Coal and syngas fueled power generation systems featuring zero atmospheric emissions

Abstract

A coal syngas or other syngas fired power plant is provided with no atmospheric emissions. Coal or other starter fuel is gasified within a gasifier which also receives oxygen and steam therein. The oxygen is provided from an air separator. Syngas produced within the gasifier is combusted within a gas generator along with oxygen from the air separator. Water is also introduced into the gas generator to control the temperature of combustion of the syngas with the oxygen. Products of combustion including steam and carbon dioxide are produced within the gas generator. The combustion products are expanded through a turbine for power output and then separated, such as within a condenser. Water discharged from the condenser is at least partially recirculated back to the gasifier and the gas generator. Carbon dioxide from the separator is compressed for capture without release into the atmosphere.

Description

BACKGROUND OF THE INVENTION

Currently and for the near future, coal provides a substantial portion of the world's supply of electric energy. Pollution from coal-fired power plants is a pressing environmental problem and the emission of carbon dioxide is of increasing concern in regard to global warming.

Coal is a desirable fuel for electric power generation especially if power plants are designed to give zero atmospheric emissions. The world has an abundant supply of energy in coal. In 1996, coal provided approximately 24% of the world's total energy supply and 38.4% of the world's electricity generation. In comparison, in 1999 the electricity production in the United States was 10.1 ExaWh (10.1×1018 Wh), while electricity production from coal was 5.67 ExaWh, or 56% of the total electricity production. The United States has 507.8 billion metric ton of demonstrated coal reserves while the consumption in the year 2000 was 1.097 billion metric tons. Hence, the United States has a coal supply of more than 460 years based on today's consumption. With a 1.5% annual growth in energy use, the United States still would have more than 100 years of energy supply in coal. Coal is expected to remain a long-term candidate for electric energy production both in the United States and in the world. Coal and other heavy liquid/solid fuels require preprocessing prior to combustion in the gas generator. The preprocessing of these fuels involves conversion to syngas in oxygen-blown gasifiers and subsequent cleansing of particulates (ash and carbon), sulfur compounds (H2S and COS), and some of the other impurities (e.g., nitrogen, chlorine, volatile metals) prior to introduction into the gas generator. Although gasification and gas cleanup moderately increase plant capital costs, this technology is well established and currently is practiced on a large scale. Oxygen is used to combust the fuel rather than air as in conventional systems thereby eliminating the formation of NO_X and the large volume of noncondensible exhaust gas. The oxygen is obtained from air via a number of processes, including commercially available cryogenic air separation units (ASU). Advanced air separation technologies such as those based on ion transfer membranes (ITM) hold promise for lowering the cost of oxygen and therefore are expected to enhance the economics of future oxygen using power generation systems.

SUMMARY OF THE INVENTION

The invention starts with oxygen blown gasification of coal. The resulting gaseous syngas is cleaned of corrosive components and burned with oxygen in the presence of recycled water in a gas generator. The combustion produces a drive gas composed almost entirely of steam and carbon dioxide. This gas drives multiple turbines/electric generators to produce electricity. The turbine discharge gases pass to a condenser where water is captured as liquid and gaseous carbon dioxide is pumped from the system. The carbon dioxide can be economically conditioned for enhanced recovery of oil or coal bed methane, or for sequestration in a subterranean formation.

OBJECTS OF THE INVENTION

Accordingly, a primary object of the present invention is to provide a power generation system which combusts a syngas produced from gasification of coal, biomass, or other fuel sources with oxygen to produce combustion products including carbon dioxide and water and to generate power without atmospheric emissions.

Another object of the present invention is to provide a power generation system which combusts a syngas fuel, such as coal syngas, with oxygen to produce power and which collects carbon dioxide in a form which can be sold as a byproduct or sequestered out of the atmosphere.

Another object of the present invention is to generate power from combustion of a hydrocarbon fuel with high efficiency and without any atmospheric emissions.

Other further objects of the present invention will become apparent from a careful reading of the included drawing figures, the claims and detailed description of the invention.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 is a schematic of the basic zero-emissions power generation system of this invention.

FIG. 2 includes schematic diagrams of a gas generator for combustion of syngas with oxygen for use in the power generation systems of this invention.

FIG. 3 is a schematic of a four hundred megawatt electric power generating plant operating on coal syngas and with zero atmospheric emissions with sets of three numbers at various locations throughout the power plant representative of pressure (top number in MPa), temperature (middle number in K) and weight flow (bottom number in kg per second).

FIG. 4 is a detailed schematic of a power generation system which is a variation on that which is shown in FIG. 3.

FIG. 5 is a power plant schematic for an integrated gasification combined cycle power plant fired with syngas and oxygen.

