Patent Application
20220252341
Reduction of carbon dioxide (“CO2”) emissions is becoming an increasingly desirable improvement for industrial processes, including the fields of hydrocarbon processing and electrical power generation.
The liquefaction of natural gas is a process having significant power requirements, primarily to drive the compressors necessary to support the liquefaction process. Efforts have been made to reduce the carbon “footprint” of natural gas liquefaction by reducing CO2 emissions by improving the efficiency of the liquefying process. For natural gas liquefaction plants (also referred to herein as “LNG plants”) using gas turbines to drive refrigerant compressors, further reductions in CO2 emissions by efficiency improvement can be achieved by recovering heat from high temperature flue gas and using it beneficially. This heat may be recovered by generating steam and using a combined cycle to generate further power. Some LNG plants obtain the refrigeration compression power via electricity from the grid. Power plants supplying electricity can employ gas turbines with heat recovery steam generation systems for additional power and efficiency.
Some power plants have reduced CO2 emissions by using hydrogen as a fuel gas or fuel gas additive. The overall CO2 emissions are reduced if this hydrogen is made using green energy such as solar power or with a process that involves a natural gas feed and CO2 capture. Such processes for converting natural gas into hydrogen include the steam methane reforming process in which the CO2 is removed from the syngas and/or flue gas. Optionally, this low-carbon intensity hydrogen can be made via autothermal reforming or partial oxidation processes or gasification processes in which the CO2 is removed from the effluent syngas.
Such improvements often result in substantially higher energy costs and require energy sources that are external to the natural gas liquefaction process. Accordingly, there is a need for a more efficient and self-contained means of reducing CO2 emissions attributable the natural gas liquefaction process and the power necessary to drive the process.
This Summary is provided to introduce a selection of concepts in a simplified form that are further described below in the Detailed Description. This Summary is not intended to identify key features or essential features of the claimed subject matter, nor is it intended to be used to limit the scope of the claimed subject matter.
Several aspects of the systems and methods are outlined below.
Aspect 1—A method comprising:
Aspect 2—The method of Aspect 1, wherein the flash vapor stream is at least 50 mol % methane.
Aspect 3—The method of any of Aspects 1 through 2, wherein the hydrogen containing stream is at least 80 mol % hydrogen.
Aspect 4—The method of any of Aspects 1 through 3, further comprising:
Aspect 5—The method of Aspect 4, further comprising:
Aspect 6—The method of any of Aspects 1 through 5, wherein step (d) further comprises reacting at least a portion of the flash vapor stream and an ambient air stream in the hydrogen production system to form the hydrogen containing stream and the first CO2-enriched stream.
Aspect 7—The method of any of Aspects 1 through 6, wherein step (d) further comprises reacting at least a portion of the flash vapor stream and an oxygen containing stream in the hydrogen production system to form the hydrogen containing stream, the first CO2-enriched stream, a first steam stream, and a waste nitrogen stream.
Aspect 8—The method of Aspect 7, wherein the oxygen containing stream is ambient air.
Aspect 9—The method of Aspect 7, further comprising:
Aspect 10—The method of Aspect 9, wherein step (e) further comprises generating power in a power generating system using the hydrogen containing stream and at least a portion of the nitrogen enriched stream.
Aspect 11—The method of any of Aspects 1 through 10, wherein step (e) further comprises generating power in a power generating system using the hydrogen containing stream and at least one steam stream from the hydrogen production system or power generating system.
Aspect 12—The method of any of Aspects 1 through 11, wherein step (e) further comprises generating power in a power generating system using the hydrogen containing stream to drive at least one gas turbine and a first steam stream to drive at least one steam turbine.
Aspect 13—The method of any of Aspects 1 through 12, wherein the power generated in step (e) comprises electrical power and step (f) comprises providing at least a portion of the electrical power to at least one motor attached to the at least one compressor.
Aspect 14—The method of any of Aspects 1 through 13, wherein the power generated in step (e) comprises electrical power and step (f) comprises providing at least a portion of the electrical power to at least one of the hydrogen production system and the natural gas liquefaction system.
