AEPA
Unrtod SiatM
Envirofvntntal Pr auction
Aganey
Offie* of Air Quality
Planning and Standards
R«Mareh Trianglt Park NC 27711
Air
Municipal Waste
Combustors-
Background
Information for
Proposed
Guidelines
for Existing
Facilities
EPA-4iO/3-89-27«
August 1«M
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DCN No. 39-239-003-46-14
MUNICIPAL WASTE COMBUSTORS --
BACKGROUND INFORMATION FOR
PROPOSED GUIDELINES FOR EXISTING FACILITIES
FINAL REPORT
Prepared for:
Ronald E. Myers
U. S. Environmental Protection Agency
Industrial Studies Branch (MD-13)
Research Triangle Park, North Carolina 27711
Prepared by:
Radian Corporation
3200 E. Chapel Hill Rd./Nelson Hwy.
Post Office Box 13000
Research Triangle Park, North Carolina 27709
and
Energy and Environmental Research Corporation
3622 Lyckan Parkway, Suite 5006
Durham, NC 27707
August 14, 1989
-------
DISCLAIMER
This report has been reviewed by the Emission Standards Division
of the Office of Air Quality Planning and Standards, EPA, and
approved for publication. Mention of trade nanes or commercial
products is not intended to constitute endorsement or
recommendation for use. Copies of this report are available
through the Library services Office (MD-35), U.S. Environmental
Protection Agency, Research Triangle Park NC 27711, or from
National Technical Information Services, 5285 Port Royal Road,
Springfield VA 22161.
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TABLE OF CONTENTS
Chapter . Page
1.0 INTRODUCTION 1-1
1.1 BACKGROUND AND OBJECTIVES OF REGULATORY ACTION ... 1-1
1.2 OVERVIEW OF EXISTING MWC POPULATION. ........ 1-1
1.3 ORGANIZATION OF REPORT ..... 1-3
2.0 BACKGROUND AND METHODOLOGY . . 2-1
2.1 SITE SELECTION AND DEFINITION OF MODEL PLANTS. ... 2-1
2.2 WASTE CHARACTERIZATION AND EMISSIONS 2-3
2.2.1 Waste Characterization ..... 2-3
2.2,2 Pollutants of Concern 2-3
2.2.3 Basel ins Emissions ............. 2-9
2.2.4 MWC Residues 2-9
2.3 OVERVIEW OF TECHNOLOGIES CONSIDERED 2-13
2.3.1 Combustion Modifications 2-10
2.3.2 Flue Gas Temperature Reduction ....... 2-16
2.3.3 Particulate Matter Control ... 2-19
2.3.4 Acid Gas Control 2-20
2.4 REFERENCES 2-23
3.0 DEFINITION OF CONTROL OPTIONS 3-1
4.0 MASS BURN REFRACTORY-WALL COMBUSTORS 4-1
4.1 TRAVELING GRATE MASS BURN REFRACTORY-WALL COMBUSTOR 4-14
4.1.1 Description of Philadelphia Northwest Plant 4-14
4.1.1.1 Combustor Design and Operation . . 4-14
4.1.1.2 Emission Control System Design and
Operation 4-19
4.1.2 Description of Model Plant ......... 4-20
4.1.2.1 Combustor Design and Operation . . 4-20
4.1.2.2 Emission Control System Design and
Operation 4-22
4.1.2.3 Environmental Baseline 4-24
4.1.3 Good Combustion and Exhaust Gas Temperature
Control. 4-24
4.1.3.1 Description of Modifications , . . 4-2S
4.1.3.2 Environmental Performance. .... 4-29
4.1.3.3 Costs 4-30
4.1.4 Good Particulate Control 4-30
4.1.4.1 Description of Modifications . . . 4-30
4.1.4.2 Environmental Performance. .... 4-30
4.1.4.3 Costs. ... ...... 4-33
4.1.S Best Particulate Control ..... 4-33
4.1.5.1 Description of Modifications . . . 4-33
4.1.5.2 Environmental Performance 4-33
4.1.5.3 Costs. ...... 4-33
4.1.6 Good Add Gas Control 4-37
4.1.6.1 Description of Modifications . . . 4-37
4.1.6.2 Environmental Performance 4-39
4.1.6.3 Costs 4-39
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TABLE OF CONTENTS (Continued)
Chapter . Page
4,1.7 Best Add Gas Control. 4-39
4.1,7,1 Description of Modifications . . . 4-39
4.1.7.2 Environmental Performance. .... 4-43
4.1.7.3 Costs 4-43
4.1.8 Summary of Control Options ......... 4-43
4.1.8.1 Description of Control Options , . 4-43
4.1.8.2 Environmental Performance 4-47
4.1.8.3 Costs. ... ...... 4-47
4.1.8.4 Energy Impacts 4-47
4.2 ROCKING/RECIPROCATING GRATE MASS BURN REFRACTORY-
WALL COMBUSTQR . 4-il
4.2.1 Description of the Shtgoygan, Wisconsin
Combustor. .......... 4-51
4.2.1.1 Combustor Design and Operation . . 4-51
4.2.1.2 Emission Control System Design and
Operation. ........... 4-54
4.2.2 Description of Model Plant . 4-55
4.2.2.1 Combustor Design and Operation . . 4-55
4.2.2.2 Emission Control System Design and
Operation. ..... 4-57
4.2.2.3 Environmental Baseline ...... 4-57
4.2.3 Good Combustion. ........ . 4-59
4.2.3.1 Description of Modifications . . . 4-59
4.2.3.2 Environmental Performance. .... 4-63
4.2.3,3 Costs. . . 4-63
4.2.4 Good Participate Control .......... 4-63
4.2.4.1 Description of Modifications . . . 4-63
4.2.4.2 Environmental Performance 4-67
4.2.4.3 Costs 4-67
4.2.5 Best Particulate Control 4-67
4.2.5.1 Description of Modifications . . . 4-67
4.2.5.2 Environmental Performance 4-67
4.2.1.3 Costs 4-70
4.2.6 Good Acid Gas Control. , 4-70
4.2.6.1 Description of Modifications . . . 4-70
4.2.6.2 Environmental Performance. .... 4-72
4.2.6.3 Costs. 4-72
4.2.7 Best Add Gas Control 4-72
4.2.7.1 Description of Modifications . . . 4-72
4.2.7.2 Environmental Performance 4-75
4.2.7.3 Costs. 4-75
4.2.8 Summary of Control Options ......... 4-75
4.2.8.1 Description of Control Options . . 4-75
4.2.8.2 Environmental Performance. .... 4-80
4.2,8.3 Costs. 4-80
4.2.8.4 Energy Impacts ... 4-80
fv
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TABLE OF CONTENTS (Continued)
Chapter , Page
4.3 GRATE/ROTARY KILN REFRACTORY-WALL COMBUSTOR 4-84
4.3.1 Description of the Montgomery County, Ohio
Plants 4-84
4,3.1.1 Combustor Design and Operation . . 4-86
4.2.1.2 Emission Control System Design and
Operation , 4-93
4.3.2 Description of Model Plant 4-94
4.3.2.1 Combustor Design and Operation . . 4-94
4.3.2.2 Emission Control System Design and
Operation. ........... 4-96
4.3.2.3 Environmental Baseline . 4-96
4.3,3 Good Combustion and Exhaust Gas Temperature
Control. , 4-98
4.3.3.1 Description of Modifications . . . 4-98
4.3.3.2 Environmental Performance. .... 4-101
4.3.3.3 Costs. ............. 4-101
4.3.4 Best Partlculate Control ..... 4-104
4.3.5 Good Acid Gas Control 4-104
4.3.5.1 Description of Modifications . . . 4-104
4.3.5.2 Environmental Performance 4-105
4.3.5.3 Costs 4-105
4.3.6 Best Add Gas Control. . 4-105
4.3,6.1 Description of Modifications . . . 4-lOi
4.3.6.2 Environmental Performance 4-109
4.3.6.3 Costs 4-109
4.3.7 Summary of Control Options ......... 4-109
4.3.7.1 Description of Control Options . . 4-109
4.3.7.2 Environmental Performance 4-114
4.3.7.3 Costs 4-114
4.3.7.4 Energy Impacts .......... 4-114
4.4 REFERENCES ...... 4-118
5.0 MASS BURN WATERWALL COMBUSTORS 5-1
5.1 LARGE MASS BURN WATERWALL COMBUSTOR .... 5-7
5.1.1 Description of Saugus Plant. 5-7
5.1.1.1 Combustor Design and Operation . . 5-7
5.1.1.2 Emission Control System Design and
Operation 5-11
5,1.2 Description of Model Plant ......... 5-12
5.1.2.1 Combustor Design and Operation . . 5-12
5.1.2.2 Emission Control System Design and
Operation 5-15
5.1.2.3 Environmental Baseline 5-15
5.1,3 Good Combustion. 5-16
5.1.3.1 Costs. 5-16
5.1,4 Good Partlculate Control ..... 5-16
5.1.5 Best Particulate Control .......... 5-16
5.1.5.1 Description of Modifications . . . 5-16
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TABLE OF CONTENTS (Continued)
Chapter . Page
5.1.5.2 Environmental Performance 5-18
5.1.5.3 Costs. ......... 5-18
5.1.6 Good Add Gas Control. ........... 5-18
5.1.6.1 Description of Modifications . . . 5-18
5.1.6.2 Environmental Performance. .... 5-22
5.1.S.3 Costs. 5-22
5.1.7 Best Add Gas Control 5-25
5.1.7.1 Description of Modifications . . . 5-25
5.1.7.2 Environmental Performance. .... 5-25
5.1.7.3 Costs 5-25
5.1.8 Summary of Control Options ......... 5-29
5.1.8.1 Description of Control Options . . 5-29
5.1.8.2 Environmental Performance 5-29
5.1.8.3 Costs. 5-29
5.1.8.4 Energy Impacts .... 5-29
5.2 MT0-SIZE MASS BURN WATERWALL COM8USTOR . 5-36
a.2.1 Description of Nashville Thermal Plant . . . 5-36
5.2.1.1 Combustor Design and Operation . . 5-38
5.2.1.2 Emission Control System Design and
Operation. ........... 5-42
5.2.2 Description of Model Plant 5-44
5.2.2.1 Combustor Design and Operation . . 5-44
5.2.2.2 Description of Emission Controls 5-46
5.2.2.3 Environmental Baseline ...... 5-46
5.2.3 Good Combustion. . 5-48
5.2.3.1 Costs. . 5-48
5.2.4 Best Particulate Control . 5-48
5.2.5 Good Acid Gas Control 5-48
5.2.5.1 Description of Modifications . . . 5-48
5.2.5.2 Environmental Performance. .... 5-50
5.2.5.3 Costs. ...... 5-50
5.2.6 Best Acid Gas Control-. 5-50
5.2.6.1 Description of Modifications . . . 5-50
5.2.6.2 Environmental Performance. .... 5-54
5.2.6.3 Costs 5-54
5.2.7 Summary of Control Options 5-54
5.2.7.1 Description of Control Options . . 5-54
5.2.7.2 Environmental Performance. .... 5-58
5.2.7.3 Costs. . ....... 5-58
5.2.7.4 Energy Impacts 5-58
5.3 SMALL MASS BURN WATERWALL COMBUSTOR. . .- 5-63
5.3.1 Description of New Hanover County MWC. . . . 5-63
5.3.1.1 Combustor Design and Operation . . 5-63
5.3.1.2 Emission Control System Design and
Operation. ........... 5-67
vi
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TABLE OF CONTENTS (Continued)
Chapter . Page
5,3.2 Description of Hodel Plant ......... 5-69
5.3.2.1 Combustor Design and Operation . . 5-69
5.3.2.2 Emission Control System Design and
Operation. ........... 5-72
5.3.2.3 Environmental Baseline 5-72
5.3.3 Good Combustion. 5-73
5.3.3.1 Description of Modifications . . . 1-73
5.3.3.2 Environmental Performance 5-74
5.3.3.3 Costs 5-74
5.3.4 Good Participate Control , , 5-74
5.3.4.1 Description of Modifications . . . 5-74
5.3.4.2 Environmental Performance. .... 5-77
5.3.4.3 Costs. 5-77
5.3.5 Best Participate Control 5-77
5.3.5.1 Description of Modifications . . . 5-77
5.3.5.2 Environmental Performance. .... 5-80
5.3.5.3 Costs. 5-80
5.3.6 Good Acid Gas Control. .... 5-82
5.3.6.1 Description of Modifications . . . 5-82
5.3.6.2 Environmental Performance. .... 5-82
5.3.6.3 Costs. 5-82
5.3.7 Best Acid Gas Control. . ..... 5-85
5.3.7.1 Description of Modifications . . . 5-85
5.3.7,2 Environmental Performance. .... 5-85
5.3.7.3 Costs 5-88
5.3.8 Summary of Control Options ......... 5-88
5.3.8.1 Description of Control Costs . . . 5-88
5.3.8.2 Environmental Performance 5-88
5.3.8.3 Costs. .... ..... 5-88
5.3.8.4 Energy Impacts ... 5-94
5.4 REFERENCES 1 . . 5-96
6.0 REFUSE-DERIVED FUEL (RDF)-FIRED COMBUSTORS . . 6-1
6.1 URGE RDF-FIRED COMBUSTOR 6-9
6.1.1 Description of the Occidental RDF-Fired
Facility .......... 6-9
6.1.1.1 Combustor Design and Operation . . 6-12
6.1.1.2 Emission Control System Design and
Operation 6-14
6.1.2 Description of Model Plant ......... 6-15
6.1.2.1 Combustor Design and Operation . . 6-15
6.1.2.2 Emission Control System Design and
Operation. ..... 6-18
6.1.2.3 Environmental Baseline ...... 6-18
6.1.3 Good Combustion and Exhaust Gas Temperature
Control 6-20
6.1.3.1 Description of Modifications . . . 6-20
vii
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TABLE OF CONTENTS (Continued)
Chapter . Page
6.1.3.2 Environmental Performance 6-22
6.1.3.3 Costs. ......... 6-22
6.1,4 Best Partlculate Control . 6-22
6.1.4.1 Description of Modifications . . . 6-22
6.1.4.2 Environmental Performance. .... 6-2S
6.1.4.3 Costs. ....... 6-25
6.1.5 Good Acid Sas Control 6-25
6.1.5.1 Description of Hodifications . . . 6-25
6.1.5.2 Environmental Performance. .... 6-27
6.1.5.3 Costs. . 6-27
6.1.6 Best Acid Gas Control 6-27
6.1.6.1 Description of Modifications . . . 6-27
6.1.6.2 Environmental Performance. .... 6-31
6.1.6.3 Costs 6-31
6.1.7 Summary of Control Options ... 6-31
6.1.7.1 Description of Control Options . . 6-31
6.1.7.2 Environmental Performance 6-3S
6.1.7.3 Costs. ........ 6-35
6.1.7.4 Energy Impacts . 6-35
6.2 SMALL RDF-FIRED COMBUSTOR. ....... 6-40
6.2.1 Description of the Albany, NY RDF-Fired
Facility . 6-40
6.2.1.1 Combustor Design and Operation . . 6-42
6.2.1.2 Emission Control System Design and
Operation 6-45
6.2.2 Description of Model Plant . 6-46
6.2.2.1 Combustor Design and Operation . . 6-46
6.2.2.2 Emission Control System Design and
Operation. ..... 6-49
6.2.2.3 Environmental Baseline ...... 6-49
6.2.3 Good Combustion Control 6-51
6.2.3.1 Description of Modifications . . . 6-51
6.2.3.2 Environmental Performance. .... 6-53
6.2.3.3 Costs. 6-53
6.2.4 Best Partlculate Control 6-53
6.2.5 Good Acid Gas Control 6-53
6.2.5.1 Description of Modifications . . . 6-53
6.2.5.2 Environmental Performance. .... 6-56
6.2.5.3 Costs. 6-56
6.2.6 Best Acid Gas Control 6-59
6.2.6.1 Description of Modifications . . . 6-59
6.2.6.2 Environmental Performance. .... 6-59
6.2.6.3 Costs 6-59
6.2.7 Summary of Control Options 6-63
6.2.7.1 Description of Control Options . . 6-63
6.2.7.2 Environmental Performance. .... 6-63
vi 11
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TABLE OF CONTENTS (Continued)
Chapter - Paog
6.2.7.3 Costs 6-63
6.2.7.4 Energy Impacts .... 6-68
6.3 REFERENCES ..... 6-70
7.0 MODULAR STARVED-AIR COMBUSTORS 7-1
7.1 LARGE MODULAR STARVED-AIR COMBUSTOR WITH TRANSFER
RAMS 7-8
7.1.1 Description of the Tuscaloosa, AL Plant. . . 7-8
7.1.1.1 Combustor Design and Operation . . 7-11
7.1.1.2 Emission Control System Design and
Operation 7-13
7.1.2 Description of Model Plant 7-14
7.1.2.1 Combustor Design and Operation . . 7-14
7.1.2.2 Emission Control system Design and
Operation. 7-16
7.1.2.3 Environmental Baseline ,7-16
7.1.3 Good Combustion Control. . 7-18
7.1.3.1 Description of Modifications . . . 7-18
7.1,3.2 Environmental Performance 7-20
7.1.3.3 Costs. 7-20
7.1.4 Best Participate Control 7-20
7.1.4.1 Description of Modifications . . . 7-20
7.1.4.2 Environmental Performance 7-23
7.1.4.3 Costs 7-23
7.1.5 Sood Acid Gas Control. ........... 7-23
7.1.5.1 Description of Modifications . . . 7-23
7.1.5.2 Environmental Performance 7-27
7.1.5.3 Costs 7-27
7.1.6 Best Acid Gas Control. ...... 7-27
7.1.6.1 Description of Modifications . . . 7-27
7.1.6.2 Environmental Performance. .... 7-32
7.1.6.3 Costs. 7-32
7.1.7 Summary of Control Options 7-32
7.1.7.1 Description of Control Options . . 7-32
7,1.7.2 Environmental Performance. .... 7-32
7.1.7.3 Costs . 7-37
7.1.7.4 Energy Impacts .......... 7-37
7.2 SMALL MODULAR STARVED-AIR COMBUSTOR WITH
RECIPROCATING GRATES . 7-40
7.2.1 Description of the Waxahachie Facility . . . 7-40
7.2.1.1 Combustor Design and Operation . . 7-41
7.2.1.2 Emission Control System Design and
Operation. 7-43
7.2.2 Description of Model Plant 7-43
7.2.2.1 Combustor Design and Operation . . 7-43
7.2.2.2 Emission Control System Design and
Operation. ..... 7-45
7.2.2.3 Environmental Baseline 7-45
ix
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TABLE OF CONTENTS (Continued)
Chaptejf . page
7.2.3 Good Combustion Control 7-45
7.2.3.1 Description of Hodifications . . . 7-45
7.2.3.2 Environmental Performance. .... 7-47
7.2.3.3 Costs 7-47
7.2.4 Moderate Particulate Control ... 7-47
7.2.4.1 Description of Modifications . . . 7-47
7.2.4.2 Environmental Performance 7-47
7.2.4.3 Costs 7-47
7.2.5 Good Particulate Control ..... 7-52
7.2.5.1 Description of Modifications . . . 7-52
7.2.5.2 Environmental Performance 7-52
7.2.5.3 Costs 7-52
7.2.6 Best Particulate Control .......... 7-54
7.2.6.1 Description of Modifications . . . 7-54
7.2.6.2 Environmental Performance 7-54
7.2.5.3 Costs 7-54
7.2.7 Good Acid Gas Control 7-54
7.2.7.1 Description of Modifications . . . 7-54
7.2.7.2 Environmental Performance. .... 7-55
7.2.7.3 Costs. ... ...... 7-55
7.2.8 Best Acid Gas Control. . . . . 7-55
7.2.8.1 Description of Modifications . . . 7-55
7.2.8.2 Environmental Performance. .... 7-59
7,2.8.3 Costs 7-59
7.2.9 Summary of Control Option 7-59
7.2,9.1 Description of Control Options . . 7-59
7.2.9.2 Environmental Performance 7-64
7.2.9.3 Costs 7-64
7.2.9.4 Energy Impacts .......... 7-64
7.3 REFERENCES 7-68
8.0 MODULAR EXCESS-AIR COMBUSTORS 8-1
8.1 INTRODUCTION 8-3
8.1.1 Description of the Pittsfield, MA Plant. . . 8-3
8.1.1.1 Combustor Design and Operation . . 8-6
8.1.1 2 Emission Control System Design and
Operation 8-10
8.1.2 Description of Model Plant ......... 8-12
8.1.2.1 Combustor Design and Operation . . 8-12
8.1.2.2 Emission Control System Design and
Operation 8-14
8.1.2.3 Environmental Baseline ...... 8-14
8.1.3 Good Combustion Control. .......... 8-16
8.1.4 Best Particulate Control 8-16
8.1.4.1 Description of Modifications . . . 8-16
8.1.4.2 Environmental Performance. .... 8-16
8.1.4.3 Costs. 8-18
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TABLE OF CONTENTS (Continued)
Chapter • Page
8.1,5 Good Acid Gas Control 8-18
8,1.5.1 Description of Modifications . . . 8-18
8.1.5.2 Environmental Performance. .... 8-18
8.1.5.3 Costs 8-18
8.1.6 Best Acid Gas Control. 8-23
8.1.6.1 Description of Modifications . . . 8-23
8.1.6.2 Environmental Performance. .... 8-23
8.1.6.3 Costs 8-23
8.1.7 Summary of Control Options 8-28
8.1.7.1 Description of Control Options . . 8-28
8.1.7.2 Environmental Performance 8-28
8.1.7.3 Costs 8-28
8.1.7.4 Energy Impacts . 8-28
8.2 REFERENCES 8-33
9.0 ROTARY HATERWALL COMBUSTORS 9-1
9.1 INTRODUCTION ..... 9-1
9.1.1 Description of the Bay County, FL Plant. . . 9-1
9.1.1.1 Combystor Design and Operation . . 9-5
9.1.1.2 Emission Control System Design and
Operation. 9-10
9.1.2 Description of Model Plant ......... 9-10
9.1.2.1 Combustor Design and Operation . . 9-10
9.1.2.2 Emission Control System Design and
Operation 9-14
9.1.2.3 Environmental Baseline ...... 9-14
9.1.3 Good Combustion 9-14
9.1.3.1 Description of Modifications . . . 9-14
9.1.3.2 Environmental Performance. .... 9-16
9.1.3.3 Costs. 9-16
9.1.4 Best Particulate Control 9-16
9.1.4,1 Description of Modifications . . . 9-16
9.1.4.2 Environmental Performance. .... 9-19
9.1.4.3 Costs. .............. 9-19
9.1.5 Good Acid Gas Control ........... 9-19
9.1.5.1 Description of Modifications . . . 9-19
9.1.5.2 Environmental Performance. .... 9-24
9.1.5.3 Costs. . 9-24
9.1.6 Best Acid Gas Control 9-24
9.1.6.1 Description of Modifications . . . 9-24
9.1.6.2 Environmental Performance 9-28
9.1.6.3 Costs 9-28
9.1.7 Summary of Control Options ... 9-28
9.1.7.1 Description of Control Options . . 9-28
9.1.7.2 Environmental Performance. .... 9-28
9.1.7.3 Costs. .............. 9-33
9.1,7.4 Energy Impacts 9-33
9.2 REFERENCES ........ 9-36
xi
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TABLE OF CONTENTS (Continued)
Chapttr • Pagg
10.0 MODEL PLANTS REPRESENTING PROJECTED lll{d) FACILITIES. . . 10-1
10.1 LARGE MODULAR EXCESS AIR COMBUSTOR . . 10-1
10.1.1 Description of the Model Plant 10-1
10.1.1.1 Combustor Design and Operation . . 10-1
10.1.1.2 Emission Control Systems Design
and Operation. . 10-3
10.1.1.3 Environmental Baseline ...... 10-3
10.1.2 Good Combustion Control. ... 10-3
10.1.3 Best Particulate Control .......... 10-3
10.1.3.1 Description of Modifications . . . 10-3
10.1.3.2 Environmental Performance 10-5
10.1.3.3 Costs 10-5
10.1,4 Good Acid Gas Control. 10-5
10.1.4.1 Description of Modifications . . . 10-5
10.1.4.2 Environmental Performance 10-9
10.1.4.3 Costs. 10-9
10.1.5 Best Acid Gas Control. 10-9
10.1.5.1 Description of Modifications . . . 10-9
10.1.5.2 Environmental Performance 10-14
10.1.5.3 Costs. ......... 10-14
10.1.6 Summary of Control Options .... 10-14
10.1.6.1 Description of Modifications . . , 10-14
10.1.6.2 Environmental Performance 10-14
10.1.6.3 Costs 10-19
10.1.6.4 Energy Impacts ... 10-19
10.2 SMALL MASS BURN WATERWALL COMBUSTOR 10-22
10.2.1 Environmental Performance 10-22
10.2.2 Costs , 10-25
10.2.3 Energy Impacts 10-25
10.3 LARGE RDF-FIRED COMBUSTOR. 10-28
10.3.1 Environmental Performance 10-28
10.3.2 Costs. . ....... 10-31
10.3.3 Energy Impacts ..... 10-31
10.4 SMALL RDF-FIRED COMBUSTOR. ....... 10-34
10.4.1 Environmental Performance 10-34
10.4.2 Costs 10-37
10.4.3 Energy Impacts . . . . , IQ-37
10.5 ROTARY WATERWALL COMBUSTOR . 10-40
10.5.1 Environmental Performance. ......... 10-40
10.5.2 Costs. ............ 10-40
10.5.3 Energy Impacts ...... 10-44
xfi
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LIST OF TABLES
Table Pace
2.1-1 MWC's Visited for this Study - 2-2
2.1-2 Model Plants for MWC Retrofit Study. ... . . 2-3
2.2-1 Typical Waste Feed Composition . 2-5
2.3-1 Summary of Emission Control Technology and Cost Parameters 2-11
2.3-2 Compliance and Downtime Requirements to Retrofit
Emission Controls on Existing MWC's ...... 2-12
2.3-3 Combustion Parameters used to Evaluate MWC's . . 2-13
4.0-1 Existing Hiss Burn Refractory-Wall Combustors 4-2
4.1-1 Philadelphia Northwest Design Data 4-15
4.1-2 Model Plant Baseline Data for Traveling Grate Mass Burn
Refractory-Wall Coiubustor. . 4-21
4.1-3 Plant Capital Cost for Combustion Modifications. ..... 4-31
4.1-4 Plant Annual Cost for Combustion Modifications 4-32
4.1-5 Plant Capital Cost for Particulate Matter Control Upgrades 4-34
4.1-6 Plant Annual Cost for Particulate Matter Control Upgrades. 4-35
4.1-7 Plant Capital Cost for Dry Sorbent Injection with Rebuild
of Existing ESP and Addition of ESP Plate Area ..... 4-40
4.1-8 Plant Annual Cost for Dry Sorbent Injection with Rebuild
of Existing ESP and Addition of ESP Plate Area 4-41
4.1-9 Plant Capital Cost for Spray Dryer with Fabric Filter. . . 4-44
4.1-10 Plant Annual Cost for Spray Dryer with Fabric Filter . . . 4-4i
4.1-11 Summary of Control Options for Traveling Grite Mass Burn
Riffactory-Wall Combustor. ............... 4-46
4.1-12 Environmental Performance Summary ForMASS BURN TRAVELING
Grate Refractory-Wall Model Plant Retrofit Control
Options 4-48
4.1-13 Cost Summary for Mass Burn Traveling Grate Refractory-Wai 1
Model Plant Retrofit Control Options 4-49
4.1-14 Plant Total Energy Impacts for Control Options 4-50
4.2-1 Shegoygan Design Data 4-52
4.2-2 Model Plant Baseline Data for Rocking/Reciprocating Grate
Mass Burn Refractory-Wall Combustor. 4-56
4.2-3 Plant Capital Cost for Combustion Modifications 4-64
4.2-4 Plant Annual Cost for Combustion Modifications 4-65
4.2-5 Plant Capital Cost for New Particulate Control ...... 4-68
4.2-6 Plant Annual Cost for New Particulate Control 4-69
4.2-7 Plant Capital Cost for Dry Sorbent Injection with Fabric"
Filter 4-72
4.2-8 Plant Annual Cost for Dry Sorbent Injection with Fabric
Filter 4-73
4.2-9 Plant Capital Cost for Spray Dryer with Fabric Filter. . -. 4-77
4.2-10 Plant Annual Cost for Spray Dryer with Fabric Filter . . . 4-78
4.2-11 Summary of Control Options for Rocking/Reciprocating Grate
Mass Burn Refractory-Wall Combustor. 4-79
4.2-12 Environmental Performance Summary for Mass Burn
Reciprocating Grate Refractory-Wall Model Plant Retrofit
Control Options. .................... 4-81
4.2-13 Csot Summary for Mass Burn Reciprocating Grate Refractory-
Wall Model Plant Retrofit Control Options 4-82
xiii
-------
LIST OF TABLES (Continued)
Table Page
4,2-14 Energy Impacts for Rocking/Reciprocating Mass Burn
Refractory-Wall Combustor Control Options 4-83
4.3-1 Montgomery County, Ohio Design Data. ...... 4-87
4.3-2 Model Plant Baseline Data for Grate/Rotary K1ln Refractory-
Wall Combustor 4-91
4.3-3 Plant Capital Cost for Combustion Modifications. ..... 4-102
4.3-4 Plant Annual Cost for Combustion Modifications ...... 4-103
4.3-S Plant Capital Cost for Dry Sorbent Injection with ESP. . . 4-107
4.3-6 Plant Annual Cost for Dry Sorbent Injection with ESP ... 4-108
4.3-7 Plant Capital Cost for Spray Dryer with Fabric Filter. . . 4-111
4.3-8 Plant Annual Cost for Spray Dryer with Fabric Filter . . , 4-112
4.3-9 Summary fo Control Options for Grate/Rotary Kiln Mass
Burn Combustor 4-113
4.3-10 Environmental Performance Summary for Grate/Rotary Kiln
Refractory-Wall Model Plant Retrofit Control Options . . 4-115
4.3-11 Cost Summary for Grate Rotary/Kiln Refractory-Wall Model
Plant Retrofit Control Options ...... 4-116
4.3-12 Energy Impacts for Grate/Rotary Kiln Mass lurn Refractory-
Wall MWC Control Options 4-117
5.0-1 Existing Mass Burn Waterwall Combustors. .... 5-2
5.0-2 Components of Guidelines -Good Combustion Practices for
Minimizing Trace Organic Emissions from Mass Burn MWC's. 5-5
5.1-1 Saugus, Massachusetts Design Data 5-8
5.1-2 Model Plant Baseline Data for Large Mass Burn Water-wall
Combustor 5-13
5.1-3 Plant Capital and Annual Operating Costs for Combustion
Modifications 5-17
5,1-4 Plant Capital Cost for Particulate Natter Controls .... 5-20
5.1-5 Plant Annual Cost for Particulate Matter and Temperature
Controls . 5-22
5.1-6 Plant Capital Cost for Dry Sorbent Injection with
Addition of ESP Plate Area 5-24
5.1-7 Plant Annual Cost for Dry Sorbent Injection with Addition
of ESP Plate Area, 5-26
5.1-8 Plant Capital Cost for Spray Dryer with Fabric Filter. . . 5-28
5.1-9 Plant Annual Cost for Spray Dryer with Fabric.Filter ... 5-30
5.1-10 Summary of Control Options for Large Mass Burn Waterwall
Combustor. 5-31
5.1-11 Environmental Performance Summary for Large Mass Burn
Waterwall MWC Model Plant Retrofit Control Options . . . 5-32
5.1-12 Cost Summary for Large Mass Burn Waterwall MWC Model Plant
Retrofit Control Options ........ 5-33
5.1-13 Energy Impacts for Large Mass Burn Waterwall Combustor
Control Options. ... ......... 5-34
5.2-1 Nashville Thermal Design and Operating Data 5-37
5.2-2 Model Plant Design and Operating Data for Mid-Size Mass
Burn Waterwall Combustor ........... 5-45
xiv
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LIST OF TABLES (Continued)
Table Page
5.2-3 Plant Cost's for Combustion Modifications 5-49
5.2-4 Plant Capital Cost for Dry Sorbent Injection with ESP, , 5-52
5.2-5 Plant Annual Cost for Dry Sorbent Injection with ESP
5.2-6 Plant Capital Cost for Spray Dryer with Fabric Filter.
5.2-7 Plant Annual Cost for Spray Dryer with Fabric Filter
. 5-53
. 5-56
. 5-57
5.2-8 Summary of Control Options for Mid-Size Mass Burn Water
Hall Combustor . 5-59
5.2-9 Environmental Performance Summary for Mid-Size Mass Burn
Waterwall Model Plant Retrofit Control Options ..... 5-60
5.2-10 Cost Summary for Mid-Size Mass Burn Water-wall Model Plant
Retrofit Control Options ... ..... 5-61
5.2-11 Energy Impacts for Mid-Size Mass Burn Waterwall Combustor
Control Options 5-62
5.3-1 New Hanover Design Data. .... ....... 5-64
5.3-2 Model Plant Baseline Data for Small Mass Burn Waterwall
Combustor 5-70
5.3-3 Plant Capital Costs for Combustion Modifications 5-75
5.3-4 Plant Annual Costs for Combustion Modifications 5-76
5.3-5 Plant Capital Cost for Participate Matter and Temperature
Controls .................. 1-78
5.3-6 Plant Annual Cost for Particulate Matter and Temperature
Controls ..... .......... 5-79
5.3-7 Plant Capital Cost for Dry Sorbent Injection with Addition
of ESP Plant Area 5-84
5.3-8 Plant Annual Cost for Dry Sorbent Injection with Addition
of ESP Plate Area 5-86
5.3-9 Plant Capital Cost for Spray Dryer With Fabric Filter. . . 5-89
5.3-10 Plant Annual Cost for Spray Dryer with Fabric Filter . . . 5-90
5.3-11 Summary of Control Options for Small Mass Burn Uaterwall
Combustor 5-91
5.3-12 Environmental Performance Summary for Small Mass Burn
Waterwall MWC Model Plant Retrofit Control Options . . . 5-92
5.3-13 Cost Summary for Small Mass Burn Waterwall MWC Model Plant
Retrofit Control Options ...... ..... 5-93
5.3-14 Energy Impacts for Small Mass Burn Waterwall Combustor
Control Options, 5-95
6.0-1 Existing RDF-Fired Facilities. . 6-2
6.0-2 ASTM Classification of Refuse-Derived Fuels 6-3
6.0-3 Components of Guidelines - Good Combustion Practices for
Minimizing Trace Organic Emissions from RDF-Fired MWC'S. 6-5
6.1-1 Occidental Design Data . ...... •. 6-10
6.1-2 Model Plant Baseline Data for Large RDF-Fired Combustor. . 6-16
6.1-3 Plant Capital Costs for Combustion Modifications ..... 6-23
6.1-4 Plant Annual Costs for Combustion Modifications. ..... 6-24
6.1-5 Plant Capital Cost for Dry Sorbent Injection with Addition
of ESP Plate Area . 6-29
xv
-------
LIST OF TABLES (Continued)
Table Page
6.1-6 Plant Annual Cost for Dry Sorbent Injection with Addition
of ESP Plate Area. . ........... 6-30
6.1-7 Plant Capital Cost for Spray Dryer with Fabric Filter. . . 6-33
6.1-8 Plant Annual Cost for Spray Dryer with Fabric Filter . . . 6-34
6,1-9 Summary of Control Options for Large ROF-Fired HWC Model
Plant. 6-36
6.1-10 Environmental Performance Summary for Large RDF-Fired MWC
Model Retrofit Control Options ..... 6-37
6.1-11 Cost Summary for Large RDF-Fired MWC Hodel Plant Retrofit
Control Options. 6-38
6.1-12 Plant Total Energy Impacts for Control Options ...... 6-39
6.2-1 Albany Design Data . ; 6-41
6.2.2 Model Plant Baseline Data for Small RDF-Fired Combustor. . 6-47
6.2-3 Plant Capital Costs for Combustion Modifications ..... 6-S4
6.2-4 Plant Annual Costs for Combustion Modifications. ..... 6-55
6.2-5 Plant Capital Cost for Dry Sorbent Injection with Addition
of ESP Plate Area. ... ........ 6-58
6.2-6 Plant Annual Cost for Dry Sorbent Injection with Addition
of ESP Plate Area. 6-60
6,2-7 Plant Capital Cost for Spray Dryer with Fabric Filter. . . 6-62
6.2-8 Plant Annual Cost for Spray Dryer with Fabric Filter . . . 6-64
6.2-9 Summary of Control Options for Small ROF-Fired MWC Model
Plant. 6-65
6.2-10 Environmental Performance Summary for Small RDF-Fired MWC
Model Retrofit Control Options . 6-66
6.2-11 Cost Summary for Small RDF-Fired MWC Model Plant Retrofit
Control Options . 6-67
6.2-12 Energy Impacts for Small RDF-Fired MWC Model Plant Control
Options. .......... ..... 6-69
7.0-1 Existing Modular Starved-Air Combustors. . 7-2
7.0-2 Components of Guidelines - Good Combustion Practices for
Minimizing Trace Organic Emissions from Modular Starved-
Air MWC's 7-7
7.1-1 Tuscaloosa, Alabama Design Data 7-10
7,1-2 Model Plant Baseline Data for Large Modular Starved-Air
Combustor. ......... ......... 7-15
7.1-3 Plant Capital Costs for Combustion Modifications ..... 7-21
7.1-4 Plant Annual Costs for Combustion Modifications 7-22
7.1-i Plant Capital Cost for Particulate Matter Controls .... 7-25
7.1-6 Plant Annual Cost for Particulate Matter Controls 7-26
7.1-7 Plant Capital Cost for Dry Sorbent Injection with New ESP; 7-29
7.1-8 Plant Annual Cost for Dry Sorbent Injection with New ESP . 7-30
7.1-9 Plant Capital Cost for Spray Dryer with Fabric Filter. , . 7-33
7.1-10 Plant Annual Cost for Spray Dryer with Fabric Filter . . . 7-34
7.1-11 Summary of Control Options for Large Modular Starved-Air
Combustor 7-35
xv i
-------
LIST OF TABLES (Continued)
Table Pace
7.1-12 Environmental Performance Summary for Large Modular
Starved-Atr MWC Model Plant Retrofit Control Options . . 7-37
7,1-13 Cost Summary for Large Modular Starved-Air MWC Model Plant
Retrofit Control Options ..... 7-38
7.1-14 Energy Impacts for Large Modular Starved-Air Combustor
Control Options 7-39
7.2-1 Model Plant Baseline Data for Small Modular Starved-Air
MWC with Reciprocating Grates 7-46
7.2-2 Plant Capital Costs for Combustion Modifications 7-48
7.2-3 Plant Annual Costs for Combustion Modifications 7-49
7.2-4 Plant Capital Cost for Particulate Matter Controls .... 7-51
7.2-5 Plant Annual Cost for New Particulate Matter Controls. . . 7-53
7.2-6 Plant Capital Cost for Dry Sorbent Injection with Fabric
Filter 7-57
7.2-7 Plant Annual Cost for Dry Sorbent Injection with Fabric
Filter 7-58
7.2-8 Plant Capital Cost for Spray Dryer with Fabric Filter. . . 7-61
7.2-9 Plant Annual Cost for Spray Dryer with Fabric Filter . . . 7-62
7.2-10 Summary of Control Options for Small Modular Starved-Air
Reciprocating Grate MWC Model Plant. 7-63
7.2-11 Environmental Performance Summary for Small Modular
Starved-Air Reciprocating Grate MWC Model Plant Retrofit
Control Options. 7-65
7.2-12 Cost Summary for Small Modular Starved-Air Reciprocating
Grate Model Plant Retrofit Control Options ....... 7-66
7.2-13 Energy Impacts for Small Modular Starved-Air Combustor
Cotnrol Options . 7-67
8.0-1 Existing Modular Excess-Air Combustor. ... . . 8-2
8.1-1 Pittsfield, Massachusetts Design Data 8-5
8.1-2 Model Plant Baseline Data for Modular Excess-Air Combustor 8-13
8.1-3 Plant Capital Cost for Parteiulate Matter Controls .... 8-19
8.1-4 Plant Annual Cost for Particulate Matter Controls. .... 8-20
8.1-5 Plant Capital Cost for Dry Sorbent Injection with
Additional ESP Collection Area 8-22
8.1-6 Plant Annual Cost for Dry Sorbent Injection with
Additional ESP Collection Area ..... 8-24
8.1-7 Plant Capital Cost for Spray Dryer with Fabric Filter. . . 8-26
8.1-8 Plant Annual Cost for Spray Dryer with Fabric-Filter . . . 8-27
8.1-9 Summary of Control Options for Modular Excess-Air
Combustor 8-29
8.1-10 Environmental Performance Summary for Modular Excess-Air
MWC Model Plant Retrofit Control Options , . 8-30
8.1-11 Cost Summary for Modular Excess-Air MWC Model Plant
Retrofit Control Options . 8-31
8.1-12 Energy Impacts for Modular Excess-Air Combustor Control
Options 8-32
9.0-1 Existing Rotary Water-wall Combustors 9-2
xvi i
-------
LIST OF TABLES (Continued)
Table Page
9.1-1 Bay County, Florida Design Data 9-3
9.1-2 Bay County, Florida Emissions Summary 9-11
9.1-3 Model Plant Baseline Data for Rotary Water-wall Combustor . 9-12
9.1-4 Plant Capital Costs for Combustion Modifications ..... 9-17
9.1-5 Plant Annual Costs for Combustion Modifications 9-18
9.1-6 Plant Capital Cost for Partial!ate Matter Controls .... 9-21
9.1-7 Plant Annual Cost for Part1culate Matter Controls 9-22
9.1-8 Plant Capital Cost for Dry Sorbent Injection with
Additional ESP Collection Area 9-25
9.1-9 Plant Annual Cost for Dry Sorbent Injection with
Additional ESP Collection Area ... 9-26
9.1-10 Plant Capital Cost for Spny Dryer with Fabric Filter. . . 9-29
9.1-11 Plant Annual Cost for Spray Dryer with Fabric Filter . . . 9-30
9.1-12 Summary of Control Options for Rotary Waterwall Combustor. 9-31
9.1-13 Environmental Performance Summary for Rotary Waterwall
MWC Model Plant Retrofit Control Options ........ 9-32
9.1-14 Cost Summary for Rotary Waterwall MWC Model Plant Retrofit
Control Options. 9-34
9.1-15 Energy Impacts for Rotary Waterwall Combustor Model Plant
Control Options 9-35
10.1-1 Model Plant Baseline Data for Large Modular Excess-A1r
Combust or s 10-2
10.1-2 Plant Capital Cost for Paniculate Matter Controls .... 10-7
10.1-3 Plant Annual Costs for Particulate Matter Controls .... 10-8
10.1-4 Plant Capital Cost for Dry Sorbent Injection with
Additional ESP Collection Area ............. 10-11
10.1-5 Plant Annual Cost for Dry Sorbent Injection with
Additional ESP Collection Area 10-12
10.1-6 Plant Capital Cost for Spray Dryer with Fabric Filter. . . 10-15
10.1-7 Plant Annual Cost for Spray Dryer with Fabric Filter . . . 10-16
10.1-8 Summary of Control Options for Large Modular Excess-Air
Combustors-. 10-17
10.1-9 Environmental Performance Summary for Large Excess-Air
MMC Model Plant Retrofit Control Options 10-18
10.1-10 Cost Summary for the Large Modular Excess-Air MWC Model
Plant Retrofit Control Options . 10-20
10.1-11 Energy Impacts for the Large Modular Excess-Air Combustor
Model Plant Control Options 10-21
10.2-1 Summary of Control Options for Small Mass Burn Waterwall
Combustor. . . .......... 10-23
10.2-2 Environmental Performance Summary for Small Burn Waterwall
MWC Model Plant Retrofit Control Options . 10-24
10.2-3 Cost Summary for Small Mass Burn Waterwall MWC Model Plant
Retrofit Control Options .... 10-26
10.2-4 Energy Impacts for Small Mass Burn Waterwall Combustor
Control Options 10-27
xviii
-------
LIST OF TABLES (Concluded)
Table Page
10.3-1 Summary of Control Options for Large RDF-Fired MWC Model
Plant , 10-29
10.3-2 Environmental Performance Summary for Large RDF-F1red MWC
Model Plant Retrofit Control Options .......... 10-30
10.3-3 Cost Summary for Large RDF-Fired MWC Model Plant Retrofit
Control Options 10-32
10.3-4 Plant Total Energy Impacts for Control Options ...... 10-33
10.4-1 Summary of Control Options for Small RDF-Fired MWC Model
Plant 10-35
10.4-2 Environmental Performance Summary for Small RDF-Fired MWC
Model Plant Retrofit Control Options ..... 10-36
10.4-3 Cost Summary for Small RDF-F1red MWC Model Plant Retrofit
Control Options. ..... 10-38
10.4-4 Plant Total Energy Impacts for Control Options ..:...' 10-39
10.5-1 Summary of Control Options for Rotary Waterwall Combustor. 10-41
10.5.-2 Envrlonmental Performance Summary for Rotary Waterwall
MWC Model Plant Retrofit Control Options 10-42
10.5-3 Cost Summary for Rotary Waterwall MWC Model Plant Retrofit
Control Options. ........... . 10-43
10.5-4 Plant Total Energy Impacts for Control Options . 10-45
ixx
-------
LIST OF FIGURES
Figure Page
2.2-1 Relationships of CO and 09 in a Nass Burn Water-wall
MWC. . . . . f . . 2-7
4.0-1 Refractory-Mall Batch Combustor 4-4
4.0-2 Mass Burn Refractory-Hall Corobustor with Traveling Grate . 4-5
4.0-3 F&E (Flynn & Emrick) Rocker Grate 4-6
4.0-4 Mass Burn Refractory-Wall Combustor with Grate/Rotary Kiln 4-8
4.0-5 Theoretical Temperature of Products of Combustion as a
Function of Excess A1r . . ..... 4-11
4.1-1 Original Philadelphia NW Combustor Profile ... 4-17
4.1-2 Plot Plan of Model Plant 4-23
4.1-3 Model Plant Combustor Profile Showing Combustion Retrofits 4-26
4.1-4 Plot Plan of New ESP Plate Area Equipment Arrangement. . , 4-36
4.1-5 Plot Plan of Dry Sorbent Injection Retrofit Equipment
Arrangement 4-38
4.1-6 Plot Plan of Spray Dryer/Fabric Filter Retrofit Equipment
Arrangement 4-42
4.2-1 Shegoygan Combustor Profile. . 4-53
4.2-2 Plot Plan of Model Plant 4-58
4.2-3 Model Plant Combustor Profile Showing Combustion Retrofits 4-60
4.2-4 Plot Plan of Particulate Control Equipment ........ 4-66
4.2-5 Plot Plan of Dry Sorbent Injection/Fabric Filter Equipment
Arrangement. 4-74
4.2-6 Plot Plan of Spray Dryer/Fabric Filter Retrofit Equipment
Arrangement 4-76
4.3-1 Profile of Original Combustor (#1 and #2) at Montgomery
County, OH ............... 4-85
4.3-2 Profile of New Combustor (13) at Montgomery County (North),
OH . 4-88
4.3-3 Plot Plan of Montgomery County (South), OH 4-93
4.3-4 Model Plant Plot Plan 4-97
4.3-5 Combustor Profile Showing Combustor Modifications. .... 4-100
4.3-6 Plot Plan of Sorbent Injection Equipment Arrangement . . . 4-106
4.3-7 Plot Plan of Spray Dryer/Fabric Filter Retrofit Equipment
Arrangement. . ......... 4-110
5.1-1 General System Diagram of Saugus MUC Plant ........ 5-9
5.1-2 Plot Plan of Model Plant . 5-14
5,1-3 Plot Plan of Temperature and Particulate Control Equipment 5-19
5.1-4 Plot Plan of Sorbent Injection Equipment Arrangement . . . 5-23
5.1-5 Plot Plan of Spray Dryer/Fabric Filter Retrofit Equipment
Arrangement. 5-27
5.2-1 Configuration of Original Combustor (#2) 5-40
5.2-2 Configuration of New Combustor (14). ...... 5-40
5.2-3 Configuration of New Combustor (14) Showing Overfire Air
Locations 5-41
5.2-4 Duct Configuration at Nashville Thermal 5-43
5.2-5 Plot Plan of Model Plant 5-47
xx
-------
LIST OF FIGURES (Continued)
Figure Page
5.2-6 Plot Plan of Sorbint Injection Equipment Arrangement ... 5-51
5.2-7 Plot Plan of Spray Dryer/Fabric Filter Retrofit Equipment
Arrangement 5-55
5.3-1 Plot Plan of Model Plant 5-71
5.3-2 Plot Plan of New ESP Plate Area Equipment Arrangement. . . 5-81
5.3-3 Plot Plan of Sorbent Injection Equipment Arrangement , . . 5-83
5,3-4 Plot Plan of Spray Dryer/Fabric Filter Retrofit Equipment
Arrangement i-87
6.1-1 General Process Diagram of EFW Facility 6-11
6.1-2 Equipment Arrangement of Nodel Plant 6-17
6.1-3 Plot Plan of Model Plant 6-19
6.1-4 Plot Plan of Temperature Control Equipment Arrangement . . 6-26
6.1-5 Plot Plan of Sorbent Injection Equipment Arrangement . . . 6-28
6.1-6 Plot Plan of Spray Dryer/Fabric Filter Retrofit Equipment
Arrangement. . 6-32
6.2-1 Albany RDF-Fired Boiler 6-43
6.2-2 Plot Plan of Model Plant 6-50
6.2-3 Plot Plan of Sorbent Injection Equipment Arrangement ... 6-57
6.2-4 Plot Plan of Spray Dryer/Fabric Filter Retrofit Equipment
Arrangement. 6-61
7.0-1 Typical Modular Starved-Air Corabustor with Transfer Rams . 7-4
7.1-1 Typical Consumat Module. . 7-9
7.1-2 Plot Plan of Model Plant ........ 7-17
7.1-3 Combustion Modification Equipment Location ........ 7-19
7.1-4 Partlculate Control Equipment Arrangement 7-24
7.1-5 Dry Sorbent Injection Equipment Arrangement 7-28
7.1-6 Spray Dryer/Fabric Filter Equipment. . . 7-31
7.2-1 Plot Plan of Model Plant 7-44
7.2-2 Plot Plan of Temperature and Partlculate Control Equipment 7-50
7.2-3 Plot Plan of Dry Sorbent Injection/Fabric Filter Retrofit
Equipment Arrangement. . ....... 7-S6
7.2-4 Plot Plan of Spray Dryer/Fabric Filter Retrofit Equipment
Arrangement. 7-60
8.1-1 Equipment Train at Pittsfleld 8-4
8.1-2 Typical V1con/Enercon Module 8-7
8.1-3 Electrified Gravel led 8-11
8.1-4 Plot Plan of Model Plant ...... ... 8-15
8.1-5 Plot Plan of Partlculate Control Equipment ........ 8-17
8,1-6 Plot Plan of Dry Sorbent Injection Equipment Arrangement . 8-21
8.1-7 Plot Plan of Spray Dryer/Fabric Filter Retrofit Equipment
Arrangement. . 8-25
9.1-1 Simplified Process Flow Diagram, Gas Cycle for-
Westinghouse Bay County Resource Management Center . . . 9-4
9.1-2 Cross-Section of the Westinghouse 0'Conner Water-Cooled
Rotary Combustor . . ............. 9-7
9.1-3 Model Plant Plot Plan. . 9-15
9.1-4 Partlculate Control Equipment Arrangement. ........ 9-20
xxi
-------
LIST OF FIGURES (Concluded)
Figure Page
9.1-S Dry Sorbent Injection Equipment Arrangement. ....... 9-23
9.1-6 Spray Dryer/Fabric Filter Equipment Arrangement 9-27
10.1-1 Plot Plan of Model Plant 10-4
10.1-2 Plot Plan of Participate Control Equipment ........ 10-6
10.1-3 Plot Plan of Dry Sorbent Injection Equipment Arrangement . 10-10
10.1-4 Plot Plan of Spray Dryer/Fabric Filter Retrofit Equipment
Arrangement. . 10-13
xxi i
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1.0 INTRODUCTION
1.1 BACKGROUND AND REGULATORY OBJECTIVES
Regulations for existing municipal waste corabustors (MWC's) will be
proposed in the form of emission guidelines under the authority of Section
lll(d) of the Clean Air Act (CM). States will be required to develop
specific regulations for their existing MNC's consistent with the Federal
guidelines. This ruleraaking will force some facilities to retrofit
combustion systems and add-on emissions control. The purpose of this
document is to identify the major categories of HWC's in the population and
evaluate the technical feasibility, environmental benefits, and cost impacts
of various retrofit options. Representative model plants have been
developed and will serve as the basis for these evaluations. Although the
technical feasibility and cost Impacts of applying retrofit control options
are site-specific, it is expected that the model plant retrofit evaluations_
will address the majority of site-specific situations that will be
encountered in retrofitting controls to the full HWC population.
