CCT-I 

Project Fact Sheets 
Development of the Coal 

Quality Expert 

Sponsor: 

ABB Combustion Engineering, Inc., and CQ, Inc. 

Additional Team Members: 

Black and Veatch-cofunder and expert system 

developer 

Elecuic Power Research Institute-cofunder 

The Babcock &Wilcox Company-cofunder and pilotscale testing 

Expert-EASE Systems Inc.-expert system architecture 

developer 

Electric Power Technologies, Inc.-field !esting 

University of North Dakota, Energy and Minerals 

Research Center-bench-scale testing 

Alabama Power Company-host utility 

Duquesne Light Company-host utility 

Mississippi Power Company-host utility 

Northern States Power Company-host utility 

Pennsylvania Electric Company and New York State 

Electric &Gas Corporation-host utilities 

Public Service of Oklahoma-host utility 

Locatlons: 

Alliance, Colombiana County, OH (pilot-scale tests) 

Windsor, Hartford County, CT (pilot-scale tests) 

Grand Forks, Grand Forks County, ND (bench tests) 

Wilsonville, Shelby County, AL (Gatson, Unit 5) 

Springdali, Westmoreland County, PA (Cheswick 

Station) 

Gulfport, Harrison County, MS (Watson, Unit 4) 

Bayport, Washington County, MN (King Station) 

Homer City, IndianaCounty, PA (Homer City, Unit 2) 

Oologah, Rogers County, OK (Northeastern, Unit 4) 

Technology: 

CQ, Inc.‘s EPRI coal quality expert (CQE) computer 

model 

8-8 PXl~~‘ZTZ Updare 1991 ABE Combustion Engineering and CQICQE Model 

Plant Capaclty/ProducUon: 

Full-scale testing will take place at six utility sites ranging in size from 250 to 880 MWe. 

Project Funding: 

Total project cost 

DOE 

Participants 

$17,38X258 100% 

8,691,129 50 

8,691,129 50 

Project Objective: 

To demonstrate ao expert system that can be run on a 

personal computer and provide coal-burning utilities 

with a predictive tool to assist in the selection of optimum quality coal for a specific boiler based on operational efficiency and environmental emissions. 

Technology/&olect Description: 

Data derived from bench-, pilot-, and full-scale testing 

are being used to develop algorithms for inclusion 

into an expert model, the Coal Quality Expert, that can 

be run on a personal computer. Utilities may use the 

information to predict the operating performance of 

coals not previously burned at a particular facility. 

Six large-scale field tests consist of burning a 

baseline coal and an alternate coal over a 2-month 

period. The baseline coal, the one currently used as 

fuel, is used to characterize the operating performance 

of the boiler. The alternate coal, a blended or cleaned 

coal of improved quality, is burned in the boiler for the 

remaining test period. 

The baseline and alternate coals for each test site 

also are burned in bench- and pilot-scale facilities under 
Calendar Year 

tsse 198.9 ,990 ,991 ,992 1&x3 ,994 1995 ,996 1997 199.3 

341234123412341 2 3 4 1 234 1234 1 2 3 4 12341234 12 

I 

j bperation intiated *igO I ’ 

Project completed~inal r*po* issue4 2% 

fnviranmental monitoring plan completed 7131190 Field testing completed 8193 

~;OE&leBlected project Cooperative agreement awarded 6114190 

‘Proiecmd date 

similar conditions. The alternate coal is cleaned at CQ, 

Inc., to determine what quality levels of clean coal can 

be produced economically and then transported to the 

bench- and pilot-scale facilities for testing. All data 

from bench-, pilot-, and full-scale facilities are evaluated and correlated to formulate algorithms being used 

to develop the model. 

Bench-scale testing will be performed at the University of North Dakota’s Energy and Mineral Research 

Center in Grand Forks, ND, pilot-scale testing will be 

done at ABB Combustion Engineering’s facilities in 

Windsor, CT, and Alliance, OH. The six field test sites 

are: Gatson, Unit 5 (880 MWe), Wilsonville, AL; 

Cheswick Station (500 MWe), Springdale, PA; Watson, 

Unit 4 (250 MWe), Gulfport, MS; King Station 

(560 MWe), Bayport, MN; Homer City. Unit 2 

(600 MWe), Homer City, PA; and Northeastern, Unit 4 

(445 MWe), Oologah, OK. 

ProJect Status/Accomplishments: 

Several field tests are complete, such as those conducted at Public Service of Oklahoma’s Northeastern 

Unit 4, Mississippi Power Company’s Watson Unit 4, 

and Northern States Power Company’s King Station. 

ABB Combustion Engineering and CQICQE Model 

Coals tested include Wyoming, blends of Wyoming/ 

Oklahoma, Illinois, and western Kentucky, and a blend 

of Wyoming/Montana/petroleum coke. Tests at Alabama Power Company’s Gatson Unit 5 will be resumed 

in the spring or summer of 1992. The CQE “Acid Rain 

Advisor” software package will be commercially released in January 1992. Pilot and bench coal tests are 

continuing. 

demonstration, CQ. Inc., will market the CQE system in 

the United States and abroad. 

Environmental Considerations: 

NEPA compliance has been satisfied by a memo-to-file 

approved on April 27, 1990. An environmental monitoring @an has been prepared. 

It is projected that by using the CQE model, SO, 

and NO, emissions can be significantly reduced on a 

national basis relative to the no-action alternative considered in the PEIS. The expert system will enable coalfired utilities to select the optimum quality coals for 

their specific boilers to reduce SO, and NO, emissions. 

Commercial Application: 

The CQE system is applicable to all electric power 

plants and industrial/institutionaJ boilers that bum coal. 

The CQE will predict the operational and emission 

reduction benefits of using cleaned coal. Following the 

Program Update 1991 8-9 
LIMB Demonstration Project 

Extension and Coolside 

Demonstration 

LIMB COOLSIDE LIMWCOOLSIDE 

Sponsor: 

The Babcock &Wilcox Company 

Additional Team Members: 

Ohio Coal Development Office-cofunder 

Consolidation Coal Company-cofunder and 

technology supplier 

Ohio Edison Company-host utility 

Location: 

Lorain, OH (Ohio Edison’s Edgewater Station) 

Technology: 

The Babcock & Wilcox Company’s limestone injection 

multistage burner (LIMB) system 

Consolidation Coal Company’s Coolside duct injection 

of lime sorbents 

Plant Capaclty/ProrJuctlon: 

105 MWe 

AND DISPOSAL 

Prolect Funding: 

Total project cost 

DOE 

Participants 

$19,404,940 toG?k 

7,591,026 39 

11,807,914 61 

Project Objective: 

Technology/Project Description: 

The LIMB process is expected to reduce SO, by 

50-60% by injecting dry sorbent into the boiler at a 

point above the burners. The sorbenthen travels 

through the boiler and is removed along with fly ash in 

the existing particulate removal equipment, either a” 

electrostatic precipitator (ESP) or a baghouse. Humidification of the flue gas before it enters a” ESP is necessary to maintain normal ESP operation and to enhance 

SO, removal. This project will test combinations of 

three coals, each with a different sulfur content (1.6%. 

3.0%, and 3.8%), and four sorbents. The tests are expected to provide commercial-scale operating and maintenance data on a variety of coallsorbent combinations 

with diverse SO, removals and costs. Both limestone 

and hydrated lime (calcitic and dolomitic) sorbents will 

be tested. 

To demonsaate., with a variety of coals and sorbents, the 

limestone injection multistage burner (LIMB) process as 

a retrofit system for simultaneous control of sulfur and 

nitrogen oxides in the combustion process, and that 

LIMB can achieve up to 60% NO, and SO, reductions: 

to test alternate sorbent and coal combinations ,using 

the Coolside duct injection process, to demonstrate induct sorbent injection, upstream of the humidifier and 

precipitator: and to show SO, removal of up to 80%. 

Iu the Coolside process, dty sorbent is injected into 

the flue gas after the boiler and before the ESP. The gas 

is humidified in this process to enhance both ESP performance and SO, absorption. Also, a chemical additive can be dissolved in the humidification water to 

improve SO, absorption. Because of these benefits, it is 

expected that humidification equipment will be part of 

most, if not all, commercial Coolside applications. The 

spent sorbent is also collected with the fly ash as in the 

LIMB process. Reduction of SO, by 50-80% is expected. 

Both demonstrations used the same low-NO, burners, which control NOx by injecting the coal and part of 

the combustion air simultaneously so that the tirst of the 

S-10 Program Update 1991 B&W/LIMB 
Calendar Year 

,986 198, 198.3 ,989 ,990 1901 1992 ,993 ,994 ,995 1998 

3 4 1 234 1 2 3 4 1234 1 234 1 234 1 234 1 234 1 234 1 234 12 

Design and Construction 

10189 7/92 

1 !L2%E: 1 

LIMB extension final report issued 7/W 

1 bz:::e:89 [p,a,io~com;,~*d ;,301s, 

Coolrlde toptcal repon issued 2192’ 

Preoperational tesfs inifiatad 7189 

NEPAprocess 

completed 6r2/87 Environmental monitoring plan completed 10119188 

Cooperative 

agreement awarded 

6~5,37 

*Proiected date 

combustion reactions takes place in an oxygen-deficient limes at a calcium-to-sulfuratio of 2~1. Sodium hy- Environmental Considerations: 

environment. The balance of the combustion air is &oxide addition and higher sorbent rates achieved NEPA compliance was satisfied with a memo-to-file 

inuoduced in a second stage to complete the combus- higher SO, removal, and sorbent recycle significantly signed on June 2, 1987. 

tion process. Staged combustion has been found to increased sorhent utilization. When Coolside testing Because of wide market application, SO, and NOx 

reduce NO, emissions by 50-60%. was concluded in February 1990, the system had oper- reductions of 30% and 11% respectively by ZOIO are 

This project was conducted at Ohio Edison’s Edgewater Plant in Lorain, OH, on a commercial, Babcock & 

Wilcox Carolina design, wall-fired 105-MWe boiler. 

ated for over 1,700 hrs, including 265 hrs of uninterrupted operation. The full-scale tests favorably confumed the previous pilot-scale testing. 

projected on a national basis, assuming maximum cnmmercialization of the technology. (Source: CCT Programmatic Environmental Impact Statement) 

Project StatWAccompllshments: 

The project has completed testing of the Coolside and 

LIMB processes. 

Coolside test results indicate that this process can 

remove up to 70% of the SO, when using 3.0% sulfur 

coal at a 2:l calcium-to-sulfur molar ratio using a commercially available hydrated lime, a 20 “F approach to 

adiabatic saturation, and an additive to the 

humidification water at a 0.2~1 sodium-to-calcium ratio. 

SO, removal rates up to 70% were routinely achieved 

with two different commercially available hydrated 

LIMB extension testing also demonstrated up to 

70% SO, removal using various coal-sorbent combinations. Sorbents tested included lignosulfonated lime, 

ground limestone, hydrated calcitic lime, and locatly 

available hydrated dolomitic lime. Three coals with 

nominal sulfurcontents of 1.5-3.0% were selected for 

testing. NOx removal was in the 40-50% range 

throughout both Coolside and LIMB testing. 

Commercial Appllcatlon: 

Sorbent injection is applicable to most utility and industrial coal-fired units and can beretrofitted with modest 

capital investment and downtime, 

Final reports describing Coolside and LIMB extension testing are being prepared. 

The LIMB and Coolside processes both provide an 

alternative to conventional wet flue gas desulfurizat,inn 

(FGD) processes. Both are expected to be substandally 

less expensive than wet FGD. and their space requirements are also substantially less. These factors are 

important in retrofit applications. 

B&W/LIMB Program Updare 1991 R-II 
Fluidized-Be’d Repowering ” 

Project 

The City of Tallahassee 

Addltlonal Team Members: 

Foster Wheeler Energy Corporation-technology 

supplier 

Bechtel Power Corporation-engineer and conshxctor 

Location: 

A” alternate site is being considered. 

Technology: 

Foster Wheeler’s aunosphaic circulating fluid&d-bed 

combustor (ACFB) 

Plant Capacity/Production: 

250 MWe 

Project Funding: 

Total project cost $276,791,974 100% 

DOE 74,733,833 27 

Participant 202,058,141 73 

(Funding is subject to project restructuring after alternate site is selected.) 

Project Objective: 

To demonstrate ACFB at 250 MWe, representing a 

1.7:1 scale-up from previously constrwted facilities: to 

verify expectations of the technology’s economic, 

environmental, and technical performance in the 

repowering of a” existing oil-/natural-gas-fired boiler at 

a utility site; and to provide the utility industry with the 

data necessary for evaluating a 250-MWe ACFB as a 

commercial alternative to accomplish greater than 90% 

SO, removal, to reduce NOx emissions by 60% when 

compared with conventional technology, and to achieve 

a steam efficiency of 88%. 

Technology/Project Description: 

a solid sorbent, such as limestone, are introduced into 

the lower portion of a water-wall combustor where 

In this project, the circulating fluidized-bed combustor 

initial combustion occws. Combustion takes place at 

relatively low temperatures of 1,500-1,600&F. As coal 

panicles decrease in size due to combustion and breakoperates at atmospheric pressure. Coal, primary air, and 

age, they ue carried higher in the combustor to an area 

where secondary air is inuoduced. As the coal panicles 

continue to be reduced in size, the coal, along with 

some of the sorbent, is canied out of the combustor, 

collected in a particle separator, and recycled to the 

lower portion of the combustor. 

separator are cooled in a convective back pass containing additional superheaters, water walls, and a” econoexchanger located within the circulating loop encommizer. The steam produced is sent to the steam turbine 

passing the combustor, pwticle separator, and solids 

to generate power. Sulfur is absorbed by the sorbent 

andremoved with the ash. 

recycle leg. Combustion gases that leave the particle 

This project involves repowering an existing steam 

electric power plant by “sing a scaled-up ACFB boiler. 

A coal-fired ACFB steam-generating system will replace the existing oil-/gas-fired steam-generating system 

used to drive a steam turbine. The existing turbine 

generator and the balance of the equipment are being 

Heat is removed by the water walls as well as by retained. 

the steam-cooled cyclone and the solids recycle heat 

8-12 Pro~rom Update 1991 City of Tallahossee 
Calendar Year 

1988 1989 w90 199f 1992 1993 ,995 ,996 ,997 lx78 

34123412341234, 234,234 1 :““, 4 1 2 3 4 1 2 3 4 1234 12 

6169 11190 3192 

I Preaward I I 

:::~:::::::::::,::j:~::_:::.:.:.:.:::~~::::::.:.:~:.:.:~:.~~::_::.:.:,:.:.:,:~~~~:,.:,:~:.:,:_:::i::,:~:~j:,:.:.:,:j:::_:.:.:,:.:.:.:_:~::::::::,~:,:,:::.:,:::::::~:.:,:::.:, 

t 

A 

DOE selected 

project 6,23,89 I 

Alternate me identified 3/92 

Cooperative agreement awarded 11,30/90 

‘Projected date: milestones to be revised following 

ahemate site ~&ctin and project restructuring 

Project Status/Accomplishments: 

The City of Tallahassee has elected not to proceed with 

the project at the Atvah B. Hopkins Station site. The 

decision was based on results from an updated economic study which compared costs of the proposed 

repowering project and continued operation of the CUIrent 23-yr-old plant using natural gas. Lower than expected natural gas prices in the near-term and environmenM controls mtxe stringent than required by law 

caused cost increases for the CCI project that indicated 

it was no longer the least-cost option. However, the 

City is still interested in CFB technology and, with DOE 

concut’rence, has authorized Foster Wheeler to locate an 

alternate host site. Work on the project has ceased 

pending identification of a new site. It is estimated that 

an alternate site will be identified and approved in early 

1992. At that time, new project milestone dates and 

revised project costs will be determined. 

* SO, reduction-44% 

. NO= reduction--17% 

- Solid waste increase. but in a dry, granular form 

amenable to some by-product markets 

* Lower capital costs 

. Reduced SO, and NO, emissions at lower costs 

. Higher combustion efficiency 

. Dry, granular solid waste 

. CO, reduction-S% 

(Source: CCT Programmatic Environmental Impact 

Statement) 

Commercial Application: 

ACFB technology has good potential for application in 

both the industrial and utility sectors, whether for use in 

repoweting existing plants or in new facilities. Coal of 

any sulfur content can be used, and any type or size of a 

coal-fired boiler can be repowered. Because an existing plant area is used, and coal- and waste-handling 

equipment as well as steam turbine equipment xe retained. the life of a plant can be extended. 

Envlronmental Considerations: 

The following are projected impacts from maximum 

commercialization of ACFB technology on a national 

basis by 2010 relative to a no-action alternative: 

In its commercial configuration, ACFB technology 

offers several potential benefits when compared to 

conventional ptdverized coal-fired systems: 

City 0fTaUahassee Program Lipdare 1991 8.13 
Advanced Cyclone 

Combustor with Internal 

zElfq,Nitrogen, and Ash 

Sponsor: 

Coal Tech Corporation 

AdditIonal Team Members: 

Commonwealth of Pennsylvania Energy Development 

Authority-cofunder 

Pennsylvania Power and Light Company-supplier of 

test coals 

Tampella K&w-host site 

Locatlon: 

Williamsport, Lycoming County, PA (Tampella Keeler 

boiler manufacturing plant) 

Technology: 

Coal Tech’s advanced, air-cooled, slagging combustor 

Plant Capacity/Production: 

23 million Btu/hr 

Project Funding: 

Total project cost 

DOE 

Participants 

Project Objective: 

$984,394 100% 

490,149 50 

494,245 50 

To demonstrate that an advanced cyclone combustor 

can be retrofitted to an industrial boiler and that it can 

simultaneously remove up to 90% of the SO, and 

90-95% of the ash within the combustor and reduce 

NOx by up to 100 ppm. 

s-14 PrO~W,, Update 1991 Coal Tech 

Technology/ProJect Descrlptlon: 

Coal Tech’s horizontal cyclone combustor is internally 

lined with ceramic that is air-cooled. Pulvetized coal, 

air, and sorbent are injected toward the wall through 

tubes in the annular region of the combustor to cause 

cyclonic action. In this manner, coal particle combustion takes place in a swirling flame in a region favorable 

to particle retention in the combustor. Secondary air is 

used to adjust the overall combustor stoichiometry. The 

ceramic liner is cooled by the secondary air and maintained at a temperature high enough to keep the slag in a 

liquid, free-flowing state. The secondary air is preheated by the combnstor walls to attain efficient combustion of the coal particles in the fuel-rich combustor. 

The fine coal pulverization allows combustion of most 

of the coal particles near the cyclone wall, with the 

balance burned on or near the wall. This improves 

combustion in the fuel-rich chamber, as well as slag 

retention. The slag contains ova 90% of the ash and 

sorbent fed to the combustor. ForNOx control, the 

combustor is operated fuel rich, with final combustion 

taking place in the boiler furnace, to which the combustar is attached. 

The project features combustion of dry pulverized 

coal in an advanced, air-cooled, cyclone coal combustor 

retrofitted on a 23-million-Btuihr, oil-designed package 

boiler located at the Tampella Keeler plant in 

Williamsport, PA. Pennsylvania bituminous coals 

containing from 1% to approximately 3.3% sulfur were 

tested to demonstrate that this combustor is capable 

of burning most U.S. coals in an environmentally 

acceptable manner. 
Calendar Year 

,986 1987 ,9BB 1989 ,990 1991 ,992 1993 1994 1995 1986 

3 4 1 234 1 234 1 234 1 2 3 4 123412341 23412341234 12 

Preaward Design and Cmstruction 

/ ll(97 operauon 

I Con*truction completed 1 l/97 

I 

919’ 

Operation Initiated 11197 

~nvir~nm.mal monitorin DIG c0mhted 9122197 Operdioncompl-d 5/9O 

I ’ -. 

Ground brealdng,construction s,aded ,/9/87 

Design completed 7197 

Cooperative a9reement awarded 3,‘20/87 

NEPA process completed 3126187 

DOE selecled project 7124195 

Project Status/Accomplishments: 

Coal Tech completed design, construction, and operation by mid-1990. The project was completed on 

February 28, 1991. The final report is entitled The 

Demonstration of Advanced Cyclone Coal Combustor. 

with Internal Sulfur, Nitrogen and Ash Controlfor the 

Conversion of a 23 MM Btuihr Oil Fired Boiler k~ 

Pulverized Coal; Volume I-Final Technical Repori; 

Volume 2-Appendices I, II, Ill, IV, and V; Volume 3- 

Appendix VI. The report is available from NTIS as 

DE 9200-2587 Volume 1, and DE 9200-2588-T7 

Appendices. 

The Coal Tech combustor was operated for a#- 

proximately 1,000 hrs under varying loads and conditions simulating industrial applications. Results indicate 

that Coal Tech has achieved most of the objectives that 

were set forth in the cooperative agreement during the 

30.month test period. The test results indicate that Coal 

Tech’s sir-cooled, coal-fired, slagging combustor can 

successfully (1) be retrofitted to and operate efficiently 

Coal Tech 

over a wide stoichiometric range on previously oil- or 

gas-fired boilers, (2) reduce coal-derived NO” emissions 

by approximately 75%, (3) remove up to 90% of the 

coal slag at the combustor slag tap upsneam of the 

boiler, and (4) capture and remove with the slag about 

10% of the sulfur contained in the coal. Coal Tech also 

has test results indicating that over 80% solfur removal 

can be achieved through a combination of sorbent injection at and downstream of the combustor. Coal Tech 

has concluded that this novel air-cooled combustor 

design concept is sound and that sufficient design and 

operational information has been obtained from this 

CCT demonstration to scale up to 100 million Btuihr. 

Envlronmental Conslderatlons: 

NEPA compliance was satisfied by a memo-to-file 

approved on March 26, 1987. 

The advanced cyclone combustor is expected to 

reduce emissions nationally as follows: 

. SO, reduction-45% 

. NO, reduction- 18% 

The SO, emissions are reduced through sorbent injection. (Source: CCT Programmatic Environmental impact Statement) 

Commercial Application: 

Coal Tech’s advanced, air-cooled, slagging combustor 

permits the combustion of a wide range of U.S. coals, 

including high-sulfur coals. This combustor can be 

used to retrofit small utility and indushial boilers that 

currently operate with oil or gas firing, due to the 

combustor’s ability to effectively eliminate coal solids 

upstream of the boiler and to control NO, and SO,emissions. 

Program Update 1991 8-1s 
Nucla CFB Demonstration 

Project 

Sponsor: 

Colorado-Ute Electric Association, Inc. 

Additional Team Members: 

Pyropower Corporation-technology supplier 

Technical Advisory Group (potential users)-cofunder 

Electric Power Research Institute- technical support 

Location: 

Nucla, Montrose County, CO (Nucla Station) 

Technology: 

Pyropower’s atmosphericirculating fluidized-bed 

combustion (ACFB) system 

Plant Capacity/Production: 

1lOMWe 

Project Funding: 

Total project cust 

DOE 

Participants 

$54,087,000 100% 

19,920,OoO 37 

34,167,OOO 63 

Project Objective: 

To demonstrate ACFB at a scale of 110 MWe, representing a 2:l scale-up from previously demonstrated 

capacities: to verify expectations of the technology’s 

economic, environmental, and technical perfortnance in 

a repowering application at a utility site; to accomplish 

greater th& 90% SO, removal; to reduce NOx emissions by 60%; and to achieve an efficiency of 34% in a 

repowering mode. 

IGH-SULFUR 

P 

L LIMESTONE 

STEAM TURBINE 

Technology/Project Descrlptlon: 

The Nucla circulating fluidized-bed system operates at 

atmospheric pressure. In the combustion chamber, a 

stream of air fluidizes and entrains the bed material, 

which includes coal, coal ash, and a sulfur sorbent such 

as limestone. Combustion takes place at relatively low 

temperatures that limit NOx fortnation. Calcium in the 

sorbent combines with SO, gases, and solids exit the 

combustion chamber and flow into a hot cyclone. The 

cyclone separates the solids from the gases, and the 

solids are recycled for combustor temperature control. 

Continuous circulation of coal and sorbent improves 

mixing and extends the contact time of solids and gases, 

thus promoting high utilization of the coal and high 

sulfur capture efficiency. Heat in the flue gas exiting 

the hot cyclone is recovered in the economizer. The 

flue gas passes through a baghouse where the particulate 

matter is removed. The steam generated in the ACFB is 

used to generate power. 

Three small, coal-tired, stoker-type boilers at the 

Colorado-Ute Nucla Station were replaced with a single 

ACFB steam generator capable of driving a new 

74-MWe turbine generator. Extraction steam from this 

turbine generator will power the three existing turbine 

generators of 12 MWe each. The majority of other existing plant equipment is being used to minimize costs and 

to demonstrate the suitability of ACFB technology for 

repowering and life extension of existing units. 

S-16 Progrm Update 1991 Colorado-Ufe 
Wab.a.sh River Coal 

;;;d$on Repowering 

Sponsor: 

Wabash River Coal Gasification Repowering Project 

Joint Venture (a joint venture of Destec Energy, Inc., 

and PSI Energy, Inc.) 

