DOE analyzes Texas Clean Energy coal gasification project

The project would demonstrate the full integration of carbon dioxide capture and sequestration with a commercial, coal-based polygeneration plant

May 18th, 2015
Content Dam Elp Online Articles 2014 11 Kemper Igcc Coal Gasification Elp

The U.S. Department of Energy on May 13 released a final supplemental analysis on the Texas Clean Energy Project of Summit Texas Clean Energy LLC, which covers some major changes to this coal gasification project, including a reduction in planned coal feed and the addition of options to fire the facility with regular natural gas.

The project would be located about 15 miles southwest of Odessa in Ector County, Texas. The project would demonstrate the full integration of carbon dioxide capture and sequestration with a commercial, coal-based polygeneration plant (polygen).

Preparation of the EIS for the project began in June 2010. In March 2011, DOE filed the draft EIS with the U.S. Environmental Protection Agency and distributed the document to elected officials, agencies, Native American tribes, organizations, and members of the general public. DOE distributed the final EIS in July 2011. The EIS process concluded with the publication of DOE’s record of decision in September 2011.

DOE announced in the record its decision to provide Summit Texas Clean Energy with about $450 million in financial assistance for the project on a cost-shared basis. Since the record was published, the plant configuration was modified, specific alternatives associated with the project’s process water supply have changed, and there is some additional information on the wastewater disposal options. DOE found that it was unclear as to whether these changes warranted a supplemental EIS and therefore prepared this supplemental analysis to help the agency in making this determination.

While the purpose and need for Summit’s action also has not changed since issuance of the final EIS, the polygen plant design has been modified. Specifically, the polygen plant configuration has been altered to use one larger gasifier, instead of two smaller gasifiers, and to use a larger gas combustion turbine-generator.

These changes increase the efficiency of the polygen plant, decrease its costs, and improve the project’s return on investment. As a consequence, the power plant’s availability, resource requirements, by-products, emissions and waste streams change slightly.

The need for the project is to fulfill the regional demand for CO2 (for use in oil fields) and a firm (non-fluctuating) supply of electric power, including peaking capacity during summer months. There also is a need for urea-based fertilizers, which would be a plant by-product.

There are now two newly identified by-products, ammonium sulfate and liquefied nitrogen gas, which have potential for local sales. Sales of ammonium sulfate would support the farming industry on an as-needed basis. Sales of the original by-products argon and sulfuric acid, along with the newly considered liquid nitrogen, would support various industries including, but not limited to, the oil and gas, food, auto, semiconductor and welding industries. Sales of inert, nonleachable slag would support cement, concrete and roofing tile manufacture, as well as road construction in the vicinity of Odessa.

The polygen plant reconfiguration includes replacing the two SFG-500 gasifiers identified in the EIS with one SFG-850 gasifier of the same design. The reconfiguration will also require a corresponding change in the combustion turbine-generator from an IGCC SGT6-5000F3 combustion turbine-generator to an IGCC SGT6-8000H combustion turbine-generator.

The SFG-850 gasifier is larger in capacity and size (i.e., diameter) than the two SFG-500 gasifiers described in the EIS; however, it would produce less syngas than the original two SFG-500 gasifiers combined. To compensate for this decrease in syngas, natural gas would now supplement the syngas fuel that feeds the larger, more efficient SGT6-8000H combustion turbine-generator. The larger turbine eliminates the need for supplemental natural gas-fueled duct burners that were required in the original design to sustain the combined power generation at about 400 MW (gross).

On average, this syngas/natural gas blend would allow the combustion-turbine-generator to send between 140 MW and 262 MW (net) to the grid. As with the original configuration, there is the potential for the combustion turbine-generator to operate at 100 percent power generation capacity using solely natural gas (no syngas, and thus no coal, would be required in this scenario).

This scenario would likely occur less than 10 percent of the time, based on contract limits with power purchasers. Under the 100 percent natural gas scenario, there would be no opportunity for Summit to produce the other marketable products that result only from syngas production, such as urea, liquid nitrogen and CO2, which further reduces this scenario’s likelihood.

The polygen plant reconfiguration will require a reduction in coal feed from 5,800 tons per day, as stated in the EIS, to 4,611 to 5,097 tons per day. No significant changes to the transportation intervals (e.g., two 150-car trains per day and two to three 150-car trains per week) of coal to the polygen plant are expected as a result of the polygen plant reconfiguration. However, on an annual basis, there will likely be fewer 150-car trains overall as arrivals are expected to be less frequent in nature and less at the regular intervals anticipated in the EIS.

No changes to the storage of coal are expected. Storage will remain at 45 days of total capacity with about nine days of active storage and 36 days of inactive storage.

The polygen plant reconfiguration will have an overall lower amount of syngas production as a result of the new single SFG-850 gasifier having a lower capacity than the two SFG-500 gasifiers combined. The total amount syngas produced by the SFG-850 gasifier is distributed through two syngas streams: one to the ammonia/urea synthesis unit and the other to the power block.

The amount of syngas required to operate the ammonia/urea synthesis unit will increase by about 18 percent from 1,077 million British Thermal Units (MMBtu) per hour under the old configuration to 1,273 MMBtu per hour to achieve higher ammonia/urea production. This increase to the ammonia/urea synthesis unit, combined with the decreased gasifier capacity, allows for an even smaller amount of syngas available to the power block.

Syngas available to the power block will decrease between 10 percent and 43 percent from 1,718 MMBtu per hour as identified in the EIS to 1,205 to 1,559 MMBtu per hour. This decrease, however, will be supplemented with natural gas to maintain about the same amount of gross power generation output.

As a result of the polygen plant reconfiguration, the natural gas required for coal drying, and gasifier and flare pilots will be reduced or at the same levels as what was identified in the EIS. The reconfiguration will now use the low pressure steam for pre-drying, then natural gas and tail gas for subsequent drying, thereby reducing the amount of natural gas compared to the original configuration, even with the use of natural gas to supplement syngas in the power block.

The polygen plant would typically require between 1,012 to 1,111 MMBtu per hour of natural gas, but has the potential to require 1,998 MMBtu per hour (or 17.5 trillion Btu per year), which is the same or less than was identified in the EIS.

Electricity output will be increased as a result of the polygen plant reconfiguration. The project will replace the SGT6-5000F3 combustion turbine-generator with an SGT6-8000H combustion turbine-generator. The combustion turbine capacity would increase between 30 percent and 43 percent from 230 MW as identified in the EIS to a range of 298 to 330 MW. The combined-cycle output would range from 377 to 440 MW, though on average would be comparable to the 400 MW identified in the EIS.

Net output to the power grid would range from 140 MW to 262 MW when operating on the expected average syngas/natural gas blend at 83.7 percent capacity or from 398 MW to 440 MW when using 100 percent natural gas. These operating capacities are an increase from the 130 MW to 213 MW net output estimated in the EIS.

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