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DOEffE-0330 

COAL Clean Coal Technology 

TECHNOLOGY Demonstration Program 

Program Update 1994 

U.S. Department of Energy 

Assistant Secretary for Fossil Energy 

Washington, DC 20585 

April 1995 
Advanced Electric 

Power Generation 

Fact Sheets 
PFBC Utility Demonstration 

Project 

Participant: 

The Appalachian Power Company 

Additional Team Members: 

American Electric Power Service Corporationdesigner, constructor, and manager 

The Babcock & 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 

fluid&d-bed combustion (PFBC) system (under license 

from ABB Carbon) (advanced &chic power generation/ 

fluidized-bed combustion) 

Plant Capacity/Production: 

340 Mwe (net) 

Project Funding: 

Total project cost %917,944,000 100% 

DOE 184,800,000 20 

Participant 733,144,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 1994 

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 ft 

high. 

The project incorporates a bubbling fluid&d-bed 

process operating at 16 atm (235 lb/in’ 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 sorbent). Dolomite or limestone in the bed 

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

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

by-product. A low bed-temperahxe of 1,600 “F 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 considered is to employ some advanced filtration devices in 

the design. The cleaned gases are then expanded 

through a 75MSVe gas turbine. 

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

250MWe. Superheated steam will be produced from 

pressurized boiler-feed water in the tubes submerged in 

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

8,500 Btu/kWb (40.2% efficiency based on HHV). SO, 

emissions are expected to be reduced by 95% and NOx 

emissions by 80%. 

Advanced Electric Power Generation 
CalendarYear ** 

1988 1989 ,990 1997 ,998 ,999 2ow 2w1 2w2 2003 2004 

3 4 1 234 1 234 1 2341234 1234123412341 2341234 12 

9190 4190 11102 2104 

DesIgnand Conslrucllon 

t 

A 

t 

DOE selected prolect 

(CCT-II) 9@8/88 

I 1 

CcJ”*tr”ctio” completed 8/M 

Design completed 8102 T 

Preoperational twts initiated S/02’ 

Operation initiated 11102 

Ground breakingiconstruction statted 6/99 1 

Project completed/final rapon issued Z/04 

NEPA process completed (EIS) 21% Operation completed 2104 

Environmental monitoring plan completed 7197 ‘Projected date 

Cooperative agreement awardsd 4M90 “Years omined 

The design coal is Pittsburgh 8, high-sulfur (4% permit utilities to add economical increments of capacity 

maximum), bituminous coal 

Project Status/Accomplishments: 

Appalachian Power is evaluating results from various 

value engineering activities, which were conducted to 

improve the efficiency and economic viability. 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. Combined-cycle PFBC systems permit the combustion of a wide range of coals, including high-sulfur 

coals. This technology will compete with circulating 

PFBC systems to repower or replace conventional power 

plants with a technology capable of using high-sulfur 

coals in an environmentally sound manner. PFBC technology appears to be best suited for a wide range of 

applications beginning at the 50-MWe size. Because of 

modular construction capability, PFBC generating plants 

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

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

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

emissions reduction to 0.1 lb/million Bht. 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 Electric Power Generation Program Update 1994 7-9 
PCFB Demonstration Project 

Participant: 

DMEC-I Limited Partnership (a partnership between 

Dairyland Power Cooperative and Midwest Power 

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

Additional Team Members: 

Pyropower Corporation -technology supplier 

Black and Veatch--architect and engineer 

Location: 

Pleasant Hill, Polk County, L4 (Des Moines Energy 

Center) 

Technology: 

Pyropower Corporation’s PYROFLOW pressurized 

circulating fluid&d-bed combustion (PCFB) 

combined-cycle system (advanced electric power 

generation/fluidized-bed combustion) 

Plant Capacity/Production: 

80 Mwe 

Project Funding: 

Total project 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 cotnmercialization of the 

technology; to assess operating perfomtance of unique 

features that include an integral ceramic hot-gas filter 

and slightly modified, comtnercially available gas 

turbine. 

Technology/Project Description: 

In the PCFB process, coal is combusted at about 

1,600 OF and 12 ahn 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. Patticulates 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 nonmggedized gas turbine 

in a pressutized fluidized-bed application. 

7.10 Program Update 1994 Advanced Electric Power Generation 
bOE selected I 

~~;K;(SCCT-III) 

I Cooperativeagreement 

awarded 8/I/91 

‘Projected date 

Project Status/Accomplishments: 

Preliminary design activities are under way. An August 

1994 announcement of a planned merger between Midwest Resources, Incorporated, parent of Midwest Power, 

and Iowa.-Illinois Gas and Electric has impacted die 

project structure. A /I-month extension was’issued on 

October 31, 1994, to provide the participant with additional time to restructure the project and iinalize continuation plans. Pending completion of the participant’s 

plans, NEPA actions have been placed on hold. 

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 co&, including 

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

can be used to repower or replace conventional power 

plants. PCFB technology appears to be best suited for 

Advanced Electric Power Generation 

utility and industrial applications of SO MWe or larger. 

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

equipment, and steam turbines. Another advantage for 

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

requirements per unit of energy generated. 

The commercial version of PCFB technology will 

include the integration of a topping combustor to fully 

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

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

Environmental attributes include in-situ sulfur removal of 95%, NOxemissions 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 1994 7-11 
Four Rivers Energy 

Modernization Project 

Participant: 

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

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

Products and Chemicals, Inc.) 

Additional Team Members: 

Foster Wheeler Energy Corporation-combustor, 

carbonizer, heat exchanger supplier; engineering 

Westinghouse Electric Corporation-gas turbine, 

topping combustor, carbonizer filter, and alkali 

removal system supplier 

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

supplier 

Location: 

Calvert City, Marshall County, KY (adjacent to Air 

Products and Chemicals’ chemicals manufacturing 

PlW 

Technology: 

Foster Wheeler’s fully integrated second-generation 

pressurized circulating fluidized-bed (PCFB) combustion 

system (advanced electric power generationifluidizedbed combustion) 

Plant Capacity/Production: 

95 MWe (equivalent if all steam were converted) 

Project Funding: 

Total project cost $360,707,500 100% 

DOE 142,460,OOO 39 

Participants 218,247,500 61 

Project Objective: 

Todemonstrate PCFB technology at a suffXent scale to 

evaluate the environmental, cost, and plant performance 

technical data that is prerequisite to commercialisation of 

7-12 Program Update 1994 

the technology; to assess operating performance ofthe 

world’s first folly integrated second-generation PCFB 

system that includes a combustor, carbon&a, ceramic 

hot-gas filbation systems, topping combustor, and a 

slightly modified, commercially available gas turbine. 

Technology/Project Description: 

Coal is fed to a pressurized carbon&x that produces a 

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

ofparticulates 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 carbonizer and 

to a PCFB combustor. Additional coal and the 

carbonizer char arc burned in the PCFB combustor, and 

the floe gas passes through ceramic filtration and alkali 

removal units and then is mixed with the carbonizer fuel 

gas for combustion in the topping combustor. A steam 

turbine is driven by steam generated in (1) the heat recovery steam generator, which is located downstream of 

the gas turbine, (2) an integrated ash-cooling heat exchanger, and (3) the PCFB combustor. 

At the Calvert City chemical manufacturing plant, 

the second-generation PCFB process will replace the 

steam-generating capacity of two operating industrial 

process boilers. These two industrial units are spreaderstoker coal-tired units which were installed in the late 

1950s. This equipment change will result in significant 

reductions in the current emissions of pollutants. The 

facility will use about 870 tons/day of 2.63.5% sulfur 

bituminous coals from western Kentucky and southern 

Illinois. 
Calendar Year 

1993 1994 ,995 1996 1997 ,988 1999 2m 2001 am2 MO3 

3 4 1 234 1 234 1 234 1 234 1 234 t 234 1 2 3 4 1 234 1 234 12 

j/93 9l94 

I ’ 1 t Environmental monitoring plan ccmpteted *’ 

Ground breakin@mtiion started l/90* 

NEPA process completed 

(EA, 9K)s 

Cwperative a9reement I 

mration initiated 1 O/98’ 

awarded X28/94; effective Q 

9h94 construction wmpletsd 1om’ 

I E selected project D&j” cmpteted l0Km 

.__-... - . 

brojact compl*tWfinat report issued 9/01’ 

Operation completed 3/01’ 

(L;GT-v, 514193 

‘Projected date 

Project StatwdAccompllshmentsz 

The cooperative agreement was awarded July 28, 1994, 

with an effective date ofAugust 1, 1994. Environmental 

information for use in the NEPA process has been submitted to DOE. Preliminary design activities are under 

W3y. 

Commercial Applications: 

This project wves as a stepping stone to move the second-generation PCFB technology to readiness for widespread commerciai application. The project is also in 

line to be one of the first commercial applications of hotgas cleanup and one of the first to use a nonruggedized 

gas turbine in a pressurized fluidized-bed application. 

In addition to other advanced technology systems, 

second-generation PCFB technology will compete with 

bubbling fluid&d-bed combustion systems to repower 

or replace conventional fossil-fueled power plants with a 

technology capable of using high-suItin coals in an environmentally sound manner. 

Advanced Electric Power Generation 

PCFB technology appears to be best suited for a 

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

The commercial version of PCFB technology will 

have a greenfield net plant efficiency of 45% (which 

equates to heat rates approaching 7,500 Bhu’kWh, based 

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

second-generation plant will (1) have a cost of electricity 

that is projected to be 20% lower than that of a conventional pulverized-coal-fued plant with flue gas desulfurtitian, (2) meet emissions limits that are half those 

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. 

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. 

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 

Program Update 1994 7-13 
Tidd PFBC Demonstration 

Project 

Participant: 

The Ohio Power Company 

Additional Team Members: 

Amacian Electric Power Service Corporationdesigner, 

constmdor, and manager 

The Bahcock & Wilcox Company-technology supplier 

Ohio Coal Development Oflice--cofimder 

Location: 

Brilliant, Jefferson County, OH (Ohio Power 

Company’s Tidd Plant, Unit 1) 

Technology: 

The Babcock &Wilcox Company’s pressurised fluid- 

&d-bed combustion (PFBC) system (under license from 

ABB Carbon) (advanced electric power generation/ 

fluidized-bedcombustion) 

Plant Capacity/Production: 

70 have 

Project Funding: 

Total project cost $189,8X6,339 100% 

DOE 66,956,993 35 

Participants 122,929,346 65 

Project Objective: 

To demonstrate PFBC at a 70.h4We 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-cycle repowering 

application at a utility site; and to accomplish greater 

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

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

mode using the existing steam system. 

DCLOM” 

COAL’ 

WATER--t 

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 

routed to a slipstream to test advanced filtration devices. 

the United States and one of only five worldwide. The 

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

stone 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 OF limits 

the gases pass through cyclones. The cleaned gases are 

then expanded through a 15-MWe gas turbine. The 

NOx fomlation. 

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 lbslinl atm and a temperature of 925 OF to produce 

approximately 55 MWe. Superheated steam is produced 

from pressurized boiler feed water in the in-bed combustar 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 Update I994 Advanced Electric Power Generation 
CalendarYear 

1966 ,967 1988 1969 ,990 1991 1532 ,993 1994 1996 1996 

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

PreaWard 

3/91 u/95 

IT 1 t plan completed Environmental monitoring 6,26,66 

Groundbreaking ceremony 4/6/66 

Construction Started I?./9167 

Cooperative agreement awarded WO/67 

NEPA process com,,lefed (MTF) 3,5,67 

T’ Operation initiated 3191 

Preoperational tests started 12/90 

Cowtwtion completed 12/9O 

Design com,Wed 12/9O I 

t 

Projecl 

completed/ 

final report 

issued 12&X 

Operation completed Z/96’ 

DOE selected project (CCT-I) 7/24166 ‘Pro@ted date 

turbine. Due to repowering, plant efficiency was improved by 10% to a heat rate of 9,750 BtukWh (an 

tions to obtain additional data on long-term gas turbine 

survivability, economical sulfur capture at a 95% level, 

and exposure of advanced ceramic filtration devices. 

Testing is expected to conclude during the first quarter of 

1995. 

cess due to pressurized operation, which reduces space 

requirements per unit of energy generated. 

efficiency of 35.1% based on HHV). 

Ohio bituminous coals having sultin contents of 

2~4% are being used in the demonstration. 

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 gasiiier could yield heat rates approaching 

7,500BtukWh (45% ef ticiency). Project Statue/Accomplishments: 

The plant accumulated approximately 4,800 hours of 

operation during 1994. Overall, coal-fueled operation 

now totals approximately 10,300 hours, including continuous coal-fired runs of 28,29,3 1, and 45 days. During 1994, Tidd produced 219,011 MWh of gross gencration and completed 39 parametric tests. SO, emissions 

reductions above 90% and NO” emission levels of 0.15- 

0.18 lb/million Btu were routinely achieved. These 

levels are well below NSPS requirements. 

Advanced ceramic hot-gas-filtration elements have 

undergone approximately 5,000 hours of exposure to 

one-seventh of the slipstream. 

Ohio Power and DOE added a fourth year of operaCommercial Application: 

Combined-cycle PFBC permits use of a wide range of 

coals, including high-sulfor 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 add increments of 

capacity economically to match load growth. Plant life 

can be extended by repowering with PFBC using the 

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

and steam turbine equipment. Another advantage for 

repowering applications is the cotupactness of the proThe environmkntal attributes of a mature system 

include in-situ sulfur removal of 95% and NO= 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 Electric Power Generation Program Update 1994 7-15 
Nucla CFB Demonstration 

Project 

Project completed, 

Participant: 

T&State Generation and Transmission Association, Inc. 

(formerly Colorado-Ute Electric Association, Inc.) 

Additional Team Members: 

Pyropower Corporation-technology supplier 

Technical Advisory Group (potential users)-cofunder 

Electric Power Research Institute-technical support 

Location: 

Nucla, Montrose County, CO (Nucla Station) 

Technology: 

Pyropower’s aunospheric circulating fluidized-bed 

combustion (ACF’B) system (advanced electric power 

generation/fl”idized-bed combustion) 

Plant Capacity/Production: 

1lOMWe 

Project Funding: 

Total project cost 

DOE 

Participants 

$54,087,000 100% 

19,920,OOo 37 

34,167,OOO 63 

Project Objective: 

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

capacities: to verify expectations of the technology’s 

economic, environmental, and technical performance in 

a repoweting application at a utility site; to accomplish 

greater than 90% SO, removal; to reduce NOx emissions 

by 60%: and to achieve a” efficiency of 34% in arepowering mode. 

Nucla’s circulating fluidized-bed system operates at 

Technology/Project Description: 

atmospheric pressure. In the combustion chamber, a 

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

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

the so&at combines with SO, gases, and solids exit the 

combustion chamber and flow into a hot cyclone. The 

cyclone separates the solids from the gases, and the 

solids are recycled for combustor temperature control. 

Continuous circulation ofcoal and sorhent improves 

mixing and extends the contact time of solids and gases, 

thus promoting high “tilizatio” of the coal and high 

sulfw capture efficiency. Heat in the flue gas exiting the 

hot cyclone is recovered in the economizer. The flue gas 

is removed. The steam generated in the ACFB is used to 

passes through a baghouse where the particulate matter 

generate electric power. 

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

Station were replaced with a new 925,000~lbs/hr ACFB 

steam generator capable of driving a new 74-MWe turbine generator. Extraction steam from this turbine genemtor powers three existing turbine generators 

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

Peabody coal (0.4-0.8% sulfur), Dorchester coal (I .5% 

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

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

the owner ofN”cla Station, was purchased by Tri-State 

Generation and Transmission Association, Inc. 

7-16 Program Update I994 Advanced Electric Power Generafion 
Project Results/Accomplishments: 

Between August 1988 and January 1991, a total of 

72 steady-state performance tests were conducted: 22 

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

a+ full load (110 MWe). Some key results, as reported by 

the participant, follow: 

* Results indicated strong correlations of absolute CO, 

SO,, and NO” emissions levels with combustor 

operating temperatures. Although NSPS compliance 

was maintained, a penalty on limestone feed 

requirements for sulfur retention was realized at the 

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

sulfur retention was achieved with 1.5 CaLS, and 

95% sulfur retention was achieved with 4.0 G/S. 

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

tu maintain 70% sulfur capture. 

* The NOx emissions for all tests were less than 

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

average level of NOx emissions for all tests was 

0.18 lb/million Btu. 

* Combustion efficiency, a measure of the quantity of 

carbon that is fully oxidized to CO,, ranged from 

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

incompletely burned carbon, the largest was carbon 

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

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

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

incompletely oxidized CO in the flue gas. The fourth 

possible source, hydrocarbons in the flue gas, was 

measured and found to be negligible. 

* Boiler efficiencies for 68 performance tests varied 

from 85.6% to 88.6%. The contributions to boiler 

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

latent heat in burning hydrogen; sorbent calcination: 

radiation, and convection; and bottom ash cooling 

Advanced Elecfric Power Generation 

water. Net plant heat rate decreased with increasing 

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

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

achieved during a full-load steady-state test was 

10,980 BttiWh. These values were affected by the 

absence of reheat, the presence of the three older 

12.5-MWe turbines in the overall steam cycle, the 

number of unit restarts, and part-load testing. 

* Over the range of operating temperatures at which 

testing was performed at Nucla, bed temperature was 

found to be the most influential operating parameter. 

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

temperature was the only parameter that had a measurable impact on emissions or efficiencies. Emissions of SO2 and NOz were found to increase with 

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

was increased. 

An economic evaluation indicated that the final 

capital costs for the Nucla ACFB system were about 

$112.3 million. This represents a cost of $l,123lnet kW. 

Total power production costs associated with test operations were about $54.7 million, which results in a normalized power production cost of $63.63/MWh. Fixed 

costs were about 62% of the total, and variable costs 

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

proved competitive with pulverized coal units not limiting emissions as significantly. 

Commercial Applications: 

ACFB technology has good potential in both industrial 

and utility sectors for new capacity additions or for repowering existing coal-tired plants. Coal of any sulfur 

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

can be repowered by ACFB using the existing plant area, 

coal- and waste-handling equipment, and steam turbine 

equipment, the life of the plant can be extended. Benefits of ACFB include 90% SO, reduction, 6%80% NOx 

reduction, and control of pollutants at lower costs than 

are offered by existing technologies. 

As a result of the Nucla demonstration, Pyropower 

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

commercial units are now offered under warranty in sizes 

ranging up to 400 MWe. Under the terms of the 

project’s repayment plan, Tri-State is required to submit 

to DOE semiannual payments based on a percentage of 

the net revenues from plant operation. This repayment 

obligation ends in October 2011 unless DOE’s contribution is repaid before that time. In September 1994, TriState made its first payment of $276,141 under the plan. 

Project Schedule: 

DOE selected project (CCT-I) Ion/87 

Cooperative agreement awarded 10/3/a 

NEPA process completed (MTF) 4/18/X8 

Environmental monitoring plan completed U27/88 

Operational testing 8/E&If91 

project completed 4192 

Final Reports: 

Final Technical Report 10/91 

Economic Evaluation Report 3192 

Public Design Report 12190 

Performance Test Summary Reports 3/92 

Program Update 1994 7.17 
York County Energy Partners 

Cogeneration Project 

Participant: 

York County Energy Partners, L.P. (a limited partnership 

which includes Air Products and Chemicals, Inc.) 

Additional Team Members: 

P.H. Glatfelter Company-site host 

Foster Wheeler Energy Corporation -technology 

supplier 

Location: 

North Codorus Township, York County, PA (greenfield 

site) 

Technology: 

Foster Wheeler’s atmospheric circulating fluidized-bed 

(ACFB) combustor (advanced electric power generationi 

fluidized-bed combustion) 

Plant Capacity/Production: 

227 MWe (net) and 400,000 Ibsihr steam 

Project Funding: 

Total project cost $379,645,450 100% 

DOE 74,733,833 20 

Participant 304,911,617 80 

Project Objective: 

To demonstrate ACFB at 250 MWe, representing a 1.7~1 

scaleup from previously constructed facilities; to verify 

expectations ofthe technology’s economic, enviromnental, and technical performance in a greenfield cogeneration application; and to provide cogenerators, as well as 

utility and nonutility power producers, with the data 

necessary for evaluating a 250.MWe ACFB as a commercial alternative to accomplish greater than 90% SO, 

removal, to reduce NOx emissions by 60% when compared with conventional technology, and to achieve a 

steam efficiency of 88%. 

Technology/Project Description: 

In this project, the circulating fluidized-bed combustor 

operates at atmospheric pressure. Coal, primary air, and 

a solid sorbent, such as limestone, are introduced into the 

lower portion of the combustor where initial combustion 

occnrs. As coal particles decrease in size due to combustion and breakage, they are carried higher in the combustar to an area where secondary air is introduced. As the 

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

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

combustor, collected in a particle separator, and recycled 

to the lower portion of the combustor. The sorbent in the 

bed renmve~ sulfur during the combustion process, 

eliminating the need for scrubbers. 

Steam is generated in tubes placed along the 

combustor’s walls and superheated in tube bundles 

placed in the solids-circulating stream and the flue gas 

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

conventi&l steam cycle. 

The project will demonstrate ACFB in a 250-MWe 

greenfield cogeneration application in York County, PA. 

The participant has an electrical power purchase agreement with Metropolitan Edison Company to supply up to 

227 MWe and a steam purchase agreement with the 

P.H. Glatfelter Company to supply steam to the papermaking facility located adjacent to the project site. 

The heat rate for this cogeneration plant is expected 

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

emissions from this demonstration plant ale below 

7.18 Program Update I994 Advanced Electric Power Generation 
Calendar Year ** tt 

1989 ,990 ,992 1993 ,995 ,996 1997 ,998 1999 2oco 2001 

3412341 2 3 4 1 234 1 2 3 4 12341 2 3 4 123412341 234 12 

bOE selected 

v$b&w1 

! 1 

t 

Design completed 3/96 

T 

t 

Operation initiated t/98’ 

t 

invircmnental monitoring plan 

completed s/95’ 

Ground breakinghnstruction started 5/9S 

NEPA process completed (EIS) 5/95’ 

Project resited 6/93 

Prqect restl”ct”red 6192 

coaperative agreement 

awarded ,1,30,90 

~onstructian com,Med 10/W’ 

Preoperational tests initiated tW97’ 

Project cmnpletedltinal 

report issued 1,O”’ 

Operation completed t/00’ 

0.24lbimillion Btu (92% reduction). This technology 

operates at lower temperatures than conventional boilers, 

thus reducing NOx production. In addition, installation 

of a selective noncatalytic reduction system planned for 

the facility is expected to reduce the NOx emissions by an 

additional 50%. 

Bituminous coal (2% sulfur) from western Pennsylvania will be used. 

Project Status/Accomplishments: 

The project is in the design stage. The participant has 

iinalized agreements with all major equipment vendors 

and with coal and limestone suppliers. During 1994, the 

participant selected Gilbert0mmonwealth as the 

project’s architect and engineer and later as the construetion manager. 

In 1993, the project was relocated 6 miles to a new 

site in North Codorus, PA. The 1994 efforts focused on 

the completion of the NEPAand state permitting processes. Environmental information for use in the NEPA 

process was prepared. Public scoping meetings for the 

North Codorus site were held in August and October 

1993 to solicit public comments on preparation of the 

project’s environmental impact statement. The draft EIS 

was released for public review in late November 1994. 

A public hearing on the draft EIS was held at York, PA, 

in December 1994; another is planned for January 1995. 

Commercial Applications: 

ACFB technology has good potential for application in 

both the industrial and utility sectors, whether for use in 

repowering existing plants or in new facilities. ACFB is 

attractive for both baseload and dispatchable power 

applications because it can be efficiently turned down tn 

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

and any type or size of a coal-tired boiler can be rcpowered. In repowering applications, an existing plant area 

is used, and coal- and waste-handling equipment as well 

as steam turbine equipment are retained, thereby extending the life of a plant. 

In its commercial configuration, ACFB technology 

offers several potential benefits when compared to conventional pulverized coal-fired systems: lower capital 

costs; reduced SO, and NOx emissions at lower costs; 

higher combustion efficiency; and dry, granular solid 

waste which is easily disposed of or which may be a 

salable by-product. 

Advanced Electric Power Generation Program Update I994 7-19 
Combustion Engineering 

IGCC Repowering Project 

Participant: 

ABB Combustion Engineering, Inc. 

Additional Team Members: 

City Water, Light and Power--cofunder and host utility 

State of Illinois, Department of Energy and Natural 

Resources-c&under 

Location: 

Springtield, Sangamon County, IL (City Water, Light 

and Power’s Lakeside Station, Unit 7). 

