Case Study of Expanding Solvent-SAGD Process for Athabasca ...

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Case Study of Expanding Solvent-SAGD Process for

Athabasca Oil Sand Reservoirs with Presensce of

Lean Zones

Yu, Yanguo

Yu, Y. (2017). Case Study of Expanding Solvent-SAGD Process for Athabasca Oil Sand Reservoirs

with Presensce of Lean Zones (Unpublished master's thesis). University of Calgary, Calgary, AB.

doi:10.11575/PRISM/25222

http://hdl.handle.net/11023/3963

master thesis

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i

UNIVERSITY OF CALGARY

Case Study of Expanding Solvent -SAGD Process for Athabasca Oil Sand Reservoirs

with Presence of Lean Zones

by

Yanguo Yu

A THESIS

SUBMITTED TO THE FACULTY OF GRADUATE STUDIES

IN PARTIAL FULFILMENT OF THE REQUIREMENTS FOR THE

DEGREE OF MASTER OF SCIENCE

GRADUATE PROGRAM IN CHEMICAL AND PETROLEUM ENGINEERING

CALGARY, ALBERTA

JULY, 2017

© Yanguo Yu 2017

ii

Abstract

Reservoir heterogeneities (i.e., lean zones or shale layers) impact the performance

of SAGD (steam assisted gravity drainage) processes. The lean zones, which have a water

saturation of more than 50%, have been reported by several oil sands fieldsduring the

development of oil sand reservoirs in the Athabasca area in western Canada. They reported

that the lean zones severely affected the production of SAGD processes. Therefore, an ES-

SAGD (expanding solvent SAGD) process has been introduced into this type of reservoir

to improve the production performance.

Simulation studies are conducted to investigate the mechanisms of how lean zones

influence the two processes by comparing their bottom, middle, and top locations in a

reservoir. Moreover, the thickness, location, water saturation of lean zones and reservoir

permeability are also investigated to understand the impacts of lean zones further on these

processes. A heterogeneous reservoir model, which contains lean zones, is carried out to

study the production performance of the SAGD and ES-SAGD processes.

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Acknowledgements

I would like to deeply thank my supervisor Dr. Zhangxing (John) Chen for giving

me the opportunity, support, resources, guidance, and freedom to do my research work at

the University of Calgary. My profound thanks go to Dr. Pedro R. Pereira Almao and Dr.

Qingye (Gemma) Lu for their gracious willingness to serve on my exam committee. My

gratitude goes to Mr. Jinze Xu and Mr. Yuan Hu for their timely support, involvement,

knowledge, commitment, and technical help provided to me throughout my research work.

I am grateful to Mr. Christof Lee and Dr. David R. Williams for dedicating their time and

efforts in reading my thesis and giving me with their valuable feedback and suggestions. I

also would like to thank all teammates in the Reservoir Simulation Group (RSG) and all

sponsors of RSG. I also thank the assistants in RSG, Ms. Jamie McInnis, Ms. Fengyue Lin

and Mr. Stephen Cartwright for their help. To Chemical and Petroleum Department,

University of Calgary, I hope to express my appreciations to all stuff in the department.

My deepest and sincere gratitude goes to my entire family, my parents, and my

older sisters for their selfless support, motivation, and love.

This thesis is dedicated to my beloved wife, Yutao (Teresa) Niu, and my wonderful

son, Guanghong (Eric) Yu.

iv

Table of Contents

Abstract ............................................................................................................................... ii

Acknowledgements ............................................................................................................ iii

Table of Contents ............................................................................................................... iv

List of Tables .................................................................................................................... vii

List of Figures and Illustrations ....................................................................................... viii

List of Symbols, Abbreviations, and Nomenclature ........................................................ xvi

Chapter One: : INTRODUCTION .......................................................................................1

1.1 Overview ........................................................................................................................1

1.2 Problem Statement .........................................................................................................2

1.3 Objectives of Thesis .......................................................................................................3

1.4 Organization of Thesis ...................................................................................................3

Chapter Two: REVIEW OF LITERATURE .......................................................................5

2.1 Cyclic Steam Stimulation (CSS) ....................................................................................5

2.2 Steam Flooding ..............................................................................................................6

2.3 Steam Assisted Gravity Drainage (SAGD)....................................................................8

2.3.1 Basic Analytical Model of SAGD ..........................................................................9

2.3.2 The Effects of Temperature on Bitumen Viscosity ..............................................11

2.3.3 The Process of Steam Chamber Development .....................................................13

2.3.4 Review of Operation Parameters in SAGD Process .............................................14

2.3.4.1 Start-up in SAGD Process ............................................................................14

2.3.4.2 Steam Trap Control in SAGD Process .........................................................16

2.3.4.3 Operation Pressure in SAGD (Low pressure vs. High pressure) .................17

2.3.5 Improvement of SAGD Process ...........................................................................19

2.4 Expanding Solvent - Steam Assisted Gravity Drainage (ES-SAGD) ..........................19

2.4.1 Basic Theory of Expanding Solvent - SAGD (ES-SAGD) ..................................20

2.4.2 Solvent Selection of ES-SAGD Process ...............................................................21

2.4.3 Effects of Solvent Concentration on ES-SAGD Process ......................................26

2.4.4 The Impacts of Operating Pressure .......................................................................27

2.4.5 Phase Behavior of Steam Chamber in ES-SAGD Process ...................................28

2.5 The Impacts of Reservoir Heterogeneities ...................................................................32

Chapter Three: RESERVOIR MODEL .............................................................................36

3.1 Basic Model Construction and Description .................................................................36

3.1.1 Grid System ..........................................................................................................36

3.1.2 Reservoir Properties ..............................................................................................39

3.2 Fluid Properties ............................................................................................................41

3.3 Operation Parameters for the Cases .............................................................................42

3.4 The Location of Lean Zones in the Reservoir Model ..................................................42

Chapter Four: DISCUSSION OF SAGD PROCESS WITH LEAN ZONES ...................43

4.1 Introduction ..................................................................................................................43

4.2 The Comparison of Base Case and Lean Zones (2 meters) Case ................................43

v

4.2.1 Analysis and Comparison of the Steam Chamber ................................................44

4.2.1.1 Bottom Area of the Reservoir .......................................................................47

4.2.1.2 Middle Area of the Reservoir .......................................................................51

4.2.1.3 Top Area of the Reservoir ............................................................................54

4.2.2 Comparative Analysis of the Impacts of Lean Zones in the Reservoir ................57

4.2.2.1 Water Saturation and Velocity Vector of Water Distribution ......................57

4.2.2.2 Production Variations in the Steam Chamber ..............................................59

4.2.3 Comparison and Analysis of the Growth of the Steam Chamber .........................61

4.3 Sensitivity Analysis of Reservoir with Lean Zones in SAGD Process .......................64

4.4 Conclusions of the SAGD Process ..............................................................................66

Chapter Five: ANALYSIS OF ES-SAGD PROCESS WITH LEAN ZONES..................68

5.1 Introduction ..................................................................................................................68

5.2 Solvent Characterization ..............................................................................................68

5.3 Solvent Injection Strategies .........................................................................................69

5.4 Results Discussion and Comparison of Base Cases and Lean Zones Cases ...............69

5.4.1 Mechanisms Analysis of Reservoir at Different Locations ..................................72

5.4.1.1 Bottom of the Reservoir ...............................................................................72

5.4.1.2 Middle of the Reservoir ................................................................................78

5.4.1.3 Top of the Reservoir .....................................................................................83

5.4.2 Impacts of Lean Zones in the Reservoir ...............................................................89

5.4.2.1 Temperature Distribution .............................................................................89

5.4.2.2 Distribution of the Water Saturation and Velocity Vector of Water ............91

5.4.3 Solvent Distribution in the Steam Chamber .........................................................94

5.4.3.1 Mole Fraction Distribution of IC4-NC5 ........................................................94

5.4.3.2 Mole Fraction Distribution of C6-C8 ............................................................96

5.4.4 Comparison of Production Performance ...............................................................97

5.4.5 Comparative Analysis of the Growth of the Steam Chamber ..............................99

5.4.6 Solvent Distribution in the Growth of the Steam Chamber ................................102

5.5 Sensitivity Analysis of Reservoir with Lean Zones in ES-SAGD Process ...............107

5.5.1 Multiple-layer of the Lean Zones .......................................................................107

5.5.2 The Locations of the Lean Zones .......................................................................108

5.5.3 The Water Saturation of the Lean Zones ............................................................109

5.5.4 The Effect of Reservoir Vertical Permeability ...................................................109

5.6 Conclusions of the ES-SAGD Process ......................................................................111

Chapter Six: COMPARISON OF SAGD AND ES-SAGD PROCESSES IN RESERVOIR

WITH LEAN ZONES......................................................................................................113

6.1 Introduction ................................................................................................................113

6.2 Comparative Mechanism Analyses of Reservoir at Different Locations ..................113

6.2.1 Comparison at Lean Zone Area ..........................................................................116

6.2.2 Comparison of the Middle of the Reservoir .......................................................118

6.2.3 Comparison of the Bottom of the Reservoir .......................................................121

6.3 Comparison of Growth of the Steam Chamber in SAGD and ES-SAGD Processes 125

6.4 Comparative Analysis and Discussion for Lean Zones .............................................128

vi

Temperature Distribution ....................................................................................128

Water Distribution and Velocity Vector of Water ..............................................129 Oil Mobility Distribution ....................................................................................130 Thickness of the Lean Zones ..............................................................................131

Comparison of SAGD and ES-SAGD Processes in a Heterogeneous Reservoir ......134 2D Heterogeneous Model Construction and Description ...................................134 Operation Parameters ..........................................................................................135 Results and Discussion .......................................................................................138

Conclusions of the Chapter ........................................................................................140

CONCLUSIONS AND FUTURE WORKS ..........................................141 Conclusions ................................................................................................................141 Future Works .............................................................................................................142

REFERENCES ................................................................................................................143

vii

List of Tables

Table 3-1 Reservoir Parameters for Simulation Model .................................................... 39

viii

List of Figures and Illustrations

Figure 1-1 Oil sand deposits in Alberta (Government of Alberta 2012) ............................ 1

Figure 2-1 Cyclic steam stimulation process (Oilberta Oil & Gas Corp.) .......................... 5

Figure 2-2 Steam flooding process (Petroleum Support Corp.) ......................................... 7

Figure 2-3 Steam assisted gravity drainage (SAGD) process (JPEC) ................................ 8

Figure 2-4 Viscosity of Athabasca bitumen vs. temperature ............................................ 12

Figure 2-5 Basic concept of steam chamber (Butler 1981) .............................................. 13

Figure 2-6 Schematic of start-up procedure in SAGD process (Rangewest Tech.) ......... 15

Figure 2-7 Schematic of an ideal steam chamber in SAGD Process (Gates 2010). ......... 16

Figure 2-8 Basic concept of Expanding Solvent – SAGD (ES-SAGD) ........................... 21

Figure 2-9 Comparison of hydrocarbons (C3 to C8) vaporization temperature with steam

temperature (Nasr et al. 2003)................................................................................... 23

Figure 2-10 Comparison of oil drainage rates and different hydrocarbon co-injecting

strategies (Nasr et al. 2003)....................................................................................... 24

Figure 2-11 Oil drainage rates vs. temperature difference between steam and solvent

(Nasr et al. 2003) ....................................................................................................... 25

Figure 2-12 Solvent (C6) volume fraction vs. viscosity of Athabasca bitumen at

constant temperature (Li 2010) ................................................................................. 27

Figure 2-13 Correlation between condensation temperature of water and hexane

mixture versus mole fraction of hexane at 2000 kPa (Dong 2012) .......................... 30


mixture versus volume fraction of hexane at 2000 kPa (calculated at 25 oC) (Dong

2012) ......................................................................................................................... 31

Figure 2-15 Temperature profiles in distance at the edge of steam chamber between

SAGD and ES-SAGD (More Fraction of Hexane at 0.01, 2000 kPa) (Dong 2012)

................................................................................................................................... 31

Figure 3-1 Grid structure of a right half reservoir model in i-k directions ....................... 37

Figure 3-2 A right half reservoir model in 3D view ......................................................... 38

ix

Figure 3-3 Water–oil relative permeabilility, ................................................................... 40

Figure 3-4 Gas-liquid relative permeability, ..................................................................... 40

Figure 3-5 The correlation of temperature versus bitumen viscosity ............................... 41

Figure 4-1Water saturation profile in cross-section of SAGD ......................................... 43

Figure 4-2 Comparison of the temperature distributions with different zones of SAGD

process with 2500 kPa injection pressure at 273 days .............................................. 45

Figure 4-3 Schematic presentation of the temperature, gas saturation, oil saturation, oil

mobility, water saturation profiles along the line of study (50-67 m) in SAGD


Figure 4-4 Comparison of the temperature profiles with three areas of the reservoir in

SAGD with 2500 kPa injection pressure at 273 days ............................................... 46

Figure 4-5 Comparison of the temperature profiles at bottom area of the reservoir with

2500 kPa injection pressure at 273 days. The dashed line indicates the location of

study line ................................................................................................................... 49

Figure 4-6 Schematic representation of the temperature, gas saturation, oil saturation,

oil mobility, water saturation profiles along the line of study (50-65 m) in SAGD


Figure 4-7 Comparison of the temperature profiles at middle area of the reservoir in

SAGD with 2500 kPa injection pressure at 273 days. The dashed line indicates

the location of study line ........................................................................................... 52


oil mobility, water saturation profiles along the line of study (50-65m) in SAGD


Figure 4-9 Comparison of the temperature profiles at top area of the reservoir in SAGD

process with 2500 kPa injection pressure at 273 days. The dashed line indicates

the location of the line of study. ................................................................................ 55



with 2500 kPa injection pressure at 273 days ........................................................... 56

Figure 4-11 Comparison of water saturation and water velocity vector in SAGD with

2500 kPa injection pressure at 273 days. .................................................................. 58

Figure 4-12 Comparison of the seam chamber volume .................................................... 59

x

Figure 4-13 Comparison of the cumulative water production .......................................... 60

Figure 4-14 Comparison of the oil recovery factor .......................................................... 60

Figure 4-15 Comparison of the temperature profiles in cross section of SAGD with

2500 kPa injection pressure at 180 days, 365 days, and 730 days ........................... 62

Figure 4-16 Comparison of the gas saturation profiles in cross section of SAGD with

2500 kPa injection pressure at 180 days, 365 days, and 730 days. ........................... 63

Figure 4-17 Comparison of the oil recovery factor vs. thickness of the lean zones ......... 65

Figure 4-18 Effects of the lean zone water saturation vs. the oil recovery factor ............ 65

Figure 4-19 Effects of the ratio of vertical and horizontal permeabilty vs. the oil

recovery factor .......................................................................................................... 66

Figure 5-1 Comparison of the temperature profiles with different zones of ES-SAGD

process with 2500 kPa injection pressure at 273 days. The dished line is the study

line ............................................................................................................................. 70


oil mobility, water saturation profiles along the line of study (50-65 m) in ES-

SAGD process with 2500 kPa injection pressure at 273 days .................................. 71

Figure 5-3 Schematic representation of the solvent mixture (IC4-NC5, C6-C8, and C9-

C11) and steam mole fraction in the vapor, the solvent mixture mole fraction in the

oil phase profiles along the line of study (50-65 m) in ES-SAGD process with

2500 kPa injection pressure at 273 days ................................................................... 71

Figure 5-4 Comparison of the temperature profiles with three areas of the reservoir in

ES-SAGD with 2500 kPa injection pressure at 273 days ......................................... 72

Figure 5-5 Comparison of temperature profiles at bottom location of the reservoir in

ES-SAGD process with 2500 kPa injection pressure at 273 days. The dashed line

indicates the location of study line ............................................................................ 75

Figure 5-6 Property variations of the temperature, gas saturation, oil saturation, oil

mobility, water saturation profiles along the line of study (50-65 m) in ES-SAGD



C11) and steam mole fraction in the vapor phase, the solvent mxiture mole fraction

in the oil phase profiles along the line of study (50-65 m) in ES-SAGD process


xi





C11) and steam mole fraction in the vapor phase, solvent mxiture mole fraction in

the oil phase profiles along the line of study (50-65 m) in ES-SAGD process with


Figure 5-10 Comparison of the temperature profiles at middle location of the reservoir

in ES-SAGD process with 2500 kPa injection pressure at 273 days. The dashed

line indicates the location of study line ..................................................................... 81




Figure 5-12 Schematic representation of the solvent (IC4-NC5, C6-C8, and C9-C11) and

steam mole fraction in vapor phase, the solvent mixture mole fraction in the oil

phase profiles along the line of study (50-65 m) in ES-SAGD process with 2500

kPa injection pressure at 273 days ............................................................................ 82



process with 2500 kPa injection pressure at 273 days. ............................................. 82


steam mole fraction in the vapor phase, the solvent mixture mole fraction in the

oil phase profiles along the line of study (50-65 m) in ES-SAGD process with


Figure 5-15 Comparison of the temperature profiles at top location of the reservoir in


indicates the location of study line ............................................................................ 86








xii








Figure 5-20 Comparison of temperature profiles vs. distances in SAGD with 2500 kPa

injection pressure at 273 days ................................................................................... 90

Figure 5-21 Comparison of water saturation and water velocity vector of in ES-SAGD


Figure 5-22 Comparison of the solvent (IC4-NC5) mole fraction profiles in the vapor

phase of ES-SAGD with 2500 kPa injection pressure at 273 days ........................... 95

Figure 5-23 Comparison of the solvent (IC4-NC5) mole fraction profiles in the oil phase

of ES-SAGD with 2500 kPa injection pressure at 273 days ..................................... 95

Figure 5-24 Comparison of the solvent (C6-C8) mole fraction distribution in the vapor


Figure 5-25 Comparison of the solvent (C6-C8) mole fraction distribution in the oil


Figure 5-26 Comparison of the steam chamber volume ................................................... 98

Figure 5-27 Comparison of the oil recovery factor .......................................................... 98

