EA029258B1 - Method and system for synthetic fuel production from a combustible material - Google Patents

Abstract

The present invention is related to a method for production of synthetic fuel from a combustible material comprising the following steps: combustible material is separated gravitationally from barren rock in water-salt solution selected so that it has a density intermediate between the combustible material density and the barren rock density; separated combustible material is heated and milled to produce paste of purified combustible material; the paste is pseudo-fluidized; and hydrogenation of the pseudo-fluidized paste is performed using Segner wheel. The invention is related also to a system for production of synthetic fuel from a combustible material by the above-described method.

Description

The invention relates to a method for producing synthetic fuel from combustible material, comprising the following steps: combustible material is gravitationally separated from waste rock in a water-salt solution, chosen so that it has a density intermediate between the density of the combustible material and the waste rock density; heat and grind the separated combustible material to form a paste of refined combustible material; fluidizing the paste and hydrogenating the fluidized paste through the use of a Segner wheel. The invention also relates to a system for producing synthetic fuel from combustible material in the manner indicated above.

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The technical field to which the invention relates.

The present invention relates to the production and processing of energy and, more specifically, to the liquefaction of natural gas and other fossil fuels.

The level of technology

The liquefaction of natural gas is associated with considerable difficulties regarding energy consumption and the delivery of natural gas to the liquefaction plant. Existing technologies use large amounts of energy and require a long pipeline to deliver natural gas from offshore fields.

Coal liquefaction is used to process coal and, in particular, to produce liquid fuels from coal (see, for example, Bergius’s method invented a hundred years ago). However, the main difficulties in performing such processes are due to the need for the extraction, processing and transportation of huge amounts of fossil fuels intended for liquefaction, as well as high energy consumption for processing, adverse environmental effects associated with liquefaction, chemicals used in this process, and some cases of low processing efficiency.

DISCLOSURE OF INVENTION

In one aspect of the present invention, an underwater gas pressure boosting module is provided, comprising: at least one vertical vessel configured to receive gas through the upper part of the vessel and pressurize the liquid through the lower part of the vertical vessel and additionally containing a layer of water-immiscible liquid on the water-based layer -salt solution, and the density of the pressure-increasing liquid is higher than the density of the water-salt solution, which, in turn, is higher than the density of the water-immiscible liquid To keep the layer of water-salt solution on top of the pressure-increasing fluid and to keep the layer of water-immiscible liquid on top of the layer of water-salt solution, and containing a valve system, designed to increase the gas pressure by introducing the pressure-increasing fluid into the vessel, pumping the increased pressure gas through the upper part of the vertical vessel after reaching a predetermined pressure and introducing gas into the vessel by pumping the pressure-increasing fluid through the lower part of the vertical vessel.

In another aspect of the present invention, an underwater natural gas liquefaction system is proposed that contains at least two underwater gas pressure boosting modules, one of which is capable of compressing natural gas and the other is capable of compressing refrigerant used to cool the compressed natural gas.

In one aspect of the present invention, there is provided an underwater gas pressure boosting module comprising at least one vessel configured to receive gas through the upper part of the vessel and seawater through the lower part of the vessel and additionally containing a layer of water-immiscible liquid separating the gas and seawater, while the liquid that is not miscible with water is selected so that it has a density intermediate between the density of the gas and the density of seawater; and a valve system configured to increase the gas pressure by introducing seawater into the vessel, pumping the pressurized gas through the upper part of the vessel after reaching a predetermined pressure and introducing gas into the vessel by pumping seawater through the lower part of the vessel. Pumped seawater can be introduced in a controlled manner into production wells to enhance gas production.

In one aspect of the present invention, a method for separating and hydrogenating combustible material is proposed, comprising the following steps: combustible material is gravitationally separated from the waste rock in a water-salt solution chosen so that it has a density intermediate between the density of the combustible material and the density of the waste rock; heat and grind the separated combustible material to form a paste of refined combustible material; fluidizing the paste and hydrogenating the fluidized paste through the use of a Segner wheel.

In one aspect of the present invention, a hydrogenation module is provided comprising a vertical shaft configured to receive a flowing combustible material and maintain its downward flow; Segner wheel having fluid communication with the vertical shaft and configured to be driven in rotation by a flowing combustible fluid material; the hydrogenation chamber surrounding the lower portion of the vertical shaft and the Segner wheel, the hydrogenation chamber containing a heating module configured to heat the flowing combustible material and a source of hydrogen configured to introduce hydrogen into the flowing combustible material coming out of the Segner wheel to produce hydrogenated combustible fluid medium; and a vertical case having fluid communication with the hydrogenation chamber and configured to maintain an upward flow of hydrogenated combustible fluid from the hydrogenation chamber while ensuring recovery heat exchange between the rising hydrogenated combustible fluid and the downward flow of combustible fluid.

These additional and / or other aspects and / or advantages of the present invention are set forth.

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in the following detailed description; while they can be derived from the detailed description and / or learn when implementing the present invention.

Brief Description of the Drawings

For a better understanding of the embodiments of the invention and to illustrate how they can be implemented, we will now refer to the accompanying drawings, which are given solely as an example, in which the same reference numbers designate identical elements or segments throughout the document.

On the attached drawings are presented:

FIG. 1 is a structural block diagram of a high level of subsea gas pressure boosting module in accordance with some embodiments of the invention.

FIG. 2 is a schematic representation of a high level of an underwater gas booster according to some embodiments of the invention.

FIG. 3 is a structural block diagram of a high level submarine natural gas liquefaction system in accordance with some embodiments of the invention.

FIG. 4 is a schematic representation of a high level of a natural gas underwater liquefaction system according to some embodiments of the invention.

FIG. 5 is a high level block diagram illustrating a method of compressing and liquefying a gas according to some embodiments of the invention.

FIG. 6 is a structural block diagram of a high level of subsea gas pressure boosting module in accordance with some embodiments of the invention.

FIG. 7 is a structural block diagram of a high level submarine natural gas liquefaction system in accordance with some embodiments of the invention.

FIG. 8 is a schematic representation of a high level of a subsea natural gas liquefaction system in accordance with some embodiments of the invention.

FIG. 9 is a high level block diagram illustrating a method of compressing and liquefying a gas according to some embodiments of the invention.

FIG. 10A is a schematic representation of a non-limiting example of a combustible material handling system according to some embodiments of the invention.

FIG. 10B is a schematic representation of a high level of subsystems in a combustible material processing system according to some embodiments of the invention.

FIG. 11A is a high level flowchart illustrating the main steps of a method for separating and hydrogenating combustible material in accordance with some embodiments of the invention.

FIG. 11B is a high level flowchart illustrating the subsequent steps of a method for separating and hydrogenating combustible material in accordance with some embodiments of the invention.

The implementation of the invention

Before setting out the detailed description of the invention below, it may be useful to define certain terms used in this document.

The term "combustible material" as used in this invention refers to any type of material used to generate energy, in particular sedimentary rocks, such as coal, oil shale and other types of fossil fuel.

With a specific reference to the accompanying detailed drawings, it should be emphasized that the specific details are depicted only as an example and only to illustrate preferred embodiments of the present invention, and they are given as, as you may think, the most useful and easy to understand description of the principles and conceptual aspects of the invention. In this regard, the structural features of the invention are presented in as much detail as is necessary to understand the fundamental principles of the invention, while on the basis of this description, in conjunction with the attached drawings, those skilled in the art can understand that various embodiments of the invention can be implemented in practice.

Before explaining in detail at least one embodiment of the invention, it should be noted that the invention is not limited in its application to the details of the structure and the arrangement of the components presented in the following description or illustrated in the drawings. The invention can be applied to other embodiments and used in practice or performed in various ways. You should also understand that the language and terminology used in this document are for the purpose of description and should not be construed as limiting.

In some embodiments, underwater modules for increasing gas pressure and liquefaction systems have been proposed, and also methods for increasing pressure and liquefying are proposed in this document. The gas is compressed hydraulically by means of an upward pressure of the rising liquid, which is separated from the gas by means of a layer of water-immiscible liquid located on top of the brine. To achieve a high compression ratio, high vessels are used.

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which lowers the liquefaction temperature. The pressurizing fluid is supplied gravitationally after gasification, transportation to shallow depths and condensation. Cooling modules are used to liquefy compressed gas. A cascade of compression and cooling modules can be used in series for higher liquefaction temperatures, which allows subsequent cooling with seawater. The pressurizing fluid, vessel dimensions, feed module, refrigerants and sales of cooling modules are selected in accordance with the marine location in order to liquefy natural gas near the gas source.

FIG. 1 is a structural block diagram of a high level of subsea gas pressure boosting module in accordance with some embodiments of the invention. FIG. 2 is a schematic representation of a high level of an underwater gas pressure boosting module 110 according to some embodiments of the invention. The thermodynamic processes used in this invention are illustrated schematically in FIG. 1 in the form of a pressure increase section 111 above the critical value and cooling the pressurized gas to its liquefaction section 115.

Underwater gas pressure boosting module 110 comprises at least one vertical vessel 111 shown in FIG. 1 in two working states, and indicated by the position number 111A to increase the pressure of the gas and 111B for the suction of gas, which is explained below. The vertical vessel 111 is adapted to receive gas 90 through the upper part 112 of the vertical vessel, for example, through the upper opening, and the pressure-increasing fluid 80 through the lower part 113 of the vertical vessel, for example, through the lower opening.

The subsea gas pressure boosting module 110 comprises a valve system 114 having an upper subsystem 114A having fluid communication with the upper part 112 of the vessel 111, and a lower subsystem 114B having fluid communication with the lower opening 113. The subsystems 114A, 114B are configured to control and regulation of the introduction and pumping of gas 90 and liquid 80, respectively. The valve system 114 is configured to increase the pressure of the gas 90 by introducing the pressure-increasing fluid 80 into the vessel 111, pumping the gas 90A at an increased pressure through the upper opening 112 after reaching a predetermined pressure and introducing the gas 90 into the vessel 111 by pumping the pressure-increasing fluid 80 through the lower part 113 vessel 111.

The vertical vessel 111 further comprises a layer of water-immiscible liquid 70 on the layer of water-salt solution 60. The layers are arranged so as to separate the pressure-boosting liquid 80 from the gas 90 in the process of pressure increase and gas suction 90. Fluids 60, 70 are selected in this way so that the density of the pressure-increasing fluid 80 is higher than the density of the water-salt solution 60, which, in turn, would be higher than the density of the liquid that is not miscible with water 70. Such a choice of densities (at working temperatures and pressures) is It is intended to hold the layer of the water-salt solution 60 on top of the pressure-increasing liquid 80 and to ensure that the layer of the water-immiscible liquid 70 is kept on top of the layer of the water-salt solution 60.

In some embodiments, the implementation of the gas 90 is pre-cleaning the source of raw materials to remove harmful impurities. The gas then undergoes compression (at 111) and condensation (at 115) due to its cooling by means of an external coolant (cooling modules 115, see below), cooled in its circulation loop at the previous stage of the cooling cascade, while the gaseous phase at each stage of such cooling cascade is compressed in vertical vessels 111, located in sea water.

For this purpose, after filling the vessel 111 with gaseous substance 90, from a higher level, a volatile and water-immiscible heavy non-aqueous liquid 80 is fed to the lower part of each vessel under a layer of water-salt substance 60, the density of which is less than the density of non-aqueous liquid 80, and which shielded, for example, by a liquid hydrocarbon 70 having a density less than the density of the water-salt substance 60.

After squeezing the compressed gas 90A by means of a rising heavy liquid column 80, the next portion of the gaseous substance 90 is sucked out by pumping the main part of the heavy non-aqueous liquid 80 out of the vertical vessel 111.

The return of the volatile heavy non-aqueous liquid 80 from the vertical vessels 111 to the upper level is accomplished by re-gasifying it in the gasifier 120 (the term gasifier is used in the present description in its physical sense, i.e., a device that turns a liquid into a gas) underwater conditions due to heat exchange (for example, in the coil 121) with an external coolant (for example, water vapor 30), followed by release to the upper elevation through the insulated pipe 122 of the resulting non-aqueous vapor 80A to condense them in the condenser 130. Then, nonaqueous heavy liquid 80, after condensation in the upper layer is supplied again under the influence of gravity (in the container 140) to the base of each vertical receptacle 111 under a layer of water-salt substances 60, the shielding 70 by the liquid hydrocarbon.

In some embodiments, a pressure-enhancing fluid 80, which may contain, for example, various non-combustible, fire-resistant and explosion-proof organic substances with the specific 3 029258

A divided set of thermodynamic, rheological, hygienic and sanitary properties, can be used as a volatile and water-immiscible heavy non-aqueous liquid. They are, for example, fully (or partially) halogen derivatives of hydrocarbons of a homologous alkane series, for example, perfluorocyclopentane, trifluorobromoethane, hexafluorochlorobromo propane, perfluoropentane, dibromofluoromethane, difluorodibromomethane, or mixtures thereof.

In some embodiments, the implementation of the water-salt solution 60 may contain various solutions of mineral and organic salts in fresh (or sea) water, the density of which is less than the density of non-aqueous medium, for example, solutions of calcium or magnesium nitrates, potassium bromides, zinc and calcium, carbonates , formates and potassium acetates, various halides of other alkali metals, as well as compounds prepared on the basis of fresh (or sea) water, containing, along with mineral salts, ethylene glycol, glycerin and other polycomponents tnye water-salt systems that differ not only lower specific gravity compared with Halogenated hydrocarbons, but also sufficiently low freezing point that can be used as an aqueous saline medium, coating column the volatile heavy liquid.

In some embodiments, the implementation of water-immiscible liquid 70 may contain various water-immiscible aliphatic or aromatic organic compounds having a low freezing point, and whose density is less than the density of mineral (organic) salt solutions 60, for example hexane or toluene, which can be used as a liquid hydrocarbon, shielding a water-salt medium, covering a column of volatile liquid.

The pressurized gas 90A can be liquefied by the cooling module 115, as explained in detail below.

The absence of any mechanical devices with electrical wiring used to compress gaseous media in the cascade method of liquefying methane at each stage of such a cascade, and their compression in submarine vertical vessels due to squeezing the gaseous phase out of such cylinders by supplying non-aqueous heavy liquids 80 with a specific set physical and other properties under the layer of water-salt substance 60 provide not only a significant reduction in the cyclical nature of the operation of such piston compressors, not containing x any moving mechanical parts, but also almost completely eliminates electricity consumption for the implementation of such a process.

In addition, the underwater placement of high-pressure vessels 111 provides a significant reduction in their material consumption (external hydrostatic pressure of seawater compensates for internal pressure, which makes it possible to manufacture such equipment with thinner walls).

The lack of high-speed mechanical compressor equipment with powerful electrical wiring not only reduces the cost of tool structures for implementing the process according to the invention, but also significantly increases the safety of developing such an underwater gas field.

Preferably, all the distinctive features of the present invention are essentially interrelated, and their combinations mentioned provide a solution to the problem of the invention. The invention, however, should not be construed as limited to the implementation details given as examples below.

Embodiments of the invention illustrated, for example, in FIG. 1 and 2, comprise an underwater gas pressure boosting module 110 comprising at least one vertical vessel 111 configured to receive gas 90 through the upper part 112 of the vessel 111 and pressurizing the liquid 80 through the lower part 113 of the vessel 111, and additionally containing no layer water-miscible liquid 70 on the layer of water-salt solution 60. The density of pressure-increasing liquid 80 is higher than the density of water-salt solution 60, which, in turn, is higher than the density of water-immiscible liquid 70, which ensures that the layer in a single brine solution 60 on top of the pressure-raising fluid 80, and that ensures the retention of a layer of water-immiscible liquid 70 on top of the layer of water-salt solution 60. The underwater gas pressure boosting module 110 further comprises a valve system 114 configured to increase the gas pressure 90 by introducing increasing the pressure of the liquid 80 into the vessel 111, pumping out the gas 90A of the increased pressure through the upper opening 112 after reaching a predetermined pressure and introducing the gas 90 into the vessel 111 by pumping the increasing pressure Liquid 80 through the lower hole 113. Any of the holes 112 and 113 may contain several holes. In some embodiments, the implementation for the introduction and pumping of gas 90 (as the top hole 112) and the fluid 80 (as the bottom hole 113) can be used separate holes.

In some embodiments, the implementation of the underwater gas pressure boosting module 110 may further comprise a feeding module 125 having fluid communication with the valve system 114B and configured to receive the pressurizing fluid 80 from the underwater gas pressure boosting module 110 and supply the pressure boosting fluid 80 to the underwater module 110 increase gas pressure.

