vvEPA
United States
Environmental Protection
Agency
Office of Air Quality
Planning and Standards
Research Triangle Park NC 27711
EPA-45O/2-77-OJ 7b
September 1979
Air
Stationary Gas
Turbines
Final
E1S
Standard Support and
Environmental Impact
Statement Volume II:
Promulgated Standards
of Performance
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EPA-450/2-77-017b
Stationary Gas Turbines
Standard Support and Environmental Impact
Statement Volume II: Promulgated Standards
of Performance
Emission Standards and Engineering Division
EPA Project Officer: Doug Bell
U.S. ENVIRONMENTAL PROTECTION AGENCY
Office of Air, Noise, and Radiation
Office of Air Quality Planning and Standards
Research Triangle Park, North Carolina 27711
September 1979
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This report has been reviewed by the Emission Standards and Engineering
Division, Office of Air Quality Planning and Standards, Office of Air, Noise
and Radiation, Environmental Protection Agency, and approved for publica-
tion. Mention of company or product names does not constitute endorsement
by EPA. Copies are available free of charge to Federal employees, current
contractors and grantees, and non-profit organizations - as supplies permit
from the Library Services Office, MD-35, Environmental Protection Agency,
Research Triangle Park, NC 27711; or may be obtained, for a fee, from the
National Technical Information Service, 5285 Port Royal Road, Springfield,
VA 22161.
Publication No. EPA-450/2-77-017b
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Standard Support and
Final Environmental Impact Statement
for Stationary Gas Turbines
Type of Action: Administrative
Prepared by:
r •*!- j " y^- ±_ ~ t ^ . ~~- i *- >--- ^^- "-"--
)on R. Goodwins/Director
Emission Standards and Engineering Division
U.S. Environmental Protection Agency
Research Triangle Park, North Carolina 27711
Approved by:
vid G. Hawkins
Assistant Administrator for Air, Noise
and Radiation
U.S. Environmental Protection Agency
Washington, D.C. 20460
6,-i H 79
(Date)
JUL 1 1 1979
(Date)
Final Statement Submitted to EPA's Office of
Federal Activities for Review on
This document may be reviewed at:
Central Docket Section
Room 2903B, Waterside Mall
401 M Street, S.W.
Washington, D. C. 20460
SEP
1979
(Date)
Additional copies may be obtained at:
U.S. Environmental Protection Agency Library (MD-35)
Research Triangle Park, North Carolina 27711
National Technical Information Service
5285 Port Royal Road
Springfield, Virginia 22161
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;-• TABLE OF CONTENTS
; ;-.. Page
Chapter T. SUMMARY •• • 1~1
1.1 SUMMARY OF CHANGES SINCE PROPOSAL ....1-1
1.2 SUMMARY OF THE IMPACTS OF THE PROMULGATED
ACTION • '"3
Chapter 2. SUMMARY OF PUBLIC COMMENTS • • • • • 2-1
2.1 GENERAL •• •••• 2-1
2.2 EMISSIONS CONTROL TECHNOLOGY 2-3
2.3 MODIFICATION AND RECONSTRUCTION 2-9
2.4 ECONOMIC IMPACT 2-12
2.5 ENVIRONMENTAL IMPACT 2-20
2.6 ENERGY IMPACT 2-24
2.7 LEGAL CONSIDERATIONS 2-29
2".8 TEST METHODS AND MONITORING 2-32
TABLE 2-1 LIST OF COMMENTERS ON THE PROPOSED
STANDARDS OF PERFORMANCE FOR STATIONARY GAS ^
TURBINES • 2-40
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1 ' • VOLUME II, CHAPTER 1 (SSEIS-GT)
1. SUMMARY
On October 3, 1977, the Environmental Protection Agency EPA) proposed
a standard of performance for stationary gas turbines (42 FR 53782)
under authority of Section 111 of the Clean Air Act. Public comments
were requested on the proposal in the Federal Register publication.
There were 78 commenters composed mainly of electric utility and oil and
gas producers, as well as gas turbine manufacturing companies. Also
commenting were state air pollution control agencies, trade and professional
associations, and several Federal agencies. The comments that were
submitted, along with responses to these comments, are summarized in
this document. The summary of comments and responses serves as the
basis for the'revisions which have been made to the standard between
proposal and promulgation.
1.1 SUMMARY OF CHANGES SINCE PROPOSAL
A number of changes of varying importance have been made since pro-
posal. The most significant of these is to require small gas turbines
(.less than 10,000 hp) to meet a standard based on dry controls of 150
parts per million (ppm) nitrogen oxides (NOX). The proposed standard
would have required small turbines to meet an emission limit of 75 ppm
NO . The five-year delay in the effective date for this standard has
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been retained. .
Another change of importance was made to address problems which
might be created in areas with limited water supplies. Gas turbines
used in oil and gas production or oil and gas transmission are most
affected. The promulgated standard includes a requirement that these
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turbines, that are not located in a Metropolitan Statistical Area (as
defined by the Department of Commerce), meet a 150 ppm NOX emission
limit which can be achieved using dry control technology. The proposed
standard would have required compliance with the 75 ppm NOX emissions
standard.
One commenter suggested that gas turbines employed for research and
development should be exempt due to the nature of such facilities. The
promulgated standard includes such an exemption and provides for a case-
by-case review to prevent abuses of the intent of the exemption, which
is to encourage the advancement of technology in the gas turbine field.
Three changes were made to proposed test methods and monitoring re-
quirements. The promulgated standard allows performance tests to be
conducted at maximum and minimum heat rates in the normal operating range
and at any two points between these Values as opposed to the four fixed
points originally proposed. The test method as promulgated also allows
a wider span range on NOV analyzers than originally proposed to accommo-
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date the changes in the standard discussed above. Finally, monitoring
of nitrogen and sulfur content in the fuel is allowed on a batch basis
in those circumstances where little variation in nitrogen or sulfur
content is expected, rather than daily, as proposed.
Several commenters requested flexibility in determining the values
of the fuel-bound nitrogen (F) and efficiency (Y) factors used in the
equations for calculating allowable emissions of NOX. Manufacturers
of stationary gas turbines will be allowed to determine the fuel-bound
nitrogen factors (F) for their various models if they so desire. These
fuel-bound nitrogen factors, however, will have a maximum limit of 50 ppm.
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Such factors must be approved by the Administrator on a case-by-case
basis. The efficiency factor (Y) may be either the manufacturer1^ or
the actual heat rate as opposed to specifying only the manufacturer's
heat rate as originally proposed. The changes contained in the promul-
gated standard are consistent with the intent of the equations as
originally proposed.
In some cases commenters were unsure about the meaning of some
sections of the standard. In these cases the wording has been changed
or expanded to provide additional clarity. The five-year exemption for
small gas turbines has been reworded so as to make it clear that the
standards can not be applied retroactively. Wording has been added to
make it clear that owners/operators may contract for fuel sample analysis
and are not required to develop in-house capability. In Reference
Method 20 the discussion on the design of moisture traps has been expanded
to avoid errors in the use of the method under test conditions where the
nitrogen dioxide (NO ) fraction is greater than 2 or 3 percent.
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1.2 SUMMARY OF THE IMPACTS OF THE PROMULGATED ACTION
1.2.1 Alternatives to the Promulgated Action
The alternative control techniques are discussed in Chapter. 4 of Volume
I of The Standard Support and Environmental Impact Statement (SSEIS,Vol. 1).
These alternative control techniques are based upon the best demonstrated
technology, considering costs, for stationary gas turbines. The analysis
of these alternatives—of taking no action and of postponing the promulgated
action—is outlined in Chapter 8 (SSEIS, Vol. I). These alternatives remain
the same.
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1.2.2 Environmental Impacts of the Promulgated Action
The standard has been changed to allow small stationary gas turbines
(less than 10,000 hp) to meet a 150 ppm NOX standard as opposed to the 75 ppm
NO originally proposed. The five year delay in the effective date of the
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standard will still apply to these turbines. An adverse air quality impact will
occur because this standard will result in a 40 percent instead of 70 percent
reduction in NO emissions from turbines of less than 10,000 hp. However,
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small turbines account for less than 10 percent of the total NOX emissions
from stationary gas turbines. Therefore, the air quality impact of allow-
ing small stationary gas turbines to meet a standard of 150 ppm NOX emissions
is considered reasonable.
The other change which will result in an adverse air quality impact
allows turbines employed in oil and gas production or oil and gas trans-
portation to meet a 150 ppm NOV emission standard originally proposed. The
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major portion of these turbines consists of turbines less than 10,000 hp and
so would be included in the small turbine provision discussed above. There
is no additional air quality impact from this group. However, a few turbines
employed in oil and gas production or oil and gas transportation are larger
than 10,000 hp. The 150 ppm NOV emission standard results in a 40 percent
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reduction in NO emissions from these turbines as opposed to the 70 percent
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reduction which would have resulted with the proposed standard of 75 ppm NOX
emissions. However, this increase in NOV emissions will occur from only
A
those turbines used in oil and gas production or oil and gas transportation
and larger than 10,000 hp. This group of turbines accounts for a very small
percentage of total NOV emissions from all stationary gas turbines. There-
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fore, the impact of this change is considered reasonable.
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Energy impacts result from the use of wet control technology as discussed
in Chapter 6 Volume I of the Standards Support and Environmental Impact
Statement, (SSEIS, Vol. I). The changes since proposal mean that dry control
technology will be used to achieve the NO emission standard of 150 ppm for
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.small gas turbines and turbines in oil. and gas production or oil and gas
transportation. Therefore, the promulgated action reduces some of the
adverse energy impacts associated with the proposed NO emission standard.
