MX2011009122A

MX2011009122A - Process for sequestration of fluids in geological formations.

Info

Publication number: MX2011009122A
Application number: MX2011009122A
Authority: MX
Inventors: Maurice B Dusseault; Roman Bilak
Original assignee: Maurice B Dusseault
Priority date: 2009-03-11
Filing date: 2010-03-11
Publication date: 2011-11-04
Also published as: US20110315386A1; CN102348614A; EP2406152A4; WO2010102385A1; KR20110137786A; AU2010223803A1; EP2406152A1; EA201101204A1; JP2012519587A; CA2751874A1; CA2751874C

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

PROCESS FOR THE SEQUESTRATION OF FLUIDS IN GEOLOGICAL FORMATIONS FIELD OF THE INVENTION The present invention relates to the underground sequestration of fluids in particular to the sequestration of water-soluble gases such as C02 and other greenhouse gases in geological formations loaded with water.

BACKGROUND OF THE INVENTION This invention claims the benefit of United States of America Patent Application No. 61 / 159,335 filed March 11, 2009 and of United States of America Patent Application No. 61 / 173,301 filed April 28. of 2009, whose contents of both are incorporated herein by reference in their entirety.

Human activities have an impact on 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 increasing in anthropogenic greenhouse gas concentrations that are likely to have caused most of the increases in average global temperatures in the half of the 20th century.

The most abundant greenhouse gases on earth include carbon dioxide, methane, nitrous oxide, ozone and chlorofluorocarbons. The most abundantly produced of these by the human industrial activity is CO2.

Several strategies have been conceived for the permanent storage of C02. These forms include the sequestration of gases in several deep geological formations, (including exhausted gas fields and salty aquifers), storage of liquids in the ocean, and storage of solids by reaction of CO2 with metal oxides to produce stable carbonates.

In a process known as geo-sequestration, the C02 generally in supercritical form (SC) is injected directly into the underground geological formations. Oil fields, gas fields, saline aquifer springs, non-mined coal seams and basalt formations filled with saline have been suggested as storage sites. Several mechanisms of physical atropamiento (for example, the highly impermeable rock), the solubility and the geochemical atropamiento are generally waited to avoid the C02 avoiding that it escapes to the surface. Geo-sequestration can also be formed by 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 to store the chemical waste in few cases, and attempts have been made to use such aquifers to sequester C02. The main advantage of saline aquifers is their great potential for storage volume and their common occurrence. One disadvantage of any practical use of saline aquifers for this purpose is their relatively little knowledge about them. The filtration of C02 back into the atmosphere can be a problem in the saline aquifer storage. However, current research shows that several entrapment mechanisms immobilize C02 underground, reducing the risk of filtering.

The densest concentration of C02 that can be placed in a porous formation such as a saline aquifer is when C02 is in a critical, critical state referred to herein as SC-C02. Most sequestration schemes are based on the injection of C02 in this supercritical state when the material behaves as a relatively dense compressible liquid with an extremely low viscosity. Much lower than any liquid formation. The object is to displace most or all of the water in the saline aquifer, replacing 100 percent or some fraction of the porosity with SC-C02.

In a prominent example of such geo-sequestration strategy, the Sleipner project operated by the Norwegian oil and gas company StatoilHydro, separates C02 (from 4 to 9.5 percent content) of natural gas recovered from a nearby gas well. The separated C02 is converted to the super critical form (SC-C02) and injected into a layer of sand containing salt water, called the Utsira formation, which lies 1000 meters below the seabed. Several seismic examinations have been carried out to investigate if the storage of C02 remains safe.

In the injection of gaseous C02 (for example not in supercritical form) in a formation of its surface in solution with water at a maximum solubility limit is a desirable approach to the sequestration of this gas that is proposed with mixed success in the past . Prior to the present invention, a problem of C02 sequestration by dissolution in an aqueous solution within a geological formation has been that the pore volume of the formation is occupied by less than the efficient form that the occupation that occurs with the injection of SC-C02. Once the active injection phase is completed, there is no more active mixing within the porous medium. Then, the dissolution of C02 within the formation of water is controlled by the concentration differences, the contact area and the length of the diffusion path. The mass transfer rates associated with such diffusion processes driven by gradient concentration in the porous medium are slow and it is expected that thousands of years have been required to approach a complete dissolution of C02 in the aqueous phase within the geological formation .