FIG. 6 is a schematic diagram of that which is shown in FIG. 5 and including supplementary heating.

FIG. 7 is a power plant schematic similar to that which is shown in FIG. 5, but additionally illustrating the inclusion of condensers and steam injection into a combustor of the power generation system depicted therein.

FIG. 8 is a schematic diagram of a power plant similar to that which is shown in FIG. 6, but additionally including the location of condensers and incorporating steam injection into a combustor of the power plant.

FIG. 9 is a schematic of an open cycle integrated gasification combined cycle power plant fired with syngas, illustrative of power plants known in the prior art.

FIG. 10 is a power plant schematic similar to that which is shown in FIG. 9 but with the inclusion of a carbon dioxide recovery system.

FIG. 11 is a power plant schematic featuring a base load steam turbine and a peak load steam turbine, along with a methanol reactor, distinguishing the system from the system shown in FIGS. 3 and 4.

FIG. 12 is a detailed schematic of a syngas powered power generation system similar to that which is shown in FIGS. 3 and 4, with the additional inclusion of hydrogen separation and fuel cells for additional electric power generation.

DESCRIPTION OF THE PREFERRED EMBODIMENT

A simplified schematic diagram of the basic process of the various embodiments of this invention is shown in FIG. 1. The use of coal in this system requires the conversion of coal to syngas by means of established oxygen-blown gasification and syngas cleanup processes. Oxygen is obtained from air in an air separation plant. The syngas, oxygen and water from the plant are delivered to a gas generator where combustion takes place. The syngas is combusted with oxygen in a gas generator while water is injected into the gas generator to control the temperature of the combustion products. The mixture of combustion products and cooling water form the drive gas for the turbines. This mixture, consists primarily of steam (H2O) and carbon dioxide (CO2). The combustion products of the gas generator preferably drive (i.e. are expanded into) multiple turbines, including a high-pressure turbine (HP), typically followed by an intermediate-pressure turbine (IP) and a low-pressure turbine (LP). The three turbines drive an electric generator. The turbine drive gas leaving the low-pressure turbine passes through a feed water heat recovery unit to a condenser where the carbon dioxide separates from the condensing steam.

Most of the water from the condenser is heated and returned to the gas generator to reduce the temperature of the combustion products in the gas generator to a temperature that is acceptable to the turbines. Excess water resulting from the combustion process is removed from the system.

Gaseous CO2 leaving the condenser passes to a recovery system. Residual moisture is removed from the CO2 in the recovery system where it is also cooled and compressed to conditions necessary either for sequestration into a subterranean formation, or for further use. For example, the CO2 can be used in enhanced oil recovery operations, injected into coal seams to recover coal bed methane, or processed into saleable products if local markets exist. With this process, atmospheric emissions of controlled pollutants and greenhouse gases are totally eliminated. The gas generator shown in FIG. 2 and described in patents listed above and incorporated herein by reference, enable the zero atmospheric emissions power systems of this invention.

The gas generator consists of an injector section, a combustor section, and a number of cooldown sections. These sections embody several aerospace derived design features to control mixture ratios, gas temperatures, gas pressures, and combustion reaction times. For instance, bonded photo-etched platelet designs are utilized to accomplish metering, mixing, and cooling functions. The injector can optionally premix the gaseous reactants (syngas and oxygen) with recycled water from the plant in precise ratios and incorporate an integral face-cooling feature. The combustor section and the cooldown sections are regeneratively cooled with recycled water. The amount of water injected into the combustor and into each cooldown section is controlled to produce specific combustion temperatures. Temperatures and residence times in those sections are selected based on reaction kinetics so that daughter species produced in the combustion process have time to recombine.

For a 400 MWe (Mega Watt electrical output) plant, three gas generators, each with a thermal output of 400 MWt (Mega Watt thermal output), would be used. The three gas generators would be installed in parallel. Two of the gas generators would drive the turbines of the plant while the third gas generator would provide a spare during service of the other units. A gas generator with 400 MWt thermal output operating at a pressure of 10.3 MPa has an internal diameter of 0.46 m and a length of 1.88 m.

FIG. 3 is a schematic diagram of a typical 400 MWe power plant using advanced turbine technology. The figure identifies major plant components and their power consumption. The plant efficiency is 55% based on the lower heating value of the coal and includes: 1) the syngas plant power consumption, 2) the power to the cryogenic air separation plant, and 3) the power to compress the CO2 to 20.7 MPa for sequestration.

In FIG. 3, the plant operating conditions are listed at various locations in the plant in terms of groups of three numbers; the top number is the local pressure in MPa, the middle number is the local temperature in ∫K, and the bottom number is the weight flow in kg/sec.

