COAL Clean Coal Technology 

TECHNOLOGY Demonstration Program 

Program Update 1990 

(As of December 31,199O) 

U.S. Department of Energy 

Assistant Secretary for Fossil Energy 

February1991 
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 

The Babcock 81 Wilcox Company--cofunder and pilotscale testing 

Electric Power Research Institute-cofunder 

Electric Power Technologies, Inc.-field testing 

Ex~I~-EASE Systems Inc.-expert system 

architecture developer 

University of North Dakota, Energy and Minerals 

Research Center-bench-scale testing 

Alabama Power Company-host utility 

Duquesrte 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 site 

Public Service of Oklahoma-host utility 

Location: 

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

Homer City, Indiana County, PA (Homer City, Unit 2) 

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

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

Bayport. Washington County, MN (King Station) 

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

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

Springdale, Wes!moreland County, PA (Cheswick 

Station) 

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

Congressional District: 

Windsor, CT, 1st U.S. Congressional District 

Homer City, PA, 4th U.S. Congressional District 

7-s Program Updare 1990 

Alliance, OH, 16th U.S. Congressional District 

Wilsonville, AL, 2d U.S. Congressional District 

Bayport, MN, 6th US. Congressional District 

Gulfport, MS, 5th U.S. Congressional Disuict 

Oologah, OK, 3d U.S. Congressional District 

Springdale, PA, 18th U.S. Congressional District 

Grand Forks, ND, 1st US. Congressional District 

Technology: 

CQ. 11~‘s coal quality expert (CQE) computer model 

Plant CapactlylProductlon: 

Full-scale testing will tie place at six utility sites 

ranging in size from 250 to 880 MWe. 

Project Funding: 

Total project cost %17,382,258 100% 

DOE 8,691,129 50 

Participants 8,691,129 50 

Project Objective: 

To demonstrate an expert system that will run on a 

personal computer and provide coal-burning utilities 

with a predictive tool to assist in the selection of 

optimum.qualiiy coal for a specific boiler based on 

operational efficiency and environmental emissions. 

Technology/Project Description: 

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

will be used to develop algorithms for inclusion 

into an expert computer model. Utilities may use the 

ABB Comburfion Engineering and CQiCQEModel 
Calendar Year 

1988 1989 ,990 1991 ,992 1993 ,994 1935 ,995 1997 1998 3 4 I 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 23412341 234123412 

I Design and Construction 

I @eralion initiated 8BO 

I ( 

Project completedflinal repon ikswd 12193’ 

Environmen~4 moniloring plan completed 7131190 Operation compleled W33’ 

cooperative agreement awarded 6/l 4180 

NEPA process completed 4/27/90 

I DOE s&aed pr*a x&9,88 

information to predict the operating performance of 

coals not previously burned at a particular facility. 

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: Watson, Unit 4 (250 MWe), 

Gulfport. MS; Gataon. Unit 5 (880 MWe). Wilsonville. 

AL; Northeastern. Unit 4 (445 MWe), Oologab, AL: 

Homer City, Unit 2 (600 MWe). Homer City, PA; King 

(560 MWe), Bayport. MN; and Cheswick (500 MWe), 

Springdale, PA. 

testing. Bench- and pilot-scale testing, begun in late 

1990, will continue into early 1991. 

Six large-scale field tests will consist of burning a 

baseline coal and an alternate coal over a Z-month 

period. The baseline coal, the one currently used as 

fuel, will be used to characterize the operating performance of the boiler. The alternate coal, a blended OT 

cleaned coal of improved quality, will be burned in the 

boiler for the remaining test period. 

Environmental Conslderatlons: 

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

approved on April 27, 1990. 

The baseline and alternate coals for each test site 

will also be burned in bench- and pilot-scale facilities 

under similar conditions. The alternate coal will be 

cleaned at CQ, Inc., to determine what quality levels of 

clean coal can be economically produced and then 

ransported to the bench- and pilot-scale facilities for 

testing. All data from bench-, pilot-, and full-scale 

facilities will be evaluated and correlated to formulate 

algorithms that will be used to develop the model. 

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

and NO, emissions can be significantly reduced on a 

national basis relative to a no-action alternative. The 

expert system *ill enable coal-fired utilities to select the 

optimum quality coal for their specific boiler to reduce 

SO, and NO, emissions. 

The project will provide a computer model, “Coal 

Quality Expert,” that will run on a personal computer 

and predict reliably and inexpensively’the operating 

performance of coals not previously burned at a facility. 

Project Status/Accomplishments: 

?he first of six field tests was conducted in August 1990 

at Public Service of Oklahoma’s Northeastern Unit 4. a 

445-MWe tangentially fired supercrilical unit commissioned in 1980. Comparative test bums of two coals 

were made to assess coal quality impacts on boiler perforounce and emissions. The two coals were a blenU of 

10% Oklahoma and 90% Wyoming and a blend of 30% 

Oklahoma and 70% Wyoming. Oklahoma coal has 

been cleaned and shipped to the pilot and bench sites for 

Commercial Application: 

The CQE system is applicable to all electric power 

plants and indusuial/institutional boilers that bum coal. 

The CQE will predict the operational and emission 

reduction benefits of using cleaned coal. Following the 

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

the United States and abroad. 

MB Comblotion Engineering and CQICQE Model Program Update 1990 7-9 
LIMB Demonstration Project 

Extension 

Sponsor: 

The B&cock & Wilcox Company 

Additional Team Members: 

Ohio Coal Development Office-+ofunder 

Consolidation Coal Company-cofunder and 

technology supplier 

Ohio Edison Company-host utility 

Locatlon: 

Lorain. OH (Ohio Edison’s Edgewater Station) 

Congressional District: 

13th U.S. Congressiona’Disaict 

Technology: 

The Babcock & Wilcox Company’s limestone injection 

multistage burner (LMB) system 

Consolidation Coal Compaoy’s Coolside duct injection 

of lime sorbems 

Plant Caqaclty/Pr0ductlon: 

104 Mwe 

ProJact Funding: 

Total project cost $19404,940 100% 

DOE 7.597.026 39 

Participants 11.807.914 61 

Project Objective: 

To demonstrate, with a variety of coals and sorbems. the 

limestone injection multistage burner (LIMB) process as 

a retmit system for sbmtltane~us control of sulfur and 

nitrogen oxides in the combustion prows. and that 

LIMB can achieve up to 6046 NO, and SO, reductions. 

Additionally, using the Coolside duct injection process, 

to test alternate sorbent and coal combinations to 

demonstrate induct sorbmt injection. upstream of the 

7-10 ProgmmUpdaeI990 

hmnidiier and precipitator, to show SO, removal of 

up to 80%. 

Technology/Project Descrlptlon: 

The LIMB process is expected to reduce SO2 by 

5&60% by injecting dry sorbent into the boiler at a 

point above the burners. The sorbem then travels 

through the boiler and is removed along with fly ash in 

the existing particulate removal equipment. either an 

elecuostatic precipitator (JISP) or a baghouse. Humidification of the flue *as before it enters an ESP is necessary to maintain normal BSP operation and to enhance 

S0,removs.l. ‘Ihis project will test combinations of 

three coals. each with a different sulfm content (1.8%, 

3.0%. and 3.8%). and four sorbenu. The tesu are 

expected to provide commercial-scale opaating and 

tnaintenane data on a variety of ooal/sorbem combinations with diverse SO, removals and costs. Both 

limestone and hydrated lie (c&.itic and dolomitic) 

sorbents will be tested. 

In the Coolside process, dry sorbem 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 benetiiu, it 

is expected that humidification equipment will be part 

of most, if not all. commercial Coolside applications. 

The spent sorbent is aIs0 collected with the fly ash as 

in the LIMB process. Reduction of SO, by 5@-80% 

is expected. 

B&WtLIMB 
Both demonstrations will use the same low-NO, commercially available hydrated lime, a 20 QF approach 

burners, which control NO” by injecting the coal and to adiabatic saturation, and an additive to the humidifipart of the combustion air simultaneously so that the cation water at a 0.2~1 sodium-to-calcium ratio. These 

first of the combustion reactions takes place in an results favorably confirmed the previous pilot-scale 

oxygen-deficient environment. The balance of the testing. The hydrated lime source affected SO, removal. 

combustion air is introduced in a second stage to 

complete the combustion process. Staged combustion 

has been found to reduce NOx emissions by SO-M)%. 

This project is being conducted at Ohio Edison’s 

Edgewater Plant in Lorain, OH, on a commercial, 

Babcock &Wilcox Carolina design, wall-fired 

l&t-MWe boiler. 

Recycling spent sorbent significantly increased sorbent 

utilization. The project clearly achieved its objectives 

to retrofit a Coolside system to au existing boiler and 

reduce significantly the amount of SO, emitted witbout 

any adverse effects on the system. A complete report of 

this testing effort will be published in early 1991. 

Environmental Conslderatlons: 

NFPA compliance was satisfied with a memo-to-file 

signed on June 2, 1987. 

Because of wide market application, SO, and NO, 

reductions of 30% and 11% respectively by 2010 are 

projected on a national basis, assuming maximum commercialization of the technology. (Source: CCT 

Programmatic F.uviromnental Impact Statement) 

Calendar Year 

,986 1987 ,988 1X.9 1990 1991 ,992 1993 1994 1995 19% 

3 412341 23412341234123412341234,234,234,2 

A 

‘i [ I’ 

1 t--- Prqect completed~%nal repoti issued 7/w’ 

operation io#ialed 10189 Cqeratbn completed 4191 

Design compleled 10189 

Ground 

Construction mmpleled 9189 

breakingi PreDperational Tests iniliated 7189 

wnSlrUCtiDn 

started 8126187 Environmental monitoring plan completed 1 O/19/88 

NEPA process completed WZ87 

Cooperalive agreement awarded 6RSB7 

DOE selected prop* 7mm 

’ Projected dafe 

Project StatuslAccompllshments: 

The project has completed testing of the Cwlside 

process and is in the middle of the LIMB extension 

testing, which nms until April 1991. 

Coolside testing results indicate that this process 

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

sulfur coal at a 1: 1 calcium-!o-sulfur molar ratio using a 

LIMB extension testing has shown similar SO, 

removal capabilities with the most reactive of the limes 

tested to date and heavy humidification (a 20 “F 

approach to adiabatic saturation). NO, removal has 

been in the 40-50% range throughout both Coolside and 

LIMB testing. 

Commercial Application: 

Sorbent injection is applicable to most utility and 

industrial coal-tired units and can be retrofitted with 

modest capital investment and downtime. 

?he LIMB and Coolside processes both provide an 

alternative to conventional wet flue gas desulftrization 

(FGD) processes. Both are expected to be substantially 

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

important in retrofit applications. 

E & W/LIMB Program Up&e 1990 7.11 
Arvah B. Hopkins Circulating 

Fluidized-Bed Repowering 

Project 

sponsor: 

Tbe City of Tallahassee 

Addltlonal Team Members: 

Foster Wheeler Energy Corporation-technology 

supplier 

Bechtel Power Corporatiorr-engineer and constructor 

City of Tallahassee-host utility 

Locatlon: 

Tallahassee, Leon County, FL (Awah B: Hopkins 

station unit 2) 

Congressional District: 

2d U.S. Congressional Disuict 

Technology: 

Foster Wheeler’s atmosphericirculatittg fluidized-bed 

combustor (ACFB) 

Plant CapacltylPrcduction: 

250 Mwe 

Project Funding: 

Total project cost $276.791.974 100% 

DOE 14,733,833 27 

Participant 202,058,141 73 

Project Ob@tive: 

To demonstrate ACFB at 250 MWe, repmsendng a

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

verify expectations of the technology’s economic. 

environmental, and technical performance in the 

repmming of an existing oil-/oattral gas-fred boiler at 

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

data necessary for evaluating a 250-MWe ACFB as a 

7-12 P?O8?Mt &&,,C 19w 

commercial alternative to accomplish greater than 90% some of the so&at, is carried out of the combustor, 

SO, removal, to reduce NOx emissions by 60%. and to collected in a particle separator, and recycled to the 

achieve a steam efficiency of 88%. lower porTion of the wmbusta. 

Technology/Project Description: 

In this project, the circulating fluid&d-bed combustor 

operates at atmospheric pressure. Coal, primary air. and 

a solid sorbat, such as limestone. are in~odttced into 

the lower portion of a water-wall combustor where 

initial combustion occurs. Combustion takes place at 

relatively low tempemtwes of 1,500-1,600 “F. As coal 

particles decrease in size due to combustion and breakHeat is removed by the water walls as well as by 

superheaters located witbin the circulating loop encompassing the combustor, particle separator, and solids 

recycle leg. Combustion gases that leave the particle 

separator are cooled in a convective back pass containing additional superheaters, water walls, and an 

economiser. The steam produced is sent to the steam 

turbine to generate power. Sulfm is absorbed by the. 

smbent and mtnoved with the ash. 

age, they are canied higher in the combustor to an area 

where secondary air is intrcdwed. As the coal particles 

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

Tbis project involves repowering an existing steam 

electric power plant by using a scaled-up ACFB boiler. 

A coal-fued ACFB steam-generating system will 
Calendar Year 

lsea wsg 

:“3 

1891 1se2 i 1994 loss 1898 1997 lsas 

3 4 1 2 3 4 1 4 1 23472 3 4 1 2’“, 4 1 2 3 4 1 2 3 4 1 2 3 4 I 2 3 4 1 2 

DOE sekcted 

project 6R3/8g 

cunstruaion stalled 5Aw 

I 1 

T cdgn canpleted smz* 

NEPAproces~wmpleted l2W* 

Environmental monitoring plan completed 6.01’ 

Cooperative agreement awarded ,1/3090 

I 

c.smonstration 

completed 

11ia7* 

Constmctim and start-up completed 11195’ 

Operation inliated 11~35’ 

‘Projected date 

replace the existing oil-/gas-f& steam-generating 

system used to drive a steam tttrbiie. The existing 

tubime generator and the balance of the equipment are 

being retained. 

Prolect Status/Accompll!8hments: 

The cooperative agreement was awarded November 30, 

1990. Design is under way. 

Environmental Considerations: 

Tbe environmenti information for the NEF’A compliance process has been submitted by the participant. 

The following zue projected impacts from maximum commercialization of the ACFB technology on 

a national basis by 2010 relative to a no-action 

dtellWiVe: 

. SO, reduction-M% 

- NO, reduction-17% 

. Solid waste increase. but in a dry, granular 

form amenable to some by-product markets 

l co, redlmio~5% 

(Source: ccc Programmatic Envlmmnemal Impact 

statement) 

- Lower capital costs 

* Reduced SO, and NO, emissions at lower costs 

* Higher combustion efficiency 

. Dry, granular solid waste 

Commercial Application: 

ACFB technology Ius good potential for application in 

both the industrial and utility sectors, whether for use in 

repowerbtg existing plants or in new facilities. Coal of 

any sulftu umtent can be used. and any type or size of a 

coal-fued boiler can be repavered. Because an 

existing plant area is used, and coal- and waste-handling 

equipment as well as: steam turbine equipment are. 

retained, the life of a plant can be extended. 

ln iu commercial coniigotation, ACFB technology 

offers several potemlal benefits when compared to 

conventioMl pulverized coal-tired sys*ems: 

Progrum update I990 7-13 
Advanced Cyclone 

Combusfor with Integral 

pof;;61N!trogen, and Ash 

Sponsor: 

Coal Tech Corpaation 

Addltlonal Team Members: 

Commonweahh of Pennsylvania Energy Development 

Pettnsylvaoia Power and Light Company--supplier of 

test coals 

Tampella Keeles-host site 

Williamspon, Lycomhtg County, PA (Tampella Keeler 

boiler matmfxhuing plant) 

Congressional Dlsttlct: 

17th U.S. Congressional District 

Technology: 

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

Plant Capadty/Productbn: 

23 million Bh& 

Project Funding: 

Total project cost 

DOE 

Participants 

Project Objectlve: 

$984,394 100% 

490,149 50 

494,245 50 

To detnonsbxte that an advanced cyclone combostor 

can be retrofitted to a small industrial boiler and that it 

can simuhaneously remove up to 90% of the SO, and 

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

NOx by up to 100 pptn. 

Technology/Project Description: 

Coal Tech’s horizontal cyclone combustor is internally 

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

air, and snrbmt 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 &worable 

to particle retention in the combustor. Secondary air is 

wed to adjust the overall combustor stoichiometry. The 

ceramic liner is cooled by the secondary air and 

maintained at a tempemmre high enough to keep the 

slag in a liquid. free-flowing state. The secondary air is 

preheated by the combustor walls to attain efficient 

combustion of the coal particles in the fuel-rich 

combustor. The tine coal pulverization allows combustion of approximately two-thirds of the coal particles 

near the cyclone wall, with the balance beiig burned on 

or near the wall. This improves combustion in the fuelrich chamber, as well as slag retention. The slag 

contains over 90% of the ash and sorbent fed to the 

combustor. For NO, control, the combustor is operated 

fuel rich, with fti combustion taking place in the 

boiler furnace, to which the combustor is attached. 

The project features combustion of dry pulverized 

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

retrofitted on a 23million Btojhr oil-designed package 

boiler located at the Tampella Keeler plant in 

Williamspat, PA. Pamsylvania bituminous coals 

containing from 1% to approximately 4% solfur were 

tested to demonstrate that this combostar is capable 

of burning most U.S. coals in an environmentally 

acceptable manner. 

7-14 PrO8W, f&d& 19% Coal Tech 
I 

calendar Year 

3’9884 ,987 ,988 ,889 1891 ,692 wB3 ,984 19s ,896 

1 2 3 4 1 2 3 4 I 2 3 4 1 :=3 4 t 2 3 4 t 23412 3 4 1 2 3 4 1 2 3 4 1 2 

I 

Cmsbudbn completed <l/87 I Project ccmpbtedninal report issued Z/S1 ’ 

Operalkln hlliamd 1 m7 Operation completed 5180 

Environmental monitoring plan mmpletsd 9f22@7 

Ground breakhglmnstructbn sttwted ,s9,%7 

Design completed ?/87 

cooperative agreement awarded 3r2m7 

NEPA prccess complefed 3RW87 

I 

WE s&&d pmjed 7/24/86 

‘Prolecled dale 

ProJect Status/Accomplishments: 

Coal Tech completed design, constmction. and operation by year-end 1990 and will issue a f& repon in 

February 1991. The Coal Tech combastor was 

operated for appwbnately 1,000 hours 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 tbc 30-month teat period. ‘Ihe test 

results indicate that Coal Tech’s air+x&d, coal-tired, 

slagging combastor can successfully (1) be retrofitted to 

and operate efficiently over a wide stoichiometric range 

on previously oil- or gas-fued boilers, (2) reduce coalderived NO, emissions by approximately 75%. 

(3) remove up to 90% of the coal slag at the combastor 

slag tap upstxam of the toiler, and (4) capture and 

remove with the slag about 10% of the sulfur contained 

in the coal. Coal Tech also has test r<s indicating 

that over 80% sulfur removal can be achieved through a 

combiition of sorbent injection at and downsueam of 

Coal Tech 

the combastor. Coal Tech has concluded that this novel 

air-cooled combustm design concept is sound and that 

sufficient design and operational information has been 

obtained from this CCT demonstration to scale up to 

loo Mh&a/hr. 

EnvIronmentat Considerations: 

NEF’A compliance was satisfied by a memo-to-file 

approved on March 26.1987. 

The advanced cyclone combastor is expected to 

Commercial Application: 

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

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

including high-salfur coals. This combastor can be 

used to rmoflt boilers that currently opaare with oil or 

gas firing, due to the combustor’s ability to effectively 

eliite cc+ solids upstream of the boiler and 10 

control NO, and SO,emissions. 

reduce emissions as follows: 

- SO2 reduction-l@% 

* NO, reduction-67% 

The SO, emissions arc reduced through sorbcot 

injection. Additionally, up to 90% of the ash is 

removed with this pmccss. 

Program update 1990 7-15 
Nucla CFB Demonstration 

Project 

Sponsor: 

Colorado-ute Electric Association, Inc. 

