Performance of Steam Assisted Gravity Drainage in Thin Oil Sand Reservoirs: Well Pair Configuration

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2016-01-08 Performance of Steam Assisted Gravity Drainage in Thin Oil Sand Reservoirs: Well Pair Configuration

Zohrehvand, Shiva

Zohrehvand, S. (2016). Performance of Steam Assisted Gravity Drainage in Thin Oil Sand Reservoirs: Well Pair Configuration (Unpublished master's thesis). University of Calgary, Calgary, AB. doi:10.11575/PRISM/27300 http://hdl.handle.net/11023/2737 master thesis

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UNIVERSITY OF CALGARY

Performance of Steam Assisted Gravity Drainage in Thin Oil Sand Reservoirs: Well Pair Configuration

Shiva Zohrehvand

A THESIS

SUBMITTED TO THE FACULTY OF GRADUATED STUDIES

IN PARTIAL FULFILMENT OF THE REQUIREMENTS FOR THE

DEGREE OF MASTER OF SCIENCE

GRADUATE PROGRAM IN CHEMICAL AND PETROLEUM ENGINEERING

CALGARY, ALBERTA

January, 2016

Abstract

Success of Steam Assisted Gravity Drainage (SAGD) depends on reservoir properties and operational parameters. Here, both areas are targeted and performance of SAGD in thin oil sand reservoirs with changing the well configuration is studied. Specifically, the influence of the injection and production wellpair configuration as well as the number of injector wells in a homogeneous formation with thicknesses of 5, 7, and 10m were investigated. The wellpairs were relocated to make different patterns where the spacing between injection and production wells was changed. SAGD performance was assessed numerically and the cumulative steam oil ratio, oil production, heat loss, and oil recovery factor were compared. The results suggest that the horizontal and vertical distances between injectors and the producer well, their locations from over or underburden and their alignments affect the performance of SAGD operation. The results also show that addition of an offset injector well can be beneficial.

Acknowledgements

First and for most I am very grateful to my supervisor Dr. Ian Gates. Thank you Ian for being a great mentor and an incredible human being.

Thank you Dr. Bahareh Khansari for your remarkable comments and great friendship.

Thank you Jacky Wang for the invaluable discussion.

I highly appreciate the financial support of “Werner Graupe” scholarship and Computer

Modeling Group Ltd. (CMG) for providing the reservoir simulator CMG STARSTM.

iii

To my family

Thank you for your unconditional love and support

Table of Contents

Abstract...... ii Acknowledgments...... iii Dedication...... iv Table of Contents...... v List of Tables...... viii List of Figures...... ix List of Symbols, Abbreviations and Nomenclature...... xi

CHAPTER 1: INTRODUCTION...... 1 1.1. Statement of the Problem...... 2 1.2. Objectives of the Thesis...... 3 1.3. Research Methodology...... 3 1.4. Outlines of the Thesis...... 4

CHAPTER 2: LITERATURE REVIEW...... 6 2.1. Oil Sands Recourses...... 6 2.2. Chemistry of Heavy Oil and Bitumen...... 9 2.3. EOR Methodologies...... 11 2.3.1. Cyclic Steam Stimulation (CSS)...... 13 2.3.2. Steam Flooding (SF)...... 15 2.3.3. In-Situ Combustion (ISC)...... 16 2.4. SAGD Process...... 17 2.4.1. SAGD Analytical Model (Butler’s Theory)...... 20 2.4.2. SAGD Variants...... 22 2.4.3. SAGD Performance...... 22 2.5. Thin Oil Sands Reservoirs...... 24 2.6. Well Spacing and Configuration...... 26 2.7. What is Missing in the Literature? ...... 31

CHAPTER 3: PERFORMANCE OF STEAM ASSISTED GRAVITY DRAINAGE IN THIN OIL SANDRESERVOIRS: Well-pair Configuration...... 32 Summary...... 32 3.1. Introduction...... 32 3.2. Reservoir Simulation Model...... 34 3.3. Reservoir Models...... 37 3.3.1. Model H10...... 37 3.3.2. Model H7...... 40 3.3.3. Model H5...... 42 3.4. Results and Discussion...... 45 3.4.1. Model H10...... 45 3.4.1.1. Cumulative Steam-to-Oil Ratio...... 45 3.4.1.2. Cumulative Produced Oil...... 49

3.4.1.3. Oil Recovery Factor...... 52 3.4.1.4. Cumulative Heat Loss...... 54 3.4.2. Model H7...... 57 3.4.2.1. Cumulative Steam-to-Oil Ratio...... 57 3.4.2.2. Cumulative Produced Oil...... 60 3.4.2.3. Oil Recovery Factor...... 62 3.4.2.4. Cumulative Heat Loss...... 64 3.4.3. Model H5...... 66 3.4.3.1. Cumulative Steam-to-Oil Ratio...... 66 3.4.3.2. Cumulative Produced Oil...... 69 3.4.3.3. Oil Recovery Factor...... 71 3.4.3.4. Cumulative Heat Loss...... 73 3.4.4. Best Case Scenarios...... 76 3.4.4.1. Cumulative Steam-to-Oil Ratio...... 76 3.4.4.2. Cumulative Produced Oil...... 77 3.4.4.3. Oil Recovery Factor...... 78 3.4.4.4. Cumulative Heat Loss...... 79 3.4.4.5. Temperature Distributions and Well Pairs Arrangement...... 81 3.5. Conclusions...... 83

CHAPTER 4: PERFORMANCE OF STEAM ASSISTED GRAVITY DRAINAGE IN THIN OIL SANDRESERVOIRS: Well-pair Configuration in a Single Producer-Double Injector Set up...... 85 Summary...... 85 4.1. Introduction...... 86 4.2. Reservoir Simulation Model...... 87 4.3. Reservoir Models...... 91 4.3.1. Model H10-2Inj...... 91 4.3.2. Model H7-2Inj...... 94 4.3.3. Model H5-2Inj...... 96 4.4. Results and Discussion...... 98 4.4.1. Model H10-2Inj...... 99 4.4.1.1. Cumulative Steam-to- Oil Ratio...... 99 4.4.1.2. Cumulative Produced Oil...... 101 4.4.1.3. Oil Recovery Factor...... 103 4.4.1.4. Cumulative Heat Loss...... 105 4.4.2. Model H7-2Inj...... 107 4.4.2.1. Cumulative Steam-to-oil Ratio...... 107 4.4.2.2. Cumulative Produced Oil...... 109 4.4.2.3. Oil Recovery Factor...... 111 4.4.2.4. Cumulative Heat Loss...... 113 4.4.3. Model H5-2Inj...... 114 4.4.3.1. Cumulative Steam-to-Oil Ratio...... 114 4.4.3.2. Cumulative Produced Oil...... 116

4.4.3.3. Oil Recovery Factor...... 118 4.4.3.4. Cumulative Heat Loss...... 119 4.4.4. Best Cases for the Single Producer-Dual Injector Models...... 120 4.4.5. Best Cases for the Single Injector-Single Producer and Dual Injector-Single Producer Models...... 125 4.5. Conclusions...... 128

CHAPTER 5: CONCLUDING REMARKS AND RECOMMENDATION...... 130

REFERENCES...... 132

vii

List of Tables

Table 2-1 API gravity classification of petroleum oil (API, 2013)...... 7 Table 2-2 Screening criteria for choosing an EOR method for an oil resource (modified from Taber et al. 1997)...... 12 Table 3-1 Reservoir simulation model and fluid properties...... 35 Table 3-2 Well placement in Model H10 with a layer thickness of 10 m...... 38 Table 3-3 Well placement in Model H7 with a layer thickness of 7 m...... 41 Table 3-4 Well placement in Model H5 with a layer thickness of 5 m...... 43 Table 4-1 Reservoir simulation model and fluid properties...... 89 Table 4-2 Well placement in Model H10-2Inj with a layer thickness of 10 m...... 92 Table 4-3 Well placement in Model H7-2Inj with a layer thickness of 7 m...... 95 Table 4-4 Well placement in Model H5-2Inj with a layer thickness of 5 m...... 97 Table 4-5 Cross-sectional reservoir view and well configuration for best case scenarios in dual injector-single producer...... 121 Table 4-6 Cross-sectional reservoir view and well configuration for best case scenarios in single injector-single producer and dual injector-single producer models...... 125

viii

List of Figures

Figure 2-1 Schematic representation of oil sand...... 8 Figure 2-2 A cartoon representation of asphaltene molecules: (A) the continental and (B) the archipelago...... 10 Figure 2-3 Schematic representation of Cyclic Steam Stimulation in a vertical well configuration...... 14 Figure 2-4 Schematic representation of steam flooding technology...... 15 Figure 2-5 Schematic representation of In-Situ Combustion method...... 16 Figure 2-6 Cross-sectional view of the Steam-Assisted Gravity Drainage recovery process...... 18 Figure 3-1 Cumulative steam oil ratio versus operation time for Model H10, (A) aligned (B) not aligned, (C) best case scenarios...... 48 Figure 3-2 Cumulative produced oil versus operation time for Model H10, (A) aligned (B) not aligned, (C) best case scenarios...... 51 Figure 3-3 Oil recovery factor versus pore volume steam injected (PVSI) for Model H10, (A) aligned (B) not aligned, (C) best case scenarios...... 53 Figure 3-4 Heat loss versus time for Model H10, (A) aligned (B) not aligned, (C) best case scenarios...... 56 Figure 3-5 Cumulative steam oil ratio (cSOR) versus operation time for Model H7 (A) aligned (B) not aligned, (C) best case scenarios...... 59 Figure 3-6 Cumulative produced oil versus operation time for Model H7, (A) aligned (B) not aligned, (C) best case scenarios...... 61 Figure 3-7 Oil recovery factor versus pore volume steam injected (PVSI) for Model H7, (A) aligned (B) not aligned, (C) best case scenarios...... 63 Figure 3-8 Heat loss versus time for Model H7, (A) aligned (B) not aligned, (C) best case scenarios...... 65 Figure 3-9 Cumulative steam oil ratio (SOR) versus operation time for Model H5, (A) aligned (B) not aligned, (C) best case scenarios...... 67 Figure 3-10 Cumulative produced oil versus operation time for Model H5, (A) aligned (B) not aligned, (C) best case scenarios...... 70 Figure 3-11 Oil recovery factor versus pore volume steam injected (PVSI) for Model H5, (A) aligned (B) not aligned, (C) best case scenarios...... 72 Figure 3-12 Heat loss versus time for Model H5, (A) aligned (B) not aligned, (C) best case scenarios...... 74 Figure 3-13 Steam oil ratio (SOR) versus time for best case scenarios...... 76 Figure 3-14 Cumulative produced oil versus operation time for best case Scenarios.78 Figure 3-15 Oil recovery factor versus pore volume steam injected (PVSI) for best case scenarios ...... 79 Figure 3-16 Heat loss versus time for best case scenarios...... 80 Figure 3-17 Heat loss behaviour for best case scenarios...... 81 Figure 3-18 Wellpair arrangements and temperature distribution for best case scenarios. (A) H10-6, (B) H7-4, (C) H5-5...... 82 Figure 4-1 Cumulative steam-to-oil ratio versus time for Model H10-2Inj cases ....101

Figure 4-2 Cumulative produced oil versus time for Model H10-2Inj cases ...... 102 Figure 4-3 Oil recovery factor versus pore volume steam injected for Model H10-2Inj cases...... 104 Figure 4-4 Heat loss versus time for Model H10-2Inj cases...... 106 Figure 4-5 Cumulative steam-to-oil ratio versus time for Model H7-2Inj cases...... 109 Figure 4-6 Cumulative produced oil versus time for Model H7-2Inj cases...... 111 Figure 4-7 Oil recovery factor versus pore volume steam injected (PVSI) for Model H7-2Inj cases...... 112 Figure 4-8 Heat loss versus time for Model H7-2Inj cases...... 113 Figure 4-9 Cumulative steam-to-oil ratio versus time for Model H5-2Inj cases...... 116 Figure 4-10 Cumulative produced oil versus time for Model H5-2Inj cases...... 117 Figure 4-11 Oil recovery factor versus pore volume steam injected (PVSI) for Model H5-2Inj cases...... 119 Figure 4-12 Heat loss versus time for Model H5-2Inj cases...... 120 Figure 4-13 cSOR versus time...... 122 Figure 4-14 Cumulative produced oil versus time...... 122 Figure 4-15 Oil recovery versus PVSI...... 122 Figure 4-16 Heat loss versus time...... 122 Figure 4-17 cSOR versus time...... 124 Figure 4-18 Cumulative produced oil versus time...... 124 Figure 4-19 Oil recovery versus PVSI...... 124 Figure 4-20 Heat loss versus time...... 124 Figure 4-21 cSOR versus time...... 127 Figure 4-22 Cumulative produced oil versus time...... 127 Figure 4-23 Oil recovery versus PVSI...... 127 Figure 4-24 Heat loss versus time...... 127

List of Symbols, Abbreviations and Nomenclature Symbols Definition

SGoil Specific gravity of the oil Q Oil production rate K Permeability g gravity acceleration ρ Oil density ϴ Inclined angle of the steam interface from horizon µ Oil viscosity ξ Distance from the interface T Temperature Ts Steam temperature Tr Initial reservoir temperature U Velocity of the advancing front Α Reservoir thermal diffusivity Ø Porosity ΔSo (Initial – residual) oil saturation g Gravity acceleration h Reservoir net pay m dimensionless constant νs Oil kinematic viscosity

Abbreviations Definition

API American Petroleum Institute cSOR cumulative Steam-to-Oil Ratio CSS Cyclic Steam Stimulation DWS Downhole Water Sink EOR Enhanced Oil Recovery ES-SAGD Expanding Solvent-Steam Assisted Gravity Drainage HWF Hot Water Flooding ISC In-Situ Combustion OOIP Original Oil In Place SAGD Steam Assisted Gravity Drainage SAGP Steam And Gas Push SF Steam Flooding SOR Steam-to-Oil Ratio VAPEX Vapor Extraction HW Horizontal Well

CHAPTER 1. INTRODUCTION

SAGD is an effective commercial process for viscous oil recovery from oil sands reservoirs with pay zone thickness greater than approximately 15 m (Gates, 2010).

However, in thinner oil sands reservoir (< 10 m), heat losses from the steam chamber to

the overburden and understrata are significant and therefore oil recovery will be

achieved at the cost of higher energy consumption or cumulative steam-to-oil ratio

(cSOR) compared to that of thicker reservoirs. This also implies that CO2 emissions per

unit volume oil produced will likely be higher in thinner reservoir than would be the case

from thicker reservoirs. The importance of thin oil sand reservoirs lies in the fact that

about 80% of oil sands resources exist in reservoirs with a net pay zone of less than 5 m

in Western Canada (Adams, 1982). Thus, there is a need for new efficient processes to

produce these resources.

Documented research on the design of recovery processes for thin oil sands reservoirs is

scarce. Zhao et al. (2014) discussed different thermal recovery strategies to produce

from thin (< 5 m) heavy oil reservoirs. They investigated four production methods

consisting of cold production without sand, alternating injection/production well steam

and hot water, steam flooding, and SAGD. They found that first and second processes

are not suitable due to high energy to oil ratio and relatively low recovery factor. Both

steam flooding and SAGD are applicable but they still suffer from large steam use. The

steam cost or cSOR can be reduced by using solvent as was investigated by Gates (2010)

and Zhao et al. (2013). These studies focused on heavy oil reservoirs where the in situ

viscosity of the oil is of order of thousands to a few tens of thousands of centipoise.

The focus of the research documented in this thesis is on the application of SAGD in thin

oil sands reservoirs (≤ 10 m) where the viscosity of the oil at original reservoir conditions is of order of 1 million cP. Since the cost of steam is the major expense of SAGD operation and main contributor to carbon dioxide emissions from the process, our aim is the reduction of cSOR through proposing various well configurations to achieve higher oil production.

1.1. Statement of the Problem

In spite large steam consumption, steam flooding and SAGD are potentially applicable

processes in thin oil sands reservoirs (Zhao et al., 2014). However, reduction of high steam use per unit oil recovered poses a challenge. It is known that reservoir parameters as well as operational parameters influence oil recovery and SAGD performance. For example, decreasing the oil column thickness raises heat losses and therefore the cSOR increases. In comparison with conventional SAGD, well pair configuration can be changed through vertical and horizontal positioning as well as changing the ratio of injector to producer wells. There is potential that different well configurations may lead to delayed production or faster steam breakthrough thus ultimately changing and hopefully improving the SOR. There is a need for a detailed

study to address these parameters when all other operational and reservoir parameters

kept constant. The main research question being investigated, within the context of

SAGD-like processes, here is how can well configuration be altered to improve the efficiency and recovery factor in reservoirs that are thinner than 10 m?

1.2. Objectives of the Thesis

The main objective of this thesis is to study the performance of SAGD operation in thin

oil sands reservoir with a thickness of (≤ 10 m). The key issue, as reported in the literature (Gates 2008; Gates 2010), suggests that the major challenge faced by thermal

(steam) recovery processes for thin reservoirs are heat losses to the overburden and understrata – that is, the energy efficiency of the process is the key challenge. However, if the residence time of steam is relatively short in the reservoir, there is potential that the energy efficiency of the process could be improved by altering the well configuration including spacing between wells and their vertical locations.

1.3. Research Methodology

The research question has been answered by using detailed thermal reservoir

simulation. In a thermal reservoir simulator, the material and energy balances are

solved by using a numerical method – in this case, the domain is tessellated into grid

blocks and the finite volume method is used. In the research documented here, the

commercial thermal reservoir CMG STARSTM was used (CMG, 2013).

In total, 59 cases were studied each having different well configurations in three

reservoir thicknesses: 5, 7, and 10 m. Specifically, 11 single injector-producer well pairs

and 10 double injector-single producer well pairs were evaluated in the case where the

reservoir thickness was equal to 10 m (these cases are referred to as Model H10).

Similarly, in the 7 m reservoir model (referred to as Model H7), 8 numbers of single

injector-producer well pairs and 8 number of double injector-single producer well pairs

were tested. Finally, in the 5 m reservoir model (Model H5), 13 numbers of single

injector-producer well pairs and 9 number of double injector-single producer well pairs

were simulated. For each model, the performance of the recovery process was

evaluated on the basis of its cumulative steam oil ratio, cumulative oil production,

cumulative heat loss, and oil recovery factor.

1.4. Outline of the Thesis

Chapter 1 presents an overview on the thesis including a general introduction, statement of the problem, objectives, research methodology and the outline.

Chapter 2 provides a general literature review on oil sands and in particular, recovery of thin oil sands reservoirs. This includes oil sands resources, composition and chemistry.

Enhanced Oil Recovery (EOR) methodologies are discussed with a focus on thermal recoveries. As SAGD is the method of choice for thicker oil sands reservoirs, in this research work, it is briefly reviewed in Chapter 2 (process description, Butler’s theory, variants of SAGD, SAGD challenges, and SAGD performance).

Chapters 3 and 4 contain the main research work. Both chapters have been submitted as two manuscripts to peer-reviewed journals.

Chapter 3 describes the performance of Steam Assisted Gravity Drainage in thin oil sand reservoirs using single injector-single producer well pair configuration. Specifically, the influence of the injection and production well pair configuration in a homogeneous formation with thicknesses of 5, 7, and 10 m was investigated. The wellpairs were relocated to make different patterns where the spacing between the injection and production wells were changed both horizontally and vertically. Also their locations with respect to the overburden and understrata rock were varied.

Chapter 4 presents an analysis of the performance of Steam Assisted Gravity Drainage in thin oil sand reservoirs using single producer-double injector well arrangement. The results of this study are compared with the results of best case scenarios in Chapter 3.

Chapter 5 lists concluding remarks and recommendations for further research.