Technology: 

ABB Combustion Engineering’s integrated gasification 

combined-cycle (IGCC) system (advanced electric power 

generation/integrated gasification combined cycle) 

Plant Capacity/Production: 

65 MWe (net) 

Project Funding: 

Total project cost $270,700,000 100% 

DOE 129,357,204 48 

Participants 141,342,796 52 

Project Objective: 

To demonstrate an advanced dry-feed, air-blown, twostage, entrained-flow coal gasifier with a moving-bed, 

zinc titanate, hot-gas cleanup system; to assess longterm reliability and maintainability of the system at a 

suffKent scale to determine commercial potential. 

4 I I/ II \$ 

STEAM TURBlNE 

Technology/ProJect Description: sulfur from the hot gas. Particulate emissions are rePressurized pulverized coal is pneumatically transported 

to the gasifier. The gasitier essentially consists of a 

bottom combustor section and a top reductor section. 

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

of the combustor allows molten slag to flow into a waterfilled quench tank. 

moved from the coal-handling system and gas stream by 

a combination of cyclone separators and baghouses, and 

ahigh percentage of particulates are fed back to the 

gasitier for more complete reaction and ultimate removal 

with the slag. 

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

40MW e (net) are generated by a gas turbine. Extracted 

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

air requirements of the gasiiier and the zinc titanate 

desulfurization system. Exhaust gases from the gas 

turbine are used to produce steam which is fed to a bottoming cycle to generate an additional 25 MWe (net). 

The demonstration project is converting 600 tons/ 

day of coal into 65 MWe. This is being accomplished 

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

approximately 2,000 “F and are reduced in temperature 

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

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

as by a subsequent fine-particulate removal system, and 

recycled back to the gasifier. 

A newly developed process consisting of a moving 

bed of zinc titanate sorb& is being used to remove 

Advanced Eleciric Power Generation 7.20 Program Update 1994 
Calendar Year 

1988 ,989 1990 1991 ,962 1993 1994 1996 1996 1997 1998 

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

nvironmental monitonng plan completed 5/G/93 

EPA process completed (EA) 3/27/92 

‘Projected date 

through the installation of an entrained-flow coal gasifier 

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 Springtield, IL. The anticipated heat rate for the repowered unit is 8,SOOBhVkWh 

(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). Illinois No. 6 bituminous coal 

containing 2.4% sulfur will be used. 

Project Status/Accomplishments: 

An environmental assessment with a finding of no sig 

niticanr impact was completed March 27, 1992. 

Efforts to reduce the projected cost or, if necessary, 

restructure the project are continuing. 

Commercial Applications: 

The IGCC system being demonstrated in this project is 

suitable for both repowering and new power plant appliAdvanced Electric Power Generation 

cations. Repowering aging plants with this technology 

will improve plant effkiency and reduce emissions of 

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

gasitier will permit a range of units to be considered for 

IepOWi”g. 

conventional pulverized-coal-tired 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 

I50 MWe. A commercial-scale facility based on the 

ABB Combustion Engineering technology is expected to 

have a heat rate less than 8,OOOBtiWh (ef iiciency 

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

least a 20% improvement in efficiency compared to a 

Program Update 1994 7-21 
Clean Energy Demonstration 

Project 

Participant: 

Clean Energy Partners Limited Partnership (a limited 

partnership consisting of Clean Energy Genco, Inc., an 

affxliate of Duke Energy Corp.; Makowski Clean Energy 

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

Additional Team Members: 

Duke Engineering & Services, Inc.dngineer and 

COnStNCtOT 

General Electric Company~ower island designer and 

supplier 

British Gas Americas, Inc., affiliate in conjunction with 

Lurgi Energie and Umwelt GmbH-gasification 

island designer 

Fuel Cell Engineering Corporation-molten carbonate 

fuel cell designer and supplier; cofimder 

Electric Power Research Institute--cofunder 

National Rural Electric Cooperative Associationcofunder 

Deutsche Aerospace AG--cofunder 

Location: 

An east coast site 

Technology: 

Integrated gasification combined-cycle (IGCC) using 

British GasiLurgi (BGiL) slagging fixed-bed gasification 

system coupled with Fuel Cell Engineering’s molten 

carbonate fuel cell (MCFC) (advanced electric power 

generation/integrated gasification combined cycle) 

Plant Capacity/Production: 

477~MWe (net) IGCC; 1.25~MWe MCFC 

Project Funding: 

Total project cost %841,096,189 100% 

DOE 183,300,OOO 22 

Participants 657,796,189 78 

Project Objective: 

To demonstrate and assess the reliability, availability, 

and maintainability of a utility-scale IGCC system using 

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

carbonate fuel cell fueled by coal gas, by an independent 

power producer under commercial terms and conditions. 

and limestone to produce a raw coal gas rich in hydrogen 

gasification, the oxygen and steam react with the coal 

and carbon monoxide. Raw coal gas exiting the gasitier 

is washed and cooled. Hydrogen sulfide and other sulfur 

compounds are removed. Elemental sulfur is reclaimed 

and disposed of as a by-product. Tars, oils, and dust are 

recycled to extinction in the gas&r. The resulting clean, 

medium-Btu fuel gas is used to fuel the gas turbine in 

the IGCC power island. A small portion of the clean gas 

is used for the MCFC. 

Technology/Project Description: 

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

The MCFC is composed of a molten carbonate 

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

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

converted to alternating power in an inverter. 

7-22 Program Update 1994 Advanced Electric Power Generation 
DOE Selected project 

(CCT-V) 5/4/93 

ccQp+xative agreement 

awarded 12/Z&4 ‘Projected date 

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

bituminous coal in a commercial-scale IGCC system and 

integrated MCFC module. 

Project Status/Accomplishments: 

The cooperative agreement was awarded December 2, 

1994. 

Commercial Applications: 

The IGCC system being demonstrated in this project is 

suitable for both repowetig applications and new power 

plants. The technology is expected to he adaptable to a 

wide variety of potential market applications because of 

several factors. First, the BGiL gasification technology 

has successftdly used a wide variety of VS. coals. Also, 

the highly modular approach to system design makes the 

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

high efficiency and excellent environmental performance 

of the system are competitive with or superior to other 

fossil-fuel-fired power generation technologies. 

8,560 BtwkWh (40% efficiency) and the commercial 

embodiment of the system has a projected heat rate of 

8,035 Bhv’kWh (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 BhukWh (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 

Bti (99% reduction); NOx emissions, less than 0.15 lb/ 

million Btu (90% reduction). 

Also, the slagging characteristic of the gasifier 

produces a nonleaching, glass-like slag that can be marketed as a usable by-product. 

Advanced Electric Power Generation Program Update 1994 7.23 
Piiion Pine IGCC Power 

Project 

Patticlpant: 

Sierra Pacific Power Company 

Additional Team Members: 

Foster Wheeler USA Corporation-architect, engineer, 

and c~nshuctor 

The M.W. Kellogg Company-technology supplier 

Location: 

Reno, Storey County, NV (Sierra Pacific Power 

Company’s Tracy Station) 

Technology: 

Integrated gasification combined-cycle (IGCC) using the 

KRW air-blown, pressurized, flnidized-bed coal 

gasification system (advanced electric power generation/ 

integrated gasification combined cycle) 

Plant Capacity/Production: 

99 Mwe (net) 

Project Funding: 

Total project cost $269,993,100 100% 

DOE 134,996,550 50 

Participant 134,996,550 50 

Project Objective: 

To demonstrate air-blown, pressurized, flnidized-bed 

IGCC technology incorporating hot gas cleanup; to 

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

long-term reliability, availability, maintainability, and 

environmental performance at a scale sufficient to determine commercial potential. 

Technology/Project Description: 

Dried and crushed coal is introduced into a pressuized, 

air-blown, fluidized-bed gasifier. Crushed limestone is 

added to the g&tier to capture a portion of the sulfur and 

to inhibit conversion of fuel nitrogen to ammonia. The 

sulfur r&s with the limestone to form calcium sulfide 

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

the form of agglomerated particles suitable for landfill. 

Hot, low8tu coal gas leaving the gasifier passes 

through cyclones which rehun most ofthe entrained 

particulate matter to the gasifier. The gas, which leaves 

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

before entering the hot-gas cleanup system. During 

cleanup, virtually all of the remaining particulates are 

removed by ceramic candle filters, and final traces of 

sulfur are removed by reaction with metal oxide sorbent. 

The hot, cleaned gas then enters the combustion 

turbine which is coupled to a generator designed to produce 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 46 MWe (gross). 

Due to the relatively low operating temperatnre of 

the gasitier and the injection of steam into the combustion fuel stream, the NOx emissions are 0.069 lb/million 

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

snlfur capture and hot gas cleanup, SO, emissions are 

0.069 lb/million Btu (90% reduction). 

In the demonstration project, 880 tons/day of coal 

are converted into 107 MWe (gross), or 99MW e (net), 

for export to the grid. Western bituminous coal 

(0.5X9% sulfur) from Utah is the design coal; tests 

7-24 Pro,yam Update 1994 Advanced Electric Power Generation 
Calendar Year 

1991 1992 1993 1994 1995 1996 1997 ,998 ,999 2wo 2001 

34123412341 234123412341 234 12341234 1 234 12 

DOE selected 

wd&GCT-IV) 

AA ‘I 

T 

t operation initiated 2/g, 

Preop~rafional t*st* initiated 11196 

Construction completbd 1 t/96 

Design completed B/95 

Environmental monitoring plan 

completed 6195 

‘1 

Project completed/final repolt iswed 7100 

Operation completed 7100’ 

Ground breakin@honstruction stalled Z/95’ 

Cooperative agreement awarded 8/1192 

NEPA process completed (EIS) II/W94 ‘Projected date 

using West Virginia or Pennsylvania bituminous coal 

containing Z-3% sulfur also are planned. The gasifier is 

being built at Siam Pacific Power Company’s Tracy 

Station, near Reno, NV 

Project Status/Accomplishments: 

Design and permitting activities continued throughout 

1994. A permit to construct the project under the provisions ofNevada’s Utilty Environmental Protection Act 

was issued by the Public Service Commission of Nevada. In June 1994, three public hearings were conducted on the draft EIS. A final EIS was r&as&for 

public comment on September 30, 1994. COE issued a 

record of decision on November 8, 1994. By December 

1994, all permits needed for plant construction had been 

received, and the participant had requested approval 

from DOE to continue with detailed design and construetion of the plant. 

Commercial Applications: 

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 Bh&Wh (43.7% efficiency), representing a 20% 

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

IGCC systems reduces space requirements per unit of 

energy generated relative to other coal-based power 

generation systems, and the advantages provided by 

modular construction reduce the financial risk associated 

with new capacity additions. 

The KRW IGCC technology is capable of gasifying 

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

minimal environmental impact. This versatility provides 

numerous economic advantages for the depressed 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 nonhazardous 

waste. SO, emissions are expected to be below 

0.045 lb/million Btu (98-99% reduction for most highsulfur coals). NO” emissions are expected to be below 

O.O53lb/million Btu, and emissions of particulates are 

expected to be below 0.01 lb/million Btu. 

Advanced Electric Power Generation Program Update 1994 7-25 
Toms Creek IGCC 

Demonstration Project 

Participant: 

TAMCO Power Parhws (a partnership between TP 

[TAMCO] Company, a subsidiary of Tamp& Power 

Corporation, and CP [TAMCO] Company, a subsidiary 

of Coastal Power Production Company) 

Additional Team Member: 

Institute of Gas Technology-technology developer and 

consultant 

Location: 

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

Coke Company’s Tams Creek Mine) 

Technology: 

Integrated gasification combined-cycle (IGCC) using the 

Tampella U-GAS” fluid&d-bed gasification system 

Plant Capacity/Production: 

190 MWe (55 MWe IGCC and 135 MWe pulverized 

coal) (net) 

Project Funding: 

Total project cost $196,570,000 100% 

DOE 95,000,000 48 

Participant 101,570,000 52 

Project Objective: 

To demons@& 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 fluid&d-bed hot-gas 

cleanup technology. 

“-FAS is a re&ered lra&marko‘tbc tnstitute OfGas Technology. 

7-26 Program Update I994 

V STACK NOT PART OF THE DOE COST-SHARED PROJECT SCOPE 

FeRTloN OF STEM NRWNE lNCL”MD IN PROJECT 

Technology/Project Description: 

Coal is gasified in a pressurized, air-blown, fluid- 

&d-bed gasifier in the presence of a calcium-based 

sorbent. About 90% sulfur removal is accomplished in 

the gasitier. Solids entrained in the gas are collected by 

cyclones in two stages. The low8ti gas, which leaves 

the secondary cyclone at 1,8OCLl,900 “F, is cooled to 

about 1,000 “F before entering the post-g&&r desulfurization unit where zinc titanate is used to remove nearly 

all of the remaining sulfur in the gas. This is accomplished in two fluid&d beds. In the first bed, the sulfur 

is absorbed by the zinc titanate; the zinc titanate is 

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 low-Bti gas. 

Hot exhaust gases from the gas turbine are directed 

to a heat recovery steam generator. The steam generated 

is used both for driving a conventional steam turbine 

generator to produce additional electricity and to provide 

steam for the gasification reaction. 

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 Ibs/hr of steam is generated for export to a coal 

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

The facility is a greenfield plant located outside 

Coebum, \“a, next to the Tams Creek Mine owned by 

Virginia Iron, Coal, and Coke Company, a subsidiary of 

Coastal Power Production Company. 

Advanced Ekctric Power Generation 
Cooperative agreement awarded 1 O/20/92 

‘Projected date 

“Years wined 

Project Status/Accomplishments: is cogeneration under PURF’A’s Qualifying Facilities are no significant wastewater streams, and the solid 

During 1994, efforts continued to be geared toward 

obtaining a power sales agreement with a third party 

purchaser of power. Preliminary design and project 

definition studies are under way. 

Commercial Applications: 

The Tans Creek IGCC system is suitable for new power 

plants, repowering needs, and cogeneration applications. 

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

plants require 15% less land area than pulverized coal 

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

performance. Because of its advantages of modularity, 

rapid and staged on-line generation capability, high 

efficiency, environmental controllability, and reduced 

land and natural resource needs, IGCC is a strong contender for widespread application for meeting future U.S. 

energy needs. Another important application for IGCC 

provisions. 

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

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

waste from the gasifier is ash and calcium sulfate, which 

is discharged as a nonhazardous waste. 

A larger, commercial-scale, 271-MWe greenfield 

facility based on the Toms Creek technology is estimated 

to have a heat rate of 7,750 Btu/kWh (44% efficiency). 

This represents a 20% increase in thermal effxiency and 

a corresponding reduction in CO, emissions as compared 

to a conventional pulverized coal plant equipped with a 

scrubber. 

The U-GAY technology is capable of gasifying all 

types of coals, including high-snlfur and b&b-swelling 

coal feedstocks. 

The total system being demonstrated is compact, 

reducing space requirements, and is very amenable to 

smaller capacity, modular construction situations. There 

Advanced Electric Power Generation Program Update 1994 7-2 7 
Tampa Electric Integrated 

Gasification Combined-Cycle 

Project 

Participant: 

Tampa Electric Company 

Additional Team Members: 

Texaco Development Corporation-gasification 

technology supplier 

General Electric Companydombined-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 Electric Company’s 

Polk Power Station, Unit 1) 

Technology: 

Integrated gasification combined-cycle (IGCC) system 

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

moving-bed desulfurization (advanced electric power 

generation/integrated gasification combined cycle) 

Plant Capacity/Production: 

250 MWe (net) 

Project Funding: 

Total project cost $260,706,446 100% 

DOE 130,353,223 50 

Participant 130,353,223 50 

Project Objective: 

To demonstrate the IGCC technology in a greenfield, 

commercial, electric utility application at the 250-MWe 

7.28 Program Update 1994 

size with a Texaco g&tier. To demonstrate the integrated perfomxuxe of a metal oxide hot-gas cleanup 

system, conventional cold-gas cleanup, and an advanced 

gas turbine with nitrogen injection (from the air separation plant) for power augmentation and NO control. 

The cooled gases flow to a particulate-removal 

section before entering gas-cleanup trains. A portion of 

the syngas is passed through a moving bed of metal 

.^ -. 

Technology/Project Description: 

Texaco’s pressurized, oxygen-blown, entrained-flow 

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

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

Molten coal-ash flows nut ofthe 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. 

oxide absorbent fo remove su~tur. the remammg syngas 

is further cooled through a series of heat exchangers 

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 

sulfnr levels below 0.21 lb/million Btu (96% capture). 

The cleaned gases are then routed to a combined-cycle 

system for power generation. A gas turbine generates 

about I92 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 heatrecovety steam-generator uses heat from the gas-turbine 

exhaust to produce high-pressure steam. This steam, 

Advanced Electric Power Generation 
j? 

j 

/ 

I 

I 

/ 

1 

, 

, 

! 

1 

1 

! 

I 

! 

1 

! 

I 

/ 

! 

I 

Calendar Year ** 

,988 t9*9 1990 ,991 1994 ,995 ,996 ,997 1998 1999 2wo 

3 4 1 2 3 4 1 234123412341 23412341 2341 234 1 234 12 

Operation initiated 1 O/96’ 

I’ ’ 

Constrwtio” mm~leted 7,96’ 

Preoperatbnal tests initiated W96’ 

Environmental monitoring plan completed Z/95’ 

Design completed 8194 

broiect completedffinal 

report issued IO/Q8 

operation completed 10,QB’ 

NEPA proces* completed (EIS, 8/17,94 

Construction started W94 

Cooperativeagreementawarded3/1 l/Q1 

)OE selected project (CCT-III) 12/19/89 ‘Pro)ected date 

“Years omitted 

along with the steam generated in the gasification pro- EPA (the lead agency) released the tine.1 EIS for The Texaco-based system has already been proven 

capable of handling both subbituminous and bituminous 

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

size. 

cess, is routed to the steam turbine to generate an additional 120 MWe (gross). The IGCC heat rate for this 

demonstration is expected to be approximately 

8,600 BhukWh (40% efficient). 

The demonstration project involves only the 

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

Polk Power Station. Coals being used in the demonstration are Illinois 6 and Pittsburgh 8 bituminous coals 

having sulfur contents ranging 2.5-3.5%. 

public comment on June 10, 1994. Favorahle records of 

decision were issued by EPA and the U.S. Army Corps 

of Engineers in July 1994. DOE issued a record of decision on the demonstration portion on August 17, 1994. 

Tampa Elec~c held a formal groundbreaking ceremony 

at the Polk County site on November 2, 1994. Engineering was approximately 75% complete by the year’s end. 

Construction is expected to be completed by mid-1996 

and will be followed by a 2-year demonstration period. 

By-products from the process-sulfuic acid and 

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

the nonleachable slag for use in roofmg shingles and 

asphalt roads and as a shuchual fill in construction 

projects. 

Project Status/Accomplishments: 

The project is in detailed design and early construction. 

In January 1994, all state permits for the plant were 

approved by the governor. 

Commercial Applications: 

The IGCC system being demonstrated in this project is 

suitable for new electric power generation, repowering 

needs, and cogeneration applications. The net effective 

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

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

baseload applications. Commercial IGCCs should 

achieve better than 98% SO, capture with NOx emissions 

reduced by 90%. 

Advanced Electric Power Generation Program Update 1994 7-29 
Wabash River Coal 

E;.dfrion Repowering 

Participant: 

Wabash River Coal Gasification Repowering Project 

Joint Venture (a joint wnhlre 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 Terre Haute, Vigo County, IN (PSI Energy’s 

Wabash River Generating Station, Unit 1) 

Technology: 

Integrated gasification combined-cycle (IGCC) using 

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

(advanced electric power generation/iitegrated 

gasification combined cycle) 

Plant Capacity/Production: 

262 MWe (net) 

Project Funding: 

Total Project cost $438,200,000 100% 

DOE 219,100,000 50 

Participant 219,100,000 50 

Project Objective: 

To demonstrate utility repowering with a two-stage, 

oxygen-blown IGCC system, including advancements in 

the technology relevant to the use of high-sulfur bituminous coal, and to assess long-term reliability, availability, 

and maintainability ofthe system at a fully commercial 

scale. 

7-30 Program Update 1994 

Technology/Project Description: 

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

pressurized, two-stage (slagging first stage and nonslagging entrained flow second stage), oxygen-blown, 

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

cleanup system which remwes particulates, ammonia, 

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

and burned in an advanced 192-MWe (gross) gas turbine. Hot exhaust from the gas turbine is passed through 

a heat recowy 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 high-pressure steam 

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

turbine. 

The process has the following subsystems: a coalgrinding and slurry system, an entrained-flow coal gasifier, 8 syngas heat recovery system, a cold gas cleanup 

system which produces a marketable sulfur by-product, a 

combustion turbine capable of using coal-derived fuel 

gas, a heat recovery steam generator, and a repowered 

steam turbine. 

One of six units at PSI Energy’s Wabash River 

Generating 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 (2.3-5.9% sulfur), Illinois Basin bituminous coal. The anticipated heat rate for the repowered 

unit is approximately 9,000 BtikWh (38% efficiency). 

Using high-sulfur bihnninous coal, SO, emissions are 

expected to be less than 0.1 lb/million Btu (98% reducAdvanced Electric Power Generation 
Calendar Year 

,991 1992 1993 1994 ,995 1996 1997 1998 1999 *cm 2201 

3 4 1 234 t 234 1 234 1 2 3 4 ,234 t 234 1 2341 234 1 234 12 

t A 

‘I 1 t tperation initiated 9195 

DOE Selected Construction completed 9,95 

Preoperatianal tests initiated 8/95 

Design completed 5/94 Project completeMinal report issued 9198 

Environmental monitoring plan completed 719/93 

Operation completed 9/S* 

Groundbreaking ceremony 7”Kr3 

NEPA process completed (EA) 5,28,93 

Cooperative agreement awarded 7128192 ‘Projected date 

tion). NOx emissions are expected to be less than 

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: 

Construction is in progress and is 70% complete. All 

major equipment has been installed, including the gasifiers, air separation unit, and gas turbine. At year-end 

1994, activities were focused on completion of mechanical piping and electrical wiring. Upgrading of the 

switchyard and transmission system has been completed. 

The tube bundle has been installed in the heat recovery 

steam generator. Design specifications for several vessels have been modified to incorporate recent experience 

from Destec Energy’s operating unit at the Louisiana 

Gasification Technology, Inc., facility in Plaquemine, LA. 

An environmental assessment was completed, and 

DOE issued a tinding of no significant impact on 

May 28, 1993. All required environmental permits have 

been granted. 

Advanced Electric Power Generation 

Commercial Applications: 

Throughout the United States, particularly in the Midwest and East, there are more than 95,000 MWc of existing coal-tired utility boilers that will be ova 30years 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,, NOx, and CO, emissions. The modularity of the 

gasitier technology will permit a range of units to be 

considered for repowering and the relatively short construction schedule for the technology will allow utilities 

greater flexibility in designing strategies to meet load 

requirements. Also, the high degree of fuel flexibility 

inherent in the gasifier design allows utilities greater 

choices in fuel supplies to meet increasingly stringent air 

quality regulations. 

Due to the advantages of modularity, rapid and 

staged on-line generation capability, high effkiency, 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 tmin which is ideally suited to 

utility-scale power generation applications. The system 

heat rate for a new power plant based on this technology 

is expected to realize at least a 20% improvement in 

efficiency compared to a conventional pulverized-coaltired plant with flue gas desulliuization. The improved 

system efficiency also results in a similar decrease in 

emissions of CO, 

Program Update I994 7-3I 
Healy Clean Coal Project 

Participant: 

Alaska Industrial Development and Export Authority 

Additional Team Members: 

Golden Valley Electric Association-host utility 

Stone and Webster Engineering Corpengineer 

TRW, Inc.-technology supplier 

Joy Technologies, Inc.-technology supplier 

Location: 

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

Technology: 

TRW’s advanced entrained (slagging) combustor 

Joy Technologies’ spray dryer absorber with sorbent 

recycle 

(advanced electric power generation/advanced 

combustion/heat engines) 

Plant Capacity/Production: 

50 MWe (nominal electric output) 

Project Funding: 

Total project cost $242,058,000 100% 

DOE 117,327,OOO 48 

Participant 124,731,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 Updote 1994 

Technology/Project Description: 

The project is to be a nominal 50-MWe facility consisting of hvo pulverized-coal-fired combustor systems. 

Emissions of SO, and NOx 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 of0.015 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-fired precombustor increases the air inlet 

temperature for optimum slagging performance. The 

boiler hopper. The main slagging combustor consists of 

a water-cooled cylinder which slopes toward a slag openTRW slagging combustors are bottom-mounted on the 

ing. The precombustor bums 2540% of the total coal 

input. The remaining coal is injected axially into the 

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

substoichiometric (fuel-rich) conditions for NOx 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 recovery section. About 7&80% of the coal’s ash is removed as molten slag. The hot gas is then ducted to the 

furnace where, to enswe complete combustion, additional air is supplied from the tertiary air windbox to 

NOxports and to final over-fire air ports. 

