Global Energy Business May/June 2001 Feature
have a stranglehold over fuel transportation."
================================================================
http://www.fetc.doe.gov/publications/press/1999/tl_global.html
U.S. Department of Energy
Issued on November 15, 1999
Richardson Approves
Federal Funding for
High-Tech, Ultra-Clean Coal Plant
in Kentucky
Energy Secretary Bill Richardson, Kentucky Governor Paul Patton,
and Senator Mitch
McConnell today announced that the Kentucky Pioneer Energy Project,
planned for Clark
County, KY, will become part of the federal government's Clean
Coal Technology Program.
Richardson approved the use of $78 million in Clean Coal Technology33333
funding as the federal share of the $432 million project. The
400-megawatt project will be one of the largest power plant
projects in
the federal Clean Coal Technology Program. The program provides
federal
matching funds for projects that demonstrate new ways to use
coal while
reducing air and other pollutants.
"The Kentucky Pioneer Energy Project will be a showcase facility,"
Richardson said. "It will
employ advanced, clean technology that will benefit the environment,
provide low cost power to
spur economic growth, and demonstrate how cities can eliminate
municipal solid waste by
mixing it with coal to produce electricity."
"The Energy Department's participation is a major boost for the
project," said Governor Patton.
"It means that project financing will be significantly strengthened
and the project will be able to
incorporate additional high-tech innovations. Importantly for
Kentucky consumers, the plant
will produce electricity at rates that will be among the lowest
in the State."
"This public-private sector partnership we are announcing today
will help move Kentucky's
coal and electric power industries into the 21st century with
some of the most sophisticated
technology now available," said Senator McConnell. "The government's
role in this project
represents a solid investment in the energy future of Kentucky
and this country."
The federal funding is part of agreements reached this week between
the Energy Department,
Duke Energy Corp. of North Carolina, and Global Energy Inc.,
the Cincinnati-based parent
company of Kentucky Pioneer Energy. Under the agreements, Global
Energy will replace Duke
Energy as the department's industrial partner in a Clean Coal
Technology project that had
encountered siting difficulties in southern Illinois.
The Illinois project was to employ much of the same technology
as the Kentucky project, and
as part of this week's agreements, the Energy Department will
approve "relocating" the project
to eastern Kentucky. Global Energy, in turn, agreed to incorporate
several unique features of
the Illinois project into the Kentucky project, including tests
of advanced fuel cell. The company
will also provide the Energy Department with technology data
from the project's design,
construction and operation.
Plans are to use a site near Trapp, Kentucky, originally slated
for a conventional coal-fired
power plant nearly two decades ago. When the forecasted demand
for electricity failed to
materialize in the early 1980s, construction at the East Kentucky
Power Cooperative's J.K.
Smith site was halted, leaving an excavated tract with plant
foundations, an administration
building, railroad spur and connections to the electrical grid.
Now, the idle 300-acre tract will become the site for a new type
of ultra-clean coal technology.
Known as "integrated gasification combined cycle," the advanced
process first converts coal to
a "synthesis gas." A key advantage of the gasification step
is that the synthesis gas can be
meticulously cleaned before it is burned to generate electricity.
In the Kentucky project, the gasification process will incorporate
an added "advanced fuel
technology" feature. Municipal solid waste will be collected
and combined with coal to form
fuel briquettes for the gasification process. Global is reviewing
possible "fuel island" locations
around the State where the briquettes will be made.
The synthesis gas will be burned in a combustion turbine to generate
electricity and exhaust
heat will be used to boil water to drive a steam turbine. The
combination of the two types of
power generating turbines accounts for the name "combined cycle."
Another high-tech innovation will be the use of a fuel cell in
the plant's power generating
section. Fuel cells generate electricity using an electrochemical
reaction, much like a battery.
Because no combustion is involved, fuel cells are among the
cleanest power technologies now
envisioned. In the Kentucky project, some of the synthesis gas
will be directed to a
1.25-megawatt molten carbonate fuel cell to be furnished by
FuelCell Energy Inc. of Danbury,
CT.
When operations begin in 2002, electricity from the plant will
be sold to East Kentucky Power
Cooperative under a 20-year contract.
The project is the fourth in the Clean Coal Technology Program
to demonstrate coal gasification
but the first to be partially fueled by municipal solid waste
and to employ a fuel cell. It will also
mean $105 million in cost savings for the taxpayer. The Illinois
project had been projected to
cost $841 million with the Energy Department's share amounting
to $183 million. Under the
new project agreement, the Energy Department's share will be
capped at $78 million.
- End of TechLine -
===============================
http://edj.net/sinor/sfr1-00art5.html
FEDERAL FUNDING APPROVED FOR KENTUCKY PIONEER ENERGY PROJECT
In November the United States Department of Energy (DOE) announced that
the Kentucky Pioneer Energy Project, planned for Clark County, Kentucky,
will
become part of the federal government?s Clean Coal Technology Program.
United States Energy Secretary B. Richardson approved the use of $78
million in Clean Coal Technology funding as the federal share of the $432-million,
400-megawatt project.
"The Kentucky Pioneer Energy Project will be a showcase facility," Richardson
said. "It will employ advanced, clean technology that will benefit the
environment, provide low cost power to spur economic growth, and demonstrate
how cities can eliminate municipal solid waste by mixing it with coal to
produce electricity."
The federal funding is part of agreements reached between the United
States Energy Department, Duke Energy Corporation of North Carolina, and
Global
Energy Inc., the Cincinnati-based parent company of Kentucky Pioneer
Energy. Under the agreements, Global Energy will replace Duke Energy as
the
department?s industrial partner in a Clean Coal Technology project
that had encountered siting difficulties in Southern Illinois.
The Illinois project was to employ much of the same technology as the
Kentucky project, and as part of the agreements, the Energy Department
will approve
"relocating" the project to Eastern Kentucky. Global Energy, in turn,
agreed to incorporate several unique features of the Illinois project into
the Kentucky
project, including tests of advanced fuel cells. The company will also
provide The DOE with technology data for the project?s design, construction
and
operation.
Plans are to use a site near Trapp, Kentucky, originally slated for
a conventional coal-fired powerplant nearly 2 decades ago. When the forecasted
demand for
electricity failed to materialize in the early 1980s, construction
at the East Kentucky Power Cooperative?s J.K. Smith site was halted, leaving
an excavated
tract with plant foundations, an administration building, railroad
spur and connections to the electrical grid.
Now the idle 300-acre tract will become the site for a new integrated gasification combined-cycle powerplant.
In the Kentucky project, the gasification process will incorporate an
added feature. Municipal solid waste will be collected and combined with
coal to form fuel
briquettes for the gasification process. Global is reviewing possible
"fuel island" locations around the state where the briquettes will be made.
Another high-tech innovation will be the use of a fuel cell in the plant?s
power generating section. Because no combustion is involved, fuel cells
are among the
cleanest power technologies now envisioned. In the Kentucky project,
some of the synthesis gas will be directed to a 1.25-megawatt molten carbonate
fuel cell
to be furnished by FuelCell Energy Inc. of Danbury, Connecticut.
When operations begin in 2002, electricity from the plant will be sold to East Kentucky Power Cooperative under a 20-year contract.
The project is the fourth in the Clean Coal Technology Program to demonstrate
coal gasification but the first to be partially fueled by municipal solid
waste and
to employ a fuel cell.
=============================
Duke Energy: Main Phone #
1-800 USE-DUKE (1-800-873-3853)
=============================
http://ens.lycos.com/ens/jul99/1999L-07-27-09.html
AmeriScan: July 27, 1999
RISING COAL USE INCREASES AIR POLLUTION
Coal consumption in the U.S. has risen almost 16 percent since 1992, says
a report by the
Environmental Working Group and the U.S. Public Interest Research Group
(USPIRG).
Many older coal burning power plants were exempted from Clean Air Act standards.
When
Congress deregulated wholesale electricity sales in 1992, these old plants
became more
profitable because they compete with more recently built plants required
to install pollution
control equipment. The report, "Up In Smoke," looks at federal data on
446 power plants
across the nation, tracks the use of coal plants since the 1992 Energy
Policy Act was
passed, and calculates the resulting smog and global warming pollution.
Increased electrical
generation at coal burning plants emitted 755,000 tons of nitrogen oxide
pollution and 298
million tons of carbon dioxide in 1998. By increasing coal generation,
eight large utility
companies, American Electric Power Company, Cinergy Corporation, Dominion
Resources
Inc, Duke Power Company, Edison International, The Southern Company, Tennessee
Valley
Authority and Associated Electric Coop each emitted as much smog pollution
as one million
cars. Increased smog pollution from Illinois, West Virginia, North Carolina,
Missouri,
Indiana and Georgia power plants each equaled that from two million cars.
"This summer,
tens of thousands of Americans will go to emergency rooms due to smog,"
said Rebecca
Stanfield, clean air advocate for USPIRG. "It's time for Congress to protect
public health by
closing the loopholes allowing old coal plants to pollute our air."
* * *
==============================
http://energy-tech.com/cgi-bin/news_search.cgi?a=1&type=newsnumber&search=n001291
Posted on Energy-Tech.com on: 2001/12/04
Americans Favor Alternative Energy Methods to Solve Shortages
According to a new poll by the Gallup Company, Americans favor investment
in the country's energy
infrastruture and the development of alternative energy sources. However,
while more than 80% of the
respondents favor the creation of new power plants, the number favoring
more nuclear plants has
dropped since the last poll in May. Anaylysts assume the decreased
support for nuclear plants stems from
the September 11 terrorists attacks and heightened concerns over the
security risks posed by nuclear
plants.
In terms of renewable energy sources, the poll found 91% of Americans
in favor of developing these
sources. While the September 11 attacks helped raise concern over the
countrie's dependence on
forgeign oil, a slim majority still oppose opening the Artic National
Wildlife Refuge to oil exploration. 51%
are opposed to the move, compared to 57% opposed in May.
These results are based on telephone interviews with a randomly selected
national sample of 512 adults,
18 years and older, conducted Nov. 8-11, 2001. For results based on
this sample, one can say with 95
percent confidence that the maximum error attributable to sampling
and other random effects is plus or
minus 5 percentage points. In addition to sampling error, question
wording and practical difficulties in
conducting surveys can introduce error or bias into the findings of
public opinion polls.
====================================
Posted on Energy-Tech.com on: 2001/11/30
http://energy-tech.com/cgi-bin/news_search.cgi?a=1&type=newsnumber&search=n001284
U.S. Carbon Dioxide Emissions Increase by 3.1 Percent in 2000
Estimated emissions of carbon dioxide in the United States and its territories,
which account for more
than 80 percent of total U.S. greenhouse gas emissions, increased by
3.1 percent in 2000, rising from
1,536 million metric tons of carbon equivalent (MMTCe) in 1999 to 1,583
MMTCe in 2000, according to
Emissions of Greenhouse Gases in the United States 2000, a report released
by the Energy Information
Administration (EIA). The growth in carbon dioxide emissions, 3.1 percent,
was one percentage point
below the 4.1 percent growth in Gross Domestic Product (GDP). Energy-related
carbon dioxide
emissions, which account for 98 percent of total carbon dioxide emissions,
stood at 1,547 MMTCe, while
carbon dioxide emissions from other sources were 36 MMTCe.
The 3.1 percent growth in emissions in 2000 is the second highest growth
rate for the 1990 to 2000 period,
with only the 3.4-percent growth rate in 1996 being higher, and is
well above the average growth rate of
1.6 percent for the 1990 to 2000 time frame. The high growth in carbon
dioxide emissions can be
attributed to a return to more normal weather, decreased hydroelectric
power generation that was
replaced by fossil-fuel power generation, and strong economic growth
(4.1 percent increase in GDP).
Total U.S. greenhouse gas emissions rose by 2.5 percent in 2000, increasing
from 1,860 million metric
tons of carbon equivalent (MMTCe) in 1999 to 1,906 MMTCe in 2000. The
2000 growth rate of 2.5
percent was well above the average annual growth rate of 1.3 percent
observed from 1990 to 2000, as
well as the 1999 growth rate of 1.3 percent.
Total estimated U.S. greenhouse gas emissions in 2000 consisted of 1,583
MMTCe of carbon dioxide (83
percent of total emissions), 177 MMTCe of methane (9 percent of total
emissions), 99 MMTCe of nitrous
oxide (5 percent of total emissions), and 47 MMTCe of hydrofluorocarbons
(HFCs), perfluorcarbons
(PFCs) and sulfur hexafluoride (SF6) (2 percent of total emissions).
Detailed information by greenhouse
gas includes the following:
Estimated methane emissions, the second largest contributor after carbon
dioxide to total greenhouse
emissions, declined by 1.6 percent, from 180 MMTCe in 1999 to 177 MMTCe
in 2000. Since 1990, U.S.
methane emissions have declined by about 11 percent.
Estimated nitrous oxide emissions in 2000 fell by 0.6 percent, from
100 MMTCe in 1999 to 99 MMTCe in
2000. Nitrous oxide emissions have grown by 5.3 percent since 1990.
Emissions of human-made gases such as hydrofluorocarbons (HFCs), perfluorocarbons
(PFCs), and
sulfur hexaflouride experienced a 4.5 percent increase (from 45 to
47 MMTCe) between 1999 and 2000.
However, these gases as a group have grown by 57.8 percent since 1990.
The report also contains estimates of carbon dioxide emissions from
energy consumption, including
emissions from purchased electric power, on a sectoral level:
Transportation-related carbon dioxide emissions, which account for about
a third of the total carbon
dioxide emissions from energy consumption, increased by 3.1 percent
in 2000 to 515 MMTCe in 2000, as
a healthy economy encouraged travel and the delivery of goods.
Carbon dioxide emissions in the residential sector increased by 4.9
percent to 313 MMTCe, while
emissions in the commercial sector rose by 5.8 percent to 268 MMTCe
in 2000. This growth was driven
by a return to more normal weather, higher fossil-fueled power generation
and a strong economy.
Despite rapid growth of the economy (4.1 percent growth), energy-related
industrial carbon dioxide
emissions in 2000 remained flat at 466 MMTCe. This constancy is due
in part to slower growth in the
energy-intensive industries compared with the non-energy-intensive
industries and possible efficiency
improvements.
Carbon dioxide emissions from the U.S. electric power sector in 2000,
which are included in the sectoral
totals above, are estimated at 642 million metric tons carbon equivalent,
4.7 percent higher than the 1999
level. The 2000 increase is almost double the 1990-2000 average increase
of 2.4 percent per year.
Contributing to the relatively large increase in 2000 was a 4.2 percent
increase in fossil fuel use for
electricity generation, as well as an 11 percent reduction in electricity
generation from renewable fuels,
including a 14 percent drop in hydroelectric generation.
Emissions of Greenhouse Gases in the United States 2000 was prepared
by EIA pursuant to section
1605(a) of the Energy Policy Act of 1992. EIA is an independent, policy-neutral
agency within the
Department of Energy that is responsible for collecting, analyzing,
and disseminating energy information.
An electronic version of the report is available on EIA's Web site at
ftp://ftp.eia.doe.gov/pub/oiaf/1605/cdrom/pdf/ggrpt/057300.pdf. Printed
copies of the Executive Summary
of the report will be available in November from the U.S. Government
Printing Office, 202/512-1800 or
through EIA's National Energy Information Center, 202/586-8800.
==================================
http://energy-tech.com/cgi-bin/news_search.cgi?a=1&type=newsnumber&search=n001259
Posted on Energy-Tech.com on: 2001/10/03
Contracts Awarded For Commercialization Of Mercury Detection And
Removal Technologies
The EPA recently awarded contracts to four small business companies
for the final development and
initial commercialization of new environmental technologies for mercury
removal and monitoring.
Mercury produced by combustion sources is a major concern to the country's
air quality. The Small
Business Innovation Research (SBIR) program spawns commercial ventures
that improve our
environment and quality of life, create jobs, increase productivity
and economic growth, and improve
international competitiveness of the country's technology industry.
For this reason, ADA Technologies
Inc. of Littleton, Colo., and Sorbent Technologies Inc. of Twinsburg,
Ohio, are developing new sorbents to
remove mercury from coal-fired power plants. These new materials and
processes have the capacity to
remove substantially more mercury than traditional activated carbon
methods at a lower cost. Apogee
Scientific Inc. of Englewood, Colo., is developing an analyzer that
will give real-time monitoring
information in flue gas from coal-fired boilers. A major advantage
of this new system is that it will be able
to distinguish between different types of mercury, allowing utilities
to make better decisions on control
options. Frontier Geosciences of Seattle, Wash., is developing a method
to remove mercury and other
toxic metals from industrial waste water. Frontier Geosciences will
be working with Unocal Thailand Ltd.
to ensure quick application of this technology to the field.
===================================
http://www.pirg.org/reports/enviro/lethal/
Premature mortality: The U.S. Environmental Protection Agency (EPA)
estimates that
"soot," or "fine particulate" air pollution
causes more than 40,000 premature deaths each
year. Older-coal-burning power plants are
the largest source of sulfur dioxide (SO2), a
primary component of soot.
Human developmental and neurological damage: Mercury pollution has contaminated
the
fish in thousands of U.S. lakes and streams.
Today 40 states have issued warnings against
consuming fish due to the risk of methylmercury
exposure.(4) When ingested by pregnant or
nursing women, methylmercury can cause neurological
damage, including delayed
development in the fetus and young children.
Coal-burning power plants are the largest
known domestic industrial source of mercury.
Ranking of the States
For each of the four pollutants under consideration,
the report ranks each state according to
total tons emitted by in-state plants in 1999
(for SO2, NOx and CO2) and estimated
emissions from 1998 for mercury.
The top ten states for each pollutant are:
SO2
NOx
Mercury
CO2
Ohio
Ohio
Pennsylvania
Texas
Pennsylvania
Texas
Texas
Indiana
Indiana
Indiana
Ohio
Ohio
Florida
Kentucky
Illinois
Florida
Illinois
West Virginia
Alabama
Kentucky
Texas
Florida
Indiana
Pennsylvania
West Virginia
Illinois
West Virginia
West Virginia
Kentucky
North Carolina
Kentucky
Illinois
Alabama
Pennsylvania
North Carolina
Alabama
Georgia
Missouri
Michigan
Georgia
The Dirty Dozen Holding Companies
For each of the four pollutants under consideration,
the report provides a list of "Dirty Dozen"
companies, based on the amount of pollution
emitted by plants owned by company in 1999
(for SO2, NOx and CO2) and estimated emissions
from 1998 for mercury.(6) For each
pollutant, the Dirty Dozen companies are:
SO2
NOx
Mercury
CO2
Southern Company
Southern Company
Southern Company
Southern Company
American Electric
Power
Tennessee Valley
Authority
American Electric
Power
American Electric
Power
Tennessee Valley
Authority
(TVA)
American Electric
Power
GPU, Inc.
Tennessee Valley
Authority
Cinergy Corp.
Allegheny Power
System
Commonwealth Edison
Texas Utilities
Allegheny Power
System
Texas Utilities
Tennessee Valley
Authority
Allegheny Power
System
GPU, Inc.
Cinergy Corp.
Texas Utilities
Cinergy Corp.
Texas Utilities
Dominion
Resources
Allegheny Power
System
Entergy
Illinova Corp.
PacifiCorp
Dominion Resources
PacifiCorp
Dominion
Resources
Entergy
Cinergy Corp.
Central and
Southwest Corp.
Carolina Power &
Light
Duke Power
Central and Southwest
Corp.
Dominion
Resources
Ohio Edison
Company
Carolina Power &
Light
Carolina Power & Light
GPU, Inc.
Duke Power
Company
Central and
Southwest Corp.
PacifiCorp
Carolina Power &
Light
Vulnerable Populations Living Near Dirty Power
Plants
In 1997, there were 236.8 million Americans
living in counties that fell wholly or partly within
a 50 mile radius of one of the 594 dirty power
plants. The health impacts of smog and soot
pollution fall disproportionately on certain
vulnerable populations, including children whose
lungs are still undergoing development, seniors,
and those who suffer from respiratory
illnesses Of the people living in counties
falling wholly or partly within 50 miles of a dirty
power plant, 56.3 million are children under
17 years of age, 27.9 million are seniors over 65
years of age, 13.1 million are people who
suffer from asthma, and 14.7 million are people who
suffer from either chronic emphysema or chronic
bronchitis.
==============================================
http://www.icci.org/news/gov2000.html
October 24, 2000
Contact: Nick Palazzolo
217-782-7355 217/524-5136
TTD: 800-526-0844
Brian Reardon, DCCA
Governor's Coal Conference Highlights Clean Coal Initiatives
SPRINGFIELD -- The 2000 Governor?s Illinois Coal Conference convened
in Springfield today, with a focus on fostering the development and deployment
of clean coal-burning
technologies.
"As a state we?ve made progress in promoting clean coal technologies,"
Governor George H. Ryan said. "However, more must be done to find new uses
for Illinois coal in ways
that are better for the environment. And that?s why we?ve brought together
not only the public and private sectors, but also producers, suppliers,
transporters and consumers to
discuss the issues facing Illinois? coal industry.
Panel discussions at the conference will cover such topics as coal ash
management, air quality goals, and changes in the markets for Illinois
Basin coal. Speakers will include
General Richard Lawson, president of the National Mining Association,
and Robert E. Murray, CEO of American Coal Sales Co.
Over the last 20 years, Illinois has achieved a 35 percent reduction
of sulfur dioxide emissions as the use of clean coal technology has increased.
During that time, the state has
deployed $108 million in Coal Bond Funds for new commercial technology
that?s lead to cleaner power plants and other coal-burning facilities.
Since 1982, Illinois has invested an additional $50 million in basic
and applied clean coal research, the largest coal research commitment of
any state in the nation. The Illinois
Department of Commerce and Community Affairs? (DCCA) Coal Research
and Development Programs sponsor and promote the advancement of technology
with special emphasis
on the removal of sulfur and other pollutants emitted during the combustion
of high-sulfur Illinois coal.
