m 

wm-0351 

COAL Clean Coal Technology 

TECHNOLOGY Demonstration Program 

Project Fact Sheets 

U.S. Department of Energy 

Assistant Secretary for Fossil Energy 

Washington, DC 20585 

September 1996 
The Clean Coal Technology Demonstration 

Program is a unique paxtnership between the United 

States Department of Energy (DOE) and industry 

that has as its primary goal the successful demonstration of a new generation of advanced coal-based 

technologies, with the most promising technologies 

being moved into the domestic and international 

marketplace. 

Begun in 1985 and expanded in 1987 to meet the 

recommendations of the United States and Canadian 

Special Envoys on Acid Rain, the program has 

resulted in a capital investment of nearly $6 billion in 

40 competitively selected projects. Of the 40 

projects, 20 have completed operations, 7 are in 

operation, 5 arc in conshuction, 7 are in design, and 

I is in negotiation. The demonstrations are at a scale 

large enough to generate data needed to enable 

potential domestic and international users to make 

judgments about the commercial viability of a 

particular process. These demonstrations will 

improve the global environment and enhance global 

energy security through the use of technologies and 

services provided by United States industry. 

The 40 projects are. directed toward satisfying 

the energy and environmental needs of four application categork 

l Advanced electric power generation 

* EnvimnmentaI control &vices 

* Coal processing for clean fuels 

* Industrial applications 

Advanced Electrit Power Genera&ion 

The growing concern over global climate 

change is being addressed through the demonstration 

of high-efficiency advanced electric power generating technologies. Nearly 900 megawatts-electric 

(MWe) of new capacity and more than 800 MWe of 

repowered capacity are represented by I2 projects 

valued at nearly $3.4 billion. These projects include 

five fluidized-bed combustion systems. four integrated gasification combined-cycle systems, and three 

advanced combustion/heat engine systems. These 

projects not only will provide environmentally sound 

electric power generation in the mid- to late 1990s. 

but also will provide the demonstrated technology 

base necessary to meet new capacity requirements in 

the 21st century. 

Environmental Control Devices 

There are 19 environmental control devices 

projects valued at nearly $704 million. These 

include seven NO, emissions contml systems 

installed on more than 1,700 MWe of utility generating capacity, five SO, emissions control systems 

installed on approximately 770 MWe, and seven 

combined SOJNO, emissions control systems 

installed on approximately 800 MWe of capacity. 

Most of these environmental control devices will 

have their operating experience documented by the 

end of 1996. 

Coal Processing for Clean Fuels 

Valued at more than $5 I9 million, the five 

pmjects in the coal processing for clean fuels 

application category represent a diversified portfolio 

of technologies. Three projects involve the pmduction of high-energy-density solid compliance fuels 

for utility or industrial boilers; one of these. projects 

also produces a liquid for use as a chemical or 

transportation fuel feedstock. A fourth project is 

demonstrating a new methanol production process. 

The fifth project has demonstrated an expert computer software system that enables a utility to predict 

operating performance of coals being considered but 

not previously burned in the utility’s boiler. 
Indudial Applications 

The four projects in the industrial applications 

category have a combined value of nearly $1.3 

billion. Projects encompass substitution of coal for 

40 percent of the coke in iron making, integration of 

a direct iron-making process with the production of 

electricity, reduction of cement kiln emissions and 

solid waste generation, and demonsaation of an 

industrial-sale combustor. 

International Activities 

Internationally, clean coal technologies are 

increasingly important in the export market, creating 

major opportunities for U.S. business. Recognizing 

the importance of this export market, a number of 

efforts are under way to define market opportunities 

to pmmote U.S. technology and to support U.S. 

project development work. International activities 

have concentmted on providing technical support to 

U.S. trade agencies. organizing trade missions, 

conducting education and training, developing 

tinancial and market analysis in response to Sectioa 

1331 of the Energy Policy Act of 1992, and develop 

ing an international technology transfer program as 

directed by Section 1332 of that act. 

The Energy Policy Act provided the Secretary of 

Energy with the responsibility. among others, to 

“encourage the export of United States clean coal 

technologies” and to “assist United States fms, 

especially firms that are in competition with firms in 

foreign countries, to obtain opportunities to . 

uudmtake projects in faeign counties.” The 

tkm%ry was suthorind to “develop policies and 

pDgramstoeltcmtageexpatsndpNmKJtion...(o 

developing countries* of all %mestic energy 

re-source techooIogies.” 

ii 

Project Fact Sheets 

Exhibit I provides the project schedules by 

application category for the 40 projects in the 

program. The remainder of this report contains fact 

sheets for all projects. The information provided 

includes the project participant, team members, 

location, process flow diagram, significant project 

features, project objectives, description of the 

process and its performance attributes, progress and 

accomplishments, commercial applications, and 

major milestones. 

To prevent the release of project-specific 

information of a proprietary nature, process flow 

diagrams contained in the fact sheets are highly 

simplified and presented only as illustrations of the 

concepts involved in the demonstrations. 

For additional information, contact: 

Dr. CL. Miller 

U.S. Dqrtment of Energy 

Oftice of Fossil Energy (FE2D27OCC) 

Germantown, MD 20874-1290 

Phone: (301) 903-9451 

Fax: (301) 903-9438 

Key lo Milestone Charts In Fact Sheets 

Each fact sheet contains a bar chart that highlights major milestones-past and planned. The bar 

chart shows a projeds duration and indicates the time 

period for three general categories of project activities-prssward. design and construction, and operation. The key provided below explains what is induded in each of these categories. 

Reaward 

Includes proaward briefings. negotiations, 

and Ot+wactlvi,ies conducted during tfw 

pedod between DOE’s selection of the 

pro@cf and award Of me cooperative agreeIlBnt 

Design and Construction 

IncludesUxe NEPAprocess. permining, 

design, procurement, construction, preoperatfonal testing, and odw activities conducted prior to the beginning of operation of the 

demonstration. 

hfrF Memo-bf!fS 

cx catsgorlcal exclusion 

EA Emimnmentalassessnwnt 

EIS Environmentafimpactstatement 

NEPA National Environmental Policy Act 

UP Of Weration and in. 

Cl”& operationaltesting, datacolle&on. 

analysis, evaluation. reporling. and other 

activities to complete the demanstratlon 

Pmj=t. 
Exhibit 1 

Project Schedules and Funding by Application Category 

:alendar 

Tri-State--Nucla 

Ohio Power--Tidd 

Penelec--ACFB 

DMEC-1 

Pen&c-Externally Fired 

ADL-Coal Diesel 

DOE TOM 

6moo~ 

17.130 46,513 

66.957 189,886 

219.1lnl 438,200 

I 142,994 285,988 

154,276 308,551 

117,327 242,058 

74,734 276,695 

Bethlehem--Blast Furnace 

0 F’mwmd m Design andConstruction m Opention and Reporting 

iii 
Exhibit 1 (continued) 

Project Schedules and Funding by Application Category 

B&W--LIMB 

SCS-Wall-Fired 

EER--GR/SI 

SC-S-Tangentially Fired 

Bechtel-CZD 

B&W--Coal Rehuming 

ABB ES-SNOX 

Purr- Air on the Lake 

PSC of Colorado 

EER--GR-LNB 

NYSED-Milliken 

NYSEG-Micrmized Coal 

NOXSO Corporation 

iv 

DOE Total 

($1 .wo) 

7,597 19,405 

6,554 14.711 

18,748 37,589 

4,440 9,153 

5,206 10,412 

6,341 13,647 

5,443 11,233 

15,719 31,438 

6,078 13,272 

63,913 151,708 

’ 10,637 21,394 

1 13,706 27,411 

2,315 7.717 

8,896 17,807 

~ 21,085 43,075 

9,407 23,230 

45,000 158,608 

’ 2,701 9,096 

! 41,406 82,812 

’ 10,864 21,746 

43,125 105,700 

45,332 90,664 

37,994 87,386 

, 92,708 213,700 
Project Fact Sheets: The United States Department of Energy’s 

Clean Coal Technology Demonstration Program 

Project Pertlclpant 

Advanced Eleotric Power Generation 

Fluidhd-Bed Combustion 

PCFB Demonstration Project 

Four Rivers Energy Modemization Project 

Tidd PFBC Demonstration Project 

ACFB Demonstration Project 

Nucla CFB Demonstration Project 

DMEC-I Limited Partnership 2 

Four Rivers Energy Partners, L.P. 4 

The Ohio Power Company 6 

Pennsylvania Blectric Company 8 

Tri-State Generation and Transmission Association, Inc. IO 

Integrated GasiGcation Combined Cycle 

Clean Energy Demonstration Project 

Pifim Pine IGCC Power Project 

Tampa Electric Integrated Gasification Combined-Cycle Project 

Wabash River Coal Gasification Repavering Project 

Advanced Combustion/Heat Eogtnes 

Healy Clean Coal Pmject 

Coal Diesel Project 

Clean Energy Partners Limited Partnership 

Sierra Pacific Power Company 

Tampa Electric Company 

Wabash River Coal Gasification Repowering F’mject Joint Venture 

Alaska Industrial Development and Export Authority 

Arthur D. Little, Inc. 

Externally Fired Combined-Cycle Demonstration Project Pennsylvania Electric Company 

Environmental Control Devioea 

NO, Control Technologies 

Demonstration of Coal Rebuming for Cyclone Boiler NOr Control 

Full-Scale Demonstration of Low-NO1 Cell Burner Retmtit 

Evaluation of Gas Rebuming and Law-NO, Burners on a Wall-Fired Boiler 

Micmnized Coal Rebutting Demonstration for NOx Control 

Demonstration of Advanced Combustion Techniques for a Wall-Fired Boiler 

Demonstration of Selective Catalytic Reduction Technology for the Control of NO. Emissions 

from High-Sulfur-Coal-Fired Boilers 

ISO-MWe Demonstration of Advanced Tangentially Fired Combustion Techniques 

for the Reduction of NO= Emissions from Coal-Fired Boilers 

The Babcock & Wilcox Company 28 

T%e B&cock & Wilcox Company 30 

Energy and Environmental Research Corporation 32 

New York State Blecttic & Gas Corporation 34 

Southern Company Services, Inc. 36 

Southern Company Services, Inc. 38 

Southern Company Services. Inc. 40 

PsSe 

I2 

I4 

I6 

I8 

m 

22 

24 
Project Fact Sheets: The United States Department of Energy’s 

Clean Coal Technology Demonstration Program 

(continued) 

PI@.& Participant Page 

SO, Contd Technologies 

IC-MWe Demonstration of Gas Suspension Absorption 

Confined Zone Dispersion Flue Gas Desulfwization Demonstration 

LIFAC Sorbed Injection Desulfmization Demonstration Project 

Advanced Flue Gas Desulfurization Demonstration Project 

Demonstration of lmwvative Applications of Technology for the CT-121 FGD Pmcess 

Combined SOflO= Control Tecbnolcgies 

SNOT Flue Gas Cleaning Demonstration FToject 

LIMB Demcmstmtion Project Extension and Coolside Demonstration 

SO;NO;Rox Boxn” Flue Gas Cleanup Demonstration Project 

Enhancing the Use of Coals by Gas Rebmning and Sorbent Injection 

Milliken Clean Coal Technology Demonstration Project 

co-al De tnonsuation of the NOXSO SO$NO, Removal Flue Gas Cleanup System 

Integrated Dry NO/SO, Emissions Control System 

AirPol, Inc. 42 

Bechtel Corporation 44 

LIFAC-North America 46 

Pure. Air on the Lake, L.P. 48 

Southern Company Services, Inc. 50 

ABB Environmental Systems 52 

The B&cock & Wilcox Company 54 

The B&cock & Wilcox Company 56 

Energy and Environmental Research Corporation 58 

New York State Electdc & Gas Corporation 60 

NOXSO Corpwation 62 

Public Service Company of Colomdo 64 

Coal Processing for Clean Fuels 

Cd Reparalion Technologies 

Development of the Coal Quality Expert 

&If-Scrubbing Coal”: An In@-ated Approach to Clean Air 

Advanced Coal Conversion Pmxss Demonstt’ation 

Mud Gad6cation 

ENCOAL Mild Coal Gasification Project 

IndIrect LiqueractioD 

ABB Combustion Engineering, Inc., and CQ Inc. 68 

Custom Coals International 70 

Ros&ud SynGaal Partnership 72 

ENCOAL Gxporatimt 74 

Cmnmercial-Scale Demonstration of the Liquid-phase Methanol (LPMEOHM) Pmwss Air Pmducts Liquid Phase Conversion Company, L.P. 76 

Induswlal Applrcations 

Blast Furnace Granulated-Coal Injection System Demonstration Project 

Advanad Cyclone Combustor with Internal Sulfur, Nitmgen. and Ash Control 

Clean Power from Integrated CoaYOre Reduction (COREX@) 

Cement Kiln Flue Gas Recovery Scrubber 

Bethlehem Steel Corporation 80 

Coal Tech Corporation 82 

CF’ICORTu Management Company, L.L.C. 84 

Passamaquoddy Tribe 86 

vi 
Advanced Electric 

Power Generation 

Fact Sheets 
Project Results/Accomplishments: 

Between August 1988 and January 1991, a total of 72 

steady-state performauce tests were conducted: 22 tests 

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

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

participant, follow: 

Results indicated strong cot~elations of absolute CO, 

SO,, and NO, emissions levels with combustor 

operating temperatures. Although NSPS compliance 

was maintained. a penalty on limestone feed 

requirements for sultiu retention was realized at the 

higher operating temperatures. Below 1,620 “F, 70% 

sulfur retention was achieved with 1.5 Ca/S, and 95% 

sulfur retention was achieved with 4.0 CaLS. At 

approximately 1,700 “F, Ca/S greater than 5.0 was 

required to maintain 70% sulfur capture. 

The NOx emissions for all tests were less than 

0.34 lb/million Btu, which was well within the stateregulated emission limit of 0.50 lb/million Btu. The 

average level of NO, emissions for all tests was 

0.18 lb/million BN. 

Combustion efficiency, a measure 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. hydrocarbons in the flue gas, was 

measured and found to be negligible. 

Boiler efficiencies for 68 perfonuauce tests varied 

from 85.6% to 88.6%. The contributions to boiler 

heat loss were identified as unburned carbon, sensible 

heat in dry flue gas, fuel and sorbent moisture, latent 

heat in burning hydrogen, sorbent caldnation, radiation and convection, and bottom ash cooling water. 

. 

Net plant heat rate decreased with increasing boiler 

load, from 12,400 BtuMVh at 50% of full load to 

11,600 Btu/kWb at full load. The lowest value 

achieved during a full-load steady-state test was 

10,980 BtuIkWb. These values were affected by the 

absence of reheat, the presence of the three older 

12.5.hIWe turbines in the overall steam cycle, the 

“umber of unit restarts, and part-load testing. 

Over the range of operating temperatures at which 

testing was performed at Nucla, bed temperature was 

found to be the most influential operating parameter. 

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

temperature was the only parameter that had a measurable impact on emissions or efficiencies. Emissions of Sq and NO, were found to increase with 

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

was increased. 

A” economic evaluation indicated that the final 

capital costs for the Nucla ACFB system were about 

$112.3 million. representing a cost of S1.123lnet kW. 

Total power production costs associated with test operations were about $54.7 million, which translates to a 

normalized power production cost of $63.63iMWh. 

Fixed costs were less than 62% of the total, and variable 

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

costs pmved competitive with pulverized coal units not 

limiting emissions as signiticantly. 

Commercial Applications: 

ACFB technology has good potential in both industrial 

and utility sectors for new capacity additions or for 

tqowering existing coal-fired plants. Coal of “y sulfur 

content can be used. Because any type or size of boiler 

can bc repowend by ACFB using the existing plant area, 

coal- and waste-handling equipment, and ?.team turbine 

equipment, the life of the plant can be extended. Benefits of ACFB include 90% SO, reduction, 60-80s NO, 

reduction, and control of pollutants at lower costs than 

are offered by existing technologies. 

As a result of the Nucla demonstration. Pyropower 

Corporation was able to save almost 3 years in estabiishing a commercial line of ACFB units. Pympower’s 

commercial units are now offered under warranty in 

sizes ranging up to 400 Mwe. Under the terms of the 

project’s repayment plan. T&State is required to submit 

to DOE semiannual payments based on a percentage of 

the net revenues from plant operation. This repayment 

obligation ends in October 2011 unless DOB’s conttibution is repaid before that time. Tri-State has made payments of $351,700 under the plan. 

Project Schedule: 

WE selected project (CCT-I) lOfl/87 

Cooperative agreement awarded lOt3ls8 

NEPA process completed (hfTF) 4/18/88 

Envimnmental monitoring plan completed 2!27/88 

Operational testing 8/88-l/91 

Project completed 4l92 

Final F&ports: 

Final Technical Report lo/91 

Economic Evaluation Report 3t92 

Petfomxmce Test Summary Reports 3192 

Public Design Report lma 

Advanced Elecrric t’ower Generation 11 
Advanced Electric Power Generation 

htegrated Gasification Combined Cycle 

Clean Energy Demonstration 

Project 

Participant: 

Clean Energy Partners Limited Partnership (a limited 

pxtnenhip consisting of Clean Energy Genco, Inc., an 

affiliate of Duke Energy Corp.: Makowski Clean Energy 

Investors, Inc.; British Gas Americas, Inc.; and an afftliate of the General Electric Company) 

Additional Team Members: 

Duke Engineering & Services, Inc.--engineer and 

COnSttuCtOr 

General Electric Company-power island designer and 

supplier 

Btitish Gas Americas, Inc., affiliate in conjunction with 

Lurgi Energie and Umwelt GmbH-gasification 

island designer 

Fuel Cell Engineering Corporation-molten carbonate 

fuel cell designer and supplier; cofunder 

Electtic Power Research InstiNt~ofunder 

National Rural Electric Cwperative Associationcofunder 

Deutsche Aerospace AG-cofunder 

Location: 

An east coast site 

Technology: 

Integrated gasification combined-cycle (IGCC) using 

British GasJLurgi (BG/L) slagging fixed-bed gasification 

system coupled with Fuel Cell Engineering’s molten 

carbonate fuel cell (MCFC) 

Plant Capacity/Production: 

477.MWe (net) IGCC; 1.25-MWe MCFC 

Project Funding: coal and limestone to produce a raw coal gas rich in 

Total project cost $841,096,189 100% hydrogen and carbon monoxide. Raw coal gas exiting 

DOE 183,300,OOO 22 

Panicipant 657,796.189 78 

Project Objective: 

To demonstrate and assess the reliability, availability, 

and maintainability of a utility-scale IGCC system using 

high-sulfur bituminous coal in an oxygen-blown, fixedbed, slagging gasifier and the operability of a molten 

carbonate fuel cell fueled by coal gas, by an independent 

power producer under commercial terms and conditions. 

Technology/Project Description: 

The BG/L gasifier is supplied with steam, oxygen, limestone flux. and coals having a high fines content. During gasification, the oxygen and steam react with the 

the gasifier is washed and cooled. Hydrogen sulfide and 

other sulfur compounds are removed. Elemental sulfur 

is reclaimed and disposed of as a by-product. Tars. oils, 

and dust are recycled to extinction in the gasifier. The 

resulting clean, medium-BN fuel gas is used to fuel the 

gas turbine in the IGCC power island. A small portion 

of the clean gas is used for the MCFC. 

The MCFC is composed of a molten carbonate 

electrolyte sandwiched between porous anode and cathode plates. Fuel (desulfurized, heated medium-BN gas) 

and steam are fed continuously into the cathode. Electrical reactions produce direct electric current which is 

convened to alternating power in an inverter. 

12 Advanced Electrib Power Genemtion 
-‘lBar 

Iam Ios4 1995 1998 1997 xxx) MO1 x02 2033 

3412341 234 1 2341 234 1 2-3 4 1 :“, 4 1 2 3 4 1 234 I 234 12 

WEsekM~mjacl 

(CCT-“, Yu93 

The project is demonstrating the use of eastern U.S. The heat rate of the ICCC demonstration facility is 

bitnminws coal in a cmnmercial-scale ICiCC system and 

integrated MCF‘C module. 

ProjeetStatuslAccomplishma: 

The wcQetative agreemen* was awarded December 2 

1994. The patticipant is looking for a” east coast site. 

Commercial Applications: 

The IGCC system being demonsaated in this pmject is 

suitable for both repoweting applications and new power 

plants. The technology is expected t” be adaptable to a 

wide variety of potential market applications because of 

sevem1 factors. First, the BG/L gasification technology 

has successtidly used a wide variety of U.S. coals. Also. 

the highly modular approach t” system design makes the 

BGLbased IGCC and molten carbonate fuel cell cornpetitive in a wide range of plant sizes. In addition, the 

high efficiency and excellent envimnnwntal perfomvmce 

of the system are competitive with or superior to other 

fossil-fuel-f&d power generation technologies. 

8.560 BWkWh (40% efficiency) and the commercial 

embodiment of the system has a projected heat rate of 

8,035 BmikWh (42.5% efficiency). The commercial 

version of the molten carbonate fuel cell fueled by a 

BCX gasitier is anticipated to have a heat rate. of 7,379 

Bm/kWh (46.2% efficiency). These efficiencies represent greater than 20% reduction in emissions of CO, 

when compared to a conventional p”lverized coal plant 

equipped with a scrubber. SO, emissions from the IGCC 

system are expected to be less than 0.1 lb/million Bm 

(99% reduction); NOx emissions, less than 0.15 Ib/million BN (90% reduction). 

Also, the slagging characteristic of the gasifier 

pmd”ces a “o”leachi”g, glass-like slag that can be marketed as a “sable by-product. 

Adwmced Ekctric Power Genernrion 13 
Advanced Electric Power Generation 

Integrated Gasification Combined Cyde 

Piiion Pine IGCC Power 

Project 

Participant: 

Sierra Pacific Power Company 

Addiiional Teem Members: 

Foster Wheeler USA Corporation-architect, engineer, 

and constructor 

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 pressmized fluid&d-bed coal 

gasification system 

Plant Capacity/Production: 

99 Mwe (net) 

Project Funding: 

Total project cost $308,55l,oco 100% 

DOE 154,275,5OU 50 

Participant 154.275,500 50 

Project Objective: 

To demonstrate air-blown, prcssurized, fluidized-bed 

IGCC technology incorporating hot gas cleanup: to 

evaluate a low-Bm gas combustion turbine; and to assess 

long-term reliability, availability, maintainability, and 

environmental performance at a scale sufficient to determine commercial potential. 

Technology/Project Description: 

Dried and crushed coal and limestone are introduced into 

a pressurized, air-blown, fluidized-bed gasitier. Crushed 

limestone is used 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 as calcium sulfate along with 

the coal ash in the form of agglomerated particles suitable 

for landfill. 

Hot, low-Btu coal gas leaving the gasilier passes 

through cyclones which remm most of the entrained 

particulate matter to the gasifier. The gas, which leaves 

the gasifier at about 1,700 “F, is cooled to about 1,100 “F 

before entering the hot-gas cleanup system. During 

cleanup, virtually all of the remaining puticulates are 

removed by ceramic candle filters, and final traces of 

sulfur are removed by reaction with metal oxide sorbent 

in a banspat reactor. 

The hot, cleaned gas then enters the combustion 

Nrbine which is coupled ta a generator designed to 

prcduce 61 Mwe (gross). Exhaust gas is used to produce steam in a heat recovery steam generator. Superheated high-pnssure steam drives a condensing steam 

turbine-genemtor designed to produce &but 46 MWe 

(groSSi 

Due to the relatively low operating tempexahwz of 

the gasifier and the injection of steam into the combustion fuel stream. the NO, emissions are 0.069 lb/million 

Bm (94% reduction). Due to the combination of in-bed 

sulfiu capture and hot gas cleanup, SO2 emissions are 

0.069 lb/million BN (90% reduction). 

14 Advanced Ekcrric Power Genemtion 
Calendar war 

1991 1992 ,993 

*‘“, 

19% 

2’“3 

1997 ,998 1999 2ca MO1 

3 4 1 234 1 234 1 4 1 2 3 4 1 4 12341 2 3 4 1 2 3 4 ,234 12 

I DOE seleded 

~;~,(CCT-W 

Grn”“d Llrea~nglco”strucbon started as5 

EPA p- mmp!ated (EIS) 1118/94 

bperatan in*ated 2197’ 

const~ cOmpk3fed zf97’ 

Pmoperatirnal tests initiated 1 llgs 

Envimntal malitonng plan 

compbt6-d 10196 Pmleet ampletedninal repon issued 7100’ 

Design eemptsted 8/95 cparafoncompleted 7Klo 

I” the demonstmtion project, 880 tons/day of coal 

are convert.ed into 107 MWe (gross), or 99 Mwe (net), 

for expoti to the grid. Western bimminous coal 

(OS-O.996 sulfitr) from Utah is the design coal; tests 

using eastern bituminous coal containing Z-390 sulfur 

also are planned. The integrated gasification system is 

being built at Sierra Pacific Power Company’s Tracy 

Station, near Reno, h-V. 

Project Status/Accomplishments: 

The pmjea is in the final stages of engineering and 

construction. Steel erection was started in late 1995 and 

completed in February 1996. Consistent with a” environmentally pristine area, all solid feedstocks and products will be unloaded, conveyed, and stored in completely enclosed subsystems. Major pieces of equipment. 

including the gasitier, syngas coolers, particulate filters, 

cyclones, and two turbines were vendor-fabricated, 

shipped to the site, and lifted into place consistent with 

a” overall modular mechanical and erection schedule. 

The combustion turbine and steam Nrbine have 

been installed, aligned with generators. and made ready 

for commissioning. Operator training for the combustion turbine has been ongoing since mid-April 19% in 

preparation for start-up on natural gas in mid-August. 

The switch to coal gas will be made as the gasification 

island becomes operational in the fourth quarter of 1996. 

Commercial Applications: 

The Pidon Pine ICCC system concept is suitable for new 

power generation, repoweting needs, and cogeneration 

applications. The net effective heat rate for a proposed 

greenfield plant using this technology is pmjected to be 

7,800 BtiWh (43.7% efficiency), representing a 20% 

increase in thermal efficiency as compared to a conventional pulverized coal plant with a scmbber and a comparable reduction in CO, emissions. ‘Ihe compactness of 

IGCC systems reduces space requirements per unit of 

energy generated relative to other coal-based power 

generation systems, and the advantages provided by 

modular construction reduce the financial risk associated 

with new capacity additions. 

The KRW IGCC technology is capable of gasifying 

all types of coals, including high-sulfur and high-swelling coals, as well as bio- or refuse-derived waste, with 

minimal environmental impact. This versatility provides 

numerous economic advantages for the depressed tinera1 extraction and cleanup industries. There are no 

significant process waste. streams that require 

rem&&ion. The only solid waste from the plant is a 

mixture of ash and calcium sulfate, a nonhazardous 

waste. 

Advmced Electric Power Genemtion 
Advanced Eleczdc Power Generation 

h&grated Gasification Combined Cycle 

Tampa Electric Integrated 

Gasification Combined-Cycle 

Project 

Participant: 

Tampa Electric Company 

Additional Team Members: 

Texaco Development Corporation-gasification 

technology supplier 

General Electric Company+ombined-cycle technology 

supplier 

GE Environmental Systems, Inc.-hot-gas cleanup 

technology supplier 

TECO Power Services Corporation-project manager 

and marketer 

Bechtel Power Corporation-architect and engineer 

Location: 

Mulberry, Polk County, PL (Tampa Electric Company’s 

Polk Power Station, unit 1) 

Technology: 

Integrated gasification combined-cycle (IGCC) system 

using Texaco’s pressurized, oxygen-blown, entrainedflow @tier technology and incorporating both conventional, low-temperature acid-gas removal and hot-gas 

moving-bed desulfutization 

Plant Capacity/Production: 

250 Mwe (net) 

Project Funding: 

Total pmject cost $285.988.446 100% 

DOE 142,994,223 50 

Participant 142,994,223 50 

I6 

Project Objective: 

To demonstrate IGCC technology in a greenfield, commercial, electric utility application at the 256MWe size 

with a Texaco gasifier. To demonstrate the integrated 

performance of a metal oxide hot-gas cleanup system, 

conventional cold-gas cleanup, and an advanced gas 

turbine with nitrogen injection (from the air separation 

plant) for power augmentation and NO. control. 