Figure 5-28 Comparison of temperature profiles in cross section of ES-SAGD with

2500 kPa injection pressure at 180, 365, and 730 days .......................................... 100

Figure 5-29 Comparison of gas saturation profiles in cross section of ES-SAGD with

2500 kPa injection pressure at 180, 365, and 730 days .......................................... 101


phase of ES-SAGD with 2500 kPa injection pressure at 180, 365, and 730 days .. 103

Figure 5-31 Comparison of the solvent (IC4-NC5) mole fraction profiles in the oil phase

of ES-SAGD with 2500 kPa injection pressure at 180, 365, and 730 days ............ 104

Figure 5-32 Comparison of the solvent (C6-C8) mole fraction profiles in the vapor phase


xiii

Figure 5-33 Comparison of the solvent (C6-C8) mole fraction profiles in the oil phase


Figure 5-34 Comparison of the oil recovery factor vs. thickness of the lean zones ....... 107

Figure 5-35 Comparison of the oil recovery factor vs. location of the lean zones ......... 108

Figure 5-36 Comparison of the oil recovery factor vs. water saturation of the lean zones

................................................................................................................................. 109

Figure 5-37 Comparison of the oil recovery factor vs. the ratio of vertical and horizontal

permeability ............................................................................................................ 110

Figure 6-1 Comparison of the temperature profiles in SAGD and ES-SAGD processes

with 2500 kPa injection pressure at 273 days ......................................................... 115


with 2500 kPa injection pressure at 273 Days. The dashed line indicates the

locations of study lines ............................................................................................ 115


mobility, water saturation profiles along the line of study (50-65 m) at lean zones

location in SAGD process with 2500 kPa injection pressure at 273 days .............. 117


mobility, water saturation profiles along the line of study (50-65 m) at lean zone

location in ES-SAGD process with 2500 kPa injection pressure at 273 days ........ 117


C11) and steam mole fraction in the vapor phase, the solvent mixture mole fraction

in the oil profiles along the line of study (50-65 m) in ES-SAGD process with

2500 KPa injection pressure at 273 days ................................................................ 118


mobility, water saturation profiles along the line of study (50-65 m) at middle

lcocation in SAGD process with 2500 kPa injection pressure at 273 days ............ 120





C11) and steam mole fraction in the vapor, the solvent mixture mole fraction in the

oil profiles along the line of study (50-65 m) in ES-SAGD process with 2500 kPa

injection pressure at 273 days ................................................................................. 121

xiv


mobility, water saturation profiles along the line of study (50-65 m) at bottom

location in SAGD process with 2500 kPa injection pressure at 273 days .............. 123


mobility, water saturation profiles along the line of study (50-65 m) at bottom


Figure 6-11 Schematic representation of the solvent mxiture (IC4-NC5, C6-C8, and C9-

C11) and steam mole fraction in the vapor phase, the solvent mixture mole fraction

in oil profiles along the line of study (50-65 m) in ES-SAGD process with 2500

kPa injection pressure at 273 days .......................................................................... 124

Figure 6-12 Comparison of the temperature profiles in cross section of SAGD and ES-

SAGD with 2500 kPa injection pressure at 180, 365, and 730 days ...................... 126

Figure 6-13 Comparison of the gas saturation profiles in cross section of SAGD and

ES-SAGD with 2500 kPa injection pressure at 180, 365, and 730 days ................ 127

Figure 6-14 Comparison of the temperature profiles vs. distance in SAGD and ES-

SAGD with 2500 kPa injection pressure at 273 days ............................................. 128

Figure 6-15 Comparison of water saturation and water velocity vector in SAGD and

ES-SAGD with 2500 kPa injection pressure at 273 days ....................................... 129

Figure 6-16 Comparison of amplified water saturation and water velocity vector in

SAGD and ES-SAGD with 2500 kPa injection pressure at 273 days .................... 130

Figure 6-17 Comparison of the oil mobility profile in SAGD and oil mobility, solvent

mole fraction profiles in the vapor and oil phase in ES-SAGD with 2500 kPa

injection pressure at 273 days ................................................................................. 131

Figure 6-18 Oil recovery factor vs. thickness of the lean zones in SAGD process ....... 132

Figure 6-19 Oil recovery factor vs. thickness of the lean zones in ES-SAGD process 133

Figure 6-20 Increasing rate of the oil recovery factor with the variable lean zone layers

................................................................................................................................. 133

Figure 6-21 Properties distribution of two-dimension heterogeneous model (A: Grid

top; B: Permeability; C: Porosity; D: Water saturation) ......................................... 136

Figure 6-22 Temperature vs. bitumen viscosity plot ...................................................... 137

Figure 6-23 Well pair trajectories and the water saturation of 2D heterogeneous model

................................................................................................................................. 137

xv

Figure 6-24 Well pair trajectories and the water saturation in cross-section of 2D

heterogeneous model (j-k direction layer 6) ........................................................... 138

Figure 6-25 Comparison of the cumulative oil production at 10 years .......................... 139

Figure 6-26 Comparison of the cumulative steam oil ratio at 10 years .......................... 139

xvi

List of Symbols, Abbreviations, and Nomenclature

Symbol Definition

a Constant

𝑔 Gravitational acceleration constant, 9.8 𝑚/𝑠2

ℎ Thickness of the pay, m

𝑘𝑟𝑔 Relative permeability of gas phase

𝑘𝑟𝑙 Relative permeability of liquid phase

𝑘𝑟𝑜 Relative permeability of oil phase

𝑘𝑟𝑤

𝐾

Relative permeability of water phase, 𝑚𝑑

Absolute permeability, D

𝑚

m

Dimensionless, between 3-5

Meters

𝑃 Pressure, 𝑘𝑃𝑎

𝑡 Time, 𝑠

𝑇 Temperature, ℃

𝑞𝑜 Oil production rate, 𝑚3/𝑑𝑎𝑦

𝑆𝑜𝑟 Residual oil saturation

𝑆𝑜 Oil saturation

𝑆𝑤 Water saturation

𝑆𝑤𝑐 Connate water saturation

∅ Porosity

𝜌𝑜 Density of oil, 𝑘𝑔/𝑚3

xvii

𝜌𝑤 Density of water, 𝑘𝑔/𝑚3

𝑣𝑠 Oil kinematic viscosity, 𝑚2/𝑠

Abbreviation

ARC

Definition

Alberta Research Council

BHP

CMG

Bottom-hole pressure

Computer Modelling Group

CSS Cyclic steam stimulation

cSOR Cumulative steam oil ratio

CumOil

CWE

ES-SAGD

Cumulative oil production

Cold water equivalent

Expanding solvent steam assisted gravity drainage

NCG Non-condensable gas

OOIP Original oil in place

SAGP Steam and gas push

SAGD Steam-assisted gravity drainage

SCV Steam chamber volume

SOR Steam-oil ratio

STL Stock-tank liquid production rate for producer

STW Surface water rate

2D

3D

Two-dimension

Three-dimension

1

: INTRODUCTION

Overview

Canada has heavy oil and bitumen reserves of 1.7 trillion bbls original oil in place

(OOIP), which is the third largest oil reserves country in the world. Most of the heavy oil

and bitumen resources are in the province of Alberta (Figure 1-1). The area of oil sand

deposits in Alberta is 142,200 km2, and the surface mineable area is 4,800 km2. The

extremely high viscosity is the detrimental physical property of bitumen. It ranges from

one million centipoises to six million centipoises at reservoir temperatures of 7-11oC

(Gates 2008). In essence, temperature is an important parameter affecting the viscosity of

heavy oil and bitumen.

Figure 1-1 Oil sand deposits in Alberta (Government of Alberta 2012)

2

Steam Assisted Gravity Drainage (SAGD) is a primary thermal method that has

been extensively applied in the heavy oil and bitumen recovery in Alberta. SAGD (Butler

1981) employs a pair of parallel horizontal wells that are drilled into a reservoir to heat and

produce bitumen. The producer is located approximately 2 meters above the base of the

reservoir and the injector is about 5 to 10 meters above the producer. Steam is injected into

the reservoir through the injection well and builds up a steam chamber. With the steam

continually injected into the reservoir, steam heats up the cold bitumen and condenses at

the edge of the chamber. Heated bitumen and condensed water are drained to the producing

well by gravity along the edge of the chamber (Butler 1991). Expanding Solvent - Steam

Assisted Gravity Drainage (ES-SAGD), which injects hydrocarbon additives at a low

concentration into a reservoir with steam, was proposed by Nasr et al. (2003). It showed

that the hydrocarbon of low concentration injected together with the steam could

substantially increase the oil recovery and upgrade the bitumen in the reservoir.

Additionally, this method can reduce energy consumption and greenhouse gas emission.

Problem Statement

Reservoir heterogeneities (i.e., shale layers or lean zones) have many negative

impacts on oil recovery. It hampers the growth of a steam chamber by adsorbing latent heat

to water zones, for example. The lean zones, which have a water saturation of more than

50%, are extensive facies in the Athabasca oil sand reservoirs. Several projects have

reported the presence of lean zones during development of Athabasca oil sand reservoirs.

Xu (2014) and Wang (2015) have conducted numerical studies to investigate the effects of

3

lean zones on SAGD performance. The studies indicated that the size, location, and

distribution of lean zones have different impacts on oil production.

Objectives of Thesis

In this thesis, ES-SAGD and SAGD will be conducted in different types of

reservoirs to study the impacts of lean zones by using CMG STARS software. The analyses

on mechanisms of how lean zones influence the SAGD and ES-SAGD processes are

investigated by comparing the growth of steam chambers at bottom, middle, and top

locations with no-lean zone reservoirs. In addition, the thickness, location, water saturation

of lean zones and reservoir permeability are also investigated to further understand the

impacts of lean zones on the SAGD and ES-SAGD processes. After comparing these two

processes, the efficient process is recommended in practice. Finally, a 2D heterogeneous

reservoir model, which contains lean zones, is developed to study the production

performance of the SAGD and ES-SAGD processes.

Organization of Thesis

The thesis contains seven chapters are listed below:

Chapter Two: This chapter is a literature review of Cyclical Steam Stimulation

(CSS), Steam flooding, Steam Assisted Gravity Drainage (SAGD), and Expanding Solvent

Steam Assisted Gravity Drainage (ES-SAGD). The reservoir heterogeneity is also

reviewed in this chapter.

4

Chapter Three: A homogenous reservoir model is established by CMG STARS

software.

Chapter Four: The comparison of a non-lean zone case with a lean zone case is

performed through a steam chamber in SAGD. Variations of gas saturation, oil saturation,

oil mobility, water saturation, and temperature are compared and analyzed at the bottom,

middle, and top steam chamber for both cases. In addition, the thickness and water

saturation of lean zones and reservoir permeability are also conducted to investigate the

sensitivity analysis in SAGD.

Chapter Five: This chapter presents the comparison of a non-lean zone case with

a lean zone case through a reservoir in the ES-SAGD process. Solvent component

distribution in the reservoir is investigated to understand the effects on both cases.

Moreover, the thickness, water saturation, locations of lean zones and reservoir

permeability are analyzed to study the sensitivity of the ES-SAGD process in a reservoir

with lean zones.

Chapter Six: This chapter consists of the comparison of a reservoir with lean zones

through a steam chamber between the SAGD and ES-SAGD processes. Moreover, the

thickness of lean zones and reservoir permeability are compared and analyzed between the

cases to study SAGD and ES-SAGD in a reservoir with lean zones. Furthermore, a 2D

heterogeneous model, which contains lean zones, is introduced into the SAGD and ES-

SAGD to study their production performance affected by the lean zones.

Chapter Seven: Conclusions and recommendations are summarized and the future

work for study is recommended.

5

REVIEW OF LITERATURE

Cyclic Steam Stimulation (CSS)

Cyclic Steam Stimulation (CSS) is also known as the “huff and puff” process. This

process is widely used in heavy oil reservoirs to enhance oil recovery in a primary

production stage. The CSS process consists of three stages to extract heavy oil from a

reservoir. Figure 2-1 shows the process of cyclic steam stimulation.

Figure 2-1 Cyclic steam stimulation process (Oilberta Oil & Gas Corp.)

To commence, steam is injected into a reservoir through a predrilled well to heat

the reservoir and reduce the oil viscosity. Second, the well is shut in for days to allow the

latent heat of the steam to spread into the reservoir to decrease the viscosity of oil. This

period is also called the “soaking”. Finally, the injection well is back to production after

6

the “soaking” period. This cycle of injection and production will be repeated for several

times until oil production declines to an uneconomical stage.

This method was initially applied in heavy oil extraction in Eastern Venezuela in

1959 (Barillas 2008). Subsequently, the CSS process has been successfully used in heavy

oil reservoirs worldwide such as in Cold Lake in Canada, Duri Field in Indonesia, and Tia

Juana in Venezuela (Ali 1978). The recovery factors of the CSS method are from 20-40%

in the OOIP. The average cumulative Steam-Oil Ratios (cSOR) are 3-5 (National

Petroleum Council, 2007). This method is widely used in heavy oil development because

of its relatively low cost and quick payout. Nevertheless, CSS has several limitations in

heavy oil recovery. The ultimate oil recovery rate is lower than that of other thermal

processes, such as SAGD and steam flooding, because it is a single well injection and

production. Another reason is that the viscosity of water or steam is less than that of the

heated oil, which leads to fingering or poor sweep efficiency. Third, heat loss is another

problem in CSS. Unexpected heat loss can cause oil to be inadequately heated which leads

to a sooner than expected production rate (Chen 1988). Finally, high injection pressure and

high temperature are also big challenges for wellbore engineering which cause casing

damage or cement failure.

Steam Flooding

Steam flooding is often referred to as a steam drive process. This method is a

combination of two mechanisms. First, steam is injected into a reservoir to heat and

mobilize oil through an injector. Then, condensed water forms a water bank and pushes the

7

mobilized oil to the production well. Finally, the oil and water are extracted through the

production well to the surface. Like water flooding, this method is designed to increase the

sweep area of a reservoir and yet it is a complex method, which contains many mechanisms

such as steam drive, water drive, oil viscosity reduction, light oil drive, and gravity

segregation. It is utilized typically after a CSS process, increasing the oil recovery factor

to 40-55% (Ali, 1978). Figure 2-2 shows the process of steam flooding.

Figure 2-2 Steam flooding process (Petroleum Support Corp.)

The Kern River oil field in the United States is a successful case in steam flooding.

The oil recovery has increased to 80% (ESON et. al. 1981). The main drawbacks of steam

flooding are early steam breakthrough and steam fingering due to gravity segregation. This

method has been gradually replaced by other advanced methods such as Steam Assisted

Gravity Drainage (SAGD) due to the development of horizontal well techniques.

8

Steam Assisted Gravity Drainage (SAGD)

Steam Assisted Gravity Drainage (SAGD) is primarily a thermal method that is

extensively applied in the heavy oil and bitumen recovery in the world. This method was

proposed by Dr. Roger Butler about 35 years ago. Figure 2-3 shows a simplified SAGD

process.

Figure 2-3 Steam assisted gravity drainage (SAGD) process (JPEC)

SAGD (Butler 1981) employs a pair of parallel horizontal wells, which are drilled

into a reservoir to heat and produce bitumen. The producer is located approximately 2

meters above the base of the reservoir and the injector is about 5 to 10 meters above the

producer. Steam is injected into the reservoir through the injection well creating a steam

chamber. With the steam continually injected into the reservoir, steam heats the cold

bitumen and condenses at the edge of the chamber. Heated bitumen and condensed water

drain to the producing well by gravity along the edge of the chamber (Butler 1991). This

9

method has been successfully tested in several stages in the Athabasca oil sand deposits

and is widely used in heavy oil and bitumen recovery in Alberta (ERCB 2010). In this

thesis, both SAGD and ES-SAGD are two main methods to investigate the impacts of lean

zones in these processes. Therefore, the processes will be discussed in detail.

Basic Analytical Model of SAGD

In 1979, Dr. Butler proposed a concept with theoretical analysis and some

experimental laboratory data for gravity drainage in heavy oil reservoirs. He and his

colleagues derived an analytical model to predict the heavy oil and bitumen production

rate.

The assumptions of this equation are as follows:

(1) The reservoir is homogeneous;

(2) The steam chamber is symmetric;

(3) The steam pressure is constant in the steam chamber;

(4) Steam is the single phase which flows in the steam chamber;

(5) The heat transfer at the edge of the steam chamber to the oil is only drived by heat

conduction.

The mathematical model is as follows:

𝑞𝑜 = √2∅∆𝑆𝑜𝑘𝑔𝛼ℎ

𝑚𝑣𝑠 (2-1)

where 𝑞𝑜 is the oil rate, 𝑚3/𝑠; ∅ is the reservoir porosity; ∆𝑆𝑜 is the oil saturation variation

between initial oil saturation and residual oil saturation; 𝑘 is the effective permeability for

10

the oil flow, 𝑚𝑑 ; 𝑔 is the gravitational acceleration, 𝑚/𝑠2 ; 𝛼 is the reservoir thermal

diffusivity, 𝑚2/𝑠; ℎ is the height of a reservoir, m; 𝑚 is a constant, between 3-5 and

dependent on an oil viscosity-temperature correlation; 𝑣𝑠 is the oil kinematic viscosity at

steam temperature, 𝑚2/𝑠.

Butler and Stephens later modified the calculated interface curves to keep the

drainage towards the production well. At the lower part of the steam chamber, the curve

becomes more vertical to the production well. The model is called the TANDAIN model

(Equation 2-2)

𝑞𝑜 = √1.5∅∆𝑆𝑜𝑘𝑔𝛼ℎ

𝑚𝑣𝑠 (2-2)

They reduced the constant to 1.5; the oil drainage rate was 87% of the original

equation. Butler also assumed that the steam chamber interface was a straight line to the

top of a reservoir to modify the equation, which reduces the constant from 2 to1.3. The

model is called linear drainage (LINDRAIN) which was a derivation of the TANDRAIN

model. These two modifications minimized the error from the previous equation and

improved the predictions of oil rate.