AdditIonal Team Members: 

Pympower Corporatio~technology supplier 

Technical Advisory Group @otemial usas)-cofunder 

Elecnic Power Research Institute-technical support 

Location: 

Nucla, Montmse County, CO (Nucla Station) 

Congreeelonal Dletrict: , 

3d U.S. Congressional District 

Technology: 

Pympmwer’s annosphericirculating fluid&d-bed 

combustion (ACFB) system 

Plant Cepecity/Productlon: 

1lOMwe 

ProJect Fundlng: 

Total project cost $54,087,CO0 100% 

WE 19.920,WO 37 

Participants 34,167,ooO 63 

Pro@3 Objective: 

To demonstrate ACFI? at a scale of 110 MWe, represming a 2: 1 scale-up from previously demm!suated 

cspacities. To verify expectations of the technology’s 

economic, environmental, and technical performance in 

a repowering application at a utility site. To accomplish greater than 90% SO, removal, to reduce NO, 

emissions by 60%. and to achieve an effYency of 34% 

in a repowuing mode. 

Technology/Project Deecrlption: 

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

as limestone. Combustion takes place at relatively low 

The Nucla circulating fluidized-bed system operates at 

tempemues that limit NOx formation. Calcium in the 

s&em combines with SO2 gases. and solids exit the 

atnmsphaic pressure. In the combustion chamber, a 

combustion chamber and flow into a hot cyclone. The 

stream of air fluidizes and entrains the bed material, 

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 

suhk capture efficiency. Heat in the ilue gas exiting 

the hot cyclone is recovered in the ewnomizer. The 

Colorado-Ute Nucla Station were replaced with a single 

flue gas passes through an electmstatic precipitator 

ACFB steam generator capable of driving a new 

74-MWe turbine generator. Extraction steam from this 

where the @calate matter is removed. The steam 

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 

generated in the ACFB is used to generate powa. 

and to demonstrate the suitability of ACFB technology 

for repowering and life extension of existing units. 

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

7-16 Program update 1990 COlOrUdO-Ule 
calendar Year 

,987 1988 1989 1990 ,991 I!?%? ,993 ,994 1995 ,996 ,997 

34123412 3412341 2 3 4 , 234123412 3412341 2 3 4 1 2 

1018 

DC 

t t ;o~~tivw agreement awarded Projed compleled 3191’ 

I Cpratlon te* prcgram inliatod WI7188 

NEPA process completed 4114133 

Environmental monitoring plan completed 2R7i33 

)E s&cmd pmjed ion7187 

‘Projacted date 

Project Status/Accomplishments: 

The project was initially scheduled to be completed in 

August 1990 following a 2.year operational test 

program. Although some 12.500 hours of testing were 

accomplished, the test program could not be completed 

within the original schedule because of numerous plant 

oUta8eS for repairs and plant moditications that were 

mostly unrelated to the ACPB technology. Therefore, 

testing was extended to March 1991 to complete the 

program and detamine the OptiNN Operating Conditions and performance with high-salfur coals. 

To date, Nucla has met all NSPS requirements with 

better than 90% sulfur capture. has typically achieved 

NO, emissions less than 80 ppm. and has removed 

99.9% of the particulates. Cost information is promising, with estimated capital cost at $873/kW and 

operating cost at $2O/MW. This is competitive with 

pulverized coal units that arc not limiting emissions 

as significantly as Nucla. Heat rates have averaged 

11,900 BtiWh, somewhat in excess of those 

projected. Future testing will determine optimum 

operating parameters to maximize thermal efficiency. 

Envlronmental Considerations: 

NEPA compliance was satisfied April 14, 1988, with a 

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

less land area for disposal than conventional scrubbez 

sludge. 

(Source: CCf Programmatic Envimntnental Impact 

Statement) 

Commercial Appllcatlon: 

ACFBs have gF potential for both the industrial and 

utility sectors in rcpowaing existing coal-fned plants or 

constructing new facilities. In rcpowcring applications, 

ACFB can increase capacity by an increment of appmximately 15%. Coal of any suhin content can be used. 

Because any type or size of boiler can be repowcred by 

ACFB using the existing plant area coal- and wastehandling equipment, and steam Nbine equipment, the 

life of the plant can be extended. Ben&u of ACFB 

include 90% SO, reduction, -0% NO, reduction and 

control of pollutants at lower costs than are offered by 

existing technologies. 

The following impacts arc projected from maximum commercislization of the ACPB technology on 

a national basis by 2010 relative to a no-action 

alternative: 

- so, reductiox-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 altcmative uses, such as consmxtion aggregate. and requiring 

Program Update 1990 7-17 
Enhancing the Use of Coals 

by Gas Reburning and 

Sorbent Injection 

Sponsor: 

Energy and Fnvironmental Research Corporation 

Additional Team Members: 

Gas Research htstitute--cofundcr 

State of Illinois, Department of Energy and Natural 

Resources-cofunder 

Illinois Power Company-host utility 

City Water. Light and Power-host utility 

Central Illinois Light Company--hosr ut#ty 

Locations: 

Hennepin, Pttmatn County, IL (Illinois Power Company, 

Hennepin Plant) 

Sptingfteld, Sangatnon County. IL (City Water, Light 

and Power. lakeside Station) 

Congresshal District: 

Hezmepin, IL, 17th U.S. Congressional District 

Sprlngfteld. IL. 20th U.S. Congressional Disuict 

Technology: 

Energy and Envimnmentel Research Corporetiott’s gas 

rebuming end sorbent injection process 

Plant CapacltylProduotlon: 

Hennepin site: tangentiaJ1y fired 80 MWe (nominal) 

Springfield site: cyclone-fued 40 MWe (nominal) 

Project Fundlng: 

Total project cost $29.998.253 Km% 

DOE 14.998.253 50 

Participants 15,m,ooo 50 

Project Objeotlve: 

To demonstrate gas rebwning to attain 60% NO, 

reduction along~witb sorbeat injection to capntre 50% of 

the SO, on two different boiler contiguationx tangentially and cyclone fued. 

Teohnology/Propol Deaoriptlon: 

Gas rebuming is a postcombustion technology that is 

being developed primarily for the removal of NO,. $ 

this process, 8045% of the fuel is coal and is supplied 

to the main combustion zone. The remaining 15-2046 

of the fuel, generally natural gas or a hydrocarbon. 

bypasses the main combustion zone and is injected 

above the main burners to form a reducing zone in 

which NO, is converted to nitrogen. A calcium 

compound (sorbem) is injected in the ic& of dry. fme 

perliculates above the rebttming zone in the boiler or 

even further dovmsueam. The calcium compounds to be 

tested will be CaCO, (calcium carbonate) and Ca(OH), 

(lime). This project will demonstrate the gas rebuming 

and sorbent injection process on two separate boilers 

representing two different ftig contigurations, a 

tangentially fved 80-MWe boiler and a cyclone-fired 

40MWe boiler. 

The project is expected to achieve 60% NOx 

reduction and 50% SO, reduction on different boiler 

cmfigttmtions at power plants burning high-sulfur 

midwestem coal. 

The project will be conducted at the Illinois Power 

Company plant near Hennepin, IL, and the City Water. 

Light and Power plant in Springfield, IL. 

7-18 Program update 1990 EERIGas Reburning and Sorbeti Injection 
Calendar Year 

1988 1987 ,988 ,989 1530 ,991 1992 1993 1994 19% ,996 

3 412341234123412341234123412341234123412 

7186 7187 

, Preaward 1 Design and Consl~ 

DOE selecfed 

NEPA process completed, 

Springlield 6125/W 

Design completed. both sties 8189 - 

invironmental monbring plan completed, Hennepin 1011519- 

tttt t +-. P,o,ecr completedhal report issued 8193 

I 

I L Operation completed, Springfield 12192 

Operation completed. Hennepin 3192’ 

Operahn initiated. Springfield 6191’ 

Constnrclion mmpleted. Springfield 5191’ 

Conslruction compkred Hennepin 1290 

Operalion initiated, Hennepin 12190 

ConstrUction stalled, Springtield e@o 

mslruction started. Hennepin 1190 

~~ironmental monitoring plan completed, Lakeside 11115189 

’ Projected date 

Project Status/Accomplishments: 

Permitting and engineering design efforts were 

completed in 1989 for the three original project sites, 

thus providing a more exact definition of project 

requirements for the sites under consideration. In 1990 

plans to use the third site (near Bartonville, IL) were 

suspended. Construction activities for the tangentially 

fired boiler at the Hennepin site were completed in 

December 1990. Operation activities at the Hennepin 

site also began in December 1990. Construction has 

begun at the cyclone-fired site at Springfield, and 

significant progress has been made. 

Environmental Considerations: 

NEPA compliance for the two active demonstration sites 

has been satisfied: 

* Hennepin site-memo-to-tile approved on 

May 9.1988 

. Springfield site--environmental assessment approved 

and finding of no significant impact issued on 

June 25, 1989. 

Assuming maximum commercialization, significant 

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

projected to be achievable nationally by 2010 with enhancement of the use of coals by gas rebuming end 

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 retrofitted to many coal-fired 

boilers. (Source: CCT Programmatic Environmental 

Impact Statement) 

Commercial Application: 

Gas rebuming and sorbent injection is the unique 

combiition of these two separate technologies. The 

commercial application for these technologies, both 

combined and separately, extends to both utility 

companies and industry in the United States end abroad. 

In the United States alone, these two technologies can 

be applied to over 900 pre-NSPS utility boilers; 

additionally the technologies can be applied to new 

utility boilers. With 60% NO, 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 sulfur coals without exceeding 

emission limits for NOx and SO, 

EERlGos Reburning and Sorbed injection Program Updare 1990 7.19 
Prototype Commercial Coal/ 

Oil Coprocessing Plant 

sponsor: 

Ohio Clean Fuels, Inc. 

Additional Team Members: 

Stone and Webster Engineering Company--engineer 

and constructor 

Hydrocarbon Research. Inc.-technology owner 

Ohio Coal Development Office-cofunder 

Location: 

Warren, Tmmbell County, OH 

Congressional District: 

17th U.S. Congressional District 

Technology: 

Hydrocarbon Research’s c&oil coprocessing using 

ebullated-bed catalytic hydrogenation 

Plant Capaclty/Productlon: 

About 11,750 barrels/day of liquid product processed 

from 800 tons/day of high-solfur coal 

Prolect Funding: 

Total project cost $225,674.805 100.0% 

DOE 45,ccO,ooo 20 

Participanu 180,674,805 80 

Project Dbpxtlve: 

To constitute a prototype commercial application of 

coal/oil copmcessing to process high-solfur. highniuoge~ bituminous coal and peuoletun residuum to 

produce a clean-bunting liquid fuel. 

7-20 PlO8rOnr Update 1990 

TechnologylProlect Description: 

The project is intended to be a grass-roots facility; 

meaning that it is a self-sustaining, folly integrated 

chemical process facility. Coal is received and prepared 

by crashing and fiie grinding and made into a coal/oil 

slurry by being blended with the heavy Cold Lake crude 

oil. T%is slurry is then presswized and raised to 

reaction temperature and, along with a hydrogm gas 

swam, is fed to the ebullated catalyst-containing 

process wactors where the coal conversion takes place. 

The resulting mixture is then dqxessurized, and the 

liquid products are separated from the heavy, solidscontaining stream The hydrogen used in the process is 

produced by a conventional steam-reforming process 

that oses natural gas as its feedstock. The liquid 

products generated can be used diitly as a boiler fuel 

or as a refinery feedstock for further upgrading to higher 

value products such as gasoline. The project will also 

produce propane. butane, salfur, and ammonia as useful 

by-products. The low-value solidscontaining stream 

can either be cornbusted on site to generate steam for 

process use or sold for direct use such as an aggregate 

for making concrete. 

The prototype plant originally was proposed for a 

site in Warren, OH. It would process 800 tons/day of 

coal plus sufficient residuum to yield 11.750 ban&/day 

of clean distillate products. However. relocation of the 

project is under consideration in an effort to improve the 

economics and attract a host facility. 

Ohio Clean Fuels 
Calendar Year 

,986 ,987 1988 19*9 ,990 ,991 ,992 ,993 ,994 ,995 ,996 

3 4,234,234,2341234i2341234,234,234,23412 

7166 12187 w91 

I I 

Cooperative agreement awarded 12/15187 

DOE selected project 7E4186 

Decision on project restructuring 6.631’ 

' Projected date 

Project Status/Accomplishments: 

Since &me 1990, most of the project activities have 

been placed on hold pending the securing of a host 

facility for the project. All of the ongoing activities 

are focused on identifying such a host. No DOE 

cost-sharing has been provided for any activities 

SinceJune 1.5, 1990. 

Design activities were initiated in December 1987 

and have progressed through completion of a preliminary process design. A process development unit 

(PDU) scale test program using the design Ohio coal 

and Cold Lake crude oil was successfully completed to 

confirm the basic process performance at design 

condilions. An alternate operating condition, known as 

once through (no recycle). performed surprisingly well 

and indicated that additional testing would be desirable 

and would serve to improve the overall economics of 

the process. Studies also showed favorable economics 

for integrating the process with an electric power utility 

to achieve air pollution control, when compared to 

Ohio Clean FwLr 

pulverized coal/wet flue gas desulfurization or 

fluidized-bed technology and a high-conversion oil 

refinery that generates a variety of liquid fuels. Also, 

a comprehensive coprocessing technology assessment 

coal ash and fines that can be readily disposed of in 

landfills. (Source: CCT Programmatic Environmental 

Impact Statemenr) 

was completed. Reports on these studies will be issued Commercial Application: 

as part of the project. 

Environmental Considerations: 

Environmental data for the NEPA compliance process 

have been compiled; however, further work is on hold 

pending site selection. 

The following impacts are projected for coal/oil 

coprocessing on a national basis by 2010 assuming 

maximum commercialization of this technology: 

. SO, reduction-9G% 

. NO, reduction-60% 

. Reduction in metals in petroleum residuum-95% 

The solid waste produced by this process consists of 

The coprocessing process can be designed to generate a 

variety of liquid products depending on a particular 

customer’s needs. The process can be deployed as a 

stand alone coal/oil refinery or integrated with an 

elecuic utility or oil refinery. Current views are that the 

most economic application is the integrated oil refinery 

approach. which makes the best use of the liquids 

handling systems and supporting facilities already in 

place at such a facility; product disrribution would also 

be simplified. 

Program Update 1990 7.21 
Tidd PFBC Demonstration 

Project 

Sponsor: 

lb Ohio Power Company 

Additional Team Membsrs: 

American Electric Power Service Corporationdesign, conauoction, and management 

ASEA B&cock-technology supplier 

Ohio Coal Development Office-cc?mder 

Locfdlon: 

Brilliao~ Jefferson County. OH (Ohio Power 

Company’s Tidd plant) 

Congressional Dlstrlct: 

18tbU.S. Congressianal District 

-reohnology: 

ASBA Babcock’s presswized fluidixd-bed combustion 

(PFBC) system 

Plant Capaclty/Productlon: 

70 Mwe 

Prolect Fundlng: 

Total project cost $167,5OO,ooO 100% 

DOB 6o,zoo,ooo 36 

Participants 107.300.oDo 64 

FTO~ Objective: 

To demonsuate PFBC at a 70-MWe scale, qresendng 

a 5: 1 scale-up from the pilot plam facility; to verify 

expectations of the tccbn010gy*s ecooomic. environmemal. and technical performance in a eombiied*ycle. 

repowering application at a utility site; and to accomplii greater than 90% SO, removal, NO, emission level 

of 0.2 1bMMBto. and an &ciency of 38% in a 

repowering mode using the existing steam system. 

Technology/Project Descrtptlon: 

The ASEA Babcock PFBC technology uses a pressorizcd bubbling floidized bed operating at 175 lblu2 atm. 

Presstuizcd combustion air is supplied by the gas 

turbine compressor. In the PFBC. the air fluidizes the 

bed material, which consists of fuel (a coal-water paste), 

coal ash. and dolomite sorbem. The hot combustion 

gases exiting the bed vessel with entrained ash particles 

pass tbmugh 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 NTbine is cooled in a waste heat recovery step and cleaned 

further in w electrostatic precipitator prior to discharge 

into the atmosphere. Pressurized boiler feedwater is 

convertexl to superheated steam in the tubes in the boila 

zone of the pressure vessel. The steam exits at 

1,335 1bW atm and 925 “F and passes through a steam 

turbine to produce 58 MSVe. The. dolomite in the Lxd 

reacts with the sulfur to form calcium sulfate, a dry, 

granular material, whlcb is discharged with the ash for 

disposal or by-product recovery. The bed temperature 

of 1,600 “F reduces the formation of NO-. 

The project will entail the replacement of the Unit 1 

boiler at the Tidd facility with The PFBC system and the 

addition of the gas cycle. The existing steam turbine, as 

well as condensate and feedwater systems. will be 

refwbisbcd for use with the demonstration. 

7-22 Progrm update 1990 The Ohio Power Company 
calelldw Year 

,988 ,887 

a’-3 

1889 1891 1895 wm 

3 4 1 2 3 4 1 4 1 2 3 4 I Z-3 4 1 2 3 4 1 :“3 4 1 *-33 4 1 *‘“, 4 1 2 3 4 I 2 

Envimnmental moniloring plan 

completed 7,10/87 

g-=$~lg.¶l~~~ 

EPA process completed 3JyS7 

I 

operation inliated 2191’ 

Ccnstmcticm and atad-up completed 291’ 

C-sign mmpleted 12/31/89 

I 

Demonstration completed 2M’ 

I DOE saledad projed 7R4B6 

‘PrOjected date 

Project Statue/Accomplishments: 

Project conshuctlon was completed in late 1990, and 

elecbicity was successftdly generated for the iirst time 

on December 6,199O. with the plant operating in a 

cotnbiied.~ycle mode. Start-up is prweeding. and 

operation is expected to begin in February 1991. The 

unit is in the preoperational test phase. and the various 

systems me being checked out in preoperation for fall 

operation. 

Much in tbe way of capital cost, design, and consUuction information has been learned and will be 

applied to the Spom and other fatare projects. A 

topical report, Tidd: The Nation’s First PPBC Combined-Cycle Demonstration, covering the information 

learned through the design and early ponion of construction was published in March 1990. 

Envlronmental Conalderatlons: 

NEPA compliance has been satisiied with a mcmc-tofile approved March 5.1987. 

The Ohio Power Compiany Program update 1990 7-23 

commarcialization of the PFBC technology on a national 

The following impacts are projected from maximum 

b&s by 2010 relative to a no-action alternative: 

- so* redwJion--48% 

. NO, reductio~z-17% 

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

more amenable to alternative uses, such as 

conshuction aggregate, and requiring less land area 

for disposal than conventiooal scrubber sludge 

because of modlllaz construction capability, PFBC geneming planu will permit utilitis to add increments of 

(lm MW) and large Q 400 MW) plants. In fact 

capacity economically to match load growth and to 

reduce utility fwcing reqlir~eots. plant life can be 

extended by repowcring with PFBC using the existing 

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

steam turbine equipment. 

(source: ccl- Programmatic Envirollm~tal Impact 

Statement) 

Commercial Appllcatlon: 

Combined~ycle PFFtC permits use of a wide range of 

coals, including high-salfar coals. It can bc used to 

repaver oil- and gas-f& boiler units, to repower coalfucd powcrplanf& and to build new PFBC units. 

Combiied-cycle PFBC technology appears to be best 

suited for electric utility applications for medium 

The pelformanw paemial Of PFEZC technology in 

its commercial configuration is characteri& below: 

* so, reduction-95% 

. NO, reduction+-80% 

* Plant effUency-up to 45% 

* Incmmenral power increase--ul% 

* Fuel flexibility-permits use of wide range of coals 

- Compacm-high process efficiency reduces space 

requirem~ts pa unit of energy generated 
Advanced Coal Conversion 

Process Demonstration 

Sponsor: 

Western Energy Company 

Additional Team Member: 

Stone and Webster Engineering Company-engineer 

and constmctor 

Location: 

Colsuip, Rosebud County. MT (adjacent to Western 

Energy’s Rosebud Mine) 

Congressional District: 

2dU.S. Congressional District 

Technology: 

Western Energy Company’s advanced coal conversion 

process for upgrading low-rank subbihuninous and 

lignite coals 

Plant Capacity/Production: 

45 to”s/hr of coal product 

Project Funding: 

Total project cost $69,ooO,ooO 100% 

DOE 34.500.000 50 

Participants 34,500.ooo 50 

Project Obiectlve: 

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

moisture content as low as 1%. sulfur content as low as 

0.3%. and a heating value up to 12,COO BN/lb. 