Technology/project Description: 

Texaco’s pressurizcd, oxygen-blown, entraine&flow 

gasifier is used to produce a medium-Btu fuel gas. Coal/ 

water shmy and oxygen are reacted 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 tumed into a 

solid slag. The syngas fmm the gasifier moves to a bightemperature heat-recovery unit which cc& the gases. 

The cooled gases flow to a particulate-removal 

section before entering gas-cleanup trains. A portion of 

the syngas is passed through a moving ted of metal 

oxide absorbent to remove sulfur. The remaining syngas 

is further cooled through a series of beat exchangers 

before entering a conventional gas-cleanup train where 

sulfur is removed by an acid-gas removal system. Combined, these cleanup systems are expected to maintain 

sulfur levels below 0.21 1Wmillion Btu (96% capture). 

The cleaned gases are then routed to a combined-cycle 

system for power generation. A gas turbine generates 

about 192 MWe. Them&y generated NO= is wntmUed 

to below 0.27 lb/million Btu by injecting nitrogen as a 

dilutent in the hubine’s combustion section. A heatAdvanced Ekctrii Power Generation 
CalmdarYeaI tt 

1988 WE3 1990 199, ,994 1995 1936 ,937 1999 ,999 2wo 

3412341 2 3 4 1 23412341 234 1 2341 23412341 234 12 

I 

A T ttt t f 

Operation iniiiated loF96’ 2; ~~~~tedninal repat 

rlesign cmpmed a94 

kzGia&h cmpleted e&6 Operation completed 10/o,’ 

Pmopmdkmal tests initiated EL96 

Environme”ti monitoring plan completed s&6 

NEPA p- mmplete., (EIS) 8/17/94 

consbuc(iar started 8194 

cwperative agreement awarded 3/l ml 

OE selected ,,,c+x.d (CCT-III) lZZ19/89 ‘Projected date 

“Years omitteli 

recovery steamgenerator uses heat from the gas-turbine 

exhaust to pmduce high-pressure steam. This steam, 

along with the steam generated in the gasification process, is muted to the steam turbine to generate an additional 120 MWe (gross). The IOCC heat rate for this 

demonstration is expected to be approximately 

8,600 Btu/kWh (40% eficient). 

The demonstration pmject involves only the 

first 250 MWe (net) of the planned 1,150~Mwe Polk 

Power Station. Being used in the demonstration are 

Illinois 6 and Pittsburgh 8 bituminous coals having 

sulfur contents ranging 2.5-3.5%. 

By-pmducu from the process-sulfuric acid and 

slagAau be sold commercially, sulfuric acid by-products a.5 a NW material ta make agricultural fetilizer and 

the nonleachable slag for use in roofing shingles and 

asphalt roads and as a structural till in construction 

projects. 

Project StatuslAccompliehments: 

Tampa Electric held a formal groundbreaking ceremony 

at the Polk County site on November 2, 1994. Site 

construction is complete. The combined cycle has generated the first 235 MWe at Polk on fuel oil. The gasifier achieved first light-off on coal on July 19. 1996. 

The g&tier operated on Pittsburgh No. 8 coal for 20 

hours before being shut down to correct minor water 

leaks downstream of the gasitier. Initiation of integrated 

tests of the gasifier and combined-cycle plant is planned 

for September 1996. Operation of the sulfuric acid plant 

on coal gas is also planned for September. 

Reclamation of the area west of Rt. 37 is complete. 

This area was approved for development of a deep pond 

tishing and recreatiooal area by the state of Florida. 

Commercial Applications: 

The IGCC system being demonstrated in this project is 

suitable for new electric power generation, repowering 

needs. and cogeneration applications. The net effective 

heat rate for the Texaco-based IGCC is expected to be 

below 8,500 Btu/kWh, which makes it very attractive for 

baseload applications. Commercial ICiCCs should 

achieve better than 98% SO, capture with a NOx emissions reduction of 90%. 

The Texaco-based system has already been pmven 

capable of handling both subbituminous and bituminous 

coals. This demonstration project is scaling up the technology from Cool Water’s lOOMWe system to the 250- 

MWe size. 

Advanced Ekaric Pomr Genemtim I7 
Advanced Electtic Power Generation 

totegrated Gasification Combined Cycle 

Wabash River Coal 

tfkf&&ion Repowering 

Participant: 

Wabash River Coal Gasification Repavering Project 

Joint Venture (a joint ventun of Destec Energy, Inc., and 

PSI Energy, Inc.) 

Additional Team Members: 

PSI Energy, Inc.-host 

Destec Energy, Inc.+ngineer, gas plant operator, and 

technology supplier 

Location: 

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

Wabash River Generating Station, Unit 1) 

Technology: 

Integrated gasification combined-cycle (IGCC) using 

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

Plant Capacity/Production: 

262 MWe (net) 

Project Funding: 

Total Project cost w38,2oo,m 100% 

DOE 219,100,ooO 50 

Participant 219,100,000 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, 

and maintainability of the system at a fully commercial 

scale. 

I8 

Technology/Project Description: 

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

pressurized, two-stage (slagging tint stage and now 

slagging entrained-flow second stage), oxygen-blown, 

gasifier. The product gas is cooled through heat exchangers and passed through a conventional cold gas 

cleanup system which removes particulates, ammonia, 

and sulfur. Tbe clean, medium-Btu gas is then reheated 

and burned in an advanced 192-MWe (gross) gas hw 

bine. Hot exhaust from the gas turbine is passed through 

a heat recovery steam generator to pmduce high-pressure 

steam. High-pressure steam is also produced from the 

gasification plant and superheated in the heat recovery 

steam generator. The combined high-pressure steam 

flow is supplied to an existing 104-MWe (gross) steam 

turbine. 

The process has the following subsystems: a coalgrinding and sluny system, an entrained-flow coal gasifier, a syngas beat recovery system. a cold gas cleanup 

system which produces a marketable sulfur by-product, 

a combustion turbine capable of using coal-derived fuel 

gas. a heat recovery steam generator, and a repowered 

steam turbine. 

One of six units at PSI Energy’s Wabash River 

Generating Staticm, located in West Terre Haute, IN, is 

being repowered. The demonstration unit will be designed to generate 262 MWe (net) using 2,544 tons/day 

of high-sulfur (2.3-5.9% sulfur), Illinois Basin hituminous coal. The anticipated heat rate for the repavered 

unit is appmximately 9,ooO Btu/kWb (38% efficiency). 

Using high-sulfur bituminous co& SO, emissions are 

expected tube less than 0.1 lb/million Btu (98% reducAdvanced Electric Power Generation 
calendar Year 

1991 1992 1993 1994 ,695 1997 ,538 1999 *ma 203 

3 4 1 234 1 234 1 234 1 2341 2-3 4 1 2 3 4 1 2 3 4 1 234 1 234 12 

9191 7/92 11195 2ls9 

‘I 1 

T 

$ 

Operatbn initiated 11195 

cons- completed 11195 

Prec+3railo”al lens initiated 8195 

Design comp!eted 594 

ENmmental monitoring plan completed 7f9iW 

Groundbreaki”g ceremo”y 7”/93 

Ii Pmjen mmpletedilinal report issued Z&3 

opmtll cmpleted 1 Ins’ 

NEPA process mmpleted (EA) W&33 

CKQerative agreement awarded 7lz* ‘PmjeLted date 

tion). NOx emissions are expected to be less than 

0.1 lb/million Btu (90% reduction). The project represents the largest single-train IGCC plant in operation in 

the world. 

Project Status/Accomplishments: 

The plant began commercial operation in November 

1995. Through July 1996, the plant has operated more 

than 1,000 hours on syngas in combined-cycle mode and 

has pmduced almost 170,000 MWh of elecuicity on 

syngas. ‘I’he combustion turbine has demonstrated 192 

MWe (100% of nameplate) and the gasifier has demonstrated 1,825 million Bhuhr, HHV (103% of nameplate). 

T%e longest continuous operation on syngas was 151 

hours. The primary problem area has been the reliability 

of the paticulate removal system, primarily due to 

bnakage of ceramic candle filters. Further testing and 

modifications to the patticulate removal system are 

under way to minimize element breakage. 

Commercial Applications: 

Throughout the United States, ptuticularly in the Midwest and East, there are more than 95,0@3 We of existing coal-tired utility boilers that will be over 30 years old 

in 1996. Many of these aging plants are without air 

pullution contmls and are candidates for repuwering 

with IGCC technology. Repuwering these plants with 

IGCC systems will improve plant efficiencies and reduce 

SO,. NO, and CO, emissions. The modularity of the 

gasifier technology will permit a range of units to be 

considered fur repuwering. and the relatively short construction schedule for the technology will allow utilities 

greater flexibility in designing strategies to meet load 

requirements. Also, the high degree of fuel flexibility 

inherent in the gasifier design will provide utilities with 

more choice in selecting fuel supplies to meet increasingly sttingent air quality regulations. 

Due to the advantages of modularity, rapid and 

staged on-line generation capability, high efficiency. fuel 

flexibility. envimnmental contmllabillty, and reduced 

land and natural resource needs, the IGCC system is also 

a strung contender for new electric paver generating 

facilities. Commercial offerings of the technology will be 

based on a 300.MWe train which is ideally suited to 

utility-scale paver generation applications. The system 

heat rate for a new power plant based on this technology 

is expected to realise at least a 20% improvement in 

efficiency compared to a conventional pulverised-coaltired plant with flue gas desulfurization. The improved 

system efficiency also results in a similar decrease in 

CO,emissions. 

Advanced Ekcwic Power Generation 19 
Advanced Electric Power Generation 

Advanced Combustion/Heat Engines 

Healy Clean Coal Project 

Participant: 

Alaska Industrial Development and Export Authority 

Additional Team Members: 

Golden Valley Electric Association-host utility 

Stone and Webster Engineering Carp--engineer 

TRW, Inc.--technology supplier 

Joy Technologies, Inc.-technology supplier 

Location: 

Healy, Denali Borough, AK (adjacent to Healy Unit #I) 

Technology: 

TRW’s advanced entrained (slagging) combustor 

Joy Technologies’ spray dryer absorber with sotbent 

recycle 

Plant Capacity/Production: 

50 MWe (nominal electric output) 

Project Funding: 

Total pmject cost %242,058,000 100% 

DOE 117.327,OOO 48 

Participant 124,731,ooo 52 

Project Objective: 

To demonstrate au innovative new power plant design 

featuring integration of au advanced combustor and heat 

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

Technology/Project Description: 

The project is to be a nominal 50.MWe facility consisting of two pulvetized-coal-tired cotnbustor 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. Additional SO, will 

be removed using Joy’s activated recycle spray dryer 

absotbeer system. Performance goals are NOx emissions 

of less than 0.2 lb/million BN, particulate emissions of 

0.015 lb/million Btu, and SO, removal greater than 90%. 

The perfottuauce coal consists of 35% run-of-mine aud 

65% waste coal, with the waste coal having a lower 

heating value and significantly more ash. 

A coal-fired precombustor increases the air inlet 

temperaN= for optimum slagging pcrfonuance. The 

boiler hopper. The main slagging combustor consists of 

TRW slagging combustors are bottom-mouuted on the 

a watewx&d cylinder that slopes toward a slag opening. The precombustor bums 21-4096 of the total coal 

input. Tbe remaining coal is injected axially into the 

combutior, rapidly enhaiued by the swirling precombustor gases and additional air flow, and burned under 

substoicbiometric (fuel-rich) conditions for NOx control. 

The ash forms molten slag which accumulates on the 

water-cwled walls and is driven by aerodynamic and 

gravitational forces through a slot into the slag recovery 

section. About 7C-80% of the coal’s ash is rr.moved as 

molten slag. The hot gas is then ducted to the furnace 

where, to ensure complete combustion, additional air is 

supplied from the tertiary air windbox to NO, potis and 

to final overtire air ports. 

20 Advanced Etecnic Power Gnvnuion 
12 m9 4&l 

‘I 

1 

t f 

I 

i$z%= 

awarded 41 Ii91 

Desip 

started ma 

OE s.&cted Pm+cl 

:: x34II) 12mm9 

I 

yu. brea&@o,~ 

NEPA P-55 ccmpletod (EIS) WI0194 

Design canpled law 

1198 S/O1 

I ‘a 

t 

Pmject cump(et&f-aI 

repoltisswd E&9’ 

OOE cost-shamd aperati~l 

completed se3 

peratbn initiated t/98’ 

2 yn d operationai 

data pmtided a, TW) 

CoMtNclion c.mplel.3d s&7 additional cat 

8/O,’ 

Preoperational tests inWeed 6197’ 

‘Prc+zted date 

“Yean omkted 

mixture of this lime (CaO) and the ash not slagged. called 

F’ulverized limestone (C&O,) for SO, control is fed 

flashalcined material, is removed in the fabric filter 

into the combustor where most is flash calcined. The 

(baghouse) system. A small part of the flash-calcined 

material is disposed of, but most is conveyed to a mixing 

tank where water is added to form a 45% flash-calcinedmaterial solids shmy. The slurry leaving the mixing tauk 

is pumped to a grinding mill where it is mechanically 

activated by abrasive grinding. Feed slurry is pumped 

from the feed tank to the spray dryer absorber where the 

slurry is atumized using Joy dry scrubbing technology. 

SO, in the flue gas reacts with the slurry droplets as 

water is simultaneously evaporated. SO, is further removed from the flue gas by reacting with the dry flashcalcined material on the baghouse filter bags. 

pollutant monitoring program will also be implemented. 

will collect performance data for 3 years, with 2 years of 

To address concerns about potential impact to the 

nearby Denali National Park and Preserve, DOE. the 

data being provided at no cost to DOE. 

National Park Service, WEA, and the project participant entered into an agreement to reduce the emissions 

A hazardous air 

from Unit #I so that the combined emissions from the 

two units will be only slightly greater than those currently emitted fmm Unit #I alone. Total site emissions 

will b-e further reduced to current levels if necessary to 

protect the park. 

Project Status/Accomplishments: 

Erection of stmctural steel is vinually complete. On-site 

fabrication of the spray dryer absorber system is complete as is the erection of the stack. Installation of the 

coal-handling, slagging combustor, boiler systems. and 

mechanical and electrical tie-ins to Unit No. I are pmceeding on schedule. 

Commercial Applications: 

This technology has a wide range of applications. It is 

appropriate for any size utility or industrial boiler in new 

and retrofit uses. It can be used in coal-fired boilen as 

well as in oil- and gas-tired boilers because of its high 

ash removal capability. However, cyclone boilers may 

be the most amenable type to retrofit with the slagging 

combustor because of the limited supply of high-Btu. 

low-sulfur, low-ash-fusion-temperature coal that cyclone 

boilers require. The commercial availability of costeffective and reliable systems for SO,, NO, 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. 

The project site is adjacent to the existing Healy 

Unit #I near HeaIy, AK. Power will go to the Golden 

Valley Electric Association (GVEA). The plant will use 

a nominal 900 tons/day of subbituminous coal containing a nominal 0.2% sulfur and waste coal. The project 

Advanced Electric Power Generarim 21 
Advanced Electric Power Generation 

Advanced Combustion/Heat Engines 

Coal Diesel Project 

Participant: 

Arthur D. Little, Inc. 

Additional Team Members: 

University of Alaska at Fairbanks-host and cofunder 

Cooper Energy Services (Cooper-Bessemer 

Recipmcating Products Division is a division of 

Cooper Energy Services which is owned by Cooper 

IudushiesJ-engine supplier and conmercializer 

CQ Inc.-coal-slurry supplier 

PSI-cleanup system designer 

AMBAC Iutemational~oal-water fuel injection system 

components supplier 

Usibelli Coal Company-coal supplier 

Location: 

Fairbanks, Alaska (University of Alaska facility) 

(Pending DOE approval) 

Technology: 

Cooper-Bessemer’s coal-t&led diesel engine 

Plant Capacity/Production: 

6.3 hfWe (net) 

Project Funding: 

Total project cost $38,309,516 

DOE 19.154.758 

Participant 19J54.758 

Project Objactive: 

100% 

50 

50 

To demonstrate an advanced, coal-fueled diesel engine 

syskm baud on Cooper-Bessemer’s LSB/LSVB diesel 

engine series. To provide critical data on the performance. reliability. and wear information of all major 

subsystems. 

Technology/Project Description: 

The project involves modifying a Cooper-Bessemer 

medium-speed (400 rpm) diesel engine to operate. on 

coal-water fuel. Engine modifications include a larger 

camshaft and fuel cams. modified engine block, hardened piston rings and liners, and hardened turbocharger 

blades. The system utilizes a coal-water fuel having a 

nominal 50% solids loading with a 2.5% ash cleanedcoal. The subbituminous Alaskan coal is ground and 

dried using an advanced hot-water drying process. Tbe 

dried product is further ground and slunied with water 

and then injected into each of the engine’s 20 cylinders. 

The exhaust gases from the engine pass through an integrated emission-control system capable of reducing 

pollutants while protecting the engine’s Ntbocharger and 

maintaining high engine and overall system efficiency. 

The exhaust emission cleanup system incorporates 

cyclones to remove the larger paniculates, a selective 

catalytic recovery system for NO” control, a duct sorbent 

injection system for SO, control, and baghouse for final 

collection of ash particulates and spent sotint. 

22 Advanced Elecrtic Power Generation 

SfRJ+ 

COAL -+ 

WATER - 

SPACE HEATlNG 

supply steam for space heating. Critical data on perforThe exhaust gases pass through a waste heat boiler to 

mance, reliability, aud wear are being collected for all 

major subsystems including the coal-water fuel metering 

and injection system, medium-speed diesel, lube oil 

protection system, exhaust cyclone, turbocharger, waste 

heat boiler, and exhaust emission cleanup system. 
calendar Year 

1993 w94 ,995 19% 1997 1998 1999 2cca 2001 as? 2cm 

34123412341 2341 23412341 2 3 4 12341 2341 234 t2 

I 

I cooparative agreEmle”t awarded mm 

DOE s-selected project 

(CCT-“, %,Q3 

I 

Project Status/Accomplishments: 

Easton Utilities, the original host, withdrew from the 

project after reevaluating its long-term need for power. 

The participant plans to resite the project at the University of Alaska in Fairbanks, where the engine would 

operate on subbituminous Alaska” coals. A” extension 

until June 30. 1997. has been granted to complete restluctuing activities, obtain fitm financial commitments, 

and establish the schedule and milestones for the project. 

Design activities are ongoing. I” addition, fullscale single-cylinder coal fuel evaluation testing and 

component durability testing will continue at Cooper’s 

research engine facility in Mount Vernon, OH. 

Commercial Applications: 

The coal-fueled diesel engine is particularly suited for 

small (below 50 Mwe) electric power generation markets. Projected markets include small nonutility genemton and repawing applications for small coal-fired 

bailers. The “et effective heat rate for the matllre diesel 

system is expected to be 6,830 Bt”IHVh (48%). which 

Advanced Elecrric Power Generarim 

makes it very competitive with similarly sized coal- and 

fuel-oil-tired installations. Environmental emissions 

from commercial diesel systems should be reduced to 

levels between 50% and 70% below NSPS. 

The diesel system has already achieved more than 

200 hours of operation “sing coal-water fuel in a 

6-cylinder engine at Cooper’s test facilities in Ohio. 

Over 6,000 hours of coal-water fuel operation in the 20. 

cylinder engine are planned for this project. Demonstration of the long-term reliability of the critical components in the diesel system will provide power producers 

with a” efficient and environmentally superior option for 

future power. 

23 
Advanced E/e&c Power Generation 

Advanced CombustionHeat Engines 

Externally Fired CombinedCycle Demonstration Project 

Participant: 

Pennsylvania Electric Company 

Additional Team Members: 

Hague International-technology developer and supplier 

Black & Veatch--engineer and co”st~ction manager 

Location: 

Site under negotiation 

Technology: 

Hague International’s externally tired combined-cycle 

(EFCC) system using a novel, high-temperature, ceramic 

gas-to-air heat exchanger 

Plant Capacity/Production: 

5 MWe slipstream 

Project Funding: 

Total project cost $146,832,0Cil 100% 

DOE 73,416,ooO 50 

Participant 73,416,OOO 50 

Project Objective: 

To demonstrate an externally tired combined-cycle system through the use of a novel ceramic heat exchanger 

and to assess the system’s envimnmental and economic 

perfotmance for meeting future energy needs. 

Technology/Project Description: 

bine to form a combined-cycle system. The central 

Feature of the EFCC is a ceramic air heater or heat exIn this project, a” existing coal-fueled steam plant is 

changer (CerHxe) and a” atmospheric combustor which 

together replace a conventional combustion system in a” 

being repowered by adding a” externally tired gas UTopen-cycle gas turbine. 

desulfurizer and a fabric filter before exiting to the ahnoheat is extracted to drive a steam turbine generator and 

sphere through the stack. The hot air from the CerHxm is 

passed through a gas turbine to produce additional elecproduce electricity. The product gas is finally passed 

tricity before being fed to the wmbustor. 

through a gas cleanup system consisting of a flue gas 

The attractiveness of the EFCC lies in its ability to 

eliminate the need for a hot gas cleanup system to protect the costly gas turbine gas-path compone”ts from the 

corrosive and abrasive elements in the combustion pm& 

uct gas. Instead, the gas turbine operates on indirectly 

heated clean air and the gas path is never exposed to the 

corrosive elements in the fuel or product gas. Ihe 

cerHxe raises the temperahlre of the air to the turbi”e 

Coal is first combusted in a staged combustor for 

NO” control. Particulate-laden gases exit the combustor 

and enter the slag screen where all particles larger than 

about 10 microns are collected. Air from the turbine 

compressor is heated by exchange with the hot product 

gas in the CerH9. The product gas is then passed 

through a heat recovery steam generator where more 

cerkti n a registmd u*m* Of “ague lntemarjonat 

24 AdvMccd E&ctric Power Gcnemrion 
camr Year 

ms3 1994 1995 19% 1997 ,999 MM) 2001 2lm 2ow 

3 4 1 2 3 4 12341 23412341 :“3 4 1 234123412341 234 12 

I ‘NEPA P- corMted (EA) 5.48195 

iYi+%alive agreemen( ewalr&d aws4 

-3E seleaed pm+& (XT-V) Y4,33 

inlet conditions using tube elemenu that are manufactured from cmmsion resistans toughened, ceramic materials. 

Potential SO, release is reduced by more than 90% 

through capture in the flue gas desulfurization system. 

NO, emissions are expected to be less than 0.13 lb/ 

million Btu. 

Project Status/Accomplishments: 

In May 1995, Pennsylvania Electric stopped all project 

activity due to lack of progress in resolving technical 

issues relating to the ceramic heat exchanger. The utility 

has announced it will not pursue the full-scale EFCC at 

Warren Station. However, the utility has proposed demonstration of a scaled-down EFCC in a slipstream at its 

Seward Station. Hague International is seeking nonfederal funds to continue developmental testing of the 

ceramic heat exchanger at the Kennebunk facility. 

Commercial Applications: 

The EFCC system concept is suitable For new electric 

power generation, repowering needs, and cogeneration 

applications. The potential commercial market for 

EFCC systems is expected to te about 24 GWe by 2010. 

The net effective heat rate For a 300~MWe greenfield 

plant using this technology is projected to be 7,790 Btul 

kWh. ‘Ibis represents a 20% increase in thermal effciency compared to a conventional pulverised coal plant 

with a scrubber. 

SO, emissions are expected to bc less than 0.081 lb/ 

million BN, which is a reduction of more than 90% for 

most coals. NO,emissions are expected to be less than 

0.15 lb/million Btu, and particulate emissions are expected to be less than 0.015 lb/million BN. 

Advanced Electric Power Generation 25 
Environmental Control 

Devices 

Fact Sheets 
Environmental Control Devices 

NO, Control Technologies 

Demonstration of Coal 

Reburning for Cyclone Boiler 

NOx Control 

Project completed. 

Participant: 

The B&cock & Wilcox Company 

Additional Team Members: 

Wtsconsin Power and Light Company-cotimder and 

host 

Sargent and Lundy--engineer for coal handler 

Electric Power Research Institute-&under 

State of Illinois, Department of Energy and Natural 

Resources-cofunder 

Utility companies (14 cyclone boiler operators)- 

cof”“ders 

Location: 

Cassville, Grant County, WI (Wisconsin Power and 

Light Company’s Nelson Dewey Station, Unit No. 2) 

Technology: 

The Babceck & Wilcox Company’s coal-rebuming 

system 

Plant Capacity/Production: 

100 MWe 

Project Funding: 

Total project cost $13,646,609 109% 

DOE 6.340.788 46 

Participant 7.305.821 54 

Project Objective: 

To evahmte the applicability of rebuming technology for 

reducing NOx emissions from a full-scale coal-tired 

cyclone boiler, pulverizing a portion of the primary coal 

28 

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

achieve greater than 50% reduction in NO. emissions 

with no serious impact on cyclone combustor operation, 

boiler efficiency, boiler fireside perfonance (corrosion 

and deposition), or ash removal system petformauce. 

Technology/Project Description: 

The coal-rebuming process reduces NO. in the furnace 

through the use of multiple combustion zones. The main 

combustion zone uses 7&80’% of the total heat equivalent fuel input to the boiler and slightly less than normal 

combustion air input. The balance of the coal (20-3095). 

along with significantly less than the theoretically determined requirement of air, is fed to the rebuming zcme 

above the cyclones to create an oxygen-deficient condition. The NO, formed in the cyclone burners reacts with 

the resultant reducing flue gas and is converted into 

nitrogen in this zone. The completion of the combustion 

process occurs in the third zone, called the bumout zone, 

where the balance of the combustion air is intmduced. 

The combined production of boiler slag and dry waste 

from the electrostatic precipitator remains unchanged 

with coal rebuming because the required coal input for 

the same boiler Load is the same. 

The coal-rebuming technology can be applied with 

the cyclone burners operating within theirnonual, noncorrosive, oxidizing conditions. thereby miuimiziug any 

adverse effects of rebum on the cyclone combusmr and 

boiler performance. 

This project involved retmtitting an existing 

ItB-MWe cyclone boiler that is repnsentative of a large 

population of cyclone units. The boiler is located at 

Wisconsin Power and Light’s Nelson Dewey Station in 

Cawille, WI. 

Envimnmenral Control Devices 
Projecl Results/Accomplishments: 

Coal-t&urn tests were conducted to determine the reduction in NO, emissions for the coal-rebuming technology 

over a range of boiler loads varying from 37 MWe to 

118 MWe (nominal maximum boiler load is 110 MWe). 

Two coals were tested, namely, the design Illinois Basin 

bituminous coal (Lamar, 1.8% sulfur avg) and a western 

subbituminous coal (Powder River Basin, 0.6% sulfur 

avg). The bihlminous coal tests evaluated a fuel typical 

of the coals fired by utilities operating cyclones. The 

subbituminous coal tests evaluated coal switching for 

so, teduction. 

As a part of the test pmgram, scve.ral parameters 

were optitied over the load range ta achieve the optimum NOx reduction while keeping other variables, such 

as unburned carbon and carbon monoxide emissions, 

within reasonable limits. The optimized parameters 

included the split of boiler fuel between the rebum system and the cyclone burners. the rebum burner and the 

rebum zone stuichiometrks, the rebum burner pulverized 

coal fineness, flue gas recirculation. and economizer 

outlet 0,cuntent. Also, adjustments were made to the 

rebum burners and the over-tire air ports during the tests. 

With the Lamar coal, the boiler NO, emissions were 

reduced as follows: 

. 52% (to 290 ppm or 0.394 lb/million Btu)at 110 MWe 

. 47% (to 285 porn or 0.387 1Wmiltio” Btu) at 82 MWe 

. 36% (325 ppm or 0.442 lb/million BN) at 60 MWe 

With Powder River Basin coal, the NO” emissions 

were reduced a.5 follows: 

+ 62% (tu 208 ppm or 0.278 lb/million BN) at 110 MWe 

* 55% (tu 215 ppm or 0.287 lb/million BN) at 82 MWe 

. 53% (to 2213 ppm or 0.294 lb/million BN) at 60 MWe 

Rebum testing with both coals indicated that varying rebum zone stoichiomehy is the most critical factor 

in controlling NOx. Rebum wne stoichiomehy can b-e 

varied by altering air flow quantities to the rebum bumers, percent rebum heat input, flue gas recirculation flow 

rate, or cyclone stoichiometry. 

Burning subbituminous coal produced lower overall 

NOx emissions levels and higher NO= emissions reductions. This result is probably due tu the coal’s higher 

volatile content, which generates higher concentrations 

of hydmctin radicals in the rebum zone. Whh the 

rebum system contributing additional burning capacity 

for the cyclone bailer, the lower Btu content western fuel 

could be tired up to the full boiler load rating. 

