United States
Environmental Protection
Agency
Industrial Environmental Research
Laboratory
Research Triangle Park NC 27711
Research and Development
EPA-600/S7-81 -122 July 1982
Project Summary
Combustion Modification
Controls for Stationary
Gas Turbine
R. Larkin, FUS. Merrill, H. I. Lips, K. J. Lim, E. B. Higginbotham, and
L. R.
Rfr "'"'J
The report gives results o'fa
mental assessment of combustion modi-
fication techniques for stationary gas
turbines with respect to nitrogen oxides
(NOX) control effectiveness, operational
impact, thermal efficiency impact, con-
trol costs, and effect on emissions of
pollutants other than NOX. Wet controls,
which inject steam or water directly into
the combustion chamber, are the only
currently available methods sufficiently
developed to reduce NOX emissions
below the recently promulgated New
Source Performance Standard of 75
ppm at 15 percent O2 for clean fuels
(greater than 50 percent reduction).
However, the effectiveness of wet con-
trols decreases significantly as the per-
centage of fuel-bound nitrogen increases.
Emissions of unburned hydrocarbons
(UHC) and carbon monoxide (CO) can in-
crease with wet controls. However, re-
sults from a detailed Level 1 Environ-
mental Assessment test on a 60 MW
utility gas turbine indicate that incre-
mental emissions of pollutants other
than NOX (trace elements, organic com-
pounds, sulfur species, CO, and particu-
late) remain relatively unchanged. Wet
controls increase the cost of electricity
by 2-5 percent, due in large part to the
associated fuel penalty. Dry NOX con-
trols, being developed, involve combus-
tor modifications, but not water or steam
injection. They hold much promise be-
cause of their NOX control effectiveness
for both clean and dirty fuels, and their
expected lower cost and operational
impacts.
This Project Summary was developed
by EPA's Industrial Environmental He-
search Laboratory, Research Triangle
Park, NC, to announce key findings of
the research project that is fuHy docu-
mented in a separate report of the same
title (see Project Report ordering infor-
mation at back).
Introduction
With the increasing extent of NOX con-
trol application in the field, and expanded
NOX control development anticipated for
the future, there is currently a need to:
(1) ensure that current and emerging
control techniques are technically and
environmentally sound and compatible
with efficient and economical operations
of systems to which they are applied,
and (2) ensure that the scope and timing
of new control development programs
are adequate to allow stationary sources
of NOX to comply with potential air quali-
ty standards. With these needs as back-
ground, EPA's Industrial Environmental
Research Laboratory, Research Triangle
Park (IERL-RTP) initiated the Environmen-
tal Assessment of Stationary Source NOX
Combustion Modification Technologies
(NOX EA) Program in 1976. This pro-
gram has two main objectives: (1) to
identify the multimedia environmental
impact of stationary combustion sources
and NOX combustion modification con-
trols applied to these sources, and (2) to
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identify the most cost-effective, envi-
ronmentally sound NOX combustion
modification controls for attaining and
maintaining current and projected N02
air quality standards to the year 2000.
The NOX EA's assessment activities
have placed primary emphasis on: major
stationary fuel combustion NOX sources
(utility and industrial boilers, gas tur-
bines, internal combustion (1C) engines,
and commercial and residential warm air
furnaces); conventional gaseous, liquid,
and solid fuels burned in these sources;
and combustion modification controls
applicable to these sources with poten-
tial for implementation to the year 2000.
This report summarizes the environ-
mental assessment of combustion modi-
fication controls for stationary gas tur-
bines. It outlines the environmental,
economic, and operational impacts of
applying combustion modification con-
trols to this source category. It also sum-
marizes results of a field test program
aimed at providing data to support the
environmental and operational impact
evaluation.
Conclusions
Source Characterization
Gas turbines are rotary 1C engines
commonly, although not universally, fired
with natural gas or "clean" liquid fuels
such as diesel or distillate oils. The basic
gas turbine consists of a compressor,
combustion chamber(s), and a turbine.
Pressurized combustion air, supplied by
the compressor, and fuel are burned in
the combustion chamber(s). The hot
combustion gases are rapidly quenched
in the combustor by secondary dilution
air and then expanded through turbines
which drive the compressor and provide
shaft power to, for example, a generator,
compressor, or pump.
