KR101951174B1 - Regasification plant - Google Patents

Abstract

A method and system for regenerating LNG is provided. A method for regasifying liquefied natural gas (LNG) includes providing heat to a LNG regasification process from a power plant. If the heat is not sufficient, additional heat may be provided to the LNG regasification process from a cooling tower operating in a heated tower configuration.

Description

{REGASIFICATION PLANT}

Cross reference of related application

This application claims the benefit of U.S. Provisional Application No. 61 / 437,392, filed January 28, 2011, entitled REGASIFICATION PLANT, and REGASIFICATION PLANT, filed on December 7, 2011, U.S. Provisional Application No. 61 / 567,818, the entire contents of which are incorporated herein by reference.

Field

Exemplary embodiments of the techniques of the present invention are directed to liquefied natural gas terminals having a flexible capability to provide pipelined natural gas, electricity to a grid, or both.

Large volumes of natural gas (ie, mainly methane) are located in remote regions of the world. This gas has significant value if it can be transported economically to the market. If the gas reservoir is located reasonably close to the market and the topography between the two locations allows, the gas is typically produced and then transported to the market through the immersed and / or land pipeline. However, when gas is produced in locations where it is impossible to install pipelines or where it is economically prohibited, other technologies should be used to get this gas into the market.

A technique commonly used for non-pipeline transportation of gas involves liquefying the gas at or near the production site and then transporting the liquefied natural gas to the market within a specially designed storage tank on the shipping vessel. Natural gas is cooled and condensed to a liquid state to produce liquefied natural gas ("LNG"). LNG is often transported at substantially atmospheric pressure, often at a temperature of about -162 DEG C (-260 DEG F), thereby significantly increasing the amount of gas that can be stored in a particular storage tank on a transportation vessel. Once the LNG carrier arrives at its destination, the LNG is typically offloaded into another storage tank from which the LNG can then be regenerated as needed and transported as a gas to the end user via a pipeline or the like. Natural gas is used for a variety of purposes, one of which is power generation. LNG has become an increasingly popular transport method for supplying natural gas to major energy consuming countries.

During the regasification process, the natural gas temperature varies from about -162 占 폚 up to about 15 占 폚, depending on the sales specification. The required heat for regasification is typically in the form of a portion of the product natural gas in a fuel burner such as a submerged combustor (SCV) or a shell-and-tube vaporiser (STV) . These fuel soft vaporizers consume about 1.5 to 2.0% of the product natural gas as fuel. Fuel consumption not only leads to large operating costs by consuming some of the product itself, but also results in large environmental emissions in the form of CO ₂ and NO _x . Using different sources of heat, such as seawater and ambient air, can reduce terminal emissions, but these have their own limitations. For example, the use of seawater requires large capital costs and may adversely affect the marine ecosystem due to the very large amounts of seawater and low temperature emissions required. In many locations, the process to allow the use of seawater from the regulatory authorities can be very complicated. The use of ambient air heat may be an option only available in high temperature climates, and even their benefits are significantly reduced by day and seasonal variations in temperature and humidity.

The general method described above utilizes a variety of heat sources to capture the cold contained within the LNG, which can be used to reduce emissions, thereby improving the process efficiency and economy of the LNG receiving terminal. Research efforts therefore focus on finding ways to reduce fuel consumption and thereby reduce operating costs and emissions associated with LNG regasification processes, for example by using LNG cold.

Numerous methods have addressed the problem of reducing emissions and have been conventionally proposed to use LNG cold with some advantages. These methods include integrating LNG regasification with development. One efficient power generation method is the combined cycle power plant (CCGT). The CCGT plant includes a gas turbine generator (GTG), which may further include a compressor, a combustor, a gas turbine (GT), and the like. The heat recovery unit (HRU) can then be used to recover waste heat from the gas turbine. An example of an HRU is a heat recovery steam generator (HRSG). The HRSG uses waste heat from the GT for steam generation, and then delivers the steam through the steam turbine generator (STG) and the steam condenser. Steam condensers can use cooling from LNG regasification for condensation. The CCGT may also include a cooling tower to provide coolant to the vapor condenser.

The use of LNG cold to cool the inlet air in a gas turbine based power plant or to condense steam exiting the steam turbine from a combined cycle power plant is disclosed in the prior art. For example, U.S. Patent No. 7,574,856 to Mark (Mak) discloses power generation integrated with LNG regasification. Cold from LNG is used in a combined power plant to increase power output. In the configuration, the first stage LNG cold provides cooling in an open or closed power cycle. The portion of the LNG is vaporized in the first stage. In the second stage, the cold from the LNG provides cooling for the intake air cooler of the combustion turbine in the power plant and the heat transfer medium used to provide the coolant for the cooling water to the steam power turbine.

U.S. Patent No. 7,299,619 to Briesch et al. Discloses the use of vaporization of LNG to increase efficiency in a power cycle. Inlet air cooling for the gas turbine is provided by vaporization of the LNG. The cycle uses regeneration to preheat the combustion air. The process provides a potential efficiency for gas turbine cycles in excess of 60%. The system and method allow vaporization of LNG using ambient air, and the final subcooled air is easy to compress. In an alternative embodiment, the vaporization of the LNG may be used as part of a bottoming cycle to increase the efficiency of the gas turbine system.

