Patent Application
20120036888
The present invention relates generally to the compression, refrigeration and liquefaction of gases, and more particularly to the liquefaction of a gas, such as natural gas, on a small scale.
There are no commercially viable Small-Scale liquefied natural gas (“LNG”) production facilities anywhere in the world. “Small-Scale” means less than about 10,000 liters/day. Thus, any existing liquefied natural gas-fueled fleet must depend on deliveries by tanker truck from larger-scale LNG plants or from LNG import terminals. The use of tanker trucks or terminals increases the cost of the LNG to the end user, because the delivered price must include the substantial cost of transporting the LNG from the production or import location to the customer. Those transportation costs tend to outweigh the lower production costs of large-scale LNG manufacture, where there is a large distance between the LNG source and the customer. Also, the transport of LNG from production or import source to end-users requires that the LNG be as cold as possible so as to avoid “boil off” (and losses through pressure relief valves) during the transport process. Thus, the LNG needs to be produced at its coldest practical temperature, say, about 260° F., rather than at warmer temperatures, requiring more energy input. When LNG is dispensed as compressed natural gas (“CNG”) to vehicles, at facilities with no on-site liquefaction systems, the cold content of the LNG is dissipated in its conversion (by pumping to pressure and warming) to CNG, throwing away a significant amount of energy that was used to liquefy the LNG at its source. More generally, the standard model for CNG production and dispensing (in the absence of an on-site LNG source) requires large compressors that produce the CNG on demand, because CNG is not dense enough to allow for any practical way to store it in advance of its dispensing to vehicles. Thus, all CNG stations operate on a “just in time” production basis, without the ability to produce and store CNG during off-peak periods. The cost of “just in time” production is higher because it often includes peak period “demand charges” for the electricity used to run the oversized compressors. The present invention seeks to solve these and other problems associated with the standard forms of LNG production and transport, L/CNG dispensing, and CNG production and dispensing.
The LNG customer must also maintain a large storage tank so that deliveries can be spread out in time. Such tanks produce “boil off” which is generally vented to the atmosphere, causing methane emissions and loss of product, further increasing the net cost of the LNG, to both the end user and (by way of the emissions) to society at large. Heat gain to the storage tank, in the absence of on-site liquefaction, results in LNG that is not the ideal density for the vehicle's fuel tank. Re-liquefaction to avoid boil-off or to increase the product's density is not an option without an on-site LNG plant.
Other drawbacks to tanker-delivered LNG include the lack of competition in the industry, making the fleet owner excessively dependent on a single supplier. The quality of the delivered product may also vary, to the detriment of the fleet that uses the fuel.
The alternative that is commonly used is on-site Compressed Natural Gas (CNG) production, using the local natural gas pipeline as the feed source. However, such CNG systems have severe limitations, including the following: CNG, because it is not very dense, cannot be stored in large quantities, so it must be made at a high capacity during the peak vehicle fueling demand period. Similarly, the on-vehicle storage of CNG is limited by the need for heavy, high-pressure CNG tanks that store relatively little product, compared to the much denser LNG, and thus limit the travel range of the CNG vehicle. Also, because of the lack of CNG storage options, the typical CNG compressor must be “over-designed” so as to be able to meet the “just in time” demand of the local CNG fleet. In other words, if the CNG station is to fill any significant number of vehicles, fast enough to compete with standard fueling rates (such as for diesel fueling), then the compressor must have a very large throughput capacity, even if that capacity is idle during much of the day. The CNG produced is generally warm, due to the heat of compression, and must be sent through ambient air coolers to dissipate the heat gained during compression. However, that approach still leaves the CNG at some 15-degrees hotter than ambient, reaching about 100° F. and more. The hotter the CNG, the less dense it is, limiting the amount of product that can be dispensed into each vehicle's on-board storage tank. Moreover, by operating during the peak fueling demand period, the CNG station is likely running its large compressors during the peak electricity demand period, causing it to pay “demand charges” to the electric distribution company. The just in time model (without on site storage) does not allow for off-peak CNG production.
The only reason vehicle-grade LNG needs to be produced at the coldest possible temperatures is to allow it to “weather” the time it spends in transport vehicles and storage tanks, before it is dispensed to the vehicles.
Therefore, a system for the small-scale production of LNG from low-pressure pipelines and stranded wells is needed to overcome the above listed and other disadvantages of existing methods of converting low-pressure natural gas to a dense form that is easily storable and transportable Also, a method of dense-phase natural gas production, storage and dispensing is needed that allows for off-peak production and off-peak power use, and which results in lower energy input costs because reduced refrigeration input is required.
The disclosed invention relates to a system for the small-scale production of liquid natural gas comprising: a natural gas supply, the natural gas supply being at a pressure in a range of about 55 psia to about 350 psia; a prime mover in fluid communication with the natural gas supply, and in fluid communication with a third heat exchanger; a multi-stage compressor in operational communication with the prime mover; the multi-stage compressor comprising at least a first stage compressor, a second stage compressor, and a third stage compressor, and where the inlet temperature of fluid entering the first stage compressor is less than about 40° F., and where the inlet temperature of fluid entering the second stage compressor is less than about 40° F.; a first inter-cooler in fluid communication with the first stage compressor; a molecular sieve in fluid communication with the first inter-cooler and in fluid communication with the natural gas supply; a fourth heat exchanger in fluid communication with the molecular sieve and in fluid communication with the first stage compressor; a second inter-cooler in fluid communication with the second stage compressor; a first heat exchanger in fluid communication with the second inter-cooler and in fluid communication with the third stage compressor; an after-cooler in fluid communication with the third stage compressor; a second heat exchanger in fluid communication with the after-cooler; a main heat exchanger in fluid communication with the second heat exchanger, in fluid communication with a phase separator, in fluid communication with a gas turbo-expander, and in fluid communication with the fourth heat exchanger, where the operational flow rate from the main heat exchanger to the gas turbo-expander can be as low as about 1,450 lb/hr during continuous operation; a first expansion device in fluid communication with the main heat exchanger; a sub-cooling heat exchanger in fluid communication with the first expansion valve;a second expansion device in fluid communication with the sub-cooling heat exchanger; a pressure tank in fluid communication with the second expansion valve; a four-way valve in fluid communication with the pressure tank; the four-way valve in fluid communication with the sub-cooling heat exchanger and in fluid communication with the main heat exchanger;the gas turbo-expander in fluid communication with the phase separator, and in operational communication with an expander driven compressor; the expander driven compressor in fluid communication with a fifth heat exchanger; the fifth heat exchanger in fluid communication with second stage compressor; an ammonia absorption chiller in fluid communication with the prime mover, in fluid communication with the first heat exchanger, in fluid communication with the second heat exchanger, in fluid communication with the third heat exchanger, and in fluid communication with a cooling tower; a make-up water line in fluid communication with the cooling tower; and where the amount of liquid natural gas produced by this system while continuously running during a 24 hour day can be as low as about 6,000 liters per day, where the system has no more than two expansion valves; and where the first and second devices are selected from a group consisting of a compressor-loaded multi-phase expander turbine, and an expansion valve.