CHAPTER 2. LITERATURE REVIEW

2.1. Oil Sands Resources

The oil sands deposits hosted in Western Canada are the third largest proven deposit of crude oil in the world (Natural Resources of Canada, 2013). Canada, along with

Venezuela holds 90% of the world’s heavy oil and bitumen (Nasr, 2005). The largest

reserves of bitumen are located in the Athabasca, Cold Lake and Peace River oil sands

deposits in Alberta with the average deposit depth of 300, 400, and 500 m, respectively

(Nasr, 2005).

The Athabasca oil sands were first explored by Pond in 1778 and a geological survey was initiated in 1875 (Govier, 1965). The first wells were drilled between 1897 and 1898 at

Pelican Rapids on the Athabasca River (Govier, 1965). According to the Alberta

Department of Energy (ADOE, 2014), 167.2 billion barrels of proven reserves in the oil

sands deposit exist in Northern Alberta. Nearly 80% are recoverable through in-situ

recovery processes whereas the remainder is shallow enough to be recovered by

surface mining. One of the key uncertainties for oil sands reservoirs is the choice of the

recovery process that will yield the greatest recovery factor and rates at target water

consumption and greenhouse gas emissions. The two most used recovery processes for

oil sands reservoirs are the Cyclic Steam Stimulation (CSS) and Steam-Assisted Gravity

Drainage (SAGD) processes (Gates, 2013). Each one of these processes uses different recovery mechanisms and as a result, the choice of the recovery process itself is a factor that affects recovery from the reservoir. For example, steam assisted gravity drainage leads to about 50-60% recovery in comparison with cyclic steam stimulation which reach to around 35-40% (ADOE, 2014).

Crude oil is classified based on the API gravity, defined by 141.5/SGoil – 131.5 (SGoil is the specific gravity of the oil), in four major types known as light, medium, heavy, and extra heavy. The lower the API gravity, the higher the oil viscosity. Table 2-1 lists different types of crude oil based on API.

Table 2-1 API gravity classification of petroleum oil (API, 2013).

Classification API gravity Viscosity, cP

Light > 31.1 < 10

Medium 22.3 - 31.1 10 - 100

Heavy 10 - 22.3 100 - 10,000

Extra Heavy < 10 > 10,000

Bitumen is categorized as extra heavy oil and has a typical API gravity of 5 to 9 with a viscosity of > 10,000 cP at room temperature (Speight, 2007). Oil sands are a mixture of sand, water, clay and bitumen (Kleindienst, 2005). For a typical McMurray Formation oil

sands reservoir, the oil sand contains about 83% sand, 14% bitumen and 3% water (Nasr

and Ayodele, 2005). As stated by Speight (1978), a typical composition for Athabasca bitumen is 84% Carbon, 10% Hydrogen, 0.9% Oxygen, O.4% Nitrogen and 4.7% Sulphur.

Fig. 2-1 illustrates a typical composition of oil sands.

Figure 2-1 Schematic representation of oil sand.

Observations of oil sands grains suggest that the particles are water wet and thus they are coated by water film which may hold clay particles (Cottrell, 1963) as shown in Fig.

2-1. Bitumen sits within the pore space between the water films. The viscosity of

bitumen depends on temperature and drops significantly as the temperature raises.

Raicar and Proctor (1984) investigated the relationship between viscosity and

temperature for light crude oil, heavy oil, and several bitumens. They showed that the

initial viscosity (at about 10 ⁰C) is highest for Athabasca (106 cP), followed by Cold Lake

(105 cP) and Lloydminster (103 cP) deposits and it drops to around 100, 80 and 8 cP,

respectively, at elevated temperature of about 300 ⁰C.

2.2. Chemistry of Heavy Oil and Bitumen

The hydrocarbon components of petroleum can be divided in three classes known as

paraffins (saturated hydrocarbons, no ring structures), naphthenes (saturated hydrocarbons with one or more rings), and aromatics (hydrocarbons with one or more aromatic rings) (Speight, 2007). Bitumen is a complicated mixture of hydrocarbons, consisting of 105 to 106 different molecules (Wiehe, 1999). It is very difficult to

characterize all the components. However, it is possible to classify them in groups of

compounds by utilizing different techniques such as distillation, solubility/insolubility,

and adsorption/desorption (Wiehe, 1999). The most common standard method

applicable to bitumen or heavy oil is to separate them in four general solubility groups

known as saturates, aromatics, resins, and asphaltenes (ASTM, 1999).

The viscosity of petroleum is significantly influenced by the presence and concentration

of asphaltenes. Asphaltene is defined as a fraction of petroleum that is not soluble in

paraffinic solvents, e.g. heptane, but soluble in aromatic solvents. The molecular

structure of bitumen and asphaltenes consists mostly of C-C, C-H, C=C bonds (in the

aromatic rings) and to a lesser degree C-S, C-O, C-N, S-H, and O-H covalent bonds. The

9 metal impurities are mostly attached to nitrogen in porphyrin and non-porphyrin structures (Rahimi and Thomas, 2006). As a result molecular aggregation occurs.

Generally, two structural models are suggested for asphaltene (Rahimi and Thomas,

2006; Schulze et al., 2015) known as continental and island (archipelago) models.

Representations of these two models are illustrated in Fig. 2-2. In reality the asphaltene is a combination of these two structures with different percentages. In the continental model, asphaltenes are composed of large aromatic cores that also contain hetero- aromatics and metallo-porphyrins. The aromatic cores are surrounded by functional groups, including alkyl groups and alkyl carboxylic acids (Mullins et al., 2012). In the archipelago model, smaller aromatic islands are joined together by alkyl chains (Gray et al., 2011).

Figure 2-2 A cartoon representation of asphaltene molecules: (A) the continental and (B) the archipelago.

Due to their high viscosity, heavy oil and bitumen recovery processes require the

application of enhanced oil recovery methods. Under natural conditions, the oil is too viscous to flow under primary drive mechanisms to the surface.

2.3. EOR Methodologies

Generally, to enable oil production after primary and secondary recovery processes,

enhanced oil recovery methods are applied to a reservoir. In typical practice, EOR is

performed via injection of a fluid into the reservoir to displace the remaining oil in the

reservoir. Displacement can be immiscible or miscible depending on the material

injected into the reservoir. In miscible displacement, the interfacial tension between the injectant and oil is equal to zero. In immiscible displacement, the injected phase displaces the oil phase from the reservoir. The overall displacement efficiency is related to wettability, capillary pressure, interfacial and surface tension forces, and relative permeability as well as the reservoir heterogeneity and oil to injectant mobility ratio

(Terry, 2001). Another key factor that influences the efficiency of oil displacement from the reservoir is the physical arrangement of injection and production wells.

Enhanced oil recovery methods can be categorized as miscible, chemical, thermal and microbial flooding processes (Terry, 2001). This classification is based on the main mechanism of oil displacement and formation lithology (Kokal and Al-kaabi, 2010).

These oil mobilization mechanisms are known as oil viscosity reduction, solvent oil

extraction, and alteration of wettability. Miscible EOR is applicable to light oil reservoirs

11 through gas injection (e.g. carbon dioxide). Chemical EOR is based on mobility control by adding polymers to reduce the mobility of the injected water and/or reduction of interfacial tension through addition of surfactants, and/or alkali. Thermal EOR is generally suitable for heavy oil and oil sands recovery. Thermal energy increases the oil temperature leading to oil viscosity reduction in the reservoir. The main thermal EOR strategies include in-situ combustion and steam injection e.g. steam flooding, steam- assisted gravity drainage, and cyclic steam stimulation.

The choice of an EOR method depends on various reservoir properties such as depth, thickness, porosity, permeability, oil saturations, initial hydrocarbon viscosity, density, and composition (Gates, 2013). Some of the screening criteria for choice of suitable EOR methods are summarized in Table 2-2 (Taber, 1997). According to Table 2-2, the method of choice for highly viscous and permeable reservoir is the application of thermal energy utilizing steam.

Table 2-2 Screening criteria for choosing an EOR method for an oil resource (modified from Taber et al. 1997).

Method Gravity Viscosity Lithology Net Average Depth (°API) (cP) thickness permeability (ft) (ft) (md) Immiscible > 12 < 600 Not critical Not Not critical > 1,800 gases critical Polymer > 15 < 150 Sandstone Not > 10 < 9,000 preferred critical Combustion > 10 < 5,000 Highly porous > 10 > 50 < 11,500 sandstone Steam > 8 < 200,000 Highly porous > 20 > 200 < 4500 sandstone Surface > 7 Mineable oil > 10 Not critical > 3:1 mining sand Overburden/sand

Generally, the main aim in recovery of extra heavy oil (bitumen) is the reduction of viscosity to make it mobile. Thermal methods, as well as solvent aided methods or their combinations, are considered as good choices. Thermal methods are usually used for oil recovery in heavy and extra heavy oils (Farouq-Ali, 2003). The main technologies based on thermal recovery are Cyclic Steam Stimulation (CSS), Steam Flooding (SF), In-Situ

Combustion (ISC), Steam-Assisted Gravity Drainage (SAGD), and Hot Water Flooding

(HWF). The choice of these thermal methods is dependent on the reservoir

characteristics. For example, Mukhametshina et al. (2014) evaluated the recovery

characteristics of bitumen (8.8 API, 53,000 cP at 21 ⁰C) through application of four

thermal recovery methods including SAGD, HWI, SF and ISC. At their specific reservoir

condition, ISC showed the highest recovery factor and HWI the lowest recovery. SAGD

came second but at higher energy cost. SF showed similar results as WF but again at

higher energy consumption. They suggested that a hybrid method consist of HWI and

ISC works best for their particular reservoir.

2.3.1. Cyclic Steam Stimulation (CSS)

CSS method works based on the injection of steam at high pressure and temperature

into a reservoir. In the first step, steam is injected over a period of time into the

reservoir. In some operations, this is done above the fracture pressure and thus steam

fracturing is done in the reservoir (Gates, 2013). In other cases, steam is injected under

the fracture pressure. After the steam injection period is done, the well is shut in and

13 the hot steam zone in the reservoir further distributes its heat to oil sand there – this is referred to as the soak period. The heated bitumen now has lower viscosity than its original value, typically in the hottest zones of the reservoir equal to less than 20 cP.

The soak period may take up to 2 weeks. After the soak period is complete, the well is re-opened for production and reservoir fluids are produced from the reservoir. After the production rate of oil has dropped to a threshold value, the well is shut in and the cycle starts again with steam injection. Typical recovery factors for CSS range from 20% to 40% of the original oil in place (OOIP) with steam-to-oil ratios between 3 and 5

(Gates, 2013; Santos et al., 2014). A schematic representation of three steps in CSS technology including injection, soak and production is illustrated in Fig. 2-3 in a vertical well configuration.

Figure 2-3 Schematic representation of Cyclic Steam Stimulation in a vertical well configuration.

2.3.2. Steam Flooding (SF)

SF is based on continuous injection of high-pressure steam through a vertical injector into a reservoir to create a hot zone which moves continuously across the reservoir displacing oil to production wells. The latent heat of steam is transferred into the oil zone and decreases the viscosity and thus raises the oil mobility. Steam zone is expanded and the mobile oil is derived towards a vertical producer. In typical practice, the oil recovery is about 50% of OOIP (Matthews, 1983; Nasr, 2005). A schematic representation of SF technology is illustrated in Fig. 2-4.

Figure 2-4 Schematic representation of steam flooding technology.

2.3.3. In-Situ Combustion (ISC)

The process was patented in 1923 in USA and it is known as the oldest thermal recovery method (Breston, 1958). A schematic representation of ISC technology is depicted in Fig.

2-5.

In-situ combustion works based on the oxidation of a small fraction of the reservoir oil.

Then, the combustion zone heats the oil and generates gas that displace the oil towards the production well (Breston, 1958; Kendall, 2009). Although ISC appears to be an effective recovery method for conventional as well as bitumen and heavy oil reservoirs

(Dayal et al., 2010), there have been no strong success cases in field operations.

Figure 2-5 Schematic representation of In-Situ Combustion method.

In bitumen and heavy oil application, the combustion front must be kept at high temperature to provide the heat to keep the oil mobilized (Alamatsaz et al., 2011). This implies that the Air-to-Oil Ratio (AOR) and the injection pressure are critical parameters for process operation.

2.4. SAGD Process

Butler et al. (1981) combined the idea of bitumen mobilized by steam injection and gravity drainage with the horizontal wellpair concept for the first time in Alberta in

1979. According to Edmunds and Chhina (2001), the Steam-Assisted Gravity Drainage

(SAGD) concept was used at an earlier time in steam flooding process using vertical wellpairs in California (Doscher, 1966). The gravity drainage concept is depicted in Fig.

2-6. The main idea behind this method is rising of the injected steam at the bottom of reservoir to heat up and decrease the oil viscosity. As a result the mobile oil and steam condensate falls due to gravity and are collected simultaneously at the lower production well.

In SAGD, a horizontal injection well and parallel horizontal production well is drilled near the bottom of the reservoir with a certain vertical distance (e.g. 5 m) between them.

Prior to steam injection, the well pair is heated up by steam circulation to establish a thermal communication between them. Then steam is introduced to the reservoir

through upper well and the mobile heavy oil and condensate are produced from the

reservoir through the lower well. A steam chamber develops in the chamber as oil is

drained from it. In the vertical direction, the steam chamber expansion rate is rapid until

it reaches the overburden cap rock. Thereafter, the steam chamber expands sideways

and downwards in the reservoir. At the edge of the chamber, steam loses its latent heat

to the oil sand and the bitumen beyond the edge of the chamber is heated via thermal

conduction.

Figure 2-6 Cross-sectional view of the Steam-Assisted Gravity Drainage recovery process.

The size of steam chamber and its uniform growth depend on how well the steam is distributed within the reservoir and how uniform heat transfer is occurring at the edge of the steam chamber. Permeability heterogeneity (Gotawala et al., 2010) and wellbore undulation (Shen, 2011) can lead to a non-uniform steam chamber development in

SAGD.

Heat transfer is a vital element of SAGD. Various studies have been done to pin down the importance and dominancy of convective and conductive heat transfer at the interface or edge of SAGD steam chamber. Butler and Stephens (1981) considered thermal conduction as the main heat transfer mechanism in SAGD operation and regarded thermal convection as negligible. Further studies performed by Reis (1992),

Liang (2005) and Nukhaev et al. (2006) supported that idea. Farouq-AIi (2005) drew the attention to the large volume of flowing steam condensate and expressed thermal convection as dominant heat transfer mechanism. Ito and Suzuki (1996) using numerical simulation showed that convection is dominant as well. Edmunds (1999) and Ito (1999) suggested that the ratio of thermal convection to conduction is either less than 5%

(Edmunds, 1999) or around 55% (Ito, 1999), respectively. Sharma and Gates (2011) showed that thermal convection provides a contribution to heat transfer at the edge of the steam chamber. However, the increase in the heat-transfer rate by convection may not necessarily translate to higher oil rates. They explained this behavior by relative permeability effects at the chamber edge. Irani and Ghannadi (2013) investigated the relative role of thermal convection in heat transfer through development of a

19 mathematical model by including both convection and conduction heat transfer to solve the energy balance and pressure-driven condensate flow normal at the edge of SAGD steam chamber. They concluded that convection can transfer a relatively large amount of heat at the edge of steam chamber. However, it cannot be translated to high temperature enhancement and supported the assumption of conduction-dominated heat transfer. Irani and Gates (2013) spread more light on the subject of heat transfer in

SAGD process and investigated the relative roles of convective heat flux both parallel and normal to the edge of the steam chamber. They suggested that the convective heat flux associated with flow parallel to the chamber edge is minor compared with that normal to the edge.

2.4.1. SAGD Analytical Model (Butler’s Theory)

Butler et al (1981) derived the oil production (drainage) rate equation for the SAGD process based on the assumption of conductive heat transfer and Darcy’s Law. The final result was:

2 = 2 ∅∆𝑆𝑆𝑜𝑜𝑘𝑘𝑘𝑘𝑘𝑘ℎ 𝑞𝑞 � 𝑚𝑚𝑣𝑣𝑠𝑠

where

q = Oil production rate

Ø = Porosity

ΔSo = Difference between Initial and residual oil saturation

K = Permeability

g = Gravity acceleration

α = Reservoir thermal diffusivity

h = Reservoir net pay

m = dimensionless constant, varies between 3 to 5 and depends on the oil

viscosity-temperature relationship

νs = kinematic oil viscosity

The temperature profile beyond the edge of the chamber used to derive this result is as follows:

= 𝑈𝑈𝑈𝑈 𝑠𝑠 − 𝑇𝑇 − 𝑇𝑇 𝛼𝛼 𝑠𝑠 𝑟𝑟 𝑒𝑒 where 𝑇𝑇 − 𝑇𝑇

T = Temperature

Ts = Steam temperature

Tr = Initial reservoir temperature

U = Velocity of the advancing front

ξ = Distance from the interface

α = Reservoir thermal diffusivity

Butler’s theory reveals that the oil production rate depends on several reservoir

parameters including the porosity, permeability, net pay thickness, reservoir thermal

diffusivity, bitumen kinematic viscosity and initial oil saturation.

2.4.2. SAGD Variants

One of the drawbacks of SAGD is its high steam consumption and therefore high cost of steam production as well as higher greenhouse gas emissions (from carbon dioxide resulting from the combustion of fuel for steam generation). There are several

technologies that have been developed in an attempt to reduce the energy and

environmental intensities of SAGD. These include the Steam And Gas Push (SAGP,

Butler, 1998; Jiang et al., 2000; Ito et al 2001), Expanding Solvent SAGD (ES-SAGD,

Butler, 1998; Nasr, 2005; Gates and Chakrabarty, 2008), and Vapor Extraction (VAPEX,

Butler, 1998) processes. In these three methods, additives are co-injected into the reservoir with steam. They all use the same well configuration as that of SAGD. These processes will not be discussed here as they are not the focus of the research documented in this thesis.

2.4.3. SAGD Performance

The success of SAGD performance depends on the reservoir properties as well as

operational parameters. Reservoir properties include porosity, thickness, gas saturation,

permeability, viscosity and API gravity, wettability, heterogeneity, lithology, and geo-

mechanics. Operational parameters include start-up procedure and steam quality,

length, spacing and, placement of horizontal wells, sub-cool temperature or steam trap

control, pressure, steam chamber monitoring and size estimation, and well bore design.

The influence of these parameters has been investigated by various researchers. For

example Albahlani and Babadagli (2008) conducted a review on the influence of both operational and reservoir properties on SAGD performance.

Sasaki et al. (1999, 2001) performed an experimental investigation with laboratory scale together with reservoir simulation to study the role of reservoir layer thickness, steam injection pressure and vertical spacing between SAGD well pair. Das (2005) conducted a study based on analytical and simulation results and discussed role of well bore design and operating pressure on SAGD performance and oil recovery rate. He reported that lower operational pressure causes more challenging lift processes. However, low pressure works in favour of water treatment at later time due to lower H2S production

and reduction in the amount of dissolved silica.

Carlson (2003) investigated the role of geomechanics and its influence on SAGD

production. Geo-mechanics directly ties with properties such as sampling procedure

(e.g. coring), formation properties (e.g. permeability, porosity, bitumen, water and gas

saturations), shearing and dilation. Therefore, by changing the operational conditions it

is possible to use geo-mechanics in favour of SAGD performance.

Su et al. (2012) developed a detailed 3D point bar model to determine the impact of

heterogeneity on SAGD performance in the McMurray Formation in the Long Lake area.

Their results revealed that SAGD orientation within the heterogeneous point bar has an

influence on the performance of SAGD. However, it requires more investigation to find out specific well pairs arrangement to achieve an optimized cSOR and oil recovery.