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In some embodiments, and referring to the detailed example below, the feed module 125 may comprise a gasifier 120, such as a steam boiler 120, configured to gasify the pressure-boosting fluid 80; a condenser 130 located at a certain depth under water and configured to condense a gasified pressurizing fluid 80A; thermally insulated pipeline 122, configured to supply a gasified pressurizing fluid 80A from the gasifier 120 to the condenser 130; and a container 140, such as underwater storage 140, configured to receive condensed pressure boosting fluid 80 and gravity feed pressure boosting fluid 80 to the valve system 114 (for example, to valves 114B).

In some embodiments, the implementation of the underwater module 110 increase the pressure of the gas may contain two vertical vessel 111, made with the ability to work in a reciprocal manner, with one vessel increases the pressure in the gas 90, while the other vessel receives the gas 90.

Underwater gas pressure boosting module 110 may be associated with natural gas production platform 20 and receive natural gas in the form of gas 90 from platform 20. Liquefied natural gas 90 may be stored in submarine storage 92 or supplied ashore. The vessels 111 are adapted to withstand the subsea pressure, as applied to the operating conditions of the module 110. The underwater module 110 for increasing the gas pressure can also be adapted to compress and / or liquefy other gases or gas mixtures. In some embodiments, the implementation of the underwater module 110 increase the pressure of the gas can be performed with the possibility of compressing and / or liquefaction of refrigerants used to liquefy natural gas 90, as illustrated below. Numerous subsea gas pressure boosting modules 110 can be arranged in a cascade for compressing gas 90 in a stepwise manner, at each stage of the cascade, taking compressed gas and compressing the received gas even more. Numerous subsea gas pressure boosting modules 110 may be arranged in a cascade for compressing and liquefying several types of gases having increasing temperatures at a critical point in order to cool the last gas in the cascade with seawater, for example, with deep seawater. With this arrangement, the cooling effect of seawater is gradually enhanced in order to provide cryogenic cooling of the first gas in the cascade. A non-limiting detailed example is provided below.

FIG. 3 is a structural block diagram of a high level of an underwater natural gas liquefaction system 100 according to some embodiments of the invention; FIG. 4 is a schematic representation of a high level of an underwater natural gas liquefaction system 100 according to some embodiments of the invention.

In some embodiments, the implementation of the underwater system 100 liquefaction of natural gas may contain three underwater module 110A, 110V, 110C increase the pressure of the gas, located in the form of a cooling and pressure-increasing cascade for the effective liquefaction of natural gas.

The first module 110A may be adapted to increase the pressure of natural gas 90, and the cooling module 115A for natural gas may be adapted to liquefy natural gas 90A at elevated pressure (to produce liquid natural gas 91) using the first refrigerant 50.

The second module 110B may be configured to increase the pressure of the first refrigerant 50, and the first cooling module 115B may be adapted to liquefy the first refrigerant 50A of increased pressure (to obtain the first liquid refrigerant 51) using the second refrigerant 40. The first liquid refrigerant 51 is used in a natural gas cooling module 115A for cooling pressurized natural gas 90A.

The third module 110C may be adapted to increase the pressure of the second refrigerant 40, and the second cooling module 115C may be adapted to liquefy the second refrigerant 40A of elevated pressure (to produce the second liquid refrigerant 41), possibly using the surrounding seawater. The second liquid refrigerant 41 is used in the first cooling module 115B to cool the first refrigerant 50A under pressure.

In some embodiments, system 100 may implement additional steps using additional refrigerants, or several pressure boosting steps (each performed using the respective vessels 111) for each refrigerant, etc. The number and type of refrigerants and the number and technical characteristics of the booster modules can be determined according to the marine characteristics (depth, surface temperatures, building restrictions) and operational factors.

The first refrigerant 50 can be selected so that it has a critical point at a higher temperature than natural gas 90, and the second refrigerant 40 is selected so that it has a critical point at a higher temperature than the first refrigerant 50. In this configuration, the cooling capacity seawater is enhanced by the use of refrigerants with a decreasing temperature of the critical point until cooling does not provide compression of natural gas 90A.

Natural gas 90, produced on the seabed (as a source of natural gas 89) for liquefaction by platform 20, can be prepared by dehydrating it from water vapor and purifying

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(if necessary) from harmful impurities, such as hydrogen sulfide and carbon dioxide. Natural gas 90 may then be introduced by suction into one of the submarine vertical vessels 111 by venting a column of volatile heavy liquid 80, shielded by a layer of water-salt substance 60 coated with liquid hydrocarbon 70, as explained below.

Natural gas 90 may undergo compression in vessels 111, followed by squeezing a portion of natural gas accumulated in a vertical underwater vessel 111 by supplying volatile heavy fluid from a higher level under a layer of water-salt substance 60, which remains near its base, into such cylinder 111.

After this, system 100 can cool and condense compressed natural gas 90A by evaporating external refrigerant boiling at low temperature, for example, the first refrigerant 50. Natural gas under elevated pressure is squeezed to liquefy from an underwater vertical vessel 111 by means of a rising volatile heavy column. fluid 80.

Liquefied natural gas can accumulate in the underwater storage 92 with its subsequent transportation and delivery to consumers on the coast by pumping via pipeline or transporting it by sea in special tankers.

Pressure boosting fluid 80 may be introduced into the vessels 111 by gravity, using the elevation difference present in the sea. For this purpose, the pressure-boosting fluid 80 undergoes the underwater re-gasification of the volatile heavy fluid 80 discharged from the vertical underwater vessels 111 (while gas is being sucked into them) by means of an external coolant, for example, the gasifier 120, followed by directing the formed vapors 80A to condensation, implemented for more high elevation by cooling them with seawater (in a condenser 130 cooled with a screw 135). After raising the pressurizing fluid 80 in the form of a gas 80A, the fluid 80 can be reintroduced into the vessels 111 by gravity, as illustrated below.

The container 140 is used to accumulate volatile heavy liquid 80 in a collection tank installed at the top level, followed by feeding a liquid non-aqueous medium 80 under a layer of saline solution 60, which persists in vertical vessels 111 after sucking the next portion of gas 90 in them.

Another subsea gas pressure boosting module 110 can be used to suck up the vapor of external coolant 50 (after evaporation of refrigerant 50 was used to divert the heat of condensation of natural gas) into one of the vertical vessels 111 of the cooling cascade (see detailed example below), with its subsequent extrusion from the cylinder 111, implemented in a similar way, that is, by supplying volatile heavy liquid 80 under a layer of water-from the left solution 60, remaining in this vessel 111.

After that, the system 100 can cool the vapor of the residual coolant 50, squeezed out of the vertical vessel 111 and cool the natural gas 90, and condense it by heat extraction of evaporation from another, boiling at a lower temperature (compared to methane), a coolant wrapping the turn into its own loop of circulation preceding the cooling stage of the cascade. All coolants, the heating of which realizes the transition of a volatile heavy liquid from a liquid to a gaseous state at all stages of the cascade, can cyclically move in system 100.

Example.

In the following non-limiting example, pressurized natural gas 80A can be cooled with ethane as the first refrigerant 50; the first pressurized refrigerant 50A may be cooled with propane as the second refrigerant 40; pressure boosting fluid 80 may be difluorodibromomethane; water-salt solution 60 may be an aqueous solution of calcium bromide; and the water-immiscible liquid 70 may be a liquid hydrocarbon.

Natural gas 90 may be supplied from source 89 for liquefying, after drying, water vapor, purification from hydrogen sulfide and suction into one of the vertical submarine vessels 111A and 111B, operating, for example, in antiphases.

The suction of natural gas occurs due to the release of a column of fluoride dibromomethane (density 2.28 g / cm ³ , boiling point 24.5 ° C), which fills such a working cylinder.

This low-boiling fluid, obtained by alternately discharging vertical vessels 111A and 111B, is fed for re-gasification to a steam boiler 120 heated with water vapor pumped into its coil 121 from a steam turbine (not shown) mounted on a drilling platform 20 which is part of the steam power plant. Condensate resulting from the condensation of this external heat exchange medium is squeezed out of the coil 121 by returning fresh steam back to the drilling platform 20, and this hot water is pumped again into the steam boiler (not shown) using a high-pressure pump (not shown).

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To avoid mixing natural gas sucked into vessels 111A and 111B with difluorodibromomethane vapors, the column of this volatile heavy liquid is shielded by a layer 60 of an aqueous solution of calcium bromide — having a low freezing point of water-salt liquid that is immiscible with an organic medium whose density is lower than the density of difluorodibromomethane (depending on the concentration and temperature, the density of calcium bromide solutions can reach 1.82 g / cm ³ ). It is characterized by an abnormally low freezing point, depending on the ratio of the components of such non-freezing liquid.

In turn, this layer 60 of water-salt substance, the screening column of fluoride dibromomethane, is poured with a layer of hexane 70 as a non-limiting example of the second refrigerant. Hexane can be used as the second refrigerant 70, since it is a water-immiscible liquid hydrocarbon with the lowest density of this series of liquids (0.66 g / cm ³ ).

However, other water-immiscible hydrocarbon liquids having a low freezing point, for example, toluene (density 0.87 g / cm ³ ), or their mixtures whose vapors of natural gas cannot spoil the consumer properties of the latter, can be used as a coating for the upper liquid.

Such double liquid insulation of the gaseous phase in vertical vessels 111 from a volatile non-aqueous liquid prevents penetration of difluorodibromomethane vapor (which is not just incombustible, but one of the most effective fire-fighting substances at the moment) into compressed natural gas, but also wetting methane with water vapor, which may be located above the surface of any solutions of mineral (organic) salts in water.

Organic vapors formed in the steam boiler 120 when the difluorodibromomethane transitions from a liquid to a gaseous state, rise along the heat-insulated channel 122 to the condenser 130 installed under the drilling platform 120, in the upper layer of sea water, having an average daily summer temperature from 12 to 14 ° C. (In the case of natural gas production at low latitudes of the ocean, if the temperature of the upper seawater layer is close to 24 ° C, perfluoropentane can be used as a volatile heavy liquid instead of difluorodibromomethane. The latter has a slightly lower density of 1.62 g / cm ³ , but higher condensing temperature equal to 29.3 ° C. Otherwise, condenser 130 should be immersed to great depths, where sea water is colder at any time of the year).

To improve the conditions of heat removal during the condensation of difluoride bromomethane, the condenser 130 is washed by seawater pumped through the latter by means of an external propeller 135.

Difluorodibromomethane 80, thus converted into a liquid state, accumulates in underwater storage 140, from where it is fed to compress natural gas through a vertical pressure pipe 122 to the bottom of an underwater vertical vessel 111B adjacent to vessel 111A, and the specified vessel 111B will be completely filled by that time methane in the process of emptying the working space of this vertical cylinder from the main volume of its previous liquid contents.

For this purpose, the liquid difluorodibromomethane is supplied from the underwater storage 140 under a layer 60 of a low freezing point of the water-salt substance remaining in the vessel 111B, which screens the rising column of this volatile liquid.

In some embodiments, system 100 comprises a feed module 125, which may include a gasifier 120, such as a steam boiler 120, configured to gasify a pressurizing fluid; a condenser 130 located at a certain depth under water and configured to condense a gasified pressurizing fluid 80A; thermally insulated pipeline 122, configured to supply a gasified pressurizing fluid 80A from the gasifier 120 to the condenser 130; and a container 140, such as underwater storage 140, configured to receive condensed pressure boosting fluid 80 and gravity feed pressure boosting fluid 80 to the valve system 114 (for example, to valves 114B).

By raising the level of difluorodibromomethane 80 in cylinder 111, the volume not flooded with liquid medium above the surface of the double liquid screen (layers 60 and 70) covering the non-aqueous liquid column 80 begins to shrink gradually. This leads to compression of methane 90 contained in the 111B vessel. When a vertical vessel 111 is filled with a liquid medium 80 to 90%, the pressure of methane 90, which is maintained above the surface of the layer 70 of hexane, increases tenfold. However, to raise the liquefaction temperature of natural gas from -161.5 ° С (liquefaction point at atmospheric pressure) to the maximum possible, i.e. critical point (-82.5 ° C), its pressure should be increased to at least 4.49 MPa.

Thus, only about 2.2% of the free geometric space of a vertical vessel 111 should remain above the surface of the water-salt substance 60 shielded by liquid hydrocarbon 70. Natural gas 90, compressed to 4.5 MPa, can be completely liquefied upon its subsequent cooling. to a temperature of about -83 ° C. In some embodiments, several vessels 111 can be used to implement several stages of compression, providing 7 029258

natural gas compression 90.

In some embodiments, the container 140 may be configured to provide a certain differential over the vessels 111, designed to allow gravity to pressurize the fluid 80 to the vessels 111. For example, to achieve this degree of compression of natural gas, the level of liquid difluorodibromomethane 80 in the underwater storage 140 (communicating via a vertical pressure pipe 122 with any of the vertical working vessels 111 in which the gases 90, 50, 40 are compressed), in order to balance this pressure must exceed the surface elevation of the double liquid screen (60, 70) covering the volatile liquid column supporting the compressed gas 90A, with a drop of at least 201 m, taking into account that the density of such a non-aqueous medium exceeds the density of water 2.28 times .

Thus, when using difluorodibromomethane as the working medium 80 of such a thermodynamic cycle, the lower part of the underwater storage 140 of such a heavy liquid 80 should be vertically spaced relative to its upper level in vertical vessels 111 with a difference of at least 201 m gas, equal to 45, i.e., from atmospheric pressure 0.1 MPa to its working value of 4.5 MPa).

In some embodiments, in which perfluoropentane is used as a pressurizing fluid 80 instead of difluorodibromomethane at offshore gas fields at tropical latitudes (as a more easily condensable liquid), this drop in height should be 1.4 times greater, i.e. 283 m, taking into account that the density of perfluoropentane is 1.62 g / cm ³ , and not 2.28 g / cm ³ .

With increasing sea depth, the proximity of the seabed to the drilling platform 20 does not limit the fall in height between the pillars of heavy fluid 80 used in such communicating vessels 111. In addition, other volatile liquids 80 of even lower density can be used as the working medium in thermodynamic cycles for example, hexafluorochlorbromopropane (density 1.55 g / cm ³ ). Their 80A vapors may condense in the upper (most heated by solar radiation) layers of seawater even on the hottest summer days (the condensation temperature of hexafluorochlorobromopropane is 35.7 ° C). In this case, vertical vessels 111, in which natural gas 90 undergoes compression to such a pressure, can be immersed to an even greater depth until they reach the seabed.

In other embodiments, in the case of underwater gas production in the coastal zone at shallow depths, an even heavier non-aqueous liquid 80, such as dibromofluoromethane (density 2.42 g / cm ³ , boiling point 64.5 ° C), used to fill I-shaped hydraulic system in order to lower the height of such a water tower. In these embodiments, at least several vessels 111 may have an imaginative form in order to lower the necessary specific differential for gravity supply of pressure-increasing fluid 80. In this case, the difference in the levels of liquid contents of such communicating vessels is even smaller, and a difference of 194 m may be sufficient. When using tribromofluoromethane (density 2.71 g / cm ³ , boiling point 105 ° C), this difference is slightly less than 170 m, etc. Likewise, pressure boosting fluid 80 can be selected to provide operation for a given marine location and topography, and vessels 111 can be similarly constructed. Pressure boosting liquid 80 and vessels 111 can be designed and selected to provide the necessary pressure boost liquids 80 as applied to at least one of the vessels 111 at a predetermined sea location.

When the pressure becomes 4.5 MPa during the operation of shut-off valves 114A, natural gas, alternately compressed to this pressure in vertical vessels 111, is released from them for cooling and condensation.

Pre-cooling of compressed natural gas 90A can be implemented in a heat exchanger 150A installed at a depth exceeding 100 m. This can be explained by the fact that the supply of warm water in the world's oceans with temperatures of 10 ° C and above is only about 8% of its total volume . It is concentrated in the upper layer of seawater with a thickness of less than 100 m. Below this layer, with increasing depth, the water temperature gradually drops to 1-3 ° C. This temperature corresponds to about 75% of the total world ocean. Such a temperature regime in the deep-sea part of the seas and oceans remains practically unchanged throughout the year and throughout the day. Accordingly, by pumping such free coolant through heat exchanger 150A with the help of propeller 155A, the temperature of the compressed natural gas passing through it can be lowered to 3-5 ° C.

The gaseous substance, previously compressed to 4.5 MPa and cooled in a heat exchanger 150A to 4 ° C, is first fed to a recovery heat exchanger 160A and then to a cold exchanger 166A cooled by evaporating the first refrigerant 51, for example, liquid ethane as the final coolant 50. The cold exchanger 166A can be located in a circulation loop on the stage of such a cooling cascade preceding the liquefaction of methane. It should be noted that, in this document, the term "cold exchanger" is used to refer to a heat exchanger serving to cool the relevant substance. The term "coolant" refers to any of the refrigerants in the system,

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for example, the first and second refrigerants 50, 40, as well as seawater at different temperatures.