The invention also relates to a system for the small-scale production of cold compressed natural gas comprising: a natural gas supply, the natural gas having a pressure in a range of about 55 psia to about 350 psia; a prime mover in fluid communication with the natural gas supply, and in fluid communication with a third heat exchanger; a multi-stage compressor in operational communication with the prime mover; the multi-stage compressor comprising a first stage compressor, a second stage compressor, and a third stage compressor, and where the inlet temperature of fluid entering the first stage compressor is less than about 40° F., and where the inlet temperature of fluid entering subsequent stages of the compressor is less than 40° F.; a first inter-cooler in fluid communication with the first stage compressor and with a waste heat driven chiller; a molecular sieve in fluid communication with the first inter-cooler and in fluid communication with the natural gas supply; a fourth heat exchanger in fluid communication with the molecular sieve and in fluid communication with the first stage compressor; a second inter-cooler in fluid communication with a waste heat driven chiller and the second stage compressor; a first heat exchanger in fluid communication with the second inter-cooler, a waste heat driven chiller and in fluid communication with the third stage compressor; an after-cooler in fluid communication with the third stage compressor and with a waste heat driven chiller; a second heat exchanger in fluid communication with the after-cooler and with a waste heat driven chiller; a main heat exchanger in fluid communication with the second heat exchanger, in fluid communication with a phase separator, in fluid communication with a compressor-loaded gas turbo-expander, and in fluid communication with the fourth heat exchanger, where the operational flow rate from the main heat exchanger to the gas turbo-expander can be as low as about 1450 lb/hr during continuous operation; a first expansion device, such as a throttle valve or compressor-loaded multi-phase expander, in fluid communication with the main heat exchanger; a sub-cooling heat exchanger in fluid communication with the first expansion valve or compressor-loaded multi-phase expander; a pressure tank in fluid communication with the second expansion valve; a four-way valve in fluid communication with the pressure tank; the four-way valve in fluid communication with the sub-cooling heat exchanger and in fluid communication with the main heat exchanger; the gas turbo-expander in fluid communication with the phase separator, and in operational communication with an expander driven compressor; the expander driven compressor in fluid communication with a fifth heat exchanger; the fifth heat exchanger in fluid communication with one of the stages of a multi-stage natural gas compressor; an ammonia or lithium bromide absorption chiller or an adsorption chiller in fluid communication with the prime mover, in fluid communication with the first heat exchanger, in fluid communication with the second heat exchanger, in fluid communication with the third heat exchanger, and in fluid communication with a cooling tower; a make-up water line in fluid communication with the cooling tower; and where the amount of cold compressed natural gas produced by this system while continuously running during a 24 hour day can be as low as the liquid equivalent of about 6,000 liters per day, and where the system has no more than two natural gas expansion devices.
In addition, the invention relates to a method of dispensing natural gas from stored cold compressed natural gas, the method comprising: dispensing cold compressed natural gas from a cold compressed natural gas storage tank, with or without pumping it with a cryogenic liquid pump to a higher pressure; pumping the cold compressed natural gas by a cryogenic liquid pump to a pressure suitable for compressed natural gas dispensing and storage in on-vehicle compressed natural gas storage tanks; recovering cold from the cold compressed natural gas by heat exchange with natural gas feeding the natural gas production plant to replace dispensed product, such that the incoming, relatively warm, feed-gas warms the pumped-to-pressure cold compressed natural gas to a temperature of about −20° F. to about 30° F., thus converting it from cold compressed natural gas to compressed natural gas; where the refrigeration content of the outbound cold compressed natural gas is used to reduce the refrigeration needed to convert the incoming feed gas to more cold compressed natural gas or liquid natural gas; where the now warmed gas stream (formerly cold compressed natural gas) is cooler than standard compressed natural gas but can be stored in standard, non-cryogenic, on-board vehicle fuel storage tanks; thus allowing for a compressed natural gas dispensing facility that can achieve storability and off-peak production, and yielding a cooler than normal, and thus denser dispensed compressed natural gas, allowing for existing, standard on-vehicle compressed natural gas tanks to take away more product (as measured in pounds per cubic foot of fuel tank capacity), then is achievable with standard compressed natural gas at the same pressure but as warm as about 100° F.
Also, the invention relates to a system for the storage, transport, and dispensing of natural gas, comprising: means for handling natural gas in a cold compressed natural gas state where the natural gas is a non-liquid, but is dense-enough to allow for pumping to pressure by a cryogenic liquid pump; a means for optimally balancing the compression and refrigeration input required to produce the cold compressed natural gas; and a means for putting the natural gas into a cold compressed natural gas state without first putting the natural into a cryogenic liquid state which is subsequently pumped to a higher-than critical pressure.
The present disclosure will be better understood by those skilled in the pertinent art by referencing the accompanying drawings, where like elements are numbered and labeled alike in the several figures, in which:
The disclosed process provides a means to produce, at small-scales, LNG at or near the vehicles that will be served by the facility. With on-site liquefaction inherent in the disclosed process, the LNG product need not be as cold as the LNG produced at distant, large-scale production plants. “Warmer” LNG requires less energy input than colder LNG, and LNG made at (or near) the vehicle fleet it serves will require less energy input for transporting the product. Similarly, if the main customer base is CNG vehicles, then the LNG used to dispense CNG (that system being known as L/CNG) need not be any colder than required for adequately storing and pumping the LNG to the pressure needed for CNG dispensing.
The inventor, who is an expert in this field, is not aware of any existing, commercially viable Small-Scale LNG plants anywhere in the world and is not aware of any CCNG production, storage or dispensing systems or of a CNG dispensing systems that includes CCNG production and storage. The smallest LNG plant that he is aware of, in the state of Delaware in the US, produces approximately 25,000 gallons (95,000 liters) per day. By contrast, the proposed invention will be viable at a production rate of only about 6,000 liters per day. That “small-scale” is an essential component of the business model for the invention, namely that it will provide vehicle grade LNG to a medium-sized bus or truck fleet, without requiring that a portion of the plant's output be shipped to a second and third, off-site fleet. In short, each small-scale LNG plant can act as an “appliance” that serves a single customer at a single location. Such small-scale LNG plants will also allow stranded gas fields (those not near pipelines, or too small for pipeline extensions) to be developed, allowing the produced LNG to be sent to off-site customers or to distant pipelines for re-gasification. Also, the invention allows for a wide range of “LNG products” from cold LNG (about −245° F. and colder), to warm LNG (between approximately −160° F. to about −240° F.), and to CCNG, which is dense-phase non-liquid state of natural gas that is colder than natural gas' critical temperature and is at a higher pressure than its critical pressure. That range of cryogenic natural gas conditions will have a density of approximately 15 to 20 pounds per cubic foot for CCNG and above about 25 pounds per cubic foot for LNG that is at about −245° F. and colder, with variation that depends on the methane and other hydrocarbon content of the natural gas.
CCNG is more than a “supercritical” phase of natural gas, with the single attribute of having a higher-than critical pressure. CCNG has the second attribute of being colder than the critical temperature of natural gas. It is those two attributes, together, that achieve its relatively high density (allowing it to be viably stored, much like LNG in readily available cryogenic storage tanks), and, most importantly, achieving the densities that allow that non-liquid (more than supercritical) phase of natural gas to be pumped to a higher pressure by standard cryogenic liquid pumps, as though CCNG were a liquid.
CCNG is not a liquid but will behave much like a liquid, allowing its pressure to be raised not only by compression (as is normally used for vapors) but also by pumping, as is used for all liquids. The pumping of liquids requires significantly less energy input than the compression of gases because liquids are virtually incompressible, allowing almost all of the energy input to accrue to raising the pressure of the liquid. CCNG is sufficiently incompressible, much like a liquid, to allow for efficient pumping. Thus a significant benefit of CCNG is the ability to raise its pressure (for example, for dispensing as CNG) by merely pumping it. An equally important benefit of CCNG is that the energy input required to produce it is lower than the energy input required to produce standard LNG, which is the standard form of dense-phase, storable and pump-able natural gas. (At temperatures as cold or colder than about −150 F and as the pressure of the LNG is raised above about 700 psia, it becomes CCNG. However, that methodology of producing CCNG, by pumping a liquid, requires more energy input than the methodology disclosed below.)