Wang and Leung (2015) investigated the effect of lean zones and shale distribution on

the performance of SAGD in typical Athabasca oil sands with a pay zone of 30 m. In

particular, they studied heterogeneous distribution of shale barriers and lean zones

through variation of location, continuity, size, saturation, and proportions.

2.5. Thin Oil Sands Reservoirs

In thin oil reservoirs, in the literature, this is any reservoir that has thickness less than

about 15 m. For example Adams (1982) defined the thickness as < 5 m, whereas Gurgel

et al. (2009) described it as 5 to 15 m, and Feng et al. (2014) as 4 to 10 m and so on. In

this research work we classified a thin oil sands reservoir as any oil sands reservoir with

thickness less than 10 m.

About 80% of oil sand resources exist in reservoirs with a net pay zone of less than 5 m

in Western Canada (Adams, 1982). Thus, there is a need for new efficient processes or

strategies to produce these resources. In spite of potentially large steam consumption,

steam flooding and SAGD are potentially applicable processes in thin oil sands reservoirs

(Zhao et al., 2014).

Doscher and El-Arabi (1983) studied a pilot steam injection process in thin oil sands reservoir (about 5 to 7 m in thickness) in California. They concluded that a higher steam

injection rate at the beginning of the process leads to higher oil recovery due to faster

arrival of the oil bank to producer well. Feng et al. (2014) investigated the parameters

affecting the steam breakthrough in a steam flooding operation in thin layer ultra-heavy

oil reservoirs (viscosity ≥ 50,000 cP) with a thickness of 4 to 10 m. Their results implied that the formation of a steam breakthrough channel depended on the reservoir permeability and oil saturation. They suggested that injection of nitrogen foam at initial stage of steam breakthrough can help the process by hindering the steam breakthrough.

Gates (2010) evaluated the operating conditions of ES-SAGD in thin heavy oil reservoirs

with a thickness of 8 m. Specifically, he used stochastic optimization to determine the

optimal injection pressure and solvent concentration in the injected steam. The results

of the study revealed that these two parameters have an impact on the system energy

efficiency. A comparison between SAGD and ES-SAGD showed that ES-SAGD leads to

lower steam and energy usage than that of SAGD. Furthermore, it was shown that the

performance of an optimized thermal-solvent added process is comparable to VAPEX. It

implies that the injected steam provides sufficient thermal energy to keep the area near

the wellpair hot. Thus, solvent remains longer in the vapor phase and leads to

promotion of the oil mobilization process.

Gurgel et al. (2009) studied the influence of operational parameters in steamflooding

process in thin oil reservoirs with a thickness of 5 to 15 m. They concluded that

horizontal permeability, water and oil zone thicknesses, and thermal conductivity have

an influence on cumulative oil production. A reservoir of 5 m height showed a better

response to optimization process (steam injection rate and well distances).

Chang (2013) investigated the application and economics of horizontal well (HW)-CSS

for thin oil sand and heavy oil reservoirs. It was shown that HW-CSS is not economical

for layer thicknesses of 5 to 8 m. While a thickness of 11 m with production duration of

8 years using 8 well pads will be economical.

2.6. Well Spacing and Configuration

Well configuration and spacing or the pattern of SAGD well pairs within the reservoir can be defined in different ways to achieve different contributions from different drive mechanisms. Usually, well spacing reflects the distance between SAGD well pairs and is

assumed as repeated within the overall pattern of the SAGD well pairs. The configuration indicates the vertical and horizontal distances or offsets between the

SAGD wells in each repeat unit. The SAGD well pair configuration can include horizontal,

vertical or slanted well arrangements. Here a review is given on the studies that are

conducted on both well pair spacing and configurations and their subsequent influence

on SAGD performance.

Joshi (1986) investigated the SAGD performance through laboratory experiment by comparing cSOR in vertical and horizontal well configuration. The results showed that horizontal SAGD gives a better performance. Miller and Xiao (2007) proposed a well configuration in which vertical wells are drilled in between classical SAGD well pair spacing in a heavy oil reservoir with a pay thickness of 20 m to improve the production.

They stated through field observation and numerical simulation that vertical production wells are able to produce the remaining oil not produced by horizontal producer wells leading to increased oil recovery. Jimenz (2008) performed an analysis on the

performance of SAGD projects in Canada and found out that a inter well pair spacing of

100 m is the most common with the best results with respect to field performance and

that SAGD is mostly applicable to reservoirs with a net pay zone greater than 15 m.

Mojarab et al. (2011) proposed dipping-injector SAGD well configuration for application

in Athabasca and Cold Lake reservoirs with a pay zone thickness of 20 m. Their

simulation results revealed a better performance in comparison with conventional SAGD through an improvement in thermal efficiency and growth of a more uniform steam chamber.

Cheung (2013) investigated the influence of SAGD well spacing while considering central

processing facility constraints (steam supply and fluid processing capacity). She reported

that the optimal well spacing is around 85 to 125 m with the most economical distance

of 100 m. Verney (2015) investigated the role of well pair length and spacing on SAGD

production through assessment of cSOR, bitumen rate and recovery factor for 1,111

well pairs in the McMurray Formation. Well pair spacing and length were varied in the

range of 40 to 160 m and 400 to 1400 m, respectively. He concluded that well length

does not influence SAGD performance. However, tighter inter-well spacing lead to lower cSOR and higher recovery factors. Gupta et al. (2015) investigated the impact of well spacing on SAGD solvent aided processes (SAGD/SAP) using results from a field trial in a net pay zone of 24 m. Their results confirmed that it is feasible to apply a wider spacing in SAGD/SAP system in comparison with conventional SAGD. Thus, SAGD/SAP requires less number of well pairs which in turn reduces the cost, footprint of surface facilities and the environmental impact.

The well configuration in conventional SAGD consists of a parallel horizontal well pair which is drilled 5 m apart. Different well configurations have been presented in the

literature to improve SAGD performance. However, there are not many studies

contributed to the bituminous thin oil reservoirs of thickness less than 10 m. Here,

several studies on the SAGD well configuration are reviewed.

Tamer and Gates (2012) investigated the impact of position and geometry of the injector wells in a McMurray Formation reservoir model with properties drawn from the

Dover SAGD Phase B. The reservoir thickness is equal to 24 m. In this study, different injector well configurations including typical SAGD, offset SAGD and vertical/horizontal well combination were evaluated. They suggested that a number of vertical injectors can deliver steam to the reservoir more efficiently than a single horizontal well at early stages of the process. This is due to smaller exposure of steam chamber to the overburden. Regarding offset SAGD, they found out that greater offset leads to the creation of larger steam-chamber volume and therefore higher oil recovery. However, the initiation of thermal communication between the injection and production wells at the start of the process revealed to be both challenging and demanding of relatively large volumes of steam.

Tavallali et al. (2011, 2012) investigated the impact of well configurations for SAGD in

Athabasca McMurray Formation with a net pay thickness of 20 m and in Lloydminster heavy oil reserve with a net pay thickness of 10 m. The viscosity of the oil in the

Lloydminster reservoir was equal to 5000 cP at the reservoir temperature. According to

Tavallali et al., under certain circumstances, it is possible to increase well spacing because the lower viscosity allows for establishment of easier thermal communication between the well pairs in comparison with higher viscosity reservoirs such as those in the McMurray Formation where the viscosity of the oil is typically above 1 million cP.

Different well configuration including conventional SAGD, vertical injector, reversed

horizontal injector, inclined injector, parallel inclined injectors and multi lateral

produced were proposed and studied via numerical simulation for Athabasca reservoirs.

They observed no advantage in using vertical injectors in Athabasca reservoirs – this

contradicts Tamer and Gates’ results and results obtained from field operations (Miller

and Xiao, 2007). The best result was obtained with the application of reversed

horizontal steam injectors. Different well configurations including conventional SAGD,

offset injector, multi lateral producer and ZIGZAC pattern were proposed for thinner

Lloydminster reservoir (Tavallali et al., 2012). Their results revealed that a maximum

offset distance of 12 m leads larger drainage volume but at higher cost of cSOR. The

multi lateral configuration showed the most optimum results with a cSOR of about 5

m3/m3.

Among the conducted studies on the SAGD well pair configuration, it was found that there are few dedicated to the role of vertical well pair spacing on SAGD performance

especially in case of thin oil sands reservoirs of ≤ 10 m. Sasaki et al. (1999), based on their laboratory experimental results, concluded that oil production rate increases with increasing vertical spacing in a conventional SAGD well pair configuration. However, it comes with the cost of longer lead time for gravity drainage to initiate oil production. In another study, Sasaki et al. (2001) suggested that the decrease in vertical spacing causes faster establishment of thermal communication and an increase in spreading rate of steam and leads to higher amount of oil production.

Tavallali et al. (2011) investigated the impact of vertical well distance on SAGD performance in Athabasca McMurray Formation with a net pay thickness of 20 m. It was shown that the preheating period is shortened when the distance is less that 5 m

(conventional SAGD) with no significant effect on SAGD performance. The performance was decreased with increasing the vertical distance. They reported that a distance within range of 3 to 6 m is desirable with an optimum distance of 4 m.

2.7. What is Missing in the Literature?

The literature review reveals that a large number of studies of the SAGD process has been conducted to improve its performance by altering the operating strategy and the well configuration. However, there are none that investigate how well configuration can be modified to improve the performance of SAGD in thin (less than 10 m) oil sands reservoirs (reservoirs with oil viscosity of order of a million cP). The research documented in this thesis fills this gap.

CHAPTER 3. PERFORMANCE OF STEAM ASSISTED GRAVITY DRAINAGE IN THIN OIL SAND RESERVOIRS: WELL CONFIGURATION

Summary

The performance of Steam Assisted Gravity Drainage (SAGD) is studied in thin oil sand reservoirs. Specifically, the influence of the injection and production well pair configuration in a homogeneous formation with thicknesses of 5, 7, and 10 m was investigated. The well pairs were relocated to make different patterns where the spacing between the injection and production wells were changed both horizontally and vertically. Also their locations with respect to the overburden and understrata rock were varied. SAGD performance was assessed numerically via a thermal reservoir simulator and the cumulative steam oil ratio (cSOR), cumulative oil production, cumulative heat loss, and oil recovery factor were compared.

3.1. Introduction

SAGD is an effective commercial process for viscous oil recovery from oil sands reservoirs with a pay zone thickness of greater than approximately 15 m (Gates, 2010).

However, in thin oil sands reservoirs with thickness lower than 10 m, heat losses from the steam chamber to the overburden and understrata are significant and therefore oil

recovery will be achieved at the cost of higher energy consumption or cumulative

steam-to-oil ratio (cSOR) compared to that of thicker reservoirs. This also implies that

carbon dioxide emissions per unit oil produced will likely be higher in thinner reservoir

than would be the case from thicker reservoirs. The importance of thin oil sand

reservoirs lies in the fact that about 80% of oil sand resources exist in reservoirs with a net pay zone of less than 5 m in Western Canada (Adams, 1982). Thus, there is a need for new efficient processes to produce these resources.

Zhao et al. (2014) discussed different thermal recovery strategies to produce from thin

(< 5 m) heavy oil reservoirs. They investigated four production methods consisting of cold production without sand, alternating injection/production well steam and hot water, steam flooding, and SAGD. They found that first and second processes are not suitable due to high energy to oil ratio and relatively low recovery factor. Both steam flooding and SAGD are applicable but they still suffer from large steam use. The steam cost or cSOR can be reduced by using solvent as was investigated by Gates (2010) and

Zhao et al. (2013). These studies focused on heavy oil reservoirs where the in situ viscosity of the oil is of order of thousands to a few tens of thousands of centipoise.

The focus of the research documented here is on the application of SAGD in thin oil sands reservoir (thickness less than 10 m) where the impact of well configuration on

process performance will be investigated. In these reservoirs, the viscosity of the oil at

original reservoir conditions is of order of 1 million cP. Since the cost of steam is the

33 major expense of SAGD operation and main contributor to carbon dioxide emissions from the process, our aim is the reduction of cSOR with higher oil production.

3.2. Reservoir Simulation Model

The reservoir simulation models used in the research documented here consist of a set of two-dimensional homogenous model with horizontal well pairs. The reservoirs do not have gas cap or bottom water zones. Specifically, three reservoir models were developed with oil sand intervals of 5, 7, and 10 m thickness, respectively labeled as

Model H5, H7, and H10. A regular Cartesian grid system was used to discretize the models with dimensions of 58 grids with a block size of 0.8 m in the cross well direction,

1 grid block with size of 750 m in the downwell direction. In the vertical direction, there are 10, 14, and 20 grid blocks in the H5, H7, and H10 models, respectively, all with dimensions equal to 0.5 m. The reservoir model properties and parameters are shown in Table 3-1.

Simulations were performed utilizing a commercial thermal reservoir simulator, CMG

STARSTM Version 2013 (CMG, 2013). In this finite volume based thermal reservoir simulator, the conservation of energy and mass equations are solved over each grid block together with the phase behavior and relative permeability curves for the gas, aqueous, and oil phases. At the lateral sides of the model, symmetry boundary

34 conditions were imposed (no flow or heat transfer). In other words, the width of the reservoir represents the horizontal well spacing and implies that the well pairs are part of a larger pattern.

Table 3-1 Reservoir simulation model and fluid properties.

Property Value

Net pay, m 10, 7 and 5 SAGD wellpair length, m 750 Horizontal permeability, mD 4000 Vertical permeability, mD 2000 Average porosity 0.3 Initial oil saturation 0.75 Initial water saturation 0.25 Irreducible water saturation (Swr) 0.15 Residual oil saturation with respect to water 0.20 Relative permeability to oil at irreducible water 1.0 Relative permeability to water at residual oil 0.992 Residual gas saturation (Sgr) 0.005 Residual oil saturation with respect to gas 0.005 Relative permeability to gas at residual oil 1.0 Relative permeability to oil at critical gas 0.992 Krw at irreducible oil (KRWIRO) 0.1 Residual oil for gas-liquid table endpoint saturation (SORG) 0.005 Initial temperature, °C 20 Initial pressure, kPa 2000 Rock heat capacity, J/m3 °C 2.600x106 Rock thermal conductivity, J/m day °C 6.600x105 Water phase thermal conductivity, J/m day °C 5.350x104 Oil phase thermal conductivity, J/m day °C 1.150x104 Gas phase thermal conductivity, J/m day °C 5.000x103 Bitumen Molecular weight, kg/kmol 465 Critical temperature, °C 903.85 Critical pressure, kPa 792 Dead oil viscosity, cP at 10°C 1587285 100°C 203.91 200°C 9.71

Table 3-1 Reservoir simulation model and fluid properties (continued).

Liquid phase component viscosity (cP) versus temperature curves (methane viscosities are liquid equivalent viscosity) T (°C) µwater µoil µmethane 5 0 4062963.508 115.042 10 0 1587284.565 98.5940 20 0 299536.7897 68.4247 30 0 71948.7369 54.1416 40 0 21109.2585 43.3994 50 0 7318.08492 35.2174 60 0 2918.2885 28.9106 70 0 1309.6336 23.9942 80 0 649.6128 20.1206 90 0 350.9125 17.0377 100 0 203.9087 14.5607 125 0 82.3894 10.9109 150 0 29.6896 7.4943 175 0 17.7130 6.0323 200 0 9.7153 4.5479 225 0 7.1037 3.8631 250 0 4.8898 3.1238

Oil-water relative permeability curves Sw Krw Krow 0.1500 0.0000 0.9920 0.2500 0.0016 0.9500 0.3500 0.0130 0.6000 0.4500 0.0440 0.3500 0.5500 0.1040 0.1650 0.6500 0.2040 0.0700 0.7500 0.3520 0.0150 0.8000 0.4470 0.0000 0.8500 0.5590 0.0000 0.9500 0.8340 0.0000 1.0000 1.0000 0.0000

Gas-liquid relative permeability curves Sl Krg Krog 0.1500 1.0000 0.0000 0.2500 0.8400 0.0016 0.3500 0.6000 0.0130 0.4500 0.3500 0.0440 0.5500 0.1650 0.1040 0.6500 0.0750 0.2040 0.7500 0.0270 0.3520 0.8000 0.0200 0.4470 0.8500 0.0100 0.5590 0.9500 0.0000 0.8340 1.0000 0.0000 0.9920

To establish thermal communication between the two wells, as is typical in field

operations, the steam circulation time was set equal to 3 months. In the model, this

was done by placing temporary heaters in the locations of the wells. When SAGD mode

started, the temporary heaters were turned off and steam injection and fluid production

started. The operation was simulated for up to 3 years.

3.3. Reservoir Models

3.3.1. Model H10

The reservoir cross-sectional views and details of well placement for Model H10 with a

single producer and a single injector cases are depicted in Table 3-2. Each well location is defined by its block number in the horizontal (I, J) and vertical (K) directions as well as vertical and horizontal distances between the wellpairs. Model H10 was run for 11 different cases to investigate the influence of well configuration on SAGD process

performance. For all cases, producer well is placed in the block 30 in the I-direction.

Cases H10-1 through 7 represents the vertically aligned wellpairs whereas cases H10-8 to 11 are the non-vertically aligned well configurations.

In Cases H10-1 to 4, the producer well is placed at the block 17 in the vertical direction

(1.75 m above the base of the reservoir). The injection well is placed at different block locations and in alignment with the producer well – the vertical offset between the wells

37 varies from 1 to 6.5 m. In Cases H10-5 to 7, the production well is placed at the block 20 in the vertical direction (0.25 m above the bottom of the reservoir). In the same fashion as in the previous cases, the position of the injector well is changed vertically.

Cases H10-8 through 11 are the not aligned (in the vertical plane) well pairs. The production well is placed in block 17 in the vertical direction. The injector well is positioned at different block locations with a vertical distance varying from 1 to 5 m and a horizontal distance of 1.6 to 8 m laterally away from the producer well.

Table 3-2 Well placement in Model H10 with a layer thickness of 10 m.

Case Well Grid Grid Grid Vert. Horiz. Image I J K Dist. Dist. (m) (m) H10-1 Prod. 30 1 17 2.5 0

Inj. 30 1 12

H10-2 Prod. 30 1 17 5 0 Inj. 30 1 7

H10-3 Prod. 30 1 17 1 0 Inj. 30 1 15

H10-4 Prod. 30 1 17 6 0 Inj. 30 1 5

H10-5 Prod. 30 1 20 2.5 0 Inj. 30 1 15

H10-6 Prod. 30 1 20 5 0 Inj. 30 1 10

H10-7 Prod. 30 1 20 6.5 0 Inj. 30 1 7

H10-8 Prod. 30 1 17 2.5 4

Inj. 35 1 12

H10-9 Prod. 30 1 17 2.5 8 Inj. 40 1 12

H10-10 Prod. 30 1 17 1 4 Inj. 35 1 15

H10-11 Prod. 30 1 17 5 1.6

3.3.2. Model H7

The reservoir cross-sectional views and details of well placement for Model H7 are

illustrated in Table 3-3. Model H7 was run for 8 different cases. Cases H7-1 through 4

represents the vertically aligned wellpairs whereas Cases H7-5 through 8 represents the

non-vertically aligned well configurations. For all cases, the producer well is placed in

the block 30 in I-direction. In cases of H7-1 and 2, the producer well is placed at the

block 11 in the vertical direction (1.75 m above the base of reservoir). In Cases H7-3 and

4 producers well were positioned at the block 14 and 0.25 m above the base of reservoir. The injection well is placed at different block locations and in alignment with the producer well – the vertical offset between the wells varies from 1 to 5 m.

In non-vertically aligned Cases H7-5 through 7, the producer well is placed at 1.75 m and in Case H7-8 at 0.25 m above the base of reservoir. The injector well is positioned at

40 different block locations with a vertical distance of 1 to 5m and a horizontal distance varying from 1.6 to 8 m from the producer well.