United States Patent Application Publication No. 2003/0005698 to Keller discloses a process and system for LNG regasification. A system for vaporizing LNG utilizes the residual cooling capacity of the LNG to condense the working fluid in the power generation cycle. LNG can also cool liquids used in direct contact heat transfer systems to cool the air. Cool air is used to supply air to a combustion gas turbine that operates in combination with a combined cycle power plant.

U.S. Patent No. 6,367,258 to Wen et al. Discloses vaporizing LNG in a combined cycle power plant. The efficiency of a combined cycle power plant can be increased using vaporization of cold liquids, including liquefied natural gas ("LNG") or liquefied petroleum gas (LPG). The vaporization is assisted by circulating a warm heat transfer fluid to transfer heat to the LNG / LPG vaporizer. The heat transfer fluid is cooled by LNG / LPG cold liquid vaporization and warmed by heat from the gas turbine. The heat transfer fluid absorbs heat from the air intake of the gas turbine and from the secondary heat transfer fluid circulating in the combined cycle power plant.

If a large enough power plant can be installed in the LNG regasification location, there is a potential to eliminate fuel consumption associated with LNG regasification. The scheme also improves the efficiency of the power plant and power output by cooling the turbine inlet air and providing cooler cooling medium to the steam turbine condenser. LNG cold can also be used for intercoolers for GTG compressors.

Another way to reduce emissions from LNG terminals is the use of ambient air heat for LNG regasification. Since the use of ambient air heat reduces fuel consumption, the terminal economy can be significantly improved. (Also known as " reverse cooling towers " or " heating towers ", for example), direct-type (natural and forced drafts), fin-fans (similar to air coolers) and warming towers There are many types of ambient air vaporizers. The use of a warm tower is described in the prior art for LNG regasification.

For example, U.S. Patent No. 6,644,041 to Eyermann discloses vaporization of liquefied natural gas using a water tower. The temperature of the water stream can be increased in the water tower. The warm water can be passed through the first heat exchanger and the circulating fluid can also be passed through the first heat exchanger to transfer heat from the warm water into the circulating fluid. The LNG may be passed into the second heat exchanger and the circulating fluid heated from the first heat exchanger may be passed through the second heat exchanger to transfer heat from the circulating fluid to the LNG gas. The vaporized natural gas is discharged from the second heat exchanger.

No. 7,137,623 to Mockry et al. Discloses a heating tower that isolates the outlet and inlet air. The heating tower may be used to heat the fluid by drawing the air stream through the inlet into the heating tower and passing the air stream over the filler medium. The fluid is passed over the filler medium, with the air stream being discharged from the heating tower through the outlet. The method further comprises isolating the inlet air stream from the outlet air stream.

In the above-described technique, a power plant integrated with the LNG regasification process can reduce emissions and utilize LNG cold, whereas use of a warm tower for LNG regasification deals only with emissions issues. However, the size of the power plant will be very large to fully utilize the cold from the LNG. For example, the sale of 2 BCFD (1 billion cubic feet per day) natural gas may require the power plant to be approximately 500 MW to utilize the cold. This size of the plant will represent a very large capital cost. Also, a large market will be required for electricity generated by the plant.

Both the power plant and the heating tower option become less attractive if there is not enough demand for seasonally occurring natural gas. A small demand for natural gas means that there is less cold available from LNG. Less available colds reduce the operating efficiency of installed equipment. The use of the warming tower can be further constrained by the widespread ambient conditions such as temperature and humidity. Thus, all of the above-described techniques provide only a partial solution without any flexibility in utilizing the LNG cold.

Related information can be found in U. S. Patent Nos. 5,295,350, 5,457,951, 6,324,867, 6,367,258, 6,374,591, 7,299,619 and 7,644,573. Additional information may also be found in U.S. Patent Application Publication Nos. 2003/0005698, 2008/0307789, 2008/0034727, 2008/0047280, 2008/0178611, 2008/0190106, 2008/0250795 , ≪ / RTI > 2008/0276617 and 2008/0307789. Additional information may also be obtained from Rosetta M. et al. Presented at the 85th Annual Congress of the United States Gas Processor (GPA 2006), "Rosetta, MJ and Himmelberger's" Integrating Ambient Air Vaporization Technology with Waste Heat Recovery - A Fresh Approach to LNG Vaporization, Grapevine, Texas, March 5-8, 2006; "Marrying LNG and Power Generation," Energy Markets: 2005, "Ebbern, D., Kotzot, H. and Durr, C." October / November, 10, 8; ABl / INFORM Trade & Industry, p. 28, presented by Rajeev Nanda and John Rizopoulos, "Utilizing Air Based Technologies as Heat Source for LNG Vaporization," presented at the 86th Annual Congress of the United States Gas Processor (GPA 2007) Grapevine, Texas, March 11-14, 2007, in San Antonio, Texas, USA.

An exemplary embodiment provides a method for regasifying liquefied natural gas (LNG). The method includes providing heat from the power plant to the LNG regasification process. If the heat is not sufficient, additional heat may be provided to the LNG regasification process from a cooling tower operating in a heated tower configuration.