1.2 OVERVIEW OF EXISTING HWC POPULATION
There are currently about 160 MWC's in operation. Three main types of
combustors are used: mass burn, modular, and refuse-derived fuel (RDF)-
fired. The first type is called "mass burn" because the waste is combusted
without any pre-processing other than the removal of large noncombustible
items. In a typical mass burn combustor, refuse 1s placed on a grate system
that moves the waste through the combustor. Combustion air in excess of
stoichiometric amounts is supplied both below (underfire air) and above
(overfire air) the grate. Mass burn combustors are usually field-erected
and range 1n size from 50 to 1,000 tons per day (tpd) of refuse throughput
per unit. The majority of mass burn facilities have two or more combustors
and many have site capacities of greater than 1,000 tpd.
The mass burn category can be further divided Into waterwall and
refractory-wall designs. Waterwall combustors are designed to recover
energy in the form of steam. Refractory-wall combustors are used for waste
volume reduction and do not recover energy. Most refractory-wall combustors
were built prior to the early 1970's. Newer units are waterwall designs.
1-1
-------
Modular eombustors also burn waste without pre-processing, but they are
typically shop fabricated and generally range in size from 5 to 120 tpd of
refuse throughput. One of the most coupon types of modular eombustors is
the starved-air or controlled-air type, incorporating two combustion
chambers. Combustion air is supplied to the primary combustion chamber at
substoichiometric levels. The incomplete combustion products pass Into the
secondary combustion chamber where excess air is added and combustion is
completed. Another type of modular combustor, functionally similar to
larger, mass burn units, uses excess air in the primary chamber. No
additional air is added in the secondary chamber.
The third main combustor type burns refuse derived fuel (RDF). This
type of combustor burns a more refined waste which may vary from shredded
waste to finely divided fuel suitable for co-firing with pulverized coal.
Most systems that are designed to burn RDF use a spreader-stoker combustor.
The RDF is burned in a semi-suspension mode. Feeding is accomplished using
an air-swept distributor. Underfire air is normally preheated and
introduced beneath the grate by a single plenum. Overfire air is injected
through rows of high-pressure nozzles. Combustor sizes range from 320 to
1,400 tpd. Most RDF facilities have two or more eombustors, and site
capacities range up to 3,000 tpd.
In terms of numbers, modular and mass burn units account for the
majority of MWC's. There are currently about 24 plants with mass burn
refractory-wall eombustors, and 25 plants with water-wall eombustors. There
are over 50 plants with modular starved-air eombustors and about 10 plants
with modular excess air eombustors. Refuse-derived fuel eombustors are used
at about 17 plants, and there are 3 existing plants with rotary waterwall
eombustors. Since modular eombustors tend to be much smaller than mass burn
and RDF eombustorst they account for a lower percent age of the national
capacity despite their greater numbers.
The remaining MWC population is made up of small numbers of other types
of MWC's. For example, rotary waterwall eombustors burn waste without
pre-processing but have a different design from most mass burn units. There
are also a few fluidized-bed eombustors (FBC's).
1-2
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1.3 ORGANIZATION OF REPORT
This document 1s divided Into two basic parts: (1) Introduction
(Sections 2.0 and 3.0), and (2) case studies. The introduction provides an
overview on the selection and development of model plants, pollutants and
emission rates, and technologies for controlling MWC air emissions. Case
studies for model facilities are presented in Sections 4.0 through 10.0,
Section 4.0 contains case studies for three mass burn refractory-wall
combustors with different grate configurations.
Section 5.0 contains case studies for three different sized mass burn
waterwall models. Section 6.0 contains case studies for both a large and
small RDF-fired model. Section 7.0 contains case studies for two types of
modular starved-air combustor. Section 8.0 presents a case study for a
modular excess-air model. Section 9.0 presents a case study for a rotary
waterwall combustor.
Section 10.0 presents summaries for model .plants which were developed.
to represent project.Ill(d) facilities. These are facilities which will
commence construction prior to November 1989 and will be subject to the
lll(d) guidelines. Each of these model plants is generally similar to one
of the existing model plants in Sections 4.0 through 9.0.
In sections where more than one model of similar type is presented,
there is an introductory section which provides discussion relevant to all
of the case studies in that section.
Each case study contains a description of an actual facility visited to
gather information for model development, as well as a detailed description
of the model itself. The remaining subsections of each case study detail
the possible retrofit control options as well as the environmental and the
cost impacts of implementing each option.
1-3
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2.0 BACKGROUND AND METHODOLOGY
2.1 SITE SELECTION AND DEFINITION OF MODEL PLANTS
Due to the infeasibility of conducting site-specific evaluations of each
of the roughly 160 existing MWC's, a model plant approach was chosen to
evaluate the impacts of retrofit controls. The Initial step in selecting
model MWC's for study was to define key criteria for categorizing the
population of existing combustors. Major categories of combustors include:
o Mass Burn Water-wall Facilities
o Mass Burn Refractory Facilities
o Refuse-Derived Fuel-Fired (RDF) Facilities
o Modular Facilities
These categories provided a logical starting point for grouping
facilities based on combustion technology. However, within each of these
groups there are combustion technologies with distinct design features which.
require further subcategorization. For example, there are modular facilities
designed to operate in an excess-air mode while others have a starved-air
primary chamber followed by an excess-air secondary chamber. Such design
features significantly influence the technical feasibility and cost impacts
of retrofit control options. Furthermore, size distributions in some
categories warranted subcategorization by size.
The existing MWC population was divided into 12 categories, and a plant
in each category was visited to gather information for representative model
plant development. A detailed discussion of the rationale for site selection
is contained in memoranda as Appendix A to this report. Table 2.1-1
identifies the sites visited and provides information on the combustor type,
size, age, and air pollution control device (APCD) applied at each site.
Based on the plant Inspections and information on the characteristics
of MWC's in each category, model plant parameters were developed for each
category. In some cases, the model plant parameters differed in some
respects from the visited plant in order to better represent the category as
a whole. In addition to the 12 model plants developed to represent existing
MWC's, 5 model plants were developed to represent plants currently under
construction which will be subject to the Ill(d) emission guidelines, and due
to size, combustion technology, or other factors are significantly
2-1
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TABLE 2.1-1. MUNICIPAL HASTE OOMBUS1OSS VISITED FOR IBIS STUDY
t\»
1
rs>
Facility
Refractory -Hall
Philadelphia NM, PA
Sheboygan, HI
Dayton, OB
Man Burn Uataruall
Saugus, MA
Nashville, TH
New Hanover County, IK
Refuse-Derived Fuel
Nlaeara, MY
Albany, NY
Modular Starved-Alr
Tuscalooia, AL
UaMhaehle, TX
Modular Exceis-Alr
Pitt. field. MA
Rotary Hateruall
Bay County, FL
So. of
Type Unit*
Refractory-Uall/Traveltng Grate 2
Refractory-Wall /Rock Ing Grate 2
Refractory-Wall /Rotary Kiln 3
Large Ha** Burn Waterwall 2
Hld-sl** Ma** Bum Hstervsll 3
Small KM* Bum Watervall 2
Large RDF 2
Small RDF 2
Modular Starved-Alr with *
Transfer Raas
Modular Starved-Alr with Gratea 2
Modular Excess-Air 3
Rotary Uateruall . 2
Unit Sice
(tpd)
375
120
300
750
2 « 360
1 I 400
100
1000
300
75
25
120
250
Start-Up
Dae*
1957
1965
1970
1975
197*
1986
198*
1981
1981
mi
1982
1981
1987
Air Pollution
Electrostatic
Hater Sprays
Electrostatic
Electrostatic
Electrostatic
Electrostatic
Electrostatic
Electrostatic
Electrostatic
Electrostatic
Hone
Control Device
Preclpltstor
free Ip It a tor
Preclpltator
Preclpltator
Preclpltstor
Preclpltator
Preclpltator
Free Lp It at or
Preclpltator
Electrified Gravel Bed
Electrostatic
Preclpltator
Section
*
*
' *
5
5
5
6
6
7
7
8
9
.1
,2
-3
.1
.2
.9
.1
.2
.1
.2
.1
.1
-------
different from the model plants for existing MWC's. Table 2.1-2 lists
information on all 17 model plants developed, including combustor type,
number, size, and APCD. Further details on sites visited and development of
the model plant parameters are contained in Sections 4.0 through 10.0 of this
document.
2.2 WASTE CHARACTERIZATION AND EMISSIONS
Each case study presents information on baseline pollutant emissions,
emissions reduction achievable with retrofit controls, costs of controls, and
other environmental impacts including quantities of solid waste (combustor
bottom ash and fly ash) generated with each control alternative. This
section discusses waste characterization, MWC air emissions, and MWC residues
(ash).
2.2.1 Waste Characterization
Municipal solid waste (MSW) is a highly variable mixture of paper,
plastics, food, yard wastes, glass, ferrous and nonferrous metals, and many
other materials. The composition of MSW received by a single MWC varies
significantly from day-to-day as well as seasonally. In addition, MSW in
different regions of the country and different locales within the same region
exhibit significant differences. The extent of material recycling
accomplished by waste disposers prior to delivery to the MWC facility also
has a significant impact on waste composition.
In this study, two model waste compositions were used, one representing
unprocessed waste and the other representing processed wastes referred to as
refuse-derived fuel (RDF) which is MSW that has been shredded, and from which
most of the noncombustibles such as ferrous metals and glass have been
removed. The assumed chemical compositions of these two waste types are
presented in Table 2.2-1. Unprocessed waste is burned in mass burn and
modular MWC's while processed waste is burned in RDF-fired facilities.
2.2.2 Pollutants of Concern
The six air pollutants addressed in this analysis are:
1. polychlorinated dibenzo-p-dioxins and dibenzofurans (COD/CDF)
2. carbon monoxide (CO)
3. particulate matter (PM)
4. trace metals
S. hydrogen chloride (HC1)
6. sulfur dioxide (S02)
2-3
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TABLE 2,1-2. MODEL PLANTS FOR EXISTING AND UNDER CONSTRUCTION MIC*«
type
Refractor-Hall
Rafractorjr-HalUTravslltn Graft*
Rafr*ctory-W*ll/Rockin* Grate
Re fractory-Uall/ Rotary Ella
Kaia Burn Haternall
Lacs.* M»»s Burn Hatervall
Mid-site Has* Bum U»terv«U
Small Mat* Burn W»terv»U
Small Ha*i Burn Hatarvall (UC}*
Rifum- Derived Fuel
Lars a RDF
Small RDF
Large RDF (UC)
a
Small RDF (UC)
Hadulaf Starved-Alr
Modular Starved-Atr with
Transfer Rams
Modular Starved-Alr with Grata*
(lodular Excess-Air
Nodular Excess-Air
a
Ur»e Modular Cxeess-AIr (UC)
Rotary Uattrv.aU
Rotary Uatervall
Rotary tlatarvall (UC)
Ho. of
Unit*
2
2
3
3
J
2
2
2
2
2
2
3
2
I
2
3
2
2
Unit Sic*
(tpd)
373
120
300
730
360
100
100
1000
300
1000
300
SO
2S
100
HO
250
240
Air Pollution Control Device
Electrostatic Freclpltator
Water Spray*
Electrostatic Praelpltater
Electrostatic Preclpltstor
Electrostatic PrecLpttstor
ELectroitstlc Preclpltatoc
Electrostatic Preclpltator
Electrostatic Preclpltator
Electrostatic Preclpltstor
Electrostatic Preclpltator
Electrostatic Preelpltator
Electrostatic Preclpltator
DOM
Electrostatic Preclpltator
Electrostatic Preclpltstor
Electrostatic Preclpltator
Electrostatic Preclpltator
Section
* 1
4.2
4,3
S.I
S.2
5.3
10.2
6.1
6.2
10.3
10.4
I.I
1.2
8.1
10.1
9.1
10.5
Repreiants MWC'« unoer corn cruet ton (UC) by the end of 1989 which differ In *Lze or combo «t-1 on technalony from model plants for existing
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TABLE 2.2-1. TYPICAL WASTE FEED COMPOSITION
1,2
Constituent
Carbon
Hydrogen
Oxygen
Sulfur
Nitrogen
Water
Chlorine
Inerts (ash)
_, Composition (%}
Unprocessed Waste
25.6
3.4
20.3
0.2
0,5
25.2
0.5
24.3
RDF
33.8
4.5
27.9
0.2
0.5
25.2
0.4
7.5
2-5
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A brief discussion of the formation mechanisms for etch of these pollutants
and the basis for estimating baseline emissions is provided in the following
section.
CDD/CDF
Only a small portion of the existing HWC's have been tested for CDD/CDF.
Furthermore, available measurements of CDD/CDF from the existing population
of combustors are highly variable.
There are a number of theories concerning the formation of PCDD's and
PCDF's from HSW combustion systems. The first theory involves the
breakthrough of unreacted PCOD/PCDF present in the raw refuse. Although MSW
samples at several facilities have identified trace quantities of CDD/CDF,
there is general agreement that air emissions of CDD/CDF from MWC's are not
primarily the result of these trace quantities in waste feed. A more
plausible theory involves the conversion of species referred to as precursors
which are of similar structure. For example, relatively simple reactions can-
convert chlorophenols and polychlorinated biphenyls to PCDD/PCDF's. The
precursors can be in the refuse and can be produced by pyrolysis in
oxygen-starved zones. A third mechanisms involves the synthesis of PCDD/PCDF
from a variety of organics and a chlorine donor. A fourth mechanism involves
the downstream formation of PCDD/PCDF due to the catalytic reaction of heavy
organics arid a chlorine donor. The limited data on this fourth mechanism
suggests that maximum CDD/CDF formation occurs at temperatures of
approximately 500°F to 600°F. At temperatures above 750°F the formation
reactions are slowed considerably.
Carbon Honoxide
As waste bums in a fuel bed it releases CO, hydrogen (H-), and unburned
hydrocarbons. Additional air then reacts with the gases escaping from the
fuel bed to convert CO and H« to CQ« and H.O. Adding too much air to the
combustion zone will lower the local gas temperature and quench (retard) the
oxidation reactions. If too little air is added, the probability of
incomplete mixing increases, allowing greater quantities of organics to
escape the furnace. Figure 2.2-1 depicts the CO concentration versus oxygen
concentration relationship in a mass burn waterwall MHC. The curve
2-6
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OXYGEN CONCENTRATION
A - INSUFFICIENT AIR C*W2—CO
8 - APPROPRIATE OPERATING REGION
C - "COLO BURNING"
Figure 2.2-1, Relationship of CO and 02 in a mass burn water-wall HWC,
2-7
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demonstrates that CO emissions are minimized if an appropriate range of
oxygen concentration is maintained.
Carbon monoxide concentrations are good indications of combustion
efficiency, and are important criteria for indicating potential instabilities
1n the combustion process. The relationship between emissions of CDD/CDF and
CO indicates that high levels of CO correspond to poor combustion conditions
and hence, high CDO/CDF emissions. When CO levels are low, however, a range
of COD/CDF levels have been observed, and correlations between CO and COO/CDF
are not well defined.
Participate Hatter
The amount of PM exiting the furnace of an MWC depends on the waste
characteristics and the physical nature of the combustor design and
operation. As stated previously, fly ash quantities vary greatly for mass
burn, RDF-fired, and modular starved-air combustors. However, the level of
uncontrolled PM emissions within each of these technologies are relatively .
consistent.
In addition to the direct impact of PM emissions, particulates
contribute to air emissions in two other ways. First, trace metals comprise
a portion of total particulate emissions. Secondly, the amount of particulate
surface area contributes to the availability of sites for catalytic reactions
involving organic compounds, thus playing a role in potential downstream
formation of CDD/CDF.
Trace Metals • .
Trace metals present in MSW are emitted from MWC's in association with
PM (e.g., arsenic, cadmium, chromium, and lead) and as a volatile gas (e.g.,
mercury). Control levels for PM-associated trace metals are generally
similar or slightly less than those associated with total PM. Control of
volatile trace metals, such a mercury, is less well defined and varies based
on the operating principles of the specific control technology used.
Acid Gases
Concentrations of HC1 and S02 in MWC flue gases are directly related to
the chlorine and sulfur content in the waste. The chlorine and sulfur
content varies considerably based on seasonal or local waste variations.
Actual emissions of SO- and HC1 from MWC's depend on the chemical form of
2-8
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sulfur and chlorine in the waste, the availability of alkali materials in
combustion-generated fly ash that act as sorbents, and the type of emission
control system used.-
2.2.3 Baseline Emissions
Baseline emissions for CDD/CDF, CO, PM, SO-, and HC1 were established
using available emissions data from facilities similar in design and/or
operation to each model plant. In cases where little or no data were
available for a given plant type, engineering judgement was used to establish
baseline emission values. Engineering judgements were made based on an
analysis of the model combustor's design and operation relative to practices
in place at facilities from which emissions data are available. Potential
emission-producing conditions, such as inadequate mixing, inadequate
combustion control, and temperature amendable to downstream formation of
CDD/COF, were considered in the development of baseline emission estimates.
For purposes of estimating baseline emission levels it is assumed that all ot
the chlorine and sulfur in the waste are converted to HC1 and SO-. The
rationale for establishing the baseline uncontrolled emission levels of
CDD/CDF, CO, and PM 1s discussed in a separate report.
2.2.4 Vim Residues
One goal of the combustion process Is to maximize the reduction of waste
volume and minimize the combustible content of the remaining ash residues.
Residues are classified as bottom ash, consisting of largely inert material
which remains on the waste bed after combustion is completed, and fly ash,
particulate matter which is carried out of the combustor with the combustion
gases and deposited on heat transfer surfaces and collected by the APCD's.
Bottom ash is generally discharged from the combustion chamber into a water
filled quench pit. However, a few existing MWC's use dry ash removal
systems. Fly ash not collected by an APCD is discharged through a stack to
the atmosphere. The majority of existing MwC's transfer collected fly ash
from hoppers back to the ash quench pit where 1t is mixed with bottom ash for
co-disposal. In some cases the two ash streams remain separated and are
disposed independently.
The amount of bottom ash and fly ash generated in an HWC depends on the
chemical and physical composition of the waste and on combustor design and
2-9
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operating conditions. Refuse-derived fuel is much lower in total ash content
due to waste processing activities which take place prior to combustion.
However, the physical characteristics of fluff RDF and the manner in which
combustion takes place (semi-suspension burning) may contribute to higher fly
ash quantities. By contrast, multiple chamber starved-air modular combustors
have much lower gas velocities in the primary combustion chamber, resulting
in lower percentages of total ash being entrained as fly ash. A good measure
of combustion efficiency is the amount of remaining carbon in the combined
residues.
2.3 OVERVIEW OF TECHNOLOGIES CONSIDERED
Four retrofit control technologies are examined:
1. good combustion,
2. flue gas temperature reduction,
3. PM control, and
4. acid gas control coupled with PM control.
Good combustion practices include three elements; combustion design,
combustor operation/control and verification of combustor performance. These
practices promote destruction and inhibit formation of CDD/CDF. In some
cases, achievement of good combustion practices requires modification of
combustor design as well as combustor operating practices and verification
of combustor performance.
Flue gas temperature reduction minimizes downstream formation of CDD/CDF
in the flue gas. Particulate matter control :echnologies reduce particulate
emissions, including various trace metals. Acid gas controls reduce HC1 and
SCL emissions as well as PM, COD/CDF, and condensible particulate emissions.
Performance levels for each of these four technologies are summarized in
Table 2.3-1 and are discussed in Sections 2.3.1 through 2.3.4. Procedures
for estimating costs for each of these technologies are presented In a
companion report and in Appendix B to this report.
Estimates of the amount of time required by an individual MWC for
regulatory compliance (from notification of retrofit requirements through
system start-up) and the amount of time an MWC is likely to be out of service
during installation of equipment are presented in Table 2.3-2. Compliance
and downtime requirements for actual MWC's will depend on the amount of time
required to obtain needed Federal, State, and local approvals, the
2-10
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TABLE 2.3-1. SUMMARY OF EMISSION CONTROL lECHHOLOGY PBRFQBKAKCE
Control Technology Perfomance
Technology PM HC1 S02 COD/CDF
Combustion Modification* Mom Don* Hon. 0-BiI
Tenfxratur* Control Nona • MOM MOD* See footnote a
ESP Rebuild . 0.03-0.08 §r/dicf Kan* Hone S«c foot not* •
Addition of ESP Plate ATM 0.01-0. 01 fc/dacf Hone Hone See footnote •
Key Dolgn uid
Cost Paruvtcrj
*
o c
EFCT - 4SO F
d
Moderate SCA
O e
EFGT - *50 f
d
Modarat* SCA
0
EFCT • 450 f
Dry Sorbint InJ«ctIon/ESP
0.01-0.03 »r/d.cf
50-901
40-701
751 or 125
Sorb«nt/AG - 2.0-3.0
o c
EFGT - 350 f
Rou»e ESP
Spray Dcyln»/ESP
0.01-0.01 »c/dicf 80-901
40-70Z
752 or 125 nt/d»cm
Sorb«nt/AC - 2.0-3.0
o e
EFGT - 300 F
KBU*« ESP
Spray Dryln»/Fabric Filter
0.01
90-971
70-90*
99X or 5 ng/d»cm
Sorb«nt/AG - 1.5-2.5
HOT - SOO r°
New Fabric filter
CDO/CDF at ESP outlet equal to COD/CDF at combuitor ouclet.
t>
See Section 2.1.1.
c
EFCT - Exit flue (ai trnfxrature.
d
SCA - Specific collection are*.
Sorbent-to-acid gai ratio.
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TABLE 2.1-2. COMPLIANCE AND DOUNTiNi REQUIREMENTS TO RETROFIT
EMISSION CONTROLS ON EXISTING MUC'S
Tine Requirements in Months
Front End Vendor
Engineering Selection
Off-Site On-Site MWC
fabrication Construction Downtime
Total
ESP - Rebuild
2 - 3
2 - 5
4 - 5
1 - 2
1 - 2
9 - 15
ESP - Add Plate
Area/Field
3 - 5
2 - 5
6-9 2 - 3d 0.5 - 1d 15 - 22d
Sorbent Injection
with ESP Reuse
3 - o
3 - 6
d d d
6-9 2-3 0.5-2 15-24
(M
Spray Dryer/Fabric
Filter Retrofit 3 * 6
Tenperature.Reduction 3-5
3 - ft
3 - 6
9-12
0.5 - 2d 21 - 28d
5-9 1 • 2d 0.5 - 1d 12 - 22d
Includes proposal solicitation, bid review, and contract negotiation.
b
Assume* no significant delays due to project financing and/or permitting.
Retrofit of separate ESP nodule.
An additional 6 month* stay be required if there are significant space limitations inpacting construction.
-------
site-specific difficulty of retrofitting controls due to site congestion, and
the ability of vendors to meet equipment delivery schedules.
2.3,1 Combustion. Modifications
The existing MWC population includes a wide variety of combustor
designs. Available emissions data indicate that uncontrolled COD/CDF
emissions from operating MWC's span at least three orders of magnitude. This
wide range of emissions reflects the variations in combustor designs and
operating procedures used in the existing MWC population.
Twelve site evaluations were conducted to examine design and operation
characteristics of facilities representing the existing MWC population.
Model plants representing subcategories of the existing population were
developed based on information gathered at the site visits and through other
sources. Baseline uncontrolled emission levels were established for each
model using the existing MWC emissions data base, and in some cases,
engineering judgement.
The design and operation of each combustor in this study was evaluated
against a set of criteria that defines good combustion practice. The focus
of the combustion evaluation was directed primarily toward minimization of
CDD/CDF emissions. The criteria defining good combustion practice are based
on three elements:
I. Design • MWC's must be designed in a manner that will ensure
minimization of air emissions.
2. Operation/Control - MWC's must be operated according to their
design, and control schemes must be in place which prevent
operation outside of the established operating envelope.
3. Verification - Monitors must be in place to verify system
performance on a continuous basis.
Table 2.3-3 presents a set of criteria against which the performance of
each model plant was evaluated. Satisfying these criteria will ensure that
COO/CDF emissions are minimized. Recommended values for each of the elements
are available for most combustion technologies. The recommended values
ensure that, in the allowable operating envelope, mixing occurs at sufficient
temperatures to destroy COD/CDF, and that the potential for downstream
formation of CDD/CDF is minimized. These are two key premises upon which the
combustion recommendations are based. Optimizing the mixing process requires
2-13
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TABLE 2.3-3. COMBUSTION PARAMETERS USED TO EVALUATE MWC'S
Element
Component
Design
Qperati on/Control
Verification
Temperature at fully mixed location
Underfire air control
Overfire air capacity
Overfire air injector design
Auxiliary fuel capacity
Downstream flue gas temperature
Excess Air
Turndown restrictions
Start-up procedures
Use of auxiliary fuel
Oxygen in flue gas
CO in flue gas
Furnace temperature
Adequate air distribution
Exit gas temperature
2-14
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that several design and operating features be addressed. Included among
these are temperature at the fully mixed location, control and distribution
of underfire (primary) air, design and operating capacity of overfire
(secondary) air, and overall system excess air levels. Because no
waste-fired system will achieve perfect mixing, the second key requirement of
good combustion (downstream temperature control) is necessary. Satisfying
this requirement involves control of combustor exit gas temperatures so that
flue gases do not experience long residence times at temperatures where
CDD/COF formation occurs.
The other components of good combustion all have specific objectives.
The requirement for auxiliary fuel firing capacity ensures that operation
during start-up and shutdown conditions results in minimal emissions, and the
corrective actions are available in the event that low temperature conditions
or high CO emissions occur during normal operation. Turndown restrictions
dictate upper and lower load limitations, thus defining the normal operating.
envelope. The verification measures ensure, through continuous monitoring
and periodic testing, that the system is operated according to its design
goals. These are important because COD/CDF emissions cannot be continuously
monitored. By maintaining specified levels for parameters such as flue gas
CO and CL content, furnace combustion and exhaust gas exit temperatures, and
air distributions, there will be good assurance that stable combustion
conditions and low emission levels are maintained.
The baseline design, operation, and emissions performance of each model
plant were examined against the good combustion criteria, and specific areas
were identified where adherence to the criteria was lacking. Following this
evaluation, combustion retrofits necessary for good combustion were
established for each model plant. Each retrofit was a highly site-specific
application involving addition or modification of existing equipment or
operating procedures, and in some cases, a virtual redesign and rebuild of
the entire combustor. The recommended approaches are based on past
experiences at existing plants, and In some cases, on engineering judgment.
Estimates of emission reductions associated with a combustion retrofit
were made for each model plant. The rationale for establishing the estimated
emission reductions is explained in a separate companion report on
2-15
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combustion. In some cases, modifications did not result in reduction of
baseline emissions, for example, retrofit of auxiliary fuel burners and CO
monitors at a model plant that did not previously Include these items would
not result directly in lower CDD/CDF emissions. However, they are necessary
components of good combustion practice. In other cases, combustion
modifications resulted in substantial reduction of CDD/CDF and CO emissions
from the baseline.
The final step in the analysis involved development of capital and
annual costs for each combustion retrofit. Capital costs were developed
based on information available from retrofits made at existing MWC's, and from
other similar studies. A description of the costing methodology is presented
in a companion document describing cost procedures.
2.3.2 Flue^Gas Temperature^eduction
As noted in Section 2.2, CDD/CDF may be catalytically formed in MWC flue
gas at temperatures of roughly 500 to 600°F. Cooling CDD/CDF to a
temperature of about 4SO°F or less is expected to inhibit CDD/CDF formation.
Exhaust gas cooling also results in condensation of CDD/CDF and some metals,
allowing subsequent removal in PM control devices. At least three
alternatives are available for lowering temperatures. These include
humidification (evaporative cooling) using water sprays, increasing heat
transfer area to remove more heat, and dilution of the flue gas with lower
temperature air. Cooling the flue gas through humidification or additional
heat recovery results in reducing the actual volume of flue gas to be treated
and, as a result, should improve the emissions control performance of
existing ESP's. Use of dilution air increases the actual flue gas volume and
is thus less attractive as a retrofit option if a significant amount of
cooling is required. The following sections discuss the use of
humidification and heat recovery for flue gas cooling.
Humi
-------
T0 " T1 " (QW * 94° f
-------
humldifi cation chamber 1s assumed to be constructed as a modular system.
Through appropriate construction planning, the chamber can then be Installed
Into the existing fl-ue gas ducting with minimal downtime of the combustor.
Additional jjeat Transfer Surface
A second approach for reducing MWC exhaust gas temperatures at energy
recovery facilities 1s to Install additional heat transfer surface.
Municipal waste-fired boilers are generally designed with radiant and
convectlve sections. The quantity of heat removed in the convectlve section
1s directly proportional to the amount of tube surface area available for
convectlve heat transfer. For a boiler with a constant heat Input (firing
rate) and gas velocity, additional exhaust gas temperature reduction can be
achieved by providing more tube surface area.
The typical application of this retrofit can involve the addition of a
bank of economizer tubes, replacement of an existing economizer with a
redesigned unit, or addition of a separate economizer where none previously .
existed. There are limitations to this retrofit, however, including
potential space constraints and practical limits on operating temperatures
(steam side and gas side). Because it is generally undesirable for steaming
to occur in the economizer, there are limitations on the amount of flue gas
temperature reduction that can be accomplished. Applications at one modular
facility and one mass burn waterwall facility have reduced flue gas
temperatures from 570 to 600°F down to 350 to 45Q°F prior to entering the
ESP, thus minimizing the gas residence time at temperatures where CDD/CDF
11 12
formation may occur. **
An added benefit of increased heat recovery is improved boiler
efficiency. As a rule of thumb, a 25°F drop in exit gas temperature equates
to a 1 percent Increase in boiler efficiency. For example, reducing the
economizer gas temperature from 600°F to 450°F boosts boiler efficiency by
about 6 percent, with an attendant increase in steam production and potential
revenues. Therefore, Incentives exist both from an economic and an
environmental standpoint to maximize the removal of available heat through
the boiler and provide Tower exit gas temperatures. The lower temperature
boundary 1s dictated by concerns over acid gas dewpoint. Currently there are
few, if any, ESP's operating at temperatures below 350°F, unless add gas
removal 1s included in the system design.
2-18
-------
2.3.3 Part1culate Hatter Control
A variety of PM control technologies are in use by existing MWC's,
Including ESP's, fabric filters, electrostatic gravel bed filters, cyclones,
and venturi scrubbers. The most common of these devices currently In use Is
the ESP. When properly designed and operated, ESP's are capable of achieving
high levels of PM control. Very limited data are available for the control
efficiency of other PM control devices applied to MWC's. Therefore, the
analysis of retrofit PM control options was limited to ESP's.
Two levels of retrofit PM control were considered, "good" control as
reflected by 40 CFR €0, Subparts Db and E, and "best" control as reflected by
current best available control technology (BACT). Subpart Db limits PM
emissions from new units with heat recovery and heat input rates of
100 million Btu/hr and greater to roughly 0.05 gr/dscf, while Subpart E
limits PM emissions from all other MWC's greater than 50 tpd to 0.08 gr/dscf.
Based on State or other permit requirements, a number of existing MWC ESP's _
are currently operating with PM emissions of 0,01 to 0.03 gr/dscf.
Technical alternatives for reducing emissions from existing MWC's included
rebuild of the existing ESP, increasing the plate area of the existing ESP,
and installation of a new ESP.
Rebuild of an existing ESP may be feasible for ESP's with PM removal
efficiencies lower than achievable with a new ESP of equivalent specific
collection area (SCA, equal to the total plate area divided by the flue gas
flow rate). An ESP rebuild includes replacing worn and damaged internal
components (e.g., plates, frame, electrodes), upgrading of controls and
electronics for more effective energization, and flow modeling to improve
flue gas distribution. A rebuild does not Include changing plate-electrode
geometry or adding plate area.
Installation of additional plate area can be used when the existing ESP
has insufficient plate area to achieve the required PM emission limit. In
this study, this additional plate area was installed as a second ESP located
in series downstream of the existing ESP. This approach was used to minimize
facility downtime and simplify cost estimating relative to addition of plate
area to an existing ESP. In concept, locating the new ESP in series is
analogous to adding one or more additional new fields to the existing unit.
2-19
-------
Installing a new ESP may be required If the MWC does not have an ESP or
the existing ESP cannot be upgraded to achieve the required level of PM
control. In this study, the cost of the new ESP was estimated by escalating
the cost of a new ESP based on space limitation and other retrofit costs
specific to each model plant.
2.3.4 Acid fias Control
Except for facilities constructed or modified In recent years, acid gas
controls are not used at most existing MWC's in the U. S. Emission test data
obtained from recently built units indicate that acid gas controls combined
with efficient PM control can achieve significant reductions in acid gases,
14
CDD/CDF, and volatile metal emissions. Removal of add gases is achieved
by chemical reaction with alkali sorbents. Current information suggests that
removal of CDD/CDF results from condensation of organics at reduced
temperatures and their subsequent collection in an efficient PM control
device. Available data indicate a fabric filter is needed to achieve maximum
reductions of CDD/CDF and mercury.
Two alternatives for acid gas control are considered in this study:
spray drying followed by a retrofit fabric filter and dry sorbent injection
combined with reuse of existing ESP's. The spray drying/fabric filter
alternative was used to evaluate the emission reductions, costs, and other
Impacts associated with maximum reductions in air emissions. The dry sorbent
injection/ESP reuse alternative was used to evaluate a lesser level of
emissions control, with a lower cost impact.
The major components in a spray drying system are the slurry preparation
system, the slurry atomizer and reaction vessel, and the PM collection
systems. The slurry, consisting of alkali sorbent (typically lime) and water
are injected into the flue gas at a prescribed stoichiometric ratio to cool
the flue gas and to achieve the desired acid gas removal efficiencies. High
removal efficiencies for HC1 (97 percent) and S02 {90 percent) have been
demonstrated by spray dryers operating at stoichiometric ratios of near 2.S
and a fabric filter operating temperature of 250 to 300°F. Removal
efficiencies for CDD/CDF with spray dryer and fabric filter systems have
14
exceeded 99 percent, with outlet concentrations less than 10 ng/dscm. If
an ESP is used for PM control, achievable emission reductions will be
lower.14
2-20
-------
Spray drying was used to evaluate the environmental, economic, and
energy Impacts of "best" acid gas control. System design was based on a
sorbent-to-acid gas stoichlometrlc ratio of 2.5, exit flue gas temperature of
300°F» and Installation of a new fabric filter following the spray dryer.
Estimated long-term emission reductions were 97 percent for HC1, 90 percent
for SOjj, and 99 percent for CDD/COF with a maximum COD/CDF outlet
concentration of 5 ng/dscm. As with temperature and PM controls discussed
previously and subject to model plant space limitations, most of the spray
dryer system construction activities can occur while the MWC 1s still
operating, thus limiting MWC downtime In most cases to system tie-in and
start-up.
Dry sorbent injection either directly Into the combustor or in a
downstream duct has been used on MWC's in Japan and Europe since the late
1970's, and has recently been installed on several MWC's in the U. S. Most
of the performance data is limited to acid gas control with only limited
CDD/CDF data currently available. The major components in dry Injection
systems Include sorbent storage and transport, sorbent injection, flue gas
temperature control, and PM collection. As with spray drying, emission
reduction potential is a function of sorbent feed rate, flue gas temperature,
and the type of PM control device. Because flue gas temperatures in the PM
control device of retrofit dry injection systems are likely to be higher than
for spray dryer systems (350 to 4SO°F versus 210 to 300°F), acid gas removal
efficiencies with dry injection systems are expected to be lower than with
14
spray dryers.
Dry sorbent injection was used to evaluate "good" acid gas control. In
this case, the focus was on achieving reasonable acid gas and CDD/COF
reductions while minimizing emission control system costs. System design was
based on a sorbent-to-ac1d gas stoichiometric ratio of 2.0, flue gas cooling
to 350°F, and reuse of the existing ESP (with upgrade if necessary to achieve
average PM emissions of 0.01 gr/dscf). Estimated emission reductions in this
case were 80 percent for HC1, 40 percent for SOg, and 75 percent for
COD/CDF. For the two model plants that did not have an existing ESP, a new
fabric filter was installed with the DSI system and the exit flue gas
temperature was reduced to 3QO°F. Emission reductions for HC1, SO-, and
2-21
-------
COO/CDF from this system were assumed to be the same as discussed above.
Except for systems with very short or tight flue gas arrangements, sorbent
was Injected Into th.e cooled flue gas downstream of the humidi float ion
system. Where duct configurations were limiting, injection of sorbent
directly Into the combustor was assumed. As with spray dryer systems,
construction activities were scheduled to occur while the HWC is still
operating, thus reducing HWC downtime except for system tie-in and start-up.
2-22
-------
2.4 REFERENCES
1. Hickuian, H.L. Jr. Thermal Systems for Conversion of Municipal Solid
Waste^ Volume 1 - An Overview. Governmental Refuse Collection and
Disposal Association* Silver Spring, MO. Prepared for Argonne National
Laboratory, U.S. Department of Energy. Hay 1983.
2. Wilkins, 6. Radian Corporation. Municipal Waste CombustionStudy;
Report to Congress. EPA/530-SW87-0212. June 1987.
3. Environment Canada. The National Incinerator Testingand Evaluation
Program; Two Stage Combustion (Prince Edward Island). Report
No. EPS 3/40/1. February, 1988.
4. Stleglitz, L., and Vogg, H. Formationand Decomposition of
Polvchloride Benzodloxjus and Furans Jn Municipal Wasjte Incineration.
Report No. KfK 4379, February 1988.
I. Energy and Environmental Research Corporation. Municipal Waste
Combustion Assessment, Combustion Control at Existing Facilities.
Prepared for U.S. Environmental Protection Agency. Publication
No. EPA600/8-89-058. August 1989.
6. Radian Corporation. Municipal Waste Combustors - Background Information
for Proposed Standards; Cost Procedures. Prepared for U.S.
Environmental Protection Agency. Publication No. EPA-450/3-89-27a.
July 1989.
7. Memorandum. White, D., Radian Corporation, to H. Johnston,
ISB/OAQPS/EPA. Time Requirements for Retrofit of Particulate Matter,
Acid Gas, and Temperature Control Technologies on Existing Municipal
Waste Combustors (MWC's). June 30, 1989.
8. Telecon between John Buschmann, Flakt, Inc. and David White, Radian
Corporation. June 9, 1989.
9. Telecon between Jim Donnelly, Joy, Inc. and David White, Radian
Corporation. June 12, 1989.
10. Telecon between Jan Zmuda, Research-Cottrell, Inc. and David White,
Radian Corporation. June 12, 1989.
11. Trip Report - Retrofit Control Site Evaluation at the Tuscaloosa Energy
Recovery Facility. Submitted to OAQPS/ISB by T. Emme], Radian
Corporation and P. Schindler, EER Corporation. February 9, 1988.
12. Trip Report - Site Visit; City of Hampton, VA Refuse Fried Steam Plant.
Submitted to OAQPS/ISB by P. Schindler, EER Corporation.
December 22, 1988.
2-23
-------
13. Telecon between Jerry Blue, Bobcock and Wilcox and P. Schindler, EER
Corporation. June 13, 1988.
14. Radian Corporation, Municipal Waste Combustors - Background Information
for Proposed Standards; Post-Combustion Technology Performance.
Prepared for U.S. Environmental Protection Agency. Publication
No. EPA-450/3-89-27c. August 1989.
2-24
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3.0 DEFINITION OF CONTROL OPTIONS
Seven mission control options are considered for existing sources. The
seven options are combinations of the four types of control technologies
described 1n Section 2,3. The same seven control options apply to each model
plant. The baseline level of combustion control and add-on control for the
model plants vary with combustor type, unit size, age, and prevalence of
APCO's at existing facilities represented by the model plant. In some cases,
a model plant at baseline 1s already controlled to the level of some of the
control options. In such cases, there are no cost or emission reductions
associated with those options for that particular model plant. Only one
level of combustion modification ("good combustion" as described in Section
2.3) was evaluated. The seven retrofit control options are described below:
Option 1 "Good Combustion and Temperature Control"
- good combustion
- exhaust gas temperature control to 450 F
- baseline PH control
- no acid gas control
Option 2 "Good Combustion and Temperature Control with Good PM Control"
- good combustion
- exhaust gas temperature control to 450 F
- good PM control (0.05 gr/dscf)
- no add gas control
Option 3 "Good Combustion and Temperature Control with Best PM Control"
- good combustion
- exhaust gas temperature control to 450 F
- best PM control (0.01 gr/dscf)
- no add gas control
Option 4 "Good Add Gas Control with Best PM Control"
- baseline combustion control
- exhaust gas temperature control to 350 F
- good add gas control - dry sorbent Injection
- best PM control (0.01 gr/dscf}
3-1
-------
Option 5 "Good Combustion and Temperature Control with Good Add Gas
Control and Best PH Control"
. good combustion
- exhaust gas temperature control to 350 F
- good acid gas control - dry sorbent duct Injection
- best PM control (0.01 gr/dscf)
Option 6 "Best Acid Gas Control with Best PH Control"
- baseline combustion control
- exhaust gas temperature control to 300 F
- best add gas control - spray dryer
- best PM control (0.01 gr/dscf}
Option 7 "Good Combustion and Temperature Control with Best Add Gas
Control and Best PM Control"
- good combustion
- exhaust gas temperature control to 300 F
- best add gas control - spray dryer
- best PM control (0.01 gr/dscf)
3-2
-------
4.0 MASS BURN REFRACTORY-WALL COHBUSTORS
Prior to the 1970's, there were hundreds of municipal waste combustors
(HWC's) burning refuse In the United States. The goal of these plants was to
achieve waste volume reduction; energy recovery was not Incorporated Into
their designs. Due to a number of reasons—economic, environmental, and
plant age--most of the municipal combustors ceased to operate during the
1970's. Some of these refractory-wall plants were replaced by energy
recovery plants. Others were replaced by landfills. The handful of
refractory-wall plants that still operate do so with largely outdated
technology. In addition, the Increasing limitations of available space for
landfills may cause some older refractory-wall plants to renew operation with
revamped designs. This section describes the current design and operation of
older refractory-wall combustors, and Identifies design and operating
features which may contribute to air emissions.
The existing population of mass burn refractory-wall MWC's consists of
more than 20 operating plants. Table 4.0-1 lists the mass burn refractory-
wall plants that remain In operation as of 1988. Included 1n the table are
grate type, number of units, unit capacity, year of start-up, and air
pollution control device (APCD) in place at each plant. Although none of the
plants were originally constructed with heat recovery capabilities, at least
two refractory-wall combustors (Waukesha, HI and Betts Avenue, NY, NY) have
been retrofit with a waste heat boiler, and three additional plants (North
and South Dayton, OH and Tampa, FL) are considering adding boilers 1n the
future. Host plants 1n this category use electrostatic predpltators (ESP's)
for partlculate control. However, a number of the plants use a wet
part1culate control device such as a wet scrubber. One plant (Framingham,
HA) 1s equipped with a spray dryer and fabric filter. Most of these plants
are publicly owned, and operate on a 24-hour/day, 5-day/week schedule with
weekend shutdowns.
At least three distinct combustor designs make up the existing
population of refractory-wall combustors. The first design 1s a batch-fed
upright combustor, which may be cylindrical or rectangular 1n shape. Very
few of these systems continue to operate. Three units have been Identified
4-1
-------
TABLE 4.0-1. EXISTING KASS BURN REFRACTORY-WALL CCKBUSTORS
Plant /Loot loo
Crate Trp»
to. at Units
Obit Slse
(tpd)
of
Start Up*
Ale Pollution Control Device
rv>
Batchfeed
Stanford I, CT
Buntln«ton, R
Continuous feed
Philadelphia H, PA
Philadelphia 1C, PA
East Chicago, IB
SB Oakland County, MI
Honolulu, Hi
Maw York, ft (Betts AIM.)
Clinton, MI
Euclid, OB
Pall River, HA
•aw Canaan, CT
Uaahlegton, DC
Bait law ra, IB
SH Brooklyn, W
Uaukaaha, WI
Stanford IX, CT
SheboTB.an, HI
Buntin*ton, WI
Slorth Dayton, OB
South Dayton, OB
Louisville, Kf
Praalatha*. MA
trtv«lln«
?«•«•! ing
Tr»v«Hn«
R«clproc«tln»
lUclptocatlnf
R»c Ipcocit Ing
R«c Iproca t Ing
Bocklng
Rockln*
Rocklnm
Ccata/Rataxy tlln
Uln
Kiln
Cr*t«/Rot*rr Kiln
Ello
1
2
2
2
a
3
2
*
2
2
2
1
4
4
4
2
1
2
1
3
3
4
2
4
ISO
150
JM
S7S
225
300
100
230
100
100
$00
123
ZM
100
240
88
160
120
ISO
100
3 DO
ISO
2SO
250
1911
195?
IMS
1971
IMS
1970
MA
1972
19SS
If 72
1971
1972
1971
1974
1963
1963
1970
1970
1956
1970
198i
Ilactmaeatle Pr«clplt»tor
U«CU
Electrostatic Ptaclpttatot
Electrostatic Preelpltator
Vcnturl Scrubber
Vent mi Scrubbex
EL«ctroit»tlc Preclpltatoc
Electrostatic PreclpLtator
Electrostatic Preclpltatar
Electrostatic Preelpltator
Hat Scrubber
Vcntuxl Scrubber
Electrostatic Preelpltator
Electrostatic Preelpltator
Electrostatic PrecVpltator.
Electrostatic Preelpltator
Electrostatic Preelpltator
Hater Sprays
Electrostatic Preelpltator
Electrostatic Preelpltator
Electrostatic Preelpltator
Hat Scrubber
Dry Scrubber/rabrlc Filter
Electrostatic Preelpltator
*HA - Infor*atloo not available.
-------
in tha existing population (Stamford I, CT, and two units at Huntington, NY).
The Stamford unit is rated at 150 tpd and Is equipped with a water quench and
an ESP. The units in Huntington, NY are reported to have unit capacities of
150 tpd and use water sprays to control emissions prior to discharge through
individual stacks. All three of these units were constructed prior to 1960.
Figure 4.0-1 shows the typical configuration of a batch-fed rectangular
combustor. This type of combustor was prevalent in the 1950's, but no
additional units of this design are expected to become operable.
A second, more common design consists of rectangular combustion chambers
with traveling, rocking, or reciprocating grates. This type of combustor is
continuously fed and operates in an excess air mode. The primary distinction
between plants with this design Is the manner in which the waste is moved
through the combustor. A schematic of a traveling grate combustor is shown
in Figure 4.0-2. The traveling grate moves on a set of sprockets and does
not agitate the waste bed as it advances through the combustor. As a result,
waste burnout is inhibited by fuel bed thickness, and there is considerable
potential for unburned waste to be discharged from the grates unless fuel
feeding, grate speeds, and combustion air flows and distributions are well
controlled. It is unlikely that these operational requirements are routinely
accomplished in existing units. As shown in Table 4.0-1, there are six mass
burn plants currently operating which use traveling grates. The average unit
capacity for the operating plants is approximately 300 tpd.
There are eleven mass burn refractory-wall plants in operation that use
rocking or reciprocating grates. The average unit capacity of these plants
is 230 tpd. While none of these systems represent state-of-the-art
combustion practice, rocking or reciprocating grates have advantages over
traveling grates. Rocking and reciprocating grate systems agitate and aerate
the waste bed as it advances through the combustion chamber, allowing more
waste surface area to be exposed to the combustion air and increasing burnout
of combustibles. The configuration and operation of a rocking grate section
is shown in Figure 4.0-3.
The list major design type in the mass burn refractory-wall population
is a system which combines grate burning technology with a rotary kiln.
4-3
-------
BUCKET
CHARGING
\L
\/
CAB
CHARGING
6ATf
PIT
•FlUE TO
EXPANSION
CHAMBER
t STACK
/
-TIPPING
Figure 4.0-1. Refractory-Hall Batch Combustor
-------
1 1
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if
BM
ft.
1
w
01
C3
(31
e
•o
t.
o
(A
9
o
•M
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+
4.0-3.
Stokers
•
r«
'"•
"««'«*«,.
.,..
1 •'••
-------
Figure 4,0-4 shows a schematic of this design. Two grate sections (drying
and ignition) precede a refractory-lined rotary kiln, where combustion is
completed. There are five existing plants in this subcategory, and the
average size among these units is 250 tpd.
For this study, three model plants representing refractory-wall
combustors were developed. The models were selected to be representative of
the most typical designs in the refractory-wall population. The first uses a
traveling grate and has an ESP for flue gas cleaning. The second has a
rocking grate and a wet baffled system for flue gas cleaning. The third
model plant is of the grate/rotary kiln design, and has an ESP. Descriptions
and analyses of these model plants are presented in the Sections 4.1 through
4.3.
There are a number of inherent design features and operating practices in
place at these refractory-wall HWC's which cause elevated emission levels of
air pollutants. Some of the primary areas of concern include:
1. Fuel feeding
2. Combustion air distribution and control
3. Excess air levels
4. Start-up/shutdown procedures
5. Temperature control
These topics are discussed below.
Fuel Feeding
While ram feeders are employed in a few units, it is more typical for
this type of plant to utilize a gravity feed system. In this instance,
control of fuel feeding 1s achieved by adjusting the grate speed directly
below the feed chute. This is typically a manual adjustment. In general,
grate speeds should be adjusted so that the waste feed 1s evenly distributed
on the grates, with the majority of burning being concentrated in the middle
portion of the grate. Problems may occur as waste properties (i.e., moisture)
change, resulting in clumping and poor distribution of waste on the grate and,
hence, potential burnout problems. Reciprocating and rocking grates have the
ability to minimize these problems by continually agitating and aerating the
fuel bed, but traveling grates cannot respond to changes in fuel properties.
Therefore, traveling grates are not acceptable technology for mass burn
systems.
4-7
-------
3k
o
D
Tipping Roor
1 rr-4
Overfire I I » ' | Tk
Air Vibrating ¥
Forced Fan Conveyor I Bottom
Draft Ash Ash
Quanch Conveyor
Pit
Rotary
Conveyors
Figure 4.0-4. Mass Burn Refractory-Hall Combustor with Grdtu/Rolary K
f
-------
A second problem with gravity feed systems relates to maintaining proper
combustor drafts. Combustor seals are maintained by the waste in the feed
chute. Episodes where the hopper seal is broken contribute to problems in
combustor draft control and have an adverse effect on combustion conditions.
Unstable combustor drafts can result in upsets which affect air flows,
temperatures, and air emissions. Use of ram feeders can minimize these
episodes,
Combustion AjrDistributionand Control
A number of deficiencies in combustion air flows can potentially occur
in older refractory-wall combustors. The amount, location, and distribution
of combustion air are all critical to ensuring that organic species emitted
from the burning waste bed are oxidized to the maximum extent possible.
Available information for this category of MMC's indicates that combustion
air systems are generally inadequate to provide good combustion and minimize
levels of trace organic emissions.
Good combustion practice requires that underfire air be adequately
distributed to the waste on the grate to provide proper burnout. This is
necessary to complete the burning process prior to discharge of ash from the
end of the grate. Underfire air distribution can be optimized by using at
least four separate underfire air plenums. The ability to individually
monitor and control underfire air pressures or flow rates to each plenum is
also a necessary element of good combustion.
Mass burn refractory-wall combustors typically have overfire air designs
which do not provide adequate mixing for minimizing organic emissions.
Rather than providing penetration and coverage of the combustor cross
section, the overfire air systems simply Inject air for dilution and cooling.
There is no wel1-defined point In the system where mixing is complete. In
addition, air flows are seldom measured or monitored, and adjustments are
left to the experience of the operator. It is important that overfire air
systems be designed to supply an adequate quantity of air in a location which
provides penetration and coverage of the combustor cross-section to ensure
good mixing and complete combustion. Failure to achieve good mixing can
result in higher levels of CO and organic emissions, and greater particulate
4-9
-------
carryover out of the cotnbustor. The number, diameter, velocity, and
arrangement of overflre i1r nozzles all contribute to the proper design and
operation of the system. Nozzle header pressures are typically measured to
provide verification of velocities and flows. Overflre air patterns can best
be established as a result of cold flow modeling. Verification of mixing
should be established by continuous.CO monitoring. It is doubtful that many
existing refractory-wall combustors are equipped with continuous CO monitors.
Combustor ExcessAir Levels
Refractory-wall combustors typically operate at higher excess air rates
(150 to 300 percent) than mass burn waterwall combustors (80 to 100 percent).
This 1s because refractory-wall combustors contain no heat transfer medium
such as the waterwalls which are present in modern energy recovery units.
The higher design excess air levels are specified to prevent excessive
temperatures which can result in refractory damage, slagging, fouling, and
corrosion problems. Figure 4.0-5 illustrates the relationship between excess
air levels (expressed as a percentage of stoichiometric air) and adiabatic
flame temperature. Adiabatic flame temperature is the theoretical maximum
temperature that can be achieved, assuming that perfect mixing is achieved
and that no heat loss occurs. When applying this relationship to
refuse-fired systems, the adiabatic flame temperature can be considered
analogous to the maximum theoretically achievable mass mean gas temperature
at the fully mixed location. As shown in Figure 4.0-5, the highest
theoretical temperature occurs at stoichiometric conditions, and as excess
air levels increase, the adiabatic flame temperature is reduced. For a fuel
with 20 percent moisture content (typical of MSU), the adiabatic flame
temperature of 1800°F occurs at 150 percent excess air. At excess air levels
of greater than 150 percent, the 1800°F temperature cannot be attained.
Thus, 1t 1s recommended that the 150 percent excess air be selected as an
operating target (maximum) for refractory-wall NWC's.