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1.2.3 Economic Impact of the Promulgated Action
Requiring small gas turbines and turbines in oil and gas production or
oil and gas transportation to meet a 150 ppm NO emission standard instead of
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the 75 ppm NO emission standard will reduce the economic impact on small
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turbines. An analysis of the economic impact of the standards based on wet
control technology (75 ppm) prior to proposal concluded that these standards
were economically feasible for Targe and small turbines. However,
new data show that for.some turbines wet control technology cannot be
applied in an economically feasible manner. ,
The costs associated with wet control technology were reexamined with
respect to small gas turbines. New. figures for the costs of redesigning
small gas turbines for use with wet control technology were obtained.
These figures indicated that costs had increased two to three, times over
the original manufacturers' estimates. These increased redesign costs
were attributed to a decline in small gas turbine sales, yielding a
smaller production base over which the nonrecurring part of the redesign
costs could be amortized. As a result of these data, the cost of wet
control.technology on small turbines now represents a 16 percent increase
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in capital cost as compared to the 4 percent increase estimated In the
SSEIS, Vol. I. This increase in cost is considered unreasonable.' There-
fore, small gas turbines will be required, by the promulgated standard,
to achieve a 150 ppm NOY emissions standard which can be accomplished using
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dry control technology, thus reducing the economic impacts discussed above.
The costs associated with wet control technology were reassessed with
special emphasis on turbines located on offshore platforms and in arid
and remote regions. The extra costs associated with these locations are
all related to lack of water of acceptable quality or quantity. When
the cost of platform space was factored into the analysis for offshore
platforms, the economic impact was as high as a 33 percent increase in
capital costs (as compared to 7 percent in the SSEIS, Vol. I). In many
arid and remote regions, water would have to be trucked, transported by
pipeline, or a large reservoir constructed, none of which is considered
economically feasible. Most of these situations are associated with
turbines used for oil and gas production or oil and gas transportation.
Therefore, the requirement that these turbines meet a 150 ppm NOX
standard, as opposed to the 75 ppm NOX standard, allows the turbines
to use dry control technology and removes these unreasonable impacts.
1.2.4 Other Considerations
1.2.4.1 Adverse Impacts
The potential adverse impacts associated with these standards are
discussed in Chapters 1 and 6 (SSEIS, Vol. I). These impacts remain
essentially unchanged since proposal. However, for the water impacts,
the trend toward dry controls which is further encouraged by the changes
since proposal will result in a more widespread use of dry control
technology and, therefore, reduce the impact on water resources.
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1.2.4.2 Relationship Between Local Short-Term Uses of Man's Environment
and the Maintenance and Enhancement of Long-Term Productivity
This impact is discussed in Chapters 6 and 8 of the SSEIS, Vol I
and remains unchanged since proposal.
1.2.4.3 Irreversible and .Irretrievable Commitments of Resources
This impact is discussed in Chapter 6 of the SSEIS, Vol I and remains
unchanged since proposal.
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2. SUMMARY OF PUBLIC COMMENTS
The list of commenters and their affiliations is shown in Table 2-
1. Seventy-eight letters contained comments on the proposed standard
and Volume I of the Standards Support and Environmental Impact State-
ment. The significant comments have been combined into the following
eight major areas:
1. General
2. Emission Control Technology
3. Modification and Reconstruction
4. Economic Impact
5. Environmental Impact '
6. Energy Impact
7. Legal Considerations '
8. Test Methods and Monitoring
The comments and issues and responses to them are discussed in the
following section of this chapter. A summary of the changes to the
regulations is included in Section 2 of Chapter 1.
2.1 GENERAL
• * , ' ' - • , ' '
Test Facilities
Exemptions were requested by several commenters for temporary and
intermittent operation of gas turbines to permit research and devel-
opment.
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It was considered reasonable to exempt gas turbines involved in
research and development testing of equipment. Therefore, gas turbines
involved in research and development for the purpose of improving
combustion efficiency or developing control technology are exempt from
the NO emission limit in the promulgated standards. Gas turbines
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involved in this type of research and development generally operate
intermittently and on a temporary basis. The exemptions, therefore, will
be allowed on a case-by-case basis as determined by the Administrator.
Five-year Exemption
Small stationary gas turbines with heat input at peak load between
10.7 and 107.2 gigajoules per hour (between 10 million Btu/hr and 100
million Btu/hr! are exempt from the standards for a period of five years
from the date of proposal. Some commenters felt that it was not clearly
stated that these gas turbines which are exempt for this five year
period would not be required to be retrofitted with NO emissions controls
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after the exemption period ended. These commenters felt the intent of
the New Source Performance Standard CNSPS) was not to require such
retrofitting, and they recommended that the standard be reworded to
explicitly state that intention.
The commenters1 understanding of the intent of the standard on this
point is correct. Gas turbines with a heat input at peak load between
10.7 and 107.2 gigajoules per hour which have commenced construction on or
before the end of the five year exemption period will be considered existing
facilities. These facilities will not have to retrofit at the end of
the exemption period. This point has been clarified in the promulgated
standards.
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2.2 EMISSIONS CONTROL TECHNOLOGY
Choice of Wet Control as Basis for Standard
The selection of water injection as the best system of emission
reduction for stationary gas turbines was criticized by a number of com-
menters. These commenters pointed out that although dry controls will not
reduce emissions as much as wet controls, dry controls will reduce NOX
emissions without the objectionable results of water injection, i.e.,
increased fuel consumption and difficulty in securing water of acceptable
quality. .These commenters, therefore, recommended postponement of stan-
dards until such time as dry controls are feasible.
As pointed out in Volume 1 of the Standards Support and Environmental
Impact Statement (SSEIS), a high priority for control of NO . emissions'has
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been established. Wet and dry controls were considered as the only
viable alternative control techniques for reducing NO emissions from gas
A
turbines. NO emissions control achievable with these two alternatives
A •
clearly favored the development of standards of performance based on wet
controls from an environmental viewpoint. Reductions in,NO emissions
A
of more than 70 percent have been demonstrated using wet controls on
many large gas turbines (greater than 10,000 horsepower) used in utility
and industrial applications. Thus, wet controls can be applied immediately
to large gas turbines, which account for 85 - 90 percent of NO emissions
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from gas turbines.
The technology of wet control is the same for both large and small
gas turbines, the manufacturers of small gas turbines, however, have not
experimented with or developed this technology to the same extent as
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the manufacturers of large gas turbines. In addition, small gas turbines
tend to be produced on more of an assembly line basis than large gas
turbines. Consequently, the manufacturers of small gas turbines need a
lead time of five years (based on their estimates) to design test and
incorporate wet controls on small gas turbines.
Even with a five year delay in application of standards to small
turbines, standards of performance based on wet controls will reduce
national NO emissions by about 190,000 tons per year by 1982. Therefore,
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the reduction in NOV emissions resulting from standards based on wet
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controls is significant.
Dry controls have demonstrated NOX emissions reduction of only
about 40 percent in laboratory and combustor rig tests. Because of
the advanced state of research, and development into dry control by the
manufacturers of large gas turbines, the much larger lead time involved
in ordering large gas turbines, and the greater attention that can be
given to "custom" engineering design of large gas turbines, dry controls
can be implemented on large gas turbines immediately. Manufacturers of
small gas turbines estimated, however, that it would take as long to
Incorporate dry controls as wet controls on small gas turbines. Basing
the standard only on dry controls, therefore, would significantly
reduce the amount of NOV emissions reductions achieved.
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The economic impact of standards of performance based on wet controls
is considered reasonable for large gas turbines. (See Economic Impact
Discussion.) Thus, wet controls represent "... the best technological
system of continuous emission reduction ... (taking into consideration
the cost of achieving such emission reduction, any nonair quality health
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and environmental impact and energy requirements) ..." for large gas
turbines.
The economic impact of standards based on wet controls, however,
is considered unreasonable for .small gas turbines, gas turbines located
on offshore platforms, and gas turbines employed in oil or gas production
and transportation which are not located in a Metropolitan Statistical
Area. The economic impact of standards based on dry controls, on the
other hand, is considered reasonable for these gas turbines. (See
Economic Impact Discussion.) Thus, dry controls represent "... the best
system of continuous emission reduction ... (taking into consideration
the cost of achieving such emission reduction, any nonair quality health
and environmental impact and and energy requirements) ..."for small
gas turbines, gas turbines located on offshore platforms, and gas
turbines employed in oil or gas production and transportation which are
not located^ in a Metropolitan Statistical Area.
Volume 1 of the SSEIS summarizes the data and informatton available
from the literature and other nonconfidential sources concerning the
effectiveness of dry controls in reducing NOV emissions from stationary
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gas turbines. More recently, additional data and information have been
published in the Proceedings of the Third Stationary Source Combustion
Symposium (EPA-600/7-79-050C), Advanced Combustion Systems for
Stationary Gas Turbines (interim report) prepared by the Pratt and
Whitney Aircraft Group for EPA (Contract 68-02-2136), "Experimental
Clean Combustor Program Phas III" (NASA CR-135253) also prepared by the
Pratt and Whitney Aircraft Group for the National Aeronautics and Space
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Administration (NASA), and "Aircraft Engine Emissions" (NASA Conference
Publication 2021). These data and information show that dry controls can
reduce NO emissions by about 40 percent. Multiplying this reduction
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by a typical NO emission level from an uncontrolled gas turbine of
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about 250 ppm leads to an emission limit for dry controls of 150 ppm.
This, therefore, is the numerical emission limit included in the
promulgated standards for small gas turbines, gas turbines located on
offshore platforms, and gas turbines employed in oil or gas production
or transportation which are not located in Metropolitan Statistical
Areas.
