US20050121200A1 - Process to sequester CO2 in natural gas hydrate fields and simultaneously recover methane - Google Patents
Process to sequester CO2 in natural gas hydrate fields and simultaneously recover methane Download PDFInfo
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- US20050121200A1 US20050121200A1 US10/771,869 US77186904A US2005121200A1 US 20050121200 A1 US20050121200 A1 US 20050121200A1 US 77186904 A US77186904 A US 77186904A US 2005121200 A1 US2005121200 A1 US 2005121200A1
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- methane
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- VNWKTOKETHGBQD-UHFFFAOYSA-N methane Chemical compound C VNWKTOKETHGBQD-UHFFFAOYSA-N 0.000 title claims abstract description 74
- NMJORVOYSJLJGU-UHFFFAOYSA-N methane clathrate Chemical compound C.C.C.C.O.O.O.O.O.O.O.O.O.O.O.O.O.O.O.O.O.O.O.O.O.O.O NMJORVOYSJLJGU-UHFFFAOYSA-N 0.000 title claims abstract description 32
- 238000000034 method Methods 0.000 title claims abstract description 22
- CURLTUGMZLYLDI-UHFFFAOYSA-N Carbon dioxide Chemical compound O=C=O CURLTUGMZLYLDI-UHFFFAOYSA-N 0.000 claims abstract description 75
- 229910002092 carbon dioxide Inorganic materials 0.000 claims abstract description 54
- 239000001569 carbon dioxide Substances 0.000 claims abstract description 52
- VTVVPPOHYJJIJR-UHFFFAOYSA-N carbon dioxide;hydrate Chemical compound O.O=C=O VTVVPPOHYJJIJR-UHFFFAOYSA-N 0.000 claims abstract description 8
- 230000014759 maintenance of location Effects 0.000 claims abstract 2
- 150000001875 compounds Chemical class 0.000 claims description 5
- 239000007789 gas Substances 0.000 description 26
- 239000013049 sediment Substances 0.000 description 18
- 229910052594 sapphire Inorganic materials 0.000 description 9
- 239000010980 sapphire Substances 0.000 description 9
- 230000009919 sequestration Effects 0.000 description 8
- 230000015572 biosynthetic process Effects 0.000 description 7
- 238000005755 formation reaction Methods 0.000 description 7
- 238000003384 imaging method Methods 0.000 description 7
- 238000002347 injection Methods 0.000 description 7
- 239000007924 injection Substances 0.000 description 7
- 239000012071 phase Substances 0.000 description 7
- 238000012360 testing method Methods 0.000 description 7
- 238000004587 chromatography analysis Methods 0.000 description 6
- XLYOFNOQVPJJNP-UHFFFAOYSA-N water Substances O XLYOFNOQVPJJNP-UHFFFAOYSA-N 0.000 description 5
- 238000010586 diagram Methods 0.000 description 4
- 239000007788 liquid Substances 0.000 description 4
- 238000010494 dissociation reaction Methods 0.000 description 3
- 230000005593 dissociations Effects 0.000 description 3
- 239000002803 fossil fuel Substances 0.000 description 3
- 239000005431 greenhouse gas Substances 0.000 description 3
- 239000012808 vapor phase Substances 0.000 description 3
- -1 CO2 hydrates Chemical class 0.000 description 2
- XEEYBQQBJWHFJM-UHFFFAOYSA-N Iron Chemical compound [Fe] XEEYBQQBJWHFJM-UHFFFAOYSA-N 0.000 description 2
- 239000003245 coal Substances 0.000 description 2
- 238000001816 cooling Methods 0.000 description 2
- 238000002474 experimental method Methods 0.000 description 2
- 150000004677 hydrates Chemical class 0.000 description 2
- VUZPPFZMUPKLLV-UHFFFAOYSA-N methane;hydrate Chemical class C.O VUZPPFZMUPKLLV-UHFFFAOYSA-N 0.000 description 2
- 239000000203 mixture Substances 0.000 description 2
- 238000012545 processing Methods 0.000 description 2
- 238000011084 recovery Methods 0.000 description 2
- 238000005070 sampling Methods 0.000 description 2
- 239000007787 solid Substances 0.000 description 2
- RZVAJINKPMORJF-UHFFFAOYSA-N Acetaminophen Chemical compound CC(=O)NC1=CC=C(O)C=C1 RZVAJINKPMORJF-UHFFFAOYSA-N 0.000 description 1
- 229910000831 Steel Inorganic materials 0.000 description 1
- 238000004458 analytical method Methods 0.000 description 1
- 230000005540 biological transmission Effects 0.000 description 1