One adverse effect of higher excess air levels is the potential for
Increased carryover of PN from the combustion chamber and ultimately stack
emission rates. It 1s hypothesized that high PH carryover may also
contribute to increased CDD/COF emissions by providing increased surface
area for downstream catalytic formation to take place. A second problem Is
-------
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3000
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the potential for .high excess air levels to quench the combustion reactions,
preventing destruction of organic species. Because there are problems with
operating an excess air level too low or too high, systems must select an
excess air level which allows for both safe operation and minimal emissions.
Oxygen monitors are used in mass burn water-wall MWC's to verify excess
air levels. Few, 1f any, older refractory-wall combustors are equipped with
oxygen monitoring. Oxygen monitoring is an important means of verifying
performance so that air flows can be optimized.
Start-up/Shutdown Procedures
The majority of refractory-wall combustors are municipally owned and
operated, and typical operating schedules include five days on line with
shutdowns on weekends. Start-ups and shutdowns are episodes during which
CDD/CDF emissions are expected to be above normal operating levels. A
substantial number of the combustors currently operating are not equipped
with auxiliary fuel sources for process start-up and shutdown. Auxiliary
fuel firing capabilities are required for good combustion practices and
should be included in the design of all MWC's. If a system shuts down over
the weekend, one operating procedure that will enable start-up time to be
minimized is to keep all combustor seals intact, enabling the system to act
as a "thermos bottle* and retain available heat so that a totally cold start
is avoided. This is a standard operating procedure for many refractory-wall
combustors.
Temperature Control
All mass burn MWC's must have the ability to maintain combustion
temperatures above 1800°F as part of good combustion. Refractory-wall MWC's
should have no problem attaining this combustion temperature if the above
described design and operating features are In place. However, recent bench-
scale and full-scale data suggests that COD/CDF formation may also occur in
the low temperature regions of the waste combustion system. Available data
indicates that CDD/CDF formation is maximized at temperatures between 500
and 600°F. This is a typical operating temperature range for many ESP's in
the waste combustion industry. Based on the available data it appears that
formation does not occur at temperatures 1n the range of 450°F or less.
4-12
-------
Therefore, existing systems must attempt to minimize retention time of flue
gases In the range of 500 to 600°F by lowering ESP operating temperatures.
Refractory-wall combustors are equipped to address this problem through the
use of existing water sprays.
4-13
-------
4.1 TRAVELINi GRATE MASS BURN REFRACTORY-HALL COMBUSTOR
This section presents the retrofit case study results for a mass burn
refractory-wall combustor equipped with a traveling grate. As shown in
Table 4.0-1, there are six known plants in this subcitegory. Section 4.1,1
presents a description of the Philadelphia Northwest (NW) MWC plant which
was visited in order to gather Information for model development.
Section 4.1.2 describes the model plant. Sections 4.1.3 through 4.1.7
detail the retrofit modifications, estimated performance, and costs
associated with various control options. Section 4.1.8 summarizes the
control options, which are discussed in more detail in Section 3.0 of this
report.
4.1.1 Description of thePhiladelphia Northwest Plant
The Philadelphia NW plant consists of two Identical refractory-wall
combustors, each with a design capacity of 375 tons of municipal solid waste.
(HSU) per day. Table 4.1-1 presents key design data for the plant. The
facility has been in operation since 1957 and processes an estimated
25 percent of the city's municipal waste, burning waste 5-days/week with
weekend shutdowns. The plant accepts no commercial or industrial waste and
does not charge a tipping fee. Individuals are permitted to dump household
waste at the plant during designated hours. There are two 2,850 cubic yard
waste holding pits at the plant which are emptied by two overhead cranes
equipped with clamshell buckets.
4,1,111 Combustor Design and Operation. Each refractory-lined
combustor consists of a water-Jacketed gravity-feed chute, an inclined
traveling grate, a horizontal traveling grate, and an ash discharge chute.
The feed rate to each combustor is controlled by the speed of the Inclined
grate. A 4-1/2 foot vertical drop separates the inclined grate and the
horizontal grate. The speed of the horizontal grate controls the depth of
the waste bed. Bottom ash is discharged from the end of the horizontal
grate into a water quench pit. The water level in the quench pit is
designed to maintain a pressure seal between the combustor and the ash
handling system. The water level is controlled by an automatic float valve.
The traveling grates do not provide any agitation of the waste bed as
1t moves through the furnace. As a result, burnout of the waste is not
4-14
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TABLE 4,1-1. PHILADELPHIA NORTHWEST DESIGN DATA
Combustor (two identical contbustors):
Capacity
Grate Area
Inclined Grate
Horizontal Grate
Combustor Dimensions
Lower Chamber
Upper Chamber
Exit Breeching
- 375 tons per day each
- 480 square feet each
- 8 feet wide by 22 feet long, 20° incline
- 8 feet wide by 40 feet long
- Each combustor consists of two connected chambers
(See Figure 4-1,1}
- 55 feet long by 8 feet wide by 21 feet high
- 21 feet long by 8 feet wide by 13 feet high
- rectangular, 8 feet by 7 feet
Gas Conditioning (identical for each combustor):
1 Spray Tower and
1 Evaporation Tower
Water Spray
- 14 feet in diameter by 42 feet high (each)
- 100 gpm, first tower only
Emission Controls (identical for each combustor):
Type
Manufacturer
Gas Flow
Collecting Area
SCA
Dimensions
Gas Velocity
Gas Residence Time
Collection Efficiency
Exit Concentration
2-field ESP
Combustion Engineering
219,000 acfm at 550°F
47,000 square feet
215 square feet per 1000 acfm
11 x 33 x 22.4 feet {11.2 feet per field)
4 ft/sec
6 seconds
97.5%
0.02 gr/dscf at 12 percent C02
4-11
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completed prior to discharge from the horizontal grate to the quench pit.
Based on visual observation, it was estimated that waste volume reductions
are no greater than 50 to 75 percent.
The original furnace configuration Included a rectangular chamber with
a height of approximately 17 feet from the top of the horizontal stoker to
the roof. At a point 34 feet from the front wall the roof height increased
to about 32 feet, forming the upper rectangular combustion chamber, which
was a burnout area for volatiles. The length of this chamber was 20 feet,
7 inches. Combustion gases originally passed from the burnout chamber
through a rectangular opening approximately 8 feet by 12 feet, 8 inches to
the flue gas cleaning system. Figure 4.1-1 shows the original combustor
profile.
Several modifications have recently been made to each of the
combustors. First, the configuration of the upper combustor chamber was
altered by addition of structural steel refractory-lined arches on the front
and rear walls of the chamber to reduce the cross-sectional area of the
inlet to the upper chamber from its previous dimensions of 8 feet by 21 feet
to an opening 8 feet wide by about 7 feet long. In addition, a vertical
baffle was installed at the exit of the combustion chamber, and the water
sprays which were previously at that location were moved approximately
25 feet downstream into the first tower. These modifications were made in
an attempt to increase mixing and flue gas retention time. Other facilities
of this type are not expected to have these types of modifications.
A single forced-draft fan provides underfire air to both grates and
overfire air to 3 rows of nozzles located on the top of the lower combustion
chamber. There are 4 underfire plenums beneath the Inclined grate and
6 plenums beneath the horizontal grate. Each plenum has a separate manually
operated damper to adjust air distribution. Each of the 3 overfire air rows
consists of seven 4-inch diameter nozzles on 12-inch centers. The first row
is above the inclined grate near its center. The second row is located
directly above the end of the inclined grate, and the third row is above the
horizontal grate approximately one-third of the way along its total length.
Each row has an individual damper which Is either fully open or fully
closed. No accurate estimates of underfire/overfire air splits are
available.
4-16
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4-17
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A second forced-draft fan supplies wall cooling air, which is
introduced Into the" combustion chamber through six 4-inch diameter nozzles
on each side of the combustor at a level approximately 6 inches above the
top of the horizontal grate. Additional overfire air ports which were
located about 1-1/2 foot above the horizontal grate are now bricked over and
inoperable. Silicon carbide blocks line the lower portion of the combustor
to a height of 2 to 3 feet above the grates,
There are a number of sources of air leakage to the combustor,
including the space where the waste drops from the inclined grate to the
horizontal grate, A steel plate with a viewing port has been constructed at
this location to prevent projectiles from shooting out of the combustor, but
the plate does not restrict airflow Into the combustor. This area was
originally open. Inspection ports are also located on the upper front wall
of the combustion chamber, and on the rear wall where the horizontal grate ~
dumps into the ash quench pit.
The combustor has a local requirement to operate above 1,4Q0°F in order
to minimize odors. This temperature is verified by two thermocouples
located on the side walls in the rear of the combustor. These readings are
continuously recorded on a circular chart on the control panel in the Plant
Superintendent's Office. The temperatures are maintained by manually
adjusting combustion air flows and MSW feed rates. No automatic controls
are available.
Variation of the combustion air distribution is left to the discretion
of the operator based on his visual observation of the flame patterns in the
combustor. An automatic draft control provides feedback to the induced-
draft fan; a negative draft of 0.2 to 0.5 inches of water is maintained by
this control.
There is no auxiliary fuel available In either combustor. Start-up is
achieved by feeding waste onto the inclined grate until it is covered,
stopping the grate, and igniting the waste. As the flame travels up the
Inclined grate and becomes more intense, the grate 1s turned on. Plant
personnel indicated that normally it takes 2 to 3 hours to achieve the
required operating temperature.
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4.1.1.2 Emission Control System Design and Operation. Each combustor
is equipped with one spray tower, one evaporation tower and an electrostatic
predpitator (ESP). Furnace exhaust gases pass through a section of
refractory-lined breeching connecting the combustor to the first of the two
cylindrical towers, both of which are 14 feet in outer diameter and
approximately 42 feet high.
A spray ring with 14 air atomizing spray nozzles located in the first
tower provides up to 200 gpra of city water for quenching the gas. The
second tower provides additional residence time for water evaporation and
gas cooling. Booster pumps are. installed to provide necessary water
pressure. The water injection rate is automatically controlled to maintain
the ESP inlet temperature at 55Q°F, as recommended by the ESP manufacturer,
A circular chart recorder on the control panel records the ESP inlet
temperature, and a strip chart recorder records the actual water flow rate,.
which is normally about 100 gpm. Excessive ESP inlet temperature will first
sound an alarm and then shut down the system induced-draft fan. The bottom
of each tower is open to the residue quench pit which removes any large ash
particles that accumulate in the tower and maintains the tower pressure
seal.
Cooled gases exit the top of the second tower through breeching to the
ESP. The precipitators on both combustors are identical 2-field units
manufactured by Combustion Engineering and were rebuilt in 1986 according to
designs by Research Cottrell. The ESP's are reportedly designed to handle
219,000 acfm at 550°F with 47,000 square feet of collecting plate area;
2
specific collection area (SCA) is 215 ft /I,000 acfm. Each ESP vents to a
separate stack. Emissions were nearly invisible during the visit (opacity
less than 5 percent). A continuous opacity monitor is the only monitoring
equipment installed.
Each ESP field is energized by a 1,250 ma, 104 KVA silicon
transformer-rectifier and is equipped with instrumentation for monitoring
primary voltage, primary current, and secondary current. The instruments
are located on the control panel and recorded by the operator hourly.
Values noted on ont field at the time of the visit were 300 volts AC,
170 amps AC and 1,050 ma DC.
4-19
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There are also timer controllers located on the panel for activating
the rapping system on each field's electrodes. The collection hoppers in
both fields are equipped with resistance heaters. Temperature controllers
for these heaters are also located on the control panel. There is a single
blower which provides preheated air from a resistance heater to the
insulators on both fields of the precipitator. An ammeter is located on the
panel for monitoring the insulator blower motor current.
Acceptance testing of the rebuilt precipitators showed approximately
97.5 percent collection efficiency with an exit PM concentration of
0.02 gr/dscf. The tests were performed in February 1987 and were conducted
according to EPA Method 5.
The fly ash collected in the precipitator is discharged to the same ash
quench pit as the bottom ash and the particulate removed in the cooling
towers. The combined residue is pulled up a 6-foot drag chain-type inclined
conveyor at a speed of 8 feet per minute. Excess water drains back into the
quench pit and the residue is discharged from the end of the drag conveyor
into waiting trucks (20 cubic yard capacity each). Ash disposal costs are
$52.00 per ton. The plant reportedly discharges 200 to 300 gpm of wastewater
to the city sewer system.
4.1.2 Description of Hodel Plant
^•1-2.1 Combustor Design and Operation,. Table 4.1-2 presents baseline
data for the model plant. For purposes of model development, it was assumed
that the model comprises two combustors with operating capacities of 375 tpd
of MSW each. As shown in Table 4.0-1, actual unit capacities for combustors
in this subcategory range from 225 to 375 tpd.
The original design configuration of the Philadelphia NM incinerators
is typical of the existing facilities represented by this model plant. The
model consists of a rectangular refractory-lined furnace with two traveling
grate sections. Waste is delivered by crane to a water-cooled gravity feed
chute which cascades the feed onto an inclined grate. The feed rate is
controlled by the speed of the Inclined grate. The Inclined grate discharge
drops vertically approximately 4 1/2 feet onto a horizontal traveling grate
where burn out is completed. Bottom ash is discharged from the end of the
horizontal finishing grate into a water-filled quench pit. The combustor
4-20
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TABLE 4.1-2. MODEL PLANT BASELINE DATA
Combustor:
Capacity
Grate Area
Combustor
Configuration
Lower Chamber
Upper Chamber
Exit Breeching
Design Percent
Excess A1r
Total Excess Air
(Including inleakage)
Gas Conditioning:
Inlet PH Loading
2 Towers
Water Spray
Emission Controls:
Type
Gas Flow
Collecting Area
SCA
Inlet PM Loading
Stack Emissions:
CDD/CDF (tetra-octa)
CO
PM
HC1
so.
Sofid Waste
Stack Parameters:
Height
Diameter
Operating Data:
Remaining Plant Life
Annual Operating
Hours
Annual Operating
Cost
2 units at 375 tons per day each
480 square feet
Combustors each consist of two connected chambers
55 feet long by 8 feet wide by 21 feet high
21 feet long by 8 feet wide by 13 feet high
rectangular, 8 feet by 13 feet
200 percent
2SO percent
-3.0 gr/dscf at 7 percent 02
- Diameter 14 feet by height 42 feet (each)
- 147 gpm, first tower only
2-field ESP
224,000 acfm at 550°F
42,500 square feet
190 square feet per 1000 acfm
0.7 gr/dscf at 7 percent 0«
6,000 ng/dscm (1.5E-6 gr/dscf)
500 ppmv
0.08 gr/dscf
500 ppmv
200 ppmv
187.5 tons per day
100 feet
8 feet
15 years
6,500
8,457,000/year
aAll values are on a dry, 7 percent 02 basis. Normal and standard
conditions are 1 atmosphere and 70 FT
4-21
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arrangement is the same as shown in Figure 4.1-1. A plot plan of the model
plant is shown in Figure 4.1-2.
There are 4 individual air plenums supplying underfire air to the
inclined grate and 6 plenums beneath the horizontal grate. A single
forced-draft fan provides underfire and overfire air to each combustor.
Overfire air is supplied through 3 rows of nozzles in the combustor roof,
similar to the current arrangement at Philadelphia NW. Cooling air is also
supplied along the combustor side walls at a level just above the grate.
These design features are expected to be fairly typical of other plants in
this subcategory.
It is assumed that each of the model units operates at 200 percent
excess air. Based on limited measured data available from Philadelphia NU,
this may be considered a representative value for plants of this design. An
additional 50 percent excess air is assumed to be due to inleakage in the
model plant. As discussed in Section 4.1.1.1, this additional air 1s drawn
into the combustor through numerous openings in the furnace walls. This is
also considered typical of older refractory-wall combustors. At 250 percent
excess air the flue gas flow rate from the combustor is approximately
90,900 scfm (84,300 dscfm). This figure includes the contribution of the
flue gas products resulting from combustion of the waste feed.
As stated previously, the upper combustor chamber configuration of the
model plant is rectangular and contains no refractory arches or baffles such
as those currently in place at Philadelphia NW. There is no source of
auxiliary fuel in the model plant. These design assumptions are typical of
the majority of plants represented by this model.
4.1.2.2 Emission Control System Design and Operation. As shown in
Table 4.0-1, 4 of the 6 plants in this subcategory are equipped with ESP's.
The Philadelphia NW plant has recently rebuilt 2-field ESP with particulate
matter (PM) emissions of 0.02 gr/dscf adjusted to 12 percent COg. The
Philadelphia East Central (EC) plant, another member of the mass burn
refractory category, has an older 2-field ESP with the same SCA that has the
ability to meet the 0.08 gr/dscf PM emission limit. For the model plant, it
will be assumed that most existing plants are similar to Philadelphia EC
from a particulate control performance standpoint.
4-22
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Elevated
Stacks
ESP
Incinerator Building
Figure 4.1-2. Plot Plan of Model PUnt.
4-23
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Both of the Philadelphia plants (NW and EC) use water quench systems
for flue gas temperature reduction. Use of water sprays is typical for this
class of corobustors and Is assumed for the model plant. It Is assumed that
the.water sprays reduce the temperature of the flue gases to 550°F before
they enter the ESP.
4.1.2.3 Environmental Baseline. Table 4.1-2 presents the environmental
baseline emission rates for the model plant. Baseline uncontrolled COO/CDF
emissions are assumed to be 4,000 ng/dscm. These levels are due to design
and operating practices which are not representative of good combustion.
Research indicates that ESP's operating in the SOO to 600°F temperature
range promote formation of COD/CDF and can increase exit concentrations by
2
50 percent over combustor exit levels. Therefore, the model plant Is
assumed to have COD/CDF emissions of 6,000 ng/dscm corrected to 7 percent 02
at the stack exit.
An average uncontrolled PM emission rate in miss burn waterwall
2
combustors is 2.0 gr/dscf at 12 percent CO . Because excess air levels are
higher in refractory-wall combustors, a greater amount of particulate matter
is assumed to be carried out of the combustor. Therefore, an uncontrolled
PM emission rate of 3.0 gr/dscf at 7 percent 02 is assumed for baseline
conditions.
Emissions of CO correlate well with combustion efficiency and have been
used in the past as an indicator of COO/CDF emissions. For the model plant,
baseline CO emissions of 500 ppmv are assumed. Baseline uncontrolled HC1
and SO- emissions are selected to be 500 ppmv and 200 ppmv, respectively.
The model plant reduces incoming waste volumes by 75 percent, and
achieves 50 percent weight reduction. At a nominal 375 tons of HSU per day,
the bottom ash (dry) is estimated to be 187.5 tons/day. It is assumed that
the bottom ash and fly ash are mixed and co-disposed, as is the practice at
Philadelphia. Generally, fly ash accounts for about 5 percent of the total
ash.
4.1.3 Good Combustion and Exhaust Gas TemperatureControl
The following sections outline retrofits necessary to Insure good
combustion at the model plant described above.
4-24
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4.1.3.1 Description of Modifications
Design Modifications
Grate Replacement. Each unit is equipped with two traveling stokers
which move the waste feed through the combustor. Traveling grates in mass
burn systems do not provide agitation and subsequent aeration of the fuel
bed in the manner that rocking or reciprocating grates do. Traveling
grates, therefore, are less able to provide good fuel bed burnout,
particularly 1f specified grate loading rates are not carefully maintained.
Excessive bed loadings contribute to high concentrations of organic
emissions. Retrofits necessary to insure good combustion and minimum levels
of air emissions are:
1) replace the traveling grate system with reciprocating grate
sections that are equipped with individually controllable
underfire air supplies.
2) add a ram feeder to establish good feed control.
Grate replacement requires extensive demolition and some redesign of the
existing structural steel and refractory brickwork. The new design Includes
3 grate sections per furnace, each supplied by 2 separate underfire air
plenums. Each of the 6 plenums 1s equipped with an individual damper and
pressure monitor/recorder. New siftings and ash hoppers and a new ash
conveyor are also required as part of this modification. It is assumed that
a new ram feeder is included as part of grate replacement for each unit.
In addition to improving waste burnout and reducing solids disposal
requirements, this retrofit will result in better control of feed rates,
fuel bed distribution, supply of underfire air, and location of burning
patterns on the grate. These improvements will help to optimize destruction
of organic compounds in the combustor and will also reduce CO emission
levels.
Furnace Reconfiguration. The baseline configuration of the model plant
is not adequate to achieve good combustion. A conceptual redesign of the
model is provided in Figure 4.1-3. The reconfiguration includes a
refractory-lined structural steel arch which 1s located on the rear wall of
the furnace. In addition, the roof of the upper combustion chamber has been
raised in order to Increase the available volume for completing the mixing
4-25
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4-26
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process. This retrofit requires partial demolition of the existing furnace
walls and roof, and construction of a new furnace shell and refractory
brickwork.
Combustion Airflow Modifications
The following design and operational modifications must be made to the
model plant's combustion air system,
o Excess air operating levels will be reduced from 200 to
ISO percent excess air. This modification has a number of
beneficial effects on system performance. First, furnace
operating temperatures can be maintained at higher levels
(approximately 1800 F at the fully mixed location). Secondly,
lower excess air levels reduce the potential for partlculate
carryover by lowering vertical velocities in the upper furnace.
Lastly, reduced excess air levels increase the SCA of existing
electrostatic precipitators, resulting in improved partlculate
removal. At ISO percent excess air, total gas flow from the
combustor will be reduced to 61,700.scfn (57,900 dscfm) per unit. .
o Each of the three new grates has two Independently controllable
air plenums with individual supply dampers, ducting, and pressure
monitors. Approximately 125 percent theoretical air (50 percent
of total air) is supplied to the six underfire plenums. The
underflre air distribution 1s established as a result of
operational performance tests. The underfire air supply to the
drying grate also includes a natural gas burner which can be fired
as needed for air preheat when feeding wet refuse.
o New overflre air headers, nozzles, dampers, ducting, and pressure
monitors are installed to provide a source of air for mixing. Two
rows of Interlaced nozzles are required, as shown 1n Figure 4.1-3.
Flow modeling studies will be used to establish nozzle sizes,
orientation, spacing, etc. In-furnace CO profiling will be used
to provide verification of mixing patterns. The quantity of air
supplied through the overflre mixing nozzles is approximately
75 percent theoretical air, or 30 percent of total air.
o The existing overfire air nozzles, comprising three rows on the
furnace celling, are retained for use as cooling air.
Approximately 50 percent of theoretical air (20 percent of total
air) 1s supplied by these existing rows. New header pressure
monitors are required as part of the system retrofit.
o The last Improvement to the combustion air system is the
elimination of air inleakage as a result of the grate replacement
and furnace reconfiguration. This results in greater operational
stability, which contributes to lower air emissions.
4-27
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Auxiliary Fuel. The modified model plant has two auxiliary fuel
burners sized to provide 60 percent of unit full load (84.4 MM Btu) for use
during process start-up and during episodes of low temperature and high CO,
The first burner is located at the head of the primary combustion chamber
above the drying grate, and it is used to ignite the waste and maintain
primary combustion chamber temperature during start-up. A second gas burner
is located in the upper chamber just downstream of the mixing air nozzles.
Location of the burner in the upper chamber helps achieve the requirement of
1800°F at the fully mixed height during start-up, shutdown, and other
episodes of high CO or low temperature. The upper auxiliary fuel burner
also preheats and maintains the temperature of the flue gas cleaning
equipment prior to initiating waste feeding and during shutdown. This
minimizes corrosion problems, thus improving system environmental and
operational performance. The optimum location and orientation of the burners
in the modified model will be established by flow modeling.
Operation/Control Modifications
Minimize Residence Time at Critical Temperature. The goal of this
operational lodification is to minimize the effects of downstream COD/CDF
formation by minimizing the residence time of flue gases in the 500 to 600°F
range, where research indicates that COD/CDF formation is maximized. The
model plant normally operates the water quench system at a flow rate that
maintains a temperature of 550°F in the ESP. This operating practice must
be modified in order to lower the ESP temperature below the critical
temperature window. The modification requires an adjustment to the set
point on the ESP temperature controller to increase the quench water flow
rate and reduce the ESP temperature to 450°F. This temperature provides an
ample factor of safety in avoiding acid gas dew point problems.
Combustion Control. In the baseline configuration the combustion
control scheme is entirely manual. As part of the combustion modifications
improved controls are necessary. Because there is no steam production, the
primary variables to include in the control scheme are excess oxygen and
temperature. The revised controls include an oxygen trim loop which
automatically adjusts the amount and distribution of underfire air in
4-28
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response to a signal from an oxygen controller. A temperature controller is
Included with an alarm at high and low setpoints. Overfire air rates are
kept constant. Adjustments in overfire air and grate speed will be made
manually, 1f needed.
Verification. Verification of good combustion consists of insuring
that the system is operating according to its design. There are a number of
operating parameters that must be monitored and controlled 1n order to
achieve this objective. At a minimum, refractory-wall combustors must
continuously monitor:
1} underflre and overfire air flows (pressure settings)
2) combustor draft
3} 02 (excess air) and CO in the flue gas
4} combustor temperature.
Underfire and overfire airflows are monitored by maintaining specified
pressures 1n supply headers. Combustor draft is maintained by a variable-
speed ID fan. Flue gas 02 and CO measurements must be at the same location"
in the system so that the CO reading can be corrected to a standard value,
such as 7 percent 0*. Combustor temperature requirements are specified at a
location where the mixing process is completed, just downstream of the last
point of overfire air injection.
Retrofit Considerations. It is estimated that the combustor downtime
required to Implement all of the combustion retrofit options is
approximately 4 months per unit.
4,1.3.2 Environmental Performance. The combustion retrofits address
the design, operation/control, and verification requirements for good
combustion for mass burn refractory-wall combustors represented by this
model plant. Through the proper application of the above combustion
retrofit options, it is estimated that uncontrolled emissions of COD/CDF
will be reduced to 500 ng/dscm corrected to 7 percent Og. In addition,
emissions of CO are estimated to be reduced to 150 ppm on a 4-hour averaging
time. No change in uncontrolled participate emissions is expected.
Emissions of HC1 and S0g» because they are related to feed properties, are
also not expected to vary due to combustion modifications.
4-29
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4.1.3.3 Costs. This section provides estiiates of total capital and
annual operating and maintenance (O&M) costs for Identical combustion
retrofits to both combustion units. Capital costs represent the installed
equipment costs, including engineering and construction. Direct and
indirect capital costs are summarized in Table 4.1-3. Operating and
maintenance costs include all utilities, labor, and ash disposal costs.
These estimated costs are presented in Table 4.1-4.
The total estimated capital cost of the combustion retrofits is
$11,900,000. Downtime cost, resulting from lost revenue, is $846,000. The
annual 1 zed capital and downtime cost is $1,680,000 per year, based on a 10
percent interest rate and 15-year plant life. Total annualized cost is
$1,330,000, including a cost saving of $1,220,000 for reduced ash disposal
costs.
4.1.4 Good Particulate Control
The existing quench towers reduce baseline PM loadings from 3.0 gr/dscf
at the combustor outlet to 0.7 gr/dscf at the outlet of the quench towers.
The existing ESP's reduce PM loadings from 0.7 gr/dscf at the ESP inlet to
0.08 gr/dscf at the outlet. This level is equal to the 0.08 gr/dscf
required .by the existing MSPS for PM emissions from MWC's.
4.1.4.1 Description of Modifications. To reduce PM emissions to
0.05-gr/dscf, the existing ESP's have to be rebuilt. This rebuild will
include replacing worn or damaged internal components (plates, frame and
electrodes), upgrading of controls and electronics for more effective
energization, and flow modeling to evaluate gas.distribution. Even gas
distribution minimizes particulate reintrainment and equalizes particulate
collection across the width and height of the ESP. These modifications do
not include major changes such as additional collection area or plate-
electrode geometry changes.
Space 1s sufficient to allow ESP-rebuild work on one unit without
hindering operation of the adjacent unit. Approximately 2 months downtime
will be required for each unit.
4.1.4.2 Environmental Performance. Particulate matter emissions will
be reduced from baseline levels of 0.08 gr/dscf to 0.05 gr/dscf. This
additional fly ash recovery will add 60 tons/year to the plant solid waste
4-30
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TABLE 4.1-3.. PLANT CAPITAL COST FOR COMBUSTION MODIFICATIONS
(Two units of 375 tpd each)
Item Cost ($1000)
DIRECT COSTS:
Flow Modeling and Thermal Analysis 125
Overfire Air Ducting and Dampers 34
Gas Pipeline (1/2 mile) 50
Auxiliary Fuel Burners 203
Stokers Rehabilitation 2,800
Underfire and Overfire Airflow Monitors 33
Oxygen and CO Monitors with Readouts and Integrators 90
CO Profiling 10
A1r Preheat 4
Oxygen Trim Controls on FD Fan 25
Furnace Reconfiguration 4.080
Total 7,460
INDIRECT COSTS AND CONTINGENCIES: 4,470
TOTAL CAPITAL COSTS 11,900
DOWNTIME COST 846
ANNUALIZED CAPITAL COST AND DOWNTIME 1,680
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TABLE 4.1-4. PLANT ANNUAL COST FOR COMBUSTION MODIFICATIONS
(Two units of 375 tpd each)
Item Cost ($1000)
DIRECT COSTS:
Auxiliary Gas Consumption 316
Ash Disposal Costs (l,220)a
Water 7
Maintenance Labor 21
Maintenance Materials 21
Operating Labor 0_
Total ( 854}*
INDIRECT COSTS:
Overhead 25
Taxes, Insurance, Administrative 477
Capital Recovery and Downtime 1.680
Total 2,180
TOTAL ANNUALIZED COST 1,330
aDenotes cost savings.
4-32
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disposal requirements. This increase is roughly 0.1 percent of the existing
disposal quantity. . Emissions of COD/CDF and acid gases are assumed to not
be affected by this modification.
4.1.4.3 Sails.. Capital cost requirements for ESP rebuild for both
units are presented in Table 4.1-5. Total capital cost is estimated to be
$962,000. This figure includes purchased equipment, installation, and
indirect costs such as engineering and contingencies. Estimates assume a
moderate APCD congestion level, no additional general facilities, and no
purchased land. Downtime cost is $423,000 for lost revenue.
Annual costs are presented in Table 4.1-6. Direct O&M costs are
estimated at $2,000 per year. Annualized capital recovery and downtime
based on a 10 percent interest and 15-year life is $182,000 per year. Total
annualized costs are $184,000 per year.
4-1.5 Best Particulate Control
4.1.5.1 Description of Hodifications. To achieve PM emissions level
of 0.01 gr/dscf with an inlet grain loading of 0.7 gr/dscf will require a
well-operated ESP with 56,200 square feet of collection for each combustor.
To achieve this performance, each existing ESP will be rebuilt and a second
ESP with 13,700 square feet of plate area will be installed in series at the
outlet of each existing ESP. Rebuild of the existing ESP's will include
replacing worn components, upgrading controls, and flow modeling. As shown
in Figure 4.1-4, installation of each new ESP will require relocation of an
ID fan and 75 feet of new ducting to an existing stack. Most of the
construction of the new ESP's can be accomplished without disrupting
operation. Downtime for rebuild of the existing ESP's and tie-in of the new
units will be approximately 2 months for each unit.
4.1.5.2 Environmental Performance. Particulate matter emissions will
be reduced from 0.08 gr/dscf to 0.01 gr/dscf. The additional recovered
fly ash will add roughly 140 tons/yr to total solid waste disposal
requirements. This is a 0.2 percent increase in fly ash to disposal.
Emissions of CDD/CDF and acid gases are assumed to not be affected by this
modification.
4.1.5.3 Costs. Capital cost requirements for the new ESP, presented
in Table 4.1-5, are estimated to be $3,280,000. This includes purchased
equipment, installation, and indirect costs such as engineering and
4-33
-------
TABLE 4.1-5. CAPITAL COST OF PARTICULATE MATTER CONTROL UPGRADES
(Two units of 375 tpd each)
Costs ($1000)
Item
Good
Particulate Control
(ESP Rebuild Only)
Best Participate
Control
(ESP Rebuild
and Additional
Plate Area)
DIRECT COSTS:
PM Control '
Upgrade Costs
Access/Congestion Cost
New Flue Gas Ducting
Ducting Costs
Access/Congestion Cost
Other Equipment
Stacks
Demolition/Relocation
Total
Indirect Costs and Contingencies
Monitoring Equipment
TOTAL CAPITAL COST
DOWNTIME COST
ANNUALIZED CAPITAL RECOVERY
800a
NAa
NA
NA
NA
NA
800
162
0
962
423
182
2,190
346
95
24
0
0
2,650
631
0
3,280
423
487
NA - not applicable.
Turnkey.
4-34
-------
TABLE 4.1-6. PLANT ANNUAL COST FOR PARTICIPATE MATTER CONTROL UPGRADES
{Two units of 37S tpd)
Cost ($1000)
Best Participate
Control
Good (ESP Rebuild and
Participate Control and Additional
Item (ESP Rebuild Only) Plate Area)
DIRECT COSTS:
Operating Labor 0
Supervision 0
Maintenance Labor 0
Maintenance Materials 0
Electricity 0
Waste Disposal 2
Monitors 0
Total 2
INDIRECT COSTS:
Overhead 0 15
Taxes, Insurance, and
Administration 0 99
Capital Recovery and 182 487
Downtime
Total 182 601
TOTAL ANHUALIZED COST 184 642
4-3S
-------
Relocated
ID Fan
New ESP
Plate Area
Existing Incinerator
Building
Relocated
ID Fan
New ESP
Rate Area
Figure 4.1-4. Plot Plin of New ESP Plats Area Equipment Arrangement I
4-36
-------
contingencies. Estimates assume a moderate APCD congestion factors,
150 feet of additional duct, no additional general facilities, and no
purchased land.
Annual costs are presented in Table 4.1-6. Direct O&M costs are
estimated at $41,000 per year. Total annualized costs including capital
recovery are estimated at $642,000 per year.
4.1.6 Good Acid Gas Control
4.1.6.1 Description of Modifications. For good acid gas control and
good CDO/CDF control on on each combustor, dry sorbent will be injected into
the existing evaporation chamber (i.e., the second tower). The water quench
system on the existing spray chamber (i.e., the first tower) will remain in
place. An additional 25 gpm will be used to cool the flue gas to 3IO°F from
450 F, if good combustion practices are in place; 35 gpm will be required
under baseline combustion conditions to cool from 550°F. New equipment for
the site includes a single sorbent storage siio, a pneumatic sorbent
conveying system, two sorbent feed bins (one for each unit), and pneumatic
injection nozzles for each evaporation chamber. No other modifications to
the evaporation chamber will be required. Hydrated lime sorbent will be fed
at a calciym-to-acid gas molar ratio of 2:1. At full load, this requires a
sorbent injection rate of 425 Ib/hr for each combustor.
In addition, the existing ESP's will be rebuilt and new plate area
added to reduce PM emissions to 0.01 gr/dscf. The rebuild will include
replacing worn components, upgrading controls and flow modeling, but no
major geometry changes. An additional 49,000 square feet of ESP plate area
will be added to each ESP under baseline combustion conditions and
30,200 square feet under good combustion. The area will be installed using
a separate ESP located in series behind each existing ESP. The project also
includes monitoring equipment for HC1, SO-, C0«, and O-. Figure 4.1-5 shows
a plot plan of the equipment arrangement.
There are no access/congestion problems related to the evaporation
chamber modifications; the lime receiving, storage, ancf conveying equipment
installation; or the particulate control upgrade installation. Installation
of each new ESP will require relocation of an ID fan and 75 feet of new
4-37
-------
Relocated
ID Fan
New ESP
Plata Are*
New Socbent
Silo
New Sortsam
Food Bina
Relocated
10 Fan
New ESP
Rate Area
Exiating Incinerator
Buikflng
Figure 4.1-5. Plot Plan of Dry Sorbent Injection Retrofit
Equipment Arrangement.
4-38
-------
ducting to an existing stack, but can be accomplished with the -adjacent
combustor still operating. Advanced planning will be required to limit
combustor downtime to approximately 2 months for each unit.
4.1.6.2 Environmental Performance. Total COD/CDF emissions are
expected to be reduced by 7i percent from inlet levels or to 50 ng/dscm
(whichever is higher). Acid gas emission reductions are estimated at
80 percent for HC1 and 40 percent for SO*, respectively. As noted above, PM
emissions will be reduced to 0.01 gr/dscf. An additional 3,700 tons/year of
solid waste (sorbent and fly ash) will be added to the baseline waste
disposal requirements for the plant.
4.1.6.3 Costs. Capital cost requirements for dry sorbent injection
are presented in Table 4.1-7. Total capital cost for the plant is estimated
at $6,750,000 with baseline combustion and $5,770,000 with good combustion.
Most of the cost 1s associated with installation of "additional particulate
control equipment. The cost estimate assumes a moderate APCD access/
congestion level, few additional general facilities, and no purchased land.
Annual O&M and indirect costs are presented in Table 4.1-8. Major direct
operating costs are associated with lime purchase and monitoring equipment
maintenance. The total annualized cost for the control option (including
capital recovery and downtime) is $1,960,000 per year with baseline
combustion and $1,750,000 per year with good combustion.
4.1.7 Best Acid Gas Control
4.1.7.1 Description of Modifications. To achieve best acid gas and
COD/CDF control, a new spray dryer/fabric filter system will be installed on
each combustor after the spray tower. The existing evaporation towers will
be removed to make room for the spray dryer vessels. Lime slurry will be
introduced In each spray dryer at a 2.5:1 calcium-to-acid gas molar ratio.
Lime will be slurried in the additional water (43 gpm) needed to cool the
flue gas to 300°F from 550°F under baseline combustion, or In the 18 gpm
required under good combustion. The proposed equipment layout 1s
illustrated in Figure 4,1-6.
This sketch also shows the location of the lime receiving, storage, and
slurry area which will serve both spray dryers. A fabric filter with
59,800 square feet of cloth (net air-to-cloth ratio of 4:1) will be installed
4-39
-------
TABLE 4.1-7. CAPITAL COST OF DRY SORBENT INJECTION WITH REBUILD Of
EXISTING ESP AND ADDITION OF ESP PLATE AREA
(Two units of 375 tpd each)
Costs ($1000)
Baseline Combustion Good Combustion
Item Practices Practices
DIRECT COSTS:
Add Gas Control
Equipment
Access/Congestion Cost
Participate Control
Equipment
Access/Congestion Cost
New Flue Gas Ducting
Ducting Cost
Access/Congestion Cost
Other Equipment
Stacks
Demol i ti on/rel ocat 1 on
Indirect Costs & Contingencies
Monitoring Equipment3
TOTAL CAPITAL COST
DOWNTIME COST
ANNUAL I ZED CAPITAL RECOVERY
394
39
3,330
632
102
25
0
, fi
Total 4,520
1,720
514
6,750
423
944
394
39
2,750
489
90
23
0
a
3,790
1,470
514
5,770
423
815
aTurnkey.
4-40
-------
TABLE 4.1-8. PLANT ANNUAL COST FOR DRY SOR8ENT INJECTION WITH REBUILD
OF EXISTING ESP AND ADDITION OF ESP PLATE AREA
(Two units of 375 tpd each)
Cost rsiOOOl
Baseline Combustion Good Combustion
Item Practices Practices
DIRECT COSTS:
Operating Labor 39 39
Supervision 12 12
Maintenance Labor 11 11
Maintenance Materials 66 56
Electricity 6i 47
Mater 14 i
. Lime 221 221
Waste Disposal 92 92
Monitors 206 206
Total 726 689
INDIRECT COSTS:
Overhead • .76 71
Taxes, Insurance, and Administration 211 172
Capital Recovery and Downtime 944 815
Total 1,230 1,060
TOTAL ANNUALRED COST 1,960 1,750
4-41
-------
New ID Fan
and Duct
New Fabric
Filter
New 10 Fan
and Duct
New Fabric
Filter
New Sortoent
Silo
Spray Dryer
Chambers
Existing incinerator
Building
Figure 4.1-6. Plot Plan of Spray Dryer/Fabric Filter Retrofit
Equipment Arrangement,
4-42
-------
following each spray dryer under baseline combustion; with good combustion,
47,800 square feet will be needed. The existing ESP's and evaporation
chambers will be demolished to make room for the new fabric filters. The
increased pressure drop of fabric filters over ESP's will require a new ID
fan for each unit as well- An estimated 200 total feet of new duct will be
needed, but the existing stacks can be reused. New monitoring instruments
for HC1, SO-. C02» and opacity will be installed. Downtime is expected to
be 3 months.
4.1.7.2 Environmental Performance. Total COD/CDF emission reductions
of 99 percent or to 5 ng/dscm (whichever is higher) are expected. Emissions
of PH will be reduced from 0.08 gr/dscf to 0.01 gr/dscf. Acid gases will be
reduced 90 percent for SO- and 97 percent for HC1.
4.1.7.3 Costs. Capital cost requirements for installing spray
dryer/fabric filter systems are presented in Table 4.1-9. Total capital
cost is estimated to be $23,900,000 for installation with baseline
combustion or $21,400,000 for installation with good combustion. This
figure includes purchased equipment, installation, demolition, and indirect
costs such as engineering and contingencies. Estimates assume moderate
access and congestion (since much of the equipment will be elevated), few
additional general facilities, and no purchased land. Downtime cost for
3 months lost revenue is $634,000.
Annual O&M and indirect costs are presented in Table 4.1-10.
Significant Q&M expenses include replacement bags for the fabric filter and
electricity for the larger ID fan needed due to the increased pressure drop
across the fabric filters. Total annualized cost, including capital
recovery and downtime is $5,920,000 with baseline combustion and $5,310,000
with good combustion practices.
4.1.8 Summaryof Control Options
4.1.8.1 Descriptioo of Control Options. The control technologies
described in the previous sections have been combined into the seven
retrofit emission control options that were discussed in detail in
Section 3.0. Table 4.1-11 summarizes the combustion, particulate,
temperature, and acid gas control technologies described in Sections 4.1.3
through 4.1,7 that were combined for each of the control options.
4-43
-------
TABLE 4.1-9. CAPITAL COST OF SPRAY DRYER WITH FABRIC FILTER
(Two units of 37S tpd each)
Item
Cost ($1000)
Baseline Combustion
Practices
Good Combustion
Practices
DIRECT COSTS:
Acid Gas Control
Equipment
Access/Congestion Cost
New Flue Gas Ducting
Ducting Cost
Access/Congestion Cost
Other Equipment
Fans
Stacks
Demo! i t ion/Re! ocati on
Indirect Costs
Contingency
Monitoring Equipment3
TOTAL CAPITAL COSTS
DOWNTIME COST
ANNUAL I ZED CAPITAL RECOVERY
AND DOWNTIME
10,500
2,630
146
37
793
0
750
Total 14,900
4,670
3,760
573
23,900
63S
3,230
9,410
2,350
131
33
644
0
750
13,300
4,150
3,350
573
21,400 .
635
2,900
aTurnkey.
4-44
-------
TABLE 4.1-10. ANNUAL COST OF SPRAY DRYER WITH FABRIC FILTER
(Two units of 37S tpd each)
Cost ($1000)
Baseline Combustion Good Combustion
Item Practices Practices
DIRECT COSTS:
Operating Labor
Supervision
Maintenance and Labor
Maintenance Materials
Electricity
Compressed Air
Water
Lime
Waste Disposal
Monitors
Total
INDIRECT COSTS:
Overhead
Taxes, Insurance, and Administration
Capital Recovery and Downtime
Total
TOTAL ANNUALIZED COST
78
12
43
399a
415
59
17
183
121
215
1,540
249
903
3,230
4,380
5,920
78
12
43
344b
329
47 .
12
182
120
215
1,380
230
803
2.900
3,930
5,310
Includes $116,000 per year for bag replacement,
Includes $93,000 per year for bag replacement.
4-45
-------
TABLE 4.1-11. SUWURV OF CONTROL OPTIONS FOR TRAVELING CRATE MASS BUM REFRACTOBV-WAU, COKBUSTOR
Control Option Description
Fjrtleul»t« H»tt«f Control
Combustion Temperature Ex I it. Ing ESP Additional
Modifications Control Rebuilt Plat* Area
Cat Control
Haw Sorbtnt Spray
Fabric Filter Injection Dryer
1. Good Combustion and
Temperature Control
2. Good FH Control with
Combustion anil feaparatura
Control
•*»
Ok
3, B«*t PM Control and
Combustion and T*nf>*ratur*
Control
A. Good Acid Ga* Control,
Beit FH Control and
Temperatut*
S. Cood Acid Gas Control and
Best PH/Coosbustlon/
femperatura Control
Control
6. Beit Acid Gai Control,
Bast PM Control and
Te*op«ratura Control
7. Best Acid Gaa Control,
and Beit PH/CombuitIon/
Temperature Control
-------
4.1,8.2 Environmental Performance. The performance of each control
option 1s summarized in Table 4.1-12. For each pollutant the table presents
both the pollutant concentrations and annual emissions. The most effective
retrofit option for controlling COO/CDF emissions is addition of spray
dryer/fabric filter systems which reduce emissions by 99 percent from inlet
levels. Good combustion practices are nearly as effective in controlling
CDD/COF, and produce emission reductions of 90 percent. Sorbent addition
technology (including dry sorbent injection) also reduces acid gas
emissions, but good combustion practices reduce CO. The best overall
control results from combining combustion control and sorbent addition as in
Options i and 7.
4.1.8.3 Costs. The total annualized cost of each option is presented
in Table 4.1-13. Total annualized cost of each option increases with
increasing control, though good combustion costs are partially offset by
lower solid waste disposal costs resulting from more complete waste burnout."
The most cost-effective option is Option 4, which provides most of the
potential emission control (except CO reduction) at a cost of $1,960,000 per
year (annualized total cost).
4.1.8.4 Energy Impacts. Table 4.1-14 presents a summary of the energy
impacts associated with the control options. The values presented are
incremental energy use relative to baseline operation, and take into account
the savings realized by not operating the existing ESP's under Options 6 and
7. Note that there is a considerable electrical penalty for the higher
(baseline) gas flow rates in Options 4 and 6.
4-47
-------
TABU 4.1-12. ENVIRONMENTAL PERFORMANCE OF SUMNASY FOR MASS BURN TRAVELING
CRATE REFRACTOBY-WALL MODEL PLANT RETROFIT CONTROL OPTIONS
(Two units of 375 tpd each)
••••line
Dioxin Emissions
(ng/dscM)
Ki/yr0
X Reduction vs. Baseline
CO Emissions
€pp»v)
Mi/yr
X Reduction vs. Baseline
PN Emissions
(gr/dscf)
*B/yr
X Reduction vs. Baseline
SO. emissions
(PpOWJ
*i/yr
X Reduction vs. Baseline
HCt Emissions
Ippttv)
K8/yr
X Reduction vs. Baseline
Total Solid Vaste
C tons/day)
m/yr .
X Reduction vs. Baseline
4,000
4.7E-3
•r *
500
494
"-
0.08
146
»-
200
452
..
500
643
--
396
92,300
0 •
Option !
500
2.0E-4
92
150
148
?0
0.05
91
38
200
452
0
500
643
0
188
46,300
(50)
Option 2
500
3.91-4
92
ISO
148
70
0.05
91
38
200
452
0
,500
643
0
188
46,300
ISO)
Option 3
500
3.9E-4
92
150
148
70
0.01
18
88
200
4S2
0
500
643
0
184
46,500
(49)
Option 4
1000
3.3f-4
83
500
494
0
0.01
18
88
120
272
40
100
128
80
389
95.800
4
Option 5
125
9.9E-5
98
150
148
70
0.01
18
88
120
272
40
too
128
80
201
49,500
(46)
Option 6
40
3.31-5
99.3
500
494
0
0.01
IB
88
19
42
90.5
15
IB
97
393
96,700
5
Option 7
f
3.9E-6
99.9
150
146
70
0.01
18
88
19
42
90.5
IS
18
97
205
50,500
(45)
All flue gas concentrations are reported on a dry 7 percent 0? baiii. Noraal and standard conditions are
1 atMsphere and 70 f.
Decrease vs. baseline shown in parentheses.
-------
TABLE 4.1-13. COST SUMMARY FOR MASS BURH TRAVELING GRATE REFRACTORY-WALL
COMBUSTOR RETROFIT CONTROL OPTIONS* (Two units of 375 tpd each)
1
•t*
to
Total Capital Cost
Downtime Cost
Annuitized Capital
and Downtime Cost
Direct 04 M Cost
Total Annual Cost
Cost Effectiveness
(S/ton HSU)
Facility DoMntine
(Months)
Total Compliance Tine
(Months)
Option 1
1 1 ,900
846
1,680
(854)b
1.330
6.55
4
11
Option 2
12,900
846
1,610
(852>b
1,460
7.19
4
13
Option 3
15,200
846
2,110
(B13)b
1,920
9.45
4
19
Option 4
6,750
423
944
726
1,960
9.65
2
19
Option S
17,700
846
2,440
CU5>b
3,020
14.90
4
19
Option 6
23,900
635
3,230
1,540
5,920
29.10
3
25
Option 7
33,300
846
4,490
526
6,560
32.30
4
25
BAll costs [except cost effectiveness) given in 11000. All costs in December 1987 dollars.
Denotes cost savings.
-------
TABLE 4.1-14 TOTAL PLANT ENERGY IMPACTS FOR CONTROL OPTIONS3
Option
1
2
3
4
5
6
7
Electrical Use
(HWh/yr)
0
0
230
1.3SQ
1,000
9,030b
7,150b
Gas Use
(Btu/yr)
2.0E10
2.0E10
2.0E10
0
2.0E10
0
2.0E10
aIncremental use from baseline.
Excludes electrical credit for not operating the ESP's.
4-50
-------
4.2 ROCKING/RECIPROCATING GRATE MASS BURN REFRACTORY-WALL COMBUSTOR
This section presents the case study results for i refractory-wall
combustor equipped with rocking/reciprocating grates, 'As shown in
Table 4,0-1, there are 11 known plants in this subcategory. Section 4,2.1
presents a description of the Sheboygan MWC plant, which was visited in order
to gather information for model development. Section 4.2.2 presents a
description of the model plant. Sections 4.2.3 through 4,2.7 detail the
retrofit modifications, estimated performance, and costs associated with
various control options. Section 4.2,8 presents a summary of the control
options, which are discussed in more detail in Section 3.0 of this report.
4.2.1 Description of the Shebovqan. Wisconsin Combustor
The Sheboygan MWC plant, which began operation in 1964, consists of two
rectangular refractory-wall combustors with individual firing capacities of
120 tpd of MSW. The stokers were manufactured by Flynn and Emrich, and
utilize three rocking grate sections per combustor. Table 4.2-1 summarizes
key design and operating data for the plant. The plant operates 4 to
5 days/week with scheduled maintenance every Monday. Reported operating
capacities are 4 to 5 tons/hr per combustor. The plant employs 15 people and
operates 24-hr/day. In addition to burning MSW the plant also burns skimmings
from the sewage treatment plant. A total of 417 tons of sludge were burned in
1986.
4.2.1.1 Combustor Design and Operation. Figure 4.2-1 illustrates the
cross-section of the combustors at the Sheboygan plant. Waste is charged from
a holding pit into a water-cooled hopper which feeds each combustor by
gravity. The feed rate is controlled by varying the speed of the first
(drying) grate section, which is 8 feet in length and 7 feet wide. The
majority of the burning takes place on the second grate section, and burnout
is completed on the third (finishing) grate. There are 1-foot vertical steps
between each of the three grates, allowing the waste to tumble from one
section to another. The second and third grate sections are 10 feet in
length. Bottom ash is discharged from the finishing grate to a wet quench. A
drag chain conveyor transports the ash to a truck for disposal in a nearby
landfill.
4-51
-------
TABLE 4.2-1, SHEBOYGAN DESIGN DATA*
Combustor:
Capacity
Total Grate Area
First Grate
Second Grate
Third Grate
Overall Combustor
Dimensions
Exit Breeching
Emission Controls:
Baffle Chambers
Spray Nozzles
- 120 tpd
- 202 square feet
-7 feet wide by 8 feet long, IS incline
- 7 feet wide by 10 feet long, 15° incline
- 7 feet wide by 10 feet long, 15 incline
- 28 feet long by 7 feet wide by 18 feet high
- Rectangular, 7 feet by 7 feet
37 feet long by 7 feet wide by 18 feet high
21 full-cone nozzles in first spray section,
21 flat-spray nozzles in second spray section,
Data are for each combustor. There are two combustors at Sheboygan,
4-52
-------
4-53
-------
Underfire air is supplied by forced-draft fans (one per combustor) and
delivered through ductwork to the burning and finishing grate sections.
Si ft Ings hoppers are located beneath the drying grate, but no imderfire air is
provided to this grate. Separate forced-draft fans (one per combustor)
located adjacent to the underfire air fans supply overfire air which is
injected at six points on each of the combustor side walls (12 ports per
combustor). The overfire air ports are 4 inches square and are located in
pairs at elevations approximately 6 to 8 feet above the grates. There are no
pressure or flow indicators for either the underfire or overfire air systems.
All adjustments in air flow are made manually based on visual observation of
the burning fuel bed and flame patterns. Grate speeds are also varied
manually by controls on the side of the combustor. The speed of each grate
section can be independently set and varied.
