Reservoir Simulation of Steam Injection in the Cold Lake Tar Sand
Abstract: A reservoir simulator of steam injection in the Cold Lake Tar Sand has been validated through a history match. The history match consists of 9 steam cycles in two wells during the period June 1978 through October 1980. Block size, fracture length, oil and water relative permeabilities, and pore compressibility were found to have a significant effect upon the simulation results. The simulation results were found to be insensitive to the time step size, heat conduction from the fracture, areal grid, and well pro… Show more
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Cited by 5 publications
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With 8 billion barrels of bitumen in place and more than 30 years of thermal piloting and demonstration projects, Peace River offers an excellent growth opportunity for Shell's ultra-heavy oil portfolio. In support of this initiative, integrated geological and reservoir modeling of two project areas was conducted. The key objectives were toimprove predictive modeling capability of cyclic steam stimulation (CSS) projects by history matching two groups of CSS multilateral wells anddevelop a history matched physical representation that not only validates empirical models but can be deployed to optimize CSS designs for full field development. Detailed geological models were created over two pad areas providing a geological framework large enough to have realistic boundary conditions, including impact of surrounding wells. The geological models were imported into CMG's STARS thermal reservoir simulator, and a relatively fine grid was extended over each project area. All available historical production, injection, pressure and temperature data were used in history matching. Steam-induced reservoir dilation, explicit fracturing, and relative permeability hysteresis were important aspects of the overall physical representation. Common physical parameters for dilation/re-compaction, fractures, permeability/porosity transforms, vertical to horizontal permeability ratios, and relative permeability hysteresis were used for both pads. Each pad area maintained its own unique geological, petrophysical, and fluid properties, in line with observed field trends. Excellent history matches (aided by experimental design) of injection and production volumes, injection wellhead pressures, estimated production bottom-hole pressures and temperature profiles were achieved not only for the entire Pad A and B groups of wells, but also for the individual wells. In summary, a predictive CSS simulation model has been developed and validated by history matching two areas of the Peace River field. The model is suitable for sensitivity studies of geological, petrophysical, and fluid properties. It is also capable of assessing impact of well configuration, spacing, steam quality, and steaming strategy. Introduction Peace River is 100% Shell owned heavy oil property located in north-western Alberta, Canada, approximately 700 km northwest of Edmonton (Fig. 1). It holds approximately 8 billion barrels of 7°API oil in place trapped in approximately 30 m thick semi-consolidated sand layer (Fig. 2a) buried at a depth of about 600 m, and spread over approximately 370 km2. The Bluesky reservoir has been broadly classified into two intervals, poorer quality Estuarine and good quality Deltaic (Fig. 2b). CSS is employed to extract the oil, most recently using closely spaced multi-lateral horizontal wells drilled from a central pad. Modeling Objectives Growth plans being considered cover development across the entire field. Optimizing such a development plan requires investigating a host of sensitivities, including well configuration, placement, spacing, steam quality, steam slug sizes, production cycle length etc. Thermal reservoir simulation is a viable tool that can be deployed to explore for the most optimum case. The challenge with such models is for them to be reasonably well history matched, while at the same time retaining their predictive capability. Injection above fracture pressure adds to physical complexities. Addressing this challenge became the primary modeling objective.
With 8 billion barrels of bitumen in place and more than 30 years of thermal piloting and demonstration projects, Peace River offers an excellent growth opportunity for Shell's ultra-heavy oil portfolio. In support of this initiative, integrated geological and reservoir modeling of two project areas was conducted. The key objectives were toimprove predictive modeling capability of cyclic steam stimulation (CSS) projects by history matching two groups of CSS multilateral wells anddevelop a history matched physical representation that not only validates empirical models but can be deployed to optimize CSS designs for full field development. Detailed geological models were created over two pad areas providing a geological framework large enough to have realistic boundary conditions, including impact of surrounding wells. The geological models were imported into CMG's STARS thermal reservoir simulator, and a relatively fine grid was extended over each project area. All available historical production, injection, pressure and temperature data were used in history matching. Steam-induced reservoir dilation, explicit fracturing, and relative permeability hysteresis were important aspects of the overall physical representation. Common physical parameters for dilation/re-compaction, fractures, permeability/porosity transforms, vertical to horizontal permeability ratios, and relative permeability hysteresis were used for both pads. Each pad area maintained its own unique geological, petrophysical, and fluid properties, in line with observed field trends. Excellent history matches (aided by experimental design) of injection and production volumes, injection wellhead pressures, estimated production bottom-hole pressures and temperature profiles were achieved not only for the entire Pad A and B groups of wells, but also for the individual wells. In summary, a predictive CSS simulation model has been developed and validated by history matching two areas of the Peace River field. The model is suitable for sensitivity studies of geological, petrophysical, and fluid properties. It is also capable of assessing impact of well configuration, spacing, steam quality, and steaming strategy. Introduction Peace River is 100% Shell owned heavy oil property located in north-western Alberta, Canada, approximately 700 km northwest of Edmonton (Fig. 1). It holds approximately 8 billion barrels of 7°API oil in place trapped in approximately 30 m thick semi-consolidated sand layer (Fig. 2a) buried at a depth of about 600 m, and spread over approximately 370 km2. The Bluesky reservoir has been broadly classified into two intervals, poorer quality Estuarine and good quality Deltaic (Fig. 2b). CSS is employed to extract the oil, most recently using closely spaced multi-lateral horizontal wells drilled from a central pad. Modeling Objectives Growth plans being considered cover development across the entire field. Optimizing such a development plan requires investigating a host of sensitivities, including well configuration, placement, spacing, steam quality, steam slug sizes, production cycle length etc. Thermal reservoir simulation is a viable tool that can be deployed to explore for the most optimum case. The challenge with such models is for them to be reasonably well history matched, while at the same time retaining their predictive capability. Injection above fracture pressure adds to physical complexities. Addressing this challenge became the primary modeling objective.