Due to the fact that the cryogenic temperature (-88.7 ° C) is reached in the cold exchanger 166A during the transition of liquid ethane 51 (previously throttled in the control valve 167A) from liquid 51 to gaseous state 50, cold natural gas compressed in vertical vessels 111 to pressure close to critical, becomes liquid. After that, the liquefied methane 91 is delivered, as a finished product, to the underwater storage 92, from where it is subsequently shipped to consumers by gas tankers or delivered to the coast in a liquid state through underwater pipelines.

Other cryogenic liquids, such as ethylene (normal boiling point 103.5 ° C) or perfluoromethane (normal boiling point -127.9 ° C) can be used as a final coolant that can liquefy compressed natural gas in addition to ethane. In this case, the pressure during the compression of methane does not necessarily reach 4.5 MPa: in this case, natural gas can also be liquefied at a lower pressure.

Accordingly, the differential provided by the container 140, i.e. the height difference between the levels of the volatile heavy liquid 80 in the “water tower” (container 140) and in the vertical vessels communicating with it 111 can also be lowered.

Ethane gas 50 leaving the cold exchanger 166A, transferring its coldness to the pre-cooled methane 90A, can be supplied for its liquefaction, which is realized in this mono-stage system in exactly the same way.

For this purpose, ethane 50, leaving the cold exchanger 166A after re-gasification, is fed to a recovery heat exchanger 160A, where it reports its remaining artificial coldness to compressed methane. After that, such residual coolant is compressed. For this purpose, the first refrigerant 50, for example ethane, is sucked into one of the vertical vessels 111 of the second gas pressure boosting module 110B, operating according to the same principles as the first gas pressure boosting module 110A, using pressure vessels 111, working in antiphases due to the fact that on them (more precisely, on their basis) from storage 140, liquid difluoridibromomethane is alternately fed under a layer of water-salt substance.

The first cooling module 115A thus comprises a heat exchanger 150A, equipped with a screw 155A, and a heat recovery heat exchanger 160A with a cold exchanger 166A.

Volumes of difluorodibromomethane, discharged from the vessels 111 after suction of multiple portions of ethane, are also fed for re-gasification to the steam boiler 120. From there, the organic vapors of such volatile liquid are released by the heat of the external heat carrier (in this case, the heat of water vapor condensed in the coil 121) into the condenser 130, mounted on the top level. This working fluid, condensed as a result of heat exchange with seawater, accumulates again in storage 140, from where it is supplied for the next filling of one of the vessels 111 of the second module 110B for compressing ethane to elevated pressure.

Unlike methane (in the form of gas 90), ethane (as the first refrigerant 50) is more easily liquefied (the boiling point of this cryogenic liquid at atmospheric pressure is not -161.5 ° C, as for methane, but almost twice as high more precisely, -88.6 ° C. The critical liquefaction temperature of ethane is positive and equal to 32.3 ° С, which almost always ensures the use of sea water as a free coolant for the removal of the heat of condensation of ethane, compressed to a critical pressure, for most of the world’s ocean). In such embodiments, system 100 may operate with a first refrigerant 50 to cool the compressed gas 90A, and the first refrigerant 50 may fluidize under the influence of low ambient sea temperatures.

Other embodiments may be intended to be used even on the hottest summer days in shallow areas of some natural water bodies (for example, in the Caspian Sea), where sea temperature may rise to a higher level.

In this case, even ethane 50, compressed to a critical pressure (4.7 MPa) in vertical vessels 111, cannot be easily condensed with high efficiency in a compact heat exchanger device by means of a coolant with such a low cooling potential.

Thus, to ensure the maintenance of high performance of the process of liquefying natural gas under any meteorological conditions of the offshore gas field, ethane condensation can also be implemented using artificial coldness formed in the first stage of such a cooling cascade, while propane can be used as a working medium. ammonia.

For this purpose, ethane 50 may undergo compression in the vertical vessels 111 of the second module 110B to a more moderate pressure as compared to the critical pressure (4.7 MPa). Ethane 50 may first be cooled by seawater in a heat exchanger 150B fitted with a screw 155B, and then ethane 50 may be supplied to a heat recovery exchanger 160B. The heat exchanger 160B may be adapted to remove artificial coldness residues performed by the cold exchanger 166B by means of a second refrigerant 41, for example propane, undergoing re-gasification in the heat exchanger 166B. The second refrigerant 41 can be passed through the preheater - 9 029258

Throttling (after liquefying as described below) in control valve 167B.

The second cooling module 115B thus contains a heat exchanger 150B, equipped with a screw 155B, and a heat recovery heat exchanger 160B with a cold exchanger 166B.

Thus, the compressed first refrigerant 50 (for example, ethane) is condensed in the refrigerant 166B due to the heat generated by the phase transition of the second refrigerant (for example, propane) from the liquid 41 to the gaseous state 40.

Propane 40, circulating in the first stage of such a cooling cascade, is also the most easily liquefiable gas of all coolants used in such a methane liquefaction system.

Propane condensation point at atmospheric pressure is not a cryogenic value. It is found in nature (-42.6 ° C) and is quite comparable with the meteorological conditions in the atmosphere over the Arctic Ocean during the polar night. The critical liquefaction temperature is 96.8 ° C. Its vapor pressure, corresponding to such a critical temperature, is also significantly lower (4.1 MPa) than for ethane (4.7 MPa). Therefore, it does not always make sense to compress propane to a pressure characteristic of ethane compression in vertical vessels 111 of the second module 110B.

Similarly, propane liquefaction in the first stage of such a cooling cascade can be implemented in the same way as for ethane and methane, but under milder process conditions. While gas 90 (for example methane) is compressed in vessels 111 of the first module 110A, and the first refrigerant 50 (for example ethane) is compressed in vessels 111 of the second module 110B, the second refrigerant 40 (for example propane) can undergo compression in vessels 111 of the third module 110C .

For this purpose, two vertical vessels 111 of the third module 110C gas pressure boosting, working in antiphases, are used. The gaseous second refrigerant 40 (for example, propane), alternately sucked into them after re-gasification (in a 166B cold exchanger) and recuperative heat exchange (in a heat exchanger 160B), is compressed in such vertical cylinders to a pressure that is higher than the warmer sea water used for cooling this gas in a heat exchanger 150С, equipped with a screw 155С.

Propane 40, alternately compressed in vertical vessels 111, is pre-cooled with seawater in a 150C heat exchanger and then fed to liquefaction realized in an even deeper condenser 160C bathed in even colder seawater pumped through it by screw 165.

In this regard, it may be necessary to use colder sea water when the condenser 160C is fixed at a significantly lower geodetic level than the 150C heat exchanger, which ensures high efficiency of propane condensation at any time of the year and during the day. In other embodiments, the cooling module 115C may be configured in the same manner as the cooling module 115B. In some embodiments (for example, if the first refrigerant 50 can be sufficiently cooled at deep sea temperatures), the cooling module 115B can be configured as the illustrated cooling module 115C.

Propane 41, thus liquefied in the condenser 160C (due to the free cooling potential of the deep sea water), is throttled in the control valve 167B and then supplied to the 166B refrigeration unit.

Propane boiling at 166B at atmospheric pressure (the normal boiling point of liquid propane is -42.6 ° C), changing from liquid to gaseous state, takes the heat of condensation from ethane. This leads to the liquefaction of such a coolant, previously compressed in vertical vessels 111 of the second module 110B, which is in the circulation loop of the second stage of the underwater cooling cascade.

The final recovery of the artificial coldness removed from the cold exchanger 166B with propane vapor is carried out in the recovery heat exchanger 160B due to the exchange of coldness between the propane gas and compressed ethane supplied for condensation.

The third cooling module 115C, therefore, contains a heat exchanger 150С, equipped with a screw 155С, and a deep-water condenser 160С with a screw 165.

Propane 41, thus re-gasified in the cold exchanger 166B, is returned for compression into one of the vertical vessels 111 of the third module 110C, i.e. at the beginning of the process, thus closing the coolant circulation loop, which is the working medium of the first stage of the underwater cooling cascade.

Thus, high standards of production and trouble-free operation of the equipment are ensured, and all cooling agents (for example, the first and second refrigerants 50, 40) used in such a multi-stage process cascade are practically not consumed, since their circulation cycles for these substances are almost completely closed

Preferably, the use of the invention may allow to overcome the well-known disadvantages of traditional multi-stage methods of cascade liquefaction of natural gas, not only due to the need to accommodate cooling equipment on the working platform of a drilling platform of extremely limited production area, but also due to the degradation of rigid communication

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between the level of its thermodynamic perfection and the production capacity of the module of the methane liquefaction device in the technological process according to the invention.

In addition, with an increase in productivity and, thus, with an increase in the height of vertical submarine vessels 111 of modules 110А, 110В and 110С (during the development of deep-water and super-deep-sea gas fields), the cyclical nature of the compression process of the corresponding gases decreases even more and each stage of the cooling cascade uses thermal energy instead of electrical power. This generation of solutions for offshore gas fields is incomparably cheaper than the generation based on electricity, using expensive floating power plants and an electric drive.

An additional advantage of placing huge working cylinders of such a hydraulic compressor in underwater conditions is to increase the efficiency of removing thermal energy of gas compression with an increase in their overall vertical dimensions. The fact is that most of the offshore gas fields found at the moment are located in deep and ultra-deep parts of the world’s ocean, which makes it possible to erect such vertical vessels 111 with a height of hundreds and thousands of meters. Thus, a large part of the natural heat exchange surface of such compression equipment with the environment is immersed in seawater having a year-round temperature of 1-3 ° C, which ensures a significant reduction in the overall energy consumption of the artificial cold generation system by diverting a significant portion of the heat generated gas, through such free coolant.

Preferably, working below sea level also reduces the surrounding working temperature. Thus, the liquefaction of natural gas is more efficient and, in particular, more thermally efficient than the liquefaction above the sea surface or onshore.

In addition, the invention is of particular interest for the development of deep-sea and super-deep-sea gas fields. This is due not only to the fact that the sea water temperature decreases with increasing depth of the sea, and it becomes possible to accommodate higher vertical submarine vessels 111, but also to the fact that the hydrostatic pressure increases. Thus, the internal pressure of the compressed gas contained in any submarine vessel is counteracted by external hydrostatic pressure. This reduces the consumption of materials for the main process equipment, which makes it cheaper and at the same time ensures higher safety of its operation.

Even greater prospects for reducing power consumption during the liquefaction of methane produced on the seabed, arise in the case of the development of deep-sea gas fields located in areas of increased thermal activity of the earth's crust. In these cases, in addition to the drilling of gas wells, under the seabed from the drilling platform 20 can drill wells that reach rocks with elevated temperatures. When the circulation of coolant (which can re-gasify, passing through the coil 121 of the steam boiler 120 for such a volatile liquid as difluorodibromomethane) in this circuit, the consumption of industrial energy resources in this process becomes even smaller.

Taking into account that methane itself is the main source of energy for offshore gas fields, the use of free thermal energy of the earth's crust to close compression cycles for all types of gaseous media in the natural gas compression method according to the invention provides an additional increase in the production capacity of such a drilling platform for its final product.

In some embodiments, the implementation of the use of the present invention provides for the development of offshore gas fields located at a distance of hundreds and thousands of kilometers from the ocean coast, regardless of the depth of natural gas. Finally, transporting one kilogram of gaseous methane over large and extra-large distances is incomparably more expensive than transporting one kilogram of liquid natural gas, since the density of one cubic meter of gaseous methane is only 720 g / m ³ , while one cubic meter of liquid methane weighs about 450 kg, i.e. 625 times more. In addition, liquefied methane, Unlike natural gas, is practically incompressible. Accordingly, when it is pumped in trunk pipelines, the main power consumption for its delivery over long distances is associated with overcoming the friction forces between such an extremely low viscosity fluid and the inside surface of the line. At the same time, when pumping methane gas, the main power consumption is associated with its compression, and not with transportation.

FIG. 5 is a high level block diagram illustrating a method of compressing and liquefying gas 200 according to some embodiments of the invention. Method 200 may include the step of increasing the pressure of a gas, such as natural gas or other gases, such as ethane or methane. Method 200 may further comprise the step of cooling the pressurized gas to liquefy it. For example, the gas pressure may exceed its critical point, and cooling the compressed gas may thus liquefy the gas. In some embodiments, method 200 may comprise

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compression and liquefaction of natural gas, as illustrated in the non-limiting example below.

Method 200 comprises the step of increasing the gas pressure in at least one vertical vessel (step 210), for example the step of increasing the pressure of natural gas (step 211) through cyclically performed steps (step 235): (ί) inject gas into the top of at least one a vertical vessel (step 212); (ίί) inject a pressure-boosting fluid into the bottom of at least one vertical vessel to increase the gas pressure (step 215); separating the pressurizing fluid from the gas through a layer of a water-immiscible liquid on the brine layer (step 220); and pumping the pressurized gas through the upper port after reaching the predetermined pressure (step 230). The pressure boosting step may be performed cyclically (step 235), for example, by introducing gas by pumping a pressure-boosting fluid from the bottom of at least one vertical vessel (step 216). Thus, in natural gas, pressure can be continuously increased by introducing and pumping a pressure-increasing fluid.

In some embodiments, method 200 may further comprise the following steps: select a pressurizing fluid so that it has a higher density than the density of the brine (step 222); select the hydrochloric solution so that it has a higher density than the density of the water-immiscible liquid (step 224); and choose a water-immiscible liquid so that it has a higher density than the gas density (step 226) to hold the gas on top of the layer of water-immiscible liquid, layer of water-immiscible liquid on top of the layer of brine and the layer of brine the solution on top of the pressurizing fluid (step 228).

In some embodiments, method 200 may further comprise the step of pumping an evacuated pressurizing fluid through gasification, conveying upward, condensing, and feeding downward, comprising the following steps: pumping the evacuated booster fluid back to the bottom of the vessel (step 240); gasifying the evacuated pressurization fluid (step 242); gasified pressurization fluid is fed up into the insulated pipe (step 244); condensing the gasified pressurization fluid (step 246); the condensed pressure boosting fluid is fed down (step 248) and pressure boosting fluid is selected, and vessels are designed to provide a certain pressure drop boost fluid for at least one vessel in the marine location (step 249).

In some embodiments, method 200 may further comprise the following steps: liquefying natural gas of elevated pressure by cooling with the first refrigerant (step 250) and selecting the first refrigerant so that it has a critical point at a higher temperature than natural gas (step 255 ). The cooling step with the first refrigerant (step 250) may comprise the step of gasifying the first refrigerant to cool the pressurized natural gas (step 252).

In some embodiments, method 200 may additionally comprise the following steps: increase the pressure of the first refrigerant (step 257) and liquefy the first refrigerant of increased pressure by cooling the second refrigerant (step 260). Method 200 may further comprise the step of selecting the second refrigerant so that it has its critical point at a higher temperature than the first refrigerant (step 265). Cooling with a second refrigerant (step 260) may include a step in which gasification of the second refrigerant is performed to cool the pressurized natural gas (step 262).

In some embodiments, method 200 may further comprise the following steps: increase the pressure of the second refrigerant (step 267) and liquefy the second refrigerant of increased pressure by cooling with seawater (step 270).

Preferably, compression by pressurizing fluid 80 is superior to compression in current pistons or in another mechanical compression module in the following aspects. First, the heat energy of compression is dissipated in liquid and in the sea, and does not destroy moving parts (for example, bearings, insulating rings, etc.). Secondly, the introduction of gas by pumping the pressure-increasing fluid 80 is more efficient than using the return stroke of the piston system, in particular at high operating speeds. Also, fluid compression is more scalable than with a piston system, in which difficulties may arise due to the increasing inertia of the piston head. Finally, by reducing the number of mechanical parts, underwater work, and the fire-resistant nature of at least a few of the suitable pressure boosting fluids 80, the disclosed systems and methods are much safer than modern systems.

Preferably the objective of the present invention is to reduce the drop in the level of energy efficiency of the process with an increase in its performance, simplify the hardware representation, reduce the electricity consumption of the natural gas liquefaction system, and increase the degree of safety of offshore gas fields.

