Liquefaction of natural gas feed containing hydrogen

Abstract

Liquefaction systems and methods suitable for processing a natural gas stream having a high concentration of hydrogen and wherein the hydrogen concentration may vary in the natural gas stream are disclosed. In some embodiments, 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 embodiments, the pressure of the end flash compressor may be controlled to maintain the hydrogen concentration in a fuel stream, typically the end flash stream, within a desired range. Some embodiments may include pre-or post-liquefaction purification using, for example, membranes, adsorption, partial condensation, distillation, stripping, and electrochemical membranes.

Description

Background Art

[0001] Blending green or blue hydrogen into existing natural gas pipelines is being discussed and studied globally as a way to reduce carbon footprint. Blue hydrogen is formed by reacting natural gas into hydrogen and carbon dioxide ("CO2") through processes such as steam methane reforming ("SMR") or autothermal reforming ("ATR"), where the CO2 is captured and then stored. Green hydrogen is produced by electrolyzing water with renewable energy. One concept involves producing green hydrogen and injecting that hydrogen into nearby natural gas pipelines. In essence, these pipelines would serve as storage devices and conduits for renewable energy.

[0002] Many countries and regions are considering hydrogen blending as an intermediate step in the process of "net zero carbon by 2050". The U.S. Department of Energy has conducted research on the effects of hydrogen blending on metallurgy and leakage rates. Various resources have proposed that up to 20% hydrogen can be blended into natural gas without adversely affecting pipeline metals and downstream equipment. The California Public Utilities Commission has studied hydrogen blending and has determined that blends of up to 5% hydrogen are generally safe, and confirmed that there is a high chance of pipeline leaks and steel pipeline embrittlement in the case of hydrogen blending. Some utilities are starting small-scale trials. The concentration of hydrogen in natural gas pipelines may also change over time.

[0003] If implemented, these proposals would impose significant costs and challenges on liquefied natural gas ("LNG") production units that draw from pipelines with hydrogen blending. It is not feasible to liquefy hydrogen into the LNG product at concentrations above a few hundred parts per million ("PPM"). Hydrogen can be discharged from the natural gas feed into a fuel stream for gas turbine drives or other uses, but will be present in the fuel stream at concentrations many times that in the natural gas feed. Because hydrogen has different thermophysical properties from natural gas, its presence in the fuel stream for gas turbine drives will result in operational impacts on the fuel stream, fuel compressors, burner flame characteristics, and NOx emissions. Many gas turbine drives will require significant modifications to operate using fuel streams with hydrogen concentrations above 20%-30%. Potential changes in hydrogen concentrations in natural gas pipelines pose a challenge to fuel balance in LNG units. Therefore, innovative solutions are needed to effectively enable natural gas feeds with hydrogen blending to be used in LNG units. Summary of the invention

[0004] The present invention summary is provided to introduce a series of concepts in simplified form, which are further described in the detailed description below. The present invention summary is not intended to identify the 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 system and method are summarized below.

[0005] refer to Figure 1 , the exemplary embodiments disclosed herein meet the needs of 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 can be used as a fuel, output (e.g., to a source pipeline or another pipeline) or further purified to form a purified hydrogen stream. The gaseous hydrogen-rich stream 114 is a mixture consisting mainly of methane, nitrogen and hydrogen, and has a higher hydrogen concentration than the blended hydrogen natural gas feed stream 110. A gaseous hydrogen-depleted stream 112 is also produced, which can be recycled into the feed stream 110. The gaseous hydrogen-depleted stream 112 is a mixture consisting mainly of methane, nitrogen and hydrogen, and has a lower hydrogen concentration than the blended hydrogen natural gas feed stream. Conventionally, an LNG product stream is also produced, which is preferably lacking in hydrogen relative to the blended hydrogen natural gas feed stream 110.

[0006] Several aspects of the systems and methods are

[0007] Aspect 1: A method, comprising:

[0008] (a) cooling and liquefying a hydrogen-containing natural gas feed stream in a natural gas liquefaction unit to form a liquefied natural gas stream;

[0009] (b) reducing the pressure of the liquefied natural gas stream to form an expanded LNG stream;

[0010] (c) separating the expanded LNG stream in a first terminal flash unit into a first terminal flash stream and a hydrogen-depleted LNG stream, wherein the first terminal flash stream has a higher hydrogen concentration than the hydrogen-containing natural gas feed stream and the hydrogen-depleted LNG stream has a lower hydrogen concentration than the hydrogen-containing natural gas feed stream; and

[0011] (d) further processing the first terminal flash stream and / or the hydrogen-depleted LNG stream to form a gaseous hydrogen-depleted stream and a gaseous hydrogen-rich stream.

[0012] Aspect 2: The method according to aspect 1, wherein step (d) is performed using at least one selected from the group consisting 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.

[0013] Aspect 3: The method according to any one of aspects 1 to 2, wherein the first terminal flash unit is a vapor liquid separator.

[0014] Aspect 4: The method according to any one of aspects 1 to 2, wherein the first terminal flash unit is a distillation column.

[0015] Aspect 5: The method according to any one of aspects 1 to 4, further comprising:

[0016] (e) compressing the gaseous hydrogen-rich stream and using it as a fuel stream.

[0017] Aspect 6: The method according to aspect 5, wherein the fuel stream is used in a gas turbine, a boiler or a fired heater.

[0018] Aspect 7: The method according to any one of aspects 1 to 6, further comprising:

[0019] (f) further processing the gaseous hydrogen-rich stream to form a purified hydrogen stream having a hydrogen concentration of at least 90%.

[0020] Aspect 8: The method according to Aspect 7, further comprising:

[0021] (g) sending the purified hydrogen gas stream to a fuel cell to generate electricity.

[0022] Aspect 9: The method according to aspect 7 further comprises:

[0023] (h) sending the purified hydrogen gas stream to a hydrogen pipeline.

[0024] Aspect 10: The method according to any one of aspects 1 to 9, further comprising:

[0025] (i) passing at least a portion of the gaseous hydrogen-depleted stream to a fuel stream.

