12 16 20 Time hr

WC

UT

Fifth Experiment


0

10

20

30

40

50

60

0 4 8 12 16 20 Time hr

RF

Fifth Experiment


204

0

20

40

60

80

100

120

0 1 2 3 4 5 Time hr

Tem

pera

ture

C

D15 D25 D35 D45 D55

0

20

40

60

80

100

120

0 4 8 12 16 20 Time hr

Tem

pera

ture

C

D15 D25 D35 D45 D55


205









Injector

Producer


206

Injector

Producer

Injector

Producer



207

Injector

Producer

Injector

Producer



208

Injector

Producer


Injector

Producer


209











1 2 3

4 5 6

7 8 9

50 cm

8 cm 50 cm









entire layer





in φΔSo value

210

85 255

425

425

255

85

222 233

220

239

223

267

217

200

251

10

12

14

16

18

20

22

24

26

28

φΔS

o

X cm

Y cm

Mid Layer














section

211

85 255

425

425

255

85

220 224

210 211 212

228

197 200

244

10

12

14

16

18

20

22

24

26

φΔS

o

X cm

Y cm

Top Layer

















212









213

Oil

Rat

e SC

(cm

3m

in)

Cum

ulat

ive

Oil

SC (c

m3)

00

50

100

150

200

0

2000

4000

6000

8000


0 200 400 600 800 1000 1200 Time (min)


Wat

er R

ate

SC (c

m3

min

)

Cum

ulat

ive

Wat

er S

C (c

m3)

0

6

12

18

24

30

0

3000

6000

9000

12000


0 200 400 600 800 1000 1200 Time (min)


214

Wat

er R

ate

SC (c

m3

min

)

Cum

ulat

ive

Wat

er S

C (c

m3)

0

7

14

21

28

35

42

0

3000

6000

9000

12000

15000


0 200 400 600 800 1000 1200 Time (min)


Stea

m C

ham

ber V

olum

e SC

TR (c

m3)

0

2000

4000

6000


0 200 400 600 800 1000 1200 Time (min)


215








pairs

















216

0

5

10

15

20

25

0 4 8 12 16 20

Time hr

Oil

Rat

e c

cm

in



00

05

10

15

20

25

30

35

0 4 8 12 16 20 Time hr

cSO

R c

ccc



217

0

10

20

30

40

50

60

70

80

90

0 4 8 12 16 20 Time hr

WC

UT



0

10

20

30

40

50

60

0 4 8 12 16 20 Time hr

RF



218
































219


reservoir








its heel








PVinj












220

0

20

40

60

80

100

120

0 1 2 3 4 Time hr

Tem

pera

ture

C

D31 D33 D35 D37 D39

0

20

40

60

80

100

120

0 2 4 6 8 10 12 14 Time hr

Tem

pera

ture

C

D31 D33 D35 D37 D39


221

Injector Producer


Injector Producer


222

Injector Producer


Injector Producer


223

Injector Producer


Injector Producer


224

Injector

Producer


















225





section

Mid Layer

14

13

12

11

85

255 10

425

136

132

129

126 127

121

131

123

122

Y cm 425 85

255

X cm

φΔS

o


226

85 255

425

425

255

85

229 223

253

235

225 237 235

225 222

10

12

14

16

18

20

22

24

26

φΔS

o

X cm

Y cm

Top Layer
















227



nearly perfect


228

24 12000

20

16

12

8

4

0


10000

8000

6000

4000

2000

0

Wat

er R

ate

SC (c

m3

min

)O

il R

ate

SC (c

m3

min

)

Cum

ulat

ive

Wat

er S

C (c

m3)

C

umul

ativ

e O

il SC

(cm

3)

0 2 4 6 8 10 12 14 Time (hr)


30 12000

25

20

15

10

5

0


10000

8000

6000

4000

2000

0 0 2 4 6 8 10 12 14

Time (hr)


229

28 14000

Wat

er R

ate

SC (c

m3

min

)

24

20

16

12

8

4

0


10000

8000

6000

4000

2000

0

Cum

ulat

ive

Wat

er S

C (c

m3)

0 2 4 6 8 10 12 14 Time (hr)


Stea

m C

ham

ber V

olum

e SC

TR (c

m3)

0

1000

2000

3000

4000

5000

6000

7000


0 2 4 6 8 10 12 14 Time (hr)


230
















Injector

18 cm

5 cm Producer











231















classic pattern













Figure 6-86

232

cSO

R c

ccc

O

il R

ate

cc

min

35


30

25

20

15

10

5

0 0

30

35

4 8 12

Time hr


16 20


25

20

15

10

05

00 0 4 8 12

Time hr


16 20

233

RF

WC

UT

70

80

90 Fifth Experiment


60

50

40

30

20

10

0 0 4 8

Time hr 12 16 20

50

60



40

30

20

10

0 0 4 8 12 16 20

Time hr


234






Injector

Producer 5 cm

18 cm

D15 D35 D55

D45D25

















235

0

20

40

60

80

100

120

0 2 4 6 8 10 Time hr

Tem

pera

ture

C

D15 D25 D35 D45 D55

0

20

40

60

80

100

120

0 1 2 3 4 Time hr

Tem

pera

ture

C

D15 D25 D35 D45 D55


236
































237



238



239


Injector

Producer


240






layer of the model









section

85 255

425

425

255

85

257

216 228

267

259 262 265

254 251

10

12

14

16

18

20

22

24

26

28

φΔS

o

X cm

Y cm

Top Layer


241


















should be so low













242









243

12000 42

35

28

21

14

7

0


10000

8000

6000

4000

2000

0

Wat

er R

ate

SC (c

m3

min

)O

il R

ate

SC (c

m3

min

)

Cum

ulat

ive

Wat

er S

C (c

m3)

C

umul

ativ

e O

il SC

(cm

3)

0 2 4 6 8 10 12 Time (hr)


25

20

15

10

5


00 20 40 60 80 100 120

10000

8000

6000

4000

2000

0

Time (hr)


0

244

30 12000

25

20

15

10

5

0


10000

8000

6000

4000

2000

0

Stea

m C

ham

ber V

olum

e SC

TR (c

m3)

W

ater

Rat

e SC

(cm

3m

in)

Cum

ulat

ive

Wat

er S

C (c

m3)

0 2 4 6 8 10 12 Time (hr)



0 2 4 6 8 10 12

8000

6000

4000

2000

0

Time (hr)


245










CHAPTER 7


247

71 Conclusions





simulation study


























248












model
















reservoirs




249
























directions




and chamber volume




250






72 Recommendations















reservoir










251






down



project operation






best pattern

252


2000



August 1981


53 1942







1987



Feb 1988












30- Sept 3 1997


253




















Vol54 2006












254










1995




February 26-28 1996


















255






















December 2008









November 2000

256













amp Eng 10 (1) 19-34 SPE-97742-PA



















257













7-9 1991



63) httpwwwercbca


httpwwwercbca








11 1980




httpwwwercbca


258


Vol15 No2 June 2006



1993



























259


Vol30 No2 June 1982






























260























Physical and Numerical Modeling of SAGD Under New Well ...

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