The program is administered by DCCA under the technical oversight of the Illinois Clean Coal Institute, located in Carterville, Illinois.
"This year, we are enhancing our commitment to clean coal technology and research by awarding $1.6 million in grants for 13 different projects," Ryan added.
"Under the leadership of Governor Ryan, scientists working on clean
coal breakthroughs will have the resources to continue and commercialize
significant projects to ensure that
Illinois Coal remains a viable part of the mix for generating power
in the Midwest and the nation," said DCCA director Pam McDonough.
"We have seen some positive developments in recent weeks, and the purpose
of this conference is to sustain the momentum we have," McDonough added.
"This afternoon, a major
energy co-operative is announcing their participation in a project
that the state committed $25 million to last year. It involves a low-emission
boiler system demonstration project
in Elkhart that will involve an 80 mega watt power generation station."
In addition to the state?s commitment to coal bond funding and research,
Commonwealth Edison has donated $25 million to the cause as a result of
the sale of its fossil fuel
generating stations. Southern Illinois University has established a
Clean Coal Review Board to oversee the development and implementation of
projects funded from the grant.
Seven innovative clean-coal projects last week won financial backing
totaling $9.25 million from the Clean Coal Review Board for high-tech improvements
at mines and electric
utilities in central and southern Illinois.
"The projects' technologies and applications are quite diverse: from
coal cleaning and gasification at the mine site to new coal combustion
at commercial and utility settings," said
SIUC Interim Chancellor John S. Jackson. ?This diversity demonstrates
the wide range of markets that will be open to Illinois coal as clean-coal
technologies gain acceptance
across the country."
A thumbnail sketch of each funded project:
Ashworth Combuster Demonstration, Lincoln,
$1 million. This project will demonstrate a break-through, three-stage,
pulverized coal combustion technology. Lime or
limestone will be added with coal in the first
stage to remove a high percentage of sulfur and ash before the fuel gas
enters the boiler furnace.
Arclar Central Preparation Plant and Coal
Handling System, Equality, $2 million. Funds will be used to build a preparation
plant that uses state-of-the-art washing
technologies to clean coal before it is shipped
to market.
Close-Coupled Gasification Microgeneration
Power Plants, Elkhart and Coulterville, $2 million. Funds will assist in
the construction of two complete facilities that use fine
coal waste during gasificiation to generate
electricity at the mine sites. The goal is to use what would otherwise
be a waste product to provide energy, lowering the mines'
operating costs and making them more competitive.
Prairie Energy Project, Elkhart, $2 million.
The project will develop a slagging furnace with low nitrous oxide emissions
while producing beneficial ash. The project aims to
boost consumption of Illinois coal and demonstrate
a clean-coal technology viable for larger electric utilities.
Installation of Advanced Fine Coal Cleaning
Equipment, Pattiki Mine's preparation plant in Carmi, $1 million. The goal
is to replace an inefficient fine coal air separator with
new, advanced fine coal processing equipment.
The new system will reduce the coal's sulfur dioxide emissions while improving
the plant's ability to recover the
by-product.
Demonstration of a Coal Industrial Park for
Illinois Coal Industry Enhancement, Elkhart, $250,000. Sounthern Illinois
University mining engineers will study the feasibility of
a new total-concept mine facility that would
encompass environmentally friendly coal extraction, cleaning, processing
and power generation at a single location.
Marion Circulating Fluidized Bed Boiler Repowering
Project, near Marion, $1 million. This electric utility will install a
clean, coal-fired fluidized bed combustion system
large enough to replace three older, coal-fired
power units.
================================
http://www.icci.org/00final/malhotra.htm
FINAL TECHNICAL REPORT
November 1, 1999, through October 31, 2000
Project Title: AGRO-FGD SCRUBBER SLUDGE WALLBOARD COMPOSITES
ICCI Project Number: 99-1/2.1C-2
Principal Investigator: Vivak M. Malhotra, Southern Illinois University at Carbondale
Project Manager: Dr. Ronald H. Carty, ICCI
Introduction: About 22 million tons of flue gas desulfurization
(FGD) scrubber sludge are currently produced in the U.S. every year.
Most of it is disposed in
the landfills near power plants. In Illinois, Indiana, and Western
Kentucky 6 million tons of wet scrubber sludge are currently produced.
About 7,000 MW of
additional capacity is expected to be wet scrubbed in the near future
in response to the Clean Air Act Amendments of 1990; and this will further
increase the
amount of wet scrubber sludge produced annually. Currently only
about five percent (5%) of wet scrubber sludge is utilized nationally.
Most of the FGD
scrubber sludge, which had found some use in Portland cement or agriculture
or plaster is sulfate-rich sludge. The wallboard industry is reluctant
to use FGD
by-product gypsum because of the impurities, both organic and inorganic,
and variations in the product from batch to batch. However, for sulfite-rich
scrubber
sludge the utilization is much bleaker even though some use as structural
fill and as aggregates has been proposed. Therefore, there is a strong
need to develop
additional utilization strategies for wet FGD scrubber sludge.
=========================================
http://www.commoncause.org/publications/hot/chart1.htm
January 1, 1989 through June 30, 1999
Total PAC And Soft Money Contributions From Members Of The Global Climate
Coalition
Total: $ 63,470,718
==========================================
http://www.retailenergy.com/articles/riskmanagement.htm
RISK MANAGEMENT FOR MERCHANT
POWERPLANT FINANCING
by Roger D. Feldman
Partner, Bingham Dana LLP
(originally published in the Cogeneration and Competitive Power Journal.
For subscription information, call
(770) 925-9388)
The use of risk management devices has been an increasing response to merchant
power plant finance
uncertainties. The importance of credit enhancement as an element of successful
merchant plant financing
clearly is an evolving matter which will be affected by the maturity of
systems of regulation, and the reliability of
power marketing backstops for projects. The basic question is: can risk
management be a satisfactory surrogate
in the financial markets for cash flow stress elements arising from those
fundamental transactional elements
typically singled out by the rating agencies?
The types of risk management being undertaken today are not necessarily
disclosed by the way in which energy
marketing affiliates have entered off-take arrangements with their special
purpose project development
companies. It is to be anticipated that over time there will be greater
analysis of the track records of individual
power marketing affiliates as risk managers, and, of counter party/credit
enhancers as well who assume risk and
seek to hedge it.
Certainly the experiences of the summer of 1998, highlighting the uncertainties
of the risk management markets,
will necessitate such analysis in individual deals, particularly to the
extent that power export outside of the local
grid is an important part of the project?s power marketing strategy. Whether
private sector Transcos will
exacerbate the pressure on power price volatility, in an effort to maximize
profit, remains to be seen.
The rating agencies have, of course, already taken note that effective
risk management techniques will
distinguish the emerging merchant power plant (?MPP?) industry from the
old IPPs. Standard & Poors
emphasizes the value to proposed project financings of in-place power marketing
services, including presence of
in-house risk management infrastructure and quality of plant information
technology, and real time data
acquisition abilities to track price fluctuations and load flows in volatile
markets.
Initial specific transaction design should build on these features by taking
into account the need to preserve
flexibility in energy transaction options with respect to transportation,
sales, transmission and mode of operation,
as well as form of credit support. However, while sales strategies based
on specific market niches tied to hedging
may be feasible and attractive in certain instances, S&P notes: ?as
in the case for most commodity markets,
identifying, developing and dwelling in that ephemeral position on the
kinked portion of the demand curve may
prove to be forever elusive.?
Strategies to alleviate excessive trading market risk include the fashioning
of quasi-merchant plants around
strong industrial off takers; to establish them as split offs from utility
plants selling back to utilities; to preserve
them as continued providers under preexisting power sales arrangements
with the utility which previously
directed their sales or to structure other partial, long-term off-take
arrangements.
There are limits to what risk management can achieve on individual projects.
The transition of the use of risk
management for individual projects into a broadening of merchant plant
capital markets is provided by credit
enhancement.
Increasingly larger integrated capital pools for risk assumption are seeking
ways not merely to provide a credit
grade up tick, but to assume those specifically identified risks necessary
to achieve project financeability (and
themselves, thereafter, backfill behind those risks through a mixture of
commodity-type trading, risk spreading
through reinsurance, and development of appropriately priced financial
products). Credit enhancers are reaching
into the marketplace as teammates, but perhaps ultimately as the displacers,
of traditional investment banking
structuring activities.
PORTFOLIO FINANCE
At this intersection between fuel convergence energy projects and credit
enhancement, is where the future
prospects for merchant plants as the building blocks of large enterprises
which possibly may be corporate
financed. Power revenues as a type of cash flow, with which risk management
markets have gotten statistically
comfortable as to their aggregate forward price curve profile, may be credit
enhanceable to a level where
merchant plant securitization as well as corporate finance is possible.
It becomes, of course, easier the greater
the diversity of project portfolio.
This perception of the future role of merchant plant development multiple
facilities, simultaneously developed in a
single region like New England, could take hold in other U.S. settings,
where combinations of merchant plants and
acquired assets are effectively creating new supply utilities to interface
with the newly emergent transmission
utilities.
Certainly the vision of many transactions being fleet-financed or jointly
portfolio-financed-with or without credit
enhancement-is the one many bankers assume will evolve into the reality
of the future for merchant plants.
Current merchant structures are perceived as simply a product of where
expertise resides right now in terms of
transactional capability. Domestically, it is seen as a transition stopgap
while different regulatory requirements,
auction processes and stranded cost recovery are sorted out. Historically,
project-financed projects generally
have been dismissed as not being subjectable to portfolio treatment like
mortgages, because of their absence of
homogeneity, particularly where multiple sponsors, multiple power off-takers
and multiple credits have been
involved. [The law of numbers invoked for dispersion of portfolio risk
in effect has been deemed trumped by the
application of Murphy?s Law to each project or capital markets risks.]
Recently, efforts to develop a collateralized loan obligation (?CLO?) structure
for merchant power plant finance
has received increasing attention, as one offering risk diversification
for investors and greater liquidity for lenders.
Of course, the quality of given debt issues, rather than generic assumptions
about loan portfolio performance,
must be in control.
A portfolio of properly credit enhanced merchant plants, or a single credit
enhanced portfolio, may be the
foundation for portfolio-based issuance of securities.
Particularly is this true in the domestic merchant plant arena, where as
we have seen, there is an emerging group
of transactions where the structural issues key to financing are coming
into clear focus, and specific risk
management techniques being used to offset them in the trenches of the
Northeast, and in the less settled portions
of the rest of the U.S. In this context, contingent equity commitment can
be substituted for contributed capital.
The effective expansion and addition of the risk management and credit
enhancement pieces to transaction and
capital structuring innovations is what will put merchant plant development
over the top on a national basis. That
is why the New England trenches experience is such a useful platform for
what we will be doing nationwide.
ABOUT THE AUTHOR
Roger D. Feldman
A 30-year veteran of utility and IPP finance in which he has participated
in the closing of over $10 billion in
transactions, he is currently a NECA board member and chair of the DC Bar
International Investment and
Finance Committee. He has chaired the American Bar Association?s Energy
Finance Committee and is a board
member of The Journal of Project Finance, The Cogeneration and Power Marketing
Letter, Cogeneration and
Competitive Power Journal, and the Construction Business Review.
Mr. Feldman is a graduate of Brown University, Yale Law School and Harvard
Business School, and served as a
deputy administrator tothe Federal Energy Administration.
Bingham Dana LLP, Suite 400, 1200 19th St. NW, Washington, DC20036-2400 (202)778-6150, fax 6155.
==============================
http://www.fe.doe.gov/events/testimony/01_gee_happrops.html
Statement of Robert W. Gee
Assistant Secretary for Fossil Energy
U.S. Department of Energy
to the
Subcommittee on Interior and Related Agencies
Committee on Appropriations
U.S. House of Representatives
March 14, 2000
...
The Clean Coal Technology Demonstration Program
A significant portion of the FY 2001 Fossil Energy budget request is
offset by funding proposed for deferral or
rescission from the Clean Coal Technology Program. The budget proposes
that $221.0 million be deferred
until FY 2001 and that an additional $105.0 million be rescinded.
We are proposing a deferral because some of the last projects in this
program have been -- or are being --
restructured, and schedules have been delayed. The proposed rescission
reflects savings from the
restructuring of a Clean Coal Technology project that originally had
been proposed by a subsidiary of the
Duke Energy Corp. On November 15, 1999, Energy Secretary Richardson
approved the use of $78 million in
Clean Coal Technology funding as the federal share of the $432 million
Kentucky Pioneer Energy Project
planned for Clark County, Kentucky, by Global Energy Inc. This represented
a $105 million cost savings
compared to the projected government cost of the Duke Energy project
which had encountered siting
difficulties in southern Illinois.
===========================
http://www.hecweb.org/ccw/FINALCC1.htm
REVIEW OF THE GLOBAL ADVERSE ENVIRONMENTAL IMPACTS TO GROUND WATER AND
AQUATIC ECOSYSTEMS FROM COAL COMBUSTION WASTES
By
Donald S. Cherry, Ph.D.1, Rebecca J. Currie, Ph.D.2 and
David J. Soucek, M.S.3
Professor of Zoology/Aquatic Ecotoxicology,1
Research Associate of Zoology,2
and Research Assistant of Zoology3
Biology Department
Virginia Tech
Blacksburg, Virginia 24061-0406
Prepared for:
Hoosier Environmental Council and Citizens Coal Council
Indianapolis, Indiana 46202
March 28, 2000
EXECUTIVE SUMMARY
The United States Environmental Protection Agency (US EPA) is completing
a determination under the federal Resources Conservation and Recovery Act
(RCRA) in April, 2000 that will decide if federal safeguards should
be required for the disposal of waste generated from the combustion of
fossil fuels. Most of
the wastes covered by this determination are coal combustion wastes
(CCW) generated at power plants. A draft determination completed by EPA
in April,
1999, asserted that a paucity of information exists which demonstrates
dangers posed by CCW or ecological damages resulting from disposal of this
waste.
Given ample data demonstrating ground water contamination around monitored
CCW disposal sites, citizens are concerned that the final determination
by US
EPA will allow substantial damages to occur to the environment and
eventually human health as a result of lax safeguards on the disposal of
CCW.
The authors of this report were asked by the Hoosier Environmental Council
and Citizens Coal Council to conduct an assessment of the toxicity posed
by
contamination from CCW and review studies of resulting ecological damages
that may have been overlooked in the draft determination. It is our hope
that this
review will provide a public record of problems caused by the lax disposal
of CCW.
1. We evaluated the
level of toxicity exhibited by contamination at 32 CCW disposal sites and
the ecological impacts from studies of
CCW contamination
on 11 fresh water aquatic communities, two salt water aquatic communities
and other coastal environments.
These sites were spread
throughout America, and one additional site was in India.
The contamination in downgradient wells at coal combustion waste landfills
and retention ponds as well as discharges into nearby surface waters were
evaluated. The disposal sites were located in Wisconsin, Illinois,
New York, Massachusetts, Arizona, Alabama, North Dakota, and Indiana. In
addition, reviews
of studies of ecological impacts at disposal sites included Belews
Lake in North Carolina, the Savannah River Project (SRP) in South Carolina,
the Glen Lyn
and Clinch River Plants in Virginia, the Columbus Electric Generating
Station in Wisconsin, Consumer's Power J. R. Whiting Power Plant in Michigan,
Northern
Indiana Public Service Company's Bailly Generating Station in Indiana,
Tennessee Valley Authority's Bull Run Steam Plant and the U.S. Department
of
Energy's Chestnut Ridge Y-12 Plant at Oak Ridge in Tennessee, 13 reservoirs
in east Texas, River Yamuna in India, and marine environments in Sequin
Bay,
Washington, Delaware's Atlantic Coast, the Netherlands' Atlantic Coast,
the Gulf Coast of Mississippi, and others.
2. The levels of contamination evaluated at disposal sites were extremely high.
Pollutants were found in ground water downgradient from disposal sites
at grossly high concentrations relative to other contaminated environments.
Sulfate
levels of 62,000 mg/L exceeded the Maximum Contaminant Levels (MCL)
established by the US EPA by more than 120 times in North Dakota and Indiana.
Boron at an Illinois site surpassed the US EPA 10-day health advisory
for children by nearly 350 times. Iron concentrations surpassed the MCL
by 3,090 times
at a Tennesee site, 1,300 times at a North Dakota site, and 460 times
in two Wisconsin sites.
Toxic trace metal concentrations in ground water and settling pond effluent
at ash disposal sites were an astonishing problem at a number of sites.
For example,
aluminum concentrations of 600,000 m g/L in sluice water at the Oak
Ridge site in Tennessee were 6,896 times above the chronic WQC limit of
87 m g/L that
protects aquatic life. Aluminum exceeded this limit by 700 times in
downgradient ground water at two sites in New York and Alabama. Arsenic,
a dangerous
contaminant for human consumption, surpassed the US EPA MCL by 10 to
16 times in two Wisconsin disposal sites and 122 times in sluice water
at the Oak
Ridge site. Concentrations of cadmium, one of the most toxic trace
metals to aquatic life, reached 800 m g/L, 727 times beyond the chronic
WQC of 1.1 m g/L in
the Bailly Power Plant's settling pond which drains into the Indiana
Dunes National Lakeshore. Cadmium concentrations reached 1,226 m g/L in
downgradient
ground water at a fly ash landfill site in Wisconsin, surpassing the
chronic WQC by 1,114 times and the acute WQC by 314 times. Concentrations
of zinc,
another trace metal highly toxic to aquatic life, reached 51,850 m
g/L at this Wisconsin site surpassing the chronic WQC by 1,103 times and
the acute WQC by
162 times.
3. The toxicity from this contamination is extremely acute.
The toxic ramifications of heavy metal contamination from CCW are immense.
The elemental concentrations of cadmium, zinc, iron and aluminum in
downgradient wells and settling pond effluent at disposal sites are
up to three orders of magnitude higher than levels defined as acutely toxic
in short-term
laboratory tests. For example, dissolved cadmium at 1,226 m g/L in
disposal site water is sixty times more concentrated than its 48 hr LC50
value of 20 m g/L,
i.e. the lethal concentration that kills 50 percent of test organisms
in 48 hrs. Extreme concentrations of zinc up to 51,850 m g/L are 741 times
more toxic in water
at these disposal sites than the 48 hr LC50 values for test organisms
in the laboratory. Concentrations of iron in water at these disposal sites
exceed 48 hr LC50
values by 122 to 340 times. Aluminum concentrations of up to 66,000
m g/L in ground water at landfill sites exceed this laboratory acute toxicity
value by 23
times, and concentrations of 600,000 m g/L of aluminum in sluice water
exceed the value by 208 times. These concentrations will shock and immobilize
US
EPA bioassay test organisms almost instantaneously, causing death several
minutes or less thereafter.
4. CCW is toxic because
of the enrichment of trace metals on fly ash particles caught by electrostatic
precipitators at power plants
and the concentration
of other pollutants in ash and sludge by air pollution control measures
such as scrubbing.
The toxicity of fly ash occurs when ash particles become enriched with
trace elements while collected in electrostatic precipitators of power
plants. Trace
elements and other pollutants from the combustion of coal in the furnaces
cool and condense upon the ash particle surfaces. Iron and trace metals
such as
aluminum, cadmium, zinc, and selenium can regularly leach or dissolve
from ash particle coatings into ground water at such high levels that their
measurement
will exceed human health and aquatic life criteria by two to three
orders of magnitude.
The addition of flue gas desulfurization programs at coal-fired power
plants that capture much greater amounts of sulfur compounds and other
air pollutants are
generating a newer form of CCW, often called scrubber sludge. Extremely
high levels of sulfates, chlorides, sodium, total dissolved solids and
pH are being
measured in ground water downgradient from scrubber sludge landfills.
5. There are documented
substantive damages from exposure to pollutants in acutely toxic levels
at CCW disposal sites where
ecological impacts
have been studied.
The toxic impacts of CCW contamination have been well documented in
studies of at least ten aquatic ecosystems receiving effluents and/or ground
water
infiltration from CCW disposal sites. They were reported by this review's
primary researcher (D. S. Cherry) at the Savannah River Project (SRP) in
South
Carolina from 1973-1984. The impacts were acutely toxic upon biota
in the aquatic receiving system and several years were required for any
degree of
recovery.
While these original SRP studies were claimed to be an anomaly by the
power industry, this review demonstrates that the SRP is not the only site
where
excessive concentrations of trace elements and other pollutants from
CCW as well as impacts from those pollutants have been documented. The
elemental
concentrations from fly ash into McCoy Branch, Tennessee, were higher
than those measured at the SRP site, and they caused an abnormally high
percentage
of fish deformities in body structure and fin deterioration. In addition
to these two sites, this review documents damages at other CCW disposal
sites in
Tennessee, Virginia, North Carolina, Wisconsin, Michigan and Texas
as well as in India and the marine environment.
6. Substantive toxic impacts have occurred from much lower levels of contamination at CCW disposal sites.
Newer toxic effects reported in the past five years at the SRP by other
researchers reveal insidious, chronic toxicity impacts from CCW upon aquatic
life.
These include body malformations and metabolic, hormonal, and behavioral
disorders that are adversely affecting the remaining hardier organisms
from that
receiving system.
Selenium, a common yet alarming element associated with CCW contamination,
has become known as the silent killer of trace elements to aquatic life
over the
past 1.5 decades because of its ability to be concentrated up the food
chain from water and sediment, to algae, insects and other similar forms,
to fish. Selenium
levels have exceeded the US EPA chronic WQC level of 5 m g/L by up
to 200 times in downgradient ground water at CCW disposal sites in Wisconsin,
Illinois
and North Dakota.