[0026] Aspect 11: The method according to any one of aspects 1 to 10, further comprising:

[0027] (j) sending at least a portion of the gaseous hydrogen-depleted stream to a recycle stream which is combined with the hydrogen-containing natural gas feed stream upstream of step (a).

[0028] Aspect 12: The method according to any one of aspects 1 to 11, further comprising:

[0029] (k) controlling the pressure of the separator during step (c) so as to maintain the hydrogen concentration in the first terminal flash stream within a first predetermined range.

[0030] Aspect 13: The method according to aspect 1, further comprising:

[0031] (1) 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, the pretreated hydrogen-containing natural gas feed stream having a lower hydrogen concentration than the hydrogen-containing natural gas feed stream.

[0032] Aspect 14: The method according to Aspect 13, further comprising:

[0033] (m) sending the hydrogen-rich pretreated stream to a fuel stream.

[0034] Aspect 15: The method according to any one of aspects 13 to 14, further comprising:

[0035] (n) performing step (a) on the pretreated hydrogen-containing natural gas feed stream.

[0036] Aspect 16: The method according to Aspect 13, further comprising:

[0037] (o) purifying the hydrogen-rich pretreatment stream to form a purified hydrogen stream having a hydrogen concentration of at least 90%.

[0038] Aspect 17: The method according to aspect 16, further comprising performing step (o) using at least one adsorption bed.

[0039] Aspect 18: A method, comprising:

[0040] (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;

[0041] (b) using the fuel flow to drive at least one refrigeration compressor of the at least one gas turbine driven refrigeration compressor;

[0042] (c) reducing the pressure of the liquefied natural gas stream to form an expanded LNG stream;

[0043] (d) separating the expanded LNG stream into a terminal flash stream and a hydrogen-depleted LNG stream in a terminal flash separator, the terminal flash stream having a higher hydrogen concentration than the hydrogen-containing natural gas feed stream;

[0044] (e) compressing the terminal flash stream to form a compressed terminal flash stream;

[0045] (f) storing the hydrogen-depleted LNG stream in an LNG storage tank;

[0046] (g) compressing the BOG stream from the LNG storage tank to form a compressed BOG stream;

[0047] (h) further compressing the compressed BOG stream to form a further compressed BOG stream; and

[0048] (i) combining the further compressed BOG stream with the hydrogen-containing natural gas feed stream upstream of performing step (a);

[0049] Wherein the fuel stream comprises the compressed end flash stream.

[0050] Aspect 19: The method according to Aspect 18, further comprising:

[0051] (j) transferring a first portion of the BOG stream upstream of step (h); and

[0052] (k) combining the first portion of the BOG stream with the tip flash stream to form the fuel stream.

[0053] Aspect 20: A method, comprising:

[0054] (a) cooling and liquefying a hydrogen-containing natural gas feed stream in a natural gas liquefaction unit to form a liquefied natural gas stream;

[0055] (b) reducing the pressure of the liquefied natural gas stream to form an expanded LNG stream;

[0056] (c) separating the expanded LNG stream in a first terminal flash unit into a first terminal flash stream and a hydrogen-depleted LNG stream, wherein the first terminal flash stream has a higher hydrogen concentration than the hydrogen-containing natural gas feed stream and the hydrogen-depleted LNG stream has a lower hydrogen concentration than the hydrogen-containing natural gas feed stream;

[0057] (d) compressing the terminal flash stream using a terminal flash compressor to form a compressed terminal flash stream;

[0058] (e) using the compressed end flash stream as a fuel stream; and

[0059] (f) controlling the pressure at which the terminal flash product compressor is operated to maintain the hydrogen concentration in the fuel stream within a predetermined range.

[0060] For electric motor driven plants that draw power from the grid and have low fuel requirements, hydrogen blowdown is required. This can be done at the cold end of the plant in a terminal flash system. The system can be designed to produce an output stream containing greater than 50% hydrogen. A number of separation schemes can also be used to remove hydrogen from the front end of the plant. However, front end removal of hydrogen requires processing of the entire feed stream, while removal of hydrogen from the back end involves processing of a flash stream that is a small portion of the total feed stream.

[0061] For gas turbine driven plants where the feed hydrogen content exceeds about 0.5% and the hydrogen is sent to the fuel, the end flash stream will be rich in hydrogen and modifications to the existing end flash compression system will be required. For feeds containing greater than 2% hydrogen, the fuel stream will be highly rich in hydrogen and major modifications to the gas turbine combustion and fuel systems will be required if the hydrogen is not exported. There are many possible schemes for producing a hydrogen / methane mixture suitable for export. The best scheme will depend on the destination of the export stream. If there is a local market demand for hydrogen, the hydrogen exported from the LNG plant can be further processed into a saleable product. BRIEF DESCRIPTION OF THE DRAWINGS

[0062] Exemplary embodiments will hereinafter be described with reference to the accompanying drawings, wherein like reference numerals refer to like elements.

[0063] Figure 1 is a schematic flow diagram depicting three streams formed from a blended hydrogen natural gas feed stream in an LNG plant;

[0064] Figure 2 is a schematic flow diagram depicting an LNG plant without flow diagram modifications to the prior art;

[0065] Figure 3 is a schematic flow diagram depicting an LNG plant in which a boil-off gas ("BOG") recycle compressor is added to recycle low hydrogen content BOG and storage tank flash to the feed;

[0066] Figure 4 is a schematic flow diagram depicting an LNG plant depicting the use of a back-end membrane to remove hydrogen to fuel;

[0067] Figure 5 is a schematic flow diagram depicting an LNG plant having a double-ended flash configuration;

[0068] Figure 6 It is shown from Figures 2 to 5 A graph showing the maximum yield achievable in an exemplary embodiment as a function of feed hydrogen content ranging from 0% to 5%;

[0069] Figure 7 It is shown Figures 2 to 5 A graph of the specific power requirement of an exemplary embodiment shown as a function of feed hydrogen content ranging from 0% to 5%;

