JP5553892B2 - Production method of carbon dioxide hydrate - Google Patents

Description

  The present invention relates to a method for producing carbon dioxide hydrate, particularly carbon dioxide hydrate deposited in underground formations. The invention also relates to a method for releasing hydrocarbon gas from hydrocarbon hydrate in a formation. The invention further relates to a material composition for releasing hydrocarbon gas from hydrocarbon hydrates and / or depositing carbon dioxide hydrates in underground formations. Furthermore, the present invention relates to a deposition apparatus suitable for carrying out the method for producing carbon dioxide hydrate described above (particularly in combination with the method for releasing hydrocarbon gas described above). In addition, the present invention relates to carbon dioxide storage (carbon dioxide sequestration) and to the recovery of hydrocarbons from underground formations.

  Since the discovery of natural hydrocarbon hydrates in underground geological formations, several methods for releasing and recovering hydrocarbon gas as an energy resource have been developed. According to one method, the hydrocarbon hydrate is replaced with carbon dioxide hydrate. Thereby, it is thought that there exists an advantage which can discard carbon dioxide simultaneously with collection | recovery of hydrocarbon gas. Several techniques for converting hydrocarbons to carbon dioxide hydrate have been proposed previously.

  US Pat. No. 5,261,490A (published in 1993: Patent Document 1) and Japanese Patent Laid-Open No. 6-071161 (published in 1994: Patent Document 2) propose a technique for injecting liquid carbon dioxide into a gas hydrate layer. . In these techniques, it is proposed to heat the gas hydrate with liquid carbon dioxide to melt the gas hydrate and the carbon dioxide hydrate layer. The disadvantage of this approach is that the melting of the gas hydrate cannot be controlled and this can cause the formation to become unstable. Furthermore, since the released hydrocarbon still contains a large amount of carbon dioxide, a large amount of carbon dioxide must be separated from the hydrocarbon gas and reprocessed.

  B. Kubanme et al. (Journal of Physical Chemistry, Vol. 99, 1995, pages 7114-7119: Non-Patent Document 1) and S. Hirohama et al. ("Journal of Chemical Engineering of Japan" Vol. 29, 1996, pp. 1014-1020: Non-Patent Document 2) further studies on the thermodynamics of carbon dioxide hydrate and hydrocarbon gas hydrate. Has been reported. S. Nakano et al. ("Proceedings of Institution of Mechanical Engineers" Vol. 212A, 1998, pages 159 to 163: Non-Patent Document 3) shows that carbon dioxide hydrate formation is an exothermic reaction, It states that the hydrocarbon hydrate will be heated. S. Hirohama et al. Nakano et al. Have introduced a model of hydrate conversion in which the conversion rate is completely limited by heat transport and the corresponding enthalpy change. In contrast, B.I. Kubanme et al. Present a differentiated model distinguishing process in which the conversion rate is kinetically limited by the phase transition itself through the Gibbs free energy difference or by only mass and heat transport. Yes. In these publications, although the theoretical conversion of hydrocarbons to carbon dioxide hydrate has been confirmed, research and suggestions have been made regarding practical implementation methods for treating geological hydrocarbon hydrates. It has not been.

  On the other hand, as another technique, a method of injecting carbon dioxide to replace methane in a gas hydrate is disclosed in US Patent Publication No. US2006 / 0060356A1 (Patent Document 3). Solid state transformations have been described that replace only methane, taking advantage of the greater thermodynamic stability of carbon dioxide hydrate compared to methane hydrate. Since this conversion process is governed by a solid state diffusion process, it can be said that the conversion speed is low and conversion efficiency is low. Yet another drawback is the fact that the actual geological system contains mineral components, which can exacerbate the transformation of the solid state.

