Impact of Well Configuration on Performance of Steam-Based

UNIVERSITY OF CALGARY

Impact of Well Configuration on Performance of

Steam-based Gravity Drainage Recovery Processes

Mohamed Rajab Tamer

A THESIS

SUBMITTED TO THE FACULTY OF GRADUATE STUDIES

IN PARTIAL FULFILMENT OF THE REQUIREMENTS FOR THE

DEGREE OF MASTER OF SCIENCE

DEPARTMENT OF CHEMICAL & PETROLEUM ENGINEERING

CALGARY, ALBERTA

October, 2008

ISBN: 978-0-494-51161-9

UNIVERSITY OF CALGARY

FACULTY OF GRADUATE STUDIES

The undersigned certify that they have read, and recommend to the Faculty of Graduate

Studies for acceptance, a thesis entitled "Impact of Well Configuration on Performance of

Steam-based Gravity Drainage Recovery Processes" submitted by Mohamed Rajab

Tamer in partial fulfilment of the requirements of the degree of Master of Science.

Supervisor, Dr. Ian. D. Gates, Department of Chemical and Petroleum Engineering

Dr. Michael S. Kallos Department of Chemical and Petroleum Engineering

Dr. Mingzhe Dong Department of Chemical and Petroleum Engineering

Dr. Stephen M. Hubbard Department of Geoscience

Date

iii

Abstract

The volume of heavy oil and bitumen in the oil sands deposits in Western Canada

is similar to that of conventional crude oil in the Middle East. This resource is immense

but is difficult and energy intensive to extract because the viscosity of the oil is high,

typically over 100,000 to 1,000,000+ cP at original reservoir conditions. Current

commercial thermal recovery processes used are Steam-Assisted Gravity Drainage

(SAGD) and Cyclic Steam Stimulation (CSS). These methods are both energy intensive and use large volumes of water to recover the oil. In this thesis, the focus is on SAGD- type processes. It has been demonstrated that operating strategy can be altered to improve SAGD performance but it is not clear how well configuration can be changed to improve recovery, energy intensity, thermal efficiency, water use, and flue gas emissions.

This thesis examines the impact of position and geometry of steam injectors on the performance of SAGD-like processes in homogenous and heterogeneous reservoirs.

Different injection well configurations including single horizontal (typical SAGD), offset

SAGD, and vertical/horizontal well combinations have been evaluated by using a detailed, three-dimensional, geostatistically-populated, large-scale thermal reservoir simulation model derived from core and log data of the Dover pilot site. The research reveals how injection well configuration impacts energy delivery to the reservoir, thermal efficiency, and how it changes the evolution of the steam conformance zone and oil flow dynamics in the reservoir. The results suggest that vertical injectors have the potential to deliver steam more efficiently than a single horizontal injector.

Acknowledgements

I would like to acknowledge to my supervisor Dr. Ian D. Gates for his valuable advice during the entire program. His help and guidance, and above all, his abundance of patience and understanding were instrumental in completion of my graduate studies.

I would like to acknowledge and thank the Government of Libya who provided the financial support to cover all my expenses during my visit to Canada, and all of the individuals who are working at the Libyan Cultural Section in Ottawa for their support and help.

I would like also to thank the examination committee, Dr. Mingzhe Dong, Dr.

Michael Kallos, and Dr. Stephen M. Hubbard for reading and reviewing my thesis. Their comments were very helpful.

I would like to thank all individuals at the University of Calgary who helped me throughout my MSc program.

I would like also to thank all my family-members and friends back home for their continuous support during my stay in Canada

Dedication

To my parents, Rahma, and Rajab,

Thanks for your prayers for me

To my family, Hanaa, Moaid and Sufana

Thanks for being patient during my MSc. program.

Table of Contents

Approval Page ...... ii Abstract ...... iii Acknowledgements ...... iv Dedication ...... v Table of Contents ...... vi List of Tables ...... I List of Figures and Illustrations ...... II List of Symbols, Abbreviations and Nomenclature ...... XI

CHAPTER ONE: INTRODUCTION ...... 1 1.1 Overview ...... 1 1.2 Statement of the Problem ...... 6 1.3 Objectives of the Study ...... 7 1.4 Methodology of Research ...... 7 1.5 Thesis Structure ...... 8

CHAPTER TWO: LITERATURE SURVEY ...... 10 2.1 Background of Steam-Based Recovery Processes ...... 10 2.1.1 Cyclic Steam Stimulation (CSS) ...... 11 2.1.2 Steam Flooding ...... 13 2.1.3 Steam Assisted Gravity Drainage (SAGD) ...... 13 2.2 Development of Steam-Assisted Gravity Drainage Well Configurations ...... 14 2.3 Effects of Reservoir Heterogeneities on SAGD ...... 35

CHAPTER THREE: CONSTRUCTION OF THE THERMAL RESERVOIR MODEL ...... 39 3.1 Summary ...... 39 3.2 Model Dimensions ...... 39 3.3 Geological Model ...... 41 3.3.1 Homogeneous Geological Model ...... 41 3.3.2 Heterogeneous Geostatistical Model ...... 42 3.3.2.1 Regional Geological Description of Dover area ...... 42 3.3.2.2 Geostatistical Modeling Work ...... 43 3.4 Fluid Component Model ...... 54 3.5 Relative Permeability Data ...... 55 3.6 Overburden and Understrata Rock Properties ...... 56 3.7 Well Configurations ...... 57 3.7.1 Typical SAGD Well Configuration ...... 57 3.7.2 Vertical Well SAGD ...... 58 3.7.3 Vertical Injection Wells and Horizontal Production Well Configuration ...... 59 3.7.4 Offset Well Configurations ...... 59

vii

3.7.4.1 9 m Offset Well Configuration ...... 60 3.7.4.2 6 m Offset Well Configuration ...... 60 3.7.4.3 Offset Vertical Well Configuration ...... 61 3.7.4.4 Offset Vertical and Horizontal Well Configuration ...... 63 3.8 Well Constraints ...... 63 3.9 Model Initialization ...... 63 3.10 Model Life ...... 64

CHAPTER FOUR: IMPACT OF WELL CONFIGURATIONS IN HOMOGENEOUS GEOLOGY ...... 65 4.1 Summary ...... 65 4.2 Performance of SAGD-Like Operations Tested in a Homogeneous Geological Model ...... 65 4.2.1 Steam Injection Rate ...... 65 4.2.2 Cumulative Steam Injected ...... 67 4.2.3 Steam Chamber Volume ...... 67 4.2.4 Oil Production Rate ...... 69 4.2.5 Cumulative Oil Produced ...... 70 4.2.6 Water Production Rate ...... 72 4.2.7 Cumulative Water Produced ...... 72 4.2.8 Cumulative Water to Oil Ratio ...... 74 4.2.9 Thermal Efficiency, Steam to Oil Ratio (SOR) ...... 74 4.2.10 Energy Consumptions ...... 77 4.2.10.1 Energy Gained by Heat Transfer Model ...... 77 4.2.10.2 Energy Consumed by Steam Injected ...... 77 4.3 Validation of SAGD Model ...... 80 4.4 Analysis and Discussion of Results ...... 81 4.5 Natural Gas Consumption and Flue Gases Emissions ...... 104 4.6 Impact of Well Configuration on a Simple Economic Measure in Homogeneous Geology ...... 107

CHAPTER FIVE: IMPACT OF WELL CONFIGURATIONS IN HETEROGENEOUS GEOLOGY ...... 110 5.1 Summary ...... 110 5.2 Performance of SAGD-Like Operations Tested in a Heterogeneous Reservoir ...110 5.2.1 Steam Injection Rate ...... 110 5.2.2 Cumulative Steam Injected ...... 111 5.2.3 Steam Chamber Volume ...... 113 5.2.4 Oil Production Rate ...... 113 5.2.5 Cumulative Oil Produced ...... 114 5.2.6 Water Production Rate ...... 115 5.2.7 Cumulative Water Produced ...... 116 5.2.8 Cumulative Water to Oil Ratio ...... 118

viii

5.2.9 Thermal Efficiency, Steam to Oil Ratio (SOR) ...... 118 5.2.10 Energy Consumptions ...... 120 5.2.10.1 Energy Gained by Heat Transfer Model ...... 120 5.2.10.2 Energy Consumed by Steam Injected ...... 120 5.3 Validation of SAGD Model ...... 123 5.4 Analysis and Discussion of Results ...... 124 5.5 Impact of Reservoir Heterogeneity on Performance ...... 150 5.6 Impact of Heterogeneous Geology on Natural Gas Consumption and Flue Gases Emissions...... 157 5.7 Impact of Well Configuration on a Simple Economic Measure in Heterogeneous Geology ...... 160

CHAPTER SIX: CONCLUSIONS AND RECOMMENDATIONS ...... 162 6.1 Conclusions ...... 162 6.2 Recommendations for Future Work ...... 163

BIBLIOGRAPHY ...... 165

APPENDICES ...... 173 A. Core Data Examinations of 17 Wells Used to Construct Heterogeneous Geostatistical Model...... 173 B. Reservoir Simulation Input Files...... 226 C. Wells Used to Validate the SAGD Model...... 227

List of Tables

Table 1-1: Initial in--place resources of crude bitumen by deposit (ERCB 2007)...... 1

Table 3-1 Average properties of the homogeneous reservoir model ...... 42

Table 3-2: Properties of the fluid component model...... 55

Table 3-3: Relative permeability data used in model (Good et al. 1997)...... 56

Table 3-4: Average properties of the homogeneous reservoir model (Gates and Chakrabarty 2006)...... 56

Table 4-1: Heat energy gained by heat transfer model in cases tested in the homogeneous geological model...... 78

Table 4-2: Comparison of the performance of typical SAGD operation in the field and the SAGD numerical model...... 81

Table 4-3: Performance of different well configurations in homogeneous reservoir model...... 104

Table 4-4: Cumulative generated CO2 to produced oil ratio (cCOR) and consumed CH4 to produced oil ratio (cNOR) in homogeneous model...... 107

Table 4-5: Economic (well cost per unit volume oil produced) performance of well configurations considered in this work...... 108

Table 5-1: Heat energy gained by reservoir during the steam circulation stage in heterogeneous model...... 121

Table 5-2: Comparison of the performance of typical SAGD operation in the field and the SAGD numerical model...... 123

Table 5-3: Impact of homogeneous and heterogeneous geology on process performance in different well configurations...... 151

Table 5-4: Cumulative generated CO2 to produced Oil Ratio (cCOR) and consumed CH4 to produced Oil Ratio (cNOR)...... 160

Table 5-5: Economic performance of SAGD-Like processes under different well configurations...... 160

List of Figures and Illustrations

Figure 1-1: Oil sand areas in Alberta, Canada (http://upload.wikimedia.org/wikipedia/commons/7/7a/Athabasca_Oil_Sands_m ap.png n.d.)...... 2

Figure 1-2: Athabasca bitumen viscosity as a function of temperature...... 4

Figure 1-3: A schematic diagram of a SAGD process proposed by Butler (Butler, 1982) ...... 5

Figure 2-1: A schematic representation of Cyclic Steam Stimulation (CSS) (Imperial Oil, 2008)...... 12

Figure 2-2: A schematic representation of standard SAGD process (Bagci 2006)...... 14

Figure 2-3: Drawing from Butler's (1982) SAGD Patent...... 16

Figure 2-4: Front and side views of horizontal wellpair used in Joshi’s (1986) experiments...... 17

Figure 2-5: Front and side views of vertical injection well and horizontal production well used in Joshi’s (1986) experiments...... 17

Figure 2-6: Pre-heat vertical steam injector proposed by Chung and Butler (1989b)...... 18

Figure 2-7: The HASDrive process (Anderson 1977)...... 19

Figure 2-8: HASDrive process with horizontal well (Anderson et al. 1976)...... 20

Figure 2-9: Vertical HASDrive configuration proposed by Anderson et al. (1976)...... 20

Figure 2-10: Vertical HASDrive well configuration proposed by Anderson et al. (1977)...... 21

Figure 2-11: Horizontal configuration of HASDrive process (Anderson 1983)...... 23

Figure 2-12: HASDrive UTF pilot design (Duerksen 1988)...... 23

Figure 2-13: Advanced Heat Annulus Steam Drive process (Porter 1984)...... 24

Figure 2-14: SAGD and HASDrive well configurations (Sarkar and Deo 1993)...... 25

Figure 2-15: Single Well SAGD configuration (Shen 1998)...... 25

Figure 2-16: SW-SAGD well configuration (Oballa and Buchanan 1996)...... 26

III

Figure 2-17: Different SAGD well configurations (Chan and Fong 1997)...... 27

Figure 2-18: SAGD well configurations (Ehlig-Economides et al. 2001)...... 29

Figure 2-19: Fast-SAGD well configuration (Polikar et al. 2000)...... 30

Figure 2-20: Typical SAGD and Fast-SAGD well configurations (Shin and Polikar 2004)...... 31

Figure 2-21: A symmetry element representing square "half pad" with producers (black) and injectors (red) (Stalder 2005)...... 33

Figure 2-22: The JAGASS wellpair configuration (Gates et al. 2007)...... 34

Figure 2-23: First shale barrier physical model experiment (Joshi 1986)...... 36

Figure 2-24: Second shale barrier physical model experiment (Joshi 1986)...... 37

Figure 3-1: Arrangement of gridblocks in the crosswell direction...... 40

Figure 3-2: Arrangement of gridblocks in the downwell directions...... 40

Figure 3-3: Permeability-Porosity transform from core data...... 44

Figure 3-4: Distribution of wells throughout the geological model...... 45

Figure 3-5: Variogram used for porosity distribution...... 47

Figure 3-6: Porosity distribution throughout reservoir model...... 47

Figure 3-7: Variogram used for oil saturation distribution...... 48

Figure 3-8: Oil saturation distribution throughout the reservoir model...... 48

Figure 3-9: Variogram used for horizontal permeability distribution...... 49

Figure 3-10: Horizontal permeability realization...... 50

Figure 3-11: Variogram used for vertical permeability distribution of IHS zone...... 51

Figure 3-12: Vertical permeability realization of IHS zone...... 52

Figure 3-13: Variogram used for vertical permeability in cross-bedded sand zone...... 52

Figure 3-14: Vertical permeability realization of cross-bedded sand zone...... 53

Figure 3-15: Composite vertical permeability realization built from IHS and cross- bedded sand zones...... 53

Figure 3-16: A sketch of Typical SAGD well configuration ...... 57

Figure 3-17: A sketch of vertical well SAGD scheme. This configuration is referred to as VSAGD...... 58

Figure 3-18: A schematic representation of well configuration of a SAGD-Like process consisting of a row of vertical injectors positioned above a horizontal producer. This well configuration is referred to as the VINGS-SAGD...... 59

Figure 3-19: A schematic representation of a 9m-offset injector from a producer well configuration for a SAGD-Like Process ...... 60

Figure 3-20: A schematic representation of a 6m-offset horizontal injector from a horizontal producer ...... 61

Figure 3-21: A schematic representation of 6m-offset vertical injectors from vertical producers for a SAGD-Like process...... 62

Figure 3-22: A schematic representation of 6m-offset vertical injectors from a horizontal producer for a SAGD-Like process...... 62

Figure 4-1: Comparison of steam injection rates in homogeneous model...... 66

Figure 4-2: Comparison of cumulative steam injected in homogeneous model...... 68

Figure 4-3: Comparison of steam chamber volumes in homogeneous model...... 68

Figure 4-4: Comparison of oil production rates in homogeneous model...... 70

Figure 4-5: Comparison of cumulative oil produced in homogeneous model...... 71

Figure 4-6: Comparison of oil recovery factor in homogeneous model...... 71

Figure 4-7: Comparison of water production rate in homogeneous model...... 73

Figure 4-8: Comparison of cumulative water produced in homogeneous model...... 73

Figure 4-9: Comparison of cumulative water-to-oil ratio in homogeneous model...... 74

Figure 4-10: Comparison of cumulative steam-to-oil ratio in homogeneous model...... 75

Figure 4-11: Comparison of instantaneous steam-to-oil ratio in homogeneous model. ... 76

Figure 4-12: Comparison of cumulative heat gained by heaters to achieve thermal communication between the injectors and producers in homogeneous model...... 78

Figure 4-13: Comparison of enthalpy injection rate as steam in homogeneous model. ... 79

Figure 4-14: Comparison of cumulative enthalpy injected as steam in homogeneous model...... 79

Figure 4-15: Temperature profile at the end of steam circulation stage: Typical SAGD Case...... 82

Figure 4-16: Temperature profile at the end of steam circulation stage: Offset6- SAGD Case...... 82

Figure 4-17: Temperature profile at the end of steam circulation stage: Offset9- SAGD Case...... 83

Figure 4-18: Temperature profile at the end of steam circulation stage: VINGS- SAGD Case...... 83

Figure 4-19: Temperature profile at the end of steam circulation stage: Offset6- VINGS- SAGD Case...... 84

Figure 4-20: Temperature profile at the end of steam circulation stage: VSAGD Case...... 84

Figure 4-21: Temperature profile at the end of steam circulation stage: Offset6- VSAGD Case...... 85

Figure 4-22: Oil Saturation profile at the end of the production operation: Typical SAGD Case...... 90

Figure 4-23: Oil Saturation profile at the end of the production operation: Offset6- SAGD Case...... 90

Figure 4-24: Oil Saturation profile at the end of the production operation: Offset9- SAGD Case...... 91

Figure 4-25: Oil Saturation profile at the end of the production operation: VINGS- SAGD Case...... 91

Figure 4-26: Oil Saturation profile at the end of the production operation: Offset6- VINGS-SAGD Case...... 92

Figure 4-27: Oil Saturation profile at the end of the production operation: VSAGD Case...... 92

Figure 4-28: Oil Saturation profile at the end of the production operation: Offset6- VSAGD Case...... 93

Figure 4-29: Distribution of phases in the reservoir at the beginning of SAGD mode in the Typical SAGD case...... 95

Figure 4-30: Distribution of phases in the reservoir after one year of SAGD mode in the Typical SAGD case...... 95

Figure 4-31: Distribution of phases in the reservoir after two years of SAGD mode in the Typical SAGD case...... 96

Figure 4-32: Distribution of phases in the reservoir after four years of SAGD mode in the Typical SAGD case...... 96

Figure 4-33: Distribution of phases in the reservoir after six years of SAGD mode in the Typical SAGD case...... 97

Figure 4-34: Distribution of phases in the reservoir after eight years of SAGD mode in the Typical SAGD case...... 97

Figure 4-35: Distribution of phases in the reservoir after twelve years of SAGD mode in the Typical SAGD case...... 98

Figure 4-36: Distribution of phases in the reservoir after sixteen years of SAGD mode in the Typical SAGD case...... 98

Figure 4-37: Distribution of phases in the reservoir at the beginning of SAGD mode in the VINGS-SAGD case...... 99

Figure 4-38: Distribution of phases in the reservoir after one year of SAGD mode in the VINGS-SAGD case...... 99

Figure 4-39: Distribution of phases in the reservoir after two years of SAGD mode in the VINGS-SAGD case...... 100

Figure 4-40: Distribution of phases in the reservoir after four years of SAGD mode in the VINGS-SAGD case...... 100

Figure 4-41: Distribution of phases in the reservoir after six years of SAGD mode in the VINGS-SAGD case...... 101

Figure 4-42: Distribution of phases in the reservoir after eight years of SAGD mode in the VINGS-SAGD case...... 101

Figure 4-43: Distribution of phases in the reservoir after twelve years of SAGD mode in the VINGS-SAGD case...... 102

Figure 4-44: Distribution of phases in the reservoir after sixteen years of SAGD mode in the VINGS-SAGD case...... 102

Figure 4-45: Comparison of cumulative methane consumed in homogeneous model. .. 105

VII

Figure 4-46: Comparison of cumulative carbon dioxide emitted in homogeneous model...... 106

Figure 4-47: Comparison of cumulative consumed CH4 to produced oil ratio (cNOR) in homogeneous model...... 106

Figure 4-48: Comparison of cumulative generated CO2 to produced oil ratio (cCOR) in homogeneous model...... 107

Figure 5-1: Comparison of steam injection rate in heterogeneous model...... 111

Figure 5-2: Comparison of cumulative steam injected in heterogeneous model...... 112

Figure 5-3: Comparison of steam chamber volumes in heterogeneous model...... 112

Figure 5-4: Comparison of oil production rates in heterogeneous model...... 113

Figure 5-5: Comparison of cumulative oil produced in heterogeneous model...... 114

Figure 5-6: Comparison of oil recovery factor in heterogeneous model...... 115

Figure 5-7: Comparison of water production rates in heterogeneous model...... 116

Figure 5-8: Comparison of cumulative water produced in heterogeneous model...... 117

Figure 5-9: Comparison of cumulative water to oil ratios in heterogeneous model...... 117

Figure 5-10: Comparison of cSOR in heterogeneous model...... 119

Figure 5-11: Comparison of iSOR in heterogeneous model...... 119

Figure 5-12: Comparison of energy gained by the reservoir during the steam circulation stage in heterogeneous model...... 121

