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.

Description

CROSS REFERENCE TO RELATED APPLICATIONS

This application is a continuation-in-part of U.S. patent application Ser. No. 13/255,438, filed on Sep. 8, 2011, which is the national stage of International Application No. PCT/CA2010/000316, filed on Mar. 11, 2010, which claims benefit of U.S. Patent Application No. 61/173,301, filed on Apr. 28, 2009, and U.S. Patent Application No. 61/159,335, filed on Mar. 11, 2009. The contents of all of the prior applications are herein incorporated by reference in their entireties.

BACKGROUND OF THE INVENTION

1. Field of the Invention

The present invention relates to subsurface sequestration of fluids, and in particular to the sequestration of water-soluble gases such as CO₂ and other greenhouse gases within water-laden geological formations.

2. Description of the Related Art

Human activities have an impact upon the levels of greenhouse gases in the atmosphere, which in turn is believed to affect the world's climate. Changes in atmospheric concentrations of greenhouse gases have the effect of altering the energy balance of the climate system and increases in anthropogenic greenhouse gas concentrations are likely to have caused most of the increases in global average temperatures since the mid-20th century. Earth's most abundant greenhouse gases include carbon dioxide, methane, nitrous oxide, ozone and chlorofluorocarbons. The most abundantly-produced of these by human industrial activity is CO₂.

Various strategies have been conceived for permanent storage of CO₂. These forms include sequestration of gases in various deep geological formations (including saline aquifers and exhausted gas fields), liquid storage in the ocean, and solid storage by reaction of CO₂ with metal oxides to produce stable carbonates.

In a process known as geo-sequestration, CO₂, generally in supercritical (SC) form, is injected directly into underground geological formations. Oil fields, gas fields, saline aquifers, un-minable coal seams, and saline-filled basalt formations have been suggested as storage sites. Various physical (e.g., highly impermeable cap-rock), solubility and geochemical trapping mechanisms are generally expected to prevent the CO₂ from escaping to the surface. Geo-sequestration can also be performed for other suitable gases.

Saline aquifers contain highly mineralized brines, and have so far been considered of little benefit to humans. Saline aquifers have been used for storage of chemical waste in a few cases, and attempts have been made to use such aquifers to sequester CO₂. The main advantage of saline aquifers is their large potential storage volume and their common occurrence. One disadvantage of any practical use of saline aquifers for this purpose is that relatively little is known about them. Leakage of CO₂ back into the atmosphere has been thought to be a problem in saline aquifer storage. However, current research shows that several trapping mechanisms immobilize the CO₂ underground, reducing the risk of leakage.

The densest concentration of CO₂ that can be placed in a porous formation such as a saline aquifer is when CO₂ is in a supercritical state—referred to herein as SC-CO₂. Most sequestration schemes are based on injection of SC-CO₂ in this supercritical state when the material behaves as a relatively dense compressible liquid with an extremely low viscosity, far lower than any formation liquid. The object is to displace most or all of the water in the saline aquifer, replacing 100% or some fraction of the porosity with SC-CO₂.

In a prominent example of such a geo-sequestration strategy, the Sleipner project, operated by the Norwegian oil and gas company StatoilHydro, separates CO₂ (4 to 9.5% in content) from the natural gas recovered from a nearby gas well. The separated CO₂ is converted to the supercritical (SC-CO₂) form and injected into a salt water-containing sand layer, called the Utsira Formation, which lies 1000 m below the sea bottom. Several seismic surveys have been undertaken to investigate whether the storage of CO₂ remains secure.

Although the safe and permanent disposal of CO₂ represents an important challenge, as referred to above, long-term disposal of other water-soluble gases and fluids also presents similar challenges, to address the greenhouse effect as well as other needs.

SUMMARY OF THE INVENTION

The present invention relates to the (essentially) permanent disposal of a wide variety of water-soluble fluids, in particular CO₂, by providing processes and systems for mixing and dispersing of such fluids within a water-laden geological formation such as a saline aquifer to improve sequestration conditions.

According to one aspect, there is disclosed a process for sequestration of a water-soluble fluid within a subsurface water-laden formation, the process comprising the sequential steps of:

a) selecting a target water-laden geological formation;

b) providing a fluid injection well into the formation, the well comprising at least one opening to discharge the fluid into the formation;

c) providing a source of the fluid, the source in communication with the injection well; and

d) injecting the fluid into the formation from the injection well at a pressure which is between 0% and 25% below the 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 density contrast-driven convection cell within the formation.

The injection pressure identified above may be 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.

In another aspect, the injection pressure may be at or slightly above the natural fracture extension pressure of the formation, namely up to 5% or 10% above this value, for at least a portion of the fluid injection step.

The injection pressure may be 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.

Optionally, the fluid may be heated prior to injection to a level which exceeds the temperature within the formation at the well opening.

The formation may have a vertical dimension which is at least 15, 20, 25, 30, 35 or 40 meters above the injection opening(s).

The fluid may comprise at least one water-soluble gas and at least one water-insoluble gas. In this aspect, the process further comprises:

a) providing a withdrawal well in the formation; and

b) 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.

The process may further comprise:

a) providing a water injection well into the formation; and

b) 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.

The process may further comprise the step of injecting additional water into the formation through one or more water injection wells spaced apart from the gas injection well, to induce flux or cross-current of fluid-unsaturated water into the formation in the region of the injection well.

