Copyright 2005, SPE/PS-CIM/CHOA International Thermal Operations and Heavy Oil Symposium This paper was prepared for presentation at the 2005 SPE International Thermal Operations and Heavy Oil Symposium held in Calgary, Alberta, Canada, 13 November 2005. This paper was selected for presentation by an SPE/PS-CIM/CHOA Program Committee following review of information contained in a proposal submitted by the author(s). Contents of the paper, as presented, have not been reviewed by the Society of Petroleum Engineers, Petroleum SocietyCanadian Institute of Mining, Metallurgy & Petroleum, or the Canadian Heavy Oil Association and are subject to correction by the author(s). The material, as presented, does not necessarily reflect any position of the SPE/PS-CIM/CHOA, its officers, or members. Papers presented at SPE and PS-CIM/CHOA meetings are subject to publication review by Editorial Committees of the SPE and PS-CIM/CHOA. Electronic reproduction, distribution, or storage of any part of this paper for commercial purposes without the written consent of the SPE or PS-CIM/CHOA is prohibited. Permission to reproduce in print is restricted to a proposal of not more than 300 words; illustrations may not be copied. The proposal must contain conspicuous acknowledgment of where and by whom the paper was presented. Write Librarian, SPE, P.O. Box 833836, Richardson, TX 75083-3836, U.S.A., fax 01-972-952-9435. Abstract Steam-Assisted Gravity Drainage (SAGD) is being operated by several operators in Athabasca and Cold Lake reservoirs in Central and Northern Alberta. In this process, steam, injected into a horizontal well, flows outwards, contacts and loses its latent heat to bitumen at the edge of a depletion chamber. As a consequence, the viscosity of the bitumen falls, its mobility rises, and it flows under the action of gravity towards a horizontal production well located several meters below and parallel to the injection well. In practice, the temperature difference between the injected steam and produced fluids, called the subcool, is maintained between 15 and 30C. Despite many pilots and commercial operations, it remains unclear what the impact of subcool on the performance and thermal efficiency of SAGD especially in reservoirs with a top gas zone. The objective of this study was to define a steam chamber operating strategy that leads to optimum oil recovery for minimum cumulative steam to oil ratio in a reservoir with a top gas zone. These findings were established from extensive simulation runs that were built from a detailed geostatistically generated static reservoir model. The strategy devised uses a high initial chamber injection rate and pressure prior to chamber contact with the top gas. Subsequent to breakthrough of the chamber into the gas cap zone, the chamber injection rates are lowered to balance pressures with the top gas and avoid or at least minimize convective heat losses of steam to the top gas zone. The results are also analyzed by examining the energetics of SAGD. Introduction

A cross-section of the Steam-Assisted Gravity Drainage (SAGD) process is displayed in Figure 1. Steam is injected into the formation through a horizontal well. In Figure 1, the wells are portrayed as points that extend into the page. Around and above the injection well, a steam depletion chamber grows. At the edge of the chamber, heated bitumen and (steam) condensate flow under the action of gravity to a production well typically placed between 5 and 10 m below and parallel to the injection well. Usually, the production well is located several meters above the base of pay. In industrial practice1,2, injection and production wells lengths are typically between 500 and 1000 m. The injection pressure, because the steam chamber operates at saturation conditions, controls the operating temperature of SAGD. Figure 1: Cross-section of the Steam-Assisted Gravity Drainage (SAGD) process. SAGD has been extensively piloted in Athabasca and Cold Lake reservoirs in Alberta2-13 and is being used as a commercial technology to recover bitumen in several Athabasca reservoirs11. These pilots and commercial operations have demonstrated that SAGD is technically effective but it has not been fully established whether its operating conditions are at optimum values. This is especially the case in reservoirs in contact with gas or water zones where the optimum operating strategy remains unclear. The

CANADIAN HEAVY OIL ASSOCIATION

SPE/PS-CIM/CHOA 97742 PS2005-332

Steam-Injection Strategy and Energetics of Steam-Assisted Gravity DrainageI.D. Gates, U. of Calgary; J. Kenny and I.L. Hernandez-Hdez, Atech Application Technology Ltd.; and G.L. Bunio, Paramount Resources Ltd.

Production Well

Steam Chamber

Native bitumen

Bitumen flow zone

Reservoir Thickness

Injection Well

2 SPE/PS-CIM/CHOA 97742

variability of the cumulative injected steam (expressed in Cold Water Equivalents, CWE) to produced oil ratio (cSOR) shows that some SAGD wellpairs operate fairly efficiently (with cSOR between 2 and 3) whereas others operate at much greater cSOR up to 10 and higher13. Higher cSOR means that more steam is being used per unit volume bitumen produced. The higher the steam usage, the greater the amount of natural gas combusted, and the less economic is the process. One key control variable in SAGD is the temperature difference between the injected steam and the produced fluids. This value, known as the subcool, is typically maintained in a form of steam-trap control between 15 and 30C. The subcool is being used as a surrogate variable instead of the height of liquid above the production well. The liquid pool above the production well prevents flow of injected steam directly from the injection well to the production well thus promoting injected steam to the outer regions of the depletion chamber and delivery of its latent heat to the bitumen. It remains unclear what is the value of the optimum steam-trap subcool temperature difference and how the operating pressure impacts the optimum subcool value. It also remains unclear how the subcool should be controlled in heterogeneous reservoirs that have top gas. In this study, a sequence of SAGD simulations were conducted on a reservoir with a detailed heterogeneous geological description obtained from geostatistical analysis of log and core data. After over 100 simulations, an optimized steam injection strategy was devised that produced a reasonable cSOR for design of a SAGD operation in McMurray reservoir with a top gas zone. In addition, the energetics of SAGD are examined by evaluating the flowing steam quality in the steam chamber. Geological Model To allow the assessment of geological variation and uncertainty on the SAGD process a detailed statistically based static geological description was prepared. The overall domain of the parent geological model covers 32 sections in the vicinity of Paramount Resources oilsands lease at Surmount described by Robinson et al. (2005). Petrophysical interpretations and picks for seven horizons were available at 33 wells within the parent geological domain and were mapped from the well inputs by using a Local B-Spline algorithm in Roxar's IRAP RMS geostatistical package12. Of the 33 wells, facies logs from fourteen of them were prepared to populate the geological model14. A stacked rectangular grid was used to build the geostatistical model. In the East to West direction, 136 columns, each 50 m wide, were used giving a total width equal to 6 800 m. In the North to South direction, 259 rows, each 50 m wide, were used to give a total length of 12 950 m. In the vertical direction, 95 layers of variable thickness, most of them under 1 m thickness, were used. The total cell count for the geological grid was 3 346 280.

