Systems and methods for power production with integrated production of hydrogen

Abstract

The present disclosure relates to systems and methods useful for power production. In particular, a power production cycle utilizing CO.sub.2 as a working fluid may be configured for simultaneous hydrogen production. Beneficially, substantially all carbon arising from combustion in power production and hydrogen production is captured in the form of carbon dioxide. Further, produced hydrogen (optionally mixed with nitrogen received from an air separation unit) can be input as fuel in a gas turbine combined cycle unit for additional power production therein without any atmospheric CO.sub.2 discharge.

Claims

1. A method for combined power production and hydrogen production, the method comprising: carrying out the power production in a power production unit comprising: combusting a first hydrocarbon fuel in a first combustor with an oxidant in the presence of a recycled CO.sub.2 stream at a combustion pressure to provide a combustion product stream including CO.sub.2; expanding the combustion product stream including CO.sub.2 across a turbine to produce power and form a turbine discharge stream including CQ.sub.2; cooling the turbine discharge stream including CO.sub.2, in a recuperative heat exchanger; separating the CO.sub.2 from any further components of the turbine discharge stream to provide a stream comprising the recycled CO.sub.2; compressing the stream comprising the recycled CO.sub.2 to substantially the combustion pressure to provide a compressed recycled CO.sub.2 stream; heating the compressed recycled CO.sub.2 stream in the recuperative heat exchanger, with heat withdrawn from the turbine exhaust stream to provide a heated stream comprising the recycled CO.sub.2; and passing the heated stream comprising the recycled CO.sub.2 to the first combustor; and carrying out the hydrogen production in a hydrogen production unit comprising: passing a stream of a second hydrocarbon fuel through a partial oxidation reactor to form a synthesis gas stream; processing the synthesis gas stream to provide a stream of substantially pure hydrogen and a waste stream comprising at least carbon monoxide; and passing at least the carbon monoxide from the waste stream to the first combustor.

2. The method of claim 1, wherein the processing the synthesis gas stream comprises passing the synthesis gas stream through a reformer that is also configured to receive the stream of the second hydrocarbon fuel gas and a stream of heated water.

3. The method of claim 2, wherein one or more of the stream of the second hydrocarbon fuel passing through the partial oxidation reactor, the stream of the second hydrocarbon fuel received by the reformer, and the stream of the heated water that is received by the reformer is heated in a supplemental heat exchanger utilizing heat transferred from the turbine discharge stream including CO.sub.2.

4. The method of claim 2, wherein the processing the synthesis gas stream comprises passing reformed synthesis gas from the reformer through a shift reactor followed by a shift stream heat exchanger.

5. The method of claim 4, wherein the second hydrocarbon fuel is provided to one or both of the partial oxidation reactor and the reformer via a hydrocarbon fuel line that passes through the shift stream heat exchanger.

6. The method of claim 4, wherein the stream of heated water received in the reformer is provided through a water line that passes through the shift stream heat exchanger.

7. The method of claim 4, further comprising passing a stream exiting the shift stream heat exchanger through a water separator to remove water and form a crude hydrogen stream including hydrogen and impurities.

8. The method of claim 7, further comprising passing the crude hydrogen stream through a pressure swing adsorption unit that outputs the substantially pure hydrogen and the waste stream.

9. The method of claim 1, wherein the waste stream is compressed to a pressure suitable for input to the combustor of the power production unit and then passed to the combustor of the power production unit.

10. The method of claim 1, wherein the power production unit further comprises an additive heat exchanger that heats the recycled CO.sub.2 stream against one or more compressed streams from the power production unit.

11. The method of claim 10, further comprising passing a heated stream from the hydrogen production unit through the additive heat exchanger such that heat from the hydrogen production unit is transferred to the recycled CO.sub.2 stream.

12. The method of claim 11, wherein the heat that is transferred from the hydrogen production unit to the recycled CO.sub.2 stream is at a temperature level below about 400° C.

13. The method of claim 1, wherein at least a portion of the turbine discharge stream including CO.sub.2 is passed through a second combustor with a stream of the first hydrocarbon fuel and oxygen so that the first hydrocarbon fuel is combusted to provide additional heat to at least a portion of the turbine discharge stream including CO.sub.2.

14. The method of claim 13, wherein at least part of the additional heat provided to at least a portion of the turbine discharge stream including CO.sub.2 is provided to one or more streams in the hydrogen production unit.

15. The method of claim 1, further comprising carrying out power production in a gas turbine that is separate from the power production unit wherein at least a portion of the substantially pure hydrogen is combusted in the gas turbine to produce power.