In two east Texas reservoirs, Martin Lake and Welsh Reservoir, high
selenium concentrations (2,200 to 2,700 m g/L) from fly ash settling pond
discharges
owned by Texas Utilities Generating Co., caused massive fish mortalities
in 1978-1979. Selenium body burdens from bioaccumulation in fish ranged
from 2,000
to 9,100 ppb causing deterioration of fish blood chemistry, kidney
ultrastructure and gill tissue. Several years after the discharge commenced,
the fish
community structure in these reservoirs remained severely altered between
the balance of plankton feeding versus predator fish, as reproductive impairment
continued. Substantial bioaccumulation of arsenic, chromium and mercury
also was evident in fish found in these reservoirs. As a result, the Texas
Parks and
Wildlife Department initiated a long term, trace metal monitoring program
in 13 reservoirs to evaluate the impact of contamination by CCW produced
from
lignite coal.
A current concern, however, is that the chronic WQC of 5 m g/L is not
low enough to prevent bioaccumulation of selenium in the food chain. In
1974, Duke
Power Company began discharging fly ash into Belews Lake, North Carolina.
Four years of study documented that resulting concentrations of 10 m g/L
of
selenium in the water eliminated 16 of the 20 fish species found in
this reservoir and rendered two of the remaining species sterile (Cumbie
and Van Horne
1978; Lemly 1985). Selenium concentrations had bioacumulated by 3,975
times in the tissues of largemouth bass from the levels of selenium in
the water and
tissues of prey consumed by this species. Subsequent research has concluded
that waterborne selenium concentrations of 2 m g/L are hazardous to the
long-term survival of fish due to the affinity of selenium to bioaccumulate
in reservoir systems (Lemly 1992).
7. Arguments that high
pollution levels from CCW will be attenuated by the environment before
damage occurs are not borne out
by research or monitoring.
The authors of this review believe that the scope of adverse environmental
impacts from CCW disposal
practices is under-acknowledged
due to an absence of monitoring measures at many disposal sites.
Certain groups are assuming without substantiation that elevated concentrations
of trace elements and other pollutants from CCW will be attenuated and/or
diluted to safe levels before damage to water supplies can occur. This
position ignores the fact that pollutant concentrations have risen to two
to three orders of
magnitude above safe limits to protect aquatic life (US EPA WQC) in
waters exiting these sites. These excessive concentrations cannot be diluted
or
attenuated without polluting a ground water resource that 117-132 million
people use for daily consumption. Many of these people are likely drawing
ground
water from private wells near CCW disposal sites for daily consumption
that is untreated and not being monitored. Even if attenuation does eventually
occur,
the site studies reviewed in this report indicate that when trace metals
such as selenium dissolve into surface water from CCW, damages from bioaccumulation
in living organisms occurs at minute concentrations, i.e., less than
10 m g/L in the water.
Furthermore there are many CCW disposal sites, particularly, ash ponds
and lagoons at power plants, where impacts are not being examined due to
the lack of
any ground or surface water monitoring programs. Even where monitoring
is occuring, the number of monitoring points is often insufficient and
many toxic
constituents in CCW, such as trace metals like molybdenum, strontium
and thallium, various radionuclides and organic compounds are not being
monitored. For
these reasons, the authors of this review believe that the scope and
severity of impacts from the contamination of ground waters and aquatic
ecosystems by
CCW is seriously under-acknowledged.
There are a number of ecological impact studies that should have been
conducted longer in this country relative to the 12-year effort at SRP,
but were not. Still,
four studies substantively document acute and chronic toxic impacts
from exposure of organisms to CCW effluents and infiltration in South Carolina,
North
Carolina, Tennessee and Texas. Sites where several years of research
have been conducted in the mid-1970-1980's and the recent studies from
1995 to the
present at SRP have established a very important data base of toxicity
from CCW that is shedding new light on the immense impact that CCW disposal
is
having upon life in aquatic receiving systems.
Unfortunately most of the other field-oriented ecological studies were
funded for short periods and terminated for reasons unknown. Furthermore,
the
long-term impact of contamination from CCW upon human health is unknown.
Until more adequate monitoring programs exist and more effort is made to
look
for and study impacts, assertions of attenuation of harmful impacts
from CCW disposal appear to be nothing more than an obfuscation of responsibility
by those
seeking lax disposal requirements for this waste.
The US EPA's determination governing wastes from the combustion of fossil
fuels needs to address the severity of the multi-directional threats that
surface
waters and ground waters contaminated by CCW pose to human health,
cropland irrigation, and aquatic communities in adjacent streams and other
receiving
systems.
========================
Clean Energy Integrated Gasification Combined Cycle Project
Description:
The proposed action is DOE participation,
through financial assistance, in a
cooperative agreement under the Clean
Coal Technology demonstration program for
design, construction, and operation
of a demonstration plant that integrates the
gasification of coal with an air separation
unit, a combustion turbine, a heat
recovery steam generator with existing
steam turbines, and certain existing
facilities at the Grand Tower Power
Station near Carbondale, Illinois; this Station is
owned by the Central Illinois Public
Service Company (CIPS). The current nominal
200 megawatt Station will be repowered
to 477 MW of electricity. Clean Energy
Partners, an industrial alliance between
Duke Energy and Ameren Holding
Company - a parent of CIPS - will construct,
own, and operate the repowered
Station as a merchant plant using local
high sulfur coal from the Southern Illinois
Basin.
NEPA Schedule:
Determination:
Notification:
Internal Scoping:
Notice of Intent:
Public Scoping:
Preliminary Draft EIS:
Draft EIS
Public Distribution:
Public Hearing:
Preliminary Final EIS:
Final EIS
Draft Record of Decision:
Approved Record of Decision:
February 1999
February 1999
March 1999
May 1999
July 1999
January 2000
March 2000
March 2000
April 2000
June 2000
July 2000
July 2000
September 2000
Estimated Cost:
$ 400,000
=====================
AMEREN Contact person
Illinois
Leigh Morris
217.535.5228
========================
http://www.netl.doe.gov/coalpower/gasification/25_clean.htm
Clean Coal Technology
Program
Kentucky Pioneer Energy IGCC
Demonstration Project
Back to Projects
LOCATION
Trapp, Clark County, KY
(East Kentucky Power Cooperative's Smith
Site)
PROJECT OBJECTIVE
To demonstrate and assess the reliability, availability, and
maintainability of a utility-scale IGCC
system using high-sulfur bituminous coal and municipal solid
waste blend in an oxygen-blown,
fixed-bed, slagging gasifier and the operability of a molten
carbonate fuel cell fueled by coal gas.
TECHNOLOGY/PROJECT DESCRIPTION
The BG/L gasifier is supplied with steam, oxygen, limestone flux,
and a coal and municipal waste
blend. During gasification, the oxygen and steam react with the
coal and muncipal waste blend and
limestone flux to produce a raw coal-derived fuel gas rich in
hydrogen and carbon monoxide. Raw
fuel gas exiting the gasifier is washed and cooled. Hydrogen
sulfide and other sulfur compounds
are removed. Elemental sulfur is reclaimed and disposed of as
a by-product. Tars, oils, and dust
are recycled to the gasifier. The resulting clean, medium-Btu
fuel gas fires the gas turbine. A
small portion of the clean fuel gas is used for the molten carbonate
fuel cell (MCFC). The MCFC
is composed of a molten carbonate electrolyte sandwiched between
porous anode and cathode
plates. Fuel (desulfurized, heated medium-Btu fuel gas) and steam
are fed continuously into the
anode; CO2-enriched air are fed directly into the cathode. Chemical
reactions produce direct
electric current, which is converted to alternating current in
an inverter.
PROJECT STATUS/ACCOMPLISHMENTS
On May 8, 1998, the DOE conditionally approved Ameren Services
Company (merger of Union
Electric Co. and Central Illinois Public Service Co.) as an equity
partner and host site provider
subject to completing specific business and teaming milestones.
The new project site to be
provided by Ameren was at their Venice Station Plant in Venice,
Illinois, or near East St. Louis,
Illinois. On April 30, 1999, Ameren Services Company withdrew
from the project for economic and
business reasons.
In November 1999, Kentucky Pioneer Energy (KPE), LLC, a wholly
owned subsidiary of Global
Energy USA, officially became the Participant for the project.
A new host site at East Kentucky
Power Cooperative's Smith site in Clark County, Kentucky was
established. With the
establishment of the new site the permitting and NEPA process
began. The EIV was submitted in
March 2000, and the public hearing was conducted in May 2000.
The draft EIS is scheduled to be
issued in July 2001 with the Record of Decision being finalized
in November 2001. On 24 May
2001, FERC confirmed KPE as an exempt Wholesale Generator and
on 7 June 2001, the Kentucky
Division of Air Quality issued the Air Quality Permit.
Also, the Kentucky Public Service
commission issued a Declaratory Order of Non- Jurisdiction during
this time. Sources of the
Municipal Solid Waste (MSW) have been identified and preliminary
agreements have been
reached to supply MSW. Preliminary engineering to better
finalize the cost has been completed.
Closure on financing the project will occur upon completion of
the NEPA process. Final design
and construction should begin early 2002.
Commercial Applications
The IGCC system being demonstrated in this project is suitable
for both repowering applications
and new power plants. The technology is expected to be adaptable
to a wide variety of potential
market applications because of several factors. First, the BGL
gasification technology has
successfully used a wide variety of U.S. coals. Also, the highly
modular approach to system
design makes the BGL-based IGCC and molten carbonate fuel cell
competitive 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.
The heat rate of the IGCC demonstration facility is projected
to be 8,560 Btu/kWh (40%
efficiency) and the commercial embodiment of the system has a
projected heat rate of 8,035
Btu/kWh (42.5% efficiency). The commercial version of the molten
carbonate fuel cell fueled by a
BGL gasifier is anticipated to have a heat rate of 7,379 Btu/kWh
(46.2% efficiency). These
efficiencies represent greater than 20% reduction in emissions
of CO2 when compared to a
conventional pulverized coal plant equipped with a scrubber.
SO2 emissions from the IGCC
system are expected to be less than 0.1 lb/106 Btu (99% reduction),
and NOx emissions less than
0.15 lb/106 Btu (90% reduction).
Also, the slagging characteristic of the gasifier produces a nonleaching,
glass-like slag that can
be marketed as a usable byproduct.
Contacts
H.H. Graves, President
Kentucky Pioneer Energy, LLC
312 Walnut Street, Suite 2000
Cincinnati, OH 45202
(513) 621-0077
(513) 621-5947 (fax)
hhgraves@globalenergyinc.com
Return to top of page
Last Update: 10/17/01
[../../footer.html]
===========================
http://www.planetark.org/dailynewsstory.cfm?newsid=2668&newsdate=29-Jul-1999
Environmentally sound utilities seen
bringing greater returns
Mail this story to a friend | Printer friendly version
USA: July 29, 1999
NEW YORK - Returns on investments in U.S. electric utilities
judged environmentally efficient have outperformed those
determined to be less environmentally friendly, a study by New
York-based investment advisory firm Innovest Strategic Value
Advisors shows.
A copy of the soon-to-be released report was obtained by Reuters.
"Companies receiving above average EcoValue 21 ratings
outperformed companies with below average ratings by
approximately six percent over the past year," Innovest's report
says.
Pacific Gas & Electric and Niagara Mohawk Power received the
highest ratings for U.S. utilities, indicating the greatest managerial
capacity to convert good environmental performance into
shareholder value, the study said.
Pacific Gas's mix of fuels includes geo-thermal, hydroelectric
energy and some natural gas as well as dirtier burning coal, while
Niagara Mohawk uses no coal at all.
The companies that Innovest ranked lowest were FirstEnergy and
Ameren , both of which burn mostly coal. FirstEnergy was worst in
its class in terms of environmental risk management, while Ameren
was worst in toxic emissions.
Innovest calculates its EcoValue 21 market after determining a
series of indicators that reflect a company's historical
environmental risk factor, the company's capacity to minimise
environmental damage and the potential profit from its management
of environmental issues.
"The correlation exists largely because eco-efficiency is an
excellent proxy for management quality, which is the primary
determinate of stock price performance," the report said.
===============================
rchive-Name: gov/us/fed/nara/fed-register/2000/apr/14/65FR20142
Posting-number: Volume 65, Issue 73, Page 20142
[Federal Register: April 14, 2000 (Volume 65, Number 73)]
[Notices]
[Page 20142-20145]
From the Federal Register Online via GPO Access [wais.access.gpo.gov]
[DOCID:fr14ap00-58]
=======================================================================
http://groups.google.com/groups?q=clean+coal+trapp&hl=en&rnum=1&selm=65FR20142%40us.govnews.org
-----------------------------------------------------------------------
DEPARTMENT OF ENERGY
Notice of Intent To Prepare an Environmental Impact Statement for
the Kentucky Pioneer Integrated Gasification Combined Cycle
Demonstration Project, Trapp, KY and Notice of Floodplain Involvement
AGENCY: U.S. Department of Energy.
ACTION: Notice of Intent to prepare an Environmental Impact Statement
and Notice of Floodplain Involvement.
-----------------------------------------------------------------------
SUMMARY: The U.S. Department of Energy (DOE) announces its intent to
prepare an Environmental Impact Statement (EIS) pursuant to the
National Environmental Policy Act (NEPA), the Council on Environmental
Quality (CEQ) NEPA regulations (40 CFR parts 1500-1508), and the DOE
NEPA regulations (10 CFR part 1021), to assess the potential
environmental and human health impacts of a proposed project to design,
construct, and operate a demonstration electric-power generating plant
in Trapp, Clark County, Kentucky. The proposed Integrated Gasification
Combined Cycle (IGCC) project, selected under the Clean Coal Technology
Program, would be the first commercial-scale demonstration of the fixed
bed British Gas Lurgi (BGL) gasification process in the United States.
The proposed project would also demonstrate a high-temperature molten
carbonate fuel cell and would involve the construction and operation
of
a nominal 400 MWe (megawatt-electric) IGCC power station. Feed to the
BGL gasifiers would be solid fuel briquettes. The EIS will help DOE
decide whether to provide 18 percent (approximately $78M) of the
funding for the currently estimated $432 M proposed project.
The purpose of this Notice of Intent is to inform
the public about
the proposed action; announce the plans for a public scoping meeting;
invite public participation in (and explain) the EIS scoping process;
and solicit public comments for consideration in establishing the
proposed scope and content of the EIS. The EIS will evaluate the
proposed project and reasonable alternatives. Because the proposed
project may affect floodplains, the EIS will include a floodplain
assessment and a statement of findings in accordance with DOE
regulations for compliance with floodplain environmental review
requirements (10 CFR part 1022).
DATES: To ensure that all of the issues related to this proposal are
addressed, DOE invites comments on the proposed scope and content of
the EIS from all interested parties. Comments must be received by May
31, 2000, to ensure consideration. Later comments will be considered
to
the extent practicable. In addition to receiving comments in writing
and by telephone, DOE will conduct a public scoping meeting in which
agencies, organizations, and the general public are invited to present
oral comments or suggestions with regard to the range of actions,
alternatives, and impacts to be considered in the EIS. The scoping
meeting will be held at Trapp Elementary School, Trapp, Kentucky on
May
4, 2000, beginning at 7:00 p.m. (See Public Scoping Process). The
public is invited to an informal session at this location beginning
at
4:00 p.m. to learn more about the proposed action. Displays and other
forms of information about the proposed agency action and location
will
be available, and DOE personnel will be present to answer questions.
ADDRESSES: Written comments on the proposed EIS scope and requests to
participate in the public scoping meeting should be addressed to: Mr.
Roy Spears, NEPA Document Manager for the Kentucky Pioneer IGCC
Demonstration Project, National Energy Technology Laboratory, U.S.
Department of Energy, 3610 Collins Ferry Road, Morgantown, WV 26507-
0880. People who would like to otherwise participate in the public
scoping process should contact Mr. Spears directly at: telephone 304-
285-5460; toll free telephone 1-800-432-8330 (extension 5460); fax
304-
285-4403; or e-mail rspears@netl.doe.gov.
FOR FURTHER INFORMATION CONTACT: To obtain additional information about
this project or to receive a copy of the draft EIS for review when
it
is issued, contact Mr. Roy Spears at the address provided above. For
general information on the DOE NEPA process, please contact Ms. Carol
M. Borgstrom, Director, Office of NEPA Policy and Assistance (EH-42),
U.S. Department of Energy, 1000 Independence Avenue, SW, Washington,
DC
20585-0119; telephone 202-586-4600 or leave a message at 1-800-472-
2756.
SUPPLEMENTARY INFORMATION:
[[Page 20143]]
Background and Need for Agency Action
Under Public Law 102-154, the U.S. Congress provided
authorization
and funds to DOE for conducting cost-shared Clean Coal Technology
Program projects for the design, construction, and operation of
facilities that significantly advance the efficiency and environmental
performance of coal-using technologies and are applicable to either
new
or existing facilities. The purpose of this proposed agency action,
which is known as the Kentucky Pioneer IGCC Demonstration Project,
is
to establish the commercial viability of the fixed bed BGL gasification
process in the United States and the operation of a high temperature
molten carbonate fuel cell using coal derived gas. The IGCC plants
have
long been recognized as being environmentally superior to conventional
coal-fired power plants while operating at significantly higher
efficiencies. The proposed project would demonstrate the improved
economic viability and process flexibility of the BGL technology and
promote fuel cells as a viable commercial source of electricity. A
slipstream of syngas would be routed to a fuel cell to produce
additional electricity in this demonstration project.
Since the early 1970s, DOE and its predecessor agencies
have
pursued research and development programs that include long-term, high-
risk activities that support the development of innovative concepts
for
a wide variety of coal technologies through the proof-of-concept stage.
However, the availability of a technology at the proof-of-concept stage
is not sufficient to ensure its continued development and subsequent
commercialization. Before any technology can be considered seriously
for commercialization, it must be demonstrated. The financial risk
associated with technology demonstration is, in general, too high for
the private sector to assume in the absence of strong incentives. The
Clean Coal Technology Program is a congressionally authorized program
designed to accelerate the development of innovative technologies to
meet the Nation's near-term energy and environmental goals; to reduce
technological risk to the business community to an acceptable level;
and to provide private sector incentives required for continued
activity in innovative research and development directed at providing
solutions to long-range energy supply problems.
Proposed Action
The proposed action is for DOE to provide, through
a cooperative
agreement with Kentucky Pioneer Energy, L.L.C., financial assistance
for the design, construction, and operation of the proposed project.
The Kentucky Pioneer IGCC Demonstration Project would be designed for
at least 20 years of commercial operation, beginning with a 2-year
Clean Coal Technology demonstration, and would cost a total of
approximately $432 M; DOE's share would be approximately $78 M (18%).
The proposed project includes the design, construction,
and
operation of a new 400 MWe IGCC power plant in rural Clark County,
Kentucky. Kentucky Pioneer Energy, L.L.C. would use licensed
gasification technology to fuel an electric generating facility. The
facility would demonstrate the three following innovative technologies:
(1) Gasification of fuel briquettes; (2) use of the syngas product
as a
clean fuel in combined cycle turbine generator sets; and (3) operation
of a high temperature molten carbonate fuel cell on coal derived
syngas. This project would be the first commercial scale application
of
the BGL gasification technology in the United States. This would also
be the first commercial scale demonstration of a molten carbonate fuel
cell operating on coal derived gas. Construction of the proposed plant
would be expected to require approximately 30 months.
The project consists of the following components:
Briquettes and
raw material transportation, receipt, and storage; sulfur removal and
recovery; a gasification plant; a combined cycle power unit; and a
fuel
cell. The IGCC facility would provide needed power capacity to the
central and eastern Kentucky areas.
To supply the proposed plant and other potential
customers with
fuel briquettes, the parent company of the applicant, Global Energy,
Inc., would construct a production facility at an off-site location.
The briquettes would be made from high-sulfur coal (at least 50%) and
refuse (municipal solid waste). The location of the briquette
manufacturing facility remains to be determined. However, sources of
low-cost high-sulfur coal, refuse availability and supporting
infrastructure would be considered by Global in siting the facility.
The EIS will consider potential environmental impacts from operation
of
a briquette facility.
The IGCC technology that Kentucky Pioneer Energy,
L.L.C. would be
demonstrating consists of the following four steps: (1) Generation
of
syngas by reacting fuel briquettes with steam and oxygen, creating
a
high-temperature, chemically reducing atmosphere; (2) removal of
contaminants, including particulates and sulfur; (3) combustion of
clean syngas in a turbine generator to produce electricity; and (4)
recovery of residual heat in the hot exhaust gas from the gas turbine
in a heat recovery steam generator and use of the steam to produce
additional electricity in a steam turbine generator.
The proposed project site comprises approximately
300 acres located
within a 3,120-acre tract, owned by East Kentucky Power Cooperative
(EKPC) in Clark County, Kentucky. The tract is 34 kilometers (21 miles)
southeast of the city of Lexington. The site can be reached by State
Highway 89 and accessed through a gated perimeter fence and access
road.
The 300-acre proposed project site was previously
disturbed by
preliminary construction activities when EKPC began construction of
its
first-phase power station in the mid-1980s. That project was canceled
in the early 1990s when decreased demand for electric power made the
project uneconomical. EKPC completed preliminary grading, primary
foundations, fire protection piping and rail spur access infrastructure
installation before the project was cancelled.
The Kentucky Pioneer IGCC Demonstration Project
would be designed
to minimize expected or potential adverse impacts to the environment.
Advanced process technology, efficient pollution control technology,
and effective pollution prevention measures, including extensive reuse
of internal process water, would be employed to minimize impacts.
Alternatives
Section 102(2)(C) of NEPA requires that agencies
discuss the
reasonable alternatives to the proposed action in an EIS. The purpose
for agency action determines the range of reasonable alternatives.