The facies logs distinguished eight rock types that were identified as follows: Facies 1: Shoreface Sand, Facies 2: Muddy Marine Sand, Facies 3: Mudstone, Facies 4: Mud Dominated Heterolithic Strata, Facies 5: Sand Dominated Heterolithic Strata, Facies 6: Sandstone, Facies 7: Breccia, and Facies 8: Mudstone Filled. Petrophysical interpretations provided logs of Sg, So, Sw, and kh for the 33 wells within the geological model parent domain. From a detailed review and synthesis of core, core analysis, logs and a history match of a McMurray SAGD pilot, correlations of permeability versus porosity and vertical to horizontal permeability ratio (kv/kh) were established for each facies in the model. The correlations are listed in Table 1. The facies specific permeability-porosity transforms were used to generate well permeability logs. Table 1: Horizontal permeability versus porosity correlations.

Facies 1 2 3 4 5 6 7 8

0.050 4.2 0.0021 0.0002 5.1 17.3 17.5 10.8 0.000230.075 18.7 0.0057 0.0005 24.0 61.0 63.0 36.2 0.000500.100 53.7 0.0118 0.0009 71.9 149.2 156.5 85.5 0.000870.125 121.8 0.0206 0.0013 168.3 298.6 317.1 166.5 0.001340.150 237.8 0.0324 0.0019 337.4 526.5 564.7 286.9 0.001910.175 418.7 0.0477 0.0026 607.6 850.4 919.7 454.6 0.002570.200 683.3 0.0665 0.0033 1011.1 1288.3 1403.3 677.2 0.003330.225 1052.7 0.0893 0.0042 1584.7 1858.4 2037.1 962.5 0.004180.250 1549.4 0.1163 0.0051 2368.6 2579.1 2843.3 1318.2 0.005120.275 2198.0 0.1475 0.0062 3407.2 3469.1 3844.2 1752.0 0.006160.300 3024.5 0.1834 0.0073 4748.4 4547.3 5062.8 2271.5 0.007290.325 4056.9 0.2240 0.0085 6443.9 5832.9 6522.2 2884.5 0.008500.350 5324.3 0.2696 0.0098 8549.2 7345.1 8246.0 3598.7 0.009810.375 6857.9 0.3203 0.0112 11123 9103.2 10258 4421.6 0.011210.400 8690.0 0.3764 0.0127 14228 11127 12582 5360.9 0.01269

For each facies, the vertical to horizontal permeability ratio for the model was set to 0.65, .055, .055, 0.055, 0.300, 0.500, 0.500 and 0.005 for facies 1, 2, 3, 4, 5, 6, 7, and 8 respectively. As described in Robinson et al. (2005), the facies and petrophysical well logs were entered into Roxar's IRAP RMS geostatistical modelling package and upscaled to populate the gridblocks intersected by the wells with the following suite of parameters: facies, Sg, So, Sw, , kh and kv. The grid was kept relatively fine in the vertical direction and the distribution of layer thickness ensured that the blocked well data represented the actual log data sufficiently well. To populate the facies at gridblocks away from the wellbores, a Sequential Indicator Simulation15, conditioned on the facies vertical proportion curve, was done. Any number of equiprobable facies realizations may be generated from this

SPE/PS-CIM/CHOA 97742 3

Oil Saturation

Gas Saturation

FACIES

data set. The facies distribution through the reservoir for one realization is displayed in Figure 2. After review by team geologists, the geological model was considered to be a reasonable reflection of the geological environment14. Figure 2: Facies distribution in geological model. To populate the permeabilities, porosities and saturation distributions in the regions between the well locations, Sequential Gaussian Simulation (SGS) was used. The SGS that was used to populate gas, oil and water saturations in the model were run independently to ensure that the underlying statistics describing these parameters were honored in the model. The saturations were then normalized to ensure that Sg+So+Sw = 1 at every grid block. To obtain porosity and permeability distributions between the well locations, a SGS was conducted with upper and lower bound cut-offs applied to the wellblock porosity and permeability distributions. Tables 2 and 3 list the minimum and maximum cut-offs, average values, and standard deviation of the porosity and permeabilities distributions. Table 2: Porosity: minimum, maximum, average, and standard deviations for each facies.

Facies Min Max Avg 1 0.1 0.32 0.2363 0.1102 2 0.05 0.25 0.1434 0.0567 3 0 0.15 0.0549 0.0508 4 0.05 0.3 0.2140 0.0728 5 0.1 0.4 0.2670 0.0657 6 0.2 0.4 0.3081 0.0454 7 0.1 0.36 0.2764 0.0652 8 0 0.15 0.0366 0.0476

Table 3: Horizontal and vertical permeabilities: minimum, maximum, average, and standard deviations for each facies.

Horizontal, mD Vertical, mD Facies Min Max Avg Min Max Avg

1 200 4000 1903 1000 130 2600 736 951 2 0.001 1 0.0678 0.1125 5(10-5) 0.055 0.0031 0.00343 0 0.005 0.0011 0.0013 0 5(10-4) 0.0001 0.00014 500 5000 2721 1239 27.5 275 122.39 64.365 750 9000 4280 2107 225 2700 1270 684 6 1500 10000 5563 2295 750 5000 2777 1178 7 750 5000 2729 1176 375 2500 1382 588 8 0 0.005 0.001 0.0015 0 0.005 0.0001 0.0005

As described in Robinson et al. (2005), 100 equiprobable facies, porosity, permeability and saturation realizations were constructed. A comparison revealed that there were small variations in volumes among the 100 realizations and a realization near the center of the population was chosen to construct the working geological model from which a reservoir simulation model could be extracted. The gas and oil saturation distributions within the model are shown in Figure 3. The gas saturation is concentrated in the upper marine sands whereas the highest oil saturations are located in the central elevations of the model. The porosity and horizontal and vertical permeability distributions are displayed and described in Robinson et al. (2005). Figure 3: Gas and oil saturation distributions in geological model.

