Report of the
Hearing Panel
National Public Hearings January 1974
on Power Plant
Compliance
with Sulfur Oxide
Air Pollution Regulations
U.S. ENVIRONMENTAL PROTECTION AGENCY • WASHINGTON, D.C. 20460
-------
UNITED STATES ENVIRONMENTAL PROTECTION AGENCY
WASHINGTON. DC 20460
January 22, 1974
OFFICE OF THE
ADMINISTRATOR
Honorable Russell E. Train
Administrator
U. S. Environmental Protection Agency
U01 M Street, S.W.
Washington, D. C. 20U60
Dear Mr. Train:
From October 18 to November 2, 1973, the Environmental Protection
Agency held a special public hearing in the Washington, D. C. area to
review the status of power plant compliance with sulfur oxide (SOX)
air pollution emission limitations. This hearing was called because
power plants are the largest source of SOX emissions in the U.S.,
because large numbers of power plants are not yet in compliance with
SOX emission limitations, and because, in most cases, only 1 1/2 years
remain under the established implementation plans for these plants to
achieve compliance.
The attached report represents the consensus of the EPA officials
who comprised the hearing panel and presents our findings and recommen-
dations. Principal among these findings are the following:
- Flue gas desulfurization (FGD) technology must be installed
on large numbers of power plants if SOX emission requirements
adopted pursuant to the Clean Air Act are to be met in the
1970's. Supplies of low-sulfur fuels are now and will continue
to be inadequate to provide the sole means of complying with
SOX emission limitations.
- Many established SOX emission limitations will not be met by
the mid-1975 compliance date of most State implementation plans
and will not be met at all unless the electric utility industry
makes the necessary commitments to install FGD systems where
needed.
- With several noteworthy exceptions, the electric utility indus-
try has not aggressively sought out solutions to the problems
they argue exist with FGD technology.
-------
- Although most utility witnesses testified that FGD technology
was unreliable, that it created difficult sludge disposal
problems, and that it cost too much, the hearing panel finds,
on the basis of utility and FGD vendor testimony, that the
alleged problems can be, and have been, solved at a reasonable
cost. The reliability of both throwaway-product and saleable-
product FGD systems has been sufficiently demonstrated on full
scale units to warrant widespread commitments to FGD systems
for SOX control at coal- and oil-fired power plants.
- The utility industry has generally lacked a real incentive to
develop FGD technology and to install this technology where
needed to meet SOX emission requirements.
These findings are based on oral and written testimony received
during the hearing. Witnesses included some 20 utilities, 5 trade asso-
ciations, 8 State agencies, 11 vendors of pollution control equipment,
and 5 environmental or public interest groups. A full transcript of the
testimony at this hearing is available to the public in EPA's Public
Affairs Office, U01 M Street, S.W., Washington, D. C.
EPA officials forming the principal hearing panel were Dr. Robert
Sansom, Assistant Administrator for Air and Water Programs; Dr. John
Burchard, Director of the Control Systems Laboratory; Dr. Bernard
Steigerwald, Director of the Office of Air Quality Planning and
Standards; Mr. Richard Wilson, Director of the Division of Stationary
Source Enforcement; and myself. Representatives from EPA regional offices
also participated on the panel during portions of the hearing.
The hearing panel recommends that the electric utility industry make
immediate commitments to install FGD systems where needed to meet SOX
emission requirements and that EPA and the States create an incentive for
this commitment by establishing expeditious but reasonable compliance
schedules and by vigorously enforcing these schedules.
Respectfully submitted,
R. Quarles, Jr.
Chairman of the Hearing Panel
Deputy Administrator, EPA
-------
Report of the Hearing Panel
National Public Hearings
on
Power Plant Compliance
with
Sulfur Oxide Air Pollution Regulations
Conducted
October 18, 1973 through November 2, 1973
by the
United States Environmental Protection Agency
Submitted to the Administrator
U.S. Environmental Protection Agency
by the
Members of the Hearing Panel
January 1974
-------
TABLE OF CONTENTS
LIST OF TABLES ii
LIST OF FIGURES Ill
1. SUMMARY AND RECOMMENDATIONS 1
Background 1
Findings 2
Recommendations 9
2. BACKGROUND 11
3. UTILITY COMPLIANCE EFFORTS 19
4. STATUS OF FLUE GAS DESULFURIZATION TECHNOLOGY 31
Lime/Limestone FGD Technology 31
WeiIman-Lord Sodium-Based Scrubbing 38
Technology Summary 40
5. VENDOR GUARANTEES 43
6. FLUE GAS DESULFURIZATION SYSTEM MALFUNCTIONS 47
7. WASTE DISPOSAL 51
8. COSTS OF FLUE GAS DESULFURIZATION SYSTEMS 55
9. TIME REQUIREMENTS FOR INSTALLATION OF FLUE GAS
DESULFURIZATION SYSTEMS • 63
10. CAPACITY OF VENDORS TO INSTALL FLUE GAS DESULFURIZATION SYSTEMS. ... 67
APPENDIX A 71
APPENDIX B 87
APPENDIX C 99
11
-------
LIST OF TABLES
3-1. FLUE GAS DESULFURIZATION STATISTICS, SEPTEMBER 1973 20
3-2. PLANNED AND OPERATING FLUE GAS DESULFURIZATION UNITS
ON U.S. POWER PLANTS, SEPTEMBER 1973 21
3-3. COMPARATIVE COST FIGURES FOR PRIVATELY OWNED ELECTRIC UTILITIES . 26
4-1. PGD OPERATING PROBLEMS AND THEIR RESOLUTIONS AT
VARIOUS PLANTS 35
5-1. USUAL BUSINESS PRACTICES 44
8-1. CAPITAL AND ANNUAL COSTS FOR FGD SYSTEMS 58
9-1. TIME REQUIRED TO INSTALL PGD SYSTEMS 65
LIST OF FIGURES
2-1. CUMULATIVE NEED: FGD FOR COAL-FIRED POWER PLANTS 16
10-1. CUMULATIVE NEED AND VENDOR CAPACITY FOR FGD SYSTEMS 69
A-l. MAJOR PROCESS VARIATIONS FOR USE OF LIME OR LIMESTONE
FOR REMOVAL OF S02 FROM STACK GAS 73
A-2. DOUBLE ALKALI PROCESS VARIATION - SODIUM SCRUBBING WITH
LIME REGENERATION 76
A-3. MgO SLURRY PROCESS - FOR FLUE GAS FREE OF PARTICULATE MATTER. . . 78
A-4. WELLMAN-LORD PROCESS SCHEMATIC 81
A-5. REHEAT CAT-OX PROCESS 84
111
-------
1. Summary and Recommendations
Background
Excess quantities of sulfur oxides (SOX) seriously affect
human health through increased incidences of respiratory disease and
damage many types of materials. Congress amended the Clean Air Act in
1970 to establish strict requirements and timetables to clean the air.
Where health-related standards were involved, cost and difficulty of
control were not to be issues in establishing the standards or the
compliance schedules to meet them.
As required by the Act, EPA promulgated primary (health-related)
and secondary (welfare-related) ambient air quality standards in April
1971 for a number of air pollutants, including sulfur oxides. By mid-
1972 the States had adopted and EPA had approved implementation plans that
established emission requirements for most sources that needed to be con-
trolled to meet the ambient air quality standards. Power plants emitted
over 17 million tons or nearly 60 percent of the total SOX in 1972 and
were therefore included among the sources needing control.
The Act required that emission limitations related to attainment
of primary standards be met as quickly as possible, and no later than mid-
1975- However, where strict criteria were met, limited extensions were
provided by the statute. Congress intended that achievement of primary
ambient air quality standards receive priority over achievement of more
stringent requirements. EPA has urged that States review their implemen-
tation plans to assure that they adequately reflect this priority.
There are about 970 fossil-fueled power plants in the U. S. today
having a combined generating capacity of about 302,000 megawatts. Of this
capacity, roughly 55 percent (l66,000 megawatts) are coal-fired, 17 percent
(51,000 megawatts) are oil-fired, and 28 percent (85,000 megawatts) are
gas-fired. All gas-fired plants are obviously now in compliance with
sulfur oxide emission requirements. Some of the coal- and oil-fired plants
were in compliance with sulfur oxide emission requirements when the require-
ments were adopted and many other plants have been or are now being brought
into compliance by converting to fuels having lower sulfur contents.
Switching to a low-sulfur fuel would seem to be the simplest
route to compliance with SOX emission requirements. Coal washing and/or
limited blending of present fuels with lower sulfur fuels is often suffi-
cient, and in such cases, total conversion to a lower sulfur fuel would not
be required. However, supplies of low-sulfur fuels are limited and will not
be sufficient to permit all noncomplying power plants to meet the emission
requirements. Furthermore, use of low-sulfur western coal by plants east
of the Mississippi River would result in a failure to use readily available
high-sulfur eastern coal during a fuel supply crisis. The energy crisis
will aggravate the existing shortage of low-sulfur fuels. Since supplies
of low-sulfur fuels will be insufficient, flue gas desulfurization (FGD)
systems will be required on a large number of power plants in order to
-------
achieve compliance with SOX emission limitations. Use of FGD systems
will enable power plants to meet emission requirements while using
important high-sulfur fuel resources.
Many utilities have suggested that, rather than meet existing
SOX emission requirements, they be allowed to use tall stacks and inter-
mittent control systems to achieve ambient air quality standards. Such
techniques rely upon the dispersion of pollutants instead of the constant
reduction of pollutant emissions. EPA considers constant emission reduction
techniques, such as FGD, far superior to dispersion techniques and has
proposed regulations that limit the use of such dispersion techniques to
situations where constant emission reduction controls are not available.
Dispersion techniques can, however, often be appropriately required as
interim steps (to minimize the impact of plant operation on air quality)
in schedules requiring compliance with emission limitations.
It is difficult to estimate the magnitude of the need for FGD
systems since this need depends on the present and future availability
of low-sulfur coal and oil, the number of oil-fired plants that will
switch to coal, and the extent to which supplies of low-sulfur fuels
can be redistributed to areas where they are most needed. EPA's best
current estimate of the need through 1980 for FGD systems to allow coal-
fired power plants to meet primary ambient air quality standards and new
source performance standards is that some 90,000 megawatts of FGD control
will be necessa. /. This represents an application of FGD control to about
30 percent of the total projected national coal-fired generating capacity
in I960. Additional long range FGD requirements will, of course, include
systems for oil-fired plants, systems for plants to meet State emission
limitations designed to improve and maintain air quality below primary
standards, and systems for other sources such as large industrial boilers.
This report assesses the oral and written testimony received dur-
ing the public hearing on the status of power plant compliance. Witnesses
included representatives of some 20 utilities, 5 trade associations, 8
State agencies, 11 vendors of pollution control equipment, and 5 environ-
mental or public interest groups. These witnesses are listed by affiliation
in Appendix C. Principal findings and recommendations are summarized
below.
Findings
1. Flue gas desulfurization (FGD) technology must be installed
on a large number of power plants if sulfur oxide (SOX)
emission requirements adopted purusant to the Clean Air Act
are to be met in the 1970's.
-------
(a) there was general agreement from witnesses at the
hearing that low-sulfur fuel supplies are now and
will continue to be inadequate to provide the sole
means of complying with SOX emission limitations.
(b) witnesses generally agreed that technologies such
as coal gasification and liquefaction to take sul-
fur from coal will not be available until the 1980's
and that therefore FGD represents the only technology
that will be available within the next several years
to control SOX.
(c) witnesses generally agreed that FGD systems, when
operating properly, can reduce SOx emissions by 85
to 9Q% (sufficient to meet most, if not all, emis-
sion requirements).
(d) the continued use of available high-sulfur coal
combined with FGD control is especially important
given our present energy crisis.
Many established SOX emission limitations will not be met
by the mid-1975 compliance date of most State implementation
plans and will not be met at all unless the electric utility
industry makes the necessary comnitments to install FGD
systems where needed.
(a) only a few utility witnesses testified that their
companies have compliance programs to install FGD
systems at plants for which low-sulfur fuels will not
be available. To date only UU FGD units controlling
about 18,000 megawatts of generating capacity have
been installed or committed to by utilities in the
U. S.
(b) while the time required to design and install an FGD
system on an existing plant varies with the size and
retrofit characteristics of the plant, testimony at
the hearing suggested that typical design and instal-
lation times will run from 27 to 36 months. This time
requirement is obviously longer than the 18 months left
before 'the mid-1975 compliance date of most State
Implementation Plans. For those installations where a
modular approach is warranted, typical design and
installation times will run from Ul to 5^ months.
-------
(c) a number of witnesses testified to the capacity of
vendors of FGD systems to provide these systems.
While it is clear that vendor capacity now exceeds
orders for FGD systems, it is also clear that excess
capacity is not now as great as the need for FGD
systems; hence, vendor capacity will tend to constrain
the speed at which systems can be installed.
3. With several noteworthy exceptions, the electric utility
industry has not aggressively sought out solutions to the
problems they argue exist with FGD technology.
(a) while a few utilities, generally the smaller ones, testi-
fied that they had aggressive programs to solve alleged
problems with FGD technology, most utilities seem con-
tent to raise the problems and wait for other utilities
to solve them. Only 22 of the some 300 utilities
operating fossil-fueled plants in this country have
installed or have made a commitment to install at least
one full scale FGD system.
(b) utility industry research and development efforts in
general are limited and in 1972 amounted to less than
1 percent of industry revenues. Work on FGD technology
is only a smn.ll but undetermined portion of this effort.
(c) the testimony of some utilities indicates that they
have applied greater efforts to defending their lack
of progress or to attempting to change existing emis-
sion requirements than they have in controlling their
SOX emission through FGD technology.
(d) while testimony at the hearing indicated that the con-
trol of the chemistry of FGD systems is critical to
reliable operation, few utilities testified that they
have hired personnel skilled in such chemical operations.
(e) testimony from several utilities indicated that they
are not aggressively following the work of those com-
panies in the U. S. and Japan that have installed full
scale FGD' systems. This lack of active monitoring
makes a 'wait and see* attitude less defensible.
k. Although most utility witnesses testified that FGD technology
was unreliable, that it created difficult sludge disposal
problems, and that it cost too much, the hearing panel finds,
-------
on the basis of utility and FGD vendor testimony, that the
alleged problems can be, and have been, solved at a reasonable
cost. The reliability of both throwaway and saleable product
FGD systems has been sufficiently demonstrated on full-scale
units to warrant widespread commitments to FGD systems for
SOX control at coal- and oil-fired power plants.
(a) although some FGD installations in the U. S. have
encountered reliability problems (primarily scaling,
plugging, erosion, or corrosion), the panel finds that
each of these problems can be solved through careful
system design and proper control of system chemistry.
Testimony at the hearing by utility and vendor witnesses
revealed that all of the above problems have been solved
at one or more full scale FGD installation in this
country or Japan.
In reaching this conclusion the panel recognizes that
operating parameters vary somewhat from plant to plant
and that minor modifications of the basic FGD design
will be required to optimize FGD operation on individual
power plants. Operating experience at the following
facilities is considered particularly important:
(l) Chemico Mitsui Miike Lime Scrubber - This unit has
operated with near 100 percent reliability control-
ling a 156-megawatt coal-fired boiler near Omutu,
Japan since its startup in March 1972. The panel
finds that this unit has established that hydrated
lime (calcium hydroxide) systems, operating generally
in a closed-loop mode and occasionally subjected
to varying loads, can operate for periods exceeding
1 year with no scaling, plugging, erosion, corrosion,
or other significant operating problems.
(2) Louisville Gas & Electric's Paddy's Run Lime
Scrubber - This unit has operated with good relia-
bility since its startup in April 1973 and has
reinforced the finding that closed-loop hydrated
lime systems can operate reliably with proper
chemistry control. This unit is particularly
significant because pH control has been successful
to date in achieving good operability despite wide
variations in S02 inlet concentration and boiler
loads.
-------
(3) Japan Synthetic Rubber's Chiba Wellman-Lord
System - This 70-megawatt facility, which produces
high-quality concentrated sulfuric acid as the by-
product, has operated with greater than 95 percent
availability to the oil-fired boiler during over
2 years of operation. The panel believes that
when efficient particulate removal equipment is
installed upstream of the SOX scrubbers, Wellman-
Lord systems can operate reliably for extended
periods of time on coal-fired boilers.
("b) the panel finds that the following commercially available
FGD process/application combinations can be installed
with the expectation of successful operability and relia-
bility, in approximate order of confidence:
FGD System Power Plant By-Product
Wellman-Lord Oil Sulfuric acid
Lime scrubbing Coal or Oil Throwaway
Wellman-Lord Coal Sulfuric acid
Limestone scrubbing Coal or Oil Throwaway
A number of other FGD process/applications, such as
magnesium oxide scrubbing (oil or coal), catalytic
oxidation (oil or coal), Wellman-Lord (producing sulfur),
and UOP/Shell (oil or coal), are not as fully demon-
strated as the previously listed systems, and are expected
to be demonstrated for full scale installations in the
near future. Commitments can be made at the present
time with good confidence that some of these systems
will achieve a high degree of SOX removal with acceptable
reliability.
(c) the disposal of sludges produced by some types of FGD
systems was cited throughout the hearing as a potential
problem, and water pollution and land deterioration
were named as two environmental complications. However,
during the hearing, technology was described that can
reclaim sludges for use as landfill at the many landfill
sites available. In those cases where landfill is not
economically practical due to a lack of available sites,
regenerable-product or saleable-product FGD systems
that do not produce throwaway sludges can be used.
Fuel switching is also possible in such cases.
-------
(d) the costs of installing FGD systems will vary depending
upon many factors such as the type of power plant, space
requirements, und the degree of control required. The
panel finds that these costs, whiK1 substantial, arc
reasonable and will not impose an undue burden on either
the electric utility industry or its customers.
(l) the hearing panel finds that the typical capital
cost to install FGD on an existing plant will most
commonly range from $50 to $65 per kilowatt of
plant capacity. Capital requirements for the
purchase of FGD equipment are estimated to be about
$5-1* billion through I960 to meet primary and new
source performance standards, an increase of about
U percent above expected power industry capital
requirements without scrubbing.
(2) annual costs for operating FGD systems involve an
annual!zation of capital costs plus such operating
costs as those for waste disposal and for additional
power to run the FGD system. The panel believes
that the typical annual operating cost will range
from 2 to U mills/kw-hr of power generated. The
impact of this increased operating cost on consumers
of electricity will vary depending upon the number
of plants a given utility must control, and could
result in a price increase of from 15 to 20 percent
where control of most plants is required. Nationally,
however, only about 30 percent of the projected
coal-fired generating capacity will need FGD systems
through 1980 to meet primary and new source perfor-
mance standards; this can be expected to result in
an average consumer cost increase of only about 3
percent.
(3) the increased electricity required to power an FGD
system typically amounts to h to 7 percent of a
plant's generating capacity. Based on EPA's esti-
mate of the number of plants that will require
FGD systems to attain primary standards, FGD
installations will increase the national demand
for electricity by only 1 percent through I960.
(U) the cost of scrubbing may be prohibitive for plants
with insufficient space or for older plants that
will be retired shortly. Such plants should receive
priority for available low-sulfur fuels.
-------
(e) during the hearing, some utilities claimed that they
should not be required to install FGD systems because
they were unable to obtain lifetime reliability guaran-
tees from vendors. Vendors have made substantial commit-
ments to the development of FGD technology and generally
offer guarantees for these systems that are comparable
to the guarantees provided for other equipment purchased
by a utility. No vendor is willing to assume all risks
during the lifetime of the scrubber by guaranteeing its
reliable operation at all times largely because the
vendor rarely has control over the operation and mainte-
nance of the system after the initial performance test.
It is understandable that the utility industry is anxious
to avoid risks, but the panel finds that guarantees now
offered by vendors are appropriate and that the utility
creating the pollution must assume the remaining risks
associated with control of that pollution.
5. The utility industry has generally lacked a real incentive
to develop FGD technology and to install this technology where
needed to meet SOX emission requirements.
(a) since FGD systems, unlike improved boiler designs, for
example, do not result in more efficient generation of
electricity, utilities do not have a profit incentive
to develop and install these systems.
(b) vigorous enforcement of State SOX emission requirements
has not taken place in many cases, apparently as a
result of the debate over whether FGD technology is
sufficiently developed.
(c) while a number of State public utility commissions
allow an automatic pass through (rate increase) of
increased costs resulting from switching to a low-
sulfur fuel, similar automatic pass throughs are not
generally allowed for increased costs resulting from
the installation of FGD systems. This tends to bias
the industry toward fuel switching as a compliance
mechanism.
(d) during the hearing many utility witnesses claimed that,
because FGD technology is new, malfunctions of the FGD
system would occur and would cause non-compliance.
Although bypasses can be Installed to prevent plant
shutdown during malfunctions and although installation
of control system redundancy and use of proper operating
8
-------
and maintenance procedures should reduce the occurrence
of breakdowns, malfunctions will still occur that cause
emissions to exceed the emission standards. Many States
do not specifically provide for unpreventable malfunc-
tions in their regulations, but use enforcement discre-
tion to deal with such occurrences. Most power companies
feel that more formal procedures should be developed;
the hearing panel agrees.
R ec omme ndat i on s
On the basis of oral and written testimony presented during
the hearing, the hearing panel recommends that:
1. The electric utility industry should:
(a) make immediate commitments to install FGD systems
where needed to meet SOX emission requirements, giving
priority to those sources where controls are needed to
meet primary ambient air quality standards and new
source performance standards
(b) aggressively pursue FGD developmental programs to
improve reliability, to lower operating costs and to
advance FGD technology that results in a saleable by-
product
(c) undertake further characterization and evaluation
efforts on sludge disposal, with emphasis on large
scale systems, to assure the widespread applicability
and effectiveness of sludge disposal systems at reason-
able costs
(d) hire (and train) personnel with the skills needed to
properly design and operate FGD systems
2. EPA and the States should:
(a) create a strong incentive for the installation of
FGD systems by establishing expeditious but reason-
able compliance schedules and by vigorously enforcing
these schedules
(b) formalize procedures for dealing with unpreventable
control system malfunction where such formal procedures
do not already exist
-------
(c) urge State public utility commissions to treat in-
creased costs from FGD control in the same manner as
increased fuel costs are treated
(d) consider such other methods of creating an incentive
to control SOX emissions as the Administration's pro-
prosed charge (tax) on SOx emissions.