In some embodiments, the implementation of the proposed underwater modules increase the pressure of the gas and

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liquefaction systems, as well as ways to increase pressure and liquefaction. Gas is compressed hydraulically by means of injected seawater, which acts as a pressurizing fluid 80, separated from the gas by a layer of water-immiscible fluid. Sea water is gravitationally supplied by the action of deep sea pressure; at the same time the rising water compresses the gas in the upper part of the compression vessels. To achieve a high compression ratio lowering the liquefaction temperature, high, as far as possible vertical spiral vessels can be used. Cooling modules are used to liquefy compressed gas, which is carried out, if possible, with the help of a refrigerant, which itself has an increased pressure as a result of a similar effect. A cascade having two or more stages of compression and cooling modules can be used to provide subsequent cooling with the surrounding seawater. In some embodiments, the implementation of the refrigerant can be selected in such a way as to provide liquefaction at temperatures of the surrounding sea water. Vessel sizes and shapes, refrigerants and the implementation of cooling modules are selected in accordance with the marine location to ensure the liquefaction of natural gas near the gas source. The seawater used to increase the gas pressure can be used after pumping to increase the pressure of the in-situ gas during the production stages.

FIG. 6 is a structural block diagram of a high level of subsea gas pressure boosting module 110 according to some embodiments of the invention. Underwater gas pressure boosting module 110 contains at least one vessel 111 illustrated in FIG. 6 in two working conditions, indicated by the number of the position 111A for increasing the gas pressure and 111B for the suction of gas, which is explained below. The vessel 111 is configured to receive gas 90 through the upper part 112 of the vessel, for example through the upper opening, and sea water 80 through the lower part 113 of the vessel, for example through the lower opening. In some embodiments, seawater 80 is used as a pressure boosting fluid 80 in the context of the embodiments disclosed above.

The subsea gas pressure boosting module 110 comprises a valve system 114 having an upper subsystem 114A having fluid communication with the upper part 112 of the vessel 111, and a lower subsystem 114B having fluid communication with the lower opening 113. The subsystems 114A, 114B are configured to control and regulation of the introduction and pumping of gas 90 and sea water 80, respectively. The valve system 114 is configured to increase the pressure of the gas 90 by introducing seawater 80 into the vessel 111, pumping the pressurized gas 90A through the upper opening 112 after reaching a predetermined pressure and introducing the gas 90 into the vessel by pumping seawater 80 through the lower part 113 of the vessel 111.

The vessel 111 further comprises a layer of water-immiscible liquid 70, designed to separate seawater 80 from gas 90 in the process of pressurizing and sucking gas 90. Liquid 70 is chosen so that it has a density intermediate between the density of seawater 80 and gas 90 The chosen density (at operating temperatures and pressures) should ensure the retention of a layer of water-immiscible liquid 70 on top of sea water 80.

In some embodiments, the implementation of the gas 90 is pre-cleaning the source of raw materials to remove harmful impurities. The gas then undergoes compression (111) and condensation (on cooling modules 115, see below).

In some embodiments, the water-immiscible liquid 70 may contain aliphatic or aromatic organic compounds or mixtures thereof, and may have a density less than the density of seawater and a freezing point below -20 ° C. For example, the water-immiscible liquid 70 may be selected from the following list: hexane, hexane isomers, heptane, heptane isomers, toluene, their derivatives, and mixtures thereof.

The absence of any mechanical devices with electrical wiring used to compress the gaseous media in the methane liquefaction method, and their compression in submarine vertical vessels due to squeezing the gaseous phase out of the vessels by supplying sea water 80 provides not only a significant reduction in the cyclical operation of such piston compressors , not containing any moving mechanical parts, but also almost completely eliminates electricity consumption for the implementation process. In addition, the underwater arrangement of high-pressure vessels 111 provides a significant reduction in their material consumption (external hydrostatic pressure of seawater compensates for internal pressure, which makes it possible to manufacture such equipment with thinner walls). The lack of high-speed mechanical compressor equipment with powerful electrical wiring not only reduces the cost of tool structures for implementing the process according to the invention, but also significantly increases the safety of developing such an underwater gas field.

Preferably, all the distinctive features of the present invention are essentially interrelated, and their combinations mentioned provide a solution to the problem of the invention. The invention, however, should not be construed as limited to the implementation details given as examples below.

Underwater module 110 increase the pressure of the gas can be associated with the platform 20 production at- 13 029258

native gas and receive natural gas in the form of gas 90 from platform 20. Liquefied natural gas 90 can be stored in an underwater storage or fed to the shore. The vessels 111 are designed to withstand the underwater pressure, with reference to the operating conditions of the module 110. The underwater module 110 for increasing the gas pressure can also be designed to compress and / or liquefy other gases or gas mixtures. In some embodiments, the implementation of the underwater gas pressure boosting module 110 may be designed to compress and / or liquefy the refrigerants used to liquefy natural gas 90, as illustrated below. Numerous subsea gas pressure boosting modules 110 can be arranged in a cascade for compressing gas 90 in a stepwise manner, at each stage of the cascade, taking compressed gas and compressing the received gas even more. Numerous subsea gas pressure boosting modules 110 may be arranged in a cascade for compressing and liquefying several types of gases having increasing temperatures at a critical point in order to cool the last gas in the cascade with seawater, for example, with deep seawater.

With this arrangement, the cooling effect of seawater is gradually enhanced in order to provide cryogenic cooling of the first gas in the cascade. A non-limiting detailed example is provided below.

Preferably, the disclosed systems and methods allow the development of an offshore gas field with the release of produced natural gas in liquefied form directly at the production site underwater conditions, while simultaneously reducing the amount of adapted power resources required for such a process. In some embodiments, the implementation for this task, natural gas is sucked into the underwater hollow tubular coil, which is in the filling phase. After that, it is compressed by a rising column of seawater, shielded by a layer of immiscible hydrocarbon liquid, due to the penetration of seawater from below, under a layer of non-aqueous liquid, due to high external hydrostatic pressure. Natural gas is compressed, thus, to a pressure not lower than the critical one and is supplied for liquefaction realized by its cooling and condensation using an external cryogenic coolant located in the in-house circulation circuit. After that, most of the sea water is pumped out of the tubular coil before it is filled with the next portion of natural gas at the initial stage of development of a gas field. At the second stage of field development, sea water coming out of a tubular coil used to compress natural gas is supplied for flooding a subsea gas field.

Preferably, the use of external hydrostatic pressure of seawater (subsequently supplied to flood the reservoir of a gas field at the second stage of its development) to compress natural gas eliminates the need for reciprocating compressors traditionally used in methane liquefaction cycles, and not only consuming large amounts of electricity fairly inefficient devices. This makes it possible both to supply the entire volume of extracted natural gas in a liquefied form directly from the place of its production, and also makes it possible to drastically reduce the energy consumption of such a gas field development.

FIG. 7 is a structural block diagram of a high level of an underwater natural gas liquefaction system 100 according to some embodiments of the invention; FIG. 8 is a schematic representation of a high level of an underwater natural gas liquefaction system 100 according to some embodiments of the invention. In some embodiments, the implementation of the underwater system 100 for liquefying natural gas may contain two underwater modules 110A, 110B for increasing the pressure of the gas, arranged in the form of a cooling and pressure-increasing cascade designed to effectively liquefy the natural gas. The first module 110A can be adapted to increase the pressure of natural gas 90, and the cooling module 115A for natural gas can be adapted to liquefy natural gas 90A at elevated pressure (to produce liquid natural gas 91) using refrigerant 50. Refrigerant 50 can be selected so that it has a critical point at a higher temperature than natural gas 90. The second module 110B can be configured to increase the pressure of the refrigerant 50, and the cooling module 115B can be made from The possibility of liquefying the refrigerant 50A of elevated pressure (to obtain a liquid first refrigerant 51) using sea water. In some embodiments, system 100 may implement additional steps using additional refrigerants, or several pressure boosting steps (each performed using the respective vessels 111) for each refrigerant, etc. The number and type of refrigerants and the number and technical characteristics of pressure boosting modules 110 can be determined according to marine characteristics (depth, surface temperatures and construction limitations) and operational factors.

Natural gas 90, produced on the seabed (as a source of natural gas 89) for liquefaction using platform 20, can be prepared by dehydrating it from water vapor and cleaning (if necessary) from harmful impurities, such as hydrogen sulfide and carbon dioxide. Then, natural gas 90 can be introduced by suction into one of the submarine vessels 111 by means of release- 14 029258

a column of seawater 80 screened by a liquid hydrocarbon 70, as explained below. Natural gas 90 may undergo compression in vessels 111, followed by squeezing a portion of natural gas accumulated in a vertical underwater vessel 111 by supplying seawater to cylinder 111 from the surrounding depth of the sea. The system 100 can then cool and condense the compressed natural gas 90A by evaporating the refrigerant 50. Natural gas at elevated pressure is squeezed out to liquefy from the underwater vessel 111 by means of a rising column of sea water 80. Liquefied natural gas 91 can accumulate in the underwater storage 92 with its subsequent transportation and delivery to consumers on the coast through pipeline transportation or transportation by sea in special tankers. Sea water 80 can be introduced into the vessels 111 under the action of gravity, using the height difference existing in the sea. In refrigerant 50, the pressure may increase in a similar booster module 110B and be cooled to liquefy in the cooling module 115B. The details of system 100 illustrated in FIG. 7 are explained in the example below.

FIG. 9 is a high level block diagram illustrating a method of compressing and liquefying gas 300 according to some embodiments of the invention. The method 300 may contain pressurizing gas, such as natural gas, or other gases, such as ethylene or methane. The method 300 may further comprise the step of cooling the compressed gas to liquefy it. For example, the gas pressure may exceed its critical point, and cooling the compressed gas may thus liquefy the gas. In some embodiments, the method 300 may comprise the step of compressing and liquefying natural gas, as illustrated in a non-limiting example below.

Method 300 includes the step of increasing the pressure of the gas in at least one vessel (step 310), for example, increasing the pressure of natural gas (step 311) through cyclically performed steps (step 335): (ί) introducing gas into the upper part of at least measure one vessel (step 312); (ίί) seawater is introduced into the bottom of at least one vessel to increase the gas pressure (step 315); seawater is separated from the gas by a layer of a water-immiscible liquid (step 320); and pumping the pressurized gas through the top of at least one vessel after reaching a predetermined pressure (step 330). The pressure boosting step may be performed cyclically (step 335), for example, by introducing gas by pumping seawater from the bottom of at least one vessel (step 316). Thus, in natural gas, it is possible to continuously increase the pressure by introducing and pumping seawater.

In some embodiments, the method 300 may further comprise the step of selecting a water-immiscible liquid so that it has a density intermediate between the density of the gas and sea water (step 326) in order to maintain the gas on top of the layer of water-immiscible liquid, a layer of water-immiscible liquid on top of the sea water in the vessel (step 328).

In some embodiments, the method 300 may further comprise the step of feeding the pumped seawater to a pressure increase tank (step 340). In some embodiments, the pumped out seawater may be supplied to the surrounding sea or to one or more pressure-boosting reservoirs, depending on the requirements of production. The feed seawater can be filtered before it is supplied and pumped into a pressure-raising reservoir.

In some embodiments, method 300 may further comprise the following steps: liquefying natural gas of elevated pressure by cooling with refrigerant (step 350) and selecting the refrigerant so that it has a critical point at a higher temperature than natural gas (step 355). The refrigerant cooling step (step 350) may comprise the step of gasifying the refrigerant to cool the pressurized natural gas (step 352). In some embodiments, method 300 may further comprise the following steps: increase the pressure of the refrigerant (step 357) and liquefy the increased pressure refrigerant (step 360). The refrigerant pressure boosting step 357 may be performed using method 300, for example, according to steps 312, 315, 316, 320, 330, and 335.

Some embodiments comprise a method for developing an underwater gas field, comprising a method 300 for underwater liquefying natural gas and a stage in which pumped seawater is supplied to a pressure-increasing reservoir to increase gas production (step 340). Method 300 may additionally comprise the following steps: develop and increase production of an underwater gas field (step 370), and also remotely control the amount of pumped sea water into the pressure-raising tank (step 375) and generate electricity using the flow of pumped sea water into the pressure-increase reservoir (step 380).

In some embodiments, the implementation of method 300 may be implemented by sequentially implementing the following basic process steps.

During the initial development of a gas field, the following steps are performed: drilling of production and pre-production wells from the platform of the drilling platform to open underwater gas deposits; equip production and pre-production wells to 15 029258

complementary technological equipment, pipelines, auxiliary devices and stop valves, as well as means of telemetric control and telemechanical control of the main parameters of the extraction and liquefaction of natural gas underwater conditions, making sure at the same time that the operation of such a marine gas field is completely safe; and start the delivery of natural gas from a subsea field through a production well.

Then, the extracted natural gas can be compressed by performing the following steps: pre-cooled the extracted natural gas through closed heat exchange with the surrounding sea water; natural gas is pumped from the production well and pre-cooled gas with seawater into the system for its underwater compression and condensation, made in the form of underwater tubular coils acting in antiphase when their inner spiral-shaped space is empty from most of the seawater at the first stage of field development and seawater discharge under the effect of gravity using well pressure into a gas reservoir after the start la internal pressure drop at the second stage of the development of the offshore gas field); and after the natural gas is sucked in, the tubular coil is poured in by means of sea water supplied from below, and its pillar inside such a coil is shielded by a layer of a water-immiscible hydrocarbon liquid. When this compressed gas is extruded from such a hydraulic compression device.

Finally, compressed natural gas can be cooled and liquefied through the following steps: natural gas, compressed in a coil, is cooled with seawater and then with an external cryogenic coolant; compressed natural gas is cooled, cooled by means of a cryogenic coolant to a liquefaction temperature; perform compression and condensation of the vapor of the external (applied to liquefied natural gas) coolant boiling when cold is transferred to condensable methane in the underwater liquefaction system of such cryogenic liquid. The system operates according to a similar scheme, including a pair of underwater coils acting in antiphase and heat exchangers using sea water as a cooling medium; and returns the regenerated cryogenic liquid to the methane liquefaction cycle.

Liquefied natural gas can accumulate in the underwater storage and subsequently be transported and delivered to consumers ashore via an underwater pipeline or by sea in special vessels.

Preferably, compression using seawater 80 is superior to compression in current pistons or in another mechanical compression module in the following aspects. First, the thermal energy of compression is dissipated in sea water and in the sea, and does not destroy moving parts (for example, bearings, insulating rings, etc.). Secondly, the introduction of gas through the pumping of sea water 80 is more efficient than using the reverse stroke of a piston system, in particular, at high operating speeds. Also, fluid compression is more scalable than with a piston system, in which difficulties may arise due to the increasing inertia of the piston head. Finally, by reducing the number of mechanical parts, underwater work, and the fire resistance of seawater 80, the systems and methods disclosed are much safer than current systems.

Example.

The following is a non-limiting example of the implementation of system 100 and modules 110 and 115. Implementation details can be tailored to specific locations and requirements.

After opening the underwater gas field from the offshore drilling platform 20 (or a special offshore vessel) and setting up a production well 22 and injection wells 23, natural gas rising to the surface of the seabed through the production well 22 is cooled in a subsea heat exchanger 104 to a temperature of 5-7 C, close to the temperature of the layer of water closest to the seabed (2-4 ° C). After that, it is sucked into one of the tubular coils 111 working in antiphase. Natural gas 90 can undergo compression with any configuration of vessels 111, and vessels 111 can have various shapes. The following non-limiting example relates to helical vessels 111 operating in pairs: one vessel compresses the gas (for example, vessel 111 in Fig. 7 is illustrated in the final compression phase), and another vessel sucks gas (for example, vessel 111B in Fig. 7 is illustrated in the final phase suction). Vessels 111 are depicted in a non-limiting manner as having a spiral shape and are referred to as coils.

In some embodiments, the implementation of water-immiscible liquid 70 may contain various non-water-miscible aliphatic or aromatic organic compounds having a low freezing point and a density less than the density of seawater 80, such as hexane or toluene. Liquid 70 that is not miscible with water may contain hexane (density 0.66 g / cm ³ , freezing point -95.3 ° С) or its isomers (2-methylpentane, freezing point -153.7 ° С; 3-methylpentane, point frost -118 ° C; 2,3-dimethylbutane, freezing point -128.5 ° C), heptane (density 0.69 g / cm ³ , freezing point -90.6 ° C), as well as its numerous derivatives and other substances- 16 029258

representatives of the homologous series of alkanes of organic aliphatic compounds.

At the first stage of development of a gas field, when the gas pressure in the well is high, a column of sea water 80 poured into tubular coils 111 at the beginning of the natural gas (111B) suction phase after compression of the previous portion of methane into them is pumped back into the sea water 80A) through the pump 107, emptying the tubular coil 111 from most of its contents. However, the coil 111 is not pumped out completely, it remains a small layer 80 of sea water, shielded by a liquid hydrocarbon layer 70.

