Patent Grant
10443926
The combustion of conventional fuels, such as gasoline and diesel, has proven to be essential in a myriad of industrial processes. The combustion of gasoline and diesel, however, may often be accompanied by various drawbacks including increased production costs and increased carbon emissions. In view of the foregoing, recent efforts have focused on alternative fuels with decreased carbon emissions, such as natural gas, to combat the drawbacks of combusting conventional fuels. In addition to providing a “cleaner” alternative fuel with decreased carbon emissions, combusting natural gas may also be relatively safer than combusting conventional fuels. For example, the relatively low density of natural gas allows it to safely and readily dissipate to the atmosphere in the event of a leak. In contrast, conventional fuels (e.g., gasoline and diesel) have a relatively high density and tend to settle or accumulate in the event of a leak, which may present a hazardous and potentially fatal working environment for nearby operators.
While utilizing natural gas may address some of the drawbacks of conventional fuels, the storage and transport of natural gas often prevent it from being viewed as a viable alternative to conventional fuels. Accordingly, natural gas is routinely converted into liquefied natural gas (LNG) at LNG plants and transported from the LNG plants to the customers via tankers. The availability of the LNG, however, may often be limited by the proximity of the customers to the LNG plants. For example, customers that are remotely located from the LNG plants may often rely on deliveries from the tankers, which may increase the cost of utilizing the LNG. Additionally, remotely located customers may often be required to maintain larger, cost-prohibitive storage tanks to reduce the frequency of the deliveries and/or their dependence on the tankers.
In view of the foregoing, small scale LNG plants have been developed to produce the LNG at pressure letdown stations. The utility of the small scale LNG plants, however, may often be limited to pressure letdown stations having a relatively high pressure natural gas source. Further, the variability in the properties (e.g., temperature, pressure, purity, etc.) of the natural gas available at each of the pressure letdown stations may make the designing, engineering, and manufacturing of the small scale LNG plants cost-prohibitive and/or impractical.
What is needed, then, is a system and method for producing liquefied natural gas from a wide variety of natural gas sources.
Embodiments of the disclosure may provide a method for producing liquefied natural gas from a natural gas source. The method may include feeding natural gas provided by the natural gas source to a liquefaction module. The method may also include flowing the natural gas through a product stream of the liquefaction module. The method may further include flowing a process fluid through a liquefaction stream of the liquefaction module to cool at least a portion of the natural gas flowing through the product stream to produce the liquefied natural gas.
Embodiments of the disclosure may also provide another method for producing liquefied natural gas from a natural gas source. The method may include compressing natural gas provided from the natural gas source in a precompression module. The method may also include removing at least a portion of a non-hydrocarbon from the natural gas in a conditioning module fluidly coupled with the precompression module. The method may further include feeding the natural gas from the conditioning module to a liquefaction module, and flowing the natural gas through a product stream of the liquefaction module. The method may also include flowing a process fluid through a liquefaction stream of the liquefaction module to cool at least a portion of the natural gas flowing through the product stream to produce the liquefied natural gas.
Embodiments of the disclosure may further provide a system for producing liquefied natural gas from a natural gas source. The system may include a liquefaction module, a precompression module, a conditioning module, a power generation module, and a storage tank. The liquefaction module may be configured to receive compressed natural gas at a predetermined pressure and cool at least a portion of the compressed natural gas to the liquefied natural gas. The precompression module may be configured to receive natural gas from the natural gas source and compress the natural gas to the predetermined pressure of the liquefaction module. The conditioning module may be fluidly coupled with the precompression module and the liquefaction module, and configured to receive the compressed natural gas from the precompression module, remove at least a portion of a non-hydrocarbon from the compressed natural gas, and feed the compressed natural gas to the liquefaction module. The power generation module may be operably coupled with the liquefaction module and fluidly coupled with the conditioning module. The power generation module may be configured to receive and combust at least a portion of the non-hydrocarbon from the conditioning module to generate electrical energy, and delivery the electrical energy to the liquefaction module. The storage tank may be fluidly coupled with the liquefaction module and configured to receive and store the liquefied natural gas from the liquefaction module.