The five year delay from the date of proposal of the standards in
the applicability date of compliance with the NOX emission limit for
small gas turbines has been retained in the promulgated standards. As
discussed above, manufacturers of small gas turbines have estimated
that it will take this long to incorporate either wet or dry controls on
these gas turbines.
Fuel-Bound Nitrogen Allowance
Several commenters criticized the fuel-bound nitrogen allowance
included in the proposed standards. It was generally felt that due to
the limited data on conversion of fuel-bound nitrogen to NOX, greater
flexibility in the equations used to calculate the fuel-bound NOX emissions
contribution should be permitted. These commenters recommended that
manufacturers be allowed to develop their own fuel-bound nitrogen allowance.
As discussed in Volume I of the SSEIS, the reaction mechanism by
which fuel-bound nitrogen contributes to NOX emissions is not fully
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understood and NO emission data are limited with respect to fuels
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containing significant amounts of fuel-bound nitrogen. The problem of
quantifying the fuel-bound nitrogen contribution to total NO emissions
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in gas turbines is further complicated by the fact that the amount of
nitrogen in the fuel has an effect on the degree of conversion.
In light of this sparcity of data, the commenters1 recommendation
seems reasonable. Therefore, a provision has been added to the standard
to allow manufacturers to develop their own fuel-bound nitrogen allowances
for each gas turbine model they manufacture. Such allowance factors,
however, must be approved by the Administrator on a case-by-case basis
before the initial performance test required by §60.8 of the General Provisions.
Petitions by manufacturers for-fuel-bound nitrogen allowance factors
must be supported by data which clearly provide a basis for determining
the contribution of fuel-bound nitrogen to total NOV emissions from the
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gas turbine. However, the amount of organic NOV emissions allowed under
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any fuel-bound nitrogen allowance factor shall not exceed 50 ppm (Also
discussed in Section 2.6, Synthetic Fuels, below). Notice of approval
of the use of these factors for various gas turbine models will be given
in the Federal Register.
Ambient Correction Factors
Some commenters requested that parameters other than ambient conditions
be included in ambient correction factors. These commenters pointed out
that the use of such parameters as combustor inlet temperature, fuel flow,
and fuel-to-air ratio should be allowed. Since the majority of research
and development work in this area focuses on these parameters, the pro-
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posed standard, in effect, requires that manufacturers develop new correc-
tion equations. They felt that this is wasteful of both engineering and
engine test time.
With respect to ambient correction factors, the intent of the stan-
dard is to avoid using parameters which are difficult to measure or are
machine-dependent and thus subject to variation due to factors other than
ambient conditions. In order to ensure that standards of performance are
enforced uniformly, the effect of ambient atmospheric conditions on NOX
emission levels should be based on those parameters which are common to
all machines.,, easily measured, and independent of individual design or
configuration. Consequently, the correction factor must be developed' in
terms of only the following variables: ambient air pressure, ambient, air
humidity, and ambient air temperature.
Operation at Partial Load
The proposed standard would have required that the water-to-fuel
ratio needed for compliance with the NOV emission limit be determined at
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30, 50, 75 and 100 percent of peak load during the initial performance
test. One commenter objected to this requirement, stating the requirement
of emission measurements at specific load condition may not be appropriate
for all gas turbine applications, and it is difficult to design a single
water injection system to operate over as wide a range as will be required
if water injection is required over a wide turbine operating range.
The commenter pointed out that certain gas turbines may not physical-
ly be able to operate between 30 and 100 percent of peak rating of the
turbine unit. Examples of such operations cited were: gas turbines in
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industrial generation service; cogeneration systems; gas turbines driving
mechanical loads, such as pumps or compressors or other systems dedicated
to a single, specific load; and gas turbines with a minimum load range.
In light of these comments, the standard has been changed to permit
testing "... at four points in the normal operating range of the gas
turbine, including the minimum and maximum points in this range." It
should not be construed from this new wording, however, that compliance
with the standard is not required outside this range. Compliance with the
standard is required at all times during operation.
The commenter's second objection seems to be based on the assumption
that water injection would be required over the entire operating range of
a gas turbine to comply with the standard, and that this would require a
complex water injection system to accomddate the wide range of water flow
rates. The commenter recommends, therefore, that gas turbines operating
at 30 percent load or less be exempt from compliance with the standard.
The standard does not require injection of water, but, rather,
compliance with an NO numerical emission limit. Emissions of NO are
A ^
relatively sensitive to load, and as load decreases, emissions decrease
fairly rapidly. Consequently, it is not likely that water injection will
be required at low loads, i.e., less than 30 percent, to comply with the
standard. Thus exempting gas turbines from compliance with the standard
at low loads does-not seem reasonable.
2.3 MODIFICATION AND RECONSTRUCTION
Definitions
Some commenters objected to lack of definitions for the terms "modi-
fication" and "reconstruction" within the standards. According to these
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commenters, the word "reconstruction" needs clarification since it could
be misconstrued to include existing gas turbines simply undergoing perio-
dic overhauls.
The terms, "modification" and "reconstruction," while not explicitly
defined in Subpart 66, Standards of Performance for Stationary 6as Turbines,
have been thoroughly defined in Subpart A, the 6eneral Provisions, which
are applicable to all standards of performance. For a complete discussion
of the meaning of these terms, the commenter is referred to the 6eneral
Provisions.
Modification essentially means any change of an existing facility
which increases the amount of a pollutant emitted into the atmosphere by
that facility. Conditions which do not constitute modification include
among other things: (1) maintenance, repair, and replacement which are
"routine"; (2) an increase in production rate of an existing facility, if
that increase can be accomplished without a capital expenditure; (3) an
increase in the hours of operation; (4) use of an alternative fuel under
certain conditions within the limitations as set forth in Section 60.14(e);
(5) the addition or use of any system or device, the primary function of
which is the reduction of air pollutants, except when such device is
determined by the Administrator to be less environmentally beneficial; and
(6) the relocation or change in ownership of an existing facility.
Reconstruction essentially means the alteration of an existing facili-
ty to such an extent that the fixed capital cost of the new components
exceeds 50 percent of the fixed capital cost that would be required to
construct a completely new facility and it is technologically and eco-
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nomically feasible to meet the applicable standards.
In-light of the definition of modification and reconstruction in the
General Provisions, they need not be reiterated in Subpart GG.
Conversion From Natural Gas To Oil
Some commenters felt that existing gas turbines which now burn na-
tural gas and are subsequently altered to burn oil should be exempt from
consideration as modifications. The high cost and technical difficulties
of compliance wi.th the standards would discourage fuel switching to con-
serve natural gas supplies.
As outlined in the General Provisions of 40 CFR Part 60, which are
applicable to all standards of performance, most changes to an existing
facility which result in an increase in emission rate to the atmosphere
are considered modifications. However, according to section 60.14(e)(4)
of the General Provisions, the use of an alternative fuel or raw material
shall not be considered a modification if the existing facility was
designed to accommodate that alternative use. Therefore, if a gas turbine
is designed to fire both natural gas and oil, then switching from one fuel
to the other would not be considered a modification even if emissions
were increased. If a gas turbine that is not designed for firing both
fuels is switched from firing natural gas to firing oil, installation of
new injection nozzles which increase mixing to reduce NOX production, or
installation of new NOV combustors currently on the market, would in
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most cases maintain emissions at their previous levels. Since emissions
would not increase, the gas turbine would not be considered modified,
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and the real impact of the standards on gas turbines switching from
natural gas to oil will probably be quite small. Therefore, no special
provisions for fuel switching have been included in the promulgated
standards.
2.4 ECONOMIC IMPACT
Operation and Maintenance
Several commenters stated that if water injection is used to meet the
NSPS, maintenance costs could increase significantly. One reason cited
for increased maintenance costs was that chemicals and minerals in the
water would Jikely be deposited on the internal surfaces of gas turbines,
such as turbine blades, leading to downtime for repair and cleaning. In
addition, the commenters felt that higher maintenance requirements could
be expected due to the increased complexity of a gas turbine with water
injection.
As pointed out in Volume I of the SSEIS, to avoid deposition of
chemicals and minerals on the gas turbine blades, the water used for
water injection must be treated. The costs for water treatment were
included in overall costs of water injection systems and, for large gas
turbines, these costs are considered reasonable.
Actual maintenance and operating costs for gas turbines operating
with water or steam injection are limited. Several major utilities, how-
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ever, have accumulated significant amounts of operating time on gas tur-
bines using water or steam injection for control of NOV emissions. There
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have been some problems attributable to the water or steam injection
systems, but based on the data available, these problems have been con-
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fined to initial periods of operation of these systems. Most of these
reported problems, such as turbine blade damage, flame-outs, water
hammer damage, and ignition problems, were easily corrected by minor
redesign of the equipment hardware. Because of the knowledge gained
from these first few systems, such problems should not arise in the
future.
As mentioned, some utilities have accumulated substantial operating
experience without any significant increase in maintenance or operating
costs or other adverse effects. For example, one utility has used water
injection on two gas turbines for over 55,000 hours without making any
major changes to their normal maintenance and operating procedures. They
followed procedures essentially identical to those required for a similar
machine not using water injection, and the plant experienced no outages
attributable to the water injection system. Another company has accumu-
lated over 92,000 hours of operating time with water injection on 17
turbines with approximately only 116 hours of outage attributable to their
water injection system. Increased maintenance costs which can be attri-
buted to these water injection systems are not available, as such costs
were not accounted for separately from normal maintenance. However, they
were not reported as significant.
Mater Injection Costs
Some commenters expressed the opinion that the cost estimates for
controlling NO emissions from large gas turbines were too low. Accor-
A
dingly, these commenters felt that wet control technology should not be
the basis of the standards for large stationary gas turbines.