Table 3-3 Well placement in Model H7 with a layer thickness of 7 m.

Case Well Grid Grid Grid Vert. Horiz. Image I J K Dist. Dist. (m) (m) H7-1 Prod. 30 1 11 Inj. 30 1 6 2.5 0

H7-2 Prod. 30 1 11 Inj. 30 1 9 1 0

H7-3 Prod. 30 1 14 Inj. 30 1 9 2.5 0

H7-4 Prod. 30 1 14 Inj. 30 1 4 5 0

H7-5 Prod. 30 1 11 Inj. 35 1 6 2.5 4

H7-6 Prod. 30 1 11 Inj. 40 1 6 2.5 8

H7-7 Prod. 30 1 11 1 4 Inj. 35 1 9

H7-8 Prod. 30 1 14 5 1.6 Inj. 32 1 4

3.3.3. Model H5

The reservoir cross-sectional views and details of well placement for Model H5 are shown in Table 3-4. Model H5 was run for 13 cases. Cases H5-1 through 7 indicates the vertically aligned wellpairs whereas Cases H5-8 through 13 represents the non-vertically aligned wellpairs. For all cases, the producer well is placed in the block 30 in I-direction.

In Cases H5-1 and 2, the producer well is placed at the block 7 in the vertical direction

(1.75 m above the base of reservoir). In Cases H5-3 and 7, the producer wells were positioned at the block 10 and 0.25 m above the base of reservoir, respectively. The injection well is placed at different block locations and in alignment with the producer well – the vertical offset between the wells varies from 1 to 4.5 m.

In non-vertically aligned Cases H5-8 through 10, the producer well is placed at 1.75 m and in Cases H5-11 to H5-13 at 0.25 m above the base of reservoir. The injector well is positioned at different block locations with a vertical distance of 0 to 4.5 m and a horizontal distance varying from 1.6 to 8 m from the producer well.

Table 3-4 Well placements in Model H5 with a layer thickness of 5 m.

Case Well Grid Grid Grid Vert. Horiz. Image I J K Dist. Dist. (m) (m) H5-1 Prod. 30 1 7 2.5 0 Inj. 30 1 2

H5-2 Prod. 30 1 7 1 0 Inj. 30 1 5

H5-3 Prod. 30 1 10 2.5 0 Inj. 30 1 5

H5-4 Prod. 30 1 10 4.5 0 Inj. 30 1 1

H5-5 Prod. 30 1 10 4 0 Inj. 30 1 2

H5-6 Prod. 30 1 10 3.5 0 Inj. 30 1 3

H5-7 Prod. 30 1 10 3 0 Inj. 30 1 4

H5-8 Prod. 30 1 7 2.5 4 Inj. 35 1 2

H5-9 Prod. 30 1 7 2.5 8 Inj. 40 1 2

H5-10 Prod. 30 1 7 1 4 Inj. 35 1 5

H5-11 Prod. 30 1 10 4 4 Inj. 35 1 2

H5- 12 Prod. 30 1 10 0 4 Inj. 35 1 10

H5-13 Prod. 30 1 10 4 1.6 Inj. 32 1 2

3.4. Results and Discussion

The simulation results are presented here as four main comparisons of the cumulative

SOR versus time, cumulative oil production versus time, oil recovery factor versus pore volume steam injected (PVSI), and cumulative heat loss as a function of time. In the following description of the results, whenever a value is given for cumulative SOR it is recorded at the end of operation time of 900 days unless otherwise is mentioned.

3.4.1. Model H10

3.4.1.1. Cumulative Steam-to-Oil Ratio

Cumulative steam oil ratios (cSOR) for the H10 cases with a layer thickness of 10 m are shown in Fig. 3-1A through C. The results in Fig. 3-1A represent the vertically aligned

wellpairs cases and Fig. 3-1B shows not vertically aligned cases. The best case scenarios

are depicted in Fig. 3-1C.

According to Fig. 3-1A, at a shorter wellpairs distances, regardless of the producer well location, the cSOR curves show a smaller peak in comparison with those well pairs

located at larger distance from each other (e.g. Cases H10-4 and 7). At shorter vertical

distances, the mobilized oil is found in the vicinity of the injector well. Thus, it requires

shorter time to travel to the producer well. After more time, more steam is needed to

cover the vaster area and the cSOR increases. It appears that the temperature

distribution is affected by the reduced heat transfer rates. In the H10 Cases 1 through 4

(producer well located at 1.75 m above underburden), as the vertical distance between

the wellpairs increases, the cSOR decreases. Case H10-3 has the shortest distance equal

to 1 m whereas Case H10-4 has the longest distance equal to 6 m. In Cases H10-5

through 7, the same trend was observed. Case H10-5 has the shortest distance of 2.5 m

and Case H10-7 has the longest distance of 6.5 m. The wellpairs with the producer well

positioned at an immediate distance from the underburden (0.25 m above) give a lower

cSOR value with an exception of Case H10-5. The cSOR value for Case H10-5 appears

somewhere between Cases H10-1 and 2. The wellpair distance between Case H10-1 and

5 are the same and the only difference is the producer well position.

Also, in Cases H10-4 and 6, in spite of having different well locations and wellpairs

distances, the same cSOR value was observed after about 650 days of operation. There

46 are two parameters that balance each other out: 1. well distance and 2. producer well location. Therefore, to reduce cSOR, the separation between the well pairs should be increased to an optimum value around 5 to 6 m or producer well should be moved to the adjacent block to the understrata. Performing both corrections, as shown by Case

H10-7, the cSOR is reduced further.

Fig. 3-1B shows the not aligned wellpairs. In Cases H10-8 through 11, the producer well is located at 1.75 m above the understrata. In both Cases H10-8 and 9, the injector wells are placed at a vertical distance of 2.5 m and a horizontal distance of 4m and 8m, respectively. The influence of horizontal positioning is compared between Cases H10-1

(with zero horizontal distance, see also Fig. 3-1A), H10-8 and H10-9.

The cSOR values at the end of 3 years of operation are equal to about 4.5, 4.2 and 8.5 m3/m3, respectively, in Cases H10-1, H10-8, and H10-9. Similar to what was observed in the vertically aligned cases, an optimum horizontal distance is also found to achieve a lower cSOR. If the distance becomes larger or smaller (zero) than the optimum value, the cSOR increases. It appears that an increase in the horizontal distance between a well pairs requires more time for establishment of thermal communication between them.

This is in agreement with Tamer and Gates (2012) and Tavallali et al.’s (2012) work who observed that larger horizontal offsets delay well production. For our particular arrangement, the smallest cSOR value was achieved in Case H10-8. In Case H10-10, the horizontal distance is kept similar to Case H10-8 and the vertical distance between well pairs is reduced from 2.5 m to 1 m.

7 H10-Case 1 H10-Case 2 H10-Case 3 H10-Case 4 A H10-Case5 H10-Case 6 H10-Case 7 3 6 /m 3 , m 5

4 SOR Cumulative Cumulative SOR 3 0 100 200 300 400 500 600 700 800 900 1000 Time, Days

3 8

/m B 3

, m 7

4 SOR Cumulative Cumulative SOR H10-Case 8 H10-Case 9 H10-Case 10 H10-Case 11 3 0 100 200 300 400 500 600 700 800 900 1000

Time, Days

7 6 3 C /m

3 5

, m 4 3 2 1 H10-Case 6 H10-Case 7 H10-Case 11 SOR Cumulative SOR 0 0 100 200 300 400 500 600 700 800 900 1000 Time, Days

Figure 3-1 Cumulative steam oil ratio versus operation time for Model H10, (A) aligned (B) not aligned, (C) best case scenarios.

The results reveal an increase in cSOR from 4.2 to 5.1 m3/m3. Apparently, the distance

passed an optimum value. The cSOR for Case H10-11 is the same as Case H10-8 (4.1

m3/m3) due to the balancing influences of vertical and horizontal distances on cSOR.

In Fig. 3-1C, the best case scenarios are compared. The cSORs for Cases H10-4, H10-6,

H10-8, and H10-11 are similar and are higher than that of Case H10-7. It can be concluded that the horizontal and vertical distances between a well pair as well as the location of producer well affects cSOR and therefore the performance of the SAGD operation.

3.4.1.2. Cumulative Produced Oil

The cumulative oil production for vertically aligned wellpairs are shown in Fig. 3-2A followed by not aligned and best case scenarios in Fig. 3-2B and C.

According to Fig. 3-2A, Case H10-6 has the highest cumulative oil production followed closely by Cases H10-1, H10-2, and H10-5. Case H10-4 produces slightly lower amounts

of oil and Cases H10-7 and H10-3 achieve the lowest amount of oil produced. A comparison between cumulative oil production amongst the cases taking into account

what was observed in Fig. 3-1A for the cSOR profiles reveals that having a lower cSOR

does not guarantee a higher cumulative oil production volume at the same time.

Therefore there are other parameters at play which should be factored in e.g. delayed

oil production. It is interesting to compare Cases H10-3 and 7 (have the shortest (1 m)

49 and longest (6.5 m) well pairs distances in their group, respectively). Case H10-3 achieves the highest cSOR whereas Case H10-7 realizes the lowest cSOR. Case H10-3 results in higher oil production than that of Case H10-7 after 520 days of operation.

After establishment of the quasi-steady cSOR, the production volumes flip between these two cases. It confirms again that shorter vertical distances lead to early simultaneous steam injection/oil production. Our result is in accordance with Butler

(1992) which mentioned if the oil is produced too quickly from the reservoir, then the steam chamber will be drawn down to the well and bypassing of steam will occur, in other words, steam trap control is lost. Therefore, more steam is needed to contact the bitumen located at farther distances from the injector.

Fig. 3-2B illustrates the behavior of the not aligned well pair cases. Sorting the cases from highest cumulative produced oil to the lowest volume achieved (almost no production) leads to the sequence of Cases H10-11, H10-8, H10-10, and H10-9. A comparison between similar cases and their cSOR confirms that at lower cSOR, higher cumulative oil production can be expected. However, Cases H10-8 and 11 have similar cSORs in spite of having different cumulative oil production. Cases H10-6 and 11 achieve different cumulative oil production, in spite of having similar cSOR. The only difference between these two cases is the horizontal distance of 1.6 m that appears to cause a slight delay in oil production. Case H10-7 realizes the lowest cSOR with the lowest oil production. This behavior will be discussed further in the following section where the oil recovery factor is measured based on pore volume of steam injected

(PVSI).

50000 3 40000 A

30000

20000

H10-Case 1 H10-Case 2 10000 H10-Case 3 H10-Case 4 H10-Case 5 H10-Case 6 H10-Case 7

Cumulative Oil Production, m Oil Production, Cumulative 0 0 100 200 300 400 500 600 700 800 900 1000 Time, Days

50000 H10-Case 8 H10-Case9 H10-Case 10 H10-Case 11

3 40000 B 30000

20000

10000

Cumulative Oil Production, m Oil Production, Cumulative 0 100 200 300 400 500 600 700 800 900 1000

Time, Days

50000 3

40000 C

30000

20000

10000 H10-Case 6 H10-Case 7 H10-Case 11 0 Cumulative Oil Production, m Oil Production, Cumulative 0 100 200 300 400 500 600 700 800 900 1000 Time, Days Figure 3-2 Cumulative produced oil versus operation time for Model H10, (A) aligned (B) not aligned, (C) best case scenarios.

(PVSI).

3.4.1.3. Oil Recovery Factor

The results are shown in Fig. 3-3A (vertically aligned wellpairs), Fig. 3-3B (not vertically aligned), and Fig. 3-3C for the best case scenarios. The recovery factor was measured as a function of the pore volumes of steam injected (PVSI, expressed as cold water equivalent) to compare the different cases. In Fig. 3-3A, the order of recovery factor after 900 days of operation from highest to lowest is Cases H10-6, H10-2, H10-5, H10-1,

H10-7, H10-3, and H10-4.

60 50 A 40

H10-Case 1 H10-Case 2 H10-Case 3

Oil Factor Recovery Oil 10 H10-Case 4 H10-Case 5 H10-Case 6 H10-Case 7 0 0 0.5 1 1.5 2 PVSI

60 50 B 40

10 Oil Factor Recovery Oil H10-Case 8 H10-Case 9 H10-Case 10 H10-Case 11 0 0 0.5 1 1.5 2

PVSI

50 C

10 Oil Factor Recovery Oil H10-Case 6 H10-Case 7 H10-Case 11 0 0 0.5 1 1.5 2

PVSI

Figure 3-3 Oil recovery factor versus pore volume steam injected (PVSI) for Model H10, (A) aligned (B) not aligned, (C) best case scenarios.

Case H10-6 achieves the highest recovery factor whereas Case H10-4, in which the injector well is positioned closest to overburden, has the lowest oil recovery of the vertically aligned cases. The recovery factor in Cases H10-5 and H10-1 is almost the same as that of H10-2 (about 58%) but at a cost of a greater PVSI as shown in Fig. 3-1A

(the cSOR profile).

3.4.1.4. Cumulative Heat Loss

The cumulative heat loss profiles are presented in Fig. 3-4A (vertically aligned well pairs), Fig. 3-4B (not vertically aligned well pairs), and Fig. 3-4C for the best case scenarios. The order of heat loss is from the lowest to the highest H10-3, H10-7, H10-4,

H10-5, H10-6, H10-2, and H10-1 as shown in Fig. 3-4A. Therefore, Case H10-1 has the highest and H10-3 shows the lowest heat loss in the vertically aligned cases. A comparison of Cases H10-1 through H10-4, where the producer well is at the same position, reveals that Case H10-3 exhibits the lowest heat loss – this case has the injector well farthest from the surface. Case H10-4 has the injector well closest to surface but it does not achieve the largest heat losses of the cases. In Cases H10-2 and

H10-1 the injector wells are located even farther from the overburden but not far enough in comparison with Case H10-3. Thus, the heat loss increases further.

Our results show that the heat loss is not the only and main issue with respect to oil production as in this particular case the lowest cumulative oil production was observed

(see Fig. 3-2A). Further, Case H10-3 showed the lowest cSOR (Fig. 3-1A).

In cases H10-5 through H10-7, H10-5 has the lowest heat loss and H10-6 the highest heat loss.

For the not aligned well pair cases, the order with respect to heat losses from the lowest to the highest is H10-9, H10-10, H10-8, and H10-11 (Fig. 3-4B).

According to Fig. 3-4C, the order with respect to heat losses from the highest to the lowest is H10-3, H10-10, and H10-9. The not vertically aligned cases lead to lowest heat losses due to delayed oil production.

The same trend in choosing the particular cases (H10-6, H10-7 and H10-11) as was observed in the best case scenarios for cSOR, cumulative oil production and recovery factor did not appear here. It seems that a higher oil production is achieved at higher energy loss. A comparison between the heat losses for Cases H10-6, H10-7 and H10-11 indicates that Case H10-6 shows the highest heat loss whereas the lowest is found in

Case H10-7. In both cases, the well pairs are located with the producer well located 0.25 m above the underburden. The only difference is the position of injector well and its distance from the producer. Although, the same trend as in cSOR (see Fig. 3-1C) is observed, the results suggest that lower cSOR means lower heat loss. However, this conclusion cannot be extended to all cases.

It can be concluded that to increase oil production from thin oil sand reservoirs, it is necessary to find an optimum vertical separation and horizontal distance the injection and production well in addition to the position of the production well.

0 A -5E+13

-1E+14

-1.5E+14 H10-Case 1 H10-Case 2 H10-Case 3 Heat Loss Cum , J , Loss CumHeat H10-Case 4 H10-Case 5 H10-Case 6 H10-Case 7 -2E+14 0 100 200 300 400 500 600 700 800 900 1000

Time, Days

0 B -5E+13

-1E+14

-1.5E+14 Heat Loss Cum , J , Loss CumHeat

H10-Case 8 H10-Case 9 H10-Case 10 H10-Case 11 -2E+14 0 100 200 300 400 500 600 700 800 900 1000

Time, Days

0 C -5E+13

-1E+14 Heat Loss Cum , J , Loss CumHeat

H10-Case 9 H10-Case 3 H10-Case 10 -1.5E+14 0 100 200 300 400 500 600 700 800 900 1000

Time, Days Figure 3-4 Heat loss versus time for Model H10, (A) aligned (B) not aligned, (C) best case scenarios.

The results show that position and lateral spacing between the well pair can yield lower heat losses, lower cSOR, and higher cumulative oil produced (as well as the onset of oil production).

The priority with respect to the commercial operation of an oil recovery process can vary by operator – for one it may be operational costs which is reflected by the cSOR and heat losses or it may be income and cash flow which is reflected by a combination of the cSOR (represents ratio of cost to revenue) and the cumulative produced oil

(which reflects the oil rate which is what sets revenues). Thus, the results can be interpreted for an oil recovery operation by deciding what is the most important factors for the operation.

3.4.2. Model H7

3.4.2.1. Cumulative Steam-to-Oil Ratio

The cumulative steam-to-oil ratios (cSORs) for Model H7 (oil column thickness of 7 m) are shown in Fig. 3-5A through 3-5C. Similar to the results presented for Model H10, Fig.

3-5A and Fig. 3-5B show the results of the vertically aligned and not aligned cases, respectively. The best case scenarios are depicted in Fig. 3-5C.

According to Fig. 3-5A, Cases H7-3 and H7-4, where the producer well is positioned at immediate distance from the understrata (0.25 m above), gives a lower cSOR compared to the results of Cases H7-1 and H7-2 (producer well located 1.75 m above understrata).

In Model H10, it was shown that having an optimum distance (vertically as well as horizontally) between the injection and production wells lead to lower cSOR. Similarly, for the H7 cases, Case H7-4 has the lowest cSOR (well separation equal to 5 m) whereas

Case H7-1 achieves the highest cSOR (with separation of 1 m).

In Fig. 3-5B, similar to H10 model, the cSOR for Case H7-6 is higher than that of Case H7-

5 due to having a horizontal well pair distance beyond the optimum value. Case H7-5 has lower cSOR compared to Case H7-7 due to shorter vertical separation between the wells. Finally, for the not aligned cases, Case H7-8 exhibits the lowest cSOR which is in agreement with the results of Model 10.

Apparently, for the not aligned cases, Case H7-8 realizes the optimum vertical and horizontal distance. For this case, the producer well is located adjacent to the understrata.

In Fig. 3-5C, the best case scenarios are compared together. Cases H7-4 and H7-8 realize the lowest cSORs in the vertically aligned and not aligned cases, respectively, as depicted in Fig. 3-5A and B. The cSOR profiles are very similar for these two cases. The only difference between these two well arrangements is a horizontal distance of 1.6m which did not lead to a significant change of the cSOR. Case H7-3 reveals slightly higher cSOR due to a shorter vertical separation distance of 2.5 m.

6 A 3

/m 5 3 , m

H7-Case 1 H7-Case 2 H7-Case3 H7-Case 4 SOR Cumulative SOR 3 0 100 200 300 400 500 600 700 800 900 1000 Time, Days

3 7 B /m 3

, m 6

4 SOR Cumulative SOR H7-Case 5 H7-Case 6 H7-Case 7 H7-Case 8 3 0 100 200 300 400 500 600 700 800 900 1000 Time, Days

5 3 C /m 3 4 , m 3

SOR Cumulative SOR H7-Case 3 H7-Case 4 H7-Case 8 0 0 100 200 300 400 500 600 700 800 900 1000

Time, Days

Figure 3-5 Cumulative steam oil ratio (cSOR) versus operation time for Model H7 (A) aligned (B) not aligned, (C) best case scenarios.