The present process may further comprise the preliminary step of determining the natural fracture extension pressure of the formation in the region around the fluid injection well, using known methods.

The formation may have a porosity exceeding 15% with the formation water being saline water.

The process may include manipulating one or more of the following parameters 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.

According to another aspect, there is disclosed a process for sequestration of a water-soluble fluid within a water-laden formation comprising the steps of:

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 at or somewhat below the 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 density contrast-driven convection cell within the formation. Optionally, the computer program may be further provided with means to simulate placement of one or more fluid withdrawal wells in the formation. The fluid injection pressure is between 0% and 25% below the natural fracture extension pressure of the formation, preferably 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.

In the method described herein, the formation may have a natural dip of up to 20°.

According to one aspect, initial movement of the fluid in the formation occurs as a low-density displacement front moving outwardly in the formation as the fluid percolates through the formation. In the case of a gas, the gas disperses initially as bubbles or pockets of undissolved gas. This displacement front will displace water within the pore spaces of the formation which is then driven to flow outwards and away from the gas discharge area. This associated water flow contributes to the development of in situ convention cells or convection currents. The injected fluid subsequently develops into and generates a low density plume that spreads laterally as well as moving vertically upwardly through the formation. This plume is a region of lower density than the water within adjacent parts of the formation where the injected fluid is not present. A lateral contrast in the average fluid density is thus generated. This process induces a density contrast-driven convective flow cell. Hence, a density-driven flow cell is generated wherein the region of lower density fluid (such as water which is heated and/or contains undissolved gas) rises vertically because it is less dense than the adjacent formation water. This more dense water then flows laterally to replace the lower density fluid that flows vertically, sustaining a large-scale convection cell.

The density contrast driven convection process described herein enhances mixing of the water-soluble fluid with formation water as the convection current develops in the formation and enhances the mixing between the injected fluid and the formation water. The undissolved soluble fluid enters into solution, and fresh, fluid-unsaturated water from remote regions of the formation is brought into contact with additional undissolved soluble fluid.

In operation, CO₂ (optionally combined with other gas) is injected under suitable conditions as described above into a formation that contains water which is unsaturated with CO₂. Unsaturated water from remote regions in the formation then moves into the region of the injection well as the result of the action of the large convection cell, and replaces local (in the vicinity of the injection well) CO₂-rich water with CO₂-free water, which can strip the CO₂ out of the injected gas more efficiently. Furthermore, the large-scale convection cell not only increases the diffusive mass transfer of CO₂ into solution, it also acts to bring remote CO₂-free water into the injection well bore region, thereby increasing the effective volume in the formation that can be accessed through one injection well as a result of this flushing action. Thus the density-driven convection process provides rapid mass transfer of CO₂ into solution and enhanced storage capacity for geo-sequestration.

Implementing the density-driven convection process described herein increases short-term storage capacity of the formation. As well, long-term capacity increases through access to lateral water flux with maximized mixing.

The process may comprise injecting a fluid consisting of a mixture of water-soluble and insoluble gases. In this aspect, a withdrawal well can be provided, which is in fluid communication with the aquifer or in communication with an insoluble gas pocket in the formation, for withdrawal of the insoluble, non-sequestered gas. The water-insoluble gas is withdrawn from the formation with the withdrawal well, thereby providing additional volume in the formation for further sequestration of the water-soluble liquid or gas.

According to another aspect, a plurality of fluid injection wells may be provided to generate a plurality of convection currents in the formation and/or multiple fluid discharge openings are provided within the fluid injection well(s), thereby providing enhanced mixing of the water-soluble liquid or gas in the formation. The configuration of the wells can be designed to promote the development of sustained convention currents in the formation. The injection wells may be horizontal injection wells, vertical injection wells or deviated wells. In some embodiments, the injection well defines a path that substantially intersects the formation vertically, horizontally or at a deviated angle from the vertical.

In some embodiments, the injected fluid is flue gas. As used herein, the term “flue gas” refers to gas produced by an industrial combustion such as a fireplace, oven, furnace, boiler or steam generator, or a recovery process (such as recovery of natural gas from a well). Such gases typically exit to the atmosphere via a flue. The term “flue gas” encompasses combustion exhaust gas produced at fossil fuel or biomass-burning burning power plants. The composition of flue gas depends on what is being burned, but it will usually consist of mostly nitrogen derived from the combustion air, CO₂ and water vapor as well as excess O₂ (also derived from the combustion air). Flue gas may further contain methane (CH₄), carbon monoxide, hydrogen sulfide, nitrous oxides and sulfur oxides, as well as particulates.

The term “gas” as used herein, unless a different meaning is expressed or implied, means either a gas or combination of gases. Similarly, “liquid” means either a liquid or combination of liquids, unless a different meaning is expressed or implied.

The term “fluid” as used herein, unless a different meaning is expressed or implied, means: a) a water-soluble liquid; b) a water-soluble gas; c) a combination of water-soluble liquids; d) a combination of water-soluble and insoluble liquids; d) a combination of water-soluble gases; or e) a combination of water-soluble gas and water-insoluble gas. The liquid or gas may comprise multiple types of liquids or gases. The fluid has a lower density than the water present in the formation to facilitate the generation of a convection current or convection cell.

As used herein, the term “insoluble” is not meant as an absolute term, but as a relative term which means “poorly soluble” or substantially less soluble than a substance recognized by one with skill in the art as “soluble.”

