NATURAL GAS LIQUEFACTION AND PROCESSING USING GEOTHERMAL ENERGY

TECHNICAL FIELD

The present disclosure relates generally to natural gas liquefaction and more particularly to natural gas liquefaction and processing using geothermal energy.

BACKGROUND

Natural gas is a mixture of hydrocarbons that can be burned as a fuel, for example, to provide heating or generate electricity. Liquefied natural gas (LNG) is natural gas that has been converted to a liquid state. The volume of natural gas in its liquid state is about 600 times smaller than its volume in its gaseous state in a natural gas pipeline. This liquefaction process makes it possible to transport natural gas to places natural gas pipelines do not reach and to use natural gas as a transportation fuel. However, there exists a need for more efficient and reliable processes for the liquefaction of natural gas.

SUMMARY

This disclosure recognizes the previously unidentified and unmet need for a more efficient and reliable process for liquefying natural gas. This disclosure provides a solution to this unmet need in the form of a geothermally powered natural gas purification and liquefaction system. The system of this disclosure may be more reliable and efficient than previous natural gas liquefaction systems. Even if a natural gas liquefaction were to be powered by other forms of renewable energy, such as solar or wind power, these resources are notoriously unreliable and have relatively low power densities. As such, to maintain consistent operation, non-renewable energy sources would need to be used. In contrast, the geothermally powered system of this disclosure can operate at high power densities and can continue operations no matter the weather conditions or time of day.

Furthermore, the use of geothermal energy (e.g., in the form of a heated fluid obtained from a geothermal wellbore) may provide additional improvements and efficiencies over previous natural gas liquefaction technology. For instance, all or a portion of the system operations may be powered by a heated fluid from the geothermal system directly, without necessarily generating electricity and using the geothermally generated electricity to power system components. For instance, in place of conventional refrigeration units to cool system components, one or more absorption chillers may be used to facilitate cooling operations. The absorption chillers may be used to generate a cooling fluid with little or no input of electricity. Further to the above, the geothermally powered system of this disclosure may be uniquely positioned adjacent or near to drilling sites used to obtain natural gas. This allows the natural gas to be locally purified and stored at or near its source, thereby limiting the need for natural gas pipelines, which can be costly and can be undesirable in certain locations.

In some embodiments, the geothermal system that powers the natural liquefaction process is a closed geothermal system that exchanges heat with an underground geothermal reservoir. The geothermal reservoir may be a magma reservoir. For example, an underground geothermal reservoir, such as a magma reservoir, may facilitate the generation of high-temperature, high-pressure steam, while avoiding problems and limitations associated with previous geothermal technology. The geothermal systems of this disclosure generally include a wellbore that extends from the surface into an underground thermal reservoir, such as a magma reservoir. A closed heat-transfer loop is employed in which a heat transfer fluid is pumped into the wellbore, heated via contact with the underground thermal reservoir, and returned to the surface to power a natural liquefaction process located within a sufficient proximity to the wellbore.

The geothermal system of this disclosure may harness a geothermal resource with sufficiently high amounts of energy from magmatic activity such that the geothermal resource does not degrade significantly over time. This disclosure illustrates improved systems and methods for capturing energy from magma reservoirs, dikes, sills, and other magmatic formations that are significantly higher in temperature than heat sources that are accessed using previous geothermal technologies, and that can contain an order of magnitude higher energy density than the geothermal fluids that power previous geothermal technologies. In some cases, the present disclosure can significantly decrease natural gas liquefaction costs and/or reliance on non-renewable resources for natural gas liquefaction. In some cases, the present disclosure may facilitate more efficient natural gas liquefaction processes in regions where access to reliable power is currently unavailable or transport of non-renewable fuels is challenging. The systems and methods of the present disclosure may also or alternatively aid in decreasing carbon emissions.

Certain embodiments may include none, some, or all of the above technical advantages. One or more technical advantages may be readily apparent to one skilled in the art from figures, description, and claims included herein.

BRIEF DESCRIPTION OF THE FIGURES

For a more complete understanding of the present disclosure, reference is now made to the following description, taken in conjunction with the accompanying drawings and detailed description, in which like reference numerals represent like parts.

FIG. 1 is a diagram of underground regions near a tectonic plate boundary in the Earth.

FIG. 2 is a diagram of a conventional geothermal system.

FIG. 3 is a diagram of an example improved geothermal system of this disclosure.

FIG. 4 is a diagram of an example system in which natural gas liquefaction is facilitated by the improved geothermal system of FIG. 3.

FIG. 5 is a diagram of an example natural gas liquefaction system in greater detail.

FIG. 6 is a flowchart of an example method for operating the system of FIG. 4.

FIG. 7 is a diagram of an example system for performing thermal processes of FIGS. 3 and 4.

DETAILED DESCRIPTION

Embodiments of the present disclosure and its advantages will become apparent from the following Detailed Description when considered in conjunction with the accompanying figures. In the figures, each identical, or substantially similar component that is illustrated in various figures is represented by a single numeral or notation. For purposes of clarity, not every component is labeled in every figure, nor is every component of each embodiment shown where illustration is not necessary to allow those of ordinary skill in the art to understand the disclosure.