Reis (1992) proposed a new prediction model (Equation 2-3) for the SAGD process.

He developed the original model by assuming that the steam chamber was an inverted

triangle. The vertex of the steam chamber was at the production well.

𝑞𝑜 = √∅∆𝑆𝑜𝑘𝑔𝛼ℎ

2𝑎𝑚𝑣𝑠 (2-3)

Where 𝑎 is a constant.

11

Sharma et al. (2010) derived a new model that took the relative permeability and

oil saturation into the consideration. They noticed that the flow behavior was more complex

at the edge of a steam chamber; the maximum oil mobility was not at the edge of the steam

chamber. They also simplified Crashaw and Jaeger’s equation by assuming a quasi-steady-

state condition in 2011. Then, they assumed there was a relationship between the growing

rates of the steam chamber with the condensate velocity to derive an analytical model for

the conductive and convective heat fluxes. Mazda (2012) modified the mass conservation

equation to obtain a new expression of conductive and convective heat fluxes according to

the quasi-steady-state results.

The Effects of Temperature on Bitumen Viscosity

The viscosity of bitumen is a key physical property which is an essential element

in reservoir engineering calculations. The relationship between temperature and bitumen

viscosity plays an important role in the thermal recovery processes. Andrade (1930) first

proposed an equation for the liquid viscosity based on temperature, and then he made

various modifications to the original equation. Walther (1933) derived a double logarithmic

function of viscosity. Based on Walther’s equation, Wright (1965) simplified the equation

to predict the relationship between oil viscosity and temperature. Khan (1984) proposed a

viscosity model for gas-free Athabasca bitumen. He summarized the theories of liquid

viscosity, and tested present empirical correlations for bitumen viscosity such as the

Andrade Equation, Gross–Zimmermann Equation, Double exponential function of

viscosity, and double logarithmic function of viscosity and a tangent function. He pointed

12

out that the Andrade and Gross-Zimmermann equations were not suitable with Athabasca

bitumen viscosity data. Since the tangent function is a complicated form that contains four

direct and two indirect empirical parameters, they agreed that the double exponential and

logarithmic functions provided good correlations with the bitumen viscosity data. They

also modified the Eyring and Hildebrand model to predict and correlate the viscosity of

Athabasca bitumen with temperatures from 20 to 130 oC. Mehrotra and Svrcek (1986)

reported a relationship of the viscosity of Athabasca bitumen versus temperature (Figure

2-4). The viscosity of bitumen is more than one million centipoises at reservoir conditions

(temperature: 7-15 oC) which means that the bitumen is immobile at that temperature. This

relationship is widely used in thermal recovery processes and reservoir engineering

calculations in Alberta.

Figure 2-4 Viscosity of Athabasca bitumen vs. temperature

(Mehrotra & Svrcek 1986)

13

The Concept of Steam Chamber Development

The steam chamber development is a fundamental point for the SAGD process.

Butler first made a basic description for steam chamber development (Figure 2-5) in 1981.

He stated that if the steam was continuously injected into the bottom of a reservoir, the

team tended to rise upward to the top of the reservoir and the condensed water and

mobilized oil fell to the bottom along the edge of the steam chamber by gravity. A

production well was placed below the injection well to extract the oil and water to the

ground. The void where the oil drained into the production well was occupied by steam

which was continuously injected into the reservoir. A steam chamber forms gradually over

an injection well. The pressure of the steam chamber is maintained by continuously

injected steam. The steam condensed at the interface of steam and the cold oil. The latent

heat of steam is conducted into the bitumen to become mobilized oil. It is important to note

that the “driving force” is gravity rather than steam.

Figure 2-5 Basic concept of steam chamber (Butler 1981)

14

Much research has been focused on a steam chamber because it has been shown

that the oil production mainly relied on the growth of a steam chamber in SAGD. It has

been proven that a steam chamber is not only affected by conduction. Other events occur

during the growth of the steam chamber such as counter-current flow, co-current flow,

emulsification, and steam fingering concurrently (Albahlani and Babadagli 2008). They

also pointed out that convection also occurs in the middle of the steam chamber due to

geomechanical effects. Ito and Ipek (2005) observed that the steam chamber rose vertically

and laterally at the same time. Edmunds et al. (1998) documented that the steam chamber

is not connected to the production well, and a pool of water and oil exists above the

production well and prevents the injected steam breaking through into the production well.

He also claimed that the steam pressure is not constant in the steam chamber.

Review of Operation Parameters in SAGD Process

2.3.4.1 Start-up in SAGD Process

The start-up process is also known as the initialization of a well pair (injector-

producer). It is a critical process, which has profound impacts on the subsequent production

performance of a SAGD process. Start-up was defined as a period when the steam is

circulating in the injector and producer before the well pair is converted to the SAGD

process (Vincent et al. 2004). The objective of the start-up in the SAGD process is to

establish a communication between the injector and producer (Anderson 2012). It is

normally achieved by the steam circulation, when the steam is injected into both wells

15

down to the toe through a tubing string, and the fluids are back to the surface through the

annulus. The entire length of horizontal wellbore and the near wellbore area are heated by

the circulated steam. The mobilized oil is drained to the wellbore and circulated to the

surface. Figure 2-7 displays the schematic of a start-up process.

Figure 2-6 Schematic of start-up procedure in SAGD process

(Rangewest Tech.)

The circulation strategies and operation procedures of a start-up are important as

they affect the heat transfer and fluid convection within a reservoir and establish a

communication of a well pair. There are three procedures for the start-up process (Vincent

et al. 2004): circulate the steam through the entire length of the wellbore at a predetermined

steam rate; build up a heat convection zone between the injector and producer; convert the

well pair to the SAGD process when the communication was established.

16

2.3.4.2 Steam Trap Control in SAGD Process

In the SAGD process, the key concern is that the latent heat of steam is effectively

conducted into bitumen. In practice, the latent heat loses into the overburden, underburden,

and thief zones such as water and gas zones. However, live steam could breakthrough into

the production well if there does not exist resistance and a barrier (Gates and Christopher

2010). The reason for this phenomenon is that the vertical distance of the well pair is

normally only 5 meters. Another reason is that the injection well and production well are

well communicated after a start-up process. Butler (1997) and Edmunds (1998) proposed

that the production well is surrounded and submerged under a liquid pool that has existed

in the region between the well pair. Gates (2010) defined that the steam trap control is the

maintenance of the liquid pool. The liquid pool consists of condensed water and mobilized

bitumen that fall from the edge of the steam chamber. Figure 2-7 shows an ideal cross-

section of a steam chamber in the SAGD process. The liquid pool exists at the bottom of

the steam chamber and between the injection well and production well.

Figure 2-7 Schematic of an ideal steam chamber in SAGD Process (Gates 2010).

17

In field practice, the measurement of a liquid pool cannot be achieved from the

surface. Nevertheless, the liquid pool can be monitored by measuring the temperature

difference between the injected steam and produced fluid. Ito and Suzuki (1996) defined

this temperature difference as subcool. It is also called interwell subcool in the SAGD

process. They reported that the subcool temperature is 30-40 oC. Edmunds (1998)

investigated a specific case in two-dimensional and three-dimensional numerical

simulations in Athabasca reservoirs. He examined the relationship between the interwell

subcool and liquid level, a production rate, pressure, and a cumulative steam-oil ratio.

Edmunds documented the optimum subcool temperature is from 20-30oC in his case. He

also pointed out that the steam trap subcool exhibits complex behavior along the whole

length of wellbores due to the variations in reservoir and fluids properties. Singhal et al.

(1998) advised that if the size of a steam chamber is expanded infinitely, the steam trap

control on production could be ignored at the early period of steam injection to obtain the

optimal production rate.

2.3.4.3 Operation Pressure in SAGD (Low Pressure vs. High Pressure)

According to an analytical model of SAGD, pressure does not show up in the

drainage rate equation, and Butler (1981) emphasized that the main drainage force is

gravity. However, the steam injection pressure does have effects on the SAGD

performance, which has been proven by many experimental analyses and simulation results

(Sasaki et al 1999, Edmunds and Chhina 2001, Robinson 2005, Gates 2005, Das 2005).

18

Sasaki et al. (1999) constructed a two-dimensional laboratory model for the effects

of steam injection pressure. They indicated that high injection pressure results in an early

time breakthrough and a faster growth rate of a steam chamber. Gates et al. (2005) pointed

out that higher injection pressure leads to higher saturation pressure and lower bitumen

viscosities in numerical simulation studies. They also stated that the vertical steam chamber

growth has a correlation with steam injection pressure. Higher injection pressure has a

positive effect on the growth speed of a steam chamber (Gates 2010). Robinson et al.

(2005) reported that the higher steam injection pressure could result in a higher production

rate. Li et al. (2006) conducted a simulation study for reservoir geomechanics in low

injection pressure and high injection pressure in SAGD. They reported that higher pressure

led to higher permeability and porosity, and, therefore, a higher production rate.

On the other hand, some researchers stated that low steam injection pressure has

positive effects on SAGD performance. Das (2005) summarized the positive effects on low

steam injection pressure in a simulation study which compared the low steam injection

pressure to high injection pressure and concluded that low steam injection pressure leads

to lower operating temperature which results in energy efficiency and favorable artificial

lifts. Edmunds and Chhina (1999) showed an analytical correlation between low steam

injection pressure and low cSOR. They stated that the net price value (NPV) of SAGD is

more sensitive to cSOR and low steam injection pressure decreases energy consumption.

19

Improvement of SAGD Process

The SAGD process has been commercially applied in heavy oil and bitumen

recovery for several decades. Nevertheless, there are some predominating conditions to

overcome to achieve a successful SAGD performance. Singhal et al. (1998) stated some

critical conditions to obtain a good SAGD performance according to a screening study.

They pointed out that high production rates, high recovery factors, approved larger

reserves, and optimal operation parameters are key elements for achieving a high

performance of the SAGD process. Moreover, McCormack (2001) proposed different

screening criteria for an economical SAGD performance. He advised that the minimum

reservoir requirements for achieving a SAGD process are a continuous high quality pay (>

10wt% oil with pay thickness more than 12 meters); the permeability of the reservoir

greater than 3.0 Darcy; top gas/water and bottom water free; a competent cap rock;

reservoir operating pressure greater than 1000 kPa; minimal adverse fluid/rock

interactions. He also pointed out that for a thicker formation, the requirements of

permeability and the restrictions on top gas/water and bottom water can be somewhat

relaxed.

Expanding Solvent - Steam Assisted Gravity Drainage (ES-SAGD)

ES-SAGD process was initially proposed by Nasr et al. in 1999 (Nasr and Isaacs

2001). The key idea is that a light hydrocarbon or a combination of light hydrocarbons

(normally C4-C7) at low concentration are injected with steam to take advantage of the

benefits from latent heat offered by steam and miscibility provided by the light

20

hydrocarbons, hence a further reduction in the viscosity of bitumen. This process has been

piloted in many heavy oil and bitumen reservoirs resulting in improvement of oil recovery

and energy efficiency (Gates and Chakrabarty 2008, Barillas 2008, Ji 2014).

Basic Theory of Expanding Solvent - SAGD (ES-SAGD)

The basic theory of adding solvent to extract heavy oil was invented by Allen

(1973), Brown et al. (1977) and Nenniger (1979) in the 1970s. They came up with a

gaseous solvent which could dissolve into bitumen and further reduce the oil viscosity, and

hence the mobilized bitumen can flow towards a production well. Butler and Mokrys

(1991) pioneered the implementation of vaporized solvent to extract heavy oil by using a

large scaled physical model. The process was known as VAPEX (vapour extraction), which

utilized vaporized propane as solvent with hot water to extract heavy oil. Nasr et al. (2003)

conducted a series of experiments that introduced light hydrocarbon additives into the

SAGD process at the Alberta Research Council. They reported that the process could

improve oil rates, and reduce energy consumption and water requirements. The novel

method is called Expanding Solvent SAGD and the abbreviation is “ES-SAGD”. Figure 2-

8 displays a steam chamber of a single well pair in the ES-SAGD process. As we can see

from this figure, the vaporized solvent is injected together with steam into a steam chamber

through an injector. The solvent condenses with steam at the interface of gas and liquid.

The latent heat of steam conducted into cold heavy oil to heat the oil, and, meanwhile, the

condensed solvent dissolved into the bitumen to reduce the oil viscosity further. The

mobilized oil, condensed water, and condensed solvent flow down to the producer along

21

the edge of the steam chamber. Nasr and Ayodele (2005) pointed out that the selected

solvent should evaporate and condense with the steam at the same conditions. The “driving

force” of this process is still dominated by gravity.

Figure 2-8 Basic concept of Expanding Solvent – SAGD (ES-SAGD)

(Fatemi 2010)

Solvent Selection of ES-SAGD Process

A solvent selection is a crucial procedure for the ES-SAGD process to function

properly. Nasr and Isaac (2001) pointed out that the hydrocarbon additives should stay at

the vapor phase in a steam chamber before condensing at the edge of the steam chamber.

This requires the hydrocarbon additives to exhibit a similar vapor-liquid phase behavior to

that of steam at the operating conditions. In their patent invention, they stated that the

sleeted hydrocarbon additives should have the evaporation temperature within a maximum

22

range of about ± 50 oC of the steam temperature at the operating pressure. However, this

temperature difference between the steam temperature and evaporation temperature of

hydrocarbon additives is much lower at the operating pressure in the SAGD process. They

also experimented with a wide range of hydrocarbon additives or solvents, which are

suitable for the ES-SAGD process. These hydrocarbon additives include C1-C25

hydrocarbons and combinations thereof.

Nasr et al. (2003) carried out a series of experiments for solvent screening in terms

of comparing evaporation temperature of hydrocarbon additives (C3 to C8 and diluent) to

that of steam temperature. Figure 2-9 displays the comparison of hydrocarbons (C3 to C8)

vaporization temperature with the steam temperature. As seen in this figure, the

vaporization temperature increased as the carbon number of hydrocarbon increased. It is

shown that hexane has the closest vaporization temperature to the steam temperature (215

oC at a corresponding operating pressure of 2100 kPa). However, as compared to the

hexane, octane has a vaporization temperature, which exceeds the injected steam

temperature at the same operating pressure.

23

Figure 2-9 Comparison of hydrocarbons (C3 to C8) vaporization temperature with

steam temperature (Nasr et al. 2003)

Nasr et al. (2003) conducted eight experiments in their study to investigate the

relationship between steam and solvent co-injection strategies and oil drainage rates.

Figure 2-10 illustrates the comparison of the oil drainage rates (averaged over 55 hours)

with different solvent-steam co-injection strategies. The pure-steam injection experiment

was the base case for comparing with the steam-solvent injection experiments. From left

to right, it shows that the co-injection of non-condensable components with steam such as

methane and ethane does not enhance the oil drainage rates as compared to the pure steam

injection case. On the other hand, co-injecting the condensable hydrocarbon additives (C3-

C8) or diluent (mainly C4-C10) with steam has positive effects on oil drainage rates. Hexane

and diluent obtained the highest oil drainage rates in the comparison.

24

Figure 2-10 Comparison of oil drainage rates and different hydrocarbon co-

injecting strategies (Nasr et al. 2003)

Nasr and his colleagues also plotted a figure (Figure 2-11) to prove their study

results. They compared the oil drainage rates with the difference between the injected

steam temperature and the solvent vaporization temperature. The minimum temperature

difference between the steam and solvent could obtain the highest oil drainage rates. It also

indicated that a solvent with a vaporization temperature within ± 50° C could be considered

adequate solvents for present experimental conditions. Nasr et al. (2003) also pointed out

that the type of solvent selection should be determined by the reservoir conditions.

25

Figure 2-11 Oil drainage rates vs. temperature difference between steam and solvent

(Nasr et al. 2003)

Nevertheless, other studies revealed that the solvent selection has converse results.

Govind et al. (2008) conducted a numerical simulation to analyze the ES-SGAD process.

They selected butane, hexane, pentane, heptane, and a mixture of C6-C8 to co-inject with

steam. They concluded that the solvent type is negligible. A comparative numerical

simulation study was done by Ardali et al. (2010); they indicated that the solvents which

were heavier than butane have the potential capabilities to enhance the oil recovery and

thermal efficiency. They also pointed out that the solvent type selection has a relationship

with bitumen properties. Butane is the best option for cold lake reservoirs and solvent

heavier than butane can improve oil recovery for Athabasca reservoirs.

26

Effects of Solvent Concentration on ES-SAGD Process

Solvent concentration is a major parameter which has a great effect on oil

production performance in the ES-SAGD process. The effects of solvent concentration

have been studied and published in reports and the literature. Govind et al. (2008)

conducted a numerical simulation model to investigate the effect of solvent concentration

during the process. They stated that an oil production rate increases as the solvent

concentration increases. Moreover, a lower cSOR and lower temperature in a steam

chamber occur during the high concentration of solvent co-injecting with steam. Shu (1984)

proposed a correlation for heavy oil and solvent systems. Based on this correlation, a

relationship between a solvent volume fraction and viscosity of Athabasca bitumen was

plotted by Li et al. (2010). Figure 2-12 illustrates the relationship between the viscosity of

Athabasca bitumen and a volume fraction of solvent (C6) at different constant temperature.

The viscosity is decreased further with a solvent volume fraction increased when mixing

the heated bitumen at a constant temperature. The purple line, the steam temperature at 200

oC, indicates that the viscosity is decreased to 4 centipoises with a solvent volume fraction

of 0.1, while the solvent volume fraction increased to 0.3 when the viscosity of bitumen is

only 1 centipoise.

Nevertheless, the high concentration of solvent co-injected with steam has its

economical limitations because of the high price of solvent. Govind (2008) pointed out that

the optimum solvent concentration selected will be a function of solvent costs, and solvent

retention and loses in a reservoir. Akinboyewa et al. (2010) conducted a numerical

simulation of filed case studies for a bitumen reservoir. They stated that a volume of 5-10%

27

of steam’s cold water equivalent (CWE) is adequate to enhance oil recovery and reduce

the operation cost; higher concentration will result in an uneconomical project. A numerical

evaluation of hydrocarbon additives to steam in the SAGD process was done by Mohebati

(2010). They stated that if a mole fraction of hydrocarbon additive (C6) is increasing more

than 0.01, the oil recovery factor increased slightly.

