PROCESS FOR SEQUESTRATION OF FLUIDS IN GEOLOGICAL FORMATIONS

Abstract

A process for geo-sequestration of a water-soluble fluid includes selection of 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 density-driven convection current of formation water which promotes enhanced mixing of the water-soluble fluid with formation water.

Description

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 in water-laden geological formations.

BACKGROUND OF THE INVENTION

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 may 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.

Injection of gaseous CO₂ (i.e. not in supercritical form) into a subsurface formation in solution with water at the maximum solubility limit is a desirable approach to sequestration of this gas that has been proposed with mixed success in the past. Prior to the present invention, a problem of sequestering of CO₂ by dissolution in an aqueous solution within geological formations has been that the porous volume of the formation is occupied far less efficiently than the occupation which occurs upon injection of SC-CO₂. Once the active injection phase is completed, there is no more active mixing within the porous medium. Thereafter, the dissolution of the CO₂ within the formation water is controlled by the concentration differences, the contact area, and the diffusion path length. Mass transfer rates associated with such concentration gradient-driven diffusion processes in porous media are slow and it is expected that thousands of years may be required to approach full dissolution of the CO₂ in the aqueous phase within the geological formation.

The “reduced-mixing, long-term concentration gradient diffusion” problem persists even with injection of SC-CO₂. At the high injection rates proposed for SC-CO₂ sequestration, the SC-CO₂ will first displace water and occupy the pore space directly, with only a small amount of convective and dispersive-occurring mixing at the displacement fronts. As SC-CO₂ is injected over time, a growing area of contact is generated between the two fluids and a dissolution zone is generated. The SC-CO₂ then becomes dissolved into the saline water along this contact area, largely as the result of diffusion and dispersion associated with forced advection caused by pressure driven flow (from injection of the SC-CO₂ under pressure).

Because of the density difference between saline water and SC-CO₂, there are also gravitational forces that will tend to segregate the liquids in the saline aquifer: the SC-CO₂ will rise above the denser water, forming a “pancake” under zones that are finer-grained with poorer permeability (shale streaks, siltstones, etc.). This not only suppresses part of the mixing component that would arise in a more uniform displacement, it also leads to a significant inefficiency in the access to the pore volumes in the formation: portions of the formation remote from the injection point are largely inaccessible to any storage mechanism (displacement by or dissolving of CO₂ into solution).

Once the injection ceases, only a small fraction of the SC-CO₂ has gone into solution because of the mixing and diffusive effects at the displacement fronts, and because the advective driving force (injection pressure) ceases. The CO₂ can no longer be advectively mixed with the water, and this leaves only diffusion effects that are driven solely by concentration gradients of CO₂ in the water.

In a saline aquifer formation, after injection, the SC-CO₂ remains high in the zone above the injection site due to its lesser density. This density-graded system provides a stabilizing force that further reduces the rate of any diffusion process. Initially, the diffusion front is relatively narrow and distinct with large surface area between the CO₂ and water and the solution process happens relatively efficiently. But over time this front grows and widens vertically. As a result, the front becomes less distinct. This produces a thicker diffusion or transition zone with less surface area between the CO₂ and water that has a low CO₂ concentration (i.e. the transition-dissolution-contact area between the SC-CO₂ and the formation water becomes enriched with CO₂. The vertical distance between water from remote regions of the formation and SC-CO₂ grows as CO₂-unsaturated water is further away from the SC-CO₂. Hence the diffusion/solution process slows considerably. As a result it can take many thousands of years for CO₂ to enter into solution, since in situ movement of water at remote regions of the formation (to facilitate the CO₂ in solution with water process) is very slow. At this stage, there is no convective mixing between the SC-CO₂ and the formation water due to the density graded system.

Density graded systems in porous media are extremely stable over long times. Once active mixing ceases, it will take thousands of years for SC-CO₂ to become dissolved in the water phase under typical sequestration conditions. There is simply no mechanism to bring “new water” into contact with the SC-CO₂, and the process becomes totally dominated by slow diffusion.

SUMMARY OF THE INVENTION

Although the safe and permanent disposal of CO₂ represents an important challenge, as referred to in detail 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. The present invention thus relates to the (essentially) permanent disposal of a wide variety of water-soluble fluids, 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.

