Power generation and LNG production

Abstract

The present techniques are directed to a system and method for generating power and producing liquefied natural gas (LNG). The system includes a power plant configured to generate power, wherein an exhaust gas from the power plant provides a gas mixture including nitrogen and carbon dioxide. The system also includes a dehydration system configured to dehydrate the gas mixture to generate a nitrogen refrigerant stream and a refrigeration system configured to produce LNG from a natural gas stream using the nitrogen refrigerant stream.

Description

FIELD OF THE INVENTION

The present disclosure relates generally to power generation and liquefied natural gas (LNG) production. More particularly, the present disclosure relates to systems and methods for integrating power generation with LNG production.

BACKGROUND

This section is intended to introduce various aspects of the art, which may be associated with exemplary embodiments of the present techniques. This discussion is believed to assist in providing a framework to facilitate a better understanding of particular aspects of the present techniques. Accordingly, it should be understood that this section should be read in this light, and not necessarily as admissions of prior art.

A Brayton cycle engine commonly known as a gas turbine engine often has a turbine compressor that is mechanically linked to an expander turbine through a shaft. The turbine compressor can be used to compress a flow of air ingested by the turbine compressor. The compressed air is then flowed to a combustor. In the combustor, fuel is injected and ignited to create a continuous flame. The high pressure exhaust gases from the flame are flowed into the expander turbine, which generates mechanical energy from the exhaust gas as it expands. Such a gas turbine engine can be adapted to combust fuel at near stoichiometric conditions with exhaust gas recirculation (EGR) and may be referred to as an ultra-low emissions technology (ULET) engine.

The exhaust gas may include a mixture of nitrogen, carbon dioxide, water, and any number of other gaseous components. A portion of the exhaust gas may be extracted from the engine or EGR system and, following some treatment, may be injected into a reservoir for pressure maintenance or enhanced hydrocarbon recovery from a subterranean reservoir or for carbon sequestration. For some applications, at least a portion of the nitrogen product from the extracted exhaust gas is not used for reservoir pressure maintenance or enhanced hydrocarbon recovery. Therefore, at least a portion of the nitrogen product may be vented to the atmosphere after expansion and power recovery. For some current applications, the excess nitrogen product is used in conjunction with a high temperature expansion process to increase the amount of power recovered from the system. However, the excess nitrogen product may also be used for a variety of other purposes.

U.S. Pat. No. 4,271,664 to Earnest discloses a turbine engine with exhaust gas recirculation. The engine has a main power turbine operating on an open-loop Brayton cycle. The air supply to the main power turbine is furnished by a compressor independently driven by the turbine of a closed-loop Rankine cycle which derives heat energy from the exhaust of the Brayton turbine. A portion of the exhaust gas is recirculated into the compressor inlet during part-load operation. However, no additional uses are disclosed for the recycled exhaust.

U.S. Pat. No. 6,412,302 to Foglietta et al. describes a process for producing a liquefied natural gas stream. The process includes cooling at least a portion of a pressurized natural gas feed stream by heat exchange contact with first and second expanded refrigerants that are used in independent refrigeration cycles. The first expanded refrigerant is selected from methane, ethane, and treated and pressurized natural gas, while the second expanded refrigerant is nitrogen. However, generation of the second expanded refrigerant from exhaust gas including nitrogen is not disclosed.

SUMMARY

An exemplary embodiment of the present techniques provides a system for generating power and producing liquefied natural gas (LNG). The system includes a power plant configured to generate power, wherein an exhaust gas from the power plant provides a gas mixture including nitrogen and carbon dioxide. The system also includes a dehydration system configured to dehydrate the gas mixture to generate a nitrogen refrigerant stream and a refrigeration system configured to produce LNG from a natural gas stream using the nitrogen refrigerant stream.

Another exemplary embodiment provides a method for generating power and producing liquefied natural gas (LNG). The method includes producing power via a power plant, wherein an exhaust gas from the power plant provides a gas mixture including nitrogen and carbon dioxide. The method also includes generating a nitrogen refrigerant stream from the gas mixture and producing LNG from a natural gas stream using the nitrogen refrigerant stream.

Another exemplary embodiment provides a system for producing liquefied natural gas (LNG) using nitrogen recovered from a combined cycle power plant. The system includes an expander turbine configured to provide mechanical energy by extracting energy from a gas mixture exiting a combustor, wherein the gas mixture includes nitrogen and carbon dioxide. The system also includes a heat recovery steam generator (HRSG) configured to generate steam by heating a boiler with the gas mixture from the expander turbine, a steam turbine configured to provide mechanical energy by extracting energy from the steam generated by the HRSG, and a generator configured to generate electricity from the mechanical energy provided by the expander turbine and the steam turbine. The system further includes a dehydration system configured to dehydrate the gas mixture, generating a nitrogen refrigerant stream, and a refrigeration system configured to produce LNG from a natural gas stream using the nitrogen refrigerant stream.

BRIEF DESCRIPTION OF THE DRAWINGS

The advantages of the present techniques are better understood by referring to the following detailed description and the attached drawings, in which:

FIG. 1 is a block diagram of a system for power generation and LNG production;

FIG. 2 is a process flow diagram of a combined cycle power plant that can be used to produce electricity and generate a diluent gas mixture including nitrogen (N₂) and carbon dioxide (CO₂);

FIG. 3 is a process flow diagram of a system for integrating low emissions power generation with LNG production;

FIG. 4 is a process flow diagram of another system for integrating low emissions power generation with LNG production;

FIG. 5 is a process flow diagram of another system for integrating low emissions power generation with LNG production; and

FIG. 6 is a process flow diagram of a method for power generation and LNG production.

DETAILED DESCRIPTION

In the following detailed description section, specific embodiments of the present techniques are described. However, to the extent that the following description is specific to a particular embodiment or a particular use of the present techniques, this is intended to be for exemplary purposes only and simply provides a description of the exemplary embodiments. Accordingly, the techniques are not limited to the specific embodiments described herein, but rather, include all alternatives, modifications, and equivalents falling within the true spirit and scope of the appended claims.

At the outset, for ease of reference, certain terms used in this application and their meanings as used in this context are set forth. To the extent a term used herein is not defined herein, it should be given the broadest definition persons in the pertinent art have given that term as reflected in at least one printed publication or issued patent. Further, the present techniques are not limited by the usage of the terms shown herein, as all equivalents, synonyms, new developments, and terms or techniques that serve the same or a similar purpose are considered to be within the scope of the present claims.

A “combined cycle power plant” is generally the combination of an open Brayton Cycle and a Rankine cycle. Combined cycle power plants typically use both steam and gas turbines to generate power, although other working fluids besides water and steam may be used in the Rankine cycle. The combined cycle gas/steam power plants generally have a higher energy conversion efficiency than gas or steam only plants. A combined cycle plant's efficiencies can be as high as 50% to 60% of a lower heating value (LHV). The higher combined cycle efficiencies result from synergistic utilization of a combination of the gas turbine with the steam turbine. Typically, combined cycle power plants utilize heat from the gas turbine exhaust to boil water to generate steam. The boilers in typical combined cycle plants can be referred to as heat recovery steam generator (HRSG). The steam generated is utilized to power a steam turbine in the combined cycle plant. The gas turbine and the steam turbine can be utilized to separately power independent generators, or in the alternative, the steam turbine can be combined with the gas turbine to jointly drive a single generator via a common drive shaft.