The
goals of the proposed agency action establish the limits of its
reasonable alternatives. Congress established the Clean Coal Technology
Program with a specific purpose: To demonstrate the commercial
viability of technologies that use coal in more environmentally benign
ways than conventional coal technologies. Congress also directed DOE
to
pursue the goals of the legislation by means of partial funding (cost
sharing) of projects owned and controlled by non-Federal government
sponsors. This statutory requirement places DOE in a much more limited
role than if the Federal
[[Page 20144]]
government were the owner and operator of the project. In the latter
situation, DOE would be responsible for a comprehensive review of
reasonable alternatives for siting the project. However, in dealing
with an applicant, the scope of alternatives is necessarily more
restricted because the agency must focus on alternative ways to
accomplish its purpose that reflect both the application before it
and
the functions the agency plays in the decision process. It is
appropriate in such cases for DOE to give substantial consideration
to
the applicant's needs in establishing a project's reasonable
alternatives.
DOE developed an overall NEPA compliance strategy
for the Clean
Coal Technology Program that includes consideration of both
programmatic and project-specific environmental impacts during and
after the process of selecting a proposed project. As part of the NEPA
strategy, the EIS for the Kentucky Pioneer IGCC Demonstration Project
will tier from the Clean Coal Technology Programmatic Environmental
Impact Statement (PEIS) that DOE issued in November 1989 (DOE/EIS-
0146). Two alternatives were evaluated in the PEIS: (1) The no-action
alternative, which assumed that the Clean Coal Technology Program was
not continued and that power suppliers would continue to use
conventional coal-fired technologies with flue gas desulfurization
and
nitrogen oxide controls to meet New Source Performance Standards; and
(2) the proposed action, which assumed that Clean Coal Technology
Program projects would be selected and funded, and that successfully
demonstrated technologies would undergo widespread commercialization
by
the year 2010.
The range of reasonable options to be considered
in the EIS for the
proposed Kentucky Pioneer IGCC Demonstration Project is determined
in
accordance with the overall NEPA strategy. The EIS also will include
an
analysis of the no-action alternative, as required under NEPA. Under
the no-action alternative, DOE would not provide partial funding for
the design, construction, and operation of the project. In the absence
of DOE funding, the Kentucky Pioneer IGCC Demonstration Project
probably would not be constructed. If the proposed Kentucky Pioneer
IGCC Demonstration Project were not built, EKPC may use alternative,
less efficient sources for electric power to meet future demands of
its
customers. Alternatives to the proposed project could include
purchasing power from other sources, adding generation capacity that
does not rely on the IGCC technology, or using some other current
technology. DOE will consider other reasonable alternatives that may
be
suggested during the public scoping period.
Because of DOE's limited role of providing cost-shared
funding for
the proposed Kentucky Pioneer IGCC Demonstration Project, and because
of advantages associated with the proposed location, DOE does not plan
to evaluate alternative sites for the proposed project. Site selection
was governed primarily by benefits that EKPC could realize. EKPC
preferred the proposed project site because the costs would be much
higher and the environmental impacts would likely be greater for an
undisturbed area.
Under the proposed action, project activities would
include
engineering and design, permitting, fabrication and construction,
testing, and demonstration of the technology. DOE plans to complete
the
EIS and issue a Record of Decision within 15 months of publication
of
this Notice of Intent, assuming timely delivery of information from
Kentucky Pioneer Energy, L.L.C. that DOE needs for preparing the EIS.
Upon completion of the demonstration, the facility could continue
commercial operation.
Preliminary Identification of Environmental Issues
The following issues have been tentatively identified
for analysis
in the EIS. This list, which was developed on the basis of analyses
of
similar projects and from agency concerns, and is presented to
facilitate public comment on the scope of the EIS, is neither intended
to be all-inclusive nor a predetermined set of potential impacts.
Additions to or deletions from this list may occur as a result of the
scoping process.
The issues include:
(1) Atmospheric resources: Potential air quality
impacts resulting
from emissions during construction and operation of the Kentucky
Pioneer IGCC Demonstration Project and the briquette manufacturing
plant;
(2) Water resources: Potential effects on surface
and groundwater
resources and withdrawal of water from the Kentucky River;
(3) Infrastructure and land use, including potential
effects
resulting from the manufacture, transportation, and storage of the
briquettes required for the proposed project;
(4) Solid waste: Pollution prevention and waste
management
practices, including impacts caused by waste generation and treatment
at the proposed project and briquette manufacturing plant;
(5) Noise: Potential impacts resulting from construction,
transportation of materials, and plant operation for the proposed
project and briquette manufacturing plant;
(6) Construction: Impacts associated with traffic
patterns and
construction related emissions;
(7) Floodplains: Impacts associated with extension
of a water
intake structure in the Kentucky River;
(8) Community impacts, including impacts from local
traffic
patterns, socioeconomic impacts on public services and infrastructure,
and environmental justice (Executive Order 12898) with respect to the
surrounding community;
(9) Cumulative effects that result from the incremental
impacts of
the proposed project when added to the other past, present, and
reasonably foreseeable future actions; and,
(10) Visual impacts associated with plant structures.
Public Scoping Process
To ensure that all issues related to this proposal
are addressed,
DOE will conduct an open process to define the scope of the EIS. The
public scoping period will run until May 31, 2000. Interested agencies,
organizations, and the general public are encouraged to submit comments
or suggestions concerning the content of the EIS, issues and impacts
to
be addressed in the EIS, and the alternatives that should be analyzed.
Scoping comments should describe specific issues or topics that the
EIS
should address in order to assist DOE in identifying significant
issues. Written, e-mailed, or faxed comments should be communicated
by
May 31, 2000 (see ADDRESSES).
DOE will conduct a public scoping meeting at Trapp
Elementary
School in Trapp, Kentucky on May 4, 2000, at 7 p.m. The address of
Trapp Elementary School is 11400 Irvine Road, Highway 89 South,
Winchester, Kentucky 40391. In addition, the public is invited to an
informal session at this location beginning at 4 p.m. to learn more
about the proposed action. Displays and other information about the
proposed agency action and location will be available, and DOE
personnel will be present to answer questions.
The formal scoping meeting will begin on May 4,
2000, at 7 p.m. DOE
asks people who wish to speak at this public scoping meeting to contact
Mr. Roy Spears, either by phone, fax, computer, or in writing (see
ADDRESSES in this Notice). People who do not arrange in advance to
speak may register at the meeting (preferably at the beginning of the
meeting) and may
[[Page 20145]]
speak after previously scheduled speakers. Speakers who want more than
five minutes should indicate the length of time desired in their
request. Depending on the number of speakers, DOE may need to limit
speakers to five minutes initially, and provide additional
opportunities as time permits. Speakers may also provide written
materials to supplement their presentations. Oral and written comments
will be given equal consideration.
DOE will begin the meeting with an overview of the
proposed
Kentucky Pioneer IGCC Demonstration Project. The meeting will not be
conducted as an evidentiary hearing, and speakers will not be cross-
examined. However, speakers may be asked questions to help ensure that
DOE fully understands their comments or suggestions. A presiding
officer will establish the order of speakers and provide any additional
procedures necessary to conduct the meeting.
Issued in Washington, DC, this 10th day of April,
2000.
David Michaels,
Assistant Secretary, Environment, Safety and Health.
[FR Doc. 00-9301 Filed 4-13-00; 8:45 am]
BILLING CODE 6450-01-P
=================================
http://www.kentuckyconnect.com/heraldleader/news/072301/commentarydocs/723musulin-response.htm
Published Monday, July 23, 2001, in the Herald-Leader
Inaccuracies undermine attack on power plant
By Mike Musulin II
The commentary about the Kentucky Pioneer Energy power plant at Trapp
contained inaccurate statements reflecting a general misunderstanding
regarding the kind of plant that will be built. The facility will be an
``integrated
gasification combined cycle'' facility, which will convert coal and municipal
solid
waste, in the form of refuse-derived fuel pellets, into synthesis gas for
use as a
fuel in a conventional gas turbine. Syngas is a substitute for natural
gas. The
entire output of the plant will be used by East Kentucky Power Cooperative.
Contrary to the information in the column, the plant will not incinerate
garbage, it
is not a fluidized bed process and it is not a merchant plant. The coal
and pellets
will be rail shipped to the plant. The gasification process uses steam
and oxygen
to convert the volatile material in the feedstock into hydrogen-rich syngas.
It is not a combustion process. Gasification takes place in a closed vessel
without a stack. Emissions from a gas turbine using syngas are much less
than
those from a traditional coal-fired power plant.
On July 3, the Herald-Leader published a chart from the Kentucky Division
for
Air Quality showing the estimated emissions of the Kentucky Pioneer Energy
plant and the other proposed power plants around the state. The chart clearly
showed that the Kentucky Pioneer Energy facility will have lower emissions,
including greenhouse gases, than the proposed coal-fired plants.
A gasification facility does not have ash waste or gob, as the commentary
states. Instead, the gasification process creates vitrified frit, an inert,
non-leaching material that resembles coarse sand or aggregate. Also known
as
synthetic aggregate, it is a saleable product with a variety of uses in
the
construction and building industries. In Great Britain, synthetic aggregate
has
been used in road paving and concrete seawalls.
At the siting analysis public hearing for the plant on June 28, officials
of Global
Energy, the parent of Kentucky Pioneer Energy, stated that plans include
the
ability to use refuse-derived fuel pellets from Kentucky sources in the
future.
However, given the volume of feedstock needed for the plant and the fact
that
municipal waste collection is spread among Kentucky's 120 counties, Kentucky
Pioneer Energy can produce lower cost electricity by using pellets produced
elsewhere for the majority of the feedstock.
Gasification was selected for this project because it is an advanced technology
that is economically and environmentally superior to any other for the
beneficial
use of coal and the elimination of waste. Kentucky Pioneer Energy will
furnish
Kentucky residents with low-cost power, high-quality jobs and a cleaner
environment for years to come.
====================================================
http://www.kentuckyconnect.com/heraldleader/news/070801/commentarydocs/708appy-herrick.htm
Published Sunday, July 8, 2001, in the Herald-Leader
Trapp waste-to-energy plant will hurt, not help, Ky.
By Will Herrick
Kentucky has a long history of attracting out-of-state trash. In the late
1980s
and early '90s, waste incinerators were frequently proposed, and after
consideration, all were rejected. Little has really changed in the waste
incineration business, and it is still in the state's interest to not burden
Central
and East Kentucky with more air and water pollution.
The only public benefit to allowing the construction of a trash-to-energy
plant
at Trapp is to ease the cost of trash disposal in New York and New Jersey,
and
to lower the cost of electricity for folks outside Kentucky. This state
doesn't lack
for electrical production, and we have adequate landfill space for our
current
needs.
The Trapp facility will, however, exacerbate our already serious air- and
water-quality problems. We are in dire need of broadening our economic
base,
but is it a good trade to suffer health risks and give up diverse economic
growth
so that out-of-state trash can be burned to make electricity to export?
There are many health issues associated with incineration. Dumping fine
particles into the air means that folks downwind will breath them. Those
particles are proving to cause cancers and heart problems. Kentucky is
already
facing the national limits on air pollution.
We have one of the highest rates of heart attack in the nation. The cost
of
pushing up against those pollution limits should be very carefully considered.
Solid waste makes strong acids when burned, not all of which are caught
in the
calcic compounds of the fluidized bed.
The effect of acid rain and its cost to the forests of Eastern Kentucky
and
beyond should also be considered. Not all the highly toxic metal vapors
like
mercury, lead, cadmium or nickle are captured. They will enter Lexington's
water supply in greater concentrations as the primary air transport moves
up
the Kentucky River basin and the water flows down.
The Kentucky River is Lexington's primary source of drinking water. Metals
like cadmium will be absorbed by tobacco plants (as well as other crops
) and
add to the health problems already weighing down the tobacco industry.
The
``clean coal'' contaminants don't go away, they are still in the calcic
gob and in
the air.
The gob and the unburned fraction of the waste must be disposed of properly.
Acid will dissolve all of the captured metals and soot right back out of
the
calcium compounds, a story all too familiar to those living around the
leachate of
mine tailings.
For those seeking employment, it's worth looking at the chicken factories,
where wages are so low that the jobs are not considered worth having, and
most locals have quit taking them. Much of the incinerator operation is
low-skill
and hence low-paying. A lot of those jobs will not be worth having. Skilled
workers need to balance the health risks of working around trash, toxic
nickle
vapors and soot against the wages being offered. I doubt that it will be
the best
job in Clark County or next door in Powell County.
About 10 years ago, Wolfe County was chosen as the site for a large incinerator
just above the Red River Gorge. Public reaction was sufficient to derail
that
facility, and folks here are still glad it wasn't built. It is clear that
our economic
diversification would be frustrated by having the incinerator instead of
beautiful
vistas of the Red River Gorge welcome visitors to Wolfe County. Our public
health problems would be worse than they are.
As one community that said no to a waste-to-energy incinerator to another:
don't permit this facility. Ten years from now, you will be glad that you
didn't.
While local and state officials suffered much of the public's outrage,
what really
made the Wolfe County incinerator go away was pressure on the governor.
Make phone calls, send letters and publicly demonstrate disapproval.
If Lexington wants to keep New York's and New Jersey's toxic metals out
of its
morning coffee, if Clark and Powell counties want to spare themselves the
burden of a waste-import facility, if Eastern Kentucky wants to preserve
its air
and water quality, and if we all want to preserve an open playing field
for
economic development, tell the governor and state legislators ``no'' to
a plant in
Trapp.
With enough public pressure, this plant will go the way of all the rest.
Will Herrick, a computer software writer who lives in Campton, is involved
in
environmental issues.
===========================
http://www.kentuckyconnect.com/heraldleader/news/120901/hlocaldocs/09Plant.htm
The $432 million project received state approval last June, but
also requires federal approval to be eligible for $61 million in federal
funds to aid in construction.
The public comment sessions are from 7 to 9 p.m. Monday at the public
library in downtown Lexington and Tuesday at Trapp Elementary School in
Winchester, said Roy Spears, the project's document manager for the Department
of Energy. The plans will be available for review from 4 to 7 p.m. each
day.
Spears said the deadline for public comment on the draft environmental
impact statement is Jan. 4 and construction could begin within the next
five months.
It will take approximately three years to finish the project,
and up to 1,000 jobs could be created during the construction phase. Company
officials have said about 120 permanent employees would run the plant.
East Kentucky Power, an electric co-op in Winchester, has agreed
to buy the plant's output for 20 years.
Officials from Global Energy USA, which is building the plant,
have said it will produce fewer emissions than traditional coal-fired plants.
Much of the fuel will come from garbage from New York and New
Jersey in the form of pellets of compacted, shredded trash. The coal that
will be used will be converted to synthetic gas before it is used to turn
the electric turbines.
http://www.tfhrc.gov/hnr20/recycle/waste/bfs1.htm
Table 3-2 depicts the typical chemical composition of blast furnace
slag. The chemical compositions shown are in general applicable to all
types of slag. The data
...
Chemical Properties
Table 3-2 depicts the typical chemical composition
of blast furnace slag. The chemical compositions shown are in general applicable
to all types of slag. The data
When ground to the proper fineness, the chemical
composition and glassy (noncrystalline) nature of vitrified slags are such
that when combined with water, these
Table 3-2. Typical composition of blast furnace slag.(9)
Constituent
Because of these cementitious properties, GGBFS
can be used as a supplementary cementitious material either by premixing
the slag with Portland cement or
Blast furnace slag is mildly alkaline and exhibits
a pH in solution in the range of 8 to 10. Although blast furnace slag contains
a small component of elemental sulfur
In certain situations, the leachate from blast
furnace slag may be discolored (characteristic yellow/green color) and
have a sulfurous odor. These properties appear
=============================================
Commonwealth of Kentucky
Natural Resources and Environmental Protection Cabinet
Department for Environmental Protection
Division for Air Quality
803 Schenkel Lane
Frankfort, Kentucky 40601
(502) 573-3382
AIR QUALITY PERMIT
Permittee Name:
Kentucky Pioneer Energy LLC
Mailing Address:
312 Walnut Street, Suite 2000, Cincinnati, Ohio 45202
Source Name:
Kentucky Pioneer Energy LLC
Mailing Address:
312 Walnut Street, Suite 2000, Cincinnati, Ohio 45202
Source Location:
12145 Irvine Road, Trapp, Kentucky 40391
Permit Type:
Federally-Enforceable
Review Type:
PSD, Title V
Permit Number:
V-00-049
Log Number:
51152
Application
Complete Date:
January 21, 2000
KYEIS ID #:
21-049-00053
SIC Code:
4911
ORIS Code:
55266
Region:
Bluegrass
County:
Clark
Issuance Date:
June 7, 2001
Expiration Date:
June 7, 2006
___________________________________
John E. Hornback, Director
DEP7001 (1-97)
Division for Air Quality
Revised 06/22/00
Page 2
TABLE OF CONTENTS
SECTION
DATE
PAGE
OF ISSUANCE
SECTION A
PERMIT AUTHORIZATION
June 7, 2001
1
SECTION B
EMISSION POINTS, EMISSIONS
June 7, 2001
2
UNITS, APPLICABLE
REGULATIONS, AND
OPERATING CONDITIONS
SECTION C
INSIGNIFICANT ACTIVITIES
June 7, 2001
32
SECTION D
SOURCE EMISSION
June 7, 2001
33
LIMITATIONS AND
TESTING REQUIREMENTS
SECTION E
SOURCE CONTROL EQUIPMENT
June 7, 2001
34
OPERATING REQUIREMENTS
SECTION F
MONITORING, RECORD
June 7, 2001
35
KEEPING, AND REPORTING
REQUIREMENTS
SECTION G
GENERAL CONDITIONS
June 7, 2001
38
SECTION H
ALTERNATE OPERATING SCENARIOS June 7, 2001
44
SECTION I
COMPLIANCE SCHEDULE
June 7, 2001
44
SECTION J
ACID RAIN PERMIT
June 7, 2001
45
Page 3
Permit Number: V-00-049
Page 1 of 50
SECTION A - PERMIT AUTHORIZATION
Pursuant to a duly submitted application which was determined to be
complete on January 21, 2000, the Kentucky
Division for Air Quality hereby authorizes the construction and operation
of the equipment described herein in
accordance with the terms and conditions of this permit. This draft
permit has been issued under the provisions of
Kentucky Revised Statutes Chapter 224 and regulations promulgated pursuant
thereto.
The permittee shall not construct, reconstruct, or modify any emission
units without first having submitted a complete
application and receiving a permit for the planned activity from the
permitting authority, except as provided in this permit
or in the Regulation 401 KAR 50:035, Permits.
Issuance of this permit does not relieve the permittee from the responsibility
of obtaining any other permits, licenses, or
approvals required by this Cabinet or any other federal, state, or local
agency.
References in this permit to regulatory requirements of 401 KAR 50:035
are based on the governing regulation which
was in effect at the time the permit application was deemed complete.
For future reference to the regulatory basis for
permit conditions and for the purposes of implementation and compliance,
the corresponding portions of the provisions
of new permitting regulations in 401 KAR Chapter 52 (effective January
15, 2001) shall apply
Page 4
Permit Number: V-00-049
Page 2 of 50
SECTION B - EMISSION POINTS, EMISSIONS UNITS, APPLICABLE REGULATIONS,
AND OPERATING CONDITIONS
Emissions Units: 01, 02 (GT1, GT2)
-
Synthesis/Natural Gas-Fired Combined Cycle
Combustion Turbines
Description:
1765 MMBTU/hr maximum heat input capacity, each, 197 MW power capacity
output (turbine only, does not include
heat recovery steam generator).
GE 7FA synthesis (primary) or natural (secondary/backup) gas-fired combined
cycle combustion turbine equipped with
steam injection.
Construction commenced: estimated - Summer 2001
Applicable Regulations:
Regulation 401 KAR 51:017, Prevention of significant deterioration of
air quality.
Regulation 401 KAR 60:005, incorporating by reference 40 CFR 60, Subpart
GG, Standards of Performance for
Stationary Gas Turbines, for emissions unit with a heat input at peak
load equal to or greater than 10 MMBTU/hour for
which construction commenced after October 3, 1977.
Regulation 401 KAR 59:021, New municipal solid waste incinerators.
Regulation 40 CFR 60 Subpart Eb, Standards of Performance for Large
Municipal Waste Combustors for which
Construction is Commenced After September 20, 1994 or for Which Modification
or Reconstruction is Commenced
After June 19, 1996.
1.
Operating Limitations:
a) Synthesis gas (mainly consists of carbon monoxide and hydrogen gas)
with natural gas back-up fuel, shall be the sole
fuels fired in the turbines. [Self-imposed restriction pursuant to Regulation
401 KAR 51:017, Prevention of significant
deterioration of air quality].
b) The heat input shall not exceed 1765 MMBTU/hour at ISO standard day
conditions, in accordance with Regulation
401 KAR 51:017. The rated heat input capacity shall be calculated
from the fuel usage, and corresponding fuel heating
value characteristic of the fuel to be combusted corrected to ISO standard
conditions based on manufacturer's curves
or equations for correction.
c) Natural gas usage in the combustion turbine shall not exceed 7,533,600
MMBTU in the first 12 months after startup,
3,766,800 MMBTU in the second twelve months, and 1,833, 400 MMBTU/yr
in any subsequent rolling 12 month
period. [This condition may be modified upon a complete analysis indicating
compliance with Best Available Control
Technology and Air Quality Impact Analyses as required by Regulation
401 KAR 51:017, Prevention of significant
deterioration of air quality, and any other applicable requirements.]