Steam injection in naturally fractured formations has drawn considerable interest recently. It is believed that the steam or water heats the rock, which then undergoes a thermally induced wettability reversal. Hot water can then spontaneously imbibe into the water wet rock matrix, resulting in favorable oil recoveries. In this study, the applicability of steam injection in an oil wet fractured carbonate previously flooded with carbon dioxide (CO2) through multi-component thermal simulations is discussed. A numerical sector model calibrated with 47 years of historical data and data from vintage pre 1970's steam pilot carried out in south east Turkey was used to study optimum operating conditions such as continuous steam injection, cyclic steam injection, steam alternating CO2 injection (SAC) and steam injection with additives such as naphta and CO2. It was observed that for both operating strategies key oil production mechanism is heat transport through the fractures and the matrix suggesting that the success of the process is directly related with fracture spacing and fracture-matrix transfer. Sensitivity studies carried out for differing fracture densities indicated a threshold fracture spacing (7 ft matrix blocks) below which process efficiency significantly decreased. It was further observed that addition of limited amounts of naphta to steam may improve the process; however, CO2 presence adversely affects the heat transport such that too much CO2 limits the heat transfer along the fractures. Introduction The interest in steam injection for naturally fractured reservoirs started more than three decades ago. Dillabough and Prats [1] were among the first to describe the design of a steam pilot to test a recovery process for the crude bitumen in the Peace River tar accumulation in Western Canada that was developed by scaled laboratory experiments and field tests. The recovery process involved a period of conventional steam drive, followed by pressurization and blow down cycles, to achieve the optimal recovery of the crude bitumen. This process was found to be successful based on results of the laboratory experiments and field tests chosen, since as opposed to conventional steam drive, steam tended to channel through a high mobility water zone which acted like a fracture. Sahuquet and Ferrier [2] described a steam-drive pilot in Lacq Superieur field in the Southwest of France, which was a highly fractured carbonate and contained oil of 20° API. Laboratory experiments carried out with core samples from the field showed that a recovery of 68% of OOIP with steam injection, compared to a 13% recovery with natural imbibition, and a 9.5% additional recovery with hot water drive. Although temperature or saturation measurements were not reported, it was mentioned that at the end of the experiment the entire model was at the steam temperature. The pilot design, based on the experimental results, was successful; and the heat transfer was efficient, without early heat breakthrough. It was reported that heat conduction smoothed the temperature profile between the fracture and the matrix. This pilot proved that steam injection can be an effective recovery technique for a highly fractured system and the pilot was extended field wide.