As shown in Figure 1, the gas turbines
represented the fifth largest contributor
of NOX emissions from stationary
sources in the U.S. in 1977—constitut-
ing 2.0 percent. However, a variety of
factors, including fuel availability, elec-
tricity demand, and increasing thermal
efficiencies, may tend to intensify the
NOX problem from stationary gas tur-
bines. Thus, they represent a priority
source category for control evaluation in
the NOX EA.
Three different thermodynamic cycles
are typically used in stationary gas tur-
bine engines—simple, regenerative, and
combined.
Noncombustion 1.9% —i r~Incineration 0.4%
Warm Air Furnaces 2.0%—\ \ I
Gas Turbines 2.0% -\ \ \ I
Others 4.1%
Industrial Process
Heaters 4.1%
Reciprocating
1C Engines
18.9%
Figure 1.
Total: 10.5 Tg/yr (11.6 x 10s tons/yr)
Distribution of stationary anthropogenic /VOX emissions for the y>
1977 (controlled /VO« levels).
The simple cycle is the basic gas tur-
bine engine; the regenerative and com-
bined cycles employ exhaust waste heat
recovery.
Gas turbines range in size from 30 kW
to over 7 5 MW (40 to over 100,000 hp)
power output. For evaluation, though,
the source category can be divided into
three capacity ranges: large capacity, in-
cluding combined cycle—greater than
15 MW (20,000 hp); medium capacity—
4-15 MW (5,000-20,000 hp); and small
capacity less than 4 MW (5,000 hp).
Each of these capacity ranges finds dis-
tinct use applications. Large capacity
turbines are primarily used for base, mid-
range, and peaking utility electricity
generation. Medium capacity turbines
find primary uses in standby electricity
generation, pipeline compression and
pumping, industrial electricity genera-
tion, and various industrial shaft power
applications. Small capacity turbines are
primarily used for gas compression and
standby electricity generation in the oil
and gas industry.
Gas turbines experienced spectacu
sales growth through 1970 due p
marily to their inherent low cost a
operational and maintenance adva
tages over other prime movers and ele
trical generators. A growing econor
combined with delays in nuclear pla
licensing also contributed to their pop
larity. However, with the 1970's car
decreased oil availability along with i
creased cost, and a growing uncertain
among users concerning the reliability
gas turbines. These caused a subseque
steady decline in sales. Thus, forecas
of new generating requirements by tl
National Electrical Manufacturers Ass
elation (NEMA) have shown substant
reductions over previous forecasts
gas turbine equipment. Figure 2 shov
results from the Sixth Biennial Survey
Power Equipment Requirements (SPER]
The gas turbine generating additioi
predicted in 1978 decreased 78 perce
from NEMA's 1973 predictions. Ho\
ever, the survey predicts a relative
level rate of additions in the near futu
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8
<0
.0
,*5
I
f
4w
i
m
to
SPER-71-
•\
SPER—Survey of Power Equipment
Requirements: by National
Electrical Manufacturers
Association biannual projections.
i /
•SPER-73
SPER-69
Year
Figure 2. Projected gas turbine generating additions.'
and manufacturers are optimistic about
an upswing in the market, particularly
for combined cycle plants.
Fuels and Emissions
Natural gas and distillate oils are pre-
ferred for gas turbines because they are
relatively clean burning and serve as the
primary experience base for manufactur-
ers and users. Those oils containing sig-
nificant ash and high levels of sulfur and
certain trace elements (particularly vana-
dium, lead, sodium, potassium, and cal-
cium), such as crude oil, residual oil, and
synthetic fuels, may require some treat-
ment before they can be used. However,
several utilities are currently firing residual
oils in spite of high pretreatment costs.
Some of the most promising new clean
fuels are low- and high-Btu gases and
process gases such as coke oven and
blast furnace gases. Improved thermo-
dynamic cycle efficiencies and low NOX
emissions make these clean fuels attrac-
tive alternatives in broadening basic
energy sources. There are, however, a
number of redesign considerations with
the use of certain low Btu fuels in con-
ventional engines. Modifications to the
combustion and fuel systems are all that
are required with some fuels. But with
others, significant problems arise from a
compressor-turbine mismatch due to
high pressure ratios caused by excessive
turbine mass flow.
Synthetic liquid fuels, such as the mid-
dle and heavy distillates obtained from
coal liquefication products, are also be-
coming potential gas turbine fuels. In-
deed, synthetic fuels may be the future
fuels for gas turbines due to the changing
market for more conventional fuels, Fed-
eral fuel use regulations, and other
considerations.
