APTD-1495
February 1974
EXHAUST EMISSIONS FROM
UNCONTROLLED VEHICLES
AND RELATED EQUIPMENT USING
INTERNAL COMBUSTION ENGINES:
PART 6 • GAS TURBINE ELECTRIC UTILITY
POWER PLANTS
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APTD-1495
EXHAUST EMISSIONS FROM
UNCONTB~OLLED VEHICLES
AND RELA TE:D EQUIPMENT USING
INTERNAL C4)MBUSTION ENGINES:
PART 6 - GAS TURBINE ELECTRIC UTILITY
POWER PLANTS
Prepared by
C~~~~l~s T Hare and Karl J. Springer
Southwest Research Institute
San Antonio, Texas
Contract No. EHS 70-108
EPA Project Officer:
William Roger Oliver
Prepared for
u . S. ENVIRONMENTAL PROTECTION AGENCY
Office of Air and Waste Management
Office of Mobile Source Air Pollution Control
Emission Control Technology Division
Ann Arbor, Michigan 48105
February 1974
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This report is issued by the Environmental Protection Agency to report
technical data of interest to a limited number of readers. Copies are
available free of charge to Federal employees, current contractors and
grantees, and nonprofit organizations - as supplies permit - from the Air
Pollution Technical Information Center, Environmental Protection Agency,
Research Triangle Park, North Carolina 27711; or, for a fee, from the
National Tcchnical Information Service, 5285 Port Royal Road, Springfield,
Vil'ginia 22151.
This report was furnished to the Environmental Protection Agency by
Southwest Research Institute, in fulfillment of Contract No. EHS 70-108.
The contents of this report are reproduced herein as received from
Southwest Research Institute. The opinions, findings, and
conclusions expressed are those of the author and not necessarily those
of the Environmental Protection Agency. Mention of company or product
names is not to be considered as an endorsement by the Environmental
Protection Agency.
Publication No. APTD-1495
ii
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ABSTRACT
This report is Part 6 of the Final Report on Exhaust Emissions
From Uncontrolled Vehicles and Related Equipment Using Internal Com-
bustion Engines, Contract EHS 70-108. In contrast to the other phases
of the subject contract, no measurements of emis sions from the source
under consideration (Gas Turbine Electric Utility Powerplants) were
taken as part of the research project. The reasons for this departure
from normal practice were that information on gas turbine emissions
available in the literature was deemed sufficient (at least on the major
emissions) and that the small test effort possible within the scope of the
contract would hardly add anything worthwhile to that body of knowledge.
Emission measurements which are used in this report were mostly
taken on- site where the generating units were located, although a few tests
have been conducted under laboratory conditions. Groups which performed
the actual emissions test work are referenced later; and they include man-
ufacturers, private research organizations, and government agencies.
Data are presented on turbines manufactured by General Electric, Turbo
Power & Marine, and Westinghouse. Emissions data include NO, NOZ'
and NOx measured by a variety of techniques; a less substantial amount
of CO and hydrocarbon data; either COZ or 0z (occasionally both) for a
given test; and ~cattered information on SOx' particulate, visible smoke,
and less important pollutants.
These emissions data are utilized together with information on
the location and population of turbine electric utility powerplants to esti-
mate national emissions impact, based on usage as reported to the Federal
Power Commission. Where possible, type of fuel used (gas or liquid)
will be taken into account, since fuel type has a pronounced effect on emis sions.
iii
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FOREWORD
The project for which this report constitutes part of the end
product was initiated jointly on June 29, 1970 by the Division of Motor
Vehicle Research and Development and the Division of Air Quality and
Emission Data, both divisions of the agency known as NAPCA. Cur-
rently, these offices are the Emis sion Characterization and Control
Development Branch of MSAPC and the National Air Data Branch of
OAQPS, respectively, Office of Air and Water Programs, Environmental
Protection Agency. The contract number is EHS 70-108, and the project
is identified within Southwest Research Institute as 11-2869-001.
This report (Part 6) covers the gas turbine electric utility power-
plant portion of the characterization work only, and the other items in
the characterization work have been or ""ill be covered by six other parts
of the final report. In the order in which the final reports have been or
will be submitted, the seven parts of the characterization work include:
Locomotives and Marine Counterparts; Outboard Motors; Motorcycles;
Small Utility Engines; Farm, Construction, and Industrial Engines; Gas
Turbine Electric Utility Powerplants; and Snowmobiles. Other efforts
which have been conducted as separate phases of Contract EHS 70-108
include: measurement of gaseous emissions from a number of aircraft
turbine engines, measurement of crankcase drainage from a number of
outboard motors, and investigation of emissions control technology for
locomotive diesel engines; and those phases either have been or will be
reported separately.
Cognizant technical personnel for the Environmental Protection
Agency are currently Messrs. William Rogers Oliver and David S.
Kircher; and past Project Officers include Messrs. J. L. Raney, A. J.
Hoffman, B. D. McNutt, and G. J. Kennedy. Project Manager for South-
west Research Institute has been Mr. Karl J. Springer, and Mr. Charles T.
Hare has carried the technical responsibility.
A great deal of the initial effort on gathering statistics for this
report was expended by Mr. Charles M. Urban, senior research engineer
at SwRI; and his contributions are sincerely appreciated.
iv
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T ABLE OF CONTENTS
Page
LIST OF ILLUSTRATIONS
vi
LIST OF TABLES
Vll
1.
INTRODUCTION
1
II.
OBJECTIVES
2
Ill.
PRESENTATION OF AVAILABLE DATA ON
EMISSIONS
3
IV~
PRESENTATION OF POPULATION AND USAGE
DATA '
11
V.
DEVELOPMENT OF EMISSION FACTORS
14
VI.
ESTIMATION OF NATIONAL EMISSIONS IMPACT
18
VII.
SUMMAR Y
22
LIST OF REFERENCES
23
APP ENDIX
v
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Figure
1
2
3
4
5
LIST OF ILLUSTRATIONS
Specific Emis sions of NOx as a Function of Load
for Gas Turbine-Powered Generators Manufactured
by Westinghouse, Turbodyne, and Turbo Power &
Marine
Specific Emissions of NOx as a Function of Load
for Gas Turbine-Powered Generators Manufactured
by General Electric
Specific Emissions of CO as a Function of Load for
Gas Turbine-Powered Genera.tors, Composite of
Several Makes and Models
Specific Emissions of Hydrocarbons as a Function
of Load for Gas Turbine-Powered Generators,
Composite of Several Makes and Models
Specific Emissions of Particulate and SOx as a
Function of Load for Gas Turbine-Powered Gen-
erators, Composite of Several Makes and Models
vi
Page
5
6
7
8
9
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Table
--
1
)
....
3
-t
5
6
7
8
9
10
11
LIST OF TABLES
Constants Used for Computation of Mass Emissions
Sum.mary of Power Output Capability of Gas Tur-
bine Electric Utility Powerplants
Postulated Operating Cycle for Electric Utility
Turbines
NOx Emission Factors for Electric Utility Turbines
Factors for Emissions of HC, CO, Particulate,
and SOx from Electric Utility Turbines
Composite Emission Factors for the 1971 Population
of Electric Utility Turbines
Computations Leadi.ng to 1971 National Impact
Estimates for Electric Utility Gas Turbines
Annual Emission Rates from Electric Utility
Turbines Based on National Population as of
12/31/72
Comparison of Electric Utility Turbine National
Impact Estimates with EPA Nationwide Air Pol-
lutant .Inventory Data
Definition of Areas U sed to Outline Distribution
of Emissions from Gas Turbine Electric Utility
Powerplants
Breakdown of Emissions from Electric Utility
Turbines by Geographic Area
vii
Page
3
11
13
15
16
17
19
19
20
20
21
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1.
INTRODUCTION
The program of research on which this report is baseod was
initiated by the Environmental Protection Agency to (1) characterize
emissions from a broad range of internal combustion engines in order
to accurately set priorities for future control, as required and (2)
as sist in developing more inclusive national and regional air pollution
inventories. This document, which is Part 6 of what is planned to be
a seven part final report, concerns emis sions from gas turbine electric
utility powerplants and the national impact of these emissions.