Additional etTe.cts of coal rebuming on the retrofitted bailer follow: 

Loss of combustion cfticiency, due to increased unburned carbon, amounted to 1.5% at full load with 

bituminous coal and 0.3% with subbituminous coal. 

The perfommnce of the ESP remained constant even 

though its ash loading doubled. The increased ash 

consisted of larger sized particulates. 

The furnace exit gas temperature decreased by more 

than 100 “F at full load, contrary to expectations. and 

thus improved the boiler heat absorption efficiency 

wmspo”di”gly. 

Slagging and fouling were significantly reduced with 

bihlminous coal rebuming. The subbihlminous rebum 

operations were too short in duration to make a teasonable observation. 

No fnmace corrosion was observed over the I-year 

test pxiod. 

Hazardous air pollutants (HAP) testing was perfomxd 

using Lamar test coal. HAP emissions were generally 

well within expected levels and emissions with rebum 

comparable to baseline opaations. 

Commercial Applications: 

The current rebum market is “early 26,GOO Mwe and 

consists of about 120 units ranging from 100 MWe to 

1,150 Mwe, with must in the lOC-300.MWe range. 

Coal rebuming is a rctmftt technology applicable across 

the size range of utility and industrial cyclone boilers. 

The principal environmental benefit is reduced NO= 

emissions. A secondary benefit may be reduced SO, 

emissions by enabling greater use of lower sulfur western 

coal: due to its lower BN content, western coals limit 

cyclone capacity. With the additional tiring capacity of 

the rebum system, full-load performance on western coal 

may be possible for some cyclone units. 

For cyclone boilers. coal rebuming offers a NOx 

reduction alternative at a cost expected to be in the range 

of $65ikW for loOMWe units to $4O/kW for a larger 

600.MWe unit. This includes costs for coal handling 

and pulvetizersJcoal piping. Coal’s cost differential and 

dependability of supply give it the long-run advantage 

over natural gas. Another advantage of the rebum system is its ability to utilize different coals. 

Project Schedule: 

DOE selected project (CCT-II) 9/28/88 

cooperative agreement awarded 4l2J90 

NBPA process completed @A) 2/12/91 

Environmental monitoring plan completed 11/18/91 

Construction 11/90-11/91 

Opel-atio”al testing 11/91-12I92 

Project completed 3l94 

Final Reports: 

Final Technical Report 2/94 

(includes economic information) 

Public Design Report 8/91 

Environmental Control Devices 29 
Environmental Control Devices 

NO” Control Technologies 

Full-Scale Demonstration of 

Low-NOx Cell Burner Retrofit 

Project completed. 

Participant: 

The B&cock & Wilcox Company 

Additional Team Members: 

The Dayton Power and Light Company-zofunder and 

host 

Electric Power Research Institute--cofunder 

Ohio Coal Development Off&-cofunder 

Tennessee Valley Authotity-cofunder 

New England Power Company--cofunder 

Duke Power Company--cofunder 

Allegheny Power System--cofunder 

CenteriorEnergy Corpaation-cofunder 

Location: 

Aberdeen, Adams County, OH (Dayton Power and Light 

Company’s 1.M. Stuart Plant, Unit No. 4) 

Technology: 

The. B&cock&Wilcox Company’s low-NO, cell burner 

(LNCB*) system 

Plant Capacity/Production: 

605 MWe 

Project Funding: 

Total project cost 

DOE 

Participant 

$11.233,392 100% 

5,442,800 48 

5.790,592 52 

LNCS is a registered wademark Of The Bakak & Wilcox Company. 

30 

Project Objective: 

To demonstrate through the first commercial-scale full 

burner retrofit the cost-effective reduction of NO, from a 

large base-load coal-tired utility boiler with LNCB* 

technology; and to achieve at least a 50% NO, reduction 

without degradation of boiler perfom~ance at less cost 

than conventional low-NOx burners. 

Technology/Project Description: 

The LNCB’ technology replaces the upper coal nozzle of 

the standard two-nozzle cell burner with a secondary-air 

port. The lower burner coal nozzle is enlarged to the 

same fuel input capacity as the two standard coal nozzles. 

The LNCB’ operates on the principle of staged combustion to reduce NOx emissions. Approximately 70% of the 

total air (primary, secondary, and excess air) is supplied 

through or around the coal-feed nozzle. The remainder 

of the air is directed to the upper pat of each cell to 

complete the combustion process. The fuel-bound uitmgen compounds are converted to nitrogen gas, and the 

reduced flame temperature minimizes the formation of 

themat NO,. 

The net effect of this technology is greater than 50% 

reduction in NO, formation with no boiler pressure part 

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

most commercial and emerging SO, control technologies, 

including confined zone dispersion, gas suspension absorption, duct injection, and advanced wet scrubbers. 

The demonstration was conducted at a large-scale 

power plant operated by The Dayton Power and Light 

Company and jointly owned with the Cincinnati Gas and 

Environmental Conrrol Devices 
Electric Company end the Columbus Southern Power 

Company. The boiler unit is a Balxock & Wilcoxdesigned, supercritical, once-through boiler equipped with 

an electrostatic precipitator. This unit contained 24 

two-nozzle cell burners arranged in an opposed-fidng 

configumtion. ‘&v&e burners (arranged in two rows of 

six burners each) were mounted on each of two opposing 

walls of the boiler. All 24 standard cell burners were 

removed, and 24 new LNCB@ were installed. Alternate 

LNCBm on the bottom rows were inverted, with the air 

port then being on the bottom to insure complete combustion in the lower furnace. 

Project Resuits/Accomplishments: 

The initial test results on the LNCB* were disappointing. 

Reducing gases containing high concentrations of carbon 

monoxide and hydrogen suffide accumulated in the lower 

furnace below the burners, and the NO, emissions reduction was only about 35%. By numerically modelling 

several possible burner configurations, B&cock & Wilcox was able to select an optimum new burner arrangement On the lower row of burners, alternate LNCB* 

were invetted so that the air potts integral to these bumem directed air into the lower fiunace. Also, a design 

chaoge for the burners’ coal impellers increased the NO= 

reduction tn above the design goal. 

The LNCBe demonstration emphasised evaluation 

of boiler performance, boiler life, end environmental 

impact. Key boiler performance parameters included 

boiler output (steam tempzatmes); flue gas temperatures 

at UK furnace. economizer, and air heat exits; the 

slagging tendencies of the unit; and unburned carbon 

losses. Boiler life potentials (corrosion tendencies) were 

measured by gas sampling for high H$ concentrations in 

the furnace, ultrasonic testing of lower furnace tube 

walls, and destructive examination of a corrosion test 

panel. Environmentally, NOx, CO, CO,, total hydmcwbuns. end particulate matter were measured at varying 

test co”ditio”s. 

Environmenml Contml Dtwices 

At full load (605 Mwe) with all mills in service, 

average NOx emissions were 0.53 lb/million Btu, a 

54.4% ttduction horn the baseline. CO emissions 

ranged from 28 to 55 ppm. Flyash unburned carbon 

averaged 1.12%. for a 0.2% loss unburned c&on efficiency. This is a 56% improvement over baseline unburned carbon losses, pmbably resulting from improved 

air flow distibution achieved by the LNCB* retrofit. At 

reduced loads of 460 Mwe and 350 MWe. the NOr 

emissions reductions were 54% and 48% respectively, 

and CO emissions and unburned carbon values were 

comparable with baseline emissions. 

Long-term NOx emissions data were accumulated 

using a third-party continuous emissions monitor over an 

8-month test period that followed the parametric and 

optimization test periods. On days when the boiler was 

operating at 590 MWe OT above. end with all mills in 

service, NO” emissions averaged 0.49 lb/million Btu, a 

58% reduction from baseline emissions. This data set 

covered 79 days. 

Overall unit efficiency remained essentially unchanged from baseline to optimized LNCB* burner 

operation. The demonstration boiler is operating at a 

lower overall excess air since the optimization testing, 

which has reduced the dry gas loss and increased the 

boilerefficiency slightly. 

A corrosion test panel was installed when the 

LNCBe burner were installed. The panel consisted of 

SA-213T2 bare tube material with some of this material 

ah~mhtized, some stainless weld overlaid, and some 

chmmized. Tbe level of corrosion is roughly equivalent 

to the boiler’s cormsion prior to the retrofit. The coated 

materials had no loss. 

The LNCB. project received the 1994 R&D 100 

Award for technical excellence in a new commercial 

product. 

Commercial Applicetions: 

The low cost and short outage time for retrofit make the 

LNCB4 design attractive. Typically, the retrofit capitalcost will be $5.5&$8.00&W in 1993 dollars, based upon 

DOE’s 500-MWe reference unit. The outage time can be 

as shott as 5 weeks because of the ‘plug-in” design. The 

LNCB@ system can be installed at about half the cost and 

outage time for other commercial lawNOx burner installations. 

Dayton Power & Light has retained the LNCB* 

burners for use in commercial operation at the unit. 

There have been eight commercial sales of LNCBe 

burners. 

Project Schedule: 

DOE selected project (CCT-III) 12/19/89 

Cmpemtive agreement awarded 10/11/90 

NEPA process completed (MTF) woi90 

Environmental monitoring plan completed 8/9/9 1 

Co”sttuctio” g/91-11191 

Gperational testing 12/91-4/93 

Project completed IzJ95 

Final Reports: 

Final Technical Report 12l95 

(includeseconomicinformation 

and corrosion test results) 

Public Design Report 8/91 

31 
Environmental Confm/ Devices 

NO, Control Technologies 

Evaluation of Gas Reburning 

and Low-NO Burners on a 

Wall-Fired Bhiler 

Project completed. 

Participant: 

Energy and Environmental Research Corporation 

Additional Team Members: 

Public Service Company of Colorado-zofunder and host 

Gas Research Institite-cofunder 

Colorado Interstate Gas Company-coftmder 

Electric Power Research Institute~ofunder 

Location: 

Denver, Adams County, CO (Public Service Company of 

Colorado’s Chemkee Station, Unit No. 3) 

Technology: 

Energy and Environmental Research Corporation’s gas 

rebuming (GR) system 

Foster Wheeler’s low-NOx burners (LNB) 

Plant Capacity/Production: 

172 MWe 

Project Funding: 

Total project cost 

DOE 

Participant 

$17.807.258 Iowa 

8,895,790 50 

8,911,468 50 

Project Objective: 

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

from an existing wall-fired utility boiler tiring low-sulfur 

coal using both gas reburning and low-NOx burners 

(GR-LNB). 

Technology/project Description: 

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 tiring creates a slightly fuelrich zone. NOx drifting upward from the lower region of 

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

molecular nitrogen. Low-NO, burners positioned in the 

coal combustion zone retard the pmduction of NO” by 

staging the burning process so that the coal-air mixture 

can be carefully controlled at each stage. The synergistic 

effect of adding a rebuming stage to wall-fired boilers 

equipped with low-NOx burners lowers NO, emissions 

by up to 70%. Gas rebuming was demonstrated with 

and without the use of recirculated flue gas, on a gas/gas 

firing mode and with optimized ovefire air. 

The project site is Public Service Company of 

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

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

burners on a 172~MWe wall-tired utility bailer. Western 

bituminous coals containing 0.354.66% sulfur were 

used in this demonstration. 

32 
Projact Results/Accomplishments: 

Parametric and long-term testing was conducted fmm 

October 1992 to January 1994 during more than 4,ooO 

hours of operation. The results showed that for the first 

genemtion GR-LNB, average NO% reductions of 37% 

(0.46 lb/million Btu) was achieved with the LNB alone 

and 65% (0.26 lb/million BN) with GR-LNB at an 

average gas input of 18% of total heat input. The second 

generation system showed average NO, reductions of 

37% for LNB and 64% for GR-LNB at an average gas 

heat input of 13%. The boiler efficiency decreased by 

approximately 1% during gas rebuming due to moisture 

in the fuel aud au increase in heat loss due to moisture 

formed in combustion. There was no measurable boiler 

tube wear resulting from CR-LNB operation and, in 

general, the tubes were free from slagging. 

Based on the demonstration and the data collected, 

the technology can be applied to utility and industrial 

units. The participant expects that most GR-LNB instal&ions will achieve 60% NO* reductions when tiring 

l&15% gas. The capital cost for units of 100 MWe or 

larger is approximately $lS/kW plus the cost of a gas 

pipeline. Operating costs are almost entirely related to 

the differential cost of gas over coal as reduced by the 

value of SO, emissions credits. 

The Public Service Company of Colorado retained 

the gas-rebuming system and associated controls. The 

low-NO, burners were also retained and repaired to 

reduce carbon-in-ash levels and thus improve the economic performance of the unit. The flue gas recirculation 

system was removed. 

Commercial Applications: 

Gas rebuming in combination with low-NO= burners is 

applicable to wall-tired utility and industrial boilers. 

The technology can be used in new and pre-NSPS walltired boilers. 

Specific features of this technology that increase its 

potential for commercialization are that it can be retrofitted to existing units. reduces NOx emissions by 70% or 

Envirormmtal Control Devices 

more. is suitable for use with a wide range of coals, has 

the potential to improve boiler operability and reduce the 

cost of electricity, consists of commercially available 

components, and 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 ret&it, repavering, or new, 

greenfield installations. There is no known limit to the 

size or scope of the application of this technology combination. Presently, the largest 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 othertechnology approaches. GR-LNB functions equally well with any kiud of coal. NO, 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 amount of natural 

gas that is substituted for coal. 

Project Schedule: 

DOE selected project (CCT-Ill) U/19/89 

Cooperative agreement awarded 10/31!90 

NEPA process completed (MTF) 916190 

Envimnmental monitoring plan completed 7/26/90 

Construction 6/91-6/92 

Opcmtional testing 10/92-l/95 

Restoration completed II/95 

Project completed 12l96 

Final Reports: 

Final Technical Report 1286 

(includes economic information) 

Public Design Report 9l96 

33 
Environmental Control Devices 

NO” Control Technologies 

Micronized Coal Reburning 

~h&mm$tration for NOx 

Participants: 

New York State Electric &Gas Corporation 

Additional Team Members: 

Eastman Kodak Company-host and cofunder 

Consol- tester 

D.B. Riley-technology supplier 

FullerCompany-technology supplier 

Energy andEnvironmental ResearchCorporationrebum system designer 

Locations: 

Laming, Tompkins County, NY (New York State Electric 

& Gas Corporation’s Milliken Station, Unit 1) 

Rochester, Monroe County, NY (Eastman Kodak 

Company’s Utility Power House, Unit 15) 

Technology: 

Advanced NO= control using D.B. Riley’s MPS mill and 

Fuller’s MicmMillTM technologies for producing 

micronized coal 

Plant CapscityiProduction: 

148 MWe (Millie” Station); 50 MWe (Eastman Kodak 

Compw) 

Project Funding: 

Total project cost 

DOE 

Participant 

$9.096,486 100% 

2,701,011 30 

6,395,475 70 

MicroMill u a VldemnrL 0‘ the Fuller compmy. 

34 

Project Objective: 

To reduce NO” emissions by 5-46 using micron&d 

coal as the rebuming fuel combined with advanced coalrebumingtechnology. 

Technology/Project Description: 

The rebuming coal, which can comprise up to 30% of the 

total fuel, is micmnized (80% below 325 mesh) and 

injected into a pulverized-coal-tired furnace above the 

main burner, the region where NOx formation occurs. 

Micronized coal has the surface area and combustion characteristics of an atomized oil flame, which 

allows carbon conversion within milliseconds and IXlease of volatiles at a more even rate. This uniform, 

compact combustion envelope allows for complete combustion of the coal/air mixture in a smaller furnace volume than conventional pulverized coal because heat rate. 

carbon loss, boiler efficiency, and NOx formation are 

affected by coal fineness. 

The combination of micmnized coal, supplying 

30% of the total furnace fuel requirements, and advanced rebuming, utilizing that requirement in conjunction with fuel/air staging, provides flexible options for 

significant combustion operations and environmental 

improvements. These options can prevent higher operating costs or furnace perfom~ance derating often associated with conventional environmental controls. 

New York State Electric&Gas Milliken Station, 

Unit 1, a 148-MWe tangentially fired bailer, is one host 

site, and Eastman Kodak Utility Power House, Unit 15. a 

50-MWe cyclone boiler, is the other host site. The 

Milliken site will “se the D.B. Riley MPS mill with dyEnvironmental Control Devices 
ca!s*r Year 

Is91 1532 1993 1994 ,535 ,997 ,998 1999 2cm 2001 

3412341 23412341 2 3 4 1 :“, 4 1 2 3 4 1 2 3 4 1 2341234 12 

DOE SBlected 

~;W&GCT-W 

Ground breakinp/construcWn started (Lansing) 3/15/96 

t 

t Project mmpletedJinal report issued 4W’ 

Rebum testing mmpk3ted (Lansing) IW98’ 

Environmental monitoring plan completed @.a~) 946 Operalion completed (Robester, 12/97 

Omund bresldngkmstnxtia stalted (Rochester) g/96’ Constixction completed (Laming) 10/97’ 

Design completed (Wi3wstw) 9i36 Operation inhiated (Roblester) Xl7 

NEPA p-s completed (CX) @I1332 Preqoerational tests initiated (Rochester) l/97 

Cmpemlive agreement awaded 7R&92 Rebum testing stated (Lansing) lOi% 

Environmental monitoring plan completed (Rochester) 12%’ 

C0”s1Ncticm completed (Rochester, la996 ‘Projected date 

namic classikiers to produce the micron&d coal. The r&urn at Milliken Station. Eastman Kodak and Fuller because of limited mill capacity would be able to reach 

coal will be rebumed for NOxcontrol using two methods. are working on preliminary design for the MicmMilP their maximum continuous rating. NOx emissions 

One method is close-coupled overfire air (CCOFA) installation at Kodak’s Rochester facility. Fuller is start- reductions will enable lost capacity to be restored, 

rebuming in which the top burner of the existing LowNOxConcentric Firing System (L.NCFSN) burners are 

used for burning the micron&d coal and the remaining 

burners are re-aimed. A second method being considered is to use the burners in a deep stage combustion 

mode and m-aim them to create bum and rebum zones. 

The third method is more standard and will use injectors 

to input micron&d coal into the boiler. At the Eastman 

Kodak site, the Fuller MicmMilP will be used to produce the micmnized coal, and injectors or burners, depending on boiler characteristics. will be used for the 

mbuting. Overtire air also will be installed. Both the 

injectowbumers and the ovefire air will be installed at 

the optimum point downstream of the cyclone burners. 

ing to place long-lead-time orders for pans to assemble 

the MicmMilP. Boiler chamcterization tests are being 

run on the Kodak boiler. 

Commercial Applications: 

Micronized-coal-rebuming technology can be applied to 

existing and greenfield cyclone-fired, wall-tired. and 

tangential-tired pulverized coal units. The technology 

reduces NO, emissions by W-60% with minimal furnace 

modifications for existing units. Forgreenfield 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 use of this technology. 

Project Status/Accomplishments: The availability of a coal-rebuming fuel, as an 

New York State Electric & Gas is in the process of be- additional fuel to the furnace, solves several problems 

ginning preliminary design to perform close-coupled concurrently. Existing units unable to switch fuels 

EnvimnmmrrJ Connol Devices 

creating a very economic source of generation. For both 

retrofit and greenfield facilities. rebum 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 bc operated on a variety of coals with 

improved performance. The combination of micronizedcoal-rebuming fuel and better pulvetizer performance 

will increase overall pulverized-fuel surface area for 

better carbon burnout. 

This demonstration will provide methods for NO, 

control at a low capital cost for utilities and industrial 

users to meet the current and upcoming NOxregulations. 

Utilities that install lawNOx burners to meet CAAA 

Title I requirements and must also meet Title IV 

requirements will have a low-cost option to choose. 

Industrial users being pressured by states to reduce NOx 

also will be provided a low-cost option, particularly 

cyclone users who are without lawNOx burners. 

3.5 
Envimnmental Contml Devices 

NO, Contml Technologies 

Demonstration of Advanced 

Combustion Techniques for a 

Wall-Fired Boiler 

Participant: 

Southern Company Services, Inc. 

Additional Team Members: 

Electric Power Research I”stiNte--cof”“der 

Foster Wheeler Energy Corporation-technology 

supplier 

Georgia Power Company-host 

Location: 

Coosa. Floyd County, GA (Georgia Power Company’s 

Plant Hammond, Unit No. 4) 

Technology: 

Foster Wheeler’s low-NO, burner (LNB) with advanced 

overftre air (AOFA) 

EPRI’s Generic NOx Control Intelligence System 

(GNOCIS) for plant optimizatia” 

Plant Capacity/Production: 

5cQ Mwe 

Project Funding: 

Total project cost $14,710.909 100% 

DOE 6.553.526 45 

Participant 8,157.383 55 

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

Project Objective: 

To achieve 50% NOr reduction with the AOFA/LNB 

system; to determine the contributions of AOFA and the 

LNB to NOr reduction and the parameters determining 

optimum AOFAILNB system perfmmance: and to assess 

the long-term effects of AOFA, LNB, and combined 

36 

L 

AOFA/LNB and advanced digital controls on NO,reduction and boiler performance. 

Technology/Project Description: 

AOFA involves (1) improving the mixing of overtire air 

with the furnace gases to achieve complete combustion, 

(2) depleting the air horn the burner zone to minimize 

NO, fcmnation, and (3) supplying air “ver furnace wall 

tube surfaces to prevent slagging and furnace corrosion. 

The AOFA technique was expected to reduce NO” endssinus by about 35%. 

In a” LNB, fuel and air mixing is controlled to preelude the formation of NO, This is accomplished by 

regulating the initial fuel-air mixture, velocities, and 

turbulence fo create a fuel-rich flame core and by co”- 

trolling the rate at which additional air required to cornplete combustion is mixed with the flame solids and 

gases so as to mainrain a deficiency of oxygen. Spical 

results for utilities indicate that LNB technology is capable of reducing NOx emissions by about 45%. 

Based on earlier experience, the use of AOFA in 

conjunction with LNB can reduce NO” emissions by as 

much as 65% compared with conventional burners. 

The demonstration is located at the Georgia Power 

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

nominal 5OOMWe pulverized coal, opposed wall-fired 

unit, which is representative of many existing pre-NSPS 

wall-tired utility boilers in the United States. The 

pmject also includes installation and testing of a” advanced digital control system that opthnizes LNB/AOFA 

perfonnauce using artificial inteIligence techniques. The 

project is using bituminous coal containing 3% sultix. 

Environmemd Control Devices 
caten&r Year 

19.38 1989 1990 1991 1532 ,993 1534 1995 1997 1998 

341234123412341 *3412341 2 3 4 1 2 3 4 1 :“3 4 1 234 12 

T 

DOE seleded 

prcf&WW 

I 

NEPA ProcesS 

-p’a*a 

bpratim initiated. LNB 4/91 

constructicn mmpkmd. LNB .4/w 

canstioil started, LNB 3/91 

Operabon mpkted, AOFA 3/91 

Envimmnental mnitodng plan mmpkted 9,14/90 

operatm imated. AOFA mQ 

constlLaon compbted. ADFA 5l90 

conrtNcdrJ” started. ADFA 4/90 

Deslg”eanpleted m 

Design and Consbuction 

I Operatim initiated. LNB/AOFA with d&l control system 6/W 

Operation mmpleted. UWAOFA W33 

Operation initiated. UWAOFA S/93 

‘Q.xmon c.2mplete-d. UiB II92 

~PrG+cted date 

mperatiw agreerent awardsd 12Rnl89 

Project Status/Accomplishments: 

Baseline, AOFA, LNL%, and LNBlAOFA test segments 

have been completed. Analysis of more than 80 days of 

AOFA operating data has provided statistically reliable 

results indicating that, depending upon load, NO” reductions of 24% are achievable under normal long-term 

operation. Analysis of the 94 days of LNB long-term 

data collected show the full-load NO, emission levels to 

be approximately 0.65 lb/million Btu. This NO, level 

represents a 48% reduction when compared to the 

baseline, full-load value of I .23 lb/million BN. These 

reductions were sustainable over the long-tarn test period and were consistent over the entire load range. Fullload, flyash loss-on-ignition values in the LNB contigura 

tion were near 8%. compared to 5% for baseline. Results from the LNB/AOFA testing indicate that full-load 

NO” emissions were approximately 0.41 lb/million BN 

with a corresponding flyash loss-on-ignition value of 

nearly 8%. Full-load. long-term NOx emission reductions in the LNBIAOFA conkiguration were about 63%. 

However, analysis of emissions data showed that the Pre-retrofit, LNB air toxics testing was performed 

incremental NOx reduction effectiveness of the AOFA to establish a baseline. Additional air toxics testing with 

system (beyond the use of the LNB) was approximately the combined LNBIAOFA configuration has been 

17% with additional reductions resulting fmm other completed. A report on this work was issued in Decemoperational changes. ber 1993. 

The new digital control system became operational 

in mid-1994, and testing of the GNOCIS for optimizing 

NO, reduction and boiler efficiency began in February 

1996. Although narrow parameters were placed on the 

recommendations that GNOCIS could provide, preliminary data analysis is encouraging, with an observed effi. 

ciency gain of 0.5%. a reduction in loss-on-ignition 

levels of l-3%. and a reduction in NO, emissions by 

lC-15% at full load. 

Commercial Applications: 

The technology is applicable in the United States for 

retrofitting the 422 existing pre-NSPS wall-ftred bailerr; 

these boilers bum a variety of coals. including biNminow. subbituminous. and lignite. Tbe GNOCIS technology is applicable to all fossil-htel-fired boilers. 

Short-term testing of the GNOCIS, in both openand closed-loop contigurations, and long-term closedloop testing will be conducted through fall 1996. The 

tinal pmject report and a report on testing of several online carbon-in-ash monitors are being prepared. 

Commercialization of the technology will be aided 

by the following characteristics: reduced NO, emissions 

by as much as 65%: competitive capital and operating 

costs; relatively easy retrofit; little or no denting of the 

boiler; use of commercially available components: and 

automatic control of boiler efficiency and maximum 

pollution abatement through use of artificial intelligence 

technology in conjunction with a digital control system. 

Environmental Convol Devices 37 
Environmental Control Devices 

NO” Control Technologies 

Demonstration of Selective 

Catalytic Reduction 

Technology for the Control of 

NO Emissions from HighSulbCoal-Fired Boilers 

Project completed. 

Participant: 

Southern Company Services, Inc. 

Additional Team Members: 

Electric Power Research Institute--cofunder 

OnttioHydwofunder 

Gulf Power Company-host 

Location: 

Pensacola, Escamhia County, FL (Gulf Power 

Company’s Plant Gist, Unit 4) 

Technology: 

Selective catalytic reduction @CR) 

Plant Capacity/Production: 

8.7~MWe equivalent (three ZS-MWe and six 0.2~MWe 

equivalent SCR reactor plants) 

Project Funding: 

Total project cost $23,22¶,129 100% 

DOE 9.406.673 40 

Panicipant 13,823,056 60 

Proiect Objective: 

To evaluate the perfomxmce of commercially available 

SCR catalysts when applied to operating conditions 

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

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

while achieving as much as 80% NOx removal. 

Technology/Project Description: 

The SCR technology consists of injecting ammonia into 

boiler flue gas and passing it through a catalyst bed 

where the NOx and ammonia react to form nitrogen and 

water Yapor. 

The project demonstrated, at high- and low-dust 

. loadings of flue gas, the applicability of SCR technology 

to provide a cost-effective means of reducing NOxemissions from power plants burning high-sulfur U.S. coal. 

The demonstration plant, which was located at Gulf 

Power Company’s Plant Crist near Pensacola, FL, utilized flue gas from the burning of principally Illinois 

No. 5 coal with approximately 3% sulfur under various 

NO” and particulate levels. 

In this demonstration project. the SCR facility consisted of three 2.5MWe-equivalent SCR reactors, supplied by separate 5,000 std ft’/min flue gas slipstreams, 

and six 0.20.MWe-equivalent 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 (two U.S., two 

European, and two Japanese) provided eight catalysts 

with various shapes and chemical compositions for 

evaluation of process chemistry and economics of operation during the operation. 