Additional Team Members: 

PSI Energy, Inc.-host utility 

Destec Energy, Inc.-engineer, gas plant operator, and 

technology supplier 

Electric Power Research Institute-cofunder 

Locatlon: 

West Terre Haute, Vigo County, IN (PSI Energy’s 

Wabash River Generating Station) 

Technology: 

Integrated gasification combined-cycle (IGCC) using 

Destec’s two-stage, entrained-flow gasification system 

FEED WATER 

Plant Capaclty/Productlon: 

265 MWe 

Project Fundlng: 

Total Project cost $591,927,376 100% 

DOE 244,585,837 41 

Participant 347,341,539 59 

(Funding amounts reflect those contained in the 

proposal and are subject to negotiation.) 

Technology/Project Description: 

Coal is ground, slurried with water, and gasified in a 

pressurized, two-stage (entrained flow slagging first 

stage and non-slagging second stage), oxygen-blown, 

entrained-flow gasifier. The product gas is cooled 

through heat exchangers and passed thraugh a conventional cold gas cleanup system which removes pzticulaw, ammonia, and sulfur. The clean, medium-Btu gas 

is then reheated and burned in an advanced 192-MWe 

gas turbine. Hot exhaust from the gas turbine is passed 

through a heat recovev steam generator to produce 

high-pressure steam. High-pressure steam is also 

produced from the gasification plant and superheated in

the heat recovery steam generator. The combined highpressure steam flow is supplied to an existing 1 IO-MWe 

steam turbine. 

The process has the following subsystems: acoalgrinding and slut’ry system, an entrained-flow coal 

gasifier, a cold gas cleanup system which produces a 

marketable sulfur by-product, a combustion turbine 

capable of using coal-derived fuel gas, a heat recovery 

steam generator, and arepowered steam turbine. 

Project Objectlve: 

One of six units at PSI Energy’s Wabash River 

Generating Station, located in West Terse Haute, IN, is 

being repowered. The demonstration unit will be 

To demonstrate utility repowering with a two-stage, 

oxygen-blown IGCC system, including advancements 

in the technology relevant to the use of high-sulfur 

bituminous coal, and to assess long-term reliability, 

availability, and maintainability of the system at a fully 

commercial scale. 

designed to generate 265 MWe net using 2,544 tons/day 

of high-sulfur, Illinois Basin bituminous coal. Upon 

completion, the project will represent the largest singletrain IGCC plant in operation in the United States. 

S-96 Program Update 1991 Wabash River Coal 
Calendar Year 

,987 ,988 ,989 ,990 1991 ,992 1993 ,994 199s ,896 ,997 

3 4 1 234 1234 1 234,234 1 234 1 2341234 t 234 1 234 12 

y7 2lQ2 

olaemlon I 

’ I ’ ‘Cooperative agreement awarded tWY88 Project completediflnal 

Operation test program initiated 8/171*8 report issued zm?’ 

Operation completed l/91 

NEPA process completed M8188 

Environmental monitoring plan completed 2127188 

DOE selected pmject ioh’/ 

‘Prqected date 

Project Status/Accomplishments: 

The project was initially scheduled to be completed in 

August 1990 following a Z-yr operational test program. 

Although some 15,700 hrs of testing were accomplished, the test program could not be completed within 

the originat schedule because of numerous plant outages 

forrepairs and plant modifications that were mostly 

unrelated to the ACFB technology. Therefore, testing 

was extended to complete the program and determine 

the optimum operating conditions and performance. 

To date, Nucla has met all NSPS requirements with 

better than 90% sulfur capture, has typically achieved 

NOx emissions less than 0.18 lb/million Btu, and has 

removed 99.96% of theparticulates. Cost information is 

promising, with capital cost of approximately 

$1,02l/gross kW and operating cost at $2O/MW. This is 

competitive with pulverized coal units that are not limiting emissions as significantly as Nucla. Net heat rates 

have averaged about 11,900 Btu/kWh. A 2007h0V.e 

facility is projected to operate at heat rates of appraximately 10,000 Btu/kWh. 

To complete project reporting requirements, the 

project has been extended to February 29, 1992. 

Environmental Considerations: 

NEPA compliance was satisfied April l&1988, with a 

memo-to-file. The performance to date of the demonstration has met or exceeded the improved environmental performance projections for the ACFB. 

The following impacts are projected from maximum commercialisation of the ACFB technology on a 

national basis by 2010 relative to a no-action 

alternative: 

* SO, reduction- 44% 

* NO, reduction-17% 

* CO, reduction-5% 

Although solid waste is expected to increase, it would be 

in a dry, granular form more amenable to alternative 

uses, such as construction aggregate, and requiring less 

land area for disposal than conventional scrubber sludge. 

(Source: CCT Programmatic Environmental Impact 

Statement) 

Commercial Apptlcatlon: 

ACFBs have good potential for both industrial and utility 

sectors in repowering existing coal-fined plants or new 

facilities. In repowering applications, ACFB can increase capacity by an increment of about 15%. Coal of 

any sulfur content can be used. Because any type or size 

of boiler can be repowered by ACFB using the existing 

plant area, coal- and waste-handling equipment, and 

steam turbine equipment, the life of the plant can be 

extended. Benefits of ACFB include 90% SO, reduction, 

60-80% NOx reduction, and control of pollutants at 

lower costs than are offered by existing technologies. 

Colorado-(ire Program Update 191 8.17 

calendar Year 

1986 ,987 1988 1989 1990 1991 1992 1993 ,994 ,995 ,996 3 4 1 234 1 234 1 2 3 4 1 2 3 4 1 2 3 4 1234 1 23412341234 12 

7187 

A A A A 

I I SPA 

DOE selected Cooperative process 

project 7,24/w agreement mmpleted. 

awarded Hennepin 

,,I 4187 5,9/98 

Design completed, both sites 5189 

Construofion stalted, Hennepin 5199 

NEPA process completed, Lakeside 6125199- i 

Environmental monitoring plancompleted, Hennepin 10115199 L 

k.--. Pro)& completedfinal report issued 9193 

I ’ Operation completed. Lakeside 9~93‘ 

Operation completed, Hennepin 9192’ 

Operation initiated, Lakeside 4192’ 

Construdion completed. Lakeside 1192’ 

Construclion completed. liennepin &91 

Operation initiated, Hennepin l/91 

nstruction stated. Lakeside 6190 

-Environmental monitoring Plan 

completed. Lakeside 1 l/15/99 

‘Projected date 

Project Status/Accomplishments: 

Permitting and engineering design efforts were completed for the 3 original project sites. In 1990, plans to 

use the third site (Bartonville, lL) were suspended. 

Construction is complete and operation activities 

have begun at the tangentially fired boiler at Hennepin. 

A matrix of 32 gas rebum tests have been completed, 

achieving NOx reduction rates of 60-,65%. III one 

short-term test, a 77% reduction in NO, was achieved. 

Evaluation of 20 over-fue air tests indicated substantial 

NOx reduction was achieved at low loads with lesser 

reductions as load increased. Combined operational 

testing of gas rebuming and sorbent injection began in 

August 1991 with SO, reduction in the range of 

50-X%. Operations at Hennepin should be completed 

by September 1992. 

At Lakeside, construction is scheduled for completion in January 1992, at which time start-up activities 

will begin. Frozen conditions at this site in early 1991 

delayed civil construction work and made it necessary 

to reschedule the completion of constmction and 

start-up. 

Environmental Considerations: 

NEPA compliance was satisfied for Hennepin with a 

memo-to-file approved on May 9, 1988, and for 

Lakeside with an environmental assessment and finding 

of no significant impact approved June ?a, 1989. 

Assuming maximum commercialization, significant 

SO, aodNORreductions (38% and 11% respectively) are 

projected to be achievable nationally by 2010 with 

enhancement of the use of coals by gas reburning and 

sorbent injection relative to a no-action alternative. Gas 

rebuming will reduce emissions of NO,, and sorbent 

injection will reduce emissions of SO,. The gas 

rebuming and sorbent injection process has wide applicability as it can be renofitted to many coal-fued boilers. (Source: CCT Programmatic Environmental Impact 

Statement) 

Gas reburning and sorbent injection is the unique combination of two separate technologies. The commercial 

application for these technologies, both separately and 

combined, extends to both utility companies and industry in the United States and abroad. In the United States 

alone, these two te@mologies can be applied to over 900 

pre-NSPS utility boilers; additionally the technologies 

can be applied to new utility boilers. With 60% NOx 

removal and 50% SO, removal, these technologies have 

the potential to extend the life of a boiler or power plant 

and also provide a way to use higher solfur coals witbout exceeding emission limits for NO, and SO,. 

EERIGas Reburning and Sorbenr Injection Prqram Update 1991 8.19 
Tidd PFBC Demonstration 

Project 

Sponsor: 

The Ohio Power Company 

Addltlonal Team Members: 

American Electric Power Service Corporationdesign, construction, and management 

ABB Carbon and Babcock & Wilcoxtechnology supplier 

Ohio Coal Development Office-cofunder 

Locatlon: 

Brilliant, Jefferson County, OH (Ohio Power 

Company’s Tidd Plant) 

Technology: 

ABB Carbon and B&cock&Wilcox’s pressurized 

fluidized-bed combustion (PPBC) system 

Plant Capaclty/Productlon: 

70 MWe 

Project Fundlng: 

Total project cost $167,500,000 100% 

DOE 60,200,000 36 

Paticipants 107,3cwo0 64 

Project Objectlve: 

To demonsuate PFBC at a 70-MWe scale, representing 

a 13: I s&-up from the pilot plant facility; to verify 

expectations of the technology’s economic, environmental, and technical performance in a combined-cycle 

repowering application at a utility site; and to accomplish greater than 90% SO, removal, NOx emission level 

of 0.2 lb/million Btu, and an efficiency of 38% in a 

repowering mode using the existing steam system. 

8.20 PrO&Vc7,,, Updore I991 

AIR - 

WLOMITVUMESTO 

COAL 

MATER 

‘, .I,:.:,.,:,:,ili~~~~:~:ji c irf~~~~C~l~;-li-::::: :~~:~~ii:~:~.l:.:,:.:lra ,.,.... //::,: TO DISPOSAL 

Technology/Project Description: 

This PFBC technology uses a pressurized bubbling 

fluidized-bed operating at 175 lb/in2 atm. Pressurized 

combustion air is supplied by the gas turbine compressor. In PFBC, the air fluidizes the bed material, which 

consists of fuel (a coal-water paste), coal ash, and dolomite sorbent. The hot combustion gases exiting the bed 

vessel with enuained ash particles pass through cyclones to remove 98% of the particles. The gas exits the 

pressure vessel and is expanded in a gas turbine to 

produce 16 MWe. The gas exiting the turbine is cooled 

in a waste heat recovery step and cleaned further in an 

electrostatic precipitator prior to discharge into the 

atmosphere. Pressurized boiler feed water is converted 

to superheated steam in the tubes in the boiler zone of 

the pressure vessel. The steam exits at 1,305 lb/id atrn 

duce 58 MWe. The dolomite in the bed reacts with the 

sulfur to form calcium sulfate, a dry, granular material, 

and 925 OF and passes through a steam turbine to prowhich is discharged with the ash for disposal or 

by-product recovery. The maximum bed temperature of 

1,600 “F reduces the formation of NOx. 

The Unit 1 boiler at the Tidd facility is being 

replaced with the PFBC system and the addition of the 

gas cycle. The existing steam turbine and condensate 

and feed water systems ale being refurbished. 

Project Status/Accomplishments: 

Electricity was successfully generated for the fist time 

on December 6, 1990, with the plant operating in a 

combined-cycle mode, Start-up proceeded through 

February 1991 with operation starting in March 1991. 

Ohio Power 
bperatian inliated 391 

Preoperalionalt~*ts ar!ad la990 

Construction csmpbted 12.QO I h+3ct completed/final 

repod issued 12194 

ODeration completed a/94’ 

bndrunian started 1219/W 

,operafive agreement awarded 3/20/87 

Design completed 12/90 

NEPAprocess completed 315/W 

I DOE S8leC1sd project 7124186 

‘Projecfed date 

The unit achieved full-bed height operation of 

127 inches on April 21, 1991. By year-end 1991, over 

900 hrs of coal-fired operation had been logged, including one continuous run exceeding 110 hrs.: Preliminary 

testing conducted at port load indicated that SO, and 

NOx emissions are below NSPS requirements. On July 

17, 1991, Power Magazine presented the Tidd Plant its 

1991 Power Plant Award. Following a planned outage 

for maintenance, repairs, and rework, testing resumed 

during the first week of December 1991. 

Envlronmental Considerations: 

NEPA compliance has been satisfied with a memo-tofile approved March 5, 1987. The environmental moni. 

toring plan has been prepared. 

Assuming maximum commercialization of the 

PFBC technology on a national basis by 2010, relative 

to a no-action alternative, the following impacts are 

projected: 

* SO, reduction-48% 

. NOx reduction-17% 

. Solid waste increase, but in a dry, granular form 

more amenable to alternative uses, such as construction aggregate, and requiring less land area for disposal than conventional scrubber sludge 

(Source: CCf Programmatic Environmental Impact 

Statement) 

Commercial Application: 

Combined-cycle PFBC permits use of a wide range of 

coals, including high-sulfur coals. It can be used to 

repaver oil- and gas-fired boiler units, to repower coalFired power plants, and to build new PFBC units. 

Combined-cycle PFBC technology appears to be best 

suited for electric utility plants greater than 100 MWe. 

Capable of being constructed modularly, PFBC 

generating plants will permit utilities to add increments 

of capacity economically to match load growth and to 

reduce utility financing requirements. Plant life can he 

extended by repowering with PFBC using the existing 

plant area, coal- and waste-handling equipment, and 

steam turbine equipment. 

The performance potential of PFBC technology in 

its commercial configuration is characterized below: 

* SO, reduction-195% 

. NO, reduction-80% 

. Plant efficiency-up to 45% 

* Incremental power increase-40% 

* Fuel flexibility-permits use of wide range of coals 

. Compactness-high process efficiency reduces 

space requirements per unit of energy generated 

Ohio Power Program Update 1991 B-21 
Advanced Coal Conversion 

Process Demonstration 

Sponsor: 

Rosebud SynCoal Partnership (a partnership between 

Western Energy Company and the NRG group, a 

nonregulated subsidiary of Northern States Power 

Compw) 

Additlonal Team Member: 

Stone and Webster Engineering Company-architect/ 

engineer 

Location: 

Colsnip, Rosebud County, MT (adjacentto Western 

Energy Company’s Rosebud Mine) 

Technology: 

Western Energy Company’s advanced coal conversion 

process for upgrading low-rank subbituminous and 

lignite coals 

Plant Capaclty/Productlon: 

45 tons/lx of SynCoal product (300,000 tonslyr) 

ProJect Fundlng: 

Total project cost 

DOE 

Participants 

$69,000,000 100% 

34,500,000 50 

34,500,090 50 

ProJect Objective: 

To demonstrate Western Energy’s advanced coal conversion process to produce a stable coal product having 

a moisture content as low as I%, sulfur content as low 

as 0.3%, and heating value up to 12,000 Btuflb. 

Technology/Project Descrlptlon: 

Being demonsaated is a” advanced thermal coal drying 

process coupled with physical cleaning techniques to 

upgrade high-moisture, low-rank coals to produce a 

high-quality, low-sulfur fuel. The coal is processed 

through two fluid&d-bed reactors that remove loosely 

held water and then chemically bound water, carboxyl 

groups, and volatile sulfur compounds. After drying, 

the coal is put through a deep-bed stratitier cleaning 

process to effect separation of the ash. 

unit train loadout facility at Western Energy Company’s 

The 45-ton/in unit is being located adjacento a 

Rosebud coal mine in Colstrip, MT. Although the demonstration plant is one-tenth the size of a commercial 

facility, the process equipment is at commercial scale 

because a full-sized commercial plant has multiple 

process trains. 

The technology, if successfully demonstrated, 

enhances low-rank western coals, usually with a moisture content of Z-55%, sulfur content of OS-1.5%. and 

heating value of 5,500-9,000 BtuAb, by producing a 

stable, upgraded coal product with a moisture content as 

low as I%, sulfur content as low as 0.3%, and heating 

value up to 12,000 Btu/lb. 

8.22 Program Update 1991 RosebudSynCoalPorlnerrhip 
Calendar Year 

19B8 1989 ,990 ,991 1992 1993 ,994 1996 1996 1997 ,998 

3 4 1 234 1234 1234 1 234 1234 1 234 1234 1234 1 234 12 

12188 9190 6/92 3/96 

t 

t 

Operation initiated 6192 

~$OEs;lecfed projea Environmental monitoring plan compleled 3/92’ 

yv 

Construction completed 2192 

Cooperative agreement 

awarded 9,21/90 Preoperalional tests initiated l/g2 

Design mmpleted 6i91 

NEPA process completed WZ’191 

Ground breakinghonrtwction started 3126191 

t 

t 

Project complefed~inal report issued Wg6’ 

Operation completed 6195’ 

‘Projected date 

Project Status/Accomplishments: Environmental Conslderatlons: restrictive emissions guidelines without requiring 

On December 12, 1990, Western Energy Company, a An environmental assessment and finding of no signifi- derating of the units or the addition of costly flue gas 

subsidiary of MontanaPower, announced that it had cant impact was approved by DOE on March 27, 1991. desulfurization systems. Western Energy’s process, 

joined with the NRG Group, a nonregulated subsidiary Because the advanced coal conversion process will therefore, will be attractive to utilities because the 

of Northern States Power Company based in Minneapo- produce SynCoal which has a very low sulfur content. upgraded fuel will be less costly to use than would the 

lis, MN, to demonstrate and commercialize the technol- high heating value, and stable physical/chemical charac- construction and use of flue gas desulfurization 

WY. 

Ground was broken on March 28.1991, and by 

June, pieces of major equipment were arriving on site. 

The construction of two 6,000~ton product storage silos 

and all foundation work was completed by July. The 

main process facility structure and the controlladminisuation building were completed by November. Initial 

“turn-over” of equipment started in December and final 

construction will be completed in January 1992. Plant 

shakedown activities are under way with full operations 

scheduled for the second quarter of 1992. 

teristics, it could have significant impact on SO, reduction relative to the no-action alternative considered in 

the PEIS. 

equipment. This will allow plants that would otherwise 

be closed to re@n in operation. 

Commercial Application: 

Western Energy’s advanced coal conversion process 

has the potential to enhance the use of low-rank western 

subbituminous and lignite coals. Many of the power 

plants located throughouthe upper midwest have 

cyclone boilers, which bum low-ash-fusion-temperature 

coals. Presently, most of these plants bum Illinois 

Basin high-sulfur coal. Processed coal would be an 

ideal low-sulfur coal substitute for these and other 

plants, because itwill allow operation under more 

Rosebud SynCoal Pannership h&‘W, Update 1991 8.23 
CCT-II 

Project Fact Sheets 
Combustion Engineering 

IGCC Repowering Project 

Sponsor: 

ABB Combustion Engineering, Inc. 

Addltlonal Team Members: 

City Water, Light and Power-cofunder and host utility 

State of Illinois, Department of Energy and Natural 

Resources-funding 

Location: 

Springfield, Stmgamon County, IL (City Water, Light 

and Power’s Lakeside Station) 

Technology: 

ABB Combustion Engineering’s integrated gasification 

combined-cycle (IGCC) system 

plant Capaclty/Productlon: 

65 MWe 

Project Funding: 

Total project cost $270,700,000 100% 

DOE 129,357,2c4 48 

Participants 141.342.796 52 

Project Objective: 

To demonstrate an advanced dry-feed, air-blown, 

two-stage, entrained-flow coal gasifier with limestone 

injection and the moving-bed, zinc ferrite, hot-gas 

cleanup system; to evaluate a kinetic coal exhuder: and 

to assess long-term reliability, availability, and maintainability at sufficient scale to determine commercial 

potential. 

GAS TURBINE,~, HOT 0~s 

- 

siamu& w 

STACK ‘I’ 

SLAG TO%&AL 

STEAM 

STEAM TURBINE 

Technology/Project Descrlptlon: 

Pressurized pulverized coal is pneumatically transported 

to the gssitier. The gasifier essentially consists of a 

bottom combustor section and a top reductor section. 

Coal is fed into both sections. A slag tap at the bottom 

of the combastor allows molten slag to flow into a water-filled quench tank. 

The raw, low-Bm gas and char leave the gasifier at 

approximately 2,000 “F and are reduced in temperature 

to about 1,000 OF by various heat exchange surfaces and 

by water spray prior to gas cleanup. Char in the gas 

stream is captured by a high-efficiency cyclone, as well 

as by subsequent fine particulate removal systems, and 

recycled back to tbe gasifier. 

A newly developed process is being used to remove sulfur from the hot gas: a moving bed of zinc 

ferrite sorbent and a limestone sorbent injection system 

provide in-bed desulfurization. Particulate emissions 

are removed from the coal-handling system and gas 

stream by a combination of cyclone separators and 

baghouses, and a high percentage of particulates are fed 

back to the gasitier for more complete reaction and 

ultimate removal with the slag. 

The cleaned low-Btu gas is routed to a combinedcycle system for electric power production. Approximately 40 MWe are generated by a gas turbine. Extracted air from the gas turbine is used to meet the highpressure air requirements of the gas&r and the zinc 

ferrite desulfurization system. Exhaust gases from the 

gas turbine are used to produce steam which is fed to a 

bottoming cycle to generate an additional 25 MWe. 

8-26 Program Update 199I ABB Combrcrtion Engineering/lGCC 
cahmdar Year 

‘ls88 Ia89 1990’ ,99, ,992 Is3 1934 ,995 1996 1597 1998 

3 4 1 2 3 4 1234 t 2 3 4 12341 2 3 4 1 2 3 4 1234 1 234 1 234 12 

OE wlecied project 9,28/88 Environmental monitoring plan completed l/93 

onrtruction starkad 12~92 

NEPA process completed 2/92 

cwperative apeme”t awarded 1 lRa9O 

sign completed 4196’ 

ontrudion completed 496 

Operation ihtiated 4196’ 

‘Projected date 

The demonstration project is converting 600 tons/ 

day of coal into 65 MWe. This is being accomplished 

through the installation of an entrained-flow coal gasifier and the integration of a 25MWe steam turbine 

with a 40-MWe gas turbine at City Water, Light and 

Power’s Lakeside Station located in Springfield, lL. 

Project Status/Accomplishments: 

The preliminiuy design package and plant cost estimates 

are complete. ABB Combustion Engineering held 

technical exchange discussions with the Japanese regarding the 200-ton/day entrained-flow gasification 

pilot plant in Japan. At the meetings, ABB Combustion 

Engineering obtained operational data for this plant for 

use in the CCT project. 

Envlronmental Considerations: 

The DOE review of the environmental assessment resulted in a finding of no significant impact. The NEPA 

process will be completed in early 1992. 

Assuming maximum commercialization of the recovery boiler are added to replace the existing coal 

IGCC technology on a national basis by the year 2010, boiler. The remaining equipment is left in place, 

relative to ano-action alternative, the following impacts including the steam turbine and electrical generator. 

are projected: The performance potential of IGCC technology in 

. SO, reduction-37% 

* NOx reduction-17% 

* Solid waste reduction--5% 

. CO, reduction-6% 

(Source: CCT Programmatic Environmental Impact 

Statement) 

Commercial Application: 

In went years, IGCC has become a rapidly emerging 

alternative for new electricity generating plants. IGCC 

plants require 15% less land area than pulvetized coal 

plants with flue gas desulfurization. IGCC technology 

also can be used in repoweting, where a gasifier, gas 

stream cleanup unit, gas turbine, and waste heat 

its commercial configuration is chuacterized as follows: 

- SO, reduction-99% 

. NOx RduCtiQn-95% 

* Plant efficiency--up to 48% 

* Incremental power increase-230% 

* Fuel flexibility-permits use of wide range of coals 

. Compactness-high process efficiency reduces 

space requirements per unit of energy generated 

* Modular construction-lends itself to economic 

addition of capacity increments to match load growth 

MB CombUrrion Engineeringl~~c Program Update 1991 8-27 
SNOX Flue Gas Cleaning 

Demonstration Project 

Sponsor: 

ABB Combustion Engineering, Inc. 

Addltlonal Team Members: 

Ohio Coal Development Office-cofunder 

Ohio Edison Company-cofunder and host utility 

Haldor Topsoe-patent owner for process technology, 

catalysts, and WSA Tower 

Snamprogetti, U.S.A.-cofunder and process designer 

Locatlon: 

Niles, Trumbull County, OH (Ohio Edison’s Niles 

Station, Unit No. 2) 

Technology: 

Haldor Tops&s SNOX catalytic advanced flue gas 

cleanup system 

Plant Capaclty/Productlon: 

35-MWe equivalent slip-stream from a t08-MWe boiler 

Prolect Fundlng: 

Total project cost %31,438,408 100% 

DOE 15,719,200 50 

Participants 15,719,208 50 

Project Objective: 

To demonstrate on U.S. coals at an electric power plant 

that SNOX technology will catalytically remove 95% of 

SO, and more than 90% of NO, from flue gas and produce a salable by-product of cancermated solfuric acid. 