Objects of the present invention include:

a) To provide a method for geo-sequestration of water-soluble fluids, in particular but not limited to gases, by injection of the fluid into a water-laden formation in a manner which improves the mixing of the fluid with formation water to improve the dissolution of the fluid, through the generation of in situ convection currents or convection cells.

b) To increase the volumetric extent of the dissolution process in the geological formation, thereby improving the storage capacity for water-soluble fluids (such as CO₂) within the formation.

c) To provide a process to enhance both the separation of water-soluble gases from a mixture of soluble and insoluble gases and the sequestration of the soluble gases in a geological formation, and to withdraw the insoluble gas from the geological formation to preserve the volume of the geological formation available to accommodate dissolved soluble gas.

d) To provide a method for determining conditions for sequestration of a water-soluble fluid in a geological formation using a computer model of the formation and computer simulations of injection of fluids.

e) To provide an alternative method for enhanced sequestration of water-soluble gases in geological formations which does not require pre-injection separation of gases nor conversion of the injected gases to a supercritical form.

In one aspect of the invention, there is provided a process for sequestration of a water-soluble fluid by injection of the fluid from an injection well into a water-laden geological formation under conditions of temperature and/or pressure selected to cause the fluid to enter and disperse within the formation with sufficient volume, pressure, and density-contrast with the formation water to generate a convection current or convection cell within the formation. A target geological formation comprising an aquifer is selected which is bounded above and optionally also below by layers of low permeability for containing the water bearing formation in a stable state. The said low permeability layer can be located either directly above or below the aquifer or separated from the aquifer by one or more layers. The injection well extends into the target formation. The fluid is pressurized and/or heated, and introduced into the formation from the injection well so as to generate one or more convection cells and thereby to enhance dispersal, dissolution and sequestration of the fluid, or a water-soluble fraction thereof, within a large region in the formation.

According to this aspect, initial movement of the fluid in the formation is expected to occur 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 may disperse 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 percolation area. This associated water flow contributes to the development of in situ convention cells or convection currents. The injected fluid will subsequently develop into 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 one embodiment, CO₂ (usually 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.

The consequences of implementing this density-driven convection process are that the short-term storage capacity of the formation increases and the long-term capacity also 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 is 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.

The process may further include providing one or more water injection wells into the formation and injecting water into the formation, thereby producing a cross current of water within the formation originating from a region remote from the injection well. This water injection process further enhances the convective current/cell process and water flux in the formation.

According to another aspect, a plurality of fluid injection wells may be provided to generate a plurality of convection currents in the formation, 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 process further includes determining appropriate placement of one or more openings in the injection well for discharge of fluid, such that the openings are spaced sufficiently below the upper face of the formation to generate a convection current so as to promote enhanced mixing of the water-soluble fluid with formation water.

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.

In another aspect of the invention, there is provided a process for determining conditions for sequestration of a water-soluble fluid. The process employs computer modeling of structure and conditions of a known water-laden formation. Computer modeling programs for simulating formations are known in the art. The skilled person will have the knowledge to modify an existing program or to develop a new program using routine methodology for simulating water-laden formations as well as the components and conditions employed in performing the processes described herein. In accordance with this aspect of the invention, a computer program stored on a computer readable medium is provided which includes a representation of a known formation and a fluid injection well. The computer program is provided with means to vary one or more of the following parameters: placement of the fluid injection well(s) in the formation, partial pressure of gas in the formation, rate of injection of fluid into the formation, numbers of injection wells placed in the formation, pH of water in the formation, salinity of water in the formation, and density of water in the formation. The computer program is configured to calculate properties of a convection cell generated in the formation based on dispersion of fluids in the formation which is influenced by one or more of the parameters. A report is then produced which provides recommended well patterns and injection conditions and, optionally, sequestration conditions within the formation. The sequestration conditions include the parameters used in determining the properties of the convection cell which is generated when the recommended conditions are adhered to.

In some embodiments, the computer program is further provided with means to simulate the varying of placement of a plurality of fluid injection wells, gas withdrawal wells, and/or water injection wells in the formation.

The process for determining conditions for sequestration of a water-soluble fluid described above may then be put into practice by configuring one or more injection wells and, optionally, one or more withdrawal wells and/or water injection wells for appropriate placement within the formation according to the parameters used to produce the convection cell in the computer simulation.

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. Said 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 terms “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 purified, supercritical (in the case of gases) or impure forms.

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

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 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.

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. The formation 10 consists of a deeply buried high permeability saline aquifer. 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. It is believed that formation 10 should have a region with a minimum vertical spacing of about 25 to 30 meters. The term “spacing” refers to the distance “y” shown in FIG. 1, that is, the vertical distance between upper and lower margins of the formation. 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 has at least one discharge opening 13 within this region. 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, the inventors do not wish to be bound by theory and 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 water-soluble and insoluble gases (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_N, 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, with multiple openings 13 spaced along the horizontal portion.

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 heats the raw gas and may optionally enrich certain components of the gas. 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.

The pressurized and optionally heated gas is fed into injection well 12 and introduced into the aquifer via openings 13. 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. It is believed that a convection cell is generated according to the following mechanism. Injection of the heated gas initially generates a current within the immediately adjacent formation water. This 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 said 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.

