CLEAN COAL TECHNOLOGY PROJECTS PROLIFERATING

The Department of Energy has approved grants to help launch 38 clean coal technology demonstration projects.

Under the clean coal technology (CCT) program, government and industry have joined in projects to speed commerciality of a new generation of coal technologies.

There have been three rounds of competition. DOE is still negotiating with sponsors of 12 other projects for cost sharing under CCT, a $5 billion program. Here's a roundup of some projects recently approved:

SORBENT INJECTION

Lifac North America will retrofit a high sulfur coal burning plant in Richmond, Ind., with an advanced pollution control technology.

The Lifac process, developed to comply with pollution control laws in Finland, will be tested on high sulfur U.S. coals for the first time in a $17 million project. Sponsor is Lifac NA, a joint venture of ICF Kaiser Engineers of Oakland, Calif., and Tampella Keeler Inc., U.S. unit of Finland's Tampella Ltd.

Lifac is one of several sorbent injection techniques that offer an inexpensive way to cut sulfur pollutants from existing coal fired boilers. The systems are especially suited for small, tightly spaced plants without space for large, costly scrubbers.

DOE said Lifac can capture 75-85% of the sulfur pollutants from flue gas vs. 50-70% typical of other injection systems through use of a two step process using an activation chamber added to a plant's existing ductwork.

In the first step, finely crushed limestone is blown into the upper part of the coal furnace, where heat converts limestone to lime. Lime passing through the furnace reacts with sulfur dioxide in the coal gases, forming solid calcium compounds.

Flue gases containing unreacted lime move through the air heater and into the new vertical chamber where they are sprayed with a fine mist of water. This moisture activates the lime to capture even higher levels of SO2. These solid particles are collected with fly ash by an electrostatic precipitator. Although costlier to build than other duct injection systems, Lifac cuts operating costs by using limestone.

The tests will be at Richmond Power & Light's Whitewater Valley station on a 19 year old, 60,000 kw boiler that burns high sulfur western Indiana coal.

DOE is providing $8.5 million, half the project's total cost. Lifac NA is spending $3.9 million, Richmond Power & Light $3.5 million, Electric Power Research Institute $500,000, Peabody Coal Co. $300,000, and Black Beauty Coal Co. $300,000.

Construction is to begin in February 1991, and startup the following September. Tests will last for 26 months.

COMBINED CYCLE

Combustion Engineering will repower an oil fired power plant in Springfield, Ill., with coal gasification combined cycle technology.

Combustion Engineering will retrofit a standby oil fired boiler at City Water, Light & Power's (CWLP) Lakeside power plant with a coal gasification combined cycle system to generate 65,000 kw.

CE will repower the Lakeside unit with an air blown, entrained flow, two stage, pressurized gasifier. Low BTU fuel gas will be burned in a modified combustion turbine to produce 40,000 kw of electricity. Steam from a new heat recovery unit and gasifier steam will produce another 25,000 kw of power from the existing turbine generator.

The system will experiment with a hot gas cleaning device that promises to increase plant efficiency and lower overall costs. Rather than cooling the gases for cleaning and then reheating them for the turbine, gases will flow through a bed of zinc ferrite. This system can operate at about 1,200 F. while absorbing as much as 99.9% of the sulfur contaminants from coal gases. The zinc ferrite pellets can be regenerated, producing marketable sulfur in the process.

The $270.7 million project is for more than 10 years, including 5 years to test and operate the advanced system. The plant will continue to provide power to the city as part of its commercial grid. Design work is to begin this year and construction in 1992 with startup by 1995. DOE is providing $129.4 million, and CE, CWLP, and Illinois's Department of Energy & Natural Resources the balance.

COAL INJECTION SYSTEM

Bethlehem Steel will retrofit blast furnaces at a plant near Gary, Ind., with coal injection systems that reduce the need for coke in steelmaking.

Bethlehem Steel plans a $143.8 million project to retrofit two blast furnaces at its Burns Harbor plant with systems that directly inject granulated coal into the furnace.