The present disclosure includes unexpected observations, which include the following: (1) magma reservoirs can be located at relatively shallow depths of less than 2.5 km; (2) the top layer of a magma reservoir may have relatively few crystals with little or no mush zone; (3) a magma reservoir does not decline in thermal output over at least a two-year period; (4) eruptions at drill sites into magma reservoirs are unlikely and have never been observed (e.g., eruptions have not happened at African and Icelandic drill sites in over 10,000 years and it is believed a Kilauea, Hawaii drill site has never erupted); and (5) drilling into magma reservoirs can be reasonably safe.

As used herein, “magma” refers to extremely hot liquid and semi-liquid rock under the Earth's surface. Magma is formed from molten or semi-molten rock mixture found typically between 1 km to 10 km under the surface of the Earth. As used herein, “borehole” generally refers to a hole that is drilled to aid in the exploration and recovery of natural resources, including oil, gas, water, or heat from below the surface of the Earth. As used herein, a “wellbore” generally refers to a borehole either alone or in combination with one or more other components disposed within or in connection with the borehole in order to perform exploration and/or recovery processes. In some instances, the terms wellbore and borehole are used interchangeably. As used herein, “fluid conduit” refers to any structure, such as a pipe, tube, or the like, used to transport fluids. As used herein, “heat transfer fluid” refers to a fluid, e.g., a gas or liquid, that takes part in heat transfer by serving as an intermediary in cooling on one side of a process, transporting and storing thermal energy, and heating on another side of a process. Heat transfer fluids are used in processes requiring heating or cooling.

FIG. 1 is a partial cross-sectional diagram of the Earth depicting underground formations that can be tapped by geothermal systems of this disclosure (e.g., for generating geothermal power). The Earth is composed of an inner core 102, outer core 104, lower mantle 106, transitional region 108, upper mantle 110, and crust 112. There are places on the Earth where magma reaches the surface of the crust 112 forming volcanoes 114. However, in most cases, magma approaches only within a few miles or less from the surface. This magma can heat ground water to temperatures sufficient for certain geothermal power production. However, for other applications, such as geothermal energy production, more direct heat transfer with the magma is desirable.

FIG. 2 illustrates a conventional geothermal power generation system 200 that harnesses energy from heated ground water. The geothermal system 200 is a “flash-plant” that generates power from high-temperature, high-pressure geothermal water extracted from a production well 202. The production well 202 is drilled through rock layer 208 and into the hydrothermal layer 210 that serves as the source of geothermal water. The geothermal water is heated indirectly via heat transfer with intermediate layer 212, which is in turn heated by magma reservoir 214. Magma reservoir 214 can be any underground region containing magma such as a dike, sill, or the like. Convective heat transfer (illustrated by the arrows indicating that hotter fluids rise to the upper portions of their respective layers before cooling and sinking, then rising again) may facilitate heat transfer between these layers. Geothermal water from layer 210 flows to the surface 216 and is used for geothermal power generation. The geothermal water (and possibly additional water or other fluids) is then injected back into layer 210 via injection well 204.

The configuration of conventional geothermal system 200 of FIG. 2 suffers from drawbacks and disadvantages, as recognized by this disclosure. For example, because geothermal water is a multicomponent mixture (i.e., not pure water), the geothermal water flashes at various points along its path up to the surface 216, creating water hammer, which results in a large amount of noise and potential damage to system components. The geothermal water is also prone to causing scaling and corrosion of system components. Chemicals may be added to partially mitigate these issues, but this may result in considerable increases in operational costs and increased environmental impacts, since these chemicals are generally introduced into the environment via injection well 204.

Example Improved Geothermal System

FIG. 3 illustrates an example magma-based geothermal system 300 that can be achieved using the systems and processes of this disclosure. The geothermal system 300 includes a wellbore 302 that extends from the surface 216 at least partially into the magma reservoir 214. The geothermal system 300 is a closed system in which a heat transfer fluid is provided down the wellbore 302 to be heated and returned to a thermal or heat-driven process system 304 (e.g., for power generation and/or any other thermal processes of interest). As such, geothermal water is not extracted from the Earth, resulting in significantly reduced risks associated with the conventional geothermal system 200 of FIG. 2, as described further below. Heated heat transfer fluid is provided to the thermal process system 304. The thermal process system 304 is generally any system that uses the heat transfer fluid to drive a process of interest. For example, the thermal process system 304 may include an electricity generation system and/or support thermal processes requiring higher temperatures/pressures than could be reliably or efficiently obtained using previous geothermal technology, such as the system 200 of FIG. 2. Further details of components of an example thermal process system 304 are provided with respect to FIG. 7 below.

The geothermal system 300 provides technical advantages over previous geothermal systems, such as the conventional geothermal system 200 of FIG. 2. The geothermal system 300 can achieve higher temperatures and pressures for increased energy generation (and/or for more effectively driving other thermal processes). For example, because of the high energy density of magma in magma reservoir 214 (e.g., compared to that of geothermal water of layer 210), a single wellbore 302 can generally create the power of many wells of the conventional geothermal system 200 of FIG. 2. Furthermore, the geothermal system 300 has little or no risk of thermal shock-induced earthquakes, which might be attributed to the injection of cooler water into a hot geothermal zone, as is performed using the previous geothermal system 200 of FIG. 2.