Air emissions in the form of exhaust
gases are essentially the only effluent
stream from stationary gas turbines.
Stream composition depends on the fuel
burned, combustor geometry, and com-
bustion and operating characteristics.
NOX emissions are highest and CO and
UHC are lowest when the engine oper-
ates at design conditions (i.e., rated
power output). Off-design firing, while
limiting NOX, enhances the production of
unburned species through incomplete
oxidation. Virtually all fuel sulfur is con-
verted to sulfur dioxide (S02) in a turbine
engine. Thus, S02 emissions are a func-
tion solely of fuel sulfur content. Panicu-
late emissions depend on the ash content
of the fuel and the levels of unburned
carbon and condensible hydrocarbons
resulting from incomplete combustion.
The only liquid and solid wastes from
gas turbines are from the water treat-
ment facilities associated with water in-
jection for NOX control. These effluent
streams are relatively small, generally
not hazardous, and easily disposed of in
landfill areas or to rivers or municipal
sewers.
Of the pollutants emitted from gas tur-
bines for which the emission level can be
affected by combustion conditions (i.e.,
not exclusively fuel composition depen-
dent) , NOX is considered the primary pol-
lutant of concern. NOX in gas turbines,
as in all combustion sources, is formed
primarily by two mechanisms—thermal
fixation and fuel NOXformation. Thermal
NOX results from the thermal fixation of
molecular nitrogen and oxygen in the
combustion air, and the rate of forma-
tion increases exponentially with local
flame temperature. Fuel NOX results
from the oxidation of organically bound
nitrogen in such fuels as residual oil, and
primarily depends on the nitrogen con-
tent of the fuel and oxygen availability in
the primary combustion zone. Since gas
turbines generally fire clean fuels, with
correspondingly low nitrogen contents,
thermal NOX predominates. However,
with increasing use of residual oils and
synthetic liquid fuels, both of which con-
tain higher levels of fuel nitrogen, the
contribution of fuel NOX will become
more important.
In general, liquid fuels yield higher NOX
emissions than gaseous fuels. This is
due primarily to higher localized flame
temperatures resulting from droplet
burning and, to some extent, to the
higher fuel nitrogen content of liquid
fuels. Still, for a given fuel, time, temper-
ature, and mixing, as it affects oxygen
availability, will govern the amount of
NOX formed. High temperature, long
residence time at high temperature, and
ready oxygen availability promote high
levels of NOX.
The effect of local flame temperature
on NOX formation is shown in Figure 3,
which shows the exponential increase in
NOX emissions with combustor inlet
temperature.
Figure 4 shows the effect of both
combustor residence time and fuel
equivalence ratio (defined as the rate of
fuel introduced into the combustor di-
vided by the stoichiometric rate of fuel
additives required to just consume all the
oxygen in the air added to the combus-
tor) for a lean primary zone combustor
typical of today's turbines. Figure 4
shows decreased NOX as the mixture is
made more lean, in essence emphasizing
the temperature dependence of NOX for-
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40
35
30
o
I25
I
I
O
20
10
Different symbols denote
different test engines and
different ambient conditions
I
I
400
500 600 700
Combustor Inlet Temperature, K
800
Figure 3. /VOX emissions as a function of combustor inlet temperature.'
mation; leaner mixtures in this range of
equivalence ratios produce lower tem-
perature flames due to the dilution and
cooling effects of the added air. Figure 4
also shows the increase in NOX with in-
creasing residence time. HC and CO
emissions are functions of the combus-
tion efficiency of the unit. Since most
units are designed for high efficiency at
maximum load, reduced load tends to in-
crease CO and HC emissions. CO reacts
slowest of all components formed during
combustion; therefore, it is emitted in
the largest concentrations.
Emissions of CO and HC are also a
function of the method of fuel injection,
including atomization method and pres-
sure, degree of fuel/air mixing, and resi-
dence time at combustion temperature.
Note that improved atomization and
rapid fuel/air mixing can reduce thermal
NOX as CO and CH are reduced. How-
ever, increased residence time and com-
bustion temperature for more complete
§/o
i 5
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I
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I
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cO.5
I
0.2
Equivaleni
Ratio
J_
_L
_L
0.5 1.0 1.5 2.O 2.5 .