The emissions data presented in this report are from numerous
sources, but no emissions tests as such were performed under the sub-
ject contract. This approach was taken to make the best possible use
of both available funds and available data. The data- gathering operation
was performed during the first several months of 1973, with the report
activity scheduled subsequently as permitted by other work phases of
the contract.
1
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II.
OBJECTIVES
The objectives of the gas turbine electric utility powerplant part
of this project were to obtain emissions data and information on engine
population and usage and to estimate emission factors and national impact
on the basis of the data acquired. Insofar as available in the literature,
it was intended to compile data on emissions of hydrocarbons, CO, NOx
(or NO or NO 2), SOx' and C02 and/ or ° 2' Although it was recognized
that only minimal amounts of data might be available, it was also intended
to characterize aldehydes and particulate as well as possible.
Since the emissions measurements reported were not under the
contractor's control, several types of measurement techniques were used.
It was necessary in some cases to separate the measurements reported
on the basis of technique and to eliminate those which did not appear
credible.
2
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III.
PRESENTATION OF AVAILABLE DATA ON EMISSIONS
Data on emissions from gas turbines as used in electrical gener-
ation service comes from a number of sources(I-13)':<; but unfortunately,
.there is little agreement among the sources on the terms in which the
emissions are expres sed. The efforts represented by this section of
the report, then, include acquisition of the data and its conversion to
uniform terms. This conversion often involved assumptions on engine
air flow or fuel flow rates (based on manufacturers' data), since many
sets of measurements were not complete. Another shortcoming of the
available information was that relatively few data were obtained at loads
below maximum rated (or base) load.
Calculation of mass emission rates was made on the basis of
lbm/hr, since this unit seemed to be most commonly used in the litera-
ture. The equations used to calculate mass rates from concentration
data were quite standard for research work. In those cases in which
exhaust rate data were available, the general equation used was:
IbmX/hr = Kx (ppm X) (exhaust flow, lbm/hr)
When fuel rate data were available, the equation used was:
IbmX/hr = 'Cx (ppm X) (fuel, lbm/hr)/TC
where TC = o/cCO + C02 + o/cHC as C,or TC ~ o/cC02 for all conditions
except idle. The last part of this statement means that very little HC
and CO occur under load, and consequently that almost all the carbon
in the exhaust appears as C02. Refer to Figures 3 and 4 for confirmation
of these trends. The constants Kx and Cx are given in Table 1, noting that
TABLE 1.
CONSTANTS USED FOR COMPUTATION OF MASS EMISSIONS"
Cx
Constituent X Kx Gas Fuel-(CH3.8)n Oil Fuel-(CH2)n
-6 -4 -4
NOx 1. 59xl0 -6 2.90xlO 3.28xlO
HC-(CH3. 8)n -4
0.547xlO-6 1.00xlO ---------
-4
HC-(CH3)n 0.519xlO 6 0.949xlO ---------
-4
HC-(CH2)n 0.484xI0=6 ---------- 1. OOxlO -4
. -4
CO 0.967xlO 1. 77xlO 2.00xlO
SOx 2.21xI0-6 4.04xI0-4 4. 57xlO-4
Particulate, grains/SCF 1. 87xlO-3 0.342 0.387
':
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particulate concentrations are given in grains/ standard cubic foot rather
than ppm. The constants Cx are computed by the relationship:
C = 100 (molecular wt. of X) xl 0-6
x molecular wt. of fuel per carbon atom
and the constants Kx are computed by:
molecular wt. of X 6
K x!O-
x = molecular wt. of exhaust
Since fuel/ air ratios for turbines are quite low, the molecular weight of
the exhaust was uniformly assumed to be that of air (28.97). The exhaust
hydrocarbon compositions as sumed for gas fuels were (CH3. 8)n for
"methane" or lIunburned fuel" hydrocarbons and (CH3)n if all the hydro-
carbons were taken together in a single concentration value. Standard
conditions were assumed to be 60° F (15.6° C) and 1 atmosphere.
Where emission rates were expressed on the basis of energy input,
it was sometimes necessary to assume fuel heating values. The assumptions
made were a: gross heating value (HHV) of 19, 700 BTU / lbm and a net heating
value (LHV) of 18, 700 BTU / Ibm for liquid fuels and an HHV of about 22,000
BTU/lbm for natural gas (a gas density of 0.047lbm/SCF was also assumed).
In order to make an equitable evaluation of emissions from all the turbines
on which data are available, it was decided to compute emissions in lbm/
megawatt hour as a function of pe rcentage of rated load. Computing the
specific emissions in this manner permits curves to be drawn which are as
representative as possible of emissions from the most popular turbine
models, and these curves are shown in Figures 1 through 5. The data used
to generate Figures I through 5 are given in the Appendix. Table A-I shows
the data as obtained from the references, and Table A-2 lists the data after
conversion to uniform units (lbm/Mwh).
Figures 1 and 2 show typical NOx emissions for commonly-used
turbines, and these two figures could have been combined but with some
penalty in legibility. It appears obvious that design differences between
turbines do have some effect on NOx emissions, but. these differences are
not so apparent for other exhaust constituents. Figures 3, 4, and 5 are
composites of data available on all types of turbines used in electric utility
service; and the reasons for combining data from different units are that
(1) only a very few data were available on which to base each curve, and
(2) no substantial differences were observed from one engine type to another.
In addition to the data depicted by Figures 1 through 5, some information
was acquired on emissions under zero load conditions which cannot, of
course, be plotted in terms of mass per unit work output. These figures
for the TP&M GG4-FT4 unit are 71.5 Ibm CO/hr and 24.6 Ibm HC/hr at low
idle, and 165 Ibm CO/hr and 61.6 Ibm HC/hr at synchronous idle. For the
G. E. MS5001-N unit at high idle (breaker open), CO emissions are 205
4
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26 Curve Gas Generator Turbine
Fuel Mfr.
A P &W GG4 P&W FT4 Oil TP & M
24 B West. 251 or 501 West. 251 or 501 Oil West.
C P&W GG4 P&W FT4 Gas TP & M
D P & W GG4 Worthington Oil Turbodyne
22 E P&W GG4 Worthington Gas Turbodyne-
20
\
18 \
\
..c: \
~ \
~ 16 \
-
6 \
.0 , A
- 14 \
,
.. ,
rn ,
c: ,
0 ...
..-4 12
rn ,
rn ,
.s '
...
....
~ 10
><
0
Z 8 C
\
6 \\
\ ,
, ...
... ...
... ...
...~
4 E
2
0
0 25 50 75 100 125
o/c Rated Load
FIGURE 1. SPECIFIC EMISSIONS OF NOx AS A FUNCTION
OF LOAD FOR GAS TURBINE-POWERED GENERATORS MANUFACTURED
BY WESTINGHOUSE, TURBODYNE, AND TURBO POWER & MARINE
5
-------
I
26 Curve Mf r. and Model Fuel
A G. E. MS500l-LA Oil
24 B G. E. MS500l-N Oil
C G. E. MS700 I-A Oil
22
20
18
..c:
~ 16
~
-
6
..D 14
~
..
CJ)
q
a 12
.M
CJ)
CJ)
.M
S
riI 10
~ C '
o
z '
8 '
'"
"
6
4
2
0
0 25 50 75 100 125
o/c Rated Load
FIGURE 2. SPECIFIC EMISSIONS OF NOx AS A
FUNCTION OF LOAD FOR GAS TURBINE-POWERED
GENERATORS MANUFACTURED BY GENERAL ELECTRIC
6
-------
20
18 .
16
..c:: 14
~
~
-
S 12
.D
.....
..
00
c:
o
..-1
00
00
..-1
S
~
o
u
10
8
6
4
2
o
o
25
50 75
o/c Rated Load
100
125
FIGURE 3. SPECIFIC EMISSIONS OF CO AS A
FUNCTION OF LOAD FOR GAS TURBINE-POWERED
GENERA TORS, COMPOSITE OF SEVERAL MAKES AND MODELS
7
-------
20
18
16
...0 14
~
~
-
S 12
..c
...-I
~
en
c: 10
o
oro!
en
en
oro!
S 8
~
u
:r: 6
4
2
o
o
25
50 75
o/c Rated Load
100
1 5
FIGURE 4. SPECIFIC EMISSIONS OF HYDROCARBONS
AS A FUNCTION OF LOAD FOR GAS TURBINE-POWERED
GENERA TORS, COMPOSITE OF SEVERAL MAKES AND MODELS
8
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3.0
2. 5
Particulate (oil fuel)
..s:::
~
~
-
s
,.!)