38 EnviroMvn~al Control Devices 
Project Results/Accomplishments: 

F’reliminay design engineering for the SCR test facility 

was concluded at the end of February 1991. Constmctie” began in late March 1992; a dedication ceremony 

was held on July 1,1992. Detailed engineering was 

completed in December 1992. Flue gas was first passed 

through the SCR facility during equipment checkout on 

January 10.1993. Const~ction was completed in February 1993. Commissioning tests without catalysts 

began the first week of March 1993, and the 2-year-long 

operations phase began on July 1,1993. The test period 

included parametric testing of each catalyst every 4-5 

months. The final report has been drafted, and the test 

facility has been dismantled. 

Upon completion of the initial parametric testing in 

December 1993, baseline measurements were obtained. 

These tests were completed during December 1993 and 

all catalysts perfotmed well at the targeted NO= removal 

rates with slip less than 2 ppm under baseline conditions 

(80% NO= removal) and in many cases the measured slip 

was below the 1 ppm detection limit. 

Project results indicate that all eight catalysts performed well in both parametric and long-term testing 

and that NO= removal rates of 80% or better, with acceptable ammonia slips, were achieved for all catalysts. 

Commsrcial Applications: 

SCR technology can be applied to existing and new 

utility applications for removal of NO, from flue gas for 

virtually any size boiler. Then are appmxitnately 

1,041 coal-fired utility boilers in active commercial service in the United States; these boilers represent a total 

generating capacity of 2%,000 We. Assuming that 

SCR technology is installed on dry-bottom boilers that 

are not equipped with low-NO% combustion technologies 

(Le., low-NO, burners, overlire air, and atmospheric 

fhidized-bed combustion), the potential total reamtit 

market for SCR technology is 154,560 MWe 

Envinmme~ti Control Devices 

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

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

(i.e., announced, sited, and committed in terms of service date or under const~ction) and 144,500 Mwe 

(290 boilers) of platmexi dry-bottom electric generating 

capacity in the United States. 

A number of successful commercial SCR installations that utilize catalysts &motWmted In this CCX 

project are now operational in the United States. As a 

result of this demonstration, utilities have a flue gas NOx 

removal technology that has the flexibility and removal 

capabilities to assist in meeting both Title N as well as 

Title I (ozone nonattainment) provisions of the CAAA 

of 1990. 

Project Schedule: 

DOE selected project (Cm-II) g/28/88 

coopenuive agreement awarded 6/14/90 

NJZF’A process completed (MTF) 8/16/89 

Environmental monitoring plan completed 3/11/93 

Co”stNctio” 3/92-2193 

operational testing 7/93-7l95 

Project completed 12196 

Final Reports: 

Final Technical Reporr 12/96 

(includes economic evaluation) 

Public Design Report n/96 

39 
Environmental Control Devices 

NO, Control Technologies 

180-MWe Demonstration of 

Advanced Tangentially Fired 

Combustion Techniques for 

the Reduction of NO, 

Emissions from Coal-Fired 

Boilers 

Project completed. 

Participant: 

Southern Company Services, Inc. 

Additional Team Members: 

Gulf Power Company-zofunder and host 

Electric Power Research Institute--cofunder 

ABB Combustion Engineering, Inc.--cofunder and 

technology supplier 

Location: 

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

Plant Lansing Smith, Unit No. 2) 

Technology: 

ABB Combustion Engineering’s Law-NO, Concentric 

Firing System (LNCFSTM) with advanced overtire air 

(AOFA), clustered coal nozzles, and offset air 

Plant Capacity/Production: 

180 MWe 

Project Funding: 

Total project cost $9.153.383 loo% 

DOE 4.440,184 49 

Participant 4.713.199 51 

---- 

L.NCFS is a trademark of AEm Cmlb”stio” Engineering. 1°C. 

40 

lProject Objective: 

To demonstrate in a stepwise fashion the short- and 

long-tam NO” reduction capabilities of Low-NO” Concentric Firing System Levels 1. II, and Ill on a single 

reference boiler under typical dynamic operating umditions. and evaluate the cost effectiveness of each 

low-NO” combustion technique. 

Technology/Project Description: 

Three different low-NOx combustion technologies for 

tangentially fired boilers were demonstrated. The concept of overtire air was demonstrated in all of these 

systems. In LNCFS Level I, a close-coupled overtire air 

(CCOFA) system is integrated directly into the windbox 

of the boiler. Compared to the baseline windbox configuration. LNCFSLevel I is arranged by exchanging the 

highest coal nozzle with an air nozzle immediately below it. This configuration provides the NO. reducing 

advantages of an overfire air system without pressure 

part modifications to the boiler. 

In LNCFS Level II, a separated overtire air (SOFA) 

system is used. This advanced overfire air system has 

backpressuring and flow measurement capabilities. The 

air supply ductwork for the SOFA is taketi off from the 

secondary air duct and routed to the comers of the furnace above the existing windba. The inlet pressure to 

the SOFA system can be increased above windbox pressure using dampen downstream of the takeoff in the 

secondary air duct. Operating at a higher pressure increases the quantity and injection velocity of the ova-fire 

air into the furnace. A multicell venhui is used to 

EnvirmmentaI Cmrrol Devices 
measure the amount of air through the SOFA system. 

LNCFS Level III utilizes both CCOFA and SOFA. 

In addition to overtire air, the LNCFSm 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 

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

varied using adjustable offset air nozzles. Separation of 

air and coal at the burner level further reduces production 

of NOx. 

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 pmvide a stepwise reduction in NO, emissions, with 

LNCFS Level III expected to provide the greatest mduction. 

Eastern bituminous coals from Kentucky, Illinois, 

and West Virginia, with an average sulfur content of 

Z-3.0%, were used. 

Project Results/Accomplishments: 

The results from the demonstration showed that, at full 

load, the NOx emissions using LNCFS I, II, and III were 

0.39.0.39, and 0.34 lb/million Btu respectively; these 

levels represented emission reductions of 37% 37%. and 

45%. respectively. from the baseline. These emissions 

are within the annual average emission limit of 0.45 lb/ 

million Bti established for tangentially fired bailers. 

Simulated load protiles showed that only LNCFSTM III 

could marginally meet the emission regulations at peak 

ing loads because of the significant increase in NOx emission for LNCFS technology below 100 MWe. 

Testing to investigate the effects of lawNOx combustion on the emissions of air toxics was also comEnvironmenral Conrrol Devices 

p&d. These tests showed that the LNCFS”,’ had little 

or no impact on the emissions of air toxics. 

Unit performance observations included increased 

CO emissions, reduced furnace slagging but increased 

back-paw fouling, and minimally impacted efficiency 

and heat rate. Further. unit operations were not sign& 

candy affected; however, operating flexibility of the unit 

was reduced at low loads with LNCFS II and III. 

The capital cost estimate for LNCFS I is $5-15/kW 

and for LNCFS II and III, $15-25&W. The cost effectiveness for LNCFS I was $103/tori of NO, removed; 

LNCFS II, $444/tori;; and LNCFS III, $4oO/ton. 

Commercial Applications: 

Commercial applications of this technology include a 

wide range of tangentially tired utility and industrial 

boilers throughout the United States and abroad. There 

are nearly 600 U.S. pulverized coal tangentially fired 

utility units. These units range in electric generating 

capacity from 25 MWe to 950 MWe. A wide range of 

coals, from low-volatile bituminous through lignite, are 

being fired in these units. LNCFSm 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 contml technologies are primarily 

based upon reducing NOxemissions from fossil-fueltired power plants. Potential exists for significant NO” 

emission reductions, depending on the unit load scenario 

and the level of technology selected. 

Gulf Power has retained the LNCFSm at its Plant 

Laming Smith Unit No. 2. The technology also is being 

used by other utilities, including the Tennessee Valley 

Authority, Illinois Power, Public Service Company of 

Colorado, Indianapolis Power and Light Cincinnati Gas 

and Electric, Virginia Power, Union Electric, and New 

York State Electric & Gas Corporation. 

Pro&t Schedule: 

WE selected project (CCT-II) 9t28l88 

Cooperative agreement awarded 9l2ol9rl 

NEPA process completed (MTF) 7/21/89 

Envimnmental monitoring plan completed 12/27/90 

Construction 1 l/90-5/91 

Operational testing 5/91-12J92 

Project completed 6i94 

Final Reports: 

Final Repofl and Key Project Findings 294 

(includes economic information) 

Measurement of Chemical Emissions Report 10193 

ESP Performance Analysis Report 9l93 

41 
Environmental Contml Devices 

SO2 Control TechnoIogies 

IO-MWe Demonstration of Gas 

Suspension Absorption 

Project completed. 

Participant: 

AirPol, Inc. 

Additional Team Members: 

FLS ndljo a/s (parent company of AirPol, Inc.+ 

te&nology owner 

Tennessee Valley Authority+funder and site owner 

Location: 

West Paducah, McCracken County, KY (Tennessee 

Valley Authority’s Center for Emissions Research) 

Technology: 

FLS tiljo a/s’ Gas Suspension Absorption (GSA) 

system for flue gas desultiuization (FGD) 

Plant CapacltylProduction: 

IO-MWe equivalent slipstream of flue gas from a 

ISO-MWe boiler 

Project Funding: 

Total project cost 

DOE 

Patticipant 

Project Objective: 

$7,717,189 100% 

2,315,259 30 

5,401,930 70 

To demonstrate the applicability of Gas Suspension 

Absorption for flue gas desulfurization using high-sulfur 

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

de-tion systm. 

Technology/Project Description: 

The GSA system consists of a vat&l 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 thmugh a” electrostatic precipitator (ESP) before being released to the 

atmosphere. The lime shmy, prepared fmm 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 sluny is controlled by 

on-line “leas”re”le”ts of the flue gas exit temperature. 

Solids collected from the cyclone and particulate control 

device are combined and disposed of in a” existing site 

disposal area. 

GSA can remove in excess of 90% of the SO, as 

well as increase lime utitization efficiency with solids 

ffiCyCle. 

This project was located at the Cater for Emissions 

Research, utilizing a IO-MWe slipstream of flue gas fmm 

a I50-MWe coal-tired boiler at tbe Tennessee Valley 

Authority’s Shawnee Fossil Plant in West Paducah, KY 

A western Kentucky coal containing about 3?b sulfur 

was used. 

42 Environmpnral Confrol Devices 
Project ResultstAccomplishments: 

Optimization testing was conducted to determine the 

effect of the process design variables on the SO, nmoval efficiency in the reactor/cyclone and the ESP. 

The testing indicated that the order of importance of the 

key variables is (1) Ca/S, (2) appmach-to-adiabaticsaturation temperature, and (3) coal chloride content. 

The SO, removal efficiency for the ovemll system 

ranged from slightly more than 60% to nearly 958, 

depending on the specific test conditions. The lower SO, 

removal efficiency levels were achieved at the higher 

appmach-to-saturation temperature (28 “F), the lower 

lime stoichiomeby level (Cal.5 of 1 .M)), and lower coal 

chloride level (0.02-0.04%). The higher SO, removal 

efficiency levels were achieved at the closer appmach-tosaturation temperatures (8 and 18 OF), the higher lime 

stoicbiometry level (Ca/S of 1.30), and higher coal chlotide level (0.12%). Most of the SO, removal in the GSA 

system occurred in the reactor/cyclone, with only about 

2-58 of the overall removal occurring in the ESP. 

Results of a 4-week around-the-clock demonstration 

tun of the GSA system with the ESP indicated that the 

GSAtESP is capable of consistently maintaining 90% or 

better SO, removal at a moderate lime requirement. A 

14.&y pulse jet baghouse (PJBH) tun was successfully 

completed in March 1994. SO, removal efficiency in the 

GSAIPJBH system averaged more than 95% during the 

demonstration; this was typically about 3-5 percentage 

points higher than that achieved in the GSAIESP system 

at the same test conditions. 

The project demonstrated a number of key technical 

attributes, including a simple and direct method of lime/ 

solid recirculation, high acid gas adsorption, low lime 

consumption with minimal waste by-product residue, low 

maintenance operation, no internal buildup, and reduced 

space requirement. I” addition, the project demonstrated 

that a pulse jet baghouse system improved SO, removal 

efficiency by about 3-5 percentage points. Also, air 

Environmental Control Devices 

toxics testing showed that a removal rate of more than 

95% could be achieved by the GSA. 

The relative process economics for the GSA system 

were evaluated for a moderately difficult retrofit to a 

300-MWe boiler burning a coal containing 2.6% snlfur. 

The design SO, removal efficiency was 90%. Theresuiting capital cost estimate (in 1990 $) is $149/kW for 

GSA as compared to $216/kW for a wet limestone, 

forced-oxidation (WLFO) scmbbing system. The 

levelized annual revenue requirement for the GSA process is lower than that for the WLFO system, but the 

difference is only about 20% (which is not considered to 

be significant given the limitations on the accuracy of 

estimates used in the analysis). The principal annual 

operating cost for the GSA process is the cost of the 

pebble lime. The 15-year levelized costs in mills/kWb 

for the two systems are listed below: 

GSA 

Fixed costs 2.3 

Variable costs 3.1 

Capital costs 5.a 

Total 10.4 

Commercial Applications: 

WLFO 

2.81 

2.93 

la 

13.04 

The GSA process offers several advantages over conventional FGD technologies: (1) GSA is 30% cheaper than 

wet FGD and 20% cheaper than spray drying; (2) GSA is 

much simpler to build and operate than wet FGD and 

regenerable processes and requires much less space; 

(3) space requirements, operability, and ease of installation are comparable to spray dryers and duct injection; 

and (4) the SO, removal capability (90%) compares to 

that of wet FGD and regenerable processes. This high 

removal rate makes the GSA process suitable for use 

with high-sulfur coal. 

Successful testing of the AirPol demonstration 

project has resulted in acommercial application in Ohio. 

The city of Hamilton, OH. received a $5-million grant 

from the Ohio Coal Development Office to install the 

GSA technology to control emissions from a 50.MWe 

coal-fired boiler at the city’s municipal power plant. The 

new system is scheduled to be operational in August 

1996 and will be the first full-sale commercial GSA unit 

in the United States as well as the world’s first GSA unit 

for a coal-fired boiler. The GSA technology was identified as the least-cost alternative for the city to meet 

CAAA compliance requirements for 1997. 

In addition, FL5 miljo has been awarded a major 

project in Sweden for a high-performance GSA system to 

remove sulfur from the flue gas of a 4-million-ton/year 

imn ore sinter plant. Sweden’s stringent standards requite a” SO, removal efticiency of 90-9596. 

The GSA should fulfil1 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 5&250-MWe utility plants. 

Simplicity in GSA design and operation plus modest 

space requirements make GSA ideal for retrotitting to 

existing plants as well as for greenfield plants. One 

major advantage of the GSA, as compared to other semidry scabbing processes, is that operation of the GSA 

will not result in excessive dust loading to the gas stteam 

thus minimizing the cost for upgrading the existing dust 

collector. The potential market for the GSA is estimated 

at $300 million within the next 20 years. 

Project Schedule: 

DOE selected project (CCl-III) 12/19/89 

Cooperative agreement awarded 10/11/90 

NEPA process completed (MTF) 9/21/90 

Environmental monitoring plan completed lOrzJ92 

Co”stNctio” 5/92-9/92 

Operational testing 10/92-3194 

Project completed 6195 

Final Reports: 

Final Project Performance and Economic Report l/95 

Air Toxics Characterization Final Repon 3195 

Public Design Report w95 

43 
Environmental Control Detices 

SD, c0ntro/ T.9cJm0Jogies 

Confined Zone Dispersion 

Flue Gas Desulfurization 

Demonstration 

Project colnph3ed. 

Participant: 

BechtelCorporation 

Additional Team Members: 

Pennsylvania Electric Company--cofunder and host 

PennsylvaniaEnergy DevelopmentAuthority-cofunder 

New York State Electric&Gas Coqcxation-cofunder 

Rockwell Lime Company--cc&under 

Location: 

Seward, Indiana County, PA (Pennsylvania Elecfric 

Company’s Seward Station, Unit No. 5) 

Technology: 

Bechtel Corporation’s in-duct, confined zone dispersion 

flue gas desulfwization (CZD/FGD) process 

Plant Capacity/production: 

73.5 hfwe 

Project Funding: 

Total project cost* $10,411,600 100% 

DOE 5,205,800 50 

Participant 5.205.800 50 

Project Objective: 

To demonstrate SO, removal capabilities of in-duct 

CZDlFGD technology; specifically, to define the optimum process operating parameters and to determine 

CZD/FGD’s operability, reliability, and costeffectivel AddiGonpl pmjecc ovemn ems were rimded La)% by lk participant 

tal=~taalpmlst~~t***,,,~~. 

44 

-1 

ness during long-term testing and its impact on downstream operations and emissions. 

Technology/Project Description: 

In Bechtel’s CZDiFGD process, a finely atomized slurry 

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

the duct by spray nozzles designed to produce a cone of 

fine spray. As the spmy moves downstream and expands, the gas within the cone cc& and the SO, is rapidly absorbed in tbe liquid droplets. The dmplets 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 Ihe unreacted lime to the ESP. 

This project included injection of different types 

of smbents (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 

the ESP to control pwticulates. The demonstration was 

conducted at Pennsylvania Electric Company’s Seward 

Station in Seward, PA. Onehalf of the flue gas capacity 

of the 147~MWe Unit No. 5 was muted through a modified, longer duct between the first- and second-stage 

ESPs. Pennsylvania bituminous coal (approximately 

1.2-2.58 sulfur) was used in the project. 

Envimnmmti Conlml Devices 
Project Results/Accomplishments: 

Bechtel began its 18.month, two-part test program for 

the CW process in July 1991. The fust 12 months of 

the test program consisted primarily of parametric testing. The latter 6 months involved continuous operational testing with the system being operated under fully 

automatic control by host utility boiler operators. The 

new &on&zing nozzles wete thoroughly tested both 

outside and inside the duct prior to testing. The lime 

slurry injection parametric test program, which began in 

October 1991, was completed in August 1992. 

I” summary, the demonstration showed the 

following: 

A 50% SO2 removal efficiency with CZDIFGD is 

possible, and continuous operation at removal rates 

lower than 50% can be maintained over long periods 

without significant process pmblems. 

The process requires that drying and SO, absorption 

take place within 2 second?.. A long and straight 

horizontal gas duct of about 100 feet is required to 

assure residence time of 2 seconds. 

During normal operations, no deposits of fly ash or 

reaction products took place in the flue gas duct. 

The fully automated ~ysiem tidy integrated with 

power plant operation. demonstrated that the 

CZDlFGD process responded well to automated 

co”tmlopemion. 

Availability of the system was very good. 

At Seward Station, stack opacity was not detrimentally affected by the CZD/FGD system. 

Results of the demonstmtion indicated that the 

CZDIFGD process can achieve costs of $3OOlton of 

SO* removed when operating a 500.MWe unit buming 4% sulfiu coal. Based on a 500-MWe plant retmfitted with CWfFGD for a 50% rate of SOz removal, 

the Ntal capital cost is estimated to be less than 

$3OikW. 

Bechtel notified DOE on June 34 1993. that it was 

discontinuing the demonstration project effective July 1. 

1993. 

Commercial Applications: 

CW can be used for retmfit of existing and installation in 

new utility boiler flue gas facilities to remove SO, derived fmm a wide variety of sulfiu-containing coals. 

A CW system can be added N a utility boiler with a 

capital investment of about $25-501kW of installed capacity. or approximately one-fourth the cost of building a 

conventional wet scrubber. I” addition to low capital 

co& other advantages include small space requirements, 

ease of retwit, low energy l-equirenle”ts, fully autonlated 

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 C7.D installation does not require major 

power station alterations and can be easily and econotitally integrated into existing power plants. 

Project Schedule: 

DOE selected project (CCNll) 

Cooperative agreement awarded 

NEPA pmcess completed (MTF) 

Environmental monitoring plan completed 

COOShUCtiO” 

operational testing 

Project discontinued 

Final Reports: 

Final Technical Report 

Public Design Report 

12119/89 

10/13/90 

9/25/90 

6llZ91 

3/91JCv91 

7i91di93 

7l93 

6l94 

lOl93 

Environmental Control Devices 45 
Environmental Control Devices 

SO, Control Technologies 

LIFAC Sorbent Injection 

Desulfurization 

Demonstration Project 

Project cofnp/eted. 

Participant: 

LIFAC-North America (a joint venNre partnership 

between Tampella Power Corporatiw and ICF Kaiser 

Engineers, Inc.) 

Additional Teem Members: 

ICF Kaiser Engineers, Inc.--zofunder and project 

manager 

TampellaPowerCorporation-cofunder 

Tampella, Ltd.-technology owner 

Richmond Power & Light--cofunder and host 

Electric Power Research Institute-zofunder 

Black Beauty Coal Company-zofunder 

State of Indiana-colitnder 

Location: 

Richmond, Wayne County, IN (Richmond Power & 

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

Technology: 

LIFAC’s sorbent injection process with sulfur capture in 

a unique, patented vettical activation reactor 

Plant Capacity/Production: 

6oMwe 

Project Funding: 

Total project cost 

DOE 

Participant 

92L393.172 100% 

10,636,864 50 

10,756,908 50 

To demonstrate that electric paver plant.+-especially 

Project Objective: 

those with space Imitations-burning high-sulfur 

coals can be retrofitted successfully with the LIFAC 

limestone injection process to remove 7545% of the SO, 

from flue gas and produce a dry solid waste product for 

disposal in a landfill. 

TechnologylProiect Description: 

Pulverized limestone is pneumatically blown into the 

upper part of the boiler near the superheater where it 

absorbs some of the SO2 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 leadbent is easily separated from the flue gas along with the 

ing to SO, capture. After leaving the chamber, the sorfly ash in the electrostatic precipitator (ESP). The sorbent material from the reactor and ESP is recirculated 

back through the reactor for increased efficiency. The 

waste is dry, making it easier to handle than the wet 

scrubber sludge produced by conventional wet limestone 

scrubber systems. 

The technology enables power plants with space 

limitations to use high-sulfur midwestem coals by providing a” injection process that removes 75-858 of the SO, 

from flue gas and produces a dry solid waste product 

suitable for disposal in a landfill. 

The process was demonstrated at the Whitewater 

Valley Station, 60.MWe Unit No. 2. This coal-tired unit 

is owned and operated by Richmond Power & Light and 

Environmental Control Devices 46 
,_::::iipil::,,;,i~i ;~i_i;:,j_,,:,:: ,,: ,:,_ ii~,:_,,i:;; :, ,>~‘,,‘, :,, :‘;:f ;” 

,i;,,,,ni;ii;: ,Z_i;ilC ~,;,:::,,_ \,,,,, -,,: 

,, ,~, 

is located in Richmond, IN. Bituminous coal containing 

Z&2.9% sulfur was used for the majority of system 

testing. 

Project Results/Accomplishments: 

The total duration of the project was 2,800 hours of 

operation over a z-year period. 

LIFAC process variables and their effects on sulfur 

removal efficiency were evaluated during parametric 

testing. The four major parameters having the greatest 

influence on sulfur removal efficiency were limestone 

quality, Cal.5 ratio, reactor bottom temperature (approach-to-saturation), and ESP ash recycling rate. Total 

SO, capture was about 15 percentage points better when 

injecting fine limestone (80% minus 325 mesh) than it 

was with coarse limestone (80% minus 200 mesh). 

Parametric tests indicated that a 70% SO, reduction 

was achievable with a Ca/S ratio of 2.0. ESP ash containing tutreacted sorbent and fly ash was recycled from 

the ESP hoppen back into the reactor inlet duct work. 

Ash recycling is essential for efficient SO, capture. The 

large quantity of ash removed from the LIFAC reactor 

bottom, and the small size of the ESP hoppers limited 

the ESP ash recycling rate. As a result, the amount of 

material recycled fmm the ESP was approximately 70% 

less than had been anticipated. However, this low racycling rate contributed au additional 15 percentage points 

to total SO, capture. During a brief test, it was found 

that increasing the recycle rate by 50% resulted in a 5 

percentage paint increase in SO, removal efficiency. It 

is anticipated that if the reactor bottom ash is recycled 

along with ESP ash, while sustaining a reactor temperature of 5 “F above saturation temperature, an SO, reduction of 85% could be maintained. 

Optimization testing began in March 1994 and was 

followed by long-tam testing in June 1994. The boiler 

was operated at an average load of 60 Mwe during long 

term testing, although it fluctuated according to power 

demand. The LIFAC process automatically adjusted to 

EnvironmemaI Control Devices 

boiler load changes. A Ca/S ratio of 2.0 was selected to 

attain SO, reductions above 70%. Reactor bottom temperature was about 5 “F higher than optimum to avoid 

ash buildup on the steam reheaters. Atomized water 

droplet size was smaller than optimum for the same 

reason. Other key process parameters held constant 

during long-term tests included degree of humidification, grind size of the high-calcium-content limestone, 

and recycle ratio of spent sorbent from the ESP. 

Long-term testing showed that SO, reductions of 

70% or more can be maintained under normal boiler 

operating ranges. Stack opacity was low (about 10%) 

and ESP efficiency was high (99.2%). The solid waste 

generated was a mixture of fly ash and calcium compounds and was readily disposed of at a local landfdl. 

The LIFAC system has few moving parts and is 

simple to operate. The process can be easily shutdown 

and restarted. The process is automated by a program 

mable logic system, which regulates process control 

loops. interlocking. start-up, shut downs, and data collection. The entire LIFAC process was easily managed 

via two personal computers located in the host utility’s 

control mom. 

The economic evaluation indicated that the capital 

cost of a LIFAC installation is lower than for either spray 

dryers or wet scrubbers. Capital costs for LIFAC technology vary depending on unit size and the quantity of 

reactors needed: 

$99&W for one LIFAC reactor at Whitewater Valley 

Station (65 MWe) 

$76/kW for one LIFAC reactor at Shaod Station 

(150 Mwe) 

$66lkW for two LIFAC reactors at Shand Station 

(300 Mwe) 

Commercial Applications: 

This process is suitable for application to all coal-tired 

utility or industrial boilers, especially those with tight 

space limitations. The LIFAC process is less expensive 

to install than conventional wet flue gas desulfurization 

processes; uses dry limestone instead of more costly 

lime; is relatively simple to operate; produces a dry, 

readily disposable waste; and can handle all types of 

coal. 

The benign waste material can be disposed of in a 

landfill along with the fly ash. Commercial use of the 

LIFAC by-product in the manufacture of construction 

materials is currently being investigated in Finland. 

There are 10 full-scale LIFAC units in operation or 

under construction in Canada, China, Finland, Russia, 

and the United States. The LIFAC system at Richmond 

Power & Light is being retained and is the first to be 

applied to a power plant using high-sulfur (2X&2.9%) 

coal. The other LIFAC installations are on power plants 

using low-sulfur (O&1.5%) coals. 

Project Schedule: 

DOE selected project (CCT-III) 

Cooperative agreement awarded 

NEPA pmcess completed (MTF) 

Environmental monitoring plan completed 

Construction 

Operational testing 

Pmjeft completed 

Final Reports: 

Final Technical Repon 

Economic Evaluation Report 

Public Design Repon 

12/19/89 

11R0/90 

10/2/90 

6/12/92 

5/91-6/92 

9l92dl94 

12l96 

12J96 

12l96 

12l96 

47 
Environmental Controt Devices 

SO. Control Technologies 

Advanced Flue Gas 

Desulfurization 

Demonstration Project 

Project completed. 

Participant: 

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.) 

Additional Team Members: 

Northern hxiiana Public Service Company-eofuuder 

and host 

Mitsubishi Heavy Industries, Ltd.-process designer 

United Engineers and Constructors (Steams-Roger 

Division)-facility designer 

Air Products and Chemicals, Inc.~onstructor and 

operator 

Location: 

Chesterton, Porter County, IN (Northern Indiana Public 

Service Company’s Bailly Generating Station, Units 7 

and 8) 

Technology: 

Pure Air’s advanced flue gas desulfurization (AFGD) 

process 

Plant Capacity/Production: 

528 MWe 

Pmve$chip is a regisiered trade- of pun Air 0” Ihe L*e. L.P. 

46 

Project Funding: 

Total project cost $151.707.898 100% 

DOE 63,913,200 42 

Participant 87.794.698 58 

Pro@zt Objective: 

To demonstrate removal of 90-95% or more of the SO, 

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

of space requirements. 

TachnologylProjact Dascription: 

In this project, Pure Air has built a single SO2 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 co-cument design, in which the 

flue gas and scrubbing slurry move in the same direction 

and at a relatively high velocity compared to conventional scrubbers. These features all combine to yield a 

state-of-the-art SO, absorber that is more compact and 

less expensive than conventional scrubbers. 