Aspect 15—The method of any of Aspects 1 through 14, wherein the power generated in step (e) comprises electrical power and the method further comprises:
Aspect 16—The method of any of Aspects 1 through 15, wherein step (e) further comprises generating power in a power generating system using the hydrogen containing stream and at least one methane-containing stream.
Aspect 17—The method of Aspect 16, wherein the at least one methane-containing stream comprises at least one selected from the group of a natural gas feed stream and the flash vapor stream.
Aspect 18—The method of any of Aspects 1 through 17, further comprising:
Aspect 19—The method of any of Aspects 1 through 18, wherein step (f) comprises driving the at least one compressor by mechanically coupling at least one gas turbine of the power generating system to the at least one compressor of the natural gas liquefaction system.
Aspect 20—The method of any of Aspects 1 through 19, further comprising:
Aspect 21—The method of any of Aspects 1 through 20, further comprising:
Aspect 22—The method of any of Aspects 1 through 21, further comprising:
Aspect 23—The method of any of Aspects 1 through 22, wherein step (a) comprises at least partially liquefying the natural gas feed stream in the natural gas liquefaction system to form the LNG stream, the natural gas liquefaction system including a closed loop refrigeration system having at least one compressor.
Aspect 24—A method of retrofitting an existing natural gas liquefaction system that at least partially liquefies natural gas feed stream at a feed temperature to form an LNG product at a product temperature, the natural gas liquefaction system comprising at least one compressor, the method comprising:
Aspect 25—The method of Aspect 24, further comprising:
Aspect 26—The method of any of Aspects 24 through 25, further comprising:
Aspect 27—The method of any of Aspects 24 through 26, wherein the power generating system was adapted to provide power to the natural gas liquefaction system prior to retrofit, the method further comprising:
Aspect 28—The method of Aspect 27, further comprising:
Aspect 29—The method of any of Aspects 24 through 28, further comprising:
Aspect 30—The method of any of Aspects 24 through 29, further comprising:
The present invention will hereinafter be described in conjunction with the appended drawing figures wherein like numerals denote like elements.
The ensuing detailed description provides preferred exemplary embodiments only, and is not intended to limit the scope, applicability, or configuration of the invention. Rather, the ensuing detailed description of the preferred exemplary embodiments will provide those skilled in the art with an enabling description for implementing the preferred exemplary embodiments of the invention. It being understood that various changes may be made in the function and arrangement of elements without departing from the spirit and scope of the invention.
In order to aid in describing the invention, directional terms may be used in the specification and claims to describe portions of the present invention (e.g., upper, lower, left, right, etc.). These directional terms are merely intended to assist in describing and claiming the invention and are not intended to limit the invention in any way. In addition, reference numerals that are introduced in the specification in association with a drawing figure may be repeated in one or more subsequent figures without additional description in the specification in order to provide context for other features.
The term “conduit,” as used in the specification and claims, refers to one or more structures through which fluids can be transported between two or more components of a system. For example, conduits can include pipes, ducts, passageways, and combinations thereof that transport liquids, vapors, and/or gases.
As used in the specification and claims, the term “flow communication” is intended to mean that two or more elements are connected (either directly or indirectly) in a manner that enables fluids to flow between the elements, including connections that may contain valves, gates, tees, or other devices that may selectively restrict, merge, or separate fluid flow.
The term “natural gas”, as used in the specification and claims, means a hydrocarbon gas mixture consisting primarily of methane.
The terms “hydrocarbon”, “hydrocarbon gas”, or “hydrocarbon fluid”, as used in the specification and claims, means a gas/fluid comprising at least one hydrocarbon and for which hydrocarbons comprise at least 80%, and more preferably at least 90% of the overall composition of the gas/fluid.
As used in the specification and claims, the terms “high-high”, “high”, “medium”, “low”, and “low-low” are intended to express relative values for a property of the elements with which these terms are used. For example, a high-high pressure stream is intended to indicate a stream having a higher pressure than the corresponding high pressure stream or medium pressure stream or low pressure stream described or claimed in this application. Similarly, a high pressure stream is intended to indicate a stream having a higher pressure than the corresponding medium pressure stream or low pressure stream described in the specification or claims, but lower than the corresponding high-high pressure stream described or claimed in this application. Similarly, a medium pressure stream is intended to indicate a stream having a higher pressure than the corresponding low pressure stream described in the specification or claims, but lower than the corresponding high pressure stream described or claimed in this application.
