Patent Application
20250146744
The present disclosure relates generally to energy conservation, and more particularly, to a liquefaction, storage, and redeployment of a gaseous fuel.
As natural gas came to be produced, long-distance transport and local distribution pipelines had an inherent, but limited, amount of buffer capacity for gaseous fuel storage. Typically, pipelines are not built to flow at peak demand, e.g., for cold climates, and it is more economical to build local storage capacity for generality. To increase the buffer supply in natural gas systems, especially at points away from production and closer to consumers, natural gas has been liquified to make it denser so that more can be stored for deployment at times of peak demand.
Typically, natural gas storage technology includes a process of liquefying natural gas, involving cooling and storing at near atmospheric pressure and cryogenic temperatures of around minus 162 degrees C. and minus 259- or 260-degrees F., where the natural gas can be converted into a liquid state in dense volume. The natural gas taken from the ground typically has components that must be removed from the gas before processing to prevent them from freezing and clogging the liquefied natural gas (short for LNG) production flow. Components that are often required to be removed before cryogenic chilling include water, carbon dioxide (CO2), compounds containing sulfur, benzene, other aromatic hydrocarbons, and other hydrocarbon components with a carbon number of six or greater, e.g., heavy hydrocarbons.
In a conventional LNG system, this gas treatment typically employs expensive and complicated processes and devices, requiring a significant capital investment. Furthermore, conventional LNG production and storage typically requires removal of CO2 to prevent the CO2 from solidifying and clogging the liquefaction equipment, which results in a stream emission enriched in O2 releasing into atmosphere. Removal of CO2 from the gaseous fuel by adsorption or distillation has been applied in the current LNG storage industries. However, the current art has to build CO2 treatment equipment into the LNG system. When CO2 is removed, e.g., by liquid amine processes or solid desiccants, the off stream is enriched CO2 and is typically released to the atmosphere. Further, since the concentrated CO2 may contain trace amounts of compounds that should be destroyed before release to the atmosphere, incinerators, also known as thermal oxidizers, consuming significant fossil fuels are employed to incinerate a stream that is mostly non-combustible CO2, often requiring temperatures in excess of one thousand degrees Fahrenheit. Significantly, the current technologies for LNG production and storage have not been reliable and efficient in achieving ultra-low carbon emissions, e.g., scope 1 and scope 2 GHG emissions.
Therefore, there is a need in the industry for an improved process or method for storing natural gas densely with minimum emissions, minimal equipment, minimal capital cost, minimum operational cost, minimum energy intensity, and/or minimum operational scope 1 and scope 2 GHGe intensity.
The following figures are included to illustrate certain aspects of the present disclosure and should not be viewed as exclusive embodiments. The subject matter disclosed is capable of considerable modifications, alterations, combinations, and equivalents in form and function, without departing from the scope of this disclosure.
Illustrative embodiments of the present invention are described in detail herein. In the interest of clarity, not all features of an actual implementation may be described in this specification. It will of course be appreciated that in the development of any such actual embodiment, numerous implementation-specific decisions may be made to achieve the specific implementation goals, which may vary from one implementation to another. Moreover, it will be appreciated that such a development effort might be complex and time consuming but would nevertheless be a routine undertaking for those of ordinary skill in the art having the benefit of the present disclosure.
Throughout this disclosure, a reference numeral followed by an alphabetical character refers to a specific instance of an element and the reference numeral alone refers to the element generically or collectively. Thus, as an example (not shown in the drawings), widget “1a” refers to an instance of a widget class, which may be referred to collectively as widgets “1” and any one of which may be referred to generically as a widget “1.” In the figures and the description, like numerals are intended to represent like elements.
The term “scope 1 emission(s)” or “scope 2 emission(s),” as used herein, refers to specific categories of greenhouse gas emissions (“GHGe”) in the environmental sustainability industry. “Scope 1 emissions,” as used herein, refers to direct greenhouse gas emissions that result from sources that are owned or controlled by an organization. Examples of Scope 1 emissions include emissions from on-site fuel combustion, such as those produced by company vehicles or the operation of a company-owned power plant. “Scope 2 emissions,” as used herein, refer to indirect greenhouse gas emissions that result from the generation of purchased or acquired electricity, heating, and cooling. They are indirect because the emissions occur at the facilities that generate the electricity or heat, not at the organization's own facilities. Scope 2 emissions include emissions associated with the energy a company buys from a utility.