Embodiments of the disclosure may further provide another system for producing liquefied natural gas from a natural gas source. The system may include a liquefaction module, a precompression module, a conditioning module, a power generation module, and a storage tank. The liquefaction module may be configured to receive compressed natural gas at a predetermined pressure and cool at least a portion of the compressed natural gas to the liquefied natural gas. The precompression module may be configured to receive natural gas from the natural gas source and compress the natural gas to the predetermined pressure of the liquefaction module. The conditioning module may be fluidly coupled with the precompression module and the liquefaction module, and configured to receive the compressed natural gas from the precompression module, remove at least a portion of a non-hydrocarbon from the compressed natural gas, and feed the compressed natural gas to the liquefaction module. The power generation module may be operably coupled with the liquefaction module and fluidly coupled with the conditioning module. The power generation module may be configured to receive and combust at least a portion of the non-hydrocarbon from the conditioning module to generate electrical energy, and delivery the electrical energy to the liquefaction module. The storage tank may be fluidly coupled with the liquefaction module and configured to receive and store the liquefied natural gas from the liquefaction module. The liquefaction module may include a first heat exchanger fluidly coupled with and disposed downstream from an inlet of the liquefaction module and configured to receive and cool the compressed natural gas therefrom. The liquefaction module may also include a first expansion valve fluidly coupled with and disposed downstream from the first heat exchanger. The first expansion valve may be configured to expand a first portion of the cooled compressed natural gas from the first heat exchanger. The liquefaction module may further include a second heat exchanger fluidly coupled with and disposed downstream from the first heat exchanger via a first line and via a first line, and further disposed downstream from the first expansion valve via a second line. The second heat exchanger may be configured to receive and cool a second portion of the cooled compressed natural gas from the first heat exchanger with the expanded first portion of the cooled compressed natural gas from the first expansion valve. The liquefaction module may also include a second expansion valve fluidly coupled with and disposed downstream from the second heat exchanger, and a liquid separator fluidly coupled with and disposed downstream from the second expansion valve. The second expansion valve may be configured to expand the second portion of the cooled compressed natural gas from the second heat exchanger to produce a two-phase fluid including the liquefied natural gas and a vapor phase. The liquid separator may be configured to separate the liquefied natural gas from the vapor phase.
The present disclosure is best understood from the following detailed description when read with the accompanying Figures. It is emphasized that, in accordance with the standard practice in the industry, various features are not drawn to scale. In fact, the dimensions of the various features may be arbitrarily increased or reduced for clarity of discussion.
It is to be understood that the following disclosure describes several exemplary embodiments for implementing different features, structures, or functions of the invention. Exemplary embodiments of components, arrangements, and configurations are described below to simplify the present disclosure; however, these exemplary embodiments are provided merely as examples and are not intended to limit the scope of the invention. Additionally, the present disclosure may repeat reference numerals and/or letters in the various exemplary embodiments and across the Figures provided herein. This repetition is for the purpose of simplicity and clarity and does not in itself dictate a relationship between the various exemplary embodiments and/or configurations discussed in the various Figures. Moreover, the formation of a first feature over or on a second feature in the description that follows may include embodiments in which the first and second features are formed in direct contact, and may also include embodiments in which additional features may be formed interposing the first and second features, such that the first and second features may not be in direct contact. Finally, the exemplary embodiments presented below may be combined in any combination of ways, i.e., any element from one exemplary embodiment may be used in any other exemplary embodiment, without departing from the scope of the disclosure.
Additionally, certain terms are used throughout the following description and claims to refer to particular components. As one skilled in the art will appreciate, various entities may refer to the same component by different names, and as such, the naming convention for the elements described herein is not intended to limit the scope of the invention, unless otherwise specifically defined herein. Further, the naming convention used herein is not intended to distinguish between components that differ in name but not function. Further, in the following discussion and in the claims, the terms “including” and “comprising” are used in an open-ended fashion, and thus should be interpreted to mean “including, but not limited to.” All numerical values in this disclosure may be exact or approximate values unless otherwise specifically stated. Accordingly, various embodiments of the disclosure may deviate from the numbers, values, and ranges disclosed herein without departing from the intended scope. Furthermore, as it is used in the claims or specification, the term “or” is intended to encompass both exclusive and inclusive cases, i.e., “A or B” is intended to be synonymous with “at least one of A and B,” unless otherwise expressly specified herein.
The natural gas source 102 may be or include a natural gas pipeline, a stranded natural gas wellhead, or the like, or any combination thereof. The natural gas source 102 may contain natural gas at ambient temperature. The natural gas source 102 may also contain natural gas at a relatively high pressure (e.g., about 3,400 kPa to about 8,400 kPa or greater) or a relatively low pressure (e.g., about 100 kPa to about 3,400 kPa). For example, the natural gas source 102 may be a high pressure natural gas pipeline containing natural gas at a pressure from about 3,400 kPa, about 3,900 kPa, about 4,400 kPa, about 4,900 kPa, or about 5,400 kPa to about 5,900 kPa, about 6,400 kPa, about 6,900 kPa, about 7,400 kPa, about 7,900 kPa, about 8,400 kPa, or greater. In another example, the natural gas source 102 may be a low pressure natural gas pipeline containing natural gas at a pressure from about 100 kPa, about 150 kPa, about 300 kPa, about 400 kPa, or about 500 kPa to about 1,000 kPa, about 1,500 kPa, about 2,000 kPa, about 2,500 kPa, about 3,000 kPa, or about 3,500 kPa.