The method may include cooling water in the cooling tower when the power plant is operating. The cooling tower may be used to heat the heat transfer fluid. The intake air for the gas turbine can be cooled by transferring heat to the LNG regasification process. Steam from the steam turbine can be condensed in the heat exchanger by transferring energy to the LNG regasification process.

Energy from the power plant can be transferred to the LNG regasification process through the heat transfer fluid. At least a portion of the heat transfer fluid may be heated against the inlet air stream for the gas turbine. At least a portion of the heat transfer fluid may be heated against condensation vapors in the power plant.

Another embodiment provides a method for vaporizing a cryogenic fluid. The method includes vaporizing the cryogenic fluid for the heat transfer fluid and providing thermal energy to the heat transfer fluid from the power plant. If the heat from the power plant is not sufficient to vaporize the cryogenic fluid, the thermal energy is provided to the heat transfer fluid from the cooling tower of the power plant operating in the warm mode.

At least a portion of the heat transfer fluid may be heated against the inlet air stream for the gas turbine. At least a portion of the heat transfer fluid may be heated against the condensation fluid in the power plant.

Another embodiment provides a system for regasifying liquefied natural gas. The system includes a cryogenic heat exchanger configured to regenerate the stream of LNG, a power plant, a cooling tower configured to operate in a cooling or warm mode, and a heat transfer fluid. The heat transfer fluid is configured to provide heat to the cryogenic heat exchanger from the power plant and to provide at least a portion of the heat from the cooling tower to the cryogenic heat exchanger if the heat is insufficient.

The system may include an intermediate heat exchanger configured to transfer heat from the cooling tower to the heat transfer fluid. The intermediate heat exchanger may be plate-frame, shell-and-tube, tube-in-tube, plate-shell or any combination thereof.

The power plant may be a combined cycle power plant including a gas turbine generator and a heat recovery steam generator. The system may include an inlet air cooler on the gas turbine generator configured to transfer heat to the heat transfer fluid. The system may include a heat exchanger configured to transfer thermal energy from the vapor condenser and the vapor condenser to the heat transfer fluid. The power plant may include a steam generator, a steam turbine generator, a steam condenser, and a recirculation pump. The power plant may be a geothermal power plant. The geothermal power plant may include a 2-cycle power plant.

The heat transfer fluid may be a single phase fluid such as water or a water / glycol mixture. The heat transfer fluid may be a phase change fluid, such as propane, Freon, phase change refrigerant, or any combination thereof.

The advantages of the techniques of the present invention are better understood with reference to the following detailed description and the accompanying drawings.

1 is a block diagram of a combined LNG terminal / power plant illustrating the use of heat from a power plant to regasify LNG;
2 is a block diagram illustrating a system for using heat from a power plant to vaporize LNG;
3 is a process flow diagram of an LNG regasification method that may be used in the system described above.
4 is a process flow diagram of a combined plant having both an LNG regeneration process and a combined cycle power plant.
5 is a process flow diagram of a combined plant having both an LNG regeneration process and a combined cycle power plant, without using separate intermediate heat transfer fluids.
5A is a process flow diagram of a combined plant having both an LNG regasification process using an intermediate heat transfer fluid on a LNG regeneration side and a combined cycle power plant.
6 is a process flow diagram of a combined plant having an LNG regasification plant in combination with a steam power plant.

In the following detailed description section, specific embodiments of the techniques of the present invention are described. However, to the extent that the following description is specific to a particular embodiment or specific use of the teachings of the invention, this is for illustrative purposes only and provides a brief description of the illustrative embodiment. Accordingly, the technology of the present invention is not limited to the specific embodiments described below, but rather includes all alternatives, modifications, and equivalents that fall within the true spirit and scope of the appended claims.

First, for ease of reference, the specific terms used in the present application and their meanings as used in the context are described. To the extent that the terms used herein are not defined below, if the broadest definition is provided, those skilled in the art should be provided with terms such as those reflected in at least one printed publication or issued patent. Also, since all equivalents, synonyms, novel developments and terms or descriptions which serve the same or similar purposes are considered to be within the scope of the claims of the present invention, the techniques of the present invention are defined by the use of the following terms It is not.

A "two-cycle power plant" is a type of power plant that allows geothermal reservoirs to be used at lower temperatures than steam power plants. In a two-cycle geothermal power plant, the pump is used to pump hot water from a geothermal well through a heat exchanger, and the cooling water is returned to the underground reservoir. A secondary circulating fluid having a low boiling point, such as butane, isobutane, pentane, alcohol or ketone, is pumped through the heat exchanger where it is vaporized from the geothermal reservoir against hot water and then through the turbine. The steam exiting the turbine is then condensed against a heat transfer fluid or a condensation fluid, such as cold water, and recycled through the heat exchanger. The efficiency of a two-cycle power plant may increase with temperature difference between the geothermal reservoir and the condensate fluid.

