Liquefaction of hydrogen-containing natural gas feeds

Abstract

Liquefaction systems and methods are disclosed that are adapted to process natural gas streams having substantial concentrations of hydrogen, where the concentration of hydrogen may vary within the natural gas stream. In some implementations, the expanded liquefied natural gas stream may be separated into a hydrogen-rich end flash stream and a hydrogen-lean LNG stream, and a second gaseous hydrogen-lean stream may be produced from the hydrogen-rich end flash stream and / or the hydrogen-lean LNG stream. In other implementations, the pressure of the end flash compressor may be controlled to maintain the hydrogen concentration in the fuel stream (often the end flash stream) within a desired range. Some implementations may include pre- or post-liquefaction purification using, for example, membranes, adsorption, partial condensation, distillation, stripping, and electrochemical membranes.

Description

[Technical Field]

[0001] Blending green or blue hydrogen into existing natural gas pipelines is being discussed and studied globally as a path toward reducing carbon footprints. Blue hydrogen is formed by reacting natural gas into hydrogen and carbon dioxide (CO2) through methods such as steam methane reforming (SMR) or auto thermal reforming (ATR), which is captured and then stored. Green hydrogen is produced by electrolyzing water using renewable energy. One vision involves producing green hydrogen and injecting this hydrogen into nearby natural gas pipelines. Essentially, these pipelines act as reservoirs and conduits for renewable energy.

[0002] Many countries are considering hydrogen blending as an intermediate step on the path to "Net Zero Carbon by 2050." The U.S. Department of Energy has commissioned a study on the effects of hydrogen blending on metallurgy and leak rates. Various sources suggest that up to 20% hydrogen can be blended with natural gas without adversely affecting piping metals and downstream equipment. The California Public Utilities Commission has studied hydrogen blending and determined that a maximum of 5% hydrogen blend is generally safe, acknowledging that hydrogen blending increases the likelihood of pipeline leaks and embrittlement of steel pipelines. Small-scale testing has begun at some utility companies. Hydrogen concentrations in natural gas pipelines may also change over time.

[0003] If implemented, these proposals could impose significant costs and challenges on liquefied natural gas (LNG) production plants drawing from pipelines with hydrogen blends. It is not feasible to liquefy hydrogen at concentrations exceeding several parts per million (PPM) into an LNG product. While hydrogen could be removed from the natural gas feed into a fuel stream for a gas turbine driver or other use, hydrogen would be present in the fuel stream at concentrations many times higher than in the natural gas feed. Because hydrogen has different thermophysical properties than natural gas, its presence in a fuel stream for a gas turbine driver would have operational impacts on the fuel flow, fuel compressor, burner flame characteristics, and NOx emissions. Many gas turbine drivers would require significant modifications to operate using a fuel stream with a hydrogen concentration greater than 20-30%. Potential variations in hydrogen concentration in natural gas pipelines present challenges for fuel balancing in LNG plants. Therefore, innovative solutions are needed to enable hydrogen-blended natural gas feeds to be effectively used in LNG plants. Summary of the Invention

[0004] 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. Certain aspects of the systems and methods are summarized below.

[0005] Referring to FIG. 1 , the disclosed exemplary embodiments fill a need in the art by providing several LNG systems 100 in which the feed stream 110 is a blended hydrogen natural gas feed stream. Downstream of liquefaction, a gaseous hydrogen-rich stream 114 is produced, which may be used as fuel, sent (e.g., to a resource pipeline or another pipeline), or further refined to produce a purified hydrogen stream. The gaseous hydrogen-rich stream 114 is a mixture of primarily methane, nitrogen, and hydrogen and has a higher hydrogen concentration than the blended hydrogen natural gas feed stream 110. A gaseous hydrogen-lean stream 112 is also produced, which may be recycled to the feed stream 110. The gaseous hydrogen-lean stream 112 is a mixture of primarily methane, nitrogen, and hydrogen and has a lower hydrogen concentration than the blended hydrogen natural gas feed stream. As is conventional, an LNG product stream is also produced, which is preferably hydrogen-lean relative to the blended hydrogen natural gas feed stream 110.

[0006] Some aspects of the system and method are as follows.

[0007] Aspect 1: (a) cooling and liquefying a hydrogen-containing natural gas feed stream in a natural gas liquefaction plant to form a liquefied natural gas stream; (b) reducing the pressure of the liquefied natural gas stream to form an expanded LNG stream; (c) separating the expanded LNG stream in a first endflash unit into a first endflash stream and a hydrogen-lean LNG stream, the first endflash stream having a higher hydrogen concentration than the hydrogen-containing natural gas feed stream and the hydrogen-lean LNG stream having a lower hydrogen concentration than the hydrogen-containing natural gas feed stream; (d) further processing the first end flash stream and / or the hydrogen-depleted LNG stream to form a gaseous hydrogen-depleted stream and a gaseous hydrogen-enriched stream; A method comprising:

[0008] Aspect 2: The method of aspect 1, wherein step (d) is carried out using at least one selected from the group of at least one membrane stage, at least one adsorption stage, a partial condensation stage, a distillation stage, a stripping stage, and an electrochemical membrane stage.

[0009] Aspect 3: The method of any one of Aspects 1-2, wherein the first end flash unit is a gas-liquid separator.

[0010] Aspect 4: The method of any one of Aspects 1-2, wherein the first end flash unit is a distillation column.

[0011] Aspect 5: Aspect 5. The method of any one of aspects 1-4, further comprising: (e) compressing the gaseous enriched hydrogen stream and using it as a fuel stream.

[0012] Aspect 6: The method of aspect 5, wherein the fuel stream is for a gas turbine, a boiler, or a furnace.

[0013] Aspect 7: Aspect 7. The method of any one of aspects 1-6, further comprising: (f) further processing the gaseous enriched hydrogen stream to form a purified hydrogen stream having a hydrogen concentration of at least 90%.

[0014] Aspect 8: 8. The method of embodiment 7, further comprising: (g) passing the purified hydrogen stream to a fuel cell to generate electricity.

[0015] Aspect 9: 8. The method of embodiment 7, further comprising: (h) sending the purified hydrogen stream to a hydrogen pipeline.

[0016] Aspect 10: Aspect 10. The method of any one of aspects 1-9, further comprising: (i) directing at least a portion of the gaseous hydrogen-lean stream to the fuel stream.