As used herein, a “compressor” includes any type of equipment designed to increase the pressure of a fluid or working fluid, and includes any one type or combination of similar or different types of compression equipment. A compressor may also include auxiliary equipment associated with the compressor, such as motors, and drive systems, among others. The compressor may utilize one or more compression stages, for example, in series. Illustrative compressors may include, but are not limited to, positive displacement types, such as reciprocating and rotary compressors for example, and dynamic types, such as centrifugal and axial flow compressors, for example. For example, a compressor may be a first stage in a gas turbine engine, as discussed in further detail herein.

As used herein, “cooling” broadly refers to lowering and/or dropping a temperature and/or internal energy of a substance, such as by any suitable amount. Cooling may include a temperature drop of at least about 1 degree Celsius (° C.), at least about 5° C., at least about 10° C., at least about 15° C., at least about 25° C., at least about 50° C., at least about 100° C., and/or the like. The cooling may use any suitable heat sink, such as steam generation, hot water heating, cooling water, air, refrigerant, other process streams (integration), and combinations thereof. One or more sources of cooling may be combined and/or cascaded to reach a desired outlet temperature. The cooling step may use a cooling unit with any suitable device and/or equipment. According to one embodiment, cooling may include indirect heat exchange, such as with one or more heat exchangers. Heat exchangers may include any suitable design, such as shell and tube, plate and frame, counter current, concurrent, extended surface, and/or the like. In the alternative, the cooling may use evaporative (heat of vaporization) cooling and/or direct heat exchange, such as a liquid sprayed directly into a process stream.

“Cryogenic temperature” refers to a temperature that is about −50° C. or below.

A “diluent” is a gas used to lower the concentration of an oxidant fed to a gas turbine to combust a fuel, a gas used to lower the concentration of a fuel fed to a gas turbine that is combusted with an oxidant, a gas used to reduce the temperature of the products of combustion of a fuel and an oxidant fed to a gas turbine or a combination of these. The diluent may be an excess of nitrogen, carbon dioxide, combustion exhaust, or any number of other gases. In embodiments, the diluent may also provide cooling to a combustor.

“Enhanced oil recovery” or “EOR” refers to processes for enhancing the recovery of hydrocarbons from subterranean reservoirs by the introduction of materials not naturally occurring in the reservoir.

An “equivalence ratio” refers to the mass ratio of fuel to oxygen entering a combustor divided by the mass ratio of fuel to oxygen when the ratio is stoichiometric. A perfect combustion of fuel and oxygen to form carbon dioxide and water would have an equivalence ratio of 1. A too lean mixture, e.g., having more oxygen than fuel, would provide an equivalence ratio less than 1, while a too rich mixture, e.g., having more fuel than oxygen, would provide an equivalence ratio greater than 1.

A “fuel” includes any number of hydrocarbons that may be combusted with an oxidant to power a gas turbine. Such hydrocarbons may include natural gas, treated natural gas, kerosene, gasoline, or any number of other natural or synthetic hydrocarbons. In one embodiment, natural gas from an oil field is purified and used to power the turbine. In another embodiment, a reformed gas, for example, created by processing a hydrocarbon in a steam reforming process may be used to power the turbine.

The term “gas” is used interchangeably with “vapor,” and is defined as a substance or mixture of substances in the gaseous state as distinguished from the liquid or solid state. Likewise, the term “liquid” means a substance or mixture of substances in the liquid state as distinguished from the gas or solid state.

A “gas turbine engine” operates on the Brayton cycle. If the exhaust gas is vented to the atmosphere, this is termed an open Brayton cycle, while recycling of the exhaust gas gives a closed Brayton cycle. As used herein, a “gas turbine” typically includes a compressor section, a number of combustors, and an expander turbine section. The compressor may be used to compress an oxidant, which is mixed with a fuel and channeled to the combustors. The mixture of fuel and oxidant is then ignited to generate hot combustion gases. The combustion gases are channeled to the expander turbine section which extracts energy from the combustion gases for powering the compressor, as well as producing useful work to power a load. In embodiments discussed herein, the oxidant may be provided to the combustors by an external compressor, which may or may not be mechanically linked to the shaft of the gas turbine engine. Further, in embodiments, the compressor section may be used to compress a diluent, such as recycled exhaust gases, which may be fed to the combustors as a coolant.

A “heat exchanger” broadly means any device capable of transferring heat from one media to another media, including particularly any structure, e.g., device commonly referred to as a heat exchanger. Heat exchangers include “direct heat exchangers” and “indirect heat exchangers.” Thus, a heat exchanger may be a plate-and-frame, shell-and-tube, spiral, hairpin, core, core-and-kettle, double-pipe or any other type of known heat exchanger. “Heat exchanger” may also refer to any column, tower, unit or other arrangement adapted to allow the passage of one or more streams therethrough, and to affect direct or indirect heat exchange between one or more lines of refrigerant, and one or more feed streams.

A “heat recovery steam generator” or “HRSG” is a heat exchanger or boiler that recovers heat from a hot gas stream. It produces steam that can be used in a process or used to drive a steam turbine. A common application for an HRSG is in a combined-cycle power plant, where hot exhaust from a gas turbine is fed to the HRSG to generate steam which in turn drives a steam turbine. This combination produces electricity more efficiently than either the gas turbine or steam turbine alone.

A “hydrocarbon” is an organic compound that primarily includes the elements hydrogen and carbon, although nitrogen, sulfur, oxygen, metals, or any number of other elements may be present in small amounts. As used herein, hydrocarbons generally refer to components found in raw natural gas, such as CH₄, C₂H₂, C₂H₄, C₂H₆, C₃ isomers, C₄ isomers, benzene, and the like.

“Liquefied natural gas” or “LNG” is natural gas generally known to include a high percentage of methane. However, LNG may also include trace amounts of other compounds. The other elements or compounds may include, but are not limited to, ethane, propane, butane, carbon dioxide, nitrogen, helium, hydrogen sulfide, or combinations thereof, that have been processed to remove one or more components (for instance, helium) or impurities (for instance, water and/or heavy hydrocarbons) and then condensed into a liquid at almost atmospheric pressure by cooling.

“Natural gas” refers to a multi-component gas obtained from a crude oil well or from a subterranean gas-bearing formation. The composition and pressure of natural gas can vary significantly. A typical natural gas stream contains methane (CH₄) as a major component, i.e., greater than 50 mol % of the natural gas stream is methane. The natural gas stream can also contain ethane (C₂H₆), higher molecular weight hydrocarbons (e.g., C₃-C₂₀ hydrocarbons), one or more acid gases (e.g., carbon dioxide or hydrogen sulfide), or any combinations thereof. The natural gas can also contain minor amounts of contaminants such as water, nitrogen, iron sulfide, wax, crude oil, or any combinations thereof. The natural gas stream may be substantially purified prior to use in embodiments, so as to remove compounds that may act as poisons.

An “oxidant” is a gas mixture that can be flowed into the combustors of a gas turbine engine to combust a fuel. As used herein, the oxidant may be oxygen mixed with any number of other gases as diluents, including carbon dioxide (CO₂), nitrogen (N₂), air, combustion exhaust, and the like. Other gases that function as oxidizers may be present in the oxidant mixture in addition to oxygen, including ozone, hydrogen peroxide, NOxs, and the like.