The term “natural gas,” as used herein, refers to methane alone or blends of methane with other gases such as other light hydrocarbons (e.g., ethane) or heavier hydrocarbons (C3+) in any proportion that would exist as gas vapor at ambient temperature and pressure. A natural gas stream may also include minor amounts of non-hydrocarbon impurities (such as water, carbon dioxide, hydrogen sulfide, and nitrogen). This natural gas may have originated as a naturally occurring fluid stream extracted from the earth or as synthetically combined mixture of molecules created for the purposes of transport in or on some form of mobile platform (such as a ship, railcar, or truck trailer). For example, natural gas, which is predominantly methane, cannot be liquefied by simply increasing the pressure, as is the case with heavier hydrocarbons used for energy purposes. The critical temperature of methane is −82.5° C. (−116.5° F.). This means that methane can only be liquefied below that temperature regardless of the pressure applied. Since natural gas is a mixture of gases, it liquefies over a range of temperatures. The critical temperature of natural gas is between about −85° C. (−121° F.) and −62° C. (−80° F.).
The term “LNG”, as used herein, refers to “liquefied natural gas”. The term “CNG”, as used herein, refers to “compressed natural gas”, whether refrigerated or not. The term “PLNG,” as used herein refers to “pressurized liquid natural gas” or “pressurized natural gas liquid.” PLNG is deeply refrigerated but may not necessarily be stored at temperatures below the critical temperature of methane. Notably, PLNG can also be chilled, produced, and stored slightly cooler than −112° C. (−170° F.) so that it is subcooled and below its bubble point temperature at the selected pressure storage operating pressure. Since in this use case of natural gas storage there may be no need for fossil fuel for power, it is best to minimize vapor evolving from the chilled fluid expansion process, that is, to eliminate the production of “end flash gas”, though such can be selected to be done in other embodiments of this disclosure as long as the additional vapor is properly managed.
The term “impurities,” as used herein, refers to impurities that may exist in natural gas, which may be removed to ensure the quality and safety of the final product. The specific impurities may vary depending on the source of the natural gas, but common impurities that are typically removed during LNG production include: carbon dioxide, benzene, other aromatic hydrocarbons, and other heavy hydrocarbons.
To facilitate a better understanding of the present disclosure, the following examples of certain embodiments are given. In no way should the following examples be read to limit, or define, the scope of the disclosure. Embodiments described below with respect to one implementation are not intended to be limiting.
The present disclosure provides for systems and methods for storage and redeployment of natural gas with low emissions. Specifically, the present disclosure relates to a method and system for liquefaction, storage, and redeployment of a gaseous fuel (such as or similar to natural gas) with ultra-low vapor emissions and ultra-low scope 1 greenhouse gas emissions. Further, scope 2 emissions can be managed and reduced by procurement of electricity with lower scope 2 content, such as electricity produced via solar photovoltaic methods, wind turbines, nuclear means, hydrogen fuel of low GHGe intensity, other lower carbon-intensity methods of producing electricity, etc., as scope 2 emission can be primarily embedded in electricity imported to the facility. Additional, scope 1 and or scope 2 emissions can be managed lower via integration of lower carbon electricity production into the present disclosure, such as can happen if solar photovoltaic methods, wind turbines, nuclear means, hydrogen fuel of low GHGe intensity, other lower carbon-intensity methods of producing electricity, etc., were used to produce electricity within the natural gas storage facility. The disclosed systems and methods may further utilize by-products such as energy gas, e.g., ethane, propane and hydrogen, and may also incorporate carbon capture, utilization, and sequestration methods. The disclosed systems and methods may, in certain embodiments, dispatch the natural gas fuel on demand and conduct energy management integrated with an automation system comprising data acquisition and machine learning. In certain embodiments, the systems and methods of the present disclosure may provide a gaseous fuel storage and redeployment combined with an achievement of ultra-low emissions, especially scope 1 and scope 2 GHGe. The process is not limited to natural gas, but can be applicable to other gaseous fuels, e.g., hydrogen, ethane, propane ethane, or any other applicable gaseous fuels.
Advantages of the systems and methods of the present disclosure include, but are not limited to providing an improved process for storing natural gas densely with minimum gas treatment, minimum equipment, minimum capital cost, minimum operating cost, minimum energy intensity, minimum operational scope 1 and scope 2 GHGe intensity, while reducing to a practical minimum or near zero intentional release of gaseous emissions including flare and vents. Moreover, this system may include no venting of CO2 and no production of a stream with concentrated CO2. In addition, the system and methods of the present disclosure may use heat from ambient sources with electricity to vaporize the fuel back to a pressurized gaseous state using imported electricity or electricity not powered by fossil fuel combustion (avoiding releasing carbon dioxide from combustion into the atmosphere). Further, the system and methods of the present disclosure may include low leakage valves and flanges to reduce the fugitive emissions of components that are considered greenhouse gases, and pressure relieving devices with minimal through-devise gas flow such as rupture pins and burst disks either before or after pumping the fuel. Further, the systems and methods of the present disclosure may produce a PLNG product for storage and subsequent vaporization with concentrations of CO2 in the inlet that may result in the existence of solid CO2 in the pressurized storage tanks. Such may form in the expansion of the chilled stream upstream of the storage tank. In such a case, solid CO2 would be of higher density than the pressurized liquid natural gas and sink to the bottom of the tank, where it will remain until the tank is warmed and the gas in the tank sent to export.