A "combined cycle power plant" includes a gas turbine, a steam turbine, a generator and a heat recovery steam generator (HRSG), and uses both steam and gas turbines to generate electricity. The gas turbine operates in the open Brayton cycle and the steam turbine operates in the Rankine cycle. Typically, the combined cycle power plant uses heat from the gas turbine exhaust to boil water in a heat recovery steam generator (HRSG) to generate steam. The generated steam is used to power the steam turbine. After powering the steam turbine, the steam can condense and the final water can be returned to the HRSG. The gas turbine and the steam turbine may be used to individually power an independent generator, or alternatively the steam turbine may be combined with a gas turbine to drive a single generator jointly via a common drive shaft. These combined cycle gas / steam generators typically have higher energy conversion efficiencies than gas or steam dedicated power plants. The combined cycle power plant efficiency can be as much as 50% to 60%. The higher combined cycle efficiency results from the synergy of the combination of gas turbine and steam turbine.

As used herein, a " cryogenic fluid " includes any fluid having a boiling point below about -130 DEG C under ambient pressure conditions. Such fluids may include liquefied natural gas (LNG), liquid nitrogen, liquid oxygen, liquid hydrogen, liquid helium, liquid carbon dioxide, and the like.

The term " gas " is used interchangeably with " steam " and refers to a substance or mixture of substances in a gaseous state as distinguished from a liquid or solid state. Likewise, the term " liquid " means a substance or mixture of substances in a liquid state as distinguished from a gas or solid state.

&Quot; Hydrocarbon " is an organic compound that includes primarily elemental hydrogen and carbon, but may be present in minor amounts of nitrogen, sulfur, oxygen, metal, or any number of other elements. As used herein, hydrocarbons generally refers to organic materials harvested from hydrocarbons, including subsurface rock layers, called reservoirs. For example, natural gas is hydrocarbons.

&Quot; Liquefied natural gas " or " LNG " refers to a high proportion of methane, as well as other elements including, but not limited to, ethane, propane, butane, carbon dioxide, nitrogen, helium, hydrogen sulfide, Lt; RTI ID = 0.0 > cryogenic < / RTI > liquid form of natural gas. The natural gas may be treated to remove one or more components (e.g., helium) or impurities (e.g., water and / or heavy hydrocarbons) and then be condensed to a liquid at near atmospheric pressure by cooling.

The term " natural gas " refers to a multi-component gas obtained from a crude oil well (associated gas) or from an underground gas containing formulation (non-accompanying gas). The composition and pressure of natural gas can vary considerably. Conventional natural gas streams contain methane (C ₁ ) as an essential component. Raw natural gas can contain trace contaminants such as ethane (C ₂ ), higher molecular weight hydrocarbons, acid gases (such as carbon dioxide, hydrogen sulphide, carbonyl sulfide, carbon disulfide and mercaptan) and water, nitrogen, iron sulfide, wax, May also be contained. As used herein, natural gas includes gases resulting from regasification of liquefied natural gas that has been purified to remove contaminants such as water, acid gases, and most higher molecular weight hydrocarbons.

"Pressure" is the force applied per unit area by the gas on the wall of the volume. The pressure can be expressed in pounds per square inch (psi). &Quot; Atmospheric pressure " refers to the local pressure of air. "Absolute pressure" (psia) refers to the sum of gauge pressure (psig) plus atmospheric pressure (14.7 psia in standard conditions). "Gauge pressure" refers to the pressure measured by the gauge, which indicates only the pressure above the local atmospheric pressure (ie, a gauge pressure of 0 psig corresponds to an absolute pressure of 14.7 psia). The term "vapor pressure" has a general thermodynamic meaning. For a pure component in the enclosure system at a given pressure, the component vapor pressure is essentially equal to the total pressure in the system.

As used herein, a " Rankine power plant " includes a steam generator, a steam turbine, a steam condenser, and a recirculation pump. Steam generators are often gas fired boilers that boil water to generate steam. However, in an embodiment, the steam generator may be a geothermal energy source, such as a hot rock bed in an underground formation. The steam is used to generate electricity in the steam turbine generator, and the reduced pressure steam is then condensed in the steam condenser. The final water is recycled to the steam generator to complete the loop.

&Quot; Significant " refers to an amount sufficient to provide the effect intended to provide the material or characteristic when used in reference to the amount of material or its particular characteristics. The precise degree of acceptable deviation may, in some cases, be dependent on the particular circumstances.

summary

The embodiments described herein provide liquid natural gas (LNG) regasification techniques and systems that reduce emissions associated with fuel-fired carburettors and enhance flexibility in utilizing LNG cold. In an embodiment, the LNG is regenerated using heat available from the gas turbine inlet air cooling or intercooling and heat from the steam condenser of the combined cycle power plant. In some embodiments, the intermediate heat transfer fluid (HTF) may transfer heat from the power plant or water tower to the LNG vaporizer.

1 is a block diagram of a combined LNG terminal / power plant 100 illustrating the use of heat from a power plant to regasify LNG. In the LNG terminal / power plant 100, the LNG 102 from the cargo ship may be unloaded into the LNG storage system 104, which may include a cryogenic tank or the vessel itself. The LNG from the storage device 106 may be transferred from the LNG storage system 104 via the re-hydration process 108 where the heat 110 from the power plant 112 may be used to assist in re- . The final natural gas 114 may be provided to the market. In addition, the portion 116 of natural gas may be converted to a power plant 112 for use as fuel. In the arrangement described herein, the power plant may not need to be dimensioned for maximum terminal capacity to utilize all available waste heat. The transfer of heat is described in more detail with respect to FIG.

