HIGH EFFICIENCY POWER GENERATION INTEGRATED WITH CHEMICAL

PROCESSES

BACKGROUND 1. Field of Invention.

The invention is the field power plants, in conjunction with chemical processes, including the Fischer-Tropsch (FT) process. 2. Description of the Related Art.

As reserves of oil and natural gas dwindle, and the prices for these products escalate, industry and consumers will seek alternative energy options. In the power generation business in the U.S., and other areas of the world where it is abundant, coal is likely to become the fuel of choice due to its availability and price stability. However, other alternate fuels such as biomass, petroleum coke, municipal solid waste, and other carbon bearing fuels may present options as well.

However, with increased environmental demands, especially with the emerging awareness of global warming, power plants of the future must not only have low emissions of criteria pollutants such as nitrous oxides (NO _x ), sulfur oxides (SO _x ), and mercury, but must also implement methods to reduce and/or eliminate emissions of carbon dioxide (CO2).

In addition to power generation, the synthesis gas created by gasification, steam methane reforming (SMR), or other processes can be utilized to produce both chemicals and fuels. This includes a Fischer-Tropsch (FT) process in which synthetic liquid fuels can be formed. The FT process produces ultra-clean fuels that are low in sulfur content, have excellent combustion characteristics, and can be derived from domestic sources. This helps to lower the cost of transportation fuels, creates jobs domestically, and reduces the reliance on imported oil. Other processes such as methanol-to-gasoline (MTG) can also be employed to produce gasoline. In this process, syngas is first converted into methanol, and then subsequently converted into gasoline.

Although integrated gasification combined cycle (IGCC), chemical production, and FT processes are of interest, they can be very capital intensive, and therefore can be somewhat expensive compared to traditional methods of power generation, chemical production, and oil production. This makes these plants less attractive to potential developers, as less costly competitive methods of power generation or a drop in crude oil prices can lead to economic disaster for these projects.

Obviously, new technologies that can provide high efficiency power generation, produce chemicals, or make fuels, and do so with minimal CO2 emissions, will be desired in the future. Utilizing a highly efficient process that converts more of the energy content of the fuel into final products is key to improved economics and reduced CO2 emissions.

PRIOR ART

Coal-to-Liquids (CTL) Example

The coal-to-liquids (CTL) process and other chemical processes can be very similar to IGCC, in that many of these processes start with gasification (see Fig. 9). Note that although this process is referred to as "coal-to-liquids", it is not meant to preclude the use of petroleum coke, biomass, municipal solid waste, and other carbonaceous fuels. The word "coal" in the embodiment is meant to include coal and/or other fuels that can be utilized in the process (with the possibility of 2 or more fuels co-fired simultaneously).

Typically, for the CTL process, pulverized coal is injected into the gasification vessel along with a supply of air or high purity oxygen (95% or higher purity). Steam may also be injected into the gasifier. These streams react to create a synthesis gas or syngas. With an oxygen supply, the syngas is comprised of mostly carbon monoxide (CO), hydrogen (H ₂ ), carbon dioxide (CO ₂ ), and water vapor (H ₂ O), with smaller amounts of hydrogen sulfide (H ₂ S), carbonyl sulfide (COS), nitrogen (N ₂ ), and other compounds. Once the syngas is produced in the gasifiers, it must be processed so that it is acceptable for use in the FT reactors. These reactors contain a catalyst that enhances the formation of hydrocarbon chains. Thus the simple syngas constituents of CO and H ₂ can be transformed into hydrocarbons such as octane (CsHi ₈ ) and decane (CioH ₂₂ ). These hydrocarbons are the essential liquids found in gasoline and diesel fuel, respectively.

For the FT reaction to be optimal, it is important to eliminate as many of the non-essential species in the syngas, and provide as much of a pure CO/H ₂ stream as possible. In addition, the ratio of H ₂ to CO should be within a specified range for the catalyst to provide optimal conversion to liquid fuel. Also, since sulfur can contaminate the catalyst, the vast majority of it must be removed from the syngas. To help meet EPA standards and provide for less pollution when burned, the lower sulfur content of the syngas equates to an FT fuel that contains less sulfur.

Therefore, after the syngas exits the gasifier, it must be cooled from its exit temperature (nominally 2600° F for an oxygen-blown gasifier) to a nominal 100° F for entry into the syngas clean-up process. Typically this also involves the need for a "shift" reaction, which increases the ratio of H ₂ to CO to the optimal ratio for the FT reaction.

One method employed to achieve the proper syngas for the FT reactors involves syngas cooling, a shift reaction, further syngas cooling, a process for syngas clean-up, mercury removal, CO ₂ removal, and finally an H ₂ removal process to provide H ₂ for product upgrade at a downstream stage in the process.

The syngas cooling can be accomplished in several ways, but the two common methods are through a syngas cooler or a quench. A syngas cooler is essentially a heat exchanger that transfers the heat from the syngas to another fluid. Typically, the other fluid is pressurized water, which boils into saturated steam in the syngas cooler (although some superheating may also be accomplished). This steam can be used to generate electricity. However, the syngas coolers are large pieces of equipment that are capital intensive, and a simpler method is the use of a quench. The quench process involves spraying pressurized water directly into the syngas stream. The water evaporates into steam, and in doing so, cools the syngas/water mixture to a lower temperature. This is also advantageous, as the shift reaction requires a mixture of steam (H ₂ O) to CO of about 2.5 on a molar basis.

Once the syngas stream is cooled to the proper temperature (about 450° to 675° F for the high temperature shift reaction), the syngas/steam mixture is passed through a catalyst and the following reaction occurs:

H ₂ O + CO → H ₂ + CO ₂

Although the entire flow of CO is not converted to CO ₂ , the process is designed such that the proper ratio of H ₂ to CO will be available upon entry to the FT reactors. With the proper amount of the CO shifted to produce extra H ₂ (and the resultant CO ₂ ), the syngas is cooled further to approximately 100° F. Since the temperatures after the shift reaction are typically less than 1000° F, it is standard practice to cool this syngas with coolers that produce lower pressure saturated steam, since lower pressure steam boils at lower temperatures. Therefore, the syngas stream after the shift reaction may produce steam at a nominal 400 psia and/or 80 psia to reduce its temperature to about 250° F. From 250° F to 100° F, cooling water may be used, and the heat in this cooling water will likely be rejected to ambient. More than 99% of the steam contained in the syngas will be condensed in this cooling process.

Note that although the syngas now has more H ₂ content, it actually has less energy content. This is a result of the shift reaction, which is mildly exothermic. Therefore, this exothermic energy may be converted into medium or low-pressure steam in the downstream heat recovery processes (see the process flow diagram XMSU-1 -DW-021 -360-02B on numbered page 136 of DOE/NETL-2007/1281 )..

The 100° F syngas, which is now very dry, proceeds to a syngas clean-up process. This could include an amine process, Rectisol process, Selexol process, or other. The purpose of the clean-up process is to reduce the sulfur content of the syngas to about 1 ppm, remove NH ₃ , HCN, and other undesired species, and also to reduce the CO ₂ content. For chemical processes, including FT, a secondary bed (such as ZnO) may be required to reduce sulfur content to less than 50 ppb. In addition to the syngas clean-up process, the syngas will typically pass through a filter bed, which will absorb at least 90% of the mercury vapor in the syngas. The clean syngas now contains very few contaminants, and consists of primarily H ₂ and CO, with some small amount of CO ₂ (typically less than 5%). For optimum FT performance, it is desired to maintain the H ₂ to CO ratio at a desired level, depending upon the final product. Methanol production would favor a 2:1 H ₂ /CO ratio, while diesel or naphtha production may favor a ratio closer to 1 :1. As an example, the DOE has completed a study of a 50,000 barrel-per-day (BPD) CTL design. The optimum H ₂ /CO ratio is essentially 1 :1 in this example. See Fig. 1 for a general process schematic of this CTL facility (which is Figure ES-1 in the DOE/NETL-2007/1260 report which is hereby incorporated by reference).

With the syngas produced in the gasifiers being cooled, shifted to provide the proper H ₂ content, cleaned of all necessary contaminants, and mixed with any recycled gases from the process, it is now at the proper conditions for entry into the FT reactors (see FT Synthesis block 102 on Fig. 1 ). In this example, as the syngas passes through the catalyst in the FT reactors, longer hydrocarbon chains are produced, which ultimately are upgraded to the FT fuels as indicated in Fig. 1. This process is exothermic, and generates a great deal of heat. To control the reaction at its optimum temperature, heat exchange elements are contained within the reactor vessels that boil medium pressure water into saturated steam. The pressure that may be typical for this service would be 350 to 500 psia. This steam may be used to generate electricity. Also from this process, a tail-gas is produced. In addition, an off-gas is produced in the product upgrade portion of the process. Both the tail-gas and the off-gas can be combusted in a gas turbine (GT), boiler, duct burner, or other device designed to combust fuel.

As indicated in Fig. 1 , a CTL plant designed to produce 50,000 barrels per day (BPD) of FT liquids can also produce a net power output of 124 MW. Based upon the energy input of the coal, the energy utilization factor for this plant is 47%, meaning that 47% of the input energy of the fuel (coal in this example) ends up as a final product, either liquid fuel or electricity. Other Chemical Processes

The CTL process is one example where a stream of syngas is created, cleaned, and subsequently converted into a final product. Other processes include, but are not limited to, the production of methanol, synthetic natural gas, ammonia, gasoline, and other fuels and/or chemicals.

Whether the syngas is created through gasification, steam methane reforming (SMR), pyrolysis, or another process, these processes typically occur at high temperatures, and the possibility exists to reclaim energy from these streams prior to the actual chemical conversion process. The preferred embodiment of the present invention seeks to capture more of this energy and utilize it to co-generate electricity and make the overall energy conversion more efficient.