As used herein, the terms “formation” or “water-laden formation” refer to a subsurface layer of water-bearing permeable rock or unconsolidated materials such as gravel, sand, silt, or clay that contains sufficient water within its pores to permit generation of a convection current therein. A saline aquifer is a non-limiting example of a geological formation suitable for the processes disclosed herein. The related term “target formation” refers to the formation selected for injection of liquids or gases for sequestration.

As used herein, the term “formation water” or “water” refers to water present within the formation. The formation water may be present in the formation as a bulk water phase or may be segregated in pockets or droplets within a geological matrix of gravel sand, silt, or clay. The water may be saline or laden with other dissolved substances.

As used herein, the term “low permeability” means less than about 100 milliDarcy (mD) and the term “high permeability” means greater than about 300 mD.

As used herein, references to CO₂ and other liquids or gases refer to such fluids in any one of a purified, concentrated, supercritical or non-supercritical (in the case of gases) or impure or diluted state.

As used herein, the term “cross-current” refers to the flow of water within a formation in an at least partially horizontal direction. A cross current may be generated by the introduction of water into the formation from a water injection well or by the injection of gas under suitable conditions that generates a dynamic convection cell within the formation; the convection cell includes a cross-current component of movement of native formation water.

As used herein, the terms “fracture pressure” and “fracture extension pressure” means the minimum hydraulic pressure at which fluid introduced into a formation will cause fracturing of the formation or extension or widening of an existing or incipient fracture.

As used herein, the terms “about” and similar terms mean +−10% of the expressed value unless otherwise stated.

Indefinite articles such as “a” or “an” include both the singular and the plural unless otherwise specified or the context clearly dictates otherwise. For example, “a well” may identify either a single well or multiple wells.

These and other advantages of the invention will become apparent upon reading the following detailed description and upon referring to the drawings.

BRIEF DESCRIPTION OF THE DRAWINGS

So that the manner in which the above recited features of the present invention can be understood in detail, a more particular description of the invention, briefly summarized above, may be had by reference to embodiments, some of which are illustrated in the appended drawings. It is to be noted, however, that the appended drawings illustrate only typical embodiments of this invention and are therefore not to be considered limiting of its scope, for the invention may admit to other equally effective embodiments.

FIG. 1 is a schematic cross-sectional view of a geological formation with a single horizontal injection well and two horizontal withdrawal wells showing the directions of the convection currents produced by gas injection, and also showing a source of flue gas and components for processing the gas prior to injection. Cross currents of formation water within the formation generated by the gas injection are also shown.

FIG. 2 is a schematic cross-sectional view of a geological formation with three horizontal injection wells and four vertical withdrawal wells showing the directions of the convection currents produced by gas injection. Cross currents are also shown.

FIG. 3 is a schematic cross sectional view of an inclined formation with a single horizontal injection well and a single withdrawal well showing the direction of a convection current produced by gas injection. Cross currents are also shown.

FIG. 4 is a schematic representation of a gas sequestration array showing a single injection well, two withdrawal wells and two water injection wells. Gas pockets within the formation are also shown.

FIG. 5 is a schematic representation of a gas sequestration array showing a horizontal gas injection well, a water injection well spaced apart from the gas injection well and a withdrawal well for withdrawing inert (non-soluble) gas from a pocket in the formation.

DETAILED DESCRIPTION

In the following description of embodiments, similar features are referred to with similar reference numerals.

FIG. 1 shows one embodiment of the process for injection of flue gas to sequester the greenhouse gas components thereof. It will be understood that similar processes may be used to sequester other fluids. FIG. 1 illustrates a schematic cross-sectional view of a subsurface formation 10 located deep beneath ground surface 5. For example, formation 10 may be about 1000 to 2000 meters beneath the surface. Formation 10 consists of a deeply buried high permeability saline aquifer. The permeability of formation 10 may be at least 300 milliDarcy, or within the range of 500 to 15,000 milliDarcy, or more narrowly 1000 milliDarcy to 10,000 milliDarcy. The formation is bounded at its upper margin and, preferably, lower margin, by upper and lower layers 60 and 80 having low permeability. Formation 10 may be disposed in various orientations and configurations, such as a flattened generally horizontal orientation, or a sloping or other configuration (for example, see FIG. 3). Formation 10 should have a region with sufficient top to bottom spacing to permit the generation of convection currents within the formation water, as will be described in more detail herein. In one aspect, formation 10 includes a region with a vertical dimension of at least 25 meters. In other aspects, the minimum vertical height of the formation is at least 15, 20, 30, 35 or 40 meters. The terms “spacing”, “height” and “vertical dimension” refer to the distance “y” shown in FIG. 1, that is, the vertical distance between upper and lower margins of the formation. In one aspect, this region with a vertical spacing of at least y should also extend horizontally for a distance of at least about 1000 meters. Injection well 12 extends into formation 10 and has a horizontal segment 11. Well 12 has at least one discharge opening 13 within horizontal segment 11.

In one example, a formation having a minimum height of about 15 m and a radius of about 1000 m could provide a potential pore volume of roughly 10 to 15 million cubic meters assuming good displacement efficiency.

The range of vertical spacing y may depend upon other factors such as the pressure and the temperature of the gases emanating from the discharge opening 13 of injection well 12. However, it is contemplated that under suitable conditions an aquifer with a lesser vertical spacing, or wherein the region with this minimum vertical spacing extends horizontally to a lesser extent than the above, may be used for the present invention.

