EPA-453/R-93-007
Alternative Control
Techniques Document
NOX Emissions from Stationary
Gas Turbines
Emission Standards Division
U. S. ENVIRONMENTAL PROTECTION AGENCY
Office of Air and Radiation
Office of Air Quality Planning and Standards
Research Triangle Park, North Carolina 27711
January 1993
-------
ALTERNATIVE CONTROL TECHNIQUES DOCUMENTS
This report is issued by the Emission Standards Division,
Office of Air Quality Planning and Standards, U.S. Environmental
Protection Agency, to provide information to State and local air
pollution control agencies. Mention of trade names and
commercial products is not intended to constitute endorsement or
recommendation for use. Copies of this report are availableas
supplies permitfrom the Library Services Office (MD-35), U.S.
Environmental Protection Agency, Research Triangle Park,
North Carolina 27711 ([919] 541-2777) or, for a nominal fee, from
the National Technical Information Services, 5285 Port Royal
Road, Springfield, Virginia 22161 ([800] 553-NTIS).
-------
TABLE OF CONTENTS
Section
1.0 INTRODUCTION
2.0 SUMMARY
2.1 NOX FORMATION AND UNCONTROLLED NOX EMISSIONS
2.2 CONTROL TECHNIQUES AND CONTROLLED NOX
EMISSION LEVELS
2.2.1 Combustion Controls
2.2.2 Selective Catalytic Reduction ....
2.3 COSTS AND COST EFFECTIVENESS FOR NOX CONTROL
TECHNIQUES 2-9
2.3.1 Capital Costs 2-10
2.3.2 Cost Effectiveness 2-17
2.4 REVIEW OF CONTROLLED NOX EMISSION LEVELS AND
COSTS 2-23
2.5 ENERGY AND ENVIRONMENTAL IMPACTS OF NOX
CONTROL TECHNIQUES 2-23
3.0 STATIONARY GAS TURBINE DESCRIPTION AND INDUSTRY
APPLICATIONS 3-1
3.1 GENERAL DESCRIPTION OF GAS TURBINES .... 3-1
3.2 OPERATING CYCLES 3-6
3.2.1 Simple Cycle 3-7
3.2.2 Regenerative Cycle 3-7
3.2.3 Cogeneration Cycle 3-10
3.2.4 Combined Cycle 3-10
3.3 INDUSTRY APPLICATIONS 3-10
3.3.1 Oil and Gas Industry 3-13
3.3.2 Stand-By/Emergency Electric Power
Generation 3-14
3.3.3 Independent Electrical Power Producers 3-14
3.3.4 Electric Utilities 3-15
3.3.5 Other Industrial Applications .... 3-16
3.4 REFERENCES FOR CHAPTER 3 3-19
4.0 CHARACTERIZATION OF NOX EMISSIONS 4-1
4.1 THE FORMATION OF NOX 4-1
4.1.1 Formation of Thermal and Prompt NOX . 4-1
4.1.2 Formation of Fuel NOX 4-4
4.2 UNCONTROLLED NOX EMISSIONS 4-6
4.2.1 Parameters Influencing Uncontrolled
NOX Emissions 4-6
4.2.2 NOX Emissions From Duct Burners . . . 4-12
4.3 UNCONTROLLED EMISSION FACTORS 4-13
4.4 REFERENCES FOR CHAPTER 4 4-15
-------
TABLE OF CONTENTS (continued)
Section Page
5.0 NOX CONTROL TECHNIQUES 5-1
5.1 WET CONTROLS 5-5
5.1.1 Process Description 5-5
5.1.2 Applicability of Wet Controls .... 5-8
5.1.3 Factors Affecting the Performance of
Wet Controls 5-8
5.1.4 Achievable NOX Emissions Levels Using
Wet Controls 5-11
5.1.5 Impacts of Wet Controls on CO and HC
Emissions 5-28
5.1.6 Impacts of Wet Controls on Gas Turbine
Performance 5-33
5.1.7 Impacts of Wet Controls on Gas Turbine
Maintenance 5-33
5.2 COMBUSTION CONTROLS 5-36
5.2.1 Lean Combustion and Reduced Combustor
Residence Time 5-36
5.2.2 Lean Premixed Combustors 5-38
5.2.3 Rich/Quench/Lean Combustion 5-59
5.3 SELECTIVE CATALYTIC REDUCTION 5-63
5.3.1 Process Description 5-63
5.3.2 Applicability of SCR for Gas Turbines 5-65
5.3.3 Factors Affecting SCR Performance . . 5-72
5.3.4 Achievable NOX Emission Reduction
Efficiency Using SCR 5-73
5.3.5 Disposal Considerations for SCR . . . 5-73
5.4 CONTROLS USED IN COMBINATION WITH SCR . . . 5-74
5.5 EFFECT OF ADDING A DUCT BURNER IN HRSG
APPLICATIONS 5-77
5.6 ALTERNATE FUELS 5-83
5.6.1 Coal-Derived Gas 5-83
5.6.2 Methanol 5-84
5.7 SELECTIVE NONCATALYTIC REDUCTION 5-87
5.8 CATALYTIC COMBUSTION 5-88
5.8.1 Process Description 5-88
5.8.2 Applicability 5-88
5.8.3 Development Status 5-88
5.9 OFFSHORE OIL PLATFORM APPLICATIONS 5-91
5.10 REFERENCES FOR CHAPTER 5 5-92
6.0 CONTROL COST 6-1
6.1 WATER AND STEAM INJECTION AND OIL-IN-WATER
EMULSION 6-2
6.1.1 Capital Costs 6-4
6.1.2 Annual Costs 6-9
6.1.3 Emission Reduction and Cost
Effectiveness Summary for Water and
Steam Injection 6-14
IV
-------
TABLE OF CONTENTS (continued)
Section
6.2 LOW-NOX COMBUSTORS
6.3 SELECTIVE CATALYTIC REDUCTION . . .
6.3.1 Capital Costs
6.3.2 Annual Costs
6.3.3 Cost Effectiveness for SCR .
6.4 OFFSHORE TURBINES
6.4.1 Wet Injection
6.4.2 Selective Catalytic Reduction
6.5 REFERENCES FOR CHAPTER 6
7.0 ENVIRONMENTAL AND ENERGY IMPACTS
7.1 AIR POLLUTION
7.1.1 Emission Reductions
7.1.2 Emissions Trade-Offs ....
7.2 SOLID WASTE DISPOSAL
7.3 WATER USAGE AND WASTE WATER DISPOSAL
7.4 ENERGY CONSUMPTION
7.5 REFERENCE FOR CHAPTER 7
APPENDIX A
APPENDIX B
v
-------
LIST OF FIGURES
Figure Page
2-1 Uncontrolled NOX emission levels and gas turbine
manufacturers' guaranteed controlled levels using
wet injection. Natural gas fuel 2-5
2-2 Uncontrolled NOX emission levels and gas turbine
manufacturers' guaranteed controlled levels using
wet injection. Distillate oil fuel 2-6
2-3 Capital costs for water or steam injection . . . 2-11
2-4 Capital costs for dry low-NOx combustion .... 2-13
2-5 Capital costs, in $/MW, for combustion controls . 2-14
2-6 Capital costs for selective catalytic reduction . 2-15
2-7 Capital costs, in $/MW, for selective catalytic
reduction 2-16
2-8 Cost effectiveness of combustion controls .... 2-18
2-9 Cost effectiveness for selective catalytic
reduction installed dowstream of combustion
controls 2-21
2-10 Combined cost effectiveness for combustion
controls plus selective catalytic reduction . . 2-22
2-11 Controlled NOX emission levels and associated
capital costs and cost effectiveness for
available NOX control techniques. Natural
gas fuel 2-24
3-1 The three primary sections of a gas turbine . . . 3-2
3-2 Types of gas turbine combustors 3-3
3-3 Single-shaft gas turbine 3-5
3-4 Two-shaft gas turbine 3-5
3-5 Three-shaft gas turbine 3-5
3-6 Simple cycle gas turbine application 3-8
3-7 Regenerative cycle gas turbine 3-9
3-8 Cogeneration cycle gas turbine application . . . 3-11
VI
-------
H-
H-
Cn
1
H-
Hi ฃL rt
H- fD hj
hi hj O
p- p-iQ
3 < fD
in 0) 3
rt
CL H- o
H - < X
cn fD H-
rt CL
H-iฃ> fD
pj [1>
M cn fD
co 3
rt rt H-
fD ฃ cn
H cn
P CT H-
H- H- O
I '33
fD
cn rt
fD
s: cn
H- rt
rt
3" p.
Co
5] H"
Co Co
rt
fD Hi
hi O
hj
H-
3 Co
LJ. p.
fD hj
n n
rt hj
p- ill
O Hi
3 rt
1
Cn
1
H-
3 iQ rt
CO CO hj
rt cn O
C 'Q
H rt fD
CO ฃ 3
h-1 hj
cr o
iQ H- X
CO 3 H-
cn fD CL
cn fD
.
S. fD
H-3
rt H-
3" cn
cn
s: H-
jS O
rt 3
fD
H rt
fD
p- cn
3 <~t
LJ.
fD CL
n co
rt rt
H- Co
O
3 Hi
O
Hi H
H-
H hj-
H- fD
3 CO
iQ <
^
1
(~) |
rt
Cn
1
Cn
H-
Hi CL rt
H- fD H
H H O
p- p-lQ
3 < fD
iQ co a
rt
3 H- o
Co < X
rt fD H-
C p.
hj iฃ> fD
Co Co
h- ' cn fD
3
iQ rt H-
Co ฃ cn
cn hj cn
cr H-
H- O
3 3
fD
cn rt
fD
s: cn
H- rt
rt
3" CL
Co
S! rt
Co Co
rt
fD Hi
H O
H
H-
3 Co
LJ. p-
fD H
n n
rt hj
p- fi>
O Hi
3 rt
1
Cn
1
H-
H- h-1 rt
3 0 H
LJ- s: o
fD 1 iQ
O fD fD
rt Hi 3
H- Hi
O H- O
3 0 X
H- p-
Hi fD P,
H- 3 fD
H 0
H-^ fD
P 3
Co cn
3 cn cn
fa H-
rt rt O
ฃ ฃ Hi
h~^ h~^
Co Cr rt
h-1 H- fD
3 cn
iQ fD rt
fa cn
cn p.
5] Co
H- rt
rt Co
3"
Hi
s: o
CO H
rt
fD cn
H 3
Co
h- '
h- '
>
.
ฃ 3
cn co
H- 3
3 ฃ
iQ Hi
Co
s. o
fD rt
rt ฃ
H
P. fD
3 H
i i. cn
fD -
n
rtiQ
p- ฃ
O CO
3 H
Co
3
rt
O fD
P . fD
cn f^
M O
Co rt
rt H
fD O
1 1 '
O M
H- fD
1 ' P-J
Hi h-1
ฃ fD
fD <
M fD
h- '
cn
.
Cn
1
co
a
n
p
3
rt
hj
P
I '
h- '
fD
p.
^
Q
X
fD
3
H-
cn
cn
H"
c?
3
cn
3
P-J
^Q
P
cn
p"
^
n.
P
i ^~
P
H- '
a 3
cn co
H- 3
3 ฃ
iQ HI
Co
s: o
fD rt
rt ฃ
H
p- fD
3 H
LJ. cn
fD -
P
rt iฃ>
H- C
P Co
3 H
fa
3
rt
^ fD
CD fD
rt P-"
H P
Co p
I ' 3
rt
iQ hj
CO P
cn h- '
1 '
Hi fD
fD
1 ' I '
fD
<
fD
h- '
cn
.
Cn
1
a
p
P
3
rt
hj
P
I '
h-1
fD
p.
^
Q
X
fD
3
H-
cn
cn
H"
c|
3
cn
3
PJ
^Q
P
cn
p"
^
n.
P
i '
fD
0 H1
O
0 H
o fa
0 rt
H-
^^ p
h-1
co hh
J^ p
0 hj
o
^ fl)
rt
a
hj
cr
3
fD
Hi
H-
hj
H-
^
. ^
Cn
1
P1
Tl
fD
ฅ, hj
O P
x fD
P
< rt
fD fD
H in
" fD
C
cn Q
HI
rt
fif ^
^ fD
r~h | i
ฃ 1
^ tr
1 j-;
^ P
P'
C
izs
1 '"
3 hi
H- o
H" ^Q
n ^
o ^
m
2 p
3 P
a
r^i ^
2 fD
ii H
^ rt
2 fD
Hi- ^
( r
( )-
go
l~!
1
M
3
rt HI
fD M
3 C
Ti fD
fD 3
H P
CO fD
rt
C P
H HI
fD
hj
P fD
3 M
Co
ฅ, rt
O H-
X
p>
0
^
H-
rt
Co
h- '
P
P
cn
rt
cn
HI
P
fD
h-1
fD
p
rt
hj
H-
P
rt
H-
h-1
H-
rt
^
IT$
*-
Co
a
rt
cn
.
co
I
o
P
H- rt
3 Co
p. l '
rj;
cn p
rt Co
hj ^
i<; Co
P
H-
rt
k^
.
rt
P
cr
fD
.
^
. ฃ
hi
P
Co
cn
fD
p.
.
cr
rt
y
fD
. ฃ
rt
H-
h-'
H-
rt
k^J
.
CO l-r]
1 H-
UD Q
fD
O
P
3
tr
H-
p
fD
p.
P
P
fD
lO
Co
cn
rt
ฃ
hj
cr
H-
fD
CO
fj-j
h- '
H-
P
CO
rt
H-
P
a
.
t-1
M
CO
o
Q
a
CO
n
o
3
rt
H-
fD
Cn
I
o
Cn
I
Cn
I
Cn
I
Cn
I
Cn
I
co
Cn
I
I
CO
I
co
co
I
co
I
co
I
-------
LIST OF FIGURES (continued)
Figure Page
5-8 Nitrogen oxide emission test data for heavy-duty
gas turbines with water injection and WFR's
less than 0.5 and firing distillate oil .... 5-21
5-9 Nitrogen oxide emission test data for heavy-duty
gas turbines with water injection and WFR's
greater than 0.5 and firing distillate oil . . 5-22
5-10 Nitrogen oxide emission test data for gas turbines
with steam injection firing natural gas .... 5-24
5-11 Nitrogen oxide emission test data for gas turbines
with steam injection firing distillate oil . . 5-25
5-12 Comparison of the WFR requirement for water-in-oil
emulsion versus separate water injection for an
oil-fired turbine 5-27
5-13 Effect of wet injection on CO emissions 5-31
5-14 Effect of water injection on HC emissions for one
turbine model 5-32
5-15 Nitrogen oxide emissions versus turbine firing
temperature for combustors with and without a
lean primary zone 5-39
5-16 Cross-section of a lean premixed can-annular
combustor 5-41
5-17 Operating modes for a lean premixed can-annular
combustor 5-42
5-18 Cross-section of lean premixed annular combustion
design 5-44
5-19 Cross-section of a low-NOx silo combustor .... 5-45
5-20 Low-N0x burner for a silo combustor 5-46
5-21 "Stepped" NOX and CO emissions for a low-NOx
can-annular combustor burning natural gas and
distillate oil fuels 5-49
5-22 "Stepped" NOX and CO emissions for a low-NOx
can-annular combustor burning natural gas . . . 5-50
VI11
-------
LIST OF FIGURES (continued)
Figure Page
5-23 Nitrogen oxide emission test results from a lean
premix silo combustor firing fuel oil without
wet injection 5-52
5-24 The CO emission test results from a lean premix
silo combustor firing fuel oil without wet
injection 5-58
5-25 Nitrogen oxide emissions versus primary zone
equivalence ratio for a rich/quench/lean
combustor firing distillate oil 5-61
5-26 Effects of fuel bound nitrogen (FBN) content of
NOX emissions for a rich/quench/lean combustor 5-62
5-27 Cutaway view of a typical monolith catalyst body
with honeycomb configuration 5-64
5-28 Possible locations for SCR unit in HRSG 5-67
5-29 Typical duct burner for gas turbine exhaust
application 5-78
5-30 Cross-sectional view of a low-NOx duct burner . . 5-79
5-31 Low-N0x duct burner designed for oil firing . . . 5-81
5-32 Influence of load on NOX, 02, and C02 emissions
for methanol and natural gas 5-86
5-33 A lean catalytic combustor 5-89
5-34 A rich/lean catalytic combustor 5-90
IX
-------
LIST OF TABLES
Table PC
2-1 UNCONTROLLED NOX EMISSION FACTORS FOR GAS
TURBINES
4-1 UNCONTROLLED NOX EMISSIONS FACTORS FOR GAS
TURBINES AND DUCT BURNERS 4-14
5-1 NOX EMISSION LIMITS AS ESTABLISHED BY THE NEW
SOURCE PERFORMANCE STANDARDS FOR GAS TURBINES . 5-2
5-2 NOX COMPLIANCE LIMITS AS ESTABLISHED BY THE SOUTH
COAST AIR QUALITY MANAGEMENT DISTRICT (SCAQMD)
FOR EXISTING TURBINES. RULE 1134. ADOPTED
AUGUST 1989 5-3
5-3 NOX EMISSION LIMITS RECOMMENDED BY THE NORTHEAST
STATES FOR COORDINATED AIR USE MANAGEMENT
(NESCAUM) 5-4
5-4 WATER QUALITY SPECIFICATIONS OF SELECTED GAS
TURBINE MANUFACTURERS FOR WATER INJECTION
SYSTEMS 5-6
5-5 MANUFACTURER'S GUARANTEED NOX REDUCTION
EFFICIENCIES AND ESTIMATED WATER-TO-FUEL RATIOS
FOR NATURAL GAS FUEL OPERATION 5-9
5-6 MANUFACTURER'S GUARANTEED NOX REDUCTION
EFFICIENCIES AND ESTIMATED WATER-TO-FUEL RATIOS
FOR DISTILLATE OIL FUEL OPERATION 5-10
5-7 ACHIEVABLE GAS TURBINE NOX EMISSION REDUCTIONS
FOR OIL-FIRED TURBINES USING WATER-IN-OIL
EMULSIONS 5-26
5-8 UNCONTROLLED NOX EMISSIONS AND POTENTIAL NOX
REDUCTIONS FOR GAS TURBINES USING WATER
INJECTION 5-29
5-9 UNCONTROLLED NOX EMISSIONS AND POTENTIAL NOX
REDUCTIONS FOR GAS TURBINES USING STEAM
INJECTION 5-30
5-10 REPRESENTATIVE WATER/STEAM INJECTION IMPACTS ON
GAS TURBINE PERFORMANCE FOR ONE MANUFACTURER'S
HEAVY-DUTY TURBINES 5-34
5-11 IMPACTS OF WET CONTROLS ON GAS TURBINE
MAINTENANCE USING NATURAL GAS FUEL 5-35
x
-------
LIST OF TABLES (continued)
Table Page
5-12 MEASURED NOX EMISSIONS FOR COMPLIANCE TESTS OF A
NATURAL GAS-FUELED LEAN PREMIXED COMBUSTOR
WITHOUT WATER INJECTION 5-53
5-13 MEASURED NOX FOR OPERATION OF A LEAN PREMIXED
COMBUSTOR DESIGN OPERATING IN DIFFUSION MODE ON
OIL FUEL WITH WATER INJECTION 5-54
5-14 POTENTIAL NOX REDUCTIONS FOR GAS TURBINES USING
LEAN PREMIXED COMBUSTORS 5-56
5-15 COMPARISON OF NOX AND CO EMISSIONS FOR STANDARD
VERSUS LEAN PREMIXED COMBUSTORS FOR TWO
MANUFACTURERS' TURBINES 5-57
5-16 GAS TURBINE INSTALLATIONS IN THE NORTHEASTERN
UNITED STATES WITH SCR AND PERMITTED FOR BOTH
NATURAL GAS AND OIL FUELS 5-70
5-17 EMISSIONS TESTS RESULTS FOR GAS TURBINES USING
STEAM INJECTION PLUS SCR 5-75
5-18 SUMMARY OF SCR NOX EMISSION REDUCTIONS AND AMMONIA
SLIP LEVELS FOR NATURAL GAS-FIRED TURBINES . . 5-76
5-19 NOX EMISSIONS MEASURED BEFORE AND AFTER A DUCT
BURNER 5-82
5-20 NOX EMISSIONS TEST DATA FOR A GAS TURBINE FIRING
METHANOL AT BASELOAD 5-85
6-1 GAS TURBINE MODEL PLANTS FOR NOX CONTROL
TECHNIQUES 6-3
6-2 FUEL AND WATER FLOW RATES FOR WATER AND STEAM
INJECTION (1990 $) 6-5
6-3 FUEL PROPERTIES AND UTILITY AND LABOR RATES ... 6-6
6-4 CAPITAL COSTS FOR WET INJECTION IN THOUSAND OF
DOLLARS 6-7
6-5 ANNUAL COSTS FOR WATER AND STEAM INJECTION
(1990 $) 6-10
6-6 COST-EFFECTIVENESS SUMMARY FOR WATER AND STEAM
INJECTION (1990 $) 6-15
XI
-------
LIST OF TABLES (continued)
Table Page
6-7 COST-EFFECTIVENESS SUMMARY FOR DRY LOW-NOX
COMBUSTORS USING NATURAL GAS FUEL (1990 $) . . 6-17
6-8 PROCEDURES FOR ESTIMATING CAPITAL AND ANNUAL COSTS
FOR SCR CONTROL OF NOX EMISSIONS FROM GAS
TURBINES 6-20
6-9 CAPITAL AND ANNUAL COSTS FOR SCR USED DOWNSTREAM
OF WATER OR STEAM INJECTION (1990 $) 6-21
6-10 CAPITAL AND ANNUAL COSTS FOR SCR USED DOWNSTREAM
OF LOW-NOX COMBUSTION 6-22
6-11 COST-EFFECTIVENESS SUMMARY FOR SCR USED DOWNSTREAM
OF GAS TURBINES WITH WET INJECTION (1990 $) . . 6-27
6-12 COST-EFFECTIVENESS SUMMARY FOR SCR USED DOWNSTREAM
OF DRY LOW-NOX COMBUSTION (1990 $) 6-28
6-13 COMBINED COST-EFFECTIVENESS SUMMARY FOR WET
INJECTION PLUS SCR (1990 $) 6-30
6-14 COMBINED COST-EFFECTIVENESS SUMMARY FOR DRY
LOW-NOX COMBUSTION PLUS SCR (1990 $) 6-31
6-15 PROJECTED WET INJECTION AND SCR COSTS FOR AN
OFFSHORE GAS TURBINE 6-33
7-1 MODEL PLANT UNCONTROLLED AND CONTROLLED NOX
EMISSIONS FOR AVAILABLE NOX CONTROL TECHNIQUES 7-2
7-2 WATER AND ELECTRICITY CONSUMPTION FOR NOX CONTROL
TECHNIQUES 7-9
XII
-------
1.0 INTRODUCTION
Congress, in the Clean Air Act Amendments of 1990 (CAAA) ,
amended Title I of the Clean Air Act (CAA) to address ozone
nonattainment areas. A new Subpart 2 was added to Part D of
Section 103. Section 183(c) of the new Subpart 2 provides that:
[w]ithin 3 years after the date of the enactment of the
CAAA, the Administrator shall issue technical documents
which identify alternative controls for all categories of
stationary sources of...oxides of nitrogen which emit or
have the potential to emit 25 tons per year or more of such
air pollutant.
These documents are to be subsequently revised and updated as
determined by the Administrator.
Stationary gas turbines have been identified as a category
that emits more than 25 tons of nitrogen oxide (NOX) per year.
This alternative control techniques (ACT) document provides
technical information for use by State and local agencies to
develop and implement regulatory programs to control NOX
emissions from stationary gas turbines. Additional ACT documents
are being developed for other stationary source categories.
Gas turbines are available with power outputs ranging from
1 megawatt (MW) (1,340 horsepower [hp]) to over 200 MW
(268,000 hp) and are used in a broad scope of applications. It
must be recognized that the alternative control techniques and
the corresponding achievable NOX emission levels presented in
this document may not be applicable for every gas turbine
application. The size and design of the turbine, the operating
duty cycle, site conditions, and other site-specific factors must
be taken into consideration, and the suitability of an
1-1
-------
alternative control technique must be determined on a case-by-
case basis.
The information in this ACT document was generated through
a literature search and from information provided by gas turbine
manufacturers, control equipment vendors, gas turbine users, and
regulatory agencies. Chapter 2.0 presents a summary of the
findings of this study. Chapter 3.0 presents information on gas
turbine operation and industry applications. Chapter 4.0
contains a discussion of NOX formation and uncontrolled NOX
emission factors. Alternative control techniques and achievable
controlled emission levels are included in Chapter 5.0. The cost
and cost effectiveness of each control technique are presented in
Chapter 6.0. Chapter 7.0 describes environmental and energy
impacts associated with implementing the NOX control techniques.
1-2
-------
2.0 SUMMARY
This chapter summarizes the more detailed information
presented in subsequent chapters of this document. It presents a
summary of nitrogen oxide (NOX) formation mechanisms and
uncontrolled NOX emission factors, available NOX emission control
techniques, achievable controlled NOX emission levels, the costs
and cost effectiveness for these NOX control techniques applied
to combustion gas turbines, and the energy and environmental
impacts of these control techniques. The control techniques
included in this analysis are water or steam injection, dry low-
NOX combustors, and selective catalytic reduction (SCR).
Section 2.1 includes a brief discussion of NOX formation
and a summary of uncontrolled NOX emission factors. Section 2.2
describes the available control techniques and achievable
controlled NOX emission levels. A summary of the costs and cost-
effectiveness for each control technique is presented in
Section 2.3. Section 2.4 reviews the range of controlled
emission levels, capital costs, and cost effectiveness.
Section 2.5 discusses energy and environmental impacts.
2.1 NOX FORMATION AND UNCONTROLLED NOX EMISSIONS
The two primary NOX formation mechanisms in gas turbines
are thermal and fuel NOX. In each case, nitrogen and oxygen
present in the combustion process combine to form NOX. Thermal
NOX is formed by the dissociation of atmospheric nitrogen (N2)
and oxygen (02) in the turbine combustor and the subsequent
formation of NOX. When fuels containing nitrogen are combusted,
this additional source of nitrogen results in fuel NOX formation.
Because most turbine installations burn natural gas or light
2-1
-------
distillate oil fuels with little or no nitrogen content, thermal
NOX is the dominant source of NOX emissions. The formation rate
of thermal NOX increases exponentially with increases in
temperature. Because the flame temperature of oil fuel is higher
than that of natural gas, NOX emissions are higher for operations
using oil fuel than natural gas.
Uncontrolled NOX emission levels were provided by gas
turbine manufacturers in parts per million, by volume (ppmv).
Unless stated otherwise, all emission levels shown in ppmv are
corrected to 15 percent 02. These emission levels were used to
calculate uncontrolled NOX emission factors, in pounds (Ib) of
NOX per million British thermal units (Btu) (Ib NOx/MMBtu).
Sample calculations are shown in Appendix A. These uncontrolled
emission levels and emission factors for both natural gas and oil
fuel are presented in Table 2-1
-------
TABLE 2-1. UNCONTROLLED NO,, EMISSION FACTORS FOR GAS TURBINES
Manufacturer
Solar
GM/Allison
General Electric
Asea Brown Boveri
Westinghouse
Siemens
Model No.
Saturn
Centaur
Centaur "H"
Taurus
Mars T 12000
Mars T 14000
501-KB5
570-KA
571-KA
LM1600
LM2500
LM5000
LM6000
MS5001P
MS6001B
MS7001EA
MS7001F
MS9001EA
MS9001F
GT8
GT10
GT11N
GT35
W261B11/12
W501D5
V84.2
V94.2
V64.3
V84.3
V94.3
Output,
MW
1.1
3.3
4.0
4.5
8.8
10.0
4.0
4.9
5.9
12.8
21.8
33.1
41.5
26.3
38.3
83.5
123
150
212
47.4
22.6
81.6
16.9
52.3
119
105
153
61.5
141
203
NOX emissions, ppmv, dry
and corrected to 15% 0,
Natural gas
99
130
105
114
178
199
155
101
101
144
174
185
220
142
148
154
179
176
176
430
150
390
300
220
190
212
212
380
380
380
Distillate
oil No. 2
150
179
160
168
267
NA"
231
182
182
237
345
364
417
211
267
228
277
235
272
680
200
560
360
355
250
360
360
530
530
530
NOX emissions factor,
Ib NCVMMBtu"
Natural gas
0.397
0.521
0.421
0.457
0.714
0.798
0.622
0.405
0.405
0.577
0.698
0.742
0.882
0.569
0.593
0.618
0.718
0.706
0.706
1.72
0.601
1.56
1.20
0.882
0.762
0.850
0.850
1.52
1.52
1.52
Distillate
oil No. 2
0.551
0.658
0.588
0.618
0.981
NA"
0.849
0.669
0.669
0.871
1.27
1.34
1.53
0.776
0.981
0.838
1.02
0.864
1.00
2.50
0.735
2.06
1.32
1.31
0.919
1.32
1.32
1.95
1.95
1.95
"Based on emission levels provided by gas turbine manufacturers, corresponding to rated load at ISO conditions.
NOX emissions calculations are shown in Appendix A.
bNot available.
-------
Uncontrolled NOX emission levels range from 99 to 430 ppmv for
natural gas fuel and from 150 to 680 ppmv for distillate oil
fuel. Corresponding uncontrolled emission factors range from
0.397 to 1.72 Ib NOx/MMBtu and 0.551 to 2.50 Ib NOx/MMBtu for
natural gas and distillate oil fuels, respectively. Because
thermal NOX is primarily a function of combustion temperature,
NOX emission rates vary with combustor design. There is no
discernable correlation between turbine size and NOX emission
levels evident in Table 2-1.
2.2 CONTROL TECHNIQUES AND CONTROLLED NOX EMISSION LEVELS
Reductions in NOX emissions can be achieved using
combustion controls or flue gas treatment. Available combustion
controls are water or steam injection and dry low-NOx combustion
designs. Selective catalytic reduction is the only available
flue gas treatment.
2.2.1 Combustion Controls
Combustion control using water or steam lowers combustion
temperatures, which reduces thermal NOX formation. Fuel NOX
formation is not reduced with this technique. Water or steam,
treated to quality levels comparable to boiler feedwater, is
injected into the combustor and acts as a heat sink to lower
2-4
-------
flame temperatures. This control technique is available for all
new turbine models and can be retrofitted to most existing
installations.
Although uncontrolled emission levels vary widely, the range
of achievable controlled emission levels using water or steam
injection is relatively small. Controlled NOX emission levels
range from 25 to 42 ppmv for natural gas fuel and from 42 to
75 ppmv for distillate oil fuel. Achievable guaranteed
controlled emission levels, as provided by turbine manufacturers,
are shown for individual turbine models in Figures 2-1 and 2-2
2-5
-------
NATURAL GAS
STEAM & WATER
EQUAL
-------
"d
H-
(D
to
to
LIQUID FUEL
3 3
CD (U
ft 0
H- Hi
ฃ3 Q)
cj. O
(D ft
O ฃ
ft '"S
H- (D
O ^
0 U
H- Pป
W H
g
o
8
rr
(D
^O
ง
(D
U
CM
O
ฉ
CL
D.
tn
c
pTcD O ฃ
rtO.0 fi
ซฃ ^
o o ^ O
H- 3 ^ "5"1
MfT ป ^
roo-
600-
500-
40U-
300
aoo-
100-
0-
_
"
UNCONTROLLED
STCAM& WATER
^ EQUAL
WATER
34
W
i
/X,'
ซ
J
ll:
8
1 '
hง
1
68
)<
/"**.
2|
P
ฃ
L,
66
1
^
%*
2
4.
65
^r
'42
r
I
3<
<
75
^
24
IK
I
II
1
f
.'/v
11
l
2gJ_
li
^
28
6B
ftft
K*
asa
,JBH
411
353
,mm
5Ss
p
60
i
ง
r
42
i
3d
<
60
v:
0 3
!
ง5
1
55
H
42
3f
r^H
>i\SS
n
m
um
55
SjJ
$
630
^2
1
1
75
9
n
i
i
1 ^ 8 S s'*. '^'s l8T8[Sr2rr?'sl fc '^'^P'^'s's'r 'S'a's'^'j'^'
a>
?^งS8 = 5g
t- i- < 2 7 5 S
J. c g f "- S "
M8 I
u7 U
_ S S P 8 S S
52r5ซ5vrC r- EKaS
_|DC')ฉ^!^'L'>2J
-------
for natural gas and oil fuels, respectively.
The decision whether to use water versus steam injection for
NOX reduction depends on many factors, including the availability
of steam injection nozzles and controls from the turbine
manufacturer, the availability and cost of steam at the site, and
turbine performance and maintenance impacts. This decision is
usually driven by site-specific environmental and economic
factors.
A system that allows treated water to be mixed with the fuel
prior to injection is also available. Limited testing of water-
in-oil emulsions injected into the turbine combustor have
achieved NOX reductions equivalent to direct water injection but
at reduced water-to-fuel rates. The vendor reports a similar
system is available for natural gas-fired applications.
Dry low-NOx combustion control techniques reduce NOX
emissions without injecting water or steam. Two designs, lean
premixed combustion and rich/quench/lean staged combustion have
been developed.
Lean premixed combustion designs reduce combustion
temperatures, thereby reducing thermal NOX. Like wet injection,
this technique is not effective in reducing fuel NOX. In a
conventional turbine combustor, the air and fuel are introduced
at an approximately stoichiometric ratio and air/fuel mixing
occurs simultaneously with combustion. A lean premixed combustor
design premixes the fuel and air prior to combustion. Premixing
results in a homogeneous air/fuel mixture, which minimizes
-------
2-9
-------
localized fuel-rich pockets that produce elevated combustion
temperatures and higher NOX emissions. A lean air-to-fuel ratio
approaching the lean flammability limit is maintained, and the
excess air acts as a heat sink to lower combustion temperatures,
which lowers thermal NOX formation. A pilot flame is used to
maintain combustion stability in this fuel-lean environment.
Lean premixed combustors are currently available from
several turbine manufacturers for a limited number of turbine
models. Development of this technology is ongoing, and
availability should increase in the coming years. All turbine
manufacturers state that lean premixed combustors are designed
for retrofit to existing installations.
Controlled NOX emission levels using dry lean premixed
combustion range from 9 to 42 ppmv for operation on natural gas
fuel. The low end of this range (9 to 25 ppmv) has been limited
to turbines above 20 megawatts (MW) (27,000 horsepower [hp]); to
date, three manufacturers have guaranteed controlled NOX emission
levels of 9 ppmv at one or more installations for utility-sized
turbines. Controlled NOX emissions from smaller turbines
typically range from 25 to 42 ppmv. For operation on distillate
oil fuel, water or steam injection is required to achieve
controlled NOX emissions levels of approximately 65 ppmv.
Development continues for oil-fueled operation in lean premixed
designs, however, and one turbine manufacturer reports having
achieved controlled NOX emission levels below 50 ppmv in limited
testing on oil fuel without wet injection.
A second dry low-NOx combustion design is a rich/quench/lean
staged combustor. Air and fuel are partially combusted in a
fuel-rich primary stage, the combustion products are then rapidly
quenched using water or air, and combustion is completed in a
fuel-lean secondary stage. The fuel-rich primary stage inhibits
NOX formation due to low 02 levels. Combustion temperatures in
the fuel-lean secondary stage are below NOX formation
temperatures as a result of the quenching process and the
presence of excess air. Both thermal and fuel NOX are controlled
with this design. Limited testing with fuels including natural
2-10
-------
gas and coal have achieved controlled NOX emissions of 25 ppmv.
Development of this design continues, however, and currently the
rich/quench/lean combustor is not available for production
turbines.
2.2.2 Selective Catalytic Reduction
This flue gas treatment technique uses an ammonia (NH3)
injection system and a catalytic reactor to reduce NOX. An
injection grid disperses NH3 in the flue gas upstream of the
catalyst, and NH3 and NOX are reduced to N2 and water (H20) in the
catalyst reactor. This control technique reduces both thermal
NOX and fuel NOX.
Ammonia injection systems are available that use either
anhydrous or aqueous NH3. Several catalyst materials are
available. To date, most SCR installations use a base-metal
catalyst with an operating temperature window ranging from
approximately 260ฐ to 400ฐC (400ฐ to 800ฐF). The exhaust
temperature from the gas turbine is typically above 480ฐC
(900ฐF), so the catalyst is located within a heat recovery steam
generator (HRSG) where temperatures are reduced to a range
compatible with the catalyst operating temperature. This
operating temperature requirement has, to date, limited SCR to
cogeneration or combined-cycle applications with HRSG's to reduce
flue gas temperatures. High-temperature zeolite catalysts,
however, are now available and have operating temperature windows
of up to 600ฐC (1100ฐF), which is suitable for installation
directly downstream of the turbine. This high-temperature
zeolite catalyst offers the potential for SCR applications with
simple cycle gas turbines.
To achieve optimum long-term NOX reductions, SCR systems
must be properly designed for each application. In addition to
temperature considerations, the NH3 injection rate must be
carefully controlled to maintain an NH3/NOX molar ratio that
effectively reduces NOX and avoids excessive NH3 emissions
downstream of the catalyst, known as ammonia slip. The selected
catalyst formulation must be resistant to potential masking
and/or poisoning agents in the flue gas.
2-11
-------
To date, most SCR systems in the United States have been
installed in gas-fired turbine applications, but improvements in
SCR system designs and experience on alternate fuels in Europe
and Japan suggest that SCR systems are suitable for firing
distillate oil and other sulfur-bearing fuels. These fuels
produce sulfur dioxide (S02) , which may oxidize to sulfite (S03)
in the catalyst reactor. This S03 reacts with NH3 slip to form
ammonium salts in the low-temperature section of the HRSG and
exhaust ductwork. The ammonium salts must be periodically
cleaned from the affected surfaces to avoid fouling and corrosion
as well as increased back-pressure on the turbine. Advances in
catalyst formulations include sulfur-resistant catalysts with low
S02 oxidation rates. By limiting ammonia slip and using these
sulfur-resistant catalysts, ammonium salt formation can be
minimized.
Catalyst vendors offer NOX reduction efficiencies of
90 percent with ammonia slip levels of 10 ppmv or less. These
emission levels are warranted for 2 to 3 years, and all catalyst
vendors contacted accept return of spent catalyst reactors for
recycle or disposal.
Controlled NOX emission levels using SCR are typically
9 ppmv or less for gas-fueled turbine installations. With the
exception of one site, all identified installations operate the
SCR system in combination with combustion controls that reduce
NOX emission levels into the SCR to a range of 25 to 42 ppmv.
Most continuous-duty turbine installations fire natural gas;
there is limited distillate oil-fired operating experience in the
United States. Several installations with SCR in the northeast
United States that use distillate oil as a back-up fuel have
controlled NOX emission limits of 18 ppmv for operation on
distillate oil fuel.
2.3 COSTS AND COST EFFECTIVENESS FOR NOX CONTROL TECHNIQUES
Capital costs and cost effectiveness were developed for the
available NOX control techniques. Capital costs are presented in
Section 2.3.1. Cost-effectiveness figures, in $/ton of NOX
2-12
-------
removed, are shown in Section 2.3.2. All costs presented are in
1990 dollars.
2.3.1 Capital Costs
Capital costs are the sum of purchased equipment costs,
taxes and freight charges, and installation costs. Purchased
equipment costs were estimated based on information provided by
equipment manufacturers, vendors, and published sources. Taxes,
freight, and installation costs were developed based on factors
recommended in the Office of Air Quality and Planning and
Standards Control Cost Manual (Fourth Edition). Capital costs
for combustion controls and SCR are presented in Sections 2.3.1.1
and 2.3.1.2, respectively.
2.3.1.1 Combustion Controls Capital Costs. Capital costs
for wet injection include a mixed bed demineralizer and reverse-
osmosis water treatment system and an injection system consisting
of pumps, piping and hardware, metering controls, and injection
nozzles. All costs for wet injection are based on the
availability of water at the site; no costs have been included
for transporting water to the site. These costs apply to new
installations; retrofit costs would be similar except that
turbine-related injection hardware and metering controls
purchased from the turbine manufacturer may be higher for
retrofit applications.
The capital costs for wet injection are shown in Figure 2-3,
and range from $388,000 for a 3.3 MW (4,430 hp) turbine to
$4,830,000 for a 161 MW (216,000 hp) turbine.
2-13
-------
1
CD
to
CO
O
8
H-
rr
(u
o
O
w
(T
u
Hi
O
(U
(T
(D
U
(T
(D
H-
0
l_l.
(D
O
(T
H-
8
V*
h-"
o
o
S...X
_l
<
51
C")
vซซซ*
D"
4.5-
4-
3.5^
"^ ~* Q-
C.
-^ 2.5-
1, 2-
1.5-
1-
0.5
n-
*
X
*
#
* *
^
x I x Water Injection . * Steam Injection 1
0 20 40 60 80 100 120 140 160
TURBINE POWER OUTPUT, MW
-------
These capital costs include both water and steam injection
systems for use with either gas or distillate oil fuel
applications. Figure 2-3 shows that the capital costs for steam
injection are slightly higher than those for water injection for
turbines in the 3 to 25 MW (4,000 to 33,500 hp) range.
The capital costs for dry low-NOx combustors are the
incremental costs for this design over a conventional combustor
and apply to new installations. Turbine manufacturers estimate
retrofit costs to be approximately 40 to 60 percent higher than
new equipment costs. Incremental capital costs for dry low-NOx
2-15
-------
combustion were provided by turbine manufacturers and are
presented in Figure 2-4.
2-16
-------
s
!{
(D
to
0
(U
d
H-
(T
(U
O
0
u
ft
Hi
0
^
P.
I-1
i
J8
o
ง
rr
H-
8
o p **
2-
1.8-
ป 1.6-
H"
O ^ "
o| 12^
X
X
-------
The incremental capital costs range from $375,000 for a 3.3 MW
(4,430 hp) turbine to $2.2 million for an 85 MW (114,000 hp)
machine. Costs were not available for turbines above 85 MW
(114,000 hp).
When evaluated on a $/MW ($/hp) basis, the capital costs for
wet injection or dry low-NOx combustion controls are highest for
the smallest turbines and decrease exponentially with increasing
turbine size. The range of capital costs for combustion
controls, in $/MW, and the effect of turbine size on capital
costs are shown in Figure 2-5.
2-18
-------
CD
to
Ul
O
H-
rr
(u
O
O
u
rr
u
Hi
O
O
rr
H-
8
O
O
0
(T
^1
O
I-1
U
140'
120-
ซ* ^ 100-
ซ S
O ซ 80
<
51
60
40-
X Water Injection * Steam injection B Dry Low NOx
K
El
El
IS
20
4c 60 ab lio
TURBINE POWER OUTPUT, MW
^
140 160
-------
For wet injection, the capital costs range from a high of
$138,000/MW ($103/hp) for a 3.3 MW (4,430 hp) turbine to a low of
$29,000/MW ($22/hp) for a 161 MW (216,000 hp) turbine.
Corresponding capital cost figures for dry low-NOx combustion
range from $114,000/MW ($85/hp) for a 3.3 MW (4,430 hp) unit to
$26,000/MW ($19/hp) for an 85 MW (114,000 hp) machine.
2.3.1.2 SCR Capital Costs. Capital costs for SCR include
the catalyst reactor, ammonia storage and injection system, and
controls and monitoring equipment. A comparison of available
cost estimates for base-metal catalyst systems and high-
temperature zeolite catalyst systems indicates that the costs for
these systems are similar, so a single range of costs was
developed that represents all SCR systems, regardless of catalyst
type or turbine cycle (i.e., simple, cogeneration, or combined
cycle).
The capital costs for SCR, shown in Figure 2-6, range from
$622,000 for a 3.3 MW (4,430 hp) turbine to $8.46 million for a
161 MW (216,000 hp) turbine.
2-20
-------
CD
to
0
(U
d
H-
(T
(U
I-1
O
O
(T
W
Hi
0
U
CD
I-1
(D
O
(T
H-
(D
O
(U
(T
(U
I-1
(T
H-
O
y
8
7-
** fr
H
CO
Q 1? 5-
o g
^1 4-
&. ^
^Hf*
0 3-
2-
1-
A-
>
*
~ x
X
xx
**
(D
O
(T
H-
O
0
20 40 60 80 100 120
TURBINE POWER OUTPUT, MW
140
160
-------
Figure 2-7 plots capital costs on a $/MW basis and shows that
these costs are highest for the smallest turbine, at $188,000/MW
($140/hp) for a 3.3 MW (4,430 hp) unit, and decrease
exponentially with increasing turbine size to $52/MW ($40/hp) for
a 161 MW (216,000 hp) machine.
-------
I
GO
(D
to
O
(u
d
H-
(T
(U
O
O
W
(T
^1 W
(D -
P.
C H-
O 0
(T
H-^^
O \
Hi
o
U
(D
I-1
(D
O
(T
H-
(D
O
(U
(T
(U
--8
200
180-
160-
140-
te
g ง 120H
O
t *- 100H
Q.
80-
40
X
X
'0 20 40 60 80 100 120
TURBINE POWER OUTPUT, MW
140 160
(T
H-
O
-------
These costs apply to new installations firing natural gas as
the primary fuel. No SCR sites using oil as the primary fuel
were identified, and costs were not available. For this
2-24
-------
2-25
-------
2-26
-------
2-27
-------
reason, the costs for gas-fired applications were also used for
oil-fired sites. Retrofit SCR costs could be considerably higher
than those shown here for new installations, especially if an
existing HRSG and ancillary equipment must be moved or modified
to accommodate the SCR system.
2.3.2 Cost Effectiveness
The cost effectiveness, in $/ton of NOX removed, was
developed for each NOX control technique. The cost effectiveness
for a given control technique is calculated by dividing the total
annual cost by the annual NOX reduction, in tons. The cost
effectiveness presented in this section correspond to 8,000
annual operating hours. Total annual costs were calculated as
the sum of all annual operating costs and annualized capital
costs. Annual operating costs include costs for incremental
fuel, utilities, maintenance, applicable performance penalties,
operating and supervisory labor, plant overhead, general and
administrative, and taxes and insurance. Capital costs were
annualized using the capital recovery factor method with an
equipment life of 15 years and an annual interest rate of
10 percent. Cost-effectiveness figures for combustion controls
and SCR are presented in Sections 2.3.2.1 and 2.3.2.2,
respectively.
2.3.2.1 Combustion Controls Cost Effectiveness. Cost
effectiveness for combustion controls is shown in Figure 2-8.
2-28
-------
to
I
(D
to
00
O
O
w
ft
(D
Hi
Hi
(D
O
(T
H-
-------
Figure 2-8 indicates that cost effectiveness for combustion
controls is highest for the smallest turbines and decreases
exponentially with decreasing turbine size. Figure 2-8 also
shows that the range of cost effectiveness for water injection is
similar to that for steam injection, primarily because the total
annual costs and achievable controlled NOX emission levels for
water and steam injection are similar. The cost-effectiveness
range for dry low-NOx combustion is lower than that for wet
x levels are similar (25
to 42 ppmv) , due to the lower total annual costs for dry low-NOx
combustion.