The "problem of diffusion of gradient of long-term concentration of reduced mixing" still persists with the injection of SC-C02. At the high injection rates proposed for the SC-CO2 sequestration, the SC-CO2 will first displace the water and occupy the pore space directly, with only a small amount of mixing occurring convective and dispersive in the displacement fronts. When the SC-CO2 is injected over time, a contact growth area is generated between the two fluids and a zone of dissolution is generated. The SC-CO2 then dissolves in the salt water throughout this contact area, mainly as the result of diffusion and dispersion associated with a forced advection caused by pressure-driven flow (from the injection of SC-CO2 under Pressure) .

Due to the density difference between salt water and SC-CO2, there are also gravity forces that will tend to segregate liquids in the saline aquifer: the SC-CO2 will be raised above the densest water, forming a low "cake" the areas that are finer grain with poorer permeability (fine deposits, aleurolites, etc.). This not only removes part of the mixing component that will arise in a more uniform displacement, it also leads to a significant inefficiency in the access to pore volumes in the formation: parts of the formation remote from the injection point are largely inaccessible to any storage mechanism (displacement by or by dissolution of C02 in solution).

Once the injection ceases, only a small fraction of the SC-CO2 has been put into solution due to mixing and effects diffusive in the displacement fronts, and due to the advection drive force (injection pressure) ceases. CO2 can no longer be mixed in advection form with water, and this leaves only diffusion effects that are driven only by the CO2 concentration gradients in the water.

In the saline aquifer formation, after injection, SC-C02 remains high in the area above the injection site due to its lower density. This qualified density system provides a stabilizing force that also reduces the rate of any diffusion process. Initially, the diffusion front is relatively narrow and distinct with a large surface area between the C02 and the water and the solution process happens relatively efficiently. But over time this front grows and widens vertically. As a result, the front becomes less different. This produces a thicker transition or diffusion zone with a smaller surface area between C02 and water that has a low C02 concentration (for example the contact-dissolution-transition area between the SC-C02 and the water of C02). formation is enriched with C02 The vertical distance between the water from the remote regions of the formation and the SC-C02 grows as unsaturated water-C02 which is also out of the SC-C02, so the diffusion / solution process slows down As a result this can take many thousands of years for the C02 to enter solution, since the movement in the water place in the remote regions of the formation (to facilitate the C02 in solution with the process of water) is very slow. In this phase, there is no convection mixing between the SC-C02 and the formation water due to the graduated density system.

Graduated systems of density in a porous medium are extremely stable over long periods. Once the active mixing ceases, it will typically take thousands of years for the SC-CO2 to dissolve in the water phase under typical sequestration conditions. There is simply no mechanism to bring "new water" into contact with SC-CO2, and the process is totally dominated by slow diffusion.

SYNTHESIS OF THE INVENTION Although the safe and permanent disposal of C02 represents a major challenge, as mentioned in detail above, the long-term disposal of other water-soluble gases and fluids also presents similar challenges, such as to refer to the greenhouse effect as well. as to other needs. The present invention also relates to the permanent arrangement (in essential form of a wide variety of water-soluble fluids by providing processes and systems for the mixing and dispersion of such fluids within a geological formation charged with water such as a saline aquifer. to improve kidnapping conditions.

The objects of the present invention include: a) providing a method for geo-sequestering water-soluble fluids, in particular but not limited to gases, by injecting the fluid into a water-charged formation in a manner which improves the mixing of the fluid with the formation of water to improve the dissolution of the fluid, through the generation of convection currents in place or convection cells. b) to increase the volumetric extension of the dissolution process in the geological formation, thereby improving the storage capacity for water-soluble fluids (such as C02) within the formation. c) to provide a process to improve both the separation of the water-soluble gases from a mixture of soluble gases and insoluble gases and the sequestration of the soluble gases in a geological formation, and to remove the insoluble gas from the geological formation for preserve the volume of the available geological formation to accommodate the soluble dissolved gas. d) To provide a method to determine the conditions for the sequestration of a water soluble fluid in a geological training using a computer model of training and computer simulations of fluid injection. e) to provide an alternative method for improving the sequestration of water-soluble gases in geological formations that do not require a pre-gas injection separation or a conversion of the injected gases to a supercritical form.

In one aspect of the invention, a process for sequestering a water-soluble fluid is provided by injecting the fluid from an injection well into a geological formation charged with water under selected temperature and / or pressure conditions to cause the fluid enters and disperses within the formation with a sufficient volume, pressure and density contrast with the formation water to generate a convection current or a convection cell within the formation. A specific geological formation comprising a selected aquifer which is bounded above and optionally and also down by low permeability layers to contain the water carrying the formation in a stable state. The said low permeability layer may 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 as to generate one or more convection cells and therefore improve the dispersion, dissolution and sequestration of the fluid or a fractionsoluble in water thereof, within a large region in the formation.

