Title: SYSTEMS AND METHODS FOR PRODUCING NATURAL GAS FROM HYDRATE DEPOSITS AND FOR STORING CARBON DIOXIDE

Abstract

Disclosed herein are systems and methods for producing natural gas from gas hydrates, which in some embodiments can sequester carbon dioxide. In an embodiment, the system includes: an injection well; a producing well; a producer annulus; a well annulus; a y-shaped well couple; a gas wellbore; a heating wellbore; a well tubing; a tank; a water pump; a separator; a wellhead choke; a work pipe; a CO.sub.2 compressor; a well casing; and a pressure-regulator valve. In another embodiment, the method includes: obtaining hot water using a y-shaped horizontal well couple; injecting water heated by geothermal energy; transferring heat from a geothermal zone to a gas hydrate deposit zoon using a dual-lateral horizontal well; regulating water-flooding flow rate using a wellhead choke; collecting water and natural gas using a dual-lateral horizontal well; and coupling the two horizontal wells through connection of two laterals in the gas hydrate zone.

Claims

1. A system for producing natural gas from gas hydrate deposits located at onshore or dissociating gas hydrates, the system comprising: an injection well; a producing well; a producer annulus; a well annulus; a y-shaped well couple; a gas wellbore; a heating wellbore; a well tubing; a tank; a water pump; a separator; a wellhead choke; a work pipe; a CO.sub.2 compressor; a well casing; and a pressure-regulator valve.

2. A method for producing natural gas from gas hydrate deposits, the method comprising: injection of water heated by geothermal energy; obtaining hot water using a y-shaped horizontal well couple; transferring heat from a geothermal zone to a gas hydrate deposit zoon using a dual-lateral horizontal well; regulating water-flooding flow rate using a wellhead choke; collecting water and natural gas using a dual-lateral horizontal well; and coupling the two horizontal wells through connection of two laterals in the gas hydrate zone.

3. A method of injecting CO.sub.2 through a natural geothermal zone to a natural gas reservoir, the method comprises the steps of: providing a tubing system comprising: an injection well; a producing well; a producer annulus; a well annulus; a y-shaped well couple; a gas wellbore; a heating wellbore; a well tubing; a tank; a water pump; a separator; a wellhead choke; a work pipe; a CO.sub.2 compressor; a well casing; and a pressure-regulator valve; obtaining heat energy from a horizontal wellbore in a geothermal zone to heat CO.sub.2; and transferring the heated CO.sub.2 to a horizontal wellbore in a gas hydrate reservoir.

4. The method of injecting CO.sub.2 through a natural geothermal zone to a natural gas reservoir of claim 3, wherein the wellhead choke regulates the flow rate of CO.sub.2 injection into the gas hydrate reservoir.

Description

BRIEF DESCRIPTION OF THE DRAWINGS

[0021] For the purposes of promoting an understanding of the principles of the present disclosure, reference can be now made to the embodiments illustrated in the drawings, which are described below. The embodiments disclosed herein are not intended to be exhaustive or limit the present disclosure to the precise form disclosed in the following detailed description. Rather, the embodiments are chosen and described so that others skilled in the art can utilize their teachings. Therefore, no limitation of the scope of the present disclosure is thereby intended.

[0022] FIG. 1 is a phase diagram for hydrate-water-natural gas.

[0023] FIG. 2 shows an embodiment of a system for producing natural gas from gas hydrate deposits by water flooding.

[0024] FIG. 3 is a phase diagram for hydrate-water-methane and CO.sub.2.

[0025] FIG. 4 shows an embodiment of a system for producing natural gas from gas hydrate deposits, which can also provide for CO.sub.2 sequestration.

