The Design of a Modern Steamflood in a Thick, Dipping, Heavy Oil Reservoir
Abstract: Mobil has completed the design phase of a steamflood project in a thick, moderately dipping, unconsolidated heavy oil reservoir. The design takes advantage of the gravity drainage recovery mechanism in the thick reservoir, allowing vertical steam zone expansion with minimal steam breakthrough. This steamflood project is economic in the late 1980's period of low oil prices. The design was completed with an interdisciplinary teamwork approach using concurrent studies for expediency. … Show more
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A numerical simulation study was conducted to elucidate recovery mechanisms and find optimum operating strategies for a steeply dipping, heavy oil reservoir. A model representing a 200 dip reservoir with an updip gas cap and a downdip edgewater was used for the study. The study showed that gravity drainage of the heated oil is the main production mechanism in steamflooding steeply dipping reservoirs. Steamflood oil recovery for this type of reservoir is strongly affected by gas cap and aquifer pressures. This is because the gas-oil or water-oil contact can move closer to or away from the initial oil zone, depending on those pressures relative to that of the steam zone. High gas cap pressure is desirable because it slows the injected steam rising above the initial gas-oil contact where injected heat is wasted. A high aquifer pressure retards the growth of steam-zone downdip, thereby reducing the steamflood efficiency. The study further showed that this type of reservoir can best be exploited by:initiating the steamflood as a line drive with steam injection into the oil zone away from the gas cap and edgewater,placing the injector closer to downdip producers than to updip producers in order to producers than to updip producers in order to distribute the injected heat evenly between the updip and downdip directions, andcontinuing to operate both updip and downdip producers to capture the displaced, heated oil until an economic limit is reached. Maintaining a high gas cap pressure by injecting a noncondensable gas, if the gas cap volume is finite, is an additional operating strategy for improving steamflood oil recovery from this type of reservoir. If the aquifer pressure is low, infill drilling downdip from the original producer can be used to improve capture of the producer can be used to improve capture of the displaced oil. Introduction A number of investigations dealing with steamdrive in dipping reservoirs have been reported in the literature. However, there are few published results concerning steamflooding in the presence of strong aquifer influx and virtually none dealing with steamflooding in the presence of both gas cap and edgewater. Most of these investigations reported numerical simulation results obtained with either actual field models to design steamflood projects or conceptual models to study projects or conceptual models to study recovery mechanisms and develop optimum operating strategies for dipping reservoirs. A numerical simulation study, published by the present author in 1988, showed that gravity drainage present author in 1988, showed that gravity drainage of the heated oil is the main recovery mechanism in steamflooding steeply dipping reservoirs. This study proposed a set of operating strategies to maximize the benefits of the recovery mechanism. However, the results were limited to a reservoir model that was sealed at the updip and downdip boundaries. Consequently, the results could not be applied to the more abundant type reservoirs, those that are unconfined and connected to an updip gas cap and a downdip aquifer. There were numerous requests from the field for recommendations on steamflooding the more abundant type reservoirs. Physical and numerical model studies were carried Physical and numerical model studies were carried out to investigate recovery mechanisms and recommend optimum operating strategies for steamflooding in the presence of strong aquifer influx. Results of these studies contributed greatly to augment the limited published information in this area. However, the results were somewhat reservoir specific and could not be generalized to cover the more commonly occurring reservoirs mentioned above. P. 79
A numerical simulation study was conducted to elucidate recovery mechanisms and find optimum operating strategies for a steeply dipping, heavy oil reservoir. A model representing a 200 dip reservoir with an updip gas cap and a downdip edgewater was used for the study. The study showed that gravity drainage of the heated oil is the main production mechanism in steamflooding steeply dipping reservoirs. Steamflood oil recovery for this type of reservoir is strongly affected by gas cap and aquifer pressures. This is because the gas-oil or water-oil contact can move closer to or away from the initial oil zone, depending on those pressures relative to that of the steam zone. High gas cap pressure is desirable because it slows the injected steam rising above the initial gas-oil contact where injected heat is wasted. A high aquifer pressure retards the growth of steam-zone downdip, thereby reducing the steamflood efficiency. The study further showed that this type of reservoir can best be exploited by:initiating the steamflood as a line drive with steam injection into the oil zone away from the gas cap and edgewater,placing the injector closer to downdip producers than to updip producers in order to producers than to updip producers in order to distribute the injected heat evenly between the updip and downdip directions, andcontinuing to operate both updip and downdip producers to capture the displaced, heated oil until an economic limit is reached. Maintaining a high gas cap pressure by injecting a noncondensable gas, if the gas cap volume is finite, is an additional operating strategy for improving steamflood oil recovery from this type of reservoir. If the aquifer pressure is low, infill drilling downdip from the original producer can be used to improve capture of the producer can be used to improve capture of the displaced oil. Introduction A number of investigations dealing with steamdrive in dipping reservoirs have been reported in the literature. However, there are few published results concerning steamflooding in the presence of strong aquifer influx and virtually none dealing with steamflooding in the presence of both gas cap and edgewater. Most of these investigations reported numerical simulation results obtained with either actual field models to design steamflood projects or conceptual models to study projects or conceptual models to study recovery mechanisms and develop optimum operating strategies for dipping reservoirs. A numerical simulation study, published by the present author in 1988, showed that gravity drainage present author in 1988, showed that gravity drainage of the heated oil is the main