Technology/Project Deecrlptlon: 

This project will demonmate an advanced thermal coal 

drying process coupled with physical cleaning techniques to upgrade high-moisture, low-rank coals to 

produce a highquality, low-sulk fuel. The coal will 

be processed through two fuidized-bed reactors that 

will remove loosely held water and then chemically 

bound water. carboxy groups. and volatile sulfu 

compounds. After drying, the coal will be put through a 

deep-bed suatifier cleaning process to effect separation 

of tie. ash. 

coal product with a moisture content as low as 1%. 

sulfu content as low as 0.3%, and heating value up to 

12,000 Btu/lb. 

The 45-tonshr unit will be located adjacent to a 

unit train loadout facility at Western Energy Company’s 

Rosebud coal mine in MT. Although the demonstration 

plant will be one-tenth the size of a commercial facility, 

the process equipment will be at commercial scale 

because a full-sized commercial plant will have multiple 

prwess trains. 

The project. if successful. will eobance low-rank 

westem coals, usually with a moisture content of 

25-55%. sulfur content of 0.5-l .5%, and heat& value 

of 5,5C@-9,OOU Bm/lb by producing a stable, upgraded 

7-24 Program Update 1990 Western Energy Company 
Calendar Year 

1888 1989 1s30 1991 1882 1993 ,994 1995 ,896 ,997 ,998 

3412341234123412341234123412341234, 2 3 4 1 2 

12/89 

~ 

1 

~$O;lecwd proed 

sign and Construction 10/92 9B5 

/ ( construction completed 3/W 

Cpxarbn intiiated 10/92* 

Precprational tests initiated 9192 

Envlr~nmental monitoring plan completed 11191’ 

Ground breakin@mnslruction staded 3191’ 

Design completed 3191’ 

NEPA process completed ZB1’ 

L-Qerative agreement awarded BR1190 

op.mtion compl*ted 9195 

Project completedflinal report issued 9195’ 

‘Projected date 

Project Status/Accomplishments: 

The cooperative agreement was signed by DOE on 

September 21.1990. Design work is ongoing. A 

subcontract has been signed with Stone and Webster 

Engineering Company for major engineering work. A 

short-duration process demonstration run was accomplished at Western Energy’s pilot plant in Butte, MT, to 

verify preliminary process designs. 

On December 12.1990. Western Energy am~mtnced 

that is ha joined with the NRG Group. a nonregulated 

subsidiary of Northern States Power Company based io 

Mimteapolis, MN, to demonstrate and commercialiw 

the technology. This clears the way for cxmstmction to 

begin in early 1991. with operation expected in 1992. 

Envlronmental Conslderatlons: 

An envirottmental assessment and fading of no 

significant impact have been prepared and are being 

reviewed by DOE. 

Because the advanced coal conversion process will therefore. will be attractive to utilities because the 

produce a coal with a very low suifu content. high upgraded fuel will be less costly to use than would the 

heating value, and stable physical/chemical chamcteris- consmxtion and use of flue gas desulfmizuion equiptics, it could have significant impa~l on SO* reduction mm. This will allow plants that would otherwise be 

relative to a no-action alternative. closed to remain in operation. 

Commercial Appllcatlon: 

Western Energy’s advanced coal conversion process 

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

subbituminous and lignite coals. Many of the power 

plants located throughout the upper midwest have 

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

coals. Presently, most of these plants bum Illinois 

Basin high-sulfu coal. Processed coal would be an 

ideal low-sulfur coal substitute for these and other 

plants. because it will allow operation under more 

restrictive emissions guidelines without requiring 

denting of the units or the addition of costly flue gas 

desulftui7.ad0” systems. weaern Energy’s process 

western Energy company Program Update 1590 7-Z 
CCT-II 

Project Fact Sheets 

J 
Combustion Engineering 

IGCC Repowering Project 

Sponeor: 

ABB Combustion Engineering. Inc. 

Additional Team Members: 

City Water, Light and Power-wfande~ and host utility 

State of Il!inois. Depamnent of Energy and Natural 

LocatIon: 

Spri@el& Sangamon County, IL (City Water, Light 

and Power’s Lakeside Station) 

Congreaslonal Dletrlct: 

20th U.S. Congressioml District 

Technology: 

ABB Combustion Engine&g’s integrated gasification 

combined-cycle (IGCC) system 

Plant Capaclty/Productlon: 

65 MWe 

Projeci Fundlng: 

Total project cost $270,700@0 10046 

DOE 129.357.204 48 

Participants 141342.7% 52 

Prolect Obiectlve: 

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

two-stage entrained-flow coal gasifies with limestone 

injection and the moving-bed zinc ferrite hot gas 

cleanup system; to evaluate a kinetic coal exhuda; and 

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

potential. 

7-28 Plognun update 1990 

STEAMNRBlNE 

Technology/Project Deecrlptlon: 

Pressurized pulverized coal is pneumatically uansponed 

to the gasifier. The gasifies essentially consists of a 

bottom combastor section and a top redactor section. 

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

of the combustor allows molten slag to flow into a 

wata-iilled quench tank. 

The raw, low-Btu gas and char leave the gasifies at 

approximately 2.ooO OF and are reduced in temperature 

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

by water spray prior to gas cleanup. C!bar in the gas 

stream is captured by a bigh-cfficiency cyclone, as well 

as by subsequent fme particulate removal systems, and 

recycled back to the g&tier. 

A newly~developed process is being used to 

remove sulfur from the hot gas: a moving bed of zinc 

ferrite sorbeat and a limestone sorbent injection system 

provide in-bed desulfarization. Pardculate emissions 

are removed from the coal-handling system and gas 

stream by a wmbiition of cyclone separators and 

baghouses. and a high percentage of paniculates are fed 

back to the gasifier for more complete reaction and 

ultimate removal with the slag. 

The cleaned lowdtu gas is muted to a combincdcycle system for electric power production. Appmximately 40 MW are generated by a gas turbine. Extracted air from the gas turbine is used to meet the highpm.wre air requirements of the gasifier and the zinc 

ferrite desulfuizxion system. Exhaust gases from the 

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

bottoming cycle to generate sn additional 25 MWe. 

ABB Combwtion EnginewinglIGCC 
ICalendarYW 

3-4 

2’8893 

1 last 1892 lses ISQS 

4 I :“, 4 

1 

2 3 4 

1 

2 3 4 1 :"3 4 1 2'8w3 4 1 2 3 4 1 2’9883 4 1 

2 1997 3 4 

t 2 

con81Nclbn smw.l Hf3l' 

vironmmtat montming plan cmpleied 10~1' 

EPA pmcess mmpleted 4M’ 

@wmpbl6d l/86' 

Canstru&n completed lM* 

Operatbn initiated ‘M’ 

WE seleded proled %28/88 C-xQeralive ag- law& llRhg0 

The demonsuaticm project is convfating 600 tons/ 

day of coal low 65 Mwe. This is being accomplished 

&rough the hwallation of an enttaincd-flow coal gasifies 

and the integration of a curendy deactivated 25-MWe 

steam turbine with a 40-MWe gas tarbii at City Water. 

Light and Power’s Lakeside Station located in 

SHingfield IL. 

ProJecl Status/Accomplishments: 

The cooperative agreement was awarded on Novanba 

20.1990. 

Preliinary design and project defiition activities 

are under way. These are projected w be completed by 

Novmba 1991 when the start of construction is 

pm&. 

Envlronmental Conslderatlona: 

The pardcipant ls preparing cnvlmmnental htfortnation 

required by DOE for the process. 

Assunlng tnaximutn cotnmexcialization of the meam cleanup unit, gas turbine. and waste heat recovIGCC technology on a national basis by the year 2010 cry boiler are added to replace the existing coal boiler. 

relative w a no-action altcmatlve. the following impacts ‘Ihe remabdng equipment is left in place, including the 

3x projected steam turbine and electrical generator. 

* so2 reduction-37% 

* NOI redttction-17% 

. Solid waste reduction-5% 

* co, reduction-6% 

(SotlIce: ccr Programmatic E.nvitonmental Impact 

Statement) 

Commercial Application: 

In mm years. IGCC has become. a rapidly emerging 

altentative for new eleculcity generating plants. IGCC 

plants require 15% less land area dun pulvetized coal 

plants with flue gas desulfcrization. IGCC technology 

also can be used in repowering, where a gesifier. gas 

The performance potential of IGCC technology in 

its commercial configuration is chamcterlzed as follows: 

. SO, reduction-99% 

. NO, reduction-9596 

- Plant efftciency-up to 48% 

. Incremental power increase-230% 

* Fuel flexibility-permits use of wide range of coals 

* Compacmcss-high process efficiency reduces space 

requirements pa unit of energy generated 

* Modular consbuction-lends irself to economic 

addition of capacity incretnents to match load 

growth 

ABB Combwtian EngineeringlKCC Program Up&e 1990 7-29 
WSA-SNOX Flue Gas 

Cleaning Demonstration 

Project 

Sponsor: 

ABB Combustion Fngineering, Inc. 

Addltlonal Team Members: 

Ohio Coal Development Office-zofunder 

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. Tntmbull County, OH (Ohio Edison’s Niles 

Station, Unit No. 2) 

Congressional Dlstrkt: 

17th U.S. Congressional Disuict 

Technology: 

Haldor Topsoc’s WSA-SNOX catalytic advanced flue 

gas cleanttp system 

Plant Capaclty/Productlon: 

35~MWe equivalent slip-stream from a 115~MWe boiler 

Project Fundlng: 

Total project cost 

DOE 

Participanu 

$31,438.408 10096 

15,719,200 50 

15.719.208 50 

Pro@3 Objective: 

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

that WSA-SNOX technology will catalytically retnove 

95% of the NO, and SO, from flue gas and produce a 

salable by-product of concentrated sulfaric acid. 

7-30 Program update I990 

TechnologylProlect Descrlptlon: 

In the WSA-SNOX process, the stack gas leaving the 

boiler is cleaned of fly ash in a high-efficiency fabric 

filter baghouse to minimize the cleaning frequency of 

the sulfutic acid catalyst in the downstream SO, 

converter. The ash-free gas is reheated. and NO, is 

reacted with small quantities of ammonia in the fust of 

two catalytic reactors where the NO, is converted to 

harmless nitrogen and water. The SO2 is oxidized to 

SO, in a second catalytic convener. The gas then 

passes through in a novel glass-tube condenser called 

the WSA Tower, which allows SO, to hydmlyze to 

concentrated sulfuric acid. 

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

to remove 95% of the NOx and SO,fmm flue gas and 

produce a salable sulfuic acid by-product. This is 

accomplished without the use of sorbents and with no 

waste by-products. 

The demonstration unit is bciig installed at Ohio 

Edison’s Niles Station in Niles, OH. The process will 

neat a 35-MWe equivalent slip-stream of flue gas from 

the 115-MWe Unit No. 2 boiler that burns a 3.4% sulfw 

coal. The process steps arc virtually the same as for 

a full-scale plant. and commercial-scale components 

will be used. 

ABB Comburrion EngineeringlWSA-SNOX 
calendar Year 

3’Y lss9 1931 IS92 ,983 1994 ,995 

1 2 3 4 

1 2’“3 4 1 

23412 34123412341234, 

2’9963 

4 

1 

2 

1987 3 4 1 199s 

2 

s/y 11 

Pnawsrd 

I: 

Tf 

r 

T 

t 

operalion inkialed lltgl’ Project completedninal repan issued 1 l/93’ 

Prec~erationat tests iniliakd Wgl’ opxation Mmplefed 8193 

Conrtnrdlon completed 7i91’ 

Design completed 2181’ 

Gmw, bmkh,gkx,r,sl~ctlon started 1,91’ 

Environmental monloring plan compleled 591 

NEPA process completed 20190 

operative egreement awarded 12Rw89 

DOE seleded projed 9,2&W * Projected date 

Proje* Status/Accomplishments: The signiiicznt reductions of SO, and NO, are projected 

Under way concurrently are design and permitting to be achievable nationally due to the 95% removal of 

activities and long-lead pwxemem. Construction is SO,and NO, emissions hm coal-fund boilers with the. 

expected to commence in early 1991. All of the long- WSA-SNOX process and the wide applicability of the 

lead procuemcnt equipment has been ordered, and a prccess. Moreover, the sulfuic acid produced is a 

major portion of the. design has been timpleted. A salable by-product. No change in solid waste is amici35-MWe duct tie-in connection was installed at a point pared because tbe technology prcduces no solid waste 

just beyond the ESP; the duct tmrtsports the flue gas to by-product. (Source: CCT Programmatic Environthe high-eff~ciency baghouse. mental Impact Statement) 

Environmental Conslderatlons: 

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

approved onFebruary 1.1990. 

Commercial Appllcatlon: 

Assuming maximum commerciatization on a 

national basis by 201Ofor the WSA-SNOX prccem 

relative to a no-action altemative. the following impacts 

are projected: 

* so, r!dwtiOI+38% 

. NO, reduction-15% 

The WSA-SNOX technology is applicable to all electric 

power plants and industrial/iititutional boilers fuiog 

coal, oil, or gas. The high removal efficiency for NO, 

and SO, will make the process atuactive in many 

applications. Eliiination of solid waste enhances the 

marketability in urban and other areas wheze solid waste 

diiposal issues are a significant impediment. 

MB Comblrrtion EngineeringiWSA-SNOX Program Update 1990 7-31 
Demonstration of Coal 

Reburning for Cyclone Boiler 

NO, Control 

Sponsor: 

The B&cock &Wilcox Company 

Addltlonal Team Members: 

Wisconsin Power and Light Company~funder and 

host utility 

Sargent and Lundy-engineer for coal handliig 

Elechic Power Research Institute-cofunda 

State of Illionois, Department of Energy and Natural 

Rcsourcescofunder 

Utility companies (10 cyclone boiler operators+ 

cofunders 

Locatlon: 

Cassville, Grant County, WI (Nelson Dewey Station, 

Unit No. 2) 

Congressional Dlstriti: 

3d U.S. Congressional District 

Technology: 

The Babcock &Wilcox Company’s coal rebuming 

system 

Plant Capaclty/Pmductlon: 

1OOMWc 

Pro@3 Fundlng: 

Total project cost 

DOE 

Participants 

$10.655.261 lC@% 

5.072.631 48 

5.582.630 52 

Pro@3 Objective: 

To evaluate the applicability of rcbuming technology 

for reducing NO, emissions from a full-scale coal-f& 

cyclone boiler, pulverizing a portion of the primary coal 

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

7-32 Program updatt? 1990 

achieve greater than 50% reduction in NO, emissions gas to be convened into nitrogen and water in this zone. 

with no serious impact on cyclone combustor operation, The completion of the combustion process occurs in the 

boiler efficiency, boiler freside p&xmance (corrosion third zone. called the burnout zone, where the balance of 

and deposition), or ash removal system performance. the combustion air is introduced. 

Technology/Project Descrlptlon: 

The coal rebuming process reduces NO, in the main 

furnace through the use of multiple combustion zones. 

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

heat equivalent fuel input to the boiler and slightly less 

than normal 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 rebuming zone to create 

an oxygen-deficient condition. The NO, formed in the 

cyclone burners reacts with the resultant reducing flue 

The coal rebundng technology can be applied with 

the cyclone burners operating within their normal, noncorrosive. oxidiziug conditions. thereby minimiziig the 

effects of rcbum on the cyclone combustor and boiler 

perfo”“ance. 

This project involves reaofitting an existing 

IOO-MWe cyclone boiler that is representative of a large 

population of cyclone units. The cyclone boila being 

retrotitted is presently in commercial operation at 

Wisconsin Power and Light’s Nelson Dewey Station in 

Cawille, WI. 

BdrWIRebuming 
cadaf Year 

3’8884 1 2’“3 4 1 2’“3 4 1 2’T 4 1 2 1992 3 4 I :“3 4 1 2 ,984 3 4 1 2 139s 3 4 1 2 1988 3 4 1 2 ,887 3 4 1 169s 2 

t 

A 

v----- PIOjecl c.xnpleledninal repon issued 4x3’ 

DOE ssleoed p&d 

111 T 

T OperaSon compbted 12/82’ 

ma%s Cperetbn intinted 12191’ 

Cbnstmion comp!&d 111381’ 

Pleoperafbnal fests initiamd 1m1 

Ewimnmmtd mmkvbg p!an completed &St’ 

Dcslgnmpbled em’ 

Gwnd ‘weahhgbxwWclion started 3181’ 

NEPA process mmpleted 2W 

cmperatiw agreemem awarded 4Emo ‘Projected dab 

L 

Project Status/AccompIlshments: 

The project is prowding with preliminay design, 

having completed the baseline boiler performance 

testing and performance modeling both with and 

without the pmposed rcbmn retrofit. Ihe detailed work 

plan and the project evaluation plan have been completed. Boila pafomunce results have been analyzed 

and inwrpin-atcd into both physical and mmerlcal 

models of the boiler. The mcdehg has demonstrated 

the need for a change from three to four rebumers and 

over-fire air ports to assure adequate NO, reduction. 

Environmental Considerations: 

An enviroumental analysis and a finding of no 

sigoificant impact have ken preped and are being 

reviewed by DOE. 

Sigoiticam reductioru of NO, (11%) are projected 

to be achievable natiauUy by 2010 doe to the capabiity 

of tbe cyclone coal-rebuming prcczw to remove 50% of 

NO, emissicms from coal-fti boilers and the wide 

potemial applicability of the process. Negligible. 

changes in effluents are anticipated. The technology 

produces no solid waste product. (Source: CCT Rogrammatic Environmemal Impact Statement) 

Commercial AppllcaUon: 

Currently, no proven retroftt cmnbustion tcclmology 

exists for reducing NO, epdssions from cyclone boilers. 

Coal reboming for cyclone boilers is expected to be a 

viable option BS a retrofit combustion technology for 

NO, control at reaonable capital and operating costs. 

AU of the approximately 26,000 MWe of currently 

installed cyclone boilers are expected to require NO, 

conhol to comply with tie Clean Air Act Amendments 

Of 1990. 

R&WIRebun+ Program Upabe 1990 7.33 
SOX-NOX-ROX Box Flue Gas 

Cleanup Demonstration 

Project 

Sponsor: 

The Babcock &Wilcox Company 

Additional Teem Members: 

Ohio Edison Company--cofunder and host utility 

Ohio Coal Development Office-cofunder 

Electric Power Research Institutc+cofundda 

Norton Company-zofunder and SCR catalyst supplies 

Minneapolis Mining and Manafacturhq Companycofunder and filter bag supplier 

Looatbn: 

WA, 

AIR 

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

Plant, Unit No. 5) 

Congressional DiStrlct: 

18th U.S. Congressional District 

Technology: 

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

box (SNRB) process 

Plant Capaclty/Productlon: 

5-hfWe equivalent slip-stxeam from a 156~MWe boiler 

Project Fundlng: 

Total project cost $10.640.293 lCO% 

DOE 4.815246 46 

Participants 5.765.047 54 

Prom ObjectWe: 

To demonstrate that the SOX-NOX-ROX box process. 

used in rewfitting a high-sulfur-coal-f& power plans 

can remove high levels of all pollutants using a single 

processing unit for aeating hue gas. thereby lessening 

on-site space. requirements and capital costs. 

Technology/Pro@l Description: 

The SNRB process will combine the removal of SOz, 

NO,, 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. NO, removal is accomplished by injecting 

ammonia (?iH,) to selectively reduce NO, in the 

presence of a selective catalytic reduction+ or SCR, 

catalyst. Particulate removal is accomplished by bightemperature cmmic fiber bag filters. 

The project will dcmonsaate the technical and 

economic feasibility of achieving 7040% SO, removal, 

up to 9046 NO, removal, and 99% particulate removal 

at lower capital and operating and maintenance costs 

than other conventional systems. The demonstration 

will be conducted at Ohio Edison’s R. E. Barget Plank 

Unit No. 5, in Dilles Bottom, OH. 