Residence Time, msec
Figure 4. Effect of residence tin
on /VOx emissions for
lean primary combust i
Propane fuel inlet mi
ture temperature, 8C
K; inlet pressure, 5
atm; reference velocit
25 and30 m/s.3
combustion may increase NOX, at lea
for the fuel-lean primary zone cor
bustors typical of today's design.
Table 1 summarizes uncontrolle
emission factors (ng/J heat input) fro
stationary gas turbines. For pollutan
which depend on fuel composition,
typical fuel composition was used.
Control Alternatives
Since NOX is the major pollutant <
concern from gas turbines, control tecl
niques discussed here focus on reducir
NOX emissions. NOX controls for gas tu
bines are usually classified either as w<
techniques which inject water or steai
into the combustion zone, or dry tecl
niques which involve some process mod
fication other than adding water. Th
typically takes the form of combustc
redesign.
The formation of thermal NOX is highl
dependent on flame temperature. I
fact, virtually all thermal NOX is forme
in the region of highest flame tempers
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Table 1. Gas Turbine Criteria Pollutant Emissions Factors (ng/J)
Size
(Power Output)
>15MW
Natural gas
Diesel oil
4-1 5 MW
Natural gas
Diesel oil
<4MW
Natural gas
Diesel oil
NO,
(as NOi)
195
365
194
365
194
365
S02
2.2
10.7
2.2
10.7
2.2
10.7
Paniculate
6.0
16.0
6.0
15.5
6.0
15.5
CO
49.0
47.0
49.4
47.3
49.4
47.3
HC
8.6
8.6
8.2
9.9
8.2
9.9
ture, and amounts formed increase
exponentially with increasing tempera-
ture, as noted in Figure 3. With the injec-
tion of atomized water or steam directly
into the primary combustion zone, peak
flame temperatures are lowered since
the sensible heat of the water or steam
as well as vaporization of water effec-
tively removes some of the heat from the
primary combustion zone. NOX emis-
sions have been reduced as much as 80
percent with water injection in gas tur-
bines, as shown in Figure 5. The figure
also shows that the effectiveness of
water injection in reducing NOX varies
strongly with injected water/fuel ratio
and that virtually any NOX reduction
below 80 percent can be attained by
varying the water/fuel ratio.
Water injection is now commonly
accepted as a valid way to control NOX
emissions from current combustor design.
One turbine manufacturer has more than
61 large gas turbines equipped with
water injection equipment. Some of
these are used to meet local air pollution
regulations; others are used to increase
power output by increasing mass flow-
rates through the turbine. Another
manufacturer guarantees its gas turbine
NOX emissions to 75 ppm at 1 5 percent
oxygen in the flue gas; yet another sup-
plies wet controls on an "as needed"
basis.
It must be emphasized, though, that
experience, described above, has largely
been limited to turbines burning clean
fuels. In contrast, recent studies have
shown that the effectiveness of wet
controls decreases significantly as the
percentage of fuel-bound nitrogen in a
fuel increases. For example, one study
showed (in tests in a subscale combus-
tor version of a commercial Westing-
house unit) that the performance of
water injection decreases significantly
with high nitrogen fuels such as solvent
refined coal fuels.5 Indeed, Figure 6
shows that, with a high water/fuel mass
ratio and a high-nitrogen fuel, water in-
jection actually hinders NOX reduction.
Dry NOX controls involve combustor
modifications, but not water or steam in-
jection. A number of general concepts
have been investigated. However, two
concepts are currently thought to be
most promising: the use of super-lean
primary zone combustors and the rich-
burn/quick-quench (RBQQ) concept.
Both rely in part on prevaporization and
premixing of fuel and air, but there the
similarities end.
Super-lean primary zone combustors
rely primarily on carrying out combus-
tion under very lean conditions to limit
flame temperature, thereby limiting ther-
mal NOX formation. Various combustor
designs have been tested to extend
flammability limits for stable super-lean
combustion. These include the General
Electric radial/axial staged combustor
with premix and lean primary combus-
tion, the Pratt and Whitney Swirl Vorbix,
and the solar vortex air blast (VAB) and
jet-induced circulation (JIC) concepts.
The General Electric and Swirl Vorbix
concepts have achieved 60 percent NOX
reduction in test rigs with very low CO
and HC emissions; the VAB concept,
over 90 percent NOX reduction; and the
JIC concept, about 90 percent reduction
in test rigs, also at very low CO and
hydrocarbon emissions.