“Pressure” is the force exerted per unit area by the gas on the walls of the volume. Pressure can be shown as pounds per square inch (psi). “Atmospheric pressure” refers to the local pressure of the air. “Absolute pressure” (psia) refers to the sum of the atmospheric pressure (14.7 psia at standard conditions) plus the gage pressure (psig). “Gauge pressure” (psig) refers to the pressure measured by a gauge, which indicates only the pressure exceeding the local atmospheric pressure (i.e., a gauge pressure of 0 psig corresponds to an absolute pressure of 14.7 psia). The term “vapor pressure” has the usual thermodynamic meaning. For a pure component in an enclosed system at a given pressure, the component vapor pressure is essentially equal to the total pressure in the system.

A “refrigerant component,” in a refrigeration system, will absorb heat at a lower temperature and pressure through evaporation and will reject heat at a higher temperature and pressure through condensation. Illustrative refrigerant components may include, but are not limited to, alkanes, alkenes, and alkynes having one to five carbon atoms, nitrogen, chlorinated hydrocarbons, fluorinated hydrocarbons, other halogenated hydrocarbons, noble gases, and mixtures or combinations thereof.

“Substantial” when used in reference to a quantity or amount of a material, or a specific characteristic thereof, refers to an amount that is sufficient to provide an effect that the material or characteristic was intended to provide. The exact degree of deviation allowable may in some cases depend on the specific context.

Overview

Embodiments described herein provide a system and method for power generation and LNG production. More specifically, embodiments described herein provide a system and method for the integration of low emissions power generation with LNG production. According to such embodiments, a gas mixture including N₂ and CO₂ is generated from a power plant during the generation of power. A CO₂ separation system, such as an amine separation, hot potassium carbonate, solid sorbent or similar system is used to separate the gas mixture into CO₂-rich and CO₂-lean streams. The CO₂-lean stream is primarily nitrogen and may be referred to as a nitrogen stream.

A dehydration system dehydrates the nitrogen stream to generate a nitrogen refrigerant stream, and a refrigeration system produces LNG from a natural gas stream using the nitrogen refrigerant stream. Alternatively, the CO₂ separation system may be excluded, and the gas mixture (primarily nitrogen, CO₂, and water vapor) may be dehydrated to generate a mixed refrigerant stream. The dehydration is intended to remove sufficient water from the refrigerant stream so that water ice or frost does not form at the cryogenic conditions attained within the refrigeration system. The dehydration system may be a glycol absorption type, membrane type or similar technologies. For a similar reason, the cryogenic temperatures attained by the mixed CO₂ and nitrogen refrigerant are limited to avoid dry ice formation. Further processing of a make-up stream to remove CO₂ may be performed prior to first fill or replacement of leakages from the refrigeration system.

Systems for Power Generation and LNG Production

FIG. 1 is a block diagram of a system 100 for power generation and LNG production. In the system 100, oxidant 102 and fuel gas 104 are provided to a power plant 106, for example, a gas turbine generator (GTG), at a substantially stoichiometric ratio. The oxidant 102 can be air having about 78% N₂ and about 21% oxygen and, thus, the ratio would be calculated between the fuel gas 104 and the oxygen portion of the oxidant 102. The fuel gas 102 and oxygen are substantially completely combusted in the GTG of the power plant 106 to form an exhaust gas that includes N₂, CO₂, and water (H₂O), as well as trace amounts of carbon monoxide (CO), nitrogen oxides (NOx), oxygen (O₂), and fuel. The energy from the exhaust gas is used to drive an expander turbine that turns a shaft. A generator coupled to the shaft generates electricity 108.

In some embodiments, the power plant 106 is a semi-closed Brayton cycle power plant. The power plant 106 may be a combined cycle power plant that includes both a semi-closed Brayton cycle and a Rankine cycle. In such embodiments, the exhaust stream from the expander turbine of the semi-closed Brayton cycle can be used to boil water or other heat transfer fluids in a heat recovery steam generator (HRSG) that can be used to power the Rankine cycle power plant. In the Rankine cycle power plant, the steam or other vapor can be used to drive a turbine and generate more electricity 108.

The treated stream from the power plant 106 forms a gas mixture 110. The gas mixture 110 may include N₂, CO₂, NOx, and any number of other gaseous components. The gas mixture 110 is flowed through a CO₂ separation system 112, in which the CO₂ 114 is separated from the N₂, H₂O, and other gaseous components within the gas mixture 110. The NOx may be removed along with the CO₂.

The gas mixture 110 is then flowed through a N₂ dehydration system 116, in which the H₂O 118 is separated from the N₂ and other gaseous components within the gas mixture 110. The dehydration of the gas mixture 110 results in the generation of a nitrogen refrigerant stream 120.

The nitrogen refrigerant stream 120 is flowed through a refrigeration system 122. Within the refrigeration system 122, the nitrogen refrigerant stream 120 is used to cool a natural gas stream 124, producing LNG 126. More specifically, the refrigeration system 122 may include a number of heat exchangers, gas expanders, compressors, pumps, and related equipment, in which the nitrogen refrigerant stream 120 is used to cool the natural gas stream 124 to produce the LNG 126 via indirect heat exchange.

The block diagram of FIG. 1 is not intended to indicate that the system 100 is to include all of the components shown in FIG. 1. Moreover, the system 100 may include any number of additional components not shown in FIG. 1, depending on the details of the specific implementation. For example, in various embodiments, the gas mixture 110 is flowed through a precooler before being flowed through the CO₂ separation system 112. The precooler may lower the temperature of the gas mixture 110 in preparation for the utilization of the nitrogen from the gas mixture 110 as a refrigerant in the refrigeration system 122.

FIG. 2 is a process flow diagram of a combined cycle power plant 200 that can be used to produce electricity 202 and generate a diluent gas mixture including N₂ and CO₂. In various embodiments, the combined cycle power plant 200 includes a semi-closed Brayton cycle including, for example, an expander turbine 206, and a Rankine cycle including, for example, a HRSG 208.

Within the combined cycle power plant 200, oxidant 210 and fuel gas 212 are fed to a combustor 214 to be burned. A compressed diluent stream 216 is also fed to the combustor 214 to dilute the fuel gas 212, oxidant 210 and/or hot exhaust gas 218, which allows the combustion process to be run at near stoichiometric conditions without overheating the combustor 214 or the expander turbine 206. As a result, the amount of O₂ and CO generated in the combustion process is decreased, and hot exhaust gas 218 exiting the combustor includes mostly CO₂, H₂O, and N₂, in addition to some trace gases, such as CO and NOx.

The oxidant 210 and fuel gas 212 pressures may be increased, for example, using compressors, to boost the pressure to match the injection pressure of the compressed diluent stream 216 at the combustor 214. The hot exhaust gas 218 from the combustor 214 is flowed to the expander turbine 206, which uses the energy of the hot exhaust gas 218 to spin a shaft 220. The shaft 220 provides mechanical energy to the compressor turbine 224, completing the Brayton cycle. The shaft 220 may also provide mechanical energy to an electric generator 222 to generate electricity 202. The electric generator 222 may be directly coupled to the shaft 220 from the expander turbine 206, or may be coupled to the shaft 220 by a gear box, clutch, or other device.

