COAL Clean Coal Technology 

TECHNOLOGY Demonstration Program 

Program Update 1993 

(As of December 3 1,1993) 

U.S. Department of Energy 

Assistant Secretary for Fossil Energy 

Washington, DC 20585 March 1994 
Advanced Electric 

Power Generation 

Fact Sheets 
PFBC Utility Demonstration 

Project 

Sponsor: 

The Appalachian Power Company 

Additional Team Members: 

America” Electric Power Service Corporahondesigner, co”strwtot, and manager 

The B&cock & Wilcox Company- technology supplier 

Location: 

New Haven, Mason County, WV (greenfield facility 

adjacent to Appalachian Power Company’s Mountaineer 

Plant) 

Technology: 

The Babcock & Wilcox Company’s pressurized 

fluidized-bed combustion (PFBC) system (under license 

from ABB Carbon) (advanced electric power generation/ 

fluidized-bedcombustion) 

Plant Capacity/Production: 

340 MWe (“et) 

Project Funding: 

Total project cost $917,944,000 100% 

DOE 184,800,000 20 

Participants 733,14d,ooo 80 

Project Objective: 

To demonstrate PFBC at 340 MWe, a large utility scale 

representing a four-fold scaleup of the technology, the 

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

reliability, availability, and maintainability of PFBC in a 

commercial operating mode and the integration of a 

reheat steam cycle. 

7-8 Program Update 1993 

Technology/Project Description: 

This project will be a greenfield facility located adjacent 

to the existing Mountaineer and Spom plants. The most 

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

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

high. 

by-product. A low bed-temperature of 1,600 OF limits 

NOx formation. 

The hot combustion gases exit the bed vessel with 

entrained ash particles, 98% of which are removed when 

the gases pass through cyclones. An option being co”- 

sidered is to employ some advanced filtration devices in 

the design. The cleaned gases are then expanded 

The project incorporates a bubbling fluidized-bed through a 75.MWe gas turbine. 

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

compressor to fluid& the bed material (consisting of a 

coal-water fuel paste, coal ash, and a dolomite or 

limestone sorbeni). Dolomite or limestone in the bed 

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

bed-ash material, which is easily disposed of 01 used as a 

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

250 MWe. Superheated steam will be produced from 

pressurized boiler-feed water in the tubes submerged in 

the fluidized bed. The projected heat rate for this unit is 

8,500 BtuikWh (40.2% efficiency based on HHV). SO, 

emissions are expected to be reduced by 95% and NOx 

emissions by 80%. 

Advanced Electric Power Generation 
t 

A 11 T 

t 

Design completed 8/W 

DOE seb%d project 

(CCT-II) X28,88 

Construction completed 8102 

Preoperational tests initiated 8/W’ 

T I 

Operation initiated 11/O*’ 

Oround breaklngiconstruction started 6199’ Project completedflinal repan issued z//o4 

NEPA process completsd (EIS) z/w Operation completed 2104* 

Environmental monitoring plan completed 7197 * Projected Date 

Cooperative agreement awarded 414190 “Years omitted 

The design coal is Pittsburgh 8, high-sulfur (4% coals in an environmentally sound manner. PFBC techmaximum), bituminous coal. 

Project Status/Accomplishments: 

During 1993, initial value engineering efforts aimed at 

reducing the technical and economic risks of the project 

were completed. These efforts were successful in 

optimidng the scaleup parameters, improving the 

understanding of sulfur capture, and reducing capital 

cost. Appalachian Power’s load growth projections are 

being refined, but they are not expected to show a large 

need for power. The utility and DOE are assessing the 

merits of continuing the project, 

Commercial Applications: 

This project will be the initial version of a commercial 

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

coals. This technology will compete with circulating 

PFBC systems to repower or replace conventional power 

plants with a technology capable of using high-sulfur 

nology appears to be best suited for a wide range of 

applications beginning at the SO-MWe size. Because of 

modular construction capability, PFBC generating plants 

permit utilities to add economical increments of capacity 

to match load growth and/or to easily repower existing 

plants using available coal- and waste-handling equipment, and existing steam turbines. Another advantage 

for repowering is the compactness of the process because 

of pressurized operation. 

The projected net heat rate for the commercial plant 

will be 8,500 BtuikWh (based on HHV) which equates 

to an efficiency of 40.2%. An advanced cycle that integrates a small gasifier could yield heat rates approaching 

7,500 BtuikWh (45% efficiency). Environmental attributes include in-situ sulfur reduction of 95% and NOx 

emissions reduction to 0.1 lb/million Btu. Although the 

system may generate a slight increase of solid waste as 

compared to conventional systems, the dry material is 

either disposable or potentially usable. 

Advanced Eiecfric Power Generation Program Update 1993 7-9 
PCFB Demonstration Project 

sponsor: 

DMEC-1 Limited Partnership (a partnership between 

Dairyland Power Cooperative and Midwest Power 

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

Additional Team Members: 

Pyropower Corporation -technology supplier 

Black and Veatch--architect and engineer 

Location: 

Pleasant Hill, Polk County, IA (Des Moines Energy 

Center) 

Technology: 

Pyropower Corporation’s PYROFLOW pressurized 

circulating fluid&&bed combustion (PCFB) 

combined-cycle system (advanced electric power 

generation/fluidized-bedcombustion) 

Plant Capacity/Production: 

80 MWe 

Project Funding: 

Totalproject cost $202,959,000 100% 

DOE 93,253,OOO 46 

Participants 109,706,OOO 54 

Project Objective: 

To demonstrate PCFB at sufficient scale to evaluate 

environmental, cost, and plant performance and to obtain 

the technical data required for commercialization of the 

technology; to assess operating performance of unique 

features that include an integml ceramic hot-gas filter 

and slightly modified, commercially available gas 

turbine. 

Technology/Project Description: 

In the PCFB process, coal is cornbusted at about 

1,600 OF and 12 atm in a circulating fluid&d bed contained within a pressure vessel. Coal is pumped into the 

PCFB via a water slurry while dolomite or limestone is 

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

gases are then expanded through a gas turbine. The 

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

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

system downstream of the gas turbine is used to generate 

power in an existing steam turbine. 

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

demonstration of PCFB technology. The project also 

would be the first commercial application of hot gas 

cleanup and the first use of a nonruggedized gas turbine 

in a pressurized fluidized-bed application. 

A boiler at the Des Moines Energy Cater is being 

repowered by a single PCFB combustor. The facility, 

owned by Midwest Power Company, is located southeast 

of Des Moines, IA. Midwest Power plans to continue 

PCFB operations commercially after the demonstration. 

Repowering the plant with a PCFB will improve the 

plant’s heat rate to 10,400 BtuikWh (an efficiency of 

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

over the previous plant. SO, emissions will be limited to 

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

will be less than 0.03 lb/million Btu (70% reduction). 

The design coal for the facility is 0.36% sulfur, 

Wyoming subbituminous coal. Test coals are Iowa 

7-10 Program Updare 1993 Advanced Electric Power Genera&m 
CalendarYear 

,990 ,991 1992 1993 ,994 ,595 19% ,997 ,998 ,999 2”“” 3 4 1 2 3 4 1 234 1 23412341 234123412341234, 234 12 

I 12,QQ s/s1 5/Q7 5199 

t t tt i’ tP *ration initiated S/97 

DOE selected Constr”cson completed IO/96 T1 

Project co+3tedmnal 

report issued 519-Y 

I 

t 

bmperational tests initiated 6/96’ I 

Cperation completed 4/99’ 

Cooperativeagreement 

awarded 8,119, 

plan conpkd ,195 

round breah”glco”str”ctlon staned 1,194’ 

Design completed ttn94’ 

NEPA process completed (EIS) 11/94 

‘Projected date 

subbituminous coal with 3.84% sulfur and Illinois 

bituminous coal with 3.0% sulfur. 

Project Status/Accomplishments: 

In October 1993, amodification was issued to extend the 

project for 12 months in order to complete project definition activities. During the extension, Midwest Power 

will fin&e the selection of a ceramic filtration hot-gas 

cleanup system and conduct configuration studies to 

verify the economic viability of the project. A draft of 

the environmental impact ?.tatement has been prepared 

and is undergoing internal DOE review. 

Commercial Applications: 

By demonstrating plant reliability and performance, this 

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

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

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

Advanced Electric Power Generation 

can be used to repower or replace conventional power 

plants. PCFB technology appears to be best suited for 

utility and industrial applications of 50 MWe OI larger. 

Because of modular constmction capability, PCFB generating plants permit utilities to add economical increments of capacity to match load growth and/or torepower plants using existing coal- and waste-handling 

equipment, and steam turbines. Another advantage for 

repowering applications is the compactness of the process due to pressurized operation, which reduces space 

requirements per unit of energy generated. 

The commercial version of PCFB technology will 

include the integration of a topping combustor to fully 

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

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

Environmental attributes include in-situ sulfur remow1 of 95%. NOx emissions less than 0.3 lb/million 

Btu, and particulate matter discharge less than 0.03 lb/ 

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

disposable or potentially usable. Program Update 1993 7-11 
Four Rivers Energy 

Modernization Project 

sponsor: 

Four Rivers Energy Partners, L.P. (a limited partnership 

between Four Rivers Energy Partners (l), Inc., and Air 

Products and Chemicals, Inc.) 

Additional Team Members: 

Foster Wheeler Energy Corporation-zombustor, 

carbonizer, and heat exchanger supplier: engineer 

Westinghouse Electric Corporation-gas turbine, 

topping combustor, and carbonizer filter supplier 

LLB Lurgi Lentjes Babcock Energietechnick GmbHcombustor filter, slurry feed, and ash removal system 

supplier 

Location: 

Calvert City, Marshall County, KY (Air Products and 

Chemicals’ chemical manufacturing plant) 

Technology: 

Foster Wheeler’s fully integrated second-generation 

pressurired circulating fluidized-bed (PCFB) combustion 

system (advanced electric power generationlfluidizedbed combustion) 

Plant Capacity/Production: 

95 MWe (equivalent if all steam were converted) 

the technology; to assess operating performance of the 

world’s first fully integrated second-generation PCFB 

system that includes a combustor, carbonizer, ceramic 

hot-gas filtration systems, topping combustor, and a 

slightly modified, commercially available gas turbine. 

combustor. Additional coal and the carbonizer char are 

burned in the PCFB combustor, and the flue gas is used 

to combust the fuel gas in the topping combustor. Prior 

to the topping combustor, the hot gases pass through 

ceramic filtration and alkali removal units. 

Project Funding: 

Total project cost $375,178,000 100% 

DOE 150,033,775 40 

Participants 225,144,225 60 

(Funding amounts reflect those contained in the proposal 

and ale subject to negotiation.) 

Project Objective: 

To demonstrate PCFB technology at a sufficient scale to 

evaluate th environmental, cost, and plant performance 

technical data that is prerequisite to commercialization of 

Technology/Project Description: 

This project represents the fast commercial application 

of Foster Wheeler’s second-generation PCFB system. 

Coal is fed to a pressurhed carbonizer that produces a 

low-Btu fuel gas and char. After the fuel gas is cleaned 

of particulates and alkali vapors by a cyclone, ceramic 

filter, and alkali removal system, it is burned in a topping 

combustor to drive a gas turbine. 

The gas turbine drives a generator and a compressor 

that delivers air to the carbon&x and to a PCFB 

A steam turbine is driven by steam generated in the 

heat recovery steam generator, which is located downstream of the gas turbine, an integrated ash-cooling heat 

exchanger. and the PCFB combustor. 

Fuel is pumped into the PCFB carbonizer and comhustor via a slurry mixture while dolomite or limestone is 

pneumatically added to absorb sulfur compounds. The 

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

easily disposable, and potentially usable. 

The project is also in line to be one of the first commercial applications of hot-gas cleanup and one of the 

7.12 Program Update 1993 Advanced Electric Power Generation 

--. ~~.~ ,,~ .,.. -...-_-._-..- 
CalendarYear 

,993 ,994 ,995 ,995 1997 ,998 1999 2000 2001 2002 2003 3 4 12341 234,234, 23412341 234123412341234 12 

5/93 5/94 

, Preaward , 

I I 

I 

1 Cooperativeagreement 

awarded 5,&l’ 

DOE selected project 

(CCT-V) 5,493 

first to use a non-tuggedized gas turbine in a pressurized 

steam-generating capacity of two operating industrial 

process boilers. These two industrial units are spreaderfluidized-bed application. 

stoker coal-tired units which were installed in the late 

1950s. This equipment change will result in significant 

reductions in the current emissions of pollutants. 

At the Calvert City chemicals manufacturing plant, 

the second-generation PCFB process will replace the 

PCFB technology appears to be best suited for a 

fluidized-bed combustion systems to repower OI replace 

wide range of utility and industrial applications beginning at a level of 50 MWe. Because of the modular 

conventional fossil-fueled power plants with a technolconstruction capability, PCFB generating plants will 

permit utilities to add economical increments of capacity 

ogy capable of using high-sulfur coals in an environmento match load growth and/or to easily repower an existing plant using available coal- and waste-handling 

tally sound manner. 

equipment and steam turbine equipment. 

currently allowed by NSPS, (3) operate economically on 

a wide range of coals. (4) be amenable to shop fabrication, and (5) be furnished in building-block modules as 

large as 300 MWe. 

Project Status/Accomplishments: 

The project is in negotiation. 

The benefits of improved efficiency include reduced 

costs for fuel and a reduction in CO, emissions. Other 

environmental attributes include in-situ sulfur reduction 

that can meet 95% removal, NOx emissions that will be 

lower than 0.3 lb/million Btu, and particulate matter 

discharge that approaches 0.01 lb/million Btu. Although 

the system will generate a slight increase of solid waste 

as compared to conventional systems, the material will 

be a dry, disposable, and potentially usable material. Commercial Applications: 

This project will serve as a stepping stone to move the 

second-generation PCFB technology to readiness for 

widespread commercial application. The project is expected to demonstrate plant reliability and performance 

and serve as a bridge for scaling to a larger plant. In 

addition to other advanced technology systems. secondgeneration PCFB technology will compete with bubbling 

The commercial version of PCFB technology will 

have a greenfield net plant efficiency of 45% (which 

equates to heat rates approaching 7,500 Btu/kWh, based 

on HHV). In addition to higher plant efficiencies, the 

second-generation plant will (I) have a cost of electricity 

that is projected to be 20% lower than that of a cowentional pulverized-coal-fired plant with flue gas desulfuri&on, (2) meet emissions limits that are half those 

Advanced Electric Power Generation Progrm Updare 1993 7-13 
Tidd PFBC Demonstration 

Project 

sponsor: 

The Ohio Power Company 

Additional Team Members: 

American Electric Power Service Corporation-designer, 

constwckx, and manager 

The Babcock & Wilcox Company-technology supplier 

Ohio CoalDevelopment Office-cofunder 

Location: 

Brilliant, Jefferson County, OH (Ohio Power 

Company’s Tidd Plant) 

Technology: 

The Babcock &Wilcox Company’s pressurized fluidix&bed combustion (PFBC) system (under license from 

ABB Carbon) (advanced electric power generation/ 

fluidized-bedcombustion) 

Plant Capacity/Production: 

70 MWe 

Project Funding: 

Total project cost $193,540,000 100% 

DOE 60,200,000 31 

Participants 133,340,000 69 

Project Objective: 

To demonstrate PFBC at a 70.MWe scale, representing a 

13: 1 scaleup from the pilot plant facility; to verify expectations of the technology’s economic, environmental, and 

technical performance in a combined-cyclerepowering 

application at a utility site: and to accomplish greater 

than 90% SO, removal, NOx emission level of 0.2 lb/ 

million Btu, and an efficiency of 35% in a repowering 

mode using the existing steam system 

Technology/Project Description: 

boiler, cyclones, bed reinjection vessels, and associated 

hardware are encapsulated in a pressure vessel 45 ft in 

Tidd is the first large-scale demonstration of PFBC in 

diameter and 70 ft high. The facility was designed so 

that one-seventh of the hot gases produced could be 

the United States and one of only five worldwide. The 

routed tn a slipstream tn test advanced filtration devices. 

The Tidd facility is a bubbling fluidized-bed combustion process operating at I2 atm (175 Ibs/in2 atm). 

Pressurized combustion air is supplied by the turbine 

compressor to fluidize the bed material which consists of 

a coal-water fuel paste, coal ash, and a dolomite or limestone sorbent. Dolomite or limestone in the bed reacts 

with sulfur to form calcium sulfate, a dry, granular bedash material which is easily disposed of or is usable as a 

entrained ash particles, 98% of which are removed when 

by-product. A low bed-temperature of 1,600 “F limits 

the gases pass through cyclones. The cleaned gases we 

then expanded through a IS-MWe gas turbine. The 

NOx formation. 

gases exiting the turbine are cooled via a waste heat 

economizer and further cleaned in an electrostatic 

precipitator. 

The hot combustion gases exit the bed vessel with 

The Tidd steam turbine operates at a pressure of 

1,305 Ibsiin’ atm and a temperature of 925 “F to produce 

approximately 55 MWe. Superheated steam is produced 

from pressurized boiler feed water in the in-bed combustnr tubes. Steam generated within the combustor and the 

heat recovery system downstream of the gas turbine is 

used to generate power in a previously existing steam 

7-14 Program Updnle 1993 Advanced Electric Powr Generation 
391 12194 

Ill 

T 

t 

Environmental monitoring 

t+ 

t 

ptan completed 5,25,** Operation intiiated 3191 Project complet*d/O”at 

Preoperationat tests started 12190 report issued 12194‘ 

Groundbreaking ceremony 416188 

Co”st,“clb” co~ieted 12190 operation canpleted 2i94’ 

COn*,rucfix started 1219187 Design corrpteted 12190 

4 Coqmdi”e agreement awarded w20187 

NEPA process corrpteted (MTF, 3,5/w 

DOE selected project (Km) 7,24/86 ‘Projected date 

turbine. Due to repowering, plant efficiency was im- the unit operated for approximately 50% of the available capacity economically to match load growth. Plant life 

proved by 10% to a heat rate of 9,750 Btu/kWh (an time during 1993. can be extended by repowering with PFBC using the 

efficiency of 35.1% based on HHV). 

Ohio bituminous coals having sulfur contents of 

24% are being used in the demonstration. 

Project Status/Accomplishments: 

The plant accumulated over 2,000 hours of operation 

during 1993. Overall, coal-fueled operation now totals 

more than 5,500 hours. SO, emissions reductions of 

about 93% and NOx emission levels of 0.15-0.18 lb/ 

million Btu were routinely achieved. These levels are 

well below NSPS requirements. 

The project is due to terminate operations by the end 

of February 1994. However, as 1993 came to a close, 

Ohio Power and DOE were considering a fourth year of 

operations. The goal of the additional 12.month test 

would be to obtain additional data on long-term gas 

turbine survivability, economical sulfur capture at a 95% 

level, and exposure of advanced ceramic filtration 

devices. 

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

and steam turbine equipment. Another advantage for 

repowering applications is the compactness of the process due to pressurized operation, which reduces space 

requirements per unit of energy generated. 

Commercial Application: 

Combined-cycle PFBC permits use of a wide range of 

coals, including high-sulfur coals. Bubbling PFBC 

technology, along with other advanced technologies, will 

compete with circulating PFBC systems to repower or 

replace conventional power plants. PFBC technology 

appears to be best suited for applications of 50 MWe or 

larger. Capable of being constructed modularly, PFBC 

generating plants permit utilities to addincrements of 

In a fully mature system, the projected net heat rate 

is 8,500 BtuikWh (based on HHV) which equates to 

40.2% efficiency. An advanced cycle that integrates a 

small gas&r could yield heat rates approaching 

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

During 1993 operations, advanced ceramic hot-gasfiltration elements were exposed to one-seventh of the 

slipstream; total exposure is now in excess of 1,800 

hours. The unit suffered a major mechanical problem 

early in 1993 whenever gas turbine blades broke during 

routine operation. The result was severe damage to the 

compressor, gas turbine blades, and rotor shafts. Disregarding a 5-month outage for repairs to the gas turbine, 

The environmental attributes of a mature system 

include in-situ sulfur removal of 95% and NOx emissions 

reduction levels less than 0.1 lb/million Btu. Although 

the system generates a slight increase in solid waste as 

compared to conventional systems, the dry material is 

either disposable or potentially usable. 

Advanced Ekctric Power Generation Prqrm Updote 1993 7-15 
CalendarYear 

1988 ,989 ,990 ,991 ,992 ,993 1994 ,995 ,996 ,997 ,998 

3412341 234 1234 1 234 1 2341234123412341 234 12 

I DOE SBkted project (CCT-II, 

9,28,W I 

lConstruction *tarted 6194 

I 

Lonstr”ction completed 10196’ 

Operation initiated 10196’ 

L 

Design completed 4196 

n”,mnme”tal monitoring plan completed 5&93 

Project comptetedi 

NEPA process completed (EA) 3127192 final report issued 

5,01+ 

I Coaperativegrement award% 1 lR0/90 

through the installation of an entrained-flow coal gasifier Commercial Applications: have a heat rate less than 8,000 BtuikWh (efficiency 

and the integration of a 25.MWe steam turbine with a 

40.MWe gas turbine at City Water, Light and Power’s 

Lakeside Station located in Springfield, IL. The anticipated heat rate for the repowered unit is 8,800 BtuikWh 

(an efficiency of 38.8%). SO, emissions are expected to 

be less than 0.1 lb/million Btu (99% reduction). NOx 

emissions are also expected to be less than 0.1 lb/million 

Btu (90% reduction). 

Project Status/Accomplishments: 

An environmental assessment with a finding of no significant impact was completed March 27, 1992. 

System definition and preliminary design activities 

are complete. At the completion of preliminary engineering, a revised cost estimate was completed. The updated 

cost projection considerably exceeds the available funding. Efforts are currently focused on reducing theprojetted cost or, if necessary, restructuring the project. 

The IGCC system being demonstrated in this project is 

suitable for both repowering and new power plant applications. Repowering aging plants with this technology 

will improve plant efficiency and reduce emissions of 

SO,, NOx, and CO,. Also, the modular design of the 

gasifier will permit a range of units to be considered for 

repowering. 

greater than 43%). This heat rate is expected to realize at 

least a 20% improvement in efficiency compared to a 

conventional pulverized-coal-fired plant with flue gas 

desulfurization. The improved system efficiency also 

results in a similar decrease in CO, emissions. 

Due to the advantages of modularity, rapid and 

staged on-line generation capability, high efficiency, fuel 

flexibility, environmental controllability, and reduced 

land and natural resource needs, the IGCC system is also 

a strong contender for new electric power generating 

facilities. Further, without the need for an oxygen plant, 

the ABB Combustion Engineering technology represents 

a potentially simpler approach to gasification-based 

power generation. A single-train IGCC system based 

on this gasifier is capable of producing more than 

150 MWe. A commercial-scale facility based on the 

ABB Combustion Engineering technology is expected to 

Advanced Electric Power Generarion Progrm Update 1993 7-21 
Camden Clean Energy 

Demonstration Project 

Sponsor: 

Duke Energy Corp. 

Additional Team Members: 

General Electric Company--cofunder; designer and 

supplier of the power island equipment 

Fuel Cell Engineering Corporationdesigner and 

supplier of the fuel cell 

J. Makowski Company--cofunder 

British Gas plc--cofunder 

Location: 

Camden, Camden County, NJ (Pavonia Industrial Area) 

Technology: 

Integrated gasification combined-cycle (IGCC) using 

British Gas/Lurgi (BG/L) slagging fixed-bed gasification 

system coupled with Fuel Cell Engineering’s molten 

carbonate fuel cell (advanced electric power generation/ 

integrated gasification combined cycle) 

Plant Capacity/Production: 

240 MWe (net) 

Project Funding: 

Total project cost $779,950,000 100% 

DOE 195,000,000 25 

Participant %4,950,000 75 

(Funding amounts reflect those contained in the proposal 

and are subject to negotiation.) 

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. 

Technology/Project Description: 

Bituminous run-of-mine coal is screened ta remove fines. 

The fines are formed into briquettes and fed to the gasifier along with the screened coal. The coal and briquettes are gasified in an oxygen-blown, pressurized, 

slagging fixed-bed gasifier. The raw product gas is 

quenched to reduce the temperature and remove tars, 

oils, ammonia, and particulates. The particulates and 

condensed tars and oils are recycled to the gasifier to 

ensure high cold-gas efficiency. The cooled product gas 

is routed to a conventional cold-gas cleanup system to 

remove sulfur compounds. The clean, medium-Btu gas 

is reheated and burned in an advanced 192.MWe (gross) 

gas turbine. A small slipstream of clean product gas is 

diverted to a gas-polishing and moisturization step and 

used to fuel the 2.5.MWe (gross) molten carbonate fuel 

cell. Waste nitrogen from the air separation unit is also 

routed to the gas turbine to increase mass flow to the 

turbine and suppress NOx formation The hot exhaust 

gas from the gas turbine is passed through a heat recovcry steam generator to produce high-pressure steam. The 

steam turbine is designed to produce 83 MWe (gross) 

using steam conditions of 1,450 lb/in2 atm and 1,000 OF/ 

1,000 “F reheat. 

The process has the following subsystems: coal 

screening and briquetting; an air separation unit; a 

slagging, fixed-bed gasifier; a cold-gas cleanup system 

which produces a marketable sulfur by-product; a molten 

carbonate fuel cell capable of utilizing coal-derived fuel 

gas: a combustion turbine capable of using coal-derived 

7.22 Program Updare 1993 
CalendarYear 

,993 ,994 ,995 ,996 ,997 199B ,999 2000 2001 2002 2003 3412341 234 1234 1234 1 234 1 2 3 4 1 2 3 4 1 2 3 4 1234 12 

5/93 5/94 

, Preaward , 

..~.... ~~~‘.~.~‘xi:::::.:.:.:,:.:.: 

1 1 

cooperatiie agreemfmt 

awarded 594 

DOE selected project 

(CCT-V) wm 

‘Projwwd date; milestones are subject to negotiation 

fuel gas; a heat recovery steam generator; and a steam 

turbine.. 

The demonstration unit is being designed to generate 240 MWe (net) using 1,850 tons/day of West Viiginia 

bituminous coal containing 3% sulfur. 

Project Status/Accomplishments: 

The project is in negotiation. 

Commercial Applications: 

The IGCC system being demonstrated in this project is 

suitable for both repowering applications and new power 

plants. The wide variability in potential market applications and new power plants. The wide variability in 

potential market applications is due to several factors. 

First, the BG/L gasification technology has successfully 

used a wide variety of U.S. coals. Also, the highly 

modular approach to system design makes the BG/Lbased IGCC and molten carbonate fuel cell competitive 

in a wide range of plant sizes. The high efficiency and 

excellent environmental performance of the system are 

Advanced Electric Power Generarim 

competitive with or superior to other fossil-fuel-fired 

power generation technologies. These characteristics 

result in a technology capable of widespread application 

in meeting future U.S. energy needs. 

The heat rate of the IGCC demonstration facility is 

8,200 Btu/kWh (41.6% efficiency) and the commercial 

embodiment of the system has a projected heat fate of 

8,035 Btu/kWb (42.5% efficiency). The commercial 

version of the molten carbonate fuel cell fueled by a 

BG/L gasifier is anticipated to have a heat rate of 

7,379 BtwkWh (46.2% efficiency). These efficiencies 

represent greater than 20% reduction in emissions of 

CO, when compared to a conventional pulverized coal 

plant equipped with a scrubber. SO, emissions from the 

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

Btu (99% reduction): NOxemissions, less than 0.15 lb/ 

million Btu (90% reduction). 

The system being demonstrated is adaptable to a 

wide range of plant sizes and applications due to (1) its 

modular design, (2) its ability to utilize a wide variety of 

coals, and (3) the system’s improved efficiency and 

environmental performance over conventional coal-bed 

power generation technologies. 

Also, the slagging characteristic of the gasifier 

produces a non-leaching, glass-like slag that can be 

marketed as a usable by-product. 

