Method of Controlling Solvent Injection To Aid Recovery of Hydrocarbons From An Underground Reservoir

Abstract

A method of operating a cyclic solvent-dominated recovery process (CSDRP) for recovering viscous oil from a subterranean reservoir of the viscous oil. The cyclic solvent process involves using an injection well to inject a viscosity-reducing solvent into a subterranean viscous oil reservoir. Reduced viscosity oil is produced to the surface using the same well used to inject solvent. The process of alternately injecting solvent and producing a solvent/viscous oil blend through the same wellbore continues in a series of cycles until additional cycles are no longer economical. Aspects of the invention relate to the particular volume of solvent injected in each cycle, when to switch from production to injection, the injection pressure to be used, the production pressure to be used, and to middle and late life operation.

1 . A method of controlling a cyclic solvent injection and production process to aid recovery of hydrocarbons from an underground reservoir, the method comprising:
 (a) injecting a volume of fluid comprising greater than 50 mass % of a viscosity-reducing solvent into an injection well completed in the reservoir;   (b) halting injection into the injection well and subsequently producing at least a fraction of the injected fluid and the hydrocarbons from the reservoir through a production well;   (c) halting production through the production well; and   (d) subsequently repeating the cycle of steps (a) to (c);   wherein, in at least one subsequent cycle, an in situ volume of fluid injected in step (a) is equal to a net in situ volume of fluids produced from the production well in an immediately preceding cycle plus an additional in situ volume of the fluid.   
     
     
         2 . The method of  claim 1  wherein immediately after halting injection into the injection well, at least 25 mass % of the injected solvent is in a liquid state in the reservoir. 
     
     
         3 . The method of  claim 1  wherein at least 25 mass % of the solvent in step (a) enters the reservoir as a liquid. 
     
     
         4 . The method of  claim 1  wherein at least 50 mass % of the solvent in step (a) enters the reservoir as a liquid. 
     
     
         5 . The method of  claim 1  wherein the fluid of step (a) comprises greater than 75 mass % of the viscosity-reducing solvent. 
     
     
         6 . The method of  claim 1  wherein the additional in situ volume of fluid in any one of the at least one subsequent cycle varies by no more than 25 vol. % from an in situ volume of any other of the at least one subsequent cycle. 
     
     
         7 . The method of  claim 1  wherein, in the at least one subsequent cycle, the in situ volume of fluid injected in step (a) is equal to a net in situ volume of fluids produced from the production well summed over all preceding cycles plus an additional in situ volume of the fluid. 
     
     
         8 . The method of  claim 1  wherein the method is operated using a plurality wells, each undergoing the cycles of injection and production according to substantially the same schedule. 
     
     
         9 . The method of  claim 1  wherein the injection well and the production well utilize a common wellbore. 
     
     
         10 . The method of  claim 1  wherein an idle period exists subsequent to halting injection and prior to initiating production. 
     
     
         11 . The method of  claim 1  wherein the hydrocarbons are a viscous oil having a viscosity of at least 10 cP at initial reservoir conditions. 
     
     
         12 . The method of  claim 1  wherein the net in situ volume of fluids produced from the production well in the immediately preceding cycle is determined by:
 (i) separating produced fluids into one or more aqueous fractions, non-solvent liquid hydrocarbon fractions, injected solvent fractions, injected non-solvent fractions; and then, 
 (ii) approximating the net in situ volume of fluids produced as the total volume of aqueous and non-solvent liquid hydrocarbon fractions produced minus the net injected solvent and injected non-solvent fractions produced. 
 
     
     
         13 . The method of  claim 12  wherein the approximated non-solvent liquid hydrocarbon fractions produced includes an adjustment for in situ pressure and temperature conditions, and an account of the produced gas fractions. 
     
     
         14 . The method of  claim 1  wherein the net in situ volume of fluids produced from the production well in the immediately preceding cycle is determined by:
 (i) injecting the volume of fluid into the injection well until an estimated bottomhole pressure reaches a threshold pressure. 
 
     
     
         15 . The method of  claim 1  wherein the additional in situ volume of fluid is injected by continuing injection for a predetermined period of time after an estimated bottomhole pressure reaches a threshold pressure. 
     
     
         16 . The method of  claims 1  wherein the additional in situ volume of fluid is injected by continuing injection of a predetermined volume of fluid after an estimated bottomhole pressure reaches a threshold pressure. 
     
     
         17 . The method of  claim 1  wherein the additional in situ volume of fluid is, at reservoir conditions, equal to 2% to 15% of a pore volume within the reservoir within a zone around the injection well within which solvent fingers are expected to travel during the cycle, wherein the reservoir conditions comprise a maximum in situ pressure expected during injection. 
     