A gasifier converts coal to syngas at a rate of 66.55 kg/sec, while a 51.5 MWe cryogenic air separation plant produces oxygen for both the gasifier and the gas generator. Two gas streams (syngas and oxygen) enter the gas generator at a pressure of 17.24 MPa where they are joined by 139.35 kg/sec of steam.

The syngas from the gasification plant is combusted with oxygen in the gas generator. The combustion products are cooled in steps by adding water until the gas temperature is at the allowable high-temperature turbine inlet temperature of 922∫K to 1256∫K. The turbine drive gas leaving the high pressure turbine is preferably reheated by a reheater before it enters the intermediate-pressure turbine.

The intermediate-pressure turbine exhaust gases are delivered to the low pressure turbine. The exhaust from the low-pressure turbine is cooled in a feed water heater to the desired condenser inlet temperature. The heated feed water is delivered to the gas generator for use as a coolant to reduce the temperature of the turbine drive gas as described above.

The turbine exhaust gases which, by weight, contain approximately 66.2% steam, 33.3% CO2 and 0.45% nitrogen, oxygen and other non-condensables are cooled in the condenser with 306∫K cooling water. In the condenser, the steam condenses at approximately 311∫K and at 0.014 MPa. There is still moisture in the CO2 stream that does not separate without compression and further cooling.

The mixture of approximately 75% CO2 and 25% steam, by weight, is then pumped from the condenser using centrifugal compressors and is cooled in stages to remove the remaining water prior to liquefying the dry CO2 in a refrigeration plant. A small amount of gaseous nitrogen, oxygen and non condensables separate from the CO2 and are returned to the air separation plant. The liquefied CO2 is then pumped to a pressure typically ranging from 13.8 to 34.5 MPa for sequestration into subterranean oil strata, coal seams, or aquifers.

In FIG. 3, the CO2 is compressed to a pressure of 20.7 MPa for injection of the CO2 into a subterranean formation for sequestration. The 20.7 MPa pressure allows the CO2 to be injected into a permeable subterranean formation located at a depth of approximately 1,000 m or less.

An advantage of the technology of this invention over combined cycle technology is the lower cost to condition CO2 for sequestration of US$9.3/metric ton versus US$28.4/metric ton. This lower CO2 conditioning cost could provide additional revenue for these plants where the CO2 could be used for enhanced oil or coal bed methane recovery, or could be sold as an industrial by product.

FIGS. 4-12 illustrate multiple schematics depicting alternative non-polluting coal, biomass or other syngas fueled power generation systems. In FIG. 4 a variation on the system of FIG. 3 is shown. This FIG. 4 system uniquely includes four turbines and CO2 compressors for sequestration.

In the alternative embodiment of FIGS. 5-10 use of a Brayton cycle gas turbine powered by a working fluid generated within a combustor fueled by syngas from a gasifier fed with coal or biomass, or other carbon containing fuels is shown. The details of the open or closed Brayton cycle portion of the systems depicted in FIGS. 5-10 can be understood more clearly with reference to U.S. patent application Ser. No. 09/855,237, having a filing date of May 14, 2001, incorporated herein by reference. When the system operates as a combined cycle the bottoming cycle can be configured similar to the systems depicted in FIGS. 1-4 with steam for the steam turbine of the bottoming cycle generated by combustion of syngas produced from coal from a biomass or other carbon containing fuel. Alternatively, the bottoming cycle can be fueled with natural gas or other hydrogen, carbon or hydrocarbon containing fuels.

FIG. 11 depicts an alternative embodiment of the systems disclosed in FIGS. 1-10 with one or more of the systems of FIGS. 1-10 utilizable as part of an overall power generation system which is optimized for base load conditions and peak load conditions. Specifically, and as shown in FIG. 11, the air separation unit (ASU), whether an air liquefaction unit or utilizing some other technique for air separation, produces a stream of both gaseous oxygen (GO2) and liquid oxygen (LO2). The liquid oxygen is directed to a liquid oxygen storage tank. The air liquefaction unit is sized to produce more oxygen than is necessary to merely operate the base load power plant in the form of a steam turbine of a Rankine cycle or a turbine of a Brayton cycle. This excess oxygen would leave the air separation unit in the form of liquid oxygen and be directed to the liquid oxygen storage tank.

In periods where peak electricity demand exists, an additional power turbine (either a Rankine cycle steam turbine or turbines, or a Brayton cycle power generation system) would be brought into operation. Liquid oxygen from the liquid oxygen storage tank and potentially additionally gaseous oxygen from the air separation unit would be utilized as the oxidizer for a gas generator in this peak load portion of the overall power generation system. When peak load conditions pass, the peak load turbine would be shut down and the air separation unit would again store excess liquid oxygen.