~
2.0
~
tI)
c::
a
....
tI)
tI)
'8
~
X
o
U)
'd
c::
1\1
(1)
4->
1\1
~
;:!
u
....
4->
'"'
1\1
~
1.5
Particulate (gas fuel)
1.0
SOx (oil fuel)
o. 5
SOx (gas fuel)
o
o
50 75
o/c Rated Load
100
125
25
FIGURE 5. SPECIFIC EMISSIONS OF PARTICULATE AND SOx
AS A FUNCTION OF LOAD FOR GAS TURBINE-POWERED
GENERA TORS, COMPOSITE OF SEVERAL MAKES AND MODELS
9
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lbm/hr and HC emissions are 53 Ibm/hr. All these data were obtained
from various outside sources(1-13), and none were confirmed by tests
under the subject contract.
Based on information derived from other references, a cycle of
operation will be postualted for electric utility turbines including various
part- and full-load conditions. This cycle will be presented late r in the
report, and it will be used with emissions values and population/usage
information to estimate national emission factors and impact.
10
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IV.
PREpENTATION OF POPULATION AND USAGE DATA
Data available on the population and usage of gas turbine electric
utility powerplants are fairly extensive(14-20), and information from the
various sources appears to be in substantial agreement. The best infor-
mation source at this point is the Federal Power Commission, and data
referenced by the Sawyer-Farmer article in Gas Turbine International(14)
were obtained on F. P. C. Form No.1 for 1971. This form must be filled
out each year by major utilities and consists of operating and financial
data. The statistics developed from the above-mentioned article are not
quite all-inclusive, even for 1971, because utility companies having electric
, revenues of $1,000,000 or less are exempt from filling out the F. P. C.
form. Moreover, the article(l4) covers only publicly-owned utilities not
privately- or investor-owned ones. Despite these small shortcomings, the
available statistics appear to include about 87 percent of the gas turbine
power used for electric generation in 1971, which is a very good repre-
sentation.
Some of the data on total power output capability of turbines in
electric generation service are summarized in Table 2, indi~ating gen-
erally good agreement. For the purposes of this report, the F. P. C.
estimate for 1972 will be assumed as the correct total power capability;
and the makeup of the national population on the basis of manufacturer
and type will be assumed to be the same as given in th~ "industry estimate"
column of Table 2.
TABLE 2. SUMMARY OF POWER OUTPUT CAPABILITY OF GAS
TURBINE ELECTRIC UTILITY POWERPLANTS
Turbine
Category
*GTI Article,
1971(14)
Total Power Output Capability in Megawatts
FPC Estimates, Units in Service
All Utilities(21) Industry Plus Orders as
.1971 1972 Est., 1972(14) of 12/71(14)
All
18,977 21,774 27,918 28, 326 26,446
7,759 ------ ------ 11, 600 11, 366
4,423 ------ ------ J 11,523 6,060
3,502 ------ ------ 4,251
2,980 ------ ------ 4,846 4,456
313 ------ ------ 357 313
G. E.
TP&M
Turbodyne
Westinghouse
Others
*Includes only those utilities submitting F. P. C. form No.1 for 1971
11
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Of the 253 generating stations listed in Reference 14,. 137 have
more than one turbine-generator unit. Consequently, it is not possible
to know how many hours each turbine was operated during 1971 for these
multiple-turbine plants. The remaining 116 (single-turbine) units, how-
ever, were operated an average of 1196 hours during 1971 (or 13. 7
percent of the time); and their average load factor (percent of rated load)
during operation was 86. 8 percent. This information alone is not adequate
for determining a representative operating pattern for electric utility tur-
bines, but it should help prevent serious errors.
The desired end product of this report includes emission factors
for commonly-used turbines as well as estimates of emis'sions from
electric utility turbines on both a national and a regional basis. Up to
this point sufficient information has been developed to achieve the end
goals, with the exception of an ope rating cycle for the engines. The need
for a cycle shows up in attempting to determine just where on the specific
emission curves (given as Figures 1 through 5) one should choose operating
points and how much impot"tance should be given to each point. Assuming
that the 86.8 percent load factor applies to alt turbines being considered,
this factor becomes the primary criterion in the cycle. Other helpful
information is that turbines in peaking service normally undergo about
250 starts per year(l9), and that each day of operation probably includes
one hour or less under no-load conditions(9).
Using 1196 hours' operation per year and250 starts per year as
normal, the resulting average operating day is about 4.8 hours long. One
hour no-load time per day would be about 21 percent of operating time,
which is considered somewhat excessive. For economy considerations,
turbines are not run at off-design conditions any more than necessary, so
time spent at intermediate power points is probably minimal. The bulk
of turbine operation must be at base or peak load to achieve the high load
factor already mentioned.
If it is assumed that time spent at off-design conditions include's
15 percent at zero load and 2 percent each at 25 percent, 50 percent, and
75 percent load, then the percentages of operating time at rated load (100
percent) and peak load (as sumed to be 125 percent of rated) can be cal-
culated to produce an 86.8 percent load factor. These percentages turn
out to be 19 percent at peak and 60 percent at rated load, and the postulated
cycle based on this line of reasoning is summarized in Table 3.
It is obvious that different values for time at base and peak loads
could be obtained by changing the' total time at lower loads (0 through 75
percent) or by changing the distribution of time spent at lower loads. The
cycle given in Table 3 seems reasonable, however, considering the fixed
load factor and the economies of turbine operation. Note that the cycle
determines only the importance of each load condition in computing com-
posite emission factors for each type of turbine, not overall operating hours.
12
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TABLE 3. POSTULATED OPERATING CYCLE FOR ELECTRIC
UTILITY TURBINES
o/c of Rated
Power
o
25
50
75
100 (base)
125 (peak)
o/c Operating
Time Spent
at Condition
Time at Condition
Based on 4.8 hr Day
in Hours in Minutes
Contribution to Load
Factor at Condition
0.00 x 0.15 = 0.0
0.25 x 0.02 = 0.005
0.50 x 0.02 = 0.010
0.75 x 0.02 = 0.015
1.0 xO.60=0.60
1. 25 x O. 19 = 0.238
L =Load.Factor = 0.868
For the purposes of this report, the operating cycle in Table 3 will be used
to compute emission factors, recognizing that it is only an estimate of
actual operating patterns.
15
2
2
2
60
19
0.72
O. 10
O. 10
O. 10
2.88
0.91
4.81
43
6
6
6
173
55
289
13
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V.
DEVELOPMENT OF EMISSION FACTORS
The factors which are the required end product of this report
section should be in such a form as to yield mass emissions in Ibm/hr
for specific turbine plants when multiplied by the ratings of those plants
in megawatts. In other words, the factors should be composites and
expressed in lbm/ megawatt hour. For the purposes of this report, NOx
emission factors will be determined for seven combinations of fuel type,
gas generators, and turbines. These combinations follow those described
in Figures 1 and 2 except that an average value will be chosen to represent
the G. E. model 5000 units, since population statistics do not include the
"- LA" and "-N" type designations. The turbine units which do not fall
into one of the major classifications shown in Figures I and 2 will be
grouped with the classifications to which they are most closely related.
The emission factors for other pollutants (HC, CO, particulate, and SOx)
will be assumed to be uniform for all the types of turbines, since insuf-
ficient information is available on which to base any other conclusion.
Factors for NOx emissions by operating condition can be found
in Table 4, in terms of (lbm/hr}/rated load for the upper par.t of the
table, and in terms of time-weighted (lbm/hr)/ rated load for the lower
part of the table. The summations of weighted mass rates at the bottom
of the table are actually composite emission factors, and it should be noted
that they bear a strong resemblance to the unweighted factors for 100 per-
cent of rated power in the upper portion of the table, although the composites
are all slightly lower.
Factors for emissions of HC, CO, particulate, and SOx are found
in Table 5, and are quite low compared with NOx factors (Table 4), with
the exception of CO. Since the factors in Table 5 are based on relatively
few data points, they should be considered somewhat less accu~ate than
the NOx factors. The SOx emis sion factor for oil fuel is based on a fuel
sulfur content of approximately 0.05 percent by weight, while that for gas
fuel is based on experimental data rather than an assumed sulfur content.