2-30
-------
For water injection, cost effectiveness, in $/ton of NOX
removed, ranges from $2,080 for a 3.3 MW (4,430 hp) unit to $575
for an 83 MW (111,000 hp) turbine and $937 for an 85 MW
(114,000 hp) turbine. For steam injection, cost effectiveness is
$1,830 for a 3.3 MW (4,430 hp) , decreasing to $375 for an 83 MW
(111,000 hp) turbine, and increasing to $478 for a 161 MW
(216,000 hp) turbine. The relatively low cost effectiveness for
the 83 MW (111,000 hp) turbine is due to this particular
turbine's high uncontrolled NO emissions, which result in a
relatively high NOX removal efficiency and lower cost
effectiveness. The cost effectiveness shown in Figure 2-8
number of oil-fired applications with water injection indicates
that the cost effectiveness ranges from 70 to 85 percent of the
NOX removal efficiency achieved in oil-fired applications.
For dry low-NOx combustion, cost effectiveness, in $/ton of
NOX removed, ranges from $1,060 for a 4.0 MW (5,360 hp) turbine
down to $154 for an 85 MW (114,000 hp) machine. A cost
effectiveness of $57 was calculated for the 83 MW (111,000 hp)
unit. Again, the relatively high uncontrolled NOX emissions and
the resulting high NOX removal efficiency for this turbine model
yields a relatively low cost-effectiveness figure. Current dry
low-NOx combustion designs do not achieve NOX reductions with oil
fuels, so the cost-effectiveness values shown in this section
apply only to gas-fired applications.
2.3.2.2 SCR Cost Effectiveness. Cost effectiveness for SCR
was calculated based on the use of combustion controls upstream
of the catalyst to reduce NOX emissions to a range of 25 to
42 ppmv at the inlet to the catalyst. This approach was used
because all available SCR cost information is for SCR
applications used in combination with combustion controls and all
but one of the 100+ SCR installations in the United States
operate in combination with combustion controls. For this cost
analysis, a 5-year catalyst life and a 9 ppmv controlled NOX
emission level was used to calculate cost effectiveness for SCR.
2-31
-------
Figure 2-9 presents SCR cost effectiveness. Figure 2-9
shows that, like combustion controls, SCR cost effectiveness is
highest for the smallest turbines and decreases exponentially
with decreasing turbine size.
-------
1
(D
to
I
co
GO
"f?
CD O
t-i W
M rr
(D
Qi (D
l-h
n. Hi
98
B rr
w
w
l-h
O
I
C
HI
w
(D
M
(D
งs
IE
S"1*
S"
Q
LU
8 25i
LU
LL
6 20
z
P "55"
L V ^ J""
tr -a 15-
W 3
C/J O
LJJ
P
o 5-
LLJ
LL
LL
LU
h- 0-
x 42to9ppmv m 25to9ppmv
H
H
ซ
K B
Q
^
K
X X 5
^ ( I fill
(
w 0 20 40 60 80 100 120 140 160
8 TURBINE POWER OUTPUT, MW
(D
o
ft
H-
O
-------
Also, because this cost analysis uses a 9 ppmv controlled NOX
emission level for SCR, NOX reduction efficiencies are higher
where the NOX emission level into the SCR is 42 ppmv than for
applications with a 25 ppmv level. Cost effectiveness
corresponding to an inlet NOX emission level of 42 ppmv, in $/ton
of NOX removed, ranges from a high of $10,800 for a 3.3 MW (4430
hp) turbine to $3,580 for a 161 MW (216,000 hp) turbine. For an
inlet NOX emission level of 25 ppmv, the cost-effectiveness range
shifts higher, from $22,100 for a 3.3 MW (4,430 hp) installation
to $6,980 for an 83 MW (111,000 hp) site.
The range of cost effectiveness for SCR shown in Figure 2-9
applies to gas-fired applications. Cost effectiveness developed
for a limited number of oil-fired installations using capital
costs from gas-fired applications yields cost-effectiveness
values ranging from approximately 70 to 77 percent of those for
gas-fired sites. The lower cost-effectiveness figures for oil-
fired applications result primarily from the greater annual NOX
reductions for oil-fired applications; the gas-fired capital
costs used for these oil-fired applications may understate the
actual capital costs for these removal rates and actual oil-fired
cost-effectiveness figures may be higher.
Combined cost-effectiveness figures, in $/ton of NOX
removed, were calculated for the combination of combustion
controls plus SCR by dividing the sum of the total annual costs
by the sum of the NOX removed for both control techniques. The
controlled NOX emission level for the combination of controls is
9 ppmv. These combined cost-effectiveness figures are presented
in Figure 2-10.
2-34
-------
1
(D
to
GO
<_n
O
e 51
U H-
0
W (D
(D P.
(D O
O O
ft W
H- ft
(D fl)
Hi
O Hi
(U (D
ft O
P) rt
I-1 H-
cr (D
H- 0
O (D
U
h{ U
(D
61 Hi
C O
O I"!
ft
H- O
O O
0 3
U
(T
H-
O
0
O
O
0
(T
Q
UJ
O
ill *KJUU
x 4000-
O
^ 3500J
p 3000-
** 2500-
W 2000-
LJJ
g 1500-
p 1000-
ง 500-
iij o-
ซ
| X Wet injection -< SCR s Dry LowNOx + SCR I
ซ "* K H
^
El CT
) 20 40 60 80 100 120 140 1ฃ
c
30
\JJ
8
TURBINE POWER OUTPUT, MW
-------
For wet injection plus SCR, the combined cost effectiveness
ranges from $4,460 for a 3.3 MW (4,430 hp) application to $988
for a 160 MW (216,000 hp) site. The $645 cost-effectiveness
value for the 83 MW (111,000 hp) turbine is lower than the other
turbine models shown in Figure 2-10 due to
2-36
-------
2-37
-------
the relatively high uncontrolled NOX emission level for this
turbine, which results in relatively high NOX removal rates and a
lower cost effectiveness. For dry low-NOx combustion plus SCR,
combined cost-effectiveness values range from $4,060 to $348 for
this turbine size range.
2.4 REVIEW OF CONTROLLED NOX EMISSION LEVELS AND COSTS
An overview of the performance and costs for available NOX
control techniques is presented in Figure 2-11.
2-38
-------
en 12,500
UJm
^b 10.000
G^ 7 ฃ00
U'T 5.COO
o
ฃ,500
CO
o
CL.
loo c-oo
eno oc-o
100 wo
Ci
งf - !
y E2j 1
ฃs
s?
_'"'" '
ฑ-
iV:
__:':
LJ
O
cfl
O ป
2;
3
O
x
c
o
50
4D
3D
20
id
WtT INJECTION
DRYljOW-
NOX
COMBUSTFON
'SMALL
TUHBWES1
01V LOW ~
NOy
CO.M0USTIGN
',L*.RGE
TURB.4ES)
25-42 ppmv)
COMBUSTION
GONTTIOLS +
SCR
Figure 2-11. Controlled NOX emission levels and associated
capital costs and cost effectiveness for available
NOX control techniques. Natural gas fuel.
2-39
-------
Figure 2-11 shows relative achievable controlled NOX emission
levels, capital costs, and cost effectiveness for gas-fired
turbine applications. Controlled NOX emission levels of 25 to 42
ppmv can be achieved using either wet injection or, where
available, dry low-NOx combustion. Wet injection capital costs
range from $30,000 to $140,000 per MW ($22 to $104 per hp), and
cost effectiveness ranges from $375 to $2,100 per ton of NOX
removed. Dry low-NOx combustion capital costs range from $25,000
to $115,000 per MW ($19 to $86 per hp), and cost effectiveness
ranges from $55 to $1,050 per ton of NOX removed.
A controlled NOX emission level of 9 ppmv requires the
addition of SCR, except for a limited number of large turbine
models for which dry low-NOx combustion designs can achieve this
level. For turbine models above 40 MW (53,600 hp), the capital
costs of dry low-NOx combustion range from $25,000 to $36,000 per
MW ($25 to $27 per hp), and the cost effectiveness ranges from
$55 to $138 per ton of NOX removed. Adding SCR to reduce NOX
emission levels from 42 or 25 ppmv to 9 ppmv adds capital costs
ranging from $53,000 to $190,000 per MW ($40 to $142 per hp) and
yields cost-effectiveness values ranging from $3,500 to
$10,500 per ton of NOX removed. The combination of combustion
controls plus SCR yields combined capital costs ranging from
$78,000 to $330,000 per MW ($58 to $246 per hp) and cost-
effectiveness values ranging from $350 to $4,500 per ton of NOX
removed.
2.5 ENERGY AND ENVIRONMENTAL IMPACTS OF NOX CONTROL TECHNIQUES
The use of the NOX control techniques described in this
document may affect the turbine performance and maintenance
2-40
-------
requirements and may result in increased emissions of carbon
monoxide (CO), hydrocarbons (HC), and NH3. These potential
energy and environmental impacts are discussed in this section.
Water or steam injection affects turbine performance and in
some turbines also affects maintenance requirements. The
increased mass flow through the turbine resulting from water or
steam injection increases the available power output. The
quenching effect in the combustor, however, decreases combustion
efficiency, and consequently the efficiency of the turbine
decreases in most applications. The efficiency reduction is
greater for water than for steam injection, largely because the
heat of vaporization energy cannot be recovered in the turbine.
In applications where the steam can be produced from turbine
exhaust heat that would otherwise be rejected to the atmosphere,
the net gas turbine efficiency is increased with steam injection.
Injection of water or steam into the combustor increases the
maintenance requirements of the hot section of some turbine
models. Water injection generally has a greater impact than
steam on increased turbine maintenance. Water or steam injection
has the potential to increase CO and, to a lesser extent, HC
emissions, especially at water-to-fuel ratios above 0.8.
Turbine manufacturers report no significant performance
impacts for lean premixed combustors. Power output and
efficiency are comparable to conventional designs. No
maintenance impacts are reported, although long-term operating
experience is not available. Impacts on CO emissions vary for
different combustor designs. Limited data from three
manufacturers showed minimal or no increases in CO emissions for
controlled NOX emission levels of 25 to 42 ppmv. For a
controlled NOX level of 9 ppmv, however, CO emissions increased
in from 10 to 25 ppmv in one manufacturer's combustor design.
For SCR, the catalyst reactor increases the back-pressure on
the turbine, which decreases the turbine power output by
approximately 0.5 percent. The addition of the SCR system and
associated controls and monitoring equipment increases plant
maintenance requirements, but it is expected that these
2-41
-------
maintenance requirements are consistent with maintenance
schedules for other plant equipment. There is no impact on CO or
HC emissions from the turbine caused by the SCR system, but
ammonia slip through the catalyst reactor results in NH3
emissions. Ammonia slip levels are typically guaranteed by SCR
vendors at 10 ppmv, and operating experience indicates actual NH3
emissions are at or below this level.
2-42
-------
3.0 STATIONARY GAS TURBINE DESCRIPTION AND INDUSTRY APPLICATIONS
This section describes the physical components and operating
cycles of gas turbines and how turbines are used in industry.
Projected growth in key industries is also presented.
3.1 GENERAL DESCRIPTION OF GAS TURBINES
A gas turbine is an internal combustion engine that operates
with rotary rather than reciprocating motion. A common example
of a gas turbine is the aircraft jet engine. In stationary
applications, the hot combustion gases are directed through one
or more fan-like turbine wheels to generate shaft horsepower
rather than the thrust propulsion generated in an aircraft
engine. Often the heat from the exhaust gases is recovered
through an add-on heat exchanger.
3-43
-------
Figure 3-1
3-44
-------
1
CD
CO
tr
CD
(T
tr
h!
(D
(D
d
co
I
Cn
W
(D
O
(T
H-
O
0
W
O
Hi
(U
(u
u
8-
H-
(D
-------
presents a cutaway view showing the three primary sections of a
gas turbine: the compressor, the combustor, and the turbine.1
The compressor draws in ambient air and compresses it by a
pressure ratio of up to 30 times ambient pressure.2 The
compressed air is then directed to the combustor section, where
fuel is introduced, ignited, and burned. There are three types
of combustors: annular, can-annular, and silo. An annular
combustor is a single continuous chamber roughly the shape of a
doughnut that rings the turbine in a plane perpendicular to the
air flow. The can-annular type uses a similar configuration but
is a series of can-shaped chambers rather than a single
continuous chamber. The silo combustor type is one or more
chambers mounted external to the gas turbine body. These three
combustor types are shown in Figure 3-2
3-46
-------
Annular
Can-annular
Figure 3-2. Types of gas turbine combustors.
3-47
-------
; further discussion of combustors is found in Chapter 5.35
Flame temperatures in the combustor can reach 2000ฐC (3600ฐF).'
The hot combustion gases
3-48
-------
3-49
-------
are then diluted with additional cool air from the compressor
section and directed to the turbine section at temperatures up to
1285ฐC (2350ฐF).6 Energy is recovered in the turbine section in
the form of shaft horsepower, of which typically greater than
50 percent is required to drive the internal compressor section.7
The balance of the recovered shaft energy is available to drive
the external load unit.
The compressor and turbine sections can each be a single
fan-like wheel assembly, or stage, but are usually made up of a
series of stages. In a single-shaft gas turbine, shown in
Figure 3-3
3-4
-------
FUEL
COMPRESSOR
r\~
COMBUSTOR
INLET
AIR
EXHAUST
t
TURBINE
LOAD
Stngle-ahafr. gas turbine.
FUEL
EXHAUST
COMPRESSOR
-J COMBUSTOR
INLET
AIR
HP
TURBINE LP
TURBINE
Figure 3-4, Two-shaft gas turbine.
EXHAUST
LP
COMPRESSOR
TURBINE
POWER
TURilNE
Figure 3-5. Three-shaft gas turbine,
LOAD
3-5
-------
, all compressor and turbine stages are fixed to a single,
continuous shaft and operate at the same speed. A single-shaft
gas turbine is typically used to drive electric generators where
there is little speed variation.
A two-shaft gas turbine is shown in Figure 3-4. In this
design, the turbine section is divided into a high-pressure and
low-pressure arrangement, where the high-pressure turbine is
mechanically tied to the compressor section by one shaft, while
the low-pressure turbine, or power turbine, has its own shaft and
is connected to the external load unit. This configuration
allows the high-pressure turbine/compressor shaft assembly, or
rotor, to operate at or near optimum design speeds, while the
power turbine rotor speed can vary over as wide a range as is
required by most external-load units in mechanical drive
applications (i.e., compressors and pumps).
A third configuration is a three-shaft gas turbine. As
shown in Figure 3-5, the compressor section is divided into a
low-pressure and high-pressure configuration. The low-pressure
compressor stages are mechanically tied to the low-pressure
turbine stages, and the high-pressure compressor stages are
similarly connected to the high-pressure turbine stages in a
concentric shaft arrangement. These low-pressure and high-
pressure rotors operate at optimum design speeds independent of
each other. The power turbine stages are mounted on a third
independent shaft and form the power turbine rotor, the speed of
3-6
-------
which can vary over as wide a range as is necessary for
mechanical drive applications.
Gas turbines can burn a variety of fuels. Most burn natural
gas, waste process gases, or liquid fuels such as distillate oils
(primarily No. 2 fuel oil). Some gas turbines are capable of
burning lower-grade residual or even crude oil with minimal
processing. Coal-derived gases can be burned in some turbines.
The capacity of individual gas turbines ranges from
approximately 0.08 to over 200 megawatts (MW) (107 to
268,000 horsepower [hp]).2 Manufacturers continue to increase
the horsepower of individual gas turbines, and frequently they
are "ganged, " or installed in groups so that the total horsepower
output from one location can meet virtually any installation's
power requirements.
Several characteristics of gas turbines make them attractive
power sources. These characteristics include a high horsepower-
to-size ratio, which allows for efficient space utilization, and
a short time from order placement to on-line operation. Many
suppliers offer the gas turbine, load unit, and all accessories
as a fully assembled package that can be performance tested at
the supplier's facility. This packaging is cost effective and
saves substantial installation time. Other advantages of gas
turbines are:
1. Low vibration;
2. High reliability;
3. No requirement for cooling water;
4. Suitability for remote operation;
5. Lower capital costs than reciprocating engines; and
6. Lower capital costs than boiler/steam turbine-based
electric power generating plants.8
3.2 OPERATING CYCLES
The four basic operating cycles for gas turbines are simple,
regenerative, cogeneration, and combined cycles. Each of these
cycles is described separately below.
3-7
-------
3.2.1 Simple Cvcle
The simple cycle is the most basic operating cycle of a gas
turbine. In a simple cycle application, a gas turbine functions
with only the three primary sections described in Section 3.1, as
depicted in Figure 3-6.
3-1
-------
1
(D
CO
W
H-
(D
o
*
-------
10 Cycle efficiency, defined as a percentage of useful shaft
energy output to fuel energy input, is typically in the 30 to
35 percent range, although one manufacturer states an efficiency
of 40 percent for an engine recently introduced to the market.9
In addition to shaft energy output, 1 to 2 percent of the fuel
input energy can be attributed to mechanical losses; the balance
is exhausted from the turbine in the form of heat.7 Simple cycle
operation is typically used when there is a requirement for shaft
horsepower without recovery of the exhaust heat. This cycle
offers the lowest installed capital cost but also provides the
least efficient use of fuel and therefore the highest operating
cost.
3.2.2 Regenerative Cvcle
The regenerative cycle gas turbine is essentially a simple
cycle gas turbine with an added heat exchanger, called a
regenerator or recuperator, to preheat the combustion air. In
the regenerative cycle, thermal energy from the exhaust gases is
transferred to the compressor discharge air prior to being
introduced into the combustor. A diagram of this cycle is
depicted in Figure 3-7
3-10
-------
co
I
1
CD
U>
fd
CD
IQ
(D
0
(D
h!
(U
(T
H-
-------
.ll Preheating the combustion air reduces the amount of fuel
required to reach design combustor temperatures and therefore
improves the overall cycle efficiency over that of simple cycle
operation. The efficiency gain is directly proportional to the
differential temperature between the exhaust gases and compressor
discharge air. Since the compressor discharge air temperature
increases with an increase in pressure ratio, higher regenerative
cycle efficiency gains are realized from lower compressor
pressure ratios typically found in older gas turbine models.7
Most new or updated gas turbine models with high compressor
pressure ratios render regenerative cycle operation economically
unattractive because the capital cost of the regenerator cannot
be justified by the marginal fuel savings.
3-12
-------
3-13
-------
3.2.3 Coaeneration Cvcle
A gas turbine used in a cogeneration cycle application is
essentially a simple cycle gas turbine with an added exhaust heat
exchanger, called a heat recovery steam generator (HRSG). This
configuration is shown in Figure 3-8
3-14
-------
1
CD
U>
00
O
O
IQ
CD
0
(D
^1
(U
rr
H-
O
O
*
-------
.12 The steam generated by the exhaust heat can be delivered at
a variety of pressure and temperature conditions to meet site
thermal process requirements. Where the exhaust heat is not
sufficient to meet site requirements, a supplementary burner, or
duct burner, can be placed in the exhaust duct upstream of the
HRSG to increase the exhaust heat energy. Adding the HRSG
equipment increases the capital cost, but recovering the exhaust
heat increases the overall cycle efficiency to as high as
75 percent.13
3.2.4 Combined Cvcle
A combined cycle is the terminology commonly used for a gas
turbine/HRSG configuration as applied at an electric utility.
This cycle, shown in Figure 3-9
3-16
-------
Figure 3 - 9,
3-.12
Combined cycle gas turbine application.
3-17
-------
, is used to generate electric power.12 The gas turbine drives
an electric generator, and the steam produced in the HRSG is
delivered to a steam turbine, which also drives an electric
generator. The boiler may be supplementary-fired to increase the
steam production where desired. Cycle efficiencies can exceed
50 percent.
3.3 INDUSTRY APPLICATIONS
Gas turbines are used by industry in both mechanical and
electrical drive applications. Compressors and pumps are most
often the driven load unit in mechanical drive applications, and
electric generators are driven in electrical drive installations.
Few sites have gas/air compression or fluid pumping requirements
that exceed 15 MW (20,100 hp), and for this reason mechanical
drive applications generally use gas turbines in the 0.08- to
15.0-MW (107- to 20,100-hp) range.14 Electric power requirements
range over the entire available range of gas turbines, however,
and all sizes can be found in electrical drive applications, from
0.08 to greater than 200 MW (107 to 268,000 hp).15
The primary applications for gas turbines can be divided
into five broad categories: the oil and gas industry,
3-18
-------
3-19
-------
stand-by/emergency electric power generation, independent
electric power producers, electric utilities, and other
industrial applications.16 Where a facility has a requirement
for mechanical shaft power only, the installation is typically
simple or regenerative cycle. For facilities where either
electric power or mechanical shaft power and steam generation are
required, the installation is often cogeneration or combined
cycle to capitalize on these cycles' higher efficiencies.
3.3.1 Oil and Gas Industry
The bulk of mechanical drive applications are in the oil and
gas industry. Gas turbines in the oil and gas industry are used
primarily to provide shaft horsepower for oil and gas extraction
and transmission equipment, although they are also used in
downstream refinery operations. Most gas turbines found in this
industry are in the 0.08- to 15.0-MW (107- to 20,100-hp) range.
Gas turbines are particularly well suited to this industry,
as they can be fueled by a wide range of gaseous and liquid fuels
often available at the site. Natural gas and distillate oil are
the most common fuels. Many turbines can burn waste process
gases, and some turbines can burn residual oils and even crude
oil. In addition, gas turbines are suitable for remote
installation sites and unattended operation. Most turbines used
in this industry operate continuously, 8,000+ hours per year,
unless the installation is a pipeline transmission application
with seasonal operation.
Competition from reciprocating engines in this industry is
significant. Although gas turbines have a considerable capital
cost advantage, reciprocating engines require less fuel to
produce the same horsepower and consequently have a lower
operating cost.17 Selection of gas turbines vs. reciprocating
engines is generally determined by site-specific criteria such as
installed capital costs, costs for any required emissions control
equipment, fuel costs and availability, annual operating hours,
installation and structural considerations, compatibility with
existing equipment, and operating experience.
3-20
-------
3.3.2 Stand-Bv/Emeraencv Electric Power Generation
Small electric generator sets make up a considerable number
of all gas turbine sales under 3.7 MW (5,000 hp). The majority
of these installations provide backup or emergency power to
critical networks or equipment and use liquid fuel. Telephone
companies are a principal user, and hospitals and small
municipalities also are included in this market. These turbines
operate on an as-needed basis, which typically is between 75 and
200 hours per year.
Gas turbines offer reliable starting, low weight, small
size, low vibration, and relatively low maintenance, which are
important criteria for this application. Gas turbines in this
size range have a relatively high capital cost, however, and
reciprocating engines dominate this market, especially for
applications under 2,000 kW (2,700 hp).18'19
3.3.3 Independent Electrical Power Producers
Large industrial complexes and refining facilities consume
considerable amounts of electricity, and many sites choose to
generate their own power. Gas turbines can be used to drive
electric generators in simple cycle operation, or an HRSG system
may be added to yield a more efficient cogeneration cycle. The
vast majority of cogeneration installations operate in a combined
cycle capacity, using a steam turbine to provide additional
electric power. The Public Utility Regulatory Policies Act
(PURPA) of 1978 encourages independent cogenerators to generate
electric power by requiring electric utilities to (1) purchase
electricity from qualifying producers at a price equal to the
cost the utility can avoid by not having to otherwise supply that
power (avoided cost) and (2) provide backup power to the
cogenerator at reasonable rates. Between 1980 and 1986,
approximately 20,000 MW of gas turbine-produced electrical
generating capacity was certified as qualifying for PURPA
benefits. This installed capacity by private industry power
generators is more than the sum of all utility gas turbine orders
for all types of central power plants during this period.20 The
Department of Energy (DOE) expects an additional 27,000 MW
3-21
-------
capacity to be purchased by private industry in the next
10 years.21
Gas turbines installed in this market range in power from 1
to over 100 MW (1,340 to 134,000 hp) and operate typically
between 4,000 and 8,000 hours per year. While reciprocating
engines compete with the gas turbine at the lower end of this
market (under approximately 7.5 MW [10,000 hp]), the advantages
of lower installed costs, high reliability, and low maintenance
requirements make gas turbines a strong competitor.
3.3.4 Electric Utilities
Electric utilities are the largest user of gas turbines on
an installed horsepower basis. They have traditionally installed
these turbines for use as peaking units to meet the electric
power demand peaks typically imposed by large commercial and
industrial users on a daily or seasonal basis; consequently, gas
turbines in this application operate less than 2,000 hours per
year.22 The power range used by the utility market is 15 MW to
over 150 MW (20,100 to 201,000 hp). Peaking units typically
operate in simple cycle.
The demand for gas turbines from the utility market was flat
through the late 1970's and 1980's as the cost of fuel increased
and the supplies of gas and oil became unpredictable. There are
signs, however, that the utility market is poised to again
purchase considerable generating capacity. The capacity margin,
which is the utility industry's measure of excess generation
capacity, peaked at 30 percent in 1982. By 1990, the capacity
margin had dropped to approximately 20 percent, and, based on
current construction plans, will reach the industry rule-of-thumb
minimum of 15 percent by 1995.21 The utility industry is adding
new capacity and repowering existing older plants, and gas
turbines are expected to play a considerable role.
Many utilities are now installing gas turbine-based combined
cycle installations with provisions for burning coal-derived gas
fuel at some future date. This application is known as
integrated coal gasification combined cycle (IGCC). At least
five power plant projects have been announced, and several more
-------
are being negotiated. Capital costs for these plants are in many
cases higher than comparable natural gas-fueled applications, but
future price increases for natural gas could make IGCC an
attractive option for the future.23
Utility orders for gas turbines have doubled in each of the
last 2 years. The DOE says that electric utilities will need to
add an additional 73,000 MW to capacity to meet demand by the
year 2000, and as Figure 3-10
3-23
-------
US DEPARTMENT OF ENERGY FORECAST -1990 to 2000
73000 MW TOTAL
COAL-FIRED
STEAM
SIMPLE CYCLE
GAS TURBINES
COMBINED CYCLE
GAS TURBINES
Figure 3-10. Total capacity to be purchased by the utility
industry.
3-24
21
-------
shows, DOE expects 36,000 MW of combined cycle and 16,000 MW of
simple cycle gas turbines to be purchased. This renewed interest
in gas turbines is a result of:
1. The introduction of new, larger, more efficient gas
turbines;
2. Lower natural gas prices and proven reserves to meet
current demand levels for more than 100 years;
3. Shorter lead times than those of competing equipment;
and
4. Lower capital costs for gas turbines.21
3-25
-------
Utility capital cost estimates, as shown in Figure 3-11
3-26
-------
3500 /
3000
2500-'
2000
1500
1000-
5004
A,
B
D
A - Repower existing plant using combined cycle gas turbines
B - New plant using combined cycle gas turbines
C - New plant using coal fired boilers
D - New plant using nuclear power
Figure 3-11. Capital costs for electric utility plants.
3-27
-------
, are (1) $500 per KW for repowering existing plants with
combined cycle gas turbines, (2) $800 per KW for new combined
cycle plants, (3) $1,650 per KW for new coal-fired plants, and
(4) $2,850 per KW for new nuclear-powered plants.24
Gas turbines are also an alternative to displace planned or
existing nuclear facilities. A total of 1,020 MW of gas turbine-
generated electric power was recently commissioned in Michigan at
a plant where initial design and construction had begun for a
nuclear plant. Four additional idle nuclear sites are
considering switching to gas turbine-based power production due
to the legal, regulatory, financial, and public obstacles facing
nuclear facilities.24
3.3.5 Other Industrial Applications
Industrial applications for gas turbines include various
types of mechanical drive and air compression equipment. These
applications peaked in the late 1960's and declined through the
1970's.25 With the promulgation of PURPA in 1978 (see
Section 3.3.3), many industrial facilities have found it
3-28
-------
3-29
-------
economically feasible to install a combined cycle gas turbine to
meet power and steam requirements. Review of editions of Gas
Turbine World over the last several years shows that a broad
range of industries (e.g., pulp and paper, chemical, and food
processing) have installed combined cycle gas turbines to meet
their energy requirements.
3.4 REFERENCES FOR CHAPTER 3
1. Letters and attachments from Christie, A. R., General
Electric Company, to Snyder, R. B., MRI. January 1991. Gas
turbine product literature.
2. 1990 Performance Specifications. Gas Turbine World.
11:20-48. 1990.
3. Letter and attachments from Sailer, E. D., General Electric
Company, to Neuffer, W. J., EPA/ISB. August 29, 1991. Gas
turbine product information.
4. Maghon, H., and A. Kreutzer (Siemens Product Group KWU,
Muelheim, Germany) , and H. Termuehlen (Utility Power
Corporation, Bradenton, Florida). The V84 Gas Turbine
Designed for Base-load and Peaking Duty. Presented at the
American Power Conference. Chicago. April 18-20, 1988.
20 pp.
5. Letter and attachments from Sailer, E. D., General Electric
Company, to Snyder, R. B., Midwest Research Institute.
August 24, 1991. Gas turbine product brochures.
6. Letter and attachments from Rosen, V., Siemens AG Power
Generation Group KWU, to Neuffer, W. J., EPA/ISB.
August 30, 1991. Gas turbine product information.
7. Brandt, D. C. GE Turbine Design Philosophy. General
Electric Company. Schenectady, New York. Presented at 33rd
GE Turbine State-of-the-Art Technology Seminar for
Industrial, Cogeneration and Independent Power Turbine
Users. September 1989.
8. Standards Support and Environmental Impact Statement,
Volume I: Proposed Standards of Performance for Stationary
Gas Turbines. U. S. Environmental Protection Agency.
Research Triangle Park, NC. Publication
No. EPA-450/2P77-017a. September 1977. pp. 3-1, 3-2.
9. General Electric Marine and Industrial Engineers. LM6000
Gas Turbine. AG-3248. Cincinnati, Ohio. June 1990.
10. Reference 8, p. 3-37.
3-30
-------
11. Reference 8, p. 3-43.
12. Reference 8, p. 3-44.
13. Kovick, J. M. Cogeneration Application Considerations.
General Electric Company. Schenectady, New York. Presented
at 33rd GE Turbine State-of-the-Art Technology Seminar for
Industrial, Cogeneration and Independent Power Turbine
Users. September 1989.
14. Reference 8, p. 3-23.
15. Reference 8, pp. 3-10, 3-11, 3-12.
16. Reference 8, p. 3-18.
17. Reference 8, p. 3-24.
18. Reference 8, p. 3-26.
19. Letter and attachments from Swingle, R. L., Solar Turbines,
Incorporated, to Neuffer, W. J., EPA:ISB. August 20, 1991.
Gas turbine product information.
20. Williams, R., and E. Larson (Princeton University).
Expanding Roles For Gas Turbines In Power Generation.
Prepared for Vattenfall Electricity with the support of the
Office of Energy of the U.S. Agency for International
Development. December 1985. p. 9.
21. Smock, R. W. Need Seen for New Utility Capacity in the
'90's. Power Engineering. 21:29-31. April 1990.
22. Reference 4, p. 3-19.
23. Smock, R. W. Coalgas-fired Combined Cycle Projects Multiply.
Power Engineering. 103:32-34. February, 1991.
24. Repowering Old Plants Gains Favor. Power Engineering.
21:25-27. May 1990.
25. Reference 4, p. 3-29.
3-31
-------
4.0 CHARACTERIZATION OF NOX EMISSIONS
This section presents the principles of NOX formation, the
types of NOX emitted (i.e., thermal NOX, prompt NOX, and fuel
NOX) , and how they are generated in a gas turbine combustion
process. Estimated NOX emission factors for gas turbines and the
bases for the estimates are also presented.
4.1 THE FORMATION OF NOX
Nitrogen oxides form in the gas turbine combustion process
as a result of the dissociation of nitrogen (N2) and oxygen (02)
into N and 0, respectively. Reactions following this
dissociation result in seven known oxides of nitrogen: NO, N02,
N03, N20, N203, N204, and N205. Of these, nitric oxide (NO) and
nitrogen dioxide (N02) are formed in sufficient quantities to be
significant in atmospheric pollution.1 In this document, "NOX"
refers to either or both of these gaseous oxides of nitrogen.
Virtually all NOX emissions originate as NO. This NO is
further oxidized in the exhaust system or later in the atmosphere
to form the more stable N02 molecule.2 There are two mechanisms
by which NOX is formed in turbine combustors: (1) the oxidation
of atmospheric nitrogen found in the combustion air (thermal NOX
and prompt NOX) and (2) the conversion of nitrogen chemically
bound in the fuel (fuel NOX) . These mechanisms are discussed
below.
4.1.1 Formation of Thermal and Prompt NO..
Thermal NOX is formed by a series of chemical reactions in
which oxygen and nitrogen present in the combustion air
dissociate and subsequently react to form oxides of nitrogen.
4-1
-------
The major contributing chemical reactions are known as the
Zeldovich mechanism and take place in the high temperature area
of the gas turbine combustor.3 Simply stated, the Zeldovich
mechanism postulates that thermal NOX formation increases
exponentially with increases in temperature and linearly with
increases in residence time.4
Flame temperature is dependent upon the equivalence ratio,
which is the ratio of fuel burned in a flame to the amount of
fuel that consumes all of the available oxygen.5 An equivalence
ratio of 1.0 corresponds to the stoichiometric ratio and is the
point at which a flame burns at its highest theoretical
temperature.5 Figure 4-1
4-2
-------
4SOO
4000-
3500-
: 3000-
gf 2500-
2000-
1500-
1000-
500-
I
No, 2 Distillate Oil Fual
0.5
FURUEftM
1.0
Equivalence Ratio
1,5
RJCLfปOH
Figure 4-1. Influence of equivalence ratio on flame
temperature.4
4-3
-------
shows the flame temperature and equivalence ratio relationship
for combustion using No. 2 distillate fuel oil (DF-2).4
The series of chemical reactions that form thermal NOX
according to the Zeldovich mechanism are presented below.3
1. 02 ^ 20;
2 . N2 ^ 2N;
3. N + 0 ^ NO;
4. N + 02 ^ NO + 0; and
5. 0 + N2 ^ NO + N.
This series of equations applies to a fuel-lean combustion
process. Combustion is said to be fuel-lean when there is excess
oxygen available (equivalence ratio <1.0). Conversely,
combustion is fuel-rich if insufficient oxygen is present to burn
all of the available fuel (equivalence ratio >1.0). Additional
equations have been developed that apply to fuel-rich combustion.
These equations are an expansion of the above series to add an
intermediate hydroxide molecule (OH):3
4-4
-------
4-5
-------
6. N + OH ^ NO + H,
and further to include an intermediate product, hydrogen cyanide
(HCN), in the formation process:3
7 . N2 + CH ^ HCN + N and
8. N + OH ^ H + NO.
The overall equivalence ratio for gases exiting the gas
turbine combustor is less than l.O.4 Fuel-rich areas do exist in
the overall fuel-lean environment, however, due to
less-than-ideal fuel/air mixing prior to combustion. This being
the case, the above equations for both fuel-lean and fuel-rich
combustion apply for thermal NOX formation in gas turbines.
Prompt NOX is formed in the proximity of the flame front as
intermediate combustion products such as HCN, N, and NH are
oxidized to form NOX as shown in the following equations:
1. CH + N2 ^ HCN + N;
2. CH2 + N2 ^ HCN + NH; and
3 . HCN, N, NH + Ox ^ NO +. . . .6
Prompt NOX is formed in both fuel-rich flame zones and
fuel-lean premixed combustion zones. The contribution of prompt
NOX to overall NOX emissions is relatively small in conventional
near-stoichiometric combustors, but this contribution increases
with decreases in the equivalence ratio (fuel-lean mixtures).
For this reason, prompt NOX becomes an important consideration
for the low-NOx combustor designs described in Chapter 5 and
establishes a minimum NOX level attainable in lean mixtures.7
4.1.2 Formation of Fuel NO.,
Fuel NOX (also known as organic NOX) is formed when fuels
containing nitrogen are burned. Molecular nitrogen, present as
4-6
-------
N2 in some natural gas, does not contribute significantly to fuel
NOX formation.8 However, nitrogen compounds are present in coal
and petroleum fuels as pyridine-like (C5H5N) structures that tend
to concentrate in the heavy resin and asphalt fractions upon
distillation. Some low-British thermal unit (Btu) synthetic
fuels contain nitrogen in the form of ammonia (NH3) , and other
low-Btu fuels such as sewage and process waste-stream gases also
contain nitrogen. When these fuels are burned, the nitrogen
bonds break and some of the resulting free nitrogen oxidizes to
form NOX.9 With excess air, the degree of fuel NOX formation is
primarily a function of the nitrogen content in the fuel. The
fraction of fuel-bound nitrogen (FBN) converted to fuel NOX
decreases with increasing nitrogen content, although the absolute
magnitude of fuel NOX increases. For example, a fuel with
0.01 percent nitrogen may have 100 percent of its FBN converted
to fuel NOX, whereas a fuel with a 1.0 percent FBN may have only
a 40 percent fuel NOX conversion rate. The low-percentage FBN
fuel has a 100 percent conversion rate, but its overall NOX
emission level would be lower than that of the high-percentage
FBN fuel with a 40 percent conversion rate.10
Nitrogen content varies from 0.1 to 0.5 percent in most
residual oils and from 0.5 to 2 percent for most U.S. coals.11
Traditionally, most light distillate oils have had less than
0.015 percent nitrogen content by weight. However, today many
distillate oils are produced from poorer-quality crudes,
especially in the northeastern United States, and these
distillate oils may contain percentages of nitrogen exceeding the
0.015 threshold; this higher nitrogen content can increase fuel
NOX formation.4 At least one gas turbine installation burning
coal-derived fuel is in commercial operation in the United
States.12
Most gas turbines that operate in a continuous duty cycle
are fueled by natural gas that typically contains little or no
FBN. As a result, when compared to thermal NOX, fuel NOX is not
4-7
-------
currently a major contributor to overall NOX emissions from
stationary gas turbines.
4.2 UNCONTROLLED NOX EMISSIONS
The NOX emissions from gas turbines are generated entirely
in the combustor section and are released into the atmosphere via
the stack. In the case of simple and regenerative cycle
operation, the combustor is the only source of NOX emissions. In
cogeneration and combined cycle applications, a duct burner may
be placed in the exhaust ducting between the gas turbine and the
heat recovery steam generator (HRSG); this burner also generates
NOX emissions. (Gas turbine operating cycles are discussed in
Section 3.2.) The amount of NOX formed in the combustion zone is
"frozen" at this level regardless of any temperature reductions
that occur at the downstream end of the combustor and is released
to the atmosphere at this level.1
4.2.1 Parameters Influencing Uncontrolled NO., Emissions
The level of NOX formation in a gas turbine, and hence the
NOX emissions, is unique (by design factors) to each gas turbine
model and operating mode. The primary factors that determine the
amount of NOX generated are the combustor design, the types of
fuel being burned, ambient conditions, operating cycles, and the
power output level as a percentage of the rated full power output
of the turbine. These factors are discussed below.
4.2.1.1 Combustor Design. The design of the combustor is
the most important factor influencing the formation of NOX.
Design considerations are presented here and discussed further in
Chapter 5.
Thermal NOX formation, as discussed in Section 4.1.1, is
influenced primarily by flame temperature and residence time.
Design parameters controlling equivalence ratios and the
introduction of cooling air into the combustor strongly influence
thermal NOX formation. The extent of fuel/air mixing prior to
combustion also affects NOX formation. Simultaneous mixing and
combustion results in localized fuel-rich zones that yield high
flame temperatures in which substantial thermal NOX production
4-f
-------
takes place.13 The dependence of thermal NOX formation on flame
temperature and equivalence ratio is shown in Figure 4-2
4-9
-------
4SQQ-
4000-
3SOO-
2500-
2000-
1SQQ-
1000-
500-
tH-r"
O.S
10
RJIL LEAN
Equivalence Ratio
Futi
400
CD
-300
.5
-200 8
-100
FL&FftCH
Figure 4-2. Thermal NOX production as a function of flame
temperature and equivalence ratio.4
4-10
-------
for DF-2.4 Conversely, prompt NOX is largely insensitive to
changes in temperature and pressure.7
Fuel NOX formation, as discussed in Section 4.1.2, is formed
when FBN is released during combustion and oxidizes to form NOX.
Design parameters that control equivalence ratio and residence
time influence fuel NOX formation.14
4.2.1.2 Type of Fuel. The level of NOX emissions varies
for different fuels. In the case of thermal NOX, this level
increases with flame temperature. For gaseous fuels, the
constituents in the gas can significantly affect NOX emissions
levels. Gaseous fuel mixtures containing hydrocarbons with
molecular weights higher than that of methane (e.g., ethane,
propane, and butane) burn at higher flame temperatures and as a
result can increase NOX emissions greater than 50 percent over
NOX levels for methane gas fuel. Refinery gases and some
unprocessed field gases contain significant levels of these
higher molecular weight hydrocarbons. Conversely, gas fuels that
contain significant inert gases, such as C02, generally produce
lower NOX emissions. These inert gases serve to absorb heat
during combustion, thereby lowering flame temperatures and
reducing NOX emissions. Examples of this type of gas fuel are
air-blown gasifier fuels and some field gases.15 Combustion of
hydrogen also results in high flame temperatures, and gases with
significant hydrogen content produce relatively high NOX
emissions. Refinery gases can have hydrogen contents exceeding
50 percent.16
4-11
-------
As is shown in Figure 4-3
4-12
-------
250
200
CO
g
to
i 100H
UJ
X
o
50
DF-2
NATURAL
GAS
800 1000 1200 1400 1600 1800 2000
TURBINE FIRING TEMPERATURE (DEG. F)
2200
Figure 4-3. Influence of firing temperature on thermal NO
formation.
17
4-13
-------
, DF-2 burns at a flame temperature that is approximately 75ฐC
(100ฐF) higher than that of natural gas, and as a result, NOX
emissions are higher when burning DF-2 than they are when burning
natural gas.17 Low-Btu fuels such as coal gas burn with lower
flame temperatures, which result in
4-14
-------
4-15
-------
substantially lower thermal NOX emissions than natural gas or
DF-2.18 For fuels containing FBN, the fuel NOX production
increases with increasing levels of FBN.
4.2.1.3 Ambient Conditions. Ambient conditions that affect
NOX formation are humidity, temperature, and pressure. Of these
ambient conditions, humidity has the greatest effect on NOX
formation.19 The energy required to heat the airborne water
vapor has a quenching effect on combustion temperatures, which
reduces thermal NOX formation. At low humidity levels, NOX
emissions increase with increases in ambient temperature. At
high humidity levels, the effect of changes in ambient
temperature on NOX formation varies. At high humidity levels and
low ambient temperatures, NOX emissions increase with increasing
temperature. Conversely, at high humidity levels and ambient
temperatures above 10ฐC (50ฐF), NOX emissions decrease with
increasing temperature.
4-16
-------
60-
0 % FWซflw HunWtty
20-
100 % Rttattv* Humidity
20 40 60 80 100
Ambient Temperature, tieg. F
120
Figure 4-4.
Influence of relative humidity and ambient
temperature on NOX formation.1
4-17
-------
This effect of humidity and temperature on NOX formation is shown
in Figure 4-4. A rise in ambient pressure results in higher
pressure and temperature levels entering the combustor and so Nox
production levels increase with increases in ambient pressure.19
The influence of ambient conditions on measured NOX emission
levels can be corrected using the following equation:20
NOX = (NOXO) (Pr/P0) ฐ-5e19(Ho"ฐ-00633) (288ฐK/Ta)
where:
NOX = emission rate of NOX at 15 percent 02 and International
Standards Organization (ISO) ambient conditions, volume
percent;
NOXO = observed NOX concentration, parts per million by volume
(ppmv) referenced to 15 percent 02;
Pr = reference compressor inlet absolute pressure at
101.3 kilopascals ambient pressure, millimeters mercury
(mm Hg) ;
P0 = observed compressor inlet absolute pressure at test, mm
Hg;
4-18
-------
4-19
-------
H0 = observed humidity of ambient air, g H20/g air;
e = transcendental constant, 2.718; and
Ta = ambient temperature, K.
At least two manufacturers state that this equation does not
accurately correct NOX emissions for their turbine models.8'12
It is expected that these turbine manufacturers could provide
corrections to this equation that would more accurately correct
NOX emissions for the effects of ambient conditions based on test
data for their turbine models.
4.2.1.4 Operating Cycles. Emissions from identical
turbines used in simple and cogeneration cycles have similar NOX
emissions levels, provided no duct burner is used in heat
recovery applications. The NOX emissions are similar because, as
stated in Section 4.2, NOX is formed only in the turbine
combustor and remains at this level regardless of downstream
temperature reductions. A turbine operated in a regenerative
cycle produces higher NOX levels, however, due to increased
combustor inlet temperatures present in regenerative cycle
applications .21
4.2.1.5 Power Output Level. The power output level of a
gas turbine is directly related to the firing temperature, which
is directly related to flame temperature. Each gas turbine has a
base-rated power level and corresponding NOX level. At power
outputs below this base-rated level, the flame temperature is
lower, so NOX emissions are lower. Conversely, at peak power
outputs above the base rating, NOX emissions are higher due to
higher flame temperature. The NOX emissions for a range of
firing temperatures are shown in Figure 4-3 for one
manufacturer's gas turbine.17
4.2.2 NO.. Emissions From Duct Burners
In some cogeneration and combined cycle applications, the
exhaust heat from the gas turbine is not sufficient to produce
the desired quantity of steam from the HRSG, and a supplemental
burner, or duct burner, is placed in the exhaust duct between the
gas turbine and HRSG to increase temperatures to sufficient
4-20
-------
levels. In addition to providing additional steam capacity, this
burner also increases the overall system efficiency since
essentially all energy added by the duct burner can be recovered
in the HRSG.22
The level of NOX produced by a duct burner is approximately
0.1 pound per million Btu (Ib/MMBtu) of fuel burned. The ppmv
level depends upon the flowrate of gas turbine exhaust gases in
which the duct burner is operating and thus varies with the size
of the turbine.23
Typical NOX production levels added by a duct burner
operating on natural gas fuel are:23
Gas turbine
megawatts
output,
(MW)
3 to 50
50+
Duct burner
referenced to
10 to
5 to
NOX
15
, ppmv,
percent
0,
30
10
4.3 UNCONTROLLED EMISSION FACTORS
4-21
-------
4-22
-------
TABLE 4-1. UNCONTROLLED NO,, EMISSIONS FACTORS FOR GAS
TURBINES AND DUCT BURNERS
8,12,15,24-29
Manufacturer
Solar
GM/Allison
General Electric
Asea Brown Boveri
Westinghouse
Siemens
Duct burners
Model No.