Summary. This paper describes the use of a black-oil, thermal simulator to compare steamflood development using five-spot and inverted nine-spot patterns. The input data selected were representative of a homogeneous patterns. The input data selected were representative of a homogeneous heavy-oil reservoir. This study considered three different development strategies: conventional pattern steamflooding, pattern steamflooding with infill drilling, and steamflooding with infill drilling and pattern realignment. Comparison of pattern steamfloods indicates that at close well spacing (1.25 acres/well [0.5 ha/well]), the inverted nine-spot recovers more oil than the five-spot. Steam breakthrough and oil production are accelerated for the nine-spot relative to the production are accelerated for the nine-spot relative to the five-spot pattern. At larger well spacing, however, oil recovery from the five-spot pattern exceeds that from the nine-spot. Conversion of a five-spot pattern to an inverted nine-spot increases and accelerates oil recovery. Processing of multiple sands will improve the effectiveness of this infill drilling strategy. A development strategy using inverted nine-spot patterns on large well spacings (2.5 to 5.0 acres/well [1 to 2 ha/well]) that yields improved oil recovery compared with conventional five-spot steamflood development was identified. This strategy uses infill drilling and pattern realignment to improve steamflood performance. Introduction Steam injection is currently the most successful EOR process. Both cyclic steam injection and steamdrives are used. Because of the hither ultimate recovery that can be achieved in a drive process, however, normal field practice dictates conversion from process, however, normal field practice dictates conversion from cyclic to continuous steam injection. Because of this evolution, judicious well placement is required to provide an appropriate flood pattern for steamdrive. pattern for steamdrive. Selection of a pattern configuration for steamflooding is usually made on the basis of existing well locations, injectivity/productivity considerations, and reservoir geology. For reservoirs with high structural relief, linedrive patterns with injectors in an updip location have been used with success. A linedrive pattern has also been used successfully in a reservoir with significant water influx. For shallow-dipping reservoirs, steamflood development has usually used repeating patterns with rectangular or triangular geometries. Where wells are on rectangular spacing, which is the usual case, five-spots and nine-spots are the most common flooding patterns. Steamflood development at the Kern River field, the world's largest thermal recovery project, has used five-spot patterns. In waterflooding with rectangular patterns, the choice between using a five-spot or a nine-spot is usually made on the basis of the mobility ratio [M= (k/ )w/l(k/)o]. Selection on this basis is justified by results of laboratory studies that indicate that oil recoveries from both patterns are virtually identical. As described by Craig, the mobility ratio is a measure of a well's injectivity relative to its productivity. At unfavorable mobility ratios (M>1), in-jectivity exceeds productivity. To balance injection with withdrawal therefore, a pattern that has more producers than injectors is required. For favorable mobility ratios (M less than 1), the opposite is true, and the preferred pattern should have more injectors than producers. At unit mobility ratio, the number of producers in a pattern should equal the number of injectors. This implies that the five-spot pattern would be the preferred configuration for a unit-mobility-ratio pattern would be the preferred configuration for a unit-mobility-ratio waterflood. Selection between five-spot and nine-spot patterns for steamflooding is complicated by two major factors. First, there has been no definitive study comparing steamflood oil recovery from the two patterns. Second, even assuming a similar recovery performance. patterns. Second, even assuming a similar recovery performance. selection on the basis of injectivity/productivity considerations is uncertain because of the variation of mobility ratio during a steamflood. The successful use of nine-spot patterns in steamflooding has been recently reported. In the first case, steamflood development began with large-area patterns. This initial phase was followed by infill drilling and well conversion to realign the inverted nine-spot configuration and to reduce well spacing. Steamflood oil recovery was predicted to exceed 50% of the original oil in place (OOIP) with this development strategy. In the second case, a multizone reservoir was developed with separate nine-spot patterns for each zone. Because of the extensive use of steamflood patterns with rectangular geometry, a study to compare the relative merits of five-spot and inverted nine-spot patterns was performed. This study used a three-phase, noncompositional (black-oil) simulator to model the steam injection process. Reservoir and fluid properties representative of the Kern River field were used in the simulation work. A previous simulation study compared steamflood performance in five-spot and inverted nine-spot patterns. This study concluded that the five-spot pattern was superior to the nine-spot pattern on the basis of ultimate oil recovery. However, this evaluation did not compare pattern performance with equal well spacings (acres per well). Use of equal well spacing and injection rate (i.e., equal capital investment and operating costs) is considered essential for a valid comparison between patterns. This investigation began by evaluating the sensitivity of oil recov-ery predicted by the simulator to numerical dispersion. This was followed by a comparison of oil recovery from five-spot and inverted nine-spot patterns with equal well spacing and normalized steam injection rates. Finally, development strategies using inverted nine-spot patterns were compared with conventional steamflood development using five-spot patterns. Reservoir and Model Descriptions Reservoir and Fluid Properties. The reservoir and fluid properties used in this study were considered representative of heavy-oil properties used in this study were considered representative of heavy-oil sands within the Kern River field. These sands are characterized by their shallow depth (1,000 ft [300 m]), negligible dip (less than 5 degrees [0.09 rad]), high permeability (4,000 md), and high compressibility (3 × 10 – psi – [0.4 × 10 - kPa -]). The oil contained in these sands (60% PV) is typified by its low gravity (14 degrees API [0.97 g/cm ]), low volatility, and temperature-sensitive viscosity. Tables 1 through 4 present the basic input data used to perform the simulations. These data were selected from previous simulation studies. SPERE P. 549
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