Integrated Gasification Combined Cycle (IGCC)

To produce electricity, an IGCC plant can be built to use coal as fuel. However, when CO2 is separated for sequestration, both the output and efficiency are impacted. This is evident from the DOE report labeled DOE/NETL-2007/1281 , which is hereby incorporated by reference. See Fig. 2 for a summary of the data for the various cases from this DOE report. Case 5 from this report (hereafter referred to as "Case 5") uses the Shell gasification process and produces a nominal 636 MW at 41.1 % efficiency. However, when CO ₂ separation is employed as in Case 6 (hereafter referred to as Case 6), more coal input is required, the output decreases to 517 MW, and the efficiency is reduced to 32.0%. See Fig. 2 for a tabulation of the results for this study.

In addition, the sulfur emissions of the IGCC plant are somewhat high, as the sulfur content of the syngas is approximately 30 ppm (parts per million). This is significantly higher than the 50 ppb (parts per billion) or less that is attained in the syngas for the CTL facility (note that the DOE CTL report used a ZnO bed to reduce sulfur content of the syngas to 1 ppb). Also, this higher level of sulfur in the fuel results in high SO _x content in the GT exhaust gas. This prevents the use of SCR (Selective Catalytic Reduction) in the HRSG, as the SO _x reacts with injected ammonia from the SCR and forms ammonia salts downstream of the SCR. These salts foul the downstream heat exchange surfaces in the HRSG. Therefore, NO _x must be controlled in the GT, as downstream treatment with SCR is not feasible with the higher syngas sulfur content. Current GT combustion technologies reduce NO _x to about 15 ppm.

SHORTCOMINGS OF PRIOR ART

Using CTL as an example of chemical conversion, it is noted that although the CTL process from the prior art can produce the desired liquid fuels, it is not very optimal at producing electricity. Saturated high-pressure (HP) steam from the syngas coolers and saturated medium-pressure (MP) steam from the FT reactors is not at ideal conditions for producing power in a steam turbine. Also, the medium pressure and low-pressure (LP) steam generated in heat recovery devices is not ideal for power production. In the power island, where the gas turbine (GT) and steam turbine (ST) are located, the overall cycle is somewhat inefficient. The off-gas (referred to as "Fuel Gas" 104 in Fig. 1 ) from the product upgrade is used as fuel in the GTs. Since this gas is at a low pressure of 20 psia, it requires a great deal of compression power (24,709 kW in this example) to pressurize this fuel to the extent required for use in the GTs 106. The exhaust gases of the GTs 106 are utilized to superheat some of the steam from the process, and may generate some additional steam as well, at the various pressures, HP, MP, and LP. This steam is heated only to the extent possible with the GT exhaust gas energy. This equates to a less than optimal steam cycle. It may be possible to produce more steam from more efficient heat recovery, but this would reduce steam temperatures to the steam turbine. The GTs in the example from the prior art produce only 250.7 MW, while the STs 108 produce 401.3 MW. Therefore, the majority of the power is emanating from the inefficient steam cycle.

The overall energy conversion rate for this CTL process from the prior art is approximately 47%. From an environmental perspective, this method of fuel production may produce more CO2 emissions than refining crude oil into similar petroleum products, even with the use of CO2 separation.

For additional power that has low CO2 emissions, an IGCC plant could be built per the designs indicated in the report labeled DOE/NETL-2007/1281. For example, the IGCC plant shown in Case 6 identifies a plant that produces 517 MW of net power. It too, utilizes Carbon Capture and Sequestration (CCS) to achieve low CO2 emissions. Its efficiency, however, is only 32%. It also has relatively high SO _x and NO _x emissions (compared to the case 14 natural gas-fired facility) and will be considerably expensive to construct. As a reference, Duke has announced a 630 MW IGCC plant in Indiana that does not include CCS (similar to Case 1 of DOE/NETL-2007/1281 ) that is projected to cost $2.35 billion. So the prior art can provide both CTL and IGCC facilities, however, the conversion efficiencies need improvement, the high costs of construction need to be reduced, and the environmental performance can be better.

SUMMARY OF THE INVENTION

To alleviate these concerns, a new process that is not only more efficient, but also more environmentally friendly is desirable. Also, a more efficient power island that will help to improve the overall electrical output is also desirable. Lower cost is always of paramount interest. Ultimately, this embodiment demonstrates an integrated, state-of-the-art facility that is more efficient than separate conventional chemical conversion and IGCC processes, can readily be designed for ultra-low emissions, and yet is economical to construct. For an incremental increase in cost and fuel consumption, the systems and methods of this invention can produce significantly more products such as electricity, fuels, and chemicals. These and other benefits, features, and advantages will be made clearer in the accompanying description, claims, and drawings.

DRAWINGS

Fig. 1 is a flow chart of the conventional CTL process, Fig. ES-1 from DOE/NETL-2007/1260.

Fig. 2 is a cost and performance summary for power plants, Fig. ES-2 from DOE/NETL-2007/1281. Fig. 3 depicts a method for optimizing the H ₂ /CO ratio of feed gas with H ₂ stripping.

Fig. 4 depicts a method for optimizing the H ₂ /CO ratio of feed gas with minimal shift.

Fig. 5 is a comparison of power cycles with and without steam superheating. Fig. 6 is a general arrangement of the present invention for an FT process.

Figs. 7A and 7B depict the syngas cooling and shift for the example of the present invention.

Figs. 8A, 8B, 8C, and 8D together make up a flow schematic of the power island for the example of the present invention. Fig. 9 is a general flow chart for gasification processes and end products

Fig. 10 depicts a conventional ASU air compression arrangement Fig. 11 depicts an ASU air compression arrangement for the present invention Fig. 12 is a general arrangement of the present invention

DESCRIPTION Introduction

A new, high efficiency integrated facility that produces electricity in conjunction with fuels and/or chemical production can be constructed by utilizing state-of-the-art techniques that demonstrate synergistic relationships. One of these new techniques is described in US Patent #6,230,480 (the '480 patent), and subsequent patents. A description of this integrated facility, its features, and novel concepts, is described herein.

Synergistic Relationships There are synergies that exist between the chemical/fuel production process and power generation. Following is a list of some of the synergies that power generation has with these processes:

1 ) Unreacted gas from the conversion process can be utilized as fuel in the power island

2) Some unreacted gas can be created at high pressures sufficient for supply to a modern gas turbine (GT) 3) Some unreacted gas or liquids from the various processes can also be utilized in the power production portion of the facility

4) Other unreacted gas, produced at a low pressure can be utilized in the duct burners, versus the GT's, saving considerable compression power.

5) The gasification, SMR, or other process may include syngas coolers that produce steam that can be utilized in the power island

6) The conversion process produces steam that can be used in the power island

7) Boiler feedwater (BFW) can be preheated by some process flows to provide preheated BFW to the steam producing sections of the plant 8) CO2 from the process can be removed

9) Some carbon may be captured in the final products 10)With a low ratio of nitrogen diluent to total Air Separation Unit (ASU) air supply, some or all nitrogen diluent for the GT may be removed as liquid from a cryogenic separation process and pumped rather than compressed, saving additional parasitic power.

11 )With relatively low nitrogen requirements in the power island, excess nitrogen can be heated and used for feedstock drying, in lieu of using fuel for this purpose.

12)With reduced quench, and minimal shifting of the syngas, less water may be consumed in the plant.

13) Integration with the ASU preheats boiler feedwater for increased production of steam

14)A unique water/gas shift process recovers more energy as high pressure steam The power generation plant also has synergies with the chemical conversion process. Following is a list of some of these synergies:

1 ) Power is provided to the plant.

2) Steam may be required at several pressure levels in these plants. Steam can be extracted from the steam turbine to supply some or all of these requirements.

3) Cold BFW from the power island can be used to cool process streams in the plant

4) Tail gases, off gases, and other streams do not have to be flared, but can be used as fuel in the power island.

5) With BFW cooling, less cooling water may be required.

6) Emission control devices such as Selective Catalytic Reaction (SCR) equipment can be included in the Heat Recovery Steam Generator

(HRSG) to control NO _x emissions.

7) Steam heating may be employed in lieu of fired heaters that consume fuel (syngas, tailgas, offgas, etc.), increasing overall efficiency.

8) Syngas coolers in lieu of the quench process may reduce the amount of water consumed by the plant.

9) Since many of these chemical conversion plants contain power plants in their conventional designs to generate internal power requirements, additional power may be added for only an incremental increase in cost

Overview

Fig. 12 is a general arrangement of the preferred embodiment of the present invention. A feedstock 220, including natural gas, coal, biomass, petroleum coke, municipal solid waste, or other carbonaceous material, or combination thereof, is fed to a device 222 that converts said feedstock into a synthesis gas 224. Such devices include gasifiers, SMR's, pyrolysis chambers, and others.

Some or all of this syngas can be directed to a syngas cooler 226. The syngas cooler accepts pressurized boiler feedwater 280, preferably preheated since this will increase the steam production, and subsequently cools the syngas, while the heat given up by the syngas boils the BFW into steam 282. This steam can then be used in the power island.

The cooled syngas 228 leaves the syngas cooler and continues to a cleanup process 230. Although conventional practice would use the energy in this syngas to create lower pressure steam, the preferred embodiment cools this portion of the process with cold BFW 284. This preheats the BFW 286, which can then be used to generate steam in other portions of the integrated plant.

After cleanup, the clean syngas 232 can be directed to the conversion process 238. This includes SNG, FT, methanol, or other conversion processes. Some of the clean syngas can also be directed to the power island to be used as fuel 234. As the syngas reacts in the conversion process, heat is generated. This heat can be captured as steam 290. Again, preheated BFW 288 is the preferred supply, as it will result in more steam generation. Some BFW may be preheated in the conversion process. The conversion process, which may consist of multiple steps, produces the final products 240 from the process. In addition to these final products, byproduct fuels, sometimes referred to as tailgas, offgas, or other names, may be produced. These fuels may be produced at higher pressures 242 and/or lower pressures 244, and can be utilized in the power island to generate electricity. By recouping energy from the HRSG, syngas cooling, process cooling, and the ASU, much more preheated feedwater is produced than in conventional processes. This preheated feedwater, when directed to the syngas cooler and conversion process, generates greater steam flows, as available energy from these processes can be used to boil said water, versus heating cold BFW up to boiling temperature.