The data noted as estimates (with asterisks) were based on' extrapolation
of concentration data to zero load, not on actual data taken at that condition.
Subject to the qualifications and assumptions already expressed, then, the
composite emission factors from Table 4 and 5 will be used with population
and usage data already discussed to compute national impact estimates.
The final reports on other categories of engines have included data on al-
dehyde and light hydrocarbon concentrations (and mass emissions of alde-
hydes, in some cases), but no such data could be located for electric utility
turbines.
If it is desired to make impact calculations on some basis other than
that described above, data presented in Table 6 will be helpful. The top half
14
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TABLE 4. NOx EMISSION FACTORS FOR ELECTRIC UTILITY TURBINES
NOx Emissions in (lbmfhr)/Rated Load for
10 Rated TP&M GG4-FT4, TP&M GG4-FT4, Turbodyne' GG4- Turbodyne GG4- GE GE
Power Gas Fuel Oil Fuel Worth., Gas Fuel Worth., Oil Fuel 5000 7000 Westinghouse
o *1. 0 *1. 0 *1. 0 *1. 0 0.69 0.49 2.30
25 1. 22 2.62 1. 28 3.10 3.45 2.05 4:00
50 2.30 5.15 2.00 4.95 4.70 2.65 5.80
75 3.90 8.25 2.70 6.45 6.45 3.90 8.10
100 6.40 12.2 3.40 7.80 9.80 6.30 11.6
125 9.88 17.4 4.38 9.25 15.0 11.1 16.2
-
\J1
Weighted NOy Emissions in (lhmfhr)/Rated Load for
% Rated Time-Based TP&M GG4-FT4, TP&M GG4-FT4, Turbodyne GG4- Turbodyne GG4- GE GE Westing-
Power Mode Weight Gas Fuel Oil Fuel Worth., Gas Fuel Worth.. Oil Fuel 5000 7000 house
o 0.15 *0.15 *0.15 *0.15 *0.15 0.10 0.07 0.34
25 0.02 0.02 0.05 0.03 0.06 0.07 0.04 0.08
50 0.02 0.05 0.10 0.04 0.10 0.09 0.05 0.12
75 0.02 0.08 0.16 0.05 0.13 0.13 0.08 0.16
100 0.60 3.84 7.32 2;04 4.68 5.88 3.78 6.96
125 0.19 1.88 3.31 0.83 1. 76 2.85 2.11 3.08
L = Composite = 6.02 11.1 3.14 6.88 9.12 6.13 10.7
Emission Factor
* Estimated
-------
TABLE 5. FACTORS FOR EMISSIONS OF HC, CO, PARTICULATE,
AND SOx FROM ELECTRIC UTILITY TURBINES
Emissions in (lbm/hr)/Rated Load for
% Rated ~:~ Particulate SOx
Power HC CO Gas Fuel Oil Fuel Gas Fuel Oil Fuel
o 2.7 8.6 ~:~~:' O. 2 ~:":~ o. 5 ~:":~ o. 0 5 0.17
25 1.1 3.2 0.3 O. 7 0.088 0.24
50 0.8 0.8 0.4 1.0 0.10 0.34
75 0.6 0.9 0.3 1.0 0.10 0.44
100 0.5 1.0 0.3 0.8 0.10 0.54
125 0.2 1.0 0.2 0.5 0.12 0.66
Weighted Emissions in (lbm/hr)/Rated Load for
% Rated Time-Based ~:~ Particulate SOx
Powe r Mode Weight HC CO Gas Fuel Oil Fuel Gas Fuel Oil Fuel
o 0.15 0.40 1. 29 ~~~:~O. 03 ):~*O. 08 ~:o~O. 008 0.026
25 0.02 0.02 0.06 0.006 0.01 0.002 0.005
50 0.02 0.02 0.02 0.008 0.02 0.002 0.007
75 0.02 0.01 0.02 0.006 0.02 0.002 0.009
100 0.60 0.30 0.60 0.18 0.48 0.060 0.324
125 0.19 0.04 0.19 0.04 0.10 0.024 0.125
L - Composite = 0.79 2.18 0.27 0.71 0.098 0.50
- Emission Factor
):~ Based on wet collection method such as Los Angeles Air Pollution Control District
technique
** Estimated
16
-------
TABLE 6. COMPOSITE EMISSION FACTORS FOR THE
1971 POPULATION OF ELECTRIC UTILITY TURBINE:>
Pollutant
Emission Factors, (lbm/hr) / Rated Load
Entire Population Gas-Fired Only Oil-Fired Only
NOx
HC
CO
Particulate
. SO
x
8.84
0.79
2. 18
0.52
0.33
7.81
0.79
2. 18
0.27
0.098
9.60
0.79
2. 18
0.71
0.50
Pollutant
Composite Factor~ Fuel Basis
(lbm/106 ft3 gas) ':' ( bm/103 gal oil) ':";,
NOx
HC
CO
Particulate
SOx
413.
42.
115.
14.
5.2
67.8
5.57
15.4
5.0
3. 5
':' Computed for emissions during gas firing only
':<*Computed for emissions during oil firing only
of Table 6 gives separate factors for units gas -fired and oil-fired, and
the bottom half gives fuel- based factors which could be used to estimate
emission rates when overall fuel comsumption data are available. It
would also be desirable to have fuel-based emission factors on a mode
basis, but fuel consumption data available are not adequate for this
purpose.
17
-------
VI.
ESTIMATION OF NATIONAL EMISSIONS IMPACT
Use of the emission factors developed in Section V for the esti-
mation of national impact requires the rated power output of the stations
(in megawatts) and the number of hours each turbo-generator unit was
used. While the usage figures for single-turbine units in the statistics(14)
are explicit, those for multiple-turbine units are not. It appears that the
usage figures for multiple-turbine units include all hours during which any
of a station's turbines were operating, not just the hours when they were
all operating or an average number of hours for each turbine. As mentioned
previously, the load factor during operation of single-turbine units averaged
86.8 percent; so it will be assumed that this factor applies to multiple-
turbine units also. This assumption indicates that a correction can be
made to the usage (in hours) of multiple-turbine units in the form:
calculated load factor
hours usage at 86.8% load factor = 86.8% x hours usage given
while still retaining the overall net generation value intact. This correction
prevents overstating emis sions from stations which ran at least part of the
time with one or more turbo- generator units inoperative.
Computation of emis sions impact on a national basis is quite straight-
forward for the available 1971 data, as shown in Table 7. Units listed in
the statistics(l4) with gas as the primary fuel were assumed to operate on
gas 75 percent of the time, and those listed with oil as primary were assumed
to operate on oil 75 percent of the time. Updating the results to reflect
the assumed 1972 population will be done by simply increasing the contri-
bution of electric utility turbines in proportion to their assumed increase
in available power output. The result of this step is shown in Table 8,
noting that the brand name and model composition of the 1972 population
is very similar to that of the 1971 population. These estimates assume
uncontrolled engines even in areas where controls are now in force, but
this factor should cause only very small errors. To place these impact
estimates in perspective, they are compared with revised 1970 EPA Inventory
Data(22) in Table 9. It appears that NOx and particulate emis sions from
electric utility turbines are considerably more significant than the other
contaminants but are still only around 1 percent of national totals.