The SNRB demonstration unit is sized at 5 MWe 

and is large enough to demonsuate. a commercial-scale 

baghouse module while nthtintizing the demonsk&m 

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

temperahue for maximum SO, and NO, reductions. 

734 Pro@wh Update 1990 BdWiSOX-NOX-ROX Box 
oiect compleledninal report issued 4193’ 

lb” compleled l/93’ 

eration initiated 2,92’ 

onstruction complsk! 12/91’ 

recperational~es1s initiated 11191’ 

esign completed 6191’ 

Environmental moniloring plan completed 3M’ 

Ground breakinghnstnrction stalled 3~91’ 

* Projeaed dale 

Project StatualAccompllshments: The significant reductions of SO, and NO, are projected 

The project is proceediig with detailed design. General to be achievable nationally due to the 70-90% removal 

arrangement of major equipment has been resolved, and of SO, and NO, emissions from coal-fired boilers with 

bid packages have been issued for ail of the major the SNRB process and the wide applicability of the 

equipment. The pilot baghouse unit, sized to test com- process. Negligible changes in liquid effluents are 

inercial-sized bags, is complete, and initial test opera- anticipated. (Source: CCI Programmatic Environtions have begun. mental Impact Statement) 

Commercial Application: Environmental Conslderatlons: 

NEF’A compliance bas been satisfied by a memo-to-file 

approved on September 19.1989. 

Assuming maximum commacialization. the following impacts are. projected on a national basis by 

2010 for the SNRB process relative to a no-action 

alternative: 

* SO, reduction-38% 

. NO, reduction-15% 

- Solid waste increas~8% 

The SNRB process, upon being commercially demonstrated, offers removal of up to 90% of the SO, and NO, 

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

lower capital and operating costs and smaller space 

requirements than conventional flue gas cleanup 

technology. In addition. SNRB offers the potential for 

increasing boiler efficiency. ‘Ihe SNRB process can be 

used to retrofit a wide range of utility and industrial 

coal-fued boilers that are without scrubbing systems in 

order to achieve a high level of emissions control at 

favorable capital and operating costs. 

B&WISOX-NOX-ROX Box Program Updare 1990 7-35 
Innovative Coke Oven Gas 

Cleaning System for Retrofit 

Applications 

Sponsor: 

Bethlehem Steel Caporation 

Addltlonal Team Member: 

Davy/St&Otto-technology developa 

Location: 

Sparrows Point, Baltimore County, MD (Bethlehem 

Steel Corporation’s Sparrows Point Plant, Coke Oven 

Battaies A, 11, and 12) 

Congressional Dlatrtct: 

2d U.S. Congressional Disuict 

Technology: 

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

coke oven gas (COG) 

Plant Capactty/Production: 

74 million std ftJ/day of COG 

Project Fundlng: 

Total project cost $45.239.781 lW% 

DOE 13,5ccwcKl 30 

Participant 31.739.781 70 

Project ObJectlve: 

To demonsmate a fust-of-a-kind novel integration of 

commercially available process steps for simultaneous 

removal of hydrogen stide and ammonia from COG, 

recovery of hydrogen stdiide and ammo& destruction 

of ammonia, and recovery of sulfur in a commercialsized application; and to reduce SOz emissions by at 

least 80% accompanied by substantially reduced 

volatile orgaoic compound emissions and ammonia 

discharge to wastewater treatment. 

7-36 hail Update 1990 

Technology/Project Description: 

This project will demonarrate an innovative technology 

developed by Davy/Still-Otto for removing hydrogen 

solfide f&S) and ammonia (NY) from COG. The 

process uses contaminated water pmhmd in the coke 

oven batteries to absorb the hydrogen tide and 

ammonia contained in the COG. Both hydrogen soltide 

and ammonia are steam shipped from the absorption 

liquor. The ammonia is destmyed in a catalytic reactor; 

the hydrogen suliide is convened to elemental sulfur in 

a conventional Claus plant, and the sulfw is recovered 

as a salable by-product. 

The technology is expected to reduce the hydrogen 

sulfide concemration in the cleaned COG by 84% and 

the ammonia’concemration by approximately 99%. 

Because the reagents used are indigenous in COG, costs 

associated with the purchase and handling of feed 

reagents, the handhg and treatment of by-products, 

labor, and utilities are reduced. 

This project involves the modification of the. COO 

processing units at Bethlehem Steel’s Sparrows Point 

plant in Baltimore County, MD. ‘Ibe demonstration 

facility will process the entire COG stream from 

Coke Oven Batteries A, 11. and 12, which amows to 

74 million std f@.iay. currently, only 60% of this 

COG stream is desulforized. The remaining 40% is 

used directly for under-ftig the coke ovens. 

Bethlehem SteeUCoke Oven Gas 
I 

CalendsrYW 

,888 ,694 ,987 ,898 

3 * 1 2’7 4 1 :“3 4 1 2 3 4 1 :=3 4 1 :“3 4 1 2’8943 4 1 :“3 4 1 :“, 4 1 2 3 4 1 2 

A ,J 

t 

t -cQmdb”wmpbled 4&w 

Opmtbn hhiated 3,92* ProJen mmpkaednlnal repolr issued 4193. 

PreopmaUonalt0*~5 iniliad &“a’ 

Conslmaion comphted 5191’ 

Envimnmental monnorlng plan campwad 4/81’ 

Destgn cmpleld 11180 

Ground lxeakh~oxwtruclbn started 3,90 

iPA pcew mmp4ad Icqmrmlve agreement awarded 11/14m ‘Projecled dale 

Prom Satu!dAccompllshmen: 

The okJailed design phase of the project is complete. 

Fabrication of major equipment is pmce&iq, and 

many item have already been delivered to the consmtctlon site. On-site consmction activity was initiated in 

February 1990 with the imauariorl of pilings and 

foundations. Erection of the smlctulal steel, major 

e&mm, and piping began in September 1990. 

The environmental monitotig plan is cumtdy 

under review by DOE, and constmction is well under 

way, proceeding toward the hlitiatiorl of start-up and acceptance testing activities in June 1991. 

Envlronmental Conslderatlons: 

The environtnentaJ assessment with a finding of no significant impact was approved by DOB on December 22. 

1989. 

The expected p&m chatactelistics and 

applicable market of the proposed COG clembq system 

ivere used to e&mate the atvlrotmental hnpacts that 

Bethlehem SteeUCoke Oven Gas 

may occur if this tcclmology reaches full commcrciali- Commercial Appllcatlon: 

sation. The existing 30 coke oven plants in the U.S. 

emit about 300,000 tons/~ of SOz. This COG cleaning 

process could be applicable to 24 plants with conespending emission levels of 200,OCO tons/~ of SOT If 

the teclmology were installed in all 24 plants. the SO, 

emissions could be reduced by 160,ooO tom/yr. The 

ammonium sulfatc. which is difficult to market and 

usually is disposed of as a solid waste, would be 

eliminated. Eveq 5-8 years. 5 tons of spent nickel 

catalyst would need to be mumed to the vendor or 

disposed of as a hazardous waste, and 10 tom of spent 

alumina catalyst would need to be disposed of as a 

nonhazardous solid waste. Depending on the configoradon of the coke oven facility where the technology is 

being implemented. the amount of watB needed for 

cooling purposes would remain the same or be reduced, 

and the amount of pollutaots in the wastewatcr would 

remain the same or be reduced. 

llte design for this innovative COG cleaning system is 

based on operating data tbat have been collected from 

individual process steps or combiitiom of individual 

pmceas steps that have been successfully operated at 

commctcifd-sized COG treaanent facilities. The novel 

integmion of commercially available process steps is 

expected to redWe the overall cost of desulfurization, 

ensure reliable operation in applications exceeding 

20 years, and provide a viable altemative to conventional technologies. Becaw. the dcmonsnation is 

designed to mat 74 million std ft’/day of COG, the 

press will be of a commciaJ size that can be reuofitted into an above-average-sized coke-making facility. 

This project will demonmate that it is possible to 

maofit any existing coke-making facility in the United 

State.4 with emmially no scale-up involved and without 

significant downtime. 

Program update 1990 7-37 
PFBC Utility Demonstration 

Project 

Sponsor: 

Tbe Ohio Power Company--cosponsor 

The Applachian Power Company-cosponsor 

Addltlonal Teem Members: 

American Elecnic Power Service CorporationASBA Babcock--technology supplia 

Won: 

New Haven, Mason County. WV (Ohio Power’s and 

Appalachiao Power’s Philip Spot Plant, Units 3 and 4) 

Congreeelonal Dleblct: 

36 U. S. Congressional District 

Technology: 

ASBA Babcock’s presswized floidized-bed combustion 

mm system 

Plant cepclty/PnJductlon: 

330 MWe 

J 

Pro)ect Fundlng: 

Total project cost $659.860.000 10% 

DOE 184,8OO,CC0 28 

Participants 475,060,oLw 72 

Project ObJectlve: 

To demonstrate PPBC at 330 MWe, a large utility scale 

representing afour-fold scale-up of the technology, the 

world’s largest PPBC. and the fast commercial application of PFBC in the United States; to assess long-term 

reliability. availability, and maintainability of PFBC in a 

commercial opemting mode and the integration of a 

reheat steam cycle; and to achieve 95% SO2 reduction, 

at least 70% NO, reduction, and an efficiency of 39% in 

a repowering mode using the existing steam system. 

Technology/Project Deec~Iptlon: 

The ASEA Babcock PFBC technology uses a bubbling 

fhddized-bed boiler enclosed in a pressure vessel 

cpzated at 16 arm to produce combustion gases with 

softicient energy to drive a gas tarbiie. The gas turbine 

exhaust is used to preheat boiler water, and the fluidiaed-bed boiler develops steam for the steam turbine. 

Because pressure in the boiler enhances combustion and 

heat transfer, the size of the vessel needed is reduced. 

F?essure also enhancesulfur capture by the sorbcnt. 

Sot’bent (limestone or dolomite) is injected into the 

boiler and react$ with SO, to form unreactive calcium 

mlfate, a dry. granular mate&l. 

&gle 33C-MWe unit. Nearly one-fourth of the power 

is to be produced through an ASEA STAL CT-MOP gas 

nubii with the balance generated through the existing 

steam hub&s. The Philip Spom Plant is co-owned by 

the Ohio Power Company and the Appalachiian Power 

Cotnpmy, both of which are operating companies of the 

Americao Electric Power Company, Inc. 

The project entails replacement of two 15OMWe 

oniu, Units 3 and 4 at the Philip Spom Plant, with a 

7-38 Program update 1990 Ohio Power andApp&chian PowerlPFBC 
calendaf Year 

3’Y ,988 1890 lo@, ISa 1E3 l98s 1997 1888 

1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 Z’gDj 4 1 2’73 4 1 2 3 4 1 2 3 4 1 2 

bOE relec(ed I 

pmlea @Z&W ~b~b” . 

caq.lnfath-aag-t4490 Envlmnmental mwltodng plan completed m’ 

NEPA prccess mmpleted 3182’ 

9/88 4ml 8m8 31’38 

+ ii&%: Commercid 

demC+lSt~atb” 

completed 12/87’ 

gg ksue 

operatbn mmpleted 8196’ 

Commercial demonsfratimi 

initiated 9196’ 

matbninlf&red 8%. 

:wabn mmpleted 4iw* 

Design completed 3196’ ‘Projoctad d&e 

Pt’ojeci Status/Accompllslwn~: 

Project is nearing completion of prelimhary engineering 

studies, which will inwporu an analysis addresshlg 

the merits of wing the same technology for a greenfield 

plant. Project management and evaluation plans have 

beat established. and significant progrw has been 

Nade toward completing prelii enginwing studies that will set the stage for detailed de&n. 

EnvIronmental Coriddefatlons: 

The environtnental h&rmation volume is beiig 

prepared by the participant as requisite input to the 

NEPA compliance process. 

Assuming maximum wm~erci8lization of the 

PPBC technology on a national basis by 2010 relative to 

a no-action alternative, the following impacts are 

projmed: 

. SO, reductid8% 

. NO, reduction-17% 

- Solid waste irtwea% but io dry. grzmalarform, facing nzqiirementr. Plant life cao be extended by 

which has more amenable altentative uses, such as repowering with PFBC using the existing plant area, 

wnstmction aggregate, and xqires less land area for coal and waste handling equipment, snd steam tarbiie 

disposal than conventional scrubber sludge equipment. 

(Source: Cm Rogmmmatic En- t8I INpact 

SNtemeN) 

Commercial AppllcMion: 

Combihmkycle PFBC allows for the combustion of a 

wide range of coals, including high-salfur coals. It cart 

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

switching them to high-sulfur coal. to repower coal-f& 

power plants. sod to build new PPEiC units. Combinedcycle PPEtC technology appears to be beat suited for 

eleculc utility applications for medium (lC0-4OO MWe) 

8nd huge 0 400 MWe) plants. In fact lwawe of 

modular conshuction capability, PFBC genemting 

plants will enable utilities to add incnments of capacity 

eamomicaUy to rtufch load growth and to reduce utility 

The performanw potential of PPBC technology in 

its wmmercial cordigoradon is chamcterized as follows: 

* SOI reduction-95% 

* NO, reducti~m-8G% 

- Phmt efiiciency-up to 45% 

. Incremental power incxase-40% 

. Fuel flexibility--permits use of wide range of coals 

* Compactne8s-high process efficiency reduces space 

mqtkement3 per unit of energy generated 

- Modular constrocdon-lends itself to economic 

additions of capacity increments to match load growth 

Ohio Power andAppcda&m PowerlPFBC Program update 1990 7-39 
Cement Kiln Flue Gas 

Recovery Scrubber 

Sponsor: 

Passamaquoddy Tribe. 

Addltlonal Team Members: 

Dragon products Company-project manager and host 

E. C. Jordan Company-engineer for overall scrubber 

SYSktll 

HPD, Incorporateddesigner and fabricator of tanks 

and heat exchanger 

Cianbro Corporatiott-constructor 

Location: 

Thomaston, Knox County, ME (Gngon Products’ 

coal-tired cement kiln) 

Congressional District: 

1st U.S. Congressional District 

Technology: 

Passamaquoddy Tribe’s Cement kiln flue gas recovery 

scrubber 

Plant Capaclty/Prcductlon: 

1,450 tons/day of cetnen$250,0!M std. ft’lmin of kiln 

@s; and up to 214 tons/day of coal 

Project Funding: 

Total project cost $12,538,648 lW% 

DOE 5,903,195 41 

Participants 6.635.453 53 

Project 0b)ectlve: 

To retrofit and demonstrate afull-scale industrial 

scrubber and waste recovery system for a coal-bunting 

wet process cement kiln using waste dust as the reagent 

to accomplish 90-95% SO, reduction using high-sttlfur 

eastern coals and to produce a commercial by-product, 

potassium-based fettilizer. 

7.40 Program Updote 1990 

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

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

sluny containing potassium-rich dust recovered from the 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 retumed to the 

cement plant as renovated and usable raw feed material. 

The liquid fraction is passed to a crystalliser that uses 

waste heat in the exhaust gas to evaporate the water and 

recover dissolved alkali metal salts. 

The Passatnaqwddy Tribe’s recovery scrubber is 

beiig constructed at the Dragon Products Company’s 

cement plant in Thomaston, ME, a plant that processes 

approximately 470,000 tottslyr of cement. The process 

was developed by the Passamaqucddy Indian Tribe 
calendar Year 

3’9s84 1 2 ,889 3 4 1 :“3 4 I 2 ,881 3 4 1 2 19w 3 4 1 :“3 4 1 2’9843 4 1 2 ,985 3 4 , 2’9883 4 1 2’“; 4 1 Is98 2 

$ 111( 

T t 

L’ Pro@t mmplete&linal repon issued 4/82 

Operatim hitiated 3631’ 

Qwrallon completed 3BZ * 

ConstNaiOn completed llim 

Precperational test* inniated 1 II90 

Environmental monloring plan cwnpleted 5R6BO 

Cdgn completed 490 

NEPA pmces~ completed 211&W 

c?cq%th agrmm.snt awa&?d 12mwa 

c.nlstNdkln stalled 6/w 

WE seleaed pmjed 9128/88 ’ ProJected date 

Project Ststus/Accompllshments: 

‘The design phase of the project has been completed. and 

the consuactionphase is nearing completion. Initial 

start-up and testing of the scrubbing system has 

achieved the project objective of 90-95% SO, reduction. Operation is scheduled to begin in March 1991. 

Environmental Conslderatlons: 

NEPA compliance has been satisfied through an ettvironmental assessment, and * fading of no significant 

impactwaappmvedFebmary16.1990. 

The expected performance characteristics and 

applicable market of the proposed cetnent kiln gas 

recovery swabber were used ta estimate the environmental impacts that might result if this technology were 

to reach fttll wmmercialization. There are over 250 

cement kiln installations in the United States and along 

the St. Lawence Riva in Canada emitting approximately 230,MtO tom&r of SO,. Based upon the characteristics of the technology, the applicable market would 

include approximately 75% of these installations. If the 

technology were installed in the applicable market 

facilities, the SO, emissions could be reduced by 

approximately 150,CCG tons/y. The effect on NO, 

ctttisSionS is being &E?‘mh~cduring the demOnSUatiOn. 

Some reductions in NO, emissions are expected. The 

waste dust that previously would have been sent to a 

landfill would be recovered for recycling to the kiln and 

to prcduce by-product fertilizer. Essentially, the solid 

waste sueant would be eliited through recovery. 

Water usage might or might not increase depending on 

the conxiguration of the existing kiln facility. However. 

the quality of wastewator would be improved and the 

amount reduced because the technology produces 

distilled water either for sale or discharge. 

materials as a scrubber reactant. The scrubber produces 

no waste sludge thereby obviating the need for disposal 

in a landfill. The systetn potentially provides income 

from the sale of by-products. and there is no net cost of 

opaatlon. 

Commercial Appllcstlon: 

The mmeq scrubber permits the use of high-salhu 

cd in canent kilns using available waste dust as the 

reagent, without requiring the puchaw of other 

Passwnaqwddy Tribe Program Update 1990 7-41 
Advanced Flue Gas 

Desulfurization 

Demonstration Project 

Sponsor: 

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

Air, which is a general partnership between Air 

Products and Chemicals, Inc., and Mitsubishi Heavy 

Industries America, Inc.) 

Addltonal Team Members: 

Northern Indiana Public Service Cotnpany-cofuttder 

and host utility 

Mitsubishi Heavy Industries, Ltd. (pare@ companyj 

process designer 

United Engineers and Constructors (Steams-Roger 

Division&facility designer 

Aii Prcducts and Chemicals, lnc.-constmctor and 

0perEU0r 

Locatlon: 

Chestertoo. Porta County. IN (Nonhem Indiana Public 

Service Company’s Bailly Generating Station) 

Congressional Dlstrtct: 

1st U.S. Congressional District 

Technology: 

Pore Air’s advanced flue gas desulfutization (AFQD) 

process 

Plant Capsclty/Productton: 

528 MWe 

ProJect Fundlng: 

Total project cost $150.497.o00 100% 

DOE 63,434.COO 42 

Participants 87,063,MlO 58 

7-42 Program UpdIm 1990 

Project Objectlve: in the same direction and at a relatively high velocity 

To demonstrate removal of 90-95% or more of the SO, compared to cqnventional sctubbers. These features all 

*t approximately one-half the cost of current conven- combine to yield a state-of-the-art SO, absorber that is 

tional scabbing technology; and to demonstrate more compact and less expensive than conventiotul 

significant reduction of space reqkentents. scrubbers. 

Technology/PfoJect Descrlptlon: 

In this project, Pore Aii is building a single 52GMwe 

scale SO, absorber. Althottgh this is expected to be the 

largest capacity absorber module in the United States, it 

has relatively modest space requirements becaose no 

spare or backup absorber modules are to be installed. 

The absorber performs three functions in a single vessel: 

prqwnchex, absorber. and oxidation of sludge to 

gptnn. Additionally, the absorber is of a cocurrent 

design, in which the flue gas and scmbbhq slurry move 

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

an air rotary sparger located within the base of the 

absorber, and a novel w&water evaporation system. 