DETAILED DESCRIPTION

[0026] In one or more embodiments, the system and method for producing natural gas from gas hydrate deposits can include, but is not limited to: one or more injection wells; one or more producing wells; one or more injection wells; one or more gas wellbores; one or more producer annulus; one or more well annulus, one or more water collection wellbores, one or more heat absorber wellbores; one or more heat dissipator wellbore; one or more well tubings; one or more well casings; one or more water tanks; one or more water pumps; one or more y-shaped well couples; one or more gas-liquid separators; one or more wellhead chokes; one or more work pipes; one or more CO.sub.2 compressors; one or more y-shaped well casing-tubing systems; one or more pressure-regulator valve, and combination thereof

[0027] The system for producing natural gas and any of its components can be made from one or more suitable materials. For example, the one or more components of the systems for producing natural gas from gas hydrate deposits can made from any one or more metals (such as aluminum, steel, stainless steel, brass, nickel), metal alloys, concretes, fiberglass, wood, composite materials (such as ceramics, wood/polymer blends, cloth/polymer blends, etc.), and plastics (such as polyethylene, polypropylene, polystyrene, polyurethane, polyethylethylketone (PEEK), polytetrafluoroethylene (PTFE), polyamide resins (such as nylon 6 (N6), nylon 66 (N66)), polyester resins (such as polybutylene terephthalate (PBT), polyethylene terephthalate (PET), polyethylene isophthalate (PEI), PET/PEI copolymer) polynitrile resins (such as poly acrylonitrile (PAN), polymethacrylonitrile, acrylonitrile-styrene copolymers (AS), methacrylonitrile-styrene copolymers, methacrylonitrile-styrene-butadiene copolymers; and acrylonitrile-butadiene-styrene (ABS)), polymethacrylate resins (such as polymethyl methacrylate and polyethylacrylate), cellulose resins (such as cellulose acetate and cellulose acetate butyrate); polyimide resins (such as aromatic polyimides), polycarbonates (PC), elastomers (such as ethylene-propylene rubber (EPR), ethylene propylene-diene monomer rubber (EPDM), styrenic block copolymers (SBC), polyisobutylene (PIB), butyl rubber, neoprene rubber, halo butyl rubber and the like)), and mixtures, blends, or copolymers of any and all of the foregoing materials.

[0028] The various components of the system for producing natural gas can be attached to and/or integrally formed with each other to make the system. In some embodiments, the various components of the system for producing natural gas can be in fluid communication with one another and will the subterranean formation. In some embodiments, the components of the system for producing natural gas can include: one or more outer surfaces, one or more inner surfaces, one or more inner spaces, include a length, height, width, radius, first end, front side, second end, back side, right side, left side, top side, bottom side, outer surface, inner surface, and inner space.

[0029] In one or more embodiments, the method for producing natural gas from gas hydrate deposits can include, but is not limited to: injecting water into a wellbore placed in a geothermal aquifer below a gas hydrate reservoir; heating the water with the geothermal energy from the geothermal aquifer is led to a wellbore placed in the gas hydrate reservoir to water-flood and dissociate gas hydrates; a portion of the water cooled by the gas hydrate reservoir is circulated back to surface; the returned water is re-injected back into the water injection well; the natural gas released in the gas hydrate reservoir is produced through the annular space of a gas production well; and the produced natural gas is purified in a separator for sale. This method makes the full use of natural geothermal energy with minimal addition of electric energy that powers the water pump.

[0030] In some embodiments, the system and method for producing natural gas from gas hydrate deposits can bring geothermal energy to the gas hydrate deposit, heats the hydrate deposit, and causes dissociation of the gas hydrates, which facilitates gas production through a horizontal well couple. The systems and methods for producing natural gas from gas hydrate deposits can include producing natural gas from gas hydrates deposits embedded in onshore and/or offshore deposits.

[0031] In some embodiments, the system and method for producing natural gas from gas hydrates can provide effective and economical for large gas hydrate reservoirs to sustain long-term gas production. The systems and methods for producing natural gas from gas hydrates can provide safe collection of natural gas through the low-pressure system with minimalized risk of a gas leak. The systems and methods for producing natural gas from gas hydrates can be used with minimal supervision. Once the systems and methods are deployed, the users can monitor the pressure and temperature of the system and change the operational scheme accordingly. For example, the user can set the wellhead choke and add water to the water tank.