Technology/ProJect Descrlptlon: by-product. This is accomplished without “sing sorI” the SNOX process, the stack gas leaving the boiler is bents a”d without creating waste by-products. 

cleaned of fly ash in a high-efficiency fabric filter The demonstration unit is being installed at Ohio 

baghouse to minimize the cleaning frequency of the Edison’s Niles Station in Niles, OH. The process will 

sulfuric acid catalyst in the downstream SO, converter. treat a 35sMWe equivalent slipstream of flue gas from 

The ash-free gas is reheated, andNOx is re&ted with the 108-MWe Unit No. 2 boiler that burns a 3.4% sulfur 

small quantities of ammonia in the first of two catalytic coal. The process steps ale vbtually the same as for 

reactors where the NOx is converted to harmless nitro- a full-scale plant, and commercial-scale components afe 

gen and water vapor. The SO, is oxidized to SO, in a being used. 

second catalytic converter. The gas the” passes through 

in a novel glass-tube condenser which allows SO, to 

hydrolyze to concentrated sulforic acid. 

The technology, while using U.S. coals, is expected 

to remove 95% of the SO, and more than 90% of the 

NOx from flue gas and produce a salable sulfuric acid 

8.28 PXQ=RZ,,, Update 1991 ABB Combustion EngineeringlSNOX 
Calendar Year 

1988 1909 1990 1991 1992 1993 1994 1995 1996 1997 1998 

3 4 1234 1 234 1 2 3 4 1234 1234 1 234 1 2 3 4 ,234 ,234 12 

s/99 12/99 2l92 12193 

izgzEii9 1, 

Cooperative *gr*eme”t 

awarded W20189 

Project completediflnal repoti issued 12193’ 

1 1 [o~~~~~~~~~~B, Lk~coil~sd Q/93’ 

Preopemtion.4 teats initiated ,219, 

Dedication oeremony hela 10,17A, 

Environments monkwing plan completed lOl31~991 

Design cmlpl*ted 8191 

Construction started i/91 

NEPA process completed v31/90 

‘Projected date 

L 

Project Status/Accomplishments: 

Design is complete: all major equipment has been procured and proprietary condenser installed. A formal 

dedication ceremony was held October 17, 1991. Construction was completed in December 1991 and operation commences in February 1992. 

Environmental Considerations: 

NEPA compliance has been satisfied by a memo-to-file 

approved on January 31.1990. An environmental 

monitoring plan was completed October 31, 1991. 

SO, and more than 90% Ng emissions from coal-fired 

boilers with the SNOX process and the wide applicability of the process. Moreover, the sulfmic acid produced 

is a salable by-product. No change in solid waste is 

anticipated; although the plant produces ash, the SNOX 

technology itself produces no solid waste by-product. 

(Source: CC? Programmatic Environmental Impact 

Statement) 

Assuming maximum commercialiiation on a national basis by 2010 for the SNOX process relative to a 

no-action alternative, the following impacts are projected: 

. SO, reduction-38% 

* NOx reduction-15% 

The significant reductions of SO, and NO, are projected 

to be achievable nationally due to the 95% removal of 

Commercial Application: 

The SNOX technology is applicable to all electric 

power plants and indusuial/institmional boilers firing 

coal, oil, or gas. The high removal efficiency for NOx 

and SO, will make the process amactive in many applications. Elimination of additional solid waste (except 

ash) enhances the marketability in urban and other areas 

where solid waste disposal issues are a significant 

impediment. 

ABB Combusrion EngineeringlSNOX Pro~rom Update 1991 8.29 
Demonstration of Coal 

Reburning for Cyclone Boiler 

NO, Control 

Sponsor: 

The Babcock & Wilcox Company 

Additional Team Members: 

Wisconsin Power and Light Company-cofunder and 

host utility 

Sargent and Lundy-engineer for coal handling 

Electric Power Research Institute-cofunder 

State of Illinois, Department of Energy and Natural 

Resources-cofunder 

Utility companies (10 cyclone boiler operators)- 

cofunders 

Locatlon: 

Cassville, Grant County, WI (Nelson Dewey Station, 

Unit No. 2) 

Technology: 

The Babcock &Wilcox Company’s coal reburning 

system 

Plant Capacity/Production: 

100 MWe 

boiler efficiency, boiler fireside performance (corrosion 

and deposition), or ash removal system performance. 

Project Fundlng: 

Total project cost 

DOB 

Participants 

$13,071,559 100% 

6,213,929 48 

6857,630 52 

Project Objective: 

To evaluate the applicability of rebuming technology 

for reducing NOx emissions from a full-scale coal-fired 

cyclone boiler, pulverizing a portion of the primary coal 

fuel to use as the secondary, “rebuming” fuel; and to 

achieve greater than 50% reduction in NOx emissions 

with no serious impact on cyclone combustor operation, 

Technology/Project Description: 

The coal reburning process reduces NO, in the main furnace through the use of multiple combustion zones. The 

main combustion zone uses 70-80% of the total heat 

equivalent fuel input to the boiler and slightly less than 

norntal combustion air input. The balance of the coal 

(20-30%), along with significantly less than the theoretically determined requirement of air, is fed to the 

boiler above the cyclones in the reburning zone to create 

a” oxygen-deficient condition. The NO, formed in the 

cyclone burners reacts with the resultant reducing flue 

gas to be converted into nitrogen and water in this zone. 

The completion of the combustion process occurs in the 

third zone, called the burnout zone, where the balance of 

the combustion air is introduced. The combined production of boiler slag and dry waste from the electrostatic 

precipitator remains unchanged with coal reburning because the required coal input for the same boiler load is 

constant. 

The coal rebuming technology can be applied with 

the cyclone burners operating within their normal, noncorrosive, oxidizing conditions, thereby minimizing the 

effects of rebum on the cyclone combustor and boiler 

perfor”Is”ce. 

This project involves retrofitting a” existing 

lOO-MWe cyclone boiler that is representative of a large 

population of cyclone units. The cyclone boiler being 

retrofitted is presently in commercial operation at 

s-30 Program Update 1991 B& WIReburning 
L 

Calendar Year 

1988 ,989 ,990 ,991 1992 1993 1994 ,995 ,996 ,997 ,998 

3 4 1 2 3 4 1234 1 23412341 234 t 234 1 234 1 234 1 234 12 

T A 

DOE selected 

project 

W28188 

I 

DSig” 

Started 

,189 

4190 12/91 

/ Deslan and Construction omrauon 3’s3 

I 

It Project completed/final report iwed 3/W 

Operation initiated 12191 

constructiin mmpleted ,,n, 

Preoperational tests initiated 11191 

Environmental monitoring plan completed 1111g191 

Design completed 6191 

ound breaking/construction started 3191 

:PA process completeed 21,219, 

ci ,operat,ve agreement awarded 4/2190 ‘Projected date 

Wisconsin Power and Light’s Nelson Dewey Station in 

Cassville, WI. 

Project Status/Accomplishments: 

Design work is complete. Short- and long-term boiler 

baseline chamcterization testing and performance modeling both with and without the proposed rebum retrofit 

is complete. Boiler performance results have been analyzed and incorporated into both physical and numerical 

models of the boiler. The modeling has demonsuated 

the need for a change from 3 to 4 rebumers and overfue air pans to assure adequate NOx reduction. 

Installation of the coal rebum system equipment 

was completed during a scheduled boiler outage in September and October 1991. Check out +nd shakedown of 

the newly installed r&urn system, including reborn 

burners, over-fire air ports, pulverizer, ducting, coal 

feed system, and control systems, began in November 

1991. Initial Nor reduction measurements will be made 

in January 1992. Testing will continue through 1992. 

Environmental Considerations: 

An environmental assxsment was completed and a 

finding of no significant impact was approved on February 12, 1991. The environmental monitoring plan was 

completed November 18, 1991. 

All of the approximately 26,000 MWe of currently installed cyclone boilers are expected to require NO, control to comply with the CAAA of 1990. 

Significant reductions of NO, (11%) are projected 

to be achievable nationally by 2010 due to the capability 

of the cyclone coal-rebuming process to remove 50% of 

NOx emissions from coal-fired boilers and the wide potential applicability of the process. Negligible changes 

in effluents are anticipated. The technology produces 

no change in solid waste production. (Source: CCX 

Programmatic Environmental Impact Statement) 

Ccmmerclal Application: 

Currently, no proven retrofit combustion technology exists for reducing NOx emissions from cyclone boilers. 

Coal rebuming for cyclone boilers is expected to be a 

viable option as a retrofit combustion technology for 

NO, control at reasonable capital and operating costs. 

B&WIReburning Program Update 1991 8.31 
SOX-NOX-ROX Box Flue Gas 

Cleanup Demonstration 

Project 

Sponsor: 

The Babcock &Wilcox Company 

Additlonal Team Members: 

Ohio Edison Company-cofunder and host utility 

Ohio Coal Development Office-cofunder 

Electric Power Research Institute-cofunder 

Norton Company-cofunder and SCR catalyst supplier 

Minneapolis Mining and Manufacturing Companycofunder and filter bag supplier 

Location: 

Dilles Bottom, Belmont County, OH (R. E. Burger 

Plant, Unit No. 5) 

Technology: 

The Babcock & Wilcox Company’s SOX-NOX-ROX 

box (SNRB) process 

Plant Capaclty/Productlon: 

5-MWe equivalent slipstream from a 156-MWe boiler 

ProJect Funding: 

Total project cost 

DOE 

Participants 

$11,419,087 100% 

5,229,942 46 

6,189,145 54 

Project Objective: 

To demonsnate that the SOX-NOX-ROX box process, 

used in retrofitting a high-sulfur-coal-fned power plant, 

can remove high levels of all pollutants using a single 

processing unit for treating flue gas, thereby lessening 

on-site space requirements and capital costs. 

CERAMIC FILTER BAG 

COAL--) 

AIR + 

Technology/Project Descrlptlon: 

The SNRB process combines the removal of SO,, NOx, 

and particulates in one unit-a high-temperature 

baghouse. SO, removal is accomplished using either 

calcium- or sodium-based sorbent injected into the flue 

gas. NOx removal is accomplished by injecting arnmonia to selectively reduce NOx in the presence of a selective catalytic reduction, or SCR, catalyst. Particulate 

removal is accomplished by high-temperature ceramic 

tiber bag filters. 

economic feasibility of achieving 70-90% SO, removal, 

The project will demonstrate the technical and 

up to 90% NO, removal, and 99% particulate removal 

at lower capital, operating, and maintenance costs than 

other conventiqnal systems. The demonstration will be 

conducted at Ohio Edison’s R. B. Burger Plans Unit 

No. 5, in Dilles Bottom, OH. 

The SNRB demonstration unit is sized at 5 MWe 

and is large enough to demonstrate acommercial-scale 

baghouse module while minimizing the demonstration 

cost. Additionally, at this scale, the flue gas temperature can readily be conuolled to determine the optimum 

temperature for maximum SO, and NOx reductions. 

S-32 Program Updare 1991 B&WISOX-NOX-ROX Box 
Calendar Year 

1988 ,989 ,990 19% 1992 1993 ,994 1995 ,996 ,997 1998 

3 4 1 2 3 4 1 2341234 1 2341234 1 23412341 2341234 12 

NEPA process 

completed 9122199 

Design completed 8191 

Ground breakingiconstruction started 519191 

‘Projected date 

Project Status/Accomplishments: 

Design work is complete. Testing of commercial-sized 

bags in the pilot baghouse “nit is complete, with NOx 

capture rates above 90% and SO, capture rates approaching 80%. 

Construction work was completed in December 

1991. Fiber fabric development test facility co”st~“ction is complete. Three different vendors’ bags are 

being tested over the next 13 months. 

Envlrorfmental Considerations: 

NBPA compliance has been satisfied by a memo-to-file 

approved on September 22, 1989. The environmental 

monitoring plan was completed December 31. 1991. 

Assuming maximum commercialization, the 

following impacts are projected on a national basis by 

2010 for the SNRB process relative to a “o-action 

alternative: 

* so, reduction-38% 

. NO, reduction-15% coal-fired boilers that are without scrubbing systems in 

. Solid waste increase-E% order to achieve a high level of emissions control at 

favorable caoital and ooeratine costs. . _ 

The significant reductions of SO, and NO, are projected 

to be achievable nationally due to the 70-90% removal 

of SO, and NO, emissions from coal-fired boilers with 

the SNRB process and the wide applicability of the 

process. Negligible changes in liquid effluents are 

anticipated. (Source: CCI Programmatic Environmental Impact Statement) 

Commercial Application: 

The SNFtB process, upon being commercially demonstrated, offers removal of up to 90% of the SO, and NOr 

and at least 99% of the particulates in a single “nit with 

lower capital and operating costs and smaller space 

requirements than conventional flue gas cleanup technology. I” addition, SNRB offers the potential for increasing boiler efficiency. The SNFtB process can be 

used to retrofit a wide range of utility and industrial 

B&WISOX-NOX-ROXBox ProgramUpdale1991 8.33 
Innovative Coke Oven Gas 

Cleaning System for Retrofit 

Applications 

Sponsor: 

Bethlehem Steel Corporation 

Additional Team Member: 

Davy/Still-Otto-technology developer 

Location: 

Sparrows Point, Baltimore County, MD (Bethlehem 

Steel Corporation’s Sparrows Point Plant, Coke Oven 

Batteries A, 11, and 12) 

Technology: 

Davy/Still-Otto’s process for precombustion cleaning of 

coke oven gas (COG) 

Plant Capacity/Production: 

74 million std ft”/day of COG 

ProJect Fundlng: 

Total project cost 

DOE 

Participant 

$45,239,781 100% 

13,500,000 30 

31,739,7x1 70 

Project Objective: 

To demonstrate afirst-of-a-kind novel integration of 

commercially available process steps for simultaneous 

removal of hydrogen sultide and ammonia from COG, 

recovery of hydrogen sulfide and ammonia, destruction 

of ammonia, and recovery of sulfur in a commercialsized application: and to reduce SO, emissions by at 

least 80% accompanied by substantially reduced emissions of volatile organic compounds and discharge of 

ammonia to wastewater treatment. 

Technology/Project Descrlptlon: 

This project is demonstrating an innovative technology 

developed by Davy/Still-Otto for removing hydrogen 

sulfide and ammonia from COG. The process uses contaminated water produced in the coke oven batteries to 

absorb the hydrogen sulfide and ammonia contained in 

the COG. Both hydrogen sulfide and ammonia are 

steam stripped from the absorption liquor. The ammonia is destroyed in a catalytic reactor; the hydrogen sulfide is converted to elemental sulfur in a conventional 

Claus plant, and the sulfur is recovered as a salable byproduct. 

agents, the handling and “eatment of by-products, labor, 

associated with the purchase and handling of feed reand utilities are reduced. 

This project involves the modification of the COG 

processing units at Bethlehem Steel’s Sparrows Point 

Plant in Baltimore County, MD. The demonstration facility will process the entire COG stream from 

Coke Oven Batteries A, 11, and 12, which amounts to 

74 million std ft’iday. Currently, only 60% of this COG 

stream is desulfurized. The remaining 40% is used directly for under-firing the coke ovens. 

Project Status/Accomplishments: 

On September 16, 1991, Bethlehem Steel Corporation 

announced that all coke production will be suspended at 

its Sparrows Point facility for at least 2 yrs. This 

The technology is expected to reduce the hydrogen 

sulfide concentration in the cleaned COG by 84% and 

the ammonia concentration by approximately 99%. Because the reagents used are indigenous in COG, costs 

8-34 Program Update 1991 Bethlehem Steel/Coke Oven Gas 
.lPA process com;letsd 12@218g 

c oopera1ive agreement awarded 11,14/89 

1 1;: Tt L +-- Project completedifinal report issued 5195’ 

Operation completed 335 

Operation inkiated 1194’ 

Preoperational tests initiated 10193 

Facility mothballing completed l/92’ 

Construction completed 12191 

Environmental monitoring plan completed 71591 

Design completed 11190 

Ground breakinalconstruction sfaned Z/90 

‘Projected date: milestones lo be updated following resumption 

of operation; assumes 2-y slippage for coke oven rebuilding 

decision was made due to the rapid deteriotiation of the 

coke ovens. During this period, an evaluation will be 

made to explore alternatives for resumption of coke 

production. Bethlehem Steel’s intent is for long-term 

coke independence at the facility. 

Construction of the coke oven gas cleaning demonstration facility is complete, and the unit has been 

“moth-balled” to maintain it in good shape so that hot 

commissioning, start-up, and operation can be accomplished successfully when coke-making operations are 

resumed. 

Environmental Considerations: 

The environmental assessment with a finding of no significant impact was approved by DOE on December 22, 

1989. Background environmental sampling has begun. 

The environmental monitoring plan has been prepared. 

The expected performance characteristics and 

applicable market of the proposed COG cleaning system 

were used to estimate the environmental impacts that 

Bethlehem Steel/Coke Oven Gas 

may occur if this technology reaches full commercialization. The existing 30 coke oven plants in the United 

States emit about 300,000 tonslyr of SO,. This COG 

cleaning process could be applicable to 24 plants with 

corresponding SO,emission levels of 200,000 tons/yr. 

If the technology were installed in all 24 plants, the SO, 

emissions could be reduced by 160.000 tons/yr. Eliminated would be the ammonium sulfate which is difficult 

to market and usually is disposed of as a solid waste. 

Every 5-8 yrs, 5 tons of spent nickel catalyst would 

need to be returned to the vendor or disposed of as a 

hazardous waste, and 10 tons of spent alumina catalyst 

would need to be disposed of as a nonhazardous solid 

waste. Depending on the configuration of the coke oven 

facility where the technology is being implemented, the 

amount of water needed for cooling purposes would 

remain the same or be reduced, and the amount of pollutants in the wastewate~ would remain the same or be 

reduced. 

Commerclal Application: 

The design for this innovative COG cleaning system is 

based on operating data that have been collected from 

individual process steps 01 combinations of individual 

process steps that have been successfully operated at 

commercial-sized COG treatment facilities. The novel 

integration of commercially available process steps is 

expected to reduce the overall cost of desulfurization, 

ensure reliable operation in applications exceeding 

20 y’s, and provide a viable alternative to conventional 

technologies. Because the demonstration is designed to 

treat 74 million std fP/day of COG (a commercial size), 

the project will demonstrate that it is possible to retrofit 

any existing coke-making facility in the United States 

with essentially no scale-up involved and without significant downtime. 

Program Update 1991 S-35 
PFBC Utility Demonstration 

Project 

Sponsors: 

The Ohio Power Company-cosponsor 

The Appalachian Power Company- cosponsor 

Addltlonal Team Members: 

American Electric Power Service Corporationdesign, construction, and management 

ABB Carbon and Babcock & Wilcox-technology 

supplier 

Location: 

New Haven, Mason County, WV (Ohio ~ower’s and 

Appalachian Power’s Philip Sporn Plant, Units 3 and 4) 

(An alternate WV greenfield site is being considered.) 

Technology: 

ABB Carbon and Babcock & Wilcox’s pressurized 

fluidized-bed combustion (PFBC) system 

Plant CapacltylProductlon: 

330 MWe 

Project Funding: 

Total project cost $917,944,000 100% 

DOE 184,800,000 20 

Participants 733,144,ooo 80 

Project Objective: 

To demonstrate PFBC at 330 MWe, a large utility scale 

representing a four-fold scale-up of the technology, the 

world’s largest PFBC, and the first commercial application of PFBC in the United States; to assess long-term 

reliability, availability, and maintainability of PFBC in a 

commercial operating mode and the integration of a reheat steam cycle; and to achieve 95% SO, reduction, at 

least 70% NOI reduction, and an efficiency of 39% in a 

repowering mode using the existing steam system. 

8-36 Program Update 1991 

Technology/Project Description: 

This PFBC technology uses a bubbling fluidized-bed 

boiler enclosed in a pressure vessel operated at 16 atm 

to produce combustion gases with sufficient energy to 

drive a gas turbine. The gas turbine exhaust is used to 

preheat boiler water, and the fluidized-bedboiler develops steam for the steam turbine. Because pressure in 

the boiler enhances combustion and heat transfer, the 

size of the vessel needed is reduced. Pressure also enhances sulfur capture by the sorbent. Sorbent (limestone or dolomite) is injected into the boiler and reacts 

with SO, to form unreactive calcium sulfate, a dry, 

granular material. 

As originally proposed, the project entails replacement of two 150-MWe units, Units 3 and 4 at the Philip 

Sporn Plant, with a single 330.MWe unit. Nearly 

one-fourth of the power from the plant is to be produced 

through a new gas turbine with the balance generated 

through the existing steam turbines. However, based on 

the results of engineering and cost studies, AEP is also 

evaluating a greenfield plant as an alternative. 

Project Status/Accomplishments: 

Preliminary engineering analysis and cost estimates 

were completed to compare a new PFBC plant with 

both a repowered PFBC unit and a conventional power 

plant with scrubbers. On the basis of these studies, AEP 

has decided that a greenfield PFBC plant is the most 

favorable option for its grid system. Additionally, 

current load growth projections indicate that there is no 

need for power until after 2000. Revision of the 

Ohio Power and Appalachinn PowerlPFBC 
Calendar Yeal 

1988 ,989 ,990 ,991 1992 1993 ,994 ,995 1996 ,997 1998 

3 4 1 234 1 234 1 2341234 1234 1 23412341234 123412 

9/m 4190 

I Premvard I 

..~..,.....,..~.... :,:.~:::‘i::i::::~:~:~:l:~::lii::.:.: 

..~..../.~......../..........~..,:.:,:,: 

:.:.:.:.:.:.:,:.“::::‘::::i::::‘:”:,::c:::::~:~:~::.:1::~~:~::~~:~ 

.., ../..../. ./.,./, ~,.,.........,............ ,... ,.,~,.,..~..,...,.,./,~,.. ,.~..,./../...., .,.I .,.I ..~.....~..../....~. I.., 

WE selected pro)& 9128188 

Codperative agreement 

awarded 4,490 

Prclject rescoped ?Jg2’ 

‘Projected date; mileemes 10 be revised following decision on 

project resmping and schedule extension 

L 

originally planned schedule is currently under DOE 

review. AEP proposes to conduct a 4-y effort that 

would include a 2-yr value engineering effort to 

optimize the design and a 2-yr engineering study to 

develop a reduced cost basis for a greenfleld plant. 

DOE is evaluating the impact of the proposed slippage 

and the merits of continuing the project. 

Environmental Considerations: 

Environmental information is being prepared for the 

NEPA compliance process. 

Assuming maximum commercialization of the 

PFBC technology on a national basis by 2010 relative to 

a no-action alternative, the following impacts are projected: 

* SO, reduction-48% 

* NO1 reduction-17% 

* Solid waste increase, but in dry. granular form, 

which has more amenable alternative uses. such as 

construction aggregate, and requires less land area 

for disposal than conventional scrubber sludge 

(Source: CCf Programmatic Environmental Impact 

Statement) 

Commercial Application: 

Combined-cycle PFBC allows for the combustion of a 

wide range of coals, including high-sulfur coals. It can 

be used to repower oil- and gas-fired boiler units while 

switching them to high-sulfur coal, to repower coal-fired 

power plants, and to build new PFBC units. Combinedcycle PFBC technology appears to be best suited for 

electric utility applications for medium (100-400 MWe) 

and large (> 400 MWe) plants. In fact, because of 

modular construction capability, PFBC generating 

plants will enable utilities to add increments of capacity 

economically to match load growth and to reduce utility 

financing requirements. Plant life can be extended by 

repowering with PFBC using the existing plant area, 

coal and waste handling equipment, and steam turbine 

equipment. 

The performance potential of PFBC technology in 

its commercial configuration is characterized as follows: 

. SO, reduction-95% 

. NOx reduction-SO% 

. Plant efficiency-up to 45% 

* IncrementaJ power increase-40% 

. Fuel flexibility-permits use of wide range of coals 

* Compactness-high process efficiency reduces 

space requirements per unit of energy generated 

* Modular construction-lends itself to economic additions of capacity increments to match load growth 

Ohio Power and Appalachim PowerlPFBC Program Update I991 8-37 
Cement Kiln Flue Gas 

Recovery Scrubber 

Sponsor: 

Passamaquoddy Tribe 

Additlonal Team Members: 

Dragon Products Company-project manager and host 

E. C. Jordan Company-engineer for overall scrubber 

system 

HPD, Incorporated-designer and fabricator of tanks 

and heat exchanger 

Cianbro Corporation-constructor 

Locatlon: 

Thomaston, Knox County, ME (Dragon Products’ 

coal-fired cement kiln) 

Technology: 

Passamaquaddy Tribe’s cement kiln flue gas recovery 

scrubber 

Plant Capaclty/Productlon: 

1,450 tons/day of cement; 250,000 std ft’/min of kiln 

gas: and up to 274 tons/day of coal 

Project Funding: 

Total project cost $12,53X,648 100% 

DOE 5,903,195 41 

Participants 6,635,453 53 

Pro@zt Objective: 

To retrofit and demonstrate afull-scale industrial scrubber and waste recovery system for a coal-burning wet 

process cement kiln using waste dust as the reagento 

accomplish 90-95% SO, reduction using high-sulfur 

eastern coals and to produce a commercial by-product, 

potassium-based fertilizer. 