Figure 2-12 Solvent (C6) volume fraction vs. viscosity of Athabasca bitumen at

constant temperature (Li 2010)

The Impacts of Operating Pressure

Operating pressure plays an important role during the ES-SAGD process. A change

of operating pressure can affect the process performance dramatically. Mohebati et al.

(2010) conducted a simulation study to investigate the operating pressure effects on solvent

added SAGD performance. The simulation results revealed that hexane could improve the

28

SAGD performance substantially at low steam injection pressure (1500 kPa) compared to

high steam injection pressure (1900 kPa). They pointed out that the reason for the

significant difference is due to more hexane retained in a reservoir under high injection

pressure. Ivoy et al. (2008) stated that a lower minimum producer bottom hole pressure

BHP (2200 versus 1500 kPa) enhanced the oil production rate up to 15% and reduce the

steam-oil ratio (SOR) for ES-SAGD. However, other investigations show that higher

operating pressure is more favorable for ES-SAGD. Govind (2008) stated that using butane

at higher operating pressure (4000 kPa) is optimal due to the higher vapor pressure of

butane in the simulation study.

Phase Behavior of Steam Chamber in ES-SAGD Process

The vapor-liquid phase behavior of a steam-solvent (light hydrocarbon)-bitumen

system is not uniform in a steam chamber because they have different physical properties

such as partial vapor pressure and boiling point (Li et al. 2010). They conducted an

experiment and a simulation model to investigate the phase behavior of vapor solvent,

liquid solvent, and water near the edge of the steam chamber. Based on their experiment

and simulation, they concluded that the vapor pressure dominates the properties and effects

of injected solvent and steam in the steam chamber, and partial pressure effects played an

important role for a successful ES-SAGD process. Moreover, they pointed out that

vaporized light solvent (C3) can be transported to the entire vapor-liquid interface to

dissolve in the bitumen, but may build a thick gas blanket to hinder the heat transfer. They

suggested that selecting a suitable multicomponent solvent mixture, which includes solvent

29

in the vapor and liquid phases such as heptane and xylene, might improve the ES-SAGD

performance by changing the condensation dynamics of the solvent.

Dong (2012) conducted an experiment to analyze the phase behavior of the solvent-

steam system in a steam chamber. He stated that the partial pressure of the steam, which is

a major factor, dominates the temperature of a vapor mixture. According to the analysis,

the condensation occurs over a range of temperatures and a solvent concentration gradient

exists between the vapor and liquid phases. A modified equilibrium state calculation was

proposed to plot a correlation of equilibrium temperature and solvent fraction. Figure 2-13

displays the correlation between condensation temperature of a water and hexane mixture

versus a mole fraction of hexane. As observed, steam was the first condensate in the water-

hexane system, and the condensate occurs at 484 K. However, the mole fraction of the

steam decreased as water condensed out of the vapor phase. Meanwhile, the reduced mole

fraction and partial pressure induce a decrease in temperature. This means that reducing

temperatures led to the steam condensing constantly. At the same time, in the water-hexane

system, the mole fraction and partial pressure of hexane raises gradually and hence

increases the saturation temperature of hexane. Only steam is condensing in the vapor

phase until the steam and hexane reach such a ratio that both condense simultaneously. The

graph shows that the co-condensation occurs at 446K with a C6 mole fraction of 0.58.

Figure 2-14 illustrates the concentration of hexane in a liquid volume fraction at 25 oC. The

two curves at the top show the temperature corresponding to a liquid concentration of

hexane. The blue curve indicates that the volume fraction of the first component (steam)

begins condensing while the red curve indicates that the volume fractions of hexane

30

condenses first. The blue line indicates that the temperature of both steam and hexane has

condensed to the liquid phase completely. Dong (2012) also pointed out that the phase

behavior of the solvent-steam system in a steam chamber is sensitive to the number of

hydrocarbons. As the number of hydrocarbon increases, the solvent concentration for

solvent condensation decreases. The pressure in the steam chamber has little effect on the

phase behavior. The temperature difference between the SAGD and the ES-SAGD

processes are shown in Figure 2-15. The temperature difference is 40 oC lower than SAGD

compared with ES-SAGD.


mixture versus mole fraction of hexane at 2000 kPa (Dong 2012)

31


mixture versus volume fraction of hexane at 2000 kPa (calculated at 25 oC) (Dong

2012)

Figure 2-15 Temperature profiles in distance at the edge of steam chamber between

SAGD and ES-SAGD (More Fraction of Hexane at 0.01, 2000 kPa) (Dong 2012)

32

The Impacts of Reservoir Heterogeneities

As aforementioned, the growth of a steam chamber is the most important for the

SAGD process. The description of the steam chamber is always assumed to be in a

homogenous, isotropic reservoir. In practice, no reservoir is homogenous and isotropic

because of natural geological features such as shale layers, water zones, and gas caps. Many

oil companies have reported the existence of shale layers and water zones in their projects

such as Long Lake (Nexen), Firebag (Suncor), and Surmont (ConocoPhillips) (Xu 2015,

Bao 2012). Therefore, an accurate prediction of SAGD performance for field-type systems

could not be achieved without a comprehensive understanding of reservoir heterogeneities

(Chen et al. 2008). Several researchers have been investigating the effects of reservoir

heterogeneities on steam chamber development in the SAGD process for several decades.

Laboratory-scale experiments and reservoir simulations are the main approaches for

investigating reservoir heterogeneities.

Yang and Butler (1992) conducted a series of experiments to investigate the effects

of heterogeneities for the SAGD process. They used a two-dimensional sand-packed model

to mimic two reservoir types: reservoirs with thin shale layers and reservoirs with

horizontal layers of different permeability. There were two scenarios in a reservoir with

two layers, one was a high/low permeability reservoir, and another was a low/high

permeability reservoir. They stated that the SAGD performance of a high/low permeability

reservoir was similar with that of a high permeability reservoir. For a low/high permeability

reservoir, they found an undermining of steam in the low layer (high permeability), and the

effect was reduced with time. Furthermore, they carried out a comparison of cumulative

33

oil production from the previous setup with all low permeability setup and found little

difference. They noticed that underlying steam improved the gravity drainage rate over the

interlayer surface. Adversely, the viscosity of a production fluid increased due to a higher

oil/water emulsion appearing over the underlying steam. For the experiments of a reservoir

with shale layers, they concluded that short horizontal barriers had no effect on production

performance. On the other hand, long horizontal barriers reduce the production rate

dramatically. In addition, they investigated the reservoir dipping effect for a low/high

permeability setup. They noticed that a high production performance was obtained from

the reservoir dipping upward compared to the reservoir dipping downward. They reasoned

that the production rates are dominated by the total drainage height. Thus, they pointed out

that a maximum production rate would be obtained by placing the production well at the

lowest location of a dip reservoir. Yang and Butler (1992) also pointed out that the presence

of long shale layers in a reservoir could cause various advancement velocity at the upper

and lower interface of the shale layers. This phenomenon is decreased by the steam and

heated bitumen conducted over the shale layers. Nasr et al. (2003) conducted an experiment

model by using an element approach to study the impacts of gas cap and top water on

SAGD performance at Alberta Research Council (ARC). They stated that the steam moved

into both gas cap and top water zones and more steam penetrated water zone than that of

gas cap. For the top water case, more initial oil in place has been produced compared to

the gas cap case. However, the experimental analyses have limitations such as time

consuming, accuracy, and design. These difficulties have been partially overcome by using

a numerical simulation method (Chen 2008, Wang 2015).

34

Numerous numerical simulation studies have investigated the impacts of reservoir

heterogeneities on the SAGD process (Law 2003, Chen 2008, and Xu 2014). Pooladi-

Darvish and Mattar (2002) conducted a simulation mode which contains a gas cap and top

water to examine the effects of shale layers’ continuity in a vertical direction on the SAGD

process. They observed only a minor effect on production performance. Law et al. (2003)

studied a simulation model with the existence of confined and unconfined top water. They

investigated the impacts of initial pressure and injection pressure on the SAGD process.

The results indicated that as the pressure difference in a steam chamber increased, a top

water zone decreased in production performance. Chen et al. (2008) carried out a numerical

simulation to investigate stochastic distribution of shale barriers near a well region and

above a well region. They concluded that short shale barriers, which are located near the

well region, impaired the vertical permeability and hampered the vertical growth of the

steam chamber. For the above well region case, the shale barriers affect both the vertical

and horizontal growth of the steam chamber. A numerical study was done by Xu et al.

(2014, 2017) to investigate impacts of lean zones on SAGD performance. They located the

lean zones above the injector, between the injector and producer, and below the producer.

They stated that the location of lean zones has a most important effect on SAGD

performance. The lean zones located above the injector severely influenced the

performance, and the lean zones located below the producer yielded a little impact. They

also conducted a sensitivity analysis of lean zones, which is related to vertical distribution,

horizontal spacing, and sizes. They indicated that increasing the sizes and reducing the

interval distance of the lean zones could influence the SAGD performance significantly.

35

Wang et al. (2015) conducted a comprehensive analysis for lean zones and shale

distribution. The results showed that significant heat lost in the lean zones caused a higher

cumulative steam-oil ratio. They pointed out that the lean zone beneath the producer will

not affect the SAGD performance. This conclusion is consistent with the results of Xu

(2014). A three-dimensional geological model which contains top water and gas cap zones

(thief zones) for a Surmont pilot was constructed by Bao et al. (2011). They utilized a

geological model to investigate the effects of top water and gas cap zones on both SAGD

and ES-SAGD. The results indicated that the production performance of the SAGD process

is more sensitive to injection pressure. The high injection pressure led to early steam

breakthrough into the water zone causing top water flows into steam chamber. For the ES-

SAGD process, they selected a hydrocarbon mixture (which ranges from C4-C11) to inject

with steam. They found that the steam chamber grows more transversely compared to the

SAGD case.

36

RESERVOIR MODEL

Reservoir simulation is a major method to eveluate the SAGD and ES-SAGD

processes. In this study, we generate a homogenous simulation model with the presence of

lean zones to investigate the production peroformance of the SAGD and ES-SAGD

processes. The CMG STARS (2015 version) simulator is used to build the homogenous

model and study the mechanisms of these processes. The parameters of the reservoir model

come from published papers for the McMurray Formation in northeast Alberta .

Basic Model Construction and Description

The resevoir is a three-dimensional, rectangular, homogenous model with a single

well pair. The lean zone layers are mobile water zones and placed into the reservoir model

before the SAGD and ES-SAGD proceses. The lean zones are placed above the injection

well. The number of lean zone layers range from 1 to 20 with an even number order. The

thickness of each lean zone layer is 0.5m. The simulations will be run for 15 years to

investigate the impacts of lean zones on the SAGD and ES-SAGD processes.

Grid System

A homogenous simulation model is established by CMG STARS software. The

dimensions of the reservoir model are 100x50x40m. It is divided into 8,000 blocks with

100x1x80 blocks in the i, j, and k directions. The dimensions of each block are 1x50x0.5m

in the i, j, and k directions. Figure 3-1 illustrates generation of a right half two-dimensional

37

simulation model in the i-k directions. Figure 3-2 displays a three-dimensional right half

reservoir model.

Figure 3-1 Grid structure of a right half reservoir model in i-k directions

I

njector

Producer

Producer

Injector

Injector

38

Figure 3-2 A right half reservoir model in 3D view

The producer and injector are placed at the bottom left corner with 50m length in

the j direction. The injector is 5 meters above and parallel to the producer. The producer is

located 5 meters above the reservoir base. The perforation of the injector is located at the

block of (1, 1, 59), and the producer is located at the block of (1, 1, 69). The SAGD and

ES-SAGD processes have the same input parameters except for solvent injected with steam

in the ES-SAGD process.

Injector

Producer

39

Reservoir Properties

The input parameters for this reservoir model are listed in Table 3-1. These

parameters are from the McMurray Formation in northeast Alberta. Figures 3-3 and 3-4

display oil-water relative permeability and gas-liquid relative permeability, respectively.

Table 3-1 Reservoir parameters for simulation model

Parameters Valus

Reference Depth, 𝑚 230

Reference Pressure, 𝑘𝑃𝑎 1050

Reference Temperature, ℃ 7

Porosity 0.307

Permeability (horizontal), 𝑚𝐷 6292

Permeability (vertical), 𝑚𝐷 4892

Connate Water Saturation 0.25

Initial Oil Saturation 0.75

Formation Heat Capacity 𝐽/𝑚3℃ 2.3E+06

Reservoir Rock Thermal Conductivity 𝐽/𝑚 𝐷𝑎𝑦 ℃ 2.7E+5

Water Phase Thermal Conductivity 𝐽/𝑚 𝐷𝑎𝑦 ℃ 5.4E+4

Oil Phase Thermal Conductivity 𝐽/𝑚𝐷𝑎𝑦 ℃ 1.2E+4

Formation Compressbility Conductivity 1/𝑘𝑃𝑎 1.0E-6

Overburden/underburden Volumetric Heat Capcity 𝐽/𝑚 ℃ 𝐷𝑎𝑦 2.3E+6

Overburden/underberden Thermal Conductivity 𝐽/𝑚3 ℃ 1.5E+5

40

𝒌𝒓𝒘 𝒌𝒓𝒐

Figure 3-3 Water–oil relative permeabilility,

𝒌𝒓𝒘 is the water-phase permeability, and 𝒌𝒓𝒐 is the oil-phase permeability

𝒌𝒓𝒈 𝒌𝒓𝒍

Figure 3-4 Gas-liquid relative permeability,

𝒌𝒓𝒈 is the gas-phase permeability, and 𝒌𝒓𝒍 is the liquid-phase permeability

41

Fluid Properties

The critical bitumen properties are characterized by CMG WinProp. The

composition of bitumen contains 0.082 mole fraction of methane and 0.918 mole fraction

of heavy components. The correlation of bitumen vicosity and temperature is shown in

Figure 3-5. As observed, the viscosity of bitumen is more than 1 million centipoises at

reservoir temperature of 7 oC. However, when the temperature is up to 200 oC, which is

the temperature at the edge of a steam chamber, the viscosity reduces to about 10

centipoises.

Figure 3-5 The correlation of temperature versus bitumen viscosity

42

Operation Parameters for Cases

The steam is injected at the temperature of 223 oC. The quality of the steam is 0.9.

The constraints of the injector are a maximum surface water rate (STW) with 30 m3 /day

in cold water equivalents (CWE) and the maximum bottom hole pressure (BHP) with 2500

kPa; the producer is constrained to a maximum liquid rate at 30 m3 /day. For the

initialization of the SAGD process, the injection and production wells need to be preheated

before bitumen is produced. The period of preheating is 90 days.

The Location of Lean Zones in the Reservoir Model

Earlier numerical moddelling by Xu et al. (2014) indicates that the location of lean

zones in a reservoir has different effects on the SAGD performance. The lean zones, which

are located above the well pair, have significant effects on the SAGD performance. The

modelling results also indicate that the sizes of the lean zones also affect the performance

severely on SAGD. Therefore, in this study, the lean zones are placed above the injection

well to analyze how the lean zones affect both SAGD and ES-SAGD performance.

43

DISCUSSION OF SAGD PROCESS WITH LEAN ZONES

Introduction

The investigation of the SAGD process with no-lean zone (base case) and lean

zones models will be compared in different aspects. Moreover, the sensitivity analysis of

lean zones will be illustrated in this chapter. In addition, this study is a reference case to

compare the SAGD process with the ES-SAGD process.

The Comparison of Base Case and Lean Zones (2 meters) Case

In this chapter, the lean zone layers with 2 meters’ thickness are created in the base

model. Figure 4-1 displays the location of the lean zone layers in an i-k 2D cross-section.

The connate water saturation of this model is 0.25. The water saturation of the lean zones

is 0.7, and they are 14 meters above the injector.

Figure 4-1Water saturation profile in cross-section of SAGD

Sw

44

Analysis and Comparison of the Steam Chamber

The mechanisms and analyses of a steam chamber have been investigated by many

researchers. Experimental and simulation methods are the two main methods to describe a

steam chamber in the SAGD process (Bulter1988, Sasaki 1999, Ardali 2010, and Ji 2014).

In this study, a numerical simulation method is used to study the effects of lean zone in the

SAGD process. For a better understanding of the mechanisms of the steam chamber, we

divided the reservoir into four zones in the i-k 2D cross-section according to the variations

of properties distribution of the reservoir. The analytical properties are temperature, gas

saturation, oil saturation, oil mobility, and water saturation. Figure 4-2 shows the

temperature distribution profiles with the four zones for the two cases, respectively. The

dashed line of the base case is curve of the analytical properties from the inner steam

chamber to the cold oil sand (left to right sides) in the i-k direction. Figure 4-3 illustrates

the variations of the temperature, gas saturation, oil saturation, water saturation, and oil

mobility along the line of study which is in the base case of Figure 4-2.

Zone A is called the steam zone where it is filled by steam, residual oil, and connate

water. The temperature is constant, and gas saturation maintains in a high level.

Zone B is called the steam condensation zone where the steam contacts with the

bitumen and reservoir rock. In this zone, the latent heat of the steam transfers into the

bitumen and the resevoir rock due to a temperature difference. As a result, the steam is

condensed in this zone. Heat conduction plays a dominant role in the heat transfer process.

As seen in Figure 4-3, the temperature begins to decrease, the gas saturation drops down

45

to zero because of the condensed steam, and the water saturation and oil saturation

increased rapidly. Hence, there is a dramatic increase in the oil mobility.

Zone C is called the mobile oil zone. The viscosity of heated bitumen has reduced

dramtically and become flowable. Subsequently, mobilized oil is drained downward to the

producer by gravity. The oil saturation stays in high level and the water saturation drops

slowly. The oil mobility decreases as the temperature is continuing to decrease.

