Integrated LNG gasification and power production cycle

Abstract

The present disclosure provides an integrated power generating system and method and liquefied natural gas (LNG) vaporization system and method. More particularly, heat from a CO.sub.2 containing stream from the power generating system and method can be used to heat the LNG for re-gasification as gaseous CO.sub.2 from CO.sub.2 containing stream is liquefied. The liquefied CO.sub.2 can be captured and/or recycled back to a combustor in the power generating system and method.

Claims

1. A power generating system comprising: a combustor adapted to receive a carbonaceous fuel, oxygen, and pressurized, recycled CO.sub.2 and output a pressurized combustion product comprising CO.sub.2; a power producing turbine fluidly connected with the combustor and adapted to expand the pressurized combustion product comprising CO.sub.2 and output a turbine exhaust comprising CO.sub.2; an economizer heat exchanger fluidly connected at a hot end of the economizer heat exchanger with the power producing turbine and the combustor and adapted to transfer heat from the turbine exhaust stream comprising CO.sub.2 to the pressurized, recycled CO.sub.2 and output from a cold end of the economizer heat exchanger a cooled turbine exhaust comprising CO.sub.2; a separator fluidly connected to the economizer heat exchanger and adapted to output substantially pure CO.sub.2; a liquid CO.sub.2 pump adapted to compress liquefied CO.sub.2; a CO.sub.2 liquefier heat exchanger fluidly connected at a cold end of the CO.sub.2 liquefier heat exchanger to the separator and to the economizer heat exchanger and fluidly connected at a hot end of the CO.sub.2 liquefier heat exchanger to both of an input of the liquid CO.sub.2 pump and an output of the liquid CO.sub.2 pump; a source of liquefied natural gas (LNG) fluidly connected with the hot end of the CO.sub.2 liquefier heat exchanger; and a further heat exchanger positioned between the economizer heat exchanger and the CO.sub.2 liquefier heat exchanger so as to be fluidly connected with the cold end of the economizer heat exchanger and the hot end of the CO.sub.2 liquefier heat exchanger; wherein the further heat exchanger includes an inlet fluidly connected with an outlet on the cold end of the economizer heat exchanger, an inlet fluidly connected with an outlet on the hot end of the CO.sub.2 liquefier heat exchanger, and an outlet fluidly connected with an inlet on the hot end of the CO.sub.2 liquefier heat exchanger.

2. The system of claim 1, wherein the separator is positioned between the outlet of the further heat exchanger and the inlet on the hot end of the CO.sub.2 liquefier heat exchanger.

3. The system of claim 1, wherein the power producing turbine is adapted to provide shaft power for the liquid CO.sub.2 pump.

4. The system of claim 1, further comprising an air separation plant.

5. The system of claim 4, wherein the air separation plant is a cryogenic air separation plant.

Description

BRIEF DESCRIPTION OF THE FIGURES

(1) FIG. 1 shows a segment of a power generating system integrated with a segment of a LNG vaporization system according to certain embodiments of the present disclosure and illustrates the heat transfer whereby a CO2 stream is liquefied and a LNG stream is vaporized to form a NG stream;

(2) FIG. 2 is a flow diagram illustrating a known system and method for vaporizing LNG to form NG for input to a pipeline; and

(3) FIG. 3 is a flow diagram illustrating a system and method according to certain embodiments of the present disclosure wherein a power generating system and method is integrated with a LNG vaporization system and method.

DETAILED DESCRIPTION OF THE DISCLOSURE

(4) The invention now will be described more fully hereinafter through reference to various embodiments. These embodiments are provided so that this disclosure will be thorough and complete, and will fully convey the scope of the invention to those skilled in the art. Indeed, the invention may be embodied in many different forms and should not be construed as limited to the embodiments set forth herein; rather, these embodiments are provided so that this disclosure will satisfy applicable legal requirements. As used in the specification, and in the appended claims, the singular forms a, an, the, include plural referents unless the context clearly dictates otherwise.

