Summary The immiscible displacement mechanism of CO2 in a simultaneous injection of CO2 and steam in a heavy-oil reservoir is evaluated with a numerical simulation model. In a steam stimulation process, the viscosity reduction effect of CO2 on heavy oil is the major contributor to increased recovery in a high-compressibility reservoir. In a normal-compressibility reservoir, the major benefit is derived from the solution gas effect of the injected CO2. Ignoring the solubility of CO2 in water can introduce an optimistic incremental recovery over steam-only injection. In a steamdrive process, the addition of CO2 to be injected steam improves the final recovery by only a small amount. However, the oil production rate before steam breakthrough appears to be production rate before steam breakthrough appears to be accelerated by the solution of CO2 in the heavy oil. The swelling effect of CO2 does not appear to play an important role in the incremental recovery, because the swelling effect of CO2 at high temperature is small when compared with the thermal expansion of the crude oil. Introduction The growing interest in the application of CO2 injection in EOR schemes has been concentrated so far on the miscible aspect of CO2. The CO2 miscible flood process generally is limited to the recovery of light-gravity process generally is limited to the recovery of light-gravity oil. Application of CO2 miscible flood to heavy-gravity oil has been hampered by the complex phase behavior, including the possible deposition of asphaltene, a solid phase, which could be detrimental to the permeability of phase, which could be detrimental to the permeability of the reservoir. In the immiscible aspect of CO2 injection, the viscosity reduction effect of CO2, generally unimportant in light-oil reservoirs, could play a significant role in the recovery of heavy oil. For all heavy-oil reservoirs, the major mechanism of enhanced recovery methods, which include steam injection and in-situ combustion process, is the reduction of reservoir oil viscosity to allow oil mobilization and to improve the mobility ratio between the reservoir oil and the displacement fluid. A study of the significant viscosity reduction effect of CO2 on high-viscosity crude oil was published as early as 1963. Welker and Dunlop showed that the viscosity reduction could be up to 98 % for a 4,800-cp (4.8-Pas) heavy crude oil at 80 deg. F (27 deg. C) and 800-psi (5515-kPa) carbonation pressure. A proposed field application of CO2 injection was reported to take advantage of this significant viscosity reduction aspect. It was also reported that supercritical CO2 was used to achieve solvent-reduced oil viscosity in some U.S. reservoirs in 1977. A study on the effect of normal reservoir parameters on a CO2 huff ‘n’ puff process was reported parameters on a CO2 huff ‘n’ puff process was reported in 1979. However, no field data have been published. In 1981, the first CO2 cyclic stimulation was conducted in Canada with interesting results. The experiment of solvent addition to steam process has been carried out in the field since probably as early as steam was applied successfully in oil recovery. No systematic evaluation was presented or published. Laboratory physical models were used to evaluate the benefit of solvent addition to steam and the results were reported by Redford. JPT P. 1591
The Court Bakken heavy oil reservoir (17 °API) in Saskatchewan has been under successful water flooding for many years. Laboratory studies have indicated that caustic flooding can enhance heavy oil recovery significantly after water flooding. This paper describes design and implementation of the first caustic flooding pilot in a heavy oil reservoir of this viscosity range in the Western Canadian basin. It reviews results of laboratory studies and a single well test. It also discusses challenges experienced at Court during the early piloting phase.
In the Court Field, the middle Bakken Sand Pool has been operated as a heavy oil waterflood for over 15 years. However, unrecovered oil volumes in the pool remain attractive for improved recovery schemes. Recently, the Court Middle Bakken Reservoir model was updated to evaluate the potential for downspacing and waterflood optimization of the reservoir. The potential for 20-acre downspacing for both infill drilling and additional water injection was identified by this study. As part of the additional development program, an injector producer well pair was drilled to create a new injection pattern with reduced inter-well spacing. Reservoir pressures, water saturation and effective permeability to water in the pattern were determined by RFT and log data. Pattern characterization was complemented by an interference test, including all the wells in the pattern. Analytical and numerical tools were used in the test design. The most comprehensive results were obtained by local grid refinement of the pattern area in the full field simulation model. Unavoidable interference with a neighboring pattern during the test was predicted. In order to account for this effect, it was decided to run the test with the new injector active intermittently. The complete test design and analysis of the results are described. In addition, a comparison of pressure measurements by downhole gauge and acoustic well sounder are presented. Introduction The Court Field, located in west central Saskatchewan, produces 17 ºAPI heavy crude from the Middle Bakken Formation, using vertical wells and a waterflood recovery scheme. The Court Bakken Sand was discovered in November 1981. The Court Bakken Sand Voluntary Unit No. 1 was formed in 1988 and waterflood commenced with only 2% of OOIP produced. There are 39 producing oil wells and 21 water injection wells currently in operation within the main pool. The current recovery factor is approximately 20%, with some wells producing up to 30m3/d oil. Recently, Majcher et al.(1) presented a geological and engineering overview of the reservoir. The Middle Bakken Formation was deposited as NE-SW trending sand ridges. The pool has undergone significant collapse of the Torquay Formation with the subsequent creation of extensive post-depositional sinkholes within the Bakken. This structural deformation interrupts the lateral continuity of the sand ridge and its characterization is the most challenging to further field development and effective waterflood management. Another important Bakken heterogeneity is the change in well log signature that represents the variation in facies at the ridge edges(2). This facies distribution within the Middle Bakken correlates with the waterflood response. Majcher et al.(1) identified the potential for infill drilling of producers and injectors near the edges of the pool. An injector-producer pair was recently drilled in Section 36-033-28W3M on 20-acre spacing. An interference test with four wells was conducted to investigate how the heterogeneities described above affect the waterflood performance of the newly configured pattern.
In the Court field, the middle Bakken Sand Pool has been operated as a heavy oil waterflood for over 15 years. However, unrecovered oil volumes in the pool remain attractive for improved recovery schemes.Recently, the Court middle Bakken reservoir model was updated to evaluate the potential for downspacing and waterflood optimization of the reservoir. The potential for 20 acre downspacing for both infill drilling and additional water injection was identified by this study.As part of the additional development program, an injectorproducer well pair was drilled to create a new injection pattern with reduced inter-well spacing. Reservoir pressures, water saturation and effective permeability to water in the pattern were determined by RFT and log data. Pattern characterization was complemented by an interference test, including all the wells in the pattern. Analytical and numerical tools were used in the test design. The most comprehensive results were obtained by local grid refinement of the pattern area in the full field simulation model. Unavoidable interference with a neighboring pattern during the test was predicted. In order to account for this effect, it was decided to run the test with the new injector active intermittently.The complete test design and analysis of the results are described. In addition, a comparison of pressure measurements by downhole gauge and acoustic well sounder are presented.
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