US Pat. No. 5,261,490A JP-A-6-071161 US Patent Application Publication No. US2006 / 0060356A1

B. Kubanme et al., "Journal of Physical Chemistry" Vol. 99, 1995, pages 7114-7119 (B. Kvamme et al. ("J. Phys. Chem.", Volume 99, 1995, p. 7114-7119)) S. Hirohama et al., “Journal of Chemical Engineering of Japan” Vol. 29, 1996, pp. 1014-1020 (S. Hirohama et al. (“Journal of chemical engineering of Japan”, volume 29, 1996, p. 1014 -1020)) S. Nakano et al., "Proceedings of Institution of Mechanical Engineers" Vol. 212A, 1998, pages 159-163 (S. Nakano et al. ("Proc. Instn. Mech. Engrs.", Volume 212 A, 1998, p. 159-163))

  Against the background as described above, a method for generating carbon dioxide hydrate capable of overcoming the problems of the prior art, improving the reaction rate and improving the conversion efficiency, and replacing the hydrocarbon hydrate with carbon dioxide hydrate. Improvement is hoped for. There is also a need for improved methods for releasing hydrocarbon gas from underground formations. Such a method needs to be realized in a controllable state without making the formation unstable. It would also be desirable to provide an improved material composition that facilitates the formation of carbon dioxide hydrate in the underground formations. Furthermore, there is a need for an improved deposition apparatus that deposits carbon dioxide hydrate in the underground layer that can avoid the problems of the prior art and that is also compatible with conventional borehole technology and deposition apparatus.

Means for Solving the Problems and Effects of the Invention

  According to the first embodiment of the present invention, a method for producing carbon dioxide hydrate is provided in which a mixture of liquid carbon dioxide and a dissociator is supplied to a hydrocarbon hydrate. In this method, carbon dioxide hydrate is formed in the following two-stage process. That is, in the two-stage process, carbon dioxide hydrate is formed by liquid water and liquid carbon dioxide in the first process for promoting the dissociation of hydrocarbon hydrate, in which hydrocarbon gas and liquid water are formed by the dissociator. A second step of forming is included. Without being limited by theory, it is believed that the method of the present invention is usefully based on a liquid phase reaction that can improve the conversion rate compared to conversion based on solid state diffusion. Preferably, the hydrocarbon hydrate dissociation step causes the conversion efficiency to be substantially improved in the method of the present invention by allowing the hydrocarbon hydrate to react completely. In a particularly preferred application of the present invention, carbon dioxide hydrate is produced in the underground formation where hydrocarbon hydrate is located.

  According to a second embodiment of the present invention, a method for releasing hydrocarbon gas from hydrocarbon hydrate in a formation is provided. In the present method, carbon dioxide hydrate is generated in the formation and the released hydrocarbon gas is delivered to the surface of the formation as in the first aspect described above replacing the hydrocarbon hydrate. Usefully, the hydrocarbon hydrate is preferably completely replaced with carbon dioxide hydrate, thus avoiding stability problems within the formation.

  According to the third embodiment of the present invention, a material composition including liquid carbon dioxide mixed with a dissociator for dissociating hydrocarbon hydrate is provided.

  According to the fourth embodiment of the present invention, a deposition apparatus for depositing carbon dioxide hydrate in the underground formation is provided. The deposition apparatus includes a mixing apparatus for generating a mixture of liquid carbon dioxide and a dissociator that dissociates hydrocarbon hydrate. The deposition apparatus further comprises a supply device for introducing the mixture into the underground formation. As a major advantage of this deposition device, the mixing device can preferably be placed on the surface of the underground formation. Thereby, the deposition apparatus of the present invention can simplify the structure and can maintain compatibility with the conventional geological machine.

The dissociator preferably promotes the decomposition of the hydrocarbon hydrate into liquid water and hydrocarbon gas. Furthermore, such dissociators preferably do not form hydrates. Thus, preferably after the decomposition step, at least a portion of the dissociator is included in the liquid water. The advantage is that further hydrocarbon hydrate dissociation is maintained because the dissociator is at least partially dissolved in liquid water. In particular, dissociating agents, including surfactants (eg, ionic, polar surfactants, or biosurfactants) are the interface between a CO ₂ hydrate and an aqueous solution or hydrocarbon hydrate. Follow.