Technology/Project Descrlptlon: while it was seeking ways to solve landfill problems, 

The recovery scrubber technology uses a water solution/ which resulted from the need to dispose of waste kiln 

slurry containing potassium-rich dust recovered from the dust from the cement-making process. 

kiln flue gas, which serves as the scrubbing medium. No 

other chemicals are required for the process. After 

scrubbing the gas, the slurry is separated into liquid and 

solid fractions. The solid fraction is returned to the 

cement plant as renovated and usable raw feed material. 

The liquid fraction is passed to a crystallizer that uses 

waste heat in the exhaust gas to evaporate the water and 

recover dissolved alkali metal salts. 

The Passamaquoddy Tribe’s recovery scrubber is 

being constructed at the Dragon Products Company’s 

cement plant in Thomaston, ME, a plant that processes 

approximately 470.000 tons& of cement. The process 

was developed by the Passamaquoddy Indian Tribe 

838 Program Update 1991 
Calendar Year 1988 1989 3 4 1 2 3 

I DOE selected WW88 pro@3 
Advanced Flue Gas 

Desulfurization 

Demonstration Project 

Sponsor: 

Pure Air on the Lake, L.P. (a project company of Pure 

Air, which is a partnership between Air Products and 

Chemicals, Inc., and Mitsubishi Heavy Indusbies 

America, Inc.) 

Addltonal Team Members: 

Northern Indiana Public Service Company-cofunder 

and host utility 

Mitsubishi Heavy Indusuies, Ltd. (parent company)- 

process designer 

United Engineers and Constroctors (Stearns-Roger 

Division)-facility designer 

Air Products and Chemicals, Inc.-constronor and 

operator 

Location: 

Chesterton, Porter County, IN (Northern Indiana Public 

Sewice Company’s Bailly Generating Station) 

Technology: 

Pure Air’s advanced flue gas desulforization (AFGD) 

process 

Plant Capacity/Production: 

528 MWe 

Project Funding: 

Total project cost $150,497,000 100% 

DOE 63,434,OOO 42 

Participants 87,063,OOO 58 

Project Objective: 

To demonstrate removal of YO-95% or more of the SO, 

at approximately one-half the cost of current conventional scrubbing technology: and to demonstrate significant reduction of space requirements. 

s-40 Program Updare 

Technology/Project Description: 

In this project, Pure Air is building a single SO, absorber for a 528~MWe power plant. Although this is 

expected to be the largest capacity absorber module in 

the United States, it has relatively modest space requirements because no spare or backup absorber modules are 

being installed. The absorber performs three functions 

in a single vessel: prequencher, absorber, and oxidation 

of sludge to gypsum. Additionally, the absorber is of a 

cocm’rent design, in which the flue gas and scrubbing 

slurry move in the same direction and at a relatively 

high velocity compared to conventional scrubbers. 

These features all combine to yield a state-of-the-art 

SO, absorber that is more compact and less expensive 

than conventional scrubbers. 

Technical features include the injection of pulverized limestone directly into the absorber, a device called 

an air rotary sparger located within the base of the absorber, and a novel wastewater evaporation system. 

The air rotary sparger combines the functions of stirring 

and air distribution into one piece of equipment to facilitate the oxidation of sludge to gypsum. 

The AFGD process being demonstrated is expected 

simultaneously to remove YO-95% or more of the SOz, 

provide a commercial gypsum by-product, and evaporate wastewat&. 

The project also seeks to demonstrate a novel 

business concept whereby Pure Air owns and operates 

the AFGD facility. Thus, Pore Aii expects to specialize 

in pollution conhol activities, relieving the electric 

Pure Air 
I 

Calendar Year 

,988 1989 I%?0 ,991 ,992 1993 1994 ,995 ,995 1997 1998 

3 4 1 2 3 4 1 23412341 2 3 4 1 2 3 4 1234 1 2 3 4 1 2 3 4 1234 12 

I 

-1 II 

? 

Design completed 10,82’ 

: 

i 

Project completedifinal report issued 9195 

Construction completed 10192’ 

Operation completed 71% 

DOE selened project Operation inRiated 719P 

9n&w 

Preoperational tests iniliated 4192’ 

Environmental monitoring plan completed 1/31191 

NEPA process completed 4116190 

Ground breaking/construction starled 4/20/90 

cooperative agreement awarded 1320,89 ‘Projected date L -I 

utility of the operation of the AFGD unit. Assuming complete and has been resin-lined. A new 480-ft stack process potentially would increase solid waste by 9%. 

that the 3-yr demonstration is successful, Pure Air will 

continue to own the AFGD facility and to operate it as a 

contracted service to the utility for an additional ll-yr 

period. The demonstration is located at Northern Indiana Power Service Company’s 528-MWe Bailly Generating Station near Chesterton, IN. 

Project StatWAccompllshments: 

Design is essentially complete, although wrap-up work 

will con&ue through the early stages of operation. To 

confhm process design, pilot testing was performed in 

1990, successfully meeting both SO, removal and gypsum purity levels using U.S. high-sulfur coal and limestone f&stocks. A long-term performance test was 

conducted to verify operational parameters for the ah 

rotary sparger; it, too, was successful. 

Construction is 85% complete despite the 

occurrence of a ground subsidence event at the Bailly 

station on July 2, 1991. The SO, absorber is shucturally 

has been built and brick-lined. All major equipment has 

been installed. Work is now focused on instrumentation 

and utilities (e.g., water, electric). Shakedown activities 

are expected to begin shortly, with operations scheduled 

to commence in mid-1992. 

Envlronmental Considerations: 

NBPA compliance has been satisfied by an environmental assessment, with a finding of no significant 

impact approved by DOE on April 16, 1990. The environmental monitoring plan was completed in January 

1991. 

Assuming maximum commercialization of the 

AFGD process, a 48% reduction of SO, could be 

achieved on a national basis by 2010, relative to a noaction alternative. The significant reductions of SO, are 

projected to be achievable nationally due to the 90-95% 

SO, removal capability forecasted for the AFGD process and its wide potential applicability. Although the 

the gypsum by-product could be sold, depending on the 

local market conditions, thereby eliminating the need to 

dispose of it as a waste product. If there is no market 

for the gypsum by-product. it is readily disposable in a 

landfill. (Source: Cff Programmatic Environmental 

Impact Statement) 

Commercial ‘Application: 

The AFGD process is attractive for both new and redofit applications. The demonsuation project is using 

coals primarily from the Indiana-Illinois coal basin, with 

sulfur content ranging from 2.0% to 4.5%. 

Pure Air Program Updafe 1991 8-4X 
Demonstration of Advanced 

Combustion Techniques for a 

Wall-Fired Boiler 

Sponsor: 

Southern Company Services, Inc. 

Addltlonal Team Members: 

Electric Power Research Institute-cofunder 

Foster Wheeler Energy Corporation--technology 

supplier 

Georgia Power Company-host utility 

Locatlon: 

Coosa, Floyd County, GA (Georgia Power’s Plant 

Hammond, Unit No. 4) 

Technology: 

Foster Wheeler’s towNOx burner (LNB) with advanced 

over-fire air (AOFA) 

Plant Capaclty/Productlon: 

500 MWe 

ProJect Funding: 

Total project cost 

DOE 

Participants 

$11,711,229 100% 

5242,911 45 

6,468,312 55 

Project ObJective: 

To achieve 50% NOx reduction with the AOFAILNB 

system; to determine the contributions of AOFA and the 

LNB to NOx reduction and the parameters determining 

optimum AOFAILNB system perfortnance: and to assess the long-term effects of AOFA and LNB on NOx 

reduction and boiler performance. 

Technology/Project Description: 

AOFA involves (1) improving the mixing of over-fire 

air with the furnace gases to achieve complete combustion, (2) depleting the air from the burner zone to minimire NOx formation, and (3) supplying air over furnace 

wall tube surfaces to prevent slagging and furnace corrosion. The AOFA technique is expected to reduce NOx 

emissions by about 35%. 

In a” LNB, fuel and air mixing is controlled to 

preclude the formation of NOx. This is accomplished by 

regulating the initial fuel-ah mixture, velocities, and 

turbulence to create a fuel-rich flame core and by controlling the rate at which additional air required to complete combustion is mixed with the flame solids and 

gases so as to maintain a deficiency of oxygen. Typical 

results for utilities indicate that LNB technology is 

capable of reducing NOx emissions by about 45%. 

Based on earlier experience, the use of AOFA in 

conjunction with LNB can reduce NOx emissions by as 

much a$6O%:compared with conventional burners. 

The demonstration is located at the Georgia Power 

Company’s Hammond Plant, Unit No. 4. The boiler is a 

nominal 500-MWe pulvetized coal, wall-fined unit, 

which is representative of most of the existing preNSPS wall-fired utility boilers in the United States. 

842 Program Update I991 Southern Company ServiceslWoll-Fired Boiler 
Calendar Year 

,988 1989 ,990 ,991 1892 ,993 1994 ,995 ,996 ,997 ,998 

3 4 1 2 3 4 ,234 1 234 1 2 3 4 1234 1234 1 234 1 234 1 234 12 

Design and Construction 

t 

t 

?3’ Project completedhal report isw3d 6/92’ 

operation completed, LNg 12191 

Operation initiated. LNB 4191 

DOE selected 

P,OjWt 

I ‘--i 

T 

Construction completed, LNB 4~91 

9123,83 Construction stalled, LNB 3191 

operation completed, AOFA 3191 

NEPA process Environmental monitoring plan completed g/14/90 

ksrnruqed 

Operation initiated, AOFA 6iW 

Constwdion completed. AOFA 5190 

Construction sttied, ACFA 4190 

Design completed 3190 

cooperatrve agwment aWarded Imom ‘Projected dare 

, 

Project Status/Accomplishments: values as compared to tbe baseline values. Results also Commercial Application: 

Design and construction activities are complete. AOFA 

diagnostic and performance testing is complete, and 

long-term AOFA testing, which began in October 1991, 

is complete. Analysis of more than 80 days of operating 

data has provided statistically reliable results indicating 

that, depending upon load, NOx reduction of 24% is 

achievable under normal long-term operation. 

The 24 new controlled-flow, split-flame LNBs 

were installed and first fired on May 1,199l. Optimization testing for LNB operation without the AOFA system was completed in late-June. The balance of coal 

fineness and LNB diagnostic and performance tests 

were completed in December 1991. Preliminary data 

analysis for both short-parametric and long-term tests 

indicates NO, reductions of 47% under full-load conditions. 

For both AOFA and LNB, preliminary analysis 

indicated significant increases of flyash loss 01 ignition 

show that post-LNB renofit precipitator particulate 

mass loading and gas flow rates are substantially above 

baseline values. 

Combined AOFA/LNB tests will be conducted in 

1992. Completion of the final analysis of project data 

and issuance of the final report are scheduled for 

mid-1992. 

Envlronmental Conslderatlons: 

NBPA compliance has been satisfied with a memo-totile approved May 22,1989. The environmental monitoring plan has been prepared. 

Significant reductions of NO, (11%) are projected 

nationally by 2010 from maximum commercialization 

of the technology due to the 60% removal capability 

forecasted and the wide applicability of the process. 

No changes in liquid effluents or solid wastes are anticipated. (Source: CCT Programmatic Environmental 

Impact Statement) 

The technology is applicable for retrofitting the 422 preNSPS wall-fired boilers existing in the United States. 

Commercialization of the technology will be aided 

by the following characteristics: 

* Reduced short-term NO, emissions by up to 60% 

* Competitivexapital and operating costs 

* Relatively easy retrofit 

. Little or no denting of the boiler 

* Use of commercially available components 

Southern Company Services/Wall-Fired Boiler Program Updatp 1991 S-43 
Demonstration of Innovative 

Applications of Technology 

for the CT-121 FGD Process 

BOILER 

Sponsor: 

Southern Company Services, Inc. 

Additional Team Members: 

Georgia Power Company-host utility 

Elecnic Power Research Institute-cofunder 

Radian Corporation-environmental and analytical 

consultant 

Ershigs, Inc.-tiberglass fabricator 

University of GeorgiaResearch FoundationAiH 

by-product utilization studies 

Locatlon: 

Newttan, Coweta County, GA (Georgia Power 

Company’s Plant Yates, Unit No. 1) 

Technology: 

Chiyoda Corporation’s Chiyoda Thoroughbred- 121 

(CT-121) advanced flue gas desulfurization (FGD) 

process 

Plant Capacity/Production: 

100 MWe 

Project Fundlng: 

Total project cost $35,843,678 100% 

DOE 17546,646 49 

Participants 18,297,032 51 

Project Objective: 

To demonsuate the m-121 flue gas desulfurization 

system, including several design innovations, at the 

100.MWe scale: more specifically, to demonstrate 

90% SO, control at high reliability with and without 

simultaneous particulate control with possible additional 

reductions in operating costs. 

Technology/Project Description: 

The project will demonstrate the CT-121 FGD process. 

This process uses a unique absorber design known as 

the jet-bubbling reactor (IRR), which combines limestone FGD reaction, forced oxidation, and gypsum 

crystallization in a one-process vessel. As a result, the 

process is mechanically and chemically simpler than 

conventional FGD processes and can be expected to 

exhibit lower cost characteristics. 

Gypsum solids settle in the dyked area, and clear water 

overflows to a retention pond. The clear water from the 

pond is returned to the process. 

ln this process, the flue gas enters the scrubbing 

solution on the jet-bubbling reactor. The SC?, in the flue 

gas is absorbed and forms calcium sulfite (CaSO,). Air 

is bubbled into the bottom of the solution to oxidize the 

calcium sulfite to form gypsum. The slurry is dewatered in a gypsum stack. The stacking technique 

involves filling a dyked area with gypsum slurry. 

As part of the project, innovations to the process will 

be evaluated to determine whether costs can be reduced 

further by using fiberglass-reinforced plastic absorbers, 

eliminating flue gas reheat and spare absorber module, 

and stacking gypsum to reduce waste management 

costs. The ability of this technology simultaneously to 

capture SO, and particulates will also be evaluated. 

A 2.5% sulfur coal will beused to demonstrate 

90% SO, control with high reliability, with and without 

simultaneous particulate control. 

Georgia Power Company’s lOO-MWe Plant Yates, 

Unit 1, near Newnan, GA (about 40 miles from 

Atlanta), is being retrofitted with the Chiyoda scrubber. 

8.44 Program Update 1991 Southern Company Services/CT-l21 
calendar Yeal 

1988 ,989 1990 ,991 1992 1993 1994 ,995 1996 1997 1998 

3 4 1 234 1 234 1 2 3 4 1234,234 1234 1 23412341234 12 

/ I I ’ Environmental monitoring 

plan complet*d 12/18l390 I i I report issued 1197 

I 

DOE s&cfed 

projecl g/281*8 

I Design completed g/92* 1 

Operation completed 8195’ 

NEPAprocess Construction completed 9192 

completed 8110190 Operation inkiated 9192 

Ground breaking/ 

conslruclion stalted 

8123190 Preoperational tests initiated 5192 

Cooperative agreement awarded 412190 

‘Projected date 

Project Status/Accomplishments: 

On-site spinning of the fiberglass JBR, limestone slurry 

tank shells, chimney, and duct work ase complete. The 

JBR inlet and outlet flanges, deck and sparger grid 

beams, lower deck ledge, and dome top have been installed. Pump foundations and slut’ry sumps are complete, as is the main power bus duct in the turbine room. 

Hydrostatic and acoustical testing of the JBR is complete, while testing on the limestone slurry tank is under 

Wiy. 

Envlrohmental Considerations: 

An environmental assessment with a tinding of 

no significant impact was approved by DOE on 

August 10, 1990. The environmental monitoring plan 

has been prepared. 

Assuming maximum commercialization of the 

CT-121 process on a national basis by 2010 relative to a 

no-action alternative, a 48% reduction of SO, could be 

achieved. The significant national reductions of SO, are 

attributable to the 90-95% SO, removal capability 

forecasted for the CT-121 process and the wide potential applicability of the process. Although solid waste 

would increase by 9%. the waste is readily disposable. 

The greatest environmental benefits may be achieved in 

the Northeast because of the large amount of coal-fired 

capacity in this region that can be retrofitted with the 

CT-121 process. (Source: CCT Programmatic Environmental Impact Statement) 

represents over 10,500,000 tons&r of potential SO, 

C”“UO1. 

Commercial Appllcatlon: 

Involvement of the Southern Company (which owns 

Southern Company Services, Inc.), with its utility 

system that has over 20.000 MWe of coal-fired 

generating capacity, is expected to enhance the 

confidence of other large, high-sulfur coal boiler users 

in the CT-121 process. By the year 2010, this process 

would be applicable to 370,000 MWe of new and 

existing generating capacity. A 90% reduction in SO, 

emissions from only the retrofit portion of this capacity 

Southern Company Services/CT-121 Program Update 1991 8-45 
Demonstration of Selective 

Catalytic Reduction 

Technology for the Control 

of NOx Emissions from 

High-Sulfur-Coal-Fired Boilers 

Sponsor: 

Southern Company Services, Inc. 

Additional Team Members: 

Electric Power Research Institute-cofunder 

Gulf Power Company-host utility 

Locatlon: 

Pensacola, Escambia County, FL (Gulf Power 

Company’s Plant Crist) 

Technology: 

Selective catalytic reduction @CR) 

Plant Capacity/Production: 

8.7-MWe equivalent (three 2.5-MWe and six 0.2-MWe 

equivalent SCR reactor plants) 

Project Funding: 

Total project cost 

DOE 

Participants 

%15,574,355 100% 

7.525.338 48 

8,049,017 52 

Project Objective: 

To evaluate the performance of commercially available 

SCR catalysts when applied to operating conditions 

found in U.S. pulverized coal-Bed utility boilers using 

U.S. high-sulfur coal under various operating conditions 

while achieving as much as 80% NOx removal. 

BOILER 

TO DISPOSAL 

Technology/Project Descrlptlon: 

The SCR technology consists of injecting ammonia into 

boiler flue gas and passing it through a catalyst bed 

In this demonsnation project, the SCR facility conwhere the NOx and ammoniareact to form nitrogen and 

sists of three 2.5-MWe SCR reactors, supplied by separate 5,000 std ft3/min flue gas slipstreams, and six 

water vapor. 

0.20-MWe SCR reactors. These reactors were calculated to be large enough to produce design data that will 

allow the SCR process to be scaled up to commercial 

size. Catalyst suppliers (three U.S., two European, and 

two Japanese) will provide nine catalysts with various 

shapes and chemical compositions for evaluation of 

process chemistry and economics of operation during 

the operation. 

The project is demonstrating, at high- and low-dust 

loadings of flue gas, the applicability of SCR technology to provide a cost-effective means of reducing NOx 

The demonstration plant, located at Gulf Power 

Company’s Plant Crist near Pensacola, FL, has access 

emissions from power plants burning U.S. high-sulfur 

to flue gas from burning approximately 3% sulfur coal 

under various NO, and particulate levels. 

coal. 

8-46 Program Update I991 Southern Company ServiceslSCR 
i 

calendar Year 

1988 ,989 ,990 ,991 ,992 ,993 ,984 1995 ,996 1997 lSS8 

34123412341 2 3 4 1 2 3 4 1234 1 2341234 1 234 1 234 12 

9/86 S/SO l/96 

I 

NEPA 

P~OCeds 

completed 

81161a9 

I bperation lnitlated 5193’ 

ConstructIon completed 1193’ L broject completedllinal repon Issued i/96’ 

OperalIon completed 2195’ 

Preoperational tests initiated W92’ 

Environmental monitoring plan completed 3~92’ 

I 

DOE selededpmjed 

9mlaa 

‘Ccaperati”e agrmm I I Ground breakinglconstrwtlon started 2192’ 

awarded a,1 4190 Design completed It/o1 

Project Status/Accomplishments: 

Detailed measurements of baseline flue gas conditions 

at Plant Crist are complete. Final, detailed catalyst 

specifications have been received from, each catalyst 

supplier. A review of these speciiicatibns was made to 

assist in SCR reactor design. Flow modeling results 

and the catalyst testing program have been released to 

the 7 catalyst suppliers for comments and recommendations. 

Detailed engineering is about 50% complete. Preliminary reactor design drawings were released for 

catalyst supplier review. Some catalyst vendors have 

provided comments on the proposed common laboratory test methods and conditions and reactor design 

drawings. The flue gas and air fan bid packages have 

been awarded. A contract for flue gas knd air electric 

heaters was also awarded. Design specification and bid 

review are ongoing for several project subsystems. 

ConsUuction is expected to begin in February 1992. 

StaR of operation has slipped from mid-1992 to 

April 1993 as a result of delays associated with design 

changes and interface issues. 

Envlronmental Considerations: 

NEPA compliance has been satisfied by a memo-to-file 

approved on August 16, 1989. 

Assuming maximum commercialization of the SCR 

process on a national basis by 2010 relative to a noaction alternative could achieve a 15% NOx reduction. 

The significant national reductions of NOr are attributable to the 80% NO, removal capability forecasted for 

the SCR process and the wide potential applicability of 

the process. There will be no additional solid waste 

because the spent catalyst will be returned to the respective catalyst suppliers. (Source: CCT Programmatic 

Environmental Impact Statement) 

Commercial Appllcatlon: 

SCR technology can be applied to retrofit and new 

utility applications for removal of NOx from flue gas. 

There are approximately 1,041 coal-fired utility boilers 

in active commercial service in the United States: these 

boilers represent a total generating capacity of 296,000 

MWe. Assuming that SCR technology is installed on 

dry-bottom boilers that ale not equipped with low-NOT 

combustion technologies (i.e., low-NOI burners, overfiie air, and atqmspheric fluidized-bed combustion), the 

potential total retrofit market for SCR technology is 

154,560 MWe (642 boilers). In addition, SCR technology could be applicable to 34,700 MWe (70 boilers) of 

new firm (i.e., announced, sited, and committed in 

terms of service date or under construction) and 

144,500 MWe (290 boilers) of planned &y-bottom 

electric generating capacity in the United States. 

So~hem Company ServiceslSCR Program Update 1991 8-47 
180-MWe Demonstration of 

Advanced Tangentially Fired 

Combustion Techniques for 

the Reduction of NO 

Emissions for Coal&red 

Boilers 

Sponsor: 

Southern Company Services, Inc. 

Additional Team Members: 

Gulf Power Company-cofunder and host utility 

Electric Power Research Institute-cofinder 

ABB Combustion Engineering, Inc.-burner/ 

technology supplier 

Location: 

LynnHaven, Bay County, FL (Gulf Power Company’s 

Plant Smith, Unit No. 2) 

Technology: 

ABB Combustion Engineering’s low-NO, bulk furnace 

staging (LNBFS) system and low-NO1 concentric firing 

system (LNCFS) with advanced over-fire air (AOFA), 

clustered coal nozzles, and offset air 

Plant Capacity/Production: 

180 MWe 

Project Fundlng: 

Total project cost 

DOE 

Participants 

Project Objective: 

$9,024,765 100% 

4,317,791 49 

4,646,974 51 

To demonstrate in a stepwise fashion the short- and long. 

term NOx reduction capabilities of low-NO, concentxic 

firing system (LNCFS) Levels I, II, and III on a single 

reference boiler under typical dynamic operating condiS-48 Program Updare 1991 

ELECTROsTATlC PRECIPmToR 

AIR 

LdoLj IPRStions, and evaluate the cost effectiveness of each 

low-NOx combustion technique. 

advanced over-fire air system having backpressuring 

and flow measurement capabilities. The air supply “” _ 

Technology/Project Description: 

Four different low-NOx combustion technologies for 

tangentially fired boilers are being demonstrated. The 

concept of over-fire air is being demonstrated in all of 

these systems. In LNCFS Level I, a close-coupled overfine air (CCOFA) system is integrated directly into the 

windbox of the boiler. Compared to the baseline 

windbox configuration, LNCFS Level 1 is arranged by 

.,. 

excnangmg me mgnest coa nozue wtn a” an nozzle 

immediately below it. This configuration provides the 

NO” reducing advantages of an over-fire air system 

without major pressure part modifications to the boiler. 

In LNBFS and LNCFS Level II, a separated 

over-fire air (SOFA) system is used. This is an 

ductwork for the SOFA is taken off tram tne seconaary 

air duct and routed to the corners of the furnace above 

the existing windbox. The inlet pressure to the SOFA 

system can be increased above windbox pressure using 

dampers downstream of the takeoff in the secondary air 

duct. Operating at a higher pressure increases the 

quantity and injection velocity of the over-fue air into 

the furnace. A multicell venturi is used to measure the 

amount of air through the SOFA system. LNCFS 

Level III utilizes both CCOFA and SOFA. 

I” addition to over-fire air, the LNCFS incorporates 

other NO* reducing techniques into the combustion 

process. IJsini offset air. two concentric circular combustion regions are formed. The majority of the coal is 

Southern Company ServiceslTangentially Fired Combustion 
Calendar Year 

,908 1989 ,990 ,991 ,992 1993 1994 ,995 ,996 1997 1998 

341234 ,234 1234 1 234 1234 1234 1234 1 2341234 12 

oestgn and ConstruGtlon 

t 

AA 

DOE selected 

projen gR8ig8 

1 II 

t 

aperation inliated 5191 T + 

Project completedninal repon issued 10193’ 

Operation completed 3/93’ 

NEPA process 

Construction completed 541 

COmpbted Design completed 4191 

7P2118Q 

Environmental monitoring plan completed 12l27190 

Ground breakmgl~nshuction started 11190 

Coaperatfve agreement awarded 9120190 

‘Projected date 

L 

contained in the fuel-rich inner region. This region is 

surrounded by a fuel-lean zone containing combustion 

air. The size of this outer circle of combusrion air can 

be varied using adjustable offset air nozzles. Separation 

of air and coal at the burner level further reduces production of NO,. 

emissions, with LNCFS Level III expected to provide Environmental Considerations: 

the greatest reduction. 