16. A method for combined power production and hydrogen production, the method comprising: carrying out the power production in a power production unit comprising: combusting a first hydrocarbon fuel in a first combustor with an oxidant in the presence of a recycled CO.sub.2 stream at a combustion pressure to provide a combustion product stream including CO.sub.2; expanding the combustion product stream including CO.sub.2 across a turbine to produce power and form a turbine discharge stream including CQ.sub.2; cooling the turbine discharge stream including CO.sub.2 in a recuperative heat exchanger; separating the CO.sub.2 from any further components of the turbine discharge stream to provide a stream comprising the recycled CO.sub.2; compressing the stream comprising the recycled CO.sub.2 to substantially the combustion pressure to provide a compressed recycled CO.sub.2 stream; heating the compressed recycled CO.sub.2 stream in the recuperative heat exchanger, with heat withdrawn from the turbine exhaust stream to provide a heated stream comprising the recycled CO.sub.2; and passing the heated stream comprising the recycled CO.sub.2 to the first combustor; and carrying out the hydrogen production in a hydrogen production unit comprising: passing a stream of a second hydrocarbon fuel through a partial oxidation reactor to form a synthesis gas stream; and processing the synthesis gas stream to provide a stream of substantially pure hydrogen and a waste stream comprising at least carbon monoxide; wherein the waste stream is compressed to a pressure suitable for input to the combustor.

Description

BRIEF DESCRIPTION OF THE DRAWINGS

(1) Having thus described the disclosure in the foregoing general terms, reference will now be made to the accompanying drawings, which are not necessarily drawn to scale, and wherein:

(2) FIG. 1 is a flow diagram of an exemplary system and method of power production using a CO.sub.2 working fluid and including a cryogenic oxygen plant;

(3) FIG. 2 is a flow diagram of a hydrogen production facility including elements for integration with a power production system and method, such as illustrated in FIG. 1; and

(4) FIG. 3 is a flow diagram illustrating a combined system wherein nitrogen gas from the air separation unit and hydrogen gas from the hydrogen generation unit are input to a gas turbine combined cycle unit.

DETAILED DESCRIPTION

(5) The present subject matter will now be described more fully hereinafter with reference to exemplary embodiments thereof. These exemplary embodiments are described so that this disclosure will be thorough and complete, and will fully convey the scope of the subject matter to those skilled in the art. Indeed, the subject matter can 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.

(6) The present disclosure provides systems and methods wherein power production and hydrogen production are simultaneously achieved. Previous efforts have been undertaken to provide for simultaneous production of power and hydrogen, and one or more elements from such previous endeavors may be integrated into the presently disclosed systems and methods. For example, U.S. Pat. No. 6,534,551 to Allam et al. describes the combination of: 1) a hydrocarbon fuel gas reaction with steam and or oxygen; and 2) a power system utilizing a compressed oxidant gas in which a fuel gas is burned with combustor products producing power by work expansion and in which the expanded combustion product gas is used to superheat the steam used in hydrogen synthesis reactions and in which the oxygen production unit is driven by at least a portion of the power produced by the expansion of the combustion product gas. The disclosure of U.S. Pat. No. 6,534,551 to Allam et al. is incorporated herein by reference.

(7) In one or more embodiments, the present systems and methods can beneficially provide for hydrogen production in combination with power production with capture of substantially all of the carbon produced, particularly substantially all of the CO.sub.2 produced. The combination can be a single system with a combination of elements suitable to achieve the simultaneous production of hydrogen and power. In some embodiments, a hydrogen production system or unit can be operated in parallel with a power production system or unit with the appropriate crossover of elements so that the two systems or units are functioning as a single, integrated system. In this manner, the present disclosure may refer to a hydrogen plant, and it is understood that such hydrogen plant refers to the combination of elements necessary to form the hydrogen production system or unit utilized herein.

(8) A power production cycle useful according to the present disclosure can include any system and method wherein CO.sub.2 (particularly supercritical CO.sub.2— or sCO.sub.2) is used in a work stream. As a non-limiting example, U.S. Pat. No. 8,596,075 to Allam et al., which is incorporated herein by reference, describes a system and method wherein a recycle CO.sub.2 stream is directly heated and used in power production. Specifically, the recycle CO.sub.2 stream is provided at high temperature and high pressure, is provided to a combustor wherein a carbonaceous fuel is combusted in oxygen, is expanded across a turbine to produce power, is cooled in a heat exchanger, is purified to remove water and any other impurities, is pressurized, is re-heated using the heat taken from the turbine exhaust, and is again passed to the combustor to repeat the cycle. Such system and method are beneficial in that all fuel and combustion derived impurities, excess CO.sub.2, and water are removed as a gaseous or supercritical fluid, a liquid or a solid (e.g., ash), and there is virtually zero atmospheric emission of any streams. The system and method achieves high efficiency through, for example, the use of low temperature level (i.e., less than 500° C.) heat input after the recycle CO.sub.2 stream has been re-pressurized and before combustion (i.e., low temperature level heat added to the recycle CO.sub.2 stream in addition to the recuperated heat from the turbine exhaust stream). It is understood that reference to a power production cycle herein indicates a power production cycle utilizing a CO.sub.2 working fluid and the combination of elements and method steps described herein and in the incorporated documents.