  According to another preferred feature of embodiments of the present invention, a liquid phase boundary is formed between the hydrocarbon hydrate and the carbon dioxide hydrate. The liquid phase boundary enables liquid mass transport to the hydrocarbon hydrate of carbon dioxide and dissociator. As hydrocarbon hydrate conversion proceeds, the liquid phase boundary moves through the hydrocarbon hydrate, which gradually replaces the hydrocarbon hydrate with carbon dioxide hydrate. At the same time, the dissociator is at least partially contained within the liquid phase boundary.

  According to another useful feature of certain embodiments of the present invention, mechanical vibrations can be applied to the hydrocarbon hydrate. Mechanical vibration promotes crack formation or expansion of cracks already present in the hydrocarbon hydrate, thereby further increasing the reaction rate. Also, additional additional energy sources (e.g., pulsed sound waves) can be used to promote crack formation or expansion of cracks already present in the hydrocarbon hydrate.

  According to a preferred embodiment of the invention, the cross-sectional dimension (thickness) of the liquid phase boundary is smaller than 500 μm, preferably smaller than 100 μm. Furthermore, the cross-sectional dimension (thickness) of the liquid phase boundary is at least 10 nm, preferably at least 10 μm.

  Various techniques are available for supplying liquid carbon dioxide and dissociator. As an example, both components can be delivered separately to the hydrocarbon hydrate via a borehole tubular material. Preferably, a mixture of liquid carbon dioxide and a dissociator is prepared and the mixture is fed to the hydrocarbon hydrate. The mixture can be prepared in a mixing container on the surface of the formation. In this case, the mixing apparatus of the deposition apparatus of the present invention preferably comprises a container and a dissociator supply device connected to the container. More preferably, the container includes a stirring device in the container for mechanically mixing the liquid carbon dioxide and the dissociator.

  Alternatively, the mixture is also prepared by providing a flow of liquid carbon dioxide and injecting a dissociator into the liquid carbon dioxide flow. In this case, the mixing apparatus of the deposition apparatus of the present invention preferably comprises an injection apparatus (for example, an injection nozzle connected to a supply apparatus). As another alternative, the dissociator can be delivered to a liquid carbon dioxide conduit prior to the stationary mixer, which mixes the dissociator with the liquid carbon dioxide as the two components move through the mixer. A liquid carbon dioxide flow containing the injected dissociator is injected into the hydrocarbon hydrate. Continuous or discontinuous injection can be performed, for example, to adjust the concentration of the dissociator, depending on the particular conditions. The discontinuous injection can include, for example, an initial injection for a limited initial time.

  In certain preferred embodiments of the invention, the concentration of the dissociator in liquid carbon dioxide is less than 500 ppm, more preferably less than 200 ppm, and most preferably less than 100 ppm. Furthermore, the concentration of the dissociator is preferably at least 20 ppm, more preferably at least 50 ppm. These boundary values include that value. It should be noted that a hydrate reservoir having a dynamic fluid flow through a portion filled with hydrate may require the addition of a large amount of dissociator or the next continuous or periodic dissociator. .

  The dissociator preferably contains at least one of an inorganic salt, a surfactant, a hydrate inhibitor, and an absorbing solution. Examples of these agents and their advantages will be described later.

  Embodiments of the invention that include releasing hydrocarbon gas preferably also include recovering hydrocarbons. The hydrocarbon preferably contains at least one of methane, ethane and ethylene.

  Further details and advantages of the present invention are described below with reference to the following attached drawings.

It is the schematic which produces | generates a carbon dioxide hydrate by the liquid phase reaction which concerns on this invention. It is a figure which illustrates roughly dissociation of hydrocarbon gas hydrate concerning the present invention, and formation of carbon dioxide hydrate.

  Preferred embodiments of the present invention will now be described with respect to the production of carbon dioxide hydrate by cracking methane hydrate. However, the embodiment of the present invention is not limited to this application example, and can be applied to other hydrocarbon hydrates (natural gas hydrate) such as ethane and ethylene hydrate. The pressure and temperature conditions for the formation of carbon dioxide hydrate sufficiently correspond to those in the stable region of natural gas hydrate for carrying out the present invention. The stable region can be determined based on measurements of natural gas hydrate deposits and experimental data described in the reported literature.