[0017] Aspect 11: 11. The method of any one of aspects 1-10, further comprising: (j) passing at least a portion of the gaseous hydrogen-lean stream to a recycle stream that is combined with the hydrogen-containing natural gas feed stream upstream of step (a).

[0018] Aspect 12: (k) controlling the separator pressure at which step (c) is performed to maintain a hydrogen concentration in the first end flash stream within a first predetermined range.

[0019] Aspect 13: 10. The method of embodiment 1, further comprising: (l) pretreating the hydrogen-containing natural gas feed stream upstream of step (a) to produce a pretreated hydrogen-containing natural gas feed stream and a hydrogen-enriched pretreated stream, wherein the pretreated hydrogen-containing natural gas feed stream has a lower hydrogen concentration than the hydrogen-containing natural gas feed stream.

[0020] Aspect 14: 14. The method of embodiment 13, further comprising: (m) passing the hydrogen-enriched pretreated stream to the fuel stream.

[0021] Aspect 15: The method of any of aspects 13-14, further comprising: (n) performing step (a) on a pretreated hydrogen-containing natural gas feed stream.

[0022] Aspect 16: 14. The method of embodiment 13, further comprising: (o) purifying the hydrogen-enriched pretreated stream to form a purified hydrogen stream having a hydrogen concentration of at least 90%.

[0023] Embodiment 17: The method of embodiment 16, further comprising performing step (o) using at least one adsorption bed.

[0024] Aspect 18: (a) cooling and liquefying a hydrogen-containing natural gas feed stream in a natural gas liquefaction plant having at least one gas turbine driven refrigeration compressor to form a liquefied natural gas stream; (b) using the fuel stream to drive at least one of the at least one gas turbine driven refrigeration compressor; (c) reducing the pressure of the liquefied natural gas stream to form an expanded LNG stream; (d) separating the expanded LNG stream in an end flash separator into an end flash stream and a hydrogen-depleted LNG stream, the end flash stream having a higher concentration of hydrogen than the hydrogen-containing natural gas feed stream; (e) compressing the end flash stream to form a compressed end flash stream; (f) storing the hydrogen-depleted LNG stream in an LNG storage tank; (g) compressing a BOG stream from the LNG storage tank to form a compressed BOG stream; (h) further compressing the compressed BOG stream to form a further compressed BOG stream; (i) combining a further compressed BOG stream with a hydrogen-containing natural gas feed stream upstream of carrying out step (a); Including, The method, wherein the fuel stream comprises a compressed end flash stream.

[0025] Aspect 19: (j) diverting a first portion of the BOG stream upstream of step (h); (k) combining a first portion of the BOG stream with the end flash stream to form a fuel stream; 20. The method of embodiment 18, further comprising:

[0026] Aspect 20: (a) cooling and liquefying a hydrogen-containing natural gas feed stream in a natural gas liquefaction plant to form a liquefied natural gas stream; (b) reducing the pressure of the liquefied natural gas stream to form an expanded LNG stream; (c) separating the expanded LNG stream in a first end flash unit into a first end flash stream and a hydrogen-depleted LNG stream, the first end flash stream having a higher hydrogen concentration than the hydrogen-containing natural gas feed stream and the hydrogen-depleted LNG stream having a lower hydrogen concentration than the hydrogen-containing natural gas feed stream; (d) compressing the end flash stream using an end flash compressor to form a compressed end flash stream; (e) using the compressed end flash stream as the fuel stream; (f) controlling the pressure at which the end flash compressor operates to maintain the hydrogen concentration in the fuel stream within a predetermined range; A method comprising:

[0027] In electric motor-driven plants that draw power from the grid and have low fuel demand, hydrogen removal is required. This can be achieved at the cold end of the plant in an end-flash system. The system can be designed to produce a send-out stream containing more than 50% hydrogen. Hydrogen can also be removed from the front end of the plant using a number of separation schemes. However, front-end removal of hydrogen requires processing of the entire feed stream, while back-end removal of hydrogen involves processing a flash stream that is a portion of the total feed stream.

[0028] For gas turbine-driven plants where the feed hydrogen content is greater than about 0.5% and the hydrogen is sent to fuel, the end flash stream will be enriched in hydrogen, requiring modifications to existing end flash compression systems. For feeds containing greater than 2% hydrogen, the fuel stream will be highly enriched in hydrogen, requiring significant modifications to the gas turbine combustion and fuel systems if the hydrogen is not sent to export. There are many possible schemes for producing a hydrogen / methane mixture suitable for export. The optimal scheme depends on the destination of the export stream. If there is local market demand for hydrogen, the hydrogen sent from the LNG plant can be further processed into a saleable product. [Brief explanation of the drawings]

[0029] An illustrative description is set forth below in conjunction with the accompanying drawings, in which like numerals represent like elements, and in which: [Figure 1] 1 is a schematic flow diagram showing three streams produced from a blended hydrogen natural gas feed stream in an LNG plant. [Figure 2] 1 is a schematic flow diagram showing an LNG plant with no flowsheet modifications from the prior art. [Figure 3] 1 is a schematic flow diagram illustrating an LNG plant with a BOG recycle compressor added to recycle hydrogen-lean boil-off gas (“BOG”) and storage tank flash to the feed. [Figure 4] 1 is a schematic flow diagram illustrating an LNG plant showing hydrogen removal to fuel using a tail membrane. [Figure 5] 1 is a schematic flow diagram illustrating an LNG plant having a double end flash configuration. [Figure 6] 6 is a graph showing the maximum production obtainable from the exemplary implementations shown in FIGS. 2-5 as a function of feed hydrogen content ranging from 0-5%. [Figure 7] 6 is a graph showing the required specific power output of the exemplary implementations shown in FIGS. 2-5 as a function of feed hydrogen content ranging from 0 to 5%. [Figure 8] 1 is a schematic flow diagram illustrating an LNG plant showing end flash H2 separation. [Figure 9] 9 is a table showing modeled system parameters for the example implementation of FIG. 8. [Figure 10] 1 is a schematic flow diagram illustrating an LNG plant with a front-end membrane. [Figure 11] 1 is a schematic flow diagram illustrating an LNG plant with a front-end membrane and using adsorption to further purify the permeate stream. [Figure 12] An LNG plant shown in Figure 11 has been modified to provide double end flashing. DETAILED DESCRIPTION OF THE INVENTION

[0030] The following detailed description provides preferred exemplary embodiments only and is not intended to limit the scope, applicability, or configuration of the present invention. Rather, the following detailed description of preferred exemplary embodiments will provide those skilled in the art with an enabling description for practicing preferred exemplary embodiments of the present invention. It will be understood that various changes can be made in the function and arrangement of elements without departing from the spirit and scope of the present invention.

