SYSTEM AND METHOD FOR HIGH EFFICIENCY POWER GENERATION USING A CARBON DIOXIDE CIRCULATING WORKING FLUID

• US 20110179799A1
• Filed: 08/31/2010
• Published: 07/28/2011
• Est. Priority Date: 02/26/2009
• Status: Active Grant

• Current Assignee: 8 Rivers Capital, LLC, Palmer Labs, LLC
• Original Assignee: Palmer Labs, LLC
• Inventors: Allam, Rodney John, Palmer, Miles, Brown, Glenn William JR.
• Granted Patent: US 8,596,075 B2
• Time in Patent Office: Days
• US Class Current: 60/772
• CPC Class Codes: F01K 13/00 General layout or general methods of operation of complete plants
• CPC Class Codes: F01K 23/10 with exhaust fluid of one cycle heating the fluid in another cycle F01K17/025 takes precedence
• CPC Class Codes: F01K 25/103 Carbon dioxide F01K25/065 takes precedence
• CPC Class Codes: F01K 3/185 using waste heat from outside the plant F02G5/00 takes precedence
• CPC Class Codes: F01K 3/186 using electric heat
• CPC Class Codes: F02C 3/04 having a turbine driving a compressor power transmission arrangements F02C7/36; control of working fluid flow F02C9/16
• CPC Class Codes: F02C 3/20 using a special fuel, oxidant, or dilution fluid to generate the combustion products
• CPC Class Codes: F02C 3/22 the fuel or oxidant being gaseous at standard temperature and pressure F02C3/28 takes precedence
• CPC Class Codes: F02C 3/34 with recycling of part of the working fluid, i.e. semi-closed cycles with combustion products in the closed part of the cycle
• CPC Class Codes: F02C 7/00 Features, components parts, details or accessories, not provided for in, or of interest apart form groups F02C1/00 - F02C6/00; Air intakes for jet-propulsion plants controlling F02C9/00
• CPC Class Codes: F05D 2260/61 Removal of CO2 removal of CO2 from waste gases B01D53/62
• CPC Class Codes: F22B 35/12 operating at critical or supercritical pressure
• CPC Class Codes: F23L 2900/07001 Injecting synthetic air, i.e. a combustion supporting mixture made of pure oxygen and an inert gas, e.g. nitrogen or recycled fumes
• CPC Class Codes: F23L 2900/07002 Injecting inert gas, other than steam or evaporated water, into the combustion chambers
• CPC Class Codes: F23L 7/007 Supplying oxygen or oxygen-enriched air
• CPC Class Codes: F23M 2900/05004 Special materials for walls or lining
• CPC Class Codes: F23M 5/00 Casings; Linings; Walls
• CPC Class Codes: F23M 5/085 using air or other gas as the cooling medium
• CPC Class Codes: F25J 2230/06 Adiabatic compressor, i.e. without interstage cooling
• CPC Class Codes: F25J 2240/70 Steam turbine, e.g. used in a Rankine cycle
• CPC Class Codes: F25J 2240/82 : with waste heat recovery, e.g. in a combined cycle, i.e. for generating steam used in a Rankine cycle
• CPC Class Codes: F25J 2260/80 : Integration in an installation using carbon dioxide, e.g. for EOR, sequestration, refrigeration etc.
• CPC Class Codes: F25J 3/04018 : of main feed air
• CPC Class Codes: F25J 3/04533 : for the direct combustion of fuels in a power plant, so-called "oxyfuel combustion"
• CPC Class Codes: F25J 3/04545 : for the gasification of solid or heavy liquid fuels, e.g. integrated gasification combined cycle [IGCC]
• CPC Class Codes: F25J 3/04618 : for cooling an air stream fed to the air fractionation unit
• CPC Class Codes: Y02E 20/32 : Direct CO2 mitigation
• CPC Class Codes: Y02E 20/34 : Indirect CO2mitigation, i.e. by acting on non CO2directly related matters of the process, e.g. pre-heating or heat recovery

Abstract

The present invention provides methods and system for power generation using a high efficiency combustor in combination with a CO₂ circulating fluid. The methods and systems advantageously can make use of a low pressure ratio power turbine and an economizer heat exchanger in specific embodiments. Additional low grade heat from an external source can be used to provide part of an amount of heat needed for heating the recycle CO₂ circulating fluid. Fuel derived CO₂ can be captured and delivered at pipeline pressure. Other impurities can be captured.