Furthermore, the heat transfer fluid is generally not substantially released into the geothermal zone by geothermal system 300, resulting in a decreased environmental impact and decreased use of costly materials (e.g., chemical additives that are used and introduced to the environment in great quantities during some conventional geothermal operations). The geothermal system 300 may also have a simplified design and operation compared to those of previous systems. For instance, fewer components and reduced complexity may be needed at the thermal process system 304 because only clean heat transfer fluid (e.g., steam) reaches the surface 216. There may be no need or a reduced need to separate out solids or other impurities that are common to geothermal water. The example geothermal system 300 may include further components not illustrated in FIG. 3.

Further details and examples of different configurations of geothermal systems and methods of their preparation and operation are described in U.S. patent application Ser. No. 18/099,499, filed Jan. 20, 2023, and titled “Geothermal Power from Superhot Geothermal Fluid and Magma Reservoirs”; U.S. patent application Ser. No. 18/099,509, filed Jan. 20, 2023, and titled “Geothermal Power from Superhot Geothermal Fluid and Magma Reservoirs”; U.S. patent application Ser. No. 18/099,514, filed Jan. 20, 2023, and titled “Geothermal Power from Superhot Geothermal Fluid and Magma Reservoirs”; U.S. patent application Ser. No. 18/099,518, filed Jan. 20, 2023, and titled “Geothermal Power from Superhot Geothermal Fluid and Magma Reservoirs”; U.S. patent application Ser. No. 18/105,674, filed Feb. 3, 2023, and titled “Wellbore for Extracting Heat from Magma Chambers”; U.S. patent application Ser. No. 18/116,693, filed Mar. 2, 2023, and titled “Geothermal Systems and Methods With an Underground Magma Chamber”; U.S. patent application Ser. No. 18/116,697, filed Mar. 2, 2023, and titled “Method and System for Preparing a Geothermal System with a Magma Chamber”; and U.S. Provisional Patent Application No. 63/444,703, filed Feb. 10, 2023, and titled “Geothermal Systems and Methods using Energy from Underground Magma Reservoirs”, the entirety of each of which is hereby incorporated by reference.

Geothermally Powered Natural Gas Liquefaction System

FIG. 4 illustrates an example combined geothermal and natural gas liquefaction system 400 of this disclosure. The combined geothermal and natural gas liquefaction system 400 includes all or a portion of the components of the magma-based geothermal system 300 described above with respect to FIG. 3, as well as geothermally powered natural gas liquefaction system 500 for purifying and liquefying natural gas. An example of the geothermally natural gas liquefaction system 500 is described in greater detail below with respect to FIG. 5. The combined geothermal and natural gas liquefaction system 400 may include all or a portion of the thermal process system 304. In operation, heat transfer fluid is injected into the wellbore 302, which extends from the surface 216 into the magma reservoir 214 underground. The heated heat transfer fluid can be conveyed to the thermal process system 304 as heat transfer fluid 404a that can be used to drive processes, such as the generation of electricity by turbines 704 and 708 in FIG. 7. Heat transfer fluid 404a may be referred to in the alternative as a stream of heat transfer fluid 404a. Heat transfer fluid 404c, which can be formed from any remaining amount of heat transfer fluid 404a (e.g., steam) exiting from the thermal process system 304 and/or the wellbore bypass stream, i.e., heat transfer fluid 404b, is provided to the geothermally powered natural gas liquefaction system 500. The electricity 408 may be used in addition to or in place of heat transfer fluid 404c for powering electrical and mechanical processes in the geothermally powered natural gas liquefaction system 500.

As described in greater detail below with respect to FIG. 5, the geothermally powered natural gas liquefaction system 500 uses the heat transfer fluid 404c to purify and liquefy natural gas. For example, heated heat transfer fluid 404c heated through heat transfer with the underground magma reservoir 214 may be used to power a chiller (e.g., an absorption chiller) that facilitates operations of the geothermally powered natural gas liquefaction system 500. For example, purification operations may be performed by cooling an initial or raw natural gas stream received by the geothermally powered natural gas liquefaction system 500. Similarly, a cooling fluid generated using heat transfer fluid 404c heated by wellbore 302 may be used to condense the natural gas. Compression of the natural gas may be facilitated using energy from the wellbore 302 (e.g., in the form of electricity 408 and/or heat transfer fluid 404c). For example, an electrically powered compressor may be powered by electricity 408, or a steam powered compressor may be powered by heat transfer fluid 404c.