The natural gas from the natural gas source 102 may include one or more hydrocarbons. For example, the natural gas may include methane, ethane, propane, butanes, pentanes, or the like, or any combination thereof. Methane may be a major component of the natural gas. For example, the concentration of methane in the natural gas may be greater than about 80%, greater than about 85%, greater than about 90%, or greater than about 95%. The natural gas may also include one or more non-hydrocarbons. For example, the natural gas may be or include a mixture of one or more hydrocarbons and one or more non-hydrocarbons. Illustrative non-hydrocarbons may include, but are not limited to, water, carbon dioxide, hydrogen sulfide, helium, nitrogen, or the like, or any combination thereof.
The storage tank 106 may be configured to receive and store the LNG produced in the system 100. For example, as illustrated in
The liquefaction module 104 may include a cooling assembly 112, one or more heat exchangers (two are shown 114, 116), a compression assembly 118, one or more liquid separators (two are shown 120, 122), a turbo-expander 124, an expansion valve 126, or any combination thereof, fluidly, communicably, and/or operatively coupled with one another. For example, as illustrated in
The cooling assembly 112 may include one or more heat exchangers or pre-cooling heat exchangers (one is shown 128) and one or more chillers (one is shown 130) thermally, operatively, and/or fluidly coupled with one another. For example, as illustrated in
In at least one embodiment, the chiller 130 may be or include a vapor absorption chiller or non-mechanical chiller configured to receive and be driven by heat (e.g., waste heat, solar heat, etc.). Illustrative non-mechanical chillers may include, but are not limited to, ammonia absorption chillers, lithium bromide absorption chillers, and the like. In another embodiment, the chiller 130 may be a vapor compression chiller or mechanical chiller configured to receive and be driven by electrical energy. For example, the chiller 130 may be a mechanical chiller operatively coupled with a power generation system 202 (see
The first and second heat exchangers 114, 116 may be fluidly coupled with and disposed downstream from the pre-cooling heat exchanger 128 of the cooling assembly 112. Each of the first and second heat exchangers 114, 116 may be configured to receive a process fluid from the pre-cooling heat exchanger 128 and cool or remove at least a portion of the heat from the process fluid. The first and second heat exchangers 114, 116 may be or include any device capable of at least partially cooling or reducing the temperature of the process fluid flowing therethrough. Illustrative heat exchangers may include, but are not limited to, a direct contact heat exchanger, a cooler, a trim cooler, a mechanical refrigeration unit, a welded plate heat exchanger, or the like, or any combination thereof.
As illustrated in
The second heat exchanger 116 may be fluidly coupled with and disposed upstream of a first liquid separator 120 and the turbo-expander 124 via line 174 and line 176, respectively. The second heat exchanger 116 may be configured to receive the cooled process fluid from the pre-cooling heat exchanger 128, further cool the cooled process fluid, and direct the further cooled process fluid to the first liquid separator 120. For example, the second heat exchanger 116 may receive the refrigeration stream from the first heat exchanger 114 via line 170, transfer heat from the cooled process fluid to the refrigeration stream to further cool the cooled process fluid, and direct the further cooled process fluid to the first liquid separator 120 via line 174. As further described herein, the heated or “spent” refrigeration stream from the second heat exchanger 116 may be directed to the turbo-expander 124 via line 176 and subsequently compressed therein.
The expansion valve 126 may be fluidly coupled with and disposed upstream of a second liquid separator 122 via line 190. The expansion valve 126 may be configured to receive the process fluid from the first heat exchanger 114 and expand the process fluid to thereby decrease a temperature and pressure thereof. As further described herein, the expansion of the process fluid through the expansion valve 126 may flash the process fluid into a two-phase fluid including a gaseous or vapor phase and a liquid phase (e.g., the LNG). In an exemplary embodiment, the expansion valve 126 may be a Joule-Thomson (JT) valve.
As illustrated in
The turbo-expander 124 of the core-module 104 may include a turbine 132 and a compressor 134 operably coupled with one another. For example, as illustrated in
The compressor 134 of the turbo-expander 124 may be fluidly coupled with and disposed downstream from the second heat exchanger 116 via line 176. The compressor 134 may be configured to utilize the mechanical energy from the turbine 132 to compress the process fluid flowing therethrough. For example, the compressor 134 may be configured to receive and compress a process fluid containing the heated or “spent” refrigeration stream from the second heat exchanger 116. The compression of the process fluid through the compressor 134 may reduce the amount of energy utilized to compress the process fluid in the compression assembly 118. For example, the compressor 134 may be fluidly coupled with and disposed upstream from the compression assembly 118 via line 182 and configured to deliver the compressed process fluid thereto.