Unless otherwise stated herein, any and all percentages identified in the specification, drawings and claims should be understood to be on a mass percentage basis. Unless otherwise stated herein, any and all pressures identified in the specification, drawings and claims should be understood to mean gauge pressure.
As used in the specification and claims, the term “compression system” is defined as one or more compression stages. For example, a compression system may comprise multiple compression stages within a single compressor. In an alternative example, a compression system may comprise multiple compressors.
Unless otherwise stated herein, introducing a stream at a location is intended to mean introducing substantially all of the said stream at the location. All streams discussed in the specification and shown in the drawings (typically represented by a line with an arrow showing the overall direction of fluid flow during normal operation) should be understood to be contained within a corresponding conduit. Each conduit should be understood to have at least one inlet and at least one outlet. Further, each piece of equipment should be understood to have at least one inlet and at least one outlet.
In the claims, letters are used to identify claimed steps (e.g. (a), (b), and (c)). These letters are used to aid in referring to the method steps and are not intended to indicate the order in which claimed steps are performed, unless and only to the extent that such order is specifically recited in the claims.
Key features of all the exemplary embodiments described herein include an LNG liquefier with one or more refrigeration compressors that produces LNG and an endflash gas from a natural gas feed, the endflash gas (predominantly methane) is sent to a hydrogen production system which produces hydrogen and carbon dioxide. The CO2 may be captured or beneficially used. For example, the CO2 could be compressed, liquefied, utilized in another process, liquefied in the pre-cooling portion of the LNG plant, or processed via other means. After these steps, the CO2 could be used for enhanced oil recovery, stored, sequestered, sold, utilized in another process, or used for another purpose. Optionally, CO2 could be extracted from the natural gas feed via an acid gas removal unit and combined with the CO2 effluent stream from hydrogen production. At least a portion of the hydrogen produced is then sent to gas turbines in a power generation system that provides power for the refrigeration compressor(s) either directly by mechanical coupling of the gas turbine(s) to the compressors, or indirectly by generation of electricity from generators coupled to the gas turbine(s) that is consumed by electric motors coupled to the compressors.
It should be noted that, even though the exemplary natural gas liquefaction system embodiments disclosed herein all have closed-loop refrigeration, the inventive concepts disclosed herein are equally applicable to natural gas liquefaction systems using either open- or closed-loop compression.
Feeding the hydrogen production system with endflash that is predominately methane from the natural gas liquefaction system has several advantages. The efficiency of the Natural gas liquefaction system is improved since the refrigerant does not have to cool the LNG to as low a temperature. For example, assuming the same gas turbine refrigeration compressor drivers, endflash fuel demand increases by 10-20%, resulting in a 2-4° F. increase in outlet temperature from the main cryogenic heat exchanger. This results in a 1-2% decrease in refrigeration compressor power demand. In addition, more LNG is produced from a refrigeration system of the same size, or alternately, the size of the equipment including compressors, heat exchangers and pipes in the refrigeration system is smaller for the same production capacity. Finally, the system can produce LNG with acceptable nitrogen content from higher nitrogen feed gas, as feed nitrogen will concentrate in the endflash gas therefore decreasing the nitrogen content of the LNG. In addition, the methane endflash is relatively free of impurities, which reduces the need for a purification step for the methane feed gas used in the hydrogen production system.
Other further integration options between the three systems are described including using refrigeration from the natural gas liquefaction system to lower the power requirement or cost of an air separation unit associated with the hydrogen production system and using steam from the power generation system for process heating in the natural gas liquefaction system.
A predominantly methane flash vapor stream 114 is sent to the hydrogen production system 118 after compression and heat exchange steps (labeled 113), which will be described more fully in the description of
The hydrogen production system 118 uses an ambient air stream 116 and the flash vapor stream 114 to produce a hydrogen stream 122 and an intermediate pressure steam stream 138, which are both sent to power generation system 124, along with a waste nitrogen stream 144, an optional hydrogen product stream 134 (which may be sent to a pipeline), and a CO2 stream 120, which is combined with CO2 containing stream 106 from the natural gas liquefaction system 103, then compressed (via compressor 130) and sent to a pipeline or sequestered in underground storage via the compressed CO2 stream 132. In other embodiments, the hydrogen production system 118 could be configured to produce the hydrogen stream 122 only and not any steam streams. The process may include vent steams (not shown) which might include exhaust from fired heaters, steam vents, and waste water steams.