Claims

1. A method of power generation comprising:

introducing a fuel, O₂, and a CO₂ circulating fluid into a combustor, the CO₂ being introduced at a pressure of at least about 12 MPa and a temperature of at least about 400°

C.;

combusting the fuel to provide a combustion product stream comprising CO₂, the combustion product stream having a temperature of at least about 800°

C.;

expanding the combustion product stream across a turbine to generate power, the turbine having an inlet for receiving the combustion product stream and an outlet for release of a turbine discharge stream comprising CO₂, wherein the pressure ratio of the combustion product stream at the inlet compared to the turbine discharge stream at the outlet is less than about 12;

withdrawing heat from the turbine discharge stream by passing the turbine discharge stream through a primary heat exchange unit to provide a cooled turbine discharge stream;

removing from the cooled turbine discharge stream one or more secondary components that are present in the cooled turbine discharge stream in addition to CO₂ to provide a purified, cooled turbine discharge stream;

compressing the purified, cooled turbine discharge stream with a first compressor to a pressure above the CO₂ critical pressure to provide a supercritical CO₂ circulating fluid stream;

cooling the supercritical CO₂ circulating fluid stream to a temperature where its density is at least about 200 kg/m³;

passing the supercritical, high density CO₂ circulating fluid through a second compressor to pressurize the CO₂ circulating fluid to the pressure required for input to the combustor;

passing the supercritical, high density, high pressure CO₂ circulating fluid through the same primary heat exchange unit such that the withdrawn heat is used to increase the temperature of the CO₂ circulating fluid;

supplying an additional quantity of heat to the supercritical, high density, high pressure CO₂ circulating fluid so that the difference between the temperature of the CO₂ circulating fluid exiting the primary heat exchange unit for recycle to the combustor and the temperature of the turbine discharge stream is less than about 50°

C.; and

recycling the heated, supercritical, high density CO₂ circulating fluid into the combustor.

2. The method of claim 1, wherein said withdrawing step cools the turbine discharge stream to a temperature below its water dew point.

3. The method of claim 1, wherein said removing step comprises further cooling the turbine discharge stream against an ambient temperature cooling medium.

4. The method of claim 3, wherein said further cooling condenses water together with the one or more secondary components to form a solution comprising one or ore of H₂SO₄, HNO₃, HCl, and mercury.

5. The method of claim 1, wherein said compressing with the first compressor pressurizes the cooled turbine discharge stream to a pressure of less than about 12 MPa.

6. The method of claim 1, wherein a product CO₂ stream is withdrawn from the supercritical, high density, high pressure CO₂ circulating fluid stream prior to passing through the primary heat exchange unit.

7. The method of claim 6, wherein the product CO₂ stream comprises substantially all of the CO₂ formed by combustion of the carbon in the carbon containing fuel.

8. The method of claim 6, wherein the product CO₂ stream is at a pressure compatible with direct input into a high pressure CO₂ pipeline.

9. The method of claim 1, wherein said combusting is carried out at a temperature of about 1,200°

C. to about 5,000°

C.

10. The method of claim 1, wherein the fuel comprises a stream of partial combustion products.

11. The method of claim 10, comprising combusting a carbon containing fuel with O₂ in the presence of a CO₂ circulating fluid, the carbon containing fuel, O₂, and CO₂ circulating fluid being provided in ratios such that the carbon containing fuel is only partially oxidized to produce the partially oxidized combustion product stream comprising an incombustible component, CO₂, and one or more of H₂, CO, CH₄, H₂S, and NH₃.

12. The method of claim 11, wherein the carbon containing fuel, O₂, and CO₂ circulating fluid being provided in ratios such that the temperature of the partially oxidized combustion product stream is sufficiently low that all of the incombustible component in the stream is in the form of solid particles.

13. The method of claim 12, wherein the temperature of the partially oxidized combustion product stream is about 500°

C. to about 900°

C.

14. The method of claim 12, further comprising passing the partially oxidized combustion product stream through one or more filters.

16. The method of claim 11, wherein the fuel comprises coal, lignite, or petroleum coke.

17. The method of claim 16, wherein the fuel is in a particulate form and is provided as a slurry with CO₂.

18. The method of claim 17, wherein particulate fuel is such that greater than 90% of the particles have an average size of less than about 500 μ

m.

19. The method of claim 18, wherein greater than 99% of the particles have an average size of less than about 100 μ

m.

20. The method of claim 1, wherein the CO₂ circulating fluid is introduced at a pressure of at least about 15 MPa.

21. The method of claim 1, wherein the CO₂ circulating fluid is introduced at a pressure of at least about 20 MPa.

22. The method of claim 1, wherein the CO₂ circulating fluid is introduced at a temperature of at least about 600°

C.