Figure 5-13: Comparison of enthalpy injection rates in heterogeneous model...... 122

Figure 5-14: Comparison of cumulative enthalpy injected in heterogeneous model. .... 122

Figure 5-15: Temperature distribution at end of steam circulation stage: Typical SAGD case...... 124

Figure 5-16: Temperature distribution at end of steam circulation stage: Offset6- SAGD case...... 125

Figure 5-17: Temperature distribution at end of steam circulation stage: Offset9- SAGD case...... 125

VIII

Figure 5-18: Temperature distribution at end of steam circulation stage: VINGS- SAGD case...... 125

Figure 5-19: Temperature distribution at end of steam circulation stage: Offset6- VINGS-SAGD case...... 125

Figure 5-20: Temperature distribution at end of steam circulation stage: VSAGD case...... 126

Figure 5-21: Temperature distribution at end of steam circulation stage: Offset6- VSAGD case...... 126

Figure 5-22: Oil saturation distribution at end of operation: Typical SAGD case...... 129

Figure 5-23: Oil saturation distribution at end of operation: Offset6-SAGD case...... 130

Figure 5-24: Oil saturation distribution at end of operation: Offset9-SAGD case...... 130

Figure 5-25: Oil saturation distribution at end of operation: VINGS-SAGD case...... 131

Figure 5-26: Oil saturation distribution at end of operation: Offset6-VINGS-SAGD case...... 131

Figure 5-27: Oil saturation distribution at end of operation: VSAGD case...... 132

Figure 5-28: Oil saturation distribution at end of operation: Offset6-VSAGD case. .... 132

Figure 5-29: Distribution of phases in the reservoir at the end of steam circulation stage: Typical SAGD case...... 134

Figure 5-30: Distribution of phases in the reservoir after one year of operation: Typical SAGD case...... 135

Figure 5-31: Distribution of phases in the reservoir after two years of operation: Typical SAGD case...... 136

Figure 5-32: Distribution of phases in the reservoir after four years of operation; Typical SAGD case...... 137

Figure 5-33: Distribution of phases in the reservoir after six years of operation: Typical SAGD case...... 138

Figure 5-34: Distribution of phases in the reservoir after eight years of operation: Typical SAGD case...... 139

Figure 5-35: Distribution of phases in the reservoir after twelve years of operation: Typical SAGD case...... 140

Figure 5-36: Distribution of phases in the reservoir after sixteen years of operation: Typical SAGD case...... 141

Figure 5-37: Distribution of phases in the reservoir at the end of steam circulation stage: VINGS-SAGD case...... 142

Figure 5-38: Distribution of phases in the reservoir after one year of operation: VINGS-SAGD case...... 143

Figure 5-39: Distribution of phases in the reservoir after two years of operation: VINGS-SAGD case...... 144

Figure 5-40: Distribution of phases after four years of operation: VINGS-SAGD case. 145

Figure 5-41: Distribution of phases in the reservoir after six years of operation: VINGS- SAGD case...... 146

Figure 5-42: Distribution of phases in the reservoir after eight years of operation: VINGS- SAGD case...... 147

Figure 5-43: Distribution of phases in the reservoir after twelve years of operation: VINGS- SAGD case...... 148

Figure 5-44: Distribution of phases in the reservoir after sixteen years of operation: VINGS- SAGD case...... 149

Figure 5-45: Effect of vertical to horizontal permeability ratio on vertical growth of the steam chamber in homogeneous reservoir: Typical SAGD case...... 152

Figure 5-46: Effect of vertical to horizontal permeability ratio on vertical growth of the steam chamber in heterogeneous reservoir: Typical SAGD case...... 153

Figure 5-47: Effect of vertical to horizontal permeability ratio on vertical growth of the steam chamber in homogeneous reservoir: VINGS- SAGD case...... 153

Figure 5-48: Effect of vertical to horizontal permeability ratio on vertical growth of the steam chamber in heterogeneous reservoir: VINGS- SAGD case...... 154

Figure 5-49: Impact of geology (A=homogeneous, B=heterogeneous) on lateral growth of steam chamber: Typical SAGD case...... 155

Figure 5-50: Impact of geology (A=homogeneous, B=heterogeneous) on lateral growth of steam chamber: VINGS-SAGD case...... 155

Figure 5-51: Effect of heterogeneity on performance of Typical SAGD case...... 156

Figure 5-52: Effect of heterogeneity on performance of VINGS-SAGD case...... 157

Figure 5-53: Comparison of cumulative methane consumed in heterogeneous model. . 158

Figure 5-54: Comparison of cumulative CO2 emitted in heterogeneous model...... 158

Figure 5-55: Comparison of cumulative CH4 to produced oil ratio (cNOR) in heterogeneous model...... 159

Figure 5-56: Comparison of cumulative CO2 to produced oil ratio (cCOR) in heterogeneous model...... 159

List of Symbols, Abbreviations and Nomenclature

Symbol Definition AOSTRA Alberta Oil Sands Technology and Research Authority API American Petroleum Institute oC Degrees Celsius cCOR Cumulative CO2-to-Oil Ratio CDOR Calendar Day Oil Rate cEOR Cumulative Energy-to-Oil Ratio cNOR Cumulative Natural Gas to Oil Ratio cP Centipoises cSOR Cumulative Steam-to-Oil Ratio CSS Cyclic Steam Stimulation CWE Cold Water Equivalent D Darcy ERCB Energy Resources and Conservation Board GGS Gaussian Geostatistical Simulations GJ Gigajoule ICCT Insulated Concentric Coiled Tubing IHS Inclined Heterolithic Strata iSOR Instantaneous Steam-to-Oil Ratio JAGASS J-well And Gravity Assisted Steam Stimulation K Degree Kelvin kg/m3 Kilogram per cubic meters krw Water Relative Permeability krow Oil Relative Permeability in Oil-Water System krg Gas Relative Permeability krog Oil Relative Permeability in Oil-Gas System krwiro End Point of Relative Permeability to Water at Residual Oil krocw End Point of Relative Permeability to Oil at Connate Water krgcw End Point of Relative Permeability to Gas at Irreducible Liquid kh Horizontal Permeability kv Vertical Permeability kPa Kilopascal kJ Kilojoule Kv1 First Coefficient for Gas-Liquid K-value Correlation, kPa o Kv4 Fourth Coefficient for Gas-Liquid K-value Correlation, C o Kv5 Fifth Coefficient for Gas-Liquid K-Value Correlation, C m Meter mPa s Millipascal Second (1 mPa s = 1 cP) MPa Megapascal n Coefficient in Oil Viscosity - Temperature Correlation OOIP Original Oil In Place RF Recovery Factor

XII

Symbol Definition

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 SAGD Steam-Assisted Gravity Drainage STARSTM Advanced Thermal Reservoir Simulator (CMG 2007) SW-SAGD Single Well Steam-Assisted Gravity Drainage T Temperature Tr Reservoir Temperature UTF Underground Test Facility UWI Universal Well Identifier XSAGD Cross-Well Steam-Assisted Gravity Drainage 3D Three Dimensional v Kinematic viscosity ρ Density µ Viscosity

ρ o Oil density

ρ osc Oil density at Standard Conditions

Chapter One: Introduction

1.1 Overview

The volume of the deposit of oil sands (called also crude bitumen) in Canada is

similar to that of the conventional crude oil in the Middle East (Butler 1994). In fact,

Canada has the largest deposit of bitumen in the world (Wightman et al. 1989). Currently,

synthetic crude oil derived from oil sands plays a significant role on the energy supply of

Canada and given future growth of energy need; it will be an increasingly more important

fossil fuel energy source (Farouq Ali, 2005).

As of December 2006, the Energy Resources and Conservation Board (ERCB)

reported that the Province of Alberta has about 270,000 million cubic metres (1,700,000

million bbl) of crude bitumen in place. As shown in Figure 1-1, this bitumen is accumulated in three main reservoir deposits: Peace River, Cold Lake, and Athabasca

(ERCB 2007). A summary of initial in-place resources of crude bitumen in the province of Alberta by deposit is listed in Table 1-1.

Table 1-1: Initial in--place resources of crude bitumen by deposit (ERCB 2007). Oil Sands Area Initial Volume in Place, 106 m3 (bbl) Peace River 21,565 (135,640) Cold Lake 31,013 (195,066) Athabasca 217,723 (1,369,434) Total 270,296 (1,700,108)

As reported by ERCB (2007), the ultimate potential recoverable crude bitumen by current technologies is about 50,000 million cubic metres. This is a small fraction, about

18.5 %, of the original bitumen in place. Currently, only 3 per cent of the initial established crude bitumen reserves have been produced since commercial production, principally by mining, started in 1967 (ERCB 2007).

Figure 1-1: Oil sand areas in Alberta, Canada (http://upload.wikimedia.org/wikipedia/commons/7/7a/Athabasca_Oil_Sands_map. png n.d.).

The key question is then: how can we improve bitumen production? Also, what

does this improvement mean? For example, is it with respect to energy intensity? Is it

with respect to flue gas emissions and water usage? In general, one would want the best

3 of all of these questions, improved bitumen production with reduced energy intensity, reduced emissions, and reduced water usage.

Despite the abundance of oil sands in Alberta, these oils are very viscous and essentially immobile at reservoir conditions. The viscosity of tar sands is typically more than 100,000 cp at the reservoir temperature (Farouq Ali, 2005). For example, in Cold

Lake the viscosity of the bitumen at original conditions is over 200,000 cP. In Athabasca, it is typically greater than 1,000,000 cP. Of all oil sands resources in Alberta, less than

5% is mineable. This portion of the resource is located on the north-eastern part of the

Athabasca oil sands area (Wightman et al. 1989). The remainder of the bitumen is too deep to be mined by conventional methods. Therefore, in situ recovery processes must be used to produce these oil sands deposits. This implies that before bitumen can be produced to the surface, its viscosity must be reduced so that it is mobile under reasonable pressure forces and gravity drainage.

There are several means that can be used to reduce the viscosity of bitumen. The most used is temperature, usually achieved by injecting steam into the bitumen formation.

An increase of the bitumen temperature can lead to a remarkable reduction in its viscosity. The viscosity of Athabasca bitumen versus temperature is displayed in Figure

1-2 (Mehrotra 1982, Mehrotra and Svrcek 1986). The plot reveals that the viscosity drops by several orders of magnitude when the temperature is raised from 15 to 215°C.

Another means to reduce bitumen viscosity is by solvent dilution. Typical solvents considered for bitumen reservoirs are propane, butane, and diluents (gas-condensates).

Diluents mainly consist of C4 to C9 alkanes with roughly 5% aromatics. As the solvent and bitumen mix, the viscosity of mixture drops. Depending on the temperature and

solvent content, the bitumen phase viscosity can drop by several orders of magnitude.

One other route to reduce oil phase viscosity is by asphaltene precipitation. This can be

achieved by using propane, which leaves a viscous precipitate (often referred to as

asphaltene) and a relatively mobile oil phase.

10,000,000

1,000,000

100,000

10,000

1,000

Bitumen Viscosity (cp) Viscosity Bitumen 100

1 5 64 123 182 241 300 Temperature (C) Figure 1-2: Athabasca bitumen viscosity as a function of temperature.

Currently, most in situ recovery processes used to recover oil sands are steam- based. One commercial process is the Steam-Assisted Gravity Drainage (SAGD) method

(Butler 1994, 1998, 2001). There are several SAGD projects currently in operation and being developed in the Athabasca area (ERCB 2008). So far, SAGD pilots and commercial operations have demonstrated success by producing economic amounts of

bitumen (Butler 2001). However, variability in performance is large; there are many

SAGD wellpairs that have performed with low production rates and thermal efficiency.

This is usually a result of reservoir geology and operating strategy. It is required that

SAGD or SAGD-variants are robust, that is, they are geotolerant, so that they can be

tuned to operate with reasonable thermal efficiency in geologically-diverse reservoirs.

The SAGD recovery process was invented by Butler (Butler 1982) while he was at Imperial Oil. In this method, displayed in Figure 1-3, a top horizontal well injects

steam into the bitumen formation. The steam releases its latent heat to the oil sands and

heated bitumen flows under gravity drainage to the lower production well.

Figure 1-3: A schematic diagram of a SAGD process proposed by Butler (Butler, 1982)

There are a number of design issues that need to be understood to develop and improve the performance of SAGD. Some examples are well configurations and operating conditions such as steamtrap control and injection pressure (Carlson, 2003).

The higher the injection pressure, the higher the corresponding saturation temperature, the lower the bitumen viscosity, and consequently, the higher the bitumen production rate. However, the higher the saturation temperature, the greater the heat losses, and the lower the thermal efficiency.

In terms of steamtrap control, there is a required amount of liquid that must be maintained above the production well to prevent live steam from coning into the production well. The optimization of steamtrap control has been addressed by Edmunds

(1998), Ito et al. (1999), and Gates and Leskiw (2008). In conventional SAGD, two parallel horizontal wells are used. Although it seems intuitively correct that horizontal wells would maximize flow of injected and produced fluids, from an economic point of view, horizontal wells are significantly more expensive than vertical wells. Thus, it might be more economic to inject by a set of vertical wells and produce from a single horizontal well below the vertical wells. This is the subject of this thesis: the geometry and the position of vertical or horizontal wells will be examined to better understand how to improve performance of SAGD or SAGD-variant processes, enhance the thermal efficiency, and reduce emissions and water usage. A measure of the economic intensity will be used to assess each well configuration.

1.2 Statement of the Problem

The recovery efficiency of the SAGD process can be improved by properly understanding the delivery of injected fluid energy to the oil sand. That is, the key for improving the performance of SAGD is by direct control of steam delivery into the formation and maximally delivering latent heat to the bitumen rather than the cap rock or underlying strata.

Two practical matters in SAGD that must be accomplished are: first, establish thermal communication between the injector and producer to optimally create a steam chamber between the injection and production wells, and second, develop and grow the steam chamber along the entire length of the wellpair. Thermal communication is

7 required to make the oil between the wells mobile. When SAGD mode starts and steam is injected into the formation and fluids are produced from the production well, the steam displaces the mobile oil from the inter-well region of the reservoir and a steam chamber is born. Given the density difference between the steam and reservoir fluids, gravity drainage starts and the chamber grows into the formation. Continuous supply of steam together with well type (whether vertical or horizontal), configuration, and placement will play significant roles on the growth of the steam-saturated zone, and potentially its shape.

1.3 Objectives of the Study

The aims of the research documented in this thesis are:

1) determine the impact of different well configurations on SAGD performance,

2) understand the delivery of injected fluid energy in SAGD process in

homogeneous and heterogeneous reservoir media, and

3) determine if there are other well type combinations that could lead to

improvements of SAGD-like recovery processes.

1.4 Methodology of Research

To achieve the objectives of the research objectives, the overall approach is as follows:

1) build a generic homogeneous Athabasca-type reservoir,

2) construct a detailed heterogeneous Athabasca-type reservoir by using

geostatistics,

3) build a base case SAGD in the homogeneous and heterogeneous reservoir models,

simulate their performance, and analyze simulation results,

4) create a suite of SAGD-like well configurations (by using combinations of

vertical and horizontal wells) in the homogeneous and heterogeneous reservoir

models,

5) run simulations and analyze results of the SAGD-like variants,

6) determine why energy delivery improved or worsened in certain well

configurations, and

7) examine energy intensity, flue gas emissions, water use, and economic measure in

SAGD-like variants.

1.5 Thesis Structure

The remainder of this thesis is as follows:

Chapter Two provides an introduction to steam-based processes currently used and a literature review of well types and configurations used or proposed in SAGD and

SAGD-like processes. The importance of reservoir heterogeneity in SAGD processes is also discussed.

Chapter Three describes construction of the large-scale, 3D thermal reservoir models used in this research. A description of the heterogeneous geostatistical approach is presented. The well constraints, operating conditions, and input data to the reservoir simulation model are also presented.

Chapter Four outlines the results of the SAGD and SAGD-like models and

includes an analysis of the impact of heterogeneity on SAGD performance.

Chapter Five describes in detail the analysis done on the models including

energetics, gas emissions, water usage, and well costs.

Chapter Six summarizes the main conclusions of the research as well as recommendations for future work.

Chapter Two: Literature Survey

2.1 Background of Steam-Based Recovery Processes

Given the viscosity of bitumen at original conditions in oil sands in Western

Canada, it can be only produced if its viscosity is reduced by several orders of magnitude.

There are several means to achieve this but the most popular is to use heat. The higher the temperature is, the lower the bitumen viscosity is. In Chapter one, as Figure 1-2 shows, the viscosity of bitumen falls by several orders of magnitude when the temperature is raised to 215°C (Mehrotra 1982, Mehrotra and Svrcek 1986). A convenient means to heat the oil sand is by steam: it can be readily injected into the formation and stores a large amount of heat in the form of latent heat. Steam-based recovery processes where the enthalpy of steam is used to heat the oil sand are very effective at reducing oil viscosity and increase the mobility of reservoir fluids (Farouq

Ali 2005). Basically, as injected into the reservoir, steam releases its latent heat to the cold heavy oil or bitumen and while the quality of the steam is greater than zero, the steam is at saturation conditions and thus its pressure and temperature remain constant.

This is important since the viscosity of bitumen depends mainly on temperature and even though convective heat transfer in the steam chamber is proportional to the quality gradient, the steam temperature is constant which sets the bitumen viscosity throughout the saturated steam chamber.

The literature contains many proposed thermal and non-thermal methods, a few

piloted in the field and many more designed by reservoir simulation, to recover heavy

oils and bitumen. The variants on thermal methods are either cyclic or continuous

processes, single, multiple, or well patterns, and processes that use one or more drive

11 mechanisms. An example of a single-well, cyclic process is Cyclic Steam Stimulation

(CSS). An example of a multiple well process is Steam Flooding (SF).

2.1.1 Cyclic Steam Stimulation (CSS)

Cyclic Steam Stimulation (CSS) was originally discovered in Venezuela by accident when an injector produced a large volume of heavy oil when it was opened to intentionally reduce the steam pressure in the reservoir (Farouq Ali 2005). This process utilizes a single well which serves both as injector and producer. The main advantage of this process is that well costs are relatively low since a single well is used. On average, in

Cold Lake, the ultimate recovery is between 20 and 25% of the original bitumen in place

(OBIP) (Batycky 1997).

The three stages of each cycle of CSS are displayed in Figure 2-1. In the first stage of CSS, the steam is injected into the reservoir at high pressure, typically exceeding

10 MPa, to fracture the bitumen formation. By fracturing the formation, the steam moves rapidly into the formation and does so without pushing a large amount of oil away from the well. If steam was injected slowly into the formation, then the steam would potentially displace oil away from the well. After the specified amount of steam has been injected into the formation, then the well is shut in for a soak stage. In this stage, heat conducts away from the steam fracture zone into the oil sand. After the specified amount of soak time, the well is converted to production and reservoir fluids, including steam condensate, mobilized bitumen, and gas are produced to the surface. In early steam injection cycles, since an appreciable amount of oil around the wellbore is heated, the soak stage is not done and the well is flowed back immediately (Butler 1997, Farouq Ali

2005). After the oil production rate drops below an economic limit, then a new cycle starts and steam injection begins.

Figure 2-1: A schematic representation of Cyclic Steam Stimulation (CSS) (Imperial Oil, 2008).

The key driving mechanisms in CSS depend on the cycle number (Denbina at el.

1991, Farouq Ali 2005). In early cycles, the formation is fractured and the reservoir pressure in the near wellbore region is raised to over 10 MPa and the reservoir is dilated.

On production, the well becomes the low pressure point in the reservoir and fluids are produced to the surface under recompaction drive. Since the temperature is increased from the steam injection, the solubility of solution gas is decreased and as the pressure

13 falls, solution gas exsolves, bubbles form which expand and displace mobilized bitumen to the production well. Later, after the steam depletion chamber is sufficiently large, gravity drainage of bitumen occurs. An additional drive mechanism occurs due to fluid thermal expansion. CSS is used by Imperial Oil Ltd. in its Cold Lake operation (Butler

1997). In California, CSS is used as the first stage in the development of steam flood projects (Farouq Ali 2005).

2.1.2 Steam Flooding

Unlike CSS, steam flooding is a continuous steam injection process that uses multiple wells often in a regular arrangement. In this type of steam-based process, steam injects into specific injection wells and oil is produced from other separate wells. In some cases, it is used as follow-up process to CSS. The recovery factor can reach 50% or even more by using steam flooding; however, it uses huge amounts of steam to achieve this due to large heat losses to the overburden (Butler 1997, Farouq Ali 2005). Another drawback of steam flooding is that it is highly unfavourable in reservoirs containing very viscous oil (Butler 1997) since the initial oil mobility is too low to move it by steam displacement.

2.1.3 Steam Assisted Gravity Drainage (SAGD)

The Steam Assisted Gravity Drainage (SAGD) process is becoming one of the most used thermal processes to extract bitumen from the Athabasca deposit in Alberta.

The method is ideally suited to very viscous bitumens with low solution gas. The method has the potential to recover more than 50% of original bitumen in place.