According to this aspect, the initial movement of the fluid in the formation is expected to occur as a low density displacement front that moves outward in the formation as the fluid seeps through the formation. In the case of gas, the gas can be initially dispersed as bubbles or pockets of undissolved gas. This displacement front will displace the water within the pore spaces of the formation which is then urged to flow outward and away from the diffusion area. This associated water flow contributes to the development of convection cells in the place or convection currents. The injected fluid will subsequently develop into a low density pen that extends laterally as well as moving vertically up through the formation. This plume is a region of lower density than water within the adjacent parts of the formation where the injected fluid is not present. A lateral contrast in the density of the average fluid is therefore generated. This process induces a convection flow cell driven by density contrast. Therefore, a density-driven flow cell is generated where the region of lower density fluid (such as water which is heated and / or contains an undissolved gas) rises vertically because it is less dense than the water of the adjacent formation. This denser water then flows laterally to replace the density lower fluid that flows vertically, holding a large-scale convection cell.

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

In one embodiment, C02 (usually combined with another gas) is injected under suitable conditions as described above in a formation containing water which is unsaturated with CO2. The unsaturated water from the remote regions in the formation then moves to the region of the injection well as a result of the action of the large convection cell, and replaces the water rich in local CO 2 (in the vicinity of the injection well) with C02 free water, which can strip the C02 out of the injected gas more efficiently. In addition, the large-scale convection cell not only increases the diffusion mass transfer of C02 in the solution, it also acts to bring the remote C02-free water to the region of the injection well orifice, thus augmenting the effective volume in the formation that can be accessed through an injection well as a result of the draining action. Therefore, the process of density-driven convection provides a rapid mass transfer from C02 to solution and improves storage capacity for geo-hijacking.

The consequences of implementing this density-driven convection process are that the short-term storage capacity of the formation increases and long-term capacity also increases through the lateral water flow access with the maximized mixing.

The process may include injecting a fluid consisting of a mixture of insoluble and water soluble gases. In this regard, a withdrawal well is provided, which is in fluid communication with the aquifer or in a communication with an insoluble gas bag in the formation, for the removal of non-sequestered insoluble gas. The water-insoluble gas is removed from the formation with the withdrawal well, thereby providing an additional volume in the formation for additional sequestration of the gas or the water-soluble liquid.

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

According to another aspect, a plurality of fluid injection wells can be provided to generate a plurality of convention currents in the formation, thereby providing an improved mixing of the gas or the water soluble liquid in the formation. The configuration of the wells can be designed to promote the development of sustained convection currents in the formation. The injection wells can be horizontal injection wells, vertical injection wells or diverted wells. In some embodiments, the injection well defines a trajectory that essentially intersects the formation at a vertical, horizontal angle or at a deviated angle from the vertical.

In some embodiments, the process further includes determining the proper placement of one or more openings in the injection weight for fluid discharge, so that the openings are sufficiently spaced below the upper face of the formation to generate a convection current to promote improved mixing of the water-soluble fluid with the formation water.

In some embodiments, the injected fluid is a combustion gas, as used herein, the term "combustion gas" refers to the gas produced by industrial combustion such as the furnace, the place of fire, the incinerator, the generator steam or a recovery process (such as recovery of natural gas from a well). Such gases typically leave the atmosphere through a tube. The term "combustion gas" encompasses combustion exhaust gas produced in fossil fuel or biomass burning power plants. The composition of the fuel gas depends on what is being burned, but it usually consists mainly of nitrogen derived from the combustion air, CO2, and water vapor as well as the excess 02 (also derived from the combustion air). The fuel gas may also contain methane, (CH), carbon monoxide, hydrogen sulfide, nitrous oxides and sulfur oxides as well as particles.

In another aspect of the invention, a process for determining the conditions for sequestering a water-soluble fluid is provided. The process uses a modeling of structure and conditions by computer of a formation loaded with known water. Computer modeling programs to stimulate formations are known in the art. The expert will have knowledge of modifying an existing program or will be able to develop a new program using a routine methodology to simulate water loaded formations, as well as the components and conditions used in carrying out the processes described here. In accordance with this aspect of the invention, a computer program stored in 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 well or wells of fluid injections in the formation, the partial pressure of the gas in the formation, the. rate of fluid injection into said formation, the numbers of injection wells placed in the formation, the pH of the water in said formation, the salinity of the water in said formation, and the density of the water in said formation. The computer program is configured to calculate the properties of a convection cell generated in the formation based on the 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, kidnapping conditions within the training. The conditions of the sequestration include the parameters used in certain properties of the convection cell which are generated when the recommended conditions are met.

In some embodiments, the computer program is further provided with means for simulating the variation of placement of a plurality of fluid injection wells, gas removal wells and / or injection wells in the formation.