Technical features include the injection of pulverized limestone direcfly into the absorber. a device called 

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

air rotary sparger combines the functions of agitation and 

air distribution into one piece of equipment to facilitate 

the oxidation of calcium sulfite to gypsum 

Envimnrmnral Contnd Devices 
Pm-e Air also demonstrated a unique gypsum 

agglomeration pmcess that produces PowerCbip~ 

gyp.““. 

Bituminous coals primarily from the IndianaIllinois coal basin containing 2.25-4.796 sulfur were 

tested. 

Project Results/Accomplishments: 

The 528~Mwe demonstratica accumulated appmximately 26,280 hours of operation over a 3-year period 

and achieved a” availability of 99.79%. Co”stmction 

began in April 1990, and in June 1992 the AFGD system 

began to process flue gas, thus becoming the first commercial scrubber to meet the requirements of the CAAA 

of 1990. Tests were on coals ranging from 2.0% to 4.5% 

sulfur. During the 3.year operation, SO, removal efficiency averaged 94.71% with a maximum of 98+% or 

0.382 lb/million Btu. Twenty-four-hour average power 

consumption was 5,275 kW, or 61% of expected consumption, and water consumption was 1,560 gallons/ 

minute. or 52% of expected consumption. The pmducdon rate of the PowexCbipe facility was 7 tonslhr. During the 3.year demonstration, an average of 207,623 

tottdyr of dry gypsum were produced, with a” average 

purity of 97.56%. 

In 1993, Power Magazine pnsented the Powerplant 

of the Year Award to the generating station for demonstrating advanced wet limestone FGD technology with 

innovations in wstwater treatment and gypsum pmductio”. In 1992, the National Society of Professional Engineers presented its Outsfanding Engineering Achievement Award to the project. 

Commercial Applications: 

The AFGD process is attractive for both new and retrofit 

utility applications. Ihe demonstration pmject is using 

bituminous coals primarily from the Indiana-Illinois coal 

basin, with sulfur conted ranging fmm 2.0% to 4.5%. 

The AFGD unit at Bailly Station will continue to 

operate for an additional 17 years under a novel business 

concept whereby Pure Air is the owner of the unit and 

Air Products and Chemicals, Inc., is the operator. This 

AFGD facility will reduce SO* emissions by approximately 75,!lOO to”s/yr. Further, the gypsum by-pmduct 

and wastewater evaporation will demonstrate that SO? 

control can occur without incnased solid waste or wastewater production. 

All this can be accomplished with costs (and space 

requirements) that are roughly one-half of those awxiatd with a conve”tio”al scrubber. 

In April 1994, Pure Air of Manatee, L.P., entered 

into a contract to provide 1,600 MWe of SO, scrubbing 

capability at Florida Power& Light Company’s Manatee 

power plant on the same own-and-operate basis. ‘The 

Manatee scrubber will feature two 8OCkhlWe absorber 

vessels. PowerChipD gypsum recycling, and wastewater 

evaporation. 

Project Schedule: 

DOE selected project &XXII) 

Cooperative agreement awarded 

NEPA process completed @A) 

Environmental monitoring plancompleted 

COtlStNCtiOtl 

Operationaltesting 

Project completed 

Final Reports: 

Final Technical Report 

(includes economics) 

Public Design Repon 

9/28/88 

12/20/89 

4/16/90 

l/31/91 

4l90-9l92 

6#2-6/95 

6l96 

6I96 

3f90 

Environmenral Control Devices 49 
Environmental Contrcl Devices 

SO, Control Technologies 

Demonstration of Innovative 

Applications of Technology for 

the CT-121 FGD Process 

Project completed. 

Participant: 

Southern Company Services, Inc. 

Additional Team Members: 

Georgia Power Company-host 

Electric Power Research lnstitutiofunder 

RadianCorporation-envimnmentalandanalytical 

colls”ltant 

Ershigs, Inc.-fiberglass fabricator 

Composite Construction and Equipment-fiberglass 

s”stain”entcms”ltant 

Awn&h-flow modeling consultant 

Ardama”-gypsum stacking consultant 

University of Georgia Research Foundationby-product utilizatio” studies consultant 

Location: 

Newnan, Coweta County, GA (Georgia Power 

Company’s Plant Yates, Unit No. 1) 

Technology: 

CbiyodaCorporatio”‘sChiyodaThoroughbre&121 

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

process 

Plant Capacity/Production: 

100 MWe 

Project Funding: 

Total projeci cost 

DOE 

Participant 

$43,074,9% 100% 

21,085,211 49 

21.989.785 51 

Project Objective: 

To demonstrate the CT-121 flue gas desulhuization 

system, including several design innovations, at the 

lOOMWe scale; more specifically, to demonstrate 90% 

SO, control at high reliability with and without 

simultaneous particulate control with possible additional 

reductions in operating costs. 

Technology/Project Description: 

The project is demonstrating the CT-121 FGD process. 

which uses a unique absorber design known as the jetbubbling reactor (JEIR). The process combines limestone FGD reaction, forced oxidation, and gypsum crystallization in one process vessel. The process is mechanically and chemically simpler than conventional 

FGD processes and can be expected to exhibit lower cost 

characteristics. 

-I 

The flue gas enters underneath the scrubbing solution in the jet-bubbling 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 &watered 

in a gypsum stack, which involves tilling a dyked area 

with gypsum slurry. Gypsum solids settle in the dyked 

area by gravity, and clear water flows to a retention 

pond. The clear water from the pond is returned to the 

pOCC%S. 

The project also evaluated process innovations to 

determine if costs can be reduced further by using tiberglass-reinforced plastic (FRP) vessels, eliminating flue 

gas reheat and spare absorber modules, and stacking 

gypsum to reduce waste management costs. The ability 

SO Environmental Conrrol Devices 
~,,j;“,l:;:; ,.,.( _,, :, ,~,,‘~S ‘, 

‘;i:j i, _:i:_i:,i_:_;:,,~::__,:“~,:~:,,; ,,, ,,, 

of this technology to capture SO2 and particulates simultaneously also was evaluated. 

Bituminous coals containing l.24.3% sadfur were 

used to demonstrate 90% SO, control with high reliability, with and without simultaneous pat&late control. 

ProjectResulte/Accompliehments: 

Parametric testing was completed in March 1993, and 

long-term testing began in May 1993. DOE-sponsored 

air-toxics testing was done in June 1993. 

During the 19,0&l hours or 27 mwths available for 

the demonstration, the scrubber operated for 14,000 

hours. The coal burned during the demonstration was a 

blend of Illinois No. 5 and 6 that averaged 2.4% sulfur. 

Other tests were conducted on coals varying from 1.2% 

to 4.3% sulfiu. The system demonstrated the ability to 

exceed 98% SO, removal efficiency with high-sulfur coal 

while at maximum boiler load and limestone utilization of 

97%. Using FRP fabrication of key components, with its 

high resistance to corrosion, enabled elimination of a 

rescmbber to remove chlorides and flue gas reheat to 

pnvent corrosive condensation in the chimney (constructed of FRP). The stmctural and chemical durability 

of FRP construction combined with the simplicity of 

design afforded by the unique JBR resulted in high availability (97% at low ash levels and 95% at elevated ash 

levels) and elimination of the need for a spare reactor 

module. The CT-121 system demonstrated high patticulate capture efficiency (97.7-99.396) at flyash levels 

reflective of marginal ESP performance (up to 

1.14 lbslmillion BN). Testing also showed the 

CT-121 to be highly efficient in the capNn of hazardous 

air poIlutants (HAPS) which are largely borne by 

pt?iCUlateS. 

In April 1996, an internal inspection of the JBR 

revealed no noticeable problems after extended operations. 

In February 19%. the project won the Society of 

Plastics Industries’ Design Award for the mist eliminaEmironmenkai Control Devices 

tar. The project received two awards in 1994: Power 

Magazine’s 1994 Powerplant of the Year Award and an 

Outstanding Achievement Award from the Georgia 

chapter of the Air and Waste Management Association 

for using an innovative technology for air quality control. In 1993. Plant Yates received an environmental 

award from the Georgia Chamber of Commerce, based 

on the SUCCESS of the CT-121 scrubber. 

Commercial Applications: 

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 mbberlined carbon steel or costly alloys; (2) no spare absorber 

is required because the system is at least 97% reliable; 

(3) reheating of the flue gas is not necessary: (4) both 

SO, and particulates are removed from flue gas; (5) more 

than 99% of the calcium in the limestone reagent is used: 

(6) the gypsum by-product can be stored safely and easily 

or used in commercial applications; (7) the CT-121 operding costs are the lowest for state-of-the-art FGD systems; (8) there is no known size limit for this technology; 

(9) utilities and industrial concerns could make immediate use of this technology: and (IO) the system is not 

sensitive to the type of coal used. its sulfur content, or the 

limestoneutilized. 

Involvement of Southern Company (which owns 

Southern Company Services, Inc.). with its utility system 

that has more than 20,CCO 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 year 2010. 

A 90% trduction in SO2 emissions from only the retmtit 

portion of this capacity represents more than 10,500.olJo 

tonslyrof potential so, control. 

In 1994 a tar sands oil extraction facility in Murray, 

Canada, purchased the CT-121 scrubber. 

Project Schedule: 

DOE selected project (Cm-II) 9/28/88 

cooperative agreement awarded 4i2J90 

NEPA process completed (EA) S/10/90 

Environmental monitoring plan completed 12/18/90 

Constmction S/90-10/92 

Operational testing 10/92-12/94 

Project completed 1197 

Final Reports: 

Final Technical Report 12i96 

Economic Evaluation Rep& l2l96 

Public Design Repat I2196 

Final Report on Gypsum Stacking II97 
Environmental contra/ oevfces 

Combined SO./NOw Contmi Technologies 

SNOF Flue Gas Cleaning 

Demonstration Project 

Pmject WmPleted. 

PerticiPent: 

ABB Environmental Systems 

Additional Teem Members: 

Ohio Coal Development Office-cofunder 

Ohio F&on Companydofuoder and host 

Haldor Topwe a/s-patent owner for process technology, 

catalysts, and WSA Tower 

Snamprogetti. U.S.A.-zofonder and process designer 

Location: 

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

Station, Unit No. 2) 

Technology: 

Haldor Topsoe’s SNOXm catalytic advanced flue gas 

cleanup system 

Plant Capacity/Production: 

35.MWe equivalent slipstream from a 108~MWe boiler 

Project Funding: 

Total project cost $3 1.438.408 100% 

DOE 15,719,200 50 

Participant 15,719,208 50 

Project Objective: 

To demonstrate at an electric power plant using U.S. 

co& that SNOP tecboology will catalytically remove 

95% of SO, and more than 90% of NO, from flue gas 

and produce a salable by-product of concentrated sulfw 

ric acid. 

SNOX is a mu&d or “et&r TopJoe a/s 

52 

Technology/Project Description: 

In the SNOP process, the stack gas leaving the boiler 

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

bagbouse to minimize the cleaning hequency 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 water vapor. The SO* is oxidized to SO, in a second 

catalytic co”veliez The gas then passes through a novel 

@.SS-Nbe condenser which allows SO, to hydmlyze to 

c0ncentIated sldfuric acid. 

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

to remove 95% of the SO+d more than 90% of the 

NO, from floe gas and produce a salable suifiuic acid 

by-product. This is accomplished without using sorbents 

and without creating waste by-products. 

The demonstration was conducted at Ohio Edison’s 

Niles Station in Niles, OH. The demonstration unit 

treated a 35-MWe equivalent slipstream of flue gas horn 

the 108~MWe Unit No. 2 boiler which burned a 3.4% 

solfur Ohio coal. The pmcess steps were viftoally the 

same as for a commercial full-scale plant, and commercial-scale components were installed and operated. 
Project Results/Accomplishments: 

Operational testing was initiated in March 1992 and 

completed in December 1994. The system operated for 

more than 8,ooO hours and produced more than 5,6CO 

tons of commercial-grade sulfwic acid. The facility has 

mutinely operated at full capacity, achieving removal 

efficiencies of 96% for SO,, 94% for NO”. and 99.9% 

for palticulates. 

Many tests for the SNOX- system were designed 

to be conducted at 75%. lGO%, and 110% of design 

capacity. During the test program, SO, removal efftcienties were normally in excess of 95% for inlet concentrations which averaged about 2,GVO ppm. System NO” 

reduction efficiencies averaged 94% with inlet NO” 

levels of approximately 5CG700 ppm. 

Sulfuric acid concentmtions and composition have 

met or exceeded federal specifications for class I acid. 

The acid from the plant has been sold to the agriculture 

industry for the production of diammonium phosphate 

fertilizer and to the steel industry for pickling. Ohio 

Edison has used a significant amount in its boiler water 

demineralizer system throughout its plants. 

Air toxics testing at the plant indicated that, for the 

majority of the species examined, especially those that 

exit primarily as particulates at the SNOXTM fabric filter 

or SNOXTM outlet, removal is very high. Because of the 

mechanism of sulfuric acid condensation in the WSA 

condenser, any particulates remaining at this point act as 

nuclei for H,SO, and are captured in the acid. For volatile species, the WSA condenser outlet temperature is 

lower than conventional boiler outlet temperatures and 

should condense and capture more of the volatile species 

than a plant with only an ESP or fabric filter. 

The economic evaluation of the SNOXTM process 

showed a capital cost of approximately $250&W and a 

total operating cost of approximately I.3 mills/kWh. 

Commercial Applications: 

The SNOXTM technology is applicable to all electric 

paver plants and industrbdlinstitutional boilers tiring 

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

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

ash) enhances the marketability in u&w and other areas 

where solid waste disposal is a significant problem. 

The host utility, Ohio Edison. is retaining the 

SNOXTM technology as a permanent part of the pollution 

control system at Niles Station to help Ohio Edison meet 

its overall SOJNOx reduction goals. 

Commercial SNOXM plants also are operating in 

Denmark and Sicily. In Denmark, a 305~MWe plant has 

operated since August 1991. The boiler at this plant 

bums coals from various suppliers around the world, 

including the United States; the coals contain 

0.5-3.0% sulfur. The plant in Sicily, operating since 

March 1991, has a capacity of about 30 MWe and fires 

petroleum coke. 

Project Schedule: 

DOE selected project (CCT-II) 9/28/88 

Cooperative agreement awarded I 2/20/89 

NEPA process completed (MTF) l/31/90 

Environmentalmonitoringplancompleted 10/31/91 

Construction l/91-12/91 

Operational testing 3/92-12J94 

Project completed 7196 

Final Reports: 

Final Technical Report 7196 

(includes economic information) 

Public Design Report 7196 

Environmenral Con~ol Devices 53 
Enviionmental Control Devices 

Combined SOJNO~ Control Technologies 

LIMB Demonstration Project 

Extension and Coolside 

Demonstration 

Project completed. 

Participant: 

The Babcock & Wilcox Company 

Addiiional Team Members: 

Ohio Coal Development Office-cofunder 

Consolidation Coal Company-cofunder and technology 

supplier 

OhioFdisonCompany-host 

Location: 

Lorain, OH (Ohio Edison’s Fdgewater Station, Unit 4) 

Technology: 

The B&cock&Wilcox Company’s limestone injection 

multistage burner (LIMB) system: B&cock & Wilcox 

DRB-XCL. low-NOx burners 

Consolidation Coal Company’s Coolside duct injection of 

lime w-bents 

Plant CapacitylProduction: 

105 Mwe 

Project Funding: 

Total project cost $19,404,940 100% 

DOE 7.597.026 39 

Participant 11.807,914 61 

Project Objective: 

To demonstmte, with a variety of coals and sorbems, the 

LIMB process as a retrofit system for simultaneous 

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

DR%Xct. is a m.gistaEd UadcmarL ofThe Babecck 6r Wilcox cmnpy. 

54 

and that LIMB can achieve up to 70% NOx and SO2 

tions. using the Coolside process, to demonstrate in-duct 

sorbent injection upstream of the humidifier and precipireductions; to test alternate sotbent and coal combinatator and to show SO, removal of up to 70%. 

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 electrostatic precipitator (ESP) or baghouse. 

Humidification of the flue gas before it enters an ESP is 

necessary to maintain normal ESP operation and to enhance SO, removal. Combinations of three eastern 

bituminous coals (1.6%. 3.0%. and 3.8% sulfur) and 

four sotbents were tested. Other variables examined 

Iu the Cwlside process, dry sorbent is injected into 

the flue gas downstream of the air preheater, followed by 

were stoichiometty, humidifier outlet temperature, and 

flue gas humidification. Humidification enhances ESP 

injection level. 

performance and SO, absorption. SO, absorption is 

improved by dissolving NaOH or Na$O, in the 

humidification water. ‘Ike spent sorbed is collected with 

the fly ash, as in the LIMB process. Au eastern bituminous coal with 3.0% sulfur was used in testing. 

The same low-NO, burners (B&cock & Wilcox 

DRB-XCL@ low-NOx burners), which control NO, 

through staged combustion, were used in demonstrating 

both LIMB and Coolside technologies. 

Environmenrol Conrrol Devices 
::“~i~~~~~,.~~;-.i;~i:, ,,,::;,:,, ,,::,:.,,~. ,,~,( ,,, ,,:, ,: i : 

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

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

Project Results/Accomplishments: 

LlMB tests were conducted over a range of Ca/S ratios 

and humidification conditions. Each of four sorb-as 

(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 3.8% sulfur). Tests were conducted 

under minimal humidification, defined as operation at a 

humidifier outlet temperature sufticient 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 LUvlB 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 SO2 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 sulfiuremovalefficiencies, without 

humidification to close approach, were attained using 

the liguo lime-61% SO,mnovaI was achieved while 

burning 3.8% sulfur coal. All sorbents tested were 

capable of removing SO, although calcium utilization 

of even finely pulverised limestone was not nearly as 

high as those of the limes. 

While injecting commercial limestone with 80% of 

the panicles less than 4.4 microns in size, removal 

. 

efficiencies of about 22% were obtained at a stoichiometry of 2.0 while burning 1.6% sulfur coal. However, removal efficiencies of about 32% were 

achieved at a stoichio~ny 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 5-7% 

higher than that obtained at similar conditions for 

limestone with all particies less than 44 microns. 

Sorbent injection at the 181-n plant elevation level 

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

the highest SO, removal rates. Here, the so&at was 

injected at close to the optimum furnace temperature 

of 2.300 “F. 

SO, removal efficiencies were enhanced by about 

IO% over the range of stoichiometties tested when 

humidification down to a 20 “F approach to saturation 

was used. 

During the Coolside demonstration, compliance 

(1.2-1.6% sulfur) and noncompliance (3.0% sulfur) coals 

were burned. Key process variables--c@., 

N&a, and approach to adiabatic saturation-were 

evaluated in short-ten” (6-8&r) parametric tests and 

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

The Coolside process routinely achieved 70% SO, 

removal at design conditions (2.0 Ca/S, 0.2 Na/Ca, and 

20 “F approach to adiabatic saturation temperature) using 

commercial hydrated lime. SO, removal depended on 

Ca/S, Na/Ca, approach to adiabatic saturation, and the 

physical properties of the hydrated lime. Sorbent recycle 

showed significant potential to improve sorbent utilization. Observed SO, removal with recycle sot-bent 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% at 0.8 

fresh Cal& 0.2 fresh N&a, 0.5 available recycle, and 

18 OF approach to adiabatic saturation. 

NO, removal wns in the 40-50% range throughout 

both LIMB and Coolside testing. 

Commercial Applications: 

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 he 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 competitive with FGD systems. For example, using 2.5% sulfurcoal at a 65% plant capacity 

factor, LIMB can be cost competitive with conventional 

wet FGD up to 450 MWe and Coolside up to 220 MW... 

The envimnmental benefits for LIMB are 40-50% lower 

NOx and more than 20% lower SO, emissions, and for 

Coolside up to 70% lower SO, emissions. The waste 

from each of these processes is dry, easily handled, and 

contains unreacted lime that has potential commercial 

application. Both processes can handle all coal types, 

especially low- to medium-sulfur coals. 

Project Schedule: 

DOE selected project (CCT-I) 7l24186 

Cwpcrative agreetuent awarded 6/25/87 

NEPA process completed (MTF) 6l2l87 

Envimnmental monitoring plancompleted 10/19/88 

Construction 8187-9189 

Coolside operational testing 7189-290 

LIMB extension operational testing 4/9&8/91 

Project completed 11/92 

Final Reports: 

Final Report (LIMB/Coolside) I l/92 

Topical Report (Coolside) 2J92 

Topical Report (LIhGVCwlside) 9190 

Public Design Repot 12/88 

55 
Entironmentel Control Devices 

Combined SO,/No. Control Technologies 

SO;NO;Rox BoxTM Flue Gas 

Cleanup Demonstration 

Project 

Project completed. 

Participant: 

The B&cock &Wilcox Company 

Additional Team Members: 

Ohio Edison Company--cohmder and host 

Ohio Coal Development Offi-ofunder 

Electric Power Research Institutwofunder 

Norton Company-cofunder and SCR catalyst supplier 

3M Company--cofunder and filter bag supplier 

Owens Coming Fiberglas Cotporation-cofunder and 

filter bag supplier 

Location: 

Dilles Bottom, Belmont County, OH (Ohio Edison 

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

Technology: 

The B&cock &Wilcox Company’s SO,-NO;Rox 

Box”.’ (SNRB’Y process 

Plant Capacity/Production: 

5MWe equivalent slipstream from a 156-MWe boiler 

Project Funding: 

Total project cost 

DOE 

Participant 

$13,271,620 100% 

6,078,402 46 

7,193,218 54 

SO;NO;Rox BOX and SNRB are trademarLs of The Babxk & 

Wilcox company. 

54 

high levels of all three pollutants (NOx. SO,. and particuProject Objective: 

lates) using a single processing unit for treating flue gas, 

To demonstrate that the SNRBTM process, used in retrothereby lessening on-site space requirements and capital 

costs. 

fitting a high-sulfur-coal-fired power plant. can remove 

Technology/Project Description: 

The SNRBM process combines the removal of SO,, 

NO,, and particulates in one unit-a high-temperature 

baghouse. SO, removal is accomplished using either 

calcium- or sodium-based sorbent injected into the flue 

gas. NO” removal is accomplished by injecting ammonia 

to selectively reduce NO, in the presence of a selective 

catalytic reduction, or SCR. catalyst. Paticulate removal 

is accomplished by high-temperature tiber bag filters. 

this scale also permitted cost-effective control of the flue 

gas temperature which allowed for evaluation of perforThe 5-MWe SNRBTM demonstration unit is large 

mance over a wide range of sorbent injection and 

enough to demonstrate commercial-scale components 

baghouse operating temperatures. Thus several different 

arrangements for potential commercial installations could 

be simulated. 

while minimizing the demonstration cost. Operation at 

The project demonstrated the technical and economic feasibility of achieving greater than 80% SO, 

removal, above 90% NOx removal, and 99% particulate 

removal at lower capital, operating, and maintenance 

costs than a combination of conventional systems. The 

demonstration was conducted at Ohio Edison 

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

Environmental Conn01 Devices 
Bottom, OH. Bituminous coal with an average sulfiu 

content of 3.4% was burned at this site during the demonstration. 

Projact Raauita/Accomplishments: 

SNRBm demonstration tests were conducted for emissions control of SOz, NO, and particulates. Four different sorbems were tested for SO, capture. Calcium-based 

sorhents included commercial-grade hydrated lime, 

sugar hydrated lime, and lignosulfonate hydrated lime. 

In addition, sodium bicarbonate was tested. The optimum location for injecting the smb-ent into the flue gas 

was immediately upstream of the baghouse. Effectively, 

the SOI was captured by the sorbent while the sotbent 

was in the form of a filter cake on the filter bags (along 

with fly ash). To capture NOx, ammonia was injected 

between the sorbent injection point and the baghouse. 

?be ammonia and NOx reacted to form nitrogen and 

water in the presence of Norton Company’s NC-300 

series mlite SCR catalyst. Because the catalyst was 

located inside the filter bags, it was well protected fi’om 

potential pat&date erosion or fouling. The sorknt 

reaction products, umracted lime, and fly ash were 

collected on the filter bags and thus removed from the 

flue gas. 

With commercial-grade lime, at a Cal.9 ratio of 2, 

and with the baghouse temperature between 800 and 

850 “F, sultiu capture was well above 80%. With the 

modified hydrated limes, at the same operating temperature range, sulfur capture approached 90%. With an 

NH.pOx ratio of 0.9, the reduction in NO, emissions 

was consistently above 90% and the ammonia slip was 

consistently below 5 ppm. Particulate emissions were 

always below 0.03 lb/million Btu, the NSPS for particul&es. Particulate emissions averaged 0.018 lb/million 

Btu (0.009 grains&d ft3), corresponding to a collection 

efficiency of 99.89%. 

High SO, removal efficiency was demonstrated in a 

brief test program with sodium bicarbonate injection. 

Envimmnmtal Control Devices 

Removal efficiency increased from 80% to 98% and the 

ratio of NaJS was increased from 1 to 2. 

All of the demonstxation tests were conducted using 

3M’s Nextel ceramic fiber filter bags or Owens Coming 

Fiberglas’s S-Glass filter hags. All of the test work was 

carried out at air-to-cloth ratios of 34 ft/min. No excessive wear or failures occurred in more than 2,000 hours 

of elevated temperature operation. 

A preliminary evaluation has been made of the pmjetted capital cost of the SNRBTM system for various 

utility boilers. For a 25&MWe boiler fired with 3.5% 

sulfur coal and generating NO, emissions of 1.2 Ibs/ 

million Btu, the projected cost of a SNRBr’” system is 

approximately $26OkW including various standard technology and project contingency factors. The cost of 

competitive technology, consisting of a combination of 

fabric filter, SCR, and wet scrubber for achieving comparable emissions control, has been estimated at 

$36&400/kw. 

Commercial Applications: 

Commercial application of the technology offers the 

potential for significant reductions of multiple pollutants 

from fossil-fired plants with the potential for increasing 

themml efficiency. SNRBM offers the potential for 

lower capital and operating costs and smaller space requirements than a combination of conventional, highefficiency control technologies. SNRBTu is capable of 

reducing emissions from plants burning high- or lowsulfur coal. In retrofit applications, SNRBW provides a 

means of improving particulate emissions control with 

the addition of SO, and NO. emissions contml capacity. 

Commercialization of the technology is expected to 

develop with au initial larger scale application equivalent 

to 50-100 MWe. The focus of marketing effotts will be 

tailored to match the specific needs of potential industrial, 

utility, and independent power producers for both retrofit 

and new plant construction. SNRBm is a flexible technology which can be tailored to maximize control of 

SO,, NOxs or combined emissions to meet current petformance requirements while providing flexibility to address future needs. 

Project Schedule: 

DOE selected project @XT-II) 

Cooperative agreement awarded 

NBPA process completed 0 

Environmental monitoring plan completed 

9/28/88 

12l20/89 

9/22!89 

12/31/91 

Constmction 5/9-1291 

Operational testing 5/92-5l93 

Project completed 9l95 

Final Reports: 

Final Technical Report 

(includeseconomic information) 

Detailed Design Report 

9195 

1 l/92 

57 
Environmental Control Devices 

Combined SOJNO, Control Technologies 

Enhancing the Use of Coals 

by Gas Reburning and 

Sorbent Injection 

Project completed. 

Participant: 

Energy and Environmental Research Corporation 

Additional Team Members: 

Gas Research Institute-zofunder 

State of Illinois. Depaltment of Energy and Natural 

Resources--cofunder 

Illinois Power Company-host 

City Water, Light and Power-host 

Locations: 

Hennepiu, Putnam County. IL (Illinois Power 

Company’s Hennepin Plant, Unit 1) 

Springfield, Saugamon County, IL (City Water, Light and 

Power’s Lakeside Station, Unit 7) 

Technology: 

FmgyandEn vlronmenralResearchC+oratiooaporaticn’sgasrebming and sotbent injectiion (GR-SI) pnress 

Plant Capacity/Production: 

Hennepin: tangential-fired 80 MWe (gross), 71 MWe (net) 

Lakeside: cyclone-tired 40 MWe (gross), 33 MWe (net) 

Project Funding: 

Total project cost $37,588,955 100% 

DOE 18.747.816 50 

Participant 18.841.139 50 

Proiect Objective: 

To demonstrate gas rebuming to attain at least 60% NO, 

reduction along with sorbeot injection to capture at least 

58 

I50% of the SO2 on two different boiler configurations 

tangentially fired and cyclone-tired-while burning 

high-sulfur midwestem coal. 