- 238000009530 blood pressure measurement Methods 0.000 description 1
- 238000009529 body temperature measurement Methods 0.000 description 1
- 239000004568 cement Substances 0.000 description 1
- 238000002485 combustion reaction Methods 0.000 description 1
- 230000001186 cumulative effect Effects 0.000 description 1
- 230000001419 dependent effect Effects 0.000 description 1
- 238000006073 displacement reaction Methods 0.000 description 1
- 238000007710 freezing Methods 0.000 description 1
- 230000008014 freezing Effects 0.000 description 1
- 238000010438 heat treatment Methods 0.000 description 1
- 230000036571 hydration Effects 0.000 description 1
- 238000006703 hydration reaction Methods 0.000 description 1
- 230000000977 initiatory effect Effects 0.000 description 1
- 229910052742 iron Inorganic materials 0.000 description 1
- 238000009533 lab test Methods 0.000 description 1
- 239000000463 material Substances 0.000 description 1
- 239000003345 natural gas Substances 0.000 description 1
- 239000004576 sand Substances 0.000 description 1
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Images
Classifications
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- B—PERFORMING OPERATIONS; TRANSPORTING
- B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
- B01D—SEPARATION
- B01D53/00—Separation of gases or vapours; Recovering vapours of volatile solvents from gases; Chemical or biological purification of waste gases, e.g. engine exhaust gases, smoke, fumes, flue gases, aerosols
- B01D53/14—Separation of gases or vapours; Recovering vapours of volatile solvents from gases; Chemical or biological purification of waste gases, e.g. engine exhaust gases, smoke, fumes, flue gases, aerosols by absorption
- B01D53/1456—Removing acid components
- B01D53/1475—Removing carbon dioxide
-
- C—CHEMISTRY; METALLURGY
- C01—INORGANIC CHEMISTRY
- C01B—NON-METALLIC ELEMENTS; COMPOUNDS THEREOF; METALLOIDS OR COMPOUNDS THEREOF NOT COVERED BY SUBCLASS C01C
- C01B32/00—Carbon; Compounds thereof
- C01B32/50—Carbon dioxide
-
- 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
- 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
- E21B41/0099—Equipment or details not covered by groups E21B15/00 - E21B40/00 specially adapted for drilling for or production of natural hydrate or clathrate gas reservoirs; Drilling through or monitoring of formations containing gas hydrates or clathrates
-
- 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
- E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
- E21B43/16—Enhanced recovery methods for obtaining hydrocarbons
- E21B43/164—Injecting CO2 or carbonated water
-
- 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
-
- 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
- Y02P—CLIMATE CHANGE MITIGATION TECHNOLOGIES IN THE PRODUCTION OR PROCESSING OF GOODS
- Y02P20/00—Technologies relating to chemical industry
- Y02P20/151—Reduction of greenhouse gas [GHG] emissions, e.g. CO2
-
- 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
- Y02P—CLIMATE CHANGE MITIGATION TECHNOLOGIES IN THE PRODUCTION OR PROCESSING OF GOODS
- Y02P90/00—Enabling technologies with a potential contribution to greenhouse gas [GHG] emissions mitigation
- Y02P90/70—Combining sequestration of CO2 and exploitation of hydrocarbons by injecting CO2 or carbonated water in oil wells
Definitions
- This invention relates to a process for storage and sequestration of carbon dioxide (CO 2 ). More particularly, this invention relates to a process for underground storage and sequestration of carbon dioxide in submerged sea areas of natural gas hydrate deposits.
- Examples of such sources include fossil-fuel power stations, oil refineries, petrochemical plant, cement works and iron and steel plants.
- transportation is most likely to be by pipeline in preference to batch handling, although liquefied gas tankers have been suggested as an option for a demonstration project.