[0070] Figure 8 is a schematic flow diagram depicting an LNG plant showing terminal flash product H2 separation;

[0071] Fig. 9 It is shown Figure 8a table of modeled system parameters of an exemplary embodiment of;

[0072] Fig.10 is a schematic flow diagram depicting an LNG plant having a front-end membrane;

[0073] Fig.11 is a schematic flow diagram depicting an LNG plant with a front-end membrane and further purification of the permeate stream using adsorption; and

[0074] Fig.12 yes Fig.11 An LNG plant is shown modified to provide a double end flash. DETAILED DESCRIPTION

[0075] The detailed description that follows only provides preferred exemplary embodiments and is not intended to limit the scope, applicability or configuration of the present invention. On the contrary, the detailed description that follows of the preferred exemplary embodiments will provide a kind of enabling description for realizing the preferred exemplary embodiments of the present invention for those skilled in the art. It should be understood that various changes may be made to the functions and arrangements of the elements without departing from the spirit and scope of the present invention.

[0076] To aid in describing the present invention, directional terms may be used in this specification and claims to describe portions of the present invention (e.g., up, down, left, right, etc.). These directional terms are intended only to aid in describing and claiming the present invention and are not intended to limit the present invention in any way. In addition, reference numerals introduced in association with the accompanying drawings in this specification may be repeated in one or more subsequent drawings without additional description in the specification in order to provide context for other features.

[0077] Unless otherwise indicated, the articles "a" and "an" as used herein, when applied to any feature in the embodiments of the invention described in this specification and claims, mean one or more. The use of "a" and "an" does not limit the meaning to a single feature unless such limitation is specifically stated. The article "the" preceding a singular or plural noun or noun phrase indicates one specific specified feature or a plurality of specific specified features and may have a singular or plural meaning depending on the context in which it is used.

[0078] The term "conduit" as used in this 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, a conduit may include a tube, a pipe, a passage, and combinations thereof that transport liquids, vapors, and / or gases.

[0079] The term "natural gas" as used in this specification and claims means a hydrocarbon gas mixture consisting primarily of methane. As used herein, the term "natural gas" also encompasses synthetic natural gas and alternative natural gas. A natural gas feed stream comprises methane and nitrogen (of which methane is typically the major component).

[0080] 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 "hydrogen-blended natural gas stream".

[0081] Unless otherwise specified herein, any and all percentages identified in this specification, drawings, and claims should be understood to be based on mole percentages. Unless otherwise specified herein, any and all pressures identified in this specification, drawings, and claims should be understood to mean metered pressures.

[0082] As used in this specification and 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. In an alternative example, a compression system may include multiple compressors.

[0083] In the claims, letters are used to identify claimed steps (e.g., (a), (b), and (c). These letters are used to help refer to method steps and are not intended to indicate the order in which the claimed steps are performed, unless and only if such an order is specifically recited in the claims.

[0084] The term "membrane module" as used in this specification and claims means a device for selectively separating gases by causing a feed gas to flow through one or more conduits contained in a shell (also referred to as a high-pressure side) at a relatively high pressure. The conduit is at least partially defined by a membrane material that provides a barrier between each conduit and a shell space (also referred to as a low-pressure side). The shell space is an internal volume within the shell and outside each membrane that is maintained at a relatively low pressure. The shell side is fluidly connected to a permeate port, and the gas that permeates the membrane leaves the shell through the permeate port. Optionally, a purge port may also be provided that supplies a purge gas to the shell space and helps the permeate gas flow through the permeate port. The membrane material is selected so that one or more gases in the feed stream (referred to as permeate gas) can pass through the membrane material at a higher rate than other gases in the feed gas stream (referred to as non-permeate gas or product gas). The membrane module may have an orifice-side feed design, in which the membrane module is pressurized by introducing a feed gas stream into its orifice side, or may have a shell-side feed design, in which the membrane module is pressurized by introducing a feed gas stream into its shell side.

[0085] When used herein to identify stated features of a method or system, the terms "first," "second," "third," etc. are merely used to help refer to and distinguish the features in question, and are not intended to indicate any particular order of the features, unless and only if such an order is specifically stated.

[0086] As used herein, the term "fuel stream" means a gaseous stream used to provide fuel to a portion of an LNG plant, such as a gas turbine or a steam generating system such as a boiler, fired heater or other combustion equipment.

[0087] As used herein, reference to a product stream from a gas separation process being "enriched" in a particular gas or component means that the product stream has a higher mole % of the particular gas or component than the feed stream supplied to the gas separation process. Non-limiting examples of fluid separation processes include separation drums, distillation columns, stripping columns, adsorption, membrane separations, and electrochemical separations.

[0088] As used herein, the term "fluid flow communication" refers to the connectivity between two or more components, so that liquid, steam and / or two-phase mixture can be directly or indirectly transported between components in a controlled manner (that is, without leakage). Two or more components are connected so that they are fluid flow connected to each other and can involve any suitable method known in the art, such as using welding, flanged conduits, washers and bolts. Two or more components can also be connected together via other components (for example, valves, doors or other devices that can selectively limit or guide fluid flow) of the system that can separate them. As used herein, the term "conduit" refers to one or more structures, and fluid can be transported between two or more components of the system by these structures. For example, a conduit may include a pipe, a pipeline, a passage and a combination thereof for transporting liquid, steam and / or gas.

[0089] See again Figure 1 , the hydrogen in the feed gas 110 may enter three locations in the LNG liquefaction unit 100. One option (option A) is to leave the hydrogen in the LNG product 116. The second option (option B) is to use the hydrogen for at least a portion of the fuel requirements of the system 100, typically as a fuel for the gas turbine that drives the refrigerant compressor. The third option (option C) is to export the hydrogen from the system 100, typically for further purification into a hydrogen product or return to the natural gas pipeline downstream of the liquefier. Option A is not practical for natural gas feeds with an excess of several hundred PPM of hydrogen due to the required cold liquefaction temperature. For both options B and C, a stream 114 can be formed to transfer the hydrogen to a fuel consumer (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 recycled to another location within the LNG unit.