  FIG. 1 schematically illustrates one embodiment of a deposition apparatus 100 of the present invention and the basic features of a method according to the present invention for producing carbon dioxide hydrate and releasing hydrocarbon gas from the gas hydrate. Yes. FIG. 1A illustrates a deposition apparatus 100 arranged to produce carbon dioxide hydrate 1 by supplying a dissociator to liquid carbon dioxide to convert methane hydrate 2 to water and methane. As shown in this figure, the methane hydrate 2 is in the underground formation 3. The deposition apparatus 100 operates on the surface 4 of the underground formation 3. The stratum 3 is part of the crust, for example the mainland region. Alternatively, the formation 3 may be a submarine layer (eg, in an ocean region). In this case, the deposition apparatus 100 is disposed on the ocean. FIG. 1B schematically illustrates an enlarged cross-sectional view of methane hydrate 2 that is partially replaced with carbon dioxide hydrate 1 and that further includes, for example, mineral 5 (eg, precipitate grains). 1C is a further enlarged cross-sectional view schematically illustrating the boundary conditions among the carbon dioxide hydrate 1, the methane hydrate 2, and the mineral 5. FIG.

  The deposition apparatus 100 includes a mixing apparatus 10, a supply apparatus 20, a recovery apparatus 30, and a borehole apparatus 40. In general, the deposition apparatus 100 can have a structure similar to an oil well or a natural gas well, and is modified to specifically implement the mixing apparatus 10 and the supply apparatus 20.

  The mixing device 10 has a container 11 in which a dissociator supply device 12 and a stirring device 13 are arranged. The container 11 formed of a heat insulating wall includes an injection pipe 14 to which liquid carbon dioxide is supplied and a discharge pipe 15 that connects the container 11 to the supply device 20. The container 11 has an internal capacity for storing liquid carbon dioxide. The internal capacity is selected according to the specific conditions for carrying out the invention, in particular according to the size of the hydrate field. Furthermore, a cooling device (not shown) can be brought into thermal contact with the container 11. When carbon dioxide is liquefied in the container 11, a compressor (not shown) can be disposed in the container 11.

  The dissociator supply device 12 has a nozzle (not shown) that opens to the internal space through the wall of the container 11. The dissociator supply device 12 is arranged to introduce a predetermined amount of dissociator into the liquid carbon dioxide in the container 11. The dissociator supply 12 is connected to a dissociator reservoir (not shown) via a supply tube 16 that can be equipped with a controllable valve (not shown).

In an alternative embodiment of the present invention, the dissociator supply 12 is connected to a discharge pipe 15 (shown by a dotted line). In this embodiment, the dissociator is injected into the liquid carbon dioxide supply and into the formation 3.

  The supply device 20 includes a compressor station 21 and a supply tubular material 22. The compressor station 21 increases the supply pressure of the liquid carbon dioxide and dissociator mixture (eg, 10-100 bar based on the local static storage pressure of the injection zone in the reservoir of methane hydrate 2). In the range of excess pressure). The supply tubular material 22 comprises an integral solid steel tube with perforations at the far end that extends, for example, to methane hydrate 2. The supply tubular material 22 has an internal diameter that is selected as a typical amount, for example, in the range of about 10 cm to about 30 cm, depending on the particular conditions in which the invention is practiced. Other diameters may also be used depending on the requirements, and such diameters can be calculated by those skilled in the art.

  When the crack 2.1 is formed in the methane hydrate 2, the decomposition step and the carbon dioxide hydrate formation step can be promoted. For this reason, the vibration device 23 can be disposed in the supply device 20. The vibration device 23 is preferably arranged in mechanical contact with the supply tubular material 22 on the surface 4 (as shown). Alternatively, it is arranged at the far end of the supply tubular material 22 in the methane hydrate 2. The vibration device 23 is configured to give a mechanical vibration to the surrounding material, thereby promoting the formation of the crack 2.1 (C in FIG. 1). For this purpose, the vibration device 23 includes a vibration source such as a magnetostrictive actuator. Here, the application of energy for promoting the formation and / or expansion of cracks may be given by any known method.