23. The method of claim 1, wherein the CO₂ circulating fluid is introduced at a temperature of at least about 700°

C.

24. The method of claim 1, wherein the combustion product stream has a temperature of at least about 1,000°

C.

25. The method of claim 1, wherein the combustion product stream has a pressure that is at least about 90% of the pressure of the CO₂ introduced into the combustor.

26. The method of claim 25, wherein the combustion product stream pressure is at least about 95% of the pressure of the CO₂ introduced into the combustor.

27. The method of claim 1, wherein the pressure ratio of the combustion product stream at the inlet compared to the turbine discharge stream at the outlet is about 1.5 to about 10.

28. The method of claim 27, wherein the pressure ratio of the combustion product stream at the inlet compared to the turbine discharge stream at the outlet is about 2 to about 8.

29. The method of claim 1, wherein the fuel is a carbon containing fuel, and wherein the ratio of CO₂ in the CO₂ circulating fluid to carbon in the fuel introduced to the combustor, on a molar basis, is about 10 to about 50.

30. The method of claim 29, wherein the ratio of CO₂ in the CO₂ circulation fluid to O₂ introduced to the combustor, on a molar basis, is about 10 to about 30.

31. The method of claim 1, wherein the CO₂ in the turbine discharge stream is in a gaseous state.

32. The method of claim 31, wherein the turbine discharge stream has a pressure of less than or equal to 7 MPa.

33. The method of claim 1, wherein the primary heat exchange unit comprises a series of at least three heat exchangers.

34. The method of claim 33, wherein the first heat exchanger in the series receives the turbine discharge stream and reduces the temperature thereof, the first heat exchanger being formed of a high temperature alloy that withstands a temperature of at least about 700°

C.

35. The method of claim 1, wherein the supercritical, high density CO₂ circulating fluid stream after passage through the second compressor has a pressure of at least about 15 MPa.

36. The method of claim 35, wherein the supercritical, high density CO₂ circulating fluid stream after passage through the second compressor has a pressure of at least about 25 MPa.

37. The method of claim 1, wherein the supercritical CO₂ circulating fluid stream is cooled to a temperature where its density is at least about 400 kg/m³.

38. The method of claim 1, wherein said additional quantity of heat comprises heat withdrawn from an O₂ separation unit.

39. The method of claim 1, wherein the O₂ is provided in an amount such that part of the fuel is oxidized to oxidation products comprising one or more of CO₂, H₂O, and SO₂, and the remaining part of the fuel is oxidized to one or more combustible components selected from the group consisting of H₂, CO, CH₄, H₂S, NH₃, and combinations thereof.

40. The method of claim 39, wherein the turbine comprises two units each having an inlet and an outlet, and wherein the operating temperature at the inlet of each unit is substantially the same.

41. The method of claim 40, comprising adding an amount of O₂ to the fluid stream at the outlet of the first turbine unit.

42. The method of claim 1, wherein the turbine discharge stream is an oxidizing fluid comprising an excess amount of O₂.

43. The method of claim 1, wherein the CO₂ circulating fluid is introduced to the transpiration cooled combustor as a mixture with one or both of the O₂ and the fuel.

44. The method of claim 1, wherein the combustor comprises a transpiration cooled combustor.

45. The method of claim 1, wherein the CO₂ circulating fluid is introduced to the transpiration cooled combustor as all or part of a transpiration cooling fluid directed through one or more transpiration fluid supply passages formed in the transpiration cooled combustor.

46. The method of claim 1, wherein said combusting is carried out at a temperature of at least about 1,300°

C.

47. The method of claim 1, wherein said combusting is carried out at a temperature of about 1,200°

C. to about 5,000°

C.

48. The method of claim 1, wherein the O₂ is provided as a stream wherein the molar concentration of the O₂ is at least 85%.

49. The method of claim 48, wherein the molar concentration of the O₂ is about 85% to about 99.8%.

50. The method of claim 1, wherein the turbine discharge stream is passed directly into the primary heat exchanger unit without passage through a further combustor.

51. The method of claim 1, wherein the efficiency of the combustion is greater than 50%, said efficiency being calculated as the ratio of the net power generated in relation to the total lower heating value thermal energy of the carbon containing fuel combusted to generate the power.

52. The method of claim 1, further comprising, between said combusting step and said expanding step, passing the combustion product stream through at least one apparatus for removing contaminants in a solid or liquid state.

