Method of Enhancing the Effectiveness of a Cyclic Solvent Injection Process to Recover Hydrocarbons

Abstract

Described is a method of operating a cyclic solvent-dominated recovery process (CSDRP) for recovering viscous oil from a subterranean reservoir of the viscous oil to enhance recovery effectiveness. 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. Conventionally, the solvent composition remains constant over time within each injection cycle and among cycles. In the present method, by contrast, the solvent composition is varied over time thereby providing operational benefits as described herein.

1 . A method of enhancing the effectiveness of a cyclic solvent injection and production process to aid recovery of in situ 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 in situ 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 a 50 mass % vaporization temperature at 1 atm of a total composition of solvent injected over a first period, is at least 10° C. higher than a 50 mass % vaporization temperature at 1 atm of a total composition of solvent injected over a subsequent period. 
     
     
         2 . The method of  claim 1 , wherein the first and subsequent periods are one of (i) separate cycles, (ii) within the same cycle and (iii) separate and non-overlapping sets of cycles, wherein each set of cycles consists of consecutive cycles and comprises at least two cycles. 
     
     
         3 .- 4 . (canceled) 
     
     
         5 . The method of  claim 1 , wherein the subsequent period comprises a final cycle. 
     
     
         6 . The method of  claim 1 , wherein the sets of cycles comprises at least 3 cycles. 
     
     
         7 . The method of  claim 1 , wherein the 50 mass % vaporization temperature at 1 atm of the total composition of solvent injected over the first period, is one of (i) at least 20° C. higher than a 50 mass % vaporization temperature at 1 atm of the total composition of solvent injected over the subsequent period and (ii) at least 50° C. higher than a 50 mass % vaporization temperature at 1 atm of the total composition of solvent injected over the subsequent period. 
     
     
         8 . (canceled) 
     
     
         9 . The method of  claim 1 , wherein the solvent injected over the first period one of (i) is more miscible with the in situ hydrocarbons than is the solvent injected over the subsequent period, in the underground reservoir, (ii) has a lower asphaltene precipitation rate in the in situ hydrocarbons than the solvent injected over the subsequent period, when mixed with the in situ hydrocarbons at an equivalent volumetric ratio at initial reservoir conditions, (iii) has a higher aromatic content than the solvent injected over the subsequent period, and (iv) has a lower viscosity than the solvent injected over the subsequent period. 
     
     
         10 .- 12 . (canceled) 
     
     
         13 . The method of  claim 1 , wherein at least 90 mass % of the solvent injected over one of (i) the subsequent period is in a gaseous phase at reservoir conditions and (ii) the first period is in a liquid phase at reservoir conditions. 
     
     
         14 . The method of  claim 13 , wherein the solvent injected over the subsequent period comprises one of (i) ethane, propane, butane, CO 2 , natural gas, or a combination thereof and (ii) SO 2 , another non-condensable gas, another inert gas, or a combination thereof. 
     
     
         15 .- 16 . (canceled) 
     
     
         17 . The method of claim  16 , wherein the solvent injected over the first period comprises an aromatic hydrocarbon, diesel, diluent, a ketone, a synthetic crude oil, a heavy vacuum gas oil, or a combination thereof. 
     
     
         18 . The method of  claim 1 , wherein the solvent injected over the first period is at least 75% soluble with the in situ hydrocarbons in the underground reservoir at initial reservoir pressure and temperature. 
     
     
         19 . The method of  claim 1 , wherein one of (i) the solvent injected over the first period is completely miscible with the in situ hydrocarbons in the underground reservoir and (ii) the solvent injected over the first period is completely miscible with the in situ hydrocarbons in the underground reservoir and the total composition of solvent injected over the subsequent period forms two liquid phases when mixed with in situ hydrocarbons in at least one ratio. 
     
     
         20 . (canceled) 
     
     
         21 . The method of  claim 1 , further comprising periodically injecting a periodic solvent, wherein a 50 mass % vaporization temperature at 1 atm of a total composition of periodic solvent injected over a periodic period, is at least 50° C. higher than a 50 mass vaporization temperature at 1 atm of a total composition of solvent injected over an immediately preceding and an immediately subsequent solvent injection period, for limiting formation of a second liquid hydrocarbon phase. 
     
