TECHNOLOGY 

U.S. Department of Energy 

Assistant Secretary for Fossil Energy 

Washington, DC 20585 

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DOE/FE-0272 

Clean Coal Technology 

Demonstration Program 

Program Update 1992 

(As of December 31, 1992) 

February1993 

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Fact Sheets of 

Completed Projects 
LIMB Demonstration Project 

Extension and Coolside 

Demonstration 

Sponsor: 

The Babcock &Wilcox Company 

Additional Team Members: 

Ohio Coal Development Office-cofunder 

Consolidation Coal Company-cofunder and 

technology supplier 

Ohio Edison Company-host utility 

Locatlon: 

Lorain, OH (Ohio Edison’s Edgewater Station) 

Technology: 

The B&cock&Wilcox Company’s limestone injection 

multistage burner (LIMB) system: Babcock & 

Wilcox DRB-XCL”’ low-NO, burners 

Consolidation Coal Company’s Coolside duct injection 

of lime sorbents 

Plant Capaclty/Prodktlon: 

105 MWe 

Project Funding: 

Total project cost 

DOE 

Participants 

%19,404,940 1009c 

7,597,026 39 

11,807,914 61 

Subprogram: 

CCT-I 

Project Objective: 

To demonstrate, with a variety of coals and sorbeots, the 

LIMB process as a retrofit system for simultaneous 

control of NO, and SO, in the combustion process, and 

that LIMB can achieve up to 60% NO% and SO, reductions: to test alternate sorbent and coal combinations, 

using the Coolside process, to demonstrate in-duct 

sorbent injection upstream of the humidifier and precipi. 

tam and to show SO, remova of up to 80%. 

Technology/ProJect Description: 

The LIMB process reduces SO, by injecting dry sorbent 

into the boiler at a point above the burners. The sorbent 

then travels through the boiler and is removed along 

with fly ash in an elecnostatic precipimtor (ESP) or 

baghouse. Humidification of the flue gas before it enters an ESP is necessary to maintain normal ESP operation and 10 enhance SO,removal. Combinations of 

three eastern bituminous coals (1.6%, 3.0’%, and 3.8% 

sulfur) and four sorbents were tested. Other variables 

examinedwere stoichiometry, humidifier outlet temperature, and injection level. 

In the Coolside process, dry sorbent is injected into 

the flue gas downstream of the air preheater, followed 

by Rue gas humidification. Humidification enhances 

ESP performance and SO, absorption. SO, absorption 

is improved by dissolving NaOH or Na,CO, in the 

humidification water. The spent sorbent is collected 

with the fly ash. as in the LIMB process. An eaStem 

bituminous coal with 3.0% sulfur was used in testing. 

The same low-NOx burners (Babcock & Wilcox 

DRB-XCLm’ low-NOx burners), which control NO% 

through staged combustion, were used in demonsuzing 

both LIMB and Coolside technologies. 

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

WilcoxCarolina-design, wall-fired lOS-MWe boiler. 

7-8 Program Update 1992 B&W/LIMB 
ProjectResults/Accompllshments: 

LIMB tests were conducted over a range of calcium-tosulfur ratios (Q/S) and humidification conditions. Each 

of four sorbents (calcitic limestone. type-N atmospherically hydrated dolomitic lime, calcitic hydrated lime. 

and calcitic hydrated lime with added calcium lignosulfonate) was injected while burning each of three coals 

(Ohio bituminous, 1.6%, 3.0%, and 3.X%, sulfur). Tests 

were conducted under minimal humidification, defined 

as operation at a humidifier outlet temperature sufficient 

to maintain ESP performance. That temperature was 

typically 25&275 “F. Tests were also conducted at a 

20 “F approach to the adiabatic saturation temperature of 

the flue gas to enhance SO, removal of the LMB system. Close-approach operation typically meant controlling the flue gas temperature at the humidifier outlet 

(ESP inlet) to about 145 “F. Other variables were stoichiometry and injection level. Highlights of reported 

test results follow: 

. 

The coal’s sulfur content, as reflected in the SO, 

concentration in the flue gas, affected SO, removal 

efficiency-the higher the sulfur content, the greater 

the SO, removal for a given sorbent at a comparable 

stoichiometry. A S-7% increase in removal occurred 

when switching to 3.8% from 1.6% sulfur coal and 

injecting at a stoichiometry of 2.0. 

The highest sulfur removal efficiencies, without 

humidification to close approach, were attained using 

the ligno lime-61% SO,removal was achieved 

while burning 3.8% sulfur coal. All sorhents tested 

were capable of removing SO, although calcium 

utilization of even finely pulverized limestone was 

not nearly as high as those of the limes. 

While injecting commercial limestone with 80% of 

the particles less than 44 microns in size, removal 

efficiencies of about 22% were obtained at a 

stoichiometsy of 2.0 while burning 1.6% sulfur coal. 

B&W/LIMB 

However. removal efficiencies of about 32% were 

achieved at a stoichiometry of 2.0 when using a 

limestone with all particles less than 44 microns. For 

a third limestone with essentially all particles less 

than IO microns, the removal efficiency was about 

5-7s higher than that obtained at similar conditions 

for limestone with all particles less than 44 microns. 

* Sorbent injection at the l81-ft plant elevation level 

inside the boiler, just above the boiler’s nose, yielded 

the highest SO, removal rates. Here, the sorbent was 

InJeCted at close to the optimum furnace temperature 

of 2,300 “F. 

* SO, removal efficiencies were enhanced by about 

10% over the range of stoichiometries tested when 

humidification dawn to a 20 “F qproach to 

saturatmn was used. 

During the Coolside demonstration, compliance 

(1.2-1.6% sulfur) andnon-compliance (3.0% sulfur) 

coals were burned. Key process variables-Q/S, 

Na/Ca, and approach to adiabatic saturation-were 

evaluated in short-term (6-E-hr) parametric tests and 

longer term (1-l l-day) process operability tests. 

The Coolside process routinely achieved 70% SO> 

removal at design conditions (2.0 Q/S. 0.2 N&a, and 

20 *F approach to adiabatic saturation temperature) 

usmg commercial hydrated lime. S0,remova.l dependedon Cal& NaiCa approach to adiabatic saturation, and the physical properties of the hydrated lime. 

Sarbent recycle showed significant potential to improve 

sorbent utilization. Observed SO, removal with recycle 

sorbent alone was 22% at 0.5 available Ca/S and 18 “F 

approach to adiabatic saturation. Observed SO, removal 

with simultaneous recycle and fresh sorbent feed was 

40% atO. fresh Ca/S, 0.2 fresh NaiCa, 0.5 available 

recycle, and 18 “F approach to adiabatic saturation. 

NOx removal was in the 40-5010 range throughout 

both LIMB and Coolside testing. 

Commercial Appllcatlons: 

Both LIMB and Coolside technologies are applicable to 

most utility and industrial coal-fired units and provide 

alternatives to conventional wet flue gas desulfurization 

(FGD) processes. They can be retrofitted with modest 

capital investment and downtime, and their space requirements are substantially less. Depending on the 

plant capacity factor and the coal’s sulfur content, they 

can be economically competititive with FGD systems. 

For example, using 2.5% sulfur coal at a 65% plant 

capacity factor, LIMB can be cost competitive with 

conventional wet FGD up to 450 MWe and Coolside up 

to 220 MWe. The environmental benefits for LIMB are 

4@50% lower NOx and more than 60% lower SO; 

emissions, and for Coolside up to 70% lower SO, emissions. The waste from each of these processes is dry 

and easily handled and contains unreacted lime that has 

potential commercial application. Both processes have 

the ahility’to handle all coal types, especially low- to 

medium-sulfur coals. 

Project Schedule: 

DOE selected project (CCT-I) 7124186 

Cooperative agreement awarded 6125187 

NEPA process completed (MTF) 612187 

Environmental monitoring plan completed 10119188 

Construction 8187-9189 

Coolside operational testing 7189-2190 

LIMB extension operational testing 4190-819 I 

Project completed/final reports issued 11192 

Final Reports: 

* T.R. Goats, M.J. DePero, and P.S. Nolan. LIMB 

Demonstration Project Extension and Coolside 

Demonsrrarion. The Babcock &Wilcox Company. 

October 1992. 

* DC. McCoy et at. The Edgewaler Coolside Process 

Demonsrration: A Topical Report. CONSOL Inc. 

February 1992. 

Program Update 1992 7.9 
Advanced Cyclone 

Combustpr with Internal 

~olf;f;,Nltrogen, and Ash 

Sponsor: 

Coal Tech Corporation 

Actdltlonal Team Members: 

Commonwealth of Pennsylvania Energy Development 

Authority-xofunder 

Pennsylvania Power and Light Company-supplier of 

test coals 

Tampella Power Corporatiow-host site 

Location: 

Williamsport, Lycoming County, PA (Tampella Power 

Corporation boiler manufacturing plant) 

Technology: 

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

Plant Capaclty/Productlon: 

23 million Btu/hr 

ProJect Funding: 

Totalprojectcost 

DOE 

Participants 

Subprogram: 

CCT-I 

$984,394 100% 

490,149 50 

494,245 50 

Project Objectlve: 

To demonstrate that an advanced cyclone combustor 

can be retrofitted to an industrial boiler and that it can 

simultaneously remove up to 90% of the SO, and 

9@95% of the ash within the combustor and reduce 

NO, by up to 100 ppm. 

7.10 Program Update 1992 

Technology/ProjectDescrlptlon: 

Coal Tech’s horizontal cyclone combustor is internally 

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

air, and sorbent are injected toward, the wall through 

tubes in the annular region of the combustor to cause 

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

to particle retention in the combustor. Secondary air is 

used to adjust the overall combustor stoichiomeuy. The 

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

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

Fine coal pulverization allows combustion of most of 

the coal particles near the cyclone wall, with the balance 

burned on or near the wall. This improves combustion 

in the fuel-rich chamber, as well as slag retention. The 

slag contains over 80% of the ash and sorbent fed to the 

combustor. For NO” control, the combustor is operated 

fuel rich, with final combustion taking place in the 

boiler furnace to which the combustor is atttached. 

In Coal Tech’s demonstration, an advanced, aircooled, cyclone coal combustor was retrofitted to a 

23-million-Btu/br, oil-designed package boiler located 

at the Tampella Power Corporation boiler factory in 

Williamsport, PA. Air cooling took place in a very 

compact combustor which could be retrofitted to a wide 

range of industrial and utility boiler designs without 

disturbing the boiler’s water-steam circuit. NOx reduction was achieved by staged combustion, and SO, was 

captured by injection of limestone into the combustor. 

Coal Tech 
The cyclonic action inside the combustor forced the coal 

ash and sorbent to the walls where it could be collected 

as liquid slag. Under optimum operating conditions, the 

slag would contain a significant fraction of vitrified coal 

sulfur. Downstream sorbent injection into the boiler 

provided additional sulfurremoval capacity. 

ProjectResuWAccompllshments: 

The test effort consisted of 800 hours of operation 

which included five individual tests, each of 4 days 

duration, plus another 100 hours of operation as part of 

separate ash vitrification tests. Eight Pennsylvania 

bituminous coals with sulfur contents ranging from 1% 

to 3.3% andvolatile matter ranging from 19% to 37% 

were tested. 

Under fuel-rich conditions, combustion efficiencies 

exceeding 99% after proper operating procedures were 

achieved. Turndown to 6 million Btu/hr from a peak of 

19 million Btu/hr was achieved. Due to facility limits 

on water availability for the boiler and for cooling the 

combustor, the maximum heat input during the tests was 

around 20 million Btw’br even though the combustor 

was designed for 30 million Btuihr and the boiler was 

thermally rated at around 25 million Btulhr. 

Coal Tech reported the following test results: 

* With fuel-rich operation of the combustor, a 75% 

reduction in boiler-outlet-stack NOI was obtained, 

corresponding to 0.3 lb/million Btu (184 ppmv). An 

additional 5-10% NO, reduction was obtained by the 

action of the wet particulate scrubber, resulting in 

atmospheric NOx emissions as low as 0.26 lb/million 

Btu (160ppmv). 

= Over 80% SO, reduction measured at the boiler 

outlet stack was achieved using sorbent injection in 

the furnace at various calcium-to-sulfur molar ratios 

(Q/S). A maximum SO, reduction of 58% was 

measured at the stack with limestone injection into 

Cool Tech 

the combustor at a Ca/S of 2. A maximum of 33% of 

the coal sulfur was retained in the dry ash removed 

from the combustor and furnace hearths, and a high 

of 11% of the coal sulfur was retained in the slag 

rejected through the slag tap. 

* Local stack particulate emission standards were met 

with the wet venturi particulate scrubber. 

. Total slagisorbent retention in the combustor, under 

efficient combustion operating conditions, averaged 

72% and ranged from 55% to 90%. Under more 

fuel-lean conditions, theslagretention averaged 

80%. In post-CCT-project tests on flyash 

vitrification in the combustor, modifications to the 

solids injection method and increases in the slag flow 

rate produced substantial increases in the slag 

retentton rate. 

* All slag removed from the combustor produced trace 

metal leachates well below theEPA drinking water 

standard. 

* Different sections of the combustor had different 

materials requirements. Suitable materials for each 

section were identified. Also, the test effort showed 

that operational procedures were closely coupled 

with materials durability. By implementing certain 

procedures, such as changing the combustor wall 

temperature, it was possible to replenish the 

combustor refractory wall thickness with slag. 

. Procedures for properly operating an air-cooled 

combustor were developed, and the entire operating 

database was incorporated into a computercontrolled system for automatic combustor operation. 

Commercial Appllcatlons: 

Coal Tech has concluded that, while the combustor is 

not yet fully ready for sale with commercial guarantees, 

it is ready to be further scaled up for commercial applications (100 million Btuhr), such as combustion of 

waste solid fuels, limited sulfur control in coal-fired 

boilers, and conversion of ash to slag. 

Coal Tech’s advanced, air-cooled, slagging combustor can use a wide range of U.S. coals and can be 

retrofitted to existing or new units. The target market is 

industrial and unity boilers sized 20-100 million Btuihr 

or more; multiple combustors can be attached to larger 

boilers. The near-term focus in on using the combustor 

in combined-cycle industrial and small utility power 

plants in the lC!-50 MWe range. The combustor is 

capable of using pulverized coal, coal-water slurry, 

cofired pulverized coal, and refuse-derived fuels (e.g., 

industrial sludge and coal-mine waste). 

ProJect Schedule: 

DOE selected project (CCf-I) 7/24/86 

Cooperative agreement awarded 3/20/87 

NEPA process completed (MTF) 3/‘26/87 

Environmental monitoring plan completed 9/22/87 

Construction 7187-11187 

Operational testing 1 l/87-5/90 

Project completedlfinal report issued 919 I 

Final Report: ~ 

B. Zauderer and E.S. Fleming. The Demonsrrarion of 

an Adwnced Cyckme Coal Combusror, wirh lnrernnl 

Sulfur. Nirrogen, and Ash Conrrolfor rheCommion of 

a 23 MMBru/Hour Oil FiredBoiler ro Pulverized Coal; 

Volume I-Final Technical Reporr; Volume 2-Appendices I, Il. Ill, IV, and V; Volume 3-Appendix VI. Coal 

TechCorporation. August 1991. (Available from NTIS 

as DE 9200-2587 and DE 9200-258%T7.) 

Program Update 1992 7.11 
Nucla CFB Demonstration 

Project 

Sponsor: 

Tri-State Generation and Transmission Association. Inc. 

(formerly Colorado-Ute Electric Association, Inc.) 

Additional Team Members: 

Pyropower Corporation-technology supplier 

Technical Advisory Group (potential users+zofunder 

Electric Power Research Institute-technical support 

Location: 

Nucla. Montrose County, CO (Nucla Station) 

Technology: 

Pyropower’s atmospheric circulating fluidized-bed 

combustion (ACFB) system 

Plant Capacity/Production: 

110 MWe 

Project Funding: 

‘Total project cost 

DOE 

Participants 

$54,087,000 100% 

19,920,000 37 

34,167,OOO 63 

Subprogram: 

CCTI 

Project ObJectWe: 

To demonstrate ACFB at a scale of 110 MWe, representing a 2: 1 scaleup from previously demonstrated 

capacities: to verify expectations of the technology’s 

economic; environmental, and technical performance in 

arepowering application at a utility site; to accomplish 

greater than 90% SO, removal; to reduce NO, emissions 

by 60% and to achieve an efficiency of 34% in arepowering mode. 

TechnologylProjectDescrtptton: 

Nucla’s circulating fluidized-bed system operates at 

atmospheric pressure. In the combustion chamber, a 

stream of air tluidizes and entrains a bed of coal, coal 

ash, and sorbent (e.g., limestone). Relatively low combustion temperatures limit NOx formation. Calcium in 

the sorbent combines with SO, gases, and solids exit the 

combustion chamber and flow into a hot cyclone. The 

cyclone separates the solids from the gases, and the 

solids arerecycledfor combustor temperature control. 

Continuous circulation of coal and sorbent improves 

mixing and extends the contact time of solids and gases, 

thus promoting high utilization of the coal and high 

sulfur capture efficiency. Heat in the flue gas exiting 

the hot cyclone is recovered in the economizer. The 

flue gas passes through a baghouse where the particu. 

late matter is removed. The steam generated in the 

ACFB is used to generate electric power. 

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

Station were replaced with a new 925,000-lb/Ix ACFB 

steam generator capable of driving a new 74-MWe 

turbiie generator. Exnaction steam from this turbine 

generator powers three existing turbine generators 

(12 MWe each). Three western coals were tested: 

Peabody coal @.&0.8% sulfur),Dorchester coal(lS% 

sulfur), and Salt Creek coal (0.5% suflur). 

In 1992, Colorado-Ute Electric Association, Inc., 

the owner of Nucla Station, was purchased by Tti-State 

Generation and Transmission Association, Inc. 

7.12 Program Updale, Tri-StatdNucla 
ProJect Results/Accomplishments: 

Between August 1988 and January 199 1, a total of 72 

steady-state performance tests wxe conducted: 22 tests 

at 50% load. 6 at 75% load, 2 at 90% load, and 42 at full 

load (110 hlWej. Some key results, as reported by the 

sp”“s”~, fallow: 

Results indicated strong correlations of absolute CO, 

SO,, and NO< emissions levels with combustor 

operating temperatures. Although NSPS compliance 

was maintained, a penalty on limestone feed 

requirements for sulfur retention was realized at the 

higher operating temperatures. Below 1,620 OF, 70% 

sulfur retention was achieved with 1.5 CalS, and 

95% sulfur retention was achieved with 4.0 CalS. 

Around 1,700 OF, Ca/S greater than 5.0 was required 

to maintain 70% sulfur capture. 

The NO, emissions for all tests were less than 

0.34 lb/million Btu, which was well within the emission limit of 0.60 lb/million Btu. The average level 

of NOz emissions for all tests was O.lSlb/million Btu. 

Combustion efficiency. a measwe of the quantity of 

carbon that is fully oxidized to CO,, ranged from 

96.9% to 98.9%. Of the four exit sources of 

incompletely burned carbon, the largest was carbon 

contained in the fly ash (93%). The next largest 

(5%) was carbon contained in the bottom ash stream, 

and the remaining feed-carbon loss (2%) was 

incompletely oxidized CO in the flue gas. The fourth 

possible source, hydrucarbons in the flue gas, was 

measured and found t” be negligible. 

Boiler efficiencies for 68 performance tests varied 

from 85.6% t” 88.6%. Thecontributions to boiler 

heat loss were identified as unburned carbon; sensible heat in dry flue gas: full and sarbent moisture; 

latent heat in burning hydrogen: sorbent calcitation, 

radiation, and convection; and bottom ash cooling 

water. Net plant heat rate decreased with increasing 

boiler load. from 12,400 Btu/kWh at 50%, of full load 

to 11,600 Btu,kWh at full load. The lowest value 

achieved during a full-load steady-state test was 

IO.YSO BtukWh. These values were affected by the 

absence of reheat, the presence of the three older 

12.5-MWe turbines in the overall steam cycle, the 

number of wit restzts, and pan-load testing. 

* Over the range of operating temperatures at which 

testing was performed at Nucla, bed temperature was 

found t” be the most influer~tial operating parameter. 

With the possible exception of coal-feed configurstion and excess air at elevated temperatures, bed 

temperature was the only parameter that had a measurable impact on emissions or efficiencies. Emissions of SO* and NQ were found t” increase with 

increasing combustor temperatures while CO emissions decreased with increasing temperature. Combustion efficiency also improved as the temperature 

was increased. 

An economic evaluation indicated chat the final 

capital costs for the Nucla ACFB system wee about 

$112.3 million. This represents acost of $l,l23/net 

kW. Total power production costs associated with test 

operations were about $54.7 million, which results in a 

normalized power production cost of $63.63/MWh. 

Fixed costs were about 62% of the total. and variable 

costs were more than 38%. Nucla’s power production 

costs proved competitive with pulverized coal units not 

limiting emissions as significantly. 

Commercial Applications: 

ACFB technology has good potential in both industrial 

and utility sectors for new capacity additions or for 

repowering existing coal-fned plants. Coal of any sulfur content can be used. Because any type or size of 

bailer can be repowwed by ACFB using the existing 

+nt area, coal- and waste-handling equipment, and 

steam turbine equipment, the life of the plant can be 

extended. Benefits of ACFB include 90% SO2 reduction. tiGXO%~ NO, reduction, and control of pollutants at 

lower costs than are offered by existing technologies. 

ProJect Schedule: 

DOE selected project (XT-I) 1017187 

Cooperative agreement awarded 1013188 

NEPA process completed (MTF) 4/18/X8 

Environmental monitoring plan completed 2/27/88 

Operational testing 8/88-l/91 

Project completed/final report issued 4192 

Final Reoorts: 

Nucla CirclrlatingArmospheric Fluidizedb’ed 

Demonrrration Project: Final Report. Colorado-Ute 

Electric Association, Inc. October 1991. (Available 

from NTIS as DE 9200-l 122.) 

Economic Ewluation Report: Topical Report. 

Colorado-Ute Electric Association, Inc. March 

1992. (Available from NTIS as DE 9300-0212.) 

Clean Coal Reference Phrs: Amxxpkeric CFE, 

FinalReporr. Gilbert/Commonwealth, Inc. June 

1992, 

Program Updare 1992 7.13 

CCT-I 

Project Fact Sheets 
Development of the Coal 

Quality Expert 

Sponsor: 

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

Additional Team Members: 

Black and Veatcb- cofunder and expert system 

developer 

Electric Power Research Institute-cofunder 

The B&cock &Wilcox Company-cofunder and 

pilot-scale testing 

Guild Products. Inc.--expert system architecture 

developer 

Electric Power Technologies, Inc.-field testing 

University of North Dakota, Energy and Minerals 

Research Center-bench-scale testing 

AlabamaPower Company-host utility 

Duquesne Light Company-host utility 

Mississippi Power Company-host utility 

Northern States Power Company-host utility 

PennsylvaniaElecuic Company andNew York State 

Electric&Gas Corporation-host utilities 

Public Service of Oklahoma-host utility 

Locations: 

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

Windsor, Hanford County. CT (pilot-scale tests) 

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

Wilsonville, Shelby County, AL (&son, Unit 5) 

Springdale, Westmoreland County, PA (Cheswick 

Station) 

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

Bayport, Washington County, MN (King Station) 

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

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

Technology: 

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

model 

Plant CapacitylProductlon: 

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

Project Funding: 

Total project cost $21,727,822 100% 

DOE 10,863,911 50 

Participants 10,863,911 50 

Project Objective: 

To demonstrate an expert system that can be run on a 

personal computer and provide coal-burning utilities 

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

Technology/Project Description: 

Dataderived from bench-, pilot-. and full-scale testing 

are being used to develop algorithms for inclusion 

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

be TU” on a personal computer. Utilities may use the 

information to predict the operating performance and 

cost of coals not previously burned at a particular 

facility. 

Six large-scale field tests consist of burning a 

baseline coal and an alternate coal over a 2-month 

period. The baseline coal, the one currently used as 

fuel, is used to cbaracterize the operating performance 

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

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

remaining test period. 

7-16 Program Update 1992 ABB Combmion Engineering and CQICQE Model 
Calendar Year 

,988 ,989 1990 1991 1992 1993 1994 ,995 19% 1997 1998 

3 4 1 234 1234 1 *34 1234, 234 1234 1 234 1234 1 234 12 

Development 

t 

Cpration intiated 8190 

Environmenfal monitodng plan completed 7131190 

Cooperalive agreement awarded 6/14190 

NEPAprocess completed (MTF) 4127190 

completedllinal report issued T/94’ 

Soaware development completed 6194 

Fieldtesting completed 8193’ 

‘Projecteddate 

I 

The baseline and alternate coals for each test site 

also ale burned in bench- and pilot-scale faciliiies under 

similar conditions. The alternate coal is cleaned at CQ, 

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

be produced economically and then transported to the 

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

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

to develop the model. 

Bench-scale testing will be performed at ABB 

Combustion Engineering’s facilities in Windsor, CT, 

and the University of North Dakota’s Energy and Mineral Research Center in Grand Forks, Nl?; pilot-scale 

testing will be done at ABB Combustion Engineering’s 

facilities in Windsor, CT, and Alliance, OH. The six 

field test sites are: Gatson, Unit 5 (880 MWe), 

Wilsonville, AL; Cheswick Station (500 MWe), 

Springdale, PA: Watson, Unit4 (250 MWe), Gulfport, 

MS: King Station (560 MWe), Bayport, MN; Homer 

City, Unit 2 (600 MWe), Homer City, PA; and Northeastern, Unit 4 (445 MWe), Oologah, OK. 

ProjectStatusdAccomplishments: 

Four of six field tests have been completed, including 

Public Service of Oklahoma’s Northeastern Unit 4, 

Mississippi Power Company’s Watson Unit 4, Northern 

States Power Company’s King Station, and Alabama 

Power Company’s Gaston Unit 5. Coals tested include 

Wyoming, blends of Wyoming/Oklahoma, Illinois, and 

western Kentucky, and a blend of Wyoming/Montana/ 

peuoleum coke. The CQE “Acid Rain Advisor” software package was commercially released in June 1992. 

The project duration has been extended 5 months to 

allow sufficient time to complete software development 

following field testing. 

Commercial Appllcatlons: 

The expert system will enable coal-fired utilities to 

select the optimum quality coals at the lowest price for 

their specific boilers to reduce SO, and NOx emissions. 

The CQE system is applicable to all electric power 

plants and indusuiallinstitutiooal boilers that burn coal. 

The system will predict the operational and emission 

reduction benefits of using cleaned coal. Following the 

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

the United States and abroad. 

ABB Combusrion Engineering and CQICQE Model Program Updote 1992 7-17 
Enhancing the Use of Coals 

by Gas Reburning and 

Sorbent injection 

Sponsor: 

Energy and Environmental Research Corporation 

Additional Team Members: 

Gas Research Institute-cofunder 

State of Illinois, Department of Energy and Natural 

Resources-cofunder 

Illinois Power Company-host utility 

City Water, Light and Power-host utility 

Locations: 

Hennepin, Putnam County, IL (Illinois Power 

Company’s, Hennepin Plant) 

Springfield, Sangamon County, IL (City Water, Light 

and Power’s Lakeside Station) 

Technology: 

Energy and Environmental Research Corporation’s gas 

reburning and sorbent injection process 

Plant Capacity/Production: 

Hennepin: tangentially fired 80 MWe (nominal) 

Lakeside: cyclone-fired 40 MWe (nominal) 

Project Funding: 

Total project cost 

DOE 

Participants 

$37,497,816 1007C 

18,747,816 50 

18.750,OOO 50 

Project Objective: 

To demonstrate gas rebuming to attain 60% NOx reduction along with sorbent injection to capture50% of the 

SO, on two different boiler configurations: tangentially 

fired and cyclone fired. 