recovery mechanism in steamflooding steeply dipping reservoirs. This study proposed a set of operating strategies to maximize the benefits of the recovery mechanism. However, the results were limited to a reservoir model that was sealed at the updip and downdip boundaries. Consequently, the results could not be applied to the more abundant type reservoirs, those that are unconfined and connected to an updip gas cap and a downdip aquifer. There were numerous requests from the field for recommendations on steamflooding the more abundant type reservoirs. Physical and numerical model studies were carried Physical and numerical model studies were carried out to investigate recovery mechanisms and recommend optimum operating strategies for steamflooding in the presence of strong aquifer influx. Results of these studies contributed greatly to augment the limited published information in this area. However, the results were somewhat reservoir specific and could not be generalized to cover the more commonly occurring reservoirs mentioned above. P. 79
SPE Members Abstract Two thermally enhanced oil recovery methods, cyclic steaming and steamflooding, have been investigated by means of numerical modeling for a massive, dipping, Midway Sunset Field reservoir. Comparative economics have been evaluated for the development alternatives. The results of the investigation indicate that ultimate recovery efficiency is not sensitive to the method of steam delivery to the reservoir. Cyclic steaming methods recovered the same percentage of original oil in place as did steamflooding. The cyclic operations required several times longer than steamflooding to reach the same ultimate recovery efficiency. On a steam utilization efficiency basis (oil to steam ratio), cyclic steaming with small steam slug volumes proved to be the most efficient recovery method. As the rate of steam injection increased, the steam utilization efficiency decreased, regardless of the manner in which steam was delivered to the reservoir. Despite having the poorest steam utilization efficiency, steamflooding provided far superior economics as compared to conventional low or moderate slug volume cyclic steaming. This is directly attributable to steamflooding having the fastest rate of increase in average reservoir temperature and therefore the greatest rate of net recovery as compared to the alternatives investigated. Steamflooding exhibited a much quicker payout of development capital and a greater present value return per dollar invested. Introduction While thermally enhanced oil recovery methods are an attractive method of extracting heavy oil, due to the large development capital costs and the significant expense in steam generation, it is important to look critically at development alternatives and to choose the method that is most attractive to the investor. A cyclic steaming project is operated significantly different from that of a steamflood. Consequently, it requires a different facilities configuration in order to allow effective optimization during its operation. It is costly to install a facilities design tailored to one method, and then to retrofit for an alternative operating strategy. It is therefore essential to choose the more attractive manner in which steam is to be delivered to the reservoir and to install and operate the project in this manner. Thermal EOR textbooks indicate that, in general, greater recovery efficiencies are possible with steamflooding than with cyclic steaming. It is generally written that while steamflooding can be expected to recover 50–60% of the original oil in place, cyclic steaming typically recovers only 10–25%. Cyclic steaming is viewed as a stimulation method with rapid response while there is a lag in the production response associated with steamflooding. The Potter Sand in the Midway Sunset Field has been developed and operated with cyclic steaming as well as a steamflood by various operators. Both methods are viewed by their respective operators as technical and economic successes. P. 429^
In the numerical modeling of a steamflood process in a highly stratified, thick reservoir with thin interbedded discontinuous permeability barriers, the vertical grid size must be comparable to the length scale of permeability variation in the vertical direction. In a thick reservoir, the smaller length scale of vertical heterogeneities results in an impractically large number of layers for the modeling of a computationally intensive process such as steamflooding. In the first part of this study a series of simulation runs were conducted for different geostatistically derived cross sectional models to study the degree of heterogeneity that is required to properly model steamfloods in the presence of thin diatomite barriers in both the dipping and non-dipping sections of a heavy oil, thick reservoir. These cross sectional models each had a different number of layers and were developed by sequential indicator simulation of log traces. The most detailed models contained 300 layers. In the second part of this work we applied different methodologies for coarsening the most detailed model while still capturing the effects of the geologic features. Two different methods were examined to coarsen the detailed models. In one method, we maintained the impermeable layers and coarsened the sands by averaging each 10 sand layers. In the other method, the 300 layer models were coarsened using a general scale up method. In this method the dominant flow paths in the cross section are first identified through solution of a single phase flow problem. This information is then used to selectively scale up the reservoir properties, leaving detail in regions where required and coarsening in other regions. The results show that the coarse models developed directly from the sequential indicator simulation underpredict the recovery in the non-dipping cross sections and overpredict the recovery in the dipping cross sections. The results also show that the scaled up coarse models predict recoveries in good agreement with the detailed model in both the dipping and non-dipping sections of the reservoir. The results also show that the coarse models which were developed by keeping the shale and averaging the sand layers only provide accurate results in the non-dipping section of the reservoir. Introduction As heat and reservoir management become more important in steamflood operations improved engineering tools are required to cost-effectively manage steam injection projects. Application of reservoir simulation as a tool for steamflood management is growing. However, many steamflood reservoirs have a high amount of geologic heterogeneities, which may impact both actual and simulated project performance. The importance and impact of heterogeneities on the performance prediction of steamflood processes in highly stratified systems have been recognized in the literature.
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