In the process of operation of a gas field inside the reservoir gas pressure in it gradually decreases, and, accordingly, gas recovery begins to fall. At this second stage of development of the offshore gas field, the in-situ pressure can be maintained at the required level to ensure continuous and stable gas recovery by direct release of sea water to the underwater gas field (in the form of sea water 80B) using an underwater hydraulic turbine 109 installed in the head of the injection well , instead of pumping out pumped seawater from coils 111 by means of a pump 107. At the inlet of the injection device can be placed on filter sleeve 130 are designed to prevent contamination of the hydraulic turbine blades 109. Electric energy generated by the turbine generator 131 may be used as an additional source of energy and compensate for some of the energy production. Preferably, such an energy generation replenishes a certain amount of energy and makes the illustrated process more cost-effective. The gas field can float in a controlled manner, and therefore the volume of sea water supplied from the coils 111 to the hydraulic turbine 109 can be recorded in seconds using the appropriate telemetric measuring equipment of the monitoring module 140, located, for example, on the platform 20. the waters can be controlled by means of a remotely controlled stop valve 129, which can likewise be controlled by the counter control module 140 la.

As a result of the smooth pumping of seawater 80, the seawater level in coils 111 gradually decreases, and the hollow spiral space above the liquid hydrocarbon layer 70 is filled with the next portion of produced natural gas, previously cooled by seawater in heat exchanger 104 to 5-7 ° C. To compress the next portion of natural gas, the hydrostatic pressure of the overlying column of seawater is used. For this, the remotely controlled adjustable shut-off valve 132 installed at the base of the coil 111 opens slightly. As a result, seawater begins to enter from below into the coil 111 (filled with gas 90 pumped during the pumping of seawater at the previous stage). Sea water 80 enters vessel 111 in the form of a spiral flow, gradually increases pressure and compresses natural gas in a space free of sea water. The final pressure of the gaseous substance (90A) in this hydraulic compressor is determined by the difference between the geodetic marks of the top of the hydrocarbon shielding layer 70, covering the seawater 80 in the coil 111, and the sea level. Thus, with an increase in the depth of subsea production, the maximum possible gas compression pressure in the coil 111 also increases continuously. For example, if the sea level exceeds the geodetic mark of the surface of the hydrocarbon layer 70 of the column of sea water in the coil 111 per 1000 m, then the pressure of the gaseous medium compressed in the vessel 111 balances this depth and thus equals 1.03x1000 = 1030 m of the fresh water column (the density of cold sea water depends on its temperature and salinity, but on average it is equal to 1.03 g / cm ³ ) or 1030x9806.65 = 10100849 Pa, i.e. 10.1 MPa. It should be noted that for methane condensation it is not necessary to compress it to such a high pressure (the critical pressure of methane is much lower — 4.64 MPa). The main condition for its transition to a liquid state is the need for its cooling to a temperature below the critical (-82.5 ° C).

After compression, the compressed gas may condense using an external cryogenic coolant 50 having a boiling point below -82.5 ° C. For example, ethylene C ₂ H ₄ can be used as such a liquid boiling at a low temperature. The thermodynamic properties of cryogenic liquid 50 are chosen so that its normal boiling point at atmospheric pressure is -103.7 ° C, i.e. 21.2 ° C below the condensation temperature of methane (as the main component of natural gas 90), compressed to its critical pressure. At the same time, the critical liquefaction temperature of ethylene is positive and amounts to 9.3 ° C, i.e. 5-6 ° C higher than sea temperature in most of the world's oceans, ranging from depths of 100 m and below. As a rule, liquid refrigerant 51 can be chosen so that the boiling point at atmospheric pressure is lower than the condensation temperature of compressed natural gas 90A, and the critical condensation temperature of the refrigerant 50A elevated pressure should be higher than the temperature of the surrounding sea water. Therefore, ethylene can be used as the refrigerant 50, which provides for the liquefaction of methane, as well as sequential condensation at seawater temperatures. Such a system uses for cooling the free potential of sea water of the world ocean, which has a year-round temperature of the deep-water part of the sea of about 2-4 ° C. Thus, ethylene 50 compressed to pressure

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above the critical (5.11 MPa), can be converted underwater conditions from gaseous to liquid only due to heat exchange with the surrounding sea water. Therefore, liquid ethylene is used in this case as a non-limiting example of low-temperature boiling cryogenic liquid 50 used to liquefy methane.

Before cooling with refrigerant 50, natural gas 90 can be alternately compressed in coils 111 to a pressure of at least 4.64 MPa, previously subjected to cooling in a refrigeration unit 134 washed by cold sea water (temperature 2-4 ° C) with a screw 135. Pressure Compression of natural gas can be set in advance in accordance with the adjusting position of the shut-off valves 133 at a certain threshold value. Compressed methane 90A, cooled in this way to a temperature of 5-6 ° C, is fed to the first stage of refrigeration, which is sold in a heat recovery heat exchanger 116, in which the last artificial cold residues removed by boiling ethylene 50 from the natural gas condensation system are transferred to the latter. Methane condensation at a temperature below -82.5 ° C occurs in a cold exchanger 117, into which liquid ethylene 51 is fed (boiling under normal conditions at a temperature of -103.7 ° C), after passing throttling in an adjustable valve 118.

The finished product, liquefied natural gas 91, can be sent to storage 92 in an underwater storage tank, from where it can be shipped to consumers via special sea transport or delivered in a liquid state to the coast via an underwater pipeline.

Ethylene, which passes from a liquid (51) to a gaseous (50) state at a temperature of 103.7 ° C, is supplied from a cold exchanger 117 to transfer the last remnants of its artificial cold to a fresh stream of compressed natural gas 90A. After that, ethylene vapor is fed to the system for liquefying a cryogenic substance for compression (to the 110V module) and condensation (to the 115V module). For this purpose, ethylene gas 50 leaving the recovery heat exchanger 116 is sucked into one of the tubular coils 111 in the pressure-raising module 110B, working, like the coils 111 in the pressure-increasing module 110A, in antiphase with respect to each other.

The suction in the vessels 111 occurs due to the release in the process of emptying most of the seawater 80 pumped back into the sea by means of a pump 107 (development of the offshore gas field), or direct seawater (alternately from each coil 111) to the gas reservoir a turbine 109 with simultaneous production of electricity by means of a turbo-generator 131 (at the second stage of the development of an offshore gas field). Similar to the structure of the contents of coils 111 in module 110A, the spiral-shaped column of seawater 80 in coils 111 is isolated from natural gas by means of a layer of liquid hexane 70B, which prevents the ingress of water vapor into the medium to be compressed. Water-immiscible liquids 70A and 70B in modules 110A, 110B may be similar or different from each other. For example, liquid 70B may be a mixture of hydrocarbons, more suited to separating ethylene from seawater, while liquid 70A may be a mixture of hydrocarbons more suited to separating natural gas from seawater. After the ethylene gas is sucked into the spiral space of one of the coils 111 (in the 110V module), the subsequent gas compression is performed in it in the same way as in the coils 111 (in the 110A module) by alternately opening the valves 122 equipped with remote-controlled actuators. As a result, the sea water surrounding such a system begins to replenish the unreleased two-layer column of liquid medium. As a result (due to the constant increase in the content level of each coil 111), the vapor pressure of ethylene above the surface of the 70B hexane layer gradually begins to rise and reaches the level required for its liquefaction at positive ambient temperatures - at least 5.11 MPa. After actuation (for example, as a result of exceeding the set threshold pressure of compression) of one of the stop valves 123, compressed ethylene 50A leaves the compression system and is fed for pre-cooling to a refrigeration unit 124, washed by cold sea water through a screw 125.

Compressed ethylene 50A, thus pre-cooled, is then fed to a deep-water condenser 126, which is installed at a lower level than the refrigeration unit 124, since the temperature of the seawater constantly decreases with increasing sea depth. Since sea water is pumped through a screw 127 through a condenser 216 having a lower temperature (2-4 ° C) than the ethylene condensation temperature (9.3 ° C) compressed to a pressure exceeding the critical one, the vapors of this organic matter pass from gaseous to liquid state.

The resulting cryogenic liquid 51 in the re-condensed form is then fed again to be throttled into the controlled valve 118, and after the pressure drops to atmospheric pressure in it, it is used again as a coolant boiling at 103.7 ° C to liquefy methane in the cold exchanger 117. Thus, the cycle of maintaining the process of methane liquefaction by means of a cryogenic liquid is almost completely closed, and, with an appropriate level of production, it is practically not consumed in such a closed circulation loop.

Preferably, the disclosed methods and systems, in comparison with known methods for developing offshore gas fields, provide a certain number of significant technical and

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economic benefits. Firstly, they allow the natural gas produced at the offshore field to be supplied directly to consumers in a liquid form. This advantage provides the ability to develop most of the offshore gas fields currently open, located at a distance of hundreds and thousands of kilometers from the coast. It should be noted that the fact that one cubic meter of liquefied natural gas is 625 times heavier than one cubic meter of methane gas is the main reason for the low cost of transporting such fuel over long distances and the lack of incentive to develop offshore gas fields very far from the coast.

As for the competitiveness of the disclosed methods and systems relative to the known methods of liquefying methane used in the development of gas fields on land, the compression of natural gas in the spiral-shaped spaces of tubular coils is incomparably less cyclical than the use of reciprocating compressors, since the geometric volumes of the working cylinders of such devices may differ hundreds and thousands of times (taking into account that the inner diameter of the spiral space is measured in meter ah, the radius of the spiral curls is tens of meters, and the total height of the spiral is hundreds of meters). Thus, not only is there an obvious increase in the performance of the compression process, but a significantly higher level of its perfection of power is achieved, since the intensification of the operation of piston compressors is associated with an increase in thermal energy generation, and thus a decrease in the share of electrical power is converted into an increase in pressure of compressed gas. Thus, the disclosed methods and systems are significantly more scalable than piston-based systems, and their advantages grow with increasing system size.

Simultaneous generation of electrical power during the emptying of the main part of the spiral-shaped working space of the coils at the second stage of development of the offshore gas field level) increases the profitability of natural gas production on the seabed using the method according to the invention.

An additional advantage of the invention is that with increasing depth of the sea, the cost-effectiveness for underwater liquefaction of methane used in the operation of such gas fields only increases, which may be due to an increase in the hydrostatic pressure of seawater and a constant decrease in its temperature as it approaches the seabed.

These benefits also imply that the environmental impact of the invention disclosed herein is much less than with current technologies. Not only the energy efficiency of the process itself is higher, but the requirements for the amount of energy and the space for gas transportation and liquefaction on the ground are also more moderate.

Embodiments of the present invention provide an integrated use of the original energy mineral, deepen its processing, reduce energy consumption in the extraction of artificial liquid fuel, reduce investment in the construction of apparatus for liquefying coal and reduce the harmful effect of the process on the environment through its implementation in underground conditions. In some embodiments, prior to hydrogenation, the processing of the initial crushed mineral (in particular, coal) begins with the preliminary separation of the combustible mineral from the waste rock, combined with its vertical transportation by floating the mineral from the mine site to the place of its further processing in a vertical column filled with water. salt solution with a density greater than the density of coal. The main ingredients for the preparation of water-salt substances are ionogenic inorganic compounds that not only have a sufficiently high solubility in water (which allows the resulting aqueous solutions to achieve a density sufficient to transport coal afloat), but also are highly active catalysts in the subsequent hydrogenation process.

FIG. 10A is a schematic representation of a non-limiting example of a combustible material handling system 500 according to some embodiments of the invention; FIG. 10B is a schematic representation of a high level of subsystems in a combustible material processing system 500 according to some embodiments of the invention; FIG. 11A is a high level flow chart illustrating the main steps of the method 600 for separating and hydrogenating combustible material in accordance with some embodiments of the invention; and FIG. 11B is a high-level flow chart illustrating the subsequent steps of the method 600 for separating and hydrogenating combustible material in accordance with some embodiments of the invention.

Method 600 may comprise the step of preparing a water-salt substance 480 having a predetermined density (step 602) and using catalytic salts (step 604). Preparation of water-salt substances 480, intended for transportation afloat, is performed by grinding and step-by-step enrichment of the original mineral by dissolving one or several mineral salts in water, which catalyzes the hydrogenation process.

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Preparation allows to obtain a solution 480 with a density that is intermediate between the density of the combustible mineral 490 and contaminating mineral impurities, i.e. waste breed 489.

Method 600 may further comprise the step where raw materials 490 are prepared and supplied (step 606), for example, by pre-dry preparation of the size of freshly mined feedstock to feed it into a heavy water-salt column for separation during , a product purified relative to its combustible component. The raw combustible material 490 is thus transformed into the prepared combustible material 490A.

Method 200 may further comprise a step in which the combustible material is gravitationally separated from the waste rock 489 in the water-salt solution 480, the density of which is selected intermediate between the density of the fuel material 490A and the density of the waste rock (step 610). This step may be performed in the afloat transport subsystem 610A containing the vertical afloat transport container 505, as described below. The method 600 may comprise the step of separating combustible material by floating and flooding the waste rock (step 612) by feeding, for example, coal, with its simultaneous release from a significant part of the waste rock from the production site to the treatment site by vertical transportation to melt in a water-salt substance with a density greater than the density of the coal substance.

Waste rock 489 can be submerged in water-salt substance 480, and then squeezed out of the liquid phase, rinsed with water and soil, while simultaneously trapping methane released into the gaseous phase in the process of reducing size. After this, the waste rock can be placed in the developed space. Method 600 may further comprise the step of separating the hydrocarbon gas and recovering the solution from the waste rock (step 620). This stage can be performed in the flooded waste treatment subsystem 620A and can contain the following steps: remove flooded waste rock 489 from the water-salt medium, squeeze out the waste rock with water (along with all other solid waste from the liquefied coal) hydromechanically from the liquid residue and additionally grind the purified material, with simultaneous trapping of the released methane and working placement of all solid waste of the technological process in the developed space. Thus, method 600 may further comprise the following steps: remove and treat the flooded waste rock (step 622); separating the water-salt substance from the waste rock and reusing it (step 624) and catching the methane from the treated waste rock (step 626).

In some embodiments, in method 600, the grinding stage (first processing stage) of the floating mineral (and enriched at the same time) of the starting mineral is performed at ambient temperature in the same solution (saturated with ingredients that catalyze the hydrogenation process) having a density greater the density of the combustible mineral, but lower than the density of the waste rock. A consistent decrease in the size of the material being processed may be accompanied by a preliminary spatial separation of the minerals that make up the original mineral. The light fraction, enriched with its combustible component, moves afloat from the zone of grinding bodies, while the heavy material, consisting mainly of mineral waste, sinks in the water-salt substance that fills the drum mill. During grinding, methane can be released from the ground material into the gaseous phase, captured and sent to catalytic processing using water vapor to produce hydrogen used in the hydrogenation process (see below).

Method 600 may further comprise the step of sequentially reducing the particle size of the separated combustible material in the solution and removing residual waste rock and gas from it (step 630), for example, in the grinding and separating subsystem 630A. The first (cold) stage of grinding coal lumps transported afloat can be performed with a simultaneous concentration of ground material sold at ambient temperature in the same water-salt solution 480, saturated to a density value that is exactly in the middle between the densities of combustible and non-combustible mineral components, while simultaneously trapping methane released in the process of grinding in the gaseous phase, followed by the separate release of the light part (concentrate not processed product) and heavy part (final residues) enriched process products. In some embodiments, method 600 further comprises any of the following steps: grind (at the first, cold stage) combustible material transported afloat in saline (step 632); trapping gas and separating the light and heavy phases (step 634); and remove additional waste material (step 636).

In some embodiments, the implementation of the second stage of grinding the light product suspension (concentrate not processed product) of the first (cold) stage of grinding and enrichment can be heated and additionally ground with moderate heating, along with its additional separation. Then, the formed process stream containing solid phases, even more fully enriched with coal matter, is heated to a higher temperature, further ground to a very fine state and, finally, precisely separated from the remnants of visible mineral impurities during hot mode in a powerful centrifugal field. Method 600 may add 20,029,258

It is desirable to contain the stage at which combustible material with reduced particle size is heated and milled to obtain a paste of purified combustible material (step 640), for example, in the heating and additionally grinding subsystem 640A.

The method 600 may further comprise the following steps: heat the suspension of the light product of the first stage to a moderate concentration; and perform the second (warm) stage of grinding and enrichment of concentrated unprocessed product in a heated aqueous solution with simultaneous (as in the first stage of grinding) release of methane released in the process of reducing the size of the ground material, and then releasing a light product, then the last stage of preparation of the material in terms of its size and composition prior to its liquefaction, and the heavy product returned, respectively, to the first (cold) stage of the process for additional oh grinding. The method 600 may further comprise the step of performing the final heating of the enriched product of the warm stage of processing the coal to a higher temperature, which will be slightly lower than the boiling point of the water-salt solution. In some embodiments, method 600 further comprises any of the following steps: heat the separated combustible material (step 641); grind (second, moderately heated phase) heated combustible material (step 642); separating the light and heavy phases and re-processing the bulky material (step 643) and heating the separated combustible material to higher temperatures (below the boiling point) (step 644).