However, all these super-lean primary
zone concepts control only thermal NOX
and would thus be less effective in re-
ducing NOX from the burning of higher
nitrogen content fuels. In fact, their
super-lean primary combustion would
promote fuel nitrogen oxidation so that
the concepts might be counterproductive
in the combustion of higher nitrogen
fuels.
In contrast, the second promising con-
cept, the RBQQ concept being developed
by Pratt and Whitney, can be used in
burning high nitrogen fuels. The RBQQ
concept essentially is a means of pro-
moting staged combustion in a gas tur-
bine. Premixed fuel and air is burned
under rich conditions in the primary
zone. Secondary dilution air is then added
through quick-quench slots to complete
combustion at lower temperature. Ther-
mal and fuel NOX are limited by the low
oxygen availability in the primary zone;
thermal NOX is further limited by the
lowered primary zone temperatures.
Laboratory testing showed the con-
cept capable of NOX emissions as low as
20 ppm (1 5 percent 02) for diesel fuel;
full scale turbine emissions of 40-45
ppm have been obtained. Tests on a 0.5
percent nitrogen fuel have given 50 ppm
NOX. All tests have had acceptably low
CO levels.
In summary, wet controls are currently
the only available way to meet the re-
cently promulgated NSPS for stationary
gas turbines of 75 ppm (1 5 percent 02).
However, rapidly developing dry controls
should be available by the mid 1980's.
Costs of Control
Implementing wet NOX controls can
significantly impact the total operating
cost of a stationary gas turbine. Actual
cost estimates vary, however. Various
utilities have reported capital costs rang-
ing from $4/kW in 1975 dollars to al-
most $23/kW in 1978 dollars. By com-
parison, a typical utility gas turbine will
cost about $15O/kW in 1978 dollars.
Actual costs are site specific and depend
to a great extent on required water purifi-
cation equipment and to a lesser extent
on required turbine modifications. The
approximately 2 percent fuel penalty re-
sulting from an increased heat rate with
water injection is another significant
cost impact. Using a nominal $10/kW
(1978 dollars) capital cost for applying
water injection to large turbines, and in-
creased operating and maintenance
costs (including fuel penalty) of about 3
percent of installed cost per year, the an-
nualized cost of wet controls, including
capital and operating costs, raises the
cost of electricity by 2-5 percent.
At this stage of development, it is diffi-
cult to accurately predict associated
-------
90
80
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70
60
50
40
30
20
10
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O Liquid Fuel
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£0 /
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//
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0.2 0.4 0.6
Water/ Fuel Ratio
0.8
1.0
1.2
Figure 5. Effectiveness of water injection in reducing NOt emissions.4
costs of dry controls. A major factor in
dry control economics is passing devel-
opment costs on to the user. Dry NOX
controls including development expen-
ditures in their total cost appear to cost
somewhat less than wet NOX controls
for a comparably sized unit. If develop-
ment costs are not passed on, dry con-
trol combustors are expected to be only
nominally more costly than existing
combustor models.
Operational Impacts of Controls
There is considerable disagreement
about the impact that wet controls have
on the daily operation and maintenance
of gas turbines. An increase in engine
heat rate, manifested as a maximum of 5
percent (nominal 2 percent) increase in
fuel usage, is the most significant impact
on operations. This may be offset some-
what by increased power output caused
by the increase in mass through
Periodic recharging of the water pi
cation system will most certainly
required. Indeed, a full-time open
maintenance person may even be '
ranted for some installations. S
users have reported significant mai
nance problems with the water ti
ment system itself and internal tur
problems due to water use. The l£
problems generally involve either
part embrittlement or particle deposi
and contamination. These problems
affected not only by water qua
water/fuel ratio, and equipment t>
but also by day-to-day operation
maintenance procedures. At least
utilities have accumulated over 50,(
hours of wet NOX control experience
have experienced no significant probl
or outages directly attributable to
control technique.