3. Compliance schedules established by the utilities, States,
and EPA should:
(a) be developed for each utility after considering the
number and types of plants requiring FGD systems and
the need to properly sequence installations to preserve
utility power reserves
(b) give priority to installation of FGD systems at those
plants where systems are needed to meet primary ambient
air quality standards and new source performance
standards
(c) require installation of FGD systems at a rate commensu-
rate with vendor capacity
(d) require, where feasible, the use of interim control
measures such as intermittent control systems in order
to minimize the impact of SOX emissions on air quality
until FGD systems can be installed
10
-------
2. Background
Sulfur oxides are a major air pollution problem. Excessive
quantities of this pollutant seriously affect human health through
increased incidences of respiratory disease. Other adverse affects,
such as increased metal corrosion and vegetation damage, are also
caused by sulfur oxides.
The Clean Air Act, as amended in 1970 by the Congress, estab-
lishes strict requirements and timetables to clean our nation's air.
The requirements of the Act demonstrated Congress' conviction that
air pollution cannot be permitted to continue to menace the public
health and welfare. Where health-related standards were involved,
cost and difficulty of control were not to be issues in establishing
the standards or the compliance schedules to meet them.
The Act required EPA to establish ambient air quality standards
for significant air pollutants. These ambient standards were to be
set at levels that would protect the public health and welfare from
the adverse effects of air pollutants. In April of 1971, EPA promul-
gated primary (health-related) and secondary (welfare-related) ambient
air quality standards for a number of air pollutants including sulfur
oxides (SO ).
Ji
Power plants are the major source of SOX emissions in this
country. In 1972 over 17 million tons of SOX was emitted into our
nation's air by power plants. These emissions accounted for nearly
60 percent of the total sulfur oxide emissions that year. Coal-fired
power plants, by far the largest source, emitted nearly l6 million
tons of SOX, accounting for over 50 percent of the total SOX emissions
in 1972.
Emissions from power plants have been increasing each year
along with our nation's demand for additional electric power. Total
SOX emissions from coal-fired power plants have increased from 10
million tons in 1963 to 16 million tons in 1972, and can be expected
to continue to increase unless these emissions are controlled.
The impact of power plants on air quality varies across the
country. In some areas the impact of power plants is relatively slight,
but in other areas power plants alone cause primary standards to be
exceeded. Use of high-sulfur coal, for example, is predominant in
our East-Central States where such coal is mined. The detrimental
impact of power plants on air quality in these States is substantial,
especially when these States are compared to those where gas or low-
sulfur oil is used as a fuel.
The Clean Air Act gave the States 9 months from the time EPA
established ambient air quality standards to develop implementation
plans containing emissions limitations sufficiently stringent to
achieve the ambient standards. Each plan was tailored to the needs of the
11
-------
State. Public hearings were held in each case. The plans were sub-
mitted to EPA early in 1972 and EPA approved or revised these plans
by the middle of 1972. At that point, a year and a half ago, most
major sources that needed to be controlled, including power plants,
were subject to an emission limit enforceable by stringent civil and
criminal penalties.
The Clean Air Act requires that schedules for compliance with
these emission limits be established to ensure that the health-
related ambient standards are met as quickly as possible, but not
later than 3 years from the date of plan approval — which is the
middle of 1975. Limited extensions are provided for by the statute
but only where strict criteria are met.
There are two general options which power plants have to
achieve compliance with SOX emission limitations. Sulfur oxide gases
can be removed after combustion with flue gas desulfurization (FGD)
systems, or emissions from the combustion process can be reduced by
burning low-sulfur fuels. The latter option has been more commonly
chosen since it is often the simplest route to compliance. A number
of utility companies with coal-fired plants requiring significant
reductions • meet applicable emission limitations have recently accel
erated purchases of coal naturally low in sulfur content, principally
from western states. Western coal cannot, however, be used by many
power plants because of its heat and ash characteristics. For plants
where only moderate emission reductions are necessary, reduction of
sulfur content by coal washing or by blending of present fuels with
lower sulfur fuels may be sufficient to achieve compliance.
Unfortunately, the amount of low-sulfur coal available now
and the amount that will be available in the 1975-1980 time frame
will not be sufficient to permit all plants out of compliance to meet
the SOX emission limitations included in State implementation plans.1»
In addition, transporting large quantities of low-sulfur western coal
to eastern plants would be expensive and would result in a failure
to use readily available high-sulfur eastern coal reserves.
The current energy crisis will aggravate the existing shortage
of low-sulfur fuels. A number of power plants now burning oil are
expected to switch to coal soon and some oil-fired plants will no
Economic Impact Analysis of State Implementation Plan Regula-
tions on Fuels and Energy Related Industries, Stephen Sabotka
and Co., New York, NY, EPA Contract no. 68-01-0565, October 1972.
^Impact of State Implementation Plans of Fossil Fuels Avail-
ability and Requirements, MITRE Corporation, McLean, Va., EPA
Contract no. 60-U2-U2U6, August, 1972.
12
-------
longer "be able to obtain low-sulfur oil. The general shortage
of low-sulfur fuels and the overall shortage of oil emphasizes this
country's need to find an environmentally acceptable way of using
our high-sulfur fuel resources.
Plants equipped with FGD systems can use high-sulfur fuels
and still have emission levels equal to or even less than those re-
sulting from the burning of low-sulfur fuels. With a substantial
increase in the use of FGD systems, primary ambient air quality stand-
ards can be achieved in this decade.
Many existing State emission requirements are not tailored
to give priority to controlling those sources that need to be control-
led to achieve primary air quality standards. Shortages of low-sulfur
fuels and the limited capacity of vendors to install FGD systems (dis-
cussed later in this report) make it especially important that appro-
priate priorities be established. EPA has urged a number of States
to review their implementation plans and revise them to give priority
to achieving primary ambient air quality standards.
Many utilities have suggested that tall stacks and other
supplementary control systems, rather than equipment required to meet
constant emission requirements, be allowed as a mechanism to achieve
ambient air quality standards. Such supplementary control systems
rely on the dispersion of pollutants rather than the constant reduction
of pollutants. EPA considers constant emission reduction techniques
such as flue gas desulfurization far superior to supplementary control
systems. EPA proposed regulations in September 1973^ that would limit
the use of supplementary control systems to those situations where
constant emission reduction techniques are not available and the only
alternative is to shutdown the facility. Some forms of dispersion
to reduce the impact of SOX emissions on air quality may, however,
be appropriate as interim measures for plants on schedules to achieve
compliance through the use of constant emission controls.
There are about 970 fossil fuel steam-electric plants operating
in the United States, with a total generating capacity of about 302,000
megawatts (1972 figures). Of this capacity, roughly 55/£ or 166,000
megawatts are coal-fired, 11% or 51jOOO megawatts are oil-fired, and
28% or 85,000 megawatts are gas-fired. Because SOX emissions from
the burning of natural gas are negligible, gas-fired plants were not
considered in this hearing.
Many of the oil- and coal-fired plants were already in com-
pliance with applicable sulfur oxide emission limitations before State
implementation plans were developed. These plants had either under-
taken control efforts, such as purchasing low-sulfur fuels, or were
federal Register, Vol. 38, September lit, 1973, p. 25697.
^Steam-Electric Plant Factors. 1972 edition, National Coal
Association, Washington, D.C.
13
-------
in areas where the sulfur dioxide ambient levels vere not severe
enough to warrant stringent emission limitations. Since the time
when the implementation plans were approved, a number of additional
plants have come or are coining into compliance by converting to fuels
having lower sulfur contents and in some cases by installing FGD
systems.
For the remaining noncomplying plants, EPA has attempted to
determine the amount of flue gas desulfurization that will be needed
nationally to assure timely attainment and maintenance of primary
ambient air quality standards. This analysis was performed by looking
at the need through 1980 for FGD on new and existing coal-fired plants
and for oil-fired plants expected to switch to coal. Due to the un-
certainties in the oil supply situation, it is not possible to analyze
the need to retrofit existing oil-fired plants with FGD systems.
The details and results of the analysis are discussed below.
To quantify the need for FGD for existing coal-fired plants,
EPA used diffusion modeling techniques to determine how many of these
plants have an impact on attainment of the primary standards. The
projected growth of U.S. coal-fired capacity from the 1972 level of
166,000 megawatts to 209,000 megawatts in 1975 (EPA estimate) was
taken into account. Of this 209,000 megawatts, some 123,000 megawatts
are not expected to need any emission reductions to achieve primary
standards; 23,000 megawatts are expected to need moderate reductions
through such techniques as washing currently used coal or blending
this coal with low-sulfur coal; and 63,000 megawatts are expected
to need substantial reductions either through the use of low-sulfur
coal or FGD.
EPA estimates that an average of 2U,000 megawatts of new fossil
fuel capacity will come into operation each year after 1975. Of this,
about lU,500 megawatts will be coal-fired. Since many of these plants
will not be able to comply with State emission requirements or Federal
new source performance standards through the use of low-sulfur coal,
they will greatly increase the need for FGD after 1975.
As indicated, a number of plants now using oil are expected
to switch to coal because of oil shortages. Most of these plants
will need to apply FGD systems in order to ensure attainment and main-
tenance of primary standards. The estimated additional scrubber needs
for plants switching from oil to coal were added to the needs calcu-
lated for existing and new coal-fired plants.
Some utilities will be able to obtain low-sulfur coal for
their plants. New supplies of low-sulfur coal will not be significant
between now and 1975; however, limited supplies will be available
after that time. By distributing our reserves and redistributing
our current supplies of low-sulfur coal to the areas where they are
-------
most needed to attain air quality standards, current and projected
supplies could significantly reduce PGD requirements after 1975- For
this reason, estimated new low-sulfur coal supplies were taken into
account in this analysis.
The results of the analysis are displayed in Figure 2-1.
The curves in the figure show the maximum and minimum estimated FGD
needs of those coal-fired power plants that need control for attainment
of primary ambient air quality standards and attainment of EPA's new
source performance standards. These curves include growth in coal-
fired capacity from erection of new plants and expansion of existing
plants, estimates of plants switching from oil to coal, the increase
in supplies of low-sulfur utility coal, and the extent to which coal
will be redistributed in response to SO emission limitations. FGD
needs for oil-fired plants are impossible to estimate at this time
and hence are not included. Inherent in this analysis is the assump-
tion that power plants having an impact on primary standards will
have priority in the distribution of low-sulfur fuels and FGD systems.
The high curve in Figure 2-1 indicates FGD needs if new low-
sulfur coal supplies do not open up as anticipated, and if redistri-
bution of existing supplies is minimal. The low curve represents
optimistic projections of new supplies and extensive redistribution
of currently used low-sulfur coal to areas where stringent emission
reductions are, needed.
Although it is difficult to precisely determine the impact
of the previously cited factors, especially the increased supply and
redistribution of low-sulfur coal, the middle curve in Figure 2-1
represents the most likely demand for FGD systems. As indicated by
this curve, the cumulative need for FGD is about 66,000 megawatts
by the end of 1975, 73,000 megawatts by the end of 1977, and
90,000 megawatts by the end of 1980.
It is important to note that there will be additional demands
for FGD systems which were not included in this analysis. For example,
there will probably be an increasing demand for these systems to con-
trol industrial boilers for which low-sulfur fuels cannot be obtained.
Also, the demand by oil-fired plants was not included in this analysis.
EPA has found that a large number of oil-fired plants have achieved
or until recently were planning to achieve compliance by using low-
sulfur oil. With the uncertain oil situation, however, it is probable
that many of these plants will have to use high-sulfur oil and will
therefore need to install FGD systems to meet emission requirements.
This analysis has focused on plants which have an impact on
primary standards because these plants should receive highest priority
for FGD application and low-sulfur fuels. States have also adopted
15
-------
0)
I
<
e>
1.
CUMULATIVE
F IGU RE 2- 1
NEED: FGD FOR COAL FIRED POWER PLANTS1
125
100
75
50
25 r
0
<
0.
<
u
76
77 78 79
TIME, YEARS
Includes new and existing coal-fired 2. Bas«d on pessimistic pro-
plants requiring controls to achieve
primary standards or new source
performance standards.
jections for new low sulfur
coal supplies and minimal
redistribution of existing
supplies.
81
3. Based on optimistic pro
jections for low sulfur
coal supplies and
maximum redistribution
of existing supplies.
-------
requirements to achieve secondary standards and to ensure that ambient
standards are maintained in the future. These requirements must also
be met and could add substantially to FGD requirements in the later
1970's.
17
-------
3. Utility Compliance Efforts
Approximately half of the time allowed by the Clean Air Act to
achieve compliance with health-related emission standards has now passed,
and the mid-1975 compliance deadlines of most State implementation plans
are only one and one-half years away. Any project to reduce SOX emissions
from a power plant (other than through reducing or halting operations)
requires considerable time from initiation to completion.
In obtaining lower sulfur coals, a utility would spend time search-
ing for the nearest source with the most convenient transportation, testing
the new fuel in the boilers to determine its effect on the efficiency of
combustion (as well as its effect on particulate control device efficiency),
and negotiating a long term commitment from the supplier. Where a new source
of coal is involved, mining operations must be initiated. The total process
can take from several months to several years. As discussed later in this
report, testimony at the hearing indicated that installation of FGD devices
requires approximately 2 to 3 years. There was general agreement from all who
testified that alternative forms of SOX control, such as coal gasification
and coal liquefaction, would not be available before the 1980's.
Obviously the one and one-half years remaining for compliance with
most SOX emission requirements will usually not be sufficient if a utility
has not begun its compliance program. For this reason, one of the objectives
of the hearing panel's questioning was to inquire into the status of uti-
lity compliance efforts.
The 20 electric utilities having witnesses at the hearing were
representative of the U. S. electric utility industry. Testimony was heard
from small utilities (such as Buckeye Power Co. and Kansas City Power and
Light Co.) as well as from the large ones (such as the Tennessee Valley
Authority (TVA), American Electric Power Service Corp. (AEP), and Ohio
Edison Co.).
The utility witnesses generally agreed that supplies of low-sulfur
fuel were insufficient and would remain insufficient for achieving compli-
ance solely through fuel switching. In addition, many utilities expressed
a strong desire, for economic and other reasons, to use locally available
high-sulfur coal. Although PGD systems could bring these plants into
compliance with SOX emission regulations, few utilities testified that they
had plans to install FGD systems where low-sulfur fuel was not available.
On the basis of this testimony, and the time required to install FGD systems,
it is clear that many SOX emission requirements will not be met in a timely
fashion.
19
-------
Table 3-1. FLUE GAS DESULFURIZATION STATISTICS,
SEPTEMBER 19731
Throwaway product
Lime
Limestone
Aqueous Na based
Saleable product
Wellman-Lord
Magnesium oxide
Cat-ox
Dry absorption
Process not selected
Lime/ 1 imestone
No selection
TOTAL
Opera-
tional ,
4
3
-
—
2
1
-
.
—
10
Under con-
struction
6
4
3
1
1
1
.
—
16
Planned
construction
1
2
-
—
-
-
10
5
18
Total ,
11
9
3
1
3
1
1
10
5
44
New
plants
7
4
-
—
-
-
-
4
4
19
Retrofit on
Existing
Plant
4
5
3
1
3
1
1
6
1
25
PROJECTED START-UP DATE
1974 1975 1976
2 8 12
LTranscript. Public Hearing and Conference on Status of Compliance with
Sulfur Oxide Emission Regulations by Power Plants. U.S. Environmental
Protection Agency, 4th & M Sts., SW, Washington, D.C. November 1973,
F. Princiotta, EPA, pp. 42-48.
20
-------
Table 3-2. PLANNED AND OPERATING FLUE GAS DESULFURIZATION UNITS
ON U.S. POWER PLANTS, SEPTEMBER 1973
Lime tone Scrubbing
Utility Company New or
Power Station Retrofit
Comonwealth Edison R
Will County Ho. 1
Kansas City Power & R
Light, Hawthorn No. 4
Kansas City Power & N
Light, LaCygne Sta.
Arizona Public Service R
Cholla Station
Detroit Edison R
St. Clair No. 6
Southern California R
Edison (operating
agent) Mohave Sta.
TVA R
Widow's Creek No. 8
Northern States Power N
Sherburne County No.l
Public Service of N
Indiana , Gibson Sta.
Northern States Power N
Sherburne County No. 2
Size of FGO
Unit (MN)
156
100
820
115
180
160
550
680
650
680
Process
Vendor
B&W
CE
B&W
Research
Cottrell
Peabody
Engineering
UOP
TVA
CE
CE
CE
Fuel and
Sulfur Content
Coal. 3.5Z
Coal, 3.5Z
Coal, 5X
Coal, 0.4 -
l.OZ
Coal, 3.7Z
Coal, 0.5 -
0.8Z
Coal. 3.7Z
Coal. 1Z
Coal. 1.5Z
Coal, 1Z
Status
(Start -Up Date)
Operational
(Feb. 1972)
Operational
(Aug. 1972)
Operational
(June 1973)
Under Construction
(October 1973)
Under Construction
(Dec. 1973)
Under Construction
(March 1974)
Under Construction
(May 1975)
Under Construction
(Hay 1976)
Planned
(1976)
Planned
(Hay 1977)
-------
Table 3-2 (continued). PLANNED AND OPERATING FLUE GAS DESULFURIZATION UNITS
ON U.S. POWER PLANTS, SEPTEMBER 1973
N)
ro
Utility Company New or
Power Station Retrofit
Union Electric Co.
Meraaec No. 2
Kansas Power & Light
Lawrence No. 4
Kansas Power & Light
Lawrence No. 5
Kansas City Power &
Light, Hawthorn No. 3
Louisville Gas &
Electric
Paddy's Run No. 6
Duquesne Light Co.
Phillips Station
Southern California
Edison (operating
agent) Mohave Sta.
Ohio Edison/Mansfield
Sta. (2 units)
Montana Power
Co Is trip No. 1 & 2
Coluabus 6 Southern
Conesville No. 5 & 6
R
R
R
R
R
R
R
N
If
N
Size of FGD
Unit (MM)
140
125
430
100
70
100
160
1650
720
750
Process
Vendor
CE
CE
CE
CE
CB
Chealco
SCB/Steama-
Roger
CheBieo
CEA
HoC Selected
Fuel and
Sulfur Content
Coal. 3Z
Coal. 3.5Z
Coal. 3.5Z
Coal. 3.5Z
Coal. 3Z
Coal. 2Z
Coal. 0.5 -
0.8Z
Coal. 4.3Z
Coal, 0.8Z
Status
(Start -Up Date)
Abandoned
(Sept. 1968)
Operational
(Dec. 1968)
Operational
(Nov. 1971)
Operational
(Nov. 1972)
Operational
(April 1973)
Under Construction
(Nov. 1973)
Under Construction
(Dec. 1973)
Under Construction
(Early 1975)
Under Construction
(May 1975)
Planned
(1976)
-------
Table 3-2 (continued). PLANNED AND OPERATING FLUE GAS DESULFURIZATION UNITS
ON U.S. POWER PLANTS, SEPTEMBER 1973
L/LS Hot Selected
Utility Company New or Size of FGD
Power Station Retrofit Unit
N>
UJ
Sale River Project N 750
Navajo No. 1
Salt River Project N 750
Navajo No. 2
Arizona Public Ser. R 175
Four Corners No. 1
Arizona Public Ser. R 175
Four Corners No. 2
Southern California R 1180
Edison (operating
agent) Mohave No. 1&2
Arizona Public Ser. R 229
Four Corners No. 3
Salt River Project N 750
Navajo No. 3
Arizona Public Ser. R 800
Four Corners No. 4
Arizona Public Ser. R 800
Four Corners No. 5
Process
Vendor
Not selected
Fuel and
Sulfur Content
Coal. 0.5-0.8Z
Not selected Coal, 0.5-0.8Z
Not selected Coal. 0.75Z
Not selected Coal, 0.75Z
Not selected Coal, 0.5-0.8Z
Not selected Coal, 0.75Z
Not selected Coal. 0.5-0.8Z
Not selected Coal, 0.75Z
Hot selected Coal, 0.75Z
Status
(Start-Up Date)
Construction Start,
Nov. 1974 (Mar.'76)
Construction Start,
Oct. 1975 (Oct.'76)
Construction Start,
Oct. 1975 (Oct.'76)
Construction Start,
Nov. 1975 (Dec.'76)
Planned
(Dec. 1976)
Construction Start,
June 1976 (Mar.'77)
Construction Start,
Mar. 1976 (Mar.'77)
Construction Start,
Sept. 1975 (Apr.'77)
Construction Start,
Nov. 1976 (June '77)
-------
Table 3-2 (continued). PLANNED AND OPERATING FLUE GAS DESULFURIZATION UNITS
ON U.S. POWER PLANTS, SEPTEMBER 1973
Kagnealum Oxide Scrubbing
Utility Company
Power Station
Boston Edison
Mystic No. 6
Potomac Electric &
Power
Oickerson No. 3
Philadelphia Electric
Eddys tone No. 1
New or
Retrofit
R
R
R
Size of FGD
Unit (MR)
ISO
100
120
Process
Vendor
Chemico
Chemico
United
Engineers
Fuel and
Sulfur Content
Oil, 2.5Z
Coal, 21
Coal. 2.5Z
Status
(Start -Up Date)
Operational
(April 1972)
Opera cional
(Sept. 1973)
Under Construct:
(Dec. 1973)
fs»
Other 909 Control Syst«
Catalytic Oxidation (Cat-Ox)
Illinois Power Co. R
Wood River No. 4
Wellman-Lord
Northern Indiana R
Public Service,
D.H.Mitchell No.11
110
115
Aqueous Sodium Base Scrubbing, Non-Regen«rable
Nevada Power R 250
Reid Gardner No. 1&2
Nevada Power R 125
Reid Gardner No. 3
Dry Adsorption
Indiana & Michigan R 150
Electric,
Tanner's Creek Station
Monsanto
Coal, 3.2Z
Davy Powergaa/ Coal, 3.5Z
Allied Chemical
CEA
CEA
B&W/Esso
Coal. 0.5
l.OZ
Coal, 0.5
l.OZ
Coal,
Operational
(Oct. 1972)
Under Construction
(Early 1975)
Under Construction
(Dec. 1973)
Under Construction
(1975)
Under Construction
(1974)
-------
Table 3-2 (continued). PLANNED AND OPERATING FLUE GAS DESULFURIZATION UNITS
ON U.S. POWER PLANTS, SEPTEMBER 1973
Process Mot Selected
Utility Company
Power Station
Public Service of
New Mexico
San Juan No. 2
Potomac Electric &
Power
Chalk Point No. 3
Potomac Electric &
Power
Chalk Point No. 4
Potomac Electric &
Power
Dickerson No. 4
Potomac Electric &
Power
Dickerson No. 5
New or
Retrofit
R
Size of FGD
Unit (MW)
100
630
630
800
800
Process
Vendor
Not Selected
Not Selected
Not Selected
Not Selected
Not Selected
Fuel and
Sulfur Content
Coal, 0.8Z
Oil
Oil
Coal, 2Z
Coal, 2%
Status
(Start-Up Pate)
Planned
(Nov. 1974)
Planned
(1975)
Planned
(1976)
Planned
(1976)
Planned
(1977)
-------
Table 3-3. COMPARATIVE COST FIGURES FOR PRIVATELY OWNED
ELECTRIC UTILITIES2
($103)
Total electric
operating revenues
Total research &
development
expenditures
Total R & D - % of
Total operating revenues
for electric utilities
1969
$18,022,904
$41,026
.237.