Method 600 may further comprise the following steps: additionally heat, reduce viscosity, grind and separate in a centrifugal manner in a grinding subsystem 640B with heating. Method 600 may comprise a third (hot) grinding stage followed by a final, precise enrichment of very fine coal in a strong centrifugal field in the same water-salt substance, but in the hot branch mode, containing the following steps: grinding (the third, hotter phase) of the heated fuel material (step 645) and separating the light and heavy phases and re-processing large material (step 646).

The method 600 may further comprise the step of mixing the obtained hot, ultra-pure coal concentrate with a hot paste-forming component (and the water from the water-salt solution impregnating the coal concentrate begins to boil). Then, the resulting paste can be diluted to a fluid consistency, the solid phase of the formed coal-oil mixture can be powdered to the size of colloidal particles and fed through a vertical rotating hollow shaft (ending with a T-shaped reactive turbine - Segner wheel), which can be installed in a vertical well, for underground hydrogenation in a blind mine, equipped with a tangential input of hydrogen. This stage can be performed in the deep-water squeezing and paste-forming subsystem 640С, in which hydromechanical squeezing of the final ultra-pure coal concentrate from the water-salt substance is performed by additional mixing with the hot pastor and simultaneously removing excess moisture from the squeezed briquette by boiling it, and further dilute coal-oil mixture to the desired consistency by means of an organic solvent. In some embodiments, method 600 further comprises the steps of: additionally heating the separated combustible material (step 647); purify the heated combustible material by rotating in a centrifuge (step 648) and fluidize the paste (step 650), for example, by diluting the paste with an organic solvent (step 651), in the fluidization subsystem 650A. Method 600 may further comprise the following steps: additionally powdering the solid phase of the coal-oil mixture prepared for hydrogenation to a colloidal size, for example, powdering to a colloidal size as a preparation for hydrogenation (step 653).

The method 600 may further comprise the following steps: hydrogenating the diluted paste (step 660), for example, in the hydrogenation subsystem 660A. In some embodiments, method 600 comprises recovering the carbon-oil mixture (by means of a hot artificial oil product rising in the opposite direction) with its subsequent supply to the hydrogenation process by means of a rotating vertical hollow shaft installed in a vertical well, cut into a sealed blind shaft at the same time, hydrogen is tangentially fed at several heights to the lower part of the blind shaft; and perform hot catalytic hydrogenation of the coal substance of the solid phase of the coal-oil mixture through its interaction with hydrogen at elevated pressure at high temperature in the presence of a catalyst, which is realized in a sealed blind mine in underground conditions. In some embodiments, method 200 further comprises any of the following steps: hot catalytic hydrogenation of the powdered diluted paste from a combustible material is performed (step 661); hydrogen is introduced at elevated pressure and high temperature in the presence of a catalyst, which is realized in a sealed blind mine in underground conditions (step 662); hydrogen is introduced into various regions of the hydrogenation column (step 663) and hydrogenated, for example, by using the Segner wheel (step 665).

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Method 600 may further comprise the step of final cleaning and processing of the hydrogenation residues (step 670), for example, in the cleaning and separating 620B subsystem, removing the residual hydrocarbons and fluids, and processing the waste rock. Method 600 may include the step of introducing liquid hydrogenation to lift from a blind shaft, designed to release gases dissolved in it from it by supplying an artificial petroleum product discharged to the surface of the earth (through an annular opening between a rotating hollow shaft and a vertical well connected to shaft) into a hollow volume, with simultaneous recuperative heat exchange between technological opposite flows between these heights. Hydrogenate rising from a blind shaft through an annular opening between the rotating shaft and the head of a vertical well can be released from dissolved hydrocarbon gases and separated into artificial oil and non-fluidized solid residue. The latter can be washed with an organic solvent, dried and mixed with the dehydrated heavy product of the first grinding stage. Blends of inert minerals, free from organic impurities, can be rinsed with water and removed from the extraction cycle. Wash water remaining after washing these fine wastes, as well as water remaining after washing large clods of rock (flooded during the transportation of coal afloat in a water-salt substance), evaporates to its original density. The regenerated water-salt solution can return to the beginning of the process. In some embodiments, method 600 further comprises any of the following steps: provide for raising a hydrogenation product from a blind shaft (step 666); the material involved is heated by heat exchange with the hydrogenation product (step 667) and the uncondensed unreacted hydrogen residues are re-circulated back into the hydrogenation system (step 668).

Method 600 may further comprise the following steps: separating vapor-gas mixtures from the hydrocarbon liquid phase in the head of a vertical well, followed by condensation of a light hydrogenation and re-circulation of uncondensed unreacted hydrogen back into the hydrogenation system; release the liquid hydrogenate from the remaining non-fluidized solid inert impurities and submit it for further processing to the refinery; purify the solid residue, extracted from the heavy hydrogenation product, from the impregnating hydrocarbon liquid phase by means of an organic solvent and its further drying and removal from the process; mix the dry solid residue of hydrogenation with a dehydrated heavy product of the first stage of grinding the source mineral; purify the final wet mechanical mixture of inert non-combustible minerals from catalyst residues with fresh water and then squeeze the wet waste from the excess liquid phase; evaporate the wash water remaining after washing the mixture from solid waste products until the evaporated solution reaches its initial density (intermediate between the density of the combustible mineral and mineral impurities), and returns the regenerated water-mineral medium to the beginning of the process. In some embodiments, method 600 further comprises any of the following steps: divide the hydrogenation product into different phases (step 672); remove residues from the product (step 674); and perform further processing and processing of the product (step 675).

In some embodiments, the implementation of the products of heavy waste of the second and third stage of enrichment by gravity can be squeezed out of the excess liquid phase and returned to wet grinding in the cycle of the first (cold) stage of concentration. As for the mineral salts, which catalyze the hydrogenation process, only water-soluble chemical compounds with high catalytic activity, which are highly soluble in water, are used to prepare solutions based on them, having a density sufficient to transport fused combustible components of the original rock to the surface, and not just ionic inorganic substances that facilitate the interaction of the carbon-containing components of the combustible mineral with hydrogen. These water-soluble compounds can be selected to catalyze the hydrogenation process, as well as to form aqueous solutions with a density intermediate between the density of the combustible mineral and the waste rock, for example, certain mineral salts with a sufficiently high solubility in water, for example, zinc or tin chlorides or bromides. ammonium paramolybdates and ammonium tetramolybdates or iron sulfates, or their other mixtures. The solubility in water of hydrogenating catalysts of this type is quite sufficient for the preparation of aqueous solutions with the density required to transport afloat only the combustible components of the original rock. For example, a 60% solution of ferric sulfate Fe ₂ (ZO ₄ ) ₃ at a temperature of 17.5 ° C has a density of 1.798 g / cm ³ , while the density of coal does not exceed, as a rule, the values of 1.319-1.546 g / cm ³ In other words, there is no need to use highly saturated solutions with a mineral component to ensure the transportation of coal afloat. A more dilute aqueous salt medium may also be applicable, for example, a 40% solution of the same ferric sulfate in water (its density at 17.5 ° C is equal to 1.449 g / cm ³ ). The preparation of such solutions based on water-soluble molybdenum-containing salts, for example, paramolybdate or ammonium tetramolybdate, and the introduction of other microadditives in the final mixture allows the water-salt substance not only to achieve a tight 22,029,258

necessary to transport coal afloat, but also to increase the catalytic activity of the compounds formed. In some embodiments, the density of all the major rock-forming minerals (argillite, aleurite, limestone, quartzite, sandstone, anhydrite, granodiorite, feldspar, montmorillonite and other aluminosilicates) is significantly high (about 2.376-2.887 g / cm ³ ), which predetermines the absence of which -the possibility of their transportation afloat with coal in such a relatively light (for them) fluid.

The paste-forming substance may contain various compounds, for example, refined products, by-products of coking or fine organic synthesis, containing thermally unstable organic substances (mainly aromatic), which can serve as donors of atomic hydrogen when they are heated, can be used, for example, a mixture tetralin with anthracene oil, subsequently diluted with isopropyl alcohol. However, not only the components of the paste-forming substance can provide atomic hydrogen in the method according to the invention, but also mineral salts, on the basis of which water-salt solutions are prepared (or introduced as impurity ingredients) to transport coal afloat. For example, if a solution of such a mineral salt as potassium formate, well soluble in water (when approaching the saturation state, its density reaches 1,570 g / cm ³ or more) is used as a heavy liquid, this is an inorganic substance entering the hydrogenation step along with the final ultrapure coal concentrate, thermally decomposes when heated above 360 ° C to potassium oxalate and hydrogen. The latter, at the time of its appearance, exists in the atomic form and is a very strong reducing agent, which significantly contributes to the binding of hydrogen atoms to carbon atoms: 2CHOOK = (COOK) ₂ + 2H ⁺ . Thus, some embodiments use unique combinations of properties inherent in potassium formate, namely, that the density of the NCOOK solution in water is greater than the density of coal, while after heating this salt decomposes to form atomic hydrogen, which leads to a sharp acceleration hydrogenation process.

In addition, in contrast to the known solutions in the field of artificial liquid fuel extraction using dry methods of transporting the source mineral from the mine face to the liquefaction site and traditional grinding processes, delivery of recently mined coal to the processing site through vertical afloat with further additional grinding in the same water-mineral environment, the density of which is intermediate between the density of the combustible mineral and its non-combustible components, is not It allows to combine the application process (shortest route) from the mine site to the cooking site for hydrogenation (simultaneously releasing it from the majority of the gangue) but also completely isolates the coal substance from contact with atmospheric oxygen.

As a result, the lack of access of oxygen to the surface of the coal leads to the prevention of its endogenous (imperceptible) oxidation, which negatively affects the completeness and liquefaction rate of the combustible mineral (not to mention the excess hydrogen consumption). At the same time, step-by-step grinding of coal, previously enriched in the process of transportation afloat in the same water-salt solution, preceding the stage of hydrogenation, leads to automatic slipping of fragments of the combustible mineral (when they are released from merging with empty rock) as a result of grinding media blows and thus reducing the ball loading of the mills. The combination of the possibility of obtaining artificial liquid fuel in underground conditions with the spontaneous recovery of free thermal energy of the Earth’s interior for the primary heating of the components of the hydrogenating interaction (due to elevated temperatures characteristic of the host rocks at great depth) and with the ability to refuse high-pressure pumps (which are the main consumers of electric power during the liquefaction of coal in the earth’s surface) for the introduction of the original coal-oil paste into the process of gi rogenizatsii, the invention provides a higher level of efficiency of processing the solid fuel produced from petroleum in artificial compared with known ground technologies produce synthetic liquid fuels from various combustible minerals.

Preferably, a general reduction in the volume of the process stream supplied during the hydrogenation step, which must be heated to the reaction temperature, and the reduction in power consumption associated with the additional separation of liquid products from solid inert impurities removed from the liquefaction process by means of artificial petroleum may provide an additional significant reduction. energy consumption for the production of artificial liquid fuels according to the invention, and a radical weakening of the harmful influence of the disclosed technological process on the natural environment. In addition, the capture of methane and other combustible gases can accompany all the processes of reducing the size and ensure the integrated use of valuable energy resources contained in the original mineral. Thus, all features of the present invention may be interconnected, and their combinations may achieve the advantages mentioned above.

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Example.

As a non-limiting example, the following detailed system diagram illustrates the implementation of the embodiments of the invention described above. In this non-limiting example, coal can be processed as a combustible material. All the values listed below are given as non-limiting examples and can be modified and adapted according to different types of combustible material, different configurations of processing modules and substances.

The afloat transportation subsystem 610A may be configured to allow gravitational separation of combustible material from waste rock in a water-salt solution, chosen so that it has a density intermediate between the density of combustible material and the density of the waste rock.

Recently produced lumps of coal or other combustible material 490 from the face of the mine are subjected to preliminary sieving by size on the sieve 501. The raw mineral lumps that have passed through the sieve are fed for further processing, while the large-sized material is crushed in a crusher 502 and then added to small-sized, past-screened product. Both the sieve 501 and the crusher 502 are enclosed in hermetic enclosures in the vacuum region created in the methane capture system (not shown). The raw combustible material 490 is thus transformed into the prepared combustible material 490A.

Combustible material 490A, thus prepared in size (the size of the largest large lumps of crushed rock does not exceed half the diameter of the vertical pipeline 505 for transporting coal afloat), is loaded into one of the branches 503 of the locking mechanism of the initial supply of coal liquefaction device to the system.

Then, in the loaded material, the pressure in the chamber is increased by rotating the valve 504 to the right position with the clamp to the vertical column 505, and filling (for example, by opening the side valves in the upper and lower parts of the column 505) with an aqueous solution 480 of mineral salt that can be used for transportation afloat combustible material 490A and flooding of waste rock 489, and can also act as a catalyst for the subsequent hydrogenation process. The air squeezed out of this hermetic volume is discharged through air valves (not shown).

Examples of a water-salt solution may include a 40% solution of zinc chloride in water with a density of 1.423 g / cm ³ (at 25 ° C) mixed with ammonium paramolybdate, which is used as a water-salt substance to implement the process. However, other mineral salts and their various mixtures can be used as such an inorganic compound with a set of properties necessary for the implementation of the process of the invention, for example, ferric sulfate iron Fe ₂ (8O ₄ ) ₃ -9H ₂ O, ammonium paramolybdate (ΝΗ ₄ ) ₆ 7ο ₇ Ο ₂₄ · 4Η ₂ Ο, ammonium tetramolybdate (ΝΗ ₄ ) ₂ · 4ΜοΟ ₃ · 2Η ₂ Ο, iron vitriol Pe8O ₄ ^ 7H ₂ O, bivalent tin chloride 8iC1 ₂ , a mixture of nano-anhydrous ferric sulfate Pe ₂ (8O ₄ ) ₃ EN ₂ O with penta-aqueous tetravalent tin chloride _{8 and} C1 ₄ ^ 5H ₂ O ( Used in a weight ratio of 3: 1), zinc bromide, etc.

In some embodiments, the implementation of the water-salt solution 480 may also contain oxidized forms of various metals of different valences, such as iron, nickel, cobalt, molybdenum, tin, aluminum, silicon oxide, and also tungsten, molybdenum, sodium, potassium, nickel sulfides and iron with addition of elemental sulfur, and various multicomponent compounds based on them, as well as sulfates and halides of certain metals or ammonium salts of isopoly molybdic and thiomolybdic acids and other chemical compounds that allow reproach hydrogenation process or deliver atomic hydrogen, and thus can be used as catalysts for the described below liquefaction combustible minerals.

The density of aqueous solutions of 480 mineral salts, which catalyze the process of hydrogenation of a coal substance, exceeds the density of the solid fuel of the corresponding species, which predetermines the possibility of transporting the combustible mineral in it afloat. At the same time, waste rock 489, which is heavier than coal, sinks in the environment of 480, which makes it possible to combine the vertical supply of coal to the place of its further processing with simultaneous pre-enrichment.

Then, by smoothly turning the center gate 504 to the right position, the internal volume of the left branch 503 is combined with the contents of the vertical column 505 in the vertical column containing the water-salt substance with a density greater than the density of the coal. This causes the next portion of 490A coal to be transported afloat from the mine to the surface of the earth, while waste rock 489, which is heavier than solution 480 of zinc chloride, sinks in fluid 480 and settles near the nipple of the feeding device.

Combustible material 490A, for example, coal, is kept afloat in a water-salt solution 480 and accumulates in the form of free cover in the upper (expanding) part of the column 505, from where it is fed to the first grinding stage, sold in the same water-salt substance, filled in ball mill 506, while waste rock, sinking in fluid 480, is released through the lock 24 029258

507. The first modules of the grinding subsystem 630A provide the possibility of successively reducing the particle size of the separated combustible material 490A in solution 480 and removing residual waste rock and gas from it (see below).

Waste 489 is processed in a flooded waste treatment subsystem 620A, for example, precipitated in a sump 507 and squeezed out of a liquid in a filtering centrifuge 508, and then released into a vacuum belt filter 509, where it is squeezed out (along with other solid process waste, see below ) from the water-salt liquid phase, rinsed with fresh water in countercurrent mode and fed for grinding in a sealed mill 510. In the process of exposing a new formation of ground material, methane released into the gaseous phase is pumped out s mill. Waste rock 489, ground and freed from methane, is placed in the goaf. This prevents the development of geomechanical processes of movement of the overlying layer of rock, causing irreparable damage to all surface objects located on the territory of the developed underground mine, as a result of the collapse of the soil surface. At the same time, an aqueous solution of 480A zinc chloride, purified from waste rock, is returned by means of a piston pump 510 to the system of a hydrostatic coal lifter.

