Patent Application
20110232298
The subject matter disclosed herein relates to gas turbines and, more particularly, to cooling mechanisms in gas turbines.
Integrated Gasification Combined Cycle (IGCC) systems are increasingly being utilized for power generation. IGCC uses a gasification process to produce synthesis gas (syngas) from fuel sources such as coal, heavy petroleum residues, biomass and others. The syngas is used as a fuel in gas turbines for producing electricity. IGCC systems can be advantageous in reducing carbon dioxide (CO2) emissions through mechanisms such as pre-combustion carbon capture.
IGCC power plants adopt pre-combustion systems for CO2 capture. Currently, the capture of CO2 from IGCC plants penalizes the performance of such plants, particularly in production output and efficiency. In addition, cooling of the stationary and rotating components of a gas turbines by the conventional method of extracting air from the turbine's compressor reduces turbine efficiency by, for example, reducing the Brayton cycle efficiency. This loss of efficiency is manifested due to factors such as reduction in firing temperatures due to non-chargeable flow diluting the combustor exit temperature, reduction in work on account of bypassing compressed air at upstream stages of the turbine, and reduction in work potential on account of dilution effects of the coolant stream mixing in the main gas path and the associated loss of aerodynamic efficiency.
According to one aspect of the invention, a system for cooling components of a turbine includes: at least one input in fluid communication with a source of carbon dioxide gas, the carbon dioxide gas removed from synthesis gas produced by a gasification unit from hydrocarbon fuel; and at least one first conduit in fluid communication with the at least one input and configured to divert a portion of the carbon dioxide gas from the source of carbon dioxide gas to at least one component of the turbine, the turbine configured to combust the synthesis gas.
According to another aspect of the invention, a system for power generation includes: a gasification unit configured to produce raw synthesis gas from an input fuel; an acid gas removal plant in fluid communication with the gasification unit, the acid gas removal plant configured to remove acid gas from the raw synthesis gas and produce clean synthesis gas, the acid gas including carbon dioxide gas; a gas turbine configured to combust the clean sythensis gas; and a cooling unit in fluid communication with the acid gas removal plant and configured to divert at least a portion of the carbon dioxide gas to at least one component of a gas turbine.
According to yet another aspect of the invention, a method of cooling components of a turbine includes: extracting carbon dioxide gas from a synthesis gas produced by a gasification process; advancing the carbon dioxide gas to a storage system; and diverting a portion of the carbon dioxide gas to the turbine to cool at least one component of the turbine.
These and other advantages and features will become more apparent from the following description taken in conjunction with the drawings.
The subject matter, which is regarded as the invention, is particularly pointed out and distinctly claimed in the claims at the conclusion of the specification. The foregoing and other features, and advantages of the invention are apparent from the following detailed description taken in conjunction with the accompanying drawings in which:
The detailed description explains embodiments of the invention, together with advantages and features, by way of example with reference to the drawings.
There is provided a system and method for improving the output and efficiency of turbine systems that utilize gasification to supply turbine combustion fuel. An exemplary turbine systems include integrated gasification combined cycle (IGCC) power generation systems. In one embodiment, the systems and method are utilized in conjunction with IGCC or other turbine systems that incorporate pre-combustion systems for carbon dioxide (CO2) capture. Exemplary systems and methods include cooling turbines using CO2 captured by a power generation and/or CO2 removal system. Exemplary systems and methods utilize captured CO2 as cooling media for cooling of stationary and/or rotating components of turbines, such as gas turbines, in a closed loop cooling scheme.
In one embodiment, the systems and method include utilizing a synthesis gas cleaning solvent or other fluid that is available in sythesis gas cleaning systems, CO2 removal systems and/or power plants such as IGCC plants. The solvents are enabled to capture CO2 from turbine fuel produced by gasification, which are utilized by the systems and methods described herein for turbine cooling.
With reference to
The turbine includes various internal components that are exposed to elevated temperatures during operation of the turbine assembly 10. Such components include a rotor shaft and rotor disks that rotate about a central axis. Exemplary components also include rotating components 24 such as blades or buckets, which can be removably attached to an outer periphery of each rotor disk. Other components include stationary components 26 such as stator vanes or nozzles.