Project Status/Accomplishments: 

Installation of LNCFS equipment, including separated 

over-fire air and offset nozzles, piping, and controls, 

took place during a scheduled outage in April 1991. 

Baseline diagnostic and performance testing had been 

completed the previous month, with 70 days of longterm data collected. The LNCFS Level-ll tests (one of 

three basic air-/coal-feed contlgurations to be tested) 

were completed in September 1991. Results indicated 

NO, emissions were reduced up to 40% compared to 

baseline emissions data. The LNCFS Level-III system 

was installed during an outage in November, as was 

equipment that will allow further testing with closecoupled over-fire air. Additional work was author&d 

for the project to allow chemicaJ emissions testing related to the CAAA of 1990. Operation continues. 

NEPA compliance has been satisfied by a memo-to-file 

approved by DOE on July 21, 1989. 

Assuming maximum commercislization of the 

technology, significant reductions of NOx (11%) are 

projected to be achievable nationally by 2010, due to the 

60% removal capability forecasted and the wide applicability of the process. Negligible changes in liquid 

effluents are anticipated, and the technology produces 

no additional dry solid waste. (Source: CCI Progratnmatic Environmental Impact Statement) 

The LNBFS consists of a standard tangentially 

Bred windbox with a SOFA system. The offset air 

nozzles in the main windbox can be repositioned to be 

in line with the fuel nozzles. No other modifications to 

the windbox repositioned are required. Due to schedule 

limits, LNBFS is being demonstrated using short-term 

diagnostic tests only. 

The names of the technologies described above 

have been changed from those originally considered for 

this project to reflect the most recent, available 

knowledge. However, the basic concepts for the 

reduction of NOx emissions have remained constant. 

These technologies provide a stepwise reduction in NO, 

4 

Commercial Application: 

Commercial applications include a wide range of 

tangentially fired utility boilers throughout the United 

States and abroad. As an example, the Southern Company (which owns Southern Company Services, Inc.) 

has over 20,000 MWe of coal-fired generating capacity 

within its system of electric utilities. About two-thirds 

of this capacity is based on pulverized-coal tangentially 

fired boilers. 

Southern Company Services/TangentiaNy Fired Comburrion Program updare 1991 8.49 
CCT-III 

Project Fact Sheets 
IO-MW Demonstration of Gas 

Suspension Absorption 

Sponsor: 

AirPol, Inc. 

Addltlonal Team Members: 

FLS miljo a/s (parent company of AirPol, Inc.)- 

technology owner 

Tennessee Valley Authority-cofunder and site owner 

Location: 

West Paducah, McCracken County, KY (Tennessee 

Valley Authority’s Shawnee Fossil Plant) 

Technology: 

FLS miljo a/s’ gas suspension absorption (GSA) system 

for flue gas desulfurization (FGD) 

Plant Capaclty/Productton: 

IO-MWe equivalent slipstream of flue gas from a 

150-MWe boiler 

Project Fundlng: 

Total project cost 

DOE 

Participants 

$6,920,679 100% 

2,oQo,ooo 29 

4,920,679 71 

ProJect Objective: 

To demonstrate the applicability of gas suspension absorption for flue gas desulfurization using high-sulfur 

U.S. coals by installing and testing a lo-MWe GSA 

demonstration system. 

Technology/Project Description: 

The GSA system consists of a vertical reactor in which 

flue gas comes into contact with suspended solids consisting of lime, reaction products, and fly ash. About 

99% of the solids are recycled to the reactor via a cy 

clone while the exit gas stream passes through a” elecuostatlc precipitator before being released to the atmosphere. The lime slurry, prepared from hydrated lime, is 

injected through a spray nozzle at the bottom of the reactor. The volume of lime slurry is regulated with a 

variable-speed pump controlled by the measurement of 

the acid content in the inlet and outlet gas sneams. The 

dilution water ad&d to the lime slurry is connalled by 

on-line measurements of the flue gas exit temperature. 

Solids collected from the cyclone and particulate control 

device are combined and disposed of in a” existing site 

disposal area. 

GSA has the potential to remove in e.xcess of 90% 

of the SO, as well as to increase lime utilization efficiency with solids recycle. 

This project is utilizing a IO-MWe slipstream of 

flue gas from a 150-MWe coal-fired boiler at the Tennessee Valley Authority’s Shawnee Fossil Plant in West 

Paducah, KY. 

8.52 PrO8WH Update 1991 AirPol 
Calendar Year 

,988 ,989 1990 1991 1992 1993 1994 1995 1996 1997 1998 

34,23412i41 234 1 234 1234 1 234 1 234 1 2 3 4 ,234 12 

12199 1 O/Q0 Design and 10/92 9193 

DOE selened 

projea 12119189 

Operation completed 9193’ 

project compleled~inal report issued 9193 

Precqterational vasts initiated 9192’ 

Construction completed 9192’ 

Cooperative agreement awarded IO,, ,190 Ground breaking/construction staned 5192’ 

Environmental monitoring plan completed 46x2 

Design completed 1192’ 

‘Projected dale 

Project Status/Accomplishments: the GSA process to remove at least 90% of the SO, 

Process flow diagrams have been finalized, and general emissions from coal-fired boilers and the wide potential 

arrangement drawings and sizing and layout of major applicability of tbe process. (Source: CCI Programequipment are complete. matic Environmental Impact Statement) 

Piping and instrumentation diagrams for the control 

system are complete, as are preliminary assembly specifications for the recycled lime feeder box. Comhustar 

material and energy balances arc complete, enabling determination/specification of GSA design conditions. 

Construction has been delayed 10 months due to 

unavailability of host site during 1991. 

Commercial Application: 

The GSA process offers several advantages over conventional FGD technologies. AirPol &mates that GSA 

is 40% cheaper than wet FGD and 20% cheaper than 

spray drying. Moreover. GSA is much simpler to build 

and operate than wet FGD and regenerable processes 

and requires much less space. Space requirements, operability, and ease of installation are comparable to 

spray dryers and duct injection. However, the SO, removal capability of the GSA technology (90%) compares to that of wet FGD and the regenerable processes, 

while dry injection processes and spray dryers generally 

remwe about 50% and 90% respectively. This high removal rate makes the GSA process suitable for use with 

high-sulfur coal, unlike the spray dryer or dry injection 

processes, which are suitable only for low- and medium-sulfur coals. 

In summary, GSA is expected to find commercial 

acceptance because it is the only semidry process that 

offers SO, removal rates comparable to the more costly 

and complex wet FGD systems. In addition, GSA offers relatively low sarbent consumption rates and may 

perform better than dry systems: it is both less costly 

and more effective than spray dryers. 

Envlronmental Consicteratlons: 

NEPA compliance has been satisfied by a memo-to-file 

approved by DOE on September 21, 1990. 

The environmental monitoring plan is scheduled 

for completion in April 1992. 

Assuming maximum commercialization of this 

technology, significant reductions of SO, (45%) are 

achievable nationally by 2010 due to the capability of 

AiPPOl Program Update 1991 8.53 
Commercial-Scale 

Demonstration of the Liquidp;;slethanol (LPMEOH@) 

Sponsor: 

Air Products and Chemicals, Inc. 

Addltlonal Team Members: 

Acurex Corporation-fuel methanol testing cofunder 

Texaco Syngas Inc.-host site and cofunder 

Dakota Gasification Company-technology consultant 

Location: 

Daggett, San Bernardino County, CA (Cool Water 

Gasification Facility: Texaco Syngas negotiating 

purchase of site) 

Technology: 

Chem Systems’ liquid-phase methanol (LPMEOHS 

p*0ES 

Plant Capacity/Production: 

150 tons/day of methanol 

Project Fundlng: 

Total project cost: $213,701,857 

DOE 92,701,297 

Participants 121,000,560 

(Funding is subject to negotiation.) 

100% 

43 

57 

ProJect bbjectlve: 

Technology/Project Description: 

This project is demonstmting the LPMEOH” process to 

produce methanol from coal-derived synthesis gas on a 

commercial scale. The combined reactor and heat 

removal system in the LPMEOH” process differentiates 

it significantly from other commercial methanol 

processes. The liquid phase not only supports the 

catalyst but functions as an efficient means to remove 

the heat of reaction away from the catalyst surface. 

This feature alone directly permits the use of a low ratio 

of hydrogen to carbon monoxide in the synthesis gas 

streams produced from coal gasification facilities as 

feed to the reactor without the need for shift conversion. 

* Carbon monoxide conversion to methanol-13% per 

reactor per pass in a hydrogen-rich feed 

* Methanol productivity comparable to gas-phase systerns-6,000 kg of methanol per 1 kg of catalyst 

. Raw methanol purity-97.5% 

To demonstrate on a commercial scale the production of 

methanol from coal-derived synthesis gas using the 

LPMEOH’process; and to determine the suitability of 

methanol produced during this demonstration for use as 

a low-SO,, low-NOx alternative fuel in boiler, turbine, 

and uansportation applications. 

* Feed gas flexibility-permits the use of synthesis gas 

produced by any commercial coal gasification system to be used without shift conversion 

* Diversity-can be combined with integrated coal 

gasification combined-cycle (IGCC) applications 

The performance of the LPMEOH” process for the 

synthesis of methanol is characterized as follows: 

In addition to the original project objective, DOE 

will receive data on the use of a combined feedstock of 

LPMEOH is aregistered mdsmark Of chcm Syrtcms. Inc. 

8.54 Program Update 1991 Air Products and Chemicals 
Calendar Year ,988 ,989 3412341 
Healy Clean Coal Project 

Sponsor: 

Alaska Industrial Development and Export Authority 

Additional Team Members: 

Golden Valley Electric Association-host utility 

Stone and Webster Engineering Companyengineer and constructor 

TRW, Inc.-technology supplier 

Joy Technologies, lx-technology supplier 

Location: 

Healy, AK (Denah Borough) 

Technology: 

TRW’s advanced entrained (slagging) combustor 

Joy Technologies’ spray dryer absorber with sorbent 

recycle 

Plant Capaclty/Productlon: 

50 MWe (net) 

Project Funding: 

Total project cost %193,407,000 100% 

DOE 93,862,OOO 4x 

Participants 99,545,ooo 52 

Project ObJectlve: 

To demonstrate an innovative new power plant design 

featuring integration of an advanced combustor and heat 

recovery system coupled with both high- and low-temperature emissions control processes. 

8-56 Program Update 1991 

Technology/Project Descrlptlon: 

The heart of the system being demonstrated is an allmetal combustor that consists of two cylindrical sections followed by a short duct that connects the combustor to the boiler. A separate precombustor burns 

about 25% of the coal, and the combustion air to the 

main (or slagging-stage) combustor is preheated by 

mixing it with the hot gases exhausted from the 

precombustor. The preheated air enters the main combustor section tangentially to impart a swirling motion 

to the coal and air. The balance of the coal is injected 

axially at the front end of this cylindrical section. 

horizontal to aid in the flow of the molten slag. Some 

slag solidifies on the water-cooled surface and serves to 

insulate and protect the metal walls from erosion and 

excessive temperatures. 

The main combustion section operates at a slight 

air deficiency to reduce the amount of NOx produced. 

Combustion products mix with sufficient air to complete 

the combustion reactions that take place in the boiler. 

The combustors are coupled with a specially designed 

boiler that, in addition to its heat recovery function, produces low NOx levels, functions as a limestone calciner, 

and accomplishes first-stage SO, removal. 

Molten slag collects on the walls of the combustor The process also uses a single spray dryer absorber 

and flows toward an opening in the bottom of the main vessel for second-stage sulfur removal and a lime acticombustor where it falls into a water-filled slag tank. vation system that recovers unused reagent from the 

The slagging combustor declines slightly from particulate collected by the baghouse. 

Alaska IDEA 
Calendar Year 

,988 ,989 ,990 19% ,992 ,993 ,994 ,995 f996 ,997 1898 

3412341 2 3 4 1 234 1 234 1 234 1234 1234 1234 123412 

I besign completed 593 

Ground breaking, 

Cooperative mnstrudion starled 5193 

C3g,WW”t 

awarded 4111191 

Design *tart 

NEPA process completed 3193 

,190 

1 Z/89 4191 1196 6197 1199 

I 

7 Final repod 

issued 6/97’ 

DOE cost-shared 

operation completed 

,197 i 

I 

operation inliakad j/96 

2 yrs 01 operational 

data provided at no 

additional ~051 

nvironmental monitoring ,199 

la” completed 12195 I PI 

COnstructian completed .5‘S 

Preoperational I&s initiated 6195 

‘Prqected date 

The slagging combustor with specially designed 

boiler and the spray dryerj~ecycle system should be capable of reducing NOx by 70% and SO, by at least 90%. 

The project involves design, construction, and operation of the slagging cumbustor spray dryer/sorbent 

recycle system at a greenfield site near Healy, AK, 

to provide power to the Golden Valley Electric 

Association. The plant will provide 3 years of data, 

with 2 years of data being provided at no cost to DOE. 

Project StatWAccompllshments: 

The cooperative agreement was awarded on April 11, 

1991. Preparation of Alaska Department of Natural 

Resources land use and EPA National Pollution 

Discharge Elimination System permit ~pplic&ons as 

well as project design and construction schedule 

activities continue. The advanced slagging combustor 

was successfully operated using Healy project fuel at 

TRW’s Cleveland facility. Jay/Niro testing of flash 

calcined sorbent was completed at the Copenhagen 

facility. The project is on schedule with approximately 

20% of the design completed. 

Environmental Considerations: 

Environmental information is being prepared for use in 

the NEPA compliance process; an EIS will be prepared. 

The following impacts are projected for the Healy 

demonstration on a national basis by 2010 with maximum commercialization of this technology: 

. SO, reduction-45% 

. NOx reduction-18% 

Ash removal efficiencies in the combustor range from 

70% to 90%. Much of the coal’s ash content is removed 

as a molten slag by cyclonic action in the combustor 

and, when cool, is a dry, coarse solid suitable for a landfill. (Source: CCT Programmatic Environmental Impact 

Statement) 

Commercial Appllcatlon: 

This technology has a wide range of applications. It is 

appropriate for any size utility or industrial boiler %1 

new and 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 

slagging combustor because of the limited supply of 

high-Btu, low-sulfur, low-ash-fusion-temperature coal 

that cyclone boilers require. Furthermore, coal of any 

sulfur content can be used as long as the minimum ash 

content is 5%. The commercial availability of cost-effective and reliable systems for SO,, NO, and particulate control is important to potential users planning new 

capacity, repowering, 01 retrofits to existing capacity to 

comply with CAAA of 1990requirements. 

Alaska IDEA Program Update 1991 8.57 
Full-Scale Demonstration of 

Low-NO, Cell BurnerTM 

Retrofit 

Sponsor: 

The B&cock &Wilcox Company 

Additional Team Members: 

The Dayton Power and Light Company-cofunder and 

host utility 

Electric Power Research Institute-cofunder 

Ohio Coal Development Office-cofunder 

Tennessee Valley Authority-cofunder 

New England Power Company-cofunder 

Duke Power Company-cofunder ’ 

Allegheny Power System-cofunder 

Centerior Energy Company-cofunder 

Locatlon: 

Aberdeen, Adams County, OH (Dayton Power and 

Light’s J. M. Stuart Plant, Unit No. 4) 

Technology: 

The Babcock &Wilcox Company’s Low-NO, Cell 

Burnernt (LNCB”) system 

Plant Capacity/Production: 

605 MWe 

ProJect Fundlng: 

Total project cost $10,046,204 100% 

DOE 4,867,2@4 48 

Participants 5,179,ooo 52 

ProJect ObJectlve: 

To demonstrate through the fast commercial-scale full 

burner retrofit the cost-effective reduction of NOx from 

a large base-load coal-fired utility boiler with Low-NO, 

Cell Burnern’ technology; and to achieve at least a 50% 

NO, reduction without degradation of boiler perfortnan~e at less cost than conventional low-NOx burners. 

S-58 Program Update 1991 

ELECTROSTATIC 

PRECIPITATOR 

FLY ASH TO DISPOSAL 

Technology/Project Oescrlption: 

Low-NO, Cell Burnein” technology replaces the upper 

coal nozzle of the standard cell burner with a secondaryair port. The lower burner throat is enlarged to 

accommodate a large coal nozzle that has the same fuel 

input capability as two standard coal nozzles. The LowNOx Cell Burn@’ operates on the principle of staged 

combustion to reduce NOx emissions. Approximately 

70% of the total air (primary, secondary, and excess air) 

is supplied through or around the coal feed nozzle. The 

remainder of the air is directed to the upper port of each 

cell to complete the combustion process. The fuelbound nitrogen compounds are converted to nitrogen 

gas, and the reduced flame temperature minimizes the 

formation of thermal NO,. 

The net effect of this technology is a 50% reduction 

in NO, formation with minimal or no boiler pressure 

part changes and no impact on boiler operation or performance. In addition, the technology is compatible 

with most commercial and emerging SO, control technologies, including confined zone dispersion, gas suspension absorption, duct injection, and advanced wet 

scrubbers. 

The demonstration is being conducted at a largescale power plant operated by the Dayton Power and 

Light Company and jointly owned with the Cincinnati 

Gas and Electric Company and the Southern Ohio Electric Company. The boiler unit is a B&W-designed, 

supercritical, once-through boiler equipped with an 

electrostatic precipitator. This unit contains 24 

two-nozzle cell burners arranged in an opposed firing 
11 

I 

DOE selected project 12119189 

Dssign Starfed 490 

NEPA process completed 81101! 

1 

t t t- Propa compleledfiinal report issued 5193 

Operation initiated 12,531 Operation completed 5193’ 

Preoperational tests initiated 11191 

Co”s.tructia” completed 11/91 

Ground breakingiconstructian started SW 

Environmental monitoring plan complefsd 8/9/91 

~operatbe agreemen, awarded 10,11/90 

Design completed 10190 

‘Projected date 

configuration. Twelve burners (arranged in two rows of 

six burners each) are mounted on each of two opposing 

walls of the boiler. The proposed demonstration will 

require the removal of all 24 standard cell burners and 

the installation of 24 new burners. 

Project Status/Accomplishments: 

Detailed design for the retrofit was completed in October 1990. Pre-reuofit baseline testing was completed in 

November 1990, and the data analysis is complete. 

Commerical boiler flow modeling for both the preretrofit baseline and retrofit cases are complete. 

The project schedule has been extended 6 months 

because the host utility, Dayton Power and Light, 

needed to delay the outage of Unit No. 4 (the project 

site) due to an extended outage required on another unit 

for turbine repairs. Fabrication of the 24 new burners is 

complete, and the burners were installed during the 

6-week outage that began September 20, 1991. 

Additional work was authorised for the project to allow 

testing of a corrosion test panel and operation of a hightemperature remote video system for recording burner 

flame characteristics. The outage was completed in 

early November 1991. Stan-up and shakedown of the 

system was initiated in November 1991. 

Environmental Considerations: 

Commercial Appllcatlon: 

This retrofit technology is applicable to approximately 

31 coal-fired boilers that are equipped with cell-type 

burners, representing a total generating capacity of 

approximately 26,000 MWe. 

NEPA compliance has been satisfied by a memo-to-file 

approved by DOE on August 1, 1990. The environmental monitoring plan was completed August 9, 1991. 

This technology can be retrofitted only with boilers 

configured with cell-type burners. The retrofit market is 

limited to approximately 37 boilers that emit an 

estimated 7X3,000-1,312,OOO tons/y? of NOx. 

Assuming maximum commercialization nationally 

of the low-NOx burner technology by the year 2010, 

NO, emissions could be reduced by 364,000-656,000 

tons/y1 relative to a no-action alternative. (Source: 

CCT Programmatic Environmental Impact Statement) 

Program Update 1991 8.59 
Confined Zone Dispersion 

Flue Gas Desulfurization 

Demonstration 

Sponsor: 

Bechtel Corporation 

Additional Team Members: 

Pennsylvania Electric Company-cofunder and host 

utility 

Pennsylvania Energy Development Authoritycofunder 

New York State Electric and Gas Corporationcofunder 

Rockwell Lime Company-cofunder , 

Locatlon: 

Seward, Indiana County, PA (Pennsylvania Electric 

Company’s Seward Station, Unit No. 15) 

Technology: 

Bechtel Corporation’s in-duct, confined zone dispersion 

flue gas desulfurization (CZD/FGD) process 

Plant Capacity/Production: 

13SMWe 

ProJect Funding: 

Total project cost 

DOE 

Participants 

ProJect Objective: 

$9,211,600 lc4l% 

4,605,800 50 

4,605,X00 50 

To demonstrate SO, removal capabilities of induct 

CZD/FGD technology; specifically, to define the 

optimum process operating parameters and to determine 

CZD/FGD’s operability. reliability, and cost-effectiveness during long-term testing and its impact on downstream operations and emissions. 

Technology/Project Description: 

I” Bechtel’s CZD/FGD process, a finely atomised slurry 

of reactive lime is sprayed into the flue gas stream between the boiler air heater and the electrostatic precipitator (ESP). The lime slurry is injected into the center 

of the duct by spray nozzles designed to produce a cone 

of fine spray. As the spray moves downstream and 

expands, the gas within the cone cools and the SO, is 

rapidly absorbed in the liquid droplets. The droplets 

mix with the hot flue gas, and the water evaporates 

rapidly. Fast drying precludes wet particle buildup in 

the duct and aids the flue gas in carrying the dry reaction products and the unreacted lime to the ESP. 

physical space and lower capital, operating, and maintenance costs. 

tive to conventional FGD processes, requiring less 

This project includes injection of different types of 

sorbents (dolomitic and calcitic lime) with several atomiser designs using low- and high-sulfur coals to verify 

the effects on SO, removal and the capability of the ESP 

to control psrticulates. The demonstration is located at 

Pennsylvania Electric Company’s Seward Station in 

Seward, PA. One-half of the flue gas capacity of the 

147~MWe Unit No. 15 is being routed throughamoditied, longer duct between the first and second ESP. 

Pennsylvania bituminous coal (approximately 1.2-2.5% 

sulfur) is being used in the project. After the variable 

test program is complete, continuous, fully automated 

The CZD/FGD process is expected to remove 50% 

of SO, emissions from coat-fired boilers. If successfully demonstrated, this technology would be an slternaS-60 Program Update1991 BechrelCorporation 
calendar Year 

,666 ,966 ,ss!l ,991 ,692 1893 ,994 ,995 ,996 169, ,996 

3 4 1 2 3 4 1 2 3 4 1 2 3 4 123412341 234 1 234 1 234 1 234 12 

Design and Construction 

12/89 10/90 6/93 

t 

k--.-- Prqect completedifinal repon issued 6/g3* 

DOE selected 

Preoperational tests Initiated 8/9l Operation completed 6193’ 

project 12119,89 lAAjP Operation initiated 7191 

Construction mmplated 6191 

Environmental monitoring plan 6/12@1 

Design *tad 6190 Ground breaking/construction s&fled 3B91 

Design completed 12190 

cooperative agreement awarded 10/13190 

NEPA process compreted 9,25/w 

‘Projected date 

L 

and integrated (with the regular power plant) operation date indicate that the expected level of emissions reduc- Commercial Application: 

is planned for 1 yr. 

Project Status/Accomplishments: 

Ground breaking occurred in March 1991, and consnuction was completed in June 1991. Bechtel began the 

ZS-month test of its process in July 1991. The new 

atomizing nozzles were thoroughly tested outside of the 

duct followed by in-duct testing. Start-up operations 

were delayed due to late deliveries of some equipment 

items. The lime slurry injection parametric test program 

began in October 1991. One project goal is to demonstrate that the CZD process is capable of reducing SO, 

emissions by 50% from coal-fired boilers. Difficulties 

encountered in achieving stable communications within 

the new temperature monitoring and recording system 

installed for this demonstration also caused delays in 

parameuic testing. However, although the CZD technology will not be fully demonstrated until the parametric testing and year-long testing are complete, tests to 

tion can he reached and possibly exceeded. Long-term 

testing may be delayed by a month or two and is 

planned for next year with operations expected to continue through the first half of 1993. 

Environmental Considerations: 

NEPA compliance has been satisfied by a memo-to-file 

approved by DOE on September 25, 1990. The environmental monitoring plan was completed June 12, 

1991. 

Sorbent injection technologies such as the 

CZD/FGD process could reduce national emissions of 

SO2 by as much as 38% by 2010, assuming maximum 

commercialization of the technology. NSPS levels of 

SO, reduction could be satisfied with low-sulfur coal. 

Although the volume of solid waste is increased 8%, 

it is dry, nontoxic, and easily disposable. (Source: CC7 

Programmatic Environmental Impact Statement) 

-I 

CZD can be used for renotit of and installation in new 

utility boiler flue gas facilities to remove SO, derived 

from a wide variety of U.S. sulfur-containing coals. 