The compression assembly 118 may include one or more compressors (one is shown 136) configured to compress and/or pressurize the process fluid directed thereto. Illustrative compressors may include, but are not limited to, supersonic compressors, centrifugal compressors, axial flow compressors, reciprocating compressors, rotating screw compressors, rotary vane compressors, scroll compressors, diaphragm compressors, or the like, or any combination thereof. The compressor 136 may include one or more compressor stages (two are shown 138, 140) and a driver 142 operatively coupled with and configured to drive the compressor stages 138, 140. For example, as illustrated in
As illustrated in
In at least one embodiment, a heat transfer medium may flow through each of the coolers 144, 146 to absorb the heat in the process fluid flowing therethrough. Accordingly, the heat transfer medium may have a higher temperature when it exits the coolers 144, 146 and the process fluid may have a lower temperature when it exits the coolers 144, 146. The heat transfer medium may be or include water, steam, a refrigerant, a process gas, such as carbon dioxide, air, propane, or natural gas, or the like, or any combination thereof. In an exemplary embodiment, the heat transfer medium may be or include a refrigerant from the chiller 130 of the cooling assembly 112. The heat transfer medium from the coolers 144, 146 may provide supplemental heating to one or more portions and/or assemblies of the system 100. For example, the heat transfer medium containing the heat absorbed from the coolers 144, 146 may provide supplemental heating to a heat recovery unit (HRU) (not shown).
In an exemplary operation, the liquefaction module 104 may be configured to receive a process fluid containing the natural gas in the gaseous phase at the inlet 108 thereof, direct or flow the process fluid containing the natural gas in the gaseous phase through a product stream to cool at least a portion of the natural gas in the process fluid to the LNG, and discharge or output the process fluid containing the LNG through the outlet 110 thereof. The liquefaction module 104 may be configured to receive the process fluid at the inlet 108 thereof at a predetermined inlet pressure. For example, the liquefaction module 104 may be configured to receive the process fluid at the inlet 108 thereof at a pressure of about 1,000 kPa to about 8,400 kPa. As further described herein, the inlet pressure and/or flow of the process fluid through the product stream may at least partially determine the amount of the LNG produced in the system 100. The liquefaction module 104 may also be configured to circulate or flow a process fluid containing natural gas through a liquefaction stream to cool at least a portion of the process fluid flowing through the product stream. As further described herein, the flow of the process fluid through one or more portions of the liquefaction stream may at least partially determine an amount or degree of cooling provided to the process fluid flowing through the product stream.
In the liquefaction stream, the process fluid containing the natural gas may be directed to the compression assembly 118 and subsequently compressed therein. For example, the process fluid may be directed to the first compressor stage 138 of the compressor 136 via line 182. The first compressor stage 138 may receive and compress the process fluid from line 182 and direct the compressed process fluid to the first cooler 144 via line 184. Compressing the recycle stream in the first compressor stage 138 may generate heat (e.g., the heat of compression) to thereby increase the temperature of the process fluid. Accordingly, the first cooler 144 may cool or remove at least a portion of the heat (e.g., the heat of compression) contained therein. The cooled process fluid from the first cooler 144 may be directed to the second compressor stage 140 via line 186. The second compressor stage 140 may compress the process fluid from the first cooler 144 and direct the compressed process fluid to the second cooler 146 via line 188. The second cooler 146 may cool the process fluid and direct the cooled process fluid to the pre-cooling heat exchanger 128 of the cooling assembly 112 via line 154.
The pre-cooling heat exchanger 128 may further cool the process fluid from the second cooler 146 and direct the further cooled process fluid to the second heat exchanger 116 via line 160. As previously discussed, the pre-cooling heat exchanger 128 may be configured to receive the refrigerant from the chiller 130 via the cooling line 162 and transfer heat from the process fluid flowing therethrough to the refrigerant to cool the process fluid and/or the natural gas contained therein. The second heat exchanger 116 may further cool the process fluid from the pre-cooling heat exchanger 128 and direct the process fluid to the first liquid separator 120 via line 174. The pre-cooling heat exchanger 128 and/or the second heat exchanger 116 may cool at least a portion of the natural gas contained in the process fluid to a liquid phase (e.g., natural gas liquids and/or the LNG). For example, as previously discussed, the natural gas in the process fluid may include a mixture of one or more hydrocarbons (e.g., methane, ethane, propane, butanes, pentanes, etc.), and the hydrocarbons having a relatively high molecular weight (e.g., ethane, propane, etc.) may be compressed, cooled, and/or otherwise condensed to the liquid phase before the hydrocarbons having a relatively low molecular weight (e.g., methane). The condensation of the hydrocarbons having the relatively high molecular weight may produce natural gas liquids (NGLs). The terms “natural gas liquids” or “NGLs” may refer to a liquid phase containing hydrocarbons having a relatively higher boiling point and/or a relatively lower vapor pressure than methane. The terms “natural gas liquids” or “NGLs” may also refer to a liquid phase containing hydrocarbons having a relatively higher molecular weight than methane.