Heat transfer fluid (e.g., condensed steam) that is cooled and/or decreased in pressure after powering the geothermally powered natural gas liquefaction system 500 may be returned to the wellbore 302 as heat transfer fluid 406a. For instance, as shown in the example of FIG. 4, a stream of return heat transfer fluid 406c may be provided back to the thermal process system 304, used to drive one or more reactions or processes, and then expelled as heat transfer fluid 406a for return to the wellbore 302. The heat transfer fluid 406a can also include a bypass stream of heat transfer fluid 406b, which can be formed from heat transfer fluid 406c, in whole or in part. Restated, thermally processed return stream of heat transfer fluid 406a includes heat transfer fluid (e.g., condensed steam) from the thermal process system 304 and/or the bypass stream of heat transfer fluid 406b. Thermally processed return stream of heat transfer fluid 406a that is sent back to the wellbore 302 may be water (or another heat transfer fluid), while the stream of heat transfer fluid 404a received from the wellbore 302 is steam (or another heat transfer fluid at an elevated temperature and/or pressure). While the example of FIG. 4 includes the thermal process system 304 of FIG. 3, in some cases, the combined geothermal and natural gas liquefaction system 400 may exclude all or a portion of the thermal process system 304. For example, the wellbore stream of heat transfer fluid 404a from the wellbore 302 may be provided directly to the geothermally powered natural gas liquefaction system 500 (see wellbore bypass stream of heat transfer fluid 404b described above).

Streams of heat transfer fluid 404a-c and 406a-c may be any appropriate fluid for absorbing heat within the wellbore 302 and driving operations of the geothermally powered natural gas liquefaction system 500, and, optionally, the thermal process system 304. For example, the heat transfer fluid may include water, a brine solution, one or more refrigerants, a thermal oil (e.g., a natural or synthetic oil), a silicon-based fluid, a molten salt, a molten metal, or a nanofluid (e.g., a carrier fluid containing nanoparticles). A molten salt is a salt that is a liquid at the high operating temperatures experienced in the wellbore 302 (e.g., at temperatures between 1,600° F. and 2,300° F.). In some cases, an ionic liquid may be used as the heat transfer fluid. An ionic liquid is a salt that remains a liquid at more modest temperatures (e.g., at or near room temperature). In some cases, a nanofluid may be used as the heat transfer fluid. The nanofluid may be a molten salt or ionic liquid with nanoparticles, such as graphene nanoparticles, dispersed in the fluid. Nanoparticles have at least one dimension of 100 nanometers (nm) or less. The nanoparticles increase the thermal conductivity of the molten salt or ionic liquid carrier fluid. This disclosure recognizes that molten salts, ionic liquids, and nanofluids can provide improved performance as heat transfer fluids in the wellbore 302. For example, molten salts and/or ionic liquids may be stable at the high temperatures that can be reached in the wellbore 302. The high temperatures that can be achieved by these materials not only facilitate increased energy extraction but also can drive thermal processes that were previously inaccessible using previous geothermal technology. The heat transfer fluid may be selected at least in part to limit the extent of corrosion of surfaces of the combined geothermal and natural gas liquefaction system 400. As an example, the heat transfer fluid may be water. The water is supplied to the wellbore 302 as a stream of heat transfer fluid 406a in the liquid phase and is transformed into steam within the wellbore 302. The steam is received as a stream of heat transfer fluid 404a and used to drive the geothermally powered natural gas liquefaction system 500.

Example Geothermally Powered Natural Gas Liquefaction System

FIG. 5 shows an example of the natural gas liquefaction system 500 of FIG. 4 in greater detail. The system 500 purifies and condenses a raw or initial natural gas stream 502 for storage in a vessel 522 or transport in a liquid pipeline 524 for some downstream use. The raw or initial natural gas stream 502 may be obtained from any appropriate source, such as the natural gas well 528 shown in FIG. 5 or a gas pipeline. In some cases, the initial natural gas stream 502 is collected from one or more wells 528 near or adjacent to the geothermally powered natural gas liquefaction system 500. For example, the wellbore 302 may be adjacent to a well 528 (or a number of such wells) producing an initial natural gas stream 502. This location of the natural gas liquefaction system 500 near natural gas well 528 may provide several advantages over conventional technologies, particularly, where the establishment of gas pipelines is not possible or is undesirable. For example, rather than needing to establish pipelines that can transport natural gas from the wells 528 to remotely located natural gas-burning infrastructure, the initial natural gas stream 502 can be liquified on site and transported in a more energy-dense liquefied form.

The example geothermally powered natural gas liquefaction system 500 includes one or more pretreatment units 504, one or more absorption chillers 506, one or more compressors 512, and one or more condensers 518. The pretreatment units 504 include components for preparing the initial natural gas 502 for liquefaction. The initial natural gas stream 502 may include methane, ethane, propane, other hydrocarbons, mercury, water, sulfur compounds, and/or carbon dioxide. The pretreatment units 504 may include components for removing impurities from the initial natural gas stream 502, such as the water, mercury, sulfur compounds, carbon dioxide, and higher molecular weight hydrocarbons. As an example, the pretreatment units 504 may cool the initial natural gas stream 502 using a cooling fluid 508 obtained from an absorption chiller 506 (described further below). The pretreatment units 504 may include one or more gas separators that separate a purified natural gas stream 514 from a waste stream 530. The purified natural gas stream 514 includes desired components of the eventual liquefied natural gas stream 520, such as a mixture of hydrocarbons including propane, butane, and/or pentane. The waste stream 530 may include water and other components with higher vaporization temperatures. The waste stream 530 may be further processed to obtain other products (not shown for conciseness).