[0031] To aid in describing the present invention, directional terms (e.g., up, down, left, right, etc.) may be used in this specification and claims to describe portions of the present invention. These directional terms are intended merely to aid in describing and claiming the present invention and are not intended to limit the present invention in any way. Additionally, reference numerals introduced herein with respect to the drawings may be repeated in one or more subsequent figures without further description herein to provide context for other features.

[0032] Unless otherwise indicated, the articles "a" and "an," as used herein, when applied to any feature in the embodiments of the invention described herein and claimed, mean one or more. The use of "a" and "an" does not limit the meaning to a single feature unless such a limitation is specifically stated. The article "the" preceding a singular or plural noun or noun phrase refers to the particular named feature or features and may have a singular or plural connotation depending on the context in which it is used.

[0033] As used herein and in the claims, the term "conduit" refers to one or more structures capable of transporting a fluid between two or more components of a system. For example, conduits can include pipes, ducts, passages, and combinations thereof that transport liquids, vapors, and / or gases.

[0034] As used in this specification and claims, the term "natural gas" means a hydrocarbon gas mixture consisting primarily of methane. As used herein, the term "natural gas" also encompasses synthetic and alternative natural gases. Natural gas feed streams contain methane and nitrogen (typically with methane being the major component).

[0035] As used in this specification and claims, the terms "hydrogen-containing natural gas" and "hydrogen-containing natural gas stream" mean a natural gas stream containing at least 100 ppm hydrogen. The terms "hydrogen-containing natural gas" and "hydrogen-containing natural gas stream" are intended to be synonymous with the term "blended hydrogen natural gas stream."

[0036] Unless otherwise stated herein, any and all percentages specified in the specification, drawings, and claims should be understood to be on a mole percentage basis. Unless otherwise stated herein, any and all pressures specified in the specification, drawings, and claims should be understood to mean gauge pressure.

[0037] As used herein and in the claims, the term "compression system" is defined as one or more compression stages. For example, a compression system may include multiple compression stages within a single compressor. Alternatively, a compression system may include multiple compressors.

[0038] In the claims, letters are used to identify the claimed steps (e.g., (a), (b), and (c)). These letters are used to aid in referencing the method steps and are not intended to dictate the order in which the claimed steps are performed, unless such order is specifically recited in the claims.

[0039] As used herein and in the claims, the term "membrane module" refers to a device used to selectively separate gases by flowing a feed gas at relatively high pressure through one or more conduits contained within a shell (also referred to as the high-pressure side). The conduits are defined at least in part by a membrane material that provides a barrier between each conduit and a shell space (also referred to as the low-pressure side). The shell space is an internal volume within the shell that is external to each membrane and maintained at a relatively low pressure. The shell side is in fluid flow communication with a permeate port through which gases that permeate the membrane exit the shell. Optionally, a sweep port may be provided to supply a sweep gas to the shell space and assist the flow of the permeate gas through the permeate port. The membrane material is selected to allow one or more gases in the feed stream (referred to as the permeate gas) to pass through the membrane material at a faster rate than other gases in the feed gas stream (referred to as the non-permeate or product gas). The membrane modules may be of a bore-side feed design in which the membrane modules are pressurized by the introduction of a feed gas stream on their bore side, or may be of a shell-side feed design in which the membrane modules are pressurized by the introduction of a feed gas stream on their shell side.

[0040] When used herein to identify recited features of a method or system, the terms "first," "second," "third," etc. are used solely to refer to and aid in identifying the features of interest and are not intended to indicate any particular order of the features unless such order is specifically recited.

[0041] As used herein, the term "fuel stream" means a gas stream used to fuel a portion of an LNG plant, such as a gas turbine or steam generation system, such as a boiler, furnace, or other combustion device.

[0042] As used herein, reference to a product stream from a gas separation process that is "enriched" in a particular gas or component means that the product stream has a higher mole percent of that particular gas or component than the feed stream to the gas separation process. Non-limiting examples of fluid separation processes include separation drums, distillation columns, strip columns, adsorption, membrane separation, and electrochemical separation.

[0043] As used herein, the term "fluid flow communication" refers to the quality of connectivity between two or more components that allows liquids, vapors, and / or two-phase mixtures to be transported, directly or indirectly, between the components in a controlled manner (i.e., without leakage). Coupling two or more components in fluid flow communication with one another can include any suitable method known in the art, such as the use of welding, flanged conduits, gaskets, and bolts. Two or more components may also be coupled to one another through other components of the system that may separate them, such as valves, gates, or other devices that may selectively restrict or direct fluid flow. As used herein, the term "conduit" 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.

[0044] Referring again to FIG. 1 , there are three points where the hydrogen in the feed gas 110 could potentially enter the LNG liquefaction plant 100. One option (Option A) is to leave the hydrogen in the LNG product 116. A second option (Option B) is to use the hydrogen for at least a portion of the fuel requirements of the system 100, typically as fuel for a gas turbine driving a refrigerant compressor. A third option (Option C) is to export the hydrogen from the system 100, typically for further purification as a hydrogen product or back into the natural gas pipeline downstream of the liquefaction unit. Option A is not practical for natural gas feeds with more than a few hundred parts per million (PPM) of hydrogen due to the low liquefaction temperatures required. In both Options B and C, stream 114 may be produced to transport the hydrogen to a fuel consumption destination (Option B) or an export destination (Option C). Stream 112 can meet additional fuel requirements or can be recycled to the natural gas feed 110 or elsewhere in the LNG plant.

[0045] FIG. 2 shows a conventional natural gas to LNG system 200. In system 200, a hydrogen-containing natural gas feed stream 210 is cooled and liquefied in liquefaction unit 218 using a liquefaction process such as a conventional C3MR, DMR, SMR, pure component cascade, reverse Brayton cycle, or other liquefaction method to form a liquefied natural gas stream 220. Stream 210 may be at a pressure of 30 bara to 80 bara or more and near ambient temperature, or may be pre-cooled to a temperature of −30° C. to −60° C. by a pre-cooling system. Stream 220 may be at a pressure of 30 bara to 70 bara or more and a temperature of −130° C. to −155° C. or less. The liquefied natural gas stream 220 is expanded through valve 224 to form an expanded LNG stream 226. The liquefied natural gas stream 220 may optionally pass through a hydraulic turbine (not shown) before expanding through valve 224. The optional encapsulation of the water turbine is applicable to all exemplary implementations described herein.

