Operating Wells In Groups In Solvent-Dominated Recovery Processes

Abstract

To recover oil, including viscous oil, from an underground reservoir, a cyclic solvent-dominated recovery process may be used. A viscosity reducing solvent is injected, and oil and solvent are produced. Unlike steam-dominated recovery processes, solvent-dominated recovery processes cause viscous fingering which should be controlled. To control viscous fingering, operational synchronization is used within groups and not between adjacent groups.

1 . A method of operating a cyclic solvent-dominated process for recovering hydrocarbons from an underground reservoir through a set of wells divided into groups of wells, the method comprising:
 (a) initiating and subsequently halting injection, into one of the groups of wells, of an amount of a viscosity reducing solvent;   (b) initiating and subsequently halting production, from the one of the groups of wells, of at least a fraction of the solvent and the hydrocarbons from the reservoir, and   (c) cyclically repeating steps (a) and (b) for the groups of wells;   wherein:
 each of the groups comprises two or more wells and no well is common between two groups; and 
 wells of the same group are operated substantially in-synch. 
   
     
     
         2 . The method of  claim 1  wherein the wells of the same group undergo opposite flow operation of injection or production for less than 10% of fluid flow on a mass basis. 
     
     
         3 . The method of  claim 2  wherein the wells of the same group undergo opposite flow operation of injection or production for less than 5% of fluid flow on a mass basis. 
     
     
         4 . The method of  claim 3  wherein the wells of the same group undergo opposite flow operation of injection or production for less than 1% of fluid flow on a mass basis. 
     
     
         5 . The method of  claim 4  wherein for at least 80% of fluid flow on a mass basis a single well of at least one group undergoes injection and production while remaining wells within the at least one group are idle. 
     
     
         6 . The method  claim 1  wherein a single well of at least one of group undergoes injection and production while remaining wells within the at least one group are idle. 
     
     
         7 . The method of  claim 1  wherein the wells of the same group undergo the same flow operation of injection or production for more than 80% of fluid flow on a mass basis. 
     
     
         8 . The method of  claim 1  wherein the wells of the same group undergo the same flow operation of injection or production for more than 90% of fluid flow on a mass basis. 
     
     
         9 . The method of  claim 1  wherein the wells of the same group undergo the same flow operation of injection or production for more than 95% of fluid flow on a mass basis. 
     
     
         10 . The method of  claim 1  wherein more than 80% of the wells of the same group undergo the same flow operation of injection or production for more than 80% of an operational time period. 
     
     
         11 . The method of  claim 1  wherein all wells of the same group undergo the same flow operation of injection or production for more than 80% of an operational time period. 
     
     
         12 . The method of  claim 1  wherein adjacent well groups are operated substantially out-of-synch. 
     
     
         13 . The method of  claim 1  wherein wells of adjacent well groups undergo opposite flow operation of injection or production for more than 10% of fluid flow on a mass basis. 
     
     
         14 . The method of  claim 1  wherein wells of adjacent well groups undergo opposite flow operation of injection or production for more than 25% of fluid flow on a mass basis. 
     
     
         15 . The method of  claim 1  wherein wells of adjacent well groups undergo opposite flow operation of injection or production for more than 50% of fluid flow on a mass basis. 
     
     
         16 . The method of  claim 1  wherein wells of adjacent well groups undergo opposite flow operation of injection or production for more than 75% of fluid flow on a mass basis. 
     
     
         17 . The method of  claim 1  wherein wells of adjacent well groups undergo opposite flow operation of injection or production for more than 90% of fluid flow on a mass basis. 
     
     
         18 . The method of  claim 1  wherein immediately after halting injection of the solvent, at least 25 mass % of the injected solvent is in a liquid state in the reservoir. 
     
     
         19 . The method of  claim 1  wherein at least 25 mass % of the solvent in step (a) enters the reservoir as a liquid. 
     
     
         20 . The method of  claim 1  wherein at least 50 mass % of the solvent in step (a) enters the reservoir as a liquid. 
     
     
         21 . The method of  claim 1  wherein each well within the set of wells is oriented within 30° of horizontal within the underground reservoir. 
     
     
         22 . The method of  claim 1  wherein, within the underground reservoir, the wells in the set are arranged within 20° of a common horizontal straight line. 
     
     
         23 . The method of  claim 22  wherein the single common straight line is within 20° of a maximum horizontal stress direction within the reservoir. 
     
     
         24 . The method of  claim 1  wherein for at least 25% of the time period between injecting and subsequently halting injection for a group of wells, an adjacent group of wells has at least one well producing; and for at least 25% of the time period between producing and subsequently halting producing for a group of wells, an adjacent group of wells has at least one well injecting. 
     
     
         25 . The method of  claim 1  wherein for at least 50% of the time period between injecting and subsequently halting injection for a group of wells, an adjacent group of wells has at least one well producing; and for at least 50% of the time period between producing and subsequently halting producing for a group of wells, an adjacent group of wells has at least one well injecting. 
     
     
         26 . The method of  claim 1  wherein the well groups are separated by buffer zones for limiting well-to-well interaction, wherein buffer zones contain no flowing wells. 
     
     
         27 . The method of  claim 26  wherein the buffer zones constitute no more than one third of a sum of an area of the groups. 
     
     
         28 . The method of  claim 26  wherein the buffer zones constitute no more than 10% of a sum of an area of the groups. 
     
     
         29 . The method of  claim 1  wherein two wells are separated by an infill well used for increasing hydrocarbon production prior to and/or during operation. 
     
     
         30 . The method of  claim 1  wherein two wells are separated by an infill well for increasing reservoir pressure prior to and/or during operation, for limiting well-to-well interaction. 
     
     
         31 . The method of  claim 29  wherein water is injected into the infill well. 
     
     
         32 . The method of  claim 26  wherein at least certain buffer zones are geological buffer zones. 
     
     
         33 . The method of  claim 32  wherein the geological buffer zones are channel boundaries. 
     
     
         34 . The method of  claim 1  wherein each group comprises a single row of wells. 
     
     
         35 . The method of  claim 1  wherein the hydrocarbons are a viscous oil having an in situ viscosity of greater than 10 cP at initial reservoir conditions. 
     
     
         36 . The method of  claim 1  wherein a common wellbore is used for both the injection and the production. 
     
     
         37 . The method of  claim 1  wherein an idle period exists subsequent to halting injection and prior to initiating production. 
     
     
         38 . The method of  claim 1  wherein the solvent comprises ethane, propane, butane, pentane, carbon dioxide, or a combination thereof. 
     
     
         39 . The method of  claim 1  wherein the solvent comprises greater than 50 mass % propane.