Technology/Project Description: 

Gas reburning is a postcombustion technology that is 

being developed primarily for the removal of NOx. In 

this process, SO-85% of the fuel is coal and is supplied 

to the main combustion zone. The remaining 15-205 

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 NOx is converted to nitrogen. A calcium compound (sorbent) is injected in the form of dry, fine particulzes above the rebuming zone in the boiler or even 

further downstream. The calcium compound to be 

tested is Ca(OH), (lime). The process is expected to 

achieve 60% NOx reduction and 50% SO, reduction on 

different boiler configurations at power plants burning 

high-sulfur midwestem coal. This project will demonstraw the gas rebuming and sorhent injection process on 

two separate boilers representing two different firing 

configurations--a tangentially fired 80-MWe boiler at 

Illinois Power Company’s Hennepin Plant in Hennepin, 

IL, and a cyclone-fired 40-MWe boiler at City Water, 

Light and Power’s Lakeside Station in Springfield, IL. 

7.18 Program Update 1992 EERIGosReburning andSorbmr Injection 
calendar Year 

1986 1967 ,988 ,989 1990 1991 1992 ,993 1994 19965 19% 

3 4 1 234 1 234 1 234 1 2 3 4 1 234 1 234 1 234 1 234 1 *a4 12 

7186 7187 1191 Design an* construcson 12l94 operation 

t WE s&dd to,,, kc 

projed 7/24/86 :zT’ 

CO~Qt*t~d, 

Hermepin 

7114@7 (MTF) 619/88 

I’[\ 1 I 

[?%~~~~;;~L~132~EE~~~~ 

Design completed. bath sites 5199 COn*lrucfion X%Qleted. lakeside 592 operaliancomQlet&. 

Construdion stated. Henneph 5189 construction CO”lQbt~d, Hennepin 8191 

Lakeside 4194’ 

NEPAprocess completed, Lakeside (EA) 6/25/89 

Environmental monitoring plan 

completed. Hennepin 1011 S/99 

Operation initiated. Hennepin 1191 

Construction started, Lakeside 6190 

E”“i,o”ment.%l monitoring plan 

armpleled. La&aide 11/15/89 

‘Projected *at* 

ProJectStatue/Acco~~~pllshments: 

Permitting and engineering design efforts were completed for the three original project sites; however, in 

1990, plans for the third site (Bartonville, IL) were 

suspended. 

Construction is complete at both Hennepin and 

Springfield, IL, sites. Operations at the Hennepin site 

began January 1991. Long-term baseline testing at 

Hennepin startedin mid-1991 after shakedown operations had been completed. Baseline testing, including 

testing with a promoted and a high-surface-area lime, 

was completedin January 1993. During the c.ourse of 

testing, NO, reductions through gas retiuming have 

ranged as high as 77%, 65% being routine, exceeding 

the project objective of 60%. Sorbent injection reduced 

SO, emissions as much as 62%. with 52.5% reduction 

being routine, also exceeding the project objective of 

50%. The calcium-to-sulfurratio is about 1.75:1. 

At the Lakeside site in Springfield IL, consuuction 

was essentially completed in May 1992. and the unit 

was temporarily placed on hold. Some minor construction activities were completed in October. Long-term 

baseline testing will start in February 1993 and is expected to be completed in April 1994. 

The project schedule has been extended to allow at 

least 12 months of gas-reburning and sorb&-injection 

demonstration operation under normal load dispatch at 

Lakeside and to allow demonstration of one of more 

alternate sorbents. 

Commercial Ap~llcations: 

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

applications for these technologies, both separately and 

combined, extend to both utility companies and industry 

in the United States and abroad. In the United States 

alone, these two technologies can be applied to over 900 

pre-NSPS utility boilers; the technologies also can be 

applied to new utility boilers. With NO” and SO, removal exceeding 60% and 50%. respectively, these 

technologies have the potential to extend the life of a 

boiler or power plant and also provide a way to use 

higher sulfur co+. The technologies are not sensitive 

to the type of coal used, regardless of its nitrogen or 

sulfur content. 

EERlGat Rebuming and Sorbent Injection Program Update 1992 7.19 
Tidd PFBC Demonstration 

Project 

Sponsor: 

The Ohio Power Company 

Additional Team Members: 

American Electric Power Service Corporation--design, 

construction, and management 

The B&cock&Wilcox Company-technology supplier 

Ohio Coal Development Office-cofunder 

Location: 

Brilliant, Jefferson County, OH (Ohio Power 

Company’s TiddPlant) 

Technology: 

The Bahcock &Wilcox Company’s pressurized 

fluidized-bed combustion (PFBC) system (under license 

from ABB Carbon) 

Plant CapacltylProduction: 

70 MWe 

Project Funding: 

Total project cost $193,54o,cOO 100% 

DOE 60,200,COO 31 

Participants 133,340,ooc 69 

Protect Objective: 

To demonstrate PFBC at a 70-MWe scale, representing 

a 13:l scaleup from the pilot plant facility: to verify 

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

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

of 0.2 lb/million But, and au efficiency of 38% in a 

repowering mode using the existing steam system. 

WLC 

COAL 

VATER 

Technology/ProJectDescrlptlon: 

Tidd is the fast large-scale demonstration of PFBC in 

the United States and one of only three worldwide. The 

boiler, cyclones,bedre.iujectionvessels, and associated 

hardware are encapsulated in a pressure vessel 45 ft in 

diameter and 70 ft high. The facility was designed so 

that one-seventh of the hot gases produced could be 

routed to a slipstream to test advanced filtration devices. 

The Tidd facility is a bubbling fluidized-bed combustion process operating at 12 arm (175 lb/in* atm). 

F’ressurized combustion air is supplied by the turbine 

compressor to fluidize the bed material which consists 

of a coal-water fuel paste, coal ash, aud a dolomite or 

limestone sorbent. Dolomite or limestone in the bed 

reacts with sulfur to form calcium sulEate, a dry, grauular bed-ash material which is easily disposed of or is 

usable as a by-product. A low bed-temperature of 

1,600 “F limits NO, formation. 

The hot combustion gases exit the bed vessel with 

entrained ash particles, 98% of which ale removed 

when the gases pass through cyclones. The cleaned 

gases are then expanded through a 15-MWe gas turbine. 

The gases exiting the turbine aTe cooled via a waste heat 

economiser and further clear& in au elecnostatic 

precipitator. 

The Tidd steam turbine operates at a pressure of 

1,305 lb/it? atm and a temperature of 925 “F to produce 

approximately 55 MWe. Superheated steam is produced from pressurized boiler feed water in the in-bed 

combustor tubes. Steam generated within the combustar and the heat recovery system downstream of the gas 

7.20 Progrmn Update I992 OhioPaver 
Calendar Year 

,986 ,987 1988 1989 1990 1991 1992 ,993 1994 19% ,996 

341234 1234 1 234 1 234 1234 1 2 3 4 12341234 ,234 t* 

Preaward 

I 1 

t 

Environmental monitoring 

plan completed 5125188 

Groundbreaking ceremony 4/6/88 

Construction stated 12/9187 

Cooperatiie agreement awarded 3,20/W 

NEPAprocess cw”ple,ed (MTF) 3,518, 

1’ Operation inliated 3191 

Preoperatia”al test6 starled Ia90 

Construction completed 12/90 

Design completed 12/90 

I 

ProjectcompletediitnaI 

report issued 12194’ 

Operation completed 3194 

DOE seleaed project 7124M ‘Prqeded date 

turbine is used to generate power in a previously existing steam turbine. Due to repowering, plant efficiency 

was improved by 10% to a heat rate of 9,750 BtuntWh 

(an efficiency of 35.1% based on HHV). 

PlojectStatus/Accomplishments: 

American Electric Power Company received two national awards in 1992 for Tidd: Power Mugmine’s 

“1991 Power Plant of the Year” award and a National 

Energy Resources Organization award. 

During 1992, the facility’s environmental compliance test and 30-day acceptance test were completed, a 

hot-gas filtration test loop was installed, and several 

parametric tests (e.g., sarbent mixing into fuel paste, 

limestone sorbent, revalidation of 30-day acceptance, 

etc.) were conducted. Approximately one-half of the 

project’s 3-year operating period has been completed. 

Results from the compliance test showed that the 

unit could operate within its permit. SO, emissions 

emissions were less than 0.24 lb/million Btu, and parwereless than 0.51 lb/million Btu (90% capture), NOx 

ticulate emissions were less than 0.02 lb/million Btu. 

Early in 1992 the unit experiettced high-cycle fatigue cracks in the low-pressure turbine and problems in 

the secondary ash removal system, but these problems 

appear to have been corrected. By year end, the facility 

had accuinulated more than 3,OCQ hours of coal-fueled 

tests, 2,000 hours of which were accumulatedin 1992. 

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

can be extended by repowering with PFBC using the 

and steam turbine equipment. Another advantage for 

repawering applications is the compactness of the 

process due to pressurized operation, which reduces 

space requiremenu per unit of energy generated. 

Commercial Appllcatbn: 

Combined-cycle PFBC permits use of a wide range of 

coals, including high-sulfur coals. Bubbling PFBC 

technology, along with other advanced technologies, 

will compete with circulating PFBC systems to repower 

or replace conventional power plants. PFBC technology 

appears to be best suited for applications of 50 MWe or 

larger. Capable of being consuucted modularly, PFBC 

generating plants permit utilities to add increments of 

capacity economically to match load growth. Plant life 

In a fully mature system, the projected net heat rate 

is 8,500 Btu/kWi (based on HHV) which equates to 

40.2% efficiency. An advanced cycle that integrates a 

small gasifier could yield heat rates approaching 

7,500 Btu/kWh (45% efficiency). 

The environmental attributes of a mature system 

include in-situ sulfur removal of 95% and NOx emissions reduction levels less than 0.1 lb/million Btu. Although the system generates aslight increase in solid 

waste as compared to conventional systems, the dry 

material is either disposable or potentially usable. 

Ohio Power Program Update I992 7-21 
Advanced Coal Conversion 

Process Demonstration 

Sponsor: 

Rosebud SynCoal Partnership (a partnership between 

Western Energy Company and the NRG group, a 

nonregulated subsidiary of Northern States Power 

Company) 

Additional Team Member: 

Stone and Webster Engineering Company-architect/ 

engineer 

Location: 

Colship, Rosebud County, MT (adjacent to Western 

Energy Company’s Rosebud Mine) 

Technology: 

Western Energy Company’s advanced coal conversion 

process for upgrading low-rank subbituminous and 

lignite coals 

PlantCapacity/Productlon: 

45 totwhr of SynCtaP’ product (300,000 tons&r) 

Project Funding: 

Total project cost 

DOE 

Participants 

$69,COO,Mx) lOc% 

34,500,cOo 50 

34,5cwoo 50 

Project Objective: 

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

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

as 0.3%. and heating value up to 12,000 Btu/lb. 

spcml is almd-k of the Roisbud syecod Pmmmhip. 

7-22 Program Update 1992 

Technology/ProjectDescrlption: 

Being demonstrated isan advanced thermal coal-drying 

process coupled with physical cleaning techniques to 

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

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

through two fluid&d-bed reactors that remove loosely 

held water and then chemically bound water, carboxyl 

groups, and volatile sulfur compounds. After drying, 

the coal is put through a deep-bed stratifier cleaning 

process to effect separation of the ash. 

content as low as l%, sulfurcontent as low as 0.3% 

and heating value up to 12,000 Btu/lb. 

The 45tonlhr unit is being located adjacento a 

unit train loadout facility at Western Energy Company’s 

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

facility, the process equipment is at commercial scale 

because a full-sized commercial plant has multiple 

process trains. 

The technology, if successfully demonstrated, 

enhances low-rank western coals, usually with amoisture content of 25-55%, sulfur content of OS-1.5%. and 

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

stable, upgraded SynCoalntproduct with amoisture 

RosebudSynCoalPartnership 
Cale"da,Y*ar 

,988 1989 ,990 ,941 ,992 ,993 1994 1995 IS96 1997 1998 

341234 1 2 3 4 ,234 1 234 1 2 3 4 1 2 3 4 1 2 3 4 1234 I 234 12 

I 9190 6/92 3196 

I DOE selected projed 

1219188 

test oper&n initiated 6192 

Envkmmental fnonitofing plan completed MB2 

Const~clion complsled Z/92 

I 

broject complete&%nal report issued 31%’ 

aperation completed a/95’ 

“““zzr* I I brsoperational les(s initiated 12181 

Project StatuslAccompllshments: 

0” December 12, 1990, Western Energy Company. a 

subsidiary of Montana Power Company, announced that 

it had joined with the NRG Group, a “onregulated subsidiary of Northern States Power Company based in 

Minneapolis, MN, to demonstrate and commercialize 

this coal conversion technology. 

Ground was broke” on March 28,1991. By June, 

pieces of major equipment were arriving on site. The 

consauction of two 6,000~ton product storage silos and 

all foundation work was completed by July. The main 

process facility smtcture and the control/administration 

building were completed by November. Initial “lumover” of equipment started in December, and final construction was completed in February 1992. Initial “hot” 

operations began in March 1992. Plant operational activities are under way with full operationscheduled for 

the second quarter of 1993. Through December 1992. 

the plant had operated 384 hours. and initial shipments 

of approximately 2,100 tons of SynCoal” product were 

/ b&s” completed an1 

NEPA process completed (EA) 3127191 

Ground br&ing/construnion started 3LZa/91 

‘Projected date 

delivered by truck to Montana Power Company for vial 

hums at Colstrip Unit 3 and the J.E. Corette Plant in 

Billings, MT. A S,OOO-ton rail shipment for test burn at 

Northern States Power Company’s Riverside Plant in 

Minneapolis is scheduled for April 1993. 

Commercial Appllcatlons: 

high heating value, and stablephysical/chemical 

characteristics; itcould have significant impact on SO, 

reduction. Western Energy’s process, therefore, will be 

attractive to utilities because the upgraded fuel will be 

less costly to use than would the construction and use of 

flue gas desulfurization equipment. This will allow 

“Iants that would otherwise be closed to remain in 

Western Energy’s advanced coal conversion process 

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

subbituminous and lignite coals. Many of the power 

plants located throughouthe upper midwest have 

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

coals. Presently, most of these plants bum Illinois 

Basin high-sulfur coal. SynCoal~’ would be a” ideal 

low-sulfur coal substitute for these and other plants, 

because itwill allow operation under more restrictive 

emissions guidelines without requiring derating of the 

units or the addition of costly fluegas desulfurization 

systems. The advanced coal conversion process will 

produce SynCoalTD’ which has avery low sulfur content, 

bperado”, 

Program Update I992 7.23 
York County Energy Partners 

Cogeneration Project 

Sponsor: 

York County Energy Partners, L.P. (a limited partnership which includes Air Products and Chemicals, Inc.) 

Addltlonal Team Members: 

J.E. Baker Company--site host 

Foster Wheeler Energy Corporation- technology 

supplier 

Locatlon: 

West Manchester Township. York County, PA 

(greenfield site) 

Technology: 

Foster Wheeler’s atmospheric circulating fluidized-bed 

(ACFB)combustor 

PlantCapaclty/ProducUon: 

227 MWe (net) and 50,000 lb/lx steam 

Project Funding: 

Total project cost $374.345.450 100% 

WE 74,733,833 20 

Participant 299,611,617 80 

ProjectObjecttve: 

To demonstrate ACFB at 250 MWe, representing a

1.7:1 scaleup from previously constructed facilities; to 

verify expectations of the technology’s economic, 

environmental, and technical performance in a 

greenfield cogeneration application; and to provide 

cogenerators, as weU as utility and non-utility power 

producers, with the data necessq for evaluating a 

250-MWe ACFB as 3 commercial alternative to 

accomplish greater than 90% SO, removal, to reduce 

NO, emissions by 60% when compared with 

conventional technology, and to achieve a steam 

efficiency of 88%. 

Technology/ProjectDescrtption: 

operates at atmospheric pressure. Coal, primary air, and 

a solid sorbent, such as limestone, are introduced into 

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

the lower portion of the combustor where initial cotnbustion occurs. As coal particles decrease in size due to 

combustion and breakage, they are carried higher in the 

combustor to an area where secondary air is introduced. 

As the coal particles continue to be reduced in size, the 

coal, along with some of the sorbent, is carried out of 

the combustor, collected in a particle separator, ahd 

recycled to the lower portion of the combustor. The 

sorbent in the bed removes sulfur during the combustion 

process, eliminating the need for scrubbers. 

The project will demonstrate ACFB in a 250~MWe 

stream. The steam is then used to produce power in a 

greenfield cogeneration application in York County, 

PA. The sponsor has an electrical power purchase 

conventional steam cycle. 

agreement with Meaopolitan Edison Company to supply up to 227 MWe and a steam purchase agreement 

with I.E. Baker Company to supply steam to the brickmaking facility located adjacento the project site. 

The heat rate for this cogeneration plant is expected 

to be 9,200 Btu/kWh (37% efficiency). Expected SO> 

emissions from this demonstration plant are below 

0.24 lb/million Btu (92% reduction). This technology 

operates at lower temperatures than conventional boilers, thus reducing NO, production. In addition, installation of a selective non-catalytic reduction system 

Steam is generated in tubes placed along the 

combustor’s walls and superheated in tub-e bundles 

placed in the solids-circulating stream and the flue gas 

7.24 Program Update I992 York County Energy Partners 
calendar war 

1989 ,990 ,991 1992 1693 ,994 1995 ,996 1997 1998 

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

co”*tnlctb” cmlphmd 11% 

Preoperational tests initiated 11/W’ I 

OpraUon iniliatsd S/97’ 

knvimnmental moniiohgplan completed 1194 

Ground bretingkonstrudion starled t/94 

Design completed 1194’ 

Project completedlnnai 

report issued lZ9S’ 

Opration completed 12&S’ 

EPAprocess completed (EIS) tZW* ‘Projecteddate 

planned for the facility is expected to reduce the NO, 

emissions by an additional 50%. 

coal- and waste-handling equipment as well as steam 

turbine equipment are retained, the life of a plant can be 

extended. 

Project StatuslAccompllshments: 

During 1992, the project was resnuctured and relocated 

to a new site in West Manchester, PA. The project is in 

the preliminary design stage. The sponsor is negotiating 

agreements with major equipment vendors and with 

coal and limestone suppliers. Environmental information for use in the NEPA process has been prepared. A 

public scoping meeting was held in August 1992 to 

solicit public comments on preparation of the project’s 

environmental impact statement. 

In its commercial contiguration, ACFB technology 

offers several potential benefits when compared to 

conventional pulverised coal-fired systems: lower 

capital costs; reduced SO, and NO= emissions at lower 

costs: higher combustion efficiency; and dry, granular 

solid waste which is easily disposed of or which may be 

a salable by-product. 

Commercial Applications: 

ACFB technology has good potential for application in 

both the industrial and utility sectors, whether for use in 

repowering existing plants or in new facilities. ACFB is 

attractive for both baseload and dispatchable power 

applications because itcan be efficiently turned down to 

25% of full load. Coal of any sulfur content can be 

used, and any type or size of a coal-fired boiler can be 

repowered. Because an existing plant area is used, and 

York County Energy Partners Program Update 1992 7.25 
CCT-I I 

Project Fact Sheets 
Combustion Engineering 

IGCC Repowering Project 

Sponsor: 

ABB Combustion Engineering, Inc. 

Additional Team Members: 

City Water, Light and Power-cofunder and host utility 

State of Illinois, Depxttnent of Energy and Natural 

Resources+ofunder 

Location: 

Springfield, Sangamon County, IL (City Water, Light 

and Power’s Lakeside Station) 

Technology: 

ABB Combustion Engineering’s integrated gasification 

combined-cycle (IGCC) system 

PlantCapaclty/Production: 

65 MWe 

Project Funding: 

Total project cost $270,7c0,000 1007c 

DOE 129,357,204 48 

Participants 141,342,796 52 

Project ObJectWe: 

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

two-stage, entrained-flow coal gasifies with amovingbed, zinc titanate, hot-gas cleanup system: to assess 

long-term reliability and maintainability of the system at 

a sufficient scale to determine commercial potential. 

7.28 Program Update’1992 

COAL 

HANDLING 

Technology/Pro)ectDescrlptlon: 

Pressurized pulverized coal is pneumatically transported 

to the gasifier. The gasifier essentially consists of a 

bottom combustor section and a top reductor section. 

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

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

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

approximately 2,ooO OF and are reduced in temperature 

to about 1,000 “F in a heat exchanger. Char in the gas 

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

as by asubsequent fine-particulate removal system, and 

recycled back to the gasifier. 

A newly developed process consisting of a moving 

bed of zinc titanate sorbent is being used to remove 

sulfur from the hot gas. Puticulate emissions are 

removed from the coal-handling system and gas stream 

j by acombination of cyclone separators and baghouses, 

and a high percentage of particulates are fed back to the 

gasitier for more complete reaction and ultimate 

removal with the slag. 

The cleanedlow-Btu gas is routed to a combinedcycle system for electric power production. About 

40 MWe are generated by a gas turbine. Extracted ah 

from the gas turbine is used to meet the high-pressure 

air requirements of the gaaitier and the zinc titanate 

desulfurizatipn system. Exhaust gases from the gas 

turbine are used to produce steam which is fed to a 

bottoming cycle to generate an additional 25 MWe. 

The demonstration project is converting 600 tons/ 

day of coal into 65 MWe. This is being accomplished 

through the installation of an entrained-flow coal 

ABB Comblrrtion EngineeringlIGCC 
11190 4196 5101 

I 

1 I 

t 

Conrtrunion started 4/93’ 

Environmental moniloring plan completed l&93’ 

NEPA process wmpleled (EA) X27/92 

Cqwatwe a9reeme”tawa,ded 11120190 

t 

Design Mmpleted 4/96’ 

ContruQion completed 4196 

Operation inliated 4196’ 

i 

Project completed! 

final re+mi ikj;u 

Operation 

completed 5Dt’ 

‘Projected date 

gasifier and the integration of a 25MWe steam turbine 

with a40-MWe gas turbine at City Water, Light and 

Power’s Lakeside Station located in Springfield, IL. 

The anticipated heat rate for the repowered unit is 

8,800 BtukWh (a” efficiency of 38.8%). SO, emissions are expected to be less than 0.1 lb/million Btu 

(99% reduction). NOx emissions are also expected to be 

less than 0.1 lb/million Bt” (90% reduction). 

The IGCC system being demonsnated in this project is 

suitable for both repowting and “ew power plant applications. Repowering aging plants with this technology 

will improve plant efficiency and reduce emissions of 

SO,, NO”, and CO,. Also, the modular design of the 

gasitier will permit arange of units to be considered for 

repowing. 

Commercial Applications: technology is expected to have a heat rate less than 

8,000 Btu/kWh (efficiency greater than431c). This heat 

rate is expected to realize at least a 20% improvement in 

efficiency compared to a co”ventionaJ pulverized-coalfied plant with flue gas desulfurizatio”. The improved 

system efficiency also results in a similar decrease in 

CO, emissions. s 

Due to the advantages of modularity, rapid and 

staged on-line generation capability, high efficiency, 

fuel flexibility, environmental conuollability, andreduced land and natural resource needs, the IGCC system is also a saong contender for new electric power 

generating facilities. Further, without the need for an 

oxygen plant, the ABB Combustion Engineering technology represents apotentially simpler approach to 

gasification-based power generation. A single-train 

IGCC system based on this gasitier is capable of producing more than 150 MWe. A commercial-scale facility based on the ABB Combustion Engineering 

Calendar Year 

,988 ,999 1990 1991 1992 1993 1994 1995 ,995 ,997 1998 

3412341234 1234 1 234 1234 1234 1 234 1234 1 234 12 

ProjectStatus/Accompllshments: 

System definition and preliminary design activities are 

complete. Refurbishment of existing facilities at the 

Lakeside Station is in progress. Also, due to advances 

in high-temperature sorbtmt development and successful 

tests of hot-gas cleanup&vices, the project will damonstrate a moving-bed hot-g% cleanup system using a zinc 

titanatesorbent. 

An environmental assessment with a finding of no 

significant impact was completedMarch 27.1992. 

d n)I) rnmhmrhn En&eertia/IGCC Program Update I992 7-29 
SNOX Flue Gas Cleaning 

Demonstration Project 

Sponsor: 

ABB Combustion Engineering, Inc. 

Additional Team Members: 

Ohio Coal Development Office-cofunder 

Ohio EdisonCompany-cofunderand host utility 

Haldor Topsoe-patent owner for process technology. 

catalysts, and WSA Tower 

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

Location: 

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

Station, Unit No. 2) 

Technology: 

Haldor Topsoe’s SNOX catalytic advanced flue gas 

cleanup system 

Plant Capacity/Production: 

35-MWe equivalent slip-stream from a 108-MWe boiler 

Project Funding: 

Total project cost $3 L438.408 100% 

DOE 15,719,200 50 

Participants 15,719,208 50 

Project Objective: 

To demonstrate on U.S. coals at a” electric power plant 

that SNOX technology till catalytically remove 95% of 

SO, and more than 90% of Nor from flue gas and produce a salable by-product of concentrated sulfuric acid. 

Technology/ProJect Description: 

In the 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 

sulfuric acid catalyst in the downstream SO, converter. 

The ash-free gas is reheated, and NO, is reacted with 

small quantities of ammonia in the first of two catalytic 

reactors where the NOx is converted to harmless nitrogen and watervapor. The SO, is oxidized to SO, in a 

second catalytic converter. The gas then passes through 

a novel glass-tube condenser which allows SO, to hydmlyze to concentrated sulfuric acid, 

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

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

NO* from flue gas and produce a salable sulfuric acid 

by-product. This is accomplished without using SOTbents and without creating waste by-products. 

The demonsaation unit is installed at Ohio 

Edison’s Nile? Station in Niles, OH. The process is 

treating a 35-MWe equivalent slipstream of flue gas 

from the 108.MWe Unit No. 2 boiler that bums a 

3.4% sulfur coal. The process steps are virtually the 

same as for a full-scale plant, and commercial-scale 

components are being used. 

7-30 Program Update1992 
CalendarYear 

wea ,989 ,990 ,991 ,992 1993 1994 1995 ,996 ,997 1998 

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

Environmental monitoring plan completed 

Ccqmmtbeagreement 

awarded 1zmM9 Design completed 8191 

Connrudion started 1191 

NEPA process completed (MTP) 1131190 

‘Projected date 

ProjectStatus/Accomplishments: 

Consrruction was compl&d in December 1991, and 

operation commenced in March 1992. After 2 months 

of operation, test results met or exceededesign objectives, as follows: 

* SO, removal-96% in tests (95% design) 

* NOr removal-94% in tests (90% design) 

* H,SO, purity-93% in tests (93% design) 

The SNOX unit has undergone little process tuning, 

and, as more information is generated, performance may 

even improve. The system has operated more than 

2,450 hours during 1992, producing approximately 

234,ooO gallons of sulfuric acid which was sold for 

indusuial use. 