At least one and preferably a plurality of withdrawal wells 22 are provided. The withdrawal well(s) 22 are employed to vent the 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 either vented to the atmosphere, if for example the insoluble gas is nitrogen or 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 be designed to 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 multiple horizontal injection well openings and multiple withdrawal wells 22 showing the directions of convection currents 14 produced by gas injection. Also shown are cross currents 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. Also as described above, four withdrawal wells 22 are employed 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.

The large-scale convection cell acts to bring remote water to the injection well bore region via a “cross-current” 24 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.

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.

Shown in FIG. 4, in another embodiment of the process, 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 water injection wells 26 for injection of water. 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.

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 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. Those skilled in the art will be able to readily determine a suitable injection pressure or range of pressures to induce the formation of density-driven convection currents within the target formation water. One of the relevant considerations 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 bore, the injection may lead to a local displacement mechanism, with the liquid in the pores being mostly physically displaced by the 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 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 one injection well by “flushing” the lateral water into the well bore region. The gases of lower solubility remain as non-dissolved gaseous phases and spread laterally and essentially upwardly, where they can be removed by withdrawal wells such as passive drain wells. The density-driven convection process provides more rapid mass transfer into solution.

Implementation of this 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.

It is envisioned that the process may include one or more long horizontally drilled well bores 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 provides some insight as to the 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 equal volumes of gas can enter the well bore 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 is considered to be advantageous if the injection wells are placed near the bottom of the formation, whether the injection wells consist of horizontal or vertical wells.

In another embodiment, conditions for sequestration of a water-soluble fluid within a water-laden formation 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 said formation, and includes means know to the art to vary one or more parameters. These parameters are selected from the group consisting of:

a) composition of said fluid to be injected into said formation;

b) placement of said fluid injection well in said formation;

c) temperature of said fluid to be injected into said formation

d) rate of injection of said fluid into said formation;

e) injection pressure of said fluid into said formation;

f) numbers of said injection wells placed in said formation;

g) locations and profiles of said injection wells in said formation;

h) pH of said water in said formation;

i) salinity of said water in said formation;

j) density of said water in said formation;

k) volume of said injected fluid;

l) partial pressure of said injected fluid in said formation water; and

m) density of said fluid.

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

Preferably, the fluid comprises a greenhouse gas, as described above.

According to another embodiment, the invention relates to a process for sequestration of a water-soluble fluid within a water-laden formation. According to this embodiment, a computer modeling step as described above is performed. The parameters determined in said model are then replicated on site under real-world conditions with components of an injection well system at the site of said known formation, in order to generate at least one density-driven convection current within said formation to achieve sequestering of said water-soluble fluid using said injection well system.

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, said process comprising: selecting a target water-laden geological formation;providing a well bore of a fluid injection well into said formation, said well bore comprising at least one opening to discharge fluid into said formation;providing a source of said fluid, said source in communication with said injection well;injecting said fluid into said formation from said injection well under conditions of temperature or pressure, or both temperature and pressure, selected to cause said fluid to enter said formation and rise within said formation with sufficient volume, flow rate and density contrast between said fluid and water within said formation to induce a convection current of said fluid and water within said formation, said convection current sufficient to enhance convective mixing of said fluid and said water, relative to fluid injected under conditions which do not induce a convection current.

2. The process of claim 1, wherein said injecting increases the rate of diffusive mass transfer or dissolution of said fluid into said water and flushes additional water substantially laterally into the region of said well bore, thereby increasing storage capacity and storage rate of said fluid in said formation.

3. The process of claim 1, wherein said fluid comprises at least one water-soluble gas and at least one water-insoluble gas, said process further comprising: providing a withdrawal well in said formation; andwithdrawing said water-insoluble gas from said formation through said withdrawal well, thereby providing additional volume in said formation for further sequestration of said water-soluble gas.

4. The process of claim 3, wherein said water-insoluble gas comprising the further step of passing said water-insoluble gas through a gas turbine after withdrawal thereof from said formation to generate electricity.

5. The process of claim 1, further comprising: providing a water injection well into said formation; andinjecting water into said formation to produce a cross current of water within said formation from a region remote from said injection well and to further promote said convective mixing of said fluid with said formation water.

6. The process of claim 1, further comprising providing a plurality of injection wells located within said formation for generating a plurality of convection currents within said formation.

7. The process of claim 1, wherein said fluid is injected at a pressure below the fracture pressure of said formation.

8. The process of claim 1, wherein said fluid is injected at a pressure above the fracture pressure of said formation.

9. The process of claim 1, further comprising the step of injecting additional water into said formation to induce flux of fluid-unsaturated water into said formation in the region of said injection well.