An additional option of the system of FIG. 11 includes providing a methanol reactor where steam is combined with syngas to produce methanol (CH3OH). This methanol could be directed to a methanol liquid fuel storage structure. This methanol fuel could then be utilized during periods of peak load to power the peak load turbine. Natural gas could additionally be optionally utilized to drive the peak load turbine.

With this system of FIG. 11 an air separation unit and coal gasification plant can be provided which are sized smaller than a maximum power output for which the power generation system is capable. During base load conditions the air separation unit and coal gasification plant are producing excess liquid oxygen and methanol. During periods of peak load the oxygen and fuel beyond that produced by the air separation unit and coal gasification plant are provided by the liquid oxygen storage tank and fuel storage, and optionally a methane or a natural gas source.

The various components of the system of FIG. 11 can be selected from any of the components specifically described in any of the references incorporated into this application by reference, as indicated above. This system also optionally provides for hydrogen gas separation from the system. This hydrogen gas could be sold as an industrial gas or utilized to produce additional power, either by combustion of the hydrogen or by utilizing the hydrogen within a fuel cell.

FIG. 12 depicts an additional variation on the coal syngas or other syngas fueled power generation systems described in FIGS. 1-11. Specifically, FIG. 12 illustrates an embodiment where syngas produced by a gasifier fed with coal, petcoke, biomass, waste, etc. is diverted through a shift reactor or through other separation structures to separate hydrogen out of the syngas. This hydrogen can then be released from the system or fed to fuel cells to generate electric power along with the power generated by the turbines fed with steam and carbon dioxide generated within the gas generator.

The system of FIG. 12 provides an overall power generation system in which a carbon or carbon and hydrogen containing fuel is gasified and hydrogen is separated for power generation through hydrogen fuel cells. While the system of FIG. 12 generally depicts a Rankine cycle for the gas generator and turbines, the system of FIG. 12 could similarly utilize a Brayton cycle or combined Rankine and Brayton cycle combustion based power generation subcomponent alongside the fuel cell power generation subcomponent of this system. Specific details of the system of FIG. 12 are further amplified by particular reference to the preferably methane fired power generation system described in U.S. patent application Ser. No. 10/155,932 filed on May 24, 2002 incorporated herein by reference.

This disclosure is provided to reveal a preferred embodiment of the invention and a best mode for practicing the invention. Having thus described the invention in this way, it should be apparent that various different modifications can be made to the preferred embodiment without departing from the scope and spirit of this disclosure. When structures are identified as a means to perform a function, the identification is intended to include all structures which can perform the function specified.

Claims

1- A low or no pollution syngas fired power generation system, comprising in combination: a source of air; a source of water; a source of syngas, the syngas taken from the group including gasified coal, landfill gas, gasified biomass, gaseous refinery residues, gasified refinery residues, gasified petcoke, gasified waste or combinations thereof; an air separator having an inlet coupled to said source of air, an oxygen enriched air outlet and a nitrogen outlet separate from said oxygen enriched air outlet, said air separator adapted to separate at least a portion of the nitrogen from the oxygen within said air separator; said source of syngas including a gasifier having a fuel inlet, an oxygen inlet coupled to said oxygen enriched air outlet of said air separator, a water inlet and a syngas outlet, said gasifier adapted to chemically react the fuel with the oxygen from said air separation plant and the water to generate syngas for delivery to said syngas outlet; a syngas combustor, said syngas combustor adapted to receive syngas from said syngas outlet of said gasifier and oxygen from said oxygen enriched air outlet of said air separator, said primary syngas combustor adapted to combust at least a portion of the syngas with at least a portion of the oxygen to produce elevated pressure and elevated temperature combustion products including water and carbon dioxide, said syngas combustor adapted to receive water from said source of water separate from said oxygen and said syngas, said syngas combustor adapted to mix the water from said source of water with the combustion products created within said combustor, said combustor having a discharge for a combination of said water from said source of water and said combustion products; at least one combustion products expander located downstream from said primary combustor, said combustion products expansion device adapted to expand said combustion products and output power; a combustion products separator downstream from said at least one combustion products expander, said separator having a first outlet for combustion products including water and a second combustion product outlet for at least a portion of the carbon dioxide; wherein said gasifier is adapted to produce syngas including hydrogen; and a hydrogen separator located downstream from said syngas outlet of said gasifier, said hydrogen separator separating at least a portion of gaseous hydrogen from the syngas, such that said system is adapted to output hydrogen.

2- The system of claim 1 wherein said hydrogen discharged from said hydrogen separator is at least partially directed to at least one fuel cell, said fuel cell including an oxygen inlet coupled to said oxygen enriched air outlet of said air separator, and a water outlet for water generated within said at least one fuel cell.

3- The system of claim 2 wherein said water outlet of said fuel cell is coupled to said source of water for introduction into said syngas combustor.