4 SPE/PS-CIM/CHOA 97742

Reservoir Simulation Model The next step of the workflow was to upscale, extract, and import the geological model into the reservoir simulator. The reservoir simulation of the SAGD process was conducted with Computer Modelling Groups (CMG) thermal reservoir simulator STARS16. As described in Robinson et al. (2005), an upscaled geological description of Section 30 was extracted consisting of 516 096 cells from the original geological parent model. From this upscaled model, within the CMG preprocessor, a subdomain able to accommodate two 750 m wellpairs, with 500 m in the East-West (X=lateral) direction by 950 m in the North-South (Y=downwell) direction, was extracted. In the downwell direction, the subdomain was tessellated into 12 gridblocks. The total number of gridblocks equals 74 592. Figure 4 displays grid of the reservoir simulation model two-thirds of the way down the wells; the left wellpair is referred to by LP whereas the right wellpair is referred to as RP. Figure 4: Dual wellpair reservoir simulation model grid. Figure 4 shows the locations of the left and right wellpairs as well as wells that were inserted into the gas cap to mimic the continuity of the gas cap beyond the model. The gas cap wells were constrained to constant bottomhole pressure equal to the gas cap pressure (they will be referred to as pressure-maintenance wells). The grid blocks in the East-West direction were refined to ensure that the maximum gridblock width 50 m on each side of the left and right wellpairs was 3.845 m. The inter-wellpair spacing is 200 m. Figure 5 displays porosity and horizontal permeability distributions of the reservoir simulation model at planes along the wellpairs and two lateral cross-sections. The black lines in the downwell planes indicate the locations of the wellpairs. In the central region of the model, the porosity ranges from 0.27 to 0.38 and it is improving from the South to the North. Similarly, the horizontal permeability mainly lies between 2 and 6 D in the central regions of the reservoir with better permeability in the Northern part of the reservoir. Figure 6 shows cross-sections of the gas, oil, and water saturations in the reservoir simulation model. Consistent with the geological model, the gas cap, typically 3 to 4 m thick, is located throughout the model.

Figure 5: Dual wellpair reservoir simulation model: porosity and horizontal permeability distributions (cross-sections along wellpairs and two lateral locations downwell). In the top gas zone, the maximum gas saturation is about 0.82 with the remainder of the pore space containing water. Initially, the pressure of the gas cap is about 1050 kPa (the pressure equaled 936 and 1631 kPa at the top and bottom of the reservoir model, respectively). The pressure-maintenance wells located in the gas cap are set to produce fluids if the pressure exceeds 1075 kPa in order to mimic an gas cap zone that extends beyond the model domain. It is anticipated that in the case with an established depletion chamber in contact with the top gas zone, if the steam injection pressure is too large, steam will be diverted from the steam chamber into the top gas zone raising the pressure there. Then, steam and gas will flow out into the gas cap and out through the gas cap pressure-maintenance wells. The oil saturation distribution displayed in Figure 6 reveals that there is a central region of the reservoir with relatively high oil saturation. The average thickness of the oil-rich zone (> 0.7 oil saturation) is about 20 m. In some parts of the reservoir, it is as high as 26 m and in others it drops as low as 14 m. The production wells of each wellpair are located just a couple meters above the bottom of the oil-rich zones. The injection wells are located 5 m above the production wells.

LP RP

East West

Horizontal Permeability, mD

Porosity WestEast North

South

LPRP

SPE/PS-CIM/CHOA 97742 5

Gas Saturation

Oil Saturation

Water Saturation

WestEast North

South

LP RP

Figure 6: Dual wellpair reservoir simulation model: gas, oil, and water saturations (cross-sections along wellpairs and two lateral locations downwell). The water saturation distribution shown in Figure 6 reveals that there are relatively high water saturation regions at the top and at the bottom of the model. The region at the top is above the gas cap and consists of tight muddy marine sand reservoir rock (Facies 2). The porosity and permeability of this facies are both low (see Tables 2 and 3). The high water saturation at the bottom of the reservoir is in Facies 6 and the water is relatively mobile given the permeability of this part of the reservoir.

Table 4 summarizes additional heat loss parameters, fluid properties, and rock-fluid properties. The reservoir simulation model fluid components consisted of bitumen, water (liquid and vapour), and solution gas. The bubble point pressure in the model was taken to be 1000 kPa. Since most of the model is above this pressure, the initial solution gas to oil ratio was constant at 4.2 m3/m3 throughout the oil layer. The K-value relationship used in the model is listed in Table 4. The bitumen viscosity was similar to Mehrotra and Svrceks (1986) correlation for Athabasca bitumen17. The oil-water and gas-liquid relative permeability curves were obtained from a detailed history match of a McMurray SAGD pilot. The endpoints are listed in Table 4. Table 4: Reservoir simulation input parameters.

Item Value Initial Reservoir Temperature, C

10

Top of model depth, m 277 Sorw 0.2 Swc 0.3 Sorg 0.15 Sgc 0.05 krwro 0.197 krocw 0.48 krogc 0.8 krg(Sorg) 1 Oilsand thermal conductivity, kJ/m day C

149.5

Over/Underburden heat capacity, kJ/m3 C

1169

Over/Underburden thermal conductivity, kJ/m day C

74.9

Methane K-value correlation,

K-value = 54

1 vv

kTk

v ePk +

kv1= 3.1914x104 kPa kv4=-330.67 C kv5 = -277.1 C

Well Constraints At the injection wells, the steam injection pressure is constrained to a maximum bottomhole pressure. The steam quality at sandface equaled 0.8. At the production wells, the steamtrap constraint was used with 5C temperature setting. The CMG steamtrap control algorithm does not impose the temperature difference between the injection and production well16. Rather, a 5C subcool in CMGs algorithm means that the bottomhole pressure in the wellblock is set corresponding to the pressure 5C above the saturation temperature of the gridblock. This means that no live steam can be produced from the well. The subcool temperature difference often referred to from field data as the difference between the steam injection temperature and the produced fluids temperature can be calculated from the results of the simulation.

6 SPE/PS-CIM/CHOA 97742

Model Initialization To model steam circulation, line heaters were positioned in the locations of the injection and production wells of each wellpair. The heating rate corresponded to the heat delivered by 250 m3/day CWE of 0.8 quality steam. In the location of the production wells, the wells were opened with a maximum bottomhole pressure equal to the initial reservoir pressure. The reason for this is to relieve pressure buildup due to thermal expansion of the fluids near the wellbore. Similarly, temporary production wells were inserted into the same locations as the steam injectors so that pressure was relieved along the injectors as the reservoir fluids near the wellbore heated up. The circulation period lasted three months. When the wellpairs were changed to SAGD mode, the line heaters were turned off, the temporary production wells positioned in the steam injection well locations were removed, and steam injection commenced at the target rate or pressure. Results: Optimization of Performance: From Dual Wellpair to Single Wellpair Models The simulation runs of the dual-wellpair model took up to 20 hours to complete a 12 year forecast with a 2.45 GHz dual-processor computer workstation with parallel-enabled STARS. It was recognized early in the study that to carry out a large number of simulations would be prohibitive and would not be possible on the available 5 workstations. To obtain simulation run times in reasonable runtimes without compromising the geological description and physics of the SAGD process, two single wellpair models, identified as RP and LP, were created. Each single wellpair model consists of half the dual-wellpair model. Each half has a 250 m by 950 m areal footprint. There are 37 296 blocks in each of the single wellpair models and 12 year forecast runs lasted under 9 hours on a 2.45 GHz dual processor workstation with parallel-enabled STARS. It was decided that first, the operating strategy of each single wellpair model would be optimized and second, the individually optimized operating strategies would be applied in the dual wellpair model. It was recognized that due to inter-wellpair communication, the results of the single wellpair operating strategies would have to be adjusted once introduced into the dual wellpair model. However, it was expected that given the presence of the gas cap, the operating strategy would have to be gentle on the reservoir (otherwise excessive steam would be lost to the gas cap), and therefore communication issues would not be too hard to resolve. The same circulation preheat strategy as was described for the dual wellpair model was used for the single wellpair models. Many cases were run or partially run to improve the cSOR after six and twelve years of SAGD operation. These runs were in sequence and in parallel and the operating strategy was modified after carefully reviewing and analyzing the results of each run to further improve the cSOR. Constant Pressure Injection First, the results for constant steam injection pressure at 2000 kPa will be presented. Figures 7 and 8 show plots of the