Zone D is called the immobile oil zone. The tempature of bitumen in this zone is

not affected sufficiently by the heat of steam. The bitumen remains in its original state. All

of the analytical properties do not change in this zone.

As observed in Figure 4-4, the steam chambers are quite different between the two

cases, especially in the middle of the steam chamber. To compare and analyze the steam

chamber in detail, we also divided the steam chamber into three areas from the bottom to

the top of the reservoir in the vertical direction.

Base case Lean zones case

Figure 4-2 Comparison of the temperature distributions with different zones of

SAGD process with 2500 kPa injection pressure at 273 days

T (oC )

46

Base case

Figure 4-3 Schematic presentation of the temperature, gas saturation, oil saturation,


process with 2500 kPa injection pressure at 273 days

Base case Lean zones case

Figure 4-4 Comparison of the temperature profiles with three areas of the reservoir

in SAGD with 2500 kPa injection pressure at 273 days

T (oC )

47

4.2.1.1 Bottom Area of the Reservoir

The comparitive analysis at the bottom area of the reservoir has been done through

the steam chamber profiles and property variations along the line of study. Figure 4-5

displays the temperature profiles at the bottom area of the reservoir at 273 days with the

base case and lean zone case. Figure 4-6 shows the variations of the analytical properties

(gas saturation, oil saturation, oil mobility, water saturation, temperature) at 273 days along

the study line.

As seen from Figures 4-5 and 4-6, zone A is the steam zone which is also called the

non-condensation zone. The intervals of the steam zones for both cases are 1.0 m. The

analytical parameters are constant in the steam zones. The temperature, gas saturation

(mainly steam), oil saturation, oil phase mobility, and water saturation are 223 oC, 0.54,

0.30, 17.05 md/cp, and 0.17 for both cases, respectively. The gas saturation fluctuates

slightly but remains in saturation conditions. There is no oil fluid flow as the oil saturation

and oil phase mobility are quite low. In this zone, the pores of the reservoir are filled with

steam, residue oil, and water.

Zone B is the condensation zone (1.0m for both cases). The steam condensed at the

vapor-liquid interface once the reservoir conditions were insufficient to the saturated steam

conditions (Butler et al. 1998). The five physical properties have been varied along the line

of study.

First, the gas saturation (mainly steam) decreased sharply from 0.53 to zero in this

region. Second, the temperature begins to drop as well. On the other hand, the oil saturation,

oil phase mobility, and water saturation increased dramatically for both cases. Third, the

48

peak of oil saturation in this region is 0.63 for the base case and 0.72 for the lean zone case.

Moreover, as the latent heat of steam is conducting into the oil phase, the oil phase mobility

is also increased significantly in both cases. The highest values are 158 md/cp for the base

cases and 253 md/cp for the lean zones case. In addition, the water saturations increase

because of the steam condensation in this region. The peaks of water saturation are 0.41

and 0.28 for both cases. It indicates that more steam has condensed in this zone for the base

case. To compare the two cases, the oil saturation in the base case is lower than that in the

lean zone case while the water saturation in the base case is higher than that in the lean

zone case. It illustrates that most heat of the steam in the lean zone case is released at the

right boundary of zone B. Therefore, the oil phase mobility in the lean zone case is higher

than that in the base case.

Zone C is the mobile oil region (4.8 m and 3.0 m). The viscosity of the bitumen has

been reduced enough to flow since the latent heat of steam was conducted into this region

continuously. The mobilized oil is drained to the producer by gravity. The gas saturations

in both cases remain at zero. The decreased rate of temperature is quicker as compared to

the other regions. Oil saturation continues to rise while the water saturation starts to drop

as the heat of steam is transmitted transversely. The oil mobility in the base case reached

the highest value, while the lean zone case decreases sharply. There are several contrasting

observations in the two cases. First, the temperature interval is different. As the oil phase

mobility drops to zero, the temperature in the lean zone case is 94.5 oC contrasted with 70.9

oC in the base case. Moreover, the mobile oil zone in the base case (4.6 m) is larger than

that in the lean zone case (3.0 m). Third, the peak of the oil phase mobility in the base case

49

is in the mobile oil zone; however, the peak value is between the interface of zone B and

zone C in the lean zone case. Thus, the efficiency of heat conduction in the base case is

higher than that in the lean zone case.

Zone D is the immobilized oil zone (after 56.75 meters in the base case and 55.25

meters in the lean zone case). The five observed properties of the bitumen and reservoir

have not changed due to the absence of heat conducting into this zone. All five properties

remain in the original reservoir conditions.

Base case Lean zone case

Figure 4-5 Comparison of the temperature profiles at bottom area of the reservoir

with 2500 kPa injection pressure at 273 days. The dashed line indicates the location

of study line

T (oC )

50

Base case (No-lean zone)

Lean zone case




51

4.2.1.2 Middle Area of the Reservoir

A similar analysis has been carried out in the middle area of the reservoir for both

cases. Figure 4-7 illustrates the comparison of the temperature profiles at the middle of the

reservoir at 273 days. Figure 4-8 shows the temperature, gas saturation, oil saturation, oil

mobility, and water saturation profiles along the dashed line (50-65 m) in the SAGD

process at 273 days. There are significant differences in the middle of the reservoir because

the lean zones are in this region. As observed from Figure 4-7, in the lean zone case, the

latent heat of steam is thieved into the lean zones extensively through all of four zones. As

a result, the temperature profile is in a convex shape.

Zone A (1.5m and 1.25m for the two cases) is the non-condensation zone. The

steam chamber remains in the saturated conditions. The properties are constant in the steam

zones. The temperature, oil saturation, oil phase mobility, and water saturation are stable.

There is no oil fluid flow but the live steam. The pores of the reservoir contain steam,

residue oil and connate water.

Zone B (0.75m in the base case and 1.0m in the lean zone case) is a steam

condensation zone. Since the latent heat of steam releases into the bitumen, the steam

condensation occurs in this region. The gas saturation decreased sharply from 0.49 to zero

due to the decreasing temperature. In contrast, the oil saturation, oil phase mobility, and

water saturation increased dramatically in the two cases. This scenario is similar to the

bottom of the reservoir. The peak of oil saturation in this region is 0.67 in the base case,

and 0.70 in the lean zone case. As quickly as oil saturation has increased, the oil phase

mobility has also increased significantly in both cases. The highest values in both cases are

52

265 md/cp in the base case and 261 md/cp in the lean zones case. These values are observed

near the interface of zone B and zone C. The water saturations increase because of the

condensation. The peaks of water saturation are 0.34 and 0.30 in both cases, respectively.

Zone C (4.75m in both cases) is the mobile oil zone. The bitumen has been able to

flow due to viscosity conduction. The gas saturations in both cases are almost zero. The

temperature drops significantly in this region. Oil saturation continues to rise while the

water saturation starts to drop as the heat of steam is delivered transversely. The oil phase

mobility decreases as the distance increases from the steam chamber. As seen, the

decreasing rate of the temperature is different in the two cases. As the oil phase mobility

drops to zero, the temperature in the lean zone case is 100 oC compared to 57.8 oC in the

base case. It indicates that the heat of steam is losing into the lean zones.

Zone D is the immobilized oil zone (after 57.0 m). The latent heat of steam has not

been conducted into this region effectively. The reservoir properties have been restored to

the original conditions.


Figure 4-7 Comparison of the temperature profiles at middle area of the reservoir in

SAGD with 2500 kPa injection pressure at 273 days. The dashed line indicates the

location of study line

T (oC )

53

Base case (No-lean zone)

Lean zone case


oil mobility, water saturation profiles along the line of study (50-65m) in SAGD


54

4.2.1.3 Top Area of the Reservoir

A similar comparative analysis has been done at the top part of the reservoir. Figure

4-9 shows the temperature profiles at the top area of the reservoir in the SAGD process at

273 days in the two cases. Figure 4-10 displays the schematic representations of the

temperature, gas saturation, oil saturation, oil mobility, and water saturation profiles along

the dashed line (50-65 m) in the SAGD process at the same time. As observed from Figure

4-9, zone B is of partial existence in this region because the growth of the steam chamber

develops to sideways once the steam has contacted the overburden (Butler et al. 1998).

Figure 4-10 displays the variations of gas, oil, and water saturations, temperature and oil

phase mobility at the top part of the reservoir.

Zone A is the non-condensation zone (3.0m and 3.25m). The temperature and

pressure are almost constant. The other properties are almost constant in the steam zones.

The temperature, gas saturation (mainly steam), oil saturation, oil phase mobility, and

water saturation are constant. The pores of the reservoir are mainly filled with steam. The

gas saturation is 0.54 in the base case and 0.58 in the lean zone case. It is consistent with

Wang et al. (2015). They found that a part of mobile water in lean zones was vaporized

into the steam zone and condensed with the injected steam at the edge of the vaper-liquid

phases.

Zone B (1.25m in the base case and 1.0m in the lean zone case) is a steam

condensation zone. Since the steam just begins condensing in this area, zone B is pinching

out at the upper part of the area. The gas saturation decreases sharply. The temperature

55

starts to reduce. However, the oil saturation, oil phase mobility, and water saturation

slightly rise in both cases. The water saturation increases because of the condensation.

Zone C is the mobile oil zone (2.75m in both cases). The bitumen has been

mobilized by the heat. The mobilized bitumen is drained towards the producer by gravity.

As seen in Figure 4-10, the gas saturations in both cases remain near zero. The temperature

declines due to the loss of heat. Oil saturation continues to increase when the water

saturation begins to drop as the thermal energy of the steam is conducted sideways. The oil

phase mobility reached the peak values in the two cases. It is 175 md/cp in the base case

and 102 md/cp in the lean zone case. The temperature decreasing rate is also different in

the two cases. When the oil phase mobility is zero, the corresponding temperature in the

lean zone case is 82.6 oC compared to 71.7 oC in the base case. The phenomena indicates

that the heat of steam is conducted into the lean zones more effectively.

Zone D is the immobilized oil zone. The temperature is still low so that bitumen

cannot be heated to flow. The reservoir condition remains in its original state.


Figure 4-9 Comparison of the temperature profiles at top area of the reservoir in

SAGD process with 2500 kPa injection pressure at 273 days. The dashed line indicates

the location of the line of study.

T (oC )

56

Base case

Lean zone case

Figure 4-10 Schematic representation of the temperature, gas saturation, oil

saturation, oil mobility, water saturation profiles along the line of study (50-65 m) in

SAGD with 2500 kPa injection pressure at 273 days

57

Comparative Analysis on the Impacts of Lean Zones in the reservoir

4.2.2.1 Water Saturation and Velocity Vector of Water Distribution

The water saturation distribution and velocity vector of water in the two cases are

shown in Figure 4-11. The direction of all velocity vectors of water is towards the producer

in the base case. On the other hand, the water not only flows to the producer but also flows

into the lean zones. This further indicates that the latent heat of steam has lost into the lean

zones. Xiu et al. (2014) stated that the lean zones were the priority pathways for the steam

because of higher mobility and heat conductivity compared to the bitumen. Due to the high

mobility of water, the mobile water also increased the convective heat flux in the lean zones.

These will lead to high consumption of steam to be injected. They also pointed out that the

mobile water in the lean zones was produced with the condensed water from the producer.

The water saturation variations in the lean zones indicate that the mobile water in the lean

zones flowed into the steam chamber. Meanwhile, the void pores are filled with the steam

causing more steam consumption in the steam zone.

58

Figure 4-11 Comparison of water saturation and water velocity vector in SAGD with

2500 kPa injection pressure at 273 days.

Base case

Lean zone case

59

4.2.2.2 Production Variations in the Steam Chamber

As seen from Figure 4-12, the steam chamber in the lean zone case is slightly bigger

than that in the base case. It illustrates that the mobile water, which is in the lean zones, is

produced with condensed water. It is because part of the mobile water was vaporized and

condensed with the steam coincidentally. Figure 4-13 shows the comparison of cumulative

water production. It is obvious that the lean zone case produced more water from the

reservoir than the base case. On the other hand, it can be seen from Figure 4-14 that since

the lean zone case produced more water than the base case, the oil recovery in the lean

zones case is less than in the base case.

Figure 4-12 Comparison of the seam chamber volume

15710 15720 15730 15740 15750 15760 15770 15780

Base case

Lean zones case

Steam chamber volume, m3

60

Figure 4-13 Comparison of the cumulative water production

Figure 4-14 Comparison of the oil recovery factor

66200 66400 66600 66800 67000 67200 67400

Base case

Lean zones case

Cumulative water production, m3

60.6 60.8 61 61.2 61.4 61.6 61.8 62 62.2 62.4 62.6

Base case

Lean zones case

Oil Recovery Factor, %

61

Comparison and Analysis of the Growth of the Steam Chamber

The growth of the steam chamber in both cases is described with the essential

reservoir properties such as gas and temperature profiles in the i-k cross section with 2500

kPa injection pressure at 180, 365, and 730 days. With reference to Figures 4-15 to 4-16,

the steam chamber grows upward as the steam is injected into the reservoir.

After the steam reached the overburden, the growth of the steam chamber expands

sideways along the overburden. As seen from these figures, the steam chamber developed

uniformly in the base case. On the other hand, in the temperature profiles, the steam

chamber has a convex shape when it contacts with the lean zones at 180 and 365 days.

According to Figure 4-16 the gas saturation distribution did not become convex in the lean

zone region. However, the steam zone in the base case is lager than that in the lean zone

case at 180 days. After 730 days, the shape of the steam chamber was not affected by the

lean zones and its shape and area are almost the same.

62


Figure 4-15 Comparison of the temperature profiles in cross section of SAGD with

2500 kPa injection pressure at 180 days, 365 days, and 730 days

180 days

365 days

730 days

63


Figure 4-16 Comparison of the gas saturation profiles in cross section of SAGD with

2500 kPa injection pressure at 180 days, 365 days, and 730 days.

180 days

365 days

730 days

64

Sensitivity Analysis of Reservoir with Lean Zones in SAGD Process

In this section, we investigated the effects of thickness and water saturation of the

lean zones on the SAGD process. Moreover, the vertical and horizontal permeability

variations were introduced into the model to study the effects of reservoir heterogeneity in

the SAGD process.

According to Figure 4-17, the layers of a lean zone were increased gradually from

0 to 20 layers (from 0 to 10 meters). As observed in this figure, as the thickness of a lean

zone increased, the oil recovery factor decreased. It proved that the thickness of a lean zone

has a significant impact on the SAGD performance.

The effects of water saturation on the performance in the lean zones are shown in

Figure 4-18. The water saturation in the lean zones is set from 0.60 to 0.95 with an interval

of 0.05. As we observed, the oil recovery rate is reduced as the water saturation in the lean

zones increased. The higher water saturation in the lean zones impairs the oil production

of the SAGD process because more water is produced from the lean zones.

Figure 4-19 illustrates the effect of vertical permeability on the SAGD process. The

ratio of vertical permeability with horizontal permeability has a different effect on the

SAGD performance. The ratio was set from 0.25 to 1.5. As the ratio increased, the oil

recovery begins to drop; when the vertical permeability is 0.75 times the horizontal

permeability, the oil recovery factor reaches the lowest value. However, as the ratio

continues to rise, the oil recovery rate increases to a higher value. The low vertical

permeability led to the lateral growth of the steam chamber. Even though the growth rate

65

of the steam chamber is reduced, the steam chamber is larger than in the normal case.

Therefore, the vertical permeability severely affects the SAGD performance.

Figure 4-17 Comparison of the oil recovery factor vs. thickness of the lean

zones

Figure 4-18 Effects of the lean zone water saturation vs. the oil recovery factor

55

56

57

58

59

60

61

62

63

0 5 10 15 20 25

Oil

reco

vry

fact

or,

%

Number of lean zone layers

60.4

60.6

60.8

61

61.2

61.4

61.6

0.5 0.6 0.7 0.8 0.9 1

Oil

reco

very

fac

tor,

%

Water saturation of the lean zones

66

Figure 4-19 Effects of the ratio of vertical and horizontal permeabilty vs. the

oil recovery factor

Conclusions of the SAGD Process

The impacts of lean zones on the SAGD process have been investigated by

comparing their bottom, middle, and top locations in a reservoir. The analyses of

temperature, gas saturation, water saturation, oil satuation, and oil mobility variations in

the SAGD process have been concluded. The presence of lean zones in the reservoir

impaired the steam chamber significantly because of the heat loss into the lean zones.

Steam consumption increased because the mobile water was produced with condensed

steam to form a larger steam chamber than those in no-lean zone reservoirs. Because of

this, higher water production led to an increased operation cost.

61.1

61.2

61.3

61.4

61.5

61.6

61.7

61.8

0 0.2 0.4 0.6 0.8 1 1.2 1.4 1.6

Oil

reco

very

fac

tor,

%

Ratio of vertical and horizontal permeability

67

Sensitivity analyses have been conducted to investigate the effects of lean zones on

the SAGD process. First of all, the thickness of the lean zones was studied in the SAGD

process. As the thickness of lean zones increased, the oil production continued to drop.

Second, the water saturation in the lean zones impairs the oil produciton of the SAGD

process. Third, lower vertical permeability in the reservoir with lean zones has effects on

the SAGD performance. The lowest oil production occurred when the ratio of vertical and

horizotal permeability was 0.75.

In conclusion, the existence of lean zones in an oil sand reservoir severely impaired

the SAGD performance. To improve the oil recovery in the reservoir with lean zones, the

ES-SAGD method will be introduced in the coming chapter.

68

ANALYSIS OF ES-SAGD PROCESS WITH LEAN ZONES

Introduction

ES-SAGD is a process in which the hydrocarbon additives (solvent) are co-injected

with steam into oil sands reservoirs to reduce the bitumen viscosity at the edge of a steam

chamber thus improving oil mobility and oil recovery (Easr. 2003). Some reserchers also

indicated that ES-SAGD decreases the steam consumption and greenhouse gases emission.