  The recovery device 30 includes a discharge tubular material 31 and a methane collector 32. The discharge tubular material 31 comprises an integral tube that can be placed in the same borehole separately from or adjacent to the supply tubular material 22. The methane collector 32 includes a gas tank that stores methane released from the methane hydrate 2.

  The operation of the deposition apparatus 100 includes the following steps. First, a substance composition containing liquid carbon dioxide and a dissociator is prepared by the mixing device 10. For this purpose, liquid carbon dioxide is introduced through the injection tube 14 and at the same time the dissociator is injected by the dissociator supply 12. The dissociator injection is adjusted to obtain a preferred concentration of about 100 ppm of dissociator in liquid carbon dioxide. Depending on the dissociator, it can also be set to a higher or lower concentration. The mixture of carbon dioxide and dissociator is transported to methane hydrate 2 by feed tubular material 22. Sufficient carbon dioxide containing the dissociator is supplied to convert methane hydrate 2 to methane and water, and the supply pressure is adjusted to form carbon dioxide hydrate at the fastest rate. Therefore, by replacing the methane hydrate 2 with the carbon dioxide hydrate 1, when producing the carbon dioxide hydrate, the supply pressure can be increased as the deposition volume of the carbon dioxide hydrate 1 increases.

  A mixture of liquid carbon dioxide and dissociator is introduced into the methane hydrate 2 around the supply tubular material 22. The dissociator promotes the decomposition of methane hydrate into methane and liquid water. Next, carbon dioxide hydrate is formed from liquid carbon dioxide and liquid water. As a result, in a region where the carbon dioxide hydrate 1 increases, methane hydrate 2 is formed as schematically illustrated in FIG. Since carbon dioxide hydrate and methane hydrate do not adhere to minerals for thermodynamic reasons, there can be a transport channel that supplies liquid carbon dioxide to methane hydrate even if carbon dioxide hydrate 1 increases. Additional transport channels are also present in carbon dioxide hydrate 1.

  A further enlarged view shown in FIG. 1C shows that a liquid phase boundary (water layer) 6 is formed between the methane hydrate 2 and the carbon dioxide hydrate 1. The liquid phase boundary 6 extends between the hydrates 1 and 2 and along the surface of the mineral 5 along the crack 2.1 in the methane hydrate 2. Thus, the liquid connection between the supply tubular material 22 and the methane hydrate 2 is continuously maintained. Here, it is considered that the dissociator contained in the liquid carbon dioxide promotes the breaking of the hydrogen bond of the methane hydrate, thereby releasing the liquid water to the liquid phase boundary 6 (but limited by theory). Not) Since such a dissociating agent does not form a hydrate state, at least a portion remains and is contained in liquid water. At the same time, carbon dioxide hydrate 1 is formed under the influence of temperature and pressure in the underground formation.

  The liquid phase boundary 6 moves gradually towards methane hydrate 2 which is preferably completely replaced by carbon dioxide hydrate 1. The liquid phase boundary 6 is a liquid water layer typically having a thickness d in the range of 10 μm to 100 μm. Despite this small thickness, even if the liquid phase boundary or crack is reduced to the range of 10 nm to 100 nm, the reaction rate is essentially improved compared to solid state diffusion. Even with such a small size, a useful decomposition process as well as a carbon dioxide hydrate forming process can be provided. Further, such dimensions of the liquid phase boundary preferably maintain the stability of the formation during carbon dioxide storage and hydrocarbon gas recovery. When the pressure is high when liquid carbon dioxide is supplied, it is thought that the thickness is increased at the crack or liquid phase boundary.

Dissociating agents such as surfactants conform to the interface between water and CO _2. If all of the surfactant can be injected within a limited initial time, or if additional dissociator is required at a later stage, the dispersion pattern of injected CO ₂ and the injected CO 2 _The corresponding contact area between ₂ and the solid hydrate is determined. This analysis can be based on available geological data and / or core samples from the reservoir prior to injection.