- a range of storage options have been proposed, including injection into depleted oil and/or gas reservoirs, geological aquifers, deep unminable coal seams and on or below the deep ocean bed. Injection into oil/gas reservoirs and deep coal seams has the attraction of utilizing geological formations with demonstrated storage capabilities.
- FIG. 1 is a schematic diagram showing a laser imaging system employed for the purpose of verifying the concept of this invention
- FIG. 2 is a graphical representation showing conditions for methane hydrate formation as part of the conceptual verification
- FIG. 3 is a laser image showing methane hydrate embedded in sediment
- FIG. 4 is a laser image showing methane hydrate embedded in the sediment near the sediment surface
- FIG. 6 is a diagram showing the gas chromatographic analysis of a gas phase sample (100 mole % CO 2 ) at the start of a test to verify operability of this invention.
- FIG. 7 is a diagram showing the gas chromatographic analysis of a gas phase sample after 68 hours (27.67 mol % of methane) of operation of a test to verify operability of this invention.
- the analytical component 11 comprises a high resolution digital camera control unit 19 operably connected to camera 21 and laser control unit 16 operably connected to laser 13 . Also included within the analytical component 11 are a PC monitor 17 operably connected to a computer processing unit (CPU) 18 to monitor and store data, a video monitor 20 operably connected to the high resolution digital camera control unit 19 and a video cassette recorder 22 to record the imaging events in the sapphire cell 12 .
- the laser imaging system is capable of operating at high pressures (1500 psia) and low temperatures ( ⁇ 40° C. to 100° C.).
- the high-pressure sapphire cell was packed with wet (water) sand sediment of about 30% porosity, similar to that of the Gulf of Mexico sediment, connected into the laser imaging system and charged with pure methane to a pressure of 700 psia.
- a NESLAB chiller available from Thermo NESLAB, Portsmouth, N.H., was used to cool and heat the cell at programmed rates (0.1° C. per minute). The temperature of the cell initially was reduced from about 25° C. to about 2° C.
- the pressure and temperature in the sapphire cell were measured simultaneously using a digital pressure sensor and thermocouple, respectively. Laser pulses from the laser illuminated the sapphire cell.
- the laser beam acts as a very short-duration strobe lamp for the high-speed digital camera, freezing the rapid action of hydrate formation and dissociation in the sediments in the sapphire cell.
- the high-resolution digital camera recorded the imaging events.
- a computer controlled the system while also collecting and processing pressure, temperature, time, and image data. Temperature and pressure measurements were tracked in real time.
- methane hydrate was formed, based upon the use of a calculated 0.0263 moles of methane, in the sediment at 3.5° C. during the cooling run. The system was then cooled to about 2° C. and held at that temperature for 2 hours.
- the laser images in FIGS. 3 and 4 generated at the initiation of CO 2 injection into the sapphire cell, show the methane hydrate (seen as “white” specks) embedded in the sediment close to the surface at 2° C.
- the laser image in FIG. 5 generated after 92 hours of CO 2 injection, shows hydrate formation (also seen as “white” specks) deeper in the sediment. These images clearly show hydrate in the voids of the sediment.
- FIG. 6 shows the gas chromatographic analysis of the sample from the gas phase (a single peak representative of 100 mole % CO 2 ) at the start of the test.
- FIG. 7 shows the gas chromatographic analysis of the sample from the gas phase after 68 hours (two peaks, one of which is representative of 27.67 mole % of methane). After the first sampling, thermodynamic material balance calculations indicated that 0.0235 moles (89.35%) of methane were released out of the total 0.0263 moles of methane utilized in the hydrate sediment. At the end of 92 hours, gas chromatographic analysis of the gas-phase sample confirmed a methane content of 17.97 mol %.
