巴西专利BR112014010651B1 power generation system and corresponding method

专利PDF首页>>巴西专利

专利附录

专利说明

权利要求

类似技术

同族专利

引用文献

法律状态

优先权

专利摘要:
ENERGY GENERATION METHOD AND SYSTEM. The present invention provides an integrated power generation system and method and a system and method for evaporating liquefied natural gas (LNG). More particularly, the heat of a CO2-containing stream (15) from the power generation system and the method can be used to heat (21) the LNG for regasification (44) as the CO2 from the CO2-containing stream is liquefied (55). The liquefied CO2 can be captured and / or recycled back to a combustor (1) in the energy generation system and method.
公开号:BR112014010651B1
申请号:R112014010651-7
申请日:2012-11-01
公开日:2021-02-09
发明作者:Rodney John Allam；Jeremy Eron Fetvedt
申请人:8 Rivers Capital, Llc；
IPC主号:

专利说明:

Field of the Invention
[001] The present invention relates to the integration of an energy production system with a liquefied natural gas regasification system. More particularly, the integrated system uses heat exchange to cool a recycling stream in the energy production system and to heat and gasify an LNG stream. Background
[002] Natural gas (ie, methane, predominantly) is often liquefied to facilitate storage and / or transportation and is regasified for end use, typically in an LNG gasification facility. Regasification generally requires pressurizing natural gas ("GN") to a required piping pressure - for example, about 1,000 psi (6.9 MPa). After pressurization, GN is typically still at or near cryogenic temperatures and therefore must be heated to raise the temperature to room temperature. This is often done with a heated water bath with a submerged combustion burner, which can use part of the NG at room temperature as fuel. Often, about 1 to 2% LNG in a regasification plant must be burned to warm LNG to room temperature after being pressurized, and this creates significant effects on efficiency, cost, fossil fuel consumption and emissions. CO2. It would be useful if you provide systems and methods for regasification that address these issues.
[003] Natural gas, coal and other carbonaceous fuels, are commonly used in energy production cycles, such as gas turbine combined cycle systems, supercritical pulverized coal systems, and others. Other energy production systems using natural gas, coal and other carbonaceous fuels as a fuel have also been used or proposed. The efficiency of energy production, however, is a limiting factor in the integration of new energy production technologies. Accordingly, it would be useful to provide systems and methods for energy production with improved efficiency. Summary of the Invention
[004] The present invention provides an integration of systems that can improve efficiencies and reduce costs in both systems. In particular, the invention provides for the integration of a power generation system and method with an LNG regasification system and method. The invention also provides for the integration of a CO2 transport process with an LNG transport process.
[005] The systems and methods for energy generation using predominantly CO2 in a closed combustion cycle are described in US patent publication No. 2011/0179799, the invention of which is incorporated herein by reference in its entirety, and in various modalities , one or more components or conditions of the power generation systems and methods described herein can be incorporated into the power generation systems and methods of the present invention. The combustion cycle can use a high pressure ratio turbine that expands a mixture of combustion products that are formed on combustion of a fuel in oxygen in the presence of a stream of CO2 working fluid (which is typically recycled - at least partly - through the closed system). In various embodiments, a CO2 cycle such as that described above can be used in the production of energy using NG, coal and other carbonaceous materials as a fuel source. The turbine's hot exhaust is used to partially preheat the recycled CO2 working fluid stream in an economy heat exchanger. The recycled CO2 working fluid stream can also be heated using a secondary heat source, such as the heat derived from the compression energy of an O2 production plant that is used to supply oxygen for combustion. Fuel and combustion-derived impurities (for example, sulfur compounds, CO2, H2O, ash, Hg, etc.) can be separated for disposal without any atmospheric emissions. The system can produce a high pressure CO2 recycling stream (is-soé, recycled as a working fluid) and a high pressure CO2 product stream (that is, excess CO2 that is not recycled into the combustor and which can be captured for use, such as improved oil recovery, or for sequestration). This can be achieved by compressing the turbine's cooled exhaust current from the economy heat exchanger in a multi-stage compression system.
[006] The present invention provides the ability to integrate a NG, coal or other carbonaceous materials fed with the CO2 cycle energy production system with LNG regasification so that the heat from one or more streams of the generation system CO2 energy sources can be used to heat compressed NG while simultaneously cooling one or more process currents in the CO2 energy cycle. In some modalities, the cooling of the compressed GN stream in the LNG gasification system may be sufficient to allow the elimination of one or more components of the CO2 cycle compression and to liquefy the gas recycling stream, against cryogenic LNG. The integration of the power generation system with the LNG gasification system can increase the efficiency of the CO2 cycle energy production process to more than 60%.
[007] In additional modalities, the integration of a LNG heating process with a CO2 compression step in a closed cycle power generation system and the process can be useful to reduce or eliminate the fuel consumption needed to heat LNG in a conventional regasification process. Additionally, the liquefaction of a rich CO2 turbine exhaust stream leaving the cold end of an economy heat exchanger following the separation of liquid water from the turbine exhaust stream can be performed simultaneously with the heating of a first LNG stream for a desired temperature, such as over 32 C (0 F). Thereafter, high-density liquid CO2 can be pumped to a pressure high enough to be recycled again for a combustion process as a CO2 working fluid, and this can be achieved with very significant energy savings compared to a procedure of normal gas compression. In additional embodiments, the natural gas from the heat exchanger used to liquefy CO2 can be heated to close to room temperature so that it can be distributed to a natural gas pipeline. For example, this can be accomplished by cooling a stream of cooling water to a desired temperature, such as about 0 C to about 10 C. This cold water can then be used in a closed-loop system to cool the air being compressed prior to delivery to a cryogenic oxygen plant in order to reduce the energy consumption of the air compressor. Additionally, the liquefied CO2 stream can be cooled to a temperature that is within about 10 C of the CO2 freezing temperature, and this can be useful in minimizing the liquid CO2 pump energy while maximizing the density of liquid CO2 . Beneficially, a portion of the heated natural gas that leaves the CO2 liquefying heat exchanger can be recycled and mixed with the cold, high-pressure LNG that is leaving the main LNG pumps to supply a natural gas fluid in a temperature between about 10 C above the CO2 freezing temperature. This mixed natural gas fluid can be used as the cooling medium in the CO2 liquefaction heat exchanger. In other embodiments, a LNG heater fired by parallel natural gas can be provided at the required operating temperature as a standby system that controls whether to switch instantly from the main power generation system to the LNG heater in the case of the generation system power is offline. Similarly, at least one additional primary LNG pump discharge at the required piping pressure can be provided so that if the LNG pump on line supplying the power generation system is switched off, the second pump can be started and meet the requirements LNG supply. In addition, a second LNG pump discharging with the required high pressure can be provided and can be used to supply a second stream of natural gas for use as fuel for the combustor in the power generation system. The cooling of this current can be recovered by heating it in the CO2 liquefaction heat exchanger in a circuit parallel to the first LNG circuit.
[008] In certain embodiments, the present invention can provide energy generation methods. For example, an energy generation method may comprise combustion of a carbonaceous fuel in a combustor in the presence of oxygen and CO2 to form the CO2 recycling stream and to produce a combined combustion production stream. The method may further comprise passing the combined combustion product stream through a turbine to generate energy and form a turbine exhaust stream comprising supercritical CO2 passing the turbine exhaust stream comprising supercritical CO2 through a first heat exchanger to converting supercritical CO2 into a stream comprising CO2 gas and passing the stream of CO2 gas through a second heat exchanger to form a stream of liquid CO2. The step of passing the stream of gaseous CO2 through the second heat exchanger may additionally comprise passing a stream of liquefied natural gas (LNG) through the second heat exchanger and thereby forming a stream of gaseous natural gas (NG). The method may further comprise pressurizing the liquid CO2 stream to form a recycling stream comprising supercritical CO2 and passing the recycling CO2 stream to the combustor. If desired, a fraction of the LNG can be used as fuel for the combustion, and a stream of LNG product can be supplied at temperatures and pressures suitable for entering a natural gas distribution pipe.
[009] In additional modalities, an energy generation method may comprise the following steps: burning a carbonaceous fuel in a combustor in the presence of oxygen and CO2 to form a CO2 recycling stream and to produce a combined combustion product stream ; passing the combined combustion product stream through a turbine to generate energy and forming the turbine exhaust stream comprising CO2; passing the turbine exhaust stream comprising CO2 through a first heat exchanger in order to transfer heat from the turbine exhaust stream to the CO2 recycling stream and forming a cooled turbine exhaust stream passing a stream of liquefied natural gas (LNG) and CO2 from the turbine exhaust stream cooled through a second heat exchanger in order to cool and liquefy the CO2 and in order to heat and evaporate the LNG to form a stream of liquefied CO2 and a stream of gaseous natural gas (GN); pressurize the liquefied CO2 stream to form the CO2 recycle stream; and pass the recycled CO2 stream to the combustor. The first heat exchanger can be characterized as a combustion product heat exchanger, and the second heat exchanger can be characterized as a CO2 liquefied heat exchanger.
[0010] The combustor can be any combustor suitable for combustion at the required temperature and pressure. A CO2 recycling stream passed to the combustion can be supplied at a pressure of about 150 bar (14 MPa) or greater, about 200 bar (20 MPa) or greater, about 250 bar (25 MPa) or greater, or about 300 bar (30 MPa) or greater. In other embodiments, the pressure can be from about 150 bar (15 MPa) to about 400 bar (40 MPa), from about 200 bar (20 MPa) to about 380 bar (38 MPa), or from about 250 bar (25 MPa) to about 350 bar (35 MPa). Combustion combustion can be carried out at a temperature, for example, of about 500 C or more, about 600 C or more, or about 700 C or more. In other embodiments, combustion can be carried out at a temperature of about 500 C to about 1600 C, about 550 C to about 1200 C, or about 600 C to about 1000 C. In other modalities, ranges of additional temperatures can be used, as otherwise described here.
[0011] The energy generation method can be characterized by the pressure ratio through the turbine. Specifically, the pressure ratio of the combined combustion product stream (entering the turbine) to the pressure of the turbine exhaust stream comprising CO2 (exiting the turbine) can be 12 or less, about 10 or less, or about 8 or less. In other embodiments, the pressure ratio can be about 4 to about 12, about 5 to about 10, or about 6 to about 10.
[0012] The combustion product heat exchanger through which the combined combustion product stream is directly passed can be a multistage heat exchanger or a series of two or more, preferably three, series heat exchangers. In such series, the first serial heat exchanger (moving from the hot to the cold end) can transfer heat across a wide, high temperature range - for example, from the turbine outlet temperature to the range of around 150 C at about 200 C. The second serial heat exchanger can transfer heat through a narrower intermediate temperature range - for example, from the outlet temperature of the first serial heat exchanger to the range of about 80 C at about 140 C. The third serial heat exchanger can transfer energy over a low temperature range - for example, the range of about 20 C to about 75 C. These ranges, likewise, can apply to past fluids from the cold end to the hot end of each heat exchanger in the series. Such series can be beneficial since the added heating of the CO2 recycling stream passing from the cold end of the serial heat exchangers to the hot end of the heat exchangers can be registered at a defined point. For example, the current leaving the third serial heat exchanger and entering the second serial heat exchanger can be divided, and a fraction can enter the second serial heat exchanger while the other fraction is heated from an external source, such as the compression heat captured from an air separation plant. The most heated fraction can then be joined with the current that exits the second serial heat exchanger and enters the first serial heat exchanger. Such added heat can be beneficial in bringing the temperature of the CO2 recycling stream to a preferable limit with respect to the temperature of the turbine exhaust stream. Specifically, the CO2 recycling stream can be heated to 50 C or less, 40 C or less, or 30 C or less from the temperature of the turbine exhaust stream.
[0013] The energy generation method can be further characterized by the nature of LNG which is processed in parallel with the combustion cycle. For example, stored LNG can often be at a pressure that is less than about 10 bar (1 MPa), less than about 5 bar (0.5 MPa), or less than about 1 bar (0.1 MPa) ). In this way, it can be beneficial that LNG passed into the second heat exchanger can be supplied at increased pressure. Specifically, LNG can be pumped at a pressure of about 30 bar (3 MPa) or more, about 40 bar (4 MPa) or more, about 50 bar (5 MPa) or more, or about 60 bar ( 6 MPa) or more. In other embodiments, LNG can be pumped to a pressure of about 50 bar (5 MPa) to about 90 bar (9 MPa), about 55 bar (5.5 MPa) to about 85 bar (8.5 MPa), or about 60 bar (6 MPa) to about 80 bar (8 MPa).
[0014] LNG can also typically be stored at a temperature that is below the CO2 freezing point at working pressures discussed here. Thus, it can be useful to increase the temperature of the LNG before passing the LNG through the second heat exchanger that removes the heat from the CO2 stream and liquefies the CO2 stream. In certain embodiments, this can be achieved through the use of a part of the heated Gaseous NG stream that is formed (and exists) in the second heat exchanger (the CO2 liquefaction heat exchanger). Specifically, a fraction of the gaseous LNG stream formed by the second heat exchanger can be removed and placed in the LNG stream that passes into the second heat exchanger, preferably immediately before the passage of the LNG stream into the second heat exchanger. The fraction of the gaseous LNG stream that enters the LNG stream may be an amount that is sufficient to raise the temperature of the LNG stream to a temperature that is above the CO2 solidification temperature. Preferably, it is sufficient to raise the temperature of the LNG stream to a temperature that is also within about 25 C, within about 20 C, within about 15 C, or within about 10 C of the solidification temperature of CO2.