From the expander turbine 206, the hot exhaust gas 218 is flowed to the HRSG 208. The HRSG 208 may boil a water stream 224 with the energy from the hot exhaust gas 218 to generate steam 226. The steam 226 that is generated can be used to drive a steam turbine 228 and spin a shaft 230. After exiting the steam turbine 228, the resulting low pressure steam 232 can be cooled and condensed, to be used as the water stream 224 to feed the HRSG 208.

The shaft 230 from the steam turbine 228 can provide mechanical energy to an electric generator 234 to generate electricity 202, or may be used power other devices, such as compressors. The electric generator 234 may be directly coupled to the shaft 230 from the steam turbine 228, or may be coupled to the shaft 230 by a gear box, clutch, or other device. Further, in the embodiment shown in FIG. 2, the expander turbine 206 and the steam turbine 228 are coupled to separate electric generators 222 and 234. However, it is to be understood that the expander turbine 206 and the steam turbine 228 may also be coupled, directly or indirectly, to one common electric generator.

The hot gas stream 236 exiting the HRSG 208 is flowed to a cooler 238. The cooler 238 chills the hot gas stream 236, causing the water vapor formed in the combustion process to condense out, allowing its removal as a separate water stream 240. After removal of the water stream 240, the chilled gas mixture 242 is provided to a compressor 244 for recompression, prior to feeding the compressed diluent stream 216 to the combustor 214 to aid in cooling the combustor 214. The recycling of the hot gas stream 236 as the diluent stream 216 partially closes the Brayton cycle in the combined cycle power plant 200, resulting in a semi-closed Brayton cycle.

As the fuel gas 212 and the oxidant 210 are continuously being fed to the combined cycle power plant 200 to maintain the combustion, a portion 246 of the diluent stream 216 is continuously removed. The diluent stream 216 may include N₂, CO₂, H₂O, NOx, and any number of other gaseous components.

According to embodiments described herein, the diluent stream 216 exiting the combined cycle power plant 200 is flowed to an LNG production system (not shown). Within the LNG production system, the diluent stream 216 undergoes CO₂ separation and dehydration. The resulting nitrogen stream is then used as a refrigerant to produce LNG from natural gas. The process of producing LNG using the diluent stream 216 is described further with respect to FIGS. 3-6.

The process flow diagram of FIG. 2 is not intended to indicate that the combined cycle power plant 200 is to include all of the components shown in FIG. 2. Moreover, the combined cycle power plant 200 may include any number of additional components not shown in FIG. 2, depending on the details of the specific implementation.

FIG. 3 is a process flow diagram of a system 300 for integrating low emissions power generation with LNG production. The system 300 provides for low emissions power generation using a combined cycle power plant including a semi-closed Brayton cycle that utilizes a gas turbine engine 302 and a Rankine cycle that utilizes an HRSG 304. In addition, the system 300 provides for LNG production by using exhaust gases from the combined cycle power plant as a refrigerant in a refrigeration system.

As shown in FIG. 3, air 306 and fuel gas 308 are fed to a combustor 310 to be burned within the semi-closed Brayton cycle. While air 306 is used as the oxidant in the embodiment shown in FIG. 3, it is to be understood that any other suitable type of oxidant may also be used in conjunction with the system 300.

A compressed diluent stream 312 is also fed to the combustor 310 to dilute the air 306 and/or fuel gas 308 that is utilized for the combustion process and/or the hot exhaust gas 314. This may allow the combustion process to be run at near stoichiometric conditions without overheating. As a result, the amount of O₂ and CO generated in the combustion process is decreased, and hot exhaust gas 314 exiting the combustor includes mostly CO₂, H₂O, and N₂, in addition to some trace gases.

The air 306 and fuel gas 308 pressures may be increased, for example, using compressors, to boost the pressure to match the injection pressure of the compressed diluent stream 312 at the combustor 310. For example, according to the embodiment shown in FIG. 3, the air 306 is compressed within an air compressor 316. In addition, the air compressor 316 may include one or more stages of compression, and may include one or more intercoolers to reduce the temperature of the air between stages. Furthermore, when more than one stage of compression is included, the individual stages may or may not be configured in a common casing or driven by a common shaft or other driving means. The compressed air 306 is then fed into the combustor 310 to be burned.

The hot exhaust gas 314 from the combustor 310 is flowed to an expander turbine 322 of the gas turbine engine 302, which uses the energy of the hot exhaust gas 314 to spin a shaft 324. The shaft 324 provides mechanical energy to an electric generator 326 to generate electricity 328. The electric generator 326 may be directly coupled to the shaft 324 from the expander turbine 322, or may be coupled to the shaft 324 by a gear box, clutch, or other device.

From the expander turbine 322, the hot exhaust gas 314 is flowed to the HRSG 304 within the Rankine cycle of the combined cycle power plant. The HRSG 304 boils a water stream 330 to generate steam 332 with the energy from the hot exhaust gas 314. In various embodiments, the generated steam 332 is used to drive the steam turbine, which uses the energy of the steam 332 to spin a shaft. The shaft may provide mechanical energy to an electric generator to generate additional electricity.

The hot gas stream 334 exiting the HRSG 304 is flowed to an exhaust gas recirculation (EGR) blower 336. The EGR blower 336 compresses the hot gas stream 334 and feeds the resulting compressed gas stream 338 into an EGR cooler 340. The EGR cooler 340 chills the compressed gas stream 338, producing a diluent stream 342 and condensed water, not shown.

The diluent stream 342 is then fed into a compressor 344. The compressor 344 compresses the diluent stream 342, producing the compressed diluent stream 312. In the embodiment shown in FIG. 3, the compressor 344 is coupled to the shaft 324, and the mechanical energy provided by the spinning of the shaft 324 is used to drive the compressor 344.

From the compressor 344, the compressed diluent stream 312 is fed to the combustor 310 to aid in cooling the combustor 310. The recycling of the hot gas stream 334 as the compressed diluent stream 312 partially closes the Brayton cycle in the combined cycle power plant, resulting in the semi-closed Brayton cycle.

As the air 306 and the fuel gas 308 are continuously being fed to the combustor 310 to maintain the combustion process, at least a portion of the compressed diluent stream 312 is continuously removed. For example, a portion of the diluent stream 312 may be removed as a gas mixture 346 including N₂, CO₂, H₂O, and any number of other gaseous components.

According to embodiments described herein, the gas mixture 346 may be extracted from the combustor 310 after it has been burned and used to drive the expander turbine 322. For example, the gas mixture 346 may be extracted from the expander turbine 322 at about 2241 kilopascals (kPa) and 427° C. The gas mixture 346 is then cooled using a purge cooler 348 and, optionally, used to generate steam 332 within the HRSG 304.

After the gas mixture 346 has been cooled within the purge cooler 348, the gas mixture 346 is flowed into a CO₂ separation system 350. Within the CO₂ separation system 350, the gas mixture 346 undergoes a CO₂ separation process in which the CO₂ is separated from the N₂, H₂O, and other gaseous components within the gas mixture 346. The CO₂ separation process may include an amine separation process, potassium carbonate separation process, or any other suitable type of separation process. The CO₂ separation process yields a low pressure CO₂ stream 352 and a nitrogen stream 354 at about 2206 kPa and 49° C. The nitrogen stream 354 includes mostly N₂, along with H₂O and other trace components, such as argon.