     
         18 . The method of  claim 1  wherein the additional volume of solvent is, at reservoir conditions, equal to 3% to 8% of a pore volume within the reservoir within a zone around the injection well within which solvent fingers are expected to travel during the cycle, wherein the reservoir conditions comprise a maximum in situ pressure expected during injection. 
     
     
         19 . The method of  claim 17  wherein the zone around the injection well within which solvent fingers are expected to travel is defined by a repeating well pattern area. 
     
     
         20 . The method of  claim 14  wherein the threshold pressure is between 90 and 100% of a reservoir minimum in situ stress. 
     
     
         21 . The method of  claim 1  wherein the solvent comprises, ethane, propane, butane, pentane, carbon dioxide, or a combination thereof. 
     
     
         22 . The method of  claim 1  wherein the solvent comprises greater than 50 mass % propane. 
     
     
         23 . The method of  claim 17  wherein the zone around the injection well within which solvent fingers are expected to travel is defined by midpoints between the injection well and adjacent injection wells. 
     
     
         24 . The method of  claim 1  wherein production of the injected fluid and the hydrocarbons from the reservoir is halted and injection of the fluid into the reservoir is initiated, to begin a new cycle, when gas production exceeds a specified value. 
     
     
         25 . The method of  24  wherein the specified value is a flowing volume fraction of a vapor phase at bottomhole conditions of at least 0.1 or a Gas-to-Oil Ratio of at least 1000 scf/stb. 
     
     
         26 . The method of  claim 1  wherein production of the injected fluid and the hydrocarbons from the reservoir in a cycle is halted and injection of the fluid into the reservoir is initiated, to begin a new cycle, when a rate of oil production from the reservoir drops below a threshold percentage of an average rate of oil production during the cycle. 
     
     
         27 . The method of  claim 26  wherein the percentage of the rate of oil production from the reservoir to the average rate of oil production during the cycle is estimated using reservoir simulation and production data obtained in previous cycles. 
     
     
         28 . The method of  claim 26  wherein the threshold percentage is between 60% and 90%. 
     
     
         29 . The method of  claim 1  wherein the injected fluid further comprises diesel, viscous oil, bitumen, or diluent, to provide flow assurance. 
     
     
         30 . The method  claims 1  wherein the injected fluid further comprises CO 2 , natural gas, C 30+  hydrocarbons, ketones, or alcohols. 
     
     
         31 . The method of  claim 1  further comprising:
 measuring a rate of production of step (c); and 
 decreasing a producing pressure if the measured production rate is less than a maximum production rate, and a producing pressure is greater than a minimum threshold pressure. 
 
     
     
         32 . The method of  claim 1  wherein the pressure in the reservoir in step (c) is maintained above a liquid/vapor phase change pressure of the solvent in at least one cycle. 
     
     
         33 . The method of  claim 1  wherein the pressure in the reservoir in step (c) is maintained above a liquid/vapor phase change pressure of the solvent. 
     
     
         34 . The method of  claim 1  wherein the fluid is injected at an injection pressure in the underground reservoir, in the first cycle, at 95-100% of the fracture pressure of the reservoir, and in subsequent cycles, the fluid is injected at an injection pressure in the underground reservoir below the fracture pressure of the reservoir and below the injection pressure of the first cycle. 
     
     
         35 . The method of  claim 1  wherein the fluid is injected at an injection pressure in the underground reservoir, in initial cycles, at 95-100% of the fracture pressure of the reservoir, and in subsequent cycles, the fluid is injected at an injection pressure in the underground reservoir below the fracture pressure of the reservoir and below the injection pressure of the initial cycles. 
     
     
         36 . The method of  claim 1  further comprising:
 (e) operating a well as an injection well, and operating at least one additional well as a production well, to operate a solvent flood between or among the wells, when: 
 the well establishes pressure communication with the at least one additional well, or when 
 an oil-to-injected-solvent ratio drops below a specified threshold; or when 
 an amount of oil being produced drops below a specified threshold. 
 
     
     
         37 . The method of  claim 36  wherein, in step (e), solvent is injected at a pressure above a liquid/vapor phase change pressure. 
     
     
         38 . The method of  claim 36  wherein, during the solvent flood, the roles of the injection well and the production well are reversed to improve sweep of the oil. 
     
     
         39 . The method of  claim 36  further comprising periodically shutting-in the production well of step (e) to increase pressure in the reservoir above a reservoir dilation pressure. 
     
     
         40 . The method of  claim 36  wherein the specified threshold oil-to-injected-solvent ratio is at least 0.15. 
     
     
         41 . The method of  claim 36  wherein the specified threshold amount of oil being produced is 10 bbl/day. 
     
     
         42 . The method of  claim 1  wherein the fluid injection comprises a period of deliberate oscillation between a relatively higher injection rate and a relatively lower injection rate in order to assist solvent conformance.