Through the dehydration unit 102, the dehydrated natural gas is delivered into the liquefaction unit 104, where natural gas is transformed from a gaseous state into a cryogenic liquid state for storage and transportation. Further, the PLNG obtained from the liquefaction unit 104 may be transported to other customers for their onsite storage. Such an embodiment may combine onsite storage for an anchor customer with a hub and spoke model connected to other customers who may have more modest onsite, reserve fuel demand. Typical processes in the liquefaction unit 104 may include gas impurities treatment (such as the removal of excess nitrogen, helium, etc.), gas compression, cooling and liquefaction.
In traditional production and storage of LNG, a CO2 removal unit may be located upstream of the dehydration unit 102 (e.g., if the gas impurity treatment involves water in a solution such as amine for CO2 removal) Additionally, the pressurized gas must typically be cooled to cryogenic temperatures, typically around −162 degrees Celsius (−260 degrees Fahrenheit) using a series of heat exchangers and refrigerants, enabling a transformation from the gas into a dense liquid, before being let down in pressure to about atmospheric.
In the present disclosure, the need to cool to −162 degrees Celsius is avoided by operating the liquefaction process and the storage at higher pressure than traditional process, for example more than 2 bar absolute. Raising the operating pressure may reduce the need for refrigeration power, sometime with a power saving of 20%, 40%, or more, depending on the inlet compositions, the operating pressure of liquefaction and storage, and the temperature of the ambient heat sink.
Further in the pressurized storage unit 106, the liquefied natural gas may not incur the freezing of impurities including carbon dioxide, depending on their concentration. In the methods and systems of the present disclosure, CO2 removal and concentration is not required. For example, even with one percent or more CO2 in the inlet, the CO2 may not form solids at some anticipated storage operating conditions of the present disclosure. Additionally, even if the CO2 content in the inlet is more than a few percent and is predicted to form solid CO2 at the liquefaction and storage operating conditions, the present disclosure includes means for managing solid CO2. Methods for predicting solid CO2 in cold methane mixtures are well known, so it can be discerned if providing such means per the current disclosure is prudent for one or more operating scenarios. Finally, in many gas transportation pipelines, the composition of the natural gas being transported changes over time. The present disclosure has means to time the sourcing of natural gas for storage to time of lower CO2 content, among other attributes. Therefore, the present disclosure for natural gas storage eliminates the need for adsorption or adsorption or other processes to removal and concentrate CO2.
One embodiment of the present disclosure is to take inlet gas and, if not already at a pressure of 450 psia, to compress to that pressure or greater, even up to 1400 psia or greater, and to chill it, and expand it to a pressure above 2 atmospheres for storage under pressure. Typical United State inter and intra state natural gas transmission lines can operate between about 450 and 1400 psia, though they can be based on their design operating below or above that pressure too, possibly even above 2160 psi.
The degree of dehydration for the inlet gas depends on the temperature of the PLNG product to be stored. Typically for processing temperatures significantly cooler than −40 degrees Celsius (−40 degrees Fahrenheit), dehydration units comprised of molecular sieve beds are used to remove water content down to the range of about one part per million or less. One or more beds are used for inlet gas dehydration while often one or more other beds are regenerated by hot gas to remove water that has been previously adsorbed in the cyclic operation of the beds, or being cooled by dehydrated, cooler gas. Alternatively, it may be possible to use some other type of solid desiccant or even some type of liquid glycol of ultra-high purity to dehydrate the inlet gas in an absorption process.
The amount of CO2 that can be in natural gas in a typical United States pipeline can be from zero to about 1 percent or more, though by commercial specification often can be up to 2 percent and sometime higher. The amount of CO2 that is soluble is given on specific demand. For example, if the PLNG is stored at 16 bar-g (17 bar absolute), its temperature should be in the range of −112° C. (161 Kelvin) and could have up to about 1.6 to 1.7% CO2 before solid CO2 would be expected to exist in the LNG tank. For PLNG stored at 10 bar-g (11 bar absolute) then the PLNG temperature may be in the range of −122° C. (151 K), and solid CO2 may exist if it was in the of 0.8 to 1% or more of the inlet gas. Whether or not CO2 is predicted to freeze in the PLNG storage condition, it need not be removed from the inlet gas in the methods and systems of the present disclosure. For example, cither a) its concentration is low enough that it will not form, or b) it may form and fall to the bottom of the storage tank and remain there until the tank is warmed, in which case it would depart with the export gas; or c) the timing of gas import can be managed so that gas is not imported for PLNG liquefaction at times when the CO2 concentration is such that it is predicted to freeze at PLNG conditions. If solid CO2 forms in the heat exchange equipment, there are a number of ways that it can be managed, for example, it can be CO2-defrosted at times when the liquefaction equipment is not in operation, that is, more PLNG volume is not being added to storage, or parallel heat exchange equipment can be installed and cycled for CO2 defrosting.