Saturn
Centaur
Centaur "H"
Taurus
Mars T 12000
Mars T 14000
501-KB5
570-KA
571-KA
LM1600
LM2500
LM5000
LM6000
MS5001P
MS6001B
MS7001EA
MS7001F
MS9001EA
MS9001F
GTS
GT10
GT11N
GT35
W261B11/12
W501D5
V84.2
V94.2
V64.3
V84.3
V94.3
All
Output,
MW
1.1
3.3
4.0
4.5
8.8
10.0
4.0
4.9
5.9
12.8
21.8
33.1
41.5
26.3
38.3
83.5
123
150
212
47.4
22.6
81.6
16.9
52.3
119
105
153
61.5
141
203
NAC
NOX emissions, ppmv, dry
and corrected to 15% 0,
Natural gas
99
130
105
114
178
199
155
101
101
144
174
185
220
142
148
154
179
176
176
430
150
390
300
220
190
212
212
380
380
380
<30
Distillate
oil No. 2
150
179
160
168
267
NA"
231
182
182
237
345
364
417
211
267
228
277
235
272
680
200
560
360
355
250
360
360
530
530
530
NA"
NOX emissions factor,
Ib NOyMMBtu"
Natural gas
0.397
0.521
0.421
0.457
0.714
0.798
0.622
0.405
0.405
0.577
0.698
0.742
0.882
0.569
0.593
0.618
0.718
0.706
0.706
1.72
0.601
1.56
1.20
0.882
0.762
0.850
0.850
1.52
1.52
1.52
<0.100d
Distillate
oil No. 2
0.551
0.658
0.588
0.618
0.981
NAb
0.849
0.669
0.669
0.871
1.27
1.34
1.53
0.776
0.981
0.838
1.02
0.864
1.00
2.50
0.735
2.06
1.32
1.31
0.919
1.32
1.32
1.95
1.95
1.95
NA"
"Based on emission levels provided by gas turbine manufacturers, corresponding to rated load at ISO conditions.
NOX emissions calculations are shown in Appendix A.
bNot available.
ฐNot applicable.
References 16 and 22.
4-23
-------
Uncontrolled emission factors are presented in Table 4-1.
These factors are based on uncontrolled emission levels provided
by manufacturers in ppmv, dry, and corrected to 15 percent 02,
corresponding to 100 percent output load and International
Standards Organization (ISO) conditions of 15ฐC (59ฐF) and 1
atmosphere (14.7 psia). Sample calculations are given in
Appendix A. The uncontrolled emissions factors range from 0.397
to 1.72 Ib/MMBtu (99 to 430 ppmv) for natural gas and 0.551 to
2.50 Ib/MMBtu (150 to 680 ppmv) for DF-2.
4-24
-------
4-25
-------
4.4 REFERENCES FOR CHAPTER 4
1. Control Techniques for Nitrogen Oxides Emissions From
Stationary Sources - Revised Second Edition. U. S.
Environmental Protection Agency. Research Triangle Park,
NC. Publication No. EPA-450/3-83-002. January 1983.
p. 2-1.
2. Stationary Internal Combustion Engines. Standards Support
and Environmental Impact Statement, Volume I: Proposed
Standards of Performance. U. S. Environmental Protection
Agency. Research Triangle Park, NC. Publication
No. EPA-450/2-78-125a. July 1979. p. 4-3.
3. Standards Support and Environmental Impact Statement,
Volume I: Proposed Standards of Performance for Stationary
Gas Turbines. U. S. Environmental Protection Agency.
Research Triangle Park, NC. Publication
No. EPA-450/277-011a. September 1977. pp. 3-71, 3-72.
4. Schorr, M. NOX Control for Gas turbines: Regulations and
Technology. General Electric Company. Schenectady, NY.
For presentation at the Council of Industrial Boiler Owners
NOX Control IV Conference. February 11-12, 1991. pp. 3-5.
5. Davis, L. Dry Low NOX Combustion for GE Heavy-Duty Gas
Turbines. General Electric Company. Schenectady, NY.
Presented at 33rd GE Turbine State-of-the-Art Technology
seminar for Industrial, Cogeneration and Independent Power
Turbine Users. September 1989.
6. Malte, P.C. Perspectives on NOX Formation and Control For
Gas Turbine Engines. University of Washington (Seattle, WA)
and Energy International (Bellevue, WA). Presented at
General Electric Research Center. Schenectady, NY.
October 10, 1988. 46 pp.
7. Semerjian, H., and A. Vranos. NOX Formation in Premixed
Turbulent Flames. Pratt and Whitney Aircraft and United
Technologies Research Center, United Technologies
Corporation. East Hartford, CT. 1976. 10 pp.
8. Letter and attachments from Rosen, V., Siemens AG Power
Generation Group KWU, to Neuffer, W. J., EPA/ISB.
August 30, 1991. Review of the draft gas turbine ACT
document.
9. Wilkes, C. Control of NOX Emissions From Industrial Gas
Turbine Combustion Systems. General Motors Corporation.
Indianapolis, IN. For presentation at the 82nd annual
meeting and exhibition - Anaheim, CA. June 25 to 30, 1989.
p. 5.
10. Reference 2, p. 4-4.
4-26
-------
11. Reference 1, p. 3-5.
12. Letter and attachments from Antes, R.J., Westinghouse
Electric Corporation, to Neuffer, W.J., EPA/ISB.
September 11, 1991. Gas turbine information.
13. Smith, K., L. Angello, and F. Kurzynske. Design and Testing
of an Ultra-Low NOX Gas Turbine Combustor. The American
Society of Mechanical Engineers. New York. 86-GT-263.
1986. p. 2.
14. Cutrone, M., M. Hilt, A. Goyal, E. Ekstedt, and
J. Notardonato. Evaluation of Advanced Combustors for Dry
NOX Suppression with Nitrogen Bearing Fuels in Utility and
Industrial Gas Turbines. Journal of Engineering for Power.
104.: 431. April 1982.
15. Letter and attachments from Sailer, E.D., General Electric
Marine and Industrial Engines, to Neuffer, W.J., EPA/ISB.
August 29, 1991. Review of the draft gas turbine ACT
document.
16. Letter and attachments from Etter, R.G., Koch Industries,
Inc., to Neuffer, W.J., EPA/ISB. October 17, 1991. Review
of the draft gas turbine ACT document.
17. U. S. Environmental Protection Agency. Background
Information Document, Review of 1979 Gas Turbine New Source
Performance Standard. Research Triangle Park, NC. Prepared
by Radian Corporation under Contract No. 68-02-3816. 1985.
p. 3-36.
18. Reference 17, p. 3-93.
19. Reference 17, pp. 3-39 through 3-41.
20. National Archives and Records Administration. Code of
Federal Regulations. 40 CFR 60.335. Washington, D.C.
Office of the Federal Register. July 1989.
21. Reference 3, pp. 3-105, 3-106.
22. Backlund, J., and A. Spoormaker. Experience With NOX
Formation/Reduction Caused by Supplementary Firing of
Natural Gas in Gas Turbine Exhaust Streams. The American
Society of Mechanical Engineers. New York. 85-JPGC-G7-18.
1985. p. 2.
23. Telecon. Fiorenza, R., Coen Company, with Snyder, R.,
Midwest Research Institute (MRI). March 8, 1991. NOX
emissions levels for duct burners operating in gas turbine
exhaust streams.
4-27
-------
24. Letters and attachments from Leonard, G.L., General Electric
Company, to Snyder, R.B., MRI. February 1991. Response to
gas turbine questionnaire.
25. Letters and attachments from Schorr, M., General Electric
Company, to Snyder, R.B., MRI. March, April 1991. Response
to gas turbine questionnaire.
26. Letters and attachments from Gurmani, A., Asea Brown Boveri,
to Snyder, R.B., MRI. February 1991. Response to gas
turbine questionnaire.
27. Letters and attachments from Swingle, R., Solar Turbines
Incorporated, to Snyder, R.B., MRI. February 1991.
Response to gas turbine questionnaire.
28. Letters and attachments from Kimsey, D.L., Allison Gas
Turbine Division of General Motors, to Snyder, R.B., MRI.
February 1991. Response to gas turbine questionnaire.
29. Letter and attachment from vanderLinden, S., Asea Brown
Boveri, to Neuffer, W.J., EPA/ISB. September 16, 1991.
Gas turbine product information.
4-28
-------
5.0 NOX CONTROL TECHNIQUES
Nationwide NOX emission limits have been established for
stationary gas turbines in the new source performance standards
(NSPS) promulgated in 1979.l This standard, summarized in
Table 5-1
5-29
-------
TABLE 5-1. NOX EMISSION LIMITS AS ESTABLISHED BY THE NEW
SOURCE PERFORMANCE STANDARDS FOR GAS TURBINES1
Fuel input
MMBtu/hr
<10
10-100
>100
<100
All
Size, MW
lc
1-10C
10+c
<30C
>30C
10C
All
Application (s)
All
All
Utility13
Nonutility
Nonutility
Regenerative cycle
e
NOX limit,
ppmv at 15%
09, dryab
None
150
75
150
None
None
None
aBased on thermal efficiency of 25 percent. This limit may be
increased for higher efficiencies by multiplying the limit in
the table by 14.4/actual heat rate, in kJ/watt-hr.
bA fuel-bound nitrogen allowance may be added to the limits
listed in the table according to the table listed below:
Fuel-bound nitrogen (N),
percent bv weight
N < 0.015
0.015 < N < 0.1
0.1 < N <. 0.25
N > 0.25
Allowable increase, ppmv
0
400 x N
40 + [6.7 x (N - 0.1)]
50
GBased on gas turbine heat rate of 10,000 Btu/kW-hr.
dAn installation is considered a utility if more than 1/3 of its
potential electrical output is sold.
""Emergency/stand-by, military (except garrison facilities) ,
military training, research and development, firefighting, and
emergency fuel operation applications are exempt from NOX
emission limits.
5-30
-------
, effectively sets a limit for new, modified, or reconstructed
gas turbines greater than 10.7 gigajoules per hour (approximately
3,800 horsepower [hp]) of 75 or 150 parts per million by volume
(ppmv), corrected to 15 percent oxygen (02) on a dry basis,
depending upon the size and application of the turbine. State
and regional regulatory agencies may set more restrictive limits,
and two organizations have established limits as low as 9 ppmv:
the South Coast Air Quality Management District (SCAQMD) has
defined limits as listed in Table 5-2
5-31
-------
TABLE 5-2. NOX COMPLIANCE LIMITS AS ESTABLISHED BY THE
SOUTH COAST AIR QUALITY MANAGEMENT DISTRICT (SCAQMD)
FOR EXISTING TURBINES. RULE 1134. ADOPTED AUGUST 1989.
a,2
Unit size, megawatt rating (MW)
0.3 to <2.9 MW
2.9 to <10.0 MW
2.9 to <10.0 MW
No SCR
10.0 MW and over
10.0 MW and over
No SCR
60 MW and over
Combined cycle
No SCR
60 MW and over
Combined cycle
NOX limit, ppmv, 15%
09 dryb
25
9
15
9
12
15
9
Compliance limit = Reference limit X EFF/25 percent
where :
EFF = amp^p^i^tW^ttip^w^^?
or
EFFC = (Manufacturer's rated efficiency at LHV) x AA4r
aThe NOX reference limits to be effective by December 31,
bAveraged over 15 consecutive minutes.
CEFF =
1995.
the demonstrated percent efficiency of the gas turbine
only as calculated without consideration of any
down-stream energy recovery from the actual heat rate
(Btu/kW-hr), or 1.34 (Btu/hp-hr); corrected to the higher
heating value (HHV) of the fuel and ISO conditions, as
measured at peak load for that facility; or the
manufacturer's continuous rated percent efficiency
(manufacturer's rated efficiency) of the gas turbine
after correction from lower heating value (LHV) to the
HHV of the fuel, whichever efficiency is higher. The
value of EFF shall not be less than 25 percent. Gas
turbines with lower efficiencies will be assigned a
25 percent efficiency for this calculation.
5-32
-------
; and the Northeast States for Coordinated Air Use Management
(NESCAUM) has recommended limits as listed in Table 5-3.
5-33
-------
5-34
-------
TABLE 5-3. NOX EMISSION LIMITS RECOMMENDED BY THE NORTHEAST
STATES FOR COORDINATED AIR USE MANAGEMENT (NESCAUM)
NEW TURBINES3
Fuel input,
MMBtu/hr
1-100
>100
Size, MWa
1-10
10 +
Fuel type
Gas
Oil
Gas
Oil
Gas/oil back-up
NOX limit, pprnV3
42
65
9C
9C
gc/18c d
aBased on gas turbine heat rate of 10,000 Btu/kW-hr.
bDry basis, corrected to 15 percent oxygen.
GBased on use of selective catalytic reduction (SCR). Limits for operation
without SCR, where permitted, should be the turbine manufacturer's lowest
guaranteed N0x limit.
dBased on the use of SCR and a fuel-bound nitrogen content of 600 ppm or less.
EXISTING TURBINES"
Operating
cycle
Simple
Combined
Fuel
Gas, no oil back-up
Oil
Gas, with oil back-up
Gas, no oil back-up
Oil
Gas, with oil back-up
NOX emission limit,
ppmv, 15 percent 0,
55
75
55 (Gas fuel)
75 (Oil fuel)
42
65
42 (Gas fuel)
65 (Oil fuel)
Note: Applies to existing turbines rated at 25 MMBtu/hr or above
(maximum heat input rate).
5-35
-------
This chapter discusses the control techniques that are
available to reduce NOX emissions for stationary turbines, the
use of duct burners, the use of alternate fuels to lower NOX
emissions, and the applicability of NOX control techniques to
offshore applications. Each control technique is structured into
categories to discuss the process description, applicability,
factors that affect performance, and achievable controlled NOX
emission levels. Where information for a technique is limited,
one or more categories may be combined. Section 5.1 describes
wet controls, including water and steam injection. Section 5.2
describes combustion controls, including lean and staged
combustion. Selective catalytic reduction (SCR), a
postcombustion technique, is described in Section 5.3, and the
combination of SCR with other control techniques is described in
5-36
-------
5-37
-------
5-38
-------
Section 5.4. Emissions from duct burners and their impact on
total NOX emissions are described in Section 5.5. Section 5.6
describes NOX emission impacts when using alternate fuels. Two
control techniques that show potential for future use, selective
noncatalytic reduction (SNCR) and catalytic combustion, are
described in Sections 5.7 and 5.8, respectively. Control
technologies for offshore oil platforms are described in
Section 5.9. Finally, references for Chapter 5 are found in
Section 5.10.
5.1 WET CONTROLS
The injection of either water or steam directly into the
combustor lowers the flame temperature and thereby reduces
thermal NOX formation. This control technique is available from
all gas turbine manufacturers contacted for this study.5"11
The process description, applicability, factors affecting
performance, emissions data and manufacturers' guarantees,
impacts on other emissions, and gas turbine performance and
maintenance impacts are discussed in this section.
5.1.1 Process Description
Injecting water into the flame area of a turbine combustor
provides a heat sink that lowers the flame temperature and
thereby reduces thermal NOX formation. Injection rates for both
water and steam are usually described by a water-to-fuel ratio
(WFR) and are usually given on a weight basis (e.g., Ib water to
Ib fuel).
A water injection system consists of a water treatment
system, pump(s), water metering valves and instrumentation,
turbine-mounted injection nozzles, and the necessary
interconnecting piping. Water purity is essential to prevent or
mitigate erosion and/or the formation of deposits in the hot
section of the turbine; Table 5-4
5-39
-------
TABLE 5-4. WATER QUALITY SPECIFICATIONS OF SELECTED GAS TURBINE
MANUFACTURERS FOR WATER INJECTION SYSTEMS 11"18
Turbine Manufacturer
Element
Total solids, ppm (dissolved
and nondissolved)
Total alkali metals, ppm
Calcium, ppm
Sulfates, ppm
Silica, ppm
Silicon, ppm
Sulfur, ppm
Chlorides, ppm
Iron and copper, ppm
Sodium and potassium, ppm
Particle size, microns
Total hardness, ppm
Oxygen5
Acidity, pH
A
5
0.1
5
..
0.02
..
0.1
..
..
10
..
..
7.0-8.5
B
5
0.5 (HD)
0.1 (AD)d
..
..
..
..
..
..
..
..
..
..
6.5-7.5
C
1
0.1
..
..
0.02
..
..
..
..
10
..
..
7.0-8.5
D
a
-
..
..
..
18.0
..
6.0
0.1
..
..
..
..
7.5-8.0
E
0.1 gram/gallon
0.5
..
..
..
..
..
..
..
5
..
..
-
F
15
0.15
..
..
0.1
..
1.0
1.0
..
..
..
0.2
..
6.5-7.5
G
5
O.05
<1.0
..
<0.02
..
..
..
..
..
..
..
6.5-7.0
H
8
-
..
0.5
0.1
..
..
0.5
..
0.1
20
..
..
6.0-8.0
I
J^
o
"Determined by local regulations for particulates exhausted from combustion process.
bHD - heavy-duty turbine.
'Including vanadium and lead.
dAD - aeroderivative turbine.
e90 percent of 0.1 gram particles shall be less than 5 microns.
-------
summarizes the water quality specifications for eight gas
turbine manufacturers.
In a steam injection system, steam replaces water as the
injected fluid. The injection system is similar to that for
water injection, but the pump is replaced by a steam-producing
boiler. This boiler is usually a heat recovery steam generator
5-41
-------
(HRSG) that recovers the gas turbine exhaust heat and generates
steam. The balance of the steam system is similar to the water
injection system. The water treatment required for boiler feed
water to the HRSG yields a steam quality that is suitable for
injection into the turbine. The additional steam requirement for
NOX control, however, may require that additional capacity be
added to the boiler feed water treatment system.
Another technique that is commercially available for
oil-fired aeroderivative and industrial turbines uses a
water-in-oil emulsion to reduce NOX emissions. This technique
introduces water into the combustion process by emulsifying water
in the fuel oil prior to injection. This emulsion has a water
content of 20 to 50 percent by volume and is finely dispersed and
chemically stabilized in the oil phase. The principle of NOX
control is similar to conventional water injection, but the
uniform dispersion of the water in the oil provides greater NOX
reduction than conventional water injection at similar WFR's.19
A water-in-oil emulsion injection system consists of
mechanical emulsification equipment, chemical stabilizer
injection equipment, water metering valves, chemical storage and
metering valves, and instrumentation. In most cases the
emulsifying system can be retrofitted to the existing fuel
delivery system, which eliminates the requirement for a separate
delivery system for water injection. At multiunit installations,
one emulsion system can be used to supply emulsified fuel to
several turbines. For dual fuel turbines, the emulsion can be
injected through the oil fuel system to control NOX emissions.19
Data provided by the vendor for this technique indicates
that testing has been performed on oil-fired turbines operating
in peaking duty. Long-term testing has not been completed at
this point to quantify the long-term effects of the emulsifier on
the operation and maintenance of the turbine.
5-42
-------
5.1.2 Applicability of Wet Controls
Wet controls have been applied effectively to both
aeroderivative and heavy-duty gas turbines and to all
configurations except regenerative cycle applications.20 It is
expected that wet controls can be used with regenerative cycle
turbines, but no such installations were identified. All
manufacturers contacted have water injection control systems
available for their gas turbine models; many also offer steam
injection control systems. Where both systems are available, the
decision of which control to use depends upon steam availability
and economic factors specific to each site.
Wet controls can be added as a retrofit to most gas turbine
installations. In the case of water injection, one limitation is
the possible unavailability of injection nozzles for turbines
operating in dual fuel applications. In this application, the
injection nozzle as designed by the manufacturer may not
physically accommodate a third injection port for water
injection. This limitation also applies to steam injection. In
addition, steam injection is not an available control option from
some gas turbine manufacturers.
5.1.3 Factors Affecting the Performance of Wet Controls
The WFR is the most important factor affecting the
performance of wet controls. Other factors affecting performance
are the combustor geometry and injection nozzle(s) design and the
fuel-bound nitrogen (FBN) content. These factors are discussed
below.
The WFR has a significant impact on NOX emissions.
Tables 5-5 and 5-6 provide NOX reduction and WFRs for natural gas
and
5-43
-------
TABLE 5-5. MANUFACTURER'S GUARANTEED NOX REDUCTION EFFICIENCIES
AND ESTIMATED WATER-TO-FUEL RATIOS FOR NATURAL
GAS FUEL OPERATION5"11'21"24
Manufacturer/model
General Electric
LM1600
LM2500
LM5000
LM6000
MS5001P
MS6001B
MS 700 IE
MS7001F
MS9001E
MS9001F
Asea Brown Boveri
GT10
GTS
GT11N
GTS 5
Solar Turbines, Inc.
T-1500 Saturn
T-4500 Centaur
Type H Centaur
Taurus
T-12000 Mars
T- 14000 Mars
Allison/GM
501-KB5
501-KC5
501-KH
570-K
571-K
Westinghouse
251B11/12
501D5
Siemens
V84.2
V94.2
V64.3
V84.3
V94.3
NOX emission levels, ppmv at 15% O2/NOX percent
reduction
Uncontrolled
133
174
185
220
142
148
154
210
161
210
150
430
390
300
99
130
105
114
178
199
155
174
155
101
101
220
190
212
212
380
380
380
Water injection
42V68
42V76
42V77
42V81
42/70
42/72
42/73
42/80
42/74
42/86
25/83
25/94
25/94
42/86
42/58
42/68
42/60
42/63
42/76
42/79
42/73
42/76
42/73
42/58
42/58
42/81
25/87
42/80
55/74
75/80
75/80
75/80
Steam injection
25/81
25/86
25/87
25/89
42/70
42/72
42/73
42/80
42/74
42/80
42/72
29/93
25/94
60/80
NA7NAC
NA7NAC
NA7NAC
NA7NAC
NA7NAC
NA7NAC
42/73
NAC/NAC
25/84
NAC/NAC
NAC/NAC
25/89
25/87
55/74
55/74
75/80
75/80
75/80
Water-to-fuel ratio (Ib water to
Ib fuel)
Water injection
0.61
0.73
0.63
0.68
0.72
0.77
0.81
0.79
0.78
NA"
0.93
1.86
1.76
1.00
0.33
0.61
0.70
0.79
0.91
1.14
0.80
NA"
NAb
NA"
0.80
1.0
1.6
2.0
1.6
1.6
1.6
1.6
Steam injection
1.49
1.46
1.67
1.67
1.08
1.16
1.22
1.34
1.18
NA"
1.07
2.48
2.47
1.20
NAC
NAC
NAC
NAC
NAC
NAC
1.53
NAC
NAb
NAC
NAC
1.8
1.6
2.0
1.6
1.4
1.4
1.4
"A NOX emissions level of 25 ppmv can be achieved, but turbine maintenance requirements increase over those
required for 42 ppmv.
5-44
-------
TABLE 5-6. MANUFACTURER'S GUARANTEED NOX REDUCTION EFFICIENCIES
AND ESTIMATED WATER-TO-FUEL RATIOS FOR DISTILLATE
OIL FUEL OPERATION5"11'21"24
Manufacturer/model
General Electric
LM1600
LM2500
LM5000
LM6000
MS5001P
MS6001B
MS7001E
MS7001F
MS9001E
MS9001F
Asea Brown Boveri
GT10
GTS
GT11N
GT35
Solar Turbines, Inc.
T-1500 Saturn
T-4500 Centaur
Type H Centaur
Taurus
T- 12000 Mars
T- 14000 Mars
Alhson/GM
501-KB5
501-KC5
501 -KH
570-K
571-K
Westinghouse
251B11/12
501D5
Siemens
V84.2
V94.2
V64.3
V84.3
V94.3
NOX emissions level, ppmv at 15% O2/NOX percent
reduction
Uncontrolled
237
345
364
417
211
267
228
353
241
353
200
680
560
360
150
179
160
168
267
NAa
231
NAa
231
182
182
355
250
360
360
530
530
530
Water injection
42/82
42/88
42/88
42/90
65/69
65/76
65/72
65/82
65/73
65/82
42/79
42/94
42/88
42/88
60/60
60/66
60/63
60/64
60/78
60/NAa
56/76
NA7NAa
56/76"
65/64a
65/64a
65/82
42/83
42/88
42/88
75/86
75/86
75/86
Steam injection
75/70
75/78
110/70
110/74
65/69
65/76
65/72
65/77
65/72
65/76
42/79
60/91
42/93
60/83
NAb/NAb
NAb/NAb
NAb/NAb
NAb/NAb
NAb/NAb
NAb/NAb
NAb/NAb
NAb/NAb
50/78
NAb/NAb
NAb/NAb
42/88
42/83
55/85
55/85
75/86
75/86
75/86
Water-to-fuel ratio (Ib water to Ib
fuel)
Water injection
NAa
0.99
NAa
NAa
0.79
0.73
0.67
0.72
0.65
NAa
0.75
1.62
1.50
1.00
0.46
0.60
0.72
0.96
1.00
NAa
NAa
NAa
NAa
NAa
NAa
1.0
1.0
1.4
1.4
1.2
1.2
1.2
Steam injection
NAa
NAa
NAa
NAa
1.06
1.20
1.19
1.35
1.16
NAa
1.25
2.15
2.28
1.20
NAb
NAb
NAb
NAb
NAb
NAb
NAb
NAb
NAa
NAb
NAb
1.8
1.6
2.0
1.6
1.4
1.4
1.4
aData not available.
5-45
-------
distillate oil fuels, respectively, based on information provided
by gas turbine manufacturers. For natural gas fuel, WFR's for
water or steam injection range from 0.33 to 2.48 to achieve
controlled NOX emission levels ranging from
25 to 75 ppmv, corrected to 15 percent oxygen. For oil fuel,
WFR's range from 0.46 to 2.28 to achieve controlled NOX emission
levels ranging from 42 to 110 ppmv, corrected to 15 percent
oxygen. Nitrogen oxide reduction efficiency increases as the WFR
5-46
-------
5-47
-------
increases. As shown in Tables 5-5 and 5-6, reduction
efficiencies of 70 to 90 percent are common. Note that, in
general, the WFR's for steam are higher than for water injection
because water acts as a better heat sink than steam due to the
heat absorbed by vaporization; therefore, higher levels of steam
than water must be injected for a given reduction level.
The combustor geometry and injection nozzle design and
location also affect the performance of wet controls. For
maximum NOX reduction efficiency, the water must be atomized and
injected in a spray pattern that provides a homogeneous mixture
of water droplets and fuel in the combustor. Failure to achieve
this mixing yields localized hot spots in the combustor that
produce increased NOX emissions.
The type of fuel affects the performance of wet controls.
In general, lower controlled NOX emission levels can be achieved
with gaseous fuels than with oil fuels. The FBN content also
affects the performance of wet controls. Those fuels with
relatively high nitrogen content, such as coal-derived liquids,
shale oil, and residual oils, result in significant fuel NOX
formation. Natural gas and most distillate oils are low-nitrogen
fuels. Consequently, fuel NOX formation is minimal when these
fuels are burned.
Wet controls serve only to lower the flame temperature and
therefore are an effective control only for thermal NOX
formation; water injection may in fact increase the rate of fuel
NOX formation, as shown in Figure 5-1.25 The mechanisms
responsible for this potential increase were not identified.
5-48
-------
Cn
I
J
c
41
O
*
O
z
O
o
-*^
i-
3-
C
O
O:
ID
100
ao
60
40
1.1 Water-to-fuel ratio
n,S4 yater-to-fuel ntio
3 Water-to-fuel ratio
ป i
o.ni 0,02 o.c4 O.M o.io 0.20
fuel Bound Nitroyen Content { Weight Percent )
_i 1 3 u I- ..1 J
0,40 0.60 1,0
-------
5.1.4 Achievable N0;: Emissions Levels Using Wet Controls
This section presents the achievable controlled NOX emission
levels for wet injection, as guaranteed by gas turbine
manufacturers. Emission test data, obtained using EPA Test
Method 20 or equivalent, are also presented.
Guaranteed NOX emission levels as provided by gas turbine
manufacturers for wet controls are shown in Figures 5-2 and
5-50
-------
Cn
"d
M- fcv4
^ CD *Q
^!
ft ti1 ""
H- CD '
O
Hi
* H H> ฃ 400-
CD 5ป 3 ฎ H
(T 0 n ^ Q
H- Hi 8 ฃ 2 CSI 353-
0 fป rf g j; O
rf ^ ' H ^~
oSU'n-o @
P ^fD rf "> ,,
* S 0 MI 6 aso-
t>J?.iQ C CL
h CD CD Q.
tu tu 8- p T w
? ^IQ- o cr o ^^
{>ป flKg" ^.0 .*>
o! B> f p X
ป ฐ 2 p, rf ฐ
2 p- p ! ^-
"^ ^ CL PI O
(D h{ jj (j{
I"1 ^, tu tr 3 at-
|&5j8
-H|_i <3> (T ^ "
"5 e> n ^
"{E, CDฐ(V ฎ
M 0 ฐJ
H, rf
W CD
H- 2, a
NATURAL GAS
O
UNCONlNUULtU
Kaa
STEAK
f
uU
WATER
ซiL
STEAM
,,
CiiLd
WATER
6:1
" " 42
~
\
a
ฃ
i
ฃ
in
r":'i
%:
s
T
5
ฃ
a
430
17
ซ
Of
''"'",
4HC
>r.v
SK
f
IB 8
" i
raa
'tV.
174
5!
1
1
-->/.
li
455
*/.:
i
^
g n in x
| 1 u ฅ
- R i g
|
101
,-<
-V
v;
m
***/'
^
&
*
*.*>
i"r
i/ju.
r
i
//,
I
ca
1
Jg
i
21U 215
| AH lซi
- *i
4.
1
88 8 8 *
5 3 3 ffi
rn
1
CJ
1
U1
a
1
i
Tซ
I
i
2S
330 Mrt
IK
1
'.'?/.
P
i j a
3
BO
1
f
H_.__ ...
220 .
ซ
I
jrfBB
1
^
#
^
^
<5',
1
j*
P
I
/b
fJrt
P
^M
^:
H
i
UJ xj|U
-------
I
Cn
(D
Ul
00
(D 0ป 0
ft 0 O
e o
H- H, 0
0 0ป ft
LJ. o n
(D ft O
O C M
ft H I-1
H- (D (D
o n o.
0 M
' "o
H- g
ill
_i D :
LIQUID FUEL
o
in
ฉ
>
Q_
fi.
w
c
g
"oa
m
E
tu
O
z
w
H-
0
-------
5-3. These figures show manufacturers' guaranteed NOX emission
levels of 42 ppmv for most natural gas-fired turbines, and from
42 to
5-53
-------
5-54
-------
5-55
-------
75 ppmv for most oil-fired turbines. The percent reduction in
NOX emissions varies for each turbine, ranging from 60 to
94 percent depending upon each model's uncontrolled emission
level and whether water or steam is injected.
Emissions data for water and steam injection are presented
to show the effects of wet injection on NOX emissions. These
data show:
1. That NOX emissions decrease with increasing WFR's; and
2. That NOX emissions are higher for oil fuel than for
natural gas.
From the available data, reduction efficiencies of 70 to
over 85 percent were achieved. The emission data and WFRs shown
for specific turbine models may not reflect the emission levels
of current production models, since manufacturers periodically
update or otherwise modify their turbines, thereby altering
specific emissions levels.
Each emission test in the following figures consists of one
or more data points. Where data points were obtained under
similar conditions, they are grouped together and presented as a
single test. For these cases, each data point, along with the
arithmetic average of all of the data points, is shown.
The nomenclature used to identify the tests consists of two
letters followed by a number. The first letter of the two-letter
designator specifies the turbine type. These types are as
follows:
Letter Turbine type
A Aircraft-derivative turbine
H Heavy-duty turbine
T Small and low-efficiency turbine (less
than 7.5 MW output, less than
30 percent simple-cycle efficiency)
The second letter identifies the facility. The number identifies
the number of tests performed at the facility. Tests performed
at the same facility on different turbines or at different times
have the same two-letter designator but are followed by different
test numbers. The short horizontal lines represent the average
of the test data.
5-56
-------
Also presented are the available data on the turbine, wet
controls, uncontrolled NOX emissions, percent NOX reduction, and
fuel type. All of the data shown are representative of the
performance of wet controls when the turbine is operated at base
load or peak load. These loads represent the worst-case
conditions for NOX emission reduction. Information on the WFR,
turbine model, efficiency, control type, and fuel are included
with the emission test data.
5-57
-------
Figures 5-4, 5-5, and 5-6 present the emission test data
5-58
-------
'J- *l-
c.
| 3- JO
iZ
Ci
1
5
% 'ป
HI
a
a D v li^
ML
1
^
- Aปi?riซlf Vtt Hit.- a
\
1 13
-e-i
O.sJ ฐ-6fi
r^ Af, '^ , 3 t.i
-ฉ^ 1 1
fTS
II 1 i
.X
J
'?
1
.;.
3
vo 5
-f
s
3
a
9
"ซit 1o. Til -i,j T"W Til TLJ -Sj rotation.
'yrblnt NQdcl
Efficiency IS)
C=rt,ซter Trw
Biป1,ปd Win, fW)
rXM rf FU<:
Lซd
(icige of H/F
ซ''(TS Cb/lbJ
5Q1*B Csntjur Centaur 5
-------
NO Re
-------
"d
H-
CD
H-
B w
W H-
ฃ ^
H-0
hซJ fl)
fD
CD
S" 8
ซ-j- g
Cn CD J!"
1 US
O^ (T H_
88
M M
H- *"^
IQ P.
P QJ
p) *"
ฃH,
2 n
IQ CD
10 1
ง*
(T
(U
U
D.in
c
a
t>
1 a JO
Q
irt
z,
v-M
I
i*
a
l^it Ha,
9.11 imtriy lift SIS (10
hH KH ^ ^ fl_w ^H
ปM
i W | D.85
" "' -ซ iH te-j ,|^ -
i1"1
'
1 , _L. 1 ป i 1 .1 1,1 . 1
IU) Ml *? Hfl HDI mt NCI HMS HC* HM MLi
mi
M
-
lurfclnt fladrl NSJMIE MSfWH WUHB MMIU H550UJ i|SO|I.i MF,0|I! 64 r>jป H wปH UK Tvpซ U nMli
ifficซซnt^ i) 31 11 '*ซ 3? 2H Jf 3? JJ j^ yt K
CariNistpr Type C* a ซ C* C* r* c* it* 5 r* taution:
SistlBil Bit In? |Hu5 14 )b ซ0 10 W tm 'C ซ Ml M DO - Kii
b|M flf Ful NS ซa "' Hi US ซo Nli N6 N6 if, UK Cfl - r*r-
^ 4 L i U
Kซis9* uf H/f n.16- ft,?? O-?6' ฐ-S6 fl.4Z- o.iB II. b? 0,76 0.71- 1. 01 J.1H-
Batio* HWlM 0,20 '*?' fl-4J P. S3 1 ?l
ป: lulssfans
yithout Wet
oSu. ISO] ป.ซ D.6M ป 0.6
-------
for water injection on turbines fired with natural gas. These
turbines have NOX emissions ranging from approximately 20 to
105 ppm with WFR's ranging from 0.16 to 1.32. Turbine sizes
range from 2.8 to 97 MW. Based on these data, water injection is
effective on all types of gas turbines and NOX emission levels
decrease as the WFR increases. However, some turbines require a
higher WFR to meet a specific emission level. For example, the
gas turbines at sites HH and HC (Figure 5-6) require much higher
WFR's to achieve NOX emission levels similar to the other gas
turbine models shown. This particular gas turbine also has the
highest uncontrolled NOX emission levels. Conversely, the gas
turbine at site AH, shown in Figure 5-5, has the lowest
uncontrolled NOX emission level and requires the least amount of
water to achieve a given emission level. Uncontrolled NOX
emission levels vary for different turbine models depending upon
design factors such as efficiency, firing temperature, and the
extent of combustion controls incorporated in the combustor
design (see Section 4.2.1.1). In general, aircraft-derivative
and heavy-duty gas turbines require similar WFR's to achieve a
specific emission level. Small, low-efficiency gas turbines
require less water to achieve a specific emission level.
The NOX emissions for turbines firing distillate oil are
shown in Figures 5-7, 5-8, and 5-9. The data range from
5-62
-------
0 60 r
X50 -
o. *o
0.30 -
| u.20
Ho.
- Avenge k/f Ratio
G.Zt
:-H
3K-30
F.ffietBney istrcent! '1!
CurfiOusrcn" Tvw CX
3*iป toad 2S
Tyoe of Fusl 00
t.oid 8a;e
Pawt o* Vl/P 0,2ซ
NO Bsiislons
vltlUUt Uซt
Controls
!ib/i*ซta, rso>
W flrtuttlon :tl
0.53
0,46
i
,
! ฉ 1
11
28
EQ
3ase
a. 559
52-8
:A
?s
CO
Base
Q.S'.-
C,5=
3-787
66.3
3?
M
DO
Bd$e
a.72
C.340
70.5
ff?
:.37
83,4
C.76
0.34
C> Natation1
CA
48. -9
Figure 5-7. Nitrogen oxide emission test data for aircraft-
derivative gas turbines with water injection firing distillate
oil.27
5-63
-------
rriQ
01 P)
(U U
0
rr
o e
- n
ui cr
H-
(U 0
0 CD
P, W
l-h 3
H- H-
- P.?
0
2 ซo <
fl,
p, rr
H- CD
u n
(T
H- H-
M 0
| 1 (_l-
(U CD
ft 0
CD ft
H-
0 0
H- 0
^{U
""P.
"d
I-"
CD
U
U
"d
H-
IQ u bi'
CD
Ul
1 4.M
00
|
H^ < nป niii mil
I Hi (haul ML
O (aiUrul*
ฃ jlb/Mttly. ISQI V 41J
_*T lit) u^i.^-tEnr jll
-------
Cn
1
O^
Cn
rriQ
0" fU
(U W
(T
o C
* ^
ui cr
H-
0 (D
P, W
Hi 3
H- H-
H fi"
H-01
3*
(U
P, ft
H- (D
M H
(T
H- H-
"""5
(U (D
ft 0
(D rr
H-
2-8
i '
'sB
p.
*i
W
IQ
(D
(U
H-
IQ
(D
Ul
. u.iu
3
H4A
* ft til
rr s
0 1
IQ J
(D S
0 "
j u.ao
O
Xiii
Cj
H" 3
o j
g
ง i OM
P. i
M '
M *
H-
0
0 o. ID
rr
(D
U
rr
-
."*ป;
J.I)
H3-1
.
t Pffirrjitlf y.'ป ^.|1 ^g
G,i2 ^ *^ 3
I 5*1 1 1 1*^ i r*\
i " i "^ i y i
t.n G
/^, ^.:3-
v ; [ Q j
"A '
^-
HrH
! , i
Q
if i
rV
W
1 < 1 1 1 ! 1
iซ
iUO
ft
rป Ut'. b ^1 '!," "!L N)
Jl) rป
JJT lurt'na tjdil yWlD UMJIi: *>HXUS Hi^JUiF u'Jllh M I>PL- H It, V>Iปป 'li IrUliB UB l.ซix ii.
(Lซlci*Wป it) 1? M SI H -1? ?? 3" JJ i.'
Hi
O .Uaiuitor I,p, l.i LI tli C* M 5 ป C* i, "WUUWI,
1^ 1VI - 4H11
iiltlMd tih*9 IWI W IK Si '* 'ป '* M JU *"*(ซ- W(ur
5" I MM o! (ml Ml W W) 1* !ป W* W BO W 4 1 ^fj'*
(D '
W ^ftj^ ias* liซvป Bile f-fit flivr Bซ4ป *Hf ปซซ fliir
*S lUnOC af y/l RII143 tld.Mt.) 0 6? (J.IซJ 0 h* H. 'l>- 0." 'J.W- l.W >-S- ป '
1 1) JJ 1.? 1 ]
PI Hfl t*lMlHrป .llhlut
Cl iiซt Iont>ป lltfWBtu. ISO} !.<ป ' '.' U hซ 0 ซ(l ^.W IW ; 'ซ '1 ?W l.ป
rr
(D
-------
approximately 30 to 135 ppm, with WFR's ranging from 0.24 to
1.31. The gas turbine sizes range from 19 to 95 MW. The data
for distillate oil-fired turbines show the same general trends as
the data for natural gas-fired turbines. Site HH (Figure 5-9)
5-66
-------
5-67
-------
5-68
-------
5-69
-------
5-70
-------
5-71
-------
again shows that higher WFR's are required due to the high
uncontrolled NOX emissions from this gas turbine. Also, by
comparing the emission data for the distillate oil-fired turbines
and natural gas-fired turbines, the data show that burning
distillate oil requires higher WFR's than does burning natural
gas for a given level of NOX emissions. Higher WFR's are
required because distillate oil produces higher uncontrolled NOX
levels than does natural gas (see Section 4.2.1.2).
The NOX emission test data for steam injection are presented
in Figures 5-10
5-72
-------
seE -[Ban^Bu EUTJTJ UOT^OSCUT uree^s
jog e^ep 3533 UOTSSTUIS sp-cxo
"OT-S
o; is =
^f-'^EJ^U =
,. lซ=|r _
C
C
'1
*-
C
o
O
^ Da *Buซa
[anj JO sa/'j.
,'jซy peni assfl
ac^'j jOS^nqtuD^
afl) Xjvsf3,jj5
Lap0w mitMni
E>N asij.
35
O
K
or^o |
M^
1^1
S'
3
\fi
"
Z?~
it,.
c-ro ฐ^
cป
,**
c?
ฃ
*--,
D
3
0ฃ C -
n-
c
^
fl*"fl
-------
Q.4Q
Q
u
0.3C -
'-ฃ>
O
0.20
D ,: o -
o
Test No.
Ttjrbire Wade?
r O" i
Average tf/F Satio
\
\
0-97
i Q i i.o,
^W1 K3H
~
i i i
HM2 W3 HZ3
'IOC
2
O
X
r^
ฃ#t
a
:/>
Z3
S)
50 -
r-J
'j*<
o
a"
3,
o"
3
VI
0
M57001S HS7001E M56001B
cent) 32 32 31
Base Load Ratinq, ,*
af
Rat.ias
NO Emissions
without Met
Controls
(Tb/l*fltu. ISO)
HO Reduction ฃ3)
?o
QQ
Base
0 fiS
0,860
56.5
DO
Base
0.31-
0.99
0.360
,16
DO
Rase
0.749
66.fi
Natation:
CC = distil late oil
Ntj = natural a^s
CA = can-annular
S = s:lci
A =
Figure 5-11. Nitrogen oxide emission test data for gas turbines
with steam injection firing distillate oil.
27
5-74
-------
and 5-11 for natural gas-fired turbines and distillate oil-fired
turbines, respectively. The turbines firing natural gas have NOX
emissions ranging from approximately 40 to 80 ppm, with WFR's
ranging from 0.50 to 1.02. The gas turbine sizes range from 30
to 70 MW.
The NOX emissions for turbines firing distillate oil range
from approximately 65 to 95 ppm, with WFR's ranging from 0.65 to
1.01, and the gas turbine sizes tested were 36 and 70 MW. Fewer
data points are available for steam injection than for water
injection. However, the available data for both distillate oil-
fired and natural gas-fired turbines show that NOX emissions
decrease as the steam-to-fuel ratio increases.
Reductions in NOX emissions similar to water injection with
oil-fired turbines have been achieved using water-in-oil
emulsions. Results of emission tests for four turbines are shown
in Table 5-7
5-75
-------
TABLE 5-7. ACHIEVABLE GAS TURBINE NOX EMISSION REDUCTIONS
FOR OIL-FIRED TURBINES USING WATER-IN-OIL EMULSIONS19
Turbine
manufacturer
Turbo Power
and Marine
General Electric
Turbine
model
A4
A9
A9
MS5001
Power
output, MW
35
33
33
15
Water-to-
fuel ratio
0.65
0.55
0.92
0.49
NOX emissions, ppmv
at 15 percent O,
Uncontrolled
184
150
126
131
Controlled
53
50
29
60
Percent
reduction
68
66
77
54
5-76
-------
The controlled NOX emissions range from 29 to 60 ppmv,
corresponding to NOX reductions of 54 to 77 percent.19 The
controlled NOX emission levels and percent reduction are
consistent with those achieved using conventional water
injection. Limited testing has shown that the emulsion achieves
a given NOX reduction level with a lower WFR than does a separate
water injection arrangement. Test data for one oil-fired turbine
showing a comparison of the WFR's for a water-in-oil emulsion
versus a separate water injection system are shown in Figure 5-12
5-77
-------
CD
m
Cn
I
CO
O CD O
H- 3 O
Hi U (U
H- H- H
H O H-
CD 0 W
P. O
< 0
S&o
K M Hi
cr e
H-M ft
0 01
CD U CD
CD
"{U ^
(U
ฃ *
CD CD
H-0
0 ft
i_i.
88-
ff-11
(T
Hi fl)
o h
H-
S 0
0 I
o
H-
0.5 1 1.5
INJECTION WATER TO FUEL RATE
EMULSION
B
H20 INJECTION
---A--
-------
As shown here, NOX reductions achieved by a water injection
system at a WFR of 1.0 can be achieved by a water-in-oil emulsion
at a WFR of 0.6.
5-79
-------
5-80
-------
5-81
-------
5-82
-------
On a mass basis, the reduction in NOX emissions using water
injection is shown in Table 5-8
5-83
-------
TABLE 5-8. UNCONTROLLED NOX EMISSIONS AND POTENTIAL NOX
REDUCTIONS FOR GAS TURBINES USING WATER INJECTION
Gas turbine
model
Saturn
Centaur
Centaur "H"
Taurus
Mars T- 12000
Mars T- 14000
501-KB5
570-K
571-K
LM1600
LM2500
LM5000
LM6000
MS5001P
MS6001B
MS7001E
MS7001F
MS9001E
MS9001F
GTS
GT10
GT11N
GT35
251B11/12
501D5
V84.2
V94.2
V64.3
V84.3
V94.3
Power
output, MWa
1.1
3.3
4.0
4.5
8.8
10.0
4.0
4.9
5.9
14.0
22.7
34.5
43.0
26.8
39.0
84.7
161
125
229
47.4
22.6
83.3
16.9
49.2
109
105
153
61.5
141
204
NOY emissions
Uncontrolled
Gas fuel,
lb/hrb
6.4
22.0
20.8
24.7
69.4
85.4
31.6
22.7
24.2
74.1
146
232
310
181
250
544
1,290
810
1,850
899
143
1,350
214
453
843
858
1,250
859
1,930
2,790
Oil fuel,
lb/hrb
9.9
31.2
32.6
37.6
107
NAd
48.5
41.0
44.0
127
301
474
609
274
459
822
2,190
1,320
3,150
1,440
196
1,990
264
741
1,120
1,570
2,290
1,290
2,910
4,170
Controlled
Gas fuel,
lb/hrb
2.8
7.4
8.6
9.4
17.0
18.7
8.9
9.8
10.4
22.4
36.4
54.5
61.3
55.5
73.2
154
267
219
382
54.1
24.6
99.0
30.9
89.5
115
176
335
176
395
571
Oil fuel,
lb/hrb
4.1
10.8
12.7
13.9
24.9
NAd
12.2
15.2
16.3
23.2
37.9
56.6
63.5
87.4
116
243
417
369
600
92.3
42.6
154
31.9
141
196
190
276
188
426
611
NOY reduction
Gas fuel,
tons/yrc
14.3
58.5
48.6
61.1
210
267
90.9
51.8
55.1
207
438
710
996
503
704
1,560
4,090
2,370
5,850
3,380
472
5,060
730
1,450
2,910
2,730
3,650
2,740
6,150
8,890
Oil fuel,
tons/yrฐ
23.3
81.5
79.8
94.9
329
NAd
145
103
111
414
1,050
1,670
2,180
747
1,370
2,320
7,090
3,820
10,200
5,410
614
7,334
929
2,400
3,710
5,520
8,050
4,390
9,920
14,200
Tower output at ISO conditions, without wet injection, with natural gas fuel.
bBased on ppmv levels shown in Tables 5-5 and 5-6. See Appendix A for conversion from
ppmv to Ib/hr.