The air rotary sparger wmbiies the functiona of stirriig 

and air distribution into one piece of equipmento 

facilitate the oxidation of sludge to gypsum. 

The APGD process beiig demonstrated is expected 

simultanwttslj to remove 90-95% or more of the S02, 

provide a commemial gypsum by-product, and evaporate wastewater. 

Pure Air 
Calendar Year 

1888 1969 Is50 ls+l 1992 1993 1994 ,995 ,QQS 1997 1996 

3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 I 2 3 4 1 234123412 

9 

Dealan and Conrtruction 

7/p2 

L 

f 

Mcdilication. if necessary 

Cpralbn hill&d 7)92’ 

Environmental 

Design completed 7192 

Constmclion mmpleted 7/92’ 

Preoperadonal tests initiated 4192 

NEPA prccers completed 4/WQO 

Ground breakinghvtruclion started 4i20,90 

nperafh’e agreement awarded 12ROiEQ 

Project completedflinal repal issued Q/85’ 

Operalk.,” comple,ed ,195’ 

‘NE seleded projen Q/28/88 

* Projected dale 

The project also seeks to demonstrate anovel 

business concept, whereby Pore Aii owns and operates 

the AFGD facility. Thus, Pure Air expects to specialize 

in pollution control activities, relieving the electric 

utility of the operation of the AFGD unit. Assuming 

that the 3-year demottsuation is successful. Pore Air 

will continue to own the AFGD facility and to operate it 

as a contracted service to the utility for an additional 17. 

year period. The demonstration is located at Northem 

Indiana Power Service Company’s 528sMWe Bailly 

Generating Station near Chesterton, IN. 

Project Status/Accomplishments: 

Design is approximately 90% complete; the remaining 

design activities will continue through the early stages 

of operation. Construction is approximately 35% 

complete; emphasis has been on site preparation, foondation installation, and snuctoral assembly. Mechanical 

installation activities are slated for 1991. and start-up 

is on schedule for mid-1992. A pilot-plant test was 

Pure Air 

performed for 2 weeks during February and March market for the gypsum by-product. it is readily dispos1990. Using U.S. high-sulfur coal and limestone 

feedstocks. the pilot test was successful both in terms of 

SO, removal and gypsum purity levels. 

able in a landfill. (Source: CC3 Programmatic Environmental Impact Statement) 

Environmental Considerations: 

NEPA compliance has been satisfied by an environmental analysis. with a finding of no significant impact 

approved by DOE on April 14 1990. 

Assuming maximum commerciallzation of the 

AFGD pmcess. 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 process potentially would increase solid waste by 

9%. 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 

Commercial Application: 

The AFGD process is attractive for both new and 

retrofit applications. The demonstration project is using 

coals primarily from the Indiana-Illinois coal basin, 

with sulfur content ranging from 2.0% to 4.5%. 

Program Update 1990 7.43 
Demonstration of Advanced 

Combustion Techniques for a 

Wall-Fired Boiler 

Sponsor: 

Somhem company services, Inc. 

Additional Teem Members: 

J3ectric Power Research Instihtte-~fttndez 

Foster Wheeler Energy Coqoration-techttology 

sapplier 

Georgia Power Company-host utility 

Location: 

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

Hammond, Unit No. 4) 

Congreeelonal Dletticti 

7th U.S. Congressional District 

Technology: 

Foster Wheeler’s low-NO, burner @NB) witb advanced 

wer-fice air (AOFA) 

Plant capaclty/Prwhlotlon: 

500 MWe 

Prolect Fundlng: 

Total project wst $11.711.229 100% 

DOE 5242.917 45 

Participants 6,468,3 12 55 

Propxt Objective: 

To achieve. 50% NO, mductiot~ with he AOIWLNB 

system; to determhte the connibmions of AOFA and the 

LNB to NOx reduction and the parameters detexmiti~ 

optimum AOFAILNEI system performance; and to 

msess the long-term effezu of AOFA and LNB on NO, 

reduction and boiler pfaformaoce. 

TechnologyfProJect Descrlptlon: 

AOFA involves (1) imprwing the mixing of over-fin 

air with the fttmaoe gases to achime complete combostion, (2) depleting the air from the bunter zone to 

minimize NO, formation, and (3) supplying air ova 

furnace wall tube surfaces to prevent slagging and 

furnace corrosion. The AOFA technique is expected to 

reduce NO, emissions by about 35%. 

In a LNB, fuel and air mixing is controlled to 

preclude the formation of NO,. ‘Ibis is accomplished by 

regulating the initial fuel-sir mixture, velocities. and 

torbolence to create a fuel-rich flame core and by 

contmlling the rate at which additional air required to 

compIete combustion is mixed with the flame sdids and 

gases so as to maintain a deficiency of oxygen. Typical 

results for utilities indicate that LNB technology is 

capable of reducing NO, emissions by about 45%. 

Based on earlier experience, the use of AOFA in 

conjmsticm with LNEz can reduce. NO, emissions by as 

much as 65% compzed with conventional bumers. 

‘he demonstration is located at the Georgia Powa 

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

a 00mineI 500~MWe pulverlzed cod, wall-fued unit, 

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

7d Program update I990 
A A 

I IfI 

: 

t 

f. 

C$xxalbn mmpletad. LNB ,ZM’ 

ProJecl mmpletedninal report Isrued 6fW 

Opmtbn iniilated. LNB 4M’ 

Conarudbn mmp!&xi. LNB 4iW ’ 

Canslrudbn starled. LNB 3181’ 

Cptmtlon completed. SOFA CVQI’ 

Envimnmenld monliodng plan ccmpleted B/13/80 

OoEselened 

O~~ralhInlllated. AOFA 6190 

proI=+ Comtrudion completed. AOFA 500 

srzaiaa Construabn ~)taded. AOFA UQO 

oeeignmmpleted 380 

c4cqmllve agmmml awarded lzfzom8 

NEPA p- mmpretsd y171UB ‘Projemed dale 

Projeci Statu!dAccompllshments: 

Design activities are complete.. tZonmactiott activities 

are under way. with the AOFA system designed and 

installed. ‘Ihe AOFA diagnostic at@ performance 

testing is complete, and the long-term AMA testing 

began during October 1990. The 24 cmttmlled-flow. 

split-flame LNBs have been designed aud are under 

ccmmucti~ installation is scheduled for March 1991. 

Jhing prelimimy diagnostic and paformmce 

testing of the AOFA system, NO, reductiom in excess 

of’Z5%havebeenmeasmdtitbamallincreaxin 

carbon loss on ignition. No sign&ant change in boiler 

operarion and combustim~ stability was experid 

while operating with he AOFA system dampers. 

Environmental Considerations: 

NEPA compliance baa been sadstied with a memo-tofile. which was approved on May 17.1989. 

Sigtdticmt reductions of NO. (11%) are projected - Little or no deratiug of the boila 

nationally by 2010 from maximum c.3mmmialization 

of tbe technology due to the 60% removal capability 

forecasted and the wide applicability of the pmess. 

No changes in liquid effluents or solid wastes are 

auticipated. (Source: Cm Pqrammatic Environmental Jmpact Statemat) 

* Use of comnmcially available ~~~FCWXS 

Commercial Application: 

This technology is applicable fa retrofitting tbe 422 

pre-NSPS wall-ftmd boilers existing in tbe United 

States. 

commerclalizatioa of the L%bnology will be aided 

by the following charactcrstics: 

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

* Competitive capital and operating costs 

* Relatively easy rauoftt 

Southern Company SwviceslWall-Fired Boiler Pmgram Up&e 1990 745 
Demonstration of Innovative 

Applications of Technology 

for the CT-121 FGD Process 

Sponsor: 

Southern Company Services, Inc. 

Additional Team Members: 

Georgia Power Company-host utility 

Electric Power Research Institute-cofunder 

Radian Corporation-environments1 and analytical 

comultant 

Ershigs, Inc.-riberglass fabricator 

University of Georgia Research Found$iooby-product utilization studies 

Location: 

Newan, Coweta County, GA (Georgia Power Company’s Plant Yates, Unit No. 1) 

Congressional District: 

6th U.S. Congressional District 

Technology: 

Chiyoda Corporation’s Chiyoda Thoroughbred-121 

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

process 

simultaneous particulate control with possible additional 

reductions in operating costs. 

Plant Capacity/Production: 

100 MWe 

Project Funding: 

Total project cost 

DOE 

Participants 

$35,843,678 100% 

17.546646 49 

18,297,032 51 

Project Objective: 

Technology/Prolect Description: 

The project will demonstmte the CT-121 FGD process. 

This process uses a unique absorber design known as 

the jet-bubbling reactor, 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. 

To demonstrate the CT-121 flue gas desulfurization Jn this process, the flue gas enters the scrubbing 

system, including several design innovations, at the solution on the jet-bubbling reactor. The SOI in the flue 

100~MWe scale; more specifically, to demonstrate gas is absorbed and forms calcium sulfite (CaSO,). Air 

90% SO, control at high reliability with and without is bubbled into the bottom of the solution to oxidize the 

7-46 Program Updare 1990 

calcium sulfite, which forms gypsum. The shmy is 

dewatered in a gypsum stack. The stacking technique 

involves filling a dyked area with gypsum slurry. 

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. 

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 demonsnate 

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

simultaneous particulate control. 

Southern Company ServiceslCT-I21 
:ale”dar Year 

1888 198s 1s¶o ,991 1992 

:“3 

,995 1996 ,997 ,998 

341234123412341 2 3 4 t 4 1 21Y 4 1 i! 3 4 1 2 3 4 1 2 3 4 1 2 

WE selectsd 

project %2&8s 

Environment4 monitoring 

plan completed 12/18BO 

NEPAprocess 

mmpleted 8/l&90 

Ground breaking/ 

construction sltied 8/Z&90 PM 

I 

Design completed 9/92 

Construction completed 9192’ 

operation initiated %@2’ 

Project completedifinal 

repo” issued i/97’ 

Operation completed 8195’ 

spcpetational tests initiated 5192 

operativeagreemmtawarded 4i2BO 

* Projectsd date 

Georgia Power Company’s 100-MWe Plant Yates 

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

Atlanta), will be retrofitted with the. Cbiycda scrubber. 

Envlronmental Conslderetlons: 

An environmental assessment with a finding of no 

significant impact was approved by DOE on August 10. 

1990. 

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 ponion of this capacity represents over 

10,SCQOCQ tons/year of potential SO, control. 

Project Status/Accomplishments: 

Preliminary design was conducted over an 

S-month period, which ended December 1.1990. 

Design and construction activities commenced on 

June 2, 1990, and will continue for 27 months or until 

September 1992. Construction began at the Plant Yates 

site. on August 23.1990. Critical foundations have been 

poured. Detailed design decisions have been made concerning the hmovatlve fiberglass-reinforced plastic 

absorber. Ersbigs set up equipment on site and daring 

December 1990 spun in place the 42-ft-high by 

42-ft-diameter jet-bubbling reactor. 

Assuming maximum commercialisation 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-!?5% SO, removal capability forecasted for the CT-121 process and the wide potential ap 

plicability 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 Ettvironmental Impact SIatemem) 

Sowhern Company Services/CT-121 Program Updare 1990 747 
Demonstration of Selective 

Catalytic Reduction 

Technology for the Control 

of NO Emissions from 

High-&lf@oal-Fired Boilers 

Sponsor: 

Southern Company Services, Inc. 

Addltlonal Team Members: 

Elecbic Power Research Institute-cofunder 

Gulf Power Company-host utility 

Locatlon: 

Pensacola Escambia County, FL (Gulf Power Company’s Plant crist) 

Congressional Dlsttict: 

1st U.S. Congressional District 

Technology: 

Selective catalytic r&ction @CR) 

Plant Capacity/Production: 

8.7~hfWe equivalent (three 2.5~MWe and six 0.2~MWe 

equivalent SCR reactor plants) 

ProJect Fundlng: 

Total project cost $15.574,355 100% 

DOE 7.525338 48 

Panicip0nB 8.049.017 52 

Project Oblecttve: 

To evaluate the p&ormancz of commercially available 

SCR catalysts when applied to operating conditions 

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

U.S. high-SIllfur coal under various operating emditimls 

while achieving as much as 80% NO, removal. 

TechnolcgylProJect Descrlptlon: 

The SCR technology consists of injecting ammonia 

(NHJ into boiler flue gas and passing it through a 

catalyst bed where the NO, and NH, react to form 

nitrogen and water vapr. 

In this demonstration project, the SCR facility 

consisu of three 2.5~hIWe SCRreactora. supplied by 

separate 5,CCO SK! ft’hnin flue gas slip-streams, and six 

0.2~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 wmmerciial 

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

two Japanese) will provide nine catalysts with various 

shapes and Wnical compositions for evaluation of 

process chemistry and economics of operation during 

the operation. 

The project is demonstrating, at high- and lowdust 

loadings of flue gas, the applicability of SCR technology to provide a cost-effective means of reducing NO, 

emissions from power plants burning U.S. high-s&w 

coal. 

The demonstration plant, located at Gulf Power 

Company’s Plant Crkt near Pemacola FL. has access 

to flue gas from burning appmximately 3% salfur coal 

under vsrious NO, end particulate levels. 

748 Program updaie 1990 Sovtkm Company SuviculSCR 
Environmental monitoring plan completed 

Construdion completed 6l92’ 

DOE selected projea 

enwe Ground breakInglcnnslrucUon Stied 4~91’ 

Cocperative agreement award.sd M4/80 

* Prqecw date L 

Prolect Status/Accomplishments: 

Design activities are under way. Detailed measurements of baseline flue. gas conditions at Plant Crist are 

complete and arc under review. Fi. detailed catalyst 

specifications have been received from each catalyst 

supplier. A review of these specifications is under way 

in order to finalize SCR reactor intemal design. 

EnvIronmental Conslderatlons: 

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% NO, reduction. 

The significant national reductions of NO, arc athibutable to the 80% NO, removal capability forecasted for 

!he 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: CCX Program 

matic Enviromnemal Impact Statement) 

Commercial Applkatlon: 

SCR technology can be applied to retrofit and new utility 

applications for removal of NO, 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 Z%.OLW Mwe. 

Assuming that SCR technology is installed on drybottom boilers tbat arc not equipped with low-NO, 

combustion technologies (i.e., low-NOx burners, overfue air, and atmospheric fluidized-bed combustion), the 

potential total retrofit market for SCR teclmology 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 constmction) and 144,500 MWe 

(290 boilers) of planned dry-bottom elcctic generating 

capacity in the United States. 

Southern Company ServiceslSCR Program Up&e 3990 7-49 
180-MWe Demonstration of 

Advanced Tangentially Fired 

Combustion Techniques for 

the Reduction of NO, 

Emissions for Coal-Fired 

Boilers 

Sponsor: 

Southern Company Services, Inc. 

Additional Team Members: 

Gulf Power Company-cofunder and host utility 

Electric Power Research Institute-cofunder 

ABB Combustion Engineering, Inc.-burner/ 

technology supplier 

Locatlon: 

Lynn Haven, Bay County, FL (Gulf Power Company’s 

Plant Smith, Unit No. 2) 

Congressional District: 

1st U.S. Congressional District 

Technology: 

ABB Combustion Engineering, Inc.‘s low-NOx concentric-firing system (LNCFS) and concentric clustered tangential-firing system (CCTFS); advanced over-fire air 

(AOFA) system 

Plant CapacltylProductlon: 

180 MWe 

Project Funding: 

Total project cost 

DOE 

Participants 

$8.555.303 100% 

4J50.055 49 

4,405,248 51 

Project Objective: 

tangential-firing system separately and in combination 

on a single reference boiler under typical dynamic 

To demonstrate advanced over-fire air, a low-NOx 

operating conditions: and to achieve a 60% reduction in 

NO, emission levels. 

concentric-firing system, and a concentric clustered 

NO, is reduced, and furnace wall slagging is decreased. 

separatiig the fuel and air streams in the tangentialfning arrangement. LNCFS has two significant 

advantages over the standard tangential arrangement: 

In an LNCFS, fuel and primary air is surrounded 

with a layer of secondary or offset air. This air is 

directed into the furnace through offset air nozzles. 

Improvements to the tangentially fired combustion technique include (1) the addition of adjustable turning 

vanes to the secondary air nozzles, (2) the addition of 

horizontally adjustable offset air nozzle tips to the main 

auxiliary compartments and end auxiliary crxnpartmerits, (3) the reduction in free area available in the coal 

compartments through which the fuel-air mixture can 

pass, and (4) the addition of divergent coal nozzle tips. 

Technology/Project Descrlptlon: 

The AOFA process involves the mixing of over-fire air 

with the furnace gases to achieve complete combustion 

and the depletion of air from the burner ulne to minimix NO, formation. 

l-he low-NO, concentric king system, or LNCFS, 

was developed solely for applications to Iangenfially fired steam generatorsnd uses a technique of 

7-50 Program Update 1990 Southern Company Services/Tangenriolly Fired Combwtion 
calendar Veal 

1ss8 1989 1890 1991 1992 1993 1995 199s 1997 1998 3 4 1 234123412 3 4 1 2 3 4 1 * 3 4 1 2’9943 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 

1 I Ai TTr 

t Cpomtkm inMated a/81* T t Project mmpleled/linal report issued 10193 

construato” mmpl*md 5191’ Operadcn completed 3/83 

Ceslgn completed 4191’ 

NEPA process 

mmpleted 

7,17/w 

WE selected 

pmjea gnalss 

Environmental monitoring plan completed 3/41’ 

Oround breakingkonslruction started 11190 

Cooperative agreement awarded 8RO~90 

* Projected date 

or CCfFS, combines several established NO, reduction 

The concentric clustered tangential-firing system, 

techniques that are applicable to tangentially fired coal 

boilers. The concept is based on the premise that both 

over-tire air staging and final furnace oxygen content 

dominafe in controlling the f& NO, levels. Clustered 

coal nozzles have been included to provide better NO, 

control over the load range. Extensions from the 

LNCFS occur as different levels of NO, reduction can 

be achieved through combinations of coal nozzle 

clustering close-coupled with over-fire air systems and 

separated over-fue air systems. Local fuel-rich zones in 

the timace burner zone reduce NO, formation. 

AL, and KY in the M-3.1% sulfur range. 

demonstmtion include bituminous coals from IL, WV, 

Project Status/Accomplishments: 

The cooperative agreement was awarded on September 

20.1990. 

effluenrs arc anticipated. and the technology produces 

no additional dry solid waste.. (Source: CCf F’mgrammatic Environmental Impact Statement) 

During the October 1990 plant outage, air heater 

baskets, instrumentation, sampling systems, and various 

support equipment were installed. Baseline diagnostic 

and performance tests were completed. Results are 

being analyzed. 

Envlronmental Conslderatlons: 

NEF’A compliance has been satisfied by a memo-to-file 

approved by DOE on July 17.1989. 

Commercial Application: 

Commercial applications include a wide range of 

tangentially fired utility boilers throughouthe United 

States and abroad. As an example, the Southern 

Company (which owns Southern Company Services, 

Inc.) has, within its system of electric utilities, over 

20,ooO MWe of coal-fired generating capacity. 

Approximately two-thirds of this capacity is based on 

pulverized-coal tangentially fired boilers. 

The planned configuration is expected to reduce 

NO, by 60% and decrease furnace wall slagging. 