(9) A power production cycle useful according to the present disclosure can include more steps or fewer steps than described above and can generally include any cycle wherein a high pressure recycle CO.sub.2 stream is expanded for power production and recycled again for further power production. As used herein, a high pressure recycle CO.sub.2 stream can have a pressure of at least 100 bar (10 MPa), at least 200 bar (20 MPa), or at least 300 bar (30 MPa). In all instances, the upper limit on pressure may be dictated by the limits of the available equipment at the time of implementation of a system and/or method according to the present disclosure. A high pressure recycle CO.sub.2 stream can, in some embodiments, have a pressure of about 100 bar (10 MPa) to about 500 bar (50 MPa), about 150 bar to about 450 bar (45 MPa), or about 200 bar (20 MPa) to about 400 bar (40 MPa). Reference to a high pressure recycle CO.sub.2 stream herein may thus be a CO.sub.2 stream at a pressure within the foregoing ranges. Such pressures also apply to references to other high pressure streams described herein, such as a high pressure work stream comprising CO.sub.2. Combustion may be carried out at a temperature of about 400° C. or greater, about 500° C. or greater, about 600° C. or greater, about 800° C. or greater, or about 1000° C. or greater. In all instances, the upper limit on temperature may be dictated by the limits of the available equipment at the time of implementation of a system and/or method according to the present disclosure. In some embodiments, the first combustor outlet temperature following mixing with recycle CO.sub.2 can be about 400° C. to about 1,500° C., about 500° C. to about 1200° C., or about 600° C. to about 1000° C.

(10) In some embodiments, integration of a power production cycle as described above with a hydrogen production facility can utilize the excess low temperature level heat produced by the hydrogen plant in order to increase the efficiency of power production. For example, superheating of the steam and hydrocarbon feed in the turbine exhaust stream can be carried out with an increase in turbine power output in the power production system and method. Further, the hydrogen plant can be integrated with the power production cycle so that substantially all of the CO.sub.2 derived from carbon present in the hydrocarbon fuel feed into the hydrogen plant or system is captured and, optionally, combined with the CO.sub.2 captured from the power production cycle plant or system. The integrated system captures up to 100% of the CO.sub.2 produced from both the power and H.sub.2 plants with zero emission to the atmosphere.

(11) A hydrogen production plant for use according to the present disclosure can incorporate any variety of elements known to be suitable in prior hydrogen production plants. For example, a hydrogen production plant can comprises a two stage reactor system including a first stage reactor which converts a hydrocarbon feed to a CO+H.sub.2 gas using partial oxidation of the hydrocarbon with oxygen and optionally with the additional use of steam. In some embodiments, such partial oxidation (PDX) of a natural gas feed with pure oxygen can be carried out at an outlet temperature of about 1300° C. to about 1500° C. at typical pressures of about 30 bar to about 150 bar. An auto-thermal reformer (ATR) can add steam and excess hydrocarbon, generally natural gas, after the partial oxidation burner so that the high temperature gases can then pass through a bed of catalyst where subsequent steam-hydrocarbon reforming reactions take place yielding further H.sub.2+CO and cooling the gas mixture to an outlet temperature of about 1000° C. to about 1100° C. at pressures of about 30 bar to about 150 bar. The second stage reactor can comprise a steam/hydrocarbon catalytic reformer in which the total H.sub.2+CO gas product from both reactors (e.g., at a temperature of about 1000° C. or greater) is used to provide the endothermic heat of the reforming reactions in a convectively heated shell side flow with catalyst in the tubes. Optionally the two reactors can operate in a series or parallel mode. A favorable configuration uses a vertical gas heated reformer (GHR) with catalyst filled open ended tubes hanging from a single tube sheet at the top of the vessel, with the product H.sub.2+CO leaving the reformer tubes and mixing with the product gas from a PDX reactor or an ATR in the base of the GHR, and the total product H.sub.2+CO stream passing through the shell side and cooling typically from about 1050° C. to 550° C. to 800° C.

(12) An advantage of the two reactor configuration is that the yield of H.sub.2+CO from hydrocarbon feed is maximized, and all CO.sub.2 formed in the reactions is contained within the high-pressure system. The product CO+H.sub.2 gas is further cooled in a steam generating waste heat boiler (WHB), and a further advantage is that this steam quantity is only sufficient to provide the required steam flow to the two H.sub.2+CO reactors with only a small excess flow. The system has no large by-product steam production.

(13) To generate hydrogen, the H.sub.2+CO product leaving the WHB at a typical temperature of about 240° C. to about 290° C. and containing typically about 20% to about 40% (molar) steam is passed through one or more catalytic shift converters where CO reacts with steam to produce CO.sub.2 and additional H.sub.2. The reactions for the whole H.sub.2 production process sequence are shown below (using CH.sub.4 as the hydrocarbon)
CH.sub.4+½O.sub.2.fwdarw.CO+2H.sub.2  Partial oxidation
CH.sub.4+2O.sub.2.fwdarw.CO.sub.2+2H.sub.2O  Heat generation
CH.sub.4+H.sub.2O.fwdarw.CO+3H.sub.2  Reforming
CH.sub.4+CO.sub.2.fwdarw.2CO+2H.sub.2  Reforming
CO+H.sub.2O.fwdarw.CO.sub.2+H.sub.2  CO shift

(14) The total CO+H.sub.2 product passing through the CO shift reactors is cooled, and a significant amount of heat is released generally at a temperature level of about 290° C. or lower as the gas cools and steam condenses. This heat is released not at a single temperature level but over a temperature range down to near ambient temperature. Part of this heat release can be used to preheat boiler feed water, but there is a large excess quantity that is at a low temperature level and only available over a temperature range.