(5) US Patent Publication No. 2011/0179799, as already noted above, describes power production systems and methods wherein a CO.sub.2 cycle is utilized. In some embodiments, a CO.sub.2 circulating fluid can be provided in a combustor suitable for high temperature and high pressure conditions along with a carbonaceous fuel (such as NG, coal, syngas, biomass, etc.) and an oxidant, such as air or O.sub.2. Such systems and methods can comprise a combustor that operates at high temperatures (e.g., about 500 C. or greater, about 750 C. or greater, about 1,000 C. or greater, or about 1,200 C. or greater), and the presence of the circulating fluid can function to moderate the temperature of a fluid stream exiting the combustor so that the fluid stream can be utilized in energy transfer for power production. The nature of the reaction process at high temperatures and pressures, and with high recycle CO.sub.2 concentrations, can provide for excellent process efficiency and reaction speeds. The combustion product stream can be expanded across at least one turbine to generate power. The expanded gas stream then can be cooled to remove combustion by-products and/or impurities from the stream, and heat withdrawn from the expanded gas stream can be used to heat the CO.sub.2 circulating fluid that is recycled back to the combustor.

(6) In the cooled state, the combustion stream can be processed for removal of water and other contaminants to provide an essentially pure CO.sub.2 stream for recycle back through the combustor with the materials for combustion. The purified CO.sub.2 stream typically is in a gaseous state, and it is beneficial to subject the stream to the necessary conditions such that the CO.sub.2 is 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 CO.sub.2 (e.g., at least 95% by mass, at least 97% by mass, or at least 99% by mass CO.sub.2), the resultant recycle CO.sub.2 stream can be compressed to increase the pressure thereof, such as to about 80 bar (8 MPa). A second compression step can be used to increase the pressure to approximately the pressure in the combustore.g., about 200 bar (20 MPa), about 250 bar (25 MPa), or about 300 bar (30 MPa). In between the compression steps, the CO.sub.2 stream can be cooled to increase the density of the stream so as to reduce the energy input required to pump the stream to the higher pressure. The finally pressurized recycle CO.sub.2 stream can then be further heated and input back into the combustor. Although the above-described power generation system and method provides increased efficiency over conventional power generation systems and methods (and does so while simultaneously capturing the produced carbon), processing the recycle CO.sub.2 stream still requires a significant amount of energy to achieve the necessary compression discussed above. The energy input for compression, however, can be significantly reduced through integration of a re-gasification process for liquefied natural gas (LNG). By utilizing cooling capacity from the LNG re-gasification system, it is possible to liquefy the CO.sub.2 at a reduced pressure (e.g., about 30 bar) and thereafter increase the pressure of the stream. Thus, the systems and methods of the present disclosure can utilize the refrigeration inherent to the LNG to decrease the energy required for compression in the CO.sub.2 cycle and also decrease the energy required for gasification of the LNG.

(7) In various embodiments of the present disclosure, a power generation system can be characterized as illustrated in FIG. 1. As seen therein, a heat exchange relationship (the shaded rectangle) is utilized as the heat source for the LNG in the re-gasification system and as a cooling source of the recycle CO.sub.2 stream in the power generation system, which can reduce or even eliminate the need for initial compression. In FIG. 1, an LNG supply 210a is provided at typical temperaturee.g., about 247 F. (155 C.), and has been pumped to a pressure of about 69 bar (6.9 MPa). The LNG supply (optionally intersected with a supplemental feed discussed below) is passed through a heat exchanger 221, and the resultant NG stream 257 exits at a temperature of about 15 F. (9.4 C.) and a pressure that is substantially unchanged. The NG stream can be divided into a product NG stream 258 and a supplement NG stream 239. The product NG stream can be input to a pipeline or otherwise transported or used as a fuel source. The supplement NG stream can be routed upstream of the heat exchanger and input to the LNG supply to provide supplemental heating of the LNG supply, if desired. The heated LNG supply 210b then can be the LNG stream input to the heat exchanger. A blower 240 can be utilized to drive the supplement NG stream.

