Enhanced hydrocarbon recovery through gas production control for noncondensable solvents or gases in sagd or es-sagd operations

Abstract

Methods are provided for enhancing hydrocarbon recovery through gas production control for noncondensable gases in SAGD or ES-SAGD operations. Steam may be injected into one or more injection wells to heat the hydrocarbons and reduce their viscosity to more easily produce the hydrocarbons. A noncondensable gas may be injected into the injection wells to beneficially reduce the steam-to-oil ratio, improving economic recovery. Unfortunately, excessive production of noncondensable gases can adversely suppress hydrocarbon production rates. To counteract this problem, gas production rates at the production wells may be controlled to optimize hydrocarbon output by limiting the produced gas-to-water ratio to certain limited ranges. The noncondensable gas may optionally comprise a combustion gas such as flue gas. By providing a useful application of existing combustion gases, green house gases emissions may be reduced. Advantages include higher efficiencies, lower costs, reduced hydrocarbon extraction time, and in some embodiments, reduced greenhouse gas emissions.

1 . A method for enhancing recovery of bitumen or heavy oil from a low mobility reservoir comprising the steps of:
 providing one or more injection wells wherein the one or more injection wells intersect the heavy oil reservoir;   providing one or more production wells wherein the one or more production wells intersect the heavy oil reservoir;   wherein the one or more injection wells and the one or more production wells are paired to form a SAGD or ES-SAGD process;   producing steam via a steam generator wherein flue gas is produced as a byproduct of the steam generator;   introducing the steam into one of the one or more injection wells;   introducing the flue gas into one of the one or more injection wells;   allowing a production flow to be produced from the one or more production wells wherein the production flow comprises a production gas flow and a production water flow;   determining a production gas-to-water ratio as a ratio of the production gas flow to the production water flow; and   limiting the production flow to obtain a production gas-to-water ratio in the production flow from about 1 to about 30.   
     
     
         2 . The method of  claim 1  wherein the step of introducing steam comprises the step of continuously introducing the steam into one of the one or more injection wells and wherein the step of introducing the flue gas comprises the step of continuously introducing the flue gas into one of the one or more injection wells. 
     
     
         3 . The method of  claim 1  wherein the step of introducing steam comprises the step of intermittently introducing the steam into one of the one or more injection wells and wherein the step of introducing the non-condensable gas comprises the step of intermittently introducing the non-condensable gas into one of the one or more injection wells. 
     
     
         4 . The method of  claim 1  wherein the steam and the non-condensable gas are combined into a single stream for injection into the one or more injection wells. 
     
     
         5 . The method of  claim 2  wherein the steam and the non-condensable gas are combined into a single stream for injection into the one or more injection wells. 
     
     
         6 . The method of  claim 1  wherein the production gas-to-water ratio is about 1 to about 10. 
     
     
         7 . The method of  claim 1  wherein the production gas-to-water ratio is about 1 to about 5. 
     
     
         8 . The method of  claim 1  wherein the production gas-to-water ratio is about 5 to about 10. 
     
     
         9 . A method for enhancing recovery of bitumen or heavy oil from a low mobility reservoir comprising the steps of:
 providing an injection well wherein the injection well extends into the heavy oil reservoir via an upper horizontal well;   providing a production well wherein the production well extends into the heavy oil reservoir via a lower horizontal well;   continuously introducing steam and a non-condensable gas into the injection well;   allowing a production flow to be produced from the production well wherein the production flow comprises a gas flow and a water flow;   determining a production gas-to-water ratio as a ratio of the production gas flow to the production water flow; and   limiting the production flow to obtain a production gas-to-water ratio from about 1 to about 10.   
     
     
         10 . The method of  claim 9  wherein the injection well and the production well are paired to form a SAGD or ES-SAGD process. 
     
     
         11 . The method of  claim 9  wherein the non-condensable gas is butane. 
     
     
         12 . The method of  claim 9  wherein the non-condensable gas is methane, ethane, propane, butane, air, oxygen, nitrogen, hydrogen, carbon dioxide, carbon monoxide, combustion gases from a control device or other direct combustion device, combustion gases from a direct steam generator, flue gas, or any combination thereof. 
     
     
         13 . The method of  claim 9  further comprising the step of providing a direct steam generator wherein the direct steam generator produces a combined output stream of steam and flue gas, wherein the non-condensable gas is the flue gas from the direct steam generator. 
     
     
         14 . The method of  claim 13  wherein the production gas-to-water ratio is about 1 to about 10. 
     
     
         15 . The method of  claim 13  wherein the production gas-to-water ratio is about 1 to about 5. 
     
     
         16 . The method of  claim 13  wherein the production gas-to-water ratio is about 5 to about 10. 
     
     
         17 . The method of  claim 13  wherein the step of continuously introducing steam and a non-condensable gas into the injection well further comprises the step of continuously introducing steam and a non-condensable gas into the injection well to form an injection flow that comprises an injection gas flow and an injection water flow, wherein the method further comprises the step of determining an injection gas-to-water ratio as a ratio of the injection gas flow to the injection water flow, wherein the injection gas-to-water ratio is from about 50 to about 100. 
     
     
         18 . The method of  claim 13  further comprising the step of introducing a solvent into the injection well. 
     
     
         19 . The method of  claim 17  wherein the solvent comprises hexane. 
     
     
         20 . The method of  claim 17  wherein the solvent is carbon dioxide, an aliphatic hydrocarbon having 4 carbons to 30 carbons, naptha, syncrude, diesel, an aromatic solvent, toluene, benzene, xylene, or any combination thereof. 
     
     
         21 . The method of  claim 20  wherein the solvent is a light non-condensable hydrocarbon solvent having one to four carbons. 
     
     
         22 . The method of  claim 10  further comprising:
 providing a direct steam generator wherein the direct steam generator produces a combined output stream of steam and flue gas, wherein the non-condensable gas is the flue gas from the direct steam generator; 
 wherein the non-condensable gas is methane, ethane, propane, butane, air, oxygen, nitrogen, hydrogen, carbon dioxide, carbon monoxide, combustion gases from a control device or other direct combustion device, combustion gases from a direct steam generator, flue gas, or any combination thereof; 
 wherein the production gas-to-water ratio is about 1 to about 5; and 
 introducing a solvent into the injection well; and 
 wherein the solvent is carbon dioxide, an aliphatic hydrocarbon having 4 carbons to 30 carbons, naptha, syncrude, diesel, an aromatic solvent, toluene, benzene, xylene, or any combination thereof.