A CZD system can be added to a utility boiler with 

a capital investment of about $25-55/kW of installed 

capacity, or approximately one-third the cost of building 

a conventionalwet scrubber. In addition to low capital 

cost, other advantages include small space 

requirements, ease of retrofit, and production of only 

nontoxic, disposable waste. The CZD technology is 

particularly well suited for retrofitting existing boilers, 

independent of type, age, or size. Further, CZD “se is 

not dependent on the type of sulfur content of the coal. 

The CZD installation does not require major power 

station alterations and can be easily and economically 

integrated into existing power plants. 

Beck&l Corporation Program Update 1991 S-61 
Blast Furnace GranulatedCoal Injection S 

J 

stem 

Demonstration reject 

Sponsor: 

Bethlehem Steel Corporation 

Addltlonal Team Members: 

British Steel Consultants Overseas Services, Inc. 

(marketing srm of British Steel Corporation)- 

technology owner 

Simon Macawber, Ltd.-equipment supplier 

Fluor Daniel, Inc.-architect and engineer 

ATSI, Inc.-injection equipment engineer (U.S. 

technology licensee) 

Locatlon: 

Bums Harbor, Porter County, IN (Blast Furnace Units 

CandD) 

Technology: 

British Steel’s blast furnace granulated-coal injection 

(BFGCI) process 

Plant CapacltylProductlon: 

7,COCl net tons/day of hot metal (each blast fnrnace) 

ProJect Fundlng: 

Total project cost $143,8OO,OM) 100% 

DOE 31.259.530 22 

Participants 112,540,470 78 

ProJect ~bjectlve: 

To demonstrate that existing iron-making blast furnaces 

can be retrofitted with blast furnace granulated-coal 

injection technology, and to demonsuate sustained 

operation with a variety of coal particle sizes, coal injection rates, and coal types, and to assess the interactive 

nature of these parameters. 

TO STEELMAKING 

Technology/Project Descrlptlon: 

the furnace called raceways. The size of a raceway is 

important andis dependent upon many factors including 

In the BFGCI process, both granulated and pulverized 

temperature. Lowering of a raceway temperature, which 

can occur with gas injection, reduces blast furnace procoal is injected into the blast furnace in place of natural 

duction rates. Coal, with a lower hydrogen content than 

either gas or oil, does not cause as severe a reduction in 

raceway temperatures. In addition to displacing injected 

gas (or oil) as a blast furnace fuel supplement. The coal 

natural gas, the coal injected through the tuyeres disalong with heated air is blown into the barrel-shaped 

places coke, the primary blast furnace fuel and reductsnt 

section in the lower part of the blast furnace through 

passages called tuyeres, which creates swept’zones in 

remain virtually unchanged by the injected coal; the gas 

exiting the blast furnace is clean, containing no measur- 

(reducing agent), on approximately a pound-for-pound 

able SO, or NO,. 

basis. Because coke production results in significant 

Sulfur from the coal is removed by 

the limestone flux and bound up in the slag, which is a 

salable by-product. In addition to the net SO, and NO, 

SO, and NO= emissions and coal could replace up to 

reduction realized by coke displacement, blast furnace 

production is increased by maintaining high raceway 

40% of the coke requirement, BFGCI technology has 

temperatures. 

significant potential to reduce emissions and enhance 

blast furnace production. 

Emissions generated by the blast furnace itself 

8-62 Program Update 1991 Bethlehem SteeNBiasr Furnace 
Calendar Year 

,988 1 Q6Q ,990 IQ91 ,982 ,993 1994 ,895 ,998 IQQ, 1998 

3 4 1 234 1 2 3 4 1234 1 234 1 2 3 4 1234 I 234 1 2 3 4 1234 12 

12l99 11190 l/94 6196 

T 

A 

I 1 T 

t t 

Construclion completed l&W Operation completed 5,W’ 

DOE selected Preopemtiond k&o inla!ed l/94’ Projed completedninal repod 

Operation inliated l/94’ issued NQ6’ 

prc+aU 12/19/89 

Environmental monitoring plan completed lOB3* 

Design completed 1193’ 

Construction slatted 5lQ2’ 

NEPA process completed 4192’ 

Cooperative qreement awarded 11126190 

‘Projected date 

Two high-capacity blast furnaces, Units C and D at 

Bethlehem Steel Corporation’s Burns Harbor Plant, xe 

being retrofitted with BFGCI technology. Each unit has 

a production capacity of 7,000 net tons/day of hot metal 

Project Status/Accomplishments: 

Conceptual design of the blast furnace granulated-coal 

injection system is complete. Process design and detailed engineering are in progress. 

Environmental Considerations: 

Environmental information for use in the NBPA compliance process has been prepared. Biological assessments 

of impacts on local lakeshore areas are complete and 

have been approved by the U.S. Department of Interior 

Fish and Wildlife Service. 

The largest reductions in emissions resulting from 

commercialization of the BFGCI technology are expected to occur in the coke-making process. As the 

BFGCI technology reaches full market penetration, the 

amount of coke required for blast furnaces would 

decrease, thus reducing the emissions associated with 

its production. Although a slight increase in slag can be 

expected from the coal ash, the slag is readily salable as 

cons~uction aggregate or rock wool. 

Commercial Appllcetlon: 

This technology can be applied to essentially all blast 

furnaces in the United States. It is anticipated that a 

wide variety of coals can be used. 

Bethlehem SteeNBlast Furnace Program Update 1991 8-63 
Air-Blown/Integrated 

Gasification Combined-Cycle 

Project 

Sponsor: 

Clean Power Cogeneration Limited Partnership (wholly 

owned by TECO Power Services) 

Additional Team Member: 

Tampa Electric Company-host utility 

Locatlon: 

Lakeland, Polk County, FL (TampaElectric Company’s 

Polk Power Station) 

Technology: 

Air-blown, integrated gasification combined-cycle 

(IGCC) system 

Plant Capaclty/Productlon: 

120 MWe 

Project Fundlng: 

Total project cost $241,458,000 

DOE 120,729,OOO 

Participants 120,729,OOO 

(Funding is subject to project restructuring.) 

100% 

50 

50 

Prolect Objective: 

To demonstrate air-blown, fixed-bed, integrated g&iication combined-cycle technology and to assess longterm reliability, availability, and maintainability at sufficient scale to determine commercial potential. 

S”LF”R BY-PRODUCT 

I 

1 

STEAMTURBINE 

Technology/Project Descrlptlon: 

Coal is gasified in a pressurized, air-blown, fixed-bed 

gasifier. The 1owBtu cord gas leaves the gasifier at 

approximately l,CXl “P and goes to a hot gas cleanup 

system where the removal of sulftir compounds is 

accomplished in a moving bed of solid sorbent. The 

cleaned gas is delivered to a combustor, which is on 

board the gas turbine frame. The gas turbine is integrated with the coal conversion system through pressurized air extiaction, which is used as gasifier air supply. 

The steam generated in the heat recovery generator is 

used both for driving a conventional steam turbine generator set producing additional electricity and for gasifier blast. The project has the following subsystems: 

fixed-bed coal gasification, hot gas cleanup, a combustion turbine capable of using low-Btu cool gas, selective 

catalytic reduction for NOx control, a briquettor to utilize coal fines, and the balance of plant. 

In the demonstration project, a nominal 1,270 tons/ 

day of coal is convened into 120 Move. The base feed 

coal for the project is a high-sulfur Illinois Basin bituminous coal. The new site is Tampa Elecnic Company’s 

Polk Power Station located in Lakeland, FL. 

S-64 Program Update 1991 Clean Power Cogeneration 
Calendar Year 

,988 1989 1990 ,991 1992 ,983 1994 ,995 1996 19.97 ,998 

3412341 234,234 1 234 123412341234 1 234 1 234 12 

1 Z/89 

I Proaward 3/91 Q/91 I I 

T 1 

t 

Site change approved 9/3/91” 

Cooperalive agreement awarded 3,,8/91 

DOE seleded projen 

12U9189 

“Milestones lo be revised following completion 

al sponror’s organisational wtructuring 

Project Status/Accomplishments: 

The cooperative agreement was awarded March 18, 

1991. On September 3, 1991, DOE approved a site 

change from the City of Tall&we’s Awah B. Hopkins 

Station to Tampa Electric Company’s Polk Power Station located in Polk County, FL. Relocation was necessary due to siting difficulties at the Arvah B. Hopkins 

Station and failure to obtain a power sales agreement 

with the City of Tallahassee. Under way are preliminary design and engineering activities and studies for 

integration of the IGCC project into Ttipa Electric’s 

260-MWe first-phase generation expansion plan. 

Environmental Conslderatlons: 

Assuming maximum cammercialization of IGCC technology on a national basis by 2010 relative to a noaction alternative, the following impacts ale projected: 

. SO, reduction-37% 

* NO, reduction-17% 

* Solid waste reduction-S% application for meeting future U.S. energy needs. 

* CO, reduction-6% 

(Source: CCT Programmatic Environmental Impact 

Statement) 

Commercial Appllcatlon: 

In recent years, IGCC is rapidly emerging as an 

alternative for new electricity generating plants. Such 

plants require 15% less land area than pulverized coal 

plants with flue gas desulfurization. IGCC technology 

also can be used in repowering by replacing the existing 

coal-fired boiler with a gaaifier, gas stream cleanup unit, 

gas turbine, and waste heat recovery boiler. The 

remaining equipment is left in place, including the 

steam turbine and electrical generator. Because of its 

advantages of modularity. rapid and staged on-line 

generation capability, high efficiency, environmentti 

controllability, and reduced land and natural resource 

needs, IGCC is a strong contender for widespread 

Another important application for IGCC is cogeneration 

under PURPA’s Qualifying Facility provisions. 

The performance potential of IGCC technology in 

its commercial configuration is characterized as follows: 

* SO, reduction-99% 

- NO, reduction-95% 

. Plant efficiency-up to 48% 

. Incremental power increase-230% 

* Fuel flexibility-permits use of wide range of coals 

. Compactness-high process efficiency reduces 

space requirements per unit of energy generated 

. Modular construction-lends itself to economic 

addition of capacity increments to match load growth 

Clean Power Cogenemkm Program Update 1991 8-65 
PCFB Demonstration Project 

Sponsor: 

DMEC-1 Limited Partnership (a partnership between 

Dairyland Power Cooperative and Iowa Power, Inc.) 

Addltlonal Team Members: 

Pyropower Corporation-technology supplier 

Black and Veatch-architect and engineer 

Location: 

Pleasant Hill, Polk County, IA (Des Moines Energy 

Center) 

Technology: 

Pyropower Corporation’s pyroflow pressuiized 

circulating fluidized-bed combustion (PCFB) 

combined-cycle system 

Plant Capaclty/Productlon: 

70 MWe 

Project Funding: 

Total project cost $202,959,000 100% 

DOE 93.253.000 46 

Participants 109,706,OOO 54 

Project Objective: 

To demonstrate PCFB at sufficient scale to evaluate 

environmental, cost, and plant performance and to obtain the technical data requisite to commercialization of 

the technology; to assess efficiency improvements associated with integration of a hot gas cleanup system 

using a ceramic barrier filter and inclusion of a topping 

combustor, to achieve SO, reduction in excess of 90% 

and NO, reduction of 70%; and to improve plant efticiency by up to 15% of its current rating. 

8-66 Program Update 1991 DMEC-I Limited Partnership 

.Technology/ProJect Descrlptlon: 

In the PCFB process, coal is combusted at about 

1,600 OF in a circulating fluid&d bed contained within 

a pressure vessel. Limestone is used within the bed to 

absorb sulfur compounds. Particulates from the hot, 

pressurized combustion gases are removed by a ceramic 

filter. The clean gas is then expanded through a gas 

turbine. During peak load demand periods, the topping 

combustor is fired with fuel oil to raise the inlet ternperature of the gases entering the gas turbine. Higher 

turbine operating temperature increases the turbine 

efficiency and power output. Steam generated within 

the PCFB combustor and the heat recovery steam generator downstream from the gas turbine are used to 

generate power in two existing steam turbines. 

The DMEC-1 project would be the worlds first 

large-scale demonstration of PCFB technology. The 

project provides for repowering an existing pulverized 

coal-fued boiler with a single PCFB combustor integrated with an oil/gas-Bred topping combustor and a gas 

turbine module operating in a combined-cycle mode. 

The repowered plant will have a capacity of about 

70 MWe. The unit is part of the Des Moines Energy 

Center located southeast of Des Moines, IA. 
Calendar Yeal 

,988 ,989 1990 ,991 ,692 ,893 1994 ,895 I99e ,997 ,998 

3 4 1 234 1 234 1 234 1 234 1 234 1 234 1 234 1 234 1 234 12 

12189 

t t t?r t tt t r I 

DOE selected project 1~1gi8g I 

NEPA process 

completed 1194* 

&mtruction completed 8195’ 

/ 

Project co~pleledl 

qmauon inItialed 8195’ hdteporl Isued 

Shakedown tasthg Mated 7AW 

ccqlerative agreement 

awarded 8,119, 

Environmental monitoring plan completed 9B3’ 

Qmund bmakinghonrlruch staled 8x)3’ 

Design completed 6/93 

OpeW¶n 

completed S/87’ 

‘Projected datt 

ProJect Status/Accomplishments: 

The cooperative agreement was awarded August 1, 

1991. Preliminary design and project definition studies 

are under way. 

Environmental Conslderatlons: 

Environmental information is being prepared for use in 

the NBPA compliance process. 

Assuming maximum commercialization of the 

technology on a national basis by 2010 relative to a noaction alternative, the following impacts are projected: 

. SO, reduction-48% 

* NO, reduction-17% 

* Solid waste decrease-4%, with the solid waste in a 

dry, granular form amenable to alternative uses such 

as construction aggregate 

. CO, reduction-8% 

(Source: CCf Programmatic Environmental Impact 

Statement) 

Commerclal Application: . Incremental plant efficiency-improved 8-15% 

The combined-cycle PCFB system permits the combustion of a wide ranae of coals. including high-sulfur 

coals, and would iotnpete with the bubbling-bed PFBC 

system. Like the bubbling-bed system, PCFB can be 

used to repower oil- and gas-fired boiler units, while 

switching them to high-sulfur coal; to repower coatfired power plants: and to build new PCFB units. Cornbined-cycle PCFB technology appears to be best suited 

for electric utility plants larger than 100 MWe. Because 

of modular construction capability, PCFB generating 

plants permit utilities to add economical increments of 

capacity to match load growth and to repower with 

PCFB using the existing plant area, coal- and wastehandling equipment, and steam turbine equipment. 

* Fuel flexibility-permits use of wide range of coals 

* Compactness-high process efficiency reduces 

space requirements per unit of energy generated 

* Modular construction-lends itself to economic 

additions of capacity increments to match load 

n.n...r,, 

B’““L” 

The performance potential of PCFB technology is 

characterized as follows: 

* SO, reduction-95% 

- NO, reduction-80% 

* Plant efficiency increase-up to 45% 

DMEC-1 LimitedPartnership Program Update 1991 8-67 
ENCOAL Mild Coal 

Gasification Project 

Sponsor: 

BNCOAL Corporation (subsidiary of Shell Mining 

C*ww) 

Additional Team Members: 

Shell Mining Company-cofunder 

TEK-KOL (partnership between Shell Mining Company 

and SGI Internationsl)-technology owner, supplier, 

and licenser 

SGI International-technology developer 

Triton Coal Company (subsidiary of Shell Mining 

Company)-host facility and coal supplier 

The M.W. Kellogg Company-engineer and 

constructor 

Locatlon: 

Near Gillette, Campbell County, WY (Buckskin Mine) 

Technology: 

SGI International’s liquids from coal process 

Plant Capacity/Production: 

1,000 tons/day of subbituminous coal feed 

Project Fundlng: 

Total project cost $72,564,000 

DOE 36,282,ooO 

Participants 36,282,OOO 

ProJect Objective: 

100% 

50 

50 

To demonstrate the integrated operation of a number of 

novel operating steps to produce two higher value fuel 

forms from mild gasification of low-sulfur subbituminous coal, and to provide sufficient products for potential end users to conduct bum tests. 

8-68 Program Update 1991 ENCOAL Corporation 

Technology/Project Description: 

The ENCOAL mild coal gasification process involves 

heating coal under carefully controlled conditions. Coal 

is fed into a rotary grate dryer where it is heated by a hot 

gas stream to reduce the moisturecontent of the coal. 

The solid bulk temperature is controlled so that no significant amounts of methane, carbon monoxide, or 

carbon dioxide are released from the coal. The solids 

from the dryer are conveyed to the pyrolyzer where the 

rate of heating of the solids and residence time are controlled to achieve desired properties of the fuel products. 

During processing in the pyrolyzer, all remaining free 

water is removed, and a chemical reaction occurs that 

results in the release of volatile gaseous material. Solids exiting the pyrolyzer are quenched, cooled, and 

transferred to a surge bin. 

The gas produced in the pyrolyzer is sent through a 

cyclone for removal of the particulates and then cooled 

to condense the liquid fuel products. Most of the gas 

from the condensation unit is recycled to the pyrolyzer. 

The rest of the gas is burned in combustors to provide 

heat for the pyrolyzer and the dryer. NO= emissions are 

controlled by staged air injection. 

The offgas from the dryer is treated in a wet venturi 

scrubber to remove patticulates and a horizontal scrubber to remove SO,, both “sing a sodium carbonate solution The treated gas is vented to a stack, and the spent 

solution is discharged into a pond for evaporation. 

The ENCOAL project is located within Campbell 

County, WY, at Triton Coal Company’s Buckskin 

Mine, 10 miles north of Gillette. The plant makes use 

of the present coal-handling facilities at the mine. 
Preaward 

i 

DOE 

selected 

projeci 

12119189 

Conwuction mmpleled g/92’ 

operation initiated 9,742 

Preoperational tests initiated 492’ 

Environmental monitoring plan completed 1192’ 

I besign completed 591 

Ground breahin9 10125190 

ooperalie a9reemenl awarded 9117190 

IEPA process completed 911190 

Project complaedfiinal repa? issued 9194 

Operation completed 9194’ 

‘Projected date 

Project StatuslAccompllshments: 

Design is complete and constntctian activities are ahead 

of schedule, with construction of all silos and the coal 

pyrolyzer complete, mine expansion tasks complete, 

all major equipment in place, and steel erection 80% 

complete. 

Environmental Considerations: 

NEPA compliance has been satisfied by an environmental assessment with a finding of no significant impact approved by DOE on August 1, 1990. The envimnmental monitoring plan is nearing completion. 

Assuming maximum commercialization of the mild 

coal gasification technology on a national basis by 2010 

relative to a no-action alternative, the following impacts 

are projected: 

* SO, reduction--S% 

* NO, reduction-2% 

EffCOAL corporarion Progranr Update 1991 8-69 

. Solid waste increasel4i%; however, this is adry, commercial boilers and furnaces and to significantly 

salable by-product. reduce sulfur emissions at industrial and utility facilities 

(Source: CCT Programmatic Environmental Impact currently burning high-sulfur bituminous fuels or fuel 

Statement) oils. 

Commercial Appllcatlon: 

The liquid products from mild coal gasification can be 

used in any market in place of No. 6 fuel oil. The solid 

product can be used in any scale industrial or utility 

boiler. The feedstock for mild gasification facilities is 

being limited to low-heating-value coals. 

The potential benefits of this mild gasification 

technology in its commercial configuration are 

attributable to the increased heating value and lower 

sulfur content of the new solid fuel product 

(approximately 12,000 Btuflb). compared to the lowrank coal feedstock and the production of low-sulfur 

liquid products requiring no hydrotreating. The product 

fuels are expected to be used economically in 
Evaluation of Gas Reburning 

and Low-NO Burners on a 

Wall-Fired Bhiler 

Sponsor: 

Energy and Environmental Research Corporation 

Addltlonal Team Members: 

Public Service Company of Colorado-&under and 

host utility 

Gas Research Institute-cofunder 

Colorado Interstate Gas Company-cofunder 

Electric Power Research Institute-cofunder 

Locatlon: 

Denver, Adams County, CO (Public Service Company 

of Colorado’s Cherokee Station, Unit No. 3) 

Technology: 

Energy and Environmental Research Corporation’s gas 

rebuming and low-NO, burner system 

Plant Capaclty/Productlon: 

172 MWe 

Project Fundlng: 

Total project cost 

DOE 

Paaicipants 

$14,472,117 100% 

7,236,058 50 

7,236,059 50 

ProJect Objective: 

To attain up to a 75% decrease in the emissions of NO, 

from an existing wall-fned utility boiler fiiing 

low-sulfur coal using both gas rebuming and low-Nor 

burners. 

STACK 

Technology/Project Description: 

Gas rebuming involves firing natural gas (up to 20% of 

total fuel input) above the main coal combustion acne in 

a boiler. This upper-level firing creates a slightly fuelrich zone. NOx drifting upward from the lower region of 

the furnace is “rebumed” in this zone and converted to 

harmless molecular nitrogen. Low-NOx burners positioned in the coal combustion zone retard the production 

of NOr by staging the burning process so that the coalair mixture can be carefully controlled at each stage. 

The synergistic effect of adding a rebuming stage to 

wall-fued boilers equipped with low-NO, burners is 

projected to lower NO, emissions by BS much as 75%. 

burners on a 172~MWe wall-fued utility boiler. Westem bituminous coal is being used. 

The project site is Public Service Company of 

Colorado’s Cherokee Station, Unit No. 3, in Denver, 

CO. This project combines gas rebuming and low-NO, 

8-70 Pro@%m Update I991 EERIWaN-Fired Boiler 
Calendar Year 

1966 1969 ,990 1691 1992 1943 ,964 ,995 1996 1997 

3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1234 1 2 3 4 1234 1 234 1 2 3 4 i-2 

I Ii 

f 

t t” Project completedm”al repon issued a/94* 

Operation Mated 692’ Operation completed 3B4’ 

Const”,dlon completed 3a2’ 

Plant dedicated 9,Qt 

Deign completed 8/9t 

Ground breatdngkonstrucfion started 691 

Cmperaiiveagresment awardsd 10/1mo 

NEPA process completed Q/6190 

Environmental monitoring plan completed 7t2WQO 

DOE seleded projeM 12119i89 ‘Prolected date 

Project StatuslAccompllshments: 

Permitting activities are complete: all engineering drawings are complete and have been released for construction. Process specifications for the gas rebuming installation are complete and long lead-time items are on 

order. Construction began in mid-1991, and retrofit 

work proceeded during the scheduled August-October 

1991 boiler outage. Demolition of the old electrostatic 

precipitator and asbestos removal are complete. All the 

new boiler penetrations, including refractory and insulation, were installed on October 23, 1991. The new 

low-NOx burners also were installed during October 

1991. Construction work in November 1991 concentrated on installation of structural steel, ductwork, and 

fan foundations. The demonstration is expected to enter 

the operations phase in May-June 1992. 

Environmental Considerations: 

NEPA compliance has been satisfied by a memo-to-file 

approved on September 6.1990. The environmental 

monitoring plan was completed in July 1990. 

Assuming maximum commercialisation of gas 

reburning and low-NOx burners on a wall-fired boiler on 

* Can be retrofitted readily to existing units 

* Reduces NO, emissions by more than 70% 

. Suitable for use with a wide range of coats 

. Has the potential to improve boiler operability 

a national basis by 2010 relative to a no-action alterna- * Has the notential to reduce the cost of elecnicitv 

tive, NO, emissions could be reduced by 13%. The 

substitution of aas for coal results in a 10% reduction of 

SO, on a national basis. No change in liquid effluents or 

solid wastes is anticipated. (Source: CCT Programmatic 

Environmental Impact Statement) 

* Consists of dommerciatly available components 

* Requires minimal space 

Commercial Appllcatlon: 

Gas rebuming in combination with low-NO, burners is 

applicable to wall-fired utility boilers. The technology 

can be used in new and pre-NSPS wall-fired boilers. 

Specific features of this technology that increase its 

potential for commerciahaation arc as follows: 

Program update 1991 8-71 
LIFAC Sorbent Injection 

Desulfurization 

Demonstration Project 

Sponsor: 

LIFAC-North America (a joint venture between Tampella Keeler, a subsidiary of Tampella, Ltd., of Finland, 

and ICF Kaiser Engineers, Inc.) 

Additional Team Members: 

ICF Kaiser Engineers, Inc.-cofunder and project 

manager 

Tampella, Ltd.-cofunder and technology owner 

Richmond Power and Light- cofunder @old host utility 

Electric Power Research Institute-cofunder 

Peabody Coal Company-cofunder 

Black Beauty Coal Company-cofunder 

LaFqe Corporation- cofunder 

Location: 

Richmond, Wayne County, IN (Richmond Power and 

Light’s Whitewater Valley Station, Unit No. 2) 

Technology: 

LIFAC’s sorbent injection process with sulfur capture in 

a unique, patented vertical activation reactor 

Plant Capacity/Production:’ 

60 MWe 

of the SO, from flue gas and produce a dry solid waste 

product for disposal in a landfill. 