injection rate and pressure and production rates, cumulative volumes produced, and cSOR for the LP wellpair, respectively. Figures 9 and 10 show the same plots for the RP wellpair. Figure 7: Steam injection strategy in the LP wellpair operated at constant 2000 kPa injection pressure. Figure 8: Production rates, cumulative volumes, and cSOR of LP wellpair operated at constant 2000 kPa injection pressure. Figure 9: Steam injection strategy in the RP wellpair operated at constant 2000 kPa injection pressure.

SPE/PS-CIM/CHOA 97742 7

Figure 10: Production rates, cumulative volumes, and cSOR of RP wellpair operated at constant 2000 kPa injection pressure. The results in Figures 8 and 10 reveal high cSOR profiles that are the result of excessive steam losses from the steam chamber to the gas cap. Because steam rates are high, very little latent heat is being delivered to the bitumen and so bitumen rates are low. Optimized Steam Injection With manual optimization, improved operating strategies were determined for both LP and RP wellpairs. The strategies for both wellpairs are similar and comprise a high steam injection pressure until each steam chamber establishes contact with the top gas. High injection pressure implies a relatively high saturation temperature that leads to favourable bitumen viscosities in the early stages of SAGD. After the top gas is encountered, the top gas pressure dictates the steam chamber operating pressure which according to the optimized strategy is maintained constant thereafter at or just below the gas cap pressure. This ensures convective losses of steam after breakthrough to the top gas are avoided or at least minimized. This operating strategy is consistent with the results of Gates and Chakrabarty13. In uniform steam injection pressure simulations, the Northern end of the LP reservoir was depleted more rapidly than the Southern part of the reservoir. This is because the geology along the LP wellpair has a large contrast in reservoir quality going from toe to heel. The toe section of the injection well has better vertical permeability than the heel section and consequently breakthrough to the top gas zone happens quickly and so makes favorable thermal management of the steam chamber more problematic. On the other hand the reservoir quality along the well pair of the RP model is more uniform and so makes the breakthrough time more uniform along the injection well, which makes favorable thermal management prior to and subsequent to breakthrough to the gas cap easier. In order to promote more uniform formation of the depletion chamber in the reservoir, steam injection into the toe of the LP and RP wells were periodically stopped.

Without steam placement control, injected steam takes the path of least resistance to better quality reservoir at the toe and bypasses reservoir of poorer quality at the heel. By introducing control of steam placement, steam is concentrated at the heel section at higher pressures for a longer time and so the steam chamber grows more uniformly at the heel. Also, injection rates and pressures at the toe section are lowered to delay the onset of the chamber contacting the top gas zone. Robinson et al. (2005) discusses steam placement control in more detail. Strategies to control steam placement might include a combination of packers and chokes along the horizontal section and/or the use of limited entry perforations as described by Boone et al. (1999) as well as any inflow control devices18. Flexibility will be key in the design of the injection string because the geology along the injector will dictate the optimal steam placement requirements. Pressure and temperature monitoring along the steam chamber will be essential to effective management. Figure 11 displays the injection well constraints of the optimized operating strategy over the twelve year forecast period for the LP wellpair. The plot reveals that over the first two years the injection constraint was a maximum bottom hole pressure limitation and beyond that, the constraint was the steam injection rate that was lowered in steps until the end of the forecast. The production rates and associated cumulative volumes of the gas, oil and water, and cSOR over the twelve year forecast period for the LP wellpair are presented in Figures 12. Figure 11: Steam injection strategy in optimized LP wellpair. In the first year of the process, the steam injection pressure is relatively high at 1800 kPa. The injection pressure is then lowered to 1100 kPa and thereafter, in the rate-constrained period, the pressure remains near 1000 kPa. The maximum steam injection rate is short-lived at 175 CWE m3/day. Over the majority of the process, the steam injection rate ranges from 100 to 150 CWE m3/day.

8 SPE/PS-CIM/CHOA 97742

Figure 12 shows that the cSOR settles after an initial transient period after the onset of SAGD to about 2.6 m3/m3. The shape of the bitumen production rate profile is similar to SAGD field data from Athabasca reservoirs. The field rate hovers just above 50 m3/day for most of the life of the process and after 8 years of SAGD operation begins to decline. With the exception of the first year, throughout the process, more water is produced than injected. This indicates that water from the formation is being produced. Figure 12: Production rates, cumulative volumes, and cSOR of optimized strategy in LP wellpair. Figure 13 displays the injection well constraints of the optimized operating strategy for the RP wellpair. The production rates and cumulative volumes of oil and water, and cSOR over the twelve year forecast period for the RP wellpair are presented in Figure 14. Similar to the LP wellpair, in the RP wellpair over the first two years the injection constraint was a maximum bottom hole pressure limitation and beyond that, the constraint was the steam injection rate, which was adjusted in a downward trend until the end of the forecast. During most of the life of the RP wellpair, the pressure was roughly 1000 kPa. The rate profiles for the RP wellpair presented in Figure 14 are similar to LP wellpair. The cSOR profile passes through an initial transient period and then evolves to a uniform value of about 2.4 m3/m3. The bitumen rate profile has a typical shape and hovers at over 60 m3/day for most of the life of the wellpair. As the steam injection rate declines, the bitumen rate also falls. Similar to the LP wellpair, throughout the majority of the life of the RP wellpair, more water is produced than is injected into the reservoir. This means that formation water is being produced from the reservoir. Compared to the constant pressure injection cases described above, the cSOR of the optimized cases are significantly improved. In the constant pressure case, the cSOR after six and twelve years are 188 and 533 m3/m3 in the LP wellpair and are 96 and 259 m3/m3 in the RP wellpair, respectively. The normalized average bitumen production rate (normalized against the well length = 750 m) of the constant pressure cases are 0.0077 and 0 m3/day/m in the LP wellpair and 0.025 and