These low-NO, technologies are being tested separately and then in combination on the 180~MWe 

tangentially fired Unit No. 2 coal boiler at Gulf 

Power’s Plant Smith. Coals being tested during the 

Assuming maximum commercialisation of the 

technology, significant reductions of NO, (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 

Soruhorn Cqmny Servkes/Tongmidfy Fired Coniwfion Program updale 1990 7.51 
Low-NOJSO, Burner Retrofit 

for Utility Cyclone Boilers 

Sponsor: 

TransAlta Resources lt~vesfmettt Corporaticm 

Addltlonal Team. Members: 

State of Illinois, Department of Energy and Natural 

Resources--cofunder 

Electric Power Research Iotitot-funder 

Southern Illinois Power Cooperativ+host utility 

Bechtel Power Corporation-engineer and constructor 

Riley Stoker Corporation-boiler conuactor 

Location: 

Marion. Williamson County, IL (Southern Illinois Power 

Coqxmtive’s Marion Plant. Unit 1) 

Congressional Dlstrlct: 

226 U.S. Congressional District 

Technology: 

TransAlta’s advan& slagging coal combttstor, which is 

a low-NO,, low-SO, (LNS) burner 

plant Capactty/Productlon: 

33 hfWe 

Project Funding: 

Total pr0jec.t cost $15,3co,Ocu 100% 

DOE 6.788.COO 44 

Participants 8,512,CKCt 56 

Project Obpctlve: 

To demoosuate alow-NO,, low-SO, (LNS) buma 

retmfitted to a utility cyclone boiler; and to achieve at 

least 70% SO, reduction on high-sulfur Illinois 

bituminous coals and control of NO, emissions to 

less than 150 ppm. 

7-52 Program update I990 

Technology/Project Dewrlptlon: 

The LNS burna is a pulverized coal-f&. etttrainedflow combustion system with staged combustion. 

Classed as a slagging combastor, the LNS banter 

involves high-temperance, fuel-rich combustion for tbe 

control of bodt SO, and NO,. High-solfur bihtmbtous 

coal, mixed with liiestone, is burned in a refractorylied. air- and water-cooled chamber. Using one&If of 

the total combustion air. the burner creates a hot fuelrich gas. During combustion, sulfttr is captured by the 

calcium from tbe limestone and is retained as a solid in 

the melted coal ash. Nitrogen chemically bound in the 

cd is converted to harmless molecular nitrogen due to 

the creation of a reducing zone. All of these operations 

are cmied out in the burner. 

The staged combustion is expected to achieve very 

low NO, emissions, and injection of tbe limestone 

wrbettt itt the enUeitted-flow system is expected to 

achieve SO, reductions in exceas of 70%. Because ash 

removal efficiency is high, there is *o detating of tlte I 

boiler, no added fly ash handling. and tto degradation of 

boiler tube surfaces. / 

In this project a cyclone-fued boiler is being ! 

Wmtitted with LiW bumers sod a coal pttlverizer I 

system at the 33-MWe Unit 1 of Soutbem Illinois Power 

Cooperative’s Marion Plattt. Two LNS bunters rated at , 

200 MMBnt/br are being used to retrofit tbe existing / 

cyclone boiler. / I 

Trdlto Resources Inves~mmt Corporation 
Calendar veal 

was ,989 Is991 w%? lsw la95 199s 

3 412 3 4 1 :“3 4 I 2 3 4 1 2 3 4 1 2’“3 4 I 23412 3 4 I 2-3 4 1 a’? 4 1 2 

I ‘JOE selected 

pfolod 9mvw 

444 44 I L- Projoc4 completeMlnal report issued SAW 

C@xatbn mpleted 4192, 

OpmIbn InHiated 5091’ 

ConstNdbn completed UBI’ 

t!aign ccmpleted 3al’ 

NEPA praess Completed 391’ 

Environmental monitoring plan cwnplaed 319%’ 

Ground breakh~mmnslructbn atMod 9c9U 

Lymtke agreem.9nt awarded smma 

* Projected date 

Project Status!Accompllshments: 

The cooperative agreement ws.3 awarded on Jute 14, 

1990. 

Construction activities began in late 1990. Major 

equipment is being procued. Test plans are t-aiig 

ftiized. Baseline tests were completed in November 

1990. Consmtction and start-up are expected to be 

fmished in April 1991. aod operation is scheduled to 

begin in May 1991. 

Envlronmantal Considwatlons: 

me ettvimnmataJ assessment with a fuufing of no 

signiticam impact has been prepared and is beiig 

reviewed by DOE. 

Assuming maximutn comtnacialiaation of the 

technology, significaot reductions of SO, and NOs 

(45% and 18% respectively) an projected to be 

achievable nationally by 2010 due to the capability of 

the LNS burner process to remove 70-90% of SO, and 

NO, emissions from coal-f& boilers and the wide 

potential applicability of the process. Negligible 

changes in liquid efflttettts are anticipated, and although 

there is a 17% increase in solid waste, it is dry and 

readily disposable. The slag product may be used as 

road grit and/or sand blast grit. thereby minimiziog 

disposal issues. (Source: Cm Programmatic Environmental Impact Statement) 

Commercial Appllcatlon: 

Coal-ftred utility cyclone boilers represent a total 

capacity of 26.000 We. Because most cyclone units 

are pNSPS, very few units use scrubbers for SO, 

control. Cyclone units also typically generate high NO, 

emissions. ‘Ibe LNS burner has the potential to reduce 

both SO,and NO, emission levels. 

TrmwANa Resowces InvcsaMI CorporaIion Program update 1990 7.53 
CCT-III 

Project Fact Sheets 
lo-MW Demonstration of Gas 

Suspension Absorption 

SponwK: 

Air@, Inc. 

AddItional Team Members: 

FLS miljo sls @rent company of Airpol, Jnc.)- 

Tennessee Valley Autbority-cofunder and site owner 

West Padwah, McCracken County, KY (Rxmessee 

Vdley Authotity’s Shawnee Fossil P+t) 

congreeelonel Dlemotz 

1st U. S. Congressional Disaict 

Technology: 

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

for fhte gas deau&idon (POD) 

Plant CapncHy/Pmductlon: 

IO-MWe equivalent slip-mam of flue gas from a 

150~MWe baila 

Fmleol FundIng: 

Total project cost s6.920*619 103% 

DOE 2,ooo.ooo 29 

Participants 4.920.679 71 

From Ob@tlve: 

To dcmonstmtc the applicability of gas suspmsion 

absorpdon for flue gas desaukadon using higb-sti 

U.S. coals by instaIling and testing a IO-MWe OSA 

demonsnntlon system. 

nohnology/Projeot DeJeotlptlon: 

TIE GSA system consista of a vertical reactor in which 

flue gas comes into contact with suspended solids consisting of lie. waction pnklucts. and fly ash. About 

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

cyclone while the exit gas stream passes through an 

electrostatic precipitatorbefoR being released to the atmosphere. The lie slay. prepaed from hydrated 

lie, is injected through * spay node. at the bottom of 

the reactor. l?ae volume of litne shmy is regulated with 

a variable-speed pump controlled by the measurement 

of the acid content in the inlet and outlet gas streams. 

lbe dilution water added to the lime shy is controlled 

by on-line measwcmems of the flue gas exit temperature. Solids collmed from the cyclone and paticnlate 

control device are combiied and disposed in an existing 

Sitedis~aIea. 

CGA has the potential to remove in excess of 90% 

of the SO2 Bs well as to increase lime utilization 

efficiency with solids recycle. 

This demonstmion is utilizing * IO-MWe slipsueam of flue gas from a 150~MWe coaLfred boiler at 

the Tennessee Valley Authority’s Shawnee Fossil Plant 

in West Paducah, KY. 

756 ProgramupdateI99o 
calendar Yew 

ww IBLIB 1891 1893 Inn4 ,886 Inns ,887 WBS 

3 4 1 2 3 4 1 a’“3 4 1 2 3 4 1 :=3 4 1 2 3 4 1 2 3 4 1 23412 3 4 1 2 3 4 1 2 

I 

WE 

selected 

Pied 

1zmmn 

Ii&?’ 

Praqrational tests initiated 12191’ Projed mmp!aterMiti repoti kdusd 11/g? 

Opwafbn i,-dOatsd 12J9, * 

Gmund tmaking/construcfion starled ,,91’ 

Environmental monitoring plan completed 3181’ 

Design cmlpieted 391’ 

3LzQmtiveagreementaward6d wlmo 

PA praess wmp!eied 9/12,90 ‘~ecled dale 

Projeci StatuWAccompllshmenW: 

The cooperative agreement was awarded October 11, 

1990. Prelimii prwess flow diagrams were prepared 

for discussion and review. and general anangement 

dmwhtgs and sizing and layout of major equipment 

were completed. 

Environmental ConsIderationa: 

hWA compliance has been satiskd by a memo-to-file 

approved by DOE on September 12.1990. 

Assuming maximum commadalization of this 

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

achievable nationally by 2010 due to the capability of 

the GSA process to remove at least 90% of the SO2 

emissions from coal-fned boilers and the wide potential 

applicability of the process. (Source: CC7 F’rogrammatic Environmentsl Impact statenlwt) 

Commercial Application: 

The GSA process offers several advantages over 

conventional FGD tccbnologies. Ail estimates that 

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

than spy 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 case 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 pmcem%. while dry injection processes and spray dryers 

generally remove 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 lowand medium-sulfur coals. 

In summary, GSA is expected to fti 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 sorbem consumption rates and may 

psform better than dry systems: it is both less costly 

and more effective than spray dryem 

PlO@Z”, &hk? 1990 7-57 
Commercial-Scale 

Demonstration of the Liquid- 

~tgwslethanol (LPMEOH@) 

Sponsor: 

Air F’mducts atuK!hemicals, Inc., and Dakota 

Gadfication Company 

Additional Team Member: 

Chem Systems, Inc.--technology developer 

Location: 

Beulah, Ivfercm County, ND (Dakota Gasitication 

Company’s Great Plains Gasification&n) 

(An akemate site is beii considered.) 

Congressional Dlstrlct: 

At-large U.S. Congressional Diiuict 

(An alternate site is beii considered.) 

Technology: 

Chem Systems’ liquid-phase methanol (LPMEOm 

process 

Plant Capaclty/Productlon: 

500 tons/day ofmetbaaol (or about 50 million 

g~loos/yr) 

Project Fundlng: 

Total pmjezt cost: $213.701.857 

DOE 92.701.297 

Participants 121,000.560 

@mling is subjecto negotiation.) 

100% 

43 

5-l 

Project Objective: 

To demonstrate on B commercial scale the production of 

methanol from coalderived synthesis gas using the 

LJMEOH~pmczss: and to determine the suitability of 

7-58 PrO8m crpdatc 15’90 

methanol produced duting this demonstration for use as 

a low-SO,, low-NO, altamuive fuel in boiler. turbine, 

and aanspatation applica!ioas. 

pmdwed hrn coal gasfication facilities as feed to the 

reactor without the need for shift conversion. 

The performance of the L.PMEOHm process for the 

synthesis of methanol is cbawterized as follows: 

* Carbon monoxide conv.zsion to methanol-13% pa 

reactor per pass in a hydrogen-rich feed 

TechnologyIProlect Descrtptlon: 

This project will demomtratc the L.PMEOH” process to 

produce methanol from coalderived synthesis gas on a 

commercial scale. The combined reactor and heat removal system in the LPMEDP press differentiates it 

significlmtly from other commercial methanol prccesses. The liquid phase not only supports the catalyst, 

but functions as an efticient means to remove the heat of 

reaction away from the catalyst surface. This feature 

alone directly permits the we of a low ratio of hydragen to carbon monoxide in the synthesis gas streams 

* Methanol productivity comparable to gas-phase 

systems-6,ooO kg of methanol per 1 kg of catalyst 

- Raw methanol purity-95.6% (fuel-grade) 

* Fe&l gas flexibility-permits the use of synthesis gas 

produced by my commercial coal gasification system 

to be used without shift conversion 

Air Products and Chemicals 
CalendarYear 

3’Y 1 2 lnm 3 4 I :“3 4 1 2 ,981 3 4 1 2 ,892 3 4 1 2-3 4 1 2-i 4 1 2-3 4 1 2 1986 3 4 I 2 ,897 3 4 1 lms 2 

1 

~~0;“” pmj6-d 

‘Pmjeded date: mIlestones are subjea to negoliatbn. 

* Diversity-can be integrated in coal gasitication unavailable for use as the project site. Subsequently. 

combinedcycle applications DOE granted an extension tc October 18,1991, for a 

Chighul plans sited the 5O~Mon/day LPMEOHm 

demonstration facility at Dakota Gasification Company’s Great Plains Gasifxation Plant in Be&h, ND. 

A pation of the methanol prcdwed at the LPM!3.0H” 

demonwation facility would be used in tests to detcrtie its suitability in boila. hubine. and transportation 

fuel applications. The rem&id- would be sold 

comm~~isJly. However, an alternate site is under 

consideration. 

new site to be idcndkd and tc develop tie demonsuation project at a suitable. alternate site. 

Envlronmental bnslderatlons 

Etwlrontnemal information is beiig prepared for use in 

the NBPA process. 

Prolscl Status/Accomplishments: 

The project is in negotiation. Several issues related to 

the business and management structure of the project 

have affected the schedule for negotiation of the 

cooperative *greement. 

Viily all of the sulfw (>99%) can be removed 

in the tnamfacturing process and converted into salable 

elemental sulfur or sulfuic acid. Nitrogen compounds 

(principally ammonia) generated in the gasification 

process are easily removed by cleanup systems and 

subsequently recovered as salable ammonia for fcrtilizer 

manufactwc. lXe principal solid waste from tie gasifer 

is coal ash, which is suitable for landfill disposal. 

the integration of the LPMF!OHa prccess in integrated 

gasification wxnbiied~ycle f.IGCC) applications. 

Cmemly recognized as one of the cleanestccbnologies 

for generating electric power from coal. IGCC can 

economically satisfy the most stringent environmemaJ 

liits for SO, and NO,. In an IGCC facility. LPMEDH’ 

technology is expected to reduce capital costs and 

improve elecuiti power generating flexibility by storing 

energy in the form of mcfbanol. Because of the variety 

of fuel products pmdwai by the indirect liquefaction 

process, the technology can be used to supply fuels for a 

wide range of applications in the utility or industrial 

sector. Virtually any size boiler that uses coal. distillate. residual oil, or nahual gas can use the fuels. The 

technology can be used in both new and renotit 

*pplhiMlS. 

DOE was notified by the sponsors that the Great 

Plains Gasitication Plant located in Bculab, ND, was 

Commercial Appkatlon: 

LPMEOHete&nology can be used in several types of 

commercial applications. Ofparticul~ hqxmmce is 

Air Pwdws and Chemica& PTO#~CWI Lrpr*rtr 19% 7-59 
Healy Clean Coal Project 

Sponsor: 

Al&a Jndustrial Development end Export Authority 

Additional Team Members 

Golden Valley Elecaic Associatiophost utility 

Stone and Webster Engineering Companyenginea and camsnuctor 

TRW. Inc.-tecboology supplier 

Joy Technologies-technology supplier 

Location: 

Healy, AK (Area is unincorporated and without 

COUUtiL?S.) 

Congressional Dlstttct: 

At-large U.S. Congressional District 

Teohnology: 

TRW’S advanced eLmaid (slagging) mmbustor 

Joy Technologies’ spray drya absorber with sabent 

recycle 

Plant Capaclty/Productlon: 

50 MWe (net) 

Project FundIng: 

Total project cost $193,407,Ooo 100% 

DOE 93.862,ooO 48 

Parlicipants 99.545.000 52 

ProJect Obpctlve: 

To demoosuate an innovative new power plant design 

featuring integration of an advanced combostor and heat 

recowy system coupled with both high- and lowtemperantremission cotmol processes. 

7-60 Program update 1990 

iOGREOATE f 

Technology/Project Descttptlon: 

~ehe;mofthesystemmbedemonsVatediswallmetal combostor that consists of two cyliidricsJ sections 

followed by a short duct that conowLs the combastor to 

the boiler. A sepamte precombustor burns about 25% 

of the coal, and the combustion air to the main (or slag 

ping-stage) combastor 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 swirliig motion to the coal and air. he 

balatw. of the coal is injected axially at the front end of 

this cylindrical section. 

Molten slag collects on the walls of the combustor 

and flows toward an opening in the bottom of the main 

combastor where it tills into a water-tilled slag tank. 

The slagging combustor declines slightly from horizontal 

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

solidifies on the water-cooled surface and sewes 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 NO, produced. 

Cqmbution prodncu 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 recowxy fomXion. 

pcduces low NO, levels, functions as a limestone 

calciner, and awomplisbes first-stage SO2 removal. 

The process also uses a single spray dryer absorber 

vessel for second-stage solfar removal and a lime 

activation system that recowrs unused reagent from the 

particulate collected by the baghouse. 

Ala.& IDEA 
CalendarYear 

37 1 4 1 2’9883 2 lmo 3 ,881 1882 lsw ,887 ‘was 

4, 1 2 3 4 1 2 3 4 1 :“3 4 , 2’8943 4 1 :“, 4 I 2 3 4 1 2 3 4 1 2 

i/66 liS? 

t t 

ri$z% 

II 

t 

DOE selected Design mpleted 5m3’ T 

pojed 12mm awarded 341’ 

I I 

Cparatbn wm@ated bQ7* 

Gmund tneaking/mnst~ction 

*misd 11182* z =$-final Wd 

Environmental monhiq plan 

Wmplew s&2+ 

NEPA pmces~ ~~~pbted mz* 

I 

Caatrudion mm@eted 1186’ 

Opwatbn hiliated MW 

Prqerational test8 Initiated 6i35’ 

The slaggii combostor with specially designed 

boiler and the spray dryajxcycle system should be 

capable of reducing NO, by 70% and SO2 by at least 

m. 

The. project involves design, coosWwion, and 

operation of the slagging combastor spray dryer/so&em 

recycle system at a greenfield site near Healy, AK, 

to provide power to the Golden Valley Electric 

Association. 

Pro)ect Status/Accomplishments: 

Negotiation has been completed; award of the cooperative agreement is pending congressional approval. 

Environmental Conslderatlons: 

The environmental information is being prepared for 

use in the NFPA compliaoce process. DOE has published in the Federal Register a ‘Notice of Intent” to 

prepare a0 environmental impact statement end to 

conducr public scoping meetings for this project. 

The following impacts are projected for the Healy 

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

* so2 reduction45% 

. NO, reduction-18% 

Ash removal efficiencies in the combcstor range from 

70% to 80%. Much of the coal’s ash content is removed 

as a molten slag by cyclooic action in the wmbustor 

and, when cool, is a dry, coarse solid suitable for a 

landfdl. (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 boila in 

new and retrofit uses. It CM be used in coal-fired 

boilers as well as in oil- and gas-fued 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-B& low-solfar. low-ash-fusion-temperature coal 

that cyclone boilers require. Furthermore, coal of any 

solfur content can be osed as long as the minimum ash 

content is 5%. The commercial availability of costeffective and reliable systems for SO, and NO, and 

particulate comrol is imponant to potential user3 

planning new capacity, repowering, or retrofits to 

existing capacity in order ta meet the Clean Air Act 

Amendment3 of 1990. 

Ala&n IDEA Program update 1990 7-61 
Full-Scale Demonstration of 

Low-NO, Cell-Burner Retrofit 

Sponeor: 

The Babcock & Wilcox Company 

Additional Team Members: 

The Dayton Power and Light Company--cofander and 

host utility 

Elecnic Power Research Institute--cofondex 

Ohio Coal Dexelqmmt OffiWder 

Tennessee Valley Authority-&.mder 

New England Power Company-c&nder 

Duke Power Company~ ’ 

Allegheny Power System--cotunda 

centerior lhergy company-~ 

Locatlonz 

Abet&en, Adams County, OH payton Power and 

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

Congreeeional DiebId: 

6th U.S. Congressional Disuict 

Technology: 

The Babcock & Wilcox Company’s low-NO, cell 

buma (LNCB) system 

Plant Capaclty/Productlon: 

605 MWe 

Project Fundlng: 

Total project cost $9,796,2LM 100% 

DOE 4,746,204 48 

Participants 5,050.ooLJ 52 

ProJect Objective: 

To demonstrate through the first commercial-scale full 

bumer remfit the cost-effective redaction of NO, from 

a large base-load coal-f& utility boiler with low-NO, 

cell burners; and to achieve at least a 50% NO, 

7-62 Program update 1990 

SOTTOM AaH 

reduction without degradation of boiler performance at 

less cost than conventionaJ low-NO, borners. 