[0090] Figure 2 A conventional natural gas LNG system 200 is shown. In the system 200, a hydrogen-containing natural gas feed stream 210 is cooled and liquefied in a liquefaction unit 218 using a liquefaction method (such as a conventional C3MR, DMR, SMR, pure component cascade, reverse Brandon cycle or other liquefaction method) to form a liquefied natural gas stream 220. The stream 210 may be at a pressure of 30 bara to 80 bara or higher, and at a temperature of near ambient temperature or precooled to -30 degrees Celsius to -60 degrees Celsius by a precooling system. The stream 220 may be at a pressure of 30 bara to 70 bara or higher, and at a temperature of -130 degrees Celsius to -155 degrees Celsius or colder. The liquefied natural gas stream 220 is expanded through a 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 expansion through the valve 224. The optional inclusion of a hydraulic turbine is applicable to all exemplary embodiments described herein.

[0091] The expanded LNG stream 226 is then separated into a terminal flash stream 238 (which is hydrogen-rich relative to the feed stream 210) and an LNG stream 230 (which is hydrogen-deficient relative to the feed stream 210) in the terminal flash tank 228. In this exemplary embodiment, the pressure of the terminal flash tank 228 is fixed, for example, at a fixed pressure between 1.0 bara and 1.5 bara. The LNG stream 230 is expanded via an expansion valve 232, and the expanded LNG stream 234 flows into the LNG storage tank 236. The stream 230 may be pumped to a higher pressure such as 7 bara to 10 bara before the valve 232. The valve 232 may be part of a storage tank inlet manifold, such as one or more spray nozzles. The LNG product stream 216 is discharged from the storage tank.

[0092] The end flash stream 238 is optionally counter-warmed in the end flash heat exchanger 240 relative to 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 an expansion valve 252 to form an expanded stream 254, which is combined with the expanded LNG stream 226.

[0093] The warm end flash stream 242 is compressed in the end flash compressor 244 to form a fuel stream 214 which is used as a fuel in the system 200. In many applications, the fuel stream 214 will be used as a fuel for gas turbines that directly drive refrigeration compressors or to generate electricity for powering electric motors that drive refrigeration compressors (not shown) that provide refrigerant for the refrigeration duty of the liquefaction unit 218.

[0094] Boiling gas ("BOG") stream 256 is discharged from LNG storage tank 236 and compressed in BOG compressor 260 to form compressed boiling gas stream 264, which is fed into fuel stream 214. Stream 256 may include steam generated due to expansion of stream 230, steam generated due to heat leakage into stream 234, and steam generated due to heat leakage into the storage tank.

[0095] Option A—Hydrogen in the LNG product

[0096] The thermodynamics of vapor and liquid equilibrium limits the feasibility of leaving the hydrogen in the LNG product with the device. It should be noted that the maximum amount of hydrogen that can be dissolved in the LNG product is about 700ppm. Therefore, it is feasible to operate the system 200 only when there is a very low hydrogen concentration (much less than 1% hydrogen) in the LNG product stream 216. In addition, doing so will increase the specific power consumption of the system 200. Another obstacle is that many existing base load LNG and peak shaving devices limit the installed refrigeration power. Most base load facilities are limited by the installed power of gas turbine drives. Peak shaving devices, small devices and medium-sized devices are typically powered by electric motors. Increasing the liquefaction specific power due to the addition of hundreds of ppm of hydrogen will reduce the output of facilities currently limited by installed power equipment. Therefore, for system 200, Option B (fuel) and Option C (hydrogen removal) are the only practical flow paths for hydrogen when there is a concentration of hydrogen greater than hundreds of ppm in the feed.

[0097] Option B—Hydrogen in Gas Turbine Fuel

[0098] For existing gas turbine driven plants, Option B has the advantage of reducing the carbon intensity of the plant, as the hydrogen will replace a portion of the methane content in the fuel. However, this solution may require significant modifications to the plant fuel system.

[0099] Hydrogen, which is more volatile than methane, will be concentrated in the flash (fuel) gas stream 238. In an LNG plant with a typical fuel requirement, 1% hydrogen in the feed will result in a fuel with greater than 15% hydrogen. In the case of a feed with 5% hydrogen, the hydrogen content in the fuel will exceed 50%.

[0100] This change in composition will affect the performance and operability of the end flash gas compressor 244, which raises the fuel pressure from near atmospheric pressure to approximately 40 bara. It is noted that the work required to compress one mole of hydrogen is 3% greater than the work required to compress one mole of methane. In addition, since hydrogen has a lower heating value of 10 / 33 that of methane, more fuel flow is required to maintain the same fuel heating value to the gas turbine to maintain the amount of power available for the refrigeration compressor. Overall, this means that the power required to compress any hydrogen in the fuel is 3.4 times that of an equal amount of displaced methane, affecting overall plant power consumption. For existing plants, if the feed hydrogen exceeds 0.5%, substantial modifications to the fuel system, including rotating and static equipment, may be required.

[0101] In addition to the problem of terminal flash compression, the fuel may also cause operational problems for the gas turbine: most existing industrial frame gas turbines equipped with dry low emission (DLE) combustion systems are not designed to operate on fuels with hydrogen concentrations greater than 30%. In order to operate at higher hydrogen concentrations, extensive engine and packaging modifications are required. Turbines that are already equipped with diffusion combustion systems still require additional fuel blending hardware and packaging safety upgrades; when operating with higher amounts of hydrogen, these turbines can only barely keep the unabated NOx emission exhaust within allowable limits. In many LNG plants, this will limit the implementation of Option B to feeds that have less than 2% hydrogen to keep the hydrogen concentration in the fuel less than 30%.