2 is a block diagram illustrating a system 200 for using heat from a power plant to vaporize LNG. It will be clear that other system arrangements may be used in the embodiments as described below. Like reference numerals are as described with reference to FIG. As described in connection with FIG. 1, the LNG from the storage device 106 may be passed through the regasification process 108, such as being vaporized in the cryogenic heat exchanger 202. Cryogenic heat exchanger 202 may include a shell-and-tube heat exchanger or any number of other types of heat exchangers in which liquid LNG 204 is vaporized against the energy of heat transfer fluid 206. The final cooled intermediate fluid 208 may be heated in the intermediate heat exchanger 210 with respect to the hot water 212 arriving from a cooling tower 214 operating, for example, in a warm tower configuration.

In the cooling tower 214, the cold water 216 coming from the intermediate heat exchanger 210 can be warmed against heat energy coming from the power plant, against ambient air, or both. The cooling tower 214 may be a falling water or evaporative cooling tower, a pin-fan cooling tower, or any other type of cooling tower that can be operated to warm the fluid against the ambient air flow. The cooling tower 214 may be redesigned to operate in both cooling and warm mode. The cooled intermediate fluid 208 may also be heated within the heat exchanger 218 in the power plant. These heat exchangers 218 can be located on the inlet air to the gas turbine, on the intercooler for the gas turbine, on the exhaust separation unit used for the CO ₂ sequestration process, on the steam condenser, or any other heat source Lt; RTI ID = 0.0 > a < / RTI > During periods when the power plant does not provide sufficient thermal energy, the cooling tower 214 of the power plant may provide excess heat used to regenerate the LNG 204. This can reduce the initial capital cost associated with the power plant. The system described above provides a flexible capacity for providing heat to the LNG vaporization process, for example using the method described in connection with FIG.

3 is a process flow diagram of an LNG regeneration method 300 that may be used in the system described above. The method 300 begins at block 302, for example, with the heating of the intermediate fluid and the LNG in the cryogenic heat exchanger 202 (FIG. 2). If the power plant provides sufficient heat energy for the intermediate fluid, as determined at block 304, all intermediate fluid may be heated in the power plant as indicated at block 306. [ In this situation, the cooling tower may not need to be operated to provide the cooling duty of the vapor condenser. However, if the power plant is off-line or operating at reduced capacity, the heat provided may be insufficient. Under these operating conditions, at block 308, a portion of the intermediate fluid, or even the whole, can be heated in the cooling tower used for the warming service. Any number of plant configurations may be used in the embodiments as described in connection with Figs. 4-6.

As used herein, "sufficient thermal energy" is determined by the amount of heat required to vaporize sufficient LNG to meet market or pipeline requirements for natural gas (NG). For example, if the power plant is fully operational or NG is not required, all cooling of the power plant can be performed by the cooling tower. As the NG demand increases, more thermal energy is provided to the regasification process until all cooling of the power plant is provided by the regasification process. At this point, if additional NG supply is required, the thermal energy from the power plant will not be sufficient to vaporize the LNG needed to supply the NG demand, and supplementary heat from other sources will be required. Accordingly, the cooling tower can be operated in a warm tower configuration to provide supplemental heat. Similarly, if the power plant is operating off-line or at a reduced speed, the supplemental thermal energy from the cooling towers operated in the warm tower configuration can be used to provide sufficient heat for the regasification process.

Combined Cycle Power Plant / LNG  terminal

4 is a process flow diagram of a combined plant 400 having both an LNG regeneration process and a combined cycle power plant. In the combined plant 400, the LNG 402 is passed through a pump 404 which leads the LNG to the selling pressure of the final gas. LNG 402 is then regenerated against a warm stream of heat transfer fluid (HTF) 406 in cryogenic heat exchanger 408. Warm HTF has a temperature higher than 60 ((15.6 캜), higher than 50 ((10 캜), higher than 40 ℉ (4.4 캜) higher than cold LNG. Natural gas 410 from the regasification process can be provided to the market, and some can be used to fuel the power plant. The cryogenic heat exchanger 408 used as the LNG vaporizer may be a shell-and-tube type, a tube-in-tube type, or any other type of heat exchanger.

After passing through the cryogenic heat exchanger 408, the cold HTF 412 may be heated in the power plant. For example, the portion 414 of the cold HTF 412 may be heated in the inlet air cooler 416 where the inlet air flow for the gas turbine generator (GTG) 418 is cooled. Cooling the inlet air increases the density of the inlet air, and thus the power output of the GTG 418.

The HTF 412 may be heated in a number of other heat exchangers in the power plant in addition to or instead of the inlet air cooler 416. For example, another portion 420 of HTF 412 may be circulated through heat exchanger 422 to cool water stream 424. The cooled water 426 may then be dispensed through the vapor condenser 428. Condensate 430 from vapor condenser 428 may be dispensed via pump 432 for return to a heat recovery steam generator (HRSG) In the HRSG 434 the water flow 430 is converted to steam 436 by heat transferred from the exhaust of the GTG 418 and the steam 436 is used to drive the steam turbine generator STG 438 do. The low pressure steam from STG 438 is then returned to vapor condenser 428 to restart the cycle.