SAGD uses two long horizontal wells, called a wellpair. The top horizontal well is the steam injector whereas the bottom one is the producer. The interwell spacing

14 between the injector and producer is usually less than 10 m, typically between 4 and 7 m.

Figure 2-2 displays a schematic describing the process. The idea is simple: injected steam flows away from the injection well into the formation and moves to the edge of the steam depletion chamber. The steam releases its latent heat to the oil sand heating the oil which now mobilized, flows under the action of gravity towards the production well

(Polikar and Cyr 2000). The latent heat liberated at the edge of the chamber is transferred largely by thermal conduction into the surrounding oil sand formation beyond the edge of the chamber (Butler 1994; Farouq Ali 1997, 2005; Bagci 2006).

Figure 2-2: A schematic representation of standard SAGD process (Bagci 2006).

2.2 Development of Steam-Assisted Gravity Drainage Well Configurations

Several authors have published their work about SAGD well placement and geometry in the literature to investigate its impact on performance of the process in the form of cumulative steam oil ratio and recovery factor (Joshi 1986, Shen 1998, Polikar and Cyr 2000, Ehlig-Economides et al. 2001, Polikar and Shin 2006, 2007). . The remainder of this section describes a literature survey that explores the development of

SAGD well placement and geometry. There are many well configurations that can be imagined under which the dominant driving force for bitumen movement is gravity drainage. One is a pair of horizontal wells as in SAGD; others are combinations of vertical and horizontal wells, or sets of vertical wells.

The lateral and vertical spacing between one or more injection and production wells are important factors to start and grow the steam chamber. This is because prior to establishing a steam chamber, thermal communication must be established between the injection and production wells. On starting SAGD, the oil sand between the wells is heated by conduction from the wells and when steam is injected into the top well and the bottom well is put on production, the mobile bitumen is displaced from the region between the wells. This then creates a density difference between the newly formed steam chamber and the bitumen at its edge. As a result, bitumen drains under gravity to the bottom of the chamber and is produced to the surface through the production well. In this manner, the steam chamber expands in the reservoir.

Butler (1982), in the original patent covering SAGD, disclosed the use of two

horizontal wells. Figure 2-3 displays the original concept described by Butler. Steam injects into the top well and fluids, including steam condensate, mobilized oil, and gas, are produced from the bottom well. As shown in Figure 2-3, Butler also suggested that a vertical fracture could be created between the wells to establish thermal communication between the two wells and enhance flow and distribution of steam into the reservoir.

Butler envisioned that oil and water segregated in the reservoir to produce distinct layers that flowed down the edges of the steam chamber. In later work, Butler derived a theory to predict the rate of bitumen drainage around an expanding steam chamber.

Figure 2-3: Drawing from Butler's (1982) SAGD Patent.

Joshi (1986) conducted a laboratory study to examine the performance of a steam- assisted gravity drainage process consisting of two well configurations: first, a vertical injector and a horizontal producer and second, a horizontal injector and a horizontal producer, as shown in Figure 2-4 and Figure 2-5. The experiments were conducted with

17 °API heavy oil (viscosity equal to about 800 cP at 22oC). He observed that heated oils

were produced from the entire length of the horizontal producer when a horizontal

injector was used resulting in a low cumulative steam to oil ratio from the beginning of

the project. On the other hand, a high cumulative steam to oil ratio resulted when using a

vertical injector due to the fact that heated oils were produced from just a limited portion

of the entire horizontal producer. Comparing both performances of well configurations,

Joshi concluded that a number of vertical injectors were required in order to achieve an

economic oil production rate.

Figure 2-4: Front and side views of horizontal wellpair used in Joshi’s (1986) experiments.

Figure 2-5: Front and side views of vertical injection well and horizontal production well used in Joshi’s (1986) experiments.

Chung and Butler (1989b) conducted an experimental work to examine the

performance of SAGD by using a pre-heat vertical injector located near a horizontal

producer. To achieve thermal communication between the vertical injector and the

18 horizontal producer, they proposed to circulate the steam down a tubing string with open end at the base of the vertical well. Steam flows upward through the annulus to the surface heating the formation and improving the injectivity of steam condensate into the formation. Then, steam is continuously injected through perforations of the vertical well near the top of the reservoir to establish a normal SAGD mode as shown in Figure 2-6.

Chung and Butler claimed that preheated oil can flow at an appreciable rate to the

horizontal production well from the beginning the steam injection.

Figure 2-6: Pre-heat vertical steam injector proposed by Chung and Butler (1989b).

Anderson (1977) conceived the idea of recovering viscous oils by using a solid

tubular sunk into the formation to provide heat energy by conduction (Duerksen 1988).

That is, hot fluid is injected through the tubular and the heat of the injected fluid is lost

19 through the wall of the tube to the cold oil sands. Then, a hot fluid is injected through a vertical injector to move heated viscous reservoir fluids toward a vertical producer. This method, called Heated Annulus Steam Drive (HASDrive), is shown in Figure 2-7.

Different configurations of HASDrive were patented by Chevron Research

Company (Anderson 1977, 1983, Anderson et al. 1976, 1977). Two vertical HASDrive well configurations are shown in Figure 2-9 and Figure 2-10. Figure 2-8 and Figure 2-11 show two different HASDrive horizontal well configurations.

Figure 2-7: The HASDrive process (Anderson 1977).

Figure 2-8: HASDrive process with horizontal well (Anderson et al. 1976).

Figure 2-9: Vertical HASDrive configuration proposed by Anderson et al. (1976).

Figure 2-10: Vertical HASDrive well configuration proposed by Anderson et al. (1977).

As shown in Figure 2-8, the HASDrive well (label 118) penetrates the oil sands zone horizontally, then, another injector (label 112) injects steam to move heated oil surrounding (label 114) the HASDrive well toward the production well (label 110). In this HASDrive configuration, the hot fluid in the well is not in direct contact with the reservoir. It is relatively time consuming to create a mobile bitumen zone by conduction

22 by using the HASDrive well. Furthermore, with injection pressures being held to less than fracture pressure, this could have a significant impact on the oil production rate in the horizontal HASDrive mode.

Anderson (1983) developed another horizontal HASDrive mode, so that the injected hot fluid was in a direct contact with reservoir fluid, and moved the heated reservoir fluids toward the producer, as shown in Figure 2-11. In this Figure, Label 10,

12, 18 show the injection, production, and HASDrive Wells drilled into the tar sands

formation (label 14).

In the vertical HASDrive well configuration modes, shown in Figure 2-9 and

Figure 2-10, the injection wells labelled 110, and 12, respectively, are placed away from

the HASDrive labelled 118, and 18, respectively, and production wells labelled 112, and

10, respectively. Labelled 127, and 27, respectively, the perforated intervals of the

production well is operated sequentially at increasing distance to improve the sweep

efficiency of process.

Duerksen (1988) reported results of a numerical simulation study done of the

HASDrive pilot that was conducted at the Underground Test Facility (UTF). He studied

the effect of operating conditions (steam injection pressure, production well pressure, and

injected steam quality) on the performance of the process. A diagram of the pilot design

of the UTF HASDrive pilot is presented in Figure 2-12.

Figure 2-11: Horizontal configuration of HASDrive process (Anderson 1983).

Figure 2-12: HASDrive UTF pilot design (Duerksen 1988).

Porter (1984) patented the Advanced Heated Annulus Steam Drive process to recover in-situ heavy oils. The method utilizes a horizontal and a vertical well labelled

20, and 30 respectively. Oil is produced through operating the vertical and horizontal

wells in complex injection procedures, so that heated oils are produced from previously

produced intervals. Figure 2-13 indicates how to apply the process in a field scale.

As shown in Figure 2-13, the horizontal well has two perforated intervals labelled

26 and 37 along the horizontal well. In the same manner, the vertical well has a

perforated interval labelled 34. The first stage produces heavy reservoir fluids by

injecting hot fluids through perforated intervals labelled 26 and 34 of the vertical and

horizontal wells, and recovering fluids through perforated interval labelled 37 of the

horizontal well. The second stage injects a hot fluid through the vertical well and through

perforated interval labelled 26 in the horizontal well. Oil is produced through the

perforated interval labelled 37. Perforated interval labelled 37 is moved back as the tar

sands formation is depleted around the vertical steam injector.

Figure 2-13: Advanced Heat Annulus Steam Drive process (Porter 1984).

Sarkar and Deo (1993) conducted a numerical simulation study to evaluate the performance of the horizontal HASDrive process with vertical injector and producer,

SAGD using a horizontal wellpair, and CSS using horizontal and vertical wells. Figure

2-14 shows the HASDrive process and SAGD well configurations used in this numerical

simulation study. Sarkar and Deo concluded that even though the HASDrive process

recovered more oil than both the SAGD and CSS processes, the steam-to-oil ratio was about twice that of the SAGD and CSS processes.

Figure 2-14: SAGD and HASDrive well configurations (Sarkar and Deo 1993).

Figure 2-15: Single Well SAGD configuration (Shen 1998).

Luft et al. (1995) reported on development and implementation of a new insulated concentric coiled tubing (ICCT) string for continuous steam injection in a horizontal

26 well. This process was implemented in a SAGD-like configuration that used a single well. The process was called Single Well Steam Assisted Gravity Drainage (SW-

SAGD). The SW-SAGD well configuration is shown in Figure 2-15. The authors claimed that the process was successfully operated in ELAN’s heavy oil lease at Cactus

Lake, Saskatchewan. Falk et al. (1996) also confirmed the feasibility of SW-SAGD process for a field pilot, after studying the key design parameters of the process, and reviewing data from the first pilot. In this process, the ICCT inserts into the horizontal wellbore injecting high quality steam to the toe of the well. Then, the condensed reservoir fluids enter the wellbore and flow back along the annulus to the heel to be produced. The idea of using insulated tubing is to minimize the heat loss, and steam condensation on its way to the oil producing zone.

Figure 2-16: SW-SAGD well configuration (Oballa and Buchanan 1996).

Oballa and Buchanan (1996) conducted a numerical simulation study to model

SW-SAGD by using a discretized wellbore flow model within a hybrid grid well model,

displayed in Figure 2-16, to account for the complexity of this process. In the computer

27 model, steam was injected through the tubing and heated fluid was produced from the annulus. They concluded that the drainage process using this type of configuration is very complicated to be operated to obtain economic performance.

Chan and Fong (1997) studied the performance of SAGD process under different

SAGD well configurations displayed in Figure 2-17. The results of their study suggested

favourable performance gains if the injector was offset from the producer. In comparison

to conventional SAGD, the “3-staggered” well configuration resulted in the best results in

terms of the oil recovery factor. However, this gain in performance came at the expense

of reduced thermal efficiency, that is, the steam to oil ratio was higher than that of

conventional SAGD.

Figure 2-17: Different SAGD well configurations (Chan and Fong 1997).

Chan and Fong also investigated the effect of offset distance on gravity drainage performance. That is, the injection well was systematically offset from the production well at several distances. The authors reported that an increase of 6% in ultimate oil

28 recovery over the non-offset case (conventional SAGD) when the injector was offset by a distance approximately equal to the oil pay section thickness. Nevertheless, increasing the distance of offset between the wells has a severe impact on the thermal efficiency of the process in the form of a higher steam-oil ratio. This is especially the case at the start of the process when thermal communication is being established.

Sasaki et al. (2001) found that the production rate can be significantly increased

when the vertical spacing between the injection and production wells is enlarged. Many

authors in the literature, such as Butler and Stephens (1981), Butler (1987), and Sugianto

and Butler (1990), also suggested greater vertical spacing between the two wells. Similar

to offset wells, there is now a greater amount of material between the wells for

conductive heating when trying to establish thermal communication between the wells.

As a result, the thermal efficiency of the process suffers.

Ehlig-Economides et al. (2001) studied the effect of adding producers above and

below the standard SAGD configuration. In this configuration, there are multiple stacks

of horizontal wells. Their idea was to add more wells to enhance heat transfer to the

reservoir. Three new configurations proposed in their study are displayed in Figure 2-18:

inverted SAGD is the case where the producer is above the injector, multilevel SAGD

has two producers below the injector, and sandwiched SAGD adds one producer above

the injector.

Figure 2-18: SAGD well configurations (Ehlig-Economides et al. 2001).

After investigating these SAGD configurations with thermal reservoir simulation,

Ehlig-Economides et al. concluded that further work was needed to be done to better

understand and optimize the performance of these SAGD configurations.

Polikar and Cyr (2000) proposed a new well configuration, called Fast-SAGD, to

improve the development of the steam chamber and accelerate communication of the

steam chamber to another horizontal well. In this configuration, displayed in Figure 2-20,

they suggested drilling a single horizontal well substantially parallel to, but roughly 50

meters away from the producer of a SAGD well pair. The single horizontal well is

operated in CSS mode. By using thermal reservoir simulation, Polikar and Cyr compared

the performance of standard SAGD and Fast-SAGD well configurations. They also

compared the results at different spacing between the wellpair and offset CSS well. They

found that introducing the offset well enhanced communication between the SAGD

30 steam chamber and the region of the reservoir surrounding the offset well. This also improved the performance of the process since more oil could be produced from the offset well as it operated CSS. This leads to an overall reduction of the cumulative steam oil ratio (cSOR), that is, an improvement of the thermal efficiency.

Figure 2-19: Fast-SAGD well configuration (Polikar et al. 2000).

Shin and Polikar (2004) reviewed several reservoir parameters to improve Fast-

SAGD performance by using two offset wells on either side of a single SAGD wellpair at

particular operating conditions in typical Cold Lake reservoirs. They also studied the

impact of reservoir parameters including permeability and reservoir thickness on

conventional SAGD.

Shin and Polikar’s study revealed operating conditions (steam injection pressure

and rate) and wellpair spacing which could be adjusted to improve performance of both

Fast-SAGD and typical SAGD well configurations. In SAGD, the operating conditions

they studied included steam injection rate and wellpair spacing. In Fast-SAGD, they

31 studied the impact of offset well location, steam injection pressure at the offset well, and steam injection rate at the SAGD injector. In addition, they examined the optimum number of offset wells required in Fast SAGD. The various SAGD and Fast-SAGD well configurations investigated by Shin and Polikar (2004) are displayed in Figure 2-20.

Figure 2-20: Typical SAGD and Fast-SAGD well configurations (Shin and Polikar 2004).

After reviewing the reservoir parameters and operating conditions for optimizing

standard SAGD and Fast-SAGD, Shin and Polikar concluded that the two offset wells

located between two SAGD well pairs is the most thermally efficient Fast-SAGD well

configuration. This configuration yielded the lowest cumulative steam to oil ratio. They

found that a number of six offset wells between two SAGD well pairs is still more

economic compared to the conventional SAGD. They found that the SAGD process is

favourable in Cold Lake type reservoirs with a minimum thickness of 20m and clean

(highly permeable and relatively homogeneous) sand.

Shin and Polikar (2006) extended their earlier work and conducted a simulation study of SAGD and Fast-SAGD in Athabasca, Cold Lake, and Peace River oil sands reservoirs. The efficiency of both processes was evaluated by developing a simple

thermal efficiency parameter based on three production performance parameters:

cumulative steam oil ratio (cSOR), calendar day oil rate (CDOR), and recovery factor

(RF). Then, from their simulation study, they concluded that Cold Lake and Peace River

type reservoirs were good candidates to implement Fast SAGD well configuration when

the offset well is placed 40 m away from the SAGD wellpair, start-up time of 1.5 years,

injection pressure of 8000 kPa at the offset well, and formation thicknesses between 20

and 30 m. On the other hand, they determined that the conventional SAGD well

configuration is the better process for thick, high permeability Athabasca type reservoirs

under maximum injection pressure of 1510 KPa.

Stalder (2005) introduced a well configuration called cross-SAGD (XSAGD). In

this well configuration, displayed in Figure 2-21, the injector is still located several meters above the production well but it is now perpendicular to the producer. However, he proposed that to achieve economic oil rate and thermal efficiency better than that of conventional SAGD, the sections of the wells close to the crossing point should be restricted to flow either at the beginning of or later during the operation of the process.

The underlying concept of this well configuration is that once the steam chamber is established between injection and production wells, it is a good idea to move the injector and the producer farther apart, both vertical and laterally. In this work, Stalder compared the conventional SAGD configuration with that of XSAGD under different operating strategies. He found that thermal efficiency can be worsened by using XSAGD well

33 configuration than that of typical SAGD configuration as the steam injection pressure is increased. Consequently, the cumulative steam oil ratio (cSOR) would be greater by using XSAGD. Stalder, however, claimed that the oil recovery obtained by using

XSAGD was remarkable, since the concept of XSAGD well configuration was developed to accelerate low pressure SAGD.

Figure 2-21: A symmetry element representing square "half pad" with producers (black) and injectors (red) (Stalder 2005).

Gates et al. (2007) suggested a new well configuration for steam-based gravity processes for reservoirs with vertical viscosity variations. In this well configuration, a combination of two wells was proposed. One is a horizontal injector, located at the top of the reservoir. This injector can start as a cold production well and then converted later to thermal use after cold production is no longer economic. The other well is a producer having an inclined J-shape to intersect almost all geological heterogeneity of reservoir.

Gates et al. took advantage of the vertical mobility gradient: they suggested that the heel

34 of the producer should be placed near the base of the reservoir, whereas the toe is to be placed few meters below the injector. This well configuration was called J-well and gravity assisted steam stimulation (JAGASS). A schematic of the JAGASS well configuration is shown in Figure 2-22.

Figure 2-22: The JAGASS wellpair configuration (Gates et al. 2007).

Through thermal reservoir simulation, Gates et al. suggested the use of the

JAGASS process rather than the conventional SAGD process to recover heavy oil from the reservoirs that have strong vertical gradients in oil mobility. Moreover, they concluded that the thermal efficiency of JAGASS was significantly higher than that of

SAGD.

All work mentioned in this literature survey have not highlighted the importance

of energy intensity under different well configurations. The question remains: what is the

35 best of these well configurations could have better performance in the based gravity drainage process.

2.3 Effects of Reservoir Heterogeneities on SAGD

The geology of reservoirs plays a significant role in the success of steam-based processes due to the fact that the injected fluids (steam) are usually costly and flow in the in the direction of least resistance in the reservoir. The flow resistance is a geological property of the reservoir and is captured by the permeablity of the reservoir. The higher the permeablity, the lower the flow resistance. Typically, the horizontal and vertical permeabilities vary by two to five times vertically and areally throughout the reservoir.

This heterogeneity of the permeabilities may lead to highly irregular distributions of the injected fluids (Farouq Ali 2005).

In addition, the ratio of vertical-to-horizontal permeabilities, kv/kh, has a large

impact on SAGD process. This is because the action of the gravity, the dominant drive

mechanism, operates in the vertical direction. The kv/kh ratio determines how the steam-

saturated depletion chamber grows within the reservoir. The formation of new minerals,

swelling of certain clays, and migration of others due to the interaction of rock minerals

and injected fluids may lead to irreparable injectivity or productivity loss. Bottom water

and high gas saturation zones tend to act as thief zones for the injected fluids. That is, it is

going to be quite challenging to exploit the injected fluid to the best advantage (Farouq

Ali 2005). In the light of that, having a heterogeneous geological model is required to

effectively evaluate the performance of SAGD process.

Sarkar and Deo (1993) stated that shale barriers (152 m (~500 feet) wide by 30.5

m (~100 feet) long by 12 m (~40 feet) thick, with zero porosity and permeability) could

36 lead the HASDrive, SAGD, and CSS processes to be uneconomic. These type of shale barriers resulted in a low thermal efficiency of all processes by interfering with vertical steam rise and oil drainage.

Joshi (1986) studied experimentally two orientations of shale barriers, as shown in

Figure 2-23 and Figure 2-24. In the first physical model, the shale layer had a 10 cm

breach in it. In the second one, the shale layer was 20 cm long. He reported that these

dimensions of shale barriers had a minor effect on the performance SAGD-like process

using horizontal wells.

Figure 2-23: First shale barrier physical model experiment (Joshi 1986).

Figure 2-24: Second shale barrier physical model experiment (Joshi 1986).

Yang and Butler (1992) conducted several physical model experiments to study the effect of layered reservoirs that contain different permeabilities and effect of shale barriers. Their results showed that faster production could be achieved if the higher permeability layer was above a lower permeability layer than that when the conditions were reversed. However, shale barriers, providing that their extent was not too large (less than 50 m when the results were scaled up to field dimensions), had less impact on the performance of the process.

Pooladi-Darvish and Mattar (2002) conducted a reservoir simulation study to show the performance of the SAGD process in the presence of a gas cap and top water layer in a selected area in Athabasca. They also proposed some discontinuous and continuous shale/mudstone barriers in their computer model based on log analysis of the wells found over the area of interest. They concluded that the presence of the top water layer could lower the thermal efficiency of SAGD process as the steam chamber

38 approached the top water layer. However, shale barriers, especially areally extensive ones, could restrict the expansion of the steam chamber to the upper parts of the reservoir. That is, a gas cap sitting above an extensive shale barrier could have no effect on the SAGD process.