Progrm Update I993 7.23 
Pihon Pine IGCC Power 

Project 

sponsor: 

S&a Pacific Power Company 

Additional Team Members: 

Foster Wheeler USA Corporation-architect, engineer, 

and cnnstructnr 

The M.W. Kellogg Company--technology supplier 

Location: 

Ram, Storey County, NV (Sierra Pacific Power 

Company’s Tracy Station) 

Technology: 

Integrated gasification combine&cycle (IGCC) using the 

KRW air-blown, pressurized, fluid&&bed coal 

gasification system (advanced electric power generation/ 

integrated gasification combined cycle) 

Plant Capacity/Production: 

95 Mwe (net) 

Prolect Funding: 

Total project cost $269,993,100 100% 

DOE 134,996,550 50 

Participant 134.996.550 50 

Project Objective: 

To demonstrate air-blown, pressurized, fluidized-bed 

IGCC technology incorporating hot gas cleanup; to 

evaluate a IowBtu gas combustion turbine: and tn assess 

long-term reliability, availability, maintainability, and 

environmental performance at a scale. sufficient tn determine commercial potential. 

Technology/Project Description: 

Dried and crushed coal is introduced into a pressurized, 

air-blown, fluid&&bed gasifier. Crushed limestone is 

added to the gasifier to capture a portion of the sulfur and 

to inhibit conversion of fuel nitrogen to ammonia. The 

sulfur reacts with the limestone to form calcium sulfidc 

which, after oxidation, exits along with the coal ash in 

the form of agglomerated particles suitable for landfill. 

Hot, low-Btu coal gas leaving the gasifier passes 

through cyclones which return most of the entrained 

particulate matter to the gasifier. The gas, which leaves 

the g&tier at about 1,700 “F, is cooled tn about 1,100 OF 

before entering the hot-gas cleanup system. During 

cleanup, virtually all of the remaining particulates are 

removed by ceramic candle filters, and final traces of 

sulfur are removed in a fked bed of metal oxide sorbent. 

The hot, cleaned gas then enters the combustion 

turbine which is coupled to a generator designed to prnduce 61 MWe (gross). Exhaust gas is used to produce 

steam in a heat recovery steam generator. Superheated 

high-pressure steam drives a condensing steam turbinegenerator designed to produce about 41 MWe (gross). 

Due to the relatively low operating temperature of 

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

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

sulfur capture and hot gas cleanup, SO, emissions are 

0.069 lb/million Btu (90% reduction). 

In the demonstration project, 893 tons/&y of coal 

are converted into 102 MWe (gross), or 95 MWe (net), 

for export to the grid. Western bituminous coal 

(0.5-0.9% sulfur) from Utah is the design coal: tests 

7.24 Program Updore I993 Advanced Ekctric Power Generarion 
I bpwation initiated 2/97 

Preoperational te* initiated 2197’ 

Design conpleted 8lQ5 Co”*b”ctio” corQlet*d 2197 

lc&!ndarYear 

,991 ,992 ,993 1994 199.5 ,996 ,997 ,598 ,959 2000 2001 3 4 1 2 3 4 ,234, 23412341 234 1 234 1 23412341234 12 

DesignandConstruction 

2/97 7/00 

bOE se&ed 

$;pm:(CCT-IV) 

I o roundb,eakin~,mnstr”ction started 12K4 

Environmental monitoring plan completed l&W 

NEPA process completed (EIS) 819.4’ 

Project mmpleted~inal regon issued 7/W 

Operation completed 7100’ 

&.watiie agreement awarded 8Hi92 

‘Projected date 

using West Virginia OI Pennsylvania bituminous coal 

containing 2-3% sulfur also are planned. The gasitier is 

being built at Sierra Pacific Power Company’s Tracy 

Station, near Reno, NY 

The construction schedule has been slipped to accommodate delays in the Nevada Commission approval 

process and the NEPA process. 

Commercial Applications: 

Project Status/Accomplishments: 

Design and permitting activities continued throughout 

1993. In June, DOE approved incorporation of the 

newly announced GE Model 6PA gas turbine into the 

project. Piiion Pine will be the fust plant anywhere to 

operate with the new turbine. This change resulted in an 

increase in the plant size from 80 to 102 MWe (gross). 

In October, the Public Service Commission of Nevada approved Sierra Pacific’s resource plan, which 

presented the Pifion Pine Project as the preferred option 

for new power generation. In its order, the Commission 

strongly weighed the fuel diversity benefits of the plant. 

Information for preparation of the environmental 

impact statement has been developed. A preliminary 

draft of the EIS was completed in December 1993. A 

draft for public comment is anticipated in early 1994. 

The Pifion Pine IGCC system concept is suitable for new 

power generation, repowering needs, and cogeneration 

applications. The net effective heat rate for a proposed 

greenfield plant using this technology is projected to be 

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

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

IGCC systems reduces space requirements per unit of 

energy generated relative to other coal-based power 

generation systems, and the advantages provided by 

modular construction reduce the financial risk associated 

with new capacity additions. 

minimal environmental impact. This versatility provides 

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

significant process waste streams that require 

remediation. The only solid waste from the plant is a 

mixture of ash and calcium sulfate, a non-hazardous 

waste. SO, emissions are expected to be below 0.045 lb/ 

million Btu (98-99% reduction for most high-sulfur 

coals). NO, emissions ax expected to be below 

0.053 lb/million Btu, and emissions of particulates are 

expected to be below 0.01 lb/million Btu. 

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 

Advanced Electric Power Generation Program Update I993 7-25 
Toms Creek IGCC 

Demonstration Project 

sponsor: 

TAMCO Power Partners (a partnership between TP 

[TAMCO] Company, a subsidiary of Tampella Power 

Corporation, and CP [TAMCOI Company, a subsidiary 

of Coastal Power Production Company) 

Additional Team Member: 

Institute of Gas Technology-technology developer and 

consultant 

Location: 

Coebum, Wtse County, VA (Virginia Iron, Coal, and 

Coke Company’s Tams Creek Mine) 

Technology: 

Integrated gasification combined-cycle (IGCC) using the 

Tampella U-GAS” fluidized-bed gasification system 

Plant Capacity/Production: 

190 MWe (55 MWe IGCC and 135 MWe pulverized 

coal) (net) 

Project Funding: 

Total project cost $196,570,000 100% 

DOE 95,000,000 48 

Participant 101,570,000 52 

Project Objective: 

To demonstrate an air-blown, fluidized-bed gasification, 

combined-cycle technology, incorporating hot gas 

cleanup, for generating electricity and to assess the 

system’s environmental and economic performance for 

meeting future energy needs. Also to demonstrate the 

newly developed zinc titanate fluidized-bed hot-gas 

cleanup technology. 

U-GAS isaregistcred trademark of mc tnstitutc ofGa.sTcchnotogy~ 

Coal is gasified in a pressurized, air-blown, fluidix&bed gasifier in the presence of a calcium-based 

sorbent. About 90% sulfur removal is accomplished in 

the gasifier. Solids entrained in the gas are collected by 

cyclones in two stages. The low8tu gas, which leaves 

the secondary cyclone at 1,800-1,900 “F, is cooled to 

about 1,000 OF before entering the post-gasifier desulfurization unit where zinc titanate is used to remove the 

bulk of the remaining sulfur in the gas. This is accomplished in two fluidized beds. III the first bed, the sulfur 

is absorbed by the zinc titanate; the zinc titanate is 

About 430 tons/day of bituminous coal are converted into 55 MWe by the gas turbine. A conventional 

pulverized coal boiler produces another 135 MWe 

through the shared steam turbine generator. Also, 

50,000 lbsibr of steam are generated for export to a coal 

preparation plant located next to the demonstration facility. The electric power is sold to a utility. 

7-26 Program Updare 1993 Advanced Electric Power Generarim 

DOE COST-SHARED PROJECT SCOPE I ‘PCRTIONOFSTEW TURBlNElNCLUOEDINPROJECr i 

Technology/Project Description: 

Being demonstrated is an IGCC system in which airblown operation has replaced the more conventional 

oxygen-blown gasifier operation and hot gas cleanup has 

replaced cold gas cleanup with the usual associated 

sulfurrecovery. 

regenerated in the second bed. In the final hot-gascleaning step, a ceramic candle filter removes particulates. The gas is then sent to the gas turbine combustor 

which has been modified to bum 1owBtu gas. 

Hot exhaust gases from the gas turbine are directed 

to a heat recover steam generator. The steam generated 

is used both for driving a conventional steam turbine 

generator to produce additional electricity and to provide 

steam feed to the gasifier. 
C*l*“d*rYMr 

,991 1992 ,993 ,594 1595 ,996 ,997 ,998 ,999 2ooLl 2001 

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

;’ 

Project conpl*t*d/ 

final report issued 4101 

Operation completed 4M1* 

nvironmental monitoring plan 

corrpleted 4,94 

bperation initiated 4198’ 

Construction completed 498’ 

Cooperative agreemen, awarded IWO192 Precperational tests initiated IO/97 

‘Projected date 

The facility is a greenfield plant located outside performance. Because of its advantages of modularity, The U-GAS’ technology is capable of gasifying all 

Coebum, VA, next to the Tams Creek Mine owned by rapid and staged on-line generation capability, high types of coals. including high-sulfur and high-swelling 

Virginia Iron, Coal, and Coke Company, a subsidiary of efficiency, environmental controllability, and reduced coal feedstocks. 

Coastal Power Production Company. land and natural resource needs, IGCC is a strong con- The total system being demonstrated is compact, 

Project Status/Accomplishments: 

During 1993, efforts have been geared toward obtaining 

a power sales agreement with a tbiid party purchaser of 

power. Preliminary design and project definition studies 

are under way. Environmental information is being 

prepared for use in the NEPA process. 

Commercial Applications: 

The Toms Creek IGCC system is suitable for new power 

plants, repowering needs, and cogaeration applications. 

In went years, IGCC has become a rapidly emerging alternative for new electric generating plants. Such 

plants require. 15% less land area than pulverized coal 

plants with flue gas desulfurization, and exhibit substantially improved thermal efficiency and environmental 

tender for widespread application for meeting future U.S. 

energy needs. Another important application for IGCC is 

cogeneration under PURPA’s Qualifying Facilities provisions. 

The heat rate of the demonstration facility is expetted to be 8,720 BtuikWh (39% efficiency) with SO, 

emissions reductions of 99% (0.056 lb/million Btu release). NO% emissions are estimated to be 0.09 lblmillion Btu. 

reducing space requirements, and is very amenable to 

smaller capacity, modular construction situations. There 

are no significant wastewater streams, and the solid 

waSte from the gasiiier is ash and calcium sulfate, which 

is discharged as a nonhazardous waste. 

A larger, commercial-scale, 271.MWe greenfield 

facility based on the Tams Creek technology is estimated 

to have a heat rate of 7,750 BtuikWh (44% efficiency). 

This represents a 20% increase in thermal efficiency and 

a corresponding reduction in CO, emissions as compared 

to a conventional pulverized coal plant equipped with a 

scrubber. 

Advanced Elecwic Power Genernrion Program Update 1993 7.27 
Tampa Electric Integrated 

Gasification Combined-Cycle 

Project 

Sponsor: 

Tampa Electric Company 

Additional Team Members: 

Texaco Development Corporation-gasification 

technology supplier 

General Electric Company-combined-cycle technology 

supplier 

GE Environmental Systems, Inc.-hot-gas cleanup 

technology supplier 

TECO Power Services Corporation-project manager 

and marketer 

Bechtel Power Corporation-architect and engineer 

Location: 

Lakeland, Polk County, FL (Tampa Elecaic Company’s 

Polk Power Station) 

Technology: 

Integrated gasification combined-cycle (IGCC) system 

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

moving-bed desulfurization (advanced electric power 

generation/integrated gasification combined cycle) 

size with a Texaco gasifier. To demonstrate the integrated performance of a zinc-titanate hot-gas cleanup 

system, conventional cold-gas cleanup, and an advanced 

gas turbine with nitrogen injection (from the air separadon plant) for power augmentation and NOx control. 

The cooled gases flow to a particulate-removal 

section before entering gas-cleanup trains. About 50% 

of the syngas is passed through a moving bed of zinctitanate absorbent to ranwe sulfur. The remaining 

_ . ^ 

Plant Capacity/Production: 

250 Mwe (net) 

Project Funding: 

Total project cost $260,706,446 100% 

DOE 130,353,223 50 

Participants 130,353,223 50 

Project Objective: 

To demonstrate the IGCC technology in a greenfield, 

commercial, electric utility application at the 250.MWe 

Technology/Project Description: 

Texaco’s pressurized, oxygen-blow”, entrained-flow 

gas&r is used to produce a mcdiumBtu fuel gas. Coal/ 

water slurry and oxygen are combined at high temperature and pressure to produce a high-temperature syngas. 

Molten coal-ash flows out of the bottom of the vessel and 

into a water-filled quench tank where it is turned into a 

solid slag. The syngas from the gasifier moves to a hightemperature heat-recovery unit which cools the gases. 

synga.3 1s rurtiler coo1ea mrougn a sates Of heat excilangers before entering a conventional gas-cleanup train 

where sulfur is removed by an acid-gas removal system. 

These cleanup systems combined are expected to maintain sulfur levels below 0.21 lb/million Btu (96% capture). The cleaned gases are then routed to a combinedcycle system for power generation. A gas turbiw 

generates about 192 MWe. Thermally generated NOx is 

controlled to below 0.27 lb/million Btu by injecting 

nitrogen as a dilutent in the turbine’s combustion section. 

A heat-recovery steam-generator uses heat from the gasturbine exhaust to produce high-pressure steam. This 

7-28 Pro~ramUpdate1993 Advanced Electric Power Generation 
CalendarYear 

Isea 

2Y 

,990 'Sal ,392 ,993 1994 1995 ,996 1997 ,998 

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

3/91 6/96 6/9f 

I ’ 

Cooperativeagreementawarded3/11/91 

DE sekted project (CCT-III) IZIg/ 1 1’ 

? Project corrQ!etedmnat 

repon issued 6/98’ 

Operation compleled 6198’ 

operation initiated g/96’ 

Construction completed 3196’ 

Design completed a94 Preqmrational tests initiated 3/g@ 

NEPA process conpleled (EIS) 6/94’ 

Environmm(al monitoring plan mmpleted 6/94’ 

Canstructlon started 6&U’ ‘Projected date 

steam, along with the steam generated in the gasification 

process, is routed to the steam turbine to generate an 

additional 130 MWe (press). The IGCC heat rate for 

this demonstration is expected to be approximately 

8,600 Btu/kWb (40% efficient). Coals being used in the 

demonstration are Illinois 6 and Pittsburgh 8 bituminous 

coals having sulfur contents ranging 2.5-3.5%. 

By-products from the process-sulfuric acid and 

slag-can be sold commercially, sulfuric acid by-products as a raw material to make agricultural fertilizer and 

the nonleachable slag for use in rooting shingles and 

asphalt roads and as a structural fill in construction 

projects. 

Project Status/Accomplishments: 

The project has completed the preliminary design stage. 

All key subcontracts and licensing have been negotiated 

and awarded. Bechtel Power Corporation was selected 

as the architect and engineer for the site and a revised 

cost estimate for the project was developed 

Advanced Electric Power Generoiion Progrm Update 1993 7-29 

The permitting process for Florida is nearing 

completion. Tampa Electric’s site certification application was presented before the state hearing officer in 

October 1993. Based an the positive comments received 

at the hearing, all required state permits are expected 

during January 1994. EPA and DOE are continuing the 

process of developing the EIS for the Polk Power Plant. 

EPA expects to release a draft EIS for public comment in 

early 1994. The project schedule has been revised to 

accommodate delays in the NEPA process and time for 

checkout and star-up activities. 

TheTexaco-based system has already been proven 

capable of handling both subbituminous and bituminous 

coals. This demonstration project is scaling up the technology from Cool Water’s 100.MWe to the 250.MWe 

size. 

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 8,5W Btu/kWh, which makes it very attractive for 

baseload applications. Commercial IGCCs should 

achieve better than 98% SO, capture with NO= emissions 

reduced by 90%. 
Wabash River Coal 

Gasification Repowering 

Project 

Sponsor: 

Wabash River Coal Gasification Repowering Project 

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

PSI Energy, Inc.) 

Additional Team Members: 

PSI Energy, Inc.-host utility 

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

technology supplier 

Location: 

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

Wabash River Generating Station) 

Technology: 

Integrated gasification combined-cycle (IGCC) using 

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

(advanced electric power generation/integrated 

gasification combined cycle) 

Plant Capacity/Production: 

262 Mwe (net) 

Project Funding: 

Total Project cost $396,000,000 

DOE 198,000,OOO 

Participant 198,000,OOO 

Project Objective: 

100% 

50 

50 

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. 

Technology/Project Description: 

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

pressurized, two-stage (entrained now slagging fust 

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

entrained-flow gasifier. The product gas is cooled 

through heat exchangers and passed through a conventional cold gas cleanup system which removes particulates, ammonia, and sulfur. The clean, mediumBtu gas 

is then reheated and burned in an advanced 192-MWe 

(gross) gas turbine. Hot exhaust from the gas turbine is 

passed through a beat recovery steam generator to produce high-pressure steam. High-pressure steam is also 

produced from the gasification plant and superheated in 

the heat recovery steam generator. The combined highpressure steam flow is supplied to an existing 104MWe 

(gross) steam turbine. 

The process has the following subsystems: a coalgrinding and slurry system, an entrained-flow coal gasif&r, a cold gas cleanup system which produces a marketable sulfur by-product, a combustion turbine capable 

of using coal-derived fuel gas, a heat recowry steam 

generator, and a repowered steam turbine. 

One of six units at PSI Energy’s Wabash River 

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

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

of high-sulfur (X3-5.9% sulfur), Illinois Basin bituminous coal. The anticipated heat rate for the repowered 

unit is approximately 9,000 Btu/kWh (38% efficiency). 

Using high-sulfur bituminous coal, SO, emissions are 

expected to be less than 0.2 lb/million Btu (98% reduction). NO= emissions are expected to be less than 

7.30 Program Update 1993 Advanced Electric Power Generation 
CalendarYear 

1991 1992 ,993 ,994 ,995 ,998 ,597 ,998 ,999 2000 2001 

3 4 f 23412341 234 1 234 1 234 I 234123412341234 12 

9/95 7199 

I 1 bperation initiated &“A5 

Construction completed ms 

Pr*opr.ational tests initiated 7195’ 

esign corQl*ted 594 

round brealdng,mnsb”ctio” started 7/W 

Environmental mnitoring plan completed 719193 

rojed conpleted~inal report issued 7/98 

Operation conpleted 7B8’ 

iPA process mnpleted (En) 5,**193 

Cooperative agreement awarded 7,2&W ‘Projected date 

0.1 lb/million Btu (90% reduction). Upon completion, 

the project will represent the largest single-train IGCC 

plant in operation in the United States. 

Project Status/Accomplishments: 

The Indiana Utility Regulatory Commission issued Certificates of Public Convenience and Necessity on May 

26, 1993. Project construction was officially initiated in 

a ceretnony at the site on July I, 1993. Major equipment 

procurement and construction arc in progress. 

Following the completion of an environmental a.- 

sessment, DOE issued a finding af no significant impact 

on May 28,1993, concluding the NEPA process. All 

required environmental permits have been granted. 

The schedule has been revised to accommodate 

delays associated with the NEPA process and air emissions permitting. 

Commercial Applications: 

Throughout the United States, particularly in the Midwest and East, there are mnre than 95,000 MWe of existing coal-f&d utility boilers which will be river 30 years 

old in 1996. Many of these aging plants are without air 

pollution controls and are candidates for repowering with 

IGCC technology. Repowering of 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 tn be 

considered for repowering 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 gasitier design allows utilities greater 

choices in fuel supplies to meet increasingly stringent air 

quality regulations. 

Due to the advantages of modularity, rapid and 

staged on-line generation capability, high efficiency, fuel 

flexibility, environmental controllability, and reduced 

land and natural resource needs, the IGCC system is also 

a strong contender for new electric power generating 

facilities. Commercial offerings of the technology will 

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

utility-scalepowergeneratinn applications. The system 

heat rate for a new power plant based on this technology 

is expected tn realize at least a 20% improvement in 

efficiency compared tn a conventional pulverizedcoalFired plant with flue gas desulfurization. The improved 

system efficiency also results in a similar decrease in 

emissions of CO, 

Advanced Electric Power Genmarion Progrm Update 1993 7-31 
Healy Clean Coal Project 

Sponsor: 

Alaska Industrial Development and Export Authority 

Additional Team Members: 

Golden Valley Electric Association-host utility 

Stone and Webster Engineering Corp.- 

engineer 

TRW, Inc.-technology supplier 

Joy Technologies, Inc.-technology supplier 

Location: 

Healy, Denali Borough, AK (adjacent to Healy Unit #1) 

Technology: 

TRW’s advanced entrained (slagging) combustor 

Joy Technologies’ spray dryer absorber with sorbent 

(advanced electric power generation/advanced 

combustion/heat engines) 

Plant Capacity/Production: 

50 MWe (nominal electric output) 

Project Funding: 

Total project cost $227,000,000 100% 

DOB 109,513,000 48 

Participants 117,487,OOO 52 

Project Objective: 

To demonstrate an innovative new Power plant design 

featuring integration of an advanced combustor and heat 

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

7.32 Program Update I993 

Technology/Project Description: 

The project is to be a nominal 50.-MWe facility consisting oftwopulverizedcoal-fuedcombustor systems. 

Emissions of SO, and NO= will be controlled using 

TRW’s slagging combustion systems with staged fuel 

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

conditions, and limestone injection. Further SO, will be 

removed using Joy’s activated recycle spray dryer absorber system. Performance goals are NOx emissions of 

less than 0.2 lb/million Btu, particulates of 0.015 lb/ 

million Btu, and SO, removal greater than 90%. The 

performance coal consists of 50% run-of-mine and 50% 

waste coal, with the waste coal having a lower heating 

value and significantly more ash. 

A coal-tied precombustor increases the air inlet 

temperature for optimum slagging performance. The 

TRW slagging combustors are bottom-mounted on the 

boiler hoppec The main slagging combustor consists of 

a water-cooled cylinder which slopes toward a slag opening. The precombustor burns 25-40% of the total coal 

input The remaining coal is injected axially into the 

combustor, rapidly entrained by the swirling precombustar gases and additional air flow, and burned under 

substoichiometric (fuel-rich) conditions for NO% control. 

The ash forms drops of molten slag which accumulate on 

the water-cooled walls and are driven by aerodynamic 

and gravitational forces through a slot into the slag recovety section About 7030% of the coal’s ash is removed as molten slag. The hot gas is then ducted to the 

furnace where, to ensure complete combustion, addtional air is supplied from the tertiary air windbox to 

NOx ports and to final over-fue air ports located in the 

furnace. 

Advanced Electric Power Generation 
CalendarYear 

,990 ,591 1992 ,993 ,994 1995 1996 ,997 ,998 ,999 2000 

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

‘I 

t 

COOp~~dl* 

agEWT-S”t 

awarded 4/l InI 

Desiin 

started 7190 

DOE selected project 

(CCT-III) l.MgiSg 

;T 

* I 

T 

t 

Environmental nwnitodng Project corQk.t*d/ 

plan conykd 4194. final report issued 

6198 

Ground breakinglwnsbuction staned 3194 DOE con-shared 

EPA process completed (EIS) Z//94’ 

$eepn completed I 

2 yrs of operational 

data provided at no 

Operation initiated 1197 additional cost 

Design completed IO/93 17J99’ 

CO”Sk”Cson conpleted 6lv6’ 

Preoperational tests initiated 6/gS’ ‘Projected date 

L 

filter (baghouse) system. A small part of the flash-calPulverized limestone (CaCO,) for SO, control is fed 

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

into the combustor where most is flash calcined. The 

mixing tank where water is added to form a 45% flashcalcined-material solids slurry. The slung leaving the 

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

mixing tank is pumped to a grinding mill where it is 

mechanically activated by abrasive grinding. Feed slurry 

called flash-calcined material, is removed in the fabric 

is pumped from the feed tank to the spray dryer absorber 

where the slurry is atomized using Joy dry scrubbing 

technology. SO, in the flue gas reacts with the slurry as 

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

impact to the nearby Denali National Park and Preserve, 

DOE, the National Park Service, Golden Valley and the 

3 years of data, with 2 years of data being provided at no 

project sponsor entered into an agreement to reduce the 

cost to DOE. A hazardous air pollutant monitoring 

emissions from Unit #l. As a result, the combined emisprogram will also be implemented. 

sions from the two units should be only slightly greater 

than those currently emitted from Unit #I alone. The 

agreement also provides that the total site emissons will 

In order to address concerns regarding the potential 

be further reduced (to current levels if necessary) in order 

to protect the park, 

scaleup designs. The design and engineering is complete; construction is scheduled to start in March 1994. 

A final EIS was issued in December 1993; and a 

record of decision is scheduled for March 1994. 

Commercial Applications: 

Project Status/Accomplishments: 

Test bums using Healy project fuel were completed at 

TRW’s Cleveland facility. Joy/Nun testing of flash 

calcined sorbent was completed at the Copenhagen 

facility. A full-scale precombustor was constructed and 

test fired at TRW’s Capistrano, CA, test facility to verify 

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 boilers as 

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

ash removal capability. However, cyclone boilers may be 

the most amenable type to retrofit with the slagging 

combustor because of the limited supply of high-Btu, 

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

boilers require. The commercial availability of costeffective and reliable systems for SO,, NO*, andparticulate 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 #l near Healy, AK. Power will go to the Golden 

Valley Electric Association. The plant will provide 

Advanced Electric Power Generation Program Update 1993 7-33 
Coal Diesel Combined-Cycle 

Project 

sponsor: 

Arthur D. Little, Inc. 

Additional Team Members: 

Ohio Coal Development Office-cofunder 

The Easton Utilities Commission--host 

Cooper Energy Services (Cooper-Bessemer 

COAL 

WATER 

Reciprocating Products Division is a division of 

Cooper Energy Services which is owned by Cooper 

Industries.)+ngine supplier and commercializer 

CQ. Inc.~oal-slurry supplier 

POWERSERVE Inc.+leanup system designer 

Location: 

Easton, Talbot County, MD (The Easton Utilities 

Commission’s Plant #2) 

Technology: 

Cooper-Bessemer’s coal-fueled diesel engine combinedcycle (CDCC) system (advanced electric power generation/advanced combustion/heat engines) 

Plant Capacity/Production: 

14 MWe (net) 

Project Funding: 

Totalprojectcost $37,309,516 100% 

DOE 18,654,758 50 

Participant 18,654,758 50 

(Funding amounts reflect those contained in the proposal 

and are subject to negotiation.) 

To demonstrate an advanced, coal-fueled diesel engine 

combined-cycle system based 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 is centered around two Cooper-Bessemer 

medium-speed (400 rpm) diesel engines (6.3 MWe each) 

modified 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. TheCDCC system utilizes a coal-water fuel with a nominal 50% solids loading with a 2% ash clean coal. The clean coal is ground 

and slurried 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 turbocharger and maintaining high engine and 

overall system efficiency (45%). The exhaust gases pass 

through a heat recovery steam boiler coupled to a steam 

turbine and generator to supply an additional 1.4 MWe. 

Critical data on performance, reliability, and wear are 

being collected for all major subsystems including the 

coal-water fuel metering and injection system, mediumspeed diesel, lube oil protection system, exhaust cyclone, 

turbocharger, heat recovery steam boiler, steam turbine, 

and exhaust emission cleanup system. 

Project Objective: 

The exhaust emission cleanup system incorporates 

cyclones to remove the larger patticulates, a selective 

catalytic recovery system for NO& control, a duct sorb& 

injection system for SO, control, and haghouse for final 

collection of ash particulates and spent sorbem. 

The demonstration site is The Eaton Utilities 

Commission’s Plant #2 in Easton, MD. Planned for use 

is an Ohio bituminous coal with characteristics suitable 

for cleaning to ash levels of about 2% (sulfur content 

undetermined). 

7.34 Program Updale 1993 Advanced Electric Power Generarim 
993 5/94 

I I 

Cocperativeagreerrent 

awarded 5,94’ 

DOE selected project 

&XT-V) 5,4/93 

‘Projected date: milestonss are subject to negotiation 

Project Status/Accomplishments: 

The project is in negotiation. Environmental information 

is being prepared for use in the NEPA process. 