With these higher steam flows, more high-end energy (higher temperature) is needed to superheat and reheat this steam to the temperatures used in modern, efficient steam turbines (typically 900° to 1150° F). Therefore, the most synergistic combined cycle for this purpose is that described in the '480 patent, with its HRSG that incorporates high degrees of supplemental firing.

The synergistic power island 250 accepts the higher-pressure tailgas 242 for supply to the GT 252, and in addition may also utilize some of the syngas 234 from upstream of the conversion process. These fuels, at higher pressure, are ideally suited for use in the GT; however, some compression may still be required to meet the fuel pressure requirements of the GT.

Lower pressure fuels 244 are ideally suited for use in the duct burners 254 in the HRSG 270, as the fuel pressure requirement for duct burners is much lower than that of a GT. Again, to meet the steam cycle requirements, syngas 234 from prior to the conversion process may also be used as supplemental fuel in the duct burners. So a mix of fuel, preferably at higher pressure, is supplied by streams, 242, 234, and possibly 244. This mix is used as a fuel supply 246 to the GT. For the duct burners, a mix of fuel, preferably from the lower pressure sources, is supplied by streams, 244, 234, and possibly 242. This mix is used as a fuel supply 248 to the duct burners.

To maximize electrical output and cycle efficiency, HP steam 256 recovered from the plant is directed to the HRSG. This steam is combined with HP steam generated from within the HRSG and directed to the superheater section 258 of the HRSG. This superheated steam is sent to the HP section 260 of the ST, where it expands to a lower pressure. The steam exiting the HP section, referred to as "cold reheat steam", can be combined with medium pressure steam 262 from the process, and redirected to the HRSG. This steam can be reheated in the reheat section 264 of the HRSG (although preferable, it is not necessary) and subsequently directed to the IP section 266 of the ST. From this point, the steam expands to lower pressure, and in many instances, to the pressure in the condenser. Some steam 268 may be extracted from the ST, at any point or pressure; to supply steam needs for the plant or process.

Since large quantities of steam may be generated in the overall integrated plant, large quantities of BFW are required to produce this steam. Preheated BFW is preferable, as it will allow for more steam production. Preheated BFW is also produced in the HRSG. Cold BFW 272 enters the HRSG and is preheated in the economizer section 276 downstream of the evaporator 278. Some of this preheated BFW is directed to the evaporator section, however, some preheated BFW 274 is diverted to other sections of the plant to aid in the production of steam. Also, to aid in said steam production, a specially designed ASU provides preheated BFW 298 to the plant for increased power production and increased integrated plant efficiency. Improved Steam Production

Due to the inherent inefficiency of the quench process and the shift reaction, a new process that can provide improved heat recovery, increased steam production, and ultimately more electricity is desired. The problem with this approach is that the process may not create an appropriate syngas stream with the correct H ₂ /CO ratio for supply to the FT reactors. However, with careful planning, a process that minimizes the quench process and the shift reaction can be utilized.

Although the prior art utilizes a single process for syngas shift and cooling, the preferred embodiment employs other methods to achieve this goal. One method is to make excess syngas (more than is required by the FT process), and create two separate streams. The first stream is the primary stream, while the second is the secondary stream. From the secondary stream, isolate and remove the needed specie (typically H ₂ ), to form stream X. Now mix this highly pure stream X with the primary stream to achieve the necessary flow, composition, and H ₂ /CO ratio needed in the downstream process. The secondary stream, now depleted of some of its flow, can be used as fuel elsewhere in the plant. In other words, for processes that need higher H ₂ in the syngas, for instance, this can be accomplished by increasing the rate of gasification, and thus the rate of syngas production (see Fig. 3). The excess amount of syngas from the secondary stream 110 provides the necessary hydrogen 112 for the process, and the remaining portion of the excess syngas 114, now depleted of some of its hydrogen, can be utilized, for instance, in the power production portion of the facility (referred to here as the "power island").

This can actually simplify the process, as the quench process is eliminated and the shift reaction is eliminated in favor of steam production via a syngas cooling system. With proper gasification, a more accurate control of the syngas composition and H ₂ /CO ratio may be possible by injecting the proper amount of H ₂ from the removal process into the syngas stream that is destined for the chemical conversion process. The drawback to the approach is that the remaining gas 114, now depleted of some hydrogen, will have a higher concentration of CO, and thus will create more CO ₂ emissions when combusted. This could be alleviated by subjecting the remaining gas 114 to a shift reaction, and subsequently removing CO ₂ . This would create a high H ₂ content gas for the power island. Another approach is to minimize the quench and shift processes (see Fig. 4). Utilizing some syngas from a stream with syngas cooling and no shift 150, and mixing this with syngas from a quenched and shifted stream 152 will accomplish this. Thus, the amount of steam/water supplied to the syngas stream for shifting is minimized, and less energy is relegated to "low energy level" status when the unreacted steam in the syngas is condensed at low temperatures. This process minimizes water consumption and maximizes the production of steam through the use of syngas coolers versus the use of the quench process. Besides the greater quantity of HP steam that is produced by the syngas coolers, the advantage to this method is that the fuel to the power island has higher H ₂ content, therefore, it will produce fewer CO ₂ emissions when combusted.

General Description

The syngas from the gasification process can be directed to syngas coolers to extract heat, and produce steam that can be used in the process or in the power island. To achieve the proper H ₂ /CO ratio, either H ₂ or CO can be stripped from a secondary flow stream and supplied to the primary stream (Fig. 3), or the use of quench and/or the shift reaction may be used to adjust the ratio of a portion of the syngas, which can again be mixed with the primary syngas stream (Fig. 4).

Once the method for obtaining the proper amount and composition of syngas is devised, it is necessary to direct the syngas to a cleanup system. This system removes particulates, ammonia, cyanide, and other undesirable species from the syngas stream. Of paramount importance, is the removal of sulfur bearing compounds. These compounds can poison the catalysts in the chemical conversion process, and therefore, must be minimized. For instance, the syngas to the FT system should contain no more than 50 ppb of sulfur bearing compounds.

During syngas cleanup, it is also typical to include some CO ₂ removal, as the chemical reactions in the conversion process are typically improved when fewer inert materials are included in the syngas. Also, this process can be employed to reduce CO ₂ emissions, as the CO ₂ stripped from the process can be sent to a sequestration site.

Once the clean syngas is directed to the chemical conversion block, the H ₂ and CO react to form final products, such as methanol, methane, FT liquids, and others. Some CO2 and H ₂ O may be generated in the process. Also, these processes are exothermic, and considerable heat is generated. However, to control the temperature at the appropriate level, heat exchange tubes may be embedded in the appropriate place in the process. These tubes typically contain water that is pressurized to the appropriate pressure such that steam is created at the desired temperature to ultimately control the reaction temperature. As a result, large quantities of saturated steam at medium pressure may be produced as a byproduct of the reaction.

Referring to Fig. 6, this medium pressure saturated steam 154, along with high-pressure saturated steam from the syngas coolers 130, can be directed to a highly fired HRSG 156 as described in US patent 6,230,480 et al. The high firing temperatures in the HRSG provide the necessary heat to superheat and reheat the HP steam 130, and to superheat the medium pressure steam 154. This is an important step to achieving higher efficiencies. It is well known in the industry that superheated steam is more efficient in a power cycle than saturated steam. See Figure 5, case 1 for a depiction of a steam cycle. Saturated steam at 438 psia (453.57° F) 116 is admitted to the steam turbine 118. Utilizing the Spencer-Cotton-Cannon curves for steam turbine efficiency, and expanding the steam to 2" HgA (0.98 psia) exhaust pressure; the net output for this unit with an inlet flow of 1 ,000,000 Ib/hr is 85.336 MW 120.

Also in Figure 5, see the 2 ^nd steam turbine 122, which utilizes the same saturated steam flow, however, prior to its introduction into the steam turbine, it is heated in the HRSG 124. In this scenario, energy is added to the saturated steam to create superheated steam at 1050° F. This steam is now admitted to the steam turbine 122. For case 2, the steam turbine output increases to 137.940 MW.

By superheating the steam, the incremental heat rate is defined as the added energy (344.3 MMBtu) divided by the incremental power (52.604 MW). This equates to 6545 Btu/kWh. This equates to an efficiency of 52.1 %, and is significantly better than the heat rate of 10,674 Btu/kWh (32.0%) listed in Fig. 2 for Case 6. Therefore, this use of heat addition to the saturated steam flows can enhance performance and efficiency.

Note that these are similar principles to those discussed in US Patent 6,230,480 et al. So the overall design concept is to capture more steam from the gasification process and chemical conversion process, and utilize the steam produced to its maximum potential to generate electricity. Thus, energy must be provided to the power island. This energy can come in the form of tail gases and off gases from the chemical conversion process, from syngas streams directly from the gasification system, or from syngas streams that have been depleted of some of their species (i.e. a syngas stream which has been stripped of some H ₂ ).

The integration of this process in the preferred embodiment of the present invention utilizes a power island 134, consisting of a GT, HRSG, and a ST. See Fig. 6 for a general arrangement of the present invention used with an FT process. It also could include a Boiler in lieu of a GT and HRSG. Some fuel from the FT process or syngas is directed to the GT 126 for power production, while some fuel is utilized in the duct burners 128 of the HRSG. High-pressure steam 130 from the syngas coolers 132, which is typically saturated, is directed to the superheaters in the HRSG 170. This superheats the HP steam flow. This superheated steam is sent to the HP section136 of the steam turbine.

In addition, steam from the FT process 154, which is typically saturated and at medium pressure, can be directed the cold reheat line exiting the HP section of the steam turbine. These steam flows are mixed 172 and directed to the reheater sections 174 of the HRSG. In these sections, the mixed steam flow is superheated and directed to the Intermediate Pressure (IP) section of the steam turbine 144.