[0015] The heat exchange in the second heat exchanger can also be characterized with respect to the temperature to which the CO2 stream is cooled. Specifically, the CO2 in the cooled turbine exhaust stream can be cooled (which can be referred to as being subcooled) and is within about 40 C, within about 30 C, or within about 20 C of temperature of CO2 solidification.
[0016] The liquefied CO2 stream can be beneficially pressurized to a pressure suitable for injection into the combustion like the CO2 recycling stream. Specifically, the step of pressurizing the CO2 recycling stream may comprise the passage of the CO2 recycling stream through a liquid pump. In some embodiments, the power generation turbine and the liquid pump can be arranged so that the power generation turbine produces the shaft energy that can be used to drive the liquid pump. The liquefied and presized CO2 stream exiting the liquid pump can be heated. In particular, the heating may comprise the passage of the pressurized CO2 recycling stream back through the second heat exchanger. In some embodiments, the CO2 recycling stream can be heated to a temperature of about -20 C or more, about -10 C or more, about 0 C or more, or about 10 C or more.
[0017] In addition to the first and second heat exchangers, one or more additional heat exchangers can be used to preserve the potential for heat exchange in one or more components of the power generation system. This potential for heat exchange can be applied to a variety of currents in the methods currently described.
[0018] In some embodiments, the carbonaceous fuel used in the combustor may comprise LN derived from the LNG stream. Other modalities of the method may use additional or different carbonaceous fuels including coal, biomass, and the like. In order to provide a GN stream for the combustion, the methods may comprise the passage of LNG through a first pump and a second pump to increase the pressure of the same, as for a pressure already described above. The LNG coming out of the second pump can then be heated, such as to a temperature of about 100 C or more, about 150 C or more, about 200 C or more, or about 250 C or more. Such heating can be achieved by passing LNG through the second heat exchanger in order to form a gaseous GN stream. If desired, the gaseous GN stream can be further heated by other means of gas exchange.
[0019] For example, heating the GN gas stream may comprise the use of compression heat from an air separation plant, specifically, a cryogenic air separation plant. Such an air separation plant can be integrated into the power generation system so that the oxygen formed in the air separation plant can be directly placed in the combustion in the power generation method. Additional means for using compression heat from an air separation plant are discussed below.
[0020] In certain embodiments, the energy generation method may comprise the passage of the turbine cooled exhaust current through a third heat exchanger after passing through the first heat exchanger and before passing through the second heat exchanger . The third heat exchanger can be a low temperature heat exchanger, and such a passage through the third heat exchanger can be efficient to provide an intermediate cooling of the turbine exhaust stream. The passage of the turbine exhaust current through the first heat exchanger significantly cools the turbine exhaust current over a relatively high temperature range - for example, from a temperature in the range of about 600 C to about 800 C (or an additional temperature close to the combustion temperature discussed here) to a temperature in the range of about 50 C to about 20 C. The cooled turbine exhaust current then receives the intermediate cooling in the third heat exchanger - for example , further cooling the turbine exhaust stream to a temperature of about -10 C to about 15 C, about -5 C to about 12 C, or about 0 C to about 10 C. This intermediate cooling can , thus, be carried out before the passage of the turbine exhaust stream through the second heat exchanger, which provides the subcooling and liquefaction of CO2 from the turbine exhaust stream. In the third heat exchanger, the turbine exhaust stream can be cooled against a fraction of the gaseous GN stream leaving the second heat exchanger.
[0021] After passing through the third heat exchanger and before passing through the second heat exchanger, the cooled turbine exhaust stream can pass through one or both of a liquid water separator and a desiccant dryer. With the water removed from the turbine exhaust stream, a purified CO2 stream from the cooled turbine exhaust stream can therefore be supplied as a dry CO2 stream. If desired (and depending on the combustion fuel used). one or more additional separators and / or filters can be included to remove additional contaminants from the turbine exhaust stream. Preferably, the CO2 stream from the turbine exhaust can enter the second heat exchanger having a CO2 purity of about 95% or more, about 97% or more, or about 99% or more. In some embodiments, the dry CO2 stream can be dried at a dew point of about -30 C or less, about -40 C or less, about -50 C or less, or about -60 C or less .
[0022] In certain embodiments, part of the recycling CO2 stream passing to the combustion can be heated using the compression heat from the air separation plant. Heat can be transferred to the recycling CO2 stream particularly over a temperature range of about 100 C to about 400 C.
[0023] The recycling CO2 stream passing to the particular combustor can be separated into a first fraction and a second fraction. The first fraction of the recycling CO2 stream passing to the combustion can enter the combustion directly. The second fraction of the recycle CO2 stream passing into the combustion can be combined with oxygen to form an oxidizing stream that enters the combustion, the oxidizing stream being able to be supplied for a variety of reasons. For example, the oxidizing stream can comprise about 20% to about 40% oxygen and about 60% to about 80% CO2 based on molar. In other embodiments, the oxidizing stream may comprise about 25% to about 35% oxygen and about 65% to about 75% CO2 based on molar.
[0024] The power generation methods of the present invention can be particularly characterized with respect to the overall efficiency of power generation. For example, power generation can be achieved with an overall efficiency at a lower heating value of at least 60%. In other modalities, the efficiency can be at least 65%.
[0025] In additional embodiments, the present invention can provide a variety of power generation systems. In certain embodiments, an energy generation system may comprise the following: a combustor adapted to burn a carbonaceous fuel in the presence of oxygen and a CO2 recycling stream to produce a combined combustion product stream; a power generation turbine in fluid communication with the combustion and adapted to receive a combined combustion product stream and send a turbine exhaust stream comprising CO2; a first heat exchanger in fluid communication with the energy generating turbine and the combustion and adapted to transfer heat from the turbine exhaust stream comprising CO2 to the CO2 recycling stream so as to provide a cooled turbine exhaust stream comprising CO2; a second heat exchanger in fluid communication with the first heat exchanger and adapted to liquefy CO2 at a pressure suitable for recycling to the combustor; and a source of liquefied natural gas (LNG) in fluid communication with the second heat exchanger. In additional embodiments, the system may additionally comprise a third heat exchanger positioned between and in fluid communication with the first heat exchanger and the second heat exchanger. The third heat exchanger may include a fluid communication input with an output on the first heat exchanger, an fluid communication input with an output on the second heat exchanger, and an fluid communication output with an input on the second heat exchanger. heat. A system according to the invention can also comprise one or more water removal devices positioned between the outlet of the third heat exchanger and the entrance to the second heat exchanger.
[0026] A power generation system as currently described can be configured so that the power generation turbine is adapted to supply shaft energy to a liquid pump. More specifically, the liquid pump can be positioned between and be in fluid communication with the LNG source and the second heat exchanger.
[0027] A power generation system as currently described can also comprise an air separation plant. More particularly, the air separation plant may be a cryogenic air separation plant comprising an adiabatic main compressor and an amplification compressor. The adiabatic main compressor can include two adiabatic stages.
[0028] In additional embodiments, a power generation system according to the present invention can comprise a combustion in which a carbonaceous or hydrocarbon fuel is combined with oxygen and mixed with a heated recycling stream comprising CO2 to produce a combined stream which is expanded into an energy producing turbine with the turbine exhaust heating the recycling stream in an economy heat exchanger and with a compressor compressing the cooled turbine exhaust leaving the economy heat exchanger to the desired recycling pressure . Such a system, in particular, can be characterized by one or more of the following:
[0029] The recycling compressor can be a liquid pump.
[0030] The turbine exhaust flow leaving the economy heat exchanger can be liquefied in a heat exchanger before entering the recycling liquid pump.
[0031] The heat removed from the turbine exhaust stream in the heat exchanger can be transferred to a stream of liquid natural gas that can be heated to a temperature defined by a temperature approximation of the CO2 liquefaction cooling temperature.
[0032] The liquid natural gas stream can be collected from the discharge of a high pressure LNG pump at a pressure consistent with the distribution of high pressure natural gas heated in a transport pipeline.
[0033] Part of the heated natural gas that leaves the hot end of the CO2 liquefying heat exchanger can be recycled and mixed with a pressurized LNG stream from the LNG pump to produce a stream of natural gas at a temperature of 10 C and above the CO2 solidification temperature and used to liquefy the CO2 stream in the CO2 liquefaction heat exchanger.
[0034] The liquefied CO2 stream can be subcooled to a temperature within 20 C of the CO2 solidification temperature.
[0035] The pressurized recycled liquid CO2 stream leaving the liquid CO2 pump can be heated in the CO2 liquefaction heat exchanger to a temperature above 0 C.
[0036] The natural gas fuel for the power system combustor can be collected from the discharge of a high pressure LNG pump and compressed to the pressure required for combustion in a second LNG pump.
[0037] The compressed liquid combustible gas for the power system combustor can be heated to a temperature above 200 C using heat from cooling, liquefaction and sub-cooling of at least part of the turbine exhaust from the dry power system plus the heat from compression of at least part of the air fed to the cryogenic oxygen plant that supplies oxygen to the combustion.
[0038] The cooled turbine exhaust current leaving the cold end of the economy heat exchanger can be additionally cooled to between 0 C and 10 C in a heat exchanger against part of the natural gas stream leaving the hot end of the heat exchanger CO2 liquefaction heat.
[0039] The turbine exhaust stream cooled to a temperature between 0 C and 10 C can be dried to a dew point below -50 C by a combination of a liquid water separator and a desiccant dryer.
[0040] A control system can allow quick switching of the pressurized LNG flow from the power supply to the integrated LNG and power generation system for a separately heated LNG heater without causing more than 2% fluctuation in the pressure of natural gas pipeline.
[0041] A control system can allow quick switching of pressurized LNG to the power generation system from one supply pump to another if the first pump fails to supply pressurized LNG without causing more than a 5% drop in pressure turbine entry into the power system.
[0042] Compressed air used as feed for the air separation plant can transfer heat from compression to part of the high pressure recycling CO2 from the power generation system over a temperature range of 100 C to 400 C .
[0043] The compressed air used as feed for the air separation plant can transfer heat from the compression to the product oxygen stream which is heated to a temperature of up to 300 C.
[0044] The compressed air used as feed for the air separation plant can transfer heat to the fuel gas stream of the high pressure energy system which is heated to a temperature of up to 300 C.
[0045] A closed-loop cooling fluid can be used in an additional heat exchanger to cool at least part of the air supply to the air separation plant and at least part of the heat transferred to cool the fluid can be used to heat at least part of the high pressure recycling CO2 leaving the warm end of the CO2 liquefaction heat exchanger.
[0046] A closed-loop cooling fluid can be used in an additional heat exchanger to cool at least part of the air supply to the air separation plant, and at least part of the heat transferred to cool the fluid is used to heat at least part of the high pressure fuel gas to the power system.
[0047] The systems and methods of the present invention are additionally beneficial since an excellent efficiency can be achieved simultaneously with carbon capture. Thus, the systems and methods described fulfill a need for energy generation with carbon capture and storage (CCS). While achieving CCS with conventional power generation systems has proven to be difficult and / or uneconomical, the methods currently described using closed-cycle combustion can achieve high efficiency and meet the needs of CCS, all while accomplishes this economically.
[0048] In other embodiments, the present invention provides improvements in the efficiency of LNG production and transportation, such as through the integration of a CO2 transport system and method with an LNG transport system and method. The integration of CO2 transport with LNG transport processes can result in a general improvement in transport efficiency, LNG production efficiency, transport energy consumption, and transport CO2 emissions. In particular, equipment used to transport or otherwise transport LNG from a NG production area to a NG distribution area can be used to transport CO2 from a CO2 production area to an NG production area. of CO2 consumption. While LNG containers are often transported empty back to a NG production area for refueling, the CO2 produced in the described energy generation system and method can be refilled in the LNG containers and transported back to the production area. of GN, where CO2 can be used for a variety of processes, such as improved oil and natural gas production, or can simply be sequestered. Thus, in addition to efficiency gains in relation to the integrated energy generation system and LNG evaporation system, the incorporation of CO2 transport from the areas of consumption of NG / areas of CO2 production to areas of production of NG / CO2 consumption areas add additional efficiency and savings that can be enjoyed by those skilled in the art and that provide useful economic benefits. Brief Invention of Figures
[0049] FIG. 1 illustrates a segment of an energy generation system integrated with a segment of an LNG evaporation system according to certain modalities of the invention and illustrates heat transfer where a stream of CO2 is liquefied and a stream of LNG is evaporated to form a NG stream;
[0050] FIG. 2 is a flow chart illustrating a known system and method for evaporating LNG to form NG for entry into a pipeline; and