[0046] Expanded LNG stream 226 is then separated in end flash drum 228 into end flash stream 238 (enriched in hydrogen relative to feed stream 210) and LNG stream 230 (depleted in hydrogen relative to feed stream 210). In this exemplary implementation, the pressure of end flash drum 228 is fixed at a fixed pressure, for example, 1.0 bara to 1.5 bara. LNG stream 230 is expanded through expansion valve 232, and expanded LNG stream 234 enters LNG storage tank 236. Stream 230 can be pumped to a higher pressure, such as 7 bar to 10 bar, prior to valve 232. Valve 232 may be part of a storage tank inlet manifold, such as a spray nozzle(s). LNG product stream 216 is withdrawn from the storage tank.

[0047] End flash stream 238 is optionally warmed in end flash heat exchanger 240 against a portion 248 of the hydrogen-containing natural gas feed stream 210 to form a warmed end flash stream 242 and a cooled portion 250. The cooled portion 250 is then expanded through expansion valve 252 to form expanded stream 254, which is combined with expanded LNG stream 226.

[0048] Warmed end flash stream 242 is compressed in end flash compressor 244 to form fuel stream 214, which is used as fuel in system 200. In many applications, fuel stream 214 is used as fuel for a gas turbine that directly drives a refrigeration compressor, or to generate electricity that is used to power an electric motor that drives a refrigeration compressor (not shown) for the refrigerant that provides the refrigeration load for liquefaction unit 218.

[0049] Boil off gas ("BOG") stream 256 is withdrawn from LNG storage tank 236 and compressed in BOG compressor 260 to form compressed boil off gas stream 264, which is supplied to fuel stream 214. Stream 256 may include vapor generated from the expansion of stream 230, vapor generated from heat leak into stream 234, and vapor generated from heat leak into the storage tank.

[0050] Option A - Hydrogen in LNG product The thermodynamics of vapor and liquid equilibrium limit the practicality of leaving the plant with hydrogen in the LNG product. It should be noted that the maximum amount of hydrogen that can be dissolved in the LNG product is approximately 700 ppm. Therefore, it is only feasible to operate system 200 when the hydrogen concentration in LNG product stream 216 is very low (well below 1% hydrogen). Furthermore, doing so increases the specific power consumption of system 200. Another barrier is the limited installed refrigeration capacity of many existing baseload LNG and peak-shaving plants. Most baseload facilities are limited by installed gas turbine driving power. Peak-shaving, small, and medium-sized plants are typically powered by electric motors. Increasing the liquefaction specific power by adding a few hundred ppm of hydrogen would reduce production from facilities currently limited by installed electric power. Therefore, for system 200, Option B (fuel) and Option C (hydrogen removal) are the only realistic paths for hydrogen when hydrogen concentrations above a few hundred ppm are present in the feed.

[0051] Option B - Hydrogen in gas turbine fuel For existing gas turbine-driven plants, option B has the advantage of lowering the plant carbon intensity because some of the methane content in the fuel is replaced by hydrogen. However, this solution may require significant modifications to the plant fuel system.

[0052] Hydrogen, being more volatile than methane, is concentrated in the flash (fuel) gas stream 238. In an LNG plant with a typical fuel demand, 1% hydrogen in the feed will result in a fuel with over 15% hydrogen. With 5% hydrogen in the feed, the hydrogen content in the fuel will be over 50%.

[0053] This change in composition affects the performance and operability of the end flash gas compressor 244, which raises the fuel pressure from near atmospheric to approximately 40 bara. Note that the work required to compress one mole of hydrogen is 3% greater than the work required to compress one mole of methane. Additionally, because hydrogen's lower heating value is 3.3 times lower than methane, more fuel flow is required to maintain the same fuel heating value to the gas turbine in order to maintain the amount of power available to the refrigeration compressor. Overall, this means that the power required to compress any hydrogen in the fuel is 3.4 times higher compared to an equivalent amount of displaced methane, thereby affecting overall plant power consumption. For existing plants, if the hydrogen feed exceeds 0.5%, significant modifications to the fuel system, including rotating and stationary equipment, will likely be required.

[0054] In addition to end-flash compression issues, the fuel can also cause gas turbine operational problems, and most existing industrial-frame gas turbines equipped with dry low emissions (DLE) combustion systems are not designed to operate on fuels with hydrogen concentrations greater than 30%. Extensive engine and package modifications are required to operate at higher hydrogen concentrations. Even turbines already equipped with diffusion combustion systems require additional fuel-blending hardware and package safety improvements, and these turbines may also struggle to maintain exhaust NOx emissions within acceptable limits when operating with higher amounts of hydrogen. In many LNG plants, this limits the implementation of Option B to feeds with less than 2% hydrogen in the feed in order to maintain hydrogen concentrations in the fuel below 30%.

[0055] Option C - Hydrogen delivered For LNG plants equipped with gas turbines and containing more than 2% hydrogen in the natural gas feed, and for refrigeration processes equipped with electric motor drives that draw power from the grid, eliminating hydrogen from the system can be an attractive option. The hydrogen can be reinjected into the natural gas pipeline or sent as a crude hydrogen stream for further purification to product / hydrogen pipeline purity. Existing electric motor-driven plants powered by the grid have very low fuel demands, so Option C is the only solution available to maintain 100% LNG production if the feed hydrogen content increases beyond about 100 ppm. As will be explained further, Option C also has significant advantages for gas turbine-driven plants, as it requires fewer modifications to existing equipment than Option B. Optionally, the purified hydrogen stream can be sent to a hydrogen fuel cell, which can be used to generate electricity.