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- Mining & Mineral Resources (AREA)
- Geology (AREA)
- Chemical Kinetics & Catalysis (AREA)
- Environmental & Geological Engineering (AREA)
- General Life Sciences & Earth Sciences (AREA)
- Physics & Mathematics (AREA)
- Fluid Mechanics (AREA)
- Geochemistry & Mineralogy (AREA)
- Organic Chemistry (AREA)
- Oil, Petroleum & Natural Gas (AREA)
- General Chemical & Material Sciences (AREA)
- Analytical Chemistry (AREA)
- Inorganic Chemistry (AREA)
- Treating Waste Gases (AREA)
- Physical Or Chemical Processes And Apparatus (AREA)
- Organic Low-Molecular-Weight Compounds And Preparation Thereof (AREA)
Abstract
A method for sequestering and storing CO2 in which gaseous carbon dioxide is injected into a subterranean methane hydrate field, displacing methane in the methane hydrate field with the carbon dioxide and forming carbon dioxide hydrate. The displaced methane may then be collected.
Description
- 1. Field of the Invention
- This invention relates to a process for storage and sequestration of carbon dioxide (CO2). More particularly, this invention relates to a process for underground storage and sequestration of carbon dioxide in submerged sea areas of natural gas hydrate deposits.
- 2. Description of Related Art
- Levels of anthroprogenic greenhouse gases, including carbon dioxide, in the Earth's atmosphere have been increasing substantially over the years due primarily to the burning of fossil fuels to supply about 80 percent of the world's energy needs. These increased emissions of greenhouse gases are believed responsible for a one degree Fahrenheit increase in the global average temperature over the past several years and if nothing is done to reduce them, the Earth will continue to warm, resulting in a host of environmentally damaging consequences, according to some scientists. There exists a range of options available for addressing this issue including the capture and storage of carbon dioxide produced in the combustion of fossil fuels. This involves three basic stages: capture, transportation and injection into a storage medium. Carbon dioxide capture would be most efficiently applied to large “point sources” in order to gain economies of scale both in the capture process itself and in subsequent transportation and storage. Examples of such sources include fossil-fuel power stations, oil refineries, petrochemical plant, cement works and iron and steel plants. Because of the large quantities of gas involved (i.e. on the order of 1-30 Mt/yr CO2 for a full scale scheme) transportation is most likely to be by pipeline in preference to batch handling, although liquefied gas tankers have been suggested as an option for a demonstration project. A range of storage options have been proposed, including injection into depleted oil and/or gas reservoirs, geological aquifers, deep unminable coal seams and on or below the deep ocean bed. Injection into oil/gas reservoirs and deep coal seams has the attraction of utilizing geological formations with demonstrated storage capabilities.
- It is also known that the oceans naturally absorb carbon dioxide based upon which it is believed that one cost-effective way to mitigate global warming is to store the excess carbon dioxide in a liquid form in the depths of the ocean. Experiments to test theoretical predictions about the behavior of liquid carbon dioxide in the depths of the ocean have been conducted and the results indicate that under cool temperatures and high pressures, carbon dioxide and other greenhouse gases react with water to form a solid ice-like compound called clathrate hydrate. At shallow depths, liquid carbon dioxide will rise to the surface. But laboratory experiments with carbon dioxide hydrates suggest that liquid carbon dioxide put deep in the ocean would form a stable layer on the sea floor with a skin of solid hydrate as a boundary, like a pond covered by ice in winter. It is believed, however, that such a method has not yet been successfully demonstrated. Accordingly, there remains a considerable interest in storage and sequestration of CO2 on the bottom of the sea.
- Accordingly, it is one object of this invention to provide a method for sequestration and storage of carbon dioxide.
- It is another object of this invention to provide a method for sequestration and storage of carbon dioxide underwater.
- It is still a further object of this invention to provide a method for sequestration and storage of carbon dioxide underwater with simultaneous recovery of methane gas.
- These and other objects of this invention are addressed by a method for sequestration and storage of carbon dioxide in which the carbon dioxide to be sequestered and stored is injected into natural gas hydrate deposits disposed in terrestrial subsurface areas in order to displace the naturally occurring methane hydrates present therein with CO2 hydrates. In this manner, the methane is produced by using the heat released from the CO2 gas hydrate formation to drive dissociation of methane hydrate sediments. The recovered methane could be used to pay for the transportation and injection costs of CO2 to the underwater site. Suitable fields of natural gas hydrate deposits are known to exist, for example, on sea bottoms in the Gulf of Mexico and Alaska.