Advanced Electric Power Generation 
189 4191 l/96 6199 6101 

I 

1 

CCOperatiW 

agreement 

awarded 4/11/91 

DWj” 

started 7/90 

3E selected project 

:cxq 12119169 

A I 

t 

Environmental monitoring plan 

completed ‘l/95’ 

Ground brealdngkonstruction 

Started 4195 

NEPA process com,Med (EIS) 3/10/94 

Design completed 10193 

t 

Project completedfinal 

wpofl issued m9 

* I 

DOE cost-shared operation 

wmplet*d a99 

Operation initiated 1198’ I 

2 yrs of operational 

data provided a, no 

Construction ~omplotec S/97’ additional cost 

6101’ 

Preoperational tests initiated 6/97’ 

‘Projected date 

“Years omitted 

Pulverized limestone (C&O,) for SO, control is fed 3’years of data, with 2 years of data being provided at 

no cost to DOE. A hazardous air pollutant monitoring 

program will also be implemented. 

opened in November 1994; construction is scheduled to 

into the combustor where most is flash calcined. The 

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

called flash-calcined material, is removed in the fabric 

filter (baghouse) system. A small part of the flash-calcined material is disposed of, but most is conveyed to a 

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

mixing tank is pumped to a grinding mill where it is 

mechanically activated by abrasive grinding. Feed slurry 

is pumped from the feed tank to the 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 flashcalcined material on the baghouse filter bags. 

start in April 1995. 

A final EIS was issued on December 15, 1993, and 

To address concerns about potential impact to the a record of decision was issued on March 10, 1994. A 

nearby Denali National Park and Preserve, DOE, the 

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

from Unit #I reducing the combined emissions from the 

two units to only slightly greater than those cuwatly 

emitted from Unit #l alone. Total site emissons will be 

further reduced to current levels ifnecessary to protect 

the park. 

final vrslblhty monitoring plan has been submitted to the 

Alaska Department of Environmental Conservation. 

Commercial Applications: 

The project site is adjacent to the existing Healy 

Unit #l near HealyAK. Power will go to the Golden 

Valley Electric Association (GVEA). The plant will use 

a nominal 900 tons/day of subbituminous coal containing a nominal 0.2% sulfur and waste coal and provide 

Project Status/Accomplishments: 

Test bums using Healy project fuel were completed at 

TRW’s Cleveland facility. JoyMiro testing of flashcalcined 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 

scale-up designs. The design and engineering is complete; bids for the general construction contract were 

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”, and particulate control is important to potential users planning new 

capacity, repowering, or retrofits to existing capacity in 

order to comply with CAAA of 1990 requirements. 

Advanced Electric Power Generation Program Update 1994 7-33 
p’,E;esel Combined-Cycle 

Participant: 

Arthur D. Little, Inc. 

Additional Team Members: 

Ohio Coal Development Offlce--cofunder 

The Easton Utilities Commission-host 

Cooper Energy Services (Cooper-Bessemer 

Reciprocating Products Division is a division of 

Cooper Energy Services which is owned by Cooper 

Indushies.&engine supplier and conuuercializer 

CQ, Inc.+oal-slung supplier 

PSI--cleanup system designer 

AMBAC Intemational~oal-water fuel injection system 

components supplier 

Location: 

Eaton, Talbot County, MD (The Easto” Utilities 

Commission’s Plant #Z) 

Technology: 

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

Plant Capacity/Production: 

14 MWe (net) 

Project Funding: 

Total project c”st 

DOE 

Participant 

$38,309,516 100% 

19,154,758 50 

19,154,758 50 

Technology/Project Description: 

The project involves modifying two Cooper-Bessemer 

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

to operate on coal-water fuel. Engine moditications 

include a larger camshafl and fuel cams, modified engine 

block, hardened piston rings and liners, and hardened 

turbocharger blades. The CDCC system utilizes a coalwater 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 a” 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 a” 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, medium-speed diesel, 

lube oil protection system, exhaust cyclone, turbocharger, 

heat recov&y steam boiler, steam turbine, and exhaust 

en&ion cleanup system. 

Project Objective: 

To demonstrate an advanced, coal-fueled diesel engine 

combined-cycle system based on Cooper-Bessemer’s 

LSBiLSVB diesel engine series. To provide critical data 

on the pafomxmce, reliability, and wear information of 

all major subsystems. 

The exhaust emission cleanup system incorporates 

cyclones to remove the larger particutates, a selective 

catalytic recowy system for NOx control, a duct sorbent 

injection system for SO, control, and baghouse for final 

collection of ash particulate and spent sorbent. 

The demonstration site is The Easton Utilities 

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

in making the coal-water fuel is a” Ohio bituminous coal 

7-34 Program Update 1994 Advanced Ekcbic Power Generation 

I / 

I 

; 

:i ‘L,
Calendar Year 

1993 1994 1995 1998 1997 ,998 1999 2"oo 2001 2002 2co3 

3 4 1 234 1 234 1 23412341 234 1 2341234 1234 1 234 12 

5193 7194 2l98 2101 

;I 

,I 

t 3 t t 

bperatio” initiated Z/98 

Preoperational tests initiated 1 l/97 

Construction completed t 1187’ 

Ground breaki”s/co”*tr”ctio” started lo/95 

Environmental monitoring plan completed IO/95 

NEPA process completed (EA) 10/95’ 

Moperative agreement awarded 7/l z/94 

DOE selected project 

(CCT-“) 5,493 

4 

I 

Pro@4 complet*Mi”al report iSSUed ZJOl‘ 

operation completed sot* 

‘Projected date 

with characteristics suitable for cleaning to an ash level should be reduced to levels between 50% and 70% beof less than 2% and a sulfw content of less than 2%. low NSPS. 

Project Status/Accomplishments: 

The cooperative agreement was awarded July 12, 1994. 

Design efforts are in progress. Environmental information is being prepared for use in the NEPA process. The 

participant has finalized its subcontract arrangements 

with Cooper-Bessemer and CQ, Inc., as well as its funding agreement with the Ohio Coal Development Off&. 

Commercial Applications: 

The CDCC system is particularly suited for small (below 

SO 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 BtuikWh (48%). which makes it very competitive 

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

Environmental emissions from commercial CDCCs 

Cooper-Bessemer is currently the largest U.S. 

manufacturer of medium-speed 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 

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. Demonstration of the long-term reliability of the critical components in the CDCC system will provide power generators 

with an efficient and environmentally superior option for 

future power. 

Advanced Electric Power Generation Propm Update I994 7-35 
Warren Station Externally 

Fired Combined-Cycle 

Demonstration Project 

Participant: 

Pennsylvania Electric Company 

Additional Team Members: 

Hague International-technology developer and supplier 

Black 81 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 

(EFCC) 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 cat $146,832,000 100% 

DOE 73,416,OOO 50 

Participant 73,416,OOO 50 

Project Objective: 

the integration of the above with a gas turbine and a 

steam turbine. 

To demonstrate an externally tired 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 combustion by-products from the product gas prior to entering the heat exchanger; a staged, wet bottom, low-NOx combustor; and 

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 featnre of the EFCC is a ceramic air heater or heat exchanger (CerHx3 and an atmospheric combustor which 

together replace a conventional combustion system in an 

open-cycle gas turbine. 

gas in the CerHx”. The product gas is then passed 

through a heat recovery steam generator, where more 

heat is extracted tn drive a steam turbine generator and 

produce electricity. The product gas is finally passed 

through a gas cleanup system consisting of a flue gas 

desulfnrizer and a fabric filter before exiting to the &nosphere through the stack. The hot air from the CerHxa is 

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

Cer”x is a registered trademark ofHague International. 

Coal is first cornbusted in a staged combustor for 

NOx control. Particulate-laden gases exit the combustor 

and enter the slag screen where all particles larger than 

about IO microns are collected. Air from the turbine 

compressor is heated by exchange with the hot product 

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 

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

corrosive elements in the fuel or product gas. The 

7-36 Program Update 1994 Advanced Electric Power Generoth 
DesignandConstruction 

I II’ Ground breakingi 

construction started 

e/95’ 

bperafion initiated Wg7 

Preoperationa, tests started l/g, 

Project completed/final repon issued 1 l/g9 

Operation completed 1 U99+ 

I Construction completed l/97’ 

NEW procass completed (EA) 4,95 

EnvironmeW monitoring plan completed Z/95’ 

Cooperative agreementawarde~ 8/l/94 

bOE selected pro,ect (CCT-V) W/93 ‘Projected date 

CerHxa raises the temperature of the air to the turbine ing on the mine. A secondary test coal is Pennsylvania SO, is expected to be below 0.081 lb/million Btu, 

inlet conditions using tube elements that are manufac- bituminous coal containing I .6% sulfur. which is a reduction of over 90% for most coals. NOx 

emissions are expected to be less than 0.15 lb/million 

Btn and particulate emissions (PMlO) are expected to be 

below 0.015 lb/million Btu. 

tured from corrosion resistant, toughened, ceramic materials. 

About 225,000 tonslyr of bituminous coal will be 

combusted 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 

47.7 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 BtuikWh 

(HHV), which is a 3 1.3% improvement over the existing 

Warren Station unit. Potential SOx release is reduced by 

over 90% through capture in the flue gas desulfurization 

system. NOx emissions are expected to be below 

0.13 lb/million Btu. 

Project Status/Accomplishments: 

The cooperative agreement was awarded on August I, 

1994. Design efforts are in progress. Environmental 

information was prepared for use in the NEPA process. 

An environmental assessment was drafted and was 

undergoing review at year’s end. 

The facility being repowered is Pennsylvania Electric 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, dependCommercial 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 Btu/kWh. This represents a 20% increase in thermal efficiency compared to a conventional pulverized 

coal plant with a scnrbber. 

Advanced Electric Power Generation Program Update 1994 7.37 
Environmental Control 

Devices 

Fact Sheets 
Demonstration of Coal 

Reburning for Cyclone Boiler 

NO, Control 

Project completed. 

Participant: 

The Babcock & Wilcox Company 

Additional Team Members: 

Wisconsin Power and Light Company--cofimder and 

host utility 

Sargent and Lundy--engineer for coal handling 

Electric Power Research Institute--cofunder 

State of Illinois, Department of Energy and Natural 

Resources--cofunder 

Utility companies (14 cyclone boiler operators& 

cofunden 

Location: 

Cassville, Grant County, WI, Wisconsin Power and 

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

Technology: 

The Babcock & Wilcox Company’s coal-rebuming 

system (environmental control devicesiNOx control 

technologies) 

Plant Capacity/Production: 

100 MWe 

Project Funding: 

Total project cost 

DOE 

Participants 

$13,646,609 100% 

6,340,788 46 

7,305,821 54 

Project Objective: 

To evaluate the applicability of rebuming technology for 

reducing NOx emissions from a full-scale coal-tired 

cyclone boiler, pulverizing a portion of the primary coal 

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

7.40 Program UpdUfe I994 Environmental Control Devices 

achieve greater than 50% reduction in NOx emissions 

with no serious impact on cyclone combustor operation, 

boiler efficiency, boiler fireside performance (corrosion 

and deposition), or ash removal system performance. 

Technology/Project Description: 

The coal-rebuming process reduces NOx in the furnace 

through the use of multiple combustion zones. The main 

combustion zone uses 70-X0% of the total heat equivalent fuel input to the boiler and slightly less than normal 

combustion air input. The balance of the coal (2&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 NOx formed in the cyclone burners reacts with 

the resultant reducing flue gas and is converted into 

nitrogen in this zone. The completion ofthe combustion 

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

where the balance of the combustion air is introduced. 

The combined production ofboiler slag and dry waste 

from the electrostatic precipitator remains unchanged 

with coal rebuming because the required coal input for 

the same boiler load is the same. 

The coal-rebuming technology can be applied with 

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

adverse effects of rebum on the cyclone combustor and 

boilerperfomxmce. 

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. 
Project Results/Accomplishments: 

Coal-rebum tests were conducted to determine the reduction in NOx emissions for the coal-rebuming technology 

over a range of boiler loads varying from 37 MWe to 

118 MWe (nominal maximum boiler load is I IO 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 NO- 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 

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

With the Lamar coal, the boiler NO, emissions were 

reduced as follows: 

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

I * 47% (to 285 ppm or 0.387 Ibitiillion 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: 

* 62% (to 208 ppm or 0.278 lb/million Btu) at 1 IO MWe 

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

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

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

in controlling NOx. Rebum zone stoichiometry can be 

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

rate, or cyclone stoichiometry. 

Burning subbituminous coal produced lower overall 

NOx emissions levels and higher NO” emissions reductions. This result is probably due to the higher volatile 

content of the western coal. The higher volatile content 

generates higher concentrations of hydrocarbon radicals 

in the rebum 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 rebuming on the retrofitted 

boiler follow: 

. Loss of combustion efficiency, due to increased unburned carbon, amounted to I .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 “F at full load, contrary to expectations, and 

thus improved the boiler heat absorption efficiency 

correspondingly. 

* Slagging and fouling were significantly reduced with 

bituminous coal rebuming. The subbituminous 

rebum operations were too short in duration to make a 

reasonable observation. 

Project Schedule: 

DOE selected project (CCT-II) 9/2X/88 

Cooperative agreement awarded 4/2/90 

NEPA process completed (EA) 2/12/91 

Environmental monitoring plan completed I l/18/91 

Constr”ctio” 11/9&l 1191 

Operatio”al testing 11/91-12/92 

Project completed 12193 

Final Reports: 

Final Technical Report 

Economic Evaluation Report 

Public Design Report 

3194 

early 1995 

819 1 

* 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 reburn 

comparable to baseline operations. 

Commercial Applications: 

The current rebum market is nearly 26,000 MWe and 

consists of about 120 units ranging from 100 MWe to 

1,150 MWe, with mnst in the IO&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 western coal; due to its lower Btu content, western coals limit 

cyclone capacity. With the additional firing capacity of 

the rebum system, full-load performance on western coal 

may be possible for some cyclone units. 

For cyclone boilers, coal rebuming offers a NOx 

reduction alternative at a cost expected to be in the range 

of $hS/kW for 100 MWe units to $40/kW 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-mu advantage. 

Another advantage of the reburn system is its ability to 

utilize different coals. 

! 

I 

Environmenral Control Devices Program Update 1994 7-41 
Full-Scale Demonstration of 

Low-NOx Cell Burner Retrofit 

Project completed. 

Participant: 

The Babcock & Wilcox Company 

Additional Team Members: 

The Dayton Power and Light Company-ofunder and 

host utility 

Electric Power Research Institute-xfunder 

Ohio Coal Development OfXce--cofunder 

TennesseeValleyAuthority--cofunder 

New England Power Company--c&under 

Duke Power Company--cofunder 

Allegheny Power Systemwcofunder 

Centerior Energy Corporation-cofunder 

Location: 

Aberdeen, Adams County, OH (Dayton Power and Light 

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

Technology: 

The Bahcock & Wilcox Company’s low-NOx cell burner 

(LNCB@‘) system (environmental control devicesmOx 

control technologies) 

Plant Capacity/Production: 

605 MWe 

Project Funding: 

Total project cost 

DOE 

Participants 

$11,233,392 100% 

5,442,800 4x 

$790,592 52 

LNCB is a registered uadernark orne *abccd &Wilcox compa”y. 

7-42 Progrm update 1994 

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 LNCB’ 

technology; and to achieve at least a 50% NOx reduction 

without degradation of boiler performance at less cost 

than conventional low-NOx burners. 

Technology/Project Description: 

The LNCB” technology replaces the upper coal nozzle of 

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

port. The lower burner coal nozzle is enlarged to the 

same fuel input capacity as the two standard coal 

nozzles. The LNCB” operates on the principle of staged 

combustion to reduce NOx emissions. Approximately 

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

is supplied through or around the coal-feed nozzle. The 

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

cell to complete the combustion process. The fuel-bound 

nitrogen compounds are converted to nitrogen gas, and 

the reduced flame temperature minimizes the formation 

of thermal NOx. 

The net effect of this technology is 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 

mosf commercial and emerging SO, control technologies, including confined zone dispersion, gas suspension 

absorption, duct injection, and advanced wet scrubbers. 

The demonstration was conducted 8 a large-scale 

power prant operated by The Dayton Power and Light 

Cbmpany andjointly owned with the Cincinnati Gas and 

Environmenta/ Control Devices 
Electric Company and the Columbus Southern Power At full load (605 MWe) with all mills in service, 

Company. The boiler unit is a Babcock & Wilcox-dc- average NO, emissions were 0.53 lb/million Btu, a 

signed, supercritical, once-through boiler equipped with 54.4% reduction from the baseline. CO emissions 

an electrostatic precipitator. This unit contained 24 ranged from 28 to 55 ppm. Flyash unburned carbon 

two-nozzle cell burners ammged in an opposed-firing averaged I. 12%, for a 0.2% loss unburned carbon efliconfiguration. Twelve burners (arranged in hvo rows of ciency. This is a 56% improvement over baseline unsix burners each) were mounted on each of hvo opposing burned carbon losses, probably resulting from improved 

walls of the boiler. All 24 standard cell burners were air flow distribution achieved by the LNCB”retrofit. At 

removed, and 24 new LNCBe were installed. Alternate reduced loads of 460 MWe and 350 MWe, the NOx 

LNCB” on the bottom rows were inverted, with the air emissions reductions were 54% and 48% respectively, 

port then being on the bottom to insure complete com- and CO emissions and unburned carbon values were 

bustion in the lower furnace. comparable with baseline emissions. 

Project Results/Accomplishments: 

The initial test results on the LNCBm were disappointing. 

Reducing gases containing high concentrations of carbon 

monoxide and hydrogen suliide 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 an optimum new burner arrangement. On the lower row of burners, alternate 

LNCBa were inverted so that the air ports integral to 

these burners directed air into the lower furnace. Also, a 

design change for the burners’ coal impellers increased 

the NOx reduction to above the design goal. 

Long-term NOx emissions data were accumulated 

using a third-party continuous emissions monitor over an 

8.month test period that followed the parametric and 

optimization test periods. On days when the boiler was 

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

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

58% reduction from baseline emissions. This data set 

covered 79 days. 

The LNCBa demonstration emphasized 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 corrosion test 

panel. Environmentally, NO+ CO, CO,, total hydrocarbons, and particulate matter were measured at varying 

test conditions. 

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

operation. The demonstration boiler is operating at a 

lower overall excess air since the optimization testing, 

which has reduced the dry gas loss and increased the 

boilereficiencyslightly. 

A corrosion test panel was installed when the 

LNCB” burner were installed. The panel consisted of 

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

aluminized, some stainless weld overlaid, and some 

chromized. The level of corrosion is roughly equivalent 

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

materials had no loss. 

Environmental Control Devices 

Commercial Applications: 

The Babcock & Wilcox Company installed the LNCB” 

technology on more than 2,500 MWe of capacity in the 

United States--each installation achieving more than 

50% NO” reduction. In addition, LNCB” retrofits (introduced in early 1993) have been ordered for an additional 

3,250 MWe. 

The low cost and shot? outage time for retrofit make 

the LNCB” design attractive. Typically, the retrofit capital-cost will be $5.50-$S.OO/kW in 1993 dollars, based 

upon DOE’s 500~MWe reference unit. The outage time 

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

design. The LNCB’ system can be installed at about 

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

The LNCBa project received the 1994 R&D 100 

award for technical excellence in a commercial product. 

Project Schedule: 

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

Cooperative agreement awarded 10/11/90 

NEPA process completed (MTF) 8/10/90 

Environmental monitoring plan completed 8/9/91 

Co”str”ctio” 9/91-11191 

Operational testing 12/91-4/93 

Project completed* 3/95 

Final Reports: 

Final Technical Report 3/95 

Economic Evaluation Report 5195 

Public Design Report 819 1 

Corrosion Test Results Report 5195 

* Project was extended to complete the boiler water-wall corrosion 

exnmination during the fall boiler outage. 

Program Updace 1994 7.43 
Evaluation of Gas Reburning 

and Low-NO Burners on a 

Wall-Fired B&Her 

Participant: 

Energy and Environmental Research Caporation 

Additional Team Members: 

Public Service Company of Colorado+ofunder and 

host utility 

Gas Research Institute--cofunder 

Colorado Interstate Gas Company--cotinder 

Electric Power Research Institute--cofunder 

Location: 

Denver, Adams County, CO (Public Service Company of 

Colorado’s Cherokee Station, Unit No. 3) 

Technology: 

Energy and Environmental Research Corporation’s gas 

rebuming and low-NO” burner (GR-LNB) system 

(environmental control devicwNOx control 

technologies) 

Plant CapacityiProduction: 

172 MWe 

Project Funding: 

Total project cost $17,811,172 100% 

DOE X,905,585 SO 

Participants 8,905,5X7 50 

Project Objective: 

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

from an existing wall-fired utility boiler tiring 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 tiring creates a slightly fuelrich zone. NOx drifting upward from the lower region of 

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

molecular nitrogen. Low-NO, burners positioned in the 

coal combustion zone retard the production ofNOx 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-tired boilers 

equipped with low-NOx burners lowers NOz emissions 

by up to 70%. Gas rebuming was demonstrated with 

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

firing mode and with optimized over-fire air. 

The project site is Public Service Company of 

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

CO. This project conibines gas rebuming and low-NO” 

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

bituminous coals containing 0.354.66% sulfur were 

used in this demonstration. 

7-44 Program Update 1994 Environmental Control Devices 
i 

,, ,\’ ,, ,: ..ir,,zi ,,(. 

measure the amount of air through the SOFA system. 

LNCFS Level111 utilizes both CCOF A and SOFA. 

In addition to over-tire 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 

sumounded by a fuel-lean zone containing combustion 

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

varied using adjustable offset air nozzles. Separation of 

air and coal at the burner level further reduces production 

ofNOx. 

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 ofNOx emissions 

have remained constant. These technologies provide a 

stepwise reduction in NOx emissions, with LNCFS Level 

III expected to provide the greatest reduction. 

Project Results/Accomplishments: 

The LNCFS Level II tests were completed in September 

1991, resulting in a maximum .NOx reduction of 40% at 

full load. The LNCFS Level II was converted to LNCFS 

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

installing CCOFA 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 incr&e in flyash 

carbon content. Finally, LNCFS Level I was evaluated 

by closing the SOFA dampers of the Level III system. 

Testing of the Level I system, completed in December 

1992, showed a maximum NOx reduction of 37% at full 

load. 

:,: i _ .~‘.:,i.~,,i:, 

,, ,v+ 

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. 

Commercial Applications: 

Gulf Power has retained the LNCFS at its Plant Laming 

Smith Unit No. 2. 

Final Reports: 

Final Report and Key Project Findings 

Chemical Emissions Report 

Economic Evaluation Report 

Final Design Report 

2194 

10193 

2194 

9193 

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 tired 

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. 

The estimated capital cost for LNCFS I ranges 

between $8-1OikW and for LNCFS II/l11 between 

$15-20ikW. 

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

based upon reducing NOxemissions from fossil-fueltired power plants. Potential exists for annual NOx emission reductions of IO%, depending on the unit load scenario and the tangentially tired NOx control selected. 

Project Schedule: 

DOE selected project (CCT-III) 9/2X/88 

Cooperative agreement awarded 9/20/90 

NEPA process completed (MTF) 712 1189 

Environmental monitoring plan completed 12/27/90 

Co”structio” 1119~5f91 

Operational testing 5/91-12/92 

Project completed 6194 

Environmental Control Devices Program Update 1994 7-49 
Demonstration of Selective 

Catalytic Reduction 

Technology for the Control 

of NOx Emissions from 

High-Sulfur-Coal-Fired Boilers 

Participant: 

Southern Company Services, Inc 

Additional Team Members: 

Electric Power Research Institute--cofunder 

OntarioHydrMofunder 

GulfPower Company-host utility 

Location: 

Pensacola, Escambia County, FL (Gulf Powa 

Company’s Plant Crist, Unit 4) 

Technology: 

Selective catalytic reduction (SCR) (environmental 

control devicesiNOx 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-tired utility boilers using 

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

while achieving as much as 80% NO” removal. 

CON 

AIR 

Technology/Project Description: 

The SCR technology consists of injecting ammonia into 

boiler flue gas and passing it through a catalyst bed 

where the NO= and ammonia react to form nitrogen and 

water vapor. 

loadings of flue gas, the applicability of SCR technology 

to provide a cost-effective mean ofreducing NOxemisThe project is demonstrating, at high- and low-dust 

sions 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 approkimately 3% sulfur under various NOx and 

particulate levels. 

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

and six 0.20.MWe-equivalent SCR reactors. These 

reactors were calculated to be large enough to produce 

design data that will allow the SCR process to be scaled 

up to commercial size. Catalyst suppliers (two U.S., two 

European, and two Japanese) provided eight catalysts 

with various shapes and chemical compositions for 

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

7.50 Program Update 1994 Environmental Control Devices 
Preaward A f t t Project completed/final report issued t/96 

NEW proce~$ Operation initiated 7/93 Operation completed 7/95 

compt*ted 

(MTF) WW89 

DOE selected project 

(CCT-II) 9/28/a? 