Since dry controls are essenti
modified conventional combusti
although more complex, there prob;
will not be any additional impact
operation and maintenance. Still,
problems experienced by manufactu
in the developmental stage must be sol
before the concepts are used comr
dally on full scale engines. Moreo
new problems will no doubt surface i
ing the scale-up process. Currently,
controls are not expected to signif ica
affect heat rate. However, combui
liners may need more frequent repls
ment than with conventional combust
Incremental Emissions Due tc
Controls
Combustion modifications used
control NOX emissions from gas turbi
might also be expected to affect
level of emissions of other pollutant s
cies discharged. If other pollutant er
sions increase significantly, the
environmental effect of controlling f
through combustion modification n
be detrimental. For stationary comb
tion sources, the pollutants of cone
are the criteria pollutants CO, UHC, i
particulate (both mass emission ra
and emitted size distribution), along v
sulfates, organic compounds, and tr
metals.
CO, UHC, and (to some extent) par
ulate (soot) are products of incompl
combustion which can result from dr
ping temperatures too rapidly. An enc
at idle and low power produces high
and UHC because combustion eff iciei
is low. Full load produces high comb
tion efficiency and therefore low CO i
-------
-20
20
40-
6O
80
100
SRC-II Fuel
(0.94%N)
2.0%/V
1.0%N
0.5%/V
0.1 %N
No. 2 (0% MJ
Oil
0.0%N
I
I
I
0.0 0.20 0.40 0.60 0.80 1.0
Water/Fuel Mass Flow Ratio
1.2
1.4
gure 6. Predicted decrease in NO* emissions through water injection with
increasing amounts of bound nitrogen in fuel oil.5
igh UHC. While data demonstrating the
feet of NOX controls on CO, UHC, and
articulate emissions are limited, trends
eem to indicate that water and steam
ijection increase these emissions. Dry
ontrols, such as the super-lean and the
BQQ concepts, appear to be capable of
linimizing CO and UHC, but each type
>f combustor has limitations that need
o be corrected before it becomes com-
mercially available.
Data on the effects of combustion
modifications on emissions of the other
•ollutants of concern are virtually non-
ixistent. For this reason, a field test pro-
jram was initiated on a large utility gas
urbine equipped with water injection for
MOX control.
The unit tested was a 60 MW (electri-
cal) simple-cycle, single-shaft, heavy
Juty utility turbine firing No. 2 distillate
jil. Tests were performed under two
operating conditions: a baseline test,
with the unit under normal full-load opera-
ion; and a low NOX test, with water in-
ection at a water/fuel weight ratio of
3.42, also at full load. The water/fuel
ratio selected was that required to lower
NOX emissions below the gas turbine
NSPS of 7 5 ppm (dry at 1 5 percent 02).
Slightly modified Environmental As-
sessment Level 1 sampling and analysis
procedures were followed.6 Flue gas
NOX, 02, CO2, CO, and UHC were meas-
ured using continuous gas monitors. The
flue gas UHC was speciated by boiling
range (C-\ to C6), using an on-site gas
chromatograph. Particulate emissions
were determined using EPA Method 5.
Flue gas sulfur species (S02, S03, con-
densed sulfate) were measured using
EPA Method 8. The flue gas was sam-
pled with a Level 1 Source Assessment
Sampling System (SASS) train. In addi-
tion, grab samples were taken of the fuel
and water from the water injection puri-
fication system.
Sample analyses essentially followed
Level 1 protocol. SASS train samples
were analyzed for trace element and
organic content. The organic analyses
included separation by boiling range
(373 to 573 K—TCO, and greater than
573 K—GRAV), and gas chromatogra-
phy/mass spectrometry analysis for
selected polycyclic organic matter
(POM) constituents. Level 1 bioassay
tests were also performed on SASS train
sorbent extract from the water injection
test, i
Summary results from the field test
program are shown in Table 2. The table
shows that, with water injection, NOX
emissions were reduced 58 percent
from baseline levels. CO and UHC (listed
as methane in Table 2 since all UHC
detected in the tests chromatographed
as methane) levels may have increased
slightly with water injection. Higher
molecular weight organic species (greater
than C-j) emissions appeared unchanged
with water injection. Most of these de-
tected for both tests were in the TCO
boiling range. POM species were detected
at low levels for both tests and may have
increased with water injection. Water in-
jection had no detectable effect on emis-
sions of all other species analyzed in the
program.
The microbial mutagenesis bioassay
of the SASS train sorbent extract gave
negative mutagenicity results. The cyto-
toxicity assay using human lung fibro-
blasts showed low toxicity.