[0051] FIG. 3 is a flow chart illustrating a system and method according to certain modalities of the present invention, where a power generation system and method are integrated with an LNG evaporation system and method. Detailed Invention of the Invention
[0052] The invention will now be described more fully by reference to various modalities. These modalities are provided in such a way that this invention is profound and complete, and fully carries the scope of the invention to those skilled in the art. In fact, the invention can be embodied in many different forms and should not be considered limited to the modalities presented here, instead, these modalities are provided in such a way that this invention satisfies the applicable legal requirements. As used in that specification, and in the appended claims, the forms in the singular "one", "one", "o" and "a" include several references unless the context clearly dictates otherwise.
[0053] U.S. Patent Publication No. 2011/0179799, as noted above, describes energy production systems and methods where a CO2 cycle is used. In some embodiments, a CO2 circulation fluid can be supplied in a combustor suitable for high temperature and high pressure conditions together with a carbonaceous fuel (such as NG, coal, syngas, biomass, etc.) and an oxidizer, such as like air or O2. Such systems and methods may comprise a combustion operating at high temperatures (for example, about 500 C or more, about 750 C or more, about 1000 C or more, or about 1200 C or more), and presence of circulating fluid can work to moderate the temperature of a fluid stream exiting the combustion so that the fluid stream can be used in the transfer of energy for energy production. The nature of the reaction process at high temperatures and pressures, and with high concentrations of recycling CO2, can provide excellent process efficiency and reaction speeds. The combustion product stream can be expanded through at least one turbine to generate energy. The expanded gas stream can then be cooled to remove combustion of by-products and / or impurities from the stream, and heat removal from the expanded gas stream can be used to heat the circulating CO2 fluid that is recycled back to the combustion.
[0054] In the cooled state, the combustion stream can be processed to remove water and other contaminants to provide an essentially pure CO2 stream to recycle back through the combustion with the combustion materials. The stream of purified CO2 is typically in a gaseous state, and it is beneficial to subject the stream to the necessary conditions so that the CO2 is in a supercritical state. For example, after the combustion stream has been expanded through a turbine for power generation, cooled, and purified to comprise essentially pure CO2 (for example, at least 95% by mass, at least 97% by mass, or at least 99% by mass of CO2), the resulting recycle CO2 stream can be compressed to increase the pressure, such as about 80 bar (8 MPa). A second compression step can be used to increase the pressure to approximately the pressure in the combustion - for example, about 200 bar (20 MPa), about 250 bar (25 MPa), or about 300 bar (30 MPa). Between the compression steps, the CO2 stream can be cooled to increase the density of the stream in order to reduce the energy input required to pump the stream to the highest pressure. The finally pressurized recycling CO2 stream can then be further heated and put back into the combustion. Although the power generation system described above and method provide increased efficiency over conventional energy generation systems and methods (and do so while simultaneously capturing the carbon produced), processing the recycling CO2 stream still requires an amount significant amount of energy to achieve the necessary compression discussed above. The energy input for compression, however, can be significantly reduced by integrating a regasification process for liquefied natural gas (LNG). By using the cooling capacity from the LNG regasification system, it is possible to liquefy CO2 at a reduced pressure (for example, about 30 bar) and, after that, increase the current pressure. In this way, the systems and methods of the present invention can use the refrigeration inherent in LNG to reduce the energy required for compression in the CO2 cycle and also reduce the energy required for LNG gasification.
[0055] In various embodiments of the present invention, a power generation system can be characterized as illustrated in FIG. 1. As noted here, a heat exchange ratio (the shaded rectangle) is used as the heat source for LNG in the regasification system and as a source of cooling the recycling CO2 stream in the power generation system, which can reduce or even eliminate the need for initial compression. In FIG. 1, a supply of LNG 210a is supplied at typical temperature - for example, about -247 F (-155 C), and has been pumped to a pressure of about 69 bar (6.9 MPa). The LNG supply (optionally intersecting with the supplementary power discussed below) is passed through a heat exchanger 221, and the resulting GN current 257 comes out at a temperature of about 15 F (-9.4 C) and a pressure that is substantially unchanged. The GN stream can be divided into a GN stream of product 258 and a supplementary GN stream 239. The GN stream of product can enter a pipeline or can otherwise be transported or used as a fuel source. The supplementary GN stream can be directed upstream of the heat exchanger and enters the LNG supply to provide supplemental heating of the LNG supply, if desired. The heated LNG supply 210b can then be the incoming LNG current to the heat exchanger. A blower 240 can be used to drive the supplementary NG stream.
The cooled and purified turbine exhaust current 255 can be a temperature and pressure, for example, of about 63 F (17.2 C) and 30 bar (3 MPa). The cooled and purified exhaust stream can be passed through the heat exchanger 221, and the recycled, subcooled CO2 stream from outlet 222 at a temperature of about -65 F (-53 C) and 30 bar (3 MPa) ) can be passed through a 205 pump. The high pressure recycle CO2 stream 223 can be at a temperature of about -45 F (-42 C) and a pressure of about 305 bar (30.5 bar) MPa). If desired, the high pressure recycle CO2 stream can again be passed through heat exchanger 221 (or a separate heat exchanger) to increase the temperature of the same - for example, to about 40 F (5 C). This heated recycle CO2 stream can then proceed through the power generation system, as described here, to recycle back into the combustor.
[0057] In additional modalities, one or more elements of a conventional LNG regasification system can be combined with an energy generation system, as described here. An example of a typical system used to convert LNG (for example, stored in a tank at about 0.05 bar to about 0.1 bar above atmospheric pressure), into natural gas ready for piping (for example, temperature almost and up to about 70 bar (7 MPa) pressure) is illustrated in FIG. two.
[0058] Generally, a conventional LNG regasification system uses a multi-stage centrifuged pump to pump LNG to a high pressure after which it is evaporated in a water bath heat exchanger that is heated by burning natural gas. In the example illustrated in FIG. 2, LNG is stored in a tank 100. LNG flows out of the base of the tank along the LNG 119 supply line and is pressurized at pump 101 to about 70 par (7 MPa). The pressurized LNG is discharged through line 118 and enters a water bath evaporator 102, which is maintained at a temperature of about 50 C to about 90 C by means of a burner 120 which is fed by a gas stream pressurized fuel 117 comprising a mixture of air supplied through the air line 109 and natural gas supplied through the fuel line of the GN burner 113. The burner 120 has an outlet tube that is submerged up to approximately 2 meters below the surface of the water in the water bath so that the combustion products must rise through and mix with the water, thereby heating the water. This arrangement results in the condensation of much of the water produced by the combustion of natural gas, thus increasing the efficiency of the heating system. The cooled flue gases are vented to the atmosphere along the ventilation line 121. The natural gas fuel is taken from the boiling line of the LNG tank 110 as a boiled current 112, which is compressed to the required burner pressure in a electrically driven boiler blower 105. The air through the atmospheric air line 107 required for combustion is purified through a filter 103, and is compressed to the burner pressure in the electrically driven burner pressure blower 104. The boiling current of remaining LNG tank 110 flows through the boiling compressor line 111 and is compressed to about 69 bar (6.9 MPa) in the boiling compressor 106 to provide a compressed boiled GN stream 114, which is mixed with the gas stream product 115 leaving the evaporator 102 to produce the total natural gas pipeline flow stream 116 at a pressure of about 69 bar (6.9 MPa) and a temperature of c about 15 C. The amount of natural gas consumed in the burner to convert LNG into pipeline gas is typically about 1.55% of the total natural gas flow in the 116 pipeline stream.
[0059] An energy generation system as noted here with respect to the system described in U.S. patent application 2011/0179799 can be particularly improved through the integration of the LNG regasification system. Such an integrated power generation system can use CO2 as a working fluid in a Brayton cycle power system that operates with an economy heat exchanger between a pressure recycling CO2 stream and a low turbine exhaust stream. pressure. In such a system, combustion of carbonaceous fuel can be carried out at a pressure of about 150 bar (15 MPa) to about 400 bar (40 MPa) and a pressure ratio of about 5 to about 12 or about 5 to about 10. The combustor where the fuel is burned in the presence of oxygen (preferably essentially pure oxygen) can be cooled by the high pressure and large recycling fluid flow, and the current entering the turbine can be a mixed flow of combustion products and recycling CO2 at a temperature of about 400 C to about 1800 C, about 600 C to about 1700 C, or about 800 C to about 1600 C. Such a system and method can provide a surprisingly high efficiency of a significant amount of heat input to the high pressure recycling CO2 stream, particularly in the temperature range of about 100 C to about 400 C. This external heat can be supplied, for example, to from the content of ca the amount of compressed air adiabatically fed to a cryogenic oxygen plant. The system, in this way, can produce a liquid CO2 product derived from the fuel at pipeline pressure - for example, about 200 bar (20 MPa) to about 400 bar (40 MPa). As an illustrative embodiment, the use of a natural gas fuel to produce a stream of combustion product with a turbine inlet temperature of about 1100 C to about 1200 C can provide net efficiency on a heating value basis (HV) in the range of about 55% to about 60%.
[0060] This can be further increased according to the present invention through integration with the LNG regasification system. It should be noted that the integration of a natural gas pipeline distribution system and LNG evaporation with a power generation system can apply to a variety of power generation systems, particularly those that incorporate a Brayton cycle using an exchanger of saving heat in which a compressor is used to pressurize a recycling of the working fluid which is then reheated in the saving heat exchanger. In various embodiments, the working fluid can be, for example, a gas rich in CO2 or N2.
[0061] A Brayton cycle saved using a power generation system as discussed above may require compression of approximately 30 times the molar flow of a natural gas fuel to a typical plant having a turbine with an inlet condition of around 300 bar (30 MPa) and about 1150 C and having an outlet pressure of about 30 bar (3 MPa). The compressor in this case has a suction temperature following the condensation and water separation of about 20 C. The energy required to compress the recycling CO2 stream and the liquid CO2 product stream into the 305 bar range (30, 5 MPa) is about 14.8% of the total output of the turbine energy. The CO2 compressor energy requirement can be reduced by liquefying the CO2 stream at a pressure of about 29 bar (2.9 MPa) and cooling the liquid CO2 to within about 10 C of its solidification temperature since this can maximize the density of the CO2 stream. After pressurization and liquefaction, the liquid CO2 stream can be pumped to a pressure of about 305 bar (30.5 MPa), and the high pressure CO2 can be heated up again to room temperature. This procedure can reduce the CO2 compression energy to about 5.3% of the total turbine energy output. In such an illustrative embodiment, the net cycle efficiency on an LHV basis can be increased from about 58.5% to about 65.7%.
[0062] The cooling required to achieve such increased efficiency in the energy generation system and method can be derived from any source that is recognized as being useful in view of the present invention. In reference to FIG. 2, the necessary refrigeration can be supplied to the system and method of power generation by exchanging heat from the heating of the high pressure LNG stream 118 leaving the pump 101.
[0063] In an illustrative embodiment, a low pressure CO2 stream from a power generation system can be dried, and the dry CO2 stream can then be liquefied and sub-cooled (for example, in a heat exchanger of high pressure, diffusion-joined stainless steel, such as a Heatric Heat Exchanger) against the LNG stream, which, in turn, receives heating. If necessary, in order to prevent the CO2 from freezing and block the passages of the heat exchanger, a fraction of the natural gas stream outlet 115 leaving the water bath evaporator 102 at a temperature of about -20 C at about 0 C can be recycled and mixed with the cold compressed LNG stream 118 (which is at a temperature of around -160 C) to produce a stream of natural gas that is within about 10 C above the freezing temperature of the CO2 stream. A stream of natural gas fuel entering a combustor in a power generation system as discussed above is preferably at a pressure noted above, for example, about 305 bar (30.5 MPa). If desired, natural gas can be derived from the LNG supply, and the natural fuel gas stream can be supplied using a second LNG pump taking its flow from line 118. The natural gas fuel stream can be be heated to room temperature first (for example) against cooling, liquefaction and sub-cooling of the CO2 stream. Second, the natural gas fuel stream can then flow through a second heat exchanger to cool a closed-loop cooling water stream, which can be used in the air compressor inter and post coolers at the gas plant. oxygen. This use of a cryogenic LNG pump instead of a natural gas compressor can increase efficiency by an additional 0.9% of the total turbine energy. The use of natural gas to liquefy and subcool the CO2 can impose a maximum temperature on the heated natural gas of about -10 C due to the narrowing of the temperature in the CO2 freezing temperature - that is, -56 C. Natural gas can be heated to about 15 C, which can be useful to distribute to a natural gas pipeline, by using it as a cooling current against the turbine exhaust stream leaving the cold end of the economy heat exchanger in the system power generation before liquid water separation. This can reduce the residual water content in the gas phase, which in turn reduces the size and cost of the desiccant dryer that may be required to prevent ice deposition in the CO2 liquefaction heat exchanger.
[0064] The integration of a power generation system as discussed above with an LNG evaporation system can preferably include all the necessary components to prevent interruptions in the generation of energy in addition to the flow of natural gas in the pipeline. For example, it may be beneficial for the LNG system to include an LNG heater system similar to that described in FIG. 2, preferably with the LNG heater 102 turned on and at or near the operating temperature to provide a quick switch to raise the LNG load being heated in the integrated power generation system if the power generation system is switched off. This can prevent any significant fluctuations in the piping supply pressure and keep that pressure within the required tolerance. Similarly, any failure of the pressurized LNG flow (such as, for example, a malfunction of pump 101) can be resolved. For example, in the example of a pump malfunction, the LNG flow can be immediately switched to a parallel LNG pump that can be present in an LNG emission facility. Preferably, such an exchange can be carried out in about 5 to 10 seconds to allow continuous operation of the power generation system.