The process for determining the conditions for sequestering a water soluble fluid described above can be practiced by configuring one or more injection wells and, optionally, one or more withdrawal wells and / or water injection wells for the proper placement inside said training according to the parameters used to produce the convention cell in computer stimulation.

The term "gas" as used herein, unless it has a different meaning is expressed or implies means, such as a gas or a combination of gases. Similarly, the term "liquid" means either a liquid or a combination of liquids unless a different meaning is expressed or implied.

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

As used herein, the term "insoluble" is not used as an absolute term, but as a relative term which means "poorly soluble" or essentially less soluble than a substance recognized by a person skilled in the arts as "soluble".

As used herein, the terms "formation" or "water-charged formation" refer to a surface layer of rock that supports water or consolidated materials that support water, such as gravel, sand, clay, that contain a sufficient amount of water inside their pores to allow the generation of a convection current there. A saline aquifer is not a limiting example of the geological formation suitable for the process described here. The related term "target formation" refers to the selected formation for injection or bases for sequestration.

As used herein the term "formation water" or "water" refers to the water present within said formation. The formation water may be present in the formation as a volume water phase or it may be secreted in bags or droplets within a geologic matrix of sand, silt or clay. The water can be saline or charged with other dissolved substances.

As used herein, the terms "low permeability" mean less than about 100 millidarcy (mD) and the term "high permeability" means more than about 300 mD.

As used herein, references to C02 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 present invention will be apparent from reading the detailed description that follows and with reference to the drawings.

BRIEF DESCRIPTION OF THE DRAWINGS FIGURE 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 the gas injection, and also showing a gas source of chimney and components to process the gas before injection. Cross currents are also shown.

FIGURE 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 the gas injection. Cross currents are also known.

FIGURE 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 stream produced by gas injection. Cross currents are also shown.

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

DETAILED DESCRIPTION In the following description of the embodiments, similar characteristics are mentioned with respect to similar reference numbers.

Figure 1 shows an incorporation of the process for the injection of the flue gas to sequester the greenhouse gas components thereof. It will be understood that similar processes can be used to sequester other fluids. Figure 1 illustrates a schematic cross-sectional view of the underground formation 10 located in the depth below the surface of the land 5. The formation 10 consists of a deeply buried deep-permeability salt aquifer. The formation is limited in its upper margin and preferably in its lower margin by upper and lower layers 60 and 80 having low permeability. The array 10 may be arranged in various orientations and configurations, such as a generally flattened horizontal orientation or an inclined configuration or other configuration (e.g., see Figure 3). The formation 10 must have a region with a sufficient upper part spacing to allow the generation of convection currents within the formation water, as will be described in more detail here. It is believed that 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 Figure 1, which is the vertical distance between the upper and lower margins of the formation. This region with a vertical spacing of at least Y must also extend horizontally by a distance of at least about 1, 000 meters. The injection well 12 has at least one discharge opening 13 within this region. The range of vertical spacing Y may depend on other factors such as the pressure and temperature of the gases emanating from the discharge opening 13 of the injection well 12. However, the inventors do not wish to be bound by the theory, and it is contemplated that under other suitable conditions an aquifer with a smaller vertical spacing, or where the region with this minimum vertical spacing extends horizontally to a smaller extent than the previous one, can be used for the present invention.

A gas source 25 is provided in which the gas usually consists of a gas mixture. In the case of flue gas (unprocessed or enriched with C02), the gas usually consists of a mixture of insoluble and water-soluble gases (such as nitrogen) in the described example, the source comprises a gas source of flue pipe such as a fossil fuel burning power plant or other installation. It will be evident that any source of stationary gas can essentially serve as the source. The gas mixture includes a water soluble gas 16 and a water insoluble gas 18. Preferably, the water insoluble gas is either a greenhouse gas or another contaminant. More preferably, the water soluble gas is one or more of the following: C02, N0X, or hydrogen sulfide. More preferably, the greenhouse gas is C02. Preferably, the water insoluble gas is nitrogen or methane. The source 25 can be located near or above the formation 10 or in some area removed from it, so that the gas is piped to an injection site 40. The raw gas can be derived from multiple sources, for example, several fuel burning facilities, where the raw gases are piped to a common waste facility.

According to another aspect, the soluble gas component can be enriched by known means, such as to improve the efficiency of the sequestration process. Such enrichment can be done at source 25 of the gas or immediately before the sequestration.