2-13
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The costs associated with wet control technology, as applied to large
gas turbines, were reassessed. In a few cases, it appared the water to
fuel ratio used in Volume I of the SSEIS was somwhat low. In these cases
the capital and annualized operating costs associated with wet control
on large gas turbines were revised to reflect injection of more water
into the gas turbine. Moe of these revisions, however, resulted in a
significant change in the projected economic impact of wet controls on
large gas turbines. Thus, depending on the size and end use of large gas
turbines wet controls are still projected to increase capital and
annualized operating costs by no more than 1 to 4 percent. Increases
of this order of magnitude are considered reasonable in light of the 70
percent reduction in NO emissions achieved by wet controls. Consequently,
yv
the basis of the promulgated standards for large gas turbines remain the
same as that for the proposed standards — wet controls.
A number of commenters also expressed the opinion that the cost
estimates for wet controls to reduce NO emissions from small gas
A
turbines were too low. Therefore, the standards for small gas turbines
should not be based on wet controls.
Information included in the comments submitted by manufacturers
of small gas turbines indicated the cost of redesigning these gas
turbines for water'injection are much greater than those included in
Volume 1 of the SSEIS. Consequently, it appears the costs of water
injection would increase the capital cost of small gas turbines by
about 16 percent, rather than about 4 percent as originally estimated.
Despite this increase in capital costs, it does not appear water
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injection would increase the annualized operating costs of small gas
turbines by more than 1 to 4 percent as originally estimated, due to
the predominance of fuel costs in operating costs. An increase of
16 percent in the capital cost of small gas turbines, however, is
considered unreasonable.
Very little information was presented in Volume 1 of the SSEIS
concerning the costs of dry controls. The conclusion was drawn,
however, that these costs would undoubtedly be less than those
associated with wet controls. .
Little information was also included in the comments submitted .
by the manufacturers of small gas turbines concerning the costs of
dry controls. Most of the cost information dealt with the costs of ..
wet controls. One manufacturer, however, did submit limited information
which appears to indicate that the capital cost impact of dry controls
on small gas turbines might increase the capital costs of small gas
by about 4 percent and the annualized operating costs by about 1 to 4
percent. The magnitude of these impacts is essentially the same as
those originally associated with wet controls in Volume 1 of the SSEIS,
and they are considered reasonable. Consequently, the basis of the
promulgated standards for small gas turbines is dry controls.
Arid And Remote Regions
A number of commenters stated that the costs associated with wet
controls on gas turbines located on offshore platforms, and in arid
and remote regions were unreasonable. These commenters felt that the
costs of obtaining, transporting, and treating water in these areas
prohibited the use of water injection.
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As mentioned by the commenters, the cost associated with water
injection on gas turbines in these locations are all related to lack
of water of acceptable quality or quantity. Review of the original
estimated costs associated with employing water injection on gas
turbines located on offshore platforms indicates that the required
expenditures for platform space were not incorporated into these
estimates. Platform space is very expensive; typical space on an off-
shore platform averages approximately $400 per square foot. When this
cost is factored in, use of water treatment systems to provide water for
NO emissions control would increase the capital costs of a gas turbine
*\
by approximately 33 percent Cas compared to an original estimate of 7
percent in Volume I of the SSEIS). This represents an unreasonable
economic impact.
Dry controls, unlike wet controls, would not require additional
space on offshore platforms. Although most gas turbines located on
offshore platforms would be considered small gas turbines under the
standards, it is possible that some large gas turbines might be
located on offshore platforms. Therefore, all the information available
concerning the costs associated with standards based on dry controls
for large gas turbines was reviewed.
Unfortunately, no additional information on the costs of dry
controls was included in the comments submitted by the manufacturers
of large gas turbines. As mentioned above, the information presented
in Volume 1 of the SSEIS is very limited concerning the costs of dry
controls, although the conclusion is drawn that these costs would
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undoubtedly be less than the cost of wet controls. It also seems
reasonable to assume that the costs of dry controls on large gas
turbines would certainly be less than the costs of dry controls on
small gas turbines. Consequently, standards based on dry controls
should not increase the capital and annualized operating costs of
large gas.turbines by more than the 1 to 4 percent projected for
small gas turbines. This conclusion even seems conservative in light
of the projected increase in capital and annualized operating costs
for wet controls on large gas turbines of no more than 1 to 4 percent.
In any event, the costs of standards based on dry controls for large
gas turbines are considered reasonable. Therefore, the promulgated
standards for gas turbines located on offshore platforms are based on
dry controls.
In many arid and remote regions, gas turbines would have to obtain
water by trucking, installing pipelines to the site, or by construction of
large water reservoirs. While costs included in Volume I of the SSEIS
do not show trucking of water to be unreasonable, these costs are not
based on actual remote area conditions. That is, these costs are based
on paved road conditions and standard ICC freight rates. However, the
gas turbines located in remote regions are not likely to have good access
roads. Consequently, it is felt that in most cases the costs of trucking,
laying a pipeline, or constructing a reservoir are unreasonable for arid
and remote areas.
A number of alternatives were examined to provide some sort of exemp-
tion for gas turbines in water-limited areas. In all cases exemption from
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the 75 ppm NO emissions standard means compliance with a 150 ppm NOX
emission standard based on dry controls. One category of gas turbines
for which it is clear that an exemption is necessary is offshore platform
turbines. Wet control technology cannot be used in offshore situations
in a manner that would be considered economically reasonable.
For other situations, defining the nature of the exemption was more
difficult. Four options were considered. The terms "arid" and "remote"
could be defined and all turbines located in these areas could be exempt.
While this option is conceptually straightforward, the actual determina-
tion of such areas would be extremely difficult. Another method of exemp-
tion considered was to exempt all gas turbines located more than a specified
distance from ah adequate water supply. Defining adequate water supply
and determining a distance Which would be equitable in all locations and
under all circumstances proved to be as difficult as the first option.
Another option Was to provide a case-by-case exemption based on
demonstrated costs of control. This approach assures that all cases are
covered and that each is justified. This approach, however, would encourage
estimation of grossly inflated costs to justify exemption. In addition it
would place an unreasonable burden on both EPA and the industry. Therefore,
this approach was considered unreasonable.
Finally, it became apparent that gas turbines located in arid and
remote regions could generally be classified by end use in many cases. Most
gas turbines located in arid or remote regions are used for either oil
and gas production, or oil and gas transportation. Included in this
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category are offshore platform, pipeline, and production field gas
turbines. These gas turbines are generally less than 10,000 horsepower
and thus would be exempt from a standard based on wet control technology
due to size alone, as discussed earlier in this section. However, a
number of the gas turbines used in oil and gas production and transportation
are larger than 10,000 horsepower.
In light of these considerations, the standard has been revised to
require gas turbines employed in oil and gas production or oil and gas
transportation and not located in a Metropolitan Statistical Area (as
defined by the Department of Commerce) to meet an emission limit based
on dry control technology of 150 ppm NO emissions. As discussed earlier
A
in this section, dry controls are available and can achieve 40 percent
reduction in NOX emissions. The total capacity that is represented by
these gas turbines is small, and exempting them from the 75 ppm NO
X
emissions level based on wet control technology will not adversely
impact the overall NO emissions reduction achieved by this standard as
X
originally proposed. Those gas turbines employed in oil and gas production
or oil and gas transportation that are located in a Metropolitan Statistical
Area (MSA) are still required to meet the 75 ppm NO emission limit because
X
in an MSA a suitable water supply for water injection wjll be available.
Gas turbines employed for electric generation, however, will be
required to meet the 75 ppm N0x standard. Electric generation gas
turbines are generally much larger than oil or gas production and transmission
gas turbines and are considered such significant sources of NO that
X
exempting such turbines is not considered reasonable. Of course, this
2-19
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pertains only to gas turbines greater than 10,000 hp because small gas
turbines, as discussed above, are required to meet a 150 ppm emission
limit. In addition, manufacturers have expressed optimism that dry
control technology for large electric generation gas turbines will be
able to achieve the 75 ppm NO standard without water injection in the
/\
very near future. In fact, some manufacturers are now taking orders for
large gas turbines guaranteed to meet the 75 ppm NOV emission standard
X
using dry control technology.
2.5 ENVIRONMENTAL IMPACT
Significance of Air Quality Improvement
The degree of air quality improvement achieved by the standards was
questioned by numerous commenters. A general comment was that the amount
of NOX emission reduction projected in Volume I of the SSEIS, is not worth
the increased costs and adverse energy impact associated with wet control
systems installed on gas turbines.
Stationary gas turbines are significant contributors to nationwide
emissions of NO . A high priority has been assigned to the development of
f\
standards of performance for major NO emission sources wherever signifi-
/\
cant reductions can be achieved. As pointed out in the SSEIS, applying
best technology to all new sources would reduce the growth of national NO
X
emissions from stationary sources but would not prevent increases from
occurring. In fact, national NO emissions would still increase by about
A
25 percent. Stationary gas turbines were selected for standards develop-
ment because they are significant sources of NO emissions and control
X
technology is available to reduce these emissions at reasonable costs.
2-20
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Some commenters also maintained that the characteristic high plume
rise of gas turbines results in negligible ground level concentrations,
which are not apt to be improved much by use of wet controls.
Standards of performance are designed to reflect best demonstrated
control technology (.considering costs) for affected sources. The over-
riding purpose of the collective body of standards is to improve existing
air quality and to prevent new pollution problems from arising, not to
achieve specific ambient air quality goals.
While it is true that simple cycle gas turbines have characteristi-
cally high plume rise, this is due to the extraordinarily high exhaust gas
temperatures (on the order.of 800? - 11007F). Plumes from combined cycle
and regenerative cycle gas turbines, however, does not share this charac-
teristic because their exhaust temperatures are much lower (on the order
of 200? - 400?F). In these cases, ground level NO concentrations can be
/v
significant and the standard will reduce these concentrations appreciably.