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SECTION B - EMISSION POINTS, EMISSIONS UNITS, APPLICABLE REGULATIONS,
AND OPERATING CONDITIONS (CONTINUED)
d) Pursuant to Regulation 40 CFR 60.53b, maximum synthesis gas fuel
flow to the gas turbines in MMBTU/hr shall not
exceed 110% of the synthesis gas fuel flow during the most recent performance
test.
e) Pursuant to Regulation 40 CFR 60.54b(a), no later than the date 6
months after the date of startup, each facility
supervisor and shift supervisor shall obtain and maintain a current
provisional certification from either the American
Society of Mechanical Engineers or a State certification program.
f) Pursuant to Regulation 40 CFR 60.54b(b), no later than the date 6
months after the date of startup, each facility
supervisor and shift supervisor shall have completed full certification
or shall have scheduled a full certification exam with
either the American Society of Mechanical Engineers or a State Certification
program.
g) Pursuant to Regulation 40 CFR 60.54b(c), 6 months after the date
of startup, no owner or operator shall allow the
facility to be operated at any time unless one of the following persons
is on duty and at the facility: A fully certified chief
facility operator, a provisionally certified chief facility operator
who is scheduled to take the full certification exam
according to the schedule specified in paragraph (b) of section 60.54
of 40 CFR 60 Subpart Eb, or a fully certified shift
supervisor who is scheduled to take the full certification exam according
to the schedule specified in paragraph (b) of
section 60.54 of 40 CFR 60 Subpart Eb.
h) Pursuant to Regulation 40 CFR 60.54b(e), a site-specific operating
manual shall be developed prior to
commencement of normal operations, and updated annually. The manual
shall include a description of the applicable
emission limits, procedures for proper operation of the gasification
plant and gas turbines, startup, shutdown, and
malfunction procedures. The manual shall include all elements
of 40 CFR 60.54b(e)(1) through (11) as they relate to
the site specific operation of an IGCC power plant. A training
program shall be developed to review the operating
manual within 6 months of startup and annually. The training program
shall include each person who has responsibilities
affecting the operation of the facility, including, but not limited
to, chief facility operators, shift supervisors, control room
operators, and appropriate maintenance personnel. The manual must
be readily accessible and available for inspection.
i) Pursuant to 40 CFR 60.57b(b), a siting analysis shall be conducted.
This analysis shall be made available to the public,
and comments accepted at the public meeting.
j) Except for periods of startup, shutdown, and malfunction, 90% full
load capacity (or greater) must be maintained by
each turbine unless additional ambient impact modeling is performed
demonstrating that other load scenarios result in less
impact.
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SECTION B - EMISSION POINTS, EMISSIONS UNITS, APPLICABLE REGULATIONS,
AND OPERATING CONDITIONS (CONTINUED)
2.
Emission Limitations:
a) Pursuant to Regulations 40 CFR 60.332, and 401 KAR 51:017, nitrogen
oxides emission level in the exhaust gas shall
not exceed 0.0735 lb/MMBTU based on 15 ppm by volume at 15 % oxygen,
on a dry basis, during any rolling three-
hour average period when firing synthesis gas. The nitrogen oxides emission
level in the exhaust gas shall not exceed
0.102 lb/MMBTU based on 25 ppm by volume at 15 % oxygen, on a dry basis,
during any rolling three-hour average
period when firing natural gas. When both fuels are fired simultaneously,
the allowable emissions shall be no higher than
the above limit specified for natural gas firing operations. Additionally,
the permittee shall keep records of the quantity
of each fuel used and the actual NOx/CO emissions during such periods.
The total emission from these operations,
together with the emissions from normal operations, shall not exceed
the emission rates used in the permittee's air quality
analysis modeling
.
The ppm level of nitrogen oxides (at ISO standard conditions)
and lb/MMBTU shall be demonstrated
by stack test, and measured with use of a continuous emission monitor
(CEM).
b) Pursuant to Regulation 401 KAR 51:017, the carbon monoxide
emission level in the exhaust gas shall not exceed
0.032 lb/MMBTU based on 15 ppm by volume at 15 % oxygen, on a dry basis,
during any rolling three-hour average
period when firing synthesis gas. The carbon monoxide emission level
in the exhaust gas shall not exceed 0.055
lb/MMBTU based on 25 ppm by volume at 15 % oxygen, on a dry basis, during
any rolling three-hour average period
when firing natural gas. When both fuels are fired simultaneously, the
allowable emissions shall be no higher than the
above limit specified for natural gas firing operations. Additionally,
the permittee shall keep records of the quantity of
each fuel used and the actual NOx/CO emissions during such periods.
The total emission from these operations,
together with the emissions from normal operations, shall not exceed
the emission rates used in the permittee's air quality
analysis modeling. The ppm level of carbon monoxide and lb/MMBTU shall
be demonstrated by stack test, and
measured with use of a continuous emission monitor (CEM).
c) Pursuant to Regulation 40 CFR 60.333, and 401 KAR 51:017, the sulfur
dioxide emission level in the exhaust gas
shall not exceed 0.032 lb/MMBTU based on any rolling three-hour average
period. Sulfur dioxide emissions also shall
not exceed 30 ppm by volume or 20% of the potential sulfur dioxide emission
concentration (80%reduction by weight
or volume) corrected to 7% oxygen (dry basis), whichever is most stringent.
The level of sulfur dioxide converted to
lb/MMBTU shall be demonstrated by stack test, and measured with use
of a continuous emission monitor (CEM).
d) Pursuant to Regulation 401 KAR 51:017, particulate emissions shall
not exceed 0.011 lb/MMBTU. The lb/MMBTU
level of particulate emissions shall be demonstrated by stack test,
then calculated based on the emission factor derived
during the test, fuel consumption data, fuel heat input, and fuel heat
content [see specific monitoring requirements].
e) Pursuant to Regulation 401 KAR 51:017, volatile organic compound
emissions shall not exceed 0.0044 lb/MMBTU.
The lb/MMBTU level of volatile organic compound emissions shall
be demonstrated by stack test, then calculated based
on the emission factor derived during the test, fuel consumption data,
fuel heat input, and fuel heat content [see specific
monitoring requirements].
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SECTION B - EMISSION POINTS, EMISSIONS UNITS, APPLICABLE REGULATIONS,
AND OPERATING CONDITIONS (CONTINUED)
f) Pursuant to Regulation 401 KAR 51:017, beryllium emissions shall
not exceed 6.0E-07 lb/MMBTU. The lb/MMBTU
level of beryllium emissions shall be demonstrated by stack test, then
calculated based on the emission factor derived
during the test, fuel consumption data, fuel heat input, and fuel heat
content.
g) Pursuant to Regulation 40 CFR 60.52b, emissions of cadmium shall
not exceed 0.020 milligrams per dry standard
cubic meter, corrected to 7% oxygen.
h) Pursuant to Regulation 40 CFR 60.52b, emissions of lead shall not
exceed 0.20 milligrams per dry standard cubic
meter, corrected to 7% oxygen.
i) Pursuant to Regulation 40 CFR 60.52b, emissions of mercury shall
not exceed 0.080 milligrams per dry standard cubic
meter, corrected to 7% oxygen.
j) Pursuant to Regulation 40 CFR 60.52b, and to preclude applicability
of 401 KAR 51:017, emissions of dioxins and
furans shall not exceed 0.01 nanograms per dry standard cubic meter
(total mass), corrected to 7% oxygen.
k) Pursuant to Regulation 40 CFR 60.52b, emissions of hydrogen chloride
shall not exceed 25 ppm by volume or 5%
of the potential hydrogen chloride emission concentration (95% reduction
by weight or volume), corrected to 7% oxygen
(dry basis), whichever is less stringent.
l) Pursuant to 40 CFR 60.58b, the above emission limits shall apply
at all times when syngas is fired, except during
periods of startup, shutdown, or malfunction. Duration of startup,
shutdown and malfunction periods are limited to 2
hours per occurrence
3.
Testing Requirements:
a) Pursuant to Regulation 40 CFR 60.335 (b), in conducting performance
tests required by 40 CFR 60.8, the owner
or operator shall use as reference methods and procedures the test methods
in Appendix A of Part 60 or other methods
or procedures as specified in 40 CFR 60.335, except as provided for
in 40 CFR 60.8(b).
b) Pursuant to Regulation 401 KAR 50:045, the owner or operator shall
conduct an initial performance test for nitrogen
oxides. The initial nitrogen oxides performance test shall be
performed in accordance with General Condition G(d)(5).
c) Pursuant to Regulation 401 KAR 50:045, the owner or operator shall
conduct an initial test for sulfur dioxide in
accordance with General Condition G(d)(5).
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SECTION B - EMISSION POINTS, EMISSIONS UNITS, APPLICABLE REGULATIONS,
AND OPERATING CONDITIONS (CONTINUED)
d) Pursuant to Regulation 401 KAR 50:045, the owner or operator shall
conduct an initial performance test for carbon
monoxide, using a reference test method approved by the Division, in
accordance with General Condition G(d)(5).
e) Pursuant to Regulation 401 KAR 50:045 and 40 CFR 60.58b, the owner
or operator shall conduct an initial and
annual performance tests for particulate matter, using a reference test
method approved by the Division, in accordance
with General Condition G(d)(5).
f) Pursuant to Regulation 401 KAR 50:045, the owner or operator shall
conduct an initial performance test for volatile
organic compounds, using a reference test method approved by the Division,
in accordance with General Condition
G(d)(5).
g) Pursuant to Regulation 401 KAR 50:045, the owner or operator shall
conduct an initial performance test for beryllium,
using a reference test method approved by the Division, in accordance
with General Condition G(d)(5).
h) See General Condition G(d)(6).
i) Pursuant to Regulation 40 CFR 60.52b, the owner or operator shall
conduct an initial and annual performance tests
for cadmium, lead and mercury, using EPA Reference Method 29 or an alternate
reference test approved by the
Division, in accordance with General Condition G(d)(5).
j) Pursuant to Regulation 40 CFR 60.52b, the owner or operator shall
conduct an initial and annual performance tests
for hydrogen chloride using EPA Reference Method 26 or 26a or an alternate
reference test approved by the Division,
in accordance with General Condition G(d)(5).
k) Pursuant to Regulation 40 CFR 60.52b, the owner or operator shall
conduct an initial and annual performance tests
for dioxins and furans using EPA Reference Method 23 or an alternate
reference test approved by the Division, in
accordance with General Condition G(d)(5). If emissions are less than
7 ng/m3, then the testing frequency can be
decreased as allowed in 40 CFR 60.58 (g)(5)(iii) upon Division approval.
4.
Specific Monitoring Requirements:
a) Pursuant to Regulation 401 KAR 50:035, Section 7(1)(c), 40 CFR 60.58b,
and 40 CFR 75, the permittee shall
install, calibrate, maintain, and operate the nitrogen oxides Continuous
Emissions Monitor (CEM). The nitrogen oxides
CEM shall be used as the indicator of continuous compliance with the
nitrogen oxides emission standard. Excluding the
startup and shut down periods, if any 3-hour rolling average exceeds
the nitrogen oxides emission limitation, the permittee
shall, as appropriate, initiate an investigation of the cause of the
exceedance and complete necessary control
device/process/CEM repairs or take corrective action as soon as practicable.
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SECTION B - EMISSION POINTS, EMISSIONS UNITS, APPLICABLE REGULATIONS,
AND OPERATING CONDITIONS (CONTINUED)
b) The nitrogen oxides CEM shall be used in lieu of the water to fuel
monitoring system for reporting excess emissions
in accordance with 40 CFR 60.334(c)(1). The calibration of the
water to fuel monitoring device required in 40 CFR
60.335(c)(2) will be replaced by the 40 CFR 75 certification tests of
the nitrogen oxides CEM. The CEM emission
rates for nitrogen oxides shall be corrected to ISO conditions to demonstrate
compliance with the nitrogen oxides
standard established in Subsection 2.
c) Additionally, a CEM system shall be installed, calibrated, maintained,
and operated for measuring oxygen levels in the
exhaust gas stacks.
d) The permittee shall comply with all of the monitoring requirements
of 40 CFR 75.
e) Pursuant to Regulation 40 CFR 60.334(a), the owner or operator using
water injection to control nitrogen oxide
emissions shall install and operate a continuous monitoring system to
monitor and record the fuel consumption. This
system shall be accurate to within plus or minus five (5) percent and
shall be approved by the Division.
f) The nitrogen oxide and sulfur dioxide CEM shall be used in lieu of
the fuel nitrogen and sulfur content monitoring
required by 40 CFR 60.334(b).
g) Pursuant to Regulation 401 KAR 50:035, Section 7(1)(c), and 40 CFR
60.58b to meet the periodic monitoring
requirement for carbon monoxide the permittee shall use a continuous
emission monitor (CEM). Excluding the startup
and shut down periods, if any 3-hour rolling average carbon monoxide
value exceeds the standard, the permittee shall,
as appropriate, initiate an investigation of the cause of the exceedance
and complete necessary process or CEM repairs
or take corrective action as soon as practicable.
h) Pursuant to Regulation 401 KAR 50:035, Section 7(1)(c), 40 CFR 60.58b,
and 40 CFR 75, to meet the periodic
monitoring requirement for sulfur dioxide the permittee shall use a
continuous emission monitor (CEM). Excluding the
startup and shut down periods, if any rolling 3-hour average sulfur
dioxide value exceeds the standard, the permittee shall,
as appropriate, initiate an investigation of the cause of the exceedance
and complete necessary process or CEM repairs
or take corrective action as soon as practicable.
i) Pursuant to Regulation 40 CFR 60.58b, to meet the periodic monitoring
requirement for opacity the permittee shall
use a continuous opacity monitor (COM). Excluding the startup
and shut down periods, if any 6 minute average exceeds
the standard, the permittee shall, as appropriate, initiate an investigation
of the cause of the exceedance and complete
necessary process or COM repairs or take corrective action as soon as
practicable.
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SECTION B - EMISSION POINTS, EMISSIONS UNITS, APPLICABLE REGULATIONS,
AND OPERATING CONDITIONS (CONTINUED)
j) Pursuant to 40 CFR 60.13(b), the continuous monitoring systems and
monitoring devices shall be installed and
operational prior to conducting the initial performance tests.
Verification of operational status shall, as a minimum, include
completion of the manufacturer's written requirements or recommendations
for installation, operation, and calibration of
the device(s).
k) Pursuant to 40 CFR 60.13(c), the owner or operator of an emissions
unit shall conduct a performance evaluation of
the continuous monitoring system during any performance test or within
30 days thereafter, in accordance with the
applicable performance specification in 40 CFR 60 Appendix B, for nitrogen
oxides, sulfur dioxide, or carbon monoxide.
Performance evaluations of CEM systems shall be conducted at other
times as required.
l) Pursuant to 40 CFR 60.13(d)(1), the owner(s) and operator(s) of all
continuous monitoring systems shall perform
appropriate calibration checks and zero and span adjustments in accordance
with a written procedure at least once daily,
in accordance with requirements specified in 40 CFR 60.13(d)(1).
m) Pursuant to 40 CFR 60.13(e), except for system breakdowns, repairs,
calibration checks, and zero and span
adjustments required under 40 CFR 60.13(d), all continuous monitoring
systems shall be in continuous operation and
shall meet minimum frequency of operation requirements which involves
one cycle of operation (sampling, analyzing, and
data recording) for each successive fifteen (15) minute period.
n) Pursuant to 40 CFR 60.13(f), all continuous monitoring systems or
monitoring devices shall be installed such that
representative measurements of emissions or process parameters from
the emissions unit are obtained. Additional
procedures for location of continuous monitoring systems contained in
the applicable Performance Specifications of 40
CFR 60 Appendix B shall be used.
o) Pursuant to 40 CFR 60.13(h), for the continuous monitoring systems
the owner(s) or operator(s) shall reduce all data
to one-hour averages. The one-hour averages shall be computed
from four or more data points equally spaced over
each one-hour period. Data recorded during periods of continuous
monitoring system breakdowns, repairs, calibration
checks, and zero and span adjustments shall not be included in the data
averages computed. An arithmetic or integrated
average of all data may be used. The data may be recorded in reduced
or nonreduced form (e.g., ppm pollutant and
percent oxygen). All excess emissions shall be converted into
units of the applicable standard using the applicable
conversion procedures specified in Subpart GG. After conversion
into units of the standard, the data may be rounded
to the same number of significant digits as used to specify the applicable
emission standard.
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SECTION B - EMISSION POINTS, EMISSIONS UNITS, APPLICABLE REGULATIONS,
AND OPERATING CONDITIONS (CONTINUED)
p) Pursuant to Regulation 401 KAR 50:035, Section 7(1)(c), for the particulate/particulate-10
periodic monitoring the
permittee shall develop the accurate emission factor during the performance
test. The permittee shall record the synthesis
gas heating value and the fuel consumption. On a daily basis,
the permittee shall calculate the emission rate for
particulate/particulate-10 using the fuel consumption, heating value
of synthesis gas, and emission factor developed during
the most recent performance test. Excluding the startup and shut down
periods, if any 24-hour rolling average
particulate/particulate-10 value exceeds the standard, the permittee
shall, as appropriate, initiate an investigation of the
cause of the exceedance and complete necessary process repairs or take
corrective action as soon as practicable.
q) Pursuant to Regulation 401 KAR 50:035, Section 7(1)(c), for the beryllium
periodic monitoring the permittee shall
develop the accurate emission factor during the performance test.
The permittee shall record the synthesis gas heating
value and the fuel consumption. On a daily basis, the permittee shall
calculate the emission rate for beryllium using the
fuel consumption, heating value of synthesis gas, and emission factor
developed during the most recent performance test.
Excluding the startup and shut down periods, if any 24-hour rolling
average beryllium value exceeds the standard, the
permittee shall, as appropriate, initiate an investigation of the cause
of the exceedance and complete necessary process
repairs or take corrective action as soon as practicable.
r) Pursuant to Regulation 401 KAR 50:035, Section 7(1)(c), for the volatile
organic compounds periodic monitoring the
permittee shall develop the accurate emission factor during the performance
test. The permittee shall record the synthesis
gas heating value and the fuel consumption. On a daily basis, the permittee
shall calculate the emission rate for volatile
organic compounds using the fuel consumption, heating value of synthesis
gas, and emission factor developed during the
most recent performance test. Excluding the startup and shut down periods,
if any 24-hour rolling average volatile organic
compounds value exceeds the standard, the permittee shall, as appropriate,
initiate an investigation of the cause of the
exceedance and complete necessary process repairs or take corrective
action as soon as practicable.
s) The permittee shall monitor the hours of operation of the emission
unit on a weekly basis.
5.
Specific Record Keeping Requirements:
a) Pursuant to Regulation 401 KAR 59:005, Section 3, the owner or operator
of the gas turbine shall maintain a file of
all measurements, including continuous monitoring system, monitoring
device, and performance testing measurements;
all continuous monitoring system performance evaluations; all continuous
monitoring system or monitoring device
calibration checks; adjustments and maintenance performed on these systems
and devices; and all other information
required by Regulation 401 KAR 59:005 recorded in a permanent form suitable
for inspection.
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SECTION B - EMISSION POINTS, EMISSIONS UNITS, APPLICABLE REGULATIONS,
AND OPERATING CONDITIONS (CONTINUED)
b) Records, including those documenting the results of each compliance
test and all other records and reports required
by this permit, shall be maintained for five (5) years pursuant to Regulation
401 KAR 50:035.
c) Pursuant to Regulation 401 KAR 59:005, Section 3, the owner or operator
of the unit shall maintain the records of
the occurrence and duration of any startup, shutdown, or malfunction
in the operation of the emissions unit, any
malfunction of the air pollution control equipment; or any period during
which a continuous monitoring system or
monitoring device is inoperative. The record shall also include
the type and quantity of fuel fired and the estimated
emissions during each episode.
d) Pursuant to Regulation 401 KAR 50:035, Section 7, records of the
hourly synthesis gas and/or natural gas (million
standard cubic feet) combusted shall be maintained. Records shall
be maintained to show that synthesis gas and natural
gas are the sole fuels burned in the turbine.
e) Pursuant to Regulation 401 KAR 50:035, Section 7, the permittee shall
maintain a weekly log of all hours of operation
of the turbine, for any consecutive twelve (12) month period.
f) Pursuant to Regulation 401 KAR 50:035, Section 7, the permittee shall
maintain a weekly log of all
particulate/particulate-10, volatile organic compounds, and beryllium
calculations, emissions, and test results.
g) The owner/operator shall comply with the recordkeeping requirements
of 40 CFR 60 Subpart Eb, section 60.59b.
6.
Specific Reporting Requirements:
a) Pursuant to Regulation 401 KAR 59:005, Section 3, minimum data requirements
which follow shall be maintained and
furnished in the format specified by the Division. Owners or operators
of facilities required to install continuous monitoring
systems shall submit for every calendar quarter a written report of
excess emissions (as defined in applicable sections)
to the Division. All quarterly reports shall be postmarked by the thirtieth
(30th) day following the end of each calendar
quarter and shall include the following information:
1) The magnitude of the excess emissions computed in accordance with
the Regulation 401 KAR 59:005,
Section 4(8), any conversion factors used, and the date and time of
commencement and completion of each time
period of excess emissions.
2) Specific identification of each period of excess emissions that occurs
during startups, shutdowns, and
malfunctions of the emissions unit. The nature and cause of any malfunction
(if known), the corrective action
taken or preventive measures adopted.
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SECTION B - EMISSION POINTS, EMISSIONS UNITS, APPLICABLE REGULATIONS,
AND OPERATING CONDITIONS (CONTINUED)
3) The date and time identifying each period during which continuous
monitoring system was inoperative except
for zero and span checks and the nature of the system repairs or adjustments.