(8) The cooled and purified turbine exhaust stream 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 exiting, sub-cooled recycled CO.sub.2 stream 222 at a temperature of about 65 F. (53 C.) and 30 bar (3 MPa) can be passed through a pump 205. The exiting high pressure recycle CO.sub.2 stream 223 can be at a temperature of about 45 (42 C.) and a pressure of about 305 bar (30.5 MPa). If desired, the high pressure recycle CO.sub.2 stream can be again passed through the heat exchanger 221 (or a separate heat exchanger) to increase the temperature thereofe.g., to about 40 F. (5 C.). This heated recycle CO.sub.2 stream then can proceed through the power generating system, as described herein, for recycle back into the combustor of the system.

(9) In further embodiments, one or more elements of a conventional LNG re-gasification system can be combined with a power generation system, such as described herein. An example of a typical system used for converting LNG (e.g., stored in a tank at about 0.05 bar to about 0.1 bar above atmospheric pressure), to pipeline-ready natural gas (e.g., near ambient temperature and up to about 70 bar (7 MPa) pressure) is shown in FIG. 2.

(10) Generally, a conventional LNG re-gasification system utilizes a multistage centrifugal pump to pump the LNG to a high pressure after which it is vaporized in a water bath heat exchanger that is heated by burning natural gas. In the example shown in FIG. 2, LNG is stored in a tank 100. LNG flows out of the base of the tank along LNG supply line 119 and is pressurized in pump 101 to about 70 bar (7 MPa). The pressurized LNG is discharges through line 118 and enters a water bath vaporizer 102, which is maintained at a temperature of about 50 C. to about 90 C. by means of a burner 120 that is fed by a pressurized fuel gas stream 117 comprising a mixture of air provided through air line 109 and natural gas provided through NG burner fuel line 113. The burner 120 has an outlet tube that is submerged up to about 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 thus heating the water. This arrangement leads to the condensation of much of the water produced by combustion of the natural gas, thus increasing the efficiency of the heating system. The cooled combustion gases are vented to the atmosphere along vent line 121. The natural gas fuel is taken from the LNG tank boil-off line 110 as boil-off stream 112, which is compressed to the required burner pressure in an electrically driven boil-off blower 105. The air through 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 remaining LNG tank boil-off stream 110 flows through boil-off compressor line 111 and is compressed to about 69 bar (6.9 MPa) in boil-off compressor 106 to give compressed boil-off NG stream 114, which is mixed with the product natural gas steam 115 exiting the vaporizer 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 about 15 C. The quantity of natural gas consumed in the burner to convert the LNG to pipeline gas typically is about 1.55% of the total natural gas flow in the pipeline stream 116.

(11) A power generation system such as noted herein in relation to the system described in U.S. patent application 2011/0179799 can be particularly improved though integration of the LNG re-gasification system. Such integrated power generation system can use CO.sub.2 as a working fluid in a Brayton cycle power system that operates with an economizer heat exchanger between a high pressure recycle CO.sub.2 stream and a low pressure turbine exhaust stream. In such system, combustion of a 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 between the combustion pressure and the pressure of the turbine exhaust stream can be in the range of about 5 to about 12 or about 5 to about 10. The combustor wherein the fuel is combusted in the presence of oxygen (preferably essentially pure oxygen) can be quenched by the large recycle high pressure working fluid flow, and the stream entering the turbine can be a mixed flow of combustion products and recycle CO.sub.2 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 system and method can provide surprising efficiency arising from a significant amount of heat input to the high pressure recycle CO.sub.2 stream, particularly in the temperature range of about 100 C. to about 400 C. This external heat can be provided, for example, from the heat content of adiabatically compressed air feed to a cryogenic oxygen plant. The system thus can produce a CO.sub.2 net product derived from the fuel at pipeline pressuree.g., about 200 bar (20 MPa) to about 400 bar (40 MPa). As an exemplary embodiment, the use of a natural gas fuel to produce a combustion product stream with a turbine inlet temperature of about 1100 C. to about 1200 C. can provide a net efficiency on a lower heating value (LHV) basis in the range of about 55% to about 60%.

