Advanced Electric Power Generation
Advanced Combustion/Heat Engines

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Participant
Alaska Industrial Development and Export Authority

Location
Healy, Denali Borough, AK (adjacent to Healy Unit No. 1)

Plant Capacity/Production
50 MWe (nominal)

Technology
TRW's Clean Coal Combustion System; Babcock & Wilcox's spray dryer absorber (SDA) with sorbent recycle

Coal
Usibelli subbituminous 50% run-of-mine (ROM) coal and 50% waste coal

Additional Team Members
Golden Valley Electric Association
host and operator
Stone and Webster Engineering Corp.
engineer
TRW Inc., Space & Technology Division
combustor technology supplier
The Babcock & Wilcox Company (B&W) 
spray dryer absorber technology supplier
Usibelli Coal Mine, Inc.
coal supplier
Steigers Corporation
environmnetal and permitting support

Project Funding

Project Objective
To demonstrate an innovative new power plant design featuring integration of an advanced combustor coupled with both high- and low-temperature emissions control processes.

Technology/Project Description
Emissions are controlled using TRW's clean coal combustion system, an advanced entrained/slagging combustor through staged fuel and air injection for NOx control and limestone injection for SO₂ control. Additional SO₂ is removed using B&W's activated recycle SDA.

A coal-fired precombustor increases the air inlet temperature for optimum slagging performance. The slagging combustors are bottom mounted, injecting the combustion products into the boiler. The main slagging combustor consists of a water-cooled cylinder that slopes toward a slag opening. The precombustor burns 25%-40% of the total coal input. The remaining coal is injected axially into the combustor, rapidly entrained by the swirling precombustor gases and additional air flow, and burned under substoichiometric conditions for NOx control. The ash forms molten slag, which flows along the water-cooled walls and is driven by aerodynamic and gravitational forces through a slot into the slag recovery section. About 70%-80% of the ash is removed as molten slag. The hot gas is then ducted to the furnace where, to ensure complete combustion, additional air is supplied from a tertiary air windbox to NOx ports and to final overfire air ports. Pulverized limestone (CaCO₃ ) for SO₂ control is fed into the combustor where it is flash calcined (converting CaCO₃ to lime [CaO]). The mixture of this CaO and ash that was not removed in the combustor, called flash-calcined material, is removed in the fabric filter system. Most of the flash-calcined material is used to form a 45% solids slurry, which is injected into the spray dryer. The SO₂ in the flue gas reacts with the slurry droplets as water is simultaneously evaporated. The SO₂ is further removed from the flue gas by reacting with the dry flash-calcined-material on the baghouse filter bags.

Healy Clean Coal Project Process Flow Diagram
Larger jpg or wmf version

Results Summary

Environmental

• NOx emissions ranged from 0.208–0.278 lb/10⁶ Btu, with typical emissions of 0.245 lb/10⁶ Btu on a 30-day rolling average, which is well below the permit limit of 0.350 lb/10⁶ Btu on a rolling day average.

• SO₂ emissions were consistently less than 0.09 lb/10⁶ Btu, with typical emissions of 0.038 lb/10⁶ Btu, which are below the permit limit of 0.10 lb/10⁶ Btu (3-hour average).

• High SO₂ removal efficiencies in excess of 90% were achieved with low-sulfur coal and Ca/S molar ratios of 1.4–1.8.

• Particulate matter (PM) emissions were 0.0047 lb/10⁶ Btu, which is well below the permit limit of 0.02 lb/10⁶ Btu.

• CO emissions were less than 130 ppm at 3.0% O₂, with typical emissions of 20–50 ppm at 3.0% O₂, which is well below the permit limit of 202 ppm at 3.0% O₂.

• Tests showed that the SDA system SO₂ emissions, PM emissions, and opacity were well within guarantees of the technology supplier.

Operational

• Carbon burnout goals for the technology supplier were achieved—greater than 99% carbon burnout at 100% maximum continuous rating (MCR) for the ROM, 50/50 blend of ROM/ waste coal, and 55/45 blend. The carbon burnout was typically 99.7%.

• The contract goal of the technology supplier for slag recovery greater than 70% at 100% MCR for all coals was also achieved. Slag recovery ranged from 78–87%, with a typical recovery of 83%.

• During a 90-day test in the second half of 1999, the plant availability was 97% at a capacity factor of 95%.

• The SDA pressure drops and power consumption were well below guarantee levels of the technology supplier.

• The system required less limestone and produced less solid waste by-product than anticipated.

Economic

• The capital costs of a 50-MWe and 300-MWe plant using this system are $90.6 million ($1,812/kW) and $450.7 million ($1,502/kW) (1993$), respectively.

• The variable operating costs for the 300-MWe system are $7.2 million/yr (1993$) for the fixed cost and $28.4 million/yr (1993$) for the variable costs (based on 90% capacity factor).

• The levelized cost of power is 36.5 mills/kWh (constant 1993$) for the 300-MWe plant (based on 90% capacity factor).

• The levelized cost per ton of SO₂/NOx removed is $6,499/ton (constant 1993$) for the 300 MWe plant (based on 90% capacity factor).

Project Summary
The Healy Clean Coal Project is the first utility-scale demonstration of the TRW clean coal combustion system. The project site is adjacent to the existing Healy Unit No. 1 near Healy, Alaska and the Usibelli coal mine. Power is supplied to the Golden Valley Electric Association (GVEA).