To enable the process to generate more saturated steam, higher temperature boiler feedwater (BFW) 138 can be provided to the syngas coolers and the FT process coolers. The HRSG, the low temperature syngas coolers 140, and FT process coolers 142 can supply this higher temperature boiler feedwater 138. In addition, a feedwater-heating loop, consisting of a series of feedwater heater(s) can be employed to preheat water prior to its introduction into one of the boiling devices. ASU Integration

Also, BFW can be preheated in a specially designed ASU. Cryogenic ASU's compress atmospheric air prior to the cryogenic separation process. This air compression consumes a great deal of power, so steps are taken to minimize these power requirements, including the use of intercooling between stages of compression. Fig. 10 illustrates a conventional ASU arrangement from the prior art. To provide oxygen, the ASU first compresses and cools air. Ambient air 300 enters a compressor 302 and is compressed to an intermediate pressure. After this compression process, the air temperature is increased. Since it takes more energy to compress hot air than it does to compress cooler air, this intermediate pressure air is then cooled in an intercooler 304. A supply of coolant, 312, is used to cool this air. This coolant is typically water.

The cooled intermediate pressure air it subsequently compressed in another compressor 306 to the final required pressure. This air, also heated by the compression process, is now directed to an aftercooler 308 that again uses a coolant 314. The cooled and compressed air 310 is directed to the cryogenic separation process.

Note that Fig. 10 depicts a simple 2-stage system. This may be a multiple stage system, with multiple compressors and multiple coolers. The coolant is typically water directly from the cooling tower of the plant, or may be from a separate auxiliary cooling loop. The energy from these coolers is ultimately rejected to ambient without assisting in the power generation process.

In contrast, the preferred embodiment will utilize the energy from the ASU to its advantage in generating power. For this new arrangement, see Fig. 11. Ambient air 320 is drawn into a compressor 322. This air is compressed to an intermediate pressure and then directed to a 2 ^nd compressor 326. This elevates the temperature of the air as well as its pressure. This air is subsequently directed to a cooler 324. This cooler utilizes cold BFW 332 as a coolant, and the preheated BFW 336 is used in the process to generate additional steam in the steam generating devices (syngas coolers, process coolers, HRSG, and other). Upon exiting cooler 324, the compressed air is sent to a secondary cooler 328 that cools the compressed air 330 to the same temperature as the conventional ASU prior to its introduction to the cryogenic process.

Table 9 provides data that corresponds with the labeled data on each stream identified in Fig. 10. Note that the conventional ASU from the prior art requires 276.4 MW of power for compression in this example. All energy from the coolers is rejected to ambient. In addition, the conventional ASU from the prior art requires 13.5 million Ib/hr of cooling water flow at a supply temperature of 71 ° F, and a return temperature that is between 135° and 140° F. This equates to 27,000 gallons per minute (gpm).

Table 10 provides data that corresponds with the labeled data on each stream identified in Fig. 11. In this example, which closely corresponds with the CTL example herein, the air is compressed and subsequently cooled first with BFW. This cooling process captures 956 MMBtu in the BFW preheat. This is equivalent to about 980 tons per day of coal, or about 3.3% of the total energy input of the fuel in said CTL example. Thus, this new invention provides 2 million Ib/hr of preheated

BFW at 1940 psia, 545° F. However, the power required to compress the air increases to 326 MW, or about 50 MW over the prior art. This preheated BFW will enable the production of additional steam in steam generating devices.

For instance, if the BFW enthalpy into an FT reactor is 200 Btu/lb, and the enthalpy of the boiled steam is 1200 Btu/lb, 1000 Btu/lb is the necessary energy input to boil the incoming water into steam. If this BFW is instead replaced by the preheated BFW from the ASU at 541 Btu/lb, Only 659 Btu/lb is required to boil this water into steam. Therefore, overall steam production from this device is increased by 52%.

For the CTL example contained herein, this would increase steam production from in the CTL process from 3.77 million Ib/hr to 5.72 million Ib/hr, for a net increase of 1.95 million Ib/hr. To superheat this steam flow would require approximately 1000 tpd of additional coal input. This would increase plant parasitic load by a nominal 20

MW.

Therefore, the added steam would produce approximately 275 MW, however,

70 MW would be used to provide the added power for air compression in the present invention ASU and the added load for an additional 1000 tpd of coal throughput.

This equates to 205 additional MW for sale to the grid. Since 1000 tpd of coal input is equal to approximately 972 MMBtu in the CTL example, this additional power comes at a heat rate of -4750 Btu/kWh, or 72%. Thus this can enhance the efficiency of the overall process. In addition, the new ASU from the preferred embodiment of the present invention only requires 2.0 million Ib/hr of cooling water flow at a supply temperature of 71 ° F, and a return temperature that is less than 125°. This equates to only 4,000 gpm. Thus the ASU from the present invention utilizes less cooling water, and rejects less heat to atmosphere.

Power Island The power island is the power generation portion of the plant. In this section of the plant, gases and other fuels from the process are fed to a GT and duct burners contained within the HRSG. High-pressure steam from the various aforementioned sections of the plant, along with steam from the HRSG, is superheated in the HRSG prior to its introduction to the ST. Higher temperatures yield higher efficiencies, so temperatures of 1000° F or greater are preferred.

After expanding through the HP section of the steam turbine, the exiting steam (cold reheat steam) can be combined with the medium pressure steam from the process. This combined steam flow may then be reheated in the HRSG prior to its introduction into the IP section of the ST. Steam may be extracted from the ST at one of more pressures for use in the plant.

The overall concept of this integrated plant is to create more steam, and more efficient steam for the production of power. Since the power island utilizes an HRSG where the heat input to the duct burners is 30% or more of the input to the GT, a great deal of steam superheating and reheating can be accomplished. The other advantage to this arrangement is the heat recovery aspects. Since this integrated process, with its high duct burner input, creates a larger quantity of steam, more BFW is needed for this steam production. Therefore, in lieu of production low-pressure steam to recoup process heat, the large quantities of cold BFW from the condenser can be utilized to recover lower temperature energy. An example would be the HRSG, which primarily produces steam at high pressure, and uses cold BFW to cool the exhaust gases from the GT to industry standard temperatures (near 200° F for the aforementioned example)

Therefore, by utilizing energy that might be otherwise rejected to ambient, upgrading such energy in the HRSG to a more efficient state, and using a more efficient cycle, the power island provides a step change in cost and efficiency for chemical conversion and power generation.

To minimize fuel compression requirements, the off gases, typically at lower pressures, can be directed to the duct burners, which may only need a fuel supply pressure of 50 psia. Higher-pressure fuel such as the tail gases (recycle gases from DOE/NETL-2007/1260), as well as clean syngas, can be used in the GTs. Large, modern GTs require fuel pressures in the vicinity of 450 psia.

This evaluation is based upon the use of Illinois #6 coal as fuel, as listed in both DOE/NETL-2007/1260 and DOE/NETL-2007/1281 , however, the use of other coals, fuels, or mixes of fuels can be employed in the gasification process.

Exemplary Benefits The benefits to the deployment of the present invention are numerous and significant. The first benefit is greater efficiency. Since more energy is captured and utilized in the present invention, the overall conversion efficiency is increased. In the CTL example that follows, overall conversion efficiency of comparable conventional facilities (CTL & IGCC) is 42.4%. However, the present invention demonstrates an overall conversion efficiency of 50.2%. This represents an 18.4% increase in efficiency for the present invention.

From an environmental perspective, the present invention also achieves lower environmental impact. Although IGCC can employ technologies for deep sulfur removal (such as the present invention), these technologies increase the cost of an already expensive method for power generation. Thus, the conventional equivalent plants emit a nominal 0.10 Ib/MWh of SO2 emissions, versus almost zero sulfur emissions for the present invention. In nominal numbers, this is a 100:1 reduction in sulfur emissions as compared to conventional technology.

For NO _x emissions, the conventional IGCC controls this pollutant by combustion techniques within the GT. Downstream SCR control cannot be employed due to the high levels of sulfur in the GT exhaust. For the CTL example contained herein, calculated NO _x emissions are 0.768 Ib/MWh. Due to the use of SCR, and the use of fewer GT's (less exhaust gas to treat), the projected emissions for the present invention are 0.077 Ib/MWh. So the NO _x emissions are reduced by a nominal 10:1 factor.

In addition, the CO2 emissions are also reduced. In the CTL example, CO2 emissions for the conventional plants are 6,085 tons per day, versus only 5,045 per day for the present invention. Of considerable interest is the quantity of CO2 that must be sequestered. The conventional plants require 56,464 tons per day of CO ₂ be sent to sequestration, while the present invention requires only 41 ,437 tons per day.

Tests by the U.S. Air Force and other agencies have shown that FT fuels burn cleaner and emit less pollution than conventional fuels derived from petroleum. So further environmental benefits will be realized from the products produced in an FT plant.

Another considerable benefit to the present invention is a reduction in overall plant costs. Due to its increased efficiency, the present invention can utilize less equipment to achieve the same rate of production. For the CTL example, the present invention can utilize fewer and/or smaller gasifiers than the prior art. This equates to both a lower up front capital cost, as well as lower on going maintenance costs. This same principle also applies to the ASU's, which are used in conjunction with gasifiers.

Much of this cost benefit is derived from the high power density power island. It is well known in the industry that supplemental firing in an HRSG adds low cost capacity. General Electric Informative document GER-4200 discusses methods of combined cycle power enhancement, and concludes the supplemental firing in the HRSG is the preferred method. They also discuss the detrimental effects that this practice has on overall plant efficiency. The '480 patent, however, embraces the concept of supplemental firing in the

HRSG, and overcomes the detrimental effects on efficiency. In cycles that are integrated with chemical processes, where a great deal of steam is generated at lower temperatures, the principles illustrated in Fig. 5 can be employed to actually increase overall plant efficiency. Therefore, the preferred embodiment of the present invention increases efficiency and reduces capital costs by exploiting the low costs benefits of supplemental firing in a combined cycle, but also be using said supplemental firing to increase the efficiency of the steam cycle.