10. The process of claim 1, wherein said injection well is a substantially vertical injection well, a horizontal injection well or a deviated well.

11. The process of claim 1, wherein said injection well defines a path for promoting said convective mixing in said formation.

12. The process of claim 1, further comprising determining optimal placement of at least one opening in said injection well with respect to the configuration of said formation for improving said convection current, thereby further promoting enhanced mixing of said water-soluble fluid with said formation water.

13. The process of claim 1, wherein said formation has an intrinsic permeability of at least 300 mD in the vertical direction.

14. The process of claim 1, wherein said formation has a porosity exceeding 15% with the formation water being saline water.

15. The process of claim 1, wherein one or more of the following parameters are assessed and/or manipulated individually or collectively to enhance said convective mixing of said fluid: a) composition of said fluid to be injected into said formation;b) placement of said fluid injection well in said formation;c) temperature of said fluid to be injected into said formationd) rate of injection of said fluid into said formation;e) injection pressure of said fluid into said formation;f) numbers of said injection wells placed in said formation;g) locations and profiles of said injection wells in said formation;h) pH of said water in said formation;i) salinity of said water in said formation;j) density of said water in said formation;k) volume of said injected fluid;l) partial pressure of said injected fluid in said formation water; andm) density of said fluid.

16. The process of claim 1, wherein said fluid comprises flue gas.

17. The process of claim 16, further comprising enriching the concentration of carbon dioxide within said flue gas prior to injection into said formation.

18. The process of claim 1 wherein said fluid comprises one or more gases selected from the following group: carbon dioxide, nitrogen, methane, NOM, and hydrogen sulfide.

19. A process for determining conditions for sequestration of a water-soluble fluid within a water-laden formation comprising: providing a computer programmed with a computer program stored on a computer readable medium, said program comprising a representation of a known geological formation and at least one injection well for injecting a mixture of soluble and insoluble fluid into said formation, said computer program provided with means to vary one or more parameters selected from the group consisting of:a) composition of said fluid to be injected into said formation;b) placement of said fluid injection well in said formation;c) temperature of said fluid to be injected into said formationd) rate of injection of said fluid into said formation;e) injection pressure of said fluid into said formation;f) numbers of said injection wells placed in said formation;g) locations and profiles of said injection wells in said formation;h) pH of said water in said formation;i) salinity of said water in said formation;j) density of said water in said formation;k) volume of said injected fluid;l) partial pressure of said injected fluid in said formation water; andm) density of said fluid;wherein said computer program is configured to calculate properties of a convection cell generated in said formation arising from density-driven movement of said fluid and formation water within said formation influenced by one or more of said parameters;inputting into said computer some or all of said parameters a through m; and producing a report providing sequestration conditions and preferred injection conditions comprising said one or more parameters.

20. The process of claim 19, wherein said computer program is further provided with means to vary placement of one or more fluid withdrawal wells in said formation.

21. The process of either of claim 19, wherein said computer program is further provided with means to vary placement of one or more water injection wells in said formation.

22. A process for sequestration of a water-soluble fluid within a water-laden formation comprising: providing a computer programmed with a computer program stored on a computer readable medium, said program comprising a representation of a known geological formation, and at least one fluid injection well, said computer program provided with means to vary one or more parameters selected from the group consisting of:a) composition of said fluid to be injected into said formation;b) placement of said fluid injection well in said formation;c) temperature of said fluid to be injected into said formationd) rate of injection of said fluid into said formation;e) injection pressure of said fluid into said formation;f) numbers of said injection wells placed in said formation;g) locations and profiles of said injection wells in said formation;h) pH of said water in said formation;i) salinity of said water in said formation;j) density of said water in said formation;k) volume of said injected fluid;l) partial pressure of said injected fluid in said formation water; andm) density of said fluid;wherein said computer program is configured to calculate properties of a convection cell generated in said formation based on dispersion of fluids in said formation, said dispersion of fluids influenced by said one or more parameters;inputting into said computer some or all of said parameters a through m;manipulating said one or more parameters to generate an effective convection cell;replicating said one or more parameters with components of an injection well system at the site of said formation and thereby generating at least one density-driven convection current within said formation; andsequestering said water-soluble fluid using said injection well system.

23. The process of claim 22, wherein said computer program is further provided with means to vary placement of a plurality of fluid injection wells in said formation.

24. The process of claim 22, wherein said computer program is further provided with means to vary placement of one or more fluid withdrawal wells in said formation.

25. The process of claim 22, wherein said computer program is further provided with means to vary placement of one or more water injection wells in said formation.

26. The process of claim 1, wherein said water-soluble fluid comprises a gas that is not in a supercritical form.

27. The process of claim 1, wherein said water-soluble fluid comprises a gas that is in a supercritical form.