Grinding subsystem 630A additionally performs grinding of combustible material 490B. Combustible material 490B is a floating material 490A, previously released from most of the waste rock 489 during its transportation afloat up (as a combustible material 490A). Further grinding is carried out in a ball mill 506 in the same water-salt substance 480. While coal is freed from its coalescence with waste rock by grinding, fragments of coal substance are not further destroyed and remain afloat on the surface of the liquid medium 480, while while all other components of the feedstock are immersed again in the zone of impact of the mill balls. As a result, when the afloat combustible material 490A is crushed by means of steel balls continuously rotating in the drum of the mill 506, fragments of clean coal, exposed in the grinding process, regardless of the degree of their crushing, overflow the energy of their further excessive crushing, which entails the effectiveness of their subsequent separation and an increase in the moisture content of enriched products.

Additional methane may be released into the gaseous phase (like other gaseous hydrocarbons), which is practically insoluble in water. Gases pass through a layer of water-salt solution 480 (inside mill 506), and then enter the system to capture them, from where they are fed to catalytic processing using water vapor in order to produce the hydrogen needed to hydrogenate coal. The excess of this energy source is sold to external consumers in the form of gaseous fuel.

The material discharged from the mill 506 is fed to a collector 512 equipped with a mixing device, from where it is fed through a pump 513 to a hydrocyclone 514, in which coal is more intensive (compared to the mill 506) separated from non-combustible inert impurities, which are significantly heavier minerals forming part of the original combustible mineral. The light product (unprocessed coal concentrate) of the first separation cycle, coming out of the upper axial nipple of the cylindrical part of the hydrocyclone 514, is fed into the steam heated container 515 (heated with steam 491A) equipped with a mixing device that is part of the heating and additionally grinding unit 640A. As a result of the heating, the density of the liquid phase of the suspension drops, for example, from 1.423 (at 25 ° C) to 1.403 g / cm ³ (at 50 ° C). The reduced density increases the separation properties of solution 480, because it can separate waste rock, the density of which is closer to the density of combustible material.

To achieve a more complete opening of the accretion, the material flow can be fed to the second grinding stage. This process is performed in a moderately warm mode in the drum of a ball mill 516, also connected by its end to a methane collector, but, Unlike a mill 506, covered with a thick layer of thermal insulation. The heavy waste of the first grinding stage, leaving the head of the conical part of the hydrocyclone 514, is hydro-mechanically squeezed out of the liquid-phase residue on the filter centrifuge 517 and fed to the mixing device 518 for mixing with the solid residue extracted from the heavy hydrogenated carbon in the final system of coal liquefaction. The denser portion of the mixture, separated by a filtering centrifuge 517, is returned to the first compartment cycle for mixing with the product coming from the mill 506 for further grinding. The flow coming out of the mill 516 (similar to that coming out of the mill 506) is also supplied from a thermally insulated collector 519 equipped with a mixing device to a compartment implemented in a hydro-cyclone 521 covered with thermal insulation (to avoid returning the density of the liquid phase to its original value at which the the first stage of grinding and separation).

The grinding subsystem 640V with heating is made with the possibility of heating and grinding of combustible material 490С with a reduced particle size to obtain a paste 490E from 25-592

Combustible material. The light fraction produced from the upper axial nipple of the cylindrical part of the hydrocyclone 521 is fed to the container 522 equipped with a mixing device and heated with 491 V steam, while the process stream is heated to 90-95 ° C, which leads to an additional decrease in the density of zinc chloride solution in water from 1.403 to 1.354 g / cm ³ and a decrease in its viscosity, respectively, from 2.469 (25 ° C) and 1.454 (50 ° C) to 0.727 centipoise (it should be noted that this is significantly lower than the viscosity of fresh water). Further grinding of this unprocessed coal concentrate is carried out in a vibrating mill (vibratory grinding mill) 523, also thermally insulated.

After that, the final exact enrichment of coal is performed in a strong centrifugal field of a precipitation centrifuge 524, covered with thermal insulation. The high efficiency of the centrifugal compartment in a strong centrifugal field precipitating centrifuge 524 is due to the fact that the separation of separated minerals occurs in a heavy environment with anomalously low viscosity. Unlike the separation in hydrocyclones 514 and 521, the separation of the initial mixture of minerals in a fast precipitation centrifuge 524 is performed in a stationary liquid, which is at rest relative to the rotating vessel in which it is located, which rotates around a horizontal axis, and not in a turbulent rotating flow. The heavy, but non-viscous fluid, which is at rest relative to the rotor of the centrifuge 524, rotates inside the centrifugal separator at the same speed as the drum, rotating around its longitudinal horizontal axis with a huge angular velocity. As a result, a stationary sleeve of fluid in the form of a body of revolution of an annular solid appears inside the centrifuge rotor, and the ultra-pure coal concentrate floats on its inner cylindrical surface. Preferably, the separation factor can reach values that are significantly higher than the separation values achieved under the conditions of mineral separation in hydrocyclones (and even more than for separation under static conditions), since the rotational speeds of centrifugal separators reach thousands of turns per minute. In addition, in any hydrocyclone, the fluid moves along a twisted trajectory relative to its fixed wall. This causes an additional loss of the turbulent flow differential due to the large contact area of the rubbing fluid and solid surfaces, not to mention the significant erosion of the housing of the separating device.

Ultra-high-purity coal material, completely free of visible mineral impurities and representing the product of the third, exact stage of coal enrichment (in the grinding subsystem 640B with heating), is released when light material is separated by a centrifuge 524. Precipitated briquettes , which are centrifugal enrichment wastes and containing the last traces of combustible matter, are returned to the beginning of the enrichment part of the process by means of a lift 525 (equipped with azhdayuschim casing and a fan for cooling to ambient temperature, the conveyed material) for mixing the input process stream, the mill 506 within the first cold the grinding cycle.

The deepwater squeezing and paste forming subsystem 640C performs the final deepwater squeezing of the ultrapure product of the third separation stage by feeding the lighter material of the precipitation centrifuge 524 into the filter centrifuge 526. The resulting clear medium of hot water and minerals is returned to the 522 container from the thermally insulated collection 527 Wet coal briquettes 490Ό, impregnated with an aqueous solution of zinc chloride (480), are fed to the screw-shaped mixing device 529, n grevaemoe closed by a pair 491S for mixing with hot (140-190 ° C) 470 pastoobrazujushchego substance comprising, e.g., tetraline (1,2,3,4-tetrahydronaphthalene - C ₁₀ H ₁₂₎ doped with anthracene oil (fraction-bituminous coal resin boiling in the range of 270-360 ° C), and a trace element of elemental sulfur. The screw-shaped mixing device 529 with the paste-forming substance 470 thus turns the wet briquettes of combustible material 490Ό into a paste 490E of combustible material. However, not only paste formation takes place, but also from residual aqueous humor (boiling at high temperature, and, as a result, a 529 screw mixer works under vacuum) an extra pure coal concentrate 490Ό and final residues of an aqueous solution containing mineral salts are produced, providing the catalytic process hydrogenation with the formation of catalyst microdroplets, converted into an emulsion. Water vapor generated in the process is pumped to condensation.

Fluid fluidization subsystem 650A of the paste is adapted to fluidize the paste 490E. The consistency of a homogeneous pasty mass 490E, prepared in a screw mixer 529, is adjusted in a mixing device 530 by adding a diluent 460, such as isopropyl alcohol (isopropanol CH ₃ SNONSN ₃ ), or by mixing with some other organic solvents and feeding it to a dispersant 531. the solid phases of the coal-oil mixture are additionally ground in a strong centrifugal field to a coloidal size, at the same time turning the catalyst into an even thinner emulsion, for Acquiring the fluid fuel material 490R. Ultrapure coal concentrate, thereby deeply refined

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from mineral impurities and frays in disperser 531 to a very fine state in the form of a mobile hot oil-coal mixture 490P, produced as a continuous jet by means of a guide nipple 532 immersed in this fluid in the receiving cone 532 of hydrogenation subsystem 660A.

The hydrogenation subsystem 660A is designed to hydrogenate the 490P fluidized paste, for example, in a vertical pipe (534) terminated at the bottom with a T-shaped connection (536) with oppositely directed nozzles (537) forming the jet turbine — Segner’s wheel. In some embodiments, the hydrogenation subsystem 660A comprises a vertical shaft 534, configured to receive a fluidized paste and maintain its descending flow 490P; A segner wheel 536 having fluid communication with the vertical shaft 534 and configured to be brought into rotation by flowing fluidized paste 490P (by releasing fluidized paste 490P through nozzles 537); hydrogenation chamber 538 (hereinafter also referred to as blind shaft 538) surrounding the lower portion of the vertical shaft 534 and Segner wheel 536. The hydrogenation chamber 538 further comprises a heating module 539 configured to heat the fluidized paste 490P and 4900 (see below) and source 540 hydrogen, made with the possibility of introducing hydrogen 450 in the fluidized paste 490P, coming out of the Segner wheel 536, to hydrogenate the fluidized paste. The hydrogenation subsystem 660A further comprises a vertical case 535, which is in fluid communication with the hydrogenation chamber 538 and configured to support an upward flow 4900 of hydrogenated fluidized paste from the hydrogenation chamber 538, while providing recuperative heat exchange between the ascending hydrogenated fluidized pastes of the 4900 and one of the 89-piece set-ups. 490R.

Some embodiments of the invention comprise a hydrogenation module 260A comprising: a vertical shaft 534, configured to receive the flowable combustible material 490P and maintain its downward flow; A segner wheel 536 having fluid communication with the vertical shaft 534 and configured to be brought into rotation by means of a flowing flowable combustible material; a hydrogenation chamber 538 surrounding the lower portion of the vertical shaft 534 and the Segner wheel 538. The hydrogenation chamber 538 contains a heating module 539 configured to heat the flowing combustible material and a hydrogen source 540 configured to introduce hydrogen into the flowable combustible material coming out of the Segner wheel 538, to obtain a hydrogenated flammable fluid. The hydrogenation subsystem 260A further comprises a vertical housing 535 having fluid communication with the hydrogenation chamber 538 and configured to support an upward flow 4900 of hydrogenated flammable fluid from the hydrogenation chamber 538, while providing recuperative heat exchange between the rising hydrogenated flammable fluid 4900 and 498 and the heat exchange fluid between the ascending hydrogenated flammable fluid 4900 and 498 and the heat exchange fluid between the rising hydrogenated flammable fluid 4900 and the recovery heat exchange between the rising hydrogenated combustible fluid 4900 and the hydrogenation fluid 4900 and the recovery heat exchange between the rising hydrogenated combustible fluid 4900 and the hydrogenation fluid 5300 and hydrogen recharge. flowing combustible material 490Р. It should be explicitly noted that the hydrogenation module 260A may be part of the system 500 or it may be an independent module that receives a combustible flowable material from any source and supplies a hydrogenated combustible fluid to any further processing device. In some embodiments, the vertical shaft 534 and the vertical cover 538 are at least one kilometer in length, and in the underground mine for combustible material is Segner's wheel 538, used to generate a flowing combustible material. A more detailed description of the hydrogenation module / subsystem 660A is provided below.

Cone 533 is the upper part of a rotating vertical pipe 534, ending at the bottom with a T-shaped connection 536 with oppositely directed nozzles 537, forming a jet turbine - Segner's wheel. Thus, the slippery coal-oil mixture 490P supplied for hydrogenation is at the same time the working medium for the hydromechanical mixing device. However, some embodiments of the invention may contain other hydrogenation subsystems 650A. The rotating vertical pipe 534, which feeds this stream for hydrogenation, is introduced in a concentric way into a vertical well 535, ending with a blind shaft 538 — a vertical recess protected from the inside of the rock pressure by means of a sealed tank.

Due to the reaction of high-pressure jets of the movable hot coal-oil mixture flowing from these nozzles 537, rotation of its entire vertical hollow shaft surrounding the coal-oil mixture 490P column, about a thousand meters or more, is ensured around its axis. If rotation with even higher angular velocities is required, the mixing device in the blind shaft 538 can be rotated using an additional electric drive. At the same time in the blind mine 538 spontaneously generated hydrostatic pressure, reaching a hundred atmospheres and more. Its value depends on the depth of the underground mine and the height of the well head below the surface of the earth. Since modern coal mines are already reaching a depth of 1,200–1,400 m (the depth record is 2,042 m), the average level of an underground mine around the world is constantly decreasing, even at a depth of 1,100–1,300 m, the pressure of a vertical column of loaded coal weighs 27,092,508

The visually hot slurry 490P reaches, naturally, values of the order of 10-12 MPa at the base of the blind shaft 538 without external energy consumption. Such a relatively high pressure is quite sufficient for highly effective liquefaction of coal substance 490Р using several highly active catalysts prepared on the basis of water-soluble inorganic compounds (including molybdenum-containing compounds, originating, for example, from solution 480). In addition, the temperature of the surrounding rocks at such depths is not subject to daily or seasonal fluctuations and is higher than the meteorological conditions in the working zone of coal liquefaction in the conditions of the earth's surface, in particular, in winter. Although free use of the earth's crust heat provides a certain decrease in the energy consumption in the described process, temperatures around 45-55 ° C are obviously not high enough to thermally destroy complex molecules in the 490P combustible material and, thus, to initiate the interaction of excited carbon atoms with hydrogen.

Blind shaft 538 can be equipped with a heat exchanger coil 539 with a high-temperature heat carrier circulating in it, which maintains the temperature in the hydrogenation reaction zone at the level of 390-420 ° C. Hydrogen source 450 into the coal hydrogenation zone is made using a vertical system of bubbling devices 540 installed on the periphery of the blind shaft 538 in such a way that gas jets 450 are introduced tangentially from the inside side wall of the hollow cylinder. At a temperature of 390-420 ° C and a pressure of 10-12 MPa in the presence of zinc chloride with an admixture of ammonium paramolybdate and elemental sulfur as a catalyst (occurring, for example, from solution 480 and from a paste-forming substance 470), the carbon contained in the original mineral reacts with molecular hydrogen (supplied to the blind mine 538 in a hot state from the methane processing device and captured from the feedstock in the process of reducing its size), and participates in the hydrogenation reaction of the coal substance 490Р with atomic hydrogen cleaved from the components of the paste-forming substance (mainly tetralin), showing, in this connection, an increased reactivity.

Hot hydrogen 450 can be supplied from the methane processing system and injected under high pressure into the blind shaft 538 tangentially to its internal cylindrical surface through several connecting tubes placed at different height levels in order to provide not only fine control of the thermal mode of hydrogenation, but also for use it as a mixing agent, because the elevation of the location of the source stream entering the hydrogenation exceeds the level of production of the extracted mixture glevodorodov (4900), the rising of the annular aperture between the bore 535 and axial tube 534, an artificial oil product resulting from the hydrogenation reaction, enters the empty space expanded head portion 535 of the well.

In the process of countercurrent of flows 490P, 4900 of material, recuperative heat exchange occurs between hot artificial petroleum product 4900, rising from a blind shaft 538, and fresh coal-oil mixture, which descends in the opposite direction along an axial pipe 534. A mixture of hydrocarbons 4900, which descends from a hydrogenation zone to a blind shaft 538 and reaching the surface of the soil, enters the separator 541, located in the head of the well 535 on the surface of the soil and is a hollow vertical sealed vessel in the shape of an inverted balloon. The main products of the process are collected in the form of a flammable liquid and hydrogenated material 490H. The vapor / gas phase of the 490H product can be separated from the liquid product and subjected to additional processing. The resulting gas-vapor mixture can be fed to the treatment from the hot separator 541 through the nozzle 542, and as a result, unreacted hydrogen (in the form of gas that cannot condense in this system) can be returned to the blind mine 538 for reuse in the hydrogenation process. Gases dissolved in rising fluid 4900 can be discharged due to the pressure difference above the surface. The gas-vapor mixture discharged from this hydrocarbon liquid can be fed to the recovery of its thermal energy by the corresponding external heat exchanging equipment (not shown). After that, it can be sent to a cold separator (not shown) for cooling, condensation, and subsequent separation into reusable hydrogen-containing gas that is recycled back into the process, and light condensed hydrogenation.

The final cleaning and processing of the residues of the hydrogenation product, after separating the combustible liquid and the hydrogenated material 490H from them, can be performed in the 620B cleaning subsystem and the separation of residues. The liquid mixture of highly boiling residual products after hydrogenation (489B), after their release from dissolved gases and flowing combustible material, may still be contaminated by residues of solid, non-fluidized material. The mixture 489B is discharged from the lower part of the separator 541 into the refrigeration unit 544 through the side nozzle 543 and accumulates in the sump 545, from where condensed liquid is fed for deep-water squeezing of the impregnating liquid phase to the batch centrifuge 546.