Environmental Impact Evaluation
The data obtained in the field test pro-
gram discussed above were evaluated
by a Source Analysis Model (SAM), spe-
cifically SAM/IA,8 to give a quantified
measure of the seriousness of the poten-
tial hazard posed by emissions from a
gas turbine. SAM/IA was developed by
IERL-RTP for use in Environmental
Assessment projects to estimate the po-
tential hazard associated with some dis-
charge streams. The basic index of
potential hazard defined by SAM/IA is
Discharge Severity (DS). The DS for a
given species is defined as the ratio of its
concentration to its multimedia environ-
mental goal. Discharge Multimedia Envi-
ronmental Goals (DMEGs), defined in
the IERL-RTP Environmental Assess-
ment program for a large number of spe-
cies, represent the maximum pollutant
concentration desirable in a discharge
stream to preclude adverse effects on
human health or ecological systems.
Table 3 presents DS (human-health-
based) values, calculated from the data
in Table 2, for species where DS exceed-
ed unity for either the baseline or water
injection test. Table 3 suggests that NOX
presents the greatest potential hazard in
the flue gas from the gas turbine, fol-
lowed by chromium, C02, S03 (vapor
phase), arsenic, SO2, and cadmium. The
high measured levels of chromium
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Table 2. Flue Gas Composition (ug/dscm): 60 MW Utility Gas Turbine
Baseline
/VOX 3.5 x 10s
SOz 3.1 x W
S03 8.1 x 103
CO 7.0 x 103
C02 8.0 x 107
Paniculate 570
Antimony < 4.6
Arsenic <14
Barium < 3.5
Beryllium < 0.92
Bismuth < 1.8
Boron < 2.2 x 103
Cadmium <13
Chromium Cj> < 1 .3 x 1031
Methane < 1.6 x 103
Dilphenyl ether 0.50
Diphenylcyclohexane
Fluoranthene
Naphthalene
Phenanthrene 0.50
Phenol 1.0
Pyrene -
Terphenyl
Water Injection
1.5 x 10s
3.4 x 104
6.0 x 103
1.0 x JO4
8.4 x 107
510
< 4.7
<14
< 3.6
< 0.14
< 2.3
< 2.0 x 103
0.55
< 7.5
< 0.13
60
89
O O
23
< 0.050
<21
< 4.8
< O 61
^^. V. \J 1
<10
< 3.4
<10
<44
<33
<49
800
< 1.1 x 103
< 2.4 x 103
_
10
0.50
1
1
1
0.50
(which cause the high DS values for this ed, SAM/IA suggests that they are emit-
species) are probably an artifact of the ted at levels too low to be of concern.
gas sampling system which contains Table
stainless steel parts. The high DS for injection
3 suggests that using water
to control NOX from gas tur-
C02 should not be of concern: its DMEG bines results in a net environmental
is based on its asphyxiant properties, not benefit.
its toxicity . Note the absence from Table senting
3 of the POM species detected and listed NOX, is
The DS for the compound pre-
the greatest potential hazard,
roughly halved, while the DS
in Table 2: although POMs were detect- values for other potentially hazardous
Table 3. Flue Gas Discharge Sevt
ity: 60 MW Utility G,
Turbine
Discharge Severity
Component Baseline Low NO
/VO, 39 17
Cr 17 8
COz 8.9 9.3
S 0$ (vapor) 8.1 6.0
As 7.0 7.0
S02 2.4 2.6
Cd 1.3 0.055
Total Stream 87.0 52.2
species remains generally unchange
Total stream DS (sum over species an
lyzed) decreases accordingly.
Recommendations
Performing the environmental asses
ment of combustion modification contrc
for stationary gas turbines has often bee
frustrated by the lack of good qualr
data in several areas. Thus, recommei
dations from the study focus on extendir
the data base necessary for evaluating tt
effects of these controls on turbine ope
ation, costs of operation, and emission
For wet controls, there are specif
areas where there appears to be a gener
lack of consensus regarding their impact
These include: ( 1 ) water injection cot
data for capital equipment, operating
and maintenance expense, (2) the cos
benefit ratio of wet controls for small gs
turbines (less than 4 MW electrical ou
put), (3) quantification of the fuel penalt
due to increased heat rate as tempere
by additional power output resultin
from more mass throughout, and (4
quantification of the effect of NOX cor
trols on incremental emissions of polk
tant species other than NOX.