The pretreatment units 504 may include one or more reactors for performing chemical purification treatments, such as acid gas treatment and the like. For example, the pretreatment units 504 may facilitate the removal of acid gases (e.g., hydrogen sulfide and carbon dioxide) from the initial natural gas stream 502. As an example, a treatment may be performed to remove acid gases. For instance, a membrane-based separation process may be performed to separate the acid gases from the initial natural gas stream 502.

Water vapor may be removed from the initial natural gas stream 502 in the pretreatment units 504. Examples of processes for removing water vapor include glycol dehydration, water adsorption using deliquescent chloride desiccants, and the like. Mercury may be removed from the initial natural gas stream 502. For example, mercury may be adsorbed from the initial natural gas stream 502 using an appropriate material, such as activated carbon or the like. Nitrogen may be removed from the initial natural gas stream 502. For example, nitrogen may be removed using an adsorption process and/or a cryogenic process. In some cases, active impurity removal techniques may be used, such as pressure swing adsorption, to remove impurities from the initial natural gas stream 502. Such processes may use cooling from the absorption chiller 506 and/or electricity 408.

The compressor 512 receives and compresses the purified natural gas stream 514. The compressor 512 is generally powered at least in part by energy obtained from the wellbore 302. For example, the compressor 512 may be powered by electricity 408 and/or heated heat transfer fluid 404c. For example, compressor 512 may be operated using a steam-powered motor using heat transfer fluid 404c that is steam. An example of a steam-powered motor that may be used in such a compressor 512 is described in U.S. Provisional Application No. 63/448,929, filed Feb. 28, 2023, and titled “Drilling Equipment Powered by Geothermal Energy”, the contents of which are incorporated herein by reference in their entirety. In other cases, an electromechanical compressor 512 may be powered by electricity 408 generated from heat transfer fluid 404a (see FIGS. 4 and 7).

The condenser 518 receives compressed, purified natural gas stream 516 and condenses this natural gas stream 516 to form liquified natural gas stream 520. The condenser 518 may be a vessel through which the compressed natural gas stream 516 flows and is cooled. A heat exchanger 526 may be positioned relative to (e.g., within or around) the condenser 518. Cooling fluid 508′ from absorption chiller 506′ (described further below) passes through the heat exchanger 526 to cool the condenser 518. In the condenser 518, the compressed natural gas stream 516 is cooled to below its condensation temperature (or to at least the condensation temperature) in order to form the liquified natural gas stream 520. The liquefied natural gas stream 520 may be provided for storage in a vessel 522 or sent for transport along a pipeline 524 (e.g., for use in another downstream process). The storage vessel 522 is generally any appropriate tank or other vessel for storing liquefied natural gas.

Absorption chiller(s) 506, 506′ can generate a cooling fluid 508, 508′ using heated heat transfer fluid 404c. An absorption chiller 506, 506′ may employ an absorption cycle (e.g., a three-phase cycle involving evaporation, absorption, and regeneration) to generate cooling fluid 508, 508′. The input energy for the absorption chiller 506, 506′ is heated heat transfer fluid 404c, which, as described above with respect to FIG. 4, includes heat transfer fluid 404a from the wellbore 302 and/or heat transfer fluid output from the thermal process system 304. The use of heat transfer fluid 404c facilitates the generation of cooling fluid 508, 508′ without the inefficiencies of first generating electricity using heat transfer fluid 404c and subsequently using this electricity to drive an electromechanical chiller. The absorption chiller 506, 506′ may also be more resilient than conventional electromechanical chillers, which have moving parts (e.g., compressors and the like) that may require increased maintenance and/or be more susceptible to failure over time. As such, the absorption chiller 506, 506′ may be capable of functioning with limited maintenance over a long period of time using the reliable energy obtained from the wellbore 302. The example of FIG. 5 shows two separate absorption chillers 506 and 506′ providing cooling to the pretreatment units 504 and condenser 518, respectively. However, the absorption chillers 506 and 506′ may be the same chiller, or each chiller 506, 506′ may include multiple chillers as necessary to achieve the cooling requirements of the natural gas liquefaction system 500.

In an example operation of the natural gas liquefaction system 500, the initial natural gas stream 502 is received from natural gas-producing wells 528. The initial natural gas stream 502 is sent to the pretreatment units 504. Operations of the pretreatment units 504 may be facilitated by a cooling fluid 508 provided by the absorption chiller 506, which itself is operated using the heated heat transfer fluid 404c as a heat source. For example, heated heat transfer fluid 404c may be used by the absorption chiller 506 to generate cooling fluid 508. The cooling fluid 508 cools components of the pretreatment units 504 to remove at least a portion of the impurities from the initial natural gas stream 502. A warmed cooling fluid 510 (i.e., the cooling fluid 508 after being heated in the pretreatment units 504) is returned to the absorption chiller 506 to be cooled for further use.

The compressor 512 compresses the purified natural gas stream 514 output by the pretreatment units 504. The compressed natural gas stream 516 is then provided to a condenser 518, which includes a heat exchanger 526 that cools the condenser 518, such that the compressed natural gas stream 516 is brought below its condensation temperature (at the current pressure of the natural gas in the condenser 518). A cooling fluid 508′ from absorption chiller 506′ is provided to the heat exchanger 526 to facilitate condensation of natural gas in the condenser 518. A warmed cooling fluid 510′ is provided back to the absorption chiller 506′. The resulting liquefied natural gas stream 520 may be stored in storage vessel 522 or provided to a liquid pipeline 524.