Based on a simulation study, Chen et al. (2007) claimed that continuous shale barriers located above well regions could severely lower the performance of the SAGD process. They also reported that vertical hydraulic fractures could enhance the performance of SAGD more than horizontal hydraulic fractures. They suggested the direction of the horizontal wells should be parallel to the vertical hydraulic fractures to maximize oil recovery from reservoirs that have vertical fractures.

Strobl et al. (1995) described in detail the impact of the Inclined Heterolithic

Stratification (IHS) unit flow at the UTF Dover SAGD pilot site on steam rise rate, oil

production, and thermal efficiency. The IHS unit sits at the top of the oil column and consists of nearly parallel shale and mud layers that are inclined by between 1 and 10°.

They claimed that due to lateral continuous mudstone-dominated IHS units that extended

over a distance of 150 m, a lower steam rise rate is expected in this flow unit. Thus,

steam (read energy) delivery to the oil sands embedded in the IHS unit is impaired and as

a consequence, oil drainage rates from this part of the reservoir is reduced compared to

that of clean, highly permeable, oil sand.

Authors are still on debate; how steam moves through heterogeneous reservoirs.

The delivery of the injected fluid energy into the porous media in steam-based gravity

drainage recovery processes has not been understood yet. In this work, the focus on the

delivery of injected fluid energy through a detailed geological model will be investigated.

Chapter Three: Construction of the Thermal Reservoir Model

3.1 Summary

This chapter describes the methods used to create the geological and reservoir

simulation models used in the research documented in this thesis. The gridding strategy

of the reservoir model is also presented.

3.2 Model Dimensions

The CMG GridbuilderTM software (CMG 2007) was used to build the large-scale thermal reservoir simulation model. For this research, an Athabasca type reservoir model, based on the Dover UTF Phase B site, is created since this type of reservoir appears to be most suited for gravity drainage thermal processes (Shin and Polikar 2006).

The geological model has physical dimensions of 600 m long by 150 m wide by

24 m high. These dimensions were chosen to fit a 500 m long wellpair with inter-wellpair spacing of 150 m. The thickness of the reservoir is 24 m.

As shown in Figures 3-1 and 3-2, the reservoir model is discretized into a regular

Cartesian grid consisting of 251 gridblocks in the crosswell direction, 50 gridblocks in the downwell direction, and 16 gridblocks in the vertical direction. In total, the model

has a total of 200,800 gridblocks. With current processing power, a reservoir model with

this number of gridblocks requires several days to run depending on the computer

processor speed and available memory.

Figure 3-1: Arrangement of gridblocks in the crosswell direction.

Figure 3-2: Arrangement of gridblocks in the downwell directions.

Figures 3-1 and 3-2 show that the gridblock dimensions vary. In the crosswell (I) direction, there are 2 gridblocks, each 10 m wide, at each side of the model. Adjacent to these blocks, there are 63 gridblocks, each 3 m wide, on both sides of the model. At the centre of the model, there are 121 gridblocks, each 1.5 m wide. In the downwell (J) direction, the model was discretized into 50 grid blocks of 3 m length each. In the vertical direction, from the top of the model, the first eight layers have a constant thickness of 2 m. The remaining 8 gridblocks have thickness equal to 1 m.

Even though the grid system is a regular Cartesian configuration, it was important to use smaller gridblock sizes near the wells where changes in pressure, temperature, oil

41 viscosity, and fluid saturations are pronounced. It is essential to have smaller gridblock sizes to obtain accurate solutions of the flow and energy equations and to reduce accumulation of numerical (grid and time) errors.

In Section 3.3, the construction of the spatial distribution of the porosity, permeability, and oil saturation from core data is described. Following Section 3.3, the

construction of the reservoir model including well constraints, relative permeability

curves, fluid data, and pressure-volume-temperature (PVT) data is described.

3.3 Geological Model

Two geological models were constructed for the research documented in this thesis.

The first is a homogeneous model. The properties are based on an Athabasca reservoir

model presented by Gates and Chakrabarty (2006). The second is a heterogeneous model

based on log and core data of the Dover UTF Phase B pilot site. These models will

permit analysis of the impact of geological heterogeneity on the performance of thermal

gravity drainage methods.

3.3.1 Homogeneous Geological Model

The homogeneous oil sand reservoir model was prepared with average properties typical of Athabasca type reservoirs. The properties of the model are listed in Table 3-1

(Gates and Chakrabarty 2006). Although a symmetry half-model could be used since the model is homogeneous, the full model was used. This was to simplify the comparison of the two models. The reservoir thickness is 24 m with horizontal permeability equal to 5

D. The vertical-to-horizontal permeability ratio is 0.2. Capillary pressure is set to zero because the oil-water interfacial tension is low at steam temperatures and capillary effects are very small compared to viscous, pressure, and gravity forces.

Table 3-1 Average properties of the homogeneous reservoir model Property value Depth to reservoir top, m 130 Net pay, m 24 Porosity, fraction 0.33 Initial oil saturation, Soi, fraction 0.85 Horizontal permeability, kh, D 5 Vertical permeability, kv, D 1 Capillary pressure, kPa 0 Effective rock compressibility, 1/kPa 14e-6 Rock heat capacity, kJ/m3 oC 2600 Rock thermal conductivity, kJ/m day oC 660

3.3.2 Heterogeneous Geostatistical Model

The heterogeneous model was created from log and core data of the Alberta Oil

Sands Technology and Research Authority (AOSTRA) Dover Underground Test Facility

(UTF) Phase B SAGD pilot site. A geostatistical model was created by using the

geostatistical modeling package available in the CMG GridbuilderTM pre-processor. The

UTF site is located in the north eastern part of Alberta, Canada (Strobl et al. 1995). In summary, the spatial distributions of porosity, oil saturation, horizontal and vertical permeabilities were constructed by using geostatistical techniques.

3.3.2.1 Regional Geological Description of Dover area

A detailed geological description of Dover UTF site can be found in (Strobl et al.

1995, Rottenfusser et al. 1988, and Wightman et al. 1989). The target reservoir at this

site is McMurray oil sands formation with dimension of about 3000 m long by 800 m

wide. Based on reservoir properties, the formation can be divided into three major flow

sections: first, trough cross-bedded sands near the base of formation, second, a transition

zone in the middle, and third, Inclined Heterolithic Stratification (IHS) near the top.

The cross-bedded unit is the best flow unit of this reservoir. Mostly, it is clean oil sand with porosity of more than 30% and with the richest oil saturation portion of the reservoir. Sources of the heterogeneity of cross-bedded unit are presented in the form of mudstone clast breccias and mudstone. However, the sources of heterogeneity in this flow unit are typically discontinuous and do not represent significant vertical flow barriers. The thickness of this unit is between about 15 and 20 m.

The middle flow unit is characterized by smaller-scale cross-bedded sands (10 to

30 cm bed sets) and current rippled laminated sands, in addition to a higher portion of argillaceous toe sets. Consequently, the transition zone has reduced oil saturation and lower absolute permeability. This region represents a gradational contact between the bottom and top flow units.

The top unit of the formation typically consists of inclined heterolithic beds which are laterally continuous over distances of up to 150 m. Sample measurements indicate that this unit flow has relatively low permeabilities (kh from about 1160 to 3500 mD) and low bitumen content.

3.3.2.2 Geostatistical Modeling Work

In this section, the construction of a static petrophysical model by using the geostatistical modeling package available in CMG GridbuilderTM 2007 version (CMG

2007) is described. The objective of developing a hypothetical geological model by using a geostatistical modelling approach was to effectively evaluate the performance of steam- assisted gravity drainage SAGD process under different well configurations in a heterogeneous system where the geology can interfere with steam rise and oil drainage.

The results of core measurements of 15 wells in the Dover area were collected from the AccuMapTM database software (IHS 2008). A permeability-porosity transform, displayed in Figure 3-3, based on 62 sample points was also derived from core data obtained from the BT06 and BTP03 wells (Strobl et al. 1995). For simplicity, the relationship between the natural logarithm of the permeability and porosity is considered linear (Gates 2005). The core data from the 17 (15+2) wells are listed in Appendix A. To condition the geological model, the wells were distributed throughout the model as

shown in Figure 3-4, to assign the petrophysical properties of McMurray formation.

Figure 3-3: Permeability-Porosity transform from core data.

The locations of wells were chosen and distributed on random basis with spacing

similar to that of the Dover pilot. Then, the original points taken from core analysis data

for all petrophysical properties were honoured and Sequential Gaussian Simulations

(SGS) were performed to populate the remainder of the gridblocks. However, before

45 performing simulations, experimental semi-variograms of oil saturations, porosities, and permeabilities were depicted and matched to analytical models.

Figure 3-4: Distribution of wells throughout the geological model.

The available analytical models used to match the experimental variograms are the

exponential, Gaussian, spherical, and power variograms. These models are used to

replace existing noisy data with a smooth analytical equation that provides a reasonable

representation of the data (Carlson 2003). The reservoir model generated is a generic

heterogeneous model for Athabasca reservoir that contains the essential characteristics of

the McMurray formation. Even the reservoir model does not represent a given Athabasca

site; it is a reasonable model for evaluating and comparing one process versus another.

The following Sections describe how spatial distributions of the fluid saturations, porosity, and vertical and horizontal permeabilities are created for the heterogeneous geological models. All figures of heterogeneous geological models shown in the

46 following sections were cut into slices to show the distribution of petrophysical properties

(porosity, permeability, oil saturation) through out the model.

3.3.2.2.1 Porosity

All core analysis data available from the 17 wells were used to set the porosity values at wellbores. Next, the experimental variogram was constructed. Then, the analytical model was fitted by adjusting the sill, range, and nugget effect until the analytical model fit the experimental variograms.

Figure 3-5 shows the variogram used to create the spatial distribution of porosity.

As shown in Figure 3-5, the analytical model that best fit the experimental variogram was

the exponential model. The fitting parameters after matching the analytical model were as

follows: nugget effect = 0.39, sill = 1.092, and range = 32.3877. Thus, this variogram

model was used to condition the SGS algorithm to spatially distribute porosity values

between wellbores. The SGS algorithm creates equiprobable realizations of the porosity

field in the model. The realization selected for the geological model, shown in Figure

3-6, was chosen so that the average porosity was equal to 0.35.

3.3.2.2.2 Oil Saturation

A set of oil saturation realizations was constructed in the same manner as that of

the porosity. The oil saturation data obtained from core data were assigned to the spatial

locations of the 17 wells discussed above. Figure 3-7 shows the experimental variogram and analytical variograms for the oil saturation. . A comparison of several analytical variograms models revealed that the exponential model fits the experimental data best.

The resulting fitted parameters are as follows: nugget effect = 0.4, sill = 1.076, and range

= 20.3045. The realization chosen for this work has average oil saturation equal to 0.85 and is displayed in Figure 3-8.

Figure 3-5: Variogram used for porosity distribution.

Figure 3-6: Porosity distribution throughout reservoir model.

Figure 3-7: Variogram used for oil saturation distribution.

Figure 3-8: Oil saturation distribution throughout the reservoir model.

3.3.2.2.3 Horizontal Permeability

The horizontal permeability realization was created in a similar manner as described above for porosity and oil saturation. The permeability-porosity transform displayed in Figure 3-3 was used to specify the permeability at the well locations. A

comparison of several variograms models revealed that the spherical model provided the

best fit of the experimental data. Figure 3-13 displays the experimental variogram of the

horizontal permeability and the spherical model. The fitted parameters are as follows:

nugget effect = 0, sill = 1, and range = 15.1846. The horizontal permeability of the

realization chosen is shown in Figure 3-10. This realization has an average horizontal

permeability between 5000 and 6000 mD.

Figure 3-9: Variogram used for horizontal permeability distribution.

Figure 3-10: Horizontal permeability realization.

3.3.2.2.4 Vertical Permeability

Unlike porosity, oil saturation, and horizontal permeability, two separate vertical permeability realizations were predicted: one for the IHS zone and the other for the trough cross-bedded sands zone. That is, vertical permeability values at the top of reservoir were individually predicted from core examinations of two wells to reliably account for the vertical deliverability of reservoir fluid from the IHS zone. Then, vertical permeability values in the trough cross-bedded sands were predicted to account for fluid conductivity in the vertical direction at the base of the reservoir model.

Vertical permeability values obtained from core samples in the IHS zone were assigned to wellbores of two wells in the computer model. Then, the experimental variogram was matched to an exponential variograms model. The experimental variogram and fitted model of the low vertical permeability IHS zone are shown in Figure

3-11.

Figure 3-11: Variogram used for vertical permeability distribution of IHS zone.

The fitted model parameters are 0.7, 1.073, and 4.77926 for the nugget effect, sill,

and range, respectively. Vertical permeability realizations of the IHS zone were

generated by using SGS. The chosen realization is displayed in Figure 3-12. In the same

manner, the vertical permeability realizations for the trough cross-bedded sands were

constructed. Figure 3-13 shows the experimental model. The best fit variograms model

was the spherical model (blue line). The fitted model parameters are as follows: nugget

effect = 1, sill = 1.071 and range = 2.95156. A set of realizations were constructed and

the chosen one is shown in Figure 3-14. To construct the full vertical permeability model, the vertical permeability realization of the IHS zone and the vertical permeability realization from the trough cross-bedded sands must be combined together. This was simply done by combining the IHS and cross-bedded sand zones. Figure 3-15 shows the

52 full vertical permeability realization used with the combined IHS and cross-bedded sand zones.

Figure 3-12: Vertical permeability realization of IHS zone.

Figure 3-13: Variogram used for vertical permeability in cross-bedded sand zone.

Figure 3-14: Vertical permeability realization of cross-bedded sand zone.

Figure 3-15: Composite vertical permeability realization built from IHS and cross- bedded sand zones.

3.4 Fluid Component Model

Three components are used in the reservoir model: bitumen, methane (CH4), and

Water (H2O). The oleic phase can be composed of bitumen and methane. The gas phase can be composed of methane and steam. The aqueous phase consists of water.

The average properties of a homogeneous fluid model are listed in Table 3-2. The dependence of bitumen viscosity on temperature is given by Mehrotra and Svrcek (1986) which is in the form of the Walther correlation (Farouq Ali 2005):

υ + =− 1 + vTTn 1 + )8.0log(log)/log()8.0log(log where υ is kinematic viscosity in centistokes, which relates to µ the dynamic viscosity, in centipoises, by υ=µ/ρ, where ρ is oil density, T is in K. The exponent n for Athabasca

bitumen is equal to 0.1719. In Chapter one, Figure 1-2 displays the dependence of

bitumen viscosity on temperature.

The liquid equivalent viscosity of methane is that given by Gates and Chakrabarty

(2006). To obtain the viscosity of the oil mixture, the log-linear mixing rule is used:

ln µoilphase = xbitumen ln µbitumen + xmethane ln µmethane

where xi is the mole fraction of component i. The methane K-value correlation was taken

from the CMG STARSTM User’s manual (2007). The properties of water and steam were taken from the CMG STARSTM internal database (CMG 2007).

The dependence of bitumen density on temperature is given by the following

correlation (Farouq Ali 2005):

T − 20 ρρ 1/( += ) o osc 1047

3 3 where, ρo is density of oil in kg/m at temperature T and ρosc is the density of oil in kg/m

at standard temperature (15°C). The density of Athabasca bitumen at standard conditions

is 999.3 kg/m3.

Table 3-2: Properties of the fluid component model. Property Value Reference pressure, kPa 600 Reference depth, m 140 o Initial reservoir temperature Tr, C 7 Dead bitumen viscosity @ Tr, mPa s 1600000 Bitumen gravity, degrees API 10 Bitumen density at 15°C, kg/m3 999.3 Bitumen molecular mass, g/gmole 570 Water thermal conductivity, kJ/m day oC 53.5 Gas thermal conductivity, kJ/m day oC 5 Bitumen thermal conductivity, kJ/m day oC 11.5 kv1, kPa 5.4547

kv4, °C -879.84

kv5, °C -265.99

3.5 Relative Permeability Data

Relative permeability data for the bitumen/water and liquid/gas systems are listed

in Table 3-3 (Good et al. 1997). As can be determined from the cross-over point of the bitumen/water curve, the system is water-wet. The irreducible water saturation (Swirr) and

relative permeability of water at irreducible oil saturation (krwiro) were taken to depend on

temperature (Husky 2007). In the reservoir model used in this research work, a single

reservoir rock type was used throughout the model. For three-phase relative

permeability, Stone’s model II was used (CMG 2007).

Table 3-3: Relative permeability data used in model (Good et al. 1997). Water-Bitumen System Gas-Oil System

Sw krw krow Sl krg krog 0.15 0.000000 1.000000 0.300 1.0000000000 0.0000000000 0.20 0.021822 0.938328 0.350 0.8600000000 0.0030000000 0.25 0.055627 0.876848 0.400 0.7200000000 0.0131100000 0.30 0.096163 0.815573 0.450 0.6000000000 0.0300000000 0.35 0.141800 0.754517 0.500 0.4900000000 0.0600000000 0.40 0.191648 0.693696 0.550 0.3800000000 0.0955100000 0.45 0.245131 0.633127 0.650 0.2200000000 0.2100000000 0.50 0.301840 0.572834 0.700 0.1500000000 0.2900000000 0.55 0.361464 0.512842 0.750 0.1000000000 0.3800000000 0.60 0.423761 0.453182 0.800 0.0500000000 0.4800000000 0.65 0.488533 0.393896 0.850 0.0243400000 0.5900000000 0.70 0.555615 0.335033 0.900 0.0098700000 0.7200000000 0.75 0.624869 0.276660 0.950 0.0023100000 0.8600000000 0.80 0.696173 0.218873 0.970 0.0007100000 0.9160000000 0.85 0.769426 0.161810 0.980 0.0002772317 0.9439940318 0.90 0.844534 0.105709 0.985 0.0001458613 0.9579971520 0.95 0.921416 0.051054 0.990 0.0000600000 0.9720000000 1.00 1.000000 0.000000 1.000 0.0000000000 1.0000000000 Relative Permeability Endpoint Temperature Dependence

Temperature, °C Swirr krwiro 10 0.15 0.0074 160 0.25 0.0144 310 0.40 0.0199

3.6 Overburden and Understrata Rock Properties

Heat losses from the reservoir to cap rock or understrata are taken into account in

the reservoir model. It is assumed that both are perfects seals with respect to fluid

movement, that is, no fluids are lost above or below the reservoir. Thermal properties of

the overburden and understrata are listed in Table 3-4.

Table 3-4: Average properties of the homogeneous reservoir model (Gates and Chakrabarty 2006). Property Value Rock heat capacity, kJ/m3 oC 2600 Rock thermal conductivity, kJ/m day oC 660

3.7 Well Configurations

This section outlines the well configurations tested in this research. All well configurations are evaluated in both the homogeneous and heterogeneous geological reservoir models.

3.7.1 Typical SAGD Well Configuration

Figure 3-16 displays a typical well configuration of a SAGD process. This well

configuration scheme consists of two parallel horizontal wells: the top one is the steam

injector whereas the bottom one is the producer. The interwell distance between the

injection and production wells is 5 m. The producer is positioned 2.5 m above the base of

the reservoir. The length of the wellpair is 500 m. In this research study, this well

configuration is referred to as Typical SAGD.

Figure 3-16: A sketch of Typical SAGD well configuration

3.7.2 Vertical Well SAGD

Figure 3-17 shows the vertical well SAGD well configuration. Technically, in this

SAGD-Like process, the vertical well serves as a steam injector in the upper part of the

reservoir and producer in the lower part of the reservoir. In practice, if this well

configuration was implemented in the field, steam would be injected down the casing

annulus and heated reservoir fluids would be produced through a production tubing

string.

To make the number of bottom hole locations roughly equal to that of Typical

SAGD, five vertical wells were used in a row. The vertical spacing between the injection

interval and the production interval is 5m. The lateral spacing between the vertical wells

is 100 m. In this work, this well configuration is referred to as VSAGD.

Figure 3-17: A sketch of vertical well SAGD scheme. This configuration is referred to as VSAGD.

3.7.3 Vertical Injection Wells and Horizontal Production Well Configuration

This multiple vertical and horizontal well configuration is displayed in Figure

3-18. To have roughly equivalent bottom hole locations, five vertical injectors are used to inject steam into the reservoir. A single horizontal production well is located 5 m below the vertical wells. The lateral spacing between the vertical injectors is 100 m. The production well is located 2.5 m above the base of the reservoir. This well configuration will be referred to as VINGS-SAGD.

3.7.4 Offset Well Configurations

In this family of well configurations, the injection wells are positioned offset by a certain distance from the production well. Both injection and production wells are horizontal wells. In the vertical direction, the injection well is positioned 5 m above the production well. The production well is located 2.5 m above the base of the reservoir.

3.7.4.1 9 m Offset Well Configuration

In this well configuration depicted in Figure 3-19, the injection well is located laterally 9 m away from a horizontal production well. Since the vertical spacing between both wells is 5 m, the total separation between the wells is about 10.3 m. This well configuration is referred to as Offset9-SAGD.