- In the parent application to this application, a process is disclosed in which a gas mixture comprising carbon dioxide and methane is brought into contact with a methane hydrate solid material disposed in a reactor vessel, whereby the methane hydrate is displaced by carbon dioxide hydrate, thereby freeing the methane, which is then removed from the reactor vessel. Without wishing to be bound by any single explanation as to the operation of this invention, it is believed that the previously disclosed method for displacement of methane hydrate by carbon dioxide hydrate is the principle behind the operation of the invention disclosed and claimed herein.
- Although described herein primarily in the context of natural gas or methane hydrates, it is to be understood that the method of this invention could be applied to any underwater or underground hydrate deposits where the hydrates in the deposit are less stable than CO2 hydrates, and all such hydrate deposits should be considered to be within the scope of this invention.
- These and other objects and features of this invention will be better understood from the following detailed description taken in conjunction with the drawings wherein:
-
FIG. 1 is a schematic diagram showing a laser imaging system employed for the purpose of verifying the concept of this invention; -
FIG. 2 is a graphical representation showing conditions for methane hydrate formation as part of the conceptual verification; -
FIG. 3 is a laser image showing methane hydrate embedded in sediment; -
FIG. 4 is a laser image showing methane hydrate embedded in the sediment near the sediment surface; -
FIG. 5 is a laser image of the sediment after completion of a test to verify operability of this invention; -
FIG. 6 is a diagram showing the gas chromatographic analysis of a gas phase sample (100 mole % CO2) at the start of a test to verify operability of this invention; and -
FIG. 7 is a diagram showing the gas chromatographic analysis of a gas phase sample after 68 hours (27.67 mol % of methane) of operation of a test to verify operability of this invention. - The invention claimed herein is a method for sequestration and storage of CO2 in which the CO2 to be sequestered and stored is injected into a subterranean methane hydrate field whereby the methane in the methane hydrate field is displaced by the CO2 and, in so doing, the methane is released for collection.
- Both CO2 and methane form structure I hydrates. At temperatures below about 283° K, there is a pressure range in which methane hydrate is unstable and CO2 hydrate is stable. The heat released from the formation of CO2 gas hydrate is larger than that needed for methane hydrate dissociation:
CH4(H2O)n→CH4+nH2O Δhf=54.49 KJ/mole
CO2(H2O)n→CO2+nH2O Δhf=57.98 KJ/mole
where n is the hydration number for methane hydrate and CO2 hydrate (assuming that n is 6.15 for both methane and CO2). It should be noted that n is dependent on pressure, temperature and the composition of the gas in the gas phase. This suggests that under certain pressure-temperature conditions, the replacement of CH4 in the hydrate with CO2 is thermodynamically possible. - To validate the concept of this invention, a laser imaging tool, shown in schematic diagram form in
FIG. 1 , was developed. The laser imaging tool comprises two primary components, alaser operation component 10 and ananalytical component 11. As shown inFIG. 1 , thelaser operation component 10 comprises an air-cooled, solid-state diode laser 13 operating with a peak power of 200 W at a wavelength of 808 nm with pulse energy up to 20 mJ, available from Oxford Lasers Company, U.K., a high-pressure sapphire cell 12 into which a sample to be tested is introduced, adiffuser 14intermediate laser 13, and a high-resolutiondigital camera 21 capable of image capture at up to 10,000 frames per second disposed on a side ofsapphire cell 12opposite laser 13. Theanalytical component 11 comprises a high resolution digitalcamera control unit 19 operably connected tocamera 21 andlaser control unit 16 operably connected tolaser 13. Also included within theanalytical component 11 are aPC monitor 17 operably connected to a computer processing unit (CPU) 18 to monitor and store data, avideo monitor 20 operably connected to the high resolution digitalcamera control unit 19 and avideo cassette recorder 22 to record the imaging events in thesapphire cell 12. The laser imaging system is capable of operating at high pressures (1500 psia) and low temperatures (−40° C. to 100° C.). - To simulate undersea hydrate bed conditions and verify the concept of this invention, the high-pressure sapphire cell was packed with wet (water) sand sediment of about 30% porosity, similar to that of the Gulf of Mexico sediment, connected into the laser imaging system and charged with pure methane to a pressure of 700 psia. A NESLAB chiller, available from Thermo NESLAB, Portsmouth, N.H., was used to cool and heat the cell at programmed rates (0.1° C. per minute). The temperature of the cell initially was reduced from about 25° C. to about 2° C. The pressure and temperature in the sapphire cell were measured simultaneously using a digital pressure sensor and thermocouple, respectively. Laser pulses from the laser illuminated the sapphire cell. The laser beam acts as a very short-duration strobe lamp for the high-speed digital camera, freezing the rapid action of hydrate formation and dissociation in the sediments in the sapphire cell. The high-resolution digital camera recorded the imaging events. A computer controlled the system while also collecting and processing pressure, temperature, time, and image data. Temperature and pressure measurements were tracked in real time.