In one embodiment, referring to
In one embodiment, the combustion chamber 18, or other suitable equipment, is utilized in an oxyfuel cycle. Oxyfuel cycles generally include the combustion of fuel with pure oxygen, in place of air. In one embodiment, oxyfuel includes an oxygen enriched gas mixture diluted with combustion gas such as gas turbine exhaust (i.e., flue gas consisting mostly of CO2 and H2O).
The gases, in one embodiment, are advanced into a two stage shift reactor 34 in which water vapor is used to convert the CO into carbon dioxide (CO2). At this stage, the syngas is only a raw syngas that includes acid gases, which include various contaminants such as CO2 and hydrogen sulphide (H2S). Various other gases are also produced in the gasification process, and present in the syngas, such as nitrogen, carbon mon-oxide, and others.
An acid gas removal (AGR) plant 42 then receives the raw syngas. The AGR plant 42 processes the raw syngas to remove H2S, which can be sent to a tail gas treatment unit (TGTU) 40, and CO2 from the raw syngas. The AGR plant 42 includes, for example, an absorber in which a solvent absorbs H2S and CO2 from the raw syngas to produce a “sweetened” or clean syngas. An example of a suitable solvent is Selexol™ (Union Carbide Corporation), although any solvent capable of removing acid gases from a gas mixture may be used. In addition to solvent-based processes, the AGR plant 42 may use any suitable process for sweetening the syngas. Examples of such sweetening processes include selective gas removal processes such as the utilization of CO2 and H2S selective membranes, warm sulphur removal technologies and others.
In one embodiment, after the syngas is cleaned, the solvent includes concentrations of H2S and CO2 and may be referred to as a “rich” solvent. The rich solvent is fed into one or more regenerators (including, for example, a stripper and boiler) in which the H2S and CO2 are stripped from the solvent, resulting in a “lean” solvent. The lean solvent can be recycled for use in subsequent acid gas removal operations.
In one embodiment, the removed CO2 is advanced through, for example, an Integrated CO2 Enrichment system 44, and sent to a compression and/or storage unit 46 for CO2 capture and/or enhanced oil recovery. A portion of the CO2, in one embodiment, is diverted via a recycling/compression system 38 and directed back into the gasification unit 32. In addition, the TGTU 40 may be used to remove sulphur from the raw syngas.
The clean syngas is then advanced through various saturation and heating systems 48 and fed into a combined cycle power block 50 for power generation. The power block 50 includes a gas turbine such as the gas turbine assembly 10 and may also include a steam turbine for producing energy from the gas turbine exhaust gases.
In one embodiment, the IGCC plant 30 includes an air separation unit (ASU) 52. Air can be diverted from the gas turbine compressor and fed into the ASU 52. The ASU 52 separates oxygen from the air that can be fed into the gasification unit 32, and also produces nitrogen, which can be diverted back to the turbine for cooling.
In one embodiment, a portion of the CO2 at a suitable pressure is extracted from the CO2 removal system and diverted to the power block 50 to cool the gas turbine stationary or rotating components in a closed loop system wherein the heat picked up by CO2 is recovered. The CO2 is diverted to the gas turbine via any suitable cooling system 54. In one embodiment, the cooling system 54, the combined cycle power block 50 and/or the IGCC power plant 30 includes one or more heat exchangers to regenerate thermal energy from the CO2 that has been heated as a result of applying the CO2 to the gas turbine. The heat exchanges are configured to heat components such as the fuel and/or diluent stream entering the gas turbine, the steam turbine, as well as any other desired fluids such as boiler fluids. After the CO2 is applied to the gas turbine and/or the steam turbine, and any additional components, it may be subsequently sent to the compression and/or storage system 46, where the CO2 is compressed to a selected pressure, such as 2000 psig (˜140 bars), a typical pressure to supply liquid CO2 for Enhanced Oil Recovery (EOR) applications.
Referring to
In one embodiment, the cooling system 60 is in operable communication with the gas turbine 64 and a portion of the AGR plant 42. The AGR plant 42 includes one or more flash tanks 68 that separate CO2 from a rich solvent. Gas conduits 69 are configured to route the separated CO2 from the flash tanks 68 to desired locations, such as the compression and/or storage unit 46. In one embodiment, CO2 fluid from a H2S reabsorber 67 is routed to the gas turbine cooling CO2 controller 66. The cooling system conduits 62 are in fluid communication with respective gas conduits 69 to divert a portion of the separated CO2 into the cooling system 60. The flow of CO2 into the cooling system can be controlled by the controller 66. In one embodiment, the cooling system 60 include valves 70 for controlling the flow of CO2 from the gas conduits 69, through the cooling system 60 and into the gas turbine 64. The valves 70 may be selectively operated via, for example, the controller 66.