53. The method of claim 1, further comprising, between said expanding step and said withdrawing step, passing the turbine discharge stream through a secondary heat exchange unit.

54. The method of claim 53, wherein said secondary heat exchange unit uses heat from the turbine discharge stream to heat one or more streams derived from a steam power system.

55. The method of claim 54, wherein the steam power system comprises a conventional boiler system.

56. The method of claim 55, wherein the conventional boiler system comprises a coal fired power station.

57. The method of claim 54, wherein the steam power system comprises a nuclear reactor.

58. The method of claim 54, wherein the one or more heated steam streams are passed through one or more turbines to generate power.

15. The method of clam 14, wherein the filter reduces the residual amount of incombustible component to less than about 2 mg/m³ of the partially oxidized combustion product.

59. A method of power generation comprising:

introducing a carbon containing fuel, O₂, and a CO₂ circulating fluid into a transpiration cooled combustor, the CO₂ being introduced at a pressure of at least about 8 MPa and a temperature of at least about 200°

C.;

combusting the fuel to provide a combustion product stream comprising CO₂, the combustion product stream having a temperature of at least about 800°

C.; and

expanding the combustion product stream across a turbine to generate power, the turbine having an inlet for receiving the combustion product stream and an outlet for release of a turbine discharge stream comprising CO₂, wherein the pressure ratio of the combustion product stream at the inlet compared to the turbine discharge stream at the outlet is less than about 12.

60. The method of claim 59, wherein the CO₂ circulating fluid is introduced at a pressure of at least about 20 MPa.

61. The method of claim 59, wherein the CO₂ circulating fluid is introduced at a temperature of at least about 700°

C.

62. The method of claim 59, wherein the combustion product stream has a temperature of at least about 1,000°

C.

63. The method of claim 59, wherein the pressure ratio of the combustion product stream at the inlet compared to the turbine discharge stream at the outlet is about 1.5 to about 10.

64. The method of claim 59, wherein the ratio of CO₂ in the CO₂ circulating fluid to carbon in the fuel introduced to the combustor, on a molar basis, is about 10 to about 50.

65. The method of claim 59, wherein the CO₂ in the turbine discharge stream is in a gaseous state.

66. The method of claim 65, wherein the turbine discharge stream has a pressure of less than or equal to 7 MPa.

67. The method of claim 59, further comprising passing the turbine discharge stream through a primary heat exchange unit that withdraws heat from the turbine discharge stream and provides a CO₂ circulating fluid stream having a temperature of less than about 200°

C.

68. The method of claim 67, wherein the primary heat exchange unit comprises a series of at least two heat exchangers.

69. The method of claim 67, further comprising performing one or more separation steps on the CO₂ circulating fluid stream to remove one or more secondary components that are present in the circulating fluid stream in addition to CO₂.

70. The method of claim 69, further comprising compressing the purified, CO₂ circulating fluid stream with a first compressor to a pressure above the CO₂ critical pressure to provide a supercritical CO₂ circulating fluid stream.

71. The method of claim 70, further comprising cooling the supercritical CO₂ circulating fluid stream to a temperature where its density is at least about 200 kg/m³.

72. The method of claim 70, further comprising passing the supercritical, high density CO₂ circulating fluid through a second compressor to pressurize the CO₂ circulating fluid to the pressure required for input to the combustor.

73. The method of claim 72, further comprising passing the supercritical, high density, high pressure CO₂ circulating fluid through the same primary heat exchange unit such that the withdrawn heat is used to increase the temperature of the CO₂ circulating fluid.

74. The method of claim 73, further comprising supplying an additional quantity of heat to the supercritical, high density, high pressure CO₂ circulating fluid so that the difference between the temperature of the CO₂ circulating fluid exiting the primary heat exchange unit for recycle to the combustor and the temperature of the turbine discharge stream is less than about 50°

C.

75. The method of claim 74, further comprising recycling the heated, supercritical, high density CO₂ circulating fluid into the combustor.

76. The method of claim 74, wherein said step of supplying an additional quantity of heat comprises the use of heat withdrawn from an O₂ separation unit.

77. The method of claim 67, wherein prior to passing the turbine discharge stream through the primary heat exchange unit, the turbine discharge stream is passed through a secondary heat exchange unit.

78. The method of claim 77, wherein said secondary heat exchange unit uses heat from the turbine discharge stream to heat one or more streams derived from a steam power system.