[0102] Option C—Hydrogen is exported

[0103] For LNG plants with gas turbines and greater than 2% hydrogen in the natural gas feed, and for those refrigeration processes in which the electric motor drives draw power from the grid, venting hydrogen from the system may be an attractive option. The hydrogen can be reinjected into the natural gas pipeline, or can be sent as a crude hydrogen stream for further purification to product / hydrogen pipeline purity. Existing electric motor-driven plants in which power is provided by the grid have very low fuel requirements, so Option C is the only solution available to maintain 100% LNG production when the feed hydrogen content increases beyond about 100 ppm. As will be discussed further, Option C also has significant advantages for gas turbine-driven plants because the modifications required to existing equipment are smaller than those required for Option B. Optionally, the purified hydrogen stream can be sent to a hydrogen fuel cell, which can be used to generate electricity.

[0104] Process options evaluated

[0105] To estimate the impact of hydrogen blended into the natural gas pipeline on downstream LNG plants, several different process scenarios using Option B (hydrogen as fuel) and Option C (hydrogen is exported) have been evaluated. The study baseline is a generic C3MR liquefaction unit that uses two industrial frame gas turbine drives to produce approximately 5 million metric tons per year (MTPA) of LNG, assuming typical U.S. Gulf Coast environmental conditions and feed gas composition, and based on a fuel demand of 460MW LHV. The evaluation assumes that the existing plant is modified to process hydrogen-containing feeds; however, the results can be extrapolated to new plants. This article shows the comparative results of some of the process scenarios evaluated.

[0106] Solutions for electric motor driven peak shaving units are also being evaluated. These units typically have very low fuel requirements and will require the option for exporting hydrogen in some form.

[0107] Options for processing feed hydrogen concentrations up to 18% were evaluated using a detailed scoring simulation of a generic C3MR liquefaction unit. Propane and mixed refrigerant compressor performance was evaluated using compressor curves, and the heat transfer and pressure drop performance of the wound tube main cryogenic heat exchanger (MCHE) was evaluated using a detailed model. Equipment associated with the end flash and boiling gas (BOG) systems was evaluated using a simple model, and the results were compared to a base case of 0% hydrogen in the feed.

[0108] The propane and mixed refrigerant power available from two industrial frame gas turbine refrigeration compression drives was fixed at the design (base case) values. A parallel drive configuration was assumed with duplicate propane and mixed refrigerant compressors on each drive. Simulations were run to maximize production subject to the constraints of available refrigeration drive power and fuel requirements.

[0109] For Option B, where hydrogen from the feed is sent to the fuel, the process scheme is designed to enrich the hydrogen in the fuel stream while maximizing LNG production. The fuel efficiency of the gas turbine is assumed to remain the same in the study and does not vary with the hydrogen in the fuel. In each case, it is assumed that the only fuel demand is that of the gas turbine and a maximum of 95% of the fuel will be provided by the end flash and BOG. ​​For the Option B scheme, this fuel balance constraint requires that the hydrogen be enriched in the fuel stream to not exceed the fuel demand and to suppress methane flash or methane recycle as required.

[0110] Option B1—No flow chart modification

[0111] For solution B1, use Figure 2 The system 200 is described in detail with no modification to the existing flowsheet. The pressure of the terminal flash tank 228 is fixed at a base case value of 1.24 bara.

[0112] Option B2—BOG Recycling

[0113] In scheme B2, if Figure 3 , an LNG system 300 is shown. In system 300, elements shared with system 200 are indicated by reference numerals increased by a factor of 100. For example, terminal flash tank 228 of system 200 corresponds to terminal flash tank 328 of system 300. For clarity, some features of system 300 that are identical to corresponding elements of system 200 are not shown in FIG. Figure 3 It should be noted that system 300 may be similar in structure to existing LNG systems, but operates differently to accommodate hydrogen in feed stream 310 as described below.

[0114] In the system 300, the pressure of the terminal flash product tank 328 is adjustable, which enables the hydrogen concentration in the fuel stream 314 to be controlled to maintain the hydrogen concentration in the terminal flash stream 338 (which becomes the fuel stream 314) within a predetermined range. The regulation / control of the pressure in the terminal flash product tank 328 can be provided by adjusting the steam flow rate drawn through the terminal flash product compressor 344. The manner of regulating the steam flow rate through the compressor 344 includes compressor recirculation, speed control, inlet guide vanes, compressor suction throttling or other known methods. The pressure of the terminal flash product tank 328 can be increased to suppress the flash of methane and increase the concentration of hydrogen in the fuel stream 314. The increase in the pressure of the terminal flash product tank 328 will result in an increase in the flash in the LNG storage tank 336. In order to compensate for this increase, at least a first portion 364 of the compressed boiling gas stream is recycled and combined with the hydrogen-containing natural gas stream 310 upstream of the liquefaction unit 318. To match the pressure of the hydrogen-containing natural gas stream 310, the compressed boil-off gas stream 364 is further compressed in a BOG recycle compressor 366 to form a further compressed BOG stream 368, which is combined with the hydrogen-containing natural gas stream 310. Optionally, a second portion 367 of the compressed boil-off gas stream 364 may be added to the fuel stream 314, thereby providing an additional way to control the hydrogen concentration in the fuel stream 314. These measures may be implemented in order to maintain a desired heating value in the fuel stream 314.

[0115] Option B3 - Hydrogen removal using membrane stages

[0116] In Scheme B3, if Figure 4, an LNG system 400 is shown in which a membrane stage 470 is used to remove hydrogen from a compressed end flash stream 441. In system 400, elements shared with system 200 are indicated by reference numerals increased by a factor of 200. For example, end flash tank 228 of system 200 corresponds to end flash tank 428 of system 400. For clarity, some features of system 400 that are identical to corresponding elements of system 200 are not shown in FIG. Figure 4 They are numbered in the manual but not specifically mentioned in the specification.

[0117] In system 400, membrane stage 470 is located downstream of terminal flash compressor 444. Membrane stage 470 may include one or more membrane modules arranged in parallel. Permeate stream 472 from membrane stage 470 is enriched in hydrogen and is 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 in LNG plant 400. Therefore, at least a portion of the compressed permeate stream may be sent to output.