From the CO₂ separation system 350, the nitrogen stream 354 is fed into an N₂ dehydration system 356. Within the N₂ dehydration system 356, the nitrogen stream 354 is dehydrated to remove the H₂O 358. In various embodiments, the nitrogen stream 354 is dehydrated such that there is a very low amount of H₂O 358 remaining in the nitrogen stream 354 to avoid the formation of water ice or frost in the later refrigeration system.

The nitrogen stream 354 is then flowed through a first heat exchanger 360. Within the first heat exchanger 360, the nitrogen stream 354 is pre-chilled to about −54° C., for example, by indirect heat exchange with a nitrogen vent stream 362. The chilled nitrogen stream 361 is flowed through a cryogenic nitrogen expander 364, which reduces the pressure and temperature of the nitrogen stream to form a cryogenic nitrogen stream 374 at about 138 kPa and 163° C., for example, and generates about 28 MW of shaft power that may be used to drive a generator or other mechanical device.

The cryogenic nitrogen stream 374 is flowed through a second heat exchanger 380. Within the second heat exchanger 380, the natural gas stream 370 is de-superheated, condensed, and sub-cooled, producing liquefied natural gas (LNG) stream 372. The second heat exchanger 380 may be referred to as a cold box and may include one or more heat exchangers arranged in series and/or in parallel to optimize the heat transfer from the natural gas stream 370 to the cryogenic nitrogen stream 374.

The nitrogen stream 382 exiting the second heat exchanger 380 is returned to the first heat exchanger 360 to pre-chill the incoming nitrogen stream 354. Upon exiting the first heat exchanger 360, the nitrogen stream 382 is flowed out of the system 300 as the nitrogen vent stream 362.

In various embodiments, the natural gas stream 370 includes mostly methane and is received at about 6895 kPa and 49° C. The natural gas stream 370 may be pre-chilled, condensed, and sub-cooled to about −158° C. in the second heat exchanger 380. The LNG 372 exiting the second heat exchanger 380 may then be flashed to near ambient pressure prior to storage in tankage. In some embodiments, the gas that is flashed off the LNG 372 may be used as a portion of the fuel gas 308 for the gas turbine generator 302.

The process flow diagram of FIG. 3 is not intended to indicate that the system 300 is to include all of the components shown in FIG. 3. Moreover, the system 300 may include any number of additional components not shown in FIG. 3, depending on the details of the specific implementation.

Table 1 lists the properties of the streams flowing through various components of the system 300 of FIG. 3. However, it is to be understood that the streams flowing through the components of the system 300 of FIG. 3 are not limited to the properties shown in Table 1. Rather, the properties shown in Table 1 merely represent one exemplary embodiment of the operation of the system 300 of FIG. 3.

TABLE 1
Properties of Streams Flowing through Various Components of FIG. 3.
	Component Number
	354	361	374	364	382	362	370	372
Phase	Vapor	Vapor	Vapor		Vapor	Vapor	Vapor	Liquid
Mole flow rate (kmol/sec)	9.47	9.47	9.47		9.47	9.47	2.02	2.02
Temperature (deg C.)	48.9	−53.8	−163.4		−60.9	46.1	48.9	−157.9
Pressure (kPa)	2206	2137	138		121	103	6895	6826
External Power Added				−28.3
(MW)
External Heat Added
(MW)
Composition (mole
fraction)
Water	0.000	0.000	0.000	0.000	0.000	0.000	0.000	0.000
Nitrogen	0.988	0.988	0.988	0.000	0.988	0.988	0.000	0.000
CO2	0.000	0.000	0.000	0.000	0.000	0.000	0.000	0.000
Argon	0.012	0.012	0.012	0.000	0.012	0.012	0.000	0.000
Carbon Monoxide	0.000	0.000	0.000	0.000	0.000	0.000	0.000	0.000
Methane	0.000	0.000	0.000	0.000	0.000	0.000	1.000	1.000
Total	1.000	1.000	1.000	0.000	1.000	1.000	0.000	0.000

FIG. 4 is a process flow diagram of another system 400 for integrating low emissions power generation with LNG production. Like numbered items are as described with respect to FIG. 3. The system 400 of FIG. 4 is similar to the system 300 of FIG. 3. However, there are several significant differences between the two systems 300 and 400. Specifically, according to the system 300 of FIG. 3, the gas mixture 346 is treated to remove most of the CO₂ 352 and the H₂O 358. In contrast, according to the system 400 of FIG. 4, the CO₂ may be removed to only about 1% by volume of the gas mixture 346, and dehydration of the gas mixture 346 may be performed using routine methods. Thus, the system 400 of FIG. 4 may be capable of producing about 50% more LNG 372 than the system 300 of FIG. 3 at the cost of less power generation.

As shown in FIG. 4, the gas mixture 346 extracted from the combined cycle power plant is cooled within the purge cooler 348. From the purge cooler 348, the gas mixture 346 is passed through a first heat exchanger 402. Within the first heat exchanger 402, the gas mixture 346 is used to heat a portion 404 of the nitrogen stream 354 exiting the CO₂ separation system 350.

The nitrogen stream 354 is then flowed through the N₂ dehydration system 356. Within the CO₂ separation system 350, the CO₂ 352 is removed from the gas mixture 346 via an amine separation process, potassium carbonate separation process, or any other suitable type of separation process. The resulting nitrogen stream 354 exiting the CO₂ separation system 350 may be at about 2206 kPa and about 49° C.

The nitrogen stream 354 is flowed into the N₂ dehydration system 356. Within the N₂ dehydration system 356, the nitrogen stream 354 is dehydrated via a conventional dehydration process using triethylene glycol (TEG) or the like. Following dehydration, the portion 404 of the nitrogen stream 354 is heated to about 149° C. within the first heat exchanger 402. The portion 404 of the nitrogen stream 354 is then passed to a first expander 406, which reduces the pressure and temperature of the chilled nitrogen stream 407 to about 138 kPa and −59° C. The chilled nitrogen stream 407 then exchanges heat in a second heat exchanger 408 to pre-chill a recirculated high pressure nitrogen refrigerant stream 410. Following the second heat exchanger 408, the nitrogen stream 407 is vented to the atmosphere as the nitrogen vent stream 362 at about 103 kPa and 35° C.

The recirculated high pressure nitrogen refrigerant stream 410 is flowed out of the second heat exchanger 408 at about 10170 kPa and −51° C. The nitrogen refrigerant stream 411 is then flowed into a second expander 412, which reduces the pressure and temperature of the nitrogen refrigerant stream 411 to about 689 kPa and −166° C. The resulting low pressure cryogenic nitrogen refrigerant stream 414 is passed to a cold box 416. Within the cold box 416, the nitrogen refrigerant stream 414 exchanges heat with the natural gas stream 370, producing the LNG 372.

From the third heat exchanger 416, the resulting warm nitrogen refrigerant stream 418 is flowed into a compressor 420. The compressor 420 compresses the nitrogen refrigerant stream 418 and then passes it back to the second heat exchanger 408 at about 10239 kPa and about 49° C.