In the prior art, the CTL plant from the DOE report included 251 MW of GT output and 401 MW of ST output. Two IGCC plants from Case 6 include 927 MW of GT output and 460 MW of ST power (gross power generation). This is a total of 1 ,178 MW of GT power and 861 MW of ST power. The ratio of ST to GT power in the prior art is 0.73. Even with a great deal of supplemental firing, it would be difficult for this ratio to be greater than 1.0. So for a CTL plant, with little export power, the ST/GT ratio is 1.6. As more power is added, this ratio is diminished in the prior art, to a ratio of 0.73 when 1034 MW of power is added. Therefore, the prior art is limited to ST/GT ratios of 1.6 or less when small amounts of export power are included. For CTL applications, when the fuel production/power ratio (FP/P) is 50,000/125, or 400, the ST/GT ratio is 1.6. When this is increased to 50,000/1159, or 43, the ST/GT ratio is 0.73. For added power in the DOE CTL facility, an additional GT could be used. This would actually increase GT and ST power, approximately 83 MW for the GT and 50 MW for the ST. This would actually decrease the ST/GT ratio to 1.35. With low For the present invention, it is anticipated that the FP/P ratio will be less than

200. The GT gross power output is 464 MW, while the ST power output is 1 ,138 MW. This equates to an ST/GT ratio of 2.45. The prior art would not see ST/GT ratios above 1.6 when the FP/P ratio was less than 200. Example of the Present Invention

The following process, data, heat balances, and description exemplify one application of the present invention. It is based upon data from the DOE/NETL- 2007/1260 and DOE/NETL-2007/1281 reports, and the systems and methods of the present invention. An examination of the CTL process in DOE/NETL-2007/1260, as disclosed in

Fig. 1 herein, reveals that the combined flows (streams 10, 11 , plus 16) into the F-T Synthesis Block contain 80,464 Ib-moles (referred to as moles) of H ₂ and 82,077 moles of CO. Other species such as CO ₂ , CH ₄ , N ₂ , Ar, and others are considered to be inert in the F-T reaction. Therefore, by providing the same flows of H ₂ and CO to the F-T Synthesis Block 102, the same amount of F-T products should be produced.

These flows can be supplied utilizing the Shell gasification process. Therefore, the gasification process detailed in the DOE/NETL-2007/1260 will be replaced by the gasification processes shown in DOE/NETL-2007/1281. By utilizing 3.563 times the flow indicated in Case 5, stream 17, (syngas production with no shift) and combining this with 1.135 times the Case 6, stream 18 syngas flow (shifted syngas), a stream containing 80,464 moles of H ₂ and 82,077 moles of CO can be created. This flow will be supplied directly to the F-T Synthesis Block 102. Note this utilizes the minimal shift process (Fig. 4), where only a portion of the syngas produced is actually subjected to the shift reaction. This negates the need for recycle flow, stream 16, from the CTL process (DOE/NETL-2007/1260). As a result, streams 5 and 15, as well as the Autothermal Reforming Block (ATR), can be deleted. This reduces some of the cost and complication of the CTL process.

Stream 14 from the CTL process can now be utilized as fuel in the power island. However, since the primary gasification process has changed, there will be less CH ₄ in stream 14, (which will now be referred to as "Tail Gas"). This will equate to less energy content in this stream. However, 1085 moles of CH ₄ are created in the F-T synthesis. Therefore, with a different syngas supply, and the creation of 1085 moles of CH ₄ in the F-T process, the corrected flow at stream 14 is shown in Table 1.

Table 1

Tail Gas Flow

(stream 14)

(Adjusted for Shell

Gasification)

Constituent MoI. Wt. Mole Fraction Molecular Flow Flow

(Gas Out) Weight

Ib/hr moles

H2 2.016 0.6007 1.2110 32397.1 16070.0

CH4 16.040 0.0294 0.4710 12601.9 785.7

CO 28.010 0.0475 1.3302 35586.7 1270.5

CO2 44.010 0.0031 0.1374 3674.8 83.5

H2O 18.016 0.0000 0.0000 0.0 0.0

N2 28.020 0.2581 7.2310 193454.1 6904.1

Ar 39.940 0.0461 1.8394 49209.8 1232.1

C2H4 28.050 0.0112 0.3152 8431.8 300.6

C2H6 30.070 0.0027 0.0812 2171.1 72.2

C3H6 42.080 0.0011 0.0450 1203.5 28.6

C3H8 44.090 0.0001 0.0066 176.4 4.0

NC4H8 56.100 0.0001 0.0036 95.4 1.7

NC4H10 58.120 0.0000 0.0007 17.4 0.3

1.0000 12.6721 339019.9 26753.3

Also as a result of the switch to the Shell gasification process, the inert gases (including CH ₄ ) will end up in the Off Gas (referred to as Fuel Gas 104 in Fig. 1 ). Table 2 shows the corrected flows and composition for this Off Gas, which will be used in the power island as fuel.

Table 2

Updated Off Gas Flow

(stream 25)

(Based on Shell

Gasification)

Constituent (Gas MoI. Wt. Mole Molecular Flow Flow

Out) Fraction Weight

Ib/hr moles

H2 2.016 0.4043 0.8150 8628.6 4280.1

CH4 16.040 0.0349 0.5601 5930.3 369.7

CO 28.010 0.0574 1.6065 17008.3 607.2

CO2 44.010 0.0037 0.1633 1729.3 39.3

H2O 18.016 0.0011 0.0192 203.5 11.3

N2 28.020 0.3069 8.5987 91037.2 3249.0

Ar 39.940 0.0548 2.1873 23157.5 579.8

C2H4 28.050 0.0137 0.3829 4054.4 144.5

C2H6 30.070 0.0095 0.2843 3010.2 100.1

C3H6 42.080 0.0346 1.4559 15413.6 366.3

C3H8 44.090 0.0213 0.9374 9924.6 225.1

IC4H8 56.100 0.0014 0.0812 859.3 15.3

NC4H8 56.100 0.0275 1.5418 16323.7 291.0

IC4H10 58.120 0.0112 0.6534 6917.4 119.0

NC4H10 58.120 0.0177 1.0264 10866.7 187.0

C5H10 70.130 0.0000 0.0019 20.4 0.3

NC5H12 72.146 0.0000 0.0006 6.0 0.1

IC5H12 72.146 0.0000 0.0001 1.0 0.0

C5H12 72.146 0.0000 0.0015 16.0 0.2

NC6H14 86.172 0.0000 0.0006 6.0 0.1

IC6H14 86.172 0.0000 0.0000 0.0 0.0

C7H14 98.182 0.0000 0.0017 17.6 0.2

C7H16 100.198 0.0000 0.0008 8.3 0.1

C8H16 112.208 0.0000 0.0018 18.6 0.2

C8H18 114.224 0.0000 0.0007 7.9 0.1

C9H18 126.234 0.0000 0.0016 17.5 0.1

C9H20 128.250 0.0000 0.0007 7.1 0.1

C10H20 140.260 0.0000 0.0015 15.5 0.1

Wax, etc. 138.000 0.0001 0.0148 156.4 1.1

1 .0000 20.3133 215362.9 10587.4

As can be seen from Fig. 6, the preferred embodiment of the present invention includes using saturated HP steam 130 from the gasification process and other processes, and superheating this steam to higher temperature. It also includes the design of the ST 134 such that the cold reheat steam from the HP section of the steam turbine 136 is reheated in the HRSG, and saturated steam from the F-T process 154 is also superheated in the HRSG. It may be possible to mix both of these steam lines and then superheat the combined flow in the HRSG, as shown in Fig. 6. This superheated/reheated steam is then directed to the IP section 144 of the ST.

To achieve the optimum arrangement, the amount of energy in the exhaust streams of the GTs must be determined, and the amount of energy required to superheat/reheat steam must also be determined. From this data, the number of GTs, their size, and the degree of supplemental firing in the HRSG can be determined. Note that there may be many different combinations of GTs and supplemental firing rates; however, one of these combinations can usually be selected on the basis of capital cost, performance, equipment constraints, etc. For this example, two (2) GE Frame 7FB gas turbines were selected with two

(2) highly fired HRSGs. Upon examination, it can be determined that not enough fuel is supplied by the Tail Gas and Off Gas for the power island. Therefore, extra fuel is required. First, to save fuel, a coal drying process that utilizes low-pressure steam was used in lieu of a fuel-based design. The fuel from the drying process (Case 5, stream 8 and Case 6, steam 8) was now sent to the power island.

However, even with this extra fuel, there was still a need for additional fuel in the power island. Therefore, the rate of gasification was increased. To maximize the capture of CO2, this additional gas shall be generated in the Case 6 gasification process (Case 5 could be used, but it would result in more CO in the fuel and thus greater CO2 emissions). To obtain the proper amount of fuel, the gasification for Case 6 is increased from 1.135 to 1.85 times the amount shown in Case 6.

Fig. 7A and Fig. 7B show a simplified schematic of the syngas cooling and shift process for this new stream, which is 1.85 times the flow tabulated in Case 6. Table 3 shows the data process, including pressure, temperatures, and flows. The shift process, although done in progressive stages, is shown here as only one stage for simplicity. Note that high pressure saturated steam is generated in the process and directed to the power island. This is in contrast to the prior art, where steam from the shift reaction is generated at medium pressure. In addition, similar to the '480 patent, the present invention primarily uses BFW and LP steam to cool the syngas. This HP steam production has efficiency advantages over the production of medium pressure steam.