(12) This can be increased even further according to the present disclosure through integration with the LNG re-gasification system. It should be noted that the integration of an LNG vaporization and natural gas pipeline delivery system with a power generation system can apply to a variety of power generation systems, particularly those incorporating a Brayton cycle using an economizer heat exchanger in which a compressor is used to pressurize a recycle of the working fluid that is then reheated in the economizer heat exchanger. In the various embodiments, the working fluid can be, for example, a CO.sub.2 or N.sub.2 rich gas.

(13) An economized Brayton cycle using a power generation system as discussed above can require the compression of approximately 30 times the molar flow of a natural gas fuel for a typical plant having a turbine with an inlet condition of about 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 water condensation and separation of about 20 C. The power required to compress the recycle CO.sub.2 stream and the net CO.sub.2 product stream to the range of 305 bar (30.5 MPa) is about 14.8% of the total turbine power output. The CO.sub.2 compressor power requirement can be reduced by liquefying the CO.sub.2 stream at a pressure of about 29 bar (2.9 MPa) and cooling the liquid CO.sub.2 to within about 10 C. of its solidification temperature as this can maximize the density of the CO.sub.2 stream. After the pressurization and liquefaction, the liquid CO.sub.2 stream can be pumped to a pressure of about 305 bar (30.5 MPa), and the high pressure CO.sub.2 can be heated back to ambient temperature. This procedure can reduce the CO.sub.2 compression power to about 5.3% of the total turbine power output. In such an exemplary embodiment, the net cycle efficiency on an LHV basis can be increased from about 58.8% to about 65.7%.

(14) The refrigeration required to achieve such increased efficiency in the power generation system and method can be derived from any source that would be recognized as being useful in light of the present disclosure. In reference to FIG. 2, the required refrigeration can be supplied to the power generation system and method via heat exchange from the heating of the high pressure LNG stream 118 leaving the pump 101.

(15) In an exemplary embodiment, a low pressure CO.sub.2 stream from a power generation system can be dried, and the dried CO.sub.2 stream then can be liquefied and sub-cooled (e.g., in a diffusion bonded stainless steel high pressure heat exchanger, such as a Heatric Heat Exchanger) against the LNG stream, which in turn receives heating. If needed, in order to prevent freezing of the CO.sub.2 and blocking of the heat exchanger passages, a fraction of the outlet natural gas stream 115 exiting the water bath vaporizer 102 at a temperature of about 20 C. to about 0 C. can be recycled and mixed with the cold compressed LNG stream 118 (which is at a temperature of about 160 C.) to produce a natural gas stream that is within about 10 C. above the freezing temperature of the CO.sub.2 stream. A natural gas fuel stream entering a combustor in a power generation system as discussed above preferably is at a pressure noted above, for example, about 305 bar (30.5 MPa). If desired, the natural gas can be derived from the LNG supply, and the fuel natural gas stream can be provided using a second LNG pump taking its flow from line 118. The natural gas fuel stream can be heated to ambient temperature firstly (for example) against the cooling, liquefying, and sub-cooling CO.sub.2 stream. Secondly, the natural gas fuel stream then can flow through a second heat exchanger to cool a closed cycle cooling water flow, which can be used in an oxygen plant air compressor inter and after-coolers. This use of a cryogenic LNG pump rather than a natural gas compressor can increase efficiency by a further 0.9% of the total turbine power. Using the natural gas to liquefy and sub-cool the CO.sub.2 can impose a maximum temperature on the heated natural gas of about 10 C. because of the temperature pinch at the CO.sub.2 freezing temperaturei.e., 56 C. The natural gas can be heated to about 15 C., which can be useful for delivery to a natural gas pipeline, by using it as a cooling stream against the turbine exhaust stream leaving the cold end of the economizer heat exchanger in the power generation system before liquid water separation. This can significantly reduce the residual water content in the gas phase which in turn reduces the size and cost of the desiccant drier which can be required to prevent water ice deposition in the CO.sub.2 liquefier heat exchanger.