3.4.2.2. Cumulative Produced Oil

The cumulative oil production profiles for the vertically aligned well, not vertically aligned well, and best cases are shown in Fig. 3-6A, B, and C, respectively. The results in

Fig. 3-6A reveal that Cases H7-3 and H7-4 have the highest cumulative oil production followed closely by Case H7-1. Case H7-2 shows the lowest oil production volume of this group. A comparison between cumulative oil production cases and cSOR profiles

(shown in Fig. 3-6A) confirms that lower cSOR does not necessarily mean a higher cumulative oil production.

Fig. 3-6B illustrates the behavior of the not aligned well cases from highest oil production volume to the lowest as H7-8, H7-5, H7-7, and H7-6.

A comparison between Fig. 3-6B and the related cSOR profiles in Fig. 3-5B shows that at a lower cSOR, a higher cumulative oil production is achieved.

According to Fig. 3-6C, the difference in the volume of oil produced between Cases H7-3 and H7-4 is not significant and it is slightly more than Case H7-8. However, a comparison between their cSOR profiles (see Fig. 3-5C) shows that Cases H7-4 and H7-8 have similar cSOR although it is slightly lower than Case H7-3.

35000 3 30000 A 25000

20000

15000

10000

5000 H7-Case 1 H7-Case 2 H7-Case 3 H7-Case 4 Cumulative Oil Production, m Oil Production, Cumulative 0 0 100 200 300 400 500 600 700 800 900 1000

Time, Days

35000 3 30000 B 25000

20000

15000

10000 H7-Case 5 H7-Case 6 5000 H7-Case 7

Cumulative Oil Production, m Oil Production, Cumulative H7-Case 8 0 0 100 200 300 400 500 600 700 800 900 1000 Time, Days

35000 3 30000 C 25000

20000

15000

10000

5000 H7-Case 3 H7-Case 4 H7-Case 8

Cumulative Oil Production, m Oil Production, Cumulative 0 0 100 200 300 400 500 600 700 800 900 1000

Time, Days Figure 3-6 Cumulative produced oil versus operation time for Model H7, (A) aligned (B) not aligned, (C) best case scenarios.

3.4.2.3. Oil Recovery Factor

The oil recovery profiles are shown in Fig. 3-7A (vertically aligned wellpairs), Fig. 3-7B

(not vertically aligned), and Fig. 3-7C for the best case scenarios. In Fig. 3-7A, the recovery factor profiles are presented – the order of recovery factor from the lowest recovery factor to the highest recovery factor are Cases H7-2, H7-1, and H7-4, and H7-3 for the vertically aligned cases. For the not aligned well cases, the order of recovery factor from the lowest recovery factor to the highest recovery factor are Cases H7-6, H7-

7, H7-5, and H7-8.

Based on the results shown in Fig. 3-7C, Cases H7-4 and H7-8 have the highest oil recovery factor with results slightly higher than was achieved by Case H7-3. This result agrees with their cSOR trends shown in Fig. 3-5C. The results show that the recovery factors achieved are in excess of 50% after about 1.75 pore volumes of steam injected

(PVSI, expressed as cold water equivalent) into the reservoir.

60 50 A 40

10 Oil Factor Recovery Oil H7-Case 1 H7-Case 2 H7-Case 3 H7-Case 4 0 0 0.5 1 1.5 2 2.5 PVSI

60 50 B 40

Oil Factor Recovery Oil 10 H7-Case 5 H7-Case 6 H7-Case 7 H7-Case 8 0 0 0.5 1 1.5 2 2.5 PVSI

50 C

Oil Factor Recovery Oil 10 H7-Case 3 H7-Case 4 H7-Case 8 0 0 0.5 1 1.5 2 2.5 PVSI

Figure 3-7 Oil recovery factor versus pore volume steam injected (PVSI) for Model H7, (A) aligned (B) not aligned, (C) best case scenarios.

3.4.2.4. Cumulative Heat Loss

Cumulative heat losses are shown in Fig. 3-8A (vertically aligned) and Fig. 3-8B (not vertically aligned). For the aligned cases, the order of heat loss from the lowest case to the highest is H7-2, H7-1, H7-4, and H7-3. For the not aligned cases, the order is H7-6,

H7-7, H7-5, and H7-8. A comparison between these two figures shows that, except in

H7-2, the aligned scenarios generate more heat loss than that of not aligned ones. The highest heat loss appears when the well pair has a vertical separation of 2.5 m. An increase of the separation to 5 m reduces the heat loss and a horizontal separation of

1.6 m reduces the heat loss further. The behavior of Cases H7-3 and H7-4 are very similar. With the exception of the PVSI, the results of cSOR, cumulative oil production, oil recovery factor, and heat losses during the SAGD operation are similar for these two cases. The well configuration of Case H7-4 experiences delayed oil production and requires more steam to achieve the same oil recovery factor as that of H7-3.

Fig. 3-8C indicates the best case scenarios with apparently lowest heat losses. The order of heat loss from the lowest case to the highest is H7-6, H7-7, H7-5, and H7-2.

So far, it was shown that Cases H7-3, H7-4, and H7-8 present best case scenarios in

Model H7 that lead to lower cSOR, higher cumulative oil production and the highest oil recovery factors. However, the same trend was not revealed in heat loss of the best case scenarios. On the contrary, these well configurations show the worst heat losses.

0 A -5E+13

-1E+14

Heat Loss Cum, J -1.5E+14

H7-Case 1 H7-Case 2 H7-Case 3 H7-Case 4 -2E+14 0 100 200 300 400 500 600 700 800 900 1000

Time, Days

0 B -5E+13

-1E+14

Heat Loss Cum, J -1.5E+14

H7-Case 5 H7-Case 6 H7-Case 7 H7-Case 8 -2E+14 0 100 200 300 400 500 600 700 800 900 1000 Time, Days

0 C -5E+13

-1E+14

-1.5E+14 Heat Loss Cum, J

H7-Case 2 H7-Case 5 H7-Case 6 H7-Case 7 -2E+14 0 100 200 300 400 500 600 700 800 900 1000

Time, Days Figure 3-8 Heat loss versus time for Model H7, (A) aligned (B) not aligned, (C) best case scenarios.

As it was mentioned in Model H10, choosing the best case scenarios are depended on

what is the most important factors for the operation.

3.4.3. Model H5

3.4.3.1. Cumulative Steam-to-Oil Ratio

The cumulative steam-to-oil ratios (cSORs) for Model H5 (oil column 5 m thick) are

shown in Fig. 3-9A through 3-9C. Similar to the previous H10 and H7 models, Fig. 3-9A

and Fig. 3-9B represent the vertically aligned and not aligned cases, respectively. The

best case scenarios are depicted in Fig. 3-9C. According to Fig. 3-9A, Cases H5-1 and H5-

2 with the producer well positioned at 1.75 m above the understrata give higher cSORs

compared to Cases H5-3 to H5-7 (producer well located at 0.25 m above understrata).

Similar results were observed for Models H10 and H7. Therefore, positioning the

producer well at an immediate distance from the understrata will lower the cSOR.

Considering Cases H5-3 to H5-7, the vertical distance is the shortest in Case H5-3 (2.5 m)

and longest in Case H5-4 (4.5 m). The cSOR values given in Fig. 3-9A confirm that Case

H5-3 has the highest cSOR (7.4 m3/m3) and H5-4 (7.2 m3/m3) has the lowest cSOR.

The influence of horizontal positioning is shown in Fig. 3-9B. The trend is somewhat

different as was observed in Models H10 and H7. The horizontal wellpairs separation

for Cases H5-8 and H5-9 are 3.2 m and 8 m, respectively.

8 3 7

/m A 3

, m 6 7.4

5 7.3 H5-Case 1 H5-Case 2 7.2 4 H5-Case3 H5-Case 4 H5-Case 5 H5-Case 6 H5-Case 7 7.1 SOR Cumulative Cumulative SOR 3 7 0 100 200 300 400 500 600 700 800 900 1000 850 900 Time, Days

3 7 B /m 3

, m 6

4 H5-Case 8 H5-Case9 H5-Case 10 SOR Cumulative SOR H5-Case 11 H5-Case 12 H5-Case 13 3 0 100 200 300 400 500 600 700 800 900 1000

Time, Days

8 3 C

/m 7 3 , m 6

4 SOR Cumulative SOR H5-Case4 H5-Case 5 H5-Case 11 H5-Case 13 3 0 100 200 300 400 500 600 700 800 900 1000

Time, Days

Figure 3-9 Cumulative steam oil ratio (SOR) versus operation time for Model H5, (A) aligned (B) not aligned, (C) best case scenarios.

In comparison with Models H10 and H7, a higher cSOR is expected for greater

separations, but on the contrary, Case H5-9 shows lower cSOR (6.9 m3/m3) than that of

Case H5-8 (7.5 m3/m3). In the case where the horizontal distance is zero (Case H5-1), the cSOR is even larger (7.8 m3/m3).

As the horizontal separation between the wells reduce (e.g. examine results of Cases

H5-1, H5-13, and H5-11), the cSOR increases regardless of the producer well elevation

above the understrata.

A cSOR of 6.7 m3/m3 is achieved for Case H5-10 in which the vertical distance is 1 m. In

models H10 and H7, this particular well pair configuration showed slightly higher cSOR

than the corresponding case with horizontal distance of 3.2 m. The lowest cSOR (6.2

m3/m3) is observed for Case H5-12.

In Fig. 3-9C, the best case scenarios are compared together. Case H7-11 shows the

lowest cSOR (6.7 m3/m3) and Cases H7-4 and 5 realize the highest cSOR (7.2 m3/m3).

Except for Case H5-11 (has a larger horizontal distance), the rest of the H5 configurations led to similar cSOR.

3.4.3.2. Cumulative Produced Oil

The cumulative oil production profiles for the vertically aligned wellpairs cases are shown in Fig. 3-10A followed by the not aligned and best case scenarios in Fig. 3-10B and 3-10C.

Cases H5-3 to H5-7, shown in Fig. 3-10A, exhibit similar cumulative oil production. This result is expected since the producer well in both Cases H5-1 and H5-2 is positioned at

1.75 m above the understrata. The remaining cases have their producer well 0.25 m above the understrata.

The change of the vertical separation of the wells did not have a significant influence on the cumulative oil production. A comparison between cumulative oil production for different cases in Fig. 3-10A and their related cSOR in Fig. 3-9A confirms that a significant change appears only when the producer well position is altered.

Fig. 3-10B illustrates the behavior of not aligned wellpairs. A comparison between Fig. 3-

10B and related cSOR profiles presented in Fig. 3-9B reveals that lower cSOR does not imply a higher cumulative oil production necessarily. The H5 model follows the same trend as that exhibited in Models H10 and H7 – they present a decrease of the cumulative oil production as a result of reduction in horizontal separation between the wells.

25000 3 20000 A

15000 21000

10000 H5-Case 1 H5-Case2 H5-Case 3 H5-Case 4 5000 H5-Case5 H5-Case6 H5-Case 7 0 20000 850 900

Cumulative Oil Production, m Oil Production, Cumulative 0 100 200 300 400 500 600 700 800 900 1000

Time, Days

25000 3 20000 B

15000

10000

H5-Case 8 H5-Case 9 5000 H5-Case 10 H5-Case 11 H5-Case 12 H10-Case 13 0 Cumulative Oil Production, m Oil Production, Cumulative 0 100 200 300 400 500 600 700 800 900 1000

Time, Days

25000 3 20000 C

15000

10000

5000 H5-Case 4 H5-Case 5 H5-Case 11 H5-Case 13 0 Cumulative Oil Production, m Oil Production, Cumulative 0 100 200 300 400 500 600 700 800 900 1000

Time, Days

Figure 3-10 Cumulative produced oil versus operation time for Model H5, (A) aligned (B) not aligned, (C) best case scenarios.

In spite of having the lowest cSOR (6.7 m3/m3), the well configuration of Case H5-11

performed poorly in comparison with the rest and the oil production was delayed

significantly. A comparison between H5-case 2 (7.9 m3/m3, the highest cSOR) and H5- case 10 (6.9 m3/m3) reveals that an increase of the horizontal distance from zero to 4 m

between the injection and production wells led to a lowering of the cSOR.

3.4.3.3. Oil Recovery Factor

The oil recovery factor profiles are shown in Fig. 3-11A (vertically aligned), Fig. 3-11B

(not vertically aligned), and Fig. 3-11C for the best case scenarios.

Roughly, the different cases divided themselves in two groups of oil recovery factors for

the vertically-aligned cases as shown in Fig. 3-11A. This is based on the elevation of the

producer well – the greater the distance between the producer well and the

understrata, the lower the recovery factor.

The not vertically aligned cases are depicted in Fig. 3-11B. The results of Cases H5-9 and

H5-12 yielded lower cSOR, but they produced negligible volumes of oil due to length of

time it took to establish thermal communication between the wells. For other cases,

the recovery factor patterns are similar to the analogous cases of the H10 and H7

models.

60 50 A 40 53.5 30

20 H5-Case 1 H5-Case 2 H5-Case 3 H5-Case 4 10 H5-Case 5 H5-Case 6

Oil Factor Recovery Oil H5-Case 7 0 0 0.5 1 1.5 2 2.5 3 52.5 2.75 2.8 PVSI

50 B

Oil Factor Recovery Oil 10 H5-Case 8 H5-Case 9 H5-Case 10 H5-Case 11 H5-Case 12 H5-Case 13 0 0 0.5 1 1.5 2 2.5 3 PVSI

50 C

30 49

20 Oil Factor Recovery Oil 10 48 H5-Case 4 H5-Case 5 H5-Case 11 H5-Case 13 0 0 0.5 1 1.5 2 2.5 3 47 PVSI 2.3 2.4

Figure 3-11 Oil recovery factor versus pore volume steam injected (PVSI) for Model H5, (A) aligned (B) not aligned, (C) best case scenarios.

The vertically aligned cases produced at higher recovery factors but at cost of higher

PVSI. The oil recovery factors varied between 53 and 54% at a PVSI of about 2.8.

According to Fig. 3-11C, the recovery factors for different cases, with the exception of

Case H5-11 (larger horizontal separation between the injection and production well) are very comparable.

3.4.3.4. Cumulative Heat Loss

The profiles of the cumulative heat losses are shown in Fig. 3-12A (vertically aligned),

Fig. 3-12B (not vertically aligned), and Fig. 3-12C for the best case scenarios.

For the vertically aligned well configurations, the order of the cases with respect to heat

loss from the lowest to the highest heat loss are Cases H5-2, H5-1, H5-4, H5-5, and H5-3,

H5-6, and H5-7. However, the difference in heat losses for cases H5-3 to 7 is small.

Therefore, changing the vertical well separation from 2.5 to 4.5 m did not play a

substantial role with respect to SAGD heat loss performance. In Case H5-2, the wellpairs

is located near the middle of the reservoir. This arrangement offers the shortest vertical

distance and led to the lowest oil production and recovery factor due to insufficient

vertical well pair separation and delayed temperature distribution. Case H5-4 presents

the longest vertical well pair separation (both wells are practically positioned adjacent

to the rock bounding the reservoir).

0 -1.7E+14

-5E+13 A

-1E+14

-1.8E+14 Heat Loss Cum , J , Loss CumHeat -1.5E+14 H5-Case 1 H5-Case 2 H5-Case 3 H5-Case 4 880 890 900 H5-Case 5 H5-Case 6 -2E+14 H5-Case 7 0 100 200 300 400 500 600 700 800 900 1000 Time, Days

-5E+13 B

-1E+14

-1.5E+14 H5-Case 8 H5-Case 9 H5-Case 10

Heat Loss Cum , J , Loss CumHeat H5-Case 11 H5-Case 12 H5-Case 13

-2E+14 0 100 200 300 400 500 600 700 800 900 1000 Time, Days

-5E+13 C

-1E+14

-1.5E+14 Heat Loss Cum , J , Loss CumHeat

H5-Case 9 H5-Case 10 H5-Case 11 H5-Case 12 -2E+14 0 100 200 300 400 500 600 700 800 900 1000 Time, Days Figure 3-12 Heat loss versus time for Model H5, (A) aligned (B) not aligned, (C) best case scenarios.

The change of heat loss is not significant compared to the other cases (Cases H5-3, 5, 6 and 7). The temperature profile showed a better distribution in comparison with H5-2 but at cost of higher heat loss.

In Fig. 3-12B, a change of the horizontal separation between the wells has profound effects on SAGD performance since it delays oil production significantly.

According to Fig. 3-12C, the order with respect to heat losses from the highest to the lowest is Cases H5-11, H5-10, H5-9 and H5-12. Similar with what observed in the previous models, not vertically aligned cases lead to lowest heat loss.

Similar to previous models, the same trend in choosing the best cases scenarios (here:

H5-4, H5-5, H5-11 and H5-13) for cSOR, cumulative oil production and recovery factor did not appear. A comparison between Cases H5-4, H5-5, H5-11 and H5-13 indicates that, except for Case H5-11, the change in heat losses is not significant. The highest heat loss is achieved when the wellpairs have a vertical distance of 3 to 4.5m from each other. Introducing a horizontal separation reduces the heat loss as well as the oil recovery factor.

3.4.4. Best Case Scenarios

The best case scenarios for Models H10, H7 and H5 are compared with each other’s and a thicker reservoir layer of 25 m known as base case in the following sections.

3.4.4.1. Cumulative Steam-to-Oil Ratio

The cumulative steam-to-oil ratios (cSORs) for the best case scenarios and the thicker base case are shown and compared with each other in Fig. 3-13. In all cases, lower cSOR is achieved by positioning the producer well at 0.25 m above understrata with a vertical alignment of the injection and production wells. The optimum vertical distance attained for the 7, 10 and 25 m reservoirs was found to be equal to 5 m and 4.5 m for the 5 m reservoir.

7 3

/m 6 3 5

2 SOR Cumulative , m 1 H25-Base Case H10-Case 6 H7-Case 4 H5-Case 5

0 0 100 200 300 400 500 600 700 800 900 1000

Time, Days

Figure 3-13 Steam oil ratio (SOR) versus time for best case scenarios.

A comparison between the cases reveals that the thicker the layer, the smaller the

cSOR. Also the cSOR profile, between 100 to 300 production days, shows a local maximum of the cSOR. Beyond this peak, the cSOR drops to a local minimum and then it grows once again for the best case scenarios. The early peak is related to higher capacity of reservoir to accept steam (larger net pay zone) and increasing heat losses to the rock outside the reservoir. Slower growth of the cSOR beyond the local minimum is observed for the thicker reservoirs. The cSOR for the thicker base case leads to a gradual decrease. Approximately, cSOR with a value of around 3.5, 4.2, 5.4 and 7.2 m3/m3 are

obtained for oil reservoirs of thickness 25, 10, 7 and 5 m, respectively.

3.4.4.2. Cumulative Produced Oil

The cumulative produced oil volume profiles for the best case scenarios together with

the thicker base case are shown in Fig. 3-14. The same trends of the rise of the

cumulative oil production for all oil reservoir thicknesses are observed. However, the

greater the thickness of the reservoir, the higher is the cumulative oil produced and the

oil rate. Obviously, a thicker layer consists of larger pay zone and consequently higher

amount of oil which allows for higher cumulative production at the same production

time.

70000 3

60000

50000

40000

30000

20000

Cumulative Oil , Oil m Production Cumulative 10000 H25-Base Case H10-Case 6 H7-Case 4 H5-Case 5 0 0 100 200 300 400 500 600 700 800 900 1000

Time, Days

Figure 3-14 Cumulative produced oil versus operation time for best case scenarios.

3.4.4.3. Oil Recovery Factor

The profiles of the oil recovery factor versus the pore volume injected steam (PVSI) for the best case scenarios together with the thicker base case are presented in Fig. 3-15.