1970 j
$19,791,066
$46,037
.23%
1971
$22,321,874
$94,390
.427.
1972
$25,354,868
$175,343
.69%
Statistics of Privately Owned Electric Utilities in the United
States. 1971. and unpublished 1972 edition of the same publication.
Federal Power Commission, Washington, D.C. Publication no. FPC-S226.
October 1972.
26
-------
Most electric utility representatives testified that their com-
panies were reluctant to install full scale FGD systems on large numbers
of plants. There was general agreement that FGD systems can, when working
properly, achieve the 85 to 90 percent reduction required to meet the emis-
sion limits, but most utilities argued that FGD systems were plagued with
problems such as unreliable operation, high cost, and sludge disposal
difficulties. These alleged problems are discussed in some detail in
later sections of this report. The remainder of this section reviews the
efforts made by electric utilities to solve what they considered to be the
major problems with FGD systems.
Only 22 of the some 300 electric utilities of all types operating
fossil-fueled plants in the United States have installed, or are committed
to install, at least one FGD unit. Table 3-1 breaks down by type the M
FGD systems (controlling about 18,000 megawatts of generating capacity)
that have been installed or are planned by these 22 utilities; and Table
3-2 shows these FGD systems by type and company. Of course, some research
and development on FGD systems could be accomplished without the instal-
lation of full scale systems; hence, it is important to review the indus-
try's overall research and development effort. Total electric utility
industry research and development, although increasing over the last few
years (see Table 3-3), is very small and amounted to less than 1 percent
of the industry's total operating revenue in 1972. Research and develop-
ment on FGD systems is only a small but undetermined part of this overall
effort.
Although research efforts by the utility industry as a whole have
lagged, several utilities (generally the smaller ones) have undertaken
vigorous FGD programs. Kansas City Power & Light Co., Louisville Gas &
Electric Co., Potomac Electric Power Co., and Arizona Public Service Co.
account for IT of the M units mentioned above. Louisville Gas & Electric
Co. testified that FGD was more economical and more in the interest of the
State of Kentucky than was fuel switching.3 Compliance schedules have been
submitted to progressively install scrubbers on eight existing and two new
Louisville Gas & Electric Co. plants by 1980. Although Kansas City Power
& Light Co. is not subject to sulfur oxide emission regulations, it too
has initiated a program to install FGD systems on all its plants. These
and a few other utilities have made substantial efforts to develop FGD
testimony, J. F. Mayrose, Louisville Gas & Electric Co., p. 1200.
^Testimony, J. F. Mayrose, Louisville Gas & Electric Co., pp.
1205-1218.
27
-------
technology even though most of them do not yet believe the technology
to be fully demonstrated. As the spokesman for Arizona Public Service
Co. said, the lack of demonstration is not an excuse for a utility to
do nothing.5
Unfortunately, most of the other utilities that testified did not
evidence aggressive programs to solve the alleged problems in applying FGD.
These utilities have generally adopted a 'wait and see1 attitude and have
apparently been content to point out all the problems while waiting for
each other or for FGD vendors to solve them. Indeed, some companies appear
to have spent more in defending their lack of progress or in attempting to
have the requirements changed than they have in controlling their sulfur
oxide emissions. Many examples of this attitude were evident during the
hearing and the following serves to illustrate this point.
Although representatives of West Penn Power Co. testified that con-
tracts to obtain low-sulfur coal for several of its power plants had been
initiated, it was acknowledged that this supply would be inadequate for the
company as a whole. Yet West Penn Power Co.'s work on FGD development
has been minimal and, in fact, no one person was working full time on FGD
technology until just prior to the hearing.^ Of the four expert witnesses
for West Penn Power Co., three were hired the month before the hearing to
prepare the company's testimony; the fourth, a meteorologist, had been in
the employ of the company for 2 years as a general consultant on air quality
problems.
AEP, like West Penn Power Co., has attempted to obtain locally
available low-sulfur coal to achieve compliance. The company, which is
the second largest user of coal in the U. S., acknowledged that nearby
low-sulfur coal would be available for only 60 to 70 percent of their
coal-fired generating capacity.° Although AEP claimed that its name "is
synonymous with pioneering"10 in such new technologies as cooling towers,
extra high voltage transmission lines, and supercritical boilers, this
large company is not pursuing any significant research program of its own
on FGD systems.
AEP pointed out a number of problems with FGD systems, yet con-
tended that it was common sense to await the outcome of current FGD demon-
stration programs at other utilities before attempting even a pilot
operation of its own. AEP's program for bringing the rest of its system
into compliance is dependent upon the availability of low-sulfur coal from
^Testimony, C. McVay, West Penn Power Co., pp. 376-379.
^Testimony, C. McVay, West Penn Power Co., pp. 376-379-
^Testimony, C. McVay, West Penn Power Co., pp. 389-390.
o
Testimony, C. McVay, West Penn Power Co., pp. 391-393-
^Testimony, J. Dowd, American Electric Power Co., pp. 26U1-261+5.
•^Testimony, J. Dowd, American Electric Power Co., p. 2636.
28
-------
western States, the expectation of an easing in the degree of control
required by some State emission standards, and the allowance of tall
stacks for SOX abatement.
The Tennessee Valley Authority is the largest utility in the
United States, producing about 10 to 15 percent of the country's electri-
city as well as a commensurate share of emissions from coal-fired power
plants. Except for requesting variances from the three states in which it
operates, TVA testified that no plans had been formulated to comply with
SOX emission limitations because TVA believed that these regulations were
under review in each State.12 It was TVA's contention that achieving
ambient air quality levels by reducing the amount of pollutants being
emitted rather than dispersing contaminants through the use of tall stacks
and intermittent controls was a "terrible mistake".13 Although TVA is
building a full scale FGD system for one boiler at its Widows Creek Station
JUKI has participated in several EPA-funded FGD research programs since
1967, the company admitted to expending greater efforts in attempting to
change State regulations than in developing FGD technology. In addition,
TVA stated that its program would not change even if the utility decided
that FGD technology had been adequately demonstrated.^
Testimony from utilities that have installed FGD systems and from
vendors of these systems indicated that control of system chemistry is
critically important for reliable operation. Such operation is, however,
unique to companies experienced with power generation but unfamiliar with
the control of chemical processes. Unfortunately, only a few companies
testified to having hired personnel skilled in chemical operations. Those
who have, such as Louisville Gas & Electric Co., seem to have had the most
reliable FGD operation.
It seems clear that utility witnesses understood and agreed that
Congress1 mandate to control sulfur oxide emissions would be met in a
timely way only through the application of FGD technology. Most utilities
argued that this technology was not yet adequately demonstrated, but few
of these companies aggressively pursued solutions to the alleged FGD system
problems. In general, utilities have been content to wait for other uti-
lities and FGD vendors to solve these problems. The general 'wait and
see1 attitude of the utility industry toward FGD systems is even less
•^Testimony, J. Dowd, American Electric Power Co., pp. 2638-26U5-
12Testimony, L. Seeber, Tennessee Valley Authority, p. 2339.
13Testimony, L. Seeber, Tennessee Valley Authority, p. 23^3.
29
-------
acceptable since many of these companies have not aggressively followed
the work of those companies that have installed FGD systems. TVA, for
example, testified that they had not visited the Louisville Gas & Electric
Co. installation until one month prior to the hearing^ even though this
FGD system had been in operation for 6 months and was only a short dis-
tance from TVA's headquarters. This approach is not responsive to the man-
date of the Clean Air Act and the utility industry must, in the future,
mount a much more aggressive program to determine solutions to its compliance
problems.
^Testimony, W. Elder, Tennessee Valley Authority, p. 2336.
-------
Status of Flue Gas Desulfurization Technology
It was generally agreed at the hearing that FGD technology,
when operating properly, can reduce sulfur emissions to the required
levels (up to 85 or 90 percent removal). Key questions were raised,
however, about the reliability, waste disposal problems, and costs
associated with these systems. This section of the hearing report
deals with the issue of scrubber reliability and operability. Waste
disposal problems and costs associated with flue gas desulfurization
are dealt with in other sections.
Although the hearing testimony on the status of FGD technology
can be roughly divided into two opposing viewpoints, only a few speakers
took the extreme positions that FGD technology will not be ready for
commercial applications for many years or that it is now fully optimized.
Most utilities stated that FGD technology is not ready for commercial
application; estimates of time required for further development ranged
from a few months to over 5 years. Louisville Gas & Electric Company
seemed to be the most optimistic of the utilities, indicating that only
a few more months of operation at their Paddy's Run Station is required
prior to commitments to full commercial-scale systems.-'- They described
the major constraints on widespread application to their generating
system as nontechnical. Several utilities took the position that devel-
opment has progressed to the point where large scale (single module)
installations are warranted for continued development and demonstration,
even though reliability has not yet been demonstrated.
Equipment vendors represented at the hearing were generally
optimistic concerning the status and future of FGD. Seven vendors
(Peabody, CEA, Chemico, Research Cottrell, CE, Davy Powergas, and UOP)
stated that they are now prepared to offer full scale commercial systems.
Certain vendors indicated that they favored some pilot work for appli-
cations with unusually high-sulfur or high-ash fuels concurrent with
full system design. In some cases, modular installation was considered
the desired approach although substantial additional time for full con-
trol is required.
Lime/Limestone FGD Technology
Lime Scrubbing - The process is offered commercially by
Chemico, Combustion Engineering, Inc. (CE), and Combustion Equipment
Associates, Inc. (CEA). The Mitsui unit built by Chemico (a U.S. firm)
^Testimony, J. F. Mayrose, Louisville Gas & Electric Co.,
p. 1236.
31
-------
has operated reliably since April 1972 on a 156-megawatt coal-fired
boiler in Japan. A Combustion Engineering-designed system has been
successfully operating at Louisville Gas and Electric's Paddy's Run
Station since April of 1973. No problems have developed with this
installation and it shows promise of successful long term operation.
Limestone Scrubbing - The process is offered commercially by
Babcock & Wilcox, Peabody Engineered Systems, Research Cottrell (RC),
and CE. Although there is currently no full scale system operating
which can be considered a successful demonstration, several systems
are now undergoing intermittent operation and modification to solve
operating problems. These installations include Will County, Hawthorn,
and LaCygne. The recently started Cholla unit of Arizona Public Service
seems to hold promise of successful operation during the coming year.
The results of the EPA Shawnee prototype facility have been encouraging.
Reliability Problems
The bulk of the testimony relevant to the reliability question
centered around lime /limestone scrubbing systems,, which represent the
great majority of FGD systems installed or planned to date.
For lime and limestone FGD systems, the following major relia-
bility prc.-lems were cited by W. D. Crawford, A. Slack, and J. Bradstreet'
as evidence that FGD technology is not sufficiently developed for util-
ity applications:
- chemical scaling in the scrubber
- plugging (demister and wet/dry interfaces)
- mechanical problems (fans, pumps, etc.)
During the course of the hearing it became apparent that, based
on testimony from expert witnesses, there were design provisions which
can, and have, at selected installations, resolved all of the above
problems. Dr. Craig" representing Edison Electric Institute commented
testimony, F. Princiotta, EPA, p. 56A.
•^Testimony, W. D. Crawford, Edison Electric Institute, p. 880.
Testimony, A. Slack, SAS Corp., representing West Penn Power
Co., pp. 165-197.
•'Testimony, J. Bradstreet, NTJS Corp., representing Public Ser-
vice Co. of Indiana and NIPSCO, pp. 561-579.
Testimony, J. Craig, Southern Services, Inc., p. 991-
32
-------
during panel questioning on the above problems by stating: "Many of
those problems are well underway to having adequate solutions to them...
The Mitsui (Chemico 156-megawatt lime scrubber in Japan) operation, for
one example, has not experienced to any great degree many of those
problems."
The following summarizes some testimony relevant to these
problem areas:
Chemical Scaling (Hard chemical deposits)
Dr. Craig' stated that "...in a well-operated system in a
well-operated plant, plugging apparently has been overcome. Scaling
is apparently well underway to being controlled. Mitsui (Chemico lime
'scrubber in Japan) did experience some slight amount of scaling, but
nothing of the order of magnitude which would cause it to be shutdown."
Louisville Gas & Electric indicated that during the 6 months of
operation of their unit scaling was not a significant problem. Dr.
Hesketh" from Southern Illinois University indicated that scaling was
not a significant problem at the Mitsui installation during its 20 months
of operation, which he described as generally operating in a closed-
loop manner. EPA-^ indicated that scaling has not been a significant
problem during the operation of limestone and lime reliability testing
to date at their Shawnee prototype facility. In general, the following
provisions were cited in testimony as capable of reducing the tendency
toward scaling problems: high liquid/gas ratios, proper scrubber selec-
tion, high percentage of solids, and probably most importantly, careful
pH control within certain limits.
Plugging (Soft solids buildup)
As stated earlier in a quote from Dr. Craig (EEl), the problem
associated with "plugging apparently has been overcome". Again, Louis-
ville Gas & Electric and Dr. Hesketh testified that problems associated
with plugging (including demisters) have not been significant during
the operation of the Paddy's Run and Mitsui Miike Power Plant lime FGD
systems, respectively. EPA described the initial problems experienced
at the Shawnee facility with demister pluggage, and modifications which
'Testimony, J. Craig, Southern Services, Inc., p. 992.
Testimony, R. VanNess, Louisville Gas & Electric Co., pp. 1229-1230.
^Testimony, H. E. Hesketh, Professional Engineer, p. 2763.
10Testimony, F. Princiotta, EPA. pp. 2513-251?.
33
-------
were made to apparently resolve these problems. Commonwealth Edison,
although plagued with demister pluggage problems since their start-up
during February 1972 stated:11 "...the plugging problem that we have had
in our demister, due to a recent modification in washing arrangement, it
looks like we might have that one under control." Generally, careful
design of demisters and their wash systems appears effective in eliminating
demister pluggage. Careful design of wet/dry interface locations was
cited as having been effective in alleviating other pluggage problems.
Erosion/Corrosion
Under cross-examination Dr. Craig1 stated that "we are well
on the way toward eliminating erosion problems." He indicated that
"...engineering judgments, selection of materials could eliminate ero-
sion and corrosion problems". He went on to say "...it will take time
to apply what we currently have available and optimize what we currently
have available". Again, Louisville Gas & Electric and Mitsui facilities
have reported no significant erosion/corrosion problems during the operation
of their lime scrubbers. The Mitsui unit is particularly significant since
there has been no deleterious erosion/corrosion since its startup in
March 1972. It should be noted that those utilities which were scrubbing
with large quantities of fly ash in the slurry and/or did not control
pH have experienced erosion/corrosion of varying magnitudes.
Mechanical Problems
Mechanical problems were cited by several utilities as major
difficulties. Reliability of pumps, fans, and other important process
equipment has sometimes not been adequate. It was not clear whether
these problems were due to: poor choice of equipment, poor quality
control, maloperation, etc. However, these problems are not generally
process related, and have not, in fact, been significant at several
installations to date, including Louisville Gas & Electric and Mitsui
Aluminum.
Table U-l presents a summary of testimony regarding observed
problems, by problem area, for important lime/limestone and other full-
scale/prototype facilities. In general, all problems identified at a
given installation have been resolved at another installation; in
addition, Mitsui Aluminum (lime), Louisville Gas & Electric (lime), and
Japan Synthetic Rubber (Wellman-Lord) have not experienced significant
difficulties in any of the problem categories.
•^Testimony, D. Gifford, Commonwealth Edison, speaking for
Edison Electric Institute, p. 1008.
12
Testimony, J. Craig, Southern Services, Inc., p. 1012.
34
-------
Table 4-1. FGD OPERATING PROBLEMS AND THEIR RESOLUTIONS AT VARIOUS PLANTS*
Problem
Chemical scaling
Demister pluggage
Wet/dry pluggage
Eros ion/ corrosion
Reheater problems
Mechanical problems
(Fans , pumps ,
dryers, etc.)
Date started up
Process
Oil or coal
Size, megawatts
Testimony
JSR
Chiba
Plant
No
No
No
No
No
No
July 1971
Wellman-Lord
Oil
75
S. Watt,
Davy Powergas
pp. 2426-2450
Coram . Ed .
Will County .
Minor
Yes
No
Yes
Yes
Yes
Feb. 1972
Limestone
Coal
156
B. Lee,
Comm. Edison,
pp. 2067-2206
Mitsui
Chemico
Plant
No
No
No
No
No
No
Mar. 1972
Lime
Coal
156
H. Hesketh,
So. 111. Univ
pp. 2W-2768
Boston
Edison
Mystic
No
No
No
Minor
No
Yes
Apr. 1972
Magnesium
oxide
Oil
150
W. Irving
Bos ton Ed . ,
pp. 1356-1386
EPA
Shawnee
No
No
No
Minor
No
No
Apr. 1972
Limestone
& lime
Coal
3x10 Mw
F. Princiotta
EPA,
pp. 35-110
K.C.P&L
LaCvgne
Minor
Yes
No
Yes
Yes
Yes
Feb. 1973
Limestone
Coal
840
D. McPhee,
KCP&L,
pp. 1436-1451
Louisville
G&L Paddy's
Run
No
No
No
No
No
Minor
Apr. 1973
Limestone
Coal
70
J. Mayrose
LG&E,
pp. 1198-1219
*Yes or Ho indicates whether problems were considered serious at time of hearing.
-------
The Relevance of the Mitsui Lime Scrubber
The most controversial lime/limestone FGD facility, and poten-
tially the most important to the question of reliability, is the 156-
megawatt Chemico lime scrubbing facility at Mitsui's Miike Station near
Omutu, Japan. EPA1^ has stated that the success of this unit, which has
ODerated reliably (by all accounts) since its start-up in March 1972, is
quite relevant to many U. S. applications; the following areas of simi-
larity were cited:
(l) Retrofit on an existing coal-fired boiler
(2) Installation on a moderately large size boiler (156
megawatts)
(3) Availability of calcium hydroxide (Ca (OH)2) in U. S.
(U) Based on U. S. (Chemico) technology
Several utility witnesses, including A. Slack,•*- mentioned
several apparent differences between the Mitsui installation and typical
U. S. applications, which they felt tended to diminish the relevance of
this unit. The following major areas of "non-relevancy" were cited:
(l) Use of carbide sludge, a form of calcium hydroxide, at
Mitsui vs. more available burnt lime form in U. S.
(2) Base load operation at Mitsui vs. widely varying boiler
loads associated with many U. S. applications
(3) Open-liquor-loop operation at Mitsui which tends to mini-
mize scaling problems yet results in a water pollution
problem unacceptable in the U. S.
There was, however, much substantive testimony presented which
tended to minimize the importance of the so-called differences between
the Mitsui facility and U. S. applications.
With regard to the use of carbide sludge at Mitsui, R. VanNess, '
who is intimately familiar with carbide sludge production and is respon-
sible for the Louisville G & E carbide sludge scrubber, said: "I don't
think there is any difference" between burnt lime and carbide sludge.
Dr. Hesketh, the professor from S. Illinois University, who has performed
the most intensive evaluation of the Mitsui system, stated that lime is
more reactive than carbide sludge due to smaller particle size and
13Testimony, F. Princiotta, EPA, p. 57.
-^Testimony, A. Slack, SAS Corp., representing West Penn Power,
Co., p. l66.
15Testimony, R. VanNess, Louisville Gas & Electric Co., p. 1232.
36
-------
"...chemically, I do not believe there is a difference between calcium
hydroxide produced by carbide sludge and calcium hydroxide produced from the
slaking of lime.
"1"
Combustion Engineering, after testing both materials
in their Windsor pilot facilities, also stated they did not think there
were any important differences between these materials.
With regard to noncycling (base) load operation at the
f, it was noted by Dr. Hesketh1" that: "I feel there he
Mitsui
facility, it was noted by Dr. Hesketh-1-" that: "I feel there have been a
number of times when this system (Mitsui) has been cycled, and during
these periods of cycling, the pH control, which seems to be one of the
very significant factors in keeping the unit from scaling up and shutting
down, has been maintained at desired levels. There have been no problems.
Also, Mr. VanNess indicated that pH control has been generally successful
at the Louisville G & E's Paddy's Run lime unit, which has experienced
pronounced variable load operation. He stated: "control is a chemical
one and pH control is very, very important in this... This tends to be
a very complicated control system, and I think we have tended to master
this, not absolutely completely, ...but so far we had some very encour-
aging results".19
With regard to the alleged open-loop operation at Mitsui, the
only testimony with factual back-up was presented by Dr. Hesketh who
performed detailed material balances around the Mitsui system. He
stated: "This operation operates completely in closed-loop operation.