Commercial Applications: 

The CDCC system is particularly suited for small (below 

50 MWe) electric power generation markets. Projected 

markets include small nonutility generators and repowering applications for small coal-fired boilers. The net 

effective heat rate for the mature CDCC is expected to be 

6,830 Bt”/kWh (48%), which makes it very competitive 

with similarly sized coal- and fuel-oil-fired installations. 

Environmental emissions from commercial CDCCs 

should be reduced to levels between 50% and 70% below NSPS. 

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

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

cylinder engines are planned for this project. Demon. 

stration of the long-term reliability of the critical compo- 

“ems in the CDCC system will provide power generators 

with an efficient and environmentally superior option for 

future power. 

Cooper-Bessemer is currently the largest U.S. 

manufacturer of large-scale diesel engines and commands a significant share of the U.S.-based market in 

that size range. The CDCC system has already achieved 

over 200 hours of operation using coal-water fuel in a 

Advanced Elecfric Power Generation Progrm Updare I993 7-35 
Warren Station Externally 

Fired Combined-Cycle 

Demonstration Project 

Sponsor: 

Pennsylvania Electric Company 

Additional Team Members: 

Hague International-technology developer and supplier 

Black & Veatch--engineer and construction manager 

Location: 

Warren, Warren County, PA (Pennsylvania Electric 

Company’s Warren Station Unit 2) 

Technology: 

Hague International’s externally fired combined-cycle 

@FCC) system using a novel, high-temperature, ceramic 

gas-to-air heat exchanger (advanced electric power 

generation/advanced combustion/heat engines) 

Plant Capacity/Production: 

62.4 MWe (net) 

Project Funding: 

Total project cost $146.438.000 100% 

DOE 73,219,OOO 50 

Participant 73,219,OOO 50 

(Funding amounts reflect those contained in the proposal 

and an. subject to negotiation.) 

ProJect Objective: 

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

and to assess the system’s environmental and economic 

performance for meeting future energy needs. Along 

with the heat exchanger, the system will demonstrate a 

ceramic slag screen for removal of combustionby-products from the product gas prior to entering the heat exCerHx is aregistered vadenmk Of Hague htematio”at. 

796 Program Update 1993 

tchanger a staged, wet bottom, low-NOx comhustor; and 

the integration of the above with a gas turbine and a 

steam turbine. 

Technology/Project Description: 

In this project, an existing coal-fueled steam plant is 

being repowered by adding an externally fired gas turbine to form a combined-cycle system. The central feature of the EFCC is a ceramic air heater or heat exchanger (CerHxe) and an atmospheric combustor which 

together replace a conventional combustion system in an 

open-cycle gas turbine. 

Coal is first combusted in a staged combustor for 

NO= control. Particulate-laden gases exit the comhustor 

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 CerHx”. The product gas is then passed 

through a heatrecovery steam generator, where more 

heat is extracted to drive a steam turbine generator and 

produce electricity. The product gas is finally passed 

through a gas cleanup system consisting of a flue gas 

desulfurizer and a fabric filter before exiting to the atmosphere through the stack. The hot air from the CerHxO is 

passed through a gas turbine to produce additional electricity before firing the combustor. 

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 components from the 

corrosive and abrasive elements in the combustion product gas. Instead, the gas turbine operates on indirectly 

Advanced Electric Power Generation 
CalendarYear 

,983 1994 ,995 ,996 1997 19n8 ,999 2000 2001 2002 2003 

3 4 1 2 3 4 12341 2 3 4 f 2 3 4 ,234 1 2 3 4 12341 2 3 4 1234 12 

5/93 5/94 

, Preaward , 

~ 

I 1 Coqwativea*reemmt 

awarded 5/94* 

DOE selected pro@4 

(CCT-V) 5,4193 

‘Projected date; milestones are subject to negotiation 

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

corrosive elements in the fuel or product gas. The 

CerHx@ raises the temperature of the air to the turbine 

inlet conditions using tube elements that are manufactured from corrosion resistant, toughened, ceramic materials. 

About 225,000 tons@ of bituminous coal will be 

cornbusted to produce 62.4 MWe. The gas turbine will 

generate 18.3 MWe with a small amount of steam 

injection and the existing steam turbine will generate 

41.1 MWe, for a total gross output of 66 MWe. Approxi. 

mately 3.6 MWe will be consumed internally. The heat 

rate of the demonstration facility will be 9,650 BtwkWh 

(HHV), which is a 31.3% improvement over the existing 

Warren Station unit. Potential SO= release is reduced by 

over 90% through capture in the flue gas desulfutiation 

system. NOx emissions are expected to be below 

0.13 lb/million Btu. 

The facility being repowered is Pennsylvania ELhit Company’s Warren Station Unit 2 near Warren, PA. 

The primary coal for the project is Pennsylvania bituminous coal containing either 1.0% or 2.3% sulfur, depending on the mine. A secondary test coal is Pennsylvania 

bituminous coal containing 1.6% sulfur. 

SO, is expected to be below 0.081 lb/million Btu, 

which is a reduction of over 90% for most coals. NOx 

emissions are expected to be less than 0.15 lb/million 

Btu and particulate emissions (PMlO) are expected to be 

below 0.015 lb/million Btu. 

Project Status/Accomplishments: 

The project is in negotiation. Environmental infornx&on 

is being prepared for use in the NEPA process. 

Commercial Applications: 

The Warren Station EFCC system concept is suitable for 

new electric power generation, repowering needs, and 

cogeneration applications. The potential commercial 

market for such systems is expected to be 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 BtujkWh. This represents a 20% increase in thermal efficiency compared to a conventional pulverized 

coal plant with a scrubber. 

Advanced Electric Power Generahm Program Update 1993 7.37 
Environmental Control 

Devices 

Fact Sheets 
Demonstration of Coal 

Reburning for Cyclone Boiler 

NO, Control 

Proled completed. 

Sponsor: 

The B&cock & Wilcox Company 

Additional Team Members: 

Wisconsin Power and Light Company~ofunder and 

host utility 

Sargemand Lundy+ngineer for coal handling 

Electric Power Research Institute--cofunder 

State of Illinois, Department of Energy and Natural 

Resourcesdofunder 

Utility companies (14 cyclone boiler operators)- 

cofunders 

Location: 

Cassville, Grant County, Wl (Nelson Dewey Station, 

Unit No. 2) 

Technology: 

The Babcock & Wilcox Company’s coal-rebuming 

system (environmental control devices/NOx control 

technologies) 

Plant Capacity/Production: 

100 MWe 

achieve greater than 50% reduction in NOx emissions 

with no serious impact on cyclone combustor operation, 

boiler efficiency, boiler fueside performance (corrosion 

and deposition), or ash removal system performance. 

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

where the balance of the combustion air is introduced. 

The combined production of boiler slag and dry waste 

from the electrostatic precipitator remains unchanged 

with coal rebuming because the required coal input for 

the same boiler load is the same. 

ProJect Funding: 

Totalprojectcost 

DOE 

Participants 

$13,646,609 100% 

6,340,788 46 

7,305,821 54 

Project Objective: 

Technology/Project Description: 

The coal-rebuming process reduces NOK 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 (20-30%), 

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

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 

The coal-rebuming technology can be applied with 

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

adverse effects of reburn on the cyclone combustor and 

boilerperformance. 

To evaluate the applicability of reburning technology for 

reducing Nor emissions from a full-scale coal-fxed 

cycloneboiler,pulverizing a portion of the primary coal 

fuel to use as the secondary, “rebuming”fue1; and to 

This project involved retrofitting an existing 

100.MWe cyclone boiler that is representative of a large 

population of cyclone units. The boiler is located at 

Wisconsin Power and Light’s Nelson Dewey Station in 

Cassville, WI. 

740 Program Updare 1993 Enviromtd Control Devices 
Project Results/Accomplishments: 

Coal-reburn tests were conducted to determine the reduction in NOx emissions for the coal-reburning 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) and a western 

subbituminous coal (Powder River Basin, 0.5% sulfur). 

The bituminous coal tests evaluated a fuel typical of the 

coals fired by utilities operating cyclones. The subbituminous coal tests evaluated coal switching for SO, 

reduction. 

As a part of the test program, several parameters 

were optimized over the load range to 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 

reburn zone stoichiometries, the reburn burner pulverized 

coal fineness, flue gas recirculation, and economizer 

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

reburn burners and the over-fire air ports during the tests. 

With the Lamar coal, the boiler NOx emissions were 

reduced as follows: 

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

a 47% (to 285 ppm or 0.387 lb/million Btu) at 82 MWe 

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

With Powder River Basin coal, the NOx emissions 

were reduced as follows: 

t 62% (to 208 ppm or 0.278 lb/million Btu) at 110 MWe 

. 55% (to 215 ppm or 0.287 lb/million Btu) at 82 MWe 

. 53% (to 220 ppm or 0.294 lb/million Btu) at 60 MWe 

Envi,-onmental Control Devices 

Rebum testing with both coals indicated that v;uying rebum zone stoichiometry is the most critical factor 

in controlling NO<. Rebum zone stoichiometry can be 

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

rate, or cyclone stoichiometry. 

Burning subbituminous coal produced lower overall 

NOx emissions levels and higher NOx emissions reductions. This result is probably due to the higher volatile 

content of the western coal. The higher volatile content 

generates higher concentrations of hydrocarbon radicals 

in the reburn zone. With the rebum system contributing 

additional burning capacity for the cyclone boiler, the 

lower Btu content western fuel could be tired up to the 

full boiler load rating. 

Additional effects of coal reburning on the retrofitted 

boilerfollow: 

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

bituminous coal and 0.3% with subbituminous coal. 

The performance of the ESP remained constant even 

though its ash loading doubled. The increased ash 

consisted of larger sizes of particulates. 

The furnace exit gas temperature decreased by more 

than 100 OF at full load, contrary to expectations, and 

thus improved the boiler heat absorption efficiency 

correspondingly. 

Slagging and fouling were significantly reduced with 

bituminous coal reburning. The subbituminous 

reburn operations were too short in duration to make a 

reasonable observation. 

No furnace corrosion was observed over the l-year 

test period. 

Hazardous air pollutants (HAP) testing was performed 

using Lamar test coal. HAP emissions were generally 

well within expected levels and emissions with rebum 

comparable to baseline operations. 

Commercial Applications: 

The current reburn market is nearly 26,000 MWe and 

consists of about 120 units ranging from 100 MWe to 

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

Coal rebuming is a retrofit technology applicable across 

the size range of utility and industrial cyclone boilers. 

The principal environmental benefit is reduced NOx 

emissions, A secondary benefit may be reduced SO, 

emissions by enabling greater use of lower sulfur weste-n coal; due to its lower Btu 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 NO= 

reduction alternative at a cost expected to be in the range 

of $65/kW for 100 MWe units to S4OikW for a larger 

600 MWe unit. This includes costs for coal handling and 

pulverizerslcoal piping. Coal’s cost differential and 

dependability of supply give it the long-run advantage. 

Another advantage of the rebum system is its ability to 

utilize different coals. 

Project Schedule: 

DOE selected project (CCl-10 9128188 

Cooperative agreement awarded 412190 

NEPA process completed (EA) 2112191 

Environmental monitoring plan completed 1 l/18/91 

Construction 11/90-11/91 

Operational testing 11/91-12192 

Project completed 12193 

Final Reports: 

Final Technical Report early 1994 

Economic Evaluation Report early 1994 

Public Design Report 8191 

Program Update 1993 7.41 
Full-Scale Demonstration of 

Low-NO, CellTM Burner 

Retrofit 

Pro/m3 completed. 

sponsor: 

The Babcock & Wilcox Company 

Additional Team Members: 

The Dayton Power and Light Company-xfunder and 

host utility 

Electric Power Research Imtitutaofunder 

Ohio Coal Development Ofiice-cofunder 

Tennessee Valley Authority-xfunder 

New England Power CompanyAofunder 

Duke Power Company--cofunder 

Allegheny Power System-cofunder 

Centerior Energy Colporation-cofunder 

Location: 

Aberdeen, Adams County, OH (Dayton Power and Light 

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

Technology: 

The Babcock & Wilcox Company’s Low-NOx CellTM 

burner (LNCBTM) system (environmental control devices/ 

NOx control technologies) 

Plant Capacity/Production: 

605 MWe 

Project Funding: 

Total project cost 

DOE 

Participants 

$11,233,392 100% 

5,442,800 48 

5,790,592 52 

Low-Nq Cc”, LNC, and mat UC !rademslkr of The Babcozk 8r 

witcoxcompany. 

Technology/Project Description: 

Low-NO= CellTM burner 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 LowNOr CeFM burner operates 

on the principle of staged combustion to reduce NOx 

emissions. Approximately 70% of the total air (primary, 

The net effect of this technology is greater than 50% 

reduction in NOx 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 

7-42 Program Update 1993 Environmental Control Devices 

Project Objective: 

To demonstrate through the first commercial-scale full 

burner retrofit the cost-effective reduction of NOx from a 

large base-load coal-fired utility boiler with Low-NOx 

CellTM burner technology; and to achieve at least a 50% 

NOx reduction without degradation of boiler performance 

at less cost than conventional low-NOx burners. 

secondary, and excess air) is supplied through or around 

the coal-feed nozzle. Tbe remainder of the air is directed 

to the upper port of each cell to complete the combustion 

process. The fuel-bound nitrogen compounds we converted to nitrogen gas, and the reduced flame temperature minimizes the formation of thermal NOx. 
,,,..................,..,......,.,........................I....

Electric Company and the Columbus Southern Power 

Company. The boiler unit is a Babcock & Wtlcox-designed, supercritical, once-through boiler equipped with 

a” electrostatic precipitator. This unit contained 24 

two-nozzle cell burners arranged in a” opposed-firing 

configuration. Twelve 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 Low-NO% CellTM burners were 

installed. Alternate Low-NOx CellTM burners on the 

bottom rows were inverted, with the air port then being 

on the bottom to insure complete combustion in the 

lower furnace. 

Project Results/Accomplishments: 

The initial test results on the LNCBTM were disappointing. Reducing gases containing high concentrations of 

carbon monoxide and hydrogen sulfide accumulated in 

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

modelling several possible burner configurations, 

Babcock & Wilcox was able to select a” optimum new 

burner arrangement. On the lower row of burners, alternate LNC? burners were inverted so that the air ports 

integral to these burners directed air into the lower fur- 

“ace. Also, a design change for the burners’ coal impellers increased the NOx reduction to above the design 

goal. 

The LNt?bumer demonstration empbasized 

evaluation of boiler performance, boiler life, and environmental impact. Key boiler performance parameters 

included boiler output (steam temperatures); flue gas 

temperatures at the 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,S concentrations in the furnace, ultrasonic testing of lower 

furnace tube walls, and destructive examination of a 

Environmntnl Conrrol Devices 

corrosion test panel. Environmentally, NOx, CO, CO,, 

total hydrocarbons, and particulate matter were measured 

at varying test conditions. 

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

average NOx emissions were 0.53 lb/million Btu, a 

54.4% reduction from the baseline. CO emissions 

ranged from 28 to 55 ppm. Flyash unburned carbon 

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

air flow distribution achieved by the LNC” burner retrofit. At reduced loads of 460 MWe and 350 MWe, the 

NOc 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 a” 

S-month test period that followed the parametric and 

optimization test periods. 0” days when the boiler was 

operating at 590 MWe or above, and with all mills in 

service, NOx emissions averaged 0.49 lb/million Btu, a 

58% reduction from baseline emissions. This data set 

covered 79 days. 

Overall unit efficiency remained essentially “nchanged from baseline to optimized,LNCTM 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 boiler 

efficiency slightly. 

A corrosion test panel was installed when the 

LNCTM burners were installed. The panel consisted of 

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

aluminized, some stainless weld overlaid, and some 

cbromized. This level of corrosion is roughly equivalent 

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

materials had no loss. 

Commercial Applications: 

Currently there are 34 operating cell-burner-freed boilers 

for which the LNCBTMsystem is applicable. Of these 

boilers, 29 are opposed-wall-fned with two rows of hvonozzle cells. The average size is 766 MWe. 

The low c”st and short outage time for retrofit make 

the LNCBTMdesign attractive. Typically, the retrofit 

capital-cost will be $5.5CGS.OO/kW in 1993 dollars, 

based up”” DOE’s 500.MWe reference unit. The outage 

time can be as short as 5 weeks because of the “plug-i”” 

design. The LNCBTM system can be installed at about 

half the cost and outage time for other commercial lowNO% burner installations. 

Project Schedule: 

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

Cooperative agreement awarded 10/l II90 

NEPA process completed (MTF) S/IO/90 

Environmental monitoring plan completed S/9/9 I 

Construction 9/91-11/91 

Operational testing 12/914/93 

Project completed 12193 

Final Reports: 

Final Technical Report early 1994 

Economic Evaluation Report early 1994 

Public Design Report 819 1 

Program Update 1993 7.43 
Evaluation of Gas Reburning 

and Low-NO Burners on a 

Wall-Fired Bhler 

Sponsor: 

Energy and Environmental Research Corporation 

Additlonal Team Members: 

Public Service Company of Colorado<ofunder and 

host utility 

Gas Research Institutb-cofunder 

Colorado Interstate Gas Company--cofunder 

Electric Power Research Institute-xfunder 

Location: 

Denver, Adams County, CO (Public Service Company of 

Colorado’s Cherokee Station, Unit No. 3) 

Technology: 

Energy and Environmental Research Corporation’s gas 

rebuming and lawNOx burner (GR-LNB) system 

(environmental control devices/NOx control 

technologies) 

Plant Capacity/Production: 

172 MWe 

ProJect Funding: 

Total project cost 

DOE 

Participants 

$17,811,172 100% 

8,905,585 50 

8.905.587 50 

Project Objective: 

To attain up to a 70% decrease in the emissions of NOx 

from an existing wall-fxed utility boiler fuing low-sulfur 

coal using both gas rebuming and low-NOx burners. 

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

the furnace is ‘reburned” in this zone and converted to 

molecular nitrogen. Low-NOx burners positioned in the 

coal combustion zone retard the production of NO% by 

staging the burning process so that the coal-air mixture 

can be carefully controlled at each stage. The synergistic 

effect of adding a rebuming stage to wall-fued boilers 

equipped with low-NOx burners is projected to lower 

NO% emissions by 70% m more. Gas rebuming is being 

demonstrated with and without the use of recirculated 

flue gas. 

The project site is Public Service Company of 

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

CO. This project combines gas rebuming and low-NOx 

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

bituminous coals containing 0.35466% sulfur are 

being used in this demonstration. 

744 Program Update I993 Environmental Conrrol Devices 
r Cale”dXYea, 

1988 ,989 1990 1991 1992 1993 ,994 ,995 ,996 ,997 ,998 

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

1 z/99 10/90 10/92 6195 

Preoperatianal test5 initiated 6,Q2 Long-term operations started 5193 

Con*tr”ction completed m2 

Design completed 8191 

Ground breaki”giconstr”clion *taded 69, 

awarded 10113190 

EPA process completed (MTF) 9,6/90 

Environmental monitoring plan completed 7126190 

DOE selscfed project (CCT-III) 12/19/89 ‘Projected date 

Project Status/Accomplishments: rebuming without the use of recirculated flue gas will be 

Permitting activities have been completed. Construction demonstrated along with gas fling-gas rebuming. 

started in mid-1991 and was completed in June 1992, 

about 3 months ahead of schedule. Construction included the installation of new boiler penetrations, new 

burners, refractory, and insulation. All of the equipment 

that was installed during construction was checked out 

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

Public Service Company of Colorado rebuilt the four 

coal-pulverizing mills to enhance the flow of primary air 

to the boiler. Optimization of the gas-rebuming unit 

started in late-September and was followed by a brief 

outage in November for minor modifications to the tertiay air system. Parametric studies were started in October 1992 and were completed in April 1993. Preliminary 

analysis indicated NOx reductions of up to 70% at 

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

started in May 1993. Long-term operations will be 

completed in 1994. Pollowing long-term operations, gas 

Commercial Applications: 

Gas rebuming in combination with low-NO= burners is 

applicable to wall-fued utility and industrial boilers. The 

technology can be used in new andpre-NSPS wall-fired 

boilers. 

Specific features of this technology that increase its 

potential for commercialization are as follows: 

* Can be retrofitted to existing units 

. Reduces NOz emissions by 70% or more 

* Suitable for use with a wide range of coals 

* Has the potential to improve boiler operability 

. Has the potential to reduce the cost of electricity 

* Consists of commercially available components 

* Requires minimal space 

Current estimates indicate that about 35 existing 

wall-fired utility installations, plus industrial boilers, 

could make immediate use of this technology. The technology would apply to retrofit, repowering or to 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, 

01 less costly, than a scrubber, selective catalytic reduction, OI other technology approaches. GR-LNB functions equally well with any kind of coal. NO= emissions 

are reduced with internally staged low-NOx 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. 

Environmenrol Conrrol Devices Program Updae 1993 745 
Demonstration of Advanced 

Combustion Techniques for a 

Wall-Fired Boiler 

sponsor: 

Southern Company Services, Inc. 

Additional Team Members: 

Electric Power Research Institute-cofunder 

Foster Wheeler Energy Corporation-technology 

supplier 

Georgia Power Company-host utility 

Location: 

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

Plant Hammond, Unit No. 4) 

Technology: 

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

over-fire air (AOFA) (environmental control devicesiNOx 

control technologies) 

Plant Capacity/Production: 

500 MWe 

Project Funding: 

Total project c”st $14,710,909 100% 

DOE 6,553,526 45 

Participants 8,157,383 55 

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

Project Objective: 

To achieve 50% NO% reduction with the AOFA/LNB 

system; to determine the contributions of AOFA and the 

LNB to NO= reduction and the parameters determining 

optimum AOFA/LNB system performance; and to assess 

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

AOFALNB and advanced digital controls on NOxreduction and boiler performance. 

Technology/Project Description: 

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

with the furnace gases to achieve complete combustion, 

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

NOx formation, and (3) supplying air over furnace wall 

tube surfaces to prevent slagging and furnace corrosion. 

The AOFA technique is expected to reduce NO= emissions by about 35%. 

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

preclude the formation of NO=. This is accomplished by 

regulating the initial fuel-air mixture, velocities, and 

turbulence to create a fuel-rich flame core andhy controlling the rate at which additional air required to complete 

combustion is mixed with the flame solids and gases so 

as to maintain a deficiency of oxygen. Ty@al 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 NOI 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. The boiler is a 

nominal 500.MWe pulverized coal, wall-fned unit, 

which is representative of most of the existing pre-NSPS 

wall-fired utility boilers in the United States. The project 

also includes installation and testing of an advanced 

LNB digital control system that optimizes LNB/AOFA 

perfor”Ia”ce. 

7-46 Program Update 1993 Environmenral Control Devices 
reject conpletedfiinal report issued 4/95’ 

Operation completed LNBlAOFAwiti digital wntrol system 4/gS 

Operation initiated, LNWAOFA with digital control system Wg4 

Environmental n-nnitoring plan completed g/14190 

I 

Design completed 

Cooperative agreement awarded 1212X39 

‘Projected date 

have been completed. Analysis of more than 80 days of 

Project Status/Accomplishments: 

AOFA operating data has provided statistically reliable 

results indicating that, depending upon load, NOx reducBaseline, AOFA, LNB, and LNB/AOFA test segments 

tions 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 NOx level 

represents a 48% reduction when compared to the 

baseline, full-load value of 1.24 lb/million Btu. These 

reductions were sustainable over the long-term test period and were consistent over the entire load range. Fullload, flyash loss-on-ignition values in the LNB configuration were near 8%. compared to 5% for baseline. Initial results from the LNB/AOFA testing indicate that 

full-load NOx emissions are approximately 0.40 Ibimillion Btu with a corresponding flyash loss-on-ignition 

value of near 8%. Full-load, long-term NOz emission 

suggests that the incremental NOx reduction effectivereductions in the LNBIAOFA configuration are near 

ness of the AOFA system (beyond the use of the LNB) 

was approximately 17 percent with additional reductions 

resulting from other operational changes. On September 

67%. However, preliminary analysis of emissions data 

3, 1993, Hammond Unit 4 began a 9.month outage. 

Configuration of the digital control system and selection 

of the artificial intelligence software package for optimizing NOx reduction and boiler efficiency is continuing, 

and modification of the Hammond Unit 4 control room is 

now in progress. 

Commercial Applications: 

The technology is applicable, in the United States, for 

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

which bum a variety of coals, including bituminous, 

subbituminous, and lignite coal. 

Completion of the final analysis of project data and 

issuance of the final report are scheduled for December 

1995. 

Pre-retrofit LNB air toxics testing was performed to 

establish a baseline. Additional air taxics testing with 

the combined LNBIAOFA configuration has been completed. A report on this work was issued the end of 

December 1993. 

Commercialization of the technology will be aided 

by the following characteristics: 

* Reduced NO= emissions by as much as 65% 

* Competitive capital and operating costs 

* Relativelyeasyretrofit 

* Little or no derating of the boiler 

- Use of commercially available components 

- Automatic control of boiler efficiency and maximum 

pollution abatement through use of artificial intelligence technology in conjunction with digital control 

Environmenkd Conlrol Devices Program Update 1993 7.47 
180-MWe Demonstration of 

Advanced Tangentially Fired 

Combustion Techniques for 

the Reduction of NO, 

Emissions from Coal-Fired 

Boilers 

Pro/ta completed. 

sponsor: 

Southern Company Services, Inc. 

Additional Team Members: 

Gulf Power Company-cofunder and host utility 

Electric Power Research Institutuofunder 

ABB Combustion Engineering, Inc.-cofunder and 

technology supplier 

Location: 

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

Plant Laming Smith, Unit No. 2) 

Technology: 

ABB Combustion Engineering’s low-NOx concentric 

fling system (LNCFS) with advanced over-fire air 

(AOFA), clustered coal nozzles, and offset air 

(environmental control devices/NOx control 

technologies) 

Plant Capacity/Production: 

180 MWe 

Project Funding: 

Total project cost 

DOE 

Participants 

%9,153,383 100% 

4,440,184 49 

4.713.199 51 

L 

ProJect Objective: 

To demonstrate in a stepwise fashion the short- and longterm NOx reduction capabilities of low-NO% concentric 

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

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

lawNOx combustion technique. 

Technology/Project Description: 

Three different lawNOx combustion technologies for 

tangentially firedboilers were demonstrated. The concept of over-fire air was demonstrated in all of these 

systems. In LNCFS Level 2 a close-coupled over-fire air 

(CCOFA) system is integrated directly into the windbox 

of the boiler. Compared to the baseline windbox configuration, LNCFS Level I is arranged by exchanging the 

highest coal nozzle with an air nozzle immediately below 

it. This configuration provides the NOx reducing advantages of an over-fue air system without pressure part 

modifications to the boiler. 

In LNCFS Level II, a separated over-fxe air (SOFA) 

system is used. This advanced over-fire air system has 

backpressuring and flow measurement capabilities. The 

air supply ductwork for the SOFA is taken off from the 

secondary air duct and routed to the corners of the furnace above the existing windbox. The inlet pressure to 

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

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

air into the furnace. A multicell venturi is used to 

7.48 Program Update 1993 Environmnrol Conrrol Devices 
measure the amount of air through the SOFA system. 

LNCFS Level III utilizes both CCOFA and SOFA. 

In addition to over-fire air, the LNCFS incorporates 

other NOx reducing techniques into the combustion 

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

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

surrounded by a fuel-lean zone containing combustion 

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

varied using adjustable offset air nozzles. Separation of 

an 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 provide a 

stepwise reduction in NOx emissions, with LNCFS Level 

Ill expected to provide the greatest reduction. 

Project Results/Accomplishments: 

The LNCFS Level II tests were completed in September 

1991, resulting in a maximum NO= reduction of 40% at 

full load. The LNCFS Level II was converted to LNCFS 

Level III during a 2-week outage in November 1991 by 

installing close-couple over-fue air nozzles in the top of 

the main windbox. The LNCFS Level III testing, completed in April 1992, showed that NOxemissions were 

reduced by a maximum of 48%: however, this decrease 

in NOx emissions was accompanied by an increase in 

flyash carbon content. Finally, LNCFS Level I was 

evaluated by closing the separated over-fire air dampers 

of the Level Ill system. Testing of the Level I system, 

completed in December 1992, showed a maximum NO* 

reduction of 37% at full load. 