Figure 3-19: A schematic representation of a 9m-offset injector from a producer well configuration for a SAGD-Like Process

3.7.4.2 6 m Offset Well Configuration

In this case, as shown in the Figure 3-20, horizontal injector is located laterally 6 m away from the horizontal producer. The total separation between the wells is 7.8 m. This

well configuration is called Offset6-SAGD.

Figure 3-20: A schematic representation of a 6m-offset horizontal injector from a horizontal producer

3.7.4.3 Offset Vertical Well Configuration

In this configuration, vertical injection wells are offset by 6 m from vertical

production wells. This well configuration is depicted in Figure 3-21. The vertical spacing

between the injection and production wells is 5 m whereas the lateral distance between the vertical wellpairs is 100m. To keep consistent with the other models, five bottom hole locations were used, that is, five vertical injector/vertical producer pairs were used. This well configuration is referred to as Offset6-VSAGD.

Figure 3-21: A schematic representation of 6m-offset vertical injectors from vertical producers for a SAGD-Like process.

Figure 3-22: A schematic representation of 6m-offset vertical injectors from a horizontal producer for a SAGD-Like process.

3.7.4.4 Offset Vertical and Horizontal Well Configuration

In this well configuration, as shown in Figure 3-22, a row of five vertical injection

wells were offset 6 m away from a horizontal production well. The producer was

positioned 2.5 m above the bottom of the reservoir model. The vertical spacing between

the injectors and horizontal producer is 5 m whereas lateral spacing between the injectors

is 100m. This well configuration plan is called Offset6-VINGS-SAGD.

3.8 Well Constraints

All injection wells, whether vertical or horizontal, in this reservoir model were

modelled as line sources, whereas producers were presented as sinks. That is, wellbore

frictional pressure drop and influence of liquid hold-up were neglected (CMG 2007). In

other words, the major resistances to flow are taken to be those originating from the

reservoir. The injection well operating constraints were constant injection pressure of

2000 kPa with steam quality equal to 0.9 at the sandface. The corresponding steam saturation temperature is 216°C. The production wells were operated under the maximum steam production constraint equal to 1 m3/day. This is an alternate form of

steam trap control in that the maximum amount of steam allowed to be produced from the

reservoir is 1 m3/day Cold Water Equivalent (CWE).

3.9 Model Initialization

At initial conditions, bitumen is very viscous, and it cannot flow under gravity

drainage in porous media at original reservoir conditions. Before a steam chamber is

created, the bitumen between the injection and production wells has to be mobilized.

This is done by conductive heating from the wells; that is, steam is circulated in each of

the injection and production wells at the reservoir pressure (this period of time is called

64 the circulation period). This means that no fluid is injected into the reservoir. Rather, a small amount of oil is produced from the reservoir due to thermal expansion as it is conductively heated. After the oil between the wells is heated to above about 80°C, it is considered that thermal communication has been established. The oil between the wells is now mobile. Next, when the injection well is converted to higher pressure steam injection and the production well is converted to fluid production, then the mobilized bitumen is displaced from the pore space between the wells. This then creates a small steam chamber between the wells. Since the density of the bitumen and steam differ, bitumen drains under the action of gravity at the edges of the steam chamber.

To mimic steam circulation in the reservoir simulator, temporary line heaters are placed in the locations of the injection and production wells. In the line heater locations, production wells are operated at bottom hole pressure constraint equal to the reservoir pressure at the production well location to relieve thermally expanded bitumen from the system.

In the reservoir simulation models used here, the circulation period lasted three months. After the circulation period is finished, the line heaters are switched off and the steam injection and fluid production wells are put into operation in the reservoir model.

3.10 Model Life

The total life of operation is 15 years. Steam circulation is done through all wells,

whether vertical or horizontal or injection or production in the first 3 months of

operation. Beyond, the injection well or wells deliver steam to the reservoir whereas the

production well removes fluids from the reservoir.

Chapter Four: Impact of Well Configurations in Homogeneous Geology

4.1 Summary

This Chapter explores results of reservoir simulations of all well configuration cases evaluated in this research. In total, fourteen simulation runs were conducted: seven were done on the homogeneous reservoir model and seven were done on the heterogeneous reservoir model. Both models are described in detail in Chapter 3. All simulation runs were done by using the CMG STARSTM advanced thermal simulator

(CMG 2007).

In the following Sections, first, the results of the simulation model of typical SAGD operations in homogeneous and heterogeneous geology are compared to field data from

SAGD operations of Phase B, E, and D located in Dover area., second, an analysis of the results of the simulation done in the homogeneous model is performed, and third, an analysis of the results of the heterogeneous model is done. The impact of heterogeneity on process performance is also conducted.

4.2 Performance of SAGD-Like Operations Tested in a Homogeneous Geological Model

4.2.1 Steam Injection Rate

Figure 4-1 shows steam injection rates achieved for each case tested in the

homogeneous geological model. As can be seen, in the first six years of SAGD operation,

the highest steam injection rates, peaking at above 190 m3/day after 2 years of operation, were achieved by using the Offset9-SAGD, Offset6-SAGD, and Typical SAGD well configurations, respectively. The steam rates for the vertical injector well configurations started at much lower values and peaked between 140 and 160 m3/day after about 5.5 years. For the Offset9-SAGD, Offset6-SAGD, and Typical SAGD cases, after two years

66 of steam injection, steam injection rates generally began to decline, and by the end of 15 years, steam injection rates approached values slightly lower than that achieved by all of the cases that used vertical injectors.

220 200 180 160 140 120 100

80 Typical SAGD VSAGD 60 VINGS-SAGD

Steam Injection Rate (m3/day) Rate Injection Steam Offset9-SAGD 40 Offset6-SAGD Offset6-VSAGD 20 Offset6-VINGS-SAGD 0 0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 Time (yr) Figure 4-1: Comparison of steam injection rates in homogeneous model.

The peak normalized steam injection rates (normalized against the injection interval length) for the Offset9-SAGD, Offset6-SAGD, and Typical SAGD cases were

0.413, 0.402, and 0.391 m3/day/m, respectively, which were reached in about 2 years of the project’s life. The highest peak steam injection rates for the VINGS-SAGD, Offset6-

VINGS-SAGD, VSAGD, and Offset6-VSAGD cases were 4.520, 4.515, 4.008, and

4.068 m3/day/m, respectively. These values were achieved in about 9, 8, 11, and 10 years of the project’s life, respectively. The reason the normalized rates were higher in the

67 vertical well configurations is because the perforation intervals are much shorter than that of the horizontal well injectors.

4.2.2 Cumulative Steam Injected

The cumulative steam injected for all cases tested in the homogeneous geological model are displayed in Figure 4-2. The results show that the largest amount of steam was

injected when horizontal steam injectors were used. On average, the vertical injection

well configurations injected about three-quarters of the steam that was injected in the

horizontal injection well configurations. Over the first four years of operation, the

amount of steam injected in the vertical injection well cases is significantly lower than

that of the horizontal injection well cases. This could have significant impact on the

economics of the process given that the steam generators could be smaller in the vertical

well cases and water handling and treatment would be reduced compared to that of the

horizontal well cases.

4.2.3 Steam Chamber Volume

Steam chamber volumes of all cases tested in the homogeneous geological model

are shown in Figure 4-3. According to the amount of steam injected into the reservoir, the largest steam chamber volumes were developed by using horizontal injectors. The smaller steam chambers in the vertical well cases imply smaller heat transfer area which implies reduced oil rates.

1000000 Typical SAGD 900000 VSAGD VINGS-SAGD 800000 Offset9-SAGD Offset6-SAGD Offset6-VSAGD 700000 Offset6-VINGS-SAGD 600000

500000

400000

300000

Cumulative Steam Injected (m3) Injected Steam Cumulative 200000

100000

0 0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 Time (yr) Figure 4-2: Comparison of cumulative steam injected in homogeneous model. 200,000 Typical SAGD 180,000 VSAGD VINGS-SAGD 160,000 Offset9-SAGD Offset6-SAGD 140,000 Offset6-VSAGD Offset6-VINGS-SAGD 120,000

100,000

80,000

60,000

Steam Chamber Volume (m3) Volume Chamber Steam 40,000

20,000

0 0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 Time (yr) Figure 4-3: Comparison of steam chamber volumes in homogeneous model.

4.2.4 Oil Production Rate

Oil production rates are plotted in Figure 4-4. In the first two years of the project,

oil production rates increase until reaching their peak values for the horizontal injection

well cases. At about two years, the steam chambers reached the top of the reservoir and

heat losses to the cap rock started to become significant and as a result, the oil production

rates declined. The peak rates for the horizontal well configurations are between 100 and

110 m3/day. In the first two years, the Typical SAGD configuration performs the worst

of the three horizontal well configurations whereas after the peak the Typical SAGD case

performs slightly better than the other horizontal cases. The highest normalized oil

production rates (normalized against production interval length) for Offset9-SAGD,

Offset6-SAGD, and Typical SAGD are 0.222, 0.216, and 0.209 m3/day/m, respectively,

which are achieved in duration of 2 years of SAGD operation.

In the vertical injection well configurations, the oil production rates are

significantly lower than that from the horizontal well cases over the first four years. The

oil production rates increase until reaching their peaks of approximately 45 to 55 m3/day after about 8 to 10 years of operation. After four years the production rates from the vertical well cases are higher than that from the horizontal well ones. The highest normalized oil production rates for cases VINGS-SAGD, Offset6-VINGS-SAGD,

VSAGD, and Offset6-VSAGD are 0.116, 0.114, 2.968, and 3.006 m3/day/m, respectively, which were reached in about 10, 9, 11, and 10 years of SAGD operation, respectively. At about 10 years of SAGD operation, the steam chambers reach the edge of the boundary of the model and the oil production rates decline thereafter.

120 Typical SAGD VSAGD VINGS-SAGD 100 Offset9-SAGD Offset6-SAGD Offset6-VSAGD 80 Offset6-VINGS-SAGD

40 Oil ProductionOil Rate (m3/day) 20

0 0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 Time (yr) Figure 4-4: Comparison of oil production rates in homogeneous model.

4.2.5 Cumulative Oil Produced

Cumulative oil produced is shown in Figure 4-5. The results show that the horizontal well cases have the highest recovered volumes of bitumen from the reservoir.

After two years of operation, the VSAGD case has the lowest recovered volume having produced about 65% of the Offset9-SAGD case. However, the gap between the cases drops as the processes evolve further. The cumulative oil produced by the vertical well cases is significantly lower than that of the horizontal ones. However, the Offset6-

VINGS-SAGD case produces about 90% of the volume that is produced by Typical

SAGD by the end of the operation. The key is that the horizontal wells allow higher delivery of steam which yields higher amounts of mobilized oil which in turn results in higher oil rates over the five years of operation.

320000 Typical SAGD VSAGD 280000 VINGS-SAGD Offset9-SAGD Offset6-SAGD 240000 Offset6-VSAGD Offset6-VINGS-SAGD 200000

160000

120000

80000 Cumulative Oil Produced Cumulative Oil (m3)

40000

0 0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 Time (yr) Figure 4-5: Comparison of cumulative oil produced in homogeneous model. 60 Typical SAGD 55 VSAGD VINGS-SAGD 50 Offset9-SAGD 45 Offset6-SAGD Offset6-VSAGD 40 Offset6-VINGS-SAGD 35 30 25 20 Oil Recovery Factor % Factor Recovery Oil 15 10 5 0 0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 Time (yr) Figure 4-6: Comparison of oil recovery factor in homogeneous model.

Figure 4-6 shows oil recovery factor versus time for cases tested in the homogeneous geological model. The highest oil recovery factors are achieved by using horizontal injectors whereas lower oil recovery factors achieved by using vertical injectors.

4.2.6 Water Production Rate

Figure 4-7 shows water production rates resulting from implementing different well configurations in the homogeneous geological model. The behaviour is a reflection of the steam injection profiles. Water production rates increased quickly until approaching their peaks of 178, 172, and 166 m3/day, after about two years of operation

for the Offset9-SAGD, Offset6-SAGD, and Typical SAGD horizontal injection well

cases, respectively. Beyond about two years, they began to diminish to the end of the

project life. When using vertical steam injectors, water production rates of VING-

SAGD, Offset6-VING-SAGD, VSAGD, and Offset6-VSAGD Cases gradually escalated

until reaching their peaks of 143, 142, 125, and 127 m3/day, respectively.

4.2.7 Cumulative Water Produced

Figure 4-8 shows the total amount of water produced in each case. The results

show that the amount of water produced in the cases in which horizontal steam injectors

were used was larger than that produced by using vertical steam injectors. This is simply

due to the amount of steam injected in each case. This implies that water handling and

treatment will be lower in the vertical well configurations than that of the horizontal

wells.

220 200 180 160 140 120 100

80 Typical SAGD VSAGD 60 VINGS-SAGD Offset9-SAGD Water Production Rate (m3/day) Rate Production Water 40 Offset6-SAGD Offset6-VSAGD 20 Offset6-VINGS-SAGD 0 0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 Time (yr) Figure 4-7: Comparison of water production rate in homogeneous model. 1000000 Typical SAGD 900000 VSAGD VINGS-SAGD 800000 Offset9-SAGD Offset6-SAGD Offset6-VSAGD 700000 Offset6-VINGS-SAGD 600000

500000

400000

300000

Cumulative Water Produced (m3) Produced Water Cumulative 200000

100000

0 0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 Time (yr) Figure 4-8: Comparison of cumulative water produced in homogeneous model.

4.2.8 Cumulative Water to Oil Ratio

Figure 4-9 plots the cumulative produced Water to Oil produced (WOR) ratio. In

the first seven years of operation, the vertical well configurations used had a higher WOR

than that of the horizontal well configurations. Beyond seven years, the vertical well

cases had a lower WOR. Of all the cases, the best case appears to have been the VINGS-

SAGD one: the WOR was low throughout the operation and beyond about three years is

lower than the horizontal well cases.

5.0 Typical SAGD VSAGD VINGS-SAGD 4.0 Offset9-SAGD Offset6-SAGD Offset6-VSAGD Offset6-VINGS-SAGD 3.0

2.0

1.0 Cumulative Water-Oil Ratio (m3/m3) Ratio Water-Oil Cumulative

0.0 0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 Time (yr) Figure 4-9: Comparison of cumulative water-to-oil ratio in homogeneous model.

4.2.9 Thermal Efficiency, Steam to Oil Ratio (SOR)

Figure 4-10 and Figure 4-11 display plots of the cumulative and instantaneous steam-oil ratios (cSOR and iSOR, respectively) of the cases tested in the homogeneous geological model. In the Typical SAGD case, the cSOR achieves a value of about 2

75 m3/m3 and remains at about this value for the first two years of operation. Thereafter, it rises and reaches a value of about 3.2 after fifteen years of operation. The results show

that the lowest SORs over the first four years of operation were achieved by the offset

horizontal injection well cases.

6.0 Typical SAGD VSAGD VINGS-SAGD 5.0 Offset9-SAGD Offset6-SAGD Offset6-VSAGD 4.0 Offset6-VINGS-SAGD

3.0

2.0

1.0 Cumulative Steam-Oil Ratio (cSOR) (m3/m3) RatioCumulative (cSOR) Steam-Oil 0.0 0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 Time (yr) Figure 4-10: Comparison of cumulative steam-to-oil ratio in homogeneous model.

The VSAGD and Offset6-VSAGD vertical well configurations had the highest

SORs over the first nine years whereas the Offset6-VINGS-SAGD case appears to have

had the best overall performance with relatively low SORs throughout the operation life.

These results suggest that the Offset6-VINGS-SAGD case performs with the overall

highest thermal efficiency, that is, it requires the least amount of steam per unit oil

produced.

The iSOR profiles reveal that all cases are below 5.5 m3/m3 throughout the operations. If a iSOR cut-off of 4.5 m3/m3 was used as a performance indicator for

economic production, then the horizontal wells would be discontinued from operation

after about ten years of operation whereas the vertical well would continue until about year fifteen for the Offset6-VINGS-SAGD and VINGS-SAGD cases and beyond for the other vertical well cases. At this cut-off, the recovery factor from the horizontal well cases was about 35% whereas for the vertical well cases it would be about 40%. The iSOR cut-off depends on the costs of fuel (often natural gas) used to generate steam, water handling and treatment, bitumen treatment (including diluent for pipelining) and the price of bitumen.

6.0

5.0

4.0

3.0

2.0 Typical SAGD VSAGD VINGS-SAGD Offset9-SAGD 1.0 Offset6-SAGD Offset6-VSAGD Offset6-VINGS-SAGD Instantaneous Steam Oil Ratio (iSOR) (m3/m3) Instantaneous Ratio (iSOR) Oil Steam 0.0 0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 Time (yr) Figure 4-11: Comparison of instantaneous steam-to-oil ratio in homogeneous model.

4.2.10 Energy Consumptions

4.2.10.1 Energy Gained by Heat Transfer Model

As mentioned earlier in Chapter Three, all steam injectors were operated at injection pressure 2000 kPa, with a steam temperature of 216oC. Before starting the

SAGD operation, the pre-heating stage was modeled using line heaters in the well locations to model steam circulation in the wells.

Given that the distances between the wells are different in different well configurations, the heat energy consumed to establish thermal communication between the injectors and the producers in each case differs from one case to another. This is also because the geometry of the vertical-horizontal well combinations are different in the vertical well injection cases. Table 4-1 shows the overall heat energy injected into the reservoir during the steam circulation stage in all cases tested in the homogenous geological model. Figure 4-12 displays the energy injected during the steam circulation

stage. The Typical SAGD case uses the least energy of the horizontal cases. The larger the offset gap between the horizontal injection and production wells, the greater the energy used. The lowest energy used of the vertical well configurations is the VSAGD one. The largest is the Offset6-VINGS-SAGD case.

4.2.10.2 Energy Consumed by Steam Injected

Figure 4-13 and Figure 4-14 displays plots of the enthalpy injection rates and

cumulative enthalpy injected by steam. Due to the use of horizontal steam injectors,

enthalpy injection rate increases very quickly at the first two years of the project. Then,

the rates gradually went down until the end of the project life.

4.0e+13 Typical SAGD VSAGD 3.5e+13 VINGS-SAGD Offset9-SAGD 3.0e+13 Offset6-SAGD Offset6-VSAGD Offset6-VINGS-SAGD 2.5e+13

2.0e+13

1.5e+13

Energy Gain by Heaters (J) by Heaters Gain Energy 1.0e+13

5.0e+12

0.0e+0 0 20 40 60 80 Time (day) Figure 4-12: Comparison of cumulative heat gained by heaters to achieve thermal communication between the injectors and producers in homogeneous model. Table 4-1: Heat energy gained by heat transfer model in cases tested in the homogeneous geological model.

Heat Energy Gained by Heat Transfer Model at the End Case ID of Pre-Heating Stage (GJ) Typical SAGD 9840 Offset6-SAGD 24313 Offset9-SAGD 31436 VINGS-SAGD 5837 Offset6-VINGS-SAGD 14390 VSAGD 844 Offset6-VSAGD 2141

6.0e+11

5.4e+11

4.8e+11

4.2e+11

3.6e+11

3.0e+11

2.4e+11 Typical SAGD 1.8e+11 VSAGD VINGS-SAGD Offset9-SAGD Enthalpy Injection Rate (J/day) Injection Rate Enthalpy 1.2e+11 Offset6-SAGD Offset6-VSAGD 6.0e+10 Offset6-VINGS-SAGD 0.0e+0 0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 Time (yr) Figure 4-13: Comparison of enthalpy injection rate as steam in homogeneous model. 2.6e+15 Typical SAGD 2.3e+15 VSAGD VINGS-SAGD 2.1e+15 Offset9-SAGD Offset6-SAGD 1.8e+15 Offset6-VSAGD Offset6-VINGS-SAGD 1.6e+15

1.3e+15

1.0e+15

7.8e+14

Cumulative Enthalpy Injected (J) 5.2e+14

2.6e+14

0.0e+0 0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 Time (yr) Figure 4-14: Comparison of cumulative enthalpy injected as steam in homogeneous model.

On the other hand, when using vertical steam injectors, enthalpy injection rates gradually increased until reaching their highest values. Thereafter, the rates went down till the end of the project.

4.3 Validation of SAGD Model

The results of the simulation were compared to SAGD operations located in Dover area by selecting some performance parameters related to SAGD projects (cumulative steam-to-oil ratio, cumulative water-to-oil ratio at the end of the project life, average steam injection rates, average calendar day oil rates, and average water production rates).

Table 4-2 shows the performance of SAGD well pairs at Phase B, D, and E. The names of wells to which the comparison is made are listed in Appendix C. All field data were collected from AccuMapTM database software (IHS 2008).

As seen from the comparison, the normalized steam injection rate (normalized against the length of the well), Calendar Day Oil Rate (CDOR), and normalized water production rate, Water-to-Oil Ratio (WOR), and Cumulative Steam-to-Oil Ratio (cSOR) of the Typical SAGD model are consistent with field results. The cSOR from the Typical

SAGD case is slightly higher than that of the field results but this is because the operating pressure used in this work is slightly higher than that of the field operations. These results suggest that the model is a reasonable representation of the geology of an

Athabasca reservoir. Furthermore, the results of the Typical SAGD model are similar to

with simulation results found in the literature for Athabasca type reservoirs (Edmonds

and Chhina 2001, Gates and Chakrabarty 2005).