Very few times does it operate in an open-loop."^O
Dr. Hesketh summed up his thoughts on the relevance of the
Mitsui unit by stating: "...we have already had the statement that the
technology is here, it can be made to go, and I agree very definitely
with this. We have got to make it go because that's what they are doing
in Japan."21
1°Testimony, H. Hesketh, Professional Engineer, p. 2T6l.
^Testimony, J. Jonakin, Combustion Engineering, Inc., p. 1312.
^Testimony, H. Hesketh, Professional Engineer, p. 2763.
^Testimony, R. VanNess, Louisville Gas & Electric Co., p. 1229.
20Testimony, H. Hesketh, Professional Engineer, p. 2762.
2lTestimony, H. Hesketh, Professional Engineer, p. 2765.
37
-------
Wellman-Lord Sodium Based Scrubbing
This process is offered commercially "by Davy Powergas, Inc.
Davy reported that this regenerable process has been operating since
August 1971 on a 75 megawatt oil-fired boiler at the Japanese Synthetic
Rubber Plant at Chiba, Japan.^2 This unit has exhibited a 97 percent
availability to the boiler for more than 2 years. An additional unit at
Chubu Electric Company was started up in May 1973. This 220-megawatt
unit is subjected to wide variations in both load and inlet sulfur
concentration. Operation of the Chubu unit has been trouble-free. There
are no technical or reliability problems associated with the Well man-Lord
process as applied to oil-fired utility boilers. Davy Power Gas stated
that coal-fired flue gas should not present any difficulties provided
adequate particulate removal is incorporated in the system. The panel
questioned the extent to which Davy was considering the potential environ-
mental problems associated with the sodium sulfate purge stream which is
characteristic of the process. The Davy representative indicated that
certain processes were being examined for treatment or elimination of
the purge and that for limited cases it may be possible to market the
sodium sulfate.^3 NO specifics regarding these alternatives were pro-
vided, however. Also, the panel indicated that the use of critical
natural gas in conjunction with the Allied reduction process was a
constraint on use of the W-L/Allied process. It is true, however, that
the W-L process is also used to produce acid as a product without the
need for natural gas. Generally the testimony given on this process was
of a positive nature. Subsequent to this testimony, there was little
disagreement with the points made.
Magnesium Oxide Scrubbing
The first commercial-size application of this process was in-
stalled by Chemico on a 155-megawatt,'O'il-fired boiler at Boston Edison's
ffystic Station. Since starting the^ystem up in April 1972, considerable
efforts have been made to improve the system's reliability. One of the
problems encountered was with magnesium sulphite crystal size; fine
particles passed through the dryer, the mechanical collector and out the
stack; particles that were too large also caused problems, probably
realted to hydration reactivity. These problems have been solved by
rerouting the dryer discharge containing the fine crystals back into the
scrubber itself and recycling, and by the installation of grinders to
get more uniform consistency of crystal size, respectively. In response
22Testimony, Stewart Watt, Davy Powergas, p. 2UU2.
23Testimony, Stewart Watt and C. Earl, Davy Powergas, pp. 2U59-2U63.
2l*Testimony, W. Irving, Boston Edison Co., pp. 1376-1377.
38
-------
to a question regarding problems inhibiting a long-term reliable run,
N. Irving of Boston Edison testified to the effect that "They all seem
solvable vith the technology that we have today" and that "we see no
mechanical or technical reasons why this will not be a successful project.
Testimony presented by R. Blinckmann of Chemico indicates that
they consider the process technology to have been adequately demonstrated
at Boston Edison. They feel that adequate reliability is yet to be
demonstrated but expect to offer the process on a full-scale commercial
basis for oil-fired units within the next several months. Chemico will
not offer the process commercially for full scale coal-fired applications
until process technology and reliability have been adequately demonstrated
at the 100-megawatt system at PEPCO's Dickerson Station, which started-up
in September 1973.
An additional system employing a variation of the Chemico
process is being installed by United Engineers at Philadelphia Electric's
coal-fired Eddystone Station on a 120-megawatt boiler. This system is
scheduled to start up in early 197**.2^
With these three systems in operation, it is anticipated that
expansion of process applicability as well as improvements in relia-
bility will be rapid in the coming months.
Other FGD Processes
The Cat-Ox System, which was developed by Monsanto, has been
installed on a 100-megawatt coal-fired boiler at Illinois Power's Wood
River Station. The demonstrating unit has been operated for a short
period of time and control efficiency and capability to produce the
specified acid product were verified and the process proven. However,
reliability and economics of operation and maintenance of eguipment are
factors yet to be determined and are hence ^still unproven.2° Efforts
to determine these factors have been delayed due to nonavailability of
natural gas for reheating of the flue gas prior to the catalyst bed.
Modification is currently underway to permit reheat with No. 2 fuel oil.
Restart is expected in the Spring of 197^. Additional problems encoun-
tered include condensation of acid in bypass ductwork with resulting
^Testimony, W. Irving, Boston Edison Co., p. 1385-
26Testimony, R. Blinckman, Chemical Construction Corp., p. 188U.
^Testimony, V. S. Boyer, Philadelphia Electric Co., p. 1928.
2°Testimony, E. Schultz, Illinois Power Co., p. l6l8.
39
-------
corrosion and failure of expansion joints permitting acid leakage.
Inadequate expansion Jpints have been replaced by better ones.^" Illinois
Power seems optimistic that reliable operation will be achieved in 197U
following completion of the oil-fired reheat burner modifications.
In addition to the four major processes mentioned earlier and
the Cat-Ox process-discussed above, UOP stated that they are offering
the Shell FGD process on a commercial basis.30 in addition, the double
alkali process shows promise of advancing to commercialization in the not
too distant future. The Japanese Chiyoda process is finding widespread
acceptance in Japan and will be tested in the U. S. in the near future.
Technology Summary
The panel finds that technological feasibility of FGD systems
has been established. Both throwaway and saleable product FGD techno-
logy have demonstrated sufficient reliability on full scale units to
warrant widespread application for SOX control at many coal- and oil-
fired power plant applications with acceptable risks.
Although some U. S. installations have encountered reliability
problems, the panel finds that each of these problems can be solved
through careful system design and proper control of system chemistry.
Testimony at the hearing revealed that all of the above problems have
been solved at one or more full scale FGD installation in this country
or Japan.
Operating experiences at the following facilities are considered
particularly important:
(l) Chemico Mitsui Miike Lime Scrubber - This unit has operated
with near 100 percent reliability controlling a 156-megawatt
coal-fired boiler near Omutu, Japan since its startup in
March 1972. The panel finds that this unit has established
that hydrated lime (calcium hydroxide) systems, operating
generally in a closed-loop mode, subjected to occasional
varying loads, can operate for periods exceeding 1 year
with no scaling, plugging, erosion, corrosion or other
significant operating problems.
29Testimony, E, Schultz, Illinois Power Co., p. 1655-
30Testimony, S. Mleczko, Universal Oil Products Co., p. 2572.
40
-------
(2) Louisville Gas & Electric fs Paddy's Run Lime Scrubber-
This unit has operated with good reliability since its
startup in April 1973 and has reinforced the finding that
closed-loop hydrated lime systems can operate reliably
with proper chemistry control. This unit is particularly
significant because pH control has been successful to date
in achieving good operability despite wide variations in
inlet concentration and boiler loads.
(3) Japan Synthetic Rubber's Chiba Wellman-Lord System - This
70-megawatt facility, which produces high-quality concen-
trated sulfuric acid as the by-product , has operated with
greater than 95 percent availability to the oil-fired
boiler during over 2 years of operation. The panel believes
that when efficient particulate removal equipment is installed
upstream of the SOX scrubbers, Wellman-Lord systems can
operate reliably for extended periods of time on coal-fired
boilers .
The panel also finds that the following commercially available
FGD/process application combinations can be installed with a high proba-
bility of successful operability and reliability, in approximate order
of confidence:
PGD
System Fuel By-Product
Wellman-Lord Oil Sulfuric Acid
Lime Scrubbing Coal or Oil Throwaway
Wellman-Lord Coal Sulfuric Acid
Limestone Scrubbing Coal or Oil Throwaway
A number of other FGD process/application combinations such as magnesium
oxide scrubbing (oil or coal), catalytic oxidation (oil or coal \ Wellman-
Lord (producing sulfur X and UOP /Shell (oil or coal), while not yet as
fully demonstrated as those systems discussed above, are expected to be
demonstrated on full scale installations in the near future.
41
-------
5. Vendor Guarantees
During the hearing, some utility industry witnesses expressed
dissatisfaction with guarantees being offered by vendors of FGD systems.
The chief drawback, as seen by these witnesses, was the refusal of ven-
dors to provide consequential damages or reliability guarantees. Con-
sequential damages involve payment by the vendor for power or revenue
lost during outages, and liability for such damages is almost univers?!.""
declined by vendors, not only for FGD systems, but for nearly all equip-
ment supplied to power plants.1 Because the guarantees offered by vendv." ?
are limited, there is a risk involved in installing an FGD system Just w-...
there is a risk involved in installing electric generating equipment.
It is understandable that utilities are reluctant to fissume the risks
involved, but the Act clearly demands that the industry creating the poJ-
lution undertake whatever risks are associated with control of that
pollution. Inability to obtain provisions covering consequential damage
or reliability does not, contrary to industry opinion, mean that FGD
technology should not be installed.
It is important to note that guarantees for FGD systems are
similar to those offered for such other major equipment purchased by
utilities as boilers, turbines, and electrical equipment. Table 5-1
describes guarantees usually provided by vendors; purchase contracts
for nearly all major equipment and for FGD systems are similar and few
contracts ever include provisions for consequential damages liability
or for reliability guarantees.
Guarantees are invariably a part of bid specifications and pur-
chase agreements for all of the equipment used by power plants. Typical
contracts include a performance guarantee and a warranty against defects
in material and workmanship. Performance guarantees for air pollution
control equipment usually specify a period of time during which the
equipment will achieve a given removal efficiency under specific condi-
tions (e.g., additive feed rate, gas throughput). The vendor's liability
is commonly limited to some fraction of the purchase price; seldom is
the full purchase price refunded if the system fails to meet guaranteed
performance. Guarantees against defects in material and workmanship
cover the basic design and mechanical integrity of the system and the
specifications for construction materials, but do not normally cover
erosion, corrosion, or normal wear. The value of the guarantee is
usually limited to replacement of the item or reimbursement of a portion
or all of its purchase price.
It should be noted that vendors often make repairs not required
by the contract in order to protect their good reputation. However, no
^Testimony, H. P. Willet, Peabody Engineered Systems, p. 229U.
"Testimony, Sidney R. Orem, Industrial Gas Cleaning Institute,
p. 1858.
43
-------
Table 5-1 Usual Business Practices
Guarantees or Warranties Provided
1. System performance of efficiency
guarantee
a. The system supplied is guaranteed to
meet the performance requirements of
the contract as demonstrated by a
short-term test on startup or within
one year following date of first com-
mercial operation.
b. In the event the system fails to meet
guaranteed performance, the vendor will
absorb the full expense of materials
and labor on a straight time basis.
c. Performance tests cannot be delayed
for more than 30 days after the
vendor gives notice to the purchaser
that the equipment is ready for
testing.
Guarantees or Warranties Not Provided
1. System reliability
a. A guarantee thai the equipment will
be operable for a specified percentage
of time after the performance test for
even short-term periods is not a usual
business policy of vendors.
b. U.O.P. stated that their company would
provide a 757- reliability guarantee for
one year with their FGD system for oil-
fired boilers. Liability is probably
limited to the cost of the equipment,
similar to performance guarantees.
2. Materials and workmanship warrantee
a. The system is warranted to be free of
defects in material or faulty design
for one year from date such material
or equipment is placed in use, or 18
months from date such material is
shipped, whichever occurs first.
b. In the event that any material or
equipment is found to be defective
or fails under design operating
conditions, the vendor shall redesign
and furnish F.O.B. shipping points
replacement or repair parts.
c. The vendor does not warrantee components
of the systems manufactured by sub-
contractors.
d. The vendor is not responsible for
damage to the system caused by operat-
ing under conditions not in accordance
with the vendor's written instructions.
e. The vendor is not responsible for replace-
ment of material and equipment which is
damaged or becomes defective as a result
of corrosion, erosion, or normal wear-and-
tear.
2. Consequential damages
a. Liability for loss of profit on sales
of electric power due to equipment
breakdown is declined by vendors.
b. Liquidated damage provisions relating
to a definite construction completion
date and to a performance level are
sometimes accepted as part of a bonus-
penalty contract provision.
3. Operating and maintenance expenses
a. Vendors do not guarantee operating
expenses. Projections of these
expenses are included in the vendor's
bid proposal. These proposals receive
close engineering evaluation by the
utility to determine which system has
the greatest potential for lowest cost
operation.
b. Maintenance costs for normal wear-and-
tear during the one-year warranty period
and all maintenance costs in subsequent
years including repair of breakdowns
are not absorbed by the vendor except
on a voluntary basis.
3. Liability limitations
The total liability of the vendor is
limited to a maximum amount equal to
the value of the system not including
the auxiliary equipment not manufactured
by the vendor or the erection labor or
alternatively to the vendor's profit.
44
-------
vendor is willing to assume all risks during the lifetime of the FGD
system by guaranteeing its reliable operation at all times because the
vendor rarely has control over the operation and maintenance of the
system after an initial performance test. Only one vendor, Universal
Oil Products Co., stated a willingness to guarantee reliability (75
percent), and then for only 1 year with the reservations that the vendor
would operate the control device and that liability was limited to the
purchase price.3 However, vendors have, in general, taken substantial
risks in developing FGD systems. Combustion Engineering, Inc., for
example, invested $20 million to develop a system, and estimates that it
will be another 20 years before this investment can be recovered in
profits.
The panel finds that FGD system guarantees now offered by vendors
are generally appropriate and that the demands put forth by the industry
are often unreasonable, not in accord with usual business practices, and
clearly not in accord with the requirements of the Act. For example,
AEP demanded a guarantee for a proposed FGD system that was unprecedented
in any of their previous equipment contracts. AEP wanted an iron-clad
guarantee that the installed equipment would function nearly trouble-free
for 15 years handling coal with a sulfur content up to 5-5 percent. Design
was to be completed less than 9 months after the contract was awarded and
the system was to be operating full scale in time to comply with 1975
standards. The equipment was to complete its first year as a "demonstration
period," and if the system failed, the vendor would be liable for 150 per-
cent of the contract price. The vendor would also have been liable for •
consequential damages of up to $53 per megawatt per day for any downtime
beyond 5 days a year for the remaining Ik years of the guarantee.5 This
same utility characterizes itself as a leader in the industry and a
pioneer in supercritical boilers. AEP took a risk in installing the first
100-megawatt supercritical boiler with no provision for consequential
damages or any reliability guarantee, but is not willing to install pol-
lution control equipment under the same conditions. The difference may
be in the incentive for the utility to take the risk. Supercritical
boilers result in lower generating costs, but there is no cost incentive
for AEP to install a pollution control system.
3Testimony, Stanley S. Mleczko, Universal Oil Products Co., p. 2596.
^Testimony, James Jonakin and Joe Singer, Combustion Engineering,
Inc., pp. 128U-1289.
^Testimony, Thomas N. Bethell, United Mine Workers of America,
p. 1959-
"Testimony, J. Tillinghast, American Electric Power Service
Corp., pp. 268U-2686.
45
-------
6. Flue Gas Desulfurization System Malfunctions
Because FGD technology is relatively new, unpreventable mal-
functions might be expected during operation of the system. Many States
have no regulatory provisions that exempt sources from emission limits
during periods of malfunction. Some industry witnesses claimed that
this creates a difficult situation because boilers must be shutdown
during malfunctions to prevent emissions from exceeding permissible
limits; this would result in a loss of revenue and in a loss of needed
electricity. Witnesses claimed that the only alternative is to maintain
operation of the generating system and face the possbility of being
found in violation of applicable regulations. Some members of the
utility industry therefore argue that the large capital investment
necessary to control SOX emissions cannot be justified until the in-
dustry is assured that emission limits will not apply during periods
of unpreventable malfunction.
The panel, however, finds that this concern is somewhat over-
stated. It is not always necessary to shutdown a boiler during mal-
function; rather, ducting can be installed to bypass the equipment
during malfunction. In addition, about one-half of the States already
have statutes that provide relief from emission limitations during
malfunctions. New Mexico's regulation is typical. It provides that
unpreventable malfunctions do not constitute a violation of the appli-
cable regulations if certain procedures are followed.1 The source
must report the breakdown to the State agency within a designated period
of time, make a maximum reasonable effort to correct the problem, and
minimize excess emissions during the breakdown. In addition, the reg-
ulation requires that a report be made to the State after the malfunc-
tion has been corrected.
Although the other 50 percent of States do not have specific
regulations covering malfunctions, very few States automatically take
enforcement action when a source exceeds emission limits during a mal-
function. Pennsylvania, for example, does not take any enforcement
action until it has carefully studied the malfunction and determined
the cause of the breakdown.2 If the malfunction occurred despite the
company's efforts to operate the equipment effectively and if the
company responds to the situation by making the maximum reasonable
effort to correct the problem and prevent its recurrence, Pennsylvania
does not bring an enforcement action.
Because AEP believed that West Virginia had no regulatory pro-
visions exempting sources from emission limitations during malfunctions,
the company conditioned its acceptance of a bid to install sulfur oxide
control equipment at its Karamer Station on the inclusion of a guarantee
Transcript, Cubia Clayton, New Mexico Environmental Improvement
Agency, p. 1531.
Transcript, Clark L. Gaulding, Penna. Department of Environ-
mental Resources, pp. 2970-2971*.
^Transcript, Richard M. Dicke, Simpson, Thacker and Bartlett,
appearing on behalf of American Electric Power Co., p. 2663.
47
-------
that the control equipment would be as reliable as various components
of the generating system. Breach of this guarantee would require the
vendor to pay the cost of the control equipment plus consequential
damages. Noting that equipment vendors were not anxious to meet the
terms of this bid specification, AEP concluded that "(There should
be an) accommodation, if you will, by the regulator, to the reasonable
needs of the industry and the manufacturers by specifically promulgating
regulations."3
AEP, however, failed to specifically discuss malfunction pro-
visions with West Virginia. Carl Beard, Director of the West Virginia
Air Pollution Control Commission, testified that a specific provision
allowing for a variance during malfunction was adopted in West Virginia
on February 1, 1973.^ It would seem that better communication with
the State agency would have brought this fact to AEP's attention.
Although the lack of formal malfunction procedures has not
proved to be a problem in the past, the panel believes that such pro-
cedures should be formalized by States lacking such regulation.
FGD systems malfunction for several reasons. When pumps and
other mechanical equipment breakdown, the scrubbers will not operate,
but this does not affect the generating system. The control system
can simply be bypassed, allowing untreated gas to pass through. A
malfunction caused by plugging or corrosion does necessitate more than
taking the scrubber off-line; a bypass to shunt the flue gas around
the control equipment to the stack must be used.
Two types of bypass systems are currently used by utilities.
The simplest system is one that uses blanking plates to close off the
ducts leading to the scrubbers. Plates are mounted on rollers and
manually moved into position. The primary deficiency in this system
is the necessity of shutting down the boiler during plate movement.
Shutdown time is a function of the manpower available to position the
plates. One to three days are normally needed to shutdown the boiler,
position the plates, and refire the boiler.
A more complicated but less time consuming system uses mech-
anical dampers activated when the control equipment malfunctions. The
dampers in these systems are either the guillotine-type which slide
down into the path of the flue gas or the louvre-type which close,
thereby blocking the gas stream.
^Transcript, J. Dowd, American Electric Power Co., p. 2675-
Transcript, C. Beard, West
Commission, pp. 2709-2711.
'Transcript, C. Beard, West Virginia Air Pollution Control
48
-------
Representatives from several utilities using such dampers
testified at the hearing that these systems often do not operate be-
cause of mechanical failures. The corrosive flue gas causes the dampers
to "freeze," either in the open or closed position. When the dampers
freeze in the open position, pressure buildup can cause toiler seals
to "blow out. To prevent this, boilers are often shutdown. Freezing
of the dampers in the closed position results in excess stack emissions
after the malfunction in the scrubber system has been corrected.
Control equipment vendors do not view the bypass system problem
with the same gravity as do industry representatives. It is the ven-
dors' opinion that the problems associated with bypass dampers are
minor and can easily be solved by proper control design and by the
installation of good quality dampers manufactured from material that
does not react with the corrosive gas stream."
Louisville Gas & Electric Company's experience with the bypass
system at its Paddy's Run Station supports this view. Although the
dampers are not 100 percent effective, the company reports good results
with the system.'
The hearing panel recognizes that difficulties can be expected
in the use of damper systems, especially when such systems are in-
stalled in ducts having large cross-sectional areas. However, the
panel finds that the problems experienced by the utilities are not
major and can be solved through proper design and workmanship.
In order to improve the overall reliability of scrubbing sys-
tems, many vendors oversize their control systems by 20 to 33 percent.
This oversizing can be effected in a number of ways. Extra scrubbers
can be installed which come on-line when the primary scrubbers mal-
function, or individual scrubbers can be designed to operate normally
at less than 100 percent capacity." In addition, extra mechanical
components such as fans and pumps can be fitted into the individual
scrubbers.
Although most utilities do acknowledge that redundancies lower
the rate of malfunctions, many do not feel that the added expense
is Justified in every case. For example, in a control system for
a plant in the 100 to 200 megawatt range, installation of a backup
scrubber could increase the capital outlay by 100 percent. Accord-
ingly, some small stations do not and should not put on extra units.
Some types of redundancy are appropriate for some sources and not
for others; appropriate redundancies can be determined only on a in-
dividual basis.
Transcript, Robert H. Quig, Chemical Construction Corp.,
pp. 1903-190U.
•Transcript, Robert VanNess, Louisville Gas & Electric Co.,
TO. 122U-1225.
