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

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The incremental capital costs range <strong>from</strong> $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-NO combustion controls are highest for x 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
Figure 2-5. Capital costs, in $/MW, for cumbustion controls. 2-19
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 and 22: Figure 2-2. Uncontrolled NO emissio
Page 23 and 24: 2-9
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: Figure 2-4. Capital costs for dry l
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
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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
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Figure 5-6. Cross-section of a lean
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Figure 5-17. Operating modes for a
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5-110
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Figure 5-18. Cross-section of lean
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35,48 Figure 5-19. Cross-section of
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48 Figure 5-20. Low-NO x burner for
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5-118
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For operation on distillate oil wit
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Figure 5-21. "Stepped" NO and CO em
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shows these stepped NO emissions le
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shows the emissions for a silo comb
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The emission levels shown in Figure
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water injection. Subsequent emissio
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at base load for No. 2 fuel oil are
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5-134
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TABLE 5-14. POTENTIAL NO REDUCTIONS
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TABLE 5-15. COMPARISON OF NO AND CO
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Figure 5-24. The CO emission test r
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5-142
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and are in the range of 0 to 2 ppmv
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Figure 5-25. Nitrogen oxide emissio
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Figure 5-26. Effects of fuel bound
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5-150
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5-152
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An ammonia injection grid is locate
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increased using a zeolite catalyst
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In addition to the locations shown,
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installation using oil fuel, a Unit
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egan operating recently and have li
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combined cycle applications to acco
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of this waste could be costly. Some
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. Ammonia slip levels were not repo
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5-170
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Figure 5-29 shows a typical natural
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installation. Figure 5-30 is a cros
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5-176
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73,75 Figure 5-31. Low-NO x duct bu
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77 TABLE 5-19. NO x EMISSIONS MEASU
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5-182
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5.6.2 Methanol Methanol has a flame
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The NO emissions from firing methan
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methanol and natural gas. Reduction
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62 to 100 ppm for natural gas. In a
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Figure 5-33. A lean catalytic combu
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Catalytic combustors can also be de
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of gas turbine combustors. Addition
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8. Letter and attachment from Swing
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33. Schorr, M. NO Control for Gas T
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55. Cutrone, M., and M. Hilt (Gener
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78. Backlund, J., and A. Spoormaker
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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
Page 396 and 397:
TABLE B-4. MAINTENANCE COSTS FOR SC
Page 398 and 399:
B.3 REFERENCES FOR APPENDIX B I. Le
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