The first liquid separator 120 may receive the process fluid from the second heat exchanger 116 via line 174, and remove or separate at least a portion of the NGLs from the process fluid to thereby provide a relatively drier process fluid. The NGLs separated from the process fluid may be directed to and stored in a storage tank (not shown) fluidly coupled with the first liquid separator 120 via line 194. The NGLs may be stored in the storage tank at a pressure and/or temperature equal or substantially equal to a pressure and/or temperature of the first liquid separator 120. Accordingly, a pump (not shown) may be fluidly coupled between the first liquid separator 120 and the storage tank and configured to transfer or pump the NGLs from the first liquid separator 120 to the storage tank.
The relatively drier process fluid from the first liquid separator 120 may be directed to the turbine 132 of the turbo-expander 124 via line 178. The turbine 132 may expand the process fluid from the first liquid separator 120 to decrease the temperature and pressure of the process fluid and thereby generate the refrigeration stream in line 168. The turbine 132 may have any expansion ratio. In an exemplary embodiment, the turbine 132 may have an expansion ratio of about 10:1. For example, the process fluid expanded through the turbine 132 may be subjected to a pressure reduction of about 10:1. The refrigeration stream from the turbine 132 may be directed to the first heat exchanger 114 via line 168 to absorb the heat from the process fluid flowing therethrough from line 158 to line 172.
In an exemplary embodiment, the refrigeration stream from the first heat exchanger 114 may provide additional cooling to one or more of the remaining heat exchangers of the system 100. For example, as illustrated in
The compressor 134 of the turbo-expander 124 may be configured to receive the refrigeration stream from the second heat exchanger 116, compress the refrigeration stream, and direct the compressed refrigeration stream to the compression assembly 118 as a recycle stream via line 182. In an exemplary embodiment, the compressor 134 may be configured to compress the refrigeration stream to a selected inlet pressure of one or more of the compressor stages 138, 140 of the compression assembly 118. For example, the compressor 134 may be configured to compress the refrigeration stream such that the recycle stream in line 182 may have a pressure equal or substantially equal to the selected inlet pressure of the first compressor stage 138. The selected inlet pressure of the compressor stages 138, 140 may be determined by one or more operating parameters of the liquefaction module 104 and/or the components and assemblies thereof. The first compressor stage 138 may receive the recycle stream from line 182 and direct the recycle stream through the liquefaction stream, as described above.
As previously discussed, the liquefaction module 104 may be configured to receive a process fluid containing the natural gas in the gaseous phase at the inlet 108 thereof, and direct or flow the process fluid containing the natural gas through the product stream to cool at least a portion of the natural gas in the process fluid to the LNG. In the product stream, the process fluid containing the natural gas in the gaseous phase may be directed from the inlet 108 to the pre-cooling heat exchanger 128 via line 156. The pre-cooling heat exchanger 128 may cool the process fluid from the inlet 108 and direct the cooled process fluid to the first heat exchanger 114 via line 158. As previously discussed, the pre-cooling heat exchanger 128 may receive the refrigerant from the chiller 130 via the cooling line 162 and transfer heat from the process fluid flowing therethrough to the refrigerant to cool the process fluid and the natural gas contained therein. The first heat exchanger 114 may further cool the process fluid from the pre-cooling heat exchanger 128 and direct the cooled process fluid to the expansion valve 126 via line 172. The refrigeration stream from the turbine 132 may be directed to the first heat exchanger 114 via line 168 to cool the process fluid flowing therethrough from line 158 to line 172.
The expansion valve 126 may receive the process fluid from the first heat exchanger 114 via line 172, expand the process fluid, and output the expanded process fluid to line 190. The expansion of the process fluid through the expansion valve 126 may decrease the temperature and pressure of the process fluid in line 190. The expansion valve 126 may decrease the process fluid to any pressure. For example, the expansion valve 126 may decrease the process fluid to a designed storage pressure of the storage tank 106. The expansion of the process fluid through the expansion valve 126 may also flash the process fluid into a two-phase fluid including a gaseous or vapor phase and a liquid phase. For example, the expansion of the process fluid through the expansion valve 126 may flash the process fluid into the two-phase fluid including the vapor phase and the liquid phase, or the LNG. In an exemplary embodiment, about 15% of the two-phase fluid in the process fluid may be in the vapor phase and about 85% of the two-phase fluid may be the LNG. The second liquid separator 122 may receive the two-phase fluid from line 190 and separate at least a portion of the LNG from the vapor phase. The LNG separated in the second liquid separator 122 may then be directed to the storage tank 106 via the outlet 110. For example, as illustrated in
As illustrated in
The conditioning module 208 may be fluidly coupled with and disposed downstream from the precompression module 206 via line 234. The conditioning module 208 may also be fluidly coupled with and disposed upstream of the liquefaction module 104 and the power generation module 202 via line 236 and line 238, respectively. The conditioning module 208 may be configured to at least partially separate or remove one or more non-hydrocarbons from the natural gas contained in the process fluid flowing therethrough. For example, as previously discussed, the natural gas from the natural gas source 102 may be or include a mixture of one or more hydrocarbons (e.g., methane, ethane, etc.) and one or more non-hydrocarbons (e.g., water, carbon dioxide, hydrogen sulfide, etc.), and the conditioning module 208 may be configured to at least partially separate the non-hydrocarbons from the hydrocarbons.