It is possible to adjust most existing processes for producing an LNG product at near atmospheric pressure and −162° C. (−262 F) to operate in the methods and systems of the present disclosure, i.e., to produce a pressurized LNG product at greater than 2 bar and perhaps more desirable at 4 to 20 bar or more. The methods and systems of the present disclosure may include one or more of these processes. These processes include: cascade refrigeration processes of one or more near pure components such as propane, ethane, ethylene, carbon dioxide, methane (the latter which could be in an open or closed loop configuration), etc.; any of the variations of single-mixed refrigeration processes including those known as PRICO, IPSMR, IPSMR+, etc., where the mixed refrigerant may be comprised of nitrogen, methane, ethane, ethylene, propane, propylene, compounds with four or more carbons, carbon dioxide, etc.; propane precooled mixed refrigeration process; dual-mixed refrigerant processes included those known as DMR, EMR, etc.; processes based on closed-loop expansion cycle(s) with nitrogen as the working fluid such as a reverse Brayton nitrogen cycle; processes based on closed-loop expansion cycle(s) with predominantly methane as the working fluid; expansion cycles with either nitrogen and or predominantly methane as the respective cycle working fluids; an open loop expansion cycle using components of the inlet gas as the working fluid; any precooled variant of an expansion cycle, etc.; any of the above which may boost the inlet gas as available to a higher pressure which often results in a net power reduction for the liquefaction after taking into account the power of the inlet compression; and any process with or without any of the above which takes advantage of pressure drop normally available from a high pressure natural gas source such as a natural gas transmission line down to a lower pressure, be it that of a local or regional distribution grid operating at lower pressure, PLNG storage conditions, etc.
The heat exchange for the liquefaction process of the present disclosure may use any heat exchange known for any LNG process, with the mechanical ratings and physical arrangement configured for the altered process conditions. Such heat exchangers could be specified as any number and variant of shell and tube, brazed aluminum heat exchanger (BAHX), spiral/coil wound heat exchanger (SWHW, CWHX), and the like.
Accordingly,
Once stored, the LNG can either be vaporized via a heat exchanger for gas export or managed through a heat exchanger and reactor. Importantly, the stream generated from the vapor management process can be recovered at a temperature of 40° C. and a pressure of 6200 kPa, making it suitable for direct industrial use, as shown in
As detailed,
Alternatively,
The condition of the feed stream after water dehydration (Stream 9) is given in Table 1.
The single mixed refrigerant process cools the inlet stream to a temperature of −113° C., stream 10. There has been some modest pressure drop through the chilling equipment, for example, somewhere around 59 kPa. Thereby the chilled, pressurized fluid is let down in pressure through an expansion devise such as a throttle valve or, as shown in
Typical large, site-built storage tanks for holding tens to hundreds of thousand cubic meters of LNG, such as used in the supply chain of international LNG, typically have a pressure rating of a bit over atmospheric pressure. In addition, the makers of cryogenic equipment also manufacture tanks with range of Maximum Available Working Pressures (MAWP) for storing LNG, e.g., 5 bar, 12 bar, and higher, with holding capacity of up to a few hundred and even a few thousand cubic meters. Storage tanks with a 5 and 12 bar MAWP can be operated as production vessels by those skilled in the art at some pressure below its MAWP, say 3 and 10 bar or higher, respectively.
For example, for PLNG storage in certain embodiments, the MAWP can be applicable for 20 bar-gage or more so that can be operated at, say, 16 bar-gage.
Illustrated in
BOG generated from heat leak is envisioned to be managed with near zero scope 1 emission via a number of means. One method in this disclosure is through a vapor management system 212. This system may heat and boost the pressure of the BOG in various sequence before returning natural gas at conditions equivalent to the operation of the local natural gas pipelines.
Another means to manage BOG is supplemental refrigeration to be added to the storage systems to mitigate the heat leak. This can be delivered via a heat exchange devise submerged into the PLGN products being stored. Or this can be provided by conduction to the system between the external wall of the storage tank and the insulation. Or such can be provided on BOG exiting the storage tank, the BOG being reliquefied, and returned to the tank. Another method to mitigate BOG formed via heat leak to the tank is to use the cold BOG to liquefy a small slip-stream of the inlet to capture the cold of the BOG before it is sent to export or, if compressed, a higher pressure higher than PLNG storage pressure.
Illustrated in
If natural gas export pressure is to be higher than the pressure of the liquified natural gas in storage, then a pump or a series of pumps can be used to get the fuel to the customer at full pressure after taking account of the pressure drop in the vaporizer and all other equipment, piping, and instrumentation that may be in line to the fuel consumers. The pumps may be located in the storage tank, that is, a type of submerged pump, or external to the storage tank, or both. If more than one pump is used, those pumps can be arranged in series and or in parallel. Furthermore, one of outputs of the system may be connected into a dispatchment system, which is used to dispatch the natural gas at a rate that matches demands in the industry or to an on-site or off-site consumer.