Pulverized limestone is pneumatically blown into the 

upper pan of the boiler near the superheater where it 

absorbs some of the SO, in the boiler flue gas. The 

limestone is calcined into calcium oxide and is available 

for capture of additional SO, downstream in the 

activation, or humidification, reactor. In the vertical 

chamber, water sprays initiate a series of chemical 

reactions leading to SO, capture. After leaving the 

chamber, the sorbent is easily separated from the flue 

gas along with the fly ash in the electrostatic prccipitatar. The sorbent material from the reactor and electrostatic precipitator will be recirculated back through the 

reactor for increased efficiency. The waste is dry, 

making it easier to handle than the wet scrubber sludge 

produced by conventional wet limestone scrubber 

systems. 

Project Funding: 

Total project cost $21,393,772 100% 

DOE 10,636,863 50 

Participants 10,756,909 50 

Project ObJective: 

To demonstrate that electric power plants-especially 

those with space limitations-burning high-sulfur 

Indiana coats. can be retrofitted successfully with the 

LIFAC limestone injection process to remove 75-85% 

The technology enables power plants with space 

limitations to use high-sulfur midwestem coals by providing an injection process that removes 7545% of the 

SO, from flue gas and produces a dry solid waste product suitable for disposal in a landfill. 

The process is being demonstrated at Whitewater 

Valley Station, a coal-fired power plant owned and 

operated by Richmond Power and Light and located in 

Richmond, IN. The 60-MWe Unit No. 2 is being 

retrofitted. The activation or humidification chamber 

is being located next to the boiler building near Unit 

No. 2. 

8.72 Program Update 1991 LIFAC 
cahld=?J Year 

1988 ,989 ,990 ,991 1992 1.9% ,984 1595 lSQ6 ,997 ,988 

3 4 1 2 3 4 1234 t 234 1 234 1 2 3 4 1234 1 2 3 4 ,234 1 234 12 

12l89 1 l/90 6/92 and Co~lruoUo 10/94 

n 

44 4 

kpera#w initiated 6~92 

Environmental monhrlng plan 3/92’ 

Preoperational tests initiated 1192’ 

ConstruClion completed 1192’ 

k$ 

I 

Projec3 completedWnal report issued 10/94’ 

aperation completed a/94’ 

Original design completed T/91 

Ground breaking/construction sttied 5/29191 

0, 

‘L 

~operative agreement awarded 11RO190 

EPA process completed 10/2&O 

WE selected projea 12119/89 ‘Projected date 

Project Status/Accomplishments: 

All original design activities are complete, Enhanced 

design features have been proposed and are under consideration. All plant tie-ins were successfully completed during the scheduled March 1991 outage. The 

balance of the LIFAC equipment can be installed without impacting plant operations. All long-lead procurement activities arc complete. Formal ground breaking 

for the new equipment occurred on May 29,199l. Construction is now in progress. The stan of operations has 

been delayed to mid-1992 primarily due to additional 

design and permitting requirements, including redesign 

of the humidification section of the activation reactor to 

improve process performance. 

Environmental Considerations: 

NEPA compliance has been satisfied by a memo-to-file 

approved on October 2, 1990. DOE has provided comments on the draft environmental monitoring plan. 

Assuming maximum commercialization, significant 

reductions of SO, (45%) are projected to be achievable 

nationally by 2010 with the LIPAC process relative to a 

no-action alternative. The LIFAC process has wide 

applicability as it can be retrofitted to many coal-fired 

boilers. (Source: CCT Programmatic Environmental 

Impact Statement) 

* It is less expensive to install than conventional wet 

flue gas desulfurization processes. 

+ It uses dry limestone instead of more costly lime. 

. It is relatively simple to operate. 

* It produces a dry, readily disposable waste. 

The benign waste material can be disposed of in a 

landfill along with the fly ash. The mat&al also may 

bc used as a road bed or excavation till material. 

Commercial use of the LIFAC by-product in the manufacture of const~ction materials is currently being 

investigated in Finland. 

Commercial Appllcatlon: 

This process is suitable for application to at1 coal-fired 

utility or industrial boilers, especially those with tight 

space limitations. The LIFAC process offers the following advantages: 

LIFAC Program Update 1991 8.73 
Commercial Demonstration of 

the NOXSO SO,/NO, Removal 

Flue Gas Cleanup System 

Sponsor: 

MK-Ferguson Company 

Additional Team Members: 

NOXSO Corporation-cofunder and technology 

supplier 

W. R. Grace and Company-cofunder 

Ohio Edison Company-cofunder and host utility 

Ohio Coal Development Office-cofunder 

Gas Research Institute-cofunder 

Elecbic Power Research Institute-cofunder 

East Ohio Gas Company-cofunder 

Location: 

Niles, Trttmbull County, OH (Ohio Edison’s Niles 

Station, Unit 1) 

Technology: 

NOXSO Corporation’s dry, regenerable flue gas 

cleanup process 

Plant Capaclty/Productlon: 

108 MWe 

PmJect Fundlng: 

Total project cost S66,249,696 100% 

DOE 33,124,848 50 

Participants 33J24.848 50 

Project Objecttve: 

To demonstrate SO, and NOx removal from a coal-fired 

boiler flue gas “sing the NOXSO process and to remove 

97% of the SO, and 70% of the NO, from the flue gas 

exhausted to the atmosphere. 

Technology/Project Description: 

The NOXSO process is a dry, regenerable system capable of removing both SO, and NOx in flue gas from 

coal-fired utility boilers. I” the basic process, the flue 

gas passes through a fluidized-bed adsorber located 

downstream of the precipitator; the SO, and NO, are 

adsorbed by the so&ant. The sorbent consists of spheri. 

cal beads of high-surface-area alumina impregnated 

with sodium carbonate. The cleaned flue gas then 

passes to the stack. 

The NOXSO sorbent regenerates with heating, 

which causes the NOx to desorb and partially decompose. The hot air containing the desorbed NOx is recycled to the boiler where equilibrium processes caue 

destruction of the remaining NO,. The absorbed sulfur 

is recovered from the sorbent in a regenerator where it 

reacts with methane at high temperature to produce a” 

offgas with high concennations of SO, and hydrogen 

sulfide (H,S). This offgas is processed in a Claus plant 

to produce elemental sulfur, a salable by-product. 

The process is expected to achieve SO, reductions 

of 97% and NO, reductions of 70%. 

The NOXSO process is being demonstrated at 

Ohio Edison’s Niles Station, Unit 1, a 108-MWe 

cyclone boiler. MK-Ferguson will design, consmxt, 

and operate a full-scale commercial NOXSO unit t” 

demonstrate process feasibility. The project is being 

structured so that &ta from the proof-of-concept facility 

at Ohio Edison’s Toronto Station can be available 

before the end of the project definition activity. 

8-74 Program Update 1991 MK-Ferguson Company 
Calendar Year 

,988 ,989 1990 1991 ,982 1993 1994 189s lsse ,987 ,698 

3 4 1234 1 2341234 123412341 2 3 4 1234 I 2 3 4 ,234 12 

12l89 3191 ?I94 l/Q7 

Precperational tesls lnltiated WQ4’ 

ConstNotlon Construcllon completed WQ4’ 

started 4lQ3’ 

Design completed 3/93’ 

Environmental monilorlng plan completed ID3 

NEPAprocess completed i/93’ 

Cooperative agreemeni awarded 31 l/91 

11 

T t 

f 

Operation initIaled l/94’ 

I 

Pro)ect completedllinal repoti 

issued 1197’ 

Opwatbn completed 1lhW 

DOE selected project 12119/89 ‘Projected date 

Project StatuslAccompllshments: Commercial Appllcatlon: 

The cooperative agreement was awarded on March 11, The NOXSO process is applicable for retrotitting exist1991. Evaluation is in progress on recent data and ing coat-fired power plants or for use in new facilities. 

results of the proof-of-concept development work essen- The demonstration is expected to use southeastern Ohio 

tial to establishing the &sign baseline. The participant and western Pennsylvania coal (3.2-3.5% sulfur averis proceeding with design: completion awaits data from age). The process is adaptable to coals with higher 

proof-of-concept work. sulfurcontent. 

Envlronmental Considerations: 

Environmental information is being compiled for use in 

the NBPA process. 

By 2010, national emissions of SO, could be reduced by as much as 48% and NO, by 11%. assuming 

masimum commercialization of this technology relative 

to a no-action alternative. Also, the process results in 

essentially no increase in solid waste and produces a 

salable by-product (sulfur). (Source: CCT Programmatic Environmental Impact Statement) 

Commercial-grade sulfur, a salable by-product, is 

produced. The technology is expected to be especially 

attractive to utilities that require high removal efficiencies for both SO, and NO, and/or need to eliminate solid 

wastes. 

MK-Fergwon Company Program Update 1991 8-75 
Integrated Dry NO, /SO, 

Emission Control System 

Sponsor: 

Public Service Company of Colorado 

Addltlonal Team Members: 

Elecnic Power Research Institute-cofunder 

Stone and Webster Engineering Corporation-engineer 

The Babcock &Wilcox Company-burner developer 

Fossil Energy Research Corporation-operational 

testing 

Western Research Institute-fly ash evaluator 

Colorado School of Mines-engineering research 

and testing 

Vendor (to be determined)-urea system provider 

Locatlon: 

Denver, Denver County, CO (Public Service Company 

of Colorado’s Arapahoe Station, Unit No. 4) 

Technology: 

The B&cock &Wilcox Company’s low-NO, burners, 

in-duct sorbent injection, and furnace (urea) injection 

Plant CapacltylProductlon: 

100 MWe 

Project Funding: 

Total project cost $26,477,878 100% 

DOE 13,238,939 50 

Participants 13,238,939 50 

Project ObJectlve: 

To demonstrate the integration of three technologies to 

achieve up to 70% reduction in NOx and SO, emissions: 

more specifically, to assess the integration of a downfired low-NOx burner with in-furnace urea injection for 

additional NO, removal and dry sorbent induct injection with humidification for SO, removal. 

8.76 Program Update 1991 

L 

Technology/Project Descrlptlon: 

All of the testing will use Babcock & Wilcox’s low-NOx 

XCL down-fued burners with over-fire air. These bumers conuol NOx by injecting part of the coal and part of 

the combustion air in an oxygen-deficient environment. 

Additioncd fuel and combustion air are introduced in a 

second stage to advance the combustion process. Additional air is introduced to complete the combustion 

process and further enhance NOx removal. The lowNO, burners ax expected to reduce up to 50% of the 

NO, and with added air, the system is expected to 

reduce NO, emissions by up to 70%. To reduce NO, 

emissions even further, in-furnace urea injection is 

being tested to determine how much additional NOx can 

be removed from the combustion gas. 

Two types of dry sorbents are being injected into 

the ductwork downsaeam of the boiler to reduce SO, 

emissions. Either calcium is injected upstream of the air 

heater or sodium or calcium is injected downstream of 

the air heater. Humidification downstream of the dry 

sorbent injection enables the electrostatic precipitator to 

maintain performance. Humidification aids SO, capture 

and lowers flue gas temperature and gas flow, which 

improves particulate collection efficiency. 

The three basic technology systems are being installed on Public Service Company of Colorado’s 

Arapahoe Station Unit No. 4, a 100-MWe down-fired, 

pulverized-coal boiler with roof-mounted burners. 

Public Service Company of Colorado E 

/ 
11194 

t 

A 

Operation InWed 7192 

DOE selected 

project 12/19/8g 

Construction completed T/92’ 

!I’1 

Design completed 7&Q’ Project compleled~inal rep00 issued 1 Y/94 

Design initiated 6190 Preoperational tests initiated 6192’ 11 

Operation complered 6194 

Environmental monitoring plan cOmpleted 12131191 

NEPA process completed 9127190 Ground breakingiconstruction rtalted WI191 

Cooperative agreement awarded 3/l ,191 

‘Projected date 

Project Status/Accomplishments: 

The cooperative agreement was awarded March 11, 

1991. Ground breaking ceremonies were held May 21, 

1991. Design activities continue on the low-NOx burners, humidification, and site utilities. Fabrication of the 

low-NOx burners has begun. Installation and checkout 

of the urea injection system has been completed. 

Baseline testing of the boiler without any modifications 

was completed in mid-December 1991. Baseline testing of the boiler with urea injection is scheduled to start 

in early February 1992 and continue for approximately 

one month. 

The Colorado School of Mines continues preliminary work on the test reactor. Construction started in 

mid-1991 and is expected to continue until mid-1992. 

Environmental Conslderatlons: 

NEPA compliance has been satisfied by the signing of a 

memo-to-file approved by DOE on September 27, 1990. 

The environmental monitoring plan has been prepared. 

SO, reduction is in the range of 55-75%. Although 

the volume of solid waste is considerably increased, it is 

dry, easily disposed of, and nontoxic. From a national 

perspective, a 38% SO, reduction is projected by 2010, 

assuming maximum commercialization of the sorbent 

injection technology. Urea injection should enhance 

NOx reduction, thereby increasing low-NO, burner 

impact on national reductions from the presently projected 11%. (Source: CCT Programmatic Environmental Impact Statement) 

Commercial Appllcatlon: 

Urea injection and sorbent injection are both applicable 

to most utility and industrial coal-fired units and can be 

renofitted with modest capital investment and downtime. 

Public Service Company of Colorado Program Update 1991 8-77 
CCT-IV 

Project Fact Sheets 
Corder0 Coal U 

I: 

grading 

Demonstration reject 

Sponsor: 

Cordero Mining Company 

Additional Team Members: 

Carbontec Wyoming Inc.-technology supplier 

Dahyland Power Cooperative-host utility 

Fluor Daniel, Inc.--engineer 

Location: 

Gillette, Campbell County, WY 

Technology: 

New fuel form using the Carbontec Syncoal process 

Plant Capacity/Production: 

1,200 tons/day of coal 

ProJect Funding: 

Total project cost $34,300,000 100% 

DOE 17,150,000 50 

Participants 17,150,000 50 

(Funding amounts reelecthose contained in the 

proposal and are subject to negotiation.) 

Project Objective: 

To demonstrate the Carbontec Syncoal process to 

upgrade high-moisture, low-sulfur, low-rank coals for 

use in power plants designed to burn higher Btu coals, 

and as a low-sulfur fuel for future power generation and 

industrial facilities. 

Technology/Project Descrlptlon: 

The Syncoal process converts high-moisture subbitumi- 

““us coal into a high-Btu, low-moisture, low-sulfur 

product by using heat to drive off moisture and to 

stabilise the physical properties of the product. Hot oil 

and flue gas serve to heat the coal and to keep it in an 

inert atmosphere during coal processing. The hot oil 

provides a protective film which seals the surface t” 

moisture as well as preventing surface degradation 

during handling. The flue gas drives off moisture and 

provides a relatively inert atmosphere to prevent 

oxidation of the coal during the treaunent process and 

until the product is cooled t” near ambient temperature. 

crushing, is diverted from the existing mine-coalhandling system to a feed silo. The coal is fed from the 

silo to a screening station where it is separated into 

three fractions: 2x1 in, 1x114 in, and 114x0 in. Each 

fraction is conveyed separately to the demonsuation 

plant on a dedicated conveyor. 

The 2x1-i” coal is fed to one of two identical 

dryers, and the 1x114-i” coal is fed to the other dryer. In 

these first dryers, the feedstock is heated while a 

mixture of hot fuel oil is sprayed on the coal as it passes 

slowly through the heater. ,The coal is carried between 

two wire mesh conveyors, permitting the excess oil to 

drain freely to a sump at the bottom of the heater. 

The project facility will be capable of producing A portion of the 1/4x0-i” coal is diverted to a feed 

250,000 tons&r of upgraded coal product. Coal bin, pulverized, and burned in the direct-fired tube 

feedstock, which has already undergone tw” stages of heater. The balance of the 1/4x0-i” feedstock is mixed 

8.80 Program Update 1991 Cordero Mining Company 
calendar bar 

1988 1989 ,990 1991 ,992 ,993 ,994 ,995 1996 1997 199* 

3 4 123412341 234 1234,234 t 234123412341234 12 

9191 9/92 

[ Preaward / 

t t 

bOE selecled 

projen 9/12191 

Cooperative agreement 

awarded 9192 

‘Projected date; milestones are sub@t lo negotiation. 

with the partially processed coal leaving the initial 

dryers. 

The combined mixture is conveyed to a dryer/ 

cooler, a rotary tray device which gently turns the 

product, exposing it to hot flue gas which drives off 

aore moisture. After passing through the upper, heated 

section of the dryer/cooler, the coal falls to the lower 

section where it is exposed to cooled flue gas from a 

condenser; the coal’s temperature is lowered to near 

ambient conditions. The finished product is then 

conveyed to a silo for storage. 

Cordero Mining Company plans to build the 

Sync& plant near its mine in Gillette, WY. 

Project Status/Accomplishments: 

The project is in negotiation. 

Environmental Considerations: 

Environmental information is being prepared for use in 

the NEPA process. 

Because the advanced coal conversion process will 

produce a coal with a very low sulfur content, high 

heating value, and stable physical/chemical characteristics, it could have significant impact on SO, reduction 

relative to the no-action alternative considered in the 

PEIS. 

desulfurization equipment. Moreover, plants that would 

otherwise be closed could remain in operation. 

Commercial Applications: 

This process has the potential to enhance the use of lowrank western subbituminous and lignite coals. It is 

expected that this upgraded coal product can be utilized 

by many midwestern and eastern utilities currently 

burning high-sulfur. high-rank, noncompliance coals to 

comply with CAAA of 1990 provisions. The processed 

coal would allow operation under more restrictive 

emissions guidelines without requiring derating of the 

units or the addition of costly flue gas desulfurization 

systems. Utilities are expected to find the upgraded fuel 

attractive because itwill be less costly to use than 

would be the construction and “se of flue gas 

Cordero Mining Company Program Updace 1991 S-81 
Self-Scrubbing Coal: An 

Integrated Approach to Clean 

Air 

Sponsor: 

Custom Coals Internation.aJ (ajoint ventore between 

Duquesne Ventures, a subsidiary of Duquesne Light 

Company, and Genesis Research Corporation) 

Addltlonal Team Members: 

Duquesne Light Company-cofunder and host utility 

Richmond Power &Light-host utility 

CC& Inc.-operator 

ICF Kaiser Engineers, Inc.-engineer “d constroctor 

Locatlons: 

Greensboro, Greene County, PA (advanced coalcleaning and magnetite plants) 

Springdale, Allegheny County, PA (combustion tests at 

Duquesne Light Company’s Cheswick Power Station) 

Richmond, Wayne County, IN (combustion tests at 

Richmond Power & Light’s Whitewater Valley 

Station, No. 2 boiler) 

Technology: 

Coal preparation using advanced physical coal cleaning 

and fine magnetite separation technology plus sorbent 

addition technology 

Plant Capaclty/Productlon: 

250 tons/br 

Project Funding: 

Total project cost $76,077,309 100% 

DOE 38,038,656 50 

Participants 38,038,653 50 

(Funding amounts reflect those contained in the 

proposal and are subject to negotiation.) 

Project Objective: 

To demonstrate advanced coal-cleaning unit processes 

to produce low-cost compliance coals that can meet full 

requirements for commercial-scale utility power plants 

to satisfy CAAA of 1990 provisions. 

Technology/Project Descrlptlon: 

An advanced coal-cleaning plant will be designed, 

blending existing and new processes, to produce from 

high-sulfur bituminous feedstocks, two types of 

compliance coals-carefree Coal and Self-Scrubbing 

coal. 

Carefree Coal is produced by crushing and 

screening run-of-mine coal and by using innovative 

dense-media cyclones and crystallized magnetite to 

remove up to 90% of thepyritic sulfur and most of the 

ash. Carefree Coal is designed to be a competitively 

priced, high-Btu fuel that can be used without major 

plant modifications or additional capital expenditures. 

While many utilities can use Carefree Coal to comply 

with SO, emissions limits, others cannot due to the high 

content of organic sulfur in their coal feedstocks. When 

compliance coal cannot be produced by reducing pyritic 

sulfur, Self-Scrubbing Coal can be produced to achieve 

compliance. 

The patented Self-Scrubbing Coal is produced by 

taking Carefree Coal, with its reduced pyritic sulfur and 

ash content, and adding to it sorbents, promoters, and 

catalysts. Self-Scrubbing Coal is expected to achieve 

compliance with virtually any US. coal feedstock 

through in-boiler absorption of SO, emissions. The 

reduced ash content of the Self-Scrubbing Coal permits 

8-82 Program Update 1991 Clrrtom Coals International 
Calendar Year 

,988 1489 ,990 ,991 1992 Ia93 1994 1695 1996 ,997 ,998 

3 4 1 2 3 4 ,234 1 234 1 234 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 ,234 12 

bOE selected 

project S/12/91 

Cooperative agreement 

awarded W2’ 

‘Projected dale; milestones are subject lo negollaticn. 

the addition of relatively large amounts of sorbent 

without exceeding the ash specifications of the boiler or 

overloading the electrostatic precipitator. 

A 250~ton/h* advanced coal-cleaning plant and a 

Z-tonihr magnetite production facility are being 

designed and constructed at a site in Greensboro. PA, 

owned by the Duquesne Light Company. The advanced 

coal-cleaning plant will manufacture Self-Scrubbing 

Coal and Carefree Coal. Two medium- to high-sulfur 

coals-Illinois No. 5 from Wabash County, IL, and 

Pittsburgh coal from Greene County, PA-will be used 

to prod&e Self-Scrubbing Coal. Carefree Coal will be 

made using Sewickley coal from Greene County, PA. 

The Pittsburgh and Sewickley coals will be combustion 

tested at Duquesne Light Company’s Cheswick Power 

Station located near Pittsburgh, PA; &Illinois No. 5 

coal will be tested at Richmond Power & Light’s 

Whitewater Valley Station No. 2 boiler located in 

Richmond, IN. 

Project Status/Accomplishments: 

The project is in negotiation. 

Environmental Conslderatlons: 

Environmental information is being prepared for use in 

the NEPA process. 

The technology produces coal products that cao be 

used to reduce a utility or industrial power plant’s total 

sulfur emissions 80-90%. 

Assuming maximum commercialization of SelfScrubbing Coal by the year 2010, SO, emissions 

nationally could be reduced 23%. (Source: CCT 

Programmatic Environmental Impact Statement) 

Commercial Applications: 

Commercialization of Self-Scrubbing Coal can bring 

into compliance about 164 million tons&r of bituminous 

coal that cannot meet emissions limits through conventional coal cleaning. This represents over 38% of the 

bituminous coal burned in SO-MWe or larger generating 

stations amoss the United States. 

Cusmm Coals Itiemationol Program Updare 1991 8.83 
Milliken Clean Coal 

Technology Demonstration 

Project 

Sponsor: 

New York State Electric &Gas Corporation 

Additional Team Members: 

Consolidation Coal Company-technical consultant 

Saarberg-H6lter-Umwelttechnik GmbH-technology 

supplier 

The Stebbins Engineering and Manufacturing 

Company-technology supplier 

NALCO FuelTech-technology supplier 

Electric Power Research Institute-cofubder 

Location: 

Laming, Tompkins County, NY (New York State 

Electric &Gas Corporation’s Milliken Station Units 1 

and 2) 

Technology: 

Flue gas cleanup using Saarberg-H6lter-Umwelttechnik 

(S-H-U) GmbH formic-acid-enhanced, wet limestone 

scrubber technology; NALCO FuelTech’s NOxOUT 

urea injection system; Stebbins tile-lined split module 

absorber: and heat-pipe air-heater system 

Plant Capaclty/Productlon: 

300 MWe 

Project Funding: 

Total Project Cost %158,607,807 100% 

DOE 64553,377 41 

Participant 94,054,430 59 

(Funding amounts reflect those contained in the 

proposal and are subject to negotiation.) 

Project Objective: 

To demonstrate at a 300-MWe utility-scale acombination of cost-effective and innovative emission reduction 

and efficiency improvement technologies, including the 

S-H-U wet scrubber system enhanced with formic acid 

to increase SO, removal in a Stebbins lined scrubber: 

urea injection for NOx removal; and a heat-pipe 

preheater. 

Technology/ProJect Description: 

The S-H-U wet flue gas desulfutization process is a 

formic-acid-enhanced, wet limestone process which 

results in very high SO, removal with low energy 

consumption and the production of commercial-grade 

gypsum. 

The flue gas desulfutization absorber is a Stebbins 

tile-lined split module vessel which has superior 

corrosion and abrasion resistance, leading to decreased 

life-cycle costs and reduced maintenance. The split 

module design is constructed in the base of the stack to 

save space and provide operational flexibility. 

The NALCO FuelTech NO%OUT system removes 

NOx by the injection of urea into the boiler gas. This 

facet of the project, in conjunction with other combustion modifications, will reduce NO, emissions and 

produce marketable fly ash: 

A heat-pipe air-heater system will be used with 

advanced temperatu controls to reduce both air 

leakage and the air heater’s flue gas exit temperature. 

Ultimate emissions reductions with increased boiler 

efficiencies will result. 

8-84 Program Update I991 New York Stare Elecrric & Gas Corporation 
I Wendar Year 

,988 ,988 ,990 1531 1992 1993 1994 1995 1996 1997 ,998 

3 4 t23412341 234 1 234 1 234 1 234123412341234 12 

9191 Q/92 

1 Preaward 1 

I 

WE selected 

project 9112191 

Coaperative agreement 

awarded 9192 

The project is designed for “total environmental 

and energy management,” aconcept encompassing low 

emissions, low energy consumption, improved combustion, upgraded boiler controls, and reduced solid waste. 