[0118] The non-permeate stream 478 lacking hydrogen may 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 may be compressed in a terminal 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 terminal flash heat exchanger 440. At least a portion 484 of the non-permeate stream 478 may be mixed into the fuel stream 414, thereby reducing the concentration of hydrogen in the fuel stream 414. Valve 485 schematically represents a means for controlling the flow of the non-permeate stream 478 to the portions 483, 484.

[0119] Option C1 - Hydrogen Flash Tank

[0120] In scheme C1, if Figure 5 , an LNG system 500 is shown that is configured to produce a crude hydrogen gas stream 586 that includes at least 50 mol % hydrogen. The crude hydrogen gas stream 586 can be sent to a hydrogen purification unit to produce product grade hydrogen for export or return to a pipeline downstream of the liquefaction unit 518. In system 500, elements shared with system 200 are represented by reference numerals increased by a factor of 300. For example, the terminal flash tank 228 of system 200 corresponds to the terminal flash tank 528 of system 500. Similarly, elements shared with system 400 are represented by reference numerals increased by a factor of 100. For clarity, some features of system 500 that are identical to corresponding elements of systems 200 and / or 400 are represented in the figure. Figure 5 They are numbered in the manual but not specifically mentioned in the specification.

[0121] The expanded LNG stream 526 is first sent to a crude hydrogen flash tank 583. The operating pressure of the crude hydrogen flash tank 583 can be selected to produce a crude hydrogen gas stream 585 having a hydrogen concentration of at least 50 mole percent. Refrigeration from the crude hydrogen gas stream 585 is recovered in the hydrogen flash exchanger 581 to cool a portion 549 of the hydrogen-containing natural gas stream 510, producing a cooled additional LNG stream 551. The cooled additional LNG stream 551 leaves the hydrogen flash exchanger 581, and then the cooled additional LNG stream is expanded through an expansion valve 553 to form an expanded additional LNG stream 555. The expanded additional LNG stream 555 is combined with the expanded LNG stream 526 and introduced into the crude hydrogen flash tank 583.

[0122] LNG stream 587 from crude hydrogen flash tank 583 is then expanded across expansion valve 588 to form expanded LNG stream 589. Expanded LNG stream 589 is then sent to terminal flash tank 528. The remaining elements of system 500 are similar to Figure 2 The system 200 is very similar.

[0123] result

[0124] All four scenarios were simulated with increasing amounts of hydrogen in the feed. Figure 6 The maximum production obtainable from the discussed flow scheme is shown as a function of feed hydrogen content ranging from 0% to 5%.The results are based on simulations of the power available from two industrial frame drives and with constraints on the overall plant fuel balance.

[0125] Figure 7 The specific power in kWh / ton LNG consumed by the terminal flash compressor (244, 344, 444, 544), BOG compressor (260, 360, 460, 560), terminal flash recycle compressor (480), BOG recycle compressor (366), and hydrogen compressor (474) is shown. The power available for the terminal flash compressor and BOG compressor is not limited to the base case values, and it is assumed that those compressors will be modified or replaced as needed to maximize production. The power required for these electric motor driven compressors is not taken into account in the fuel balance. Only the refrigerant driver is considered in the fuel requirement calculation.

[0126] Option B1—No flow chart modification

[0127] Maintaining the desired steam flow rate from the end flash tank 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 leaving the liquefaction unit 218 must become colder to suppress the flash so as not to exceed the fuel requirement and maintain fuel balance. For example, for the same liquefaction unit outlet temperature and end flash tank pressure, the heating value (energy / time, such as Btu / s or MW) of the end flash steam produced with 3% hydrogen in the feed may be 88% higher than the heating value of the end flash steam produced with 0% hydrogen in the feed. In the case of 3% hydrogen in the feed, the reduction in the liquefaction unit outlet temperature necessary to maintain the same fuel stream heating value as 0% hydrogen in the feed results in a 6.7% reduction in production at a fixed drive power.

[0128] Figure 7 It is shown that for 3% hydrogen in the hydrogenated natural gas feed stream 210, the power consumed by the end flash compressor 244 and the BOG compressor 260 is almost doubled relative to the base case (no hydrogen in the feed stream 210). This large increase is primarily due to the increase in the power of the end flash compressor 244. For as little as 0.5% hydrogen in the feed, the end flash compressor 244 will need to be modified to accommodate the lower molecular weight and increased volume flow of the resulting end flash stream 238. Aerodynamic changes (including impeller changes or increased rotational speed) may be accompanied by a more powerful drive motor. In the event that the hydrogen concentration in the hydrogenated natural gas feed stream 210 is above 0.5%, the end flash compressor 244 will need to be replaced or supplemented with new parallel compression wires.

[0129] Option B2—BOG Recycling

[0130] For this configuration, controlling the pressure of the terminal flash tank 328 to reduce flashing adds another degree of operational freedom in maintaining proper fuel balance, thereby allowing the device to operate with hydrogen-containing natural gas stream 310 ( Figure 3 ) to achieve 100% LNG production with a concentration of up to about 3% hydrogen. However, this production recovery requires additional operating costs: Note that in Figure 7 In the embodiment of the present invention, for 3% hydrogen in the hydrogen-containing natural gas stream 310, the power consumed by the back-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. The required BOG compression power increases significantly because the higher end flash tank 328 pressure transfers the adiabatic flash from the end flash tank 328 to the storage tank 336. In the case of above 3% hydrogen in the feed, it is impossible to achieve 100% design LNG production using this scheme for the conditions of this study.

[0131] Option B3 - Hydrogen removal using membrane stages

[0132] In this scheme, membrane stage 470 is added to concentrate the hydrogen in fuel stream 414. This scheme allows 100% LNG production with 5% hydrogen in hydrogen-containing natural gas stream 410, but the operating cost is higher. Note that Figure 7 The power of the hydrogen compressor 474 used to compress the permeate stream 472 is included.