A source 25 of gas is provided, in which the gas normally consists of a mixture of gases. In the case of flue gas (raw or CO₂ enriched), the gas normally consists of a mixture of one or more water-soluble gasses such as CO₂ and one or more insoluble gasses such as nitrogen. In the described example, source 25 comprises a source of flue gas, such as a fossil-fuel burning power plant or other facility. It will be apparent that essentially any stationary source of gas may serve as the source. The gas mixture includes a water-soluble gas 16 and a water-insoluble gas 18. Preferably, the water-soluble gas is either a greenhouse gas or other pollutant. More preferably, the water-soluble gas is one or more of the following: CO₂, NO_x, or hydrogen sulfide. Most preferably, the greenhouse gas is CO₂. Preferably, the water-insoluble gas is nitrogen or methane. Source 25 may be located close to or above formation 10 or at some remove therefrom, such that the gas is piped to an injection site 40. The raw gas may derive from multiple sources, for example several fuel-burning facilities, wherein raw gases are piped to a common disposal facility.

According to another aspect, the soluble gas component may be enriched by known means, so as to enhance the efficiency of the sequestration process. Such enrichment may be done at source 25 of the gas or immediately prior to sequestration.

One or more gas injection wells 12 extend into formation 10. In FIG. 1, only a single such well is shown. Well 12 is a generally conventional high pressure gas injection well, having at least one and preferably multiple gas discharge openings 13 within formation 10. Well 12 may comprise any suitable orientation, but is preferably horizontal within formation 10 at segment 11, with multiple openings 13 spaced along the horizontal segment 11.

The natural fracture pressure of formation 10 is determined by conventional means prior to injection of gas into the formation. This value may be determined for the entire formation or a substantial portion thereof, or for a region of the formation immediately surrounding the injection site.

In order to provide sufficient pressure, heating and other conditions of the flue gas, the gas is piped from source 25 to a gas treatment unit 40 prior to being fed into injection well 12. The gas treatment unit pressurizes and optionally heats the raw gas. The heating may be provided by compressing the gas, which can elevate the gas temperature of the gas by 10 to 30 degrees Celsius. The conditions of pressure and temperature depend in part on the conditions within the aquifer including its permeability, formation pressure, the salinity of water within the aquifer, as well as the composition of the gas being injected. According to one aspect, the gas is pressurized to a level which is at or somewhat below the natural fracture pressure of the formation. According to one embodiment the maximum pressure of the gas is sufficiently below the natural fracture pressure to provide a margin of safety against fracturing, which may comprise an injection pressure of about 3%, 5%, 10%, 15%, 20% or 25% below the natural fracture pressure (also referred to as the “fracture pressure” or “natural fracture extension pressure”), or at a value within a range which is between any pair of the injection pressures. For example, the gas may be injected within a range of 0-25% below the natural fracture pressure of the formation. Preferable ranges are 3-15%, 3-10% and (most preferably) 3-5% below the natural fracture pressure of the formation. Other ranges that are within the present disclosure are 3-20%, 10%-25%, 10%-20%, 5-20%, 5-15% and 5-10% below the natural fracture pressure of the formation. The selected “margin of safety” below the fracture pressure may be dictated by regulation.

When gas is injected at the selected pressure, and particularly when the horizontal and vertical formation dimensions relative to the gas injection location are as identified herein, the injected gas rises within the formation in a plume of undissolved gas and with sufficient velocity to generate a convection cell within the formation characterized by dynamic (non-static) convective mixing as described below. To properly calculate this limiting pressure at the injection point to control the process appropriately, one may calculate the effect of the different hydrostatic pressures in a column of gas and a column of formation water. The methodology is summarized here.

As the injection process proceeds, a continuous vertical column of gas may be generated within the formation above the gas injection point. Because the gas is less dense than the saline water, at its uppermost possible limit, the top of the saline aquifer stratum being used for injection, it may be under an additional pressure. The maximum value of that additional pressure can be calculated based on the distance to the top of the saline aquifer above the injection point (ΔH=zinj−ztop), the difference in fluid densities (Δρ) between the continuous saline aqueous phase and the gaseous phase (Δρ=pwater−pgas), and the gravitational acceleration (g). Calculation of the expected value of the hydraulic fracture extension pressure at different elevations in the saline aquifer may also be performed to permit that everywhere or substantially everywhere within the vertical column above the injection point the pressure in the gas remains at least 3% to 5% (or other selected value) below the hydraulic fracture extension pressure (often referred to as the minimum horizontal stress).

For any given injection well, the pressure limit necessary to minimize the possibility of creation of a vertical hydraulic fracture will place a direct control on the injection rate of fluid into the formation (or into any off-set well or array of wells that may inject water into the reservoir to further promote advective mixing). The relationship that exists between injection rate and bottom-hole injection pressure for a given well in a given permeable saline aquifer with a given completion strategy may be determined with known methods. As a gaseous phase is introduced into the stratum, the ability of the stratum to accept an injection rate yet stay at or below the pressure specified above will change because the relative permeability will change. One should control the injection rate at the injection point so as to remain at or below the limit calculated above to avoid hydraulic fracturing of the reservoir rock. Therefore, one embodiment involves measuring or calculating the bottom-hole pressure at the injection point so as to control the injection rate appropriately, without exceeding the pressure limit. The pressure measurements may be performed at the surface or at the bottom-hole.

The gas injection rate may be affected by the presence and injection rate activity of off-set wells or arrays of wells; measurements of pressure may be used to properly manage the process in an optimal manner.

