Process for sequestration of fluids in geological formations

Abstract

A process for geo-sequestration of a water-soluble fluid includes selecting a target water-laden geological formation bounded by an upper formation of low permeability, providing an injection well into the formation and injecting the fluid into the injection well under conditions of temperature, pressure and density contrast selected to cause the fluid to enter the formation and rise within the formation. This generates a dynamic density-driven convection current of formation water which promotes enhanced mixing of the water-soluble fluid with formation water.

1 . A process for sequestration of a water-soluble fluid within a subsurface water-laden formation, the process comprising:
 selecting a target water-laden geological formation;   providing a fluid injection well into the formation, the injection well comprising at least one opening to discharge the fluid into the formation;   providing a source of the fluid, the source in communication with the injection well; and   injecting the fluid into the formation from the injection well at an injection pressure which is between 0% and 25% below a natural fracture extension pressure of the formation whereby the fluid rises within the formation in a plume of undissolved fluid with sufficient volume, flow rate, and density contrast between the fluid and water within the formation to induce a dynamic density contrast-driven convection cell within the formation.   
     
     
         2 . The process of  claim 1 , wherein the fluid injection well comprises multiple ones of the fluid injection well and/or multiple ones of the openings. 
     
     
         3 . The process of  claim 1 , wherein the injection pressure is within a range which is 3-20%, 3-15%, 3-10%, 3-5%, 5-20%, 5-15% or 5-10% below the natural fracture extension pressure of the formation. 
     
     
         4 . The process of  claim 1 , wherein the injection pressure is maintained for a duration which is the entirety of the process or for a selected portion thereof which consists of at least 50%, 60%, 70%, 80% or 90% of the duration of the process. 
     
     
         5 . The process of  claim 1 , further comprising heating the fluid prior to injection to a level which exceeds a temperature within the formation at the well opening. 
     
     
         6 . The process of  claim 1 , wherein the formation has a vertical dimension of at least 15, 20, 25, 30, 35 or 40 meters above the opening. 
     
     
         7 . The process of  claim 1 , wherein the formation has a horizontal dimension of at least 500, 700, 900 or 1000 meters. 
     
     
         8 . The process of  claim 1 , wherein the injecting increases the rate of diffusive mass transfer or dissolution of the fluid into the water and flushes additional water substantially laterally into a region of the injection well, thereby increasing storage capacity and storage rate of the fluid in the formation. 
     
     
         9 . The process of  claim 1 , wherein the fluid comprises at least one water-soluble gas and at least one water-insoluble gas, the process further comprising:
 providing a withdrawal well in the formation; and   withdrawing the water-insoluble gas from the formation through the withdrawal well, thereby providing additional volume in the formation for further sequestration of the water-soluble gas.   
     
     
         10 . The process of  claim 9 , comprising the further step of passing the water-insoluble gas through a gas turbine after withdrawal thereof from the formation to generate electricity. 
     
     
         11 . The process of  claim 1 , further comprising:
 providing at least one water injection well into the formation; and   injecting water into the formation to produce a cross current of unsaturated water within the formation from a region remote from the injection well and to further promote the convective mixing of the fluid with the formation water, wherein the water is unsaturated with the water-soluble fluid.   
     
     
         12 . The process of  claim 1 , wherein the formation has an intrinsic permeability of at least 300 mD in a vertical direction. 
     
     
         13 . The process of  claim 1 , wherein the formation has an intrinsic permeability of 1,000 to 10,000 mD. 
     
     
         14 . The process of  claim 1 , wherein the formation has a porosity of at least 15%, and wherein the formation water is saline water. 
     
     
         15 . The process of  claim 1 , wherein one or more of the following parameters are manipulated to enhance the convective mixing of the fluid:
 a) composition of the fluid to be injected into the formation;   b) placement of the fluid injection well in the formation;   c) temperature of the fluid to be injected into the formation;   d) rate of injection of the fluid into the formation;   e) injection pressure of the fluid into the formation;   f) numbers of the injection wells placed in the formation;   g) locations and profiles of the injection wells in the formation;   h) pH of the water in the formation;   i) salinity of the water in the formation;   j) density of the water in the formation;   k) volume of the injected fluid;   l) partial pressure of the injected fluid in the formation water; and   m) density of the fluid.   
     