[0065] An illustrative embodiment of a power generation system (using a pressurized natural gas fuel supply) integrated with a pressurized natural gas supply and LNG evaporation system is illustrated in FIG. 3. The discussion of FIG. 3 illustrates the system and method with respect to a specific modality, and certain values and ranges should not be considered limiting. Those skilled in the art after reviewing the following in view of the present invention will recognize that various values can be changed based on the specific operating conditions of the LNG power generation and evaporation system. The full scope of such ranges should be encompassed by this invention, which is illustrative in nature and provided to meet all requirements of the invention.
[0066] The power generation system comprises a combustion 1 that burns natural gas fuel with oxygen in the presence of a recycled CO2 working fluid to form a stream of combustion product 6 that is rich in CO2. In this example, the combustion product stream is at a pressure of about 300 bar (30 MPa) and a temperature of around 1150 C. The combustion product stream 6 enters a power turbine 2 by driving an electric generator. turbine 3 producing an electrical output 4 together with the additional shaft energy that is used to drive a liquid CO2 pump 5. A turbine discharge flow stream 15 at a temperature of around 788 C and a pressure of about 30 bar (3 MPa) is cooled in an e-conomy heat exchanger 46 to provide an initially cooled turbine discharge flow stream 16 to a temperature of about 25 ° C. The initially cooled turbine discharge stream 16 is additionally cooled in a low temperature heat exchanger 17 and comes out as the second turbine discharge stream cooled 51 at a temperature of about 4 C. This is achieved against a stream of cooling natural gas 56, which it is part of the total natural gas stream 57 leaving the CO2 liquefaction heat exchanger 21. The cooling natural gas stream 56 is heated in the low temperature heat exchanger 17 to provide a partial product natural gas stream 71 in a temperature of about 20 C, and this current joins the natural product pipeline stream 30 leaving the LNG facility (for example, at a temperature of around -10 C or more). The second cooled turbine discharge stream 51 passes into a liquid water separator 18, and a condensed water stream 19 is thereby removed from the second cooled turbine discharge stream 51. The Separate CO2 20 is dried to a dew point of about -60 C in a thermally regenerated desiccant dryer 54. Other water removal systems, such as pressure swing adsorption units (PSA) can also be used. The dry CO2 gas stream 55 is cooled for liquefaction, and the liquid CO2 is subcooled to about -50 C (for example, -56 C or more) in the CO2 liquefaction heat exchanger 21 (for example, a Heatric type heat exchanger joined by stainless steel diffusion), which simultaneously heats a stream of preheated LNG product 44 at a pressure of about 68.9 bar (6.89 MPa) to a temperature of around - 9.4 C to form the total natural gas stream 57. From the total natural gas stream 57 a fraction of LNG heating natural gas 39 is divided, which is compressed in an electrically driven blower 40. A gas stream natural heating of compressed LNG formed in this way 45 is mixed with the compressed LNG product stream 43, which is the main fraction of compressed LNG, to form the preheated LNG product stream 44, which enters the heat exchanger of CO2 liquefaction 21 at a temperature that is above the temperature CO2 freezing rate of -56 C (for example, for a temperature of -55 C or more). This arrangement with dry CO2 and heated LNG can be particularly useful in preventing CO2 freezing to block or damage the CO2 liquefaction heat exchanger 21.
[0067] In the present example, LNG is stored at a pressure of about 0.08 bar (0.8 MPa) in the LNG tank 33. A LNG tank discharge stream 50 is pumped to a pressure of about 70 bar (7 MPa) at the LNG pump 25 driven by an electric motor 34. An LNG discharge stream 26 can pass through a water bath heater 24 to supply a stream of natural gas heated by the bath 31 at a temperature of about 15 C. The water bath is heated by a fuel gas stream from the bath 27 which is burned in the air in a chain-tube burner with the flue gases passing through the water and discharging through a pile of bath 28. The flow of compressed LNG stream 32 can be controlled as desired. For example, the first control valve 29 and the second control valve 49 can be used to determine the direction of the LNG. These, in combination with a variety of additional pumps and water bath heaters in the LNG facility (not shown), can be used to switch the flow path of the LNG stream to ensure a continuous supply of LNG to the LNG generation system. energy if the LNG pump 25 is switched off and the continuous heating of all compressed LNG to piping conditions if the power generation system is switched off. Such security support provisions are further described here.
[0068] In the present example, the natural gas used as the fuel in combustor 1 of the power generation system can be removed from the compressed LNG stream as a fraction of LNG fuel 41 and pumped to a pressure of about 306 bar (30 , 6 MPa) in a LNG 48 fuel pump (for example, an electrically driven multi-cylinder powered pump). A high pressure LNG fuel stream 70 is heated to about -10 C in the CO2 liquefaction heat exchanger 21 and exits as a high pressure natural gas fuel stream 62. Such heating is against cooling, liquefying and sub-cooling the CO2. The high pressure natural gas fuel stream 62 is then heated in an air separation plant 47 to a temperature of about 230 C against the compressed air in an additive manner using a closed-loop heat transfer fluid, which can be beneficial in preventing flammable gas from leaking into the air separation plant. The heated high pressure natural gas stream from outlet 11 then proceeds to combustor 1. The cryogenic air separation plant may include a first stage adiabatic main compressor with a discharge pressure of about 4 bar (0, 4 MPa) and an amplification compressor where about one third of the first stage compressed air is compressed in two adiabatic stages by about 100 bar (10 MPa). The volume of the adiabatic compression heat is transferred first to a high pressure recycled CO2 side stream 13 taken from the high pressure CO2 recycling stream being heated in the economy heat exchanger 46. The side stream high pressure recycling CO2 can be removed at a temperature of around 110 C and returned as a side stream of superheated high pressure recycling CO2 12 at a temperature of around 149 C. The adiabatic heat of the two-stage compression adiabatic is used in second place to heat the high pressure natural gas fuel stream 62 to a temperature of about 230 C to form a heated high pressure natural gas fuel stream 63. Compression heat is used in third place to heat the stream of oxygen product 11 to a pressure of about 305 bar (30.5 MPa) from the air separation plant to a temperature of about d and 230 C.
[0069] Leaving the cold end of the CO2 liquefaction heat exchanger 21 there is a subcooled CO2 recycling stream 22. This stream is compressed to about 306 bar (30.6 MPa) in the liquid CO2 pump 5 , which can be coupled via a gearbox directly to the electric turbine generator 3. Alternatively, an amplification compressor (not shown) at the cryogenic air separation plant can be directly coupled to the electric turbine generator 3. As an alternative In addition, the main air compressor in the air separation plant can be directly coupled to the electric turbine generator. It is preferable that the turbine be charged directly with a demand for energy from one of these alternatives so that in the event of an electrical disconnection from the electrical installation (for example, resulting from a generator trip), there is a load on the generator that will function as a brake as the high pressure turbine feed gas will flow until the system pressures are equalized.
[0070] The pressurized sub-cooled CO2 recycling stream 23 at a temperature of about -43 C is then heated in the CO2 liquefaction heat exchanger 21 to a temperature of about 5.5 C. The CO2 stream high pressure recycler 68 is heated to a temperature of about 25 C in an additional CO2 heat exchanger 66 to form a preheated high pressure recycle CO2 stream 67. A heat transfer fluid stream from heated, closed loop 64 at a temperature of about 40 C is cooled to a temperature of about 10 C to exit as a cooled 65 heat transfer fluid stream. Similarly, a fraction of the total natural gas stream 38 at a temperature of about -9.4 C it can be passed through a secondary natural gas heat exchanger 35 to be heated against a second stream of closed-loop heat transfer fluid heated 36 to about 40 C. flu current secondary cooled heat transfer oxide 37 leaves at a temperature of about 10 ° C.
[0071] The preheated high pressure recycling CO2 stream 67 leaving the supplementary CO2 heat exchanger 66 is divided into a first fraction of high pressure recycling CO2 14 and a second fraction of high pressure recycling CO2 53, both passing through the economy heat exchanger 46 and exiting at a temperature of about 752 C. The recycled CO2 fraction control valve 52 at the cold end of the economy heat exchanger 46 controls the flow rate of the first fraction of CO2 14 for the second fraction of CO2 53. The stream of heated first fraction of CO2 7 is distributed to combustion 1 as the working fluid. The heated second fraction CO2 stream 9 mixes with the oxygen product stream 63 to provide a molar ratio of 30% oxygen and 70% CO2 in the oxidizing stream 10 entering combustion 1, which moderates the adiabatic flame temperature to a value below about 3000 C. The liquid CO2 product derived from the burned fuel is available as a pipeline-ready CO2 product stream 77 at a pressure of about 305 bar (30.5 MPa) and a temperature of about of 25 C.
[0072] Performance values based on a 250 MW net electrical output have been calculated for the integrated system illustrative above using pure methane from the LNG source as the fuel for the combustor. Calculated values were as follows:
[0073] natural gas flared in the NET energy system = 380.4 MW
[0074] = 34.269 mmscfd
[0075] natural gas heated in the NET energy system = 1095.9 mmscfd
[0076] saving natural gas for hot water bath = 16,986 mmscfd
[0077] Based on the above, modeling was used to calculate the efficiencies for a 1000 MW electric power generation system with an integrated LNG system as discussed above providing a natural gas flow rate of 1000 mmscfd at 68 bar (6.8 MPa) distributed for a 15 C pipe. The calculated overall efficiency was 68.06%. The overall efficiency calculated with a LNG flow rate equal to zero for the 1000 MW power plant was 58.87%. In an additional modality modeled using Aspen Plus, a system and method according to the present invention uses a methane fuel in the combustor, a turbine, a first heat exchanger (which has a series of three heat exchange units), a water separator, a second heat exchanger where CO2 has been liquefied against LNG to produce LNG (with a side chain being used to preheat LNG), a single pump to pressurize the recycling CO2 stream, and heat recovered from an air separation plant to supplement the heating of the recycling CO2 stream. In the model of such modality, the general efficiency of the integrated energy generation and LNG evaporation system and method was 65.7%. All of the efficiency calculations above encompass the complete capture of all excess CO2 from combustion.
[0078] The benefits are further observed with respect to conventional LNG regasification systems where, typically, about 1.4% of the LNG that is processed is burned to provide heating, as in the submerged burner described with reference to FIG. 2, for the rest of the 98.6% of LNG processed. This task is imposed without any additional benefit. According to the present invention, however, a 250 MWe power generation system, for example, can be integrated with an LNG regasification plant. In such an example, the LNG plant can reheat approximately 10.8 B m3 / year of LNG while burning approximately 3.1% to provide heat. Due to the integration, although the total gas emission is reduced to 96.9% of the total amount processed, the increased task supplies electricity generation at the 250 MW power plant. Beneficially, such systems can be scaled as desired to increase or decrease capacity with respect to processed LNG and / or produced electricity.
[0079] Many modifications and other modalities of the invention presented here will be remembered by those versed in the technique to which this invention belongs, having the benefit of the teachings presented in the invention above. It should be understood that the modalities described should not be considered limiting, and modifications and other modalities must be included in the scope of the attached claims. Although specific terms are used here, they are used in a generic and descriptive sense only and not for the purpose of limitation. Invention of Numerical References 1 combustor 2 energy turbine 3 electric turbine generator 4 electrical outlet 5 liquid CO2 pump 6 combustion product stream 7 first heated CO2 fraction stream 8 second heated CO2 fraction stream 9 oxidant stream 10 oxygen product stream 11 superheated high pressure recycle CO2 side stream 12 high pressure recycle CO2 side stream 13 first high pressure recycle CO2 fraction 14 turbine discharge flow current 15 discharge flow current initially cooled turbine 18 liquid water separator 19 condensed water flow 20 separate CO2 gas flow 21 CO2 liquefaction heat exchanger 22 subcooled CO2 recycling chain 23 pressurized subcooled CO2 recycling chain 24 heater water bath 25 LNG pump 26 LNG discharge stream 27 bath fuel gas stream 28 bath stack 2 9 first control valve 30 total product pipeline natural gas stream 31 bathed natural gas stream 32 compressed LNG stream 33 LNG tank 34 electric motor 35 secondary natural gas heat exchanger 36 closed loop heat transfer fluid secondary heated 37 secondary cooled heat transfer fluid 38 fraction of total natural gas stream 39 fraction of natural heating gas LNG 40 blower 41 fraction of LNG fuel 43 compressed LNG product stream 44 preheated LNG product stream 45 compressed LNG heating natural gas stream 46 economy heat exchanger 47 air separation plant 48 LNG fuel pump 49 second control valve 50 LNG tank discharge stream 51 second turbine discharge stream 52 recycling CO2 control valve 53 second fraction of high pressure recycling CO2 54 thermal desiccant dryer regenerated te 55 dry CO2 gas stream 56 cooling natural gas stream 57 total natural gas stream 62 high pressure natural gas stream 63 high pressure heated natural gas stream 64 heat transfer fluid stream closed, heated cycle 65 cooled heat transfer fluid stream 66 supplementary CO2 heat exchanger 67 preheated high pressure recycle CO2 stream 68 high pressure recycle CO2 stream 70 high pressure LNG fuel stream 71 partial product natural gas stream 77 CO2 product stream 100 tank 101 pump 102 water bath evaporator 103 filter 104 burner pressure blower 105 boiling blower 106 boiling compressor 107 atmospheric air line 109 air line 110 LNG tank boiling line 111 boiling compressor line 112 boiling current 113 NG burner fuel line 114 current Compressed boiling NG 115 product natural gas stream 116 total natural gas pipeline stream 117 pressurized fuel gas stream 119 LNG supply line 120 burner 121 ventilation line 210a LNG supply 210b heated LNG supply 221 heat exchanger 239 supplementary GN stream 240 blower 257 GN stream 258 product GN stream