(15) The efficiency of the H.sub.2+CO generation in the two reactors can be significantly increased by preheating the hydrocarbon and steam feeds to typically about 400° C. to about 550° C. and preferably to about 500° C. to about 550° C. This preferably is done using an external heat source since no excess heat at these temperature levels is available within the H.sub.2+CO generation reactors plus WHB.

(16) The cooled H.sub.2 rich gas stream is next passed through a cooler (e.g., an ambient cooler) where condensed water is removed. The gas stream is then passed to a separator wherein substantially pure hydrogen can be isolated. For example, the gas stream can be passed through a conventional multi-bed pressure swing adsorber which separates typically about 85% to about 90% (molar) of the hydrogen as a pure stream having typically about 10 ppm to about 50 ppm total impurities and having a drop in pressure from feed to product H.sub.2 of typically about 1 bar to about 2 bar. All the impurities in the crude H.sub.2 feed stream are separated as a waste fuel gas stream, which waste stream can comprise any combination of components, such as H.sub.2, CO, CO.sub.2, CH.sub.4, N.sub.2, argon, and a small quantity of vapor phase H.sub.2O. The pressure is typically about 1.1 bar to about 1.5 bar. This waste gas typically has about 20% of the total hydrocarbon reactor hydrocarbon feed lower heating value (LHV) so its efficient use is advantageous to the overall economics of H.sub.2 production. The waste gas contains all the carbon from the total hydrocarbon feed as CO.sub.2+CO and the recovery of this carbon as pure CO.sub.2 at pipeline high pressure is likewise advantageous to meet climate change emission objectives.

(17) The integration of the high-pressure, two-reactor hydrogen generation system with power production cycle utilizing a CO.sub.2 working stream can achieve a variety of benefits. The turbine exhaust from the power production cycle is typically in the range of about 700° C. to about 800° C. The steam and hydrocarbon feeds to the two reactors can be preheated to a range of about 500° C. to about 550° C. utilizing part of the turbine exhaust flow in a separate heat exchanger. This simply requires an increase in the fuel burned in the turbine combustor to provide the extra heat required. This increases the turbine inlet temperature and flow rate and provides a significant additional power output from the turbine. The steam and hydrocarbon or carbonaceous fuel can be heated to a typical temperature of about 400° C. to about 550° C. while the turbine exhaust can be cooled to a typical temperature of about 700° C. to about 800° C. before entering the recuperative heat exchanger.

(18) As an alternative arrangement, a second combustor can be provided to preheat at least part of the turbine exhaust stream to deliver the heat required for preheating the fuel and steam required for the generation of synthesis gas in the two stage reactor system. One combustor arrangement uses an oxidant comprising substantially pure O.sub.2 diluted with CO.sub.2 to produce an oxidant containing 20% to 30% molar O.sub.2 to burn the fuel. A second combustor arrangement uses an O.sub.2 ion transport membrane reactor that diffuses substantially pure O.sub.2 derived from a preheated low pressure air stream into at least a portion of the turbine exhaust to which has been added a controlled portion of the fuel so that the temperature is increased as desired for H.sub.2 plant preheat duty.

(19) The waste gas from the PSA can be compressed to typically about 200 bar to about 400 bar and mixed with the feed hydrocarbon and used very efficiently as fuel gas in the power production cycle. An additional advantage is that the carbon from the hydrocarbon reactor feeds can be captured as CO.sub.2 within the power production cycle system. A further advantage is the large mass flow of the waste gas due to its high CO+CO.sub.2 content of typically about 50% to about 70% (molar) that increases extra turbine power. Alternatively the waste gas from the PSA can be compressed to the inlet pressure of the first PSA, the CO.sub.2 can be removed in one of a number of known processes, and the CO.sub.2 depleted gas stream can be sent to a second PSA to separate more H.sub.2 to add to the total H.sub.2 product stream. Optionally the waste gas can be preheated in an economizer heat exchanger, steam can be added, and more H.sub.2 can be produced in an additional catalytic CO shift reactor. The gas can then be cooled in the economizer heat exchanger before being processed to separate more H.sub.2 in the second PSA.

(20) The significant quantity of low grade heat available from the cooling H.sub.2+CO stream is ideally suited to provide the low temperature level heat that can be added to the power production cycle to augment the recuperated heat from the turbine exhaust and thus achieve a high efficiency. Specifically, the “low grade” heat from the cooling H.sub.2+CO stream can be at a temperature level of about 200° C. to about 400° C., about 220° C. to about 350° C., and particularly about 240° C. to about 290° C. Depending on H.sub.2 output, this can result in the power production cycle oxygen plant main air compressor being a conventional inter-cooled compressor rather than an adiabatic unit with significant parasitic power reduction in the power production cycle. It will also lead to lower hot CO.sub.2 compressor flow with further parasitic power reductions. The availability of this excess heat over a temperature range as noted above (and down to near ambient) suits the heating of a side-stream of high pressure recycle CO.sub.2 over a similar temperature range. The integration system defined is equally applicable to power production cycle systems utilizing conventional cryogenic oxygen production plus an oxy-fuel combustor or to systems utilizing oxygen ion combustors.