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

ash) enhances the marketability in urban and other areas 

where solid waste disposal issues are a significant 

impediment. 

Commercial Applicattons: 

The SNOX technology is applicable to all electric 

power plants and industrial/institutional boilers fling 

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

ABB Comb&on EngineeringlSNOX Pro.qram Updare I992 7.31 
PFBC Utility Demonstration 

Project 

Sponsor: 

The Appalachian Power Company 

AddItionalTeam Members: 

American Electric Power Selvice Corporation-design, 

construction, and management 

The B&cock & Wilcox Company-technology 

supplier 

Location: 

New Haven, MasonCounty, WV (greenfieldfacility adjacent to Appalachian Power Company’s Mountaineer 

Plant) 

Technology: 

The Babcock & Wilcox Company’s pressurized 

fluidized-bed combustion (PFBC) system (under license 

from ABB Carbon) 

Plant Capacity/Production: 

340 Mwe (net) 

Project Fundlng: 

Total project cost $917,944,000 100% 

DOE 184,800,OOO 20 

Participants 733,144,OOo 80 

ProjectObjective: 

To demonstrate PFBC at 340 MWe, a large utility scale 

representing afour-fold scaleup of the technology, the 

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

reliability, availability, and maintainability of PFBC in a 

commercial operating mode and the integration of areheat steam cycle. 

7-32 Program Update I992 

Technology/ProjectDescrlptlon: 

Tbis project will be a greenfield facility located adjacent 

to the existing Mountaineer and Sporn plants. The most 

noticeable aspect of the unit is that the boiler, cyclones, 

reinjection vessel, and associated hardware are encapsulated in a pressure vessel 60 ft in diameter and 100 ft 

high. 

The project incorporates a bubbling floidized-bed 

process operating at 16 atm (235 lb/in’ atm). Pressurized combustion air is supplied by the turbine 

compressor to fluidize the bed material (consisting of a 

coal-water fuel paste, coal ash, and a d&mire or 

limestone sort@. Dolomite or limestone in the bed 

reacts with sulfur to form calcium sulfate, adry, 

granular bed-ash material, which is easily disposed of or 

used BS a by-product. A low bed-temperature of

1,600 “F limits NO” formation. 

The hot combustion gases exit the bed vessel with 

enaained ash panicles, 98% of which are removed 

when the gases pass through cyclones. An option being 

considered is to employ some advanced filtration devices in the design. The cleaned gases are then expanded through a 75-MWe gas turbine. 

The reheat system turbine operates at a state-of-theart pressure and temperature to produce at least 

250 MWe. Superheated steam will be produced from 

pressurised boiler-feed water in the tobes submerged in 

the fluid&d bed. The projected heat rate for this unit is 

8,500 BtuikWb (40.2% efticiency based on HHV). SO, 

emissions are expected to be reduced by 95% and NO, 

emissions by 80%. 

Appolachian PowrlPFBC 
9188 4190 11102 2104 

I 

t 

f 

Design completed 802’ 

~;&lected project 

.I\ 1 

C~n~t,wl,on completed SlO2’ 

Preoperational tests initiated 8102’ 

T 1 

operation initiated 11102’ 

Ground breakingiconstruction starved 6199’ Project completed/final repon issued 2lO4’ 

NEPA process completed (EIS) .?/9S’ operation completed 2/04’ 

Environmental monbxlng plan completed 7197 

Cooperative agreement awarded 414190 

‘Projected date 

‘Years onlined 

ProjectStatu~/Accomplishments: 

During 1992, DOE approvedres!mcturing and 

continuation of the project. Value engineering and 

preliminary design efforts are under way. The aim is to 

reduce the technical and economic risks of the project 

during the time before the utility’s load growth warrants 

construction of the new power plant. The Babcock & 

Wilcox Company, the technology vendor, is conducting 

thevalue engineering efforts, including optimization of 

scaleup parameters, improved sulfur capture, and capital 

cost reductions. 

Commercial Appllcatlons: 

This project will be the initial version of a commercial 

plant. Combined-cycle PFBC systems permit the combustion of a wide range of coals, including high-sulfur 

coals. This technology will compete with circulating 

PFBC systems to repower or replace conventional 

power plants with a technology capable of using highsulfur coals in an environmentally sound manner. 

PFBC technology appears to be best suited for a wide 

range of applications beginning at the 50-MWe size. 

Because of modular construction capability, PFBC generating plants permit utilities to add economical increments of capacity to match load growth and/or to easily 

repower existing plants using available coal- and wastehandling equipment, and existing steam turbines. Another advantage for repowering is the compactness of 

the process because of pressurized operation. 

The projected net heat rate for the commercial plant 

will be 8,500 Btu/kWh (based on HHV) which equates 

to an efficiency of 40.2%. An advanced cycle that integrates a small gasifier could yield heat rates approaching 7,500 Btu/kWh (45% efficiency). Environmental altributes include in-situ sulfur reduction of 95% andNOx 

emissions reduction to 0.1 lb/million Btu. Although the 

system may generate a slight increase of solid waste as 

compared to conventionaJ systems, the dry material is 

either disposable or potentially usable. 

Program ffpdare 1992 7.33 
Demonstration of Coal 

Reburning for Cyclone Boiler 

NO, Control 

Sponeor: 

The B&cock &Wilcox Company 

Additional Team Members: 

Wisconsin Power and Light Company-cofunder and 

host utility 

Sargent and Lundy-engineer for coal handling 

Electric Power Research Institute-cofunder 

State of Illinois, Depanment of Energy and Natural 

Resources-cofunder 

Utility companies (14 cyclone boiler operators)- 

cofunders 

Location: 

Cassville, Grant County, WI (Nelson Dewey Station, 

Unit No. 2) 

Technology: 

The Babcock 81 Wilcox Company’s coal reburning 

system 

PlantCapacitylProducUon: 

100MWe 

Project Funding: 

Total project cost $13,071,559 100% 

DOE 6,213,929 48 

Participants 6J57.630 52 

Project Objective: 

To evaluate the applicability of rebuming technology 

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

cyclone boiler, pulveriziing a portion of the primary coal 

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

achieve greater than 50% reduction in NO, emissions 

with no serious impact on cyclone combustor operation, 

7-34 Program Update 1992 

boiler efficiency, boiler fireside performance (corrosion 

and deposition), or ash removal system petformance. 

Technology/Project Description: 

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

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

equivalent fuel input to the boiler and slightly less than 

normal combustion air input. The balance of the coal 

(20-30s). along with significantly less than the theoretically determinedrequirement ofair, 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 

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

The completion of the combustion process occws in the 

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

the combustion air is introduced. The combined production of boiler slag and dty waste from the elecaostatic 

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

constant. 

The coal rebuming technology can be applied with 

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

effects of rebum on the cyclone combustor and boiler 

performance. 

This project involves retrofitting an existing 

100.MWe cyclone boiler that is representative of a large 

population of cyclone units. The cyclone boiler being 

retrofitted is presently in commercial operation at 

B&W/Rebuming 
Calendar Year 

1988 ,989 ,990 ,991 1992 1993 1984 1995 1986 ,997 1998 

341234 1 * 3 4 1 2 3 4 1234 1 234 1 234 1 2 3 4 12341234 12 

T 

projecl 1 DOE selected 

W28i*8 

Design 

started 

T/89 

A A 

11 Ts Operation initiated 

tperation+ 

Project Fompletedifinal report issued 6193’ 

12191 

CO”StN*,o” cmnpleted ,119, 

Preoperational tests inkiated 11191 

Environmental monkodng plan completed 1W3191 

Design completed 6191 

NEPAprocess completed (En) 2/12/91 

Ground breakingicons!rudion started 11/l/90 

Caoperatbe agwment awarded 42m ‘Projecteddate 

Wisconsin Power and Light’s Nelson Dewey Station in 

Cassville, WI. The coal specified for testing is Lamar 

coal from Indiana. It is bituminous coal withabout 

1.8% sulfur. Law-Btu, low-sulfur western coal is also 

being tested. 

Project Status/Accomplishments: 

Operational testing began in December 1991 and continued through 1992. Results of testing in 1992 indicated that NO” emissions were reduced by about 55% 

between 110 MWe (full load) and 70 MWe. From 

70 MWe to 40 MWe, the NO, reductions ranged from 

50% to 35%. Long-range testing was completed in 

early October 1992, followed by a 3-week outage on the 

boiler. Air toxics emissions monitoring was conducted 

in November 1992. Rebum testing of western coal as 

well as all testing scheduled for the Nelson Dewey 

Station was completed in December 1992. 

Commercial Appllcatlons: 

The current reburn market is nearly 26,000 MWe and 

consists of about 120 units ranging from 100 MWe to 

1,150 MWe, with most in the 100-300 MWe range. 

Coal reburning is a retrofit technology applicable across 

the size range of utility and industrial cyclone boilers. 

advantage of the rebum system is its ability to utilize 

different coals. 

The principal environmental benefit is reduced NO= 

emissions. A secondary benefit may be reduced SO, 

emissions by enabling greater use of lower sulfur westem coal; due to its lower Btu content, western coals 

limit cyclone capacity. With the additional firing capacity of thereburn system, full-load petfom~aoce on westem coal may be possible for some cyclone units. 

Coal reburning has economic advantages. Although capital costs for coal handling and preparation 

are higher than for other fuels, the overall cost differential fawn coal. Coal’s cost differential and dependahility of supply give it the long-run advantage. Another 

B&WlRebuming Program Update 1992 7-3s 
SOX-NOX-ROX Box Flue Gas 

;zittp Demonstration 

Sponsor: 

The Babcock & Wilcox Company 

Additional Team Members: 

Ohio Edison Company-cofunder and host utility 

Ohio Coal Development Office-cofunder 

Elecuic Power Research Institute-cofunder 

Norton Company-cofunder and SCR catalyst supplier 

Minnesota Mining and Manufacturing Company 

cofunder and filter bag supplier ( 

Locatlon: 

Dilles Bottom, Belmont County, OH (Ohio Edison 

Company’s R.E. Burger Plant, Unit No. 5) 

Technology: 

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

box (SNRB) process 

Plant CapacltylProduction: 

5-MWe equivalent slipstream from a 156~MWe boiler 

Project Funding: 

Total project cost 

DOE 

Participants 

$13,327,217 100% 

6,094,057 46 

7.233.220 54 

ProJect Objective: 

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

usedin retrofitting a high-sulfur%oal-fued power plant, 

can remove high levels of all three pollutants using a 

single processing unit for treating flue gas, thereby lessening on-site space requirements and capital costs. 

COAl 

AIR 

HIGH-TEMPERATURE 

T 

BOTTOM 

ASH ..&$,w~ 

oh*.+ ‘;~$#$qw. 

DRY WASTE TO DlSP0S.C 

Technology/ProJectDescrlptlon: 

l’be SNRB process combines the removal of SO,, NO,, 

andparticulates 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 to sele.ctively reduce NOx in the presence of a selective catalytic reduction, or SCR, catalyst. Particulate 

removal is accomplished by high-temperature fiber bag 

filters. 

economic feasibility of achieving greater than 70% SO, 

removal, up to 90% NOx removal, and 99% particulate 

The project will demonstrate the technical and 

removal at lower capital, operating, and maintenance 

costs than a combination of conventional systems. The 

demonstration will be conducted at Ohio Edison 

Company’s R.E. Burger Plant, Unit No. 5, in Diltes 

Bottom, OH. Bituminous coal with an average sulfur 

content of 3.4% is being burned at this site. 

The 5-MWe SMB demonstration unit is large 

enough to demonstratecommercial-scale components 

while minimizing the demonsuation cost. Additionally, 

at this scale, the flue gas temperature can be readily 

controlled to determine the optimum temperature for 

maximum SO, and NOx reductions. 

7-36 Program Update I992 B&WISOX-NOX-R0XBo.r 
Calendar Year 

1988 ,989 w90 ,991 1992 ,993 1994 ,995 ,996 1997 1?#98 

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

‘Projacladdate 

9188 12/89 5192 8/93 

EPAProcesscompleted 

pm=) w22,89 

Operation inliated 5192 

struc,io” completed ,2/w 

‘mnmental monaaling pIall completed 

eradonaltesls initiated 11191 

8191 

ProjectStatuslAccompllshments: Commercial Appllcatlons: current performance requirements while providing 

Operations and testing of the unit on the 5-MWe Commercial application of the technology offers the flexibility to address future needs. 

equivalent slipstream at the R.E. Burger Plant began in potential for significant reductions of multiple pollutants 

May 1992. Emission control performance has exceeded from fossil-fired plants with the potential for increasing 

project goals. SO, reduction has reached 85% at a thermal efficiency. SNRB offers tbepotential for lower 

calcium-ta-solfurratio of 2.0:1 and 850 “F baghouse capital and operating costs and smaller space requiretemperature. NO% emissions have been reduced by ments than a combination of conventional, high-effigreater than 90% with ammonia slip less than 10 ppm, ciency control technologies. SNRB is capable of reducParticulate emissions are consistently less than 0.03 lb/ ing emissions from plants burning high- or low-sulfur 

million Btu. Approximately 2,600 hours of testing have coal. In retrofit applications, SNRB provides a means 

been completed at the R.E. Burger Plant. Testing is of improving particulate emissions control with the 

expected to be completed in March 1993. addition of SO, and NO,emissions control capacity. 

Approximately 3,800 hours of testing and three 

types of fabric filters have been accumulated at the 

Fabric Durability Test Facility in Colorado Springs. 

This testing was completed in December 1992. 

An air toxics emissions test program hasbeen 

finalized by the participant and is scheduled to becompleted in February 1993. 

Commercialization of the technology is expected to 

develop with an initial larger scale application equivalent to 50-100 h4We. The focus of marketing efforts 

will be tailored to match the specific needs of potential 

industrial. utility, and independent power producers for 

both retrofit and new plant constn~ction. SNRB is a 

flexible technology which can be tailored to maximize 

control of SO,, NOx, or combined emissions to meet 

Program Update 1992 7-37 
Innovative Coke Oven Gas 

Cleaning System for Retrofit 

Applications 

Sponsor: 

Bethlehem Steel Corporation 

Addltlonal Team Member: 

Still-Otto-technologydeveloper 

Location: 

Sparrows Point, Baltimore County, MD (Bethlehem 

Steel Colporation’s Sparrows Point Plant, Coke Oven 

Batteries A. 11. and 12) 

Technology: 

Still-Otto’s process for precombustion cleaning of coke 

oven gas (COG) 

Plant Capacity/Production: 

14 million std ft’iday of COG 

Project Funding: 

Total project cost 

DOE 

Participant 

$45,239,781 100% 

13,500,000 30 

31,739,781 70 

ProJect Objectlve: 

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

commercially available process steps for simultaneous 

removal of hydrogen sultide and ammonia from COG, 

recovery of hydrogen sulfide and ammonia destruction 

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

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

ammonia to wastewater treatment. 

Technology/Project Description: 

This project is demonstrating an innovative technology 

developed by Still-Otto for removing hydrogen sulfide 

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

COG. Both hydrogen sulfide and ammonia are steam 

stripped from the absorption liquor. The ammonia is destroyed in acatalytic reactor; hydrogen sulfide is convened to elemental sulfur in a conventional Claus plant, 

and sulfur is recovered as asalable by-product. 

The technology is expected to reduce the hydrogen 

sulfide concentration in the cleaned COG by 88% and 

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

associated with the purchase and handling of feed 

reagents, the hwdling and treatment of by-products, labar, and utilities are reduced. 

This project involves the modification of the COG 

processing units at Bethlehem Steel’s Sparrows Point 

Plant in Baltimore County, MD. The demonstration facility is processing the entire COG stream from Coke 

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

74 million std ft’lday. These coke oven batteries produce up to 1.2 million tons& of coke from a blend of 

Pennsylvania and Virginia coals having sulfur contents 

ranging from 0.8% to 1.37%. The raw COG has a hydrogen suliide content of 175-340 grains/100 ft3. Currently, only 60% of this COG stream is desulfurized. 

The remaining 40% is used directly for under-firing the 

coke ovens. 

7-38 Program Update 1992 Bethlehem SreeUCoke Own Gas 
catendar Year 

,988 1989 1990 1991 ,992 ,993 1994 1995 1996 1997 1998 

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

Oeshn and Construction 

1 II1 t’ 4- t- Prqect completedifinal report iswad 5195’ 

Operation completed *:195’ 

operation i”Riatsd ,194 

Preoperatianaltests initiated 10193 

Facilly mothballing completed 1192 

Construction completed 12191 

Environmental monitoring plan completed 715191 

Design completed 11/90 

bound breaking/construction stated 2190 

.:PAprocess completed (EA) 12122/8g 

ooperatwe agreement awarded 1,,14,8g 

‘Projected date: milestones to be updated following resumption 

of operation: a.es~me~ 2-y slippage for coke own rebuilding 

ProjectStatus/Accompllshments: 

On September 16, 1991, Bethlehem Steel Corporation 

announced that all coke production will be suspended at 

its Sparrows Point facility for at least 2 years. This 

decision was made due to therapid deterioration of the 

coke ovens. During this period, a” evaluation will be 

made to explore alternatives for resumption of coke 

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

coke independence at the facility. 

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

mothballed to maintain it in good shape so that hot commissioning, start-up, and operation can be accomplished 

successfully when coke-making operations are resumed. 

Given the high background levels of contaminants 

present in the coke oven batteries, specific air toxics 

monitoring is not contemplated at this time. Baseline 

environmental sampling is complete. 

Commercial Applications: process could be applicable to 24 plants with correThe design for this innovative COG cleaning system is spending SO,emission levels of 200,000 tonsiyr. If the 

based on operating data that have been collected from technology were installed in all 24 plants, the SO, 

individual process steps or combinations of individual emissions could be reduced by 160,CQtl tons/yr. Elimiprocess steps that have been successfully operated at nated would be the ammonium sulfate which is difficult 

commercial-sized COG treatment facilities. The novel to market and usually is disposed of as a solid waste. 

integration of commercially available process steps is Every 5-8 years,.5 tons of spent nickel catalyst would 

expected to reduce the overall cost of desulfurization, need to be returned to the vendor or disposed of as a 

ensure reliable operation in applications exceeding hazardous waste, and 10 tons of spent alumina catalyst 

20 years, and provide a viable alternative to canven- would need to be disposed of as a nonhazardous solid 

tional technologies. Because the demonstration is de- waste. Depending on the configuration of the coke oven 

signed to treat 74 million std ft’/day of COG (acommer- facility where the technology is being implemented, the 

cial size), the project will demonstrate that it is possible amount of water needed for cooling purposes would 

to retrofit any existing coke-making facility in the remain the same or be reduced, and the amount of 

United States with essentially no scaleup involved and pollutants in the wastewater would remain the same or 

without significant downtime. be reduced. 

Bethlehem Steel will license the use of this COGcleaning technology through Still-Otto to the existing 

30 coke oven plants in the United States which emit 

about 3C0,CtJl tons&r of SO,. This COG-cleaning 

Program Updare 1992 7.39 
Cement Kiln Flue Gas 

Recovery Scrubber 

Sponsor: 

Passamaquoddy Tribe 

AddItionalTeam Members: 

Dragon Products Company-project manager and host 

EC. Jordan Company-engineer for overall scrubber 

HPD, Incorporated-designer and fabricator of tanks 

and heat exchanger 

CianbroCorporation-constructor 

Location: 

Thomaston, Knox County, ME (Dragon Products 

Company’s coal-fired cement kiln) 

Technology: 

Passamaquoddy Tribe’s cement kiln flue gas recovery 

scrubber 

Plant Capaclty/Productlon: 

1.450 tons/day of cement 250,000 std ft%in of kiln 

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

Project Fundlng: 

Total project cost $16,500,000 100% 

DOE 5,982,592 36 

Participants 10,517,408 64 

ProJect Objectlve: 

To retrofit and demonstrate a full-scale indusuIaJ scrubber and waste recovery system for acoal-burning wet 

process cement kiln using waste dust as the reagent to 

accomplish 90-95s SO,reductIon using high-sulfur 

eastern coals and to produce a commercial by-product, 

potassium-basedfertllizer. 

7-40 Program Update 1992 

Technology/ProjectDescrlptlon: while it was seeking ways to solve landtill problems, 

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

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

kiln flue gas, which serves as the scrubbing medium. No The kiln burns bituminous coal containing approxiother chemicals are required for the process. After mately 3% sulfur. 

scrubbing the gas, the slurry is separated into liquid and 

solid fractions. The solid fraction is returned to the 

cement plant as renovated and usable raw feed material. 

The liquid fraction is passed to a crystallim that uses 

waste heat in the exhaust gas to evaporate the water and 

recover dissolved alkali metal salts. 

The Pawmaquoddy Tribe’s recovery scrubber is 

being constructed at the Dragon Producu Company’s 

cement plant in Thomaston, ME, a plant that processes 

approximately 470,000 tons&r of cement. The process 

was developed by the Passamaquoddy Indian Tribe 

Passamaquoddy Tribe 
Calendar Year 

,988 ,989 1990 1991 1992 1993 1994 199s 1996 1987 1998 

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

9188 

Prem 

~ 

I 

DOE 

selected 

Pr‘JM 9RBi88 

I Preoperational tests initiated 5191 

Design completed 4190 

Environmental monitoring plan completed 3R6190 

NEPAprocess completed (EA) 2/16/gO 

operative agreement awarded fW3,18g 

nstrutiion statW 6189 ‘Projecteddate 

4193 

ProjectStatus/Accomplishments: 

The recovery scrubber began operations in August 1991 

and has continued operations with several temporary 

shutdowns for normal kiln repairs and maintenance and 

amore lengthy shutdown from January to May 1992 

due to poor economic conditions in the area. In a 

5-month period from May to September 1992, the plant 

produced approximately 140,000 tons of cement while 

the scrubber removed 70 tons of SO, and treated 

6,000 tons of kiln dust for return to the kiln as raw feed. 

Initial testing of the scrubbing system achieved the 

project objective of 90-95s SO, emission reduction, 

with amaximum reduction of 98%. Project operations 

continued through December 1992 when the scrubber 

became a permanent part of the Dragon facility. The 

final report is expected at the end of April 1993. 

Commercial Applications: 

The recovery scrubber permits the use of high-solfur 

coal in cement kilns using available waste dust as the 

reagent, without requiring the purchase of other materials as scrubber reactant. 

There are over 250 cement kiln installations in the 

United States and along the St. Lawrence River in 

Canada emitting approximately 230,000 tonsiyr 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 150,000 tonsiyr. 

the amount reduced because the technology produces 

distilled water either for sale or discharge. 

The waste dust that previously would have been 

sent to a landfill would be recovered for recycling to the 

kiln and to produce byproduct fertilizer. EssentiaJly, 

the solid waste stream would be eliminated through 

recovery. 

The effect on NOx emissions is being determined 

during the demonstration. Some reductions in NOx 

emissions are expected. 

Water usage might or migbt not increase depending 

on the configuration of the existing kiln facility. However, the quality of wastewater would be improved and 

Passanuzquoddy Tribe Program Update 1992 7-41 
Advanced Flue Gas 

Desulfurization 

Demonstration Project 

Sponsor: 

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

Air which is a general partnership between Air Products 

and Chemicals, Inc., and Mitsubishi Heavy Industries 

America, Inc.) 

Additonal Team Members: 

Northern Indiana Public Service Company-cofunder 

and host utility 

Mitsubishi Heavy Industries, Ltd. (pa&t company) 

process designer 

United Engineers and Constructors (Stearns-Roger 

Division)-facilitydesigner 

Air Products and Chemicals, Inc.-constructor and 

Location: 

Chesterton, Porter County, JN (Northern Indiana Public 

Service Company’s Badly Generating Station) 

Technology: 

Pure Air’s advanced flue gas desulfurization (AFGD) 

p”XCSS 

Plant Capaclty/Productlon: 

528 MWe 

Project Funding: 

Total project cnst $150,497,000 100% 

DOE 63,434,OoO 42 

Participants 87,063,OOO 58 

Project Objective: 

To demonsUate removal of 90-95s or more of the SO, 

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

Technology/ProjectDescrlptlon: 

In this project, Pure Air has built a single SO, absorber 

for a 528~MWe power plant. Although this is the largest capacity absorber module in the United States, it has 

relatively modest space requirements because no spare 

or backup absorber modules are required. The absorber 

performs three functions in a single vessel: 

prequencher, absorber, and oxidation of sludge to gypsum. Additionally, the absorber is of a cocurrent design, in which the flue gas and scrubbing slurry move in 

the same direction and at a relatively high velocity 

compared to conventional scrubbers. These features all 

combine to yield a state-of-the-art SO, absorber that is 

more compact and less expensive than conventional 

scrubbers. 

ized limestone directly into the absorber, a device called 

an airrotary sparger located within the base of the abTechnical features include the injection of pulversorber, and a novel wastewater evaporation system. 

The air rotary sparger combines the functions of stirring 

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

The AFGD process has demonstrated simultaneous 

removal of 90-95s or mnre of the SOI while providing 

acommercial gypsum by-product and is demonstrating 

wastewaterevaporation. 

The project also seeks to demonstrate a novel 

business concept whereby Pure Air owns and operates 

the AFGD facility. Thus, Pure Air expects to specialize 

in pollution control activities, relieving the elecrric 

7.42 Program Update1992 Pure-Air 
C&“&r Year 

1988 1989 ,990 1991 ,992 1983 1994 1995 1995 1997 1998 

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

I 

A’., 1’ 

t 

Design compl*r*d g/9.2 T 

Project completed/final report issued 9195 

Construnion completed 9,992 I 

Operation intiated 6192 

Operation completed 61% 

DOE selected project 

9Rwa8 Preaperationaltests inkted 3192 

Environmental monloring plan completed 1131191 

NEPA ~RX~S.S armpleled (EA) 4116190 

Gmund breaking/wnstruc(ion started 4/20/90 

Cooperaliveagreemenlawarded 1’242018g ‘Projecteddate 

utility of the operation of the AFGD unit. Assuming 

that the 3-year demonstration is successful, Pure Ah 

will continue to own the AFGD facility and to operate it 

as a contracted service to the utility for an additional 

1Fyearperiod. The demonstration is located at Northern Indiana Public Service Company’s 52%MWe Bailly 

Generating Station near Chesterton, IN. 

ProjectStatus/Accotipllshments: 

Design is complete. To confirm process design, pilot 

testing was performed in 1990, successfully meeting 

both SO, removal and gypsum purity levels using U.S. 

high-sulfur coal andlimestone f&stocks. A long-term 

performance test was conductedin 1991 to verify operational parameters for the air rotary sparger. it, too, was 

s”ccessf”l. 

Construction was completed ahead of schedule, 

despite the occurrence of a ground subsidence event at 

the Bailly station on July 2, 1991. The AFGD facility 

began operations in June 1992. By year end, operations 

had gone well; SO, removals in excess of 95% and 

average by-product gypsum purities of 9697% had 

been achieved. Tests on the utility’s standard coal 

(3-3.5%s”lfur) werecompleted. 

Commercial Appllcatlons: 

The AFGD process is attractive for both new and reuofit utility applications. The demonstration project is 

using bituminous coals primarily from the IndianaIllinois coal basin, with sulfur content ranging from 

2.0% to 4.5%. 

