- Page 1 and 2: Alternative Control Techniques Docu
- Page 3 and 4: TABLE OF CONTENTS Section Page 1.0
- Page 5 and 6: TABLE OF CONTENTS (continued) Secti
- Page 7 and 8: LIST OF FIGURES (continued) Figure
- Page 9 and 10: LIST OF FIGURES (continued) Figure
- Page 11 and 12: LIST OF TABLES (continued) Table Pa
- Page 13 and 14: 1.0 INTRODUCTION Congress, in the C
- Page 15 and 16: 2.0 SUMMARY This chapter summarizes
- Page 17 and 18: TABLE 2-1. UNCONTROLLED NO EMISSION
- Page 19 and 20: flame temperatures. This control te
- Page 21: Figure 2-2. Uncontrolled NO emissio
- Page 25 and 26: gas and coal have achieved controll
- Page 27 and 28: emoved, are shown in Section 2.3.2.
- Page 29 and 30: These capital costs include both wa
- Page 31 and 32: Figure 2-4. Capital costs for dry l
- Page 33 and 34: Figure 2-5. Capital costs, in $/MW,
- Page 35 and 36: Figure 2-6. Capital costs for selec
- Page 37 and 38: Figure 2-7. Capital costs, in $/MW,
- Page 39 and 40: 2-25
- Page 41 and 42: 2-27
- Page 43 and 44: Figure 2-8. Cost effectiveness of c
- Page 45 and 46: For water injection, cost effective
- Page 47 and 48: Figure 2-9. Cost effectiveness for
- Page 49 and 50: Figure 2-10. Combined cost effectiv
- Page 51 and 52: 2-37
- Page 53 and 54: Figure 2-11. Controlled NO emission
- Page 55 and 56: equirements and may result in incre
- Page 57 and 58: 3.0 STATIONARY GAS TURBINE DESCRIPT
- Page 59 and 60: Figure 3-1. The three primary secti
- Page 61 and 62: Figure 3-2. Types of gas turbine co
- Page 63 and 64: 3-49
- Page 65 and 66: 3-5
- Page 67 and 68: which can vary over as wide a range
- Page 69 and 70: Figure 3-6. Simple cycle gas turbin
- Page 71 and 72: Figure 3-7. Regenerative cycle gas
- Page 73 and 74:
3-13
- Page 75 and 76:
Figure 3-8. Cogeneration cycle gas
- Page 77 and 78:
Figure 3-9. Combined cycle gas turb
- Page 79 and 80:
3-19
- Page 81 and 82:
3.3.2 Stand-By/Emergency Electric P
- Page 83 and 84:
are being negotiated. Capital costs
- Page 85 and 86:
shows, DOE expects 36,000 MW of com
- Page 87 and 88:
Figure 3-11. Capital costs for elec
- Page 89 and 90:
3-29
- Page 91 and 92:
11. Reference 8, p. 3-43. 12. Refer
- Page 93 and 94:
The major contributing chemical rea
- Page 95 and 96:
shows the flame temperature and equ
- Page 97 and 98:
6. N + OH º NO + H, and further to
- Page 99 and 100:
currently a major contributor to ov
- Page 101 and 102:
Figure 4-2. Thermal NO production a
- Page 103 and 104:
As is shown in Figure 4-3 4-12
- Page 105 and 106:
, DF-2 burns at a flame temperature
- Page 107 and 108:
substantially lower thermal NO x em
- Page 109 and 110:
This effect of humidity and tempera
- Page 111 and 112:
H = observed humidity of ambient ai
- Page 113 and 114:
4-22
- Page 115 and 116:
Uncontrolled emission factors are p
- Page 117 and 118:
4.4 REFERENCES FOR CHAPTER 4 1. Con
- Page 119 and 120:
24. Letters and attachments from Le
- Page 121 and 122:
TABLE 5-1. NO x EMISSION LIMITS AS
- Page 123 and 124:
TABLE 5-2. NO COMPLIANCE LIMITS AS
- Page 125 and 126:
5-34
- Page 127 and 128:
This chapter discusses the control
- Page 129 and 130:
5-38
- Page 131 and 132:
TABLE 5-4. WATER QUALITY SPECIFICAT
- Page 133 and 134:
(HRSG) that recovers the gas turbin
- Page 135 and 136:
TABLE 5-5. MANUFACTURER'S GUARANTEE
- Page 137 and 138:
distillate oil fuels, respectively,
- Page 139 and 140:
increases. As shown in Tables 5-5 a
- Page 141 and 142:
5.1.4 Achievable NO Emissions Level
- Page 143 and 144:
Figure 5-3. Uncontrolled NO emissio
- Page 145 and 146:
5-54
- Page 147 and 148:
75 ppmv for most oil-fired turbines
- Page 149 and 150:
Figures 5-4, 5-5, and 5-6 present t
- Page 151 and 152:
Figure 5-5. Nitrogen oxide emission
- Page 153 and 154:
for water injection on turbines fir
- Page 155 and 156:
Figure 5-8. Nitrogen oxide emission
- Page 157 and 158:
approximately 30 to 135 ppm, with W
- Page 159 and 160:
5-68
- Page 161 and 162:
5-70
- Page 163 and 164:
again shows that higher WFR's are r
- Page 165 and 166:
Figure 5-11. Nitrogen oxide emissio
- Page 167 and 168:
TABLE 5-7. ACHIEVABLE GAS TURBINE N
- Page 169 and 170:
Figure 5-12. Comparison of the WFR
- Page 171 and 172:
5-80
- Page 173 and 174:
5-82
- Page 175 and 176:
Gas turbine model TABLE 5-8. UNCONT
- Page 177 and 178:
As an example, a 21.8 MW turbine bu
- Page 179 and 180:
shows the impact of water injection
- Page 181 and 182:
Figure 5-14. Like CO emissions, hyd
- Page 183 and 184:
5-92
- Page 185 and 186:
5.1.6 Impacts of Wet Controls on Ga
- Page 187 and 188:
5.1.7 Impacts of Wet Controls on Ga
- Page 189 and 190:
As this table shows, the maintenanc
- Page 191 and 192:
5.2 COMBUSTION CONTROLS The formati
- Page 193 and 194:
For combustors with reduced residen
- Page 195 and 196:
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
- Page 201 and 202:
5-110
- 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
- Page 209 and 210:
5-118
- 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
- Page 225 and 226:
5-134
- 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
- Page 233 and 234:
5-142
- 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
- Page 241 and 242:
5-150
- Page 243 and 244:
5-152
- Page 245 and 246:
An ammonia injection grid is locate
- Page 247 and 248:
increased using a zeolite catalyst
- Page 249 and 250:
In addition to the locations shown,
- 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
- Page 261 and 262:
5-170
- Page 263 and 264:
Figure 5-29 shows a typical natural
- Page 265 and 266:
installation. Figure 5-30 is a cros
- Page 267 and 268:
5-176
- 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
- Page 273 and 274:
5-182
- Page 275 and 276:
5.6.2 Methanol Methanol has a flame
- Page 277 and 278:
The NO emissions from firing methan
- Page 279 and 280:
methanol and natural gas. Reduction
- 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
- Page 299 and 300:
TABLE 6-1. GAS TURBINE MODEL PLANTS
- Page 301 and 302:
plant for this turbine. As a result
- Page 303 and 304:
for each model plant. Fuel rates we
- Page 305 and 306:
2 . Water (or steam) injection rate
- Page 307 and 308:
. These costs were developed based
- Page 309 and 310:
6-218
- Page 311 and 312:
turbines, the water treatment syste
- Page 313 and 314:
TABLE 6-5. ANNUAL COSTS FOR WATER A
- Page 315 and 316:
determine the fuel penalty for each
- Page 317 and 318:
plants that use diesel fuel instead
- Page 319 and 320:
6-228
- Page 321 and 322:
The uncontrolled and controlled NO
- Page 323 and 324:
. LOW-NO COMBUSTORS x Incremental c
- Page 325 and 326:
TABLE 6-7. COST-EFFECTIVENESS SUMMA
- Page 327 and 328:
also lower. According to two turbin
- Page 329 and 330:
TABLE 6-8. PROCEDURES FOR ESTIMATIN
- Page 331 and 332:
TABLE 6-9. CAPITAL AND ANNUAL COSTS
- Page 333 and 334:
ii. Annual Costs Total annual costs
- Page 335 and 336:
6-244
- Page 337 and 338:
facilities as described below and i
- Page 339 and 340:
costs are equal to 4 percent of the
- Page 341 and 342:
and 6-12, respectively. For continu
- Page 343 and 344:
6-252
- Page 345 and 346:
TABLE 6-13. COMBINED COST-EFFECTIVE
- Page 347 and 348:
figures are calculated by dividing
- Page 349 and 350:
sum of the annual reduction of NO e
- Page 351 and 352:
without adjustment because there is
- Page 353 and 354:
REFERENCES FOR CHAPTER 6 I. 1990 Pe
- Page 355 and 356:
XXV. Kolp, D. (Energy Services, Inc
- Page 357 and 358:
6-266
- Page 359 and 360:
TABLE 7-1. MODEL PLANT UNCONTROLLED
- Page 361 and 362:
TABLE 7-1. (continued) Controlled N
- Page 363 and 364:
(1) Impacts of Wet Controls on CO a
- Page 365 and 366:
in small communities, or in areas w
- Page 367 and 368:
for each model plant. Water purity
- Page 369 and 370:
Water and steam injection controls
- Page 371 and 372:
atio of the fuel. The derivation of
- Page 373 and 374:
Gas turbine: Solar Centaur 'H' Powe
- Page 376 and 377:
APPENDIX B. COST DATA AND METHODOLO
- Page 378 and 379:
B.1.3 General Electric General Elec
- Page 380 and 381:
natural gas were used for both fuel
- Page 382 and 383:
Figure B-2. Annual Maintenance Cost
- Page 384 and 385:
Figure B-4. Inlet Air Flow Rate for
- Page 386 and 387:
B-10
- Page 388 and 389:
B-12
- Page 390 and 391:
TABLE B-1. COMBUSTOR REPAIR INTERVA
- Page 392 and 393:
TABLE B-2. ANNUAL COST OF ADDITIONA
- Page 394 and 395:
TABLE B-3. TOTAL CAPITAL INVESTMENT
- Page 396 and 397:
TABLE B-4. MAINTENANCE COSTS FOR SC
- Page 398 and 399:
B.3 REFERENCES FOR APPENDIX B I. Le