(21) Integrated power production and hydrogen production according to the present disclosure is described hereafter in relation the various figures. In particular, FIG. 1 illustrates a power production cycle system having a cryogenic oxygen plant and using a natural gas fuel. Although the system is described below in relation to operating parameters corresponding to an exemplary embodiment, it is understood that the power production cycle can be as defined otherwise herein. Further, the power production cycle can incorporate elements and/or operating parameters as otherwise described in U.S. Pat. No. 9,068,743 to Palmer et al., U.S. Pat. No. 9,062,608 to Allam et al., U.S. Pat. No. 8,986,002 to Palmer et al., U.S. Pat. No. 8,959,887 to Allam et al., U.S. Pat. No. 8,869,889 to Palmer et al., U.S. Pat. No. 8,776,532 to Allam et al., and U.S. Pat. No. 8,596,075 to Allam et al, the disclosures of which are incorporated herein by reference.

(22) In one or more embodiments, a power production cycle according to the present disclosure can be configure such that a working fluid comprising CO.sub.2 is repeatedly cycled at least through stages of compressing, heating, expanding, and cooling. The CO.sub.2 in particular can be supercritical through at least some of these steps, although it can transition between supercritical and liquid and/or gaseous states in some embodiments. In various embodiments, a power production cycle for which efficiency can be improved may include combinations of the following steps: combustion of a carbonaceous fuel with an oxidant in the presence of a recycled CO.sub.2 stream to provide a combustion product stream at a temperature of at least about 500° C. or at least about 700° C. (e.g., about 500° C. to about 2000° C. or about 600° C. to about 1500° C.) and a pressure of at least about 100 bar (10 MPa) or at least about 200 bar (20 MPa) (e.g., about 100 bar (10 MPa) to about 500 bar (50 MPa) or about 150 bar (15 MPa) to about 400 bar (40 MPa)); expansion of a high pressure recycled CO.sub.2 stream (e.g., at a pressure as noted above) across a turbine for power production; cooling of a high temperature recycled CO.sub.2 stream (e.g., at a pressure as noted above), particularly of a turbine discharge stream, in a recuperative heat exchanger; condensing of one or more combustion products (e.g., water) in the recuperative heat exchange and in an ambient cooler, the combustion products being present particularly in a combustion product stream that has been expanded and cooled; separating water and/or further materials from CO.sub.2 to form a recycled CO.sub.2 stream; compressing a recycled CO.sub.2 stream to a high pressure (e.g., a pressure as noted above), optionally being carried out in multiple stages with inter-cooling to increase stream density; heating a compressed recycled CO.sub.2 stream in a recuperative heat exchanger, particularly heating against a cooling turbine exhaust stream; and optionally adding heat to the recycled CO.sub.2 stream in addition to the heat recuperated from the cooling turbine exhaust stream, said heat being from another source, such as low grade heat taken from the hydrogen production system or unit as described herein.

(23) Turning more specifically to FIG. 1, a power production unit suitable for combination with a hydrogen production unit is exemplified. It is understood that a power production unit is intended to encompass a combination of individual components that, when operated together, are effective for power production and, as such, is intended to have the same meaning as a power production system. Likewise, it is understood that a hydrogen production unit is intended to encompass a combination of individual components that, when operated together, are effective for hydrogen production and, as such, is intended to have the same meaning as a hydrogen production system. Although the exemplified power production unit is described in relation to specific operating parameters, it is understood that the power production unit can be operated across a range of parameters consistent with the overall disclosure herein. In the power production unit exemplified in FIG. 1, a CO.sub.2 stream 107 at 304 bar, heated to 715° C. in heat exchanger 101 enters a combustor 102 where it mixes with the combustion products derived from a methane stream 112 compressed to 305 bar (251° C.) in compressor 105 driven by electric motor 106 burning in an oxidant stream 108 which has a composition of about 25% oxygen and about 75% CO.sub.2 molar and has been heated to 715° C. in heat exchanger 101. The resulting mixed stream 110 enters the turbine 103 at 1150° C. and 300 bar and is expanded to 30 bar and 725° C. leaving as stream 109 and generating power in generator 104. The 30 bar stream cools in the heat exchanger 101 and transfers heat to the high pressure CO.sub.2 stream and leaves at 65° C. as stream 113. It is further cooled in direct contact water cooler 115 that has a packed section 114 and a circulating water section comprising a pump 116 and an indirect water-cooled heat exchanger 117, which directs water flows 119, 120 and 121 to the top of the packing section. The excess liquid water produced from CH.sub.4 combustion, stream 118, is removed from the base of water cooler 115. The cooled stream of substantially pure CO.sub.2 122 leaving the top of the cooler 115 splits into multiple streams. A first portion 123 of the substantially pure CO.sub.2 stream 122 is divided into a net CO.sub.2 product stream 161, which is drawn off for export or other use and a diluent stream 163. In preferred embodiments, diluent stream 163 blends with the combustor oxygen flow 150 at 29 bar to form the combustor oxidant stream 151 containing 25% (molar) oxygen. The main portion 124 of the cooled, substantially pure CO.sub.2 enters a two stage intercooled CO.sub.2 compressor (with first compressor stage 159, intercooler 160, and second compressor state 125) where it is compressed to 67.5 bar, leaving as stream 162. The CO.sub.2 stream exiting the cooler 115 is substantially pure in that it comprises less than 3 mol %, less than 2 mol %, less than 1 mol %, less than 0.5 mol %, less than 0.1 mol %, or less than 0.01 mol % impurities.