Briquette, periodically squeezed in a centrifuge 546, is cleaned in it (also in a batch mode) from the last impregnating residues of heavy hydrogenation with an organic

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solvent 440, for example, petroleum ether (a mixture of light hydrocarbons, predominantly saturated, with five and six carbon atoms). It then passes through a drying device 547 to obtain a residual product 4901 and waste 489C, loaded onto a belt conveyor 548, which transports this waste to a mixing device 518 for mixing with a wet heavy product removed from the original combustible mineral at the first stage of its grinding. The material discharged from the sump 545 is combined with the filtrate of the centrifuge 546, and the heavy hydrogenation product thus obtained, already completely free from solids, is sent for further processing, which is carried out, however, in an oil refinery.

The waste treatment subsystem 620A can receive waste rock at all stages of the process, for example, waste 489 from the afloat transportation separation subsystem 610A, waste 489A from the grinding and grinding subsystems 630A, 640A, 640V, 640C, and also waste 489С from the 620V cleaning and separation system residues. The wet solid waste mixture obtained in the mixing device 518 is cleaned with hot fresh water from the last residues of mineral salts removed from the process by multistage countercurrent washing in a vacuum belt filter 509, with grinding in an airtight mill 510 (with simultaneous trapping of methane). Then it is removed from the production cycle and placed in the developed space as a cheap bulk material. Wash water obtained in the countercurrent washing process, which is a dilute solution of zinc chloride in water mixed with molybdenum-containing compounds, is sent from collector 549 through a pump 550 to an evaporation system 551 for evaporation. Sparse water vapor released during evaporation from the solution is liquefied in condenser 552. The resulting fresh hot condensate returns to the first stage of countercurrent washing of solid waste in a belt vacuum filter 509. An aqueous solution of zinc chloride with the remaining molybdenum-containing admixtures recovered to the required initial density 1.423 g / cm ³ by evaporation, by means of the pump 511 is removed from the internal circulation loop of the evaporator system 551 in the beginning of the process, i.e., in the hydrostatic system Skogen coal lift. Thus, the production cycle of zinc chloride and molybdenum-containing compounds used as water-salt solution 480 in the process, as well as the production cycle of mineral salts that catalyze the hydrogenation process, can be almost closed. With proper manufacturing standards, the irreversible loss of these substances is minimal.

Thus, it is preferable that the above-described methods and systems in the coal mining industry for the production of artificial liquid fuels in underground conditions are energy-saving and environmentally friendly, and their use can significantly increase the technical and economic efficiency of processing combustible minerals, in particular those that have a high content. non-combustible mineral impurities. At the same time, extraction of composite materials is ensured (due to the associated extraction of methane from the feedstock) and liquefaction can be carried out (due to the increased purity of the coal concentrate supplied for hydrogenation, which, moreover, is deeply impregnated with the catalyst of the hydrogenation process and did not sink into contact with air oxygen during transportation and grinding). This reduces the specific consumption of the original solid combustible mineral per ton of the resulting liquid product. In addition, the harmful effects of an underground mine and the production of artificial liquid fuels on the natural environment are significantly weakened, since all the waste of such an enterprise is located in an underground underground space. In addition, the release of the finished product — an artificial petroleum product produced using underground coal mines — instead of extracting raw solid fuel to the earth’s surface, makes it possible not only to exclude such powerful energy consumers as cable winch lifts from the mine’s equipment modern mines reaches 15,000 kW) and coal preparation plants (the total electrical power of ground-based device drives can reach 10,000 kW), but also Do not completely abandon the use of rail transport. In this situation, it is much more cost-effective to transport the product to its destination by transporting it through a pipeline, which is about three pelvis cheaper than transporting the railway (not to mention the mechanical loss of solid fuel as a result of blowing coal dust out of railway cars. ).

Preferably, the disclosed methods and systems may be of particular interest for deep-sea and super-deep-sea sediments of energy minerals. For example, the current depth record in the coal industry is approaching 2000 m. Coal liquefaction at such extreme depths leads to an increase in the operating pressure in the hydrogenation zone to 21-22 MPa (without attracting input power from outside), which significantly intensifies such underground technological process and greatly facilitates the processing of even the most carbonized types of combustible minerals into artificial petroleum products. However, according to modern geological science, coal seams extend to even greater depths, which opens up prospects for the development of these huge deposits of energy minerals, not for the extraction of solid fuels, but

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for the conversion of mining from coal mining to environmentally friendly production of synthetic liquid fuels. The constant rise in the temperature of the surrounding formation with a decrease in the level of the underground mine provides a significant increase in the share of free thermal energy of the Earth’s subsoil in the overall energy balance of the process. In addition, the saturation of coal and the surrounding formation with methane increases dramatically with increasing location of the coal seam.

Thus, the possibility of integrated use of the potential of the power of the extracted raw materials with simultaneous extraction of methane preferably distinguishes the method of the invention from the known technologies for processing solid fuels into alternative energy sources. The reduced need for hydrogen also contributes to the profitability of the underground liquefaction of coal as compared to the surface extraction of artificial liquid fuels. The fact is that the new extracted combustible mineral obtained from the mine bottom immediately becomes isolated from the atmosphere of the mine by means of operational immersion into the water-salt substance. Thus, atmospheric oxygen loses contact with the coal component of the combustible mineral and initiates the mechanism of its endogenous oxidation. In general, the main advantage of the technological process of the invention is the constant increase in the technical and economic efficiency of underground coal liquefaction, while traditional approaches to the production of artificial liquid fuel (when the coal liquefaction system is located on the surface) lead to an inevitable increase in the basic cost of artificial liquid fuel. and to the harmful effects of such industrial activity on the natural environment when an underground mine reaches deeper depths.

In some embodiments, the method of treating combustible minerals comprises the following steps: preliminarily prepare the feedstock in size with its subsequent gravitational concentration, mix the resulting concentrate with a paste-forming substance and hydrogenate the coal substance in a hot mode at elevated pressure, after which the mixture of liquid liquefaction products is separated from the remaining solid inert residue. After preliminary preparation of the feedstock in size sold in underground conditions, the milled material is loaded into a liquid medium column with a density intermediate between the density of the combustible mineral and the waste rock prepared by dissolving mineral salts in water that have a catalytic effect on the further hydrogenation of the extracted mineral mineral. After that, step-by-step wet grinding and concentration by means of gravity of an enriched material that is afloat on the surface of the earth are performed in the same water-salt substance within the framework of a three-stage enrichment. Then, the resulting final concentrate is mixed with a paste-forming substance, diluted with an organic solvent, ground to a colloidal size, and fed to a hollow rotating shaft installed in a vertical well and ending with a Segner wheel for hydrogenation in a blind shaft. The hydrogenate rising in the annular opening between the hollow rotating shaft and the vertical well is freed from gases dissolved in it, separated from the solid residue, and the product of liquefying the combustible mineral is fed to the distillation into fractions.

In some embodiments, the waste rock flooded after it enters the water-salt medium column is squeezed out of the liquid phase, rinsed with water and soil, at the same time trapping methane released into the gaseous phase in the process of reducing the size of said waste rock, after which it is placed in the developed space.

In some embodiments, the method further comprises the step of grinding the material being afloat in the first stage of the enrichment cascade at ambient temperature in the same solution, while simultaneously collecting the released methane, in a mill operating in a closed loop with a separator of a combustible mineral.

In some embodiments, the implementation of the product of the first stage of the enrichment cascade, mixed in an aqueous salt solution, is heated and additionally milled with simultaneous capture of released methane in the second stage of the enrichment cascade, while at the same time it is additionally separated under the action of moderate heating.

In some embodiments, the obtained process stream of the second stage of the enrichment cascade is heated at the third stage of the enrichment cascade to an even higher temperature that does not reach the boiling point of the water-salt substance, after which it additionally grinds its solid phase to a very fine state and, finally, is precisely separated from the last remnants of visible mineral impurities in a strong centrifugal field in a hot technological mode.

In some embodiments, the implementation of the waste of the second and third stages of enrichment under the action of gravity is squeezed out of the residue of the liquid phase and returned to wet grinding at the first stage of the enrichment cascade, followed by removal from the process along with the waste of the first stage of the enrichment cascade.

In some embodiments, the implementation of the solid residue, separated from the product of the liquefaction of a combustible mineral, is purified from the impregnating mixture of hydrocarbons with an organic solvent, dried and mixed with the dehydrated waste of the first stage of the enrichment cascade, mixed with the waste of the second and third stages of enrichment, after which the resulting mixture is inert

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the minerals are rinsed with fresh water along with the waste rock flooded in a column of water-salt medium, after which the initial crushed raw material is fed to the latter.

In some embodiments, the implementation of the wash water remaining after the waste treatment process is evaporated to its original density and returned to the beginning of the process.

In some embodiments, the implementation of the increase in pressure and liquefaction of the produced natural gas can be performed using any of the above-described embodiments.

In some embodiments, the implementation of mineral salts used for the preparation of water-salt substances, with a density intermediate between the density of the combustible mineral and barren rock, may contain individual inorganic compounds and / or mixtures thereof, such as zinc or tin chlorides or bromides, various ferrous sulfates, ammonium salts molybdic acids, as well as potassium formate, which later has a positive effect on the hydrogenation process, either due to its catalytic effect or due to the release of atomic hydrogen a.

In some embodiments, the paste-forming substance for preparing an oil-carbon mixture supplied for hydrogenation may contain organic compounds of the aromatic series that can serve as atomic hydrogen donors, for example, tetralin, methylnaphthalene, a mixture of quinoline with phenol, cresol, naphthalene solution in phenol, technical anthracene and other components of anthracene oil.

In some embodiments, the implementation of the solvent of the coal-oil mixture to adjust its consistency may contain gasoline processing products and / or individual organic compounds and mixtures thereof obtained in a synthetic way, for example, isopropanol and other alcohols.

It should be noted that some embodiments of the present invention overcome most of the transportation problems inherent in known technologies by performing a liquefaction underground near the actual place of extraction of combustible material. Underground location also eliminates many of the adverse environmental effects associated with known technologies. In addition, the separation of combustible material by means of transportation afloat solves both the problem of feeding and the problem of removing waste rock, since the latter can simply be returned to the underground mine after the processing described above. Finally, the energy requirement is significantly reduced due to the use of the Segner wheel, which is rotated under the influence of the material flow, and the use of thermal energy and pressure, provided by the underground location of the hydrogenation chamber. Processes can be organized, as illustrated above, with maximum reuse of the fluids used in the process, using hydrogen extracted from the combustible material for hydrogenation and minimizing energy consumption, while ensuring maximum liquefaction efficiency.

In the above description, the embodiment is an example or implementation of the invention. Different expressions such as "one embodiment", "an embodiment", "certain embodiments of" or "certain embodiments of" are not necessarily all refer to the same embodiments.

Although the various features of the invention may be described in the context of a single embodiment, the features may also be provided separately or in any acceptable combination. Conversely, although the invention may be described herein for clarity in the context of separate embodiments, the invention may also be implemented in a single embodiment.

Some embodiments of the invention may include features from various embodiments disclosed above, while some embodiments may contain elements from other embodiments disclosed above. Disclosure of the elements of the invention in the context of a specific embodiment should not be taken as limiting them, used separately in a particular embodiment.

In addition, it should be understood that the invention can be performed or implemented in various ways, and that the invention can be implemented in the form of some embodiments other than those described in the description above.

The invention is not limited to the diagrams or corresponding descriptions. For example, a stream should not go through each illustrated block or state, or in exactly the same order as illustrated and described.

The meanings of technical and scientific terms used in this document should be understood as they are used by experts in the field of technology to which the invention relates, unless otherwise specified.

Although the invention has been described with reference to a limited number of embodiments, they should not be construed as limiting the scope of the invention, but rather as an explanation of examples of several preferred embodiments. Other possible variations, modifications and uses are also included in the scope of the invention. Similarly, it is assumed that the scope of the invention is not limited to the above, but the attached claims and its legal equivalents.

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Claims (13)

CLAIM 1. The method of obtaining synthetic fuel from combustible material, containing the following steps: combustible material is gravitationally separated from waste rock in a water-salt solution chosen so that it has a density intermediate between the density of combustible material and the density of the waste rock; heat and grind the separated combustible material to form a paste of refined combustible material; fluidized pasta and perform hydrogenation of fluidized paste through the use of Segner wheels. 2. The method of claim 1, further comprising successively reducing the particle size of the separated combustible material in the solution and removing the residual gangue and gas therefrom, wherein heating and grinding includes heating and grinding the combustible material with a reduced particle size. 3. The method according to claim 2, additionally containing re-use of water-salt solution removed during separation and with a consistent reduction in particle size, in which the brine is chosen to catalyze the separation and successive reduction in particle size and / or in which successive reduction in particle size is performed in water-salt solution. 4. The method according to claim 1, wherein the aqueous saline solution contains at least one of the following: potassium formate, zinc chloride, ammonium paramolybdate, nanohydrous ferric sulfate (Fe ₂ (8O ₄ ) ₃ -9H ₂ O), ammonium paramolybdate ((ΝΗ. ₁ ) ₆ Μο-Θ _{2. 1} · 4Η ₂ Ο). ammonium tetramolybdate ((ΝΗ. |) ₂ · 4ΜοΘ ₃ · 2Η ₂ ). iron vitriol (E8O ₄ DN ₂ O), bivalent tin chloride 8iC1 ₂ , pentavalent chloride of tetravalent tin (8iC1 ₄ 0H ₂ O), zinc bromide and their mixtures. 5. The method according to claim 1, further comprising using an aromatic paste-forming substance to make a paste, wherein the paste-forming substance contains at least one of the following: tetralin, methylnaphthalene, a mixture of quinoline with phenol, cresol, naphthalene solution in phenol, anthracene, and anthracene oil components . 6. The method according to claim 1, wherein fluidization is carried out by mixing the paste with a diluent containing an organic solvent. 7. System for the production of synthetic fuel from combustible material by the method according to claim 1, containing a floating subsystem made with the possibility of gravitational separation of combustible material from waste rock in a water-salt solution, chosen so that it has a density intermediate between the density of combustible material and the density of waste rock; a grinding subsystem with heating, made with the possibility of heating and grinding the separated combustible material to obtain a paste of purified combustible material; fluid paste fluidization subsystem, made with the possibility of fluidizing the paste; and a hydrogenation subsystem configured to hydrogenate fluidized paste through the use of Segner wheels. 8. The system of claim 7, further comprising a grinding subsystem configured to progressively reduce the particle size of the separated combustible material in the solution and remove residual waste rock and gas from it, the grinding subsystem being heated to grind and grind the combustible material with a reduced particle size to make a paste. 9. The system of claim 7, further comprising a residue purification and separation subsystem, configured to separate the additional product from the residues of the hydrogenated material. 10. The system according to claim 7, wherein the floating subsystem is configured to receive combustible material inside the underground mine, while the hydrogenation subsystem is configured to perform hydrogenation inside the underground mine. 11. The system of claim 7, wherein the hydrochloric solution contains at least one of the following: potassium formate, zinc chloride, ammonium paramolybdate, nanohydrous ferric sulfate (Fe ₂ (8O ₄ ) ₃ ^ 9H ₂ O), ammonium paramolybdate ((ΝΗ ₄ ) ₆ 7ο ₇ Ο ₂₄ · 4Η ₂ Ο), ammonium tetramolybdate ((ΝΗ ₄ ) ₂ · 4ΜοΟ ₃ · 4Η ₂ Ο), iron vitriol (Pe8O ₄ DN ₂ O), bivalent tin chloride § and С1 ₂ s penta-aqueous tetravalent chloride of tin (8 and Cl ₄ H ₂ O), zinc bromide, and mixtures thereof. 12. The system according to claim 7, wherein the grinding subsystem with heating is adapted to use an aromatic paste-forming substance to make a paste, and the paste-forming substance contains at least one of the following: tetralin, methylnaphthalene, a mixture of quinoline with phenol, cresol, naphthalene solution phenol, anthracene and anthracene oil components. 13. The system according to claim 7, wherein the hydrogenation subsystem contains - 32 029258 a vertical shaft configured to receive a fluidized paste and maintain its downward flow; Segner wheel having fluid communication with the vertical shaft and configured to be driven in rotation by flowing fluidized paste; a hydrogenation chamber surrounding the lower portion of the vertical shaft and a Segner wheel, the hydrogenation chamber containing a heating module configured to heat the fluidized paste and a hydrogen source configured to introduce hydrogen into the fluidized fluid leaving the Segner wheel to hydrogenate the fluidized paste; and a vertical jacket having fluid communication with the hydrogenation chamber and configured to maintain an upward flow of the hydrogenated fluidized paste from the hydrogenation chamber while ensuring recuperation heat exchange between the rising hydrogenated fluidized paste and the downward fluidizing paste.