[0056] Evaluated flow schemes To evaluate the impact of hydrogen blended into a natural gas pipeline on downstream LNG plants, several different flow schemes using Option B (hydrogen as fuel) and Option C (shipped hydrogen) were evaluated. The baseline for the study is a typical C3MR liquefaction unit using two industrial frame gas turbine drives producing approximately 5 million metric tons per year (MTPA) of LNG, with fuel requirements based on a 460 MW LHV, assuming typical U.S. Gulf Coast environmental conditions and feed gas composition. The evaluation assumes the retrofitting of an existing plant to process hydrogen-containing feeds, but the results can be applied to new plants. Comparative results for some of the evaluated flow schemes are presented herein.

[0057] Solutions for electric motor driven peak shaver plants were also evaluated. These plants generally have very low fuel demands and require the option to deliver hydrogen in some form.

[0058] A detailed scoring simulation of a typical C3MR liquefaction unit was used to evaluate options for processing feed hydrogen concentrations up to 18%. Propane and mixed refrigerant compressor performance was evaluated using compressor curves, and the heat transfer and pressure drop performance of the coiled main cryogenic heat exchanger (MCHE) was evaluated using a detailed model. Equipment associated with the end flash and boil-off gas (BOG) systems was evaluated using a simplified model, and results were compared to a base case of 0% hydrogen in the feed.

[0059] The available propane and mixed refrigerant power from the two industrial frame gas turbine refrigeration compression drives was fixed at design (base case) values. A parallel driver configuration with dual propane and mixed refrigerant compressors on each drive was assumed. Simulations were run to maximize production, subject to available refrigeration drive power and fuel demand constraints.

[0060] In Option B, where hydrogen from the feed is routed to fuel, the flow scheme is designed to enrich the hydrogen in the fuel stream while maximizing LNG production. This study assumed that the gas turbine fuel efficiency remained the same and was not a function of the hydrogen in the fuel. In both cases, it was assumed that the only fuel demand was the gas turbine fuel demand, with up to 95% of the fuel being provided by end flash and BOG. ​​In the Option B scheme, this fuel balance constraint requires that the hydrogen in the fuel stream be enriched to not exceed the fuel demand, and that the methane flash be suppressed or the methane be recirculated as needed.

[0061] Scheme B1 - No changes to flowsheet Scheme B1 used the system 200 of Figure 2 without any changes to the existing flowsheet. The pressure in the end flash drum 228 was fixed at the base case value of 1.24 bara.

[0062] Scheme B2 - BOG recirculation Schematic B2 shown in Figure 3 illustrates LNG system 300. Elements in system 300 that are shared with system 200 are designated by reference numbers increased by 100. For example, end flash drum 228 in system 200 corresponds to end flash drum 328 in system 300. For clarity, some features of system 300 that are identical to corresponding elements in system 200 are numbered in Figure 3 but are not specifically mentioned herein. Note that system 300 may be structurally similar to existing LNG systems, but operates differently to accommodate hydrogen in feed stream 310, as described below.

[0063] In system 300, the pressure of end flash drum 328 is adjustable, which allows the hydrogen concentration in fuel stream 314 to be controlled to maintain the hydrogen concentration in end flash stream 338 (which becomes fuel stream 314) within a predetermined range. Regulation / control of the pressure in end flash drum 328 can be provided by adjusting the vapor flow rate drawn through end flash compressor 344. Means for adjusting the vapor flow rate through compressor 344 include compressor recirculation, speed control, inlet guide vanes, compressor suction throttling, or other known methods. The pressure of end flash drum 328 can be increased to suppress methane flashing and increase the concentration of hydrogen in fuel stream 314. Increasing the pressure of end flash drum 328 increases flashing in LNG storage tank 336. To compensate for this increase, at least a first portion 364 of the compressed boil-off gas stream is recirculated and combined with the hydrogen-containing natural gas stream 310 upstream of liquefaction unit 318. To match the pressure of hydrogen-containing natural gas stream 310, compressed boil-off gas stream 364 is further compressed in BOG recycle compressor 366 to form further compressed BOG stream 368, which is combined with hydrogen-containing natural gas stream 310. Optionally, a second portion 367 of compressed boil-off gas stream 364 may be added to fuel stream 314, thereby providing an additional means of controlling the hydrogen concentration in fuel stream 314. These means may be implemented with the objective of maintaining a desired heating value in fuel stream 314.

[0064] Scheme B3 - Hydrogen removal using a membrane stage Scheme B3, shown in Figure 4, illustrates an LNG system 400 that uses a membrane stage 470 to remove hydrogen from a compressed end flash stream 441. In system 400, elements shared with system 200 are designated by reference numbers increased by 200. For example, end flash drum 228 of system 200 corresponds to end flash drum 428 of system 400. For clarity, some features of system 400 that are identical to corresponding elements of system 200 are numbered in Figure 4 but are not specifically mentioned herein.

[0065] In system 400, membrane stage 470 is located downstream of end flash compressor 444. Membrane stage 470 may comprise one or more membrane modules arranged in parallel. Permeate stream 472 from membrane stage 470 is enriched in hydrogen and further compressed in hydrogen compressor 474 to form compressed permeate stream 476, which forms at least a portion of fuel stream 414. Optionally, the compressed permeate stream may have the highest hydrogen concentration of any stream within LNG plant 400. Accordingly, at least a portion of the compressed permeate stream may be exported.

[0066] The hydrogen-depleted non-permeate stream 478 can be distributed in one or more ways depending on the needs of the system 400. At least a portion 483 of the non-permeate stream 478 can be compressed in an end flash recycle compressor 480 to form a compressed recycle stream 482, which is combined with a portion 448 of the hydrogen-containing natural gas stream 410 upstream of the end flash heat exchanger 440. At least a portion 484 of the non-permeate stream 478 can be mixed with the fuel stream 414, thereby reducing the hydrogen concentration in the fuel stream 414. A valve 485 schematically represents a means for controlling the flow of the non-permeate stream 478 to portions 483, 484.

[0067] Scheme C1 - Hydrogen Flash Drum Scheme C1 shown in Figure 5 illustrates an LNG system 500 configured to produce a crude hydrogen stream 586 containing at least 50 mole percent hydrogen. The crude hydrogen stream 586 may be sent to a hydrogen purification unit to produce product-grade hydrogen for delivery or may be returned to the pipeline downstream of the liquefaction unit 518. In system 500, elements shared with system 200 are designated by reference numerals increased by 300. For example, end flash drum 228 of system 200 corresponds to end flash drum 528 of system 500. Similarly, elements shared with system 400 are designated by reference numerals increased by 100. For clarity, some features of system 500 that are identical to corresponding elements of systems 200 and / or 400 are numbered in Figure 5 but are not specifically mentioned herein.