Adverse Hater Impact •
One frequent criticism concerned the potential impact of the stan-
dards on the nation's water supply. Commenters stated that the impact on
water resources has not been adequately considered. The commenters pointed
out that wet controls could result in water shortages in some areas of the
country and that the effluent from water treatment necessary for wet
controls could create water pollution problems. One commenter suggested
exemptions in the standards for periods of drought.
Th.e potential water pollution impact of standards based on wet con-
trols is minimal. The only potential source of water pollution is from
the treatment system for water used to control NO emissions. The quality
}\
2-21
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of the wastewater is essentially the same as that of the influent water
except that the concentration of total dissolved solids in the waste
stream is about three to four times that of the influent. The owner/
operator of the gas turbine would need a permit for the discharge, and,
while treatment requirements of the discharge may vary by locale, in most
cases, the effluent may be sewered directly or returned to the river,
lake, or other natural source.
The quantity of water required by a stationary gas turbine using wet
controls is relatively small. Even at a water-to-fuel ratio of 1:1 (a
worst case estimate, with 0.6:1 or 0.7:1 more typical), a gas turbine
using wet controls consumes only five percent of a comparably sized steam
boiler using cooling towers. Since 90 percent of the total U.S. gas
turbine capacity is utilized for electricity generation, for which the
only viable alternative would in fact be steam boiler utilization, the
impact of using wet controls on water supplies is quite reasonable.
The remainder of the U.S. gas turbine capacity is generally repre-
sented by turbines smaller than 10,000 hp and, for this group, the stan-
dard will have no impact on water supplies since, as discussed earlier,
these turbines will use dry controls to meet the 150 ppm standard which
becomes effective five years after promulgation. The five-year exemption
for small gas turbines was explicitly selected in order to provide manu-
facturers the time needed to implement dry control technology.
In addition, manufacturers will incorporate dry controls on gas tur-
bines of all sizes as quickly as this technology is developed. This trend
toward dry controls would tend to further lessen any impact the standard
would have on water pollution or water supplies.
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In specific instances of drought in a local geographical area, how-
ever, where temporary mandatory water restrictions are placed on homeowners
by governmental agencies, it seems reasonable to allow temporary exemp-
tions from the standards for gas turbines operating with water injection
for NOX control. Such an exemption has been incorporated into the stan-
dards; these exemptions, however, are to be determined by the Administra-
tor on a case-by-case basis.
Peaking Gas Turbines
A number of commenters felt gas turbines used as "peaking" units
should be exempt. Peaking units operate relatively few hours per year
(approximately 1,500). According to commenters, use of water injection
would result in a very small reduction in annual NO emissions and negli-
A
gible improvement in ground level concentrations.
Standards of performance under Section 111 of the Clean Air Act must
reflect the use of the best system of emission reduction (considering
costs).. The objective of Section 111 is to improve existing air quality
as older industrial sources of air pollution are replaced with new indus-
trial sources and to prevent new pollution problems from arising.
As pointed out in Volume I of the SSEIS, about 90 percent of all new
gas turbine capacity is expected to be installed by electric utility
companies to generate electricity, and possibly as much as 75 percent of
all N0x emissions from stationary gas turbines are emitted from these
installations. Of these electric utility gas turbines, a large majority
are used to generate power during periods of peak demand. Consequent-
ly, by their very nature, peaking gas turbines tend to operate when the
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need for emission control is greatest, that is, when power demand is
highest and air quality is usually at its worst. Therefore, it does not
seem reasonable to exempt peaking gas turbines from compliance with the
standards.
2.6 ENERGY IMPACT
Synthetic Fuel
A number of writers commented on the potential impact of the stan-
dards on the use of shale oil, coal-derived, and other synthetic fuels.
It was generally felt that these types of fuels should not be covered by
the standards at this time, since this could hinder further development of
these fuels. Commenters recommended that EPA wait until such fuels are
available and being fired successfully in gas turbines and then set the
fuel-bound nitrogen allowance for these fuels based on actual data.
Total NOV emissions from any combustion source, including stationary
/>
gas turbines, are comprised of thermal N0v and organic NO . Thermal NO
X A A
is formed in a well-defined high temperature reaction between oxygen and
nitrogen in the combustion air. Organic NOX is produced by the combina-
tion of fuel-bound nitrogen with oxygen during combustion in a reaction
that is not yet fully understood. Shale oil, coal-derived, and other
synthetic fuels have high nitrogen content and, therefore, produce rela-
tively high organic NO emissions.
/\ j
Control technology for gas turbines is effective for reducing thermal
NO , but not for reducing organic NO. Thermal NO emissions can be
X A A ,
reduced by 40 percent with dry control technology and by 70 percent with
wet control technology. Organic NO emissions are not reduced by wet
J\
control technology. The amount of organic NOX reduction achieved by dry
control technology, if any, is uncertain.
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As fuel-bound nitrogen increases, the organic NO emissions from a
X
gas turbine with thermal NO control become a predominant fraction of
X
total NOX emissions (See Figure 2-1). Consequently, the standards must
address in some manner the increased NO emissions caused by fuel-bound
X
nitrogen. Since NO emission control technology is not effective in
A
reducing organic NOX emissions from gas turbines, the possibility of
basing standards on removal of nitrogen from the fuel prior to com-
bustion was considered as an alternative. The cost of removing nitrogen
from the fuel ranges from $2.00 - $3.00 per barrel. Nitrogen removal
from the fuel, therefore, is not considered reasonable, as the basis for
standards of performance.
Two other alternatives were considered. Gas turbines using high
nitrogen fuels could be exempt from the standards, as some commenters
requested. Exempting turbines from the standard based on the type of fuel
used, however, would not require best available control technology in
cases where the application of such technology is feasible. The purpose
of the NSPS is to reduce NO emissions using the best demonstrated tech-
A
nological system of continuous emission reduction, considering costs.
The other alternative considered would establish a fuel-bound nitro-
gen allowance. Beyond some point it is simply not reasonable to allow
combustion of high nitrogen fuels. In addition, high nitrogen fuels,
including shale oil and coal-derived fuels, can be used in other combus-
tion devices in which control of organic NO emissions is possible. In
X
fact, utility boilers can achieve 30 - 50 percent reduction in organic NO
X
emissions. Greater reduction of nationwide NO emissions could be achieved
2-25
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O-
Q.
CO
s:
O
CO
CO
Z--.26
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by utilizing these fuels in facilities where organic NO emissions control
X
is possible rather than in gas turbines where organic NO emissions are
X
essentially uncontrolled. Therefore, this approach would balance the
trade-off between allowing unlimited selection of fuels and controlling
NO emissions.
X
Low nitrogen fuels, such as premium distillate fuel oil and natural
gas, are now being fired in nearly all stationary gas turbines. However,
energy supply considerations may cause more gas turbines to fire heavy
fuel oils and synthetic fuels in the future. A standard based on present
practice of firing low nitrogen fuels, therefore, would too rigidly restrict
the use Of high nitrogen fuel, especially in light of the uncertainty in
world energy markets. This is clearly not desirable.
A limited fuel-bound nitrogen allowance which would allow NO emissions
X
above the NO emission standard is most reasonable. An upper limit of 50
X
ppm NOV was selected because such a limit would allow approximately 50
X
percent of existing heavy fuel oils to be fired in stationary gas turbines
(for a more detailed discussion of the fuel-bound nitrogen allowance the
reader is referred to Volume I, Chapter 8 of the SSEIS). The fuel-bound
nitrogen allowance is considered a reasonable means of allowing flexibility
in the selection of fuels while retaining effective control of total NOV
X
emissions from stationary gas turbines.
Efficiency Correction Factor
One commenter requested that the heat rate term (Y) in the efficiency
correction equation for calculating the allowable NO emission cohcentra-
X
tion be redefined to permit substitution of a more appropriate value
whenever operating parameters or equipment changes are made by the owner/
operator that increase gas turbine thermal efficiency.
2- 27
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If operating changes are made which increase gas turbine thermal
efficiency, it does not seem reasonable to use a heat rate which is no
longer appropriate. Therefore, the heat rate term Y has been redefined as
the manufacturer's rated heat rate at manufacturer's rated peak load, or
the actual heat rate as measured at peak load for the gas turbine.
A number of commenters felt that the efficiency correction factor
included in the standard should use the overall efficiency of a gas tur-
bine installation rather than the thermal efficiency of the gas turbine
itself. For example, many commenters recommended that the overall effi-
ciency of a combined cycle gas turbine installation should be used in this
correction factor.
Section 111 of the Clean Air Act requires that standards of perfor-
mance for new sources reflect the use of the best system of emission
reduction. Water injection is considered the best system of emission
control for reducing NO emissions from stationary gas turbines. To be
X
consistent with the intent of Section 111, the standards must reflect the
use of water injection in the gas turbine, independent of any ancillary
waste heat recovery equipment, which might be associated with a gas tur-
bine. To allow an upward adjustment in the NO emission limit based on
X
the efficiency of the combined cycle gas turbine and boiler could mean
that water injection might not have to be applied to the gas turbine.
Thus, the standards would not be as effective or stringent as they would
be if they were based on the efficiency of the gas turbine alone, and this
would imply that the standards would not reflect the use of the best
system of emission reduction. Therefore, the use of the efficiency factor
must be based on the gas turbine efficiency itself, not the overall
2- 28
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efficiency of the gas turbine combined with other equipment.