The conditioning module 208 may include a separator 216 fluidly coupled with and disposed downstream from the precompression module 206 and/or the cooler 214 thereof, and configured to remove water and/or carbon dioxide from the natural gas in the process fluid flowing therethrough. The separator 216 may include or contain one or more adsorbents configured to separate the non-hydrocarbons. The adsorbents may include, but are not limited to, one or more molecular sieves, zeolites, metal-organic frameworks, or the like, or any combination thereof. The adsorbent, such as the molecular sieve, may be activated at varying temperatures and/or pressures. The adsorbent may have an adsorptive capacity determined by an amount of an adsorbate or the non-hydrocarbons separated by the adsorbent under predetermined conditions (e.g., temperature and/or pressure). In an exemplary embodiment, the separator 216 and/or the adsorbent contained therein may be configured to separate the non-hydrocarbons from the process fluid at a predetermined separation pressure and/or a predetermined separation temperature. For example, the separator 216 and/or the adsorbent may be configured to separate the non-hydrocarbons at a relatively high pressure (e.g., about 3,400 kPa to about 8,400 kPa or greater) or a relatively low pressure (e.g., about 1,000 kPa to about 3,400 kPa). In another example, the separator 216 and/or the adsorbent may be configured to separate the non-hydrocarbons from the process fluid at ambient temperature or at a temperature of about 10° C. to about 55° C. or greater.
As illustrated in
The power generation system 202 may include an internal combustion engine 218 and a generator 220 operatively coupled with the internal combustion engine 218. In at least one embodiment, the internal combustion engine 218 may be fluidly coupled with the natural gas source 102 and configured to receive and combust at least a portion of the natural gas from the natural gas source 102 to generate mechanical energy. In another embodiment, the internal combustion engine 218 may be fluidly coupled with another component or assembly of the system 200 and configured to receive and combust the natural gas therefrom to generate mechanical energy. For example, as illustrated in
The control module 204 may be operatively coupled with one or more components, modules, systems, and/or assemblies of the system 200, and configured to monitor and/or control the components, modules, systems, and/or assemblies. For example, the control module 204 may include a controller 222 operatively and/or communicably coupled (e.g., wired or wirelessly) with the flash recovery module 210, the power generation module 202, the precompression module 206, the conditioning module 208, the liquefaction module 104, and/or components thereof. In an exemplary embodiment, the controller 222 may be configured to control a flow of the process fluid through the system 200 and/or one or more components thereof. For example, the controller 222 may be configured to control the inlet pressure and/or flow of the process fluid through one or more portions of the liquefaction module 104. In another example, the controller 222 may be configured to control the inlet pressure and/or flow of the process fluid through the liquefaction stream and/or the product stream of the liquefaction module 104.
The flash recovery module 210 may be fluidly coupled with and disposed downstream from the conditioning module 216 via line 244. The flash recovery module 210 may also be fluidly coupled with and disposed upstream of the liquefaction module 104 via line 248. The flash recovery module 210 may include one or more heat exchangers (one is shown 224) configured to receive and cool the natural gas in the process fluid flowing therethrough. For example, the heat exchanger 224 may be configured to receive and cool the natural gas contained in the process fluid from the conditioning module 208. As further described herein, the flash recovery module 210 and/or the heat exchanger 224 thereof may be configured to recover energy or work utilized to cool the natural gas to the LNG to thereby increase the efficiency of the system 200.
As illustrated in
In an exemplary operation of the system 200, the precompression module 206 may be configured to receive a process fluid containing the natural gas in the gaseous phase and compress the process fluid to the designed inlet pressure of the liquefaction module 104. For example, as previously discussed with reference to
The compressed process fluid from the compressor 212 may be directed to the cooler 214 via line 246 and subsequently cooled therein. The cooler 214 may absorb at least a portion of the heat in the compressed process fluid and direct the cooled process fluid to the conditioning module 218 via line 234. In at least one embodiment, the cooler 214 may be configured to receive a heat transfer medium (e.g., water, steam, a refrigerant, a process gas, etc.) to absorb the heat in the process fluid flowing therethrough. For example, the heat transfer medium may be or include a refrigerant from the chiller 130. In another example, the heat transfer medium may be or include the vapor phase from the second liquid separator 122.