The common aspects of the wide-range of cryogenic natural gas conditions are the increased density, when compared to pipeline gas and to CNG, and the ability to pump such moderate-pressure cryogenic natural gas to any desired outflow pressure from the storage container, using standard cryogenic liquid pumps. Those attributes of storability and “pump-ability” are the main attributes of standard LNG. However, the present invention achieves those attributes at many warmer (and higher-pressure) conditions than for standard LNG. Those warmer and higher-pressure conditions require significantly less energy input than standard (cold and low-pressure) LNG, because cryogenic processes are more energy “sensitive” to the depth of refrigeration than to the pressure under which the gas is refrigerated. Thus, the present invention discloses the novel use of CCNG as a phase of natural gas suitable for the production, storage, transport, and dispensing of a variety of dense-phase natural gas products, including (but not limited to) vehicle-grade fuels. We say “phase,” rather than “state” or “condition,” because CCNG can be identified on a phase diagram of methane (and natural gas) shown at
“Pump-ability” is an important attribute of cryogenic methane because often the stored cryogenic methane is dispensed as high-pressure, near-ambient CNG at pressures of approximately 3,000 to about 3,600 psia. Pumping LNG to such pressures, at L/CNG dispensing sites is routine, but is often wasteful of the refrigeration content of the LNG if there is no on-site liquefaction equipment or other cold recovery options. By contrast, the disclosed method allows for the pumping of non-liquid CCNG, and includes cold recovery, as illustrated in
It should be noted that some cryogenic liquid pumps would easily tolerate the approximately 700-psia inlet pressure that is required for the pumping of CCNG. Other pumps, that can only tolerate, say, about 300 psia inlet pressures, can be used to pump CCNG if the CCNG is first expanded down to about 300 psia (causing most of it to become a liquid), and where that two-phase product of expansion is sent through a commonly available phase-separator. The smaller, vapor portion of that expansion can be further expanded down toward atmospheric pressure, producing more mostly liquid (suitable for pumping) and some vapor. Alternatively, the vapor portion of the first expansion and separation can be returned (cold) to the VX Cycle for re-compression. Thus, there are several practical and widely available techniques for pumping CCNG, much like a liquid, to any desired higher-pressure.
The ability to economically produce vehicle-grade LNG, CCNG or CNG dispensed from stored LNG or from CCNG will be achieved by at least two aspects of the invention: a) low capital costs, and b) high-efficiency. In one embodiment, the disclosed method offers, in a single deployment, the option of producing LNG, CCNG and CNG. LNG and CNG have an existing and growing vehicle fuel market as well as other non-vehicular uses. At the moment, the benefit of CCNG is that it is less costly to produce than LNG, but can be dispensed as a liquid (as discussed above) or, after cold recovery, as CNG. The dispensing and on-vehicle storage of CCNG as vehicle fuel is a plausible near term concept that only depends on certifications by US DOE and/or other such agencies, of the use of on-vehicle, composite, cryogenic pressure vessels (such as those that rely on outer wrappings of carbon fiber and other high-strength fabrics), which will tolerate the about −150° F. and colder and about 700 psia and higher pressure conditions of CCNG. Thus, the present invention offers an entirely new form of on-vehicle fuel—CCNG—that will have nearly the density of LNG, but which will not “boil off” because, as a single-phase fluid, any heat gain will only cause its pressure to rise. As such, an appropriately designed CCNG vehicle fuel tank will be lighter than an LNG tank, will not require space above the liquid for vapor to form, and will contain the product indefinitely, without “burping” methane.
The invention will allow an about 2,000-gallon/day LNG/CCNG plant to be constructed for less than about $2,000,000 The innovative LNG production cycle will yield approximately 83% LNG/CCNG out of every unit of natural gas that is delivered to the plant from the local low-pressure pipeline or stranded well, with only approximately 17% of the natural gas used as fuel for the prime mover. That combination of relatively low capital cost and low fuel use (high-efficiency) will yield an operating cost and “price per liter/gallon” that will allow the LNG/CCNG (or CNG that is dispensed from the stored LNG/CCNG) to be sold at a discount to the market price of diesel, accounting for the energy content (BTU) both fuels.
That achievement—competitively priced LNG/CCNG/CNG—will allow natural gas to be more than just an “alternative fuel” but also an economically viable alternative fuel.
The attached process flow diagrams illustrate the invention, which is known as the disclosed system. The invention is a unique and innovative variant of the methane expansion cycle, which to date, has only been deployed commercially in certain special, large-scale configurations, specifically known as “letdown plants”. Thus, the system described here is also known as Vandor's Expansion Cycle or the “VX Cycle”. It should be noted that the definition of CCNG offered above was included in U.S. Pat. No. 7,464,557 B2, which was co-invented by the inventor of the presently disclosed method. That prior invention is referenced here in its entirety.
The disclosed method and system assumes that a low-pressure natural gas pipeline or stranded well is available adjacent to the fleet that will use the liquefied natural gas; that the natural gas is delivered at a pressure of about 60 psia or greater; at a temperature of approximately 60° F.; and with a chemical composition that is about 95% methane, with some N2 and CO2, but otherwise “clean”. In the event that the pipeline gas is not as clean, there are several known clean up systems that can be integrated with the disclosed method and system. In the event that the gas source is at a lower-than about 60-psia pressure, a small booster compressor can be used to raise its pressure, prior to entry into the main compressor. Alternatively, the first stage of the main compressor can receive the feed gas at whatever pressure above atmospheric that is available.
The low-pressure pipeline (or stranded gas well) stream is separated into a fuel stream that provides fuel to a natural gas fired “prime mover”, such as an internal combustion engine or a micro-turbine, and into a product stream to be compressed and liquefied. The use of natural gas as a fuel in a prime mover (an internal combustion engine or gas turbine) is well understood and is not claimed as an innovation. In contexts, such as California, where it may be difficult to obtain a permit for a natural gas fired prime mover, the disclosed method can function with a motor drive, with electricity delivered by the electrical grid. In that embodiment, the waste heat that would drive the chiller would be limited to the heat of compression that is produced in the multi-stage compressor. Depending on the configuration of the compressor, including the number of stages, the outflow stream from any single compressor stage may be hotter than about 280° F., which is more than adequate to drive a chiller that can produce worthwhile low grade (approximately 42° F.) refrigeration.
The first step in the liquefaction process is the removal of CO2 and any water from the pipeline gas stream, in a multiple vessel molecular sieve, which requires periodic regeneration, where the regeneration gas (loaded with CO2) is sent to the prime mover for use as fuel. This step is well understood in the industry and is not claimed as an innovation. The cleaner the pipeline gas the less complex the molecular sieve system and the less frequent the need for regeneration. Alternatives to molecular sieves include membrane separation technology and refrigerated methanol clean up systems. The disclosed method is neutral as to which CO2 and water removal method is optimal for the particular scale and location at which the invention is deployed.
The cleaned, dry natural gas is sent to a multi-stage natural gas compressor, such as might be used at CNG stations, but likely smaller, because it will be operating 24-hours per day at a steady rate, rather than in the “just in time” mode of most CNG compressors. A novel aspect of the disclosed method and system is the use of a CNG station and/or standard CNG equipment to produce liquefied natural gas or CCNG, allowing for the upgrading of existing CNG stations, yielding an operating mode that includes off-peak production, on-site storage, fast fill during vehicle fueling, and the dispensing of a wider range of natural gas products, all of which are colder and denser than standard CNG
The disclosed method and system will allow existing CNG stations to be upgraded to LNG/CCNG production, by using the existing CNG compressors; and it will allow makers of existing CNG equipment to participate in the expansion of the vehicle-grade LNG industry. Thus, a widely deployed small-scale LNG/CCNG network need not displace all existing, well established CNG production and dispensing facilities, allowing for a smooth transition from low-density CNG to high-density LNG/CCNG, including the continued dispensing of CNG, say, to light-duty vehicles, but where that CNG is as cool as can be tolerated by existing CNG fuel tanks (say, about −20° F.) as compared to standard CNG which is almost always above ambient, say, at about 100° F. In other words, disclosed method allows for the stored LNG/CCNG to be dispensed as high-pressure CNG but at cooler temperatures than standard CNG, resulting in a denser product delivered to the on-vehicle fuel tank than can be accomplished with standard CNG dispensing. Note that the “cold content” of the stored LNG/CCNG does not need to be dissipated before it is dispensed to the non-cryogenic on-vehicle fuel tanks Rather, the outbound cryogenic LNG/CCNG is heat exchanged with incoming feed gas, warming the outbound, pumped-to-pressure LNG/CCNG to temperatures acceptable by the on-vehicle fuel tank, and thus pre-cooling the inbound natural gas feed stream to the VX Cycle equipment. That aspect of the disclosed system/method allows for the optimal temperature and density of the CNG but without wasting the refrigeration that was used to achieve the storability and pump ability of the LNG/CCNG.