Cooperative agreement A I Preoperationat tests initiated Z/93 

Environmental monitoring plan completed 3/t I/93 

Construction completed u9/93 

Design completed 12/992 

I 0,0”“d breakinqlconstr”dio” started 3/92 ‘Projected date 

was concluded at the end of Febrwuy 1991. Const~cProject Status/Accomplishments: 

tion began in late-March 1992; a dedication ceremony 

was held on July I, 1992. 

Preliminary design engineering for the SCR test facility 

Detailed engineering was 

completed in December 1992. Flue gas was first passed 

through the SCR facility during equipment checkout on 

January IO, 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 I, 1993. 

and one low dust), supplied by six different companies, 

Results of parametric tests through December 1994 

are performing within or exceeding designed specificaindicate that the eight different catalysts (seven high dust 

tions, both with respect to activity and life. However, 

differences have been noted in NO, reduction activity, 

SO, oxidation, physical fouling, and pressure drop. 

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

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

(i.e.,aunounced, sited, and committed in termsof service 

date or under conshuction) and 144,500MW e (290boiL 

ers) of planned dry-bottom electric generating capacity in 

the United States. 

Commercial Applications: 

SCR technology can be applied to existing and new 

utility applications for removal of NO” fmm flue gas for 

virtually any size boiler. There are approximately 

1,04lcoal-tired 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 lowNOr combustion technologies (i.e., lawNOx burners, over-tire air, and attnosphaic fluidized-bed combustion), the potential total 

retrofit market for SCR technology is 154,560 MWe 

Upon completion of the initial parametric testing in 

December 1993, baseline ammonia slip measurements 

were repeated. These tests were completed during December 1993 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% 

NO” removal) and in many cases the measured slip was 

below the I ppm detection limit. 

Environmental Control Devices Program Update 1994 7.51 
Micronized Coal Reburning 

Demonstration for NO 

Control on a 175-MWe” 

Wall-Fired Unit 

Participant: 

Tennessee Valley Authority 

Additional Team Members: 

Duke/Fluor Daniel (partnership between Duke 

Engineering & Services, Inc., and Fluor Daniel, 

Inc.&engineer and constructor 

Fuller Company--technology supplier 

Energy and Environmental Resew&Corporationtesting/environmental/technical consultant 

Location: 

Negotiations for a new site are under way. 

Technology: 

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

devices/NOx control technologies) 

Plant Capacity/Production: 

175 MWe 

Project Funding: 

Total project cost $7,330,041 100% 

DOE 3,514,755 48 

Participants 3,815,2X6 52 

Project Objective: 

To reduce NOx emissions by 5&60% using micronized 

coal as the rebuming fuel combined with advanced coalrebuming technology. 

h4icrdvfiti is a nadcmark ofthe Futtcr company 

7.52 Program Updare 1994 

COAL 

n 

L 

I 

I 

UIL--J III EXISTING U 

PVLVERIZERS AIR t 

Technology/Project Description: 

The technology will be applied to a pulverized coal furnace. The coal to be used to tire the furnace will be a 

low-sulfur bituminous coal. This same coal will be used 

as 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 

Central to the project technology is the two-element 

system which consists of a patented centrifugal-pneumatic MicroMillrM and an external classifier. The mill is 

capable of grinding coal into a fine powder without the 

mechanical attrition 01 roll crushing normally associated 

with coal mills. The MicroMillTM takes coal away from 

the existing bunker and supplies it to the new micronised 

coal burners. 

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

of volatiles at a more even rate. This uniform, compact 

combustion envelope allows for complete combustion of 

the coal/air mixhue 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. 

These options can prevent higher operating costs OT 

furnace performance dating often associated with conventional environmental controls. 

Environmental Control Devices 
Calendar Ysar 

1991 1992 1993 1994 1995 ,996 ,997 ,998 19% 2ow 2001 

3 4 1 23412341 234 1 234 I 234 1 234 1 234 1 2341234 12 

I DOE selected 

y&,(CCT-IV) 

!I 

I 

Alternate sit* identified 395 

~EPA P~OCBSS c0mpk.m (Cx) 8113192 

COOperative agreement awarded 7128,92 

‘Projected date 

Project Status/Accomplishments: 

Due to plant problems and operational and environmental strategy changes, the original host site, the Tennessee 

Valley Authority’s Shawnee Fossil Plant, was no longer 

suitable to demonstrate the technology. The project 

participant is investigating other possible host sites, 

including sites both inside and outside the Tennessee 

Valley Authority system. 

Commercial Applications: 

Micron&d-coal-rebuming technology can be applied to 

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

tangential-fired pulverized coal units. The technology 

reduces NOx emissions by 5CL60% with minimal furnace modifications for existing units. For greentield 

units, the technology can be designed as an integral part 

of the system. Either way, the technology enhances 

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

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

technology. 

Environmental Control Devices 

The availability ofa coal-rebuming fuel, as an 

additional fuel to the furnace, solves several problems 

concurrently. Existing units unable to switch fuels 

because of limited mill capacity would be able to reach 

their maximum continuous rating. NOx emissions 

reductions will enable lost capacity to be restored, 

creating a very economic source of generation. For both 

retrofit and greentield facilities, rebum burners also can 

serve as low-load burners, and commercial units can 

achieve a turndown of 8: I on nights and weekends 

without consuming expensive auxiliary fuel. Existing 

pulverizers can be operated on a variety of coals with 

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

will increase overall pulverized-fuel surface area for 

better carbon burnout. 

Program Update 1994 7.53 
IO-MWe Demonstration of 

Gas Suspension Absorption 

Participant: 

AirPol, Inc. 

Additional Team Members: 

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

technology owner 

Tennessee Valley Authority+ofunder and site owna 

Location: 

West Paducah, McCracken County, Ki’ (Tennessee 

Valley Authority’s Center for Emissions Research) 

Technology: 

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

system for flue gas desnltiaization (FGD) (environmental 

control devices/SO, control technologies) 

Plant Capacity/Production: 

IO-MWe equivalent slipstream of flue gas from a 

150.MWe boiler 

Project Funding: 

Total project cost 

DOE 

Participants 

Project Objective: 

$7,717,189 100% 

2,315,259 30 

$401,930 70 

To demonstrate the applicability of Gas Suspension 

Absorption for flue gas desulfuization using high-sulfur 

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

demonstration system. 

7-54 Program Updare 1994 

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 (ESP) before being released to the ahnosphere. The lime slurry, prepared from hydrated lime, is 

injected through a spray nozzle at the bottom of the 

reactor. The volume of lime slurry is regulated with a 

variable-speed pump controlled by the measurement of 

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

dilution water added to the lime slurry is controlled by 

on-line measurements of the flue gas exit temperature. 

Solids collected from the cyclone and particulate contio1 

device are combined and disposed of in an existing site 

disposal area. 

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

well as increase lime utilisation efficiency with solids 

ECYCIC 

This project is located at the Center for Emissions 

Research, utilizing a IO-MWe slipstream of flue gas 

from a 150-MWe coal-tired boiler at the Tennessee Valley Authority’s Shawnee Fossil Plant in West Paducah, 

KY. A western Kentucky coal containing about 3% 

sulfur was used. 

Project Results/Accomplishments: 

Optimization testing was conducted to determine the 

effect of the process design variables on the SO, remova, 

efficiency in the reactor/cyclone and the ESP. The testing 

Environmental Control Devices 
indicated that the order of importance of the key variables is (I) 0./S, (2) approach-to-adiabatic-saturation 

temperature, and (3) coal chloride content. 

The SO, removal efficiency for the overall system 

ranged from slightly more than 60% to nearly 95%, 

depending on the specific test conditions. The lower SO, 

removal efficiency levels were achieved at the higher 

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

lime stoichiomehy level (Q/S of l.OO), and lower coal 

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

efficiency levels were achieved at the closer approach-tosaturation temperatures (8 and I8 “F), the higher lime 

stoichiometry level (Ca/S of I .30), and higher coal chloride level (0.12%). Most of the SO, removal in the GSA 

system occurred in the reactor/cyclone, with only about 

2-5% of the overall removal occurring in the ESP. 

300.MWe boiler burning a coal containing 2.6% sulfur. 

The design SO, removal efficiency was 90%. The resulting capital cost estimate (in 1990 $) is $149ikW for GSA 

as compared to $216ikW for a wet limestone, forcedoxidation (WLFO) scrubbing system. The levelized 

annual revenue requirement for the GSA process is lower 

than that for the WLFO system, but the difference is only 

about 20% (which is not considered to be significant 

given the limitations on the accuracy of estimates used in 

the analysis). The principal annual operating cost for the 

GSA process is the cost of the pebble lime. The IS-year 

levelized costs in mills/kWh for the two systems are 

listed below: 

1996 and will be the first full-scale commercial GSA 

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

unit for a coal-fired boiler. The GSA technology was 

identified as the least-cost alternative for the city to meet 

CAAA compliance requirements for 1997. 

In addition, 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 sinter plant. Sweden’s stringent standards require an SO, removal efficiency of 90-95%. 

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

run of the GSA system with the ESP indicated that the 

GSAiESP is capable of consistently maintaining 90% or 

better SO, removal at a moderate lime requirement. A 

14.day pulse jet baghouse (PJBH) run was successfully 

completed in March 1994. SO, removal efficiency in the 

GSAiPJBH system averaged more than 95% during the 

demonstration; this was typically about 3-5 percentage 

points higher than that achieved in the GSA/ESP system 

at the same test conditions. 

Fixed costs 

Variable costs 

Capital costs 

Total 

GSA WLFO 

2.3 2.81 

3.1 2.93 

u LB 

10.4 13.04 

Commercial Applications: 

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

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

much simpler to build and operate than wet FGD and 

regenerable processes and requires much less space; 

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

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

that of wet FGD and the regenerable processes. This 

high removal rate makes the GSA process suitable for 

use with high-sulfur coal. 

The GSA should fultill the need of the utility indusby 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 5s250-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 minimizing the cost for upgrading the existing dust collector. The potential market for the GSA is 

estimated at $300 million within the next 20 years. 

The project demonstrated a number of key technical 

attributes, including a simple and direct method of lime/ 

solid recirculation, high acid gas adsorption, low lime 

consumption with minimal waste by-product residue, 

low maintenance operation, no internal buildup, and 

reduced space requirement. In addition, the project 

demonstrated that a pulse jet baghouse system improved 

SO, removal efficiency by about 3-5 percentage points. 

Also, air toxics testing showed that a removal rate of 

over 95% could be achieved by the GSA. 

The relative process economics for the GSA system 

were evaluated for a moderately difficult retrofit to a 

Successful testing of the AirPol demonstration 

project has resulted in a commercial application in Ohio. 

The city ofHamilton, OH, received a $5-million grant 

from the Ohio Coal Development Office to install the 

GSA technology to control emissions from a 50-MWe 

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

new system is scheduled to be operational in August 

Project Schedule: 

DOE selected project (CCT-III) 12ll9189 

NEPA process completed (MTF) 9/21/90 

Cooperative agreement awarded 10111190 

Construction 5/92-9192 

Environmental monitoring plan completed lo/2192 

Operational testing 10/92-3194 

Project completed 3195 

Final Reports: 

Final Technical Report 3195 

Economic Evaluation Report 1195 

Public Design Report 2195 

Environmental Contml Devicss Program update I994 7-55 
Confined Zone Dispersion 

Flue Gas Desulfurizatibn 

Demonstration 

Participant: 

Bechtel Corporation 

Additional Team Members: 

Pennsylvania Electric Company--cofbnder and host 

utility 

Pennsylvania Energy Development Authoritydofunder 

New York State Electric & Gas Corporation-cofunder 

Rockwell Lime Company--cofunder 

Locatlon: 

Seward, Indiana County, PA (Pennsylvania Electric 

Company’s Seward Station, Unit No. 5) 

Technology: 

Bechtel Corporation’s in-duct, confined zone dispersion 

flue gas desultixization (CZD/FGD) process 

(environmental control devices/SO, control technologies) 

Plant CapacltylProduction: 

13.5 Mwe 

Project Funding: 

Total project cost $10,411,600 100% 

DOE 5,205,x00 50 

Participants 5,205,800 50 

Project Objective: 

To demonstrate SO, removal capabilities of in-duct 

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

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

Technology/Project Description: 

In Bechtel’s CZDiFGD process, a finely atom&d 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 withii 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. 

alternative to conventional FGD processes, requiring less 

physical space and lower capital, operating, and maintesuccessfully demonstrated, this technology would be an 

nance costs. 

This project includes injection of different types of 

sorbents (dolomitic and calcitic limes) with several atomizer designs using low- and high-sultir 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 I .2-2.5% sulfur) 

is being used in the project. 

The CZD/FGD process is expected to remove up to 

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

7-56 Program Update 1994 Environmental Control Devices 
Project Results/Accomplishments: 

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

the CZD process in July 1991. The first I2 months of 

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

continuous operation test period with the system being 

operated under folly 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 continuing efforts to submit and finalize 

all reports required under the cooperative agreement. 

Commercial Applications: 

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. 

* CZDiFGD 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 aswre residence time of 2 seconds. 

* During normal operations, no deposits of fly ash or 

reaction products took place in the flue gas duct. 

A CZD system can be added to a utility boiler with 

a capital investment of about $25-50ikW of installed 

capacity, or approximately one-fourth the cost ofbuilding 

a conventional wet scmbber. In addition to low capital 

cost, other advantages include small space requirements, 

case of retrofit, low energy requirements, folly 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 economi- 

* The folly automated system, folly integrated with 

power plant operation, demonstrated that the 

CZDiFGD process responded well to automated 

controloperation. 

cally integrated into existing power plants. 

* Availability of the system was very good. 

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

* Results of the demonstration indicated that the 

CZDiFGD process can achieve costs of $300/tori of 

SO, removed when operating a 500-MWe unit buming 4% sulfor coal. Based on a 500-MWe plant retrotitted with CZDiFGD for a 50% rate of SO, removal, 

the total capital cost is estimated to be less than 

$3O/kW. 

Project Schedule: 

DOE selected project (CCT-III) 

Cooperative agreement awarded 

NEPA process completed (MTF) 

Environmental monitoring plan completed 

Construction 

Operational testing 

Project completed 

12/19/89 

lO/l3/90 

9/25/90 

6/12/91 

3/91-6/91 

7/9l-6/93 

6195 

Final Reports: 

Final Technical Report 

Public Design Report 

Economic Evaluation Report 

6195 

4193 

6196 

Environmental Control Devices Program Update 1994 7.57 

,, . ,. il C” .:, r- I ^ ,; ~ 
LIFAC Sorbent Injection 

Desulfurization 

Demonstration Project 

Project completed. 

Participant: 

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

Engineers, Inc.) 

Additional Team Members: 

ICF Kaiser Engineers, Inc.+ofunder and project 

manager 

Tampella Power Corporation-cotimder 

Tampella, Ltd.-technology owner 

Richmond Power of Light--cofunder and host utility 

Electric Power Research Institute--cofunder 

Black Beauty Coal Company--cofunder 

State of Indiana--cofimder 

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 %21,393,772 100% 

DOE 10,636,864 SO 

Participants 10,756,908 50 

Project Objective: 

To demonstrate that electric powerplants-especially 

those with space limitations-burning high-sulfur 

7.58 Program Update 1994 

coals can be retrofitted successfully with the LIFAC 

limestone injection process to remove 75-85% of the 

SO2 from flue gas and produce a dry solid waste product 

for disposal in a landfill. 

Technology/Project Description: 

Pulverized limestone is pneumatically blown into the 

upper part of the boiler near the superheater where it 

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

limestone is calcined into calcium oxide and is available 

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

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

fly ash in the electrostatic precipitator (ESP). The SOTbent material from the reactor and electrostatic precipitator is recirculated back through the reactor for increased 

eiXciency. The waste is dry, making it easier to handle 

than the wet sctubber 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 flue gas and produces a dry solid waste product 

suitable for disposal in a landfill. 

The process was demonstrated at the Whitewater 

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

is owned and operated by Richmond Power & Light and 

is located in Richmond, IN. Bituminous coal containing 

2.&2.9% sulfur was used. 

Environmenml Control Devices 
,., ,. ,: ., 9, ? ~:‘, i ,,, ,,. 

Project ResultslAccomplishments: 

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

operation over a 2-year period. 

LIFAC process values and their effects on sulfor 

removal efficiency were evaluated during parametric 

testing. The four major parameters having the greatest 

influence on sulfor removal efficiency were limestone 

quality, CalS, reactor bottom temperature (approach-tosaturation), and ESP ash recycling rate. Total SO, capture was about 15 percentage points better when injecting tine limestone (80% minus 325 mesh) than it was 

with coarse limestone (80% minus 200 mesh). 

Parametric tests indicated that a 70% SO, reduction 

was achievable with a Ca/S of 2.0. ESP ash containing 

unspent sorbent and fly ash was recycled from the ESP 

hoppers back into the reactor inlet duct work. Ash recycling is essential for efficient SO, capture. The large 

quantity of ash removed from the LIFAC reactor bottom, 

and the small size of the ESP hoppers limited the ESP 

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

recycled from the ESP was approximately 70% less than 

had been anticipated. However, this low recycling rate 

contributed an additional 15 percentage points to total 

SO, capture. During a brief test, it was found that increasing the recycle rate by 50% resulted in a 5 percentage point increase in SO, removal efficiency. It is anticipated that if the reactor bottom ash is recycled along with 

ESP ash, while sustaining a reactor temperature of 5 “F 

above saturation temperahue, an SO, reduction of 85% 

could be maintained. 

Optimization testing began in March 1994 and was 

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

was operated at an average load of 60 MWe during longterm testing, although it fluctuated according to power 

demand. The LIFAC process automatically adjusted to 

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

SO, reductions above 70%. Reactor bottom temperature 

was about 5 “F higher than optimum to avoid ash 

buildup on the steam reheaters. Atom&d water droplet 

size was smaller than optimum for the same reason. 

Other key process parameters held constant during the 

long-tam tests included the degree of humidification, the 

grind size of the high-calcium-content limestone, and 

recycle of spent sorbent from the ESP. 

Long-term testing showed that SO, reductions of 

70% or more can be maintained under normal boiler 

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

and ESP efficiency was high (99.2%). The quantity of 

solid waste, which is a mixture of fly ash and calcium 

compounds, equals the amount of limestone injected. 

ESP and LIFAC fly ash were readily disposed of at the 

same local landfill 

The LIFAC system proved to be highly operable 

because it has few moving parts and is simple to operate. 

The process can be easily shutdown and restarted. The 

process is automated by a programmable logic system, 

which regulates process control loops, interlocking, startup, shut downs, and data collection. The entire LIFAC 

process was easily managed via hvo personal computers 

located in the host utility’s control room. 

The economic evaluation indicated that the capital 

cost of a LIFAC installation is lower than both spray 

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

reactors needed: 

* $99/kW for one LIFAC reactor at Whitewater Valley 

Station (65 MWe) 

* $76/kW for one LIFAC reactor at Shand Station 

(150 MWe) 

* $66lkW for two LIFAC reactors at Shand Station 

(300 MWe) 

Crushed limestone accounts for about one-half of 

LIFAC’s operating costs. LIFAC requires 4.3 tons of 

limestone to remove 1 ton of SO,, assuming 1.5% SO, 

capture, a Ca/S of 2.0, and limestone containing 95% 

&CO,. If limestone costs %15/tori,,” then the gperating 

cost is $65/tori of SO2 removed. 

Commercial Applications: 

This process is suitable for application to all coal-fired 

utility or industrial boilers, especially those with tight 

space limitations. The LIFAC process is less expensive 

to install than conventional wet flue gas desulfurization 

processes, uses dry limestone instead of more costly 

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

readily disposable waste, and can handle all trpes of 

COd. 

The benign waste material can be disposed of in a 

landtill along with the fly ash. Commercial use of the 

LIFAC by-product in the manufacture of construction 

materials is currently being investigated in Finland. 

Project Schedule: 

DOE selected project (CCT-III) 12119189 

Cooperative agreement awarded I1120190 

NEPA process completed (MTF) 10/2/90 

Environmental monitoring plan completed 6112192 

Construction 5/91-6/92 

Operational testing 9192-6194 

Project completed 3195 

Final Reports: 

Final Technical Report 3195 

Economic Evaluation Report 3195 

Public Design Report 3/95 

Environmental Control Device.~ Program Update 1994 7-59 
Advanced Flue Gas 

Desulfurization 

Demonstration Project 

Participant: 

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

Air which is a general partnership between Air Products 

and Chemicals, Inc., and Mitsubishi Heavy Industries 

America, Inc.) 

Additonal Team Members: 

Northern Indiana Public Service Company-cotimder 

and host utility 

Mitsubishi Heavy Industries, Ltd.-p&as designer 

United Engineers and Constructors (Steams-Roger 

Division)-facility designer 

Air Products and Chemicals, Inc.--constructor and 

Location: 

Chesterton, Porter County, IN (Northern Indiana Public 

Service Company’s Bailly Generating Station, Units 7 

and 8) 

Technology: 

Pure Air’s advanced flue gas desulfuization (AFGD) 

process (environmental control devices/SO, control 

technologies) 

Plant Capacity/Production: 

528 MWe 

Project Fundlng: 

Total project cost $151,707,898 100% 

DOE 63,913,200 42 

Participants 87,794,698 58 

POwerChip is a trademark OfPure Air on the Lake, L.P 

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. Additionally, the absorber is of a cocurrent design, in which the 

flue gas and scrubbing slurry move in the same direction 

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

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

less expensive than conventional scrubbers. 

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

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

air rotary sparger combines the functions of 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 90695% or more of the SO, while providing a 

commercial gypsum by-product in lieu of solid waste. 

Some of the by-product gypsum is being agglomerated 

and flaked into PowerChipTM gypsum to enhance its 

7-60 Program Update 1994 Environmentnl Control Devices 
Calendar Year 

1988 1989 1990 1991 ,992 1993 1994 1995 1996 1997 ,998 

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

Proim completed/final repod issued Q/95’ 

I 

Operation initiated 6192 

Preoperational tests initiated 392 

bperath completed W95’ 

I knvironnwntal monitoring plan completed 1/M/91 

Ground breakinQkons.truction staned 4/20/90 

NEPA process completed (EA) NW90 

Coooerative awsement awarded 12/2OlQQ 

+Projected date 

transportation and marketability to gypsum end-users. 

Additionally, wastewater treahnent is being 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. Afier the 3-year demonstration period, 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 52X-MWe Bailly Generating Station near 

Chesterton, IN, and testing bituminous coals containing 

24.5% sulfw. 

Project Ststus/Accompllshments: 

Operational testing continued through 1994. Tests on 

the utility’s standard coal (3-3.5% sulfur) were completed in 1992. During 1993, tests were conducted on 

Environmental Control Devices 

coals with 3.511% sulfur and X5-3% sulfur. In 1994, 

tests were completed on coals with +4.5% sulfur and 

2-2.5% sulfur. The scrubber is achieving SO, removals 

in excess of 95% while producing a commercial gypsum 

by-product with an average purity level of 97%. Smooth 

operation continues, and performance continues to be 

very good. 

As of the end of November 1994, the AFGD facility 

had accumulated almost 22,000 hours of operation with 

an availability of P&99% and 100% reliability. Approximately 181,500 tons of SO, have been removed and over 

501,000 tons of gypsum produced. 

Commercial Applications: 

The AFGD process is attractive for both new and retrofit 

utility applications. The demonstration project is using 

bituminous coals primarily from the Indiana-Illinois coal 

basin, with sultixcontent ranging from 2.0% to 4.5%. 

The AFGD facility will reduce SO, emissions at the 

Bailly St&ion by approximately 75,000 tons/yr. Further, 

the gypsum by-product and wastewater evaporation will 

demonstrate that SO, control can occw 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. 

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

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

capability at Florida Power & Light Company’s Manatee 

power plant, on an own-and-operate basis. The Manatee 

scrubber will feature two 800 MWe absorber vessels, 

PowerChipTM gypsum recycling, and wastewater 

evaporation. 

Program Update 1994 7.61 
Demonstration of Innovative 

Applications of Technology 

for the CT-121 FGD Process 

Participant: 

Southern Company Services, Inc. 

Additional Team Members: 

Georgia Power Company-host utility 

Electric Power Research Institute--c&under 

Radian Corporation~nvironmental and analytical 

co”s”lt”“t 

Ershigs, Inc.-fiberglass fabricator 

University of Georgia Research Foutidationby-product utilization studies 

Location: 

Newnan, Coweta County, GA (Georgia Power 

Company’s Plant Yates, Unit No. I) 

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 MWc 

Project Funding: 

Total project cost %43,074,996 100% 

DOE 21,085,211 49 

Participants 21,989,785 51 

Project Objective: 

To demonstrate the CT-121 flue gas desulfurization 

system, including several design innovations, at the 

lOO-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 Update 1994 

COAL 

1 

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 sultite (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 tilling a dyked area 

with gypsum slurry. Gypsum solids settle in the dyked 

area by gravity, and clear water flows to a retention pond. 