Environmental Performance
The entrained/slagging combustor is designed to minimize NOx emissions, achieve high carbon burnout, and remove the majority of fly ash from the flue gas prior to the boiler. The slagging combustor is also the first step of a three-step process for controlling SO₂ by first converting limestone to flash-calcined lime. Second, the flash calcined-lime absorbs SO₂ within the boiler. Third, the majority of the SO₂ is removed with B&W's SDA system, which uses the flash-calcined lime and fly ash captured in the baghouse. Because most of the coal ash is removed by the slagging combustors, the recycled material is rich enough in calcium content that the SDA can be operated solely on the recycled solids, eliminating the need to purchase or manufacture lime for the back end scrubbing system.

During a cumulative six-month combustion system characterization test, a series of tests were performed to establish baseline performance of the combustion system while burning ROM and ROM/waste coal blends, to map combustor performance characteristics over a broad range of operating conditions and hardware configurations, and to determine the best configuration and operating conditions for long-term operation. During the 24-month demonstration test period, the NOx, SO₂, PM, opacity, and CO emission goals were met with the exception of short-term SO₂ and opacity exceedances during start-up and repairs. The emissions, as well as permit and NSPS requirements, are presented in Exhibit 5-47.

Performance testing of the SDA system conducted in June 1999 showed that the technology performed well. Measurements of the SDA inlet, SDA outlet, stack, limestone feed, coal feed, air preheater hopper ash, surge bin ash, electrical power consumption, and stack opacity, as well as normal plant data from the plant distributed control system, showed that the technology exceeds the guarantees. The results of the tests and the performance guarantees are shown in Exhibit 5-48. It should be noted that environmental performance was not fully optimized.

Operational Performance
The slagging stage of the combustor performed extremely well and continuously demonstrated the capability to burn both ROM and ROM/waste coal blends over a broad range of operating conditions. The precombustor performed very well with ROM coal, but exhibited more variable performance, in terms of slagging behavior, during the initial tests with ROM/waste coal blends.

Localized slag freezing was observed in the precombustor during early testing. A combination of hardware configuration and operational configuration changes were made that minimized slag freezing. These changes included relocating the secondary air from the precombustor mix annulus to the head end of the slagging stage and completely transferring the precombustor mill air to the boiler NOx ports following boiler warmup. These changes eliminated the mixing of excess air downstream of the precombustor chamber to minimize local slag freezing and increased the precombustor operating temperature to provide additional temperature margin. The mill air change had the added benefit of simplifying combustor operation by eliminating the need to monitor and control coal-laden mill air flow to the precombustor mill air ports during steady-state operation.

Testing of the slagging combustor also showed that the contract goals were achieved, which included greater than 99% carbon burnout at 100% MCR for the performance, ROM, 50/50 blend of ROM/waste coal, and 55/45 blend; and greater than 98% carbon burnout at 100% MCR for waste coal. The carbon burnout was typically 99.7%. Slag recovery ranged from 78–87%, with a typical reading of 83%, easily meeting the contract goal for slag recovery of greater than 70% at 100% MCR for all coals.

The SDA system also performed well. During performance testing in June 1999, system pressure drops were well below the 13 inches water gage (in. w.g.) guarantee. The range was 9.6– 10.0 in. w.g. as can be seen in Exhibit 5-48. Power consumption was approximately 38–41% less than the guaranteed level. Based on these results, Stone & Webster concluded that the SDA system met all performance guarantees.

Economic Performance
Capital and operating cost estimates were prepared by an independent consultant to the participant for new plants in the “lower 48” that incorporate the technology demonstrated at Healy. The capital costs for a 50-MWe and 300- MWe plant are $90.6 million (1,812 $/kW) and $450.7 million (1,502 $/kW) (1993$), respectively. The variable operating cost for the 300-MWe plant is estimated at $7.2 million per year and the fixed operating costs are estimated at $28.4 million per year based on a 90 percent capacity factor (1993$). The levelized cost of power would then be 36.5 mills/kWh (constant 1993$). The levelized cost per ton of SO₂ and NOx removed is $6,499/ton (constant 1993$) for the 300-MWe plant.

Commercial Applications
This technology is appropriate for any size utility or industrial boiler in new or retrofit uses. It can be used in coal-fired boilers as well as in oil- and gas-fired boilers because of its high ash-removal capability. However, cyclone boilers may be the most amenable type to retrofit with the entrained/slagging combustor because of the limited supply of high-Btu, low-sulfur, low-ash-fusion-temperature coal that cyclone boilers require. The commercial availability of cost-effective and reliable systems for SO₂, NOx, and particulate control is important to potential users planning new capacity, repowering, or retrofits to existing capacity in order to comply with CAAA requirements.

Contacts

Arthur E. Copoulos, Project Manager
  Alaska Industrial Development and Export Authority
  813 West Northern Lights Boulevard
  Anchorage, Alaska 99503
  (907) 269-3029
  (907) 269-3044 (fax)
  acopoulos@aidea.org

Victor K. Der, DOE/HQ, (301) 903-2700
  victor.der@hq.doe.gov

Robert M. Kornosky, NETL, (412) 386-4521
  robert.kornosky@netl.doe.gov

Web Site:
  www.aidea.org