Hydrocarbon recovery with steam and solvent stages

Abstract

A steam-assisted gravity drainage method includes a two stage solvent injection scheme, wherein steam plus solvent injection is followed by steam plus heavier-solvent injection. The two solvent injections improve recoveries of both the heavy oil and the injected solvent while limiting steam requirements, thus improving the economics of the method.

Claims

1. A method of producing heavy oil comprising: a) providing an injection well and a production well in fluid communication with said injection well; b) initially injecting steam and a first light hydrocarbon solvent into said injection well for a first period of time, said first solvent consisting essentially of C1-C4; c) subsequently injecting steam and a second heavier hydrocarbon solvent instead of the first solvent into said injection well for a second longer period of time after the first period of time, said second solvent consisting essentially of C5-C12; and d) collecting a mobilized heavy oil and said first and second solvents from said production well; wherein said method improves recoveries of said first and second solvents as compared to a steam and light solvent co-injection alone or as compared to a steam and heavy solvent co-injection followed by a steam and light solvent co-injection.

2. The method of claim 1, wherein steps b) and c) are repeated two or more times.

3. The method of claim 1, wherein the first solvent is at least 90% C3-C4, and the second solvent is at least 90% C5-C9.

4. The method of claim 1, wherein the first solvent is at least 90% C3-C4, and the second solvent is at least 90% C5-C6.

5. The method of claim 1, wherein the first solvent is at least 66% C1-C4, and the second solvent is at least 95% C5-C12.

6. The method of claim 1, wherein the first solvent is at least 66% C4, and the second solvent is at least 80% C5.

7. The method of claim 1, wherein the first solvent includes methane, ethane, propane or butane or combinations thereof.

8. The method of claim 1, wherein the second solvent includes pentane, hexane, heptane or octane or combinations thereof.

9. The method of claim 1, wherein said first and second solvents comprise 10-30% liquid volume of the injected steam and first and second solvents.

10. The method of claim 1, wherein said first and second solvents comprise 25% liquid volume of the injected steam and first and second solvents.

11. The method of claim 1, wherein the first solvent is C4 and the first period is about 1 year, and the second solvent is C5 and the second period is about 3.5 years.

12. The method of claim 1, wherein the first solvent is about 66% C4 and the first period is about 1 year, and the second solvent is about 95% C5 and the second period is about 3.5 years.

13. The method of claim 1, wherein the injection and production wells have horizontal lengths that are in fluid communication.

14. A method of producing heavy oil, consisting essentially of: injecting steam and hydrocarbon solvent into an injection well and recovering produced hydrocarbons from a production well, wherein the steam is initially injected with a first hydrocarbon solvent for a first period of time, followed by injecting the steam with a second hydrocarbon solvent instead of the first solvent that is of higher molecular weight than said first solvent for a second longer period of time, wherein the first solvent is C1-C4 and the second solvent is C5-C12 and wherein said first and second solvents comprise 10-30% liquid volume of injected fluid, and wherein said method improves recoveries of said first and second solvents as compared to a steam and light solvent co-injection alone or as compared to steam and heavy solvent co-injection followed by steam and light solvent co-injection.

15. The method of claim 14, wherein the first solvent is at least 50% C1-C4 and the second solvent is at least 50% C5-C12.

16. The method of claim 14, wherein the first solvent is injected for about 0.5-1.5 years, and the second solvent is injected for greater than 3 years.

17. The method of claim 14, wherein said first and second solvents comprise 25% liquid volume of the injected liquid volume.

Description

BRIEF DESCRIPTION OF THE DRAWINGS

(1) FIG. 1 Cumulative Oil Production Comparisons. In FIG. 1 and FIG. 2 and as used herein, “C4−” signifies a mixture of C1-C4, and C5+ signifies a mixture of C5 and higher carbon number solvents.

(2) FIG. 2. Solvent Retention Characteristics.

DETAILED DESCRIPTION OF THE INVENTION

(3) Prior art ES-SAGD technology involved the co-injection of steam and solvent for the gravity assisted production of heavy oils. The art generally teaches that heavier solvents give earlier recovery and greater recovery efficiency in terms of less solvent loss, but lighter solvents give improvement of oil production over SAGD, but at higher solvent loss.