'Based on 8,000 hours operation per year.
dData not available.
5-84
-------
NO,, REDUCTIONS FOR GAS TURBINES USING STEAM INJECTION
Gas turbine model
Saturn
Centaur
Centaur "H"
Taurus
Mars T- 12000
501-KB5
570-K
571-K
LM1600
LM2500
LM5000
LM6000
MS5001P
MS6001B
MS7001E
MS7001F
MS9001E
MS9001F
GTS
GT10
GT11N
GT35
251B11/12
501D5
V84.2
V94.2
V64.3
V84.3
V94.3
Power
output,
MWa
1.1
3.3
4.0
4.5
8.8
4.0
4.9
5.9
14.0
22.7
34.5
43.0
26.8
39.0
84.7
161
125
229
47.4
22.6
83.3
16.9
49.2
109
105
153
61.5
141
204
NO, emissions
Uncontrolled
Gas fuel,
lb/hrb
6.4
22.0
20.8
24.7
69.4
31.6
22.7
24.2
74.1
146
232
310
181
250
544
1,290
810
1,850
899
143
1,350
214
453
843
858
1,250
859
1,930
2,790
Oil fuel,
lb/hrb
9.9
31.2
32.6
37.6
107
48.5
41.0
44.0
127
301
474
609
274
459
822
2,190
1,320
3,150
1,440
196
1,990
264
741
1,120
1,570
3,290
1,290
2,910
4,170
Controlled
Gas fuel,
lb/hrb
6.4
22.0
20.8
24.7
69.4
8.6
22.7
24.2
13.0
21.2
31.7
35.6
54.1
71.4
150
260
214
373
61.2
40.4
147
43.1
52.0
112
225
327
171
386
557
Oil fuel,
lb/hrb
9.9
31.2
32.6
37.6
107
48.5
41.0
44.0
40.5
66.0
145
162
85.3
113
237
407
360
585
129
41.6
151
44.4
88.6
191
242
353
184
415
596
NOV reduction
Gas fuel,
tons/yrcd
0
0
0
0
0
194
0
0
245
499
802
1,100
508
711
1,580
4,110
2,390
5,890
3,350
410
4,830
681
1,600
2,920
2,530
3,690
2,750
6,190
8,940
Oil fuel,
tons/yrc d
0
0
0
0
0
0
0
0
345
938
1,320
1,790
755
1,380
2,340
7,130
3,850
10,200
5,260
618
7,350
878
2,610
3,730
5,310
7,740
4,410
9,960
14,300
Tower output at ISO conditions, without wet injection, with natural gas fuel.
bBased on ppmv levels shown in Tables 5-5 and 5-6. See Appendix A for conversion from ppmv to Ib/hr.
5-85
-------
As an example, a 21.8 MW turbine burning natural gas fuel can
reduce NOX emissions by 452 tons/yr (8,000 hours operation) using
water injection and 511 tons/yr using steam injection. This same
turbine burning oil fuel will reduce annual NOX emissions by
1,040 tons using water injection and by 925 tons using steam
injection.
5.1.5 Impacts of Wet Controls on CO and HC Emissions
While carbon monoxide (CO) and hydrocarbon (HC) emissions
are relatively low for most gas turbines, water injection may
increase these emissions. Figure 5-13
5-86
-------
Figure 5-13. Effect of wet injection on CO emissions.
29
5-87
-------
shows the impact of water injection on CO emissions for several
production gas turbines. In many turbines, CO emissions increase
as the WFR increases, especially at WFR's above 0.8. Steam
injection also increases CO emissions at relatively high WFR's,
but the impact is less than that of water injection.29'30
Water and steam injection also increase HC emissions, but to
a lesser extent than CO emissions.29'30 The effect of water
injection on HC emissions for one turbine is shown in
5-!
-------
0,07
o.ai r
0.2.
WIQ1K Gas Turbine
3istiFate Oi 1-Fired
0.4
O.fi
'3. 5
1.0
1,2
Figure 5-14. Effect of water injection on HC emissions for one
turbine model.29
5-89
-------
Figure 5-14. Like CO emissions, hydrocarbon emissions increase
at WFR's above 0.8.
For applications where the water or steam injection rates
required for NOX emission reductions result in excess CO and/or
HC emissions, it may be possible to select an alternative turbine
and/or fuel with a relatively flat CO curve, as indicated in
Figure 5-13. Another alternative is an oxidation catalyst to
reduce these emissions. This oxidation catalyst is an add-on
control device that is placed in the turbine exhaust duct or HRSG
and serves to oxidize CO and HC to H20 and C02. The catalyst
material is usually a precious metal (platinum, palladium, or
rhodium), and oxidation efficiencies of 90 percent or higher can
be achieved. The oxidation process takes place spontaneously,
without the requirement for introducing reactants (such as
ammonia) into the flue gas stream.31
5-90
-------
5-91
-------
5-92
-------
5-93
-------
5.1.6 Impacts of Wet Controls on Gas Turbine Performance
Wet controls affect gas turbine performance in two ways:
power output increases and efficiency decreases. The energy from
the added mass flow and heat capacity of the injected water or
steam can be recovered in the turbine, which results in an
increase in power output. For water injection, the fuel energy
required to vaporize the water in the turbine combustor, however,
results in a net penalty to the overall efficiency of the
turbine. For steam injection, there is an energy penalty
associated with generating the steam, which results in a net
penalty to the overall cycle efficiency. Where the steam source
is exhaust heat, which would otherwise be exhausted to the
atmosphere, the heat recovery results in a net gain in gas
turbine efficiency.32 The actual efficiency reduction associated
with wet controls is specific to each turbine and the actual WFR
required to meet a specific NOX reduction. The overall
efficiency penalty increases with increasing WFR and is usually
higher for water injection than for steam injection due to the
heat of vaporization associated with water. The impacts on
output and efficiency for one manufacturer's gas turbines are
shown in Table 5-10.
5-94
-------
TABLE 5-10. REPRESENTATIVE WATER/STEAM INJECTION
IMPACTS ON GAS TURBINE PERFORMANCE FOR ONE
MANUFACTURER'S HEAVY-DUTY TURBINES33
Nox
level,
ppmv
75 NSPS
42
42
25
25
Water/fuel
ratio
0.5
1.0
1.2
1.2
1.3
Percent
overall
efficiency
change
-1.8
<-3
-2
-4
-3
Percent
output
change3
+ 3
+ 5
+ 5
+ 6
+ 5.5
Remarks
Oil-fired, simple
cycle, water
inj ection
Natural gas,
simple cycle,
water injection
Natural gas,
combined cycle,
steam injection
Natural gas,
water injection,
multinozzle
combustor
Natural gas,
steam injection,
combined cycle
(Frame 6 turbine
model)
aCompared with no injection.
5-95
-------
5.1.7 Impacts of Wet Controls on Gas Turbine Maintenance
Water injection increases dynamic pressure oscillation
activity in the turbine combustor.33 This activity can, in some
turbine models, increase erosion and wear in the hot section of
the turbine, thereby increasing maintenance requirements. As a
result, the turbine must be removed from service more frequently
for inspection and repairs to the hot section components. A
summary of the maintenance impacts as provided by manufacturers
is shown in Table 5-11.
5-96
-------
TABLE 5-11.
IMPACTS OF WET CONTROLS ON GAS TURBINE MAINTENANCE
USING NATURAL GAS FUEL5"11'17'24
Manufacturer/Model
General Electric
LM1600
LM2500
LM5000
LM6000
MS5001P
MS6001B
MS7001E
MS7001F
MS9001E
MS9001F
Asea Brown Boveri
GT10
GTS
GT11N
GTS 5
Siemens Power Corp.
V84.2
V94.2
V64.3
V84.3
V94.3
Solar Turbines, Inc.
T-1500 Saturn
T-4500 Centaur
Type H Centaur
Taurus
T- 12000 Mars
T- 14000 Mars
Allison/General
Motors
501-KB5
501-KC5
501 -KH
570-K
571-K
Westinghouse
251B11/12
501D5
NOX emissions, ppmv (5) 15% O,
Standard
combustor
133
174
185
220
142
148
154
179
176
176
150
430
400
300
212
212
380
380
380
99
150
105
114
178
199
155
174
155
101
101
220
190
Water
injection
42/25
42/25
42/25
42/25
42
42
42
42
42
42
25
25
25
42
42
55
75
75
75
42
42
42
42
42
42
42
42
42
42
42
42
25
Steam
injection
25
25
25
25
42
42
42
42
42
42
42
29
25
60
55
55
75
75
75
NAC
NAC
NAC
NAC
NAC
NAC
NAC
NAC
25
NAC
NAC
25
25
Inspection interval, hours
Standard
25,000
25,000
25,000
25,000
12,000
12,000
8,000
8,000
8,000
8,000
80,000b
24,000
24,000
80,000b
25,000
25,000
25,000
25,000
25,000
NAd
NAd
NAd
NAd
NAd
NAd
25,000
30,000
25,000
20,000
20,000
8,000
8,000
Water
injection
16,000a
16,000a
16,000a
16,000a
6,000
6,000
6,500
8,000
6,500
8,000
80,000b
24,000
24,000
80,000b
25,000
25,000
25,000
25,000
25,000
NAd
NAd
NAd
NAd
NAd
NAd
17,000
22,000
17,000
12,000
12,000
8,000
8,000
Steam
injection
25,000
25,000
25,000
25,000
6,000
8,000
8,000
8,000
8,000
8,000
80,000b
24,000
24,000
80,000b
25,000
25,000
25,000
25,000
25,000
NAC
NAC
NAC
NAC
NAC
NAC
NAd
NAd
20,000
NAd
NA
8,000
8,000
aApplies only to 25 ppmv level. No impact for 42 ppmv.
bThis interval applies to time between overhaul (TBO).
ฐSteam injection is not available for this model.
dData not available.
5-97
-------
As this table shows, the maintenance impact, if any, varies
from manufacturer to manufacturer and model to model. Some
manufacturers stated that there is no impact on maintenance
intervals associated with water or steam injection for their
turbine models. Data were provided only for operation with
natural gas.
5-98
-------
5-99
-------
5.2 COMBUSTION CONTROLS
The formation of both thermal NOX and fuel NOX depends upon
combustion conditions, so modification of these conditions
affects NOX formation. The following combustion modifications
are used to control NOX emission levels:
1. Lean combustion;
2. Reduced combustor residence time;
3. Lean premixed combustion; and
4. Two-stage rich/lean combustion.
These combustion modifications can be applied singly or in
combination to control NOX emissions.
The mechanisms by which each of these techniques reduce NOX
formation, their applicability to new gas turbines, and the
design or operating factors that influence NOX reduction
performance are discussed below by control technique.
5.2.1 Lean Combustion and Reduced Combustor Residence Time
5.2.1.1 Process Description. Gas turbine combustors were
originally designed to operate with a primary zone equivalence
ratio of approximately 1.0. (An equivalence ratio of 1.0
indicates a stoichiometric ratio of fuel and air. Equivalence
ratios below 1.0 indicate fuel-lean conditions, and ratios above
1.0 indicate fuel-rich conditions.) With lean combustion, the
additional excess air cools the flame, which reduces the peak
flame temperature and reduces the rate of thermal NOX formation.34
In all gas turbine combustor designs, the high-temperature
combustion gases are cooled with dilution air to an acceptable
temperature prior to entering the turbine. This dilution air
rapidly cools the hot gases to temperatures below those required
for thermal NOX formation. With reduced residence time
combustors, dilution air is added sooner than with standard
combustors. Because the combustion gases are at a high
temperature for a shorter time, the amount of thermal NOX formed
decreases.34
Shortening the residence time of the combustion products at
high temperatures may result in increased CO and HC emissions if
5-100
-------
no other changes are made in the combustor. In order to avoid
increases in CO and HC emissions, combustors with reduced
residence time also incorporate design changes in the air
distribution ports to promote turbulence, which improves fuel/air
mixing and reduces the time required for the combustion process
to be completed. These designs may also incorporate fuel/air
premixing chambers. Therefore, the differences between reduced
residence time combustors and standard combustors are the
placement of the air ports, the design of the circulation flow
patterns in the combustor, and a shorter combustor length.34
5.2.1.2 Applicability. Lean primary zone combustion and
reduced residence time combustion have been applied to annular,
can-annular, and silo combustor designs.35'37 Almost all gas
turbines presently being manufactured incorporate lean combustion
and/or reduced residence time to some extent in their combustor
designs, incorporating these features into production models
since 1975.38'39 However, the varying uncontrolled NOX emission
levels of gas turbines shown in Figures 5-2 and 5-3 indicate that
these controls are not incorporated to the same degree in every
gas turbine and may be limited in some turbines by the quantity
of dilution air available for lean combustion.
Lean primary zone and reduced residence time are most
applicable to low-nitrogen fuels, such as natural gas and
distillate oil fuels. These modifications are not effective in
reducing fuel NOX.40
5.2.1.3 Factors Affecting Performance. For a given
combustor, the performance of lean combustion is directly
affected by the primary zone equivalence ratio. As shown in
Figure 4-2, the further the equivalence ratio is reduced below
1.0, the greater the reduction in NOX emissions. However, if the
equivalence ratio is reduced too far, CO emissions increase and
flame stability problems occur.41 This emissions tradeoff
effectively limits the amount of NOX reduction that can be
achieved by lean combustion alone.
5-101
-------
For combustors with reduced residence time, the amount of
NOX emission reduction achieved is directly related to the
decrease in residence time in the high-temperature flame zone.
5.2.1.4 Achievable NO.. Emission Levels Using Lean
Combustion and Reduced Residence Time Combustors. Lean
combustion reduces NOX emissions, and when used in combination
with reduced residence time, NOX emissions are further reduced.
Figure 5-1
5-102
-------
>- 250
200
150
:oo
50
w/o Lean Prirnary Zone
j' Zone
Distillate Oil Fuel
800
1000
1200
1400
1600
1300
Turbine Fifing Temperature,
Figure 5-15. Nitrogen oxide emissions versus turbine firing
temperature for combustors with and without a lean
primary zone.42
5-103
-------
5 shows a comparison of NOX emissions from a combustor with a
lean primary zone and NOX emissions from the same combustor
without a lean primary zone. At the same firing temperature, NOX
emissions reductions of up to 30 percent are achieved using lean
primary zone combustion without increasing CO emissions.
Reducing the residence time at elevated temperatures reduces NOX
emissions. One test at 1065ฐC (1950ฐF) yielded a reduction in
NOX emissions of 40 percent by reducing the residence time.
Carbon monoxide emissions increased from less than 10 to
approximately 30 ppm.42~45
5.2.2 Lean Premixed Combustors
5.2.2.1 Process Description. In a conventional combustor,
the fuel and air are introduced directly into the combustion zone
and fuel/air mixing and combustion take place simultaneously.
Wide variations in the air-to-fuel ratio (A/F) exist, and
combustion of localized fuel-rich pockets produces significant
levels of NOX emissions. In a lean premixed combustor design,
the air and fuel is premixed at very lean A/F's prior to
introduction into the combustion zone. The excess air in the
lean mixture acts as a heat sink, which lowers combustion
temperatures. Premixing results in a homogeneous mixture, which
minimizes localized fuel-rich zones. The resultant uniform,
fuel-lean mixture results in greatly reduced NOX formation
rates.17
To achieve NOX levels below 50 ppmv, referenced to
15 percent 02, the design A/F approaches the lean flammability
limit. To stabilize the flame, ensure complete combustion, and
minimize CO emissions, a pilot flame is incorporated into the
combustor or burner design. In most designs, the relatively
5-104
-------
small amount of air and fuel supplied to this pilot flame is not
premixed and the A/F is nearly stoichiometric, so the pilot flame
temperature is relatively high. As a result, NOX emissions from
the pilot flame are higher than from the lean premixed
combustion.46
Virtually all gas turbine manufacturers have implemented
lean premixed combustion development programs. Three
manufacturers' designs that are available in production turbines
are described below.
The first design uses a can-annular combustor and is shown
in Figure 5-16
5-105
-------
OU1
PRIMARY [~
FUEL NOZZLES ~X
m
LE*N AND E
PREMISING <**
PRIMARY ZONE 5
t
SECONDARY *"
FUEL NOZZLE
(n
PER
"^
'3
CASINO . FLOW SLEEVt
n \ / rr
/ ^
:T^ \^
e^n^ ^-^ CENTERBODY
r * 7
>* J SICONDABY ZONE DILUTION ZONE
-5 s " '"*-%
s
4
^
H
'"TV.
T> /r\
/
/^^^^^^ __
J / LL
/
4 VEMTURI
END COVER
Figure 5-6. Cross-section of a lean premixed can-annular
combustor.
47
5-106
-------
This is a two-stage premixed combustor: the first stage is
the portion of the combustor upstream of the venturi section and
includes the six primary fuel nozzles; the second stage is the
balance of the combustor and includes the single secondary fuel
nozzle.33
The operating modes for this combustor design are shown in
Figure 5-17. For ignition, warmup, and acceleration to
approximately 20 percent load, the first stage serves as the
complete combustor.
5-107
-------
Figure 5-17. Operating modes for a lean premixed can-annular
i i 33
combustor.
5-108
-------
Flame is present only in the first stage, and the equivalence
ratio is kept as low as stable combustion will permit. With
increasing load, fuel is introduced into the secondary stage, and
combustion takes place in both stages. Again, the equivalence
ratio is kept as low as possible in both stages to minimize NOX
emissions. When the load reaches approximately 40 percent, fuel
is cut off to the first stage and the flame in this stage is
extinguished. The venturi ensures the flame in the second stage
cannot propagate upstream to the first stage. When the first-
stage flame is extinguished (as verified by internal flame
detectors) , fuel is again introduced into the first stage, which
becomes a premixing zone to deliver a lean, unburned, uniform
mixture to the second stage. The second stage acts as the
complete combustor in this configuration.33
For operation on distillate oil, fuel is introduced and
burned only in the first stage for ignition and for loads up to
approximately 50 percent. For loads greater than 50 percent,
fuel is introduced and burned in both stages.33
5-109
-------
5-110
-------
Figure 5-18 shows a lean premixed combustor design used by
another manufacturer for an annular combustor.
5-111
-------
1
(D
Ui
M
00
O
O
w
W
U
(D
O
(T
H-
O
%l
U ">
H- ^
? 2
d
(D
Q-
(u
c
M
(U
PRIMARY
AIR
INLET
NATURAL
GAS
INJECTJON
PREMIXINQ
ZONE
SECONDARY
ZONE
O
O
o
o
_TL
PILOT
FUEL
PRIMARY
AIR
SWIRLER
COMBUSTOR
PRIMARY
ZONE
SECONDARY
AIR INJECTION
PORTS
u
rr
H-
O
-------
The air and fuel are premixed using a very lean A/F, and the
resultant uniform mixture is delivered to the primary combustion
zone where combustion is stabilized using a pilot flame. Using
one or more mechanical systems to regulate the airflow delivered
to the combustor, the premix mode is operable for output loads
between 50 and 100 percent. Below 50 percent load, only the
pilot flame is operating, and NOX emissions levels are similar to
those for conventional combustors.46
Another manufacturer's production low-NOx design uses a silo
combustor. Unlike the can-annular and annular designs, the silo
combustor is mounted externally to the turbine and can therefore
be modified without significantly affecting the rest of the
turbine design, provided the mounting flange to the turbine is
unchanged. In addition, this large combustion chamber is fitted
with a ceramic lining that shields the metal surfaces from peak
flame temperatures. This lining reduces the requirement for
cooling air, so more air is available for the combustion
process.17
This silo low-NOx combustor design uses six burners, as
shown in Figure 5-19
5-113
-------
SILO COMBUSTGJX
Figure 5-19. Cross-section of a low NOX silo combustor.
5-114
35,48
-------
For operation on natural gas, each burner serves to premix the
air and fuel to deliver a lean and uniform mixture to the
combustion zone. To achieve the lowest possible NOX emissions,
the A/F of the premixed gases is kept very near the lean
flammability limit and a pilot flame is used to stabilize the
overall combustion process. This burner design is shown in
Figure 5-20
5-115
-------
Figure 5-20. Low-N0x burner for a silo combustor.
5-116
-------
Like the can-annular design, the burner in the silo combustor
cannot operate over the full power range of the gas turbine in
the premix mode due to inability of the premix mode to deliver
suitable A/F's at low power output levels. For this reason, the
burners are designed to operate in a conventional diffusion
burning mode at startup and low power outputs and switch to a
premix burning mode at higher power output levels.
5-117
-------
5-11!
-------
5-119
-------
For operation on distillate oil with the current burner
design, combustion occurs only in a diffusion mode and there is
no premixing of air and fuel.
5.2.2.2 Applicability. As discussed in Section 5.2.2.1,
lean premixed combustors apply to can-annular, annular, and silo
combustors. This combustion modification is effective in
reducing thermal NOX emissions for both natural gas and
distillate oil but is not effective on fuel NOX. Therefore, lean
premixed combustion is not as effective in reducing NOX levels if
high-nitrogen fuels are fired.49
The multiple operating modes associated with the percent
operating load results in "stepped" NOX emission levels. To
date, low NOX emission levels occur only at loads greater than 40
to 75 percent.
Lean premixed combustors currently are available for limited
models from three manufacturers contacted for this study.6'17'24
Two additional manufacturers project an availability date of 1993
or 1994 for lean premixed combustors for some turbine models.11'50
All of these manufacturers state that these lean premixed
combustors will be available for retrofit applications.
5.2.2.3 Factors Affecting Performance. The primary factors
affecting the performance of lean, premixed combustors are A/F
and the type of fuel. To achieve low NOX emission levels, the
A/F must be maintained in a narrow range near the lean
flammability limit of the mixture. Lean premixed combustors are
designed to maintain this A/F at rated load. At reduced load
conditions, the fuel input requirement decreases. To avoid
combustion instability and excessive CO emissions that would
occur as the A/F reaches the lean flammability limit, all
manufacturers' lean premixed combustors switch to a
diffusion-type combustion mode at reduced load conditions,
typically between 40 and 60 percent load. This switchover to a
diffusion combustion mode results in higher NOX emissions.
Natural gas produces lower NOX levels than do oil fuels.
The reasons for this are the lower flame temperature of natural
gas and the ability to premix this fuel with air prior to
5-120
-------
delivery into the second combustion stage. For operation on
liquid fuels, currently available lean premixed combustor designs
require water injection to achieve appreciable NOX reduction.
5.2.2.4 Achievable NO.. Emission Levels. The achievable
controlled NOX emission levels for lean premixed combustors vary
depending upon the manufacturer. At least three manufacturers
currently guarantee NOX emission levels of 25 ppmv, corrected to
15 percent 02 for most or all of their gas turbines for operation
on natural gas fuel without wet injection.6'17'24 Each of these
three manufacturers has achieved controlled NOX emission levels
of less than 10 ppmv at one or more installations in the
United States and/or Europe and guarantee this NOX level for a
limited number of their gas turbine models.51 All three
manufacturers offer gas turbines in the 10+ MW (13,400 hp+) range
and anticipate that guaranteed NOX emission levels of 10 ppmv or
less will be available for all of their gas turbines for
operation on natural gas fuel in the next few years. These
low-NOx combustor designs apply to new turbines and existing
installation retrofits.
For gas turbines in the range of 10 MW (13,400 hp) and
under, one gas turbine manufacturer offers a guarantee for its
lean premixed combustor, without wet injection, of 42 ppmv using
natural gas fuel for two of its turbine models for 1994 delivery.
This manufacturer states that a controlled NOX emission level of
25 ppmv has been achieved by in-house testing, and this 25 ppmv
level firing natural gas fuel is the goal for all of its gas
turbine models, for both new equipment and retrofit
applications.50
These controlled NOX emission levels of 9 to 42 ppmv
correspond to full output load; at reduced loads, the NOX levels
increase, often in "stepped" fashion in accordance with changes
in combustor operation from premixed mode to conventional or
diffusion-mode operation (see Section 5.2.2.3). Figure 5-21
5-121
-------
3flO
220
2W
g 1iO
t ISO
t,ซ
e-i
0 120
n 1tป
t- ao
O
o
11
FUEL
CO
x
a
a
40
_i_
30 4tt 9) bO 70 aO
i GAS TURBINE LOAD
20
O
z
90 'M
200
OIL FUEL
30 ซ SO 60 70 SO 90 [00
% GAS TURBINE LOAD
Figure 5-21.
"Stepped" NOX and CO emissions for a low-NOx
annular combustor burning natural gas and
distillate oil fuels.47
can-
5-122
-------
o
'3
M
1
LLJ
o
a
O Oifluiioii Bumtr Operation
O PIWWJS Burner Operation
with 9H Pilot Ramป
Maximum
Dilution 9
Air-4
Win
Comprซ&ปDr
-------
shows these stepped NOX emissions levels for a can-annular
combustor for natural gas and oil fuel operation. Figure 5-22
5-124
-------
5-125
-------
shows the emissions for a silo combustor operating on natural gas
only.
5-126
-------
pprn
C
o
419
LfJ
4.
X
O
z
2IKi-
iftO-
100-
5(1-
Pilot PueJ OH Row;
i.4
1.8
2 2
2.9
Equivalence Ratio
In Dry E-XhiuM Qfla wltn 15ซii O, by Votyme
Figure 5-23.
Nitrogen oxide emission text results from a lean
premix silo combustor firing fuel oil without wet
injection.53
5-127
-------
The emission levels shown in Figures 5-21 and 5-22 correspond
to full-scale production turbines currently available from the
manufacturers.
Reduced NOX emissions when burning oil fuel in currently
available lean premixed combustor designs have been achieved only
with water or steam injection. With water or steam injection, a
65 ppmv NOX level can be achieved in the turbine with a can-
annular combustor design; a 65 ppmv level can also be met with
water injection in the turbine with a silo combustor at a WFR of
1.4.48'52 This 65 ppmv level for lean premixed combustors is
higher than the controlled NOX levels achieved with water
injection in oil-fired turbines using a conventional combustor
design.
Modification of the existing burner design used in the silo
combustor to allow premixing of the oil fuel with air prior to
combustion is under development. Tests performed using a 12 MW
(16,200 hp) turbine achieved NOX emission levels below 50 ppmv
without wet injection, corrected to 15 percent 02, compared to
uncontrolled levels of 150 ppmv or higher. The NOX levels,
without wet injection, as a function of equivalence ratio are
shown in Figure 5-23. The design equivalence ratio at rated load
is approximately 2.1. As shown in this figure, NOX emissions
below 50 ppmv were achieved at rated power output at pilot fuel
flow levels of 10 percent of the total fuel input.52
Site test data for two turbines using silo-type lean
premixed combustors, as reported by the manufacturer, are shown
in Table 5-12. As this table shows, NOX emission levels as low
as 16.5 ppmv were recorded for using natural gas fuel without
5-12!
-------
TABLE 5-12. MEASURED NOX EMISSIONS FOR COMPLIANCE TESTS
OF A NATURAL GAS-FUELED LEAN PREMIXED COMBUSTOR
WITHOUT WATER INJECTION
,22
Turbine No.
1
1
2
2
1
2
Output, percent of
baseline
107
100
100
75
50
50
NOX emission level,
ppmva
17.7
16.5
24.1
20.4
22.3
22.2
aln dry exhaust with 15 percent 02, by volume.
5-129
-------
water injection. Subsequent emission tests have achieved levels
below 10 ppmv.51 Corresponding data for operation on oil fuel
using only the pilot (diffusion) stage for combustion, and with
water injection, is shown in Table 5-13. Levels of NOX emissions
5-130
-------
TABLE 5-13. MEASURED NOX EMISSIONS FOR OPERATION OF A LEAN
PREMIXED COMBUSTOR DESIGN OPERATING IN DIFFUSION MODE
ON OIL FUEL WITH WATER INJECTION22
Turbine No.
1
2
1
2
1
2
2
Output, percent of
baseload
Peak
Peak
100
100
75
75
50
NOX emission level,
ppmva
69.3
53.6
59.9
51.6
54.3
49.2
54.8
aln dry exhaust with 15 percent 02, by volume.
5-131
-------
at base load for No. 2 fuel oil are between 50 and 60 ppmv.
Based on information provided by turbine manufacturers, the
potential NOX reductions using currently available lean premixed
5-132
-------
5-133
-------
5-134
-------
combustors are shown in Table 5-14. As this table indicates, NOX
emission reductions range from 14.7 tons/yr for a 1.1 MW
(1,480 hp) turbine to 10,400 tons/yr
5-135
-------
TABLE 5-14.
POTENTIAL NOX REDUCTIONS FOR GAS TURBINES USING
LEAN PREMIXED COMBUSTORS
Turbine model
Saturn0
Centaur T-4500C
Centaur "H"c
Taurus0
Mars T-12000C
Mars T-14000C
MS6001B
MS7001E
MS7001F
MS9001E
MS9001F
GT10
GT11N
V84.2
V94.2
V64.3
V84.3C
V94.36
Power
output,
MW
1.1
3.3
4.0
4.5
8.8
10.0
39.0
84.7
161
125
229
22.6
83.3
105
153
61.5
141
204
NOY emissions
Uncontrolled
Gas fuel,
ppmv
99
130
105
114
178
199
148
154
210
161
210
150
390
212
212
380
380
380
Oil fuel,
ppvm
150
179
160
168
267
NAd
267
228
353
241
353
200
560
360
360
530
530
530
Controlled
Gas fuel,
ppmv
42
42
42
42
42
42
25/9e
25/9e
25
25/9e
25
25
25/9e
25/9e
9e
42
42
42
Oil fuel,
ppmv
NAd
NAd
NAd
NAd
NAd
NAd
65
65
65
65
65
42
42
NAf
NAf
NAd
NAd
NAd
NOY reduction
Gas fuel, tons/yra
14.7
59.5
49.8
62.4
212
270
829/937
1,820/2,050
4,540
2,740/3,060
6,500
476
5,070/5,290
3,030/3,290
4,410/4,780
3,210
7,230
10,400
Oil fuel,
tons/yrab
NAd
NAd
NAd
NAd
NAd
NAd
1,139
2,360
5,190
3,490
7,250
620
7,360
NAf
NAf
NAd
NAd
NAd
aBased on 8,000 hours operation per year.
bRequires water or steam injection.
'Scheduled availability is 1994 for natural gas fuel.
dNA = Data not available.
'Standard NOX guarantee is 25 ppmv. Manufacturers offer guaranteed NOX levels as low as 9 ppmv for these
turbines.
'Scheduled availability 1993 for oil fuel without water injection. Reference 17.
5-136
-------
for a 204 MW (274,000 hp) turbine for operation on natural gas
without wet injection. Corresponding NOX emission reductions for
operation on oil fuel, with water injection, range from
620 tons/yr for a 22.6 MW (30,300 hp) turbine to 7,360 tons/yr
for an 83.3 MW (112,000 hp) turbine.
Limited data from two manufacturers showing the impact of
lean premixed combustor designs on CO emissions are shown in
Table 5-15.
5-137
-------
TABLE 5-15. COMPARISON OF NOX AND CO EMISSIONS FOR STANDARD
VERSUS LEAN PREMIXED COMBUSTORS FOR
TWO MANUFACTURERS' TURBINES46'"
GT Model
Centaur H
Mars T- 14000
MS6001B
MS7001E
MS9001E
MS7001F
MS9001F
Emissions, ppmv, referenced to 15 percent O2a
Power
output,
MW
4.0
10.0
39.0
84.7
125
161
229
Standard combustor
NOX
105
199
148
154
161
210
210
CO
15
5.5
10
10
10
25
25
Lean premixed combustor
NOY
25-42
25-42
9
9
9
25
25
CO
50"
50"
25
25
25
15
15
Tor operation at ISO conditions using natural gas fuel.
bMaximum design goal for CO emissions. Most in-house test configurations have achieved CO emission levels between 5
and 25 ppmv.
5-13!
-------
For natural gas-fueled turbines with rated outputs of 10 MW
(13,400 hp) or less, controlled NOX emission levels of 25 to 42
ppmv result in a rise in CO emission levels from 25 ppmv or less
to as high as 50 ppmv.43 For turbines above 10 MW (13,400 hp) ,
controlled NOX emission levels of 9 ppmv result in a rise in CO
emissions from 10 to 25 ppmv for natural gas fuel. Conversely,
for controlled NOX emission levels of 25 ppmv, the CO emissions
drop from 25 to 15 ppmv.51 For one manufacturer's lean premixed
silo combustor design, CO emissions at rated load are less than
5 ppmv, as shown previously in Figure 5-21. This limited data
suggest that the effect of lean premixed combustors on CO
emissions depends upon the specific combustor design and the
controlled NOX emission level.
The emission levels shown in Table 5-15 correspond to rated
power output. Like NOX emission levels, CO emissions change with
changes in combustor operating mode at reduced power output. The
"stepped" effect on CO emissions is shown in Figures 5-21 and
5-22, shown previously.
Operation on oil fuel with wet injection, shown previously
in Figure 5-21, shows CO emission levels of 20 ppmv. Additional
CO emission data were not available for operation on oil fuel
with water injection in lean premixed combustors. Developmental
tests for operation on oil fuel without wet injection in a silo
combustor are presented in Figure 5-24
5-139
-------
3 DC
O
100%
Pilot Fuel Qซl Flow
Q - 100% -
A - 20%
12
Equivalence Ratio
2 k
1.6
"' In DTV ฃ*nซua1 Gas iwllh 15% Oj By
Figure 5-24. The CO emission test results from a lean premix
silo combustor firing fuel oil without wet injection.
5-140
-------
At rated load, shown in this figure at an equivalence ratio of
approximately 2.1, CO emissions are less than 10 ppmv, corrected
to 15 percent 02j
5-141
-------
5-142
-------
5-143
-------
and are in the range of 0 to 2 ppmv for a pilot oil fuel flow of
10 percent (representing 10 percent of the total fuel flow) .53
This 10 percent pilot fuel flow corresponds to controlled NOX
emission levels below 50 ppmv, as shown previously in
Figure 5-22. No data for HC emissions were available for lean
premixed burner designs.
5.2.3 Rich/Ouench/Lean Combustion
5.2.3.1 Process Description. Rich/quench/lean (RQL)
combustors burn fuel-rich in the primary zone and fuel-lean in
the secondary zone. Incomplete combustion under fuel-rich
conditions in the primary zone produces an atmosphere with a high
concentration of CO and hydrogen (H2) . The CO and H2 replace
some of the oxygen normally available for NOX formation and also
act as reducing agents for any NOX formed in the primary zone.
Thus, fuel nitrogen is released with minimal conversion to NOX.
The lower peak flame temperatures due to partial combustion also
reduce the formation of thermal NOX.55
As the combustion products leave the primary zone, they pass
through a low-residence-time quench zone where the combustion
products are rapidly diluted with additional combustion air or
water. This rapid dilution cools the combustion products and at
the same time produces a lean A/F. Combustion is then completed
under fuel-lean conditions. This secondary lean combustion step
minimally contributes to the formation of fuel NOX because most
of the fuel nitrogen will have been converted to N2 prior to the
lean combustion phase. Thermal NOX is minimized during lean
combustion due to the low flame temperature.55
5.2.3.2 Applicability. The RQL combustion concept applies
to all types of gas turbines. None of the manufacturers
contacted for this study, however, currently have this design
available for their production turbines. This may be due to lack
of demand for this design due to the current limited use of
high-nitrogen-content fuels in gas turbines.
5.2.3.3 Factors Affecting Performance. The NOX emissions
from RQL combustors are affected primarily by the equivalence
ratio in the primary combustion zone and the quench airflow rate.
5-144
-------
Careful selection of equivalence ratios in the fuel-rich zone
will minimize both thermal and fuel NOX formation. Further NOX
reduction is achieved with increasing quench airflow rates, which
serve to reduce the equivalence ratio in the secondary (lean)
combustion stage.
5.2.3.4 Achievable N0;: Emissions Levels Using
Rich/Ouench/Lean Combustion. The RQL staged combustion has been
demonstrated in rig tests to be effective in reducing both
thermal NOX and fuel NOX. As shown in Figure 5-25, NOX emissions
are reduced by 40 to 50 percent in a test rig burning diesel
fuel.
5-145
-------
o
J3
c
O
C^
Q
0.7C
0.60
;,so
0.40
0,30
Q.2C
D
V
Uncontrolled
Controlled
1.5
1 .4
1.6 1,7 i.8 i,9 2.0
Primary Zone Eouivalenca Ratio
Figure 5-25.
Nitrogen oxide emissions versus primary zone
equivalence ratio for a rich/quench/lean combustor
firing distillate oil.56
5-146
-------
At an equivalence ratio of 1.8, the NOX emissions can be
reduced from 0.50 to 0.27 Ib/MMBtu by increasing the quench
airflow from 0.86 to 1.4 kg/sec. Data were not available to
convert the NOX emissions figures to ppmv. The effectiveness of
rich/lean staged combustion in reducing fuel NOX when firing
high-FBN fuels is shown in Figure 5-26.
5-147
-------
0,3
c
o
J,
!.0
ฃEli
Distillate Oil
Oil
wt,"
li disci i ,'ซ3 -w
caal-derive-d fuel
Q.27
0-83
1.1
Zone EouiviJenca fiatic
Figure 5-26. Effects of fuel bound nitrogen (FBN) content of NO
emissions for a rich/quench/lean combustor.
57
5-14!
-------
Increasing the FBN content from 0.13 to 0.88 percent has little
impact on the total NOX formation at an operating equivalence
ratio of 1.3 to 1.4. Tests on other rich/lean combustors
indicate fuel nitrogen conversions to NOX of about 7 to
20 percent.58'59 These fuel nitrogen conversions represent a fuel
NOX emission reduction of approximately 50 to 80 percent.
One manufacturer has tested an RQL combustor design in a
4 MW (5,360 hp) gas turbine fueled with a finely ground coal and
water mixture. The coal partially combusts in a fuel-rich zone
at temperatures of 1650ฐC (3000ฐF), with low 02 levels and an
extremely short residence time. The partially combusted products
are then rapidly quenched with water, cooling combustion
temperatures to inhibit thermal NOX formation. Additional
combustion air is then introduced, and combustion is completed
under fuel-lean conditions. In tests at the manufacturer's
plant, cosponsored by the U. S. Department of Energy, a NOX
emission level of 25 ppmv at 15 percent 02 was achieved. This
combustor design can also be used with natural gas and oil fuels.
Single-digit NOX emission levels are reported for operation on
5-149
-------
5-150
-------
natural gas fuel. This combustor design is not yet available for
production turbines.60
5.3 SELECTIVE CATALYTIC REDUCTION
Selective catalytic reduction (SCR) is an add-on NOX control
technique that is placed in the exhaust stream following the gas
turbine. Over 100 gas turbine installations use SCR in the
United States.61 An SCR process description, the applicability
of SCR for gas turbines, the factors affecting SCR performance,
and the achievable NOX reduction efficiencies are discussed in
this section.
5.3.1 Process Description
The SCR process reduces NOX emissions by injecting ammonia
into the flue gas. The ammonia reacts with NOX in the presence
of a catalyst to form water and nitrogen. In the catalyst unit,
the ammonia reacts with NOX primarily by the following
equations:62
NH3 + NO + 1/4 02 - N2 + 3/2 H20; and
NH3 + 1/2 N02 + 1/4 02 - 3/2 N2 + 3/2 H20.
The catalyst's active surface is usually either a noble
metal, base metal (titanium or vanadium) oxide, or a
zeolite-based material. Metal-based catalysts are usually
applied as a coating over a metal or ceramic substrate. Zeolite
catalysts are typically a homogenous material that forms both the
active surface and the substrate. The geometric configuration of
the catalyst body is designed for maximum surface area and
minimum obstruction of the flue gas flow path to maximize
conversion efficiency and minimize back-pressure on the gas
turbine. The most common catalyst body configuration is a
monolith, "honeycomb" design, as shown in Figure 5-27.
5-151
-------
5-152
-------
Figure 5-27. Cutaway view of a typical monolith catalyst body
with honeycomb configuration.
62
5-153
-------
An ammonia injection grid is located upstream of the
catalyst body and is designed to disperse the ammonia uniformly
throughout the exhaust flow before it enters the catalyst unit.
In a typical ammonia injection system, anhydrous ammonia is drawn
from a storage tank and evaporated using a steam- or
electric-heated vaporizer. The vapor is mixed with a pressurized
carrier gas to provide both sufficient momentum through the
5-154
-------
injection nozzles and effective mixing of the ammonia with the
flue gases. The carrier gas is usually compressed air or steam,
and the ammonia concentration in the carrier gas is about
5 percent.62
An alternative to using the anhydrous ammonia/carrier gas
system is to inject an a aqueous ammonia solution. This system
is currently not as common but removes the potential safety
hazards associated with transporting and storing anhydrous
ammonia and is often used in installations with close proximity
to populated areas.61'62
The NH3/NOX ratio can be varied to achieve the desired level
of NOX reduction. As indicated by the chemical reaction
equations listed above, it takes one mole of NH3 to reduce one
mole of NO, and two moles of NH3 to reduce one mole of N02. The
NOX composition in the flue gas from a gas turbine is over
85 percent NO, and SCR systems generally operate with a molar
NH3/NOX ratio of approximately 1.0.63 Increasing this ratio will
further reduce NOX emissions but will also result in increased
unreacted ammonia passing through the catalyst and into the
atmosphere. This unreacted ammonia is known as ammonia slip.
5.3.2 Applicability of SCR for Gas Turbines
Selective catalytic reduction applies to all gas turbine
types and is equally effective in reducing both thermal and fuel
NOX emissions. There are, however, factors that may limit the
applicability of SCR.
An important factor that affects the performance of SCR is
operating temperature. Gas turbines that operate in simple cycle
have exhaust gas temperatures ranging from approximately 450ฐ to
540ฐC (850ฐ to 1000ฐF). Base-metal catalysts have an operating
temperature window for clean fuel applications of approximately
260ฐ to 400ฐC (400ฐ to 800ฐF). For sulfur-bearing fuels that
produce greater than 1 ppm S03 in the flue gas, the catalyst
operating temperature range narrows to 315ฐ to 400ฐC (600ฐ to
800ฐF) . The upper range of this temperature window can be
5-155
-------
increased using a zeolite catalyst to a maximum of 590ฐC
(1100ฐF) ,64
Base metal catalysts are most commonly used in gas turbine
SCR applications, accounting for approximately 80 percent of all
U.S. installations, and operate in cogeneration or combined cycle
applications. The catalyst is installed within the HRSG, where
the heat recovery process reduces exhaust gas temperatures to the
proper operating range for the catalyst. The specific location
of the SCR within the HRSG is application-specific; Figure 5-28
shows two possible SCR locations.
5-156
-------
Figure 5-28. Possible locations for SCR unit in HRSG.
5-157
-------
In addition to the locations shown, the catalyst may also be
located within the evaporator section of the HRSG.
As noted above, zeolite catalysts have a maximum operating
temperature range of up to 590ฐC (1100ฐF), which is compatible
with simple cycle turbine exhaust temperatures. To date,
however, there is only one SCR installation operating with a
zeolite catalyst directly downstream of the turbine. This
catalyst, commissioned in December 1989, has an operating range
of 260ฐ to 515ฐC (500ฐ to 960ฐF) and operates approximately
90 percent of the time at temperatures above 500ฐC (930ฐF) .65
Another consideration in determining the applicability of
SCR is complications arising from sulfur-bearing fuels. The
sulfur content in pipeline quality natural gas is negligible, but
distillate and residual oils as well as some low-Btu fuel gases
such as coal gas have sulfur contents that present problems when
used with SCR systems. Combustion of sulfur-bearing fuels
produces S02 and S03 emissions. A portion of the S02 oxidizes to
S03 as it passes through the HRSG, and base metal catalysts have
an S02-to-S03 oxidation rate of up to five percent.64 In
addition, oxidation catalysts, when used to reduce CO emissions,
will also oxidize S02 to S03 at rates of up to 50 percent.66
Unreacted ammonia passing through the catalyst reacts with
S03 to form ammonium bisulfate (NH4HS04) and ammonium sulfate
[(NH4)2 SOJ in the low-temperature section of the HRSG. The rate
of ammonium salt formation increases with increasing levels of
S03 and NH3, and the formation rate increases with decreasing
5-15!
-------
temperature. Below 200ฐC (400ฐF), ammonium salt formation occurs
with single-digit ppmv levels of S03 and NH3.66
The exhaust temperature exiting the HRSG is typically in the
range of 150ฐ to 175ฐC (300ฐ to 350ฐF), so ammonium salt
formation typically occurs in the low-temperature section of the
HRSG.66 Ammonium bisulfate is a sticky substance that over time
corrodes the HRSG boiler tubes. Additionally, it deposits on
both the boiler and catalyst bed surfaces, leading to fouling and
plugging of these surfaces. These deposits result in increased
back pressure on the turbine and reduced heat transfer efficiency
in the HRSG. This requires that the HRSG be removed from service
periodically to water-wash the affected surfaces. Ammonium
sulfate is not corrosive, but like ammonium bisulfate, it
deposits on the HRSG surfaces and contributes to plugging and
fouling of the heat transfer system.33
Formation of ammonium salts can be avoided by limiting the
sulfur content of the fuel and/or limiting the ammonia slip. Low
S02-to-S03 oxidizing catalysts are also available. Base metal
catalysts are available with oxidation rates of less than
1 percent, but these low oxidation formulas also have lower NOX
reduction activity per unit volume and therefore require a
greater catalyst volume to achieve a given NOX reduction level.
Zeolite catalysts are reported to have intrinsic S02-to-S03
oxidation rates of less than 1 percent.64'66 As stated above,
pipeline-quality natural gas has negligible sulfur content, but
some sources of natural gas contain H2S, which may contribute to
ammonium salt formation. For oil fuels, even the lowest-sulfur
distillate oil or liquid aviation fuel contains sulfur levels
that can produce ammonium salts. According to catalyst vendors,
SCR systems can be designed for 90 percent NOX reduction and
10 ppm or lower NH3 slip for sulfur-bearing fuels up to 0.3
percent by weight.64 Continuous emission monitoring equipment
has been developed for NH3, and may be instrumental in regulating
ammonia injection to minimize slip.67
To date, there is limited operating experience using SCR
with oil-fired gas turbine installations. One combined cycle
5-159
-------
installation using oil fuel, a United Airlines facility in
San Francisco installed in 1985, experienced fuel-related
catalyst problems and now uses only natural gas fuel.33 In the
past, sulfur was found to poison the catalyst material.