No data are presently available on the seasonal aspects of emis-
sions from electric utility turbines, but it would be expected that their
usage (and consequently their emissions) would o:::cur primarily in the
summer months when overall electric power demand is at its peak. This
expectation is based on the idea that gas turbines will be operated only
when absolutely necessary, since their specific operating costs are
higher than the larger steam plants. Emissions can be broken down
18
-------
TABLE7. COMPUTATIONS LEADING TO 1971 NATIONAL IMPACT
ESTIMATES FOR ELECTRIC UTILITY GAS TURBINES
Turbine Rated Load x Hours, Tons Emitted During 1971
Category Fuel Mwh x 10-6 NOx HC CO ~:'Part. ~
--
TP&M gas 1.462 4,400 ----- ------ 195 70
oil 4.348 24,200 ----- ------ 1550 1100
all 5.810 28,600 2,300 6,350 1740 1170
Tur bodyne gas 1. 910 3,000 ------ 260 95
oil 1.652 5, 700 ------ 600 415
all 3.562 8, 700 1, 400 3,880 860 510
GE 5000 gas 4.162 ------ ----- ------ 550 205
oil 5.195 ------ ----- ------ 1850 1300
all 9.357 42,600 3, 700 10,200 2400 1500
GE 7000 oil 0.227 695 90 248 80 55
Westing- gas 2.095 ------ ----- ------ 285 105
house oil 1. 290 ------ ----- ------ 460 325
all 3.385 18,100 1,350 3,690 745 430
Others gas 0.022 ------ ----- ------ 3 1
oil 0.168 ------ ----- ------ 60 42
all 0.190 845 75 208 63 43
~:' Wet collection method such as LA APCD technique
TABLE 8. ANNUAL EMISSION RATES FROM ELECTRIC UTILITY
TURBINES BASED ON NATIONAL POPULATION AS OF 12/31/72
Emission Rates in tons/year Based on 1972 Population
NOx HC CO Particulate
SOx
146,000
13,100
36,100
8640
5400
19
-------
TABLE 9. COMPARISON OF ELECTRIC UTILITY TURBINE
NATIONAL IMPACT ESTIMATES WITH EPA NATIONWIDE AIR
POLLUTANT INVENTORY DATA
Contaminant
1970 EPA Inventory Data,
106 tons/ye~r(22) (Revised)
All Sources Mobile Sources
Electric Utility Turbine
Estimates as Percent of
All Sources Mobile Sources
NOx
HC
CO
Particulate
SOx
22.1
27.3
100.7
25.5
33.4
11.0
15.2
78.1
0.9
1.0
0.661
0.0480
0.0358
>:~O. 0339
0.0162
1. 33
o. 0862
O. 0462
>:~O. 960
0.545
;'( Data based on wet collection methods
regionally in almost any way desired, since records are kept on individual
units. For the purposes of this report, seven geographic .areas will be
used to outline the national distribution of emissions from electric utility
turbines, as described by Table 10. The emi'ssions released into each of
these areas are listed in Table 11, and it can be noted that these emissions
tend to occur in areas where urban and suburban populations are substantial
rather than in more rural areas.
TABLE 10. DEFINITION OF AREAS USED TO OUTLINE
DISTRIBUTION OF EMISSIONS FROM GAS TURBINE
ELECTRIC UTILITY POWER PLANTS
States in Area
1 2 3 4 5 6 7
Maine Penn. Ohio Tenn. Texas Calif. Other
Vermont New Jersey Indiana North Car. Louis. States
New Hamp. Delaware Illinois South Car. Ark.
Conn. Dist. of Col. Ken. Georgia Ok.
Rhode Is. Maryland Mich. Ala bama
Mas s. West Va. Wis. Miss.
New York Virginia Fla.
20
-------
TABLE 11. BREAKDOWN OF EMISSIONS FROM ELECTRIC UTILITY
TURBINES BY GEOGRAPHIC AREA
Emis sions by Area in tons/ year Based on 1972, Population
Contaminant 1 2 3 4 5 6 7
--
NOx 39,500 39,000 34,400 18,600 6,610 >:<3, 020 5,170
HC 3,410 3,430 3,140 1,880 518 260 449
CO 9,410 9,470 8,660 5,190 1,430 , ,719 1,240
>:<>',< Particulate 2, 790 2,410 1,890 986 188 140 231
SOx 1, 910 1, 560 1, 100 547 75 78 127
, '
>:< Based on uncontrolled engines - value for controlled engines ,'VIi'ould be some-
what lower(23, 24)
>:<>:< Wet collection method
21
-------
VII.
SUMMARY
This report is the end product of a study on emissions from gas
turbine electric utility engines, and it is Part 6 of a planned seven-
part final report on "Exhaust Emissions From Uncontrolled Vehicles
and Related Equipment U sing Internal Combustion Engines, " Contract
EHS 70-108. It includes summaries of test data and discussion on
emissions from a number of engine types, as well as estimated emis-
sion factors and national emissions impact. Unlike the other six reports
in the characterization series, this report does not contain any data
developed under the subject contratt but is rather based on work per-
formed by other agencies and groups. As a part of the final report on
the characterization phase of EHS 70-108, this report does not include
information on aircraft turbine emissions, outboard motor crankcase
drainage, or locomotive emissions control technology. These three
latter areas have been or will be reported on separately.
Measurements used in compiling this report were acquired by
a variety of techniques and included hydrocarbons, CO, NOx' and some-
times particulate and/ or SOx. The NOx data are considered. most reliable,
and both HC and particulate data are considered least reliable with CO
and SOx reliability s~mewhere in between.
Expres sing emissions from electric utility turbines as percentages
of 1970 national totals from all sources, they appear to account for ap-
proximately 0.6 percent of NOx' 0.05 percent of hydrocarbons, 0.04 per-
cent of CO, 0.03 percent of particulate, and 0.02 percent of SOx. As
percentages of 1970 mobile source totals, these turbines are estimated
to a.ccount for about 1.3 percent of NOx' 0.09 percent of HC, 0.05 per-
cent of CO, 1.0 percent of particulate, and 0.5 percent of SOx. This
latter comparison has little logical basis, since the engines in question
are essentially stationary; but it is drawn to keep continuity in form with
the other engine classes investigated under the subject contract.
Although overall emissions from electric utility turbines are
not a large percentage of total emissions, it should be noted that they
do occur in urban/ suburban areas where they have a good potential to
affect people. It should also be noted that these emissions probably
occur during afternoon pollution peak hours and during summer when
other air pollution problems may be severe. The potential growth of
turbine usage for power generation is quite substantial, although the Fed-
eral Power Commis sion has estimated that the fraction of total electric
power generated by turbines will probably not increase substantially in
the near term.
22
-------
LIST OF REFERENCES
1.
Robert H. Johnson and Milton B. Hilt, "Gas Turbine Environmental
Factors - 1971", General Electric Company.
2.
Robert H. Johnson, et aI, "Gas Turbine Environmental Factors -
1972", General Electric Company.
3.
Report on emissions from a gas turbine installation in the City of
Burbank (California) Power Plant, submitted to EPA by TP&M,
sampling and analysis by Truesdail Laboratories, August l7, 1970.
4.
Report on emissions from a gas turbine installation at the Dow
Chemical Plant in Pitts burg, California, submitted to EPA by TP&M
sampling and analysis by Truesdail Laboratories, August 17, 1970.
5.
Report on emissions from a gas turbine installation. in the Huntington
Beach Power Station of Southern California Edison Company, submitted
to EPA by TP&M, sampling and analysis by Truesdail Laboratories,
August 17, 1970.
6.
"Tabulation of Emissions - Turbines & Combined Cycle Units", sub-
mitted to SwRI by David S. Kircher of EPA, January 1973.
7.
"Turbo Power Tech Talk, 4 - Emission Control, " Turbo Power and
Marine Systems, January 1973. (Also data on FT4 engine history
and graphical emissions data. )
8.
Data on emissions from and performance of General Electric gas
turbines submitted to David S. Kircher of EPA by Robert H. Johnson
of General Electric.
9.
Letter to William D. Ruckelshaus, (then) Administrator of EPA,
from Norman R. Dibelius of ASME, containing comments and data
on gas turbines by the Combustion and Fuels Committee of the Gas
Turbine Division, ASME. Ft;bruary 8, 1973.
10.
M. J. Ambrose and E. S. Obidinski, "Recent Field Tests for Control
of Exhaust Emissions from a 33 Mw Gas Turbine, " engineering report
E-1486, W estinghous e Eleuric Corporation, June 20, 1972.
11.
Reports on emissions from gas turbine installations of the Southern
California Edison Company (Mandalay, Garden State, Los Alamitos,
Huntington Beach, and Etiwanda stations), submitted to EPA by
Southern California Edison, sampling and analysis by Truesdail
Laboratories, 1969 and 1970.
23
-------
22.
23.
24.
LIST OF REFERENCES (Cont'd)
12.
EPA test number 73-TRB-2 on the Kearny Mesa Turbines,
Diego Gas & Electric Company, Contract No. 68-02-0225,
14, submitted by Engineering-Science, Inc., March 1973.
San
Task
13.