^Transcript, Jack B. Moore, Southern California Edison, p. 1795-
49
-------
Although many utilities testified that when an FGD system
malfunctions the plant would have to be shutdown if it is to remain
in compliance with SOX limitations, testimony on available bypass
systems and on existing State regulations and procedures does not
support this contention. The panel, however, urges those States that
have not already done so to formalize procedures for dealing with
malfunctions. The panel also finds that appropriate control system
redundancies should be determined on a case by case basis.
50
-------
7. Waste Disposal
During the hearing the electric utility industry evidenced con-
cern for disposing of sludges created by FGD systems. However, not all
types of FGD systems generate sludge. Some regenerable systems reduce
the captured 869 to a much more compact form. The disposal problem is
minimized or eliminated with such systems. FGD systems therefore fall
into two categories: "saleable product" systems and "throwaway" systems.
Saleable product systems produce such materials as sulfuric acid and
sulfur which can be marketed in many locations in the U. S. Throwaway
systems produce semisolid vastes, generally referred to as sludge, that
require the use of waste disposal technologies. Such wastes, produced
by wet lime, limestone, and double alkali systems, contain various pro-
portions of calcium sulfite, gypsum, fly ash, water, and assorted other
materials in trace quantities.
Nearly all representatives of EPA, utilities, and FGD system
vendors stated or implied that sludge disposal was a significant problem
having potential environmental implications. Representatives of Environ-
mental Sciences, Inc. (Chemfix) and I.U. Conversion Systems, Inc. (IUCS),
two companies commercially offering sludge fixation/disposal services,
testified that technology is available at reasonable cost for fixation
and disposal of sludge in an environmentally acceptable manner.l>2
Dr. Minnick of IUCS stated that "our organization is prepared to finance,
construct, and operate processing facilities for the treatment of fly ash
and sludge for a specific fee per amount of waste product handled, and is
in a position to prepare definitive cost proposals on a long-term service
agreement basis for utilities having disposal problems."2 Although there
was no testimony given by Dravo or Chicago Fly Ash, two other companies /
that offer sludge fixation/disposal services, allusion to their techno-
logy and activities was made by other witnesses. It should be noted
that the historical power plant problem of coal fly ash disposal has
been handled for each plant in operation today; in fact, testimony by
IUCS brought out the fact that their company was in that business.
EPA discussed the potential environmental problems created by
scrubber sludges: water pollution and land deteoriation. Surface
waters such as rivers, streams, lakes, and ponds can be contaminated
following rainfall by runoff or discharge from sludge disposal areas or
by water balance problems in the scrubber system. Ground water can be
contaminated by leaching and percolation of sludge liquor into the
ground water through soil in sludge storage areas. Land deterioration
could result from having to store on large areas of land large amounts
Testimony, J. Conner, Environmental Sciencies, Inc., pp. 3050-3070.
"Testimony, L. J. Minnick, I.U. Conversion Systems, Inc.,
pp. 2768-2787.
51
-------
of sludge materials typically containing 50 to TO percent water and
having a "toothpaste-like" consistency. This land could be made useless
by the nonsettling characteristics of the sludge. To minimize the po-
tential environmental problems created by FGD system sludges, the liquor
must be recycled to the scrubber while the remaining wet solids are
either ponded in a nonpermeable pond or are solidified for landfill or
other disposal. The liquor and dissolved chemical species must be en-
trapped physically and/or chemically in the solid matrix. This is the
basis of the technology offered by Dravo, IUCS, Chemfix, and Chicago
Fly Ash.
Although this technology is offered commercially, it has not
been used to date on any full-scale control system other than at Common-
wealth Edison Co. where a process developed by Chicago Fly Ash Co. is
being used. Both Dravo and IUCS, however, are planning to process sludge
from future systems. Dravo expects to process sludge from the 100-megawatt
system at the Phillips Station of the Duquesne Light Co. scheduled for
startup in December 1973 and from the l650-megawatt Bruce Mansfield plant
of the Ohio Edison Co. scheduled to startup in 1975- » Dr. Minnick of
IUCS testified that IUCS expects to operate a sludge fixation/disposal
system at an unidentified full-scale utility plant by the beginning of
197^. The Chemfix process of Environmental Sciences, Inc. was applied
to samples of sludge from Commonwealth Edison Company's Will County plant
and from the TVA Shawnee plant.
The costs discussed for treatment of sludge vary substantially.
The highest cost mentioned was $17-10 per ton of dry solids, which was
cited by Commonwealth Edison Co. as the actual operating cost for the
Will County Station for treating thickener sludge with the Chicago Fly
Ash process from May through September 1973. This is equivalent to
2.2U mills per kilowatt-hour or about 22 percent of the total FGD system
operating cost. Duquesne Light Co. estimated the cost for sludge fixation
treatment using Dravo's technology at their Phillips Station at $lU to
$15 per ton of dry solids or about 1.2 mills per kilowatt-hour.7 The
IUCS estimate is $1.5 to $3.0 per ton of dry solids or about 0.2 to 0.3
mills per kilowatt-hour, exclusive of dewatering equipment and hauling
^Testimony, S. L. Pernick, Duquesne Light Co., p. 1578.
h
Testimony, D. W. Tschapport, Ohio Edison Co., p. 2212.
^Testimony, L. J. Minnick, I. U. Conversion Systems, p. 2786.
"Testimony, Byron Lee, Commonwealth Edison Co., p. 2086.
"^Testimony, Steve Pernick, Duquesne Light Co., 1590.
52
-------
costs. Dr. Minnick indicated that disposal site availability is an
important variable affecting cost because long distance hauling can be
quite expensive." No costs for the Environmental Sciences Chemfix pro-
cess were cited in the testimony.
Most of the commercially offered sludge fixation technology is
considered proprietary by the vendor. However, all of the vendors
claim that they can dispose of calcium sludge in an environmentally
acceptable manner if they are given samples of the material to experiment
with; they must tailor their process to the specific sludge in question.
Although the IUCS process was stated to be proprietary by Dr. Minnick,
he did admit that fly ash is an essential ingredient to the fixation
process.9 In general, however, the ratio of fly ash to calcium-sulfur
compounds produced at most power plants using lime or limestone FGD
systems is favorable to the fixation process.
Both IUCS and Environmental Sciences, Inc., suggested that solidi-
fied sludges may have uses other than landfill. Some of the uses cited
include construction material for dikes and retaining walls, road base,
and construction aggregate.
The issue of sludge leachability was brought up several times
during the course of the hearings. Environmental Sciences, Inc. has
attempted to develop standard test methods to determine the degree of
leachability of fixed solid waste. These methods were described, and
some comparisons of treated and untreated sludge leachate samples were
shown. The treatment appears to reduce soluble contaminant concentrations
considerably. Both Environmental Sciences, Inc. and IUCS claim to be
capable of making a solid waste product that is environmentally acceptable
from the standpoint of leachability. However, regulatory standards for
levels of soluble solids in landfill materials were not cited.
In summary, the disposal of sludge produced by throwaway FGD
systems was cited throughout the hearing as a potential problem. How-
ever, the panel finds that during the course of the hearings, technology
was described that could minimize or eliminate the associated environ-
mental problems. This technology includes closed-loop operation, use
of pond liners, and chemical treatment (fixation) enabling disposal of sludge
as an acceptable landfill material at the large number of landfill sites
that are available for sludge disposal. There are, however, specific
cases, generally in urban areas, where sludge disposal could be prohibi-
tively expensive due to a lack of readily available landfill sites.
Regenerable or saleable product FGD systems which do not produce throwaway
sludges should be considered for these applications; fuel switching could
also be used to achieve compliance. Utilities are urged to move ahead
quickly with developmental work on ponding and fixation technology.
Further characterization and evaluation efforts, with emphasis on large
scale systems, are needed to assure wide spread applicability and effec-
tiveness at reasonable costs.
"Testimony, L. J. Minnick, I.U. Conversion Systems, pp. 2780-2781.
53
-------
8. Costs of Flue Gas Desulfurization Systems
One of the most important and perhaps most elusive issues
discussed at the hearing was the cost of installing and operating FGD
systems. Almost every witness referred in some way to the cost of
controls and a number of witnesses gave cost figures based on their
own experience or on the experience of others. The most objective
way to assess the cost of FGD systems is to look at the cost estimates
discussed at the hearing for specific plants. These cost figures,
including capital and annual costs, where given, are summarized in
Table 8-1.
As shown in Table 8-1, testimony regarding capital costs for
retrofitting FGD systems on existing plants ranged from as low c:s $39
per kilowatt to as high as $108 per kilowatt. Most estimates fell
in the range of $50 to $65 per kilowatt. Capital costs for new plants
were generally lower.
Annual costs for retrofitted plants ranged from 2.U mills/kw-
hr to a high of 10 mills/kw-hr, with most plants falling in the 2.1^
to U.O range. Only two estimates of annual costs for new plants were
given — EPA's estimate of 1.5 mills per kw-hr and Ohio Edison Co.'s
estimate of 2.7.
It is difficult to compare the cost figures in Table 8-1 be-
cause many of them include different items in the costs or are based
on different assumptions. For example, some cost estimates include
the cost of building sludge disposal ponds while others include the
assumption that sludge would be hauled away. Others factors, such
as the age of the plant, peculiar retrofit and operating problems,
variations in sulfur content, degree of control required, annual load
factors, amount of redundancy, vendor guarantee specifications and
different time bases, also caused variations in the costs. Some of
these factors are included in the comments column in the table.
The cost of flue gas desulfurization may be prohibitive for
plants having severe space limitations. In addition, the annualized
cost of retrofitting older plants may be severe if the plant will be
retired shortly. The hearing panel therefore suggests that these plants
have first priority for available low-sulfur fuels.
The costs of installing and operating FGD systems will ulti-
mately result in increased costs to the consumer. The costs cited
above constitute increases in costs at the individual plants, but the
amount of corresponding increase that must be passed on to the consumer
depends upon the number of plants within the particular system that
need control. The most straightforward example is the case where a
customer is in an area served by a utility company having only one
55
-------
plant. If this plant must install control that will result in an in-
crease of 3 to 1* mills/kw-hr in annual costs, then the consumer's rates
could increase by as much as 15-20 percent annually (assuming that
the consumer had been paying the typical rate of 20 mills/kw-hr).
However, companies commonly have several plants and in this case, the
consumer's costs would not be as severe. In fact, as discussed in
the Background section of this report, only about 90,000 megawatts
of power plant capacity will require FGD by I960 in order to meet pri-
mary air quality standards. Using 3 mills/kw-hr and a 7-5 percent
annual inflation factor, this amounts to an increase in the average
price of electricity of only about 3 percent by 1980.1
Most State public utility commissions provide for automatic
pass-throughs (rate increases) of increased fuel costs caused when
a utility switches to more expensive low-sulfur fuel as an emission
control mechanism. Similar automatic pass-throughs are not generally
allowed for the installation of control devices such as FGD systems;
this tends to make switching to scarce low-sulfur fuel a preferred
control alternative. The panel feels that State public utility
commissions should treat increased costs from FGD control in the
same manner as increased fuel costs are treated.
The capital cost to the utility industry of installing FGD,
while substantial, will not be great in comparison to projections of
total future capital investments of the industry. Using an average
of $60 per kilowatt, the 90,000 megawatts of scrubbing needed by 1980
to meet primary standards amounts to an investment of about $5.^ billion.
Assuming an annual inflation rate of 7-5 percent, the installation
of scrubbers will increase the industry's capital requirements only
U percent through I960 (based on a projected expenditure of $195 billion
between 197^ and 1980 for generation and transmission facilities).
Included in the cost of flue gas desulfurization is an energy
penalty resulting from the operation of the scrubber. This amounts
to a penalty of U to 7 percent of energy produced at an individual
plant.2 Nationwide, however, this energy penalty is not large in
comparison to the environmental benefits received. Using a national
average of a 5-5 percent energy penalty for those plants operating
FGD systems, the total electricity used by FGD systems in 1980 will
only be about 1 percent of the total electricity projected to be used
in that year.l
•^-Economic and Financial Implication of the Federal Water
Pollution Control Act of 1972 for the Electric Utility Industry,
prepared under EPA contract no. 68-ol-1582, Temple, Barker and
Sloane, Inc., Wellesley Hills, Massachusetts, September 1973.
testimony, Frank Princiotta, EPA, p. 38.
56
-------
The hearing panel finds that while the costs of installing
and operating needed FGD systems will be substantial, the overall
national costs will not impose an undue burden on either the electric
utility industry or its customers. Although the national costs discussed
above are based only on FGD needs to meet primary ambient air quality
standards, the additional needs to meet other requirements of State
implementation plans are not expected to be so large as to change
this conclusion.
57
-------
TABLE 8-1. CAPITAL AND ANNUAL COSTS FOR FGD SYSTEMS
COMPANY
PLANT CAPACITY CAPITAL ANNUAL BASIS
(Mw) COSTS COSTS FOR
($/kv) (mills/kw-hr) COSTS
COMMENTS
WITNESS,
AFFILIATION
AND PAGE
NUMBER
Lime/Limestone systems - Retrofit
Typical 200
52
2.U
Estimate
Northern
vn Indiana
00 Public
Service
Northern
Indiana
Public
Service
Bailly
7,8
615
62
Estimate
Bailly
7,8
615
1*7
U-6
Estimate
Assumes 80% load
factor. Annual
costs include
facilities for
waste disposal
and environmental
controls to mini-
mize land and
water pollution.
Does not include
sludge ponds
(Not enough land
for on-site dis-
posal. )
Does not include
sludge ponds. Cap-
ital investments
required for
sludge treatment
included. Annual
costs include fix-
ation and hauling.
55/S load factor.
Princiotta,
EPA, p. 55
Kuhlman,
Sargent &
Lundy (NIPSCo
consultant),
p. 589
Gerstle,
PEDCo (EPA
consultant),
pp. 660-661
-------
TABLE 8-1 (continued). CAPITAL AND ANNUAL COSTS FOR FGD SYSTEMS
VI
VO
COMPANY
Public
Service
Co. of
Indiana
Public
Service
Co. of
Indiana
Detroit
Edison
PLANT CAPACITY
(Mw)
Wabash 880
River
Vabash 880
River
St. Clair 170
CAPITAL
COSTS
($/kw)
68
•66
50
ANNUAL
COSTS
( mills /kw-hr)
3.2
3-7
j
BASIS
FOR
COSTS
Estimate
Estimate
Estimate
COMMENTS
Includes sludge
disposal area
facilities. 68$
load factor.
Sludge disposal
included. Sludge
pumping included
in annual costs.
66% load factor.
Includes pond for
sludge disposal
WITNESS ,
AFFILIATION
AND PAGE
NUMBER
Kolf lat ,
Sargent &
Lundy (PSI
consultant ) ,
p. 703A
Gerstle,
PEDCo
(EPA con-
sultant) ,
pp. 820-821
Willett ,
Peabody En-
West Perm
Power
Mitchell
U70
62
but not the cost gineering
of land. (Detroit
Edison, vendor)
p. 2282
Estimate Does not include Gerstle, PEDCo
sludge pond costs (EPA consultant),
(pond is already p. U29
constructed).
Annual costs in-
clude sludge fixa-
tion and hauling.
70S? load factor.
-------
TABLE 8-1 (continued). CAPITAL AND ANNUAL COSTS FOR FGD SYSTEMS
COMPANY
Louisville
Gas &
Electric
Public
Service
Co. of
New Mexico
TVA
Duquesne
Light
Commonwealth
Edison
Lime/Limestone
PLANT
Paddy ' s
Run
San Juan
1,2
Widows
Creek 8
Phillips
Will
County 1
Systems -
CAPACITY
(Mw)
70
670
550
380
155
New Plants
CAPITAL
COSTS
($/kw)
57
1*5-60
76
70-75
108
ANNUAL BASIS COMMENTS
COSTS FOR
(mills/kw-hr) COSTS
Experience
Estimate
Estimate
2.11 Estimate & Annual cost does
experience not include an-
nualized capital
costs .
10 Experience Includes sludge
treatment . 35$
load factor.
WITNESS ,
AFFILIATION
AND PAGE
NUMBER
Mayrose, LG&E,
pp. 12U2-121+3
Geist, Pub.
Service Co. .of
N. Mexico,
pp. 11*78, ll*86
Seeber, TVA,
p. 2318
Pernick,
Duquesne Light ,
p. 1566
Lee, CommEd,
pp. 2079-2080
Typical 1000
35
1.5
Estimate Assumes 80% load Princiotta, EPA,
factor. Costs p. 55
include facilities
for sludge dis-
posal and environ-
mental controls for
land and water
pollution.
-------
TABLE 8-1 (continued). CAPITAL AND ANNUAL COSTS FOR FGD SYSTEMS
COMPANY
PLANT CAPACITY
(Mw)
CAPITAL
COSTS
($/kw)
ANNUAL
COSTS
(mills/kw-hr)
BASIS COMMENTS
FOR
COSTS
WITNESS,
AFFILIATION
AND PAGE
NUMBER
Kansas LaCygne 1 820
City Power
& Light
Ohio
Edison
Mansfield 1600
Commonwealth Powerton 8UO
Edison 6
U2
93
72-86
2.7
MgO Systems - Retrofit
Boston
Edison
Mystic 6
155
39
Experience McPhee,
KCP&L,
p. 1U36
Estimate Capital costs Mansfield,
include sludge Ohio Edison,
disposal. Assumed p. 2170
100% load factor.
Bids Lee, CommEd,
p. 2079
Also in CommEd*s
written submittal
dated 10-12-73
III-D-6
Estimate & Includes cost of Irving, Boston
experience calciner facility Edison, p. 1363
but not of acid
plant (acid plant
is responsibility
of chemical con-
tractor )
Cat-Ox Systems - Retrofit
Illinois
Power
Wood
River
880
77
Experience 68.5$ load
(capital factor.
costs)
Estimate
(annual
costs)
Shultz,
Illinois Power,
pp. l6ll-l6l2
-------
9- Time Requirement for Installation of Flue Gas Desulfurization
Systems
One of the aims of the hearing was to determine the time required
to install flue gas desulfurization systems on power plants. Much infor-
mation was brought out on this subject; a total of some IT organizations
presented their views, based on either estimates or actual experience.
The installation times discussed ranged from 27 to U8 months for direct
installation of full scale FGD systems and from Ul to 51* months for full
scale systems installed in the course of a modular or developmental
program. The time estimates were distributed by witness experience as
indicated below. (Figures were adjusted to a common basis.) Details on
individual inputs are given in Table 9-1•
Time from Decision to
Number of put in SOg Control to
Experience of Witness Inputs Compliance (months)
Actual installations 6 27 to 36
Estimates by EPA consultant 1 27
Estimates by utilities and utility 3 36 to U8
consultants
Estimates by vendors 2 30 to 36
Various estimates involving a 5 Ul to 60
modular or developmental program
The greatest weight should be given to the testimony concerning
the actual time it took to install currently operating systems. Instal-
lation times will, of course, vary with the situation. Variables affect-
the time requirements include the size of the plant, the type of FGD
system installed, and the difficulty of retrofit.
The testimony leads the panel to conclude that the time neces-
sary to install a full scale FGD system will generally be from 27 to 36
months from decision to install FGD to compliance with emission regula-
tions. This can be broken down into the following stages: signed con-
tracts in 6 to 9 months, construction begun in 8 to 11 months, startup
in 21 to 30 months, and compliance in 27 to 36 months.
This schedule could be shorter or longer, depending upon the
many factors affecting particular installations. These include such
localized factors as labor, parts delivery, and more general factors
such as the limited vendor capacity discussed in this report. An
important consideration in scheduling is the restriction on when
63
-------
systems can be tied in to the generating facility. The actual time
required to tie in an FGD system to a boiler unit is only a few weeks.
However, because the boiler must be out of operation during tie in, timing
would have to be planned carefully so that the overall generating system
would still produce adequate power. For a utility company which munt
install FGD systems at several plants, the tie in operations at each
plant would have to be properly sequenced.
These time frames assume that the utility will proceed to install
a full scale FGD system with no piloting or experimentation. In those
cases where a developmental program is required, completion of the full
scale system could take 12 to 36 months longer depending upon the degree
of experimentation. Piloting of a new system would require the greatest
additional time.
The more typical "front-end modular" approach discussed at the
hearing is the case where one FGD module is installed and operated for
a few months before installation of the full FGD system. In such in-
stances, the additional time is used to optimize operating parameters
and possibly to investigate innovations in process. In many cases the
modular approach is not necessary and installation of a full scale system
can proceed directly through the usual steps of construction, tie in,
shakedown, and compliance. However, in some situations, such as the
installation of a new type of system, use of the modular approach could
be appropriate. A reasonable schedule for installation of a full scale
system via the modular approach will generally be from 1*1 to 51* months.
64
-------
TabU 9-1. TIMS REQUIRED TO INSTALL FED SYSTEM)
IP
=1
isT Hit 11
(CO
.
6,
6 i
. 9 I/
, 3 1/2
t B
npl lance (
6 nx
4 •
6 n
. 3 no*
„ 6»n
in ths
ipnths
months
jnths (su
nonths
14 mo
ijifer)
tfiths
i 18 mon
iths
ths
"" J
•
nlttal
iths "
E
j 1/2jn
•
hs
1,
12-18 months ' 20-24 months
Engineering '
Purchasing 1
Delivery j
12-18 months • 21 months
Equipment :
Manufacturers'*
Engineering 1 :
Fabrication :
6 months ^'- .. 19 months
: 36-40 months
•to agency)
24 months
'* 6 months . 18 months
is. 8 months 13 months
* (including . -
pilot) .
_ • _ 24 months
30 months :
36 months •
24 month;
24 month?
•13 months
24-i5 months
'24 months
• 20 muatns
i
i | Total Time
St S Reference for Compliance
Estimate by George 38-48
: C Kuhlman of Sar- months
'. NIPSCO (p 589
590)
Estimate by Tor 39-45
Korflat of Sargent months
Indiana (p 712)
Allowed under Pa 39 1/2
for West Penn Power
(p 2929 - 2931 )
StHes of Research
: Given by Gerstle of 27 months
PEDCo (f 664 - 665)
: Actual time for Approx.