Even in the thinnest case, the recovery factor of 55% can be achieved but at higher cost of injected steam (PVSI=2.8). The thicker the oil column, the higher the oil recovery factor is given a PVSI. A range of 55 to 60% was observed for oil reservoir thickness of 5 to 10 m. For the base case of 25 m about 33% cumulative oil recovery observed at the end of 900 operation days. Obviously due to the size of reservoir it takes longer time to achieve higher recovery factor. For example, the cumulative recovery factor increased

to 69% (H25-Base Case*) after 1500 operation days. To achieve the same recovery

factor, a greater PVSI is required as the oil reservoir gets thinner.

Oil Factor Recovery Oil 10 H25-Base Case H25-Base Case* H10-Case 6 H7-Case 4 H5-Case 5 0 0 0.5 1 1.5 2 2.5 3

PVSI Figure 3-15 Oil recovery factor versus pore volume steam injected (PVSI) for best case scenarios.

3.4.4.4. Cumulative Heat Loss

The cumulative heat losses for the best case scenarios are depicted in Fig. 3-16. Ignoring

Case H5-12, it can be concluded that higher layer thicknesses lead to lower heat losses.

In all cases with the exception of H5-12, the producer well is located at 1.75 m above

the underburden and the injector well is positioned with a vertical and horizontal

distances of 2.5 and 8 m respectively. Turning our attention to Case H5-12, it is shown

that this particular well configuration leads to a lower heat loss than that of layer

79 thickness of 7 and 10 m. Here both injector and producer wells are positioned at the adjacent block to the underburden and 4 m apart. Evaluating SAGD well performance based on the lowest heat losses does not make sense as far as we are interested in achieving higher oil recovery and production.

-5E+12

-1E+13 Heat Loss Cum, J H10- Case 9 H7-Case 6 H5-Case 12 H5- Case 9

-1.5E+13 0 100 200 300 400 500 600 700 800 900 1000 Time, Days

Figure 3-16 Heat loss versus time for best case scenarios.

In our investigation, the best case scenarios from the heat loss point of view led to poorest SAGD well performances.

The selected well configuration of best case scenarios (H10-6, H7-4 and H5-5) for cSOR, cumulative oil production and oil recovery were similar and completely different from the well configuration selected for heat loss best case scenarios (H10-9, H7-6 and H5-

12).

In order to be able to come in conclusion, we are selecting Cases H10-6, H7-4 and H5-5 and look at their heat loss behavior. This is depicted in Fig. 3-17 and reveals that layer thickness of 10 m leads to lower heat loss (-1.67 x 1014 J). However, for the particular well arrangement in H7-4 and H5-5 the heat losses almost are the same. Under the same circumstances, the base case of 25 m thickness leads to a cumulative heat loss of

(-1.14 x1014 J).Roughly, thinner layers lead to 46% up to 59% more heat loss in comparison with the thicker base case.

-5E+13

-1E+14 Heat Loss Cum, J -1.5E+14

H25-Base Case H10- Case 6 H7-Case 4 H5-Case 5

-2E+14 0 100 200 300 400 500 600 700 800 900 1000 Time, Days

Figure 3-17 Heat loss behaviour for best case scenarios.

3.4.4.5. Temperature Distributions and Well Pairs Arrangement

The wellpairs arrangements as well as temperature distribution for best case scenarios

(regardless of best heat loss cases) are depicted in Fig. 3-18. As the oil reservoir

thickness decreases, the steam injector position gets closer to overburden. The injector

distance from the overburden for Cases H10-6, H7-4, and H5-5 are 4.75, 1.75 and 0.75

m, respectively. Therefore, a higher heat loss to overburden is expected. As the oil

reservoir thickness increases, better temperature distribution is expected due to smaller

heat loss and better heat transfer to the larger reservoir volume.

(A)

(B)

(C)

Figure 3-18 Wellpair arrangements and temperature distribution for best case scenarios. (A) H10-6, (B) H7-4, (C) H5-5.

3.5. Conclusions

The influence of well configuration on the production performance of SAGD operation

was studied in thin (less than 10 m thick) oil sand reservoirs. Production is possible with

oil recovery factors of 60% to 55% at cSORs equal to about 4, 5, and 7 m3/m3 for oil

reservoir thicknesses of 10, 7 and 5m, respectively. The best case scenarios were achieved by positioning the producer well at 0.25 m above the understrata and having a vertical wellpairs alignment with a distance of about 4 to 5 m. The steam injector distance from overburden was varied between 0.75 and 4.75 m. The results imply that with the decrease in oil reservoir thickness, position of the injector well gets closer to the overburden. The cumulative heat losses were almost in the same range for oil reservoir equal to 5 and 7 m and slightly lower for layer thickness of 10 m. In comparison with a thicker layer reservoir of 25 m, higher heat losses were observed –

the increase in heat loss led to 46, 56 and 59% for layer thickness of 10, 7 and 5 m respectively.

It can be concluded that vertical as well as horizontal distances between wellpairs, and

their position or distances in respect to over and underburden rock affect the SAGD

production. Finding an optimum value will have an influence in cSOR, heat loss, recovery

factor and oil production. Therefore, to maximize SAGD production in thin oil sands

reservoirs requires finding an optimized well configuration. Introducing a horizontal

separation between the injector and producer wells usually decreases SAGD

83 performance through delayed oil production. Under our experimental condition, a horizontal offset of about 1.6 m was found to be optimal.

CHAPTER 4. PERFORMANCE OF STEAM ASSISTED GRAVITY DRAINAGE IN THIN OIL SAND RESERVOIRS: WELL PAIR CONFIGURATION IN A SINGLE PRODUCER - DOUBLE INJECTOR SET UP

Summary

The performance of Steam Assisted Gravity Drainage (SAGD) is studied in thin oil sand

reservoirs where the basic unit of operation is a single producer with two steam

injectors. Specifically, the influence of the injection and production well triplet

configuration is investigated in homogeneous oil sands formations with thicknesses of 5,

7, and 10 m. Various well configurations were explored where the vertical and horizontal spacing between the injection and production wells were varied. Thus, well

locations with respect to the overburden and understrata rock also varied. SAGD

performance was assessed numerically by using a thermal reservoir simulator and the

cumulative steam-to-oil ratio (cSOR), cumulative oil production, cumulative heat loss,

and oil recovery factor were compared. The results of study were compared with the

best case scenarios from single producer-single injector well configurations. The results

suggest that horizontal and vertical distances between injectors and the producer well,

their locations from the overburden and understrata and their vertical alignment impact

their performance. The results also show that the addition of an offset injector well

85 reduces cSOR under certain well configuration. Generally, the dual injector-single- producer performs better than the single injector-single-producer.

4.1. Introduction

The Steam-Assisted Gravity Drainage (SAGD) oil sands recovery process is an effective commercial process for viscous oil recovery when the reservoir thickness is greater than about 15 m (Gates, 2010). However, in thinner oil sands reservoir (< 10 m), heat losses from the steam chamber to the overburden and understrata are significant and the process is considered inefficient and uneconomic. However, the importance of thin oil sand reservoirs lies in the fact that about 80% of extra heavy oil resources exist in reservoirs with a net pay zone of less than about 5 m in Western Canada (Adams, 1982).

Thus, there is a need for new efficient processes to produce these resources.

In Chapter 3, the importance and influence of well configuration on SAGD performance in thin oil sand reservoirs (≤ 10 m) were investigated. The key parameters such as vertical as well as horizontal separation between the injector and producer wells, and their positions with respect to overburden and understrata were evaluated by using a single injector-single producer system. It was shown that these parameters have an influence on the cSOR, heat losses, recovery factor, and cumulative oil production.

Introducing a horizontal separation between the wells usually decreases SAGD performance at the cost of delaying the onset of oil production. However, unless the

vertical distance is already less than the optimum value, then a small horizontal shift or

offset improves process performance. From the study in Chapter 3, a horizontal offset of

about 1.6 m between the wells is suggested.

The focus of the research documented here is an evaluation of a dual injector-single

producer well configuration in thin oil sands reservoir (≤ 10 m). In practice, the dual injector could be completed in the reservoir using multilateral drilling technology and thus, there are no technical barriers to using dual injection wells as envisioned in the

research documented here.

4.2. Reservoir Simulation Model

The reservoir simulation model consists of a two-dimensional homogenous model with

horizontal wellpairs. The reservoirs do not have gas cap or bottom water zones.

Specifically, similar to Chapter 3, three reservoir models were developed with oil sand

intervals of 5, 7, and 10 m thickness, respectively labeled as cases H5-2Inj, H7-2Inj, and

H10-2Inj. It should be noted that for the sake of comparison with Chapter 3 results, the

2Inj suffix added to model names implies that the SAGD well configuration consists of

single-producer-double injector wells. The second injector well is referred as 2Inj or

offset well here.

A regular Cartesian grid system was used to discretize the models with dimensions of

58 grids with a block size of 0.8 m in the cross well direction, 1 grid block with length

750 m in the downwell direction. In the vertical direction, there are 10, 14, and 20 grid

blocks in the H5-2Inj, H7-2Inj, and H10-2Inj models, respectively, all with grid block

dimensions equal to 0.5 m. The reservoir model properties and parameters are listed in

Table 4-1.

Simulations were performed using a commercial thermal reservoir simulator CMG

STARSTM version 2013 (CMG, 2013) which has been used in the oil sands industry for over 15 years for SAGD simulation. In this finite volume thermal reservoir simulator, the conservation of energy and mass equations are simultaneously solved over each grid block together with the phase behavior and relative permeability curves for the gas, aqueous, and oil phases. At the lateral sides of the model, symmetry boundary conditions were imposed (no flow or heat transfer). In other words, the width of the reservoir represents the horizontal well spacing and implies that the well triplets are

part of a larger pattern.

In our models, to establish thermal communication between injector and producer

wells, the steam circulation time was set equal to 3 months. In the model, this was

done by placing temporary heaters in the locations of the wells. When SAGD mode

started, the temporary heaters were turned off and steam injection and fluid production

started. The operation was simulated for up to 3 years.

Table 4-1 Reservoir simulation model and fluid properties.

Property Value

Table 4-1 Reservoir simulation model and fluid properties (continued).

4.3. Reservoir Models

4.3.1. Model H10-2Inj

The reservoir cross-sectional views and detailed well configuration in Model H10-2Inj

with a single producer and dual injector cases are depicted in Table 4-2. Each well

location is defined by its grid block number in the horizontal (I and J) and vertical (K)

directions as well as vertical and horizontal separations between the injector wells and

the producer well. Model H10-2Inj was run with 10 different cases to investigate the

influence of well configuration on performance.

For all Model H10-2inj cases, the producer well is placed in grid block 30 in the I- direction. However the vertical positioning of the producer well was varied. In Cases

H10-2Inj-1 to H10-2Inj-3 as well as Case H10-2Inj-6, the producer well was placed 1.75

m above the base of the oil reservoir (grid block 17 in the K-direction). For the rest of

the H10-2Inj cases, the producer well is positioned 0.25 m above the bottom of the

reservoir (grid block 20 in the K-direction).

Cases H10-2Inj-1 through H10-2Inj-5 are the vertically aligned well pairs (one of the

injector wells is aligned with the producer well). In these configurations the offset

injector well (Inj-2) was positioned with a vertical and horizontal separation away from

the producer and aligned injector (Inj-1) well. Cases H10-2Inj-6 and H10-2Inj-10 are the

91 not vertically aligned configurations where the injector wells are positioned at both sides of the producer well.

Table 4-2 Well placement in Model H10-2Inj with a layer thickness of 10 m.

Case Well Grid Grid Grid Vert. Horiz. Image i j k Dist. Dist. (m) (m) H10- Prod. 30 1 17 2Inj-1 Inj-1 30 1 12 2.5 0 Inj-2 32 1 12 2.5 1.6

H10- Prod. 30 1 17 2Inj-2 Inj-1 30 1 12 2.5 0 Inj-2 35 1 12 2.5 4

H10- Prod. 30 1 17 2Inj-3 Inj-1 30 1 12 2.5 0 Inj-2 40 1 12 2.5 8

H10- Prod. 30 1 20 2Inj-4 Inj-1 30 1 10 5 0 Inj-2 35 1 10 5 4

H10- Prod. 30 1 20 2Inj-5 Inj-1 30 1 10 5 0 Inj-2 32 1 15 2.5 1.6

H 10- Prod. 30 1 17 2Inj-6 Inj-1 28 1 12 2.5 1.6 Inj-2 33 1 12 2.5 2.4

H10- Prod. 30 1 20 2Inj-7 Inj-1 28 1 10 5 1.6 Inj-2 33 1 10 5 2.4

H10- Prod. 30 1 20 2Inj-8 Inj-1 28 1 15 2.5 1.6 Inj-2 33 1 10 5 2.4

H10- Prod. 30 1 20 2Inj-9 Inj-1 28 1 15 2.5 1.6 Inj-2 32 1 15 2.5 1.6

H10- Prod. 30 1 20 2Inj-10 Inj-1 28 1 15 2.5 1.6 Inj-2 33 1 15 2.5 2.4

In general, the vertical separations between injectors and producers were varied between 2.5 to 5 m. The horizontal separation of the offset injector well to the producer well was varied between 1.6 to 8 m.

4.3.2. Model H7-2Inj

The reservoir cross-sectional views and detailed well configuration in Model H7-2Inj are

shown in Table 4-3. Model H7-2Inj was evaluated with 8 well configuration cases. The

producer well in Model H7-2inj is placed at grid block 30 in the I-direction for all of the

cases. In Cases H7-2Inj-1 through H7-2Inj-3, the producer well was placed 1.75 m above

the bottom of the reservoir (grid block 11 in the K-direction) and 0.25 m above the base

of the reservoir (grid block 14 in the K-direction) for Cases H7-2Inj-4 through H7-2Inj-8.

Cases H7-2Inj-1 through H7-2Inj-6 are the vertically aligned well cases (one injector is

aligned with the producer). In these configurations the offset injector well (Inj-2) was

positioned with a vertical and horizontal separation away from the producer and aligned

injector (Inj-1) wells.

Cases H7-2Inj-7 and H7-2Inj-8 are the not vertically aligned cases in which the injector

wells are positioned at both sides of the producer well. In general, the vertical distance

between the injector and producer wells was varied between 1 to 5 m. The horizontal

distance of the offset injector well was varied between 1.6 to 8 m.

Table 4-3 Well placement in Model H7-2Inj with a layer thickness of 7 m.

Case Well Grid Grid Grid Vert. Horiz. Image i j k Dist. Dist. (m) (m) H7- Prod. 30 1 11 2Inj-1 Inj-1 30 1 6 2.5 0 Inj-2 35 1 6 2.5 4

H7- Prod. 30 1 11 2Inj-2 Inj-1 30 1 6 2.5 0 Inj-2 40 1 6 2.5 8

H7- Prod. 30 1 11 2Inj-3 Inj-1 30 1 9 1 0 Inj-2 35 1 9 1 4

H7- Prod. 30 1 14 2Inj-4 Inj-1 30 1 9 2.5 0 Inj-2 35 1 9 2.5 4

H7- Prod. 30 1 14 2Inj-5 Inj-1 30 1 4 5 0 Inj-2 35 1 4 5 4

H7- Prod. 30 1 14 2Inj-6 Inj-1 30 1 4 5 0 Inj-2 32 1 9 2.5 1.6

H7- Prod. 30 1 14 2Inj-7 Inj-1 28 1 4 5 1.6 Inj-2 33 1 4 5 2.4

H7- Prod. 30 1 14 2Inj-8 Inj-1 28 1 9 2.5 1.6 Inj-2 33 1 4 5 2.4

4.3.3. Model H5-2Inj

The reservoir cross-sectional views and detailed well configuration of the 9 Model H5-

2Inj cases are listed in Table 4-4. The producer well in Model-H5-2inj is placed in grid block 30 in the I-direction for all cases. In Cases H5-2Inj-1 through H5-2Inj-3, the producer well was placed 1.75 m above the base of the oil reservoir (grid block 7 in the

K-direction). For Cases H5-2Inj-4 to H5-2Inj-9, the producer well was placed 0.25 m above the bottom of the reservoir (grid block 10 in the K-direction).

Cases H5-2Inj-1 through H5-2Inj-7 are the vertically aligned well pairs (where one injector is aligned with the producer well). In these configurations the offset injector well (Inj-2) was positioned with a vertical and horizontal separation away from the producer and aligned injector (Inj-1) wells.

Cases H5-2Inj-8 and H5-2Inj-9 are the not vertically aligned cases in which the injector wells are positioned at both sides of the producer well. In general, the vertical distance between the injector and producer wells was varied between 1 to 4 m. The horizontal separation of the offset well was varied between 1.6 to 8 m.

Table 4-4 Well placement in Model H5-2Inj with a layer thickness of 5 m.

Case Well Grid- Grid- Grid- Vert. Horiz. Image i j k Dist. Dist. (m) (m) H5- Prod. 30 1 7 2Inj-1 Inj-1 30 1 2 2.5 0 Inj-2 35 1 2 2.5 4

H5- Prod. 30 1 7 2Inj-2 Inj-1 30 1 2 2.5 0 Inj-2 40 1 2 2.5 8

H5- Prod. 30 1 7 2Inj-3 Inj-1 30 1 5 1 0 Inj-2 35 1 5 1 4

H5- Prod. 30 1 10 2Inj-4 Inj-1 30 1 2 4 0 Inj-2 35 1 2 4 4

H5- Prod. 30 1 10 2Inj-5 Inj-1 30 1 2 4 0 Inj-2 35 1 6 2 4

H5- Prod. 30 1 10 2Inj-6 Inj-1 30 1 2 4 0 Inj-2 35 1 10 0 4

H5- Prod. 30 1 10 2Inj-7 Inj-1 30 1 2 4 0 Inj-2 32 1 10 0 1.6

H5- Prod. 30 1 10 2Inj-8 Inj-1 28 1 2 4 1.6 Inj-2 33 1 2 4 2.4

H5- Prod. 30 1 10 2Inj-9 Inj-1 28 1 2 4 1.6 Inj-2 33 1 5 2.5 2.4

4.4. Results and Discussion

The simulation results compared consist of the cumulative steam-to-oil ratio (cSOR) versus time, cumulative oil production versus time, oil recovery factor versus pore volume of steam injected (PVSI), and cumulative heat loss versus time.

4.4.1. Model H10-2Inj

4.4.1.1. Cumulative Steam-to-Oil Ratio

Cumulative steam-to-oil ratios (cSOR) profiles for Model H10-2Inj with a layer thickness

of 10 m are shown in Fig. 4-1. The cSOR profiles change in a close range from 4.1 to 4.5

m3/m3 and include both aligned and not aligned configurations.

In Cases H10-2Inj-1 through H10-2Inj-3, the position of the offset injector well (Inj-2)

was increased from 1.6 to 8 m horizontally. This change of the separation causes a slight

decrease in cSOR.

Similar to what was observed in Chapter 3, positioning the producer well at the adjacent

layer to the understrata reduces the cSOR due to collection of oil from a larger area of

the reservoir. This result is observed for both vertically aligned and non aligned cases. A

cSOR reduction of 4.5 to 4.4 m3/m3 was observed for the not vertically aligned well

Cases H10-2Inj-6 and H10-2Inj-10. For vertically aligned cases H10-2Inj-2 and H10-2Inj-4,

a decrease of cSOR from 4.4 to 4.2 m3/m3 was found. A comparison between these two

cases reveals that the position of the injector wells and their distance from the producer well affects the cSOR.

In the vertically aligned Case H10-2Inj-5, the position of the offset injector well was

changed such that there is no alignment between both injectors. The offset well is

positioned at a vertical and horizontal distances of 2.5 and 1.6 m to the producer well.

The cSOR obtained was equal to 4.2 m3/m3. A comparison between the cSOR for the single injector-single producer, Case H10-6 described in Chapter 3, reveals no significant

change in cSOR.