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

The project is also evaluating process innovations to 

determine whether costs can be reduced further by using 

iiberglass-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 paniculates simultaneously is also being evaluated. 

A nominal 2.5% sulfur bituminous coal is being 

used ta demonstrate 90% SO, control with high~reliability, with and without simultaneous particulate control. 

Project Status/Accomplishments: 

Parametric testing was completed in March 1993, and 

long-ten” testing began in May 1993. DOE-sponsored 

Environmental Control Devices 
Calendar Year 

1988 1989 1990 1991 ,992 1993 1994 1995 ,996 ,997 1998 

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

] ’ pTkr * /lIz”?J4193 ] 

Constr"ction completed lo/92 

[ 

Final repolt on operations issued 12/95 

DOE selected project 

(COT-I,) Q/28/88 Ground breakingiconstruction Operation completed 1195 

Started 8,23,90 Preoperational tests initiated 5,92 

Cooperatiye agreement awarded 4/Z/90 ‘Projected date 

air-toxics testing was done in June 1993. Alternate the CT-121 system’s SO, removal ranges between 93% (5) more than 99% of the calcium in the limestone relimestones were tested in December 1993. and 98% at all loads and conditions at expected pH and agent is used; (6) the gypsum by-product can be stored 

In 1994, tests were conducted on high-sulfur coal pressure drop with 100% limestone utilization. Particu- safely and easily or used in commercial applications; 

(X5%), compliance coal (1.5%) and low-sulfur coal 

(1.35%). The CT-121 process successfully removed the 

SO, from the higher sulfur test coal. The ESP was 

deenergized in stages in 1994 for the last year of operation to evaluate the particulate removal capability of the 

scrubber. The scrubber effectively removed the particulate, indicating that an ESP probably would not be 

needed when the process is used for SO, control. 

Ash/gypsum product is being diverted to the northem-most disposal cell for segregation from pure gypsum 

Growth studies on pure gypsum continue on the now 

inactive, clean gypsum stack. 

The demonstration has exceeded all of its performance goals. By the end of 1994, over 12,000 hours of 

successful operations had been logged. Availability has 

been 98% and reliability has exceeded 99%, confirming 

the acceptability of the use of tiberglass as a rextoT 

vessel material. At inlet SO, levels of about 2,000 ppm, 

Environmental Control Devices 

late removal has exceeded 99%. 

The project received two awards in 1994: Power 

Magazine > 1994 Powerplant Award and an Outstanding 

Achievement Award from the Georgia chapter of the Air 

and Waste Management Association for the use of an 

innovative technology for air quality control. In 1993, 

Plant Yates received an environmental award from the 

Georgia Chamber of Commerce, based on the wxess of 

the CT-121 scrubber. 

Commercial Applications: 

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

pre-NSPS utility and industrial boilers 

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

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 necessmy; 

(4) both SO, and particulates are removed from flue gas; 

(7) the CT-121 operating costs are the lowest for state-ofthe-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-tired generating CBpacity, is expected to enhance the confidence of other 

large, high-s&w 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/ 

yr ofpotential SO, control. 

In 1994 a tar sands oil extraction facility in Murray, 

Canada, purchased the CT-121 scrubber. 

Program Update 1994 7.63 
SNOXTM Flue Gas Cleaning 

Demonstration Project 

Participant: 

ABB Environmental Systems 

Additional Team Members: 

Ohio Coal Development Off~ce+ofinder 

Ohio Edison Company--cofunder and host utility 

Haldor Topsoe al-patent owner for process technology, 

catalysts, and WSA Tower 

Snamprogetti, U.S.A.*otimder and process designer 

Location: 

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

Station, Unit No. 2) 

Technology: 

Haldor Topsoe’s SNOXTM catalytic advanced flue gas 

cleanup system (environmental control devices/combined 

SOJiVOx control technologies) 

Plant Capacity/Production: 

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

Project Funding: 

Total project cost $31,438,408 100% 

DOE 15,719,200 50 

Participants 15,719,208 50 

Project Objective: 

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

that SNOXTM technology will catalytically remove 95% 

of SO, and more than 90% ofNOx from flue gas and 

produce a salable by-product of concentrated sulfuric 

acid. 

Technology/Project Description: 

In the SNOXTM 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 NO% 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 sulfwic acid. 

The technology, while using US. coals, is designed 

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

NOI 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 was conducted at Ohio Edison’s 

Niles Station in Niles, OH. The demonstration unit 

treated a 35-MWe equivalent slipstream of flue gas from 

the l08-MWe Unit No. 2 boiler which burned a 

3.4%sulfur Ohio coal. The process steps were virtually 

the same as for a commercial full-scale plant, and commercial-scale components were installed and operated. 

7.64 Program Update 1994 Environmental Control Devices 
i : / : ‘, i ,, ., ” 2: :,;-;:.‘).,,,rill~;‘.,.;-,;r ,,. ~,.~‘, 

Project Results/Accomplishments: 

Operational testing was initiated in March 1992 and 

completed in December 1994. The system has operated 

for over 7,800 hours and produced more than 5,400 tons 

of commercial-grade sulfuric acid. The facility has routinely operated at full capacity, achieving removal efIiciencies of 96% for SO,, 94% forNOx, and 99.9% for 

particulates. 

Many tests for the SNOXTM system were designed 

to be conducted at 75%, 100%. and 110% of design 

capacity During the test program, SO, removal &cienties were normally in excess of 95% for inlet concentrations which averaged about 2,000 ppm. System NO% 

reduction efficiencies averaged 94% with inlet NOx 

levels of approximately 500-700 ppm. 

Sulfuric acid concentrations and composition have 

met or exceeded federal specifications for class I acid. 

The acid from the plant has been sold to the agriculture 

industry for the production ofdiammonium phosphate 

fertilizer and to the steel industry for pickling. Ohio 

Edison has used a significant amount in its boiler water 

demineralizer system throughout its plants. 

Air toxics testing at the plant indicated that, for the 

majority of the species examined, especially those that 

exit primarily as particulates at the SNOX” fabric filter 

or SNOX”“’ outlet, removal is very high. Because of the 

mechanism of sulfuric acid condensation in the WSA 

condenser, any paniculates remaining at this point act as 

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

lower than conventional boiler outlet temperatures and 

should condense and capture more of the volatile species 

than a plant with only an ESP or fabric filter. 

The economic evaluation of the SNOXiM process 

showed a capital cost of approximatley $25O/kW and a 

total operating cost of approximatley I.3 millsfkWh. 

Commercial Applications: 

The SNOXTM technology is applicable to all electric 

power plants and industrial/institutional boilers firing 

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

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. 

The host utility, Ohio Edison, is retaining the 

SNOXTM technology as a permanent part of the pollution 

control system at Niles Station and to help Ohio Edison 

meet its overall SO,lNOx reduction goals. 

Commercial SNOXTM plants also have been started 

up in Denmark and Sicily. In Denmark, a 305-MWe 

plant has been designed and constructed; it has operated 

since August 1991. The boiler at this plant bums coals 

from Vanbus suppliers around the world, including the 

United States; the coals contain 0.5-3.0% sulfur. The 

plant in Sicily, operating since March 1991, has a capw 

ity ofabout 30-MWe and fires petroleum coke. 

Project Schedule: 

DOE selected project (CCT-11) 9128188 

Cooperative agreement awarded 12/20/89 

NEPA process completed (MTF) 1131190 

Environmental monitoring plan completed IO/31191 

Construction 1191-12191 

Operational testing 3192-12194 

Project completed 3195 

Final Reports: 

Final Technical Report 3195 

Economic Evaluation Report 3195 

Public Design Report 3195 

Environmental Control Devices Program Updm 1994 7-65 
LIMB Demonstration Project 

Extension and Coolside 

Demonstration 

Project com/h?ted. 

Participant: 

The Babcock & Wilcox Company 

Additional Team Members: 

Ohio Coal Development Oftice--cofunder 

Consolidation Coal Company&ofunder and technology 

supplier 

Ohio Edison Company-host utility 

Location: 

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

Technology: 

The Babcock & Wilcox Company’s limestone injection 

multistage burner (LIMB) system; Babcock & Wilcox 

DRB-XCLe low-NO” burners 

Consolidation Coal Company’s Coolside duct injection 

of lime sorbents 

(environmental control devices/combined SO,lNOx 

control technologies) 

Plant Capacity/Production: 

105 MWe 

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

sorbent injection upstream of the humidifier and precipitator and to show SO, removal of up to 70%. 

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, 

Technology/Project Description: 

The LIMB process reduces SO, by injecting dry sorbent 

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

then travels through the boiler and is removed along with 

fly ash in an electrostatic precipitator (ESP) or baghouse. 

Humidification of the flue gas before it enters an ESP is 

necessary to maintain normal ESP operation and to enhance SO, removal. Combinations of three eastern bituminous coals (1.6%, 3.0%, and 3.8% sulfw) and four 

sorb&s wre tested. Other variables examined were 

stoichiomehy, humidifier outlet temperature, and injection level. 

In the Coolside process, dry sorbent is injected into 

the flue gas downstream of the air preheater, followed by 

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 eastern bihnninous coal with 3.0% sulfur was used in testing. 

The same low-NOx burners (Babcock & Wilcox 

DRB-XCLW low-NO” 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 105MWe boiler. 

DRB-XCL is a registered trademark orThe Babcack 81 Wilcox Company 

7-66 Program Update 1994 Environmental Control Devices 
/ 

I 

., ,, ., , ,,, 

Project Results!Accompllshments: 

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

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 conductcd under minimal humidification, defined as operation at a humidifier outlet temperature sufficient to maintain ESP performance. That temperature was typically 

250-275 “F. Tests were also conducted at a 20 “F approach to the adiabatic saturation temperature of the flue 

gas to enhance SO, removal of the LIMB system. Closeapproach operation typically meant controlling the flue 

gas temperature at the humidifier outlet (ESP inlet) to 

about 145 “F. Other variables were stoichiometq and 

injection Icvel. Highlights of reported test results follow: 

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

concentration in the flue gas, affected SO, removal 

efficiency-the higher the sulfur content, the greater 

the SO, removal for a given sorbent at a comparable 

stoichiometty. A5-7% increase in removal occurred 

when switching to 3.X% from 1.6% sulfur coal and 

injecting at a stoichiometry of 2.0. 

The highest sulfur removal efficiencies, without 

humidification to close approach, were attained using 

the ligno lime--61% SO,removal was achieved 

while burning 3.8% sulfur coal. All sorb&s 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 efftciencies of about 32% were achieved 

. 

at a stoichiometry of 2.0 when using a limestone with 

all particles less than 44 microns. For a third limestone with essentially all particles less than IO microns, the removal effkiency 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-A plant elevation level 

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

the highest SO2 removal rates. Here, the sorbent was 

injected at close to the optimum furnace temperature 

of 2,300 “F. 

SO, removal efficiencies were enhanced by about 

10% over the range of stoichiometries tested when 

humidification down to a 20 “F approach to saturation 

was used. 

During the Coolside demonstration, compliance 

(l.2-1.6% sulfur) and noncompliance (3.0% sulfur) 

coals were burned. Key process variables-CaiS, 

N&a, and approach to adiabatic saturation-were 

evaluated in short-term (k-8.br) parametric tests and 

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

The Coolside process routinely achieved 70% SO, 

removal at design conditions (2.0 US, 0.2 N&a, and 

20 “F approach to adiabatic saturation temperature) using 

commercial hydrated lime. SO, removal depended on 

Ca’S, NaJCa, approach to adiabatic saturation, and the 

physical properties of the hydrated lime. Sorbent recycle 

showed signiticant potential to improve sorbent utilization. Observed SO, removal with recycle sorbent alone 

was 22% at 0.5 available Ca/S and IX OF approach to 

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

fresh Ca/S, 0.2 fresh Na/Ca, 0.5 available recycle, and 

I8 “F approach to adiabatic saturation. 

NO” removal was in the 4&50% range throughout 

both LIMB and Coolside testing. 

1 ~,. ~ - ,/ ,, ,.~. .: ,. ,,..,, 

Commercial Applications: 

Both LIMB and Coolside technologies are applicable to 

most utility and industrial coal-fired units and provide 

alternatives to conventional wet flue gas desulfurization 

(FGD) processes. They can 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% sulfix coal at a 65% plant 

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

220 MWe. The environmental benefits for LIMB are 

4%50% lower NOx and more than 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 tuneacted lime that has potential 

commercial application. Both processes have the ability 

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

coals. 

Project Schedule: 

DOE selected project (CCT-I) 7124186 

Cooperative agreement awarded 6125187 

NEPA process completed (MTF) 612187 

Environmental monitoring plan completed 10/19/88 

Construction 8187-9189 

Coolside operational testing 7/89-2/90 

LIMB extension operational testing 4190-819 I 

Project completed II192 

Final Reports: 

Final Report (LIMB/Coolside) II/92 

Topical Report (Coolside) 2192 

Topical Report (LIMBiCoolside) 9190 

Public Design Report 12188 

Ewironnrental Canfrol Devices .%grm Update 1994 7-67 
SOx-NOx-Rox-BoxTM Flue Gas 

Cleanup Demonstration 

Project 

Project completed. 

Participant: 

The Babcock & Wilcox Company 

Additional Team Members: 

Ohio Edison Company-cofunder and host utility 

Ohio Coal Development Offlce---cofunder 

Electric Power Research Institute-z&under 

Norton Company+o&mder and SCR catalyst supplier 

3M Company--cofunder 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 Babcock & Wilcox Company’s SOx-NOx-RoxBoxrM (SNRBTM) process (environmental control devices/combined SO,iNOx 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 a single processso*-Piox-Rex-Box and SNRB are trademarks OfThe Babcock 8.. 

WilcoxCompa”y. 

7-68 Program Update 1994 

t 

*an “I” 

SURFACE 

aOTrOM 

ASH 

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

space requirements and capital costs. 

Technology/Project Description: 

The SNRBTM 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 ammonia to selectively reduce NO1 in the presence of a selective catalytic reduction, or SCR, catalyst. Particulate 

removal is accomplished by high-temperature fiber bag 

filters. 

The S-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 ofperformance 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% NOx removal, and 99% particulate 

removal at lower capital, operating, and maintenance 

costs than a combination of conventional systems. The 

demonstration was conducted at Ohio Edison Company’s 

R.E.Bur ger 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. 

Environmental Control Devices 
Project Results/Accomplishments: 

SNRBTM 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 wastested. 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 NO+ ammonia was injected between 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 Cal.? ratio of 2, 

and with the baghouse temperature between 800 and 

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

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

NH,MOx ratio of 0.9, the reduction in NOx 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 forparticulates. Particulate emissions averaged 0.018 lb/million 

Btu (0.009 grainsistd ft’), corresponding to a collection 

efficiency of99.89%. 

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 Na/S was increased from I to 2. 

All of the demonstration tests were conducted using 

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

Environmental Control Devices 

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

carried out at air-to-cloth ratios of 34 tUrnin. No excessive wear or failures occurred in over 2,000 hours of 

elevated temperature operation. 

A preliminary evaluation has been made of the 

projected capital cost of the SNRBN system for various 

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

sulfur coal and generating NOx emissions of 1.2 Ibs/ 

million Btu, the projected cost of a SNRBTM system is 

approximately $26OikW 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 

$360400/kW. 

Commercial Applications: 

Commercial application of the technology offers the 

potential for significant reductions of multiple pollutants 

from fossil-tired 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. SNRB” is capable of reducing emissions from plants burning high- or lowsulfur coal. In retrofit applications, SNRBTM provides a 

means of improving particulate emissions control with 

the addition of SO, and NOx emissions control capacity. 

Commercialization of the technology is expected to 

develop with an initial larger scale application equivalent 

to 50-100 MWe. The focus ofmarketing efforts will be 

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

retrofit and new plant construction. SNRBTM 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. 

Project Schedule: 

DOE selected project (CCT-II) 

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 

9/28/88 

9122189 

12/20/89 

S/91-12/91 

12/31/91 

5192-5193 

5195 

5195 

early 1995 

11192 

Program Update I994 7.69 
Enhancing the Use of Coals 

by Gas Reburning and 

Sorbent Injection 

Project completed. 

Participant: 

Energy and Environmental Research Corporation 

Additional Team Members: 

Gas Research Institute--cofunder 

State of Illinois, Department of Energy and Natural 

Resources--ilofunder 

Illinois Power Company-host utility 

City Water, Light and Power-host utility 

Locations: 

Hennepin, Putnam County, IL (Illinois Power 

Company’s, Hennepin Plant, Unit 1) 

Springfield, Sangamon County, IL (City Water, Light 

and Power’s Lakeside Station, Unit 7) BOTTOM ASH 

Technology: 

Energy and Environmental Research Corporation’s gas 

rebuming and sorbent injection process (environmental 

control devices/combined SO,lNOx control technologies) 

Plant Capacity/Production: 

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

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

rations--a tangentially tired, 80.MWe (gross) boiler at 

Illinois Power Company’s Hennepin Plant in Hennepin, 

IL, and a cyclone-fired, 40-MWc (gross) boiler at City 

Water, Light and Power’s Lakeside Station in Springfield, IL. Illinois bituminous coal containing 3% sulfur 

was the test coal for both Hennepin and Lakeside. 

Project Funding: 

Total project cost 

DOE 

Participants 

$37,588,955 100% 

18,747,X16 50 

18,841,139 50 

Technology/Project Description: 

In this process, SO-85% of the fuel is coal and is supplied to the main combustion zone. The remaining 15- 

20% of the fuel, generally natural gas or 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, tine particulates 

above the rebuming zone in the boiler or even further 

downstream. The calcium compound tested is Ca(OH), 

(lime). The goal was to achieve at least 60% NOx reduction and at least 50% SO, reduction on different boiler 

configurations at power plants burning highadfur 

midwestem coal. This project demonstrated the gas 

rebuming and sorbent injection GR-SI process on two 

separate boilers representing two different tiring contiguProject Results/Accomplishments: 

Project Objective: 

To demonstrate gas rebuming to attain 60% NOx reduction along with sorbent injection to capture 50% of the 

SO, on two different boiler configurations: tangentially 

tired and cyclone-tired 

A matrix of 32 gas rebum tests were completed on 

the tangentially tired boiler at the Hennepin Plant. NOx 

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

routine--exceeding the project objective of 60%. Evaluation of 20 over-fire air tests indicated substantial NOx 

reduction was achievable at low power generation loads, 

with lesser reductions as load increased. Sorbent injection reduced SO, emissions as much as 62%, with 52% 

7- 70 Program Update 1994 Environmental Control Device.y 
reduction being routine-also exceeding the project 

objective of SO%. The Ca/S was about 1.75. 

Three proprietary sorbents (including PromiSorb A, 

PromiSorb B, and high surface area hydrated lime) were 

also tested at Henncpin. The sorb&s showed higher 

SO, capture and higher calcium utilization than the 

regular hydrated lime. 

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

emissions as well as NOx and SO,. During sorbent 

injection, particulate emissions were reduced by flue gas 

burniditicatian upstream of the ESP 

A total of 25 sorbent injection parametric tests to 

isolate the effects ofthe sorbent on boiler performance 

and operability were completed. Tests indicated that SO, 

reduction level varied with load because of the effect of 

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

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

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

(20 MWe), 32% reduction at Lakeside. 

The system installed at Hennepin operated for more 

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

rebuming; 115 hours, sorbent injection; and nearly 

760 hours, combined operation (the remainder was 

baseline testing). 

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

rebuming fuel injection nozzles based on the results of 

the initial gas rebuming parametric tests. Tests did not 

indicate any adverse effect of the change in the thermal 

profile. SO, reductions of over 50% could be achieved 

with Ca/S greater than 1.25 along with gas heat inputs of 

22-25%. The total SO, reduction from the combined 

effect of fuel replacement and sorbent injection exceeded 

the project goal of 50% reduction. 

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 hvo technologies can be applied to over 900 

pre-NSPS utility boilers; the technologies also can be 

applied to new utility boilers. With NO” and SO* removal exceeding 60% and 50%, respectively, these technologies have the potential to extend the life ofa boiler 

or power plant and also provide a way to use higher 

sulfur coals. 

After reviewing the operational performance, boiler 

impact, and economics, Illinois Power, the host utility, 

has chosen to retain the gas-rebut&g portion of the gasrebuming and sorbent injection system for possible use 

in 1995 for NOx control. 

Parametric testing on the cyclone boiler at the 

Lakeside Station was conducted in three series: gas 

rebutting parametric testing, sorb& injection parametric testing, and GR-SI optimization tests. The goal of 

the parametric test series was to define the optimum 

GR-SI operating conditions with minimal degradation of 

the thermal performance of the boiler and to evaluate the 

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

The primary goal of the long-term testing was to 

operate GR-SI during the normal operating cycle of the 

Lakeside unit. The unit typically operated in cycling 

service with a very low capacity factor, so testing was 

conducted whenever the unit was operated. The average 

NO” reduction was 61% after a total of 249 hours of gas 

rebuming operation. The average SO, reduction atkr 

22 1 hours of GRSI operation was 58%. During GR-SI 

operation there was a 0.8% drop in thermal efficiency 

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

flue gas temperature. 

A total of 100 gas rebuming parametric tests were 

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

20 MWe. The rebnm parametric tests achieved NO% 

reduction levels either at or just marginally above the 

60% reduction goal. Additional flow mod&g and 

computer modeling studies indicated that smaller 

rebuming fuel jet nozzles could increase rcbuming fuel 

mixing and improve NOz reduction performance. 

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

continuous run, a 115-hr OR-only continuous run, and a 

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

variable load met the project goals of 60% NOx reduction 

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

impacts were observed. Compliance test results for 

particulate emissions averaged 0.016 lb/million Btu, well 

below the limit of 0.1 lb/million Btu. 

Project Schedule: 

DOE selected project (CCT-I) 7/24186 

Cooperative agreement awarded 7114187 

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

Environmental monitoring plan completed, 

Hennepin 10/15/89 

Lakeside 11/15/89 

Construction, Hennepin 5/89-S/91 

Operational testing, Hetmepin l/91-1/93 

NEPA process completed, Lakeside (EA) 6125189 

Constntction, Lakeside 6190-5192 

Operational testing, Lakeside 5193-10194 

Restoration completed 10195 

Project completed 12195 

Flnel Reports: 

Final Technical Report, Hennepin I o/94 

Final Technical Report, Edwards 10/94 

Final Technical Report, Lakeside 5195 

Economic Evaluation Report 7/95 

Public Design Report 7195 

Environmental Control Devices Program Update 1994 7-71 
Milliken Clean Coal 

Technology Demonstration 

Project 

Participant: 

New York State Electric & Gas Corporation 

Additional Team Members: 

New York State Energy Research and Development 

Administration+ofunder 

Empire State Electric Energy Research Corporationcofunder 

Consolidation Coal Company-technical consultant 

Saarberg-HGlter-Umwel~echnik, GmbH-technology 

supplier 

The Stebbins Engineering and Manufacturing 

Company-technology supplier 

NALCO Fuel Tech-technology supplier 

ABB Air Preheater, Inc.-technology supplier 

DHR Technologies, Inc.--operator advisor system 

Location: 

Laming, Tompkins County, NY (New York State Electric & Gas Corporation’s Milliken Station, Units 1 

and 2) 

Technology: 

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

limestone scrubber technology; ABB Combustion 

Engineering’s Low-NOx Concentric Firing System 

(LNCFS) Level III; NALCO Fuel Tech’s NOxOUT urea 

injection system; Stebbins’ tile-lined split-module 

absorber; and ABB Air Preheater’s heat-pipe air-heater 

system (environmental control devices/combined 

SO,lNOx control technologies) 

7.72 Program Update I994 

Plant Capacity/Production: 

300 MWe 

Project Funding: 

Total Project Cost $158,607,807 100% 

DOE 45,000,000 28 

Participant Il3,607,807 72 

Project Objective: 

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

and efficiency improvement technologies, including the 

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

increase SO, removal in a Stebbins lined scrubber, urea 

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

Technology/Project Description: 

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

formic-acid-enhanced, wet limestone process which 

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

gypsum. 

The flue gas desulfixization absorber is a Stebbins 

tile-lined split-module vessel which has superior corm 

sion 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. 