Technology/Propct Deecrtptlon: 

The LNCB technology replaces the upper coal nozzle of 

the standard cell bornez with a secondary-air port. The 

lower burner throat is enlarged to accommodate alarge 

coal nozzle that has the same fuel input capability as 

two standard coal nozzles. The LNCB operates on the 

principle of staged combustion to reduce NO, endssions. Approximately 70% of the total air @imary. 

kxxmhry. 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 fuel-bound niuogen 

compounds are cmnwted to nitrogen gas, and the 

redtmd flame temperature minimim the formation of 

thermal NO,. 

The net effect of this technology is a 50% reduction 

in NOx formation with minimal or no boiler pressure 

part changes end no impact on boiler operation or 

performawe. In addition, the technology is compatible 

with most commercial and emerging SO, control technologies, includingconfiied zone dispersion, gas 

suspension absorption, duct injection, and advanced wet 

scrubbers. 

The demonstration project will be conducted at a 

large-scale power plant opexated by the Dayton Power 

and Light Company and jointly owned with the 

Cincinnati Gas and Blectic Company and the Southern 

Ohio Electric Company. The boiler unit is a B&Wdesigned, supcrcrhical, once-through boiler equipped 

B&WLmv-NOa Cell-Burner 

t 

I 

L 

I 

I 

/ 

! 

I 

1 

I 

! 

I 

I 

I 
’ I 

tt 

LhI 

ProJect ccmpletedninal mpwi issued II&Z 

C~~atimn hISated 691’ 

Operatbn ampleted 9~92~ 

c4naNabn cmpi&d rimI’ 

Preoperaaonal tests ihlliatd 59,’ 

Ground ,maNnglmdru*bn started 3B,’ 

Envimmenal moniloring plan completed ZB,’ 

Cooperative agreement awarded IM 1160 

CSS@I compkied lOB0 

; NEPA bmcess cmpleted WI/80 

DOE seledsd ps@l W/19/89 ‘Projecled dale 

with an electrostatic precipitator. This unit contains 

24 two-nozzle cell burners arranged in an opposed king 

configuration. Twelve burners (arranged in hvo rows of 

six bunters each) are mounted on each of two opposing 

walls of the boiler. The proposed demonsuation will 

require the removal of all 24 standard cell burners and 

the installation of 24 new LNCBs. 

Project Status/Accompllshments~ 

Detailed design for the reuofit was completed at the end 

of October 1990, and procurement and burner fabrication are in progress. &retrofit testing was completed 

in November 1990 and data analysis is under way. 

Initial numerical flow modeliig of the boiler for both 

the prereuofit base case and the LNCB retrofit case has 

been completed. Major sukontractors have ken 

s&aed with the exception of the buma installation 

conuactor who will be selected in early 1991. 

Envlronmental Conslderatlons: 

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

approved by DOE on August 1.1990. 

This technology can be reuofitted only with boilers 

configured with cell-type burners. The retrofit market is 

limited to approximately 37 boilers that emit an 

estimated 728,G0@-1,312.C#O tons/y of NOx. 

Assuming maximum commercializxion nationally 

of the LNCB technology by the year 2010, NO, emissions could be. reduced by 364&0-656,000 tom& 

relative to a no action alternative. (Source: CtT 

Programmatic Environmental Impact Statement) 

Commercial Appllcatlon: 

This retrofit technology is applicable to approximately 

37 coal-fued boilers that are equipped with cell-type 

burners, representing atotal generating capacity of 

approximately 26.000 MWe. 

Bb WiLm-NO* Cd-Burner Program Up&c 1990 7-63 
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 

Location: 

Seward, Indiana County, PA (Pennsylvania Electric 

Company’s Seward Station, Unit No. 15) 

Congressional Dlstrlct: 

4th U.S. Congressional District 

Technology: 

Bechtel Corporation’s in-duct, confined zone dispersion effectiveness during long-term testing and its impact on 

flue gas desulfurization (CZD/FGD) process downstream operations and emissions. 

Plant Capacity/Production: 

13.5 MWe 

Project Funding: 

Total project cost 

DOE 

Participants 

Project Objective: 

$9.211.600 100% 

4,605,800 50 

4~505,800 50 

To demonstrate SO, removal capabilities of induct 

CZD/FGD technology; more specifically, to define the 

optimum process operating parameters and to determine CZD/FGD’s operability, reliability, and costTechnology/Project Description: 

In Bechtel’s CZD/FGD process, a finely atomized 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 downstreti 

and expands, the gas within the cone coois 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 panicle buildup in 

the duct and aids the flue gas in carrying the dry 

reaction products and the unreacted lime to the ESP. 

7-M Program Updare 1990 

The CZDFGD process is expected to remove 50% 

of SO, emissions from coal-fired boilers. If successfully demonsuated, this technology would be an 

alternative to conventional FGD processes, requiring 

less physical space and lower capital, operating, and 

maintenance costs. 

This project includes injection of different types of 

sorbents (dolomitic, calcitic, etc.) with several atomizer 

designs using low- and high-sulfur coals to verify the 

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

control paniculates. 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 through a 

modified duct between the first and second ESP. 

Pennsylvania bituminous coal (approximately 1.2-2.5% 

Bechrel Corpomion 
c.k.n*, “m., 

’ 441; 

t 

t 

Operatim initiated 6,91* 

t 

-. Prqect completedninal report issue-3 T/93’ 

operation completed 5,93^ 

Environmental monitoring plan completed 5191’ 

Prwperaticnal tests initiated 5191’ 

Gans.tru*ion mlpl*ted S/91’ 

Grn”“d breaki”g/~nstrualon stalled 241’ 

DeJign completed 12190 

Cooperative agreement awarded 1011390 

NEPA procas.7 wmpleted 9mv90 

DOE s&c&d project 12119/89 ‘Projected date 

I 

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

test program is complete, continuous, fully automated 

and integrated (with the regular power plant) operation 

is planned for a year. 

Project Status/Accomplishments/ 

The cooperative agreement was awarded on October 13, 

1990. Design activities, which began in June 1990. 

were, completed by the end of December 1990. Construction is scheduled to begin in February 1991. and 

stan-up is expected to begin midyear. Operation is 

scheduled for June 199 I. 

Envlronmental Condderatlons: 

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

approved by DOE on September 20,199O. 

Sorbent injection technologiesuch as the 

UD/FGD process could redwe national emissions of 

SO, by as much BS 38% by 2010, assuming maximum 

commercialisation of the technology. NSPS levels of 

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

Although the volume of solid waste is increased 8%. 

it is dry, nontoxic, and easily disposable. 

Commercial Appllcatlon: 

CZD can be used for retrofit of and installation in new 

utility boiler flue gas facilities to remove SO, derived 

from a wide variety of U.S. sulfwcontaining coals. 

A CZD system can be added to a utility boiler with 

a minimal capital invesrment of $2.5-55&W of installed 

capacity, or one-third the cost of building a conventional 

wet 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 reaoiitting onto existing boilers, independent of 

type. age, size. or coal burned (e.g., type, salfar 

content). The CZD installation does not require major 

power station alterations and can he easily and economically integrated into existing power plants. 

Be&d Corporation Program Updale 1990 7-65 
Blast Furnace GranulatedCoal Injection S stem 

Demonstration J reject 

Sponeor: 

Bethlehem Steel Corporation 

Addltlonel Team Members: 

British Steel Ckwltants Ovawas Services, Inc. 

(marketing arm of British Steel)-technology owner 

Simon Macawk, Ltd.--equipment suppliex 

ATSI, Inc.-architect and en8itte.z 

Lcsetkil: 

Bums Herbor, Potter County, JN (Blast Ijurnace Units C 

&D) 

Congreeelcnel Dlstrlct: 

1st U.S. Congressional District 

British Steel’s blast fmnece gmm~latedaal injection 

(Brocr,proce~ 

Plant Cepeclty/Pmductlon: 

7,ooO net tom/day of hot metal (each blast funace) 

Project Funding: 

Total project at $143,8oO,ooO 100% 

DOE 31.2259.530 22 

Panicipflms 112540,470 78 

Project Oblectlve: 

To demonstrate that existing iron-making blast furnaces 

can be retrofitted with blest furnace granulated-coal 

injection technology; and to demonsuate sustained 

opem!ion with a variety of coal particle sizes, coal 

hjection rates, and coal types and to Bssess the intmactlve nature of these parameters. 

Technology/Project Deecriptlon: 

Jn the BFCCI process. both gmmtlated and pulverized 

coal is injected into the blest furnace in place of oetmal 

gas (a oil) BS a blast fitmace fuel supplement. The coal 

along with heated air is blown into the barrel-shaped 

seztion In the lower part of the blat futttace through 

pesseges celled myeres, which creates swept zones in 

and redttctant (redWing apent), on approximately a 

pound-for-pound basis. Because coke production 

results In significant SO, and NO, emissions and coal 

could replace yp to 40% of the coke requirement, 

BFGCI technology hu significant potential to reduce 

emissions and enbence blast furnace production. 

Emissions generated by the blest fmnace itself 

the finnace called raceways. The size of the raceway is remain virtually unchanged by the injected coal; the gas 

htIpOIttmt and iS dependent upon many fectors i11~1udhg exiting the blast furnace is clean, containing no measurtemperature. Lowering of the raceway tempaature, able SO2 or NO,. Sulfm fmm the coal is removed by 

which cm occur with gas injection, reduces blast the liiestone flux and bound up in the slag, which is 

f!xtIace prOdWiOn rates. Coal, with a lower hydrogen readily salable BS a constmction aggregate material 

content than either gas or oil, does not cause as severe a ml rock wool. In additicm to the net SO, end NO, 

reduction in meway tempet’atur~. In addition to reduction real&d by coke displacement. blast furnace 

displacing injeaed natural gas. tbe coal injected tbroogh p’cduction is incteased by maimaMng high aceway 

the tuyeres displaces coke, the primary blast furnace fuel tem~mmres. 

7-56 PlOgrMl trpd&? 1990 Bethlehem SteeUBlast Furnace 
ti* Year 

3’9884 ,968 lwl tw wsz I%3 19% 1ws 1897 

1 2 3 4 1 2 3 4 1 2 3 4 1 23412 3 4 1 23412341 2Y 4 1 2 3 4 

t 1898 

2 

T 

t%s@l completed 6.632’ 

Environmental monitoring plan cmpieted 6191’ 

NEPA pmcsss cmpleted 6iW’ 

Gmund Lwakinglmnsfructbn statad 6,W 

DOE reledad pro,ecl 12/W/88 

Cperatbn hkted 7,%4’ 

nSt1~c0on mmpkisd V94’ 

Opxatbn cmpleled 9196’ 

Pro,ed mpietedtlnal report 

i8.9wd Qms’ 

Two higb-apacity blest fmnaca Units C and D at 

Bethlehem Steel Corpomtiot~‘s Bums Ha&or Plant, are 

belq retrofitted with BFGCI technology. Each unit has 

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

ProJect Status/Accomplishments: 

‘lb cooperative agreement WELT awarded November 26, 

1990. Design is under way; the conceptual design of 

the blest iirnece gmt~ttlated-coal injeaion system ha 

been completed. Coosttuction is scbedtded to begin in 

mid-1991. 

Envlronmental Conslderatlons: 

Fnvimnmental information far we in the NEF’A compliance process has been compiled. 

The largest reductions in emissions resulting from 

COmmerCialimiOn Of the BFGCI technOlOgy are 

expeaed to OCCUI inthe coke-making process. As the 

BFGCl technology reaches full market &!aetn~iott, d-te 

amount of coke required for blast fomacee would 

decrease, tints reducing the emissions associated with 

B&khan Sted!Blast Furnace 

its prc&ction. Although a slight increase in slag can be 

eXpeCted from the C0d & the Slag is readily salable as 

ccmstmction aggregate or mck wool. 

Commercial Appllcatlon: 

This technology can be. applied to essentially all blast 

furnaces in the United States. It is anticipated tbet a 

wide variety of co& can be used. 

Progtm updote 767 
Air-Blown/Integrated 

Gasification Combined-Cycle 

Project 

Sponsor: 

clean Power cogeneration Limited Parmership 

AddItIonal Team Member: 

City of Tallabawe-host utility 

LOl%tlOll: 

Tallahmee, Leon County, PL (City of Tallahassee’s 

Arvah B. Hopkins Station) 

Congressional District: 

2d U.S. Congressional District 

Technology: 

Largi-based integrated gasification combinedcycle 

(IGW system 

Plant Capaclty/Productlon: 

120 Mwe 

pr0~et.A Funding: 

Total project cost $241,458,0cn 10090 

DOE 120,729,CGU 50 

F%rticipts 120,729,OGU 50 

Project Objective: 

To demonstrate air-blown fued-bed integrated gaSiiiCation combined-cycle technology and to assess long-tetm 

reliability, availability, and maintainability at sufficient 

SC&. to determine cotmnewial potential. 

Technolcgy/Project Descrlptbn: 

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

gasifier. The 1owBta coal gas leaves the gasiiier at ap 

proximately 1,000 “I’ and goes to a hot gas cleattup 

system where the removal of salfar compounds is 

accomplished in amoving bed of solid smbent. The 

cleat& 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 presserized air extraction, which is used a3 gasiiier 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 

gasifiia blast. The project has the following subsystems: fued-bed coal gasification Qrgi). hot gas 

cleanup, a combustion ta&ii capable of using low-Btu 

coat gas, selective catalytic reduction for NO, control, a 

btiquettor to utilize coal fmes, and the balance of plant. 

In the demonsnation project, a nominal 1.270 tons/ 

day of coal is convertedinto 120 MWe. The base feed 

coal for the project is a high-sulfur Illinois Basin bimminom coal. The propow site is the City of Tallahassee’s AI-&B. Hopkins Station, which is located in 

Tallahassee, FL. 

768 Program update 1990 Clef Power Cogcneration 
calendar Year 

3’8884 1 2 198s 3 4 1 :“3 4 1 2 laQI 3 4 1 23412 188ISa3 3 4 1 2 lm4 3 4 1 2 lsu5 3 4 t 2 1808 3 4 1 2 ,887 3 4 1 ,888 2 

A 

* i I 

t 

t 

cpmtbn ccmpbted lm5’ 

*raIlon Inlied l&.4* Pro)ea canplet&liwl report ibsued lZ95’ 

Pmperalional teats initiated 3493 

NEPA p- mmpleted 2&Q 

constludbll inltiated a%z* 

c.xQewive agreement werded 3.91* 

DOE seleded prc+ct 12Rlt8p 

‘Projated date 

Prolecl Stetus/Accompllshments: Commercial Applicetlon: * so, reduction-9?% 

The project is under negotiada. In recent years, IGCC has become a rapidly emerging 

Envlronmentel Conslderetlons: 

alternative for new elexxricity generating plants. Such 

. NO, ~tduction-95% 

plants require 15% less land area than pulverized coal * Plant efficiency-up to 48% . . .I on LS oentg comptteu *or use * 

the NEPA compliice process. 

Assuming maximum commercializatiott of IGCC 

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

plants with flue gas desulfuliz.ation. IGCC te&oology 

also can be wed in repowering, where a gasifier, gas 

stream cleanup unit gas turbine, and waste heat recovmy boiler are added to replace the existing coal-fued 

boiler. The remainittg equipment is left in place. includ- 

* Incremental power increase-230% 

. Fuel flexibility-permits use of Wide range Of Coals 

- Compacmess-high process efficiency reduces space 

requirements per unit of energy generated 

* so, reduction-37% 

. NO= reduction-17% 

. Solid waste reduction-5% 

. CO2 reduction-6% 

(Source: CCC Programmatic Envhuntnemal Impact 

Statement) 

ing the steam turbine and electrical generator. Because 

of its advantages of modularity, rapid amI staged on-liie 

genaation capability, high efficiency, enviromn~tal 

controllability. and reduced land and nataral resource 

needs, another impxtant application for IGCC is 

cogeneration under the PURPA Qualied Facility 

regulations. 

The perfomlance pmntial of IGCC technology in 

* Modular const~ction- lends itself to economic 

addition of capacity increments to match load 

growth 

its commexcial contiguration is cbaracterized as follows: 

CIean Power cogenmdon Program updott? 1990 7-69 
Alma PCFB Repowering 

Project 

Sponsor: 

Dairyland Power Cooperative 

Addltlonal Team Members: 

Pyropower Corporation-technology supplier 

Black and Veatch-architect and engineer 

Locatlon: 

Alma, Buffalo County, WI (Dairyland Power 

Cooperative’s Alma Power Station, Units 1 and 2) 

(Alternate sites are under consideration.), 

Congresslonal District: 

3d U.S. Congressional District 

Technology: mm-+~RW”l4C s I MM 

Pyropawer Corporation’s pymflow pressarlzed 

circulating fluidized-bed combustion (PCFB) combmedcycle system 

Plant Capacity/Production: 

40 MWe 

ProJect Fundlng: 

Total project cost %189,393,0c@ 

DOE 93,253.lwo 

Participants 96,140,OOO 

(Funding is subject to negotiation.) 

100% 

48 

52 

Project Objective: 

To demonstrate PCFB at sufficient scale to evaluate 

environmental, cost, and plant performance and to 

obtain the technical data requisite to commercialiration 

of the technology; to assess efficiency improvements as. 

sociawd with integration of a hot gas cleanup system 

using a ceramic barrier filter and inclusion of a topping 

combastor: to achieve SO, reduction in excess of 90% 

and NO, reduction of 70%; and to improve plant 

efficiency by up to 15% of its current rating. 

Technology/Project Description: 

In the PCFB process, coal is cornbusted at about 

1,600 OF in a circulating fluidized bed contained within 

a pressure vessel. Limestone is used within the bed to 

absorb sulfur compounds. Particulatea 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 temperature 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 

dovmsueam from the gas mrbine are used to generate 

power in two existing steam turbines. 

The Alma project would be the world’s tirst largescale demonstration of PCFB technology. As originally 

proposed, two commercially operating 18-MWe pulverized coal-fired steam turbines would be repowered with 

a single PCFB combustor integrated with an oil-fired 

topping combustor and a gas turbinemodule operating 

in a combined-cycle mode. The boilers proposed for repowering are Units 1 and 2 of the Alma Station located 

in Alma, WI. The repowered plant would have a 

capacity of at least 40 MWe. However, alternate sites 

are under consideration. 

7-70 Progrmn Update I990 Dairyland Power Cooperative 
II CalsndarYM 3’8884 I 1 2’9Ba3 4 1 :“3 4 1 2 we1 3 4 1 2 lees 3 4 1 2-3 4 1 2 3 we4 4 1 :“, 4 I 2 ,908 3 4 1 2 1087 3 4 1 Ima 2 

11,’ ckxpemthre agreement awarded 7rnl’ 

0oE reloaed pmjm imass 

‘Pmjeded Me; milestones are sutjad lo negotiatbn. 

Projeci Status/Accomplishments: 

The project is in negotiation. 

Environmental Considerations: 

Environmentat information is being compiled for use in 

the NBPA compliance process. 

Assuming maximum commercialimtion of the 

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

* so,mductiw-48% 

. NO, reduction-17% 

l Solid waste decrease-4%. with the solid waste in a 

dry, granular form amenable to altentative uses such 

as conshuction aggregate 

. CO, nxhwicm-8% 

(Somw ccr Programmatic Environmental Impact 

statement) 

Commerolal Application: 

The wmbllcycle FCFB system permits the combustion of a wide range of coals. including high-suifm 

coals, and would compete with the bubbling-bed PPFJC 

system. Lie the bubbling-bed system, PCPB can be 

us3.i to reposer oil- and gas-fti boiler units. while 

switch tbm to high-sulk coal; to rqmver walfred power plants; and to build new PCFB units. 

Combmed<ycle FCFB technology appears to be best 

suited for eleuric utility applications in medium 

(100-400 MWe) and large 0 400 MWe) plants. Because of modular cmwrwtion capability, PCFB 

generating plants permit utilities to add economical 

lmements of capacity to match load growth and to 

repaver with PCFB using the existing plant area. coaland waste-handling equipment. and steam turKme 

equipment 

* soz reduction-95% 

l NO, reduction-80% 

* plant efficiency increase-up to 45% 

- lmmmental plant efficiency-improved g-15% 

a Fuel flexibility-pamits use of wide range of coals 

_-. 