The feed gas to the LNG plant will be compressed, in stages, from, about 60 psia to about 400 psia. That choice is an essential feature of the invention because pressures to about 3,600 psia are routinely provided by most CNG compressors. Operating a CNG compressor at lower pressures will reduce the compressor's workload and reduce the “heat of compression” that is absorbed by the natural gas. In some embodiments of the disclosed system/method, especially where the optimal product is CCNG at about −150° F. and colder and stored at about 700 psia and greater pressure, the feed gas may be compressed to above about 700 psia. That increase in compression work is a relatively minor manner when compared to the energy savings of not having to chill the natural gas down toward about −260° F., because for each degree of lowered temperature, the energy input required is exponential. By contrast, increasing the pressure of the gas from about 400 psia to about 700 psia, a less than about 2:1 pressure increase, requires only a modest extra amount of energy input.
The disclosed system has a preferred compression range of about 375 psia to about 710 psia, yielding a unique balance between compressor work in the front end and refrigeration output at the back end of the cycle. Note that the about 710 psia compression range is required only when CCNG is the optimal product. If warm LNG is the product, the lower-pressure range (about 400 psia) is adequate. Thus, each embodiment and deployment of the present invention will be calibrated to balance the refrigeration and compression input required to produce the desired product. That front-end compressor work includes the compression of a low-pressure recycle stream, whose pressure is directly related to the expansion of the about 400-to- about 700-psia natural gas stream to approximately 18 psia during the refrigeration process.
The single CNG compressor will perform two functions. It will be both the feed gas compressor and the recycle compressor. This is possible because the disclosed method and system is an “all methane” cycle, where the working fluid (refrigerant) and the feed stream are both methane. Both streams will be compressed simultaneously in a single CNG compressor. This is a major advance in LNG production, because the only LNG plants that use methane cycles are letdown plants, generally found at pipeline gate stations that serve large urban areas. However, letdown plants (by definition) do not require compression because they rely on high-pressure feed gas, and have the opportunity to send out large quantities of low-pressure natural gas into local low-pressure pipelines.
The disclosed method and system will use a uniquely integrated chiller to counteract the heat of compression and to pre-cool the CNG immediately after it exits the compressor's last stage after-cooler. That unique use of a well-established technology (absorption/adsorption chilling) is a second innovation of the invention, and is described in more detail below. In this disclosure the word chiller shall mean any non-mechanical chiller, such as an ammonia absorption chiller, lithium bromide absorption chiller, desiccant-based adsorption chiller, all of which are driven by waste heat rather than a motor.
Another novel aspect of the disclosed method and system is that the heat of compression will be mitigated, and the natural gas will be pre-cooled by refrigeration from a chiller powered by waste heat from the prime mover. In some embodiments of the disclosed method/system, the higher-grade portion of the heat of compression (from approximately 150° F. to above about 280° F.) is used to partially drive the chiller. Any remaining low-grade heat of compression contained in the gas stream is then dissipated in an inter- or after-cooler, prior to further chilling by the refrigerant produced at the chiller. Thus, the inlet temperature to each stage of compression (including the first stage) can be cooler than would be possible with inter-coolers alone. Those inlet temperatures can be reduced to at least about 50° F., and preferably down to about 30° F., substantially reducing the workload on each stage of compression.
The CNG compressor's inter-coolers (between stages) and after-cooler will be integrated with the chiller as outlined above. Thus, the gas streams that enter each stage of compression can be as cool as about 30° F. (or colder), increasing the density of the gas and reducing the workload on each compressor stage. (No freezing of the gas will occur because water and CO2 are removed prior to compression.) Also, the inter-cooler between the first and second stage of the multi-stage compressor will heat exchange the CNG stream with the colder recycle stream, chilling the CNG on its way to the second stage, and warming the recycle stream on its way to the first stage. This is an example of cold recovery from the low-pressure recycle stream that leaves the heat exchanger at approximately −30° F.
The inter-cooler between the second and third stage will be cooled by the refrigeration output of the waste-heat driven chiller. The same chiller will cool the CNG stream in the compressor's after-cooler, and in a subsequent heat exchanger, down to as cold as about −22° F.
The chiller will be “powered” by the waste heat from the prime mover, recovering a significant portion of the approximately 67% of the energy content of the fuel used by the engine/turbine that is normally “wasted” by the engine's exhaust and water jacket or in the turbine exhaust. That recovered heat will increase the about 32%-35% thermal efficiency of the engine/turbine to a practical efficiency of approximately 43%, through the refrigeration output from the absorption chiller. In some embodiments, a portion the refrigeration output of the chiller can be used to pre-cool the inlet air to the turbine that drives the cycle, thus improving the efficiency of the turbine. The disclosed method and system seeks to use any recovered refrigeration at the earliest possible place in the cycle, reducing workload as soon as possible so that energy saving cascades through the process. Thus, when a turbine is the prime mover, the chiller's refrigeration output will first be used for cooling the inlet air to the turbine. Any remaining refrigeration will be used to cool the inlet gas streams to each compressor stage, with any remaining deep refrigeration used to cool the last stage outflow gas, prior to its entry into the main heat exchanger.
The integrations between the chiller and the compressor, as outlined above, will allow the “heat of compression” to be mitigated in each stage of the compressor and/or used to drive the chiller, improving the compressor's efficiency and allowing the CNG to exit the compression cycle pre-cooled to as low as about −22° F.
The pre-cooled CNG (at between approximately 400 psia and about 700 psia) will then be sent to a heat exchanger where it is further cooled, condensed, and (after several steps outside the heat exchanger) is sub-cooled and liquefied to produce liquefied natural gas, which will be sent to a cryogenic storage tank at an appropriate pressure (about 65 psia) and a temperature of approximately −245° F. Alternatively, the approximately 700 psia natural gas is cooled to only about −150° F. (or slightly colder) and is stored in a cryogenic storage tank at that pressure, as CCNG. As such, the cryogenic “product” of the disclosed method/system is dense enough (at approximately 15 pounds per cubic feet) for storage, and suitable for pumping to any desired pressure by standard cryogenic liquid pumps, even though the CCNG is not a liquid. The optimum pump choice, especially as to the inlet pressures to the pump, will be determined by the cost and efficiency of available equipment by various pump makers. As discussed above, some pumps will tolerate higher inlet pressures, while others will require a two-step approach that first expands the CCNG to a lower pressure, causing much of it to become a pump-able liquid, with the remaining vapor either returned for re-compression or expanded again.
The chiller will improve the cycle efficiencies in two ways. First, it will cool the compressors second-stage inlet stream. Second, it will reduce the “warm end loss” of the heat exchanger, turning it into “warm end gain”.
The cooling of the compressor inlet streams will result in approximately an about 10% reduction in compressor power usage. This feature alone will increase the efficiency of the prime mover from, about 33% to about 36.5%, or approximately 10 kW.
The chilling of the compressed feed gas will significantly reduce the stream's heat content (enthalpy), compared to the heat content of the returning low-pressure stream. That will happen because the feed gas will be compressed to nearly about 400 psia, in one embodiment, where its behavior is “non-ideal” (similar to a liquid's behavior), while the low-pressure recycle stream (at about 18 psia) will behave in a nearly “ideal” manner. Those conditions will reduce the expander's refrigeration requirement by approximately 15%, reducing power demand by another about 15 kW.
The total power reduction achieved (10 kW+15 kW=25 kW) for the production of LNG equals about 20%. At the scale of the disclosed method and system, that power reduction is important. The power required for CCNG production, will be further reduced by another approximately, 25%.
Another novel aspect of the disclosed method and system is that the three main components of the “front-end”—the engine, the chiller, and the CNG compressor—will be linked, each to the other two components, allowing standard CNG equipment to produce cold, moderate pressure CNG which is then further chilled to produce LNG or CCNG
The disclosed method and system, unique among LNG cycles, will harness the CNG compressor's power source for the chilling of the CNG. The same engine or turbine that powers the CNG compressor will (through waste heat) power the chiller. Also, the disclosed method and system is unique among LNG cycles in that it can produce CCNG, which has many of the same attributes as LNG (storability, transportability, pump-ability) but requires significantly less energy input.
That integration of the prime mover, chiller and compressor is unprecedented for a variety of reasons, including because all other commercial-scale LNG cycles are not dependent on the compression of low-pressure gas to CNG, and the subsequent condensing and liquefaction by expansion of the same (cooled) CNG.