The hot water stream 440 from the vapor condenser 428 may be sent to the cooling tower 442 to remove excess heat. The cooling tower may be an evaporative air transfer heat exchanger in which water transfers heat from or to the atmosphere. If pin-fan cooling water is used, the heat transfer fluid can also be used to transfer heat from or into the atmosphere. The cooling water 444 is sent to the pump 446 and returned to the cooling cycle. If the bypass 448 is sufficient for the portion 420 of the cold HTF 412 flowing through the heat exchanger 422 to be sufficient to condense all or part of the steam from the STG 438, 428 < / RTI > to bypass the cooling tower 442 in the circulating loop. The cooling tower 442 also allows the power plant to operate when the cold from the LNG 402 is not available, or when the flow is insufficient to remove all thermal energy.

In other situations, the cold from the LNG 402 may be greater than the power plant can be used for inlet air cooling, intercooling, and vapor condensation. In this situation, the cooling tower 442 may be operated in an inverted or heated tower configuration to provide some or all of the energy required to vaporize the LNG 402, as indicated in FIG. 4 by the dashed line. In the warm mode, a portion or even all of the HTF 412 may be converted to a stream 450 that can be dispensed through intermediate heat exchanger 452. The intermediate heat exchanger 452 may be plate-frame, shell-and-tube, tube-in-tube, plate-shell or any combination thereof. In the intermediate heat exchanger 452, the cold stream 450 may be warmed against the stream of hot water 454 from the cooling tower 442. Cooling water 456 from intermediate heat exchanger 452 may then be returned to cooling tower 442, which will be warmed by ambient heat from the atmosphere. The warmed stream 458 of the HTF 412 is returned to the circulation loop to be recycled from the inlet cooler 416 and the vapor condenser 428 to the warm HTF 406 and the cryogenic heat exchanger 408. In the warm tower configuration, the cooling tower 442 also generates fresh water by condensing moisture from ambient air as ambient air is cooled by cold water. The cooling tower 442 may also be used in a heating tower configuration when the power plant is not operational or shut down for maintenance, thus ensuring continuous operation of the regasification terminal.

The HTF 412 may be, for example, a single phase fluid including, among other things, water and a water / glycol mixture. Various phase change fluids such as ammonia, propane, Freon or other refrigerants may also be used as the HTF 412. If a single phase heat transfer fluid is used, the warm HTF 406 may have a temperature of, for example, below about 32 ° F (0 ° C) or lower to a temperature of about 70 ° F (21.1 ° C) or higher. The cold HTF 412 may have a temperature of, for example, about 32 ° F (0 ° C) or may be lowered to a temperature of about 45 ° F (7.2 ° C) or higher. The temperature range can be low for phase change fluids, for example, above -40 ° F (-4.4 ° C), if propane is used, as a significant portion of the energy can be accompanied by phase changes per se.

The intermediate heat exchanger 452 may or may not be required depending on the choice of heat transfer fluid circulating between the cryogenic heat exchanger and the power plant. For example, if water is used as the heat transfer fluid, it can be combined with water in a cooling tower loop. Thus, as described in connection with FIG. 5, the cooling and warming circulation may be a single integrated loop.

5 is a process flow diagram of a combined plant 500 having both an LNG regasification process and a combined cycle plant using separate intermediate heat transfer fluids. Items with similar reference numerals are as described in connection with FIG. In complex plant 500, water may be used to carry heat flow through the process unit of the plant. The warm water stream 502 returned from various heat exchangers, such as, for example, heat exchangers 416, 422 and cooling towers 442, is used to regenerate the LNG 402 within the cryogenic heat exchanger 408, Lt; / RTI > The final cold water stream 504 can be used to provide cooling to other parts of the plant.

In some embodiments, the cryogenic heat exchanger 408 may be a submerged combustor (SCV). In the submerged combustor, a fuel such as natural gas and air and an oxidant may be supplied to the submerged burner nozzle in the water filling container. The flame from the burner heats the water, which for example transfers heat to the submerged tube through which the LNG flows. The SCV may be operated in the non-combustion mode as long as heat is available from another source, such as a power plant or a cooling tower (operated in a warm tower mode). If the SCV is used as the cryogenic heat exchanger 408, the burner may be used if the heat from other sources is not sufficient.

For example, the first portion 506 of the cold water stream 504 from the cryogenic heat exchanger 408 may be delivered to the inlet cooler 416 to provide inlet cooling for the GTG 418. The second portion 508 may be dispensed through the heat exchanger 422 to provide cooling for the steam condenser 428 to assist in condensation of the steam flow from the STG 438. The third portion 510 may be dispatched directly to the cooling tower 442 for warming by ambient air, for example if the thermal energy from the power plant is not sufficient to re-vaporize the LNG 402. The hot water stream 512 from the cooling tower 442 is directed to the return stream 514 from the heat exchanger 422 on the steam condenser 428 and the return stream 516 from the inlet cooler 416 on the GTG 418 Can be combined. The final hot water stream 502 may then be returned to the cryogenic heat exchanger 408 to close the loop. It will be appreciated that this is not the only configuration that can be used. Any number of heat sources may be cooled by the cold water stream 412 from the cryogenic heat exchanger 408. Further, the technique of the present invention is not limited to a combined cycle power plant using the GTG 418 and the HRSG 434 as described above, and may also utilize steam based on Rankine cycle It can be used with power plants based on other power generation cycles such as power plants.