In various embodiments, the compressor is coupled to the first expander 406 and the second expander 412 via a shaft 422, and the mechanical energy provided by the spinning of the shaft 422 via the expanders 406 and 412 is used to drive the compressor 412. In some embodiments, gear boxes are positioned between the compressor 412, the first expander 406, and the second expander 412. Such gear boxes may be used to adjust for differing shaft speeds, split the expanders 406 and 412 to individually drive different compressor casings, or add additional drivers, e.g., motors, steam turbines, expander turbines, or the like. In addition, generators may be used to electrically couple the machinery, simplifying the balance of power among the individual machines.

In various embodiments, the nitrogen refrigerant stream 418 is produced from a portion 424 of the nitrogen stream 354 exiting the N₂ dehydration system 356. The portion 424 of the nitrogen stream 354 is flowed into an H₂O and CO₂ removal system 426. Within the H₂O and CO₂ removal system 426, the portion 424 of the nitrogen stream 354 is processed to remove the CO₂ and water vapor to a very low level. This may be accomplished using, for example, a methanol extraction process and a molecular sieve water removal process. However, other techniques known to those skilled in the art may also be used for this purpose.

According to the embodiment shown in FIG. 4, the natural gas stream 370 may be received at about 6895 kPa and about 49° C. The natural gas stream 370 may or may not be pre-chilled prior to being flowed into the third heat exchanger 416, depending on the details of the specific implementation. The resulting LNG 372 may exit the third heat exchanger 416 at about 6826 kPa and −155° C., and at a rate of about 1.34 MTonnes/year, e.g., 8000 hours per year. In some embodiments, about 3.6% of the LNG 372 is flashed off in order to bring the LNG 372 to near ambient pressure for storage. The gas that flashes off may be recompressed and used as the fuel gas 308 for the expander turbine 322.

The process flow diagram of FIG. 4 is not intended to indicate that the system 400 is to include all of the components shown in FIG. 4. Moreover, the system 400 may include any number of additional components not shown in FIG. 4, depending on the details of the specific implementation. For example, in some embodiments, the refrigeration loop including the second and third heat exchangers 408 and 416 has a very high operating pressure, e.g., about 31026 kPa.

In some embodiments, auxiliary drivers may be added to the system 400 to increase the power available for the refrigeration system. In addition, one or more supplementary refrigeration loops using nitrogen refrigerants or other refrigerants known to those skilled in the art may be added to the system 400 or to increase the amount of LNG 372 that may be produced by the system 400.

Furthermore, in some embodiments, argon is also removed from the nitrogen stream 354 to provide a substantially pure nitrogen refrigerant stream. The removed argon may then be used as a refrigerant within an additional refrigeration system, for example.

In various embodiments, the temperature of the nitrogen stream 354 exiting the first heat exchanger 402 is adjusted in a range above and below 149° C. Increasing this temperature may increase the amount of power produced by the first expander 406, as well as increase the temperature of the expander effluent that is used to chill the high pressure nitrogen refrigerant stream 410 in the second heat exchanger 408. If an additional refrigeration system is used to further cool the high pressure nitrogen refrigerant stream 410 exiting the second heat exchanger 408, the amount of LNG 372 produced by the system 400 may also be increased.

Tables 2A and 2B list the properties of the streams flowing through various components of the system 400 of FIG. 4. However, it is to be understood that the streams flowing through the components of the system 400 of FIG. 4 are not limited to the properties shown in Tables 2A and 2B. Rather, the properties shown in Tables 2A and 2B merely represent one exemplary embodiment of the operation of the system 400 of FIG. 4.

TABLE 2A
Properties of Streams Flowing through Various Components of FIG. 4.
	Component Number
	404	407	406	362	410	411
Phase	Vapor	Vapor		Vapor	Vapor	Vapor
Mole flow rate	9.47	9.47		9.47	7.39	7.39
(kmol/sec)
Temperature (deg C.)	148.9	−58.9		35.0	48.9	−50.5
Pressure (kPa)	2172	138		103	10239	10170
External Power Added			−57.0
(MW)
External Heat Added
(MW)
Composition (mole
fraction)
Water	0.000	0.000	0.000	0.000	0.000	0.000
Nitrogen	0.979	0.979	0.000	0.979	0.988	0.988
CO2	0.010	0.010	0.000	0.010	0.000	0.000
Argon	0.012	0.012	0.000	0.012	0.012	0.012
Carbon Monoxide	0.000	0.000	0.000	0.000	0.000	0.000
Methane	0.000	0.000	0.000	0.000	0.000	0.000
Total	1.000	1.000	0.000	1.000	1.000	1.000

TABLE 2B
Properties of Streams Flowing through Various Components of FIG. 4.
	Component Number
	412	414	418	420	370	372
Phase		Vapor	Vapor		Vapor	Liquid
Mole flow rate		7.39	7.39		2.90	2.90
(kmol/sec)
Temperature (deg C.)		−165.9	13.2		48.9	−154.8
Pressure (kPa)		689	669		6826	6757
External Power Added	−19.2			75.4
(MW)
External Heat Added				−70.9
(MW)
Composition (mole
fraction)
Water	0.000	0.000	0.000	0.000	0.000	0.000
Nitrogen	0.000	0.988	0.988	0.000	0.000	0.000
CO2	0.000	0.000	0.000	0.000	0.000	0.000
Argon	0.000	0.012	0.012	0.000	0.000	0.000
Carbon Monoxide	0.000	0.000	0.000	0.000	0.000	0.000
Methane	0.000	0.000	0.000	0.000	1.000	1.000
Total	0.000	1.000	1.000	0.000	0.000	0.000

FIG. 5 is a process flow diagram of another system 500 for integrating low emissions power generation with LNG production. Like numbered items are as described with respect to FIGS. 3 and 4. The system of FIG. 5 is similar to the systems 300 and 400 of FIGS. 3 and 4. However, in contrast to the systems 300 and 400 of FIGS. 3 and 4, the system 500 of FIG. 5 does not include the CO₂ separation system 350.

As shown in FIG. 5, the gas mixture 346 extracted from the combined cycle power plant is cooled within the purge cooler 348. From the purge cooler 348, the gas mixture 346 is passed through the first heat exchanger 402. The gas mixture 346 is then flowed into a dehydration system 502. Within the dehydration system 502, the gas mixture 346 is dehydrated via a conventional dehydration process using TEG or the like.

A portion 504 of the resulting dehydrated gas mixture 506 is passed through the first heat exchanger 402. Within the first heat exchanger 402, the portion 504 of the dehydrated gas mixture 506 is heated using the gas mixture 346 exiting the purge cooler 348.

The dehydrated gas mixture 506 is then passed to the first expander 406, which reduces the pressure and temperature of the dehydrated gas mixture 506 to about 138 kPa and −62° C. The chilled gas mixture 507 then exchanges heat in the second heat exchanger 408 to pre-chill the recirculated high pressure nitrogen refrigerant stream 410. Following the second heat exchanger 408, the gas mixture 506 is vented to the atmosphere as the nitrogen vent stream 362 at about 103 kPa and 31° C.

The recirculated high pressure nitrogen refrigerant stream 410 exits the second heat exchanger 408 at about 10170 kPa and −54° C. The nitrogen refrigerant stream 411 then enters the second expander 412, which reduces the pressure and temperature of the nitrogen refrigerant stream 411 to about 689 kPa and −168° C. The resulting low pressure cryogenic nitrogen refrigerant stream 414 then passes to a third heat exchanger, or cold box, 416. Within the third heat exchanger 416, the nitrogen refrigerant stream 414 exchanges heat with the natural gas stream 370, producing the LNG 372.