79. The method of claim 78, wherein the steam power system comprises a conventional boiler system.

80. The method of claim 79, wherein the conventional boiler system comprises a coal fired power station.

81. The method of claim 78, wherein the steam power system comprises a nuclear reactor.

82. The method of claim 78, wherein the one or more heated steam streams are passed through one or more turbines to generate power.

83. The method of claim 59, wherein at least part of the CO₂ circulating fluid is introduced to the transpiration cooled combustor as a mixture with one or both of the O₂ and the carbon containing fuel.

84. The method of claim 59, wherein the CO₂ circulating fluid is introduced to the transpiration cooled combustor as all or part of a transpiration cooling fluid directed through one or more transpiration fluid supply passages formed in the transpiration cooled combustor.

85. The method of claim 59, wherein said combusting is carried out at a temperature of at least about 1,300°

C.

86. The method of claim 59, wherein said combusting is carried out at a temperature of about 1,300°

C. to about 5,000°

C.

87. The method of claim 59, wherein the O₂ is provided as a stream wherein the molar concentration of the O₂ is at least 85%.

88. The method of claim 59, wherein the efficiency of the combustion is greater than 50%, said efficiency being calculated as the ratio of the net power generated in relation to the total lower heating value thermal energy of the carbon containing fuel combusted to generate the power.

89. A power generation system comprising:

a transpiration cooled combustor configured for receiving a fuel, O₂, and a CO₂ circulating fluid stream, and having at least one combustion stage that combusts the fuel in the presence of the CO₂ circulating fluid and provides a combustion product stream comprising CO₂ at a pressure of at least about 8 MPa and a temperature of at least about 800°

C.;

a primary power production turbine in fluid communication with the combustor, the primary turbine having an inlet for receiving the combustion product stream and an outlet for release of a turbine discharge stream comprising CO₂, the primary turbine being adapted to control pressure drop such that the ratio of the pressure of the combustion product stream at the inlet compared to the turbine discharge stream at the outlet is less than about 12;

a primary heat exchange unit in fluid communication with the primary turbine for receiving the turbine discharge stream and transferring heat therefrom to the CO₂ circulating fluid stream; and

at least one compressor in fluid communication with the at least one heat exchanger for pressurizing the CO₂ circulating fluid stream.

90. The power generation system of claim 89, further comprising one or more separation devices positioned between the heat exchange unit and the at least one compressor for removal of one or more secondary components present in the CO₂ circulating fluid in addition to the CO₂.

91. The power generation system of claim 89, comprising a first compressor adapted to compress the CO₂ circulating fluid stream to a pressure that is above the CO₂ critical pressure.

92. The power generation system of claim 91, comprising a cooling device adapted to cool the CO₂ circulating fluid stream exiting the first compressor to a temperature where its density is greater than about 200 kg/m³.

93. The power generation system of claim 92, comprising a second compressor adapted to compress the cooled CO₂ circulating fluid stream to a pressure required for input to the combustor.

94. The power generation system of claim 92, further comprising one or more heat transfer components that transfers heat from an external source to the CO₂ circulating fluid upstream from the combustor and downstream from the second compressor.

95. The power generation system of claim 94, wherein the heat transfer components are associated with an O₂ production device.

96. The power generation system of claim 89, further comprising a second combustor located upstream from and in fluid communication with the transpiration cooled combustor.

97. The power generation system of claim 96, further comprising one or more filters or separation devices located between the second combustor and the transpiration cooled combustor.

98. The power generation system of claim 97, wherein the second combustor is a transpiration cooled combustor.

99. The power generation system of claim 96, further comprising a mixing device for forming a slurry of a particulate fuel material with a fluidizing medium.

100. The power generation system of claim 96, further comprising a milling device for particularizing a solid fuel.

101. The power generation system of claim 89, wherein the heat exchange unit comprises at least two heat exchangers.

102. The power generation system of claim 101, wherein the heat exchange unit comprises a series of at least three heat exchangers.

103. The power generation system of claim 101, wherein the first heat exchanger in the series is adapted for receiving the primary turbine discharge stream and is formed of a high temperature alloy that withstands a temperature of at least about 700°

C.

104. The power generation system of claim 89, wherein the primary power production turbine comprises a series of at least two turbines.

105. The power generation system of claim 89, further comprising a secondary heat exchange unit located between and in fluid communication with the primary power production turbine and the primary heat exchange unit.

106. The power generation system of claim 105, further comprising a boiler in fluid communication with the secondary heat exchange unit via at least one steam stream.

107. The power generation system of claim 106, further comprising a secondary power production turbine having an inlet for receiving the at least one steam stream from the secondary heat exchange unit.