4) When no excess emissions have occurred or the continuous monitoring
system(s) have not been inoperative,
repaired, or adjusted, such information shall be stated in the report.
b) Pursuant to Regulation 40 CFR 60.334 (c), for the reports regarding
nitrogen oxides excess emissions, in lieu of those
based on the water to fuel ratio monitoring, periods of excess emissions
are defined as follows:
Nitrogen oxides: any three-hour period during which the average nitrogen
oxides emission level as measured by
the continuous monitoring system, falls above the emission limitation
specified in Subsection 2.
c) Pursuant to Regulation 40 CFR 60.334(c), each report of nitrogen
oxides excess emissions shall include the average
nitrogen oxides emission level in lieu of water to fuel ratio, average
fuel consumption, ambient conditions, gas turbine load,
and the graphs or figures developed.
d) Pursuant to 401 KAR 50:035 Section 7(1)(c), monitoring requirement
with CEM for nitrogen oxides, excess
emissions are defined as any three (3) hour period during which the
average emissions (arithmetic average) exceed the
applicable nitrogen oxides emission standard. These periods of
excess emissions shall be reported quarterly.
e) Pursuant to Regulation 40 CFR 60.334(c), excess emissions of sulfur
dioxide are defined as any daily period during
which the sulfur dioxide emissions as indicated by continuous emission
monitoring, or the sulfur content (or as otherwise
required in an approved custom fuel sulfur monitoring plan) of the fuel
being fired in the gas turbine(s) exceeds the
limitations set forth in Subsection 2, Emission Limitations. These
periods of excess emissions shall be reported quarterly.
f) Pursuant to 401 KAR 50:035, Section 7(1)(c), monitoring requirement
with CEM for carbon monoxide, excess
emissions are defined as any three (3) hour period during which the
average emissions (arithmetic average of three
contiguous one hour periods) exceed the applicable carbon monoxide emission
standard. These periods of excess
emissions shall be reported quarterly.
g) Pursuant to 401 KAR 50:035, Section 7(1)(c), monitoring requirement
with record keeping and calculations with test
data and the recorded data for particulate/particulate-10, excess emissions
are defined as any 24-hour period during
which the average emissions exceed the applicable particulate/particulate-10
emission standard. These periods of excess
emissions shall be reported quarterly.
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SECTION B - EMISSION POINTS, EMISSIONS UNITS, APPLICABLE REGULATIONS,
AND OPERATING CONDITIONS (CONTINUED)
h) Pursuant to 401 KAR 50:035, Section 7(1)(c), monitoring requirement
with record keeping and calculations with test
data and the recorded data for volatile organic compounds, excess emissions
are defined as any 24-hour period during
which the average emissions exceed the applicable volatile organic compounds
emission standard. These periods of
excess emissions shall be reported quarterly.
i) Pursuant to 401 KAR 50:035, Section 7(1)(c), monitoring requirement
with record keeping and calculations with test
data and the recorded data for beryllium, excess emissions are defined
as any 24-hour period during which the average
emissions exceed the applicable beryllium emission standard. These
periods of excess emissions shall be reported
quarterly.
j) Pursuant to 401 KAR 50:035, Section 7(1)(c), monitoring requirement
with record keeping and calculations with test
data and the recorded data for cadmium, excess emissions are defined
as any 24-hour period during which the average
emissions exceed the applicable cadmium emission standard. These
periods of excess emissions shall be reported
quarterly.
k) Pursuant to 401 KAR 50:035, Section 7(1)(c), monitoring requirement
with record keeping and calculations with test
data and the recorded data for lead, excess emissions are defined as
any 24-hour period during which the average
emissions exceed the applicable lead emission standard. These
periods of excess emissions shall be reported quarterly.
l) Pursuant to 401 KAR 50:035, Section 7(1)(c), monitoring requirement
with record keeping and calculations with test
data and the recorded data for mercury, excess emissions are defined
as any 24-hour period during which the average
emissions exceed the applicable mercury emission standard. These
periods of excess emissions shall be reported
quarterly.
m) Pursuant to 401 KAR 50:035, Section 7(1)(c), monitoring requirement
with record keeping and calculations with
test data and the recorded data for hydrogen chloride, excess emissions
are defined as any 24-hour period during which
the average emissions exceed the applicable hydrogen chloride emission
standard. These periods of excess emissions
shall be reported quarterly.
n) Pursuant to 401 KAR 50:035, Section 7(1)(c), monitoring requirement
with record keeping and calculations with test
data and the recorded data for dioxins/furans, excess emissions are
defined as any 24-hour period during which the
average emissions exceed the applicable dioxins/furans emission standard.
These periods of excess emissions shall be
reported quarterly.
o) Pursuant to Regulation 40 CFR 60.59b, The owner or operator shall
submit semi-annual reports containing a summary
of collected data as outlined in 40 CFR 60.59b for all pollutants and
parameters regulated under 40 CFR 60.59b.
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SECTION B - EMISSION POINTS, EMISSIONS UNITS, APPLICABLE REGULATIONS,
AND OPERATING CONDITIONS (CONTINUED)
p) Pursuant to Regulation 40 CFR 60.59b, the owner or operator shall
submit to the Division's Frankfort Regional Office
a notification of construction which shall include:
1) The intent to construct;
2) The planned initial startup date;
3) The types of fuels planned for use;
4) The unit capacity and supporting calculations, and
5) Documents associated with the siting analysis conducted in accordance
with 40 CFR 60.57b(b).
A copy of the notification of the public meeting, a transcript of the
public meeting, and a summary of responses to public
comments shall be accompany the notice of construction.
7.
Specific Control Equipment Operating Conditions:
a) The diluent injection control measure for nitrogen oxides emissions
and, for sulfur removal, the acid gas scrubbing
system with the Claus plant and tailgas recycle, shall be operated as
necessary to maintain compliance with permitted
emission limitations, in accordance with manufacturer's design specifications
and/or good engineering practices. The
permittee shall implement good combustion control and use clean, low
sulfur/low ash synthesis gas as fuel. Natural gas
may be fired in the combustion turbine during periods when the gasification
system or sulfur removal and recovery system
are not operated due to maintenance, malfunction, or emergency situations.
Natural gas may be fired at any time, as long
as the annual usage does not exceed the operating limits in subsection
1.c.
b) See Section E for further requirements.
Page 16
Permit Number: V-00-049
Page 14 of 50
SECTION B - EMISSION POINTS, EMISSIONS UNITS, APPLICABLE
REGULATIONS, AND OPERATING CONDITIONS (CONTINUED)
Emissions Unit: 03 (02) - Flare
Description:
Construction commenced: expected Summer 2001
Steam-assisted flare, 150 SCF/hr natural gas for pilot flame
Applicable Regulations:
Regulation 401 KAR 63:015, Flares
Regulation 401 KAR 51:017, Prevention of significant deterioration of
air quality
1.
Operating Limitations:
None.
2.
Emission Limitations:
Pursuant to Regulation 401 KAR 63:015, no person shall cause or allow
the emission into the open air of particulate
matter from any flare which is greater than twenty (20) percent opacity
for more than three (3) minutes in any one (1)
day.
3.
Testing Requirements:
None.
4.
Specific Monitoring Requirements:
The permittee shall perform a qualitative visual observation of the
opacity of emissions from the flare on a weekly basis
and during the occurrence of any syngas flaring and maintain a log of
the observations. If visible emissions from the flare
are perceived or believed to exceed the applicable standard, the permittee
shall determine the opacity of emissions by
Reference Method 9 and initiate an inspection of the flare and the entire
process making any necessary repairs.
5.
Specific Recordkeeping Requirements:
None.
6.
Specific Reporting Requirements:
None.
7.
Specific Control Equipment Operating Conditions:
Pursuant to Regulation 401 KAR 51:017, Prevention of significant deterioration
of air quality, the permittee shall comply
with best available control technology with use of use of low ash/low
sulfur natural gas fuel and good flare design.
Page 17
Permit Number: V-00-049
Page 15 of 50
SECTION B - EMISSION POINTS, EMISSIONS UNITS, APPLICABLE REGULATIONS,
AND OPERATING CONDITIONS (CONTINUED)
Emissions Unit: 04 (04) - Briquette Handling Operations
Description:
Construction commenced: expected Summer 2001
Rated capacity: 5000 tons/day
Units
Briquette delivery by rapid dump railcar (12 hours/day)
Conveyor transfer to storage area (12 hours/day)
Conveyor and transfer points (two), (continuous)
Conveyor drop of briquettes into gasifier hopper (continuous)
Applicable Regulations:
Regulation 401 KAR 63:010, Fugitive emissions, and
Regulation 401 KAR 51:017, Prevention of significant deterioration of
air quality
Applicable Requirements
a) Pursuant to Regulation 401 KAR 63:010, Section 3, reasonable precautions
shall be taken to prevent particulate
matter from becoming airborne. Such reasonable precautions shall
include, when applicable, but not be limited to the
following:
1.
Application and maintenance of asphalt, application of water, or suitable
chemicals on roads, material
stockpiles, and other surfaces which can create airborne dusts;
2.
Installation and use of hoods, fans, and fabric filters to enclose and
vent the handling of dusty materials,
or the use of water sprays or other measures to suppress the dust emissions
during handling.
b) Pursuant to Regulation 401 KAR
63:010, Section 3, discharge of visible fugitive dust emissions beyond
the
property line is prohibited.
1.
Operating Limitations:
Pursuant to Regulation 401 KAR 51:017, The "rapid railcar dump and the
conveyor transfer to storage area" equipment
shall be operated no more than 12 hours/day (weekly average). This limitation
is required to ensure the air quality impact
is below the significant impact level and a full impact analysis will
be required to increase this limit.
2.
Emission Limitations:
None.
3.
Testing Requirements:
None.
Page 18
Permit Number: V-00-049
Page 16 of 50
SECTION B - EMISSION POINTS, EMISSIONS UNITS, APPLICABLE REGULATIONS,
AND OPERATING CONDITIONS (CONTINUED)
4.
Specific Monitoring Requirements:
a) The permittee shall monitor/record the hours of operation of the
equipment specified in the description.
b) The permittee shall monitor/record the weight of briquettes handled
on a weekly basis.
5.
Specific Recordkeeping Requirements:
The permittee shall maintain records of weekly briquettes processed,
the weight of materials handled, and weekly hours
of operation. The record shall be maintained on site and made
available for inspection by authorized personnel from the
Division.
6.
Specific Reporting Requirements:
See
Section F.
7.
Specific Control Equipment Operating Conditions:
Pursuant to Regulation 401 KAR 51:017, Prevention of significant deterioration
of air quality, the permittee shall comply
with best available control technology with use of enclosures and good
operating practices.
Page 19
Permit Number: V-00-049
Page 17 of 50
SECTION B - EMISSION POINTS, EMISSIONS UNITS, APPLICABLE REGULATIONS,
AND OPERATING CONDITIONS (CONTINUED)
Emissions Unit: 05 (05) - Vitrified Frit Handling Operations
Description:
Construction commenced: expected Summer 2001
Rated capacity: 500 tons/day
Units
Dump from gasifier to conveyor
Transfer to storage pile
Transfer point
Load into railcar (2 hours/day)
Applicable Regulations:
Regulation 401 KAR 63:010, Fugitive emissions, and
Regulation 401 KAR 51:017, Prevention of significant deterioration of
air quality
Regulation 401 KAR 60:005, incorporating by reference 40 CFR 60 Subpart
Eb, Standards of Performance for Large
Municipal Waste Combustors for which Construction is Commenced After
September 20, 1994 or for Which
Modification or Reconstruction is Commenced After June 19, 1996
Applicable Requirements
a) Pursuant to Regulation 401 KAR 63:010, Section 3, reasonable precautions
shall be taken to prevent particulate
matter from becoming airborne. Such reasonable precautions shall
include, when applicable, but not be limited to the
following:
1. Application and maintenance of asphalt, application of water,
or suitable chemicals on roads, material stockpiles, and
other surfaces which can create airborne dusts;
2. Installation and use of hoods, fans, and fabric filters to
enclose and vent the handling of dusty materials, or the use
of water sprays or other measures to suppress the dust emissions during
handling.
b) Pursuant to Regulation 401 KAR 63:010, Section 3, discharge
of visible fugitive dust emissions beyond the property
line is prohibited.
1.
Operating Limitations:
Pursuant to Regulation 401 KAR 51:017, The "vitrified frit load into
railcar" equipment shall be operated no more than
2 hours/day (weekly average). This limitation is required to ensure
the air quality impact is below the significant impact
level and a full impact analysis will be required to increase this limit.
Page 20
Permit Number: V-00-049
Page 18 of 50
SECTION B - EMISSION POINTS, EMISSIONS UNITS, APPLICABLE REGULATIONS,
AND OPERATING CONDITIONS (CONTINUED)
2.
Emission Limitations:
a. Pursuant to Regulation 40 CFR 60.55b, there shall be no discharge
of visible emissions from conveying systems
(including transfer points) in excess of 5% of the observation period
(i.e., 9 minutes per 3-hour period) as determined
by EPA Reference Method 22.
b. Pursuant to 40 CFR 60.55b(b) and (c), the emission limit listed above
does not cover visible emissions discharged
inside buildings or enclosures; however the emissions limit does cover
visible emissions discharged to the atmosphere
from buildings or enclosures. The limit listed in section 2.b above
does not apply during maintenance of the conveying
system.
3.
Testing Requirements:
Pursuant to Regulation 40 CFR 60.55b, the owner or operator shall conduct
initial and annual performance tests for
fugitive particulate emissions using EPA Reference Method 22 or an alternate
reference test method approved by the
Division, in accordance with General Condition G(d)(5). The minimum
observation time shall be a series of three 1-hour
observations. The observation period shall include times when the facility
is transferring frit from the gasification unit to
the storage area. The average duration of visible emissions per hour
shall be calculated from the three 1-hour
observations. The average shall be used to determine compliance with
40 CFR 60.55b.
4.
Specific Monitoring Requirements:
a) The permittee shall monitor/record the hours of operation of the
equipment specified in the description.
b) The permittee shall monitor/record the weight of vitrified frit handled
on a weekly basis.
5.
Specific Recordkeeping Requirements:
The permittee shall maintain records of weekly vitrified frit processed,
the weight of materials handled, and weekly hours
of operation. The record shall be maintained on site and made
available for inspection by authorized personnel from the
Division.
6.
Specific Reporting Requirements:
See Section
F.
7.
Specific Control Equipment Operating Conditions:
Pursuant to Regulation 401 KAR 51:017, Prevention of significant deterioration
of air quality, the permittee shall comply
with best available control technology with use of enclosures and good
operating practices.
Page 21
Permit Number: V-00-049
Page 19 of 50
SECTION B - EMISSION POINTS, EMISSIONS UNITS, APPLICABLE REGULATIONS,
AND OPERATING CONDITIONS (CONTINUED)
Emissions Unit: 06 (06) - Limestone Material Silo Loading
Description:
Construction commenced: Expected Summer 2001
Rated capacity: 135 tons/day
Control equipment: filter
Units
Limestone transfer to silo (one hour/day, weekly average)
Applicable Regulations:
Regulation 401 KAR 59:010, New process operations, and
Regulation 401 KAR 51:017, Prevention of significant deterioration of
air quality
1.
Operating Limitations:
Pursuant to Regulation 401 KAR 51:017, the "limestone transfer to silo"
unit shall be operated no more than one (1)
hour/day (weekly average). This limitation is required to ensure
the air quality impact is below the significant impact level
and a full impact analysis will be required to increase this limit.
2.
Emission Limitations:
a) Pursuant to Regulation 401 KAR 51:017, and pursuant to Regulation
401 KAR 59:010, Section 3(2), particulate
matter emissions into the open air shall not exceed 0.02 lb/hour. Compliance
with the allowable particulate standard may
be demonstrated by calculating particulate emissions using the following
formula:
PM emissions (lbs/hour) from silo loading = (U.S. EPA approved
or AP-42 emission factor with filter efficiency factored
in: 0.001 lb/ton)(silo loading rate in tons/hr).
b) Pursuant to Regulation 401 KAR 59:010, Section 3(1)(a) visible emissions
shall not equal or exceed twenty (20)
percent opacity based on a six-minute average.
3.
Testing Requirements:
None.
4.
Specific Monitoring Requirements:
a) The permittee shall monitor/record the hours of operation of the
units specified in the description.
b) The permittee shall monitor/record the weight of limestone handled
on a weekly basis.
Page 22
Permit Number: V-00-049
Page 20 of 50
SECTION B - EMISSION POINTS, EMISSIONS UNITS, APPLICABLE REGULATIONS,
AND OPERATING CONDITIONS (CONTINUED)
c) The permittee shall perform a qualitative visual observation of the
opacity of emissions from control equipment on a
daily basis and maintain a log of the observations. If visible
emissions from any control equipment are perceived or
believed to exceed the applicable standard, the permittee shall determine
the opacity of emissions by Reference Method
9 and initiate an inspection of the control equipment making any necessary
repairs.
5.
Specific Recordkeeping Requirements:
a) The permittee shall maintain records of weekly limestone processed,
the weight of materials handled, and weekly hours
of operation. The record shall be maintained on site and made
available for inspection by authorized personnel from the
Division.
b) The permittee shall calculate and maintain records of such calculations
to assure compliance with the hourly emission
limitations for the limestone.
6.
Specific Reporting Requirements:
See
Section F.
7.
Specific Control Equipment Operating Conditions:
Pursuant to Regulation 401 KAR 51:017, Prevention of significant deterioration
of air quality, the permittee shall comply
with best available control technology with use of a high efficiency
filter unit and good operating practices.
Page 23
Permit Number: V-00-049
Page 21 of 50
SECTION B - EMISSION POINTS, EMISSIONS UNITS, APPLICABLE
REGULATIONS, AND OPERATING CONDITIONS (CONTINUED)
Emissions Unit: 07 (07) - Limestone Handling Operations
Description:
Construction commenced: Expected Summer 2001
Rated capacity: 135 tons/day
Control equipment: Enclosures
Units
Transfer out of silo, (continuous)
Transfer to gasifier hopper (continuous)
Applicable Regulations:
Regulation 401 KAR 63:010, Fugitive emissions, and
Regulation 401 KAR 51:017, Prevention of significant deterioration of
air quality
Applicable Requirements
a) Pursuant to Regulation 401 KAR 63:010, Section 3, reasonable precautions
shall be taken to prevent particulate
matter from becoming airborne. Such reasonable precautions shall
include, when applicable, but not be limited to the
following:
1.
Application and maintenance of asphalt, application of water, or suitable
chemicals on roads, material stockpiles,
and other surfaces which can create airborne dusts;
2.
Installation and use of hoods, fans, and fabric filters to enclose and
vent the handling of dusty materials, or the
use of water sprays or other measures to suppress the dust emissions
during handling.
b) Pursuant to Regulation 401 KAR
63:010, Section 3, discharge of visible fugitive dust emissions beyond
the
property line is prohibited.
1.
Operating Limitations:
None.
2.
Emission Limitations:
None.
3.
Testing Requirements:
None.
4.
Specific Monitoring Requirements:
None.
Page 24
Permit Number: V-00-049
Page 22 of 50
SECTION B - EMISSION POINTS, EMISSIONS UNITS, APPLICABLE REGULATIONS,
AND OPERATING CONDITIONS (CONTINUED)
5.
Specific Recordkeeping Requirements:
None.
6.
Specific Reporting Requirements:
See
Section F.
7.
Specific Control Equipment Operating Conditions:
Pursuant to Regulation 401 KAR 51:017, Prevention of significant deterioration
of air quality, particulate emissions shall
be controlled by partial enclosures.
Page 25
Permit Number: V-00-049
Page 23 of 50
SECTION B - EMISSION POINTS, EMISSIONS UNITS, APPLICABLE REGULATIONS,
AND OPERATING CONDITIONS (CONTINUED)
Emissions Unit: 08 (08) - Pet Coke Silo Loading
Description:
Construction commenced: Expected Summer 2001
Rated capacity: 60 tons/startup, 12 startups per year (initial Global
estimate)
Control equipment: Filter
Pet coke transfer to silo
Applicable Regulations:
Regulation 401 KAR 59:010, New process operations, and
Regulation 401 KAR 51:017, Prevention of significant deterioration of
air quality
1.
Operating Limitations:
Pursuant to Regulation 401 KAR 51:017, The pet coke silo loading units
shall only be operated associated with the 12
startups per year. This limitation is required to ensure the air
quality impact is below the significant impact level and a
full impact analysis will be required to increase this limit.
2.
Emission Limitations:
a) Pursuant to Regulation 401 KAR 51:017, and pursuant to Regulation
401 KAR 59:010, Section 3(2), particulate
matter emissions into the open air shall not exceed 0.48 lb/hour. Compliance
with the allowable particulate standard may
be demonstrated by calculating particulate emissions using the following
formula:
PM emissions (lbs/hour) from silo loading = (U.S. EPA approved or AP-42
emission factor with filter efficiency factored
in: 0.002 lb/ton)(silo loading rate in tons/hr).
b) Pursuant to Regulation 401 KAR 59:010, Section 3(1)(a) visible emissions
shall not equal or exceed twenty (20)
percent opacity based on a six-minute average.
3.
Testing Requirements:
None.
4.
Specific Monitoring Requirements:
a) The permittee shall monitor/record the hours of operation of the
units specified in the description.
b) The permittee shall monitor/record the weight of pet coke handled
on a weekly basis.
Page 26
Permit Number: V-00-049
Page 24 of 50
SECTION B - EMISSION POINTS, EMISSIONS UNITS, APPLICABLE REGULATIONS,
AND OPERATING CONDITIONS (CONTINUED)
c) The permittee shall perform a qualitative visual observation of the
opacity of emissions from control equipment at least
once during each material transfer event or operation and maintain a
log of the observations. If visible emissions from
any control equipment are perceived or believed to exceed the applicable
standard, the permittee shall determine the
opacity of emissions by Reference Method 9 and initiate an inspection
of the control equipment making any necessary
repairs.
5.
Specific Recordkeeping Requirements:
a) The permittee shall maintain records of monthly pet coke processed,
the weight of materials handled, and monthly
hours of operation. The record shall be maintained on site and
made available for inspection by authorized personnel
from the Division.
b) The permittee shall calculate and maintain records of such calculations
to assure compliance with the hourly emission
limitations for the pet coke.