Several commenters felt the .efficiency correction factor should be
exponential rather than linear. They made the point that since NO
/\
emissions theoretically increase exponentially with efficiency, it appears
inconsistent to allow only a linear increase in emissions for increased
efficiency. The commenters further stated that a linear correction could
discourage use of more efficient gas turbines at some point.
As discussed in Volume I of the SSEIS, it is simply not reasonable
from an emission control viewpoint to select an exponential efficiency
adjustment factor. Such an adjustment would at some point allow very
large increases in emissions for very small increases in efficiency. The
objective of the efficiency adjustment factor is to give an emissions
credit for the lower fuel consumption of high efficiency gas turbines.
Since fuel consumption of gas turbines varies linearly with efficiency, a
linear efficiency adjustment factor is included in the standards to
permit increased NO emissions from high efficiency gas turbines.
A
2.7 LEGAL CONSIDERATIONS
Priority List for Stationary Sources
Four comments were received regarding legal considerations. One
comment was that the proposed standard does not address the statutory
scheme as set forth in Section lll(f), as amended in August, 1977.
Section lll(f) requires EPA to establish a priority list, by August 7,
1978, of the categories of major stationary sources that had not been
listed under Section 111 by August 7, 1977. In the commenter's view,
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development of standards for gas turbines, as well as development of
other standards for sources listed as of August 7, 1977, must halt
pending publication of the priority list.
This conclusion is not supported by the legislative history of
Section lll(f). The purpose of the priority list is to ensure that all
categories of major stationary sources are regulated promptly under
Section 111. There is no indication that development of any standards
should halt pending the development of the priority list. Such a halt
could well last a year (the time allowed for publication of the priority
list), and a year's delay would substantially impair EPA's ability to
complete the task of regulating all categories of major stationary sources
by 1982 as required in Section 111.
Public Hearing Opportunity
Another comment was that gas turbines have not been designated as a
source category after notice and opportunity for a public hearing as set
forth in Section lll(f)(8).
Section Tll(g)(8). requires EPA to offer an opportunity for a public
hearing in proposing, among other things, the Section 111 priority list.
It does not require a public hearing in conjunction with the establishment
of a specific new source performance standard. Section 307 of the Clean
Air Act requires an opportunity for a public hearing but only if an NSPS
were proposed after November 5, 1977. Standards for gas turbines were
proposed on,October 3, 1977. Again, it would be contrary to the intent of
the Clean Air Act, as discussed above, to stop the NSPS program until the
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priority list is proposed and a public hearing held.
Requirement for a Percentage Reduction in Emissions
The meaning of "standard of performance" has changed as set forth in
Section 111 according to several commenters. It was pointed out that the
requirement of achieving a percentage reduction in emissions has been
included in Section 111.,
These commenters have apparently misconstrued the gas turbine stan-
dard and Section 111, as amended, to suggest that gas turbines designed to
comply with the proposed standards would later have to be redesigned to
meet a future gas,turbine standard that will include a requirement to
achieve a percentage reduction in NOX emissions. It is not clear if
Section 111 requires development of standards calling for a percentage
reduction in emissions from all fossil-fuel-fired stationary sources; the
legislative history of this provision deals only with utility power plant
boilers. The commenters1 impression that gas turbines designed to meet
the promulgated standards would have to be redesigned to meet a future
standard that will include a requirement to achieve a percentage reduction
in NOV emission is incorrect. Any such future standard would apply only
J\ . i
to gas turbines constructed, modified, or reconstructed after the date of
proposal of the future standards.
Conflicting Definitions
One commenter maintained that conflict exists between definitions in
the Clean Air Act as amended August 74 1977, and definitions in the General
Provisions of Part 60 which apply to all standards of performance.
The conflict specifically mentioned is in the definition of "standard"
or "standard of performance." However, the definition is quite general
and is consistent with the 1977 amendments.
2=31
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2.8 TEST METHODS AND MONITORING
Excessive Monitoring Requirements
A large number of commenters objected to the amount of monitoring
required. The proposed standards called for continuous monitoring of fuel
consumption and water/fuel ratio, and daily monitoring of sulfur content,
nitrogen content, and lower heating value (LHV) of the fuel. The commen-
ters were generally in favor of less frequent periodic monitoring.
The comments with respect to daily monitoring of sulfur and nitrogen
content and lower heating value of fuel seem reasonable. Therefore, the
standard has been changed to permit determination of these quantities only
when a fresh supply of fuel is added to the gas turbine fuel storage
facilities. However, in those cases in which gas turbines are fueled from
a pipeline transport system without intermediate storage, daily monitoring
is still required by the standard unless the owner or operator can show that
the composition of the fuel does not fluctuate from day to day. If this is
the case, then the owner or operator may submit a custom schedule outlining
the time interval for monitoring of fuel sulfur, nitrogen and lower heating
value. These custom schedules must be substantiated by data and approved
by the Administrator on a case-by-case basis.
Continuous monitoring of water-to-fuel ratio and fuel consumption is
retained in the standards. These parameters are readily measured by
existing techniques. Even in the case of turbines operated infrequently
or remotely, automatic recording techniques are available. Data can be
recorded and retrieved for documentation purposes without unreasonable
extra manpower application. In any case, such devices would likely be
installed for operational purposes.
In addition to objecting to the frequency of monitoring, several
commenters maintained that the gas turbine standard should allow fuel
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analysis by the fuel vendor, since vendors are generally equipped and
staffed for such analyses on a routine basis. The commenters pointed out
that parameters such as sulfur and nitrogen content and LHV require labor-
atory equipment and skilled laboratory personnel. Such facilities and
personnel are not generally a part of gas turbine installations, and their
establishment to meet the requirements of the gas turbine standards would
be uneconomical.
There is nothing in the gas turbine standards that specifically
requires an owner/operator to have the required analyses performed by
himself or his own personnel. Analysis required to meet the monitoring
requirements of the standard may be accomplished by anyone, so long, as the
methods used* comply with applicable parts of the standards. This means an
owner/operator may contract such analyses to qualified contractors or
obtain such; services from his fuel supplier if he so desires. The gas
turbine standard has been changed to clarify this point.
Acceptability of Manufacturers' Test in Lieu of Performance Tests
Several commenters stated that the regulation should be clarified to
allow the performance test to be performed by the manufacturer in lieu of
the owner/operator. These commenters viewed site testing procedures as
unnecessarily difficult, costly, and of questionable reliability. To
simplify verification of compliance with standards and to; reduce cost to
users, to the government, and to manufacturers, the. recommendation was
made that each gas turbine model be performance tested at the manufac-
turer's site. The commenters maintained that gas turbines should not be
required to undergo a performance test at the owner/operator's site if
they have been shown to comply with) the standard by the manufacturer.
Section 111 of the Clean Air Act is not flexible enough to permit the
use of a formal certification program such as that described by the commenter.
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Responsibility for complying with the standard ultimately rests with the
owner/operator, not with manufacturers. Thus, the gas turbine standard
does not formally include such a procedure for determining compliance.
Section 60.8 of the General Provisions, however, is applicable to all
standards of performance, and allows the use of approaches other than
performance tests on a case-by-case basis to determine compliance, if
the alternate approach demonstrates to the Administrator's satisfaction
that the facility is in compliance with the applicable standard. Con-
sequently, manufacturers' tests will be considered, on a case-by-case
basis, in lieu of performance tests at the owner/operator's site to
demonstrate compliance with the standard of performance for stationary
gas turbines. For a manufacturer's test to be acceptable in lieu of a
performance test, however, as a minimum the operating conditions of the
gas turbine at the installation site would have to be shown to be similar
to those during the manufacturer's test. In addition, this procedure
will not preclude the Administrator from requiring a performance test at
any time to demonstrate compliance^with the standard. It thus remains .
the ultimate responsibility of the owner/operator to comply with the gas
turbines standard.
Sampling Methodology—Method 20
Numerous comments were received regarding the sampling methodology
(Method 20). Two comments were received stating that the effect of a
moisture trap on NO and N02 sample concentrations should be studied and
specified in the method.
There is no indication that NO is removed from sample gas by contact
with condensed moisture. N02 will be absorbed in condensed moisture,
2-34
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especially if direct contact is allowed. N02 makes up about 2 to 3 per-
cent of the total NO gas concentration under peak load conditions of gas
A
turbine operation. Therefore, the maximum effect on the final concentra-
tion due to N02 loss is only a negative 2 to 3 percent bias under these
conditions.
An N02 to NO converter has been included in Reference Method 20 for
test conditions which produce significant proportions of N02, i.e., more
than 5 percent of the total NOV. The converter is placed upstream of the
A
moisture trap in the sample train to minimize the effect of N02 removal in
the moisture trap. In addition, the design of an acceptable moisture trap
is specified in Reference Method 20 and emphasizes the need to minimize
direct contact of the sample gas with the condensate.
Another commenter pointed out that calibration gas is introduced
downstream from the filter, whereas the gas sample is not. The commenter
points out that absorption of NOX on the filter and leakage at the filter
will reduce the concentration of NOY in the sample analysis.
A
Based on the nonreactive properties of NO, the los$ of NO on the
filter is expected to be negligible. Any leakage that occurs at the
filter or any component of the sample conditioning equipment is accounted
for by the 02 correction in the calculation of emissions. Reference
Method 20 has been revised, however, to reposition the calibration valve
assembly upstream of all sample conditioning equipment in order to allow
checks of the N02 to NO converter and to ensure that any losses that do
occur are detected.
One commenter expressed the opinion that sample transport lines from
the probe to the analyzer should be reduced to produce response times of
2-35
-------
30 seconds or less in order to minimize any reaction of NOX with the
sampling system.
EPA agrees that the sample transport time should be minimized and has
included a specification for this factor in the method.