EPA test number 73-TRB-1 on the South Bay Gas Turbine,
Diego Gas & Electric Company, Contract ~o. 68-02-0225,
14, submitted by Engineering-Science, Inc., March 1973.
San
Task
14.
J. W. Sawyer and R. C. Farmer, "Gas Turbines in U. S. Electric
Utilities, " Gas Turbine International, issues of January-February
and March-April, 1973, data acquired from FPC Form No.1 for
1971.
15.
IIHeavy-Duty Gas Turbine Installations" (February 28, 1972), Gen-
eral Electric Company, Gas Turbine Products Division, Schenectady,
New York 12345.
16.
I'Gas Turbine Product Sales Summaryll (December 31, 1972), Westing-
house Electdc Corporation.
17.
"Installations of Turbo Power & Marine Systems, Inc. Gas Generators
and Gas Turbine Engines", December 15, 1972.
18.
Listing of gas turbine installations by Turbodyne (Worthington).
19.
"Gas Turbines in Utility Power Generation", Sawyer's Gas Turbine
Catalog, 1971 Edition.
20.
"Gas Turbines - An Industry with Worldwide Impact", Mechanical
Engineering, March ~ 973.
21.
Correspondence from Robert B. Boyd, Acting Chief, Bureau of
Power, Federal Power Commission to John J. Martin of Colt In-
dustries, dated May 4, 1973. Submitted to Karl J. Springer of SwRI
by Mr. Martin (with "additional note s).
1970 EPA Air Pollutant Inventory Estimates (Revised), 1973
Report of the Council on Environmental Quality.
Annual
County of Los Angeles (California), Air Pollution Control District,
Rules and Regulations, Rules 67 and 68.
County of San Diego (California), Department of Public Health,
Rule 68.
24
-------
APPENDIX
EMISSION CONCENTRATION AND RATE DATA
A-I
-------
Engine
Model
GG4A-8
GG4A-8
TP4-Z
P &. W,
Type N. A.
>
I
N
FT 45C
TP4-Z
FT4A-9DF
Location
So. Cal. Ed.,
Huntington Beach
So. Cal. Ed..
Etiwanda
Not Given
Not Given
Not Given
Not Given
Burbank Public
Service Co.
(I) plus 50 ppm "catalyst"
(Z) plus 100 ppm "catalyst"
(3) plus 150 ppm "catalyst"
TABLE A-l. CONCENTRATION AND RATE DATA AS OBTAll'IED FROM REFERENCES
Gas
Oil
Oil
Oil
Oil
Oil
Oil
Ga.
Ga.
Ga.
Gas
Ga.
Ga.
Ga.
~
% Peak
Load
Ga.
Oil
Oil(l )
Oil(Z)
100
Oil(Z)
100
Ga.
Oil(3)
100
Oil
84
Oil
100
Ga.
100
Oil(4)
91
Oil
100
100
Low Idle
5ynch.
Idle
80.5
100
80
100
100
36
Z3
55
64
73
81
(4) plus steam
(5)atIZ"'>COl
NO"
n
n
65 ppm
93 ppm
84
73 ppm
92 ppm
99 ppm
84
5Z ppm
100 ppm
73 ppm
165 ppmlO' 89 Ibm)
lOb BTU
115 ppml0.6Z Ibm)
106 BTU
lO.8 ppmlO' II Z Ibm)
lOb BTU
(53 Ibm/hr)
189 ppm!~J
10 BTU
138 ppmfO.66 Ibm)
lOb BTU
------------------
------------------
------------------
------------------
0.84 Ibm NO"
lOb BTU
0.96 Ibm NO"
lOb BTU
0.70 Ibm NO"
lOb BTU
65 ppm
ZI Ibm NOz/hr
79 Ibm NOz/hr
84 Ibm NOz/hr
85 Ibm NOz/hr
89 Ibm NOZ/hr
HC
-----..-............
--......-------
o ppm C6
o ppm C6
--...--------
o ppm C6
o ppm C6
7 ppm C6
(16 Ibm/hr)
------........--
-------......--
-----------
-----------
---..------..
18.6 Ibm
103 Ibm fuel
15.4 Ibm
loj Ibm fuel
0.8 Ibm
loj Ibm fuel
0.05 Ibm
loj Ibm fuel
-------..---
------......---
-----------
...----------
under 10
ppmC
-----------
under 10
ppm C
-----------
10 ppm C
CO
---...-------
---...--.....--..
o
o
-----------
1017. ~;bm)
o
o
-----------
-----------
--------..--
------..---...
-----------
54. Z Ibm
103 Ibm fuel
41. 3 Ibm
10j Ibm fuel
1.1 Ibm
10j Ibm fuel
0.75 Ibm
loj Ibm fuel
-----------
-----------
--------...--
---...-------
Z5 ppm
---...-------
17 ppm
---------.....
Z5 ppm
Part.
--------
0.0071 IIr
SCF
0.015 r
SCF(5
O.OZO r
SCFI'
0.016 ,r
SCFP
0.009 r
SCFI'
0.016 r
SCFI~
O.OZZ r
SCF{'
--------
--------
0.00Z6 IIr
SCF
--------
0.0018 IIr
SCF
0.001911r
SCF
SOy
-----..------
------------
------------
-----....----...
-----...------
........---------
------------
......----...-----
-----......---.....
------......---..
--......--------
------------
------------
--...---------
-----------..
-------~ ---
-----....-----
....--.....--...---
-----...--..---
.----------...
--------...---
I. 0 ppm 50Z
-----...---...--
Z.6 ppm SOz
------------
3.0 ppm 50Z
Othe r s
COZ-l.8, OZ-17.6
COZ-Z.5, OZ-17. 5
COZ-l.8, OZ-18.4
COZ- Z. 0, 0Z-18. Z
OZ-18. Z
COZ-l.Z,OZ-18.0
COZ-Z.7, OZ-16.8
COZ-Z.5, OZ-17. 4
----------------
----------------
----------------
----------------
----------------
----------------
----------------
--- ------------
---------------..