(16) The integration of a power generation system as discussed above with an LNG vaporizing system preferably can include all necessary components to prevent interruptions in power generation as well as natural gas flow to the pipeline. For example, it can 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 on and at or near operating temperature to provide for rapid switch-over to take up the LNG load being heated in integrated power generation system if the power generation system goes offline. This can prevent any significant fluctuations in pipeline supply pressure and maintain such pressure within the required tolerance. Similarly any failure of the pressurized LNG flow (such as, for example, a malfunction of pump 101) can be handled. For example, in the example of pump malfunction, LNG flow can be immediately switched to a parallel LNG pump which can be present in an LNG send-out facility. Preferably, such changeover can be carried out within about 5 to about 10 seconds to allow continuous operation of the power generation system.

(17) An exemplary embodiment of a power generation system (using a pressurized natural gas fuel supply) integrated with a LNG vaporization and pressurized natural gas supply system is shown in FIG. 3. The discussion of FIG. 3 below illustrates the system and method in relation to a specific embodiment, and certain values and ranges should not be viewed as limiting. Rather, one of skill in the art reviewing the following in light of the present disclosure as a whole will recognize that various values can be changed based upon the specific operating conditions of the power generating system and the LNG vaporization system. The full scope of such ranges is intended to be encompassed by the following discussion, which is exemplary in nature and provided to meet all disclosure requirements.

(18) The power generation system comprises a combustor 1 that combusts the natural gas fuel with oxygen in the presence of a recycled CO.sub.2 working fluid to form a combustion product stream 6 that is rich in CO.sub.2. In this example, the combustion product stream is at a pressure of about 300 bar (30 MPa) and a temperature of about 1150 C. The combustion product stream 6 enters a power turbine 2 driving a turbine electrical generator 3 producing an electrical output 4 together with additional shaft power that is used to drive a liquid CO.sub.2 pump 5. A turbine discharge flow stream 15 at a temperature of about 788 C. and a pressure of about 30 bar (3 MPa) is cooled in an economizer heat exchanger 46 to provide an initially cooled turbine discharge flow stream 16 at a temperature of about 25 C. The initially cooled turbine discharge stream 16 is further cooled in a low temperature heat exchanger 17 and exits as the secondly cooled turbine discharge stream 51 at a temperature of about 4 C. This is achieved against a cooling natural gas stream 56, which is part of the total natural gas stream 57 leaving the CO.sub.2 liquefier 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 at a temperature of about 20 C., and this stream joins with the total product pipeline natural gas stream 30 leaving the LNG facility (e.g., at a temperature of about 10 C. or greater). The secondly cooled turbine discharge stream 51 passes into a liquid water separator 18, and a condensed water stream 19 is thereby removed from the secondly cooled turbine discharge stream 51. The separated CO.sub.2 gas stream 20 is dried to a dew point of about 60 C. in a thermally regenerated desiccant drier 54. Other water removal systems, such as pressure swing adsorption (PSA) units also can be used. The dried CO.sub.2 gas stream 55 is cooled to liquefaction, and the liquid CO.sub.2 is sub-cooled to about 50 C. (e.g., 56 C. or greater) in the CO.sub.2 liquefier heat exchanger 21 (e.g., a stainless steel diffusion bonded Heatric type heat exchanger), which simultaneously heats a pre-heated LNG product stream 44 at a pressure of about 68.9 bar (6.89 MPa) to a temperature of about 9.4 C. to form total natural gas stream 57. From the total natural gas stream 57 is divided an LNG heating natural gas fraction 39, which is compressed in an electrically driven blower 40. A thereby formed compressed LNG-heating natural gas stream 45 is mixed with the compressed LNG product stream 43, which is the major fraction of the compressed LNG, to form pre-heated LNG product stream 44, which enters the CO.sub.2 liquefier heat exchanger 21 at a temperature that is above the CO.sub.2 freezing temperature of 56 C. (e.g., to a temperature 55 C. or greater). This arrangement with dry CO.sub.2 and heated LNG can be particularly useful to prevent freezing of the CO.sub.2 to block or damage to the CO.sub.2 liquefier heat exchanger 21.