The AFGD facility will reduce SO, emissions at the 

Bailly Station by approximately 50,000 tons/y*. Further, the gypsum by-product and wastewater evaporation will demonstrate that SO, control can occur without 

increased solid waste or wastewater production. 

All this can be accomplished with costs (and space 

requirements) that are roughly one-half of those associated with a conventional scrubber. 

Pure AL Program Updare 1992 743 
Demonstration of Advanced 

Combustion Techniques for a 

Wall-Fired Boiler 

Sponsor: 

Southern Company Services, Inc. 

Addltlonal Team Members: 

Elecaic Power Research Institute-cofunder 

Foster Wheeler Energy Corporation-technology 

supplier 

Georgia Power Company-host utility 

Locatlon: 

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

Plant Hammond, Unit No. 4) 

Technology: 

Foster Wheeler’s low-NOx burner (LNB) with advanced 

aver-fire air (AOFA) 

Plant CapacRy/Productlon: 

500 MWe 

Project Funding: 

Total project cost $14,710,909 1007c 

DOE 6,553,526 45 

Participants 8,157383 55 

(Of the total project cost, $523,680 are for toxics 

testing.) 

Project Objective: 

To achieve 50% NOxreduction with the AOFA/LNB 

system: to determine the contributions of AOFA and the 

LNB m NOz reduction and the parameters determining 

optimum AOFA/LNB system performance; and to assess the long-term effects of AOFA and LNB on NO= 

reduction and boiler performance. 

Technology/Project Descrtptlon: 

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

air with the furnace gases to achieve complete combustian, (2) depleting the air from the burner zone to minimix NOx formation, and (3) supplying air ovtx furnace 

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

emissions by about 35%. 

In an LNB, fuel and air mixing is controlled to 

preclude the formation of NO,. This is accomplished by 

regulating the initial fuel-air mixture, velocities, and 

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

gases so as to maintain a deficiency of oxygen. Typical 

results for utilities indicate that LNB technology is 

capable of reducing NOx emissions by about 45%. 

Based an earlier experience, the use of AOFA in 

conjunction with LNB can reduce NO, emissions by as 

much as 60% compared with conventional burners. 

The demonstration is located at the GeorgiaPower 

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

nominal 500XWe pulverized coal, wall-fned unit, 

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

7.44 h&W,, Updnre1992 
CalendarYear 

,988 1989 1990 Is91 1982 1993 1994 1995 ,996 1997 ,998 

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

Dsslgn and Construction 

12/94 

I 

DOE seleded 

prOjed 

9RW88 

I 

NEPAprwss 

cognnp~ted (MTF) 

bperation initiated, LNB 4/91 

Construction complet&d. LNB 4191 

ConstruCtion staned, LNB 3191 

Operation completed, AOFA 3191 

Environmental monitoring plan completed 9114190 

Operation inMated, AOFA 6190 

ConstrucIion completed. AOFA 5190 

Construction started, AOFA 4190 

Design completed 3190 

operalivsagreementawar*d 12rm89 

project completed/final repon issued 12/94* 

Operation completed. LNBIAOFA 12194’ 

‘Projected date 

ProJectStatus/Accompllshments: 

Analysis of more than 80 days of AOFA operating data 

has provided statistically reliable results indicating that, 

depending upon load, NOx reductions of 24% are 

achievable under normal long-term operation. 

New work has been added to the test schedule, 

including installation and testing of an advanced LNB 

digital control system that has the potential to optimize 

LNB/AOFA performance. Completion of the final 

analysis of project data and issuance of the final report 

are scheduled for December 1994. 

* Competitive capital and operating costs 

- Relatively easy retrofit 

* Little or no derating of the boiler 

Preliminary data analysis for both short-parametric 

and long-term LNB operation tests indicates NO, reductions of 48% are achievable under full-load conditions. 

* Use of commercially available components 

For both AOFA and LNEt, preliminary analysis 

indicated significant increases of flyash lass on ignition 

values as compared to the baseline values. Results also 

show that post-LNEI retrofit precipitator particulate 

mass loading and gas flow rates are substantially above 

baselinevalues. 

Pre-retrofit LNB air toxics testing was performed to 

establish a baseline. Additional air toxics testing with 

the combined LNFVAOFA configuration is planned for 

early 1993. 

Combined LNB/AOFA tests began in late-1992 

and will continue into 1993. Delays in completion of 

planned testing have resulted from operating the test 

boiler at reduced loads to meet particulatecompliance 

limits. A variance is being sought from the State of 

Georgia to allow completion of the planned tests. 

Commercial Appllcatlons: 

The technology is applicable, in the United States, for 

retrofitting the 422 existing pre-NSPS wall-fired boilers, 

which bum avariety of coals, including bituminous, 

subbituminous. and lignite coal. 

Commerciaiization of the technology will be aided 

by the following characteristics: 

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

Southern Company Se~icesiWall-FiredBoiler Program Update 1992 745 
Demonstration of Innovative 

Applications of Technology 

for the CT-121 FGD Process 

sponsor: 

Southern Company Services, Inc. 

Additional Team Members: 

GeorgiaPowerCompany-host utility 

Electric Power ResearchInstitute-cofunder 

Radian Corporation-environmental and analytical 

Ershigs, Inc.-fiberglass fabricator 

University of Georgia Research Foun@ionby-product utilization studies 

Location: 

Newnan, Coweta County, GA (Georgia Power 

Company’s Plant Yates, Unit No. 1) 

Technology: 

ChiyodaCorporation’sChiyodaThoroughbred-121 

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

prOC?eSS 

Plant Capacity/Production: 

100 MWe 

Project Funding: 

Total project c”st 

DOE 

Participants 

$35,843,678 100% 

17,546,646 49 

18,297,032 51 

Project Objective: 

To demonsnate the CT-121 flue gas desulfutization 

system, including several design innovations, at the 

lOO-MWe scale: more specifically, t” demonstrate 

90% SO, control at high reliability with and without 

simultaneous particulate control with possible additional 

reductions in operating costs. 

7-46 Program Update 1992 

Technology/Project Description: 

The project is demonstrating the CT-121 FGD process, 

which uses a unique absorber design known as the jetbubbling wact”r (IBR). The process combines limest”ne FGD reaction, forced oxidation, and gypsum 

crystallizatio” in one process vessel. The process is 

mechanically and chemically simpler than conventional 

FGD processes and can be expected t” exhibit lower 

cost characteristics. 

The flue gas enters the scrubbing solution on the jetbubbling reactor. The SO, in the flue gas is absorbed 

and forms calcium sulfite (CaSO,). Air is bubbled into 

the bottom of the solution to oxidize the calcium sulfite 

to form gypsum. The slurry is dewatered in a gypsum 

stack, which involves filling a dyked area with gypsum 

slurry. Gypsum solids settle in the dyked area, and 

clear water flows t” a retention pond. The clear water 

from the pond is returned to the process. 

The project is also evaluating process innovations 

t” determine whether costs can be reduced furthw by 

using fiberglass-reinforced plastic absorbers, eliminating flue gas reheat and spare absorber modules, and 

stacking gyp&m to reduce waste management c”sts. 

The ability of this technology to capture SO, and particulates simultaneously is also being evaluated. 

A 2.5% sulfur coal is being used t” demonstrate 

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

simultaneous particulate control. 

The site is Georgia Power Company’s 100~MWe 

Plant Yates, Unit No. 1, “ear Newnan, GA. 

Southern Company ServiceslCT-I21 
CalendarYear 

1988 ,989 1990 1991 1992 1993 ,994 ,995 1996 ,997 ,998 

3412341 234 1 234 1 2341234 1 234 1234 1234 1 234 12 

1 ‘1 

T t t 

Environmentalmooitoring 

‘1 

Operation inkiated 10192 

plan cwnpleted 12,18/90 Canstruaion completed 10192 

Design compl*ted 9192 

NEPAprocess 

completed (EA) 8/10190 

1 T E”a,“atio” 0, 

Project completedifinal 

repott issued 1/w’ 

DOE selected 

projecl 9,28,a8 

gyps”m-stacld”g operation started 8/W 

Oroundbreakinglcanstruction Operation completed 1195 

stamd 81233190 Preoperalional tests in Wed 5192 

C.x,,e,a,iveagreeme”t awarded 4&W 

‘Projecteddate 

Project Status/Accomplishments: 

Construction was completed in October 1992, and ail 

system components were turned over to the plant for 

operations. All requests by the Georgia Environmental 

Protection Division and the Georgia Geological Survey 

have been fulfilled, and the permit for the waste disposal area was issued. Gperations started at the end of 

October following a l-week outage. 

found in the phosphate fettilizer industry. Preliminary 

observations show no evidence of acidic “rain out” from 

stored safely and easily or used in commercial applications; (7) the CT-12 1 operating costs are the lowest for 

the fiberglass-reinforce plastic scrubber chimney, state-of-the-art FGD systems; (8) there is no known size 

indicating that the static flow control modifications in limit for this technology: (9) utilities and industrial 

the chimney elbow are working as expected. Testing concerns could make immediate use of this technology; 

for parametric values and for particulate loadings will and (IO) the system is not sensitive to the type of coal 

begin in early 1993. used or its sulfur content. 

Commercial Applications: 

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. This process will be applicable to 

370,000 MWe of new and existing generating capacity 

by the yeas 2010. A 90% reduction in SO, emissions 

from only the retrofit portion of this capacity represents 

over 10,500,000 tons/yr of potential SO, contml. 

Initial experience has been very good, with almost 

no off-line time attributable to the scrubber. At inlet 

SO, levels of about 2,000 ppm, the CT-121 system 

removes over 90% of the SO, at all loads and conditions 

at expected pH and pressure drop with lCQ% limestone 

utilization. Continuous emission monitors and the flow 

monitors were calibrated and certified in November, and 

the data reduction system is currently compiling data 

every 15 seconds on over 140 data points. 

The calcium sulfate produced has been placed in a 

Hypalon-lined gypsum “stacking” area for the development of an above-ground gypsum stack similar to those 

The CT- 121 FGD system is applicable to both new and 

pre-NSPS utility and industrial boilers. 

Specific features of this technology that will enhance its potential forcommercialization follow: (1) fiberglass construction can be used, eliminating the need 

for tubber-lined carbon steel or costly alloys; (2) no 

spare absorber is required because the system is at least 

98% reliable: (3) reheating of the flue gas is not necessary; (4) both SO, andpaniculates are removed from 

flue gas; (5) more than 99% of the calcium in the limestonereagent is used, (6) the gypsum by-product can be 

Southern Compony ServiceslCT-J2J Pro@wn Update 1992 7-17 
Demonstration of Selective 

Catalytic Reduction 

Technology for the Control 

of NOx Emissions from 

High-Sulfur-Coal-Fired Boilers 

Sponsor: 

Southern Company Services, Inc. 

AdditionalTeam Members: 

Electric Power Research Institute-cofunder 

OntarioHydm-cofunder 

Gulf Power Company-host utility . 

Location: 

Pensacola, Escambia County, FL (Gulf Power 

Company’s Plant Crist) 

Technology: 

Selective catalytic reduction (SCR) 

Plant Capacity/Production: 

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

equivalent SCR reactor plants) 

ProJect Funding: 

Total project cost $15,574,705 100% 

DOE 1,525,338 48 

Participants 8,049,367 52 

Project Objective: 

To evaluate the pafortnance of commercially available 

SCR catalysts when applied to operating conditions 

found in U.S. pulvetized coal-fired utility boilers using 

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

while achieving as much as 80% NOx removal. 

7.48 i%O~~Om Update 1992 

Technology/Project Description: 

The SCR technology consists of injecting ammonia into 

boiler flue gas and passing it through a catalyst bed 

where the NO, and ammonia react to form nitrogen and 

water vapor. 

In this demonstration project, the SCR facility consists of three 2.5-MWe SCR reactors, supplied by separate 5,000 std ft3/min flue gas slipstreams, and six 

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

allow the SCR process to be scaled up to commercial 

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

two Japanese) will provide nine catalysts with various 

shapes and chemical compositions for evaluation of 

process chemistry and economics of operation during 

the operation. 

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

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

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

coal. 

The demonstration plant, located at Gulf Power 

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

to flue gas from the burning of principally Illinois 

No. 5 coal with approximately 3% sulfur under various 

NOx and particulate levels. 

Southern Company ServiceslSCR 
Calendar Year 

1988 1989 1990 1991 ,992 1993 1994 1995 1996 1997 1998 

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

t 

Project completedhal repoti issued 1196 

operation initiated +“a’ Operation completed 3195’ 

Environmental monitoring plan completed 4195’ 

Construction completed 1193* 

WE selected project 9128188 

Caaperativeagreement 

awarded 6,14tW 

Precperation.4 tests initiated 1193’ 

Design completed 12192 

Ground breaking/construction staned 3192 ‘Projected date 

ProjectStatus/Accompllshments: 

Follow-up work on the environmental monitoring plan 

was completed in late-1992. Detailed engineering, 

construction, and start-up are under way. Detail design 

engineering is over 90% complete. Major subsystems 

(including the air preheaters. gas/air fans, venturis, 

disuibutedconnol/data acquisition system, electrical 

system, bypass heat exchangers, cyclones, flue gas/air 

electric heaters, gas analyzing system, and ammonia 

storage system) have been specified and ordered, and a 

majority of the equipment has been delivered to the site 

for installation. The SCR reactor design and fabrication 

have been completed, and the reactors have been delivered to the site. Consuuction began at the end of March 

1992. All of the major consuuction contracts have been 

awarded. Foundations, structural steel fabrication, and 

structural steel erection havebeen completed. PracticallyaRofthemajorprocessequipmenthasbeeninstalled. Construction of the control room and installation of ductwork, piping, insulation, elecuical cables 

and switchgears are nearly finished. Start-up is sched 

uled forJanuary 1993, with long-term operation expected to begin in April 1993. 

Catalyst suppliers have provided detailed inform& 

tion of laboratory reactor design and operations, and a 

common laboratory testing protocol has been established. The connact for the required testing and analytical services has been awarded. 

retrofit market for SCR technology is 154,560 MWe 

(642 boilers). In addition, SCR technology could be 

applicable to 34,700 MWe (70 boilers) of new fiim 

(i.e., announced, sited, and committed in terms of service date or under consnuction) and 144,500 MWe 

(290 boilers) of planned dry-bottom electric generating 

capacity in the United States. 

Commercial Appllcatlons: 

SCR technology can be applied to existing and new 

utility applications for removal of NO, from flue gas for 

virtually any size boiler. There are approximately 

1,Ml coal-fired utility boilers in active commercial 

service in the United States: these boilers represent a 

total generating capacity of 296,OOG MWe. Assuming 

that SCR technology is installed on dry-bottom boilers 

that are not equipped with low-NOx combustion technologies (i.e., low-NOx burners, over-fire air, and atmospheric ftuidized-bed combustion), the potential total 

Southern Company ServiceslSCR Program Update 1992 749 
180-MWe Demonstration of 

Advanced Tangentially Fired 

Combustion Techniques for 

the Reduction of NOx 

Emissions from Coal-Fired 

Boilers 

Sponsor: 

Southern Company Services, Inc. 

Additional Team Members: 

Gulf Power Company-cofunderand host utility 

Electric Power Research Institute-cofunder 

ABB Combustion Engineering, Inc.-cofunder and 

technology supplier 

Locatlon: 

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

Plant Smith, Unit No. 2) 

Technology: 

ABB Combustion Engineering’s low-NO, concenwic 

firing system (LNCFS) with advanced over-tire air 

(AOFA), clustered coal nozzles, and offset air 

Plant Capacity/Production: 

180 MWe 

Project Funding: 

Total project cost 

DOE 

Participants 

$9,024.765 100% 

4377,791 49 

4,646,974 51 

ProJect Objective: 

To demonstrate in a stepwise fashion the short- and long 

term NOx reduction capabilities of low-NOx concentric 

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

reference boiler under typical dynamic operating conditions, and evaluate the cost effectiveness of each 

low-NO,comhustion technique. 

7.50 Program Updare 1992 

Technology/Project Descrlptlon: 

tangentially fired boilers are being demonshated. The 

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

Three different lawNOx combustion technologies for 

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

windbox of the boiler. Compared to the baseline 

windbox configuration, LNCFS Level I is arranged by 

exchanging the highest coal nozzle with an air nozzle 

immediately below it. This configuration provides the 

NOs reducing advantages of an over-fire air system 

without pressure part modifications to the boiler. 

windbox. The inlet pressure to the SOFA system can be 

SOFA is taken off from the secondary air duct and 

increased above windbox pressure using dampers 

downstream of the takeoff in the secondary air duct. 

rooted to the comers of the furnace above the existing 

Operating at a higher pressure increases the quantity 

and injection velocity of the over-fire air into the 

furnace. A multicell venturi is used to measure the 

mount of air through the SOFA system. LNCFS 

Level III utilizes both CCOFA and SOFA. 

In addition to over-fire air. the LNCFS incorporates 

other NOx reducing techniques into the combustion 

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

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

surrounded by a fuel-lean zone containing combustion 

In LNCFS Level II, a separated over-fire air 

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

air system having backpressuring and flow measurement capabilities. The air supply ductwork for the 

Southern Company Services/Tangential/~ Fired Combustion 
Calendar Year 

,988 1489 1990 19% ,992 1993 1994 ,995 1996 ,997 1998 

3412341 234 1 2 3 4 ,234 1 2 3 4 1 2 3 4 1 234 1234 1 234 12 

Design and Constructton 

I 

I DOE selected 

projen 9128188 :1/l’ I’ Operation inliatsd 5,91 Lbrojed completed/final report issued VY33’ 

Operation completed 12192 I 

NEPAprocess 

yy!&@d VW I ’ Construction completed 5191 

Design completed 4191 

EnvirDnment.4 monttodng plan completed wR7190 

bround breakingiconsfruction started 11190 

Cooperative agreement awarded g/20/90 

*Projected date 

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

bevaried using adjustable bffset air nozzles. Separation 

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

The names of the technologies described above 

have been changed from those originally considered for 

this project to reflect the most recent knowledge. 

However, the basic concepts for the reduction of NO, 

emissions have remained constant. These technologies 

provide a stepwise reduction in NO” emissions, with 

LNCFS Level III expected to provide the greatest 

reduction. 

testing, completed in April 1992, showed that NO” 

emissions were reduced by a maximum of 48%: however, this decrease in NO,emissions was accompanied 

by an increase in flyash carbon content. Finally, 

LNCFS Level I was evaluated by closing the separated 

over-fire air dampers of the Level III system. Testing of 

the Level I system, completed in December 1992, 

showed a maximum NOx reduction of 38% at full load. 

Testing to investigate the effects of low-NOx combustion on the emissions of air toxics was also cornp&d. A report is expected in 1993. 

Commercial Appllcatlons: 

Project Status/Accomplishments: Commercial applications of this technology include a 

The LNCFS Level II tests were completed in September wide range of tangentially fired utility and industrial 

1991, resulting in a maximum NO, reduction of 40% at boilers throughout the United States and abroad. There 

full load. The LNCFS Level II was converted to are nearly 600 U.S. pulverized coal tangentially fired 

LNCFS Level III during a 2-week outage in November utility units. These units range in electric generating 

1991 by installing close-couple over-fire air nozzles in capacity from 25 MWe to 950 MWe. A wide range of 

the top of the main windbox. The LNCFS Level III coals, from low-volatile bituminous through lignite, are 

being tired in these units. LNCFS technologies can be 

used in retrofit as well as new boiler applications. 

Boiler operation with these in-furnace technologies does 

not require intensive retraining. 

Environmental benefits to be realized with these infurnace emission control technologies are primarily 

based upon reducing NOxemissions from fossil-fuelfired power plants. Potential exists for annual NOx 

emission reductions of lo%, depending on the unit load 

scenario and the tangentially fired NOx control selected. 

Southern ComoanvServiceslTaneenriollvFiredCombustion 

1 I Program Update 1992 7.51 
CCT-III 

Project Fact Sheets 
Commercial-Scale 

Demonstration of the Liquid- 

;F;islethanol (LPMEOHTM) 

Sponsor: 

Air Products and Chemicals, Inc. 

Additional Team Members: 

Acurex Environmental Corporation-fuel methanol 

testing and cofunder 

Texaco Syngas Inc.-host site and cofunder 

Dakota Gasification Company-technology consultant 

Location: 

Daggett, San Bernardino County, CA (Cool Water 

Gasification Facility; Texaco Syngas, Inc., negotiating 

purchase of site) 

Technology: 

Air Products and Chemicals’ liquid-phase methanol 

(LPMEOH”) process 

Plant Capacity/Production: 

150 tons/day of methanol 

Project Funding: 

Total project cost: $213,700,000 100% 

DOE 92,708,370 43 

Participants 120,991,630 57 

Pro]ect Objective: 

To demonstrate on a commercial scale the production of 

methanol from coal-derived synthesis gas using the 

LPMEOH” process; and to determine the suitability of 

methanol produced during this demonstration for use as 

alow-SO,, lowNOr alternative fuel in boiler, turbine, 

and transportation applications. 

LPMEOH is amadcma* ot*irPmdwts and acmicalr, Inc. 

7.54 Program Updote 1992 

Technology/Project Description: * Methanol productivity comparable to gas-phase sysThis project is demonstrating the LPMEOH” process terns-6,000 lb of methanol per 1 lb of catalyst 

to produce methanol from coal-derived synthesis gas on 

a commercial scale. The combined reactor and heat 

removal system is different from other commercial 

methanol processes. The liquid phase not only supports 

the catalyst but functions as an efficient means to 

remcwe the heat of reaction away from the catalyst 

surface. This feature permits the direct use of synthesis 

gas streams as feed to the react01 without the need for 

shiftconversion. 

. Raw methanol purity-97.5% 

* Feed gas flexibility-permits the use of synthesis gas 

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

DOE also will receive data on the use of a combined feedstock of coal and sewage sludge. A western 

bituminous loiv-sulfur coal is to be used. However, 

Texaco’s gasification process has been proven on a 

wide variety of coals and other feedstocks. The use of 

coal and sewage sludge represents a new solution to a 

The performance of the LPMEOHm’ process for 

the synthesis of methanol is characterized as follows: 

* Carbon monoxide conversion to methanol -13% per significant environmental problem. Also the project 

reactor per pass in a hydrogen-rich feed 

Air Products and Chemicals 
Calendar Year 

1990 1991 1992 1993 1994 1995 1995 1997 ,998 1999 

1 234 1234 1 234 1 234,234 1 234 1 234 1 234 1234 1234 

* III 

Ii 

t 

Operation inliamd 1~95 

Preoperational tests initiated 12194 

Construction complslsd 1,194 

Design Completed 6194 

Environmental monitoring plan complelsd 1194 

Operation cample,ed 7199 

Project completed/final report issued 12199’ 

Construction staded 10193’ 

NEPAprocess completed ,EA) 10193 

Cooperative agreement awarded 10116192 

‘Prajecteddafe 

I 

Commercial Appllcetions: 

no1 is an excellent peaking fuel. It contains no sulfur 

and has exceptionally low-NOz characteristics when 

burned. Fuel methanol can be produced from coal as a 

Methanol can besubstituted for conventional fuels in 

co-product in an IGCC facility. Among the cleanest 

stationary andmobile combustion applications. Methacoal technologies for generating electric power, IGCC 

can economically satisfy the most stringent environmew 

tal limits for SO, and NOz. About 99% of the sulfur can 

be removed in the manufacturing process and converted 

into salable elemental sulfur or sulfutic acid. Nitrogen 

compounds generated in the gasification process are 

easily removed by cleanup systems and may be recovered as salable ammonia for fertilizer manufacture. The 

solid waste from the gasifier is an inert, granular slag 

which can be used as an aggregate for road and building 

materials. 

later use to provide a back-up and peaking fuel. Unique 

electricity produced in 1GCC electric power plants. A 

power production load-following flexibility not normally associated with coal-based elecuic power 

production plants is available using IGCCI’LPMEOH~‘. 

flexibility-enhancing add-on feature, the LPMEOIF’ 

process produces methanol during off-peak periods for 

A variety of f&l products may be produced by the 

indirect liquefaction process. These may be used to 

supply fuels for a wide range of applications in the utility or industrial sector. The technology can be used in 

both new and ret&it applications. 

Typical commercial-scale LPMEOHn’ units are 

expected to range in size from 150 to 1,000 tons/day of 

methanol produced when associated with commercial 

IGCC power generation trains of 200-350 MWe. Air 

Products and Chemicals expects to market the 

LPMEO~’ technology through licensing, owning/ 

operating, and tolling arrangements. 

will demonstrate combined lGCC/LPMEOHT”’ operation to produce power and a liquid fuel in a load-following mode. 

Project Status/Accomplishments: 

DOE approved a site change to the Cool Water Gasiftcation Facility located at Daggett, CA. Texaco Syngas, 

Inc., is negotiating to purchase the facility and plans to 

recommission it in 1995. A portion of the synthesis gas 

stream (up to 50%) will be diverted to a nominal 

150-ton/day LPMEOH*“’ unit. 

A cooperative agreement was awarded in October 1992. The participants are now developing therelevant environmental information needed for the NEPA 

process, obtaining the required permits, and initiating 

project definition activities, including the development 

of an environmental monitoring plan that incorporates 

an air toxics monitoring program. 

The LPMEOHn’ process is an advanced methanol 

production technology which can lower the cost of 

Air Producls and Chemicals PrO8,TTm Update 1992 7-5s 
IO-MW Demonstration of Gas 

Suspension Absorption 

sponsor: 

AirPal, Inc. 

Additional Team Members: 

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

technology owner 

Tennessee Valley Authority-cofunder and site owner 

Location: 

West Paducah, McCracken County, KY (Tennessee 

Valley Authority’s National Center for Emissions 

Research) 

Technology: 

FLS miljo ais’ gas suspension absorption (GSA) system 

for flue gas desulfurization (FGD) 

Plant Capacity/Production: 

lo-MWe equivalent slipstream of flue gas from a 

150-MWeboiler 

Project Funding: 

Total project cost 

DOE 

Participants 

$7,717,189 100% 

2,315,259 30 

$401,930 70 

ProJect Objective: 

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

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

demonstsarionsystan. 

7.56 Program Update 1992 

Technology/ProjectDescrtption: 

The GSA system consists of a vertical reactor in which 

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

99% of the solids are recycled to the reactor via a cyclone while the exit gas stream passes through an electrostatic precipitator before being released to the atmosphere. The time slurry, prepared from hydrated lime, is 

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

variable-speed pump controlled by the measurement of 

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

dilution water added to the lime slurry is controlled by 

on-line measurements of the flue gas exit temperature. 

Solids collected from the cyclone and particulate control 

device are combined and disposed of in an existing site 

disposal area. 

GSA has tbe potential to remove in excess of 90% 

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

A west& Kentucky coal with a sulfur content of 

about j% is being used. 

This project is located at the National Cater for 

Emissions Research and is utilizing a lo-MWe slipstream of flue gas from a 150-MWe coal-fired boiler at 

the Tennessee Valley Authority’s Shawnee Fossil Plant 

in West Paducah, KY. 