0.00067 m3/day/m in the RP wellpair at six and twelve years, respectively. Figure 13: Steam injection strategy in optimized RP wellpair. Figure 14: Production rates, cumulative volumes, and cSOR of optimized strategy in RP wellpair. In the optimized LP wellpair, the cSOR after six and twelve years equals 2.6 m3/m3 at both times. The normalized average bitumen production rate at six and twelve years are 0.068 and 0.067 m3/day/m, respectively. In the optimized RP wellpair, the cSOR is 2.4 m3/m3 at both six and twelve years. The normalized average bitumen rate is 0.071 and 0.069 m3/day/m at six and twelve years, respectively. The reason for improved performance in the optimized strategies is that after the steam chamber contacts the top gas zone, the injection pressure drops to values below that of the gas cap pressure. As a consequence, steam does not invade and penetrate the gas cap and is not lost from the depletion chamber. This implies that the steams latent heat is more directly transferred to the bitumen at the edges of the chamber than lost to the gas zone and overburden. Also, as the pressure falls, the saturation temperature falls and some of the invested heat in the formation and overburden rock is harvested back to the chamber fluids.

SPE/PS-CIM/CHOA 97742 9

Figures 15, 16, and 17 shows the sequence of temperature, oil saturation, and flowing steam quality cross-sections roughly two-thirds downwell for the LP wellpair, respectively. The LP wellpair and gas cap pressure-maintenance wells are displayed. SAGD mode starts 2005-04-01 after circulation. The temperature, oil and gas saturation distributions are displayed in Figures 18 to 20 for the RP wellpair. Figure 15: Temperature distribution in section two-thirds downwell of LP wellpair (optimized strategy).

Figure 16: Oil saturation distribution in section two-thirds downwell of LP wellpair (optimized strategy). The flowing steam quality is determined by calculating the volume of mobile water in the vapour phase, converting it to a mass of water in the vapour phase, and dividing it by the total mass of mobile water (both vapour and liquid) in the gridblock. This is a novel way to visualize the steam chamber in SAGD where heat transfer is viewed as a change in the

10 SPE/PS-CIM/CHOA 97742

flowing steam quality. Because temperature and pressure are nearly constant in SAGD, the flowing steam quality provides a means to examine convective heat transfer in the steam chamber. Figure 17: Flowing steam quality distribution in section two-thirds downwell of LP wellpair (optimized strategy). At the gridblock above the injection wellblock the flowing steam quality is higher than the injected steam quality. The reason for this is because there is a separation effect as the

liquid water phase in the injection stream falls under gravity to the region below the injection well whereas the vapour rises into the steam chamber. In the region between the wells, as a consequence of this mechanism, the flowing steam quality is relatively low because the liquid water content, derived from injected liquid water, is relatively high in this region. Above the injection well, the flowing steam quality forms a nearly uniform radial profile moving away from the injection well. Figure 18: Temperature distribution in section two-thirds downwell of RP wellpair (optimized strategy).

SPE/PS-CIM/CHOA 97742 11

Figure 19: Oil saturation distribution in section two-thirds downwell of RP wellpair (optimized strategy). Figure 18 displays the temperature distributions of the RP wellpair roughly two-thirds downwell. A comparison with Figure 15 shows that the RP wellpair operates at slightly lower temperature than the LP wellpair and that the thermal zone grows more in the vertical direction in the LP wellpair than it does in the RP wellpair. Figure 20 shows how the RP wellpair gas cap zone and steam chamber interact as the process

evolves. The visualizations, especially at 2008-04-01, reveal that the gas zone has thickened just above the chamber, most likely because heated oil just above the chamber is flowing downwards under gravity and gas has fingered up to the gas zone from the chamber. At this particular section of the reservoir, the chamber reaches the top gas zone between 3 and 4 years after SAGD starts. Figure 20: Gas saturation distribution in section two-thirds downwell of RP wellpair (optimized strategy).

12 SPE/PS-CIM/CHOA 97742

Results from Dual Wellpair Model After the individual LP and RP wellpairs were optimized, the two operating strategies were integrated into the dual wellpair model. Figure 21 displays a comparison between the production rates and cSOR calculated from the LP wellpair in the dual wellpair model versus the single LP wellpair model. Figure 21: Production rates and cSOR of the single LP wellpair model versus the result for the LP wellpair from the dual wellpair model. Figure 22 shows a comparison between the production rates and cSOR calculated from the RP wellpair in the dual wellpair model versus the single RP wellpair model. Figure 22: Production rates and cSOR of the single RP wellpair model versus the result for the RP wellpair from the dual wellpair model. The results show that communication occurs between the two wellpairs after about one year of SAGD mode. This communication is in the form of the pressure fields interacting from the two wellpairs. However, fluid communication between the wellpairs is small and so differences of the rate profiles between the single-wellpair and dual-wellpair models are not significant.

Figure 23: Oil saturation distribution in section two-thirds downwell of dual wellpair model (optimized strategy obtained from single wellpair models).

SPE/PS-CIM/CHOA 97742 13

Figure 24: Gas saturation distribution in section two-thirds downwell of dual wellpair model (optimized strategy obtained from single wellpair models).

The results of the SAGD models demonstrate how the steam chambers grow to the top gas zone as SAGD proceeds in each wellpair. Due to geological differences, the steam chamber interacts and reaches the top gas zone first with the LP wellpair compared to the RP wellpair. The oil production rates from each of the wellpairs are similar but the RP wellpair has slightly lower cSOR than that in the LP wellpair. The reason for this is explained by the earlier interaction of the left steam chamber with the top gas zone. After the steam chamber reaches the top gas zone, steam, that is, latent heat, is delivered to the top gas instead of being delivered entirely to bitumen. The gas saturation distributions in Figure 24 reveal that the RP wellpair chamber, up to 2010, was growing faster in the lateral (horizontal) direction than in the vertical direction. A comparison of the cSOR profiles in Figures 20 and 21 shows that the cSOR of the RP wellpair was slightly lower than that of the LP wellpair. This comparison reflects the higher thermal efficiency achieved when breakthrough to the top gas is delayed. These results indicate that after the chamber is near the top of the oil pay, it is advantageous to lower the rate of vertical growth of the chamber to prevent penetration into the top gas zone. At this point, it would be advantageous to promote, if possible, lateral growth of the steam chamber. Steamtrap Control and Subcool As was described above, at the production wells, a 5C subcool in the CMG algorithm means that the bottomhole pressure in the wellblock is set corresponding to the pressure 5C above the saturation temperature of the gridblock and therefore no live steam can be produced from the well. In the field, the steamtrap subcool temperature difference is defined as the difference between the steam injection temperature and the produced fluids temperature. Figure 25 displays the temperature difference between the injection and production wells for the LP and RP wellpairs in a section roughly two-thirds downwell of the dual-wellpair model. Figure 25: Subcool temperature difference in LP and RP wellpairs obtained from dual-wellpair model. In the first year and a half of SAGD, the subcools of both wellpairs oscillates and achieves high values. From Figures

0102030405060708090

2005

-04-

01

2007

-04-

01

2009

-04-

01

2011

-04-

01

2013

-04-

01

2015

-04-

01

2017

-04-

01

Time (Date)

Subc

ool (

Inj.