[0068] Expanded LNG stream 526 is first sent to crude hydrogen flash drum 583. The operating pressure of crude hydrogen flash drum 583 can be selected to produce crude hydrogen stream 585 having a hydrogen concentration of at least 50 mole percent. Refrigeration from crude hydrogen stream 585 is recovered in hydrogen flash exchanger 581 to cool portion 549 of hydrogen-containing natural gas stream 510 to produce cooled additional LNG stream 551. Cooled additional LNG stream 551 exits hydrogen flash exchanger 581, where it is expanded through expansion valve 553 to form expanded additional LNG stream 555. Expanded additional LNG stream 555 is combined with expanded LNG stream 526 and introduced into crude hydrogen flash drum 583.

[0069] LNG stream 587 from crude hydrogen flash drum 583 is then expanded through expansion valve 588 to form expanded LNG stream 589. Expanded LNG stream 589 is then sent to end flash drum 528. The remaining elements of system 500 are very similar to system 200 of FIG.

[0070] result All four schemes were simulated while increasing the amount of hydrogen in the feed. Figure 6 shows the maximum production available from the considered flow schemes as a function of feed hydrogen content ranging from 0 to 5%. Results are based on simulations with constraints on the power available from two industrial flame drives and the overall plant fuel balance.

[0071] Figure 7 shows the specific power in kWh per ton of LNG consumed by the end flash (244, 344, 444, 544), BOG (260, 360, 460, 560), end flash recycle (480), BOG recycle (366), and hydrogen compressor (474). The power available for the end flash and BOG compressors was not limited to base case values, and it was assumed that these compressors would be modified or replaced as needed to maximize production. No fuel balance was taken into account in the power required for these electric motor-driven compressors. Only refrigerant-driven units were considered in the fuel requirement calculations.

[0072] Scheme B1 - No changes to flowsheet Maintaining the desired steam flow rate from the end flash drum 228 in an existing LNG plant requires a significant reduction in production without adding new equipment. This is because the liquefied natural gas stream 220 exiting the liquefaction unit 218 must be cooler to suppress flashing so as not to exceed fuel requirements and maintain fuel balance. For example, the end flash steam heating value (energy / hour, e.g., Btu / s or MW) produced with 3% hydrogen in the feed can be 88% higher than that produced with 0% hydrogen in the feed for the same liquefaction unit outlet temperature and end flash drum pressure. With 3% hydrogen in the feed, the reduction in liquefaction unit outlet temperature required to maintain the same fuel stream heating value as with 0% hydrogen in the feed results in a 6.7% reduction in production in stationary drive power.

[0073] FIG. 7 shows that for 3% hydrogen in the hydrogen-containing natural gas feed stream 210, the power consumed by the end flash compressor 244 and BOG compressor 260 nearly doubles relative to the base case (no hydrogen in the feed stream 210). Most of the increase is primarily due to an increase in the output of the end flash compressor 244. With only 0.5% hydrogen in the feed, the end flash compressor 244 requires modification to accommodate the lower molecular weight and increased volumetric flow rate of the resulting end flash stream 238. Aerodynamic modifications, including impeller changes or increased rotational speed, can be achieved with a more powerful drive motor. Hydrogen concentrations above 0.5% in the hydrogen-containing natural gas feed stream 210 require the end flash compressor 244 to be replaced or a new parallel compression string to be added.

[0074] Scheme B2 - BOG recirculation In this configuration, the pressure of the end flash drum 328 is controlled to reduce flashing, adding another degree of operational freedom in maintaining the proper fuel balance and enabling the plant to achieve 100% LNG production for hydrogen concentrations up to approximately 3% in the hydrogen-containing natural gas stream 310 ( FIG. 3 ). However, this recovery production comes with additional operating costs. Note in FIG. 7 that the power consumed by the rear-end compression (consisting of the end flash gas compressor 344, BOG compressor 360, and additional BOG recycle compressor 366 in this scheme) is more than twice that of the base case of 3% hydrogen in the hydrogen-containing natural gas stream 310. Higher end flash drum 328 pressure shifts the adiabatic flash from the end flash drum 328 to the storage tank 336, significantly increasing the required BOG compression power. Above 3% hydrogen in the feed, 100% design LNG production is not possible with this scheme for research conditions.

[0075] Scheme B3 - Hydrogen removal using a membrane stage In this scheme, a membrane stage 470 is added to concentrate the hydrogen in the fuel stream 414. This scheme allows for 100% LNG production with 5% hydrogen in the hydrogen-containing natural gas stream 410, but at higher operating costs. Note that the power of the hydrogen compressor 474 to compress the permeate stream 472 is included in Figure 7.

[0076] In addition to the new end flash recycle compressor 480, membrane stage, and permeate hydrogen compressor 474, the existing end flash compressor 444 would also have to be modified or replaced at the higher hydrogen concentration because the new operating conditions are significantly different.

[0077] With significant plant modifications, both Schemes B2 and B3 are capable of producing their original design LNG output with 3% hydrogen in the hydrogen-containing natural gas stream 310, 410. However, the resulting fuel stream 314, 414 to the turbine contains 40% hydrogen by volume. The current class of industrial frame gas turbine drivers is not designed to operate with hydrogen concentrations greater than 30% when equipped with dry low-emission (DLE) combustion systems, but turbines with diffusion combustion systems may require additional NOx reduction hardware. Turbines must undergo material and packaging safety studies to evaluate high hydrogen concentrations in the fuel system, and gas turbine OEMs should be considered for fuel compositions with more than 10% hydrogen.

[0078] 3 and 4, the hydrogen-rich stream (338, 472) may be sent as crude hydrogen instead of being sent to a fuel stream, or sent to a purification unit and sent as hydrogen product. Fuel requirements, if any, can be met by the hydrogen-lean stream (367, 478).

[0079] Scheme C1 - Hydrogen Flash Drum In Scheme C1, hydrogen is rejected into a stream containing 50% (molar) hydrogen (crude hydrogen stream 585), which may be sent for further purification to product-grade hydrogen or returned to the pipeline.