AirPol 
Calendar Year 

1988 1989 ,990 1991 ,992 1993 ,994 ,995 1996 1997 1998 

3412341 2 3 4 1 2 3 4 ,234 1 234 1 ?.34 1 2 3 4 1 2 3 4 1234 12 

t 

r 7 

t 

+ 

Project completed/final repolt issued 2194’ 

DOE selected operation completed 10193 

projen 12/19,*9 Operation initiated 10192 

NEPAprocess completed (MTF) 9,2,,90 Environmental monitoring plan completed 1012192 

Preoperational tests inliated 9192 

CooperaWagreement awarded ,011 I,90 Constr”c,ion complsted 9192 

Groundbreakingiconstruclion started 5192 

Design completed 1’2191 

‘Projected date 

Project Status/Accomplishments: 

Engineering and design larks were completed on time 

according to the revised project schedule incorporating 

the l-year delay in obtaining the host site. The fabrication and construction effort was completed in August 

1992, ahead of schedule. The GSA and associated 

equipment was checked out and ready for operation by 

the end of September 1992. The environmental monitoring plan was completed October 2, 1992. 

AirPol began start-up of the GSA system in October 1992. The GSA will be operated and tested over 

12 months. Also, the cooperative agreement was 

amended to add air toxics and l-MWe fabric filter testing. Preliminary tests conducted to determine the GSA 

operating limits indicated that 99+% SO,removal can 

be achieved both with and without calcium chloride addition. The tests were conducted using 3% sulfur coal 

and 0.03% chloride. The project duration was extended 

5 months to allow time for final reporting. 

Commercial Appllcatlons: 

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

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

spray drying. Moreover, GSA is much simpler to build 

and operate than wet FGD and regenerable processes 

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

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

while dry injection processes and spray dryers generally 

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 low- and medium-sulfur coals. 

GSA is expected to find commercial acceptance because it is the only semi-dry process that offers SO, removal rates comparable to the more costly and complex 

wet FGD systems. In addition, GSA offers relatively 

low sorbent consumption rates and may perform better 

than dry systems; it is both less costly and more effective than spray dryers. 

The GSA should fulfili the need of the utility industry to meet the new SO, emission standard as set forth 

by the CAAA of 1990. Based on a comparison of GSA 

capital and operating costs with other FGD processes, 

the GSA is especially suited for utility plants ranging in 

size from 50 MWe to 250 MWe. The simplicity in GSA 

design and operation plus the modest space requirement 

make the GSA ideal for retrofitting to existing plants as 

well as for greenfield plants. One major advantage of 

the GSA, as compared to other semi-dry scrubbing processes, is that operation of the GSA will not result in additionaJ dust loading to the gas stream, thus eliminating 

the cost for upgrading the existing dust collector. The 

potential market for the GSA is estimated at $300 million within the next 20 years. 

AirPol 

Pro~rwn Updaze 1992 7.57 
Healy Clean Coal Project 

Sponsor: 

Alaska Industrial Development and Export Authority 

AdditionalTeam Members: 

Golden Valley Electric Association-host utility 

Stone and Webster Engineering Companyengineer 

TRW, Inc.-technology supplier 

Joy Technologies, Inc.-technology supplier 

Location: 

Healy, Denali Borough, AK (greenfiel$ site) 

Technology: 

TRW’s advanced entrained (slagging) combustor 

Joy Technologies’ spray dryer absorber with sorbent 

recycle 

Plant Capacity/Production: 

50 MWe (nominal electric output) 

Project Fundlng: 

Total project c”st $215,000,000 100% 

DOE 103,693,OOO 48 

Participants 111,307,000 52 

Project Objective: 

To demonstrate an innovative new power plant design 

featuring integration of an advanced combustor and heat 

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

7.58 Program Updatei 1992 

Technology/Project Description: 

The project is to be a nominal SO-MWe facility consisting of two pulverized-coal-fired combustar systems. 

Emissions of SO, and NO, will be controlled using 

TRW’s slagging combustion systems with staged fuel 

and air, a boiler that controls fuel- and thermal-related 

conditions, and limestone injection. Further SO, will be 

removed using Joy’s activated recycle spray dryer absorber @DA) system. Performance goals are NOx 

emissions of less than 0.2 lb/million Btu, particulates of 

0.015 lb/million Btu, and SO,removal greater than 

90%. The performance coal consists of 50% run-ofmine and 50% waste coal, with the waste coal having a 

lower heating value and significantly m”re ash. 

A coal-fired precombustor increases the air inlet 

temperature for optimum slagging performance. The 

TRW slagging combustors are bottom mounted on the 

boiler hopper. The main slagging combustor consists of 

a water-cooled cylinder which slopes toward a slag 

opening. The precombustor bums 25-40s of the total 

coal input. The remaining coal is injected axially into 

the combustor, rapidly entrained by the swirling 

precambustor gases and additional air flow, and burned 

under substoichiometric (fuel-rich) conditions for NOz 

conuol. The ash forms drops of molten slag which accumulate on the water-cooled walls and are driven by 

aerodynamic and gravitational forces through a slot into 

the slag recovery section. About 70-80s of the coal’s 

ash is removed as molten slag. The hot gas is then 

ducted t” the furnace where, to ensure complete combustion, additional air is supplied from the tertiary air 

windbox t” NO, ports and to final over-fire air ports located in the furnace. 

AIDEA 
CalendalYeal 

,988 ,989 ,990 1991 ,992 1993 1994 1995 ,995 1997 W98 

3 4 1 234 12341234 1 234 1 2341234 1 234 1234 1234 12 

12189 1196 6197 12/98 

Desion and Construclion I 

44 4 4 4 44 4 4 4 

I I I 

Cooperative 

S.gW%llC3”t 

awarded 411,191 

I besign slarl 

7190 

DOE selected project 

12119189 

I 

Design cwnpleted 5193’ 

Groundbrea~ngi 

CO”Str”dlOn Stalled 5143 

NEP*proces* completed 

(EIS) 5193 

/ 

Projectcampietedi 

final repan issued 

6197 

DOE cost-shared 

operationcompleted 

12196’ 2 yrs of operational 

Operation inliatsd 186 data provided a, “0 

additional cost 

Environmentalmonilonng ,288 

plan completed 12/W 

~on*lruction completed w95 

Preoperational &*I5 initiated 6/W ‘Projscfeddate 

calcined sorhent was completed al the Copenhagen 

facilily. A full-scale precombustor was constructed and 

test fired at TRW‘s Capistrano, CA, test facility to 

verify scaleup designs. The projecl is on schedule with 

approximately 60% of the design cornpled. 

Project Status/Accomplishments: thnl cyclone boilers require. The commercial availabilTest burns using Healy project fuel were completed at ity of cost-effective and reliable systems for SO,, NO>, 

TRW’s Cleveland facility. Joy/Niro testing of flash and particulate control is important to potential users 

planning new capacity, repowering, or retrofits to existing capacity in order to comply with CAAA of 1990 

requirements. 

Pulverired limestone (CaCO,) for SO, control is 

fed into the comhustor where most is flash calcined. 

The mixture of this lime (GO) and the ash nor slagged, 

called flash-calcined material (FCM), is removed in the 

fabric filter (baghouse) system. A small part of the 

FCM is disposed of, hut mos( is conveyed 10 a mixing 

lank where wafer js added 10 form a 45% FCM solids 

slurry. The slul~y leaving the mixing tank is pumped to 

a grinding mill where it is mechanically activated by 

abrasive grinding. Feed slurry is pumped from the feed 

tank to the SDA where it is atomized using Joy dry 

scrubbing rechnology. SO, in the flue gas reacts with 

the FCM slurry as water is simultaneously evaporated. 

SO, is further removed from the flue gas by reacting 

with the dry FCM on the haghouse filter hags. 

The project involves a greenfield site near 

Healy, AK. Power will go to Ihe Golden Valley Electric 

Association. The plant will provide 3 years of data, 

with 2 years of &(a being provided at uo cost to DOE. 

A draft EIS has been completed and public meetings were held in December 1992 to obtain commenrs. 

Commercial Applications: 

This technology has a wide range of applications. It is 

appropriate far any size utility or industrial boiler in 

new and reuofit uses. It can he used in coal-fired boilers as well as in oil- and gas-fired boilers because of its 

high ash removal capability. However, cyclone boilers 

may be the mosf amenable type 10 retrofit with the 

slagging comhustor because of the limited supply of 

high-B~u,low-sulfur,low-ash-fusion-temperaturecoal 

AIDEA Program Update 1992 7.59 
Full-Scale Demonstration of 

Low-NO CellTM Burner 

Retrofit’ 

Sponsor: 

The Babcock & Wilcox Company 

AdditIonalTeam Members: 

The Dayton Power and Light Company-cofunder and 

host utility 

Electric Power Research Institute-cofunder 

Ohio Coal Development Office-cofunder 

Tennessee Valley Authority-cofunder 

New England Power Company-cofutider 

Duke Power Company-cofunder 

Allegheny Power System- cofunder 

Centerior Energy Company-cofunder 

Location: 

Aberdeen, Adams County, OH (Dayton Power and 

Light Company’s J.M. Stuar! Plant, Unit No.4) 

Technology: 

The Babcock &Wilcox Company’s Low-NOx Celln’ 

burner (LNCB”‘) system 

Plant Capacity/Production: 

605 MWe 

Project Funding: 

Total project cost 

DOE 

Participants 

$11.233.392 100% 

5,442,800 48 

5.790.592 52 

Project Objective: 

To demonstrate through the first commercial-scale full 

burner retrofit the cost-effective reduction of NO* from 

a large base-load coal-fired utility boiler with Low-Nor 

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

Low-NO, Cc” bulm and LNCB arc uadcmarkr ofnx Ba!xock & 

Wilcox Company. 

7.60 Program Update 1992 

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

Technology/ProjectDescrtption: 

Low-NOx CeF burner technology replaces the upper 

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

same fuel input capability as two standard coal nozzles. 

The Low-NOx Cellrn’ burner operates on the principle of 

staged combustion to reduce NO= emissions. Approximately 70% of the total air (primary, secondary, and 

excess air) is supplied through or around the coal-feed 

nozzle. The remainder of the air is directed tn the upper 

port of each cell to complete the combustion process. 

The fuel-bound nitrogen compounds are converted to 

nitrogen gas, and the reduced flame temperature 

minimizes the formation of thermal NOx. 

The net effect of this technology is a 50% reduction 

in NOx formation with minimal or no boiler pressure 

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

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

scrubbers. 

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

Light Company and jointly owned with the Cincinnati 

Gas and Electric Company and the Columbus Southern 

Company. The boiler unit is a B&W-designed, supercritical, once-through boiler equipped with an electrostatic precipitator. This unit contains 24 two-nozzle cell 

burners arranged in an opposed-firing configuration. 

t?& W/Low--NO, 
Calendar Year 

1988 1989 ,990 199, 1992 1993 1994 ,995 1996 1997 ,998 

341234 1 2 3 4 1 234 1 234 1234 1234 1 234 1234 ,234 12 

AA 

4 1 

t $ t--k- Pqect completed/final report issued s/93’ 

Operalion initiated 1241 Operation completed 3193 

Preoperational tests initiated 11191 

Construction completed 1 I/91 

DOE selected project 12119189 Groundbreakingiconstrudion starled 91% 

Design stalled ~4190 Environmental monitoring plan completed iSV31 

Cooperative agreemenl awarded IO,, ,190 

NEPAprocess completed (MTF) 8110190 Design comp,e,ed ,ono 

‘Projected date 

Twelve burners (arranged in two rows of six burners 

each) are mounted on each of two oppoiing walls of the 

boiler. All 24 standard cell burners ax being removed, 

and 24 new burners are being installed. 

economicaJ burner configuration for minimizing the CO 

and H,S concentrations in the lower furnace. The best 

computer generated solution was inverting the airport 

and burner components of every other LNCB”’ unit on 

the lower row. 

Project Status/Accomplishments: 

Pre-retrofit baseline testing completed in November 

1990 showed NOx emissions of 1.17 lb/million Btu. 

Preliminary testing completed in December 1991 

showed that the best NOx emissions reduction was only 

35%. Also, high concentrations of CO and H,S in combustion gases in the lower furnace, below the lowest 

row of burners, were unacceptable due to potential for 

corrosion and other hazards. 

the burner zone, compared to drum boilers. Fieldverified analysis is needed to confirm or refute the 

laboratory analysis and to identify potential operations 

and maintenance costs associated with LNCBTD’ 

technology. 

These changes were installed in May 1992, and 

testing of the LNCBn’ system was resumed. The 

LNCBT”’ retrofitted boiler is now achieving 55% NOI 

reduction (0.526 lb/million Btu). The CO and H,S 

concentrations in the lower furnace ate below the 

baseline levels. in addition, carbon in the fly ash for the 

LNCBn’ system is 3-4s (loss oo ignition) and the CO 

concentration in the flue gas is 4&50 ppm. 

Commercial Applications: 

Currently there are 34 operating cell-burner-fired boilers 

for which the LNCBn’ system is applicable. Of these, 

29 are opposed-wall-fired with two TOWS of two-nozzle 

cells. The average size is 766 MWe. 

Pilot-scale testing andsimulated boiler testing 

indicated that nat~ower, angled coal impellers would 

improve NO, reduction. Also, numerical simulation of 

the combustion gas flows and composition profiles in 

the furnace section of the boiler for several alternative 

burner configurations produced an effective and 

The laboratory corrosion and HIS-probing work 

shows that there is risk of increased tube wastage on 

bare furnace wall tubes because of the deep staging 

technique used by the LNCBrn’. The risk is greater for 

once-through (universal pressure) boilers due to their 

inherently higher operating tube-metal temperatures in 

The low cost and short outage time for retrofit 

make the LNCBm’ design attractive. Typically, the 

retrofit capital-cost will be $&lZkW in 1990 dollars, 

based upon DOE’s 500-MWe reference unit. The outage time can be as short as 5 weeks because of the 

“plug-in”design. The LNCBI”‘system can be installed 

at about half the cost and outage time for other commercial low-NO” burner installations. 

Ll&WILow-NO= Program Update I992 7.61 
Confined Zone Dispersion 

Flue Gas Desulfurization 

Demonstration 

Sponsor: 

Bechtel Corporation 

AdditIonalTeam Members: 

PennsylvaniaElectric Company-cofunderand host 

utility 

PennsylvaniaEnergy Development Authoritycofunder 

New York State Electric & Gar Corporation-cofunder 

Rockwell Lime Company-cofunder , 

Location: 

Seward, Indiana County, PA (Pennsylvania Electric 

Company’s Seward Station, Unit No. 15) 

Technology: 

Bechtel Corporation’s in-duct, confined zone dispersion 

flue gas desulfurization (CZD/FGD) process 

Plant Capacity/Production: 

73.5 MWe 

Project Funding: 

Total project cost $10,411,600 100% 

DOE 5,205,800 50 

Participants 5,205,800 50 

Project Objective: 

To demonstrate SO, removal capabilities of in-duct 

CZD/FGD technology; specifically, to define the 

optimum process operating parameters and to deter.nine 

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

Technology/Project Description: 

tween the boiler air heater and the electrostatic precipitator (ESP). The lime slurry is injected into the center 

In Bechtel’s CZD/FGD process, a finely atomized slul~y 

of the duct by spray nozzles designed to produce a cone 

of fine spray. As the spray moves downstream and 

of reactive lime is sprayed into the flue gas stream beexpands, the gas within the cone cools and the SO, is 

rapidly absorbed in the liquid droplets. The droplets 

mix with the hot flue gas, and the water evaporates 

rapidly. Fast drying precludes wet particle buildup in 

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

The CZDIFGD process is expected to xmove up to 

50% of the SO, emissions from coal-fired boilers. If 

successfully demonstrated, this technology would be an 

This project includes injection of different types of 

alternative to conventional FGD processes,requiring 

sorbents (dolomitic and calcitic limes) with several 

atomizer designs using low- and high-sulfur coals to 

verify the effects on SO, removal and the capability of 

less physical space and lower capital, operating, and 

the ESP to control particulates. The demonstration is 

maintenance costs. 

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, longer duct between the first and second 

ESP. Pennsylvaniabituminous coal (approximately 

1.2-2.5% sulfur) is being used in the project. After the 

variable test program is complete, continuous, fully 

7-62 Program Update 1992 Bechtel Corporation 
wsndar Year 

,988 1989 ,990 ,991 1992 1993 1994 1995 1996 1997 1998 

341234 1234 123412341234, 234 1234 1 234 1234 12 

I Design and Construction 

t ttt t-, Prqect completed/final report issued 6193 

Design stall 6190 

I 

Preoperatianaltests intiiated 7191 I 

Operation ink&d 71% 

Construction wmpleted 61% 

Environmental monitoring plan 6/12191 

Ground breakingiconstruaion started 3/91 

Operation completed 3193’ 

Cooperative agreement awarded 10113190 

Design completed 10190 

EPA process completed (MTF) 9125190 ‘Projecteddale 

automated and integrated (with the regular power plant) 

operation is planned for 6 months. 

ProjectStatus/Accompllshments: 

Bechtel began its M-month, two-part test program for 

the CZD process in July 1991. The first 12 months of 

the test program consisted primarily of parametric testing. The second part includes a 6.month continuous 

operation test period with the system being operated 

under fully automatic control by the host utility boiler 

operators. Initially, the new atomizing nozzles were 

thoroughly tested both outside and inside the duct. The 

lime slul~y injection parametric test program, which 

began in October 1991, was completed in August 1992, 

and the goal of 50% SO, reduction was achieved. Continuous operations testing is under way; it involves 

three-shift. fully automatic operations by operators of 

the host utility company. Bechtel intends to c.onduct 

additional performance tests during thiS period. 

Commercial Applications: 

CZD can be used for retrofit of existing and installation 

in new utility boiler flue gas facilities to remove SO, 

derived from a wide variety of sulfur-containing coals. 

A CZD system can be added to a utility boiler with 

a capital investment of about $25-5OkW of installed 

capacity, 01 approximately one-fourth the cost of 

building aconventional wet scrubber. In addition to 

low capital cost, other advantages include small space 

requirements, ease of retrofit, low energy requirements, 

fully automated operation, and production of only 

nontoxic, disposable waste. The CZD technology is 

particularly well suited for retrofitting existing boilers, 

independent of type. age, or size. The CZD installation 

does nor require major power station alterations and can 

be easily and economically integrated into existing 

povferplants. 

Bechrel Corporarim Program Update 1992 7-63 
Blast Furnace GranulatedCoal Injection System 

Demonstration Project 

Sponsor: 

Bethlehem Steel Corporation 

Additional Team Members: 

British Steel Consultants Overseas Services, Inc. 

(marketing arm of British Steel Corporation)- 

technology owner 

Simon-Macawber, Ltd.-equipment supplier 

Fluor Daniel, Inc.-architect and engineer 

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

technology licensee) 

Location: 

Bums Harbor, Porter County, LN (Bethlehem Steel’s 

Burns Harbor Plant, Blast Furnace Units C and D) 

Technology: 

British Steel’s blast furnace granulated-coal injection 

(BFGCI) process 

Plant CapacltylProductlon: 

7,000 net tons/day of hot metal (each blast furnace) 

Project Fundlng: 

Total project cost $143,800,000 100% 

DOE 31,259,530 22 

Participants 112,540,470 78 

Project ObJectWe: 

To demonstrate that existing iron-making blast furnaces 

can be retrofitted with blast furnace granulated-coal 

injection technology; and to demonstrate sustained 

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

nature of these parameters. 

Technology/Project Description: 

along with heated air is blown into the barrel-shaped 

section in the lower part of the blast furnace through 

passages called tuyeres, which creates swept zones in 

In the BFGCI process, both granulated and pulvetized 

the furnace called raceways. The size of a raceway is 

coal is injected into the blast furnace in place of natural 

important and is dependent upon many factors including 

temperature. Lowering of a raceway temperature, which 

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

can occur with gas injection, reduces blast furnace productionrates. Coal, with alower hydrogen content than 

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

raceway temperatures. In addition to displacing injected 

natural gas. the coal injected through the tuyeres displaces coke, the primary blast furnace fuel and reductant 

technology has significant potential to reduce emissions 

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

and enhance blast furnace production. 

basis. Because coke production results in significant 

emissions of NOx, SO,, and air toxics and coal could 

replace up to 40% of the coke requirement, BFGCI 

Emissions generated by the blast furnace itself 

remain virtually unchanged by the injected coal; the gas 

exiting the blast furnace is clean, containing no measurable SO, or NO,. Sulfur from the coal is removed by 

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

salable by-product. In addition to the net emissions 

reduction realized by coke displacement, blast furnace 

production is increased by maintaining high raceway 

temperatures. 

7.64 Program Update 1992 BethlehemSteeUBlosr Furnace 
Calendar Year 

1988 ,989 1990 ,991 1992 1993 ,994 1995 1996 ,997 1998 

3 4 1 2341234 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 ,234 1 234 1 234 i* 

I bperation intiated 3195’ 

DOE seleded preoperational \W.s initiated 3195’ 

projed 12119189 Co”auc,ion compfelsd 3/w 

Environmental monitoring plan completed 11194’ 

Design completed 12193 

ConE.tNctlon started 3193 Project completed/final repon 

NEPA process completed (EA) ‘h’93’ issued 11197* 

Cooperative agreement awarded 11126180 

Operation completed 11/97’ 

‘Projected date 

Two high-capacity blast furnaces, Units C and D at The project schedule has been extended due to a 

Bethlehem Steel Corporation’s Bums Harbor Plant. are longer-than-expected period to complete formal negobeing retrofitted with BFGCI technology. Each unit has tiation of a technology license acceptable to both doa production capacity of 7,CiiO net tons/day of hot metal mestic and foreign organizations. The project schedule 

The two units will use about 2,800 tons/day of coal has also been impacted by the recent ongoing recession 

during full operation. and its particularly harsh impact on the steel induwy. 

Project StatuslAccompllshments: 

Process engineering and preliminary design are in 

progress. Technology license agreements have been 

signed between Bethlehem Steel Corporation; British 

Steel Consultants Overseas Services, Inc.: ATSI, Inc.: 

and Simon-Macawber, Ltd. Due to poor economics in 

the steel industry and in order to contain capital requirements, the sponsor has been actively exploring tbirdparty owner-financing for certain nonproprietary equip 

ment and plant sections. Bethlehem Steel has made 

significant progress in design efforts and has made large 

capital outlays to complete the prerequisite blast-furnace 

modifications needed for the retrofits. 

An environmentaJ assessment is under way. 

Commercial Appllcatlons: 

BFGCI technology can be applied to essentially all U.S. 

blast furnaces. The technology should be applicable to 

any rank coal commercially available in the United 

States. The environmental impacts of commercial 

application are primarily indirect and consist of a 

signiticadt reduction of emissions resulting from 

diminishedcokemakingrequirements. 

Bethlehem SteeUBlart Furnace Program Updale 1992 7.65 
PCFB Demonstration Project 

Sponsor: 

DMEC-1 Limited Partnership (a partnership between 

Dairyland Power Cooperative and Midwest Power 

Systems. Inc. [previously Iowa Power, Inc.]) 

Additional Team Members: 

PyropowerCorporation-technology supplier 

Black and Vearcb--architect and engineer 

Location: 

Pleasant Hill, Polk County> IA (Des Moines Energy 

Center) 

Technology: 

Pyropower Corporation’s PYROFLOW pressurized 

circulating fluidized-bed combustion (PCFB) 

combined-cyclesystem 

Plant Capacity/Production: 

80 MWe 

Project Funding: 

Total project cost $202,959,000 100% 

DOE 93,x3,000 46 

Participants 109,706,OOO 54 

Project Objective: 

Ta demonswate PCFB at sufficient scale to evaluate 

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

the technology; to assess operating performance of 

unique features that include an integral ceramic hot-gas 

filter and slightly modified, commercially available gas 

turbine. 

7-66 r%&V~?H Update 1992 

CON 

v/ATE 

w 

I’ 

___, - -._ 

HIGH-PREWRE s 

I 

I 

Technology/Project Description: 

In the PCFB process, coal is combusted at about 

1,600 “F and 12 atm in a circulating fluidized bed contained within a pressure vessel. Coal is pumped into the 

PCFB via a water slurry while dolomite or limestone is 

added to the combustion process to absorb sulfur compounds. Particulates from the hot, pressurized combustion gases ale removed by a ceramic filter, and the clean 

gases are then expanded through a gas turbine. The 

solid waste (bed and fly ash) from the process is dry, 

easily disposed of, and potentially usable. Steam generated within the PCFB combustor and the heat recovery 

system downstream of the gas turbine is used to generate power in an existing steam turbine. 

would be the first commercial application of hot gas 

cleanup and the first use of a nonruggedized gas turbine 

in apressurized tluidized-bed application. 

A boiler at the Des Moines Energy Center is being 

repowered by a single PCFB combustor. The facility, 

owned by Midwest Power Company, is located 

southeast of Des Moines, IA. Midwest Power plans to 

continue PCFB operations commercially after the 

demonsuation. 

Repowering the plant with a PCFB will improve 

the plant’s heat rate to 10,400 Btu/kWh (an efficiency of 

32.8% based on HHV) which is a 15% improvement 

over the previous plant. SO, emissions will he limited 

to 0.71 lb/million Btu (90% reduction) and NOx 

emissions will be less than 0.03 lb/million Btu (70% 

reduction). 

The project would be the world’s first large-scale 

demonstration of PCFB technology. The prdject also 

DMEC-I Limired Parrnership 
Calendar Yeal 

,990 ,991 ,992 1993 1994 1995 1996 ,997 1998 1999 2000 

3 4 1 234 1234 1 234 1 234 1234 1 234 1 2 3 4 1 234 1 234 34 

Design and ConstructIon 

i 

DOE selected 1 7 P 

pew&n inhiated 6196 +-Project ixu*d completedifinat 5198 report 

Conslruclion completed 5196 Operatian completed 5198’ 

project 12119m Preoperationalt*st5 initiated 2196’ 

Graundbreakingic~nsfrudion Started 7194 

caoperativeagreement 

awarded WIIQI Design completed 6194 

Environmental monitoring plan completed 5194’ 

NEPAprocesscampleted (EIS) 1,193 ‘Projecteddate 

Commercial Applications: 

By demonstrating plant reliability and performance, this 

project serves as a bridge for scaling up to a larger plant 

and a stepping stone toward moving PCFB to commercial readiness. The combined-cycle PCFB system permits the combustion of a wide range of coals, including 

high-sulfur coals, and would compete with the bubbling-bed PFBC system. Like the bubbling-bed system, 

PCFB can be used to repower or replace conventional 

power plants. PCFB technology appears to be best 

DMEC-1 LimitedPartnership 

Project Status/Accomplishments: 

Preliminary design efforts to fin&x the technical 

scope, cost baseline, and business aspects of the project 

continued during 1992. In August 1992, design efforts 

were extended for 10 months to provide additional time 

to factor in results from ongoing hot-gas filtration tests. 

Environmental information for use in the NEPA 

process has been developed and the public scoping 

meeting was held. Drafting of the environmental impact 

statement has begun. 

suited for utility and industrial applications of 50 MWe 

or larger. Because of modular construction capability, 

PCFB generating plants permit utilities to add economical increments of capacity to match load growth and/or 

to repower plants using existing coal- and waste-handling equipment, and steam turbines. Another advantage for repowering applications is the compactness of 

the process due to pressurized operation, which reduces 

space requirements per unit of energy generated. 

The commercial version of PCFB technology will 

include the integration of a topping combustor to fully 

utilize commercially available gas turbines. The projected net heat rate for this system is 7,964 BtuikWh 

(based on HHV) which equates to 42.8% efficiency. 