----------------
----------------
----------------
----------------
COZ-0.6, 0Z-ZO.O
----------------
COZ-I.9,OZ-17.6
----------------
COZ-3.Z,OZ-15.4
-------
TABLE A-I (Cont'd). CONCENTRATION AND RATE DATA AS OBTAINED FROM REFERENCES
Engine % Peak
Model Location Fuel Load NOy HC CO Part. SO- Others
FT4A-9DF Burbank Public Oil Z3 5Z Ibm NOzl hr under 10 Z3 ppm 0.0058 IIr I . Z ppm SO Z COZ-0.9, 0Z,ZO.O
Service Co. ppm C SCF
Oil 55 15Z Ibm NOz/hr -----......---- -........-----..- ------------ ----------------
Oil 64 164 Ibm NOZ/hr under 10 under 10 0.0043 IIr Z.O ppm SOz COZ-Z. I, OZ-17.7
ppm C ppm SCF
Oil 73 Zu Ibm NOz/hr ----"'----...- ----------- .....---------- ----------------
Oil 81 Z45 Ibm NOZ/hr under 10 under 10 0.0057 IIr I. 8 ppm SOz COZ-Z.5, OZ-17.4
ppm C ppm SCF
FT4A Dow Plant, Gas Z8 Z9 Ibm NOz/hr none 17 ppm O. 03~~r 0.33 ppm SOz COZ-1.5, OZ-18.0
Pitts burg, Cal. detected SCF
Gas 54 60 Ibm NOz/hr under 10 I 7 ppm 0.OZ9 ,r 0.6Z ppm SOz COZ-Z.O, Ozol 7. 6
ppm C SCFlj
Gas 70 10Z Ibm NOz/hr under 10 Z5 ppm 0.OZ6 ,r O. Z9 ppm SOz COZ-Z.Z, OZ-17.3
ppm C SCFlj
Gas 88 163 Ibm NOZ/hr under 10 under 10 O. OI~Sr 0.7Z ppm SOz COZ-Z.3, OZ-I 7, 0
ppm C ppm SCF
Gas 98 Z07 Ibm NOZ/hr under 10 under 10 O. ozz r I. 47 ppm SOz COZ-Z.5, OZ-16.5
ppm C ppm SCFlj
GG4Ax8 So. Cal. Edison Oil 100 70 ppm ----------- under 10 0.007 gr "..-----........-- COZ-Z.6, 0Z-17.4
ppm SCF
Gas 100 35 ppm ----------- ----------- ---...-------- COZ-I. 9, OZ-17.6
GG4Ax8 So. Cal. Edison Oil Z5 5Z Ibm NOz/hr under 10 under 10 ~ 3.5 ppm SOz COZ-I. 8, OZ-18.1
ppm C ppm SCF
Oil 60 93 Ibm NOZ/hr ---..-...----.. -------..--- ----.....----..- COZ-Z.5, OZ-17.6
Oil 74 I ZO Ibm NOZ/hr under 10 under 10 0.075 r 4. Z ppm SOz COZ-Z.3, OZ-17.8
ppm C ppm SCFlj
:x> Oil 81 135 Ibm NOz/hr ----------- ----------- ---"---"00__- COZ-Z.8, 0Z-17.Z
I Oil 92 154 Ibm NOz/hr under 10 under 10 0.041 IIr 3.8 ppm SOZ COZ-Z.7, 0Z-17.Z
W ppm C ppm SCF(5)
Gas Z8 ZO Ibm NOz/hr under 10 under 10 ~ 1.5 ppm SOZ COZ-I. 4, 0Z'18.4
ppm C ppm SCF
Gas 66 37 Ibm NOZ/hr --....------- --------..-- ..----------- COZ-Z.O, OZ-17.7
Gas 77 44 Ibm NOZ/hr under 10 under 10 ~ 5.0 ppm SOz COZ-I. 9. OZ-17.8
ppm C ppm SCF
Gas 88 6Z Ibm NOZ/hr ----------... ----------- ------------ COZ-Z. I, OZ-17.3
Gas 99 66 Ibm NOz/hr under 10 under 10 O. Oil r Z. Z ppm SOz COZ-Z. Z, OZ-17.Z
ppm C ppm SCFlj
MS5001-LA Not Given Oil 9Z 150 ppm (dry) -..--------- 0 "'--"''''-''.--'-- OZ-15. 5
Gas 9Z 85 ppm (dry) ----------- 500 ppm ------------ OZ-15. 5
(dry)
Oil 95 J 10 ppm (dry) ----------- under 10 ...----------- COZ-3.5, OZ-15. I
ppm (dry)
Gas 100 88 ppm (dry) ----------- under 10 ...----------- COZ-Z.8, OZ-I 5.3
ppm (dry)
MS5001 -N Not Given N.A. 0 ------------------ 13 Ibm 50 Ibm ------------ .---------------
10~ Ibm fuel 103 Ibm fuel
N.A. 7(Synch. ------------------ 7.0 Ibm 34 Ibm -..---------- -----..----------
Idle) 10~ Ibm fuel I O~ Ibm fuel
N.A. 90 ------------------ LO.06 Ib~ I. 0 Ibm ....----------- -----------....---....
1 O~ Ibm fuel I O~ Ibm fuel
N.A. 100 ------------------ LO.Ob Ibm 0.7 Ibm ------------ ----------------
10> Ibm fuel 10> Ibm fuel
-------
Engine
Model
MS5001-SC
MS7001-SC
MS5001-LA
MS5001-N
MS7001-A
>
I
H>-
WZ51-SC
W501-SC
WZ51-AA
WZ51
Locatjon
Not Given
Not Given
Mfr. Data
Mfr. Data
Mir. Data
Not Given
Not Given
Not Given
Mir. Data
TABLE A-I (Cont'd). CONCFNTRATION AND RATE DATA AS OBTAINED FROM REFERENCES
'1. Peak
~ ~ --~- _-.!:!f_-- CO
Oil 81> 0.70 Ibm/lOb BTU ----------- ---...-------
Oil 100 0.78 Ibm/lOb BTU ----------... --------.--
Oil(l» 86 0.50 Ibn,!1 01> BTU ----------- -----------
Oil(6) 100 0.55 Ibm/l01> BTU ----------- ...------- ---
Oil(7) 81> 0.30 Ibm/I 06 BTU ----------- ---..-------
Oil (7) 100 0.28 Ibm/I 06 BTU ----------- -----------
Gas 81> 0.55 Ibm/IOI> BTU -------...--- -----------
Gao(l» 81> 0.35 Ibm/IOI> BTU ----------- -----------
Oil 91 0.9Z Ibm/I g6 BTU ----------- -----------
Oil 100 1.llbm/IO BTU ----------- -----------
Oil <; 17 ppn'l ----------- - - - - - - -. - --
Oil 12 34 ppm ----------- - - - -- - - . . --
Oil Z5 48 ppm ----------- - - - - - -- - - --
Oil 50 1>8 ppm ----...------ -----------
Oil 75 108 ppm -------...--- -----------
Oil 100 188 ppm --....-------- -- - - - - - - - --
Oil 4 17 ppm ----"',------ -----------
Oil 10 30 ppm ----------- -----------
Oil ZO 40 ppm ----------- ----....-....----
Oil 40 55 ppm ..-----..---- ------..----
Oil 1>0 78 ppm ---..------- --------....--
Oil 80 IZO ppm ----------- -...---------
Oil 100 180 ppm ----------- --------..--
Oil 8 Z8 ppm ----.....---...- -----------
Oil 17 3Z ppm ----------- -----------
Oil Z5 38 ppm ----------- -- ---------
Oil 33 40 ppm ----------.... -----------
Oil 4Z 45 ppm -----...----- -----------
Oil 58 1>3 ppm --..--..----- --------...--
Oil 75 90 ppm ----------- -----------
Oil 92 143 ppm ------...---.. --------...--
Oil 100 2Z0 ppm -...--------- -----------
Oil(8) 100 57 ppm ----------- -----------
Oil 100 ZZO ppm ----------- -----------
Oil 99 Z02 ppm (dry) ----------- 40 ppm
Oil(9) (dry)
100 1>0 ppm (dry) --..-------- 10 ppm
(dry)
Oil 0 40 ppm ----------- -----------
Oil ZO 5Z ppm ----------- -----------
Oil Z3 --------------..--- ------...---- 30 ppm
Oil Z8 1>0 ppm -...--------- -----------
Oil 3Z ------------------ ----------- Z3 ppm
Oil 44 80 ppm -"--------.. -----------
Oil 48 ------------------ ----------- II> ppm
Oil 57 100 ppm ----------- -----------
Oil 65 ------------------ ---------..- 15 ppm
Oil 68 IZO ppm ----------- -----------
Oil 75 140 ppm ----------- -..-------......
Oil 81 ------------------ ----------- 18 ppm
Oil 84 160 ppm -- - -- - -. - - - -----------
Oil 90 180 ppm -...--------- -----------
Oil 97 ------------------ ----------- Z9 ppm
Oil 100 212 ppm ----------- -----------
(6) modified combustor
(7) plus water injection .it 1. 3~ of air rate
(8) plus water injection
(9) plus water inJcction at b5r~ of~ate
Part.
SOy
------------
-..----...-...--..
------------
-...----------
-------.....---
--...-----..-...-
--...-----...---
...-----------
------------
----...-----...-
--..---------
------------
-..-----..----
---------..--
-----------...
------------
-----------...
------------
----....--....--......
......-------..--
-------....----
---...--------
----------...-
------------
--------..---
------------
----------...-
------------
------------
------------
-----------....
------------
-------....---...
-----------....
------------
------------
------------
------------
----------...-
------------
------------
------------
------------
------------
------------
--...---------
------------
------------
------------
---...--------
------------
------------
Others
...---------------
----------------
----------------
----------------
----------------
----------------
----------------
--...-------------
---..------------
----------------
..------------...--
--------...-------
----..---------..-
--...-------------
-------...-------..
-------...--------
----------------
----------------
-...--------------
-----...---------..
----------------
----------------
---...------------
----------------
----------------
----.--..--------
----------------
----------------
--..-------------
--------.....------
----------------
-.--------------
----------------
----....----------
OZ-14.0 (dry)
COZ-3.0 (dry)
OZ-13.8 (dry)
------------...---
---..----...---..---
----------------
--..-------------
----------------
----------------
----------------
----...-----------
----------...-----
----------------
----------------
---------...--..---
----------------
----------------
----------------
----------------
-------
TABLE A-I (Cont'd). CONCENTRATION AND RATE DATA AS OBTAINED FROM REFERENCES
Engine .,., Peak
Model Location ~ ~ NOy
W501 Mfr. Data Oil 0 40 ppm
Oil ZO 5Z ppm
Oil Z8 60 ppm
Oil H 80 ppm
Oil 57 100 ppm
Oil 68 lZ0 ppm
Oil 75 140 ppm
Oil 84 160 ppm
Oil 90 180 ppm
Oil 100 ZIZ ppm
~
I
U1
HC
__...__a__.....-
......-...-----.....