Testing to investigate the effects of low-NO= combustion on the emissions of air toxics was also completed. These tests showed that the LNCFS had little or 

no impact on the emissions of air toxics. A report has 

been prepared. 

Final Reports: 

Final Report and Key Project Findings 

Chemical Emissions Report (draft) 

Final Design Report 

12193 

10/93 

9193 

Commercial Applications: 

Commercial applications of this technology include a 

wide range of tangentially fired utility and industrial 

boilers throughout the United States and abroad There 

are nearly 600 U.S. pulverized coal tangentially fued 

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. LNCFS technologies can be 

used in retrofit as well as new boiler applications. Boiler 

operation with these in-furnace technologies does not 

require intensive retraining. 

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

based upon reducing NOxemissions from fossil-fuelfired power plants. Potential exists for annual NOxemission reductions of lo%, depending on the unit load scenario and the tangentially fired NOx control selected. 

Project Schedule: 

DOE selected project (CC?-III) 9128188 

Cooperative agreement awarded 9/20/90 

NEPA process completed (MTF) 7121189 

Environmental monitoring plan completed 12127190 

Construction 1 l/90-5/91 

Operational testing S/91-12/92 

Project completed 3i94 

Environmnrol Conrrol Devices Program Update 1993 7.49 
Demonstration of Selective 

Catalytic Reduction 

Technology for the Control 

of NO, Emissions from 

High-Sulfur-Coal-Fired Boilers 

Sponsor: 

Southern Company Services, Inc. 

Additional Team Members: 

Electric Power Research Institut~ofunder 

Ontario Hydro--cofunder 

Gulf Power Company-host utility 

Location: 

Pensacola, Escambia County, FL (Gulf Power 

Company’s Plant Crist) 

Technology: 

Selective catalytic reduction (SCR) (environmental 

control devices/NOx control technologies) 

Plant Capacity/Production: 

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

equivalent SCR reactor plants) 

Project Funding: 

Total project cost 

DOE 

Participants 

$23.229.729 100% 

9.406.673 40 

13,823,056 60 

Project Objective: 

To evaluate the performance of commercially available 

SCR catalysts when applied to operating conditions 

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

U.S. high-sulfur coal under various 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 vapor. 

In this demonstration project, the SCR facility consists of three 2.5.MWe-equivalent SCR reactors, supplied by separate 5,000 std f@/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 (three U.S., 

two European, and two Japanese) provided nine catalysts 

with various shapes and chemical compositions for 

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

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

loadings of flue gas, the applicability of SCR technology 

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

The demonstration plant, located at Gulf Power 

Company’s Plant Crist near Pensacola, FL, utilizes flue 

gas from the burning of principally Illinois No. 5 coal 

with approximately 3% sulfur under various NOx and 

particulate levels. 

7-50 Program Update I993 Environmenrol Conrrol Devices 
CalendarYear 

1988 ,989 ,990 ,991 1992 1993 ,994 IQ95 1996 ,997 1998 

3 4 1 2 3 4 1234 1 2341234 ,234 1 234 1 2341234 1234 ,2 

9199 6/90 7/93 l/96 

I 

NEPA process 

completed 

(km) *,1m9 

I 

Operation Mated T/93 L brojaa completedlfinal report ksued l/W 

Operation completed ,195’ 

Preoperational tesh initiated 3193 

Environmental monitoring plan completed 3/11/93 

DOE seleaed project I ’ (CCT-II) 9,28,88 

kmperative aQW"Te"t 

awarded 6H4190 k,“str”ction completed Z/93 

asign completed 12192 I 

Ground breakingiconsbuction started S/92 ‘Projected date 

Project Status/Accomplishments: 

Preliminary design engineering for the SCR test facility 

was concluded at the end of February 1991. Construction 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. Construction 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. 

Upon completion of the initial parametric testing in 

December 1993, baseline ammonia slip measurements 

were repeated These tests were completed during December and the results indicate all catalysts were performing well at the targeted NOx removal rates with slip 

less than 2 ppm under baseline conditions (80% Nor 

removal) and in many cases the measured slip was below the 1 ppm detection limit. 

Commercial Applications: 

SCR technology can be applied to existing and new 

utility applications for removal of NO% from flue gas for 

virtually any size bailer. There are approximately 

1,041 coal-fired utility boilers in active commercial 

service in the United States: these boilers represent a 

total generating capacity of 296,000 MWe. Assuming 

that SCR technology is installed on dry-bottom boilers 

that are not equipped with low-NOx combustion technologies (i.e., low-NO% burners, over-Fue air, and atmospheric fluid&d-bed combustion), the potential total 

retrofit market for SCR technology is 154,560 MWe 

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

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

(i.e., announced, sited. and committed in terms of service 

date or under construction) and 144,500 MWe (290 boilers) of planned dry-bottom electric generating capacity in 

the United States. 

Environmental Conrrol Devices Program Update 1993 7-51 
Micronized Coal Reburning 

Demonstration for NO 

Control on a 175MWeX 

Wall-Fired Unit 

Sponsor: 

TennesseeValley Authority 

Additional Team Members: 

Duke/Fluor Daniel (partnership between Duke 

Engineering & Services, Inc., and Fluor Daniel, 

Iuc.)~ngineer and cunstmctor 

Fuller Company-technology supplier 

Radian Corporation-testing/environmental/technical 

consultant 

Location: 

West Paducah, McCracken County, KY (Tennessee 

Valley Authority’s Shawnee Fossil Plant) 

Technology: 

Advanced NOx control using Fuller’s micronized-coalrebuming combustion technology (environmental control 

devicwNOxconuol technologies) 

Plant Capacity/Production: 

175 MWe 

Technology/Project Description: 

The technology is being applied to a 175.MWe frontwall-fired, dry-bottom furnace. The coal currently used 

to fire the furnace (low-sulfur bituminous coal from 

Kentucky or West Virginia) will be the rebuming fuel. 

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

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

injected into the furnace above the main burner, the 

region where NOx formation occurs. 

the existing bunker and supplies it to the new micmnized 

coal burners. 

Project Funding: 

Total project cost $7,330,041 100% 

DOE 3,5 14,755 48 

Participants 3,815,286 52 

Project Objective: 

To reduce NOr emissions by 50-60% using micronized 

coal as the reburning fuel combined with advanced coalreburning technology. 

Central to the project technology is the two-element 

system which consists of a patented centrifugal-pneumatic MicroMilF” and au external classifier. The mill is 

capable of grinding coal into a fine powder without the 

mechanical attrition or roll crushing normally associated 

with ooal mills. The MicroMill’” takes coal away from 

Micronized coal has the surface area and combustion characteristics of an atom&d oil flame, which allows carbon conversion within milhseconds and release 

of v&tiles 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 micronized 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. 

7.52 Program Update 1993 Environmenkzl Control Devices 
CalendarYear 

,991 ,992 1993 1994 1995 ,996 ,997 ,998 ,999 2000 2001 

3412341 234 1 234 1 234 1 234 1 234123412341234 12 

t A.$ 

I1 

T + 

Operation initiated 12194 

DOE selected Con*truction completed 10194’ t t 

Project completed: final report iesued 6/W 

yrot,(CCT-IV) Operation completed 7196 

Preaperation test.5 initiated 10/94’ 

Design completed 534 

Construction Started 594 

Environmental monitoring plan completed 3194 

NEPA process complet*d (Cxj 8113192 

&xperative agreement awarded 7128lQ2 

‘Projected date 

These options can prevent higher operating costs OI 

furnace performance denting often associated with conventional environmental controls. 

The Tennessee Valley Authority plans to retrofit its 

Shawnee Fossil Plant, located near West Paducah, KY, 

with the micronized-coal-rebuming technology. Bituminous coals from Kentucky and West Virginia, containing 

about 1% sulfur, will be used. 

Project Status/Accomplishments: 

Design efforts began shortly after the cooperative agreement was awarded in July 1992. Design and construction are expected to overlap for a short period, with construction being completed in mid-1994. The environmental monitoring plan is being prepared and is expected to be complete in early 1994. 

The Fuller Company purchased MicroFuel Corporation (the technology supplier) in September 1992 and 

assumed MicroFuel’s obligations to this project. Radian 

Corporation joined the team in August 1993. Radian 

replaced Research Cottrell which withdrew in early 

Enkmmntal Control Devices 

1993. Radian is responsible for modeling, testing, and 

NEPA compliance has been satisfied through a 

categorical exclusion approved on August 13, 1992. 

conceptual rebumer design. Boiler baseline and characterization testing started in November 1993. 

Commercial Applications: 

Micronised-coal-reburning technology can be applied to 

existing and greenfield cyclone-fried, wall-fired, and 

tangential-fired pulverized coal units. The technology 

reduces NOx emissions by 50-60% with minimal furnace modifications for existing units. For greenfield 

units, the technology can be designed as an integral part 

of the system. Either way, the technology enhances 

boiler performance with the improved burning characteristics of micronized coal. About 25% of the mwe than 

1,000 existing units could benefit from the use of this 

technology. 

creating avery economic source of generation. For both 

because of limited mill capacity would be able to reach 

retrofit and greenfield facilities, rebum burners also can 

save as low-load burners, and commercial units can 

their maximum continuous rating. NOx emissions 

achieve a turndown of 8:l on nights and weekends 

without consuming expensive auxiliary fuel. Existing 

pulverizers can be operated on a variety of coals with 

reductions will enable lost capacity to be restored, 

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

will increase overall pulverized-fuel surface area for 

better carbon burnout. 

The availability of a coal-rebuming fuel, as an 

additional fuel to the furnace, solves several problems 

concurrently. Existing units unable to switch fuels 

Program Updare I993 7.53 
IO-MW Demonstration of Gas 

Suspension Absorption 

Sponsor: 

AirPol, Inc. 

Additional Team Members: 

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

technology owner 

Tennessee Valley Autbority-xfunder and site owner 

Location: 

West Paducah, McCracken County, KY (Tennessee 

Valley Authority’s National Cater for Emissions 

Research) 

Technology: 

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

for flue gas desulfurization (FGD) (environmental 

control devices/SO,control technologies) 

Plant Capacity/Production: 

IO-MWe equivalent slipstream of flue gas from a 

150.MWe boiler 

Project Funding: 

Totalprojectcost 

DOE 

Participants 

$7,717,189 100% 

2,315,259 30 

5,401,930 70 

ProJect Objective: 

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

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

demonstration system. 

Technology/Project Description: 

The GSA system consists of a vertical reactor in which 

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

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

while the exit gas stream passes through an electrostatic 

precipitator before being released to the atmosphere. The 

lime slurry, prepared from hydrated lime, is injected 

through a spray nozzle at the bottom of the reactor. The 

GSA has the potential to remove in excess of 90% 

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

This project is located at the National Cater for 

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

the Tennessee Valley Authority’s Shawnee Fossil Plant 

in West Paducah, KY. A western Kentucky coal with 

about 3% sulfur is being used. 

volume of lime slurry is regulated with a variable-speed 

pump controlled by the measurement of the acid content 

in the inlet and outlet gas streams. The dilution water 

added to the lime slurry is controlled by on-line measuremats of the flue gas exit temperature. Solids collected 

from the cyclone and particulate control device are combined and disposed of in an existing site disposal area. 

Project Status/Accomplishments: 

Optimization testing was conducted February-August 

1993 to determine the effect of the process design variables on the SO, removal efficiency in the reactor/cyclone 

and the ESP. The test indicated that the order of importance of key variables is (1) calcium-to-sulfur ratio, 

7.54 Program Update I993 Environmenfal Control Devices 
CalendarYear 

1988 ,989 ,990 ,991 1992 1993 ,994 ,995 ,995 ,997 ,998 

3 4 1 2341234 1 *34,234 1234 1234 1 2341234, 234 12 

t 

DOE selected project 

(CCT-III) 12119189 

NEPA process completed (MTF) 9121Bd 

Cooperative agreement awarded ,01,,/90 

(2) approach-to-adiabatic-saturation temperature, and less than the comesponding costs for a limestone forced sinter plant. Sweden has stringent sulfur emission stan- 

(3) coal chloride content. oxidation system. dards which require a removal efficiency of 90-95%. 

The GSA system was found to be able to operate at 

an 8 “F approach-to-saturation temperature at the lowchloride condition without arty indication of plugging. 

This is an outstanding feature given the very low flue gas 

residence time in thereactorlcyclone. 

Air toxics testing was conducted during October 

1993. The results showed that a removal rate of over 

95% could be achieved by the GSA. A 4.week aroundthe-clock demonstration run was conducted in November 

1993. Results indicate that the GSA is capable of consistently maintaining 90+% SO,removal at a moderate 

lime requirement. The GSA has also demonstrated high 

availability. 

Commercial Applications: 

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

wet FGD and 20% cheaper than spray dtyinying; (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 the regenerable processes. This 

high removal rate makes the GSA process suitable for 

use with high-sulfur coal. 

An economic evaluation of the GSA process, conducted by Raytheon Engineers and Constructors, concluded that on the basis of a 300-MWe coal-fired boiler 

plant, capital costs were 31% and operating costs 20% 

TVA is evaluating the possibility of retrofitting a 

full-scale GSA unit for a 150.MWe coal-fired boiler. In 

addition, FLS 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 iron ore 

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 50-250-MWe utility 

plants. Simplicity in GSA design and operation plus 

modest space requirements make GSA ideal for retrofitting to existing plants as well as for greenfield plants. 

One major advantage of the GSA, as compared to other 

semi-dry scrubbing processes, is that operation of the 

GSA will not result in excessive dust loading to the gas 

stream, thus minimhing the cost for upgrading the existing dust collector. The potential market for the GSA is 

estimated at $300 million within the next 20 years. 

4 44 4 4 

I broje~3 wnpletedifinal report issued 8194’ 

bperation completed 1~34 

Operation initiated 10192 

Environmental monitoring plan completed ,WX!2 

Preoperational tests initiated 9192 

CO”Sb”ctio” coll@eted 9lQ2 

Ground brea~ngiconsuuction started 5/92 

,dgn com,hted ,219, 

‘Projected date 

Environmental Control Devices Program Updare I993 7-55 
Confined Zone Dispersion 

Flue Gas Desulfurization 

Demonstration 

Pro/ect completed. 

Sponsor: 

BechtelCorporation 

Additional Team Members: 

Pennsylvania Electric Company-cofunder and host 

utility 

PennsylvaniaEnergy Development Authority<ofunder 

New York State Electric & Gas Corporation-cofunder 

Rockwell Lime Company-zofunder 

Location: 

Seward, Indiana County, PA (Pennsylvania Electric 

Company’s Seward Station, Unit No. 5) 

Technology: 

Bechtel Corporation’s in-duct, confined zone dispersion 

flue gas desulfurization (CZD/FGD) process 

(environmental control devices/SO, control technologies) 

Plant Capacity/Production: 

73.5 MWe 

ProJect Funding: 

Totalprojectcost $10,411,600 100% 

DOE 5,205,800 50 

Participants 5,205,800 50 

Project Objective: 

To demonstrate SO,removal capabilities of in-duct 

CZD/FGD technology: specifically, to define the optimum process operating parameters and to determine 

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

7-56 ProgrmUpdate1993 

PULVERlZED COAL+ AIR --s 

BOILER 

L 

Technology/Project Description: 

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

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

the duct by spray nozzles designed to produce a cone of 

fine spray. As the spray moves downstream and expands, the gas within the cone cools and the SO, is rapidly absorbed in the liquid droplets. The droplets mix 

with the hot flue gas, and the water evaporates rapidly. 

Fast drying precludes wet particle buildup in the duct 

and aids the flue gas in carrying the dry reaction products 

and the unreacted lime to the ESP. 

The CZDIFGD process is expected to remove up to 

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

successfully demonstrated, this technology would be an 

alternative to conventional FGD processes, requiring less 

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

This project includes injection of different types of 

sorbents (dolomitic andcalcitic limes) with several atomher designs using low- and high-sulfur coals to verify 

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

to control particulates. The demonstration is located at 

Pennsylvania Electric Company’s Seward Station in 

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

147.MWe Unit No. 5 is being routed through a modified, 

longer duct between the first and second ESP. Pennsylvania bituminous coal (approximately 1.2-2.5% sulfur) 

is being used in the project. 

Environmnral Conrrol Devices 
Project Results/Accomplishments: 

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

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

the test program consisted primarily of parametric testing. The second pat was supposed to include a 6.month 

continuous operation test period with the system being 

operated under fully automatic control by the host utility 

boiler operators. Initially, the new atomizing nozzles 

were thoroughly tested both outside and inside the duct. 

The lime slurry injection parametric test program, which 

began in October 1991, was completed in August 1992. 

In summary, the demonstration showed the 

following: 

Bechtel notified DOE on June 30. 1993, that it was 

discontinuing the demonstration project effective July 1, 

1993. Bechtel is in the process of modifying the CZD 

process design to improve SO, removal during continuous operation. Once the CZD process modifications are 

made, a follow-on period of continuous boiler-integrated 

operation will be required Bechtel is pursuing this 

follow-on work with the host utility, the Pennsylvania 

Electric Company. 

Final Reports: 

Final Technical Report 

Public Design Report 

early 1994 

early 1994 

Bechtel is continuing efforts to submit and tinalire 

all reports required under the cooperative agreement. 

Commercial Applications: 

* CZD/FGD can achieve 50% SO, removal efficiency. 

* The process requires that drying and SO1 absorption 

take place within 2 seconds. A long, straight (horizontal or vertical) gas duct of about 100 feet is required to assure residence time of 2 seconds. 

If successful, CZD can be used for retrofit of existing and 

installation in new utility boiler flue gas facilities to 

remove SO, derived from a wide variety of sulfur-containing coals. 

. During normal operations, no deposits of fly ash ot 

reaction products took place in the flue gas duct. 

* The fully automated system, fully integrated with 

power plant operation, demonstrated that the 

CZD/FGD process responded well to automated 

control operation. 

* Availability of the system was vety good. 

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

A CZD system can be added to a utility boiler with 

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

capacity, or approximately one-fourth the cost of building 

a conventional wet scrubber. In addition to low capital 

cost, other advantages include small space requirements, 

ease of retrofit, low energy requirements, fully automated 

operation, and production of only nontoxic, disposable 

waste. The CZD technology is particularly well suited 

for retrofitting existing boilers, independent of type, age, 

or size. The CZD installation does not require major 

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

* Results of the demonstration indicated that the 

CZDIFGD process can achieve costs of $3UOlton of 

SO, removed when operating a SOO-MWe unit burning 4% sulfur coal. Based on a 500.MWe plant IetIofitted with CZD/FGD for a 50% Iate of SO, removal, 

the total capital cost is estimated to be less than 

$3O/kW. 

Project Schedule: 

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

Cooperative agreement awarded 10/13/90 

NEPA process completed (MTF) 9125190 

Environmental monitoring plan completed 6112191 

Construction 3191-6191 

Operational testing l/91-6/93 

Project completed 3194 

Environmnral Conlrol Devices Progrmn Update I993 7.57 
LIFAC Sorbent Injection 

Desulfurization 

Demonstration Project 

Sponsor: 

LIFAC-North America (a joint venture partnership between Tampella Power Corporation and ICP Kaiser 

Engineers, Inc.) 

Additional Team Members: 

ICF Kaiser Engineers, Inc.+ofunder and project 

manager 

Tampella Power Corporation-afunder 

Tampella, Ltd.--technology owner 

Richmond Power and Light--cofunder and host utility 

Electric Power Research Institute-cofunder 

Black Beauty Coal Company--cofunder 

State of Indiana--cofunder 

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 vertical activation reactor 

(environmental control devices/SO, control technologies) 

Plant Capacity/Production: 

60 MWe 

Project Funding: 

Total project cost $21,393,112 100% 

DOE 10,636,864 50 

Participants 10,756,908 50 

Project Objective: 

To demonstrate that electric power plants~specially 

those with space limitations--burning high-sulfur 

coals, can be retrofitted successfully with the LIFAC 

7.58 Program Updare 1993 

limestone injection process to remove 75-85% of the 

SO, from flue gas and produce a dry solid waste product 

for disposal in a landfill. 

Technology/Project Description: 

Pulvaized limestone is pneumatically blown into the 

upper part of the boiler near the superheater where it 

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

.1. limestone is calcined into calcium oxide and is available 

for capture of additional SO, downstream in the activation, or humidification, reactor. In the vertical chamber, 

water sprays initiate a series of chemical reactions leading to SO, capture. After leaving the chamber, the sorbent is easily separated from the flue gas along with the 

fly ash in the electrostatic precipitator. The sorbent 

material from the reactor and electrostatic precipitator 

will be recirculated back through the reactor for increased efficiency. The waste is dry, making it easier to 

handle than the wet scrubber sludge produced by conventional wet limestone scrubber systems. 

The technology enables power plants with space 

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

SO, from tlue gas and produces a dry solid waste product 

suitable for disposal in a landfill. 

The process is being demonstrated at the 

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

coal-fired unit is owned and operated by Richmond 

Power and Light and is located in Richmond, IN. 

Environmntol Control Devices 
CalendarYear 

1988 ,989 ,990 ,991 ,992 ,993 ,994 ,995 ,996 ,997 19sE 

3 4 1 234 1 23412341 234 1 2 3 4 1 2 3 4 f23412341234 12 

A 

** I] 

If 

tpemtion initiated 9192 

t 

t 

Prqxrational tests initiated 7192 Project mmpl*t*dni”al repolt issued 8/W 

Environmental monitoring plan cper.alio” corrQleted 594 

completed s/12,92 

Co”sb”ctio” completed 6192 

Original *sign completed 7191 

Ground breatdngko”s+mtio” *taned s/29/91 

Cooperative agreement awarded 1 t/20/90 

NEPA process conpleted (MTF, 10Ri90 

‘Projected date 

, 

DOE selected project (CCT-III) 12119189 

ProJect Status/Accomplishments: Commercial Applications: 

Operational testing began in September 1992 after 

baseline tests to characterize the 60.MWe unit were 

completed. Mechanical star-up and checkout were 

completed in February 1993. 

Parametric testing was initiated in March 1993: 

however, LIFAC operations increased opacity levels 

above acceptable limits, Tests conducted during May 

and June 1993 showed the increased opacity levels were 

due to reduced ash resistivity caused by lower operating 

temperatures in the ESP resulting from humidification of 

the flue gas in the activation reactor. Bypassing a portion 

of the flue gas maintains the ESP operating temperature 

above 200 “F, which results in acceptable opacity levels. 

Preliminary LILAC results show that SO, reductions in 

the boiler are between 20% and 30% and reductions 

through the reactor are an additional 4t-55%. yielding 

total SO, reductions approaching 80-85%. Parametric 

testing was completed at the end of December 1993. 

Optimization testing is scheduled to begin in 

February 1994. 

This process is suitable for application to all coal-fued 

utility or industrial boilers, especially those with tight 

space limitations. The LILAC process offers the following advantages: 

* It is less expensive to install than conventional wet 

flue gas desulfurization processes. 

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

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

LIFAC sales are projected to total 18,000 MWe of capacity over the next decade. 

. It uses dry limestone instead of more costly lime. 

* It is relatively simple to operate. 

* It produces a dry, readily disposable waste. 

. It can handle all types of coal. 

The benign waste material can be disposed of in a 

landfill along with the fly ash. The material also may 

be used as a road bed or excavation fill material. 

Commercial use of the LILAC by-product in the manufacture of construction materials is currently being investigated in Finland. 

Enviromenfal Conrrol Devices Program Updare 1993 7.59 
Advanced Flue Gas 

Desulfurization 

Demonstration Project 

Sponsor: 

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

Air which is a general partnership between Air Products 

and Chemicals, Inc., and Mitsubishi Heavy Industries 

America, Inc.) 

Additonal Team Members: 

Northern Indiana Public Service Company-cofunder 

and host utility 

Mitsubishi Heavy Industries, Ltd.--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) 

Technology: 

Pure Air’s advanced flue gas desulfurization (AFGD) 

process (environmental control devices/SO, control 

technologies) 

Plant Capacity/Production: 

528 MWe 

Project Funding: 

Total project cost $151,707,898 100% 

DOE 63,913,200 42 

Participants 87,794,698 58 

Powcrchip is amdemark ofPure Air al the Lake, L.P. 

7.60 Program Update 1993 

L 

Project 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. 

Technology/Project Description: 

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

for a 528.MWe power plant. Although this is the largest 

capacity absorber module in the United States, it has 

relatively modest space requirements because no spare or 

backup absorber modules are required The absorber 

performs three functions in a single vessel: prequencher, 

absorber, and oxidation of sludge to gypsum. Addifionally, the absorber is of a cocurrent design, in which the 

flue gas and scrubbing slurry move in the same direction 

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

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

less expensive than conventional scrubbers. 

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

an air rotary sparger located within the base of the absorber, and a novel w&water evaporation system. The 

air rotary sparger combines the functions of agitation and 

air distribution into one piece of equipment to facilitate 

the oxidation of calcium sulfite to gypsum. 

The AFGD process has demonstrated simultaneous 

removal of 90-95% or more of the SO, while providing a 

commercial gypsum by-product in lieu of solid waste. 

Some of the by-product gypsum will be agglomerated 

and flaked into PowerChipT” gypsum to enhance its 

Environmenral Conrrol Devices 

- 
C&“dWYW, 

1988 1989 ,990 199, 1992 1993 ,994 ,995 ,996 1997 ,998 

3 4 1 23412341 234 1 23412341 234 1 2 3 4 1 2341234 12 

Project completedifinal report issued 9195’ 

I 

DOE selected project 

(XT-II) 9128188 

I 

Operation initiated 6192 

Preoperational tests initiated 3192 

nvironmental nwnitoring plan completed 1131191 

NEPA process completed (EA) 4116190 

Ground breahngimnstructio” started 4120190 

‘Projected date 

transportation and marketability to gypsum end-users. 

Additionally, wastewater treatment will be demonstrated 

to minimize water disposal problems inherent with many 

high-chloride coals. 

The project also seeks to demonstrate a novel business concept whereby Pure Air owns and operates the 

AFGD facility. Thus, Pure Air expects to specialize in 

pollution control activities, relieving the electric utility of 

the operation of the AFGD unit. Assuming that the 

3.year demonstration is successful, Pure Air will continue to own the AFGD facility and to operate it as a 

contracted service to the utility for an additional 17.year 

period. The demonstration is located at Northern Indiana 

Public Service Company’s 528.MWe Bailly Generating 

Station near Chesterton, IN. 

Project Status/Accomplishments: 

Design is complete. To confirm process design, pilot 

testing was performed in 1990, successfully meeting 

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

high-sulfur coal and limestone feedstocks. A long-term 

Environmental Control Devices 

performance test was conducted in 1991 to verify operational parameters for the air rotary sparger; it, to”, was 

s”ccessf”l. 

Construction was completed ahead of schedule, 

despite the “ccurrence of a ground subsidence event at 

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

began operations in June 1992. Operations to date have 

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

average by-product gypsum purities of 96-97% have 

been achieved. Tests on the utility’s standard coal 

(3-3.5% sulfur) were completed in 1992. 

The AFGD process is attractive for both new and retrofit 

utility applications. The demonstration project is using 

Commercial Applications: 

bituminous coals primarily from the Indiana-Illinois coal 

basin, with sulfur content ranging from 2.0% to 4.5%. 

During 1993, tests were conducted on coals with 

3.54% sulfur and 2.5-3% sulfur. Additionally, airtoxics measurements were taken by the Southern 

Reseach Institute as part of a separate project that is 

being sponsored by DOE’s Flue Gas Cleanup R&D 

Program. 

Operations will continue through 1994 with commencement of wastewater evaporation and PawerChipT” 

gypsum agglomeration. 

The AFGD facility will reduce SO, emissions at the 

Bailly Station by approximately 50,000 tonslyr. Further, 

the gypsum by-product and wastewater evaporation will 

demonstrate that SO, control can occur without increased 

solid waste or wastewater production. 

All this can be accomplished with costs (and space 

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

Progrm Update 1993 7-61 
Demonstration of Innovative 

Applications of Technology 

for the CT-121 FGD Process 

Sponsor: 

Southern Company Services, Inc. 