Environmental attributes include in-situ sulfur 

removal of 95% NOremissions less than 0.3 lb/million 

Btu, and particulate matter discharge less than 0.03 lb/ 

million Btu. Solid waste will increase slightly as compared to conventional systems, but the dry material is 

disposable or polenrially usable. 

Program Update 1992 7.67 
ENCOAL Mild Coal 

Gasification Project 

Sponsor: 

ENCOAL Corporation (a subsiditoy of SMC Mining 

Cww9 

Additional Team Members: 

SMC Mining Company-cofunder 

TEK-KOL (partnership between SMC Mining Company 

and SGI International)-technology owner, supplier, 

and licenser 

SO1 lmemational-technology developer 

Triton Coal Company (subsidiary of SMC Mining 

Company)-host facility and coal supplier 

The M.W. Kellogg Company-engineer and 

Location: 

Near Gillette, Campbell County, WY (Triton Coal 

Company’s Buckskin Mine) 

Technology: 

SGI International’s liquids from coal process 

Plant Capacity/Production: 

1,wO tons/day of subbituminous coal feed 

Project Funding: 

Total project cost $72,564,000 lCG% 

DOE 36,282,ooO 50 

Participants 36,282,OOO 50 

Project ObJectlve: 

To demonsuate the integrated operation of a number of 

novel processing steps to produce two higher value fuel 

forms from mild gasification of lowsulfur subbituminow coal; and to provide sufficient products for potential end users to conduct bum testis. 

7-68 Program Update 1992 

Technology/Project Description: 

The ENCOAL mild coal gasification process involves 

heating coal under carefully controlled conditions. Coal 

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

gas stream to reduce the coal’s moisture content. The 

solid bulk temperature is controlled so that no significant amounts of methane, CO, or CO, are released from 

the coal. The solids from the dryer are conveyed to the 

pyrolyzer where the rate of heating of tbe solids and 

residence time are controlled to achieve desired properties of the fuel products. During processing in the pyrelyzer, all remaining f&e water is removed, and a chemical reaction occurs that results in the release of volatile 

gaseous material. Solids exiting thepyolyzer are 

quenched. cooled, and transferred to a surge bin. 

The gas produced in the pyrolyzer is sent through a 

cyclone for removal of the paticulates and then cooled 

to condense the liquid-fuel products. Most of the gas 

from the condensation unit is recycled to the pyrolyzer. 

The rest of the gas is burned in combustors to provide 

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

controlled by staged air injection. 

The offgas from the dryer is treated in a wet venturi 

scrubber to remove pticulates 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 ENCOAL project is located within Campbell 

County, WY, at Triton Coal Company’s Buckskin 

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

of the present coal-handling facilities at the mine. 

ENCOAL Comorarion 
Calendar Year 

,988 1989 1990 ,991 1992 1993 ,994 ,995 ,996 ,997 ,998 

3412341 234 1 234 1 234 1 2 3 4 1234 1 234 1234 1 234 12 

I Preaward 

7192 Q/94 

I’ DOE selected pro@3 12119189 

1 IOperation i”lhW T/92 

Constructlo” completed 6192 Operation completed 9194‘ 

nvironmental monlodng plan completed 5i29B92 

Preoperational tests inniated 4.Q 

Design mmpleted 7R1 

Ground breaking/construction staned 10i26/90 

CooperatNe aqreemmt awarded 9/t T/90 

EPA pmcess completed (EA) 8,1/W 

‘Projecteddafe 

Project StatuslAccompllshments: 

The project is now in operation. Construction and plant 

start-up were completed in mid-1992,2 months ahead of 

schedule. 

The plant has madeseveral plannedruns, with 

equipment or process changes after each, in an attempt 

to optimize plant operability and the quality of each 

product. The requirements of all enviro&xtal permits 

have been met in the plant operations conducted to date. 

Wisconsin Power & Light has agreed to purchase about 

30,000 tom of the solid, process-derived fuel (PDF). 

TEXPAR Energy Inc. of Waukesha, WI, will purchase 

up to 135,000 barrelsiyr of the liquid product. The PDF 

has been tested on-site and has been successfully burned 

in alarge-scale laboratory combustion furnace. Analysis has shown that the heating value of the feed coal is 

upgraded from 8,4OOBtu1lb to about 12,000 Btujlb. The 

particle size of the PDF is smaller than the run-of-mine 

coal but is not expected to be a problem. The stability 

of the solid product requires more testing because it has 

ENCOAL Corporation 

not been comparable to run-of-mine coal in tests performed to date. Three railroad tank can of liquid product have been shipped to TEXPAR. 

In November 1992, Zeigler Coal Holding Company 

purchased the primary assets and operations of the Shell 

Mining Company (renamed SMC Mining Company 

after acquisition). ENCOAL remains a subsidiary of 

SMC Mining Company, and no material impact on the 

project or the future commercialization of the technology 1s expected as a result of this business transaction. 

Commercial Appllcatlons: 

The liquid products from mild coal gasification can be 

used in existing markets in place of No. 6 fuel oil. The 

solid product can be used in most industrial or utility 

boilers. The feedstock for mild gasification facilities is 

being limited to high-moisture, low-heating-value coals. 

The potential benefits of this mild gasification 

technology in its commercial configuration are 

attributable to the increased heating value (about 

12,000 Btuilb) and lower sulfur content (per unit of fuel 

value) of the new solid-fuel product compared to the 

low-rank coal feedsrock, and the production of lowsulfur liquid products requiring no further treatment for 

the fuel oil market. The product fuels are expected to be 

used economically in commercial boilers and furnaces 

and to reduce sig+ficantly SO, emissions at industrial 

and utility facilities currently burning high-sulfur 

bituminous coals or fuel oils. 

Pro&wn Update 1992 7-69 
Evaluation of Gas Reburning 

and Low-NO Burners on a 

Wall-Fired Bhler 

Sponsor: 

Energy and Environmental Research Corporation 

Additional Team Members: 

Public Service Company of Colorad+cofunder and 

host utility 

Gas Research Institute-cofunder 

Colorado Interstate Gas Company-cofunder 

Electric Power Research Institute-cofunder 

Location: 

Denver, Adams County, CO (Public Service Company 

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

Technology: 

Energy and Environmental Research Corporation’s gas 

rebuming and low-NO2 burner (GR-LNB) system 

Plant Capacity/Production: 

172 MWe 

Project Funding: 

Total project cost $16,194,172 100% 

DOE 8,097,085 50 

Participants 8,097,087 50 

Project Objective: 

To attain up to a 70% decrease in the emissions of NO, 

from an existing wall-fired utility boiler firing 

low-sulfur coal using both gas rebuming and lawNOx 

burners. 

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. NOx drifting upward from the lower region of 

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

harmless molecular niuogen. LowNOr burnerspositioned in the coal combustion zone retard the production 

of NO, by staging the burning process so that the coalair mixture can be carefully controlled at each stage. 

The synergistic effect of adding a rebuming stage to 

wall-fxed boilers equipped with low-NOx burners is 

projected to lower NO” emissions by 70% or more. 

burners on a 172-MWe wall-fired utility boiler. A 

variety of westem bituminous coals containing 

0.3%0.66% sulfur are being used in this demonsuatlon. 

The project site is Public Service Company of 

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

CO. This project combines gas reburning and low-NO” 

7.70 Program Update 1992 EERIWoll-FiredBoiler 
Calendar Year 

,988 1989 1990 1991 1992 1993 1994 ,995 ,996 1997 1998 

3 4 1 234 1234 1234 1 234 1234 1234 1234 12341234 12 

12/89 10190 Q/92 6/94 

Design and Conslruclion 

I I 

T 

t ?’ Project completedilinal rep04 issued 6194 

Operation Mated 9192 Operation completed 3/94 

Preoperatianal tests Mated 692 

Conswclion completed 6192 

Design completed 8191 

Ground breaking/construction Staned 6191 

Cooperative agreement awarded 10113190 

NEPAprocess comPleted [MTF) 916190 

Environmental monitoring plan completed 7126190 

DOE selected project 12119189 ‘Projecteddate 

ProjectStatus/Accompllshments: COmmerCial AppllCatlDnS: 

Permitting activities have been completed. Construc- Gas rebuming in combination with low-NOx burners is 

tion started in mid-1991 and was completed in June applicable tu wall-fired utility and industrial boilers. 

1992, about 3 months ahead of schedule. Construction The technology can be used in new and pre-NSPS wall- 

. . ~. ” I. ., lncluoea me l”staIra”o” o* new nLl*m penetrmons, new 

burners, refractory, and insulation. All of the equipment 

that was installed during construction was checked out 

and found to be functional. Start of operation was delayed during the period July-August 1992 when the 

Public Service Company of Colorado rebuilt the four 

coal-pulverizing mills to enhance the flow of primary air 

to the boiler. Optimization of the gas-reburning unit 

started in late-September and was followed by a brief 

outage in November for minor modifications to the 

tertiary air system. Parameuic studies started in October and were completed in December 1992. Preliminary 

analysis indicated NOz reductions of up to 70% at 

150 MWe. Long-term I-year load-following operations 

will start in February 1993. Long-ten operations will 

be completed in 1994. 

rtrea ootri?rs. 

Specific features of this technology that increase its 

potential for commercialization are as follaws: 

. Can be retrofitted tu existing units 

* Reduces NOx emissions by 70% or more 

. Suitable for use with a wide range of coals 

* Has the potential to improve boiler operability 

+ Has the potential to reduce the cust of electricity 

. Consists of commercially available components 

. Requires minimal space 

Current estimates indicate that about 35 existing 

wall-fired utility installations, plus industrial boilers, 

could make immediate use of this technology. The 

technology would apply to retrofit, repowering OI to 

new, greenfield installations. There is no known limit to 

the size or scope of the application of this technology 

combination. Presently, thelargest existing utility 

boiler is estimated at about 1,300 MWe. The GR-LNB 

combination could be applied directly to this size boiler 

because the equipment is an integral part of the unit. 

For this reason, GR-LNB is expected to be less capital 

intensive, or less costly, than a scrubber, selective catalytic reduction, or other technology approaches. GRLNB functions equally well with any kind of coal. NOx 

emissions are reduced with internally staged low-NO, 

burners, followed by gas rebuming. As a side benefit, 

SO,is decreased in direct proportion to the amuunt of 

natural gas that is substituted for coal. 

EERlWall-FiredBoiler Program Update 1992 7.71 
LIFAC Sorbent Injection 

Desulfurization 

Demonstration Project 

Sponsor: 

LIFAC-North America (a joint venture partnership 

between Tampella Power Corporation and ICF Kaiser 

Engineers, fnc.) 

AdditionalTeam Members: 

ICF Kaiser Engineers, Inc.-cofunder and project 

manager 

TampellaPowerCorporation--cofunder 

Tampella Ltd.- technology owner 

Richmond Power andlight-cofunder and host utility 

Electric Power Research Institute-cofunder 

Black Beauty Coal Company- cofunder 

State of Indiana- cofunder 

Location: 

Richmond, Wayne County, !.N (Richmond Power & 

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

Technology: 

LIFAC’s sorbent injection process with sulfur capture in 

a unique, patented vertical activation reactor 

Plant Capacity/Production: 

60 MWe 

ProJect Fundlng: 

Total project cost 

DOE 

Participants 

$11,393,772 100% 

10,636,863 50 

10,756,909 50 

Project Objective: 

To demonstrate that electric power plants-especially 

those with space limitations-burning high-sulfur 

coats, can be retrofitted successfully with the LIFAC 

limestone injection process to remove 75435% of the 

7-72 Program Update, I992 

SO, from flue gas and produce a dry solid waste product reactor for increased efficiency. The waste is dry, 

for disposal in a landfill. making it easier to handle than the wet scrubber sludge 

Technology/Project Descrlptlon: 

Pulverfzed limestone is pneumatically blown into the 

upper pan of the boiler near the superheater where it 

absorbs some of the SOi 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 precipitator. The sorbent material from the reactor and elecaostatic precipitator will be recirculated back through the 

produced by conventional wet limestone scrubber 

systems. 

The technology enables power plants with space 

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

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

The process is being demonstrated at the 

Whitewater Valley Station, 60-MWe Unit No. 2. This 

coal-fired unit is owned and operated by Richmond 

Power&Light and is located in Richmond, IN. 

LIFAC 
Calendar Year 

1988 198s 1990 1591 1992 ,993 1994 1995 ,996 ,997 1998 

341234 1 234 1 234 1 234 1 234 1 234 1 2 3 4 ,234 1 234 12 

A 

AA II 

t+ 

t 

Operation iniiiated 9192 t 

Preoperationat tests intiiated 7192 t 

Project compteted4inat report issued 8194 

Environmental monitoring plan operation completed 33.4’ 

completed 6/12192 

Ganstwtion completed 6192 

Original design completed 7/91 

Groundbreakinglconstruction sfaned 5&3&l 

Cooperative agreemen, awarded 11120190 

NEPA process completed (MTF) 10Ng0 

DOE selected projed 12/,g,%g ‘Projededdate 

ProjectStatus/Accompllshments: 

All plant tie-ins were successfully completed during the 

scheduledMarch 1991 outage. To improve LIFAC 

efficiency from 75% to 85%. the process was modified 

to recirculate sorbent material, which contains about 

25% onreacted limestone. Formal ground breaking for 

the new equipment occurred on May 29,199 1. Ckstroction was completed in June 1992, and shakedown 

operations began in July. Baseline testing was comspace limitations. The LIFAC process offers the following advantages: 

* It is less expensive to install than conventional wet 

floe gas desulforization processes. 

* It uses dry limestone instead of more costly lime. 

- It is relatively simple to operate. 

* It produces a dry, readily disposable waste. 

plants (500 MWe or less) and some industrial sites. 

LIFAC sales are projected to total 18,000 MWe of 

capacity over the next decade. 

pleted by August 1992. Pammeuic testing. first at- . It can handle all types of coal 

tempted-in September 1992, was delayed 3 months to 

resolve mechanical and electrical problems with the 

LIFAC system. 

The environmental monitoring plan was completed 

in June 1992. 

Commercial Applications: 

This process is suitable for application to all coal-tired 

utility or industrial boilers, especially those with tight 

. . 

The benign waste material can be disposed of in a 

landfill along with the fly ash. The material also may 

be used as a road bed or excavation fill material. 

Commercial use of the LIFAC by-product in the manufacture of consmtction materials is currently being 

investigated in Finland. 

The potential market penetration of LIFAC is assumed to be 20% of the smaller and medium-size power 

LlFAC Program Update 1992 7.73 
Commercial Demonstration of 

the NOXSO SO,/NOx Removal 

Flue Gas Cleanup System 

Sponsor: 

MK-FergusonCompany 

Addltlonal Team Members: 

NOXSO Corporation-cofunder and technology 

supplier 

W.R. Grace and Company-cofunder 

Ohio Edison Company-cofunder and host utility 

Ohio Coal Development Office-cofunder 

Gas Research Institute-cofunder 

Electric Power Research Institute-cofunder 

East Ohio Gas Company-cofunder 

Locatlon: 

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

Niles Station, Unit 1) 

Technology: 

NOXSO Corporation’s dry, regenerable flue gas 

cleanup process 

Plant CapacltylProduction: 

115 MWe 

Project Fundlng: 

Total project cost 

DOE 

Participants 

$66,249,696 100% 

33,124,848 50 

33,124,848 50 

Project Objective: 

To demonstrate removal of 91% of the SO, and 70% of 

the NO, from a coal-fired boiler’s flue gas using the 

NOXSOprocess, 

Technology/Project Description: 

The NOXSO process is a dry, regenerable system ca 

pable of removing both SO, and NO, in flue gas from 

coal-fired utility boilers burning medium- to high-sulfur 

coals. 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 sore 

bent. The sorbent consists of spherical beads of highsurface-area alumina impregnated with sodium carbonate. The cleaned flue gas then passes to the stack. 

The NO, is desorbed from the NOXSO sorbent 

when heated by a stream of hot air. The hot air contain. 

ing the desorbed NO, is recycled to the boiler where 

equilibrium processes cause destruction of the 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 sulfide (H,S). This offgas is 

pro-cessed in a Claus plant to produce elemental sulfur, 

asalable by-product. 

The process is expected to achieve SO, reductions 

of 97% and NO, reductions of 70%. 

The NOXSO process is being demonstrated at 

Ohio Edison Company’sNiles Station, Unit 1, a 

115.MWe cyclone boiler. MK-Ferguson will design, 

construct, and operate a full-scale commercial NOXSO 

unit to demonsuate process feasibility. The project is 

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

facility at Ohio Edison Company’s Toronto Station can 

be available before the end of the project definition 

activity. 

7.74 Prqram Update,1992 MK-Ferguson Company 
Calendar Year 

1988 1989 1990 ,991 ,992 1993 1994 ,995 ,996 ,997 ,998 

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

ua! 4$ :,:~:~: ~,,:,: ::,:i: :::,: 

T 

DOE se,eCled project l’Ng189 

h I 

Cooperative agreement awarded 3111191 

operatkm 

Prsoperalional ,es,s. initiated 1 ,/g4 

Construction completed II/94 

Environmental monitoring plan completed 1194’ 

CmWrwtion staded 10193’ 

Design completed 9193 

IEPAprocess completed (EA) 6193 

Project completediflnal 

repon isw*d 397’ 

Operalion completed 11%’ 

‘projecteddate 

Pro]ect Status/Accomplishments: 

The proof-of-concept, pilot-plant testing, which was 

proceeding in parallel with the project definition phase 

of the demonsuarion project, is complete, with results as 

expected. Preliminary process flow diagrams, piping 

and instrumentatioo diagrams, equipment specifications, 

and plant arrangement drawings have been prepared. 

Power plant, site, and process-specific environmental 

information has been compiled for use in the NEPA 

process. 

Commercial-grade sulfur, a salable by-product, is 

produced. The technology is expected to be especially 

attractive to utilities that require high removal efficienties for both SO, and NOx and/or need to eliminate solid 

wastes. 

Commercial Applications: 

The NOXSO process is applicable for retrofit or new 

facilities. The process is suitable for utility and industrial coal-fired boilers of 75 MWt or larger. The demoostration is using southeastern Ohio and western Pennsylvaniacoal(3.2-3.5% sulfur average): however, the 

process is adaptable to coals with higher sulfur content. 

MK-Ferguson Company Program Update 1992 7-75 
Integrated Dry NOx /SO, 

Emissions Control System 

Sponsor: 

Public Service Company of Colorado 

Additlonal Team Members: 

Electric Power Research Institute-cofunder 

Stone and Webster Engineering Corporation-engineer 

The Babcock &Wilcox Company-burner developer 

Fossil Energy Research Corporation-operational 

testing 

Western Researchinstitute-flyashev;ll”ator 

Colorado School of Mines-bench-scaleengineering 

research and testing 

Noell, Inc.-mea-injection system provider 

Location: 

Denver, Denver County, CO (Public Service Company 

of Colorado’s Arqahoe Station, Unit No.4) 

Technology: 

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

in-duct sorbent injection, and furnace (urea) injection 

Plant CapacltylProductlon: 

100 MWe 

Project Funding: 

Total project cost $21,411,462 100% 

DOE 13,705,73 1 50 

Participants 13,705,731 50 

Project 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 adownfired low-NOx burner with in-furnace mea injection for 

DRB-XCL is a tiemark of ns aatxoek dr wikox compsoy. 

7.76 Program Updare 1992 

additional NO, removal and dry sorbent in-duct injec- injection is being tested to determine how much addition with humidification for SO, removal. tional NO, can be removed from the combustion gas. 

Technology/ProjectDescrlptlon: 

All of the testing is using Babcock & Wilcox’,s low-NOx 

DRB-XCLTh’ down-fued burners with aver-fue air. 

These burners control NOx by injecting part of the coal 

and part of the combustion air in a” oxygen-deficient 

environment. Additional fuel and combustion air are 

introduced in a second stage to advance the combustion 

process. Additional air is introduced to complete the 

combustion process and further enhance NO,removal. 

The lawNOx burners are expected to reduce NOx emissions by up to 50%. and, with added air, by up to 70%. 

To reduce NO= emissions eve” further, in-furnace urea 

Two types of dry sorbents are being injected into 

the ductwork downstream of the boiler to reduce SO, 

emissidns. Either calcium is injected upstream of the air 

heater or sodium or calcium is injected downstream of 

the air heater. Humidification downstream of the dry 

sorbent injection aids SO, capture and lowers flue gas 

temperature and gas flow, which can decrease pressure 

drop at the fabric filter dust collector. 

Low-sulfur (0.4%) western bituminous coal is the 

main fuel being tested, but for a run of short duration 

(less than 1 month), eastern bituminous coal containing 

2.5% sulfur is being used. 

Public Service Company ofColorado 
Calendar Year 

,986 1969 1990 1991 1992 1993 1994 ,995 1996 1997 1998 

3 4 1 2 3 4 1 2 3 4 1*34 1 234 1 2 3 4 1 2 3 4 123412341234 12 

12189 3 

I ::i,:.,, ..I ;., I.~,: ,.,, .,~,~ ,~ ,,:,,,:,~,:,: 

1 DOE ssleded 

project 12,t9,*9 

T:T 

Design initiated 6/9o 

NEPA process completed (MTF) gQUg0 

11194 

Gv&uctton 

t tt t t 

bperation initiated 8192 

Construction completed 8/X 

Preaperationdtests initiated 6192 Project completedifinal report issued 11194’ 

Design completed 3,92 Operation completed 6194’ 

Environmental monitaring plan completed W0192 

-.‘ound breaking/construction stalted WI141 

,perattie agreement awarded 311,191 

‘Projected date 

The three basic technology systems have been 

installed on Public Service Company of,Colorado’s 

Arapahoe Station Unit No. 4, a lOO-MWe down-fired, 

pulverized-coal boiler with roof-mounted burners. 

ProjectStatusiAccomplishments: 

Baseline testing of the boiler without any modifications 

was completed in mid-December 1991. Baseline testing of the boiler with urea injection began in early February 1992 and continued for approximately 1 month. 

Construction requiring plant outage was completed in 

May 1992, and then preoperational testing of the boiler 

with lawNOx burners and NO” ports began. Operational testing of these Tao key components started in 

early August 1992. 

Testing of the combustion modifications was completed in late-October 1992. While firing western bituminous coal, NO, was reduced from an original baseline 

of 1.15 lb/million Btu to about 0.4 lb/million Btu--a 

65% reduction--with no operating problems. Shortterm testing while firing natural gas also was completed. 

In-furnace urea injection testing began in January 1993 

and is scheduled to continue for 2 months. 

The environmentaJ monitoring plan was conditionally approved on March 20, 1992, pending the inclusion 

of air toxics testing information. 

can reduce NOz emissions by up to 70% and SO, emissions by 55-75s. and they produce a dry solid waste 

product. These processes have the ability to handle all 

coal types, especially coals with low- to mid-sulfur 

content. 

Commercial Applications: 

Either the entire integrated dry NOJSO, emissions 

control system or the individual technologies are applicable to most utility and industrial coal-fired units. 

They provide a lower capital-cost alternative to conventional wet flue gas dwlfurization processes. They can 

be retrofitted with modest capital investment and downtime, and their space requirements are substantially less. 

They can be applied to any unit size but are mostly 

applicable to the older. small- to mid-size units. They 

PublicService Company ofColorado Program Update 1992 7.77 
Tampa Electric integrated 

Gasification Combined-Cycle 

Project 

Sponsor: 

Tampa Electric Company 

Additional Team Members: 

Texaco Development Corporation-gasification 

technology supplier 

General Electric Company-combined-cycle 

technology supplier 

GE Environmental Systems, Inc.-hot-gas cleanup 

technology supplier 

TECO Power Services Corporation-project manager 

and marketer 

Location: 

Lakeland, Polk County, FL (Tampa Electric Company’s 

Polk Power Station) 

Technology: 

Integrated gasification combined-cycle (IGCC) system 

using Texaco’s pressurized, oxygen-blown, entrainedflow gasifier technology and incorporating both conventional, low-temperature acid-gas removal and hot-gas 

moving-beddesulfurization 

system, conventional cold-gas cleanup, and a” advanced 

gas turbine with niuoge” injection (from the air separation plant) for power augmentation and NOx control. 

Plant Capacity/Production: 

260 MWe (net) 

Technology/ProJect Description: 

-, . . . 

Project Funding: 

Total project cost $241,458,000 100% 

DOE 120,729,OOO 50 

Participants 120,729,OOO 50 

Project Objective: 

To demonstrate the IGCC technology in a greenfield, 

commercial, electric utility application at the 260.MWe 

size with a Texaco gasifier. To demonstrate the integrated performance of a zinc-titanate hot-gas cleanup 

lexaco’spress”nzeo, oxygen-“low”, e”tral”ea-rmv 

gasifier is used to produce a medium-Btu fuel gas. 

Coal/water slurry and oxygen are combined at high 

temperature and pressure to produce a high-temperature 

syngas. Molten coal-ash flows out of the bottom of the 

vessel and into a water-filled quench tank where it is 

turned into a solid slag. The syngas from the gasifies 

mnves to a high-temperature heat-recovery unit which 

cools the gases. 

The cooled gases flow t” a particulate-removal 

section before entering gas-cleanup trains. About 50% 

of the syngas is passed through a moving bed of zinc. 

titanate absorbent to remove sulfur. The remaining 

syngas is further cooled through a series of heat exchangers before entering aconventional gas-cleanup 

train where sulfur is removed by an acid-gas removal 

system. These cleanup systems combined are expected 

to maintain sulfur levels below 0.21 lb/million Btu (96% 

capture). The cleaned gases are the” routed to a combined-cycle system for power generation. A gas turbine 

generates about 192 MWe. Thermally generated NOx is 

controlled tn below 0.27 lb/million Btu by injecting 

nitrogen as a dilutent in the turbine’s combustion section. A heat-recovery steam-generator uses heat from 

the gas-turbine exhausto produce high-pressure steam. 

This steam, along with the steam generated in the gasification process, is routed t” the steam turbine t” generate 

7-78 Program Update 1992 Tampa Electric Company 
Calendar Year 

1988 1989 1990 1991 1992 1993 ,994 1995 1996 ,997 ,998 

341234 1 2 3 4 1234 1 234 1234 1 2 3 4 1 2 3 4 1 234 I 234 I:! 

la89 3/91 3/96 1247 

t 

Project completedllnal 

remxl issued 12197’ 

I I 

I 

I Cooperative agreement awarded 3191 

DOE se,actec project ,a89 

Operation completed 

12197 

I 

bpsratian initiated 3196 

Canstruction completed 1196 

Design completed f/94’ Precpwational tests initiated 106’ 

NEPAprocess completed (EIS) ,194 

Environmental monitoring plan completed 1194 

COnstruction Staned i/94’ 

‘Pmjecteddate 

an additional 130 MWe. The IGCC heat rate for this 

demonstration is expected to be below 8,500 BtuikWh 

(more than 40% efficient). 

By-products from the process-sulfur, sulfuric 

acid, and slag-can be sold commercially, the sulfur 

and sulfuric acid by-products as araw material to make 

agricultural fenilizer and the nonleachable slag for use 

in roofing shingles and asphalt roads and as a &mctural 

fill in construction projects. 

ProjectStatus/Accompllshments: 

The cooperative agreement was modified in March 

1992 to change the sponsor from Clean Power Cogeneration L.P. to Tampa Electric Company. In addition, 

the site of the project was moved from Tallahassee to 

Polk County, FL, and the gasification technology was 

changed from air-blown fixed-bed to oxygen-blown 

entrained-flow. 