(24) The power production cycle requires a significant quantity of additionally generated heat to be provided to the high pressure CO.sub.2 stream at a temperature level below 400° C. In this exemplified embodiment, the heat is derived from two sources that provide heat of compression. The first source is the adiabatically compressed cryogenic oxygen plant feed air stream 142 at 5.6 bar and 226° C. from air compressor 140, which compresses air stream 139 driven by electric motor 141. The second source is a stream 135 of 29.3 bar CO.sub.2 taken from heat exchanger 101 at a temperature of 135° C. and adiabatically compressed in compressor 136 to produce stream 137 at 226° C. These two streams are passed through additive heat exchanger 134 where they provide additive heat to a 304 bar CO.sub.2 stream 131 split from discharge stream 130 that is taken directly from the multi-stage pump 129. The additive heat from the additive heat exchange 134 raises the temperature of the CO.sub.2 from 50° C. in stream 131 to 221° C. in stream 133. The cooled CO.sub.2 stream 138 and the CO.sub.2 recycle compressor discharge stream 162 combine to form the total CO.sub.2 stream 127 that is cooled in the cooling water heat exchanger 126 to produce CO.sub.2 recycle stream 128 at 19.7° C. This stream of high-density CO.sub.2 liquid is compressed to 305 bar in a multi-stage pump 129. The discharge stream 130 at 50° C. divides into a main portion 132 which enters the recuperative heat exchanger 101 and a minor stream 131 that is heated in heat exchanger 134 to 221° C. against the cooling adiabatically compressed streams 137 and 142 producing stream 133 as noted above. The stream 133 rejoins the main portion 132 of the high pressure CO.sub.2 flow in heat exchanger 101. In this manner, additive heating is provided to the recycled CO.sub.2 stream (i.e., in addition to the recuperated heat from the turbine discharge stream 109) in order to achieve a high level of operating efficiency. A side stream 179 can be taken from the main portion 132 of the high pressure CO.sub.2 stream and directed to the turbine 103 as a turbine blade cooling stream.

(25) The cooled air stream 143 at 56° C. enters the cryogenic air separation system. This comprises an air purification unit 144 that has a direct contact air cooler, a water chiller, and a switching duel bed thermally regenerated adsorption unit that delivers a dry CO.sub.2 free stream of air at 5.6 bar and 12° C. Part of this air (stream 145) is compressed to 70 bar in compressor 146 driven by electric motor 178, and air streams 148 and 147 enter a pumped liquid oxygen cycle air separation cryogenic system 149. The products from the air separator are a waste nitrogen stream 160 and a 30 bar product oxygen stream 150, which blends with a cooled portion of the CO.sub.2 stream (the diluent stream 163) leaving the direct contact CO.sub.2 cooler 115 to produce the oxidant stream 151. This is compressed to 304 bar in the CO.sub.2/O.sub.2 compression train. Specifically, the oxidant stream 151 is compressed in compressor 152 driven by electric motor 153 leaving as stream 155, which is cooled in intercooler 154, leaving as stream 156, which is compressed further in pump 157. The resulting compressed oxidant stream 158 is heated to 715° C. in heat exchanger 101 leaving as stream 108 to enter the combustor 102.

(26) The power production cycle requires a separate cryogenic air separator plant to produce oxygen. This must be delivered to the combustor at a controlled concentration of about 20% to about 30% molar preheated to typically over 700° C. diluted with CO.sub.2 which in general involves a separate O.sub.2/CO.sub.2 compressor train or alternatively a more complex cryogenic air separation plant with a significantly high power consumption. The CH.sub.4 fuel 111 is compressed to 305 bar in a high-pressure compressor 105 as discussed above.

(27) The integration of the hydrogen plant with the power production cycle system (fueled with natural gas in the exemplified embodiment) is shown in FIG. 2. The system has a partial oxidation (PDX) reactor 201 with a feed stream 221 of 99.5% pure O.sub.2 at 270° C. and a natural gas stream 246 at 500° C., both at 85 bar pressure. The PDX reactor 201 provides a product H.sub.2+CO stream 222 at 1446° C. (which can optionally be quenched and cooled by the addition of a saturated steam stream 223 to 1350° C.) enters the base 203 of the gas heated reformer reactor 202. The product H.sub.2+CO stream 222 mixes with reformed H.sub.2+CO product stream leaving each of the open ended catalyst filled tubes 204, and the total product CO+H.sub.2 stream passes upwards through the shell side, providing heat for the endothermic reforming reactions and leaving as stream 224 at 600° C. The tubes are free to expand downwards at operating temperatures and the pressure difference at the hot end and hence stresses in the tube walls are negligible. The tubes plus any exposed metal parts are fabricated from an alloy such as INCONEL® 693, which is resistant to metal dusting corrosion caused by Boudouard reaction depositing carbon. Additionally, the metal surfaces can be further protected by coating with alumina.