Additional Team Members: 

Georgia Power Company-host utility 

Electric Power Research Institute--cofunder 

Radian Corporation-environmental and analytical 

Ershigs, Inc.-fiberglass fabricator 

University of Georgia Research Foundationby-product utilizatinn studies 

Location: 

Newnan, Coweta County, GA (Georgia Power 

Company’s Plant Yates, Unit No. 1) 

Technology: 

Chiyoda Corporation’s Chiyoda Thoroughbred-121 

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

process (environmental control devices/SO, control 

technologies) 

Plant Capacity/Production: 

100 MWe 

Project Funding: 

Total project cost $44,388,886 100% 

DOE 21,728,169 49 

Participants 22,660,717 51 

Project Objective: 

To demonstrate the CT-121 flue gas desulfurization 

system, including several design innovations, at the 

100.MWe scale; more specifically, to demonstrate 90% 

SO, control at high reliability with and without 

simultaneous particulate control with possible additional 

reductions in operating costs. 

7-62 Program @dote 1993 

COAL L 

r AIR 

Technology/Project Description: 

The project is demonstrating the CT-121 FGD process, 

which uses a unique absorber design known as the jetbubbling reactor (JBR). 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. 

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 dewatered 

in a gypsum stack, which involves filling 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 process. 

The project is also evaluating process innovations to 

determine whether costs can be reduced further by using 

fiberglass-reinforced plastic (FRP) absorbers, eliminating flue gas reheat and spare absorber modules, and 

stacking gypsum to reduce waste management costs. 

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

A 2.5% sulfur coal is being used to demonstrate 

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

simultaneous particulate control. 

A gypsum washing/drying operation will be used to 

determine if the scrubber by-product will be usable in 

cement and wallboard manufacturing. 

Environmenlal Control Devices 
L 

Cd0"darYear 

,988 ,989 ,990 19% 1992 1993 ,994 ,995 1996 ,997 ,998 

3 4 1 234123412341 2 3 4 1234 1 234 1 2 3 4 12341234 12 

I I ’ Environmental monitoring I I bperation initiated 10192 

plan completed 1211&Q” Constr”ctio” completed I”/92 I I 

I 

Pro@A ConpMetinal 

report issued l/97’ 

I 

I 

I 

Design completed 9192 I 

Evaluation of gypsum-stacking 

NEPA process qmation started 8/W 

DOE selected project 

completed (EA) 8/10/90 I 

(Cc3II) w28B8 Ground breakingiConstr”Ction Operation completed ,195’ 

started 81’23/90 Preoperational tests initiated 5192 

Cwperative agreement awarded 4/2/90 

‘Projected dale 

Project Status/Accomplishments: 

Construction at Plant Yates was completed in October 

1992, and start-up activities began immediately afterward. Experience has been very good with almost no 

off-line time attributable to the scrubber. Cumulative 

availability and reliability are both 98%. Over 8,150 

hours of successful operations have been logged. 

At inlet SO, levels of about 2,000 ppm. the CT-121 

system removes more than 90% of the SO, at all loads 

and conditions at expected pH and pressure drop with 

100% limestone utilization. Initial testing of simultaneous particulate removal by the JBR shows over 90% 

removal following a fully energized ESP. Continuous 

emission monitors and the flow monitors were calibrated 

and certified in November 1992 and recertified in October 1993. 

The calcium sulfate produced has been placed in B 

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

found in the phosphate fertilizer industry. Preliminary 

obsenaions show no evidence of acidic “rain out” from 

Environmenral Control Devices 

the FRP scrubber chimney, indicating that the static 

aerodynamic internal modifications in the chimney el 

bow are working as expected. DOE-sponsored supplemental air toxics sampling was done in mid-1993; results will be available in 1994. Late in 1993, testing on 

an alternate limestone was conducted demonstrating the 

flexibility of the process. Early in 1994 a higher sulfur 

coal will be tested. The ESP will be de-energized in 

stages in 1994 for the last year of operation in order to 

evaluate the particulate removal capability of the 

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 for commercialization follow: (1) fiberglass construction can be used, eliminating theneed 

for rubber-lined carbon steel or costly alloys; (2) no spare. 

absorber is required because the system is at least 98% 

reliable: (3) reheating of the flue gas is not necessary; 

(4) both SO, 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 operating costs are the lowest for stateof-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 

(10) the system is not sensitive to the type of coal used or 

its sulfur content. 

Involvement of the Southern Company (which owns 

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

that has over 20,000 MWe of coal-fired generating capacity, is expected to enhance the confidence of other 

large, high-sulfur coal boiler users in the CT-121 process. This process will be applicable to 370,000 MWe 

of new and existing generating capacity by the year 

2010. A 90% reduction in SO, emissions from only the 

retrofit portion of this capacity represents over 

10,500,OOO tons&r of potential SO, control. 

Progrm Update 1993 7-63 
SNOXTM Flue Gas Cleaning 

Demonstration Project 

Sponsor: 

ABB Environmental Systems 

Additional Team Members: 

Ohio Coal Development Oftice-cofunder 

Ohio Edison Company+ofunder and host utility 

Haldor Topso.+patent ownerforprocess technology, 

catalysts, and WSA Tower 

Snamprogetti, U.S.A.+ofunder and process designer 

Location: 

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

Station, Unit No. 2) 

Technology: 

Haldor Topsoe’s SNOXM catalytic advanced flue gas 

cleanup system (environmental control devices/combined 

SOJNOx control technologies) 

Plant Capacity/Production: 

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

Project Funding: 

Total project cost 

DOE 

Participants 

$3 1,438,408 100% 

15,719,200 50 

15.719.208 50 

Project Objective: 

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

that SNOXM technology will catalytically remove 95% 

of SO, and mcxe than 90% of NO= from flue gas and 

produce a salable by-product of concentrated sulfuric 

acid. 

Technology/Project Description: 

In the SNOFM process, the stack gas leaving the boiler 

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

baghouse to minimize the cleaning frequency of the 

sulfuric acid catalyst in the downstream SO, converter. 

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

small quantities of ammonia in the first of two catalytic 

reactors where the NOe is converted to harmless nitrogen 

and water vapor. The SO, is oxidized to SO, in a second 

catalytic converter. The gas then passes through a novel 

glass-tube condenser which allows SO, to hydrolyze to 

concentrated sulfuric acid. 

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

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

NOK from flue gas and produce a salable sulfuric acid 

by-product. This is accomplished without using sorbents 

and without creating waste by-products. 

The demonstration unit is installed at Ohio Edison’s 

Niles Station in Niles, OH. The process is treating a 

35.MWe equivalent slipstream of flue gas from the 

108.MWe Unit No. 2 boiler that bums a 3.4% sulfur 

coal. The process steps are virtually the same as for a 

full-scale plant, and commercial-scale components are 

being used. 

7-64 Program Update I993 Environmenld Control Devices 
Dedication ceremony held 101,719, 

Environmental monitoring plan completed 10131/91 

awarded 12/20,89 Des@n completed 8191 

Construction started 1191 

I 

NEPA process ccmpleted (MTF) 1/31/90 ‘Projected date 

Project Status/Accomplishments: 

Construction was completed in December 1991, and 

operation commenced in March 1992. After 2 months of 

operation, test results met “I exceeded design objectives, 

as follows: 

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

* Nor removal-94% in tests (90% design) 

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

In addition, hazardous air pollutant monitoring was 

conducted. Removal efficiencies for hazardous air pollutant elements were determined for the SNOXTM 

baghouse and for the entire SNOXTM process. The results indicate that most elements had removal efficiencies that exceeded 99% for both cases. The substances 

measured include 5 major and 16 trace elements, such as 

mercury, chromium, cadmium, lead, selenium, arsenic, 

beryllium, and nickel. 

The system has operated more than 5,700 hours, 

producing approximately 3,800 tons of sulfuric acid, 

which was sold for industrial use. 

The host utility, Ohio Edison, has decided that the 

SNOX’” technology has performed so well during the 

CCT demonstration project that it will become a permanent part of the pollution control system at Niles Station. 

Consequently, money set aside for site restoration will be 

used to fund extended operations through December 

1994. 

Commercial Applications: 

The SNOXTM technology is applicable to all electric 

power plants and industrial/institutional boilers tiring 

coal, oil, “I gas. The high removal efficiency for NOr 

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

ash) enhances the marketability in urban and other areas 

where solid waste disposal issues are a significant impediment. 

Environn,enlal Control Devices Program Update 1993 7-65 
LIMB Demonstration Project 

Extension and Coolside 

Demonstration 

Pro/ect completed. 

sponsor: 

TheBabcock & Wilcox Company 

Additional Team Members: 

Ohio Coal Development Oftice--cofunder 

Consolidation Coal Company-cofunder and technology 

supplier 

Ohio Edison Company--host utility 

Location: 

Lorain, OH (Ohio Edison’s Edgewater Station) 

Technology: 

The Babcock Br W&ox Company’s limestone injection 

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

DRB-XCLTM1ow-NOx burners 

Consolidation Coal Company’s Coolside duct injection 

of lime sorbents 

(environmental control devices/combined SO,lNOx 

control technologies) 

Plant Capacity/Production: 

105 MWe 

Project Funding: 

Total project cost $19,404,940 100% 

DOE 7,597,026 39 

Participants 11,807,914 61 

Project Objective: 

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

LIMB process as a retrofit system for simultaneous 

control of NOx and SO, in the combustion process, 

and that LIMB can achieve up to 70% NO* and SO, 

7-66 Program Update 1993 

reductions; to test alternate sorb& and coal combinations, using the Coolside process, to demonstrate in-duct 

sorb& injection upstream of the humidifier and precipitator 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 ta maintain normal ESP operation and to enhance SO, removal. Combinations of three @stem bituminous coals (1.6%, 3.0%, and 3.8% sulfur) and four 

sorbents were tested. Other variables examined were 

stoichiomew, humidifier outlet temperature, and injection level. 

ln the Coolside process, dry sorbent is injected into 

the flue gas downstream of the air preheater, followed by 

flue gas humidification. Humidification enhances ESP 

performance and SO, absorption. SO, absorption is 

improved by dissolving NaOH or Na,CO, in the 

humidification water. The spent sorbent is collected with 

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

The same low-NO% burners (Babcock & Wilcox 

DRB-XCLTM lowNOx burners), which control NOx 

through staged combustion, were used in demonstrating 

both LIMB and Coolside technologies. 

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

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

Environmenrd Control Devices 
Project Results/Accomplishments: 

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

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

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

bituminous, 1.6%, 3.0%, and 3.8% sulfur). Tests were 

conducted under minimal humidification, defined as 

operation at a humidifier outlet temperature sufficient tn 

maintain ESP perfornxnce. That temperature was typically 250-275 OF. Tests were also conducted at a 20 -F 

approach to the adiabatic saturation temperature of the 

flue gas to enhance SO, removal of the LIMB system. 

Close-approach operation typically meant controlling the 

flue gas temperature at the humidifier outlet (ESP inlet) 

to about 145 OF, Other variables were stoichiometry and 

injection level. Highlights of reported test results follow: 

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

concentration in the flue gas, affected SO, removal 

efficiency-the higher the sulfur content, the greater 

the S0,remow.l for a given sorb& at a comparable 

stoichiometry. A 5-7% increase in removal occurred 

when switching to 3.8% from 1.6% sulfur coal and 

injecting at a stoichiometry of 2.0. 

* The highest sulfur removal efficiencies, without 

humidification to close approach, were attained using 

the ligno lime--hl% SO,removal was achieved 

while burning 3.8% sulfur coal. All sorbents tested 

were capable of removing SO, although calcium 

utilization of even finely pulverized limestone was not 

nearly as high as those of the limes. 

* While injecting commercial limestone with 80% of 

the particles less than 44 microns in size, removal 

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

Environmnral Conrr01 Devices 

at a stoichiometry of 2.0 when using a limestone with 

all particles less than 44 microns. For a third limestone with essentially all particles less than 10 microns, the removal efficiency was about 5-7% higher 

than that obtained at similar conditions for limestone 

with all particles less than 44 microns. 

Sorbent injection at the 181.ft plant elevation level 

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

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

injected at close to the optimum furnace temperature 

of 2,300 OF. 

SO, removal efficiencies were enhanced by about 

10% over the range of stoichiometries tested when 

humidification down to a 20 ‘F approach to saturation 

was used. 

During the Coolside demonstration, compliance 

(1.2-1.6% sulfur) andnoncompliance (3.0% sulfur) 

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

N&a, and approach to adiabatic saturation-were 

evaluated in short-term (63.hr) 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, N&a, 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 sorbent alone 

was 22% at 0.5 available Ca/S and 18 -F approach to 

adiabatic saturation. Observed SO, removal with simultanenus recycle and fresh sorbent feed was 40% at 0.8 

fresh Ca/S, 0.2 fresh N&a, 0.5 available recycle, and 

18 -F approach to adiabatic saturation. 

NOx removal was in the 40-50% range throughout 

both LIMB and Coolside testing. 

Commercial Applications: 

Both LIMB and Coolside technologies are applicable to 

mnst utility and industrial coal-tired units and provide 

alternatives to conventional wet flue gas desulfurization 

(FGD) processes. They can be retrofitted with modest 

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

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

can be economically competititive with FGD systems. 

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

capacity factor, LIMB can be cost competitive with conventional wet FGD up to 450 MWe and Coolside up to 

220 MWe. The environmental benefits for LIMB are 

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 and easily 

handled and contains unreacted lime that has potential 

commercial application. Both processes have the ability 

tn handle all coal types, especially low- to medium-sulfur 

coals. 

Project Schedule: 

DOE selected project (CCT-I) 7/2@6 

Cooperative agreement awarded 6125187 

NEPA process completed (MTF) 612187 

Environmental monitoring plan completed 10/19/88 

Construction S/87-9/89 

Coolside operational testing 7/89-Z/90 

LIMB extension operational testing 4190-8191 

Project completed 11192 

Final Reports: 

Final Report (LlMB/Coolside) 11192 

Topical Report (Coolside) 2192 

Topical Report (L&lB/Coolside) 9190 

Public Design Report 12188 

Progrm Update 1993 7.67 
SOx-NOx-Rox-BoxTM Flue Gas 

Cleanup Demonstration 

Project 

Project completed. 

Sponsor: 

The B&cock & Wilcox Company 

Additional Team Members: 

Ohio Edison Company+ofunder and host utility 

Ohio Coal Development Oftic~ofunder 

Electric Power Research Institutuofunder 

Norton Company-zofunder and SCR catalyst supplier 

3M Company-zofunder and filter bag supplier 

Owens Coming Fiberglas Corporation-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 & Wtlcox Company’s SOx-NOx-RoxBox” (SNRBTM) process (environmental control devices/combined SO,lNOx control technologies) 

Plant Capacity/Production: 

5-MWe equivalent slipstream from a 156.MWe boiler 

Project Funding: 

Total project cost $13,271,620 100% 

DOE 6,078,402 46 

Participants 7,193,218 54 

Project Objective: 

To demonstrate that the SNRBrM process, used in retrofitting a high-sulfur-coal-fired power plant, can remove 

high levels of all three pollutants using B single processSOx-Nti-Rex-*ox and SNRB are UadcmarkS of The Babccck & 

Wilcox cmpny. 

7-68 Program Update 1993 

COALAIR -, 

EKITTOM 

ASH 

ing unit for treating flue gas, thereby lessening on-site 

space requirements and capital costs. 

Technology/Project Description: 

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

and particulates in one unit-a high-temperature 

baghouse. SO, removal is accomplished using either 

calcium- or sodium-based sorbent injected into the flue 

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

removal is accomplished by high-temperature fiber bag 

filters. 

The 5.MWe SNRBTM demonstration unit is large 

enough to demonstrate commercial-scale components 

while minimizing the demonstration cost. Operation at 

this scale also permitted cost-effective control of the flue 

gas temperature which allowed for evaluation of performance over a wide range of sorbent injection and 

baghouse operating temperatures. Thus several different 

arrangements for potential commercial installations 

could be simulated. 

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

removal, above 90% NO” 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 Bottom, OH. 

Bituminous coal with an average sulfur content of 3.4% 

was burned at this site during the demonstration. 

En~hmmental Conrrol Devices 
Project Schedule: 

DOE selected project (UT-10 

NEPA process completed (MTF) 

Cooperative agreement awarded 

Construction 

Environmental monitoring plan completed 

Operational testing 

Project completed 

Final Reports: 

Final Technical Report 

Economic Evaluation Report 

Detailed Design Report 

Project Status/Accomplishments: 

SNRB” demonstration tests were conducted for emissions control of SO,, NO, and particulates. Four different sorbents were tested for SO, capture. Calcium-based 

sorbents included commercial-grade hydrated lime, sugar 

hydrated lime, and lignosulfonate hydrated lime. In 

addition, sodium bicarbonate was tested. The optimum 

location for injecting the sorbent into the flue gas was 

immediately upstream of the baghouse. Effectively. the 

SO, was captured by the sorbent while the sorbent was 

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

fly ash). To capture Nor, ammonia was injected betweeu the sorbent injection point and the baghouse. The 

ammonia and NOx reacted to form nitrogen and water in 

the presence of Norton Company’s NC-300 series zeolite 

SCR catalyst. With the catalyst being located inside the 

filter bags, it was well protected from potential particulate erosion or fouling. The sorbent reaction products, 

unreacted lime, and fly ash were collected on the filter 

bags and thus removed from the flue gas. 

With commercial-grade lime, at a CaiS ratio of 2, 

and with the baghousc temperature between BOO and 

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

modified hydrated limes, at thz same operating temperature range, and with an NH,jNOx ratio of 0.9, thz 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 particulates. Particulate emissions 

averaged 0.018 lb/million Btu (0.009 grainsistd ft”), 

corresponding to a collecrion efficiency of 99.89%. 

High SO, removal efficiency was demonstrated in a 

brief test program with sodium bicarbonate injection. 

Removal efficiency increased from 80% to 98% and the 

ratio of NaJS was increased from 1:l to 2:l. 

All of the demonstration tests were conducted using 

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

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

En~ironmentd Control Devices 

carried out at air-to-cloth ratios of 3-4 ft/min. No excessive wear OI failures occurred in over 2,000 hours of 

elevated tempe~rature operation. 

A preliminary evaluation has been made of the 

projected capital cost of the SNRBTM system for various 

utility boilers. For a 250.MWe boiler fired with 3.5% 

sulfur coal and generating NO= emissions of 1.2 Ibs/ 

million Btu, the projected cost of a SNRB” system is 

approximately %26O/kW including various standard 

technology and project contingency factors. A combination of fabric filter, SCR, and wet scrubber for achieving 

comparable emissions control has been estimated at 

S360-4OOikW. 

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 

thermal efficiency. SNRBTM offers the potential for lower 

capital and operating costs and smaller space requirements than a combination of conventional, high-efficiency control technologies. SNRBT” is capable of reducing emissions from plants burning high- or lowsulfur coal. In retrofit applications, SNRB’” provides a 

means of improving particulate emissions control with 

the addition of SO, and NO= emissions control capacity. 

Commercialization of the technology is expected to 

develop with an initial larger scale application equivalent 

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

tailored to match the specific needs of potential industrial, utility, and independent power producers for both 

retrofit and new plant construction. SNRB” is a flexible 

technology which can be tailored to maximize control of 

SO,, NO., or combined emissions to meet current performance requirements while providing flexibility to address future needs. 

9128188 

9122f89 

1 mY89 

5/9 l-l 219 1 

12/31/91 

5192-5193 

3194 

early 1994 

early 1994 

1 l/92 

Program Updnre I993 7.69 
Enhancing the Use of Coals 

by Gas Reburning and 

Sorbent Injection 

sponsor: 

Energy and Environmental Research Corporation 

Additional Team Members: 

Gas Research Institute-cofunder 

State of Illinois, Department of Energy and Natural 

Resources+ofunder 

Illinois Power Company-host utility 

City Water, Light and Power-host utility 

Locations: 

Hennepin, Putnam County, IL (Illinois Power 

Company’s, Hennepin Plant) 

Springfield, Sangamon County, IL (City Water, Light 

and Power’s Lakeside Station) 

Technology: 

Energy and Environmental Research Corporation’s gas 

rebuming and sorbent injection process (environmental 

control devices/combined SO,/NOxcontrol technologies) 

Plant Capacity/Production: 

Hennepin: tangentially fired 80 MWe (nominal) 

Lakeside: cyclone-fired 40 MWe (nominal) 

ProJect Funding: 

Total project cost 

DOE 

Participants 

$37,497,816 100% 

l&747,816 50 

18,750,000 50 

Project Objective: 

To demonstrate gas reburning to attain 60% NOx reduction along with sorbentinjection to capture 50% of the 

SO, on two different boiler configurations: tangentially 

f&d and cyclone fired. 

L i 

BOTTOM ASH 

Technology/Project Description: 

Gas rebuming is a postcombustion technology that is 

being developed primarily for the removal of NOi In 

this process, 80-U% of the fuel is coal and is supplied 

to the main combustion zone. The remaining 15-20% of 

the fuel, generally natural gas or a hydrocarbon, bypasses 

the main combustion zone and is injected above the main 

burners to form a reducing zone in which NOx is converted to nitrogen. A calcium compound (sorbent) is 

injected in the form of dry, ftne particulates above the 

rebuming zone in the boiler 01 even further downstream. 

The calcium compound to be tested is Ca(OH), (lime). 

The process is expected to achieve 60% NO% reduction 

and 50% SO, reduction on different boiler configurations 

at power plants burning high-sulfur midwestem coal. 

This project will demonstrate the gas reburning and 

sorbent injection process on two separate boilers representing two different tiring configurations-a tangentially fired 80.MWe boiler at Illinois Power Company’s 

Hennepin Plant in Hennepin, IL, and a cyclone-fired 

40.MWe boiler at City Water, Light and Power’s 

Lakeside Station in Springfield, IL. Illinois bituminous 

coal containing 3% sulfur is the test coal for both 

Hennepin and Lakeside. 

7.70 Program Update 1993 Environmental Conrrol Devices 
CalendarYear 

,986 1987 ,988 ,989 ,990 1991 1992 1993 ,994 1995 1996 

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

Design and Con~truclion 

A A AA Y 

I I I kEPA II II 

I 

DOE selected &aopmtive process 

p~Yo~wr-I’ ww”’ COllQlded, 

Hennepin 

7/14/w (MTF) 519m 

Design mmpleted, both sites 5d 

Constructian started, Hennepin 5189 

NEPA ,,,oc=sss completed. Lakeside (EA) 6,25/89 

I ’ Hennepin 1193 

Const~ction wnpleted, Lakeside 592 

C0n9tru~Uon conpleted. Hennepin 891 Restoration oompleted, 

OperaUon Initiated. Hennepin 1t91 Hem+ 11193 

‘Projec,@d date 

Project Status/Accomplishments: 

Permitting and engineering design efforts were cornpleted for the three original project sites: however, in 

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

suspended. 

Operations at the Hennepin site began January 

1991. Long-term testing at Hennepin started in mid1991 aftex shakedown operations hadbeen completed. 

All testing, including testing with a promoted and a 

high-surface-ares lime, was completed in January 1993. 

During the course of testing, NOxreductions through gas 

reburning have ranged as high as 77%, 65% being routine, exceeding the project objective of 60%. Sorbent 

injection reduced SO, emissions as much as 62%, with 

52% reduction being routine, also exceeding the project 

objective of 50%. The calcium-to-sulfur ratio was about 

1.75:1. The system installed at Hennepin operated for 

more than 2,100 hours. 

Illinois Power, the host utility, has chosen to retain 

the gas-reburning portion of the gas-reburning and sorbent-injection system for potential use in NOx control at 

the Hennepin Plant. The sorbent injection portion has 

been removed and the site restored. 

At City Water, Light and Power’s Lakeside site. in 

Springfield IL. construction was essentially completed 

in May 1992, and the unit was temporarily placed on 

hold Some minor construction activities were completed between October 1992. Operation with sorbent 

injection began in May 1993 and with gas reburning in 

June 1993. Parametric testing began in July 1993. As at 

the Hennepin site, the Springfield site achieved NOxand 

SO, reductions better than the targets of 60% and 50% 

respectively. The long-term test program began November 15, 1993, under optimized conditions and will conclude in September 1994. 

The project schedule allows at least 12 months of 

gas-rebuming and sorknt-injection demonstration operation under normal load dispatch at Lakeside and 

demonstration of one or more alternate sorbents. 

Commercial Applications: 

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

applications for these technologies, both separately and 

combined, extend to both utility companies and industry 

in the United States and abroad In the United States 

alone, these two technologies can be applied to over 900 

pre-NSPS utility boilers; the technologies also canbe 

applied to new utility boilers. With NOx 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. The technologies are not sensitive to the 

type of coal used, regardless of its nitrogen or sulfur 

content. 

Environmmrnl Control Devices Program Update I993 7.71 
Milliken Clean Coal 

Technology Demonstration 

Project 

sponsor: 

New York State Electric & Gas Corporation 

Additional Team Members: 

Consolidation Coal Company-technical consultant 

Saarberg-HBlter-Umwelttechnik,GmbH-technology 

supplier 

The Stebbins Engineering and Manufacturing 

Company4ecbnology supplier 

NALCO Puel Tech-technology supplier 

Location: 

Laming, Tompkins County, NY (New York State ElecUic & Gas Corporation’s Milliken Station Units 1 and 2) 

Technology: 

Flue gas cleanup using Saaberg-HSlterUmwelttechnik’s (S-H-U) formic-acid-enhanced, wet 

limestone scrubber technology; NALCO Fuel Tech’s 

NOxOUT urea injection system; Stebbins’ tile-lined 

split-module absorber; and heat-pipe air-heater system 

(environmental control devices/combined SOJNOx 

control technologies) 

Plant Capacity/Production: 

300 MWe 

Project Funding: 

Total Project Cost $158,607,807 100% 

DOE 45,000,000 28 

Participant 113,607,807 72 

Project Objective: 

To demonstiate at a 300-MWe utility-scale a combination of cost-effective and innovative emission reduction 

and efficiency improvement technologies, including the 

7-72 Program Update 1993 

S-H-U wet scrubber system enhanced with formic acid to 

increase SO, removal in a Stebbins lined scrubber; urea 

injection for NOx removal; and a heat-pipe preheater. 

Technology/Ploject Description: 

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

formic-acid-enhanced, wet limestone process which 

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

gypsum. 

The NALCO Fuel Tech NOxOUT system removes 

NOx by the injection of urea into the boiler gas. This 

facet of the project, in conjunction with other combustion 

modifications, will reduce NOx emissions and produce 

marketable fly ash. 

The flue gas desulfurization absorber is a Stebbins 

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

design is constructed in the base of the stack to save 

space and provide operational flexibility. 

A heat-pipe air-heater system by ABB Air Preheater 

Inc. will be used with advanced temperature controls to 

reduce both air leakage and the air heater’s flue gas exit 

temperature. Ultimate emissions reductions with increased boiler efficiencies will result. 

The project is designed for “total environmental and 

energy management,“* concept encompassing low 

emissions. low energy consumption, improved combustion, upgraded boiler controls, and reduced solid waste. 

The system is being designed to achieve at least a 95% 

SO2 removal efkXency (or up to 98%) using limestone 

Environmenral Control Device! 
CalendarYear 

1591 ,992 ,993 ,994 1995 ,996 ,997 ,998 ,999 2000 2001 

3 4 1 2 3 4 1 2 3 4 ,234 1 2 3 4 ,234 1 2 3 4 1 2 3 4 12341234 12 

Lvironmmtal I 

monitoring Operation initiated 7/95* 

plan collqet4 

4194’ Precperational te*tfs initiated W85 

EPA process mnpleted (EA, Construction conpleted 5195’ 

8/l 8193 

r@ect mnpletedlminal repolt issued 6/w 

eratim cm~lete.d 5998’ 

tjround bmakin9,mnstruction sta,Wd 4/93 

Design completed 4,W 

booperative agreement awarded IO/20192 ‘Projected date 

L 

while burning high-sulfur coal. NOx reductions will be 

achieved using selective non-catalytic reduction technology and separate combustion modifications. The system 

has zero wastewater discharge and produces marketable 

by-products (e.g., commercial-grade gypsum, calcium 

chloride, and fly ash), minimizing solid waste. 

New York State Electric &Gas plans to demonstrate 

these technologies at Units 1 and 2 of its Mill&n Station located in Laming, NY: Pittsburgh, Freeport, and 

Kittaning coals, with sulfur contentS of 1.5%, 2.9%. and 

4.0%, will be used. 