权利要求:
Claims (15)
[0001]
1. Energy generation method, the method characterized by the fact that it comprises: burning a carbonaceous fuel in a combustor (1) in the presence of oxygen and a CO2 recycling stream to produce a combined combustion product stream; passing the combined combustion product stream through a turbine (2) to generate energy and form a turbine exhaust stream comprising CO2; passing the turbine exhaust stream comprising CO2 through a first heat exchanger (46) in order to transfer heat from the turbine exhaust stream to the CO2 recycling stream and form a cooled turbine exhaust stream; pass a stream of liquefied natural gas (LNG) and CO2 from the cooled turbine exhaust stream through a second heat exchanger (21) in order to cool and liquefy the CO2 and in order to heat and evaporate the LNG to form a stream of liquefied CO2 and a stream of gaseous natural gas (NG); pressurize the liquefied CO2 stream to form the CO2 recycle stream; and passing the recycled CO2 stream to the combustor (1).
[0002]
2. Method, according to claim 1, characterized by the fact that one or more of the following conditions is (are) met: the CO2 recycling stream is passed to the combustor (1) at a pressure about 150 bar (15 MPa) or more; combustion is carried out at a temperature of about 500 ° C or more; the ratio of the pressure of the combined combustion product stream to the pressure of the turbine exhaust stream comprising CO2 is about 12 or less; and the LNG passed into the second heat exchanger (21) is at a pressure of about 50 bar (5 MPa) to about 90 bar (9 MPa).
[0003]
3. Method, according to claim 1, characterized by the fact that a fraction of the gas stream formed by the second heat exchanger (21) is removed and inserted in the LNG stream passed into the second heat exchanger (21) optionally, where the fraction of the gaseous LNG stream inserted in the LNG stream is sufficient to raise the temperature of the LNG stream to a temperature that is above the CO2 solidification temperature and is within about 20 ° C of the temperature of CO2 solidification.
[0004]
4. Method according to claim 1, characterized in that the CO2 cooled from the turbine exhaust stream is cooled in the second heat exchanger (21) to a temperature that is above the CO2 solidification temperature and is within about 30 ° C of the CO2 solidification temperature.
[0005]
5. Method, according to claim 1, characterized by the fact that the step of pressurizing the CO2 recycling stream comprises the passage of the CO2 recycling stream through a liquid pump (5), optionally, in which the The power generation turbine produces shaft energy, and the shaft energy is used to drive the liquid pump (2).
[0006]
6. Method according to claim 5, characterized by the fact that the pressurized CO2 recycling stream leaving the liquid pump (5) is heated, preferably, in which one or both of the following conditions is (are) met (s): the heating comprises passing the pressurized CO2 recycling stream through the second heat exchanger; the CO2 recycling stream is heated to a temperature of about 0 ° C or more.
[0007]
7. Method, according to claim 1, characterized by the fact that the carbonaceous fuel is NG derived from the LNG stream.
[0008]
8. Method according to claim 7, characterized by the fact that the bypass comprises the passage of LNG through a first pump (25) and a second pump (48), preferably, in which the LNG exiting the second pump (48) is heated to a temperature of about 200 ° C or more, preferably, where the heating comprises the passage of LNG through the second heat exchanger (21) so as to form a stream of gaseous NG, preferably wherein the heating additionally comprises the use of compressive heat from an air separation installation (47).
[0009]
9. Method according to claim 1, characterized in that it additionally comprises the passage of the cooled turbine exhaust current through a third heat exchanger (17) after passing through the first heat exchanger and before passing through the second heat exchanger (21), preferably, where the passage through the third heat exchanger (17) cools the turbine exhaust stream to a temperature of about 0 ° C to about 10 ° C, preferably where one or both of the following conditions are (are) met: the turbine exhaust stream is cooled against a fraction of the gaseous NG stream leaving the second heat exchanger (21); the method further comprises the passage of the cooled turbine exhaust stream through one or both of a liquid water separator (18) and a desiccant dryer (54), in order to supply CO2 from the cooled turbine exhaust stream as a stream CO2 dry, optionally where the dry CO2 stream is dried to a dew point of about -50 ° C or below.
[0010]
10. Method according to claim 1, characterized by the fact that a part of the recycled CO2 stream passing to the combustion (1) is heated using the compression heat of an air separation installation (47), or in that the recycled CO2 stream passing to the combustor (1) is separated into a first fraction and a second fraction, preferably, in which one or both of the following conditions is (are) met: the first fraction of the CO2 stream recycled to the combustor (1) directly enters the combustor (1). the second fraction of the recycled CO2 stream passing to the combustion (1) is combined with oxygen to form an oxidizing stream that enters the combustion (1).
[0011]
11. Power generation system, characterized by the fact that it comprises: a combustor (1) adapted to burn a carbonaceous fuel in the presence of oxygen and a CO2 recycling stream to produce a combined combustion product stream; an energy producing turbine (2) in fluid communication with the combustion (1) and adapted to receive the combined combustion product stream and send a turbine exhaust stream comprising CO2; a first heat exchanger (46) in fluid communication with the energy generating turbine (1) and the combustion and adapted to transfer heat from the turbine exhaust stream comprising CO2 to the CO2 recycling stream in order to provide a stream exhaust from a cooled turbine comprising CO2; a second heat exchanger (21) in fluid communication with the first heat exchanger (46) and adapted to liquefy CO2 in the turbine exhaust stream; a recycling compressor (5) adapted to pressurize the liquefied CO2 to a pressure suitable for recycling to the combustor (1); and a source (33) of liquefied natural gas (LNG) in fluid communication with the second heat exchanger (21).
[0012]
12. System according to claim 1, characterized by the fact that it additionally comprises a third heat exchanger positioned between and in fluid communication with the first heat exchanger and the second heat exchanger (21), preferably in which the The third heat exchanger (17) includes an input in fluid communication with an output in the first heat exchanger (46), an input in fluid communication with an output in the second heat exchanger (21), and an output in fluid communication with an inlet to the second heat exchanger (21), optionally comprising additionally one or more water removal devices positioned between the outlet in the third heat exchanger and the inlet in the second heat exchanger.
[0013]
13. System according to claim 11, characterized by the fact that the energy production turbine (2) is adapted to supply shaft energy to a liquid pump (25), optionally in which the liquid pump (25 ) is positioned between and is in fluid communication with the LNG source (33) and the second heat exchanger (21).
[0014]
System according to claim 11, characterized by the fact that it still comprises an air separation installation (47), preferably, in which the air separation installation (47) is a cryogenic air separation installation comprising a adiabatic main compressor and an amplification compressor.
[0015]
System according to claim 11, characterized in that the first heat exchanger (46) comprises a series of three heat exchange units.