In this chapter, the ES-SAGD process is conducted in the model to investigate the impacts

on a reservoir with lean zones.

Solvent Characterization

Many solvents are typically not pure components due to a high price. In practice, a

blend of various light hydrocarbon components (a hydrocarbon mixture) is used as an

injecting solvent. In this study, a selection of hydrocarbon mixture (C4 to C11) was

characterized by using CMG software (WinProp 2015 version) to match the phase

behavior of the additives at resevoir conditions. Furthermore, the components of the

hydrocarbon mixtures have been lumped into three pseudo-components which match the

liquid density and saturation pressure based on experimental data. After charaterization,

the data was exported into STARS for the ES-SAGD simulation.

The equilibrium K-value calculation in the STARS simulator uses a two-phase

equilibrium description fluid model. Liquid viscosities are inputted as tables which are

referenced as temperature and pressure. The defaults non-linear mixing rule was used to

determine both the oleic and water phases viscosities.

69

Solvent Injection Strategies

The hydrocarbon additives (a solvent mixture) are co-injected with the steam. It

contains 66.63% mole fraction of IC4-NC5, 31.06% mole fraction of C6-C8, and 2.31%

mole fraction of C9-C11. Solvent is co-injected with steam continuously at a 10% weight

fraction. The injection period is 15 years.

Comparison of Base Case and Lean Zone Case

A similar analysis as discussed in the previous chapter for SAGD is for the ES-

SAGD process to investigate the effects of solvent in resevoirs with lean zones. Figure 5-

1 displays the comparison of temperature profiles in the base case and the lean zone case

in the ES-SAGD process. The steam chambers in the two cases are significantly different

due to the presence of lean zones. The growth of the steam chamber in the base case

develops more transversely due to the hydrocarbon additives (solvent). In the lean zone

case, it is obvious that the shape of the steam chamber is affected by the lean zones severely.

The steam chamber is formed in a concave shape in the lean zone area. Figure 5-2 shows

the variations of the analytical properties along the line of study which is shown in Figure

5-1 in the base case. The distributions of the hydrocarbon additives (in three pseudo-

components) and steam mole fraction are shown in Figure 5-3. The reservoir is divided

into four zones according to the property variations. The description of the divided four

zones is as follows:

70

Non-condensation zone A: The pores of rock are filled with steam, solvent, residual

oil and water. Since the steam and solvent are in saturation conditions, there is no

condensation occurring. The temperature and pressure remain constant.

Condensation zone B: The steam and solvent start to condense once the vapor

contacts with the sorrounding bitumen and reservoir rock. The latent heat of steam transfers

to the cold oil. The solvent begins to dissolve the bitumen to further reduce the viscosity.

Bitumen mobilized zone C: Due to the heat conduction and solvent dissolution, the

bitumen is mobilized and drains to the producer by gravity.

Immobilized zone D: As this zone is beyond the steam chamber, the reservoir is in

original reservoir conditions.

As we have done in Chapter Four, the bottom, middle, and top of the reservoir are

selected in order to compare and analyze the differences of the steam chamber in the two

cases. Figure 5-4 illustrates the comparison of the steam chamber in the three locations in

the ES-SAGD process in the two cases.


Figure 5-1 Comparison of the temperature profiles with different zones of ES-SAGD

process with 2500 kPa injection pressure at 273 days. The dished line is the study line

T (oC )

71


oil mobility, water saturation profiles along the line of study (50-65 m) in ES-SAGD



C11) and steam mole fraction in the vapor, the solvent mixture mole fraction in the oil

phase profiles along the line of study (50-65 m) in ES-SAGD process with 2500 kPa

injection pressure at 273 days

72


Figure 5-4 Comparison of the temperature profiles with three areas of the reservoir

in ES-SAGD with 2500 kPa injection pressure at 273 days

Mechanisms Analysis of Reservoir at Different Locations

5.4.1.1 Bottom of the Reservoir

Figure 5-5 shows the temperature distribution profiles in the bottom location of the

reservoir at 273 days in the two cases. Figures 5-6 and 5-8 are property variations of

temperature, gas saturation, oil saturation, oil mobility, and water saturation profiles along

the line of study (50-65 m) in ES-SAGD in the two cases. Figures 5-7 and 5-9 are the

property variations of the solvent and steam mole fraction in the vapor phase, and the

solvent mole fraction in the oil phase profiles along the line of study in ES-SAGD at 273

days.

T (oC )

73

Zone A is the non-condensation zone (1.75m in the base case and 1.5m in the lean

zone case). The gas saturation in the two cases is constant. The oil and water saturations

remain at the residual level under the constant temperature and pressure. The solvent mole

fraction keeps in a low level. The temperature in the steam chamber in the base case is 184

oC and 179 oC in the lean zone case. It illustrates that the temperature is reduced by the

lean zones.

Zone B is the condensation zone (1.0m in both cases). In this zone, gas saturation

drops to zero. Oil and water saturations start to rise sharply. The steam mole fraction and

temperature start to drop, which indicates that the steam and solvent begin to condense in

this zone. The solvent mole fraction increased slightly. There are two observed differences

between the two cases.

1. The incremental extents of the oil and water saturations are different in the

two cases. The oil saturation is 60.5% and water saturation is 39.5% in the base

case. The leans zone case is 46.5% for the oil saturation and 53.5 % for the water

saturation. This phenomenon indicates that more water is present at the vapor-liquid

interface in the lean zone case.

2. The oil mobility is different in the two cases. The oil mobility starts to rise

in the base case; however, it remains in a low level in the lean zone case due to high

water saturation.

Zone C represents the mobile oil zone (6 m and 5.75m). As the temperature and

steam mole fraction drop, the latent heat of steam is conducted into the oil sand causing

the bitumen to flow. In addition, solvent which is dissolved into the bitumen further reduces

74

the viscosity of the bitumen. Oil saturation continually rises to a peak level. Water

saturation begins to drop. The differences in the two cases are concluded as follows:

1. The curves of oil and water saturations are different. As the oil saturation is

increasing, the water saturation decreases gradually in the base case. In the lean zone

case, after the water saturation increased in zone B, the peak value of water saturation

appears in the side boundary of zone C. On the other hand, the peak of the oil saturation

is in the middle of the mobile oil zone in the lean zone cases.

2. The oil mobility distribution and magnitude are different. The oil mobility is

850 md/cp in the base case. The peak value is near the right-side boundary of the zone

C. As the C6-C8 components condensed at upper layers and were drained by gravity,

the high mole fraction of the C6-C8 flowed and accumulated at the bottom of this zone

causing high oil phase mobility in this zone. Nevertheless, the peak value of oil

mobility in the lean zone case is 143 md/cp due to high water saturation which is

affected by the lean zones. The highest value of the oil mobility is in the middle of

zone C.

3. Solvent distribution is different in the two cases. At the same position, the

peak value of the C6-C8 components in the oil phase is 0.83 in the base case and 0.78

in the lean zone case. It is 0.40 and 0.22 in the vapor phase in the two cases. IC4-NC5

in the vapor phase is 0.27 in the base case and 0.23 in the lean zones case. The highest

mole fraction distributes near the right-side boundary due to the accumulation of

solvent in this zone.

75

Zone D is the immobile oil zone (after 59.25m in the base cases and 58.75m in the

lean zone case). The oil immobile zone is far from the oil flow boundary. There is no

movement. The properties of the reservoir remain in their original conditions.


Figure 5-5 Comparison of temperature profiles at bottom location of the reservoir in


indicates the location of study line

T (oC )

76

Base case




Base case


C11) and steam mole fraction in the vapor phase, the solvent mxiture mole fraction in

the oil phase profiles along the line of study (50-65 m) in ES-SAGD process with 2500

kPa injection pressure at 273 days

77

Lean zone case




Lean zone case


C11) and steam mole fraction in the vapor phase, solvent mxiture mole fraction in the

oil phase profiles along the line of study (50-65 m) in ES-SAGD process with 2500 kPa


78

5.4.1.2 Middle of the Reservoir

A comparative analysis has been done at the middle location of the reservoir

between the base case and the lean zone case. Figure 5-10 displays the temperature

distribution profiles which are divided into four zones in both cases. The schematic

representations of temperature, gas saturation, water saturation, oil saturation, and oil

mobility along with the line of study are shown in Figure 5-11 to investigate the property

variations in non-condensation zone (A), condensation zone (B), mobile oil zone (C), and

immobile oil zone (D). Figure 5-12 shows solvent (IC4-NC5, C6-C8, and C9-C11) mole

fraction profiles in the vapor and oil phases. In addition, the steam mole fraction profile in

the vapor phase along the line of study is shown in this figure.


zone case). The properties in the middle location are similar with those in the bottom

location. The water and oil saturations are in a low level. Temperature and pressure remain

constant. The gas saturation keeps in the saturation conditions. The steam mole fraction in

the vapor phase is under a high level. The solvent mole fraction in the oil and vapor phases

remains in a low level. Since the oil mobility is near zero, there is no oil flow. The growth

of the steam chamber tends to be sideways in the base case contrasting with the lean zone

case. The temperature in the base case is higher than that in the lean zone case.

Zone B is the condensation zone (1.75m in the base case and 1.0m in the lean zone

case). In this zone, the gas saturation drops to zero. The oil saturation and water saturation

start to increase. The oil mobility and solvent mole fraction also rise slightly. The

79

temperature and steam mole fraction vary slightly. The differences between the two cases

are observed below:

1. Temperature did not change until it reached the right of the zone boundary

compared with the lean zone case. This is because the growth direction of the

steam chamber in the base case tends to develop transversely. The steam mole

fraction was steady in the condensation zone because of the unchanged

temperature. In the lean zone case, the temperature and steam mole fraction start

to drop.

2. As seen from Figure 5-11, the oil mobility in the base case increases slightly

along with the increased oil saturation. However, it remains close to zero due to

the higher water saturation in the lean zone case. This phenomenon demonstrates

that there is more steam condensed in zone B where the steam mole fraction is

also reduced in the lean zone case. A high water saturation is caused by the lean

zones.

3. The solvent mole fraction in the vapor and oil phases increased in the lean zone

case as observed in Figure 5-14. In the base case, it is not changed severely. This

is because a small amount of solvent which was injected with steam was

condensed with the steam at the vapor-liquid boundary.

Zone C is the mobile oil zone (4.25m and 6.0m, respectively). The gas saturation

in this zone remains close to zero in both cases. The temperature and steam mole fraction

start to go down. The oil and water saturations remain in a relatively high level in both

cases. As the bitumen has been mobilized, the oil mobility reaches its peak value. The

80

mobile oil flows downwards due to gravity. There are two noted differences between the

two cases.

1. The increased value of water saturation is different. The water saturation is

0.3 in the base case and 0.6 in the lean zone case. It is similar to the bottom

of the reservoir, and the two peak values in the lean zone case are located in

the both-side boundary of zone C.

2. The oil mobility magnitude and distribution are different. The peak value of

oil mobility in the base case is 1024 md/cp. It is 338 md/cp in the lean zone

case. The distribution of high oil mobility skew to the right-side flow

boundary in the base case. It is almost a normal distribution in the lean zone

case.

From the above comparison, in the base case, the high level solvent mole fraction,

which most came from the upper layers, accumulated at the flow boundary leading to the

higher mobility of oil drained to the producer by gravity. Due to the high mobility of oil

flow, the thickness of zone C became thinner than that in the lean zone case. On the other

hand, the oil mobility in the lean zone case is relatively low because of high water

saturation which is caused by the lean zones. The presence of lean zones in the reservoir

also caused a lower mole faction of the solvent.

Zone D is the immobile oil zone (after 62.5m in the base case and 58.5m in the lean

zone case). Since the zone is beyond the flow boundary, there is no oil movement.

81


Figure 5-10 Comparison of the temperature profiles at middle location of the

reservoir in ES-SAGD process with 2500 kPa injection pressure at 273 days. The

dashed line indicates the location of study line

Base case




T (oC )

82

Base case


steam mole fraction in vapor phase, the solvent mixture mole fraction in the oil phase

profiles along the line of study (50-65 m) in ES-SAGD process with 2500 kPa injection

pressure at 273 days

Lean zone case



process with 2500 kPa injection pressure at 273 days.

83

Lean zone case


steam mole fraction in the vapor phase, the solvent mixture mole fraction in the oil

phase profiles along the line of study (50-65 m) in ES-SAGD process with 2500 kPa


5.4.1.3 Top of the Reservoir

A similar comparative analysis for the top of the reservoir has been conducted to

investigate the impact of lean zones on the ES-SAGD process. The schematic variations

along with the dished line in the non-condensation, condensation, mobile oil, and immobile

oil zones are shown in Figures 5-15 to 5-19. In this location, the steam and solvent

accumulate at the top of the steam chamber to heat and dissolve in the bitumen in both

cases. The line of study is in the lean zone layers to analyze their impacts.

84


zone case). Gas saturation is in 0.4-0.5 in both cases. The fluctuations of the gas and oil

saturations in the base case are caused by the fingering effect of the solvent (IC4-NC5 in

the vapor phase). This phenomenon can also be observed in Figures 5-22 and 5-23. Water

saturation is in a low level. Oil mobility in this zone is near zero so there is no oil flow.

The solvent mole fraction remains in a low level under the constant temperature and

pressure.

Zone B is the condensation zone (4.0m and 1.5m, respectively). The temperature

and steam mole fraction start to drop. Gas saturation in the two cases drops to zero. The

mole fraction of the solvent mixture in the vapor and oil phases reached a high level so the

oil mobility reached a peak value.

In the base case, the steam chamber grows more transversely than in the vertical

direction. At the top part of the steam chamber region, as seen in Figures 5-16 and 17, gas

saturation is still at a high level because of the high mole fraction of solvent (IC4-NC5, C6-

C8) in the vapor phase. When the gas saturation dropped to zero, the steam chamber

boundary is reached. In this area, the solvent in the vapor phase contacts and dissolves into

the cold bitumen directly. The higher mole fraction of solvent in the vapor and oil phases

demonstrates that the latent heat of steam is no longer the dominant effect for reducing the

viscosity. Once the bitumen is mobilized, the oil and solvent mixture drain to the producer

quickly. As observed in Figure 5-16, oil saturation and water saturation are still in the

residual state. This indicates that only solvent was condensed and dissolved in this zone.

85

There are vast differences in zone B in the lean zones case. The water and oil

saturations begin to increase while the gas saturation decreases to zero. The steam mole

fraction and temperature dropped significantly. Oil mobility rose dramatically towards the

end of zone B because of solvent (mainly C6-C8) in this vapor-liquid boundary.

Zone C is the mobile oil zone (4.0 m and 7 m, respectively). This zone does not

exist in the base case because the steam and solvent contact with the cold oil sand directly.

Once the oil is mobilized by the latent heat of steam and solvent, they mixed and were

drained away by gravity.

In the lean zone case, oil saturation continues to increase. Water saturation drops to

a low level. Oil mobility reaches a peak value (1225 md/cp) because of the high mole

fraction of solvent (mainly C6-C8) accumulating in this region. Gas saturation is in a low

level because solvent (mainly IC4-NC5) is present in the vapor phase. The temperature

continues to decrease and the steam mole fraction is zero. The mole fraction of the solvent

mixture in the vapor and oil phases are still at a high level. This demonstrates that the

solvent has intruded into this zone after the temperature reduced to the original level. The

presence of solvent in this zone protects the mobile water in the lean zone layers

communicating with the steam chamber. Therefore, it prevents the heat of steam losing

into the lean zones. However, the presence of lean zones reduces the temperature of the

steam chamber. The small amount of mobile water mixes with steam causing the alteration

of the growth of the steam chamber. It can be observed in Figure 5-19 that a high mole

fraction of solvent (mainly IC4-NC5 in the vapor and oil phases and C6-C8 in the oil phases)

was distributed widely in this zone.

86

Zone D is the immobile oil zone (after 58.5m in the base case and 61m in the lean

zone case). In the base case, the oil saturation and water saturation are in the initial level

as this zone is far away from the steam chamber.


Figure 5-15 Comparison of the temperature profiles at top location of the reservoir

in ES-SAGD process with 2500 kPa injection pressure at 273 days. The dashed line

indicates the location of study line

87

Base case




Base case





88

Lean zone case




Lean zone case





89

Impacts of Lean Zones

5.4.2.1 Temperature Distribution

Temperature plays a critical role in the development of a steam chamber. In this

section, the comparison of temperature distribution in various locations is shown in Figure

5-20. As observed, from the top to the bottom of the steam chamber, the temperatures in

the steam chamber in the lean zone case are always lower than that in the base case. Most

importantly, the temperature deviation in the two cases mainly concentrates on the

condensation zone and mobile oil zone. In addition, an increase in deviation is in the middle

of the steam chamber. The high temperature lasts for 9 meters in the base case, and 2.5

meters in the lean zone case which indicates that the shape of the steam chamber has been

changed because of the lean zones. Furthermore, it also demonstrates that the lean zones

altered the growth direction of the steam chamber in the lean zones case.

90

Figure 5-20 Comparison of temperature profiles vs. distances in SAGD with 2500 kPa


91

5.4.2.2 Distribution of the Water Saturation and Velocity Vector of Water

Figure 5-21displays the water saturation and velocity vector of water at 273 days

in the two cases. The low water saturation area is distributed mainly in two locations in the

base case. One is in the upper part of the steam chamber. The co-injected solvent

accumlated in this area to dissolve in the bitumen further. The other is above the injector

where the solvent is just injected into the resevoir with the steam. The velocity vector of

water in the upper part of the steam chamber shows that the condensed steam flows

downward at the boundary of the steam chamber. At the lower part of the steam chamber,

the condensed water flows with the mobilized oil and condensed solvent along the edge of

the steam chamber to the producer. The lower water saturation can be found at the edge of

the lower part of the steam chamber and above the producer.

In the lean zone case, the low water saturation is at the upper part of the steam

chamber and above the injector. The injected solvent accumulated in these areas. In

addition, the low saturation is also shown in the lean zone area. This phenomenon indicates

that the injected solvent has intruded into the lean zones layers. On the other hand, the high

water saturation areas are shown in three locations of the steam chamber. First, in the lean

zones area there is a small area where mobile water communicates with the steam chamber.