Project Status/Accomplishments: 

The cooperative agreement was awarded on October 20, 1992. The NEPA process has been completed. 

The environmental assessment with a finding of no 

significant impact was signed August 18, 1993. The 

environmental monitoring plan was completed in December 1993. New York State completed its environmental review and issued permits in August 1992. 

i 

Construction is expected to continue through mid1995 and operations are scheduled through mid-1998. 

Hazardous air pollutant monitoring will be part of the 

test program. 

Commercial Applications: 

The S-H-U SO, removal process, the NALCO NOrOUT 

non-catalytic reduction process, Stebbins’ tile-lined splitmodule absorber, and heat-pipe air-heater technology are 

applicable to virtually all electric utility power plants. 

Commercialization of all technologies in both retrofit and 

greenfield applications of virtually any megawatt size is 

expected. The high removal efficiency, up to 98% for 

SO, and up to 30% beyond combustion modifications for 

NOx, will make the combination of these technologies 

attractive. 

limited on-site space. In addition, the inherent energy 

efficiency of the combined technologies minimizes any 

secondary environmental impacts from the operation of 

pollution control equipment 

The space-saving design features of the S-H-U, 

NALCO, Stebbins, and heat-pipe technologies, combined with the production of marketable by-products, 

offer significant incentives to generating stations with 

Environmenral Conrrol Devices Propm Updote I993 7.73 
Commercial Demonstration of 

the NOXSO SOJNO, Removal 

Flue Gas Cleanup System 

Cosponsors: 

NOXSO Corporation 

MK-Ferguson Company 

Additional Team Members: 

W.R. Grace and Company~ofunder 

Ohio Coal Development Officecofunder 

Gas Research Institut-ofunder 

Electric Power Research Institute--cofunder 

East Ohio Gas Company-+ofunder 

Location: 

Negotiations for a new site and host utility are under 

Way. 

Technology: 

NOXSO Corporation’s dry, regenerable flue gas cleanup 

process (environmental control devices/combined 

SO,/NOx control technologies) 

Plant Capacity/Production: 

100 MWe (typical) 

Project Funding: 

Total project cost $66,249,696 100% 

DOE 33,124,848 50 

Participants 33,124,848 50 

Project Objective: 

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

the NOx from a coal-tired boiler’s flue gas using the 

NOXSO process. 

Technology/Project Description: 

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

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

coals. In the basic process, the flue gas passes through a 

fluidized-bed adsorber located downstream of the precipitator: the SO, and NOx are adsorbed by the sorbent. 

The sorbent consists of spherical beads of high-surfacearea alumina impregnated with sodium carbonate. The 

cleaned flue gas then passes to the stack. 

The NOx is desorbed from the NOXSO sorbent 

when heated by a stream of hot air. The hot air containing the desorbed NOx is recycled to the boiler where 

equilibrium processes cause destruction of the NOx. The 

adsorbed sulfur is recovered from the sorbent in a regenerator where it reacts with methane at high temperature 

to produce an offgas with high concentrations of SO, and 

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

Claus plant to produce elemental sulfur, a salable 

by-product. 

The process is expected to achieve SO, reductions of 

97% and NO= reductions of 70%. 

The NOXSO process will be demonstrated on a 

typical 100.MWe cyclone boiler. Presently, NOXSO 

Corporation is negotiating with several potential host 

utilities for a new site for the demonstration project. 

MK-Ferguson will design, construct, and operate a fnllscale commercial NOXSO unit to demonstrate process 

feasibility. The project is being structured so that data 

from the proof-of-concept facility at Ohio Edison 

Company’s Toronto Station (now completed) can be 

incorporated into the project definition activity. 

7.74 Program Update 1993 Environmental Conrrol Devices 
CalendarYear 

1989 ,990 ,991 ,592 ,993 ,994 1995 ,996 1997 19% ,999 

3 4 1 234 1 2341234 1 2 3 4 1 2 3 4 ,234 1 2 3 4 1 2 3 4 ,234 12 

Cooperative agreement awarded 3/t list 

I 

DOE selected project (COT-III) 120 9/m 

1 1 bperalion inltiated 7/86’ 

1 brecqrationd tests inhhted w96’ 

COnSVUCson co”-Qleted 596 

onstruction started 6,W 

bedgn completed 5%’ 

NEPA process cmgeted (EA, 4lw 

Environrranlal monitoring plan completed 3/9S 

I Operation completed 

7lw 

‘Projected date 

Prolsct Status/Accomplishments: 

The proof-of-concept, pilot-plant testing, which was 

proceeding in parallel with the project definition phase of 

the demonstration project, is complete, with results as 

expected. Preliminary process flow diagrams, piping 

and instrumentation diagrams, equipment specifications, 

and plant arrangement drawings have been prepared. 

Power plant, site, and process-specific environmental 

information has been compiled for use in the NEPA 

process. 

Commercial-grade sulfur, a salable by-product, is 

produced The technology is expected to be especially 

attractive to utilities that require high removal effkienties for both SO, and NOx and/or need tn eliminate solid 

wastes. 

Commercial Applications: 

The NOXSO process is applicable for retrofit or new 

facilities. The process is suitable for utility and industrial coal-fired boilers of 75 MWe or larger. Southeastern 

Ohio and western Pennsylvania coal (3.2-3.5% sulfur 

average) are intended for use in the demonstration; however, the process is adaptable to coals with higher sulfur 

content. 

Enviromnentd Control Devices Program Update 1993 7.75 
Integrated Dry NOJSO, 

Emissions Control System 

Sponsor: 

Public Service Company of Colorado 

Additional Team Members: 

Electric Power Research Institut~ofunder 

Stone and Webster Engineering Corp.--engineer 

The Babcock & Wilcox Company-burner developer 

Fossil Energy Research Corporation-operational 

testing 

Western Research Instituthfiyash evaluator 

Colorado School of Mines-bench-scale engineering 

research and testing 

Noell, Inc.--urea-injection system provider 

Location: 

Denver, Denver County, CO (Public Service Company of 

Colorado’s Arapahoe Station, Unit No. 4) 

Technology: 

The Babcock & Wilcox Company’s low-NOx burners, induct sorbent injection, and furnace (urea) injection 

(environmental control devices/combined SO,lNOx 

control technologies) 

Plant Capacity/Production: 

100 MWe 

Project Funding: 

Total project cnst $27,411,462 100% 

DOE 13,705,731 50 

Participants 13,705,731 50 

Project Objective: 

To demonstrate the integration of three technologies to 

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

DRB-XCL is atrademark of mx Facd 8s wikox company. 

7-76 Program Update 1993 

more specifically, to assess the integration of a downtired low-NOx burner with in-furnace urea injection for 

additional NOx removal and dry sorbent in-duct injection 

with humidification for SO,removal. 

Technology/Project Description: 

All of the testing is using Batcock & Wilcox’s low-NOx 

DRB-XCL* down-fued burners with over-fire air. These 

burners control NOx by injecting the coal and the combustion air in an oxygen-deficient environment. Additional air is introduced via over-fne air ports to complete 

the combustion process and further enhance NOx removal. The low-NOx burners are expected to reduce NO= 

emissions by up tn 50%. and, with added air, by up tn 

70%. To reduce NOx emissions even further, in-furnace 

additional NO% can be removed from the combustion gas. 

urea injection is being tested to determine how much 

Two types of dry sorbents are being injected into the 

ductwork downstream of the boiler to reduce SO, emissions. Either calcium is injected upstream of the air 

heater or sodium or calcium is injected downstream of 

the air heater. Humidification downstream of the dq 

sorbent injection aids SO, capture and lowers flue gas 

temperature and gas flow, which can decrease pressure 

drop at the fabric filter dust collector. 

-1 

Low-sulfur (0.4%) bituminous coal from Colorado 

is the main fuel being tested, but for a run of short duration (less than 1 month), Illinois bituminous coal containing 2.5% sulfur is the planned test fuel. 

Environmenrd Conrrd Devices 

- 
CalendarYear 

,988 1989 ,990 ,991 1992 ,993 ,994 ,995 ,996 ,997 1998 

3412341 2 3 4 1234 1 23412341 234 1 2 3 4 12341234 12 

I~ 

t tt 

DOE selected projecl 

(CCT-III) 12l19/8g 

I 

Design initiated 6/90 

NEPA process completed (MTF) gl27W~ 

4 4t 4 

Environmental 

monitonng plan 

completed 

815193 I 

eratim inlfiated 8192 Prqled completedifinal report issued 1 l/94 

Construction conpleted 8192 operation completed 6194’ 

Preoperalional tests initiated 6192 

3esign mr@mJ 3,s 

Or ound breaking/construction started 5/21/91 

Cooperative agreement awarded 3,11191 ‘Projected date 

L 

The three basic technology systems have been installed on Public Service Company of Colorado’s Arapahoe Station Unit No. 4, a 100.MWe down-fired, pulverix&coal boiler with roof-mounted burners. 

Project Status/Accomplishments: 

Baseline testing of the boiler without any modifications 

was completed in mid-December 1991. Baseline testing 

of the boiler with urea injection began in early February 

1992 and continued for approximately 1 month. Construction requiring plant outage was completed in May 

1992, and then preoperational testing of the boiler with 

low-NOx burners and over-fire air began. Operational 

testing of these two key components started in early 

August 1992. 

Testing of the combustion modifications was completed in late October 1992. While firing western bituminous coal, NOx was reduced from an original baseline 

Environmenrol Control Devices F’ro~ram Update I993 

J 

of 1.15 lbslmillion Btu to about 0.4 lb/million Btu--a 

65% reduction-with no operating problems. Short-tam 

testing while fling natural gas was also completed. IIfurnace urea injection testing began in January 1993 and 

continued for 3 months. At full load, 44% NOx reduction 

was achieved with a 10.ppm ammonia slip. Duct sorbent-injection testing began in August 1993. PrelimiCommercial Applications: 

Either the entire integrated dry NOxlSO, emissions contml system or the individual technologies are applicable 

to most utility and industrial coal-fued units. They provide a lower capital-cost alternative to conventional wet 

flue gas desulfurization processes. They can be retmfitted with modest capital investment and downtime, and 

nary results with sodium injection indicate that over 70% their space requirements are substantially less. They can 

SO, removal can be obtained. Baseline and urea injec- be applied to any unit size but ale mostly applicable to 

tion air toxics monitoring has been performed. Prelimi- the older, small- to mid-size units. They can reduce NOx 

nary data indicate that the baghouse successfully re- emissions by up to 70% and SO, emissions by 50-70%. 

moves nearly all air toxics emissions. Aii toxics testing and they produce a dry solid waste product. These produring calcium and sodium injection was conducted cesses have the ability to handle all coal types, especially 

during October 1993. coals with low- to mid-sulfur content. 

Arapahoe 4 has operated over 12,000 hours since 

combustion modifications were completed in May 1992. 

The availability factor during this period was over 96%. 

7.77 
Coal Processing 

for Clean Fuels 

Fact Sheets 
Development of the Coal 

Quality Expert 

Cosponsors: 

ABB Combustion Engineering, Inc. 

CQ, Inc. 

Additional Team Members: 

Black and Veatch--cofunder and expert system 

developer 

Electric Power Research Institutecofunder 

The Babcock & Wilcox Company~ofunder and 

pilot-scale testing 

Guild Products, Inc.~xpert system architecture 

developer 

Electric Power Technologies, Inc.-field testing 

University of North Dakota, Energy and Minerals 

Research Center-bench-scale testing 

Alabama Power Company-host utility 

Mississippi Power Company-host utility 

New England Power Company-host utility 

Northern States Power Company-host utility 

Public Service of Oklahoma-host utility 

Locations: 

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

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

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

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

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

Somerset, Bristol County, MA (Brayton Point, Units 2 

and 3) 

Bayport, Washington County, MN (King Station) 

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

Technology: 

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

model (coal processing for clean fuels/coal preparation 

technologies) 

Plant Capacity/Production: 

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

Project Funding: 

Total project cost $21,746,004 100% 

DOE 10,863,911 50 

Participants 10,882,093 50 

Project Objective: 

To demonstrate an expert system that can be run on a 

personal computer and provide coal-burning utilities 

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

Technology/Project Description: 

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

are being used to develop algorithms for inclusion 

into a” expert model, the Coal Quality Expert, that can 

be run on a personal computer. Utilities may use the 

information to predict the operating performance and 

cost of coals not previously burned at a particular facility. 

Six large-scale field tests consist of burning a 

baseline coal and an alternate coal over a 2.month perind. The baseline coal, the one currently used as fuel, is 

used to characterize the operating performance of the 

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

improved quality, is burned in the boiler for the remaining test period. 

7.80 Program Updare 1993 Cod Processing for Clean Fuels 
CalendarYear 

1988 ,989 1wo ,991 ,592 ,993 1994 ,995 ,996 ,997 ,998 

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

t ttt t T 1 t 

Operation initiated 8&O Project conpletedfinal report issued 9,94’ 

monitoring plan completed 7/31/90 LItware d*“ekpme”t corrQl*ted 6,94’ 

(am, 12ms8 coop*,awe agreement awar*d 6/t 4190 Field testing completed 4193 

NEPA ~RICBSS conpleted (MTF) 4/27/90 

*Projected me 

The baseline and alternate coals for each test site 

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

similar conditions. The alternate coal is cleaned at CQ, 

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

produced economically and then transported to the 

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

bench-, pilot-, and full-scale facilities are evaluated and 

correlated to formulate algorithms being used to develop 

the model. 

Bench-scale testing will be performed at ABB Combustion Engineering’s facilities in Windsor, CT, and the 

University of North Dakota’s Energy and Mineral Research Cater in Grand Forks, ND, pilot-scale testing 

will be done at ABB Combustion Engineering’s facilities 

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

sites are: G&son, Unit 5 (88d MWe), Wilsonville, AL; 

Watson, Unit4 (250 MWe), Gulfport, MS; Brayton 

Point, Unit 2 (285 MWe) and Unit 3 (615 MWe), 

Somerset, MA, King Station (560 MWe), Bayport, MN; 

and Northeastern, Unit 4 (445 MWe), Oologah, OK. 

Cod Processing for Clean Fuels 

Projsct Status/Accomplishments: 

All six field tests have been completed. A commercial 

sale of the CQE Acid Rain Advisor software package 

was made in 1993. A CQE prototype was showcased in 

September 1993. A CQE beta version is scheduled for 

testing in March 1994. 

Commercial Applications: 

The expert system will enable coal-fired utilities to select 

the optimum quality coals at the lowest price for their 

specific boilers to reduce SO, and NOx emissions. 

The CQE system is applicable to all electric power 

plants and industrial/institutional boilers that bum coal. 

The system will predict the operational and emission 

reduction benefits of using cleaned coal. Following the 

demonstration, CQ, Inc., and Black and Veatch, will 

market the CQE system in the United States and abroad. 

Program Update 1993 7.81 
Self-Scrubbing Coal? An 

Integrated Approach to Clean 

Air 

Sponsor: 

Custom Coals International (a joint Venture between 

Genesis Coals Limited Partnership and Genesis Research 

Corporation) 

Additional Team Members: 

Duquesne Light Company-host utility 

Richmond Power&Light--host utility 

Cent&or Service Company-host utility 

CQ, Inc.--operator 

Locations: 

Central City, Somerset County, PA (advanced 

coalcleaning plant) 

Springdale, Allegheny County, PA (combustion tests at 

Duquesne Light Company’s Cheswick Power Station) 

Richmond. Wayne County, IN (combustion tests at 

Richmond Power & Light’s Whitewater Valley 

Station, Unit No. 2) 

Ashtabula, Trumbull County, OH (combustion tests at 

Cent&or Service Company’s Ashtabula C-Plant) 

Technology: 

Coal preparation using CustomCoals’ advanced physical 

coal cleaning and fine magnetite separation technology 

plus sorbent addition technology (coal processing for 

clean fuels/coal preparation technologies) 

Plant Capacity/Production: 

500 tons/br 

Project Funding: 

Total project cost $89,715,781 100% 

DOE 38,038,6X 42 

Participants 51,677,125 58 

sslf.3crubbing Cd end c.vcticc coal arc trademarLs of curtam coals 

rntcmarional. 

7.82 Program Update 1993 

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/Prolect Description: 

An advanced coal-cleaning plant will be designed, 

blending existing and new processes, to produce, from 

high-sulfur bituminous feedstocks, two types of compliance coals-Carefree C!oalTM and Self-Scrubbing Co@‘. 

Carefree CoalTM is produced by breaking and screening run-of-mine coal and by using innovative densemedia cyclones and finely sized magnetite to remove up 

to 90% of the pyritic sulfur and most of the ash. Carefree Coalrm is designed to be a competitively priced, 

high-Btu fuel that can be used without major plant modifications or additional capital expenditures. While many 

utilities can use Carefree CoalTM to comply with SO, 

emissions limits, others cannot due to the high content of 

organic sulfur in their coal feedstacks. When compliance coal cannot be produced by reducing pyritic sulfur, 

Self-Scrubbing CoalTM cm be produced to achieve 

compliance. 

Self-Scrubbing Coal”” is produced by taking Carefree CoalTM, with its reduced pyritic sulfur and ash content, and adding to it sorbents, promoters, and catalysts. 

Self-Scrubbing CoalTM 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 tbe 

Cod Processing for Clean Fuels 
CalendarYear 

l99l ,992 1993 1994 1995 19% 1997 1998 1999 2000 2001 

341234 1 234 1234 1 234 1 234 1 234 1 234 1 234 1 234 12 

9191 1 O/92 l/95 3/96 

t 

* 11 

Tt 

t-k---- 

Project wmpletedmnal report ks”ed WV 

operation completed ,196’ 

DOE selected 

;;xo,(CCT-IV) Operation initiated l/95’ 

Precprational test* initiated 12/94 

Construction completed ,2,94’ 

nvironmental manbring plan completed a/94’ 

NEPA ,xocess cm&ted (EA) Y94’ 

D&gign completed l/94’ 

Construction started 1194’ 

, 

Cwpemtive agreement awarded 1 O/29192 ‘Projected date 

ash specifications of the boiler 01 overloading the electrostatic precipitator. 

A 500.ton/hr advanced coal-cleaning plant is being 

designed and constructed at .s site near Central City, PA. 

The advanced coal-cleaning plant will manufacture SelfScrubbing CoalTM and Carefree Co@‘. Two medium- to 

high-sulfur coals-Illinois No. 5 from Wabash County, 

IL, and Lower Freeport Seam coal from Belmont County, 

OH-will be used to produce Self-Scrubbing Coalm. 

Carefree Co@’ will be made using Sewickley coal from 

Greene County, PA. The Sewickley coal will be combustion tested at Duquesne Light Company’s Cheswick 

Power Station located near Pittsburgh, PA; the Illinois 

No. 5 coal will be tested at Richmond Power & Light’s 

Whitewater Valley Station Unit No. 2 located in Richmond, W; and the Lower Freemont Seam coal will be 

tested at Centerior Service Company’s Ashtabula 

C-Plant. 

Project Status/Accomplishments: 

The cooperative agreement was awarded in October 

1992. Design work has started. Foundations were completed in January 1994. An environmental assessment 

has been prepared, and approval is expected in 

February 1994. 

Commercial Applications: 

Commercialization of Self-Scrubbing CoalTM has the 

potential of bringing into compliance about 164 million 

tonstyr of bituminous coal that cannot meet emissions 

limits through conventional coal cleaning. This represents over 38% of the bituminous coal burned in 

SO-MWe or larger U.S. generating stations. 

The technology produces coal products that can be 

used to reduce a utility or industrial power plant’s total 

sulfur emissions 80-90%. 

Coal Processing for Clean Fuels Program Updare 1993 7.83 
Advanced Coal Conversion 

Process Demonstration 

sponsor: 

Rosebud SynCoal Partnership (a partnership between 

Western Energy Company and the NRG Group, B 

nonregulated subsidiary of Northern States Power 

Company) 

Additional Team Member: 

Stone and Webster Engineering Corp.-architect/ 

engineer 

Location: 

Colstrip, Rosebud County, MT (adjacent to Western 

Energy Company’s Rosebud Mine) 

Technology: 

Western Energy Company’s advanced coal conversion 

process for upgrading low-rank subbituminous and 

lignite coals (clean processing for clean fuels/coal 

preparation technologies) 

Plant Capacity/Production: 

45 tons/hr of SynCoalTMproduct (300,000 tonsfyr) 

Project Funding: 

Total project cost %69,000,000 100% 

DOE 34,500,000 50 

Participants 34,500,000 50 

Project Objective: 

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

moisture content as low as l%, sulfur content as low as 

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

synccd is a tmdamrk ofthe Rorcbud syncoat Partnership. 

7.84 Program Update 1993 

Technology/Project Description: 

Being demonstrated is an advanced thermal coal-drying 

process coupled with physical cleaning techniques to 

upgrade high-moisture, low-rank coals to produce a highquality, low-sulfur fuel. The coal is processed through 

two fluidized-bed reactors that remwe loosely held water 

and then chemically bound water, carboxyl groups, and 

volatile sulfur compounds. After drying, the coal is put 

through a deep-bed stratitier cleaning process to effect 

separation of the ash. 

The technology, if successfully demonstrates enhances low-rank western coals, usually with a moisture 

content of 25-55%, sulfur content of 0.5-1.5%, and 

heating value of 5,500-9,000 Btu/lb, by producing a 

stable, upgraded SynCo@’ product with a moisture 

content as low as l%, sulfur content as low as 0.3%. and 

heating value up to 12,000 Btu/lb. 

The 45.ton/hr unit is located adjacent to a unit train 

loadout facility at Western Energy Company’s Rosebud 

coal mine in Colstrip, MT. Although the demonstration 

plant is one-tenth the size of a commercial facility, the 

process equipment is at commercial scale because a fullsized commercial plant has multiple process trains. 

Cod Processing for Clean Fuels 
CalendarYear 

1w ,999 ,990 1991 1992 1993 1994 1995 19% 1997 ,998 

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

12laa Q/90 6/92 3/96 

t 

I 

t 

f 

f 

Test operation initiated 6~92 ProjM 0x7-phdrnnd,epar( issued 393 

DOE selected project 

&CT-I) 1219/M 

nvimnmental monitoring plan wmpletad 4”92 Operation completed 595’ 

Consbuction completed 2/92 

CO~~rat~ree~; 1 ( 1 Preopsrationat tests in~t~atwd 12191 

I besign armpleted Q/91 

NEPA process completed (EA) M7.Ql 

Grwnd breakinglmmtruction stated 3,28191 

‘Projected date 

Project Status/Accomplishments: 

On December 12,1990, Western Energy Company, a 

subsidiary of Montana Power Company, announced that 

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

Minneapolis, MN, to demonstrate and commercialize 

this coal conversion technology. 

Ground was broken on March 28,1991. By June, 

pieces of major equipment were arriving on site. The 

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

all foundation work was completed by July. The main 

process facility structure and the control/administration 

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

operations began in March 1992. 

During the summer of 1993, the facility was shut 

down for extended maintenance and retrofit to the dust 

transport system. The plant resumed operation in August 1993 andreached 100% capacity on December 6, 

1993. SynCoalTM is being shipped by truck and rail to 

indusaial and utility customers for handling tests and 

short-term test burns. 

Commercial Applications: 

Western Energy’s advanced coal conversion process has 

the potential to enhance the use of low-rank western 

subbituminous and lignite coals. Many of the power 

plants located throughout the upper midwest have cyclone boilers, which burn low-ash-fusion-temperature 

coals. Presently, most of these plants bum Illinois Basin 

high-sulfur coal. SynCa@’ would be an ideal lowsulfur coal substitute for these and other plants, because 

it will allow 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 will produce 

SynCo@‘which has a very low sulfur content, high 

heating value, and stable physical/chemical characteristics; it could have significant impact on SO, reduction. 

Western Energy’s process, therefore, will be attractive to 

utilities because the upgraded fuel will be less costly to 

use than would the construction and use of flue gas 

desulfurization equipment. This will allow plants that 

would otherwise ix closed to remain in operation. 

On December 20, 1993, Rosebud SynCoal Partnership announced the signing of a letter of intent with 

Minnkota Power Cooperative to prepare a $2.million 

study to examine the merits of scaling up the coal processing technology to an $80.million commercial plant 

If results are positive a commercial plant could be in 

place by 1996. 

Coal Processing for Clean Fuels Progrm Update I993 7.85 
ENCOAL Mild Coal 

Gasification Project 

Sponsor: 

ENCOAL Corporation (a subsidiary of SMC Mining 

Company) 

Additional Team Members: 

SMC Mining Company-cofunder 

TBK-KOL (partnership between SMC Mining Company 

and SGI International)-technology owner, supplier, 

and licenser 

SGIInternational-technologydeveloper 

Triton Coal Company (subsidiary of SMC Mining 

Company&host facility and coal supplier 

The M.W. Kellogg Company--engineer and 

Location: 

Near Gillette, Campbell County, WY (T&on Coal 

Company’s Buckskin Mine) 

Technology: 

SGI International’s liquids from coal process (coal 

preparation for clean fuels/mild gasification) 

Plant Capacity/Production: 

1,000 tons/day of subbituminous coal feed 

Project Funding: 

Total project cost 

DOE 

Participants 

$72,564,000 100% 

36,X32,000 50 

36,282,OOO 50 

Project Oblective: 

To demonstrate the integrated operation of a number of 

novel processing steps to produce two higher value fuel 

forms from mild gasification of low-sulfur subbitumnous coal; and to provide sufficient products for potential 

end users to conduct bum tests. 

Technology/Project Description: 

coal. The solids from the dryer are conveyed to the pyr’olyzer where the rate of heating of the solids and residence 

The BNCOAL mild coal gasification process involves 

time are controlled to achieve desired properties of the 

fuel products. During processing in the pyrolyzer, all 

remaining free water is removed and a chemical reaction 

heating coal under carefully controlled conditions. 

occurs that results in the release of volatile gaseous 

Coal 

material. Solids exiting the pyralyzer are quenched, 

cooled, and transferred to a surge bin. 

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

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

solid bulk temperature is controlled so that no significant 

amounts of methane, CO, or CO, ale released from the 

The offgas from the dryer is treated in a wet venturi 

scrubber to remove particulates and a horizontal scrubber 

The gas produced in the pyrolyzer is sent through a 

to remove SO, both using a sodium carbonate solution. 

cyclone for removal of the particulates and then cooled 

The treated gas is vented to a stack, and the spent solution is discharged into a pond for evaporation. 

The ENCOALproject is located within Campbell 

County, WY, at Triton Coal Company’s Buckskin Mine, 

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

10 miles north of Gillette. 

from the condensation unit is recycled to the pyrolyzer. 

The plant makes use of the 

The rest of the gas is burned in combustors to provide 

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

controlled by staged air injection. 

7-86 ProgramUpdate Coal Processing for Clean Fuels 
Preawsrd 

Lperation inhiated 7i992 b ropct mn@etedifinal repon issued 9194’ 

o”str”ction completed 6192 operation con@etecl 9194’ IL nvironmental monitoring plan cnmplsted 5/29/92 

preoperational tests initiated 4192 

Design con-&ted T/91 

Ground breakingimnstruction started 10126190 

I 

!hoperative agreement awarded 9117f30 

LEPA ~~OOSSS ~~mpkaed (E.4) m30 

‘Projected date 

- 

present coal-handling facilities at the mine. Subbituminous coal having sulfur content of O&0.9% is being 

used. 

Project Status/Accomplishments: 

Operation continued during 1993. Fifteen runs have 

been conducted to date, logging more than 1,400 hours of 

operation. A major milestone was achieved in April 

1993 when the plant completed a 16.day run. The run 

confirmed that the plant had been able to overcome several mechanical problems that had previously prevented 

sustained operations beyond 7 days. During the run, 

more than 5,000 tons of low-rank Powder River Basin 

coal were processed, yielding more than 125,000 gallons 

of high-quality liquid fuel and several thousand tons of 

clean solid product. 

ENCOAL operators logged another milestone run in 

June 1993, this one 12 days in duration. The plant 

reached 100% of design capacity for a short period during the run, which ended in a planned shutdown. On 

Cod Processing for Clean Fuels 

June 15, the plant was shut down to enable a major 

The ENCOAL plant continued to attract a large 

number of international visitors, especially from Pacific 

Rim countries, interested in using the technology or in 

modification which incorporates a new step in the overall 

purchasing fuel products. Among these was the Indonesolids-cooling system to continuously produce a solid 

sian ambassador to the United States who visited the 

plant in June. On the domestic front, commercial conproduct sufficiently stable for long-distance shipping. 

tracts are in place for the fust customers of its products. 