5A is a cross-sectional view of the heat transfer fluid shown in FIG. 5B except for the addition of a heat exchanger 518, which is used to regenerate the LNG by exchanging heat with other heat transfer fluids, such as, for example, glycol, water, . Preferably, water is used in the remainder of the system including GTG inlet cooling, vapor condenser and cooling tower. The flow lines designated by the singular representation " a ", i.e. 502a, 508a, 510a, 512a, 514a and 516a, correspond to the flow lines of FIG. However, the singular expression " a " represents a potentially different flow rate, temperature and composition as compared to FIG. The flow rate and temperature difference and mass and energy balance generated by the addition of the heat exchanger 518 are immediately determined by those skilled in the art. The new lines 520 and 522 are each an output and an input from the heat exchanger 518.

6 is a process flow diagram of a combined plant 600 having an LNG regasification plant in combination with a steam power plant. Units of similar reference numbers are as described in connection with FIG. 6, the Rankine cycle power plant generally includes a steam generator 602, a steam turbine 604, a steam condenser 606, and a circulation pump 608. The thermal energy from the vapor condenser 606 may be removed by either energy exchange within the cooling tower 442 or with the portion 420 of the cold HTF 412 coming from the cryogenic heat exchanger 408. If cooling from portion 420 of HTF 412 flowing through heat exchanger 422 is sufficient, the cooling loop bypasses cooling tower 442 and may instead flow through bypass 448 have.

However, the thermal energy required to regenerate the LNG 402 may be greater than the thermal energy from the vapor condenser 606 or other source in the power plant. The portion 454 of the HTF 412 is dispensed through the intermediate heat exchanger 452 and discharged from the cooling tower 442 to the hot water 454 as the thermal energy from the power plant is not sufficient to re- Can be warmed up by the stream. In addition, if the power plant is not operating, all thermal energy may be provided from the cooling tower 442.

The combined plant 600 may also include any number of other sources of heat energy for the power generation system. For example, power generation can be performed by harvesting heat from a geothermal energy source, such as a hot rock bed. This configuration may generally appear as shown in the hybrid plant 600 of FIG. However, in this case, the steam generator 602 may be a geothermal heat source such as a hot rock bed below the surface. Heat within the hot rock bed can be accessed by pumping water into the cracks in the hot rock bed and harvesting the vapors produced from the hot rock bed.

However, the geothermal energy source may not have a sufficiently elevated temperature to efficiently provide energy to the Rankine cycle, for example by boiling water. In this case, a secondary circulating fluid having a low boiling point, such as isobutane, alcohol or other phase change fluids, can be used in the two-cycle power plant. In a two-cycle power plant, the steam generator 602 will be replaced by a geothermal heat exchanger that can be used to flash a secondary circulating fluid against the flow of warmed water from a geothermal energy source. The secondary circulating vapor will circulate through the turbine generator before being condensed in the heat exchanger, such as heat exchanger 606. After condensation, the secondary circulating fluid will then be returned to the geothermal heat exchanger to close the loop. The energy from the condensation of the secondary circulating fluid can be removed by the portion 420 of the HTF 412 circulated through the heat exchanger 422. The large temperature difference that may exist between the HTF 412 and the geothermal energy source can increase the efficiency of bi-cyclic generation and also allow the use of a limited geothermal energy source in a cost-effective manner.

Other configurations of any number of complex plants may be used to utilize the waste heat to regasify the LNG 402. For example, in addition to providing cooling to the condenser, the LNG regasification process can provide cooling for the quench process used to sequester CO ₂ from the exhaust or stack gas. In addition, the cooling tower 442 need not be based on backwash flow, but may also be a fin-fan type heat exchanger. The fin-to-fan heat exchanger may be used to exchange energy from the circulating fluid for ambient air, for example to cool the hot water stream 440 or warm the cooling water 456 from the intermediate heat exchanger 452. This configuration may be useful in areas where water resources are limited, such as in desert climates.

The composition of the combined plant can provide the ability to optimize the use of cold from the LNG 402 while reducing environmental emissions associated with LNG regasification. For example, if a 250 megawatt (MW) power plant is installed in the regasification terminal with a capacity of 2 billion cubic feet per day (BCFD) for the production of natural gas 410, A cold can be used from the LNG 402, which is equivalent to only one BCFD. Up to this point, the cooling tower 442 of the power plant may not need to be utilized to remove thermal energy from the power plant.

When the sale of natural gas 410 exceeds 1 BCFD, the cooling tower 442 of the power plant can operate as a warming tower to meet the sale requirements. Similarly, if there is a reduced demand for electricity, both the power plant and the cooling tower 442 can be operated to meet the sale requirements for the natural gas 410. To assist in meeting the demand for natural gas when the power plant is not in operation, the cooling tower 442 may be specialized so that sufficient LNG 410 can be regenerated when operating in the warm tower mode. It can be noted that the life cycle economic analysis can suggest different combinations of power plant and heating tower sizes, and thus the values described herein are merely exemplary and not limiting.