Example Method of Geothermally Powered Natural Gas Liquefaction

FIG. 6 illustrates an example method 600 of operating the systems 400 and 500 of FIGS. 4 and 5. The method 600 may facilitate the efficient treatment and liquefaction of natural gas. For example, the method 600 may facilitate the liquefaction of natural gas at or near a location where natural gas is obtained or is already available through existing gas pipelines without the need for an external energy source and without relying on intermittent energy sources such as solar and/or wind energy sources. The method 600 may begin at step 602 where initial natural gas stream 502 is received. The initial natural gas stream 502 may include both hydrocarbons of interest as well as a number of impurities, such as water, carbon dioxide, sulfur-containing compounds, mercury-containing compounds, and the like.

At step 604 heated heat transfer fluid 404c is received. The heated heat transfer fluid 404c can include fluid obtained directly from wellbore 302 and/or fluid that is still sufficiently hot that is output from the thermal process system 304 (see FIG. 4). The heated heat transfer fluid 404c may be received by an absorption chiller 506, 506′ and used to generate a cooling fluid 508, 508′ that facilitates processes at steps 606 and 610, described below.

At step 606, the natural gas stream 502 received at step 602 is pretreated to remove impurities. Examples of pretreatment operations that may be performed at step 606 are described above with respect to the pretreatment units 504 of FIG. 5. The removal of impurities at step 606 is generally performed at least in part using cooling fluid 508, 508′ that is obtained using the heated heat transfer fluid 404c.

At step 608, the purified natural gas from step 606 (e.g., purified natural gas stream 514 of FIG. 5) is compressed. The purified natural gas may be compressed using electricity 408 from the thermal process system 304 and/or heated heat transfer fluid 404c, as described above with respect to the example compressor 512 of FIG. 5.

At step 610, the compressed natural gas from step 608 (e.g., compressed natural gas stream 516 of FIG. 5) is liquefied. An example of this liquefaction is described above with respect to the condenser 518 of FIG. 5. At step 612, the resulting liquefied natural gas (e.g., liquified natural gas stream 520 of FIG. 5) is provided for storage and/or transport.

Modifications, omissions, or additions may be made to method 600 depicted in FIG. 6. Method 600 may include more, fewer, or other steps. For example, at least certain steps may be performed in parallel or in any suitable order. While generally described as the geothermally powered natural gas liquefaction system 500 performing operations of the method 600, any equipment or associated component(s) may perform or may be used to perform one or more steps of the method 600.

Example Thermal Process System

FIG. 7 shows a schematic diagram of an example thermal process system 304 of FIG. 3. The thermal process system 304 includes a steam separator 702, a first turbine set 704, a second turbine set 708, a high-temperature/pressure thermochemical process 712, a medium-temperature/pressure thermochemical process 714, one or more lower temperature/pressure processes 716a,b, and a condenser 742. The thermal process system 304 may include more or fewer components than are shown in the example of FIG. 7. For example, a thermal process system 304 used for power generation alone may omit the high-temperature/pressure thermochemical process 712, medium-temperature/pressure thermochemical process 714, and lower temperature/pressure processes 716a,b. Similarly, a thermal process system 304 that is not used for power generation may omit the turbine sets 704, 708. As a further example, if heat transfer fluid is known to be received only in the gas phase, the steam separator 702 may be omitted in some cases. The ability to tune the properties of the heat transfer fluid received from the unique wellbore 302 of FIG. 3 facilitates improved and more flexible operation of the thermal process system 304. For example, the depth of the wellbore 302, the residence time of heat transfer fluid in the wellbore 302, the pressure achieved in the wellbore 302, and the like can be selected or adjusted to provide desired heat transfer fluid properties at the thermal process system 304.

In the example of FIG. 7, the thermal process system 304 receives a stream 718 from the wellbore 302. One or more valves (not shown for conciseness) may be used to control the allocation of stream 718 within the thermal process system 304, e.g., to a steam separator 702 via stream 720, and/or to the first turbine set 704 via stream 728, and/or to the thermal process 712 via stream 729. Thus, the entirety of stream 718 can be provided to any one of streams 720, 728, or 729, or distributed equally or unequally among streams 720, 728, and 729.

The steam separator 702 is connected to the wellbore 302 that extends between the surface and the underground magma reservoir. The steam separator 702 separates a gas-phase heat transfer fluid (e.g., steam) from liquid-phase heat transfer fluid (e.g., condensate formed from the gas-phase heat transfer fluid). A stream 720 received from the wellbore 302 may be provided to the steam separator 702. A gas-phase stream 722 of heat transfer fluid from the steam separator 702 may be sent to the first turbine set 704 and/or the thermal process 712 via stream 726. The thermal process 712 may be a thermochemical reaction requiring high temperatures and/or pressures (e.g., temperatures of between 500° F. and 2,000° F. and/or pressures of between 1,000 psig and 4,500 psig). A liquid-phase stream 724 of heat transfer fluid from the steam separator 702 may be provided back to the wellbore 302 and/or to condenser 742. The condenser 742 is any appropriate type of condenser capable of condensing a vapor-phase fluid. The condenser 742 may be coupled to a cooling or refrigeration unit, such as a cooling tower (not shown for conciseness).