Table 4-2: Comparison of the performance of typical SAGD operation in the field and the SAGD numerical model. Steam Injection Water Production CDOR WOR cSOR Project Rate Rate m3/d/m m3/m3 m3/m3 m3/d/m m3/d/m Typical SAGD Case 0.1 - 0.39 0.1 - 0.21 0.1 - 0.34 2.95 3.25 (Homogeneous geology) Phase B (B1) 0.1 - 0.6 0.1 - 0.25 0.1 - 0.55 2.97 3.96 Phase B (B2) 0.1 - 0.5 0.1 - 0.30 0.25 - 0.55 2.94 1.14 Phase B (B3) 0.1 - 0.5 0.1 - 0.20 0.1 - 0.45 2.96 2.77 Phase D (D2) 0.15 - 0.45 0.1 - 0.19 0.15 - 0.40 2.33 2.87 Phase E (E1) 0.1 - 0.4 0.1 - 0.15 0.15 - 0.33 3.73 3.00

4.4 Analysis and Discussion of Results

Early-Time Response

Early time response in SAGD-like processes is very important for the creation and

growth of the steam chamber. The steam chamber is the main vehicle for transmitting

heat to the cool oil sands at its edges and thus its size, really surface area, is a direct

control on the amount of oil produced. In each of the cases considered in this research,

the thermal communication region to be established between the injection and production

wells is different for each case. For example, the mobilized-oil zone required to establish sufficient thermal communication between a vertical injector and a vertical producer

would be smaller in extent than that required to establish a thermally communication

zone between two parallel horizontal wells. Figure 4-15 to Figure 4-21 show temperature distributions at the end of steam circulation stage for each case tested in the homogeneous geological model.

The goal of the steam circulation stage is to raise the temperature in the region between the wells to above 80°C. At this temperature, the bitumen is sufficiently mobile so that when steam injection and production of fluids starts, then the heated, mobilized oil

82 can be displaced from the inter-well region and occupied by the injected steam. The temperature distributions demonstrate why the heat energy transferred by the heat transfer model is different in each case to successfully establish thermal communication between injectors and producers (see Figure 4-12).

Figure 4-15: Temperature profile at the end of steam circulation stage: Typical SAGD Case.

Figure 4-16: Temperature profile at the end of steam circulation stage: Offset6- SAGD Case.

Figure 4-17: Temperature profile at the end of steam circulation stage: Offset9- SAGD Case.

Figure 4-18: Temperature profile at the end of steam circulation stage: VINGS- SAGD Case.

Figure 4-19: Temperature profile at the end of steam circulation stage: Offset6- VINGS- SAGD Case.

Figure 4-20: Temperature profile at the end of steam circulation stage: VSAGD Case.

Figure 4-21: Temperature profile at the end of steam circulation stage: Offset6- VSAGD Case.

Steam Injection Rate Profiles

Given different well geometries and positions, each injection well in each well configuration has a different contact area to the reservoir model. For instance, vertical injectors have smaller contact area to the formation than that of horizontal injectors. For a vertical injector, the steam circulation stage must heat up the region in the near wellbore region. This is the length of the perforations of the vertical well which would be some fraction of the reservoir thickness which implies the length of the circulation zone is between 6 and 25 m For horizontal wells, the circulation zone is the length of the perforated interval of the steam injection well. After the steam circulation stage, given the different heated zones, when the wells are converted to production, the steam injection rate corresponding to a constant steam injection pressure will be different for each case (see Figure 4-1). Thus, by the end of the life of operation of each well

86 configuration, the total volume of steam injected in each case is different (see Figure

4-3).

As can be seen in Figure 4-1, higher steam injection rates occur in the first two

years of operation in the cases where the injection well is a horizontal well. In these

cases, the steam chambers develop more rapidly than that of the vertical cases. This is

due to the extent of reservoir that is heated during the steam circulation stage.

After the steam circulation stage, steam, injected into the injection well, displaces

mobile oil and water from the heated zone. Since the steam injection pressure is

constrained, the amount of steam required is different for each well configuration. This

means that the initial size of the steam chamber is different for each injection well

configuration and that the amount of oil displaced in each case is different.

In addition to generating different mobile zones at the end of the steam circulation

stage, the rates of heated reservoir fluid withdrawal are different based on the connection

between the injection wells and the production well. Fluid production rates influence

how fast the steam front advances into the cold oil sands after heated reservoir fluids at

the edges of the chamber are removed by gravity.

Steam injection rates in vertical injectors and horizontal producers or vertical

producers developed slowly until they reached their peak values. Compared to cases

where horizontal wells were used both as an injector and a producer, the heated inter-well

section is smaller in these configurations (see Figure 4-15 to Figure 4-21). That is, smaller mobile zones were created in these well configurations and thus, the flow of steam at the beginning of the operation drains a smaller volume of heated reservoir fluids.

After the steam circulation stage, for all cases, steam is injected into the formation at the same bottomhole pressure, yet, heated reservoir fluids are withdrawn at different rates due to the use of horizontal producers in some cases, and vertical producers in the others. For instance, in the VINGS-SAGD case, after about five years of steam injection, the steam injection rate is getting higher than that in the cases where vertical steam injectors and vertical producers are used. That means, steam injected through vertical wells displaced the same volume of heated reservoir fluids over the first five years until the horizontal producer captured more heated fluids than the vertical producer does.

Oil Production Rate Profiles

Oil production rate profiles were relatively high at the beginning of operation for the Offset9-SAGD, Offset6-SAGD, and Typical SAGD cases. Over the majority of the first two years of production, oil rates climbed rapidly, as a result of rising steam injection rates (see Figure 4-1 and Figure 4-4). Due to the growth of the rising steam chamber, heated mobilized oil drained at the edge of the steam chamber. Variations in oil production rates in the three cases were due to the fact that each well configuration had developed a different initial steam chamber early in the process.

After approximately two years of production, oil rates in the Offset9-SAGD,

Offset6-SAGD, and Typical SAGD cases started to diminish. In these well configurations, steam injects into the homogeneous reservoir at constant injection pressure throughout the life of the operation. This implies that a significant amount of the steam’s latent heat was transferred to the overburden after the steam chamber reached the top of the formation. By the end of the operation, oil rates were low compared with cases in which vertical injectors were used (see Figure 4-4).

In the VINGS-SAGD, Offset6-VINGS-SAGD, VSAGD, and Offset6-SAGD cases, oil rates showed better performance than that when using vertical producers, when using horizontal producers. This is only due to the fact that horizontal wells have a larger contact to the reservoir and capture more mobilized oil than that of vertical wells. For instance, in cases where horizontal injectors and horizontal producers were used, the heated reservoir fluids were being produced from the majority of the length of the producer. However, in cases where vertical injectors and horizontal producers were used, heated reservoir fluids were recovered from certain portions of the reservoir where thermal communication was established between the injection and production wells.

However, compared to the Offset9-SAGD, Offset6-SAGD, and Typical SAGD cases, oil rate profiles continued to rise over years 7 to 10 of operation. This means most the heat energy is still delivered to the native bitumen. Later, beyond years 7 to 10, bitumen rates fell indicating an increase in heat losses to the overburden (see Figure 4-4).

Water Production Rate Profiles

Steam condenses at the edge of the steam chamber throughout the life of the

operation and in turn, water (that is, steam condensate plus connate water in the reservoir)

is produced. In all cases, the water production rate profiles exhibited the same trend as

that of the steam injection rate profiles. This means, as steam releases its latent heat to

cool oil sands, it becomes liquid. Then, water, along with heated bitumen, drains by

gravity to the producer (see Figure 4-7). As the water-bitumen mixture flows under gravity along the edge of the steam chamber, it loses further heat to the oil sands and its temperature drops below the saturation temperature of steam. This then leads to reduced

89 temperature at the production well and accounts for the temperature subcool that exists between the injection and production well.

Cumulative Steam Injected, Steam Chamber Volume, Cumulative Oil Produced, Oil Recovery Factors, and Cumulative Water Produced

Because steam injection rates are different in each case, the total amount of steam

injected into the reservoir is unique for all well configurations tested (see Figure 4-2).

This, in turn, implies that the steam chamber evolved with different volumes in each case

(see Figure 4-3). Given that the extent of the chamber area in the reservoir sets the heat

exchange area, this means that the total amount of heated fluid drained at the edge of

each chamber and oil recovery factors are different for each case (see Figure 4-5, Figure

4-6, and Figure 4-8).

Three-dimensional (3D) oil saturation distributions of all cases at the end of the

production operation can be seen in Figure 4-22 to Figure 4-28. These figures

demonstrate how different well configurations lead to different chamber shapes and sizes

and thus different oil production volumes.

Figure 4-22: Oil Saturation profile at the end of the production operation: Typical SAGD Case.

Figure 4-23: Oil Saturation profile at the end of the production operation: Offset6- SAGD Case.

Figure 4-24: Oil Saturation profile at the end of the production operation: Offset9- SAGD Case.

Figure 4-25: Oil Saturation profile at the end of the production operation: VINGS- SAGD Case.

Figure 4-26: Oil Saturation profile at the end of the production operation: Offset6- VINGS-SAGD Case.

Figure 4-27: Oil Saturation profile at the end of the production operation: VSAGD Case.

Figure 4-28: Oil Saturation profile at the end of the production operation: Offset6- VSAGD Case.

The oil saturation distributions reveal that the depleted areas in the Typical

SAGD, Offset9-SAGD, Offset9-SAGD cases are the largest of all the well configurations studied here.

However, this does not necessarily translate into the most efficient economic recovery. As shown in Figure 4-2, it is obvious that an equivalent amount of steam injected into the reservoir is delivered more quickly in cases when horizontal steam injectors are used; yet, this equivalent amount of steam realizes different oil recovery factors.

Thermal Efficiency: Steam-to-Oil Ratio (SOR)

The overall efficiency of thermal process can be described by cumulative Steam- to-Oil ratio (cSOR). This represents the total energy injected into the reservoir per

94 volume of oil produced: the volume of steam is given in cold water equivalents. In industry practice, the instantaneous Steam-to-Oil ratio (iSOR) is often used to detect when the thermal process is running uneconomically. As shown in Figure 4-11, after an initial transient stage, for the Offset9-SAGD, Offset6-SAGD, and Typical SAGD cases, the iSOR ranges between about 1.5 to 3 m3/m3 over the first four years of operation.

Beyond four years, the iSOR rises until it reaches 5.16, 5.17, and 5.18 m3/m3, respectively. The reason for this is that the majority of latent heat of steam is transferred to surrounding formation through the top of the reservoir after approximately four years of continuous steam injection.

When using vertical injectors and vertical producers, as in the VSAGD, and

Offset6-VSAGD cases, however, the iSOR tends to be between 3 to 4 m3/m3 for about one year, and after that, it holds between 2 to 3 m3/m3 for about 7 years. Again, it begins to rise until it reaches about 4 m3/m3. This means that in these projects, excessive steam

loss occurs after 8 years of SAGD operation

Tracking the Development of the Steam Chamber

Here, the development of the steam chambers in the VINGS-SAGD and Typical

SAGD cases are compared. The ternary diagram was chosen to describe the overall

development of the steam chamber. This diagram indicates the distributions of the water, oil, and gas phases in reservoir. The Typical SAGD case is displayed in the sequence of ternary diagrams shown in Figure 4-29 to Figure 4-36. The VINGS-SAGD case is shown

in Figure 4-37 to Figure 4-44.

Figure 4-29: Distribution of phases in the reservoir at the beginning of SAGD mode in the Typical SAGD case.

Figure 4-30: Distribution of phases in the reservoir after one year of SAGD mode in the Typical SAGD case.

Figure 4-31: Distribution of phases in the reservoir after two years of SAGD mode in the Typical SAGD case.

Figure 4-32: Distribution of phases in the reservoir after four years of SAGD mode in the Typical SAGD case.

Figure 4-33: Distribution of phases in the reservoir after six years of SAGD mode in the Typical SAGD case.

Figure 4-34: Distribution of phases in the reservoir after eight years of SAGD mode in the Typical SAGD case.

Figure 4-35: Distribution of phases in the reservoir after twelve years of SAGD mode in the Typical SAGD case.

Figure 4-36: Distribution of phases in the reservoir after sixteen years of SAGD mode in the Typical SAGD case.

Figure 4-37: Distribution of phases in the reservoir at the beginning of SAGD mode in the VINGS-SAGD case.

Figure 4-38: Distribution of phases in the reservoir after one year of SAGD mode in the VINGS-SAGD case.

100

Figure 4-39: Distribution of phases in the reservoir after two years of SAGD mode in the VINGS-SAGD case.

Figure 4-40: Distribution of phases in the reservoir after four years of SAGD mode in the VINGS-SAGD case.

101

Figure 4-41: Distribution of phases in the reservoir after six years of SAGD mode in the VINGS-SAGD case.

Figure 4-42: Distribution of phases in the reservoir after eight years of SAGD mode in the VINGS-SAGD case.

102

Figure 4-43: Distribution of phases in the reservoir after twelve years of SAGD mode in the VINGS-SAGD case.

Figure 4-44: Distribution of phases in the reservoir after sixteen years of SAGD mode in the VINGS-SAGD case.

The ternary diagrams indicate that despite the fact that the steam chamber developed by using vertical steam injectors and reached the top of the formation faster

103 than that developed by using a horizontal injector, significant amount of heat energy was still transferred to the native bitumen rather than to the caprock. This is because the steam chamber has a smaller contact area to the overburden in the cases where vertical wells were used compared to that of a horizontal steam injector. A comparison of the phase distributions at year four demonstrates that the chamber was water-rich in the Typical

SAGD case whereas it had higher gas phase content in the VINGS-SAGD case. That is, steam vertical injectors were more efficiently in transferring the heat energy into the formation to yield a dominantly vapour-filled chamber. However, the size of the chamber in the Typical SAGD case is larger. The individual steam chambers of the

VINGS-SAGD case merge after about twelve years of operation.

The overall recovery factor (RF), thermal efficiency measured by the cSOR, and

cumulative Energy-to-Oil Ratio (cEOR) of all projects tested in the homogeneous and

heterogeneous geological model are listed in Table 4-3. The recovery factor is the

volume of oil as a percentage of the initial oil in place in the reservoir. The cEOR is the

total energy injected into the formation per unit of oil produced from the reservoir. The

results in Table 4-3 reveal that the recovery factors for all processes are reasonably close

for the horizontal steam injector cases with similar cSOR and cEOR. These values of

recovery factor are consistent with that found in industry (ERCB 2008). The VINGS-

SAGD and Offset6-VINGS-SAGD cases have slightly lower oil recovery but with

significantly lower cSOR and cEOR. The results show that horizontal production wells

perform better than vertical ones. This is because of reservoir contact and the extended

drainage length that is realized by horizontal wells.

104

Table 4-3: Performance of different well configurations in homogeneous reservoir model. RF cSOR cEOR Case ID % m3/m3 GJ/m3 Homogeneous Geological Model Typical SAGD 44.21 3.25 8.38 Offset9-SAGD 45.47 3.22 8.38 Offset6-SAGD 45.02 3.22 8.35 VINGS-SAGD 39.34 2.88 7.40 Offset6-VINGS-SAGD 40.56 2.94 7.60 VSAGD 34.85 3.04 7.77 Offset6-VSAGD 35.70 3.04 7.80

4.5 Natural Gas Consumption and Flue Gases Emissions

In this section, emissions of Carbon Dioxide (CO2) were calculated as a result of the combustion of methane (CH4) to generate steam to investigate the impact of well

configurations on flue gases emissions. Total steam energy injected at the surface for all

projects was determined based on a steam generator efficiency of 75%, allowing 5%, as

equipment surface heat losses, and 20% of flue gas heat losses (Yang, and Gates 2008).

The heating value for the methane through its combustion was used to estimate the

consumed amount of the natural gas, and generated Carbon Dioxide. The heating value

for methane combustion is 890.8 kJ/gmol (Lide 2007).

A comparison of cumulative methane consumption and cumulative carbon dioxide

emissions in millions of cubic meters (at standard conditions) in homogeneous reservoir

media are displayed in Figure 4-45 and Figure 4-46. The results show that the cumulative methane consumption as fuel to generate steam is less in cases where vertical injectors are used. This will in turn emit less carbon dioxide.

105

Both cumulative CH4 to Oil Ratio (cNOR) and cumulative CO2 to Oil Ratio

(cCOR) are illustrated in Figure 4-47 and Figure 4-48, respectively. Of all the cases,

VINGS-SAGD and Offset6-VINGS-SAGD show lower cNOR and cCOR relatively, as shown in Table 4-4. However, one can notice that there is no significant impact observed

for the SAGD process under different well configuration on the homogeneous model. At

the end of the 16 years, cNOR, and cCOR have typical values ranging from 300 to 350

m3/m3.

Figure 4-45: Comparison of cumulative methane consumed in homogeneous model.

106

Figure 4-46: Comparison of cumulative carbon dioxide emitted in homogeneous model.

Figure 4-47: Comparison of cumulative consumed CH4 to produced oil ratio (cNOR) in homogeneous model.

107

Figure 4-48: Comparison of cumulative generated CO2 to produced oil ratio (cCOR) in homogeneous model.

Table 4-4: Cumulative generated CO2 to produced oil ratio (cCOR) and consumed CH4 to produced oil ratio (cNOR) in homogeneous model. cNOR cCOR Case ID m3/m3 m3/m3 Typical SAGD 348 348 Offset9-SAGD 345 345 Offset6-SAGD 346 346 VINGS-SAGD 309 309 Offset6-VINGS-SAGD 316 316 VSAGD 326 326 Offset6-VSAGD 326 326

4.6 Impact of Well Configuration on a Simple Economic Measure in Homogeneous Geology

Capital costs of SAGD projects include cost of surface facilities, drilling and

completions and downhole equipment used to produce the bitumen, surface pipelines and

storage vessels. These costs have to be estimated to ensure that the oil production

108 forecast is sufficient to generate revenues to make the project profitable. In this work, a simple analysis is conducted that takes into account well costs to evaluate the relative economics of each well configuration.

An estimate of the drilling, completion, and wellhead equipment cost of a single horizontal SAGD wellpair is $3,000,000 (Edmunds, and Chhina 2001). The drilling, completion, and wellhead equipment cost of a single vertical well is about $250,000

(Gates Personal Communication). The production performance parameter which is usually used to evaluate an operating SAGD project is iSOR. For this purpose, the well costs of the SAGD projects are evaluated at iSOR cutoffs equal to 3 and 3.5 m3/m3 for each well configuration.

Table 4-5: Economic (well cost per unit volume oil produced) performance of well configurations considered in this work. iSOR, Time Cum. Oil Well Cost Case ID m3/m3 day m3 $/m3 Typical SAGD 3 1,936 131,901 22.7 3.5 2,465 158,243 19.0 Offset9-SAGD 3 1,731 134,062 22.4 3.5 2,398 166,519 18 Offset6-SAGD 3 1,802 133,231 22.5 3.5 2,343 159,918 18.8 VINGS-SAGD 3 3,999 165,934 16.6 3.5 4,443 186,187 14.8 Offset6-VINGS-SAGD 3 3,587 162,010 17.0 3.5 4,046 183,059 15.0 VSAGD 3 3,090 95,555 13.1 3.5 4,997 176,565 7.1 Offset6-VSAGD 3 2,953 94,640 26.4 3.5 4,861 176,986 14.1

The results of the analysis are listed in Table 4-5. The time at which the iSOR

values of 3 and 3.5 m3/m3 are reached are listed in the Table. Also listed are the

109 cumulative oil volumes and resulting well cost per unit oil volume produced at the iSOR cutoffs. If the time to the iSOR cutoff is not an issue, then the results reveal that VSAGD has the lowest well cost per unit oil produced. The combinations of vertical injectors and a horizontal producer appear to be the next best.

In brief, SAGD operations that use vertical steam injectors and a horizontal producer exhibit better performance over the other cases in homogeneous geological models. The injected fluid energy is distributed into the reservoir less efficiently in the cases where horizontal steam injectors were used. Also, well cost per unit volume of oil produced is lower when using vertical injectors compared to that of a horizontal injector.

110

Chapter Five: Impact of Well Configurations in Heterogeneous Geology

5.1 Summary

This Chapter describes the results of reservoir simulations of all well configurations in a heterogeneous reservoir model. The creation of the heterogeneous geological model is described in detail in Chapter 3. All reservoir simulations were conducted by using the

CMG STARSTM advanced thermal simulator (CMG 2007).

In the following Sections, first, an analysis of the results of the simulation done in

the heterogeneous model is presented, and second, the impact of heterogeneity on process

performance is also examined.