The disclosed system exploits the limitations of low-pressure methane compression-to-expansion, without using refrigerants such as N2, as in nitrogen expansion cycles; or “mixed refrigerants” as in MR cycles; or hydrocarbons, as in cascade cycles; and without the inefficiencies of high-pressure Joule Thompson cycles. The disclosed method and system will achieve a good degree of the efficiency available to turbo-expander (letdown) LNG plants, but at much smaller scales and at lower capital costs, and without the need for a high-pressure pipeline or a low-pressure outflow “sink”. Also, the disclosed system builds on the CCNG principles advanced in U.S. Pat. No. 7,464,557 B2 by providing a cost-effective way of producing CCNG and by enhancing the “cold recovery” innovations in that invention to the cold recovery from stored CCNG to dispensed CNG, as outlined above.
A significant portion of the product stream cannot be liquefied in a single run through the process and is sent back to the beginning of the cycle to be re-compressed, mixed with more (cleaned) natural gas from the pipeline (or stranded well), pre-cooled by the chiller and sent through the heat exchanger for liquefaction or CCNG production. This return stream (the recycle stream) gives up its cold in the heat exchanger (a form of cold recovery), contributing to the cooling and condensing of the portion of the stream that ends up as LNG/CCNG.
Another novel aspect of the disclosed method and system is that known refrigeration “producers”, such as JT valves and turbo-expanders are integrated at the “back-end” to convert the cold CNG produced in the front into LNG. An alternative, and preferred embodiment uses a compressor-loaded, (or generator-loaded or brake-loaded), multiphase, turbo-expander in lieu of a JT valve, (also known as a JT valve). That device is shown as E2 (for expander 2) and C5 (for compressor 5) on
In order to achieve about −250° F. LNG at about 65 psia, (or the about −150° F. CCNG at about 700 psia) significantly more refrigeration is needed than can be provided by the front-end chiller. Two sources of refrigeration are at work near the main heat exchanger.
The first refrigeration source is a JT valve, also known as a throttle valve, or preferably, as illustrated on
A portion of the about −170° F. (or about −150° F.) stream, at about 400 psia (or just above about 700 psia when CCNG is the intended product), is sent through the JT valve or preferably the multi-phase, compressor-loaded expander (shown as E2 and C5 on
For the sake of clarity, the sub-cooler 94 is shown in the process flow diagram as a separate heat exchanger. However, the sub-cooling task might occur in the single plate fin heat exchanger. On
The low-pressure stream that cooled the main product stream in the sub-cooler will be sent back toward the beginning of the process as part of the recycle stream. Prior to its return trip through the single heat exchanger, the recycle stream will be joined by a recycle stream from the second refrigeration source, a two-stage cryogenic methane turbo-expander 110. The combined recycle stream, while low pressure, will be cold enough to substantially cool the main process stream to say, about −140° F. (when CCNG is the goal) to about −170° F. when LNG is the goal. The balanced use of a cold, low pressure recycle stream to achieve fairly deep refrigeration of the “moderate” pressure main stream, is yet another novel aspect of the disclosed method and system. That balance is especially efficient when the intended product is CCNG, which requires only slightly more compression work than LNG but significantly less refrigeration input. Thus, the production of CCNG by way of the disclosed method and system allows for the optimal phase of vehicle-grade cryogenic methane, achieving all the benefits of standard (cold) LNG but with significantly reduced energy input. Indeed, the energy input required to achieve CCNG will be nearly as low as the energy input required to produce CNG, but the product will be significantly more valuable because of its storability, (allowing for off-peak production) and because it will always be dispensed cooler and denser, even when dispensed as CNG.
The second source of refrigeration, the turbo expander 110 on
The methane expander receives that portion of the main stream from the heat exchanger (HX5 on
That second stream will leave the heat exchanger at approximately −90° F. to about −104° F., and approximately 400 psia and will be expanded in the cryogenic expander to approximately 40 psia, and thus cooled to approximately −220° F. (when LNG is the desired product); sent back to the heat exchanger for “reheat” (cooling the other streams in the heat exchanger); exiting the heat exchanger at about 39 psia and about −30° F.; giving up its “coldness” to the warm outflow stream from the compressor that “loads” the expander; entering that compressor at approximately 35° F. and about 38 psia; and returning to the second stage of the main compressor for further compression. When CCNG is the desired product the pressure of the gas streams is slightly above about 700 psia but the gas streams need not be cooled to colder than about −150° F. (However, if the CCNG is to be transported, it may be cooled to a colder temperature in anticipation of some heat gain during transport.)
The JT valve, multi-phase expander and the cryogenic methane expander all function well with the about 400-psia to about 700 psia inlet pressures. When LNG is the desired product, a higher than about 400-psia pressure might yield slightly more refrigeration at the JT valve or multi-phase expander, but not enough to warrant a more expensive heat exchanger and the need for more work by the compressor. The about 400 psia is a “comfortable” inlet pressure for a small expander. In short the selected conditions constitute a “sweet spot” in the efficient small-scale production or LNG yielding an excellent balance between refrigeration produced, the size and temperature of the recycle stream, the workload of the compressor, and the total amount of LNG produced per unit of fuel required to run the compressor. When CCNG is the desired product the work required to produce the extra pressure is more than offset by the lowered refrigeration requirement. If the cryogenic expander is most “comfortable” operating with about 400 psia inlet gas, then that portion of the gas stream that is sent to that expander can be withdrawn from the main compressor at that pressure, and the remaining portions can be further compressed to just above about 700 psia and directed to the main heat exchanger as outlined above. That optimization will require “extra” compression for only a portion of the throughput of the compressor.
The JT or multi-phase expander effect, the sub-cooler and the expander reheat cycle outlined above are all known in the industry. What is unique is the application of those individual techniques to a small-scale LNG plant in a specific, optimal manner. The disclosed method and system uses the main CNG stream as a “working fluid” (refrigerant) to liquefy a significant portion of itself, returning a “recycle” portion for re-compression, but only after several “cold recovery” steps. Also, the disclosed method and system offers a wide-range of cryogenic methane products, all dense enough for cost-effective storage (and thus, off-peak production), and pump-ability. At the warm end, CCNG production by the disclosed method and system achieves those benefits with the lowest possible energy input, rivaling the energy input required for ordinary CNG production.
The pre-cooling by absorption/adsorption refrigeration captures the waste heat of the engine (and/or the heat of compression) and delivers a significant amount of refrigeration to the CNG compressor without any additional fuel use. That pre-cooling step is illustrated on
The recycle stream will be lower in volume than found in alternative LNG cycles because of the combined effect of the front-end absorption chiller; the moderate pressure, cold JT valve or multi-phase expander; the sub-cooler; and the cryogenic methane expander. This is especially true when CCNG is the desired product. The smaller recycle stream, will allow the compressor to do less work, requiring less power output from the prime mover, which in turn will use less fuel, reducing the plant's fuel use relative to the total output of LNG/CCNG to levels matched only by much larger LNG plants.
The prime mover 10 may be an internal combustion engine fueled by natural gas. A micro-turbine may also be used as the prime mover 10. The prime mover 10 directly drives a multi-stage compressor 34 comprising a first stage 22, second stage 26, and third stage 30. Variations on the number of stages are possible, as are methods for transferring the power of the prime mover to the compressor. Those variations will not impact the core methodology of the disclosed invention and may be selected on the basis of capital costs, equipment availability, and other “optimization” factors.
Waste heat from the prime mover 10 is used to heat the regeneration gas in the molecular sieve clean up system, discussed bellow. Waste heat is also used as an energy source in an ammonia absorption chiller 38, shown simply as a circle, which provides cooling to the compressor's second inter-cooler 82 and after-cooler 86, at the first heat exchanger 42 and second heat exchanger 46, which will be discussed in more detail below.