Sulfur-resistant catalyst materials are now available, however,
and catalyst formulation improvements have proven effective in
resisting performance degradation with oil fuels in Europe and
Japan, where catalyst life in excess of 4 to 6 years has been
achieved, versus 8 to 10 years with natural gas fuel.64 A
zeolite catalyst installed on a 5 MW (6710 hp) dual fuel
reciprocating engine in the northeastern United States has
operated for over 3 years and burned approximately
600,000 gallons of diesel fuel while maintaining a NOX reduction
efficiency of greater than 90 percent.3
In its guidance to member states, NESCAUM recommends that
SCR be considered for NOX reduction in dual-fueled turbine
applications. There are four combined cycle gas turbines
installations operating with SCR in the northeast United States
burning natural gas as the primary fuel with oil fuel as a
back-up.3 These installations, listed in Table 5-16,
5-160
-------
TABLE 5-16. GAS TURBINE INSTALLATIONS IN THE NORTHEASTERN
UNITED STATES WITH SCR AND PERMITTED FOR
BOTH NATURAL GAS AND OIL FUELS3
Installation
Altresco-Pittsfield
Cogen
Technologies
Ocean State Power
Pawtucket Power
State
MA
NJ
RI
RI
Gas turbine
model
MS6001
MS6001
MS7001E
MS6001
Output,
MWa
38.3
38.3
83.5
38.3
NOX emissions, ppmv (gas fuel/oil fuel)
Uncontrolled*
148/267
148/267
154/277
148/267
Wet
injection*
42/65
42/65
42/65
42/65
Wet
injection
+ SCRC
9/18de
15/65f
9/42f
9/18d
Tower output for a single gas turbine. Installation power output is higher due to multiple units and/or combined
cycle operation.
bPer manufacturer at ISO conditions.
'Operating permit limits.
dThis installation requires the SCR system to be operational when burning oil fuel.
"This installation operated 185 hours on oil fuel in 1991, burning approximately 354,000 gallons of oil fuel.
'Ammonia injection is shut down during operation on oil fuel.
5-161
-------
began operating recently and have limited hours of operation on
oil fuel. As indicated in the table, two of these installations
shut down the ammonia injection when operating on oil fuel to
prevent potential operating problems arising from sulfur-bearing
fuels. Permits issued more recently in this region for other
dual-fuel installations, however, require that the SCR system be
operational on either fuel.3
A final consideration for SCR is catalyst masking or
poisoning agents. Natural gas is considered clean and free of
contaminants, but other fuels may contain agents that can degrade
catalyst performance. For refinery, field, or digester gas fuel
applications, it is important to have an analysis of the fuel and
properly design the catalyst for any identified contaminants.
Arsenic, iron, and silica may be present in field gases, along
with zinc and phosphorus. Catalyst life with these fuels depends
upon the content of the gas and is a function of the initial
5-162
-------
design parameters. With oil fuels, in addition to the potential
for ammonium salt formation, it is important to be aware of heavy
metal content. Particulates in the flue gas can also mask the
catalyst.64
Selective catalytic reduction may not be readily applicable
to gas turbines firing fuels that produce high ash loadings or
high levels of contaminants because these elements can lead to
fouling and poisoning of the catalyst bed. However, because gas
turbines are also subject to damage from these elements, fuels
with high levels of ash or contaminants typically are not used.
Coal, while not currently a common fuel for turbines, has a
number of potential catalyst deactivators. High dust
concentrations, alkali, earth metals, alkaline heavy metals,
calcium sulfate, and chlorides all can produce a masking or
blinding effect on the catalyst. High dust can also erode the
catalyst. Erosion commonly occurs only on the leading face of
the catalyst. Airflow deflectors and dummy layers of catalyst
can be used to straighten out the airflow and reduce erosion.
There is currently no commercial U.S. experience with coal. In
Japan, which burns low-sulfur coal with moderate dust levels,
catalyst life has been 5 years or more without replacement. In
Germany, with high dust loadings, the experience has also been
5 years or more.64
Masking agents deposit on the surface of the catalyst,
forming a barrier between the active catalyst surface and the
exhaust gas, inhibiting catalytic activity. Poisoning agents
chemically react with the catalyst and render the affected area
inactive. Masking agents can be removed by vacuuming or by using
soot blowers or superheated steam. Catalysts cleaned in this
manner can recover greater than 90 percent of the original
reduction activity. The effects of poisoning agents, however,
are permanent and the affected catalyst surface cannot be
regenerated.64
Retrofit applications for SCR may require the addition of a
heat exchanger for simple cycle installations, and replacement or
extensive modification of the existing HRSG in cogeneration and
5-163
-------
combined cycle applications to accommodate the catalyst body.
For these reasons, retrofit applications for SCR could involve
high capital costs.
5.3.3 Factors Affecting SCR Performance
The NOX reduction efficiency for an SCR system is influenced
by catalyst material and condition, reactor temperature, space
velocity, and the NH3/NOX ratio.63 These design and operating
variables are discussed below.
Several catalyst materials are available, and each has an
optimum NOX removal efficiency range corresponding to a specific
temperature range. Proprietary formulations containing titanium
dioxide, vanadium pentoxide, platinum, or zeolite are available
to meet a wide spectrum of operating temperatures. The NOX
removal efficiencies for these catalysts are typically between 80
and 90 percent when new. The NOX removal efficiency gradually
decreases over the operating life of the catalyst due to
deterioration from masking, poisoning, or sintering.63 The rate
of catalyst performance degradation depends upon operating
conditions and is therefore site-specific.
The space velocity (volumetric flue gas flow divided by the
catalyst volume) is an indicator of gas residence time in the
catalyst unit. The lower the space velocity, the higher the
residence time, and the higher the potential for increased NOX
reduction. Because the gas flow is a constant determined by the
gas turbine, the space velocity depends upon the catalyst volume,
or total active surface area. The distance across the opening
between plates or cells in the catalyst, referred to as the
pitch, affects the overall size of the catalyst body. The
smaller the pitch, the greater the number of rows or cells that
can be placed in a given volume. Therefore, for a given catalyst
body size, the smaller the pitch, the larger the catalyst volume
and the lower the space velocity. For natural gas applications
the catalyst pitch is typically 2.5 millimeters (mm) (0.10 inch
[in.]), increasing to 5 to 7 mm (0.20 to 0.28 in.) for coal-fuel
applications.64
5-164
-------
As discussed in Section 5.3.1, the NH3/NOX ratio can be
varied to achieve the desired level of NOX reduction. Increasing
this ratio increases the level of NOX reduction but may also
result in higher ammonia slip levels.
5.3.4 Achievable N0;: Emission Reduction Efficiency Using SCR
Most SCR systems operating in the United States have a space
velocity of about 30,000/hr, a NH3/NOX ratio of about 1.0, and
ammonia slip levels of approximately 10 ppm. The resulting NOX
reduction efficiency is about 90 percent.41 Reduction efficiency
is the level of NOX removed as a percentage of the level of NOX
entering the SCR unit. Only one gas turbine installation in the
United States was identified using only SCR to reduce NOX
emissions. This installation has two natural gas-fired 8.5 MW
gas turbines, each with its own HRSG in which is installed an SCR
system. A summary of emission testing at this site lists NOX
emissions at the inlet to the SCR catalyst at 130 ppmv.
Controlled NOX emissions downstream of the catalyst were 18 ppmv,
indicating a NOX reduction efficiency of 86 percent. Maximum
ammonia slip levels were listed at 35 ppmv.68
All other gas turbine installations identified as using SCR
in the United States use this control method in combination with
wet injection and/or low-NOx combustors. The emission levels
that can be achieved by this combination of controls are found in
Section 5.4.
5.3.5 Disposal Considerations for SCR
The SCR catalyst material has a finite life, and disposal
can pose a problem. The guaranteed catalyst life offered by
catalyst suppliers ranges from 2 to 3 years.64 In Japan, where
SCR systems have been in operation since 1980, experience shows
that many catalysts in operation with natural gas-fired boilers
have performed well for 7 years or longer.63'64 In any case, at
some point the catalyst must be replaced, and those units
containing heavy metal oxides such as vanadium or titanium
potentially could be considered hazardous wastes. While the
amount of hazardous material in the catalyst is relatively small,
the volume of the catalyst body can be quite large, and disposal
5-165
-------
of this waste could be costly. Some suppliers provide for the
removal and disposal of spent catalyst. Precious metal and
zeolite catalysts do not contain hazardous wastes.
5.4 CONTROLS USED IN COMBINATION WITH SCR
With but one exception, SCR units installed in the United
States are used in combination with wet controls or combustion
controls described in Sections 5.1 and 5.2. Wet controls yield
NOX emission levels of 25 to 42 ppmv for natural gas and 42 to
110 ppmv for distillate oil, based on the data provided by gas
turbine manufacturers and shown in Figures 5-10 and 5-11. A
carefully designed SCR system can achieve NOX reduction
efficiencies as high as 90 percent, with ammonia slip levels of
10 ppmv or less for natural gas and low-sulfur (<0.3 percent by
weight) fuel applications.64
As discussed for wet injection in Sections 5.1.4 and
5.2.2.4, controlled NOX emission levels for natural gas range
from 25 to 42 ppmv for natural gas fuel and from 42 to 110 ppmv
for oil fuel. Applying a 90 percent reduction efficiency for
SCR, NOX levels can be theoretically reduced to 2.5 to 4.2 and
4.2 to 11.0 ppmv for natural gas and oil fuels, respectively.
For oil fuels and other sulfur-bearing fuels, a reduction
efficiency of 90 percent requires special design considerations
to address potential operational problems caused by the sulfur
content in the fuel. This subject is discussed in Section 5.3.2
The final controlled NOX emission level depends upon the NOX
level exiting the turbine and the achievable SCR reduction
efficiency.
Test reports provided by SCAQMD include three gas turbine
combined cycle installations fired with natural gas that have
achieved NOX emission levels of 3.4 to 7.2 ppmv, referenced to
15 percent oxygen. The NOX and CO emissions reported for these
tests are shown in Table 5-17
5-166
-------
TABLE 5-17. EMISSIONS TESTS RESULTS FOR GAS TURBINES USING
STEAM INJECTION PLUS SCR
69-71
Test
No.
1
2
3
Gas turbine
model
MS7001E
MS7001E
MS6001B
Output,
MW
82.8
79.7
33.8
Fuel
Natural gas + refinery
gas mixture
Natural gas + refinery
gas + butane mixture
LPG + refinery gas
mixture
NOY emissions, ppmv (Ib/hr)
Uncontrolled
154
148
148
Wet
injection
42
42
42
Wet injection
+ SCR
5.66
(25.2)
7.17
(31.7)
3.36
(5.82)
CO, ppmv
<2.00
<2.00
<2.00
5-167
-------
TABLE 5-18. SUMMARY OF SCR NOY EMISSION REDUCTIONS AND AMMONIA SLIP LEVELS FOR NATURAL'
fift
GAS-FIRED TURBINES
Site
A
B
C
D
E
F
G
H
I
J
K
L
M
Gas turbine
Manufacturer
GE
GE
GE
ABB
GE
GE
GE
Allison
Solar
GE
GE
GE
GE
Model
LM2500
MS5001
LM2500
Type 8
LM2500
MS7001E
LM2500
501-KB
Mars
LM2500
MS7001E
MS6001
MS6001
Power output,
MW
22
18
22
44
22
80
22
3.5
8.5
22
80
37
37
SCR operating
temperature, ฐF
730
645
685
760
680
630
625
650
580
750
754
650
700
Maximum
permit level
for injection,
NH3/NOX molar
ratio
1.0
1.0
1.1
1.2
1.0
1.0
0.9
1.1
1.6
1.0
1.0
1.0
NA
NO emissions, ppmv at 1,5% O
SCR in
50
45
37
27
60
28
68
25
130
37
40
47
33
SCR out
9.0
4.5
8.9
4
12.6
8.4
13.6
1.0
18.2
14.8
6.0
8.9
3.3
Percent
reduction
82
90
76
85
79
70
80
96
86
60
85
81
90
O
2 3
H
fu
cn
Compliance test H
h7-^
NH3 slip, ppmv at
15% (V H
10 ro
2 M
S.
20 m
/U ,_(
CD
9 c
O
7 n
4.1 fD
'O
1 ฐ
1 H
(-1
10 ฃ
35
11 ji
2 E
!-
4 ป
en
8 H
"Calculated from ppmv entering the SCR and percent reduction figures.
bNH3 permit limit. Test emission level not available.
cTest was run at less than permit NH 3/NOx ratio of 1.1. SCR designed for exhaust from total of 5 turbines. Only one turbine operating during test.
dThis site does not use wet injection for gas turbine NO x reduction.
eNH3 compliance test not required. NH 3 level from NH 3 monitor testing.
(D
<
(D
\'
cn
-------
were reported, however, in a summary of emission tests for 13 SCR
installations and are presented in Table 5-18.68 For these
sites, operating on natural gas fuel, the NOX reduction
efficiency of the catalyst ranges
5-169
-------
5-170
-------
from 60 to 96 percent, with most reduction efficiencies between
80 and 90 percent. Ammonia slip levels range from 1 to 35 ppmv.
The site with the 35 ppmv ammonia slip level is unique in that it
is the only site identified in the United States that uses only
SCR rather than a combination of SCR and wet injection to reduce
NOX emissions. With the exception of this site, all NH3 slip
levels in Table 5-18 that are based on test data are less than
10 ppmv. Based on information received from catalyst vendors, it
is expected that an SCR system operating downstream of a gas
turbine without wet injection could be designed to limit ammonia
slip levels to 10 ppmv or less.64 No test data are available for
SCR operation on gas turbines fired with distillate oil fuels.
5.5 EFFECT OF ADDING A DUCT BURNER IN HRSG APPLICATIONS
A duct burner is often added in cogeneration and combined
cycle applications to increase the steam capacity of the HRSG
(see Section 4.2.2). Duct burners in gas turbine exhaust streams
consist of pipes or small burners that are placed in the exhaust
gas stream to allow firing of additional fuel, usually natural
gas. Duct burners can raise gas turbine exhaust temperatures to
1000ฐC (2000ฐF), but a more common temperature is 760ฐC (1400ฐF).
The gas turbine exhaust is the source of oxygen for the duct
burner.
5-171
-------
Figure 5-29 shows a typical natural gas-fired duct burner
5-172
-------
LL
*
3
JltfiYOi
Figure 5-29. Typical duct burner for gas turbine exhaust
application.
72
5-173
-------
installation. Figure 5-30 is a cross-sectional view of one style
QAS
TUHBINi
EXHAUST
GAS
GAS
MANIFOLD
STABILIZER
CASiNG
Figure 5-30. Cross-sectional view of a low-NOx duct burner.
5-174
73,74
-------
of duct burner that incorporates design features to reduce NOX.
In this low-NOx design, natural gas exits the orifice in the
manifold and mixes with the gas turbine exhaust entering through
a small slot between the casing and the gas manifold. This
mixture forms a jet diffusion flame that causes the recirculation
shown in Zone "A." Due to the limited amount of turbine exhaust
that can enter Zone A, combustion in this zone is fuel-rich. As
the burning gas jet exits into Zone "B," it mixes with combustion
products that are recirculated by the flow eddies behind the
wings of the stabilizer casing. The flame then expands into the
turbine exhaust gas stream, where combustion is completed.
5-175
-------
5-176
-------
For oil-fired burners, the design principles of the burner
are the same. However, the physical layout is slightly
different, as shown in
5-177
-------
Figure 5-31. Low-N0x duct burner designed for oil firing.
5-178
73,75
-------
Figure 5-31. Turbine exhaust gas is supplied in
substoichiometric quantities by a slip stream duct to the burner.
This slip stream supplies the combustion air for the fuel-rich
Zone A. The flame shield produces the flow eddies, which
recirculate the combustion products into Zone B.76
Most duct burners now in service fire natural gas. In all
cases, a duct burner will produce a relatively small level of NOX
emissions during operation (See Section 4.2.2), but the net
impact on total exhaust emissions (i.e., the gas turbine plus the
duct burner) varies with operating conditions, and in some cases
may even reduce the overall NOX emissions. Table 5-19 shows the
NOX emissions measured at one site upstream and downstream of a
duct burner. This table shows that NOX emissions are reduced
across the duct burner in five of the eight test runs.
5-179
-------
TABLE 5-19. NO,, EMISSIONS MEASURED BEFORE AND AFTER A DUCT BURNER
Gas turbine operation
Test No.
1
2
3
4
5
6
7
8
Load, MW
33.8
35.0
34.5
32.0
32.8
31.5
33.0
11.1
parameters
Steam/fuel
inj ection
ratio, Ib/lb
0.94
0.97
0.95
0.50
0.46
0.00
0.00
0.00
Duct burner operating
parameters
Heat input,
MM Btu/hr
133.8
93.3
40.8
137.5
43.8
136.7
42.0
140.9
Load, percent
82.1
57.3
25.0
84.4
26.8
83.9
25.8
86.5
Duct burner inlet
NOX, Ib/MM
Btu
0.149
0.142
0.134
0.207
0.228
0.392
0.384
0.157
NO , Ib/hr
61.4
58.8
57.5
85.8
95.2
159.7
166.7
29.1
Duct burner outlet
NOX, Ib/MM
Btu
0.097
0.113
0.118
0.151
0.192
0.270
0.313
0.132
NO , Ib/hr
55.7
58.9
58.7
83.9
94.0
156.2
156.7
42.1
Change across duct burner
NOX, Ib/MM
Btu
-0.043
0.001
0.029
-0.014
-0.027
-0.026
-0.238
0.092
NO , Ib/hr
-5.7
0.1
1.2
-1.9
-1.2
-3.5
-10.0
13.0
Cn
I
CO
o
-------
The reason for this net NOX reduction is not known, but it
is believed to be a result of the reburning process in which the
intermediate combustion products from the duct burner interact
with the NOX already present in the gas turbine exhaust. The
manufacturer of the burner whose emission test results are shown
in Table 5-19 states that the following conditions are necessary
for reburning to occur:
1. The burner flame must produce a high temperature in a
fuel-rich zone;
2. A portion of the turbine exhaust containing NOX must be
introduced into the localized fuel-rich zone with a residence
time sufficient for the reburning process to convert the turbine
NOX to N2 and 02; and
3. The burner fuel should contain no FBN.78
In general, sites using a high degree of supplementary
firing have the highest potential for a significant amount of
reburning. In practice, only a limited number of sites achieve
these reburning conditions due to specific plant operating
requirements .78
5-181
-------
5-182
-------
5 . 6 ALTERNATE FUELS
Because thermal NOX production is an exponential function of
flame temperature (see Section 4.1.1), it follows that using
fuels with flame temperatures lower than those of natural gas or
distillate oils results in lower thermal NOX emissions.
Coal-derived gas and methanol have demonstrated lower NOX
emissions than more conventional natural gas or oil fuels. For
applications using fuels with high FBN contents, switching to a
fuel with a lower FBN content will reduce thermal NOX formation
and thereby lower total NOX emissions.
5.6.1 Coal-Derived Gas
Combustor rig tests have demonstrated that burning
coal-derived gas (coal gas) that has been treated to remove FBN
produces approximately 30 percent of the NOX emission levels
experienced when burning natural gas. This is because coal gas
has a low heat energy level of around 300 Btu or less, which
results in a flame temperature lower than that of natural gas.79
The cost associated with producing coal gas suitable for
combustion in a gas turbine has made this alternative
economically unattractive, but recent advances in coal
gasification technology have renewed interest in this fuel.
A coal gas-fueled power plant is currently operating in the
United States at a Dow Chemical plant in Placquemine, Louisiana.
This facility operates with a subsidy from the Federal
Government, which compensates for the price difference between
coal gas and conventional fuels. Several commercial projects
have been recently announced using technology developed by
Texaco, Shell, Dow Chemical, and the U.S. Department of Energy.
Facilities have been permitted for construction in Massachusetts
and Delaware.80
A demonstration facility, known as Cool Water, operated
using coal gas for 5 years in Southern California in the early
1980's. The NOX emissions were reported at 0.07 lb/MMBtu.80 Fuel
analysis data is not available to convert this NOX emission level
to a ppmv figure. No other emissions data are available.
5-183
-------
5.6.2 Methanol
Methanol has a flame temperature of 1925ฐC (3500ฐF) versus
2015ฐC (3660ฐF) for natural gas and greater than 2100ฐC (3800ฐF)
for distillate oils. As a result, the NOX emission levels when
burning methanol are lower than those for either natural gas or
distillate oils.
Table 5-20 presents NOX emission data for a full-scale
turbine firing methanol.
5-184
-------
TABLE 5-20. NCL EMISSIONS TEST DATA FOR A GAS TURBINE
FIRING METHANOL AT BASELOAD
a,81
Test
A
B
C
D
E
F
G
H
I
J
K
L
M
AVERAGE
N
0
P
Q
W/F ratio,
Ib/lb
0
0
0
0
0
0
0
0
0
0
0
0
0
0.11
0.23
0.23
0.24
NOX emissions
ISO
conditions,
ppm at 15% 0,
41
45
48
49
60
47
53
48
51
52
41
47
48
49
28
17
18
18
NOX reduction,
percent13
0
0
0
0
0
0
0
0
0
0
0
0
0
42.2
65.2
62.7
62.7
Caseload = 25 MW output
Calculated using the average of the uncontrolled emissions
5-185
-------
The NOX emissions from firing methanol without water injection
ranged from 41 to 60 ppmv and averaged 49 ppmv. This test also
indicated that methanol increases turbine output due to the
higher mass flows that result from methanol firing. Methanol
firing increased CO and HC emissions slightly compared to the
same turbine's firing distillate oil with water injection. All
other aspects of turbine performance were as good when firing
methanol as when the turbine fired natural gas or distillate
oil.82 Turbine maintenance requirements were estimated to be
lower and turbine life was estimated to be longer on methanol
fuel than on distillate oil fuel because methanol produced fewer
deposits in the combustor and power turbine.
Table 5-20 also presents NOX emission data for methanol
firing with water injection. At water-to-fuel ratios from
0.11 to 0.24, NOX emissions when firing methanol range from 17 to
28 ppmv, a reduction of 42 to 65 percent.
In a study conducted at an existing 3.2 MW gas turbine
installation in 1984, a gas turbine was modified to burn
methanol. This study was conducted at the University of
California at Davis and was sponsored by the California Energy
Commission. A new fuel delivery system for methanol was
required, but the only major modifications required for the
turbine used in this study were new fuel manifolds and nozzles.
Tests conducted burning methanol showed no visible smoke
emissions, and only minor increases in CO emissions. Figure 5-32
shows the NOX emissions measured while burning
5-186
-------
at
uo
100
eo
so
40
O Methanol
Q Natural Gas
17
16
15
4
J
2
1
0
L.OOO
J.OOO
LOAD
Figure 5-32. Influence of load on NOX, and C02 emissions for
methanol and natural gas.
83
5-187
-------
methanol and natural gas. Reductions of up to 65 percent were
achieved, as NOX emissions were 22 to 38 ppm when burning
methanol versus
5-1!
-------
5-189
-------
62 to 100 ppm for natural gas. In addition to the intrinsically
lower NOX production, water can be readily mixed with methanol
prior to delivery to the turbine to obtain the additional NOX
reduction levels achievable with wet injection. Gas turbine
performance characteristics, including startup, acceleration,
load changes, and full load power, were all deemed acceptable by
the turbine manufacturer.83
The current economics of using methanol as a primary fuel
are not attractive. There are no confirmed commercial
methanol-fueled gas turbine installations in the United States.
5.7 SELECTIVE NONCATALYTIC REDUCTION
Selective noncatalytic reduction (SNCR) is an add-on
technology that reduces NOX using ammonia or urea injection
similar to SCR but operates at a higher temperature. At this
higher operating temperature of 870ฐ to 1200ฐC (1600ฐ to 2200ฐF) ,
the following reaction occurs:84
NOX + NH3 + 02 + H20 + (H2) - N2 + H20.
This reaction occurs without requiring a catalyst,
effectively reducing NOX to nitrogen and water. The operating
temperature can be lowered from 870ฐC (1600ฐF) to 700ฐC (1300ฐF)
by injecting hydrogen (H2) with the ammonia, as is shown in the
above equation.
Above the upper temperature limit, the following reaction
occurs:84
NH3 + 02 - NOX + H20.
Levels of NOX emissions increase when injecting ammonia or
urea into the flue gas at temperatures above the upper
temperature limits of 1200ฐC (2200ฐF).
Since SNCR does not require a catalyst, this process is more
attractive than SCR from an economic standpoint. The operating
temperature window, however, is not compatible with gas turbine
exhaust temperatures, which do not exceed 600ฐC (1100ฐF).
Additionally, the residence time required for the reaction is
approximately 100 milliseconds, which is relatively slow for gas
turbine operating flow velocities.85
5-190
-------
It may be feasible, however, to initiate this reaction in
the gas turbine where operating temperatures fall within the
reaction window, if suitable gas turbine modifications and
injection systems can be developed.85 This control technology
has not been applied to gas turbines to date.
5 . 8 CATALYTIC COMBUS TION
5.8.1 Process Description
In a catalytic combustor, fuel and air are premixed into a
fuel-lean mixture (fuel/air ratio of approximately 0.02) and then
pass into a catalyst bed. In the bed, the mixture oxidizes
without forming a high-temperature flame front. Peak combustion
temperatures can be limited to below 1540ฐC (2800ฐF), which is
below the temperature at which significant amounts of thermal NOX
begin to form.86 An example of a lean catalytic combustor is
shown in Figure 5-33.
5-191
-------
Cn
I
CD
ui
oo
ui
CD
(u
o
(U
ft
(U
ft
H-
O
O
(T
O
FUEL VAPOR HAT IOMS MIXING ZONE COMBUSTION ZONE
DILUTION
AIR
J M
CERAMIC
LINED
CATALYST
BED
i \
.t >
DILUTION
ZONE
i M
M
00
-J
-------
CO
1
CD
Ul
CO
H-
o
tf
I CD
I 1 fjj
o
(U
ft
(U
ft
H-
O
O
I
c
u
(T
O
FUEL-RICH
PftlHARY AIR
V
FIRST-STAGE
CATALYST
TOBCH /
IGH1TOR
PR1MARV A1K
SECOND-STAGE
CATALYST
FUEL-LEAN MIXTURE
x- FUO
-------
Catalytic combustors can also be designed to operate in a
rich/lean configuration, as shown in Figure 5-34. In this
configuration, the air and fuel are premixed to form a fuel-rich
mixture, which passes through a first stage catalyst where
combustion begins. Secondary air is then added to produce a lean
mixture, and combustion is completed in a second stage catalyst
bed.89
5.8.2 Applicability
Catalytic combustion techniques apply to all combustor types
and are effective on both distillate oil- and natural gas-fired
turbines. Because of the limited operating temperature range,
catalytic combustors may not be easily applied to gas turbines
subject to rapid load changes (such as utility peaking
turbines) .90 Gas turbines that operate continuously at base load
(such as industrial cogeneration applications) would not be as
adversely affected by any limits on load following capability.91
5.8.3 Development Status
Presently, the development of catalytic combustors has been
limited to bench-scale tests of prototype combustors. The major
problem is the development of a catalyst that will have an
acceptable life in the high-temperature and -pressure environment
5-194
-------
5-195
-------
of gas turbine combustors. Additional problems that must be
solved are combustor ignition and how to design the catalyst to
operate over the full gas turbine operating range (idle to full
load) ,92
5.9 OFFSHORE OIL PLATFORM APPLICATIONS
Gas turbines are used on offshore platforms to meet
compression and electrical power requirements. This application
presents unique challenges for NOX emissions control due to the
duty cycle, lack of a potable water source for wet injection, and
limited space and weight considerations. The duty cycle for
electric power applications of offshore platforms is unique.
This duty cycle is subject to frequent load changes that can
instantaneously increase or decrease by as much as a factor of
10.93 Fluctuating loads result in substantial swings in turbine
exhaust gas temperatures and flow rates. This presents a problem
for SCR applications because the NOX reduction efficiency depends
upon temperature and space velocity (see Section 5.3.3).
The lack of a potable water supply means that water must be
shipped to the platform or sea water must be desalinated and
treated. The limited space and weight requirements associated
with an SCR system may also have an impact on capital costs of
the platform.
A 4-year study is underway for the Santa Barbara County Air
Pollution Control Board to evaluate suitable NOX control
techniques for offshore applications. The goals of the study are
to reduce turbine NOX emissions at full load to 9 ppmv, corrected
to 15 percent 02, firing platform gas fuel and to achieve part
load reductions of 50 percent. The study consists of two phases.
The first phase, an engineering evaluation of available and
emerging emission control technologies, is completed. The second
phase will select the final control technologies and develop
these technologies for offshore platform applications. Phase I
5-196
-------
of this study concludes that the technologies with the highest
estimated probability for success in offshore applications are:
- Water injection plus SCR (80 percent);
- Methanol fuel plus SCR (70 percent);
- Lean premixed combustion plus SCR (65 percent); and
- Steam dilution of fuel prior to combustion plus SCR
(65 percent) .
A key conclusion drawn from Phase I of this study is that
none of the above technologies or combination of technologies in
offshore platform applications currently has a high probability
of successfully achieving the NOX emission reduction goals of
this study without substantial cost and impacts to platform and
turbine operations, added safety considerations, and other
environmental concerns. These issues will be further studied in
Phase II for the above control technologies.
5.10 REFERENCES FOR CHAPTER 5
1. National Archives and Records Administration. Code of
Federal Regulations. 40 CFR 60.332. Subpart GG.
Washington, B.C. Office of the Federal Register. July
1989.
2. South Coast Air Quality Management District. Emissions of
Oxides of Nitrogen from Stationary Gas Turbines. Rule 1134.
Los Angeles. August 4, 1989.
3. Letter and attachments from Conroy, D. B., U.S. EPA Region
I, to Neuffer, W. J., EPA/ISB. January 15, 1992. Review of
draft gas turbine ACT document.
4. Northeast States For Coordinated Air Use Management.
Recommendation On NOX RACT for Industrial Boilers, Internal
Combustion Engines and Gas Turbines. September 18, 1992.
5. Letter and attachment from Leonard, G. L., General Electric
Company, to Snyder, R. B., MRI. February 1991. Response to
gas turbine questionnaire.
6. Letters and attachments from Schorr, M., General Electric
Company, to Snyder, R. B., MRI. March, April 1991.
Response to gas turbine questionnaire.
7. Letter and attachments from Gurmani, A., Asea Brown Boveri,
to Snyder, R. B., MRI. February 4, 1991. Response to gas
turbine questionnaire.
5-197
-------
8. Letter and attachment from Swingle, R., Solar Turbines
Incorporated, to Snyder, R. B., MRI. February 1991.
Response to gas turbine questionnaire.
9. Letter and attachment from Kimsey, D. L., Allison Gas
Turbine Division of General Motors, to Snyder, R. B., MRI.
February 1991. Response to gas turbine questionnaire.
10. Letter and attachment from Kraemer, H., Siemens Power
Corporation, to Snyder, R. B., January 1991. Response to
gas turbine questionnaire.
11. Letter and attachments from Antos, R. J., Westinghouse
Electric Corporation, to Neuffer, W. J., EPA. September 11,
1991. Review of Draft Gas Turbine ACT document.
12. Letter and attachment from Bogus, A. S., Garrett Turbine
Engine Company, to Dalrymple, D., Radian Corporation.
April 13, 1983. Stationary gas turbines. p. 7.
13. General Electric Company. General Electric Heavy-Duty Gas
Turbines. Schenectady, New York. 1983. Section 6.
14. Letter from Dvorak, United Technologies Corporation, Power
Systems Division, to Goodwin, D. R., EPA. April 7, 1978.
Limits on water used for injection into the FT4 gas turbine
combustion chamber to control emissions.
15. Letter and attachments from Solt, J. C., Solar Turbines
Incorporated, to Noble, E., EPA. August 23, 1983. NSPS
review.
16. General Motors. General Motors Response to Four-Year Review
Questions on the NSPS for Stationary Gas Turbines.
Submitted to U. S. Environmental Protection Agency.
Research Triangle Park, NC. July 5, 1983. 144 Federal
Register 176. September 10, 1979. 52 pp.
17. Letter and attachments from Rosen, V., Siemens AG, to
Neuffer, W. J., EPA/ISB. August 30, 1991. Review of Draft
Gas Turbine ACT document.
18. Letter and attachments from Sailer, E. D., General Electric
Marine and Industrial Engines, to Neuffer, W. J., EPA/ISB.
August 29, 1991. Review of Draft Gas Turbine ACT document.
19. Letter and attachments from Mincy, J. E., Nalco Fuel Tech,
to Neuffer, W.J., EPA/ISB. September 9, 1991. Review of
draft gas turbine ACT document.
5-19!
-------
20. U. S. Environmental Protection Agency. Background
Information Document, Review of 1979 Gas Turbine New Source
Performance Standard. Research Triangle Park, NC. Prepared
by Radian Corporation under Contract No. 68-02-3816. 1985.
p. 4-36.
21. Letters and attachments from Leonard, G. L., General
Electric Company, to Snyder, R. B., MRI. May 24, 1991.
Response to gas turbine questionnaire.
22. Telecon. Snyder, R., MRI, with Rayome, D., U.S. Turbine
Corporation. May 23, 1991. Gas turbine NOX control and
maintenance impacts.
23. Letter and attachment from Gurmani, A., Asea Brown Boveri,
to Snyder, R. B., MRI. May 30, 1991. Response to gas
turbine questionnaire.
24. Letter and attachments from van der Linden, S., Asea Brown
Boveri, to Neuffer, W. J., EPA/ISB. September 16, 1991.
Review of draft gas turbine ACT document.
25. Wilkes, C., and R. C. Russell (General Electric Company).
The Effects of Fuel Bound Nitrogen Concentration and Water
Injection on NOX Emissions from a 75 MW Gas Turbine.
Presented at the Gas Turbine Conference & Products Show.
London, England. April 9-13, 1978. ASME Paper No.
78-GT-89. p. 1.
26. Reference 20, pp. 4-33, 4-34.
27. Reference 20, pp. 4-39 through 4-47.
28. Letter and attachments from Valentine, J. M., Energy and
Environmental Partners, to Neuffer, W. J., EPA/ISB.
April 26, 1991. Control of NOX emissions using water-in-oil
emulsions.
29. Reference 20, pp. 4-48 thru 4-50.
30. Sailer, E. D. NOX Abatement With Steam Injection on
Aircraft Derivative Gas Turbines. General Electric Marine
and Industrial Engines. Presented to the American
Cogeneration Association. Scottsdale, AZ. March 13, 1989.
5 pp.
31. Becker, E., M. Kosanovich, and G. Cordonna. Catalyst Design
for Emission Control of Carbon Monoxide and Hydrocarbons
From Gas Engines. Johnson Matthey. Wayne, PA. For
presentation at the 81st Annual Air Pollution Control
Association meeting. Dallas. June 19-24, 1988. 16 pp.
32. Reference 20, p. 4-51.
5-199
-------
33. Schorr, M. NOX Control for Gas Turbines: Regulations and
Technology. General Electric Company. Schenectady, NY.
For presentation at the Council of Industrial Boiler Owners
NOX Control IV Conference. February 11-12, 1991. 11 pp.
34. Reference 20, pp. 4-2 thru 4-5.
35. Maghon, H., and A. Krutzer (Siemens Product Group KWU,
Muelheim, Germany) and H. Termuehlen (Utility Power
Corporation, Bradenton, FL) . The V84 Gas Turbine Designed
for Reliable Base Load and Peaking Duty. Presented at the
American Power Conference. Chicago. April 18-20, 1988.
20 pp.
36. Meeting. Barnett, K., Radian Corporation, to File.
February 6, 1984. Discuss Rolls-Royce Emission Testing
Procedures and Low-N0x Combustors. p. 3.
37. U. S. Environmental Protection Agency. Standards Support
and Environmental Impact Statement. Volume 1: Proposed
Standards of Performance for Stationary Gas Turbines.
Research Triangle Park, NC. Publication No.
EPA 450/2-77-017a. September 1977. pp. 4-48 - 4-83.
38. Touchton, G. L., J. F. Savelli, and M. B. Hilt (General
Electric Company, U.S.A.). Emission Performance and Control
Techniques for Industrial Gas Turbines. Schenectady,
New York. Gas Turbine Reference Library No. GER-2486H.
1982. p. 351.
39. Johnson, R. H. and C. Wilkes (General Electric Company).
Emissions Performance of Utility and Industrial Gas
Turbines. Presented at the American Power Conference.
April 23-25, 1979. Schenectady, New York. p. 5.
40. Reference 20, p. 4-5.
41. Angello, L. (Electric Power Research Institute, Palo Alto,
CA) and P. Lowe (InTech, Inc., Potomac, MD) . Gas Turbine
Nitrogen Oxide (NOX) Control. Current Technologies and
Operating Combustion Experiences. Presented at the 1989
Joint Symposium on Stationary NOX Control. San Francisco.
March 6-9, 1989. 18 pp.
42. Guthan, D. C. and C. Wilkes (General Electric Company,
U.S.A.). Emission Control and Hardware Technology.
Schenectady, New York. Gas Turbine Reference Library
No. GERP3125. 1981. p. 4.
43. Letter and attachments from Malloy, M. K., Rolls-Royce
Limited, to Jennings, M., Radian Corporation. May 12, 1983.
8 pp. Response to questionnaire concerning emission levels
of Rolls-Royce gas turbines and of emission control
techniques offered.
5-200
-------
44. McKnight, D. (Rolls-Royce Limited). Development of a
Compact Gas Turbine Combustor to Give Extended Life and
Acceptable Exhaust Emissions. Journal of Engineering for
Power. 101(3):101. July 1979.
45. Reference 36, Attachment 1.
46. Smith, K. 0., and P. B. Roberts. Development of a Low NOX
Industrial Gas Turbine Combustor. Solar Turbines Inc. San
Diego, CA. Presented at the Canadian Gas Association
Symposium on Industrial Application of Gas Turbines. Banff,
Alberta. October 16-18, 1991. 18 pp.
47. Letter and attachments from Cull, C., General Electric
Company, to Snyder, R. B., MRI. April 1991. Response to
request for published General Electric Company presentation
materials.
48. Maghon, H., and L. Schellhorn (Siemens Product Group KWU,
Muelheim, Germany); J. Becker and J. Kugler (Delmorva
Power & Light Company, Wilmington, DE); and H. Termuehlen
(Utility Power Corporation, Bradenton, FL). Gas Turbine
Operating Performance and Considerations for Combined Cycle
Conversion at Hay Road Power Station. Presented at the
American Power Conference. Chicago. April 23-25, 1990.
12 pp.
49. Reference 20, p. 4-10.
50. Letter and attachments from Swingle, R., Solar Turbines
Incorporated, to Snyder, R., MRI. May 21, 1991. Low-N0x
gas turbine information.
51. Smock, R. Utility Generation Report - Gas turbines reach
9 ppm nitrogen oxide emissions dry. Power Engineering.
96.O) :10. March 1992.
52. Davis, L. Dry Low NOX Combustion Systems for GE Heavy-Duty
Gas Turbines. General Electric Company. Schenectady, NY.
Presented at 35th GE Turbine Sate-of-the-Art Technology
Seminar. August 1991. 10 pp.
53. Magnon, H., and P. Berenbrink (Siemens KWU) and
H. Termuehlen and G. Gartner (Siemens Power Corporation).
Progress in NOX and CO Emission Reduction of Gas Turbines.
Presented at the Joint American Society of Mechanical
Engineers/Institute of Electronic and Electrical Engineers
Power Generation Conference. Boston. October 21-25, 1990.
7 pp.
54. Letter and attachments from King, D., General Electric
Industrial Power Systems Sales, to Snyder, R. B., MRI.
August 25, 1992. Performance and emission levels for
industrial gas turbines.
5-201
-------
55. Cutrone, M., and M. Hilt (General Electric Company,
Schenectady, NY); A. Goyal and E. Ekstedt (General Electric
Company, Evandale, OH) ; and J. Notardonato (NASA/Lewis
Research Center, Cleveland, OH) . Evaluation of Advanced
Combustors for Dry NOX Suppression With Nitrogen Bearing
Fuels in Utility and Industrial Gas Turbines. Journal of
Engineering for Power. 104:429-438. April 1982.
56. Stambler, I. Strict NOX Codes Call for Advanced Control
Technology. Gas Turbine World. 13(4):58.
September-October 1983. p. 58.
57. Novick, A. S., and D. L. Troth (Detroit Diesel Allison) and
J. Notardonato (NASA Lewis Research Center.) Multifuel
Evaluation of Rich/Quench/Lean Combustor. ASME Paper No.
83-GT-140. p. 6.
58. Lew, H. G. (Westinghouse Electric Company) et al. Low NOX
and Fuel Flexible Gas Turbine Combustors. Presented at the
Gas Turbine Conference & Products Show. Houston, TX.
March 9-12, 1981. ASME Paper No. 81-GT-99. p. 10.
59. McVey, J. B., R. A. Sederquist, J. B. Kennedy, and L. A.
Angello (United Technologies Research Center). Testing of a
Full-Scale Staged Combustor Operating with a Synthetic
Liquid Fuel. ASME Paper No. 83-GT-27. p. 8.
60. Allison-DOE Run Gas Turbine Directly on Pulverized Coal. Gas
Turbine World. ฃ1_(6):39. November-December 1991.
61. Minutes of meeting dated February 5, 1992, among
representatives of the Institute of Clean Air Companies
(formerly Industrial Gas Cleaning Institute), U.S.
Environmental Protection Agency, and Midwest Research
Institute. December 10, 1991. Review of draft gas turbine
ACT document.
62. Radian Corporation. Evaluation of Oil-Fired Gas Turbine
Selective Catalytic Reduction (SCR) N02 Control. Prepared
for the Electric Power Research Institute, Palo Alto, CA,
and the Gas Research Institute (Chicago). EPRI GS-7056.
December 1990. pp. 4-7.
63. Benson, C., G. Chittick, and R. Wilson. (Arthur D. Little,
Inc.). Selective Catalytic Reduction Technology for
Cogeneration Plants. Prepared for New England Cogeneration
Association. November 1988. 54 pp.
64. Letter and attachments from Smith, J. C., Institute of Clean
Air Companies, to Neuffer, W. J., EPA/ISB. May 14, 1992.
Response to EPA questionnaire regarding flue gas treatment
processes for emission reductions dated March 12, 1992.
5-202
-------
65. Letter and attachments from Craig, R. J., Unocal Science and
Technology Division of Unocal Corporation, to Lee, L.,
California Air Resources Board. July 24, 1991. Gas turbine
SCR installation experience and information.
66. May, P. A., L. M. Campbell, and K. L. Johnson (Radian
Corporation). Environmental and Economic Evaluation of Gas
Turbine SCR NOX Control. Research Triangle Park, NC.
Presented at the 1991 Joint EPRI/EPA Symposium for
Stationary Combustion NOX Control. March 1991. Volume 2.
18 pp.
67. Durham, M. D., T. G. Ebner, M. R. Burkhardt, and F. J.
Sagan. Development of An Ammonia Slip Monitor for Process
Control of NH3 Based NOX Control Technologies. ADA
Technologies, Inc. Presented at the Continuous Emission
Monitoring Conference, Air and Waste Management Association.
Chicago. November 12-15, 1989. 18 pp.
68. Field Survey of SCR Gas Turbine Operating Experience.
Prepared for the Electric Power Research Institute. Palo
Alto, CA. May, 1991.
69. Harris, B., and J. Steiner (Pope and Steiner Environmental
Services). Source Test Report. South Coast Air Quality
Management District. Los Angeles. PS-90-2107. April 11,
1990.
70. Harris, B., and J. Steiner (Pope and Steiner Environmental
Services). Source Test Report. South Coast Air Quality
Management District. Los Angeles. PS-90-2108. April 12,
1990.
71. Harris, B., and J. Steiner (Pope and Steiner Environmental
Services). Source Test Report. South Coast Air Quality
Management District. Los Angeles. PS-90-2148. May 1,
1990.
72. Reference 20, pp. 3-20.
73. Letter and attachments from Brown, R., Coen Company, Inc.,
to Dalrymple, D., Radian Corporation. August 16, 1983.
Duct Burner Emissions in Turbine Exhaust Gas Streams.
74. Reference 20, p. 3-21.
75. Reference 20, p. 3-22.
76. Reference 20, pp. 3-19, 4-79, 4-80.
77. Podlensky, J., et al. (GCA Corporation). Emission Test
Report, Crown Zellerbach, Antioch, CA. March 1984.
5-203
-------
78. Backlund, J., and A. Spoormaker. Experience with NOX
Formation/Reduction Caused by Supplementary Firing of
Natural Gas in Gas Turbine Exhaust Streams. The American
Society of Mechanical Engineers. New York. 85-JPGC-G7-18.
1985. 5 pp.
79. Reference 36, pp. 3-93, 3-94.
80. Smock, R. Coal Gas-fired Combined Cycle Projects Multiply.
Power Engineering. 135(2) :32-33. February 1991.
81. Weir, A., Jr., W. H. von KleinSmid, and E. A. Danko
(Southern California Edison Company). Test and Evaluation
of Methanol in a Gas Turbine System. Prepared for Electric
Power Research Institute. Palo Alto California.
Publication No. EPRI AP-1712. February 1981.
pp. A-76 through A-78.
82. Reference 81, pp. 5-1, 5-2.
83. Shore, D., and G. Shiomoto (KVB, Incorporated, Irvine, CA)
and G. Bemis (California Energy Commission, Sacramento, CA).
Utilization of Methanol as a Fuel for a Gas Turbine
Cogeneration Plant. Prepared for Electric Power Research
Institute. Chicago. CS-4360, Volume II, EPA Contract
No. 68-02-3695. January 1986.
84. Fellows, W. D. Experience with the Exxon Thermal DeNOx
Process in Utility and Independent Power Production Exxon
Research and Engineering Company. Florham Park, NJ. August
1990. 5 pp.
85. Bernstein, S., and P. Malte (Energy International, Inc.).
Emissions Control for Gas Transmission Engines. Prepared
for the Gas Research Institute. Chicago. Presentation
No. PRES 8070. July 1989. 17 pp.
86. Krill, W. V., J. P. Kesselring, and E. K. Chu (Acurex
Corporation). Catalytic Combustion for Gas Turbine
Applications. Presented at the Gas Turbine Conference &
Exhibit & Solar Energy Conference. San Diego, CA.
March 12-15, 1979. ASME Paper No. 79-GT-188. p. 4.
87. Reference 58, p. 6.
88. Reference 86, p. 8.
89. Washam, R. M. (General Electric Company). Dry Low NOX
Combustion System for Utility Gas Turbine. Presented at the
1983 Joint Power Generation Conference. Indianapolis, IN.
ASME Paper No. 83-JPGC-GT-13. p. 1.