The first turbine set 704 includes one or more turbines 706a,b. In the example of FIG. 7, the first turbine set includes two turbines 706a,b. However, the first turbine set 704 can include any appropriate number of turbines for a given need. The turbines 706a,b may be any known or yet to be developed turbine for electricity generation. The turbine set 704 is connected to the steam separator 702 and is configured to generate electricity from the gas-phase heat transfer fluid (e.g., steam) received from the steam separator 702 (stream 722). A stream 730 exits the set of turbines 704. The stream 730 may be provided to the condenser 742 and then back to the wellbore 302.

If the heat transfer fluid is at a sufficiently high temperature, as may be uniquely and more efficiently possible using the wellbore 302, a stream 732 of gas-phase heat transfer fluid may exit the first turbine set 704. Stream 732 may be provided to a second turbine set 708 to generate additional electricity. The turbines 710a,b of the second turbine set 708 may be the same as or similar to turbines 706a,b, described above.

All or a portion of stream 732 may be sent as gas-phase stream 734 to a thermal process 714. Process 714 is generally a process requiring gas-phase heat transfer fluid at or near the conditions of the heat transfer fluid exiting the first turbine set 704. For example, the thermal process 714 may include one or more thermochemical processes requiring steam or another heat transfer fluid at or near the temperature and pressure of stream 732 (e.g., temperatures of between 250° F. and 1,500° F. and/or pressures of between 500 psig and 2,000 psig). The second turbine set 708 may be referred to as “low pressure turbines” because they operate at a lower pressure than the first turbine set 704. Fluid from the second turbine set 708 is provided to the condenser 742 via stream 736 to be condensed and then sent back to the wellbore 302.

An effluent stream 738 from the second turbine set 708 may be provided to one or more thermal processes 716a,b. Thermal processes 716a,b generally require less thermal energy than processes 712 and 714, described above (e.g., processes 716a,b may be performed at temperatures of between 220° F. and 700° F. and/or pressures of between 15 psig and 120 psig). As an example, processes 716a,b may include water distillation processes, heat-driven chilling processes, space heating processes, agriculture processes, aquaculture processes, and/or the like. For instance, an example heat-driven chiller process 716a may be implemented using one or more heat driven chillers. Heat driven chillers can be implemented, for example, in data centers, cryptocurrency mining facilities, or other locations in which undesirable amounts of heat are generated. Heat driven chillers, also conventionally referred to as absorption cooling systems, use heat to create chilled water. Heat driven chillers can be designed as direct-fired, indirect-fired, and heat-recovery units. When the effluent stream includes low pressure steam, indirect-fired units may be preferred. An effluent stream 740 from all processes 712, 714, 716a,b, may be provided back to the wellbore 302.

This disclosure describes example systems 300, 400 that may facilitate improved geothermal operations. While these example systems 300, 400 are described as employing heating through thermal contact with a magma reservoir 214, it should be understood that this disclosure also encompasses similar systems in which another thermal reservoir or heat source is harnessed. For example, heat transfer fluid may be heated by underground water at an elevated temperature. As another example, heat transfer fluid may be heated by radioactive material emitting thermal energy underground or at or near the surface. As yet another example, heat transfer fluid may be heated by lava, for example, in a lava lake or other formation. As such, the magma reservoir 214 of FIGS. 3 and 4 may be any thermal reservoir or heat source that is capable of heating heat transfer fluid to achieve desired properties (e.g., of temperature and pressure). Furthermore, the thermal reservoir or heat source may be naturally occurring or artificially created (e.g., by introducing heat underground that can be harnessed at a later time for energy generation or other thermal processes).

Additional Embodiments

An embodiment of a method for producing liquefied natural gas, the method comprising:

- receiving heated heat transfer fluid from a wellbore extending from a surface into an underground magma reservoir, the wellbore configured to heat the heat transfer fluid via heat transfer with the underground magma reservoir to form the heated heat transfer fluid;
- receiving an initial natural gas stream;
- performing a purification operation on the initial natural gas stream to form a purified natural gas stream using the heated heat transfer fluid; and
- condensing the purified natural gas stream, wherein the method optionally includes any one or more of the following limitations:
- an embodiment further comprising compressing the purified natural gas stream using energy obtained from the heated heat transfer fluid;
- an embodiment wherein: the heated heat transfer fluid comprises steam; and compressing the purified natural gas stream using energy obtained from the heated heat transfer fluid comprises operating a compressor using the steam;
- an embodiment wherein: the heated heat transfer fluid comprises steam; and compressing the purified natural gas stream using energy obtained from the heated heat transfer fluid comprises: generating electricity using the steam; and operating a compressor using the generated electricity;
- an embodiment wherein performing the purification operation comprises: receiving, by an absorption chiller, the heated heat transfer fluid; using, by the absorption chiller, the heated heat transfer fluid to generate a cooling fluid; and cooling the initial natural gas stream using the cooling fluid;
- an embodiment wherein condensing the purified natural gas stream comprises: receiving, by an absorption chiller, the heated heat transfer fluid; using, by the absorption chiller, the heated heat transfer fluid to generate a cooling fluid; and cooling the purified natural gas stream using the cooling fluid below a condensation temperature of the purified natural gas stream;
- an embodiment wherein the initial natural gas stream comprises one or more of methane, ethane, propane, mercury, water, sulfur compounds, and carbon dioxide.