In summary, the embodiments described herein provide benefits over fuel-fired carburettors, including for example the efficient use of installed equipment such as cooling towers. The technology of the present invention also provides increased flexibility using the cold contained within the LNG 402 and reduces the amount of fuel used to vaporize the LNG 410 thus reducing the amount of natural gas 410 Increase sales and profits. The elimination or reduction of the fuel-fired carburettor can also reduce the associated capital costs and operating costs and provides a reduction in emissions such as CO ₂ and NO _x associated with the fuel consumption of the vaporizer within the terminal. The use of cold from LNG 402 also provides increased power plant efficiency and power output. In addition, condensation can produce a significant amount of fresh water that can be used as the feed to the heat recovery steam generator 434.

While the techniques of the present invention may be susceptible to various modifications and alternative forms, the above-described exemplary embodiments are shown by way of example only. It should be understood, however, that the teachings of the present invention are not intended to be limited to the specific embodiments disclosed herein. Indeed, the techniques of the present invention include all alternatives, modifications and equivalents that fall within the true spirit and scope of the appended claims.

Claims (28)

A method for regasifying liquefied natural gas (LNG)
Providing heat from the power plant to the LNG regasification process; And
In a cooling tower of the power plant configured to operate in both a warm mode and a cooling mode:
Providing additional heat to the LNG regasification process from the cooling tower operating in the warm mode if the provided heat is not sufficient for the regasification process; And
And providing cooling to the cooling water for the power plant from the cooling tower operating in the cooling mode if the provided heat is sufficient for the regasification process. The method of claim 1, further comprising cooling water in the cooling tower when the power plant is operating. The method of claim 1, further comprising using the cooling tower to warm the heat transfer fluid. The method of claim 1, further comprising cooling the intake air for the gas turbine by transferring heat to the LNG regasification process. The method of claim 1, further comprising condensing steam from the steam turbine within the steam condenser by transferring energy to the LNG regasification process. The method of claim 1, further comprising transferring energy from the power plant to the LNG regasification process through a heat transfer fluid. 7. The method of claim 6, further comprising heating at least a portion of the heat transfer fluid relative to an inlet air stream for a gas turbine. 7. The method of claim 6, further comprising heating at least a portion of the heat transfer fluid by heat generated as the steam from the steam turbine condenses within the power plant. A method for vaporizing a cryogenic fluid,
Vaporizing the cryogenic fluid against a heat transfer fluid;
Providing thermal energy to the heat transfer fluid from a power plant; And
If heat from the power plant is not sufficient to vaporize the cryogenic fluid,
And providing thermal energy to the heat transfer fluid from a cooling tower of the power plant operating in a warm mode. 10. The method of claim 9, further comprising heating at least a portion of the heat transfer fluid relative to an inlet air stream for a gas turbine. 10. The method of claim 9, further comprising heating at least a portion of the heat transfer fluid by heat generated as the steam from the steam turbine condenses within the power plant. A system for regasifying liquefied natural gas,
A cryogenic heat exchanger configured to regenerate the stream of LNG;
Power plant;
A cooling tower configured to operate in a cooling or warming mode; And
A heat transfer fluid, said heat transfer fluid comprising
Providing heat from the power plant to the cryogenic heat exchanger; And
If the provided heat is not sufficient for the LNG regasification process,
And to provide at least a portion of the heat from the cooling tower to the cryogenic heat exchanger. 13. The system of claim 12, further comprising an intermediate heat exchanger configured to transfer heat from the cooling tower to the heat transfer fluid. 14. The system of claim 13, wherein the intermediate heat exchanger is plate-frame, shell-and-tube, tube-in-tube, plate-shell or any combination thereof. 13. The system of claim 12, wherein the power plant comprises a combined cycle power plant including a gas turbine generator and a heat recovery steam generator. 16. The system of claim 15, further comprising an inlet air cooler on a gas turbine generator configured to transfer the heat to the heat transfer fluid. 13. The system of claim 12 including a vapor condenser and a heat exchanger configured to transfer thermal energy from the vapor condenser to the heat transfer fluid. 13. The system of claim 12, wherein the power plant comprises a steam generator, a steam turbine generator, a steam condenser, and a recirculation pump. 13. The system of claim 12, wherein the power plant comprises a geothermal power plant. 20. The system of claim 19, wherein the geothermal power plant comprises a two-cycle power plant. 13. The system of claim 12, wherein the heat transfer fluid is a single phase fluid. 13. The system of claim 12, wherein the heat transfer fluid is water or a water / glycol mixture. 13. The system of claim 12, wherein the heat transfer fluid is a phase change fluid. 13. The system of claim 12, wherein the heat transfer fluid is propane, freon, phase change refrigerant or any combination thereof. 13. The system of claim 12, wherein the cooling tower is an evaporative cooling tower or a fin-fan cooling tower. 13. The system of claim 12, wherein the cryogenic heat exchanger is a submerged combustor (SCV). 27. The system of claim 26, wherein the SCV is used in a combustion mode to provide additional heat. 13. The system of claim 12, wherein the cryogenic heat exchanger is a shell-and-tube vaporizer.

Images