- Compacmess-high process eittcmcy reuuces space 

requiremems pa wit of energy generated 

. Modular ams!nction-lends itself to economic 

additicm of capacity increments to match load growth 

The performance ptemial of PCPB technology is 

characterized a.9 follows: 

Dairylmi Power Cooperative Program update 1990 7-71 
ENCOAL Mild Coal 

Gasification Project 

Sponsor: 

BNCOAL Corporation (subsidiary of Shell Mining 

c,=v=Y) 

Addltlonal Team Members: 

Shell Minjng company-cofimder 

TEK-KOL (pannership between Shell Mining Company 

and SC1 Intanatiol@-technotogy owner. Sup~lia, 

and licensor 

t?Gl httemational-technO1Ogy developer 

Triton Coal Company (subsidiary of Shell Mining 

Company&host facility and coal supplia 

‘he M. W. Kellogg Company-enghteer and 

Location: 

Near Gillette. Campbell County, WY (Buckskin Mine) 

Congreeelonel Dletttct: 

At-large U.S. Co%~gr&onal Disaict 

Technology: 

SGI Intemational’s liquids from coal (LFC!) prwess 

Plant CepecltylProductlon: 

l,oOa tons/day of subbhumlnous coal feed 

Project Funding: 

Total project cost 

DOE 

Participants 

$12,564,C00 100% 

36.282.000 50 

36,282,ooO 50 

The @S ~OdUCed in the pymlyzer is sent rbrough a 

cyclone for removal of tie. particulates and then cooled 

to condense the liquid fuel products. Most of the gas 

from the condensation unit is recycled to the py~olyzer. 

‘Ihe 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. 

Project Ob)wtlve: 

To demonstrate tbe integrated operation of a number of 

nOW.1 operating Steps 10 PrOdaCe tW0 high= VillUe fuel 

forms from mild gasitication of low-salfur subbimminous coal: and to pmvide sufficient products for 

p~tentlal end users to conduct bum tests. 

Technology/Proje* Descrlptlon: 

The BNCOAL mild coal gasification process involves 

heating coal under camfully contmlled conditions. Coal 

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

gas stream to reduce the moisture content of the coal. 

The solid bulk temperature is con!xolled so tbat no 

significant amounts of methane, carbon monoxide, or 

carbon dioxide are released from the coal. The solids 

from the dryer am conveyed to the pyrolyzer where the 

rate of heating of tie solids and residence time are 

contmlled to achieve desired properties of the fuel 

products. During processing in the pyrolyzer. all 

mmaining free water is removed, and a chemical 

reaction occurs that results in the release of volatile 

gaseous mataial. Solids exiting the pyrolyzer are 

qwnched, cc&d, and transferred to a surge. bin. 

‘Ihe offgas from the dryer is treated in a venturi 

scrubber to remove particulates and a horizontal scrubber 

to remove SO, both using a sodium carbonate solution. 

The treated gas is vented to a stack, and the spent 

solution is discharged into a pond for evaporation. 

The site of the ENCOAL project is located within 

Campbell County. WY, at T&on Coal Company’s Buckskin Mine. 10 miles north of Gillette. The plam makes 

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

7-72 h8rM, [Ipdnte lpi%, ENCOAL Corporadon 
cab& Yew 

a’“, 188s 

:“3 

1ew 1eez 1983 wB4 lee5 IS98 ,697 ,888 

1 2 3 4 1 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 I 2 3 4 1 2 

1: 

I 

A A444 4 4 4 

I 

I 4 

CMlstwdbn completed 9182. 

- ProJec4 ccmplekfvnnal repon )rrsued ws4* 

QwalbnhMtsd S/92’ 

Pleoperalbnal lest8 initiated 3182’ 

Design cnmpkted 5l91’ 

Envimnmentd moniiodng plan completed ml* 

COnstrudb” earled ,0/w) 

r2oqwmlve agreement awareed eA7Bo 

NI EPA procsas completed eJlm0 

cxx aded pt0jea me/88 

‘Prcjecbd date 

Project Status/Accomplishments: 

The cwpmative agreement for this project was awarded 

on September 17.1990. 

Both design and conshw~on activities are ahead 

of schedule. Detailed design is 60% complete. The 

largest continuous concrete pour (3,000 yd3 in a 32-hr 

period) ever performed in Wyoming was completed. 

Full mobilisation of the field office is scheduled for 

March 1991. 

Envlronmental Conslderatlons: : 

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

impact approved by DOE on August 1.1990. 

Assuming maximum commercialization of the mild 

coal ghfmtion technology on anational basis by 2010 

relative to a no-action alternative, the following impact5 

arc pmjeetedz 

- SO2 reduction-5% 

. NO, reduction-2% 

- Solid waste increase-14%. however, tbis is 

a dry, salable by-product. 

expsaed to be used economically in commercial boilers 

and firnacea and to significantly reduce salfur emissions at induskial and utility facilities cmmntly burning 

high-sulfiu bhuminous fuels or fuel oils. 

(Source: CCT Progmnmatic Bnvironmemal Impact 

Statement) 

Commercial Appllcatlon: 

‘Ihe 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 lbnited to lower &fur, low-heating-value CO&. 

‘Ihe potential bemflts of this mild gasification technology in its commacial configuration are atnibutable 

to the increased heating value and lower sulfu content 

of the new solid fuel product, compared to the subbimminous feed stock and the production of liquid pxducts 

requiring limited hydroutig. The product fuels are 

ENCOAL Corporation Program updale 1990 7-73 
Evaluation of Gas Reburning 

and Low-NO Burners on a 

Wall-Fired Bhiler 

Sponsor: 

Energy and Enviromuental Research Corporation 

Additlonal Team Members: 

Public Service Company of Colomdo-cofunder and 

host utility 

Gas Research Jnstitute-cofunder 

Colorado Interstate Gas Company-cofunder 

Elecuic Power Research Institute-cofunder 

Location: 

Denver, Adams County, CO (Public Service Company 

of Colorado’s Cherokee Station Unit No. 3) 

Congresslonsl District: 

1st U.S. Congressional District 

Technology: 

Energy and Environmental Research Corporation’s gas 

reburrdng and low-NO, bumer system 

Plant Capacity/Production: 

172 MWe 

Prolect Fundlng: 

Total project cost $14.472.117 10096 

DOE 7,236,058 50 

participants 7,236,059 50 

Project Ob/ective: 

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

from an existing wall-fred utility boiler fvhtg lowsulfur coal using both gas rebuking and low-NO, 

burners. 

7.74 Progrm Updare’l99O E&?/Wall-Fired BoiIer 

Technology/Project Descrlptlon: 

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

total fuel input) above the main coal combustion zone in 

a boiler. This upper-level firing creates a slightly fuelrich zone. NO, drifting upward from the lower region 

of the furnace is ‘Yeburned” in this zone and converted 

to harmless molecular nitrogen. Low-NO, burners 

positioned in the coal combustion zone retard the 

production of NO, by staging the burning process so 

that the coal-air mixture can be carefully controlled at 

each stage. The synergistic effect of adding a rebuming 

stage to wall-fired boilers equipped with low-NOx 

burners is projected to lower NO* emissions by as much 

as 15%. 

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, 

burners on a 172-MWe wall-tired utility boiler. Westem bituminous coal is being used. 
lCalendar Year 

1988 1989 1990 1931 1992 ,993 ,894 19% 1997 1998 

3 4123412311*3412341234123412341 2’9963 4 1 2 3 4 1 2 

12/89 1 o/so S/92 s/94 

‘I ’ 

t 

T” Proiect completed~inal report issued 5194’ 

op.mion cmlpleled 3t9.4’ 

Conslruclion completed 9/92 

Operation Maled 9LQ’ 

Ground breakIng/mnslruction started 7BI’ 

Design compl&d 7/91* 

Cooperative agrw”e”1 awarded IOil 3/90 

NEPA process completed WW90 

Environmental monitoring plan completed 7/26/90 

WE SeleCled project 12119189 * Pro~sd date 

Project Status/Accomplishments: 

Design and permitting activities are proceediig well and 

are expected to be completed in July 1991. Preliminary 

high-velocity testing for baseline flue gas temperahues, 

velocities, and oxygen content was conducted. The environmentaJ monitoring plan bas been prepared. 

Environmental Considerations: 

NEX’A compliance has been satisfied by amemo-to-file 

approved on August 31.1990. 

Assuming maximum commercialisation of gas 

rebuming and low-NO, burners on a wall-fired boiler on 

a national basis by 2010 relative to a no-action altemathe, NO, emissions could be reduced by 13%. The 

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

SO, on a national basis. No changes in liquid effluents 

or solid wastes are anticipated. (Sauce: CCT Programmatic Environmental Impact Statement) 

Commercial Application: 

Gas rebaming in combination with low-NOx burners is 

applicable to wall-fired utility boilers. The technology 

can be used in both new and pre-NSPS wall-fired 

boilers. 

Specific featares of this technology that increase its 

potential for commercialization are as follows: 

. Can be retrofitted readily to existing units 

* Reduces NO, emissions by more than 70% 

* Suitable for use with a wide range of coals 

. Has the potential to improve boiler operability 

. Has the potential to reduce the cost of electricity 

* Consists of commercially available components 

* Requires minimal space 

EERIWoN-Fired Boiler Program Update 1990 7-75 
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 

Tampella, Ltd.-cofunder and technology owner 

Richmond Power and Light-cofunder and host utility 

Electric Power Research Institute-coftmder 

Peabody Coal Company-cofundez 

Black Beauty Coal Company-cofunder 

LaFarge Corporation-cofunder 

Locatlon: 

Richmond, Wayne County, IN (Richmond Power and 

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

Congressional Dlstrtct: 

2d U.S. Congressional District 

Technology: 

LIFAc’s sorbent injection process with sulfur capture in 

a unique, patented vertical activation reactor 

Plant Capaclty/Productlon: 

6OMWe 

Project Fundlng: 

Total project cost $17,018,982 lCQ% 

DOE 8.509491 50 

Participants 8,509,491 50 

Project Objective: 

To demonstrate that electric power plants-especially 

those with space limitations-burning high-sulfur 

7.76 Prqram Update 1990 

Indiana coals, can be retrofitted successfully with the precipitator. The waste is dry, making it easier to 

LlFAC limestone injection process to remove 75~35% handle than the wet scrubber sludge produced by 

of the SO, from flue gas and produce a dry solid waste conventional wet limestone scrubber systems, 

product for disposal in a landfill. The technology enables power plants with space 

Technology/Project Descrlptlon: 

Pulverized limestone is pneumatically blown into the 

upper part 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 

limitations to use high-solfur midwestem coals by providing an injection process that removes 75-85% of the 

SO, from flue gas and produces a dry solid waste 

product suitable for disposal in a landtill. 

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. 
Calendar Year 

W.98 ,989 ,990 1991 1992 ,993 1994 1995 ,996 1997 1998 

3 4,2341234,2341 2341234123412341234123412 

Design and COnltrUction 

11193 

“:I I’ 

t 

1 

t 

Operalion initialed 9191’ Pro@ct completed*inal report issued 11193’ 

Preaperational tests iniliated 8i91’ Operalion compleled %93 

Cmstrudion compleled 7191’ 

Ground breakingimnslruction skied 2191’ 

Environmental monitoring plan completed 1191 

Design completed lZ28190 

Cooperafive agreement awarded 1 IROB 

NEPA process completed 9127190 

DOE selected projecf 12119189 * Projecled dale 

Project StatuslAccompllshments: 

The cooperative agreement was awarded on November 

20, 1990. The LIFAC team completed the development 

of the preliminary design package. Reparations are 

under way to procure. the key pieces of equipment 

required for a March 1991 outage. 

Environmental Considerations: 

N!ZPA compliance has been satisfied by a memo-to-file 

approved on September 21, 1990. 

Assuming maximum commercialization, significant 

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

nationally by 2010 with the LIFAC 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) 

‘Ihe benign waste material can be disposed in a 

landfill along with the fly ash. The material also may 

be used as a road bed or excavation till material. 

Commercial use of the LIFAC by-product in the 

manufacture of construction materials is currently b&g 

investigated in Finland. 

Commercial Application: 

This process is suitable for application to all coal-fred 

utility or industrial boilers, especially those with tight 

space limitations. The LILAC process offers the 

following advantages: 

- It is less expensive to install than conventional 

wet flue gas desulfurization processes. 

- It ttse~ dry limestone instead of the more expensive 

lime. 

- It is relatively simple to operate. 

- It produces a dry, readily disposable waste. 

LIFAC Program update 1990 7-n 
Commercial Demonstration of 

the NOXSO SOJNO, Removal 

Flue Gas Cleanup System 

Sponsor: 

MK-Ferguson Company 

Additional Team Members: 

NOXSO Corporation-cofunder and technology 

supplier 

W. R. Grace and Company-cofonder 

Ohio Edison Company-cofunder and host utility 

Ohio Coal Development Office-cofundy 

Gas Research Institute-coftmder 

Electric Power Research Institute-cofunder 

East Ohio Gas Company-cofttnder 

LocatIon: 

Nile& Tnmtbull County, OH (Ohio Edison’s Niles 

station, Unit 1) 

Congressional Dlstrlct: 

17th U.S. Congressional District 

Technology: 

NOXSO Corporation’s dry, regenerable flue gas 

cleanup process 

Plant Capacity/Production: 

108 MWe 

Project Fundlng: 

Total project cost $66249,696 lC@% 

DOE 33.124.848 50 

Participants 33,124,848~ 50 

Project Objectlve: 

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

boiler flue gas using the NOXSO process and to remove 

7.78 Progrm Update 1990 

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. In 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 sorbem. The sorbent consists of 

spherical beads of high-surface-area alumina impregnated with sodium carbonate. The cleaned flue gas then 

passes to the stack. 

The NOXSO sorbem regenerates with heating, 

which causes the NO, to desorb and partially decompose. The hot air containing the desorbed NOx is 

recycled to the boiler where equilibrium processes cause 

destruction of this NO,. The adsorbed sulfur is recovered from the sorbent in a regenerator where it reacts 

with methane at high temperature to produce an offgas 

with high concentrations of SO, and hydrogen suliide 

(IZS). 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 beiig demonstrated at Ohio 

Edison’s Niles Station, Unit 1, a 108-MWe cyclone 

boiler. MK-Ferguson will design, cottstruct, and 

operate a full-scale commercial NOXSO unit to 

demonstrate process feasibility. The project is being 

structured so that data from the proof-of-concept facility 

being constructed at Ohio Edison’s Toronto Station can 

MK-Ferguson Company 
Calendar “ear 

,988 1989 79% 1991 1992 193s 1995 199s 1987 ,998 

3 4 1 23412 3 4 1 23412 3 4 1 2 3 4 t 219843 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 

12189 3/91 7194 l/97 

A 

-1 ’ 

i ’ 

t 

Operalion initiated 7194 

Preoperational I*sfs lnitiabd 6194’ 

Construction Ccwlrudion mmpleted 6/94’ 

started 4,93’ 

Design completed 3193’ 

1[ 

NEPA process completed 3192’ 

Project completed, 

final report issued 1197’ 

Environmental monitoring plan completed 8191’ Operation completed 11199 

CooperaWe agreemenl awarded 391’ 

DOE seleded project 12/19/89 * Projected date 

be available before rhe end of the project definition 

activity. 

Project Status/Accomplishments: 

Negotiation was completed in December 1990; approval 

of the cooperative agreement is pending congressional 

approval. 

Environmental Conslderatlons: 

Environmental information is being compiled for use in 

the NEPA process. 

By 2010, national emissions of SO, could be 

reduced by as much as 48% and NO, by 11%. assuming 

maximum commercialisation of this technology relative 

to a no-action alternative. Also, the process results in 

essentially no increase in solid waste and prcdu~es a 

salable by-product (sulfur). (Source: RogramoMic Environmental Impact Statement) 

Commercial Appllcatlon: 

The NOXSO process is applicable for reuofitting 

existing coal-fired power plants or for use in new 

facilities. The demonsuation is expected to use southeastern Ohio and western Pennsylvania coal (3.2-3.5% 

sulfur average). The process is adaptable to coals with 

higher sulfu content. 

Commercial-grade sulfu, 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 NOx and/or need to eliminate solid 

wastes. 

MK-Fer@mn Cornpony Progmm updare 1990 7-79 
Integrated Dry NO /SO, 

Emission Control System 

Sponsor: 

Public Service Company of Colorado 

AdditIonal Team Members: 

Elmic Power Research Institute-cofundfl 

Stone and Webster Engineering Company-engineer 

The Batack & Wilcox Company-bumer developer 

FosSilbergy Research Ccqomtion-opemtiuoal 

testing 

Western Research Instih~te-fly ash evaluator 

Colorado School of Mines--engineaing research 

andtesting 

Vendor (to be de&mine+-urea system provida 

Lwxtion: 

Denver, Denver County, CO (Poblic’Savice Company 

of Colorado’s Amp&e. Station, Unit No. 4) 

Congreeelonal Dletrlct: 

1st U.S Congmssional Disaict 

Technology: 

The B&cock & Wilcox Company’s low-NO, burners, 

induct sorbem injection, and furnace (urea) injection 

Plant Capaclty/Productlon: 

lOOMwe 

Pro@3 Fundlng: 

Total project cost $26.411.818 lCO% 

DOE 13.238.939 50 

Participant5 13.238939 50 

Probct Objective: 

To demonstrate the integration of three technologies to 

achieve up to 70% reduction in NO, and SO, emissions; 

more specifically, to assess the. integration of a downfired low-NO, burner with in-furnace urea injection for 

7-80 Progmm update 1990 

additional NO, removal and dry sorbent induct 

injection with humidification for SO2 removal. 

Technology/Project Deecrlptlon: 

All of the testing will use B&cock & Wilcox’s low-NO, 

XCL down-f& burners with over-fm? air. These 

homers control NOa by injecting part of the coal and 

pat of the combustion air in an oxygen-deficient 

environment. Additional fuel end combustion air are 

introduced in a secad stage to advance the combustion 

process. Additional air is introduced to complete the 

combustion process and further enhance NO, removal. 

The low-NO= burners are 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-fomace urea injection is 

being tested to determine how much additional NO, can 

be removed from the combustion gas. 

Two types of dry sorbents ae being injected into 

!be ductwork downstream of the. boiler to reduce SO, 

emissions. E&es calcium is injected upstream of the air 

heater or sodium or calcium is injected downstream of 

the air heater. Humidification downstream of the dry 

sorbem injection enables the eIectmstatic precipitator to 

maintain @ormane. Humiditication 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 

Ampahoe Station Unit No. 4, a IDO-MWe down-fued, 

pulverized-coal boiler with roof-mounted burners. 

Public Service Company of Coiorado 
‘constN*bfl completed llrnl’ 

Opemtbnlnliated 11,W’ 

Dssiin cmpi6ied SW* 

Pfeopenruonal tests i”iuated ml* 

Envimnmental nwnbim~ plan compbtsd 6,91’ 

CxQmralNe agreement awarded 391’ 

Ground bm&hglmnsINdion slatted 3B1’ 

Projecl Eompletedninal rspod issued 495’ 

OperaQon c.mpbted 11,94* 

proiea I 

lY19rQQ NEPA pmcess ccmpkd 9rZ7iQO 

‘Projected dale 

ProJecl Status/Accomplishments: 

Negotiation has been completed; award of the coopemtive agreement is pending congressional approval. 

Envlronmental Conslderatlons: 

Commercial Appllcatlon: 

Urea injection and sorht injection are both applicable 

to most utility and hdushial coal-tired units and can 

be retmtitted with modest capital investment and 

downtime. 

NEF’A compliance has been satisfied by the signing of a 

memo-to-fde approved by DOE on Septemk.r 27.1990. 

SO, reduction is in the range of 575%. Although 

the volume of solid waste is considerably increased, itis 

dry, easily disposed of. and nontoxic. From a national 

pxspective. a 38% SO, reduction is projected by 2010, 

assuming maximum commacialization of the sorbent 

injection technology. Urea injection Gould enhance 

NOx reduction, thereby increasing low-NO, burner 

impact on national reductions from the presently 

projected 11%. (Source: CCTFTogrammatic Environmental impact Statement) 

Public Service Company of Colorado Program Update 1990 7.81