; • PEPCo. 'p 2472 - 30 months
j, 2171)
•?e1*yjfv? Actual time as given 36 months1'2
-tOBrtWi- by Illinois Power
•a'-ST %% (p 1602-
Actual time as given Approx
... by Mr Mayrose for 30 months
' . IG I E (i> «n» -
1203)
Actual planned time 60 months?
for Philadelphia full
(p 1928)
Estimate of P S J6 months
(p 3098)
Allowed to Uhio 36 months2
12 mos. Utilities in Alan
> •< >• Farkas testinony
"shake-. (p 1417 »n« 1441)
. down
variance"
_. Actual at Lacvgne Aoprox 33
"•* (p 1459 - 146D) months
Written submit tal Approx 30
by Woods of Ariz months
__•* • Public Service
Excessive over-
time Participate
only (p 1699)
Actual time at Approx 27
"Crash program"
(p 2076 -2081)
Universal Oil Approx 36
Schedule as 34 months'
Duquesne Light .-
Company (p 1545 - J8 month*
1547. p 1578, totaj.
P 1595 - 1596 I compliance
submiUlil-
* TOi. i Jist1™te »y Ap,«rox 30
t f -31 "ivy Pn"Pr mnnlSr
* « *. Ga, (p 2469) '"U"1"'
Type of
Development
Full scale
large unit
Full scale
large unit
Full scale
larg° unit
Full scale
large unit
Full scale
demonstra-
tion unit
New process
Full scale
demonstra-
tion unit
New Process
Demonstration
unit
Full scale
medium-size
unit
Full scale
large unit
Full scale
large unit
Full scale
large unit
Full scale
medium-size
unit
Full scale
large unit
Pilot and
modiilar
approach
One year
operation
of module
Full-scale
large unit
Notes
Schedule requires all
equipment on site be-
fore construction
begins
Schedule requires all
equipment on site be-
fore construction
begins.
Assuming 3-month
startup
Assuming 6-month
startup
Delay due to major
modification
Actual startup about
3 months.
Characterized as
long due to
"developmental
nature"
May be paniculate
only
Does not Include
"shakedown"
Described as crash
program. Rcconnend
36 months
Crash program
Paniculate only.
Described as crash
program for
difficult retrofit.
34 montfts to to
partTcolaa
scrubbing only.
I - ,
'° no"-™"'-"n9 Codification due to natural
Bhleh
-------
During the course of the hearing, it became apparent that the
ability of vendors of flue gas desulfurization (FGD) systems to install
such systems could be a constraint to timely compliance with sulfur
oxide emission limitations. Two predictions of overall vendor capacity
were dicussed at the hearing: the Sulfur Oxide Control Technology
Assessment Panel (SOCTAP) final report on Projected Utilization of
Stack Gas Cleaning Systems by Steam-Electric Plants^ and the Industrial
Gas Cleaning Institute (IGCI) survey and analysis.2 In addition, some
individual vendors discussed their capacity for future installation of
scrubbers. Each prediction given was based on certain assumptions.
It is important to examine some of me key assumptions of each
of the reports. SOCTAP evaluated 15 sulfur oxide control system vendors
and projected that three or four could expand rapidly and that another
three or four could expand at a slower rate. The remaining seven to
nine vendors were considered to have unproven abilities and the panel
felt that they would not play an important role until the late 1970's.
SOCTAP also predicted that some new vendors would enter the market.
SOCTAP did use two "choke points" in their projections: one, the ability
of the vendors to sell their wares; and two, the ability of vendors to
bring systems on-line smoothly while continuing to take on new projects.
The potential for delays due to shortages in critical materials and
engineering and skilled construction manpower was considered in their
projections.
The IGCI conducted a survey of 2U vendors (including nonmembers),
asking for an assessment of each company's unconstrained capacity to
provide commercial sulfur oxide control systems. The IGCI analysis
essentially assumed that each vendor polled would provide 100 percent
of predicted capacity. This assumption may hold in the 1978-1980 period
as more vendors gain experience and the most promising systems are
licensed, but it is questionable for the 197^-1977 period because few
vendors have proven capabilities to supply scrubbing systems. In addi-
tion, IGCI stated that possible material and labor shortages were not
considered in their estimates.
Mr. Watt of Davy Powergas Co. stated that his company is handling
a current load of four or five projects^ and Mr. Singer of C.E. testified
that six projects are currently in his shop.'* Combustion Engineering pro-
jected that it would be able to handle nine additional projects by 1978.
The major problem now faced by the SOX control equipment vendors, as
stated by IGCI, is that "no market exists."
•*-Final Report: Projected Utilization of Stack Gas Cleaning S^'tems
by Steam-Electric Plants. Sulfur Oxide Control Technology Assess-
ment PanelTsOCTAP) Report to the Federal Interagency Committee.
U.S.E.P.A., Research Triangle Park, N.C. Publication No. APTD-
1569. April, 1973-
^Transcript, Sidney R. Orem, Industrial Gas Cleaning Institute,
p. 1839.
3Testimony, Stewart Watt, Davy Powergas, p. 2l*70.
^Testimony, Joe Singer, Combustion Engineering, p. 1292.
67
-------
Figure 10-1 shovs the cumulative need and cumulative vendor
capacity estimates made "by SOCTAP and by IGCI in megawatts of installed
capacity versus time. Also shown is the curve which the hearing panel
feels test estimates the ability of vendors to install scrubbing
systems.
Because orders must be placed soon for scrubbers to be installed
in 1976-1977> vendor capacity through that period is largely limited
by existing experience and capability of vendors. For this reason,
the panel believes that actual experience during this period will
likely follow the more conservative SOCTAP estimate. Capacity in
the later 1970's, however, will be dependent on the extent to which
additional vendors gain experience and the extent to which all vendors
increase their capacities. This increase will depend largely upon
the market the vendors envision. Assuming that States and EPA push
ahead vigorously with sulfur oxide compliance requirements, the panel
believes that actual experience during the later 1970's will most
likely approach the IGCI estimates.
It is important to stress that future vendor capacity will
depend upon expected demand. At the moment, capacity exceeds demand.
In addition, many vendors can gain experience only through the instal-
lation of scrubbers. The panel believes that its estimate of vendor
capacity will not be achieved unless firm compliance schedules are
established and vigorously enforced.
Figure 10-1 also shows EPA's best estimate of FGD needs (dis-
cussed in the Background section of this report) for existing coal-
fired power plants impacting primary standards and for new coal-fired
plants. On the basis of this estimate of FGD requirements and the
hearing panel's estimate of vendor capacity, it is clear that the
timetables of many State implementation plans (compliance by mid-1975)
will not be met.
The date by which all the requirements will be met is difficult
to estimate. Although Figure 10-1 leads to the conclusion that the
last scrubber needed by coal-fired power plants to meet primary ambient
air quality standards can be installed sometime in 1978, it must be
noted that scrubber needs for oil-fired power plants and for such
other sources as large industrial boilers were not included in the
analysis.
It is also important that Figure 10-1 does not estimate all
FGD needs for existing State implementation plans since these plans
require controls beyond those needed for attainment of primary stand-
ards. Although requirements related to attainment of primary standards
should receive priority over other requirements, the other requirements
must also be met and will add to the demand for FGD systems, partic-
ularly in the later 1970's.
68
-------
VO
125
FIGURE TO - t
CUMULATIVE NEED 8c VENDOR CAPACITY
— -I
TIME, YEARS
1-Includes new and existing coal-fired plants requiring controls to achieve primary
standards or new source performance standards.
-------
Vendor capacity is expected to constrain the rate at which
needed FGD systems can be installed; however, it is more important
that capacity currently exceeds the demand for these systems. Com-
mitments must now be made to order and install needed FC1D systems
and this effort should continue at the quickest possible rat«?; that
is, at a rate commensurate with vendor capacity.
70
-------
APPENDIX A_- Description and Summary
of Important FGD Processes
71
-------
A. Sulfur Product Throwaway Systems
1. Lime and Limestone Flue Gas Desulfunzation Processes -
Throwaway
Process
Several methods have been developed for the use of limestone and
lime slurries in a wet scrubbing process. The major variations are as
follows: (See Figure A-l)
(1) use of limestone (CaCO-j) added to the scrubber circuit
(2) use of hydrated lime (Ca(OH)2) added to the scrubber circuit
(3) use of limestone injected in the boiler affecting calcination
to lime with subsequent lime slurry scrubbing.
In all three process modes, a slip stream subjected to a dewatering
operation consisting of reaction products, flyash, and unreacted alkali is
discharged as waste to either a disposal pond or landfill site.
The overall reactions for limestone and lime scrubbing can be
represented by reactions (1) and (2) respectively:
( , CaC03 + S02 + l/2H20-»CaS03.1/2H20 + C02
(2) Ca(OH)2 + S02->CaS03.1/2H20 + l/Zh^O
History and Experience
There has been a considerable amount of bench model, pilot- plant,
and full scale activity since the early 1930's. Over the last 5 years
developmental activities have been particularly intense and 31 full scale
commercial systems have been ordered in the U. S. since 1968, of which 7
have started-up and have a backlog of operating experience.
The boiler injection plus wet scrubbing process has been extensively
tested on a commercial scale by Combustion Engineering, Inc., (C.E.) since-
1968. After 4 years of intermittent operation filled with numerous
technical difficulties, C. E. no longer offers this process; C.E. favors
the lime/limestone tail-end scrubbing process.
The first full scale installation in this country that uses lime-
stone introduced into the scrubbing circuit is the 175 megawatt Common-
wealth Edison Will County Station - Unit No. 1. This unit was started
up in February 1972, and has operated intermittently since then, achieving
S02 removal efficiencies in the range of 75 to 85 percent. The major
problems experienced to date have involved demister pluggage by a soft,
mud-like substance, system reliability caused by mechanical problems, and
finding an economic means for disposal of waste sludge. A great deal has
been learned in the past year at the Will County Unit concerning practical
operating problems with limestone scrubbing. None of the problems
encountered at this unit appear to be insurmountable.
72
-------
STACK
GAS
METHOD 1. SCRUBBER ADDITION OF LIMESTONE
CaS03+CaS04
TO WASTE
STACK ^
GAS W~
CaC03
CALCINER
•4 GAS TO STACK
Ca(OH)2
SCRUBBER
CaO
PUMP
TANK
SETTLER
CaS03+CaS04
TO WASTE
METHOD 2. SCRUBBER ADDITION OF LIME
GAS TO STACK
CaC03
BOILER
CaO GAS
SCRUBBER
PUMP
TANK
SETTLER
METHOD 3. BOILER INJECTION
CaS03+CaS04
TO WASTE
Figure A-l.
Major process variations for use of lime or limestone for
removal of SC>2 from stack gases.
73
-------
Additional valuable information concerning operation of lime/lime-
stone scrubbing processes is being gathered at the versatile EPA prototype
test facility at the TVA Shawnee Steam Plant. The 30 megawatt' facility
includes three types of 10 megawatt (equivalent) scrubbers (venturi, TCA,
and marble-bed), extensive process instrumentation, and sophisticated data
acquisition and handling systems. Tests to date have identified test
conditions which have led to reliable operation during tests up to 1 month
in duration.
The most recent successful operation of a lime wet scrubbing process
is the 70 megawatt installation at Louisville Gas and Electric Company's
Paddy's Run Station. The unit uses carbide sludge (Ca(OH)2) as the alkaline
absorbent. No scaling or plugging problems have been encountered in over
1000 hours of closed-loop operation since April 1972. The system has
demonstrated near 100 percent availability while removing 85 to 95 percent of
the flue gas from boilers fired with 3.5 to 4.0 percent sulfur. Waste sludge
is thickened, filtered, and disposed of as untreated landfill.
The most successful lime scrubbing system is Chemico's Mitsui
Aluminum Company's facility. This 156 megawatt power plant has been retro-
fitted with two Chemico dual-stage venturi scrubbing systems, each capable
of handling 75 percent of the full load gas flow. The system has demon-
strated reliable, trouble-free operation since being put on-stream in
March 1972. The plant is presently burning 2 percent sulfur coal (1800 to
2200 ppm inlet S02) and achieving 80 to 85 percent S02 removal from the flue
gas using _arbide sludge as the alkaline absorbent. Since coming on-stream,
the system has operated at near 100 percent availability. The absence of
scaling difficulties has been attributed to operational data developed by
Mitsui in extensive pilot plant tests (in Japan) and to precise pH control.
S02 Removal Efficiency
A survey of the seven companies having experience in full-scale
tail-end wet scrubbing shows that most companies will provide S02 removal
guarantees varying from 70 to 90 percent, or as required to meet EPA
standards.
Advantages and Disadvantages
The advantages of lime and limestone systems are as follows:
(1) relatively low capital and operating costs
(2) potentially high S02 removal efficiencies
(3) ability to simultaneously remove both SC>2 and particulates
(4) most fully characterized of flue gas desulfurization systems
The disadvantages are:
(1) requirement to dispose of large quantities of waste sludge in
an environmentally acceptable manner
74
-------
(2) If not carefully designed, a tendency toward chemical scaling,
plugging, and erosion problems.
Performance and Reliability Summary
Operating experience at the Mitsui, Shawnee , and Louisville Gas and
Electric scrubbers indicates that lime/limestone scrubbers which have the
alkali added to the scrubber circuit can be made to operate reliably. The
Mitsui unit in particular has demonstrated reliable operation of this
technology over 1 1/2 years.
However, experience at other facilities indicates that reliability
can be a problem if the systems are not carefully designed and operated.
Also, the boiler injection mode has proven to be a troublesome configuration
(Union Electric and KansasCity Power & Light units) prone to serious
operating problems.
2. Double Alkali Flue Gas Desulfurization Process - Throwaway
Process (See Figure A-2)
The many double alkali process variations involve the scrubbing of
flue gases with a clear liquor containing dissolved sodium or ammonium salts,
followed by treatment of the depleted liquor with lime or limestone in a
reaction producing a throwaway sludge for disposal and alkali liquor for
scrubbing. Typical reactions occuring in the scrubber and reaction tank,
respectively, are as follows for a sodium-based system:
(1) Na2S03 + S02 + H2
(2) 2NaHS03 + Ca(OH)2 — >Na2S03 + 3/2H20 + CaS03.l/2H20
History and Experience
In the United States primary developmental attention has been placed
on sodium-based double alkali systems using lime for regeneration. Important
pilot plant work has been performed by General Motors, FMC Corp., Envirotech,
A. D. Little/Combustion Equipment Associates, and Chemico.
Southern Co. is planning to test a double alkali system on equivalent
20 megawatts of coal combustion flue gas at the Sholz plant operated by Gulf
Power Co. in Florida.
Intensive development of double alkali systems has been performed in
Japan, with limestone used as the input alkali and gypsum produced as a
saleable product. Showa Denko has recently star ted -up a 156 megawatt system
on an oil-fired power plant. Two additional .150 megawatt units treating
oil-fired boilers using Kawasaki/Kureha technology are under construction
and will start-up in 1974.
S02 Removal Efficiency
Based on pilot scale results to date, S02 removal efficiencies be-
tween 90 and 99 percent are achievable at reasonable costs.
75
-------
FLUE
GAS
BY-PASS
FLUE
FEED'
H20
SCRUBBED
1 GAS
1
1
1
1
1
»,
n
SCRUBBER
SCRUBBER
EFFLUENT
i'ii
I MIXING I
| TANK |_»J
\
CAUSTICIZER
SCRUBBER
FEED
THICKENER
MAKE-UP
Na2C03
WASTE
CALCIUM
SALTS
Figure A-2. Double alkali process variation - sodium scrubbing with lime regeneration.
-------
Advantages and Disadvantages
The advantages oC double alkali systems include:
(1) relatively low capital and operating costs
(2) very high S02 removal efficiencies can be obtained
(3) use of clear solution scrubbing minimizes solids buildup and
erosion problems offering potential for high reliability
ability to simultaneously remove S02 and particulates
Disadvantages include:
(1) Requirement to dispose of large quantities of waste sludge in
an environmentally acceptable manner
(2) Design complexities necessary to deal with the following
problems :
(a) necessity to prevent excessive purge of N32S04 produced
as a result of oxidation (N32S04 is difficult to regen-
erate)
(b) necessity to avoid scrubbing with clear liquor saturated
with calcium sulfate which could lead to scaling problems
Performance and Reliability Summary
Based on pilot scale operating experience at General Motors, FMC
Corp., Envirotech, A. D. Little in the United States, and Kureha and Showa
Denko in Japan, double alkali systems offer potentially high S02 removal
(^•90 percent) with high reliability.
B. Saleable Product FGD Systems
1. Magnesium Oxide SC^ Scrubbing Process - Saleable Product
Process (See Figure A-3)
The Chemico/Basic MgO process utilizes an aqueous slurry of magnesium
oxide, magnesium sulfite and magnesium sulfate to scrub SC>2 from flue gas
streams. The major reaction involves the formation of additional magnesium
sulfite through combination of S02 and magnesium oxide. Magnesium sulfite
removed from the scrubber loop is dried and subsequently calcined to drive
off S02 and regenerate active MgO for return to the scrubber loop. The
regeneration can be accomplished either at the power plant site or at some
remote location since the magnesium sulfite and magnesium oxide are stable
solids capable of being shipped. The S02 generated in the calcining operation
can be converted to high grade sulfuric acid or to elemental sulfur by pro-
vision of the appropriate equipment.
77
-------
FLUE GAS
CONTAINING S02
VENTURI
ABSORBER
SCRUBBER
AIR
PUMP
Figure A-3. MgO slurry process - for flue gas free of participate matter.
-------
History and Experience
In June of 1970 EPA entered into an agreement with Chemico/Basic,
Boston Edison Company and Essex Chemical Company for construction and
operation of the Chemico/Basic Magnesia Slurry Process on the No. 6 boiler
at Boston Edison's Mystic Station in Everett, Massachusetts. The installa-
tion on this 155 megawatt oil-fired boiler was completed in May of 1972. The
year following completion of the system has been devoted to equipment modifi-
cations and investigations directed toward solving numerous operational
problems which developed. Most of the.- problems which were encountered were
of a materials-handling nature resulting from the character of the solids
generated in the scrubber loop. The fact that most of these problems have
been satisfactorily solved is demonstrated by the 85 to 90 percent avail-
ability factor for June and July of this year. Some equipment modifications
are continuing to improve operability.
An additional MgO system has recently been started in September of
this year at Potomac Electric Power Co.'s Dickerson Station. This unit will
handle one-half the flue gas from a 195 megawatt coal-fired unit. The system
is designed to accommodate flue gas from the burning of 3.0 percent sulfur
coal. Very early results are encouraging. An additional coal-fired applica-
tion designed and engineered by United Engineers & Constructors is nearing
completion at Philadelphia Electric's Eddystone Station. This unit, which is
due for a December 1973 startup, will handle the equivalent of 120 megawatts
with 2.5 percent sulfur coal fuel.
Advantages and Disadvantages
The major advantages to the MgO process are summarized as follows:
(1) sulfur can be recovered as high grade acid or elemental sulfur
depending upon equipment provided for regeneration
(2) regeneration can be accomplished at a location quite distant
from the power plant (for instance, at an existing sulfuric
acid plant) thus permitting the use of a central regeneration
facility servicing several flue gas cleaning locations.
(3) by maintaining adequate inventories of MgO, extended outages of
the regeneration facility can be tolerated without interruption
of the pollution control facility.
(4) process reliability has benefitted from the modifications and
investigations at the Boston Edison site and will continue to
improve as the two additional systems (Potomac and Philadelphia)
become fully operational in the near future.
The major disadvantage of the process is the lack of reliable long
term operating experience and a lack of experience with coal fired power
plants.
S02 Removal Efficiency
The MgO process is capable of achieving 90 percent S02 removal over
a wide range of inlet S02 concentrations.
79
-------
Performance and Reliability
The experience to date at Boston Edison has established the capa-
bility of the process to consistently achieve 90 percent 502 removal. Also,
the high turndown capability and the reliable operation of the venturi
scrubber configuration used at Boston Edison have both been established.
The reliability of the entire MgO process has not as yet been established
through long term operation; however, the on-stream time at Boston Edison
has improved with the various modifications to achieve an 85 to 90 percent
availability for June and July 1973. Modifications to improve system
reliability are continuing.
2. Wellman-Lord Flue Gas DesulEurization Process - Saleable Product
Process (See Figure A-4)
The Wellman-Lord (W-L) SC>2 Recovery Process utilizes a sodium sulfiLe-
sodium bisulfite solution to absorb S02 from flue gas. The spent absorbent,
rich in bisulfite, is processed in a steam-heated evaporator, regenerating
active sodium sulfite crystals and producing a stream of S02 for further
processing. The process, depicted in simplest form is:
- Absorption
S02 + N32S03 + H20 —> 2NaHS03
- Regeneration
2NaHS03 ^ Na2S03 * + S02 /N + H20f
heat '
Inactive sodium sulfate is formed by three mechanisms: 863 absorption,
disproportionation, and sulfite oxidation. Sodium sulfate must be purged
from the system in order to maintain adequate levels of active sulfite in the
absorber/evaporator loop.
History and Experience
Patents for the W-L Process were filled in 1966 and patent rights
are currently held by Davy Powergas, Inc., Lakeland, Fla. Two Japanese firms
are licensed to market the system. There are currently seven operating
plants in the U. S. and Japan including two oil-fired boiler applications.
Additionally, more than ten systems are on order, including five more boiler
applications. The earliest operating W-L System is the sulfuric acid plant
application at Paulsboro, New Jersey, which has been operating since July of
1970. The earliest boiler application is the industrial boiler (oil-fired)
at Japan Synthetic Rubber Co., Chiba, Japan. This unit, equivalent to 75
megawatts, has been operating successfully since August of 1971 and has an
excellent on-stream factor of 97 percent since that time. It is worthy of
note that both Japan Synthetic Rubber (JSR) and Olin Corporation (owner of
the Paulsboro system) have ordered additional systems, thus attesting to the
satisfactory performance of the W-L System. Standard Oil of California pur-
chased a W-L System for Glaus Plant tailgas cleanup which was started in June
80
-------
NaOH
MAKEUP
I
DESULFURIZED
STACK GAS
REHEATER AND
BLOWER
ABSORBER
1
PRESCRUBBER
f
FLUE GAS
N32S03
NaHS03
H20
DISSOLVER
T N32S03
I SLURRY Na2S04
Na?S03
NaRS0
S02
CONDENSER
EVAPORATIVE
CRYSTALLIZER
STEAM
J
j
PURGE TO WATER TREATMENT
Figure A-4. Wellman-Lord process schematic.