[0032] The natural gas hydrates can include crystalline water structures with low-molecular-weight guest molecules. The natural gas hydrates can also include. The presence of the gas molecules leads to stability of the crystalline structure. Natural gas hydrates can form a variety of crystal structures, depending primarily on the sizes of the guest molecules. They can include metastable minerals whose formation, stability, and decomposition depend on pressure, temperature, composition, and other properties of the gas and water. The hydrates can include nitrogen, carbon dioxide, methane, ethane, propane, iso-butane, n-butane, and some branched or cyclic C5-C8 hydrocarbons. FIG. 1 shows a simple phase diagram of the method of the invention invoking dissociation of gas hydrates. Equilibrium curves are based on data from the public domain. Dissociation of gas hydrates from solid hydrate to liquid water and gas is affected by the increased temperature under isobar conditions. The dissociation temperature and pressure are indicated at point B.

[0033] FIG. 2 shows an embodiment of a system and method for producing natural gas from gas hydrates deposits. In the embodiment, water in water tank 1 is injected by pump 2 into the water injection well 3 along the work pipe 4 reaching the geothermal zone 5. The water in the injection wellbore annulus 6 is heated by the geothermal zone. The hot water travels along the well annulus and arrives at the heating wellbore 7 in the gas hydrate zoon 8. The heat energy in the hot water dissipates into the gas hydrate zoon by heat convection through wellbore perforations and heat conduction through wellbore casing and cement sheath. At least a portion of water stream enters the well tubing 9, flows through wellhead choke 10 of the gas producing well 11. The wellhead choke 10 can be used for regulating water flow rate into the gas hydrate zoon. The dissociated gas in the gas hydrate zone enters gas wellbore 12, flows along the producer annulus 13, and arrives at separator 14 for phase separation and sale.

[0034] In some embodiments, the system and method for producing natural gas from gas hydrate deposits can utilize geothermal energy through ay-shaped wellbore couple to facilitate the production of natural gas from gas hydrate reservoirs, which can reduce or eliminate the need to burn fossil fuels or use electricity to heat the injection water, thereby reducing the carbon footprint. In some embodiments, the wellhead choke can regulate water-flooding flow rate.

[0035] The systems and methods for producing natural gas from gas hydrate deposits can use natural geothermal energy to facilitate the dissociation of natural gas and greatly reduces the energy consumed for gas production. The source of heat is the key to the technical and economic feasibility as well as to the long-term sustainability of gas production. The replacement of artificial energy with natural energy not only greatly reduces the operational cost to heat the water but also entails minimal operational complexity once the system is deployed. The combination of the geothermal technique along with the established mathematical model also allows for a ranged evaluation of alternative scenarios that would be intangible to investigate otherwise.

[0036] The systems and methods for producing natural gas from gas hydrate deposits can provide quantitative optimization and design for the selection of the properties of the circulating water and cement/insulation for each section of the wellbores for a higher heat transfer performance. In some embodiments, the system and method for producing natural gas from gas hydrate deposits the wells are completed according to the design of configurations; the water is injected by the pump through the work pipe of the injection wellbore; the water is heated by the heat absorber horizontal wellbore; the heated water flows back through the injection annulus and enters the heat dissipator wellbore and floods the gas hydrate deposit; the remaining water flows through the tubing of the production wellbore and gets collected by the water tank; the natural gas released from the gas hydrates enters the gas production wellbore, flows up the annulus of the gas well, and arrives at separator for sale. The method can heat the water to the in-situ temperature of the geothermal zoon and create a temperature difference of over 30 C. (54 F.) at the gas hydrate zone.

[0037] The systems and methods for producing natural gas from gas hydrate deposits can utilize natural energy instead of commercial energy supplies to facilitate gas production, which can significantly minimize the environmental footprint. The systems and methods for producing natural gas from gas hydrate deposits can be an ecologically and geologically friendly process. In some embodiments, the system and method for producing natural gas from gas hydrate deposits can allow for the production of natural gas without a significant pressure drop in the gas hydrate deposits, which greatly reduces the risk of tectonic movement associated with depleted reservoirs.