The NALCO Fuel Tech NOxOUT system is being 

used to remove NOx by the injection of urea into the 

boiler gas. This facet ofthe project, in conjunction with 

other combustion modifications, including LNCFS Level 

Environmental Control Devices 
Calendar “ear 

1991 1992 1993 1994 1995 1995 1997 1998 1999 2coo 2001 

341234 1234 1 234 1 234 1 2 3 4 7234 1 234 1 2.34 1 234 12 

Project completeditinal report issued 8198 

NEPA process completed 

(EA) 9/18/93 

Preoperational test.3 initiated 4195’ 

Construction completed 3/95 

Ground breakin@onstruction started 4193 

Design com,Med 419.3 

Cooperative agreement awarded IO/20192 ‘Projected date 

111 (low-NOx burner system), will reduce NOx emissions 

and produce marketable fly ah. 

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. DHR Technologies, Inc., will 

provide a state-of-the-art boiler and plant artificial-intelligence-based control system. Ultimate emissions reductions with increased boiler efficiencies will result. 

The project is designed for “total environmental and 

energy management,” a concept encompassing low 

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

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

SO, removal efficiency (or up to 98%) using limestone 

while burning high-sulfurcoal. NO” reductions will be 

achieved using selective non-catalytic reduction technology and separate combustion modifications. NO, emissions have been reduced from 0.65 to 0.40 lb/million Btu 

(23%) by retrofitting the two boilers with low-NO” bumers. NOxOUT is expected to reduce NO” emissions from 

Unit 2 by an additional IS-20%. The system has zero 

wastewater discharge and produces marketable by-products (e.g., cummercial-grade gypsum, calcium chloride, 

and fly ash), minimizing solid waste. 

New York State Electric & Gas is demonstrating 

these technologies at Units 1 and 2 of its Milliken 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: 

Conshuction has stayed 2-3 months ahead of schedule. 

Hydra testing of the scrubber began in November 1994, 

with passage of flue gas in December 1994. Equipment 

shakedown and start-up will begin in IanuatyiFebmary 

1995. Baseline and preoperational testing is expected to 

commence in April 1995, with full-scale operation beginning in July and mnning for the next 3 years. 

Commercial Applications: 

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

non-catalytic reduction process, Stebhins’ 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 

greentield applications of virtually any megawatt size is 

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

SOI and up to 30% beyond combustion modifications for 

NOx, will make the combination of these technologies 

attractive. 

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

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

offer significant incentives to generating stations with 

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

effXency of the combined technologies minimizes any 

secondary environmental impacts from the operation of 

pollution control equipment. 

L-*..i.“..m”“d c-,m,t.“l n0vire.q Program Update 1994 7.73 
Commercial Demonstration of 

the NOXSO SOJNOx Removal 

Flue Gas Cleanup System 

Participant: 

NOXSO Corporation 

Additional Team Members: 

ALCOA--cofunder 

W.R. Grace and Company--cofunder 

Gas Research Institute--cc&under 

Electric Power Research Institute--cotinder 

Location: 

Newburgh, Warwick County, IN (Alcoa Generating 

Company’s Warrick Power Plant, Unit 2) 

Technology: 

NOXSO Corporation’s dry, regenerable flue gas cleanup 

process (environmental control devices/combined 

SO,iNOx control technologies) 

Plant Capacity/Production: 

144 MWe (net) 

Project Funding: 

Total project cost $67,181,325 100% 

DOE 33,506,012 50 

Participants 33,675,313 50 

Project Objective: 

To demonstrate removal of 98% of the SO, and 70% of 

the NO” from a coal-tired boiler’s flue gas using the 

NOXSO process. 

COAL 

AIR 

Technology/Project Description: 

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

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

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

tluidized-bed adsorber located downstream of the precipitator; the SO, and NO” are adsorbed by the sorbent. 

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

cleaned flue gas then passes through a baghouse to the 

stack. 

to produce an offgas with high concentrations of SO, and 

erator where it reacts with methane at high temperature 

hydrogen @tide (H,S). This offgas is processed to 

produce elemental sultiz The elemental sultiu will be 

processed further to produce liquid SO,, a higher valued 

by-product. 

The process is expected to achieve SO, reductions of 

98% and NO1 reductions of 70%. 

The NOXSO Corporation is demonstrating a fullscale commercial NOXSO unit on a 144.MWe (net) 

cyclone boiler at Alcoa Generating Company’s Warrick 

Power Plant, Unit 2, in Newburgh, IN. The fuel coal is 

Indiana bituminous coal containing an average of 3.3% 

sulfur. Data from the proof-of-concept facility at Ohio 

Edison Company’s Toronto Station is being incorporated 

into the plant design. 

The NOx is desorbed from the NOXSO sorbent 

when heated by a stream of hot air. The hot air containing the desorbed NO” is recycled to the boiler where 

equilibrium processes cause deshuction of the NOx. The 

adsorbed sulfur is recovered from the sorbent in a regen7-74 Program Update I994 Environmenfal Control Devices 
Calendar Year 

1989 ,990 1991 1992 1993 1995 1998 ,997 1998 1999 

34123412341 2 3 4 1 234 1 :“, 4 1 234 1 234 1 2 3 4 1 234 12 

12l89 3191 12/96 4I99 

bperation initiated 1 Z/96’ 

Preoperational tests initiatsd 9/W 

Construction complet*d lx/96 

Construction started V3.5’ Operation completed I Z/9/98 I besign completed G/95’ Project completed/ 

NEPA process completed (EA) 6/95’ final report issued I I Cooperative agreement awarded 311191 II Environmental monitoring plan completed 6/95’ 4l99’ 

bOE selected project (CCT-III) 12/19,89 I’ Prolect definition phase completed 10194 

I 

Novatim of cooperative agreement with NOXSO Corp. *4 

Selscted new host sita 8194 

‘Projected date 

Project Status/Accomplishments: 

A new project site was identified in 1996Alcoa Generating Company’s Wanick Power Plant Unit 2. The 

proof-of-concept, pilot-plant testing, which proceeded in 

parallel with the project definition phase of the demonstration project, is complete. The test results from the 

proof-of-concept and pilot plant exceed the expected 

goals. These results will be used for the scale-up design 

for the full-size commercial unit. 

The NEPA process is well under way. Preliminary 

process flow diagrams, piping and instrumentation diagrams, equipment specifications, and plant arrangement 

drawings have been prepared. 

Commercial Applications: 

The NOXSO process is applicable for retrofit or new 

facilities. The process is suitable for utility and industrial coal-tired boilers of 75 MWe or larger. A highsulfur coal is being used in the demonstration; however, 

the process is adaptable to coals with any sulfur content. 

The process produces one of the following as a 

salable by-product: elemental sulfur, sulfuric acid, 

or liquid sulfur dioxide. A readily available market 

exists for these products. 

The technology is expected to be especially 

attractive to utilities that require high removal 

efficiencies for both SO, and NOx and/or need to 

eliminate solid wastes. 

Environmental Control Devices Program Update 1994 7- 75 
Integrated Dry NOJSO, 

Emissions Control System 

Participant: 

Public Service Company of Colorado 

Additional Team Members: 

Electric Power Research Institute--cofUnder 

Stone and Webster Engineering Corp.--engineer 

The Babcock & Wilcox Company-burner developer 

Fossil Energy Research Corporation-operational 

testing 

Western Research Institute-tlyash 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 DRB-XCL” lowNOx burners, in-duct sorbent injection, and furnace 

(urea) injection (environmental control devices/combined 

SO,/NOx control technologies) 

Plant Capacity/Production: 

100 MWe 

Project Funding: 

Total project cost S27,411,462 100% 

DOE 13,705,731 50 

Participants 13,705,731 SO 

Project Objective: 

To demonstrate the integration of three technologies to 

achieve up to 70% reduction in NOx and SO, emissions; 

ORB-XL is a registered trademark OfTtllhe Babed & WikOX company 

7.76 Program Update 1994 

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

additional NO” removal and dry sorbent in-duct injection 

with humidification for SO, removal. 

Technology/Project Description: 

All of the testing is using Babcock & Wilcox’s low-NO” 

DRB-XCLm down-fired burners with aver-tire air. These 

burners control NOx by injecting the coal and the combustion air in an oxygen-deficient environment. Additional air is introduced via over-fire air ports to complete 

the combustion process and further enhance NO” removal. The low-NO” burners are expected to reduce NOx 

emissions by up to 50%, and, with added air, by up to 

70%. To reduce NOx emissions even further, in-furnace 

urea injection is being tested to determine how much 

additional NOx can be removed from the combustion gas. 

Two types of dry sorbents are being injected into the 

ductwork 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 ofthe dry 

sorbent injection aids SO, capture and lowers flue gas 

temperature and gas flow, which can decrease pressure 

drop at the fabric filter dust collector. 

The three basic technology systems have been installed on Public Service Company of Colorado’s Arapahoe Station Unit No. 4, a IOO-MWe down-tired, pulverized-coal boiler with roof-mounted burners. All testing 

Environmental Control Devices 
Calendar Year 

1989 1989 ,999 1991 1992 ,993 1994 1995 ,996 1997 ,998 

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

t tt tt t tt 

t 

Environmental tt t 

DOE selected pro@2 

I : b 

monitoring plan 

(CCT.III) 12/19/89 

completed 

wJ93 

peration initiated W92 

Design initiated W9O Construction completed 8192 

NEPA process completed (MTF) g/27/90 

Preoperational tests initiated 6/92 

Design completed 3l92 

Ground breaking/construction started 5/21/91 

Cooperative agreement awarded 3/t 1191 

Project mmpletedbinal report issued 11195’ 

Urea injection and a11 operations completed 6/95 

I 

Long-term sodium testi” completed 3/95’ 

‘Pmjected date 

is being conducted using a low-sulfur (0.4%) bituminous 

Colorado coal. 

Project Status/Accomplishments: 

Operational testing of the boiler with low-NOx burners 

and over-fire air started in early August 1992. Testing of 

the combustion modifications was completed in late 

October 1992. While tiring western bituminous coal, 

NOx was reduced from an original baseline of 1.15 ibsi 

million Btu to about 0.4 lb/million Btu-a 65% reduction-with no operating problems. In-furnace urea injection testing began in January 1993 and continued for 3 

months. At full load, 44% NOx reduction was achieved 

with a lo-ppm ammonia slip. Duct sorbent-injection 

testing began in August 1993 and was completed in May 

1994. Sodium-bicarbonate injection achieved over 70% 

SO, removal at a stoichiometric ratio of approximately 

1.0. Sodium sesquicarbonate injection after the air 

heater also obtained a 70% SO, removal but at a stoichiometric ratio of approximately 1.8. Calcium-based 

dry reagent injection achieved a maximum of 40% SO, 

the integration of sodium and urea injection began in 

June 1994 and will be completed in mid-1995. Overall 

removal and caused some operational concerns. PreNO2 reduction of 80% has been demonstrated at full 

economizer calcium-based injection achieved only 10% 

load. 

SO2 removal, significantly less khan expected. Testing of 

tive noncatalytic reduction system will be made after the 

Due to the successful application of the system, the 

Public Service Company of Colorado plans to continue 

test progmm is completed. All testing will be completed 

operation of the combustion modifications and the soin mid-1995, with project completion scheduled for 

November. 

dium-based DSI system. A final decision on the selecThe project schedule has been extended I year, to 

November 1995, to allow for additional long-term sodium injection testing. The urea injection system also 

will be modified to improve low-load NOx removal. 

Four series of air toxics testing have been completed. Results indicate that the baghouse successfully 

removes nearly ail trace metal emissions and nearly 80% 

of the mercury emissions. Radionuclides, semi-volatile 

organic compounds, and dioxins/furans were below or 

very near their detection limit. 

Arapahoe 4 has operated over 20,000 hours since 

combustion modifications were completed in May 1992. 

The availability factor during this period was over 96%. 

Commercial Applications: 

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

to most utility and industrial coal-tired units. They provide a lower capital-cost alternative to conventional wet 

flue gas desulfurization processes. They can be retrofitted with modest capital investment and downtime, and 

their space requirements are substantially less. They can 

be applied to any unit size but are mostly applicable to 

the older, small- to mid-size units. 

r ., .~ . . ..^. n^._&^f “^.,i,.^. Program Update 1994 7.77 
Coal Processing 

for Clean Fuels 

Fact Sheets 
Development of the Coal 

Quality Expert 

Participants: 

ABB Combustion Engineering, Inc. 

CQ, Inc. 

Additional Team Members: 

Black and Veatch-zofunder and expert system 

developer 

Electric Power Research Institute--cofunder 

The Babcock & Wilcox Company--cofunder and 

pilot-scale testing 

Guild Products, Inc.--expert system architecture 

developer 

Electric Power Technologies, Inc.--field testing 

University ofNorth Dakota, Energy and Environmental 

Research Cater-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) 

Baypon, Washington County, MN (King Station) 

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

Technology: 

CQ, 1”~‘s EPRl coal quality expert (CQE) computer 

model (coal processing for clean fuels/coal preparation 

technologies) 

7.80 Program Update 1994 

Plant Capacity/Production: 

Full-scale testing took place at six utility sites ranging in 

size from 250 to 880 MWe. 

Technology/Project Description: 

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

were used to develop algorithms for inclusion 

Project Funding: 

Total project cost $21,746,004 100% 

DOE 10,X63,911 50 

Participants 10,882,093 50 

Project Objective: 

To demonstrate an expert system that can be nm 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 efftciency, cost, and environmental emissions. 

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

be run on a personal computer Utilities may use the 

information to predict the operating performance and 

cost of coals not previously burned at a particular facility. 

Six large-scale field tests consisted of burning a 

baseline coal and an alternate coal over a 2.month period. The baseline coal, the one currently used as fuel, 

was used to characterize the operating performance of 

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

of improved quality, was burned in the boiler for the 

remaining test period. 

Coal Processingfor Clean Fuels 
Calendar Year 

1988 1989 ,990 1991 1992 ,993 1994 1995 1996 1997 ,998 

3412341 23412341234, 234 1 234 1 2 3 4 1 234,234 12 

Development 

12m 6190 6190 6195 

I 

t 

t 

t 

Operation initiated B/90 Project complst*d/final report issued 6/95* 

Environmental monitoring plan completed 7131190 

DOE Selected project 

Software de”elopme”f cmpleted 4,95 

(CCT-I) 12/9/m Cooperative agreement awarded 61,490 Field te*ting completed 4t93 

NEPA process completed (MTF) 4/27/90 

‘Projected date 

The baseline and alternate coals for each test site 

also were burned in bench- and pilot-scale facilities 

under similar conditions. The alternate coal was 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 were 

evaluated and correlated to formulate algorithms being 

used to develop the model. 

Bench-scale testing was performed at ABB Combustion Engineering’s facilities in Windsor, CT, and the 

University of North Dakota’s Energy and Environmental 

Research Cater in Grand Forks, ND; pilot-scale testing 

was performed at ABB Combustion Engineering’s facilities in Windsor, CT, and Alliance, OH. The six field test 

sites were Gatson, Unit 5 (880MW e), Wilsonville, AL; 

Watson, Unit 4 (250MW e), Guifport, MS; Brayton 

Point, Unit 2 (285 MWe) and Unit 3 (615 MWe), 

Somerset, MA; King Station (560MW e), Bayport, MN; 

and Northeastern, IJnit4 (445 MW e), Oologah, OK. 

Project Status/Accomplishments: 

All six field tests have been completed. A CQE prototype was showcased in September 1993. Emphasis 

during I994 was on final model development, 

prototyping, and validation. A CQE beta version will be 

released in early 1995, and the tinal version is expected 

in Iune 1995. 

nonexclusive worldwide rights to sell users’ licenses and 

to offer consulting services that include the use of CQE 

software. 

Commercial Applications: 

The expert system will enable coal-tired 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 industrialiinstititional boilers that bum coal. 

The system will predict the operational and emission 

reduction benefits of using cleaned coal. A commercial 

sale of the CQE Acid Rain Advisor soiIware package 

was made in March 1993. 

CQ, Inc., and Black and Veatch have signed a commercialization agreement which gives Black and Veatch 

Coal Processingfor Clean Fuels Program Updafe 1994 7.81 
Self-Scrubbing CoalTM: An 

Integrated Approach to Clean 

Air 

Participant: 

Custom Coals International (a joint venture between 

Genesis Coals Limited Partnership and Genesis Research 

Corporation) 

Additional Team Members: 

Duqnesne Light Company-host utility 

Richmond Power&Light-host utility 

Cent&or Service Company-host 

CQ, Inc.--operator 

Locations: 

Central City, Somerset County, PA (advanced 

coal-cleaning plant) 

Springdale, Allegheny County, PA (combustion tests at 

Duquesne Light’s Cheswick Power Station, Unit I) 

Richmond, Wayne County, IN (combustion tests at 

Richmond Power & Light’s Whitewater Valley 

Generating Station, Unit No. 2) 

Ashtabula, Trnmbnll County, OH (combustion tests at 

Cent&or Energy’s Ashtabula C) 

Technology: 

Coal preparation using Custom Coals’ 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 tonsibr 

Project Funding: 

Total project cost $89,715,781 100% 

DOE 38,038,656 42 

Participant 51,677,125 58 

Self.Scrubbing Coal and Carefree Cod are lIdema*h of Custom coats 

!XSll~liO”Cll. 

7-82 Program Update 1994 

RUN-OF-MINE COAL 

1 ADVANCED 

_.. TECHNOLOGY 

COAL CLEANING 

ASH B PYRlTlC 

SULFUR 

U 

Proiect Objective: 

To demonstrate advanced coal-cleaning unit processes to 

produce low-cost compliance coals that can meet full 

requirements for commercial-scale utility power plants to 

satisfy CAAA of 1990 provisions. 

Technology/Project Description: 

An advanced coal-cleaning plant will be designed, 

blending existing and new processes, to produce, from 

high-sulfnr bituminous feedstocks, two types of compliance coals-Carefree CoaPM and Self-Scrubbing CoalN. 

Carefree Coal” 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 pyribc sulfur and most of the ash. Carefree CoalTM is designed to be a competitively priced, 

high8tn fuel that can be used without major plant modifications or additional capital expenditures. While many 

utilities can use Carefree Coal” to comply with SO, 

emissions limits, others cannot due to the high content of 

organic sulfur in their coal feedstocks. When compliance coal cannot be produced by reducing pyritic sulfnr, 

Self-Scrubbing Co@ can be produced to achieve 

compliance. 

Self&rubbing CoaF’ is produced by taking Carefree Co@‘, with its reduced pyritic sulfur and ash content, and adding to it sotbents, 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 Coal? permits the addition of relatively large amounts of sorbent without exceeding the 

Coal Processingfor Clean Fuels 
Calendar Year 

1991 1992 1993 1994 1995 1996 1997 1998 1999 2cm *001 

3 4 1 234123412341 234 1 234 1 234 t 23412341 234 12 

9191 1 O/92 3195 3196 

Imm~WT-IV) Operation initiated 3195’ 

Environmental monitoring plan completed 3195 

Preopwationat tests initiated Z/95 

Construction completed X35’ 

Design completed 12/94 

NEPA process completed (EA) 2114194 

Constr”ction started 12193 

Coaperative agreement awarded 10129192 ‘Projected date 

AA II 

t 

+ 

Project completedhal report issued 396’ 

Operation complet.+c 3/w 

ash specifications of the boiler or overloading the electrostatic precipitator 

A 500-to&x advanced coal-cleaning plant is being 

designed and constructed at a site near Central City, PA. 

The advanced coal-cleaning plant will manufacture SelfScrubbing CoalTM and Carefree Coal’*. Two medium- to 

high-sulfur coals--lllinois No. 5 (2.7% sultix) from 

Wabash County, IL, and Lower Freeport seam coal 

(3.9% sultir) from Belmont County, OH-will be used 

to produce Self-Scrubbing Co@‘. Carefree Co@’ will 

be made using Sewickley coal (4.8% sulfur) from Greene 

County, PA. The Sewickley coal will be combustion 

tested at Duquesne Light Company’s Cheswick Power 

Station located in Springdale, PA; the Illinois No. 5 coal 

will be tested at Richmond Power & Light’s Whitewater 

Valley Generating Station Unit No. 2 located in Richmond, IN; and the Lower Freeport seam coal will be 

tested at Centerior Energy’s Ashtahula C Power Plant 

near Ashtabula, OH. 

Project Statue/Accomplishments: 

Construction has moved at a rapid pace since beginning 

in December 1993. Structural steel erection is complete. 

Over 99% of the equipment has been installed. Raw 

coal bum testing to provide baseline data to determine 

the cleaning effect is scheduled to begin in early 1995. 

DOE approved a finding of no significant impact for 

an environmental assessment on February 14, 1994. 

Commercial Applications: 

Commercialization of Self-Scrubbing CoalTM has the 

potential ofbringing into compliance about 164 million 

tonslyr of bituminous coal that cannot meet emissions 

limits through conventional coal cleaning. This reprosents 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 8&90%. 

In August 1994, a U.S.-led consortium with Custom 

Coals Corporation as the principal partner signed a cooperative agreement with the People’s Republic of China to 

build a coal-cleaning plant, a 500-mile underground 

slurry pipeline, and port facility. The pipeline will bring 

coal from the Shanxi province in northwest China to the 

coastal province of Shandong. The work included under 

the agreement is valued at $888.6 million. 

Coal Processingfor Clean Fuels Program Update 1994 7-83 
Advanced Coal Conversion 

Process Demonstration 

Participant: 

Rosebud SynCoat Partnership (a partnership between 

Western Energy Company and the NRG Group, a 

nonregulated subsidiary of Northern States Power 

Company) 

Additional Team Member: 

NOW? 

Location: 

C&trip, Rosebud County, MT (adjacent to Western 

Energy Company’s Rosebud Mine) 

Technology: 

Rosebud SynCoal Partnership’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/h, of SynCoal” product (300,000 tons/y,) 

Project Funding: 

Total project cost $105,700,000 100% 

DOE 43,125,OOO 41 

Participant 62,575,OOO 59 

Project Objective: 

To demonstrate Rosebud SynCoal’s advanced coal conversion process to produce a stable coal product having a 

moisture content as low as I%, sulfnr content as low as 

0.3%, and heating value up to 12,000 Btuilb. 

SynCOis a registered trademark Ofthe Rosebud SynCod Partnership. 

Technology/Project Description: 

Being demonstrated is an advanced thermal coal conversion 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 remove loosely held water 

and then chemically bound water, carboxyl groups, and 

volatile sulfur compounds. After conversion, the coal is 

put through a deep-bed stratifier cleaning process to 

effect separation of the ash. 

The technology enhances low-rank western coals, 

usually with a moisture content of 25+tO%, sulfur content of 0.5-1.5%, and heating value of 5,500-9,000 

Btu/lb, by producing an upgraded SynCoal” product with 

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

0.3%, and heating value up to 12,000 Btuilb. 

The 45-ton/h, unit is located adjacent to a unit train 

loadout facility at Western Energy Company’s Rosebud 

coal mine in C&trip, MT. The demonstration plant is 

one-tenth the size of a commercial facility. However, the 

process equipment is at 113-112 commercial scale because a full-sized commercial plant will have multiple 

process trains. 

7-84 Program Update 1994 CoolProcessinfi fur Clean Fuelr 
I 

I 

I 

I 

/ 

/ 

1 

, 

! 

i 

Calendar mar 

1988 1989 1990 ,991 1992 1993 1994 ,995 1998 1997 ,998 

3 4 1 234 1 23412341 234 1 234 1 234 1 23412341 234 12 

9/90 6192 11197 

Test operation initiated 6192 

DOE selected project 

cm-0 1mBs Environmental monitoring plan completed 417192 Operation completed 

t T 6197 I Cooperative agreement 

BWwad g/21/90 I ’ Iconstruction completed 7./92 

Preoperational tests initia,.%i ,219, 

Design completed 8191 

Project completed/final 

repor! issued 1,197’ 

&round b,eaki”&o”str”ctio” started 3&9,91 

NEPA process Mmpleted (EA) 3127191 

‘Projected date 

Project Status/Accomplishments: 

Ground was broken on March 28, 1991. Initial “turnover” of equipment started in December 1991, and final 

construction was completed in February 1992. Initial 

delivered to Ash Grove Cement, Bentonite Corporation, 

and Empire Sand and Gravel. 

Commercial Applications: 

clean alternative fuel to many regional industrial facilities and small utilities being forced to use fuel oil and 

natural gas. Rosebud Syncoal’s process, therefore, will 

“hot” operations began in March 1992. On December 6, Rosebud SynCoal’s advanced coal conversion process 

be attractive to industry and utilities because the upgraded fuel will be less costly to use than would the 

1993, the plant exceeded its 68.ton/lx design capacity by has the potential to enhance the use of low-rank western 

subbituminous and lignite coals. Many of the power 

construction and use of flue gas desulfuriration equipprocessing 70 tonslhr. 