6.
Specific Reporting Requirements:
See
Section F.
7.
Specific Control Equipment Operating Conditions:
Pursuant to Regulation 401 KAR 51:017, Prevention of significant deterioration
of air quality, the permittee shall comply
with best available control technology with use of a high efficiency
filter unit and good operating practices.
Page 27
Permit Number: V-00-049
Page 25 of 50
SECTION B - EMISSION POINTS, EMISSIONS UNITS, APPLICABLE REGULATIONS,
AND OPERATING CONDITIONS (CONTINUED)
Emissions Unit: 09 (09) - Pet Coke Material Handling
Description:
Construction commenced: Expected Summer 2001
Rated capacity: 240 tons/day
Control equipment: Enclosures
Units
Transfer out of silo, (continuous)
Transfer to gasifier hopper (continuous)
Applicable Regulations:
Regulation 401 KAR 63:010, Fugitive emissions, and
Regulation 401 KAR 51:017, Prevention of significant deterioration of
air quality
Applicable Requirements
a) Pursuant to Regulation 401 KAR 63:010, Section 3, reasonable precautions
shall be taken to prevent particulate
matter from becoming airborne. Such reasonable precautions shall
include, when applicable, but not be limited to the
following:
1.
Application and maintenance of asphalt, application of water, or suitable
chemicals on roads, material stockpiles,
and other surfaces which can create airborne dusts;
2.
Installation and use of hoods, fans, and fabric filters to enclose and
vent the handling of dusty materials, or the
use of water sprays or other measures to suppress the dust emissions
during handling.
b) Pursuant to Regulation 401 KAR
63:010, Section 3, discharge of visible fugitive dust emissions beyond
the
property line is prohibited.
1.
Operating Limitations:
None
2.
Emission Limitations:
None.
3.
Testing Requirements:
None.
4.
Specific Monitoring Requirements:
None.
Page 28
Permit Number: V-00-049
Page 26 of 50
SECTION B - EMISSION POINTS, EMISSIONS UNITS, APPLICABLE REGULATIONS,
AND OPERATING CONDITIONS (CONTINUED)
5.
Specific Recordkeeping Requirements:
None.
6.
Specific Reporting Requirements:
See Section
F.
7.
Specific Control Equipment Operating Conditions:
Pursuant to Regulation 401 KAR 51:017, Prevention of significant deterioration
of air quality, particulate emissions shall
be controlled by partial enclosures.
Page 29
Permit Number: V-00-049
Page 27 of 50
SECTION B - EMISSION POINTS, EMISSIONS UNITS, APPLICABLE REGULATIONS,
AND OPERATING CONDITIONS (CONTINUED)
Emissions Unit: 10 (-) - Sulfur Recovery Operations and Sulfur Loading
& Storage Operations
Description:
Construction commenced: Expected Summer 2001
Rated capacity: 3.1 Tons/hour
Unit
Sulfur recovery unit - 99.9 % recovery
Applicable Regulations:
Regulation 401 KAR 59:105, New process gas streams, and
Regulation 401 KAR 51:017, Prevention of significant deterioration of
air quality
1.
Operating Limitations:
At all times during normal operation (non-emergency situations), the
gas cleanup with specialty amine solvent scrubbing
and Claus process sulfur recovery with closed loop tailgas recycle,
shall be operated in accordance with design
specifications and/or good engineering practices.
2.
Emission Limitations:
Pursuant to Regulation 401 KAR 59:105, Section 3, for sources whose
combined process gas stream emission rate
totals less than two (2) tons per day of hydrogen sulfide (for example,
KY Pioneer sulfur recovery process emissions
potential emissions equal 0.108 tons/year, reference application log
G364 Appendix A, page 5 of 13, 11/12/1999) the
permittee shall either reduce such emissions by eighty-five (85) percent
or control such emissions such that hydrogen
sulfide in the gas stream emitted into the ambient air does not exceed
ten (10) grains per 100 dscf (165 ppm by volume)
at zero percent oxygen.
3.
Testing Requirements:
Pursuant to Regulation 401 KAR 59:105, Section 6, an initial performance
test to demonstrate compliance with the
hydrogen sulfide emission limitation requirement in Subsection 2 shall
be conducted according to Reference Method 11.
The sample shall be drawn from a point near the centroid of the gas
line. The minimum sampling time shall be ten (10)
minutes and the minimum sample volume shall be 0.01 dscm (0.35 dscf)
for each sample. The arithmetic average of two
(2) samples shall constitute one (1) run. Samples shall be taken
at approximately one (1) hour intervals.
Page 30
Permit Number: V-00-049
Page 28 of 50
SECTION B - EMISSION POINTS, EMISSIONS UNITS, APPLICABLE REGULATIONS,
AND OPERATING CONDITIONS (CONTINUED)
4.
Specific Monitoring Requirements:
a) The permittee shall monitor/record the hours of operation of the
units specified in the description.
b) The permittee shall monitor/record the weight of sulfur produced
on a weekly basis.
c) The permittee shall monitor/record the amount of sulfur produced,
and assure the calculated sulfur production rate,
as determined from weekly data, does not exceed the maximum production
rate of sulfur from which resulting hydrogen
sulfide emission levels are shown to assure compliance as demonstrated
during the performance test.
5.
Specific Recordkeeping Requirements:
a) The permittee shall maintain records of weekly sulfur produced, the
weight of sulfur handled, and weekly hours of
operation. The record shall be maintained on site and made available
for inspection by authorized personnel from the
Division.
b) The permittee shall calculate and maintain records of such calculations
to assure compliance with the hydrogen sulfide
emission limitation. The calculations shall be performed weekly
with use of the weekly sulfur production rate, based on
the weight of sulfur and hours of operation per week, emission factors
as determined from the hydrogen sulfide
performance test required as specified in Subsection 3, Testing Requirements.
6.
Specific Reporting Requirements:
See Section
F.
7.
Specific Control Equipment Operating Conditions:
Pursuant to Regulation 401 KAR 51:017, Prevention of significant deterioration
of air quality, the permittee shall comply
with best available control technology with use of a high efficiency
filter unit and good operating practices.
Page 31
Permit Number: V-00-049
Page 29 of 50
SECTION B - EMISSION POINTS, EMISSIONS UNITS, APPLICABLE REGULATIONS,
AND OPERATING CONDITIONS (CONTINUED)
Emissions Unit: 11 (10) - Cooling Tower
Description:
Construction commenced: Expected Summer 2001
Rated capacity: 20,000 gallons/minute
Control equipment: high efficiency mist eliminators
Applicable Regulations:
Regulation 401 KAR 63:010, Fugitive emissions, and
Regulation 401 KAR 51:017, Prevention of significant deterioration of
air quality
Applicable Requirements
a) Pursuant to Regulation 401 KAR 63:010, Section 3, reasonable precautions
shall be taken to prevent particulate
matter from becoming airborne.
b) Pursuant to Regulation 401 KAR 63:010, Section 3, discharge of visible
fugitive dust emissions beyond the property
line is prohibited.
1.
Operating Limitations:
None.
2.
Emission Limitations:
a) Pursuant to Regulation 401 KAR 51:017, emissions of particulate matter
shall not exceed 1.5 lb/hour. Compliance
with the allowable particulate standard may be demonstrated by calculating
particulate emissions using the following
formula:
b) PM emissions (lbs/hour) from cooling tower = (U.S. EPA approved or
AP-42 emission factor with filter efficiency
factored in: 1.25xE-6 lb/gallon)(circulation rate in gallons/hr).
3.
Testing Requirements:
None.
4.
Specific Monitoring Requirements:
The permittee shall monitor the circulation rate on a daily basis.
5.
Specific Recordkeeping Requirements:
a) The permittee shall keep records of the circulation rate on a daily
basis.
b) The permittee shall calculate and maintain records of such calculations
to assure compliance with the particulate
matter emission limitation.
Page 32
Permit Number: V-00-049
Page 30 of 50
SECTION B - EMISSION POINTS, EMISSIONS UNITS, APPLICABLE REGULATIONS,
AND OPERATING CONDITIONS (CONTINUED)
6.
Specific Reporting Requirements:
See
Section F.
7.
Specific Control Equipment Operating Conditions:
Pursuant to Regulation 401 KAR 51:017, particulate emissions shall be
controlled by high efficiency mist eliminators.
Page 33
Permit Number: V-00-049
Page 31 of 50
SECTION B - EMISSION POINTS, EMISSIONS UNITS, APPLICABLE REGULATIONS,
AND OPERATING CONDITIONS (CONTINUED)
Emissions Unit: 12 (11) - Wastewater Treatment
Description:
Construction commenced: Expected Summer 2001
Rated capacity: 100,000 gallons/day
Applicable Regulations:
Regulation 401 KAR 51:017, Prevention of significant deterioration of
air quality
1.
Operating Limitations:
None.
2.
Emission Limitations:
None.
3.
Testing Requirements:
None.
4.
Specific Monitoring Requirements:
The permittee shall monitor amount of wastewater discharged on a daily
basis.
5.
Specific Recordkeeping Requirements:
a) The permittee shall maintain records of wastewater discharged on
a daily basis.
b) The permittee shall maintain records of wastewater treatment design
and
engineering estimates of average free-phase VOC concentrations.
6.
Specific Reporting Requirements:
See
Section F.
7.
Specific Control Equipment Operating Conditions:
Pursuant to Regulation 401 KAR 51:017, Prevention of significant deterioration
of air quality, VOC emissions shall be
controlled by enclosed piping and storage of wastewater streams with
flows greater than 1 liter per minute (annual
average) and VOC concentrations greater than 1% by weight (annual average).
Page 34
Permit Number: V-00-049
Page 32 of 50
SECTION C - INSIGNIFICANT ACTIVITIES
The following listed activities have been determined to be insignificant
activities for this source pursuant to 401 KAR
50:035, Section 5(4). While these activities are designated as
insignificant the permittee must comply with the applicable
regulation and some minimal level of periodic monitoring may be necessary.
Description
Generally Applicable Regulation
1.
Emergency diesel electric generator
NA
2.
Fuel cell
NA
Page 35
Permit Number: V-00-049
Page 33 of 50
SECTION D - SOURCE EMISSION LIMITATIONS AND TESTING REQUIREMENTS
1.
Nitrogen oxide, carbon monoxide, sulfur dioxide, particulate, volatile
organic compounds, beryllium, cadmium,
lead, mercury, hydrogen chloride, and dioxins/furans emissions, as measured
by methods referenced in 401
KAR 50:015, Section 1, shall not exceed the respective limitations specified
herein.
2.
Compliance with annual emissions and processing limitations imposed
pursuant to 401 KAR 50:035, Section
7(1)(a), and contained in this permit, shall be based on emissions and
processing rates for any twelve (12)
consecutive months.
3.
Between 18 to 24 months after startup , the permitee shall submit to
the Division for Air quality a NOx BACT
determination as if it was a new source, using the data gathered on
this facility, other similar facilities, and the
equipment manufacturer's research. The Division will make a determination
on BACT for NOx only, require
control equipment based on the BACT analysis, and adjust the NOx
emission limits accordingly.
Page 36
Permit Number: V-00-049
Page 34 of 50
SECTION E - SOURCE CONTROL EQUIPMENT REQUIREMENTS
Pursuant to 401 KAR 50:055, Section 2(5), at all times, including periods
of startup, shutdown and malfunction, owners
and operators shall, to the extent practicable, maintain and operate
any affected facility including associated air pollution
control equipment in a manner consistent with good air pollution control
practice for minimizing emissions. Determination
of whether acceptable operating and maintenance procedures are being
used will be based on information available to
the division which may include, but is not limited to, monitoring results,
opacity observations, review of operating and
maintenance procedures, and inspection of the source.
Page 37
Permit Number: V-00-049
Page 35 of 50
SECTION F - MONITORING, RECORD KEEPING, AND REPORTING REQUIREMENTS
1.
When continuing compliance is demonstrated by periodic testing or instrumental
monitoring, the permittee shall
compile records of required monitoring information that include:
a.
Date, place as defined in this permit, and time of sampling or measurements.
b.
Analyses performance dates;
c.
Company or entity that performed analyses;
d.
Analytical techniques or methods used;
e.
Analyses results; and
f.
Operating conditions during time of sampling or measurement;
2.
Records of all required monitoring data and support information, including
calibrations, maintenance records,
and original strip chart recordings, and copies of all reports required
by the Division for Air Quality, shall be
retained by the permittee for a period of five years and shall be made
available for inspection upon request by
any duly authorized representative of the Division for Air Quality.
[401 KAR 50:035, Permits, Section 7(1)(d)2
and 401 KAR 50:035, Permits, Section 7(2)(c)]
3.
In accordance with the requirements of 401 KAR 50:035, Permits, Section
7(2)(c) the permittee shall allow the
Cabinet or authorized representatives to perform the following:
a.
Enter upon the premises where a source is located or emissions-related
activity is conducted, or where
records are kept;
b.
Have access to and copy, at reasonable times, any records required by
the permit:
i.
During normal office hours, and
ii.
During periods of emergency when prompt access to records is essential
to proper assessment
by the Cabinet;
c.
Inspect, at reasonable times, any facilities, equipment (including
monitoring and pollution control
equipment), practices, or operations required by the permit. Reasonable
times shall include, but are not
limited to the following:
i.
During all hours of operation at the source,
ii.
For all sources operated intermittently, during all hours of operation
at the source and the hours
between 8:00 a.m. and 4:30 p.m., Monday through Friday, excluding holidays,
and
iii.
During an emergency; and
d.
Sample or monitor, at reasonable times, substances or parameters to
assure compliance with the permit
or any applicable requirements. Reasonable times shall include,
but are not limited to the following:
i.
During all hours of operation at the source,
ii.
For all sources operated intermittently, during all hours of operation
at the source and the hours
between 8:00 a.m. and 4:30 p.m., Monday through Friday, excluding holidays,
and
iii.
During an emergency.
4.
No person shall obstruct, hamper, or interfere with any Cabinet employee
or authorized representative while in
the process of carrying out official duties. Refusal of entry
or access may constitute grounds for permit
revocation and assessment of civil penalties.
Page 38
Permit Number: V-00-049
Page 36 of 50
SECTION F - MONITORING, RECORD KEEPING, AND REPORTING REQUIREMENTS
(CONTINUED)
5.
Summary reports of any monitoring required by this permit, other than
continuous emission or opacity monitors,
shall be submitted to the division's Frankfort Regional Office at least
every six (6) months during the life of this
permit, unless otherwise stated in this permit. For emission units that
were still under construction or which had
not commenced operation at the end of the 6-month period covered by
the report and are subject to monitoring
requirements in this permit, the report shall indicate that no monitoring
was performed during the previous six
months because the emission unit was not in operation.
The reports are due within 30 days after the end of each six-month reporting
period that commences on the initial
issuance date of this permit. The permittee may shift to semi-annual
reporting on a calendar year basis upon
approval of the regional office. If calendar year reporting is
approved, the semi-annual reports are due January
30th and July 30th of each year. Data from the continuous emission
and opacity monitors shall be reported to
the Technical Services Branch in accordance with the requirements of
401 KAR 59:005, General Provisions,
Section 3(3). All reports shall be certified by a responsible
official pursuant to Section 6(1) of 401 KAR
50:035, Permits. All deviations from permit requirements shall
be clearly identified in the reports.
6.
a.
In accordance with the provisions of 401 KAR 50:055, Section 1 the owner
or operator shall notify the
Division for Air Quality's Frankfort Regional Office concerning startups,
shutdowns, or malfunctions as
follows:
1.
When emissions during any planned shutdowns and ensuing startups will
exceed the standards
notification shall be made no later than three (3) days before the planned
shutdown, or
immediately following the decision to shut down, if the shutdown is
due to events which could
not have been foreseen three (3) days before the shutdown.
2.
When emissions due to malfunctions, unplanned shutdowns and ensuing
startups are or may be
in excess of the standards notification shall be made as promptly as
possible by telephone (or
other electronic media) and shall cause written notice upon request.
b.
In accordance with the provisions of 401 KAR 50:035, Section 7(1)(e)2,
the owner or operator shall
report emission related exceedances from permit requirements including
those attributed to upset
conditions (other than emission exceedances covered by general condition
6 a. above) to the Division
for Air Quality's Frankfort Regional Office within 30 days. Other
deviations from permit requirements
shall be included in the semiannual report required by general condition
F.5.
Page 39
Permit Number: V-00-049
Page 37 of 50
SECTION F - MONITORING, RECORD KEEPING, AND REPORTING REQUIREMENTS
(CONTINUED)
7.
Pursuant to 401 KAR 50:035, Permits, Section 7(2)(b), the permittee
shall certify compliance with the terms
and conditions contained in this permit, annually on the permit issuance
anniversary date or by January 30th of
each year if calendar year reporting is approved by the regional office,
by completing and returning a Compliance
Certification Form (DEP 7007CC) (or an approved alternative) to the
Division for Air Quality's Frankfort
Regional Office and the U.S. EPA in accordance with the following
requirements:
a.
Identification of each term or condition of the permit that is the basis
of the certification;
b.
The compliance status regarding each term or condition of the permit;
c.
Whether compliance was continuous or intermittent; and
d.
The method used for determining the compliance status for the source,
currently and over the reporting
period, pursuant to 401 KAR 50:035, Section 7(1)(c),(d), and (e).
e.
For an emissions unit that was still under construction or which has
not commenced operation at the end
of the 12-month period covered by the annual compliance certification,
the permittee shall indicate that
the unit is under construction and that compliance with any applicable
requirements will be demonstrated
within the timeframes specified in the permit.
f.
The certification shall be postmarked by the thirtieth (30) day following
the applicable permit issuance
anniversary date, or by January 30th of each year if calendar year reporting
is approved by the regional
office.
Annual compliance certifications should be mailed to the following
addresses:
Division for Air Quality
U.S. EPA Region IV
Frankfort Regional Office
Air Enforcement Branch
643 Teton Trail, Suite B
Atlanta Federal Center
Frankfort, KY 40601-1758
61 Forsyth St.
Atlanta, GA 30303-8960
Division for Air Quality
Central Files
803 Schenkel Lane
Frankfort, KY 40601
8.
In accordance with 401 KAR 50:035, Section 23, the permittee shall
provide the division with all information
necessary to determine its subject emissions within thirty (30) days
of the date the KEIS emission report is
mailed to the permittee.
9.
Pursuant to Section VII.3 of the policy manual of the Division for Air
Quality as referenced by 401 KAR 50:016,
Section 1(1), results of performance test(s) required by the permit
shall be submitted to the Division by the
source or its representative within forty-five days after the completion
of the fieldwork.
Page 40
Permit Number: V-00-049
Page 38 of 50
SECTION G - GENERAL CONDITIONS
(a)
General Compliance Requirements
1.
The permittee shall comply with all conditions of this permit.
A noncompliance shall be (a) violation(s) of 401
KAR 50:035, Permits, Section 7(3)(d)
and Federal Statute 42 USC 7401 through 7671q
and is grounds for
enforcement action including but not limited to the termination, revocation
and reissuance, or revision of this
permit.
2.
The filing of a request by the permittee for any permit revision, revocation,
reissuance, or termination, or of a
notification of a planned change or anticipated noncompliance, shall
not stay any permit condition.
3.
This permit may be revised, revoked, reopened and reissued, or terminated
for cause. The permit will be
reopened for cause and revised accordingly under the following circumstances:
a.
If additional applicable requirements become applicable to the source
and the remaining permit term is
three (3) years or longer. In this case, the reopening shall be
completed no later than eighteen (18)
months after promulgation of the applicable requirement. A reopening
shall not be required if compliance
with the applicable requirement is not required until after the date
on which the permit is due to expire,
unless this permit or any of its terms and conditions have been extended
pursuant to 401 KAR 50:035,
Section 12(2)(c);
b.
The Cabinet
or the U. S. EPA determines that the permit must be revised or revoked
to assure
compliance with the applicable requirements;
c.
The Cabinet or the U. S. EPA
determines that the permit contains a material mistake or that inaccurate
statements were made in establishing the emissions standards or other
terms or conditions of the permit;
d.
If any additional applicable requirements of the Acid Rain Program become
applicable to the source.
Proceedings to reopen and reissue a permit shall follow the same procedures
as apply to initial permit issuance
and shall affect only those parts of the permit for which cause to reopen
exists. Reopenings shall be made as
expeditiously as practicable. Reopenings shall not be initiated
before a notice of intent to reopen is provided to
the source by the division, at least thirty (30) days in advance of
the date the permit is to be reopened, except
that the Division may provide a shorter time period in the case of an
emergency.
4.
The permittee shall furnish to the Division, in writing, information
that the division may request to determine
whether cause exists for modifying, revoking and reissuing, or terminating
the permit, or to determine compliance
with the permit. [401 KAR 50:035, Permits, Section 7(2)(b)3e and 401
KAR 50:035, Permits, Section 7(3)(j)]
5.
The permittee, upon becoming aware that any relevant facts were omitted
or incorrect information was submitted
in the permit application, shall promptly submit such supplementary
facts or corrected information to the
permitting authority.
Page 41
Permit Number: V-00-049
Page 39 of 50
SECTION G - GENERAL CONDITIONS (CONTINUED)
6.
Any condition or portion of this permit which becomes suspended or is
ruled invalid as a result of any legal or
other action shall not invalidate any other portion or condition of
this permit. [401 KAR 50:035, Permits, Section
7(3)(k)]
7.
The permittee shall not use as a defense in an enforcement action the
contention that it would have been
necessary to halt or reduce the permitted activity in order to maintain
compliance. [401 KAR 50:035, Permits,
Section 7(3)(e)]
8.