An embodiment of a system for producing liquefied natural gas, the system comprising:

- a wellbore extending from a surface into an underground magma reservoir, the wellbore configured to heat transfer fluid via heat transfer with the underground magma reservoir to form a heated heat transfer fluid; and
- a pretreatment system configured to
  - receive an initial natural gas stream; and
  - perform a purification operation on the initial natural gas stream to form a purified natural gas stream using the heated heat transfer fluid; and
- a condenser configured to condense the purified natural gas stream, wherein the system optionally includes any one or more of the following limitations:
  - an embodiment further comprising a compressor configured to compress the purified natural gas stream using energy obtained from the heated heat transfer fluid;
  - an embodiment wherein: the heated heat transfer fluid comprises steam; and the compressor is configured to compress the purified natural gas stream using mechanical energy obtained from the steam;
  - an embodiment wherein: the heated heat transfer fluid comprises steam; the system further comprises a turbine configured to generate electricity using the steam; and the compressor is configured to operate at least in part using the generated electricity;
  - an embodiment further comprising an absorption chiller configured to: receive the heated heat transfer fluid; generate a cooling fluid; and provide the cooling to the pretreatment system to perform the purification operation;
  - an embodiment further comprising an absorption chiller configured to: receive the heated heat transfer fluid; generate a cooling fluid; and provide the cooling to the condenser to cool the purified natural gas stream below a condensation temperature of the purified natural gas stream;
  - an embodiment wherein the initial natural gas stream comprises one or more of methane, ethane, propane, mercury, water, sulfur compounds, and carbon dioxide.

An embodiment of a system for producing liquefied natural gas, the system comprising:

- a pretreatment system configured to:
  - receive an initial natural gas stream; and
  - perform a purification operation on the initial natural gas stream to form a purified natural gas stream using a heated heat transfer fluid, the heated heat transfer fluid obtained via heat transfer with an underground magma reservoir; and
- a condenser configured to condense the purified natural gas stream, wherein the system optionally includes any one or more of the following limitations:
  - an embodiment further comprising a compressor configured to compress the purified natural gas stream using energy obtained from the heated heat transfer fluid;
  - an embodiment wherein: the heated heat transfer fluid comprises steam; and the compressor is configured to compress the purified natural gas stream using mechanical energy obtained from the steam;
  - an embodiment wherein: the heated heat transfer fluid comprises steam; the system further comprises a turbine configured to generate electricity using the steam; and the compressor is configured to operate at least in part using the generated electricity;
  - an embodiment further comprising an absorption chiller configured to: receive the heated heat transfer fluid; generate a cooling fluid; and perform one or both of the following: providing the cooling to the pretreatment system to perform the purification operation; and provide the cooling to the condenser to cool the purified natural gas stream below a condensation temperature of the purified natural gas stream;
  - an embodiment wherein the initial natural gas stream comprises one or more of methane, ethane, propane, mercury, water, sulfur compounds, and carbon dioxide.

Although embodiments of the disclosure have been described with reference to several elements, any element described in the embodiments described herein are exemplary and can be omitted, substituted, added, combined, or rearranged as applicable to form new embodiments. A skilled person, upon reading the present specification, would recognize that such additional embodiments are effectively disclosed herein. For example, where this disclosure describes characteristics, structure, size, shape, arrangement, or composition for an element or process for making or using an element or combination of elements, the characteristics, structure, size, shape, arrangement, or composition can also be incorporated into any other element or combination of elements, or process for making or using an element or combination of elements described herein to provide additional embodiments. Moreover, items shown or discussed as coupled or directly coupled or communicating with each other may be indirectly coupled or communicating through some interface device, or intermediate component whether electrically, mechanically, fluidically, or otherwise.

While this disclosure has been particularly shown and described with reference to preferred or example embodiments, it will be understood by those skilled in the art that various changes in form and detail may be made therein without departing from the spirit and scope of the disclosure. Accordingly, this disclosure includes all modifications and equivalents of the subject matter recited in the claims appended hereto as permitted by applicable law. Changes, substitutions and alterations are ascertainable by one skilled in the art and could be made without departing from the spirit and scope disclosed herein. Moreover, any combination of the above-described elements in all possible variations thereof is encompassed by the disclosure unless otherwise indicated herein or otherwise clearly contradicted by context.

Additionally, where an embodiment is described herein as comprising some element or group of elements, additional embodiments can consist essentially of or consist of the element or group of elements. Also, although the open-ended term “comprises” is generally used herein, additional embodiments can be formed by substituting the terms “consisting essentially of” or “consisting of.”

NATURAL GAS LIQUEFACTION AND PROCESSING USING GEOTHERMAL ENERGY

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