The pressurized and optionally heated gas is fed into injection well 12 and introduced into the aquifer via openings 13 within well 12. The gas is injected into formation 10 with sufficient volume and driving pressure and optionally added heat to generate one or more convection current cells within the formation water. Injection of the relatively highly pressurized and optionally heated gas initially generates a convection current within the immediately adjacent formation water. This convection current develops as a result of the upward movement of bubbles of undissolved gas formed within the formation water, and optionally the elevated temperature of the injected gas, displacing natural formation water from the pore space of the formation. The gas disperses initially as bubbles or pockets of undissolved gas. The resulting movement of the formation water initiates one or more convection currents or cells 14 within the formation water. Over time, a relatively low density plume of formation water develops as the gas becomes dispersed in the formation water because of horizontal dispersion during vertical flow and the heterogeneity of the formation. The gas plume therefore tends to spread laterally as well as moving vertically. The corresponding movements of the formation water and gas plume generate one or more convection currents or cells 14 within the formation. As additional gas is fed into the formation, the resulting plume will continue to generate convection currents or cells 14 within the formation water in the region of the injection well due to density differences between the ambient formation water and the plume. This current includes a component that flows laterally and rises upwardly, as a result of the dispersive movement of the plume of injected gas. The dimensions of this current depend at least in part on the dimensions of the aquifer including its vertical spacing and the density, driving pressure, volume or flow rate and temperature of the injected gas. The soluble gas 16 dissolves into the formation water, facilitated by the enhanced mixing action caused by the convection cells/currents. The water-insoluble gas 18 separates out due to its insolubility, and rises to accumulate in a gas cap or pocket 20 which is usually located immediately beneath the upper low permeability formation 60.

The conditions of gas injection pressure, the gas injection rate and the volume of injected gas generate a density difference between the less dense mixture of water and gas pockets/bubbles and the surrounding formation water that is free of such bubbles and gas pockets. This density difference in turn gives rise to a dynamic convection process within the formation that actively circulates the gas within a large region of the formation, thereby bringing undissolved gas and gas-saturated brine into contact with a large volume of the formation water in order to rapidly and efficiently diffuse the gas into the formation.

In one aspect, at least one withdrawal well 22 is provided. The withdrawal well(s) 22 are employed to vent water-insoluble gas 18 out of the formation 10, thereby providing additional volume in the formation 10 for further sequestration of the water-soluble gas 16. The withdrawal wells 22 extend into the formation 10, at least into an upper portion thereof. These wells include inlet openings 23 located within the formation 10, at locations where the gas caps or pockets are expected to accumulate. The withdrawal well(s) 22 may provide a conduit to a surface installation 50 where the insoluble gas may be vented to the atmosphere, if for example the insoluble gas is nitrogen. Alternatively, the insoluble gas may be diverted into a gas treatment or capture facility, if for example the insoluble gas represents a useful product such as methane.

The venting process may rely on the internal pressure within the gas pocket to vent the gas, or alternatively the accumulated gas may be pumped in order to more rapidly and thoroughly withdraw the insoluble gases from the formation 10. Preferably, a portion of withdrawal well 22 is horizontal to permit it to extend through an extended region of a gas pocket 20.

The venting process may extract some of the energy present in the compressed insoluble gases by passing high-pressure vented gases through a gas turbine to generate electricity, after such gasses have vented from the gas pocket.

Shown in FIG. 2, in another embodiment of the process is a schematic cross-sectional view of a geological formation 10 with injection well 12 having a horizontal segment provided with multiple gas discharge openings 13. There are also provided multiple withdrawal wells 22. FIG. 2 depicts convection currents 14 produced by gas injection. Also shown are crosscurrents 24 which are influenced by the development of the convection currents 14. As described in the embodiment of FIG. 1, water-soluble gas 16 becomes dispersed within formation 10 as a plume of lower density fluid and generates a convection current 14 while water-insoluble gas 18 rises toward a gas pocket 20. Cross currents 24 provide additional mixing between water-soluble gas 16 and the formation water. Four withdrawal wells 22 are provided to draw the water-insoluble gases out of the formation 10, thereby providing additional volume in the formation 10 for further sequestration of the water-soluble gas 16.

According to one aspect of the embodiment of FIG. 2, multiple gas injection wells 12 are provided. Wells 12 are arranged to be generally parallel with each other. The spacing between adjacent horizontal well segments 12 may be set at a minimum of 4 to 5 times the available formation height above gas discharge opening 13. In a further aspect, this inter-well spacing is 20 to 40 times the formation height. In one aspect, the inter-well spacing may be based in part on the ratio of vertical to horizontal permeability, wherein higher horizontal permeability permits greater inter-well spacing. In one example of a method for arranging the spacing between parallel injection wells, in a water-containing formation that is on average about 40 m height, 20% porosity and with a 50% efficiency in mixing, there may be provided about 4 square km per well in horizontal area. If the well is 2 km long, the lateral (inter-well) spacing between each pair of adjacent horizontal well segments 12 should be about 1 km, which yields a ratio of 1000/40, or about 25 times the formation height.