The process fluid from the precompression module 206 may then be directed to the conditioning module 208 via line 234. The separator 216 of the conditioning module 208 may remove at least a portion of the non-hydrocarbons from the natural gas contained in the process fluid to increase the concentration of the hydrocarbons in the process fluid. For example, the non-hydrocarbons in the process fluid flowing through the separator 216 may be adsorbed into the adsorbent contained in the separator 216. Removing the non-hydrocarbons, such as water and/or carbon dioxide, from the process fluid may prevent the natural gas in the process fluid from subsequently crystallizing (e.g., freezing) in one or more portions and/or downstream processes of the system 200. For example, the liquefaction module 104 may cool the process fluid to or below a freezing point of one or more of the non-hydrocarbons (e.g., water and/or carbon dioxide). Accordingly, removing water and/or carbon dioxide from the natural gas contained in the process fluid may prevent the subsequent freezing or crystallization of the process fluid in the liquefaction module 104.
The non-hydrocarbons adsorbed to the adsorbent may be desorbed from the adsorbent by directing or flowing a purge gas through the separator 216 to thereby regenerate the separator 216 and/or the adsorbent. As the purge gas flows through the separator 216, the non-hydrocarbons may desorb from the adsorbent and combine with the purge gas, thereby producing a regeneration gas including a mixture of the purge gas and the non-hydrocarbons. In an exemplary embodiment, the regeneration gas may contain a mixture of the purge gas, carbon dioxide, and/or water. The regeneration gas may be utilized as fuel for one or more processes or components of the system 200. For example, as illustrated in
As illustrated in
The process fluid from the cooling assembly 112 may then be directed to the first heat exchanger 114 via line 158. The first heat exchanger 114 may further cool the process fluid from the cooling assembly 112 and direct the cooled process fluid to the expansion valve 126 via line 172. The expansion valve 126 may receive the process fluid from the first heat exchanger 114 via line 172 and expand the process fluid to line 190. The expansion of the process fluid through the expansion valve 126 may flash the process fluid into a two-phase fluid including a vapor phase (e.g., flash gas) and a liquid phase or the LNG. The two-phase fluid may be directed to the second liquid separator 122 where the LNG and the vapor phase may be separated from one another. The LNG separated in the second liquid separator 122 may then be directed to the storage tank 106 via the outlet 110. The vapor phase separated in the second liquid separator 112 may be discharged from the outlet 148 of the liquefaction module 104 via line 192.
In at least one embodiment, the vapor phase from the second liquid separator 122 may be combined with the process fluid flowing through one or more portions of the core-module 104. For example, the vapor phase from the second liquid separator 122 may be combined with the process fluid flowing through the liquefaction stream and/or the product stream. In another embodiment, the vapor phase from the second liquid separator 122 may be directed to one or more of the heat exchangers and/or coolers of the system 200. For example, the vapor phase may be directed to one or more of the coolers 144, 146 of the compression assembly 118 to cool the process fluid flowing therethrough.
In yet another embodiment, the vapor phase discharged from the outlet 148 of the liquefaction module 104 may be directed to one or more of the modules 202, 204, 206, 208, 210 of the system 200 via line 258. For example, as illustrated in
The cooled process fluid from the flash recovery module 210 may be directed to any portion of the liquefaction module 104. For example, the cooled process fluid from the flash recovery module 210 may be combined with the process fluid flowing through the liquefaction stream and/or the product stream. In an exemplary embodiment, the cooled process fluid from the flash recovery module 210 may be directed to the liquefaction module 104 downstream the first heat exchanger 114. For example, as illustrated in
The heated or “spent” vapor phase from the heat exchanger 224 of the flash recovery module 210 may be directed to any portion or module of the system 200 including the liquefaction module 104, the power generation module 202, the precompression module 206, the conditioning module 208, or any combination thereof. For example, the vapor phase from the flash recovery module 210 may be combined with the process fluid flowing through the liquefaction stream and or the product stream of the liquefaction module 104. In another example, the vapor phase from the flash recovery module 210 may be directed to one or more of the heat exchangers and/or coolers of the system 200. In yet another example, illustrated in
In an exemplary operation, the liquefaction module 104 may be configured to receive a process fluid containing the natural gas in the gaseous phase at the inlet 108 thereof, direct or flow the process fluid containing the natural gas in the gaseous phase through the product stream to cool at least a portion of the natural gas in the process fluid to the LNG, and discharge the process fluid containing the LNG through the outlet 110 thereof. The liquefaction module 104 may also be configured to circulate a process fluid containing natural gas through a liquefaction stream to cool at least a portion of the process fluid flowing through the product stream.
In the product stream illustrated in
In the liquefaction stream, the process fluid containing the natural gas may be directed to the compression assembly 118 and subsequently compressed therein. In an exemplary embodiment, the compression assembly 118 may compress the process fluid to a pressure of at least about 7,000 kPa. For example, the compression assembly 118 may compress the process fluid to a pressure from about 7,000 kPa, about 7,300 kPa, about 7,600 kPa, about 7,900 kPa, or about 8,200 kPa to about 8,500 kPa, about 8,800 kPa, about 9,100 kPa, about 9,400 kPa, about 9,700 kPa, about 10,000 kPa, or greater. In another example, the compression assembly 118 may compress the process fluid to a pressure from about 7,000 kPa to about 10,000 kPa, from about 7,300 kPa to about 9,700 kPa, from about 7,600 kPa to about 9,400 kPa, from about 7,900 kPa to about 9,100 kPa, or from about 8,200 kPa to about 8,500 kPa.