Data needs for the dry control cor
cepts, though, are perhaps more press
ing, in addition to being more extensive
Dry controls are an emerging technology
and there are many unanswered ques
tions regarding their incremental effect
and associated costs. Manufacturer
appear to be focusing on the most effec
tive dry control concepts in reducini
NOX while minimizing incremental emis
sions and maintaining acceptable systen
efficiencies. The next critical step i
scaling up to full size engines, assessin;
the various environmental impacts and de
veloping long term operating experience
-------
At present, dry NOX controls appear to
>e the preferred option for new gas tur-
bines within 5 years. Due to their pre-
sent state of development, though,
issentially no data regarding emission
evels, control costs, and operation and
naintenance impacts exist for the appli-
cation of dry controls to full scale
mgines. All of these data are required to
perform a meaningful environmental
issessment of dry NOX control. As the
direction of dry controls research be-
comes evident, additional testing pro-
grams can be designed to provide the
proper data base. Then, as dry controls
lecome commercially feasible and users
gain operating experience, additional
lata gaps can be filled. The types of data
needed will primarily relate to additional
operating and maintenance costs. These
:an be predicted accurately only through
ong-term accounting of such expendi-
ures. Only by such careful front-end
racking of dry control developments
:an a comprehensive environmental
issessment be performed.
References
. "Sixth Biennial Survey of Power
Equipment Requirements of the U.S.
Electric Utility Industry." National
Equipment Manufacturers Associa-
tion, Washington, DC. March 1978.
2. Anderson, D. "Effects of Equivalence
Ratio and Dwell Time in Exhaust
Emissions from an Experimental Pre-
mixing Prevaporizing Burner." ASME
75-GT-69. December 1974.
3. Shaw, H. "The Effects of Water,
Pressure, and Equivalence Ratio on
Nitric Oxide Production in Gas Tur-
bines." Journal of Engineering for
Power, Vol. 96, No. 3, pp. 240 to
246. July 1974.
4. "Standards Support and Environmen-
tal Impact Statement, Volume I: Pro-
posed Standards of Performance for
Stationary Gas Turbines." EPA-450/
2-77-017a (NTIS PB No. 272 422).
U.S. EPA, Office of Air Quality Plan-
ning and Standards, Research Trian-
gle Park, NC. September 1977.
5. Singh, P.P., et al. "Combustion Ef-
fects of Coal Liquid and Other Syn-
thetic Fuels in Gas Turbine Combus-
tors—Part 1: Fuels Use and Subscale
Combustion Results." ASME 80-GT-
67. December 1979.
6. Lentzen, D.E., et al. "IERL-RTP Pro-
cedures Manual: Level 1 Environmen-
tal Assessment (Second Edition)."
EPA-600/7-78-201 (NTIS PB No. 293
795). U.S. EPA, Industrial Environ-
mental Research Laboratory, Re-
search Triangle Park, NC. October
1978.
Duke, K.M., et al. "IERL-RTP Proce-
dures Manual: Level 1 Environmental
Assessment Biological Tests for Pilot
Studies." EPA-600/7-77-043 (NTIS
PB No. 268 484). U.S. EPA, Industrial
Environmental Research Laboratory,
Research Triangle Park, NC. April
1977.
Schalit, L.M., and K.J. Wolfe. "SAM/
IA: A Rapid Screening Method for En-
vironmental Assessment of Fossil
Energy Process Effluents." EPA-600/
7-78-015 (NTIS PB No. 277 088).
U.S. EPA, Industrial Environmental
Research Laboratory, Research Tri-
angle Park, NC. February 1978.
/?. Larkin, R. S. Merrill, H. I. Lips, K. J. Lim, E. B. Higginbotham, and L. R.
Water/and are with Acurex Corporation, Energy and Environmental Division,
Mountain View, CA 94042.
J. S. Bowen is the EPA Project Officer (see below).
The complete report consists of two volumes, entitled "Combustion Modification
Controls for Stationary Gas Turbine,"
"Volume I. Environmental Assessment," (Order No. PB 82-226 465; Cost:
$15.00)
"Volume II. Utility Unit Field Test," (Order No. PB 82-226 473; Cost: $ 15.00)
The above reports will be available only from: (costs subject to change)
National Technical Information Service
5285 Port Royal Road
Springfield. VA 22161
Telephone: 703-487-4650
The EPA Project Officer can be contacted at:
Industrial Environmental Research Laboratory
U.S. Environmental Protection Agency
Research Triangle Park. NC 27711
•US.QOVERNMENT PRINTING OFFICE:1M2-SS9-092-422
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