[0080] The production shown in Figure 6 decreases with increasing hydrogen content in the hydrogen-containing natural gas stream 510, reaching a decrease of approximately 2% at 5% hydrogen in the feed. This production loss is primarily due to the loss of cooling provided by the LNG hydro turbine (not shown). As the hydrogen in the feed increases, the turbine discharge pressure increases to prevent steam from forming within the turbine. At 5% hydrogen, the discharge pressure approaches the inlet pressure and the turbine is bypassed. However, this production loss could be eliminated by adding an end flash recycle compressor 566 (dashed line).

[0081] This scheme minimizes the modifications required to existing LNG plants and the downtime required to implement them. For electric motor-driven LNG plants with low fuel consumption, eliminating hydrogen from the process is the only feasible solution evaluated for feed hydrogen contents above 200-500 PPM.

[0082] FIG. 8 illustrates another exemplary implementation of an LNG system 600 equipped with a hydrogen cooling box. In system 600, elements shared with system 200 are designated by reference numbers increased by 400. For example, end flash drum 228 of system 200 corresponds to end flash drum 628 of system 600. Similarly, elements shared with system 300 are designated by reference numbers increased by 300. For example, recycle compressor 366 of system 300 corresponds to BOG recycle compressor 666 of system 600. For clarity, some features of system 600 that are identical to corresponding elements of systems 200 and / or 300 are numbered in FIG. 8 but are not specifically mentioned herein.

[0083] In system 600, end flash drum 628 operates at a pressure between 1.5 bara and 55 bara. Hydrogen-enriched vapor 638 from end flash drum 628 is cooled and partially liquefied in heat exchanger 643. The two-phase mixture 627 is separated in separator 629 into further hydrogen-enriched vapor 631 and methane-enriched liquid 633. The further hydrogen-enriched vapor is warmed in heat exchanger 643 and end flash exchanger 640 to form crude hydrogen product 637. The crude hydrogen product may be reinjected into the natural gas pipeline or further refined to produce a pure hydrogen product.

[0084] Methane-enriched liquid 633 is expanded through valve 635 and warmed in heat exchanger 643 to produce intermediate methane stream 641, which is then sent to BOG compressor 660. At least a portion 625 of intermediate methane stream 641 may be warmed in end flash exchanger 640 to produce warm methane-enriched vapor 642 and compressed in end flash compressor 644 to form fuel stream 614. At least a portion 639 of crude hydrogen product 637 may be combined with warm methane-enriched vapor 642 to provide additional fuel. At least a portion 615 of hydrogen-enriched vapor 638 may bypass heat exchanger 643 and be sent to at least a portion of intermediate methane stream 625.

[0085] LNG stream 630 is sent to a storage tank. BOG stream 656 and intermediate methane stream 641 are compressed in BOG compressor 660 to form compressed boil-off gas stream 664, which may be compressed in BOG recycle compressor 666 to form further compressed BOG stream 668, which is combined with hydrogen-containing natural gas feed stream 610. At least a portion 667 of compressed boil-off gas stream 664 may be sent to fuel stream 614.

[0086] Figure 9 is a table showing modeled system parameters for the example implementation of Figure 8 for a range of hydrogen concentrations in feed gas stream 610. Note that the temperature of LNG stream 620 is warmest when the hydrogen concentration in feed gas stream 610 is 10%. It should also be noted that LNG production begins to decline when the hydrogen concentration in feed gas stream 610 exceeds 3%.

[0087] FIG. 10 shows another exemplary implementation of an LNG system 700 in which a feed gas stream 710 is pretreated to remove some hydrogen from the gas stream prior to liquefaction. In system 700, elements shared with system 200 are designated by reference numbers increased by 500. For example, end flash drum 228 of system 200 corresponds to end flash drum 728 of system 700. Similarly, elements shared with system 300 are designated by reference numbers increased by 400. For example, recycle compressor 366 of system 300 corresponds to recycle compressor 766 of system 700. For clarity, some features of system 700 that are identical to corresponding elements of systems 200 and / or 300 are numbered in FIG. 10 but are not specifically mentioned herein.

[0088] In system 700, feed gas stream 710 passes through membrane module 763 prior to liquefaction to form a hydrogen-enriched permeate stream 765 and a hydrogen-lean retentate stream 771, which can be liquefied in liquefaction unit 718 with lower power consumption than required to liquefy feed gas stream 710. A bypass stream 773 is provided to allow for bypassing membrane module 763 when the hydrogen concentration in feed gas stream 710 is low enough that pre-liquefaction hydrogen removal is not necessary. The hydrogen-lean retentate stream 771 is combined with further compressed BOG stream 768 upstream of liquefaction. The hydrogen-enriched permeate stream 765 is compressed in compressor 767 to form fuel stream 714. A portion 759 of the warmed and compressed end flash stream 797 and a portion 793 of BOG stream 764 can be combined with fuel stream 714. The hydrogen-enriched permeate stream 765 may alternatively be sent to a natural gas pipeline or may be further purified to produce a hydrogen product.

[0089] Another exemplary implementation of an LNG plant 800 is shown in FIG. 11. In this LNG plant 800, a feed gas stream 810 is processed in a pretreatment unit 875 to remove CO, water, and heavy hydrocarbons to produce a pretreated feed gas stream 876. Pretreatment to remove CO is typically accomplished by adsorption in an acid gas removal unit. Water removal can be achieved by cooling the natural gas to promote condensation of bulk water, followed by dehydration in an adsorption unit. Heavy hydrocarbon removal can be achieved by adsorption, partial condensation, distillation, or a combination thereof. The pretreated feed gas stream 876 is then compressed in a compressor 877 to produce a compressed pretreated feed gas stream 879, which is cooled in exchanger 881 with ambient air heat, cooling water, or another cooling medium such as propane, an HFC, or a mixed refrigerant to produce a cooled pretreated gas stream 886. Cooled, pretreated gas stream 886 then passes through membrane module 863 to form a hydrogen-enriched permeate stream 878 and a hydrogen-depleted retentate stream 872. The hydrogen-depleted retentate stream 872 is optionally compressed and cooled (via compressor 893 and heat exchanger 894) before being liquefied.

[0090] Hydrogen-enriched permeate stream 878 is then compressed in compressor 867 to form compressed hydrogen-enriched permeate stream 869. Compressed hydrogen-enriched permeate stream 869 is then processed using pressure swing adsorption unit 887 to produce purified hydrogen stream 888 and hydrogen-lean stream 889. Purified hydrogen stream 888 can have a hydrogen concentration of at least 90%. Hydrogen-lean stream 889 is combined with end flash stream 838 and then compressed using end flash compressor 844 to produce fuel stream 814.