As shown in Figure 4.2-1, the original design of the combustor included a^
refractory arch extending from the top of the combustion chamber, pinching the
gas flow from the combustor prior to its exit. The arch was removed and the
furnace configuration is now rectangular.
There are no auxiliary fuel burners in either combustor, although natural
gas is used to heat the plant offices and adjacent buildings. The combustor
is started up by establishing a bed of waste on the first grate section and
igniting the waste by hand. Plant operators reported that during start-up it
takes approximately 1 to 2 hours to achieve a temperature of 1400°F in the
combustion chamber. When this temperature is achieved the overfire air is
introduced and the furnace temperature is established at 1700 to 1800°F. The
flue gas temperature must be maintained for nearly 20 to 24 hours to bring the
refractory temperatures up to the same level. The temperature is measured by
a probe in the roof of the combustion chamber located just before the first
baffle in the APCD.
4.2.1.2 Emission,Control System Design and Operation. Combustion
products leaving the active burning region flow through a three-pass wet
baffled system which both cools the hot flue gases and reduces particulate
matter (PH) emissions. After passing through the wet baffle system, flue
gases from both combustion trains are combined in a short run of ducting to
the stack.
4-54
-------
The original spray nozzles were recently replaced with new stainless
steel FOGJET nozzles. The first spray section has 21 full-cone spray nozzles
(FOGJET 76 type) and the second spray section has 21 flat-spray nozzles
(FOGJET FF type). No changes were made to the nozzle water feed system, which
operates at 65 pounds of pressure. During a recent test the PM emissions from
the stack varied from 0.226 to 0.326 gr/dscf corrected to 7 percent CL.
Water and PM collected in the baffle system flow to a concrete lagoon
where the ash settles out from the water. Every 3 to 4 months this ash is
dredged out and disposed of at a nearby landfill. Approximately 100 tons of
lagoon ash are disposed of at each cleaning. The landfill will be shut down
at the end of 1988. Overflow water from the lagoon is discharged to the storm
sewer which flows to a nearby river. The plant has a discharge permit which
requires weekly and quarterly monitoring for BOO, pH, and metals.
4.2.2 description of Model Plant
4.2.2.1 Combustor Design and Operation. Table 4.2-2 presents model
plant baseline data. Based on available information gathered for the other
plants in this subcategory, the current design configuration of the Sheboygan
MWC is considered representative of the existing population of reciprocating/
rocking grate refractory-wall combustors. Although rocking and reciprocating
grates vary in design and operation, they are assumed to be equivalent in
terms of bed agitation and aeration.
The model plant consists of two rectangular 120-tpd combustors, each with
three rocking grate sections. The model operates 24-hr/day, 5-days/week.
Fuel feeding is accomplished by gravity and is controlled by manually
adjusting the speed of the first (drying) grate section. Underfire air is
supplied to the burning and finishing grate sections through individual
plenums. Overfire air is supplied through ports in the combustor sidewalls.
This arrangement is identical to that described for the Sheboygan plant. All
air flows and grate speeds are manually controlled. Separate forced-draft
fans supply underfire and overfire air. Continuous monitoring of combustion
gases is not conducted.
The model plant burns only MSW and is not equipped with an auxiliary fuel
source. At the design feed rate (120 tpd) the theoretical combustion air is
approximately 7,150 scfm. Limited emissions testing data available for the
4-55
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TABLE 4.2-2. MODEL PLANT BASELINE DATA FOR ROCKING/RECIPROCATING GRATE
MASS BURN REFRACTORY-WALL COMBUSTOR
Combustor:
Capacity
Grate Area
Overall Combustor
Dimensions
Exit Breeching
Emission Controls;
Type
Gas Flow
Inlet PM Concentration
120 tpd per unit (2 units)
202 square feet per unit, IS degrees slope
28 feet long by 7 feet wide by 15 feet high
Rectangular, 7 feet by 7 feet
wet baffle chamber
29,400 dscfm, 120,300 acfm at 400°F total
3.0 gr/dscf at 7% 0
Emissions:
CDD/CDF (tetra-octa)
CO
PM
HC1
SO,
Sofid Waste
Stack Parameters:
Height
Diameter
Operating Data:
Remaining Plant Life
Annual Operating Hours
Annual Operating Cost
4000 ng/dscm
50 ppmv
0.33 gr/dscf
500 ppmv
200 ppmv
3i tons per day
150 feet
9 feet
15 years
6,500
$3,560,OQQ/year
values are on a dry, 7 percent 09 basis.
4-56
-------
Sheboygan plant indicate that the excess air level in the stack approaches
300 percent. Therefore, the excess air level assumed for the model was
300 percent. Air inleakage is assumed to be negligible based on the
well-sealed appearance of the Sheboygan plant. At an excess air level of
300 percent, the flue gas flow rate is approximately 30,600 scfm
(29,400 dscfm), including all flue gas products. At 300 percent excess air
the flue gas temperature at the combustor exit is approximately 1400°F.
One design feature of the Sheboygan plant which is considered to be
atypical of the population is that Sheboygan does not have an induced-draft
fan. It is assumed that the model includes a variable speed induced-draft fan
upstream of the stack, The fan automatically adjusts flow rate to maintain a
set negative pressure in the combustion chamber.
4.2.2.2 Emission Control System Desiqn_and Operation. As shown in
Table 4.0-1, seven of the 23'refractory-wall MWC's currently use some type of
wet PM control device. The existence of these plants justifies the need for
examining retrofit modifications on a plant equipped with such an APCD system.
Therefore, while the majority of existing refractory-wall MWC's have ESP's,
the model plant for this subcategory is equipped with an APCD system similar
to that in place at Sheboygan. The other refractory-wall model plants (see
Sections 4.1 and 4.3) are equipped with ESP's.
The model plant for this subcategory uses a wet baffle system for control
of PM and temperature. This system is assumed to reduce PM emissions from
3.0 gr/dscf to 0.33 gr/dscf (at baseline). The flue gas temperature is
assumed to be reduced from 1400°F to 450°F. No additional PM or acid gas
controls are in place at the model plant.
Figure 4.2-2 shows a plot plan of the model plant. Although based on the
Sheboygan plant, is is assumed for the purposes of model development that
there are moderate access/congestion constraints for the model plant at the
APCD end of the system. Although the details of access/congestion constraints
are not known for all of the plants in this subcategory» assuming moderate
constraints should provide a model plant representative of the majority of
plants in the population.
4.2.2.3 Environmental Baseline. Table 4.2-2 presents the environmental
baseline for the model plant. There are no available data to directly support
a CDD/CDF emissions estimate. However, due to the lack of a distinct point of
4-57
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Stack
Tipping
Area
01
oa
Control
Room
Combustor
Area
Parking
Area
Figure 4.2-2. Plot Plan of Model Plant
o
t--
O
-------
high pressure overflre air injection downstream of the finishing grates,
mixing of flue gases is assumed to be incomplete. Therefore, relatively high
levels of organic emissions are assumed to be present in the flue gases. In
addition, the high excess air rates restrict the maximum temperatures that can
be achieved in the furnace, so that complete destruction of CDO/COF and
precursors does not occur. As a result, it is assumed the baseline
2
uncontrolled CDD/CDF emission levels are 4,000 ng/dscm.
As a result of less than optimal combustion gas mixing conditions, and
low gas temperatures at 300 percent excess air, it is assumed that the
oxidation of CO is also incomplete. Uncontrolled CO emissions are estimated
to be 500 ppmv at 7 percent Og. In addition, high excess air levels con-
tribute to increased particulate carryover from the combustion chamber. As a
result, baseline PM levels at the combustor exit are estimated to be
2
3,0 gr/dscf at 7 percent 0.. Emissions of HC1 and S02 are based on waste
feed properties and are not expected to vary appreciably with combustion
conditions. Therefore, average uncontrolled values for HC1 and SOg are
estimated to be 500 ppmv and 200 ppmv, respectively, corrected to 7 percent
Q«. All baseline emission levels are assumed to be measured at the combustor
exit.
The model plant is estimated to achieve a waste volume reduction of
90 percent and a weight reduction of 70 percent. Therefore, the baseline
solid waste disposal requirement for each combustor is to be for 36 tpd (dry)
ash.
4.2.3 Good Combustion
The following sections describe the modifications required to establish
good combustion for the model plant.
4.2.3.1 Descriot i on of Hodif ications.
Fuel Feeding. In the baseline design, the model plant uses gravity feed.
As part of the combustion modifications ram feeders will be added to both
units. The grates are 8 feet wide, so a single ram is sufficient for each
unit. This modification will ensure good waste distribution to the drying
grate and more stable combustion conditions. In addition, the ram feeders
provide a furnace seal that was previously maintained by waste in the hoppers.
Furnace Reconfiguration. The baseline configuration of the model
combustion is not adequate to achieve good combustion. A conceptual redesign
of the combustor is illustrated in Figure 4.2-3. The new design includes a
4-59
-------
o
+•>
O)
ec
o
01
o
a.
o
+•»
(/>
o
-------
refractory-lined structural steel arch which is located on the rear wall of
the furnace. In addition, the roof of the furnace has been raised to form an
upper combustion chamber where mixing of combustion gases is completed. The
retrofit requires partial demolition of the existing walls and roof, and
construction of a new furnace shell and refractory brickwork.
Combustion Airflow Modifications. The following modifications are
included in the redesign of the model plant's combustion air system,
• Excess air operating levels are reduced from 300 to 150 percent.
This allows furnace operating temperatures to be maintained at
1800 F at the fully mixed location. It also reduces the potential
for particulate entrainment. At 150 percent excess air, the total
gas flow from the combustor is reduced to 19,800 scfm
{18,500 dscfm).
• An underfire air plenum with supply ducting, dampers, and pressure
monitors is provided for the drying grate section. This underfire
air supply has a natural gas burner which can be fired as needed for
air preheat when feeding wet refuse. Total undergrate air flows are
approximately 125 percent of theoretical air preheat^when feeding
wet refuse. Total undergrate air flows are approximately
125 percent of theoretical air, or 50 percent of total air.
• New overfire air headers, dampers, ducting, and pressure monitors
are installed to provide a source of air for.mixing. Two rows of
interlaced nozzles are required, as shown in Figure 4.2-3. Flow
modeling studies are used to establish nozzle sizes, orientation,
spacing, etc. In-furnace CO profiling provides verification of
mixing patterns. Approximately 75 percent of theoretical air, or
30 percent of total air, is supplied through these nozzles during
normal operating conditions.
• The existing sidewall air nozzles are retained for use as cooling
air. New header pressure monitors are required as part of the
system upgrade. Approximately 50 percent of theoretical air
(20 percent of total air) is supplied by these existing nozzles.
Auxiliary Fuel. The modified model plant has two auxiliary fuel burners,
sized to provide 60 percent of unit full load (27 MM 8tu/hr} for use during
process start-up and during episodes of low temperature and high CO. The
first burner is located at the head of the primary combustion chamber above
the drying grate, and it is used to ignite the waste and maintain required
combustion chamber temperatures. A second burner is located in the upper
chamber just downstream of the mixing air supplies. Location of the burner in
the upper chamber helps achieve the requirement of 1800 F at the fully mixed
4-61
-------
height during start-up, shutdown, etc. The upper auxiliary fuel burner also
preheats and maintains the temperature of flue gas cleaning equipment prior to
initiating waste feeding and during shutdown. This minimizes corrosion
problems and improves the system's environmental and operational performance.
Combustion Control. In the baseline configuration, the combustion
control scheme is entirely manual. As part of the combustion modifications
improved controls are necessary. Because there is no steam production, the
primary variables to include in the control scheme are excess oxygen and
temperature. The revised controls include an oxygen trim loop which
automatically adjusts the amount and distribution of underfire air in response
to a signal from an oxygen controller. A temperature controller is included
with an alarm at high'and low setpoints. Overfire air rates are kept
constant. Adjustments in overfire air and grate speed will be made manually,
if needed.
Verification. Verification of good combustion consists of insuring that-
the system is operating according to its design. There are a number of
operating parameters that must be monitored and controlled in order to achieve
this objective. At a minimum, refractory-wall combustors must continuously
monitor:
1. underfire and overfire air flows (pressure settings),
2. combustor draft,
3. 0- (excess air) and CO in the flue gas, and
4. combustor temperature.
Underfire and overfire air flows are monitored by maintaining specified
pressures 1n supply headers. Combustor draft 1s maintained by a variable-
speed ID fan. Flue gas 02 and CO are measured at the same location in the
system so that the CO reading can be corrected to a standard value, such as
7 percent 02. Combustor temperature requirements are specified at a.location
where the mixing process is completed, just downstream of'the last point of
overfire air injection.
Retrofit Considerations. It is estimated that the combustor downtime
required to Implement all of the combustion retrofit options is approximately
two months per unit.
4-62
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4.2.3.2 Environmental Performance. The combustion retrofits address
the design, operation/control, and verification requirements for good
combustion for mass burn refractory-wall combustors represented by this model
plant. Through the proper application of the above combustion retrofit
options, it is estimated that uncontrolled emissions of CDD/COF will be
2
reduced to 500 ng/dscm corrected to 7 percent 02< In addition, emissions of
CO are estimated to be reduced to 150 ppmv on a 4-hour averaging time. No
change in uncontrolled particulate emissions is expected. Emissions of HC1
and SOg, because they are related to feed properties, are also not expected
to vary due to combustion modifications.
4.2.3.3 Costs. Capital costs for combustion retrofits are presented in
Table 4.2-3. The total estimated capital cost of the combustion modifications
is $3,860,000. Annual costs are presented in Table 4.2-4. The annualized
capital cost is $532,000 per year, based on a 10 percent interest rate and
fifteen year plant life. Total annualized costs are $847,000.
4.2.4 Good PM Control
4.2.4.1 Description of Modification. The existing baffle quench system
is capable of reducing PM loadings at the combustor outlet from 3.0 gr/dscf to
0,33 gr/dscf. This section describes modifications required for adding an ESP
to achieve good (0.05 gr/dscf} PM control to the ESP. No temperature control
equipment is needed because the flue gas temperature is 450°F.
Achievement of good PM control (0.05 gr/dscf} will require the addition
of a new ESP with 16,000 square feet of plate area. This ESP is sized to
handle the combined flue gas from both combustors. It is assumed that there
is sufficient space near the existing stack to locate the ESP, and that
access/congestion constraints are moderate. Approximately 240 feet of flue
gas ducting would be required to tie the ESP into the existing ductwork as it
leaves the building and return the flue gas to the existing stack. An opacity
monitor will be installed at the outlet of the ESP. Figure 4.2-5 shows the
location of the ESP and ductwork.
Because of the additional pressure drop caused by the ESP and ducting, a
new induced-draft fan will also be required. Approximately 1 month of
downtime will be required to tie the new ductwork into the existing ducting to
the stack.
4-63
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TABLE 4.2-3 PLANT CAPITAL COST FOR COMBUSTION MODIFICATIONS
(Two units of 120 tpd each)
Item Cost ($1000)
DIRECT COSTS:
Flow Modeling and Thermal Analysis 125
New Overfire Air Ducting and Dampers 18
Furnice Reconfiguration 1,900
Gas Burntr for Air Preheat 4
Two Auxiliary Burners Per Unit 104
Ram Feeders 242
Underfire Air Plenum 28
Underfire and Overfire Airflow Monitors 21
Oxygen and CO Monitors 90
CO Profiling 10
Oxygen Trim Controls on FD Fan 2jj
Total 2,670
INDIRECT COSTS AND CONTINGENCY 1,290
TOTAL CAPITAL COSTS 3,860
DOWNTIME COSTS 190
ANNUALIZED CAPITAL COSTS AND DOWNTIME 532
4-64
-------
TABLE 4.2-4 PLANT ANNUAL COST FOR COMBUSTION MODIFICATIONS
(Two units of 120 tpd each)
Item Costs ($1000)
DIRECT COSTS:
Auxiliary Gas Consumption 97
Maintenance Labor 20
Maintenance Materials 20
Total 137
INDIRECT COSTS:
Overhead 24
Taxes, Insurance, and Administration 154
Capital Recovery and Downtime 532
Total 710
TOTAL ANNUALIZED COSTS 847
4-65
-------
Stack
New Ductwork
X
Tipping
Area
crt
Control
Boom
Combustof
Area
Induced
Draft
Fan
Additional
ESP Volume
for "Best"
Control
Parking
Area
New ESP
for "Good"
Control
Figure 4.2-4, Plot Plan of Particulate Control Equipment
(C
m
-------
4.2.4.2 Ertvironment al Performaneg. Particulate matter emissions will be
reduced from baseline levels of 0.33 gr/dscf to O.OS gr/dscf. This additional
fly ash recovery will, add 178 tons/year (dry) to the plant solid waste
disposal requirements. CDD/CDF and acid gas emissions are not affected by
this modification and are expected to be equal to the concentrations at the
combustor exit.
4*2,4,3 Costs, Total capital cost requirements for the new ESP
achieving the good particulate control level are presenter in Table 4,2-5.
Total capital cost is estimated to be $1,800,000. This figure includes
purchased equipment, installation, and indirect costs such as engineering and
contingencies. Estimates assume a moderate APCD congestion level.
Annual costs are presented in Table 4.2-6 for good particulate control.
The costs are dominated by annualized capital recovery and downtime. Indirect
annual costs including capital recovery and downtime are estimated at $338,000
per year. Direct operating and .naintenance costs are estimated at $55,000 per.
year. Thus, total annualized cost for good PM control is estimated at
$393,000 per year.
4.2.5 Best Particulate Control
4.2.5.1 De sc r i p t ion o f Hod i JM^ati ons. To achieve best PM control
(0.01 gr/dscf) will require the addition of an ESP with approximately
29,600 square feet of collection area. No temperature control equipment is
needed since the inlet ESP temperature is 450°F. The ESP and new ductwork
would be located as shown in Figure 4.2-5, A new induced-draft fan will also
be required. Approximately 230 feet of new ducting will be required to divert
the flue gases from the building to the ESP and back to the stack. An opacity
monitor will be installed at the outlet of the ESP. Approximately one month
of downtime is needed to accomplish the ductwork tie-ins,
4.2.5.2 Environmental Performance. Particulate matter emissions will be
reduced from 0.33 gr/dscf to 0.01 gr/dscf. The additional recovered fly ash
will add 204 tons/yr to the plant total solid waste disposal requirements.
CDD/CDF and add gas emissions are not affected by this modification and are
expected to be equal to the concentrations at the combustor exit.
4-67
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TABLE 4.2-5 PLANT CAPITAL COST FOR NEW PARTICULATE CONTROL
• (Two units of 120 tpd each)
Item
DIRECT COSTS:
Participate Control
Equipment
Access/Congestion Cost
New Flue Gas Ducting
Ducting Cost
Access/Congestion Cost
Other Equipment
Fan
Stacks
Demo! i t i on/re 1 ocati on
Total
Indirect Costs and Contingencies
Monitoring Equipment1
TOTAL CAPITAL COSTS
DOWNTIME COSTS
ANNUAL I ZED CAPITAL RECOVERY AND DOWNTIME
Costs
Good PH Control
758
190
122
30
195
0
1,300
442
60
1,800
95
249
($10005
Best PM Control
968
242
117
29
195
0
0
1,606
529
60
2,140
95
294
aTurnkey.
4-68
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TABLE 4.2-6 PLANT ANNUAL COST FOR NEW PARTICIPATE CONTROL
{Two units of 120 tpd each)
costs rsiooo)
Item Good PM Control Best PM Control
DIRECT COSTS:
Operating Labor 10 10
Supervision 1 1
Maintenance Labor S 5
Maintenance Materials 17 21
Electricity 10 16
Waste Disposal 4 . 5
Monitors _S JJ
Total 55 67
INDIRECT COSTS:
Overhead 20 22
Taxes, Insurance, and Administration 69 83
Capital Recovery and Downtime 249 294
Total 338 399
TOTAL ANNUALIZED COSTS 393 466
4-69
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4.2.5.3 Costs. Total capital cost requirements for the best participate
control are presented, in Table 4.2-i. Total capital cost is estimated to be
$2,140,000. This includes purchased equipment, installation, and indirect
costs such as engineering and contingencies. Estimates assume a moderate APCD
congestion level.
Annual costs are presented in Table 4.2-6 for best particulate control.
Direct operating and maintenance costs are estimated at $67,000 per year.
Indirect annual costs are $399,000 per year. Total annualized cost for good
PM control is estimated at $466,000 per year.
4.2.6 Good Acid Gas Control
4.2.6.1 Description of Modifications. For good acid gas control, dry
sorbent will be injected into new ductwork going to a new fabric filter. The
existing water quench system will remain in place. New equipment for the site
includes a single sorbent storage silo with baghouse, a pneumatic sorbent
conveying system, one sorbent feed bin and pneumatic injection nozzles.
Hydrated lime sorbent will be fed at a calcium-to-acid gas molar ratio of 2:1.
At full-load, this requires a sorbent injection rate of 281 Ib/hr for both
combustors operating either under baseline or good combustion practices.
Reductions in HC1 and SO. are estimated at 80 and 40 percent, respectively.
The flue gas flow rates at the quench system outlet are 130,500 acfm at
300°F for both combustors operating with baseline combustion, and 91,700 acfm
at 300§F for both combustors operating with good combustion. This temperature
reduction is achieved by an additional water quench of 19 and 12. gpm in the
existing wet baffle system for baseline and good combustion, respectively.
The new fabric filter will require 240 feet of new ductwork and a new
induced-draft fan to overcome the pressure drop. Approximately 43,500 and
30,600 square feet of fabric filter cloth will be required (based on a gross
air-to-cloth ratio of 3:1) for baseline and good combustion, respectively,
The project also Includes monitoring equipment for HC1, SO-, 0-( and opacity.
These monitors will be located in the ducting prior to sorbent injection and
also at the outlet of the fabric filter. An opacity monitor will also be
installed at the outlet of the fabric filter.
4-70
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Figure 4.2-5 shows the location of the equipment. Moderate access/
congestion levels were assumed for the ductwork and fabric filter. Moderate
access/congestion levels were also assumed for the lime receiving, storage and
conveying equipment. Advanced planning will be required to limit combustor
downtime to approximately one month.
4.2.6.2 Environmental Performance. Total CDD/CDF emissions are
expected to be reduced by 75 percent from outlet corabustor levels. Acid gas
emission reductions are estimated at 80 percent for HCl and 40 percent for
S02» respectively. PM emissions are 0,01 gr/dscf. An additional 1,380
tons/year of sorbent and fly ash will be added to the baseline solid waste
disposal requirements* or either combustion practices.
4.2.6.3 Costs. Total capital cost requirements for dry sorbent
injection are presented in Table 4.2-7 for baseline and good combustion. Most
of the cost is associated with particulate control equipment. Total capital
cost is estimated at $4,320,000 for baseline combustion and $3,510,000 for
good combustion. Both estimates assume moderate APCD access/congestion level.
Annual O&M and indirect costs are presented in Table 4.2-8 for both
combustion practices. Major direct operating costs are associated with
maintenance materials, electricity, lime, and monitor maintenance. The
largest annualized cost is the capital recovery and downtime. The total
annualized cost for the modification is $1,400,000 per year for baseline
combustion and $1,170,000 for good combustion.
4.2.7 Best Acid Gas Control
4.2.7.1 Description of Modifications. For best acid gas control a new
spray dryer/fabric filter system will be installed to treat the total flue gas
from both combustors. Lime slurry will be fed to a single spray dryer at a
2.5:1 molar calcium-to-acid gas ratio. Lime will be slurried in sufficient
water to cool the flue gas to from 450°F to 3QQ°F at a rate of 19 and 12 gpm
for baseline and good combustion, respectively. A fabric filter with 43,500
and 30,600 square feet of cloth (gross air-to-cloth ratio of 3:1} will be
installed following the spray dryer for baseline and good combustion
practices, respectively. The project also includes monitoring equipment for
HCl, S02, 02, and opacity.
4-71
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TABLE 4.2-7 PLANT CAPITAL COST FOR DRY SORBENT INJECTION WITH FABRIC FILTER
(Two units of 120 tpd each)
Costs (S1000)
Item
Baseline Combustion
Practices
Good Combustion
Practices
DIRECT COSTS:
Acid Gas Control
Equipment
Access/Congestion Cost
Part icul ate Control
Equipment
Access/Congestion Cost
New Flue Gas Ducting
Ducting Cost
Access/Congestion Cost
Other Equipment
Fan
Stacks
Demolition/relocation
Total
Indirect Costs and Contingencies
Monitoring Equipment3
TOTAL CAPITAL COST
DOHNTIME COST
ANNUAL I ZED CAPITAL RECOVERY AND DOHNTIME
198
20
1,200
294
144
36
253
0
ITBo
1,890
286
4,320
94
580
198
20
• 932
233
121
30
180
0
0
1,710
1,510
286
3,510
94
474
Turnkey.
4-72
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TABLE 4.2-8 PLANT ANNUAL COST FOR DRY SORBENT INJECTION-WITH FABRIC FILTER
(Two units of 120 tpd each)
Costs (S10001
Item Baseline Combustion Good Combustion
Practices Practices
DIRECT COSTS:
Operating Labor
Supervision
Maintenance Labor
Maintenance Materials
Electricity
Compressed Air
Waterc
Lime
Waste Disposal
Monitors
Total
INDIRECT COSTS:
Overhead
Taxes, Insurance, and Administration
Capital Recovery and Downtime
Total
TOTAL ANNUAL IZED COST
40
6
16-
150a
105
17
4
73
35
_JS1
553
101
161
S80
842
1,400
40
6
16K
116b
76
12
0
73
35
. 107
480
88
129
474
691
1,170
Includes bag replacement costs of $42,000.
Includes bag replacement costs of $30,000.
Incremental increase in water costs from baseline.
4-73
-------
Stack
New Ducting
X
Tipping
Area
Control
Room
Combustor
Area
New Induced
Draft Fan
New
Sorfaent
Injection
Figure 4.2-5. Plot Plan of Dry Sorbent Injection/Fabric Filter Equipment Arrangement.
-------
Monitors for HC1, SO-, and CL will be located in the ducting before the spray
dryer and at the outlet of the fabric filter. An opacity monitor will also be
installed at the outlet of the fabric filter.
This arrangement will require about 270 total feet of new duct, but will
allow the existing stack to be reused. The proposed equipment layout is
illustrated in Figure 4.2-6. This sketch also shows the location of the lime
receiving, storage, and slurry area and the location of the waste storage
silo. Access and congestion levels are assumed to be moderate for the flue
gas ducting, spray dryer/fabric filter and the sorbent preparation and waste
silo. Advanced planning will be required to limit combustor downtime to
approximately one month.
4.2.7.2 Environmental Performance. Total CDD/CDF emission reductions of
99 percent from the combustor outlet levels or to 5 ng/dscm, whichever is
greater, are expected. Emissions of particulate matter will be reduced from
0.33 gr/dscf to 0.01 gr/dscf. Acid gases will be reduced 90 percent for SCL -
and 97 percent for HC1. Solid waste will be increased by 1,240 tons/yr
relative to baseline.
4.2.7.3 Costs. Capital cost requirements for installing a spray dryer/
fabric filter system are presented in Table 4.2-i for baseline and good
combustion. Total capital cost is estimated at $9,600,000 and $8,020,000 for
baseline and good combustion conditions, respectively. This figure includes
purchased equipment, installation, and indirect costs such as engineering and
contingencies. Estimates assume moderate access and congestion.
Annual O&M and indirect costs are presented in Table 4.2-10. • Total
annualized cost of good acid gas control are $2,350,000 and $1,990,000 per
year for baseline and good combustion, respectively.
4.2.8 Summary of Control Options
4.2.8. Description of Control Options. The control technologies
described in the previous sections have been combined into seven retrofit
emission control options. Table 4.2-11 summarizes the combustion, particulate
control, and acid gas control technologies described in Section 4.2.3 through
4.2.7 that were combined for each of the control options described in
Section 3.0.
4-7S
-------
Stack
New Ducting
Tipping
Area
-p-
CTl
Control
Room
Combustor
Area
New
Induced Draft
Fan
New
Spray
Dryer
Parking
Area
New Lime
Storage and
Handling
Figure 4.2-6. Plot Plan of Spray Dryer/Fabric Filter Equipment Arrangement.
E
-------
TABLE 4.2-9 PLANT CAPITAL COST FOR SPRAY DRYER WITH FABRIC FILTER
(Two units of 120 tpd each)
Costs fSlQOOl
Item Baseline Combustion Good Combustion
Practices Practices
DIRECT COSTS:
Acid Gas and Parti cul ate Control
Equipment
Access/Congestion Cost
New Flue Gas Ducting
Ducting Cost
Access/Congestion Cost
Other Equipment
Fan
Stacks
Demol ition/relocation
Indirect Costs and Contingencies
Monitoring Equipment
TOTAL CAPITAL COST
DOWNTIME COSTS
ANNUAL I ZED CAPITAL RECOVERY AND DOWNTIME
4,290
1,070
162
41
271
0
0
5,840
3,480
286
9,600
94
1,270
3,580
899
136
34
194
0
0
4,840
2,880
286
8,020
94 .
1,070
aTurnkey.
4-77
-------
TABLE 4.2-10 PLANT ANNUAL COST FOR SPRAY DRYER WITH FABRIC FILTER
(Two units of 120 tpd each)
costs rsioooi
Item Baseline Combustion Good Combustion
Practices Practices
DIRECT COSTS;
Operating Labor
Supervision
Maintenance Labor
Maintenance Materials
Electricity
Compressed Air
Water
Lime
Waste Disposal
Monitors
Total
INDIRECT COSTS:
Overhead
Taxes, Insurance, and Administration
Capital Recovery and Downtime
Total
TOTAL ANNUAL I ZED COST
39
6
21
159a
132
20
4
60
44
_lflZ
592
110
373
1.270
1,750
2,310
39
6
21b
127°
94
14
2
60
44
107
514
98
309
U07Q
1,480
1,990
alncludes bag replacement costs of $42,000.
Includes bag replacement costs of $30,000.
4-78
-------
TABLE 4.2-11 SUmARY OF CONTROL OPTIONS FOR ROCKING/RECIPROCATIHC CRATE MASS BURN RZFRACTOBY-UAU, COHBUStOB
Control Option Description
Combustion
Modification!
Part tcul »te attar Contro
Hew ESP
Acid Cjs Control
Hev " Sorbent
Fabric Filter Injection Spray Dryer
US
1, Good Cocnbultion Control
2. Good FM Control »nd Coenbuitlon
Control
3. Best I'M Control and Combustion
Control
4. Good Acid C»i Control and Beit PM
Coot col
. Good Acid Ct» Control and B«»t
PM/CombujtIon Control
6. B*ic Acid C»» Control and B*tt PM Control
7, Beat Acid Gai Control and B*it FH/Combust Ion X
Control
-------
4-2.8.2 Environmental Performance. The performance of each control
option 1s summarized In Table 4.2-12. For each pollutant the table presents
both the pollutant concentrations and annual emissions. The greatest on acid
gases, participate matter, and CDO/CDF all are achieved with a spray dryer/
fabric filter system. The next most effective control for all these
pollutants is the dry sorbent injection technology. Dry sorbent injection
technology increases the baseline solid waste disposal by about 6.S percent,
and the spray dryer/fabric filter system increases the baseline solid waste
disposal by about 5.8 percent. CO reduction of 70 percent from baseline is
achieved for those options having good combustion.
4*2.8,3 Costs. The total annualized cost of each option is presented in
Table 4.2-13. The most expensive control option is the spray dryer/fabric
filter installation with combustion modification {Option 7). The total
capital costs for this option is 11,900,000 and the total annualized cost is
$2,820,000. This annualized cost is roughly 3 times higher than the
annualized costs for Option 1. Overall, both capital and annualized costs are
higher for higher levels of control.
4.2.8.4 Energy Impacts. Table 4.2-14 presents a summary of the energy
impacts associated with the control options. The energy use figures are
incremental use from baseline, The spray dryer with fabric filter control
options consume the most electricity of the two fabric filter options, Option
6 consumes more electricity at a rate of 2,870 MWh per year. Auxiliary fuel is
fired for those options requiring combustion modification all at a rate of
22 billion Btu per year.
4-80
-------
TABLE 4.2-12 EHVIBONXEHTAJL PEBPORHANCB SUHHAKV POX MASS tUU RECIPROCAHKC GRATB RBJTUCTORlf-WAU.
we MODEL yuan RITBOTIT COHTROL onions (two unit* of 120 tpd
Total Cm/CDF 2tel**loiu
Hs/yr
I Reduction vi. Baiellne
CO Emiulon*
(opnw}
Mf/yc
S Reduction V*. Ba**llna
PH Eml«»lon»
(cr/d»cf)
Mg/jrr
X Reduction v». Batvlln*
SO Eml.ilonj
1 fppo*)
00 H»/yr
I Reduction v». Baseline
BC1 EnLtilorv*
Cppffivl
MSI yr
I Reduction v*. B***lln*
total Solid UMt*
(toru/dar)
M§/yc
I Iaer*a*a •»». Baaallna
.a,.!^
4.000
l.OE-J
— .
sao
147
—
0.33
191
**
200
142
--
SOO
206
—
72
17,700
"
Option 1
SOO
l.St-4
87
ISO
44
70
0.31
191
0
200
142
0
SOO
206
0
72
17,700
0
Option 2
SOO
1.JB-*
87
ISO
44
70
O.OS
29
as
200
142
0
$00
206
0
72.7
17,900
0.9
Option 3
SOO
1.31-4
87
ISO
44
70
0.01
S.8
97
200
142
0
SOO
206
0
72.8
17,800
1.0
Option 4
1000
2.41-4
75
SOO
147
0
0.01
S.8
97
120
as
40
100
41.
iO
77.1
18,900
7.1
Option S
12S
3 2E-S
96.8
ISO
44
70
0.01
S.8
97
120
as
40
100
41
80
77.1
18,900
7,1
Option 6
40
J.OE-6
99.0
500
147
0
0.01
S.8
97
19
13
90. S
IS
6
97
78.3
19,300
9,0
Option 7
S
1.301-6
99.8
ISO
44
70
0.01
S.B
97
19
13
90. S
IS
6
97
78.3
19,300
9.0
All flu* g*s concMitratloa* »r« reported on * 71 0 b*«l*.
-------
TABLE *.2-13 COST SUHHARY FOR MASS BURN RECIPROCAIIHC OUTE XEfKACfORY-HALL WC MODEL PLANT RETROFIT CONTROL OPTIONS*
{two unit* of 120 tpd each)
00
ro
Tot»L Capital Co«t
Downtime Cojt
Annual I *«d Capital Coat
and Doimfciac
Dlccet 0 I M Cost
focal Annual co«t
Coat Eff«cclv«n*»«
Option 1
1,860
190
312
13?
847
13.10
Option I
S, 660
190
769
192
1,210
19.00
Option 3
6,000
190
013
20*
1,)00
21,00
Option *
4,320
95
S80
551
1.400
22.60
Option 9
1,310
190
99*
61?
2,000
J2.JO
Option 6
9,600
94
1,270
592
2,350
37.90
Option 7
11,900
190
1,590
651
2,820
45.50
(S/ton HSH)
Facility Downtime
(Month*)
Total Compliant:* Tint
(Monttu)
19
19
19
19
25
25
AIL coiti (•xeapt co»t *ff*cttv«na**) given In $1000. All co>t» *c* December 199? dollars.
-------
TABLE 4.2-14 ENERGY IMPACTS FOR ROCKING/RECIPROCATING MASS BURN
REFRACTORY-WALL COHBUSTOR CONTROL OPTIONS
Electrical Use Gas Use
Option (MWh/yr) (Btu/yr)
1 0 2.2E10
2 217 2.2E10
3 349 2.2E10
4 2,280 0
5 1,650 2.2E10
6 2,870 0
7 2,030 2.2E10
4-83
-------
4.3 GRATE/ROTARY KILN REFRACTORY-WALL COHBUSTOR
This section presents the case study results for a mass burn
refractory-wall MWC'using a split flow configuration with a rotary kiln. As
shown in Table 4.0-1, there are 5 known plants of this type. Section 4.3.1
presents a description of the Montgomery County (Dayton) Ohio, plants, which
were visited to gather information for model development. Section 4.3.2
presents a description of the model plant. Sections 4.3.3 through 4.3.6
describe the retrofit modifications, estimated performance, and costs
associated with various retrofit controls. Section 4.3.7 presents a summary
of the control options, which are described in more detail in Section 3.0 of
this report.
4.3.1 Description of Montgomery County. Ohio Plants
Montgomery County, Ohio operates two MWC plants, referred to as the
North and South plants. Both plants began operating in 1970 using nearly
identical designs, and both plants are currently undergoing expansions which'
are expected to be complete in 1988. The original design at each plant
consisted of two 300 tpd Volund refractory-lined combustors (#1 and 12) with
reciprocating grate sections followed by a rotary kiln. The units are
illustrated in Figure 4.3-1. The original air pollution controls consisted
of low energy wet scrubbers. Electrostatic precipitators (ESP's) were added
to all of the existing combustors in the early 1980's. The original wet
scrubbers are now used as cooling and mixing chambers.
The current facility expansions will add a third 300 tpd combustor (#3)
at each plant site. The #3 combustor at the North plant is equipped with a
Combustion Engineering waste heat boiler with a design capacity of
82,000 Ib/hr of steam at 750 psig and 750°F» and a 6 MW extraction turbine.
Space is being provided at the South plant for a similar boiler design to be
added later to its #3 combustor. Boiler addition at the South plant is
contingent on the successful operation of the boiler at the North plant.
The description of the plants which follows will apply to the existing
combustors (#1 and #2) at either of the plants. Where design and operations
differ between the two plants these differences will be identified.
4-84
-------
I
00
in
Tipping Floor
If iNLJUU
4 MM
Ioverfire
Air Vibrating
Forced Fan Conveyor
Draft
Fan
Bottom
Ash Ash
Quench Conveyor
Pit
„ ., Cooling
Cooling Chamb|r
Sprays
Rotary
Conveyors
Figure 4.3-1. Profile of Original Combustor (il and #2) at Montgomery County, OH.
-------
4.3.1.1 Combustor Design and Operation. The two existing combustors
operate 24 hours/day, 7 days/week, with as few shutdowns as possible. Waste
is dumped by trucks into a large holding pit where it is mixed by an
overhead crane and charged to individual combustor feed hoppers. Both
plants have experienced pit fires in the past. This problem has been
addressed with installation of emergency water hoses on the ceiling of the
building above the holding pit. Waste is fed to each combustor by gravity.
The feed rate is controlled by the speed of the first grate section. A
profile sketch of the existing combustors is shown in Figure 4.3-1, and
operating and design data are presented in Table 4.3-1.
Waste tumbles from the feed chute onto the first of two short drying
grate sections, where moisture is released prior to ignition. A grate step
of about two feet separates the two sections. No undirfire air is supplied
to the drying grates. Hoppers are located beneath the grates to catch waste
which falls through. The sittings and riddlings are conveyed to the ash
disposal system. A transverse refractory arch is located above the drying
grate sections in 3 of the 4 existing combustors at the 2 plants to provide
radiative heat to the drying grates. Existence of these arches does not
appear to be an essential design feature, however. The #1 combustor at the
North plant no longer has the transverse arch, and the design being used in
the #3 combustors will include a vertical arch rather than the transverse
design (see Figure 4.3-2).
From the second drying grate section waste tumbles approximately S feet
down onto the ignition grate, where active burning takes place. Individual
forced-draft fans supply underfire air to a single windbox beneath the
ignition grate in each of the combustors. This flow is adjusted manually by
a damper located in the supply header. Underfire air is drawn from the pit
area. The windbox is not well sealed, as the air is not highly pressurized.
When these fans are inoperable the system operates with only the ID fan
pulling air through the windbox.
Flue gas temperatures are measured by a thermocouple located in the
roof of the ignition chamber and are displayed in the control room. Normal
operating temperatures in the ignition chamber were reported to be 1,700 to
1,800°F. Two sidewall overfire air ports (4 inch square) are located on
4-86
-------
TABLE 4.3-1. MONTGOMERY COUNTY, OHIO DESIGN DATA
General:
Number of combustors at each plant
Type
Combustor capacity
Plant Capacity
Kiln Parameters:
Length
Diameter
Maximum Kiln Speed
Gas Conditioning:
Conditioning Chamber
Maximum Cooling Water Flow
Particulate Emission Controls:
Type
Manufacturer
Number of ESP's
Number of Fields
Operating Temperatures
Design Outlet Grain Loading
Particulate Emission Limit
Gas Flow
Total Plate Area
SCA 9 100,000 acfm
Residence Time
Dimensions:
Length
Width
Height
Particulate Matter Emissions (March 1985)
Acid Gas Emission Control:
Furnace Sorbent Injection
2 (3 with expansion)
Reciprocating grate followed
by rotary kiln.
300 tpd each
600 tpd (900 tpd with
expansion)
30 feet
10 feet
10 rph
27 feet in length
28 feet in height
180 gpm
Electrostatic Precipitator
United - McGill
2 (one per combustor)
3 per ESP n
450 to 600°F
0.03 gr/dscf at 12% CO,
0.03 gr/dscf at 12% CO-
100,000 acfm i
32,580 square feet
326
8 seconds
30 feet
20 feet
30 feet
0.036 gr/dscf at 12% C02
4-87
-------
co
CO
3V
Mixing
Chamber
Ash Conveyor
Figure 4.3-2. Profile of New Combustor (13) at Montgomery County (North), OH.
1C
f-
-------
each side of the combustor approximately 5 feet above the level of the
grate. These air ports are the last point of controlled air injection to
the system. However, there are numerous points of air inleakage from ports,
doors, and seals downstream. A single overfire air fan with an operating
pressure of 27 inches of water head capacity provides overfire air to both
existing combustors (#1 and #2). Thus, loss of this fan eliminates the
overfire air supply to both units.
Burning waste is discharged from the ignition grate and falls
approximately 4 feet into a refractory-lined rotary kiln. The kiln is
approximately 10 feet in diameter and 30 feet in length. The kiln rotates
at a maximum speed of 10 rph. The kiln is a co-flow design; flue gases flow
in the same direction as the waste. Burnout of solids is achieved through
long retention times in the kiln. Bottom ash is discharged from the kiln
and falls into a *ater quench pit where it is removed by a drag chain
conveyor.
The flow of combustion gases from the ignition chamber is split, with
portions flowing through the rotary kiln or through a refractory-lined
overhead bypass duct. The split flows converge in a mixing chamber down-
stream of the rotary kiln (see Figure 4.3-1). A thermocouple is located on
the roof of the mixing chamber. Typical operating temperatures in this
region vary from 1,700 to 1,900°F. The gases then flow to a cooling chamber
where water sprays lower their temperatures to approximately 600°F. Typical
water spray rates were reported to vary from 80 to 110 gpm. The maximum
cooling water flow rate is about 180 gpm. The flow of water is adjusted
automatically to maintain a temperature set point at the ESP inlet. An
emergency dump stack is located at the top of the mixing chamber for use
when the ESP's or water sprays are inoperable.
Grate System. The existing combustors were originally equipped with
Volund cast iron grate systems. As the cast iron grates have failed, they
have been replaced by a custom design which was fabricated specifically for
the two plants. The new stainless steel grates are arranged in 13 rows,
called stringers, across the width of the grate section (side wall to side
wall). Underfire air passes up through slots located between the grates and
at the front of the grate nose. The South plant has drilled holes through
4-89
-------
the top of the grate bars, while the North plant uses solid sections. No
design or operational advantages have been realized from either grate system
to date.
Combustion Controls. The combustors are operated on a manual control
scheme. Air flows and grate and kiln speeds are adjusted manually based on
visual observations of the burning process and on the temperature readings
at the various stages through the system. The combustor draft requires a
manual setting on the ID fan with automatic control to maintain -0.25 inches
of water pressure in the ignition chamber and -0.7 inches of water in the
mixing chamber. As mentioned above, temperatures in the ISP are maintained
by the adjustment of the water sprays in the cooling chamber. With the
addition of the third combustor the controls will all be consolidated at one
new location in the building. They will, however, remain largely manual.
Agh^Ojsposyal. Siftings, riddlings, bottom ash, and fly ash are
combined in the wet ash quench and removed from the building by a drag chain
conveyor. All of the ash from both plants is buried in a single landfill
site adjacent to the North plant. The ash at the South plant is stored
temporarily behind the plant until it can be trucked to the North site
landfill. Private scavengers are permitted to remove and reclaim scrap
metals from the landfill site prior to burial, and a base price per ton of
metal recovered is paid to the County, The landfill site is lined with clay
and was reported to be equipped with groundwater monitoring wells. No
substances other than ash are disposed of in the landfill at the North
pi ant.
Start-Up/Shutdown. None of the existing combustors is equipped with a
source of auxiliary fuel. The plants reported that they almost never have
both existing combustors off line at any given time. A crossover duct is
located in the hairpin duct section downstream of the conditioning chamber,
connecting both combustors. When one unit is started up, the crossover duct
1s opened and hot gases from the other combustor are used to preheat the
cold ESP. However, the combustors are started up by igniting the waste and
gradually developing stable burning patterns. From a cold start the
refractory takes up to 24 hours to reach steady state operating temperatures.
.4-90
-------
Auxiliary gas burners are reportedly being added in the mixing chamber of
the new combustor (#3). Shutdown is achieved simply by burning out the
waste in the system and letting the combustor cool.
Facility Expansion. As mentioned previously, the #3 cotnbustor at the
North plant will include a waste" heat boiler and turbine generator, and the
South plant is providing space to include a similar design. The arrangement
at the North plant is depicted in Figure 4.3-2. The basic configuration
does not change appreciably from that of the existing combustors. Specific
changes include:
- A vertical refractory arch hangs from the combustor roof,
- the riddlings conveying system uses a wet chain conveyor rather than
a vibrating conveyor,
- the riddlings hopper is water sealed,
- the windbox under the ignition grate will be sealed, and
- air is injected through fan ports on the back wall of the ignition
chamber, where waste builds up.
Sufficient fan capacity is available in the two underfire air fans and the
single overfire air fan that service the existing combustors so that ducting
from these units can supply air to the #3 combustor.
An interesting design feature of this system is the operational
flexibility provided to the plant through a boiler bypass. This bypass
provides a flue gas flow path similar to that used in the existing
combustors. Plant personnel estimate that 75 percent of the flue gas will
normally pass through the boiler and 25 percent through the bypass.
However, all of the flue gas can pass through the bypass, allowing
incineration to continue in the event that the boiler must be removed from
service for maintenance or other reasons. In the new unit, design attention
was focused on unit reliability rather than on maximized steam production.
The boiler will be operated at 500 psig and 6SO°F, considerably below
its design rating (750 psig at 750°F). Boiler load will also be slightly
less than rated capacity (82,000 Ib/hr of steam). Additional safety factors
were taken into account in the boiler design by providing an additional
1/2 inch of steel on all areas of the.steam drum that come into direct
contact with flue gases. Waterwall and superheater tube wastage experienced
4-91
-------
at othir resource recovery plants due to flame impingement and participate
carryover are not expected to occur In the current design because of the
remote locations of heat transfer surface relative to the active burning
regions.
Electricity will be generated by a 13-stage Murray steam turbine and
sold to the local grid. The price was under negotiation during the time of
the site visit. The plant does not currently have a steam customer, but a
blind connection has been provided in the boiler design. A fin tube
economizer is located downstream of the ID fan to preheat boiler feedwater.
Feedwater treatment equipment is located on site, and without sale of steam,
make-up water is minimal.
4.3.1.2 Emission Control System Design and Operation. Each combustor
is equipped with a dedicated 3-field ESP manufactured by United-McGill,
Table 4.3-1 presents design and operating data for the ESP's, and Figure
4.3-3 shows a plot plan of the South plant. Flue gases flow upward from the
cooling chamber through a hairpin duct and enter the ESP. A thermocouple
located at the top of the hairpin duct measures the temperature at this
point and controls the rate of water injection upstream in the cooling
chamber. Setpoint temperatures reportedly vary from 500 to 590°F.
The plates are made of COR-TEN steel so that a protective coating of
rust forms early after installation, preventing further corrosion. The
plant reported that the ESP's have been operated below 500°F, but long-term
operation at these temperatures has resulted in deposits of an unknown
substance on the plates that must be periodically "baked off" at tempera-
tures in excess of 600°F. Measured particulate data provided by the State
regulatory office indicated that the ESP's have achieved an average grain
loading of 0.036 gr/dscf corrected to 12 percent C02 (March 1985 compliance
test results).
Each plant has one stack for the two existing combustors. A new stack
is being constructed at each plant for dedicated use with the new combustors.
An opacity monitor is located in each stack. Opacity wa.s observed to be
about 5 percent during the 2-day visit.
4-92
-------
F1§yrt 4.3-3. Plot Plifi of Montgomery County (South), OH.
4-93
-------
With the construction of the new combustors (#3), a number of air
permitting Issues arose concerning S0» emission levels and BACT
determinations. The- plants Installed combustor dry sorbent Injection
systems on the existing combustors (#1 and #2} to reduce SO- emissions and
allow erection of the #3 combustors.
Crushed limestone is pneumatically conveyed from a storage silo one
cubic foot at a time to a three cubic foot surge bin. A meterable auger
feeding system feeds the limestone to a venturi device, which injects
limestone into the overfire air ducts. After experimenting with a number of
sorbents, crushed limestone was selected due to lower costs than lime. The
limestone is injected into the flue gas at a rate of 135 to 160 Ib/hr per
combustor. Limited emissions testing indicates that somewhat less than
30 percent SO- reduction is achieved. These results were documented by
continuous S0~ monitors at the stack'while the sorbent injection system was
operating and then turned off. The State emission limit for SO. is
2,S Ib/ton of waste charged. The marginal control efficiency of these
systems has permitted the plants to comply with this regulation and avoid
PSD applicability for SO-. No impact on fly ash amount or ESP performance
has been noted by the operators since operation of the injection system
began.
4.3.2 Description of Hodel Plant
4.3.2.1 Comfaustor Des1qn and Operation. The configuration of the
combustion system is similar in configuration to that of the existing units
at the Montgomery County, OH plants. This is typical of the four other
facilities in this subpopulation. The model plant is comprised of three
combustors, each with a design capacity of 300 tpd. It is assumed that the
plant operates at 100 percent capacity, 24-hours/day, 7-days/week. Baseline
data for the model plant is shown in Table 4.3-2.
The plant uses early Volund technology, which consists of two drying
gratis, a burning (ignition) grate, and a refractory-lined rotary kiln.
Waste feeding is accomplished by gravity and controlled by manual adjustment
of the first drying grate section. Each of the combustors has separate
underflre and overfire air fans. Underfire air is supplied beneath the
4-94
-------
TABLE 4.3-2.
MODEL PLANT BASELINE DATA FOR GRATE/ROTARY KILN
REFRACTORY-HALL COHBUSTOR
Combustors:
Capacity
Rotary K1ln
Design Percent
Excess Air
Total Excess Air
(including inleakage)
Gas Conditioning:
Inlet PM Loading
Conditioning Chamber
Emission Controls*.
Type
Number
Gas Flow
Collecting Area
SCA at 210,000 acfm and 550°F
Inlet PM Loading
Emissions3:
CDD/CDF (tetra-octa) (stack)
CO
PM (stack)
HC1
so2
Sofid Waste
Stack Parameters:
Height
Oi ameter
Operating Data:
Remaining Plant Life
Annual Operating Hours
Annual Operating Cost
3 units at 300 tons per day each
30 feet in length
10 feet diameter
10 rpm maximum speed
250 percent
275 percent
3.0 gr/dscf at 7 percent, Q
27 feet in length ^
28 feet in width
3-field ESP
3, one per eombustor
210,000 acfm at 550°F
53,000 square feet
250 square feet per 1000 acfm
1.0 gr/dscf at 7 percent ()„
6,000 ng/dscm
500 ppmv
0.03 gr/dscf at 7
500 ppmv
200 ppmv
270 tpd
120 feet
8 feet
15 years
8,000
$9,910,QQO/year
percent 0
2
All values are dry, corrected to 7 percent Q--
conditions are both 1 atmosphere and 70 F. All
COO/CDF are measured at combustor exit.
Standard and normal
emissions except PM and
4-95
-------
Ignition grate just upstream of the rotary kiln. There is no underfire air
supplied to the drying grates. Overfire air is supplied on each of the side
walls of the ignition chamber through two square ports. Control of both air
supplies is totally manual (based on individual damper settings). Grate
speeds and rotary kiln rotational speeds are manually adjusted.
Theoretical air requirements are approximately 17,800 scfm at full
capacity. Based on measured data from the North plant, 250 percent excess
air is assumed to be provided by the forced-draft fans. There are, however,
a number of points of air inleakage in the system which are assumed to
contribute an additional 25 percent excess air. Therefore, the total gas
flow is 77,600 scfm (72,300 dscfm), including all flue gas products.
Temperatures are monitored by thermocouples located in the roof of the
ignition chamber and at the ESP inlet. Water sprays are automatically
adjusted in the cooling chamber based on the temperature set point at the
ESP inlet.
4.3.2.2 EmissionControl System Designand Operation. As shown in
Table 4.0-1, 3 of the 5 plants in this subcategory and 16 of the
24 refractory-wall MWC's are equipped with ESP's. Therefore, the most
representative APCO for the model plant is an ESP. For the purposes of
model development, the model is assumed to have an emission control system
similar to the Montgomery County plants, with the exception that the model
does not have sorbent injection. Furnace sorbent injection is unique to
Montgomery County plants and is not representative of the population.