Technology/Project Description: 

In this process, 8&85% of the fuel is coal and is supplied to the main combustion zone. The remaining 

15-20% of the fuel, generally natural gas or other hydrocarbon, bypasses the main combustion zone and is injected above the main burners to form a reducing 

(rebum) zone in which NOx is converted to nitrogen. A 

calcium compound (so&at) is injected in the form of 

dry, fine particulates above the rebuming zone in the 

boiler or even further downstream. The calcium cornpound tested is Ca(OH), (lime). This project demonstrated the CR-S1 process on two separate boilers representing two different firing configurationsa taogentially fired, SO-MWe (gross) bailer at Illinois Power 

Company’s Hennepin Plant in Hennepin, IL, and a cyclone-fired, 40-MWe (gross) boiler at City Water, Light 

and Power’s Lakeside Station in Springtield, IL. Illinois 

bituminous coal containing 3% sulfur was the test coal 

for both Heunepin and Lakeside. 

Project Results/Accomplishments: 

A matrix of 32 gas rebum tests were completed on the 

tangentially tired boiler at the Hennepin Plant. NO, 

reductions of up to 77% were achieved, with 65% being 

routine--exceeding the project objective of 60%. Evaluation of 20 overfire air tests indicated substantial NO, 

reduction was achievable at low power generation loads, 

with lesser reductions as load increased. Sotbent injecEnvironmenti Control Devices 
don mhmd SO2 emissions as much as 62%. with 52% 

reduction being routine--also exceeding the project 

objective of 50%. The C&S was about 1.75. 

Three proprietary sorbents (including PmmiSorb A, 

PmmiSorb B, and high surface area hydrated lime) were 

also tested at Hennepin. The sotbents showed higher 

SO, capture and higher calcium utilisation than the ngular hydrated lime. 

The GR-SI process reduced COr, HCI, and HF 

emissions as well as NO, and SO,. During sorbent injection, particulate emissions were reduced by flue gas 

humidification upstream of the ESP. 

The system installed at Hennepin operated for more 

than 2,100 hours, of which about 400 hours were gas 

mbuming; 115 hours, sorbent injection; and nearly 

760 hours, combined operation (the remainder was 

baseline testing). 

After reviewing the operational performance, boiler 

impact, and economics, Illinois Power retained the gas 

burtdng portion of the GR-SI system for possible use for 

NO% control. 

Parametric tetxing on the cyclone boiler at the 

Lakeside Station was conducted in three series: gas 

rebuming parametric testing, sotbent injection parametric 

testing, and GR-SI optimization tests. The goal of the 

parametric test series was to &fine the optimum GR-SI 

operating conditions with minimal degradation of the 

thermal performance of the boiler and to evaluate the 

GR-SI process over a wide range of representative operating conditions. 

A total of 100 gas rebuming parametric tests were 

conducted at boiler loads of 33 MWe, 25 MWe. and 

20 MWe. The rebum parametric tesrs achieved NO, 

reduction levels either at or just marginally above the 

60% reduction goal. Additional flow modeling and 

computer modcling studies indicated that smaller 

rebuming fuel jet nozzles could increase teburuing fuel 

mixing and improve NOz reduction performance. 

Envinmmenrd Control Devices 

:~; : 

,_:,’ 

A total of 25 sorbent injection parametric tests to 

isolate the effects of the sotbent on boiler performance 

and operability were completed. Tests indicated that SO, 

reduction level varied with load because of the effect of 

temperature on the sulfurizrdion reaction. At a Ca/S of 

2.0, full load (33 MWe) achieved a 44% SO, reduction; 

mid-load (25 MWe). 38% reduction; and low load 

(20 MWe). 32% reduction at Lakeside. 

In the GR-SI optimisation tests. the two technologies were integrated. Modiftcations were made to the 

rebuming me1 injection nozzles based on the results of 

the initial gas rebuming parametric tests. Tests did not 

indicate any adverse effect from changing the thermal 

pmfile. SO, reductions of more than 50% could be 

achieved with Ca/S greater than I .25 along with gas heat 

inputs of 22-25%. The total SOa reduction from the 

combined effect of fuel replacement and sorknt injection exceeded the project goal of 50% reduction. 

The primary goal of the long-term testing was to 

operate GR-SI during the normal operating cycle of the 

Lakeside unit. ‘Ihe unit typically operated in cycling 

service with a very low capacity factor, so testing was 

conducted whenever the unit was operated. The average 

NOx reduction after 249 hours of gas rebuming operation was 67%. The average SO, reduction after 221 

hours of GR-SI operation was 58%. During GR-SI 

operation there was a 0.8% drop in thermal efficiency 

due to tbe fuel switch and a small increase in the exit 

flue gas temperature. 

During extended tests that included a 38.hr GR-SI 

continuous run, a 115.hr GR-only continuous nut. and a 

66-hr continuous GR-SI run, process operation with 

variable load met the project goals of 60% NO% reduction 

and 50% SO, reduction. No significant boiler or ESP 

impacts were observed. Compliance test results for 

particulate emissions averaged 0.016 lb/million Btu, well 

below the limit of 0. I lb/million Btu. 

City Water Light and Power is retaining the equip 

ment for possible future use. Restoration involves preparing the system for long-term storage. 

Commercial Applications: 

Gas reburning and sorbent injection is a 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 die United States 

alone, these two technologies can be applied to more 

than 900 pm-NSPS utility boilers; the t&nologies 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 coals. 

Project Schedule: 

DOE selected project (CCT-I) 7f2.4186 

Cooperative agreement awarded 7/14/87 

NEPA process completed, Hennepin (MTF) 5/9/88 

Environmental monitoring plan completed, 

Hennepin 10/15/89 

Lakeside 11115/89 

Construction. Hennepin 5/X9-8/91 

Operational testing, Hennepin l/91-1/93 

Restoration completed, Hetmepin 12l93 

NEPA process completed, Lakeside (EA) 6/25/89 

Construction, Lakeside 6/9C-5i92 

Operational testing, Lakeside 5/93-10194 

Restoration completed, Lakeside 12/95 

Project completed 1 a96 

Final Reports: 

Final Technical Report, Hetmepin 10194 

Final Technical Report, Edwards 10194 

Final Technical Report, Lakeside 1 Z96 

Economic Evaluation Report 12i96 

Public Design Report 12l96 

c9 
Environmental Comd Devics 

Combined SO,nVO.Control Technologiiss 

Milliken Clean Coal 

Technology Demonstration 

Project Project 

Participant: 

New York State Electric & Gas Corporation 

Additional Team Members: 

New York State Energy Research and Development 

Administration-cofunder 

Empire State Electric Energy Research Corporationcotbnder 

Consolidation Coal Company-technical consultant 

Saarberg-falter-UmwelttechnikGmbH--technology 

supplier 

The Stebbins Engineering and Manufacturing 

Company-technology supplier 

Nalco Fuel Tech--technology supplier 

ABB Ait Preheater, lx-technology supplier 

DHR Technologies, Inc.-operatorof advisor system 

Location: 

Laming, Tompkins County, NY (New York State Electric 

&Gas Coqmation’s Milliken Station, Units 1 and 2) 

Technology: 

Flue gas cleanup using Saarberg-Helter-Umwelttechnik’s 

(S-H-U) formic-acid-enhanced, wet limestone scrubber 

technology; ABB Combustion Engineering’s Low-NO% 

Concentric Firing System (LNCFSW) Level m; N&o 

Fuel Tech’s NOPUT” urea injection system; Stebbins’ 

tile-lined split-module absorber: and ABB Air 

Preheater’s heat-pipe air-heater system 

NO,OvTi~ .a registered tradema& of NPleo F”d ksh 

LNCFS is I trrdemti of ABB Combustirn Engineering, ,nc 

PEOA is a tmdenlark Of DHR Tchnolagiw, Inc. 

Plant CapacityiProduction: 

300 Mwe 

Project Funding: 

Total Project Cost $158,607.807 

TechnologyiProject Description: 

The S-H-U wet flue gas desulfiuization process is a 

formic-acid-enhanced, wet limestone process which 

100% 

results in very high SO, removal with low energy consumption and the production of commercial-grade 

DOE 45.ooo.ooo 28 

Participant 113,607&n 72 

Project Objective: 

To demonsaate 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 

to increase SO2 removal in a Stebbins tile-lined scrubber, 

low-NO” burner, urea injection for NO” removal, and a 

heat-pipe air preheater. 

gypsum. 

The flue gas desulfmization abs~~t+xx is a Stebbins 

tile-lined split-module vessel which has superior cormsion and abrasion resistance, leading to decreased lifecycle costs and reduced maintenance. The split-module 

design is constructed below the stack to save space and 

provide ope.rationaJ flexibility. 

The Nako Fuel Tech NOxOW system is used to 

remow NOx by injecting urea into the boiler flue gas. 

This facet of the project, in conjunction with other com- 
rado coal, with a short test using low-sulfur (0.35%) 

subbituminous Wyoming coal. 

Project Results/Accomplishments: 

Operational testing of the boiler with low-NO, bumen 

and ove.rlirc air SW in early August 1992. while 

firing western bituminous coal, NOx was reduced from 

an original baseline of I .15 Ibs/million BN to about 0.4 

lb/million BN--a 65% reduction-with no operating 

problems. In-furnace urea injection resulted in a 44% 

NO% reduction at full load with a lO-ppm ammonia slip, 

but at low load, only 11% NO, reduction was obtained. 

New retractable injection lances were installed in April 

1995, and NOxreduction at low load was improved to 

35% at IO-ppm slip. Sodium-bicarbonate injection 

achieved more than 70% SOz removal at a stoichiometric 

ratio of approximately 1.0. Sodium sesqoicarbaate 

injection after the air heater also obtained a 1% SO, 

removal but at a stoichiometric ratio of approximately 

1.8. Calcium-based dry reagent injection achieved a 

maximum of 40% SO, removal and caused some operational concems. Overall NO, reduction of 80% has been 

demonstrated at full load with the integrated sodium and 

una injection system. 

A 2.week test bum of Power River Basin coal was 

completed doting November 1995. SO, emissions were 

reduced about 20% due to the lower sulfur content of the 

cod. NOx emissions decreased by 25-30% at both 60 

and 80 MWe. 

Testing of the integrated system was completed in 

March 1996. The system worked as expected and significantly decreased NO, emissions that occur due to 

sodium injection and the ammonia emissions that occur 

due to urea injection. The project goal of obtaining 70% 

SO* and NO, reductions was demonstrated. The combination of sodium and urea injection allowed much 

higher urea injection while maintaining stack ammonia 

concematioE. of 10 ppm or less. The control system 

was adjusted to allow a maximum of 5 ppm ammonia 

Envimnmenrol Control Devices 

concentration at the stack, and the ammonia concentmtion in the flyash unloading area was greatly reduced. 

The project has been extended through February 1997 to 

test and evaluate an improved urea lance design. 

Four series of air toxics testing have been comFinal Reports: 

Final Technical Repon 

Economic Evaluation Report 

Public Design Report 

pleted. Results indicate that the baghouse successfully 

removes nearly all trace metal emissions and nearly 80% 

of the menxny emissions. Radionuclides, semi-volatile 

organic compounds. and dioxins/forans were below or 

very near their detection limits. 

Arapahoe 4 has operated more than 33,700 hours 

since combustion modifications were completed in May 

1992. The availability factor during this period was over 

91%. 

Due to the successful application of the system, the 

Public Service Company of Colorado plans to continue 

operation of the combustion modifications and the sodium-based dry sorbent injection system. A final decision on the selective noncatalytic reduction system will 

be made after the test program is completed. 

Commercial Applications: 

Either the entire integrated dry NOJSO, emissions control system or the individual technologies are applicable 

to most utility and industrial coal-f& units. They pmvide a lower capital-cost alternative to conventional wet 

flue gas desulfulization processes. They can be retmfltted 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. 

Project Schedule: 

DOE selected project (CCT-El) u/19/89 

Cooperative agrmnem awarded 3/11/91 

NEPA process completed (MTF) 9/27&w 

Environmental monitoring plan completed 8l5l93 

ConstNction 5l91-8192 

Operational testing 8l92-3196 

Project completed 2J97 

65 
Coal Processing 

for Clean Fuels 

Fact Sheets 
Coal Processing for Clean Fuels 

Cod Preparation Techmbgi~s 

Development of the Coal 

Quality Expert 

Project completed. 

Participants: 

ABB Combustion Engineering, Inc. 

CQ Inc. 

Additional Team Members: 

Black and Veatch-cofunder and software 

Electric Power Research I”stiNte~of”“der 

The B&cock & Wilcox Company--fofunder and 

pilot-scale tester 

Electric Power Technologies, Inc.-field tester 

University of North Dakota, Energy and Environmental 

Research Center-bath-scale tester 

Alabama Power Company-host 

Mississippi Power Company-host 

New England Power Company-host 

Northern States Power Company-host 

Public Service Company of Oklahoma-host 

Locations: 

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

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

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

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

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

Somerset, Bristol County, MA (Brayton Point Units 2 

Plant Capacity/Production: TechnologylProject Description: 

Full-scale testing took place at six utility sites ranging in Data derived from bench-, pilot-, and full-scale testing 

size from 250 to 880 MWe. were used co develop algorithms for inclusion into a 

Project Funding: 

state-of-the-art sofiware package, the Coal Quality ExTotal project cost $21,746,004 ICOB 

pert, that can be run on a personal computer. utilities 

DOE 10.863.911 50 

may use CQE to predict the operating perfomxmce ‘md 

Participants 10.882.093 50 

cost of coals not previously burned at a pticular 

facility. 

Project Objective: 

and 3) 

Bayport, Washington Cwnty, MN (King Station) 

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

Technology: 

CQ Inc.‘s EPRI Coal Quality Expert (CQE) computer 

software 

To develop and demonstrate a personal computer software package that will serve as a predictive tool to assist 

coal-burning utilities in the selection of optimum quality 

coal for a specific boiler based on operational efficiency, 

cost, pnd environmental emissions. 

Six large-scale field tests consisted of burning a 

. .- . . . . ^ oasemte coal an0 a” aKmme mad owx a Id-cnonm perid The baseline coal was “scd to characterize the 

operating performance of the boiler. The alternate coal, 

” blended or cleaned coal of improved quality, was 

burned in the boiler for the remaining test period. 

6.8 Coal Processing for Ckan Fuck 
The badine and akmnate coals for each test site 

also were burned in bench- and pilot-scale facilities 

under similar conditions. T& alternate coal was cleaned 

at CQ Inc. to determine what quality levels of clean coal 

can be produced e-conomically and then uansported to 

the. bench- and pilot-scale facilities for testing. All &ta 

from bench-, pilot-, and full-scale facilities were cvaluated and an-related to formulate algorithms being used to 

develop the model. 

Bench-scale testing was performed at ABB Combustion Engineering’s facilities in Windsor, Cl’, and the 

University of North Dakota’s Energy and Envimnmental 

Research Cater in Grand Forks, ND; pilot-scale testing 

was performed at ABB Combustion Engineering’s faciiities in Windsor, CT, and Alliance, OH. The six field test 

sites were Catson, Unit 5 (880 MWe), Wilwxwille, AL; 

Watson, Unit 4 (250 MWe), Gulfport, MS; Brayton 

Point, Unit 2 (285 MWe) and Unit 3 (615 MWe), 

Somerset, MA; King Station (560 Ml%), Bayport, MN; 

and Northeastern, Unit 4 (445 MWe), Oologah, OK. 

Project Results/Accomplishments: 

More than 100 algorithms based on data generated from 

six Ii&scale field tests have been developed. Acid Rain 

Advisor s&ware became available in 1992. with two 

commercial sales made (one in 1993 and one. in 1995). 

Debugging of the CQE software pmceded thmugh 

the end of the project. A CQE beta version was t&ased 

in May 1995 and evaluated by several utilities by July 

1995. The initial commercial version of CQE was released in December 1995. CQE has been disbibuted ta 

about 35 U.S. utilities and 1 U.K. utility through their 

memberships in EPRI. 

A CQE home page has been created on the World 

Wide Web ta promote CQE. facilitate communications 

with and among CQE users, and distribute an easily 

updated electmnic user’s manual. 

An update of CQE, version 1 .l, is planned for late 

1996, and the software may be migrated from OS/2 to 

winQws95orNT. 

The final report is being prepared. 

Commercial Applications: 

The software will enable coal-fired utilities to select the 

optimum quality coals for their specific boilers to reduce 

SO,, NO,, and paticulate emissions and ta achieve the 

lowest operating costs. 

Ihe CQE system is applicable to all electric power 

plants and industrial/institutional boilers that bum pulverized coal. The system can predict the operational 

benefits of using alternative or cleaned coals. 

CQ Inc. and Black and Veatch have signed a canmercialization agreement which gives Black and Veatch 

nonexclusive worldwide rights to sell usas licenxs and 

to offer consulting services that include the use of CQE 

sotiware. 

Project Schedule: 

DOE selected project (CCT-I) 12/9/88 

cooperative agnetnent awarded 6/14/90 

NEPA process completed (hlTF) 4/27/90 

Environmental monitoring plan completed 7/31/90 

opxational testing 8/90-l/96 

Project completed 1296 

Final Reports: 

Final Technical Report 12&x 

CQE Sot%xe 

Final version released 9l96 

First commercial version released 1295 

Cool Proccssin~ for Ckma F&s 69 
Coal Processing for Clean Fuels 

Coal Preparation Technologies 

Self-Scrubbing CoalTM: An 

Integrated Approach to Clean 

Air 

Participant: 

Custom Coals International (a joint venture between Genesis Coals Limited Partnership and Genesis Research 

Corporation) 

Additional Team Members: 

Pennsylvania Power & Light Company-host 

Richmond Power & Light-host 

Cent&x Service Company-host 

Locations: 

Central City, Somerset County, PA (advanced 

coal-cleaning plant) 

Lower Mt. Bethel Township, Northampton County, PA 

(combustion tests at Pennsylvania Power & Light’s 

Martin’s Creek Power Station, Unit 2) 

Richmond, Wayne County, IN (combustion tests at 

Richmond Power & Light’s Whitewater Valley 

Generating Station, Unit No. 2) 

Ashtabula, Tmmbull County, OH (combustion tests at 

Centerior Energy’s Ashtabula C) 

Technology: 

Coal preparation using Custom Coals’ advanced physical 

coal-cleaning and tine magnetite separation technology 

plus sorbat addition technology 

Plant Capacity/Production: 

500 tonsihr 

Project Funding: 

Total pmject cost 

DOE 

Participant 

70 

$87,386,102 100% 

37.994.431 43 

49,391,665 57 

L 

Project Objective: 

To demonstrate advanced coal-cleaning unit processes to 

produce low-cost compliance coals that can meet full requirements for commercial-scale utility power plants to 

satisfy CAAA of 1990 provisions. 

Technology/Project Description: 

An advanced coal-cleaning plant has been designed, 

blending existing and new processes, to produce, from 

high-sulfur bituminous feedstocks, two types of compliance coals--Carefree Coalw and Self-Scmbbing Coal”“. 

Carefree CoalTM 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 the pyritic sulfur and most of the ash. Carefree Coal”” 

Self-Scmbbing Cd and carefree Cd are trademarks ofcusmn coals 

I”tMdWd. 

is designed to be a competitively priced, highBtu fuel that 

can be used without major plant modifications or additional 

capital expendiNns. While many utilities can use Carefree 

Coal” to comply with SO, emissions limits, others cantwt 

due to the high content of organic sulfur in their coal feedstocks. When compliance coal cannot be pmduced by 

reducing pyritic sulfur, Self-Scrubbing Coalw can be pmduced to achieve compliance. 

Self-Scrubbing Co@’ is produced by taking Carefree 

Co@‘, with its reduced pyritic sultiu and ash content, and 

adding to it sabents, pmmoters, and catalysts. Self-Scmbbing CoalR” 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@’ permits the addition of relatively large 

amounts of sorbent without exceeding the ash specificaCoal Processing for Clean Fuels 
MtXd6lr~W 

,591 1532 1993 1994 ,995 

1 :“3 4 1 

1997 

341234 

,998 

1234 I 1539 

234 1 2CCO 

2 3 4 

2031 

2 3 4 12341 234 1 234 12 

991 W/92 2l96 6l97 

1 proaward , DeeignandCon&ruetion Operation I 

“.~::~~:;,~,.~.,>.,“.,::.,,:-~~~~~~~~~ 

;i:D~~~~~,~cl”~;~~;,~;-~~,,,-.. ‘a~~:~~~-li-_...,,;:;s-i_,;,i 

- 

DOE s&cted mmp(etd 237’ 

Pmjea mmpletedllinal npod issued 6/97 

y$$CCT-W Operation initiated 2/96 

Envimnmental monitmiw Plan ComPkd Y&W 

Pmoperational t&s initiated Ilk35 

Constrwtion completed 11195 

Oasign completed W94 

rep.4 process completed (EAI 204/94 

corstNcficil stmkd 1203 

cooperatiw agreement awarded 1oEw92 ‘Plc+cted date 

tions of the bailer or overloading the electrostatic precipitator. 

A 500~to&r advanced coal-cleaning plant is located at a site near Central City, PA. Two medium- to 

high-sulfur coals-Illinois No. 5 (2.7% sulfur) and 

Lower Freepon Seam coal (3.9% sulfur)--are being used 

to produce Self-Scrubbing CoalwM. Carefree Coal” is 

being made using Lower Kittanning Seam coal (1.8% 

sulfur). The Lower Kittanning coal is being tested at 

Martin’s Creek Power Station; the Illinois No. 5 coal is 

being tested at Whitewater Valley Generating Station; 

and the Lower Freepal Seam coal is being tested at 

Ashtiula C. 

Project Status/Accomplishments: 

Since February 1996, the facility has operated 900 hours. 

received 301,000 tons of raw coal, processed 289,ooO 

tons of raw coal, and pmduced 208,OGQ tons of clean 

coal. Clean coal quality has averaged 8.5% ash and 1% 

or less sulfur (SO* content of 1.2 IbsJmillion BN). 

CoalScan continues to make adjustments to the analyzer 

and calibrated the unit during July 1996. Approximately 

36,OWl tons of compliance steam coal were shipped to 

Homer City in July. Four unit trains (appmximately 

28.800 tons) were shipped to PEPCO during June 19% 

and another unit train (7.200 tons) was shipped in July. 

The first unit train (7.200 ton) of metallurigical coal was 

shipped May 29.1996. 

Bank performance testing began in June 1996 and is 

nearly completed. 

Commercial Applications: 

Commercialization of Self-Scrubbing Co@’ has the 

potential of bringing into compliance about 164 million 

tonslyr of bituminous coal that cannut meet emissions 

limits through conventional coal cleaning. This represents mure than 38% of the bituminous coal burned in 

50.MWe or larger U.S. generating stations. 

The technology prcduces coal products that can be 

used to reduce a utility or industrial paver plant’s total 

sulfur emissions 8&90%. 

In August 1994, a U.S.-led consortium with Custom 

Coals Corporation as the principal partner signed a cooperative agreement with the People’s Republic of China to 

build a coal-cleaning plant, a 5OOmile underground 

slurry pipeline, and pat facility. The pipeline will bring 

coal from the ShanXi province in northwest China to the 

coastal province of Shandong. The work included under 

the agreement is valued at $888.6 million. 

Custom Coals is aggressively marketing the technology in Eastern Europe and has received letters of 

intent from three Polish paver plants that wish to produce 7.5 million tonsJyr of cleaned coal. 

Custom Coals also has a proposed agreement with 

domestic coal-marketing companies for 1 million tons of 

compliance coal annually. 

Coat Processing for Clean Fuels 71 
Coal Processing for Clean Fuels 

Coal Preparation Technologies 

Advanced Coal Conversion 

Process Demonstration 

Participant: 

Rosebud SynCoalPartnership (a partnership between 

Western Energy Company and the NRG Group, a 

nonregulated subsidiary of Northern States Power 

C*wW 

Additional Team Member: 

None 

Location: 

Colstrip, Rosebud County. MT (adjacent to Western 

Energy Company’s Rosebud Mine) 

Technology: 

Rosebud SynCoalPartnership’s advanced coal 

conversion process for upgrading low-rank 

subbituminous and lignite coals 

Plant Capacity/Production: 

45 ton.vlu of SynCoal~ pmdwt (3OQ,coO t”“s/yr) 

Project Funding: 

Total project cost $105,7OwoO 100% 

DOE 43.125,OOO 41 

Participant 62,575.ooO 59 

Project Objective: 

To demonstmte Rosebud SynCoal’s advanced coal conversion process to pmdwe SynCoalb, a stable coal pmduct having a moishre c”ntent as low as 1%. sulfur content as low as 0.3% and heating value up to 12,000 

Btib. 

syncoat is a regisfual u*rn* orthe It*“* SyTcdP*enhip. 

r 

TechnologyfProject Description: Tl~e 45-ton/hr unit is located adjacent to a unit train 

Being demonstrated is a” advanced thermal coal conver- loadout facility at Western Energy Company’s Rosebud 

sion pmcess coupled with physical cleaning techniques to coal tie in C&tip, MT. The demonstration plant is 

upgrade high-moisture, low-rank coals to pmduce a high- one-tenth the size of a wnunercial facility. However, the 

quality, low-sulfur fuel. The coal is pmcessed thmugh pmcess equipment is at I/3-1/2 commercial scale betw” fluidized-bed dryer/reactors that rem”ve loosely held cause a full-sized commercial plant will have multiple 

water and then chemically bound water, cartaxyl groups. pmcess trains. 

and volatile sulfur compounds. After conversion, the 

coal is put thmugh a deep-bed stratifier cleaning prccess 

to effect separation of the ash. 

The technology enhances low-rank weStem coals, 

usdiy with a moisture content of 25-4096, m&u content of 0.5-1.5%. and heating value of 5,50&9,aoO 

Bm/lb. by producing a” upgraded SynCc# product with 

a moisture content as low a3 I %, sulhrr content a.9 low as 

0.3% and heating value up t” 12.000 Btu/lb. 

72 Coal Processing for ClrM Fuels 
CalendarYear 

,988 1989 ,990 1991 ,992 1993 ,994 1995 1996 1997 1998 

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

t 

1 A IfI 

t 

I TS, operation initiated s/s? 

DOE releoted project 

(03-I) 12Km 

Environmental monitoring p!an completed *I%? 

f I 

operation completed Em’ 

Construction completed ?.i32 Project completed/final 

Ccoperativ* agreement Preoperational tests initiated 12/91 

rep”” issued 11,w’ 

awarded 9/21/90 

Design canpled W31 

Ground brealdnglconstrwtion started Z&W91 

NEPA process completed (EA) 3/27/91 

‘Projected date 

Project Status/Accomplishments: 

It has processed more than one million tons of coal and 

produced nearly 825,CCQ tons of SynCoal@ products 

The demonstration facility continues reliable operation. 

through July 1996. Rosebud continues to supply different products to a range of customers, including industrial, institutional, and utility users. Total sales of 

SynCoaF product have exceeded 720,000 tons. 

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

Commercial Applications: 

subbituminous and lignite coals. Many of the power 

plants located throughout the upper Midwest have cyRosebud SynCoal’s advanced coal conversion process 

clone boilers. which bum low-ash-fusion-temperature 

coals. Presently, most of these plants bum Illinois Basin 

high-sulfor coal. SynCoal@ is an ideal low-sulfor coal 

substitute for these and other plants because it allows 

operation under more restrictive emissions guidelines 

without requiring derating of the units or the addition of 

costly flue gas desulfurization systems. The advanced 

coal conversion process produces SynCoal@ which has a 

consistently low moisture content, a low sulfur content, a 

high heating value, and a high volatile content. Because 

of these characteristics. SynCoal”could have significant 

impact on SO, reduction and provide a clean, economical 

alternative fuel to many regional industrial facilities and 

small utilities being forced to use fuel oil and natural 

gas. Rosebud SynCoal‘s process, therefore, will be 

attractive to industry and utilities because the upgraded 

fuel will be less costly to use than would the constroction and use of flue gas desulfurization equipment. This 

will allow plants that would otherwise be closed toremain in operation. 

SynCoalB products have been delivered to several 

industrial and utility customers, including Ash Grove 

Cement, Bentonite Corporation, Wyoming Lime, Continental Lime, Empire Sand and Gravel. Montana Power, 

Minnkota Power, and the University of Nonh Dakota. 