(19) In the present example, the LNG is stored at a pressure of about 0.08 bar (0.8 MPa) in LNG tank 33. A LNG tank discharge stream 50 is pumped to a pressure of about 70 bar (7 MPa) in LNG pump 25 driven by an electric motor 34. An LNG discharge stream 26 can pass through a water bath heater 24 to provide a bath heated natural gas stream 31 at a temperature of about 15 C. The water bath is heated by a bath fuel gas stream 27 that is burned in air in a draught tube burner with the combustion gases passing through the water and discharging through a bath stack 28. Flow of the compressed LNG stream 32 can be controlled as desired. For example, first control valve 29 and second control valve 49 can be used to determine the routing of the LNG. These, in combination with a variety of further pumps and water bath heaters in the LNG facility (not illustrated), can be used to alternate the flow path of the LNG stream to ensure continuous supply of LNG to the power generation system if the LNG pump 25 goes offline and continuous heating of all the compressed LNG to pipeline conditions if the power generation system goes offline. Such safety back-up provisions are described further herein.

(20) In the present example, the natural gas used as the fuel in the combustor 1 of the power generation system can be drawn from the compressed LNG stream as LNG fuel fraction 41 and pumped to a pressure of about 306 bar (30.6 MPa) in an LNG fuel pump 48 (e.g., a multi-cylinder reciprocating electrically driven pump). A high pressure LNG fuel stream 70 is heated to about 10 C. in the CO.sub.2 liquefier heat exchanger 21 and exits as high pressure natural gas fuel stream 62. Such heating is against the cooling, liquefying and sub-cooling CO.sub.2. 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 adiabatically compressed air from air stream 81 using a closed cycle heat transfer fluid, which can be beneficial to prevent leaking of flammable gas into the air separation plant. The exiting, heated, high pressure natural gas stream 11 then proceeds to the combustor 1. The cryogenic air separation plant can include a first stage adiabatic main compressor with a discharge pressure of about 4 bar (0.4 MPa) and a booster compressor where about one third of the first stage compressed air is compressed in two adiabatic stages to about 100 bar (10 MPa). The bulk of the adiabatic heat of compression is transferred firstly to a high pressure recycle CO.sub.2 side stream 13 taken from the high pressure CO.sub.2 recycle stream being heated in the economizer heat exchanger 46. The high pressure recycle CO.sub.2 side stream can be taken at a temperature of about 110 C. and returned as super-heated high pressure recycle CO.sub.2 side stream 12 at a temperature of about 149 C. The adiabatic heat of compression of the two adiabatic stages is secondly used to heat the high pressure natural gas fuel stream 62 to a temperature of about 230 C. to form the heated high pressure natural gas fuel stream 11. The heat of compression is thirdly used to heat the oxygen product stream 63 at a pressure of about 305 bar (30.5 MPa) from the air separation plant to a temperature of about 230 C.

(21) Leaving the cold end of the CO.sub.2 liquefier heat exchanger 21 is a sub-cooled CO.sub.2 recycle stream 22. This stream is compressed to about 306 bar (30.6 MPa) in the liquid CO.sub.2 pump 5, which can be coupled through a gear box directly to the turbine electrical generator 3. Alternatively, a booster compressor (not illustrated) in the cryogenic air separation plant can be directly coupled to the turbine electrical generator 3. As a further alternative, main air compressor in the air separation plant can be directly coupled to the turbine electrical generator. It is preferably for the turbine to be directly loaded with a power demand from one of these alternatives so that in the event of an electrical disconnection from the electricity grid (e.g., arising from a generator trip), there is a load on the generator that will function as a brake since high pressure turbine feed gas will flow until system pressures equalize.