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

In order to provide sufficient pressure, heating and other conditions of the flue pipe gas, the gas is piped from a source 25 to a gas treatment unit 40 before being fed into an injection well 12. The unit of gas treatment pressurizes and heats the unprocessed gas and can optionally enrich certain gas components. The pressure and temperature conditions depend in part on the conditions within the aquifer including its permeability, the formation pressure, the salinity of the water within the aquifer as well as the composition of the gas that is being injected.

The pressurized and optionally heated gas is fed into the injection well 12 and is introduced into the aquifer through the openings 13. The gas is injected into the formation 10 with sufficient volume and delivery pressure and optionally adding heat to the gas. 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. The injection of the heated gas initially generates a current into the water of the formation immediately adjacent. This current develops as a result of the upward movement of the undissolved gas bubbles formed within the formation water, and optionally the elevated temperature of the injected gas, displacing the water of the natural formation from the pore space of the formation. The gas is initially dispersed 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 disperses in the formation water due to horizontal dispersion during vertical flow and formation heterogeneity. The gas pen thus tends to spread laterally as well as to move vertically. The corresponding movements of the formation water and the gas plume generate one or more cells or convection currents 14 within said formation. As additional gas is fed into the formation, the resulting plume will continue to generate cells or convection currents 14 within the formation water in the region of the injection well due to differences in density between the formation water of the environment and the plume . This current includes a component that flows laterally and rises upwards, as a result of the dispersive movement of the injected gas plume. The dimensions of this current depend at least in part on the dimensions of the aquifer including its vertical spacing and density, the driving pressure, the volume or flow rate and the temperature of the injected gas. The soluble gas 16 is dissolves into the formation water, facilitated by the improved mixing action caused by convection currents / cells. The insoluble gas 18 is separated due to its insolubility, and rests to accumulate in a gas bag 20 which is usually located below the upper low permeability formation 60.

At least one and preferably a plurality of withdrawal wells 22 are provided. The withdrawal wells 22 are employed to vent the water-insoluble gas 18 to outside the formation 10, thereby providing an additional volume in the formation 10 for further sequestration of the water-soluble gas 16. The withdrawal wells 22 extend inside the formation 10, at least in the upper part thereof, these wells include the inlet openings 23 located within the formation 10, in places where the bags or gas lids are expected to accumulate. The well or withdrawal wells 22 can provide a conduit to a surface facility 50 where the insoluble gas can be either vented to the atmosphere, if for example, the insoluble gas is nitrogen or inside a capture or storage facility. gas treatment, if for example, the insoluble gas represents a useful product such as methane.

The ventilation process can be relied on the internal pressure inside the gas bag to vent the gas, or alternatively the accumulated gas can be pumped in order to removing more rapidly and completely the insoluble gases from the formation 10. Preferably, a part of the withdrawal well 22 is horizontal to allow it to extend through an extended region of the gas bag 20.

The ventilation process can be designed to extract some of the energy present in the compressed insoluble gases by passing the gases vented at high pressure through a gas turbine to generate electricity, after such gases have been vented from the bag Of gas.

In Figure 2 another embodiment of the process is shown as a schematic cross-sectional view of a geology formation 10 with multiple horizontal injection well openings and multiple withdrawal wells 22 showing the directions of the convention currents 14 produced by the injection of gas. Transverse currents 24 are also shown which are influenced by the development of convection currents 14. As described in the embodiment of Figure 1, the water-insoluble gas 16 becomes dispersed within the formation 10 as a pen of a fluid of lower density and generates a convection current 14 while the water-insoluble gas 18 rises towards a gas bag 20. The transverse currents 24 promote further mixing between the water-soluble gas 16 and the formation of water. Also described above are four retirement wells 22 that are employed to remove the insoluble gases in water outside the formation 10, thereby providing an additional volume in the formation 10 for further sequestration of the. water soluble gas 16.

The large-scale convection cells act to bring the remote water to the region of the orifice of the injection well through a "cross current" 24 increasing the effective volume in said formation 10 that can be accessed through an injection well. by "draining" the lateral water into the well orifice region.

In Figure 3, another embodiment of the process is shown - in 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 1 produced by the injection Of gas. As described above, the water soluble gas 16 is dispersed within the formation as a plume of a lower density fluid and generates a convection stream 14 while the water insoluble gas 18 rises towards the gas bag 20. The transverse currents 24 are shown through the formation 10 towards the gas bag 20.

Shown in Figure 4, in another embodiment of the process, there is a schematic representation of a gas sequestration arrangement placed in the formation 10 showing a well of gas injection 12 for injection of gas mixture 35, withdrawal wells 22 and water injection wells 26 for injection of water. The gas outlet region of the gas injection well 12 is positioned near the lower limit of the formation 10. Each withdrawal well 22 extends inside the gas bags 20 within the formation 10 for removal of the insoluble gas. contained therein, which has been separated from the injection gas mixture by differential solubility of the respective components of the mixture 35. The additional water 28 can be injected into the formation through one or more water injection wells. 26. This added water can then flow into the formation matrix 10 as indicated by the arrows 32 to carry the additional water into the formation 10 and promote the mixing of the gas mixture 35 in the formation 10.