That technique reduces pollution by using coal to replace coke made in a highly polluting process. In the coal injection system, finely ground coals are blown into the furnace in place of oil or natural gas. Each pound of coal means one less pound of coke needed in the furnace. The process results in no increased emissions, because sulfur and other impurities from burning coal are captured by limestone and removed in slag byproduct.

Each of the two furnaces to be used for the demonstration produces 7,000 tons/day of hot metal. Bethlehem Steel will replace as much as up to 40% of the furnace's coke with coal injection. The new equipment to be installed at Burns Harbor will be able to inject up to 1,400 tons/day of coal into each blast furnace. New facilities will include coal storage, drying, grinding plant, and 28 injectors will be added to each furnace.

Bethlehem Steel will experiment with coal fines and coarser coals ground only to the consistency of granulated sugar. Coals will be injected at various rates, with a target of 400 lb of coal/ton of hot metal. Four different high and low sulfur coals will be used.

The agreement with DOE requires Bethlehem to share results with other U.S. steel companies. DOE will fund $31.6 million. Construction will begin next summer, and 32 months of operations will begin in early 1994.

BECHTEL PROJECT

Bechtel Corp. will demonstrate a low cost way to reduce sulfur dioxide pollutants with confined zone dispersion (CZD) at Pennsylvania Electric Co.'s Seward Station near Johnstown, Penn.

The technology is expected to help smaller, older power plants cut their sulfur emissions. Some of those plants are not expected to continue operating long enough to justify the costs of installing an expensive scrubber.

The CZD approach would capture pollutants inside a plant's ductwork. Although not as effective as a scrubber-50% of the sulfur pollutants will likely be captured vs. 90% in a scrubber-the technology could allow many existing power plants to remain operating while newer, cleaner plants are built.

CZD would use atomizers to inject a fine spray of water and lime into the ductwork between a boiler's air heater and particulate removal equipment. The atomizers create a cone shaped confined zone of wet particles surrounded by an envelope of hot combustion gases.

As the cone moves through the duct, gas inside the cone would cool and SO2 would be absorbed by the droplets, then mix with hot gases outside the cone and dry very quickly.

The CZD process prevents reaction particles from building up on duct walls and other parts of the plant and allows their removal by existing particulate collection equipment.

A CZD system is expected to cost only $25-55/kw of installed capacity-a third the cost of installing a conventional wet scrubber. The process requires little retrofit and produces only nontoxic disposable wastes, rather than the wet sludge of a conventional scrubber.

Bechtel will replace one of two existing ducts at Seward Station Unit No. 15 with a new, straight 110 ft duct for the project, treating half the flue gas from the 147,000 unit, Calcitic and dolomitic limes will be tested with high and low sulfur coals.

DOE is providing $4.6 million of the project's total $9.2 million cost. Pennsylvania Electric is contributing $3 million, Bechtel $760,000, the Pennsylvania Energy Development Authority $750,000, New York State Gas & Electric Co. $100,000, and Rockwell Lime Co. $23,000.

Bechtel has begun work on the project. The 25 month operating period, including 1 year of continuous tests, will begin in June 1991. The process could be ready for commercial use by 1994.

GAS REBURN

EER Inc., Irvine, Calif., will focus on techniques for lowering nitrogen oxides.

EER will expand its work on gas reburn technology at Public Service of Colorado's Cherokee power station in Denver. Gas reburning is a NOx control technology that EER also is testing in a previously approved CCT project in Illinois.

The Colorado project will use low sulfur western coals and integrate gas reburn with low NOx burners. The combination of reburning and low NOx burners could cut nitrogen oxide emissions by 70%, DOE said.

Low NOx burners control flame temperature in burners, the amount of oxygen at high temperatures, and the time coal and air are kept at high temperatures. Only part of the combustion air is injected with the coal, with the remaining air injected separately. The burner delays mixing most of the air and coal until temperatures are low enough to prevent NOx from forming. Conventional low NOx burners can cut NOx emissions by 30-50%. EER plans to reduce NOx emissions even more by adding gas reburning. Natural gas, about 20% percent of the total fuel input, will be added to coal combustion products above the main coal combustion zone.