From the third heat exchanger 416, the resulting warm nitrogen refrigerant stream 418 flows into the compressor 420. The compressor 420 compresses the nitrogen refrigerant stream 418 and then passes it back to the second heat exchanger 408 at about 10239 kPa and 49° C.

In various embodiments, the nitrogen refrigerant stream 418 is produced from a remaining portion 508 of the dehydrated gas mixture 506 exiting the dehydration system 502. The remaining portion 508 of the dehydrated gas mixture 506 is flowed into the H₂O and CO₂ removal system 426. Within the H₂O and CO₂ removal system 426, the portion 508 of the dehydrated gas mixture 506 is processed to remove the CO₂ and water vapor to a very low level. This may be accomplished using, for example, a methanol extraction process and a molecular sieve water removal process. However, other techniques known to those skilled in the art may also be used for this purpose.

According to the embodiment shown in FIG. 5, the natural gas stream 370 may be received at about 6895 kPa and 49° C. The natural gas stream 370 may or may not be pre-chilled prior to being flowed into the third heat exchanger 416, depending on the details of the specific implementation. The resulting LNG 372 may exit the third heat exchanger 416 at about 6826 kPa and −157° C., and at a rate of about 1.46 MTonnes/year, e.g., 8000 hours per year. In some embodiments, about 2.4% of the LNG 372 is flashed off in order to bring the LNG 372 to near ambient pressure for storage. The gas that flashes off may be recompressed and used as the fuel gas 308 for the expander turbine 322.

The process flow diagram of FIG. 5 is not intended to indicate that the system 500 is to include all of the components shown in FIG. 5. Moreover, the system 500 may include any number of additional components not shown in FIG. 5, depending on the details of the specific implementation. For example, as discussed with respect to FIG. 4, the refrigeration loop including the second and third heat exchangers 408 and 416 may have a very high operating pressure, e.g., about 31,026 kPa.

Tables 3A and 3B list the properties of the streams flowing through various components of the system 500 of FIG. 5. However, it is to be understood that the streams flowing through the components of the system 500 of FIG. 5 are not limited to the properties shown in Tables 3A and 3B. Rather, the properties shown in Tables 3A and 3B merely represent one exemplary embodiment of the operation of the system 500 of FIG. 5.

TABLE 3A
Properties of Streams Flowing through Various Components of FIG. 5.
	Component Number
	506	507	406	362	410	411
Phase	Vapor	Vapor		Vapor	Vapor	Vapor
Mole flow rate	10.74	10.74		10.74	8.19	8.19
(kmol/sec)
Temperature (deg C.)	135.0	−62.3		30.8	48.9	−53.9
Pressure (kPa)	2172	138		103	10239	10170
External Power			−63.0
Added (MW)
External Heat
Added (MW)
Composition (mole
fraction)
Water	0.000	0.000		0.000	0.000	0.000
Nitrogen	0.870	0.870		0.870	0.988	0.988
CO2	0.119	0.119		0.119	0.000	0.000
Argon	0.010	0.010		0.010	0.012	0.012
Carbon Monoxide	0.001	0.001		0.001	0.000	0.000
Methane	0.000	0.000		0.000	0.000	0.000
Total	1.000	1.000		1.000	1.000	1.000

TABLE 3B
Properties of Streams Flowing through Various Components of FIG. 5.
	Component Number
	412	414	418	420	370	372
Phase		Vapor	Vapor		Vapor	Liquid
Mole flow rate		8.19	8.19		3.15	3.15
(kmol/sec)
Temperature (deg C.)		−167.8	8.4		48.9	−156.7
Pressure (kPa)		689	669		6826	6757
External Power	−20.7			82.9
Added (MW)
External Heat Added				−76.8
(MW)
Composition (mole
fraction)
Water		0.000	0.000		0.000	0.000
Nitrogen		0.988	0.988		0.000	0.000
CO2		0.000	0.000		0.000	0.000
Argon		0.012	0.012		0.000	0.000
Carbon Monoxide		0.000	0.000		0.000	0.000
Methane		0.000	0.000		1.000	1.000
Total		1.000	1.000		0.000	0.000

Method for Power Generation and LNG Production

FIG. 6 is a process flow diagram of a method 600 for power generation and LNG production. The method 600 may be implemented by any of the systems 100-500 described with respect to FIGS. 1-5. Moreover, the method 600 may be implemented by any variation of the systems 100-500 described with respect to FIGS. 1-5, or any suitable alternative system that is capable of integrating power generation with LNG production.

The method 600 begins at block 602, at which power is produced via a power plant. An exhaust gas from the power plant provides a gas mixture including nitrogen and carbon dioxide. The gas mixture may also include argon and any number of other trace gases.

In various embodiments, producing power via the power plant includes providing mechanical energy via an expander turbine of a gas turbine engine using energy extracted from the gas mixture after combustion of the gas mixture in a combustor and generating electricity via a generator using the mechanical energy provided by the expander turbine. Further, in various embodiments, producing power via the power plant also includes generating steam via a HRSG by heating a boiler with an exhaust stream from the expander turbine, providing mechanical energy via a steam turbine using energy extracted from the steam generated by the HRSG, and generating electricity via a generator using the mechanical energy provided by the steam turbine. In some embodiments, one common generator is used to generate electricity from the mechanical energy provided by the expander turbine and the steam turbine, while, in other embodiments, separate generators are used.

At block 604, a nitrogen refrigerant stream is generated from the gas mixture. Generating the nitrogen refrigerant stream may include cooling the gas mixture using a purge cooler as the gas mixture exits the combustor, for example, and dehydrating the gas mixture within a dehydration system. In various embodiments, generating the nitrogen refrigerant stream also includes separating the carbon dioxide from the gas mixture within a carbon dioxide separation system.

At block 606, LNG is produced from a natural gas stream using the nitrogen refrigerant stream. More specifically, the LNG may be produced from the natural gas stream by cooling the natural gas stream via heat exchange with the nitrogen refrigerant stream. This may be accomplished using a refrigeration system. In some embodiments, the refrigeration system includes a number of heat exchangers configured to chill the natural gas stream to produce the LNG via indirect heat exchange with the nitrogen refrigerant stream.

In other embodiments, the refrigeration system includes a nitrogen refrigeration loop. The nitrogen refrigeration loop may include a first heat exchanger configured to cool the nitrogen refrigerant stream and an expander configured to reduce a temperature and a pressure of the nitrogen refrigerant stream. The nitrogen refrigeration loop may also include a second heat exchanger configured to produce the LNG via indirect heat exchange between the nitrogen refrigerant stream and the natural gas stream and a compressor configured to compress the nitrogen refrigerant stream and pass the nitrogen refrigerant stream back to the first heat exchanger. According to such embodiments, a portion of the nitrogen refrigerant stream from the dehydration system may be used as the nitrogen refrigerant stream for the nitrogen refrigeration loop, and a remaining portion of the nitrogen refrigerant stream from the dehydration system may be used to cool the portion of the nitrogen refrigerant stream in the first heat exchanger.