Second, the high water saturation is at the middle part of the flow boundary. Third, at the

edge of the vapor-liquid interface water accumulated in the lower part of the steam chamber.

These phenomena are consistent with the previous analyses. The velocity vector of water

shows that the water fluid flow is along the flow boundary of the steam chamber and the

vapor-liquid interface which is in the steam condensation area. In the lean zone area, a

92

small amount of water flows into the lean zones. It demostrates the steam channels into

the lean zones due to the higher mobility and heat conductivity. However, most of the lean

zones are blocked by the solvent.

Comparing the two cases, the shape of the steam chamber has been deformed

because of the lean zones. The mobile water in the lean zones which flows into the steam

chamber has altered the temperature in the steam chamber.

93

Figure 5-21 Comparison of water saturation and water velocity vector of in ES-SAGD

with 2500 kPa injection pressure at 273 days

Base case

Lean zone case

94

Solvent Distribution in the Steam Chamber

As mentioned, the solvent plays an important role in ES-SAGD with lean zones.

The solvent distribution in the reservoir is analyzed in this section. The injected solvent

mixture consists of IC4-NC5, C6-C8, and C9-C11. The C9-C11 has no effect on the growth of

a steam chamber because it always condenses near the injector due to high molecular

weight.

5.4.3.1 Mole Fraction Distribution of IC4-NC5

Figure 5-22 shows the light component of the solvent (IC4-NC5) mole fraction in

the vapor phase. As it can be seen, the light component mainly accumulates in the upper

steam chamber in both cases. In the lean zone case, the light solvent has intruded into the

lean zones. As a result, it hampers the mobile water of the lean zones to communicate with

the steam chamber. This intrusive effect also occurred in the oil phase which is shown in

Figure 5-23.

95



phase of ES-SAGD with 2500 kPa injection pressure at 273 days


Figure 5-23 Comparison of the solvent (IC4-NC5) mole fraction profiles in the oil


96

5.4.3.2 Mole Fraction Distribution of C6-C8

The middle components (C6-C8) of the solvent profiles are shown in Figures 5-24

and 5-25. They show that the middle components in the vapor phase have not intruded into

the lean zones. On the other hand, the middle components in the oil phase has intruded into

the lean zones. Thus, the middle components in the oil phase also blocked the mobile water

flowing into the steam chamber.


Figure 5-24 Comparison of the solvent (C6-C8) mole fraction distribution in the vapor


97


Figure 5-25 Comparison of the solvent (C6-C8) mole fraction distribution in the oil


Comparison of the Production Performance

Figure 5-26 shows the comparison of the steam chamber volume in the two cases.

As observed, the steam chamber volume in the base case is higher than that in the lean zone

case. The reason is a part of the solvent intruded into the lean zone layers resulting in the

reduction of solvent dissolved into the bitumen. Therefore, in Figure 5-27, the oil recovery

factor in the base case is also higher than that in the lean zone case. In addition, a lower

temperature in the steam chamber caused by the lean zones is another reason for the

reduced steam chamber volume and oil recovery factor in the lean zones case.

98

Figure 5-26 Comparison of the steam chamber volume

Figure 5-27 Comparison of the oil recovery factor

22400 22600 22800 23000 23200 23400 23600 23800 24000

lean zones case

Base case

Steam Chamber Volume, m3

81 82 83 84 85 86 87 88

Lean zones case

Base case

Oil recovery factor %

99

Comparative Analyses of the Growth of the Steam Chamber

The growth of the steam chamber in the two cases is analyzed by temperature and

gas distribution in the ES-SAGD at 180, 365, and 730 days. According to Figures 5-28 to

5-29, the lateral growth of the steam chamber is accelerated because of the solvent. The

shapes of the steam chamber are almost the same at 180 days. However, the shape of the

steam chamber has altered in the lean zone case since the steam chamber reached the lean

zone layers. The growth direction of the steam chamber also altered towards the vertical

direction, especially in the lower part of the steam chamber. Because of the lean zones, the

temperature in the steam chamber in the lean zone case is lower than that in the base case

at 365 days. Moreover, the mobile water in the lean zones results in a deformed steam

chamber. At the lower part of the steam chamber, high water saturation in the vapor phase

leads to accelerated growth in the vertical direction. As the steam chamber grew

continuously, it reached the overburden at 730 days. At the upper part of the steam chamber,

the steam chamber in the lean zone case is larger than in the base case. It means that the

growth direction of the steam chamber in the lean zone case is along the overburden of the

reservoir. Nevertheless, the growth of the steam chamber in the base case develops

primarily sideways in the middle of the steam chamber. On other hand, the lower part of

the steam chamber in the base case is larger than that in the lean zone case at 730 days.

This indicates that more mobilized bitumen drains to the producer contrasting with the lean

zone case.

100


Figure 5-28 Comparison of temperature profiles in cross section of ES-SAGD with

2500 kPa injection pressure at 180, 365, and 730 days

180 days

365 days

730 days

101


Figure 5-29 Comparison of gas saturation profiles in cross section of ES-SAGD with

2500 kPa injection pressure at 180, 365, and 730 days

180 days

365 days

730 days

102

Solvent Distribution in the Growth of the Steam Chamber

The comparison of solvent mole fraction profiles in the growth of the steam

chamber at 180, 365, and 730 days is shown in Figures 5-30 to 5-33.

Figure 5-30 shows the comparison of solvent (IC4-NC5) mole fraction profiles in

the vapor phase at 180, 365, and 730 days in the two cases. As seen in these figures, the

high mole fraction of the light component mainly accumulates in the upper part of the edge

of the steam chamber. The light components and mobilized oil are drained to the producer

by gravity after they are dissolved into the bitumen. The vaporized light components have

intruded into the lean zones when the steam chamber reached the lean zones. At 730 days,

the solvent intrusion phenomenon is still proceeding. The light components intrusion

results in the reduction of solvent in the upper part of the steam chamber boundary

compared to the base case. Therefore, the upper part of the steam chamber in the lean zone

case is smaller than that in the base case.

In Figure 5-31, the light components of solvent in the oil phase distribute slightly

in the upper part of the steam chamber. They can also be found in the lean zone layers.

Figure 5-32 displays a comparison of the middle components (C6-C8) mole fraction

profiles in the vapor phase at the flow boundary in different periods. There is a low mole

fraction of middle components distributed along the steam chamber boundary. At 365 days,

the middle components in the vapor phase did not intrude into the lean zones. In contrast,

it can be observed in Figure 5-33 that a high mole fraction of middle components in the oil

phase fill in the whole steam chamber boundary. Some of the components can also be found

in the lean zone layers.

103



phase of ES-SAGD with 2500 kPa injection pressure at 180, 365, and 730 days

180 days

365 days

730 days

104


Figure 5-31 Comparison of the solvent (IC4-NC5) mole fraction profiles in the oil


180 days

365 days

730 days

105


Figure 5-32 Comparison of the solvent (C6-C8) mole fraction profiles in the vapor


180 days

365 days

730 days

106


Figure 5-33 Comparison of the solvent (C6-C8) mole fraction profiles in the oil phase

of ES-SAGD with 2500 kPa injection pressure at 180, 365, and 730 days

180 days

365 days

730 days

107

Sensitivity Analyses of a Reservoir with Lean Zones in ES-SAGD Process

The variations of the thickness and locations of lean zones in reservoirs and the

vertical permeability of reservoirs have close relationships with the ES-SAGD

performance. Thus, the variations of these properties are investigated in this section.

Multiple-layers of the Lean Zone

The thickness of lean zones is increased from 0 to 10 meters with an interval of 2

meters. Figure 5-34 displays the relationship between the thicknesses of lean zones with

an oil recovery factor in the ES-SAGD process. As it can be seen, the oil recovery factor

decreased as the thicknesses of lean zones increased. The oil recovery factor drops from

87.21% to 84.10%. However, when the thickness of lean zone increased more than 5 meters,

the oil recovery in the ES-SAGD process did not decrease any more. The oil recovery

factor remains around 82%. This indicates that in this study, the oil recovery factor was not

changed after the thickness of the lean zones was more than 5 meters.

Figure 5-34 Comparison of the oil recovery factor vs. thickness of the lean zones

81

82

83

84

85

86

87

88

0 5 10 15 20 25

Oil

reco

very

fac

tor

%

Number of the lean zone layers

108

Locations of the Lean Zones

The lean zones are located above the injector with various distances (from 2m to

20m) to study the effects on the ES-SAGD performance. Figure 5-35 illustrates the

correlation between the distance and oil recovery factor. This figure shows that the oil

recovery factor drops from 87.77% to 83.91% as the interval of lean zones from the injector

increases from 2 meters to 20 meters. The oil recovery factor drops slightly before the

distances increase to 14 meters. From 14-20 meters, the oil recovery decreased

dramatically (86.87%-83.91%). The oil recovery factor is more sensitive to upper locations

than the lower location of the lean zones.

Figure 5-35 Comparison of the oil recovery factor vs. location of the lean

zones

83.5

84

84.5

85

85.5

86

86.5

87

87.5

88

0 5 10 15 20 25

Oil

reco

very

fac

tor

%

Disteance between the injector and lean zones (m)

109

The Water Saturation in the Lean Zones

The water saturation in the lean zones is set from 0.6-0.9 to investigate the effects

on ES-SAGD performance. Figure 5-36 shows the relationship between the oil recovery

factor and water saturation in the lean zones. The oil recovery factor reduced slightly

(84.13%-83.31%) as the water saturation in the lean zones increases from 0.6-0.9. Thus,

the water saturation in the lean zones has a minor impact on the ES-SAGD performance.

Figure 5-36 Comparison of the oil recovery factor vs. water saturation of the

lean zones

The Effect of Reservoir Vertical Permeability

The effect of vertical permeability on ES-SAGD performance is shown in Figure

5-37. The ratio of the vertical and horizontal permeability was set from 0.25 to 1.5, and the

various intervals of oil recovery are from 61.51% to 87.76%. The lowest oil recovery factor

83.2

83.3

83.4

83.5

83.6

83.7

83.8

83.9

84

84.1

84.2

0.5 0.55 0.6 0.65 0.7 0.75 0.8 0.85 0.9 0.95

Oil

reco

very

fac

tor

%

Water saturation of the lean zones

110

corresponds with the lowest vertical and horizontal permeability ratio. As the ratio

increased, the oil recovery began to increase. When the vertical permeability is more than

0.75 times the horizontal permeability, the oil recovery factor slightly changed. The oil

recovery factor remains stable as the ratio increased continuously. Since the growth of the

steam chamber in the ES-SAGD tends in a lateral direction, the vertical permeability has a

small effect on the performance after the ratio is more than 0.75.

Figure 5-37 Comparison of the oil recovery factor vs. the ratio of vertical and

horizontal permeability

0

10

20

30

40

50

60

70

80

90

100

0 0.2 0.4 0.6 0.8 1 1.2 1.4 1.6

Oil

reco

very

fac

tor

%

Ratio of vertical and horizontal permeability

111

Conclusions on the ES-SAGD Process

The impacts of lean zones on the ES-SAGD process have been demonstrated in this

chapter. The presence of lean zones altered the shape of a steam chamber because the

mobile water in the lean zones results in the alteration in the growth direction of the steam

chamber. In addition, the lean zones reduced the temperature in the steam chamber.

A solvent mixture plays an important role in ES-SAGD. The performance of the

ES-SAGD process has improved dramatically by bitumen viscosity reduction through

solvent dissolution. The solvent mixture protected the steam chamber from the lean zones

in addition to viscosity reduction. Since injected solvent intrudes into the lean zone layers,

the communication of the lean zone layers and steam chamber is isolated by the injected

solvent mixture. Furthermore, the lumped solvent components play different roles in the

growth of the steam chamber. In the steam chamber conditions, the light components (IC4-

NC5) which are in the vapor phase primarily distribute in the upper part of the steam

chamber boundary. A small amount of light components are in the oil phase. The light

components intruded into the lean zones layers. The middle components (C6-C8) play a

major role in the growth of the steam chamber. The middle components are mainly in the

oil phase and distribute at the entire steam chamber boundary in a high mole fraction. They

also intruded into the lean zone layers in a high level of mole fraction. Nevertheless, a

minor amount of the middle components are in the vapor phase around the steam chamber

boundary and did not intrude into the lean zone layers. Heavy components (C9-C11) did not

have effect on the growth of the steam chamber because most of heavy components

condensed around the bottom of the steam chamber.

112

The thickness of lean zones influences the performance of the ES-SAGD process.

However, as the thickness of lean zones was more than 5 meters, the oil recovery of the

ES-SAGD was not changed. .

The location of the lean zone has negative effects on the oil production. The impact

increased as the distance between the injector and lean zone layers increased. The water

saturation in the lean zones has a minor effect on oil production.

The vertical permeability influences the production performance severely.

However, after the ratio of vertical and horizontal permeability increases to 0.75, the

vertical permeability does not obviously influence the production performance of the ES-

SAGD process.

113

COMPARISON OF SAGD AND ES-SAGD PROCESSES IN

RESERVOIR WITH LEAN ZONES

Introduction

The mechanism analyses of lean zones in the SAGD and ES-SAGD processes have

been explored in the previous chapters. As concluded in the previous chapters, the

existence of lean zones influences both thermal recovery methods. The comparison of the

SAGD and ES-SAGD processes will be studied in this chapter to choose an optimal

approach for oil sand reservoirs with lean zones. Moreover, a two-dimensional geological

modeling with lean zones is used in SAGD and ES-SAGD to investigate the influences of

the lean zones on production performance.

Comparative Mechanism Analyses of the Reservoir at Different Locations

The similar comparative analyses for a reservoir with lean zones in the SAGD and

ES-SAGD processes are conducted in this section. Figure 6-1 displays the comparison of

temperature distribution profiles in the SAGD and ES-SAGD processes at 273 days. As

observed in this figure, the growth direction and shape of the steam chamber are completely

different in the two processes. First, the growth direction of the steam chamber in the

SAGD process tends to be vertical, and the direction tends to be lateral in ES-SAGD.

Second, the temperature in the steam chamber in the SAGD process is higher than that in

the ES-SAGD process. The reason is that the cold solvent mixture is injected with the steam

causing a reduction in the steam temperature. Moreover, the temperature profile is in a

114

convex shape in the lean zone area in the SAGD process, and it is concave in shape in the

ES-SAGD. These differences are discussed in detail in the next section.

As discussed in the previous chapters, the reservoir is divided into four zones,

which are from the inner part of a steam chamber to the original reservoir (left to right

sides), according to the various properties (temperature, gas saturation, oil saturation, water

saturation, and oil mobility) along the line of study. Figure 6-2 shows the study line at

different locations of the reservoir. The four zones include non-condensation zone A,

condensation zone B, mobile oil zone C, and immobile oil zone D. From top to bottom, the

three locations are the lean zone area, middle and bottom locations.

The description and discussion of the four zones are as follows:

Non-condensation zone A: Steam in this zone is in the vapor phase. The water and

oil saturation and solvent mole fraction remain a low level. Oil mobility is almost zero so

there is no oil flow. The temperature and pressure are constant.

Condensation zone B: Steam starts to condense. A small amount of solvent also

condenses in this zone. Gas saturation reduces to zero at the vapor-liquid interface.

Mobile oil zone C: The viscosity of bitumen is reduced by the latent heat of the

steam. In addition, the viscosity is reduced further by solvent in the ES-SAGD process.

The mobilized oil drains to the producer due to gravity.

Immobile oil zone D: As this zone is beyond the flow boundary, the reservoir

remains at the original conditions.

115

SAGD ES-SAGD


with 2500 kPa injection pressure at 273 days

SAGD ES-SAGD


with 2500 kPa injection pressure at 273 Days. The dashed line indicates the locations

of study lines

116

Comparison in the Lean Zone Area

The variations of the temperature, gas saturation, oil saturation, water saturation,

and oil mobility profiles for the SAGD and ES-SAGD are shown in Figures 6-3 to 6-5.

Comparing these figures, there are several differences in the two processes:

Zone A in the SAGD and ES-SAGD processes is 1.25m, and 4.25m, respectively.

The temperatures in the steam chamber in the two cases are 220 oC and 179 oC. The gas

saturation is 0.5 in the SAGD and 0.4 in the ES-SAGD due to the temperature difference.

Oil and water remain in a low level under constant temperature and pressure.

In condensation zone B (1.0m in SAGD and 1.5m in ES-SAGD), the gas saturation

drops to zero due to a reduction in temperature. Water and oil saturations start to increase.

Oil mobility in both processes rises to a high level. The thickness of zone B is 0.5 m less

than that in ES-SAGD. Steam starts to condense in this zone. The solvent mole fraction

begins to increase because solvent dissolution starts in the bitumen.

Mobile oil zone C (4.25m and 5.25m, respectively). The oil saturation remains at a

high level. Water saturation reduces to the residual level as the temperature continues to

drop. The oil mobility in both cases reaches a peak value, and the value in ES-SAGD is

almost six times that in the SAGD process because a high mole fraction of solvent exists

in this zone. After the oil mobility has decreased to zero, the mole fraction of solvent is

still at a high level. It indicates that as the mobile water flowed away, the solvent occupied

the void pores instead of the steam.

Zone D is the immobile oil zone. In this zone, bitumen is not mobilized because it

is far away from the flow boundary.

117

SAGD


mobility, water saturation profiles along the line of study (50-65 m) at lean zones

location in SAGD process with 2500 kPa injection pressure at 273 days

ES-SAGD


mobility, water saturation profiles along the line of study (50-65 m) at lean zone

location in ES-SAGD process with 2500 kPa injection pressure at 273 days

118


C11) and steam mole fraction in the vapor phase, the solvent mixture mole fraction in

the oil profiles along the line of study (50-65 m) in ES-SAGD process with 2500 KPa


Comparison of the Middle of the Reservoir

In Figures 6-6 and 6-7, the variations of gas saturation, oil saturation, oil mobility,

water saturation, and temperature at 273 days are shown in the middle location of the

reservoir. The solvent mole fraction in the vapor and oil phases and the steam mole fraction

in the vapor phase are shown in Figure 6-8.