Example 1: Sequestration of Carbon Dioxide in Saline Acuifero by Convection Powered by Density In this example, the gas mixture that is injected includes C02, which is highly soluble in water, together with other gases which are less soluble in water under the conditions of temperature, pressure, pH and salinity within said formation. The gas mixture is injected at a high rate into a location near the base of the formation. The formation has a considerable vertical extension, or a depth which provides a vertical extension of around 20 meters. For example, not including other possible cases that may be acceptable, a desirable salt formation will be located at a depth of 1000 meters within the stratum and a greater lateral extent. This will have an intrinsic permeability of at least one Darcy in the vertical direction. The formation will have a porosity that exceeds 15 percent with the pore fluid being saline water. This is considered more desirable if the formation has a natural depth (inclination) of up to 20 degrees. It is advantageous if the formation is limited by a superior formation of rocks of low permeability to the mobile phases involved in the sequestration process, including gases and water.

Preferably, the injection pressure is greater than the formation pressure within the salt water formation by an amount which is determined by the porosity and the permeability of the host rock, together with other secondary factors. For example, an injection well within a horizontal section of 1000 meters long is drilled in a 1,500 meter deep saline aquifer which has a natural formation pressure of 15 MPa. A mixture containing C02 and other gases is injected uniformly along the length of the horizontal section at a pressure greater than 15 Pa. The injection pressure is usually somewhat below the fracture pressure of the formation. However, in some circumstances where it is considered necessary to encourage and promote vertical flow within the training (where it is desired to increase the fluid flow rate and improve fluid distribution in the formation), the injection pressure may be slightly higher than the natural fracture pressure of the formation, so that limited vertical fractures of length are generated in order to increase the length of mixing of the water and gas contact zone. Those skilled in the art will be able to determine an adequate injection pressure or pressure range to induce the formation of density-driven convection currents within the target forming water. One of the relevant considerations is the extent to which it is desired to increase the sweeping efficiency, or the extent of gas distribution in the formation laterally or vertically, of the gas injected.

The gas can optionally be injected at an elevated temperature above the ambient temperature of the formation water, so as to further improve the density contrast between the injected gas and consequently the water in the formation which is charged with the injected gas. , and the water of the surrounding formation.

Initially, under the high pressure gradients near the well hole, the injection can lead to a local displacement mechanism, with the liquid in the pores being mainly displaced physically by the gas that is entered. In a suitable formation, when increasing the size of the injected zone, the pressure of impulse decreases (due to the radio more large, the pressure drops due to radial spacing), and the height of the gas column increases leading to gravity segregation 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, more feasibly through a tortuous path due to the presence of small flow impedance barriers such as scarce currents or small bodies of sand in fine grain.

Due to the dispersion of the vertical flow and the heterogeneity of the formation, the gas will tend outwards in a feather that moves upwards which extends laterally as well as moving vertically. This pen represents the region of pore fluid density lower than the adjacent parts of the salt formation that do not have free gas, therefore a lateral contrast in the density of the average fluid is generated which creates a convection flow cell driven by large density difference.

This density contrast will increase greatly in the forced mixing in place between the injected gas and the formation water. The water is taken from the remote locations in the formation to the injection site as a result of the creation of a large convection cell, and this partly replenishes the local water with C02-free water, which can therefore disrobe the C02 out of the gas injected more efficiently. Therefore, the Large-scale convection cell not only increases the transfer of diffusive mass of C02, inside the solution, but also acts to bring the remote water to the injection well orifice region, increasing the effective volume in the formation that can to be accessed through the injection well by "draining" the lateral water into the well hole region. The lower solubility gases remain as undissolved gaseous phases and spread laterally and essentially upward, where they can be removed by withdrawal wells such as passive drainage wells. The density-driven convection process provides a rapid mass transfer within the solution.

The implementation of this process increases the short-term storage capacity of the soluble gases in the formation as well as increases the long-term capacity by maximizing the mixing and promoting the lateral water flow. The global sequestration process may involve the preliminary passage of a flue gas mixture (for example, containing about 13 percent C02 and 87 percent N2) through a membrane or other type of enrichment system. gas or purification so that the gas injected is 25 percent-80 percent C02, with the remainder being essentially N2; such gas enrichment process / C02 will also help with the improved storage capacity at the site and particularly with the rate at which the soluble gases (C02 in this embodiment) can be injected and subjected to contact with the waters of training. The specific content of the injected gas can be varied in response to boost economic and environmental factors, since the process does not depend on having a specific composition of the gas injected.