-------
of 1972. As a result of the performance of the unit, Standard has ordered
three additional W-L Systems for other locations.
The largest unit in operation is on a 220-megawatt oil-fired
utility boiler operated by Chubu Electric in Japan. This unit has been
operating since Mav of this year with particular success in minimizing the
quantity of sulfate purge by fractional crystallization of sodium sulfate
from the absorber effluent liquor.
EPA has undertaken demonstration of the W-L System on a 115 coal-
fired boiler at NIPSCO's D. H. Mitchell Station in Gary, Indiana. The
capital cost of the system is being cost-shared on a 50-50 basis with the
using utility, NIPSCO, and the demonstration year is scheduled to start in
Spring of 1975. In the case of the EPA/NIPSCO demonstration unit, the W-L
System will be mated with the Allied Chemical S(>2 Reduction Process to pro-
duce elemental sulfur. Allied Chemical will operate and maintain the W-L
Allied System under contract with NIPSCO.
S02 Removal Efficiency
W-L Systems have obtained greater than 90 percent S02 removal
efficiency for commercial systems operating for long periods of time.
Advantages and Disadvantages
The V. L process has several major advantages as follows:
(1) simplicity and reliability of the various unit operations in-
volved
(2) when mated with the proper process, ability to produce elemental
sulfur, or high grade sulfuric acid
(3) potential to achieve high efficiency S02 removal when required
(95 percent or better)
(4) provided with surge capacity before and after the absorber to
handle flue gas surges and to enhance system reliability
(5) the many applications and considerable operating experience pro-
vide a high confidence for success in future applications
Major process difficulties and disadvantages are:
(1) need to sell or dispose of a quantity of purge solids (sodium
sulfate and other sodium salts)
(2) high energy demand results in derating of power station (3 to 6
percent)
(3) no coal-fired applications in operation
82
-------
Performance and Reliability Summary
Operating W-L Systems have consistently achieved SC>2 removal
efficiencies in excess of 90 percent for a wide range of S(>2 inlet con-
centrations. The most significant development efforts to date have been
in the areas of reduced capital costs and minimization of purge requirement.
As a result of process modifications which have now been proven in various
operating systems, purge requirements of 5 percent or less of inlet sulfur
can be anticipated.
Both the inherent high reliability of the equipment involved in the
W-L process and the actual operating experience (97 percent on-stream factor
over a 2 year period at the JSR boiler installation) point to an availability
in excess of 95 percent. The high system reliability would be enhanced in
large scale systems due to the opportunity for greater use of equipment spares
and partial system operation as a result of multi-train configuration. The
current practice of providing absorbent surge capacity permits short-term
shutdown of the regeneration process without interruption of the scrubbing
capability.
3. Catox Flue Gas Desulfurization Process - Saleable Product
Process (See Figure A-5)
The Monsanto Cat-Ox process utilizes catalytic oxidation to convert
most of the S02 present in the flue gas stream to 503 for subsequent removal
by an acid absorbing tower (followed by a fiber-packed mist eliminator to re-
move H2S04 mist). For retrofit or "reheat" applications, the flue gases
emerging from the boiler are passed through a high efficiency (99.6 percent
precipitator)and then heated ("reheated") to 850°F as preparation for the
catalytic oxidation step. The strength of acid produced in the absorbing
tower LS280 percent, which is primarily suitable for use in fertilizer pro-
duction.
History ancl Experience
The Cat-Ox process was piloted on a 15 megawatt scale for 2 years
commencing in August of 1967. Based on the successful pilot operation,
agreement was reached in June 1970 between EPA, Illinois Power (IP), and
Monsanto to install and operate a demonstration Cat-Ox system on a 110 mega-
watt coal-fired boiler at IP's Wood River Station at East Alton, Illinois.
Construction of the system was completed in July of 1972 and after a con-
siderable debugging period, the system was acceptance-tested in July 1973.
However, because of the present lack of availability of natural gas, the
reheat burners must now be modified to provide the capability for 100 percent
firing on fuel oil. This has occasioned another delay which will preclude
commencement of the year-long demonstration program until approximately
April 1974.
S02 Removal Efficiency
During the acceptance test, the Illinois Power system achieved the
emission control guarantees of 85 percent S02 removal and 99 percent
83
-------
STACK
OIL OR
GAS
FIRED
FURNACE
CAT-OX
MIST
ELIMIN-
ATOR
a:
STORAGE
ABSORBING
TONER
I
SULFURIC
ACID
ACID
COOLER
Figure A-5. Reheat Cat-Ox process.
-------
particulate removal. Removal efficiencies of greater than 90 percent are
achievable with this technology for many applications.
Advantages and Disadvantages
The Cat-Ox Process advantages are as follows:
(1) Generates a product, which, in certain limited locations, can
be disposed of by sale
(2) operating costs are relatively low
(3) achieves consistent 85 percent or better S02 removal over a
wide range of S02 Input concentrations
The major process difficulties and disadvantages are:
(1) Cat-Ox must be used near an appropriate acid user and dilute
acid can be difficult to market in large quantities in some
locations
(2) capital costs are high
(3) reliability and maintenance costs are not currently established
due to a lack of operating experience
Performance and Reliability Summary
Work to date at the Wood River demonstration site has established
the capability of the system to achieve 85 percent S02 removal; however,
no information is available regarding system reliability or any possible
performance degradation as a function of operating time. It should be
noted, however, that the process and equipment are similar to the standard
contact acid process and that major reliability uncertainties associated
with the process center around the ability of the precipitator to provide
adequate particulate removal to protect the catalyst bed.
85
-------
APPENDIX B - Summary of Operational
Experience with Full
Scale FGD Units in the
United States S Japan
87
-------
A. Operational Experience on U. S. Installation
Process: Boiler Injection of Limestone Followed by Wet Scrubbing
Process Supplier; Combustion Engineering
Constructor; Combustion Engineering
System Location; Union Electric Co., Meramec unit 2, St. Louis, Mo.
Start-Up Date; September 1968
SYSTEM DESCRIPTION AND HISTORY OF OPERATION
This 140 MW unit, the first full-scale utility S02 control system in
this country, was officially shut down and abandoned in December 1971
approximately three years after its inception. This system consisted of
two parallel single-stage marble bed absorbers equipped with demisters
and reheaters. It was operated with some clarified liquor recycle.
The reason for abandonment was massive plugging and scaling in the
entire boiler and S02 removal system. This recurrent problem barred the
company from keeping the generating unit going for long periods. It has
been said, however, that the up and down operation of the boiler necessitated
by scrubber problems, due to the fact that no provisions for gas by-pass
had been made, may have compounded the problems by causing moisture to
combine with powdery deposits on the boiler tubes to form concrete-like
deposits during periods of boiler shutdown. The implication is that boiler
plugging might ha
-------
Process: Limestone injection in boiler with throwaway product.
Process Supplier: Combustion Engineering.
Constructor: Combustion Engineering.
System Location: Kansas Power and Light, Lawrence, Kansas, Units No. 4 & 5.
Startup Date: December 1968 and November 1971.
The 125 mw Unit No. 4, started up in December of 1968, was one of
the first attempts to design a full size S02 scrubber. The limestone
injection method was used. Multiple problems occurred during early
stages of operation including corrosion, plugging of lines, and problems
with reheaters and demisters. These problems did not include scaling.
During the first four months of 1971, modifications in the original
design enabled operation with some reliability.
•
When the scrubbers for the much larger 420 mw unit No. 5 started
up in November 1971, the pond which was common to both units became
overloaded and scaling occurred. Modifications in the design have been
made that enable these chemical problems to be reduced but mechanical
problems remain. At the present time, the modular arrangement enables
the scrubbers to be cleaned without necessitating shutdown of the boiler.
The experiences at Lawrence have proved invaluable in making changes
fiv lar.er Combustion Engineering units such as the successful Paddy's Run
o1«nl. [he Lawrence Station is, however, set in much of its design as
a boiler injection system and in the closeness of the demisters to the
absorbing bed. It, therefore, cannot fully benefit from the knowledge
that has come from the operation of it and other systems.
Kansas Power and Light is able to operate a limestone SC^ scrubbing
sys'ero with significant S02 removal and some reliability while serving a
lar^e utility generating plant. This is a milestone in the development
of SO;, control technology.
89
-------
Process: Limestone Scrubbing with Throwaway Product
Process Supplier: Babcock fi Wilcox
Constructor: Babcock fi Wilcox
System Location: Commonwealth Edison Co., Will County Station No. 1,
Romeoville, 111., near Chicago
Start-Up Date: February 1972
SYSTEM DESCRIPTION AND HISTORY OF OPERATION:
Will County Unit 1 with scrubber on line, has a net power output of
156 MW. The system consists of two identical parallel wet limestone
scrubbing trains, each consisting of a venturi for particulate removal,
followed in series by a turbulent contact absorber (TCA) for S02 absorption.
Each absorber and scrubber is equipped with its own recirculation tank.
Spent slurry is bled to a clarifier which produces liquor for recycle via
a 5 acre pond and a thickened sludge (underflow) which is pumped to a
ready mix concrete truck where additives are mixed with the sludge in an
attempt to make the sludge acceptable as landfill.
Since Feb~uary 1972, the SOX control systems have operated inter-
mittently Generally, SOx removal efficiencies in the 80-90% range are
attainable during periods of operation. Chemistry is not considered to
b'~. =. problem wi'th the system. Problems which have been responsible for
shutdown of the system can be classified as mechanical, and were not all
•ittributable to the SOX control system. Some of the problems attributed
Co the limestone SOx control system are: (1) demister and rcheater pluggagc;
(2) wearing and plugging of spray nozzles; (3) reheater vibration and stress
corrosion cracking; (4) plugging of slurry lines; (5) "sulfite blinding"
of limestone and (6) scaling. Some of the other reasons cited for system
outage are: (1) expansion joint failure; (2) inspection; (3) boiler outage;
(4) motor failure; (5) contractor and operator errors; (6) fan trip;
(7) water loss to pump glands; (8) fan damper operation; (9) leaks in
slurry lines; (10) limestone supply and (11) booster fan vibration.
Solutions to almost all of the problems do not require development
of new technology. Methods of controlling all of the problems specific to
limestone wet scrubbing except for the reheater problems, have been used
with some degree of success at Will County. Installation of inconel
alloy reheater tubes is expected to solve the reheater stress corrosion
cracking problem. Plugging is avoided by maintaining adequate flow of
slurry. Scaling is controlled by circulation of high solids slurries and
using adequate liquid/gas ratios. Uemister pluggage is minimized by good
demister wash techniques. Wear of nozzles is controlled by proper selection
of materials of construction.
Between February and December 1972, the two SOX control trains have
accumulated in excess of 1400 and 1200 hours of operation respectively.
During the outage periods many improvements and repairs were made. One of
the trains has been shut down since April 1973 and presently is being canni-
balized to support the other. Commonwealth Edison is attempting to iron out
the problems with one train before attempting to operate both simultaneously.
90
-------
Process; Magnesium Oxide Scrubbing with. Thermal Regeneration
Process Supplier; Chemical Construction Corporation (Chemico)
Constructor; Chemical Construction Corporation
System Location; Boston Edison's Mystic Station
Everett, Massachusetts
Startup Date; April 1972
System Description and Operational History;
The MgO system which has been applied to the 150 MW oil-fired boiler
at Boston Edison's Mystic Station utilizes a venturi scrubber to contact
the magnesium oxide-magnesium sulfite slurry with boiler flue gases. The
solids removed from the scrubber, rich in magnesium sulfite, are dried in
a direct fired rotary dryer. The dried solids are shipped by truck to
the Essex Chemical Company contact acid plant in Rumford, Rhode Island
where the magnesium sulfite is calcined. The S02 produced by the calcining
operation is converted t;o high grade sulfuric acid and the MgO produced
is shipped back to Mystic Station for reuse in the absorber.
In April 1972, the shakedown period began for the Mag-Ox scrubbing
system. The venturi scrubber has operated intermittently since then due
to mechanical difficulties. During operation, the scrubber has achieved
SO2 removal efficiencies in excess of 90% with no apparent scrubber-related
problems. The major problem has been with the design and operation of the
MgS03 crystal dryer. Redesign of the dryer and a change of fuel to a low
viscosity oil appear to be resolving these problems. Other problems with
centrifuging the sulfite crystals from the scrubbing liquor and properly
calcining the sulfite to regenerate MgO appear to be manageable. An
availability factor of 85-90% was achieved for June and July of 1973.
This project is quite important because it will be the first time the
individual steps of scrubbing, centrifuging, and calcining on an integrated
basis for the Chemico process have been combined. Partially funded by EPA,
the project involves not only the scrubber, centrifuge, and dryer at the
Boston Edison plant but also the calcining and acid plants at Essex Chemical
Company in Rumford, Rhode Island.
The first large scale coal-fired application was started up in September
of this year at the Dickerson Station of Potomac Electric and Power. Flue gas from
approximately 100 MW of the 195 MW of Dickerson Unit 3 will be processed.
Since the plant burns coal (3% S, 8% ash), the scrubbing facility uses one
venturi scrubber to remove the particulate and a second to remove the S02-
Regeneration of MgO for this system will be carried out at the Essex Chemical
facility which also serves the Boston Edison system.
91
-------
Process; Cat-Ox
Process Supplier; Monsanto Enviro-Chem Systems, Inc.
Constructor; Leonard Construction Co.
System Location; Illinois Power Company, Wood River Station
East Alton, Illinois
Start-Up Date;
Construction was completed in July 1972 followed by debugging and
modification. Acceptance testing was completed July 1973 with full
operation to commence April 1974 following provision of additional
modifications.
System Description and History of Operation;
The retrofit or "reheat" version of the Cat-Ox System has been installed
on the 110 MW coal fired Wood River No. 4 boiler operated by Illinois Power.
The process accepts flue gases from the discharge of a specially provided
high efficiency ESP. The gases are heated to 850°F by heat exchange with
processed gases from the catalytic converter and by supplemental "reheat"
burners. The heated gases pass through the fixed bed catalytic converter
where S02 is oxidized to SO-}. An acid absorbing tower followed by a fiber
acid mist eliminator serve to remove the 803 prior to discharge of the
flue gas to the stack. Product acid is cooled and stored in tankage.
Since its completion in July of 1972, a series of mechanical difficulties
have occurred and modifications or repairs have been effected. During July
of 1973 an acceptance test was conducted which established the capability
of the system to achieve the specified 85% SC>2 removal while producing an
acid product of somewhat greater than the required 77.7% concentration.
Also, subsequent testing of the high efficiency ESP has established the
particulate removal to be sufficient to prevent undue costs for catalyst
cleaning. Long term operation of the system has been delayed until April
of 1974 due to late delivery of equipment for a planned system modification
to permit operation of the reheat burners on fuel oil rather than natural gas,
92
-------
Process: Limestone scrubbing with throwaway product.
Process Supplier; Combustion Engineering.
Constructor:Combustion Engineering.
System Location; Kansas City Power and Light, Hawthorn Station,.
Units No. 3 and 4.
In September 1972, the 100 mw Kansas City Power and Light's
Hawthorn 3 and 4 started up. Each of the boilers was originally
equipped with a boiler injection system and two identical scrubber
modules. Unit No. 4 has recently been converted to a tail-end
system. Before changing to a tail-end system, boiler pluggage
problems were experienced on Unit No. 4. Unit No. 3 still uses
boiler injection and has not experienced boiler pluggage. No problems
have been reported with .the fans or reheaters on either unit. The
remaining problems appear to be primarily with the recirculation
system. Modifications similar to those used successfully at
Combustion Engineering's scrubber at Louisville Gas and Electric
Company's Paddy's Run plant show great promise of overcoming these
problems. These include problems with headers and drain pots.
Demister pluggage has been a problem but this appears to be solved.
Some settling has occurred in the recirculation tank but this should
be corrected with Improvements in the agitation of the tank.
The method of ultimate sludge disposal has not been decided upon.
Enough land area is available to enable them to pond the sludge for
up to 15 years.
This plant is the last plant Installed by Combustion Engineering
using the limestone injection technique. Removal efficiencies have
been between 70 and 80 percent.
93
-------
Process: Limestone scrubbing with throwaway product.
Process Supplier: Babcock and Mil cox.
Constructor: Babcock and Mil cox.
System Location; Kansas City Power and Light, LaCygne Station, Unit No. 1.
Startup DaTelJune 1973.
The S02 scrubber at the new 820 row LaCygne Station started operation
in February 1973. The system consists of seven modules. At present, one
module is controlling $62 and parti oil ate with a venturi scrubber and a
grid plate scrubber. The limestone is added to the scrubber rather than to
the boiler.
The remaining six modules at LaCygne are controlling particulate only
using the venturi section. The grid plate will be installed and limestone
added at a future date to control SOg for the entire plant.
It is too early to accurately assess the reliability of this system
since the boiler is new and has not become fully operational yet. The
system is essentially a duplicate of the Will County scrubbing system and
has experienced many of the same problems. These include plugging of the
demisters, corrosion of the reheater tubes, and other mechanical problems.
Like Will County", the problems are mechanical in nature and solvable using
state-of-the-art methods. It is worthwhile to note that no chemical problems
with the scrubber itself have occurred. It appears likely that the system
will achieve reliable operation in the near future.
Unlike Will County, there are no bypass provisions at LaCygne, and
no electrostatic precipitators are installed to collect particulate. The
scrubbers are expected to achieve 80 percent control of S02 as well as
satisfactory control of particulate.
One year hold time is available for sludge disposal. Plans beyond
that time are uncertain.
-------
Process: Lime Scrubbing with Throwaway Product
Process Supplier: Combustion Engineering
Constructor: Combustion Engineering
System Location: Louisville Gas and Electric Company, Paddy's Run
Station No. 6, Southwest of Louisville
Start-Up Date: April 1973
System Description and History of Operation:
The SOX control system installed on this 70 MW electric generating unit
consists of two parallel, two-stage marble bed scrubbers installed downstream
of an electrostatic precipitator. The scrubber effluent liquor enters a large
reaction vessel from which some spent liquor is bled to a thickener followed
by a rotary drum filter. A carbide sludge slurry which contains lime as the
active ingredient is fed to the reaction vessel. This absorbent slurry feed
is controlled by a measurement of acidity in the system, and changes as
necessary with variations in SOx throughput. SOx throughput varies with
boiler-generator load and with variation of fuel sulfur content.
Between April and August 1973 the unit has accumulated about 1000 hours
of operation. The scrubbers have operated for periods of up to 10-12 days
with no problems. SOX removal has been in the 90% range. There has been
no evidence of scaling or plugging. Erosion/corrosion has not been a problem.
There have been some minor mechanical problems.
The demisters, two stages of standard chevron, have not been a problem.
Demister wash is accomplished once every eight hours with high velocity
fresh water at the bottom of the demister. The amount of water used is only
that amount needed to make up for normal evaporation and losses with the
throwaway sludge. Thus, the system is operated as close to closed loop
operation as can be expected.
The limited operation, overall, has not been due to problems for the
most part, but due to the lack of operating manpower. During the peak demand
periods, when all the Paddy's run units were on line, LG&E has had to shut
the scrubber system down since operating manpower was spread thin and operation
of the electric generating equipment took first priority.
95
-------
B. Operational Experience on Japanese Installations
Process: Soluble sodium scrubbing with thermal regeneration (Wellman-Lord)
Process Supplier: Davy Powergas.
Constructor: Mitsubishi Chemical Machinery Company.
System Location: Japan Synthetic Rubber Company (JSR) near Chiba, Japan.
Startup Date: July 1971.
Successful reliable operation of the Wellman-Lord SOX control process
at Chiba with essentially 100 percent availability for over two years is
considered quite significant for the U. S. control situation. This process
consistently removes over 90 percent of the SOg from the exhaust gases of
a 75 mw equivalent oil-fired boiler. The lo-.d is essentially constant but
the concentration of S02 varies from 400 to 2000 ppm.
It appears that the process should be applicable to coal-fired boilers
if fly ash removal equipment is installed upstream of the absorber. A
Northern Indiana Power Service Company (NIPSCO) unit, partially funded by
EPA, will evaluate such systems on a coal-fired boiler. Cost studies indicate
that capital and operating costs for a Wellman-Lord system in the U. S. on a
coal-fired boiler are not a great deal higher than those for wet lime/lime-
stone or magnesium oxide scrubbing systems, which are generally considered
the least expensive of the flue gas desulfurization systems. The system
is commercially offered and guaranteed in the U. S.
The major problem with the process is the requirement for a bleed to
remove contaminants, primarily sodium sulfate (^SOA). Present information
indicates about 10 percent of the total incoming sulfur is lost as soluble
N32S04 at Japan Synthetic Rubber (JSR).
Sodium sulfate is a natural component of sea water but could possibly
cause problems in fresh water. This purge has been substantially reduced at
the newer installation at Chubu Power and may be further reduced by oxidation
retardants research by Sumitomo.
The product of the Wellman-Lord system at JSR is high-purity sulfuric
acid. While there may be insufficient markets for the sulfuric acid produced-
if a large percentage of the plants in the U. S. used this method, there
is probably a market available for the output of several plants, particularly
those in eastern and midwestern industrial areas.
Elemental sulfur, which will be produced in the NIPSCO unit, is another
potential product which is both storable and potentially saleable; this could
ultimately be a more desirable end product,especially for utilities not near
a market for sulfuric acid. A disadvantage of elemental sulfur production
is the necessity of the use of considerable quantities of a reducing agent
such as coke or natural gas.
96
-------
Process: Lime scrubbing with throwaway product.
Process Supplier; Chemical Construction Company (Chemico).
Constructor:MTtsui Miiki Machinery Company.
System Location: Mitsui Aluminum Company, Omuta Power Station, Japan.
Startup Date: March 1972.