5.2 Performance of SAGD-Like Operations Tested in a Heterogeneous Reservoir

5.2.1 Steam Injection Rate

Figure 5-1 displays plots of the steam injection rates of all cases evaluated in the

heterogeneous geology. The results show that horizontal steam injectors yielded higher

steam injection rates at the very beginning of the operation. Also, steam injection rates

reached their peak values after about one year of steam injection. The highest normalized

steam injection rates for the Offset9-SAGD, Offset6-SAGD, and Typical SAGD cases

are 0.434, 0.407, and 0.401 m3/day/m; respectively. In the Typical SAGD case, this maximum steam injection rate is achieved after about 4 years of operation. From years 4 to 6, steam injection rates for the horizontal injection well cases remained at about 200 m3/day. Thereafter, the rates declined until the end of the operation at 16 years.

111

220 200 180 160 140 120 100

80 Typical SAGD VSAGD 60 VINGS-SAGD

Steam Injection Rate (m3/day) Injection Steam Offset9-SAGD 40 Offset6-SAGD Offset6-VSAGD 20 Offset6-VINGS-SAGD 0 0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 Time (yr) Figure 5-1: Comparison of steam injection rate in heterogeneous model.

For the vertical steam injector cases, steam injection rates increased from relatively small start-up values until approaching their peaks after about 8 years of operation. The maximum normalized steam injection rates for the VINGS-SAGD,

Offset6-VINGS-SAGD, VSAGD, and Offset6-VSAGD cases are 5.129, 5.261, 4.580, and 4.83 m3/day/m; respectively. Beyond the peak rates, the steam injection rates

declined until the end of operation.

5.2.2 Cumulative Steam Injected

Similar to the results described in Chapter Four for the homogeneous geological model, the amount of steam injected by using horizontal steam injectors was larger than that injected by using vertical steam injectors. Figure 5-2 displays plots of the amount of steam injected in each case.

112

1.0e+6 Typical SAGD 9.0e+5 VSAGD VINGS-SAGD 8.0e+5 Offset9-SAGD Offset6-SAGD 7.0e+5 Offset6-VSAGD Offset6-VINGS-SAGD 6.0e+5

5.0e+5

4.0e+5

3.0e+5

Cumulative Steam Injected (m3) 2.0e+5

1.0e+5

0.0e+0 0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 Time (yr) Figure 5-2: Comparison of cumulative steam injected in heterogeneous model. 200,000 SAGD 180,000 VSAGD VINGS-SAGD 160,000 Offset9-SAGD Offset6-SAGD Offset6-VSAGD 140,000 Offset6-VINGS-SAGD 120,000

100,000

80,000

60,000

Steam Chamber Volume (m3) Steam 40,000

20,000

0 0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 Time (yr) Figure 5-3: Comparison of steam chamber volumes in heterogeneous model.

113

5.2.3 Steam Chamber Volume

Figure 5-3 shows plots of the volume of the steam chamber that evolves through the life of the operation in all cases tested in the heterogeneous reservoir. The results reveal, similar to results of Chapter Four, that the cases which use horizontal steam injectors have the largest steam chamber volumes.

120 Typical SAGD VSAGD VINGS-SAGD 100 Offset9-SAGD Offset6-SAGD Offset6-VSAGD 80 Offset6-VINGS-SAGD

40 Oil Production Rate (m3/day) Rate Production Oil 20

0 0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 Time (yr) Figure 5-4: Comparison of oil production rates in heterogeneous model.

5.2.4 Oil Production Rate

Figure 5-4 displays oil production rates for all cases tested in the heterogeneous

reservoir. The results show that the maximum oil production rates in the cases in which

horizontal steam injectors are used are reached faster than that in the cases in which

vertical steam injectors are used. The Offset9-SAGD case approaches its maximum

114 normalized oil production rates of 0.226 m3/day/m in less than a year. The Offset6-

SAGD and Typical SAGD cases reach their maximum normalized oil production rates of

0.220, and 0.196 m3/day/m; respectively in about one year. Thereafter, oil production

rates decline until the end of the operation.

5.2.5 Cumulative Oil Produced

The evolution of the cumulative oil volumes produced for each case is plotted in

Figure 5-5. The results indicate that the total volumes produced by using horizontal injectors are largest among the well configurations considered in this work. This aligns with the steam injection rates: the larger the amount of steam delivered to the formation, the greater the volume of oil produced. Figure 5-6 displays the oil recovery factors of all

cases.

320,000

280,000

240,000

200,000

160,000

120,000 Typical SAGD VSAGD 80,000 VINGS-SAGD Cumulative Oil Produced (m3) Offset9-SAGD Offset6-SAGD 40,000 Offset6-VSAGD Offset6-VINGS-SAGD 0 0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 Time (yr) Figure 5-5: Comparison of cumulative oil produced in heterogeneous model.

115

60 55 50 45 40 35 30 25 20 Typical SAGD

Oil Recovery Factor % Factor Recovery Oil VSAGD 15 VINGS-SAGD Offset9-SAGD 10 Offset6-SAGD Offset6-VSAGD 5 Offset6-VINGS-SAGD 0 0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 Time (yr) Figure 5-6: Comparison of oil recovery factor in heterogeneous model.

5.2.6 Water Production Rate

Water production rates for all cases are shown in Figure 5-7. Similar to the

results obtained from the homogeneous geological model, the amount of water produced

in the cases where horizontal steam injectors were used is larger than that produced by

vertical steam injectors. To be clearer, the amount of water production is directly related

to the amount of steam injection. The results show that water production rates rose to

their highest values over the first four years of operation in cases where horizontal

injectors were used. In cases where vertical steam injectors were used, water rates

increased until reaching their peaks after eight years of continuous steam injection.

Beyond, water production rates decreased until the end of the operation.

116

220 200 180 160 140 120 100

80 Typical SAGD VSAGD 60 VINGS-SAGD Offset9-SAGD Water Production Rate (m3/day) Rate Production Water 40 Offset6-SAGD Offset6-VSAGD 20 Offset6-VINGS-SAGD 0 0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 Time (yr) Figure 5-7: Comparison of water production rates in heterogeneous model.

5.2.7 Cumulative Water Produced

Figure 5-8 shows the cumulative water volume produced in all cases tested in the

heterogeneous geological model. The amount of water produced in the cases where

horizontal steam injectors were used is larger than that produced when vertical injectors

were used. As stated above, the reason for this is due to the amount of steam that could

be injected in each well configuration.

117

1.0e+6 Typical SAGD 9.0e+5 VSAGD VINGS-SAGD 8.0e+5 Offset9-SAGD Offset6-SAGD 7.0e+5 Offset6-VSAGD Offset6-VINGS-SAGD 6.0e+5

5.0e+5

4.0e+5

3.0e+5

Cumulative Water Produced (m3) Produced Water Cumulative 2.0e+5

1.0e+5

0.0e+0 0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 Time (yr) Figure 5-8: Comparison of cumulative water produced in heterogeneous model. 5.0 Typical SAGD VSAGD VINGS-SAGD 4.0 Offset9-SAGD Offset6-SAGD Offset6-VSAGD Offset6-VINGS-SAGD 3.0

2.0

1.0 CumulativeWater-Oil Ratio (m3/m3)

0.0 0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 Time (yr)

Figure 5-9: Comparison of cumulative water to oil ratios in heterogeneous model.

118

5.2.8 Cumulative Water to Oil Ratio

The cumulative produced water to oil ratio of all cases is displayed in Figure 5-9.

Over the first three years, the offset horizontal injection well cases exhibited the lowest

water to oil ratios. Beyond three years, the vertical injection cases had the lowest water

to oil ratios.

5.2.9 Thermal Efficiency, Steam to Oil Ratio (SOR)

Figure 5-10 and Figure 5-11 display the cumulative and instantaneous steam to oil ratios (cSOR and iSOR), respectively. The cSOR provides a measure of the overall thermal efficiency whereas the iSOR is often used as a measure of the economics of the process and is often used to indicate when the process should be terminated. As shown in

Figure 5-10, the horizontal steam injector cases show good thermal efficiency over the

first two years of the project. Thereafter, the thermal efficiency rises to the end of

operation.

Well configurations where vertical steam injectors and a horizontal producer were

used (VINGS-SAGD and Offset6-VINGS-SAGD cases) also performed well with good

thermal efficiency over the first six years of operation. Cases where vertical wells were

used show good thermal efficiency throughout the life of the project.

119

6.0 Typical SAGD VSAGD VINGS-SAGD 5.0 Offset9-SAGD Offset6-SAGD Offset6-VSAGD 4.0 Offset6-VINGS-SAGD

3.0

2.0

1.0 Cumulative Steam-Oil Ratio (cSOR) (m3/m3)

0.0 0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 Time (yr) Figure 5-10: Comparison of cSOR in heterogeneous model. 6.0

5.0

4.0

3.0

2.0 Typical SAGD VSAGD VINGS-SAGD Offset9-SAGD 1.0 Offset6-SAGD Offset6-VSAGD

Instantaneous Steam-Oil Ratio (iSOR) (m3/m3) (iSOR) Ratio Steam-Oil Instantaneous Offset6-VINGS-SAGD 0.0 0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 Time (yr) Figure 5-11: Comparison of iSOR in heterogeneous model.

120

5.2.10 Energy Consumptions

5.2.10.1 Energy Gained by Heat Transfer Model

Figure 5-12 shows heat energy injected into the reservoir to establish thermal

communication between the injection and production wells during the steam circulation

stage in all cases. The amount of energy varies from case to another since it depends on

the distances between the injectors and producers and the configuration of the injection

well with respect to the production well. For instance, the separation distance between

the injector and producers in cases where horizontal steam injectors were offset 6 and 9m

away from the producer is larger than that in Typical SAGD case. In the offset cases, a

larger region of the reservoir lies between the wells and therefore more energy is required

to heat the inter-well region.

Table 5-1 shows overall heat energy gained by the reservoir during the steam circulation stage in each case. The lowest value is for the vertical well SAGD case,

VSAGD, where the region of reservoir to be heated between the injection and production points is relatively small. The value for the offset horizontal cases is largest.

5.2.10.2 Energy Consumed by Steam Injected

Figure 5-13 and Figure 5-14 show the rate of heat energy and the overall cumulative heat energy injected into the reservoir model by steam during production, respectively. As shown in Figure 5-13, the cases with horizontal steam injection wells allow higher heat energy injection rates than that with vertical steam injection.

121

4.0e+13 Typical SAGD VSAGD 3.5e+13 VINGS-SAGD Offset9-SAGD 3.0e+13 Offset6-SAGD Offset6-VSAGD Offset6-VINGS-SAGD 2.5e+13

2.0e+13

1.5e+13

Energy Gain by Heaters (J) Heaters by Gain Energy 1.0e+13

5.0e+12

0.0e+0 0 20 40 60 80 Time (day) Figure 5-12: Comparison of energy gained by the reservoir during the steam circulation stage in heterogeneous model.

Table 5-1: Heat energy gained by reservoir during the steam circulation stage in heterogeneous model.

Heat Energy Gained by Heat Transfer Model at the End Case ID of Pre-Heating Stage, GJ Typical SAGD 9390 Offset6-SAGD 23972 Offset9-SAGD 31077 VINGS-SAGD 5488 Offset6-VINGS-SAGD 14070 VSAGD 844 Offset6-VSAGD 2147

122

6.0e+11

5.4e+11

4.8e+11

4.2e+11

3.6e+11

3.0e+11

2.4e+11 Typical SAGD 1.8e+11 VSAGD VINGS-SAGD

Enthalpy Injection Rate (J/day) 1.2e+11 Offset9-SAGD Offset6-SAGD Offset6-VSAGD 6.0e+10 Offset6-VINGS-SAGD 0.0e+0 0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 Time (yr) Figure 5-13: Comparison of enthalpy injection rates in heterogeneous model. 2.60e+15 Typical SAGD 2.34e+15 VSAGD VINGS-SAGD 2.08e+15 Offset9-SAGD Offset6-SAGD Offset6-VSAGD 1.82e+15 Offset6-VINGS-SAGD 1.56e+15

1.30e+15

1.04e+15

7.80e+14

Cumulative Enthalpy Injected (J) 5.20e+14

2.60e+14

0.00e+0 0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 Time (yr) Figure 5-14: Comparison of cumulative enthalpy injected in heterogeneous model.

123

5.3 Validation of SAGD Model

As was done for the homogeneous model, the results of the simulation were compared to SAGD operations located in Dover area by selecting performance parameters related to SAGD projects (cumulative steam-to-oil ratio, cumulative water-to- oil ratio at the end of the project life, average steam injection rates, average calendar day oil rates, and average water production rates). Table 5-2 compares the results of Typical

SAGD from the homogeneous and heterogeneous models to the performance of SAGD

well pairs at Phase B, D, and E (see Appendix C for names of the wells).

As was the case for the homogeneous reservoir model, the normalized steam

injection rate (normalized against the length of the well), calendar day oil rate (CDOR),

and normalized water production rate, water-to-oil ratio (WOR), and cumulative steam-

to-oil ratio (cSOR) of the heterogeneous Typical SAGD model are consistent with field results. These results indicate that the heterogeneous model is a reasonable representation of the geology of an Athabasca reservoir.

Table 5-2: Comparison of the performance of typical SAGD operation in the field and the SAGD numerical model. Steam Inj. Rate CDOR Water Pro. Rate WOR cSOR Project m3/d/m m3/d/m m3/d/m m3/m3 m3/m3 Typical SAGD Case 0.1 - 0.39 0.1 - 0.21 0.1 - 0.34 2.95 3.25 (Homogeneous geology) Typical SAGD Case 0.1 - 0.38 0.1 - 0.20 0.1 - 0.37 2.90 3.18 (Heterogeneous geology) Phase B (B1) 0.1 - 0.6 0.1 - 0.25 0.1 - 0.55 2.97 3.96 Phase B (B2) 0.1 - 0.5 0.1 - 0.30 0.25 - 0.55 2.94 1.14 Phase B (B3) 0.1 - 0.5 0.1 - 0.20 0.1 - 0.45 2.96 2.77 Phase D (D2) 0.15 - 0.45 0.1 - 0.19 0.15 - 0.40 2.33 2.87 Phase E (E1) 0.1 - 0.4 0.1 - 0.15 0.15 - 0.33 3.73 3.00

124

5.4 Analysis and Discussion of Results

Early-Time Response

In all cases tested in the heterogeneous geological model, thermal communication between the injection and production wells was achieved in the same manner as was done in the homogeneous cases described in Chapter Four. As mentioned above, steam is circulated in both wells at the beginning of the process. Heat is conducted from the wells into the formation to generate a mobile zone so that when steam is afterwards continuously injected into the upper well, it can displace the mobile oil from the reservoir

to create a steam chamber. Figure 5-15 to Figure 5-21 show temperature distributions of each case at the end of steam circulation stage. The results reveal that each well configuration generates a different volume of mobile oil after the steam circulation stage.

Figure 5-15: Temperature distribution at end of steam circulation stage: Typical SAGD case.

125

Figure 5-16: Temperature distribution at end of steam circulation stage: Offset6- SAGD case.

Figure 5-17: Temperature distribution at end of steam circulation stage: Offset9- SAGD case.

Figure 5-18: Temperature distribution at end of steam circulation stage: VINGS- SAGD case.

Figure 5-19: Temperature distribution at end of steam circulation stage: Offset6- VINGS-SAGD case.

126

Figure 5-20: Temperature distribution at end of steam circulation stage: VSAGD case.

Figure 5-21: Temperature distribution at end of steam circulation stage: Offset6- VSAGD case. Steam Injection-Rate Profiles

All injection wells are set to a maximum bottom-hole pressure of 2 MPa. The initial rates that meet this pressure constraint vary depending on the initial size of the steam chamber established during the steam circulation stage and the growth of the steam chamber beyond. In cases where horizontal steam injectors were used, the steam injection rate profiles rise from the beginning of the project. Steam injection rates achieved in the vertical well cases have a more gradual increase because their initial steam chamber volumes are smaller than that of the horizontal well cases. Figure 5-1

127 shows that over the first seven years of operation, horizontal steam injectors have higher

rates over that of the vertical steam injectors. Beyond that time, the individual steam

chambers of the vertical well VINGS-SAGD and Offset6-VINGS-SAGD cases have

merged and the overall injection rate into this larger steam chamber is higher than that of

the horizontal well cases. After being injected into the formation, steam rises into the

formation. The rise rate of the chambers depends on the size of the chambers. That is,

different amounts of heated reservoir fluids are drained at the edge of steam chamber

depending on the heat transfer area. In addition, the rate of fluid withdrawal from the

reservoir is directly impacted by the geometry of the producer. The larger the reservoir

contact, as in horizontal producers, the greater the production rates of fluids.

Oil Production-Rate Profiles

As a result of high steam injection rates at the beginning of projects in cases where horizontal steam injectors were used, initial oil production rates are also high in these cases. Yet, by the end of the second year of the operation, oil rates of the horizontal well cases decline to the end of the operation. This is because the long chambers along the length of the wellpairs reach the overburden and heat losses become large. For the vertical well cases, the losses to the overburden are smaller earlier in the operation. In the VINGS-SAGD and Offset6-VINGS-SAGD cases, the oil rates are higher than that of the horizontal cases beyond about year 5.5. The rates reach their peak values and then decline towards the end of the operation. For the VSAGD and Offset6-VSAGD cases,

the peak rates are achieved after about five years of operation and persist at this value for

several years. At about year 9, the rates decline. The differences between the VINGS-

SAGD cases and VSAGD cases are the configuration of the production wells. There is a

128 difference of the length of the perforating interval of each production well which in turn controls the rate of withdrawal of heated reservoir fluids. As a result of this, oil production rates in the cases where horizontal producers were used (VINGS-SAGD cases) were higher than oil rates in cases where vertical ones (VSAGD cases) were used.

The higher fluid withdrawal obtained when using a horizontal producer speeds up the advance of the steam chamber in the lateral (cross-well) direction. This in turn provides a larger heat transfer area which in turn provides a larger amount of mobilized oil.

Water Production Rate Profiles

Water production rates depend on the amount of steam that condenses while latent heat energy is transferred to the cool oil sands at the edges of the chamber (see Figure

5-7). The larger the chamber, the greater the amount of steam that can be injected into it,

the larger the heat transfer area, and the larger the oil and water (steam condensate)

production rate.

Cumulative Steam Injected, Steam Chamber Volume, Cumulative Oil Produced, Oil Recovery Factors, and Cumulative Water Produced

The results show that horizontal steam injectors deliver more steam than vertical

ones to the reservoir (see Figure 5-2). Again, this is due to the fact that the steam

chamber that forms in the reservoir after the steam circulation stage is larger in extent for

horizontal wells than that of vertical wells. Thus, at constrained injection pressure, the

larger the initial steam chamber, the greater the amount of steam that can be injected into

it. Figure 5-22 to Figure 5-28 show three-dimensional (3D) oil saturation distributions at

the end of sixteen years of operation for the well configurations cases evaluated in the

heterogeneous reservoir. The distributions in the heterogeneous geological model show

129 similar behavior in terms of distributing the injected fluid energy through the reservoir model as that of the homogeneous model described in Chapter Four. The results show that injecting equivalent amount of steam in cases where horizontal steam injectors were used and in cases where vertical injectors were used produce different amounts of oil.

Figure 5-22: Oil saturation distribution at end of operation: Typical SAGD case.

130

Figure 5-23: Oil saturation distribution at end of operation: Offset6-SAGD case.

Figure 5-24: Oil saturation distribution at end of operation: Offset9-SAGD case.

131

Figure 5-25: Oil saturation distribution at end of operation: VINGS-SAGD case.

Figure 5-26: Oil saturation distribution at end of operation: Offset6-VINGS-SAGD case.

132

Figure 5-27: Oil saturation distribution at end of operation: VSAGD case.

Figure 5-28: Oil saturation distribution at end of operation: Offset6-VSAGD case.

133

Thermal Efficiency: Steam to Oil Ratio

Cases where vertical steam injectors were used exhibited overall better performance in terms of overall thermal efficiency, that is, the cSOR, over the life of the operation. The iSOR revealed that horizontal steam injectors run less economically over the majority of the life of the operation. This can be seen in Figure 5-10 and Figure 5-11.

After steam circulation, the Typical SAGD, Offset6-SAGD, and Offset9-SAGD cases

have the lowest cSORs for about 1.5 years of operation. Thereafter, the iSOR of these

cases rise due to the increased loss of heat to the overburden. On the other hand, cases

where vertical steam injectors were used experienced an increase in the iSOR after 4 to 6

years of operation.

The perforating intervals of the vertical steam injectors were located higher into

the formation than that of the horizontal steam ones. That is, the steam chamber in the

vertical steam injector cases reached the overburden before that of the horizontal steam

injector cases. However, heat losses to the overburden in the horizontal cases were still

high. The reason for this is that the steam conformance zone achieved by the horizontal

injectors is larger than that obtained by the vertical wells simply because the horizontal

well extends for a long distance throughout the reservoir. The relative amount of heat

energy transferred to the cool oil sands is relatively high compared to that transferred to

the overburden when using vertical steam injectors.