It is envisaged that the process may include one or more horizontally large well drilled holes for injection completed with a cementless slotted liner. Such wells can be placed in a decentralized and parallel configuration, with the distance between the wells depending on the analysis, such as computer modeling that provides some perspective of the effective convection cell size. The length of the wells can be designed based on the rate at which the gas can enter the formation at an approximate rate to maximize mass transfer and convection mixing.

Each well can be equipped with an internal tubing system that can distribute the gas injection evenly along the length of the well so that equal gas volumes can enter without the well hole in several places over time in a way known by itself in art.

The well can be operated to maximize the contact of the CO2, with the water of saline formation by controlling on the surface the volume, the rate and the pressure of the gas stream what is 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, the conditions for the sequestration of the water-soluble fluid within a water-charged formation are determined by a computer-implemented simulation. The process consists of providing a computer which is programmed by a computer program stored in a medium that can be read by computer. The program comprises a representation of a known geological formation in a manner known in the art. The computer is programmed to represent at least one injection well for injecting a fluid mixture, insoluble and soluble within said formation, and includes means known in 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) placing said fluid injection well in said formation; c) temperature of said fluid to be injected into said formation; d) injection rate of said fluid into said formation; e) injection pressure of said fluid into said formation; f) numbers of 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; 1) partial pressure of said fluid injected into said formation water; m) density of said fluid.

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

The computer program is also provided with means to radiate the placement of one or more water injection or fluid withdrawal 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 sequestering a water-soluble fluid within a water-charged formation. According to this incorporation, a step of computer modeling is described above and is carried out. The parameters determined in said model are then duplicated on site and under real conditions in the world 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 the sequestration 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 can de-vary or vary the embodiments described in detail herein, while still remaining within the scope of this invention as defined in this patent description as a whole, including the claims.

Claims

R E I V I N D I C A C I O N S

1. A process for the sequestration of a water-soluble fluid within a formation charged with groundwater, said process comprises: select a geological formation loaded with target water; providing a well orifice of a fluid injection well in said formation, said well orifice comprising at least one opening for discharging the fluid into said formation; provide a source of said fluid, said source is in communication with said injection well; injecting said fluid in said formation from said injection well under conditions of temperature or pressure, or both temperature and pressure, selected so that the fluid enters said formation and rises within said formation with a sufficient volume, a flow rate and density contrast between said fluid and the water within said formation to induce a convection current of said fluid and the water inside said formation, said convection current is sufficient to improve the convection mixing of said fluid and said water, in relation to the fluid injected under conditions which do not induce a convection current.

2. The process as claimed in clause 1, characterized in that the injection increases the rate of transfer or dissolution of the diffusive mass of said fluid into said water and drains the additional water essentially laterally into the region of said orifice. well, thereby increasing the storage capacity and the storage rate of said fluid in said formation.

3. The process as claimed in clause 1, characterized in that said fluid comprises at least one gas soluble in water and at least one gas insoluble in water, said process further comprising: provide a retirement well in said formation; Y withdrawing said water-insoluble gas from said formation through the withdrawal well, thereby providing an additional volume in said formation for further sequestration of said water-soluble gas.

4. The process as claimed in clause 3, characterized in that said water insoluble gas comprises the additional step of passing said insoluble gas in water to through a gas turbine after its removal from said formation to generate electricity.

5. . The process as claimed in any one of clauses 1 to 4 further characterized because it comprises: provide a water injection well within said information; Y injecting the water into said formation to produce a cross-flow of water within formation from a remote region from said injection well and to further promote said convection mixing of said fluid into said formation water.

6. The process as claimed in any one of clauses 1 to 5 further characterized in that it comprises providing a plurality of injection wells located within said formation to generate a plurality of convection currents within said formation.

7. The process as claimed in any one of clauses 1 to 6, characterized in that said fluid is injected at a pressure below the fracture pressure of said formation. 4

8. The process as claimed in any one of clauses 1 to 6, characterized in that said fluid is injected at a pressure above the fracture pressure of said formation.

9. The process as claimed in any one of clauses 1 to 8 further characterized in that it comprises the step of injecting additional water into said formation to induce the flow of unsaturated water and fluid into said formation in the injection well region. .

10. The process as claimed in any one of clauses 1 to 9, characterized in that said injection well is an essentially vertical injection well, a horizontal injection well or a deviated well.

11. The process as claimed in any one of clauses 9 to 10 characterized in that the injection well defines a path to promote said convection mixing in said formation.