(28) Stream 224 is cooled by passage through a waste heat boiler 236 and leaves as product gas stream 254 at 320° C. The product gas stream 254 passes through two catalyst filled CO shift reactors 207 and 208 in series. The outlet streams 226 and 228 enter the shift stream heat recovery heat exchangers 209 and 210 where heat is used for boiler feed-water preheating and natural gas stream preheating. Specifically, stream 226 leaving CO shift reactor 207 passes through shift stream heat exchanger 209 leaving as stream 227 to enter CO shift reactor 208. The stream 228 leaving CO shift reactor 208 passes through shift stream heat exchanger 210 before passing through water cooler 235 to leave as stream 229. Boiler feedwater streams 256 and 257 are heated in shift stream heat exchangers 210 and 209, respectively to provide heated water stream 258. Natural gas streams 241 and 242 are heated in the shift stream heat exchangers 210 and 209, respectively, to provide natural gas stream 243 at 290° C. The boiler feed-water stream 258 divides into a waste heat boiler feed stream 260 and a large excess stream 259 at 290° C. which is cooled to 60° C. in the heat exchanger 134 (see FIG. 1) releasing its heat to a portion of the power production cycle recycle high pressure CO.sub.2 stream 131 to 133 (shown in FIG. 1).

(29) The crude H.sub.2 stream 271 leaving heat exchanger 210 (which contains substantially all of the CO.sub.2 derived from combustion of carbon in the hydrocarbon or carbonaceous feed together with water vapor and minor amounts of CO, CH.sub.4, N.sub.2 and Ar) is cooled to near ambient in water cooler 235. Condensed water is separated from stream 229 in separator 212. water stream 262 leaving the separator 212 and the cooled water stream 253 leaving the heat exchanger 134 enter a water treatment unit 214, which produces purified water 255 and an excess water stream 261. The purified water 255 functions as the boiler feed-water stream and is pumped to about 87 bar pressure in pump 213. The pressurized boiler feedwater stream 256 leaving the pump 213 enters the heat exchanger 210.

(30) The waste heat boiler feed stream 260 is heated in the waste heat boiler 236 leaving as saturated steam stream 249, which splits into steam stream 250 and quenching stream 223. The saturated steam stream 250 and the preheated natural gas stream 243, both at 290° C. enter a supplemental heat exchanger 237 where they are heated to 500° C. against stream 247, which corresponds to stream 109, the turbine exhaust stream in FIG. 1. The outlet stream 248 enters the recuperative heat exchanger 101 (in the power production unit of FIG. 1) at about 725° C. In this case the inlet temperature for the turbine 103 in the power production unit of FIG. 1 is elevated to provide the required heat transferred in heat exchanger 237, and the turbine power output is increased. The supplemental heat exchanger 237 is thus configured to provide supplemental heating to the saturated steam stream 250 and the natural gas stream 243, the supplemental heating being provided by a stream from the power production unit.

(31) The hot natural gas stream 244 leaving the heat exchanger 237 splits to provide feed at 500° C. to the PDX reactor 201 as stream 246 and to the GHR 202 as stream 245, which mixes with the steam stream 251 to form total GHR feed stream 252. The steam stream 251 fed to the GHR reactor 202 provides a steam to carbon ratio (carbon combined with hydrogen in the GHR reactor feed) of 6:1 in this case. This high ratio allows 80 bar H.sub.2+CO production pressure with a low quantity of unconverted methane in the total product H.sub.2+CO stream 224.

(32) The crude hydrogen product stream 230 leaving the water separator 212 passes into a multi-bed pressure swing adsorption unit 215 that produces a substantially pure H.sub.2 product stream 239 with 50 ppm impurity level comprising 88% of the hydrogen present in stream 230. A substantially pure H.sub.2 product stream thus can comprise less than 500 ppm impurities, less than 250 ppm impurities, less than 100 ppm impurities, or less than 75 ppm impurities (e.g., down to 0 impurities). The waste stream 232 at 1.2 bar pressure that contains all the CO.sub.2 plus various contents of CO, H.sub.2, CH.sub.4, Argon, N.sub.2 and traces of water vapor is compressed to 30 bar in compressor 216 driven by electric motor 219 to leave as stream 238. The discharge stream 238 is cooled in cooler 217 to near ambient and added to the power production system natural gas compressor 105 (see FIG. 1) as part of inlet stream 111 (see FIG. 1). The compressor discharge stream 112 (see FIG. 1) at 320 bar provides the feed to the power production unit combustor 102 (see FIG. 1). The natural gas feed stream 241 at 85 bar can also be produced from a separate natural gas compressor stage, which would be part of the compressor 105 from FIG. 1.