Tracking the Development of the Steam Chamber

Two examples, Typical SAGD and VINGS-SAGD, are shown here to

demonstrate the differences of the growth of the steam chambers. Figure 5-29 to Figure

5-36 display the sequence of 3D ternary diagrams for Typical SAGD case whereas Figure

134

5-37 to Figure 5-44 show the sequence of 3D ternary diagrams for VINGS-SAGD. The impact of the heterogeneity of the reservoir is visible in the Figures. Figure 5-30 and

Figure 5-38 showed the development of steam chamber after one year of operation in the

Typical SAGD and VINGS-SAGD cases. The latter case indicated that steam tends to climb up first to the top of the reservoir model early in the process since the perforating intervals in the vertical steam injectors are higher than that of the horizontal steam injectors. In the Typical SAGD case, a larger volume of steam contacts the overburden than that of the VINGS-SAGD case.

Figure 5-29: Distribution of phases in the reservoir at the end of steam circulation stage: Typical SAGD case.

135

Figure 5-30: Distribution of phases in the reservoir after one year of operation: Typical SAGD case.

136

Figure 5-31: Distribution of phases in the reservoir after two years of operation: Typical SAGD case.

137

Figure 5-32: Distribution of phases in the reservoir after four years of operation; Typical SAGD case.

138

Figure 5-33: Distribution of phases in the reservoir after six years of operation: Typical SAGD case.

139

Figure 5-34: Distribution of phases in the reservoir after eight years of operation: Typical SAGD case.

140

Figure 5-35: Distribution of phases in the reservoir after twelve years of operation: Typical SAGD case.

141

Figure 5-36: Distribution of phases in the reservoir after sixteen years of operation: Typical SAGD case.

142

Figure 5-37: Distribution of phases in the reservoir at the end of steam circulation stage: VINGS-SAGD case.

143

Figure 5-38: Distribution of phases in the reservoir after one year of operation: VINGS-SAGD case.

144

Figure 5-39: Distribution of phases in the reservoir after two years of operation: VINGS-SAGD case.

145

Figure 5-40: Distribution of phases after four years of operation: VINGS-SAGD case.

146

Figure 5-41: Distribution of phases in the reservoir after six years of operation: VINGS- SAGD case.

147

Figure 5-42: Distribution of phases in the reservoir after eight years of operation: VINGS- SAGD case.

148

Figure 5-43: Distribution of phases in the reservoir after twelve years of operation: VINGS- SAGD case.

149

Figure 5-44: Distribution of phases in the reservoir after sixteen years of operation: VINGS- SAGD case.

Comparing oil production rate profiles in both cases, the results suggest that most of injected heat energy delivered to the reservoir model by using vertical steam injectors was transferred to the cool oil sand at the edges of the chamber rather than to the overburden. In the horizontal well cases, this is not so since the steam chamber is more extensive and loses significant amounts of heat to the overburden.

150

Now, it is clear that vertical steam injectors for SAGD process can deliver the heat energy more efficiently even in heterogeneous media. However, the greater reach of horizontal wells for steam conformance provides a larger overall steam chamber which in turn implies a larger heat transfer surface which in turn implies more mobilized oil and higher oil production rates. When the steam chambers of the vertical well cases merge, the surface area becomes large enough to produce more mobilized oil than that of the horizontal well cases.

5.5 Impact of Reservoir Heterogeneity on Performance

Based on the realizations developed by using geostatistical model generation, the resulting reservoir model has good oil sands quality at the base of the formation. That is, higher permeability and higher porosity and higher oil saturation are found towards the base of the reservoir. The average properties of the homogeneous and heterogeneous reservoir models are roughly equal to each other. The results from the heterogeneous reservoir model clearly reveal the impact of heterogeneity on the performance of steam- based operations. The shape and conformance zones of the steam chambers were different between the homogenous and heterogeneous cases.

The overall recovery factor (RF), thermal efficiency (measured by the cSOR), and cEOR of the cases evaluated in the homogeneous and heterogeneous geological model are listed in Table 5-3. The results reveal that the processes perform better in the heterogeneous geological model. One factor that accounts for this is that the heterogeneity leads to dispersion of heat as it moves out from the injection wells in the heterogeneous model. This dispersion effect leads to more spreading of the heat as it moves away from the injection well and promotes slower vertical growth of the steam

151 chamber. Thus, this delays heat losses to the overburden. Flow barriers or tight zones in

the reservoir that slow down vertical movement of heat can delay the steam chamber

from reaching the top of the formation. The results in Table 5-3 reveal that the cSORs

and cEORs were slightly lower for the vertical injector well cases whereas it remained

about the same or was slightly higher for the horizontal injector well cases. The overall

recovery factors for all the cases are about 8 to 9% higher in the heterogeneous cases.

This demonstrates that for roughly the same cSOR (and cEOR), the heterogeneous cases

are producing more oil than that of the homogeneous cases. This is due to the thermal

dispersion effect resulting from the heterogeneity of the reservoir.

Table 5-3: Impact of homogeneous and heterogeneous geology on process performance in different well configurations. RF cSOR cEOR Case ID % m3/m3 GJ/m3 Homogeneous Geology Typical SAGD 44.21 3.25 8.38 Offset9-SAGD 45.47 3.22 8.38 Offset6-SAGD 45.02 3.22 8.35 VINGS-SAGD 39.34 2.88 7.40 Offset6-VINGS-SAGD 40.56 2.94 7.60 VSAGD 34.85 3.04 7.77 Offset6-VSAGD 35.70 3.04 7.80 Heterogeneous Geology Typical SAGD 53.47 3.18 8.17 Offset9-SAGD 54.60 3.16 8.18 Offset6-SAGD 53.96 3.17 8.19 VINGS-SAGD 48.41 2.91 7.47 Offset6-VINGS-SAGD 49.89 2.95 7.61 VSAGD 41.75 3.10 7.95 Offset6-VSAGD 43.88 3.09 7.92

The effect of heterogeneity on vertical growth of the steam chamber is visualized

in Figure 5-45 to Figure 5-48. The figures display ternary diagrams of the distribution of

152 phases in the reservoir. In each figure, Image A denotes a cross-sectional view of the reservoir model (along the wells) whereas Image B denotes a plan view of the computer model. The results show that the steam is better distributed in the heterogeneous reservoir compared to that in the homogeneous reservoir. The depletion chambers in the homogeneous cases appear to have relatively high water (liquid) phase content whereas the heterogeneous cases appear to have more steam within the depletion chamber.

Figure 5-45: Effect of vertical to horizontal permeability ratio on vertical growth of the steam chamber in homogeneous reservoir: Typical SAGD case.

153

Figure 5-46: Effect of vertical to horizontal permeability ratio on vertical growth of the steam chamber in heterogeneous reservoir: Typical SAGD case.

Figure 5-47: Effect of vertical to horizontal permeability ratio on vertical growth of the steam chamber in homogeneous reservoir: VINGS- SAGD case.

154

Figure 5-48: Effect of vertical to horizontal permeability ratio on vertical growth of the steam chamber in heterogeneous reservoir: VINGS- SAGD case.

Figure 5-49 and Figure 5-50 demonstrate the impact of heterogeneity on lateral growth of the steam chamber. Figure 5-49 displays a cross-section of the Typical SAGD

case in the homogeneous and heterogeneous reservoir models. The results show how the

lateral growth is greater in the heterogeneous case over that of the homogeneous case.

This is especially apparent in the vertical well case displayed in Figure 5-50 where the majority of the individual chambers have merged in the heterogeneous reservoir whereas they are completely separate in the homogeneous reservoir.

155

Figure 5-49: Impact of geology (A=homogeneous, B=heterogeneous) on lateral growth of steam chamber: Typical SAGD case.

Figure 5-50: Impact of geology (A=homogeneous, B=heterogeneous) on lateral growth of steam chamber: VINGS-SAGD case.

156

To demonstrate the impact of reservoir heterogeneity on the performance of the processes, the Calendar Day Oil Rates (CDOR) of the Typical SAGD and VINGS-SAGD cases are plotted in Figure 5-51and Figure 5-52. In both cases, higher oil production rates result from the process operated in the heterogeneous reservoir model. The results also show that the thermal efficiency, as measured by the iSOR, is slightly better in the

Typical SAGD case but is largely unchanged in the VINGS-SAGD case. This is because the steam chambers in the horizontal cases are slower to reach the overburden in the heterogeneous case and because the size of the chamber is relatively large, the impact of this slower growth yields slightly better iSOR. In the VINGS-SAGD case, the chambers are small and as a result, the slower vertical growth of the chamber in the heterogeneous reservoir has relatively small effect on the iSOR.

160 8.0 Homogeneous Geology Case (CDOR) 140 Heterogeneous Geology Case (CDOR) 7.0 Homogeneous Geology Case (iSOR) Heterogeneous Geology Case (iSOR) 120 6.0

100 5.0

80 4.0

60 3.0

40 2.0

20 1.0 Calendar Day Oil Rate (CDOR) Rate DayCalendar Oil (m3/day)

0 0.0 Instantaneous Steam-Oil Ratio(iSOR) (m3/m3) 0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 Time (yr) Figure 5-51: Effect of heterogeneity on performance of Typical SAGD case.

157

160 8.0 Homogeneous Geology Case (CDOR) 140 Heterogeneous Geology Case (CDOR) 7.0 Homogeneous Geology Case (iSOR) Heterogeneous Geology Case (iSOR) 120 6.0

100 5.0

80 4.0

60 3.0

40 2.0

20 1.0 Calendar Day Oil Rate (CDOR) DayRate Oil Calendar (m3/day)

0 0.0 (iSOR) (m3/m3) Ratio Steam-Oil Instantaneous 0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 Time (yr) Figure 5-52: Effect of heterogeneity on performance of VINGS-SAGD case.

5.6 Impact of Heterogeneous Geology on Natural Gas Consumption and Flue Gases Emissions

Cumulative CH4 consumed and cumulative CO2 emissions per unit bitumen

produced are calculated and plotted in Figure 5-53 and Figure 5-54, respectively. Similar to the results in Chapter Four, the simulation reveal that well configurations that utilized vertical injectors consume lower natural gas in the duration of 16 years. On the other hand, well configurations employing a horizontal steam injector emitted more carbon dioxide.

cNOR and cCOR are plotted in Figure 5-55 and Figure 5-56, respectively. They

show similar trends as was found for the homogeneous model. By the end of the

158 operation, typical values of 300 to 350 m3/m3 are observed, as listed in Table 5-4. The

VINGS-SAGD well configuration has the lowest cNOR and cCOR values.

Figure 5-53: Comparison of cumulative methane consumed in heterogeneous model.

Figure 5-54: Comparison of cumulative CO2 emitted in heterogeneous model.

159

Figure 5-55: Comparison of cumulative CH4 to produced oil ratio (cNOR) in heterogeneous model.

Figure 5-56: Comparison of cumulative CO2 to produced oil ratio (cCOR) in heterogeneous model.

160

Table 5-4: Cumulative generated CO2 to produced Oil Ratio (cCOR) and consumed CH4 to produced Oil Ratio (cNOR). cNOR cCOR Case ID m3/m3 m3/m3 Typical SAGD 341 341 Offset9-SAGD 339 339 Offset6-SAGD 340 340 VINGS-SAGD 312 312 Offset6-VINGS-SAGD 317 317 VSAGD 333 333 Offset6-VSAGD 331 331

5.7 Impact of Well Configuration on a Simple Economic Measure in Heterogeneous Geology

Table 5-5 list the results of simple well cost per unit bitumen produced in the heterogeneous model in the same manner as was used in Chapter Four. As before, the iSOR cutoffs are set equal to 3 and 3.5 m3/m3.

Table 5-5: Economic performance of SAGD-Like processes under different well configurations.

iSOR Time Cum. Oil Well Cost Case ID m3/m3 day m3 $/m3 Typical SAGD 3 2,223 162,397 18.5 3.5 3,004 208,309 14.4 Offset9-SAGD 3 1,991 162,429 18.5 3.5 2,760 207,262 14.5 Offset6-SAGD 3 2,052 161,939 18.5 3.5 2,851 208,362 14.4 VINGS-SAGD 3 3,603 188,202 14.6 3.5 4,230 221,298 12.4 Offset6-VINGS-SAGD 3 3,255 185,488 14.8 3.5 3,887 219,281 12.5 VSAGD 3 2,432 83,174 15.0 3.5 5,277 220,492 5.7 Offset6-VSAGD 3 2,507 96,258 26.0 3.5 4,866 216,578 11.5

161

At a cutoff of 3 m3/m3, the combination of vertical injectors with a horizontal producer (VINGS-SAGD) appears to have the lowest well cost per unit oil produced. At a cutoff of 3.5 m3/m3, the VSAGD well configuration appears to perform the best.

162

Chapter Six: Conclusions and Recommendations

6.1 Conclusions

In this research, homogeneous and heterogeneous models with properties typical of that of Athabasca oil sands reservoirs were constructed to investigate the impact of different well configurations on the performance of thermal gravity drainage processes.

The main conclusions from the research conducted in this thesis are as follows:

1. Horizontal steam injectors deliver more steam to the formation due to the larger

initial steam chamber formed when production first starts. Horizontal steam

injectors develop faster steam chambers and recover more oil. However, heat

energy consumption due to large losses to the overburden can render the process

relatively thermally inefficient.

2. Vertical steam injectors have the advantage that the exposure of the steam

chamber to the overburden is smaller than that of horizontal steam injectors

earlier in the operation. This allows more efficient delivery of energy to the oil

sand in the early stages of the process.

3. The advantages of vertical injectors to deliver energy to the reservoir endorses the

use of limited-entry perforations (LEPs) as has been done for horizontal CSS

wells in Cold Lake (Boone et al. 2001). LEPs have the benefit of having discrete

injection intervals along the length of the horizontal well.

4. Horizontal producers perform better than vertical producers when vertical steam

injectors are used.

5. Heterogeneity of the reservoir helps to distribute steam and heat in the lateral

direction in the reservoir. This is due to a thermal dispersion effect that slows

163

vertical flow of heat in the reservoir thus leading to lower heat losses to the

overburden than would be the case in a homogeneous reservoir.

6. The key control on the oil production rate from the reservoir is the size of the

steam chamber. The evolution of the steam chamber and its size is set by the size

of the initial steam chamber volume formed directly after the steam circulation

stage. The larger the steam chamber volume, the larger the heat transfer area, and

in turn, the greater the mobilized oil and production rate.

6.2 Recommendations for Future Work

The recommendations that result from this research are as follows:

1. Reservoir characterization is an important factor in thermal gravity drainage

processes. More studies are required to determine the robustness of the

conclusions made in this thesis.

2. Uncertainty analyses of the reservoir characterization (permeability, porosity, and

reservoir fluid saturations) should be done to assess the sensitivities of

performance (both rates and thermal efficiency) of different well configurations.

3. The cost of both surface facilities and subsurface equipment to operate number of

vertical steam injectors should be considered versus that of horizontal injectors.

4. The impact of heterogeneity and well configuration on performance of steam-

solvent gravity drainage processes should be evaluated. Depending on the well

configuration, solvent recovery could potentially be optimized thus improving the

performance and economics of steam-solvent processes.

5. The opportunity for using a set of vertical steam injectors with a horizontal

producer (VINGS-SAGD) for intelligent control of steam chamber evolution

164

should be explored. This could be an alternative to horizontal smart well injectors

where interval control valves are used. The use of a set of vertical steam injectors

may yield improved steam conformance control as well as be more cost effective

than a horizontal smart well.

6. Pad-scale VINGS-SAGD control strategies should be explored where multiple

vertical steam injectors and horizontal producers are used where initially the

process is dominated by gravity drainage but later transitions into a steam flood.

165

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Appendices

A. Core Data Examinations of 17 Wells Used to Construct Heterogeneous Geostatistical Model.

a. UWI AB/01-18-093-12W4/0

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B. UWI AD/01-18-093-12W4/0

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G. UWI AE/02-18-093-12W4/0

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224

P. BTP03 (STROBL et al. 1995)

Sample Sample Kh, Kv, Density, Sample Flow Units Porosity Depth Number mD mD kg/m3 Description 132.17 1 3280 - 0.361 2630 ss vf f 134.20 2 4330 0.360 2650 ss vf f 134.90 3 1160 0.324 2610 vf f shy 135.39 4 3090 0.349 2650 vf f shy 136.95 5 3510 - 0.353 2650 ss vf f 137.71 6 3870 0.378 2650 ss vf f IHS 138.32 7 3310 0.369 2620 ss vf f 138.51 8 0.06 0.279 2540 sh sdy 139.47 9 0.04 0.337 2550 vf vshy 140.5 10 4030 - 0.361 2630 ss vf f 141.49 11 706 0.332 2600 vf f shy 141.63 12 3910 - 0.361 2630 ss vf f 142.36 13 - 6380 0.403 2620 vf f shy 143.07 14 52.40 0.270 2550 sh sdy 143.36 15 3790 0.380 2640 vf f shy Transitional 144.15 16 3140 0.348 2650 vf f sshy 144.78 17 4560 - 0.354 2650 vf f sshy 146.77 18 5390 0.372 2630 ss vf f 147.44 19 5010 - 0.353 2630 ss vf f 148.31 20 5180 - 0.37 2630 vf f sshy Trough 150.25 21 5660 - 0.399 2630 ss vf f Cross 150.76 22 - 1490 0.398 2400 vf shy Bedded 151.71 23 6440 - 0.388 2620 vf f carb (Upper) 153.47 24 5620 - 0.360 2630 ss vf f 153.9 25 6910 - 0.377 2630 vf f sshy 154.0 Siltstone - 2.08 0.054 2660 sltst sdy Trough 154.20 26 7210 - 0.368 2630 ss vf f Cross 154.80 27 5520 - 0.354 2630 ss vf f Bedded 155.34 28 5440 - 0.384 2620 ss vf f (Lower) 156.10 29 4930 - 0.371 2620 vf f sshy 156.54 30 - 1780 0.350 2440 vf f sshy

225

Q. BTP06 (STROBL et al. 1995)

Sample Sample Kh, Kv, Density Sample Flow Units Porosity Depth Number mD mD kg/m3 Description 129.10 1 - 20.10 0.272 2560 vf f vshy 131.50 2 2910 0.360 2640 vf f vshy 131.73 3 4140 0.354 2640 ss vf f 132.90 4 3400 0.358 2650 ss vf f 133.94 5 3100 - 0.376 2650 vf f sshy 134.64 6 3840 0.362 2650 ss vf f 137.20 7 3060 0.361 2640 vf f sshy 138.22 8 3900 0.361 2640 ss vf f 140.12 9 5390 0.372 2650 ss vf f IHS 141.37 10 3700 - 0.361 2650 ss cf f 142.16 11 4.65 0.268 2530 sh sdy 142.75 12 5020 0.384 2640 ss vf f 144.38 13 3080 0.336 2620 vf f sshy 145.52 14 4990 0.388 2630 vf f sshy 146.68 15 - 159 0.346 2580 vf f shy 147.26 16 4570 0.382 2650 ss vf f 147.65 17 5550 0.417 2640 ss vf f 147.92 18 5580 - 0.390 2640 vf f sshy 148.95 19 5690 - 0.400 2650 ss vf f 149.50 20 6050 - 0.393 2640 ss vf f Transitional 150.36 21 5840 - 0.384 2640 ss vf f 151.75 22 5510 - 0.365 2630 ss vf f Trough 153.19 23 - 2050 0.386 2490 f sshy Cross 153.75 24 6140 - 0.382 2640 ss vf f Bedded (Upper) 154.68 25 6180 - 0.368 2630 ss vf f 155.0 Siltstone - 1.47 0.044 2660 sltst sdy Trough 155.15 26 7840 - 0.377 2640 ss vf f Cross 155.89 27 6670 - 0.398 2640 ss vf f Bedded 156.25 28 5820 - 0.384 2630 ss vf f (Lower) 156.69 29 8780 - 0.370 2640 ss vf f 156.95 30 6410 - 0.355 2650 ss vf f

226

B. Reservoir Simulation Input Files.

All cases tested in the homogeneous geological model were as follows:

1. Typical SAGD001.dat

2. Offset6-SAGD001.dat

3. Offset9-SAGD001.dat

4. VINGS-SAGD001.dat

5. Offset6-VINGS-SAGD001.dat

6. VSAGD001.dat

7. Offset6-VSAGD001.dat

All cases tested in the heterogeneous geological model were as follows:

1. Typical SAGD002.dat

2. Offset6-SAGD002.dat

3. Offset9-SAGD002.dat

4. VINGS-SAGD002.dat

5. Offset6-VINGS-SAGD002.dat

6. VSAGD002.dat

7. Offset6-VSAGD002.dat

227

C. Wells Used to Validate the SAGD Model.

a. UWI AG/01-18-093-12W4/0

b. UWI AH/01-18-093-12W4/0

c. UWI AJ/01-18-093-12W4/0

d. UWI AK/01-18-093-12W4/0

e. UWI AL/01-18-093-12W4/0

f. UWI AM/01-18-093-12W4/0

g. UWI 03/10-18-093-12W4/0

h. UWI 04/10-18-093-12W4/0

i. UWI 00/01-18-093-12W4/0

j. UWI 02/01-18-093-12W4/2