类似技术:

公开号 | 公开日 | 专利标题

BR112014010651B1|2021-02-09|power generation system and corresponding method

US7637109B2|2009-12-29|Power generation system including a gas generator combined with a liquified natural gas supply

US7950214B2|2011-05-31|Method of and apparatus for pressurizing gas flowing in a pipeline

US20110132032A1|2011-06-09|Liquid air method and apparatus

CA2996904A1|2017-03-09|Systems and methods for power production using nested co2 cycles

CA2907062C|2021-09-07|System and method for high efficiency power generation using a carbon dioxide circulating working fluid

WO2016204893A1|2016-12-22|Cryogenic liquid energy storage

FR3002311A1|2014-08-22|DEVICE FOR LIQUEFACTING GAS, IN PARTICULAR NATURAL GAS

US20210372322A1|2021-12-02|Gas storage apparatus and method

Borisov et al.2020|Analysis of the compressorless combined cycle gas turbine unit performance efficiency in district heating systems

KR101922273B1|2018-11-27|A Treatment System of Liquefied Gas

PL233789B1|2019-11-29|Installation for storage of energy in condensed air, with the oxygen separation module

同族专利:

公开号 | 公开日

TW201337091A|2013-09-16|

EP2776692B1|2016-05-04|

EP2776692A1|2014-09-17|

KR20140104953A|2014-08-29|

US20130104525A1|2013-05-02|

EA201400520A1|2014-10-30|

EA201790092A1|2017-05-31|

ZA201403385B|2019-11-27|

AU2012332494A1|2014-06-19|

KR102044831B1|2019-11-15|

WO2013067149A1|2013-05-10|

MX345755B|2017-02-15|

TWI616585B|2018-03-01|

CA2854402A1|2013-05-10|

US9523312B2|2016-12-20|

IN2014KN01081A|2015-10-09|

EA033615B1|2019-11-11|

BR112014010651A2|2017-04-25|

AR088637A1|2014-06-25|

US20170067373A1|2017-03-09|

MX2014005365A|2014-08-27|

US10415434B2|2019-09-17|

CN104160130B|2017-08-25|

CN104160130A|2014-11-19|

CA2854402C|2020-03-24|

HK1200895A1|2015-09-11|

PL2776692T3|2016-11-30|

JP6104926B2|2017-03-29|

AU2012332494B2|2016-07-07|

ES2574263T3|2016-06-16|

JP2014532833A|2014-12-08|

EA026826B1|2017-05-31|

引用文献:

公开号 | 申请日 | 公开日 | 申请人 | 专利标题

US3376706A|1965-06-28|1968-04-09|Angelino Gianfranco|Method for obtaining mechanical energy from a thermal gas cycle with liquid phase compression|

CH476208A|1967-07-27|1969-07-31|Sulzer Ag|Gas turbine system with CO2 as the working medium|

US3736745A|1971-06-09|1973-06-05|H Karig|Supercritical thermal power system using combustion gases for working fluid|

US3816595A|1971-11-15|1974-06-11|Aqua Chem Inc|Method and apparatus for removing nitrogen oxides from a gas stream|

US3868817A|1973-12-27|1975-03-04|Texaco Inc|Gas turbine process utilizing purified fuel gas|

DE2407617A1|1974-02-16|1975-08-21|Linde Ag|METHOD OF ENERGY RECOVERY FROM LIQUID GASES|

US3971211A|1974-04-02|1976-07-27|Mcdonnell Douglas Corporation|Thermodynamic cycles with supercritical CO2 cycle topping|

CH584837A5|1974-11-22|1977-02-15|Sulzer Ag|

US3976443A|1974-12-18|1976-08-24|Texaco Inc.|Synthesis gas from solid carbonaceous fuel|

DE2523672C3|1975-05-28|1980-03-20|Gutehoffnungshuette Sterkrade Ag, 4200 Oberhausen|Device for the evaporation of liquefied natural gas with the aid of a gas turbine system with a closed circuit|

US4191500A|1977-07-27|1980-03-04|Rockwell International Corporation|Dense-phase feeder method|

US4154581A|1978-01-12|1979-05-15|Battelle Development Corporation|Two-zone fluid bed combustion or gasification process|

US4206610A|1978-04-14|1980-06-10|Arthur D. Little, Inc.|Method and apparatus for transporting coal as a coal/liquid carbon dioxide slurry|

US4193259A|1979-05-24|1980-03-18|Texaco Inc.|Process for the generation of power from carbonaceous fuels with minimal atmospheric pollution|

US4702747A|1981-03-24|1987-10-27|Carbon Fuels Corporation|Coal derived/carbon dioxide fuel slurry and method of manufacture|

GB2100801B|1981-06-18|1984-10-10|Air Prod & Chem|Method and apparatus for compressing gas|

US4522628A|1981-12-16|1985-06-11|Mobil Oil Corporation|Method for removing ash mineral matter of coal with liquid carbon dioxide and water|

US4498289A|1982-12-27|1985-02-12|Ian Osgerby|Carbon dioxide power cycle|

US4602483A|1985-03-08|1986-07-29|Southwestern Public Service Company|Coal slurry system|

US4765781A|1985-03-08|1988-08-23|Southwestern Public Service Company|Coal slurry system|

DE3600432A1|1985-05-21|1987-02-05|Gutehoffnungshuette Man|METHOD FOR GASIFYING A CARBONATED FUEL, IN PARTICULAR COAL|

US4721420A|1985-09-03|1988-01-26|Arthur D. Little, Inc.|Pipeline transportation of coarse coal-liquid carbon dioxide slurry|

GB2196016B|1986-08-29|1991-05-15|Humphreys & Glasgow Ltd|Clean electric power generation process|

US4999995A|1986-08-29|1991-03-19|Enserch International Investments Ltd.|Clean electric power generation apparatus|

US4765143A|1987-02-04|1988-08-23|Cbi Research Corporation|Power plant using CO2 as a working fluid|

US4839030A|1988-05-27|1989-06-13|Hri, Inc.|Coal liquefaction process utilizing coal/CO2 slurry feedstream|

US4957515A|1988-11-03|1990-09-18|Air Products And Chemicals, Inc.|Process for sulfur removal and recovery from fuel gas using physical solvent|

JP2664984B2|1989-02-28|1997-10-22|三菱重工業株式会社|Flame retardant low calorific value gas combustion device|

US4942734A|1989-03-20|1990-07-24|Kryos Energy Inc.|Cogeneration of electricity and liquid carbon dioxide by combustion of methane-rich gas|

US4995234A|1989-10-02|1991-02-26|Chicago Bridge & Iron Technical Services Company|Power generation from LNG|

US5175995A|1989-10-25|1993-01-05|Pyong-Sik Pak|Power generation plant and power generation method without emission of carbon dioxide|

US5247791A|1989-10-25|1993-09-28|Pyong S. Pak|Power generation plant and power generation method without emission of carbon dioxide|

JP2954972B2|1990-04-18|1999-09-27|三菱重工業株式会社|Gasification gas combustion gas turbine power plant|

US5937652A|1992-11-16|1999-08-17|Abdelmalek; Fawzy T.|Process for coal or biomass fuel gasification by carbon dioxide extracted from a boiler flue gas stream|

US5353721A|1991-07-15|1994-10-11|Manufacturing And Technology Conversion International|Pulse combusted acoustic agglomeration apparatus and process|

NL9201179A|1992-07-02|1994-02-01|Tno|PROCESS FOR THE REGENERATIVE REMOVAL OF CARBON DIOXIDE FROM GAS FLOWS.|

SE469668B|1992-07-13|1993-08-16|Bal Ab|COMBINED COMBUSTION COMBUSTION AND EXHAUST WAS|

US6289666B1|1992-10-27|2001-09-18|Ginter Vast Corporation|High efficiency low pollution hybrid Brayton cycle combustor|

DE4303174A1|1993-02-04|1994-08-18|Joachim Dipl Ing Schwieger|Method for the generation of electrical energy|

DE4407619C1|1994-03-08|1995-06-08|Entec Recycling Und Industriea|Fossil fuel power station process|

US5467722A|1994-08-22|1995-11-21|Meratla; Zoher M.|Method and apparatus for removing pollutants from flue gas|

EP0828929B1|1994-08-25|2004-09-22|Clean Energy Systems, Inc.|Reduced pollution power generation system and gas generator therefore|

GB9425691D0|1994-12-20|1995-02-22|Boc Group Plc|A combustion apparatus|

US5595059A|1995-03-02|1997-01-21|Westingthouse Electric Corporation|Combined cycle power plant with thermochemical recuperation and flue gas recirculation|