[0038] The systems and methods for injecting carbon dioxide into methane hydrate reservoirs geothermal method uses the natural geothermal energy from a zone below the gas hydrate reservoir for accelerating the dissociation of gas hydrates, and, yet still does not hinder the formation of CO.sub.2 hydrates. These systems and methods can be feasible if the temperature of the gas hydrate reservoir is maintained above the methane-hydrae dissociation temperature and below the CO.sub.2-hydrate formation temperature at a desired level of gas production pressure. This range of reservoir temperature is achievable using the y-shaped well couples in the systems for injecting carbon dioxide into methane hydrate reservoirs. The risk that the solid hydrate structure will dissociate, and huge amount of water will be discharged with the produced gas can be solved by methane-CO.sub.2 hydrate exchange in low-temperature reservoirs.

[0039] The systems and methods for injecting carbon dioxide into methane hydrate reservoirs takes the advantage of the naturally cold environment in gas hydrate reservoirs to store CO.sub.2 in solid state (CO.sub.2-hydrates) so that high-pressure condition is avoided to prevent CO.sub.2 leak into atmosphere. In some embodiments, the method for injecting carbon dioxide into methane hydrate reservoirs can include, but is not limited to: placing CO.sub.2 in solid form in natural gas hydrate reservoirs, dissociating the methane hydrates; forming CO.sub.2 hydrates; displacing the methane by the CO.sub.2 hydrates, and storing the CO.sub.2 in a reservoir. In some embodiments, the method can include, but is not limited to: completing wells according to the design of configurations; injecting CO.sub.2 using a compressor through the work pipe of the injection wellbore; heating the CO.sub.2 by the heat absorber horizontal wellbore, where the heated CO.sub.2 flows back through the injection annulus and enters the heat dissipator wellbore; at least partially flooding the gas hydrate deposit with CO.sub.2, where the remaining CO.sub.2 flows through the tubing of the production wellbore and gets collected by the CO.sub.2 tank for recycling injection; releasing the natural gas from the gas hydrates, where the gas enters the production wellbore, where the gas flows up the annulus of the gas well, and arrives at separator for sale. In some embodiments, the method can include heating the CO.sub.2 to the in-situ temperature between the forming temperatures of methane hydrate and CO.sub.2 hydrate.

[0040] FIG. 3 shows a phase diagram for the dissociation of methane hydrates and formation of CO.sub.2 hydrates. Equilibrium curves are based on data from Sloan and Koh. Point A represents the initial condition (pressure and temperature) of the gas reservoir. Point B refers to the methane hydrate dissociation pressure in the conventional depressurization method of gas production. Point C denotes the operating point in the newly invented method. The temperature increase is induced by the injected CO.sub.2 which is heated by the geothermal energy. Maintaining the condition defined by the operating point C allows for dissociation of methane hydrates and formation of CO.sub.2 hydrates.

[0041] The methods and systems for injecting carbon dioxide into methane hydrate reservoirs uses the natural geothermal energy from a zone below the gas hydrate reservoir for accelerating the dissociation of gas hydrates and yet still does not hinder the formation of CO.sub.2 hydrates. These methods and systems are feasible if the temperature of the gas hydrate reservoir is maintained above the methane-hydrae dissociation temperature and below the CO.sub.2-hydrate formation temperature at a desired level of gas production pressure. This range of reservoir temperature is achievable using the y-shaped well couples.

