NOx Emissions from Stationary Gas Turbines - US Environmental ...

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Figure 5-28. Possible locations for SCR unit in HRSG. 62 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 590EC (1100EF), 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 260E to 515EC (500E to 960EF) and operates approximately 90 percent of the time at temperatures above 500EC (930EF). 65 Another consideration in determining the applicability of SCR is complications arising <strong>from</strong> 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 SO 2 and SO 3 emissions. A portion of the SO 2 oxidizes to SO 3 as it passes through the HRSG, and base metal catalysts have 64 an SO2-to-SO 3 oxidation rate of up to five percent. In addition, oxidation catalysts, when used to reduce CO emissions, 66 will also oxidize SO 2 to SO 3 at rates of up to 50 percent. Unreacted ammonia passing through the catalyst reacts with SO 3 to form ammonium bisulfate (NH4HSO 4) and ammonium sulfate [(NH 4) 2 SO 4] in the low-temperature section of the HRSG. The rate of ammonium salt formation increases with increasing levels of SO 3 and NH 3, and the formation rate increases with decreasing 5-158
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Alternative Control Techniques Docu
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TABLE OF CONTENTS Section Page 1.0
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TABLE OF CONTENTS (continued) Secti
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LIST OF FIGURES (continued) Figure
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LIST OF FIGURES (continued) Figure
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LIST OF TABLES (continued) Table Pa
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1.0 INTRODUCTION Congress, in the C
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2.0 SUMMARY This chapter summarizes
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TABLE 2-1. UNCONTROLLED NO EMISSION
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flame temperatures. This control te
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Figure 2-2. Uncontrolled NO emissio
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2-9
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gas and coal have achieved controll
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emoved, are shown in Section 2.3.2.
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These capital costs include both wa
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Figure 2-4. Capital costs for dry l
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Figure 2-5. Capital costs, in $/MW,
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Figure 2-6. Capital costs for selec
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Figure 2-7. Capital costs, in $/MW,
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2-25
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2-27
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Figure 2-8. Cost effectiveness of c
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For water injection, cost effective
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Figure 2-9. Cost effectiveness for
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Figure 2-10. Combined cost effectiv
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2-37
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Figure 2-11. Controlled NO emission
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equirements and may result in incre
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3.0 STATIONARY GAS TURBINE DESCRIPT
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Figure 3-1. The three primary secti
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Figure 3-2. Types of gas turbine co
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3-49
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3-5
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which can vary over as wide a range
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Figure 3-6. Simple cycle gas turbin
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Figure 3-7. Regenerative cycle gas
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3-13
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Figure 3-8. Cogeneration cycle gas
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Figure 3-9. Combined cycle gas turb
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3-19
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3.3.2 Stand-By/Emergency Electric P
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are being negotiated. Capital costs
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shows, DOE expects 36,000 MW of com
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Figure 3-11. Capital costs for elec
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3-29
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11. Reference 8, p. 3-43. 12. Refer
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The major contributing chemical rea
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shows the flame temperature and equ
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6. N + OH º NO + H, and further to
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currently a major contributor to ov
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Figure 4-2. Thermal NO production a
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As is shown in Figure 4-3 4-12
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, DF-2 burns at a flame temperature
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substantially lower thermal NO x em
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This effect of humidity and tempera
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H = observed humidity of ambient ai
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4-22
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Uncontrolled emission factors are p
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4.4 REFERENCES FOR CHAPTER 4 1. Con
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24. Letters and attachments from Le
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TABLE 5-1. NO x EMISSION LIMITS AS
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TABLE 5-2. NO COMPLIANCE LIMITS AS
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5-34
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This chapter discusses the control
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5-38
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TABLE 5-4. WATER QUALITY SPECIFICAT
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(HRSG) that recovers the gas turbin
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TABLE 5-5. MANUFACTURER'S GUARANTEE
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distillate oil fuels, respectively,
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increases. As shown in Tables 5-5 a
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5.1.4 Achievable NO Emissions Level
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Figure 5-3. Uncontrolled NO emissio
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5-54
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75 ppmv for most oil-fired turbines
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Figures 5-4, 5-5, and 5-6 present t
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Figure 5-5. Nitrogen oxide emission
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for water injection on turbines fir
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Figure 5-8. Nitrogen oxide emission
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approximately 30 to 135 ppm, with W
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5-68
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5-70
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again shows that higher WFR's are r
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Figure 5-11. Nitrogen oxide emissio