In one embodiment, the minimum formation height is about 25 m. This value is selected in this embodiment to address a problem that can arise from limitations of volume in the formation. Once the water in the formation becomes CO₂ saturated within the influence volume, the dissolving process attenuates. However, this limitation can be at least partially overcome by providing a mechanism by which CO₂-saturated water flows away from the injection well; this process to some extent occurs naturally, but it can also be “forced” by generating a cross current by injecting water into the formation with one or more water injection wells. This in turn provides more leeway in the spacing between gas injection wells, as this process generates an enhanced “mixing region” wherein nitrogen is being removed in one area, CO₂-saturated water is removed from the near-well area by flowing out of the mixing region, and new water enters this mixing area through lateral flow which in turn is enhanced by water injection through water-injection wells.

The large-scale convection cell 42 acts to bring remote water to the injection well region via a “cross-current” 24 (shown in FIGS. 3 and 5) increasing the effective volume in formation 10 that can be accessed through one injection well by “flushing” the lateral water into the well bore region. Cross current 24 comprises native formation water in which its motion is caused by the dynamic convection cell process, which in turn is instigated by the injection of gas under sufficient pressure as described herein.

Shown in FIG. 3, in another embodiment of the process, is a schematic cross sectional view of an inclined formation 10 indicating a horizontal injection well 12 and a withdrawal well 22 showing the direction of a convection current 14 produced by gas injection. As described above, water-soluble gas 16 becomes dispersed within the formation as a plume of lower density fluid and generates a convection current 14 while water-insoluble gas 18 rises toward gas pocket 20. Cross currents 24 are shown moving through the formation 10 towards the gas pocket 20.

According to a further aspect of the invention as depicted in FIG. 4, an enhanced cross current of unsaturated water 32 is induced within the formation by injecting unsaturated water into the formation from a second well 26 remote from the gas injection well. Shown in FIG. 4 is a schematic representation of a gas sequestration array disposed in a formation 10 showing a gas injection well 12 for injection of a gas mixture 35, withdrawal wells 22 and multiple water injection wells 26 for injection of water 28. The gas outlet region of gas injection well 12 is placed near the lower boundary of the formation 10. Each withdrawal well 22 extends into gas pockets 20 within the formation 10 for withdrawal of insoluble gas 18 contained therein, which has separated from the injected gas mixture 35 by differential solubility of the respective components of the mixture 35. Additional water 28 can be injected into the formation via one or more water injection wells 26. This added water can then flow into the matrix of formation 10 as indicated by arrows 32 to bring additional water into the formation 10 and promote mixing of gas mixture 35 in formation 10.

In one aspect, water is continuously injected through at least some of water injection wells 26 to displace CO₂-saturated water away from the region of active (convection cell) mixing. In another aspect, water injection is discontinuous. Injected water combined with the convection currents induced within the formation generate a large lateral flow within the formation which is mostly pressure-driven. As well, the water flow within the formation includes a vertical (mostly buoyant) flow component. To achieve this it is preferred to use a large capacity saline aquifer of great lateral extent.

In the embodiment of FIG. 4, water injection well 26 is remote from gas injection well 12, by a distance whereby water injection occurs outside the region where the dynamic convection cell 42 is active. However, injection well 26 must be sufficient close to gas well 12 to provide an effective cross current. For example, water injection well 26 may be about 50, 100, 200, 300, 400, 500, 750 or 1,000 meters away from gas injection well 12, or any distance between these values. Multiple injection wells 26 may be provided, whereby all of the injection wells are located at one side of gas injection well 12 to thereby urge the gas-saturated water 42 within the convection cell out of the zone of convection cell 14, as shown more particularly in FIG. 5.

According to another aspect, water introduced through water injection well 26 may be contaminated or otherwise targeted for disposal. For example, the injected water may comprise sewage or other contaminants that are suitable for disposal within a deep, stable aquifer.

The rising plume of water which contains undissolved gas generates a convection cell, in tandem with the forced lateral flow generated by water injection through wells 26, continuously displaces the entire convection cell laterally. As a result, the CO₂ saturated water gradually is “pushed” out of the system, and non-saturated (injected) water is then introduced into the vertically-rising mixing plume.

FIG. 5 depicts an embodiment wherein a gas injection well includes a horizontal well segment 11 within a formation 10, adjacent to the base of the formation. Injection of gas through openings 13 generates a gas bubble plume 14 that forms a dynamic, density contrast-driven convection cell within formation 10. A water injection well 28 is provided which extends into formation 10. Well 28 is spaced horizontally from gas injection well 11 whereby it is outside the outer edges of the expected lateral spread of convection cell 14. Injection of water into formation 10 from well 28 generates a cross-current 24 of unsaturated water within formation 10 that intrudes into convection cell 14 and displaces gas-saturated water away from convection cell 14. This process improves the efficiency of the dissolution of gas into the formation water and permits the convective mixing to occur for a longer time as compared with processes that do not employ such a cross-current. As shown in FIG. 5, one or more gas withdrawal wells 22 are provided with extend into gas pockets within an upper portion of formation 10, to withdraw undissolved gas such as nitrogen from the formation.

The amount of unsaturated water that may be injected into formation 10 may be calculated by known methods and empirical observations of the injection process. In particular, the water injection rate is based on the quantity of saturated water that is created by the gas injection process and the rate of its creation; the rate of saturation is in turn determined by the rate of gas injection into formation 10. An efficiency factor may be applied, which can be determined from field observations, to determine a suitable water injection rate.