(22) The pressurized sub-cooled CO.sub.2 recycle stream 23 at a temperature of about 43 C. is then heated in the CO.sub.2 liquefier heat exchanger 21 to a temperature of about 5.5 C. The high pressure recycle CO.sub.2 stream 68 is heated to a temperature of about 25 C. in a supplemental CO.sub.2 heat exchanger 66 to form a pre-heated high pressure recycle CO.sub.2 stream 67. A heated, closed cycle heat transfer fluid stream 64 at a temperature of about 40 C. is cooled to a temperature of about 10 C. to exit as cooled heat transfer fluid stream 65. In a similar fashion, a total natural gas stream fraction 38 at a temperature of about 9.4 C. can be passed through a secondary natural gas heat exchanger 35 to be heated against a second heated, closed cycle heat transfer fluid stream 36 at about 40 C. A secondary cooled heat transfer fluid stream 37 exits at a temperature of about 10 C.

(23) The pre-heated high pressure recycle CO.sub.2 stream 67 leaving supplemental CO.sub.2 heat exchanger 66 is divided into a first high pressure recycle CO.sub.2 fraction 14 and a second high pressure recycle CO.sub.2 fraction 53, which both pass through the economizer heat exchanger 46 and exit at a temperature of about 752 C. Recycle CO.sub.2 fraction control valve 52 at the cold end of economizer heat exchanger 46 controls the flow ratio of the first CO.sub.2 fraction 14 to the second CO.sub.2 fraction 53. The heated, first CO.sub.2 fraction stream 7 is delivered to the combustor 1 as the working fluid. The heated, second CO.sub.2 fraction stream 9 mixes with the oxygen product stream 63 to give a 30% oxygen, 70% CO.sub.2 molar ratio in the oxidant stream 10 entering the combustor 1, which moderates the adiabatic flame temperature to a value below about 3000 C. The net CO.sub.2 product derived from the combusted fuel is available as a pipeline ready CO.sub.2 product stream 77 at a pressure of about 305 bar (30.5 MPa) and a temperature of about 25 C.

(24) Performance values based on a 250 MW net electrical output were calculated for the above exemplary integrated system using pure methane from the LNG source as the fuel for the combustor. Calculated values were as follows:

(25) $\begin{array}{c}\mathrm{Natural}\mathrm{gas}\mathrm{burned}\mathrm{in}\mathrm{NET}\mathrm{Power}\mathrm{system}=380.4\mathrm{MW}\\ =34.269\mathrm{mmscfd}\end{array}$$\mathrm{Natural}\mathrm{gas}\mathrm{heated}\mathrm{in}\mathrm{NET}\mathrm{Power}\mathrm{system}=1095.9\mathrm{mmscfd}$$\mathrm{Saving}\mathrm{in}\mathrm{natural}\mathrm{gas}\mathrm{for}\mathrm{water}\mathrm{bath}\mathrm{heater}=16.986\mathrm{mmscfd}$

(26) Based on the foregoing, modeling was used to calculate efficiencies for a 1000 MW net electrical power generating system with an integrated LNG system as discussed above providing 1000 mmscfd natural gas flow rate at 68 bar (6.8 MPa) delivered to a pipeline at 15 C. Calculated overall efficiency was 68.06%. Calculated overall efficiency with a zero LNG flow rate to the 1000 MW power plant was 58.87%. In still a further embodiment modeled using Aspen Plus, a system and method according to the present disclosure used a methane fuel in the combustor, a turbine, a first heat exchanger (which was a series of three heat exchange units), a water separator, a second heat exchanger where CO.sub.2 was liquefied against LNG to produce NG (with a side stream being used to pre-heat the LNG), a single pump to pressurize the recycle CO.sub.2 stream, and recovered heat from an air separation plant to supplement heating of the recycle CO.sub.2 stream. In the model of such embodiment, the overall efficiency of the integrated power generating and LNG vaporizing system and method was 65.7%. All of the above efficiency calculations encompass the complete capture of all excess CO.sub.2 from combustion.