- Graphical software was used to update and display traces of temperature and pressure vs. time, and pressure vs. temperature. The hydrate formation process was monitored in real time. Images were captured during the heating and cooling cycle at a rate of 40 frames per second using a high-resolution and high-speed digital camera and processed using VISILOG software, available from N or Pix, Inc., Montreal, Quebec, Canada. Once methane hydrate was formed in the sediment in the cell, excess methane gas above the sediment was replaced by CO2 gas. The head pressure was maintained at 550 psia by a high-pressure pump. Small samples were extracted from the gas phase in the cell above the sediment hydrate at constant pressure maintained by the pump. Methane and CO2 content were analyzed using a Hewlett Packard (HP) gas chromatograph three times: at the start, after 68 hours, and after 92 hours. The data were collected and analyzed. The results of these tests confirm that the methane gas released from the hydrate field was displaced by CO2.
- As shown in
FIG. 2 , methane hydrate was formed, based upon the use of a calculated 0.0263 moles of methane, in the sediment at 3.5° C. during the cooling run. The system was then cooled to about 2° C. and held at that temperature for 2 hours. The laser images inFIGS. 3 and 4 , generated at the initiation of CO2 injection into the sapphire cell, show the methane hydrate (seen as “white” specks) embedded in the sediment close to the surface at 2° C. The laser image inFIG. 5 , generated after 92 hours of CO2 injection, shows hydrate formation (also seen as “white” specks) deeper in the sediment. These images clearly show hydrate in the voids of the sediment. However, it is not possible from the images alone to ascertain whether the hydrate shown inFIG. 5 is methane hydrate or CO2 hydrate. Rather, determination of the hydrate type may be inferred from an analysis of the vapor phase exiting the sapphire cell. In particular, gas chromatographic analysis of the vapor phase confirmed that the gas released at the end of the test (i.e. after 92 hours of CO2 injection) was 99.6% methane. From this data, it may be inferred that the methane gas in the vapor phase, initially present in the form of methane hydrate, was displaced by CO2 to form CO2 hydrate in the sediment -
FIG. 6 shows the gas chromatographic analysis of the sample from the gas phase (a single peak representative of 100 mole % CO2) at the start of the test.FIG. 7 shows the gas chromatographic analysis of the sample from the gas phase after 68 hours (two peaks, one of which is representative of 27.67 mole % of methane). After the first sampling, thermodynamic material balance calculations indicated that 0.0235 moles (89.35%) of methane were released out of the total 0.0263 moles of methane utilized in the hydrate sediment. At the end of 92 hours, gas chromatographic analysis of the gas-phase sample confirmed a methane content of 17.97 mol %. After the second sampling, similar calculations indicated that 0.0262 (cumulative) moles (99.6%) of methane were released out of the total 0.0263 moles of methane from the hydrate sediment. The number of moles used to form the hydrate agrees substantially with the number of moles of methane released at the end of the experiment, indicating the recovery of virtually all of the methane gas used to form the methane hydrate. - Implementation of the method of this invention may be carried out in a variety of manners. One of the simplest implementations involves the use of concentric conduits in which the carbon dioxide is injected through the inner conduit into the methane hydrate field and displaced methane is collected in the annular region between the inner and outer concentric conduits for transmission away from the resulting carbon dioxide hydrate field.
- While in the foregoing specification this invention has been described in relation to certain preferred embodiments thereof, and many details have been set forth for the purpose of illustration, it will be apparent to those skilled in the art that the invention is susceptible to additional embodiments and that certain of the details described herein can be varied considerably without departing from the basic principles of this invention.