Table 3

stream From To Temperature Pressure Flow Enthalpy Quality

Degrees F psia Ib/hr btu/lb

FTLPS1 SP4 _ 312.0404053 80 661800 1183.071777 1

FWC1 - ECON3 100.0000305 80 3665941.75 68.20749664 0.0E+01

FWC2 ECON3 SP3 280.2978821 80 3665941.75 249.5361481 0.0E+01

FWC3 SP3 EVAP2 280.2978821 80 961404 249.5361481 0.0E+01

FWS 1 PUMP1 ECON2 283.5271301 1900 2704538 256.3769226 0.0E+01

FWS2 ECON2 SP1 414.724762 1900 2704538 392.7945251 0.0E+01

FWS3 SP1 ECON1 414.724762 1900 1495837.875 392.7945251 0.0E+01

FWS4 ECON1 EVAP 1 624.5903931 1900 1495837.875 653.5158081 0.0E+01

FWW1 SP1 - 414.724762 1900 0.0E+01 392.7945251 0.0E+01

FWW2 SP3 PUMP1 280.2978821 80 2704538 249.5361481 0.0E+01

GASIF1 SP2 V1 628.5641479 1900 240072 1145.586182 1

GASIF2 V1 SPHT1 518.2088013 800 240072 1145.586182 0.921980

441

GASIF3 SPHT1 - 800.0060425 800 240072 1399.147339 1

HPSS1 EVAP 1 SP2 628.5641479 1900 1495837.875 1145.586182 1

HPSS2 SP2 - 628.5641479 1900 866525.75 1145.586182 1

LPH1 SP4 - 312.0404053 80 299603.9688 1183.071777 1

LPSS1 EVAP2 SP4 312.0404053 80 961404.0625 1183.071777 1

QW1 SP1 M1 414.724762 1900 1208700 392.7945251 0.0E+01

STM 1 SP2 M2 628.5641479 1900 389240.0313 1145.586182 1

SYN 1 - SPHT1 2600 650.00012 1602000 969.8135986 28.75

Z OA I

SYN 1 A SPHT1 M1 2508.067139 650.00012 1602000 931.4355469 28.75

Z OA I

SYN2 M1 M2 643.9625854 650.00012 2810699.75 231.9933929 28.75

Z \

SYN3 M2 FPT1 641.8131104 650.00012 3199939.75 235.6729889 28.75

Z OA I

SYN4 FPT1 EVAP 1 1179.241577 650.00012 3199939.75 470.8330383 28.75

Z OA I

SYN5 EVAP 1 ECON1 648.5621338 650.00012 3199939.75 238.5105133 28.75

Z OA I

SYN6 ECON1 ECON2 430.1768188 650.00012 3199939.75 115.4154663 28.75

Z OA I

SYN7 ECON2 EVAP2 415.3327026 650.00012 3199939.75 -1.035281181 28.75

Z OA I

SYN8 EVAP2 ECON3 332.0383606 650.00012 3199939.75 -284.3157959 28.75

Z OA I

SYN9 ECON3 - 132.993454 650.00012 3199939.75 -494.128479 28.75 21

The gasification process now consists of generating 3.563 times the syngas that is created in Case 5, stream 17 (non-shifted syngas). Also, 1.85 times the amount of syngas is created as compared to Case 6, stream 18 (shifted syngas). Of this shifted stream, 1.135 times the Case 6 flow is directed to the F-T synthesis block. This is combined with the non-shifted syngas (3.563 times Case 5) to yield the proper flow and composition into the F-T synthesis block. A portion of the remaining shifted syngas is combined with the Tail Gas (corrected flow and composition in Table 1 ) and used as high-pressure fuel for the GTs. Meanwhile, flow from the Off Gas (Table 2) is compressed from its low pressure of 20 psia to 50 psia for use in the duct burners. Note that this requires much less compression power than compressing this fuel to the GT required fuel pressure of 460 psia. Also, the remaining shifted syngas, as well as fuel diverted from the coal drying process, is combined with the Off Gas and directed to the duct burners. Note that a syngas expander may be utilized when higher pressure fuel can be used at a lower pressure, such as using shifted syngas at a nominal 600 psia for fuel in the duct burners at 50 psia.

Figs. 8A through 8D, referred to collectively as Fig. 8, make up a schematic of one-half of the power island for this integrated CTL/IGCC facility. Therefore, one half of the steam flows from the F-T process, syngas cooling, and other sections of the plant are indicated. Also, one-half of the fuel is used in this section of the power island, and one-half of the steam required for the process (export steam) is extracted. The net power is the gross power generated in this half of the power island minus one-half of the auxiliary loads. Therefore, total power generated is twice that of the number indicated in Fig. 8, or 1100 MW. Table 4 includes the data for the various streams included in Fig. 8.

Table 4A

Stream From To Temperature Pressure Flow Enthalpy Quality

Degrees F psia Ib/hr btu/lb

AHTDR1 AHT1 FWH5 413.3415833 770.7999878 81041.30469 390.090271 0.0E+01

ASUS1 IPST TMX6 854.454834 160 7411.18457 1454.98999 1

ASUS2 TMX6 - 365.5497437 160 9240 1196.347656 1

ASUSA1 SP2 TMX6 175.053894 2200 1828.816528 148.2130127 0.0E+01

CMIX1 SP14 TMX2 175.053894 2200 73716.64063 148.2130127 0.0E+01

CONDIN SPLDA CND1 91 .73403168 0.736999989 2763562.75 1031 .766724 0.933053434

CONDM1 CND1 LPPMP1 91 .73403168 0.736999989 5715025.5 59.74866867 0.0E+01

CONDM2 LPPMP1 SP11 91.8167572 100 5715025.5 60.09667969 0.0E+01

CONDM3 SP11 CNDPMP 91.8167572 100 3882075.5 60.09667969 0.0E+01

CRET1 - CNDR1 266 60 500000 234.9108429 0.0E+01

CRET2 CNDR1 M4 269.9479675 2393.790527 500000 243.6187592 0.0E+01

CRH1 B PI2 RHT1 564.3312378 369.3750305 3468732.5 1289.12085 1

CRH2 RHT1 TMX3 800.0005493 357.3750305 3468732.5 1418.8573 1

CRH3 TMX3 RHT2 800.0005493 357.3750305 3468732.5 1418.8573 1

CRHA HPST M6 630.1959229 375.0000305 2422078.75 1326.517456 1

CRHB M6 PI2 566.8870239 375.0000305 3468732.5 1290.12085 1

CW 1 CND1 CIRCP1 80.91238403 12.4351 1581 138637744 48.97973633 0.0E+01 CW2 CIRCP1 CT1 80.92842865 40 138637744 49.070858 0.0E+01

CW3 CT1 CND1 60.91292953 12.4351 1581 138637744 29.006567 0.0E+01

DAOUT DEAER MIXFHO 91 .73403168 0.736999989 1615375.5 59.74866867 0.0E+01

DASTM SPLDA DEAER 91 .73403168 0.736999989 19225.01758 1031 .766724 0.933053434

DBT1 M1 1 DB1 171.4537354 50 140098.0156 76.55802155 2.65841 1264

DILI - HX3 49.99998856 499.9999695 595450 -2.487657547 4

DIL2 HX3 HX4 96.30318451 499.9999695 595450 9.02528286 4

DIL3 HX4 - 403.6652832 499.9999695 595450 85.6967392 4

DILH1 SP17 HX4 419.6902161 2184 175000 398.4394226 0.0E+01

DILH2 HX4 M8 161.7506104 2184 175000 134.950531 0.0E+01

DRY1 SP18 - 309.61 12671 75 250000.0156 1182.978027 1

EVAP 1 HPEVAP M1 644.7230835 2129 199412.0313 1128.166016 1

EXT 1 SP5 TMX2 680.8189697 80 405783.3438 1370.958618 1

EXT2 CONDST FWH 1 231.8045502 8 93159.52344 1162.288452 1

EXTGS1 HPST SP16 825.6206665 820 108000 1412.980225 1

EXTGS2 SP16 M10 825.6206665 820 10212.72656 1412.980225 1

EXTR2 CONDST FWH2 501.4355164 35 60310.91406 1286.193115 1

EXTR3 SP5 FWH3 680.8189697 80 43764.72266 1370.958618 1

EXTR4 IPST FWH4 975.1881714 249.9999847 75570.875 1514.587036 1

FHMIXI MIXFHO CND1 91 .73403168 0.736999989 2951462.75 87.80314636 0.026929876

FT65A M10 TMX5 690.4284668 820 130201.9219 1331 .899536 1

FT65B TMX5 - 649.9984741 625 132403.2031 1320.169556 1

FTA4 M7 SP4 419.6902161 2184 1050000.75 398.4394226 0.0E+01

FTA5 SP4 V2 419.6902161 2184 121201.2188 398.4394226 0.0E+01

FTA6 V2 EVAP2 420.0722961 1800 121201.2188 398.4394226 0.0E+01

FTATT 1 SP7 TMX5 608.9178467 2129 2202.90918 626.8878784 0.0E+01

FTCW1 SP1 M7 334.4390869 2200 100000 308.9623108 0.0E+01

Table 4B

Stream From To Temperature Pressure Flow Enthalpy Quality

Degrees F psia Ib/hr btu/lb

FTFW1 SP3 93.60511017 2200 1110000 67.45703125 0.0E+01

FTGAS 1 AHT1 M13 508.9485168 540 1435800.75 192.4888611 4

FTGAS2 M13 509.4082947 540 1478838.625 193.0521851 4

FTS 1 SP12 440.32901 375.0000305 1100100 1205.895142 1

FTSG 1 HX1 110.0000076 499.9999695 39300.00781 64.21170807 4

FTSG2 HX1 M9 404.3126526 499.9999695 39300.00781 446.1060486 4

FTSGH1 SP4 HX1 419.6902161 2184 60000.00391 398.4394226 0.0E+01

FTSGH2 HX1 HX3 172.6629944 2184 60000.00391 145.7971954 0.0E+01

FTSGH3 HX3 M8 56.14876175 2184 60000.00391 30.39829254 0.0E+01

FTSH1 SP9 AHT1 523.0490112 820 81041.30469 1200.924927 1

FTSHT2 TMX4 SP9 523.0490112 820 124079.3125 1200.924927 1

FTSTM 1 SP9 M13 523.0490112 820 43038.01563 1200.924927 1

FTWA1 SP6 TMX4 432.2322388 2184 26283.20508 411.9673462 0.0E+01

FTWA2 SP6 M5 432.2322388 2184 200000 411.9673462 0.0E+01

FTWA3 M5 M7 428.4336853 2184 950000.6875 407.8580322 0.0E+01

FURNG1 SP8 87.99999237 20 21560 13.29325867 2.656331062

FW1 D SP14 ECON1 175.053894 2200 1246464.75 148.2130127 0.0E+01

FW2A ECON1 SP6 432.2322388 2184 1246464.75 411.9673462 0.0E+01

FW2B SP6 ECON2 432.2322388 2184 1020181.5 411.9673462 0.0E+01

FW3 ECON2 SP7 608.9178467 2129 1020181.5 626.8878784 0.0E+01

FW3A SP7 HPEVAP 608.9178467 2129 201426.2969 626.8878784 0.0E+01

FWC1 CNDPMP SP3 93.60511017 2200 3882075.5 67.45703125 0.0E+01

FWC1A SP3 M4 93.60511017 2200 1972075.5 67.45703125 0.0E+01

FWC2 M4 FWH 1 129.5972595 2200 2472075.5 103.0873642 0.0E+01

FWC3 FWH 1 SP13 175.053894 2200 2472075.5 148.2130127 0.0E+01

FWC3A SP13 SP14 175.053894 2200 1320181.375 148.2130127 0.0E+01 FWD1 SP13 FWH2 175.053894 2200 1150000.75 148.2130127 0.0E+01