-......----........
-.......------..
...----.....----
---------..-
-.....-.....-----
-----------
-------......--
...---..-.......--
CO
-----..----...
--...--------
-...------..-...
----------...
----------...
.........-----....
-------...--..
-...--------..
-----..----...
--..--------
Part.
SOy
------------
-----------..
......... - -- -...............
-----------..
------------
----------.....
-......---------
-----------...
------------
------------
Othe r I
--"'''-------...----
----------------
--..................... --...... -...-
-_... --.................................
-------------.....-
----------------
---------------..
----------------
----------------
----------------
-------
TABLE A-2. RATE DATA USED TO PLOT FIGURES 1-5
(RESTATEMENT OF TABLE A-I DATA AFTER PROCESSING)
Engine o/c Peak Emission Rate in Ibm/Megawatt hour
Model Fuel Load NOx HC CO Particulate SOx
GG4A Gas 72 6. 16
Oil ( 1) 72 8.80 0.85
Oil (2) 84 5. 94 0.22
Oil (3) 100 6.28 0.28
Ga( 100 6.72 0.22
Oil 3) 84 4.21 0.50 0.089
Oil 100 6.83 0.30
Oil 84 5.94 1. 1 0.45
FT4 Oil 100 8.4
Gas 100 . 5.8
Oil (4) 91 1.1
FT 4-SC Oil 80 0.52 0.73 -- --
Oil 100 '0.029 0.45
FT4-SC Oil 80 10.8
Oil 100 11. 4
Gas 100 6.64
Gas 36 9. 1
FT4A-9DF Gas. 23 4.2 3.8 6.6 1.3 0.60
Gas 55 5.7
Gas 64 6.0 0.49 0.81 0.17 0.29
Gas 73 5.3
Gas 81 5.0 0.62 0.79 0.11 0.21
Oil 23 10.4 8.0 2.8 0.66
Oil 55 12.7
Oil 64 11.7 0.57 0.31
Oil 73 13.2
Oil 81 13.8 0.62 0.23
FT4A Gas 28 4.5 1. 9 0.98 0.085
Gas 54 4.9 1.1 0.59 0.090
Ga's 70 6.3 1.4 0.50 0.048
Gas 88 8. 1 0.28 0.080
Gas 98 9.2 " 0.40 0.15
GG4A Oil 100 4.9 0.56
Gas 100 2.4
~Mp1us 50 ppm catalyst
plus 100 ppm catalyst
(3)p1us 150 ppm catalyst
(4)plus steam
A-6
-------
TABLE A-2. (Contld.) RATE DATA USED TO PLOT FIGURES 1-5
(RESTATEMENT OF TABLE A-I DATA AFTER PROCESSING)
Engine % Peak Emission Rate in Ibm/Megawatt hour
Model Fuel Load NOx HC CO Particulate SOx
GG4A Oil 25 11.6 2.7 1.2
Oil 60 8.6
Oil 74 9. 1 1.8 0.63
Oil 81 9.2
Oil 92 9.3 0.96 0.46
Gas 28 4.0 0.46 0.36
Gas 66 3.1
Gas 77 3.2 0.2.7 0.52
Gas 88 3.9
Gas 99 3. 7 O. 15 O. 18
MS5001-LA Oil 92 7.9
Gas 92 4.5 16.
Oil 95 6.3
Gas 100 3.8
MS500 I-N Oil 7 18. 86.
Oil 90 0.67
Oil 100 0.46
MS5001-SC Oil 86 13.3
Oil 100 14.0
Oil ( 5) 86 9.50
Oil (5) 100 9.86
Oil (6 ) 86 5.71
Oil (6) 100 5.04
Gas 75 7.76
Gas(5) 75 4.95
MS7001-SC Oil 91 15.3
Oil 100 17.4
MS500 I-LA Oil 5 25.0
Oil 12 19.6
Oil 25 14.0
Oil . 50 9.80
Oil 75 10.4
Oil 100 13.6
MS500 I-N Oil 4 25.0
Oil 10 17.2 -----
Oil 20 11.8
(5)modified combustor
(6)plus water injection at 1. 3% of air rate
A-7
-------
TABLE A-2. (Contld.) RATE DATA USED TO PLOT FIGURES 1-5
(RESTATEMENT OF TABLE A-I DATA AFTER PROCESSING)
Engine % Peak Emission Rate in Ibm/Megawatt hour
Model Fuel Load NOx HC CO Particulate SOx
Oil 40 8.00
Oil 60 7.53
Oil 80 8.70
Oil 100 10.4
MS700 I-A Oil 8 16.3 -- -- .
Oil 17 9.34
Oil 25 7.40
Oil 33 5.84
Oil 42 5.25
Oil 58 5.25
Oil 75 5.84
Oil 92 7.59
W25l-SC Oil 100 13.8
Oil (7) 100 3.61
W50l-SC Oil 100 12.3
W25l-AA Oil 99 9.47
Oil (8) 100 2.77
W25l Oil 20 16.0
Oil 23 4.91
Oil 28 13. 1
Oil 32 2.72
Oil 44 11. 2
Oil 48 1.28
Oil 57 10.8
Oil 65 0.84
Oil 68 10.9
Oil 75 11. 5
Oil 81 0.84
Oil 84 11. 7
Oil 90 12.3
Oil . 97 1. 13
Oil 100 13.0
W501 Oil 20 15.8
Oil 28 13.0
Oil 44 11. 1
Oil 57 10.7
Oil 68 10.8
Oil 75 11. 4
Oil 84 11. 6
Oil 90 12.2
Oil 100 12.9
(7)plus water injection
(8)plus water injection at 65% of fuel rate
A-8
-------
- TECHNICAL REPORT DATA
(Please read flu/ructions on the revene before completing)
1. REPORT NO. 2. 3. RECIPIENT'S ACCESSION-NO.
APTD-1495
4.TITLEANDSUBTITLE rXrJttlJst; IJII1SS10nS r-rom uncOntrolled 5. REPORT DATE
Vehicles and Related Equipment Using Internal Combustion - lQ7il
Engines 'Part 6: Gas Turbine Electric Utility Power 6. PERFORMING ORGANIZATION CODE
Plants
7. AUTHOR(S) B. PERFORMING ORGANIZATION REPORT NO.
-
Charl es T. Hare and Karl J. Springer AR-940
9. PERFORMING ORG '\NIZATION NAME AND ADDRESS 10. PROGRAM ELEMENT NO.
Southwest Research Institute
Vehicle Emissions Research Laboratory 11. CONTRACT/GRANT NO.
8500 Culebra Road
San Antonio, Texas 78284 EHS 70-108
12. SPONSORING AGENCY NAME AND ADDRESS 13. TYPE OF REPORT AND PERIOD COVERED
Environmental Protection'Agency Final
2565 Plymouth Road 14. SPONSORING AGENCY CODE
Ann Arbor, Michigan 48105
15. SUPPLEMENTARY NOTES
16. ABSTRACT
This report includes summaries of test data and discussion on emissions
from a number of gas turbine electric utility engines. It a 1 so covers the
estimation of emission factors and national air ,quality impact of these engines.
A regional estimate of the distribution of these emissions is also made.
:
The data are based on work performed by other agencies and groups. The
measurements were made by a variety of techniques and included HC, CO, NOx, and
sometimes particulate and SOx.
17. KEY WORDS AND DOCUMENT ANALYSIS
a. DESCRIPTORS b.IDENTIFIERS/OPEN ENDED TERMS c. COSATI Field/Group
.
HI. DlsrRIBUTION STATEMENT 19. SECURITY CLASS (This Report) 21. NO. OF PAGES
Unclassified 35
Un 1 i IT)ited 20. SECURITY CLASS (This page) '22. PRICE
Unclassified
EPA Form 2220.1 (9-73)
A-9
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