In the reburn zone, hydrocarbon fragments from the gas react with nitric oxide to form harmless molecular nitrogen. To complete combustion, air is added above the reburn zone at temperatures low enough to prevent additional NOx formation.

The project will be in Cherokee's 28-year old Unit 3, a 172,000 kw boiler that burns low sulfur bituminous coal.

DOE is providing $7.2 million of the $14.5 million cost. Gas Research Institute is providing $3.5 million, Public Service of Colorado $3 million, Colorado Interstate Gas $300,000, EER $206,000, and Electric Power Research Institute (EPRI) $200,000.

EER will conduct baseline tests for 9 months, and begin construction in July.

The 20 month operating period is to begin in September 1992.

NOX CONTROL BURNERS

Babcock & Wilcox Co., Alliance, Ohio, will outfit a boiler at Dayton Power & Light's station in Aberdeen, Ohio, with burners that can limit NOx formation inexpensively.

B&W will demonstrate use of burners to limit NOx formation in full scale, 1960s design coal burning utility boilers equipped with tightly spaced cell burners designed to achieve rapid, efficient combustion at very high temperatures.

DOE said there are 37 utility boilers in the U.S. equipped with cell type burners, accounting for about 15% of nitrogen emissions from boilers built before controls were required on new plants. B&W with support from EPRI has developed low NOx cell (LNC) burners in which one of the two coal nozzles in the dual burner cell is replaced with an air port.

About 70% of the air needed for complete combustion is supplied through or around the coal feed nozzle, with the remaining air directed to the new upper port. By limiting oxygen available at the highest combustion temperatures, LNC burners halve the formation of NOx, and they are only half as expensive to install as commercial low NOx burners.

DOE will fund $4.75 million of the project's total $9.8 million cost. Other contributors are Dayton Power & Light $2.3 million, Ohio Coal Development Office $500,000, EPRI $1 million, B&W $500,000, and other private utilities $750,000.

Design has begun on the 32 month project and 6 weeks of construction are to begin next March, followed by 18 months of tests.

GAS SUSPENSION ABSORPTION

AirPol Inc., Teterboro, N.J., will test a new system to remove sulfur pollutants at a Tennessee Valley Authority (TVA) plant in West Paducah, Ky.

DOE said AirPol's GSA technique is one of several processes near commercialization that can be retrofitted to existing plants to reduce SO2 at a much lower cost.

Conventional SO2 reduction methods typically involve wet scrubbers, which remove about 90% of sulfur pollutants from flue gases but are expensive to build and operate and produce a sludge requiring further treatment before disposal. Spray or dry scrubbers produce a dry waste product, but are uneconomic with high sulfur coals.

DOE said the GSA method would combine the benefits of spray dryers with the emission reduction capabilities of conventional scrubbers at 40% less cost than wet scrubbers. The system also takes less space than conventional scrubbers and is relatively simple to operate.

It mixes coal combustion gases with a suspended mixture of solids, including sulfur-absorbing lime. After the lime absorbs the sulfur pollutants, the solids are separated from the gases in a cyclone device and recirculated to capture additional sulfur pollutants. The cleaned flue gases are sent through a final dust collector before release into the atmosphere.

DOE said the key to the system's successful economics with high sulfur coals is recirculation of solids; a solid particle will pass through the system about 100 times before leaving the system. Another advantage is that a single spray nozzle is used to inject fresh lime slurry.

The method was first developed as a calcining device for limestone used in cement production. It has also been used to capture chloride emissions from a commercial waste to energy plant in Denmark. Tests of the process will divert a portion of the flue gases equivalent to about 10,000 kw from a 150,000 kw boiler currently burning high sulfur coal. Design is to be complete by February, followed by 8 months of construction. The system will be tested for 12 months.

DOE is contributing $2 million of the project's $6.9 million cost. Other contributors are AirPol and parent FLS miljo AS, Copenhagen, $2.3 million and TVA $2.6 million.

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