Each combustor at the model plant is equipped with a 3-field ESP with
53,000 square feet of collecting area. Current stack PM emissions are
0.03 gr/dscf. For the purposes of model development, it will be assumed
that each combustor has its own stack, and that access/congestion
constraints are moderate. A plot plan of the model-plant is shown in
Figure 4.3-4.
4,3.2.3 Environmental Baseline. Table 4.3-2 also presents baseline
emissions data for the model plant. The Montgomery County plants do not
have measured CDD/CDF emission data available. Due to the absence of an
overfire air injection point downstream of the rotary kiln it is assumed
4-96
-------
Stacks
XX XX XX
Figure 4.3-4. Modtl Plant Plot Plan,
4-97
-------
that mixing of combustion gases is not optimized, and that CDD/COF
destruction is also not optimized. Tht high excess air levels also
contribute to quenching of the combustion process, resulting in insufficient
furnace temperatures. Assumed CDD/CDF baseline emission values are
2
4,000 ng/dscm corrected to 7 percent 02- These values do not reflect
possible organics formation which may take place downstream of the
combustor. Therefore, the model plant is. assumed to have CDD/CDF emissions
of 6,000 ng/dscm corrected to 7 percent 0- at the stack.
Uncontrolled particulate emissions in mass burn water-wall combustors
average 2.0 gr/dscf. Because excess air levels are higher in refractory-
wall combustors, a greater amount of particulate is assumed to be carried
out of the combustor than in waterwall MWC's. Therefore, an uncontrolled PM
emission rate of 3.0 gr/dscf at 7 percent 0- is assumed for baseline
conditions.
Due to the poor mixing conditions and low operating temperatures
assumed for the model plant, baseline CO emissions are assumed to be
SOO ppmv. Uncontrolled HC1 and SCL emissions are assumed to be 500 ppmv and
200 ppmv, respectively.
The model plant achieves 90 percent waste volume reduction and
70 percent weight reduction. These values are assumed based on visual
observation during the site visit to North Montgomery County. Although ash
disposal is free for the Montgomery County plants, an average disposal fee
of $2S/ton is assumed for the model plant to be more representative of the
existing population.
4.3.3 Goojj Combustion and ExhaustGas Temperature Control
The following sections describe combustion retrofits developed for the
model plant described above.
4.3.3.1 Description of Modifications
Combustion Airflow Modifications. The following modifications to
combustion airflows are included in the modified model plant:
o Excess air operating levels are reduced from 250 percent to
150 percent, allowing furnace operating temperatures to be
maintained at 1,800 F in the fully mixed location and reducing the
potential for particle entrainment. At 150 percent excess air the
gas flow from the combustor is reduced to 49,300 scfm
(46,300 dscfm).
4-98
-------
o New overfire air ports are added in the overpass duct and in the
mixing chamber to provide a source of mixing air. The exact
specifications of these nozzles are to be determined using flow
modeling studies. Approximately 110 percent of the theoretical
air requirement (21,700 scfm} is supplied by the mixing air, with
35 percent theoretical air supplied at the overpass duct and
75 percent theoretical air supplied In the mixing chamber. In
furnace CO profiling is used to verify mixing patterns.
o The sidewall ports are retained to supply wall cooling air. The
combined total air supplied by the underfire air supply and the
wall cooling air is 140 percent of the theoretical air
requirement (27,600 scfm).
o A double guillotine airlock 1s installed at the bottom of the
supply plenum/hopper beneath the ignition grate, providing i seal
to the air supply and eliminating this source of air inleakage.
However, inleakage downstream of the combustor results in stack
flows equivalent to 175 percent excess air (53,000 dscfm)
The reconfigured combustion air design is illustrated in Figure 4.3-5.
Fuel. The modified model plant has two auxiliary fuel
burners, sized to provide a total heat input equal to 60 percent of full
unit load (67.5 MM Btu/hr). One burner 1s located above the drying grates
on the roof of the ignition chamber. The second burner is located downstream
of the overfire air nozzles in the mixing chamber. The burners are used
during start-up, shutdown, and episodes of low furnace temperature and high
CO.
Combustion Control. In the baseline configuration the combustion
control scheme is entirely manual. As part of the combustion modifications
improved controls are necessary. Because there is no steam production, the
primary variables to include in the control scheme are excess oxygen and
temperature. The revised controls include an oxygen trim loop which
automatically adjusts the amount of underfire air in response to a signal
from an oxygen controller. A temperature controller is included with an
alarm at high and low setpoints. Overfire air rates are kept constant.
Adjustments in overfire air and kiln grate speeds will be made manually, if
needed.
4-99
-------
VI
B
O
e
o
o
01
o
Q.
b.
O
1
o
Lrt
I
41
4-100
-------
Verification. Verification of good combustion consists of insuring
that the system is operating according to its design. There are a number of
operating parameters* that must be monitored and controlled in order to
achieve this objective. At a minimum, refractory-wall cornbustors must
continuously monitor:
1) underfire and overfire air flows (pressure settings)
2) combustor draft
3) CL (excess air) and CO in the flue gas
4} combustor temperature.
Underfire and overfire air flows are monitored by maintaining specified
pressures in supply headers. Combustor draft is maintained by a variable-
speed ID fan. Flue gas 02 and CO are measured at the same location in the
system so that the CO reading can be corrected to a standard value, such as
7 percent 0*. Combustor temperature requirements are specified at a location
where the mixing process is completed, just downstream of the last point of
overfire air injection.
Temper ature Control Downstream. The set point on the cooling water
sprays should be lowered so as to maintain the ESP inlet temperature at
450°F.
Retrofit Considerations. It is estimated that total facility downtime
for installation of the combustion modifications will be one week per unit,
4.3,3.2 Environmental Performance. As a result of applying the above
described modifications to the model plant, baseline CDD/CDF emissions are
2
estimated to be reduced to 500 ng/dscm. Emissions of CO are reduced to
150 ppmv. No change in uncontrolled emissions of PH, HC1» or SO- can be
anticipated as a result of these modifications. The modifications also have
no effect on solid waste disposal quantities.
4.3.3.3 Costs. Capital costs of the.combustion retrofit options are
presented in Table 4.3-3. Annual operating and maintenance costs are
presented in Table 4.3-4. The total capital cost of the modifications is
$1,130,000. Downtime cost is $109,000. Annualized capital and downtime
costs are $163,000. Total annualized costs, including operating and
maintenance costs, are $429,000.
4-101
-------
TABLE 4.3-3. PLANT CAPITAL COSTS FOR COMBUSTION RETROFITS
(Three units of 300 tpd each)
Item Costs ($1000)
DIRECT COSTS;
Flow modeling and thermal analysis 125
Overfire air ducting, dampers, positioners and nozzles 39
Underfeed and Overfeed air flow monitors 32
Gas pipeline (1/2-miltl 50
Auxiliary fuel burners 244
0, and CO monitors with readouts and integrators 135
Co profiling 10
02 trim controls on forced draft fans 38
Underfire air plenum/hopper 79
Total 752
INDIRECT COSTS AND CONTINGENCY: 376
TOTAL CAPITAL COSTS 1,130
DOWNTIME COST 109
ANNUAL1ZED CAPITAL COSTS 163
aOne per combustor. Includes controller and flame detectors.
4-102
-------
TABLE 4,3-4 PLANT ANNUAL COSTS FOR COMBUSTION RETROFIT
(Three units of 300 tpd each)
Item • Costs ($1000)
DIRECT COSTS:
Natural gas consumption2 87
Operating labor 0
Maintenance labor 42
Haintenance materials 42
Total 171
INDIRECT COSTS;
Overhead 50
Taxes, Insurance, Administration 45
Annualized Capital and Downtime 163
Total 258
TOTAL ANNUALIZED COSTS 429
a!2 start-ups/uhit/year.
4-103
-------
4.3.4 Best Particulate Control
The existing gas conditioning chambers reduce baseline uncontrolled PM
loadings from 3.0 gr/dscf at the corabustor outlet to 1.0 gr/dscf at the
outlet of the chambers. Under baseline combustion conditions, the existing
ESP's reduce PM emissions from 1.0 gr/dscf to 0,03 gr/dscf at the outlet.
This emission level is below the level (0,05 gr/dscf) defined by this study
as good control; thus, no equipment modifications are required for good PM
control for the model plant.
Under good combustion conditions, reduced flue gas volume will also
result in improved ESP performance, and the existing ESP's will reduce PM to
0.01 gr/dscf. Thus, there are also no particulate control equipment
modifications required for best particulate control (Q;Q1 gr/dscf) .for this
model plant.
4-3.5 Good Acid Gas Control
4.3.5.1 Description of Modifications. For good acid gas and CDD/COF
control, dry sorbent will be injected into each combustor through the
overfire air ducts. The water quench system in the cooling chamber will
remain in place, but an additional 30 gpin will be used to cool the flue gas
from 550°F to 350°F under baseline combustion conditions. With good
combustion in place, 22 gpm will be used. New equipment for the site
includes a sorbent storage silo with baghousi, a pneumatic sorbent conveying
system, six sorbent feed bins (two for each combustor), and two pneumatic
injection nozzles for each combustor,
Hydrated lime sorbent will be fed at a calcium-to-acid gas molar ratio
of 2:1. At full load, this will require a sorbent injection rate of
340 Ib/hr per combustor. In addition, ESP plate area necessary to reduce PM
emissions to 0.01 gr/dscf (best PM control) will be added. Under good
combustion, a 13,300 square feet addition of area will be required. With
baseline combustion 36,200 feet is needed. The additional area will be
added as an ESP in series behind the existing ESP on each unit. Installa-
tion will also require an additional 150 feet of duct, and thus replacement
of the ID fan, for each unit. The project also includes new monitoring
equipment for HC1, SO-, and CO-.
4-104
-------
Figure 4.3-6 shows the planned equipment arrangement. Work on each
combustor can proceed while the other two combustors continue to operate.
This plan would limit combustor downtime to approximately 1 month for each
unit.
4.3.5.2 Environmental Performance. Total CDD/CDF emissions are
expected to be reduced by 98 percent. Acid gas emission reductions are
estimated at 50 percent for HC1 and 50 percent for SO-. Particulate
emissions will be reduced from 0.03 to 0.01 gr/dscf.
Application of sorbent injection technology will add 5,300 tons/year of
recovered sorbent and fly ash to the baseline waste disposal requirements
for the plant,
4.3.5.3 Costs. Capital cost requirements for dry sorbent injection
are presented in Table 4.3-5. Total capital cost is estimated to be
$9,410,000 for baseline combustion practices and $7,250,000 with good
combustion. Downtime cost is $437,000 in both cases.
Annual operating and maintenance costs and annual indirect costs are
present in Table 4.3-6. Major direct costs are for lime and maintenance of
monitors. Electricity costs are also substantially higher than baseline as
a result of the additional ESP plate area and larger ID fans. The total
annualized cost (including capital recovery and downtime) is $2,890,000 per
year with baseline combustion and $2,450,000 with good combustion practices.
4.3.6 Best Acid Gas Control
4,3.6.1 Description of Modifications. To achieve greater reduction in
S(L» HC1, and CDD/CDF emissions, a new spray dryer/fabric filter system will
be installed on each combustor after the conditioning chamber. Lime slurry
will be Introduced in each spray dryer at a 2.5:1 molar calcium-to-acid gas
ratio. Lime for each combustor will be slurried in the 37 gpm needed to
cool the flue gas from 550° to 300°F under baseline. With good combustion
in place, 27 gpm will be needed. A fabric filter with 56,200 net square
feet of cloth (net air-to-cloth ratio of 4:1} will be installed following
each spray dryar if baseline combustion is practiced; the required area is
41,800 square feet if good combustion is In place. The increased pressure
drop of fabric filters over ESP's will require a new ID fan for each unit as
well. New monitoring instruments for HC1, SO*, CO- and opacity will also be
installed.
4-105
-------
^ NewESPs
and ID Fans
New Sorbent
Storage Silo
M
go
S
Figure 4.3-6. Plot Plan of Sorbent Injection Equipment Arrangement
4-106
-------
TABLE 4.3-5. PLANT CAPITAL COST FOR DRY SORBENT INJECTION WITH ESP
(Three units of 300 tpd each)
Cost fil.OOOl
Baseline Combustion Good Combustion
Item Practices Practices
DIRECT COSTS:
Acid Gas Control3
Equipment Cost
Access/Congestion Cost
Particulate Control
Equipment Cost
Access/Congestion Cost
New Flue Gas Ducting
Ducting Cost
Access/Congestion Cost
Other Equipment
Fans
Stacks
Demol iti on/Relocation
Total
Indirect Costs and Contingencies
Monitoring Equipment
TOTAL CAPITAL COST
DOWNTIME COST
ANNUAL I ZED CAPITAL RECOVERY
AND DOWNTIME
674
67
3,210
802
295
74
959
0
0
6,080
2,560
771
9,410
437
1,300
674
67
2,150
S38
255
64
722
0
0
4,470
2,010
771
7,250
. 437
1,010
aBased on moderate access/congestion.
Turnkey.
4-107
-------
TABLE 4.3-6. PLANT ANNUAL COST FOR DRY SORBENT INJECTION WITH ESP
(Three units of 300 tpd each)
Cost tSI.OOP)
Baseline Combustion Good Combustion
Item Practices Practices
DIRECT COSTSJ
Operating Labor 72 72
Supervision 32 32
Maintenance Labor 20 20
Maintenance Materials 96 77
Electricity 97 58
Water 11 8
Lime 326 326
Waste Disposal 133 133
Monitors ' 309 309
Total 1,100 1,040
INDIRECT COSTS:
Overhead 152 141
Taxes, Insurance, and Administration 342 256
Capital Recovery and Downtime 1.300 1.010
Total 1,790 1,410
TOTAL ANNUALIZED COST 2,890 2,450
4-108
-------
The proposed equipment arrangement is shown in Figure 4.3-7. The new
equipment will be located primarily behind the existing stacks. The
250 feet of new ductwork will tied in just ahead of the ESP's, allowing them
to be deactivated and left in place. The existing stacks will also be
reused under this arrangement. The new lime receiving, storage and slurry
area will serve all three spray dryers.
Location of new equipment behind the existing stack will allow
continued combustor operation during construction. Downtime for tie-in is
expected to be approximately 1 month.
4.3.6.2 Environmental Performances. Total CDD/CDF emission reductions
of 99 percent or to 5 ng/dscm (whichever is higher), is expected. Emissions
of particulate matter will be reduced from 0.03 gr/dscf to 0.01 gr/dscf.
Acid gases will be reduced 90 percent for SO^ and 97 percent for HC1.
Solid waste will be increased with this technology relative to baseline
amounts. The total increases in solid waste (both sorbent and fly ash) is
4,690 tons per year for the plant.
4.3.6.3 Cost. Capital cost requirements for installing spray
dryer/fabric filter systems are presented in Table 4.3-7. Total capital
cost is estimated to be $34,300,000 and $29,400,000 for baseline.and good
combustion, respectively. Downtime cost is $437,000 for both cases.
Annual operating and maintenance costs and annual indirect costs are
presented in Table 4.3-8. Major operating expenses are for maintenance
materials and increased electricity use by the larger ID fan needed because
of the increased pressure drop across the fabric filters. Total annualized
cost of best acid gas control (including capital recovery and downtime) is
$8,750,000 per year for baseline, and $7,550,000 with good combustion
practices.
4.3.7 Summary of Control Optiojis
4.3.7.1 Description ofControl Options. The control technologies
described in the previous sections have been combined into seven retrofit
emission control options. These options are discussed in detail in
Section 3.0. Table 4.3-9 summarizes the combustion, temperature,
particulate, and acid gas control technologies described in Sections 4.3.3
4-109
-------
. New Spray Dryers,
Fabric Filters and Farts
Existing
ESP's
NewSorbem
Storage Silo
Figure 4,3-7.
Plot Plan of Spray Dryer/Fabric Filter Retrofit Equipment
Arrangement
4-110
-------
TABLE 4.3-7, PLANT CAPITAL COST FOR SPRAY DRYER WITH FABRIC FILTER
(Three units of 300 tpd)
Item
DIRECT COSTS;
Acid Gas and Part icul ate Control
Equipment Cost
Access/Congestion Cost
New Flue Gas Ducting
Ducting Cost
Access/Congestion Cost
Other Equipment
Fans
Stacks
Demolition/Relocation
Total
Indirect Costs
Monitoring Equipment3
Contingency
TOTAL CAPITAL COST
DOWNTIME COST
ANNUALIZED CAPITAL RECOVERY
AND DOWNTIME
Cost ($1
Baseline Combustion
Practices
15,300
3,840
534
134
1,130
0
20,900
6,920
859
5,580
34,300
437.
4,570
,000)
Good Combustion
Practices
3,290
3,390
461
115
849
0
0
17,900
5,910
859
4,761
29,400,
437
3,930
aTurnkey.
4-111
-------
TABLE 4.3-8- PUNT ANNUAL COST OF SPRAY DRYER WITH FABRIC FILTER
(Three units of 300 tpd each)
Cost (SI.0001
Baseline Combustion Good Combustion
Item Practices Practices
DIRECT COSTS:
Operating Labor
Supervision
Maintenance Labor
Maintenance Materials
Electricity
Compressed Air
Water
Lime
Waste Disposal
Monitors
Total
INDIRECT COSTS:
Overhead
Taxes, Insurance, and Administration
Capital Recovery and Downtime
Total
TOTAL ANNUAL I ZED COST
144
22
79a
584a
714
102
27
271
171
322
2,440
399
1,340
4.S70
6,310
8,750
144
22
79b
480°
534
76
20
270
174
322
2,120
312
1,140
3.930
5,430
7,SSO
alncludes $164,000 for bag replacement.
Includes $122,000 for bag replacement.
4-112
-------
TABU 4.3-9 SlimARY 0? CONTROL OPTIONS FOR CRATE/ROTARY KILN MASS BURN REFRACTORY-WALL OQMBUSTOR
Control. Option Description
Combustion Temperature
Modification* Control
P«rtlcul«tg Matter Control^
Exlttln* Additional
ESP Rebuilt PUte Area
Acid Cat Control
New Fabric Sorbent Spray
Filter Injection Dryer
1. Good Coobuitlon »rvd Tcofxrmtura Control
2. Good PH Control with Corabuition
and Teispacatur* Control
3, Bflit PH Control with Coabuitlon «nd
Teraper»cur« Control
4. Good Acid Gas Control and Beit PH
Control wlrh Temperature Control and
Baseline Combujcion
5. Cood Acid Cij Control-and Beat
PM Control with Combuitlon and
T«B]p«ratur« Control
6. Beat Acid Cat Control and Best PM Control
with Ten3»eratur« Control and Baseline
Combustion
?. Sett Acid Gai Control and Best PM Control
with Combustion and T«o|>«rature Control
-------
through 4.3.6 that were combined for each of the control options. It should
be noted that because good PM control is already achieved by the model plant
at baseline, Option 1 and Option 2 are identical. Since good combustion
control also reduces PM emissions to 0.01 gr/dscf, Option 3 is also the same
as Options 1 and 2.
4.3.7.2 Environmental Performance, The performance of each control
option is summarized in Table 4.3-10. For each pollutant the table presents
both the pollutant concentrations and annual emissions. The greatest
reductions in acid gases and total CDD/CDF are achieved with the spray
dryer/fabric filter systems. The next most effective control for these
pollutants is dry sorbent injection. Combustion control provides similar
control of COD/CDF to duct sorbent injection, but also reduces CO emissions
and lowers flue gas volumes, resulting in reduced PH emissions as well.
4.3.7.3 Costs. .The total annualized cost of each option is presented
in Table 4.3-11. The most effective control options are also the most
costly, with the exception of the options where APCO's are combined with
good combustion practices. For Options 5 and 7, the cost of combustion
modifications is recovered by the reduced cost of PM control equipment
resulting from reduced flue gas volume. Thus, Options 5 and 7 are less
costly overall than the same type APCD's installed with baseline combustion
gas volumes (Options 4 and 6).
4.3.7.4 Energy Impacts. Table 4.3-12 presents a summary of the energy
impacts associated with the control options. The incremental energy use
shown includes the electrical savings realized by not operating the existing.
ESP under Options 6 and 7. The auxiliary fuel use is calculated from
12 startups and shutdowns per year with auxiliary burners providing
60 percent of the thermal load.
4-114
-------
TAILS *.}-lo DmBomoiTAt PERFORMANCE suttuxt n» OUIE/RDTAHY IILH REFRACTORY-WALL me MODEL PLAHT
RETROFIT CONTROL OPTIOKS* (This* unit* of 300 tpd ucli)
total COO /CDF Eal«»Lon*
(n*/d»ca)
6
fljljff
I Reduction vs. Beaellne
CO bait lions
tppsw)
H*/jr
X Reduction vs. Baseline
PM Bnlsslon*
(tc/dse<)
Kg/ ye
1 Reduction vs. Baseline
SO. Emissions
fpponr)
Hg/yr
I Reduction vs. Baseline
BC1 Eoilsilons
(PP«r)
Mg/yr
X Reduction vs. B«s«lln*
Total Solid lisst*
(toiu/da?)
H«/yr
I Inerssse vs. Ba-allna
»«.im.
6000
7.0S-J
--
SCO
7JO
—
0.03
•0
™
200
86?
—
500
951
* —
270
81,800
*""*
Option 1
300
S.6B-4
92
ISO
216
70
0.01
2?
0
200
66?
0
500
951
0
270
•1,800
0
Option 2
500
S.6E-4
92
150
216
70
0.01
2?
0
200
66?
0 .
500
951
0
270
81,800
0
Option I
soo
S.BE-4
92
ISO
216
70
0.01
27
67
200
66?
0
500
931
0
270
81,000
0
Option 4
1000
1.2E-3
83
500
7)0
0
0.01
27
6?
100
334
50
250
476
SO
286
86, £00
6
Option S
125
1.4E-4
90
ISO
216
70
0.01
2?
67
100
334
SO
250
476
SO
286
86,100
6
Option 6
40
S.OE-S
99.3
500
710
0
0.01
27
6?
19
63
90.5
IS
2?
97
291
88,200
a
Option 7
S
7.08*6
99.9
150
216
70
0.01
27
6?
19
63
90.5
15
2?
9?
2»1
88,200
a
All flu* |St conc«ntr»tlon» «r« nporttd an » 71 O_ bad*. Hotmil mad (CuvUrd conditions scs 1 staesph*r* and 7Q°F.
-------
TABU 4.1-11 COSf StMURf FOR CRATE/ROTARY IILB REFRACTORY-HALL MIC KfflEL PLANT RETROFIT CONTROL OPTIOHS
(Thra* unit* of 300 tpd «ach)
Downtime Coat
Direct 0 I M Coat
Total Annual Coat
Coat Effactlvan*aa
($/ton KSH)
Facility Down11m.
(Months)
Total Compliant* Tim*
(Month.)
Option 1
Option 2
Option 3
Option 4
Option 5 Option 6 Option 1
Total Capital Coat
Dotmttflw Coat
Anmialliad Capital and
1,130
10$
163
1,130
109
163
1,130
109
163
9,410
437
1,300
8,380
43?
1,160
34,300
437
4,570
30.500
437
4,080
171
429
1.43
0.2S
171
429
1.43
0.25
171
429
1.43
0.25
19
1,100
2,890
9.63
1,210
2,860
9.51
2,440 2,290
8,750 7,960
29.20 26.50
19
25
"all coata (•xcapt coat affactlwtnaia) given In $1000. All coata |lv«n ID Dacambar 1987 dollar*.
-------
TABLE 4.3-12. ENERSY IMPACTS FOR GRATE/ROTARY KILN MASS BURN
REFRACTORY-WALL HWC CONTROL OPTIONS1
Option
1
2
3
4
5
6
7
Electrical Use
(MHh/yr)
0
0
0
2,100
1,260
15,5QQb
ll»600b
Gas Use
(Bty/yr)
1.5E10
1.5E10
1.5E10
0
1.5E10
0
1.5E10
alneremental use from baseline.
Excludes the electrical credit for not operating the ESP's.
4-117
-------
4,4 REFERENCES
1. Lamb, L,, Radlarr Corporation, Schindler, P., Energy and Environmental
Research Corporation. Trip Report - Retrofit Control Site Evaluation at
the Philadelphia Northwest Incinerator and East Central Facility.
January 19, 1989.
2. Schindler, P. EER Corporation, Combustion Control Memorandum - Existing
HWCs. October 31, 1988.
3. Schindler, P., Energy and Environmental Research Corporation, and
Emmel, T., Radian Corporation. HWC Site Evaluation - Sheboygan, WI
Incinerator Harch 25, 1988.
4. Epner, E., Radian Corporation, and Schindler, P., Energy and
Environmental Research Corporation. Trip Report - Retrofit Control Site
Evaluation at the North Dayton and South Dayton Municipal Waste
Incinerators. March 22, 1988.
5. ASTH. AB88-J. C, 0.19%; Cu, 0.25-0.4%; Mn, 0,8-1.25%; Pb, 0.04% max.;
S, 0.05% max; Si, 0.3-0.65%; Ni, 0.4% max; Cr, 0.4-0.65%; V, 0.02-0.1%.
4-118
-------
5.0 MASS BURN WATERWALL COMBUSTORS
One of the predominant technologies in the existing population of MWC's
is the mass burn waterwall design. This section describes the current design
and operation of newer waterwall combustors and identifies features in the
design and operation which minimize air emissions.
The existing population of mass burn waterwall MWC's consists of
24 operating plants (S6 individual units). Table 5.0-1 lists the mass burn
waterwall plants operating or in start-up as of 1988. Included in the table
are number of units, unit capacity, year of start-up, and APCD in place at
each plant. Individual combustor design capacities range from SO to
1000 tons/day of MSW. The table is divided into three sections, representing
large mass burn waterwalls with individual capacities of more than 600 tpd,
mid-size units with individual capacities between 250 and 600 tpd, and small
units with Individual capacities of less than 250 tpd. Nineteen plants in
this category use ISP's for particulate control. One plant uses dry lime
injection into the furnace followed by an ESP and one plant uses dry lime
injection into a duct followed by a fabric filter. Five other plants use a
spray dryer followed by either a fabric filter or an ESP. Most of these
plants are publicly owned and operate on a 24-hours/day, 7-days/week schedule.
Typical mass burn waterwall systems are shown in Figures 5.1-1, 5.2-1,
5.2-2, and 5.2-3, Unprocessed waste (with large, bulky, non-combustibles
removed) is delivered by an overhead crane to a feed hopper from which it is
fed into the combustion chamber. Earlier mass burn designs utilized gravity
feeders, but it is more typical today for feeding to be accomplished by single
or dual hydraulic rams that operate on a set frequency. The ram frequency is
usually a manual setting, but some newer facilities are incorporating ram
feeder speed into the automatic combustion control system.
Nearly all modern conventional mass burn facilities utilize reciprocating
grates to move the waste through the combustion chamber. The grates typically
Include two or three separate sections where designated stages in the
combustion process occur. For example, the Initial grate section is referred
to as the drying grate, where the moisture content of the waste 1s removed
5-1
-------
TAILS 5.0-1. EXISTING MASS BITRN WATESHALL CCMBUSTORS
tn
i
ro
Plant/Location
MlUbury. MA
PLrwllaa Count T. Ft
Horth AiuS«v«c, HA
Sauaua, MA
tl»Meh»»t«r County, m
Baltimore, MD (EE3QO)
Bridgeport, CI
Otloaso, IL (MW)
»a»hvtlla, TH
HllLcborough County, FL
tuts*, OK
Barrl»bur|, FA
Alexandria, V*
Coon»ree>, CA
Merlon County, OK
JJorfolk «av»l Station, VA
Glwt Gova, KY
H»mpton, VA
K«v Ouiovcr County, MC
Cl.r«oot, HH
J*ek*on County, MI
K*r "••». n.
a«rrl»onbur«, VA
Oliuti&d County, MB
Ho. of Unit*
2
1
1
2
3
$
S
*
J
1
2
2
J
1
2
I
2
2
2
2
2
2
2
2
Unit Site
(tpd)
750
1000
740
750
750
750
750
400
2 i 360
1 8 400
400
175
360
125
JOO
ITS
180
12S
100
100
100
100
75
SO
100
Yc.r of
St«t Up
1988
198J
1985
1973
1984
1981
1986
1970
1974
1986
1987
1986
1873
1987
19B7
I486
1967
1983
isao
1984
1987
1967
1987
1982
1988
Air Pollution Control D«vlc«
Dry Scrubb«r/ESP
Blactroitctlc Pr«clplt«tor
El»etro»t«tlo Pr*cl.plt»tor
El«ctro»t«tlc Pr«ciplt«tor
ElcctrottAtIc Prcclpltator
El«ctroit*tlc Pr«clplt*cor
Dry Scrubb«r/F«brlc filter
El*6troct*tlc Pr«clplt»tor
El«ctro>c*clc Pr«ctplt»tor
El»ctro»t»tlc Prcclpltator
EL«ctroit»tlo Pr«clpltttor
Elcctiattatlc Pcictpltctur
El*ccro>tmtlc Pccclpltator
FurMC' Lint Injection/
Bl«<:tro«t»tlc Pr«clplt«tor
Dry Scrubb»rfF«brlc FlLtar
Dry Secubb*c|P*brle Fllt«r
Elcctrojtatic Pr*clplt*tor
Blaetroautic Pr«clplt«tot
Elcctrojtattc Pr«clplt»tor
Ei*ctto«taclc Pr*cl|>lt*tor
Duct Lima In j. /Fabric FUt«r
Dry Scmbbar/Pabrlc Filter
Elactroitatlc Praclpltacor
ElactcoitaClc Pr«clplt»cor
El«ctro»tatlc Praelpltatoc
-------
prior to ignition. The second grate section is the burning grate, where the
majority of active burning takes place. The third grate section is referred
to as the burnout or finishing grate, where remaining combustibles are burned.
Smaller units may include two rather than three individual grate sections. In
a typical mass burn waterwall system, bottom ash is discharged from the
finishing grate into a water-filled ash quench pit. Dry ash systems have been
used in some designs, but are not widespread.
Combustion air is added to the waste from beneath the grate by way of
underfire air plenums. The majority of mass burn waterwall systems supply
underfire air to the Individual grate sections through multiple plenums. The
ability to control heat release from the waste bed is enhanced by separately
controllable underfire air supplies. The lower furnace is generally lined
with castable refractory such as silicon carbide, to prevent excessive heat
removal in the lower furnace by waterwall tubes.
As the waste bed burns, additional air is required to oxidize fuel-rich
gases and complete the combustion process. Overfire air 1s Injected through
rows of high-pressure nozzles (usually 2 to 3 inches in diameter). Properly
designed and operated overfire air systems are essential for good mixing and
burnout of organics in the flue gas. Overfire air jets should provide
complete coverage and penetration of the furnace cross-section. Proper
overfire air system design usually requires flow modeling studies, but may be
accomplished by ensuring design consistency with systems for which good
performance has been verified.
Typically, mass burn waterwall MWC's are operated with 80 to 100 percent
excess air. Normally 25 to 40 percent of total air is supplied as overfire
air and 60 to 75 percent as underfire air. These are nominal ranges that may
vary between specific designs. Continuous oxygen monitors are typically
located at the exit of the boiler or economizer to verify the excess air
operating levels.
Most heat recovery systems incorporate temperature monitoring at various
locations through the system. One reference point is the furnace exit gas
temperature, where flue gases leave the radiant furnace and enter the
superheater and convective passes of the boiler. Another typical location 1s
at the boiler or economizer outlet. Typical superheater Inlet temperatures
are in the range of 1400 to 1SOO°F. Economizer outlet temperatures vary from
5-3
-------
3SO to 600°F based on the amount of heat removal through the system,
The most common combustion control system used in mass burn waterwall
technology utilizes automatic feedback from steam flows or pressures to
underfire air. The underfire air flowrate automatically varies to maintain
desired steam level setpoints. Some more recent designs incorporate oxygen
trim loops, ram feeder speed controls, grate speed controls, and temperature
control loops.
Guidelines for minimizing emissions of trace organics have been developed
for mass burn waterwall combustors, A list of design, operation/control, and
verification components associated with the guidelines is presented in
Table 5.0-2. The basic guidelines require that:
o stable stoichiometries be maintained through proper distribution of
fuel and combustion air,
o good mixing be achieved at a sufficiently high temperature to
adequately destroy trace organic species, and
o the design and operation of the system be verified through
monitoring or performance tests.
The majority of existing mass burn waterwall MWC's employ most of the design
features of good combustion. This is due in part to the fact that most of
these plants are less than five years old and incorporate refinements in
technology that have resulted in many design improvements. The following
discussion focuses on elements of concern to mass burn waterwall systems,
Combustion Air
A major area of concern in older mass burn waterwall systems is the
design of overfire air systems. Several existing facilities have undertaken
retrofits to improve the design in these systems. Improvements in the
performance of overfire air systems can-be verified by the relatively low
levels of organic and CO emissions, which indicates good mixing and oxidation
of combustion gases with overfire air.
Auxiliary Fuel
All existing facilities in this subpopulation are expected to be able to
meet the temperature design requirement, and multiple underfire air plenums
with separate controls are in place at most operating facilities. Although
new MWC's are expected to have auxiliary fuel firing capabilities, many of the
older units do not. One facility built in 1984 (New Hanover County, NC) is
5-4
-------
TABLE 5.0-2 COMPONENTS OF GUIDELINES -
GOOD COMBUSTION PRACTICES FOR MINIMIZING TRACE ORGANIC
EMISSIONS FROM MASS BURN MWC's
Element
Component
Design
Operation/Control
Verication
Temperature at fully mixed height
Underfire air control
Overfire air capacity
Overfire air Injector design
Furnace exit gas temperature
Excess Air
Turndown restrictions
Start-up procedures
Use of auxiliary fuel
Oxygen in flue gas
CO in flue gas
Furnace temperature
Temperature at APCD inlet
Adequate air distribution
5-5
-------
not equipped with auxiliary fuel, although a planned expansion reportedly will
Include natural gas burners in a new unit.
Operatlon/Control
The operation/control elements specified in Table S.0-2 are also largely
in place in most operating units. A few exceptions may be low load operating
limits and conditions of auxiliary fuel use. The mass burn waterwall units
reportedly operate at close to design load whenever possible, and more
facilities are becoming electrical generators rather than simply following
load demand of a steam customer. For other facilities, load levels can be
dictated by waste availability as well as steam demand, but load reductions
for mass burn water-wall systems are more likely due to the latter. Those
systems without auxiliary fuel must start-up and shutdown on waste alone.
However, mass burn water-wall* systems typically operate continuously with as
few unscheduled shutdowns as possible.
All mass burn waterwall systems are expected to be equipped with oxygen *
monitors and thermocouples for temperature measurements. These are necessary
requirements for ensuring proper boiler operation. However, CO monitors are
less likely to be in place in most operating units, with the exception of
facilities where State requirements include CO monitoring. In addition, most
existing units are not expected to have performed CO profiling studies to
establish combustion air distribution patterns. Therefore, verification of
proper air distributions in existing systems are largely based on continuous
oxygen and temperature measurements and visual observation of waste burning
conditions.
Temperature Control
As discussed in Section 4.0, recent data suggest that COO/CDF formation
may occur downstream at temperatures between 500 and 6QO°F. This is a typical
operating temperature for many ESP's in the waste combustion industry. Based *
on available data it appears that formation does not occur at temperatures of
450°F or less. Therefore, existing systems must attempt to minimize retention
time of flue gases in the range of 500 to 600°F by lowering ESP operating
temperatures.
5-6
-------
5.1 LARGE MASS BURN WATERWALL COHBUSTOR
This section presents the retrofit case study results for a large mass
burn waterwall municipal waste combustor (MWC). This subcategory comprises
mass burn waterwall combustors with individual corabustor capacities of more
than 600 tpd. As shown in Table 5.0-1, there are 7 known plants in this
subcategory. Section 5.1.1 presents a description of the Saugus MWC plant,
which was visited in order to gather information for model development.
Section 1.1.2 presents a description of the model plant. Section 5.1.3
through 5.1.7 detail the retrofit modifications, estimated performance, and
costs associated with various control options. Section 5.1.8 presents a
summary of control options, which are discussed in more detail in
Section 3.0 of this report.
2
5.1.1 Descr i p t i on o f $ a ug u s P1 ant
The Saugus facility consists of two mass burn waterwall combustors.
Each is rated at 750 tons per day of municipal solid waste. Table 5.1-1
presents design and operating data for the plant. The plant was started up
in October 1975, and currently serves 19 Boston North Shore communities.
The project was financed by industrial revenue bonds (75 percent) and
private equity (25 percent). All steam is used on site to generated
electricity which is sold to New England Power Company. Figure 5.1-1
illustrates the general system configuration.
5.1.1.1 CombustorDesign and Operation. This plant was the first
large Von Roll design built in the U.S., and is typical of the type of
system supplied by Von Roll in the mid-1970's. There is no ram feeder.
Fuel feeding is by gravity and is controlled by the speed of the first
grate. The facility burns a combination of municipal and commercial waste.
Currently, only about 15 percent of the refuse burned is commercial. No
auxiliary fuel is available. The units operate continuously, 7-days/week.
There are three reciprocating grates in each combustor. They are
designated as the feed grate, burning grate, and burnout grate. There are
1-meter vertical steps from the feed grate to the burning grate, and from
the burning grate to the burnout grate. This is not typical of the other
5-7
-------
TABLE 5.1-1. SAUGUS, MASSACHUSETTS DESIGN DATA
Combustor:
Type
Number of Combustors
Combustor Unit Capacity
Srate Manufacturer
Boiler Manufacturer
Emission Controls:
Type
Manufacturer
Number of Fields
Inlet Design Participate Loading
Operating Temperature
Design Collection Efficiency
Particulate Emission Limit
Gas Flow
Original Design
Revised Design
Operating
Total Plate Area
SCA at 180,00 acfm
Residence Time
Mass Burn Water-wall
2
710
Van Roll
Dominion Bridge
Electrostatic Precipitator
Wheelabrator-Frye
2
0.2 to 2.0 ar/dscf
428 to 550°F
97.5 percent
0.05 gr/dscf
240,000 acfm
200,000 acfm
180,000 acfrn
41,745 ft*
232
5.8 seconds
5-8
-------
I/I
3
o»
fO
trt
%~
to
•^
a
fO
01
01
3
O>
-------
plants of this design type, which have eliminated the use of large grate
steps in their design. The stepped grates may contribute to flashing of the
waste as it tumbles from one section to another, making combustion control
more difficult.
Bottom ash is discharged to a wet quench system. The bottom ash is
then trommeled, and ferrous materials are separated and recovered. The
remaining bottom ash is then combined with fly ash and disposed of in an
adjacent landfill. The landfill -is owned by OeHatteo Construction, which
has a 50 percent interest in the facility.
There are six pairs of air plenums supplying underfire air--three pairs
are located beneath the burning grate and three pairs beneath the burnout
grate. The underfire air flows are adjusted manually to each plenum.
Adjustments are made based on burning conditions and waste characteristics.
The feed grate is equipped with two siftings hoppers but not an underfire
air supply. The air is not preheated. Underfire air is generally 55 to
70 percent, of total air.
The overfire air system was redesigned as part of a larger modification
implemented in the late 1970's. There are two rows of 3-inch diameter
nozzles on the combustor front wall and one row of 3-inch nozzles on the
rear wall. There are nine nozzles in the front wall upper row, spaced
28.5 inches apart. The lower row on the front wall contains ten nozzles
spaced 28.1 inches apart. There are fifteen nozzles on the rear wall,
spaced 18.75 inches apart. Side wall overfire air nozzles are also in
place, but are not currently used. Overfire air nozzle pressures are
measured in the supply headers. Jet penetration is verified by calculation
using the nozzle pressure and by visual observation of the furnace. The
owner/operator also stated that CO profiling and flow modeling are used to
establish overfire air firing patterns, and that they consider both of these
activities to be necessary at new facilities.
The furnace design excess air level is 100 percent (200 percent
theoretical air). Changes in excess air are made by varying underfire air
and holding overfire air constant.
Each combustor is equipped with a Dominion Bridge boiler rated at
188,500 Ib/hr of 675 psi, 875°F steam. Current operating conditions are
165,000 Ib/hr, 650 psi, 850°F. Soot is removed from the boiler tubes by
5-10
-------
mechanical rapping, which takes place for five minutes once every hour.
Electricity is generated in General Electric steam turbine generator sets,
with a total capacity of 40 MW,
In addition to redesigning the overfire air system, additional
combustor and boiler modifications have been made at Saugus. Arches have
been added in the front and rear walls, and the upper combustion chamber has
been reconfigured. In addition, the superheater section was moved further
downstream and screen tubes were added prior to the superheater. After
experimenting with tube materials the superheater tubes were replaced with
Inconel tubes.
Although the newer Wheelabrator plants typically use a fully automatic
computerized combustion control system, the Saugus plant uses a pneumatic
type control system. Air flows and grate speeds are adjusted automatically
based on steam pressure. In addition, a number of operating variables are
monitored and serve as a guide to good operation. These include: 02 at
the economizer outlet; temperature in the upper furnace and at the
economizer outlet; and steam and water flow rates, temperatures, and
pressures.
Since no auxiliary fuel is used, the system is started up cold. First,
the hopper doors are opened and the feed hopper is charged with refuse up to
the normal operating level. Next, the grates are started and run
intermittently until a refuse bed has been established. The induced-draft
fan and the ESP's are also started at this time. The refuse is then lit
manually, and the underfire and overfire air fans are started. The
fuel-to-air ratio is controlled until stable conditions are reached, usually
in two to three hours.
5.1.1,2 Emission Control Design and Operation. Each combustor is
equipped with 2-field ESP. The ESP's have 97.5 percent design particulate
control efficiencies. Table 5.1-1 summarizes pertinent ESP design and
operating parameters. Each ESP operates with a gas flow of 180,000 acfm,
and operating temperatures were reported to vary from 428 to 550°F depending
on boiler conditions and cleanliness. There is a 31'-8" horizontal duct run
from the economizer outlet to the ESP inlet. The State is requiring
5-11
-------
retrofit of acid gas controls by June 1, 1989. tfheelabrator anticipates
demolishing the existing ESP's ind installing spray dryers followed by
fabric filters to achieve the State emission levels.
5.1.2 Description of Model Plant
5.1.2.1 Comfaustor Design and Operation. There are 7 operating plants
in the existing population for large mass burn waterwall combustors. With
the exception of Saugus, which began operating in 1975, the plants have all
been built since 1982. Typical unit size is 750 tpd, except at Pinellas
County, Florida where three 1000-tpd units are in place. Based on the
distribution of unit sizes and numbers at the operating plants, the model
for this subcategory is assumed to include three units with individual
capacities of 750 tpd (total plant capacity 2,250 tpd).
Table 5.1-2 presents baseline data for the model plant. The physical
configuration of the model plant is similar to the current design of the
Saugus plant except that the model includes a ram feeder and several other
design features which are more typical of the existing population. Each
unit has three reciprocating grate section equipped with multiple,
individual controlled underfire air plenums. Air preheat is available for
use when firing wet refuse. Overfire air comprises 30 percent of total
combustion air. It is assumed that overfire air firing patterns are
established during initial start-up by in-furnace CO profiling. Each
combustor operates at 100 percent excess air. Auxiliary fuel burners are
available to provide 60 percent of the thermal load. The combustor
arrangement is the same as shown in Figure 5.1-1 with the exception of the
stepped grates, since the majority of the plants in this subcategory do not
use stepped grates. A plot plant of the model plant is shown in
Figure 5.1-2.
Each combustor is equipped with a boiler rated at 188,500 Ib/hr of
675 psi, 875°F steam. Normal operation is 95 percent of rated capacity
(179,000 Ib/hr). Soot removal cycles are hourly, achieved by mechanical
rapping. Waste volume reduction is estimated to be 90 percent and weight
reduction 70 percent.
5-12
-------
TABLE 5.1-2.
MODEL PLANT BASELINE DATA FOR LARGE
MASS BURN WATERWALL COMBUSTOR
Combustor:
Type
Number of Corobustors
Combustor Unit Capacity
Emission Controls
Type
Number of Fields
Inlet Temperature
Collection Efficiency
Gas Flow
Total Plate Area
SCA at 187,500 cfm
Emissions:3
CDD/CDF
PM (stack)
CO
HC1
so2
Stack Parameters;
Height
Diameter
Operating Data:
Remaining Plant Life
Annual Operating Hours
Annual Operating Cost
Mass Burn Waterwall
3
750
Electrostatic Precipitator
450°F
99 percent
187,500 acfn
73,800 ftz
394
500 ng/dscm h
0.02 gr/dscf°
50 ppmv
500 ppmv
200 ppmv
230 feet
9.5 feet
> 20 years
8,000 hours
$16,500,00/year
aAll emissions are dry, corrected to 7 percent 02-
Inlet PM emissions to the ESP are 2.0 gr/dscf at 7 percent
5-13
-------
Stack i~10' I.D.)
o q
Existing Incinerator Building
S
«
n
s
S
Figure 5.1-2. Plot plan of the model plant.
S-14
-------
Combustion controls are largely automatic. The ram feeder frequency Is
modulated along with the underfire air to the middle region of the grate to
maintain desired steam production levels. Grate speeds are adjusted
manually. An oxygen monitor is located at the economizer exit.
Temperatures are measured in the upper combustion chamber just prior to the
convective section of the boiler, and at the economizer outlet. Based on an
examination of the plants in this category, an economizer outlet temperature
of 450°F is selected for the model plant.
At 100 percent excess air, total combustion air requirements are
90,300 scfin. Seventy percent of this figure (63,200 scfm) is supplied as
underfire air and 30 percent (27,100 scfm) is overfire air. Assuming that
all of the combustibles become flue gas products, and that there is no air
inleakage to the combustor, the flue gas flow rate exiting the boiler is
approximately 100,800 scfm (93,100 dscfm).
5.1.2.2 Emission Control System DesignandOperation. As shown in
Table 5.0-1, all 7 plants in the subcategory are equipped with ESP's.
Although the Saugus plant has a 2-field ESP that achieves 97.5 percent PM
removal and has emissions of less than 0.03 gr/dscf, the other five plants
in this subcategory are equipped with ESP's that have at least three fields
and achieve at least 99 percent PM removal. Available test data from three
of these plants show PM emissions of less than 0.01 gr/dscf. Therefore, a
3-field ESP that achieves 99 percent PM removal is most representative
of the existing population.
5.1.2.3 "Environmental Baseline. Table 5.1-2 also presents the
environmental baseline emission rates for the model plant. CDD/CDF
stack emission data are available for 5 of the 7 facilities in the
population. In addition, simultaneous uncontrolled and controlled CDD/CDF
emissions were measured at four of these facilities. Based on these
available data sets, average uncontrolled emissions of 500 ng/dscm CDD/CDF
(tetra- through octa-} corrected to 7 percent 0- are selected as a baseline
emissions rate for the model.
Available data for the 6 of the 7 plants also supports an average CO
emission value of 50 ppm and an average uncontrolled PM emission value of
2.0 gr/dscf, both corrected to 7 percent (L.
5-15
-------
Air emissions of HC1 and SO- are largely dependent on waste feed
content and do not vary appreciably due to combustion conditions. Changes
in the chlorine and sulfur contents of the waste feed will directly affect
HC1 and SCL emissions. Based on the assumed waste composition used for this
study, uncontrolled HC1 and SCL emissions are estimated at 500 ppmv and
200 ppmv, respectively, both corrected at 7 percent 0-.
Assuming a waste volume reductions of 90 percent, weight reductions of
70 percent, and a nominal 750 tons of MSW per day, the total ash (dry) is
estimated to be 22S tons/day. It is assumed that the bottom ash and fly ash
are mixed and co-disposed, as is the practice at Saugus.
S.I.3 Good Combustion
The model plant has good combustion practices in place when considering
design and operational features. Combustion controls are also judged to be
state-of-the-art. The only additional requirement for the model plant is to
install continuous CO monitors at the same location as the existing Oj
monitors to verify CO emission levels.
5.1.3.1 Costs. Table 5.1-3 presents capital and annual operating
costs for installation of CO monitors. Capital costs of CO monitors for the
model plants are estimated at $86,000, including readouts and integrators.
The annualized capital cost is $11,000, based on a 10 percent interest rate
and 15-year facility life. Total annualized costs are estimated to be
$169,000 per year.
5.1.4 Good Particulate Control
The existing ESP's are assumed to reduce PM loadings from 2.0 gr/dscf
at the ESP inlet to 0.02 gr/dscf at the outlet, operating at 450°F. Because
the existing ESP's can reduce PM emissions below that required for good PM
control (0,05 gr/dscf}, no equipment modifications are required for this
model plant to achieve good particulate control.
5.1.5 Best Particulate Control
5.1.5.1 Description of Modification. The existing ESP's have
sufficient plate area to achieve best particulate control (0.01 gr/dscf PM
emissions), but will require rebuilding to replace worn or damaged internal
components (plates, frame, and electrodes), upgrading of controls and
S-16
-------
TABLE 5.1-3. PLANT CAPITAL AND ANNUAL OPERATING COSTS FOR
COMBUSTION MODIFICATIONS
(Three units of 750 tpd each)
Item Costs ($1000)
CAPITAL COSTS:
Direct Costs:
CO monitors 66
Total 66
Indirect Cost and Contingency ' 20
TOTAL CAPITAL COST 86
Downtime Cost 0
Annualized Capital Recovery 11
ANNUAL OPERATING COSTS:
Direct Costs:
Maintenance Labor 42
Maintenance Materials 42
Total 84
Indirect Costs:
Overhead 50
Taxes, Insurance, and Administration 3
Capital Recovery II
Total 64
TOTAL ANNUALIZED COST 148
5-17
-------
electronics for more effective energization, and flow modeling to evaluate
gas distribution. No additional plate area or changes in plate-electrode
geometry are required. Downtime for this rebuild will be approximately
2 months for each unit.
5.1.5.2 Environmental Performance. Particulate matter emissions will
be reduced from 0.02 to 0.01 gr/dscf. The additional recovered fly ash will
add roughly 73 tons/yr to total solid waste disposal requirements. This is
a 0.5 percent increase in fly ash to disposal. Emissions for CDD/CDF and
acid gases are equal to the concentrations at the cotnbustor exit.
5.1.5.3 Costs. Total capital cost requirements for best participate
control, presented in Table 5.1-4, are estimated at $1,990,000. This
includes purchased equipment, installation, and indirect costs such as
engineering and contingencies. Estimates assume a moderate APCO congestion
factor for the ESP, and high APCD congestion factor for the ducting used for
temperature control.
Annual costs are presented in Table 5.1-5 for best particulate control.
The costs are dominated by annualized capital recovery and downtime.
Indirect costs including capital recovery and downtime are estimated
$959,000. Direct O&M costs are estimated at $2,000 per year. Total
annualized costs are estimated at $961,000 per year.
5.1.6 Good Acid Gas Control
5.1.6.1 Description of Modification. To achieve good acid gas
control, dry sorbent will be injected into the combustor through existing
overfire air ports. Duct sorbent injection was not considered because of
limited space between the economizer and the ESP. To reduce the inlet flue
gas temperature to 350°F, water will be sprayed into the ductwork between
the economizer and the ESP for each combustor. Demolition of the existing
ductwork between the economizer and the ESP is required for installing
32 feet of new ducting fabricated with water spray nozzles. The fabricated
ducting has the same cross-sectional area of the existing ducting, because
5-18
-------
Stack (~1
X^X
ExMSng IndfMntor Budding
Figure 5.1-3. Plot Plan of Particulatt Control Equipment
5-19
-------
TABLE 5.1-4. PLANT CAPITAL COST FOR PARTICULATE MATTER CONTROL
(Three units of 750 tpd each)
Item . Costs ($1000)
DIRECT COSTS:
PH Control3
Equipment (Rebuild ESP) 1,660
Access/Congestion Cost NA
New Flue Gas Ducting3
Ducting Costs NA
Access/Congestion Cost NA
Other Equipment
Fan NA
Stack NA
Demolition/Relocation NA
Total 1,660
Indirect Costs and Contingencies 336
Monitoring Equipment 0
TOTAL CAPITAL COST 1,990
DOWfTIHE COSTS 5,300
ANNUALIZED CAPITAL RECOVERY AND
DOWNTIME 959
Based on moderate access/congestion.
bTurnkey.
CNA - not applicable.
5-20
-------
TABLE 5.1-5 PLANT ANNUAL COST FOR PARTICULATE MATTER AND TEMPERATURE
CONTROLS (Three units of 750 tpd eich)
Item Costs ($1000)
DIRECT COSTS:
Operating Labor , 0
Supervision 0
Maintenance Labor 0
Maintenance Materials 0
Electricity 0
Water 0
Waste Disposal 2
Monitors _0
Total 2
1HDIRECT COSTS:
Overhead 0
Taxes, Insurance, and
Administration 0
Capital Recovery and
Downtime 959
Total 959
TOTAL ANHUALIZED COST 961
5-21
-------
enough residence time is already available for flue gas cooling
(2.9 seconds) in the existing ductwork. A water rate of 39 gpm per
combustor is required to cool the flue gas to 350°F.