Claims (6)
1. A method for sequestering and storing CO2 comprising the steps of:
injecting gaseous carbon dioxide into a subterranean area comprising at least one hydrate of at least one compound, said at least one hydrate having a stability less than carbon dioxide hydrate, whereby said carbon dioxide displaces said at least one compound, forming said carbon dioxide hydrate in said subterranean area and releasing said compound from said subterranean area.
2. A method in accordance with claim 1 , wherein said compound is methane and said at least one hydrate is methane hydrate.
3. A method in accordance with claim 2 further comprising collecting said methane.
4. A method in accordance with claim 1 , wherein said subterranean area comprises a sea bottom.
5. A method for recovering methane from a subterranean methane hydrate field comprising the step of:
injecting a gaseous stream comprising carbon dioxide into said methane hydrate field, displacing methane in said methane hydrate field, forming carbon dioxide hydrate and displaced methane; and
collecting said displaced methane.
6. A method in accordance with claim 5 , wherein said subterranean methane hydrate field is disposed at a sea bottom.
Priority Applications (2)
Application Number | Priority Date | Filing Date | Title |
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US10/771,869 US20050121200A1 (en) | 2003-12-04 | 2004-02-04 | Process to sequester CO2 in natural gas hydrate fields and simultaneously recover methane |
PCT/US2005/003485 WO2005076904A2 (en) | 2004-02-04 | 2005-01-28 | Process to sequester co2 in natural gas hydrate fields and simultaneously recover methane |
Applications Claiming Priority (2)
Application Number | Priority Date | Filing Date | Title |
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US10/728,332 US6946017B2 (en) | 2003-12-04 | 2003-12-04 | Process for separating carbon dioxide and methane |
US10/771,869 US20050121200A1 (en) | 2003-12-04 | 2004-02-04 | Process to sequester CO2 in natural gas hydrate fields and simultaneously recover methane |
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US10/728,332 Continuation-In-Part US6946017B2 (en) | 2003-12-04 | 2003-12-04 | Process for separating carbon dioxide and methane |
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US20050121200A1 true US20050121200A1 (en) | 2005-06-09 |
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US10/771,869 Abandoned US20050121200A1 (en) | 2003-12-04 | 2004-02-04 | Process to sequester CO2 in natural gas hydrate fields and simultaneously recover methane |
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US (1) | US20050121200A1 (en) |
WO (1) | WO2005076904A2 (en) |
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US20060113079A1 (en) * | 2003-11-13 | 2006-06-01 | Yemington Charles R | Production of natural gas from hydrates |
US20100048963A1 (en) * | 2008-08-25 | 2010-02-25 | Chevron U.S.A. Inc. | Method and system for jointly producing and processing hydrocarbons from natural gas hydrate and conventional hydrocarbon reservoirs |
WO2009155270A3 (en) * | 2008-06-19 | 2010-04-22 | M-I L.L.C. | Producing gaseous hydrocarbons from hydrate capped reservoirs |
CN1920251B (en) * | 2006-09-07 | 2010-08-18 | 中国科学院广州能源研究所 | Method and device for natural gas hydrate exploitation with in-situ catalytic oxidation thermochemistry method |
US20110123432A1 (en) * | 1999-12-30 | 2011-05-26 | Marathon Oil Company | Hydrate formation for gas separation or transport |
US20120038174A1 (en) * | 2010-08-13 | 2012-02-16 | Board Of Regents, The University Of Texas System | Storing Carbon Dioxide and Producing Methane and Geothermal Energy from Deep Saline Aquifers |
WO2012061027A1 (en) * | 2010-10-25 | 2012-05-10 | Conocophillips Company | Selective hydrate production with co2 and controlled depressurization |
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WO2013056732A1 (en) | 2011-10-19 | 2013-04-25 | Statoil Petroleum As | Improved process for the conversion of natural gas to hydrocarbons |
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DE102009007453B4 (en) | 2009-02-04 | 2011-02-17 | Leibniz-Institut für Meereswissenschaften | Process for natural gas production from hydrocarbon hydrates with simultaneous storage of carbon dioxide in geological formations |
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