The system is being designed to achieve at least a 95% 

SO, removal efficiency using limestone while burning 

high-sulfur coal. NO= reductions will be obtained using 

selective non-catalytic reduction technology and 

separate combustion modifications. The system has 

zero wastewater discharge and produces marketable byproducts (e.g., commercial-grade gypsum, calcium 

chloride, and fly ash) to minimize solid waste disposal. 

New York State Electric &Gas plans to demonstrate these technologies at Units 1 and 2 of its Millie” 

Station located in Laming, NY, using Pittsburgh, 

Freeport, and Kittoning coals. 

Project Status: 

The project is in negotiation. 

Environmental Considerations: 

Environmental information is being prepared for use in 

the NEPA process. 

Assuming maximum commercialization of the 

S-H-U and NALCO processes on a national basis by 

2010 relative to a no-action alternative, the following 

impacts,are projected: 

* SO, reduction-38% 

Commercial Application: 

The S-H-U SO, removal process and the NALCO 

NOrOUT non-catalytic reduction technology are 

applicable to virtually all electric utility power plants. 

The high removal efficiency, up to 98%, for SO, will 

make the combination of these technologies, together 

with the tile-lined scrubber at the base of the exhaust 

stack, attractive for many applications. Elimination of 

solid waste by sale of the fly ash and zero wastewater 

discharge enhance the marketability of the technologies. * NOx reductio+l5% 

The significant reductions of SO, and Nor are 

projected to be achievable nationally because of the 

wide applicability of the technologies. In addition, 

because the fly ash may be salable, the technology 

potentially may produce no solid waste by-product. 

(Source: CCT Programmatic Environmental Impact 

Statement) 

New York State Elecrric & Gas Corporation Program Update 1991 S-85 
Project 

Sponsor: 

Sierra Pacific Power Company 

Additional Team Members: 

Foster Wheeler USA Corporation-engineer and 

The M.W. Kellogg Company-technology supplier 

Location: 

Reno, Storey County, NV (Sierra Pacific Power 

Company’s Tracy Station) 

Technology: 

Integrated gasification combined-cycle (IGCC) using 

the KRW air-blown, fluidized-bed coal gasification 

system 

Plant Capacity/Production: 

80 Mwe (net) 

Project Funding: 

Total project cost $340,726,600 100% 

DOE 170,363,300 50 

Participant 170,363,300 50 

(Funding amounts reflect those contained in the 

proposal and are subject to negotiation.) 

ProJect Objective: 

To demonstrate air-blown, fluid&d-bed IGCC technology incorporating hot gas cleanup; to evaluate a lowBtu gas combustion turbine; and to assess long-term 

reliability, availability, maintainability and environmentat performance at a scale sufficient to determine 

commercial potential. 

; 

a 

Technology/Project Description: 

Dried and crushed coal is introduced into a pressurized, 

air-blown, fluidized-bed gasifier through a lock hopper 

system. The bed is fluidized by the injection of air and 

steam through special nozzles into the combustion zone. 

Crushed limestone is added to the gasitier to capture a 

portion of the sulfur introduced with the coat as well as 

to inhibit conversion of fuel nitrogen to ammonia. The 

sulfur reacts with the limestone to form calcium sultide 

which, after oxidation, exits along with the coal ash in 

the form of agglomerated particles suitable for landfill. 

Hot, low-Btu coat gas leaving the gasifier passes 

through cyclones which return most of the entrained 

particulate matter to the gasifier. The gas, which leaves 

the gasifier at about 1,700 “F, is cooled to 1,050 OF 

before entering the hot gas cleanup system. During 

cleanup, virtually all of the remaining particulates are 

removed by ceramic candle filters, and final @aces of 

sulfur are removed in a fixed bed of zinc ferrite sorbent. 

The hot, cleaned gas then enters the combustion 

turbine. The combustion turbine is coupled to a 

generator designed to produce 56 MWe (gross). The 

heat from the combustion turbine’s exhaust gas is used 

to produce steam in a heat recovery steam generator. 

Superheated high-pressure steam drives a condensing 

Steam turbine-generator designed to produce about 

30 MWe (gross). 

Due to the relatively low operating temperature of 

the gasifier and as a result of the injection of steam into 

the combustion fuel stream, theNOx content of the 

exhaust gases is very low. 

8-86 Program Update I991 Sierra Pacific Power Company 
Cahdar Year 

,988 ,989 1990 1991 ,892 1903 1994 ,995 IS% ,997 1998 

3 4 1 2 3 4 1234 1 234 1 234 ,234 1 234 1 2 3 4 1234 1 234 12 

9/91 9/92 

Proaward 

I~ ili/ilii~ 

t 

WE selected 

projecl s,,ust 

In the demonstration project, a nominal 800 tons/ 

day of coal is converted into 86 MWe (gross); support 

facilities for the plant require 6 MWe, leaving 80 MWe 

for export to the grid. The project will be designed to 

run on western bituminous coal from Utah; operation 

with higher sulfur and lower rank coals also is being 

considered. The gasitier is being built at Sierra Pacific 

Power Company’s Tracy Station, located about 17 miles 

east of Reno, NV. 

ProJeq Status/Accomplishments: 

The project is in negotiation. 

Envlronmental Conslderations: 

Environmental information is being prepared for use in 

the NEPA process. 

Assuming maximnm commercialisation of IGCC 

technology on a national basis by 2010, relative to a noaction alternative, the following impacts are projected: 

. SO, reduction-37% 

Sierra Pacific Paver Company 

* NO, reduction-17% capability, high efficiency, environmental controllabil- 

* Solid waste reduction-5% 

* CO, reduction-6% 

(Source: CCf Programmatic Environmental Impact 

Statement) 

Commercial Application: 

In recent years, IGCC has become a rapidly emerging 

alternative for new electric generating plants. Such 

plants require 15% less land area than pulverized coal 

plants with flue gas desulfurization and exhibit suhstantially improved thermal efficiency and environmental 

performance. IGCC technology also can be used in 

repowering, where a gasitier, gas stream cleanup unit, 

gas turbine, and waste heat recovery boiler are added to 

replace the existing coal-fired boiler. The remaining 

equipment is left in place, including the steam turbine 

and electrical generator. Because of its advantages of 

modularity, rapid and staged on-line generation 

ity, and reduced land and natural resource needs, IGCC 

is a strong contender for widespread application for 

meeting future U.S. energy needs. Another important 

application for IGCC is cogeneration under PURPA’s 

Qualifying Facilities provisions. 

The performance potential of IGCC technology in 

its commercial configuration is characterized as follows: 

. SO, reduction-99% 

* NO, reduction-95% 

* Plant efficiency-up to 48% 

. Incremental power increase (repowering)-230% 

* Fuel flexibility-permits use of wide range of coals 

* Compactness-high process efficiency reduces space 

requirements per unit of energy generated 

. Modular construction-lends itself to economic 

increments of capacity additions to match load 

growth 

Program update 1991 8-87 
Toms Creek IGCC 

Demonstration Project 

Sponsor: 

TAMCO Power Paqners (a partnership between 

Tampella Power Corporation and Coastal Power 

Production Company) 

Additional Team Member: 

Institute of Gas Technology-technology developer and 

consultant 

Location: 

Coeburn, Wise County, VA (ANR Coal’s Toms Creek 

Mine) 

Technology: 

Integrated gasification combined-cycle (IGCC) “sing 

the Tampella U-Gas fluidized-bed gasification system 

Plant Capacliy/Productlon: 

107 MWe (55 MWe net coal-based) 

Project Funding: 

Total project cost $219,100,000 100% 

DOE 109,003,000 50 

Participant 110,097,MH) 50 

(Funding amounts reflect those contained in the 

proposal and are subject t” negotiation.) 

Project Objective: 

To demonstmte a” air-blown, fluid&d-bed gasification, 

combined-cycle technology incorporating hot gas 

cleanup for generating electricity and t” assess the 

system’s environmental and economic performance for 

meeting future energy needs. 

S-88 Program Update 1991 

Technology/Project Description: 

Coal is gasified in apressurized, air-blown, fluidizedbed gasifier in the presence of a calcium-based sorbent. 

Approximately 90% sulfnr removal is accomplished in 

the gasifier. Solids enuained in the gas are collected by 

cyclones in tw” stages. The low-Btu gas, which leaves 

the secondary cyclone at 1,800-1,900 “F, is cooled t” 

approximately 1,000 “F before entering the post-gasifies 

desulfurization unit where zinc titanate is used t” 

remove the bulk of the remaining sulfur in the gas. This 

is accomplished in tw” fluid beds. In the first bed the 

sulfur is absorbed by the zinc titanaw and the zinc 

sorbate is regenerated in the second bed. In the final hot 

gas cleaning step, a ceramic candle filter removes 

particulates. The gas is then sent t” the gas turbine 

combustor. 

Hot exhaust gases from the combustion turbine are 

directed to a heat recovery steam generator. The steam 

generated in the heat recovery generator is used both for 

driving a conventional steam turbine generator set 

producing additional electricity and for gas&r blast. 

A nominal 430 tons/day of bituminous coal will be 

converted into 55 MWe by a coal-gas-fired gas turbine. 

An additional gas turbine tired with natural gas and a 

heat recovery steam generator will be co-located at the 

demonstration site. The two gas turbines will be 

coupled with a single steam turbine t” generate a total of 

107 MWe and approximately 20,000 lbntr of steam for 

export tu a” adjacent coal preparation facility. The 

electric power will be sold t” a utility. 

The planned site for construction of the new IGCC 

power plant is Coebum, VA, at the Tams Creek Mine 

TAMCO Power Partners 
calendar Year 

,988 1989 1990 ,991 1992 1993 1994 1995 1996 1997 1998 

3 4 1 234 1 2 3 4 1’2 3 4 1 234 1 2341234 t 234 1 234 1 234 12 

9191 9192 

1 Prepward 1 

t DOE SBleCted 

projec( 9112191 

I 

I 

Coopsrarivs agreement 

awarded 9192 

‘Projected date: mileStoneS are subject to negotiation. 

owned by ANR Coal, a subsidiary of Coastal Power 

Production Company. 

Project Status/Accompllshments~ 

The project is in negotiation. 

Environmental Considerations: 

Environmental information is being prepared for use in 

the NEPA process. 

Assuming maximum commercialization of IGCC 

technology on a national basis by 2010, relative to a noaction alternative. the following impacts are projected: 

* SO, reduction-37% 

. Nor reduction-17% 

* Solid waste reduction-5% 

* CO, reduction-6% 

(Source: CCT Programmatic Environmental Impact 

Statement) 

Commercial Application: 

In went years, IGCC has become a rapidly emerging 

alternative for new electric generating plants. Such 

plants require 15% less land area than pulverized coal 

plants with flue gas desulfurization, and exhibit 

substantially improved thermal efficiency and environmental performance. IGCC technology also can be used 

in repowering, where a gasifier, gas stream cleanup unit, 

gas turbine, and waste heat recovery boiler are added to 

replace the existing coal-tired boiler. The remaining 

equipment is left in place, including the steam turbine 

and electrical generator. Because of its advantages of 

modularity, rapid and staged on-line generation 

capability, high efficiency, environmental conuollability, and reduced land and natural resource needs, IGCC 

is a strong contender for widespread application for 

meeting future US. energy needs. Another important 

application for IGCC is cogeneration under PURPA’s 

Qualifying Facilities provisions. 

The performance potential of IGCC technology in 

its commercial configuration is characterized as follows: 

. SO, reductioll-99% 

. NOx reduction-95% 

. Plant efficiency-up to 48% 

* Incremental power increase (repowering)-230% 

. Fuel flexibility-permits use of wide range of coals 

* Compactness-high process efficiency reduces space 

requirements per unit of energy generated 

* Modular construction-lends itself to economic 

increments of capacity additions to match load 

growth 

TAMCO Power Parrners Program Update 1991 8.89 
Micronized Coal Reburning 

Demonstration for NO 

Control on a 175-MWe” 

Wall-Fired Unit 

Sponsor: 

Tennessee Valley Authority 

Addltlonal Team Members: 

Duke/Fluor Daniel (partnership between Duke 

Engineering & Services, Inc., and Fluor Daniel, 

Inc.) -engineer and consmtctor 

MicroFuel Corporation-technology supplier 

R-C Environmental Services and Technologiestechnical consultant 

Location: 

West Paducah, McCracken County, KY (Tennessee 

Valley Authority’s Shawnee Fossil Plant) 

Technology: 

Advanced NOx control using micronized coal reburning 

combustion technology 

Plant Capacity/Production: 

175 MWe 

Project Funding: 

Total project cost $7,330,042 100% 

DOE 3,515,008 48 

Participants 3,815,034 52 

(Funding amounts reflect those contained in the 

proposal and are subject to negotiation.) 

Project Objective: 

To reduce NO, emissions by SO-60% using micronised 

coal as the reburning fuel combined with advanced coal 

rebuming technology. 

ASH TO DISPOSAL 

Technology/Project Descrlptlon: 

The technology is being applied to a 175-MWe frontwall-fued, dry-bottom furnace. The coal currently used 

to tire the furnace (low-sulfur bituminous coal) will be 

the reburning fuel. The reburning coal, which can 

comprise up to 30% of the total fuel, is micronised 

(80% below 325 mesh) and injected into the furnace 

above the main burner, the region where NO, formation 

occ”rs. 

Central to the project technology is the MicroFuel 

Corporation’s two-element MicroFuel system, which 

consists of a patented centrifugal-pneumatic MicroMill 

and an external classifier. The mill is capable of 

grinding coal into a fine powder without the mechanical 

attrition or roll crushing normally associated with coal 

mills. The MicroMill is being installed between the 

existing pulverizers and the microfine burners. 

Minonized coal has the surface area and combustion characteristics of an atom&d oil flame, which 

allows carbon conversion within milliseconds and 

release of volatiles at a more even rate. This uniform, 

compact cumbustion envelope allows for complete 

combustion of the coal/air mixture in a smaller furnace 

volume than conventional pulverized coal because heat 

rate, carbon loss, boiler efficiency, and NO, formation 

are affected by coal fineness. 

The combination of micronised coal, supplying 

30% of the total furnace fuel requirements, and advanced rebuming utilizing that requirement in conjunction with fuel/ah staging, provides flexible options for 

s-90 Program Update 1991 Tennessee Valley Authority 
I 

CC% selected 

proJea 9,12!91 

Cooperallve *grwne”l 

awarded 9,92’ 

‘Projected date: milestones are subject lo negotiation. 

significant combustion operations and environmental 

improvements. These options can prevent higher 

operating costs OI furnace performance derating often 

associated with conventional environmental contro1s. 

The Tennessee Valley Authority plans to retrofit 

the micronised-coal-rebuming technology to its 

Shawnee Fossil Plant located 10 milesporthwest of 

Paducah, KY. 

ProJect Status/Accomplishments: 

The project is in negotiation. 

Envlronmental Conslderatlons: 

Environmental information is being prepared for use in 

the NEPA process. 

Assuming maximum commercialization of this 

rebuming technology by the year 2010, NO, emissions 

can be reduced by 11%. (Source: CCT Programmatic 

Environmental Impact Statement) 

Commercial Applications: 

Micronized-coal-rebuming technology can be applied to 

cyclone-fired, wall-fired, and tangential-fuedpulverized 

coal units. The technology reduces NOx emissions by 

50 -60% with minimal furnace modifications and 

enhances boiler performance with the improved burning 

characteristics of micronized coal. 

micronized-coal-rebuming fuel and better pulverizer 

performance will increase overall pulwized fuel 

surface area for better carbon burnout. 

The availability of a coal-rebuming fuel, as an 

additional fuel to the furnace, solves several problems 

concurrently. Units that are “mill limited” from fuel 

switching would have mill capacity to reach their 

maximum continuous rating. Restoration of lost 

capacity, as a benefit to NO, reduction, can become :L 

very economic somce of generation. Reborn burners 

also can serve as low-load burners, and commercial 

units can achieve a turn down of 8:l on nights and 

weekends without consuming expensive auxiliary fuel. 

Existing pulverisers can be operated on a variety of 

coals with improved performance. The combination of 

Tennessee Valley Authority Pro&wn Clpdare I991 8-91 
Demonstration of Pulse 

Combustion in an Application 

for Steam Gasification of Coal 

Sponsor: 

ThermoChem, Inc. 

Additional Team Members: 

Weyerhaeuser Paper Company-host site 

Manufacturing and Technology Conversion 

International, Inc.--technology supplier 

Engineering Services, Inc.-constructor 

Locatlon: 

Springfield, Lane County, OR 

Technology: 

Advanced combustion using Manufacturing and 

Technology Conversion International’s (MTCI) pulse 

combustor 

Plant Capacity/Production: 

161 million Btu/br of medium-But fuel gas plus 

40,000 lb/hr of export steam 

ProJect Funding: 

Total project cost $37,333,473 100% 

DOE l&666,736 50 

Participants 18,666,737 50 

(Funding amounts reflect those contained in the 

proposal and are subject to negotiation.) 

ProJect Objective: 

To demonsnate the MTCI pulse combustor in an 

application for steam gasification of coal to produce a 

medium-Btu fuel gas from subbituminous coal. 

Technology/Project Description: 

The MTCI fluidized-bed gasifler incorporates an 

innovative indirect heating process for thermochemical 

steam gasification of coal to produce hydrogen-rich, 

clean, medium-Btu fuel gas without the need for an 

oxygen plant. The indirect heat transfer is provided by 

MTCI’s multiple resonance tube pulse combustor 

technology with the resonance tubes comprising the 

heat exchanger immersed in the fluidized-bed reactor. 

Heat transfer is 3-5 times greater than other indirectly 

heated gasifier concepts, allowing the heat transfer 

surface to be minim&d. 

expected to be 72% or more. In major commercial 

applications. char combustion and heat recovery 

operations can be included to enhance overall plant 

efficiency. 

Aqueous sodium hydroxide scrubbing is used to 

control SO, emissions. Scrubber overflow is utihzeo m 

the paper mill. 

The demonstratioin facility will be built at 

Weyerhauser Paper Company’s Containerboard 

Division mill in Springfield, OR. The fuel gas and byproduct steam produced in the demonstration facility 

will be consumed by the mill. Subbituminous coal from 

The product gas has a heating value of about Gillette, WY,‘will be used. 

161 million Btu/hr with a cold gas efficiency of 53% or 

more. The demonstration plant’s overall efficiency is 

8.92 Program Update 1991 ThernwChem 
Calendar Year 

1988 1989 ,990 1991 1992 1993 1994 1995 1996 1997 ,998 

3 4 1 2 3 4 1 2 3 4 ,234 1234,234 1 234 1234 1 2 3 4 ,234 12 

g/91 9192 

/ Prasward 1 

I 

t t 

bOE selected 

project 9,12191 

Cooprati”e agreement 

awarded g/92’ 

‘Projeded date: milestones are subject to negotiation. 

Project StatuslAccompllshments: 

The project is in negotiation. 

Environmental Considerations: 

Environmental information is being prepared for use in 

the NEPA process. 

The MTCI pulse combustion technology can be 

expected to significantly reduce SO,, NO,, and particulate emissions, compared to conventional technology, in 

industrial use. The largest reductions in emissions 

resulting from commercialization of the MTCI pulse 

combustion technology are expected to occm initially in 

the pulp and paper industry. In the demonstration 

application, NO, emissions reductions of 50-60% are 

expected. The use of aqueous caustic scrubbing should 

result in a 99% reduction of SO, emissions. 

Commercial Appllcatlons: 

The MTCI pulse combustion technology has a wide 

range of potential applications, including utility steam 

and power generation. This project is demonsuating the 

use of pulse combustion for steam gasification of coal in 

a majorpaper company’s indushial containerboard mill 

to produce medium-Btu fuel gas and by-product steam. 

The new technology will replace hog-fuel boilers 

currently in use. 

Potential applications of this technology in the pulp 

and paper industry are substantial. There are more than 

350 pulp mills, which produce 64 million tonslyr of 

pulp, and 600 paper mills in the United States alone. 

The processing of pulp results in the production of 

about 88 million tons of by-product black liquor. The 

current practice of using black liquor recovery boilers to 

produce steam and electricity is inefficient. Replacing 

these boilers with MTCI gasitiers would significantly 

improve the conversion efficiency. The estimated 

market for MTCI gasifiers in this application alone is 

28 units annually. 

ThernwChem Program Update 1991 8-93 
Demonstration of the Union 

Carbide CANSOLVTM at the 

ALCOA Generatipg 

G&ytoratlon Warrick Power 

Sponsor: 

Union Carbide Chemicals and Plastics Company Inc. 

Additional Team Members: 

Aluminum Company of America (ALCOA) Generating 

Corporation-host and cofunder 

Stone and Webster Engineering Corporation-engineer 

Locatlon: 

Newburgh, Warrick County, IN (ALCOA Generating 

Corporation’s Warrick Generating Station Unit No. 2) 

Technology: 

Flue gas cleanup using Union Carbide Chemicals and 

Plastics Company’s CANSOLV” regenerable flue gas 

desulfurization (FGD) system 

Plant Capaclty/Productlon: 

75 MWe 

ProJect Funding: 

Total Project Cost %32,715,000 100% 

DOE 16,357,500 50 

Participants 16,357,500 50 

(Funding amounts reflect those contained in the 

proposal and are subject to negotiation.) 

Project Objective: 

To demonstrate the CANSOLVTM regenerable flue gas 

desulfurization system to achieve SO,removal efticienties of at least 99%. 

c*NsoL” ir atradrmark Of ““km Cami& Chcmicds Md Plsstics 

Compsny Inc. 

s-94 Program Updare 1991 

* NOTE: ona of three stagfa.081 Of wbent inlsccnl 

Technology/ProJect Descrlptlon: 

In the CANSOLVTM process, untreated flue gas enters 

the process from a particulate control device, such as a 

electrostatic precipitator, where it is contacted first by 

water and then by an aqueous solution of the SO, 

absorbent, both introduced to the gas stream as ultrafine droplets through atomizing nozzles. Following 

each spraying section, mist elimination equipment 

removes the droplets from the gas stream, and after the 

last section, the treated gas is released to the chimney. 

The water loop removes any particulate matter 

remaining in the gas, saturates the gas, and absorbs any 

chlorides and fluorides. The SO, is scrubbed from the 

flue gas by contact with the absorbent solution. In the 

absorbent loop, rich absorbent laden with SO, is routed 

to the absorbent regeneration unit where, through the 

application of heat, the SO, is stripped from the 

absorbent. The SO, stream is convened to salable 

products appropriate to local market conditions and 

opportunities. A 1% slipstream is taken from the 

recirculating lean absorbent and treated in the absorbent 

purification unit to prevent the build-up of impurities. 

An advanced FGD technology, the CANSOLVM 

process is capable of SO, capture rates over 99%. The 

demonstration project is using Indiana high-sulfur 

bituminous coal, with a sulfur content of about 3.4%. 

ALCOA Generating Corporation’s Warrick 

Generating Station Unit No. 2, located in Newburgh, 

IN, will be retrofitted with a newly designed and 

constructed CANSOLVTM scrubber facility capable of 

treating 50% of the flue gas from the unit. 

Union Carbide Chemicals and Plastics Company 
Calendar Year 

1988 1989 1590 1981 ,892 ,993 1994 1995 ,996 1997 1998 

3 4 1 234 1 2 3 4 1234 1 234 1 2 3 4 1 2 3 4 t 2 3 4 1 2 3 4 ,234 t2 

9191 9/w 

1 Prsaward ( 

bcE selecled 

project g112191 

Cooperative agreement 

awarded 9192’ 

Trojeaed date: milestones are subjea to negotiation. 

Project Status/Accomplishments: particularly advantageous where high-sulfur coals are 

The project is in negotiation. used. 

Environmental Conslderatlons: 

Environmental information is being prepared for use in 

the NEF’A process. 

Assuming maximum commercialization of the 

CANSOLV” process, a 48% reduction of SO, could be 

achieved nationally by 2010 relative to the no-action 

alternative considered in the CCT Programmatic 

Environmental Impact Statement. This significant 

reduction of SO, is attributable to an average 

conservative 90-9596 SO, removal capability for the 

CANSOLV” process and its wide potential applicability. It is a regenerable process in which the SO, from 

the gas stream is recovered for conversion to salable 

products. In the Warrick demonsuation, anhydrous 

(dry) liquid SO, is being captured and sold to 

neighboring SO, distributors for resale. Because the 

absorbent is recirculated and regenerated, the process is 

The CANSOLVw process generates minimal 

solid OI liquid wastes for disposal. Solids recovered by 

an in-duct prescrubber are those that pass through the 

precipitators and are directed to the existing ash 

handling system. 

Commercial Application: 

The CANSOLVTM process is attractive for both new 

and retroftt utility and indusaial applications. 

The process is designed to operate as an in-duct 

scrubber system, without the need for costly scrubbing 

vessels. Regeneration occurs in relatively small vessels 

requiring a minimal amount of space. Consequently the 

process potentially is applicable to the many spaceconstrained facilities. CANSOLVTM may be integrated 

effectively with other NO, and particulate control 

systems to provide for overall emission control. 

Union Carbide Chemicals and Plastics Company Progmm Updaie 1991 8.95