[0091] Another exemplary implementation of an LNG plant 900 is shown in Figure 12. LNG plant 900 is very similar to LNG plant 800, with the main difference being the inclusion of two end flash drums 983 and 928 in series. An end flash stream 990 from the first end flash drum 983 is combined with the hydrogen-enriched permeate stream 978 before compression. An LNG stream 987 from the first end flash drum 983 is further separated in the second end flash drum 928. An end flash stream 938 from the second end flash drum 928 is combined with a hydrogen-lean stream 989 upstream of the end flash compressor 944. An LNG stream 930 from the second end flash drum 928 is then sent to an LNG storage facility (not shown).

[0092] The present invention is not limited in scope by the specific aspects or embodiments disclosed in the examples which are intended to be illustrative of some aspects of the invention; any embodiments which are functionally equivalent are within the scope of the invention. Various modifications of the invention in addition to those shown and described herein will become apparent to those skilled in the art and are intended to be included within the scope of the appended claims.

Claims

1. (a) cooling and liquefying a hydrogen-containing natural gas feed stream in a natural gas liquefaction plant to form a liquefied natural gas stream; (b) reducing the pressure of the liquefied natural gas stream to form an expanded LNG stream; (c) separating the expanded LNG stream in a first end flash unit into a first end flash stream and a hydrogen-lean LNG stream, the first end flash stream having a higher hydrogen concentration than the hydrogen-containing natural gas feed stream, and the hydrogen-lean LNG stream having a lower hydrogen concentration than the hydrogen-containing natural gas feed stream; (d) further processing the first end flash stream and / or the hydrogen-depleted LNG stream to form a gaseous hydrogen-depleted stream and a gaseous hydrogen-enriched stream; A method comprising:

2. 10. The method of claim 1, wherein step (d) is carried out using at least one selected from the group of at least one membrane stage, at least one adsorption stage, a partial condensation stage, a distillation stage, a stripping stage, and an electrochemical membrane stage.

3. 10. The method of claim 1, wherein the first end flash unit is a gas-liquid separator.

4. 10. The process of claim 1, wherein the first end flash unit is a distillation column.

5. 10. The method of claim 1, further comprising: (e) compressing the gaseous hydrogen-enriched stream and using it as a fuel stream.

6. The method of claim 5 , wherein the fuel stream is for a gas turbine, a boiler, or a furnace.

7. 10. The method of claim 1, further comprising: (f) further processing the gaseous hydrogen-rich stream to form a purified hydrogen stream having a hydrogen concentration of at least 90%.

8. 8. The method of claim 7, further comprising: (g) passing the purified hydrogen stream to a fuel cell to produce electricity.

9. 8. The method of claim 7, further comprising: (h) sending the purified hydrogen stream to a hydrogen pipeline.

10. The method of claim 1 further comprising: (i) directing at least a portion of the gaseous hydrogen-lean stream to a fuel stream.

11. 10. The method of claim 1, further comprising: (j) directing at least a portion of said gaseous hydrogen-lean stream to a recycle stream that is combined with said hydrogen-containing natural gas feed stream upstream of step (a).

12. 10. The method of claim 1, further comprising: (k) controlling the pressure of the separator in which step (c) is performed to maintain the hydrogen concentration in the first end flash stream within a first predetermined range.

13. 10. The method of claim 1, further comprising: (l) pretreating the hydrogen-containing natural gas feed stream upstream of step (a) to produce a pretreated hydrogen-containing natural gas feed stream and a hydrogen-enriched pretreated stream, wherein the pretreated hydrogen-containing natural gas feed stream has a lower hydrogen concentration than the hydrogen-containing natural gas feed stream.

14. 14. The method of claim 13, further comprising: (m) passing the hydrogen-enriched pretreated stream to a fuel stream.

15. 14. The method of claim 13, further comprising: (n) performing step (a) on the pretreated hydrogen-containing natural gas feed stream.

16. 14. The method of claim 13, further comprising: (o) purifying the hydrogen-enriched pretreated stream to form a purified hydrogen stream having a hydrogen concentration of at least 90%.

17. 17. The method of claim 16, further comprising carrying out step (o) using at least one adsorption bed.

18. (a) cooling and liquefying a hydrogen-containing natural gas feed stream in a natural gas liquefaction plant having at least one gas turbine driven refrigeration compressor to form a liquefied natural gas stream; (b) using the fuel stream to drive at least one of the at least one gas turbine driven refrigeration compressor; (c) reducing the pressure of the liquefied natural gas stream to form an expanded LNG stream; (d) separating the expanded LNG stream into an end flash stream and a hydrogen-depleted LNG stream in an end flash separator, the end flash stream having a higher concentration of hydrogen than the hydrogen-containing natural gas feed stream; (e) compressing the end flash stream to form a compressed end flash stream; (f) storing the hydrogen-depleted LNG stream in an LNG storage tank; (g) compressing a BOG stream from the LNG storage tank to form a compressed BOG stream; (h) further compressing the compressed BOG stream to form a further compressed BOG stream; (i) combining said further compressed BOG stream with said hydrogen-containing natural gas feed stream upstream of carrying out said step (a); Including, The method, wherein the fuel stream comprises the compressed end flash stream.

19. (j) diverting a first portion of the BOG stream upstream of step (h); (k) combining the first portion of the BOG stream with the end flash stream to form the fuel stream; 20. The method of claim 17, further comprising:

20. (a) cooling and liquefying a hydrogen-containing natural gas feed stream in a natural gas liquefaction plant to form a liquefied natural gas stream; (b) reducing the pressure of the liquefied natural gas stream to form an expanded LNG stream; (c) separating the expanded LNG stream in a first end flash unit into a first end flash stream and a hydrogen-lean LNG stream, the first end flash stream having a higher hydrogen concentration than the hydrogen-containing natural gas feed stream, and the hydrogen-lean LNG stream having a lower hydrogen concentration than the hydrogen-containing natural gas feed stream; (d) compressing the end flash stream using an end flash compressor to form a compressed end flash stream; (e) using the compressed end flash stream as a fuel stream; (f) controlling the pressure at which the end flash compressor operates to maintain a hydrogen concentration in the fuel stream within a predetermined range; A method comprising:

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