[0133] In addition to the new end flash recycle compressor 480, membrane stage and permeate hydrogen compressor 474, the existing end flash compressor 444 must also be modified or replaced at the higher hydrogen concentration due to the significant difference in the new operating conditions.

[0134] With significant plant modifications, both Schemes B2 and B3 can achieve initial design LNG production 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 drives are not designed to operate at hydrogen concentrations greater than 30% when equipped with a dry low emissions (DLE) combustion system, and turbines with diffusion combustion systems may require additional NOx reduction hardware. The turbine must undergo material and packaging safety inspections to estimate high hydrogen concentrations in the fuel system; the gas turbine OEM should be consulted for fuel compositions greater than 10% hydrogen.

[0135] for Figure 3 and Figure 4 Both, the hydrogen-rich stream (338, 472) can be output as crude hydrogen or sent to a purification unit and output as hydrogen product, rather than being sent to a fuel stream. Fuel requirements, if any, can be met by the hydrogen-depleted stream (367, 478).

[0136] Option C1 - Hydrogen Flash Tank

[0137] In Scheme C1, hydrogen is vented in a stream containing 50 mol% hydrogen (crude hydrogen stream 585). This crude hydrogen stream 585 can be sent for further purification into product grade hydrogen or returned to the pipeline.

[0138] like Figure 6 As shown, the yield decreases with increasing hydrogen content in the hydrogen-containing natural gas stream 510, reaching a decrease of about 2% in the case of 5% hydrogen in the feed. This yield loss is mainly due to the refrigeration loss provided by the LNG hydraulic turbine (not shown). As the hydrogen in the feed increases, the discharge pressure of the turbine also increases to prevent steam from forming in the turbine. In the case of 5% hydrogen, the discharge pressure approaches the inlet pressure and the turbine is bypassed. However, this yield loss can be eliminated by adding a terminal flash recycle compressor 566 (dashed line).

[0139] This solution minimizes the changes required to the existing LNG plant and the downtime required to implement these changes. For an electric motor driven LNG plant with low fuel consumption, venting hydrogen from the process was the only feasible solution among the solutions evaluated for feed hydrogen content above 200PPM-500PPM.

[0140] Figure 8 Another exemplary embodiment of an LNG system 600 is shown in which a hydrogen cold box is provided. In system 600, elements shared with system 200 are indicated by reference numerals increased by a factor of 400. For example, the end flash tank 228 of system 200 corresponds to the end flash tank 628 of system 600. Similarly, elements shared with system 300 are indicated by reference numerals increased by a factor of 300. For example, the recycle compressor 366 of system 300 corresponds to the 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 not shown in FIG. Figure 8 They are numbered in the manual but not specifically mentioned in the specification.

[0141] In system 600, the end flash tank 628 operates at a pressure of 1.5 bara to 55 bara. The hydrogen-rich vapor 638 from the end flash tank 628 is cooled and partially liquefied in a heat exchanger 643. The two-phase mixture 627 is separated into additional hydrogen-rich vapor 631 and methane-rich liquid 633 in a separator 629. The additional hydrogen-rich vapor is warmed in the heat exchanger 643 and the end flash exchanger 640 to form a crude hydrogen product 637. The crude hydrogen product can be reinjected into a natural gas pipeline or further purified to produce a pure hydrogen product.

[0142] The methane-rich liquid 633 is expanded in valve 635 and warmed in heat exchanger 643 to produce an intermediate methane stream 641, which is then sent to BOG compressor 660. At least a portion 625 of the intermediate methane stream 641 can be warmed in terminal flash exchanger 640 to produce warm methane-rich steam 642 and compressed in terminal flash compressor 644 to form fuel stream 614. At least a portion 639 of the crude hydrogen product 637 can be combined with the warm methane-rich steam 642 to provide additional fuel. At least a portion 615 of the hydrogen-rich steam 638 can bypass heat exchanger 643 to at least a portion of the intermediate methane stream 625.

[0143] LNG stream 630 is sent to storage tanks. BOG stream 656 and intermediate methane stream 641 are compressed in BOG compressor 660 to form compressed boil-off gas stream 664, which can 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 can be sent to fuel stream 614.

[0144] Fig. 9 is shown for a range of hydrogen concentrations in the feed gas stream 610, Figure 8 Table of modeled system parameters for an exemplary embodiment of . Note that the temperature of the LNG stream 620 is highest when the hydrogen concentration in the feed gas stream 610 is 10%. It is also noteworthy that when the hydrogen concentration in the feed gas stream 610 is above 3%, the LNG production begins to decline.

[0145] Fig.10 Another illustrative embodiment of an LNG system 700 is shown in which a feed gas stream 710 is pretreated to remove a portion of the hydrogen from the gas stream prior to liquefaction. In system 700, elements shared with system 200 are represented by reference numerals that are increased by a factor of 500. For example, the end flash tank 228 of system 200 corresponds to the end flash tank 728 of system 700. Similarly, elements shared with system 300 are represented by reference numerals that are increased by a factor of 400. For example, the recycle compressor 366 of system 300 corresponds to the 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 not shown in FIG. Fig.10 They are numbered in the manual but not specifically mentioned in the specification.

[0146] In system 700, feed gas stream 710 is passed through membrane module 763 before liquefaction to form hydrogen-rich permeate stream 765 and hydrogen-depleted non-permeate stream 771, which can be liquefied in liquefaction unit 718 at a lower power consumption than the power consumption required to liquefy feed gas stream 710. When the hydrogen concentration in feed gas stream 710 is low enough that pre-liquefaction hydrogen removal is not required, bypass stream 773 is provided to enable membrane module 763 to be bypassed. Hydrogen-depleted non-permeate stream 771 is combined with further compressed BOG stream 768 upstream of liquefaction. Hydrogen-rich permeate stream 765 is compressed in compressor 767 to form fuel stream 714. A portion 759 of warm compressed end flash stream 797 and a portion 793 of BOG stream 764 can be combined into fuel stream 714. Hydrogen-rich permeate stream 765 can alternatively be exported to a natural gas pipeline or further purified to produce a hydrogen product.