T - P

rd. T

)

LP Wellpair

RP Wellpair

Subc

ool T

emp.

Diff

eren

ce, C

14 SPE/PS-CIM/CHOA 97742

21 and 22, the cSOR achieves its maximum values in this time interval. To recall, the optimized operating strategy had relatively high pressure steam injection in the first year at 1800 kPa and lowered it to about 1100 kPa thereafter. After one year of SAGD, the subcool in the LP wellpair climbed to over 60C for a couple of months. In the same time interval, the RP wellpair subcool dropped to zero for several months. When the injection pressure was lowered after one year to 1100 kPa, the LP wellpair responded by a jump in liquid production, which then led to cooler liquid being produced from the LP producer and consequently a higher subcool. After the system stabilized, the subcool reached the steady value between 20 and 30C which persisted throughout the remainder of the process. In the RP wellpair, after the injection pressure was reduced to 1200 kPa, liquid production rates did not rise immediately but initially remained roughly constant and consequently, the produced fluids temperature remained roughly the same. However, because the injection pressure was reduced, its temperature also fell and the subcool became nearly zero. Beyond about two years, the subcool of the RP wellpair also stabilized between 20 and 30C. The differences in the subcool behaviour revealed by the simulation reflect the difference between the geology at each of the wellpairs and its impact on the growth of the steam chambers. From the gas saturation distributions displayed in Figure 23, the LP wellpair has a smaller steam chamber than that in the RP wellpair after one year of SAGD. Energetics of SAGD As has been described above the optimum steam chamber operating strategy employed in all the cases we have reviewed have a common methodology. This methodology calls for maintaining a high steam chamber pressure early in the SAGD process. The higher steam chamber pressures lead to faster chamber growth and to higher chamber temperatures. This in turn leads to a favourably higher oil production profile. In general, the higher the chamber temperature, the higher the oil production. Eventually the steam chamber will contact the top gas after which the steam chamber operating pressure is dropped in line with the prevailing top gas pressure. In this section, the relative roles of vertical and horizontal heat transfer are investigated. The analysis here will focus on the LP wellpair model. Figures 26 to 28 display the temperature, pressure, and flowing steam quality along a vertical plane intersecting the wells roughly two-thirds downwell. The injection well is located at 37 m whereas the production well is located at about 42 m (the distance equal to 0 m is located at the top of the reservoir). The plots in Figures 26 to 28 are good representatives of the profiles at other locations along the wellpair. Beyond 2008, the profiles at each time overlay each other suggesting that the steam chamber is under quasi steady state conditions. Figure 26 shows that the temperature across the steam chamber is roughly constant at 177C. The temperature profiles above the chamber edge indicate conductive heat transfer into the

reservoir rock directly above the steam chamber. In the period between 2006 and 2008 the steam chamber grows roughly 20 m in the vertical direction indicating a vertical rise rate of about 2.7 cm/day. Given the temperature profile and due to the chamber being at saturation conditions, beyond 2008, the pressure is largely constant across the steam chamber. Thus the temperature and pressure gradients in the steam chamber are very small. Figure 28 displays the flowing steam quality profiles. At the start of SAGD model in 2005-04-01, the quality profile exhibits two peaks, one at the injection well elevation and the other at the production well location. The reason for these two peaks is because circulation was occurring in both wells and it was sufficiently hot that there is steam in reservoir at the well locations. After a quasi steady state has evolved, beyond about 2008, the vertical quality profile has roughly constant slope equal to 0.016 quality units per meter. Beyond the steam chamber, the flow steam quality falls rapidly to zero. This is the location where the steam is releasing all of its latent heat to the oilsand at the edges of the steam chamber. Figure 26: Temperature through vertical profile intersecting the LP wellpair. Figure 27: Pressure through vertical profile intersecting the LP wellpair.

SPE/PS-CIM/CHOA 97742 15

Figure 28: Flowing steam quality through vertical profile intersecting the LP wellpair. Figures 29 to 31 display the temperature, pressure, and flowing steam quality along a horizontal plane located 2 m above the injection well. The injection and production wells are located at 92 m. The plots in Figures 29 to 31 are good representatives of the profiles at other locations across the domain. The temperature profiles in Figure 29 demonstrate the lateral growth rate of the steam chamber. Beyond 2008, the lateral growth rate is on average 0.7 cm/day. This is roughly 3.8 times less than the initial vertical growth rate. The temperature in the steam chamber is roughly constant at 177C. As expected due to saturation conditions in the steam chamber, Figure 30 confirms that the pressure is also nearly constant within the steam chamber. Figure 29: Temperature through horizontal profile 2 m above the LP wellpair injector.

Figure 30: Pressure through horizontal profile 2 m above the LP wellpair injector. Figure 31: Flowing steam quality through horizontal profile 2 m above the LP wellpair injector. Figure 31 shows the flowing steam quality profiles through horizontal section 2 m above the injection well. In the steam chamber, the steam quality profiles have an average slope roughly equal to 0.02 quality units per m. As a means to analyze the quality slopes in the vertical and horizontal directions, the heat balance can be used. The heat balance is derived by considering a small volume element of dimensions dx, dy, and dz as shown in Figure 32 and is given by the statement that the net heat into the element is equal to the heat flux, Q , lost from the element. The heat balance is given by: ( ) ( ) ( )

( )[ ] ( )[ ]( )[ ] dxdydzdtQdxdydtdqq

dxdzdtdqqdydzdtdqqdxdydtqdxdzdtqdydzdtq

zz

yyxx

zyx

++++++=

++ 1

16 SPE/PS-CIM/CHOA 97742

dx

dy

dz qx qx+dqx

qy+dqy

qy

qz+dqz

qz Q

Figure 32: Heat transfer into and out of a differential element. After dividing by the elemental dimensions, taking the limit as they approach zero, the result is:

0=++

+ Q

zq

yq

xq zyx . 2

In the x direction, the heat flux in each direction is the sum of the conductive and convective terms:

[ ]xLLLVVVTHx huhuxTkq ++

= 3 where kTH is the thermal conductivity, T is the temperature, V and L are the vapour and liquid densities, uV and uL are the vapour and liquid phase (x-directed) velocities, and hV and hL are the vapour and liquid phase specific enthalpies. The first term on the right side of Equation 3 is the conductive heat transfer term whereas the second term on the right side is the convective term. The x-directed vapour and liquid phase mass fluxes, VVV um = and LLL um = , can be substituted into Equation 3 to give:

[ ]LLxVVxTHx hmhmxTkq ++

= . 4 Often, the enthalpy is expressed as a function of temperature by using the specific heat capacity to express Equation 3 as:

( ) ( )[ ]xrefpLLLrefpVVVTHx

TTcuTTcuxTkq ++

= 5 which results in the more often found temperature-based convective heat transfer term in the differential heat balance.

Given the definition of steam quality, f, the heat flux in the x direction given by Equation 4 can be re-expressed as:

( )[ ]LxVxTHx hmfhfmxTkq ++

= 1 6 or

[ ] xLTHx mhfxTkq ++

= 7 where is the latent heat of vapourization, given by

LV hh = , and mx is the total (vapour and liquid) mass flux. Similarly, the y and z directed heat fluxes are given by:

[ ] yLTHy mhfyTkq ++

= 8

[ ] zLTHz mhfzTkq ++

= 9 After substituting Equations 7-9 into Equation 2, the result is:

( )[ ] ( )[ ] ( )[ ]

+

+

+

=+

++++

zTk

zyTk

yxTk

x

Q

mhfz

mhfy

mhfx

THTHTH

zLyLxL

10

Within a SAGD steam chamber, the temperature and pressure are nearly constant. This means that the heat conduction terms in Equation 10 are very small and that the latent heat of vapourization and liquid enthalpy are essentially constant. Applying constant temperature and pressure to Equation 10 yields:

( )[ ] ( )[ ] ( )[ ] Qmhfz

mhfy

mhfx zLyLxL

=+++

++

11 or after re-arrangement and canceling terms associated with mass continuity:

[ ] [ ] [ ] Qfmzfmyfmx zyx=

++

12 Equation 12 reveals that the energy needed to account for the heat losses, Q , are generated from a loss of steam quality in the domain. For one-dimensional flow, Equation 12 simplifies to:

xmQ

xf

=

13 From observation, it can be seen that in a constant

SPE/PS-CIM/CHOA 97742 17

temperature, pressure domain where there are heat losses, the steam quality will fall with distance. In one-dimension, if at x = x0, the steam quality is f0, then the steam quality distribution is given by:

( )00 xxmQff

x

=

14

which reveals that providing the ratio between the heat losses to mass flow are constant, that the steam quality drops linearly with distance. Another way of interpreting Equation 13 is that the larger the steam quality gradient, the larger the specific heat losses at the edges of the steam chamber, that is, the larger the heat transfer. On considering the steam quality slopes in the vertical (0.016 m-1) and horizontal (0.02 m-1) directions determined from Figures 28 and 31, because the quality gradient is larger in the horizontal direction, more of the heat supplied is being directed towards expanding the chamber laterally as opposed to feeding overburden losses. This is a key result that indicates that the optimized steam injection strategy provided less heat flux in the vertical direction than the horizontal direction. This means that there was less heat transferred to the overburden and convective losses to the gas cap zone and most of it was directed to growth at the sides of the chamber. In a 3D SAGD chamber, there are not only heat losses in the plane (lateral-vertical plane) but also from heat losses in the downwell direction. If the temperature varies in the downwell direction, then there is also conductive heat transfer in the downwell direction. This will further impact the steam quality variation at any lateral-vertical slice of the steam chamber. Enthalpy versus Temperature Figure 33 displays a steam saturation curve and the enthalpy versus temperature two-phase envelope. Within the envelope, both vapour and liquid exist. The lines within the two-phase region are constant steam quality lines. The topmost line represents the 100% steam quality line whereas the bottom-most line represents the 0% steam quality line. Consider the situation where the steam chamber exists at state A. The steam chamber is at nearly constant temperature and pressure and so sits at point A throughout the chamber. If the steam quality is known at the steam injector, then the enthalpy of the injected steam is known. If the steam quality is 90%, then the injected steams enthalpy is given by the value at point B. Due to heat losses to the outer regions of the steam chamber, the steam quality in the chamber falls moving away from the injection well. Because the temperature and pressure are roughly constant throughout the chamber, the enthalpy at any point in the chamber will lie along the line from point B to point C. If the steam loses all of its latent heat, it reaches the point C and is liquid water. If further cooling occurs, then a reduction of the liquid water temperature results. As the pressure of the process evolves, given that the chamber is at

saturation conditions, point A will shift along the steam saturation curve. For example, if the injection pressure falls as the process evolves, point A will move in the left direction along the saturation curve. As a consequence, points B and C will also shift in the left direction. Figure 33: Steam saturation curve and enthalpy versus temperature diagram. The extents of the vertical profiles of the flowing steam quality can be plotted on the enthalpy versus temperature diagram as shown in Figure 34. This is a subregion of the diagram displayed in Figure 33. The vertical portions of the profiles, above the dotted line in Figure 34, represent the part of the chamber that is nearly all steam and is at saturation conditions. Here the temperature is roughly constant and heat tranfer throughout the chamber is mainly due to convection and is reflected by the steam quality variation. At the edges of the chamber, the portions of the plots below the dotted line, steam is losing its latent heat, the quality rapidly falls and the specific enthalpy of the wet steam is relatively low. Also, partial pressure effects come into play because solution gas comes out of solution from the bitumen at the edges of the chamber. The top part of each profile represents the enthalpy of the steam near the injection well (highest quality and consequently enthalpy) whereas the

0250500750

100012501500175020002250250027503000

100 150 200 250 300 350 400Temperature, Deg. C

Enth

alpy

, kJ/

kg

Spec

ific

Enth

alpy

, kJ/

kg

0% Quality

100% Quality

A

B

C

0

1000

2000

3000

4000

5000

6000

7000

8000

9000

10000

100 150 200 250 300 350 400Temperature (C)

