US20110315386A1 - Process for sequestration of fluids in geological formations - Google Patents

Process for sequestration of fluids in geological formations Download PDF

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US20110315386A1
US20110315386A1 US13/255,438 US201013255438A US2011315386A1 US 20110315386 A1 US20110315386 A1 US 20110315386A1 US 201013255438 A US201013255438 A US 201013255438A US 2011315386 A1 US2011315386 A1 US 2011315386A1
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water
fluid
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gas
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Maurice B. Dusseault
Roman Bilak
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    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B41/00—Equipment or details not covered by groups E21B15/00 - E21B40/00
    • E21B41/005—Waste disposal systems
    • E21B41/0057—Disposal of a fluid by injection into a subterranean formation
    • E21B41/0064—Carbon dioxide sequestration
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21F—SAFETY DEVICES, TRANSPORT, FILLING-UP, RESCUE, VENTILATION, OR DRAINING IN OR OF MINES OR TUNNELS
    • E21F17/00—Methods or devices for use in mines or tunnels, not covered elsewhere
    • E21F17/16—Modification of mine passages or chambers for storage purposes, especially for liquids or gases
    • B—PERFORMING OPERATIONS; TRANSPORTING
    • B65—CONVEYING; PACKING; STORING; HANDLING THIN OR FILAMENTARY MATERIAL
    • B65G—TRANSPORT OR STORAGE DEVICES, e.g. CONVEYORS FOR LOADING OR TIPPING, SHOP CONVEYOR SYSTEMS OR PNEUMATIC TUBE CONVEYORS
    • B65G5/00—Storing fluids in natural or artificial cavities or chambers in the earth
    • Y—GENERAL TAGGING OF NEW TECHNOLOGICAL DEVELOPMENTS; GENERAL TAGGING OF CROSS-SECTIONAL TECHNOLOGIES SPANNING OVER SEVERAL SECTIONS OF THE IPC; TECHNICAL SUBJECTS COVERED BY FORMER USPC CROSS-REFERENCE ART COLLECTIONS [XRACs] AND DIGESTS
    • Y02—TECHNOLOGIES OR APPLICATIONS FOR MITIGATION OR ADAPTATION AGAINST CLIMATE CHANGE
    • Y02C—CAPTURE, STORAGE, SEQUESTRATION OR DISPOSAL OF GREENHOUSE GASES [GHG]
    • Y02C20/00—Capture or disposal of greenhouse gases
    • Y02C20/40—Capture or disposal of greenhouse gases of CO2