New equipment for sorbent injection includes two storage silos, a
pneumatic sorbent system, six sorbent feed bins (two for each combustor},
and six pneumatic injection nozzles (two for each combustor). Hydrated lime
sorbent will be fed at a calcium-to-acid gas molar ratio of 2:1. At
full-load, a sorbent injection rate of 878 Ib/hr is required for each
combustor.
In addition, the existing ESP will require a new ESP field to reduce PM
emissions to 0.01 gr/dscf. This field is attached to each of the existing
ESPs. The additional plate area for each ESP is 24,600 ft . New I.D. fans
are also required to handle the additional pressure drop of the new field
and ductwork. The project also includes monitoring equipment for HC1, SO.,
0., and opacity. Monitors for HC1, SO-, 0., and opacity will be located at
the outlet of each ESP. Figure 5.1-4 shows the retrofit changes. Downtime
is expected to be 2 months.
5.1.6.2 Environmental Performance. Total COO/COF emissions are
expected to be reduced by 75 percent. Acid gas emission reductions are
estimated at 50 percent for HC1 and 10 percent for SO-, respectively. As
noted above, PM emissions would be reduced to 0.01 gr/dscf. An additional
13,600 tons/year of waste (sorbent and fly ash) will be added to the
baseline waste disposal requirements for the plant.
5.1.6.3 Costs. Capital cost requirements for dry sorbent injection
are presented in Table 5.1-6, Most of the cost is associated with
temperature and particulate control equipment. Total capital cost is
estimated at $7,740,000. This cost estimate assumes a moderate APCD
access/congestion level and for sorbent injection and ESP upgrade, a high
APCD access/congestion for the ducting used for temperature control,
ductwork demolition of 60 feet per combustor, and new ID fans.
5-22
-------
«**(*" 10* 1-0.)
ill
X
x, ,--'
i 1
. — '
vt%
X
New I.D. F«n«
^r^
^ / \
/ \
s«
...*:*, r-.'...
t i
*"*
X
H
ExMIng IndMnnor SuRdlng
Figure 5.1-4. Plot Plan of Sorbent Injection Equipment Arrangement
5-23
-------
TABLE 5.1-6. PLANT CAPITAL COST FOR DRY SuRBENT INJECTION
WITH ADDITION OF ESP PLATE AREA
(Three units of 750 tpd each)
Item Costs ($1000)
DIRECT COSTS:
Acid Gas Control3
Equipment 896
Access/Congestion Cost 90
Particulate and Temperature Control3'
Equipment 3,530
Access/Congestion Cost 68?
New Flue Gas Ducting3
Ducting Cost 304
Access/Congestion Cost , 88
Other Equipment
Fan 931
Stacks 0
Demolition/Relocation 50
Total 6,570
Indirect Cost & Contingencies 2,760
C
Monitoring Equipment 859
TOTAL CAPITAL COST 10,200
DOWNTIME COSTS 5,300
ANNUALIZED CAPITAL RECOVERY AND
DOWNTIME 2,040
aBased on moderate access/congestion.
Based on high access/congestion for ducting of temperature control
cTurnkey.
5-24
-------
Annual O&M and indirect costs are presented in Table 5.1-7, Major
direct operating costs are associated with lime, solid waste disposal, and
monitor maintenance.- The largest annualized cost is capital recovery and
downtime. The total annualized cost for the control option is S3,650,000
per year.
S.I.7 Best Acid Gas Control
5.1.7.1 Description of Modifications. To achieve greater reductions
of CDD/CDF, SO-, and HC1, a new spray dryer/fabric filter system will be
installed on each combustor. The existing ESP will be demolished to make
room for the spray dryer vessels. Lime slurry will be introduced in each
spray dryer at a 2.5:1 calcium-to-acid gas molar ratio. Water in the lime
slurry of 30 gpm will be required to cool the flue gas to 300°F for each
combustor. The proposed equipment layout is illustrated in Figure 5.1-5.
This sketch also shows the location of the lime receiving, storage, and
slurry area which will serve the spray dryers. A fabric filter with
41,000 effective square feet of cloth (net air-to-cloth ratio of 4:1) will
be installed following each spray dryer. The increased pressure drop of a
fabric filter over an ESP will require a new ID fan for each unit as wel-1.
An estimated 80 feet of new duct will be needed to connect the spray
dryer/fabric filter to the existing stack. New monitoring instruments for
HC1, SO*, and 0- will be installed at both the inlet to the spray dryer and
the outlet of the fabric filter. An opacity monitor will be installed at
the outlet of the fabric filter. Downtime is expected to be 2 months for
ductwork tie-in and ESP demolition.
5,1.7.2 Environmental Performance. Total CDD/COF emission reductions
of 99 percent to 5 ng/dscm will result. Emissions of PM will be reduced
from 0.02 gr/dscf to 0.01 gr/dscf. Acid gases will be reduced 90 percent
for SCL and 97 percent for HC1.
5.1.7.3 Costs. Capital cost requirements for installing spray
dryer/fabric filter systems are presented in Table 5.1-8. Total capital
cost is estimated at $34,000,000. This figure includes purchase equipment,
installation, ESP demolition, and indirect costs such as engineering and
contingencies. Estimates assume moderate access and congestion, 80 feet of
new ductwork, and new ID fans.
5-25
-------
TABLE 5.1-7, PLANT ANNUAL COST FOR DRY SORBENT INJECTION WITH
ADDITION OF ESP PLATE AREA
(Thret units of 750 tpd each)
Item Costs ($1000)
DIRECT COSTS:
Operating Labor 90
Supervision 35
Maintenance Labor 40
Maintenance Materials 122
Electricity 81
Water 14
Lime 843
.Waste Disposal 342
Monitors 322
Total 1,890
INDIRECT COSTS:
Overhead 167
Taxes, Insurance, and
Administration 374
Capital Recovery and
Downtime 2.040
Total 2,580
TOTAL ANHUALIZED COST 4,470
5-26
-------
New
I.D. Fan
I.D. Fan /
New
I.D. Fan
u
£
/ 1
W
Fabric
. Filter
V)/ 4
§f E
Fabric
Fitter
Fabric
Filter
lime Storage
and Sorbent
Preparation Area
Unit 1 Unit 2 Unit 3
Existing Incinerator Building
Figure 5.1-5.
Plot plan of spray dryer/fabric filter retrofit
equipment arrangment.
5-27
-------
TABLE S.I-8 PLANT CAPITAL COST FOR SPRAY DRYER WITH FABRIC FILTER
-------
Annual operating costs are presented in Table 5,1-9. Significant
direct operating expenses include maintenance materials, electricity for the
larger ID fan needed due to increased pressure drop access in the fabric
filter, and monitoring equipment maintenance. Total annualized costs,
including capital recovery and downtime, would be $9,410,000.
5.1-8 Summary of Control Options
5.1.8.1 Description,of Control Costs. The control technologies
described in the previous sections have been combined into seven retrofit
emission control options. Table 5.1-10 summarizes the combustion,
particulate control, and acid gas control technologies described in
Sections 5.1.3 through 5.1.7 that were combined for each of the control
options described in Section 3.0. Of the seven options, Options 1 and 2
would be the same for this plant,"because good combustion practices are
in place and baseline PM emissions are below good PM control level of
0.05 gr/dscf.
5.1.8.2 Environmental Performance. The performance of each control
option is summarized in Table 5.1-11. For each pollutant, the table
presents both the pollutant concentrations and annual emissions. The
greatest reductions on acid gases, particulate matter, and CDD/COF all are
achieved with a spray dryer/fabric filter system. Then next most effective
control for all these pollutants is the dry sorbent injection technology.
Dry sorbent injection technology increases the baseline. Solid waste
disposal by about 6 percent, and the spray dryer/fabric filter system
increases the baseline solid waste disposal by about 5 percent.
5.1.8.3 Costs. The total annualized cost of each option is presented
1n Table 5.1-12. The most expensive control option is the spray
dryer/fabric filter installation with combustion modification (Option 7).
The total capital cost for this option is $34,100,000 and the total
annualized cost is $9,550,000. This annualized cost is roughly 65 times
higher than the annualized costs for Option 1. Overall, both capital and
annualized costs are higher for higher levels of control.
5.1.8.4 Energy Impacts. Table 5.1-13 presents a summary of the
energy impacts associated with the control options. The energy use figures
are incremental use. The spray dryer with fabric filter control options
5-29
-------
TABLE 5.1-9. PLANT ANNUAL COST FOR SPRAY DRYER WITH FABRIC FILTER
(Three units of 750 each)
Item Costs ($1000)
OIRICT COSTSs
Operating Labor
Supervision
Maintenance Labor
Maintenance Materials
Compressed Air
Electricity
Water
Lime
Waste Disposal
Monitors
Total
INDIRECT COSTS:
Overhead 378
Taxes, Insurance, and
Administration 1,230
Capital Recovery and Downtime . 5.160
Total 6,770
TOTAL ANNUALIZED COST 9,760
alncludes bag replacement costs of $160,000.
5-30
-------
TABLE 5.1-10. SUMMARY OF CONTROL OPTIONS FOR LARGE MASS BURN UATERWALL COHBUSTOR
Part [dilate Control
Ac Id Cm Control
Control Option Detcrlptlon
Combust Ion
Modification*
Temperature
Control
EM!J ting ISP
Rebuilt
Additional
SCA
Hex
Fabric Filter
So r bent
Injection
Spray
Dryer
cn
1. Good Combuition and
Temperature Control
2. Good PM Control with
Combu*tlon Control
3. Beit PM Control and
Corabuttlon and Temperature
Control
4, Good Acid Gai Control,
Beit PM Control and
Temperature Control
5. Good Acid Gai Control
and Beit rtt/Ccobuit Ion/
Temperature Control
6. Beit Acid Gai Control,
Beat PM Control, and
Temperature Control
7. Best Acid Gal Control and
Beat PH/CombustLon/
Ttoip«r«tiic« Control
-------
TABLE 5.1-11. ENVIRONMENTAL PERFORMANCE SUMMARY FOR LARGE MASS BURK WATERWALL HUC MODEL PUlMT RETRDFIT CONTROL OPTIONS
{Three Unit* of 750 TPD Each)
Total CDO/CDF Emission*
(ni/dgcm)
Mi/yr
X Reduction vs. Basal Ina
CO Emissions
Hi/jrr
X Reduction vs. B*i*Hne
PM Emission*
(ir/d.cf)
Mt/yr
-------
TABLE 5.1-12. COST SUMMARY FOR LARGE MASS fiURH UATERUAH
MWC MODEL PLANT RETROFIT OOKTROL OPIIOHS*
(3 unlt» at 720 tpd «ach)
1
UJ
u>
Total Capital Co it
Daunt lac Coat
Annual Ized Capital and
Da wit la* Coat
Direct OtK Cojt
Total Annual Coat
Co»t EffcctlvaiMaa
' Optio* ,
86
0
11
84
143
0.20
Option 2
86
0
11
a*
143
0.20
Option 3
2,800
5,300
970
86
1.100
1.47
Option 4
10,200
5,300
2,040
1,890
4,470
5.96
Option 5
10,290
5,300
2,050
1,970
4,610
6.15
Option £
34,000
5,300
5,160
2,990
9,760
13.10
Option 7
34,100
5,300
5,170
3,070
9,900
13.20
($/ton KSW)
Facility Downtlm*
(Month*)
Total Compliance Tine
(Month!)
13
13
13
19
19
25
All coat* (except co»t *£fectlv«n*») alv«n In $1000. All coita In Dcceotxr 1987 dollar*.
-------
TABLE S.I-13 ENERGY IMPACTS FOR LARGE MASS BURN WATERWALL
COMBUSTOR CONTROL OPTIONS
Option
1.
2.
3.
4.
5.
6.
7.
Electrical Use
(MWh/yr)
0
0
195
1,500
1,500
h
13,600°
13,600°
Gas Use
(Btu/yr)
0
0
0
0
0
0
0
Increase from baseline consumption.
Total electrical use excludes the electrical savings of not operating the
existing ESP's.
5-34
-------
consume the most electricity, about 10,500 MW/yr. Auxiliary fuel is fired
for these options and baseline requiring combustion modifications all at the
same rate of 36 biTHon Btu per year. Therefore, no increase in auxiliary
fuel consumption from baseline is expected for the seven options.
5-35
-------
5.2 MID-SIZE MASS BURN WATERWALL COMBUSTOR
This section presents the case study for a model mid-size mass burn
waterwall municipal- waste combustor (MWC). This subcategory comprises mass
burn water-wall combustors with individual combustor capacities between
275 and 600 tpd. As shown in Table 5.0-1, there ire eight known plants in
this subcategory. Five of these eight plants have started operating in the
last two years. The remaining four plants were built between 1970 and 1974.
A facility expansion also occurred at the Nashville plant in 1986. Six of
the eight existing facilities are equipped with electrostatic precipitators
(ESP's); two plants were built with spray dryer/fabric filter systems.
Section 5.2.1 presents a description of the Nashville Thermal Plant,
which was visited in order to gather information for model development.
Section 5.2.2 presents a description of the model plant. Sections 5.2.3
through 5.2.6 detail the retrofit modifications, estimated performance, and
costs associated with various control options. Section 5.2.7 summarizes the*
control options, which are discussed in more detail in Section 3.0 of this
report.
5.2.1 Description of Nashville Thermal Plant
the Nashville Thermal Plant began operating in 1974. At that time, the
plant consisted of one gas/oil standby boiler (#1) and two waste-fired
combustors (92 and #3). Each of the original waste-fired units has a rated
capacity of-360 tpd of MSW. An additional waste-fired combustor (#4) started
up in 1986. The 14 combustor has a rated capacity of 400 tpd. All three of
the waste-fired boilers are equipped with Detroit Stoker grates and Babcock
and Wilcox (B&W) boilers, and each is equipped with a 4-field ESP. The three
units operate continuously, 7-days/week.
Table 5.2-1 presents design and operating data for the plant. The plant
is unique in that 1t was the first waste-fired plant in the U.S. to provide
district heating and cooling. Steam and chilled water are supplied to more
than thirty buildings in downtown Nashville, some of which rely solely on the
waste-fired plant for heating and cooling. Two steam-driven centrifugal
chillers were originally in place with the 12 and 13 units. With the plant
expansion, two additional chillers brought total chilled water capacity to
27,000 ton/hr. The expansion also included installation of a 7.3 MW
turbine-generator. Electricity is sold to the Tennessee Valley Authority.
5-36
-------
TABLE 5.2-1. NASHVILLE THERMAL DESIGN AND OPERATING DATA
Combustor:
Type
Number of Combustors
Individual Combustor Capacity
Steam Production:
Design Steam Capacity
Maximum Steam Capacity
Steam Conditions
Emissions Control:
Type
Manufacturer
Number of ESP's
Number of Fields
Design PM Operating Temperatures
Actual PM Operating Temperature
Inlet Particulate Loading (typical)
Design Collection Efficiency
Measured Collection Efficiency
Particulate Emission Limit
Design Gas Flow
Total Plate Area
SCA at 115,000 acfm, 450°F
Design Superficial Gas Velocity
Residence Time
Dimensions (length x width x height)
Tested Emissions (Unit #4)
Particulate Matter
SO-
NO;
cox
Mass Burn Waterwall
3
360 tpd (#2 and
400 tpd (14)
80,000 Ib/hr (12 and #3)
90,000 Ib/hr (#4)
100,000 Ib/hr (#2 and #3)
120,000 Ib/hr (14)
400 psig at 6QO°F
Electrostatic PrecipitatDr
American Air Filter
3 (one per combustor)
4 each
450 to 650°F
400 to 500°F
1.5 gr/dscf
99%
98.8%
0.025 gr/dscf
140,000 acfm at 6SO°F
(115,000 acfm at 450°F)
44,240 square feet
385
3.5 ft/sec
14 seconds
40 x 25 x 33 feet
0.018 gr/dscf
105 ppm
96 ppm
2.5 ppm
aPlant personnel feel that CO emissions from the older units (12 and 13)
would probably be higher than this value.
5-37
-------
An underground distribution network contains steam supply and condensate
return headers, and chilled water supply and return lines. Nearly all of the
condensate and chilled water is returned to the plant so that make-up water
is minimized.
5.2.1.1 Combustor Design and Operation. Waste is delivered to the
plant six days/week, and consists largely of residential solid waste. Three
cranes are available, with two normally on standby. Waste is transferred
from the pit to the individual combustor hoppers where it is charged to the
combustor by hydraulic rams. The ram feeders were retrofit on units #2 and
13 in 1978 and ram speeds are varied manually. On the #4 unit, the ram cycle
is automatically adjusted as part of the combustion control system.
Each of the conibustors contains three grate sections: (1) drying,
(2) burning, and (3) finishing. The grates are reciprocating type, with
alternating stationary and moving portions. The newer Detroit Stoker grates
on unit 14 are steeper (12° angle) than those in the #2 and #3 units
(6° angle}, and the design of the grate bars also varies. Grate wear was a
common problem which has been corrected by the installation of a new
chrome/nickel alloy.
Each grate section contains two independently controlled underfire air
plenums. On the older units (12 and #3), adjustments to underfire air damper
settings are made manually, and in the 14 unit the settings are adjusted
automatically to maintain an established underfire air distribution. In all
units the majority of the underfire air is provided to the middle (burning)
grate. Steam coil air preheaters are in place to supply 150°F combustion air
to all three plenums when firing wet refuse.
Each combustor 1s designed to operate at 80 percent excess air, and the
original overfire/underfire air ratio was 15/85. Separate forced-draft fans
supply overfire and underfire air to each combustor. Excessive tube wastage
problems in early years of operation were an indication that the ratio of
overfire to underfire air was insufficient. Due to capacity limitations in
the original overfire air fans, new fans and overfire air ports were
installed in 1982 to adjust the ratio to 40/60 at 80 percent excess air.
The original overfire air system consisted of two rows of nozzles across
the front wall and a single row of nozzles across the rear wall. All of
these nozzles were 1-1/4 inches in diameter, and each row included
5-38
-------
14 nozzles. The overfire air fan provided a maximum pressure of 18 inches of
H20 gage in the supply header. In 1975 an additional row of 14 nozzles was
added to the lower front wall.
The new overfire air system consists of the four rows of nozzles
described above and 16 nozzles on each side wall, supply headers, and a new
fan and motor. The side wall nozzles are squashed pipe approximately
1-1/16 inches wide by 3-1/2 inches high and fit between the existing
waterwall tubes in the membrane wall.
The maximum horizontal distance from front to rear combustor walls is
IS feet 5 inches at the elevation of the lower overfire air nozzles. This
distance is reduced in the upper combustor by a bull nose that extends two
feet horizontally from the front wall. Plant personnel indicated that normal
pressure settings on the front and rear wall overfire air supply headers is
30 inches of water gage, and 15 inches of water gage on the side walls. Two
combination gas/oil burners are located on the combustor rear wall 5 to
6 feet above the highest overfire air jets. Profiles of the original and new
combustors are shown in Figures 5.2-1 through 5.2-3.
Gas temperatures are recorded in the upper combustors and at several
downstream locations in the system. The combustor exit gas temperature is
reported to be 1400 to 1500°F. The economizer inlet gas temperature is
approximately 760 F, and the flue gases at the economizer exit are
approximately 460°F.
Gas is fired during process start-up and the combustor temperatures are
stabilized on refuse after approximately three hours. There is no
requirement to attain a specific combustion temperature prior to charging
waste feed. Total gas burner capacities were reported to be 50 percent of .
total thermal load.
Units #2 and #3 are equipped with pneumatic controls which maintain a
constant steam flow by varying underfire air flows. Ram feeder and grate
speeds are adjusted manually. Unit #4 is equipped with a Bailey Network
90 Combustion Control system which provides total system control. Underfire
air is controlled automatically with a variable speed forced-draft fan,
providing constant steam pressure at a targeted steam flow. There are
automatic dampers on the ovtrfire air fans. Grate and ram speeds are
5-39
-------
Figure 5.2-1. Configuration of Original Combustor (12). ngure 5.2-2. Configuration of New Combustor (14)
(Figures provided by Nashville Thermal Transfer Corp.)
-------
Overfire Air
Fiaure S 2-3 Configuration of New Combustor (#4) Showing Overfire Air
Figure *,* Locations. (Figure provided by Nashville Thermal)
5-41
-------
controlled automatically, but can be manually overridden. The control system
has CL/CO trim for excess air control (tied to underfire air system), and
there is capacity for future installation of combustor temperature override
to increase underfire air flows with falling combustor temperatures, thus
overriding the normal underfire air flow control.
5.2.1.2 Emission Control Design and Operation. Each of the three
waste-fired combustors is controlled by a separate 4-field ESP manufactured
by American Air Filter. ESP's were added to the original combustors (#2 and
#3) in 1976 to replace wet scrubbing systems. Each of the ESP's at Nashville
Thermal achieve PM emissions of less than 0.02 gr/dscf. Despite the age
difference of the units, the ESP's are virtually identical. Table 5.2-1
presents design and operating data for the 14 ESP.
Figure 5.2-4 shows the unusual duct arrangement from the boiler outlets
to the ESP inlets. Crossovers are provir!~d between 12 and the other two
units to allow continued operation of a boiler in the event an ESP is
'inoperative.
The ESP's have not been rebuilt since they were put in service. Despite
the operating temperatures, which are often lower than design, the operators
have not experienced corrosion problems. One reason for this may be the
continuous boiler operation, which keeps the flue gas temperature above the
acid dew point, preventing acid condensation on the surfaces of the ESP.
Spatial constraints at the back end of the system are severe. There is
probably not enough space at the back end of the system for a complete spray
dryer/fabric filter retrofit due to the close proximity of the existing
chimneys, ESP's, cooling towers, and transformers. However, there is
substantial space toward the front of the plant. The parking area beside
Unit #4 would have to be relocated to make space available for a spray
dryer/fabric filter system. Also, space is available, with some limitations,
beside Unit #1 along the Cumberland River. The addition of a planned Unit #5
will further constrain this area and make the retrofit of acid gas controls
difficult. Unit #2 has existing ductwork of about 100 feet prior to the ESP.
Units #3 and #4 have significantly shorter duct runs. As such, sufficient
5-42
-------
Unit
1
(Gas/Oil)
Unit
2
(MSW)
Unit
3
(MSW)
Unit
4
(MSW)
o
Chimney
Expanded to
show crossover
scheme. Ducts
are actually
stacked
vertically
against side
of building
Duct Crossovers
Chimneys
Not to Scale
Figure 5.2-4. Duct Configuration at Nashville Thermal
5-43
-------
duct residence time may be available for a duct sorbent injection system, but
the unusual duct arrangement discussed above would preclude installation of
such a system without major duct reconfigurations,
5-2.2 Description of Model Plant
As shown in Table 5.0-1, there are eight operating plants in this
subcategory of MWC's. The eight operating plants have individual units
ranging in size from 275 to 400 tons per day. Despite the age of the older
plants, nearly all of the facilities incorporate-the majority of design and
operating elements which represent good combustion practices for mass burn
waterwall systems. This group of plants typically use a ram feeder and have
multiple, separately controllable underfire air plenums. They also typically
have properly designed overfire air systems to provide full coverage and
penetration of the combustor. Combustion control loops -are established to
maintain constant steam flow by automatic adjustment of underfire air flows.
Excess air levels are maintained between 80 and 100 percent. A few of the
systems may have more advanced controls, including oxygen trim loops,
temperature control loops, and automatic adjustments to ram speeds. The
majority of plants also contain auxiliary fuel burners for start-up,
shutdown, and equipment preheat. Typically, these plants are equipped with a
continuous Q? monitor, and airflow, temperature, steam, and feedwater
controls and monitors. In addition, typical economizer flue gas exit
temperatures are below 450°F, thus minimizing the potential for COD/CDF
formation in downstream flue gas treatment equipment.
5.2.2.1 Combustor Design and Operation. Table 5.2-2 presents
operating and design data for the model plant. A model plant consisting of
three 360-tpd mass burn waterwall combustors was selected based on the
population described above. The units are assumed to operate at 80 percent
excess air with an overfire/underfire air ratio of 30/70, Both of these
figures are typical values for the facilities in the existing population.
Each combustor has two gas burners which are used during start-up and
shutdown. The burners are located on the rear wall just above the overfire
air ports. Underfire air flow rates are adjusted automatically to maintain
constant steam flows. Grate speeds are adjusted manually. Temperatures are
monitored in the upper combustor and at the economizer outlet. Oxygen is
continuously monitored at the economizer outlet.
5-44
-------
TABLE 5.2-2.
MODEL PLANT DESIGN AND OPERATING DATA FOR MID-SIZE
MASS BURN WATERWALL COMBUSTOR
Combustor:
Type
Number of Combustors
Individual Combustor Capacity
Steam Production:
Design Steam Capacity
Steam Conditions
Emissions Control:
Type
Number of ESP's
Number of Fields
Operating Temperature
Inlet Particulate Loading (typical)
Design Collection Efficiency
Gas Flow
Total Plate Area
SCA at 82,000 acfm and 450°F
Emissions:
CDD/CDD (octa - tetra)
PH
CO
HC1
so2
Stack Parameters:
Height
Diameter
Mass Burn Waterwal1
3
360 tpd (each)
80,000 lb/hr» each boiler
400 psig at 600°F
Electrostatic Precipitator
3 (one per corabustor)
450°F
2,0 gr/dscf
>99%
82,000 acfm at 450°F
34,700 square feet
425
200 ng/dscm
0.01 gr/dscf
50 ppmv
500 ppmv
200 ppmv
200 ft
7 ft
Operating Data:
Remaining Plant Life
Operating Hours per Year
Annual Operating Cost
- > 20 years
- 8000
- $10,60Q,QO/year
5A11 emissions are dry, corrected to 7 percent 0-. Standard and normal
conditions are 1 atmosphere and 70 F,
5-45
-------
At i flue gas flow rate of 80 percent excess air, total combustion air
are approximately 39,000 scfm. Underfire air flow is 27,300 scfm and over-
fire air flow is 11-,700 dscfm. Total flue gas air flow at the boiler exit,
including flue gas products, is approximately 48,000 scfm (41,400 dscfm).
5.2.2.2 Description of Emission Controls. As shown in Table 5.0-1, the
majority of plants in this subcategory are equipped with ESP's. These ESP's
are typically operated at temperatures lower than 450°F and achieve at least
99 percent removal of PM. Acid gas controls are not typically in place at
these plants.
The model plant for this subcategory is equipped with dedicated 4-field
ESP's similar to those in place at Nashville. Operating data for the ESP's
are given in Table 5.2-2. It is assumed that the model plant ESP's operate
at a temperature of 450°F, are well-operated, and have sufficient SCA at
450°F to achieve an outlet PM loading of 0.01 gr/dscf.
The existing duct arrangement is not assumed to be typical of the
existing population of mid-size mass burn water-wall plants. The site
congestion at Nashville is also not typical, since Nashville Thermal was
intentionally located in the downtown area to provide district heating and
cooling. As previously discussed, this aspect is unique for plants in this
subcategory. For purposes of representative model development, the model
plant is assumed to have a standard duct arrangement and moderate APCD
congestion, as shown in Figure 5.2-5. It is also assumed that each ESP is
equipped with its own stack. Stack parameters for the model plant are also
presented in Table .5.2-2,
5.2.2.3 Environmental Baseline. Table 5.2-2 also presents the
environmental baseline for the model plant. Five of the plants in this
subcategory have reported emissions of CDD/COF. From this available data, it
is assumed that the model plant has baseline emissions at the combustor exit
of 200 ng/dscm CDO/COF corrected to 7 percent Og. ESP's operating at 450°F
are assumed to neither promote nor deter formation of COD/CDF. Therefore,
CDD/CDF emissions at the stack are assumed to be equal to CDD/CDF emissions
at the combustor exit.
Based on measured data from plants in this subcategory, an uncontrolled
PM emission rate of 2.0 gr/dscf at 7 percent 02 was selected for the model
plant. The ESP's are assumed to reduce this level to 0.01 gr/dscf at the
5-46
-------
o o
ESP
ESP
=r t
ESP
Heating Plant
Storage Pit
Figure S.2-S. Plot Plan of Model Plant
S
i
5
3
5-47
-------
stack. Baseline CO emissions are assumed to be 50 ppmv at 7 percent 0«» also
based on data from other plants in the population. Based on the waste
composition used in this study, baseline emissions of HC1 and SCL are assumed
to be 50 ppmv and 200 ppmv respectively. It is assumed that the combustion
process reduces waste 90 percent by volume and 70 percent by weight.
5.2.3 Good Combustion
An analysis of the model plant design and operation indicates that good
combustion practices are largely in place. The only additional requirement
for the model plant is the installation of continuous CO monitors for
performance verification. Each unit should be equipped with a CO monitor
with readout and integrator. Installation of this equipment can be performed
during a routine scheduled outage, so that the modification will not cause
any unscheduled downtime.
5.2,3.1 CrqsjLS-. Plant costs for combustion modifications are shown in
Table 5.2-3. It is estimated that the capital cost of installing CO monitors
will be $86,000, and that the annualized costs, including annualized capital,
will be $148,000 yearly.
5.2.4 Best ParticulateControl
The existing ESP's are assumed to reduce PM loadings from 2.0 gr/dscf at
the ESP inlet to 0.01 gr/dscf at the outlet. Thus no equipment modifications
are required for this model plant to achieve 0.01 gr/dscf, the emission level
associated with best particulate control,
5.2.5 Good Acid Gas Control
5-2.5.1 Description of Modifications. For good acid gas control on
each combustor, dry calcium sorbent will be injected into the duct upstream
of the ESP. Water will also be sprayed into the duct, at this point, to cool
the gas stream to 350°F. This cooling is estimated to require 8 gpm of water
per combustor.
Required equipment to accomplish the sorbent injection includes a
sorbent storage silo, a pneumatic sorbent conveying system, three sorbent
feed bins, and pneumatic injection nozzles for each combustor. Hydrated lime
sorbent will be fed at a calcium-to-acid gas molar ratio of 2:1. At full
load, this requires a sorbent injection rate of 407 Ib/hr per combustor.
5-48
-------
TABLE 5.2-3 PLANT COSTS FOR COMBUSTION MODIFICATIONS
(Three units of 360 tpd each)
Item Cost ($1000)
CAPITAL COSTS:
CO monitors, with readouts and integrators 66
Indirect costs £0
TOTAL CAPITAL COSTS 86
Downtime Costs 0
ANNUALIZED CAPITAL COST AND DOWNTIME 11
ANNUAL OPERATING COSTS;
Direct Costs:
Maintenance and Labor 42
Maintenance and Materials- 42
Total 84
Indirect Costs:
Overhead 50
Taxes, Insurance, Administration 3
Capital Recovery- 11
Total 64
TOTAL ANNUALIZED COST 148
5-49
-------
To control the additional participate loading generated by the lime
sorbent, plate area will be added to maintain PM emissions at 0.01 gr/dscf.
An additional 5,300 square feet of ESP collection area will be added to each
ESP using a separate ESP in series behind each existing unit. The project
also includes monitoring equipment for HC1, SO., and CO-, and new ID fans.
Figure 5.2-6 shows these retrofit changes.
There are no access and congestion problems related to the addition of
water lines and pumps for humidification. However, replacement of each
economizer exit duct with a new duct containing sorbent and water injection
nozzles is highly restricted since the duct passes through the heating
building wall to the outdoor ESP. Access/congestion level for the lime
sorbent conveying equipment and the additional ESP's is assumed to be
moderate. An additional 150 feet of new ducting will be required to connect
each new ESP to an existing stack. Combustor downtime can be limited to
approximately 1 month for each unit.
5.2.5.2 Environmental Performance. CDO/CDF emissions are expected to
be reduced by 75 percent from baseline levels. Acid gas emission reductions
are estimated at 80 percent for HC1 and 40 percent for S0?, respectively. As
mentioned above, PM emissions will be maintained at 0.01 gr/dscf. An
additional 6,290 tons/per year of solid sorbent waste will be added to the
site disposal requirements. This represents a 6 percent increase in solid
waste.
5.2.5.3 Costs. Capital costs for duct sorbent injection are presented
in Table 5,2-4. Total capital cost is estimated at $6,800,000. Host of this
cost 1s associated with upgrading participate control equipment. Downtime
cost 1s also substantial, at $1,270,000. Annual operating and maintenance
costs are presented in Table 5.2-5. Najor direct operating costs are
associated with sorbent purchase and maintenance of monitoring instruments.
The total anmialized cost (Including capital recovery and downtime) is
$2,580,000.
5.2.6 Best Acid Gas Control
5.2.6.1 Description of Modifications. To achieve 70 percent reduction
of SO- and 90 percent reduction of HC1, a new spray dryer/fabric filter
system will be installed on each combustor. L1me slurry will be introduced
in each spray dryer at a 2.5:1 calclum-to-acld gas molar ratio.
5-50
-------
> NewiSPs
and ID Fans
t
=r t
Heating Plant
N«w SortMnt
Storage Silo
Storage Pit
Figure 5.2-6. Plot Plan for Duct Sorbent Injection Equipment Arrangement.
5-51
-------
TABLE 5.2-4 PLANT CAPITAL COST FOR DRY SORBENT INJECTION WITH ESP
(Three units of 360 tpd each)
Item
Cost ($1000)
DIRECT COSTS:
Add Gas Control
Equipment
Access/Congestion Cost
Particulate Control
Equipment
Access/Congestion Cost
New Flue Gas Ducting
Ducting Cost
Access/Congestion Cost
Other Equipment
Temperature Control
Fan
Stacks
Demolition/relocation
Total
560
56
1,780
444
229
63
197
569
0
4,300
Indirect Costs and Contingencies
Monitoring Equipment
1,730
771
TOTAL CAPITAL COST
DOWNTIME COST
ANNUALIZED CAPITAL RECOVERY AND DOWNTIME
6,800
1,270
1,060
aBased on high access and congestion for installation.
Turnkey.
5-52
-------
TABLE 5.2-5 PLANT ANNUAL COST FOR DRY SORBENT INJECTION WITH ESP
(Three units of 360 tpd each)
Item Costs ($1000)
DIRECT COSTS:
Operating Labor 90
Supervision 35
Maintenance Labor 40
Maintenance Materials 72
Electricity 44
Water 6
Lime 391
Waste Disposal - 157
Monitors 309
Total 1,140
INDIRECT COSTS:
Overhead
Taxes, Insurance, and Administration
Capital Recovery and Downtime
Total 1,440
TOTAL ANNUALIZED COST 2,580
5-53
-------
lime will be slurried in the additional 13 gpm of water needed to cool the
flue gas to 300°F.
The proposed equipment layout is illustrated in Figure 5.2-7. This
sketch shows the location of the lime receiving, storage, and slurry area
which will serve all three spray dryers. A fabric filter with
23,900 effective square feet of cloth (net air-to-cloth ratio of 4:1) will be
installed following each spray dryer. The increased pressure drop of fabric
filters over existing ESP's will require new ID fans for each unit as well.
An estimated 750 total feet of new duct will be needed to access the existing
stacks. New monitoring instruments for HC1, SO*, CQg, and opacity will be
installed,
The new equipment will be located behind the existing stacks. New duct
will be tied in just ahead of the existing ESP's which will be abandoned in
place. Downtime for duct tie-in for-each new unit is expected to be
1 month.
5.2.6.2 Environmental Performance. COD/CDF emission reductions to
5 ng/dscm are expected. Emissions of particulate matter will be maintained
at 0.01 gr/dscf. Acid gases will be reduced to 90 percent for SO* and
97 percent of HC1.
5.2.6.3 Costs. Capital cost requirements for installing spray dryer/
fabric filter systems are presented in Table 5.2-6. Total capital cost is
estimated to be $21,000,000. This figure includes purchased equipment,
installation, and indirect costs such as engineering and contingencies.
Estimates assume moderate access and congestion, few additional facilities
and no purchased land. Downtime cost (lost revenue) is estimated to be
$1,270,000.
Annual operating and maintenance costs are presented in Table 5.2-7.
The most significant O&M expenses include replacement bags for the fabric
filters and electricity for the larger ID fan needed due to the increased
pressure drop across the fabric filters. Total annualized cost, including
capital recovery and downtime is $5,790,000.
5.2.7 Summary of CoqtroJ Options
5.2.7.1 Description of Control Options. The control technologies
described in the previous sections have been combined into seven retrofit
5-54
-------
New Spray Dryers,
Fabric Filters
and ID Fans
Heating Plant
i i—i i—i r
New Sorbent
Storage Silo
Storage Prt
M.
Figure 5.2-7. Plot Plan of Spray Dryer/Fabric Filter Retrofit Equipment -
Arrangement
5-55
-------
TABLE 5.2-6 PLANT CAPITAL COST FOR SPRAY DRYER WITH FABRIC FILTER
(Three units of 360 tpd each)
Hem Cost ($1000)
DIRECT COSTS;
Acid Gas and Part1culate Control
Equipment 9,410
Access/Congestion Cost 2,350
New Flue Gas Ducting
Ducting Cost 333
Access/Congestion Cost 83
Other Equipment
Fan 454
Stacks 0
Demo!ition/relocation 0
. Total 12,600
Indirect Costs and Contingencies 7,530
Monitoring Equipment3 859
TOTAL CAPITAL COST 21,000
DOWNTIME COST 1,270
ANNUALIZED CAPITAL RECOVERY AMD DOWNTIME 2,930
aTurnkey.
5-56
-------
TABLE 5.2-7 PLANT ANNUAL COST FOR SPRAY DRYER WITH FABRIC FILTER
(Three units of 360 tpd each)
Item Costs ($1000)
DIRECT COSTS:
Operating Labor 144
Supervision 22
Maintenance Labor 79
Maintenance Materials 323a
Electricity 282
Compressed Air 40
Water 9
Lime 324
Waste Disposal 208
Monitors 322
Total 1,750
INDIRECT COSTS;
Overhead 298
Taxes, Insurance, and Administration 806
Capital Recovery and Downtime 2J30
Total 4,030
TOTAL ANNUALIZED COST 5,790
Includes bag replacement of $70,000 per year.
-------
emission control options. These options are discussed in detail In
Section 3.0. Table 5.2-8 summarizes the combustion, particulate control and
acid gas control technologies described in Sections 5.2.3 through 5.2.6 that
were combined for each of the control options. It should be noted that since
the model plant achieves 0.01 gr/dscf and practices good combustion at
baseline. Options 2 and 3 are identical to Option 1.
5.2.7.2 Environmental Performance. The performance of each control
option is summarized in Table 5.2-9. For each pollutant the table presents
both the pollutant concentrations and annual emissions. The greatest
reduction in total CDD/CDF, and acid gas emissions is achieved by addition of
the spray dryer/fabric filter systems. Since good combustion is practiced at
baseline, CO emissions are unchanged. Similarly, best particulate control is
practiced at baseline, so PH emissions are unchanged. Spray drying and dry
sorbent injection increase solid waste disposal requirements by 5 percent and
6 percent, respectively.
5.2.7.3 Costs. The total annual!zed cost of each option is presented
in Table 5.2-10. Cost of control increases with increasing level of control
for CDQ/CDF and acid gases. However, duct sorbent injection is more cost
effective than spray drying, on a per pound of reduction basis. Duct sorbent
injection achieves a 75 percent reduction in CDD/CDF for one-third to one-
half the cost of 98 percent reduction by spray drying.
5.2.7.4 Energy Impacts. Table 5.2-11 presents a summary of the energy
impacts associated with the control options. The electrical use figures take
into account the cost savings of not operating the existing ESP's under
Options 6 and 7. There is no increase in auxiliary fuel use because
auxiliary burners are in place on the model plant and are used under baseline
operition.
5*58
-------
TABLE i.2-8 SUMURV OF CONTROL OPTIONS FOR MID-SIZE MASS BURN UATERWALL COHBUSTOR
Control Option Description
Partleulata Hatter Control
Acid Ca» Control
New
Combustion Temperature Existing Additional fabric Sorbent
Hodlflcatlon* Control Rebuilt ESP Plat* Ar«a Filter Injection Spray Dryer
1. Good Combuatlon and Temper* tur«
Control
2. Good PM Control with Combustion
ure Control
3. Best PM Control and Combustion
and Tcmperatut* Control
n
O
4, Good Acid Cas Control, Beat PM
Control Control and Temperature Control
5. Good Acid Cas Control and Beit
PH/Ccobujtton/Temperature Control
6. Beat Acid C»i Control, Best PM Control,
and Teoperatuce .Control
1. Beat Acid C»J Control and Beit PM/Combuation/ X
uEe Control
-------
TABLE 5.2-9 ENVIRONMENTAL PERFORMANCE SUMMARY FOR MID-SIZE MASS DIKUt UAXERUALL MODEL PLANT RETROFIT CONTROL OPTIONS*
(Thr«« unit* of J60 tpd each)
Tool CDC/CDF Emlsilon*
(n»/d«cm)
Hl/yr
I Reduction v*. Ba*ellae
00 £ml»jlon«
(WWW)
Mj/jrr
Z Reduction v*. Baseline
PM EmU»loo»
ltcfa»ef)
M»/yc
X Reduction v*- Be»ellne
SO. Iniailon*
2
fppowl
Mi/re
,_ 1 Reduction v«. Baaellae
Ul
1
g HC1 EraliJlon*
(pprav)
Mf/yc
X Reduction v». B*«eline
Total Solid Wa*te
(cocu/day)
M»/yr
S Incre»*e v*. B»»e\ln*
B...!^
200
2.8E-4
—
50
87
—
0,01
32
—
200
797
—
500
1140
—
324
98,200
__
Option 1
200
2.8E-*
0
50
87
0
0.01
32
0
200
797
0
500
11*0
0
32*
98,200
0
Option 2
200
2. BE-*
0
50
87
0
1
o.ot
32
0
200
797
0
SOO
1140
0
324
.98,200
0
Option 3
100
2.BE-4
0
50
87
0
0,01
32
0
200
791
0
500
1140
0
324
98,200
0
Option 4
SO
7.0E-5
75
50
87
0
0,01
32
a
120
478
40
100
228
80
3*3
103,900
6
Option 5
SO
7.0B-5
75
50
87
0
0.01
32
0
120
4TB
40
100
228
80
1*3
103.900
6
Option 6
5
7.0S-6
98
SO
87
0
0.01
32
0
19
7S
90. 5
15
32
97
3*9
105,700
8
Option 7
5
7.0E-6
98
SO
87
0
0.01
32
0
19
IS
90.5
15
32
97
3*9
105,700
8
• o
Ail flu* §*i concent cat tons are reported on * '/I 0 basis. Standard and normal condition* *f« both i «tmo»ph*r* and 70 F
-------
TABLE S.2-10 COST SUMMARY FOR MID-SIZE MASS BU8M UAtEKUALL MODEL PLANT RETROFIT CONTROL OPTIONS
(Three uniti of 360 tpd e»ch)
Total Capital Cost
Dovntlm* Cost
Annu»ll«d Capital «i*J Downtime
Cost
Direct DIM Coat
local Annual Colt
Coat Effectiveness
($/ton MSW)
Facility Downtime (Months)
Total ComplUnct Tint
(Months)
Option 1
•6
0
11
8*
148
0,41
0
3
Option 2
86
0
11
84
US
O.U
0
3
Option 3 Option 4
86 6,800
0 1,270
11 1,060
84 1,140
148 2,580
0.41 7,17
0 1
13 19
Option 5
6,890
1,270
1,070
1,230
2,730
7.58
1
19
Option 6 Option 7
21,000 21,100
1,270 1,270 '
2,930 2,940
1,750 1,830
5,790 5,940
16.10 16,50
1 1
25 25
All coici (except cost «ffcctlven«»») given In $1000. Ail costs given In December 1987 dollarj.
-------
TABLE 5.2-11 ENERGY IMPACTS FOR MID-SIZE MASS BURN
WATERWALL COMBUSTOR CONTROL OPTIONS3
(Three units of 360 tpd each)
Option
1
2
3
4
5
6
7
Electrical Use
(Mtfh/yr)
0
0
0
967
967 '
h
6,150°
h
6,150°
Gas Use
(Btu/yr)
0
0
0
0
0
0
0
Increase from baseline consumption,
Excludes electricity credit of not operating the ESP's,
5-62
-------
5,3 SMALL MASS BURN WATERWALL COMBUSTOR
This section presents the case study results for a small mass burn
water-wall municipal-waste combustor (MWC). This model plant represents MWC's
with individual unit capacities smaller than 250 tpd. As shown in
Table 5,0-1, there are 9 known plants in this subcategory, including the
oldest mass burn waterwall facility in the United States (Norfolk Naval
Station) and several new facilities with state-of-the-art design and
controls. Seven of the nine facilities are equipped with ESP's; one facility
has a spray dryer with fabric filter, and one uses duct lime injection with
fabric filters for control of acid gas and PM.
Section S.3.1 describes the New Hanover County facility, which was
visited in order to gather information for model development. Section 5.3.2
describes the model plant, including baseline emission performance estimates.
Sections 5.3.3 through 5.3.7 detail the retrofit modifications, estimated
emission reductions, and costs associated with each retrofit control option.-
Section 5.3.8 summarizes the control options, which are discussed in more
detail in Section 3.0 of this report.
4
5.3.1 Description of New Hanover County HVIC
5.3.1.1 Combustor Design and Operation. The New Hanover County, North
Carolina facility is comprised of two identical waterwall mass-burn furnaces
(boilers), each with a design capacity of 100 tons of municipal solid waste
(MSW) per day. Table 5.3-1 presents key design data for the facility. The
facility has been in operation since 1984 and processes an estimated
55 percent of the county's generated wastes, burning waste 7-days/week,
24-hours/day. Each unit is brought off line monthly for maintenances and for
removing soot from the convective section of the boiler. This "clean out"
period typically lasts 8 hours; however, 1n cases where there is low soot
build-up, the boilers can be cleaned in 3 to 4 hours. The facility has a
projected 30-year remaining life.
The boilers and reciprocating grate stokers were built by E. Keeler
Company and Detroit Stoker, respectively. The boilers are tube and tile
construction rather than membrane wall. Both were shop-fabricated in two
sections and sent to the facility for assembly. Only MSW is fired in the
boilers. Each boiler is capable of producing 26,144 pounds per hour of
5-63
-------
TABLE 5.3-1. NEW HANOVER DESIGN DATA
Combustor:
Type
Number of Combustors
Combustor Unit Capacity
Grate Hanufacturer
Boiler Hanufacturer
Emission Controls:
Type
Hanufacturer
Number of Fields
Inlet design participate loading
Operating Temperature
Design Collection Efficiency
Particulate Emission Limit
Gas Flow
Normal Conditions
Upset Conditions
Total Plate Area
SCA at 26,000 acfm
SCA at 40,000 acfm
Gas Residence Time at 26,000 acfw
Gas Residence Time at 40,000 acfm
Mass Burn Materwall
2
100 tpd
Detroit Stoker
Keeler
- Electrostatic Precipitator
- United McGill
- 2
-5.0 gr/dscf
- 425 to 550°F
- 99 percent
- 0.05 gr/dscf
- 26,000 acfm at 425°F
- 40,000 acfm at 550°F
- 6,860 ft*
- 264 ft,/I,000 acfm
- 172 ftyl.OOO acfm
-4.5 seconds
-2.9 seconds
1-64
-------
superheated steam at 52S psig and 650 F . Each unit currently contains a bare
tube economizer which is not an integral part of the boiler. The economizer
preheats boiler makeup water to about 250°F while cooling the flue gas to
450°F.
The facility operates on a four shift system commonly used by utility
power plants. Each shift includes one shift supervisor, one plant operator,
two assistant plant operators, and one crane operator. The plant operator is
responsible for control room functions. The assistant plant operators perform
various functions in the boiler areas as well as driving the ash trucks to the
landfill. Five mechanics are available during the daytime hours for
maintenance and repairs of the boiler facility. For the nighttime shifts, one
of the operators is skilled in.maintaining and repairing the boiler facility.
During the downtime days, operators will assist the mechanics in repairing the
equipment.
Garbage trucks dump household waste each day into a 1,700 cubic yard
refuse pit. The refuse pit is capable of storing a 3-day supply of MSW at
200 tpd. One overhead crane equipped with a grapple is used to transfer MSW
from the pit to the charging hopper of each boiler. A second cranf is
available for standby service. From the charging hopper, the wastes move down
through the feed chute to the feed table, where a hydraulic ram feeds the
boiler. A cutoff gate is located between the charging hopper and the feed
chute. There are two Detroit Stoker reciprocating grate sections in each
unit; each section is 8 feet, 2 inches wide by 11 feet, 2 inches long. Each
grate section contains a single underfire air plenum. Approximately 70 percent
of primary air is supplied to the upper grate section and 30 percent to the
lower section. There is a vertical grate step of approximately 1.5 feet
between the grate sections.
The boilers contain two rows of overfire air nozzles on the front wall
and two rows on the rear wall. Sidewall air is also injected just above the
grate elevation on both sidewalls to provide temperature control and prevent
slagging. The overfire air nozzles are 2 inches in diameter. The front to
rear wall distance across the furnace is 14 feet. The overfire air fan has
capacity to operate at 50 percent of total air, but the normal operating
range is 25 to 30 percent of total air. Each unit has separate forced-draft
fans for underfire and overfire air supply. Flue gas oxygen is monitored by
-------
an analyzer at the economizer outlet. The facility operates each boiler at an
0- concentration of 10 percent (wet basis), or approximately 100 percent
excess air.
The bottom ash is sent directly to water-filled residue conveyor
troughs. Ash collected in a hopper below the economizer and in the ESP's is
conveyed by a dry mechanical chain fly ash conveyor. The fly ash is then
combined with the bottom ash in the water-filled residue conveyor troughs
before it is dumped into ash hauling trucks. The trucks transport the ash to
a local landfill for disposal. New Hanover County currently charges a flat
tipping fee of 53,68/cubic yard (S22/ton) on the ash. The landfill is double-
lined and incorporates a leachate collection system. An average of 7 truck
loads of ash are sent to the landfill per day.
The facility sells a portion of the steam produced in the boilers to
W. R. Grace Chemical Company. The steam price is equivalent to 110 percent of
the cost of the least expensive fossil fuel available. Because W, R. Grace"
Chemical Company requires 250 psig steam, a steam turbine on-site reduces the
steam pressure while generating electricity. The facility has a 5-year
contract with W. R. Grace.
Excess steam capacity is used to generate electricity by a second steam
turbine. The steam turbine is rated at 4 MW and produces about 2000 kw per
year. For 1986 and 1987, the plant generated about 12.2 million kwh per year.
All electricity not used on site is sold to Carolina Power and Light at their
cogeneration rate. The steam used to produce electricity is condensed and
sent to the demineralizer tank for reuse as boiler makeup. However,
condensate from the steam sold to W. R..Grace is not returned to the facility
since the condensate contains high levels of nitrates. Therefore, additional
feed water is provided to the facility by on-site wells. The feedwater supply
system has the capacity for 100 percent water makeup.
Control loops are in place to maintain constant steam drum pressure
through modulation of undergrate air. Grate speed and ram speed are also
varied to maintain desired furnace temperatures, and constant furnace
pressure (-0.5 inch water gage) is achieved by ID fan controls. Detroit
Stoker provided an electronic feed control which now has a manual override.
Overfire air adjustments are manual, with variations to control furnace
temperature.
5-66
-------
Since start-up, the facility has experienced continual flame
impingement, erosion, and corrosion problems on the steam drum and corrective
section. To alleviate some of the problems, the facility coated the
convective tubes with castable refractory. Furthermore, extensive
modifications are being evaluated by the facility and the County to eliminate
these problems. Some of the options being considered by the County's
consultant include:
1, increasing boiler height by 14 to 15 feet through addition of a
membrane wall,
2. segmenting underfire air supplies and providing individual plenum
controls,
3. installing furnace arches and redesigning overfire air firing
patterns, and
4. adding steam coil air preheaters.
The modifications will be implemented by bringing one boiler down and keeping
one on-line, with an estimated downtime of three months per unit.
In addition to the modifications to the existing boilers, construction
of a third mass-burn waterwall boiler is in planning stages. The new boiler
will process 250 tpd of MSW and will be equipped with natural gas auxiliary
burners. The facility has easy access to natural gas, since the main gas
line is about 200 feet from the facility. The new boiler will also be
equipped with a Bailey Network 90 controller and a spray dryer and fabric
filter emission control.
Start-up of the existing boilers is accomplished without any auxiliary
fuels. Before start-up, several grapple loads of the driest material
available in the refuse pit is delivered to the feed chute by the crane
operator. The hydraulic ram charges part of the waste onto the burning
grate. The material on the grate is ignited by hand. Undergrati air flows
are adjusted until burning is self-sustaining.
5.3.1.2 Emission ControlSystem Design and__Qperalion. Two identical
United McGfll 2-f1eld ESP's are used to control partlculate matter (PM)
emissions. The flue gas leaving each ESP 1s ducted to a common stack. Both
-------
ESP's contain flat plates. Programmable controls are used to maintain a
stable corona. Opacity monitors are located at the exit of each ESP's to
monitor smoke. The facility cannot exceed a 20 percent opacity limit imposed
by the State. The facility reported opacity levels less than 10 percent
during normal operation.