Except as identified as state-origin requirements in this permit, all
terms and conditions contained herein shall be
enforceable by the United States Environmental Protection Agency and
citizens of the United States.
9.
This permit shall be subject to suspension if the permittee fails to
pay all emissions fees within 90 days after the
date of notice as specified in 401 KAR 50:038, Section 3(6). [401
KAR 50:035, Permits, Section 7(3)(h)]
10.
Nothing in this permit shall alter or affect the liability of the permittee
for any violation of applicable requirements
prior to or at the time of permit issuance. [401 KAR 50:035, Permits,
Section 8(3)(b)]
11.
This permit shall not convey property rights or exclusive privileges.
[401 KAR 50:035, Permits, Section 7 (3)(g)]
12.
Issuance of this permit does not relieve the permittee from the responsibility
of obtaining any other permits,
licenses, or approvals required by the Kentucky Cabinet for Natural
Resources and Environmental Protection
or any other federal, state, or local agency.
13.
Nothing in this permit shall alter or affect the authority of U.S. EPA
to obtain information pursuant to Federal
Statute 42 USC 7414, Inspections, monitoring, and entry. [401 KAR 50:035,
Permits, Section 7(2)(b)5]
14.
Nothing in this permit shall alter or affect the authority of U.S. EPA
to impose emergency orders pursuant to
Federal Statute 42 USC 7603, Emergency orders. [401 KAR 50:035, Permits,
Section 8(3)(a)]
15.
Permit Shield: Except as provided in 401 KAR 50:035, Permits,
compliance by the affected facilities listed
herein with the conditions of this permit shall be deemed to be compliance
with all applicable requirements
identified in this permit as of the date of issuance of this permit.
16.
All previously issued construction and operating permits are hereby
subsumed into this permit.
Page 42
Permit Number: V-00-049
Page 40 of 50
SECTION G - GENERAL CONDITIONS (CONTINUED)
(b)
Permit Expiration and Reapplication Requirements
This permit shall remain in effect for a fixed term of five (5) years
following the original date of issue. Permit expiration
shall terminate the source's right to operate unless a timely and complete
renewal application has been submitted to the
division at least six months prior to the expiration date of the permit.
Upon a timely and complete submittal, the
authorization to operate within the terms and conditions of this permit,
including any permit shield, shall remain in effect
beyond the expiration date, until the renewal permit is issued or denied
by the division. [401 KAR 50:035, Permits,
Section 12]
(c)
Permit Revisions
1.
A minor permit revision procedure may be used for permit revisions involving
the use of economic incentive,
marketable permit, emission trading, and other similar approaches, to
the extent that these minor permit revision
procedures are explicitly provided for in the SIP or in applicable requirements
and meet the relevant
requirements of 401 KAR 50:035, Section 15.
2.
This permit is not transferable by the permittee. Future owners
and operators shall obtain a new permit from
the Division for Air Quality. The new permit may be processed
as an administrative amendment if no other
change in this permit is necessary, and provided that a written agreement
containing a specific date for transfer
of permit responsibility coverage and liability between the current
and new permittee has been submitted to the
permitting authority thirty (30) days in advance of the transfer.
(d)
Construction, Start-Up, and Initial Compliance Demonstration Requirements
1.
Construction of process and/or air pollution control equipment authorized
by this permit shall be conducted and
completed only in compliance with the conditions of this permit.
2.
Within thirty (30) days following commencement of construction, and
within fifteen (15) days following start-up,
and attainment of the maximum production rate specified in the permit
application, or within fifteen (15) days
following the issuance date of this permit, whichever is later, the
permittee shall furnish to the Division for Air
Quality's Frankfort Regional Office in writing, with a copy to the division's
Frankfort Central Office, notification
of the following:
a.
The date when construction commenced.
b.
The date of start-up of the affected facilities listed in this permit.
c.
The date when the maximum production rate specified in the permit application
was achieved.
Page 43
Permit Number: V-00-049
Page 41 of 50
SECTION G - GENERAL CONDITIONS (CONTINUED)
3.
Pursuant to 401 KAR 50:035, Permits, Section 13(1), unless construction
is commenced on or before 18
months after the date of issue of this permit, or if construction is
commenced and then stopped for any
consecutive period of 18 months or more, or if construction is not completed
within eighteen (18) months of the
scheduled completion date, then the construction and operating authority
granted by this permit for those affected
facilities for which construction was not completed shall immediately
become invalid. Extensions of the time
periods specified herein may be granted by the division upon a satisfactory
request showing that an extension
is justified.
4.
Operation of the affected facilities for which construction is authorized
by this permit shall not commence until
compliance with the applicable standards specified herein has been demonstrated
pursuant to 401 KAR 50:055,
except as provided in Section I of this permit.
5.
This permit shall allow time for the initial start-up, operation, and
compliance demonstration of the affected
facilities listed herein. However, within sixty (60) days after
achieving the maximum production rate at which the
affected facilities will be operated but not later than 180 days after
initial start-up of such facilities, the permittee
shall conduct a performance demonstration on the affected facilities
in accordance with 401 KAR 50:055,
General compliance requirements. These performance tests must
also be conducted in accordance with General
Conditions G(d)6 of this permit and the permittee must furnish to the
Division for Air Quality's Frankfort Central
Office a written report of the results of such performance test
.
6.
Pursuant to Section VII 2.(1) of the policy manual of the Division for
Air Quality as referenced by 401 KAR
50:016, Section 1.(1), at least one month prior to the date of the required
performance test, the permittee shall
complete and return a Compliance Test Protocol (Form DEP 6027) to the
division's Frankfort Central Office.
Pursuant to 401 KAR 50:045, Section 5, the division shall be notified
of the actual test date at least ten (10)
days prior to the test.
(e)
Acid Rain Program Requirements
If an applicable requirement of Federal Statute 42 USC 7401 through
7671q (the Clean Air Act) is more stringent than
an applicable requirement promulgated pursuant to Federal Statute 42
USC 7651 through 7651o (Title IV of the Act),
both provisions shall apply, and both shall be state and federally enforceable.
(f)
Emergency Provisions
1.
An emergency shall constitute an affirmative defense to an action brought
for noncompliance with the technology-
based emission limitations if the permittee demonstrates through properly
signed contemporaneous operating logs
or other relevant evidence that:
Page 44
Permit Number: V-00-049
Page 42 of 50
SECTION G - GENERAL CONDITIONS (CONTINUED)
a.
An emergency occurred and the permittee can identify the cause of the
emergency;
b.
The permitted facility was at the time being properly operated;
c.
During an emergency, the permittee took all reasonable steps to minimize
levels of emissions that
exceeded the emissions standards or other requirements in the permit;
and,
d.
The permittee notified the division as promptly as possible and submitted
written notice of the emergency
to the division within two working days after the time when emission
limitations were exceeded due to
the emergency. The notice shall meet the requirements of 401 KAR
50:035, Permits, Section 7(1)(e)2,
and include a description of the emergency, steps taken to mitigate
emissions, and the corrective actions
taken. This requirement does not relieve the source of any other
local, state or federal notification
requirements.
2.
Emergency conditions listed in General Condition (f)1 above are in addition
to any emergency or upset
provision(s) contained in an applicable requirement.
3.
In an enforcement proceeding, the permittee seeking to establish the
occurrence of an emergency shall have the
burden of proof. [401 KAR 50:035, Permits, Section 9(3)]
(g)
Risk Management Provisions
1.
The permittee shall comply with all applicable requirements of 40 CFR
Part 68, Risk Management Plan
provisions. If required, the permittee shall comply with the Risk
Management Program and submit a Risk
Management Plan to:
RMP Reporting Center
P.O. Box 3346
Merrifield, VA, 22116-3346
2.
If requested, submit additional relevant information to the division
or the U.S. EPA.
(h)
Ozone depleting substances
1.
The permittee shall comply with the standards for recycling and emissions
reduction pursuant to 40 CFR 82,
Subpart F, except as provided for Motor Vehicle Air Conditioners (MVACs)
in Subpart B:
a.
Persons opening appliances for maintenance, service, repair, or disposal
shall comply with the required
practices contained in 40 CFR 82.156.
b.
Equipment used during the maintenance, service, repair, or disposal
of appliances shall comply with the
standards for recycling and recovery equipment contained in 40 CFR 82.158.
c.
Persons performing maintenance, service, repair, or disposal of appliances
shall be certified by an
approved technician certification program pursuant to 40 CFR 82.161.
d.
Persons disposing of small appliances, MVACs, and MVAC-like appliances
(as defined at 40 CFR
82.152) shall comply with the recordkeeping requirements pursuant to
40 CFR 82.166.
Page 45
Permit Number: V-00-049
Page 43 of 50
SECTION G - GENERAL CONDITIONS (CONTINUED)
e.
Persons owning commercial or industrial process refrigeration equipment
shall
comply with the leak repair requirements pursuant to 40 CFR 82.156.
f.
Owners/operators of appliances normally containing 50 or more pounds
of refrigerant shall keep records
of refrigerant purchased and added to such appliances pursuant to 40
CFR 82.166.
2.
If the permittee performs service on motor (fleet) vehicle air conditioners
containing ozone-depleting substances,
the source shall comply with all applicable requirements as specified
in 40 CFR 82, Subpart B, Servicing of
Motor Vehicle Air Conditioners.
Page 46
Permit Number: V-00-049
Page 44 of 50
SECTION H ALTERNATE OPERATING SCENARIOS
Not Applicable
SECTION I COMPLIANCE SCHEDULE
Not Applicable
Page 47
Permit Number: V-00-049
Page 45 of 50
SECTION J ACID RAIN
Commonwealth of Kentucky
Natural Resources and Environmental Protection Cabinet
Department for Environmental Protection
Division for Air Quality
803 Schenkel Lane
Frankfort, Kentucky 40601
(502) 573-3382
PHASE II ACID RAIN PERMIT
Plant Name:
Kentucky Pioneer Energy
Plant Location:
12145 Irvine Road, Trapp, Kentucky 40391
Owner:
Kentucky Pioneer Energy LLC
Mailing Address:
312
Walnut Street, Suite 2000, Cincinnati, Ohio 45202
Region:
Bluegrass
County:
Clark
ACID RAIN PERMIT CONTENTS
1)
Statement of Basis
2)
SO
2
allowances allocated under this permit and NOx
requirements for each affected unit.
3)
Comments, notes and justifications regarding permit decisions and changes
made to the
permit application forms during the review process, and any additional
requirements or
conditions.
4)
The permit application submitted for this source. The owners and
operators of the source
must comply with the standard requirements and special provisions set
forth in the
Phase II
Application.
5)
Summary of Actions
1. Statement of Basis:
Statutory and Regulatory Authorities:
In accordance with KRS 224.10-100 and Titles IV and V of
the Clean Air Act, the Kentucky Natural Resources and Environmental
Protection Cabinet, Division for Air
Quality issues this permit pursuant to Regulations 401 KAR 50:035, Permits,
401 KAR 50:072, Acid Rain
Permit, and Federal Regulation 40 CFR Part 76.
Page 48
Permit Number:
V-00-049
Page:
48
of
50
PERMIT (Conditions)
Plant Name:
Kentucky Pioneer Energy
Affected Unit:
01 GT1
2. SO
2
Allowance Allocations and NO
x
Requirements for the affected unit:
Year
SO
2
Allowances
2001
2002
2003
2004
2005
Tables 2, 3 or 4 of
40 CFR Part 73
0*
0*
0*
0*
0*
NO
x
Requirements
NO
x
Limits
N/A**
*
The number of allowances allocated to Phase II affected units by the
U.S. EPA may change under
40 CFR part 73. In addition, the number of allowances actually held
by an affected source in a unit
account may differ from the number allocated by U. S. EPA. Neither of
the aforementioned
conditions necessitate a revision to the unit SO
2
allowance allocations identified in this permit (See
40 CFR 72.84).
**
This unit currently does not have applicable NO
x
limits set by 40 CFR, part 76
.
Page 49
Permit Number:
V-00-049
Page:
49
of
50
PERMIT (Conditions)
Plant Name:
Kentucky Pioneer Energy
Affected Unit:
02 GT2
SO
2
Allowance Allocations and NO
x
Requirements for the affected unit:
Year
SO
2
Allowances
2001
2002
2003
2004
2005
Tables 2, 3 or 4 of
40 CFR Part 73
0*
0*
0*
0*
0*
NO
x
Requirements
NO
x
Limits
N/A**
*
The number of allowances allocated to Phase II affected units by the
U.S. EPA may change under
40 CFR part 73. In addition, the number of allowances actually held
by an affected source in a unit
account may differ from the number allocated by U. S. EPA. Neither of
the aforementioned
conditions necessitate a revision to the unit SO
2
allowance allocations identified in this permit (See
40 CFR 72.84).
**
This unit currently does not have applicable NO
x
limits set by 40 CFR, part 76
.
Page 50
Permit Number:
V-00-049
Page:
50
of
50
PERMIT (Conditions)
3. Comments, Notes, and Justifications:
The two (2) Combined Cycle Combustion Turbines, units 01 and 02 will
be constructed after the
SO
2
allocation date; therefore these units will have no SO
2
allowances allocated by U.S. EPA and
must obtain SO
2
allowances through other means.
The two (2) Combined Cycle Combustion Turbines, units 01 and 02 do not
have applicable NO
x
limits set by 40 CFR part 76.
4. Permit Application:
Attached
The Phase II Permit Application is a part of this permit and the source
must comply with the
standard requirements and special provisions set forth in the Phase
II Application.
5. Summary of Actions:
Past Action:
1. Draft Phase II Permit (# A-00-007) was proposed for public comment.
Present Action:
1. Acid Rain Phase II permit # A-00-007 was included (as Section J)
in Title V permit #V-
00-049 and issued as a proposed permit on June 7, 2001.
======================================
One of the world's pioneering commercial-scale coal gasification-based
power facilities, Wabash River's Integrated Gasification Combined-Cycle
(IGCC) plant, has successfully completed its fourth year of commercial
operation and processed over one-and-a-half million tons of coal.
A winner
of
Power
magazine's 1996 Powerplant Award, as well as other honors,
Wabash River is one of the cleanest coal-fired facilities in the world,
and has
contributed greatly to the commer-
cial potential of this advanced coal-
based power generation technology.
Gasification is already in wide use for
syngas-to-chemical production, and
under the DOE Office of Fossil En-
ergy Vision 21 initiative, coal-based
IGCC is expected to coproduce
power and high-value chemicals and
clean transportation fuels.
DOE selected Wabash River in
September 1991 as a Clean Coal
Technology (CCT) Program Round
IV demonstration project, and the
Cooperative Agreement between the industrial participants and DOE was
signed in July 1992. Commercial operation began in December 1995.
The
Cooperative Agreement ended in January 2000 after a four-year commercial
demonstration, and the plant continues in commercial operation.
The original Participant was the Wabash River Coal Gasification Repower-
ing Project Joint Venture, formed in 1990 by Destec Energy, Inc. of
Houston,
Texas and PSI Energy, Inc. of Plainfield, Indiana. Destec owned
and
operated the gasification facility, and PSI Energy owned and operated
the
power generation facility. In 1997, Houston-based Dynegy, Inc.
purchased
Destec. A final transfer took place last December when Global
Energy, Inc.
purchased Dynegy's gasification assets and technology. PSI Energy
remains
the owner and operator of the generating facility.
The project is located at PSI's
Wabash River Generating Station
near West Terre Haute, Indiana.
PSI repowered a 1950s vintage steam
turbine and installed a new syngas-
fired combustion turbine while con-
tinuing to utilize locally mined
high-sulfur Indiana bituminous coal.
The repowered steam turbine pro-
duces 104 MWe that combines with
the combustion turbine generator's
192 MWe and the system's auxiliary
load of 34 MWe to yield 262 MWe
(net) to the PSI grid.
G
ASIFICATION
P
ROCESS
The Wabash Project features the
integration of the E-GAS process
with an advanced General Electric
MS 7001 FA high-temperature gas
turbine. The E-GAS process fea-
tures an oxygen-blown, two-stage
entrained flow gasifier capable of
operating on both coal and petroleum
coke, with continuous slag removal.
As illustrated in the schematic,
syngas is generated from gasifica-
tion of a coal/water slurry with 95
percent oxygen in a reducing atmo-
sphere at 2,600
o
F and pressure of
400 psig. The syngas produced from
coal comprises 45.3 percent carbon
monoxide, 34.4 percent hydrogen,
15.8 percent carbon dioxide, 1.9 per-
cent methane, and 1.9 percent nitro-
gen, and has a higher heating value of
277 Btu per standard cubic foot (dry
basis). The ash melts and flows out
of the bottom of the vessel as a
vitrified slag (frit) by-product. Addi-
tional coal/water slurry added to the
second gasification stage undergoes
devolatilization, pyrolysis, and partial
gasification to cool the raw gas and
increase its heating value. The syngas
flows to a heat recovery unit, produc-
ing high-pressure saturated steam
that is superheated and used to drive
a steam turbine. Subsequently, the
particulates (char) in the raw gas are
removed with a hot/dry candle filter
and recycled to the gasifier where
the remaining carbon is converted
to syngas. After particulate removal,
the syngas is water-scrubbed for
chloride removal and passed through
a catalyst that hydrolyzes carbonyl
sulfide to hydrogen sulfide. The hy-
drogen sulfide is removed using
methyldiethanolamine absorber/strip-
per columns. The syngas is then
burned in a gas turbine that produces
electricity. Gas turbine exhaust heat
is recovered in a heat recovery steam
generator to produce steam that
drives the steam turbine to produce
more electricity.
Over its four years of operation,
the plant has demonstrated an im-
pressive record of continually in-
creasing reliability and syngas pro-
duction, with 2.7 x 10
12
Btu in 1996,
6.2 x 10
12
Btu in 1997, and 8.8 x 10
12
Btu in 1998. Overall, plant availabil-
ity has increased from 56 percent in
1997 to 72 percent in 1998 and 79
percent in 1999. Thermal efficiency
(HHV) is 39.7 percent on coal and
40.2 percent on petroleum coke com-
pared to the 3335 percent figure for
conventional pulverized coal-fired
plants. The greater the thermal effi-
ciency, the less coal is needed to
generate a given amount of electric-
ity, thereby reducing both fuel costs
and carbon dioxide emissions.
Emissions from Wabash River's
IGCC facility are 0.1 pounds of SO
2
and 0.15 pounds of NO
x
per million
Btu of coal input. This SO
2
emission
rate is less than one-tenth the emis-
sion limit set for the year 2000 by the
acid rain provisions of the Clean Air
Act Amendments of 1990.
Fuel cell subcontract approved
for Kentucky Pioneer IGCC
Project.
DOE has reviewed and
approved the subcontract between
Fuel Cell Energy (FCE) and Ken-
tucky Pioneer L.L.C. FCE is plan-
ning to build and operate a 2-MWe
molten carbonate fuel cell (MCFC)
on a slipstream of clean syngas from
the 400-MWe plant. FCE will scale
up the design of their module from an
existing 250-kW test facility. The
FCE activity will cost about $34 mil-
lion, of which DOE will fund 50
percent. The IGCC project is planned
for an existing power plant site in
eastern Kentucky and is currently in
the design and permitting stage.
When completed, this will be the
largest commercial-scale IGCC and
MCFC facility to operate on coal-
derived syngas.
================================================
presented in Table 3-2 suggest that the chemical
composition of blast furnace slags produced in North America has remained
relatively consistent over the years.
presented in Table 3-2 suggest that the chemical
composition of blast furnace slags produced in North America has remained
relatively consistent over the years.
vitrified slags react to form cementitious
hydration products. The magnitude of these cementitious reactions depends
on the chemical composition, glass content,
and fineness of the slag. The chemical reaction
between GGBFS and water is slow, but it is greatly enhanced by the presence
of calcium hydroxide, alkalies and
gypsum (CaSO4).
Percent
1949a.
1957a.
1968a.
1985a.
Mean
Range
Mean
Range
Mean
Range
Mean
Range
Calcium Oxide (CaO)
41
34-48
41
31-47
39
32-44
39
34-43
Silicon Dioxide (SiO2)
36
31-45
36
31-44
36
32-40
36
27-38
Aluminum Oxide (Al2O3)
13
10-17
13
8-18
12
8-20
10
7-12
Magnesium Oxide (MgO)
7
1-15
7
2-16
11
2-19
12
7-15
Iron
(FeO or Fe2O3)
0.5
0.1-1.0
0.5
0.2-0.9
0.4
0.2-0.9
0.5
0.2-1.6
Manganese Oxide
(MnO)
0.8
0.1-1.4
0.8
0.2-2.3
0.5
0.2-2.0
0.44
0.15-0.76
Sulfur
(S)
1.5
0.9-2.3
1.6
0.7-2.3
1.4
0.6-2.3
1.4
1.0-1.9
a. Data source
is the National Slag Association data: 1949 (22 sources); 1957 (29 sources);
1968 (30 sources) and 1985 (18 sources).
hydrated lime to produce a blended cement
(during the cement production process) or by adding the slag to Portland
cement concrete as a mineral admixture.
(1 to 2 percent), the leachate tends to be
slightly alkaline and does not present a corrosion risk to steel in pilings(10)
or to steel embedded in concrete made with
blast furnace slag cement or aggregates.(11)
to be associated with the presence of stagnant
or slow moving water that has come in contact with the slag. The stagnant
water generally exhibits high
concentrations of calcium and sulfide, with
a pH as high as 12.5.(12) When this yellow leachate is exposed to oxygen,
the sulfides present react with oxygen to
precipitate white/yellow elemental sulfur
and produce calcium thiosulfate, which is a clear solution. (See references
13,14,15,16,17,18,19.) Aging of blast furnace
slag can delay the formation of yellow leachate
in poor drainage conditions but does not appear to be a preventative measure,
since the discolored leachate can still
form if stagnant water is left in contact
with the slag for an extended period.(12)
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