12. The process as claimed in any one of clauses 1 to 11 further characterized in that it comprises determining the optimal placement of at least one opening in said injection well with respect to the configuration of said formation to improve the flow of convection, therefore further promoting the improved mixing of said water-soluble fluid with said forming water.

13. The process as claimed in any one of clauses 1 to 12, characterized in that said formation has an intrinsic permeability of at least 300 mD in the vertical direction.

14. The process as claimed in any one of clauses 1 to 13 characterized in that said formation has a porosity that exceeds 15 percent with the formation water being saline water.

15. The process as claimed in any one of clauses 1 to 14 characterized in that one or more of the following parameters are evaluated and / or manipulated individually or collectively to improve said convection mixing of said fluid: a) composition of said fluid to be injected into said formation; b) placing said fluid injection well in said formation; c) temperature of said fluid to be injected into said formation; d) injection rate of said fluid into said formation; e) injection pressure of said fluid into said formation; f) numbers of 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; 1) partial pressure of said fluid injected into said formation water; m) density of said fluid.

16. The process as claimed in any one of clauses 1 to 15, characterized in that the fluid comprises flue gas.

17. The process as claimed in clause 16, further characterized in that it comprises the step of enriching the concentration of carbon dioxide within said fuel gas prior to injection into said formation.

18. The process as claimed in any one of clauses 1 to 17, characterized in that said fluid comprises one or more gases selected from the following group: carbon dioxide, nitrogen, methane, N0X, and hydrogen sulfide.

19. A process for determining the conditions for sequestering a water-soluble fluid within a water-charged formation comprising: providing a computer program with a computer program stored in a medium that can be read by computer, said program comprising a representation of a known geological formation and at least one injection well for injecting a mixture of a soluble and insoluble fluid within said training, said computer program being 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) placing said fluid injection well in said formation; c) temperature of said fluid to be injected into said formation; d) injection rate of said fluid into said formation; e) injection pressure of said fluid into said formation; f) numbers of 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; 1) partial pressure of said fluid injected into said formation water; m) density of said fluid. wherein said computer program is configured to calculate the properties of a convection cell generated in said formation arising from the movement driven by density of said fluid and formation water within said formation influenced by one or more of said parameters; insert some or all of said parameters from "a" to "m" into said computer; and producing a report that provides sequestration conditions and preferred injection conditions comprising one more of said parameters.

- 20. The process as claimed in clause 19, characterized in that said computer program is further provided with means for varying the placement of one or more fluid withdrawal wells in said formation.

21. The process as claimed in any one of clauses 19 or 20, characterized in that said computer program is further provided with means for varying the placement of one or more water injection wells in said formation.

22. A process for sequestering a water-soluble fluid within a water-charged formation comprising: providing a computer programmed with a computer program stored in a medium that can be read by computer, said program comprises a representation of a known geological formation, and at least one fluid injection well, said computer program provided with means for vary one or more parameters selected from the group consisting of: a) composition of said fluid to be injected into said formation; b) placing said fluid injection well in said formation; c) temperature of said fluid to be injected into said formation; d) injection rate of said fluid into said formation; e) injection pressure of said fluid into said formation; f) numbers of 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; 1) partial pressure of said fluid injected into said formation water; n) density of said fluid. wherein said computer program is configured to calculate the properties of a convection cell generated in said formation based on the dispersion of fluids in said formation, said fluid arrangement is influenced by said one or more parameters-: put inside this computer some or all of the parameters of the letter a to m; manipulating said one or more parameters to generate an effective convection cell; duplicating 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; Y sequestering said water-soluble fluid using said injection well system.

23. The process as claimed in clause 22, characterized in that said computer program is further provided with means for varying the placement of a plurality of injection wells in said formation.

24. The process as claimed in any of clauses 22 or 23, characterized in that said computer program is further provided with means to vary the placement of one or more fluid withdrawal wells in said formation.

25. The process as and as claimed in any of clauses 22 or 24, characterized in that said computer program is further provided with means to vary the placement of one or more water injection wells in said formation.

26. The process as claimed in any of clauses 1 or 25, characterized in that said water-soluble fluid comprises a gas that is not in super-critical form.

27. The process as claimed in any of clauses 1 or 25, characterized in that the water-soluble fluid comprises a gas that is in a supercritical form. SUMMARIZES A process for the geo-sequestration of a water-soluble fluid includes the selection of a geological formation laden with limited target water by a superior formation of low permeability, providing an injection well inside the formation and injecting the fluid into the well. injection 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 convection current driven by a formation water density which promotes the improved mixing of the water-soluble fluid with the formation water.