     
         22 . The method of  claim 1 , further comprising using second and third injection periods between the first and subsequent injection periods,
 wherein a 50 mass % vaporization temperature at 1 atm of a total composition of solvent injected over the first period, is at least 10° C. higher than a 50 mass % vaporization temperature at 1 atm of a total composition of solvent injected over the second period,   wherein a 50 mass % vaporization temperature at 1 atm of a total composition of solvent injected over the second period, is at least 10° C. higher than a 50 mass % vaporization temperature at 1 atm of a total composition of solvent injected over the third period, and   wherein a 50 mass % vaporization temperature at 1 atm of a total composition of solvent injected over the third period, is at least 10° C. higher than a 50 mass % vaporization temperature at 1 atm of a total composition of solvent injected over the subsequent period.   
     
     
         23 . The method of  claim 22 , wherein the solvent injected over the first period comprises at least 50 mass % of an aromatic hydrocarbon, diesel, diluent, a ketone, a synthetic crude oil, a heavy vacuum gas oil, or a combination thereof;
 the solvent injected over the second period comprises at least 50 mass % of a C 5  to C 7  hydrocarbon, or a combination thereof;   the solvent injected over the third period comprises at least 50 mass % ethane, propane, butane, or a combination thereof; and   the solvent injected over the subsequent cycle comprises at least 50 mass % CO 2 , N 2 , SO 2 , another non-condensable gas, another inert gas, or a combination thereof.   
     
     
         24 . The method of  claim 1 , wherein the solvent comprises a blend of at least two solvent components, the ratio of which is changed between the first and subsequent periods to achieve the difference in the 50 mass % vaporization temperature between the first and subsequent cycles. 
     
     
         25 . The method of  claim 24 , wherein the blend comprises
 a) a polar component, the polar component being a compound comprising a non-terminal carbonyl group; and   b) a non-polar component, the non-polar component being a substantially aliphatic substantially non-halogenated alkane.   
     
     
         26 . The method of  claim 24 , wherein one of the polar component comprises a ketone and the non-polar component comprises a C 2 -C 7  alkane. 
     
     
         27 . (canceled) 
     
     
         28 . The method of  claim 25 , wherein the polar component comprises acetone and the non-polar component comprises propane. 
     
     
         29 . The method of  claim 1 , wherein the injection well and the production well utilize a common wellbore. 
     
     
         30 . The method of  claim 1 , wherein the in situ hydrocarbons are a viscous oil having a viscosity of at least 10 cP at initial reservoir conditions. 
     
     
         31 . The method of  claim 1 , wherein the injected fluid comprises diesel, viscous oil, natural gas, bitumen, diluent, C 5+  hydrocarbons, ketones, alcohols, non-condensable gas, water, biodegradable solid particles, salt, water soluble solid particles, solvent soluble solid particles, a viscous polymer solution, or a combination thereof. 
     
     
         32 . The method of  claim 1 , wherein the injected fluid is heated such that it is injected into the underground reservoir at a temperature greater than 20° C. 
     
     
         33 . The method of  claim 1 , wherein at least 25 mass % of the solvent one of in an injection cycle enters the reservoir as a liquid and at the end of an injection cycle is a liquid. 
     
     
         34 . (canceled) 
     
     
         35 . The method of  claim 1 , wherein an in situ volume of fluid injected over a cycle 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 fluid. 
     
     
         36 . The method of  claim 35 , wherein the additional in situ volume of fluid is, at reservoir conditions, equal to 2% to 15% of a pore volume within the reservoir zone around the injection well within which solvent fingers are expected to travel during the cycle. 
     
     
         37 . The method of  claim 1 , wherein the method comprises:
 a first injection stage, wherein the solvent comprises a primary lighter solvent and a secondary heavier solvent; the proportion of which is selected based on the additional cost of the secondary heavier solvent versus the cost benefit realized by decreased flow impairment caused by the formation of a second liquid hydrocarbon phase resulting from the injection of the primary lighter solvent, to optimize economic recovery of the in situ hydrocarbons; wherein the primary solvent has a 50 mass % vaporization temperature at 1 atm of at least 20° C. lower than a 50 mass % vaporization temperature at 1 atm of the secondary solvent;   a second injection stage, wherein the relative proportion of the primary lighter solvent is increased to account for the reduction in flow impairment caused by a second liquid hydrocarbon phase, resulting from increased reservoir voidage due to reservoir depletion;   during the second injection stage, periodically injecting the secondary heavier solvent for limiting formation of a second liquid hydrocarbon phase; and   a third injection stage, where the primary lighter solvent is injected to allow a second liquid hydrocarbon phase to form, for limiting adverse effects of well to well communication or reservoir thief zones, or both.