  The reaction at the liquid phase boundary 6 is schematically illustrated with reference to further details shown in FIG. The substance composition 7 of the present invention having liquid carbon dioxide 7.1 and a dissociator 7.2 (for example, potassium phosphate) is in contact with methane hydrate 2 dissociated into liquid water 8 and methane gas 9. Carbon dioxide 7.1 reacts with liquid water 8 to form carbon dioxide hydrate 1. Methane gas 9 is released and delivered to the surface 4 of the formation 3 (FIG. 1).

  The released methane is collected in the methane collector 32. The methane collector 32 can be provided with a membrane for gas separation of methane and carbon dioxide, which separates residual carbon dioxide contained in the recovered methane. Useful gas separation membranes for this purpose include, for example, polyethylene glycol (hexafluoropropane dianhydride (6FDA), dimercaptopropane-sulfonate (DMPS), methylene-diphenylene-diisocyanate-hard segment ( PEG / MDI-MDEA-MDI) and the like.

Several groups of dissociators that can be utilized in the present invention to decompose hydrocarbon hydrates are described below. The suitability of agents for dissociating hydrocarbon hydrates under actual pressure and temperature conditions in laboratory experiments is shown.
1. Surfactant (surfactant)

  A surfactant is a dissociator that promotes the splitting of hydrogen bonds between water and hydrocarbons in hydrocarbon hydrates. Thereby, liquid water and hydrocarbon gas are formed, and the mass transport rate can be suitably increased (especially, it can be increased by several orders of magnitude).

  The surfactant may be a negatively charged group or, for example, at least one anion of a sulfonic acid group, a carboxylic acid group or a phosphoric acid group, or an anion, and / or at least one positive ion. A positively charged group or an ionic surfactant comprising at least one cation, for example sodium, potassium, ammonium or potassium, and / or an acidic group.

  The ionic surfactant has a particularly excellent advantage that the dissociation efficiency is high with respect to the decomposition of the hydrocarbon hydrate.

  The surfactant may also include a nonionic surfactant containing at least one of alcohol ethoxylate, glycoside, glucamide and ester, for example.

As a further example, the surfactant can also include a biosurfactant, ie, a surfactant contained in a biological material (eg, a biological cell or a portion thereof). Preferred examples of biosurfactants are trehalose and lipids. Useful biosurfactants are active molecules in the dissolution of hydrocarbon hydrate surfaces. However, they do not decompose newly formed carbon dioxide hydrate. This is because the newly formed carbon dioxide hydrate has a higher thermodynamic stability.
2. Hydrate inhibitor

  In general, agents that suppress the formation of hydrocarbon hydrates that have molecules with a C atom chain having a polar component at one end can be used as hydrate inhibitors. As the chain length increases, the active interface between water and carbon dioxide widens, improving the efficiency of hydrocarbon cracking. The polar component adheres to the hydrocarbon hydrate, while the nonpolar backbone (C chain) is oriented to liquid carbon dioxide.

Further, the hydrate inhibitor includes, for example, an amine, a compound having a carbon pattern of oxygen or a chain backbone double-bonded to a ring structure, and an alcohol group, and particularly promotes CO ₂ diffusion through the hydrate inhibitor. Has a chain length distribution. The preferred chain length of the chain backbone is 10-15 carbon atoms, but can be longer at lower concentrations.
3. Absorbing liquid

  A third group of dissociators includes absorbents that have the advantage of increasing the solubility of carbon dioxide in liquid water. The absorbent therefore has the dual function of dissociating the hydrocarbon hydrate and improving the formation of carbon dioxide hydrate.

Examples of absorbing liquids that can be used in the present invention include, for example, reactive amines that can be rendered non-reactive by replacing hydrogen on the nitrogen with alkanes (CH ₃ or longer). Quality diisopropanolamine (DIPA). Further examples include methyl-di-ethyl-amine (MDEA) or NAM / NFM (NAM: N-acetylmorpholine, NFM: N-formyl-morpholine). Other useful dissociating agents include chitosan.
4). Inorganic salt

  Examples of inorganic salts that can be used as the dissociator include at least one of potassium phosphate, potassium phosphate, sodium chloride, or potassium chloride. Alternatively, any inorganic salt having a solubility in water equivalent to the solubility of the salt described above can be used.

