Method for improving oil sands hot water extraction process

Abstract

A method for increasing the bitumen extraction efficiency in the hot water oil sands extraction process. A volume of gaseous carbon dioxide is added into the oil sands slurry that is being transported through a hydrotransport pipeline from the oil sands mining site to the bitumen extraction plant at a position where the oil sands has been conditioned to a desired degree. Carbon dioxide is injected into the slurry under elevated pressure through a gas distribution device while the hydraulic pressure in the pipeline is maintained at an elevated pressure. After the carbon dioxide-bearing oil sands slurry is fed into the separation vessel, a part of the carbon dioxide is recovered for reinjection.

1 . A method for recovering bitumen comprising adding carbon dioxide to a pipeline containing an oil-bearing formation being transported. 
     
     
         2 . The method as claimed in  claim 1  wherein said oil-bearing formation is being transported to a processing plant. 
     
     
         3 . The method as claimed in  claim 1  wherein said oil-bearing formation is selected from the group consisting of an oil sands slurry, tar sands slurry and oil-contaminated soil slurry. 
     
     
         4 . The method as claimed in  claim 1  wherein the volumetric flow rate ratio of said carbon dioxide to process water in said pipeline is controlled from 0.2:1 to 15:1. 
     
     
         5 . The method as claimed in  claim 1  wherein the volumetric flow rate ratio of said carbon dioxide to process water in said pipeline is controlled from 0.5:1 to 10:1. 
     
     
         6 . The method as claimed in  claim 1  wherein said carbon dioxide injection pressure is maintained at a pressure from 1.2 bars to 21 bars. 
     
     
         7 . The method as claimed in  claim 1  wherein said carbon dioxide injection pressure is maintained at a pressure from 3 bars to 10 bars. 
     
     
         8 . The method as claimed in  claim 1  wherein the pressure in the pipeline behind the carbon dioxide injection point is maintained between 1.1 bars to 20 bars. 
     
     
         9 . The method as claimed in  claim 1  wherein the pressure in the pipeline behind the carbon dioxide injection point is maintained between 2 bars to 10 bars. 
     
     
         10 . The method as claimed in  claim 4  wherein the pressure is maintained by a boost pump. 
     
     
         11 . The method as claimed in  claim 3  wherein the pH of the oil sands slurry in the pipeline is adjusted to a level below 8. 
     
     
         12 . The method as claimed in  claim 11  wherein the pH of the oil sands slurry is adjusted by controlling the carbon dioxide flow rate. 
     
     
         13 . The method as claimed in  claim 11  wherein the pH is measured by a set of pH probes installed on the pipeline. 
     
     
         14 . The method as claimed in  claim 1  wherein said carbon dioxide is injected in the pipeline at a point where the oil-bearing formation has been conditioned to a degree higher than 50%. 
     
     
         15 . The method as claimed in  claim 1  wherein said carbon dioxide is injected in the pipeline at a point where the oil-bearing formation has been conditioned to a degree higher than 80%. 
     
     
         16 . The method as claimed in  claim 1  wherein the length of said pipeline is from 1 meter to 2 kilometers. 
     
     
         17 . The method as claimed in  claim 16  wherein the length of said pipeline is from 100 meters to 1 kilometer. 
     
     
         18 . The method as claimed in  claim 1  wherein the oil-bearing formation flow is merged with a fresh water stream before it is fed to a separation vessel and the volumetric flow rate ratio of the fresh water to oil-bearing formation is from 0:1 to 3:1. 
     
     
         19 . The method as claimed in  claim 18  wherein the volumetric flow rate ratio of the fresh water to oil-bearing formation is from 0.1:1 to 1:1. 
     
     
         20 . The method as claimed in  claim 1  wherein said carbon dioxide is directly injected into said oil-bearing formation through a device selected from the group consisting of nozzles and a venturi device. 
     
     
         21 . The method as claimed in  claim 18  wherein the temperature of the water is from 20° C. to 120° C. 
     
     
         22 . The method as claimed in  claim 1  wherein the carbon dioxide-bearing oil-bearing formation is fed into said separation vessel through a device selected from the group consisting of a nozzle and pressure reducing. 
     
     
         23 . The method as claimed in  claim 22  wherein said separation vessel is operated under ambient pressure. 
     
     
         24 . The method as claimed in  claim 23  wherein said separation vessel is operated at a pressure lower than the pressure in said hydrotransport pipeline. 
     
     
         25 . The method as claimed in  claim 22  wherein gaseous carbon dioxide in the separation vessel is recycled through a carbon dioxide recovery pipeline to a carbon dioxide storage tank. 
     
     
         26 . The method as claimed in  claim 22  wherein gaseous carbon dioxide in the separation vessel is recycled through a carbon dioxide recovery pipeline and directly injected in a separate pipeline in parallel operation. 
     
     
         27 . The method as claimed in  claim 26  wherein the impurity concentration in said recycled carbon dioxide is lower than 20%. 
     
     
         28 . The method as claimed in  claim 18  wherein water is recycled from the separation vessel and is aerated by a gas selected from the group consisting of air, nitrogen, methane, carbon monoxide and argon. 
     
     
         29 . The method as claimed in  claim 28  wherein the recycled water from the separation vessel is heated to a higher temperature by injection of steam or other heating methods before reuse. 
     
     
         30 . The method as claimed in  claim 1  wherein carbon dioxide is mixed with a water stream before being injected in the pipeline. 
     
     
         31 . The method as claimed in  claim 30  wherein the volumetric flow rate ratio of said carbon dioxide to said water is from 1:0 to 20:1. 
     
     
         32 . The method as claimed in  claim 31  wherein the temperature of the water is from 1° C. to 100° C. 
     
     
         33 . The method as claimed in  claim 1  wherein carbon dioxide is injected in the pipeline at several points. 
     
     
         34 . The method as claimed in  claim 33  wherein the distance between two adjacent injection points is from 1 meter to 500 meters. 
     
     
         35 . The method as claimed in  claim 33  wherein the number of said injection points is from 2 to 20. 
     
     
         36 . The method as claimed in  claim 33  wherein the injection rates of carbon dioxide will be the same or different at said several points. 
     
     
         37 . The method as claimed in  claim 30  wherein the volumetric flow rate ratio of the carbon dioxide to the water in the oil-bearing formation is from 0.2:1 to 15:1. 
     
     
         38 . The method as claimed in  claim 37  wherein the volumetric flow rate ratio of the carbon dioxide to the water in the oil-bearing formation is from 0.5:1 to 10:1.