[0042] The methods and systems for injecting carbon dioxide into methane hydrate reservoirs can provide quantitative optimization and design for the selections of CO.sub.2 injection rate and insulations of pipe and cement for each section of the wellbores to ensure high efficiency of heat transfer. The methods and systems for injecting carbon dioxide into methane hydrate reservoirs utilize geothermal energy through a y-shaped wellbore couple to facilitate the dissociation of gas hydrates, formation and deposition of CO.sub.2 hydrates, and production of natural gas from gas hydrate reservoirs, which eliminates the need to burn fossil fuels or use electricity to heat the injection CO.sub.2 and greatly reduces the carbon footprint. An advantage of this technique is that it is a process that allows CO.sub.2 be stored in low-temperature environment at low pressure. This condition ensures that the CO.sub.2 is firmly stored in solid form without being leaked to the atmosphere. Another advantage of this technique is that it is an ecologically and geologically friendly process. The technique does not cause significant pressure drop in the gas hydrate deposit, which greatly reduces the risk of tectonic movement associated with depleted gas hydrate reservoirs. Yet another advantage of the technique is that it requires minimal supervision. Once the system is deployed, the onsite engineers only need to monitor the pressure and temperature of the system and automatically change the operational scheme accordingly through setting of wellhead choke and feeding the CO.sub.2 tank with make-up CO.sub.2. Still another advantage of the technique is that it is especially effective and economical for large gas hydrate reservoirs to store CO.sub.2 and sustain long-term gas production.

[0043] FIG. 4 shows an embodiment of a system for injecting carbon dioxide into methane hydrate reservoirs. In the embodiment, a y-shaped well couple for heat transfer from a geothermal zone to a gas hydrate reservoir. The CO.sub.2 from the CO.sub.2 tank 1 is compressed by CO.sub.2 compressor 2 and transferred to the CO.sub.2 injection well 3 where the CO.sub.2 is injected through injection pipe 4 down to a horizontal hole in a geothermal zone 5. The CO.sub.2 is heated in the heat-receiving hole 6 by the geothermal energy. The heated CO.sub.2 is lead to a heat-releasing horizontal hole 7 where a fraction of the CO.sub.2 stream is injected into the gas hydrate reservoir 8 for dissociating methane-hydrates. At least a portion of the CO.sub.2 stream returns to surface through well tubing 9. The wellhead choke 10 at the gas production well 11 controls back pressure for adjusting the amount of CO.sub.2 returning to the CO.sub.2 tank 1 for re-circulation. The amount of CO.sub.2 injected to the hydrate reservoir is made up from a CO.sub.2 supply line. The horizontal gas wellbore 12 collects methane gas at a pressure that is below the methane-hydrate dissociation pressure and above the CO.sub.2-hydrate formation pressure at the in-situ temperature. The collected gas is transported through well tubing string 13 and delivered to separator 14. Only minimal amount of energy is supplied to the system for power the CO.sub.2 compressor. The system allows to inject CO.sub.2 to bring geothermal energy to the methane hydrate reservoir, dissociate the methane hydrates, form CO.sub.2 hydrates, displace the methane by the CO.sub.2 hydrates, and permanently store the CO.sub.2 in the reservoir.

[0044] Although the invention has been described in detail with particular reference to these preferred embodiments, other embodiments can achieve the same results. Variations and modifications of the present invention will be obvious to those skilled in the art and it is intended to cover in the appended claims all such modifications and equivalents. The entire disclosures of all references, applications, patents, and publications cited above, and of the corresponding application(s), are hereby incorporated by reference.

[0045] One of ordinary skill in the art will readily appreciate that alternative, but functionally equivalent components, materials, designs, and equipment may be used. The inclusion of additional elements may be deemed readily apparent and obvious to one of ordinary skill in the art. Specific elements disclosed herein are not to be interpreted as limiting, but rather as a basis for the claims and as a representative basis for teaching one of ordinary skill in the art to employ the present invention.

[0046] Various terms have been defined above. To the extent a term used in a claim is not defined above, it should be given the broadest definition persons in the pertinent art have given that term as reflected in at least one printed publication or issued patent. Furthermore, all patents, test procedures, and other documents cited in this application are fully incorporated by reference to the extent such disclosure is not inconsistent with this application.

[0047] Certain embodiments and features have been described using a set of numerical upper limits and a set of numerical lower limits. It should be appreciated that ranges including the combination of any two values, e.g., the combination of any lower value with any upper value, the combination of any two lower values, and/or the combination of any two upper values are contemplated unless otherwise indicated. It should also be appreciated that the numerical limits may be the values from the examples. Certain lower limits, upper limits and ranges appear in at least one claim below. All numerical values are about or approximately the indicated value, and take into account experimental error and variations that would be expected by a person having ordinary skill in the art.

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