The project is in the preliminary design stage. 

License agreements have been obtained with Texaco for 

the gasification technology and General Electric for the 

frame 7F turbine-based combined-cycle. 

Environmental information for use in the NEPA 

process has been developed. Tampa Electric Compaq 

has submitted an extensive Site Certification Application to the State of Florida to support all of the environmental permits for the Polk County site. In August 

1992, a public scoping meeting was held to solicit 

comments on preparation of the environmental impact 

statement. 

The Texaco-based system has already been proven 

capable of handling both subbituminous and bituminous 

coals, This demonstration project is scaling up the 

technology from Cool Water’s 100 MWe to the 

260-MWesize. 

Commercial Appllcatlons: 

The IGCC system being demonstrated in this project is 

suitable for new electric power generation, repowering 

needs. and cogeneratian applications. The net effective 

heat rate for the Texaco-based IGCC is expected to be 

below 8,500 BwkWh, which makes it very attractive 

for baseload applications. Commercial 1GCCs should 

achieve better than 98% SO, capture with NOr emissions reduced by 90%. 

Tampa Electric Company Program Update 1992 7-79 
CCT-IV 

Project Fact Sheets 
Self-Scrubbing CoalTM: An 

Integrated Approach to Clean 

Air 

Sponsor: 

Custom Coals International (a joint venture between 

Genesis Coals Limited Partnership and Genesis 

Research Corporation) 

Additional Team Members: 

Duquesne Light Company-host utility 

Richmond Power & Light-host utility 

Centerior Service Company-host utility 

CQ, Inc.--operator 

ICF Kaiser Engineers, Inc.--engineer and constructor 

Locations: 

Stoystown, Somerset County, PA (advanced coalcleaning plant) 

Springdale, Allegheny County, PA (combustion tests at 

Duquesne Light Company’s Cheswick Power 

Station) 

Richmond, Wayne County, IN (combustion tests at 

Richmond Power&Light’s Whitewater Valley 

Station, Unit No. 2) 

Ashtabula, Trumbull County, OH (combustion tests at 

Centerior Service Company’s Ashtabula C-Plant) 

Technology: 

Coal preparation using advanced physical coal cleaning 

and fine magnetite separation technology plus sorbent 

addition technology 

ProJect Objective: 

To demonstrate advanced coal-cleaning unit processes 

to produce low-cost compliance coals that can meet full 

requirements for commercial-scale utility power plants 

to satisfy CAAA of 1990 provisions. 

Plant Capacity/Production: 

350 tonsihr 

Project Funding: 

Total project cost $81,726,346 lOc% 

DOE 3X,038,656 47 

Participants 43,687,690 53 

Self-Scrubbing Cod and Carcfrcc Cod eaIc tmdcmarks Of cus,0m Coals 

hlcmauonal. 

Technology/Project Description: 

An advanced coal-cleaning plant will be designed, 

blending existing and new processes, to produce, from 

high-rulfur bituminous feedstocks, two types of 

compliance coals--Carefree Coaln’ and Self-Scrubbing 

COP. 

ash. Carefree Coal”‘is designed to be a competitively 

priced, highgtu fuel that can be used without major 

plant modifications or additional capital expenditures. 

While many utilities can use Carefree Coalm’ to comply 

with SO, emissions limits, others cannot due to the high 

content of organic sulfur in their coal feedstocks. When 

compliance coal cannot be produced by reducing pMtic 

sulfur, Self-Scrubbing Coal”’ can be produced to 

achieve compliance. 

Carefree Co@’ is produced by breaking and 

screening run-of-mine coal and by using innovative 

dense-media cyclones and finely sized magnetite to 

remove up to 90% of thepyrific sulfur and n&t of the 

Self-Scrubbing Coal”’ is produced by taking 

Carefree Co@“, with its reduced pyritic sulfur and ash 

content, and adding to it sorbents, promoters, and 

catalysts. Self-Scrubbing Coal”’ is expected to achieve 

compliance with virtually any U.S. coal feedstock 

through in-boiler absorption of SO, emissions. The 

reduced ash content of the Self-Scrubbing Co@ 

7.82 Program Updare I992 Custom Cools Inremafional 
Calendar Year 

,991 1992 19% ,994 19% ,996 ,997 1998 war3 2000 2001 

341234 1234 1234 1 234 1 234 1234 1234 1234 1234 12 

t t+. 

Project complew.Vlinal report issued 12195’ 

DOE selected project 9112191 

A 1 

1 

Operation iMated 9194 

Preoperationaltests initiatad 8194’ 

Environmental monitoring plan completed 9194 

Constwclion completed 8194’ 

Design completed 8193 

Construclion *taned 8193 

NEPApracess completed (EA) ,193 

Cooperattte agreement awarded 10129192 

‘Projecteddate 

permits the addition of relatively large amounts of 

sorbent without exceeding the ash specifications of the 

boiler or overloading the electrostatic precipitator. 

A 350-tonm advanced coal-cleaning plant is being 

designed and consuucted at a site in Stoystown, PA. 

The advanced coal-cleaning plant will manufacture 

Self-Scrubbing Co@‘and Carefree Co@. Two 

medium- to high-sulfur Coals-Illinois No. 5 from 

Wabash County, IL, and Lower Freepon Seam coal 

from Belmont County, OH-will be used to produce 

Self-Snubbing Co@‘. Carefree Coal’“’ will he made 

using Sewickley coal from Greene County, PA. The 

Sewickley coal will be combustion tested at Duquesne 

Light Company’s Cheswick Power Station located “ear 

Pittsburgh, PA; the Illinois No. 5 coal will be tested at 

Richmond Power &Light’s Whitewater Valley Station 

Unit No. 2 located I” Richmond, IN; and the Lower 

Freemont Seam coal will be tested at Centerior Service 

Company’s AshtahulaC-Plant. 

ProjectStatWAccompllshments: 

The cooper&e agreement was awarded in Octobet 

1992. De&g” work has started. Environmental 

information is being prepared for use in the NEPA 

PIOCW. 

Commercial Applications: 

Cammercialization of Self-Scrubbing CottIm’ has the 

potential of bringing into compliance about 164 million 

tons/y? of bituminous coal that cannot meet emissions 

limits through conventional coal cleaning. This 

represents over 38% of the bituminous coal burned in 

50-MWe or larger US. generating stations. 

The technology produces coal products that can be 

used to reduce a utility or industrial power plant’s total 

sulfur emissions SO-90%. 

Program Update I992 7-83 
Milliken Clean Coal 

Technology Demonstration 

Project 

Sponsor: 

New York State Electric & Gas Corporation 

AddItIonalTeam Members: 

Consolidation Coal Company-technical consultant 

Saarberg-H6lter-Umwelttechnik,GmbH-technology 

supplier 

The Stebbins Engineering and Manufacturing 

Company-technology supplier 

NALCO Fuel Tech-technology supplier 

Location: 

Lansing, Tompkins County, NY (New York State 

Electric &Gas Corporation’s Milliken Station Units 1 

and 2) 

Technology: 

Flue gas cleanup using Saarberg-HelterUmwelttechnik’s (S-H-U formic-acid-enhanced, wet 

limestone scrubber technology; NALCO Fuel Tech’s 

NOxOUT urea injection system; Stebbins’ tile-lined 

split-module absorber; and heat-pipe air-heater system 

Plant CapacltylProduction: 

300 MWe 

Project Funding: 

Total Project Cost $158,607,X07 100% 

DOE 45,000,000 28 

Participant 113,607,X07 72 

Project Objectlve: 

To demonstrate at a 300.MWe utility-scale a combination of cost-effective and innovative emission reduction 

and efficiency improvement technologies, including the 

S-H-U wet scrubber system enhanced with formic acid 

7-84 Program Update I992 

to increase SO, removal in a Stebbins lined scrubber; 

urea injection for NOx removal; and a heat-pipe 

preheater. 

Technology/Project Descrlptlon: 

The S-H-U wet flue gas desulfurization process is a 

formic-acid-enhanced, wet limestone process which 

results in very high SO, removal with low energy 

consumption and the production of commercial-grade 

gypsum. 

The flue gas desulfurization absorber is a Stebbins 

tile-lined split-modulevessel which has superior 

corrosion and abrasion resistance, leading to decreased 

life-cycle costs and reduced maintenance. The splitmodule design is constructed in the base of the stack to 

save space and provide operational flexibility. 

The NALCO Fuel Tech NOxOUT system removes 

NO, by the injection of urea into the boiler gas. This 

facet of the project, in conjunction with other combustion modifications, will reduce NO= emissions and 

produce marketable fly ash. 

A heat-pipe air-heater system will be used with 

advanced temperature controls to reduce both air 

leakage and the air heater’s flue gas exit temperature. 

Ultimate emissions reductions with increased boiler 

efficiencies will result. 

The project is designed for “total environmental 

and energy management: a concept encompassing low 

emissions, low energy consumption, improved combustion, upgraded boiler conDaIs, and reduced solid waste. 

The system is being designed to achieve at least a 95% 

SO, removal efficiency using limestom? while burning 

New York Starr Electric c? Gas Corporation 
reject completed; final report issued 6198’ 

*ration intiiated 71%’ 

perational tests initiated 6195’ ration complefed 5/98’ 

nvirmmental monitoring 

ian completed 5193 

Oround breakingiconstrudion *laded 

NEPA process completed (En, 4193 

Design completed 4193 

‘Projecteddate 

high-sulfur coal. NO, reductions will be achieved using 

selectivenon-catalytic reduction technology and 

separate combustion modifications. The system has 

zero wastewater discharge and produces marketable byproducts (e.g., commercial-grade gypsum, calcium 

chloride, and fly ash), minimizing solid waste. 

New York State Electric &Gas plans to demonstrate these technologies at Units 1 and 2 of its Milliken 

Station located in Laming, NY. Pittsburgh, Freeport, 

andKittaning coals, with sulfur contents of 1.5%. 2.9%, 

and 4.0%, will be used. 

Project Status: 

The cooperative agreement was awarded on 

October 20. 1992. Environmental information is being 

prepared for use in the NEPA process. The environmental monitoring plan is being prepared. New York 

State completed its environmental review and issued 

permits in August 1992. 

Commercial Applications: 

The S-H-U SO, removal process, the NALCO NOxOUl 

non-catalytic reduction process. Stebbins’ tile-lined 

split-module absorber, and heat-pipe air-heater technology are applicable to virtually all electric utility power 

plants. Commercialization of all technologies in both 

retrofit and greenfield applications of virtually any 

megawatt size is expected. The high removal efficiency, up to 98% for SO, and up to 30% beyond 

combustion modifications for NOS. will make the 

combination of these technologies attractive. 

The space-saving design features of the S-H-U, 

NALCO, Stebbins, and heat-pipe technologies, combined with the production of marketable by-products, 

offer significant incentives to generating stations with 

limited on-site space. In addition, the inherent energy 

efficiency of the combined technologies minimizes any 

secondary environmental impacts from the operation of 

pollutioncontrolequipment. 

New York Store Elecrric & Gas Corporation Program Update 1992 745 
PiAon Pine IGCC Power 

Project 

Sponsor: 

Sitma Pacific Power Company 

Addltional Team Members: 

Foster Wheeler USA Corporation-architect, engineer, 

andconsuuctor 

The M.W. Kellogg Company-technology supplier 

Location: 

Reno, Storey County, NV (Sierra Pacific Power 

Company’s Tracy Station) 

Technology: 

Integrated gasification combined-cycle (IGCC) using 

the KRW air-blown, pressurized, fluid&d-bed coal 

gasification system 

Plant Capacity/Production: 

80 MWe (net) 

Project Funding: 

Total project cost $269,993,100 100% 

DOE 134,996,550 50 

Participant 134,996,550 50 

Project Objective: 

To demonstrate air-blown, pressurized, fluidized-bed 

IGCC technology incorporating hot gas cleanup; to 

evaluate a low-Btu gas combustion turbine: and to 

assess long-term reliability, availability, maintainability, 

and environmental performance at a scale sufficient to 

determine commercial potential. 

7.86 ,+0~~‘2~ Update 1992 

Technology/Project Description: 

Dried and crushed coal is introduced into a pressurized, 

air-blown, fluidized-bed gasifier. Crushed limestone is 

added to the gasifier to capture a portion of the sulfur 

and to inhibit conversion of fuel nitrogen to ammonia. 

The sulfur reacts with the limestone to form calcium 

sulfide which, after oxidation, exits along with the coal 

ash in the form of agglomerated particles suitable for 

landfill. 

particulate matter to the gasifier. The gas, which leaves 

Hot, low-Btu coal gas leaving the gasifierpasses 

through cyclones which return most of the entrained 

the gasifier at about 1,700 “F, is coo1e.d to about 

1,100 “F before entering the hot gas cleanup system. 

During cleanup, virtually all of the remaining pardculates are removed by ceramic candle filters, and final 

traces of sulfur are removed in a fixed bed of metal 

oxide sorhent. 

The hot, cleaned gas then enters the combustion 

turbine which is coupled to a generator designed to 

produce 56 MWe (gross). Exhaust gas is used to 

produce steam in a heat recovery steam generator. 

Superheated high-pressure steam drives a condensing 

steam turbine-generator designed to produce about 

30 MWe (gross). 

tion fuel stream, the NO, emissions are 0.069 lb/million 

Due to the relatively low operating temperature of 

the gasifier and the injection of steam into the combusBtu (94% reduction). Due to the combination of in-bed 

sulfur capture and hot gas cleanup, SO, emissions are 

0.069 lb/million Btn (90% reduction). 

Sierra Pactfic Power Company 
Calendar Year 

,991 1992 ,993 1994 1995 ,996 ,997 ,998 ,999 ZODO 2001 

3 4 1 234 1 *34 1 234 1234 1 234 1 234 1234 1234 1 234 12 

I 

DOE selected 

project w&9/91 

Design completed 8195 

Groundbreakingiconstrunion started 21%’ 

NEPAprocess completed (EIS) ,194 

Environmental monitoring plan completed 1194’ 

bperation inliated 2197 

Preoperational te*ts initiated 2/V’ 

Construction completed 2197’ 

Project complete&final report issued 7/W 

Operation completed 7100 

Cooperativea~reemeot awarded 81,192 

‘Projededdate 

I” the demonstxatio” project, a nominal 800 tons/ 

day of coal is converted into 86 MWe (gross), or 

80 MWe (net) for export to the grid. Western bituminous coal from Utah is the design coal; tests with higher 

sulfur and lower rank coals also are planned. The gasifier is being built at Sierra Pacific Power Company’s 

Tracy Station, “ear Reno, NV. 

ProjectStatus/Accomplishments: 

The cooperative agreement was awarded August 1, 

1992. The sponsor’s major activities centered on 

preparing and submitting its Triennial Resource Plan to 

the Public Service Commission of Nevada (PSCN). The 

plan recommended the Pifio” Pine IGCC project as the 

least-cost option for new baseload. I” a public meeting 

on November 23, 1992, the PSCN requeSted that Sierra 

Pacific Power Company refile a portion of the plan 

which includes the IGCC project; the request concerned 

overall long-term aspects of the plan and was not 

directly related to the proposed IGCC project. The 

refiled plan is due in April 1993, with a final ruling by 

the PSCN expected by July 1. The PSCN directed 

SierraPacific to take whatever steps are necessary to 

maintain Pinon Pine as an option in the meantime. 

advantages provided by modular construction reduce the 

otixr coal-based power generation systems, and the 

financial risk associated with new capacity additions. 

The KRW IGCC technology is capable of gasifying 

all types of coals, including high-sulfur and highswelling coals, as well as bio- or refuse-derived waste, 

with minimal environmental impact. This versatility 

provides numerous economic advantages for the 

depressed mineral extraction and cleanup industries. 

There are no significant process waste streams that 

require remediation. The only solid waste from the 

plant is a mixture of ash and calcium sulfate, a “onhazardous waste. SO, emissions are expected to be 

below 0.045 lb/million Bt” (98-99s reduction for most 

high-sulfur coals). NOr emissions are expected to be 

below 0.053 lb/million Bt”, and emissions of particulaws are expected to be below 0.01 lb/million Btu. 

Environmental information is being prepared for 

the NEPA process. Three public scoping meetings were 

held in the Reno area to support preparation of a” 

environmental impact statement. 

Commercial Applications: 

The Pifton Pine IGCC system concept is suitable for 

new power generation, repowering needs, and cogeneratio” applications. The net effective heat rate for a 

proposed greenfield plant “sing this technology is 

projected to be 7,800 BtuAWh (43.7% efficiency), 

representing a 20% increase in thermal efficiency as 

compared to aconventional pulverised coal plant with a 

scrubber and a comparable reduction in CO, emissions. 

The compactness of IGCC systems reduces space 

requirements per unit of energy generated relative to 

Sierra PaciJic Power Compony Program Update 1992 747 
Toms Creek IGCC 

Demonstration Project 

Sponsor: 

TAMCO Power Partners (a partnership between TP 

[TAMCO] Company, a subsidiary of Tampella Power 

Corporation, and CP [TAMCO] Company. a subsidiary 

of Coastal Power Production Company) 

Additional Team Member: 

Institute of Gas Technology-technology developer and 

cons”ltant 

Location: 

Coeburn, Wise County, VA (Virginia Iron, Coal, and 

Coke Company’s Tams Creek Mine) 

Technology: 

Integrated gasification combined-cycle (IGCC) using 

the Tampella U-GAS’ fluid&d-bed gasification system 

Plant Capacity/Production: 

190 MWe (55 MWe IGCC and 135 MWe pulverized 

coal) 

Project Funding: 

Total project cost $196,570,000 100%’ 

DOE 95,000,000 48 

Participant 101,570,000 52 

Project Objective: 

To demonstrate an air-blown, fluidized-bed gasification, 

combined-cycle technology, incorporating hot gas 

cleanup, for generating electricity and to assess the 

system’s environmental and economic performance for 

meeting future energy needs. Also to demonstrate the 

newly developed zinc titanate fluidized-bed hot-gas 

cleanup technology. 

U-GAS i. a lcgismcd trademark ofthe !mtimtc of Gas Technology 

7-88 Program Update 1992 

Technology/Project Descrlptlon: 

Being demonstrated is an IGCC system in which airblown operation has replaced the more conventional 

oxygen-blown gasifier operation and hot gas cleanup 

has replaced cold gas cleanup with the usual associated 

sulfurrecovery. 

Coal is gasified in a pressurised, air-blown, 

fluidized-bed gasifier in the presence of acalcium-based 

sorhent. About 90% sulfur removal is accomplished in 

the gasifier. Solids entrained in the gas are collected by 

cyclones in two stages. The IowBtu gas, which leaves 

the secondary cyclone at 1,800-1,900 “F, is cooled to 

about 1,000 “F before entering the post-gasifier desulfutization unit where zinc titanate is used to remove the 

bulk of the remaining sulfur in the gas. This is accomplished in two fluidized beds. In the first bed, the sulfur 

is absorbed by the zinc titanate; the zinc tittmate is 

regenerated in the second bed. In the final hot-gascleaning step, a ceramic candle filter removes particulams. The gas is then sent to the gas turbine combustor 

which has been modified to burn low-Btu gas. 

Hot exhaust gases from the gas turbine are directed 

to a heat recovery steam generator. The steam generated is used both for driving a conventional steam 

turbine generator to produce additional electticity and to 

provide steam feed to the gasifler. 

About 430 tons/day of bituminous coal are 

converted into 55 MWe by the gas turbine. A conventional pulverized coal boiler produces another 135 MWe 

through the shared steam turbine generator. Also, 

50,000 lb/h* of steam are generated for export to a coal 

preparation plant located next to the demonstration 

facility. The elecnic power is sold to a utility. 

TAMCO Power Porrners 
Calendar Year 

,991 1992 1993 1994 ,995 1996 ,997 ,998 ,999 2000 2001 

3 4 1 234 1 234 1 234 1234 1234 123412341234 1234 12 

A 

bOE selected 

t 1 

project 9121 I91 I besign completed 6195 

NEPAprocesscompleted (EIS) 1195’ 

Ground breakingiconstruction started 1195 

9191 10192 Design and Construction 

Environmenral monitoring plan completed 1194’ 

co operaWe agreement awarded 10120192 Pn toperational test9 initiated 7197 

1198 12100 

I 

Projectcompletedl 

final repon i*wed 12100 

operation completed 12/00’ 

Canstruclion completed 1198’ 

Operation indiafed 1198’ 

‘Projected date 

The facility is a greenfield plant located outside 

Coeburn, VA. next to the +oms Creek Mine owned by 

Virginia Iron, Coal, and Coke Company, a subsidiary of 

Coastal Power Production Company. 

ProjectStatus/Accomplishments: 

The cooperative agreement was signed on October 20, 

1992. Preliminary design and project definition studies 

are under way. Environmental information is being 

prepared for use in the NEPA process. 

Commercial Applications: 

The Toms Creek IGCC system is suitable for new 

power plants, repowering needs, and cogeneration 

applications. 

In xcent years, IGCC has become a rapidly 

emerging alternative for new electric generating plants. 

Such plants require 15% less land area than pulverized 

coal plants with flue gas desulfurization, and exhibit 

substantially improved themul efficiency and environmental performance. Because of its advantages of 

modularity. rapid and staged on-line generation capability, high efficiency, environmental controllability, and 

reduced land and natttrill resource needs. IGCC is a 

strong contender for widespread application for meeting 

future US. energy needs. Another important application for IGCC is cogeneration under PURPA’s Qualifying Facilities provisions. 

The heat rate of the demonstration facility is 

expected to be 8,720 BtuikWh (39% efficiency) with 

SO, emissions reductions of 99% (0.056 lb/million Btu 

release). NO, emissions are estimated to be 0.09 lb/ 

million Btu. 

A larger, commercial-scale, 271-MWegreenfield 

facility based on theToms Creek technology is estimated to have a heat rate of 7,750 Btu/kWh (44% 

efficiency). This represents a 20% increase in thermal 

efficiency and a corresponding reduction in CO, 

emissions as compared to a conventional pulverized 

coal plant equipped with a scrubber. 

The U-GAS” technology is capable of gasifying ail 

types of coals, including high-sulfur and high-swelling 

coal feedstocks. 

The total system being demonstrated is compact, 

reducing space requirements, and is very amenable to 

smaller capacity, modular construction situations. 

There are no significant wastewater streams, and the 

solid waste from the gasifier is ash and calcium sulfate, 

which is discharged as a non-hazardous waste. 

T4MCO Power Pamm Program Update 1992 739 
Micronized Coal Reburning 

Demonstration for NO 

Control on a 175MWe” 

Wall-Fired Unit 

Sponsor: 

Tennessee Valley Authority 

Additional Team Members: 

Duke/Floor Daniel (partnership between Duke 

Engineering & Services, Inc., and Fluor Daniel, 

Inc.) --engineer and constructor 

Fuller Company-technology supplier 

R-C Environmental Services and Technologytechnical consultant 

Location: 

West Paducah, McCracken County, KY (Tennessee 

Valley Authority’s Shawnee Fossil Plant) 

Technology: 

Advanced NO, control using micronized-coal-reburning 

combustiontechnology 

Plant Capaclty/Productlon: 

175 MWe 

Project Fundlng: 

Total project cost 

DOE 

Participants 

$7,330,041 100% 

3,514,755 48 

3.815.286 52 

ProJect Objective: 

To reduce NO, emissions by 50- 60% using micronized 

coal as the rebuming fuel combined with advanced coal. 

rebuming technology. 

MicroMill is atmdmwk of*cF”“erCmnpany. 

Technology/ProjectDescrlptlon: MicroMilln’iis being installed between the existing 

The technology is being applied to a 175-MWe front- pulverizers and the newly installed microtine burners 

wall-fired, dry-bottom furnace. The coal currently used for the project. 

to fire the furnace (low-sulfur bituminous coal from Micronized coal has the surface area and combusKentucky or West Virginia) will be the reburning fuel. tion characteristics of an atomized oil flame, which 

The rebuming coal, which can comprise up to 30% of allows carbon conversion within milliseconds and 

the total fuel, is micronized (80% below 325 mesh) and release of volatiles at a more even rate. This uniform, 

injected into the furnace above the main burner, the compact combustion envelope allows for complete 

region where NOz formation OCCUIS. combustion of the coal/air mixture in a smaller furnace 

Central to the project technology is the two-element volume than conventional pulverized coal because heat 

MicroFuel system, which consists of a patented rate, carbon loss, boiler efficiency, and NOx formation 

centrifugal-pneumatic MicroMill”’ and an external ale affected by coal fineness. 

classifier. The mill is capable of grinding coal into a The combination of micronized coal, supplying 

tine powder without the mechanical attrition or roll 30% of the total furnace fuel requirements, and adcrushing normally associated with coal mills. The vancedrebuming utilizing that requirement in conjunction with fuel/air staging, provides flexible options for 

7.90 Program Update 1992 Tennessee Valley Aurhority 

L 
II I I I bperation initiated 121%’ 

I project 9,1*191 

I! II 

/Construction completed 7193’ 

Preoperation tests initiated 7193’ 

I’ Prqect completed: final repan issued 8196 

I Operation completed 7196 

hronmental monitoring plan completed 5193 

Design completed 3193 

Construction staned 3193’ 

NEPApracess completed (CX) 8113192 

cooperative agreement awarded 7128192 

‘Projecteddate 

significant combustion operations and environmental 

improvements. These options can prevent higher 

operating costs or furnace performance derating often 

associated with conventional environmental controls. 

The Tennessee Valley Authority plans to retrofit its 

Shawnee Fossil Planl, located near West PaducaJt, KY, 

with the micronized-coal-reburning technology. 

ProjectStatusiAccomplishments: 

Design efforts began shortly after the cooperative 

agreement was awarded in July 1992. Design and 

construction are expected to overlap for a short period, 

with construction being completed in mid-1993. The 

environmental monitoring plan is being prepared and is 

expected to be complete in early spring 1993. 

The Fuller Company purchased MicroFuel 

Corporation (the technology supplier) in September 

1992 and will assume MicroFuel’s obligations to this 

project. 

categorical exclusion approved on August 13.1992. 

NEPA compliance has been satisfied through a 

Commercial Appllcatlons: 

Micronized-coal-rebuming technology can be applied to 

exisdng and greenfield cyclone-fired, wall-tired, and 

tangential-fired pulvetized coal units. The technology 

reduces NOx emissions by 50 -60% with minimal 

furnace modifications for existing units. For greenfield 

units, the technology can be designed as an integral part 

of the system. Either way, the technology enhances 

boiler performance with the improved burning characteristics of micronized coal. About 25% of the more 

than 1,000 existing units could benefit from the use of 

this technology. 

creating a very economic source of generation. For both 

reductions will enable lost capacity to be restored, 

retrofit and greenfield facilhies, reburn burners also can 

serve as low-load burners, and commercial units can 

achieve a turndown of 8:l on nights and weekends 

without consuming expensive auxiliary fuel. Existing 

pulverizers can be operated on avariety of coals with 

improved performance. The combination of micronized-coal-reburning fuel and better pulverizer petformance will increase overall pulverized-fuel surface area 

for better carbon burnout. 