A Wisconsin utility will buy 30,000 tons of the solid 

product and TEXPAR Energy Inc., of Waukesha, WI, 

Operations are expected to resume in January 1994. 

will buy up to 135,000 barrels of the liquid product. 

Further, ENCOAL announced in November an agreement with Dakota Gasification Company to bum up to 

250,000 barrels of product liquid at the Great Plains 

Synfuel Plant at Beulab, ND. 

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

Commercial Applications: 

The potential benefits of this mild gasification technology in its commercial configuration are attributable to 

The liquid products from mild coal gasification can be 

the increased heating value (about 12,000 Btwlb) .md 

lower sulfur content (per unit of fuel value) of the new 

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

solid-fuel product compared to the low-rank coal feedstock, and the production of low-sulfur liquid products 

requiring no further treatment for the fuel oil market. 

solid product can be used in most industrial or utility 

The product fuels are expected to be used economically 

boilers. The feedstock for mild gasification facilities is 

in commercial boilers and furnaces and ta reduce significantly SO, emissions at industrial and utility facilities 

currently burning high-sulfur bituminous coals or fuel 

oils. 

Progrm Update 1993 7-87 
Commercial-Scale 

Demonstration of the Liquidpwslethanol (LPMEOHTM) 

SpOllSOr: 

Air Products and Chemicals, Inc. 

Additional Team Members: 

Acurex Environmental Corporation-fuel methanol 

testing and cofunder 

Eastman Chemical Company-host site and cofunder 

Location: 

Kingsport, Sullivan County, TN (Eastman Chemical 

Company’s Integrated Coal Gasification Facility) 

Technology: 

Air Products and Chemicals’ liquid-phase methanol 

(LPMEOH”“) process (coal processing for clean fuels/ 

indirect liquefaction) 

Plant Capacity/Production: 

200 tons/day of methanol 

Project Funding: 

Totalprojectcost: $213,700,000 100% 

DOE 92,708,370 43 

Participants 120,991,630 57 

Project Objective: 

To demonstrate on a commercial scale the production of 

methanol fram coal-derived synthesis gas using the 

LPMEOHTM process; and to determine the suitability of 

methanol produced during this demonstration for use as 

a chemical feedstock or as a lowSOx, low-NO= altemative fuel in stationary and transportation applications. In 

addition, the production of dimethyl ether (DME) as a 

mixed coproduct with methanol will be demonstrated. 

LPMEOH is aV*mark of.& t+oductr ad cbcmicdr, Inc. 

7-88 Program Update 1993 

Technology/Project Description: * Methanol productivity comparable to gas-phase sysThis project is demonstrating the LPMEOHTM process to tems-6,oOO lbs of methanol per 1 lb of catalyst 

produce methanol from coal-derived synthesis gas on a 

commercial scale. The combined reactor and heat re- 

* Raw methanol purity-97.5% 

moval system is different from other commercial metha- . Feed gas flexibility-pa&s the synthesis gas pro- 

.I 

no1 processes. The liquid phase not only supports the 

catalyst but functions as an efficient means to remove the 

heat of reaction away from the catalyst surface. This 

feature permits the direct use of synthesis gas streams as 

feed to the reactor without the need for shift conversion. 

The performance of the LPMEOHTM process for the 

synthesis of methanol is chaacterized as follows: 

* Carbon monoxide conversion to methanol-13% per 

reactor per pass in a hydrogen-rich feed 

d”Cd by any cOmme*Clat coal gasltlcatlon system to 

be used without shift conversion 

The Eastman Chemical Company’s integrated coal 

gasification facility at Kingsport, TN, has operated commercially since 1983. At this site, it will be possible to 

ramp up and down to demonstrate the unique load-following flexibility of the LPMEOH”( unit for application 

to coal-based electric power generation facilities. Methanol fuel testing will be conducted in both on- and off-site 

stationay and mobile applications, such as boilers, 

Cod Processing for Clean Fuels 
CalendarYear 

,989 ,990 ,991 ,992 1993 1994 ,995 ,995 1997 ,998 1999 

341234123412341234123412341 23412341234 12 

1 z/69 10192 l/96 9/00 

I 

t 

A 

1’ 

I’ 

t 

DOE selected project (CCT-III) 12l19,*9 

Operation initiated 1/96 

Precperational tests initiated 12/W Operation completed *ml 

Consbuction completed 111995’ ! 

Project conpleted/final repon issued 9/W’ 

Design completed 6195 

nvimnmenlal monitoring plan completed 1195’ 

Con*buction started 12/94 

NEPA process mmpleted (EA, 12194 

cooperative *gr*emmt*war&3d 10,16/92 ‘Pmjected date 

Ibuses, and van pools. The operation at Kingsport also 

includes the planned production of DME as a mixed 

coproduct with methanol for demonstration as storable 

fuel. 

Commercial Applications: 

The LPMEOHTMprocess has been developed to enhance 

integrated gasification combined-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. Methanol can be substituted for conventional fuels 

in stationary and mobile combustion applications. 

Methanol is an excellent fuel for peak power production. 

Methanol contains no sulfur and has exceptionally lowNOx characteristics when burned. Methanol can be 

produced from coal as a co-product in an IGCC facility. 

DME has several commercial uses. I” B storable 

Project Status/Accomplishments: 

The cooperative agreement was modified in October 

1993 to recognize a change in the host site from the Cool 

Water Gasification Facility in Daggett, CA, to Eastman 

Chemical Company’s Integrated Coal Gasification Facility in Kingsport, TN. The host-site change became “ecessay when the project sponsors determined that restarting the mothballed Cool Water facility-a demonstration 

coal-gasification combined-cycle power plant-was not 

economically feasible. 

blend with methanol, the mixture can be used as peaking 

fuel in IGCC electric power generating facilities. DME 

con also be used to increase the vapor pressure of a 

methanol blend. The resulting higher volatility is expected to provide beneficial “cold start” properties to 

methanol being used as a diesel engine fuel. 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 a” environmentally friendly aerosol in personal 

products. 

The participants are initiating project definition 

activities and developing the relevant environmental 

information needed for the NEPA process. The Eastman 

Chemical site offers the advantage of using existing, 

operating coal gasifiers which will require little, if any, 

modification to support the LPMEOH” demonstration. 

Among the cleanest coal technologies for generating 

electric power, IGCC can economically satisfy the most 

stringent environmental limits for SO, and Nor. About 

99% of the sulfur can be removed in the manufacturing 

process and converted into salable elemental sulfur or 

sulfuric acid. The solid waste from the gas&r is an 

inert, granular slag which can be used as a” aggregate 

for road and building materials. 

Typical commercial-scale LPMEOHrM units are 

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

methanol produced when associated with commercial 

IGCC power generation trains of 200-350 MWe. Air 

Products and Chemicals expects t” market the 

LPMEOHrM technology through licensing, owning/ 

operating, and tolling arrangements. 

Coal Processing for Clean Fuels Program Update 1993 7-89 

- 
Industrial Applications 

Fact Sheets 
Blast Furnace GranulatedCoal Injection System 

Demonstration Project 

sponsor: 

Bethlehem Steel Corporation 

Additional Team Members: 

British Steel Consultants Overseas Services, Inc. 

(marketing arm of British Steel Corporation)- 

technology owner 

Simon-Macawlxr, Ltddquipment 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 Harbor Plant, Blast Furnace Units C and D) 

Technology: 

British Steel’s blast furnace granulated-coal injection 

(BFGCD process (industrial applications) 

Plant Capacity/Production: 

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

Project Funding: 

Total project cost $191,700,000 100% 

DOE 31,259,530 16 

Participants 160,440,470 84 

Prolect Objective: 

To demonstrate that existing iron-making blast furnaces 

can be retrofitted with blast furnace granulated-coal 

injection technology: and to demonstrate sustained 

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

nature of these parameters. 

Technology/Project Description: 

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

along with heated air is blown into the barrel-shaped 

In the BFGCI process, both granulated and pulverized 

section in the lower part of the blast furnace through 

passages called tuyeres, which cxates swept zones in the 

coal is injected into the blast furnace in place of natural 

furnace called raceways. The size of a raceway is important and is dependent upon many factors including ternperature. 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 OI oil, does not cause as severe a reduction in raceway temperatures. In addition to displacing injected 

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

replace up to 40% of the coke requirement, BFGCI technology has significant potential to reduce emissions and 

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

enhance blast furnace production. 

basis. Because coke production results in significant 

emissions of NO=, SO,, and air toxics and coal could 

Emissions generated by the blast furnace itself 

remain virtually unchanged by the injected coal; the gas 

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

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

salable by-product. In addition to the net emissions 

reduction realized by coke displacement, blast furnace 

production is increased by maintaining high raceway 

temperatures. 

7.92 Program Updofe I993 Industrial Applicariom 
I 

DOE selected 

yrrec3(~CT-III) 

12199 11/90 

Cde”dXY*W 

1968 1969 ,990 ,991 ,992 1993 ,994 19% ,995 1997 ,996 

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

kqmtive agreernmt awarded 1 l/26190 

Lperation inkiated 5% 

Preoperational tests initiated 3166 

Construction completed 3.M’ 

Environmental monitodng Plan compkac ttR4’ 

Design completed ,194 

‘Conat~clion started 9193 

IPA process completed (EA) 6,6/93 

Project conyrbted/final repori 

Issued I/96’ 

Operation completed ,196 

‘Pmjected date 

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

Bethlehem Steel Corporation’s Bums Harbor Plant, are 

being retrofitted with BFGCI technology. Each unit has 

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

The two units will use about 2,800 tons/day of coal 

during full operation. Bituminous coals with sulfur 

content ranging from 0.8% to 2.8% from West Virginia, 

Pennsylvania, Illinois, and Kentucky are to be used. A 

western subbituminous coal having 0.4-0.9% sulfur 

might he tested also. 

was initiated. By the end of the year, excavation work 

was completed, the pouring of foundations was well 

under way, and erection of structural steel was 

beginning. 

Project Status/Accomplishments: 

Bethlehem Steel has signed a turnkey contract with Fluor 

Daniel, Inc., of Greenville, SC, for the project’s engineering, procurement, and construction. Project design continued throughout the year and by December 1993 was 

approximately 90% complete. 

Facilities being constructed include those needed to 

prepare the coal, to deliver the prepared coal to the two 

blast furnaces, and to inject it into the furnaces. In addition, the blast furnaces will be modified to accept the 

prepared coal. The necessary modifications to furnace D 

will be made on-the-fly through a series of short outages 

on the operating furnace. Furnace C will be modified 

during a reline scheduled for third quarter 1994. 

An environmental assessment with a finding of no 

significant impact was approved in June 1993, completing the NEPA process. With receipt of a construction 

permit from the state of Indiana also in June, site work 

Commercial Applications: 

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

blast furnaces. The technology should be applicable to 

any rank coal commercially available in the United 

States. The environmental impacts of commercial application are primarily indirect and consist of a significant 

reduction of emissions resulting from diminished cokemaking requirements. 

Industrial Applicarions Program Update 1993 7.93 
Innovative Coke Oven Gas 

Cleaning System for Retrofit 

Applications 

Sponsor: 

Bethlehem Steel Corporation 

Additional Team Member: 

Still-Ott~technologydeveloper 

Location: 

Sparrows Point, Baltimore County, MD (Bethlehem 

Steel Corporation’s Sparrows Point Plant, Coke Oven 

Batteries A, 11, and 12) 

Technology: 

Still-Otto’s process for precombustion cleaning of coke 

oven gas (COG) (industrial applications) 

Plant Capacity/Production: 

74 million std ftYd/day of COG 

Project Funding: 

Total project cost 

DOE 

Participant 

$45,239,781 100% 

13,500,000 30 

31,739,781 70 

Project objective: 

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

commercially available process steps for simultaneous 

removal of hydrogen sulfide and ammonia from COG, 

recovery of hydrogen sulfide and ammonia, destruction 

of ammonia, and recovay of sulfur in a commercialsized application; and to reduce SO, emissions by at 

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

ammonia to wastewater treatment. 

Technology/Project Description: associated with the purchase and handling of feed re- 

‘This project is demonstrating an innovative technology 

developedby Still-Otto for removing hydrogen sulfide 

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

the hydrogen suliide and ammonia contained in the 

COG. Both hydrogen sulfide and ammonia are steam 

stripped from the absorption liquor. The ammonia is 

destroyed in a catalytic reactor: hydrogen sulfide is converted to elemental sulfur in a conventional Claus plant, 

and sulfur is recovered as a salable by-product. 

agents, the handling and treatment of by-products, labor, 

and utilities are reduced. 

This project involves the modification of the COG 

processing units at Bethlehem Steel’s Sparrows Point 

Plant in Baltimore County, MD. The demonstration 

facility is designed to process the entire COG stream 

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

to74 million std ft’/day. These coke men batteries have 

the capability to produce up to 1.2 million tons/yr of coke 

from a blend of Pennsylvania and Virginia coals having 

sulfur caents ranging from 0.8% to 1.37%. The raw 

COG has a hydrogen sulfide content of 175-340 grains/ 

100 ft’. Currently, only 60% of this COG stream is 

desulfuurized. The remaining 40% is used directly for 

fueling the fire under the coke ovens. 

The technology is expected to reduce the hydrogen 

sulfide concentration in the cleaned COG by 88% and 

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

7.94 Program LIpdare 1993 Industrial Application 
Cal*“da,Y*M 

,988 1989 19wl 1991 ,992 ,593 1994 ,995 1996 ,997 1998 

341234123412341 2 3 4 1234 1 2 3 4 12341 234,234 12 

9/89 1 l/89 7194 11/95 

t 

AAA 1 I 1’ 

Tt 

L. 

t 

Project camptetedifinat report issued 11195 

DOE selected 

Operation completed 8195’ 

project(CCT-4) Operation initiated T/94’ 

9128188 Preoperational test* initiated 4194 

Facility mothballing completed 1192 

Construction completed 12191 

Environmental monitoring plan completed 715191 

Design completed lt,W 

Ground breaki”g,constr”ction started 2190 

NEPA process completed (EA, 12122189 ‘Projected date: milestones to be updated 

Cooperative agreement awarded 11114189 following resumption of operation 

Project Status/Accomplishments: Commercial Applications: about 300,000 tonslyr of SO,. This COG-cleaning proOn September 16, 1991, Bethlehem Steel Corporation 

announced that all coke production will be suspended at 

its Sparrows Point facility for at least 2 years. This decision was made due to the rapid deterioration of the coke 

ovens. During this period, an evaluation will be made to 

explore alternatives for resumption of coke production. 

Bethlehem Steel’s intent is for long-term coke independence at the facility. 

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

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

successfully when coke-making operations are resumed. 

Given the high background levels of contaminants 

present in the coke oven batteries, specific air toxics 

monitoring is not contemplated at this time. Baseline 

environmental sampling is complete. 

Industrial Applicarions 

The design for this innovative COG cleaning system is cess could be applicable to 24 plants with corresponding 

based on operating data that have been collected from SO,emission levels of 200,000 tonsiyr. If the technology 

individual process steps 01 combinations of individual were installed in all 24 plants, the SO, emissions could 

process steps that have been successfully operated at be reduced by 160,000 tonslyr. Eliminated would be the 

commercial-sized COG treatment facilities. The novel ammonium sulfate which is difficult to market and usuintegration of commercially available process steps is ally is disposed of as a solid waste. Every S-8 years, 

expected to reduce the overall cost of desulfurization, 5 tons of spent nickel catalyst would need to be returned 

ensure reliable operation in applications exceeding to the vendor or disposed of as a hazardous waste, and 

20 years, and provide a viable alternative to conventional 10 tons of spent alumina catalyst would need to be distechnologies. Because the demonstration is designed to posed of as a nonhazardous solid waste. Depending on 

treat 74 million std ft31day of COG (a commercial size), the configuration of the coke oven facility where the 

the project will demonstrate that it is possible to retrofit technology is being implemented, the amount of water 

any existing coke-making facility in the United States needed for cooling purposes would remain the same 01 

with essentially no scaleup involved and without signifi- be reduced, and the amount of pollutants in the wastewacant downtime. ter would remain the same or be reduced. 

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

30 coke oven plants in the United States which emit 

Progrm Update 1993 7.95 
Clean Power from lnte rated 

Coal/Ore Reduction (C 8 REX@) 

Sponsor: 

Cent&x Energy Corporation 

Additional Team Members: 

LTV Steel Company-site owner; constructor and 

operator of COREX’unit 

Air Products and Chemicals, Inc.4esigner, engineer, 

constructor, and operator of air separation and 

combinedcycle units 

Deutsche Voest-Alpine Industrieanlagenbau GmbHCOREX@ developer/supplier; designer and engineer 

of COREX@ unit 

Electric Power Research Institute--cofunder 

Ohio CoalDevelopment Office-cofunder 

Location: 

Cleveland, Cuyahoga County, OH (LTV Steel 

Company’s Cleveland Works) 

Technology: 

Integration of Deutsche Vow&Alpine 

Industrieanlagenbau’s COREX@ iron-making process 

with a combined-cycle power generation system 

(industrial applications) 

Project Objective: 

To demonstrate the integration of a direct iron-making 

process (COREXm) with the production of electricity 

using various U.S. coals in an efficient and environmentally responsible manner. 

The gasification process generates the reducing gas for 

use in the reduction furnace as well as sufficient heat to 

melt the resulting iron in the melter-gasifier. 

Plant Capacity/Production: 

150 MWe (net) and 3,200 tons/day of hot metal (liquid 

iron) 

Project Funding: 

Total project cost $825,092,000 100% 

DOE 150,000,000 18 

Participants 675,092,OOO 82 

(Funding amounts reflect those contained in the proposal 

and are subject to negotiation.) 

CDREX is arcgistcmi IrdcmarL ofDc”Uc!K “Ocst-Atptie 

hd”suiclnlagc”bauGmbHmbH. 

Technology/Project Description: 

The clean power from integrated coal/ore reduction 

(CPICOR) 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 iron ore to 

iron, and the melter-gas&x, located beneath the reduction furnace, which gasifies the coal and melts the iron. 

Excess reducing gas exiting the reduction furnace is 

cooled, cleaned, compressed, mixed with air and nitrogen, and burned in a gas turbine generator system capable of combusting low-Btu fuel gas. The hot exhaust 

from the turbine is then delivered to a heat recovery 

steam generator where process steam is made for utilization in a steam turbine generator system to produce 

additional electric power. 

During the demonstration, about 2,800 tons/day of 

coal will be gasified to produce 3,200 tons/day of hot 

metal and 150 MWe for sale. 

CPICOR technology is less complex and environmentally superior when compared to competing 

7-96 ProgramUpdate 1993 lndusrrial Applicotiom 
L 

CalendarYear 

,993 19% 1995 ,996 ,997 1998 ,999 2000 2001 2002 2003 

3 4 1 23412341234 1234 1 23412341234, 2341234 12 

5/93 994 

, Preaward , 

A I 

Coop*rativeagr*ement 

awarded 5194’ 

DOE selected projea 

(Cc%“) w‘l193 

‘Pro@t*d date; mi1estones are subject to negotiation 

iron-making and power-generating technologies. All 

criteria air pollutants are reduced by more than 85% due 

largely to (1) the inherent desulfuriring capability of the 

COREX’ process wherein the limestone fed to the reduc 

tion furnace captures the sulfur present in the coal and 

(2) the efficient control systems within the combinedcycle power generation process. Because coke is not 

used, coke plants and their associated pollutants can be 

eliminated. 

The energy efficiency of the CPICOR process is 

over 35% greater than competing commercial technology. This efficiency advantage is gained by more effective use of both the sensible heat in the process and the 

volatile matter in the coal, as well as by incorporation of 

the combined-cycle power generation system. 

The technology is being demonstrated at LTV Steel 

Company’s Cleveland Works in Cleveland, OH. 

Project Status/Accomplishments: 

The project is in negotiation. 

Commercial Applications: 

The CPICOR 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 CPICOR 

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 non-coking range. 

The total emissions of NO= from the commercial 

plant are expected to be 0.012 lb/million Btu, which is a 

reduction of more than 97% from thecombination of a 

comparably sized blast furnace, associated coke-making 

facilities, and a comparably sized pulverized coal power 

plant with flue gas desulfurization. Similarly, the total 

emissions of SO, from the commercial facility are expected to be 0.0244 lb/million Btu, a reduction of more 

than 90%. The net electrical generating efficiency of the 

commercial facility will be 47.2% (a net effective heat 

rate of 7,232 BtuikWh on an LHV basis). This is to be 

compared to a net efftciency of 29.1% for comparably 

sized conventional facilities. 

Overall, a CPICOR commercial plant would produce minimal solid or liquid impacts to the environment, 

especially when compared to existing competing facilities. All solid wastes are expected to be exempt from the 

Resource Conservation and Recovery Act requirements. 

The 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 reusable 

as ballast for road construction and foundations. 

Industrial Application Program Update 1993 7.97 
Advanced Cyclone 

Combustor with Internal 

polff;&,Nitrogen, and Ash 

Project completed. 

Sponsor: 

Coal Tech Corporation 

Additional Team Members: 

Commonwealth of Pennsylvania Energy Development 

Pennsylvania Power and Light Company--supplier of 

test coals 

Tampella Power Corporation-host site 

Location: 

Wdliamsport, Lycoming County, PA (Tampella Power 

Corporation boiler manufacturing plant) 

Technology: 

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

(industrial applications) 

Plant Capacity/Production: 

23 million Btuibr 

Project Funding: 

Total project cost 

DOE 

Participants 

Project Objective: 

$984,394 100% 

490,149 50 

494,245 50 

To demonstrate that an advanced cyclone combustor can 

be retrofitted to an industrial boiler and that it can simultaneously remnve up tn 90% of the SO, and 90-95% of 

the ash within the combustor and reduce NOx by up to 

100 ppm 

Technology/Project Description: 

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

air, and sorhent are injected tangentially toward the wall 

Coal Tech’s horizontal cyclone combustor is internally 

through tubes in the annular region of the combustor to 

cause cyclonic action. In this manner, coal-particle 

combustion takes place in a swirling flame in a region 

favorable to particle retention in the combustor. Secondary air is used to adjust the overall combustor stoichiomdry. The ceramic liner is cooled by the secondary air and 

maintained at a temperature high enough tn keep the slag 

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

coal pulverization allows combustion of mat of the coal 

particles near the cyclone wall, with the balance burned 

contains over 80% of the ash and sorbent fed tn the combustor. For NOx control, the comhustor is operated fuel 

on or near the wall. This improves combustion in the 

rich, with final combustion taking place in the boiler 

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

furnace to which the combustor is attached. 

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

23.million-Btuibr, oil-designed package boiler located at 

the Tampella Power Corporation boiler factory in 

Williamsport, PA. Air cooling in this combustor takes 

place in a very compact comhustor which can be retrofitted to a wide range of industrial and utility boiler designs 

without disturbing the boiler’s water-steam circuit. NO, 

reduction is achieved by staged combustion, and SO, is 

captured by injection of limestone into the combustor. 

7.98 Program Update 1993 Industrial Applications 

.______ - .--.- 
The cyclonic action inside the combustor forces the coal 

ash and sorbent tu 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 the boiler provides 

additional sulfur removal capacity. 

Project Results/Accomplishments: 

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 cuntents ranging from 1% tu 3.3% and 

volatile matter ranging from 19% to 37% were tested. 

Under fuel-rich conditions, combustion efficiencies 

exceeding 99% after proper operating procedures were 

achieved. Turndown to 6 million Btuihr from a peak of 

19 million Btu/br was achieved Due to facility limits on 

water availability for the boiler and for cooling the combustor, the maximum heat input during the tests was 

around 20 million Btujhr even though the combustor was 

designed for 30 million Btuibr and the boiler was thermally rated at around 25 million Btujbr. 

Coal Tech reported the following test results: 

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

reduction in boiler-outlet-stack NO= was obtained, 

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

additional 5-10% NOx reduction was obtained by the 

action of the wet particulate scrubber, resulting in 

atmospheric NOx emissions as low as 0.26 lb/million 

Btu (160 ppmv). 

. Over 80% SO, reduction measured at the boiler outlet 

stack was achieved using sorbent injection in the 

furnace at various calcium-to-sulfur molar ratios 

(G./S). 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 

Industrial Applicariom 

the coal sulfur was retained in the dry ash removed 

from the combustor and furnace hearths, and a high of 

11% of the coal sulfur was retained in the slag rejected through the slag tap. 

Local stack particulate emission standards were. met 

with the wet venturi particulate scrubber. 

Total slag/sorbent retention in the combustor, under 

efficient combustion operating conditions, averaged 

72% and ranged from 55% tu 90%. Under mure fuellean conditions, the slag retention averaged 80%. In 

post-CCT-project tests on flyash vitrification in the 

combustor, modifications to the solids injection 

method and increases in the slag flow rate produced 

substantial increases in the slag retention rate. 

All slag removed from the combustor produced trace 

metal leachates well below the EPA drinking water 

standard. 

Different sections of the combustor had different 

materials requirements. Suitable materials for each 

section were identified Also, the test effort showed 

that operational procedures were closely coupled with 

materials durability. By implementing certain procedures, such as changing the combustor wall temperature. it was possible tu replenish the combustor refractory wall thickness with slag. 

Procedures fur properly operating an air-cooledcombustor were developed and the entire operating database was incorporated into a computer-controlled 

system for automatic combustor operation. 

Commercial Applications: 

Coal Tech has concluded that, while the combustor is not 

yet fully ready for sale with commercial guarantees, it is 

ready to be further scaled up for commercial applications 

(100 million Btw’hr), such as combustion of waste solid 

fuels, limited sulfur control in coal-fired boilers, and 

conversion of ash to slag. 

Coal Tech’s advanced, aircooled, slagging combustar can use a wide range of U.S. coals and can be retrokitted to existing or new units. The target market is industrial and utlity boilers sized 20-100 million Btu/br or 

tnure: multiple combustors canbe attached to larger 

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

in combined-cycle industrial and small utility power 

plants in the lo-50.MWe range. The combustor is capable of using pulverized coal, coal-water shmy, cofned 

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

sludge and coal-mine waste). 

Project Schedule: 

DOE selected project (CCT-l) 7lW86 

Cooperative agreement awarded 3/20/87 

NEPA process completed (MTF) 3/26/87 

Environmental monitoring plan completed g/22/87 

CO”StNCti0” 7187-l l/87 

Operational testing 1 l/87-5/90 

Project completed 919 1 

Final Reports: 

Final Technical Report 8191 

DOE Assessment 5193 

Program updare 1993 7.99 
Cement Kiln Flue Gas 

Recovery Scrubber 

Project completed. 

Sponsor: 

Passamaquoddy Tribe 

Additional Team Members: 

Dragon Products Company--project manager and host 

E.C. Jordan Company~ngineer for overall scrubber 

system 

HPD, Incorporated-designer and fabricator of tanks and 

heat exchanger 

Cianbro Corporatiorr-constructor 

Location: 

Thomaston, Knox County, ME (Dragon Products 

Company’s coal-fned cement kiln) 

Technology: 

PassamaquoddyTechnology Recovery ScrubberTM 

(industrial applications) 

Plant Capacity/Production: 

1,450 tons/day of cement; 250,000 std f@/min of kiln 

gas; and up tu 274 tons/day of coal 

Project Funding: 

Total project cust $17,800,000 100% 

DOE 5,982,592 34 

Participants 11,817,408 66 

Project Objective: 

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

process cement kiln using waste dust as the reagent tu 

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

eastern coals and to produce a commercial by-product, 

potassium-based fertilber. 

Technology/Project Description: 

The Passamaquoddy Technology Recovery ScrubberT?” 

uses a water solution/slurry containing potassium-rich 

plant in Thomaston, ME, a plant that processes approximately 470,000 tons& of cement. The process was 

developed by the Passamaquoddy Indian Tribe while it 

was seeking ways to solve landfill problems, which 

resulted from the need tu dispose of waste kiln dust from 

the cement-making process. 

dust recovered from the kiln flue gas, which serves as the 

scrubbing medium. No other chemicals are required for 

the process. After scrubbing the gas, the shmy is separated into liquid and solid fractions. The solid fraction is 

returned tu the cement plant as renovated and usable raw 

feed material. The liquid fraction is passed to a crystalL 

lizer that uses waste heat in the exhaust gas tu evaporate 

the water and recuvcr dissolved alkali metal salts. 