In non-condensation zone A, the thickness is 1.25m in the SAGD and 1.5m in ES-

SAGD. Steam is in the vapor phase under constant temperature and pressure. Oil and water

saturations are at the residual level. The solvent mole fraction is also at the residual level.

The temperature in the SAGD process is higher than in the ES-SAGD process. The steam

mainly fills in the pores of the reservoir rock.

119

In condensation zone B (1.0m in both cases), the gas saturation drops to zero as the

temperature begins to decline. Oil and water saturations start to increase in both processes.

The oil mobility rises to a high level in the SAGD process while it remains at a low level

in the ES-SAGD process. The oil saturation is 0.78 in the SAGD process because the latent

heat of the steam conducted into the bitumen led to mobilization of the bitumen. The water

saturation is 0.63 in the ES-SAGD process due to mobile water in the lean zones.

In mobile oil zone C (3.0m in the SAGD and 5.0m in the ES-SAGD), oil saturation

remains in a high level in SAGD, and it fluctuates in the ES-SAGD case. The peak value

of oil mobility occurred because the solvent which is shown in Figure 6-8 distributed in

this zone and helpd to reduce oil viscosity further in the ES-SAGD process. There is a thick

mobile oil zone in the ES-SAGD process because of the solvent effect.

Immobile oil zone D is beyond the oil flow boundary. The reservoir is at low

temperature and there is no oil movement.

120

SAGD



lcocation in SAGD process with 2500 kPa injection pressure at 273 days

ES-SAGD


mobility, water saturation profiles along the line of study (50-65 m) at middle location

in ES-SAGD process with 2500 kPa injection pressure at 273 days

121

ES-SAGD


C11) and steam mole fraction in the vapor, the solvent mixture mole fraction in the oil



Comparison of the Bottom of the Reservoir

The variations of gas saturation, oil saturation, oil mobility, water saturation, and

temperature along the line of study at the bottom of the reservoir are shown in Figures 6-9

and 6-10. Figure 6-11 displays the solvent mole fraction in the vapor and oil phases, and

the steam mole fraction in the vapor phase.

Non-condensation zone A (1.25m in the two cases): Gas saturation is at a high level.

Oil, water saturation, oil mobility and a solvent mole fraction remain in the residual level.

There is no oil flow except for the steam.

122

Condensation zone B is 1.0m in the two cases. Gas saturation drops to zero. Steam

starts to condense as the temperature starts to decrease. The oil saturation and oil mobility

jump up to 0.73 and 222 md/cp, respectively, in the SAGD case because the latent heat of

the steam transfers to the bitumen. In the ES-SAGD case, the water saturation reaches 0.56.

Oil mobility retains in the residual level. As seen in Figure 6-11, a small amount of solvent

condensed at the vapor-liquid interface in zone B.

In mobile oil zone C, the temperature continues to drop. The thickness is 2.0m in

the SAGD case and 6.0m in the ES-SAGD case. In the SAGD case, the oil saturation

increases to 0.82. Water saturation decreases to 0.16. The oil mobility from the vapor-

liquid interface to the flow boundary reduces to zero. The gas saturation is zero. In the ES-

SAGD, the oil saturation and water saturation are influenced by mobile water in the lean

zones. High water saturation is present at both boundaries of zone C. The peak of the oil

mobility is in the middle of zone C due to a high mole fraction of the solvent. The existence

of low gas saturation is caused by the high mole fraction of the solvent in the vapor phase.

Zone D is the immobile oil zone. This zone is far from the steam chamber. Bitumen

is not mobilized because of low temperature in both cases. The reservoir is in the original

conditions.

123

SAGD


mobility, water saturation profiles along the line of study (50-65 m) at bottom location

in SAGD process with 2500 kPa injection pressure at 273 days

ES-SAGD


mobility, water saturation profiles along the line of study (50-65 m) at bottom location

in ES-SAGD process with 2500 kPa injection pressure at 273 days

124

ES-SAGD

Figure 6-11 Schematic representation of the solvent mxiture (IC4-NC5, C6-C8, and C9-

C11) and steam mole fraction in the vapor phase, the solvent mixture mole fraction in

oil profiles along the line of study (50-65 m) in ES-SAGD process with 2500 kPa


125

Comparison of Growth of Steam Chamber in SAGD and ES-SAGD Processes

The growth of the steam chamber in the SAGD and ES-SAGD processes are

described by property profiles at 180, 365, and 730 days.

Comparing the two processes, in Figure 6-12, the growth of the steam chambers is

completely different. In the SAGD process, the steam chamber is dominated by the

temperature of the injected steam. The growing direction is upward to the top of the

reservoir. The temperature profile is in a convex shape due to the heat loss in the lean zone

area at 365 days. After the steam chamber has contacted with the overburden, the steam

chamber develops transversely along the upper boundary of the reservoir. The temperature

remains in 220 oC. On the other hand, the growth of the steam chamber in the ES-SAGD

process is not only determined by the temperature of steam but also the solvent. The

temperature is 184 oC in the steam chamber. The temperature reduction is caused by the

vaporization of the co-injected solvent. Injected solvent condenses at the upper part of the

steam chamber to dissolve in the cold bitumen. The profiles of the temperature deformed

after the steam chamber reached the lean zones. The temperature distribution profile forms

a concave shape in the lean zone area at 365 days. As seen at 730 days, the growth of the

steam chamber in the ES-SAGD process is still a lateral movement after the steam chamber

touched the upper reservoir boundary.

According to Figure 6-13, it demonstrates that the growing directions of the steam

chambers are different at the upper part of the steam chambers, and the lower steam

chamber is similar comparing the two cases.

126

SAGD ES-SAGD

Figure 6-12 Comparison of the temperature profiles in cross section of SAGD and

ES-SAGD with 2500 kPa injection pressure at 180, 365, and 730 days

180 days

365 days

730 days

127

SAGD ES-SAGD

Figure 6-13 Comparison of the gas saturation profiles in cross section of SAGD and

ES-SAGD with 2500 kPa injection pressure at 180, 365, and 730 days

180 days

365 days

730 days

128

Comparative Analysis and Discussion for Lean Zones

To better understand the effects of lean zones on the SAGD and ES-SAGD

processes, the temperature distribution, velocity vector of water, water saturation, oil

mobility distribution, and oil recovery factor have been compared to investigate the impacts

of lean zones on the peformance of two processes.

Temperature Distribution

According to Figure 6-14, the temperature distributions in the lean zone area for

the two processes are different. First, the temperature of the SAGD case is 220 oC compared

to 184 oC in the ES-SAGD case. Second, the decline rate of the temperature is lower than

in the ES-SAGD case. It indicates that the heat is losing into the lean zones during the

SAGD process. On the other hand, the temperature decreases sharply at the boundary of

the steam chamber. It means that there is no heat loss in the lean zones.

Figure 6-14 Comparison of the temperature profiles vs. distance in SAGD and ES-

SAGD with 2500 kPa injection pressure at 273 days

129

Water Distribution and Velocity Vector of Water

The comparisons of the water saturation and velocity vector of water in the SAGD

and ES-SAGD processes are shown in Figure 6-15. As seen in the diagram, there is water

flow in the lean zone area in the SAGD process which indicates that the steam chamber

communicates with the lean zones which leads to the heat loss. It can also be seen in the

amplified profile which is shown in Figure 6-16. On the other hand, in the ES-SAGD

process, there is only a small amount of water flow into the lean zone layers because most

of the lean zones are isolated by the solvent which intruded into the lean zone layers. It

also can be seen clearly in Figure 6-16 in the ES-SAGD case that the lean zone has been

blocked by the solvent. A high mole fraction of solvent filled between the steam chamber

and lean zones.

SAGD ES-SAGD

Figure 6-15 Comparison of water saturation and water velocity vector in SAGD and

ES-SAGD with 2500 kPa injection pressure at 273 days

130

SAGD ES-SAGD

Figure 6-16 Comparison of amplified water saturation and water velocity vector in

SAGD and ES-SAGD with 2500 kPa injection pressure at 273 days

Oil Mobility Distribution

The distribution of oil mobility in the lean zone area in the two cases is shown in

Figure 6-17. The distribution of the solvent mixture is also shown in this figure to illustrate

the high mobility in the ES-SAGD process. As illustrated, in the SAGD process, the peak

value (261 md/cp) of the oil mobility is at the vapor-liquid interface. It indicates that the

latent heat of steam transfers to the cold bitumen mostly by conduction. In the ES-SAGD

process, the peak value (1226 md/cp) of oil mobility is located in a different zone of the

reservoir. It is mostly in the mobile oil zone. The high mole fraction of the solvent mixture

is at the same location with the high oil mobility. This demonstrates that the solvent has

dissolved into the cold bitumen. Furthermore, after the oil mobility has reduced to zero,

the mole fraction of the solvent was still in a high level along with the increasing distance.

131

This indicates that the solvent has intruded into the lean zones. The light component

(mainly IC4 to NC5) plays an important role in the invasion of the solvent mixture.

Figure 6-17 Comparison of the oil mobility profile in SAGD and oil mobility, solvent

mole fraction profiles in the vapor and oil phase in ES-SAGD with 2500 kPa injection


Thickness of the Lean Zones

As seen, Figure 6-18 shows a quick ramp down in the oil recovery factor in the

SAGD process. With an increase in the number of the lean zone layers, there is more

decreasing in oil recovery. The relationship between recovery and the number of lean zone

layers forms a straight decline curve. Figure 6-19 shows higher oil recovery in the ES-

SAGD process. When running the simulation model with an increasing number of lean

zone layers, it is observed that the thickness of a lean zone affects the ES-SAGD

performance for the initial simulation cases and hence this parameter is important for a

Solvent

invasion

zone

132

small number of lean zone studies. After the lean zone layers are more than 10 layers (5

meters), the oil recovery factor of the ES-SAGD process was not changed. Figure 6-20

shows the oil recovery increasing rate (Equation (6.1)) vs. the number of lean zone layers.

It does confirm that there is quite a difference in the oil recovery increased rate for ES-

SAGD as opposed to SAGD. With increasing the thickness of a lean zone, ES-SAGD

primarily accelerates oil recovery than the SAGD process.

O𝑖𝑙 Recovery Increasing Rate =𝐸SSAGD Oil Recovery Factor−SAGD Oil Recovery Factor

SAGD Oil Rcovey Factor (6.1)

Figure 6-18 Oil recovery factor vs. thickness of the lean zones in SAGD

process

55

56

57

58

59

60

61

62

63

0 5 10 15 20 25

Oil

reco

very

fac

tor,

%


133

Figure 6-19 Oil recovery factor vs. thickness of the lean zones in ES-SAGD process

Figure 6-20 Increasing rate of the oil recovery factor with the variable lean zone

layers

81

82

83

84

85

86

87

88

0 5 10 15 20 25

Oil

reco

very

fac

tor

%


35

37

39

41

43

45

47

49

0 5 10 15 20 25

Oil

reco

very

incr

easi

ng

rate

%

Number of the lean zone layes (m)

134

Comparison of SAGD and ES-SAGD Processes in a Heterogeneous Reservoir

The impacts of lean zones on the SAGD and ES-SAGD processes have been

investigated in a homogenous model. ES-SAGD is proven more efficient over SAGD in

terms of developing mechanisms of a steam chamber and improving the production

performance in homogenous reservoirs. Nevertheless, there is no completely homogenous

reservoir in practice. The reservoir heterogeneities are universal in all geological

formations. Even within the same formation, the variations of reservoir heterogeneities are

significant. It is obvious that variations of water saturation, permeability and porosity

influence the growth of a steam chamber and oil production in the SAGD and ES-SAGD

processes. Therefore, in this section, a 2D heterogeneous model is introduced to investigate

the possible effects further on the SAGD and ES-SAGD processes.

2D Heterogeneous Model Construction and Description

A well-tuned 2D cross-sectional heterogeneous model was cut from a well-

established geological model. The model represents a typical Fort McMurray formation in

the Athabasca region, which is composed of oil sand and a lean zone area in the middle of

the formation. The dimensions of the geological model are 110m in width, 1100m in length,

and 72m in height. Then, the intercepted model is imported into the CMG STARTS

simulator. The simulation model divides the geological mode into 55x11x72 blocks in the

i, j, k directions, a total of 43,560 grids. The dimensions of each grid block are 2x100x1m.

The distributions of reservoir properties including a grid top, permeability, porosity, and

water saturation are shown in Figure 6-21. The connate water saturation of the model is

135

0.2. As observed from Figures 6-23 and 6-24, the lean zones spread extensively in the

reservoir.

The bitumen is characterized by using CMG WinProp. The relationship of the

bitumen and temperature is displayed in Figure 6-22. As seen in Figure 6-23, the well pair

are drilled at the bottom of the reservoir. The injector is 5 meters above the producer. The

perforation intervals of the well pair are 850 meters. Well pair trajectories and water

saturation of the model in the j-k direction of layer 6 are shown in Figure 6-24.

Operation Parameters

Steam is injected at 240 oC with a quality of 0.9. The constraints of the injector are

a maximum surface water rate (STW) with 350 m3 /day in cold water equivalents (CWE),

and the maximum bottom-hole pressure (BHP) with 1300 kPa; the producer is constrained

to a maximum liquid rate at 350 m3 /day. For the initialization of the SAGD process, the

injection and production wells are preheated before the bitumen is produced. The period of

preheating is 9 months. The simulation will be run for 10 years. For the ES-SAGD process,

the type and proportion of injected solvent is the same as in the homogeneous model.

136

A B

C D

Figure 6-21 Properties distribution of two-dimension heterogeneous model (A: Grid

top; B: Permeability; C: Porosity; D: Water saturation)

137

Figure 6-22 Temperature vs. bitumen viscosity plot

Figure 6-23 Well pair trajectories and the water saturation of 2D heterogeneous

model

138

Figure 6-24 Well pair trajectories and the water saturation in cross-section of 2D

heterogeneous model (j-k direction layer 6)

Results and Discussion

Figure 6-25 displays the comparison of cumulative oil production between the

SAGD and ES-SAGD processes. The cumulative oil production in the ES-SAGD case is

much higher than in the SAGD case. After 10 years’ production, the yields of the SAGD

case is 150,734 m3, and the yields of the ES-SAGD case is 436,638 m3. The yields of ES-

SAGD is almost 3 times that of the SAGD case.

Moreover, the cumulative steam-oil ratio (cSOR) of the ES-SAGD case decreases

dramatically compared to the SAGD case. It can also be confirmed from the comparison

of the cumulative steam-oil ratio between the two cases in Figure 6-26. The existence of

139

lean zones in the reservoir leads to high steam consumption and high green-house gases

emission in the SAGD case.

Figure 6-25 Comparison of the cumulative oil production at 10 years

Figure 6-26 Comparison of the cumulative steam oil ratio at 10 years

140

Conclusions of the Chapter

1. The ES-SAGD process improves the production performance in a reservoir with

lean zones compared to the SAGD process.

2. Solvent plays an important role to protect the steam chamber from the lean zones.

The solvent intrudes into the lean zones to prevent the mobile water flowing into

the steam chamber.

3. As the thickness of a lean zone increased more than 5 meters, the oil recovery of

the ES-SAGD process was not changed.

4. The production performance of SAGD and ES-SAGD in the heterogeneous model

with lean zones is consistent with that in the numerical modelling. The ES-SAGD

process reduces the water consumption and improves the oil production.

141

CONCLUSIONS AND FUTURE WORKS

Conclusions

SAGD is a proven thermal method to develop oil sand reservoirs. In practice, the

SAGD process is severely impacted by reservoir heterogeneities especially in reservoirs

with high water saturation zones. In this thesis, we have compared the mechanisms and

performance of SAGD and ES-SAGD in reservoirs with and without lean zones. Moreover,

the comparison of the SAGD and ES-SAGD processes in reservoirs with lean zones

through the numerical simulation has been reported in this study. Furthermore, a filed-scale

geological model, which contains lean zones, was introduced into the study to investigate

the impacts on the SAGD and ES-SAGD process. The conclusions of the study are as

follows:

1. The presence of lean zones severely influences the steam chamber in the SAGD

process. Owing to the high conductivity and mobility of water, the latent heat of

the steam was lost into the lean zones significantly. The heat loss reduced the

efficiency of the steam. The increase of the produced water from lean zones raises

the operation costs.

2. The existence of lean zones in an oil sand reservoir also has negative effects on the

ES-SAGD process. However, the mechanisms of the effect are different when

compared to the SAGD process. Not only did the heat loss reduce the viscosity, the

solvent also acted in a crucial role in the growth of a steam chamber. It intrudes into

the lean zones to prevent the mobile water flowing into the steam chamber. As the

142

lean zones increase to more than 5 meters, the oil recovery of the ES-SAGD process

was not changed.

3. The comparison of production performance between SAGD and ES-SAGD in the

heterogeneous model with lean zones is consistent with that in the homogeneous

modelling. In a reservoir with lean zones, the ES-SAGD process reduces the

negative impacts of lean zones and improves oil production.

In conclusion, the impacts of lean zones on the SAGD and ES-SAGD processes are

investigated. The results demonstrate that the ES-SAGD is an effective method to deal with

lean zones in oil sand reservoirs.

Future Work

The sensitivity analysis of the ES-SAGD process in oil sand reservoirs with lean

zones needs to be conducted, such as concentration of solvent, a type of solvent and

connate water saturation in the reservoirs.

An analytical model of the ES-SAGD process in an oil sand reservoir with lean

zones need to be analyzed.

The effects of lean zones on the SAGD and ES-SAGD process in carbonate

reservoirs need to be investigated in future work.

Other recovery methods such as vapor extraction (VAPEX), foam, pure solvent,

and surfactant are also needed to be tested in reservoirs with lean zones.

143

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