Flue gas enters the ESP's at a temperature of 425°F and leaves at about
405°F. The inlet flue gas temperature is not controlled but is monitored
with a thermocouple located at the outlet of the economizer. -The ESP's have
experienced some corrosion on cool surfaces around the electrical connection
boxes. According to the Bolin Chart, the flue gas temperatures between
405 and 42S°F are within the temperature range of 300 to 600°F for minimal
corrosion. Below 300°F, electochemical corrosion will likely occur; whereas
for flue gas temperatures above 600°F, corrosion caused by chlorides and iron
sulphite reduction will take place.
Each ESP is designed to handle flue gas flow rates of 26,000 acfm at
425°F based on MSW with a heating value of 5,000 Btu/lb (normal conditions)
and 40,000 acfm at 550°F based on an MSW heating value of 3,750 Btu/lb (upset
conditions). The ESP can remove 99 percent of the particulates during normal
conditions, resulting in outlet PM emissions of 0.05 gr/dscf corrected to
12 percent CO,. The specific collection area (SCA) is 264 and
2
172 ft /10QO acfm during normal and upset conditions, respectively. The
velocity inside the ESP is 3.5 and 5.3 feet per second during normal and
upset conditions. At normal conditions, the gas residence time is
4.5 seconds, while at upset conditions, the gas residence time is 2.9 seconds.
Each ESP is about 16 feet long by 14 feet wide by 15 feet tall. United
McGill provided additional room for adding another field. The facility said
that United McGill agreed to add this field at no costs if PM emissions were
above the Subpart E emission level of 0.08 gr/dscf during initial PM testing.
Initial PM testing conducted on August 1984 using EPA Method 5 showed that PM
emissions from the exit of each ESP were below this level, ranging from 0.03
to 0.04 gr/dscf corrected at 12 percent C02.
5-68
-------
The electrical field gradient at the discharge electrodes is
8,25 kV/inch and the average electrical field gradient at the grounded
collecting electrodes is 24 kV/inch. Voltage applied to the emitting plates
is 26 kV. Distance between emitting plates and collecting plates is
3.15 inches. Corona power of each ESP is 152 watts/1000 cfm. Each field has
one transformer/rectifier (T/R) set,
For removing particulates caught by the ESP's, the whole field is
rapped. During rapping, a visible plume above the stack is observed by the
operators. The consultant at this facility indicated that if his company
were to build another plant, they would design the ESP's to rap each plate
individually instead of the whole field for minimizing smoke emissions.
The operators visually inspect the ESP's monthly for potential corrosion
or performance problems. No problems have been, observed-by the operators to
date.
5.3.2 Description of Model Plant
5.3.2.1 ggmbustor Design and Operation. A list of facilities
represented by this model plant is presented in Table 5.0-1. The 9 operating
facilities include units ranging in size from 50 to 180 tpd. All of the
plants are comprised of two individual combustors. Based on the
distributions of unit sizes in the population, a representative model plant
consists of two units, each with a rated capacity of 100 tpd. The boilers
are assumed to use tube and tile constructed waterwalls. It is assumed that
the mode! plant burns MSW at full capacity on a continuous operating
schedule. Table 5.3-2 presents baseline design and operating data for the
model plant. Figure 5.3-1 shows a plot plan of the model plant.
The average age of the 9 facilities in this population is 7 years.
Based on available information regarding design, operation/control, and
verification practices in place at the existing facilities, a representative
configuration for the model plant includes the following features. Waste is
introduced to the units by hydraulic ram feeders. Each unit contains three
individual grate sections. Each grate section has two underfire air plenums
which distribute primary air to the grate. Changes in underfire air
distribution are made by manual adjustment. The damper on the forced-draft
-------
TABLE 5.3-2
MODEL PLANT BASELINE DATA FOR SMALL
MASS BURN WATERWALL COMBUSTOR
Combustor:
Type
Number of Combustors
Combustor Unit Capacity
Emission Controls
Type
Number of Fields
Inlet Temperature
Collection Efficiency
Gas Flow
Total Plate Area
SCA at 24,000 cfm
Emissions:
CDO/CDF
PM (stack)
CO
HC1
so2
Stack Parameters:
Height
Diameter
Operating Data:
Remaining Plant Life
Annual Operating Hours
Annual Operating Cost
Mass Burn Waterwall
2
100 tpd
Electrostatic Precipitator
2 n
500°F
98 percent
24,000 acfm
5,830 ft*
243 ftvl.OOO acfm
2,000 ng/dscn
0.05 gr/dscr
400 ppmv
500 ppmv
200 ppmv
140 feet
5 feet
> 20 years
8,000 hours
$3,130,000/year
aAll emissions are dry, corrected to 7 percent Og-
blnlet PM emissions to the ESP are 2.0 gr/dscf at 7 percent
c frt
-------
ESP
1.0. Fin
ESP
Ash
Disposal
Area
r r
Cooling
Towar
Unit Unit
*1 f2
Existing Indrwrator
Building
Office
Building
Refusa Pit
Trudc DoNvery
Ana
Figure 5.3-1. Plot plan of the mode! plint,
oe
ia
5-71
-------
fan is automatically controlled based on a desirad steam flow set point.
Each unit is designed to operate at 80 percent excess air, with 70 percent of
total air as underf-ire air and 30 percent as overfire air. At 80 percent
excess air, the total combustion air flow is 10,000 scfm per unit, with
7,000 scfra underfire air and 3,000 scfm overfire air. Total gas flow exiting
the combustor is approximately 12,200 scfm (11,200 dscfm), including all flue
gas products.
Overfire air is supplied through three rows of high pressure nozzles.
Two of the nozzle rows are located on the furnace front wall and a single row
is located on the rear wall. It is assumed that the units do not have
auxiliary fuel firing capacity. The model plant utilizes continuous oxygen
monitors, which are located at the economizer outlet, but does not monitor
CO. Typical of all heat recovery units, flue gas temperature measurements
are made in the upper furnace Just upstream of the superheater and at the
exit of the economizer (inlet to the flue gas cleaning equipment). It is -
assumed that the flue gas temperature at the economizer outlet is maintained
at 500°F.
5-3.2.2 Emission Control System Design and Operation. As shown in
Table 5.0-1, 8 of the 9 plants in this subcategory are equipped with ESP's.
The New Hanover plant has a 2-field ESP with PM emissions of 0.05 gr/dscf
adjusted to 7 percent 0». For the model plant, it will be assumed that most
existing plants are similar to New Hanover from a particulate control
performance standpoint.
5.3.2.3 Envi ronmental Baseline. Table 5.3-2 also presents baseline
emissions data for the model plant. It is assumed that the overfire air
system does not provide adequate mixing to achieve low organics and CO
emissions. As a result, baseline uncontrolled COD/CDF emissions are
established at 2000 ng/dscm, and baseline CO emissions are 400 ppmv,
corrected to 7 percent 0-. Typical of mass burn water-wall MWC's, an average
uncontrolled particulate rate of 2.0 gr/dscf is selected for the model plant.
Uncontrolled emissions of HC1 and S02 are assumed to be 500 ppmv and 200 ppmv,
respectively. It is assumed that the combustion process results in a waste
volume reduction of 90 percent (70 percent by weight).
5-72
-------
5.3.3 Good Combustion
The following sections describe retrofits necessary to bring the
performance of the model plant to a level which is representative of good
combustion practice. The retrofits address the design, operation/control,
and verification elements of good combustion practice.
5.3.3.1 descriptionof Modifications.
Overfire Air System. The model requires a redesign of the overfire air
system to provide good mixing patterns in the upper furnace. Flow modeling
studies are required to establish the new jet sizes and configuration. It is
assumed that the existing fan h.as adequate capacity to provide the needed
quantities of air. Because the waterwalls are assumed to be tube and tile
construction rather than membrane wall, relocation of overfire air nozzles,
if necessary, will not require modification to the waterwall tubes.
Equipment needed for the new system includes ducting, dampers, nozzles, and
pressure monitors. Improved mixing conditions will be verified through
in-furnace profiling of CO, CL, and temperature, and through the use of
continuous monitors.
UnderfireAir System. Monitors will be added to each of the underfire
air plenum supplies to provide a continuous reading of the individual plenum
pressures.
Auxiliary Fuel. The model plant requires installation of auxiliary fuel
burners in the combustion chamber above the highest row of overfire air
nozzles. The exact placement of the burners can be established as part of
the flow modeling studies. The auxiliary fuel firing capacity needed for
each unit is approximately 22.5 HMBtu/hr (60 percent of full load thermal
input). The auxiliary fuel burners will be used during start-up and
shutdown, and during any upsets which result in abnormally high CO levels or
low furnace temperatures.
0>, Trim Loop. The model plant's combustion control system will be
modified to include an 0- trim loop. The purpose of this control loop is to
adjust automatically the distribution of underfire air to the various
undergrate plenums in the event that 0^ concentrations vary from established
upper and lower set points. When used in combination with a steam
flow/underfire air control loop, the control system will have the ability to
5-73
-------
adjust both air quantities and distributions with changing waste burning
characteristics, thus improving the stability of the burning process on the
grates and minimizing the occurrence and severity spikes in CO and organic
emissions.
CO Monitors. New CO monitors must be installed to provide continuous
verification of stable combustion conditions. The monitors should be at the
same location as the existing 02 monitors at the boiler outlet, and should
include readouts and integrators.
Retrofit Considerations. It is estimated that total downtime for each
unit will be 2 weeks in order to complete retrofit of the combustion systems
as described above. Flow modeling studies can be completed in approximately
3 months while the units remain operational.
5.3.3.2 Environmental Performance. Through the proper application of
the retrofits described above, it is estimated that emissions of CDD/CDF
will be reduced to 200 ng/dscm corrected to / percent 0«. In addition,
emissions of CO are estimated to be reduced to 50 ppmv corrected to 7 percent
Q-. No change in uncontrolled PM emissions is assumed to result from the
modifications. No changes in HC1 or SO- emissions are assumed since these
are related to waste properties which are not expected to vary due to
combustion modifications.
5.3.3.3 Costs. Cost estimates are provided in Table 5.3-3 for the
combustion retrofit options described above. The total capital cost of the
modifications is estimated to be $492,000. Annual costs are presented in
Table 5.3-4. Annualized capital costs are $80,000 based on a 10 percent
interest rate and a 15-year facility life. Total annualized costs, including
annualized capital and yearly O&M costs, are $205,000/year.
5.3.4 Good Particulate Control
5.3.4.1 Description of Modifications. The model plant's 2-field ESP's
are well-operated and are relatively new in operation. The ISP's can reduce
the inlet from 2.0 gr/dscf to 0.05 gr/dscf operating at an inlet flue gas
temperature of 500°F. To cool the inlet flue gas temperature to 450°F, water
will be sprayed in the ductwork between the economizer and the ESP.
Demolition of the existing ductwork between the economizer and the ESP is
required for installing 14 feet of larger diameter ducting with a cross-
5-74
-------
TABLE 5.3-3. PLANT CAPITAL COST FOR COMBUSTION MODIFICATIONS
(Two units of 100 tpd eich)
Item Costs (31,000)
DIRECT COSTS:
Flow Modeling Studies 75
New Overfire Air Nozzles 25
Gas Pipeline (1/2 mile) 50
Auxiliary Gas Burners 99
CO Monitoring 44
CO Profiling 10
02 Trim System 25
Total 328
INDIRECT COSTS AND CONTINGENCY 164
TOTAL CAPITAL COSTS 492
DOWNTIME COSTS 118
ANNUALI2ED CAPITAL COSTS AND DOWNTIME 80
5-75
-------
TABLE 5.3-4. PLANT ANNUAL COST FOR COMBUSTION MODIFICATIONS
(Two units of 100 tpd each)
Item Costs ($1,000)
DIRECT COSTS:
Gas Consumption 15
Maintenance Labor 28
Maintenance Material 28
Operating Labor _0
Total 71
INDIRECT COSTS:
. Overhead 34
Taxes, Insurance, and Administration 20
Capital Recovery 80
Total 134
TOTAL ANNUALIZED COST 205
5-76
-------
sectional area of 25 square feet. This larger diameter ducting is required
to ensure that enough residence time is available for flue gas cooling
(0,7 seconds). A water rate of 1.2 gpm is required to cool the flue gas to
450°F for each combustor. No relocation of the ID fan is expected.
Access and congestion to install the humidification equipment are high
due to the close proximity of the ESP and the economizer. Installation of
the humidification equipment can be expected to be completed during the
scheduled shutdown of the plant. Therefore, no unscheduled downtime is
required.
Because the flue gas flow rate is reduced by humidification, it is
expected that the existing ESP will be able to reduce PM emissions to
0.05 gr/dscf without adding more plate area. No modifications to the ESP's
are expected. The existing opacity monitor can be reused.
5.3.4.2 Environmental Performance. Particulate matter emissions will
remain unchanged from baseline. Total CDO/CDF and acid gas emissions are
expected to be equal to the concentrations at the combustor exit.
i.3.4.3 Costs. Capital cost requirements for good particulate control
are presented in Table 5.3-5. The major cost item is the temperature control
equipment. Total capital cost is $381,000. This estimate includes purchased
equipment, installation, and indirect costs such as engineering and
contingencies. A high APCD congestion factor for the 14-foot ducting used
for temperature control is assumed.
Annual costs are presented in Table 5.3-6 for good particulate control.
The costs are dominated by annualized capital recovery and downtime.
Indirect annual costs including capital recovery and downtime is $83,000.
Direct operating and maintenance costs are estimated at $31,000. Thus, total
annualized cost for good PM control is 5115,000 per year.
5.3.5 Best Particulate Control •
5.3.5.1 Description of Modification. To achieve best PM control (a PM
emission level of 0.01 gr/dscf) with an inlet grain loading of 2.0 gr/dscf
will require an ESP operating at 450°F with a total plate area of 12,200 ft .
2
The existing ESP has a total plate area of 5,830 ft . Therefore, to achieve
an emission limit of 0.01 gr/dscf, the existing ESP will be upgraded by
2
adding an additional plate area of 6,320 ft . This additional plate area
5-77
-------
TABLE 5.3-5. PLANT CAPITAL COST FOR PARTICULATE MATTER AND
TEMPERATURE CONTROLS (Two units of 100 tpd each)
Item
DIRECT COSTS:
PM Control3
Equipment
Access/Congestion Cost
Temperature Control
Humldificatlon Costs
Access/Congestion Costs
New Flue Gas Ducting*
Ducting Costs
Access/Congestion Cost
Other Equipment
Stacks
Demol 1 tt on/Re 1 ocati on
Total
Indirect Costs and Contingencies
Monitoring Equipment0
TOTAL CAPITAL COST
DOWNTIME COST
ANNUALIZED CAPITAL RECOVERY
AND DOWNTIME
Costs ($1000)
Good PM
Control
0
0
291
6
7
4
0
4
312
69
0
381
0
50
Best PM
Control
1,140
284
291
6
19
7
0
11
1,760
560
120
2,440
235
352
Based on moderate access/congestion.
'Based on high access/congestion for ducting.
"Turnkey.
1-78
-------
TABLE 5.3-6. PLANT ANNUAL COST FOR PARTICIPATE MATTER AND TEMPERATURE
CONTROLS (Two units of 100 tpd each)
Costs ($1000)
Item Good PH Best PM
Control Control
DIRECT COSTS;
Operating Labor 12 12
Supervision 2 2
Maintenance Labor 13 13
Maintenance Materials 4 23
Electricity 0 4
Mater 1 1
Waste Disposal 0 1
Monitors 0 16
Total 31 72
INDIRECT COSTS:
Overhead 18 30
Taxes, Insurance, and
Administration 15 93
Capital Recovery and Downtime 50 35£
Total 83 475
TOTAL ANNUALIZED COST 115 547
5-79
-------
will be added as a second ESP downstream of the existing ESP. As shown in
Figure 5.3-2, installation of the new ESP will not require relocation of the
ID fan. In addition, 25 feet of ductwork is needed to connect the second ESP
to the existing stack. A new opacity monitor will also be installed at the
outlet of the second ESP.
Similar to good particulate control, demolition of ductwork between the
economizer and the ESP is required for installing 14 feet of larger diameter
ducting which will be used to humidify and cool the flue gas. A water rate
of 1.2 gpm is required to cool the flue gas to 450°F for each combustor.
This ducting will allow gas residence time of about 0.7 seconds for gas
cooling.
Access and congestion to install the humidification equipment are high
due to the close proximity of the ESP and the economizer and at the ESP
outlet. Access and congestion to install the new ESP plate area are
moderate. Downtime for this addition will be approximately 1 month for each*
unit.R
5.3.5.2 Environmental Performance. Particulate matter emissions will
be reduced from 0.05 to 0.01 gr/dscf. The additional recovered fly ash will
add about 26 tons/yr to total solid waste disposal requirements. This is a
2.0 percent increase in fly ash to disposal. Emissions of COD/CDF and acid
gases are equal to the concentrations at the combustor exit.
5.3.5.3 Costs. Total capital cost requirements for best particulate
control, presented in Table 5.3-5, are estimated at $2,440,000, The major
cost item is the particulate control equipment. This estimate includes
purchased equipment, installation, and indirect costs such as engineering and
contingencies. Estimates assume a moderate APCD congestion factor for the
ESP, high APCD congestion factor for the ducting used for temperature
control, 25 feet of additional duct, and ductwork demolition. The costs are
dominated by annualized capital recovery and downtime. Indirect costs
including capital recovery are estimated at $352,000 per year.
Annual costs are presented in Table 5.3-6 for best particulate control.
Direct O&M costs are $72,000 per year. Thus, total annualized cost for best
PM control is $547,000 per year.
5-80
-------
Stack
New
Plata
Ami
1.0, Fan
ESP
Water -y-
Sprays —j<
ESP
Cooling
Tower
Ash
Removal
Area
Water
•Sprays
Unit Unit
#1 #2
Existing Incinerator
Building
Office
Building
Refuse Pit
Figure 5.3-2.
Plot plan of new ESP plate area
equipment arrangement.
5-81
-------
5.3.6 GoodAcid Gas Control
5.3.6.1 Descr 1 ption of Hodificat1 on. For good acid gas control on
each combustor, dry- sorbent will be injected in the combustor furnace through
existing overfire air ports. Duct sorbent injection was not considered
because of limited space between the economizer and the ESP. Water spray
nozzles will be installed as similarly discussed in Section 5.3.4.1 to
provide the needed flue gas temperature reduction. A water rate of 3.6 gpra
per combustor is required to cool the flue gas to 350°F. New equipment for
sorbent injection includes one storage silo (one for the plant), a pneumatic
sorbent system, four sorbent feed bins (two for each combustor), and four
pneumatic injection nozzles (two for each combustor) Hydrated lime sorbent
will be fed at a calcium-to-acid gas molar ratio of 2:1. At full-load, a
sorbent injection rate of 117 Ib/hr is required for each combustor.
Reduction in HCT and SO, are estimated at 80 and 40 percent, respectively.
The existing ESP will require additional plate area to reduce PM
emissions to 0.01 gr/dscf. A separate ESP located in series behind the
existing unit will require 6,500 ft of plate area. The project also
includes monitoring equipment for HC1, SOj, C£L, 0^, and opacity. Monitors.
for HC1, SO- and 02 will be located in the ducting upstream of the sorbent
injection area and at the outlet of the secured ESP. The opacity monitor
will be located at the outlet of the second ESP. Figure 5.3-3 shows the
retrofit changes. As shown in this figure, installation of a new ESP will
require relocation of the ID fans. In addition, 25 feet of ductwork is
needed to connect the second ESP to the existing stack. Downtime is expected
R
to be 1 month per combustor for ductwork tie-ins.
5.3.6.,2 Environmental Performance. Total COO/CDF emissions are expected
to be reduced by 75 percent from the inlet level or 50 ng/dscm whichever is
greater. Acid gas emission reductions are estimated at 80 percent for HC1
and 40 percent for SO-, respectively. As noted above, PM emissions would be
reduced.to 0.01 gr/dscf. An additional 1,230 tons/year of waste {sorbent and
fly ash) will be added to the baseline waste disposal requirements for the
plant.
5.3.6.3 Costs. Capital cost requirements for dry sorbent injection are
presented in Table 5.3-7. Most of the cost is associated with the
temperature and particulate control equipment. Total capital cost is
5-82
-------
Stack
l.D,,
Fan
l.D. Fan
New
Plate-
Area
ESP
Water -c—
Sprays—]<
ESP
Cooling
Tower
Ash
Removal
Area
Office
Building
Water
Sprays
Unit Unit
#1 92
Existing Incinerator
Building
Refuse Pit
Figure 5.3-3. Plot plan of dry sorbent injection
retrofit equipment arrangement.
5-83
-------
TABLE 5.3-7. PUNT CAPITAL COST FOR DRY SORBENT INJECTION WITH ADDITION
• OF ESP PLATE AREA (Two units of 100 tpd each)
Item Costs ($1,000)
DIRECT COSTS:
Acid Gas Control1
Equipment 384
Access/Congestion Cost 39
Parti oil ate and Temperature Controla'
Equipment 1,470
Access/Congestion Cost 304
New Flue Gas Ducting*
Ducting Cost 18
Access/Congestion Cost 7
Other Equipment
Stacks 0
Demolition/relocation 12
Total 2,230
Indirect Costs & Contingencies 999
Monitoring Equipment5" S73
TOTAL CAPITAL COST 3,810
DOWNTIME COSTS 235
ANNUALIZED CAPITAL RECOVERY AMD DOWNTIME 531
aBased on moderate access/congestion.
Based on high access/congestion for ducting of temperature control
cTurnkey.
5-84
-------
$3,810,000. This cost estimate assumes a moderate APCD access/congestion
level for sorbent injection and ESP upgrade, and a high APCD access/congestion
for the ducting used for temperature control and ductwork demolition/fan
relocation.
Annual O&M and indirect costs for good acid gas control are presented in
Table 5.3-8. Major direct operating costs are monitoring equipment
maintenance and line. The largest annualized cost is annualized capital
recovery and downtime. The total annualized cost for the control option is
$1,250,000 per year.
5,3.7 Best Acid Gas Control
5.3,7.1 Description of Modifications. To achieve greater reductions
of COD/CDF, SQ^, and HC1, a new spray dryer/fabric filter system will be
installed on each combustor. The existing ESP will be demolished to make
room for the spray dryer vessels. Two new smaller stacks will be included
because of an extremely difficult tie-in from the fabric filter to the
existing stack. However, the existing stack will not be demolished. Lime
slurry will be introduced in each spray dryer at a 2.5:1 calcium-to-acid gas
molar ratio. Additional water in the lirae slurry of 4.7 gpm will be required
to cool the flue gas to 300°F for each combustor. The proposed equipment
layout is illustrated in Figure 5.3-4.
This sketch also shows the location of the lime"receiving, storage, and
slurry area which will serve the spray dryers. A fabric filter with
5,060 effective square feet of cloth (gross air-to-cloth ratio of 3:1} will
be installed following each spray dryer. The increased pressure drop of a
fabric filter over an ESP will require a new ID fan for each unit as well.
An estimated 60 feet of new duct will be needed to connect the spray dryer/
fabric filter to the the existing stack. New monitoring instruments for HC1,
S02» and 02 will be installed at both the inlet of the spray dryer and the
outlet of the fabric filter. An opacity monitor will be installed at the
o
outlet of the fabric filter. Downtime is expected to be 1 month for tie-in.
5.3.7.2 Environmental Performancg. CDO/CDF emission reductions of
99 percent or 5 ng/dscm, whichever is greater are expected. Emissions of PM
will be reduced from 0.05 gr/dscf to 0.01 gr/dscf. Acid gases will be reduced
90 percent for SCL and 97 percent for HC1.
5-85
-------
TABLE 5.3-8. PLANT ANNUAL COST FOR DRY SQRBENT INJECTION WITH ADDITION
OF ESP PLATE AREA (Two units of 100 tpd each)
Item Costs ($1,000)
DIRECT COSTS:
Operating Labor 60
Supervision 16
Maintenance Labor 26
Maintenance Materials 45
Electricity 28
Water 2
Lime 75
Waste Disposal 31
Monitors 214
Total 498
INDIRECT COSTS:
Overhead 88
Taxes, Insurance, and Administration 129
Capital Recovery and Downtime 531
Total 748
TOTAL ANNUALIZED COST - 1,250
5-86
-------
Staclt
I.D..
Fan"
Fabric
Filter
d)*
. Stack
• 1.0. Fan
• Existing Stack
Fabric
Filter
Coaling
Tower
Ash
Disposal
Area
Unit Unit
#1 #2
Existing Incinerator
Building
Office
Building
Refuse Pit
Figure 5.3-4,
Plot plan of spray dryer/fabric filter
retrofit equipment arrangement.
ee
i*
s
00
8
5-87
-------
5.3,7.3 Costs. Capital cost requirements for installing the spray
dryer/fabric filter systems are presented in Table S.3-9. Total capital cost
is estimated at $8,190,000. This figure includes purchase equipment,
installation, ESP demolition, addition of two new stacks, ductwork
demolition, and indirect costs such as engineering and contingencies.
Estimates assume moderate access and congestion, 60 feet of new ductwork, and
new ID fans.
Annual operating costs are presented in Table 5.3-10. Significant
direct operating expenses include maintenance materials, electricity for the
larger 10 fan needed due to increased pressure drop access in the fabric
filter, and monitoring equipment maintenance. Total annualized costs,
including capital recovery and downtime, would be $2,190,000.
5.3.8 Summary of Control Potions
5.3.8.1 Description of Control Costs. The control technologies
described in the previous sections have been combined into seven retrofit
emission control options. Table 5.3-11 summarizes the combustion, particu-
late control, and acid gas control technologies described in Sections 5.3.3
through 5.3.7 that were combined for each of the control options described in
Section 3.0. It should be noted that since the model plant already achieves
good PH control at baseline, Option 1 is identical to Option 2.
5.3.8.2 Environmental Performance. The performance of each control
option is summarized in Table 5.3-12. For each pollutant, the table presents
both the pollutant concentrations and annual emissions. The greatest
reductions on acid gases, particulate matter, and CDD/CDF all are achieved
with a spray dryer/fabric filter system. The next most effective control for
all thest pollutants is the dry sorbent injection technology. Dry sorbent
injection technology increases the baseline solid waste disposal by about
6 percent, and the spray dryer/fabric filter system increases the baseline
solid waste disposal by about 5 percent.
5.3.8.3 Costs. The total annualized cost of each option is presented
in Table 5.3-13. The most expensive control option is the spray dryer/fabric
filter installation with combustion modification {Option 7). The total
capital cost for this option is $8,680,000 and the total annualized cost is
$2,380,000. The annualized cost is roughly 7 times higher than the annualized
5-1
-------
TABLE 5.3-9. PLANT CAPITAL COST FOR SPRAY DRYER WITH FABRIC FILTER
(Two units of 100 tpd each)
Item
Based on moderate access/congestion
'Turnkey
Costs (S1000)
DIRECT COSTS:
Acid Gas Control3
Equipment
Access/Congestion Cost
New Flue Gas Ductinga
Ducting Cost
Access/Congestion Cost
Other Equipment
Fans
Stacks
Demolition/Relocation
Total
Indirect Costs
Contingency
Monitoring Equipment
TOTAL CAPITAL COSTS
DOWNTIHE COSTS
ANNUAL IZED CAPITAL RECOVERY
3,320
836
29
7
93
211
495
4,990
1,480
1,150
573
8,190
235
1,110
5-89
-------
TABLE 5.3-10, PLANT ANNUAL COST FOR SPRAY DRYER WITH FABRIC FILTER
(Two units of 100 tpd each)
Item Costs (S1000)
DIRECT COSTS:
Operating Labor 96
Supervision 14
Maintenance Labor 53
Maintenance Materials 99
Electricity 65
Compressed Air 8
Water 2
Lime 62
Waste Disposal 40
Monitors 21.5
Total 654
INDIRECT COSTS:
Overhead 149
Taxes, Insurance, and Administration 285
Capital Recovery 1,110
Total 1,540
TOTAL ANNUALIZED COST 2,190.
alncludes bag replacement costs of $13,000.
5-90
-------
TABLE 5.3-It. SUM1ARY OF COMTROL OPTIONS FOR. SHALL MASS BURN UATERUAU. COMBUSTOft
Pacttcutaie control
Actd Cat Control
Combustion Temperature Existing ESP
Control Option Description Modifications Control Rebuilt
Additional
SCA
New
Fabric Filter
Sorbent
Inject Ion
Spray
Dryer
1. Good Combust Ion and
Temperature Control
2. Good PM Control with
Combustion Control
3. Best PM Control and
Cocnbustlon and Temperature
Control
4. Good Acid Gas Control,
Best PH Control and
Temperature Control
5. Good Acid Gas Control
and Best PN/Cotnbuitlon/
Temperature Control
6. Beit Acid Gas Control,
Best fit Control., and
Temperature Control
?. Best Acid Cas Control and
Beit PH/Combujtlon/
Teof>erature Control
-------
cn
i
to
rv>
TABLE 5.S-12. EHVIROOffiHTAL PEHTORMAKCE SUMMARY FOB SHALL MASS BURN MATERHALL KUC
MODEL PLAHT RETROFIT CONTROL OPTIONS
(Two unit* of 100 tpd **ch)
Total COD /CDF En In Ion*
(ot/dgco)
1 Reduction v*. Ba»ellne
00 Emliilona
(pptnv)
H»/ft
X Reduction ft- B***llne
PM Emit lion*
(ir/d»cf)
Hg/jrc
X Reduction v». Ba**lln«
SO Enl*»lon*
(pparv)
Mi/fr
I Reduction v». Be**ttn*.
BC1 Eal**lons
(pponr)
Ht/jr
I Reduction vi. Huellne
total Solid Waste
(ton* /day)
**''* c
I lncr«**e v* . BacellM
Ba**Llne
3,000
7.8E-4
—
400
120
—
0.05
30
—
200
146
--
SOO
212
--
60
18,140
Option 1
200
S.2E-S
93
SO
IS
88
0,05
30
0
200
146
0
SOO
212
80
'
60
18,140
0
Option 2
200
S.2E-S
9)
50
IS
88
0.05
30
0
ZOO
146
0
SOO
212
0
60
18,140
0
Option 3
200
S.2E-S
93
SO
IS
68
0.01
6
20
ZOO
146
0
500
212
0
60
18,170
0.1
Option 4
SOO
81
400
120
0
0.01
6
20
120
8?
40
100
42
80
64
19,260
6
Option S
SO
1.3E-S
98
50
IS
88
0.01
6
20
120
87
40
100
42
80
64
19,260
6
Option 6
12
S.2E-6
99.3
400
120
0
0,01
6
20
19
14
90. S
IS
6
97
65
19,610
8
Option 7
S
1 , 3E-6
99, •
SO
15
W
0.01
6
20
19
14
90.5
IS
6
97
6S
19,610
8
All flu« §** concentrmtIon* »re report«d on t dry ? percent 0 b««l*.
b
M*i* calf*lon cat** *r« for total plant (both combuiior«).
-------
TABLE 5.1-11. COST SUItMRY FOR SMALL MASS BURN UATEEUALL MIC MODEL PLAJCT
RETROFIT CONTROL OPTIOKS* (Two unit* at 100 tpd)
U1
I
10
CO
Option 1 Option 2 Option 3 Option 4 Option 5 Option 6 Option 1
Total Capital Co it
Dovntlm* Co»t
Annuall**d Capital and
Downtime Coat
Direct OIK Cost
Total Annual Cost
Coit Ef f«cMV*neii
($/ton HSU)
Facility Dotmtlra*
(Month* )
Total Canplltnct TlOM
(Month*)
873 873 2,930 3,810 4,300 8,190 8,680
118 118 235 235 23S 235 215
120 120 *12 543 . 592 1,110 1,170
. 102 102 143 *9a 569 654 725
320 320 736 1,250 1,440 2,190 2,3*0
4,80 4.80 11.00 18.80 21.60 32.90 35.70
0.5 0.5 1 1 1 1 1
11 13 19 19 19 25 25
All coat* (except cott «ff«ctlv«n«i») giv*n in $1000. All ceit* an In D»c*mb«r 1907 dollar*.
-------
costs for option 1. Overall, both capital and annualized costs are higher for
higher levels of control.
5,3.8.4 Energy Impacts. Table 5.3-14 presents a summary of the energy
impacts associated with the control options. The average use figures are
incremental use. The spray dryer with fabric filter control options consume
the most electricity. Auxiliary fuel is fired for those options requiring
combustion modifications all at the same rate of 3 billion Btu per year.
1-94
-------
TABLE 5.3-14. ENERGY IMPACTS FOR SHALL MASS BURN
WATERWALL COHBUSTOR CONTROL OPTIONS4
Option
1
2
3
4
5
6
7
Electrical Use
(MWh/yr)
1.5
1.1
93.8
601
601
l,420b
l,420b
Gas Use
(Btu/yr)
3.2E9
. 3.2E9
3.2E9
0
3.2E9
0
3.2E9
aIncrease from baseline consumption.
Total electrical use excludes the electrical savings of not operating the
existing ESP's.
5-95
-------
5.4 REFERENCES
1. Heap, N.D., Lanisr, M.S., and Seeker, W.R., Energy and Environmental
Research Corporation. Municipal Waste Combustion Study: Combustion
Control of MSW Combustors to Minimize Emission of Trace Organics.
EPA/530-SW-87-021C. June 1987.
2, Epner, Radian Corporation, and Schindler, P. Energy and Environmental
Research Corporation. Trip Report - Retrofit Control Site Evaluation at
Saugus Resco Facility. February 16, 1989.
3. Epner, E., Radian Corporation, and Schindler, P., Energy and
Environmental Research Corporation. Trip Report - Retrofit Control Site
Evaluation at the Nashville Thermal Transfer Corporation. March 1, 1988.
4. Martinez, J,» Radian Corporation, and Schindler, P., Energy and
Environmental Research Corporation, trip Report -Retrofit Control Site
Evaluation at the New Hanover County Municipal Solid Waste (MSW} Resource
Recovery Facility.
5. Schindler, P., Energy and Environmental Research Corporation, Combustion.
Control Memorandum - Existing MWCs, Draft Report. October 31, 1988.
5-96
-------
6.0 REFUSE-DERIVED FUEL (RDF)-FIRED COMBUSTORS
Refuse-derived fuel (RDF) combustion practices have undergone some
evolution since their inception in the 1960's and 70's. A number of
obstacles related to fuel processing, feeding, and combustion had to be
overcome prior to establishing RDF as a viable technology. Some of these
challenges continue to exist in the current generation of RDF plants. An
extensive discussion of these topics is available in a report prepared for
Argonne National Laboratory, which contains a number of historical case
studies describing RDF processes. This section describes the current design
and operation of RDF-fired MWC's and identifies features in their design and
operation which minimize air pollution.
The existing population of RDF-fired MWC's consists of 18 operating
plants. Table 6.0-1 lists the RDF-fired MWC's in operation as of 1988.
Most of these facilities burn primarily ftDF. Several utility boilers also*
co-fire RDF as a supplemental fuel. Thirteen of the 18 existing plants use
spreader-stoker boilers, which is the most common design for a dedicated RDF
combustor. Four of the existing facilities burn RDF as a portion of total
fuel input in pulverized coal (PC) boilers. One plant (Wilmington, DE)
co-fires RDF with raw municipal solid waste (MSW) in a modular excess air
combustor. Refuse-derived fuel is also burned in fluidized-bed combustors
(FBC's). Of the 18 RDF plants, 14 have electrostatic precipitators (ESP's)
for PH control and 3 are equipped with spray dryer/fabric filter systems.
One has a cyclone.
Two .RDF-fired model plants were developed to represent the population
of existing facilities. Both model plants burn RDF as a primary fuel in
spreader-stoker boilers, which are the predominant RDF-fired boiler. The
first (Section 6.1) represents a plant with large (unit size > 600 tpd), and
the second (Section 6.2) represents a plant with smaller units. Each model
plant Is equipped with an ESP for PM control.
A set of standards for classifying RDF types has been established by
ASTM and is presented in Table 6.0-2. The type of RDF used is dependent on
the boiler design. With few known exceptions, boilers that are designed to
burn RDF is a primary fuel utilize spreadtr-stokers and fire RDF-3 (fluff,
6-1
-------
TABLE £.0-1. EXISTING WF-FIRED FACILITIES
o»
Plant Location
Lawrence, MA
Niagara Fall*, Ht
Dad* County, WL
Hertford, CT
Portsmouth, VA
Coluabu*. OH
Red Hint, MH
Mankato, MH
Penobacot, K£
Blddaford, MB
Akron, OH
Albany, NV
Hadl.on, VI (Ojcar May
Hadl.on (Git), HI
Aroaa, IA
Lakeland, FL
Baltimore (GlE), KD
Ullolnston, DE
Coobustor Type
Spreader/Stoker Boiler*
Spreeder/Stoker Boiler.
Spreader /Stoker Boiler*
Spreader /Stoker Boiler*
Spreader /Stoker Bollar*
Spreader/Stoker Boilers
Spreader/Stoker Bollari
Spreader/Stoker Botlera
Spreader/Stoker Bollar*
Spreader /Stoker Boiler*
Spreader/Stoker Boilers
Spreadar /Stoker Boiler*
er)Spread*r/Stokar Boiler*
Pulverlted Coal Bollari
Pulverlted Coal Boiler*
Pulverized Coal Bolter*
Pulverised Coal Bollar*
Modular £*««•* Air MWC
80. of Unit*
1
2
*
3
4
6
. 2
2
2
2
3
2
I
2
2
1
2
5
Unit Slsa
(tjXJ)
looo
1000
750
667
500
400
360
360
360
350
300
300
60
HA*
i e 700
1 i 1400
320
MA
120
Percent
RDF FUed
100X
1001
10QX
100X
1001
100X
100X
1001
100X
100X
100X
100X
100X
151
18Z
18X
101
10X
SOX
Year of
Start -Up
198*
1981
1982
1988
1988
1983
1987
1987
1988
1988
197»
1981
1979
1919
197$
1981
198)
1980
1987
Air Pollution Control Device
Electrostatic Praclpltator
Electrostatic Preclpltator
Electrostatic Praclpltator
Spray Dryer/Fabric Filter
Electrostatic Praclpltator
Electrostatic Praclpltator
Electrostatic Praclpltator
Electrostatic Preclpltator
Spray Dryer/Fabrlc Filter
Spray Dryer/Fabric Filter
Electrostatic Preclpltator
Electrostatic Preclpltator
Cyclone
Electrostatic Preclpltator
Electrostatic Preclpltator
Electrostatic Preclpltator
Electrostatic PrectpUsror
Electrostatic Preclpltator
Electrostatic PreclpltuLor
HA - Information not available.
-------
TABLE 6.0-2. ASTH CLASSIFICATION OF REFUSE-DERIVED FUELS
Type of RDF Description
RDF-1 (MSW) Municipal solid waste used as a fuel in as-discarded
form, without oversize bulky waste (OEM),
RDF-2 (c-RDF) MSW processed to coarse particle size, with or without
ferrous metal separation, such that 95 percent by
weight (wt %) passes through a 6-inch square mesh
screen.
RDF-3 (f-ROF) Shredded fuel derived from MSW and processed for the
removal of metal, glass, and other entrained
inorganics. The particle size of this material is such
that 95 wt % passes through a 2-inch square mesh
screen. Also called "fluff RDF."
RDF-4 (p-RDF) Combustible-waste fraction processed into powdered
form, 95 wt % passing through a 10-mesh (0.035 Inch
square) screen.
RDF-5 (d-RDF) Combustible waste fraction densified (compressed) into
the form of pellets, slugs, cubettes, briquettes, or
some similar form.
RDF-6 Combustible-waste fraction processed into a liquid fuel
(no standards developed).
RDF-7 Combustible-waste fraction processed into a gaseous
fuel (no standards developed).
6-3
-------
or f-RDF) in i semi-suspension mode. This mode of feeding is accomplished
by using an air-swept distributor, which allows a portion of the feed to
burn in suspension and the remainder to be burned out after falling on a
horizontal traveling grate. Schematics of typical RDF spreader-stoker
boilers are shown in Figures 6.1-2 and 6.2-1. The number of RDF
distributors in a single unit varies directly with unit capacity. For
example, each of the 1,000 tpd units at Niagara Falls, NY is equipped with
8 distributors.
Suspension-fired RDF boilers, such as pulverized coal-fired (PC}
boilers, can co-fire RDF-3 or ROF-4 (powered or p-RDF). If RDF-3 is used,
the fuel processing must be more extensive so that a very fine fluff results.
Currently, the 4 PC boilers in operation co-fire fluff with pulverized coal.
Suspension firing is usually associated with larger boilers due to the
increased boiler height and retention time required for combustion to be
completed in total suspension. Smaller systems firing RDF in suspension
require moving or dump grates in the lower furnace to handle the falling
material that does not complete combustion in suspension. Boilers co-firing
RDF in suspension are generally limited to 50 percent of total heat input by
RDF alone. When multiple fuels are burned, the optimum balance of under-
fire, overfire, distributor air, and possibly burner air, is far more
difficult to establish and control.
Guidelines for minimizing emissions of trace organics have been
2
developed for RDF combustors. A list of design, operation/control, and
verification components associated with the guidelines is presented in
Table 6.0-3. These guidelines are directed toward conventional spreader-
stoker ROF boilers and may not be adapted to suspension-fired systems or
FBC's. As such, the discussion of these guidelines and their application is
focused on the spreader-stoker facilities.
The basic guidelines that apply to mass burn systems also apply to RDF
systems. These guidelines require that:
t stable stoichiometries be maintained through proper distribution
of fuel and combustion air,
• good mixing be achieved at a sufficiently high temperature to
adequately destroy trace organic species, and
6-4
-------
TABLE 6,0-3 COMPONENTS OF GUIDELINES - GOOD COMBUSTION PRACTICES FOR
MINIMIZING TRACE ORGANIC EMISSIONS FROM ROF-FIRED MWC'S
Element
Component
Design
Operation/Control
Verification
Temperature at fully mixed height
Underfire lir control
Overflre i1r capacity
Overfire air injector deslqn
Furnace exit gas temperature
Excess Air
Turndown restrictions
Start-up procedures
Use of auxiliary fuel
Oxygen in flut gas
CO in flue gas
Furnace temperature at fully mixed height
Temperature at APCD inlet
Adequate air distribution
6-S
-------
• tht design and operational performance of the system be verified
through monitoring or performance tests.
These design, operation/control, and verification practices are expected to
minimize trace organic emissions. Recent research data Indicate that
CDD/CDF formation may also occur at lower temperatures in downstream
portions of the system through catalytic reactions. Therefore, another
guideline should be Included which addresses this phenomenon. This guide-
line Is to minimize the retention time of flue gases in the temperature
window where CDD/CDF formation occurs. A discussion of basic Industry
practices and the application of set of guidelines is presented in the
following paragraphs.
Fuel Feeding
As mentioned above, spreader-stokers generally use air-swept
distributors to feed RDF into the combustion chamber. The distributors are
normally adjustable so that the trajectory of the waste feed can be varied m
from front to rear of the furnace. Because the traveling grate moves from
the rear to the front of the furnace, distributor settings are adjusted so
that most of the waste lands on the rear two-thirds of the grate. This
allows more time for combustion to be completed on the grate. Some
traveling grates operate at a single speed, but most can be manually
adjusted to accommodate variations in burning conditions.
Three common problems with RDF feeding include:
• plugging of distributors, resulting in feed interruptions and
stoichiometry upsets,
• erosion of waterwall surfaces by abrasive constituents in the
feed. This can sometimes be corrected by adjusting distributor
trajectories, and
• high participate carryover out of the radiation section of the
boiler.
Due to the basic design of RDF feeding practices, particulate loadings are
typically at least twice as high as mass burn systems and more than an order
of magnitude higher than modular starved-air combustors. The higher
particulate loadings may contribute to the catalytic formation of CDD/CDF.
6-6
-------
Combustion Air
Underfire air is normally preheated and introduced beneath the grate by
a single plenum. One of the newer facilities (Hartford, CT), is equipped
with a multiple plenum design. This is a desirable feature which provides
the operator with better ability to vary the distribution of underfire air
to various portions of the fuel bed.
Overfire air is injected through rows of high-pressure nozzles,
providing a zone for mixing and completion of the combustion process. The
guideline specifies that systems incorporate a design capacity of 40 percent
of total air as overfire air. Operational quantities are typically less
than 40 percent of total, although the Red Wing, MN facility reports a
normal operating ratio of 50/50. The guideline also specifies that overfire
air systems provide complete coverage and penetration of the furnace cross-
section to achieve good mixing. As shown in Figures 6.1-2 and 6.2-1, a
typical RDF boiler has a straight wall design. As unit size increases,
boiler cross-sections provide greater distances that nozzles must penetrate.
Therefore, nozzle diameters, pressures, and velocities will change. A new
lower furnace design used at the Biddeford, ME facility includes pinched
walls through which overfire air is injected into the combustion gases. The
pinched section greatly reduces the cross-sectional area of the boiler, but
may increase the vertical velocities of gases in that section of the
combustion chamber.
Auxiliary Fuel
All ROF-fired HWC's have the capability to co-fire additional fuels.
Four of the existing spreader-stokers in Table 6.0-1 co-fire coal or wood
with RDF under normal operating conditions. The remaining facilities are
equipped with natural gas, fuel oil, or combination gas/oil burners. The
burners are operated during start-up, shutdown, and during periods of RDF
feed interruption. Because the use of auxiliary fuels is expected to be
more frequent in RDF facilities than in mass burn waterwall systems, it is
critical that burner design, location, and capacity be optimized.
Low Temperature Catalytic Formation of_CDD/CDF
Downstream catalytic formation of CDD/CDF may be particular problem in
RDF facilities for two reasons. First, existing units typically operate
6-7
-------
it ESP temperatures between 500 and 600°F, where formation has been
demonstrated. Second, the higher uncontrolled particulate emission rates
associated with this technology may provide more surface area for catalytic
reactions to occur. However, few emissions data are available from RDF
facilities to document the effects of these variables on CDD/CDF emissions.
6-8
-------
6.1 LARGE ROF-FIRED COMBUSTOR
This section presents the case study results for a large RDF
spreader-stoker facility (unit size greater than 600 tpd). As shown in
Table 6.0-1, there are 4 existing facilities within this subcategory.
Section 6.1.1 presents a description of the Occidental Chemical Corporation
facility in Niagara Falls, NY, which was visited to gather information for
model plant development. Section 6.1.2 presents a description of the model
plant. Sections 6.1.3 through 6.1.7 detail the retrofit modifications,
estimated performance, and costs associated with each control option.
Section 6.1.8 presents a summary of the control options, which are discussed
in more detail in Section 3.0 of this report..
6.1.1 Descriptionof the OccidentalRDF-Fired Facility3
The Occidental Energy From Waste (EFW) project began with a feasibility
study in 1973. Construction began in 1978, and was essentially complete in
1980. The original project cost of $94 million was funded through a leveraged
lease using Niagara County Industrial Development Bonds. A 2-1/2 year
start-up and system redesign costing another $50 million was required to
bring the facility to acceptable levels of continuous operation. Occidental
currently Teases the facility from a group of banks. However, Occidental
would bear the burden of any retrofit costs brought about by regulation.
Table 6.1-1 presents design data for the EFW facilities, and
Figure 6.1-1 is an overall process diagram. The facility consists of,an
on-site waste processing plant and 2 Foster-Wheeler boilers with Detroit
Stoker air-swept distributors and traveling grates. Each unit is rated at
1,200 tons of RDF per day with a design rating of 300,000 Ib/hr of superheated
steam and 25 HW of electricity. Normal operating rates are currently about
230,000 Ib/hr steam production per unit, which plant personnel consider to be
the effective maximum continuous operating capacity of each unit. The
combined effective electrical generating capacity of both units is 35 MW.
Steam and electricity are delivered to the adjacent Occidental chemical plant
and excess electricity sold to the local utility. The EFW facility was sized
to provide the chemical plant with 100 percent of its steam requirements.
Furnace partlculati emissions are controlled by separate 4-field hot-side
ESP's. Acid gases are not controlled.
6-9
-------
TABLE 6.1-1. OCCIDENTAL DESIGN DATA
Combustor:
Type
Number of Combustors
Combustor Unit Capacity
Straight Wall Spreader Stoker
2
1,000 tpd
Emission Controls:
Type
Manufacturer
Number of Fields
Inlet design particulate loading
Operating Temperature
Design Collection Efficiency
Permitted PN Emissions
Gas Flow
Total Plate Area
Calculated SCA
Gas Residence Time In ESP
- Electrostatic Precipitator
- Belco
- 4
-3.36 gr/acf
- 550°F to 62Q°F
- 99.77 percent
- 0.03 gr/dscf at 12% C02a
- 367,420 acfm 9 650°F
- 146,900 ft2
- 400 ft2/!,000 acfm
- 10 seconds
Reference 5.
6-10
-------
Figure 6.1-1. General process diagram of EFW facility.
(Figure provided by Occidental Chemical Corp.)
-------
6.1.1,1 CombustorDesign and Operation. The EFW facility receives
municipal solid waste (HSW) and processes RDF on site. Prior to fuel
processing, bulky or large non-combustible waste is separated on the tipping
floor and routed to a landfill. With the exception of these items, all of
the incoming waste is processed into RDF. The waste receiving pit has
2 lines of 16 hydraulic rams that push the MSW onto the shredder feed
conveyors. Each of three 1,500-hp shredders (horizontal-type hammer mills)
is equipped with forty 225-pound hammers. Each shredder was designed to
process 70 tons of waste per hour, and currently each shreds approximately
50 to 60 tons per hour. Ferrous materials are magnetically separated and
recovered. The RDF, nominally less than 4 inches in particle size, is then
conveyed to the storage building. Storage capacity is 5,000 tons.
The rate of fuel fed to each boiler is controlled by surge bins. Each
surge bin contains 24 augers and delivers RDF through individual feed chutes"
to eight 10-inch by 24-inch air swept distributors in the boilers. The
distributors are located on the front wall, approximately 3 feet above the
grate. The front-to-rear distribution of RDF on the grate can be adjusted by
varying the air supplied to the distributors. Higher air velocities
concentrate more waste on the back portion of the traveling grate. The RDF
feed rate can be set to respond either to the steam flow or the steam
pressure. Plant personnel indicated that it is more typical to operate in a
flow control rather than a pressure control mode. The grate speed is
manually set and adjusted based on the steam production rate. The fuel burns
in a semi-suspension mode with combustion taking place partially in suspension
in the furnace and partially on the traveling grate. The grate area is
594 square feet, and desired grate speed was reported to be 5 to 7 ft/hr. As
a result of burning waste in semi-suspension, the grate area per unit weight
of fuel burned is considerably less than that found in typical mass burn
plants. Plant personnel reported the desired thickness of the ash bed coming
off the grate to be 4 to 6 inches.
Eight coal feeders are located 7 feet, 3 inches above the RDF
distributors on the front wall, but coal is not currently fired. Fuel oil
and natural gas burners (4 each) are located on the rear wall about 10 feet
6-12
-------
above thi RDF distributors. Natural gas is currently fired In the furnaces
during start-up and during periods when RDF feeding is interrupted. Start-up
is achieved with a 6-hour warm-up period on gas and refuse feed is Initiated
after 10 percent of steam load is attained while firing gas. The units are
brought up to full load on a prescribed load curve. Each of the natural gas
burners has a rated firing capacity equal to one-fourth of the unit capacity,
so each furnace can be operated at full load on supplemental fuel. Both of
the units also have the ability to burn hydrogen, which is available as a
by-product from the .adjacent chlorine plant. However, this has not been done
recently.
The furnace is designed to operate at 8.2 percent excess 0- (dry).
However, the boilers are currently operated between 10 and 14 percent excess
(L (90 to 200 percent excess air) with 70 percent of the total air supplied
as underfire air. A forced-draft fan moves combustion air through a gas-to-
air preheater and supplies preheated primary air to 2 laterally separated
plenums located under the grate. A booster fan located downstream of the air
preheater routes a portion of the preheated air to the secondary (overfire)
air headers and the RDF distributor.
The-overfire air system has been redesigned as a result of flow modeling
studies. Rows of interlaced and opposed overfire air jets are located on the
upper rear and front walls at an elevation approximately 16 feet above the
RDF distributors. There are seventeen 3-inch nozzles on the front wall and
twelve 3.5-inch nozzles on the rear wall. Intermediate overfire air rows are
also located on the front wall and the rear wall above the RDF distributors.
There are forty 2-inch diameter intermediate air nozzles in the 2 rows on the
front wall and seventeen 3-inch diameter air nozzles on the rear wall.
Carrier air is supplied by the booster fan to the RDF distributors on the
front wall and a lower overfire air row on the rear wall. The carrier air,
which is used to blow the RDF into the combustion chamber, is supplied
through five 2-inch diameter nozzles per distributor. There are seventeen
3-inch diameter lower air nozzles on the rear wall, 1.5 feet below the RDF
distributors. Four soot blowers are located on the rear wall between the
-------
lower and intermediate overfire air rows. Overfire air flow rates are
adjusted so that the, majority of the flow is Introduced at the rear wall
location, where the burning is concentrated.
Adjustments to total airflows are made by changing overfire air settings
while maintaining constant undtrfire air flow rates. Excess air rates are
manually set to provide the desired excess 0. level. The boilers operate
only at base load, so variations in excess air to accommodate load changes
are not normally required. An oxygen trim loop is available, but the plant
reports that it has not been used due to the unstable operation of the
boilers. Excess air levels are operated higher than design in an attempt to
keep furnace temperatures at an acceptable level and to avoid slag formation
in the lower furnace and corrosion in the upper furnace.