The power generation system 124 uses the hydrogen stream 122 and the intermediate pressure steam stream 138 from the hydrogen system 118 to produce electric power 128 for use in the overall facility and natural gas liquefaction system 103 (represented by line 126). Optionally electric power can be exported to a power grid via line 136. Power sent from the natural gas liquefaction system 103 via line 126 could take the form of electricity sent to motors attached to compressors or by mechanically coupling gas turbines in the power production system 124 to the refrigeration compressors of the natural gas liquefaction system 103.
The natural gas liquefaction system 203 could use any known process for natural gas liquefaction. In this embodiment, a propane precooled, mixed refrigerant process is used. The process will not be described in detail because it is well-known in the art. The pre-treated feed gas stream 252 is cooled to about −30 degrees C. by the pre-cooling system 250, followed by further cooling in a main heat exchanger 251 to −140 to −150 degrees C., exiting as stream 204. The high-pressure LNG stream 204 is then flashed to a lower pressure of 1-3 bara in pressure reduction device 208 which may be a valve or work producing turbine. Stream 256, which is typically less than 20% of the natural gas stream 253 exiting the pre-cooling system 250 is then further cooled in flash exchanger 258 while warming flash gas stream 211. The resulting two phase stream 210 is separated in 242 to form a vapor stream 211 and LNG stream 212. Vapor stream 211 is warmed to around −40 to −30 degrees C. in flash exchanger before being compressed to preferably about 40 to 60 bara (more preferably about 40 to 50 bara) in compressor 260 to form stream 214. The vapor stream 214 may optionally include additional methane-containing gas from an LNG storage tank (not shown). Energy for the liquefaction process is mainly provided by three refrigeration compressors 262,264 and 266. Compressors 262 and 264 compress the vaporized low-pressure mixed refrigerant prior to precooling in the pre-cooling system 250. Compressor 266 compresses vaporized propane before it is condensed in ambient cooler 268 and returned to the propane system. In this embodiment, power for the compressors 262, 264, 266 is provided by mechanically coupling the compressors 262, 264, 266 to two identical gas turbine drivers located in the power generation system of
In the arrangement shown, compressors 264 and 266 are connected to the same shaft powered by mechanical work stream 226a while compressor 262 is powered by mechanical work stream 226b, allowing for full utilization of the mechanical power provided by two equal gas turbine drivers located in the power generation system of
The ambient air stream 316 is compressed in a compressor 346, then cooled in an ambient cooler 374. Optionally, the compressed air stream may be further cooled using refrigeration from the natural gas liquefaction system 203 (represented by stream 317, which corresponds to the energy stream 217 of
The cooled, dry compressed air stream 376 is fed to a cryogenic air separation unit (ASU) 348. Other types of air separation technology such as adsorption or membranes may be used in place of the ASU 348. The ASU 348 produces an oxygen enriched stream 350 preferably having greater than about mole 95% O2, and a nitrogen stream 344. Additional optional product steams from the ASU 348 include gaseous argon, liquid argon, liquid oxygen, and liquid nitrogen. Further integration between the ASU and LNG plant can include sending a portion of the compressed air to the main heat exchanger 251 to be liquified. This integration may eliminate the ASU expander, thus lowing CAPEX.
Oxygen stream 350 is mixed with predominantly methane stream 314 and steam stream 354 then sent to an autothermal reformer (ATR) 352. In most applications, the steam stream 354 would be pre-heated before being introduced into the ATR 352. Reactions in the ATR 352 include a reforming reaction where methane and water form carbon monoxide and hydrogen (1), a shift reaction where carbon monoxide reacts with water to form hydrogen (2), and partial oxidation reactions involving methane, carbon monoxide, and hydrogen (3-5):
CH4+H2O→CO+3H2 (1)
CO+H2O→CO2+H2 (2)
2CH4+O2→2CO+4H2 (3)
CO+1/2O2→CO2 (4)
H2+1/2O2→H2O (5)
In addition, various combinations of these reactions are possible.