Definitions

  • the present invention relates to subsurface sequestration of fluids, and in particular to the sequestration of water-soluble gases such as CO 2 and other greenhouse gases in water-laden geological formations.
  • CO 2 In a process known as geo-sequestration, CO 2 , 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 CO 2 from escaping to the surface. Geo-sequestration can also be performed for other suitable gases.
  • SC supercritical
  • 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 CO 2 .
  • 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 CO 2 back into the atmosphere may be a problem in saline aquifer storage.
  • current research shows that several trapping mechanisms immobilize the CO 2 underground, reducing the risk of leakage.
  • the densest concentration of CO 2 that can be placed in a porous formation such as a saline aquifer is when CO 2 is in a supercritical state—referred to herein as SC-CO 2 .
  • SC-CO 2 supercritical state
  • Most sequestration schemes are based on injection of SC-CO 2 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-CO 2 .
  • the Sleipner project operated by the Norwegian oil and gas company StatoilHydro, separates CO 2 (4 to 9.5% in content) from the natural gas recovered from a nearby gas well.
  • the separated CO 2 is converted to the supercritical (SC-CO 2 ) form and injected into a salt water-containing sand layer, called the Utsira Formation, which lies 1000 m below the sea bottom.
  • the SC-CO 2 In a saline aquifer formation, after injection, the SC-CO 2 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.
  • the diffusion front is relatively narrow and distinct with large surface area between the CO 2 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 CO 2 and water that has a low CO 2 concentration (i.e. the transition-dissolution-contact area between the SC-CO 2 and the formation water becomes enriched with CO 2 .
  • Density graded systems in porous media are extremely stable over long times. Once active mixing ceases, it will take thousands of years for SC-CO 2 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-CO 2 , and the process becomes totally dominated by slow diffusion.
  • 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 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.
  • 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.
  • 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.
  • 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.
  • CO 2 (usually combined with other gas) is injected under suitable conditions as described above into a formation that contains water which is unsaturated with CO 2 .
  • 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) CO 2 -rich water with CO 2 -free water, which can strip the CO 2 out of the injected gas more efficiently.
  • the large-scale convection cell not only increases the diffusive mass transfer of CO 2 into solution, it also acts to bring remote CO 2 -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.
  • the density-driven convection process provides rapid mass transfer of CO 2 into solution and enhanced storage capacity for geo-sequestration.
  • the process may comprise injecting a fluid consisting of a mixture of water-soluble and insoluble gases.
  • 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.
  • 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.
  • the injection well defines a path that substantially intersects the formation vertically, horizontally or at a deviated angle from the vertical.
  • 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.
  • the injected fluid is flue gas.
  • 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.
  • 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, CO 2 and water vapor as well as excess O 2 (also derived from the combustion air). Flue gas may further contain methane (CH 4 ), carbon monoxide, hydrogen sulfide, nitrous oxides and sulfur oxides, as well as particulates.
  • a process for determining conditions for sequestration of a water-soluble fluid 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.
  • 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.
  • 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.
  • gas as used herein, unless a different meaning is expressed or implied, means either a gas or combination of gases.
  • liquid means either a liquid or combination of liquids, unless a different meaning is expressed or implied.
  • fluid 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.
  • 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.”
  • 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.
  • target formation refers to the formation selected for injection of liquids or gases for sequestration.
  • 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.
  • the terms “low permeability” means less than about 100 millidarcy (mD) and the term “high permeability” means greater than about 300 mD.
  • references to CO 2 and other liquids or gases refer to such fluids in purified, supercritical (in the case of gases) or impure forms.
  • 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.
  • 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 .
  • a source 25 of gas is provided, in which the gas normally consists of a mixture of gases.
  • the gas normally consists of a mixture of water-soluble and insoluble gases (such as nitrogen).
  • 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 .
  • 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: CO 2 , NO N , or hydrogen sulfide.
  • the greenhouse gas is CO 2 .
  • 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.
  • 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 .
  • 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.
  • 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.
  • 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.
  • 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 .
  • 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.
  • FIG. 2 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 .
  • water-soluble gas 16 becomes dispersed within formation 10 as a plume of lower density fluid and generates a convection current 14 while water-insoluble gas 18 rises toward a gas pocket 20 .
  • Cross currents 24 provide additional mixing between water-soluble gas 16 and the formation water.
  • four withdrawal wells 22 are 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.
  • FIG. 3 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.
  • 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 .
  • FIG. 4 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 .
  • the gas mixture being injected includes CO 2 , 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.
  • 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.
  • 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.
  • 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.
  • 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.
  • 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.
  • 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.
  • the large-scale convection cell not only increases the diffusive mass transfer of CO 2 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.
  • the overall sequestration process may involve preliminary passage of a flue gas mixture (for example, containing about 13% CO 2 and 87% N 2 ) through a membrane or other type of purification or gas enrichment system so that the injected gas is 25%-80% CO 2 , with the remainder being essentially N 2 ; such a gas/CO 2 enrichment process will also help with improved storage capacity in situ and particularly with the rate at which the soluble gases (CO 2 in this realization) can be injected and subjected to contact with the formation waters.
  • a flue gas mixture for example, containing about 13% CO 2 and 87% N 2
  • a membrane or other type of purification or gas enrichment system so that the injected gas is 25%-80% CO 2 , with the remainder being essentially N 2 ;
  • a gas/CO 2 enrichment process will also help with improved storage capacity in situ and particularly with the rate at which the soluble gases (CO 2 in this realization) can be injected and subjected to contact with the formation waters.
  • the specific content of the injected gas can
  • 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 CO 2 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.
  • 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:
  • composition of said fluid to be injected into said formation a) composition of said fluid to be injected into said formation
  • 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.
  • the fluid comprises a greenhouse gas, as described above.

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CN114278257A (zh) * 2021-12-24 2022-04-05 中海石油(中国)有限公司 海上油田开采与超临界二氧化碳封存的同步装置与方法
US11306571B2 (en) * 2019-03-19 2022-04-19 Southwest Petroleum University Method for injecting non-condensable gas or in-situ combustion to recover remaining oil in a heavy oil reservoir with bottom water
CN115306479A (zh) * 2022-08-23 2022-11-08 中国矿业大学 一种基于废弃矿井采空区的co2区块化封存方法
WO2023225467A1 (fr) * 2022-05-15 2023-11-23 Advantek Waste Management Services, Llc Séquestration du dioxyde de carbone dans des puits souterrains horizontaux
CN117780312A (zh) * 2024-02-26 2024-03-29 中国石油大学(华东) 含硫烟道气地下组分分离与二氧化碳及硫化物埋存方法

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US11306571B2 (en) * 2019-03-19 2022-04-19 Southwest Petroleum University Method for injecting non-condensable gas or in-situ combustion to recover remaining oil in a heavy oil reservoir with bottom water
CN114278257A (zh) * 2021-12-24 2022-04-05 中海石油(中国)有限公司 海上油田开采与超临界二氧化碳封存的同步装置与方法
WO2023225467A1 (fr) * 2022-05-15 2023-11-23 Advantek Waste Management Services, Llc Séquestration du dioxyde de carbone dans des puits souterrains horizontaux
CN115306479A (zh) * 2022-08-23 2022-11-08 中国矿业大学 一种基于废弃矿井采空区的co2区块化封存方法
CN117780312A (zh) * 2024-02-26 2024-03-29 中国石油大学(华东) 含硫烟道气地下组分分离与二氧化碳及硫化物埋存方法

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AU2010223803A1 (en) 2011-08-25
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EP2406152A1 (fr) 2012-01-18
CA2751874C (fr) 2016-05-17
WO2010102385A1 (fr) 2010-09-16
EP2406152A4 (fr) 2015-10-14
EA201101204A1 (ru) 2012-04-30
CN102348614A (zh) 2012-02-08
CA2751874A1 (fr) 2010-09-16
JP2012519587A (ja) 2012-08-30

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