The scrubber at Mitsui Aluminum's Omuta Power Station began operation
on March 29, 1972. The system uses as an absorbent carbide sludge that is
chemically identical to lime with regard to S02 scrubbing. The scrubber
serves a coal-fired 156 mw boiler that burns coal equivalent to about 2.5
percent sulfur eastern or midwestern U. S. coal. The scrubber has had
several load variations similar to, albeit less frequent than, typical U. S.
boilers. The system has, operated at closed-loop conditions for substantial
periods of time and is open loop only occasionally during periods of heavy
rain. Fly ash concentration into the scrubber IB similar to that for
typical U. S. retrofits.
The system has obtained 18 months of continuous, essentially trouble
free, operation since startup.
It should be noted that the reliable performance of this system is of
real significance to the United States air pollution control program, since
the design ground rules for the Japanese unit are quite similar to those of
many of our power utilities requiring desulfurization systems. The following
are among'the areas of commonality: retrofit of existing coal-fired boiler,
moderately efficient electrostatic precipitators, installation on moderately-
large size boiler, production of a throwaway product, and availability of lime
(calcium hydroxide). The unit takes on additional significance since the system
was designed based on U. S. technology (Chemico) and is offered and guaranteed
in this country. Two similar units using lime on coal boilers are being
constructed in the U. S. for Duquesne Light Company's Phillips Station and
Ohio Edison's Bruce Mansfield Station.
97
-------
Process: Sodium Scrubbing with Thermal Regeneration (Wellman-Lord Process)
Process Supplier: Davy Powergas, Inc.
Constructor: Mitsubishi Chemical Machinery (MKK)
System Location: Chubu Electric
Nagoya, Japan
Startup Date: May 1973
System Description and History of Operation:
The Chubu system is applied to a peaking service, oil-fired utility
boiler of 220 MW output. The system utilizes a rectangular sieve tray
absorber which has maintained SO outlet levels consistently below 150 ppm.
Double effect evaporation is utilized for regeneration and a purge
crystallization system is provided to minimize sodium loses through purge.
The purge crystals have assayed higher than 85% sodium sulfate. The
system is designed to treat flue gas from burning of 4% sulfur and to
handle changes in boiler load from 25% to 100%. Because of the peaking
service application, the system is subjected to frequent weekend shut-
downs with no restart problems encountered to date. It is noteworthy
that at one point during the recent testing program the boiler fuel was
changed from 0.7% sulfur oil to 4% sulfur oil instantaneously through boiler
operator error. In spite of this many-fold step change in inlet concen-
tration, outlet concentration of S02 remained below 150 ppm.
98
-------
APPENDIX C - Names and Affiliations
of Hearing Witnesses
99
-------
Allegheny County (Penna.) Bureau of Air Pollution;
FEIGENBAUM, Simon, Engineer
GORR, Wilpen L., Dr., Ohio State University
American Electric Power Service Corporation;
CLARKE, A.J., Head, Environmental Studies Group, Central Electric Genera-
ting Board, London, England
DICKE, Richard M., New York City Law Finn of Simpson, Thacher and Bartlett
DOWD, Joseph, Vice President & General Counsel; and Asst Secy of Ohio Power
Company
FLANNERY, David, Esq.
MARTINKA, Paul, Vice President, Fuel Supply
REEVES, Robert W., Head of Environmental Engineering.Div.
SMITH, Maynard, of Smith-Singer Meteorologists of Long Island
TILLINGHAST, John, Senior Executive Vice President in charge of Engineering
and Construction
Appalachian Research & Defense Fund;
RODECKER, Robert, Esq., Staff Attorney—appearing for Paul Kaufman, former
Director
Arizona Public Service Company;
NORTON, Bruce, Esq.
WOODS, Thomas G., Jr., Vice President, Engineering
Babcock and Wilcox;
GRIFFIN, E.M., Division Vice President, Power Generation Group
STEWART. J.F.. Foreman-Supervisor, Air Quality Control Section
BALET, William, Bureau of Power, Federal Power Commission
BALZHISER, Richard, Director, Fossil Fuel & Advanced Systems, EEI
BARNARD, Richard E., Manager, Commercial & Technical Development
BAUM, Robert, Deputy Asst Administrator for General Enforcement , EPA
BEARD, Carl G., II, Director, West Virginia Air Pollution Control
Commission
BENZIGER, Peter H., Vice President of Generating, Potomac Electric
Power Company
BETHELL, Thomas N., Research Director, United Mine Workers of Am.
BLINCKMANN, Robert A., Vice President and General Manager, Air Pollution
Control Co., Chemical Construction Corporation
Boston Edison Company:
IRVING, William M., Director, Research & Environmental Affairs
QUIGLEY, Christopher P., Director, Mechanical & Structural Design Division
BOYER, Vincent S., Vice President in Charge of Engineering, Philadelphia
Electric Company
BRADSTREET, Jeffrey, Dr., NUS Corp., Appearing for NIPSCO
BRECHER, Joseph T., Esq., Native American Rights Fund
Buckeye Power Company;
MONE, Robert, General Counsel
BURCHARD, John, Director, Control Systems Laboratory, EPA
CARSON, J.H., General Production Environmental & Performance Engineer, Ohio
Edison Company
100
-------
Combustion Equipment Associates, Inc. (CEA);
SHAH, I.S.
Chemfix Division of Environmental Sciences, Inc.:
CONNER, Jesse, President
Chemical Construction Corporation:
BLINCKMANN, Robert A., Vice President & General Manager of CCC's Air
Pollution Control Company
QUIG, Robert H., Vice President, Business Development
WECHSELBLATT, Peter, Manager, Process Engineering
Citizen's Environmental Task Force;
MADOFF, Michelle
CLARKE, A.J., Head, Environmental Studies Group, CEGB, appearing for
American Electric Power
CLAYTON, Cubia, Chief, Air Quality Div., New Mexico Environmental
Improvement Agency
Combustion Engineering. Inc.;
JONAKIN, Jim, Project Manager, Air Quality Control Systems
SINGER, Joe, Director, Special Projects Engineer
Commonwealth Edison Company;
LEE, Byron, Jr., Vice President
MARCUS, George, Director of Fuels
POWELL, Richard, Esq., Cross-examining Frank Princiotta
SMYK, Eugene, Chemical Engineer, Will County Station
CONNER, Jesse, President, Chemfix Div., Environmental Sciences, Inc.
CRAIG, John M., Dr., Senior Research Engineer, Southern Services, appearing
for Edison Electric Institute
CRAMER, John, Esq., Duquesne Light Co.
CRAWFORD, W. Donham, President, Edison Electric Institute
Davy Powergas;
EARL, Christopher, Director, Process Section
WATT, Stewart, Senior Vice President
Detroit Edison Co. and Peabody Engineered Systems; (Joint Statement)
SALEEM, Ab, Dr., of Peabody
WILLETT, H.B.,of Peabody
DICKE, Richard M., Esq., NYC Law Firm of Simpson, Thacher and Bartlett,
appearing for American Electric Power
DOWD, Joseph, Vice President and General Counsel, American Electric Power
and Asst.Secretary of Ohio Power Company
DUNKELBERGER, Ed, Esq., of Covington & Burling, appearing on behalf of Public
Service Co. of Indiana
Duquesne Light Company:
CRAMER, John, Esq., Attorney
PERN1CK, Steve L., Jr., Manager, Environmental Affairs
EARL, Christopher, Director, Process Section, Davy Powergas
EBERHART, Russell, Dr., Maryland Power Plant Siting Program
101
-------
Edison Electric Institute;
BALZHISER, Richard, Director of Fossil Fuel & Advanced Systems
CRAWFORD, W. Donham, President
CRAIG, John M., Dr., Senior Research Engineer, Southern Services, Inc.,
appearing on behalf of Edison Electric Inst.
GIFFORD, Donald C., General Engineer, Commonwealth Edison Co.
SMITH, Maynard E., President, Smith-Singer Meteorologists, Inc.
EICHHORN, Fred F., Esq., appearing for Northern Indiana Public Service
Company
ELDER, William, Director, Stack Gas Emission Studies Staff, TVA
ENGDAHL, Richard B., Atmospheric Chemistry & Combustion Research Section,
Battelie-Columbus Laboratories, appearing for West Penn Power Co.
Environmental Protection Agency:
BAUM, Robert, Deputy Asst Administrator for General Enforcement
BURGHARD, John, Director, Control Systems Laboratory
LUNEBURG, William, Esq., Enforcement Division, Region V
McDONALD, James 0., Director, Enforcement Division, Region V
PADGETT, Joseph, Project Standards Division
PRINCIOTTA, Frank T., Chief, Non-Regenerable Section:
QUARLES, John R., Deputy Administrator
RASNIC, John, Chief, Air Compliance Branch, Region III
SANSOM, Robert L., Asst Administrator, Air & Water Programs
SHEPARD, John, Chief, Legal Branch, Enforcement Div., Region III
STEIGERWALD, Bernard J., Dr., Director, Office of Air Quality Planning and
Standards
TRAIN, Russell E., Administrator
TRAINA, Paul J., Director, Enforcement Division, Region IV
WILBURN, James T., Chief, Air Enforcement Division, Region IV
WILSON, Richard D., Director, Division of Stationary Source Enforcement
ERDMAN, Mr., Project Engineer, Potomac Electric Power Company
FARKAS, Alan L., Deputy Director for Policy Development, Ohio EPA
Federal Power Commission;
BALET, William, Bureau of Power
JIMESON, Robert M., Office of Advisor on Environmental Quality
JOURNEY. Drexel, Deputy General Counsel
FEIGENBAUM, Simon, Engineer, Allegheny County (Penna.) - Bureau of Air
Pollution
FEIN, Marvin, Director, Bureau of Litigation Enforcement - Penna. Dept.
of Environmental Resources
FLANNERY, David, Atty, Representing American Electric Power
GARRETT, Theodore, Esq. of Covington & Burling, appearing for Public
Service Co. of Indiana—cross-examining F. Princiotta
GARTRELL, Frank, Director, Environmental Planning, TVA
GAULDING, Clark L., Director, Bureau of Air Quality and Noise Control,
Penna. Dept. of Environmental Resources
GEIST, Jerry, Executive Vice President, Public Service Company of New
Mexico
102
-------
GERSTLE, Richard W., PEDCO Environmental:
Reporting on a study of Mitchell Station, West Penn Power Co.
Reporting on a study of Bailly Station, NIPSCO
Reporting on a study of Wabash River Station, PSI
GIFFORD, Donald C., General Engineer, Commonwealth Edison Co., appearing
on behalf of Edison Electric Institute
GORR, Wilpen L., Dr., Ohio State University
GREEN, George, Director of Engineering, Environmental Engineering and
Planning, Public Sorvicc Company of Colorado
GRIFFIN, E.M., Division Vice President, Power Generation Group, Babcock
Wilcox
HARRIS, Thomas 0., Commissioner, Kentucky Dept. of Natural Resources and
Environmental Protection
HARRISON, Douglas, Engineer, Hydroelectric Power Commission of Ontario,
appearing for West Penn Power Company
HESKETH, Howard E., Professional Engineer
Illinois Power Company:
MILLER, Wendell, Director of Environmental Affairs
SHULTZ, Emerson A., Senior Vice President
Indiana Air; Pollution Control Board:
WILLIAMS, Harry D., Director, Division of Air Pollution Control
Industrial Gas Cleaning Institute;
OREM, Sidney R., Technical Director
IRVING, William M., Director, Research & Environmental Affairs, Boston
Edison Company
I. U. Conversion Systems. Inc;
MINNICK, L. John, Executive Vice President
IVES, Joseph S., Environmental Counsel, NRECA
Jefferson County (Kentucky) Air Pollution Control District:
OFFUTT, Robert T., Secretary-Treasurer
JONAKIN, Jim, Project Manager, Air Quality Control Systems, Combustion
Engineering, Inc.
JOURNEY, Drexel, Deputy General Counsel, Federal Power Com.
JIMESON, Robert M., Office of Advisor on Environmental Quality, FPC
Kansas City Power and Light Company;
McPHEE, Donald T., Vice President, Production
KAUFMAN, Paul, former Director, Appalachian Research and Defense Fund
KEBSCHULL, William David, Bureau of Air Quality, Maryland Department of
Health and Mental Hygiene
Kennecott Copper Corporation;
SWAN, David, Vice President—Technology
KENNEDY, James M.. Jr., Chairman, Tennessee Valley Indus trial.Com.
Kentucky, State of;
HARRIS, Thomas 0., Commissioner, Dept. for Natural Resources and
Environmental Protection
103
-------
KIMBERLIN, Greg, Esq., Atty for Public Service Company of Indiana
KOLFLAT, Tor, of Sargent & Lundy--Engineers, appearing for Public Service
Company of Indiana
KUHLMAN, George C. of Sargent & Lundy--Engineers, appearing for Northern
Indiana Public Service Company
LEE, Byron, Jr., Vice President, Commonwealth Edison Co.
Louisville Gas & Electric Company:
MAYROSE, J.F., Executive Vice President
VAN NESS, Bob, Manager, Environmental Affairs
LUNEBURG, William, Esq., Enforcement Division, Region V, EPA
LYLE, Horace P., Vice President, Electric Production and Engineering,
Northern Indiana Public Service Company
McDONALD, James O., Director, Enforcement Division, EPA, Region V
McPHEE, Donald T., Vice President, Production, Kansas City Power and
Light Company
McVAY, Cecil, Operating Vice President, Allegheny Power Services,
appearing for West Penn Power Company
MADOFF, Michelle, Citizens Environmental Task Force
MANSFIELD, Bruce, President, Ohio Edison Co. & Chairman of the
Board of Pennsylvania Power Company
MARCUS, George, Director of Fuels, Commonwealth Edison Co.
MARTINKA, Paul, Vice President, Fuel Supply, American Electric
Maryland, State Bureau of Air Quality Control:
EBERHART, Russell, Dr., Md. Power Plant Siting Program
KEBSCHULL, William David
MATTHEWS, Walter J., President, Public Service Co. of Indiana
MAYROSE, J.F., Executive Vice President, Louisville Gas & Elec.
MILLER, Wendell, Director of Environmental Affairs, Illinois Power Co.
MINNICK, L. John, Executive Vice President, I.U. Conversion Systems, Inc.
MLECZKO, Stanley S., Vice President and General Manager, UOP
MONE, Robert, General Counsel, Buckeye Power Co.
Monsanto Enviro-Chem Systems;
BARNARD, Richard E., Manager, Commercial & Technical Development
MOORE, Jack B., Vice President, Southern California Edison
National Rural Electric Cooperative Association;
IVES, Joseph S., Environmental Counsel
Native American Rights Fund;
BRECHER, Joseph T., Atty
New Mexico Environmental Improvement Agency:
CLAYTON, Cubia, Chief, Air Quality Division
Northern Indiana Public Service Company;
EICHHORN, Fred P., Esq., Schroer, Eichhorn & Morrow
KUHLMAN, George,of Sargent & Lundy--Engineering Firm
LYLE, Horace P., Vice President, Electric Production and Engineering
NORTON, Bruce, Esq., Arizona Public Service
104
-------
OFFUTT, Robert T., Secretary-Treasurer, Jefferson County (Ky) Air
Pollution Control District
Ohio Edison Company:
CARSON, J.H., General Production Environmental & Performance Engineering
MANSFIELD, Bruce, President & Chairman of Board of Penna. Power Co.
TSCHAPPAT, D. W., Chief, Industrial & Mechanical Engineering
Ohio Environmental Protection Agency:
FARKAS, Alan L., Deputy Director for Policy Development
OREM, Sidney R., Technical Director, IGCI
PADGETT, Joseph, Project Standards Division, EPA
Peabody Engineered Systems and Detroit Edison Co. (Joint Statement)
SALEEM, Ab, Dr., of Peabody Engineered Systems
WILLETT, H.B., Mr., of Peabody Engineered Systems
PENKALA, Stanley J., Dr., Chief Air Pollution Engineer--DeNardo and
McFarland Weather Services, Inc.--Appearing for West Penn Power Co.
Mitchell Power Station
Pennsylvania Department of Environmental Resources;
FEIN, Marvin, Director, Bureau of Litigation Enforcement
GAULDIMG, Clark L., Director, Bureau of Air Quality & Noise con.
PER NICK, Steve L., Jr., Manager, Environmental Affairs, Dequesne Light Co.
Philadelphia Electric Company:
BOYER, Vincent S., Vice President in Charge of Engineering
PIERCE, Donald, Economist, United Mine Workers of America
POHLENZ, J. B., Dr., Process Division, UOP
Potomac Electric Power Company;
BENZIGER, Peter H., Vice President of Generating
ERDMAN, Mr., Project Engineer
POWELL, Richard, Esq., Representing Commonwealth Edison Co., Cross-
examining F. Princiotta
PRINCIOTTA, Frank I., Chief, Non-Regenerable Process Section, EPA
Public Service Company of Colorado:
GREEN, George, Director of Engineering, Environmental Engineering and
Planning
WALKER, Richard F., Vice President of Engineering and Planning, Electric
Department
Public Service Company of Indiana:
DUNKELBERGER, Ed, Esq., of Covington & Burling
GARRETT, Theodore, Esq., of Covington & Burling - Cross-examining
F. Princiotta
KIMBERLIN, Greg, Attorney
105
-------
KOLFLAT, Tor, of Sargent and Lundy--Engineers
MATTHEWS, Walter J., President
SHIELDS, S. W., Chief Engineer
Public Service Company of New Mexico:
GEIST, Jerry, Executive Vice President
SLAMINSKI, Mike, Supervisor, Resource and Process Analysis
QUARLES, John R., Deputy Administrator, EPA
QUIGLEY, Christopher P., Director, Mechanical & Structural Design
Division, Boston Edison Co. - Mr. Quigley's remarks were interspersed
with Mr. Irving's statement
QUIG, Robert H., Vice President, Business Development, Chemico
RASNIC, John, Chief, Air Compliance Branch, EPA, Region III
REEVES, Robert W., Head of Environmental Engineering Div., AEP
Research-Cottrell, Inc.;
STITES, Joseph, Jr., Director, Program Management
RODECKER, Robert, Staff Attorney, Appalachian Research and Defense Fund -
Appearing for Paul Kaufman, former Director of ARDF
SALEEM, Ab, Dr., of Peabody Engineered Systems
SANSOM, Robert L., Assistant Administrator, Air & Water Programs
SCHMIDT, Harold, Esq..--Attorney:
Representing West Penn Power Co.
SHULTZ, Emerson A., Senior Vice President, Illinois Power Co.
SEEBER, Lynn, General Manager, TVA
SHAH, I.S., Combustion Equipment Associates, Inc. (CEA)
SHEPARD, Jonathan, Chief, Legal Branch, Enforcement Div., Region III
SHIELDS, S.W., Chief Engineer, Public Service Co. of Indiana
Sigrra Club;
TERRIS, Bruce, Attorney
SINGER, Joe, Director, Special Projects Engineer, Combustion Engineering,
Inc.
SLACK, A.V., President, SAS Corp.--Appearing for West Penn Power
SLAMINSKI, Mike, Supervisor, Resource & Process Analysis, Public Service
Co. of New Mexico
SMITH, Maynard E., Dr., President, Smith-Singer Meteorologists, Inc.
Appearing on behalf of Edison Electric Institute
Appearing on behalf of American Electric Power
SMYK, Eugene, Chemical Engineer, Will County Station, Commonwealth Edison Co.
Southern.California Edison;
MOORE, Jack B., Vice President
Southern Services, Inc.;
CRAIG, John M., Senior Research Engineer
STEIGERWALD, Bernard J., Dr., Director, Office of Air Quality Planning
and Standards, EPA
STEWART, J.F"., Foreman-Supervisor, Air Quality Control Section, Babcock
& Wilcox Company
STITES. Joseph, Jr., Director, Program Management, Research-Cottrell, Inc.
SWAN, David, Vice President-Technology, Kennecott Copper Corp.
106
-------
Tennessee Valley Authority:
ELDER, William, Director, Stack Gas Emission Studies Staff
GARTRELL, Frank, Dr., Director, Environmental Planning
SEEBER, Lynn, General Manage r
Tennessee Valley Industrial Cooperative (TVIC) ;
KENNEDY, James M. , Chairman
TERRIS, Bruce, Esq., Sierra Club
TILLINGHAST, John, Senior Executive Vice President in charge of
Engineering and Construction, American Electric Power Service Corp.
TSCHAPPAT, D.W., Chief Industrial and Mechanical Engineer, Ohio Edison Co.
TRAIN, Russell E., Administrator, EPA
TRAINA, Paul J., Director, Enforcement Division, Region IV, EPA
United Mine Workers of America;
BETHELL, Thomas N., Research Director
PIERCE, Donald, Economist
Universal Oil Products Company:
MLECZKO, Stanley S., Vice President and General Manager
POHLENZ, J.B., Dr., Process Division
VAN NESS, Bob, Manager, Environmental Affairs, Louisville Gas and
Electric Company
WALKER, Richard F., Vice President of Engineering and Planning, Electric
Department—Public Service Company of Colorado
WATT, Stewart, Senior Vice President, Davy Powergas
WESCHSELBLATT, Peter, Manager, Process Engineering, Chemico Corp.
West Penn Power Company;
ENGDAHL, Richard B., Atmospheric Chemistry & Combustion, Research
Section, Battelle-Columbus Laboratories
HARRISON, Douglas, Engineer, Hydroelectric Power Commission of Ontario
McVAY, Cecil, Operating Vice President, Allegheny Power Services
PENKALA, Stanley J., Dr., Chief, Air Pollution Engineer, DeNardo &
McFarland Weather Services, Inc.
SCHMIDT, Harold, Esq.
SLACK, A.V., President of SAS Corp.
West Virginia Aj-r^gj^bjtion Control Commission;
BEARD, Carl G., II, Director
WILBURN, James T., Chief, Air Enforcement Div. , EPA, Region IV
WILLETT, H.B., Peabody Engineered Systems
WILLIAMS, Harry D., Director, Division of Air Pollution Control, State
of Indiana
WILSON, Richard D., Director, Division of Stationary Source Enforcement,
EPA
WOODS, Thomas G., Jr., Vice President, Engineering, Arizona Public Service
Company
107
------- |