     
         16 . The process of  claim 1 , wherein the fluid comprises flue gas. 
     
     
         17 . The process of  claim 16 , further comprising enriching a concentration of carbon dioxide within the flue gas prior to injection into the formation. 
     
     
         18 . The process of  claim 1 , wherein the fluid comprises one or more gases selected from the following group: carbon dioxide, nitrogen, methane, NO x , and hydrogen sulfide. 
     
     
         19 . The process of  claim 1 , wherein multiple ones of the fluid injection wells are provided wherein the wells are spaced apart by at least 4 times a height of the formation. 
     
     
         20 . The process of  claim 19 , wherein the wells are spaced apart by at least 10, 20 or 40 times the formation height. 
     
     
         21 . The process of  claim 1 , comprising the further step of co-injecting water that is unsaturated with a greenhouse gas with the water-soluble fluid through the fluid injection well. 
     
     
         22 . The process of  claim 11 , wherein at least one of the fluid injection wells and at least one of the water injection wells are operated episodically and alternately. 
     
     
         23 . The process of  claim 1 , wherein the formation has a natural dip of up to 20°. 
     
     
         24 . The process of  claim 1 , wherein the fluid is injected into the formation at a temperature higher than an ambient temperature of the formation water. 
     
     
         25 . A process for sequestration of a water-soluble fluid within a water-laden formation comprising:
 i) providing a computer programmed with a computer program stored on a computer readable medium, the program comprising a representation of a known geological formation, and at least one fluid injection well, the computer program provided with means to simulate at least one parameter selected from the group consisting of:
 a) composition of the fluid to be injected into the formation; 
 b) placement of the fluid injection well in the formation; 
 c) temperature of the fluid to be injected into the formation; 
 d) rate of injection of the fluid into the formation; 
 e) injection pressure of the fluid into the formation; 
 f) numbers of the injection wells placed in the formation; 
 g) locations and profiles of the injection wells in the formation; 
 h) pH of the water in the formation; 
 i) salinity of the water in the formation; 
 j) density of the water in the formation; 
 k) volume of the injected fluid; 
 l) partial pressure of the injected fluid in the formation water; and 
 m) density of the fluid, 
   wherein the computer program is configured to calculate properties of a convection cell generated in the formation based on dispersion of fluids in the formation, the dispersion of fluids influenced by the one or more parameters;   ii) inputting into the computer some or all of the parameters (a) through (m);   iii) manipulating the one or more parameters to determine the injection conditions required to generate a convection cell within the formation; and   iv) injecting the fluid into the formation through the injection well with conditions determined by the step iii, at a pressure which is between 0% and 25% below a natural fracture extension pressure of the formation whereby the fluid rises within the formation in a plume of undissolved fluid with sufficient volume, flow rate, and density contrast between the fluid and water within the formation to induce a dynamic density contrast-driven convection cell within the formation.   
     
     
         26 . The process of  claim 25 , wherein the computer program is further provided with means to simulate placement of one or more fluid withdrawal wells in the formation. 
     
     
         27 . The process of  claim 25 , wherein the injection pressure is within a range which is 3-20%, 3-15%, 3-10%, 3-5%, 5-20%, 5-15% or 5-10% below the natural fracture extension pressure of the formation. 
     
     
         28 . The process of  claim 25 , wherein the fluid comprises at least one water-soluble gas and at least one water-insoluble gas, the process further comprising:
 providing a withdrawal well in the formation; and   withdrawing the water-insoluble gas from the formation through the withdrawal well, thereby providing additional volume in the formation for further sequestration of the water-soluble gas.   
     
     
         29 . The process of  claim 25 , further comprising:
 providing at least one water injection well into the formation; and   injecting water into the formation to produce a cross current of water within the formation from a region remote from the injection well and to further promote the convective mixing of the fluid with the formation water, wherein the water is unsaturated with the water-soluble fluid.