(27) The benefit is further seen in relation to conventional LNG re-gasification systems wherein, typically, about 1.4% of the LNG that is processed is burned to provide heating, such as in the submerged burner described in relation to FIG. 2, for the remaining 98.6% of the processed LNG. This duty is imposed without any added benefit. According to the present disclosure, however, a 250 MWe power generating system, for example, can be integrated with a LNG re-gasification plant. In such example, the LNG plant can reheat approximately 10.8 B m.sup.3/year of LNG while burning approximately 3.1% to provide the heat. Because of the integration, although total gas sendout is reduced to 96.9% of the total amount processed, the increased duty fuels the generation of the electricity in the 250 MW power plant. Beneficially, such systems can be scaled as desired to increased or decreased capacity in relation to processed LNG and/or produced electricity.

(28) Many modifications and other embodiments of the inventions set forth herein will come to mind to one skilled in the art to which these inventions pertain having the benefit of the teachings presented in the foregoing descriptions. Therefore, it is to be understood that the inventions are not to be limited to the specific embodiments disclosed and that modifications and other embodiments are intended to be included within the scope of the appended claims. Although specific terms are employed herein, they are used in a generic and descriptive sense only and not for purposes of limitation.

DESCRIPTION OF THE REFERENCE NUMERALS

(29) 1 combustor 2 power turbine 3 turbine electrical generator 4 electrical output 5 liquid CO.sub.2 pump 6 combustion product stream 7 heated, first CO.sub.2 fraction stream 9 heated second CO.sub.2 fraction stream 10 oxidant stream 11 natural gas stream 12 super-heated high pressure recycle CO.sub.2 side stream 13 high pressure recycle CO.sub.2 side stream 14 first high pressure recycle CO.sub.2 fraction 15 turbine discharge flow stream 16 initially cooled turbine discharge flow stream 17 low temperature heat exchanger 18 liquid water separator 19 condensed water stream 20 separated CO.sub.2 gas stream 21 CO.sub.2 liquefier heat exchanger 22 sub-cooled CO.sub.2 recycle stream 23 pressurized sub-cooled CO.sub.2 recycle stream 24 water bath heater 25 LNG pump 26 LNG discharge stream 27 bath fuel gas stream 28 bath stack 29 first control valve 30 total product pipeline natural gas stream 31 bath heated natural gas stream 32 compressed LNG stream 33 LNG tank 34 electric motor 35 secondary natural gas heat exchanger 36 secondary heated, closed cycle heat transfer fluid 37 secondary cooled heat transfer fluid 38 total natural gas stream fraction 39 LNG-heating natural gas fraction 40 blower 41 LNG fuel fraction 43 compressed LNG product stream 44 pre-heated LNG product stream 45 compressed LNG-heating natural gas stream 46 economizer heat exchanger 47 air separation plant 48 LNG fuel pump 49 second control valve 50 LNG tank discharge stream 51 secondly cooled turbine discharge stream 52 recycle CO.sub.2 control valve 53 second high pressure recycle CO.sub.2 fraction 54 thermally regenerated desiccant drier 55 dried CO.sub.2 gas stream 56 cooling natural gas stream 57 total natural gas stream 62 high pressure natural gas fuel stream 63 oxygen product stream 64 heated, closed cycle heat transfer fluid stream 65 cooled heat transfer fluid stream 66 supplemental CO.sub.2 heat exchanger 67 pre-heated high pressure recycle CO.sub.2 stream 68 high pressure recycle CO.sub.2 stream 70 high pressure LNG fuel stream 71 partial product natural gas stream 77 CO.sub.2 product stream 100 tank 101 pump 102 water bath vaporizer 103 filter 104 burner pressure blower 105 boil-off blower 106 boil-off compressor 107 atmospheric air line 109 air line 110 LNG tank boil-off line 111 boil-off compressor line 112 boil-off stream 113 NG burner fuel line 114 compressed boil-off NG stream 115 product natural gas stream 116 total natural gas pipeline flow stream 117 pressurized fuel gas stream 119 LNG supply line 120 burner 121 vent line 210a LNG supply 210b heated LNG supply 221 heat exchanger 239 supplement NG stream 240 blower 257 NG stream 258 product NG stream