(33) Performance

(34) The integration of a hydrogen production unit operating 246,151 Nm.sup.3/hr with a power production cycle system producing 290.3 MW of power, both having pure CH.sub.4 or natural gas feed, gives the following calculated performance data.

(35) H.sub.2 is produced at 50 ppm total impurity level at a pressure of 74 bar.

(36) Power production=234.23 MW from the integrated system.

(37) CH.sub.4 for hydrogen production=92,851.2 Nm.sup.3/hr (equal to 923.2 Mw).

(38) CH.sub.4 for power production at 43,773.9 Nm.sup.3/hr (equal to 435.2 Mw).

(39) Recovery of carbon derived from CH.sub.4 feed to the hydrogen plant and power plant, as CO.sub.2 is 100%.

(40) CO.sub.2 production from the integrated system is 6,437.1 MT/D

(41) The CO.sub.2 is produced at 150 bar pressure

(42) In systems and methods as described herein, the use of substantially pure oxygen in the combustor can have the side benefit of providing a large quantity of substantially pure nitrogen. The nitrogen can be provided at relatively high pressure directly from the air separation unit that can be associated with the power production unit to provide the necessary stream of substantially pure oxygen. At least a portion of this nitrogen can be blended with the hydrogen that can be produced as described herein. The end result is an H.sub.2+N.sub.2 fuel gas that is suitable for use in a conventional gas turbine combined cycle power generation system. This is exemplified in FIG. 3, wherein nitrogen gas 160 from an air separation unit (see FIG. 1) and hydrogen gas 239 from a hydrogen production facility (see FIG. 2) are input to a gas turbine combined cycle unit 300.

(43) The H.sub.2+N.sub.2 fuel gas can be utilized in any gas turbine combined cycle power generation system. Known systems can be modified as necessary to remove, decommission, or otherwise forego the use of elements that would otherwise be required for removal of CO.sub.2. Known gas turbine combined cycle power generation systems that can be utilized according to the present disclosure are described in U.S. Pat. No. 8,726,628 to Wichmann et al., U.S. Pat. No. 8,671,688 to Rogers et al., U.S. Pat. No. 8,375,723 to Benz et al., U.S. Pat. No. 7,950,239 to Lilley et al., U.S. Pat. No. 7,908,842 to Eroglu et al., U.S. Pat. No. 7,611,676 to Inage et al., U.S. Pat. No. 7,574,855 to Benz et al., U.S. Pat. No. 7,089,727 to Schutz, U.S. Pat. No. 6,966,171 to Uematsu et al., and U.S. Pat. No. 6,474,069 to Smith, the disclosures of which are incorporated herein by reference.

(44) The combination of systems provided by the present disclosure whereby hydrogen gas and nitrogen gas are provided from a combustion power system wherein a hydrocarbon fuel is combusted with substantially no atmospheric discharge of CO.sub.2, provides a distinct advantage over the conventional operation of a gas turbine combined cycle system. In particular, the present combination of systems can eliminate the natural gas fuel typically required in a gas turbine and substitute a fuel with no CO.sub.2 production when combusted. As such, in some embodiments, the present disclosure provides a combination of: 1) an oxygen based hydrogen production unit; 2) a power generation unit that captures substantially all of the CO.sub.2 produced; and a conventional gas turbine combined cycle power generation unit that provides for additional power generation. Combined systems as described herein can provide a surprisingly high efficiency, low cost power generation, and approximately 100% CO.sub.2 capture. The result is thus a heretofore unknown manner for providing power production from natural gas combustion with approximately 100% CO.sub.2 capture and operating costs that are equal to or lower than known power productions methods that do not provide for 100% CO.sub.2 capture.

(45) The combination of systems can be implemented in a variety of manners. In some embodiments, an existing combined cycle power station can be converted to eliminate all CO.sub.2 emissions and simultaneously increase the power generation capacity. Such conversion can include addition of the further system components described herein for production of power using a CO.sub.2 circulating fluid and production of H.sub.2+N.sub.2 fuel gas.

(46) Performance

(47) Performance calculations for a combined system as described above can be based on a GE PG9371(FB) gas turbine cogeneration system that is adapted to produce 432.25 Mw of power at iso conditions. Calculated values according to embodiments of the present disclosure are provided below considering the combination of a natural gas combustion power production unit with 100% CO.sub.2 capture, H.sub.2 production, N.sub.2 production, and combustion of H.sub.2+N.sub.2 fuel gas in the gas turbine.

(48) Total net power production from the combined system is 697 Mw

(49) Fuel to the gas turbine is assumed to be 50% H.sub.2+50% N.sub.2 (molar)

(50) Total methane feed is 1,368.6 Mw (LHV)

(51) Oxygen required is 4979 MT/day

(52) CO.sub.2 produced at 150 bar pressure is 6,437 Mt/day

(53) Overall efficiency is 50.9% (LHV basis)

(54) Many modifications and other embodiments of the presently disclosed subject matter will come to mind to one skilled in the art to which this subject matter pertains having the benefit of the teachings presented in the foregoing descriptions and the associated drawings. Therefore, it is to be understood that the present disclosure is not to be limited to the specific embodiments described herein 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.