Not vertically aligned Case H10-2Inj-7 leads to almost similar cSOR as in the vertically

aligned Case H10-2Inj-4. Here the lowest cSOR observed is about 4.1 m3/m3 for Cases

H10-2Inj-4 and H10-2Inj-7. Further increase of the cSOR to 4.4 m3/m3 is observed when

the vertical distance between injectors and the producer is reduced from 5 to 2.5 m in

not vertically aligned cases H10-2Inj-9 and H10-2Inj-10. Under this well configuration, a

further reduction of the separation between injectors from 5 to 3.2 m yields to a slight

reduction of cSOR.

It can be concluded that the horizontal and vertical separations between injectors and

the producer well, their positions away from the overburden and understrata and their

alignments affects cSOR. Here, 10 different triple well configurations were examined. A

comparison with single injector-single producer well configuration in Model H10 reveals

a tighter cSOR variation range in Model H10-2Inj. That is a cSOR of 4.5 to 4.1 and 4 to

8.4 m3/m3 for Model H10-2Inj and Model H10 respectively.

100

5 3 4 4.5 /m 3

, m 4.4 3 4.3

2 4.2 H10-2Inj-Case 1 H10-2Inj-Case 2

SOR Cumulative Cumulative SOR H10-2Inj-Case 3 H10-2Inj-Case 4 4.1 1 H10-2Inj-Case5 H10-2Inj-Case 6 H10-2Inj-Case 7 H10-2Inj-Case 8 4 H10-2Inj-Case 9 H10-2Inj-Case 10 880 890 900 0 0 100 200 300 400 500 600 700 800 900 1000

Time, Days Figure 4-1 Cumulative steam-to-oil ratio versus time for Model H10-2Inj cases.

4.4.1.2. Cumulative Produced Oil

As shown in Fig. 4-2, Case H10-2Inj-5 has the highest cumulative oil production followed by Cases H10-2Inj-8, H10-2Inj-10, H10-2Inj-9, H10-2Inj-6, H10-2Inj-1, H10-2Inj-2, H10-

2Inj-3, H10-2Inj-4 and H10-2Inj-7. Cases H10-2Inj-5 and H10-2Inj-8 are examples of vertically aligned and not aligned configurations, respectively. Recalling the results of their related cSOR from the previous section reveals that these cases did not led to the lowest cSOR in their group. Therefore, it can be concluded that lower cSOR cannot be interpreted as higher cumulative oil production or a better performance. There are other factors in play such as heat loss and oil recovery factor.

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50000

3 40000 44000

43600 30000 H10-2Inj- Case 1 43200 H10-2Inj-Case 2 H10-2Inj-Case 3 20000 42800 H10-2Inj-Case 4 H10-2Inj-Case 5 42400 H10-2Inj-Case 6 830 835 10000 H10-2Inj-Case 7 H10-2Inj-Case 8 Cumulative Oil , Oil m Production Cumulative H10-2Inj-Case 9 H10-2Inj-Case 10 0 0 100 200 300 400 500 600 700 800 900 1000 Time, Days

Figure 4-2 Cumulative produced oil versus time for Model H10-2Inj cases.

In Cases H10-2Inj-1 through H10-2Inj-3, the cumulative oil production slightly decreased as the position of the offset injector well (Inj-2) increases. It can be due to delay in thermal communication between injectors and the producer. The impact of the positioning of the producer well above the understrata on the cumulative oil production is shown in Cases H10-2Inj-6 and H10-2Inj-10. The results show that lower the producer is in the oil reservoir, the greater the cumulative oil production volume.

It was observed that the not vertically aligned Case H10-2Inj-7 with the producer wells

0.25 m above the understrata exhibit the lowest cSOR in its group. However, the same case led to the lowest cumulative oil production in its group of the not aligned cases.

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Similar behavior was observed regarding H10-2Inj-4. Apparently, the production is delayed in these cases. Cases H10-2Inj-10 and H10-2Inj-9 both show a higher oil production than Cases H10-2Inj-7 but a lower produced volume than that of Case H10-

2Inj-8. These cases confirm that position of injector wells with respect to the overburden and understrata has an impact on oil production.

4.4.1.3. Oil Recovery Factor

According to Fig. 4-3, recovery factors between 59 to 63% are achieved for all cases with

PVSI in the range of 1.77 to 1.95. At PVSI of 1.76, the recovery factor is the highest for

Cases H10-2Inj-5 and H10-2Inj-8 followed by Cases H10-2Inj-4, H10-2Inj-7, H10-2Inj-9,

H10-2Inj-10, H10-2Inj-3, H10-2Inj-2, H10-2Inj-6, and H10-2Inj-1. As expected, to achieve higher recovery factor a higher PVSI is required. In Case H10-2Inj-7, a recovery factor of

63% at PVSI of 1.94 is realized. Cases H10-2Inj-5 and H10-2Inj-8 exhibit the same recovery factor at PVSI of 1.75, but the well configuration in Case H10-2Inj-8 enables higher recovery factor equal to 61.8% at a PVSI of 1.86.

In Cases H10-2Inj-1 through H10-2Inj-3, the oil recovery factor (at certain PVSI) slightly increases as the distance between injector wells increases. However, the ultimate recovery factor was increased at higher cost of PVSI as the separation between injector wells decreased. It appears that longer distance between injector wells allows for more steam injection due to the delay of thermal communication between the offset injector

103

and the producer well. The impact of the positioning of the producer well just above

the understrata on the recovery factor is illustrated by Cases H10-2Inj-6 and H10-2Inj-

10. It reveals that the oil recovery factor increases as the producer well get closer to

understrata. This is because oil under the producer well is not recovered since there is

no force that would promote movement of oil from layers under the well. Cases H10-

2Inj-4 and H10-2Inj-5 represent vertically aligned and cases H10-2Inj-7 and H10-2Inj-8

not aligned cases. A comparison between these cases reveals that not aligned cases led

to higher steam injectivity and therefore a higher recovery factor.

63 50 62 40 61 30 60

20 59

Oil Factor Recovery Oil H10-2Inj-Case 1 H10-2Inj-Case 2 H10-2Inj-Case 3 H10-2Inj-Case 4 10 H10-2Inj-Case 5 H10-2Inj-Case 6 58 H10-2Inj-Case 7 H10-2Inj-Case 8 H10-2Inj-Case 9 H10-2Inj-Case 10 0 57 0 0.5 1 1.5 2 56 PVSI 1.65 1.75 1.85 1.95 Figure 4-3 Oil recovery factor versus pore volume steam injected for Model- 10-2Inj cases.

104

4.4.1.4. Cumulative Heat Loss

The profiles of the cumulative heat losses are presented in Fig. 4-4. Case H10-2Inj-5 has the highest loss whereas Case H10-2Inj-7 and H10-2Inj-4 show the lowest heat loss. The rest of cases show approximately similar heat losses. Cases H10-2Inj-4 and H10-2Inj-7 represent the vertically aligned and not aligned cases. In spite of different well alignment, the well configuration with respect to producer well position, and distance of injector wells from the overburden and distance between injector and producer, the results are similar. However, Case H10-2Inj-7 allows for more steam injectivity and higher recovery factor at a cost of higher PVSI. Case H10-2Inj-5 shows that the highest heat loss is due to positioning of the offset well at closer distance (2.5 m) to understrata and a probable steam short circuiting directly from the injector to the producer wells.

The closer distance of offset injector well to the producer makes it possible to achieve higher cumulative oil production as it was shown in Fig. 4-2.

Cases H10-2Inj-1 through H10-2Inj-3 represents the effect of the offset injection well from the producer well. As the offset well distance increases, the heat losses decreases.

It implies that longer distance between injector wells prevents steam short circuiting and probably reaches a larger region of the reservoir. However, as was mentioned above, the delay of thermal communication between the offset injector and the producer well causes lower recovery factor at comparable times.

105

0 -1.4E+14

-5E+13 -1.45E+14

-1.5E+14 -1E+14

-1.55E+14

-1.5E+14 H10-2Inj-Case 1 H10-2Inj-Case 2 Heat Loss Cum, J H10-2Inj-Case 3 H10-2Inj-Case 4 -1.6E+14 H10-2Inj-Case 5 H10-2Inj-Case 6 H10-2Inj-Case7 H10-2Inj-Case 8 820 H10-2Inj-Case 9 H10-2Inj-Case 10 -2E+14 0 100 200 300 400 500 600 700 800 900 1000

Time, Days

Figure 4-4 Heat loss versus time for Model- 10-2Inj cases.

The impact of injector well positioning on the heat loss is compared in Cases H10-2Inj-7 and H10-2Inj-8. Case H10-2Inj-8 shows a higher heat loss compared to Case H10-2Inj-7.

In Case H10-2Inj-8, the well arrangement of one of the injector wells is positioned at closer distance (2.5 m) to the producer well and underburden. Cases H10-2Inj-8 and

H10-2Inj-2 show similar heat losses in spite of having different well configuration, different cSOR, oil recovery factor and oil production. It implies that having a lower heat loss does not guarantee better process performance. A comparison between Cases

H10-2Inj-8 and H10-2Inj-5 shows the lower heat loss and cSOR, higher recovery factor at cost of higher PVSI and slightly lower cumulative oil production. It is difficult to pick the best case scenario without having an economical comparison or knowing the operational and production priorities; Case H10-2Inj-8 has been selected as the best case for further comparison with other cases. However, this particular case is very

106

comparable with Cases H10-2Inj-7 (not-vertically aligned) and H10-2Inj-4 (vertically

aligned).

4.4.2. Model H7-2Inj

4.4.2.1. Cumulative Steam-to-Oil Ratio

Cumulative steam-to-oil ratios (cSOR) for Model H7-2Inj (oil reservoir thickness of 7 m)

are shown in Fig. 4-5. The cSOR profiles occur in a range from 5.3 to 5.9 m3/m3. Similar

to the previous model the change in the cSOR for all the examined well configuration is

in a close range - a difference order of 0.6 m3/m3 .

In general, the aligned Cases (H7-2Inj-1 to H7-2Inj-3) with having the producer well 1.75

m away from the underburden show higher cSOR with values at around 5.7 to 5.8

m3/m3.

When the position of the offset injector well (Inj-2) was increased from 4 to 8 m

horizontally, a slight decrease in cSOR was observed.

A way to decrease cSOR in these aligned cases is the placement of the producer well at

closer distance to the underburden – as it was done in Case H7-2Inj-4 and 5 in

comparison with Case H7-2Inj-1.

107

Placing the offset injector well at closer distance to the producer well, as was done in

Case H7-2Inj-6 in comparison with Case H7-2Inj-5, causes an increase in cSOR in the

aligned cases.

While arranging the injectors on both sides of the producer well, as it is the case in H7-

2Inj-8 in comparison with Case H7-2Inj-6, decreases the cSOR. No significant changes in

cSOR were observed in vertically aligned and not aligned cases of H7-2Inj-5 and H7-2Inj-

A comparison between the single injector-single producers (Case H7-4, cSOR of 5.4

m3/m3) reveals that addition of an offset injector well can help to reduce the cSOR only

under certain well configurations.

Not vertically aligned cases (where no injector is aligned with the producer) with the producer wells positioned 0.25 m above the understrata, with the exception of Case H7-

2Inj-5, exhibit the lowest cSOR ranging from 5.3 to 5.4 m3/m3. In Case H7-2Inj-7, similar

to vertically aligned Case H7-2Inj-5, the positioning of the injector wells in an aligned

arrangement leads to lower cSOR. When the injector wells are not aligned as is the case

with Case H7-2Inj-8 and Case H7-2Inj-6, the cSOR rises to 5.4 and 5.5 m3/m3

respectively.

Similar to the results of Model H10-2Inj, it can be concluded that the horizontal and

vertical distances between injectors and the producer well, their locations from the

overburden or understrata and their alignments affect cSOR. A comparison with single

108

injector-single producer well configuration in Model H7 reveals a closer cSOR variation

range in Model H7-2Inj. That is a cSOR of 5.3 to 5.9 and 5.3 to 7.8 m3/m3 for Model H7-

2Inj and Model H7 respectively.

6 H7-2Inj-Case 1 H7-2Inj-Case 2 H7-2Inj-Case 3 H7-2Inj-Case 4 H7-2Inj-Case 5 H7-2Inj-Case 6 H7-2Inj-Case 7 H7-2Inj-Case 8 5 3 /m 3

, m 4

3 SOR Cumulative Cumulative SOR 2

1 0 100 200 300 400 500 600 700 800 900 1000 Time, Days Figure 4-5 Cumulative steam-to-oil ratio versus time for Model H7-2Inj cases.

4.4.2.2. Cumulative Produced Oil

According to Fig. 4-6, Case H7-2Inj-6 has the highest cumulative oil production followed

very closely by Case H7-2Inj-8, and then Cases H7-2Inj-4, H7-2Inj-7, H7-2Inj-5, H7-2Inj-2,

H7-2Inj-1 and H7-2Inj-3.

109

Cases H7-2Inj-6 and H7-2Inj-8 present examples of the vertically aligned and not aligned cases (one injector and the producer). Recalling the results of cSOR for these two cases, the results reveal that both cases did not led to the lowest cSOR of their groups of well

arrangement. Here, both of these cases show the highest oil production in their own

groups. In Case H7-2Inj-8, in spite of having lower cSOR in comparison with Case H7-

2Inj-6, it did not realize a higher cumulative oil production. Again it can be concluded

that lower cSOR cannot be interpreted as higher cumulative oil production.

In Cases H7-2Inj-1 and H7-2Inj-2, the cumulative oil production rises slightly as the

position of the offset injector well (Inj-2) increases. This result is different with what was

observed in similar cases Model H10. The impact of the location of producer well on the

cumulative oil production is illustrated by Cases H7-2Inj-3 and H7-2Inj-4. The results

show that the cumulative oil production rises as the producer well is moved closer to

the understrata. A comparison between Cases H7-2Inj-7 and H7-2Inj-8 shows that Case

H7-2Inj-7 achieved lower cumulative oil production. This behavior is related to the

position of injector wells. In Case H7-2Inj-8, the well configuration provides more

balanced steam distribution in the formation due to having different distances from

overburden.

110

35000

30000 32500 3 25000 31500 30500 20000 29500 28500 15000 27500 26500 10000 H7-2Inj- Case 1 H7-2Inj-Case 2 25500 H7-2Inj-Case 3 H7-2Inj-Case 4 5000 24500 H7-2Inj-Case 5 H7-2Inj-Case6 845 850

Cumulative Oil , Oil m Production Cumulative H7-2Inj-Case7 H7-2Inj-Case8 0 0 100 200 300 400 500 600 700 800 900 1000

Time, Days Figure 4-6 Cumulative produced oil versus time for Model H7-2Inj cases.

4.4.2.3. Oil Recovery Factor

According to Fig. 4-7, recovery factors achieved are between 50 to 60% for all cases with

PVSI in the range of 2.1 to 2.4. At the lowest PVSI, the recovery factor is the highest for

Cases H7-2Inj-7 and H7-2Inj-5 followed by Cases H7-2Inj-8, H7-2Inj-6, H7-2Inj-4, H7-2Inj-

2, H7-2Inj-1, and H7-2Inj-3. At this particular PVSI, the recovery factor is equal to 50%.

To achieve higher recovery factor, a higher PVSI is required. For example, in Case H7-

2Inj-7, a recovery factor of 60.2% at PVSI of 2.4 is achieved. In Cases H7-2Inj-5, H7-2Inj-

7, and H7-2Inj-8 show similar recovery factor at PVSI of 2.2, but the only well

configuration that achieves higher recovery factor (60%) is that of Case H7-2Inj-8 at PVSI

of 2.4. In Cases H7-2Inj-1 and H7-2Inj-2, the oil recovery factor (at PVSI of 2.3) rises

slightly as the distance between injector wells increases.

111

The impact of the location of producer well on the recovery factor is illustrated by Cases

H7-2Inj-3 and H7-2Inj-4. The results show that the recovery factor enlarges as the producer well is lowered in the oil reservoir. In general, as shown in Fig. 4-7, the oil recovery factors can be roughly categorized into three groups of higher, medium and lower recovery factors. Cases H7-2Inj-4 through H7-2Inj-8 achieves higher recovery

factors followed by Cases H7-2Inj-1 and H7-2Inj-2, and the lowest is realized in Case H7-

2Inj-3. It is found out that in the highest category, similar to Model H10, the producer

well is located just above the understrata. Case H7-2Inj-3 shows that the lowest

recovery factor results from small inter well separation where steam short circuiting

occurs.

60 61 50 60 59 58 40 57 56 30 55 54 20 53 Oil Factor Recovery Oil 52 10 H7-2Inj-Case 1 H7-2Inj-Case 2 H7-2Inj-Case 3 2.1 2.3 2.5 H7-2Inj-Case 4 H7-2Inj-Case 5 H7-2Inj-Case 6 H7-2Inj-Case7 H7-2Inj-Case8 0 0 0.5 1 1.5 2 2.5 PVSI Figure 4-7 Oil recovery factor versus pore volume steam injected (PVSI) for Model H7- 2Inj cases.

112

4.4.2.4. Cumulative Heat Loss

The cumulative heat losses are depicted in Fig. 4-8. The results show that Case H7-2Inj-6 achieves the highest losses whereas Case H7-2Inj-3 results in the lowest heat losses.

Cases H7-2Inj-5 and H7-2Inj-7 represent examples of the vertically aligned and not aligned cases.

Cases H7-2Inj-1 and H7-2Inj-2 illustrate the effect of the offset of the injection well from the producer well. As the offset well distance rises, no significant changes were observed in the extent of heat loss. The impact of injector well positioning on the heat loss is compared in Cases H7-2Inj-7 and H7-2Inj-8 (smaller separation between injector and producer). Case H7-2Inj-8 shows a higher heat loss in comparison to that of Case

H7-2Inj-7.

-5E+13

-1E+14 Heat Loss Cum, J -1.5E+14 H7-2Inj-Case 1 H7-2Inj-Case 2 H7-2Inj-Case 3 H7-2Inj-Case 4 H7-2Inj-Case 5 H7-2Inj-Case 6 H7-2Inj-Case 7 H7-2Inj-Case 8 -2E+14 0 100 200 300 400 500 600 700 800 900 1000 Time, Days

Figure 4-8 Heat loss versus time for Model H7-2Inj cases.

113

Similar to the previous Model H10-2Inj, it is difficult to choose the best case scenario

without knowing the operational and production priorities; Case H7-2Inj-8 has been

selected as the best case for further comparison with other cases. However, this

particular well configuration is very comparable with Cases H7-2Inj-7 (not-vertically

aligned) and H7-2Inj-5 (vertically aligned).

4.4.3. Model H5-2Inj

4.4.3.1. Cumulative Steam-to-Oil Ratio

The cumulative steam-to-oil ratios (cSOR) for Model H5-2Inj (oil reservoir thickness 5 m)

are shown in Fig. 4-9. For these cases, the cSOR ranges from 7.1 to 7.7 m3/m3

depending on the well configuration. Generally, the aligned cases, Cases H5-2Inj-1 to

H5-2Inj-3 with having the producer well 1.75 m away from the underburden, exhibit

higher cSOR at around 7.6 to 7.7 m3/m3. When the position of the offset injector well

(Inj-2) was increased from 4 to 8 m horizontally, a slight decrease in cSOR was observed.

A way to decrease cSOR in these aligned cases is the placement of the producer well at a closer distance to the underburden - as it was done in Case H5-2Inj-4 in comparison with

Case H5-2Inj-1.