. . . ment. This will allow plants that would otherwise be 

In March 1994 a 50150 SynCoal” blend test was closed to remain in operation. 

completed at Montana Power Company’s I.E. Corette 

Plant. Wyoming subbituminous feedstock was tested at 

the SynCoal” demonstration plant in May 1994. This 

plant demonstrated a 75% availability factor and 98% 

capacity factor for the first 6 months of 1994. 

plants tocare* tnrougnout me upper NatWest nave cyclone boilers, which bum low-ash-fusion-temperature 

coals. Presently, mnst of these plants bum Illinois Basin 

high-sulfur coal. SynCoal” is an ideal low-sultitr coal 

substitute for these and other plants because it allows 

operation under more restrictive emissions guidelines 

without requiring derating of the units or the addition of 

costly flue gas desulfurization systems. The advanced 

coal conversion process produces SynCoala which has a 

consistently low moisture content, a low sulfw content, a 

high heating value, and a high volatile content. Because 

of these characteristics, SynCal” could have significant 

impact on SO, reduction and provide an economical 

A scheduled maintenance and plant improvement 

outage was completed in September 1994. A follow-up 

test bum using a 50150 SynCoal” blend was conducted at 

the J.E. Corette Plant following chemical cleaning of the 

boiler. Testing at the power plant continues at the main 

utility test bum site. A total of 5,412 tons have been 

delivered to the utility In addition, 5,757 tons have been 

Cod Processing for Glenn FIreIs 

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 applying the coal processing technology to a commercial plant integrated into an 

existing power plant site. The study’s results have been 

positive, but market commitments are still necessary. 

Program Update 1994 7-85 
ENCOAL Mild Coal 

Gasification Project 

Participant: 

ENCOAL Corporation (a subsidiary of SMC Mining 

Company) 

Additional Team Members: 

SMC Mining Company--cofunder 

TEK-KOL (partnership between SMC Mining Company 

and SGI International)-technology owner, supplier, 

and licenser 

SGI International-technology developer 

Triton Coal Company (subsidiary of SMC Mining 

Company&host facility and coal supplier 

The M.W. Kellogg Company--engineer and 

constructor 

Location: 

Near Gillette, Campbell County, WY (Triton 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 $90,664,000 100% 

DOE 45,332,OOO 50 

Participants 45,332,OOO 50 

Project Objective: 

To demonstrate the integrated operation of a number of 

novel processing steps to produce two higher value fuel 

forms from mild gasification of low-sulfnr subbituminous coal; and to provide sufficient products for potential 

end users to conduct bum tests. 

Technology/Project Description: 

The ENCOAL mild coal gasification process involves 

heating coal under carefully controlled conditions. Coal 

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

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

solid bulk temperature is controlled so that no significant 

amounts of methane, CO, or CO, are released from the 

coal. The solids from the dryer are conveyed to the pyroThe gas produced in the pyrolyzer is sent through a 

cyclone for removal of the particulates and then cooled 

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

from the condensation unit is recycled to the pyrolyzer. 

The rest of the gas is burned in combustors to provide 

heat for the pyrolyzer and the dryer. NOx emissions are 

controlled by staged air injection. 

The offgas from the dryer is treated in a wet venturi 

lyzer where the rate of heating of the solids and residence scrubber to remove particulates and a horizontal scrubber 

time are controlled to achieve desired properties of the to remove SO,, both using a sodium carbonate solution. 

fuel products. During processing in the pyrolyzer, all The treated gas is vented to a stack, and the spent soluremaining tiee water is removed, and a chemical reaction tion is discharged into a pond for evaporation. 

occurs that results in the release of volatile gaseous The ENCOAL project is located within Campbell 

material. Solids exiting the pyrolyzer are quenched, County, WY, at Triton Coal Company’s Buckskin Mine, 

cooled, and transferned to a surge bin. IO miles north of Gillette. The plant makes use of the 

7-86 Pro~rom Update 1994 Coal Processingfor Clean Fuels 
cahldar Yea, 

,988 ,989 ,990 1991 1992 1993 1994 1995 ,996 1997 1999 

3 4 1 2 3 4 1234 1 2 3 4 1 23412341 2 3 4 123412341 234 12 

PreaWaKl 

7192 9196 

T 3 

Operation initiated 7/92 Project complet*dnklal report 

issued 9/w 

Construction completed 6t92 

DOE Operation completed 9rQ6 

selected 

v 

Envimnmental monitonna plan completed 5/29/92 

proje$t 

y;;;g 

I 1 

Preoperational tests initiatsd 4l92 

Design completed 7l91 

Ground breakinghonstruction started 1 O/26/90 

Cooperative agreement awarded 9/17/90 

NEPA process completed (EA) 8/1,90 ‘Projected date 

present coal-handling facilities at the mine. Subbituminous coal having sulfur content of 0.4-0.9% is being 

used. 

Project Status/Accomplishments: 

The plant officially entered the production mode in June 

1994; operation has been at a coal feed rate of 500 tons/ 

day. By year-end 1994,22 test runs were completed, 

representing more than 5,000 hours of operation on coal. 

Solid and liquid products being produced by the plant are 

being shipped to industrial and utility cus<omers. In 

September 1994, approximately 8,000 tons of solid pmduct were shipped as l&35% blends with Powder River 

Basin coal for use in electricity generation at the Western 

Farmers Cooperative’s Hugo plant in Oklahoma. This 

rural electric cooperative used the product successfully in 

its boilers. ENCOAL also has contracted with Wisconsin Power & Light for the sale of 30,000 tons of solid 

product. A contract to sell blends of up to 92% solid 

product was signed with Muscatine Power and Water of 

Muscatine, IA. Other major utility companies have 

expressed interest in purchasing solid product. Tank cars 

of liquid product are being shipped on a regular basis to 

several customers in the Midwest for use in industrial 

boilers. The Dakota Gasitication Company tested the 

liquid product in I992 and in 1994 purchased an additional 800,000 gallons for use in its synfuel plant in 

Beulah, ND. 

The project has been extended for2 years in order to 

resolve problems with the in-process stabilization of the 

solid product and to conduct and analyze utility test 

bums of solid product. 

Commercial Applications: 

The liquid products from mild coal gasification can be 

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

solid product can be used in most industrial or utility 

boilers and also shows promise for iron ore reduction 

applications. The feedstock for mild gasification facilities is being limited to high-moisture, low-heating-value 

CO&. 

The potential benefits of this mild gasification technology in its commercial configuration are attributable to 

the increased heating value (about 12,00OBtu!lb) and 

lower sulfur content (per unit of libel value) of the new 

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. 

The product fuels are expected to be used economically 

in commercial boilers and furnaces and to reduce significantly SO, emissions at industrial and utility facilities 

currently burning high-sulfur bituminous coals or fuel 

oils. 

SGI International and Mitsubishi Heavy Industries 

are studying the economic and engineering feasibility of 

developing a 6,000-metric-ton/day liquids-from-coal 

plant in the Shandong province of the People’s Republic 

of China. Feasibility studies have also been proposed for 

projects in Indonesia and Poland. 

j Coal Processingfor Ckan Fuels Program Update 1994 7-87 
Commercial-Scale 

Demonstration of the Liquid- 

;;::welethanol (LPMEOHTM) 

Participant: 

Air Products Liquid Phase Conversion Company, L.P. (a 

limited partnership between Air Products and Chemicals, Inc., the general partner, and Eastman Chemical 

Company) 

Additional Team Members: 

Air Products and Chemicals, Inc.-technology supplier 

and cofunder 

Eastman Chemical Company-host; synthesis gas and 

services provider 

Acurex Environmental Corporation-fuel methanol 

testing and cc&under 

Electric Power Research Institute--fuel methanol testing 

and c&under 

Location: 

Kingsport, Sullivan County, TN (Eastman Chemical 

Company’s Integrated Coal Gasification Facility) 

Technology: 

Air Products and Chemicals’ liquid-phase methanol 

(LPMEOHTM) process (coal processing for clean fuels/ 

indirect liquefaction) 

Plant Capacity/Production: 

260 tons/day of methanol (nominal) 

Project Funding: 

Total project cost: %213,700,000 

DOE 92,708,370 

Participants 120,991,630 

LPMEOH is a trademark of Air Products and Chemicab, Inc. 

7-88 Program Update 1994 

100% 

43 

57 

Project Objective: 

To demonstrate on a commercial scale the production of 

methanol from coal-derived synthesis gas using the 

LPMEOWM process; and to determine the suitability of 

methanol produced during this demonstration for use as 

a chemical feedstock or as a lowSOx, low-NOx altemative fuel in stationary and transportation applications. If 

practical, the production of dimethyl ether (DME) as a 

mixed coproduct with methanol also will be demonstrated. 

Technology/Project Description: 

This project is demonstrating, at commercial scale, the 

LPMEOWPM process to produce methanol from coalderived synthesis gas. The combined reactor and heat 

removal system is different from other commercial 

methanol processes. The liquid phase not only suspends 

the catalyst but functions as an &cient means to remove 

the heat of reaction away from the catalyst surface. This 

feature permits the direct use of synthesis gas streams as 

feed to the reactor without the need for shift conversion. 

The Eastman Chemical Company’s integrated coal 

gasification facility at 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 LPMEOHTM unit for application 

to coal-based electric power generation facilities. Methanol fuel testing will be conducted in off-site stationay 

and mobile applications, such as boilers, fuel cells, 

buses, and van pools. Design verification testing for the 

production of DME 8s a mixed coproduct with methanol 

for use as a storable fuel is planned, and a decision to 

Coal Processingfor Ckan Fuels 
‘OE Selected 

rot?~d&CT-lll) 

1 

i 

r 

Operation initiated 12/Q/96 

PreOp.mtio”al tests initiated ,,,96 

’ . 

operation completed 2101’ 

ConStruction com~lsted 11196 Project completedninal repoll issued 12101” 

Design completed t/96 

Environmental monitoring plan completed 1196 

Cooperative agreement awarded tO/t6/92 

Construction mrted 5195 

NEPA process completed (EA, 4196 

‘Projected date 

demonstrate will be made. Eastern high-sulfur bituminous coal (Mason seam) containing 3% sulfur (5% maximum) and 10% ash will be used. 

Project Status/Accomplishments: 

To provide a contractual basis to manage and execute the 

LPMEOHTM demonstration project, Air Products and 

Chemicals and the Eashnan Chemicals Company have 

formed the limited partnership, Air Products Liquid 

Phase Conversion Company. Project definition activities 

were completed in September 1994 and design was 

initiated. Relevant environmental information for the 

NEPA process is being updated, an environmental assessment is in progress. Construction is expected to start 

in May 1995. 

Commercial Applications: 

The LPMEOHTM process has been developed to enhance 

integrated gasification combined-cycle (ICCC) power 

generation by producing a clean burning, stbrable liquid 

fuel-methanol-from the clean coal-daived gas. 

Coal Processing for Clean Fuels 

Methanol also has a broad range of commercial applications, can be substituted for conventional fuels in stationary and mobile combustion applications, is an excellent 

fuel for peak power production, contains no sulfur, and 

has exceptionally low-NO” characteristics when burned. 

Methanol can be produced from coal as a coproduct in an 

IGCC facility. 

methanol produced when associated with commercial 

IGCC power generation trains of ZOO-350 MWe. Air 

Products and Chemicals expects to market the 

LPMEOHTM technology through licensing, owning/ 

operating, and tolling arrangements. 

DME has several commercial uses. In a storable 

blend with methanol, the mixture can be used as peaking 

fuel in IGCC electric power generating facilities. DME 

can 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 

tixl additives. Pure DME has been gaining acceptance 

as an environmentally friendly aerosol in personal 

products. 

Typical commercial-scale LPMEOHTM units are 

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

Program Update 1994 7.89 
industrial Applications 

Fact Sheets 
Blast Furnace GranulatedCoal Injection System 

Demonstration Project 

Participant: 

Bethlehem Steel Corporation 

Additional Team Members: 

British Steel Consultants Overseas Services, Inc. 

(marketing arm of British Steel Corporation)- 

technologyowner 

Simon-Macawher, Ltd.dquipment supplier 

Fluor Daniel, Inc.-architect and engineer 

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

technology licensee) 

Location: 

Bums Harhor, Porter County, IN (Bethlehem Steel’s 

Bums Harhor Plant, Blast Furnace Units C and D) 

Technology: 

British Steel’s blast furnace granulated-coal injection 

(BFGCI) process (industrial applications) 

Plant Capacity/Production: 

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

Project Fundlng: 

Total project cost $191,700,000 100% 

DOE 31,259,530 I6 

Participant 160,440,470 84 

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

nahxe of these parameters. 

7-92 Program Update 1994 

Technology/Project Description: 

In the BFGCI process, both granulated and pulverized 

coal is injected into the blast furnace in place of natural 

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

basis. Because coke production results in significant 

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

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

along with heated air is blown into the barrel-shaped 

section in the lower part of the blast furnace through 

passages called tuyeres, which creates swept zones in the 

furnace called raceways. The size of a raceway is important and is dependent upon many factors including temperature. Lowering of a raceway temperature, which can 

occur with gas injection, reduces blast furnace production 

rates. Coal, with a lower hydrogen content than either 

gas or oil, does not cause 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 

enhance blast furnace production. 

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 NOx. 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. 

Industrinl Applications 
I 

I 

’ 

I 

/ 

! 

/ 

I 

I 

! 

I 

Calendar mar 

1988 1989 ,990 ,991 1992 1993 1994 1995 1996 ,997 1998 

3412341 234 1 234 I 2 3 4 12341 234 1234 1 234 1 234 12 

12la9 11190 5195 1199 

I Operation initiated S/95 

DOE selected Preaperational tests initiated 12i94 

y{eN;CTW Construction completed W94 

Environmental monitoring plan completed 1Z23l94 

esign con#eted 12193 

Construction started 9,93 Project compktetifinal report 

NEPA proco55 completed (EA, ml93 

issued l/98 

cooperative agreemsnt awarded 1 l/26/90 Operation completed 1198 

‘Projected date 

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

Bethlehem Steel Corporation’s Burns 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 O&0.9% sulfur 

might be tested also. 

Project Status/Accomplishments: 

Construction has been completed, andpreoperational 

tests have been initiated. Facilities 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 were modified 

to accept the prepared coal. The necessary modifications 

to furnace D were made on-the-fly through a series of 

short outage8 on the operating furnace. Furnace C was 

modified during a reline in late 1994. 

Industrial Applications 

Bethlehem Steel expects to submit a public design 

report in January 1995. 

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 that has a moisture content no higher than 12%. 

The environmental impacts of commercial application 

are primarily indirect and consist of a significant reduction of emissions resulting from diminished coke-making 

requirements. 

Program Update 1994 7-93 
Innovative Coke Oven Gas 

Cleaning System for Retrofit 

Applications 

Participant: 

Bethlehem Steel Corporation 

Additional Team Member: 

Thyssen Still/Otto Technical Services-technology 

developer 

Location: 

Sparrows Point, Baltimore County, MD (Bethlehem 

Steel Corporation’s Sparrows Point Plant, Coke Oven 

Batteries A, 1 I, and 12) 

Technology: 

Thyssen Still/Otto’s process for precombustion cleaning 

of coke oven gas (COG) (industrial applications) 

Plant Capacity/Production: 

74 million std @Iday of COG 

Project Funding: 

Total project cost 

DOE 

Participant 

$45,239,781 100% 

13,500,000 30 

31,739,7x1 70 

Project Objective: 

To demonstrate a first-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 recowy 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 wastewata treatment. 

Technology/Project Description: 

This project is demonstrating an innovative technology 

developed by Thyssen Still/Otto for removing hydrogen 

sulfide and ammonia from COG. The process uses 

contaminated water produced in the coke oven batteries 

to absorb the hydrogen suliide and ammonia contained in 

the COG. Both hydrogen sulfide and ammonia are 

steam shipped from the absorption liquor. The ammonia 

is destroyed in a catalytic reactor; hydrogen sultide 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, 

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

This project involves the modification of the COG 

processing units at Bethlehem Steel’s Sparrows Point 

Plant in Baltimore County, MD. The demonstration 

facility is designed to process the entire COG stream 

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

to 74millionstdft ‘/day. These coke oven batteries have 

the capability to produce up to 1.2 million tonslyr of coke 

from a blend of Pennsylvania and Virginia coals having 

sulfur contents ranging from 0.8% to 1.37%. The raw 

COG has a hydrogen sultide content of 175-340 grains/ 

100 ft’. Currently, only 60% of this COG stream is 

desulfurized. The remaining 40% is used directly for 

fuel@ the tire under the coke ovens. 

The technology is expected to reduce the hydrogen 

suliide 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 Update 1994 Industrial Applications 
Calendar Year 

,988 1989 1990 1991 1992 1993 1994 ,995 19% 1997 1998 

3 4 1 234 1 2 3 4 1 234 1 234 1 2341234 1 2 3 4 12341234 12 

t 

A. A 

DOE selected 

project &CT-II) 

9,28/88 

A Hi 

Facility mothballing completed l/g2 

Construction completed 1x31 

Environmental monitoring plan completed 7/5/91 

-Designcompleted 11/W 

Ground breaking/construction stated 2/W 

NEPA process completed (EA, 12lW89 ‘Milestones to be updated 

Cooperative agreement awarded 1 l/14/89 following resumption of coke-making operations 

Project Status/Accomplishments: commercial-sized COG treatment facilities. The novel would be the ammonium sulfatc which is diff%xdt to 

On December 5, 1991, Bethlehem Steel Corporation integration of commercially available process steps is market and usually is disposed of as a solid waste. Evsuspended all coke production at its Sparrows Point 

facility for a period of at least 2 years. This decision was 

made due to the rapid deterioration of the coke ovcos. 

During this period, an evaluation will be made to explore 

alternatives for resumption of coke production. 

Bethlehem Steel’s interest is for long-term coke indepcndence at this facility. 

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

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

successfully when coke-making operations arc resumed. 

Commercial Applications: 

The design for this innovative COG cleaning system is 

based on operating data that have been collected from 

individual process steps or combinations of individual 

process steps that have been successfully operated at 

lndusrrial Applications Program Update 1994 7-95 

expected to reduce the overall cost of dcsultiuization, cry 5-8 years, 5 tons of spent nickel catalyst would need 

ensure reliable operation in applications exceeding to be returned to the vendor or disposed of as a hazard20 years, and provide a viable alternative to conventional ous waste, and 10 tons of spent alumina catalyst would 

technologies. Because the demonstration is designed to need to be disposed of as a nonhazardous solid waste. 

treat 74 million std A’Jday of COG (a commercial size), Depending on the configuration of the coke oven facility 

the project will demonstrate that it is possible to retrofit where the technology is being implemented, the amount 

soy existing coke-making facility in tbc United States of water needed for cooling purposes would remain the 

with essentially no scalcup involved and without signifi- same or be reduced, and the amount of pollutants in the 

cant downtime. wastewater would remain the same or be reduced. 

Bethlehem Steel will license the use of this COGcleaning technology through Thyssen Still/Otto to the 

existing 30 coke oven plants in the United States which 

emit about 300,000 tons& of SO,. This COG-cleaning 

process could be applicable to 24 plants with conespending SO, emission levels of 200,000 tons&r. If tbc 

technology were installed in all 24 plants, the SO, cmissions could be reduced by 160,000 tons/yr. Eliminated 
Clean Power from integrated 

Coal/Ore Reduction (COREX@) 

Participant: 

Centcrior Energy Corporation 

Additional Team Members: 

Geneva Steel Company-site owner; constructor and 

operator of COREX”unit 

Air Products and Chemicals, Itxdesigner, engineer, 

constructor, and operator of air separation and 

combined-cycleunits 

Dcutsche Vow-Alpine Industrieanlagcnba” GmbHCOREX* dcvclopcrlsupp1ier; designer and engineer 

of COREX” “nit 

Electric Power Research Institutc--cofimdcr 

Location: 

Vineyard, Utah County, UT (Geneva Steel Company’s 

mill) 

Technology: 

Integration of Deutschc Voest-Alpine 

Industrieanlagcnbau’s COREX’ iron-making process 

with a combined-cycle power generation system 

(industrial applications) 

Plant Capacity/Production: 

195 MWc (net) and 3,300 tons/day of hot metal (liquid 

iron) 

Project Funding: 

Total project cost $825,092,000 100% 

DOE 150,002,000 18 

Participants 675,090,OOO 82 

(Funding amounts reflect those contained in tbc proposal 

and are subject to negotiation.) 

CDREX is a registered trademark of Deutrehe “oest-Alpine 

t”*“~~~~“l~g~~b~“G~bH. 

Project Objective: 

To demonstrate the integration of a direct iron-making 

process (COP&X”) with the production of electricity 

using various U.S. coals in an efficient and cnvironmentally responsible manner. 

The gasification process generates the reducing gas for 

“se in the reduction fmnace as well as sufficient heat to 

melt the resulting iron in the melter-gasificr. 

Technology/Project Description: 

The clean power from integrated coal/ore reduction 

(CPICORTM) process integrates two historically distinct 

processes-iron-making and electric power generation. 

COREXm is a novel iron-making technology which 

eliminates the need for coke production. The key innovative features of tbe COREXm process include the reduction shaft furnace, which is used to reduce the iron OTC to 

iron, and the melter-gasifier, located beneath the reduction furnace, which gasifies the coal and melts the iron. 

Excess reducing gas exiting tnc rcauct~on turnace IS 

cooled, cleaned, compressed, mixed with air, and burned 

in a gas turbine generator system capable of cornbusting 

1owBtu gas to make electric power. The hot exhaust 

from tbc 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 3,400 tons/day of a 

bituminous coal blend containing about 0.5% sulfur will 

be “tilized. The project will produce 3,300 tons/day of 

hot metal and 195 MWc for sale. 

7-96 Program Update 1994 Industrial Applications 
Calendar Year 

,993 1994 1995 ,996 1997 ,998 lS69 2000 mot 2002 2003 

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

I Cooperativeagreement 

awarded a/95’ 

I ‘Projected date: mile*tonw are subpact to negotiation 

CPICORTM technology is less complex and environmentally superior than competing iron-making and 

power-generating technologies. Criteria air pollutants 

are reduced substantially largely due to (1) the inherent 

desulfuriring capability of the COREXa process wherein 

the limestone fed to the reduction furnace captures the 

sulfur present in the coal and (2) the efficient control 

systems within the combined-cycle power generation 

process. Because coke is not used, coke plants and their 

associated pollutants can be eliminated. 

The energy efficiency of the CPICORTh technology 

is much greater than competing commercial technology. 

This efficiency advantage is gained by more effective use 

of both the sensible heat in the process and the volatile 

matter in the coal, as well as by incorporation of the 

combined-cycle power generation system. 

Project Status/Accomplishments: 

The project is in negotiation. In April 1994, LTV Steel 

elected to withdraw from the proposed project. In 

July 1994, Air Products and Chemicals, Centerior En- Similarly, the total emissions of SO, from the commerergy, and Geneva Steel Company signed an agreement to cial facility are expected to be 0.024 lb/million Btu, a 

develop and site the project at Geneva Steel’s mill in reduction of more than 90%. The net electrical generatVineyard, UT (near Orem). ing efficiency of the commercial facility is estimated to 

Commercial Applications: 

The CPICORTM 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 CPICORTM 

demonstration project will produce nearly 200 MWe (net 

exportable) and 1,200,OOO tons&r of hot metal while 

expanding the type of coals that can be used to produce 

hot metal into the much larger noncoking range. 

The total emissions ofNO= from a future commercial plant are expected to be 0.012 lb/million Btu of coal, 

which is a reduction of more than 91% from the combination of a comparably sized blast furnace, associated 

coke-making facilities, and a comparably sized pulverized coal power plant with flue gas desulfurization. 

be 41% (a net effective heat rate of 7,262 Btu/kWb on an 

LHV basis). This compares to a net efficiency of 32% 

for comparably sized conventional facilities. 

Overall, a CPICORm 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 ofsolid wastes are beneficially 

reused, which increases the economic benefit of the 

technology and avoids burdening landfills. Most of the 

solid waste is slag from the iron-making process, which 

is usable in applications such as ballast for road construction and foundations. 

Program Update 1994 7.97 
Advanced Cyclone 

Combustor with Internal 

Sulfur, Nitrogen, and Ash 

Control 

Partlcipent: 

Coal Tech Corporation 

Additional Team Members: 

Commonwealth of Pennsylvania Energy Development 

Authority--cofunder 

Pennsylvania Power and Light Company-supplier of 

test coals 

Tampella Power Corporation-host site 

Location: 

Williamsport, Lycoming County, PA (Tampella Power 

Corporation boiler manufacturing plant) 

Technology: 

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

(industrial applications) 

Plant Capacity/Production: 

23 million Btuihr 

Project Funding: 

Total project cost 

DOE 

Participants 

$984,394 100% 

490,149 50 

494,245 50 

Project Objective: 

To demonstrate that an advanced cyclone combustor can 

be retrofitted to an industrial boiler and that it can simultaneously ~etnove up to 90% of the SO, and 9&95% of 

the ash within the combustor and reduce NOx by up to 

100 ppm 

7.98 Program Update 1994 Industrial Applications 

Technology/Project Description: 

Coal Tech’s horizontal cyclone combustor is internally 

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

air, and sorhent are injected tangentially toward the wall 

through tubes in the annular region of the combustor to 

cause cyclonic action. In this manner, coal-particle 

combustion takes place in a swirling flame in a region 

favorable to particle retention in the combustor. Secondary air is used to adjust the overall combustor stoichiometry. The ceramic liner is cooled by the secondary air and 

maintained at a temperature high enough to keep the slag 

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

coal pulverization allows combustion of most of the coal 

particles near the cyclone wall, with the balance burned 

on or near the wall. This improves combustion in the 

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

contains over 80% of the ash and sorbent fed to the combustor. For NO” control, the combustor is operated fuel 

rich, with final combustion taking place in the boiler 

furnace to which the combustor is attached. 