The waste heat from the prime mover 10 is delivered to the ammonia absorption chiller 38 by piping that extends the prime mover's jacket water system (not shown for clarity), which normally cools the engine. That hot jacket water is further heated by hot engine exhaust in the third heat exchanger 54. The engine exhaust gas is then sent to a flue 58 at about 225° F. A catalytic converter may be located at the appropriate place in the engine exhaust outflow system. A water pump 62 is shown just prior to the hot water's entry into the third heat exchanger 54. The pumping of the water with pump 62 to pressure will keep it from boiling. The hot water stream and the return stream from the ammonia absorption chiller 38 are shown as dotted lines on the process flow diagram.
The configuration of the ammonia absorption chiller 38, and its rejection of low-grade waste heat is a well-known technology. The process flow diagram does not show the internal process for the ammonia absorption chiller, but does show a cooling tower 66, which uses water as the cooling medium, disposing low-grade waste heat to the atmosphere. That cooling tower 66, in fluid communication with a make-up water line 67, also helps cool the compressor's inter- and after-coolers 80, 82, 86.
Point 3a′ is the location where the inlet natural gas stream from the pipeline (or stranded well), at approximately 60 F and about 55 psia, is mixed with a clean re-cycle stream (about 80 F, about 55 psia) that arrives at that point from down-stream process points that will be described in subsequent sections of this narrative.
The first significant step in the liquefaction process is the clean up cycle, which is well understood by those in the natural gas processing field, especially related to natural gas that is delivered from a pipeline, known as “pipeline quality natural gas.” Most pipeline gas contains some amount of CO2 and water, which need to be removed prior to liquefaction; otherwise ice will form down stream in the process, causing the cycle to “freeze up”.
A molecular sieve 70 is configured to remove CO2 and water from the natural gas in an adsorbent such as, but not limited to, zeolyte. The molecular sieve 70 does not remove any heavy hydrocarbons from the natural gas feed stream. That portion of the clean up cycle, if required, occurs near point 16a, and will be discussed below. The molecular sieve 70 may be a multi-vessel system that regenerates the adsorbent beds by using heated natural gas as the “purging” fluid. The resultant CO2 laden regeneration gas is sent from the molecular sieve 70 to the prime mover 10 as fuel.
The process flow diagram does not show the configuration of the molecular sieve 70 system, nor the detailed piping and valves that control the delivery of hot exhaust gas to warm the regeneration stream, because that technology is well understood and is not an innovation of this invention.
At point 3a, the feed gas stream (at about 68° F., 55 psia) consists of the cleaned “make up” stream from the pipeline (or stranded well) and the recycle stream that joined it at point 2a. The reason clean recycled gas is mixed with pipeline gas, prior to the molecular sieve 70, is to reduce the CO2 and water load on the mole sieve, by “diluting” the stream's CO2 and water content. The stream arriving at point 2a is the outflow of the first stage compressor 22. The purpose of the first stage compressor 22 and the source of the “flash recycle” stream that it compresses will be discussed below. The stream arrives at point 2a after going through a first inter-cooler 80
The first cooling step in the LNG production process occurs through the fourth heat exchanger 74. The fourth heat exchanger 74 allows the about −30° F. “flash recycle stream” to chill the cleaned gas to about 42° F., as shown at point 3b. The slightly cooled main gas stream is mixed with a recycle stream from a natural gas expander's 78 (located on
The combined stream enters the second stage compressor 26 at about 54 psia for compression, and leaves the second stage compressor 26 at about 210 psia. The heat of compression warms the natural gas stream to about 284° F., as shown at point 4.
Natural gas at about +284° F. and about 210 psia will be called warm CNG. The warm CNG is sent to an inter-cooler 82 (which is cooled by water from the cooling tower 66) and then on to the first heat exchanger 42 where it is further cooled by the refrigerant stream from the ammonia absorption chiller 38. The cooling water inflow and outflow from the inter- and after-coolers are not shown, because that aspect of the process is well understood by those familiar with gas processing and the workings of gas compressors.
The natural gas stream exits the first heat exchanger 42 at about 35° F. and about 209 psia, as shown at point 5. It then enters the third stage compressor 30 for additional (and final) compression, leaving the third stage compressor 30 at about 150° F. (due to the heat of compression) and approximately 404 psia. The warm CNG travels to the after-cooler 86, exiting it at about 80° F. and then on to the second heat exchanger 46 where it is further cooled by the refrigerant from the ammonia absorption chiller 38 to about −22° F. The entire purpose of the waste-heat driven ammonia absorption chiller 38 is to chill the natural gas stream during its trip through the second and third stages 26, 30 of the compressor 34, and to deliver the natural gas, pre-cooled to about −22° F., to the plant's main heat exchanger 90 (shown on
The main heat exchanger 90 is the main heat exchanger for the disclosed system. The sub-cooling heat exchanger 94 may be integrated into heat exchanger 90 or may be a separate heat-exchanging unit as shown. The pre-cooled CNG enters the heat exchanger 90, traveling from point 8 toward point 9. However, it is split into two streams, one going to point 9 and one to point 16. The stream that moves to point 9 arrives there at about −170° F. as LNG at moderate-pressure, having been chilled by the counter-flowing stream in the main heat exchanger 90.
The moderate-pressure LNG moves from point 9 toward point 13, but is split into two streams, one of which moves through the first expansion valve 98 (also known as a JT valve), with the other portion moving on toward point 10. The first expansion valve 98 causes the LNG to become a two-phase (mostly liquid and less than about 30% vapor) stream, arriving at point 13 at about −254° F., but “letdown” to at a substantially lower pressure of only 19 psia. This stream's function is to act as a refrigerant on the main stream that is chilled to become LNG. Refrigeration occurs in a sub-cooling heat exchanger 94 as the liquid portion of the stream vaporizes and transfers its “coldness” to the about −170° F. LNG counter-flowing through the sub-cooler. The vaporization of the refrigerant stream does not change its temperature during that phase shift from liquid to vapor, allowing the vaporized refrigerant stream to move on to points 14 and 15 at approximately −253° F., ready to impart further cooling in heat exchanger 90, as described below.
That cryogenic two-phase “refrigerant” stream, described above, is sent through sub-cooling heat exchanger 94 (a sub-cooler) where it cools the “product” stream arriving from point 10 (about −170° F., about 400 psia) to become LNG, arriving at point 11 at about −199° F. to approximately −251° F. by the time the product reaches point 11. The about 399 psia LNG is then dropped in pressure through another expansion valve 102 arriving at point 12, and subsequently sent to the LNG storage tank 106, at the design pressure of that tank. In the embodiment shown in
Returning to the “refrigerant” stream that exits the sub-cooling heat exchanger 94, it arrives at points 14 and at 15 at approximately −253° F. and moves on for additional “cold recovery” in heat exchanger 90, leaving the main heat exchanger 90 at approximately −30° F., as indicated by the values shown at point 18 and 18a. The remaining cold is further recovered in the fourth heat exchanger 74, as discussed above. The relatively warm stream (about 35° F.) arrives at point 18b at just about 17 psia. Thus, the function of the first stage compressor 22 is to recompress this (clean) stream so that it can return to the cycle and join the make up stream after point 2a, as discussed above.
Returning to the stream that entered heat exchanger 90, and was split into two portions, we can now follow the portion that arrives at point 16. Its trip through heat exchanger 90 allowed the about −22° F. inflow stream to be chilled by the other streams in the heat exchanger, so that it exits heat exchanger 90 at between about −90° F. to about −105° F. (the “warmer” the exit stream, the less energy was spent on cooling it.) This stream is also a “refrigeration” stream, providing the bulk of the refrigeration required to cool the product stream. The, say, about −100° F. CNG (at approximately 400 psia) is sent to a turbo-expander 110 that substantially cools the stream by expanding it to about 40 psia, and by having the turbo-expander 110 “compressor loaded” (by an expander driven compressor 114) so that “work” is performed. It is the expansion process, including the work performed, that achieves the dramatic cooling of the CNG.