FWDA1 FWH2 FWH3 250.6623535 2200 1150000.75 223.7880859 0.0E+01

FWDA2 FWH3 FWH4 302.7889099 2200 1150000.75 276.5417175 0.0E+01

FWDA3 FWH4 FWH5 390.5601807 2200 1150000.75 367.4453125 0.0E+01

FWDA4 FWH5 SP10 427.4040222 2200 1150000.75 406.7622375 0.0E+01

FWDA5 SP10 M5 427.4040222 2200 750000.6875 406.7622375 0.0E+01

FWDA6 SP10 M3 427.4040222 2200 400000 406.7622375 0.0E+01

FWH 1 DR FWH 1 MIXFHO 138.5981903 7.519999981 407288.4375 106.560051 0.0E+01

FWH2DR FWH2 FWH 1 184.0539551 32.90000153 314126 152.1245117 0.0E+01

FWH3DR FWH3 FWH2 259.6623535 75.20000458 253815.0938 228.494278 0.0E+01

FWH4DR FWH4 FWH3 31 1.7889099 235 210055.4375 282.165802 0.0E+01

FWH5DR FWH5 FWH4 399.5601807 352.5000305 134484.5781 374.7372742 0.0E+01

GASST2 FGCOOL M1 644.7230835 2129 1897240.625 1128.166016 1

GT3X7 HPEVAP EC0N2 662.7230835 12.72309208 4343266.5 163.324234 2.65841 1264

GTEX1 GTD1 DB1 1080.944946 13.01249123 4203168.5 273.6381836 3.093600035

GTEX3 DB1 RHT2 2160.624268 12.97649193 4343266.5 623.9285889 2.65841 1264

GTEX4 RHT2 SPHT1 1827.349487 12.92949104 4343266.5 515.461 1816 2.65841 1264

GTEX5 SPHT1 RHT1 1484.902832 12.8784914 4343266.5 407.0649414 2.65841 1264

Table 4C

Stream From To Temperature Pressure Flow Enthalpy Quality

Degrees F psia Ib/hr btu/lb

GTEX6 RHT1 SPHT2 1142.245972 12.85649204 4343266.5 302.4280701 2.658411264

GTEX6A SPHT2 HPEVAP 745.1520386 12.77709103 4343266.5 186.5976105 2.658411264

GTEX8 ECON2 ECON1 478.9004822 12.64369106 4343266.5 112.337204 2.658411264

GTF1 M9 560.2080688 499.9999695 208810.0156 353.44104 3.093600273

GTFG1 HX2 110.0000076 540 1435800.75 21.22589111 4

GTFG2 HX2 AHT1 404.3415833 540 1435800.75 147.1758118 4

GTSGH1 SP4 SP17 419.6902161 2184 868799.5 398.4394226 0.0E+01

GTSGH2 HX2 M8 161.9840698 2184 693798.875 135.1824493 0.0E+01

HEAT TMX2 SP18 309.61 12671 75 479499.9688 1182.978027 1

HGA1 M12 99.99997711 499.9999695 15492 13.84834003 4

HGAB1 M12 M11 99.99997711 499.9999695 18092.00195 19.23766518 4

HGB1 M12 99.99997711 499.9999695 2600.001221 51.34973145 4

H PATT 1 SP13 SP2 175.053894 2200 1828.816406 148.2130127 0.0E+01

HPATT2 SP2 TMX1 175.053894 2200 0.0E+01 148.2130127 0.0E+01

HPATT3 SP2 TMX3 175.053894 2200 0.0E+01 148.2130127 0.0E+01

HPS1 M1 SPHT2 636.3933105 2008.339966 2529917.75 1130.648438 0.984808564

HPS2 SPHT2 TMX1 785.4151001 1937.339966 2529917.75 1327.528198 1

HPS2A TMX1 SPHT1 785.4151001 1937.339966 2529980 1327.528198 1

HPS3 SPHT1 M2 1052.997559 1844.339966 2529980 1511.771729 1

HPS3A M2 PM 1052.997559 1844.339966 2529980 1511.771729 1

HPS4 PM HPST 1050.053955 1816.675049 2529980 1510.771606 1

HRH1 RHT2 PI3 1052.99939337.3750305 3468732.5 1553.301758 1

HRH2 PI3 IPST 1050.87207332.3143921 3468778 1552.301758 1

HTBFW1 SP7 M3 608.9178467 2129 816455.1875 626.8878784 0.0E+01

IPSTM2 SP12 M6 440.32901 375.0000305 1046653.438 1205.895142 1

IPSTM3 SP12 FWH5 440.32901 375.0000305 53446.51172 1205.895142 1

MAKWAT MAKEUP DEAER 80.00002289 2.175565243 1596150.375 48.04108429 0.0E+01

OFFG1 SP8 87.99999237 20 107816 13.29325867 2.656331062

OFFG2 SP8 C1 87.99999237 20 86256.00781 13.29325867 2.656331062

OFFG3 C1 M11 262.6072388 50 86256.00781 99.03115845 2.656331062

PROC1 SP18 309.61 12671 75 229499.9688 1182.978027 1

S1 GTD1 550.000061 499.9999695 208792.125 346.0439758 3.093600035

S3 M3 FGCOOL 591.8934326 2129 1916455.125 602.3468628 0.0E+01

S34 CONDST SPLDA 91.73403168 0.736999989 2782787.75 1031.766724 0.933053434

SFTW1 SP11 91.8167572 100 1832950 60.09667969 0.0E+01 SGAS1 FGCOOL 1635 650.0001221 2758388 576.8737793 28.75

SGAS1A FGCOOL EC0N3 664.7230225 625.0001831 2758388 211.0004883 28.75

SGAS2 ECON3 SP15 391.9761047 606.2501221 2758388 114.4941025 28.75

SGAS2A SP15 EC0N4 391.9761047 606.2501221 1475702.625 114.4885635 28.75

SGAS3 ECON4 - 100.3775253 588.0626221 1475702.625 -17.74420547 28.75

SGASR1 SP15 - 391.9761047 606.2501221 1282685 114.4941025 28.75

SGBH1 - M1 1 99.99997711 499.9999695 35750 51.34972382 4

SGCW1 SP3 EC0N4 93.60511017 2200 800000 67.45703125 0.0E+01

SGCW2 ECON4 SP1 334.4390869 2200 800000 308.9623108 0.0E+01

Table 4D

Stream From To Temperature Pressure Flow Enthalpy Quality

Degrees F psia Ib/hr btu/lb

SGCW3 SP1 ECON3 334.4390869 2200 700000 308.9623108 0.0E+01

SGCW4 ECON3 M3 644.4468384 2200 700000 685.4856567 0.0E+01

SGHA1 SP17 HX2 419.6902161 2184 693799.4375 398.4394226 0.0E+01

SGHTR1 M8 MIXFHO 155.1257935 2184 928798.8125 128.3706665 0.0E+01

SHSTM1 M1 638.3933105 2008.339966 433265 1142.661987 1

STACK ECON1 195.4597931 12.5496912 4343266.5 35.89162827 2.65841 1264

STSHT1 SP16 TMX4 825.6206665 820 97787.28125 1412.980225 1

TAIL1 SPHT3 1706 499.9999695 169510 996.1653442 3.090374231

TAI L2 SPHT3 EVAP2 1516.736206 499.9999695 169510 872.7185059 3.090374231

TAI L3 EVAP2 M9 641.0136108 499.9999695 169510 331.9559021 3.090374231

TS 1 EVAP2 SPHT3 621.015686 1800 119989.2031 1152.332031 0.99999994

TS2 SPHT3 M10 771.3502808 1800 119989.2031 1325 1

XOVER IPST SP5 680.8189697 80 3385795.5 1370.958618 1

XOVERB SP5 CONDST 680.8189697 80 2936247.5 1370.958618 1

Although DOE/NETL-2007/1260 contains a great deal of data, it does not include steam flows and other pertinent data. Table 8 is a DOE provided compilation of the steam data for the various sections of the CTL facility. The negative numbers indicate steam production, while positive numbers indicate steam consumption. The far right hand column provides the net sum of the steam production for the various steam "headers" or steam supply lines. This steam must be supplied from a source in the integrated CTL/IGCC for the F-T process to function properly.