Pres

sure

(kPa

a)Pr

essu

re, k

Pa

Saturation Curve

18 SPE/PS-CIM/CHOA 97742

bottom parts of the curves represent the top of the vapour chamber where the quality transitions from that at steam chamber conditions to zero (where the plots cross the zero quality line). Figure 34: Vertical flowing steam quality profiles in form of enthalpy versus temperature for LP wellpair. After the chamber has matured, after about 3 years of operation, the maximum and minimum specific enthalpies of the steam (beyond the chamber edge, that is, above the dotted line in Figure 34) are roughly constant throughout the chamber. The profiles in the edge region of the chamber (below the dotted line) become more vertical as the process evolves due to continued conductive heating of the materials above the edge of the chamber. Conclusions The flowing steam quality provides a novel method to visualize heat transfer within and at the boundaries of the steam chamber. This is useful because the pressure and temperature of the steam chamber are nearly constant. The flow steam quality profiles provide a means to examine convective heat transfer in the reservoir. The optimized operating strategy for SAGD in reservoirs with top gas have high initial chamber injection rates and pressures prior to chamber contact with the top gas. Subsequent to breakthrough the chamber injection rates are lowered to balance pressures with the top gas and so avoid or at the least minimize convective heat losses of the steam to the top gas zone. The lower the top gas pressure, the lower the chamber pressure and therefore the lower the chamber temperature. In addition to avoiding convective heat losses to top gas, the lowering of chamber pressure also reduces conductive heat losses to the over and under burden and allows harvesting of heat stored in the chamber prior to breakthrough. The lower chamber temperature does however lead to higher bitumen viscosities. To optimize SAGD, steam conformance must be managed

along the wellbore to ensure full contact of the steam chamber to the reservoir penetrated by the horizontal well. The optimized steam injection strategy promotes heat transfer in the lateral direction over that in the vertical direction. This reduces heat losses to the overburden and convective losses to the top gas zone. The amount of heat supplied by the injected steam should be only that required to mobilize the bitumen at the edges of the chamber, not to induce large conductive losses to the overburden. The dual wellpair operating strategy was determined by optimizing the individual wellpair reservoir simulation models separately and then integrating the optimized operating strategies into the dual wellpair model. Due to the existence of the top gas zone, the strategies developed for each of the single wellpair models were designed to be gentle and not promote extensive communication with the top gas zone. For this reason, the two individually optimized operating strategies could be implemented together in the dual wellpair model. The dual wellpair model revealed that communication between the two wellpairs did influence the performances of the wellpairs slightly. Acknowledgements The authors would like to acknowledge Paramount Resources Ltd. for permission to publish this study. References 1. SINGHAL, A.K., ITO, Y., and KASRAIE, M. Screening

and Design Criteria for Steam-Assisted Gravity Drainage (SAGD) Projects. SPE Paper 50410, 1998.

2. KOMERY, D.P., LUHNING, R.W., and OROURKE, J.C. Towards Commercialization of the UTF Project Using Surface Drilled Horizontal SAGD Wells. J. Can. Pet. Tech. 38(9):36-43, 1999.

3. BUTLER, R.M. Thermal Recovery of Oil and Bitumen. GravDrain Inc. 1997.

4. KISMAN, K.E., and YEUNG, K.C. Numerical Study of the SAGD Process in the Burnt Lake Oil Sands Lease. SPE Paper 30276, 1995.

5. ITO, Y., and SUZUKI, S. Numerical Simulation of the SAGD Process in the Hangingstone Oil Sands Reservoir. J. Can. Pet. Tech. 38(9):27-35, 1999.

6. EDMUNDS, N. and CHHINA, H. Economic Optimum Operating Pressure for SAGD Projects in Alberta. J. Can. Pet. Tech. 40:13, 2001.

7. ITO, Y., HIRATA, T., and ICHIKAWA, M. The Effect of Operating Pressure on the Growth of the Steam Chamber Detected at the Hangingstone SAGD Project. J. Can. Pet. Tech. 43(1):47-53, 2004.

8. SALTUKLAROGLU, M., WRIGHT, G.N., CONRAD, P.R., MCINTYRE, J.R., and MANCHESTER, G.J. Mobils SAGD Experience at Celtic, Sashatchewan. Paper 99-25 CSPG and Petroleum Society Joint

0250500750

100012501500175020002250250027503000

120 130 140 150 160 170 180 190Temperature, Deg. C

Enth

alpy

, kJ/

kg

Spec

ific

Enth

alpy

, kJ/

kg

0% Quality

100% Quality 1: 2006-04-01

2: 2008-04-01

3: 2010-04-01

5: 2014-04-01

4: 2012-04-01

6: 2016-04-01

SPE/PS-CIM/CHOA 97742 19

Convention in Calgary, Alberta, Canada, 14-18 June, 1999.

9. SUGGETT, J., GITTINS, S., and YOUN, S. Christina Lake Thermal Project. SPE/Petroleum Society of the CIM Paper 65520, 2000.

10. SIU, A.L., NGHIEM, L.X., GITTINS, S.D., NZEKWU, B.I., and REDFORD, D.A. Modelling Steam-Assisted Gravity Drainage Process in the UTF Pilot Project. SPE Paper 22895, 1991.

11. AED (Alberta Economic Development). Oil Sands Industry Update. Available at Alberta Dept. of Energy Website: http://www.energy.gov.ab.ca/com/default.htm. March 2004.

12. YEE, C.-T. and STROICH, A. Flue Gas Injection Into a Mature SAGD Steam Chamber at the Dover Project (Formerly UTF). J. Can. Pet. Tech. 43(1):54-61, 2004.

13. GATES, I.D., and CHAKRABARTY, N. Optimization of Steam-Assisted Gravity Drainage (SAGD) in Ideal McMurray Reservoir. Paper 2005-193 presented at Canadian International Petroleum Conference, Calgary, Alberta, Canada, June 7-9, 2005.

14. ROBINSON, W., KENNY, J., HERNANDEZ-Hdez, I.L., BERNAL, A., CHELAK, R. Geostatistical Modeling Integral to Effective Design and Evaluation of SAGD Processes of an Athabasca Oilsands Reservoir, A Case Study. Paper 97743 presented at the 2005 SPE International Thermal Operations and Heavy Oil Symposium held in Calgary, Alberta, Canada, 1-3 November, 2005.

15. ROXAR. IRAP RMS Users Manual. 2004. 16. Computer Modelling Group (CMG) Ltd. STARS Users

Manual, Version 2004.10. Calgary, Alberta, Canada. 17. MEHROTRA, A.K. and SVRCEK, W.Y. Viscosity of

Compressed Athabasca Bitumen. Can. J. Chem. Engrg. 64:844-847, 1986.

18. BOONE, T.J., YOUCK, D.G., and SUN, S. Targeted Steam Injection Using Horizontal Wells with Limited Entry Perforations. SPE 50429, 1998.