The exit stream from the turbo-expander 110E will be approximately −220° F. and about 40 psia (see point 16b), allowing the natural gas stream to separate into heavy hydrocarbon liquids (such as ethane, and butane) and a nearly pure methane stream in a phase separator 130, shown near point 16a. That phase separation will take place if the feed gas contains any such heavy hydrocarbons. In that event, the liquid heavies are sent through a pump 134, to increase the stream's pressure (see point 16h), and then sent into the storage tank 106 to join the main liquid product of the process, the liquefied natural gas. The exact location of where the liquid heavies enter the tank can vary, and is subject to engineering decisions related to the mixing of the slightly warmer heavy hydrocarbon liquids with the larger and colder LNG, that will not impact the basic aspects of the disclosed system. Note that the small heavies stream, which is approximately at −220° F. will slightly warm the contents of the LNG tank, even though it is receiving LNG at approximately −250° F. On the other hand, if the feed gas to the cycle contains very little or no heavy hydrocarbons, such slight warming will not occur. For feed gas streams with a higher concentration of heavy hydrocarbons, or where the product LNG is used by vehicles that cannot tolerate any significant heavy hydrocarbon content in the LNG, some portion of the heavies from the phase separator may be sent as fuel to the prime mover. In short, the disclosed system can tolerate a variety of feed gas compositions, including from pipelines and stranded wells, and variety of product specifications for the LNG.
Continuing the process at 16a, the very pure methane stream, at about −220 F is a refrigerant stream that helps cool the stream that went from point 8 to 9 and the stream that went from point 8 to point 16. In this manner, (and by way of the sub-cooler previously described), the pre-cooled (about −22° F.) about 400 psia CNG is both a “product” stream (beyond points 10, 11, and 12) and a refrigerant stream. This aspect of the disclosed system is a unique version of a “methane expansion” cycle and is a core element of the innovation.
The outflow stream from the turbo-expander 110 leaves the heat exchanger 90 at about −30° F. and serves to mitigate the heat of compression as the same (about 39 psia) stream is sent through the expander driven compressor 114 that “loads” the turbo-expander 110. That “cold recovery” occurs in a fifth heat exchanger 118, allowing the expander 110 recycle stream to enter the expander driven compressor 114 at a “warm” state of about 35° F., exiting the expander driven compressor 114 at about 98° F., and exiting the fifth heat exchanger 118 at about 35° F., having dealt with the heat of compression. One optimization of the disclosed system may include a water-cooled after-cooler immediately after the expander driven compressor 114, before point 17, allowing the temperature of the stream to be cooler than now shown at point 17a, all of which is included in the scope of the disclosed system. Other optimizations will be obvious to those familiar with natural gas processing, but without impacting the core aspects of the innovative methane expansion cycle disclosed here.
It is the work performed by the expander driven compressor 114 that allows the expander 110 recycle stream to be returned to point 3b at about 56 psia, so that it can enter the second stage compressor 26 at a moderate pressure, rather than the first stage compressor 22 at a lower pressure.
As discussed above, several features of the disclosed method and system can be optimized. The following are examples of such adjustments and are generally illustrated on
It should be noted that
When the process shown in
The process shown in
Returning to
After clean up, the feed gas moves on to HX2 where it is pre-cooled by a portion of the refrigerant output (shown as stream R) of the Chiller. Also, the feed gas is blended with a recycle stream of natural gas that results from pressure letdown later on the process. That blended stream enters the second stage of compression and its pressure is increased by a ratio that may range from two-to-one to a ratio of four-to-one, depending on the number of compressor stages selected. The heat of compression is dissipated in a Fin-Fan cooler (F2). The now near-ambient gas stream moves on the HX3 where it is cooled to approximately 30° F. by a portion of the refrigeration output of the Chiller. Such pre-cooling before each stage of compression helps reduce the workload of the compressor.
Next, the gas stream is compressed in the third (or last stage) of the compressor to the approximately 400 psia that is needed for LNG production. The heat of compression is dissipated in F3, and final pre-cooling is accomplished in HX4. As discussed above, in the description of
The product stream, having been liquefied by heat exchange from the outflow from E2 is then allowed to enter the cryogenic storage tank as LNG. As discussed above, the LNG's temperature and pressure can be “designed” for different end uses.
Meanwhile, the refrigerant stream that caused the liquefaction of the product stream in HX5S moves through HX5 to give up any remaining refrigeration to the other streams in HX5, and then exits HX5 at colder than zero F but warmer than about −30° F., and is sent to C5 for some compression. The purpose of C5 is to “load” E2, so that work can be performed and refrigeration produced in E2. The impact of C5 on raising the pressure of that recycle stream will vary, depending on design decisions for each deployment. After compression in C5, that recycle stream enters HX6, where it is cooled by the remaining refrigeration contained in the outflow from E, (which leaves HX5 at colder than zero degrees F.).
The next stop for the cooled and somewhat compressed recycle stream is to be further compressed in C1 of the main compressor. That heat of compression is dissipated in F1, and the recycle stream is further cooled in HX2 by the refrigerant output of the Chiller (shown as stream A′), where the recycle stream is blended with the cleaned process stream.
Meanwhile, the recycle stream that left E1 and HX5, and was also used as a refrigerant in HX6, is compressed in C4, which loads E1. Again, the purpose of C4 is to allow E1 to produce work, thus creating refrigeration. After C4 that second recycle stream's heat of compression is dissipated in F4. The stream is further cooled in HX7 by Chiller-produced stream A-B. The second recycle stream then enter C2 and, along with the clean feed gas and the recycle stream that left C1, is compressed to at least a two-to-one ratio, depending on the total number of compression stages selected by the process designer. The combined streams leave C2 at the selected pressure (approximately 200 psia or higher) and then move on to F2 for the dissipation of the heat of compression. (It should be noted that each trip through a heat exchanger or a Fin-Fan cooler will cause a, say, about one pound pressure drop, which needs to be accounted for in the overall pressure increase ratios at each compressor in the process.) After F2, the combined gas stream is pre-cooled in HX3 by the refrigerant output of the Chiller, and then the gas stream moves on to C3, which on
Exiting C3, the combined gas stream's heat of compression is dissipated in F3. The gas stream is pre-cooled in HX4 and enters HX5 as discussed above. Thus, the gas stream that enters HX5 is a product stream that ends up as LNG after leavening HX5S and is two refrigerant streams (one cooled by E2 and the second one cooled by E1), where the two refrigerant streams are recycled through several steps of “cold recovery” and compression.
Returning to the Chiller on
In other words,
Thus
As in
Instead of a Fin-Fan cooler at the outflow from C2, C3 and C4,
After each stage of compression and with the heat of compression given up to warm the hot water that drives the Chiller, the natural gas streams are pre-cooled in HX3 and then sent on to HX5 for further cooling as described above. However, when
Thus, when the process illustrated in
As noted above, the core elements of
Turning to
In most aspects,
The high-pressure CCNG warms slightly (approximately 2-degrees F.) above its storage temperature, warming from, say, about −150° F. to about −148° F. That “cold content” is recovered in HX7, where the high-pressure CCNG is heat exchanged with the pre-cooled gas stream that left HX3 at a temperature as cold as about −22° F. and as warm as about 50° F., (depending on the choice of the Chiller and the available waste heat sources) and which has not yet been chilled in HX5. The chilling of that pre-cooled gas stream in HX7 will cause its temperature to fall to within about 10-degrees of the high-pressure CCNG that is flowing counter to it in HX7. Thus, the process gas stream leaves HX7 and enters HX5 at approximately −138° F., requiring significantly less refrigeration input from E2 and E1 to exit HX5S at about −150° F., ready for storage.
At the same time, the high-pressure CCNG is warmed in HX7 by the process stream, leaving HX7 as CNG (at 3,000 to 3,600 psia) with a temperature of about −20° F. to about 60° F., depending on the inlet temperature of the process gas and the relative flow rates of the process gas and the high-pressure CCNG. The cool CNG (about −20° F. to about 60° F.) is substantially cooler than standard CNG at above about 100° F., and therefore denser than standard CNG. Instead of the approximately 10.5 pounds per cubic feet density of standard CNG, such cool CNG, dispensed from CCNG (or “warm” LNG) will have a density of more than about 13 pounds per cubic feet, substantially increasing the capacity of existing on-board CNG fuel tanks
The disclosed process illustrated on
The disclosed process illustrated on
The disclosed process illustrated on
The main purpose of producing LNG (at any scale), CCNG, or CNG is to increase the density of natural gas, making it heavier per cubic foot of volume, thus increasing the energy content of the natural gas per a given volume (say, per cubic foot). Generally, LNG is the densest form, with CCNG a close second, and CNG the least dense form.