The cooling system 60, in one embodiment, is a closed loop system. For example, as shown in
Another embodiment of the cooling system 60 is shown in reference to
In this embodiment, CO2 fluid from the ICU is fed to heat exchangers 82 that are configured to transfer heat from the bleed CO2 to fluids such as the fuel, diluent, compressor discharge air and/or boiler feed water (BFW). Further heat is transferred back to the CO2 which is entering ICU through a regenerative heat exchanger system 84. CO2 fluid can also be cooled through optional low temperature heat exchange systems 94 (e.g., trim coolers, other areas of steam heat exchangers and others) that further cool the CO2 to facilitate compression, liquefication and/or sequestration. Lastly, the cooled CO2 is diverted to the compression and sequestration unit 90.
In one embodiment, the cooling system 60 is in fluid communication with a CO2 capture, recovery and sequestration system 86. The CO2 capture unit includes a number of capture modules 88. Exemplary capture modules include flash tanks 68 which through which rich solvent is passed. The capture modules 88 can include high pressure (HP), medium pressure (MP) and/or low pressure (LP) modules 88 in fluid communication with a CO2 compression and sequestration unit 90.
In use, a portion of the CO2 from capture modules 88 may be diverted through an optional gas compression system 92 through regenerative heat exchangers 84 to selected ICU of turbine components.
In the first stage 101, fuel is flowed into a gasification system such as the gasification and scrubbing unit 32 and raw syngas is produced. The raw syngas is cleaned or sweetened by a suitable cleaning system such as the AGR plant 42 to remove acid gases from the raw syngas.
In the second stage 102, CO2 gas is extracted from the raw syngas and/or from byproducts of cleaning the raw syngas. For example, CO2 gas is removed from a solvent used to clean the raw syngas by the flash tanks 68 or other CO2 extraction mechanisms. The CO2 gas is advanced to a CO2 capture and/or storage system, such as the compression and/or storage unit 46.
In the third stage 103, a portion of the CO2 gas is diverted to a cooling system such as the cooling system 60 that applies the CO2 gas portion to selected components of a turbine such as a gas turbine. Exemplary components include rotating blades or buckets and stationary components such as stator vanes.
In the fourth stage 104, the CO2 gas portion, which has been heated by the turbine components, is recovered in thermal energy/regenerated and then returned to the CO2 capture and/or storage system. In one embodiment, the heated CO2 gas portion is cooled and thermal energy is transferred to fuel, diluents and/or other components of a power generation system prior to returning the CO2 gas portion to the CO2 capture and/or storage system.
In one embodiment, the CO2 gas portion is cooled by transferring thermal energy from the CO2 gas portion to an indirect cooling unit by a suitable heat exchange mechanism such as the regenerative heat exchanger 84.
Although the systems and methods described herein are provided in conjunction with gas turbines, any other suitable type of turbine may be used. For example, the systems and methods described herein may be used with a steam turbine or turbine including both gas and steam generation.
The systems and methods described herein may be utilized in conjunction with any of various turbine power generation systems, and are not limited to the specific power generation systems described herein. In addition, the systems and methods described herein may be utilized in place of or in addition to various other cooling systems. Examples of such cooling systems include closed loop systems using cooling media for hot gas path components such as steam, nitrogen and liquid (e.g., water) coolants.
The devices, systems and methods described herein provide numerous advantages over prior art systems. The devices, systems and methods provide the technical effect of increasing efficiency and performance of the turbine. For example, based on analyses of exemplary systems, systems and methods such as those described herein can improve output and efficiency, for example by improving net output by 14.5% and efficiency by 0.52 points over the baseline scenario that is practiced in the prior art.
While the invention has been described in detail in connection with only a limited number of embodiments, it should be readily understood that the invention is not limited to such disclosed embodiments. Rather, the invention can be modified to incorporate any number of variations, alterations, substitutions or equivalent arrangements not heretofore described, but which are commensurate with the spirit and scope of the invention. Additionally, while various embodiments of the invention have been described, it is to be understood that aspects of the invention may include only some of the described embodiments. Accordingly, the invention is not to be seen as limited by the foregoing description, but is only limited by the scope of the appended claims.