Objections were expressed by another commenter regarding the number
of sampling points. The commenter maintained that the necessity for such
a large number of cross-sectional sampling points at the sampling site
should be reviewed in light of the fact that this is gaseous sampling as
opposed to particulate sampling.
In the exhaust from gas turbines, stratification of NOX concentra-
tions is likely and must be taken into account during the performance
test. The requirement to use the specified 8 sample points is not un-
realistic, nor is it unduly restrictive.
One commenter felt that the reference method for oxygen concentration
determinations should be the paramagnetic analyzer method.
EPA does not normally specify a particular type of test equipment,
but instead, requires the test equipment to meet minimum operational
requirements and calibration specifications. In this case, several types
of 02 analyzers can be acceptable for the Reference Method.
One writer requested allowance for use of equivalent analytical
methodology for measuring pollutants, without Administrator approval, as
agreed upon by regional EPA or state authorities and the company operating
the turbine. This is already allowed. As in many cases, the EPA Admini-
strator is represented by the EPA Regional office. The Office of Air
Quality Planning and Standards represents the EPA Administrator only in
those cases where alternative methods are approved for nationwide use.
2- 36
-------
Another writer commented that the NOV analyzer range specification
A
should allow a higher-than-120-ppm range.
The 120-ppm range was chosen to maintain a satisfactory degree of
resolution in the range of emission measurements and to have the measure-
ments at the level of the standard at mid-scale. Because of adjustments
to the emission standard allowed in the revised regulation, the 120-ppm
span level may be exceeded and the gas turbine may still be in compliance.
Reference Method 20 has been revised to specify calibration gas levels and
measurement ranges based on span levels specified in the regulation. The
span level is chosen to allow the accuracy and resolution required of the
method and to allow*measurement of emissions over the expected range.
One commenter indicated that traceability should be insured by using
standard reference gases available from NBS and by using a protocol currently
being developed by Environmental Monitoring Systems Laboratory, EPA. (6T-
29)
At this time there is no traceability protocol published for source
level gas cylinders. Reference Method 20 provides for inclusion of such
procedures when they become available.
One criticism was.that Method 7 for analysis of NOX calibration gas
mixtures should not be the recommended method since it has been shown to
be extremely variable.
EPA recognizes that Reference Method 7 produces variable results at
*>
low NO concentrations, but careful laboratory practices and proper
/\
administered sampling can produce acceptable results. Detailed procedures
for establishing cylinder concentrations have been developed to insure
reliable results.
2- 37
-------
According to one commenter, measurement system calibration is not
adequately precise. The nitrogen oxides analyzer should be spanned at 90
percent (± 10 percent) of the expected measured NOX value.
To set the span value at this high concentration would prohibit
measurement of excess emissions if such occurred. The calibration values
and procedures required in Reference Method 20 provide adequate analysis
precision and accuracy for the emissions determination.
One commenter maintained that Method 20 does not guarantee that the
sample is representative; thus it does not assure that there have been no
errors. The commenter suggests the use of a carbon balance to assure a
representative sample. In the suggested technique, the following measure-
ments are required: fuel input rate, fuel analysis, effluent volumetric
flow rate, effluent hydrocarbons, C02, and CO.
The carbon balance technique is a good method for providing repre-
sentative flow rate and carbon measurements. These determinations are not
required for the gas turbine NOX standard. Representative NOX measure-
ments are handled in Reference Method 20 by the requirement of a suitable
number of sample points. Data from many sources indicate that stratifica-
tion problems in stacks can be corrected by multi-point sampling and
proper positioning of the probe.
Two commenters felt that the accuracy of the method has not been
adequately specified.
The accuracy of Reference Method 20 is dependent on the proper
introduction and certification of calibration gases and proper sample
collection. Both of these criteria are addressed in Reference Method 20.
If the method is followed correctly, accuracy should be on the order of
2-38
-------
reproducibility of the method.
Alternative Sulfur Measurement Method
One commenter suggested that alternative methods for determining
sulfur content of the fuel should be allowed. The writer proposed that
several alternative methods would serve the purpose as well as ASTM
02880-71, which Was specified in the proposed standard.
The valfdity of using alternative test methods is recognized. In
fact, there are provisions made for alternative methods in the General
•$p;.'
Provisions. Thus, subject to prior approval, on a case-by-case basis,
alternative methods of measurement are acceptable.
2-39
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TABLE 2-1
LIST OF COMMENTERS ON THE PROPOSED STANDARDS OF PERFORMANCE
FOR STATIONARY GAS TURBINES
Commenter
GT-1
Affiliation
Richard F. Rienter
Assistant Administration - Electric
U. S. Department of Agriculture
Rural Electrification Administration
Washington, D. C. 20250
6T-2
J. M. Otts, Jr., Vice-President
Gulf Energy & Minerals Company
Post Office Box 2100
Houston, Texas 77001
GT-3
Charles W. Whitmore
State Coordinator, Air Support
Air & Hazardous Materials Division
Region VII
Environmental Protection Agency
Research Triangle Park, North Carolina 27/11
GT-4
M. F. Tyndall, Project Manager
Catalytic, Incorporated
Centre Square West
1500 Market Street
Philadelphia, Pennsylvania 19102
GT-5
J. V. Day, Manager
Environmental Affairs
Kaiser Aluminum & Chemical Corporation
300 Lakeside Drive
Oakland, California 94643
GT-6
John M. Vaught, Chairman
ASME Gas Turbine Division
Combustion Research & Development
Detroit Diesel Allison
Post Office Box 894
Indianapolis, Indiana 46206
2-40
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Commenter
6T-7
Affiliation
Don E. Gerard, General Manager
Board of Public Utilities
City of McPherson, Kansas 67460
GT-8
D. McKnight
Assistant Chief Development Engineer
Rolls-Royce Limited
Post Office Box 72
Ansty, Coventry CV7 9JR
GT-9
D4 R. Plumley
General Electric
One River Road
Schenectady, New York 12345
GT-lO
James L* Grahl
Basin Electric Power Cooperative
1717 East Interstate Avenue
Bismarck, North Dakota 58501
GT-11
Perry G. Brittain, President
Texas Utilities Services, Incorporated
2001 Bryan Tower
Dallas, Texas 75201
GT-12
K. A. Krumwiede
Southern California Edison Company
Post Office Box 800
Rosemead, California 91770
GT-13
J. Thomas Via, Jr., Vicer-President
Tucson Gas & Electric Company
Post Office Box 711
Tucson, Arizona 85702
GT-14
S. David Childers* Attorney
Law Department
Salt River Project
Post Office Box 1980
Phoenix, Arizona 85001
2-41
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Comments
GT-15
Affiliation
R. J. Moolenaar
Environmental Sciences Research
Dow Chemical U. S. A.
Midland, Michigan 48640
GT-16
W. J. Coppoc, Vice-President
Environmental Protection
Texaco Incorporated
Post Office Box 509
Beacon, New York 12508
GT-17
Raymond E. Kary, Ph.D., Manager
Environmental Management Department
Arizona Public Service Company
Post Office Box 21666
Phoenix, Arizona 85036
GT-18
WilliamS. LaLonde, III, P.E., President
National Energy Leasing Company
Elizabeth Plaza
Elizabeth, New Jersey 07207
GT-19
H. D. Belknap, Jr., Assistant Counsel
Southern California Edison Company
Post Office Box 800
Rosemead, California 91770
GT-20
GT-21
0. Morris Si evert, President
Solar Turbines International
Post Office Box 80966
San Diego, California 92138
James A. Shissias, General Manager
Environmental Affairs
Public Service Electric & Gas Company
80 Park Place
Newark, New Jersey 07101
GT-22
George Opdyke, Jr., Manager
Combustor Section
Avco Lycoming Divsion
550 South Main Street
Stratford, Connecticut 06497
2-42
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Comments
GT-23
Affiliation
W. H. Axtman, Assistant Executive Director
American Boiler Manufacturers Association
Suite 317 - AM Building
1500 Wilson Boulevard
Arlington, Virginia 22209
GT-24
Douglas W. Meaker, Technical Director
Reigel Products Corporation
Subsidiary of James River Corporation
Mil ford, New Jersey 08848
GT-25
GT-26
S. J. Thomson, P. E.
1174 Gleneagles Terrace
Costa Mesa, California 92627
I. H. Gilman, General Manager
Environmental Affairs
Chevron U. S. A. Incorporated
Post Office Box 3069
San Francisco, California 94119
GT-27
W. Samuel Tucker, Jr., Manager
Environmental Affairs
Florida Power & Light
Miami, Florida 33101
GT-28
John M. Daniel, Jr., P. E.
Assistant Executive Director
Commonwealth of Virginia
State Air Pollution Control Board
Room 1106 - Ninth Street Office Building
Richmond, Virginia 23219
GT-29
John B. Clements, Chief (MD-77)
Quality Assurance Branch
Environmental Monitoring and Support Laboratory
Environmental Protection Agency
Research Triangle Park, North Carolina 27711
GT-30
John G. Farley, Jr., Manager
Environmental Licensing Department
Southern Company Services, Incorporated
Post Office Box 2625
Birmingham, Alabama 35202
2-43
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Commenter
GT-31
Affiliation
B. E. Davis, System Engineer
Environmental Regulation
Duke Power Company
Steam Production Department
Post Office Box 2176 .