Table 5 details the calculations for the auxiliary loads. It does not include the auxiliary loads for the pumps, cooling tower, and other equipment included in the Fig. 8 schematic, as these loads are calculated by the GateCycle® program (a GE software that calculates performance of combined cycle power plants). Note that the total coal flow is 5.50 times the Case 5 example, therefore, items such as coal grinding, slag handling, and other related loads are taken from Case 5 and scaled by the 5.50 factor. Some items, such as fuel gas compression have been calculated. Table 5

50,000 BPD

CTL w/'48O patent

Shell Gasification

From Gasif. From From Scale Final

CTL Calcs Factor Per DOE

Service

Coal Handling 430 0 5.50 2,365

Coal Milling 2,110 0 5.50 11 ,605

Slag Handling 540 0 5.50 2,970

Air Separation 1 ,000 0 3.00 3,000

Unit Auxiliaries

ASU Main Air 41 ,630 0 Per 206,220

Compressor Calcs

Oxygen 10,080 0 Per 109,120

Compressor Calcs

Nitrogen 37,010 0 Per 4,800

Compressor Calcs

Air Chiller Per 10,180

Calcs

Syngas Recycle 1 ,650 0 5.50 9,075

Compressor

Syngas 0 0 0.00 0

Compressor

Fuel Gas 0 0 1.00 4,330

Compressor

CO2 28,050 0 1.85 51 ,893

Compressor,

Gasifier Section

CO2 0 43,156 1.00 43,156

Compressor, F-T Section

Syngas Recycle 0 0 1.00 0 Blower

Tail Gas Recycle 0 0 1.00 0

Blower

All F-T 0 19,207 1.00 19,207

Processes

Flash Bottom 200 0 5.50 1 ,100

Pumps

Scrubber Pumps 120 0 5.50 660 Selexol Unit O 7,200 1.22 8,762

Auxiliaries Gas Turbine 1 ,000 0 1.00 1 ,000

Auxiliaries

Steam Turbine 100 0 5.50 550

Auxiliaries

Claus 250 0 5.50 1 ,375

Plant/TGTU Auxiliaries

Miscellaneous 3,000 3,000 1.00 6,000

Balance of Plant

Transformer 4,800

Losses

Total 502,168

For the ASU, the design is significantly different than the IGCC cases. With Case 5 and 6 from the IGCC study, a significant portion of the nitrogen from the cryogenic separation process is needed as diluent to the GTs to suppress the formation of NO _x in the combustors. However, with the present invention, a large quantity of oxygen is required for gasification, yet, only a relatively small portion of the nitrogen is required by the GTs (since only a minor portion of the syngas is used by the power island, with the vast majority used in the F-T process). Therefore, the design is such that it may allow some nitrogen from the cryogenic process to be pumped as a liquid rather than compressed as a gas. This saves considerable power.

Also, with the higher-pressure gasification process, the syngas compressor is no longer needed. The recycle to gasifier is eliminated, and since the recycle loop in the F-T process is eliminated, the recycle blower is not required. All these factors lead to lower auxiliary loads for the present invention.

The net result for the present invention is lower fuel consumption, lower emissions, and lower cost. Lower maintenance costs are also anticipated, as there is less overall equipment as compared to practice in the prior art. The present invention, like a cogeneration facility, makes excellent use of the heat and energy from the CTL plant in the power island, while the power island provides superheating of steam, preheated feedwater, and power to the CTL/gasification facility. Some of the carbon from the feedstock is captured in the F- T liquids, while a large portion of the remaining carbon (as CO2) is captured for sequestration. This arrangement is far superior to the prior art method of constructing separate IGCC and CTL plants.

Let's look at a comparison between the prior art coal conversion and the present invention. For an apples-to-apples comparison, one (1 ) facility using the example of the present invention will produce 50,000 BPD of F-T liquids and 1 ,100 MW of electricity. To produce this same amount of F-T liquids, one (1 ) facility comparable to the DOE/NETL-2007/1260 CTL plant would be required. This would also provide a nominal 125 MW of export power. Thus, another two (2) 517 MW IGCC plants as described in DOE/NETL-2007/1281 , Case 6, would be required to provide an equivalent amount of power to the example described in the present invention. Table 6 below provides a performance comparison between the prior art and the example in the present invention.

Table 6

Prior Art vs. Present Invention Performance Comparison

For the prior art combination of one CTL facility and two IGCC plants (Case 6), the overall conversion efficiency is 42.4%. For the present invention, the overall conversion efficiency is increased to 50.2%. Note that Table 6 outlines the performance differences between the prior art and the present invention. The next question one might ask is "what are the capital cost differences"? Although there are many facets in determining capital cost, one large contributing factor is the amount of major equipment required. For this comparison, we will examine the ASU's, gasification, and power island equipment. Gas turbines (GT's) in the CTL are 6FA or equal while all others are GE 7FB or equal.

Table 7 provides a comparison of the major pieces of equipment that are required in the prior art versus the present invention.

Table 7

Prior Art versus Present Invention Equipment Comparison

The other major cost factor for these plants is the O&M (Operation and

Maintenance) costs. Studies have shown that the O&M costs for IGCC plants are typically proportional to the capital cost of the plant. With far less equipment for equal capacity, it would appear that both the capital cost (dollars per kW and dollars per BPD), and the O&M costs would be significantly lower with the present invention. The other area for major savings in the present invention is the cost of CO ₂ sequestration. Note that the 41 ,437 TPD of CO ₂ sent to sequestration is only 73% of the amount required by the coal plants from the prior art. Therefore, the pipelines, compressor stations, and saline reservoirs can be sized commensurately. This is a third factor that augments the economics of the present invention. The present invention will also demonstrate significantly lower emissions of

SO _x , NO _x , and mercury. In the Case 6 IGCC example from DOE/NETL-2007/1281 , the syngas to the GTs contains approximately 30 ppm. In the present invention, all syngas contains 1 ppb of sulfur. Therefore, SO _x emissions (IGCC plus CTL) are reduced by a nominal factor of 100. Also, this low sulfur syngas fuel allows the use of SCR (Selective Catalytic Reduction) in the HRSG. This reduces the NO _x at the stack from 15 ppm to 3 ppm. Also, since the present invention uses only two (2) GTs in lieu of seven (7) in the prior art, the total GT exhaust flow is reduced, which equates to less NO _x . A tenfold reduction in NO _x is anticipated. With a minimum of 90% mercury capture in all aforementioned plants, prior art and present invention, the mercury emissions of the present invention will be less as a result of the lower coal consumption.

The power island for the present invention utilizes the '480 patent combined cycle technology and consists of 2 GTs (GE Frame 7FB or equal), 2 - highly fired HRSG's, and two (2) moderate sized 600 MW steam turbines (ST's). One large 1200 MW ST could possibly be utilized in lieu of the moderate-sized units. Because of the size and design for these steam turbines, the possibility also exists to use this concept to repower existing coal-fired assets.

In this repowering, much of an existing plant could be reused, including the steam turbine(s), transformers, and transmission. Also, other infrastructure such as coal handling, condensers, cooling towers, and other equipment may also be reapplied. The gasification island, the GTs, and HRSG's would replace the main boilers. This could be useful as it becomes increasingly difficult to find suitable sites for these large plants.

The present invention provides the means to efficiently and cost-effectively convert coal into both liquid fuels and electricity. It utilizes more of the coal's energy in the end products, has lower emissions of SO _x , NO _x , mercury, and CO2, and only needs to sequester 73% of the CO2 that conventional plants of similar output would require.

Table 8

Raw Syngas

Constituent MoI. Wt. Mole Fraction Molecular Flow Flow

(Gas Out) Weight

Ib/hr moles

H2 2.016 0.3381 0.6814 16040 7956.3

CH4 16.04 0.0000 0.0000 0 0.0

CO 28.01 0.6164 17.2581 406253 14503.8

CO2 44.01 0.0241 1.0620 25000 568.1

H2O 18.016 0.0000 0.0000 0 0.0

N2 28.02 0.0066 0.1918 4335 154.7

Ar 39.94 0.0000 0.0075 0 0.0

H2S 34.082 0.0141 0.4811 1 1324 332.3

COS 60.076 0.0006 0.0353 832 13.8 1.000 19.71719542 463784 23529.03755

Syngas after

Cold Gas

Clean Up

Constituent MoI. Wt. Mole Fraction Molecular Flow Flow

(Gas Out) Weight

Ib/hr moles

H2 2.016 0.34301 0.6915 16040 7956.3

CH4 16.04 0.00000 0.0000 0 0.0

CO 28.01 0.62528 17.5140 406253 14503.8

CO2 44.01 0.02449 1.0778 25000 568.1

H2O 18.016 0.00055 0.0099 230 12.8

N2 28.02 0.00667 0.1869 4335 154.7

Ar 39.94 0.00000 0.0000 0 0.0

H2S 34.082 0.00001 0.0002 5 0.1

COS 60.076 0.00000 0.0001 3 0.0

1.000 19.4804 451865 23195.9

Table 9

Stream From To Temperature Pressure Flow Enthalpy Quality

Degrees F psia Ib/hr btu/lb

AIR1 _ C1 58.99998856 14.69521904 8565000 -0.241481513 4

AIR2 C1 HX1 279.9961243 44.08565521 8565000 53.29851532 4

AIR3 HX1 C2 88.51097107 43.20394135 8565000 6.884737492 4

AIR4 C2 HX2 321.6124573 129.6118164 8565000 63.46019745 4

AIR5 HX2 - 90.74256897 127.0195847 8565000 4.501454353 4

CW1 - HX1 71.00008392 50 6000000 39.1880722 0

CW2 HX1 - 136.7224426 48.50000381 6000000 104.7877502 0

CW3 - HX2 71.00008392 50 7500000 39.1880722 0

CW4 HX2 137.7878418 48.50000381 7500000 105.8523254 0

Table 10

Stream From To Temperature Pressure Flow Enthalpy Quality

Degrees F psia Ib/hr btu/lb

AIR1 _ C1 58.99998856 14.69521904 8565000 _ 4

0.241481513

AIR2 C1 C2 279.9961243 44.08565521 8565000 53.29851532 4

AIR4 C2 HX2 587.7236938 132.256958 8565000 129.4444122 4

AIR5 HX2 HX1 129.1072083 129.6118164 8565000 16.69301224 4

AIR6 HX1 - 90.41270447 127.0195847 8565000 4.383625031 4

BFW1 - HX2 90 1999.999878 2000000 63.36014175 0

BFW2 HX2 - 545.0217896 1940 2000000 541.4373169 0

CW3 - HX1 71.00008392 50 2000000 39.1880722 0

CW4 HX1 _ 123.3001633 48.50000381 2000000 91 .381 10352 0 Although the preferred embodiments of the present invention have been described herein, the above description is merely illustrative. Further modification of the invention herein disclosed will occur to those skilled in the respective arts and all such modifications are deemed to be within the scope of the invention as defined by the appended claims.