90. Reference 86, p. 7.
5-204
-------
91. Reference 20, p. 4-23.
92. Reference 37, p. 4-88
93. Little, A.D. Offshore Gas Turbine NOX Control Technology
Development Program. Phase I--Technology Evaluation.
Prepared for Santa Barbara County Air Pollution Control
Board. August 1989. 130 pp.
5-205
-------
6.0 CONTROL COSTS
Capital and annual costs are presented in this chapter for
the nitrogen oxide (NOX) control techniques described in
Chapter 5.0. These control techniques are water and steam
injection, low-NOx combustion, and selective catalytic
reduction (SCR) used in combination with these controls. Model
plants were developed to evaluate the control techniques for a
range of gas turbine sizes, fuel types, and annual operating
hours. The gas turbines chosen for these model plants range in
size from 1.1 to 160 megawatts (MW) (1,500 to 215,000 horsepower
[hp]) and include both aeroderivative and heavy-duty turbines.
Model plants were developed for both natural gas and distillate
oil fuels. For offshore oil production platforms, cost
information was available only for one turbine model.
The life of the control equipment depends upon many factors,
including application, operating environment, maintenance
practices, and materials of construction. For this study, a
15-year life was chosen.
Both new and retrofit costs are presented in this chapter.
For water and steam injection, these costs were assumed to be the
same because most of the water treatment system installation can
be completed while the plant is operating and because gas turbine
nozzle replacement and piping connections to the treated water
supply can be performed during a scheduled downtime for
maintenance. Estimated costs are provided for both new and
retrofit low-NOx combustion applications. No SCR retrofit
applications were identified, and costs for SCR retrofit
applications were not available. The cost to retrofit an
6-206
-------
existing gas turbine installation with SCR would be considerably
higher than the costs shown for a new installation, especially
for combined cycle and cogeneration installations where the
heat-recovery steam generator (HRSG) would have to be modified or
replaced to accommodate the catalyst reactor.
This chapter is organized into five sections. Water and
steam injection costs are described in Section 6.1. Low-N0x
combustor costs are summarized in Section 6.2. Costs for SCR
used in combination with water or steam injection or low-NOx
combustion are described in Section 6.3. Water injection and SCR
costs for offshore gas turbines are presented in Section 6.4, and
references are listed in Section 6.5.
a. WATER AND STEAM INJECTION AND OIL-IN-WATER EMULSION
Ten gas turbines models were selected, and from these
turbines 24 model plants were developed using water or steam
injection or water-in-oil emulsion to control NOX emissions.
These 24 models, shown in Table 6-1
6-207
-------
TABLE 6-1. GAS TURBINE MODEL PLANTS FOR NOx CONTROL TECHNIQUES
Model plant"
CON-G-W-3.3
CON-G-W-4.0
CON-G-W-22.7
CON-G-W-26.8
CON-G-W-83.3
CON-G-W-84.7
CON-G-S-4.0
CON-G-S-22.7
CON-G-S-26.8
CON-G-S-34.4
CON-G-S-83.3
CON-G-S-84.7
CON-G-S-161
CON-O-W-3.3
CON-O-W-26.3
CON-O-W-83.3
PKR-G-W-3.3
PKR-G-W-26.8
PKR-G-W-84.7
PKR-O-W-3.3
PKR-O-W-26.3
PKR-O-W-84.7
STD-O-W-1.1
STD-O-E-28.0
GT model
Centaur T4500
501-KB5
LM2500
MS5001P
ABB GT11N
MS7001E
501-KB5
LM2500
MS5001P
LM5000
ABB GT11N
MS7001E
MS7001F
Centaur T4500
MS5001P
MS7001E
Centaur T4500
MS5001P
MS7001E
Centaur T4500
MS5001P
MS7001E
Saturn T1500
TPM FT4
Turbine output, MW
3.3
4.0
22.7
26.8
83.3
84.7
4.0
22.7
26.8
34.5
83.3
84.7
161
3.3
26.3
83.3
3.3
26.8
84.7
3.3
26.3
84.7
1.0
28.0
Annual operating
hours
8,000
8,000
8,000
8,000
8,000
8,000
8,000
8,000
8,000
8,000
8,000
8,000
8,000
8,000
8,000
8,000
2,000
2,000
2,000
2,000
2,000
2,000
1,000
1,000
Fuel, natural gas or oil
Gas
Gas
Gas
Gas
Gas
Gas
Gas
Gas
Gas
Gas
Gas
Gas
Gas
Oil
Oil
Oil
Gas
Gas
Gas
Oil
Oil
Oil
Oil
Oil
Type of emission
control
Water
Water
Water
Water
Water
Water
Steam
Steam
Steam
Steam
Steam
Steam
Steam
Water
Water
Water
Water
Water
Water
Water
Water
Water
Water
Water-in-oil
pmiilcmn
Aeroderivative (AD)
or heavy-duty (HD)
turbine
HD
AD
AD
HD
HD
HD
AD
AD
HD
AD
HD
HD
HD
HD
HD
HD
HD
HD
HD
HD
HD
HD
HD
AD
o
CO
"Model plant legend:
First entry: annual
operating hours
CON-continuous duty, 8,000 hours
PKR-peaking duty, 2,000 hours
STD-stand-by duty, 1,000 hours
Second entry: fuel type
G = natural gas fuel
O = oil fuel
Third entry: control type
W = water injection
S = steam injection
E = water-in-oil emulsion
Fourth entry: power output
inMW
For example, CON-G-W-3.3 designates that the model plant is continuous-duty, uses natural gas fuel, has water injection, and has a power output of 3.3 MW.
-------
, characterize variations in existing units with respect to
turbine size, type (i.e., aero-derivative vs. heavy duty),
operating hours, and type of fuel. A total of 24 model plants
were developed; 16 of these were continuous-duty (8,000 hours per
year) and 8 were intermittent-duty (2,000 or 1,000 hours per
year). Thirteen of the continuous-duty model plants burn natural
gas fuel; 6 of the 13 use water injection, and 7 use steam
injection to reduce NOX emissions. The three remaining
continuous-duty model plants burn distillate oil fuel and use
water injection to reduce NOX emissions. Of the eight
intermittent-duty model plants, six operate 2,000 hours per year
(three natural gas-fueled and three distillate oil-fueled), and
two operate 1,000 hours per year (both distillate oil-fueled).
All intermittent-duty model plants use water rather than steam
for NOX reduction because it was assumed that the additional
capital costs associated with steam-generating equipment could
not be justified for intermittent service.
Costs were available for applying water-in-oil emulsion
technology to only one gas turbine, and insufficient data were
available to develop costs for a similar water-injected model
6-209
-------
plant for this turbine. As a result, the costs and cost
effectiveness for the water-in-oil emulsion model plant should
not be compared to those of water-injected model plants.
Capital costs are described in Section 6.1.1, annual costs
are described in Section 6.1.2, and emission reductions and the
cost effectiveness of wet injection controls are discussed in
Section 6.1.3. Additional discussion of the cost methodology and
details about some of the cost estimating procedures are provided
in Appendix B.
Fuel rates and water flow rates were calculated for each
model plant using published design power output and efficiency,
expressed as heat rate, in British thermal units per
kilowatt-hour (Btu/kWh).l The values for these parameters are
presented in Table 6-2
6-210
-------
TABLE 6-2. FUEL AND WATER FLOW RATES FOR WATER AND STEAM INJECTION (1990 $)
Model plant
CON-G-W-3.3
CON-G-W-4.0
CON-G-W-22.7
CON-G-W-26.8
CON-G-W-83.3
CON-G-W-84.7
CON-G-S-4.0
CON-G-S-22.7
CON-G-S-26.8
CON-G-S-34.4
CON-G-S-83.3
CON-G-S-84.7
CON-G-S-161
CON-O-W-3.3
CON-O-W-26.3
CON-O-W-83.3
PKR-G-W-3.3
PKR-G-W-26.8
PKR-G-W-84.7
PKR-O-W-3.3
PKR-O-W-26.3
PKR-O-W-84.7
STD-O-W-1.1
STr>-n-K-98 n
GT model
Centaur T4500
501-KB5
LM2500
MS5001P
ABB GT11N
MS7001E
501-KB5
LM2500
MS5001P
LM5000
ABB GT11N
MS7001E
MS7001F
Centaur T4500
MS5001P
MS7001E
Centaur T4500
MS5001P
MS7001E
Centaur T4500
MS5001P
MS7001E
Saturn T1500
TPM FT4
Turbine output,
kW
3,270
4,000
22,670
26,800
83,300
84,700
4,000
22,670
26,800
34,450
83,300
84,700
161,000
3,270
26,300
83,300
3,270
26,800
84,700
3,270
26,300
83,300
1,130
98000
Heat rate (HR),
Btu/kW-hr
12,900
12,700
9,220
11,870
10,400
10,400
12,700
9,220
11,870
9,080
10,400
10,400
9,500
12,900
11,950
10,470
12,900
11,870
10,400
12,900
11,950
10,470
14,200
14500
Fuel flow
Ib/hr"
2,050
2,460
10,100
15,400
42,000
42,700
2,460
10,100
15,400
15,200
42,000
42,700
74,200
2,300
17,100
47,600
2,050
15,400
42,700
2,300
17,100
47,600
875
19700
MMBtu/yrb
337,000
406,000
1,670,000
2,540,000
6,930,000
7,050,000
406,000
1,670,000
2,540,000
2,500,000
6,930,000
7,050,000
12,240,000
337,000
2,510,000
6,980,000
84,400
640,000
1,760,000
84,000
630,000
1,740,000
16,000
406 000
Estimated WFR, Ib
water/lb fuel
0.61
0.80
0.73
0.72
1.83
0.81
1.50
1.46
1.08
1.67
2.12
1.22
1.34
0.60
0.79
0.67
0.61
0.72
0.81
0.60
0.79
0.67
0.46
0 55
Water flow, gal/minc
2.50
3.94
14.8
22.2
154
69.2
7.38
29.5
33.3
50.8
178
104
199
2.76
27.0
63.8
2.50
22.2
69.2
2.76
27.0
63.8
0.81
91 7
Treatment system
capacity, gal/mind
4.20
6.60
24.7
37.2
258
116
12.4
49.5
55.8
85.2
299
175
334
4.63
45.3
107
4.20
37.2
116
4.63
45.3
107
1.35
364
'Natural gas: Ib/hr = HR x kW x (lb/20,610 Btu). Diesel oil: Ib/hr = HR x kW x (lb/18,330 Btu).
bMMBtu/yr = HR x kW x (MM/10 6) x (operating hours/year).
'Water (or steam) flow, gal/min = Fuel flow (Ib/hr) x (1 hr/60 min) x (1 gal/8.33, Ib. H 20) x WFR.
A 30 perceiit design factor has been included per discussion with system supplier, and the waste stream from the water treatment system is calculated to be 29 percent. The design capacity is
therefore Water Flow x 1.3 x 1.29.
-------
for each model plant. Fuel rates were estimated based on the
heat rates, the design output, and the lower heating value (LHV)
of the fuel. The LHV's used in this analysis for natural gas and
diesel fuel are 20,610 Btu per pound (Btu/lb) and 18,330 Btu/lb,
respectively, as shown in Table 6-3
6-212
-------
TABLE 6-3. FUEL PROPERTIES AND UTILITY AND LABOR RATES3
Fuel properties
Natural gas
Diesel fuel
Factor
20, 610
930
18,330
7.21
Units
Btu/lb
Btu/scfc (LHV)
Btu/lb (LHV)
Ib/gal
Reference
Ref . 3
Ref . 3
Ref. 2
Ref. 2
Utility rates
Natural gasb
Diesel fuel
Electricity
Raw water
Water treatment
Waste disposal
3.88
0.77
0.06
0.384
1.97
3.82
$/scf
$/gal
$/kW-hr
$/l,000 gal
$/l,000 gal
$/l,000 gal
Ref. 4
Ref. 5
Ref. ' s 6 and 7
Ref. 2, escalated @ 5% per
year
Ref. 2, escalated @ 5% per
year
Ref. 2, escalated @ 5% per
year
Labor rate
Operating
Maintenance
25.60
31.20
$/hr
$/hr
Ref. 2, escalated @ 5% per
year
Ref. 2, escalated @ 5% per
year
aAll costs are average costs in 1990 dollars.
bNatural gas and electricity costs from Reference 4
for industrial and commercial customers.
cscf = standard cubic foot.
are the average of the costs
6-213
-------
.2 Water (or steam) injection rates were calculated based on
published fuel rates and water-to-fuel ratios (WFR) provided by
manufacturers.8"12 According to a water treatment system
supplier, treatment facilities are designed with a capacity
factor of 1.3.13 An additional 29 percent of the treated water
flow rate is discarded as wastewater.2 Consequently, the water
treatment facility design capacity is 68 percent (1.30 x 1.29)
greater than the water (or steam) injection rate.
i. Capital Costs
The capital costs for each model plant are presented in
Table 6-4
6-214
-------
TABLE 6-4. CAPITAL COSTS FOR WET INJECTION IN THOUSAND OF DOLLARS
Model plant
CON-G-W-3.3
CON-G-W-4.0
CON-G-W-22.7
CON-G-W-26.8
CON-G-W-83.3
CON-G-W-84.7
CON-G-S-4.0
CON-G-S-22.7
CON-G-S-26.8
CON-G-S-34.4
CON-G-S-83.3
CON-G-S-84.7
CON-G-S-161
CON-O-W-3.3
CON-O-W-26.3
CON-O-W-83.3
PKR-G-W-3.3
PKR-G-W-26.8
PKR-G-W-84.7
PKR-O-W-3.3
PKR-O-W-26.3
PKR-O-W-84.7
STD-O-W-1.1
STn-n-F-9x n
GT model
Centaur T4500
501-KB5
LM2500
MS5001P
ABBGT11N
MS7001E
501-KB5
LM2500
MS5001P
LM5000
ABBGT11N
MS7001E
MS7001F
Centaur T4500
MS5001P
MS7001E
Centaur T4500
MS5001P
MS7001E
Centaur T4500
MS5001P
MS7001E
Saturn Tl 500
TPM FT4
Injection
system
(IS)b
113
115
212
215
874
562
154
278
262
530
1,090
715
1,130
114
231
532
113
215
562
114
231
532
71.9
198
Water
treatment
system (WTS)C
89.9
113
218
268
705
473
154
309
328
405
759
580
802
94.5
296
454
89.9
268
473
94.5
296
454
51.0
MAf
Total system
(TS) = (IS + WTS)
203
228
430
483
1,580
1,030
308
587
590
935
1,850
1,300
1,930
208
527
986
203
483
1,030
208
527
986
123
198
Taxes and freight
(TF) = (8%ofTS)
16.2
18.2
34.4
38.6
126
82.4
24.7
46.9
47.2
74.8
148
104
154
16.7
42.1
78.9
16.2
38.6
82.4
16.7
42.1
78.9
9.83
in 9
Direct install.
costs (DC) =
(45% [TS + TF1)
50.0d
50.0d
209
235
768
501
50.0
285
287
454
899
632
938
50.0d
256
479
50.0d
235
501
50.0d
256
479
50.0
ซ9 9
Indirect install, costs
(IC)=(33% of [TS + TF
+DC1 + 5,000)
53. 8e
59.2e
227
254
822
537
76.6
308
310
488
961
677
1,000
55.0e
277
515
53. 8e
254
537
55.0e
277
515
36.6
71 1
Contingency (C) =
(20% of [TS + TF
+ DC + IC1)
64.6
71.0
180
202
659
430
92.0
245
247
391
772
543
804
66.0
220
412
64.6
202
430
66.0
220
412
43.9
SAT:
Total capital cost (TCC)
= [TS + TF + DC + 1C
+ C1
388
426
1,080
1,210
3,950
2,580
552
1,470
1,480
2,340
4,630
3,260
4,830
396
1,320
2,470
388
1,210
2,580
396
1,320
2,470
263
T,1f,
I
[\J
I1
Cn
"All costs in 1990 dollars.
""Injection nozzle costs provided by manufacturers. Balance of water injection system calculated at a cost of $4,200 x GPM.
CWTS = 43,900 x (design capacity, gal/min) ฐ'5
dDirect installation cost is estimated at $50,000 for model plants rated at 5 MW or less.
'Indirect installation cost factor of 33 percent is reduced to 20 percent for model plants rated at 5 MW or less.
*NA = cost calculations based on using a portable demineralizer systems during turbine operating periods. Cost for system usage is included in Table 6-5.
-------
These costs were developed based on methodology in
Reference 2, which is presented in this section. The capital
costs include purchased equipment costs, direct and indirect
installation costs, and contingency costs.
(1) Purchased Equipment Costs. Purchased equipment costs
consist of the injection system, the water treatment system,
taxes, and freight. All costs are presented in 1990 dollars.
6-216
-------
6-217
-------
6-21!
-------
(a) Water injection system. The injection system delivers
water from the treatment system to the combustor. This system
includes the turbine-mounted injection nozzles, the flow metering
controls, pumps, and hardware and interconnecting piping from the
treatment system to the turbine. On-engine hardware (the
injection nozzles) costs were provided by turbine
manufacturers.9'14'17 Flow metering controls and hardware, pumps,
and interconnecting piping costs for all turbines were calculated
using data provided by General Electric for four heavy-duty
turbine models.17 No relationship between costs and either
turbine output or water flow was evident, so the sum of the four
costs was divided by the sum of the water flow requirements for
the four turbines. This process yielded a cost of $4,200 per
gallon per minute (gal/min), and this cost, added to the on-
engine hardware costs, was used for all model plants.
(b) Water treatment system. The water treatment process,
and hence the treatment system components, varies according to
the degree to which the water at a given site must be treated.
For this cost analysis, the water treatment system includes a
reverse osmosis and mixed-bed demineralizer system. The water
treatment system capital cost for each model plant was estimated
based on an equation developed in Reference 2:
WTS = 43, 900 X (G) ฐ'50
where
WTS = water treatment system capital cost, $; and
G = water treatment system design capacity, gal/min.
This equation yields costs that are generally consistent
with the range of costs presented in Reference 18.
(c) Taxes and freight. This cost covers applicable sales
taxes and shipment to the site for the injection and water
treatment systems. A figure of 8 percent of the total system
cost was used.2'7
(2) Direct Installation Costs. This cost includes the
labor and material costs associated with installing the
foundation and supports, erecting and handling equipment,
electrical work, piping, insulation, and painting. For smaller
6-219
-------
turbines, the water treatment system is typically skid-mounted
and is shipped to the site as a packaged unit, which minimizes
field assembly and interconnections. The cost to install a skid-
mounted water treatment skid is typically $50,000, and this cost
is used for the direct installation cost for model plants less
than 5 MW (6700 hp).19 For larger turbines, it is expected that
the water treatment system must be field-assembled and the direct
installation costs were calculated as 45 percent of the injection
and water treatment systems, including taxes and freight.2
(3) Indirect Installation Costs. This cost covers the
indirect costs (engineering, supervisory personnel, office
personnel, temporary offices, etc.) associated with installing
the equipment. The cost was taken to be 33 percent of the
systems' costs, taxes and freight, and direct costs, plus
$5,000 for model plants above 5 MW (6,700 hp).2 The indirect
installation costs for skid-mounted water treatment systems are
expected to be less than for field-assembled systems; therefore,
for model plants with an output of less than 5 MW (6,700 hp), the
cost percentage factor was reduced from 33 to 20 percent.
(4) Contingency Cost. This cost is a catch-all meant to
cover unforeseen costs such as equipment redesign/ modification,
cost escalations, and delays encountered in startup. This cost
was estimated as 20 percent of the sum of the systems, taxes and
freight, and direct and indirect costs.2
ii. Annual Costs
6-220
-------
The annual costs are summarized in Table 6-5
6-221
-------
TABLE 6-5. ANNUAL COSTS FOR WATER AND STEAM INJECTION (1990 $)
Model plant
CON-G-W-3.3
CON-G-W-4.0
CON-G-W-22.7
CON-G-W-26.8
CON-G-W-83.3
CON-G-W-84.7
CON-G-S-4.0
CON-G-S-22.7
CON-G-S-26.8
CON-G-S-34.4
CON-G-S-83.3
CON-G-S-84.7
CON-G-S-161
CON-O-W-3.3
CON-O-W-26.3
CON-O-W-83.3
PKR-G-W-3.3
PKR-G-W-26.8
PKR-G-W-84.7
PKR-O-W-3.3
PKR-O-W-26.3
PKR-O-W-84.7
STD-O-W-1.1
STD-O-E-28.0
GT model
Centaur T4500
501-KB5
LM2500
MS5001P
ABB GT11N
MS7001E
501-KB5
LM2500
MS5001P
LM5000
ABB GT11N
MS7001E
MS7001F
Centaur T4500
MS5001P
MS7001E
Centaur T4500
MS5001P
MS7001E
Centaur T4500
MS5001P
MS7001E
Saturn T1500
TPM FT4
Fuel penalty
(FP)'
30,000
47,400
178,000
267,000
1,852,000
834,000
25,400
102,000
114,000
174,000
613,000
359,000
684,000
41,200
404,000
954,000
7,500
67,000
208,000
10,300
101,000
238,000
1,500
45,500
Electricity
(E)b
193
304
1,140
1,714
11,884
5,348
571
2,280
2,572
3^925
13,768
8,055
15,374
213
2,089
4,931
48.3
429
1,337
53.3
522
1,233
7.78
209
Added
maintenance
cost (M)c
16,000
24,000
28,000
33,000
0
25,700
24,000
0
33,000
0
0
0
0
20,800
42,900
33,400
4,000
8,250
6,430
5,200
10,725
8,350
1,300
0
Water treatment (WT)d
Raw water'
595
936
3,510
5,270
36,600
16,500
1,760
7,020
7,910
12,100
42,400
24,800
47,300
657
6,430
15,200
149
1,320
4,110
164
1,610
3,790
23.9
644
Treat-mentf
3,050
4,800
18,000
27,100
188,000
84,400
9,010
36,000
40,600
62,000
217,000
127,000
243,000
3,370
33,000
77,800
760
6,770
21,100
840
8,240
19,500
123
51,100
Labor8
1,080
1,710
6,390
9,620
66,700
30,000
1,600
6,390
7,210
11,000
38,600
22,600
43,100
1,200
11,700
27,700
270
2,400
7,500
300
2,930
6,910
43.7
1,170
Disposal11
1,330
2,090
7,840
11,800
81,800
36,800
3,930
15,700
17,700
27,000
94,700
55,400
106,000
1,470
14,400
33,900
330
2,950
9,200
370
3,590
8,480
53.6
1,440
Total cost
(TW)
6,050
9,540
35,700
53,800
373,000
168,000
16,300
65,100
73,400
112,000
393,000
230,000
439,000
6,700
65,500
155,000
1,510
13,400
41,900
1,670
16,400
38,700
244
54,400
Plant
overhead
(P0) =
(30%ofM)
4,800
7,200
8,400
9,900
0
7,710
7,200
0
9,900
0
0
0
0
6,240
12,900
10,020
1,200
2,500
1,929
1,560
3,200
2,505
390
0
G&A
taxes,
insurance
(GATI)1
15,500
17,100
43,200
48,400
158,000
103,000
22,100
58,800
59,200
93,600
185,000
130,000
193,000
15,800
52,800
98,800
15,500
48,400
103,000
15,800
52,800
99,000
10,530
13,000
Capital
recovery
(CR)i
51,000
56,100
142,000
159,000
519,000
339,000
72,600
193,000
195,000
308,000
609,000
429,000
635,000
52,100
174,000
325,000
51,000
159,000
339,000
52,100
174,000
325,000
34,600
42,900
Total
annual cost
(TAC)k
124,000
162,000
436,000
573,000
2,910,000
1,480,000
168,000
421,000
487,000
692,000
1,810,000
1,160,000
1,970,000
143,000
754,00
1,580,000
80,800
299,000
702,000
86,700
359,000
713,000
48,600
156,000
'FP for water = 0.035 x WFR x (MMBtu/yr) x (ft 3/940 Btu) x ($3.88/1,000 ft 3) x (106/MM).
bE = Water flow rate (gal/min) x 0.161 x operating hours x ($0.06/kWH).
'Maintenance costs for the Centaur and Allison 501 turbines were obtained from the manufacturers. Costs for the MS5001 and MS7001 were estimated based on information about
inspections and parts replacement presented in Appendix B. Maintenance for turbines that use diesel fuel are 30 percent higher than costs for comparable turbines using natural gas.
No additional maintenance costs were assessed for steam injection.
gattiS^ hours x 1.29.
'Treatment Cost = Water Flow (gal/min) x ($1.97/1,000 gal) x (60 min/hour) x operating hours x 1.29.
8Labor Cost for water = Water Flow (gal/min) x ($.70/1,000 gal) x (60 min/hour) x operating hours x 1.29.
Labor Cost for steam = Water Flow (gal/min) x ($.70/1,000 gal) x (60 min/hour) x operating hours x 1.29 x 0.5.
'Disposal Cost = Water Flow (gal/min) x ($3.82/1,000 gal) x (60 min/hour) x operating hours x 0.29.
'GATI = 0.04 x TCC (TCC is shown in Table 6-4).
'CR = 0.1315 x TCC based on an equipment life of 15 years and a 10 percent interest rate.
-------
for each model plant. Annual costs include the fuel penalty;
electricity; maintenance requirements; water treatment; overhead,
general and administrative, taxes, and insurance; and capital
recovery, as discussed in this section.
(1) Fuel Penalty. The reduction in efficiency
associated with water injection varies for each turbine model.
Based on data in Reference 2, it was estimated that a WFR of
1.0 corresponds to a fuel penalty of 3.5 percent for water
injection and 1.0 percent for steam injection. This percentage
was multiplied by the actual WFR and the annual fuel cost to
6-223
-------
determine the fuel penalty for each model plant. The fuel flow
was multiplied by the unit fuel costs to determine the annual
fuel costs. As shown in Table 6-3, the natural gas cost is
$3.88/1,000 standard cubic feet (scf) and the diesel fuel cost is
$0.77/gal.4'5
An increase in output from the turbine accompanies the
decrease in efficiency. This increase was not considered,
however, because not all sites have a demand for the available
excess power. In applications such as electric power generation,
where the excess power can be used at the site or added to
utility power sales, this additional output would serve to
decrease or offset the fuel penalty impact.
(2) Electricity Cost. The electricity costs shown in
Table 6-5 apply to the feedwater pump(s) for water or steam
injection. The pump power requirements are estimated from the
pump head (ft) and the water flow rate as shown in the following
equation:2
,1T7 . FR . . 1 v 0.7457 kW 1
power pump (kW ) = x H x (S. G. ) x X x
3,960 0.6 hp 0.9
where:
FR = feedwater flow rate, gal/min (from Table 6-2);
H = total pump head (ft);
S.G. = specific gravity of the feed water;
0.6 = pump efficiency of 60 percent;
0.9 = electric motor efficiency of 90 percent;
3,960 = factor to correct units in FR and H to hp; and
0.7457 = factor to convert hp to kW.
For water injection, the feedwater pump(s) supply treated water
to the gas turbine injection system. For steam injection, the
feedwater pump(s) supply treated water to the boiler for steam
generation. This cost analysis uses a feedwater temperature of
55ฐC (130ฐF) with a density of 61.6 lb/ft3 and a total pump head
requirement of 200 pounds per square inch, gauge (psig)
6-224
-------
(468 ft) .2 Based on these values, the pump electrical demand for
either water or steam injection is calculated as follows:
,1T7, FR x 468 61.6 1 . I
pump power (kWe) = 3?960 x ^^ x _ x 0.7457 x __
= 0.161 x FR
The electrical cost for each model plant is the product of
the pump electrical demand, the annual hours of operation, and
the unit cost of electricity. The unit cost of electricity,
shown in Table 6-3, is $0.06/kWH.6'7
Maintenance costs were developed based on information from
manufacturers, and water treatment labor costs were estimated
based on information from a water treatment vendor. Other costs
were developed based on the methodology presented in Reference 2.
No backup steam or electricity costs were developed for
water or steam injection because it was assumed that no
additional downtime would be required for scheduled inspections
and repairs. Maintenance intervals could be scheduled to
coincide with the 760 hr/yr of downtime that are currently
allocated for scheduled maintenance. If this were done, the
annual utilization of the backup source would not increase.
(3) Added Maintenance Costs. Based on discussions with gas
turbine manufacturers, additional maintenance is required for
some gas turbines with water injection. The analysis procedures
used to develop the incremental maintenance costs are presented
in Appendix B.
The incremental maintenance cost associated with water
injection for natural gas-fueled turbines was provided by the gas
turbine manufacturers.10'20"24 All gas turbine manufacturers
contacted stated that there were no incremental maintenance costs
for operation with steam injection. Two manufacturers provided
maintenance costs for natural gas and oil fuel operation without
water injection.10'20 Using an average of these costs, incremental
maintenance costs for water injection are 30 percent higher for
6-225
-------
plants that use diesel fuel instead of natural gas. Costs were
prorated for model plants that operate less than 8,000 hr/yr.
(4) Water Treatment Costs. Water treatment operating costs
include the cost of treatment (e.g., for chemicals and media
filters), operating labor, raw water, and wastewater disposal.
The raw water flow rate is equal to the treated water flow rate
(the water or steam injection rate) plus the flow rate of the
wastewater generated in the treatment plant. As noted in Section
6.1, the wastewater flow rate is equal to 29 percent of the
injection flow rate. The annual raw water, treated water, and
wastewater flow rates were multiplied by the appropriate unit
costs in Table 6-3 to determine the annual costs. Water
treatment labor costs were calculated at $0.70/1,000 gal for
water injection.25 This cost was multiplied by the total annual
treated water flow rate to determine the annual water treatment
labor cost for water injection. Labor costs for steam injection
were assumed to be half as much as the costs for water injection
because it was assumed that the facility already has a water
treatment plant for the boiler feedwater. Therefore, the
operator requirements would be only those associated with the
increase in capacity of the existing treatment plant.
(5) Plant Overhead. This cost is the overhead associated
with the additional maintenance effort required for water
injection. The cost was calculated as 30 percent of the added
maintenance cost from Section 6.1.2.3.2
(6) General and Administrative, Taxes, and Insurance Costs
(GATI). This cost covers those expenses for administrative
overhead, property taxes, and insurance and was calculated as
4 percent of the total capital cost.2
(7) Capital Recovery. A capital recovery factor (CRF) was
multiplied by the total capital investment to estimate uniform
end-of-year payments necessary to repay the investment. The CRF
used in this analysis is 0.1315, which is based on an equipment
life of 15 years and an interest rate of 10 percent.
(8) Total Annual Cost. This cost is the sum of the annual
costs presented in Sections 6.1.2.1 through 6.1.2.7 and is the
6-226
-------
total cost that must be paid each year to install and operate
water or steam injection NOX emissions control for a gas turbine,
iii. Emission Reduction and Cost-Effectiveness Summary for
Water and Steam Injection
6-227
-------
6-22!
-------
TABLE 6-6. COST-EFFECTIVENESS SUMMARY FOR WATER AND STEAM INJECTION (1990 $)
Model plant
CON-G-W-3.3
CON-G-W-4.0
CON-G-W-22.7
CON-G-W-26.8
CON-G-W-83.3
CON-G-W-84.7
CON-G-S-4.0
CON-G-S-22.7
CON-G-S-26.8
CON-G-S-34.4
CON-G-S-83.3
CON-G-S-84.7
CON-G-S-161
CON-O-W-3.3
CON-O-W-26.3
CON-O-W-83.3
PKR-G-W-3.3
PKR-G-W-26.8
PKR-G-W-84.7
PKR-O-W-3.3
PKR-O-W-26.3
PKR-O-W-84.7
STD-O-W-1.1
STD-O-E-28.0
GT model
Centaur T4500
501-KB5
LM2500
MS5001P
ABB GT11N
MS7001E
501-KB5
LM2500
MS5001P
LM5000
ABB GT11N
MS7001E
MS7001F
Centaur T4500
MS5001P
MS7001E
Centaur T4500
MS5001P
MS7001E
Centaur T4500
MS5001P
MS7001E
Saturn T1500
TPMFT4
NO emissions"
Uncontrolled NOX
ppmvb
130
155
174
142
390
154
155
174
142
185
390
154
210
179
211
228
130
142
154
179
211
228
150
150
tons/yr
88.1
126
581
723
5,410
2,170
126
581
723
930
5,410
2,170
5,150
125
1,090
3,290
22.0
181
543
31.2
273
822
4.97
122
Controlled NOX
ppmv
42
42
42
42
25
42
42
25
42
25
42
42
42
60
65
65
42
42
42
60
65
65
60
50
b tons/yr
28.5
34.2
140
214
347
593
34.2
83.5
214
126
583
593
1,030
41.8
337
938
7.12
53.5
148
10.5
84.2
234
1.99
37.3
Total NOX
removed,
tons/yr
59.6
91.9
441
509
5,060
1,580
91.9
497
509
804
4,830
1,580
4,120
82.9
753
2,350
14.9
127
395
20.7
189
588
2.98
84.7
Total annual cost, $
124,000
162,000
436,000
573,000
2,910,000
1,480,000
168,000
421,000
487,000
692,000
1,810,000
1,160,000
1,970,000
143,000
754,000
1,580,000
80,800
299,000
702,000
86,700
359,000
713,000
48,600
156,000
Cost effectiveness,
$/t6n
2,080
1,760
989
1,130
575
937
1,830
846
957
861
375
734
478
1,720
1,000
672
5,420
2,350
1,780
4,180
1,900
1,210
16,300
1,840
"Example NOX emission calculations are given in Appendix A.
""Referenced to 15 percent oxygen.
Trom Table 6-5.
-------
The uncontrolled and controlled NOX emissions and the annual
emission reductions for the model plants are shown in Table 6-6.
The emissions, in tons per year (tons/yr), were calculated as
shown in Appendix A.
The total annual cost was divided by the annual emission
reductions to determine the cost effectiveness for each model
plant. For continuous-duty natural gas-fired model plants, the
cost-effectiveness figures range from approximately $600 to
$2,100 per ton of NOX removed for water injection, and decrease
to approximately $400 to $1,850 per ton for steam injection. The
lower range of cost-effectiveness figures for steam injection is
primarily due to the greater NOX reduction achieved with steam
injection. For continuous-duty oil-fired model plants, the cost
effectiveness ranges from approximately $675 to $1,750 per ton of
NOX removed, which is comparable to figures for gas-fired model
plants. The cost-effectiveness figures are higher for gas
turbines with lower power outputs because the fixed capital costs
associated with wet injection system installation have the
greatest impact on the smaller gas turbines.
Cost-effectiveness figures increase as annual operating
hours decrease. For turbines operating 2,000 hr/yr, the cost-
effectiveness figures are two to nearly three times higher than
those for continuous-duty model plants, and increase further for
model plants operating 1,000 hr/yr. For the oil-in-water
emulsion model plant, the cost effectiveness corresponding to
1,000 annual operating hours is $l,840/ton of NOX removed. No
data were available to prepare a conventional water injection
model plant for this turbine to compare the relative cost-
effectiveness values.
6-230
-------
6-231
-------
b. LOW-NOX COMBUSTORS
Incremental capital costs for low-NOx combustors relative to
standard designs for new applications were provided by three
manufacturers for several turbines.3'14'26 Based on information
from the manufacturers, the performance and maintenance
requirements for a low-NOx combustor are expected to be the same
as for a standard combustor, and so the only annual cost
associated with low-NOx combustors is the capital recovery. The
capital recovery factor is 0.1315, assuming a life of 15 years
and an interest rate of 10 percent.
6-232
-------
Table 6-7
6-233
-------
TABLE 6-7.
COST-EFFECTIVENESS SUMMARY FOR DRY LOW-NO
NATURAL GAS FUEL (1990 $)
COMBUSTORS USING
Model plant a
CON-L-3.3-42
CON-L-4.0-42
CON-L-4.5-42
CON-L-8.8-42
CON -L-l 0-42
CON-L-3.3-25
CON-L-4.0-25
CON-L-4.5-25
CON-L-8.8-25
CON -L-l 0-25
CON-L-39-25
CON-L-83-25
CON-L-85-25
CON-L-39-9
CON-L-83-9
CON-L-85-9
PKR-L-3.3-42
PKR-L-4.0-42
PKR-L-4.5-42
PKR-L-8.8-42
PKR-L-10-42
PKR-L-3.3-25
PKR-L-4.0-25
PKR-L-4.5-25
PKR-L-8.8-25
PKR-L-10-25
PKR-L-39-25
PKR-L-83-25
PKR-L-85-25
*PKR-L-39-9
PKR-L-83-9
PKR-L-85-9
GT model
Centaur T4500
Centaur 'H'
Taurus
Mars T12000
Mars T14000
Centaur T4500
Centaur 'H1
Taurus
Mars T12000
Mars T14000
MS6000
ABB GT11N
MS7001E
MS6000
ABB GT11N
MS7001E
Centaur T4500
Centaur 'H1
Taurus
Mars T12000
Mars T14000
Centaur T4500
Centaur 'H1
Taurus
Mars T12000
Mars T14000
MS6000
ABB GT11N
MS7001E
MS6000
ABB GT11N
MS7001E
Power output,
MW
3.3
4.0
4.5
8.8
10.0
3.3
4.0
4.5
8.8
10.0
39.0
83.3
84.7
39.0
83.3
84.7
3.3
4.0
4.5
8.8
10.0
3.3
4.0
4.5
8.8
10.0
39.0
83.3
84.7
39.0
83.3
84.7
Annual operating
hours
8,000
8,000
8,000
8,000
8,000
8,000
8,000
8,000
8,000
8,000
8,000
8,000
8,000
8,000
8,000
8,000
2,000
2,000
2,000
2,000
2,000
2,000
2,000
2,000
2,000
2,000
2,000
2,000
2,000
2,000
2,000
2,000
NOX emissionsb
Uncontrolled NO x
ppmvc
130
105
114
178
199
130
105
114
178
199
220
390
154
220
390
154
130
105
114
178
199
130
105
114
178
199
220
390
154
220
390
154
Tons/yr
88.1
83.0
98.7
278
341
88.1
83.0
98.7
278
341
1,480
5,420
2,180
1,480
5,420
2,180
22.0
20.7
24.7
69.4
85.4
22.0
20.7
24.7
69.4
85.4
371
1,350
540
371
1,350
540
Controlled NO x
ppmv
42.0
42.0
42.0
42.0
42.0
25.0'
25.0'
25.0'
25.0'
25.0'
25.0
25.0
25.0
9.00
9.00
9.00
42.0
42.0
42.0
42.0
42.0
25.0'
25.0'
25.0'
25.0'
25.0'
25.0
25.0
25.0
9.00
9.00
9.00
Tdhs/yr
28.5
33.2
36.4
65.5
72.1
16.9
19.8
21.7
39.0
42.9
168
347
353
60.6
125
127
7.12
8.30
9.09
16.4
18.0
4.24
4.94
5.41
9.75
10.7
42.1
86.8
88.3
15.2
31.3
31.8
NOK removed,
tons/yr
59.6
49.8
62.4
212
269
71.2
63.2
77.1
239
299
1,310
5,070
1,830
1,420
5,290
2,050
14.9
12.4
15.6
53.1
67.3
17.8
15.8
19.3
59.7
74.6
328
1,260
452
355
1,320
508
Incremental capital
cost,$d
375,000
400,000
425,000
700,000
725,000
375,000
400,000
425,000
700,000
725,000
1,400,000
2,200,000
2,140,000
1,400,000
2,200,000
2,140,000
375,000
400,000
425,000
700,000
725,000
375,000
400,000
425,000
700,000
725,000
1,400,000
2,200,000
2,140,000
1,400,000
2,200,000
2,140,000
Annual cost,
$=
49,300
52,600
55,900
92,100
95,300
49,300
52,600
55,900
92,100
95,300
184,000
289,000
281,000
184,000
289,000
281,000
49,300
52,600
55,900
92,100
95,300
49,300
52,600
55,900
92,100
95,300
184,000
289,000
281,000
184,000
289,000
281,000
Cost effective-
ness, $/ton
NO^ removed
827
1,060
896
434
354
693
832
725
386
319
140
57.0
154
130
54.6
137
3,310
4,230
3,590
1,740
1,420
2,770
3,330
2,900
1,540
1,280
560
229
622
518
219
553
CT>
I
CO
"Model plant legend: First entry: annual operating hours Second entry: control technique Third entry: power output, in MW Fourth entry: controlled NO level, ppmv at 15 percent O
CON - Continuous duty, 8,000 hours L - dry low-NO combustor x
PKR - peaking/intermittent duty, 2,000 hours
For example, CON-L-3.3-42 designates that the model plant operates 8,000 hours per year, is fitted with a dry low-NO x combustor, has a power output of 3.3 MW, and has a controlled NO x level of 42 ppmv.
bExample NOS emission calculations are shown in Appendix A.
Referenced to 15 percent oxygen.
Incremental capital costs were provided by the manufacturers.
-------
presents the uncontrolled and controlled emission levels, the
annual emission reductions, incremental costs for a low-NOx
combustor over a conventional design, and the cost effectiveness
of low-NOx combustors for all gas turbine models for which
sufficient data were available. Cost-effectiveness figures were
calculated for 8,000 and 2,000 hours of operation annually, using
controlled NOX emission levels of 42, 25, and 9 parts per
million, by volume (ppmv) , referenced to 15 percent oxygen, which
are the achievable levels stated by the turbine manufacturers.
The cost effectiveness varies according to the uncontrolled NOX
emission level for the conventional combustor design and the
achievable controlled emission level for the low-NOx design. For
continuous-duty applications, cost effectiveness for a controlled
NOX emission level of 42 ppmv ranges from $353 to $1,060 per ton
of NOX removed. The cost-effectiveness range decreases to $57 to
$832 per ton of NOX removed for a controlled NOX emission level
of 25 ppmv and decreases further to $55 to $137 per ton of NOX
removed for a 9 ppmv control level. In all cases, the cost
effectiveness increases as the operating hours decrease. In
general, the cost effectiveness is higher for smaller gas
turbines than for larger turbines due to the relatively higher
capital cost per kW for low-NOx combustors for smaller turbines.
The cost-effectiveness range is lower for low-NOx combustors
than for water or steam injection because the total annual costs
are lower and, in some cases, the controlled emission levels are
6-235
-------
also lower. According to two turbine manufacturers, retrofit
costs are 40 to 60 percent greater than the incremental costs
shown in Table 6-7 for new installations.3'14
c. SELECTIVE CATALYTIC REDUCTION
The costs for SCR for new installations were estimated for
all model plants. Retrofit costs for SCR were not available but
could be considerably higher than the costs shown for new
installations, especially in applications where an existing heat
recovery steam generator (HRSG) would have to be moved, modified,
or replaced to accommodate the addition of a catalyst reactor.
To date, most gas turbine SCR applications use a base metal
catalyst with an operating temperature range that requires
cooling of the exhaust gas from the turbine. For this reason,
SCR applications to date have been limited to combined cycle or
cogeneration applications that include an HRSG, which serves to
cool the exhaust gas to temperatures compatible with the
catalyst. The introduction of high-temperature zeolite
catalysts, however, makes it possible to install the catalyst
directly downstream of the turbine, and therefore feasible to
use SCR with simple-cycle applications as well as heat recovery
applications. As discussed in Section 5.3.2, to date there is at
least one gas turbine installation with a high-temperature
zeolite catalyst installed downstream of the turbine and upstream
of an HRSG. At present, no identified SCR systems are installed
in simple-cycle gas turbine applications.
An overview of the procedures used to estimate capital and
annual costs are described in Sections 6.3.1 and 6.3.2,
respectively; a detailed cost algorithm is presented in
Appendix B. The emission reduction and cost-effectiveness
calculations are described in Section 6.3.3.
i. Capital Costs
Five documents in the technical literature contained SCR
capital costs for 21 gas turbine facilities. Most of these
documents presented costs that were obtained from vendors, but
some may have also developed at least some costs based on their
own experiences.27'31 Most of the documents presented only the
6-236
-------
total capital costs, not costs for individual components, and
they did not provide complete descriptions of what the costs
included. These costs were plotted on a graph of total capital
costs versus gas turbine size. To this graph were added
estimates of total installed costs for a high-temperature
catalyst SCR system for installation upstream of the HRSG for
four turbine installations ranging in size from 4.5 to 83 MW
(6,030 to 111,000 hp). These high-temperature SCR system
estimates include the catalyst reactor, air injection system for
exhaust temperature control, ammonia storage and injection
system, instrumentation, and continuous emission monitoring
equipment. These SCR costs were estimated by the California Air
Resources Board (CARB) in 1991 dollars and are based on NOX
emission levels of 42 ppmv into and 9 ppmv out of the SCR.35
These estimated costs, shown in Appendix B, fit well within the
range of costs from the 21 installations discussed above, and the
equation of a line determined by linear regression adequately
fits the data (R2 = 0.76) for all 25 points. Based on this
graph, the total capital cost for either a base-metal SCR system
installed within the HRSG or a high-temperature zeolite catalyst
SCR system installed directly downstream of the turbine can be
calculated using the equation determined by the linear
6-237
-------
TABLE 6-8. PROCEDURES FOR ESTIMATING CAPITAL AND
ANNUAL COSTS FOR SCR CONTROL OF NOX EMISSIONS FROM GAS TURBINES3
A. Total capital investment, $
B. Direct annual costs, $/yr
1. Operating labor0
2. Supervisory labor
3. Maintenance labor and materials
4. Catalyst replacement
Catalyst disposal4
Anhydrous ammonia6
Dilution steam'
5.
6.
7.
8. Electricity8
9. Performance loss11
10. Blower (if needed)
11. Production loss1
C. Indirect annual costs, $/yr
1. Overhead
2. Property taxes, insurance, and
administration
3. Capital recovery
= (49,700 x TMW) + 459,000
(1.0 hr/8 hr-shift) x ($25.60/hr) x (H)
(0.15) x (operating labor)
(1,250 x TMW) + 25,800
(4,700 x TMW) + 37,200
(V) x ($15/ft3) x (.2638)
(N) x ($360/ton)
(N) x (0.95/0.05) x (MW H2O/MW NH3) x ($6/1,000 Ib
steam) x (2,000 Ib/ton)
N/A
(0.005) x (TMW) x ($0.06/KWH) x (1,000 KW/MW) x (H)
0.1 x (Performance Loss)
None
(0.6) x (all labor and maintenance material costs)
(0.04) x (total capital investment)
(0.13147) x [total capital investment - (catalyst
replacement/0.2638)]
aAll costs are in average 1990 dollars.
bTMW=turbine output in MW for each model plant.
The annual operating hours are represented by the variable H. The labor rate of $25.60/hr is from Table 6-3.
dThe catalyst volume in ft is represented by the variable V. The catalyst volume for each model plant is estimated
as V = (TMW) x (6,180 ft3/83 MW).
The ammonia requirement in tons is represented by the variable N and is calculated using a NH3-to-NOx molar ratio
of 1.0.
The annual tonnage of NOX is taken from the controlled levels shown in Tables 6-11 and 6-12.