The participant has negotiated a contract with Colstrip 

Units I and 2 to take excess production of SynCoal@ 

after Colstrip Units 3 and 4 were switched to a Wyoming 

coal supplier. 

Rosebud SynCoal Partnership conducted a 

$Zmillion study for Minnkota Power Cooperative to 

examine the merits of applying the coal-processing technology to a commercial plant integrated into an existing 

power plant site. The study’s results have been positive, 

but market commitments are still necessary. The partnership is working on plans for two semi-commercial 

projects, one each in Wyoming and Montana. 

Extended kiln testing is continuing at Wyoming 

Lime. 

Cool Processing for Clean Fuels 73 
Coal Processing for Clean Fuels 

Mild Gasification 

ENCOAL Mild Coal 

Gasification Project 

Participant: 

ENCOAL Caporation (a subsidiary of SMC 

Mining Company, which is a unit of Zeigler Coal 

Holding Company) 

Additional Team Members: 

SMC Mining Company-cofunder 

TEK-KOL (partn.~d~ip between SMC Mining Company 

and SGI Intemation@-technology owner, supplier, 

and licenser 

SGI International-technology developer 

Trim” Coal Company (subsidiary of SMC Mining 

Company)Amst and coal supplier 

‘Ibe M.W. Kellogg Company+ngi”ecr and 

Location: 

Near Gillette, Campbell County, WY f.Triton Coal 

Company’s Buckskin Mine) 

Technology: 

SGI Intmmtinn~s liquids from coal FSS 

Plant Capacity/Production: 

1,000 tons/day of subbituminous coal feed 

Project Funding: 

Total project cost $90664,ooo 100% 

DOE 45,332,OOO 50 

Participant 45,332,OOO 50 

Project Objective: 

To demonstrate the integrated operation of a “umber of 

tXWd Q-Sing SkQS to QIdUCe tW” higher value fuel 

forms fmm mild gasification of low-sulfur subbitumi74 

““us coal; and to provide sufficient Qtducts for potential material. Solids exiting the pymlyzer are cc&d and 

end users to conduct bum tests. transferred to a process-derived fuel (PDF) storage bin. 

Technology/Project Description: 

The ENCOAL mild coal gasification process involves 

heating coal under caretiAly contmlled 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. ‘Ike 

solid bulk temperature is controlled so that no significant 

amounts of methane, CO, or CO, are released from the 

coal. The solids fmm the dryer are conveyed to the pyrelyzer where the rate of heating of the solids and residence 

time are controlled to achieve desired properties of the 

fuel prnducts. During pmcessing in the pyrnlyzer, all 

remaining free water is removed, and a chemical reaction 

nccun that results in the release of volatile gaseous 

The gas Qrod”C.?d in the Qy”,lyZer is Sent thmugh a 

cyclone for removal of the Qticulates and then cooled 

to condense the liquid-fuel products, or coal-derived 

liquids (CDL). Most of the gas from the condensation 

unit is recycled to the pyrnlyzer. The rest of the gas is 

burned in combustors to provide heat for the pyrolyzer 

and the dryer. NOc emissions are controlled by staged 

air injection. 

The offgas horn the dryer is treated in a wet venturi 

scrubber to remove paticulates and a horizontal scrubber 

to remwe 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. 

Cd Processing for Clean Fuels 
Calendar&w 

1988 1999 1990 1991 19% 1993 1995 ,996 I997 19% 

3 4 1 2 3 4 1234 1 2 3 4 1234 1 2 3 4 1 :“3 4 1 2 3 4 12341 234 12 

Constfuct~ mmpleted &92 

Environmental monitoring plan completed !X?9/82 

Pmoperationat 18618 initiated 4&z? 

De&,” completed 7iW 

onwnd brea!dnglconstrucson stalted loLa%o 

report issued 3197’ 

Operation mmp!eted 397’ 

1 ‘&+xative agreement awarded g/17/90 

NEPA p- completed (EA) 8/l/90 

Tl~e ENCOAL project is located within Campbell 

County, WY, at T&on Coal Company’s Buckskin Mine, 

10 miles nottb of Gillette. The plant makes use of the 

present coal-handling facilities at the mine. SubbiNminous coal with 0.449% sulfur content is being used. 

ENCOAL also shipped 12 tank cars of CDL to Michigan 

and Maine and another 13 tank cars of CDL to a Louisiana refinery. 

ENCOAL has negotiated the sale of 10,000 tons of 

PDF to Bethlehem Steel for use as a blast furnace fuel 

injectant. BNCOAL is also negotiating a similar sale N 

another major steel producer. 

the increased heating value (about 12,000 BMb) and 

lower sulfur content (per unit of fuel value) of the new 

solid-fuel product compared to the low-rank coal feedstock, and the production of low-sulfur liquid pmducts 

requiring no further treatment for the fuel oil market. 

Project Status/Accomplishments: 

?he plant officially entered the production mode in June 

1994; operation has bee” at a coal feed rate of 500 tons/ 

day. By mid-1996 the QkX”t had logged more than 9,200 

hours of operation on coal. By the end of July 1996, 

more than 63,COl tons of solid product and mote tha” 

2.5 million gallons of liquid product had bee” shipped to 

hxiustrid and utility customers. 

‘l-h.2 QdUCt f”dS Wt eXQEkd to be Used WZO”O”,iCdly 

in commercial boilers and furnaces and to reduce significantly SO2 emissions at industrial and utility facilities 

cm’mntly burning high-s&m bituminws coals or fuel oils. 

Design has begun cm * large commercial “grain 

drye? for full-scale passivation of PDF. 

ENCOAL also has begun construction of a pcmw- 

“em wastewater disposal pond. 

Commercial Applications: 

As a result of the very successlid PDF combustion 

test in a pulvefized-cod boiler by the American Electric 

Power Company, a ““it train of Q,“E PDF was shipped to 

a major Missouri utility where it was successfully 

handled and burned. 

The liquid products from mild coal gasification can be 

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

solid product ca” be used in most industrial or utility 

boilers and also shows pmndse for imn ore reduction 

applications. The feedstock for mild gasification is 

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

US. Steel successh~lly tested two tank cars of CDL The potential benefits of this mild gasification techas a” injectant fuel in B Gary, IN, blast furnace. nology in its commercial configuration are attributable to 

Numerous feasibility ?.Ndies have been pexfomxd 

for both domestic and intemational clients who are ptimadly interested in upgrading their low-rank coal reserves. TBK-KOL and Mitsubishi Heavy Industries are 

performing advanced feasibility studies regarding joint 

engineering, design, and construction of commercial 

plants in Indonesia, China, and Russia. TBK-KOL is 

also negotiating with Japanese trading companies to 

market both liquid and solid products in Southeast Asia. 

Cd Processing for Clean Fuels 75 
Coal Processing for Clean Fuels 

Indirect Liquefaction 

Commercial-Scale 

Demonstration of the Liquid- 

;F:haieAethanol (LPMEOHTM) 

Participant: 

Air Products Liquid Phase Conversion Company, L.P. 

(a limited partnership between Air Products and 

Chemicals, Inc., the general partner, and Eastman 

Chemical Company) 

Additional Team Members: 

Air Products and Chemicals, Inc.-technology supplier 

and cofunder 

Eastman Chemical Company-host: operator; synthesis 

gas and services provider 

Acurex Environmental Corporation-fuel methanol 

tester and cofunder 

Electric Power Research Institute-fuel methanol test 

advisor 

Location: 

Kingsport, Sullivan County, TN (Eastman Chemical 

Company’s Integrated Coal Gasification Facility) 

Technology: 

Air Products and Chemicals’ liquid-phase methanol 

(LPMEOF) process 

Plant Capacity/Production: 

80,000 gallons/day of methanol (nominal) 

Project Funding: 

Total project cost $213,7CO,OOO 

DOE 92.708.370 

Participant 120.991.630 

LPMEOH is a trademark ofAir Prducts and amnicalr, Inc. 

76 

100% 

43 

57 

Project Objective: 

To demonstrate on a commercial scale the production of 

methanol from coal-derived synthesis gas using the 

LPMEOP process; and to determine the suitability of 

methanol produced during this demonstration for use as a 

chemical feedstock or as a low-SO+ towNOx alternative 

fuel in stationary and transportation applications. If 

practical, the production of dimethyl ether (DME) as a 

mixed coproduct with methanol also will be demonstrated. 

Technology/Project Description: 

This project is demonstrating, at commercial scale, the 

LPMEOW process to produce methanol from coalderived synthesis gas. The combined reactor and heat 

removal system is different from other commercial 

methanol processes. The liquid phase not only SW 

pads the catalyst but functions as an efficient means to 

remove the heat of reaction away from the catalyst 

surface. This feature permits the direct use of synthesis 

gas streams as feed to the reactor without the need for 

shift conversion. 

The Eastman Chemical Company’s integrated coal 

gasification facility at Kingspott, TN, has operated 

commercially since 1983. At this site, it will be passible to ramp up and down to demonstrate the unique 

load-following flexibility of the LPMEOHn” unit for 

application to coal-based electric power generation 

facilities. Methanol fuel testing will be conducted in 

off-site stationary and mobile applications, such as fuel 

cells, buses, and distributed electric power generation. 

Design verification testing for the production of DME 

Coal Processing for Clam Fuels 
CalendarYear 

1991 ,992 1533 ,994 199.5 1997 1999 2ccm MO1 

341234 1 234 1 234 1 2 3 4 1 :=3 4 1 2 3 4 1 :“3 4 1 234 1 234 12 

/ !I 

t 

t 

Dperation initiated 2197’ 

Preoperaticml tssts initiated 12/96’ 

Construction completed 12/S’ 

E”vimnmental mmitodrg plan ccmpleted 8/96 

Operation c.mp!-s.ted 301’ 

Pmiectcompletedllinal report issued 1201’ 

Design mmpleted 6/96 

I 

kJns1luucli0” started lois5 

NEPA process ccmpleted (EA) 6/30/95 

Coc~erative agreement awarded 10116/92 *Projected date 

as a mixed coproduct with methanol for use as a storable 

fuel is planned, and a decision on whether or not to 

demonstrate will be made. Eastern high-sulfur bituminnus coal (Mason seam) containing 3% sulfur (5% maximum) and 10% ash will bc used. 

Project Statue/Accomplishments: 

Construction activities are at their peak. The liquidphase reactor was installed on July 2, 1996. All other 

major process equipment has been installed, and the 

installation of StNCNral and pipe rack steel, process 

piping, and electrical and instrumentation equipment is 

continuing on schedule. Cwstmction is scheduled to be 

completed in late December 1996, with start-up expected 

to begin in early 1997. 

Commercial Applications: 

The LPMEOHM process has been developed to enhance 

integrated gasification combine&cycle (IGCC) power 

generation by producing a clean burning, storable liquid 

fuel-methanol-from the clean coal-derived gas. 

Methanol also has a broad range of commercial applications. can be substituted for conventional fuels in stationm-y and mobile combustion applications, is an excellent 

fuel for utility peaking units, contains no sulfur, and has 

exceptionally low-NO” characteristics when burned. 

Methanol can b=e produced from coal as a copmduct in 

an IGCC facility. 

Products and Chemicals expects to market the 

LPMEOV technology through licensing, owning/ 

operating. and tolling arrangements. 

DME has several commercial uses. In a storable 

blend with methanol. the mixture can be used as peaking 

fuel in IGCC electric power generating facilities. Blends 

of methanol and DME can also be used as a chemical 

feedstock for the synthesis of chemicals or new, oxygenate fuel additives. Pure DME has been gaining acceptance as an environmentally friendly aemsol in personal 

pIOd”CU. 

ppic.4 commercial-scale LPMEOT units are 

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

methanol produced when associated with commercial 

IGCC power generation trains of ZOO-350 MWe. Air 

Cd Processing for Clean Fuels 77 
Industrial Applications 

Fact Sheets 
fndusfrial Applications 

Blast Furnace GranulatedCoal Injection System 

Demonstration Project 

Participant: 

Bethlehem Steel Corporation 

Additional Team Members: 

British Steel Consultants Overseas Services, Inc. 

(marketing arm of British Steel Corporation)- 

technology owner 

Simon-Macawber, Ltd.+quipment supplier 

Fluor Daniel, Inc.-architect and engineer 

ATSI, Inc.-injection equipment engineer 

(U.S. technology licensee) 

Location: 

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

Bums Hartor Plant, Blast Furnace Units C and D) 

Technology: 

British Steel’s blast furnace granulated-coal injection 

(BFGCI) process 

Plant Capacity/Production: 

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

Project Funding: 

Total project cost $191,7oo,ooo 100% 

DOE 3 I ,259,530 16 

Pa&ipant 160,440,470 84 

Project Objective: 

To demonstrate that existing iron-making blast furnaces 

can be racditted 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. 

80 

TO STEELMAKNG 

!- 

Technology/Project Description: 

In the BFGCI process, both granulated and pulverized 

coal is injected into the blast htmace in place of natural 

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

along with heated air is blown into the bamel-shaped 

section in the lower part of the blast furnace through 

passages called tuyeres, which creates swept zones in 

the furnace called raceways. The size of a raceway is 

important and is dependent upon many factors including 

temperature. Lowering of a raceway temperature. 

which can occur with gas injection. reduces blast furnace production rates. Coal, with a lower hydrogen 

content than either gas or oil, does not cause BS were a 

reduction in raceway temperatures. In addition to displacing injected natural gas, the coal injected through 

the tnyeres displaces coke, the primary blast furnace 

fuel and reductant (reducing agent), on approximately a 

pound-for-pound basis. Because coke production results 

in significant emissions of NO,. SO,, and air toxics and 

coal could replace up to 40% of the coke requirement, 

BFGCI t@nology has significant potential to reduce 

emissions and enhance blast furnace production. 

Emissions generated by the blast furnace itself remain vhtually 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 real&d by coke displacement, blast tiunace pmduction is increased by maintaining high raceway temperatures. 

Indumial Applicarions 
cahldar mar 

1989 ,990 1991 1992 1993 ,994 1995 ,993 1997 1998 ,998 

3 4 1 2 3 4 1 234 1 234 1 2 3 4 1 2341234, 2 3 4 1 234 1 234 12 

bOE selected 

y~8~C”““” b Lpemtion initiated II/95 

PreOperatcml tests initiated 2kX 

Crmstructi~ completed Z95 

Environmental monitoling plan wnpleted 12/2?J94 

sign completed IL?/%3 

Construction stalted g/Q3 Pmiect comoletedlfinal won 

I 

I 

NEPA process cm~leted (EA) WW93 

ccGpefa,,w agreement awarded 1 lm390 

issued 9i98* 

Operation comgleled 9/98* 

*Pmjecbd date 

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

Bethlehem Steel Corporation’s Bums Habor Plant, are 

being retrofitted with BFGCI technology. Each unit has a 

mined that this injection rate will be the new operating 

baseline for Furnace C for all future test coal comparisons. Furnace C also has been operated with a coke rate 

production capacity of 7,ooO net tons/day of hot metal. of approximately 650 Ibs/net ton of hot metal without 

The two units will use about 2,8M) tons/day of coal dur- coal injection, down from 770 IbsJnet ton. Furnace D 

ing full operation. Bituminous coals with sulfur content has been operated with a coal injection rate of approxiranging from 0.8% to 2.8% from West Virginia, Peonsyl- mately 190 lbslnet ton of hot metal, which is above its 

vmia, Illinois, and Kentucky are to be used. A western design paint of 180 Ibs/net ton. Bethlehem Steel has 

subbituminous coal having 0.449% sulfor might be completed repairs to a coal preparation plant necessitated 

tested also. by tramp organ& in recent coal supplies. 

any rank coal commercially available in the United 

States that has a moisture content no higher than 12%. 

The environmental impacts of commercial application 

are primarily indirect and consist of a significant reduction of emissions resulting from diminished coke-making requirements. 

Project Status/Accomplishments: 

Construction was completed in Febmary 1995. 

Bethlehem Steel submitted a public design report in 

March 1995. Stat-up testing has been completed, and 

the plant is folly commissioned. Operational testing 

began in November 1995. 

Furnace C has been operated with an average coal 

injection rate of 275 Ib%et ton of hot metal, using lowvolatile bituminous coals. Bethlehem Steel has deterBethlehem Steel plans to increase substantially the 

coal feed rate through all 52 toyeres for comparison with 

the baseline standard of 275 Ibs/net ton of hot metal on 

Furnace C. In addition, the purchase of lO,OtXl tons of 

ENCOAL’s process derived fuel is king negotiated for a 

future test. 

Commercial Applications: 

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

blast furnaces. The technology should be applicable to 

b&mid Applicaiom 81 
industrial Applications 

Advanced Cyclone Combustor 

with Internal Sulfur, Nitrogen, 

and Ash Control 

Project completed. 

Participant: 

Coal Tech Corporation 

Additional Team Members: 

Commonwealth of Pennsylvania Energy Development 

Authority-cofunder 

Pennsylvania Power and Light Company-supplier of 

test coals 

TampellaPowerCorporation-host 

Location: 

W~lliamspxt, Lycoming County, PA (Tampella Power 

Corporation’s boiler manufacturing plant) 

Technology: 

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

Plant Capacity/Production: 

23 million Bto/lu 

Project Funding: 

Total project cost 

DOE 

Participant 

$984,394 100% 

490,149 50 

494,245 50 

Project Objective: 

To demonstrate that an advanced cyclone combustor can 

be retrofitted to an industrial boiler and that it can simultaneously remove up to 90% of the SO, and 90-95% of 

the ash within the combustor and reduce Nor by up to 

loo ppm. 

TechnologylProject Description: 

cause cyclonic action. In this manner, coal-particle 

combustion takes place in a swirling flame in a region 

Coal Tech’s horizontal cyclone combustor is internally 

favomble to particle retention in the combustor. Secondary air is used to adjust the overall combustor stoichiomlined with ceramic that is air-cooled. Pulverized coal, 

etry. The ceramic liner is cooled by the secondary air 

and maintained at a temperature high enough to keep the 

air, and sorbent are injected tangentially toward the wall 

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

preheated by the combustor walls to attain efficient 

through tubes in the annular region of the combustor to 

combustion of the coal panicles in the fuel-rich 

cumbustor. Fine coal pulverization allows combustion 

of most of the coal particles near tbe cyclone wall, with 

taking place in the boiler furnace to which the combustor 

the balance burned on or near the wall. This improves 

is attached. 

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

retention. The slag contains more than 80% of the ash 

and sorbem fed to the combustor. For NO% control, the 

combustor is operated fuel rich, with final combustion 

Iu Coal Tech’s demonstration, an advanced, aircooled, cyclone coal combustor was ntmfitted to a 

23-million-Btu/hr, oil-designed package bailer located at 

the Tampella Power Corporation boiler factory in 

WIlliamsport, PA. Air cooling in this combustor takes 

place in a very compact combustor which cao be retrofitted to a wide range of industrial and utility boiler designs 

without disturbing the boiler’s water-steam circuit. NOx 

reduction is achieved by staged combustion, and SO, is 

82 tndunial Applicatiom 
captured by injection of limestone into tbe combustor. 

The cyclonic action inside the combustor forces the coal 

ash and sorbat to the walls where it can be collected as 

liquid slag. Under optimum operating conditions, the 

slag contains a significant fraction of vitrified coal sulfur. Downstream sorbent injection into tbe boiler pmvides additional sulfuur removal capacity. 

Project ResultdAccomplishments: 

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% and 

volatile matter ranging from 19% to 37% were tested. 

Under fuel-rich conditions, combustion efficiencies 

exceeded 99% after proper operating procedures were 

achieved. Turndown to 6 million Btullu from a peak of 

19 million Btoihr was achieved. Due to facility limits on 

water availability for the boiler and for cwling the combustor, the maximum heat input during the tests was 

approximately 20 million Btulhr even though the combustor was designed for 30 million Btulhr and the boiler 

was thermally rated at around 25 million Btuihr. 

Coal Tech repotled the following test results: 

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

reduction in boiler-outlet-stack NOx was obtained, 

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

additional S-IO% 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 (16Oppmv). 

Over 80% SO, reduction measured at the boiler outlet 

stack was achieved using sorbent injection in the 

furnace at various Cal.5 molar ratios. A maximum 

SO, reduction of 58% was measured at the stack with 

limestone injection into the combustor at a Ca/S of 2. 

A maximum of 33% of the coal sulfur was retained in 

lndusrrid Applicarionr 

the dry ash removed from the combustor and furnace 

hearths, and a high of I1 % 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 slag/so&at retention in the combustor, under 

efficient combustion operating conditions, averaged 

72% and ranged from 55% to 90%. Under more fuellean conditions, the slag retention averaged 80%. In 

post-CCT-project tests on flyash vitritication in the 

combustor, modifications to the solids injection 

method and increases in the slag flow rate produced 

substantial increases in the slag retention rate. 

All slag removed from the combustor produced trace 

metal leachates well below the EPA drinking water 

standard. 

Different sections of tbe 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 pmcedures, 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 computer-controlled 

system for automatic combustor operation. 

Commercial Applications: 

At the end of this demonstmtion, Coal Tech had concluded that, while tbe combustor was not at that time 

folly ready for sale with commercial guarantees, it was 

ready to be further scaled up for commercial applications 

(100 million Bto/hr), such as combustion of waste solid 

fuels, limited sulfur control in coal-tired boilers, and 

conversion of ash to slag. Since the CCT demonstration, 

a modified and improved version of the air-cooled combustor has been built and is currently being tested. Results so far indicate improvements in performance, and 

Coal Tech officials indicate that the technology is now 

commercially ready. 

Coal Tech’s advanced. air-cooled, slagging combustar can use a wide range of U.S. coals and can be retrcfitted to existing or new units. The target market is 

industrial and utility bailers sized 20-100 million Bto/br 

or more; multiple combustors can be attached to larger 

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

in combined-cycle industrial and small utility paver 

plants in the IO-50.MWe range. The combustor is capable of using pulverized coal, coal-water slurry, cotired 

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

sludge and coal-mine waste). 

Project Schedule: 

DOE selected project (CCT-I) 7l24lg6 

Cooperative agreement awarded 3/20/87 

NEPA process completed (MTF) 3/26/87 

Environmental monitoring plan completed 9/22/87 

Construction 7/!37-11187 

Opaational testing 1 l/87-5/90 

Project completed 9/91 

Final Reports: 

Final Technical Report S/91 

DDE Assessment 5l93 

83 
/ndustria/ Applications 

Clean Power from Integrated 

Coal/Ore Reduction (COREX@) 

Participant: 

CPICORm Management Company, L.L.C. (a limited 

liability company composed of subsidiaries of Centerior 

Energy Corporation, Air Products and Chemicals, Inc., 

and the Geneva Steel Company) 

Additional Team Members: 

Geneva Steel Company+ofunder; site owner; 

constructor and operator of COREX%nit 

Centerior Energy Corporation-cofunder 

Air Products and Chemicals, Iwafunder; designer, 

engineer, c~nst~ct~~. and operator of air separation 

and combined-cycle units 

Deutsche Voest-Alpine Industrieanlagenbau GmbHCOREXe developer/supplier; designer and engineer 

of COREX@ unit 

Location: 

Vineyard, Utah County, UT (Geneva Steel Company’s 

mill) 

Technology: 

Integration of Deutsche Voest-Alpine 

Industrieardagenbau’s COREX@ iron-making pmccss 

with a combined-cycle power generation system 

Plant Capscitylproduction: 

195 MWe (net) and 3,300 tons/day of hot metal (liquid 

iron) 

COREX is a ngistemd trademark ofDe”tsctlc “Cest-Atpinc 

t”dwticmlagenba”CmbH. 

CP,COR is a !mdem* ofthe CPKOR Mmqcment company. L.L.C. 

84 

Project Funding: 

Total project cost $1,065,805,0OLI 100% 

DOE 149.469,242 14 

Participant 916,335.758 86 

(Funding amounts are preliminary and subject to 

negotiation. pending award of a cceperative agreement.) 

Project Objective: 

To demonstrate the integration of a direct iron-making 

process (COREX’) with the co-production of electricity 

using various U.S. coals in an efficient and environmen. 

tally responsible manner. 

Technology/Project Description: 

The clean power from integrated coaUore reduction 

(CPICORm) process integrates two historically distinct 

processes-iron-making and electric power generation. 

COREX* is a novel iron-making technology which 

eliminates the need for coke production. The key innovative features of the COREX@ process include the 

reduction shaft furnace, which is used to reduce the imn 

ore to iron. and the melter-gasifier. located beneath the 

reduction furnace, which gasifies the coal and melts the 

iron. The gasification process generates the reducing gas 

for use in the reduction furnace as well as sufficient heat 

to melt the resulting imn in the melter-gasitier. 

Excess reducing gas exiting the reduction furnace is 

ceded. cleaned, compressed, mixed with air, and bumed 

in a gas Nrbine generator system capable of comhusting 

low8tu gas ta make electric poower. The hot exhaust 

fmm the turbine is then delivered to a heat recovery 

steam generator where process steam is made for utilizahduwial Applicahnu 
calendar Year 

,993 ,994 1995 ,996 1997 ,938 1999 Mw 2031 2002 2003 

3 4 1 2341234, 2 3 4 1 234 1 234 1 23412341 234, 234 12 

5m3 lom6 9loo 1103 

I 

\ 

OOE aeleded rmj@ct 

(CCT-V) 5/4/93 

I i 

NEPA p,cxeas m~le,ed (TBO) 4198 

Constmction started 4199 

cc4mfative .%greamem awarded 10196 

i 

t Pmiect complete&Final report issued l/o3 

operatm completed l/w’ 

Operation initiated 9/w’ 

E”vironmemal monitoring plan completed 9/w 

constNction cmpleted 9/w’ 

‘Projected date 

TBD = lo be determined 

tion in a steam turbine generator system to produce 

additional elecbic power. 

During the demonstration, approximately 3.400 

tons/day of a western bituminous coal blend containing 

about 0.5% sulfur will be utilized. The project will 

produce 3,300 tons/day of hot metal and 195 MWe. 

tile matter in the coal, as well as by incorporation of the 

combined-cycle power generation system. 

Project StatuslAccomplishments: 

---. 

CPICORm technology is less complex and environmentally superior than competing imn-making and 

power-generating technologies. Criteria air pollutants 

are reduced substantially largely due to (I) the inherent 

desulfurizing capability of the COREXe process in 

which limestone fed to the reduction furnace captures 

the sulfur present in the coal and (2) the efficient control 

systems within the combined-cycle power generation 

process. Because coke is not used. coke plants and their 

associated pollutants can be eliminated. 

U”J2 has compretal negouatrons lv,fh the panicrpant 

and approved the project. Award of the co~pemtive 

agreement is subject to congressional approval. 

Commercial Applications: 

The CPICOR’M technology is a direct replacement for 

existing blast furnace and coke-making capacity with the 

additional benefit of combined-cycle power generation. 

A full-scale commercial plant based on the CPICORM 

demonstration project will produce nearly 200 MWe (net 

exportable) and 1,200.OOO tons/yr of hot metal while 

expanding the type of coals that can be used to produce 

hot metal into the much larger noncoking range. 

coke-making facilities, and a comparably sized pulver. 

ized coal power plant with flue gas desulfmization. 

Similarly, the total emissions of SO, from the commercial facility are expected to be 0.024 lb/million Btu, a 

reduction of more than 90%. The net electrical genemting efficiency of the commercial facility is estimated to 

be 47% (a net effective heat rate of 7,262 BtwkWh on 

an LIIV basis). This compares to a net efficiency of 

32% for comparably sized conventional facilities. 

The energy efficiency of the CPICORTM technology 

is much greater than competing commercial technology. 

This efficiency advantage is gained by more effective 

use of both the sensible heat in the process and the vola- 

?he total emissions of NO, from a future commercial plant arc expected to be 0.012 lb/million Btu of coal. 

which is a reduction of more than 97% from the combination of a comparably sized blast furnace, associated 

Overall, a CPICORTM commercial plant would 

produce minimal solid or liquid impacts to the environment. especially when compared to existing competing 

facilities. All solid wastes arc expected to be exempt 

from Resource Conservation and Recovery Act requirements. ‘Ilw majority of solid wastes are beneficially 

reused, which increases the economic benefit of the 

technology and avoids burdening landfills. Most of the 

solid waste is slag from the iron-making process, which 

is usable in applications such as ballast for road construction and foundations. 

Indamial Applicdonr 85 
lndustdal Applications 

Cement Kiln Flue Gas 

Recovery Scrubber 

Project completed. 