The kiln burns Pennsylvania bituminous coal containing approximately 3% sulfur. 

Parranaqucddy Tcchwlogy Recovery Scrlsxr is amdcmark ofthe 

Pauam.q”cddyTtibc. 

The Passamaquoddy Tribe’s recovery scrubber was 

constructed at the Dragon Products Company’s cement 

7.100 Program Update 1593 Indusrrial Applications 
Project Results/Accomplishments: 

The recovery scrubber began operations in August 199 1 

and has continued operations with several temporary 

shutdowns for normal kiln repairs and maintenance and 

a mope lengthy shutdown from January to May 1992 due 

to poor economic conditions in the area. In a S-month 

period from May to September 1992. the plant produced 

approximately 140,000 tons of cement while the scrubber removed 70 tons of SO, and treated 6,000 tons of 

kiln dust for return to the kiln as raw feed. Initial testing 

of the scrubbing system achieved the project objective of 

90-95% SO, emission reduction, with a maximum reduction of 98%. Operations have totaled5,316 hours. 

Capital costs are approximately $10 million for a 

450,000.ton/y plant, with a simple payback estimated to 

be 3-4 years. Project 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-sulfur coal 

in cement kilns using available waste dust as the reagent, without requiring the purchase of other materials 

as scrubber reactant. 

There are ova 250 cement kiln installations in the 

United States and along the St. Lawrence Rivet in 

Canada emitting approximately 230,000 tons& of SO,. 

Based upon the characteristics of the technology, the 

applicable market would include approximately 75% of 

these installations. If the technology were installed in 

the applicable market facilities, the SO, emissions could 

be reduced by approximately 150,000 tons/yr. 

The effect on NO= emissions is being determined 

during the demonstration. Some reductions in NOx 

emissions are expected. 

Water usage might or might not increase depending 

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

Industrial Application 

the amount reduced because the technology produces 

distilled water either for sale OI 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 fertilizer. Essentially, 

the solid waste stream would be eliminated through 

recovety. 

Project Schedule: 

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

Cooperative agreement awarded i2/20/89 

NEPA process completed (EA) 2/16/90 

Environmental monitoring plan completed 3126190 

Co”structio” 4/90-5/9 1 

Operational testing 819 l-9193 

Project completed 2194 

Final Reports: 

Final Technical Report early 1994 

Topical Report 3192 

Public Design Report 10193 

An economic assessment will be conducted after project 

completion. 

Progrum Update 1993 7.101 
Demonstration of Pulse 

Combustion in an Application 

for Steam Gasification of Coal 

Sponsor: 

ThermoChem, Inc. 

Additional Team Member: 

Manufacturing and Technology Conversion International, 

Inc.-technology supplier 

Location: 

Near Gillette, Campbell County, WY (Caballo Rojo 

Mine) 

Technology: 

Advanced combustion using Manufacturing and 

Technology Conversion International’s (MTCO pulse 

combustorlgasifia (industrial applications) 

Plant Capacity/Production: 

161 million Btuibr of 325 Btu/std ft3 medium-Btu fuel 

gas plus 40,000 lbibr of export steam 

Project Funding: 

Total project cost 

DOE 

Participants 

$37,333,474 100% 

18,666.737 50 

l&666,737 50 

Project Objective: 

To demonstrate the MTCI pulse combustor in an application for steam gasification of coal to produce a mediumBtu fuel gas from subbituminous coal. 

7.102 Progrm Update I993 

Technology/Project Description: 

The MTCI fluidized-bed gasifier incorporates an innovative indirect heating process for thermochemical steam 

gasification of coal to produce hydrogen-rich, clean, 

medium-Btu fuel gas without the need for an oxygen 

plant. The indirect heat transfer is provided by MTCI’s 

multiple resonance tube pulse combustor technology 

with the resonance tubes comprising the heat exchanger 

immersed in the fluidized-bed reactor. Heat transfer is 

3-5 times greater than other indirectly heated gasifier 

concepts, allowing the heat transfer surface to be 

minimized. 

The demonstration plant’s overall efficiency is expected to be 72% 01 more. In major commercial applications, char combustion and heat recovery operations can 

he included to enhance overall plant efficiency. 

SO, emissions are controlled by scrubbing the product gas using commercially available processes. A market for the by-product sulfur is being sought, and disposal methods are being evaluated. 

The demonstration facility will be built at the 

Caballo Rojo Mine in conjunction with a new facility to 

demonstrate the K-Fuel coal-upgrading process. Water 

required to gasify the subbituminous coal will be produced by the K-Fuel process and the steam produced in 

the gasification demonstration facility will be used in the 

K-Fuel facility. The product gas will be burned in a gas 

turbine to generate electricity to operate both facilities. 

hdusrrial Applications 
Cde”dCl,WJM 

,991 1992 1993 1994 1995 ,996 1997 1999 1999 2000 2001 

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

t t 

DOE **kxted Cooperativeagreement t 

+ 

Project corrpleted: final report issued 6/99 

gv&(CCT-IV) awarded I on7192 Cendruction completed 1X15* 

“1~ 

aperation completed 1 l/97 

Operation initiated 11195’ 

Preaperational tests. initiated 10195’ 

Environmental monitoring plan completed 9195’ 

EPA process mmpleted (EA) 5195’ 

Construction started 3195’ 

3esign completed 12194’ 

‘Projected date 

Project Status/Accomplishments: Because of its potential for reducing emissions 

The cooperative agreement was awarded on October 27, while producing a clean-burning, hydrogen-rich fuel gas, 

1992, and design activities are under way. Design verifi. the MTCI fluidized-bed gasifier is expected to have 

cation tests are under way at MTCI’s Baltimore facility. considerable commercial potential. Some of the early 

The design tests include the construction and test firing industrial applications of this technology are expected to 

of one full-sire pulse combustor tube bundle. Environ- be waste-to-energy or waste and coal cofired facilities for 

mental information is being prepared for use in the power and steam generation. One of the more promising 

NEPA process. non-coal applications is processing of kraft black liquor. 

Commercial Applications: 

The MTCI fluidized-bed gasifier is expected to provide 

the exceptional environmental performance exhibited by 

coal gasification in general. SO, emissions are controlled by removing hydrogen sulfide from the product 

gas prior to combustion: removal efficiencies approaching 99% are possible. Particulate emissions are also 

controlled in highly efficient scrubbers. Finally, the 

MTCI pulse combustion technology that provides the 

required gasificr heat is an inherently low-NOx combustion process, thereby assuring that NOx emissions are 

substantially below acceptable limits. 

The processing of pulp results in the production of 

about 88 million tons of by-product black liquor. The 

current practice of using black liquor recovery boilers to 

produce steam and electricity is inefficient. Replacing 

these boilers with MTCI gasifiers would significantly 

improve the conversion efficiency. The estimated market 

for MTCI gasifiers in this application alone is 28 units 

annually. 

Another potential application for the technology is 

in industrial coal gasification because of its modularity 

and ability to produce a medium-Btu gas without requiring an oxygen plant. 

Induslriol Applications Progrm Updare 1993 7.103 
Appendix E: CCT Project Contacts 

In this section are listed contacts for obtaining 

further information about specific CCT Program 

demonswtion projects. Each listing provides the 

name, title, phone number, and mailing address of 

the contact person. In those instances where the 

project sponsor 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 

PFBC Utility Demonstration Project 

Sp07LW. 

The Appalachian Power Company 

Contacts: 

Mario Marrocco, Manager, PFBC Programs 

(614) 223-1740 

American Electric Power Service Corporation 

1 Riverside Plaza 

Columbus, OH 43215 

Jeffrey Summers, DOE/HQ, (301) 903-4412 

Larry K. Carpenter, METC, (304) 291-4161 

PCFB Demonstration Project 

Sponsor: 

DMEC-1 Limited Partnership 

contacrs: 

Gary E. Kmempel, Project Manager 

(515) 281-2459 

Midwest Power Systems, Inc. 

907 Walnut 

P.O. Box 657 

Des Moines, IA 50303 

John Geffken, DOE/HQ, (301) 903-9430 

Lany K. Carpenter, METC, (304) 291-4161 

Four Rivers Energy Modem&&m Project 

SpOTUOK 

Four Rivers Energy Panners, L.P. 

Contacts: 

Edward Holley, Senior Pmject Manager 

(215) 481-8568 

Air Pmducts and Chemicals, Inc. 

7201 Hamilton Boulevard 

Allentown, PA 18195-1501 

George Lynch, DOE/HQ, (301) 903-9449 

Larry K. Carpenter, METC, (304) 291-4161 

Tidd PFBC Demonstration Project 

Sponsor: 

American Electric Power Service Corporation as 

agent for The Ohio Power Company 

Contacts: 

Mado Marrocco, Manager, PFBC Programs 

(614) 223-1740 

American Electric Power Service Corporation 

1 Riverside Plaza 

Columbus, OH 43215 

Jeffrey Summers, DOE/HQ, (301) 903-4412 

Larry K. Carpenter, METC, (304) 291-4161 

Nucla CFB Demonstration Project 

Sponsor: 

Tri-State Generation and Transmission 

Association, Inc. 

Contacts: 

Marshall L. Pendergmff, Assistant General Manager 

(303) 249-4501 

Tri-State Generation and Transmission 

Association, Inc. 

P.O. Box 1149 

Montmse, CO 81402 

John Geftken, DOE/HQ, (301) 903-9430 

Nelson F. Rekos, METC, (304) 291-4066 

Program Updare 1993 E-l 
York County Circulating Fluidized-Bed 

Cogeneration Project 

Sponsor: 

York County Energy Partners, L.P. 

Contacts: 

Bradley F. Hahn, Project Manager 

(717) 225-6601 

York County Energy Partners, L.P. 

25 South Main Street 

Spring Grove, PA 17362 

John Geffken, DOE/HQ, (301) 903-9430 

Nelson F. Rekos, METC, (304) 291-4066 

Advanced Electric Power Generation/ 

Integrated Gasification Combined Cycle 

Combustion Engineering IGCC Repowering 

Project 

Sponsor: 

ABB Combustion Engineering, Inc. 

Contacts: 

Robert W. Glamwina, Project Director 

(203) 285-5904 

ABB Combustion Engineering, Inc. 

P.O. Box 500 

Windsor, CT 06095-0500 

Jeffrey Summers, DOE/HQ, (301) 903-4412 

R. Daniel B&r, METC, (304) 291-4666 

Camden Clean Energy Demonstration Project 

Sponsor: 

Duke Energy Corp. 

Contacts: 

Victor Shellhorse, Vice President 

(704) 373-2474 

Duke Energy Corp. 

400 S. Tryon Sheet 

Charlotte, NC 28202 

George Lynch, DGE/HQ, (301) 903-9449 

R. Daniel B&r, METC, (304) 291-4666 

Pbion Pme IGCC Power Project 

Sponsor: 

Sierra Pacific Power Company 

Contacts: 

John W. (Jack) Matter, Project Manager 

(702) 689-4013 

Sierra Pacific Power Company 

6100 Neil Road 

P.O. Box 10100 

Reno, NV X9520-0400 

John Geffken, DOE/HQ, (301) 903.9430 

Douglas M. Jewell, METC, (304) 291-4720 

Toms Creek IGCC Demonstration Project 

Sponsor: 

TAMCO Power Partners 

Contacts: 

Michael Schmid, Project Director 

(717) 327-4457 

TAMCO Power Partners 

2600 Reach Road 

P.O. Box 3308 

Williamsport, PA 17701-0308 

John Geftken, DOE/HQ, (301) 903-9430 

Robert B. Reuther, METC, (304) 291-4578 

Tampa Electric Integrated Gasification 

Combined-Cycle Project 

Sponsor: 

Tampa Electric Company 

Contacts: 

Donald E. Pless, Director, Advanced Technology 

(813) 228.1332 

TECO Power Services Corporation 

P.O. Box 111 

Tampa, FL 33601.0111 

John Geffken, DOE/HQ, (301) 903.9430 

Nelson F. Rekos, METC, (304) 291-4066 

E-2 Program Update 1993 
Wabash River Coal Gasification Repowering 

Project 

spoilsor: 

Wabash River Coal Gasification Repowering Project 

Joint Venture 

Contacts: 

W. Paul Ruwe, Jr., Joint Venture Manager 

(713) 735-4138 

Destec Energy, Inc. 

2500 City West Boulevard, Suite 1700 

Houston, TX 77042 

Jeffrey Summers, DOE/HQ, (301) 903-4412 

R. Daniel Brdar, METC, (304) 291-4666 

Advanced Electric Power Generation/ 

Advanced Combustion/Heat Englnes 

Healy Clean Coal Project 

sponsor: 

Alaska Industrial Development and Export Authority 

Contacts: 

John Olson, Project Manager 

(907) 561-8050 

Alaska Industrial Development and Expon 

Authority 

480 West Tudor 

Anchorage, AK 99503.6690 

Stan Roberts, DOE/HQ, (301) 903-9431 

Steven J. Heintz, PETC, (412) 8924466 

Coal Diesel Combined-Cycle Project 

spoilsor: 

Environmental Control Devices/NO, Control 

Technologies 

Arthur D. Little, Inc. 

Contacts: 

Robert P. Wilson, Vice President 

(617) 498.5806 

Demonstration of Coal Reburning for Cyclone 

Boiler NO= Control 

sponsor: 

Arthur D. Little, Inc. 

200 Acorn Park 

The B&cock & Wilcox Company 

Contacts: 

Cambridge, MA 02140 

George Lynch, DOE/HQ, (301) 903-9449 

Nelson F. Rekos, METC, (304) 2914066 

Todd Johnson, Senior Marketing Specialist 

(216) 829-7355 

Warren Station Externally Fired Combined-Cycle 

Demonstration Project 

The Babcock & Wilcox Company 

1562 Beeso” Street 

Alliance, OH 44601 

Sponsor: 

William Femald, DOE/HQ, (301) 903-9448 

Ronald W. Corbett, PETC, (412) 892-6141 

Pennsylvania Electric Company 

Contacts: 

Full-Scale Demonstration of Low-NOx CellTM 

Burner Retrofit 

Thomas J. Bradish, Manager, Research and 

Development 

(814) 533.8593 

sponsor: 

The Babcock & Wilcox Company 

Pennsylvania Electric Company 

1001 Broad Street 

contacrs: 

Johnsontown, PA 15907 

Todd Johnson, Senior Marketing Specialiit 

(216) 829-7355 

George Lynch, DOE/HQ, (301) 903-9449 The Babccck & Wilcox Company 

Robert B. Reuther, METC, (304) 291-4578 1562 Beeson Street 

Alliance, OH 44601 

William Fen&d, DGE/HQ, (301) 903-9448 

Ronald W. Corbett, PETC, (412) 892-6141 

Program Update 1993 E-3 
Evaluation of Gas Reburning and Low-NOx 

Burners on a Wall-Fired Boiler 

Sp0iW0r: 

Energy and Environmental Research Corporation 

Contacts: 

Blair A. Folsom, Senior Vice President 

(714) 859-8851 

Energy and Environmental Research 

Corporation 

18 Mason 

lwine, CA 92718 

William Femald, WE/HQ, (301) 903.9448 

Harry J. Ritz, PETC, (412) 892-6137 

Demonstration of Advanced Combustion 

Techniques for a Wall-Fired Boiler 

Sponsor: 

Southern Company Services, Inc. 

Contacts: 

John N. Serge, ICCT Project Manager 

(205) 877-7426 

Soutbem Company Services, Inc. 

P.O. Box 2625 

Birmingham, AL 35202-2625 

William Femald, DOE/HQ, (301) 903-9448 

Arthur L. Baldwin, PETC, (412) 892-6011 

ISO-MWe Demonstration of Advanced 

Tangentially Fired Combustion Techniques for the 

Reduction of NO= Emissions from Coal-Fired 

Boilers 

Sponsor: 

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, DOE/HQ, (301) 903.9448 

Gerard G. Elia PETC, (412) 892-5862 

Demonstration of Selective Catalytic Reduction 

Technology for the Control of NOx Emissions from 

High-Sulfur-Coal-Fired Boilers 

Sponsor: 

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, DOE/HQ, (301) 903-9448 

Arthur L. Baldwin, PETC, (412) 892-6011 

Micronized Coal Reburning Demonstration of 

NO= Control on a 175MWe Wall-Fired Unit 

Sponsor: 

Tennessee Valley Authority 

Contacts: 

Tom Butler, Mechanical Engineer 

(615) 751.6120 

Tennessee Valley Authority 

1101 Market Street, ATTN: MR-3A 

Chattanooga, TN 37402 

William Femald, DOE/HQ, (301) 903-9448 

James U. Watts, PETC, (412) 892-5991 

Environmental Control Devices/SO, Control 

Technologies 

IO-MW Demonstration of Gas Suspension 

Absorption 

Sponsor: 

AirPOI, Inc. 

Contacts: 

Frank E. Hsu, Project Manager 

(201) 288-7070 

AirPol, Inc. 

32 Henry Street 

Teterboro, NJ 07608 

Stan Roberts, DOE/HQ, (301) 903-9431 

Sharon K. Marchant, PETC, (412) 892.6008 

E4 Program Update 1993 
Confined Zone Dispenion Flue Gas 

Desulfurization Demonstration 

Sponsor: 

Bechtel Corporation 

Contacts: 

Joseph T. Newman, Project Manager 

(415) 768-6514 

Bechtel Corporation 

P.O. Box 3965 

San Francisco, CA 94119-3965 

William FernaId, DOE/HQ, (301) 903-9448 

Arthur L. Baldwin, PETC, (412) 892-6011 

LIFAC Sorbent Injection Desulfurization 

Demonstration Project 

sponsor: 

LIFAC-North America 

Contacts: 

Jim Hervol, Project Manager 

(412) 497-2735 

ICF Kaiser Engineers, Inc. 

4 Gateway Center 

Pittsburgh, PA 15222-1207 

William Femald, DOE/HQ, (301) 903-9448 

Robert J. Evans, PETC, (412) 892.5988 

Advanced Flue Gas Desulfurization 

Demonstration Project 

Sponsor: 

Pure Air on the Lake, L.P. 

Contacts: 

Don Vymazal, Manager, Contract Administration 

(215) 481.3687 

Pure Air on the Lake, L.P. 

7201 Hamilton Boulevard 

Allentown, PA 18195-1501 

Stan Roberts, DOE/HQ, (301) 903-9431 

Thomas A. Sarkus, PETC, (412) 892-5981 

Demonstration of Innovative Applications of 

Technology for the CT-121 FGD Process 

Sponsor: 

Southern Company Services, Inc. 

Contacts: 

David P. Butford, Project Manager 

(205) 870-6329 

Southern Company Services, Inc. 

P.O. Box 2625 

Birmingham, AL 35202-2625 

Stan Roberts, DOE/HQ, (301) 903-9431 

Harry I. Ritz, PETC, (412) X92-6137 

Envlronmental Control Devices/Combined 

SOJNO, Control Technologies 

SNOX Flue Gas Cleaning Demonstration Project 

sponsor: 

ABB Environmental Systems 

Contacts: 

Bill Kingston, Project Manager 

(205) 995.5368 

Environmental Systems Division 

ABB Combustion Engineering, Inc. 

P.O. Box 43030 

Birmingham, AL 35243 

Stan Roberts, DOE/HQ, (301) 903-9431 

Robert J. Evans, PETC. (412) 892-5988 

LIME Demonstration Project Extension and 

Coolside Demonstration 

sponsor: 

The Babcock & Wilcox Company 

Contacts: 

Todd Johnson, Senior Marketing Specialist 

(216) 829-7355 

The Babcock & Wilcox Company 

1562 Beeson Street 

Alliance, OH 44601 

William FernaId, DOE/HQ, (301) 903-9448 

Thomas W. Anigoni, PETC, (412) 892-6258 

Progrcm Update 1993 E-5 
.......... ....... 1:.:.~~1:::~::-1::~::::::::: ........... ....... ............ ............ ........... ..~ .......... .... ... ..................... ................. ... ....................... ........ . ........................................ . ............................................................ ............................................................. ..................... :;. ...................... ..................................................................................................................... .......................................................................... 

....... I.. ............ ............... .......... ...... ....... ............... 

...................................... :.:.: ............. ~...:.:...: .: 

......... .................. ..... ... ............................ ............. ................................................ ....... .................................................................................................................. ......., ..................... i.,.~ ......... ..................... ....... ..... ............ ....... ............ Ij.i ....................... .... ........... 

SOx-NOx-Rex-BoxTM Flue Gas Cleanup Milliken Clean Coal Technology Demonstration 

Demonstration Pmject Project 

SpWr: Sponsor: 

The Babcwk & Wilcox Company 

Contacts: 

New York State Electric & Gas Corporation 

Contacts: 

Todd Johnson, Senior Marketing Special& Dennis O’Dea, Project Manager 

(216) 829-7355 (607) 729-255 1 

The B&cock &Wilcox Company 

1562 Beeson Street 

AUiance, OH 44601 

Stan Roberts, DOE/HQ, (301) 903-9431 

Ronald W. Corbett, PETC, (412) 892-6141 

New York State Electric 81 Gas Corporation 

120 Chenango Street 

Binghamton, NY 13902 

Stan Roberts, DOERIQ, (301) 903-9431 

Gerard G. Elia, PETC, (412) 892-5862 

Enhanciag the Use of Coals by Gas Rebuming and 

Sorb& Injection 

Sponsor: 

Energy and Environmental Research Corporation 

Contacts: 

Commercial Demonstration of the NOXSO 

SOJNOx Removal Flue Gas Cleanup System 

Sponsor: 

NOXSO Corporation and MK-Ferguson Company 

Contacts: 

Blair A. Folsom, Senior Vice President Eugene R. Recher, Program Manager 

(714) 859-8851 (216) 523-5923 

Energy and Environmental Research MK-Ferguson Company 

Corpomtion 1500 West 3d Street 

18 Mason Cleveland, OH 44114 

Itvine, CA 92718 

William Femald, DOE/HQ, (301) 903-9448 

Hamy J. Ritz, PETC, (412) 892-6137 

Stan Roberts, DOE/HQ, (301) 903.9431 

Gerard G. Elia, PETC, (412) 892-5862 

One Quality Center 

P.O. Box 280 

Homer City, PA 15748-0280 

Integrated Dry NOJSO, Emissions Control System 

Sp0lW0it 

Public Service Company of Colorado 

Contacts: 

Gordon A. Schott, Project Manager 

(303) 329-1702 

Public Service Company of Colorado 

5900 East 39th Avenue 

Denver, CO 80207 

William Femald, DOE/HQ, (301) 903-9448 

Thomas W. Arrigoni, PETC, (412) 892-6258 

Coal Processing for Clean Fuels/Coal 

Preparation Technologies 

Development of the Coal Quality Expert 

Sponsors: 

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

Contacts: 

Clark Harrison, President 

(412) 479.6016 

CQ, Inc. 

Douglas Archer, DOE/HQ, (301) 903-9443 

Stan Roberts, DOE/HQ, (301) 903-9431 

Robert J. Evans, PETC, (412) 892-5988 

E-6 Program Updare I993 
..~ ,.. ~..,..~..,..~..,.....,........~ ~..,~ ,..,.,. ../.~.....~........ ~,~..,..~....,.....,.,~..~..........,..., ....,...,....~.......ii ..,..~..,.,..~.............~..,..~...,~..~....i,.....,..~.............,. ..~.............................. .,.....,..............., ../.......... 

Self-Scrubbing Coal? An Integrated Approach 

to Clean Air 

sponsor: 

Custom Coals International 

Contacts: 

Robin Godfrey, Project Manager 

(412) 642-2625 

Custom Coals International 

100 First Avenue, Suite 500 

Pittsburgh, PA 15222 

Douglas Archer, DOE/HQ, (301) 903-9443 

Robert J. Evans, PETC, (412) 892-5988 

Advanced Coal Conversion Process Demonstration 

sponsor: 

Rosebud SynCoal Partnership 

Contacts: 

Ray W. Sheldon, Project Manager 

(406) 748-2366 and/or (406) 252-2277 

Rosebud SynCoal Partnership 

P.O. Box 7137 

Billings, MT 59103-7137 

Douglas Archer, DOE/HQ, (301) 903-9443 

Steven I. Heintz, PETC, (412) 892.4466 

Coal PrOCeSSing for Clean Fuels/Mild 

Gaslflcatlon 

ENCOAL Mild Coal Gasfication Project 

Sponsor: 

ENCOAL Corporation 

Contacts: 

J.P. (Jim) Frederick, F’roject Manager 

(307) 686-5493 

ENCOAL Corporation 

P.O. Box 3038 

Gillette, WY 82717 

Douglas Archer, DOE/HQ. (301) 903.9443 

Douglas M. Jewell, METC, (304) 2914720 

Coal Processing for Clean Fuelsllndlrect 

Liquefaction 

Commercial-Scale Demonstration of the LiquidPhase Methanol (LPMEOHTM) Process 

sponsor: 

Air Products and Chemicals, Inc. 

Contacts: 

William R. Brown, Project Manager 

(215) 481.7584 

Air Products and Chemicals, Inc. 

7201 Hamilton Boulevard 

Allentown, PA 18195-1501 

Douglas Archer, DOE/HQ, (301) 903-9443 

Robert M. Kornosky, PETC, (412) 892-4521 

lndustrlal Applications 

Blast Furnace Granulated-Coal Injection System 

Demonstration Pmject 

spoiwx: 

Bethlehem Steel Corporation 

Contacts: 

Daniel Kwasnoski, Program Manager 

(215) 694-6478 

Bethlehem Steel Corporation 

Homer Research Laboratory 

Building C, Room 229 

Bethlehem, PA 18016 

Jeffrey Summers, DOE/HQ, (301) 9034412 

Douglas M. Jewell, METC, (304) 291-4720 

Innovative Coke Oven Gas Cleaning System for 

Retrofit Applications 

sponsor: 

Bethlehem Steel Corporation 

Contacts: 

Daniel Kwasnoski, Project Manager 

(215) 694-6478 

Bethlehem Steel Corporation 

Homer Research Laboratory 

Building C, Room 229 

Bethlehem, PA 18016 

Jeffrey Summers, DOE/HQ, (301) 9034412 

Robert M. Komosky, PETC, (412) 892-4521 

Progrm Update 1993 E-7 
Clean Power from Integrated Coal/Ore Reduction 

(COREX*) 

Sponsor: 

Centerior Energy Corporation 

Contacts: 

I. Lee Bailey, Manager, Corporate Communications 

(216) 447-3235 

Centerior Energy Corporation 

6200 Oak Tree Boulevard 

Independence, OH 44 13 1 

George Lynch, DOE/HQ, (301) 903-9449 

Robert B. R&her, METC, (304) 291-4578 

Advanced Cyclone Combustor with Internal 

Solfur, Nitrogen, and Ash Control 

sponsor: 

Coal Tech Corporation 

Contacts: 

Bert Zauderer, Resident 

(215) 667-0442 

Coal Tech Corporation 

P.O. Box 154 

Merion, PA 19066 

Stan Roberts, DOE/HQ, (301) 903-9431 

Arthur L. Baldwin, PETC, (412) 892-6011 

Cement Kiln Flue Gas Recovery Scmbber 

sponsor: 

Passamaquoddy Tribe 

conracts: 

Garrett Morrison, Project Manager 

(207) 594-5555 

Passamaquoddy Technology, L.P. 

P.O. Box 350 

Thomaston, ME 04861-0350 

Jeffrey Summers, DOE/HQ, (301) 903-4412 

John C. McDowell, PETC, (412) 892-6237 

Demonstration of Pulse Combustion in an 

Application for Steam Gasification of Coal 

Sponsor: 

ThermoChem, Inc. 

conlaclK 

William Steedman, Program Manager 

(410) 997-9671 

TbermoChem, Inc. 

5570 Stemtt Place, Suite 210 

Columbia, MD 21044 

William Fernald, DOE/HQ, (301) 903-9448 

Steven J. Heintz, PETC, (412) 892-4466 

E-8 Program Update 1993