Charlotte, North Carolina 28242
GT-32
L. A. McReynolds, Manager
Environmental and Consumer Protection
Phillips Petroleum Company
Bart!esvilie, Oklahoma 74004
GT-33
F. D. Bess, Manager
Regulatory Coordination and Information
Union Carbide Corporation
Post Office Box 8361
South Charleston, West Virginia 25303
GT-34
Robert A. McKnight
Chief Environmental Engineer
Inianapolis Power & Light
Indianapolis, Indiana 46206
GT-35
John R. Thorpe, Manager
Environmental Affairs
GPU Service Corporation
260 Cherry Hill Road
Parsippany, New Jersey 07054
GT-36
Jack M. Heineman, Advisor
Environmental Quality
Federal Energy Regulatory Commission
Washington, D. C. 20426
GT-37
Charles Custard, Director
Office of Environmental Affairs
Department of Health, Education & Welfare
Office of the Secretary
Washington, D. C. 20201
2-44
-------
Commenter
GT-38
Affiliation
J. B. Miller, President
Rio Blanco Oil Shale Project
9725 E. Hampden Avenue
Denver, Colorado 80231
GT-39
P. W. Howe, Vice-President
Technical Services
Carolina Power & Light Company
Post Office Box 1551
Raleigh, North Carolina 27602
6T-40
James L. Grahl, General Manager
Basin Electric Power Cooperative
1717 East Interstate Avenue
Bismarck, North Dakota 58501
GT-41
R. M. Robinson, Coordinator
Environmental Conservation
Continental Oil Company
Houston, Texas 77001
GT-42
M. C. Steele, Assistant Director
Engineering
Airesearch Manufacturing Company
of Arizona
Post Office Box 5217
Phoenix, Arizona 85010
GT-43
M. W. Beard, P. E.
2529 Cardillo Avenue
Hacienda Heights, California 91745
GT-44
J. Albert Curran
Vice-President and Secretary
C F Braun & Company, Engineers
Alhambra, California 91802
2-45
-------
Commenter
GT-45
Affiliation
Douglas L. Lesher, Chief
Permit Section
Division of Abatement & Compliance
Bureau of Air Quality and Noise Control
Commonwealth of Pennsylvania
Department of Environmental Resources
Post Office Box 2063
Harrisburg, Pennsylvania 17120
6T-46
H. D. Ege, Jr., P. E.
Burns & McDonnell
Engineers-Architects-Consultants
Post Office Box 173
Kansas City, Missouri 64141
GT-47
Larry E. Meierotto
Deputy Assistant Secretary
United States Department
of the Interior
Washington, D. C. 20240
GT-48
R. J. Corbeil, Manager
Environmental Affairs
Southern California Gas Company
Box 3249 - Terminal Annex
Los Angeles, California 90051
GT-49
W. B. Read, President
The Oil Center
2150 Westbank Expressway
Harvey, Louisiana 70058
GT-50
W. D. Cleaver, Assistant Vice-President
Northern Illinois Gas
Post Office Box 190
Aurora, Illinois 60507
GT-51
R. C. Jackson, Chairman
Pipeline Research Committee
American Gas Association
1515 Wilson Boulevard
Arlington, Virginia 22209
2-46
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Commenter
GT-52
Affiliation
R. W. Hospodarec, P. E.
3652 Pine street
Irvine, California 92714
6T-53
William T. Turner, Jr., Vice-President
Engineering
Texas Gas Transmission
3800 Frederica Street
Owensboro, Kentucky 52301
GT-54
D. R. Plumley
General Electric Company
One River Road
Schenectady, New York 12345
GT-55
Lawrence J. Ogden, Director
Construction & Operations
Interstate Natural Gas Association
1660 L Street Northwest
Washington, D. C. 20035
GT-56
Rodger L. Staha, Ph.D.
Air Quality Advisor - Environmental Quality
Pacific Gas and Electric Company
77 Beale Street
San Francisco, California 94106
GT-57
Waifred E. Hensala, P. £.» Manager
Environmental Affairs
Post office Box 1526
Salt Lake City, Utah 84110
GT-58
John Mi Craig, Director
Environmental Affairs
El Paso Natural Gas Company
Post Office Box 1492
El Paso, Texas 79978
GT-59
Albert C. Clark
Vice-President/Technical Director
Manufacturing Chemists Association
1825 Connecticut Avenue, Northwest
Washington, D. C. 20009
2-47
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Coromenter
GT-60
Affiliation
T. H. Rhodes, Manager
Environmental Conservation
Exxon Chemical Company U. S.
Post Office Box 3272
Houston, Texas 77001
A.
GT-61
Thomas R. Hanna, Supervisor
Air Quality Control - State of Alaska
Department of Environmental Conservation
Pouch 0
Juneau, Alaska 99811
GT-62
D. R. Jones, manager
Longe Range Development
Generation Systems Division
Westinghouse Electric Corporation
Lester Branch Box 9175
Philadelphia, Pennsylvania 19113
GT-63
H. H. Meredith, Jr., Coordinator
Public Affairs Department
Environmental Conservation
Exxon Company U. S. A.
Post Office Box 2180
Houston, Texas 77001
GT-64
D. G. Assard, Director
Engineering
United Technologies
Power Systems Division
1690 New Britain Avenue
Farmington, Connecticut 06032
GT-65
T. M. Fisher, Director
Automotive Emission Control
Enviromental Activities Staff
General Motors Corporation
Warren, Michigan 48090
GT-66
Robert W. Welch, Jr., Vice-President
Environmental Affairs
Columbia Gas Systems Service Corporation
20 Montchanin Road
Wilmington, Delaware 19807
2-48
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Commenter
Affiliation
GT-67
Donald W. Moon
Senior Environmental Analyst
Salt River Project
Post Office Box 1980
Phoenix, Arizona 85001
6T-68
R. H. Gay!ordj Senior Engineer
Advanced Projects Engineering
Brown Boveri Turbomachineryi Incorporated
711 Anderson Avenue North
Saint Cloud» Minnesota 56301
GT-69
Howard A, Koch, Manager
Atlantic Richfield Company
North American Producing Division
Dallas* Texas 52311
GT-70
C. W. Kern, Supervisor
Environmental Planning
Northern Indiana Public Service Company
5265 Hohman Avenue
Hammond, Indiana 46325
GT-71
V. Rock Grundman, Jr.j Counsel
Government/Business Affairs
Dresser Industries, Incorporated
Dresser Building - Elm at Akard
Dallas, Texas 75221
GT-72
F. R. Fisher* Manager
Environmental Protection
Alyeska Pipeline Service Company
Post office Box 4-Z
Anchorage, Alaska 99509
GT-73
W. HL Pennington, Director
Office of National Environmental
Policy Act Coordination
Department of Energy
Washington, D. C. 20545
2-49
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Commenter
GT-74
Affiliation
W. M. Hathaway, Vice-President
Process and Environmental Engineering
Flour Engineers and Constructors, Inc.
Post Office Box 11977
Santa Ana, California 92711
GT-75
C. H. Golliher, Supervisor
Environmental Services Division
Iowa-Illinois Gas & Electric
Post Office Box 4350
Davenport, Iowa 52808
GT-76
John 0. Kearney, Senior Vice-President
Edison Electric Institute
1140 Connecticut Avenue, N. W.
Washington, D. C. 20036
GT-77
William W. Hopkins, Executive Director
Alaska Oil and Gas Association
505 West Northern Lights Boulevard
Suite 219
Anchorage, Alaska 99503
6T-78
John F. Vogt, Jr., Vice-President
Engineering and Operations
Middle South Services, Incorporated
Box 61000
New Orleans, Louisiana 70161
2-50
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TECHNICAL REPORT DATA
(Please read Instructions on the reverse before completing)
1. REPORT NO.
EPA-45Q/2-7-7-017b
3. RECIPIENT'S ACCESSION NO.
4. TITLE AND SUBTITLE
Standards Support and Environmental Impact
Statement, Volume II: Promulgated. Standards of
Performance for Stationary Gas Turbines
5. REPORT DATE
September 1979
6. PERFORMING ORGANIZATION CODE
7. AUTHOR(S)
8. PERFORMING ORGANIZATION REPORT NO
9. PERFORMING ORGANIZATION NAME AND ADDRESS
Standards Development Branch .
Emission Standards and Engineering Division
Research Triangle Park, N. C. 27711
10. PROGRAM ELEMENT NO.
11. CONTRACT/GRANT NO.
12. SPONSORING AGENCY NAME AND ADDRESS
13. TYPE OF REPORT AND PERIOD COVERED
OAA for Air Quality Planning and Standards
Office of Air and Waste Management
U.S. Environmental Protection Agency
Research Triangle Park, N. C. 27711
14. SPONSORING AGENCY CODE
EPA/200/04
Volume I discussed the proposed standards and the resulting
environmental and economic effects. Volume II contains a summary of public comments,
EPA responses and a discussion of differences between the proposed and promulgated
3. ABSTRACT stanaaras. ~~~
15. SUPPLEMENTARY NOTES
Standards of performance to control nitrogen oxides and sulfur dioxide
emissions from new, modified and reconstructed stationary gas turbines in the
U.S. are being promulgated under section 111 of the Clean Air Act. This
document contains information on the public comments made after proposal, EPA
responses and differences between the proposed and promulgated standards.
17-
KEY WORDS AND DOCUMENT ANALYSIS
DESCRIPTORS
b.lDENTIFIERS/OPEN ENDED TERMS
c. COSATI Field/Group
Gas Turbines
Air pollution control equipment
Standards of Performance
Air pollution control
sulfur dioxides
Nitrogen oxides
Water injection , T
18. DISTRIBUTION STATEMENT
Unlimited - Available to the public free
of charge from: U.S. EPA Library (MD-35)
' M: C. 2771]
19. SECURITY CLASS (ThisReport)
unclassified
21. NO. OF PAGES
60
20. SECURITY CLASS (This page}
unclassified
22. PRICE
EPA Form 2220-1 (Rev. 4-77)
PREVIOUS .EDITION IS OBSOLETE
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