US6170264B1|1997-09-22|2001-01-09|Clean Energy Systems, Inc.|Hydrocarbon combustion power generation system with CO2 sequestration|

US5724805A|1995-08-21|1998-03-10|University Of Massachusetts-Lowell|Power plant with carbon dioxide capture and zero pollutant emissions|

US5906806A|1996-10-16|1999-05-25|Clark; Steve L.|Reduced emission combustion process with resource conservation and recovery options "ZEROS" zero-emission energy recycling oxidation system|

EP0859136A1|1997-02-17|1998-08-19|N.V. Kema|Gas turbine with energy recovering|

NO308400B1|1997-06-06|2000-09-11|Norsk Hydro As|Power generation process comprising a combustion process|

GB9801200D0|1998-01-20|1998-03-18|Air Prod & Chem|Intergration of a cryogenic air separator with synthesis gas production and conversion|

EP0939199B1|1998-02-25|2004-03-31|ALSTOM Technology Ltd|Power plant and process for operating a power plant with a CO2-cycle|

DE69931548T2|1998-04-07|2007-05-10|Mitsubishi Heavy Industries, Ltd.|turbine plant|

EP0953748B1|1998-04-28|2004-01-28|ALSTOM Ltd|Power plant with a CO2-cycle|

US6148602A|1998-08-12|2000-11-21|Norther Research & Engineering Corporation|Solid-fueled power generation system with carbon dioxide sequestration and method therefor|

JP2000120447A|1998-10-12|2000-04-25|Toshiba Corp|Thermal power plant|

US6199364B1|1999-01-22|2001-03-13|Alzeta Corporation|Burner and process for operating gas turbines with minimal NOx emissions|

US6209307B1|1999-05-05|2001-04-03|Fpl Energy, Inc.|Thermodynamic process for generating work using absorption and regeneration|

JP2001041007A|1999-05-26|2001-02-13|Mitsubishi Heavy Ind Ltd|Turbine equipment|

US6202574B1|1999-07-09|2001-03-20|Abb Alstom Power Inc.|Combustion method and apparatus for producing a carbon dioxide end product|

JP4094185B2|1999-08-24|2008-06-04|三井造船株式会社|Cold power generation system|

DE19952884A1|1999-11-03|2001-05-10|Abb Alstom Power Ch Ag|Operation method for carbon dioxide gas turbine system, involves using combustion chamber in which fuel is burnt with oxygen, with at least one turbine and one generator|

NL1013804C2|1999-12-09|2001-06-12|Wouter Willem Van De Waal|Environmentally friendly method for generating energy from natural gas.|

US6196000B1|2000-01-14|2001-03-06|Thermo Energy Power Systems, Llc|Power system with enhanced thermodynamic efficiency and pollution control|

GB0005374D0|2000-03-06|2000-04-26|Air Prod & Chem|Apparatus and method of heating pumped liquid oxygen|

DE10016079A1|2000-03-31|2001-10-04|Alstom Power Nv|Method for removing carbon dioxide from the exhaust gas of a gas turbine system and device for carrying out the method|

WO2001090548A1|2000-05-12|2001-11-29|Clean Energy Systems, Inc.|Semi-closed brayton cycle gas turbine power systems|

SE518487C2|2000-05-31|2002-10-15|Norsk Hydro As|Method of operating a combustion plant and a combustion plant|

US6333015B1|2000-08-08|2001-12-25|Arlin C. Lewis|Synthesis gas production and power generation with zero emissions|

DE10064270A1|2000-12-22|2002-07-11|Alstom Switzerland Ltd|Method for operating a gas turbine system and a related gas turbine system|

FR2819583B1|2001-01-12|2003-03-07|Air Liquide|INTEGRATED AIR SEPARATION AND ENERGY GENERATION PROCESS AND INSTALLATION FOR CARRYING OUT SUCH A PROCESS|

FR2819584B1|2001-01-12|2003-03-07|Air Liquide|INTEGRATED AIR SEPARATION AND ENERGY GENERATION PROCESS AND INSTALLATION FOR CARRYING OUT SUCH A PROCESS|

US6532743B1|2001-04-30|2003-03-18|Pratt & Whitney Canada Corp.|Ultra low NOx emissions combustion system for gas turbine engines|

US6993912B2|2003-01-23|2006-02-07|Pratt & Whitney Canada Corp.|Ultra low Nox emissions combustion system for gas turbine engines|

US6622496B2|2001-07-12|2003-09-23|Praxair Technology, Inc.|External loop nonfreezing heat exchanger|

DE50207526D1|2001-10-01|2006-08-24|Alstom Technology Ltd|METHOD AND DEVICE FOR ACCESSING EMISSION-FREE GAS TURBINE POWER PLANTS|

US20030131582A1|2001-12-03|2003-07-17|Anderson Roger E.|Coal and syngas fueled power generation systems featuring zero atmospheric emissions|

JP3814206B2|2002-01-31|2006-08-23|三菱重工業株式会社|Waste heat utilization method of carbon dioxide recovery process|

US7284362B2|2002-02-11|2007-10-23|L'Air Liquide, Société Anonyme à Directoire et Conseil de Surveillance pour l'Étude et l'Exploitation des Procedes Georges Claude|Integrated air separation and oxygen fired power generation system|

US6871502B2|2002-02-15|2005-03-29|America Air Liquide, Inc.|Optimized power generation system comprising an oxygen-fired combustor integrated with an air separation unit|

US6532745B1|2002-04-10|2003-03-18|David L. Neary|Partially-open gas turbine cycle providing high thermal efficiencies and ultra-low emissions|

NO20023050L|2002-06-21|2003-12-22|Fleischer & Co|Process and facilities for carrying out the process|

US20040011057A1|2002-07-16|2004-01-22|Siemens Westinghouse Power Corporation|Ultra-low emission power plant|

US6820689B2|2002-07-18|2004-11-23|Production Resources, Inc.|Method and apparatus for generating pollution free electrical energy from hydrocarbons|

US6775987B2|2002-09-12|2004-08-17|The Boeing Company|Low-emission, staged-combustion power generation|

US6802178B2|2002-09-12|2004-10-12|The Boeing Company|Fluid injection and injection method|

US6877322B2|2002-09-17|2005-04-12|Foster Wheeler Energy Corporation|Advanced hybrid coal gasification cycle utilizing a recycled working fluid|

US7303597B2|2002-10-15|2007-12-04|Pratt & Whitney Rocketdyne, Inc.|Method and apparatus for continuously feeding and pressurizing a solid material into a high pressure system|

AU2003298266A1|2002-11-08|2004-06-07|Alstom Technology Ltd|Gas turbine power plant and method of operating the same|

US7191587B2|2002-11-13|2007-03-20|American Air Liquide, Inc.|Hybrid oxygen-fired power generation system|

AU2003295610B2|2002-11-15|2010-01-28|Clean Energy Systems, Inc.|Low pollution power generation system with ion transfer membrane air separation|

US6898936B1|2002-12-04|2005-05-31|The United States Of America As Represented By The United States Department Of Energy|Compression stripping of flue gas with energy recovery|

US7007474B1|2002-12-04|2006-03-07|The United States Of America As Represented By The United States Department Of Energy|Energy recovery during expansion of compressed gas using power plant low-quality heat sources|

EP1429000A1|2002-12-09|2004-06-16|Siemens Aktiengesellschaft|Method and device for operating a gas turbine comprising a fossile fuel combustion chamber|

US7021063B2|2003-03-10|2006-04-04|Clean Energy Systems, Inc.|Reheat heat exchanger power generation systems|

US7074033B2|2003-03-22|2006-07-11|David Lloyd Neary|Partially-open fired heater cycle providing high thermal efficiencies and ultra-low emissions|

US7007486B2|2003-03-26|2006-03-07|The Boeing Company|Apparatus and method for selecting a flow mixture|

GB2401403B|2003-05-08|2006-05-31|Rolls Royce Plc|Carbon dioxide recirculation|

WO2004109206A1|2003-06-05|2004-12-16|Fluor Corporation|Liquefied natural gas regasification configuration and method|

US7192569B2|2003-06-30|2007-03-20|Pratt & Whitney|Hydrogen generation with efficient byproduct recycle|

EP1687518A1|2003-09-30|2006-08-09|BHP Billiton Innovation Pty Ltd|Power generation|

US7017329B2|2003-10-10|2006-03-28|United Technologies Corporation|Method and apparatus for mixing substances|

US7469544B2|2003-10-10|2008-12-30|Pratt & Whitney Rocketdyne|Method and apparatus for injecting a fuel into a combustor assembly|

US7299619B2|2003-12-13|2007-11-27|Siemens Power Generation, Inc.|Vaporization of liquefied natural gas for increased efficiency in power cycles|

US7124589B2|2003-12-22|2006-10-24|David Neary|Power cogeneration system and apparatus means for improved high thermal efficiencies and ultra-low emissions|

US7111463B2|2004-01-23|2006-09-26|Pratt & Whitney Rocketdyne Inc.|Combustion wave ignition for combustors|

FR2867463B1|2004-03-15|2007-05-11|Commissariat Energie Atomique|SOLID POWER SUPPLY OF VARIABLE GRANULOMETRY OF A DEVICE UNDER PRESSURE|

US20050241311A1|2004-04-16|2005-11-03|Pronske Keith L|Zero emissions closed rankine cycle power system|

WO2005114050A1|2004-05-19|2005-12-01|Innovative Energy, Inc.|Combustion method and apparatus|

US7360639B2|2004-06-16|2008-04-22|Pratt & Whitney Rocketdyne, Inc.|Hot rotary screw pump|

US7547419B2|2004-06-16|2009-06-16|United Technologies Corporation|Two phase injector for fluidized bed reactor|

US7637109B2|2004-08-02|2009-12-29|American Air Liquide, Inc.|Power generation system including a gas generator combined with a liquified natural gas supply|

DE102004039164A1|2004-08-11|2006-03-02|Alstom Technology Ltd|Method for generating energy in a gas turbine comprehensive power generation plant and power generation plant for performing the method|

US7459131B2|2004-08-16|2008-12-02|United Technologies Corporation|Reduced temperature regernerating/calcining apparatus for hydrogen generation|

US7402188B2|2004-08-31|2008-07-22|Pratt & Whitney Rocketdyne, Inc.|Method and apparatus for coal gasifier|

JP2006125767A|2004-10-29|2006-05-18|Tokyo Institute Of Technology|Heat exchanger|

US7736599B2|2004-11-12|2010-06-15|Applied Materials, Inc.|Reactor design to reduce particle deposition during process abatement|

EP1657409A1|2004-11-15|2006-05-17|Elsam A/S|A method of and an apparatus for producing electrical power|

EP1669572A1|2004-12-08|2006-06-14|Vrije Universiteit Brussel|Process and installation for producing electric power|

EP1828410A2|2004-12-13|2007-09-05|F. Hoffmann-Roche AG|Single nucleotide polymorphism associated to type ii diabetes|

US7950243B2|2006-01-16|2011-05-31|Gurin Michael H|Carbon dioxide as fuel for power generation and sequestration system|

US7547423B2|2005-03-16|2009-06-16|Pratt & Whitney Rocketdyne|Compact high efficiency gasifier|

AU2006229877B2|2005-03-30|2009-04-23|Fluor Technologies Corporation|Integrated of LNG regasification with refinery and power generation|

WO2006107209A1|2005-04-05|2006-10-12|Sargas As|Low co2 thermal powerplant|

US8196848B2|2005-04-29|2012-06-12|Pratt & Whitney Rocketdyne, Inc.|Gasifier injector|