Participant: 

Passamaquoddy Tribe 

Additional Team Members: 

Dragon Products Company-project manager and host 

HPD, 1nco~rated~esigne.r and fabricator of tanks 

and heat exchanger 

Cianbro Corpomtion-zonstmctor 

Location: 

Thomaston. Knox County, ME (Dragon Products 

Company’s coal-fired cement kiln) 

Technology: 

Passamaquoddy Technology Recovery ScmbberTM 

Plant CapacitylProduction: 

1,450 tons/day of cement: 250,ooO std ft’/min of kiln 

gas; and up to 274 tons/day of coal 

Project Funding: 

Total project cost $17,8oo,oca 100% 

DOE 5,982,592 34 

Participant 11,817,408 66 

Project Objective: 

To retrofit and demons&ate a full-scale industrial scmbher and waste recovery system for a coal-burning wet 

process cement kiln using waste dust as the reagent to 

accomplish 9lL95% SO, reduction using high-sulfur 

eastern coals and to produce a commercial by-product, 

potassium-based fertilizer. 

PIssunsqucddy r*oto!$y RecOVuy scrubber is B tladernark Of the 

P~“oddY Tribe. 

86 

Technology/Project Description: developed by the Passamaquoddy Indian Tribe while it 

The Passamaqucddy Technology Recovery Sc”bb@’ was seeking ways to solve landfill problems, which 

resulted from the need to dispose of waste kiln dust from 

the cement-making process. 

The kiln bums Pennsylvania bituminous coal containing approximately 3% sulfur. 

uses a water solutiou/sluny containing potassium-rich 

dust recovered from the kiln flue gas, which serves as 

the scmbbing medium. No other chemicals am required 

for the process. Atier scrubbing the gas. the slurry is 

separated into liquid and solid fractions. The solid fmction is returned to the cement plant as renovated and 

usable raw feed material. The liquid fraction is passed 

to a crystallizer that uses waste heat in the exhaust gas to 

evaporate the water and recover dissolved alkali metal 

salts. 

The Passamaquoddy Tribe’s recovery scmbba was 

constructed at the Dragon Products Company’s cement 

plant in Thomaston. ME, a plant that processes approximately 470,Mnl tons/y1 of cement. The process was 

Industrial Applications 
Project Results/Accomplishments: 

The recovery scrubber began operations in August 1991 

and has continued operations with several temporary 

shutdowns for normal kiln repairs and maintenance and 

a more lengthy shutdown from January to May 1992 due 

to poor economic conditions in the area. I” a 5-month 

period from May to September 1992, the plant produced 

approximately 140,000 tons of cement while the saubbcr removed 70 tons of SO, and treated 6,ooO tons of 

kiln dust for return to the kiln as raw feed. Initial testing 

of the scrubbing system achieved the project objective of 

90-9596 SO2 emission reduction, with a maximum reduction of 98%. The effect on NO, emissions also was 

determined during the demonstration. NO, emission 

reductio”s averaged 18.8% for the entire operating period. Operations have totaled 5,316 hours. Capital costs 

are approximately $10 “liltion for a 450,000-ton/y1 

plant, with a simple payback in about 3-4 years. Pmject 

operations continued through September 1993 when the 

scrubber became a permanent part of the Dragon Products facility. 

Commercial Applications: 

The recovery scrubber permits the use of high-sulhu 

coal in cement kilns “sing available waste dust as the 

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

There are more than 250 cement kiln installations in 

the United States and along the St. Lawrence River in 

Canada emitdng approximately 230,OCil tons/y1 of SO, 

Based on the technology’s characteristics, the applicable 

market would include approximately 75% of these instalations. If the technology were. installed in the applicable 

market facilities, SO, emissions could be reduced by 

approximately 150,OGU tons/yr. Commercialisation of 

the technology may be spurred when EPA issues emissions limits on cement kilns under the CAAA of 1990. 

The technology may also have broader applications in 

paper production and municipal waste. incineration in the 

United States and abroad. 

Water usage might or might not increase depending 

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

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 by-product fatilizer. Essentially, 

the solid waste stream would be eliminated through 

recovely. 

Project Schedule: 

DOE selected project (CCT-lI) 9/28/8g 

Cooperative agreement awarded 12izOB9 

NEPA process completed (EA) U16/90 

Environmental monitoring plan completed 3/26/90 

Construction 4/9&5/91 

Operational testing S/9-9l93 

Project completed 2194 

Final Reports: 

Final Technical Report 

(including economic assessment) 2l94 

Topical Report 3l92 

Public Design Report IO/93 

Industrial Applicdow 87 
Appendix A: CCT Project Contacts 

Listed below are contacti for obtaining further 

information about specific CCT Program demonstm 

tion projects. Each listing provides the name, title, 

phone number, and mailing address of the contact 

person. In those instances where the project 

participant consists of more than one company. a 

partnership, or joint venture., the mailing address 

listed is that of the contact person. 

Advanced Electric Power Generation/ 

Fluidized-Bed Combustion 

PCFB Demonstration Project 

Pam’cipmt: 

DMEC-1 Limited Partnership 

Contacts: 

Gary E. Kruempel, Project Manager 

(515) 281-2459 

(515) 281-2355 (fax) 

Midwest Power Systems, Inc. 

907 Walnut 

P.O. Box 657 

Des Moines, IA 50303 

Jeffrey Summers, DOE/Ha. (301) 903-4412 

Gary A. Nelkin. METC, (304) 285-4216 

Four Rivers Energy Modemization Project 

Participant: 

Four Rivets Energy Partners, L.P. 

Contacts: 

Edward Halley, Senior Project Manager 

(610) 481-8568 

(610) 481-3228 (fax) 

Air Products and Chemicals, Inc. 

7201 Hamilton Boulevard 

Allentown. PA 18195.1501 

Jeffi-ey Summers, DOIYHQ, (301) 903-4412 

Donald W. Geiling. METC, (304) 2854784 

Tidd PFBC Demonstration Project 

Participant: 

American Electric Power Service Corporation as 

agent for The Ohio Power Company 

Contacts: 

Mario Mamcco, Manager, PFBC Programs 

(614) 223- 1740 

(614) 223-2466 (fax) 

American Electric Power Service Corporation 

1 Riverside Plaza 

Columbus, OH 43215 

Jeffrey Summers, DOEnrQ, (301) 903-4412 

Donald W. Geiling, METC. (304) 2854784 

ACFB Demonstration Project 

Participant: 

Pennsylvania Electric Company 

Contacts: 

Kenneth Gray, Project Manager 

(814) 533-8044 

(814) 533-8108 (fax) 

Pennsylvania Electric Company 

1001 Broad Street 

Johnstown. PA 15907 

Jeffrey Summers, DOE!HQ, (301) 903-4412 

Nelson F. Rekos. METC. (304) 285-4066 

Nucla CFB Demonstration Project 

Participant: 

T&State Generation and Transmission 

Association, Inc. 

contacts: 

Marshall L. Pendergmss, Assistant General Manager 

(303) 249-4501 

Tri-State Generation and Transmission 

Association, Inc. 

P.O. Box 1149 

Montrose, CO 81402 

Jeffrey Summers, DDWHQ, (301) 903-4412 

Nelson F. Rekos, METC, (304) 2854066 

CC7 Project Contacts A-l 
Advanced Electric Power Generation/ 

Integrated Gasification Combined Cycle 

Clean Energy Demonstration Project 

Participant: 

Clean Energy Partners Limited Partnership 

Contacts: 

Victor Shellhorse, Vice President 

(704) 373-2474 

(704) 382-9325 (fax) 

Duke Energy Corp. 

400 S. Tryon Street 

Charlotte, NC 28202 

Jeffrey Summers, DOEiHQ, (301) 903.4412 

Donald W. Geiling, METC, (304) 285-4784 

Piion Pine IGCC Power Project 

Participant: 

Sierra Pacific Power Company 

contacts: 

John W. (Jack) Mot&r, Project Manager 

(702) 689-4013 

(702) 689-3047 (fax) 

Sierra Pacific Power Company 

6100 Neil Road 

P.O. Box 10100 

Reno, NV 89520-0400 

Lawrence Saroff, DOEYHQ, (301) 903-9483 

Douglas M. Jewell, METC, (304) 285-4720 

Tampa Electric Integrated Ga.sification CombiiedCycle Project 

Participant: 

Tampa Electric Company 

contacts: 

Donald E. Pless, Director, Advanced Technology 

(813) 228-1332 

(813) 228.1308 (fax) 

TECO Power Services Corporation 

P.O. Box 111 

Tampa, FL 33601-0111 

William Femald, DOE/HQ, (301) 903-9448 

Nelson F. Rekos, METC, (304) 2854066 

Wabash River Coal Gasitkatioo Repowerhg 

Project 

Participant: 

Wabash River Coal Gasification Repowering F’mject 

Joint Venture 

Contacts: 

Michael R. Woodruff 

(713) 735-4131 

(713) 735-4169 (fax) 

Destec Energy, Inc. 

2500 City West Boulevard, Suite 1500 

Houston, TX 77042 

Jeftiey Summers, DOUHQ, (301) 903-4412 

Gary A. N&in, METC, (304) 285-4216 

Advanced Electric Power Generation/ 

Advanced CombustionRleat Engines 

Hcaly Clean Coal Project 

Participant: 

Alaska Industrial Development and Export Authority 

Contacts: 

John B. Olson, Project Manager 

(907) 269-3MUJ 

Alaska Industrial Development and Export 

AUthOIity 

480 West Tudor Road 

Anchorage, AK 99503-6690 

Jeffrey Summers, DOE’HQ, (301) 9034412 

Robert M. Komosky, PETC, (412) 892-4521 

Coal Diesel Project 

Participant: 

Arthur D. Little, Inc. 

contacts: 

Robert P. Wilson, Vice President 

(617) 498.5806 

(617) 498-7206 (fax) 

Arthur D. Little, Inc. 

200 Acorn Park 

Cambridge, MA 02140 

Jeffrey Summers, DOE/HQ, (301) 9034ll2 

Nelson F. Rekos, METC, (304) 2854066 

A-2 CCT Project Contacts 
Externally Fired Combined-Cycle Demonstration 

Project 

Participant: 

Pennsylvania Electric Company 

Contacts: 

Kenneth Gray. Project Manager 

(814) 533-8044 

(814) 533-8108 (fax) 

Pennsylvania Electric Company 

1001 Broad Street 

Johnstown, PA 15907 

Douglas Archer, DOEnlQ, (301) 903-9443 

Donald W. Geiling, METC, (304) 2854784 

Environmental Control Devicee/NO, Control 

Technologies 

Demonstratiou of Coal Reburning for Cyclone 

Boiler NO= Control 

Participant: 

The B&cock & Wilcox Company 

contacts: 

Tony Yagiela 

(330) 829-7403 

The. Baback & Wilcox Company 

1562 Beeson Street 

Alliance. OH 44601 

Jeffrey Summers, DDE/HQ, (301) 903-4412 

John C. McDowell, PETC, (412) 892-6237 

Full-Scale Demonstration of LawNOx CellBurner 

Retrofit 

Participant: 

The B&cock&Wilcox Company 

Contucts: 

Tony Yagiela 

(330) 829-7403 

The Babcock &Wilcox Company 

1562 Beeson Street 

Alliance, OH 44601 

Jeffrey Summers, DOEJHQ, (301) 903-4412 

Ronald W. Corbett, PETC, (412) 892-6141 

Evaluatioo of Gas Rebuming and Low-NO, 

Burners cm a Wall-Fired Boiler 

Participant: 

Energy and Environmental Research Corporation 

conracts: 

Blair A. Folsom. Senior Vice President 

(714) 859-8851 

Energy and Environmental Research 

Corporatio” 

18 Mason 

hvine. CA 92718 

William Femald, DOE/HQ. (301) 903-9448 

Jerry L. Hebb, PETC, (412) 892-6079 

Micron&d Coal Reburning Demonstration of NOx 

C0ntd 

Participant: 

New York State Electric &Gas Corporation 

contacts: 

Dennis O’Dea, Project Manager 

(607) 729-2551 

New York State Electric &Gas Corporation 

120 Chenango Street 

Binghamton, NY 13902 

Lawrence Samff, DOWHQ, (301) 903-9483 

James U. Watts, PETC, (412) 892-5991 

Demonstration of Advanced Combustion 

Techniques for a Wall-Fired Boiler 

Participant: 

Southern Company Services, Inc. 

Contucts: 

John N. Serge, ICCT Project Manager 

(205) 877-7426 

Southern Company Services. Inc. 

P.O. Box 2625 

Birmingham, AL 35202-2625 

William Femald, DOE/HQ, (301) 903-9448 

Scott M. Smouse, PETC. (412) 892-5725 

CCI Project Comacts A-3 
Demonstration of Selective Catalytic Reduction 

Technology for the Control of NOx Emissions from 

High-Sulfur-Coal-Fired Boilers 

Participant: 

Southern Company Services, Inc. 

Contacts: 

J.D. (Doug) Maxwell, Project Manager 

(205) 877.7614 

Southern Company Services, Inc. 

P.O. Box 2625 

Birmingham, AL 35202-2625 

William Femald. DOEbIQ, (301) 903.9448 

Arthur L. Baldwin, PETC, (412) 892.6011 

180.MWe Demonstration of Advanced 

Tangentially Fired Combustion Techniques for the 

Reduction of NO. Emissions from Coal-Fired 

Boilers 

Participant: 

Southern Company Services, Inc. 

Contacts: 

Robert R. Hardman, Project Manager 

(205) 877.7772 

Southern Company Services, Inc. 

P.O. Box 2625 

Birmingham, AL 35202-2625 

William Femald, DOIYHQ, (301) 903.9448 

Scott M. Smouse, PETC, (412) 892-5725 

Environmental Control DevicedSO, Control 

Technologies 

lO-MWe Demonstration of Gas Suspension 

Absorption 

Participant: 

AirPol, Inc. 

Contacts: 

Frank E. Hsu,Vice President, Operations 

(201) 490-6400 

AirPol, Inc. 

3 Century Drive 

Parsippany, NJ 07054 

Lawrence Satoff, DOFXIQ, (301) 903-9483 

Sharon K. Marchant, PETC, (412) 8926008 

Confined Zone Dispersion Flue Gas 

Desulfurization Demonstration 

Participant: 

Bechtel Corporation 

Contactst 

Joseph T. Newman, Project Manager 

(415) 768-1189 

(415) 768-3580 (fax) 

Bechtel Corporation 

P.O. Box 193965 

San Francisco, CA 94119-3965 

Lawrence Saroff, DOE&IQ, (301) 903.9483 

Joanna M. Markusen, PETC, (412) 892.5734 

LIFAC Sorbent Injection Desulfurization 

Demonstration Project 

Panicipant: 

LIFAC-North America 

Contacts: 

Jim Hervol, Project Manager 

(412) 497-2235 

(412) 497-2298 (fax) 

ICF Kaiser Engineers, Inc. 

4 Gateway Center 

Pittsburgh, PA 15222-1207 

Lawrence Samff, DOE/HQ, (301) 903-9483 

Joanna M. Markussen, PETC, (412) 892-5734 

Advanced Fbw Gas Desulfurbation Demonstration 

Project 

Participant: 

Pure Air on the Lake, L.P. 

Contacts: 

Don Vymaml, Manager, Contract Administration 

(610) 481.3687 

Pure Air on the Lake, L.P. 

7201 Hamilton Boulevard 

Allentown, PA 18195-1501 

Lawrence Saroff, DOE&IQ, (301) 903.9483 

Karen M. Khonsari, PETC, (412) 892.6106 

A-4 CC7 Project Contacts 
Demonstration of Innovative Applications of 

Technology for the CT-121 FGD Process 

Participant: 

Southern Company Services, Inc. 

contacts: 

David P. Butford, Pmjea Manager 

(205) 8706329 

Southern Company Services, Inc. 

P.O. Box 2625 

Birmingham, AL 35202-2625 

Lawnmce Smoff, DOIX-IQ, (301) 903-9483 

Karen M. Khonsati, PETC, (412) 892-6106 

Environmental Control DevicesKomblned 

SOflO. Control Technologies 

SNOXTM Flue Gas Cleaning Demonshntlon 

Project 

Participant: 

ABB Environmental Systems 

contacts: 

Bill Kingston, Project Manager 

(205) 995-5368 

ABB Environmental Systems 

P.O. Box 43030 

Birmingham, AL 35243 

Lawrence Saroff, DOFYHQ, (301) 903-9483 

James U. Watts, PETC, (412) 892-5991 

LJMB Demonstration Project Extension and 

Coolside Demonstration 

Participant: 

The B&cock & Wilcox Company 

Contacts: 

Paul Nolan 

(216) 860-1074 

(216) 860-2045 (fax) 

The Babccck &Wilcox Company 

20 South Van Buren Avenue 

P.O. Box 351 

Barberton, OH 44203-0351 

William Femald. DOWHQ, (301) 903-9448 

Joanna M. Markussen, PETC, (412) 892.5734 

SO;NO;Rox BoxTw Flue Gas Cleanup 

Demonstratioo Project 

Participant: 

The Babcock & Wilcox Company 

Contacts: 

Kevin Redinger 

(330) 829-7719 

The B&cock&Wilcox Company 

1562 Beeson Street 

Alliance., OH 44601 

William Femald, DOE’HQ, (301) 903-9448 

John C. McDowell, PETC, (412) 892-6237 

Enhancing the Use of Coals by Gas Reburniog and 

sorbeot IQjectlon 

Participant: 

Energy and Environmental Research Corporation 

contacts: 

Blair A. Folsom, Senior Vice President 

(714) 859-8851 

Energy and Environmental Research 

corporation 

I8 Mason 

Irvine, CA 927 18 

William Femald, DOWHQ, (301) 903-9448 

Jerry L. Hebb, PETC, (412) 892-6079 

Mllliken Cleao Coal Technology Demonstration 

Project 

Participant: 

New York State Electric & Gas Corporation 

Contacts: 

Dennis O’Dea, Project Manager 

(607) 729-2551 

New York State Electric & Gas Corporation 

120 Chenatqo Street 

Binghamton, NY 13902 

Lawrence Saroff, DOWHQ, (301) 903-9483 

James U. Watts, PETC, (412) 892-5991 

CC7 Project Contacts A-S 
Commercial Demonstration of the NOXSO 

SOpOx Removal Flue Gps Cleanup System 

Participant: 

NOXSO Corporation 

Contacts: 

James Black 

(412) 854-1200 

NOXSO Corporation 

2414 Lytle Road 

Bethel Park, PA 15102-2704 

Lawrence Samff, DOEMQ, (301) 903.9483 

Jerry L. Hebb, PETC, (412) 892-6079 

Integrated Dry NOJSO, Emissions Control System 

Participant: 

Public Service Company of Colorado 

Contucts: 

Terry Hunt, Project Manager 

(303) 329-l I I3 

Public Service Company of Colorado 

5900 East 39th Avenue 

Denver, CO 80207 

William Femald, DOE/HQ. (301) 903-9448 

Jerry L. Hebb, PETC, (412) 892-6079 

Coal Processing for Clean FuelaKoal 

Preparation Technologies 

Development of the Coal Quality Expert 

Participants: 

ABB Combustion Engineering, Inc., and CQ Inc. 

Contacts: 

Clark Harrison, President 

(412) 479-6016 

CQ Inc. 

One Quality Cater 

P.O. Box 280 

Homer City, PA 15746-0280 

Douglas Archer, DOE/HQ, (301) 903-9443 

Scott M. Smouse, PETC, (412) 892-5725 

Self-Scrubbing CoaP: An Integrated Approach 

to Clean Air 

Participant: 

Custom Coals International 

contacts: 

Robin Godfrey, President and CEO 

(412) 642-2625 

Custom Coals International 

100 First Avenue, Suite 500 

Pittsburgh, PA 15222 

Douglas Archer, DOmQ, (301) 903-9443 

Joseph B. Renk, PETC, (412) 892.6249 

Advanced Coal Conversion Process Demonstration 

Participant: 

Rosebud SynCoal Partnership 

contacts: 

Ray W. Sheldon, P.E., Director of Development 

(406) 748-2366 or (406) 252-2277 

Rosebud SynCoal Patinersbip 

P.O. Box 7137 

Billings, MT 59103-7137 

Douglas Archer, DGE/HQ, (301) 903-9443 

Joseph B. Ret&, PETC, (412) 892-6249 

Coal Processing for Clean Fuels/Mild 

Gasification 

ENCOAL Mild Coal Gasification Project 

Participant: 

ENCOAL Corporation 

Contacts: 

J.P. (Jim) Frederick, Project Manager 

(307) 686-5493 

(307) 682-7938 (fax) 

ENCOAL Corporation 

P.O. Box 3038 

Gillette, WY 82717 

Douglas Archer, DOE&IQ, (301) 903-9443 

Douglas M. Jewell, METC, (304) 285-4720 

A-6 CC7 Project Contacts 
Coal Processing for Clean Fuels/Indirect 

Liquefaction 

Commercial-Scale Demonstration of the LiquidPhase Methanol (LPMEOWH) Process 

Participant: 

Air Products Liquid Phase Conversion 

Company, L.P. 

contacts: 

William R. Brown, Project Manager 

(215) 481-7584 

Air Products Liquid Phase Conversion 

Company, L.P. 

7201 Hamilton Boulevani 

Allentown, PA 18195-1501 

Douglas Archer. DOB’HQ, (301) 903-9443 

Robert M. Komosky, PETC, (412) 892-4521 

Industrial Applications 

Blast Furnace Grasulati-Cost Injection System 

Demonstration Project 

Participant: 

Bethlehem Steel Corporation 

Contacts: 

Robert W. Bournan. Project Manager 

(610) 694-6792 

(610) 694-2981 (fax) 

Bethlehem Steel Corporation 

Homer Research Laboratory 

Building C, Room 211 

Bethlehem, PA 18016 

Jeffmy Summers. DOWHQ, (301) 9034412 

Douglas M. Jewell. METC. (304) 285-4720 

Advanced Cyclone Comb&or with Internal 

Sulfur, Nitrogen, and Ash Control 

Participant: 

Coal Tech Corporation 

COlltnCW 

Bert Zauderer, President 

(215) 667-0442 

Coal Tech Corporation 

P.O. Box 154 

Metion, PA 19066 

Douglas Archer, DOE’HQ. (301) 903-9443 

Arthur L. Baldwin, PETC, (412) 892-6011 

Clean Power from Integrated Coal/Ore Reduction 

(COREX@) 

Participant: 

CPICORW Management Company, L.L.C. 

Contacts: 

Barry Halper 

(610) 481-7685 

(610) 481-2393 (fax) 

Air Products and Chemicals, Inc. 

7201 Hamilton Boulevard 

Allentown, PA 18195-1501 

Lawrence Samff, DOE&IQ, (301) 903.9483 

Douglas M. Jewell, METC, (304) 285-4720 

Cement Kiln Ftue Gas Recovery Scrubber 

Participant: 

Passamaquoddy Tribe 

Contacts: 

Thomas N. Tureen, Project Manager 

(207) 773-7166 

Passamaquoddy Technology. L.P. 

1 Monument Way 

Portland, ME 04101 

Jeffrey Summers, DOEUHQ, (301) 903-1412 

John C. McDowell, PETC, (412) 892-6237 

CCI Project Contacts A-7 
Appendix B: Acronyms and Abbreviations 

Acronyms 

ABB CE 

ABB ES 

ADL 

ACFB 

AFBC 

AFGD 

AlDEA 

AOFA 

BFGCI 

BGfL 

B&W 

CAAA 

CCOFA 

CCT 

CCT Program 

CDL 

CFB 

CQE 

cx 

CZD 

DME 

DOE 

WmQ 

ABB Combustion Engineering, Inc. 

ABB Environmental Systems 

Arthur D. Little, Inc. 

armospheric circulating fhddixd bed 

atmospheric fluidized-bed 

combustion 

advanced flue gas desulf”rizatio” 

Alaska Industrial Development and 

Export Authority 

advanced overfire air 

blast furnace granulated-coal 

injection 

BritishGtiurgi 

The B&cock & Wilcox Company 

Clean Air Act Amendments of 1990 

close-co”pled overfire air 

clean coal tech”o1ogy 

Clean Coal Technology 

Demonstration Program 

coal-derived liquid 

circulating fluidized bed 

Coal Quality Expert 

categorical exclusion 

confined zone dispersion 

dimethyl ether 

U.S. Department of Energy 

U.S. Department of Energy 

Headquarters 

Acronym and Abbrevidiom 

EA 

EER 

EPCC 

EIS 

EMP 

EPA 

EPRI 

ESP 

FBC 

FGD 

FRP 

m 

GE 

GNOCIS 

GR 

GR-LNB 

GRSI 

GSA 

HAP.HAPs 

HHV 

HRSG 

IGCC 

3BR 

LHV 

UMB 

LNB 

environmental assessment 

Energy and Envinxunental Research 

C0rporati0” 

externally fired combined cycle 

environmental impact statement 

environmental monitoring plan 

U.S. Environmental Protection 

Agency 

Electric Power Research Institute 

electrostatic precipitator 

fluidized-bed combustion 

flue gas desulfurization 

tiberglass-reinforced plastic 

fiscal year 

General Electric 

Generic NOz Control intelligence 

system 

gas rebuming 

gas rebuming and low-NO, burner 

gas rebuming and sorhent injection 

gas suspension absorption 

hazardous air pollutant(s) 

high heating value 

heat recovery steam generator 

integrated gasification combined 

cycle 

jet-bubbling reactor 

low heating value 

limestone injection multistage 

burner 

low-NO< burner 

LNCFS 

LSFO 

MCFC 

MBTC 

MIT 

NEPA 

NSPS 

NYSEG 

PCFB 

PDF 

PENELEC 

PEPCO 

PETC 

PFBC 

PJBH 

Pscc 

SCR 

scs 

S-H-U 

SI 

SNCR 

SOFA 

TVA 

UBCL 

U.K. 

low-NO, concentric-fting system 

limestone forced oxidation 

molten carbonate fuel cell 

Morgantown Energy Technology 

tX”tEI 

memorandum (memoranda)-@tile 

National Environmental Policy Act 

New Source Performance Standards 

New York State Electric &Gas 

Corporation 

pressw&d circulating fluid&d bed 

proce.ssderived fuel 

Pennsylvania Electric Company 

Potomac Electric Power Company 

Pittsburgh Energy Technology 

center 

presswized fluidized-bed 

combustion 

pulse jet baghouse 

Public Service Company of Colorado 

selective catalytic reduction 

Southern Company Services, Inc. 

Saarberg-Halter-Umwelttechnik, 

GmhH 

sorbent injection 

selective noncatalytic reduction 

separated over-fire air 

Tennessee Valley Authority 

unburned carbon boiler efficiency 

losses 

United Kingdom 

B-I 
U.S. 

VOC 

United States 

volatile organic compound Abbreviations 

WLFO wet limestone, forced oxidation 

States are abbreviated using twxletter postal codes. 

atm atmosphere(s) 

% average 

Bhl British thermal unit 

cm molar ratio of carbon ta hydrogen 

taco, calcium carbonate (calcitic 

limestone) 

cao calcium oxide (lie) 

WOW, calcium hydroxide (c&tic 

hydrated lie) 

Ca(OH),*MgO dolomitic hydrated lime 

cals molar ratio of calcium to sulfur 

case, calcium sulfite 

case, calcium sulfate 

co carbon monoxide 

co2 carbon dioxide 

OF degrees Fahrenheit 

ft. ft*, ftz foot (feet), square feet, cubic feet 

HP hydrogen sulfide 

YSO, sulfwic acid 

HCl hydrogen chloride 

HF hydrogen fluoride 

hr,hrs hour, hours 

in . in’ in’ 9 inch(es), square inches, cubic inches 

KC1 potassium chloride 

YSO, potassium sulfate 

kW kilowatt 

kWb kilowatt-hour 

lb, lbs pound, pounds 

tno, mos month, months 

MgO magnesium oxide 

Mwe megawatt(s)-electric 

5 atmospheric. nitrogen 

N&a molar ratio of sodium to calcium 

NG molar ratio of sodium to sulfur 

NaOH sodium hydroxide 

NGO, sodium carbonate 

NH3 ammonia 

V nitrogen oxides 

PPm parts per million (mass) 

ppmv parts per million by volume 

psi pound(s) per square inch 

Tpm revolutions per minute 

SO2 sulfw dioxide 

std ft) standard cubic feet 

yr, yrs year, years 

B-2 Acronvms and Abbreviations