Additionally, an automation unit 110 may be integrated into the system 100 via a connection to all units and components of the envisioned systems and to data sources outside the system. The automation unit 110 may include a data processor, machine learning processor, and artificial intelligence processor, and the like.
In some embodiments, the automation unit 110 may optimize scope 1 and scope 2 GHGe intensity. The data from electricity generation and market data can be acquired and processed by the automation unit 110 for facilitating for example, sourcing low-carbon intensity electricity, sourcing lower cost electricity and or natural gas, timing liquefaction operations to windows of lower cost electricity and or natural gas or some optimized combination of same, etc.
The automation unit 110 may determine a threshold value and rate for dispatching natural gas to downstream users and or customers at different scenarios. For example, thresholds and rates may be set in response to low pressure or reduced flow rates in gas supply pipelines, indicating fuel supply constraints due to physical, contractual, or operational limitations. Another example includes high spot prices for natural gas, where elevated fuel costs justify performing fuel cost arbitrage by utilizing stored natural gas as pressurized liquefied natural gas (PLNG).
For the embodiments for establishing automation system integrating an automation unit 110, a monitoring unit 114 can be set up for monitoring temperature and pressure for safety.
In one or more embodiments, the automation unit and associated components may
track and optimize a variety of key metrics including, but not limited to end-use or customer natural gas demand-such as gross natural gas demand, gross natural gas supply, natural gas fuel pressure, and loss of inlet flow-along with weather information and modeling data. Additionally, the system may monitor site operational Scope 1 and Scope 2 emissions and their measurable components, market electricity and natural gas prices, natural gas purchase volumes and timing, timely gas compositions (including energy and CO2 content), electricity purchase volumes and timing, and facility-specific operational parameters such as total power consumption, flow rates, temperature, and pressures.
In some embodiments, the liquefaction unit 104 may utilize cooling solely from ambient sources, e.g., air, water, and supplemental power from electricity unit 112. Meanwhile, the resultant water from cooling natural gas procedure may be recirculated to the electricity unit 112.
In some embodiments, the system 100 may be configured to integrate equipment with no continuous vapor emissions to the atmosphere and a significant reduction of fugitive emissions. For example, the equipment may include low fugitive emissions pressure relief devices, such as rupture pins, rupture disks, and low-leakage pressure release valves.
At 202, dehydration of a gaseous fuel is performed. A gaseous fuel may be selected from any fuel that is eligible for a compression and liquefaction at appropriate temperature and pressure, e.g., gas substantially including methane. The gaseous fuel is introduced to a dehydrator at a rate. Selectively, before the dehydration, a general waste removal may be conducted to remove impurities including, but not limited to water, gas, and sulfur compounds, and any combination thereof. In some embodiments, no waste or impurity removal steps are performed.
At 204, liquefaction of the gaseous fuel is carried out. The liquefaction may include compression, cooling, and liquefaction. The gaseous fuel is compressed to raise its pressure and temperature, facilitating the cooling and conversion to a liquid state. Following the compression, the compressed gas is then cooled to cryogenic temperatures, typically around −162 degrees Celsius (−260degrees Fahrenheit) for natural gas. This cooling process is achieved using a series of heat exchangers and refrigerants, and may transform the gas into a dense, clear, colorless liquid, e.g., LNG. In some embodiments, liquefaction may be performed by chilling using cooling solely from ambient sources such as air and water and supplemental power solely from electricity sourced from low GHGe sources, to produce a liquid product having a temperature of about −112°° C. (−170 F) and a pressure sufficient for the liquid product to be at or below its bubble point temperature, thereby reducing its volume.
At 206, the liquefied gas may be pressurized and stored as a fluid. In some embodiments, controls on temperature and pressure of the liquefied fuel may be operated to preclude the freezing of the liquefied gas and any impurities therein. These impurities include, but are not limited to, carbon dioxide, benzene, other aromatic hydrocarbons, and other heavy hydrocarbons. By avoiding freezing of these impurities, no removal steps or equipment may be needed to remove those impurities. Therefore, the present disclosure is more reliable and efficient in reducing emissions, compared to the current technologies. In some embodiments, the pressurization storage can be implemented as given in the example below.
At 208, a vaporization of the pressurized liquefied fuel is performed. The vaporization may be executed by a reception of gaseous fuel demand signal, which may be delivered from fuel consumers. In some embodiments, a threshold for such a signal delivery may be determined on demand of fuel peak time. Further, the vaporization may be actuated using heating from ambient sources, e.g., air and water, or supplemental power from electricity sourced from other plants and sites.