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TABLE 5-7. ACHIEVABLE GAS TURBINE N
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Figure 5-12. Comparison of the WFR
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5-80
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5-82
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Gas turbine model TABLE 5-8. UNCONT
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As an example, a 21.8 MW turbine bu
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shows the impact of water injection
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Figure 5-14. Like CO emissions, hyd
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5-92
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5.1.6 Impacts of Wet Controls on Ga
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5.1.7 Impacts of Wet Controls on Ga
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As this table shows, the maintenanc
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5.2 COMBUSTION CONTROLS The formati
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For combustors with reduced residen
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5 shows a comparison of NO emission
Page 197 and 198: Figure 5-6. Cross-section of a lean
Page 199 and 200: Figure 5-17. Operating modes for a
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Page 203 and 204: Figure 5-18. Cross-section of lean
Page 205 and 206: 35,48 Figure 5-19. Cross-section of
Page 207 and 208: 48 Figure 5-20. Low-NO x burner for
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Page 211 and 212: For operation on distillate oil wit
Page 213 and 214: Figure 5-21. "Stepped" NO and CO em
Page 215 and 216: shows these stepped NO emissions le
Page 217 and 218: shows the emissions for a silo comb
Page 219 and 220: The emission levels shown in Figure
Page 221 and 222: water injection. Subsequent emissio
Page 223 and 224: at base load for No. 2 fuel oil are
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Page 227 and 228: TABLE 5-14. POTENTIAL NO REDUCTIONS
Page 229 and 230: TABLE 5-15. COMPARISON OF NO AND CO
Page 231 and 232: Figure 5-24. The CO emission test r
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Page 235 and 236: and are in the range of 0 to 2 ppmv
Page 237 and 238: Figure 5-25. Nitrogen oxide emissio
Page 239 and 240: Figure 5-26. Effects of fuel bound
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Page 245 and 246: An ammonia injection grid is locate
Page 247: increased using a zeolite catalyst
Page 251 and 252: installation using oil fuel, a Unit
Page 253 and 254: egan operating recently and have li
Page 255 and 256: combined cycle applications to acco
Page 257 and 258: of this waste could be costly. Some
Page 259 and 260: . Ammonia slip levels were not repo
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Page 263 and 264: Figure 5-29 shows a typical natural
Page 265 and 266: installation. Figure 5-30 is a cros
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Page 269 and 270: 73,75 Figure 5-31. Low-NO x duct bu
Page 271 and 272: 77 TABLE 5-19. NO x EMISSIONS MEASU
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Page 275 and 276: 5.6.2 Methanol Methanol has a flame
Page 277 and 278: The NO emissions from firing methan
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Page 281 and 282: 62 to 100 ppm for natural gas. In a
Page 283 and 284: Figure 5-33. A lean catalytic combu
Page 285 and 286: Catalytic combustors can also be de
Page 287 and 288: of gas turbine combustors. Addition
Page 289 and 290: 8. Letter and attachment from Swing
Page 291 and 292: 33. Schorr, M. NO Control for Gas T
Page 293 and 294: 55. Cutrone, M., and M. Hilt (Gener
Page 295 and 296: 78. Backlund, J., and A. Spoormaker
Page 297 and 298: 6.0 CONTROL COSTS Capital and annua
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TABLE 6-1. GAS TURBINE MODEL PLANTS
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plant for this turbine. As a result
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for each model plant. Fuel rates we
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2 . Water (or steam) injection rate
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. These costs were developed based
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6-218
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turbines, the water treatment syste
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TABLE 6-5. ANNUAL COSTS FOR WATER A
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determine the fuel penalty for each
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plants that use diesel fuel instead
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6-228
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The uncontrolled and controlled NO
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. LOW-NO COMBUSTORS x Incremental c
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TABLE 6-7. COST-EFFECTIVENESS SUMMA
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also lower. According to two turbin
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TABLE 6-8. PROCEDURES FOR ESTIMATIN
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TABLE 6-9. CAPITAL AND ANNUAL COSTS
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ii. Annual Costs Total annual costs
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6-244
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facilities as described below and i
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costs are equal to 4 percent of the
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and 6-12, respectively. For continu
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6-252
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TABLE 6-13. COMBINED COST-EFFECTIVE
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figures are calculated by dividing
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sum of the annual reduction of NO e
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without adjustment because there is
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REFERENCES FOR CHAPTER 6 I. 1990 Pe
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XXV. Kolp, D. (Energy Services, Inc
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6-266
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TABLE 7-1. MODEL PLANT UNCONTROLLED
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TABLE 7-1. (continued) Controlled N
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(1) Impacts of Wet Controls on CO a
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in small communities, or in areas w
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for each model plant. Water purity
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Water and steam injection controls
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atio of the fuel. The derivation of
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Gas turbine: Solar Centaur 'H' Powe
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APPENDIX B. COST DATA AND METHODOLO
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B.1.3 General Electric General Elec
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natural gas were used for both fuel
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Figure B-2. Annual Maintenance Cost
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Figure B-4. Inlet Air Flow Rate for
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B-10
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B-12
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TABLE B-1. COMBUSTOR REPAIR INTERVA
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TABLE B-2. ANNUAL COST OF ADDITIONA
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TABLE B-3. TOTAL CAPITAL INVESTMENT
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TABLE B-4. MAINTENANCE COSTS FOR SC
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B.3 REFERENCES FOR APPENDIX B I. Le
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