The ammonia is diluted with steam to 5 percent by volume before injection.
The amount of electricity required for ammonia pumps and exhaust fans is not known, but is expected to be small.
The electricity cost comprised less than 1 percent of the total annual cost estimated by the South Coast Air Quality
Management District (SCAQMD) for SCR applied to a 1.1 MW turbine.
hBased on information from three sources, the backpressure from the SCR reduces turbine output by an average of
about 0.9 percent.
TSTo production losses are estimated because it is assumed that all SCR maintenance, inspections, cleaning, etc. can
be performed during the 760 hours of scheduled downtime per year.
The capital recovery factor for the SCR is 0.13147, based on a 15-year equipment life and 10 percent interest rate.
The catalyst is replaced every 5 years. The 0.2638 figure is the capital recovery factor for a 5-year equipment life
and a 10 percent interest rate.
6-231
-------
regression. This equation is shown in Table 6-8 and was used to
calculate the total capital investment for SCR for each model
plant shown in Tables 6-9 and 6-10.
6-239
-------
TABLE 6-9. CAPITAL AND ANNUAL COSTS
FOR SCR USED DOWNSTREAM OF WATER OR STEAM INJECTION (1990 $)
Model plant
CON-G-W-3.3
CON-G-W-4.0
CON-G-W-22.7
CON-G-W-26.8
CON-G-W-83.3
CON-G-W-84.7
CON-G-S-4.0
CON-G-S-22.7
CON-G-S-26.8
CON-G-S-34.4
CON-G-S-83.3
CON-G-S-84.7
CON-G-S-161
CON-O-W-3.3
CON-O-W-26.3
CON-O-W-83.3
PKR-G-W-3.3
PKR-G-W-26.8
PKR-G-W-84.7
PKR-O-W-3.3
PKR-O-W-26.3
PKR-O-W-84.7
STD-O-W-1.1
STD-O-E-28.0
GT model
Centaur T4500
501-KB5
LM2500
MS5001P
ABB GT11N
MS7001E
501-KB5
LM2500
MS5001P
LM5000
ABB GT11N
MS7001E
MS7001F
Centaur T4500
MS5001P
MS7001E
Centaur T4500
MS5001P
MS7001E
Centaur T4500
MS5001P
MS7001E
Saturn T1500
TPMFT4
Total
capital
investment,
$'
622,000
658,000
1,590,000
1,790,000
4,600,000
4,670,000
658,000
1,590,000
1,790,000
2,170,000
4,600,000
4,670,000
8,460,000
622,000
1,770,000
4,600,000
622,000
1,790,000
4,670,000
622,000
1,770,000
4,600,000
515,000
1,850,000
Operating
labor, $
25,600
25,600
25,600
25,600
25,600
25,600
25,600
25,600
25,600
25,600
25,600
25,600
25,600
25,600
25,600
25,600
6,400
6,400
6,400
6,400
6,400
6,400
3,200
3,200
Super-
visory
labor,
$
3,840
3,840
3,840
3,840
3,840
3,840
3,840
3,840
3,840
3,840
3,840
3,840
3,840
3,840
3,840
3,840
960
960
960
960
960
960
480
480
Main-
tenance
labor &
materials,
$
29,900
30,800
54,100
59,300
130,000
132,000
30,800
54,100
59,300
68,900
130,000
132,000
227,000
29,900
58,700
130,000
7,470
14,800
32,900
7,470
14,700
32,500
3,400
60,800
Catalyst
replace-
ment, $
52,600
56,000
144,000
163,000
429,000
435,000
56,000
144,000
163,000
199,000
429,000
435,000
794,000
52,600
161,000
429,000
13,100
40,800
109,000
13,100
40,200
107,000
5,310
21,100
Catalyst
disposal,
$
963
1,180
6,680
7,900
24,500
25,000
1,180
6,680
7,900
10,100
24,500
25,000
47,400
963
7,750
24,500
241
1,970
6,240
241
1,940
6,140
41.6
1,030
Ammonia,
$
2,980
3,570
14,700
22,400
29,600
62,000
3,570
7,110
22,400
10,700
61,000
62,000
108,000
3,890
32,400
90,000
740
5,600
15,500
970
8,100
22,500
185
3,180
Dilution
steam, $
1,770
2,130
8,740
13,300
17,600
36,900
2,130
4,240
13,300
6,380
36,300
36,900
64,200
2,320
19,300
53,800
440
3,330
9,240
580
4,830
13,440
158
2,960
Perfor-
mance
loss, $
7,850
9,600
54,400
64,300
200,000
203,000
9,600
54,400
64,300
82,700
200,000
203,000
386,000
7,850
63,100
200,000
1,960
16,100
50,800
1,960
15,800
50,000
339
8,400
Blower (if
needed), $
785
960
5,440
6,430
20,000
20,300
960
5,440
6,430
8,270
20,000
20,300
38,600
785
6,310
20,000
196
1,610
5,080
196
1,580
5,000
33.9
840
Over-
head, $
35,600
36,100
50,100
53,200
95,700
96,900
36,100
50,100
53,200
59,000
95,700
96,900
154,000
35,600
52,900
95,700
8,900
13,300
24,200
8,900
13,200
23,900
4,250
38,700
Taxes,
insurance
& admin,
$
24,900
26,300
63,600
71,600
184,000
187,000
26,300
63,600
71,600
86,800
184,000
187,000
338,000
24,900
70,800
184,000
24,900
71,600
187,000
24,900
70,800
184,000
20,600
74,000
Capital
recovery,
$
55,600
58,600
137,000
154,000
391,000
397,000
58,600
137,000
154,000
186,000
391,000
397,000
717,000
55,600
152,000
391,000
75,300
215,000
560,000
75,300
213,000
552,000
65,100
233,000
Total
annual cost,
$
242,000
255,000
568,000
645,000
1,550,000
1,620,000
255,000
556,000
645,000
747,000
1,600,000
1,620,000
2,900,000
244,000
654,000
1,650,000
141,000
391,000
1,010,000
141,000
392,000
1,000,000
103,000
448,000
o
"Costs shown are for SCR systems used downstream of gas turbines with wet injection to achieve controlled NO x emission levels at the inlet to the SCR as shown in Table 6-6.
-------
TABLE 6-10. CAPITAL AND ANNUAL COSTS FOR SCR USED DOWNSTREAM OF LOW-NO COMBUSTION
Model plant a
CON-L-3.3-42
CON-L-4.0-42
CON-L-4.5-42
CON-L-8.8-42
CON -L-l 0-42
CON-L-3.3-25
CON-L-4.0-25
CON-L-4.5-25
CON-L-8.8-25
CON -L-l 0-25
CON-L-39-25
CON-L-83-25
CON-L-85-25
PKR-L-3.3-42
PKR-L-4.0-42
PKR-L-4.5-42
PKR-L-8.8-42
PKR-L-10-42
PKR-L-3.3-25
PKR-L-4.0-25
PKR-L-4.5-25
PKR-L-8.8-25
PKR-L-10-25
PKR-L-39-25
PKR-L-83-25
PKR-L-85-25
GT model
Centaur T4500
Centaur 'H1
Taurus
Mars T 12000
Mars T 14000
Centaur T4500
Centaur 'H1
Taurus
Mars T 12000
Mars T 14000
MS6000
ABB GT11N
MS7001E
Centaur T4500
Centaur 'H1
Taurus
Mars T 12000
Mars T 14000
Centaur T4500
Centaur 'H1
Taurus
Mars T 12000
Mars T 14000
MS6000
ABB GT11N
MS7001E
Total capital
invest, $b
622,000
658,000
683,000
896,000
956,000
622,000
658,000
683,000
896,000
956,000
2,400,000
4,600,000
4,670,000
622,000
658,000
683,000
896,000
956,000
623,000
658,000
683,000
896,000
956,000
2,400,000
4,600,000
4,670,000
Operating
labor,$
25,600
25,600
25,600
25,600
25,600
25,600
25,600
25,600
25,600
25,600
25,600
25,600
25,600
6,400
6,400
6,400
6,400
6,400
6,400
6,400
6,400
6,400
6,400
6,400
6,400
6,400
Super-
visory
labor, $
3,840
3,840
3,840
3,840
3,840
3,840
3,840
3,840
3,840
3,840
3,840
3,840
3,840
960
960
960
960
960
960
960
960
960
960
960
960
960
Main-
tenance
labor &
materials, $
29,900
30,800
31,400
36,800
38,300
29,900
30,800
31,400
36,800
38,300
74,600
130,000
132,000
7,480
7,700
7,860
9,200
9,580
7,480
7,700
7,860
9,200
9,580
18,600
32,500
32,900
Catalyst
replacement,
$
52,700
56,000
58,400
78,600
84,200
52,700
56,000
58,400
78,600
84,200
221,000
429,000
435,000
55,100
107,000
109,000
9,300
13,200
14,600
19,600
21,100
9,300
13,200
14,000
14,600
19,600
Catalyst
disposal, $
970
1,180
1,330
2,590
2,950
970
1,180
1,330
2,590
2,950
11,490
24,540
24,960
2,870
6,140
6,240
0
240
330
650
740
0
240
290
330
650
Ammonia,$
2,980
3,470
3,800
6,850
7,530
1,440
1,680
1,840
3,320
3,650
14,300
29,600
30,100
740
870
950
1,710
1,880
360
420
460
830
910
3,590
7,390
7,520
Dilution
steam, $
1,770
2,070
2,270
4,080
4,490
860
1,000
1,100
1,980
2,180
8,550
17,600
17,900
440
520
570
1,020
1,120
210
250
270
490
540
2,140
4,410
4,480
Perfor-
mance
loss, $
7,920
9,600
10,800
21,100
24,000
7,920
9,600
10,800
21,100
24,000
93,600
200,000
203,000
1,980
2,400
2,700
5,280
6,000
1,980
2,400
2,700
5,280
6,000
23,400
50,000
50,800
Blower
(if
needed),
$
790
960
1,080
2,110
2,400
790
960
1,080
2,110
2,400
9,360
20,000
20,300
200
240
270
530
600
200
240
270
530
600
2,340
5,000
5,080
Over-
head, $
35,600
36,100
36,500
39,700
40,600
35,600
36,100
36,500
39,700
40,600
62,400
95,700
96,900
8,900
9,000
9,100
9,900
10,200
8,900
9,000
9,100
9,900
10,200
15,600
23,900
24,200
Taxes,
insurance
& admin., $
24,900
26,300
27,300
35,800
38,200
24,900
26300
27,300
35,800
38,200
96,000
184,000
186,800
24,900
26,300
27,300
35,800
38,200
24,900
26,300
27,300
35,800
38,200
96,000
184,000
186,800
Capital
recovery,
$
55,500
58,600
60,700
78,600
83,700
55,500
58600
60,700
78,600
83,700
205,000
391,000
397,000
54,300
33,200
35,500
113,000
119,000
74,600
76,800
79,300
113,000
119,000
309,000
598,000
604,000
Total annual
cost, $
242,000
255,000
263,000
336,000
356,000
240,000
252,000
260,000
330,000
350,000
826,000
1,550,000
1,570,000
164,000
201,000
207,000
193,000
207,000
141,000
151,000
156,000
192,000
206,000
492,000
927,000
943,000
aSee Table 6-7 for model plant legend.
bCosts shown are for SCR systems used downstream of gas turbines with dry low-NO
, combustion to achieve controlled NO ^ emission levels at the inlet to the SCR as shown in Table 6-7.
-------
ii. Annual Costs
Total annual costs for SCR control were developed following
standard EPA procedures described in the OAQPS Control Cost
Manual for other types of add-on air pollution control devices
(APCD's). Information about annual costs was obtained from the
same sources that provided capital costs.27"31 Total annual costs
consist of direct and indirect costs; parameters that make up
these categories and the equations for estimating the costs are
6-242
-------
6-243
-------
6-244
-------
presented in Table 6-8 and are discussed below. The annual costs
are shown in Tables 6-9 and 6-10 for injection and dry low-NOx
combustion, respectively, for each of the model plants.
(1) Operating and Supervisory Labor. Information about
operating labor requirements was unavailable. Most facilities
have fully automated controls and monitoring/recording equipment,
which minimizes operator attention. Therefore, it was assumed
that 1 hr of operator attention would be required during an 8-hr
shift, regardless of turbine size. This operating labor
requirement is at the low end of the range recommended in the
OAQPS Control Cost Manual for other types of APCD's.7 Operator
wage rates were estimated to be $25.60/hr in 1990, based on
escalating the costs presented in Reference 2 by 5 percent per
year to account for inflation. Supervisory labor costs were
estimated to be 15 percent of the operating labor costs,
consistent with the OAQPS Control Cost Manual.
(2) Maintenance Labor and Materials. Combined maintenance
labor and materials costs for 14 facilities were obtained from
four articles, but almost half of the data (6 facilities) were
provided by one source.27"30 The costs were escalated to 1990
dollars assuming an inflation rate of 5 percent per year. All of
the data are for facilities that burn natural gas. Provided that
ammonium salt formation is avoided by limiting ammonia slip and
sulfur content, the cost for operation with natural gas should
also apply for distillate oil fuel.32 Therefore, it was assumed
that the cost data also apply to SCR control for turbines that
fire distillate oil fuel. The costs were plotted versus the
turbine size, and least-squares linear regression was used to
determine the equation of the line through the data (see
Appendix B). This equation, shown in Table 6-8, was used to
estimate the maintenance labor and materials costs shown in
Table 6-9 for the model plants.
(3) Catalyst Replacement. Replacement costs were obtained
for nine gas turbine facilities, and combined replacement and
disposal costs were obtained for another six gas turbine
facilities.27"30 The disposal costs were estimated for the six
6-245
-------
facilities as described below and in Appendix B. The replacement
costs for these six facilities were then estimated by subtracting
the estimated disposal costs from the combined costs. A catalyst
life of 5 years was used. All replacement costs were escalated
to 1990 dollars assuming a 5 percent annual inflation rate.
The estimated 1990 replacement costs were plotted versus the
turbine size, and least-squares linear regression was used to
determine the equation of the line through the data (see
Appendix B). This equation is shown in Table 6-8 and was used to
estimate the catalyst replacement costs shown in Table 6-9 for
the model plants.
(4) Catalyst Disposal. Catalyst disposal costs were
estimated based on a unit disposal cost of $15/ft3, which was
obtained from a zeolite catalyst vendor.32 This cost was used
for each model plant, but the disposal cost may in fact be higher
for catalysts that contain heavy metals and are classified as
hazardous wastes. The catalyst volume for each model plant was
estimated based on information about the catalyst volume for one
facility and the assumption that there is a direct relationship
between the catalyst volume and the turbine output (i.e., the
design space velocity is the same regardless of the SCR size) .
At one facility, 175 m3 (6,180 ft3) of catalyst is used in the
SCR with an 83 MW (111,000 hp) turbine.33 The disposal cost for
this catalyst would be $92,700, using a cost of $15/ft3.
(5) Ammonia. The annual ammonia (NH3) requirement is
calculated from the annual NOX reduction achieved by the SCR
system. Based on an NH3/NOX molar ratio of 1.0, the annual
ammonia requirement, in tons, would equal the annual NOX
reduction, in tons, multiplied by the ratio of the molecular
weights for NH3 and NOX. Anhydrous ammonia with a unit cost of
$360/ton was used.34'35 The equation to calculate the annual cost
for ammonia is shown in Table 6-8.
(6) Dilution Steam. As indicated in Section 5.3.1, steam
is used to dilute the ammonia to about 5 percent by volume before
injection into the HRSG. According to the OAQPS Control Cost
6-246
-------
Manual, the cost to produce steam, or to purchase it, is about
$6/1,000 Ib.
(7) Electricity. Electricity requirements to operate such
equipment as ammonia pumps and ventilation fans is believed to be
small. For one facility, the cost of electricity to operate
these components was estimated to make up less than 1 percent of
the total annual cost, but it is not clear that the number and
size of the fans and pumps represent a typical installation.27
This cost for electricity is expected to be minor, however, for
all installations and was not included in this analysis.
For high-temperature catalysts installed upstream of the
HRSG, a blower may be required to inject ambient air into the
exhaust to regulate the temperature and avoid temperature
excursions above the catalyst design temperature range. The cost
to operate the blower is calculated to be 10 percent of the fuel
penalty.35
(8) Performance Loss. The performance loss due to
backpressure from the SCR is approximately 0.5 percent of the
turbine's design output.34"36 To make up for this lost output, it
was assumed that electricity would have to be purchased at a cost
of $0.06/kWH, as indicated in Table 6-3.
(9) Production Loss. No costs for production losses were
included in this analysis. It was assumed that scheduled
inspections, cleaning, and other maintenance will coincide with
the 760 hr/yr of expected or scheduled downtime. It should be
recognized that adding the SCR system increases the overall
system complexity and the probability of unscheduled outages.
This factor should be taken into account when considering the
addition of an SCR system.
(10) Overhead. Standard EPA procedures for estimating
annual control costs include overhead costs that are equal to
60 percent of all labor and maintenance material costs.
(11) Property Taxes, Insurance, and Administration.
According to standard EPA procedures for estimating annual
control costs, property taxes, insurance, and administration
6-247
-------
costs are equal to 4 percent of the total capital investment for
the control system.
(12) Capital Recovery. The CRF for SCR was estimated to be
0.13147 based on the assumption that the equipment life is
15 years and the interest rate is 10 percent.
iii. Cost Effectiveness for SCR
As indicated in Section 5.4, virtually all gas turbine
installations using SCR to reduce NOX emissions also incorporate
wet injection or low-NOx combustors. The NOX emission levels
into the SCR, therefore, were in all cases taken to be equal to
the controlled NOX emission levels shown for these control
techniques in Tables 6-6 and 6-7. The most common controlled NOX
emission limit for gas-fired SCR applications is 9 ppmv,
referenced to 15 percent oxygen. The capital costs used in this
analysis are expected to correspond to SCR systems sized to
reduce controlled NOX emissions ranging from 25 to 42 ppmv from
gas-fired turbines to a controlled level of approximately 9 ppmv
downstream of the SCR. Based on the controlled NOX emission
limits established by the Northeast States for Coordinated Air
Use Management (NESCAUM), shown in Table 5-3, these SCR systems
would reduce NOX emissions to 18 ppmv for oil-fired applications.
Cost-effectiveness figures for SCR in this analysis are therefore
calculated based on controlled NOX emission levels of 9 and
18 ppmv, corrected to 15 percent oxygen, for gas- and oil-fired
SCR model plants, respectively.
Cost effectiveness for SCR used downstream of wet injection
or dry low-NOx combustion is shown in Tables 6-11
6-24!
-------
TABLE 6-11.
COST-EFFECTIVENESS SUMMARY FOR SCR USED DOWNSTREAM OF GAS TURBINES WIT H
WET INJECTION (1990 $)
Model plant
CON-G-W-3.3
CON-G-W-4.0
CON-G-W-22.7
CON-G-W-26.8
CON-G-W-83.3
CON-G-W-84.7
CON-G-S-4.0
CON-G-S-22.7
CON-G-S-26.8
CON-G-S-34.4
CON-G-S-83.3
CON-G-S-84.7
CON-G-S-161
CON-O-W-3.3
CON-O-W-26.3
CON-O-W-83.3
PKR-G-W-3.3
PKR-G-W-26.8
PKR-G-W-84.7
PKR-O-W-3.3
PKR-O-W-26.3
PKR-O-W-84.7
STD-O-W-1.1
STD-O-E-28.0
GT model
Centaur T4500
501-KB5
LM2500
MS5001P
ABB GT11N
MS7001E
501-KB5
LM2500
MS5001P
LM5000
ABBGT11N
MS7001E
MS7001F
Centaur T4500
MS5001P
MS7001E
Centaur T4500
MS5001P
MS7001E
Centaur T4500
MS5001P
MS7001E
Saturn Tl 500
TPM FT4
Turbine output,
MW
3.3
4.0
22.7
26.8
83.3
84.7
4.0
22.7
26.8
34.4
83.3
84.7
161
3.3
26.3
83.3
3.3
26.8
84.7
3.3
26.3
84.7
1.1
28.0
NOX emissions"
Inlet to SCR
ppmv
42
42
42
42
25
42
42
25
42
25
42
42
42
60
65
65
42
42
42
60
65
65
60
50
tons/yr
28.5
34.2
140
214
347
593
34.2
83.5
214
126
583
593
1,030
41.8
337
938
7.12
53.5
148
10.5
84.2
234
1.99
37.3
Downstream of SCR
ppmv
9.0
9.0
9.0
9.0
9.0
9.0
9.0
9.0
9.0
9.0
9.0
9.0
9.0
18.0
18.0
18.0
9.0
9.0
9.0
18.0
18.0
18.0
18.0
18.0
tons/yr
6.10
7.32
30.0
45.8
125
127
7.32
30.0
45.8
45.2
125
127
221
12.5
93.3
260
1.52
11.5
31.8
3.14
23.3
64.9
0.60
13.4
Total NOX
removed, tons/yr
22.4
26.8
110
168
222
466
26.8
53.4
168
80.4
458
466
809
29.3
244
678
5.59
42.0
116
7.32
60.9
169
1.39
23.9
Total annual cost,
-------
TABLE 6-12
COST-EFFECTIVENESS SUMMARY FOR SCR USED DOWNSTREAM
OF DRY LOW-NOx COMBUSTION (1990 $)
Model plant"
CON-L-3.3-42
CON-L-4.0-42
CON-L-4.5-42
CON-L-8.8-42
CON-L- 10-42
CON-L-3.3-25
CON-L-4.0-25
CON-L-4.5-25
CON-L-8.8-25
CON-L- 10-25
CON-L-39-25
CON-L-83-25
CON-L-85-25
PKR-L-3.3-42
PKR-L-4.0-42
PKR-L-4.5-42
PKR-L-8.8-42
PKR-L- 10-42
PKR-L-3.3-25
PKR-L-4.0-25
PKR-L-4.5-25
PKR-L-8.8-25
PKR-L- 10-25
PKR-L-39-25
PKR-L-83-25
PKR-L-85-25
GT model
Centaur T4500
Centaur 'H'
Taurus
Mars T 12000
Mars T 14000
Centaur T4500
Centaur 'H'
Taurus
Mars T 12000
Mars T 14000
MS6000
ABBGT11N
MS7001E
Centaur T4500
Centaur 'H'
Taurus
Mars T 12000
Mars T 14000
Centaur T4500
Centaur 'H'
Taurus
Mars T 12000
Mars T 14000
MS6000
ABB GT11N
MS7001E
Turbine
output, MW
3.3
4.0
4.5
8.8
10.0
3.3
4.0
4.5
8.8
10.0
39.0
83.3
84.7
3.3
4.0
4.5
8.8
10.0
3.3
4.0
4.5
8.8
10.0
39.0
83.3
84.7
NOX emissions'"
Uncontrolled
ppmvc
130
105
114
178
199
130
105
114
178
199
220
390
154
130
105
114
178
199
130
105
114
178
199
220
390
154
tons/yr
88.1
83.0
98.7
278
341
88.1
83.0
98.7
278
341
1,480
5,420
2,180
22.0
20.7
24.7
69.4
85.4
22.0
20.7
24.7
69.4
85.4
371
1,350
540
Inlet to SCR
ppmv
42
42
42
42
42
25
25
25
25
25
25
25
25
42
42
42
42
42
25
25
25
25
25
25
25
25
tons/yr
28.5
33.2
36.4
65.5
72.1
16.9
19.8
21.7
39.0
42.9
168
347
353
7.12
8.30
9.09
16.4
18.0
4.24
4.94
5.41
9.75
10.7
42.1
86.8
88.3
Downstream of SCR
ppmv
9.0
9.0
9.0
9.0
9.0
9.0
9.0
9.0
9.0
9.0
9.0
9.0
9.0
9.0
9.0
9.0
9.0
9.0
9.0
9.0
9.0
9.0
9.0
9.0
9.0
9.0
tohs/yr
6.1
7.1
7.8
14.0
15.4
6.1
7.1
7.8
14.0
15.4
61
125
127
1.52
1.78
1.95
3.5
3.9
1.52
1.78
1.95
3.51
3.9
15.2
31.3
31.8
Total NOX
removed,
tons/yr
22.4
26.1
28.6
51.5
56.6
10.8
12.6
13.9
25.0
27.5
108
222
226
5.6
6.5
7.1
12.9
14.2
2.7
3.2
3.5
6.2
6.9
26.9
55.6
56.5
Total annual
cost, $d
242,000
255,000
263,000
336,000
356,000
240,000
252,000
260,000
330,000
350,000
826,000
1,550,000
1,570,000
164,000
201,000
207,000
193,000
207,000
141,000
151,000
156,000
192,000
206,000
492,000
927,000
943,000
CJ
1
1
K
Cost effective-,.
n
ness, $/ton (T>
(Ji
10,800 ^
9,780 Q
9,200 rl
6,530 <<
6,290
22,100 "5
19,900
18,800 ^
13,200 O
12,800 h
7,660 n
6,970 ฐ
1 '
6,940 rl
29,300 2
30,800 O
29,000 ^
15,000 1
14,600 J3
rl
52,000 ^
47,800 "
45,000 ฃ
30,800 ^
30,000 ฃ
18,300 ^
16,700 h-
16,700 .^
Cn
O
"See Table 6-7 for model plant legend.
""Example NOX emission calculations are shown in Appendix A.
'Referenced to 15 percent oxygen.
dFrom Table 6-10.
Ul
I
CD
-------
model plants using water or steam injection,the cost
effectiveness for SCR ranges from approximately $3,500 to $10,800
per ton of NOX removed.
The cost-effectiveness range for SCR installed downstream of
continuous-duty, natural gas-fired turbines from 3 to 10 MW
(4,000 to 13,400 hp) using dry low-NOx combustion is $6,290 to
$10,800 per ton of NOX removed for an inlet NOX emission level of
42 ppmv. The cost-effectiveness range for SCR increases for an
6-251
-------
6-252
-------
inlet NOX emission level of 25 ppmv due to the lower NOX
reduction efficiency. For an inlet NOX level of 25 ppmv, the
cost effectiveness ranges from $12,800 to $22,100 per ton of NOX
removed for 3 to 10 MW (4,000 to 13,400 hp) turbines and
decreases to $6,940 to $7,660 per ton of NOX removed for larger
turbines ranging from 39 to 85 MW (52,300 to 114,000 hp). As
these ranges indicate, the cost effectiveness for SCR is affected
by the inlet NOX emission level and not the type of combustion
control technique used for the turbine. The cost effectiveness
for continuous-duty, oil-fired model plants ranges from
approximately $2,450 to $8,350 per ton of NOX removed. The SCR
cost-effectiveness range for oil-fired applications is lower than
that for gas-fired installations in this cost analysis because
the same capital costs were used for both fuels (capital costs
were not available for applications using only distillate oil
fuel). The percent NOX reduction for oil-fired applications is
higher, so the resulting cost-effectiveness figures for oil-fired
applications are lower. It should be noted that this higher NOX
reduction for oil-fired applications may require a larger
catalyst reactor, at a higher capital cost. As a result, the
cost-effectiveness figures may actually be higher than those
shown in Table 6-11 for oil-fired applications.
The cost-effectiveness figures are higher for smaller gas
turbines because the fixed capital costs associated with the
installation of an SCR system have the greatest impact on smaller
gas turbines. Cost-effectiveness figures increase as annual
operating hours decrease. For turbines operating 2,000 hours per
year, cost-effectiveness figures are more than double those for
continuous-duty model plants, and they increase even further for
model plants operating 1,000 hr/yr.
Because virtually all SCR systems are installed downstream
of controlled gas turbines, combined cost-effectiveness figures
for wet injection plus SCR and also dry low-NOx combustion plus
SCR have been calculated and are shown in Tables 6-13
6-253
-------
TABLE 6-13. COMBINED COST-EFFECTIVENESS SUMMARY FOR WET INJECTION PLUS SCR (1990 $)
Model plant
CON-G-W-3.3
CON-G-W-4.0
CON-G-W-22.7
CON-G-W-26.8
CON-G-W-83.3
CON-G-W-84.7
CON-G-S-4.0
CON-G-S-22.7
CON-G-S-26.8
CON-G-S-83.3
CON-G-S-84.7
CON-G-S-84.7
CON-G-S-161
CON-O-W-3.3
CON-O-W-26.3
CON-O-W-83.3
PKR-G-W-3.3
PKR-G-W-26.8
PKR-G-W-84.7
PKR-O-W-3.3
PKR-O-W-26.3
PKR-O-W-84.7
STD-O-W-1.1
STD-O-E-28.0
GT model
Centaur T4500
501-KB5
LM2500
MS5001P
ABB GT11N
MS7001E
501-KB5
LM2500
MS5001P
LM5000
ABBGT11N
MS7001E
MS7001F
Centaur T4500
MS5001P
MS7001E
Centaur T4500
MS5001P
MS7001E
Centaur T4500
MS5001P
MS7001E
Saturn Tl 500
TPM FT4
Turbine output
MW
3.3
4.0
22.7
26.8
83.3
84.7
4.0
22.7
26.8
34.4
83.3
84.7
161
3.3
26.3
83.3
3.3
26.8
84.7
3.3
26.3
84.7
1.1
28.0
NOX emissions"
Uncontrolled
ppmvb
130
155
174
142
390
154
155
174
142
185
390
154
210
179
211
228
130
142
154
179
211
228
150
150
tons/yr
88.1
126
581
723
5,410
2,170
126
581
723
930
5,410
2,170
5,150
125
1,090
3,290
22.0
181
543
31.2
273
822
4.97 122
Inlet to SCR
ppmv
42
42
42
42
25
42
42
25
42
25
42
42
42
60
65
65
42
42
42
60
65
65
60
50
t<5ns/yr
28.5
34.2
140
214
347
593
34.2
83.5
214
126
583
593
1,030
42
337
938
7.1
53.5
148
10
84
234
1.99
37.3
Downstream of SCR
ppmv
9.0
9.0
9.0
9.0
9.0
9.0
9.0
9.0
9.0
9.0
9.0
9.0
9.0
18.0
18.0
18.0
9.0
9.0
9.0
18.0
18.0
18.0
18.0
18.0
t&is/yr
6.10
7.32
30
46
125
127
7.32
30.0
45.8
45.2
125
127
220
12.5
93.3
260
1.5
11.5
31.8
3.14
23.3
64.9
0.60
13.4
Total NOX
removed,
tons/yrc
82.0
119
551
677
5,290
2,040
119
551
677
884
5,290
2,040
4,930
112
997
3,030
20.5
169
512
28.1
250
757
4.4
109
Total annual
cost, $c
366,000
417,000
1,000,000
1,220,000
4,460,000
3,100,000
423,000
977,000
1,130,000
1,440,000
3,410,000
2,780,000
4,870,000
387,000
1,410,000
3,230,000
222,000
690,000
1,710,000
228,000
751,000
1,710,000
152,000
604,000
Cost effective-
ness, $/tonc
4,460
3,510
1,820
1,800
843
1,520
3,560
1,770
1,670
1,630
645
1,360
988
3,450
1,410
1,070
10,800
4,080
3,340
8,130
3,000
2,260
34,700
5,563
I
[\J
Cn
"Example NOX emission calculations are shown in Appendix A.
""Referenced to 15 percent oxygen.
Total for both wet injection plus SCR control techniques.
-------
TABLE 6-14.
COMBINED COST-EFFECTIVENESS SUMMARY FOR DRY LOW-NOx COMBUSTION PLUS SCR
(1990 $)
Model plant
CON-L-3.3-42
CON-L-4.0-42
CON-L-4.5-42
CON-L-8.8-42
CON-L- 10-42
CON-L-3.3-25
CON-L-4.0-25
CON-L-4.5-25
CON-L-8.8-25
CON-L- 10-25
CON-L-39-25
CON-L-83-25
CON-L-85-25
PKR-L-3.3-42
PKR-L-4.0-42
PKR-L-4.5-42
PKR-L-8.8-42
PKR-L- 10-42
PKR-L-3.3-25
PKR-L-4.0-25
PKR-L-4.5-25
PKR-L-8.8-25
PKR-L- 10-25
PKR-L-39-25
PKR-L-83-25
PKR-L-85-25
GT model
Centaur T4500
Centaur 'H'
Taurus
Mars T 12000
Mars T 14000
Centaur T4500
Centaur 'H'
Taurus
Mars T 12000
Mars T 14000
MS6000
ABB GT11N
MS7001E
Centaur T4500
Centaur 'H'
Taurus
Mars T 12000
Mars T 14000
Centaur T4500
Centaur 'H'
Taurus
Mars T 12000
Mars T 14000
MS6000
ABBGT11N
MS7001E
Turbine
output
MW
3.3
4.0
4.5
8.8
10.0
3.3
4.0
4.5
8.8
10.0
39.0
83.3
84.7
3.3
4.0
4.5
8.8
10.0
3.3
4.0
4.5
8.8
10.0
39.0
83.3
84.7
Annual
operating
hours
8,000
8,000
8,000
8,000
8,000
8,000
8,000
8,000
8,000
8,000
8,000
8,000
8,000
2,000
2,000
2,000
2,000
2,000
2,000
2,000
2,000
2,000
2,000
2,000
2,000
2,000
NOX emissions"
Uncontrolled
ppmvb
130
105
114
178
199
130
105
114
178
199
220
390
154
130
105
114
178
199
130
105
114
178
199
220
390
154
tons/yr
88.1
83.0
98.7
278
341
88.1
83.0
98.7
278
341
1,480
5,420
2,180
22.0
20.7
24.7
69.4
85.4
22.0
20.7
24.7
69.4
85.4
371
1,350
540
Inlet to SCR
ppmv
42
42
42
42
42
25
25
25
25
25
25
25
25
42
42
42
42
42
25
25
25
25
25
25
25
25
toWyr
28.5
33.2
36.4
65.5
72.1
16.9
19.8
21.7
39.0
42.9
168
347
353
7.1
8.3
9.1
16.4
18.0
4.2
4.9
5.4
9.8
10.7
42.1
86.8
88.3
Downstream of SCR
ppmv
9.0
9.0
9.0
9.0
9.0
9.0
9.0
9.0
9.0
9.0
9.0
9.0
9.0
9.0
9.0
9.0
9.0
9.0
9.0
9.0
9.0
9.0
9.0
9.0
9.0
9.0
tohs/yr
6.1
7.1
7.8
14.0
15.4
6.1
7.1
7.8
14.0
15.4
60.6
125
127
1.5
1.8
1.9
3.5
3.9
1.5
1.8
1.9
3.5
3.9
15.2
31.3
31.8
Total NOX
removed,
tons/yrc
82.0
75.8
90.9
264
326
82.0
75.8
90.9
264
326
1,420
5,290
2,050
20.5
19.0
22.7
65.9
81.5
20.5
19.0
22.7
65.9
81.5
355
1,320
508
Total
annual
cost, $c
291,000
308,000
319,000
428,000
451,000
289,000
305,000
316,000
422,000
445,000
1,010,000
1,840,000
1,850,000
213,000
254,000
263,000
285,000
302,000
190,000
204,000
212,000
284,000
301,000
680,000
1,220,000
1,220,000
1
?
Cost effective-
ness, $/toij[)
3,55ฎ
4,06$
3,51,01-
1,62^-
1,380)
3,52$
4,020
3,470
1,60^
l,37fl>
7$>
348
9
I
[\J
Cn
"Example NOX emission calculations are shown in Appendix A.
""Referenced to 15 percent oxygen.
Total for both dry low-NOx combustion plus SCR control techniques.
(V
en
-------
figures are calculated by dividing the sum of the total annual
costs by the
6-256
-------
6-257
-------
sum of the annual reduction of NOX emissions for the combined
emission control techniques. For continuous-duty, natural gas-
fired model plants, the combined cost-effectiveness figures for
wet injection plus SCR range from approximately $650 to $4,500
per ton of NOX removed. For continuous-duty, oil-fired model
plants, the combined cost effectiveness ranges from approximately
$1,100 to $3,550 per ton of NOX removed. The combined cost-
effectiveness figures for dry low-NOx combustion plus SCR for
continuous-duty, natural gas-fired model plants range from
approximately $350 to $3,550 per ton of NOX removed.
The combined cost-effectiveness figures increase with
decreasing turbine size and annual operating hours. Data were
not available to quantify the wet injection requirements and
controlled emissions levels for oil-fired turbines with low-NOx
combustors, so cost-effectiveness figures were not tabulated for
this control scenario.
d. OFFSHORE TURBINES
The only available information about the cost of NOX
controls for offshore gas turbines was presented in a report
prepared for the Santa Barbara County Air Pollution Control
District (SBCAPCD) in California.37 The performance and cost of
about 20 NOX control techniques for a 2.8 MW (3,750 hp) turbine
were described in the report. Wet injection and SCR were
included in the analysis; low-NOx combustors were not. The costs
from the report are presented in Table 6-15
6-251
-------
TABLE 6-15. PROJECTED WET INJECTION AND SCR COSTS
FOR AN OFFSHORE GAS TURBINE3
Capital cost, $
Annual costs, $/yr
Ammonia
Catalyst replacement
Operating and maintenance"1
Fuel penalty6
Capital recovery1
Total annual costs, $/yr
Wet injection
costs
70, 000
N/Ab
N/A
24, 600
10,500
14, 000
49, 100
SCR costs
585, 000
3, 050C
28, 000
18, 000
5, 000
117, 000
171, 000
aCosts are for a 2.8 MW gas turbine and are obtained from
Reference 37.
bN/A = Not applicable.
"Ammonia cost is based on $150/ton and 0.4 Ib NH3/lb NOX.
dOperating and maintenance cost for SCR is estimated as 3 percent
of the total capital investment.
eFuel penalty is estimated as 2 percent of the annual fuel
consumption for wet injection and 1 percent for SCR.
fCapital recovery is estimated based on an equipment life of
8 years and an interest rate of 13 percent.
6-259
-------
without adjustment because there is insufficient cost
information to know what adjustments need to be made.
Additionally, insufficient information is available to scale up
these costs for larger turbines. The water and steam injection
costs and SCR costs for offshore applications are discussed in
Sections 6.4.1 and 6.4.2, respectively.
i. Wet Injection
The report prepared for SBCAPCD assumed water injection
costs are the same as steam injection costs. The report did not
describe the components in the capital cost analysis for these
injection systems, but the results are much lower than those that
6-260
-------
would be estimated by the procedures described in Section 6.1.1
of this report. The authors may have assumed that the engine-
mounted injection equipment cost was included in the turbine
capital cost and that a less rigorous water treatment process is
installed. Annual costs are also much lower than those that
would be estimated by the procedures described in Section 6.1.2
of this report. There are at least three reasons for the
difference: (1) the low capital cost leads to a low CRF, even
though the turbine life was assumed to be only 8 years;
(2) overhead costs and taxes, insurance, and administration costs
are not considered; and (3) the capacity factor is only
50 percent (i.e., about 4,400 hr/yr, vs. 8,000 hr/yr, as in
Section 6.1.2) . The turbine life was only 8 years, which may
correspond to a typical service life of an offshore platform.
ii. Selective Catalytic Reduction
The total capital costs presented in the report for SBCAPCD
are similar to those that would be estimated by the procedures in
Section 6.2.1 of this report. However, it appears that $150,000
of the total in Reference 37 is for structural modifications to
the platform and $75,000 is for retrofit installation. When the
difference in the load factor is taken into account, some of the
annual costs are similar to those that would be estimated by the
procedures in Section 6.2.2 for a similarly sized turbine. The
catalyst replacement cost, however, is much lower; neither the
type of catalyst nor the replacement frequency were identified.
Ammonia costs are lower because the uncontrolled NOX emission
level was assumed to be 110 ppmv instead of 150 ppmv and because
a unit cost of $150/ton was used instead of $400/ton. The
reference does not indicate whether or not catalyst disposal,
overhead, taxes, freight, and administration costs were
considered. Capital recovery costs are higher because the
equipment life is assumed to be only 8 years on the offshore
platform.
6-261
-------
REFERENCES FOR CHAPTER 6
I. 1990 Performance Specifications. Gas Turbine World.
11:20-48. 1990.
II. U. S. Environmental Protection Agency. Background
Information Document, Review of 1979 Gas Turbine New Source
Performance Standards. Research Triangle Park, NC.
Prepared by Radian Corporation under Contract
No. 68-02-3816. 1985.
III. Letter and attachments from Swingle, R., Solar
Turbines Incorporated, to Neuffer, W. J.,
EPA/ISB. August 20, 1991. Review of draft gas
turbine ACT document.
IV. Monthly Energy Review. Energy Information Administration.
March 1991. p. 113.
V. Petroleum Marketing Annual 1990. Energy Information
Administration.
VI. Reference 3, p. 109.
VII. OAQPS Control Cost Manual (Fourth Edition).
EPA-450/3-90-006. January 1990.
VIII. Letter and attachment from Leonard G., General
Electric Company, to Snyder, R., MRI. May 24,
1991. Response to gas turbine questionnaire.
IX. Letter and attachment from Swingle, R., Solar Turbines
Incorporated, to Snyder, R., MRI. February 8, 1991.
Maintenance considerations for gas turbines.
X. Telecon. Snyder, R., MRI, with Rayome, D., US Turbine
Corporation. May 6, 1991. Maintenance costs for gas
turbines.
XI. Telecon. Snyder, R., MRI, with Schorr, M., General Electric
Company. May 22, 1991. Gas turbine water injection.
XII. Letter and attachments from Gurmani, A., Asea
Brown Boveri, to Snyder, R., MRI. May 30, 1991.
Response to gas turbine questionnaire.
XIII. Letter and attachment from Gagnon, S., High
Purity Services, Inc., to Snyder, R., MRI.
April 4, 1991. Water treatment system design.
XIV. Letter and attachments from Gurmani, A., Asea
Brown Boveri, to Snyder, R., MRI. February 4,
1991. Response to gas turbine questionnaire.
6-262
-------
XV. Letter and attachment from Kimsey, D., Allison Gas Turbine
Division of General Motors, to Snyder, R., MRI.
February 19, 1991. Response to gas turbine request.
XVI. Letter and attachment from Leonard, G., General
Electric Company, to Snyder, R. MRI.
February 14, 1991. Response to gas turbine
questionnaire.
XVII. Letter and attachments from Cull, C. General
Electric Company, to Snyder, R., MRI. May 14,
1991. On-engine costs for water and steam
injection hardware.
XVIII. Bernstein, S., and P. Malte (Energy
International, Inc.). Emissions Control for Gas
Transmission Engines. Prepared for the Gas
Research Institute. Chicago. Presentation
No. PRES 8070. July 1989. 17 pp.
XIX. Letter and attachments from All, S. A., Allison
Gas Turbine Division of General Motors, to
Neuffer, W. J., EPA/ISB. August 30, 1991.
Review of draft gas turbine ACT document.
XX. Telecon. Snyder, R., MRI, with Schubert, R., General
Electric Marine and Industrial Division. April 26, 1991.
Maintenance costs for gas turbines.
XXI. Letter and attachments from Swingle, R., Solar
Turbines Incorporated, to Snyder, R., MRI.
May 21, 1991. Maintenance considerations for gas
turbines.
XXII. Walsh, E. Gas Turbine Operating and Maintenance
Considerations. General Electric Company.
Schenectady, NY. Presented at the 33rd GE
Turbine State-of-the-Art Technology Seminar for
Industrial, Cogeneration and Independent Power
Turbine Users. September 1989. 20 pp.
XXIII. Telecon. Snyder, R., MRI, with Pasquarelli, L.,
General Electric Company. April 26, 1991.
Maintenance costs for gas turbines.
XXIV. Letters and attachments from Schorr, M., General
Electric Company, to Snyder, R., MRI. March,
April 1991. Response to gas turbine
questionnaire.
6-263
-------
XXV.
XXVI.
XXVII.
XXVIII
XXIX.
XXX.
XXXI.
XXXII.
XXXIII
XXXIV.
Kolp, D. (Energy Services, Inc.), S. Gagnon (High
Purity Services), and M. Rosenbluth (The Proctor
and Gamble Co.). Water Treatment and Moisture
Separation in Steam Injected Gas Turbines.
Prepared for the American Society of Mechanical
Engineers. New York. Publication No. 90-GT-372,
June, 1990.
Letter from Cull, C., General Electric Company,
to Snyder, R., MRI. May 29, 1991. Low-N0x
Combustor Costs.
Permit Application Processing and Calculations by
South Coast Air Quality Management District for
proposed SCR control of gas turbine at Saint
John's Hospital and Health Center, Santa Monica,
CA. May 23, 1989.
Prosl, T. (DuPont), and G. Scrivner (Dow).
Technical Arguments and Economic Impact of SCR's
Use for NOX Reduction of Combustion Turbine for
Cogeneration. Paper presented at EPA Region VI
meeting concerning NOX abatement of combustion
turbines. December 17, 1987.
Sidebotham, G., and R. Williams. Technology of
NOX Control for Stationary Gas Turbines. Center
for Environmental Studies. Princeton University.
January 1989.
Shareef, G., and D. Stone. Evaluation of SCR NOX
Controls for Small Natural Gas-Fueled Prime
Movers. Phase I. Prepared by Radian Corporation
for Gas Research Institute. July 1990.
Hull, R., C. Urban, R. Thring, S. Ariga, M.
Ingalls, and G. O'Neal. Nox Control Technology
Data Base for Gas-Fueled Prime Movers, Phase I.
Prepared by Southwest Research Institute for Gas
Research Institute. April 1988.
Letter and attachments from Henegan, D., Norton
Company, to Snyder, R., MRI. March 28, 1991.
Response to SCR questionnaire.
Schorr, M. NOX Control for Gas Turbines:
Regulations and Technology. General Electric
Company. Schenectady, New York. Paper presented
at the Council of Industrial Boiler Owners NOX
Control IV Conference. Concord, California.
February 11-12, 1991. 11 pp.
Letter and attachment from Smith, J. C.,
Institute of Clean Air Companies, to Neuffer, W.
6-264
-------
J., EPA/ISB. May 14, 1992. Response to EPA
questionnaire regarding flue gas treatment
processes for emission reductions dated March 12,
1992.
XXXV. State of California Air Resources Board.
Determination of Reasonably Available Control
Technology and Best Available Retrofit Technology
for the Control of Oxides of Nitrogen From
Stationary Gas Turbines. May 18, 1992.
XXXVI. Field Survey of SCR Gas Turbine Operating
Experience. Prepared for the Electric Power
Research Institute. Palo Alto, CA. May, 1991.
XXXVII. Offshore Gas Turbine NOX Control Technology
Development Program. Phase I Technology
Evaluation. Arthur D. Little, Inc. for Santa
Barbara County Air Pollution Control District.
August 1989.
XXXVIII. Champagne, D. See SCR Cost-effective for Small
Gas Turbines. Cogeneration. January-February
1988. pp. 26-29.
6-265
-------
6-266
-------
7..0 ENVIRONMENTAL AND ENERGY IMPACTS
This chapter presents environmental and energy impacts for
the nitrogen oxide (NOX) emissions control techniques described
in Chapter 5.0. These control techniques are water or steam
injection, dry low-NOx combustors, and selective catalytic
reduction (SCR) . The impacts of the control techniques on air
pollution, solid waste disposal, water pollution, and energy
consumption are discussed.