Electricity for this system can be sourced with lower scope 1 and scope 2 greenhouse gas intensity such as solar photovoltaic production, wind power, nuclear power, or fossil fuel combustion with carbon capture and sequestration. In some embodiments, the power supply may be adapted to power availability, e.g., low emissions sources such as solar and wind power may be used when available. In some cases, liquefaction and/or vaporization may be performed off very low carbon intensity electricity, for example, only liquefying when renewable energy is available, be it photovoltaic solar when the sun is shining or wind power when wind is turning the wind turbines that are either physically or virtually supplying the plant, coupled to the timing of gas offtake from the natural gas pipeline supply.
At 210, a redeployment of the vaporized gaseous fuel is performed to match demand. The redeployment can transport and distribute fuel to end-users, which can include power plants, industrial facilities, residential areas, etc. In some embodiments, to integrate a redeployment, a monitoring may be performed for safety. The monitoring may include a monitoring on temperature and pressure to prevent a leakage or accident.
As described in the storage and redeployment system 100, an automation system may be integrated into the system to achieve automatic management for the method and system. In the automation procedure, data can be collected and processed in computing module/processors therein, e.g., machine learning and artificial intelligence.
Another objective of the process 200 is to ensure that there are no continuous vapor emissions to the atmosphere other than fugitive emissions, and a minimization of fugitive emissions.
Therefore, a configuration of the process and system is specialized to enhance the above objective. For example, embodiments of the present disclosure may exclude certain features normally associated with natural gas and LNG operations. This can include omitting an amine system, which is commonly used for CO2 removal, concentration, venting, and the combustion of gas to destroy trace components in the CO2 stream co-absorbed by the amine solution. Additionally, embodiments may exclude fossil-fuel-fired eaters and engines. In certain embodiments, conventional relief valves, which may leak into the safety pressure relief device, can also be replaced with rupture disks or rupture pin devices. In further embodiments, instead of using hydrocarbon purge gas in the safety pressure relief device, system components may be designed to withstand pressures from potential deflagration events, or an inert gas such as nitrogen may be used to purge the system.
Minimization of the above systems results in a minimization of valves and other piping leak points of fugitive emissions. Features that may be included in embodiments of the present disclosure to further enhance these objectives include, but are not limited to, low leak and high integrity valves, using only ambient (air, water, geothermal) or electric heating, sourcing of low carbon intensity electricity.
In some embodiments, the gaseous fuel in the system and process may be a majority natural gas which is substantially methane along with other hydrocarbons, inert components, and contaminants. In addition, the method further includes a collection for export of gaseous fuel either not liquefied or counterpart liquefied yet through heat leaks converted back to gaseous state. Accordingly, the process can comprise an additional compression before gaseous fuel export for storage and redeployment afterwards.
In some embodiments, the methods and systems of the present disclosure may include capture and optimization of waste heat. Along with the utilization of power during the cooling and vaporization of the fuel, waste heat and water from other sources can be captured or circulated by the methods and systems of the present disclosure to increase energy availability and overall efficiency of the fluid, reduce hydrocarbon fuel consumption, or decrease power demand from external sources.
In some embodiments, the methods and systems of the present disclosure may include BOG Management, including embodiments whereby a refrigerant is used to offset heat leak. In some embodiments, the refrigerant may include liquid nitrogen. In some embodiments, the refrigerants may include one or more noble Gases such as Argon, Krypton, Neon, Xenon. In some embodiments, the liquid nitrogen is used to cool a heat exchanger embedded in the vapor space of the storage tank. In some embodiments, vapor circulated by a blower through heat exchanger using refrigerant(s) and condensed fluids are routed back to tank (can be by pressure or by pumping, etc.). In some embodiments, a drip back condenser may be used using elevation external to storage tank. In some embodiments, the heat exchanger is in the vapor space of the storage tank. In some embodiments, the methods and systems of the present may include a tank pressure-sensing mechanism and a device to throttle LIN appropriately to keep storage more than 90 or more than 120 days.
Therefore, the disclosed systems and methods are well adapted to attain the ends and advantages mentioned as well as those that are inherent therein. The particular embodiments disclosed above are illustrative only, as the teachings of the present disclosure may be modified and practiced in different but equivalent manners apparent to those skilled in the art having the benefit of the teachings herein. Furthermore, no limitations are intended to the details of construction or design herein shown, other than as described in the claims below. It is therefore evident that the particular illustrative embodiments disclosed above may be altered, combined, or modified and all such variations are considered within the scope of the present disclosure. The systems and methods illustratively disclosed herein may suitably be practiced in the absence of any element that is not specifically disclosed herein and any optional element disclosed herein. While compositions and methods are described in terms of “comprising,” “containing,” or “including” various components or steps, the compositions and methods can also “consist essentially of” or “consist of” the various components and steps. All numbers and ranges disclosed above may vary by some amount. Whenever a numerical range with a lower limit and an upper limit is disclosed, any number and any included range falling within the range is specifically disclosed. In particular, every range of values (of the form, “from about a to about b,” or, equivalently, “from approximately a to b,” or, equivalently, “from approximately a-b”) disclosed herein is to be understood to set forth every number and range encompassed within the broader range of values. Also, the terms in the claims have their plain, ordinary meaning unless otherwise explicitly and clearly defined by the patentee. Moreover, the indefinite articles “a” or “an,” as used in the claims, are defined herein to mean one or more than one of the elements that it introduces.