[0147] Fig.11Another exemplary embodiment of an LNG plant 800 is shown in FIG. In the LNG plant 800, a feed gas stream 810 is processed in a pretreatment unit 875 to remove CO2, water and heavy hydrocarbons, thereby producing a pretreated feed gas stream 876. The pretreatment to remove CO2 is usually carried out by adsorption in an acid gas removal unit. The removal of water can be carried out by cooling the natural gas to promote the condensation of a large amount of water, followed by dehydration in an adsorption unit. The removal of heavy hydrocarbons can be carried out 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 an exchanger 881 with ambient air heat, cooling water or another cooling medium such as propane, HFC or a mixed refrigerant to produce a cooled pretreated gas stream 886. The cooled pretreated gas stream 886 then passes through a membrane module 863 to form a hydrogen-rich permeate stream 878 and a hydrogen-poor non-permeate stream 872. Hydrogen-depleted non-permeate stream 872 is optionally compressed and cooled (via compressor 893 and heat exchanger 894) before being liquefied.

[0148] The hydrogen-rich permeate stream 878 is then compressed using a compressor 867 to form a compressed hydrogen-rich permeate stream 869. The compressed hydrogen-rich permeate stream 869 is then processed using a pressure swing adsorption unit 887 to produce a purified hydrogen stream 888 and a hydrogen-depleted stream 889. The purified hydrogen stream 888 may have a hydrogen concentration of at least 90%. The hydrogen-depleted stream 889 is combined with the end flash stream 838 and then compressed using an end flash compressor 844 to produce a fuel stream 814.

[0149] Fig.12 Another exemplary embodiment of an LNG plant 900 is shown in FIG. LNG plant 900 is very similar to LNG plant 800, with the main difference being that two terminal flash tanks 983 and 928 are arranged in series. The terminal flash stream 990 from the first terminal flash tank 983 is combined with the hydrogen-rich permeate stream 978 before compression. The LNG stream 987 from the first terminal flash tank 983 is further separated in the second terminal flash tank 928. The terminal flash stream 938 from the second terminal flash tank 928 is combined with the hydrogen-depleted stream 989 upstream of the terminal flash compressor 944. The LNG stream 930 from the second terminal flash tank 928 is then sent to an LNG storage device (not shown).

[0150] The scope of the present invention is not limited to the specific aspects or embodiments disclosed in the examples, which are intended to illustrate several aspects of the present invention, and any embodiments that are functionally equivalent are within the scope of the present invention. In addition to the modifications shown and described herein, various modifications of the present invention will become apparent to those skilled in the art and are intended to fall within the scope of the appended claims.

Claims

1. A method, comprising: (a) cooling and liquefying a hydrogen-containing natural gas feed stream in a natural gas liquefaction unit 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 terminal flash unit into a first terminal flash stream and a hydrogen-depleted LNG stream, wherein the first terminal flash stream has a higher hydrogen concentration than the hydrogen-containing natural gas feed stream and the hydrogen-depleted LNG stream has a lower hydrogen concentration than the hydrogen-containing natural gas feed stream; and (d) further processing the first terminal flash stream and / or the hydrogen-depleted LNG stream to form a gaseous hydrogen-depleted stream and a gaseous hydrogen-rich stream.

2. The method according to claim 1, wherein step (d) is performed using at least one selected from the group consisting 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. The method of claim 1, wherein the first end flash unit is a vapor liquid separator.

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

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

6. The method of claim 5, wherein the fuel stream is used in a gas turbine, a boiler or a fired heater.

7. The method according to 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. The method according to claim 7, further comprising: (g) sending the purified hydrogen gas stream to a fuel cell to generate electricity.

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

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

11. The method according to claim 1, further comprising: (j) sending at least a portion of the gaseous hydrogen-depleted stream to a recycle stream which is combined with the hydrogen-containing natural gas feed stream upstream of step (a).

12. The method according to claim 1, further comprising: (k) controlling the pressure of the separator during step (c) so as to maintain the hydrogen concentration in the first terminal flash stream within a first predetermined range.

13. The method according to claim 1, further comprising: (1) 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, the pretreated hydrogen-containing natural gas feed stream having a lower hydrogen concentration than the hydrogen-containing natural gas feed stream.

14. The method according to claim 13, further comprising: (m) sending the hydrogen-rich pretreated stream to a fuel stream.

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

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

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

18. A method comprising: (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 flow to drive at least one refrigeration compressor 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 a terminal flash stream and a hydrogen-depleted LNG stream in a terminal flash separator, the terminal flash stream having a higher hydrogen concentration than the hydrogen-containing natural gas feed stream; (e) compressing the terminal flash stream to form a compressed terminal flash stream; (f) storing the hydrogen-depleted LNG stream in an LNG storage tank; (g) compressing the 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; and (i) combining the further compressed BOG stream with the hydrogen-containing natural gas feed stream upstream of performing step (a); Wherein the fuel stream comprises the compressed end flash stream.

19. The method according to claim 17, further comprising: (j) transferring a first portion of the BOG stream upstream of step (h); as well as (k) combining the first portion of the BOG stream with the tip flash stream to form the fuel stream.

20. A method comprising: (a) cooling and liquefying a hydrogen-containing natural gas feed stream in a natural gas liquefaction unit 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 terminal flash unit into a first terminal flash stream and a hydrogen-depleted LNG stream, wherein the first terminal flash stream has a higher hydrogen concentration than the hydrogen-containing natural gas feed stream and the hydrogen-depleted LNG stream has a lower hydrogen concentration than the hydrogen-containing natural gas feed stream; (d) compressing the terminal flash stream using a terminal flash compressor to form a compressed terminal flash stream; (e) using the compressed end flash stream as a fuel stream; as well as (f) controlling the pressure at which the terminal flash product compressor is operated to maintain the hydrogen concentration in the fuel stream within a predetermined range.

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