The compressed process fluid from the compression assembly 118 may be directed to the pre-cooling heat exchanger 230 of the cooling assembly 112 via line 154 and subsequently cooled therein. In at least one embodiment, the cooled process fluid in the liquefaction stream may flow directly from the pre-cooling heat exchanger 230 of the cooling assembly 112 to the turbine 132 of the turbo-expander 124. In another embodiment, illustrated in
The first liquid separator 120 may receive the process fluid from the cooling assembly 112 and remove or separate at least a portion of the NGLs from the process fluid to thereby provide a relatively drier process fluid. The relatively drier process fluid from the first liquid separator 120 may be expanded through the turbine 132 to decrease the temperature and pressure thereof and thereby generate the refrigeration stream in line 168. The refrigeration stream in line 168 may have a temperature of about −50° C., about −75° C., about −100° C., about −125° C., or lower. For example, the temperature of the refrigeration stream in line 168 may be less than about −50° C., less than about −75° C., less than about −85° C., less than about −95° C., less than about −100° C., less than about −105° C., less than about −110° C., less than about −115° C., less than about −120° C., less than about −125° C., less than about −130° C., or less than about −140° C. The refrigeration stream in line 168 may have a pressure less than about 2,200 kPa, less than about 2,000 kPa, less than about 1,800 kPa, less than about 1,500 kPa, less than about 1,200 kPa, less than about 1,000 kPa, less than about 900 kPa, less than about 800 kPa, less than about 700 kPa, or less than about 600 kPa. The refrigeration stream from the turbine 132 may be directed to the first heat exchanger 114 via line 168 to absorb the heat from the process fluid flowing through the product stream from line 302 to line 172.
In the system 300 illustrated in
As further illustrated in
As illustrated in
As illustrated in
In an exemplary operation, with continued reference to
In the product stream illustrated in
The inlet pressure and/or flow of the process fluid through the product stream of the systems 100, 200, 300, 400 illustrated in
The pressure and/or the flow of the process fluid through one or more portions of the liquefaction stream may also determine, at least in part, the amount of the LNG produced in each of the systems 100, 200, 300, 400. For example, the pressure and/or the flow of the process fluid through one or more portions of the liquefaction stream may at least partially determine the amount or degree of cooling provided to the process fluid flowing through the product stream. In at least one embodiment, increasing the pressure and/or the flow of the process fluid through the liquefaction stream may correspondingly increase the cooling provided to the process fluid flowing through the product stream. For example, increasing the pressure and/or the flow of the process fluid to the turbine 132 of the turbo-expander 124 may increase refrigeration. In another example, increasing the pressure of the process fluid may increase volumetric or volume flow through the turbine 132. In yet another example, increasing the pressure and/or the flow of the process fluid to the turbine 132 of the turbo-expander 124 may decrease the temperature of the refrigeration stream directed to the first heat exchanger 114 and thereby increase the cooling or refrigeration provided to the process fluid flowing through the product stream.
The foregoing has outlined features of several embodiments so that those skilled in the art may better understand the present disclosure. Those skilled in the art should appreciate that they may readily use the present disclosure as a basis for designing or modifying other processes and structures for carrying out the same purposes and/or achieving the same advantages of the embodiments introduced herein. Those skilled in the art should also realize that such equivalent constructions do not depart from the spirit and scope of the present disclosure, and that they may make various changes, substitutions, and alterations herein without departing from the spirit and scope of the present disclosure. Additionally, all numerical values are “about” or “approximately” the indicated value, and take into account experimental error and variations that would be expected by a person having ordinary skill in the art. It should be appreciated that all numerical values and ranges disclosed herein are approximate valves and ranges, whether “about” is used in conjunction therewith. It should also be appreciated that the term “about,” as used herein, in conjunction with a numeral refers to a value that may be +/−1% (inclusive) of that numeral, +/−2% (inclusive) of that numeral, +/−3% (inclusive) of that numeral, +/−5% (inclusive) of that numeral, +/−10% (inclusive) of that numeral, or +/−15% (inclusive) of that numeral. It should further be appreciated that when a numerical range is disclosed herein, any numerical value falling within the range is also specifically disclosed.
This application claims the benefit of U.S. Provisional Patent Application having Ser. No. 62/081,799, which was filed Nov. 19, 2014 and of U.S. Provisional Patent Application having Ser. No. 62/246,171, which was filed Oct. 26, 2015. The aforementioned patent applications are hereby incorporated by reference in their entirety into the present application to the extent consistent with the present application.
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