As discussed, the pressure at the injection point in the saline aquifer may be maintained to be somewhat below the hydraulic fracture extension pressure within the saline aquifer to avoid creating a vertical hydraulic fracture that could degrade the process. The injection pressure may be maintained at the selected level for the entirety of the gas injection stage or for a selected portion of this stage which may consist of at least 50%, 60%, 70%, 80% or 90% of the duration of the gas injection stage into the formation. In this aspect, the gas may be injected in a cycle alternating between gas injected at a selected first pressure that is at or somewhat below the natural fracture pressure of the formation and a second pressure which is reduced from this level or in which no gas is injected.

Example 1

Sequestration of Carbon Dioxide in a Saline Aquifer by Density Driven Convection

In this example, the gas mixture being injected includes CO₂, which is highly soluble in water, along with other gases which are less soluble in water under the conditions of temperature, pressure, pH, and salinity within the formation. The gas mixture is injected at a high rate into a location close to the base of the formation. The formation has considerable vertical extent, or a dip which provides a vertical extent of about 20 m. For example, not excluding other possible cases that may be acceptable, a desirable saline formation would be located over 1000 m deep within the strata and of great lateral extent. It would have an intrinsic permeability of at least 1 Darcy in the vertical direction. The formation would have a porosity exceeding 15% with the pore fluid being saline water. It is considered more desirable if the formation has a natural dip (inclination) of up to 20°. It is advantageous if the formation is bounded by an upper formation of rocks of low permeability to the mobile phases involved in the sequestration process, including gases and water.

Preferably, the injection pressure is significantly higher than the formation pressure within the saline aquifer formation by an amount that is determined by the porosity and permeability of the host rock, along with other secondary factors. For example, an injection well with a 1000 m long horizontal section is drilled into a 1500 m deep saline aquifer which has a natural formation pressure of 15 MPa. A mixture containing CO₂ and other gases is injected uniformly along the length of the horizontal section at a pressure greater than 15 MPa. The injection pressure is normally somewhat below the fracture pressure of the formation. However, in some circumstances where it is deemed necessary to encourage and promote vertical flow within the formation (for example where it is desired to increase the fluid flow rate and enhance distribution of fluid in the formation), the injection pressure may be slightly higher than the natural fracturing pressure of the formation, such that limited length vertical fractures are generated in order to increase the mixing length of the gas-water contact zone.

With the proper choice of reservoir parameters and injection rates, it is appropriate in some embodiments to inject gas at somewhat above the measured fracture pressure because the induced fractures are very short, and cannot propagate significant distances, given the permeability and porosity of the formation. And, this can be controlled by measuring the pressures of injection and making sure that they are no higher than some value such as 5 to 10% above the intrinsic fracture pressure.

One of the relevant considerations for determining gas injection pressure and rate is the extent to which it is desired to increase the sweep efficiency, or the extent of distribution of gas in the formation laterally or vertically, of the injected gas.

The gas may be optionally injected at an elevated temperature above the ambient temperature of the formation water, in order to further enhance the density contrast between the injected gas—and consequently the formation water which is charged with the injected gas, and the surrounding formation water.

Initially, under the high pressure gradients near the well, the injection may lead to local displacement, with the liquid in the pores being mostly physically displaced by the undissolved gas that is entering. In a suitable formation, as the size of the injected zone increases, the driving pressure decreases (because of the greater radius, pressure drops off because of radial spreading), and the height of the gas column increases, leading to a gravitational segregation effect which arises from differences in phase densities. Once the effect is large enough, the undissolved gas will tend to rise towards the top of the formation, most likely through a tortuous path due to the presence of small flow impedance barriers such as shale streaks or small bodies of fine-grained sand.

Due to dispersion in vertical flow and the heterogeneity of the formation, the gas will spread out in an upward-moving plume that spreads laterally as well as moving vertically. This plume represents a region of lower pore fluid density than the adjacent parts of the saline formation that have no free gas, therefore a lateral contrast in the average fluid density is generated which creates a large density-difference-driven convective flow cell.

This density contrast will greatly increase the in situ forced mixing between the injected gas and the formation water. Water is brought from remote locations in the formation to the injection site as the result of the creation of the large convection cell, and this replenishes in part the local water with CO₂-free water, which can therefore strip the CO₂ out of the injected gas more efficiently. Therefore, the large-scale convection cell not only increases the diffusive mass transfer of CO₂ into solution, it also acts to bring remote water to the injection well bore region, increasing the effective volume in the formation that can be accessed through an injection well by “flushing” the lateral water into the well bore region. The gases of lower solubility remain as undissolved gaseous phases and spread laterally and upwardly, where they can be removed by withdrawal wells 22. The density-driven convection process provides more rapid mass transfer into solution.

Implementation of the present process increases the short-term storage capacity of soluble gases in the formation as well as increasing the long-term capacity by maximizing mixing and promoting lateral water flux. The overall sequestration process may involve preliminary passage of a flue gas mixture (for example, containing about 13% CO₂ and 87% N₂) through a membrane or other type of purification or gas enrichment system so that the injected gas is 25%-80% CO₂, with the remainder being essentially N₂; such a gas/CO₂ enrichment process will also help with improved storage capacity in situ and particularly with the rate at which the soluble gases (CO₂ in this realization) can be injected and subjected to contact with the formation waters. The specific content of the injected gas can be varied in response to driving economic and environmental factors, as the process does not depend upon having a specific composition of the injected gas.

The process may include one or more long horizontally drilled wells for injection completed with a slotted liner with no cement. Such wells may be placed in a parallel offset configuration, with the distance between the wells dependent on analysis, such as computer modeling that determines an effective convection cell size. The length of the wells may be designed based on the rate at which gas can enter the formation at an appropriate rate to maximize mass transfer and convection mixing.