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

23-million~Btu/hr, oil-designed package boiler located at 

the Tampella Power Corporation boiler factory in 

Williamsport, PA. Air cooling in this comhustor takes 

place in a very compact combustor which can be retroiitted to a wide range of industrial and utility boiler designs 

without disturbing the boiler’s water-steam circuit. NOx 

reduction is achieved by staged combustion, and SO, is 

captured by injection of limestone into the combustor. 
The cyclonic action inside the combustor forces the coal 

ash and sorbent to the walls where it can be collected as 

liquid slag. Under optimum operating conditions, the 

slag contains a significant fraction of vitrified coal sulfnr. 

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 sultiu contents ranging from 1% to 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 Btuilu from a peak of 

19 million BtuAw 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 Btuihr even though the comb&or was 

designed for 30 million BtuAu and the boiler was t&rmally rated at around 25 million Btuibx 

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 Btn (184 ppmv). An 

additional S-IO% NO” reduction was obtained by the 

action of the wet particulate scrubber, resulting in 

atmospheric NOx emissions as low as 0.26 lb/million 

Btu (160 ppmv). 

. 

the coal sulhu was retained in the dry ash removed 

from the combustor and furnace hearths, and a high of 

11% of the coal sulfur was retained in the slag rejected through the slag tap. 

Local stack particulate emission standards were met 

with the wet venturi particulate scrubber. 

Total slagisorbent retention in the combustor, under 

efficient combustion operating conditions, averaged 

72% and ranged from 55% to 90%. Under more 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 opkrational procedures were closely coupled with 

materials durability. By implementing certain procedures, such as changing the combustor wall temperature, it was possible to replenish the combustor refractory wall thickness with slag. 

Procedures for properly operating an air-cooled combustor were developed, and the entire operating database was incorporated into a computer-controlled 

system for automatic combustoroperation. 

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 SO2 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 

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 tinther scaled up for commercial applications 

(100 million Btu!hr), such as combustion of waste solid 

fuels, limited sulfur control in coal-tired boilers, and 

conversion of ash to slag. 

Coal Tech’s advanced, air-cooled, slagging combustar can use a wide range of U.S. coals and can be retrofitted to existing or new units. The target market is industrial and utlity boilers sized 20-100 million Btu/hr or 

more; multiple combustors can be attached to larger 

boilers. The near-tam focus is on using the combustor 

in combined-cycle industrial and small utility power 

plants in the 10-50-MWe range. The combustor is capable of using pulverized coal, coal-water slurry, cofired 

pnlverized coal, and refuse-derived fuels (e.g., industrial 

sludge and coal-mine waste). 

Project Schedule: 

DOE selected project (CCT-I) 7124186 

Cooperative agreement awarded 3120187 

NEPA process completed (MTF) 3/26/87 

Environmental monitoring plan completed 9122187 

Conshuction 7/87-II/87 

Operational testing 1 l/87-5/90 

Project completed 9191 

Final Reports: 

Final Technical Report 8/91 

DOE Assessment 5193 

Industrial Applications Program Update 1994 7.99 
Cement Kiln Flue Gas 

Recovery Scrubber 

Project completed. 

Participant: 

Passamaquoddy Tribe 

Additional Team Members: 

Dragon Products Company-project manager and host 

E.C. Jordan Company-engineer for overall scrubber 

HPD, Incorporated-designer and fabricator of tanks and 

heat exchanger 

Cianbro Corporation-constructor 

Location: 

Thomaston, Knox County, ME (Dragon Products 

Company’s coal-tired cement kiln) 

Technology: 

Passamaquoddy Technology Recovely ScrubberTM 

(industrial applications) 

Plant Capacity/Production: 

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

gas; and up to 214 tons/day of coal 

Project Funding: 

Total project cost $17,800,000 100% 

DOE 5,982,592 34 

Participant 11,817,408 66 

Project Objective: 

To retrofit and demonstrate a full-scale industrial scmbber and waste recovery system for a coal-burning wet 

process cement kiln using waste dust as the reagent to 

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

Pasnamaquoddy Technology Rscovery Scrubber isa trademark ofthe 

Passamaquoddy Tribs. 

7-100 Program Update 1994 

,’ ” .’ x ,, : : 

:‘+ ‘, i, ( : ,, 

,; i ; : : , 

eastern coals and to produce a commercial by-product, 

potassium-based fertilizer. 

Technology/Project Description: 

ThePassamaquoddy Technology Recovery ScmbberTM 

uses a water solution/slurry containing potassium-rich 

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 slurry is separated into liquid and solid fractions. The solid fraction is 

returned to the cement plant as renovated and usable raw 

feed material. The liquid fraction is passed to a crystallizer that uses waste heat in the exhaust gas to evaporate 

the water and recover dissolved alkali metal salts. 

The Passamaquoddy Tribe’s recovery scrubber was 

constructed at the Dragon Products Company’s cement 

plant in Thomaston, ME, a plant that processes approximately 470,000 tons&r of cement. The process was 

developed by the Passamaquoddy Indian Tribe while it 

was seeking ways to solve landfill problems, which 

resulted from the need to dispose of waste kiln dust from 

the cement-making process. 

The kiln burns Pennsylvania bituminous coal containing approximately 3% sulfur. 

Industrial Applications 
,,: :~ ::: ,,, 5~,\? in ..~.I:&* ,,, &; :;. ,;, ‘,..A .Ll..,~.,.~,,jiil,;,.r,b,lrir,.;~...I:~. 

Project Results/Accomplishments: 

The recovery scrubber began operations in August 1991 

and has continued operations with several temporary 

shutdowns for normal kiln repairs and maintenance and 

a more lengthy shutdown from January to May 1992 due 

to poor economic conditions in the area. 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,OOOtons 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%. The effect on NOx emissions also was 

determined during the demonstration. NOx emissions 

were reduced S-15%. Operations have totaled 5,316 

hours. Capital costs are approximately $10 million for a 

450,000-ton&r plant, with a simple payback in about 

34 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 over 250 cement kiln installations in the 

United States and along the St. Lawrence River in 

Canada emitting approximately 230,000 tonsiyr of SO, 

Based upon the characteristics of the technology, the 

applicable market would include approximately 75% of 

these installations. If the technology were installed in 

the applicable market facilities, SO, emissions could be 

reduced by approximately 150,000 tons&r. Commerciali&ion of the technology may be spurred on when EPA 

issues emissions limits on cement kilns under the CAAA 

of 1990. The technology may also have broader appiicaIndustrial Applications 

,, ,;_. ,~ .,, ,& ,,&i ._,A .,,, ~~‘,. ,,,, ,.,, * ,; ‘, _ i,,,i -. .i,‘l,i,,;,L *..,i,+.i?:,.&*:&i / :,,,i ., : ,, 

tions in paper production and municipal waste incineration in the United States and abroad. 

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 

the amount reduced because the technology produces 

distilled water either for sale or discharge. 

The waste dust that previously would have been 

sent to a landfill would be recovered for recycling to the 

kiln and to produce by-product fertilizer. Essentially, 

the solid waste stream would be eliminated through 

recovery. 

In 1994 a Taiwanese cement company engaged 

Passamaquoddy Technologies, L.P., to do a preliminary 

study for the installation of the Passamaquoddy Technology Recovery ScrubberTM on a new cement plant in 

Taiwan. 

Project Schedule: 

DOE selected project (CCT-II) 9128/88 

Cooperative agreement awarded 12/20/89 

NEPA process completed (EA) 2116190 

Environmental monitoring plan completed 3126190 

Construction 4190-5191 

Operational testing 8191-9193 

Project completed 2194 

Final Reports: 

Final Technical Report 

(including economic assessment) 2194 

Topical Report 3192 

Public Design Report 10/93 

Program Update 1994 7.101 
Demonstration of Pulse 

Combustion in an Application 

for Steam Gasification of Coal 

Participant: 

ThexmoChem, Inc. 

Additional Team Member: 

Manufactiting 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 (MTCI) pulse 

combustor/gasitier (industrial applications) 

Plant Capacity/Production: 

I61 million Bha’br of 325 BWstd fi’ medium-Btu fuel 

gas plus 4O,OOOlb/lu of export steam 

Project Funding: 

Total project cost 

DOE 

Participants 

$37,333,474 100% 

l&666,731 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. 

Technology/Project Description: 

The MTCI fluidized-bed gasitier incorporates an innovative indirect beating process for thermochemical steam 

gasification ofcoal 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 fluid&d-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 &iciency is expected to be 72% or more. In major commercial applications, char combustion and heat recovery operations can 

be 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. 

Subbituminous coal (0.3% sulfur) will be used. 

7-102 Program Update 1994 Industrial Applicafions 
1 t 

Note: Mll*sto”s* to be remed ‘oNowl”g a,temathe site select/on and pro,ect mstructurlng 

DOE selected Cooperati”eagreeme”t 

yW&(CCT-W awarded 10127192 

‘Projected date 

Project Status/Accomplishments: MTCI pulse combustion technology that provides the Another potential application for the technology is 

The cooperative agreement was awarded on October 27, required &tier heat is a” inherently lawNOx combus- in industrial coal gasification because of its modularity 

and ability to produce a medium8tu gas without requiring an oxygen plant. 

1992. Design verification tests at MTCI’s Baltimore 

facility are continuing. The design tests include the 

constmction and test tiring of one full-size pulse combustor txbe bundle. Fabrication of the design-veritication-scale 252-tube pulse combustor has been completed. 0” October 26, 1994, ThennoChem, Inc., requested that DOE consider relocating the project to a” 

alternative host site. A detailed planning conference on 

changing sites was held in December 1994. 

tion process, thereby assuring that NO, emissions are 

substantially below acceptable limits. 

Because of its potential for reducing emissions 

Commercial Applications: 

The MTCI tluidized-bed gasitier is expected to provide 

the exceptional environmental perfomxmce 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% arc possible. Particulate emissions are also 

controlled in highly cfticient scrubbers. Finally, the 

while producing a clean-burning, hydrogen-rich fuel gas, 

the MTCI fluid&d-bed gasiticr is expected to have 

considerable commercial potential. Some of the early 

industrial applications of this technology are expected to 

be waste-to-energy or waste and coal cotired facilities for 

power and steam generation. One of the more promising 

non-coal applications is processing of kmft black liquor. 

The processing of pulp results in the production of 

about 8X million tons ofby-product black liquor. The 

cement 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 2Xunits 

annually. 

Indusrrial Applications Program Update I994 7-103 
Appendix E: CCT Project Contacts 

Listed in this section are contacts for obtaining 

timher information about specific CCT Program 

demonstration projects. Each listing provides the 

name, title, phone number, and mailing address of 

the coraxt person. In those instances where the 

project participant consists of more than one 

company, a partnership, or joint venture, the mailing 

address listed is that of the contact person. 

Advanced Electric Power Generation/ 

Fluidized-Bed Combustion 

PFBC Utility Demonstration Project 

Participant: 

The Appalachian Power Company 

Contacts: 

Mario Marrocco, Manager, PFBC Programs 

(614) 223-1740 

(614) 223-2466 (fax) 

American Elechic Power Service Corporation 

I Riverside Plaza 

Columbus, OH 43215 

Jeffrey Summers, DOE/HQ, (301) 903-4412 

Larry K. Carpenter, METC, (304) 285-4161 

PCFB Demonstration Project 

Participant. 

DMEC-I Limited Partnership 

Contacts: 

Gary E. Kmempel, Project Manager 

(515) 281-2459 

(515) 2X1-2355 (fax) 

Midwest Power Systems, Inc. 

907 Walnut 

P.O. Box 651 

Des Moines, IA 50303 

John G&ken, DOE/HQ, (301) 903-9430 

Larry K. Carpenter, METC, (304) 285-4161 

Four Rivers Energy Modernization Project 

Participanl. 

Four Rivers Energy Partners, L.P. 

Contacts: 

Edward Halley, Senior Project Manager 

(610) 481.8568 

(610) 481-3228 (fax) 

Air Products and Chemicals, Inc. 

7201 Hamilton Boulevard 

Allentown, PA 18195-1501 

William Femald, DOE/HQ, (301) 903-9448 

Larry K. Carpenter, METC, (304) 285-4161 

Tidd PFBC Demonstration Project 

Participant. 

American Electric Power Service Corporation as 

agent for The Ohio Power Company 

Contacts: 

Mario Marrocco, Manager, PFBC Programs 

(614) 223-1740 

(614) 223-2466 (fax) 

American Electric Power Service Corporatiu 

I Riverside Plaza 

Columbus, OH 432 I5 

Jeffrey Summers, DOE/HQ, (301) 903.4412 

Larry K. Carpenter, METC, (304) 285-4161 

Nucla CFB Demons&&ion Project 

Participant: 

T&State Generation and Transmission 

Association, Inc. 

Contacts: 

Marshall L. Pendergraff, Assistant General Manager 

(303) 249-4501 

Tri-State Generation and Transmission 

Association, Inc. 

P.O. Box I I49 

Montrose. CO 81402 . 

John GeB?w, DOEMQ, (301) 903-9430 

Nelson F. Rekos, METC, (304) 285-4066 

Program Update 1994 E-l 
York County Energy Partners Cogenerstion 

Project 

Participant: 

York County Energy Partners, L.P. 

Contacts: 

Bradley F. Hahn, Project Manager 

(610) 481-3955 

(610) 481-2393 (fax) 

York Coonty Energy Partners, L.P. 

15 So:r!b Main Street 

Spring Grove, PA 17362 

John Gefnten, DOEIHQ, (301) 903-9430 

Nelson F. Rekos, METC, (304) 285-4066 

Integrated Gasification Combined Cycle 

Combustion Engineering WCC Repowering 

Project 

Participonl: 

AllB Combustion Engineering, Inc. 

Contl7ct.K 

Hwry H. Vroom, Project Director 

(203) 2X5-9085 

(203) 285-3861 (fax) 

ABB Combustion Engineering, Inc. 

P.O. Box 500 

Windsor, CT 06095-0500 

Lawrence Samff, DOWHQ, (301) 903-9483 

Gary A. Nelkin, METC, (304) 285-4216 

Clean Energy Demonstration Project 

Participant: 

Clean Energy Partners Limited Partnership 

Contacts: 

Victor Shellhorse, Vice President 

(704) 373-2474 

(704) 382-9325 (fax) 

Duke Energy Corp. 

400 S. Tryon Street 

Charlotte, NC 28202 

Stanley Roberts, DOE&IQ, (301) 903-9431 

Donald W. Geiling, METC, (304) 285-4784 

Piiion Pine IGCC Power Project 

Participant: 

Sierra Pacific Power Company 

Contacts: 

John W. (Jack) Matter, Project Manager 

(702) 6X9-4013 

(702) 689-3047 (fax) 

Sierra Pacific Power Company 

6100 Neil Road 

P.O. Box 10100 

Reno, NV 89520-0400 

Lawrence Saroff, DOE/HQ, (301) 903-94X3 

Douglas M. Jewell, METC, (304) 2X5-4720 

Toms Creek IGCC Demonstration Project 

Participant. 

TAMCO Power Partners 

Con/acts: 

J.G. Patel, Project Director 

(404) 859-262 I 

(404) 9X4-2441 (fax) 

Tampella Power Corporation 

2300 Windy Ridge Parkway 

Suite II25 

Atlanta, GA 30339 

John G&ken, DOEIHQ, (301) 903-9430 

Gary A. Nelkin, METC, (304) 285-4216 

Tampa Electric Integrated Gasification 

Combined-Cycle Project 

Participant: 

Tampa Electric Company 

Contacts: 

Donald E. Pless, Director, Advanced Technology 

(813) 228.1332 

(813) 228-130X (fax) 

TECO Power Services Corporation 

P.O. Box I I1 

Tampa, FL 33601-01 I I 

William Femald. DOE/HQ, (301) 903-9448 

Nelson F. Rekos, METC, (304) 2X5-4066 

1 E-2 Program Update 1994 

I 
“’ :,,,. ,/ “I, .‘;*;“:<,,‘:.“, ‘. 

Wabash River Coal Gasification Repowering 

Project 

Participant: 

Wabash River Coal Gasification Repowering Project 

Joint Venhlre 

Contacts: 

Michel R. Woodruff 

(713) 7354131 

(713) 735.4169 (fax) 

Destec Energy, Inc. 

2500 City West Boulevard, Suite 1500 

Houston, TX 77042 

Jeffrey Summers, DOE&IQ, (301) 903-4412 

Gary A. Nelkin, METC. (304) 285-4216 

Advanced Electric Power Generation/ 

Advanced Combustion/Heat Engines 

Healy Clean Coal Project 

Participant. 

Alaska Industrial Development and Export Authority 

Contacts: 

John Olson, Project Manager 

(907) 561-8050 

Alaska Industrial Development and Export 

Authority 

480 West Tudor 

Anchorage, AK 99503.6690 

Stanley Roberts, DOEMQ, (301) 903-9431 

Robert M. Komosky, PETC, (412) 8924521 

Coal Diesel Combined-Cycle Project 

Participant: 

Arthur D. Little, Inc. 

Contacts: 

Robert P. Wilson, Vice President 

(617) 498-5806 

(617) 498-7206 (fax) 

Arthur D. Little, Inc. 

200 Acorn Park 

Cambridge, MA 02 140 

Jeffrey Summers, DOEiHQ, (301) 903-4412 

Nelson F. Rekos, METC, (304) 285-4066 

Warren Station Externally Fired Combined-Cycle 

Demonstration Project 

Participant: 

Pennsylvania Electtic Company 

Contacts. 

Kenneth Gray, Project Manager 

(814) 533-8593 

(814) 533-8108 (fax) 

Pennsylvania Electric Company 

1001 Broad Street 

Johnsontown, PA 15907 

Douglas Archer, DOEnlQ, (301) 903-9443 

Donald W. Geiling, METC, (304) 2854784 

Environmental Control Devices/NO, Control 

Technologies 

Demonstration of Coal Reburniog for Cychme 

Boiler NOx Control 

Participant: 

The Babcock & Wilcox Company 

t3nfocts. 

Tony Yagiela 

(2 16) 829-7403 

The Babcock & Wilcox Company 

1562 Beeson Street 

Alliance, OH 4460 I 

Jeffky Summers, DOEiHQ, (301) 903-4412 

Ronald W. Corbett, PETC, (412) 89&6141 

FullScale Demonstration of Low-NO, CellBurner 

Retrofit 

Participant: 

The Babcock & Wilcox Company 

Contacts: 

Tony Yagiela 

(216) 829-7403 

The B&cock & Wilcox Company 

1562 Beeson Street 

Alliance, OH 44601 

J&q Summers, DOEiHQ, (301) 903-4412 

Ronald W. Corbett, PETC, (412) 892-6141 

Pmgrnm Update 1994 E-3 
Evaluation of Gas Reburning and Low-NO, 

Burners on a Wall-Fired Boiler 

Participant: 

Energy and Environmental Research Corporation 

Con1octs: 

Blair A. Folsom, Senior Vice President 

(714) 859-8851 

Energy and Environmental Research 

Corporation 

I8 Mason 

Irvinc, CA 92718 

%‘illiam Femald, DOWHQ, (301) 903-9448 

~lnny J. Ritz, PETC, (412) 892-6137 

Drmoastratlon of Advanced Combustion 

Techniques for a Wall-Fired Boiler 

Pm+ipant: 

Southcm Compnny Services, Inc. 

Cor:twts: 

Johtn N. Sornc, ICCT Project Manager 

t205) X 77-7426 

Southern Company Services, Inc. 

r.0. Box 2625 

Rirmingham, AL 35202-2625 

William Fcmald, DOE/HQ, (301) 903-9448 

Scott M. Smousc, PETC, (412) 892-5725 

IEO-MWe Demonstration of Advanced 

Tangentially Fired Combustion Techniques for the 

Reduction of NO, Emissions from Coal-Fired 

Boilers 

Participant: 

Southern Company Services, Inc 

Robert R. Hardman, Project Manager 

(205) 877-7772 

Southern Company Services, Inc. 

P.O. Box 2625 

Birmingham, AL 35202-2625 

William Fcmald, DOEiHQ, (301) 903-9448 

Gerard G. Elia, PETC, (412) 892-5862 

Demonstration of Selective Catalytic Reduction 

Technology for the Control of NO, Emissions from 

HighSalTar-Coal-Fired Boilers 

Participant: 

Southern Company Services, Inc 

Contacts: 

J.D. (Doug) Maxwell, Project Manager 

(205) 877-7614 

Southern Company Services, Inc. 

P.O. Box 2625 

Birmingham, AL 35202-2625 

William Fcmald, DOE/HQ, (301) 903-9448 

Arthur L. Baldwin, PETC. (412) 892-601 I 

Micronized Coal l&burning Demonstration of 

NO, Control oa a 17%MWe Wall-Fired Unit 

Parlicipanr: 

Tcnncsscc Valley Authority 

COnfUCtS: 

Tom Butler. Mechanical Engineer 

(615) 751-6120 

Tennessee Valley Authority 

I IO1 Market Street, ATTN: MR-3A 

Chattanooga, TN 37402 

Stanley Roberts, DOE/HQ, (301) 903-943 I 

James U. Watts, PETC, (412) X92-5991 

Environmental Control Devices/SO, Control 

Technologies 

IO-MWe Demonstration of Gas Suspension 

Absorption 

Participant: 

AirPol, Inc. 

conrac1s: 

Frank E. Hsu, Project Manager 

(201) 288-7070 

AirPol, Inc. 

32 Henry Street 

Tetcrboro, NJ 07608 

Lawrence Saroff, DOE/HQ, (301) 903-9483 

Sharon K. Marchant, PETC, (412) 892-6008 

E-4 Program updote I994 
Confined Zone Dispersion Flue Gas 

Desulfurization Demonstration 

Participant: 

Bechtel Corporation 

COfltUCtS. 

Joseph T. Newman, Project Manager 

(415) 768-6514 

Bechteel Corporation 

P.O. Box 3965 

San Francisco, CA 94119-3965 

Stanley Roberts, DOE/HQ. (301) 903-9431 

Arthur L. Baldwin, PETC, (412) 892-601 I 

LIFAC Sorbent Injection Desulfurization 

Demonstration Project 

Participant: 

LIFAC-North America 

Contacts: 

Jim Hervol, Project Manager 

(412) 497.2735 

ICF Kaiser Engineers, Inc. 

4 Gateway Cater 

Pittsburgh, PA 15222-1207 

John Geffken, DOERIQ, (301) 903-9430 

Joanna M. Markussen, PETC, (412) 892-5734 

Advanced Flue Gas Desulfurization 

Demonstration Project 

Participant: 

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 

Lawrence &off. DOEIHQ, (301) 903-9483 

Thomas A. Sarkus, PETC, (4 12) 892-598 I 

Demonstration of Innovative Applications of 

Technology for the CT-121 FGD Process 

Participant: 

Southern Company Services, Inc. 

Contacts: 

David P. Burford, Project Manager 

(205) X70-6329 

Southern Company Services, Inc. 

P.O. Box 2625 

Birmingham, AL 35202-2625 

Lawrence Saroff, DOE/HQ, (301) 903-9483 

Harry J. Ritz, PETC, (412) 892-6137 

Environmental Control Devices/Combined 

SOJNO, Control Technologies 

SNOXTM Flue Gas Cleaning Demonstration 

Project 

Participant: 

ABB Environmental Systems 

Contacts: 

Bill Kingston, Project Manager 

(205) 995-5368 

ABB Environmental Systems 

P.O. Box 43030 

Birmingham, AL 35243 

Stanley Roberts, DOEiHQ, (301) 903-943 I 

Gerard G. Elia, PETC, (412) 892-5862 

LIMB Demonstration Project E&tcoaicn and 

Coolside Demonstration 

Participant: 

The B&cock & Wilcox Company 

Contacts: 

Paul Noland 

(216)860-1074 

(216) 860-2045 (fax) 

The Babcwk & Wilcox Company 

1562 Beeson Street 

Alliance, OH 44601 

William Femald, DOE/HQ, (301) 903-9448 

Joanna M. Markussen, PETC, (412) 892-5734 

Program Update I994 E-5