Placing the offset injector well at a closer distance to the producer well, as was done in

Case H5-2Inj-5 and Case H5-2Inj-6 in comparison with Case H5-2Inj-4, did not have a

significant effect on cSOR value. When the position of the offset injector well was

114

increased from 1.6 to 4 m horizontally, a slight decrease in cSOR was observed for Case

H5-2Inj-7 and Case H5-2Inj-6 respectively.

While arranging the injectors on both sides of the producer well, as it is the case in H5-

2Inj-8 in comparison with Case H5-2Inj-4, decreases the cSOR.

Not vertically aligned Case H5-2Inj-8 with the producer well positioned at 0.25 m above

the understrata exhibits the lowest cSOR of 7.1 m3/m3. In Case H5-2Inj-7, similar to

vertically aligned Cases, the positioning of the offset injector well in a closer

arrangement to underburden leads to higher cSOR. When the injector wells are not

aligned as it is the case in H5-2Inj-9, the cSOR rises to 7.2.

Recalling the result of cSOR for single injector-single producer well configuration in Case

H5-5 from Chapter 3, shows a value of 7.2 m3/m3. The addition of an offset injector well

to this arrangement reduces the cSOR further to 7.1 m3/m3. In cases where the

producer well is positioned at 0.25 m above the understrata and the injector wells are

not aligned with the producer well yields cSORs ranging from 7.1 to 7.2 m3/m3.

Similar to the results of the previous models, it can be concluded that the horizontal and

vertical distances between injectors and the producer well, their locations from the

overburden or understrata and their alignments affects cSOR. A comparison with single

injector-single producer well configuration in Model H5 reveals a closer cSOR variation

115

range in Model H5-2Inj. That is a cSOR of 7.1 to 7.7 and 7.1 to 7.9 m3/m3 for Model H5-

2Inj and Model H5 respectively.

7 3

/m 6 7.3 3

, m 5 7.2 4

3 7.1 H5-2Inj-Case 1 H5-2Inj-Case 2 2 H5-2Inj-Case 3 H5-2Inj-Case 4

SOR Cumulative Cumulative SOR H5-2Inj-Case 5 H5-2Inj-Case 6 7 1 H5-2Inj-Case 7 H5-2Inj- Case 8 890 900 0 H5-2Inj- Case 9 0 100 200 300 400 500 600 700 800 900 1000 Time, Days

Figure 4-9 Cumulative steam-to-oil ratio versus time for Model H5-2Inj cases.

4.4.3.2. Cumulative Produced Oil

As shown in Fig. 4-10, Cases H5-2Inj-4 to H5-2Inj-9 achieved the highest cumulative oil

production followed by Cases H5-2Inj-2, H5-2Inj-1, and H5-2Inj-3. Cases H5-2Inj-4 to H5-

2Inj-9 represents the vertically aligned and not aligned cases (one injector and

producer). The producer well in all cases is located at 0.25 m above the understrata. The

results show that different positioning of the offset well did not have any significant

influence on the cumulative oil production in spite of lower cSOR observed in Case H5-

2Inj-8. Here, the impact of the location of the producer well on the cumulative oil

116 production can be observed by comparison of Cases H5-2Inj-1 to H5-2Inj-3 with Cases

H5-2Inj-4 to H5-2Inj-9 – the lower is the producer, the higher is cumulative oil production.

In Cases H5-2Inj-1 and H5-2Inj-2, the cumulative oil production slightly increases as the position of the offset injector well (Inj-2) increases. This result is different with what was observed in similar cases of Model-H10 but is similar to the results obtained with

Model-H7. The results suggest that as the oil reservoir thickness decreases, having an offset distance of about 8 m is beneficial.

25000

20000 3

15000

10000

5000 H5-2Inj- Case 1 H5-2Inj-Case 2 H5-2Inj-Case 3 H5-2Inj-Case 4 H5-2Inj-Case 5 H5-2Inj-Case 6 H5-2Inj-Case7 H5-2Inj- Case 8 H5-2Inj- Case 9 Cumulative Oil , Oil m Production Cumulative 0 0 100 200 300 400 500 600 700 800 900 1000 Time, Days

Figure 4-10 Cumulative produced oil versus time for Model H5-2Inj cases.

117

4.4.3.3. Oil Recovery Factor

As displayed in Fig. 4-11, recovery factors of the H5-2Inj cases is between 45 and 54.7% with PVSI in the range from 2.60 to 2.85. At the lowest PVSI, the recovery factor is the highest for Cases H5-2Inj-8 followed by Cases H5-2Inj-9, H5-2Inj-4, H5-2Inj-5, H5-2Inj-6,

H5-2Inj-7, H5-2Inj-2, H5-2Inj-1, and H5-2Inj-3. Similar to other models (H10 and H7), a higher recovery factor is achieved at a higher PVSI. In Cases H5-2Inj-1 and H5-2Inj-2, the oil recovery factor (at PVSI of 2.65) slightly increases as the separation between the injector wells grows. The impact of the location of producer well on the recovery factor is shown in Cases H5-2Inj-1 and H5-2Inj-4; the results show that the recovery factor rises when the producer well is placed at the base of the oil reservoir. In general, as shown in

Fig. 4-11, the oil recovery factors can be roughly categorized in two groups. Cases H5-

2Inj-4 through H5-2Inj-9 present higher recovery factors and Cases H5-2Inj-1 to H5-2Inj-

3 are the lower ones. Similar to Models H10-2Inj and H7-2Inj, the producer well located at the base of the oil reservoir achieves the highest recovery factor. Case H5-2Inj-3 shows that the lowest recovery factor occurs in the case where a lot of steam circuiting occurs. It seems that as the layer thickness decreases, the performance become less sensitive to well configuration with respect to the oil recovery factor.

118

55 40 54.5 30 54

20 53.5

Oil Factor Recovery Oil 10 53 H5-2Inj-Case 1 H5-2Inj-Case 2 H5-2Inj-Case 3 2.65 2.75 2.85 H5-2Inj-Case 4 H5-2Inj-Case 5 H5-2Inj-Case 6 0 H5-2Inj-Case 7 H5-2Inj-Case 8 H5-2Inj-Case 9 0 0.5 1 1.5 2 2.5 3 PVSI Figure 4-11 Oil recovery factor versus pore volume steam injected (PVSI) for Model H5-2Inj cases.

4.4.3.4. Cumulative Heat Loss

The cumulative heat losses for the H5-2Inj cases are depicted in Fig. 4-12. Case H5-2Inj-9 has the highest heat losses whereas Case H5-2Inj-3 has the lowest heat losses. In Cases

H5-2Inj-1 and H5-2Inj-2, as the offset well distance increases, the heat losses increase slightly. Similar heat losses can be observed for Cases H5-2Inj-4, 7 and 8. A comparison between Cases H5-2Inj-4 and H5-2Inj-6 reveal that positioning each of the injector wells close to the overburden and understrata can lead to somewhat lower heat loss. As it was discussed in previous cases, the lower heat loss cases do not correspond to better process performance.

119

0 -1.6E+14 -1.64E+14 -1.68E+14 -5E+13 -1.72E+14 H5-2Inj- Case 1 -1.76E+14 H5-2Inj-Case 2 -1E+14 H5-2Inj-Case 3 -1.8E+14 H5-2Inj-Case 4 -1.84E+14 H5-2Inj-Case 5 -1.88E+14 H5-2Inj-Case 6 890 895 900

Heat Loss Cum, J -1.5E+14 H5-2Inj-Case 7 H5-2Inj-Case 8 H5-2Inj-Case 9 -2E+14 0 100 200 300 400 500 600 700 800 900 1000

Time, Days

Figure 4-12 Heat loss versus time for Model H5-2Inj cases.

Case H5-2Inj-9 has been selected as the best case for further comparison with other cases. However, this particular well configuration is very comparable with Cases H5-

2Inj-8 (not-vertically aligned) and H5-2Inj-4 (vertically aligned).

4.4.4. Best Cases for the Single Producer-Dual Injector Models

Case H10-2Inj-8 represents model H10 with a layer thickness of 10 m. Similarly, Cases

H7-2Inj-8 and H5-2Inj-9 represent Models H7 (thickness 7 m) and H5 (thickness 5 m), respectively. For sake of comparison the reservoir cross-section well configurations are recalled here and are shown in Table 4-5.

A comparison between cSOR, cumulative produced oil, cumulative recovery factor and heat loss for the best case scenarios are depicted in Figs. 4-13 through 4-16.

120

Table 4-5 Cross-sectional reservoir view and well configuration for best case scenarios in dual injector-single producer.

Case H10-2Inj-8 H7-2Inj-8 H5-2Inj-9

Image

The cumulative steam-to-oil ratios for best cases are shown and compared with each other in Fig. 4-13. In all cases, the lower cSOR achieved by positioning the producer well at 0.25 m above understrata and in a not aligned well configuration.

A comparison between cases reveals that the thicker the layer, the smaller the cSOR.

The establishment of the steam chamber occurs faster in lower thickness followed by an abrupt increase in cSOR. It can be related to lower capacity of reservoir to accept steam

(smaller net pay zone). After formation of a minimum in the cSOR profiles, the opposite behavior is observed – thereafter, a slower increase of the cSOR for thicker layers is observed. Approximately, the cSORs are equal to 4.1, 5.4 and 7.2 m3/m3 are obtained for layer thicknesses of 10, 7 and 5 m, respectively.

The cumulative produced oil versus production time for the best cases is presented in

Fig. 4-14. The same trends in increase in cumulative oil production for all Models are observed. However, the increase is more rapid for the thicker reservoirs. Obviously, a

121 thicker reservoir consists of larger pay zone and higher initial amount of oil which allows for higher cumulative production at the same production time.

The oil recovery factor versus pore volume of steam injected for the best cases are shown in Fig. 4-15.

8 3 50000 H10-2Inj-Case 8 H10-2Inj-Case 8 3 H7-2Inj-Case 8 H7-2Inj-Case 8 /m 40000 H5-2Inj-Case 9 3 6 H5-2Inj-Case 9

30000 4 20000

2 10000 SOR Cumulative , m

0 , Oil m Production Cumulative 0 0 200 400 600 800 1000 0 500 1000 Time, Days Time, Days Figure 4-13 cSOR versus time. Figure 4-14 Cumulative produced oil versus time.

70 0 60 -4E+13 50

40 -8E+13

30 -1.2E+14

20 H10-2Inj-Case 8 H10-2Inj-Case 8 H7-2Inj-Case 8 -1.6E+14 H7-2Inj-Case 8 Oil Factor Recovery Oil 10

H5-2Inj-Case 9 Heat Loss Cum, J H5-2Inj-Case 9 0 -2E+14 0 1 2 3 0 200 400 600 800 1000 PVSI Time, Days Figure 4-15 Oil recovery versus PVSI. Figure 4-16 Heat loss versus time.

122

Even in the thinnest case, a recovery factor of 55% is achieved but at higher cost of injected steam. The thicker the reservoir, the higher the oil recovery factor. A range of

56% to 61% was observed for reservoir thickness of 5 to 10 m. To achieve the same recovery factor more pore volumes of injected steam is required as the reservoirs gets thinner.

The cumulative heat losses during production time are shown for nominal cases (H5-

2Inj-8, H7-2Inj-8 and H5-2Inj-9) in Fig. 4-16. It should be mentioned that heat losses does not represent the lowest heat losses per se. It would be expected to achieve higher heat losses for thinner oil reservoirs. However, the particular well arrangement in

Case H5-2Inj-9 provided slightly lower heat loss in comparison with cases in the thicker layer of 7 m.

It worth mentioning, that it is possible to select other sets of the best case scenarios.

The selected well configuration depends on considering the production priorities.

For example by choosing the Cases H10-2Inj-7, H7-2Inj-7 and H5-2Inj-8 as the best case scenarios lower cSOR, lower heat losses are achieved. However, the oil production is delayed leading to lower cumulative oil production and lower cumulative oil recovery factors. The difference between the newly selected triple well configurations with the selected best case scenarios is the position of the first injector well. That is moved away vertically from the underburden and set parallel to the offset well.

123

A comparison between cSOR, cumulative produced oil, cumulative recovery factor and heat loss for the second selected set and the best case scenarios are depicted in Figs. 4-

17 through 4-20.

8 50000

3 H10-2Inj-Case 8

3 H7-2Inj-Case 8 40000 H5-2Inj-Case 9 /m 6 3 H10-2Inj-Case 7 H7-2Inj-Case 7 30000 H5-2Inj-Case 8 4 H10-2Inj-Case 8 20000 H7-2Inj-Case 8 2 H5-2Inj-Case 9 H10-2Inj-Case7 10000

SOR Cumulative , m H7-2Inj-Case 7 H5-2Inj-Case 8

0 , Oil m Production Cumulative 0 0 500 1000 0 500 1000 Time, Days Time, Days

Figure 4-17 cSOR versus time. Figure 4-18 Cumulative produced oil versus time.

70 0 60

50 -5E+13 40 H10-2Inj-Case 8 -1E+14 30 H7-2Inj-Case 8 H10-2Inj-Case 8 H7-2Inj-Case 8 20 H5-2Inj-Case 9 H10-2Inj-Case 7 -1.5E+14 H5-2Inj-Case 9

Heat Loss Cum, J H10-2Inj-Case 7 Oil Factor Recovery Oil 10 H7-2Inj-Case 7 H7-2Inj-Case 7 H5-2Inj-Case 8 H5-2Inj-Case 8 0 -2E+14 0 0.5 1 1.5 2 2.5 3 0 500 1000 PVSI Time, Days

Figure 4-19 Oil recovery versus PVSI. Figure 4-20 Heat loss versus time.

124

4.4.5. Best Cases for the Single Injector-Single Producer and Dual Injector-Single

Producer Models

The best cases for two major categories of single injector-single producer and dual injector- single producer models are discussed here. Reservoir cross-sections and well configurations for the best cases are depicted in Table 4-6.

The dual injector-single producer cases (not aligned) configurations led to best performance whereas in the single injector-single producer cases, the aligned ones appeared to perform better.

Table 4-6 Cross-sectional reservoir view and well configuration for best case scenarios in single injector-single producer and dual injector-single producer models.

Case Dual inj. - Single-prod. Case Single-inj. - Single prod.

H10-2Inj-8 H10-6

H7-2Inj-8 H7-4

H5-2Inj-9 H5-5

Fig. 4-21 shows a comparison of cSOR performance. The dual injector-single producer cases lead to lower cSOR values for all reservoir thicknesses. Having two injector wells in

125 comparison with one helped with faster growth of steam chamber and thus oil mobilization.

Fig. 4-22 displays the cumulative produced oil as a function of time. The dual injector- single producer cases deliver higher cumulative oil production.

Fig. 4-23 compares the oil recovery factor versus pore volume injected steam. The dual injector-single producer cases realize higher oil recovery factor.

Fig. 4-24 shows the cumulative heat losses during production for the nominal cases and do not represent the lowest heat losses per se. The dual injector-single producer cases lead to higher heat losses.

A comparison between the single injector-single-producer and dual injector-single producer scenarios at different reservoir thicknesses were shown in Fig. 4-20 through 4-

24. Similar trends with respect to increases or decreases of the value of a specific parameter (e.g. PVSI, cSOR, and recovery factor) based on the reservoir thickness is recognizable in both scenarios.

126

8 3 50000 H10-2Inj-Case 8 H7-2Inj-Case 8

3 40000 H5-2Inj-Case 9 6 H10-Case 6 /m 3 H7-Case 4 30000 H5-Case 5 4 H10-2Inj-Case 8 20000 H7-2Inj-Case 8 2 H5-2Inj-Case 9 H10-Case 6 10000 H7-Case 4 SOR Cumulative , m H5-Case 5 , Oil m Production Cumulative 0 0 0 500 1000 0 500 1000 Time, Days Time, Days Figure 4-21 cSOR versus time. Figure 4-22 Cumulative produced oil versus time.

70 0

40 -1E+14 H10-2Inj-Case 8 30 H7-2Inj-Case 8 H10-2Inj-Case 8 H7-2Inj-Case 8 20 H5-2Inj-Case 9 H10-Case 6 H5-2Inj-Case 9 Heat Loss Cum, J H10-Case 6

Oil Factor Recovery Oil 10 H7-Case 4 H7-Case 4 H5-Case 5 H5-Case 5 0 -2E+14 0 0.5 1 1.5 2 2.5 3 0 500 1000

PVSI Time, Days Figure 4-23 Oil recovery versus PVSI. Figure 4-24 Heat loss versus time.

In general, in the dual injector-single producer scenarios higher cumulative oil production and higher recovery factor at cost of higher heat losses and a similar cSOR are achieved. It should be emphasised that this trend may change - for example,

127

preference of a lower heat loss and cSOR in favour of delayed oil recovery as it was

shown by altering the best case scenarios selection.

4.5. Conclusions

The influence of well configuration on the production performance in steam-injection

gravity drainage operations was studied through different well positioning by relocation

and providing vertical and horizontal spacing between the injection and production

wells. The results show that the best cases of the dual injector-single producer

configuration showed an oil recovery factor of 61%, 60%, and 56% at cSOR about equal

to 4.1, 5.4, and 7.2 m3/m3 in oil sand reservoirs with thickness equal to 10, 7 and 5 m,

respectively. These results were attained by positioning the producer well at 0.25 m

above the understrata with no vertical and horizontal alignment between producer and

injectors. This configuration led to the best performance when the vertical and

horizontal distances between the first injector and the producer were set at 2.5 and 1.6

m, respectively, for all reservoir thicknesses. Similarly, these parameters in the case of

second injector were set at 5 and 2.4 m for reservoir thicknesses of 10 and 7 m and 4 and 2.4 m for reservoir thickness of 5 m.

It can be concluded that the horizontal and vertical distances between injectors and the producer well, their locations from the overburden and understrata and their alignments affects cSOR and therefore the performance of the recovery process. The results also show that addition of an offset injector well reduces cSOR. Generally, dual

128 injector-single producer in comparison with single injector-single producer cases led to a higher cumulative oil production and higher recovery factor at cost of higher heat loss and a similar cSOR. An economical evaluation is recommended since an additional injector well causes additional cost to the operation.

129

CHAPTER 5. CONCLUDING REMARKS AND RECOMMENDATIONS

The results suggest that horizontal and vertical distances between injectors and the producer well, their locations from over or underburden, and their alignments impact the performance of steam-based recovery processes in thin oil sands reservoirs. The conclusions are as follows:

1. Positioning the producer well at layer adjacent to underburden is necessary to attain

higher oil production and recovery.

2. It was observed that as the reservoir thickness decreases, the recovery process

performance become less sensitive to different well configuration.

3. It is necessary to find optimum vertical and horizontal distances between the

injector and producer well pair. It was found that in single injector-single producer

cases, if the vertical separation reduces, then a horizontal offset between the wells

can improve the performance of the recovery process.

4. The dual injector-single producer cases not aligned well configuration led to best

performance whereas the best performance of the single-injector-single producer

cases were obtained when the wells were aligned.

5. It is observed that the well configuration can impact heat losses based on reservoir

thickness. The results indicate that in single injector-single producer aligned cases,

the difference in heat losses for layer thicknesses of 7 and 5 m was not significant. In

130

the dual injector-single producer cases, heat loss from layer thickness of 5 m was

slightly less than that of the 7 m thickness cases.

6. For the selected well configurations, the dual injector-single producer case in

comparison with single injector-single producer cases led to higher cumulative oil

production and higher recovery factor at a cost of higher heat losses and a similar

cSOR.

7. In general, the performance of offset well and its influence on the cSOR, cumulative

oil production, recovery factor and heat loss depends on the triple well

configuration.

8. The result of the research documented here suggests that addition of an offset

injector well can improve the recovery process performance.

The following recommendation is made:

It is recommended that an economic evaluation is conducted to understand how the additional well required in the dual injector-single producer well configuration affects the financial viability of the recovery process compared to the single injector-producer

well processes.

131

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