  A particularly preferred example of the salt used is potassium phosphate known as E340 as a food additive (illustrated in FIG. 2). This hydrate inhibitor has the excellent advantage of being environmentally friendly and very inexpensive.

  Useful dissociators can be determined by a simple test, i.e., contacting the hydrocarbon hydrate with a dissociator candidate to see if the hydrate decomposes into liquid water and hydrocarbon gas. Any agent determined to be useful by such tests can be used in the practice of the present invention. Of course, some agents are more useful than others in terms of degradation rate.

  The features of the invention disclosed in the above specification, drawings, and claims are important in the practice of the invention in various embodiments, both individually and in combination. Those skilled in the art can make modifications and improvements within the concept and scope of the present invention in view of the disclosure herein.

1 ... carbon dioxide hydrate 2 ... methane hydrate; 2.1 ... crack 3 ... formation 4 ... surface 5 ... mineral 6 ... liquid phase boundary (water layer)
7 ... Material composition; 7.1 ... Liquid carbon dioxide; 7.2 ... Dissociator 8 ... Liquid water 9 ... Methane gas 10 ... Mixing device 11 ... Container 12 ... Dissociator supply device 13 ... Stirrer 14 ... Injection pipe 15 ... Discharge Pipe 16 ... Supply pipe 20 ... Supply apparatus 21 ... Compressor station 22 ... Supply tubular material 23 ... Vibrating apparatus 30 ... Recovery apparatus 31 ... Discharge tubular material 32 ... Methane collector 40 ... Borehole apparatus 100 ... Deposition apparatus

Claims (31)