Each well may be equipped with an interior tubing system that can distribute the gas injection evenly along the length of the well so that generally equal volumes of gas can enter the well at various locations over time, in a manner known per se in the art.

The well may be operated to maximize the contact of CO₂ with saline formation water by controlling at the surface the volume, rate and pressure of the gas stream being injected. It can be advantageous if the injection wells are placed near the bottom of the formation, whether the injection wells consist of horizontal or vertical wells. The injection rate may be determined by the injection pressure; a longer horizontal well having more multiple openings 13 permits a higher overall injection rate at a given pressure than a similar well with fewer openings 13. In principle, there is no absolute limit on the rate, except in so much as is dictated by the practical limitations in the design of the injection well itself.

In another embodiment, the sequestration method comprises injection of a greenhouse gas wherein at least some parameters for the injection process are determined by a computer-implemented simulation. The process consists of providing a computer which is programmed by a computer program stored on a computer readable medium. The program comprises a representation of a known geological formation in a manner known to the art. The computer is programmed to represent at least one injection well for injecting a mixture of soluble and insoluble fluid into the formation, and includes means known to the art to vary one or more parameters. These parameters are 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.

The computer program is configured to calculate properties of a convection cell generated in the formation arising from density-driven movement of the fluid and formation water within the formation influenced by one or more of the parameters. The computer produces a report providing sequestration conditions and preferred injection conditions comprising the one or more parameters.

The computer program is further provided with means to vary placement of one or more fluid withdrawal or water injection wells in the formation.

The parameters determined in this model are then replicated on site under real-world conditions with components of an injection well system at the site of the known formation, in order to generate at least one density-driven convection current within the formation to achieve sequestering of the water-soluble fluid using the injection well system. The replication step includes providing a source of pressurized and optionally heated fluid as described above and injecting this fluid into the formation through an injection well under conditions determined by the computer modeling process. The injection occurs under conditions of pressure, rate, volumes and optionally temperatures as described herein. For example, the process may include limiting the injection pressure for at least a portion of the injection process to a pressure which is between 0% and 25% below the natural fracture extension pressure of the formation. In other aspects, the injection pressure is between 3% and 5% below the natural fracture extension pressure of the formation. In other aspects, the injection pressure is within a range which is one 3-15%, 3-10%, 5-20%, 5-15% or 5-10% below the natural fracture extension pressure of the formation. The injected 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 density contrast-driven convection cell within the formation.

The computer-assisted process described above may include the following steps:

1) Using a Geomechanical Earth Model, determine the pore volume (saline water) available in the repository.

2) Using known p-V-T and solubility information relating to the particular repository pore water (different salinity water will have different solubility), determine the amount of the gas that can sequestered (e.g. CO₂) in a unit volume at steady state, ambient conditions (original pressure and temperature). This is the “theoretical maximum storage capacity” per cubic meter of pore fluid, as calculated by multiplying the total repository volume by the average porosity.

3) Begin injecting gas into the long horizontal injection well 11, 12 that is placed at or close to the bottom (deepest part) of the repository stratum. The gas injection will generate a buoyant plume with a large contact area between gas and the water. Because the injection pressure is substantially higher than the original reservoir pressure, this will also generate some lateral flow, helping the gas plume to spread laterally as well to some degree. The shape of the plume can be calculated with a mathematical model that includes buoyancy (density differences), capillary effects (surface tension between the gas and the water as well as the pore throat size distribution of the reservoir, rate and pressure effects, and the rate of dissolution of the gas to be sequestered into the water.

The embodiments described herein will lead to a large volume of water becoming saturated with the gas to be sequestered. The saturated water is circulated in the convection cells, which leads to a gradual impairment of the efficacy of the dissolving process whereby the gas enters into solution in the water.

Depending on the modeling and monitoring calibration, it will be determined approximately what volume of water in what injection time period will become saturated or partially saturated with the gas to be sequestered. Once this volume is known, its value is used to control the volume input of non-saturated water, at as high a pressure as feasible, but short of the formation fracturing pressure. The water may be input through a horizontal well parallel to the gas injection well, or by an array of vertical wells sufficient to achieve the required volume rate without exceeding the limits on injection pressure. Necessarily, this injection will be at a somewhat higher pressure that the gas injection well, and will be located appropriately in properly designed system, so that water that is free of gas in solution can enter the plume region and help displace the water that has become saturated with gas, so that the process can proceed with greater efficiency.

The geological disposition of the repository will control the specific locations of the wells so as to take the best advantage of the pore space available and the displacement processes that can be controlled though appropriate injection strategies for the fluids (water and gas).

In a further embodiment, water that is unsaturated with the greenhouse gas is co-injected with the gas in the injection well.

In a further embodiment, the gas injection wells and the water injection wells are operated episodically and alternately. The respective wells provide alternating gas injection into the injection well and water injection into the injection well. This improves the flushing of saturated water away from the mixing zone (buoyant plume), allowing gas-free water easier access to the injection well.

The present process can be monitored using various techniques to optimize its utility in terms of the maximum feasible storage capacity for the gas to be sequestered.

It will be seen that the present invention has been described by way of preferred embodiments of various aspects of the invention. However, it will be understood that one skilled in the art may depart from or vary the embodiments described in detail herein, while still remaining within the scope of the invention as defined in this patent specification as a whole, including the claims.

Claims

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, NOx, 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.