The process flow diagram of FIG. 6 is not intended to indicate that the steps of the method 600 are to be executed in any particular order, or that all of the steps of the method 600 are to be included in every case. Further, any number of additional steps may be included within the method 600, depending on the details of the specific implementation.

Claims

1. A system for generating power and producing liquefied natural gas (LNG), comprising: a power plant configured to generate power, wherein an exhaust gas from the power plant provides a gas mixture comprising nitrogen and carbon dioxide;a dehydration system configured to dehydrate the gas mixture to generate a nitrogen refrigerant stream; anda refrigeration system configured to produce LNG from a natural gas stream using the nitrogen refrigerant stream.

2. The system of claim 1, comprising a carbon dioxide separation system configured to separate the carbon dioxide from the gas mixture.

3. The system of claim 2, wherein the carbon dioxide separation system separates the carbon dioxide from the gas mixture via an amine separation process.

4. The system of claim 2, wherein the carbon dioxide separation system separates the carbon dioxide from the gas mixture via a potassium carbonate separation process.

5. The system of claim 1, wherein the power plant comprises: an expander turbine configured to provide mechanical energy by extracting energy from the gas mixture after combustion of the gas mixture in a combustor; anda generator configured to generate electricity from the mechanical energy provided by the expander turbine.

6. The system of claim 1, wherein the power plant comprises a combined cycle power plant.

7. The system of claim 6, wherein the combined cycle power plant comprises: an expander turbine configured to provide mechanical energy by extracting energy from the gas mixture after combustion of the gas mixture in a combustor;a heat recovery steam generator (HRSG) configured to generate steam by heating a boiler with an exhaust stream from the expander turbine;a steam turbine configured to provide mechanical energy by extracting energy from the steam generated by the HRSG; anda generator configured to generate electricity from the mechanical energy provided by the expander turbine and the steam turbine.

8. The system of claim 6, wherein the combined cycle power plant comprises: an expander turbine configured to provide mechanical energy by extracting energy from the gas mixture after combustion of the gas mixture in a combustor;a first generator configured to generate electricity from the mechanical energy provided by the expander turbine;a heat recovery steam generator (HRSG) configured to generate steam by heating a boiler with an exhaust stream from the expander turbine;a steam turbine configured to provide mechanical energy by extracting energy from the steam generated by the HRSG; anda second generator configured to generate electricity from the mechanical energy provided by the steam turbine.

9. The system of claim 1, wherein a portion of the gas mixture is recycled to the power plant.

10. The system of claim 1, wherein the refrigeration system comprises a plurality of heat exchangers configured to chill the natural gas stream to produce the LNG via indirect heat exchange with the nitrogen refrigerant stream.

11. The system of claim 1, wherein the refrigeration system comprises a nitrogen refrigeration loop.

12. The system of claim 11, wherein the nitrogen refrigeration loop comprises: a first heat exchanger configured to cool the nitrogen refrigerant stream;an expander configured to reduce a temperature and a pressure of the nitrogen refrigerant stream;a second heat exchanger configured to produce the LNG via indirect heat exchange between the nitrogen refrigerant stream and the natural gas stream; anda compressor configured to compress the nitrogen refrigerant stream and pass the nitrogen refrigerant stream back to the first heat exchanger.

13. The system of claim 12, wherein a first portion of the nitrogen refrigerant stream from the dehydration system is used as the nitrogen refrigerant stream for the nitrogen refrigeration loop, and wherein a second portion of the nitrogen refrigerant stream from the dehydration system is used to cool the first portion of the nitrogen refrigerant stream in the first heat exchanger.

14. The system of claim 13, wherein the first portion of the nitrogen refrigerant stream is flowed from the dehydration system to a water and carbon dioxide removal system prior to being flowed to the nitrogen refrigeration loop.

15. The system of claim 13, wherein the second portion of the nitrogen refrigerant stream is flowed from the dehydration system to a third heat exchanger and a second expander prior to being flowed to the first heat exchanger.

16. The system of claim 1, wherein the power plant is configured to operate at a substantially stoichiometrically balanced condition, and wherein at least a portion of the exhaust gas is recirculated to the power plant.

17. A method for generating power and producing liquefied natural gas (LNG), comprising: producing power via a power plant, wherein an exhaust gas from the power plant provides a gas mixture comprising nitrogen and carbon dioxide;generating a nitrogen refrigerant stream from the gas mixture; andproducing LNG from a natural gas stream using the nitrogen refrigerant stream.

18. The method of claim 17, comprising generating the nitrogen refrigerant stream by dehydrating the gas mixture.

19. The method of claim 17, comprising generating the nitrogen refrigerant stream by removing the carbon dioxide from the gas mixture.

20. The method of claim 17, comprising generating the nitrogen refrigerant stream by removing argon from the gas mixture.

21. The method of claim 17, comprising generating the nitrogen refrigerant stream by cooling the gas mixture.

22. The method of claim 17, wherein producing the power via the power plant comprises: providing mechanical energy via an expander turbine using energy extracted from the gas mixture after combustion of the gas mixture in a combustor; and generating electricity via a generator using the mechanical energy provided by the expander turbine.

23. The method of claim 17, wherein producing the power via the power plant comprises: providing mechanical energy via an expander turbine using energy extracted from the gas mixture after combustion of the gas mixture in a combustor; generating steam via a heat recovery steam generator (HRSG) by heating a boiler with an exhaust stream from the expander turbine;providing mechanical energy via a steam turbine using energy extracted from the steam generated by the HRSG; andgenerating electricity via a generator using the mechanical energy provided by the expander turbine and the steam turbine.

24. The method of claim 17, comprising producing the LNG from the natural gas stream by cooling the natural gas stream via heat exchange with the nitrogen refrigerant stream.

25. A system for producing liquefied natural gas (LNG) using nitrogen recovered from a combined cycle power plant, comprising: an expander turbine configured to provide mechanical energy by extracting energy from a gas mixture exiting a combustor, wherein the gas mixture comprises nitrogen and carbon dioxide;a heat recovery steam generator (HRSG) configured to generate steam by heating a boiler with the gas mixture from the expander turbine;a steam turbine configured to provide mechanical energy by extracting energy from the steam generated by the HRSG;a generator configured to generate electricity from the mechanical energy provided by the expander turbine and the steam turbine;a dehydration system configured to dehydrate the gas mixture, generating a nitrogen refrigerant stream; anda refrigeration system configured to produce LNG from a natural gas stream using the nitrogen refrigerant stream.

26. The system of claim 25, comprising a carbon dioxide separation system configured to separate the carbon dioxide from the nitrogen refrigerant stream.

27. The system of claim 25, comprising a precooler configured to chill the gas mixture before dehydration of the gas mixture in the dehydration system.

28. The system of claim 25, wherein the refrigeration system comprises a plurality of heat exchangers configured to cool the natural gas stream to produce the LNG via indirect heat exchange with the nitrogen refrigerant stream.

29. The system of claim 25, wherein the refrigeration system comprises a nitrogen refrigeration loop configured to cool the natural gas stream to produce the LNG via indirect heat exchange with the nitrogen refrigerant stream as the nitrogen refrigerant stream circulates through the nitrogen refrigeration loop.

30. The system of claim 25, wherein the expander turbine is configured to operate at a substantially stoichiometrically balanced condition, and wherein at least a portion of the gas mixture is recirculated to the combustor.