The remainder of this chapter is organized in five sections.
Section 7.1 presents the air pollution impacts; Section 7.2
presents the solid waste disposal impacts; Section 7.3 presents
the water pollution impacts; and Section 7.4 presents the energy
consumption impacts. References for the chapter are listed in
Section 7.5.
a. AIR POLLUTION
i. Emission Reductions
Applying any of the control techniques discussed in
Chapter 5 will reduce NOX emissions from gas turbines. These
emission reductions were estimated for the model plants presented
in Table 6-1 and are shown in Table 7-1. For each model plant,
the uncontrolled and controlled emissions, emission reductions,
and percent reductions are presented. The following paragraphs
discuss NOX emission reductions for each control technique.
Nitrogen oxide emission reductions for water or steam
injection are estimated as discussed in Section 6.1.3. The
percent reduction in emissions from uncontrolled levels varies
for each model plant ranging, from 60 to 96 percent. This
reduction depends on each model's uncontrolled emissions, the
7-1
-------
TABLE 7-1.
MODEL PLANT UNCONTROLLED AND CONTROLLED NOX
AVAILABLE NCX CONTROL TECHNIQUES
EMISSIONS FOR
Gas turbine model
Centaur T4500
3.3 MW
Gas fuel
501-KB5
4.0 MW
Gas fuel
LM2500
22.7 MW
Gas fuel
MS5001P
26.8 MW
Gas fuel
ABB GT11N
83.3 MW
Gas fuel
MS7001E
84.7 MW
Gas fuel
501-KB5
4.0 MW
Gas fuel
LM2500
22.7 MW
Gas fuel
MS5001P
26.8 MW
Gas fuel
Annual
operating
hours
8,000
8,000
8,000
8,000
8,000
8,000
8,000
8,000
8,000
Type of
wet
injection
Water
Water
Water
Water
Water
Water
Steam
Steam
Steam
Annual emissions"
Emissions, tons/yr
Reduction, tons/yr
Total reduction, %
Emissions, tons/yr
Reduction, tons/yr
Total reduction, %
Emissions, tons/yr
Reduction, tons/yr
Total reduction, %
Emissions, tons/yr
Reduction, tons/yr
Total reduction, %
Emissions, tons/yr
Reduction, tons/yr
Total reduction, %
Emissions, tons/yr
Reduction, tons/yr
Total reduction, %
Emissions, tons/yr
Reduction, tons/yr
Total reduction, %
Emissions, tons/yr
Reduction, tons/yr
Total reduction, %
Emissions, tons/yr
Reduction, tons/yr
Total reduction, %
Uncon-
trolled NOX
emissions,"
tons/yr
88.1
126
581
723
5,410
2,170
126
581
723
Controlled NO., emissions, tons/year
Wet injection
to levels in
Table 6-6
28.5
59.6
68%
34.2
91.8
73%
140
441
76%
214
509
70%
347
5,060
94%
593
1580
73%
34.2
92
73%
83.5
498
86%
214
509
70%
Dry low-NOx
combustor to
42 ppmv
28.5
59.6
68%
NA
_
NA
_
NA
_
NA
_
NA
_
NA
_
NA
_
NA
_
Dry low-NOx
combustor to
25 ppm
16.9
71.2
81%
NA
_
NA
_
NA
_
347
5060
94%
353
1820
84%
NA
_
NA
_
NA
_
Dry low-NOx
combustor to
9 ppmv
NAd
_
NA
_
NA
_
NA
_
125
5290
98%
127
2040
94%
NA
_
NA
_
NA
_
NOX
emissions, wet
injection
+ SCRb
6.10
22.4
93%
7.32
26.9
94%
30.0
110
95%
45.8
168
94%
125
222
98%
127
466
94%
7.32
26.9
94%
30.0
53.5
95%
45.8
168
94%
SCR NH3 emissions
@ SLIP = 10 ppm
(tons/yr)c
2.92
2.58
11.2
20.4
51.7
49.6
2.58
11.2
20.4
7-2
-------
TABLE 7-1. (continued)
Gas turbine model
LM5000
34.4 MW
Gas fuel
ABB GT11N
83.3 MW
Gas fuel
MS7001E
84.7 MW
Gas fuel
MS7001F
161 MW
Gas fuel
Centaur T4500
3.3 MW
Oil fuel
MS5001P
26.3 MW
Oil fuel
MS7001E
83.3 MW
Oil fuel
Centaur T4500
3.3 MW
Gas fuel
MS5001P
26.8 MW
Gas fuel
Annual
operating
hours
8,000
8,000
8,000
8,000
8,000
8,000
8,000
2,000
2,000
Type of
wet
injection
Steam
Steam
Steam
Steam
Water
Water
Water
Water
Water
Annual emissions"
Emissions, tons/yr
Reduction, tons/yr
Total reduction, %
Emissions, tons/yr
Reduction, tons/yr
Total reduction, %
Emissions, tons/yr
Reduction, tons/yr
Total reduction, %
Emissions, tons/yr
Reduction, tons/yr
Total reduction, %
Emissions, tons/yr
Reduction, tons/yr
Total reduction, %
Emissions, tons/yr
Reduction, tons/yr
Total reduction, %
Emissions, tons/yr
Reduction, tons/yr
Total reduction, %
Emissions, tons/yr
Reduction, tons/yr
Total reduction, %
Emissions, tons/yr
Reduction, tons/yr
Total reduction, %
Uncon-
trolled NOX
emissions,"
tons/yr
930
5,410
2,170
5,150
125
1,090
3,290
22.0
181
Controlled NO., emissions, tons/year
Wet injection
to levels in
Table 6-6
126
804
86%
583
4830
89%
593
1580
73%
1,030
4120
80%
41.8
83.2
67%
337
753
69%
938
2350
71%
7.1
14.9
68%
53.5
128
70%
Dry low-NOx
combustor to
42 ppmv
NA
_
NA
_
NA
_
NA
_
NA
_
NA
_
NA
_
NA
_
NA
_
Dry low-NOx
combustor to
25 ppm
NA
_
347
5060
94%
353
1820
84%
610
4540
88%
NA
_
NA
_
NA
_
NA
_
NA
_
Dry low-NOx
combustor to
9 ppmv
NA
_
125
5290
98%
127
2040
94%
NA
_
NA
_
NA
_
NA
_
NA
_
NA
_
NOX
emissions, wet
injection
+ SCRb
45.2
80.8
95%
125
458
98%
127
466
94%
221
809
96%
12.5
29.3
90%
46.6
290
96%
130
808
96%
1.5
6
93%
11.5
42
94%
SCR NH3 emissions
@ SLIP = 10 ppm
(tons/yr)c
20.5
51.7
49.6
71.7
2.9
20.4
49.6
0.7
5.1
7-3
-------
TABLE 7-1. (continued)
Gas turbine model
MS7001E
84.7 MW
Gas fuel
Centaur T4500
3.3 MW
Oil fuel
MS5001P
26.8 MW
Oil fuel
MS7001E
84.7 MW
Oil fuel
SATURN T1500
1.1 MW
Oil fuel
TPM FT4
28.0 MW
Oil fuel
Annual
operating
hours
2,000
2,000
2,000
2,000
1,000
1,000
Type of
wet
injection
Water
Water
Water
Water
Water
Water-in-
oil
emulsion
Annual emissions"
Emissions, tons/yr
Reduction, tons/yr
Total reduction, %
Emissions, tons/yr
Reduction, tons/yr
Total reduction, %
Emissions, tons/yr
Reduction, tons/yr
Total reduction, %
Emissions, tons/yr
Reduction, tons/yr
Total reduction, %
Emissions, tons/yr
Reduction, tons/yr
Total reduction, %
Emissions, tons/yr
Reduction, tons/yr
Total reduction, %
Uncon-
trolled NOX
emissions,"
tons/yr
543
31.2
273
822
5.00
977
Controlled NO., emissions, tons/year
Wet injection
to levels in
Table 6-6
148
395
73%
10.0
21.2
68%
84
189
69%
234
588
72%
1.99
3
60%
37.3
940
96%
Dry low-NOx
combustor to
42 ppmv
NA
_
NA
_
NA
_
NA
_
NA
_
NA
_
Dry low-NOx
combustor to
25 ppm
88
455
84%
NA
_
NA
_
NA
_
NA
_
NA
_
Dry low-NOx
combustor to
9 ppmv
32
511
94%
NA
_
NA
_
NA
_
NA
_
NA
_
NOX
emissions, wet
injection
+ SCRb
31.8
116
94%
3.14
6.9
90%
23.3
61
91%
64.9
169
92%
0.30
1.7
94%
6.72
30.6
99%
SCR NH3 emissions
@ SLIP = 10 ppm
(tons/yr)c
12.4
0.7
5.1
12.4
0.13
NCe
_
"Uncontrolled and controlled NOX emissions are from cost-effectiveness tables in Chapter 6.
""Controlled NOX emission level for wet injection plus SCR is 9 ppmv for natural gas fuel and 18 ppmv for distillate oil fuel.
cAmmonia emissions, in tons per year = (SLIP, ppmv) x (MM/1,000,000) x (GT exhaust,lb/sec) x (MW NH3 = 15/MW exhaust = 28.6) x (3,600 sec/hr) x (ton/2,000 Ib) x (annual
operating hrs).
dNA-control technology not available for this model plant.
eNC-data not available to calculate emissions for this control scenario.
7-4
-------
water-to-fuel ratio (WFR), and type of fuel and whether water or
steam is injected.
Achievable emission levels from gas turbines using dry low-
NOX combustors were obtained from manufacturers. Controlled NOX
levels of 42, 25, and 9 parts per million, by volume (ppmv),
referenced to 15 percent oxygen, were reported by the various
turbine manufacturers, and each of these levels is shown in
Table 7-1, where applicable, for each model plant. The percent
reduction in NOX emissions from uncontrolled levels for gas
turbines using these combustors ranges from 68 to 98 percent.
Virtually all SCR units installed in the United States are used
in combination with either wet controls or combustion controls.
For this analysis, emission reductions were calculated for SCR in
combination with water or steam injection. Using the turbine
manufacturers' guaranteed NOX emissions figures for wet injection
and a controlled NOX emission level of 9 ppmv, referenced to 15
percent oxygen, exiting the SCR, the percent reduction in NOX
emissions for this combination of control techniques ranges from
93 to 99 percent.
Estimated ammonia (NH3) emissions, in tons per year,
corresponding to ammonia slip from the SCR system are also shown
in Table 7-1. These estimates are based on an ammonia slip level
of 10 ppmv, consistent with information and data presented in
Section 5.4. For continuous-duty model plants, the annual NH3
emissions range from approximately 3 tons for a 3.3 megawatt (MW)
(4,425 horsepower [hp]) model plant to 72 tons for a 160 MW
(215,000 hp) model plant.
ii. Emissions Trade-Qffs
The formation of both thermal and fuel NOX depends upon
combustion conditions. Water/steam injection, lean combustion,
and reduced residence time modify combustion conditions to reduce
the amount of NOX formed. These combustion modifications may
increase carbon monoxide (CO) and unburned hydrocarbon (HC)
emissions. Using SCR to control NOX emissions produces ammonia
emissions. The impacts of these NOX controls on CO, HC, and
ammonia emissions are discussed below.
7-5
-------
(1) Impacts of Wet Controls on CO and HC Emissions. As
discussed in Section 5.1.5, wet injection may increase CO and HC
emissions. Injecting water or steam into the flame area of a
turbine combustor lowers the flame temperature and thereby
reduces NOX emissions. This reduction in temperature to some
extent inhibits complete combustion, resulting in increased CO
and HC emissions. Figure 5-12 shows the impact of water and
steam injection on CO emissions for production gas turbines.2
The impact of steam injection on CO emissions is less than that
of water injection. As seen in Figure 5-12, CO emissions
increase with increasing WFR's. Wet injection increases HC
emissions to a lesser extent than it increases CO emissions.
Figure 5-13 shows the impact of water injection on HC emissions
for one turbine. In cases where water and steam injection result
in excessive CO and HC emissions, an oxidation catalyst (add-on
control) can be installed to reduce these emissions by converting
the CO and HC to water (H20) and carbon dioxide (C02) .
(2) Impacts of Combustion Controls on CO and HC Emissions.
As discussed in Section 5.2.1, the performance of lean combustion
in limiting NOX emissions relies in part on reduced equivalence
ratios. As the equivalence ratio is reduced below the
stoichiometric level of 1.0, combustion flame temperatures drop,
and as a result NOX emissions are reduced. Shortening the
residence time in the high-temperature flame zone also will
reduce the amount of thermal NOX formed. These lower equivalence
ratios and/or reduced residence time, however, may result in
incomplete combustion, which may increase CO and HC emissions.
The extent of the increase in CO and HC emissions is specific to
each turbine manufacturer's combustor designs and therefore
varies for each turbine model. As with wet injection, if
necessary, an oxidation catalyst can be installed to reduce
excessive CO and HC emissions by converting the CO and HC to C02
and H20.
(3) Ammonia Emissions from SCR. The SCR process reduces
NOX emissions by injecting NH3 into the flue gas. The NH3 reacts
with NOX in the presence of a catalyst to form H20 and nitrogen
7-6
-------
(N2) . The NOX removal efficiency of this process is partially
dependent on the NH3/NOX ratio. Increasing this ratio reduces NOX
emissions but increases the probability that unreacted ammonia
will pass through the catalyst unit into the atmosphere (known as
ammonia "slip"). Some ammonia slip is unavoidable because of
ammonia injection control limitations and imperfect distribution
of the reacting gases. A properly designed SCR system will limit
ammonia slip to less than 10 ppmv (see Section 5.4).
b. SOLID WASTE DISPOSAL
Catalytic materials used in SCR units for gas turbines
include precious metals (e.g., platinum), zeolites, and heavy
metal oxides (e.g., vanadium, titanium). Vanadium pentoxide, the
most commonly used SCR catalyst in the United States, is
identified as an acute hazardous waste under RCRA Part 261,
Subpart D - Lists of Hazardous Wastes. The Best Demonstrated
Available Technology (BOAT) Treatment Standards for Vanadium P119
and P120 states that spent catalysts containing vanadium
pentoxide are not classified as hazardous waste.1 State and
local regulatory agencies, however, are authorized to establish
their own hazardous waste classification criteria, and spent
catalysts containing vanadium pentoxide may be classified as a
hazardous waste in some areas. Although the actual amount of
vanadium pentoxide contained in the catalyst bed is small, the
volume of the catalyst unit containing this material is quite
large and disposal can be costly. Where classified by State or
local agencies as a hazardous waste, this waste may be subject to
the Land Disposal Restrictions in 40 CFR Part 268, which allows
land disposal only if the hazardous waste is treated in
accordance with Subpart D - Treatment Standards. Such disposal
problems are not encountered with other catalyst materials, such
as precious metals and zeolites, because these materials are not
hazardous wastes.
c. WATER USAGE AND WASTE WATER DISPOSAL
Water availability and waste water disposal are
environmental factors to be considered with wet injection. The
impact of water usage on the water supply at some remote sites,
7-7
-------
in small communities, or in areas where water resources may be
limited is an environmental factor that should be examined when
considering wet injection. The volume of water required for wet
injection is shown in Table 7-2
-------
TABLE 7-2. WATER AND ELECTRICITY CONSUMPTION FOR NOX
CONTROL TECHNIQUES
Gas turbine
model"
Centaur T4500
501-KB5
LM2500
MS5001P
ABB GT11N
MS7001E
501-KB5
LM2500
MS5001P
LM5000
ABB GT11N
MS7001E
MS7001F
Centaur T4500
MS5001P
MS7001E
Centaur T4500
MS5001P
MS7001E
Centaur T4500
MS5001P
MS7001E
SATURN
T1500
TPM FT4
Turbine
power
output,
MW
3.3
4.0
22.7
26.8
83.3
84.7
4.0
22.7
26.8
34.4
83.3
84.7
161
3.3
26.3
83.3
3.3
26.3
84.7
3.3
26.3
84.7
1.1
28.0
Annual
operating
hours
8,000
8,000
8,000
8,000
8,000
8,000
8,000
8,000
8,000
8,000
8,000
8,000
8,000
8,000
8,000
8,000
2,000
2,000
2,000
2,000
2,000
2,000
1,000
1,000
Fuel
type
Gas
Gas
Gas
Gas
Gas
Gas
Gas
Gas
Gas
Gas
Gas
Gas
Gas
Oil
Oil
Oil
Gas
Gas
Gas
Oil
Oil
Oil
Oil
Oil
Type of
emission
control
Water inj.
Water inj.
Water inj.
Water inj.
Water inj.
Water inj.
Steam inj.
Steam inj.
Steam inj.
Steam inj.
Steam inj.
Steam inj.
Steam inj.
Water inj.
Water inj.
Water inj.
Water inj.
Water inj.
Water inj.
Water inj.
Water inj.
Water inj.
Water inj.
Water-
in-oil
emulsion
Total
water
flow,
gal/min"
2.5
3.94
14.8
22.2
154
69.2
7.38
29.5
33.3
50.8
178
104
199
2.76
26.7
63.8
2.50
22.2
69.2
2.76
26.7
63.8
0.81
21.7
Waste
water
flow,
gal/minb
0.73
1.14
4.29
6.44
44.7
20.1
2.14
8.56
9.66
14.7
51.6
30.2
57.7
0.80
7.74
18.5
0.73
6.44
20.1
0.80
7.74
18.5
0.23
6.29
Water
pump
power,
kWc
0.40
0.63
2.38
3.57
24.8
11.1
1.19
4.75
5.36
8.18
28.7
16.7
32.0
0.44
4.30
10.3
0.40
3.57
11.1
0.44
4.30
10.3
0.13
3.49
Wet injec-
tion power
consump-
tion,
kW-hr/yrd
3,220
5,070
19,100
28,600
198,000
89,100
9,510
38,000
42,900
65,400
229,000
134,000
256,000
3,550
34,400
82,200
3,220
28,600
89,100
3,550
34,400
82,200
1,040
27,900
SCR
power
penalty,
kW-hr/yre
132,000
160,000
908,000
1,070,000
3,330,000
3,390,000
160,000
908,000
1,070,000
1,380,000
3,330,000
3,390,000
6,440,000
132,000
1,050,000
833,000
33,000
263,000
847,000
33,000
263,000
847,000
5,500
140,000
"From Table 6-2.
""Calculated as 29 percent of the total water flow.
Tower requirement for water pump is calculated as shown in Section 6.1.2.2.
7-9
-------
for each model plant.
Water purity is essential for wet injection systems in order
to prevent erosion and/or the formation of deposits in the hot
sections of the gas turbine. Water treatment systems are used to
achieve water quality specifications set by gas turbine
manufacturers. Table 5-4 summarizes these specifications for six
manufacturers.
Discharges from these water treatment systems have a
potential impact on water quality. As indicated in Section 6.1,
approximately 29 percent of the treated water flow rate
(22.5 percent of the raw water flow rate) is considered to be
discharged as wastewater. The wastewater flow rates for each of
the model plants with a water or steam injection control system
are estimated using this factor, and the results are presented in
Table 7-2. The wastewater contains increased levels of those
pollutants in the raw water (e.g., calcium, silica, sulfur, as
listed in Table 5-4) that are removed by the water treatment
system, along with any chemicals introduced by the treatment
process. Based on a wastewater flowrate equal to 29 percent of
the influent raw water, the concentration of pollutants
discharged from the water treatment system is approximately three
times higher than the pollutant concentrations in the raw water.
The impacts of these pollutants on water quality are
site-specific and depend on the type of water supply and on the
discharge restrictions. Influent water obtained from a
municipality will not contain high concentrations of pollutants.
However, surface water or well water used at a remote site might
contain high pollutant concentrations and may require additional
pretreatment to meet the water quality specifications set by
7-10
-------
manufacturers. This additional pretreatment will increase the
pollutant concentrations of the wastewater discharge. Wastewater
discharges to publicly-owned treatment works (POTW's) must meet
the requirements of applicable Approved POTW Pretreatment
Programs.
d. ENERGY CONSUMPTION
Additional fuel and electrical energy is required over
baseline for wet injection controls, while additional electrical
energy is required for SCR controls. The following paragraphs
discuss these energy consumption impacts.
Injecting water or steam into the turbine combustor lowers
the net cycle efficiency and increases the power output of the
turbine. The thermodynamic efficiency of the combustion process
is reduced because energy that could otherwise be available to
perform work in the turbine must now be used to heat the
water/steam. This lower efficiency is seen as an increase in
fuel use. Table 5-10 shows the impacts of wet injection on gas
turbine performance for one manufacturer. This table shows a 2
to 4 percent loss in efficiency associated with WFR's required to
achieve NOX emission levels of 25 to 42 ppmv in gas turbines
burning natural gas. The actual efficiency loss is specific to
each turbine model but generally increases with increasing WFR's
and is higher for water injection than for steam injection
(additional energy is required to heat and vaporize the water) .
One exception to this efficiency penalty occurs with steam
injection, in which exhaust heat from the gas turbine is used to
generate the steam for injection. If the heat recovered in
generating the steam would otherwise be exhausted to atmosphere,
the result is an increase in net cycle efficiency.
The energy from the increased mass flow and heat capacity of
the injected water/steam can be recovered in the turbine,
resulting in an increase in power output accompanying the reduced
efficiency of the turbine (shown in Table 5-10 for one manufac-
turer) . This increase in power output can be significant and
could lessen the impact of the loss in efficiency if the facility
has a demand for the available excess power.
7-11
-------
Water and steam injection controls also require additional
electrical energy to operate the water injection feed water
pumps. The annual electricity usage for each model is the
product of the pump power demand, discussed in Section 6.1.2.2,
and the annual hours of operation. Table 7-2 summarizes this
electricity usage for each of the model plants.
For SCR units, additional electrical energy is required to
operate ammonia pumps and ventilation fans. This energy
requirement, however, is believed to be small and was not
included in this analysis.
The increased back-pressure in the turbine exhaust system
resulting from adding an SCR system reduces the power output from
the turbine. As discussed in Section 6.3.2.9, the power output
is typically reduced by approximately 0.5 percent. This power
penalty has been calculated for each model plant and is shown in
Table 7-2.
e. REFERENCE FOR CHAPTER 7
1.. 55 FR 22276, June 1, 1990.
7-12
-------
APPENDIX A
Exhaust NOX emission levels were provided by gas turbine
manufacturers in units of parts per million, by volume (ppmv), on
a dry basis and corrected to 15 percent oxygen. A method of
converting these exhaust concentration levels to a mass flow rate
of pounds of NOX per hour (Ib N0x/hr) was provided by one gas
turbine manufacturer.1 This method uses an emission index
(EINOJ , in units of Ib NOX/1,000 Ib fuel, which is proportional
to the exhaust NOX emission levels in ppmv by a constant, K. The
relationship between EINOX and ppmv for NOX emissions is stated
in Equation 1 below and applies for complete combustion of a
hydrocarbon fuel and combustion air having no C02 and an 02 mole
percent of 20.95:
NQ;: Ref. 15% 02 = K
Equation 1
EINCX
where: NOX Ref. 15% 02
= NOX, ppmvd @15% 02 (provided by gas
turbine manufacturers);
EINCX
= NOX emission index, Ib NO /I,000 Ib
fuel; and
K
= constant, based on the molar
hydrocarbon
-------
ratio of the fuel.
The derivation of Equation 1 was provided by the turbine
manufacturer and is based on basic thermodynamic laws and
supported by test data provided by the manufacturer. According
to the manufacturer, this equation can be used to estimate NOX
emissions for operation with or without water/steam injection.
Equation 1 shows that NOX emissions are dependent only upon
the molar hydrocarbon ratio of the fuel and are independent of
the air/fuel ratio (A/F). The equation therefore is valid for
all gas turbine designs for a given fuel. The validity of this
approach to calculate NOX emissions was supported by a second
A-2
-------
turbine manufacturer.2 Values for K were provided for several
fuels and are given below:1'2
Pipeline quality natural gas:
K = 12.1
Distillate fuel oil No. 1 (DF-i;
K = 13.1
Distillate fuel oil No. 2 (DF-2;
K = 13.2
Jet propellant No. 4 (JP-4):
K = 13.0
Jet propellant No. 5 (JP-5)
K = 13.1
Methane:
K = 11.6
The following examples are provided for calculating NOX
emissions on a mass basis, given the fuel type and NOX emission
level, in ppmv, dry (ppmvd), and corrected to 15 percent 02.
Example 1. Natural gas fuel
A-3
-------
Gas turbine:
Solar Centaur 'H'
Power output:
4,040 kW
Heat rate:
12,200 Btu/kW-hr
NOX emissions:
105 ppmvd, corrected to 15 percent 02
Fuel:
Natural gas
- lower heating value = 20,610 Btu/lb
- K = 12.1
Fuel flow:
n/m . V7 12,200 Btu 1 Ib fuel 0 _ni n,,,
4,040 kW x '- x = 2,391 Ib/hr
kW-hr 20,610 Btu
From Equation 1:
EINO
NOX emissions, Ib/hr:
Ib fuel 8-68 lb N0 lb N0
2,391 iantuel x x .
hr 1,000 lb fuel hr
Example 2. Distillate oil fuel
A-4
-------
Gas turbine:
General Electric LM2500
Power output:
22670 kW
Heat rate:
9296 Btu/kW-hr
Nox emissions: 345 ppmvd, corrected to 15 percent 02
Fuel:
Distillate oil No. 2
lower heating value = 18,330 Btu/lb
K = 13.2
Fuel flow:
22,670 kW x 9296 Btu x l lb fuel = 11,500 Ib/hr
kW-hr 18,330Btu
From Equation 1:
345
EINO
NOX emissions, Ib/hr:
lb fuel 26-! lb N0x lb N0x
11,500 1D ruel x * = 3QQ
hr 1,000 lb fuel hr
REFERENCES FOR APPENDIX A:
1. Letter and attachments from Lyon, T.F., General Electric
Aircraft Engines, to Snyder, R.B., MRI. December 6, 1991.
Calculation of NOX emissions from gas turbines.
2. Letter and attachments from Hung, W.S., Solar Turbines, Inc.,
to Snyder, R.B., MRI. December 17, 1991. Calculation of NOX
emissions from gas turbines.
A-5
-------
-------
APPENDIX B. COST DATA AND METHODOLOGY USED TO PREPARE COST
FIGURES PRESENTED IN CHAPTER 6
-------
APPENDIX B. RAW COST DATA AND COST ALGORITHMS
The maintenance costs for water injection and several of the
SCR costs presented in Chapter 5 are based on information from
turbine manufacturers and other sources that required
interpretation and analysis. Information about additional gas
turbine maintenance costs associated with water injection is
presented in Section B.I. Information on SCR capital costs,
catalyst replacement and disposal costs, and maintenance costs is
presented in Section B.2. References are listed in Section B.3.
B.I WATER INJECTION MAINTENANCE COSTS
Information from each manufacturer and the applicable
analysis procedures used to develop maintenance cost impacts for
water injection are described in the following sections.
B.1.1 Solar
This manufacturer indicated that the annual maintenance cost
for the Centaur is $16,000/year.^ The cost for the Saturn was
estimated to be $8,000.2 This $8,000 cost was then prorated for
operation at 1,000/hr/yr, and was multiplied by 1.3 to account
for the additional maintenance required for oil fuel.
B.1.2 Allison
Maintenance costs for water injection were provided by a
company that packages Allison gas turbines for stationary
applications. This packager stated that for the 501 gas turbine
model, a maintenance contract is available which covers all
maintenance materials and labor costs associated with the
turbine, including all scheduled and unscheduled activities. The
cost of this contract for the 501 model is $0.0005 to $0.0010 per
KW-hour (KWH) more for water injection than for a turbine not
using water injection.3 For an installation operating
8,000 hours per year at a base-rated output of 4,000 KW, and
using an average cost of $0.00075 per KWH, the annual additional
maintenance cost is $24,000. By the nature of the contract
offered, this figure represents a worst case scenario and to some
extent may exceed the actual incremental maintenance costs that
would be expected for water injection for this turbine.
B-l
-------
B.I.3 General Electric
General Electric (GE) offers both aero-derivative type
(LM-series models) and heavy-duty type (MS-series models) gas
turbines. For the aero-derivative turbines, GE states that the
incremental maintenance cost associated with water injection is
$3.50 per fired hour. This cost is used to calculate the
maintenance cost for water injection for GE aeroderivative
turbines. No figures were provided for steam injection and no
maintenance cost was used for steam injection with these
turbines.4
Water injection also impacts the maintenance costs for the
heavy-duty MS-series models. Costs associated with more frequent
maintenance intervals required for models using water injection
have been calculated and summarized below. A GE representative
stated that the primary components which must be repaired at each
maintenance interval are the combustor liner and transition
pieces.5 Approximate costs to repair these pieces were provided
by GE.5 For this analysis, the maximum cost estimates were used
to calculate annual costs to accommodate repairs that may be
required periodically for injection nozzles, cross-fire tubes,
and other miscellaneous hardware. According to GE, a rule of
thumb is that if the repair cost exceeds 60 percent of the cost
of a new part, the part is replaced.5 The cost of a replacement
part is therefore considered to be 1.67 times the maximum repair
cost. If water purity requirements are met, there are no
significant adverse impacts on maintenance requirements on other
turbine components, and hot gas path inspections and major
inspection schedules are not impacted.5 Combustion repair
schedules, material costs, and labor hours are shown in
Table B-l. Scheduled maintenance intervals for models with water
injection were provided in Reference 6. Corresponding
maintenance intervals for models with steam injection were
assumed to be the same as models with no wet injection; these
scheduled maintenance intervals were provided in Reference 7.
Using the information in Table B-l, the total annual cost is
-------
calculated and shown in Table B-2 for three GE heavy-duty turbine
models.
B.I.4 Asea Brown Boveri
This manufacturer states there are no maintenance impacts
associated with water injection.8
B.2 SCR COSTS
The total capital investment, catalyst replacement, and
maintenance costs are estimated based on information from the
technical literature. The cost algorithms are described in the
following sections.
B.2.I Total Capital Investment
Total capital investment costs, which include purchased costs
and installation costs, were available for SCR systems for
combined cycle and cogeneration applications from five
sources.9"13 These costs were scaled to 1990 costs using the
Chemical Engineering annual plant cost indexes and are applicable
to SCR systems in which the catalyst was placed within the heat
recovery steam generator (HRSG). In addition, estimated capital
investment costs were available from one source for SCR systems
in which a high temperature zeolite catalyst is installed
upstream of the HRSG.14 Both the original data and the scaled
costs are presented in Table B-3. The scaled costs were plotted
against the turbine size and this plot is shown in Figure B-l. A
linear regression analysis was performed to determine the
equation for the line that best fits the data. This equation was
used to estimate the total capital investment for SCR for the
model plants and was extrapolated to estimate the costs for model
plants larger than 90 MW.
B.2.2 Maintenance Costs
Maintenance costs for SCR controls were obtained from four
literature sources, although 6 of the 14 points were obtained
from one article.9'11"13 These costs were scaled to 1990 costs
assuming an inflation rate of five percent per year. All of the
data are for turbines that use natural gas fuel. Because there
are no data to quantify differences in SCR maintenance costs for
oil-fired applications, the available data for operation on
B-3
-------
natural gas were used for both fuels. Both the original data and
the scaled costs are presented in Table B-4. The scaled costs
were plotted versus the turbine size in Figure B-2. The equation
for the line through the data was determined by linear
regression, and it was used to estimate the maintenance costs for
the model plants.
B.2.3 Catalyst Replacement Costs
Catalyst replacement costs were obtained from three articles
for nine gas turbine installations.9'11'13 Combined catalyst
replacement and disposal costs were obtained for another six gas
turbine installations from one article.12 The disposal costs for
these six gas turbine installations were estimated based on
estimated catalyst volumes and a unit disposal cost of $15/ft3,
given in Reference 15.
The catalyst volumes were estimated assuming there is a
direct relationship between the volume and the turbine size; the
catalyst volume stated in Reference 16 for one 83 MW turbine is
175 m3. The resulting disposal costs for these six facilities
were subtracted from the combined replacement and disposal costs
to estimate the replacement-only costs. All of the replacement
costs were scaled to 1990 costs assuming an inflation rate of
5 percent per year. The original data and the scaled costs are
presented in Table B-5, and the scaled replacement costs were
also plotted versus the turbine size in Figure B-3. Linear
regression was used to determine the equation for the line
through the data. This equation was used to estimate the
catalyst replacement costs for the model plants.
B-4
-------
(D
W
O
rr
M P
w O
H-*d
O H-
P rr
w ("
i-h
M
I
(D
fd
O
8
rr
O
HI
ง
6
5
*- "
0)
e 4
m ^
(D en
> c
~ = 3
cd ^
to
-II
O
2
1
0
Total Capital Investment
SCR Control for Gas Turbines
Referenced Silas * CARB Esflriiates
TCI, $ = 49,700 x MW 4 459,000; rf =0.76
. a
0 10 20 30 40 50 60 70 80 90
Turbine size, MW
-------
M
I
1
(D
W
to
Vl
H- M
U
jป 3
o"01
2 H-
H,g
i^ pj
3 o
(D
tu o
M O
U
H rr
.
cr o
S" h
CD W
M o
fd
O
O
0
(T
*i
O
250
200i
^,rf
8 _
8 | 150
05
100
50-
g
IB
c:
c
o-
Annual Maintenance Cost
SCR Control for Gas Turbines
Mairtarmnce cosl, $/yr -1,248 x MW * 25,840; R -0.90
0 20 40 60 80 100 120 140 160
Turbine size,
-------
1
CD
W
CO
O
(u
(T
(U
U
(T
fd
(D
d
(U O
M
I
(D
(U
O
O
U
(T
Hi
O
w
o
o
o
0
(T
^1
o
o
Hi
Catalyst Replacement Annual Cost
SCR Control for Gas Turbines
oslt $/w = 4,700 x MW + 37,168; R =0,99
20 40 60 80 100 120 140 160
Turbine size, MW
-------
Inlet Air Flow Rate vs. Turbine Size
^
(D
W
M
I
CO
(D
(T
"3
I-1
8
fd
(u
(T
(D
(u
(D
U
1200
1000-
800-
I 600
oj 400
200
0
20
40
60 80 100
Turbine size, MW
120 140
160
-------
5-9
-------
B-10
-------
B-ll
-------
B-12
-------
B-13
-------
TABLE B-l. COMBUSTOR REPAIR INTERVALS, HOURS, AND MATERIAL COST
Gas turbine
MS5001P
MS7001E
MS9001E
Repair interval, hr
Dry
12,000
8,000
8,000
Wetb
6,000
6,500
6,500
Replacement interval, hr
Dry"
48,000
48,000
48,000
Wef
24,000
39,000
39,000
Repair cost, $ d
10,000-15,000
15,000-20,000
15,000-30,000
30,000-50,000
31,000-62,000
62,000-124,000
Replacement
cost, $d
25,000
42,000
50,000
83,000
103,000
206,000
Item
Liners
Transition pieces
Liners
Transition pieces
Liners
Transition pieces
Labor hours
160
576
624
M
I
"Reference 7.
""Reference 6.
cScaled from Dry Repair/Replace intervals found in Reference 9.
""Reference 5.
-------
B-15
-------
TABLE B-2. ANNUAL COST OF ADDITIONAL MAINTENANCE REQUIRED FOR WATER INJECTION
GT Model
MS5001P3
Combustor liners
Transition pieces
Number of inspections over 15 years
Dry
Inspection
8
8
Replacement
2
2
Wet
Inspection
15
15
Replacement
5
5
Added number for wet
Inspection
7
7
Replacement
3
3
Material costs
Inspection
15,000
20,000
Replacement
25,000
42,000
Labor, each inspection
Hours
160
Cost
4,998
MS7001Ee
Combustor liners
Transition pieces
12
13
3
2
15
15.5
3.5
3
3
2.5
0.5
1
30,000
50,000
50,000
83,000
576
17,994
MS9001Ee
Combustor liners
Transition pieces
12
13
3
2
15
15.5
3.5
3
3
2.5
0.5
1
62,000
124,000
103,000
206,000
624
19,494
Total added
cost 1 5 years
18,000
315,980
495,980
115,000
270,979
385,979
237,500
584,229
821,729
Total added
annual cost
33,065
25,732
54,782
M
I
aBased on $31.24/hr. Since parts are normally removed and a spare set is installed at each inspection, the labor cost would be the same for either repair or replacement interval.
bSchedule assumes liners and transition pieces are replaced every fourth inspection interval.
ฐ(7 x $15,000) + (3 x $25,000) = $180,000.
d(7 x $20,000) + (3 x $42,000) + ($4,998 x 10) = $315,980.
Schedule assumes liners are replaced every fifth interval and transition pieces every sixth interval.
-------
B-17
-------
TABLE B-3.
TOTAL CAPITAL INVESTMENT FOR SCR TO CONTROL
NO,, EMISSIONS FROM GAS TURBINES
Gas
turbine
size, MW
1.1
1.5
3
3.2
3.7
3.7
4
4.5
6
8.4
9
10
20
21
21
21
22
26
33
37
37
78
80
80
83
SCR capital cost3
$
1,250, 000
180, 000
320, 000
600, 000
477, 000
579, 000
839, 000
750, 000
480, 000
800, 000
1, 100, 000
1, 431, 000
1,700, 000
798, 000
1,500, 000
1,200, 000
1, 000, 000
1, 800, 000
990, 000
2, 000, 000
2,700, 000
4,300, 000
5,400, 000
1,760, 000
5,360, 000
Year
1989
1986
1986
1989
1988
1989
1991
1988
1986
1986
1987
1991
1987
1988
1986
1986
1987
1991
1988
1986
1986
1986
1987
1988
1991
Refb
9
10
10
11
12
11
14
11
10
11
13
14
13
12
10
10
11
14
12
11
10
10
13
12
14
Scaling
factor0
357.6/355.4
357.6/318.4
357.6/318.4
357.6/3.554
357.6/342.5
357.6/355.4
1.0
357.6/342.5
357.6/318.4
357.6/318.4
357.6/323.8
1.0
357.6/323.8
357.6/342.5
357.6/318.4
357.6/318.4
357.6/323.8
1.0
357.6/342.5
357.6/318.4
357.6/318.4
357.6/318.4
357.6/323.8
357.6/342.5
1.0
1990 SCR
capital
cost, $
1,260,000
202, 000
359, 000
604, 000
498, 000
583, 000
839, 000
783, 000
539, 000
898, 000
1,210, 000
1, 431, 000
1, 880,000
833, 000
1, 680,000
1,350,000
1, 100,000
1, 800,000
1, 030, 000
2,250,000
3, 030,000
4, 830,000
5, 960,000
1, 840,000
5,360,000
continued
B-18
-------
TABLE B-3. (Continued)
aTotal capital costs were provided by several sources, but it is
not clear that they are on the same basis. For example, it is
likely that the type of catalyst varies and the target NOX
reduction efficiency may also vary. In addition, some estimates
may not include costs for emission monitors; auxiliary equipment
like the ammonia storage, handling, and transfer system; taxes
and freight; or installation.
bReference 12 also provided costs for SCR used with 136 MW and
145 MW turbines. All of the costs for this reference are lower
than the costs from other sources, and the differential
increases as the turbine size increases. Because there are no
costs from other sources for such large turbines, these two data
points would exert undue influence on the analysis; therefore,
they have been excluded. Costs for large model plants were
estimated by extrapolating with the equation determined by
linear regression through the data for turbines with capacities
less than 90 MW (see Figure B-l).
GCosts for years prior to 1990 are adjusted to 1990 dollars
based on the annual CE plant cost indexes. Costs estimated in
1991 dollars were not adjusted.
B-19
-------
TABLE B-4. MAINTENANCE COSTS FOR SCR
Gas
turbine
size, MW
1.1
3.2
3.7
3.7
8.4
8.9
9
20
21
33
80
80
136
145
SCR maintenance cost3
$/yr
52,200
50, 000
43, 000
15,500
22, 000
18, 000
25, 000
50, 000
37, 900
63,700
124, 000
60, 000
184, 000
205, 000
Year
1989
1989
1988
1988
1986
1988
1987
1987
1988
1988
1988
1987
1988
1988
Ref
9
11
11
12
11
11
13
13
12
12
12
13
12
12
Scaling
factor13
1.050
1.050
1.103
1.103
1.216
1.103
1.158
1.158
1.103
1.103
1.103
1.158
1.103
1.103
1990 SCR
maintenance
cost, $
54, 800
52,500
47,400
17, 100
26,700
19, 800
28, 900
57, 900
41, 800
70,200
137, 000
69,500
203, 000
226, 000
aAll of the maintenance costs are for turbines that are fired
with natural gas. Although sulfur in diesel fuel can cause
maintenance problems, there are no data to quantify the impact.
Therefore, the maintenance costs presented in this table were
used for both natural gas and diesel fuel applications.
bScaling factors are based on an estimated inflation rate of
5 percent per year.
B-20
-------
TABLE B-5. CATALYST REPLACEMENT AND DISPOSAL COSTS
Gas turbine
size, MW
1.1
3.2
3.7
3.7
4.5
8.4
9
20
21
22
33
80
80
136
145
Catalyst replacement cost a
S
74,600
200,000
100,000
300,000
200,000
255,000
434,000
400,000
1,400,000
Year
1989
1989
1988
1988
1988
1986
1987
1987
1988
1987
1988
1988
1987
1988
1988
Ref.
9
11
12
11
11
11
13
13
12
11
12
12
13
12
12
Scaling
factor"
1.050
1.050
1.103
1.103
1.103
1.216
1.158
1.158
1.103
1.158
1.103
1.103
1.158
1.103
1.103
1990 catalyst
cost, S
78,300
210,000
215,000
110,000
331,000
243,000
295,000
502,000
512,000
463,000
864,000
1,660,000
1,620,000
2,450,000
2,740,000
Annual cost,
S/yrc
20,700
55,400
56,600
29,000
87,300
64,100
77,800
132,000
135,000
122,000
228,000
437,000
427,000
645,000
723,000
Catalyst disposal cost
Catalyst
volume, m 3
2.32
6.75
7.80
7.80
9.49
17.7
19.0
42.2
44.3
46.4
69.6
169
169
287
306
1990 cost,
se
1,230
3,570
4,130
4,130
5,030
9,380
10,100
22,300
23,500
24,600
36,900
89,300
89,300
152,000
162,000
Annual cost,
S/yrc
324
940
1,090
1,090
1,330
2,470
2,660
5,880
6,200
6,490
9,700
23,600
23,600
40,100
42,700
Catalyst
replacement and
disposal annual
cost, S/yr
21,000
56,300
57,700
30,100
89,000
67,000
80,000
138,000
141,000
128,000
238,000
461,000
451,000
685,000
766,000
M
I
"Reference 12 provided only combined catalyst replacement and disposal costs.
b Scaling factors are based on an inflation rate of 5 percent per year.
'Annual costs are based on the assumption that the catalyst will be replaced every 5 years. Therefore, the capital recovery factor is 0.2638, assuming an annual interest rate
of 10 percent.
dln one SCR application, 175 m 3 of catalyst is used with an 83 MW turbine. If the space velocity is the same for any size SCR (assuming the same catalyst), then there is
a direct relationship between the amount of catalyst and the exhaust gas flow rate. The exhaust gas flow rate was calculated as equal to the inlet air flow rate, and as Figure
B-4 shows, there is nearly a direct relationship between the inlet airflow rate and turbine capacity. Therefore, the catalyst volume for the turbines in this table were estimated
assuming there is a direct relationship between the catalyst volume and the turbine output.
'Disposal costs are estimated based on a unit cost of S15/ft 3.
-------
B.3 REFERENCES FOR APPENDIX B
I. Letter and attachments from Swingle, R., Solar Turbines
Incorporated, to Snyder, R., MRI. May 21, 1991.
Maintenance considerations for gas turbines.
II. Letter and attachments from Swingle, R., Solar Turbines
Incorporated, to Neuffer, W.J., EPA/ISB. August 20, 1991.
Review of draft gas turbine ACT document.
III. Letter and attachments from Lock, D., U.S. Turbine
Corporation, to Neuffer, W.J., U.S EPA/ISB. September
17, 1991. Review of draft gas turbine ACT document.
IV. Letter and attachments from Sailer, E.D., General Electric
Marine and Industrial Engines, to Neuffer, W.J., EPA/ISB.
August 29, 1991. Review of draft gas turbine ACT document.
V. Telecon. Snyder, R., MRI, with Pasquarelli, L., General
Electric Company. April 26, 1991. Maintenance costs for
gas turbines.
VI. Letter and attachment from Schorr, M., General Electric
Company, to Snyder, R., MRI. April 1, 1991. Response to
gas turbine questionnaire.
VII. Walsh, E. Gas Turbine Operating and Maintenance
Considerations. General Electric Company.
Schenectady, NY. Presented at the 33rd GE Turbine
State-of-the-Art Technology Seminar for
Industrial, Cogeneration and Independent Power
Turbine Users. September, 1989. 20 pp.
VIII. Letter and attachments from Gurmani, A., Asea
Brown Boveri, to Snyder, R., MRI. May 30, 1991.
Response to gas turbine questionnaire.
IX. Permit application processing and calculations by South
Coast Air Quality Management District for proposed SCR
control of gas turbine at Saint John's Hospital and Health
Center, Santa Monica, California. May 23, 1989.
X. Hull, R., C. Urban, R. Thring, S. Ariga, M. Ingalls, and
G. O'Neal. NOX Control Technology Data Base for Gas-Fueled
Prime Movers, Phase I. Prepared by Southwest Research
Institute for Gas Research Institute. April 1988.
XI. Shareef, G., and D. Stone. Evaluation of SCR NOX Controls
for Small Natural Gas-Fueled Prime Movers. Phase I.
Prepared by Radian Corporation for Gas Research Institute.
July 1990.
B-22
-------
XII. Sidebotham, G., and R. Williams. Technology of NOX Control
for Stationary Gas Turbines. Center for Environmental
Studies. Princeton University. January 1989.
XIII. Prosl, T., DuPont,and Scrivner, G., Dow.
Technical Arguments and Economic Impact of SCR's
Use for NOX Reduction of Combustion Turbine for
Cogeneration. Paper presented at EPA Region 6
meeting concerning NOX abatement of Combustion
Turbines. December 17, 1987.
XIV. State of California Air Resources Board. Draft Proposed
Determination of Reasonably Available Control Technology And
Best Available Retrofit Technology for Stationary Gas
Turbines. August, 1991. Appendix C.
XV. Letter and attachments from Henegan, D., Norton Company,
to Snyder, R., MRI. March 28, 1991. Response to SCR
questionnaire.
XVI. Schorr, M. NOX Control for Gas Turbines: Regulations and
Technology. General Electric Company. Schenectady, New
York. Paper presented at the Council of Industrial Boiler
Owners NOX Control IV Conference. Concord, California.
February 11-12, 1991. 11 pp.
B-23
------- |