US7717046B2|2005-04-29|2010-05-18|Pratt & Whitney Rocketdyne, Inc.|High pressure dry coal slurry extrusion pump|

FR2894838B1|2005-12-21|2008-03-14|Gaz De France Sa|METHOD AND SYSTEM FOR CAPTURING CARBON DIOXIDE IN FUMEES|

NO332159B1|2006-01-13|2012-07-09|Nebb Technology As|Process and facilities for energy efficient capture and separation of CO2 from a gas phase|

US8075646B2|2006-02-09|2011-12-13|Siemens Energy, Inc.|Advanced ASU and HRSG integration for improved integrated gasification combined cycle efficiency|

NO328260B1|2006-06-20|2010-01-18|Aker Engineering & Technology|Process and plant for re-gasification LNG|

US7827797B2|2006-09-05|2010-11-09|General Electric Company|Injection assembly for a combustor|

US7387197B2|2006-09-13|2008-06-17|Pratt & Whitney Rocketdyne, Inc.|Linear tractor dry coal extrusion pump|

US7722690B2|2006-09-29|2010-05-25|Kellogg Brown & Root Llc|Methods for producing synthesis gas|

US7827778B2|2006-11-07|2010-11-09|General Electric Company|Power plants that utilize gas turbines for power generation and processes for lowering CO2 emissions|

US20080115500A1|2006-11-15|2008-05-22|Scott Macadam|Combustion of water borne fuels in an oxy-combustion gas generator|

WO2008076947A2|2006-12-16|2008-06-26|Papile Christopher J|Methods and/or systems for removing carbon dioxide and/or generating power|

US7740671B2|2006-12-18|2010-06-22|Pratt & Whitney Rocketdyne, Inc.|Dump cooled gasifier|

US7553463B2|2007-01-05|2009-06-30|Bert Zauderer|Technical and economic optimization of combustion, nitrogen oxides, sulfur dioxide, mercury, carbon dioxide, coal ash and slag and coal slurry use in coal fired furnaces/boilers|

AT504863B1|2007-01-15|2012-07-15|Siemens Vai Metals Tech Gmbh|METHOD AND APPARATUS FOR GENERATING ELECTRICAL ENERGY IN A GAS AND STEAM TURBINE POWER PLANT|

US8088196B2|2007-01-23|2012-01-03|Air Products And Chemicals, Inc.|Purification of carbon dioxide|

US7731783B2|2007-01-24|2010-06-08|Pratt & Whitney Rocketdyne, Inc.|Continuous pressure letdown system|

US8771604B2|2007-02-06|2014-07-08|Aerojet Rocketdyne Of De, Inc.|Gasifier liner|

US20080190214A1|2007-02-08|2008-08-14|Pratt & Whitney Rocketdyne, Inc.|Cut-back flow straightener|

JP4859981B2|2007-04-26|2012-01-25|株式会社日立製作所|Gas turbine equipment and its remodeling method|

US7826054B2|2007-05-04|2010-11-02|Pratt & Whitney Rocketdyne, Inc.|Fuel cell instrumentation system|

MX2009012464A|2007-05-30|2009-12-02|Fluor Tech Corp|Lng regasification and power generation.|

US7874140B2|2007-06-08|2011-01-25|Foster Wheeler North America Corp.|Method of and power plant for generating power by oxyfuel combustion|

US8850789B2|2007-06-13|2014-10-07|General Electric Company|Systems and methods for power generation with exhaust gas recirculation|

US7814975B2|2007-09-18|2010-10-19|Vast Power Portfolio, Llc|Heavy oil recovery with fluid water and carbon dioxide|

US20090260585A1|2008-04-22|2009-10-22|Foster Wheeler Energy Corporation|Oxyfuel Combusting Boiler System and a Method of Generating Power By Using the Boiler System|

US20090301054A1|2008-06-04|2009-12-10|Simpson Stanley F|Turbine system having exhaust gas recirculation and reheat|

US20100018218A1|2008-07-25|2010-01-28|Riley Horace E|Power plant with emissions recovery|

US8806849B2|2008-07-30|2014-08-19|The University Of Wyoming|System and method of operating a power generation system with an alternative working fluid|

US20100024378A1|2008-07-30|2010-02-04|John Frederick Ackermann|System and method of operating a gas turbine engine with an alternative working fluid|

US20100024433A1|2008-07-30|2010-02-04|John Frederick Ackermann|System and method of operating a gas turbine engine with an alternative working fluid|

TR200809852A1|2008-12-26|2010-07-21|Yenbu Maki̇ne Sanayi̇ Ve Ti̇caret Anoni̇m Şi̇rketi̇|Consumption saving system by using the expansion of gases.|

US8596075B2|2009-02-26|2013-12-03|Palmer Labs, Llc|System and method for high efficiency power generation using a carbon dioxide circulating working fluid|

JP2011032954A|2009-08-04|2011-02-17|Chiyoda Kako Kensetsu Kk|Combined power generation system using cold of liquefied gas|

US8685120B2|2009-08-11|2014-04-01|General Electric Company|Method and apparatus to produce synthetic gas|

US20110289941A1|2010-05-28|2011-12-01|General Electric Company|Brayton cycle regasification of liquiefied natural gas|

US20120017639A1|2010-07-21|2012-01-26|Synfuels International, Inc.|Methods and systems for storing and transporting gases|

US8220248B2|2010-09-13|2012-07-17|Membrane Technology And Research, Inc|Power generation process with partial recycle of carbon dioxide|US5863653A|1996-07-09|1999-01-26|Life Energy Industry Inc.|Rayon fiber containing tourmaline particles and method for the preparation thereof|

US9457313B2|2010-09-13|2016-10-04|Membrane Technology And Research, Inc.|Membrane technology for use in a power generation process|

US9856769B2|2010-09-13|2018-01-02|Membrane Technology And Research, Inc.|Gas separation process using membranes with permeate sweep to remove CO2 from combustion exhaust|

CA2890484A1|2012-08-30|2014-03-06|Enhanced Energy Group LLC|Cycle turbine engine power system|

US9188285B2|2012-12-24|2015-11-17|General Electric Company|Systems and methods for oxidation of boil-off gas|

CA2903784C|2013-03-04|2021-03-16|Echogen Power Systems, L.L.C.|Heat engine systems with high net power supercritical carbon dioxide circuits|

WO2014146861A1|2013-03-21|2014-09-25|Siemens Aktiengesellschaft|Power generation system and method to operate|

JP6250332B2|2013-08-27|2017-12-20|８リバーズキャピタル，エルエルシー|Gas turbine equipment|

EA035969B1|2014-09-09|2020-09-08|8 Риверз Кэпитл, Ллк|Method for production of low pressure liquid carbon dioxide from a power production system|

US11231224B2|2014-09-09|2022-01-25|8 Rivers Capital, Llc|Production of low pressure liquid carbon dioxide from a power production system and method|

MA40950A|2014-11-12|2017-09-19|8 Rivers Capital Llc|SUITABLE CONTROL SYSTEMS AND PROCEDURES FOR USE WITH POWER GENERATION SYSTEMS AND PROCESSES|

TWI537865B|2015-03-11|2016-06-11|Liquid Gas Transmission and Distribution and Gasification Management System|

US9976448B2|2015-05-29|2018-05-22|General Electric Company|Regenerative thermodynamic power generation cycle systems, and methods for operating thereof|

PL3308004T3|2015-06-15|2022-01-31|8 Rivers Capital, Llc|System and method for startup of a power production plant|

PL413001A1|2015-07-06|2017-01-16|Tadeusz Bąk|Method for regasification of liquefied natural gas and the regasification system for liquefied natural gas|

CA2996904C|2015-09-01|2021-11-02|8 Rivers Capital, Llc|Systems and methods for power production using nested co2 cycles|

WO2017083778A1|2015-11-14|2017-05-18|New Fg Co, Llc|Method for transporting liquefied natural gas and liquefied carbon dioxide|

BR112018069543A2|2016-02-26|2019-01-29|8 Rivers Capital Llc|systems and methods for controlling a power plant|

KR102307554B1|2016-04-21|2021-09-30|8 리버스 캐피탈, 엘엘씨|Systems and methods for oxidation of hydrocarbon gases|

MX2019002409A|2016-08-30|2019-07-04|8 Rivers Capital Llc|Cryogenic air separation method for producing oxygen at high pressures.|

BR112019005434A2|2016-09-22|2019-06-18|Gas Technology Inst|power cycle systems and methods|

MX2019005639A|2016-11-15|2019-07-04|8 Rivers Capital Llc|Removal of impurities from a process stream by contacting it with an oxidant and with an aqueous stream.|

US9782718B1|2016-11-16|2017-10-10|Membrane Technology And Research, Inc.|Integrated gas separation-turbine CO2 capture processes|

CA3055401A1|2017-03-07|2018-09-13|8 Rivers Capital, Llc|System and method for operation of a flexible fuel combustor for a gas turbine|

CN111094705A|2017-07-20|2020-05-01|八河流资产有限责任公司|System and method for power generation using solid fuel combustion and carbon capture|

US10767515B2|2017-08-23|2020-09-08|Stanislav Sinatov|Method for liquid air and gas energy storage|

US10914232B2|2018-03-02|2021-02-09|8 Rivers Capital, Llc|Systems and methods for power production using a carbon dioxide working fluid|

CN108625990B|2018-04-13|2020-08-18|华中科技大学|Natural gas oxygen-enriched combustion and transcritical CO2Cyclic coupled power generation system|

US11187112B2|2018-06-27|2021-11-30|Echogen Power Systems Llc|Systems and methods for generating electricity via a pumped thermal energy storage system|

WO2020021456A1|2018-07-23|2020-01-30|8 Rivers Capital, Llc|System and method for power generation with flameless combustion|

US10961920B2|2018-10-02|2021-03-30|8 Rivers Capital, Llc|Control systems and methods suitable for use with power production systems and methods|

CN109441574B|2018-11-02|2021-07-23|中国石油大学|Integrated coal gasification combined power generation process with near-zero carbon emission for peak regulation|

CN109441573B|2018-11-02|2021-07-23|中国石油大学|Zero-carbon-emission natural gas combined power generation process for peak regulation|

WO2021079324A1|2019-10-22|2021-04-29|8 Rivers Capital, Llc|Control schemes for thermal management of power production systems and methods|

法律状态:
2018-12-04| B06F| Objections, documents and/or translations needed after an examination request according [chapter 6.6 patent gazette]|

2020-02-11| B06U| Preliminary requirement: requests with searches performed by other patent offices: procedure suspended [chapter 6.21 patent gazette]|

2020-11-24| B09A| Decision: intention to grant [chapter 9.1 patent gazette]|

2021-02-09| B16A| Patent or certificate of addition of invention granted [chapter 16.1 patent gazette]|Free format text: PRAZO DE VALIDADE: 20 (VINTE) ANOS CONTADOS A PARTIR DE 01/11/2012, OBSERVADAS AS CONDICOES LEGAIS. |

优先权:

申请号 | 申请日 | 专利标题

US201161554880P| true| 2011-11-02|2011-11-02|

US61/554,880|2011-11-02|

US201161555096P| true| 2011-11-03|2011-11-03|

US61/555,096|2011-11-03|

US201261597717P| true| 2012-02-11|2012-02-11|

US61/597,717|2012-02-11|

PCT/US2012/063012|WO2013067149A1|2011-11-02|2012-11-01|Power generating system and corresponding method|

[返回顶部]