A combined cycle power generation plant whose 993 MW all-in capacity rating (just shy of a full gigawatt rating) is composed of two natural gas fired gas turbines coupled with waste heat recovery to generate steam to drive one steam turbine. With its modern equipment and arrangement, the plant can be operated in the region of 60% or more thermal efficiency. A typical heat rate may be 5,950 kJ/kWh net energy content (5,640 BTU/kWh “lower heating value” basis) with its electricity generated at 60 Hz. A typical US natural gas pipeline may be carrying a gas of composition mostly methane with some smaller amounts of nitrogen, CO2, ethane, propane, heavier hydrocarbons, and impurities. At typical net energy content of 910 BTU per standard cubic foot (gross energy content of 1010 BTU per standard cubic foot) the power plant may consume on the order of 148 million standard cubic feet a day (MMscfd) of natural gas.
Typically, the operator wishes to greatly reduce the probability of natural gas supply interruptions during the times when weather and other incidents may create a large grid-wide demand and or when grid power supplies are curtailed for one reason or another. The operator also wishes to reduce or totally eliminate all onsite combustion for natural gas storage and subsequent dispatch such as: amine reboilers, dehydration unit heat, compressor or generator drives, and practically always an overpressure relief system with a flare header using purge gas and a pilot flame system. Some LNG vaporization facilities combust part of the natural gas product stream.
On the contrary, the traditional process does not have the above outcomes. Typically, there are several problems therein. For example, venting of CO2 removed upstream of liquefaction occurs in all known liquefied natural gas production facilities if the CO2 content in the inlet is much above 50 to 100 ppm CO2. Also, standard practices have led to measurement of three to seven percent methane leakage for some natural gas handling facilities, through it has been proposed that one percent may be obtainable.
Table 2 is the basis of the analysis on fugitive methane emissions.
By applying the methods and systems of the present disclosure, the operator can derive the following GHGe benefits as listed in Table 3 versus traditional LNG storage at about atmospheric pressure, conventionally procured power from the grid. Also, an enhanced and certified methods for methane fugitive emissions control in the present disclosure versus historical practices is present in an example, showing cumulatively this disclosed method in reducing Scope 1 and scope 3 GHGe emission in excess of 90% for the gas storage facility. With design optimization it may be possible to potentially achieve in excess of 95% reduction.
Further, the GHGe intensity is favorable when it is examined compared to the PLNG that is stored day in and day out during a year. per Table 4.
While other operators in the art cite targets to get to a methane intensity of 0.2%, the operator in the disclosure could use the configurations of methods of this disclosure to have a technically assured way of meeting and exceeding those targets. With this disclosed method, the operator can select and derive the following, but not limiting to, parameters for their gas storage system: 1) 32,500 m3 (8.6 million gallons) of pressurized liquefied natural gas (PLNG) storage, which can provide 4 days of power plant fuel supply if the plant is operating at full rated power. Storage was selected to be at 16 bar-g (17 bar-a, 1700 kPa, about 250 psia). The tank was selected to have a higher pressure for its MAWP, in this case 18 bag-g. 2) Liquefaction can be in a unit capable of producing 100,000 actual US gallons per day of pressurized LNG. A unit much larger or smaller could have been specified. In this case this size would be selected since it results in reasonable number of days to refill the tank depending on how much fuel was withdrawn for use, on the order of less than 22 days if one full day of fuel was previously withdrawn, up to less than 90 days if a very severe event caused a full four days of withdrawals, as per Table 5.
Pumping and vaporization of the PLNG at 178 MMscfd, that is, the full fuel rate and system inlet pressure for the power plant fuel system, is equivalent to sourcing from the gas distribution pipeline(s).
In some embodiments, the design is powered by electricity for rotating equipment and heating to temperatures and or above ambient and for LNG/send out gas heating, including lower temperature heat sourced from ambient, e.g. air, water, geothermal, pressure available in the inlet natural gas stream, or various methods of internal heat transfer and power recapture from pressure let down devices.
A vapor management system may perform the at least following functions: 1) as the storage is filled with PLNG, it displaces vapor. The vapor management system warms the vapor, and either run it to export at a pressure below PLNG storage if a local customer is willing to accept, or it is compressed to the normal operating pressure(s) of the pipelines supplying the power plant so that the power generation facility may use it for fuel; while cryogenic liquid storage uses a number of methods to prevent heat leak, it still occurs though it has been minimized. A typical range of heat leak is on the order to cause boil off of 0.01% by weight of the tank contents up to 0.1% by weight or more. Filled tanks tend to have lower weight percent boil offs and near empty tanks tend to have higher rate of boil off.