(4) Golvind concluded that butane was the optimum solvent for the Cold Lake type reservoir with no initial solution gas, and that the optimum butane concentration was around 10% by weight; higher amounts leading to only incremental oil recovery. Nasr, in contrast, concluded that hexanes or diluents that contain mostly higher carbon numbers than 6 were the most preferred hydrocarbon additives. Others suggested that a mixture of solvents co-injected at the same time would be best. Work still needs to be done to provide a cost effective injection strategy.

(5) In this work, we have surprisingly found that a two stage approach, e.g., butane followed by pentane, results in improved heavy oil mobility and better sweep of the reservoir. We theorize that a deep penetration is achieved with the lighter solvent, but that following with a heavier solvent more effectively allows heat transfer and solvent recovery by sweeping out and replacing the lighter solvent. Furthermore, we believe that repeated cycles of light followed by heavy solvents sweeps may allow even better recoveries.

(6) A 3D heterogeneous field scale numerical model, based on Athabasca reservoir and fluid properties, was used to examine strategies for reducing solvent retention in the reservoir. The commercial thermal reservoir simulator “STARS,” developed by Computer Modeling Group (CMG), was used in the numerical simulations described herein.

(7) The simulated reservoir was 132 m wide and 44 m thick. Two horizontal wells, 950 meters long and separated by 5 meters were used in the investigation. A pre-heat period was used by circulating steam in both wells for a period of time, similar to field pre-heat. Following the pre-heat, steam plus solvent (ES-SAGD) was injected into the top well at a pressure of 3500 kPa for 4.5 years. The solvent used was a mixture of different hydrocarbons at a fixed total solvent concentration of 25%, 75% steam (% liquid volumes used).

(8) Different compositions of solvent were evaluated during a simulated solvent injection period of 4.5 years. These compositions included: Injecting 66% C4− during the entire 4.5 year injection period. Injecting 66% C4− for 3 years followed by 95% C5+ for 1.5 years. Injecting 66% C4− for 1.5 years followed by 89% C5+ injected for 3 years. Injecting 66% C4− for 1 year followed by 95% C5+ injected for 3.5 years. Injecting 89% C5+ for 3 years followed by 66% C4− injected for 1.5 years.

(9) It was surprisingly found that ES-SAGD performance improved when a mixture of solvents containing 66% C4− (remainder C5+) was injected for 1 year followed by injection of solvent containing 95% C5+ (remainder C4−) for 3.5 years.

(10) FIG. 1 shows that decreasing the initial injection duration for a solvent containing 66% C4− from 4.5 years to 1 year, followed by a 3.5 year sweep with 95% C5+, resulted in a dramatic 15% improvement in oil production over the use of C4− alone (762,465 m.sup.3 versus 663,664 m.sup.3).

(11) In contrast, when 66% C4− was injected initially for 3 yrs followed by a 1.5 year 95% C5+ sweep, e.g., longer light solvent sweep, the oil production decreased from 762,465 m.sup.3 to 707,655 m.sup.3, although there was still an improvement over the use of C4− alone.

(12) Interestingly, the reverse—C5+ followed by C4− is also less effective than a short C4− sweep followed by a longer C5+ sweep.

(13) In addition, the solvent retention in the reservoir was reduced from 49% to 39% in FIG. 2 in the best case scenario, e.g., short light solvent sweep followed by longer heavy solvent sweep, although improvement was seen in all cases.

(14) The above simulations show the benefit of a two solvent steam injection approach wherein a lighter solvent is followed by a heavier solvent to improve recovery rates and minimize solvent losses. This work may next be validated in a physical model or other bench top experiment, before being implemented as test in situ.

(15) The following references are incorporated by reference in their entirety for all purposes.

(16) SPE129963: Akinboyawa, et al., Simulation of Expanding Solvent-Steam Assisted Gravity Drainage in a Field Case Study of a Bitumen Oil Reservoir (2010).

(17) Nasr, et al., Novel Expanding Solvent-SAGD Process “ES-SAGD,” J. Can. Petrol. Technol. 42(1): 13-16 (2003).

(18) U.S. Pat. Nos. 6,230,814; 6,591,908; 7,464,756

(19) SPE117571: Govind, P., et al., Expanding Solvent SAGD in Heavy Oil Reservoirs (2008).

(20) SPE133277: Li et al., Light- and Heavy-Solvent Impacts on Solvent-Aided-SAGD Process: A Low-Pressure Experimental Study (2011).

(21) SPE130802-PA: Li et al., Solvent-Type and -Ratio Impacts on Solvent-Aided SAGD Process (2011).