A method for producing carbon dioxide hydrate comprising:
Supplying liquid carbon dioxide and a dissociator to the hydrocarbon hydrate;
Decomposing hydrocarbon hydrate into hydrocarbon gas and liquid water by the dissociator;
Forming carbon dioxide hydrate from liquid carbon dioxide and liquid water;
A method comprising the steps of: The method of claim 1, comprising:
The decomposing step includes
Promoting the splitting of hydrogen hydrates in the hydrocarbon hydrate with a dissociator so that liquid water is formed;
A method wherein at least a portion of the dissociator is dissolved in liquid water. The method according to claim 1 or 2, wherein
A method wherein the dissociator does not form a hydrate. A method according to any one of claims 1-3,
After the decomposing step, at least a part of the dissociator is contained in liquid water. A method according to any one of claims 1-4,
A liquid phase boundary is formed between the hydrocarbon hydrate and carbon dioxide hydrate,
The liquid phase boundary is moved by continuous supply of liquid carbon dioxide, whereby hydrocarbon hydrate is gradually replaced with carbon dioxide hydrate. A method according to any one of claims 1-5,
The supplying step comprises:
Preparing a mixture of liquid carbon dioxide and a dissociator;
Supplying the mixture to a hydrocarbon hydrate;
A method comprising the steps of: The method of claim 6, comprising:
The supplying step comprises:
Providing a flow of liquid carbon dioxide;
Mixing a dissociator with the liquid carbon dioxide flow;
Supplying the liquid carbon dioxide flow comprising a dissociator to a hydrocarbon hydrate;
A method comprising the steps of: A method characterized by that. The method of claim 7, comprising:
A dissociator is mixed into the liquid carbon dioxide flow by a stationary mixer in the liquid carbon dioxide flow. A method according to any one of claims 1-8,
A method wherein the concentration of the dissociator in liquid carbon dioxide is less than 500 ppm. A method according to any one of claims 1-9,
Dissociation agent is inorganic salt, potassium phosphate, potassium phosphate, sodium chloride, potassium chloride, surfactant, ionic surfactant, nonionic surfactant, biosurfactant, trehalose, lipid, hydrate suppression A method comprising at least one of an agent, an absorbing solution, a substance containing an amine or an alcohol group. The method of claim 10, comprising:
Ionic surfactant
(I) a negatively charged group or a sulfonic acid group, a carboxylic acid group or a phosphoric acid group at least one anion;
(Ii) an anion and / or at least one of a positively charged group or at least one cation of potassium, ammonium or potassium, or (iii) an acidic group how to. The method of claim 10, comprising:
The method characterized in that the nonionic surfactant comprises at least one of alcohol ethoxylate, glycoside, glucamide or ester. The method of claim 10, comprising:
Hydrate inhibitors
(I) amine,
A method comprising at least one of (ii) oxygen double-bonded to a ring structure, a carbon pattern of a chain backbone, or (iii) an alcohol group. 14. A method according to claim 13, comprising:
A method wherein the hydrate inhibitor comprises an agent having a chain length distribution that promotes CO ₂ diffusion through the hydrate inhibitor. The method of claim 10, comprising:
A method characterized in that the absorbent comprises a molecular structure of limited size selected from monodiethanolamine (MDEA) or dipropanolamine (DIPA). The method according to any one of claims 1 to 15, further comprising:
A method comprising the step of recovering hydrocarbons. A method according to any one of claims 1 to 16, comprising
The carbon dioxide hydrate is formed in a subterranean formation containing hydrocarbon hydrate. The method according to any one of claims 1 to 17, further comprising:
A method comprising the step of applying mechanical vibration to a hydrocarbon hydrate. A method for releasing hydrocarbon gas from hydrocarbon hydrate in a formation,
Supplying liquid carbon dioxide and a dissociator to the hydrocarbon hydrate;
Accelerating the decomposition of hydrocarbon hydrate into hydrocarbon gas and liquid water by a dissociator;
Sending hydrocarbon gas to the surface of the formation;
A method comprising the steps of: A material composition for depositing carbon dioxide hydrate in the underground formation,
Liquid carbon dioxide,
A dissociating agent capable of promoting dissociation of hydrocarbon hydrate;
A material composition comprising: The substance composition according to claim 20,
A substance composition characterized in that the concentration of the dissociator in liquid carbon dioxide is less than 500 ppm. The substance composition according to claim 20 or 21,
Dissociation agent is inorganic salt, potassium phosphate, potassium phosphate, sodium chloride, potassium chloride, surfactant, ionic surfactant, nonionic surfactant, biosurfactant, trehalose, lipid, hydrate suppression A substance composition comprising at least one of an agent, an absorbing solution, a substance containing an amine or an alcohol group. The substance composition according to claim 22,
Ionic surfactant
(I) a negatively charged group or at least one anion of a sulfonic acid group, a carboxylic acid group or a phosphoric acid group,
(Ii) at least one of an anion and / or at least one positively charged group or at least one cation of potassium, ammonium or potassium, or (iii) an acidic group Material composition. The substance composition according to claim 22,
A substance composition, wherein the nonionic surfactant comprises at least one of alcohol ethoxylate, glycoside, glucamide or ester. The substance composition according to claim 22,
A substance composition comprising a hydrate inhibitor comprising at least one of an amine, oxygen double-bonded to a ring structure, a carbon pattern of a chain backbone, or an alcohol group. The substance composition according to claim 22,
A substance composition, wherein the hydrate inhibitor has a chain length distribution that promotes CO ₂ diffusion through the hydrate inhibitor. The substance composition according to claim 22,
A substance composition characterized in that the absorbent comprises a molecular structure of limited size selected from monodiethanolamine (MDEA) or diisopropanolamine (DIPA). A deposition apparatus configured and arranged to deposit carbon dioxide hydrate in an underground formation,
Liquid carbon dioxide,
A dissociating agent capable of promoting dissociation of hydrocarbon hydrate;
A mixing device arranged to supply a mixture of
A supply device configured and arranged to supply a mixture of liquid carbon dioxide and a dissociator into the underground formation;
A deposition apparatus comprising: A deposition apparatus according to claim 28, wherein
Mixing device
A container configured and arranged to contain liquid carbon dioxide;
A dissociator supply connected to the container;
A deposition apparatus comprising: 30. The deposition apparatus of claim 29, wherein
A deposition apparatus, wherein the container comprises a stirring device arranged in the container to mix liquid carbon dioxide and a dissociator. A deposition apparatus according to any one of claims 28 to 30, comprising:
A deposition apparatus, wherein the mixing apparatus comprises an injection apparatus connected to a supply apparatus.

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