A gas dehydration system may be used to treat the inlet gas down to a specification of less than one part per million water, in this case using molecular sieve whereby about 10% of the feed gas is used in the dehydration process and recycled to the fuel storage facility inlet. The system will use electricity to heat the natural gas circulating to regenerate the mole sieve beds rather than the traditional fired heater.
This example includes no intentionally designed-in scope 1 emissions and routine venting of natural gas.
In certain embodiments, fugitive emissions detection systems are included to reduce inadvertent methane emissions to the bar set by certifying parties, typically below 0.2% of throughput and possibly lower. A battery of various detection devices will be installed in the facility to excessive leakage above de minimis.
In certain embodiments, the system incorporates comprehensive safety pressure relief capabilities without using active header purging with natural gas or an active pilot flame. It employs rupture pin devices and burst plates to prevent gas leaks that could occur with standard pressure relief valves. Instead of natural gas, nitrogen is used for the safety pressure relief piping header. Additionally, an auto ignition device can be activated upon detecting pressure relief, utilizing direct or indirect measurement methods such as pressure waves or acoustic signals.
In certain embodiments, a procurement management system is in place to optimize several factors, including the carbon intensity of purchased power to reduce scope 2 greenhouse gas emissions, electricity costs, the cost of gas purchased for storage, and the revenue generated from selling power when accessing the stored fuel.
Representative operating conditions along the inlet and liquefaction processes are in listed Table 6, with reference to
The pipeline(s) supplying the power plant typically operate at about 6200 kPa (62 bar-a) at the power plant fence line. It is at that point that natural gas will be brought into the fuel storage facility, as stream 1 (as shown in
Note that while the CO2 content in stream 1 is only 0.0080 mole fraction (0.8 mole percent), such is also 8,000 parts per million (ppm) CO2, far in excess of the established LNG process licensors specification to remove CO2 to the range of 50 to 100 ppm before liquefaction.
Pipelined natural gas typically has a low water content, for example, 7 pounds of water per million standard cubic feet of gas, to prevent gas transmission freeze-up in winter. Such is not low enough to prevent water freezing in the envisioned cryogenic operating temperatures. Therefore, a molecular sieve system with solid beds alternately dehydrating will be used to reduce the water content to less than one part per million at the outlet of the dehydration system as stream 9 (with reference to
Notably, the CO2 content in stream 9 is on the order of 0.0080 mole fraction (8,000 ppm).
From here, the dehydrated natural gas is taken to a liquefaction process 204 where it is chilled and subcooled to temperature of −113 C, stream 10. Other temperatures may be appropriate depending on the species in the gas to be liquefied. At this point there has been a minor pressure drop that has occurred through the piping and heat exchange equipment.
The liquefaction process is competed when the chilled fluid is expanded, in this case by a hydraulic turbine though it could be another devise such as a valve, to a tank operating at a discretionary pressure of 16 bar-g (1700 kPa). Another tank operating pressure can be selected, for example for PLNG as low as 2 bar-g or up to 20 bar-g or even higher up to the fluid critical pressure, e.g., 46.5 bar-a for pure methane.
Because the fluid was subcooled during heat exchange, no vapor is formed in or after
the expansion process, stream 11 (
One or more tanks, either separate or interconnected, may be used for storing the PLNG, at conditions approximately equal to those in stream 11 in this particular example, illustrated in
With reference to
Additionally, the system includes a vaporizer E-104, selected to utilize a series of ambient air vaporizers. These can operate continuously or in a cyclic manner to allow for defrosting. Alternative configurations may involve sourcing ambient heat by pumping a heating medium fluid and other means.
The Vapor Management System 212 is configured to handle various scenarios, including the management of vapor space during LNG production and filling of the tank. In certain embodiments, when 15.77 m3 of PLNG is introduced into the tank, an equivalent volume of cold vapor must be managed as it displaces from the tank's top. These embodiments utilize a compressor to export the vapor at pressures aligned with the normal operating pressures of the sourcing pipeline. If a buyer can be secured for the gas at a pressure lower than the PLNG storage pressure, the need for compression in the vapor management system can be eliminated.
Additionally, effective tank pressure and vapor management are necessary for
balancing the vapor during the send-out of vaporized fuel, paralleling the management during PLNG production. Generally, CO2 concentration is not a significant concern since the gas used to fill the vapor space originates from the tank itself. The vaporized product in stream ST-GasExport (referenced in
This U.S. Non-Provisional Application, claims priority to U.S. Provisional Application No. 63/595,557, filed on Nov. 2, 2023, the contents of which is incorporated herein by reference in its entirety.
| Number | Date | Country | |
|---|---|---|---|
| 63595557 | Nov 2023 | US |