That range of density, from densest (coldest) LNG to the least dense (and warmest) CNG does not necessarily shed light on the energy input required for each condition relative to the density achieved. In other words, most observers would guess that LNG is the most costly product, because it requires “expensive” refrigeration, and that CNG is the least costly product because it “only” requires compression. However, that “conventional wisdom” is not accurate.
The approximate energy input required to make CNG (at 3,600 psia and 90 F, with a density of 10.65 pounds per cubic foot) from one decatherm of natural gas is 333 kWH. The ratio of that energy input to the density achieved is 333÷10.65=31.3.
By contrast, the VX Cycle will produce LNG (at 65 psia and −245 F, with a density of 25.6 pounds per cubic foot), from the same decatherm of natural gas, using approximately 721 kWH of power. That ratio of power to density achieved is 721÷25.6=28.2, which is lower than for CNG. In other words, the VX Cycle will achieve a higher-density product at a lower energy input cost (per density achieved) then standard CNG production systems. Stated differently, VX Cycle LNG will cost less to produce than CNG, when accounting for what is achieved.
More to the point of the CIP, “warm” LNG and CCNG produced by the VX Cycle are the most cost-efficient products, per the following:
The energy input to density ratio of VX Cycle “warm” LNG or CCNG is approximately 19% lower than the energy input to density ratio required for standard CNG production. Over the lifetime of any single facility, especially if the feed-gas is on a pipeline, where “retail” prices are the norm, the extra capital cost of VX, compared to a CNG production system, will be quickly offset by the reduced energy input costs.
Generally, the coldest LNG is approximately −260° F. at approximately 50 psia. However, for most small-scale applications, including for use as a vehicle fuel, LNG need not be that cold. (The colder the LNG is the more energy input is required for its production, but not in a linear way but “exponentially” because each degree drop in temperature requires an exponential input of energy.)
Coldest LNG (near −260° F.) is necessary if the LNG is to be shipped across the oceans in LNG tankers, where warmer LNG would boil off quicker. Similarly, regional LNG production facilities that produce large amounts of LNG for distribution to individual customers, delivering the LNG in cryogenic trailers, need to produce cold LNG in order to avoid boil off (or “weathering”) during transport and during on-site storage, prior to dispensing.
Because the VX Cycle is primarily (but not exclusively) designed for small-scale LNG production, at the customer's site, avoiding long-distance transport, it can aim for warmer LNG as a product. In other words, the LNG bus or truck that receives the dispensed LNG does not “care” if it is −260° F. or −240° F., as long as the tank is full. (The LNG is vaporized and sent to the engine as gas, so the engine does not “care” what the temperature of the on-board LNG is.)
The innovations described in
That entire range of temperatures, pressures and resultant densities is pump-able by cryogenic liquid pumps, even though the warm end of the range is CCNG, a non-liquid phase of natural gas.
That entire range of storable and pump-able products can be achieved by the VX Cycle at a ratio of energy input (kWH) to density that is lower than 30, with most of the conditions on that continuum achieved by VX at a ratio of less than 26.
Thus the VX Cycle identifies a wide-ranging sweet-spot for dense-phase natural gas production where the density of the VX product is between approximately 19 to 25 pounds per cubic foot, and where that density is achieved by the optimal balance between compression and refrigeration input.
Below are suggested operational values for 3 proposed VX systems:
The disclosed system has many advantages. Returning to
As outlined in more detail above and below, the disclosed system offers many advantages over standard LNG production and to standard CNG production. Broadly, with regard to LNG production, the disclosed system may produce a wide-range of LNG products (as measured by the temperature, pressure and density of the LNG), but with lower refrigeration input costs, which yield lower fuel and operating costs, using readily available equipment. As in the parent application the disclosed system can operate with low-pressure feed gas, with only two natural gas expansion devices, and at production scales as small as 6,000 liters per day. In summary, the disclosed system may produce storable, pump-able, and transportable LNG from low-pressure feed gas sources, at small production scales and at lower energy input costs than other systems facing the same low-pressure and small-scale challenges.
With regard to CCNG production, the disclosed system offers many advantages over standard LNG production and to standard CNG production. The disclosed system may produce a new range of dense-phase natural gas products (CCNG) that, while not a liquid, can be stored and transported in moderate-pressure cryogenic storage containers, and, most importantly, can be pumped by cryogenic liquid pumps to any desired pressure. That range of dense-phase natural gas products (CCNG of varying temperatures colder than about −150° F., and varying pressures higher than about 700 psia), may be produced with lower refrigeration input costs, yielding lower fuel and operating costs, using readily available equipment. As in the parent application, the disclosed system can operate with low-pressure feed gas, with only two natural gas expansion devices, and at production scales as small as 6,000 liters per day. In summary, the disclosed system may produce storable, pump-able, and transportable CCNG from low-pressure feed gas sources, at small production scales and at lower energy input costs than other systems facing the same low-pressure and small-scale challenges.
With regard to CNG production, the disclosed system offers a cost-effective way to produce dense-phase natural gas (CCNG) during off-peak periods, which can be pumped by cryogenic liquid pumps to any desired pressure, for dispensing as cooler-than-standard (and denser) CNG, suitable for use in existing on-vehicle CNG fuel tanks, using readily available components, only two expansion devices, at scales as small as the equivalent of 6,000 liquid gallons per day. In summary, the disclosed system may produce a storable and pump-able dense-phase natural gas that can be dispensed as CNG, but without losing the refrigeration content inherent in the stored CCNG (as compared to standard L/CNG systems where the refrigeration content is lost), and which can be sited at a low-pressure feed gas source, at production scales suitable for individual CNG fleets, and which system will have a lower energy input cost than any L/CNG dispensing system, rivaling the energy input costs of standard CNG production/dispensing systems, but yielding colder/denser CNG.
It should be noted that all temperatures and pressures listed are approximate, and the disclosed system will work at other selected temperature and pressure values, but the about 400 psia range of the CNG is a “sweet spot” for a methane expansion cycle. The heat recovery from the prime mover 10, and the use of the ammonia absorption chiller 38 is not an essential element of the innovation. For example, a high-efficiency gas-fired turbine (for example, with an adjacent steam cycle or an organic Rankine cycle) may increase the efficiency of the prime mover 10 (by using its waste heat) such that the operation of the ammonia absorption chiller 38 would not be viable. In that event, the disclosed system would “spend” more energy on compressing the CNG, but by way of a more efficient prime mover, thus causing the total energy use to be about the same. Similarly, the main compressor 34 may be, in an alternative embodiment of the disclosed system, an electric power driven compressor, especially where low-cost electricity is available. The vapor return stream shown on the process flow diagram is to allow any “flash” from the liquefied natural gas-fueled vehicle's storage tank to be recycled, rather than vented. The vapor return stream may travel within a vapor return line 125. The process flow diagram shown in
It should be noted that the terms “first”, “second”, and “third”, and the like may be used herein to modify elements performing similar and/or analogous functions. These modifiers do not imply a spatial, sequential, or hierarchical order to the modified elements unless specifically stated.
While the disclosure has been described with reference to several embodiments, it will be understood by those skilled in the art that various changes may be made and equivalents may be substituted for elements thereof without departing from the scope of the disclosure. In addition, many modifications may be made to adapt a particular situation or material to the teachings of the disclosure without departing from the essential scope thereof. Therefore, it is intended that the disclosure not be limited to the particular embodiments disclosed as the best mode contemplated for carrying out this disclosure, but that the disclosure will include all embodiments falling within the scope of the appended claims.
This patent application is a continuation-in-part of patent application Ser. No. 11/934,845 by David Vandor, entitled “Method and System for the Small-scale Production of Liquefied Natural Gas (LNG) from Low-pressure Gas”, filed on Nov. 5, 2007, the entire contents of which are fully incorporated by reference herein.
| Number | Date | Country | |
|---|---|---|---|
| Parent | 11934845 | Nov 2007 | US |
| Child | 13216803 | US |