Hot effluent from the ATR 352 is then cooled in a steam generator 356, which vaporizes a recycled water stream 340 (labeled 440 in
CO+H2O→CO2+H2 (6)
In addition, various combinations of these reactions are possible. For example, the shift reactor could consist of a two-stage shift with cooling between stages.
Hydrogen containing stream 362 is then cooled (364) and sent to carbon dioxide removal unit 366 which removes carbon dioxide stream 320 from the hydrogen product. Unit 366 may be an adsorption system, for example, an amine-based carbon dioxide removal unit or alternate means to remove carbon dioxide such as adsorption system, membrane system, or partial condensation system. Addition optional processing could be done to remove impurities, such as carbon monoxide.
Optionally a hydrogen product stream 334 may be removed then further purified using, for example, a pressure swing adsorption system, and sent via pipeline, liquefied, or converted to ammonia for transport to external users.
After compression (via compressor 368), a portion 318 of the nitrogen from ASU 348 may optionally be added to a hydrogen stream 370. A compressor 372 may be used to compress the hydrogen before it's sent to the power generation system as stream 322 (labeled as 122 in
Additional features of the ATR system for hydrogen generation can include: a prereformer, means to preheat feeds including oxygen, fired heater for feed preheating and steam superheating, various configurations of shift reactors including high temperature shift, medium temperature shift, low temperature shift, isothermal shift and/or combinations thereof, purification of the feed to remove trace impurities such as sulfur, recuperative reforming reactor, and/or a methanator to convert carbon monoxide to methane.
Although
A hydrogen feed gas stream 422 may be blended with a portion of steam stream 438 before being sent to the combustors 460a-e of five parallel gas turbines 446a-e. Four of the turbines 446a-d are mechanically coupled to four compression strings in the two parallel trains of the natural gas liquefaction system (represented by work streams 226a, 226b). The combined work streams of 426a-d are represented in
The high pressure steam stream 466 and intermediate pressure steam 482 are then expanded in a work producing steam turbine 468, which is mechanically coupled to a generator 470, thereby producing electrical power 472. Low pressure steam 467 could be used advantageously to provide heat duty for the hydrogen production system 118 and/ or the natural gas liquefaction system 103. The steam turbine 468 and coupled generator 470 are depicted as a single unit in
It is also possible to use steam generated by the power generation system 424 to drive additional steam turbine mechanical drives (not shown) for large compressors in the facility rather than electric motor drive. Steam turbines could be mechanically coupled to compressor 130, compressor 260, and/or compressor 346 for this purpose.
In some applications, it may be desirable to use a mixture of hydrogen and methane or natural gas to fuel the gas turbines 466a-e. In such applications, natural gas could be added to the hydrogen feed gas stream 422 from the natural gas feed stream 100 (represented by line 182 in
Referring to
Referring to
Alternatively, the inventive concepts discussed herein could be applied to a retrofit modification of an existing natural gas liquefaction plant to reduce carbon footprint without any reduction in LNG production capacity. In fact, it is believed that inventive concepts disclosed herein enable a substantial reduction in carbon emissions (primarily CO2), while increasing LNG production capacity. Existing gas turbines 446a-d (See
The following modeled example is based on the process diagrams represented by
Table 2 shows key parameters for this example which uses five Baker Hughes/GE gas turbines for power generation and refrigerant compression. The process produces 13 million tonnes per year LNG while capturing 97% of the CO2 for sequestration and converting 92.6% of the feed natural gas to LNG.
Table 3 shows key modeled parameters for an example of an alternate embodiment in which two GE frame 7F gas turbines are used for combined cycle power generation. In this example, the natural gas liquefaction system produces 11.5 million tonnes per year of LNG, while capturing 97% of the CO2 for sequestration and converting 94.3% of the feed natural gas to LNG product.
As such, an invention has been disclosed in terms of preferred embodiments and alternate embodiments thereof. Of course, various changes, modifications, and alterations from the teachings of the present invention may be contemplated by those skilled in the art without departing from the intended spirit and scope thereof. It is intended that the present invention only be limited by the terms of the appended claims.