The availability of a coal-rebuming fuel, as an 

additional fuel to the furnace, solves several problems 

concurrently. Existing units unable to switch fuels 

because of limited mill capacity would be able to reach 

their maximum continuous rating. NOx emissions 

Tennessee Valley Authority Program Update 1992 7.91 
Demonstration of Pulse 

Combustion in an Application 

for Steam Gasification of Coal 

Sponsor: 

ThermoChem, Inc, 

Additional Team Member: 

Manufacturing and Technology Conversion 

International. Inc.-technology supplier 

Location: 

Near Gillette, Campbell County, WY (Caballo Rojo 

Mine) 

Technology: 

Advanced combustion using Manufacturing and 

Technology Conversion International’s (MTCIJ pulse 

combustorigasifier 

Plant CapacltylProductlon: 

161 million Btu/br of 325 Btuistd ft”medium-Btu fuel 

gas plus 40,000 lb/lx of export steam 

Project Funding: 

Total project cost $31,333,414 100% 

DOE l&666,737 50 

Participants 18,666,737 50 

Project Objective: 

To demonstrate the MTCI pulse combustor in an 

application for steam gasification of coal to produce a 

medium-Btu fuel gas from subbituminous coal. 

’ WASTE TO DISPOSAL 

Technology/Project Descrlptlon: 

technology with the resonance tubes comprising the 

heat exchanger immersed in the fluidized-bed reactor. 

The MTCI fluidized-bed gasifier incorporates an 

Heat transfer is 3-5 times greater than other indirectly 

heated @tier concepts, allowing the heat transfer 

innovative indirect heating process for thermochemical 

surface to be minimized. 

steam gasification of coal to produce hydrogen-rich, 

clean, medium-Btu fuel gas without the need for an 

oxygen plant. The indirect heat transfer is provided by 

MTCI’s multiple resonance tube pulse combustor 

The demonstration plant’s overall efficiency is 

expected to be 72% or more. In major commercial 

applications, char combustion and heat recovery 

Caballo Rojo Mine in conjunction with a new facility to 

demonstrate the K-Fuel coal-upgrading process. Water 

operations can be included to enhance overall plant 

required to gasify the subbituminous coal will be 

efficiency. 

produced by the K-Fuel process and the steam produced 

in the gasification demonstrarion facility will be used in 

the K-Fuel facility. The product gas will be burned in a 

SO, emissions are controlled by scrubbing ttie 

gas turbine to generate electricity to operate both 

product gas using the Sulfur-Ox process. A market for 

facilities. 

the by-product sulfur is being sought, and disposal 

methods are being evaluated. 

The demonstration facility will be built at the 

7-92 Program Update 1992 ThermoChem 
oa,endar Yea, 

,991 1992 1993 ,994 ,995 1996 1997 ,998 1999 2000 200, 

3 4 1 2 3 4 ,234 1 234 1 234 1 2341234 ,23412341234 ta 

I DOE selected 

projea 9112191 

N EPAprocess completed (EA) 8193 

I Design completed 8193 

co ~operatiie agreement awarded IO/27192 

11194 11196 

I II &ration initiated 11194’ I 

Operation completed 8196’ 

lCOnStr”Ction completed 10194 

Preoperational t**h initiated 10/94’ 

Environmental monitoring plan completed Q/94 

Conwxtion started 9193 

‘Projecteddate 

ProjectStatudAccomplishments: 

The cooperative agreement’was awarded on October 27, 

1992, and design activities are under way. Environmental information is being prepared for usd in the NEPA 

process. 

Commercial Appllcatlons: 

The MTCI fluidized-bed gasifier is expected to provide 

the exceptional environmental performance exhibited by 

coal gasification in general. SO, emissions are controlled by removing hydrogen sultide from the product 

gas prior to combustion: removal efficiencies approaching 99% are possible. Particulate emissions are also 

controlled in highly efficient scrubbers. Finally, the 

MTCI pulse combustion technology that provides the 

required gasifier heat is an inherently lowNOr combustion process, thereby assuring that NOx emissions are 

substantially below acceptable limits. 

Because of its potential for reducing emissions 

while producing a clean-burning, hydrogen-rich fuel 

gas, the MTCI fluidized-bed gasifier is expected to have 

considerable commercial potential. Some of the early 

industrial applications of this technology areexpected to 

be waste-to-energy or waste and coal co-fired facilities 

for power and steam generation. One of the more 

promising non-coal applications is processing of kraft 

black liquor. 

significant application of this technology is likely to be 

in conjunction with coal-upgrading facilities as demonstrated in this project. 

The processing of pulp results in the production of 

about 88 million tons of by-product black liquor. The 

current practice of using black liquor recovery boilers to 

produce steam and electricity is inefficient. Replacing 

these boilers with MTCI gasifiers would significantly 

improve the conversion efficiency. The estimated 

market for MTCI g&sifters in this application alone is 

28 units annually. 

Another potential application for the technology is 

in industrial coal gasification because of its modularity 

and ability to produce a medium-Btu gas without 

requiring an oxygen plant. In the short term, the most 

ThemwChem Program Update 1992 7.93 
Demonstration of the Union 

Carbide CANSOLVTM System 

at the ALCOA Generating 

Corporation Warrick Power 

Plant 

Sponsor: 

Union Carbide Chemicals and Plastics Company Inc. 

Additional Team Members: 

Aluminum Company of America (ALCOA) Generating 

Corporation-host and cofunder 

Stone and Webster Engineering Corporation-engineer 

Location: 

Newburgh, Warrick County, IN (ALCOA Generating 

Corporation’s Warrick Generating Station Unit No. 2) 

Technology: 

Flue gas cleanup using Union Carbide Chemicals and 

Plastics Company’s CANSOLVm’ regenerable flue gas 

desulfurization (FGD) system 

Plant Capacity/Production: 

75 MWe 

Project Funding: 

Total Project Cost $32,715,000 100% 

DOE 16,357,500 50 

Participants 16,357,500 50 

(Funding amounts reflect those contained in the 

proposal and are subject to negotiation.) 

Project Objective: 

To demonstrate the CANSOLY’ regenerable flue gas 

desulfurization system to achieve SO,removal efkicienties of at least 99%. 

CANSOL” is B trademark Of Union Carbids thmicalr and rkitics 

company Inc. 

. NOTE: one 0, three stages 0, so,MJnt i”iem” 

Technology/Project Descrlptlon: 

water and then by an aqueous solution of the SO, 

absorbent, both introduced to the gas stream as ultraIn the CANSOLVm’ process, untreated flue gas enters 

tine droplets through atomizing nozzles. Following 

each spraying section, mist elimination equipment 

removes the droplets from the gas stream, and after the 

the process from a particulate control device, such as a 

last section, the treated gas is released to the chimney. 

electrostatic precipitator, where it is contacted first by 

recirculating lean absorbent and treated in the absorbent 

purification unit to prevent the build-up of impurities. 

application of heat, the SO, is stripped from the 

absorbent. The SO, stream is converted.to salable 

products appropriate to local market conditions and 

opportunities. A 1% slipstream is taken from the 

An advanced FGD technology, the CANSOLVw 

process is capable of SO, capture rates over 99%. The 

demonstration project is using Indiana high-sulfur 

bituminous coal, with a sulfur content of about 3.4%. 

The water loop removes any particulate matter 

remaining in the gas, saturates the gas, and absorbs any 

chlorides and fluorides. The SO, is scrubbed from the 

flue gas by contact with the absorbent solution. In the 

absorbent loop, rich absorbent laden with SO, is routed 

to the absorbent regeneration unit where, through the 

ALCOA Generating Corporation’s Warrick 

Generating Station Unit No. 2, located in Newburgh, 

IN, will be retrofitted with a newly designed and 

constructed CANSOLVn’ scrubber facility capable of 

treating 50% of the flue gas from the unit. 

7.94 Program Updare 1992 Union Carbide Chemicals andPlastics Company 
Q/91 6193 Preaward 

1 

5 DOE sehxted 

proJecl g/12/91 

I 

Cooperative agreement awarded 6193 

I ‘Projected date; mils%nss ars subject 10 negotiation. 1 

ProjectStatos/Accomplishments: 

The project is in negoti&tion. At the sponsor’s request, 

DOE’s negotiating deadline was extended 7’% months 

so that the sponsor could find a.partner to share the 

project risk. Environmental information is being 

prepared for use in the NEPA process. 

Commercial Applications: 

The CANSOLV”’ process is attractive for both new 

and retrofit utility and indusuiaJ applications. 

The process is designed to operate as’ an in-duct 

scrubber system, without the need for costly scrubbing 

vessels. Regeneration occurs in relatively small vessels 

requiring a minimal amount of space. Consequently the 

process potentially is applicable to the many spaceconstrained facilities. CANSOLVm’may be integrated 

effectively with other NOx and paniculate control 

systems to provide for overall emission control. 

The CANSOLy7h’ process is a viable alternative to 

and economically competitive with conventional wet 

FGD processes. CANSOLV”‘can be retrofitted with 

modest capital investment and downtime, and its space 

requirements are substantially less. CANSOLVT”l can 

reduce SO, emissions by up to 99% while producing 

only minimal solid or liquid waste. The SO, removed 

from the flue gas can be converted to a salable byproduct-liquid SO,, sulfuric acid, or elemental sulfur. 

CANSOLVT”‘can handle all types of coal. 

Union Carbide Chemicals and Plastics C&pany Program Update 1992 7.95 
Wabash piver Coal 

;;;zscGlon Repowering 

Sponsor: 

Wabasb River Coal Gasification Repowering Project 

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

and PSI Energy, Inc.) 

Additional Team Members: 

PSI Energy, Inc.-host utility 

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

technology supplier 

Electric Power Research Institute-cofunder 

Location: 

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

Wabash River Generating Station) 

Technology: 

Integrated gasification combined-cycle HGCC) using 

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

Plant Capacity/Production: 

268 MWe (“et) 

Project Funding: 

Total Project cost $396,000,000 100% 

DOE 198,ooo,c0J 50 

Participant 198,000,000 50 

Project Objective: 

To demonstrate utility repowering with a two-stage, 

oxygen-blown IGCC system. including advancements 

in the technology relevant to the use of high-sulfur 

bituminous coal, and to assess long-term reliability, 

availability, andmaintainability of the system at a fully 

commercial scale. 

7-96 Program Update 1992 

Technology/Project Description: 

gas turbine. Hot exhaust from the gas turbine is passed 

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

pressurized, two-stage (entrained flow slagging first 

through a heat recovery steam generator to produce 

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

entrained-flow gasiiier. The product gas is cooled 

high-pressure steam. High-pressure steam is also 

through heat exchangers and passed through a conventional cold gas cleanup system which removes particuproduced from the gasification plant and superheated in 

lates, ammonia, and sulfur. The clean, medium-Btu gas 

is then reheated and burned in an advanced 192.MWe 

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

steam turbine. 

The process has the following subsystems: a cordgrinding and slurry system, an entrained-flow coal 

gasifier, a cold gas cleanup system which produces a 

marketable sulfur by-product, acombustion turbine 

capable of using coalderived fuel gas, a heat recovery 

steam generator, and arepowered steam turbine. 

designed to generate 268 MWe net using 2,544 tons/day 

of high-sulfur; Illinois Basin bituminous coal. The 

anticipated heat rate for the repowered unit is 8,974 Btul 

One of six units at PSI Energy’s Wabash River 

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

kWh (38% efficiency). Using high-sulfur bituminous 

being repowered. The demonstration unit will be 

coal, SO, emissions are expected to be less than 0.2 lb/ 

million Btu (98% reduction). NOI emissions are 

expected to be less than 0.1 lb/million Btu (90% 

Wnhnsk Riwr 
t 

* 

DOE seleaed 11 I 1 

project 9117.m Operation inliated 7195 I 

Design completed 12193 Preoperational tests initiated 7195 Project completed/final report i**ued 6/W 

Construclion completed 7/W Operation completed 6/98 

Environmental monitoring plan completed 6193’ 

NEPA process completed (EA) 393 

Ground breakingiconsfrunion $taned 3193 

Cooperative agreement awarded 7128192 ‘projecteddate 

reduction). Upon completion, the project will represent these plants with IGCC systems will improve plant 

the largest single-train IGCC plant in operation in the 

United States. 

ProjectStatudAccomplishments: 

The cooperative agreement was signed on July 28, 

1992. Initial design efforts and preliminary site 

preparation are under way. In December 1992, a. draft 

environmental assessment was prepared, as required by 

the NEPA process. Applications for air and water 

permits were filed with the Indiana Department of 

Environmental Management, and a Petition for Need 

was filed with the Indiana regulatory commission. 

efficiencies and reduce SO,, NO”, and CO, emissions. 

The modularity of the gasifier technology will permit a 

range of units to be considered for repowering and the 

relatively short construction schedule for the technology 

will allow utilities greater flexibility in designing 

strategiesto meet load requirements. Also, the high 

degree of fuel flexibility inherent in the gasifier design 

allows utilities greater choices in fuel supplies to meet 

increasingly stringent airqualityregulations. 

improvement in efficiency compared to a conventional 

pulverized-coal-fired plant with flue gas desulfurization. 

The improved system efficiency also results in a similar 

decrease in emissions of CO,. 

Commercial Applications: 

Throughout the United States, pwticulaly in the 

Midwest and East, there are more than 95,000 MWe of 

existing coal-firedutility boilers which will be over 

30 years old in 1996. Many of these aging plants are 

without air pollution controls and are candidates for 

repowering with IGCC technology. Repowering of 

Wabash River 

Due to the advantages of modularity, rapid and 

staged on-line generation capability, high efficiency, 

fuel flexibility, environmental controllability, and 

reduced land and natural resource needs, the IGCC 

system is also a strong contender for new electric power 

generating facilities. Commercial offerings of the 

technology will be based on a 300-MWe train which is 

ideally suited to utility-scale power generation applications. The system heat rate for a new power plant based 

on this technology is expected to realize at least a 20% 

Program ffpdare 1992 7.97 
Appendix E: CCT Project Contacts 

In this section are listed contacts for obtaining 

further information about specific CCT Program 

demonstration projects. Each listing provides the 

name, tide, phone number, and mailing address of 

the contacl person. In those instances where lhe 

project sponsor consists of more than one company, 

a partnership, or joint venture. the mailing address 

listed is that of the contact person. 

CCT-I Projects 

Development of the Coal Quality Expert 

Sponsors: ABB Combustion Engineering, Inc., and 

CQ, Inc. 

Contact: Clark Harrison, President 

(412)479-6016 

CQ, Inc. 

One Quality Cutter 

P.O. Box 280 

Homer City, PA 15748.0280 

LIMB Demonstration Project Extension and 

Coolside Demonstration 

Sponsor: The Babcock &Wilcox Company 

Conracr: Todd Johnson, Senior Marketing Specialist 

(216)829-7355 

The Babcock &Wilcox Company 

1562 Beeson Street 

Alliance, OH 44601 

Advanced Cyclone Combustorwith Internal 

Solfor, Nitrogen, and Ash Control 

Spunsor: Coal Tech Corporation 

Conracr: Bert Zauderer, President 

(215)667-0442 

Coal Tech Corporation 

P.O. Box 154 

Merion, PA 19066 

Nucla CFB Demonstration Project 

Sponsor: Tri-State Generation and Transmission 

Association, Inc. 

Conrac~: Raymond Keith, Executive Vice President 

(303) 249-4501 

T&State Generation and Transmission 

Association, Inc. 

P.O. Box 1149 

Montrose, CO 81402 

Enhancing the Use of Coals by Gas Rebuming 

and Sorbent Injection 

Sponsor: Energy and Environmental Research 

Corporation 

Conracr: Blair A. Folsom, Senior Vice President 

(714)859-8851 

Energy and Environmental Research 

Cwporation 

18 Mason 

Irvine. CA 92718 

Tidd PFBC Demonstration Project 

Sponsor: American Electric Power Service 

Corporation as agent for The Ohio Power 

Company 

Contact: Mario Marrocco, Manager, PFBC Programs 

(614)223-1740 

American Electric Power Service Corporation 

1 Riverside Plaza 

Columbus,OH43215 

Advanced Coal Conversion Process 

Demonstration 

Sponsor.: Rosebud SynCoal Partnership 

Conracr: Ray W. Sheldon, Project Manager 

(406)748-2366and/or(406)252-2277 

Rosebud S ynCoa1 Partnership 

P.O. Box7137 

Billings, MT59103-7137 

YorkCounty Circulating Fluidized-Bed 

Cogeneration Project 

Sponsor: York County Energy Partners, L.P. 

Conracr: Bradley Hahn, Project Manager 

(215)481-3955 

York County Energy Partners, L.P. 

2146 White Street 

York, PA 17404 

Pro‘qnm7 Updole 1992 E-l 
CCT-II PKJject.9 

I Combustion Engiueeriug IGCC Repowering 

Project 

Sponsor: ABB Combustion Engineering, Inc. 

Conmcr: Robert W. Glamusina, Project Manager 

(203) 285-5904 

ABB Combustion Engineering, Inc. 

P.O. Box 500 

wiudsor. CT 06095-0500 

SNOX Woe Gas Clemhg Demonstratiou Project 

Sponsor: ABB Combustion Engineering, Inc. 

Conracr: Bill Kingston, Project Manager 

(205) 995-5368 

Environmental Systems Division 

ABB Combustion Engineuiug, Inc. 

P.O. Box 43030 

Birmingham, AL 35243 

P~monsfratloa of Coal Relnwaiag for Cyclone 

Boiler NO, Control 

Spmsor: The B&cock &Wilcox Company 

Conmrr: Todd Johnson, Senior Marketing Specialiit 

! 

(216) 829-7355 

The Babcock &Wilcox Company 

1562 Beeson Street 

Alliice, OH 44601 

SOX-NOX-ROX Box Flue Gas Cleanup 

Demonstration Project 

Sponsor: The B&cock & Wilcox Company 

Contacr: Todd Johnson, Senior Marketing Specialist 

(216) 829-7355 

Cement Kiln Flue Gas Recovery Scrubber 

Sponsor: Passamaquoddy Tribe 

Conmcr: Garrett Morrison, Project Manager 

(207) 594-5555 

The Babcock & Wilcox Company 

1562 Beeson Street 

Alliance, OH 44601 

Passamaquoddy Technology, L.P. 

P.O. Box 350 

Thomaston, ME 04861-0350 

hnovative Coke Oven Gas Cleaning System for 

Retrofit Applications 

Sponsor: Bethlehem Steel Corporation 

Conmcr: Marshall R. Maxer, Project Manager 

(215)694-2389 

Advanced Flue Gas Desulfurizatioo 

Demonstration Project 

Sponsor: Pure Aii on the Lake, L.P. 

Conrocr: Don Vymazal, Manager, Contract 

Adminisaation 

(215)481-3687 

Bethlehem Steel Corporation Pure Air on the J.&e, L.P. 

1739 Martin Tower 7201 Hamilton Boulevard 

1170 8th Avenue Allenlown,PA 18195-1501 

Bethlehem.PA 18016 

PFBC Utility Demoustratioa Project 

Sponsor: The Appalachii Power Company 

Confacr: Mario Marmcco. Manager. PFBC Programs 

(614)223-1740 

Demonstration of Advanced Combustion 

Techniques for a Wall-Fired Boiler 

Sponsor: Southern Company Services, Inc. 

Conmcr: John N. Serge, ICCT Project Manager 

(205) 877-7426 

American Electric Power Service Corporation 

I Riverside Plaza 

Cohtmbus.OH43215 

Southern Company Services, Inc. 

P.O. Box 2625 

Binningham, AL 35202-2625 

, 

; 

I 

! E-2 Program Update 1992 
Demonstration of Innovative Applications of 

Technology for the CT-121 FGD Process 

Sponsor: Southern Company Services. Inc. 

Co/rfoct.- David P. Burford, Project Manager 

(205) 870.6329 

Southern Company Services, Inc. 

P.O. Box 2625 

Birmingham, AL 352022625 

Demonstration of Selective Catalytic Reduction 

Technology for the Control of NO, Emissions 

from High-Sulfur-Coal-FiredBoilers 

Sponsor: Southern Company Services, Inc. 

Conracr: J.D. (Doug) Maxwell, Project Manager 

(205) 877-7614 

Southern Company Services, Inc. 

P.O. Box 2625 

Birmingham, AL35202-2625 

180~MWe Demonstration of Advanced 

Tangentially Fired Combustion Techniques 

for the Reduction of NOx Emissions from 

Coal-Fired Boilers 

Sponsor: Southern Company Services, Inc. 

Conracrt Robert R. Hardman, Project Manager 

(205) 877-7772 

Southern Company Services, Inc. 

P.O. Box 2625 

Birmiigham, AL 35202-2625 

CCT-III Projects 

lo-MW Demonstration of Gas Suspension 

Absorption 

Sponsor: AirPol. Inc. 

Conracr: Frank E. Hsu. Project Manager 

(201) 288-7070 

AirPal, Inc. 

32 Henry Street 

Teterboro. NJ 07608 

Commercial-Scale Demonstration of the 

Liquid-Phase Methanol (LPMEOHTN) Process 

Sponsor: Ai Products and Chemicals, Inc. 

Conmcr.- William R. Brown, Project Manager 

(215)481-7584 

Air Products and Chemicals, Inc. 

7201 Hamilton Boulevard 

Allentown,PA 18195-1501 

Healy Clean Coal Project 

Sponsor: Alaska Industrial Development and Export 

Authority 

Confacr: John Olson, Project Manager 

(907) 561-8050 

Alaska htdustrial Development and Export 

Authority 

480 West Tudor 

Anchorage, AK 995036690 

Full-Scale Demonstration of Low-NO, 

Cell’” Burner Retrofit 

Sponsor: The Babcock & Wilcox Company 

Conracr: Todd Johnson, Senior Marketing Specialist 

(216) 829-7355 

The Babcock &Wilcox Company 

1562 Beeson Street 

Alliance, OH 44661 

Confmed Zone Dispersion Flue Gas 

DesnlfurizationDemonstration 

Sponsor: Bechtel Corporation 

Contact: Allen 0. Rubin, Project Manager 

(415)768-6514 

Bechtel Corporation 

P.O. Box 3965 

SanFmncisco,CA94119-3965 

Blast Furnace Granulated Coal fnjection System 

Demonstration Project 

Sponsor: Bethlehem Steel Corporation 

Contacr: Daniel Kwasnoski, Project Director 

(215)694-6478 

Bethlehem Steel Corporation 

1739 Martin Tower 

1170 8th Avenue 

Bethlehem.PA 18016 

Program Vpdate I992 E-3 
:::::: :i.:.::,::,:::::i:l:i::::i:::::::::::::::::::~: :~:h :::,:: :::::::::~:~:: ~~,,::,,~,::::::1’,::: :::::,.:,,A ~~,~ ,‘::, :: 

PCFB Demonstration Project 

S~OIISOI: DMEC-I Limited Partnership 

Contarf: Gary Kmempel. Project Manager, Midwest 

Power, Inc. 

(515)281-2459 

Midwest Power, Inc. 

6f56 Grand Avenue 

Des Moines, IA 50303 

ENCOAL Mild Coal Gasification Project 

Spmsor: ENCOAL Corporation 

Coatacl: Jim Frederick, Project Manager 

(307)686-5493 

ENCOALCorporation 

P.O. Box 3038 

Gillette, WY 82717 

Ilrabvl!nn of Gas Reburning and Low-NOx 

Burners on a Wall-Fired Boiler 

.S[~onsor: Energy and Environmental Research 

Coqwation 

Contarr: Rlair A. Folsom, Senior Vice President 

(71.1)859-X851 

Energy and Environmental Research 

Colpomion 

18 Mason 

,j 

i 

Irvine, CA 927 18 

LIFAC Sorbent Injection Desolfurization 

Demonstration Project 

S/xwsor: LIFAC-North America 

Corlracr: Jim Hervol, Project Manager 

(412)497-2735 

ICF Kaiser Engineers. Inc. 

4 Gateway Cenler 

Pittsburgh,PA 15222.1207 

Commercial Demonstration of the NOXSO 

SO,INOx Removal Floe Gas Cleanup System 

Spoasor: MK-Ferguson Company 

Contacr: Eugene R. Recher, Program Manager 

(216)523-5923 

MK-FergusonCompany 

1500 West 3d Street 

Cleveland, OH 44114 

Integrated Dry NOJSO, Emissions Control 

Sgstem 

Sponsor: Public Service Company of Colorado 

Cormrr: Gordon A. Schott, Project M,anager 

(303)329-1702 

Public Service Company ofColorado 

5900 East 39th Avenue 

Denver. CO 80207 

Tampa Electric Integrated t;asilication 

Combined-Cycle Project 

S~OIISD~: TampaElectric Company 

Cortracr: Donald E. Pless. Project Manager 

(813)228-1332 

Tampa Electric Company 

P.O. Box II I 

Tampa. FL 33601-0111 

CCT-IV Projects 

Self-Scrubbing Coal*“‘: An Integrated Approach 

to Clean Air 

S/xvuor: Custom Coals International 

Conracr: Robin Godfrey. Project Manager 

(412)1X2-2625 

Custom Coals lntemarional 

100 First Avenue. Suite 500 

Pittsburgh, PA 15222 

Milliken Clean Coal Technology Demonstration 

Project 

S~OIISO~: New York State Electric & Gas 

Corporation 

Conrocr: Dennis O’Dea, Project Manager 

(607) 729.255 1 

New York State Electric & Gas Corporation 

120 Chenango Sweet 

Binghamton. NY 13902 

E~4 Progron, Updare 1992 
Piiion Pine IGCC Power Project 

S~JOIISOI.: Sierra Pacitic Power Company 

Couracr: Jack Matter, Project Manager 

(702)68Y-4013 

Sierra Pacific Power Company 

6100 Neil Road 

Reno. NV 89520-0400 

Toms Creek 1GCC Demonstration Project 

S/IYI)OIISOI: TAMCO Power Partners 

Conrocr: J.G. Patel, Vice President. New 

Technology 

(404) 984-887 1 

Demonstration of Pulse Combustion in an 

Application for Steam Gasification of Coal 

Spw~sur: ThermoChcm. Inc. 

Courucr: William Steedman. Program Manager 

(41O)YY7-9671 

ThennoChem, Inc. 

5570 Sterrett Place, Suite 210 

Columbia. MD 21044 

Demonstration of the Union Carbide 

CANSOLVrh’ System at the ALCOA Generating 

Corporation Warrick Power Plant 

Sponsor: Union Carbide Chemicals and Plastics 

Tampella Pow er Corporation 

23OOII” may ’ Kidge - Parkway, Suite 225 

Marietl !a, GA 30067 

company Inc. 

Conracr: Alex B. Bamett, Market Manager, Flue Gas 

Treating 

(203)794-2561 

Micronized Coal Reburning Demonstration of 

NO, Control on a 17S-MWe Wall-Fired Unit 

Sponsor: Tennessee Valley Authority 

Conmct: Tom Butler, Mechanical Engineer 

(6153751.6120 

Tennessee Valley Authority 

1101 Market Street, ATTN: MR-3A 

Chattanooga, TN 37402 

Union Carbide Chemicals and Plastics 

company Inc. 

39 Old Ridgebury Road J3-386 

Danbury, CT06817-0001 

Wabash River Coal Gasification Repowering 

Project 

Sponsor: Wabash River Coal Gasification 

Repowering Project Joint Venture 

Conmct: David G. Sundstrom, Business 

Developmenl Manager 

(713) 974-8238 

Destec Energy. Inc. 

2500 City West Boulevard. Suite 1700 

Houston, TX 77042 

Program Update 1992 E-5