Honitors are in place which provide continuous readings of CL, CO, flue
gas temperatures, and flue gas opacity. Oxygen and CO are measured at the
boiler outlet. Flue gas temperature measurements are made at the inlet to
the convective section of the boiler and between the convective section and
the convective section of the boiler and between the generating section and
the economizer. Opacity is measured in the stack. None of the emission
monitor readings are used for process control. Occidental reported that they
are able to keep CO below 100 ppm (uncorrected).
6.1.1.2 Emission Control System Design and Operation. Each combustor
is equipped with a Belco 4-field ESP. Table 6,1-1 presents design and
operating parameters for the ESP's. Particulate testing indicates the units
are in compliance with Federal and State regulations of 0,03 gr/dscf at
12 percent 0~. Extensive inlet and outlet PM emissions data are available
under varying load conditions. Flue gas temperatures entering the ESP's
range from 550 to 620°F. The air preheater is located downstream of the
ESP's.
The ESP's are located inside the building. A dyct, 2 feet 8 inches in
width, connects the economizer to the ESP. This duct is approximately
20 feet long. However, it runs vertically between the economizer and ESP
with only about 3 feet of clearance on the ESP side, and only 8 inches on the
furnace side.
6-14
-------
6.1.2 Description of Model Plant
6.1.1.2 Combustor Design and Operation. Table 6.1-2 presents design
data for the model plant. A model plant was selected consisting of two
1,000-tpd RDF-fired units. The model plant uses a spreader-stoker design to
burn fluff RDF on a seven days per week, 24 hours per day operating schedule.
The boiler configuration is a typical straight-wall design, and the stoker is
a variable speed traveling grate. The equipment arrangement of the model
plant is shown in Figure 6.1-2.
As with all 4 of the operating facilities, fuel feeding is accomplished
by air-swept distributors. The model contains 8 RDF distributors located on
the front wall of the boiler. The boilers also have 4 burners which can fire
natural gas or fuel oil located on the rear wall. Each burner has a rated
heat output of 105 MM Btu/hr. All 4 burners fired simultaneously can provide
100 percent of design steam load.
Each model boiler operates at 125 percent excess air with an
overfire/underfire air ratio of 30/70. The RDF feed composition assumed for
model plant development is presented in Chapter 2 of this report.
Stoichiometric air requirements for the fuel are approximately 4.25 Ib of air
per Ib of RDF. For a 1,000 tpd unit, the theoretical air requirements are
78,700 scfm. At 125 percent excess air, the total flue gas flow from the
unit Is approximately (194,200 scfm) 182,900 dscfm.
Typical of older RDF systems, underfire air is preheated by a
regenerative air heater located downstream of the ESP, Underfire air is
supplied beneath the traveling grate at a temperature of 350°F through
2 separate parallel plenums. The air plenums divide the grate laterally into
2 separately controlled burning regions, with each region fed by 4 RDF
distributors.
The overfire air system consists of 2 nozzle rows on the boiler front
wall and 2 rows on the rear wall. It is assumed that the overfire air
penetration and coverage is not optimized to provide sufficient mixing. This
assumption 1s based on an assessment of measured emissions available for the
group of combustors represented by this model.
6-15
-------
TABLE 6.1-2 MODEL PLANT BASELINE DATA FOR LARGE RDF-FIRED COMBUSTOR
Combustor:
Type
Number of Combustors
Combustor Unit Capacity
Emission Controls:3
Type
Number of Fields
Inlet Temperature
Collection Efficiency
Gas Flow
Total Plate Area
SCA at 392,600 acfm
Emissions:
COD/CDF
PM (stack)
CO
HC1
Operating Data:
Remaining Plant Life
Annual Operating Hours
Annual Operating Cost
Spreader-Stoker
2
1,000 tpd
Electrostatic Precipitator
4 n
600°F
99.8 percent
392,600 acfm
204,000 ft*
520 ftVI.000 acfm
3,000 ng/dscp
0.01 gr/dscfc
200 ppmv
500 ppmv
300 ppmv
> 20 years
8,000 hours
S22,700,000/year
Per combustor.
All emissions are dry, corrected to 7 percent Q-.
clnlet PM emissions to the ESP are 4 gr/dscf at 7 percent
6-16
-------
ID Fan
Figure 6.1-2. Equipment arrangement of the model plant.
fi-17
-------
The combustion control system for the model plant is designed to
maintain constant steam flow or steam pressure. This is accomplished by
automatic adjustment of RDF feed rates. The steam flow controller sends a
signal to the feeding system and the speed of the metering screws auto-
matically adjusts to change the feed rate and raise or lower steam flow to a
desired set point. Air flows are manually set and adjusted in an attempt to
maintain a relatively stable excess air level. This is verified by a
continuous oxygen monitor located at the economizer outlet. Flue gas
temperatures are recorded in the upper portion of the radiation section of
the boiler and at the economizer outlet location. The assumed economizer
outlet temperature is 600°F.
6.1.2.2 Emission Control System Design and Operation. As shown in
Table 6.0-1, 3 of the 4 plants in this subcategory are equipped with ESP's.
The fourth plant is equipped with a spray dryer/fabric filter. The
Occidental plant has a 4-field ESP with PM emissions of about 0.012 to
0.03 gr/dscf at 7 percent Q~. Test data from the other two ESP-equipped
MWC's indicate PM emissions of 0.01 gr/dscf or less. For the model plant, a
PM emission rate of 0.01 gr/dscf is assumed.
The model plant has 2 combustors, and each is equipped with a 4-field
ESP controlling PM emissions to 0.01 gr/dscf. At a gas flow of 392,600 acfm,
the SCA of the ESP's is 520 ft2/!,000 acfm. Total plate area is 204,100
square feet. An opacity monitor is located at the outlet of the ESP, The
flue gas flows from the outlet of the ESP to an air preheater'and then to the
stack. Figure 6.1-3 shows a plot plant of the model plant. Because the
combustor and ESP are located indoors, a high access and congestion level is
assumed for retrofitting additional APCD's. This access and congestion level
is typically of other large RDF facilities being that the combustors and the
APCD's are also located indoors.
6.1.2.3 Environmental Baseline. Table 6.1-2 presents baseline emission
data for the model plant. Baseline uncontrolled CDD/CDF emission levels are
assumed to be 2,000 ng/dscm, corrected to 7 percent 02< These values are
measured at the exit of the boiler. It is assumed that the hot ESP increases
baseline COO/CDF emissions by 50 percent, so that stack concentrations are
3,000 ng/dscm.
6-18
-------
Combustor
Combustor
/ \
ESP
\ /
r
Building AirPrehaaters
ESP
Stacks
\
0981388R
Figure 6.1-3. Plot plan for the model plant.
-------
RDF-fired facilities generally exhibit higher uncontrolled participate
emissions than other technologies due to the manner in which the fuel is
fired (semi-suspension mode). This model plant is assumed to have an
uncontrolled PM emissions of 4.0 gr/dscf, corrected to 7 percent 02.
As a result of insufficient mixing conditions, uncontrolled CO emissions
from the model plant are assumed to be 200 ppmv at 7 percent 0-. Uncontrolled
HC1 and SOg emissions are estimated to be 500 and 300 ppmv at 7 percent CL,
respectively. It is assumed that the combustion process reduces waste volume
by 95 percent (90 percent by weight).
6.1.3 Good Combustjon and Ixhaust Gas Temperature Control
The following sections describe combustion retrofits necessary to bring
the performance of the model plant to a level which is representative of good
combustion practices. The combustion retrofits address design, operation/
control, and verification elements of good combustion practice.
6.1.3.1 Description of Modifications
Overfire Air Systems. Due to insufficient mixing conditions, the model
plant will require a redesign to the overfire air system. The overfire air
configuration can be established as a result of cold flow modeling studies.
The size, location, and pressures for each row of nozzles will be established
as a result of the study. It is assumed that the modeling results require a
design that includes 2 rows of overfire air nozzles on each of the front and
rear walls, and that the location of these rows will be different than in the
baseline case. New nozzles locations will require modification to existing
water-wall tubes so that new nozzles penetrations can be made. As part of the
flow modeling studies, the location and firing patterns of the auxiliary
burners should also be examined to determine the effects of firing auxiliary
fuel" on overfire air patterns. The modified overfire air system provides
better mixing conditions and lower emissions of trace organics and CO from
the furnace.
Fuel Feeding. The RDF feeding system is redesigned to include metered
feeders, which provide more uniform distribution of RDF on the traveling
grate and more stable burning conditions. Four separate metered feeding
modules are required for each boiler, serving 2 RDF distributors each.
6-20
-------
Excess Air Levels. As a result of the fuel feeding and combustion air
modifications made to the model plant, the excess air operating level can
safely be reduced to 80 percent. This contributes to reductions in CO and
uncontrolled particulate emissions. In addition, reductions in excess air
rates directly affect adiabatic flame temperatures. For a waste with
25 percent moisture content, flame temperatures should increase by about
150 to 200°F. At 80 percent excess air the theoretical air requirements are
reduced to 142,000 scfm, and total air flows from the boilers are
158,800 scfm (147,500 dscfm).
ESP Temperature. In order to minimize the potential for CDD/CDF
formation in lower temperature regions of the MWC system, the flue gas
temperature entering the ESP roust be reduced from 600 to 450°F. The existing
ductwork is redesigned so that flue gases exit the boiler and are routed to
the air heater, where available heat is transferred to combustion air supplied
by the existing forced-draft fan. The flue gases are then ducted back to the
ESP inlet location. New insulated ductwork is required as part of the
redesign.
In order to provide flexibility with regard to ESP operating
temperatures, the modifications at the model plant include installation of
ducting and dampers to allow bypass of up to 100 percent of the combustion
gases around the air heater. This modification provides the operators with a
means of adjusting the operating temperature of the ESP, as needed. It is
assumed that the system has the capability of reducing ESP inlet gas tempera-
tures to 350°F. At normal operating conditions a percentage of the gases
bypass the air heater, and the ESP inlet gas temperature is reduced to 450°F.
Determination of the overall effect of these flue gas modifications will
require a detailed analysis that is beyond the scope of this study. Excess
air levels, combustion air inlet temperatures, flue gas velocities, and many
other factors will influence corabustor exit gas temperatures. However, the ,
modifications included in this study will all contribute to improved emission
performance.
Combustion Control and Monitoring. The primary control loop in the
baseline plant regulates the rate of RDF feed to the boiler based on a
desired steam flow. However, the modified combustion air system will also
6-21
-------
require control of air flows and distribution, temperature, and other
features. Therefore', an automatic combustion controller is installed to
provide full system control and monitoring. Continuous CO monitors are
installed at the economizer outlet to provide verification of combustion
stability. The combustion control system also ties in the existing 0» and
temperature monitors as needed to fully automate the system.
Retrofit Considerations. It is estimated that modeling studies can be
completed in 3 months while the units remain on-line. During this time
engineering studies for the needed modifications can be completed. It is
estimated that total downtime required to complete the modifications is
2 months per unit.
6.1.3.2 Environmental Performance. Through the application of the
combustion modifications described above, it is estimated that emissions of
CDO/CDF are reduced to 1,000 ng/dscrn, corrected to 7 percent (L. In addition-,
CO emissions are reduced to 150 ppmv on a 4-hour average. No change in
particulate or acid gas emissions can be expected due to the modifications.
6.1.3.3 Costs. Table 6.1-3 presents the costs required to complete the
required combustion modifications. Total capital cost estimates are
$4,330,000 for both units. Annualized capital and downtime is estimated to
be $1,430,000 based on a 10 percent interest rate and a 15-year facility
life. Annual costs are presented in Table 6.1-4. The total annualized
costs, which include Q&M and annualized capital, are estimated to be
$1,690,000.
6.1.4 Best Particulate Control
5.1.4.1 Description of Modifications. The ESP's for this model plant
reduce PM emissions from an inlet PM loading of 4.0 gr/dscf to 0.01 gr/dscf
at 600°F. Because the flue gas flow rate is reduced after combustion
modification, the existing ESP's are assumed to still achieve 0.01 gr/dscf.
This outlet PM emission level is the same level required for best PM control
(0.01 gr/dscf) and thus is well below the level required for good PM control
(0.05 gr/dscf). Therefore, no equipment modifications are required for
compliance with either control level.
To cool the flue gas from 600 to 450°F, the flue gas ducting between the
economizer and the ESP will be rerouted to .the air preheater such that the
6-22
-------
TABLE 6.1-3. PLANT CAPITAL COST FOR COMBUSTION MODIFICATIONS
(Two units of 1,000 tpd RDF each)
Item Costs ($1,000)
DIRECT COSTS:
Flow Modeling Studies 75
Overfire Air Nozzles 383
Metered Feeders 1,740
Combustion Controller 290
Automatic CO Monitors 44
Ducting, Dampers, Insulation for
Air Preheater 352
Total 2,880
INDIRECT COSTS AND CONTINGENCY: 1,440
TOTAL CAPITAL COSTS 4,330
DOWNTIME COSTS 6,520
ANNUALIZED CAPITAL RECOVERY AND DOWNTIME 1,430
6-23
-------
TABLE 6.1-4. PLANT ANNUAL COST FOR COMBUSTION MODIFICATIONS
(Two units of 1,000 tpd RDF each)
Item Costs ($1,000)
DIRECT COSTS:
Maintenance Labor 28
Maintenance Materials 28
Total S6
INDIRECT COSTS:
Overhead 34
Taxes, Insurance, and Administration 173
Capital Recovery and Downtime 1.430
Total 1,640
TOTAL ANNUALIZED COST 1,690
6-24
-------
flue gas leaving the economizer 1s sent to the air preheater before going to
the ESP. The flue gas temperature at the outlet of the air prehetter will be
reduced to 450°F from the heat absorbed by the incoming combustion air. As
shown in Figure 6.1-4, no relocation of the ID fan is required for modifying
the air preheater. The existing opacity monitor can also be used.
Cooling of the flue gas to 450°F will increase the SCA from 520 to 606
2
ft /I,000 acfm, which is sufficient to maintain best PM control. No
additional plate area is required to achieve a PH emission level of
0.01 gr/dscf» after the flue gas is cooled to 450°F.
6.1.4.2 Environmental Performance. PM emissions are assumed to be the
same before and after cooling of the flue gas. Emissions of CDD/CDF and acid
gases are equal to concentrations at the combustor exit.
6.1.4,3 Costs. No additional costs are required for this control
option, because the existing ESP can achieve the best particulate control
level without incurring additional costs.
6.1.5 Good Acid_Gas Control
6.1.5.1 Description of Modification. For good acid gas and CDD/CDF
control, dry sorbent will be injected into the combustor through existing
overfire air ports. Duct sorbent injection was not considered because of
limited space between the economizer and the ESP. New equipment for sorbent
injection includes 2 storage silos (1 for each combustor), a pneumatic
sorbent transport system, 4 sorbent feed bins (2 for each combustor), and
4 pneumatic sorbent injection nozzles (2 for each combustor). Hydrated lime
sorbent will be fed at a calcium-to-acid gas molar ratio of 2:1. At full
load, a sorbent injection rate of 1,610 Ib/hr is required for each combustor
with and without good combustion practices. Reduction in HC1 and SO. are
estimated at 80 and 40 percent, respectively.
The air preheater will be modified as discussed in Section 6.1.3.1 to
provide flue gas cooling to 350°F. The existing ESP will be reused and be
operated at 350°F. The SCA of 680 ft2/!,000 acfm at 350°F for the existing
ESP is more than adequate for removing the injected sorbent during baseline
and good combustion conditions. Therefore, the existing ESP will not require
additional plate area to reduce PM emissions to 0,01 gr/dscf.
The project also includes monitoring equipment for HC1, SO-, and 0-.
The monitors will be located at the outlet of the existing ESP. Installation
6-25
-------
0981389R
Combustor
Air Preheater
v—\
ESP
7
Building
Combustor
ESP
Air Preheater
Stacks
Figure 6.1-4. Plot plan of temperature control equipment arrangement.
6-26
-------
of the dry sorbent injection equipment will not require relocation of the ID
fan. Figure 6.1-5 shows the retrofit changes. Downtime is expected to be
3 months per combustor.
6.1.5.2 Environmental Performance. Total CDD/CDF emissions are
expected to be reduced by 92 percent. Acid gas emission reductions are
estimated at 50 percent for HC1 and 50 percent for SO^, respectively. As
noted above, PM emissions would be 0.01 gr/dscf. An additional
16,400 tons/year of waste (sorbent} will be added to the baseline waste
disposal requirements for the plant.
6.1.5.3 Costs. Capital cost requirements for dry sorbent injection
are presented in Table 6,1-5 for baseline and good combustion practices.
Total capital costs are $2,770,00 and $2,240,000 for baseline and good
combustion, respectively. Included in the total capital costs for baseline
combustion is the costs to modify the air preheater for temperature control, .
This cost estimate assumes a 10 percent increase in sorbent injection
equipment costs.
Annual O&H and indirect costs for both combustion practices are presented
in Table 6.1-6. Major direct operating costs are associated with lime and
solid waste disposal. The largest annualized cost is capital recovery and
downtime. The total annualized costs for the baseline and good combustion
are $3,600,000 and $3,510,000, respectively.
6.1.6 Best Acid Gas Control
6.1.6.1 Description of Modifications. To achieve greater reductions
of COD/CDF, SCL, and HC1, a new spray dryer/fabric filter system will be
installed on each combustor. The spray dryer/fabric filter will be located
outside the building near the stack. Flue gas from the combustor will be .
bypassed around the existing ESP and sent to the air preheater before going
to the spray dryer and fabric filter. The air preheater will be used to cool
the flue gas to 450°F as discussed in Section 6.1.3.1 as well as provide
preheated combustion air to the boilers. The existing ESP will not be
demolished. A total of 200 feet of new duct will be installed for connecting
the spray dryer and fabric filter to the stack.
Lime slurry will be introduced in each spray dryer at a 2.5:1
calcium-to-acid gas molar ratio. Water rates in the lime slurry of 109 and
6-27
-------
MQ6C1860
/ \
A
I
\
•a
J2
H
a
I
Figure 6.1-5.
Plot plan of dry sorbent Injection retrofit
equipment arrangement.
6-28
-------
TABLE 6.1-5. PLANT CAPITAL COST FOR DRY SORBENT INJECTION WITH ADDITION
OF ESP PLATE AREA (Two units of 1,000 tpd RDF each)
Item
DIRECT COSTS:
Acid Gas Control
Equipment
Access/Congestion Cost
Participate and Temperature Control
Equipment
• Access/Congestion Cost
New Flue Gas Ducting
Ducting Cost
Access/Congestion Cost
Other Equipment
Stacks
Air Preheater Modifications
Total
Indirect Costs & Contingencies
Monitoring Equipment3'
TOTAL CAPITAL COST
DOWNTIME COSTS
ANNUAL I ZED CAPITAL RECOVERY
AND DOWNTIME
aTurnkey.
•**^JKJK JC.MKUK Nk * UK M t*.M W M *k At t*. UB BBkM J* £4****+-* *%•*!« *« MfcM JMl
Costs
Baseline
Combustion
Practices
788
78
0
0
0
0
0
_252
1,220
1,040
514
2,770
9,780
1,650
r* 1 i i«in<>i 4 n /*«%f*it
($1,000)
Good
Combustion
Practices
788
78
0
0
0
0
_&>
866
862
514
2,240
9,780
1,580
*ll m * nE AM
modification costs {see Table 6.1-3).
6-29
-------
TABLE 6.1-6.
PLANT ANNUAL COST FOR DRY SORBENT INJECTION WITH ADDITION
OF ESP PLATE AREA (Two units of 15000 tpd RDF each)
Item
Costs ($1.000)
Baseline
Combustion
Practices
Good
Combustion
Practices
DIRECT COSTS:
Operating Labor
Supervision
Maintenance Labor
Maintenance Materials
Electricity
Water
Lime
Waste Disposal
Monitors
Total
INDIRECT COSTS:
Overhead
Taxes, Insurance, and Administration
Capital Recovery and Downtime
Total
TOTAL ANNUALIZED COST
71
90
1.650
1,810
3,600
48
14
13
43
28
0
1,030
411
206
1,790
71
69
1.580
1,720
3,510
6^30
-------
87 gpm will be required to cool the flue gas to 300°F for each combustor
during baseline and good combustion practices, respectively.
The location of the lime receiving, storage, and slurry area which will
serve the spray dryers is near the spray dryer. A fabric filter with 73,900
and 60,400 effective square feet of cloth (net air-to-cloth ratio of 4:1)
will be installed following each spray dryer during baseline and good
combustion, respectively. The increased pressure drop of a fabric filter
over an ESP will require a new ID fan for each unit as well. New monitoring
instruments for HC1, S02, and, Q2 will be installed at both the inlet to the
spray dryer and the outlet of the fabric filter. Also, an opacity monitor
will be installed at the outlet of the fabric filter. The proposed equipment
layout is shown in Figure 6.1-6. Downtime is expected to be 6 months.
6.1.6.2 Environmentaj performance. CDD/CDF emissions are expected to
decrease to 20 ng/dscm without combustion modifications and 10 ng/dscm with
combustion modifications. Emissions of PH will be at 0.01 gr/dscf. Acid
gases will be reduced 90 percent for S02 and 97 percent for HC1. Solid waste
will be increased relative to baseline amounts by 7,280 tons per year per
combustor or 14,600 tons per year for the plant.
6.1.6.3 Costs. Capital cost requirements for installing spray
dryer/fabric filter systems are presented in Table 6.1-7 for both combustion
practices. Total capital costs are estimated at $33,600,000 and $29,700,000
for baseline and good combustion, respectively and include purchase equipment,
installation, and indirect costs such as engineering and contingencies.
Estimates assume high access and congestion, 200 feet of new ductwork, and
new 10 fans.
Annual costs are presented in Table 6.1-8 for both combustion conditions.
Significant direct operating expenses include maintenance materials and
electricity for the larger ID fan needed due to increased pressure drop
access in the fabric filter. Total annualized costs are $11,900,000 and
$11,000,000 for baseline and good combustion, respectively.
6.1.7 Summary of Control Options
6.1.7.1 Description of Control Costs. The control technologies
described in the previous sections have been combined into seven retrofit
6-31
-------
ID Fan
Spray
Dryer
Sorbent
Storage and
Preparation
Area
Fabric
Filter
u
ID Fan
Figure 6.1-6. Plot plan of spray dryer/fabric filter retrofit
equipment arrangement.
n
3
§
6-32
-------
TABLE 6.1-7. PLANT CAPITAL COST FOR SPRAY DRYER WITH FABRIC FILTER
(Two units of 1,000 tpd RDF each)
Item
DIRECT COSTS:
Acid Gas Control3
Equipment
Access/Congestion Cost
New Flue Gas Ducting3
Ducting Cost
Access/Congestion Cost
Other Equipment
Fans
Stacks
Air Preheater Modifications
Indirect Costs
Contingency
Monitoring Equipment
TOTAL CAPITAL COSTS
DOWNTIME COSTS
ANNUAL I ZED CAPITAL RECOVERY AND
DOWNTIME
Costs
Baseline
Combustion
Practices
13,000
5,470
360
151
1,340
0
352
Total 20,700
6,820
5,480
573
33,600
19,600
6,990
($1,000)
Good
Combustion
Practices
11,700
4,980
326
136
M
1,100
_J<
18,200
6,020
4,850
573
29,700
19,600
6,480
aBased on high access/congestion.
Turnkey.
cCosts for air prtheater modifications are included in the combustor
modification costs (see Table 6.1-3).
6-33
-------
TABLE 6.1-8. PLANT ANNUAL COST FOR SPRAY DRYER WITH FABRIC FILTER
(Two units of 1,000 tpd RDF each)
Item
DIRECT COSTS:
Operating Labor
Supervision
Maintenance Labor
Maintenance Materials
Electricity
Compressed Air
Water
Lime
Waste Disposal
Monitors
Costs
Baseline
Combustion
Practices
96
14
53a
599a
746
109
26
853
548
115
(SI. 000)
Good
Combustion
Practices
96
14
53b
• 611
89
21
852
547
215
Total
3,260
3,020
INDIRECT COSTS
Overhead 342
Taxes, Insurance, and Administration 1,320
Capital Recovery and Downtime 6.990
Total 8,650
317
1,160
6.480
7,960
TOTAL ANNUALIZED COSTS
11,900
11,000
Includes bag replacement costs of $192,000.
Includes bag replacement costs of $157,000.
6-34
-------
emission control options. Table 6.1-9 summarizes the combustion, particulate
control, and acid ga-s control technologies described in Sections 6.1.3
through 6.1.6 that were combined for each of the control options described in
Section 3.0. It should be noted that since the model plant already achieves
good PH control at baseline, Options 1, 2, and 3.are identical.
6,1.7.2 Environmental Performance. The performance of each control
option is summarized in Table 6.1-10. For each pollutant, the table presents
both the pollutant concentrations and annual emissions. The greatest
reductions in acid gases, particulate matter, and COD/CDF all are arrived
with the spray dryer/fabric filter system. The next most effective control
for all these pollutants is the dry sorbent injection. Both sorbent addition
technologies increases the baseline solid waste disposal between 15 and
17 percent. Combustion modifications reduced baseline CO emissions by
25 percent.
6.1.7.3 Costs, The total annualized cost of each option is presented
in Table 6.1-11. The most expensive control option (Option 6 on an
annualized cost basis) is the spray dryer/fabric filter installation at
$11,800,000. This cost is roughly a factor of 7 higher than the costs for
Option 1. Annualized costs for Option 6 are higher than these after
Option 7, because the cost associated with the increase in the flue gas flow
rate for Option 6 be higher than the increase in cost of Option 7 due to
combustion modification. Overall, both capital and annualized costs are
higher for higher levels of control.
6.1.7.5 Energy Impacts. Table 6.1-12 presents a summary of the energy
impacts associated with the control options. The energy use figures are
incremental use. The spray dryer with fabric filter options consume the most
electricity. The electricity consumed by Options 6 and 7 is 10,600 and
7,710 MWh/yr, respectively. There is no increase in auxiliary fuel use
because auxiliary burners are already in place on the model plant and burn
the same amount of fuel under baseline and the other control options.
6-35
-------
TABLE 6,1-9. SUMMARY Of OOHTBOL OPTIONS FOR LARGE RDF-FIRED MIC MODEL PLANT
Pacticutatti control
Acid Gas Control
Combustion Temperature Existing ESP
Control Option Da script Ion ModIfIcattoiu Control Rebuilt
Additional
SO*
Mew Sorbenc Spray
Fabric Filter Injection Dryer
en
1, Good Combuitlon and
temperature Control
2. Good PH Control with
Combustion Control
3, Best PM Control and
Combustion and Temperature
Control
*. Good Acid pas Control,
Best PM Control and
fesperatur* Control
5. Good Acid Gaa Control
and Best PM/Cwnbuitlon/
Teio|iatatui:e Control
6. Best Acid Gas Control,
Best PH Control, and
Teopatature Control
7. Best Acid Gas Control and
Beit PH/Combustlon/
Teoperature Control
-------
TABLE 6.1-10. ENVIRONMENTAL PERFORMANCE SUMMARY FOR LARGE SBF-FIRED KUC MODEL PLANT
RETROFIT CONTROL OPTIONS*' (Two units of 1,000 tpd KI)f each)
Base line Option 1
Total CDD/CDF Emissions
(ni/dgcn) 3
M«/yr 9
X Reduction vi . Baseline
CO Eralilloni
(ppmv)
Hg/yr
I Reduction vs. Baseline
ttl Emissions
(gr/dscf)
Mg/yr
I Reduction vs. Baseline
SO Emissions
{ppmv)
Mglyr 2
X Reduction vs. Baseline
HCl Enlsslons
(pprav)
Mg/yr 2
X Reduction vs- Baseline
Total Solid y**tc
(tons/day)
H«/yr 60
I Increase vs. Baseline
All flue gas concentrations
.000
.6E-3
--
200
739
~-
0.01
73
—
300
,420
--
500
,430
—
200
,500
" «"
ate
1,000
3.2E-3
67
150
554
25
0.01
73
0
300
2,420
0
500
2,430
0
200
60,500
0
reported on s
Option 2 Option 3 Option 4
1,000
3 . 2E- 3
£7
150
554
25
0,01
73
0
300
2,420
0
500
2,430
0
200
60,500
0
i 7 percent
1 , 000 500
3.2E-3. 1.6E-3
67
150
.554
25
0.01 .
73
0
300
2,420 1
0
SOO
2,430 1
0
200
60,500 75
0
0 dry basis.
83
200
739
0
0.01
73
0
150
.210
50
250
,215
50
249
,400
25
Option 5
250
8.0C-4
92
150
551.
25
0.01
73
0
150
1,210
50
250
1,215
50
249
75,400
25
Option 6 Option 7
20
6.4E-5
99.3
200
739
0
0.01
73
0
29
230
90. 5
15
71
97
265
80,400
33
10
1.6E-5
99.7
150
554
25
0.01
7J
0
29
230
90.5
15
73
97
265
80,400
33
H*s« emission rates arc for total plant (both combuitori).
-------
TABLE 6.1-11. COST SUMMARY FOR LARGE RDF-FIRED MWC MODEL PLANT RETROFIT
CONTROL OPTIONS* (Two units of 1,000 tpd RDF ««ch)
00
Option 1 Option 2 Option 3 Option 4 Option 5 Option 6 Option 7
Total Capital Cost
Downtime Coat
Annuilired Capital and
Downtime Cast
Dlltcx OIN Cost
Total Annual Cost
Coit Effect tv*i>a*»
(SI ton RDF)
Facility Downtime
(Month*)
Total Compliance Tlott
(Month*)
4,330 4,330 k.330 2,770 6,570 33,600 34.000
6,520 «,520 6,520 9,780 9,780 19,600 19,600
1,430 1,430 1,430 1,650 2,150 6,990 7,050
16 54 16 1,790 1,850 3,260 3,080
1,690 1,690 1,690 3,600 4,340 11,900 11,800
2.53 2.53 2.53 5.40 6.51 17.90 17,70
2 2 2 3 3 6-6
7 7 7 19 19 25 25
*&il ca»t» («ncept east *£C«ctlvetM«s) In $1000. All coiti tlven In December 1987 dollar*.
-------
TABLE 6.1-12. PLANT TOTAL ENERGY IMPACTS FOR CONTROL OPTIONS2
Option
1
2
3
4
5
6
7
Electrical Use
(MWh/yr)
0
0
0
615
615
16,200b
13,300b
Gas Use
(Btu/yr)
0
0
0
0
0
*
0
0
Increase from baseline consumption.
Total electrical use excludes the electrical savings of not operating the
existing ESP's.
6-39
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6.2 SMALL RDF-FIRED CQMBUSTOR
This section presents case study results for small RDF-fired
facilities (individual unit size less than 600 tpd). As shown in
Table 6.0-1, 8 existing facilities are represented by this subcategory,
Section 6.2.1 presents a description of the Albany, NY facility, which was
visited to gather information for model development. Section 6.2.2 presents
a description of the model plant, including baseline design and performance
assumptions. Section 6.2.3 to 6.2.6 detail the retrofit requirements,
estimated performance, and costs associated with each retrofit option.
Section 6.2.7 presents a summary of the control options, which are discussed
in more detail in Section 3.0 of this report.
6.2.1 Description of the Albany. NY RDF-Fired FacilItv4
The Albany New York Solid Waste Energy Recovery System (ANSWERS)
consists of 2 component plants:
o RDF production plant owned ,-j the City of Albany and operated
under contract by AENCO, and
o Sheridan Avenue steam plant designed, owned, and operated by New
York Office of General Services.
The RDF processing plant is remotely located from the steam plant, because
of space limitations at the steam plant. The steam plant is situated on
less than an acre of land so that limited space is available for delivery
and storage.
The Albany Sheridan Avenue RDF-firtd plant began operation in 1981. It
consists of 2 identical waterwall combustors (boiler and firing system)
supplied by Zurn. Each combustor has a rated capacity of 300 tpd RDF (total
plant capacity 600 tpd). Plant design data are shown in Table 6.2-1.
Normal firing rate was reported to be about 500 tpd. The lower firing rate
is the result of limited steam demands and boiler/stoker size limitations
which will be discussed below. Maximum operating capacity was reported to
be about 640 to 660 tpd. Steam is produced for district heating and cooling
for the downtime Albany (Empire State Plaza) area. Steam generating
capacities are 100,000 Ib/hr of 2SO psig steam at 450°F. The plant operates
7 days/week and 24 hours/day.
6-40
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TABLE 6.2-1. ALBANY DESIGN DATA
Combustor:
Type
Number of Combustors
Combustor Unit Capacity
Plant Capacity
Emission Controls:
Type
Number of Precipitators
Manufacturer
Number of Fields
Inlet design participate loading
Operating Temperature
Design Collection Efficiency
Controlled PM Emissions
Gas Flow
Straight Wall Spreader-Stoker
2
300 tpd
600 tpd
Electrostatic Precipitator
2 (one per combustor)
Precipitair
3
3.0 gr/dsef at 12% C03
400 to 450°F c
99 percent
0.03 gr/dscf at 12% C0?
134,000 acfm *
6-41
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6.2.1.1 Combustor Design and Operation. The City collects MSW and
processes RDF that is sold to the steam plant based on the current price of
oil. According to. the contract with the State, the City of Albany is paid
63.3 percent of the cost of oil required to produce the same quantity of
steam as is actually produced by firing RDF. The heating value of RDF was
measured in tests performed by Raltech Laboratories in St. Louis in 1980,
and was reported to be between 4,500 and 4,600 Btu/lb,
The RDF produced at Albany is a coarse fluff RDF. The front-end
processing consists of two 1,500 hp diesel powered shear shredders with
50 tons/hour capacity (each)"and magnetic separators. The typical particle
size distribution of the RDF is 96.5 percent of the particles less than 2 by
2 inches. Trucks deliver the RDF to the steam generating plant and dump it
into a storage pit. An overhead crane transfers RDF from the dumping
station to a live center surge bin, where it is metered into separate chutes
that feed the combustors. The surge bin contains 8 vertical and 2 horizontal
metering screws. There are 2 air-swept RDF distributors per combustor. A
deflection plate 1n the distributor controls the trajectory of the fuel and
attempts to spread the RDF evenly from front to rear on the grate. Plant
personnel estimate that 40 to 50 percent of the RDF burns in suspension.
' Both of the combustion trains are identical. Typical of suspension-
fired RDF systems, a single traveling grate moves from the rear to the front
of each combustor at a fixed speed. Television cameras view across the
discharge end of the grate to allow observation of fuel burnout. If burning
is occurring at the end of the grate, the rate of fuel feeding is reduced.
The length of the traveling grate is approximately 19 feet. Based on
burnout of waste on the grate, the plant manager estimates that the grate is
approximately 30 percent too short. The single-speed stoker could
accommodate burn out at design load if the grite was longer or if the speed
could be reduced. Currently, however, the firing rates cannot be increased
to achieve the design load, A profile of the boiler and gas cleaning
equipment is provided in Figure 6,2-1.
Underfirt air is supplied through a single plenum beneath the grate.
Each boiler includes 2 rows of overfire air nozzles on the boiler front wall
and 2 rows of nozzles on the rear wall. On the front wall, 1 row of nozzles
6-42
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OJ
Steam Coil
Air Preheater
Figure 6.2-1. Albany RDF-fired boiler.
a.
r*
o>
8
-------
is located about 3 feet above the RDF distributor and the other is
approximately 25 feet above the distributor. On the rear wall, 1 row is
located at the level of the distributors and the other is approximately 20
feet above the distributor. The operating permit specifies that the system
be operated at 50 percent excess airf but the actual operating rate is
between 80 and 100 percent excess air with no overfire air. The actual
excess air levels are higher than design to improve boiler stability and to
minimize CO emissions. Operating instability reportedly results at
50 percent excess air. Plans are underway to remove the overfire air from
both combustors in the near future. This decision was based on results from
a number of tests including PM emission levels and continuous gas monitoring
under varying overfire air operating conditions. The Plant Manager stated
that the lowest CO levels were achieved when overfire air was off.
The boilers are equipped with auxiliary fuel burners which can fire
fuel oil or natural gas. Gas is preferred over oil, because problems with .
sidewall erosion have been encountered when oil is fired. The auxiliary
fuel burners are located on the lower rear wall of the boilers about 5 feet
above the RDF distributors. Each unit contains 3 burners with a combined
heat output of 85 percent of load capacity (approximately 106 MM Btu/hr).
The burners are fired during start-up to achieve steam pressure and
temperature. Approximately 4 hours of gas firing are required prior to
bringing the ESP's on line. Auxiliary fuel is normally fired for 8 to
9 hours before RDF feeding begins. One boiler is brought off line each week
from midnight on Friday until midnight on Saturday. The plant reports that
there have been only 2 unscheduled outages in 7 years of operation.
Since the RDF distributors are located on the opposite wall from the
auxiliary burners, problems with the RDF plugging the ignition and air doors
have been encountered. The steam plant 1s considering changing the location
of the auxiliary burners to the front wall of the combustor at a different
elevation.
Combustor temperatures were originally measured by 1 thermocouple
located just below the nose in the rear water-wall. Because of the extreme
temperatures at this location, the thermocouple had a short life. The plant
plans to replace this thermocouple with 3 thermocouples. The 3 thermocouples
6-44
-------
ire to bt located 1n a row on the back wall higher up in the combustor. The
recorded temperature will be an average of the 3 thermocouple values.
A number of additional design features are being altered in each of the
combustors. For example, the underfire air was originally preheated by a
steam-coil preheater, but this practice has been stopped. Stack gas
temperatures have hence been reduced from 500°F to 4IO°F. The lower 7 feet
of the furnaces were originally lined with silicon carbide refractory, but
this has been removed due to excessive build up of slag on the walls which
required removal by spikes and sledge hammers. Another factor contributing
to slagging was the practice of reinjecting economizer fly ash into the
furnace. This material was being injected through 3/4-inch tubes approxi-
mately 36 inches above the grate, and it was migrating to the side wall and
slagging. The injection also caused a sandblasting effect on the waterwall
tubes. In an effort to minimize these erosion problems this practice was
discontinued. "
Continuous gas monitoring for CO and CL takes place at the boiler exit.
Boiler controls include air flows which are automatically adjusted based on
steam flow. As mentioned above, the stoker is a single-speed type. RDF
feeding can be adjusted automatically bas3d on steam flow and temperature or
varied manually by adjusting the surge bin horizontal screw speeds. The
plant attempts to keep minimum boiler loads at 70 percent of rated capacity;
boiler stability becomes a problem when load is reduced to- between 50 and
60 percent. Burn out is acceptable based on visual inspections of the ash.
There are 6 combination gas/oil fired boilers adjacent to the RDF units to
pick up load swings as necessary when the waste-fired combustors are down
for scheduled maintenance. These boilers also can be operated during low
steam demands.
6.2.1.2 Emission Control System Design andOperation. Emissions are
controlled by two 3-field ESP's. Table 6,2-1 presents the design data for
the ESP's built by Precipitair and in use since the plant began operation.
The ESP's are located inside of the building. No major rebuilds have ever
been performed on them. Little detailed information about the ESP's was
available from the Plant Hanager at the time of the visit.
6-45
-------
The ESP's typically operate with an inlet temperature of about 400 to
450°F. Operating parameters recorded during the visit included:
Primary Voltage - 150 to 200 Volts AC
Primary Current - 1 to 20 Amps AC
Precipitator Voltage - 30 kV
The permit PM emission limit for the plant is 0.03 gr/dscf corrected to
12 percent CO-. Measured PM emissions ranged widely from 0.02 to
0.34 gr/dscf corrected to 70 percent 0^, Continuous opacity, SO*, and NOX
monitors are located in the stack. A single stack serves both boilers.
Emissions data available from 1 test in which RDF was the only fuel had HC1
and SO, emissions at the stack of 50 and 225 ppm, corrected to 7 percent 0-.
3 *
COO/CDF emissions during a single test series were 578 ng/Nm corrected to
12 percent COg. During the visit, stack opacity was observed to be 9 to
11.percent, as measured by the opacity monitor.
Fly ash and bottom ash are currently combined for co-disposal in a
landfill. There were numerous problems with the original ash handling
equipment which have resulted in a redesign of this portion of the plant.
Fly ash is currently conveyed to a separate truck loading area. The newly
designed ash handling system will start up sometime in the summer of 1988.
Total ash is estimated to be between 23 and 28 percent by weight of the
incoming RDF.
6.2.2 Description of Model Plant
There are 9 facilities firing RDF in small spreader-stoker boilers
(unit size less than 600 tpd). The oldest facilities in the group began
operating in 1979. Five of the 9 facilities have begun full-scale operation
in the last year: Red Wing, MN and Mankato, MN are converted coal-fired
stoker units; Biddeford, ME and Penobscot, ME co-fire wood with RDF; and
Portsmouth, VA co-fires RDF and coal. The Columbus facility commenced
operation in 1983, co-firing RDF and coal in its 6 boilers. Current
practice is to fire the fuels separately, using coal only as needed during
RDF shortages or during peak steam demands. The following sections describe
the model plant developed to represent the facilities in this category.
6.2.2.1 Combustor Design and Operation. Table 6.2-2 presents design
data for the model plant. The model plant configuration consists of two
6-46
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TABLE 6.2-2 MODEL PLANT BASELINE DATA FOR SMALL RDF-FIRED COMBUSTOR
Corabustor:
Type
Number of Combustors
Combustor Unit Capacity
Plant Capacity
Excess Air
Emission Controls:
Type
Number of Precipitators
Number of Fields
Inlet Temperature
Collection Efficiency
Gas Flow
Total Plate Area
. SCA. at 82,800 acfm and 450°F
Emissions:3
CDD/CDF (tetra - octa)
PM (stack)
CO
HC1
so2
Stack Parameters:
Height
Diameter
Operating Data:
Remaining Plant Life
Annual Operating Hours
Annual Operating Cost
Spreader-Stoker
Straight Wai
2
300 tpd
600 tpd
80 percent
Electrostatic Precipitator
2, one per combustor
.4 each
4508F
99.8 percent
82,800 acfm
39,600 ft*
478
2000 ng/dscm.
0.01 gr/dscf°
200 ppmv
500 ppmv
300 ppmv
200 feet
8 feet
> 20 years
1,000 hours
$12,200,000
aAll emissions are dry, corrected to 7 pgrcent 02- Standard and Normal
conditions are both 1 atmosphere and 70 F.
blnlet PM emissions to the ESP are 4.0 gr/dscf at 7 percent 0-
6-47
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300-tpd boilers, each firing 100 percent RDF. Five of the 9 existing plants
consist of 2 Individual boilers; there are 3, 4, and 6 boilers at Akron,
Portsmouth and Columbus, respectively. Unit sizes vary from 60 to 400 tpd,
with the exception of the 500 tpd boilers at Portsmouth, With the exception
of the newer Biddeford boiler, which uses a pinched-wall lower furnace
design, all of the boilers in the population are straight-wall designs.
Therefore, the model plant configuration includes 2 straight-wall boilers.
All of the facilities utilize a traveling grate with a single underfire air
plenum. This design feature is also included in the model plant. Typical
of all existing facilities, fuel feeding is accomplished by air-swept
distributors. The number of distributors varies with unit capacity. For
example, the 300 tpd boilers at Albany Include 2 distributors per unit, and
the 1,000 tpd boilers at Niagara Falls have 8 distributors each. Each of
the 300 tpd units in the model plant is assumed to have 2 Individual
distributors located on the boiler front wall.
Underfire air and overfire air are generally preheated prior to
injection into the combustion chamber. Based on an assessment of available
Information from existing facilities included in this category, it is
assumed that a tubular air heater is used, and that it is located upstream
of the flue gas cleaning equipment. Underfire and overfire air temperatures
are assumed to be 350°F entering the furnace, and flue gas temperatures
exiting the air heater are 450°F. The boiler is assumed to operate at
80 percent excess air, with 70 percent of the total air supplied as under-
fire air. The remaining 30 percent is supplied as overfire air. At
80 percent excess air, total combustion air requirements are 42,500 scfra,
with 29,750 scfm as underfire air. Total gas flow at the preheater is
approximately 82,800 acfm.
All RDF boilers have auxiliary fuel firing capacity. This is necessary
due to the potential for interruption in RDF feeding. It is assumed that
the model boilers have two combination gas/oil burners located on the rear
wall above the traveling grate. The burners have the ability to carry
100 percent of the boiler's design steam load. Some of the facilities in
this group of plants have in the past injected captured economizer ash back
into the combustion chamber of thi boiler. This practice has largely been
6-48
-------
discontinued due to waterwall tube erosion and slagging problems. As a
result, this design feature has not been includad in the model plant.
The most common combustion control loop in an RDF-fired plant utilizes
automatic control of fuel feed rates to maintain desired steam flow or
pressures. This feature is included in the control system for the model
plant. It is assumed that the combustion air flows and grate speed are
adjusted manually in response to temperature and excess oxygen readings in
each unit. It is assumed that temperatures are measured in the upper
furnace and at the economizer outlet, and that a continuous oxygen monitor
is located it the economizer outlet.
•6.2.2.2 Emission Control SystemDesign and Operation. As shown in
Table 6.0-1, 8 of the 9 plants in this subcategory are equipped with ESP's.
The Albany plant has a 3-field ESP on each combustor with PM emissions
ranging from 0.02 to 0.34 gr/dscf at 7 percent 0«. Most existing plants are
equipped with 4-field ESP's. Therefore, the model plant is equipped with -
4-field ESP's controlling PM emissions to 0.01 gr/dscf at 7 percent 02.
Emissions data show that 4-field ESP's are capable of achieving PM emissions
of 0.01 gr/dscf for this type of facility.
A tubular air preheater is located upstream of the ESP to provide
preheated combustion air while cooling the flue gas to 450°F. Each
combustor is connected to its own stack. Because the combustors, air
preheaters, and ESP's are located indoors, a high access and congestion
level is assumed for APCD retrofitting. A plot plan of the model plant is
shown in Figure 6.2-2.
Total ash is assumed to be 10 percent of the incoming RDF by weight.
This value is lower than the 23 to 28 percent observed at Albany, but is
considered to be more representative of the RDF population. A considerable
amount of metal (wire, etc.) goes through the RDF processing plant at Albany
and ends up in the waste feed.
6.2.2.3 Environmental Baseline. Table 6.2-2 presents baseline
emission data for the model plant based on an assessment of available
measured emissions data. All emission estimates are corrected to 7 percent
{L at the economizer outlet. Baseline uncontrolled COD/CDF emissions are
2,000 ng/dscm. Uncontrolled particulate emissions are 4.0 gr/dscf
6-49
-------
Stacks
X\
ISP
ESP
Prehe*tars
\
j | Economatn
\ {
Combuctof
Combuttcx
Figure 6.2-2. Plot PUn of Model Plant
6-50
-------
and CO emissions are 200 ppmv. Uncontrolled HC1 and SCL emissions are
assumed to be 500 ppmv and 300 ppmv, respectively,
6,2.3 Good Combustion Control
The following sections describe retrofits necessary to bring the
performance of the model plant to a level representing good combustion
practice. The retrofits address design, operation control, and verification
elements of good combustion practices.
6.2.3.1 Description of Modifications
Overfire Air System. The baseline CDD/CDF and CO emissions indicate
that flue gas mixing conditions are not optimized in the system, and that
some redesign is necessary. Flow modeling studies can be used to establish
the optimum overfire air firing pattern. For this model plant, it is
assumed that the new overfire air design includes four rows of overfire air
nozzles which are designed to provide 40 percent of the total combustion
air. New supply headers are equipped with pressure sensors to verify
pressures from which velocities and nozzle penetrations can be calculated.
It Is assumed that the existing overfire air fan has sufficient load
capacity to supply 40 percent of the total combustion air (17,000 dscfm).
Actual ovirfire air flow rates are assumed to be 30 percent of total air
(12,800 dscfm). The radiation sections of the boiler are assumed to be
membrane wall construction. It is assumed that the overfire air nozzle
sizes and pressures require modification, and that some waterwall tube
realignment is required. Lastly, as part of flow modeling, the effects of
auxiliary fuel firing on mixing patterns should be examined. Verification
of mixing conditions and final adjustment of overfire air nozzle settings
can be established by CO profiling studies.
Fuel Feeding. RDF-fired boilers use fuel feed rate as the primary
control variable to maintain desired steam flows. It is essential that the
feeding system be designed to provide a relatively constant feed rate to the
combustor. The distribution of fuel on the traveling grate is also an
Important operating parameter for maintaining stable combustion conditions.
Because the grate is supplied with underfire air from a single plenum,
uneven waste distributions and Inconsistent bed densities will result in
channeling of underfire air through less dense portions of the fuel bed.
6-51
-------
This leads to less stable burning conditions and variable lower furnace
stoichiometry, with fuel-lean flue gases emitted from some areas of the
waste bed and fuel-rich flye gases from other areas. These conditions will
lead to potentially higher levels of organic emissions.
This problem can be corrected by installing individual metered feeding
modules for each RDF distributor. Each metered feeding module, consisting
of two fuel bins, a ram, and a variable speed conveyor, will be installed at
the front of each boiler. Normally, installation of this system at a new
boiler is accomplished by lifting the equipment into place by crane prior to
completing the building roof. Therefore, it is assumed that the model plant
will require removal of a portion of the furnace building roof in order to
install the metered feeders.
The modification provides a more constant feed rate to the boilers and
more uniform distribution of waste on the grates. This will result in
stable burning conditions and better control of lower furnace stoichiometry",
minimizing the potential for periods of high air emissions.
Air Heater Bypass. A bypass duct and dampers will be installed to
allow up to 100 percent of the combustion gases to be bypassed around the
air heater. This modification provides the operator with the ability to
vary air preheat temperatures as needed to accommodate changes in waste
characteristics and boiler operation.
Cgmbtjgtion Control and Monitoring. The existing combustion control
system will be modified to include additional operating parameters, and
additional flue gas monitors are required for performance verification. As
a minimum, the following operating parameters will be incorporated into the
existing control scheme;
o steam flow rates
o fuel feed rates
o excess air flows
o CO levels
o flue gas temperatures
o underfire and overfire air flows or pressures
o furnace pressures
It is assumed that steam drum levels and pressures and feedwater flow rates
are also Included In the control system. A combustion control scheme based
on these operating parameters can be established by use of microprocessor-
6-52
-------
based electronic Instrumentation, providing total system control. Manual
override functions will be in place so that the operators can start the
system up manually-, switching to automatic control when stable combustion
conditions are established. Continuous CO monitors must be installed with
integrators and readouts, so that verification of combustion efficiency can
be established. It is sufficient for grate speed adjustments to be made
manually based on periodic visual observations of the ash bed coming off the
front of the grate.
Retrofit Considerations. Flow modeling studies can be completed in
3 months while the units continue to operate. It is estimated that all
remaining modifications can be made with 2 months of downtime per unit,
6.2.3.2 Environmental Performance. As a result of applying the above
described combustion modifications to the model plant, it is estimated that
COO/CDF emissions will be reduced to 1,000 ng/dscm, corrected to 7 percent
Og. In addition, a reduction in CO emissions to 150 ppmv can be expected to.
occur as a result of these modifications. The modifications would also have
no effect on solid waste disposal quantities.
6.2.3.3 Costs. The capital costs required to complete the combustion
modifications are presented in Table 6.2-3. Total capital costs are
estimated to be $2,370,000. Downtime cost is estimated at $1,960,000.
Based on a 15-year remaining plant life, and a 10-percent interest rate, the
annualized capital and downtime cost is $569,000. Table 6.2-4 presents the
annual O&M costs. Annual Q&M costs of the modifications are estimated to be
$56,000. Total annual costs including G&M and annualized capital and
downtime are estimated to be $754,000.
6.2.4 Best Particulate Control
The ESP's in place on this model plant already reduce PM from an inlet
loading of 4.0 gr/dscf to an outlet emission rate of 0.01 gr/dscf (values
corrected to 7 percent 0-). This emission rate is equal to the rate required
for best PM control and is significantly lower than the rate designated as
good control. Thus, no modifications of particulate control equipment will
be required for compliance at either control level for this model plant.
6.2.5 Good Acid Gas Control
6.2.5.1 Description of Modifications. For good acid gas control,
hydrated lime will be injected into each combustor through the overfire air
6-53
-------
TABLE 6.2-3. PLANT CAPITAL COST FOR COMBUSTION MODIFICATIONS
(Two units at 300 tpd each)
Item Cost (51,000)
DIRECT COSTS:
Metered Feeding System 870
Flow Modeling Studies 75
Overfire Air Nozzles 257
Automatic Combustion Control System 290
CO Profiling 10
CO Monitors with Readouts and Integrators 44
Air Heater Bypass Ducting, Damper, Insulation
Total
INDIRECT COSTS AND CONTINGENCY:
TOTAL CAPITAL COSTS
DOWNTIME
ANNUALIZED CAPITAL COSTS AND DOWNTIME
6r54
-------
TABLE 6.2-4, PLANT ANNUAL COST FOR COMBUSTION MODIFICATIONS
(Two units of 300 tpd each)
Item Cost ($1,000)
DIRECT COSTS;
Operating Labor 0
Maintenance Labor 28
Maintenance Materials _28_
Total 56
INDIRECT COSTS:
Overhead . 34
Taxes, Insurance, Administrative 95
Capital Recovery and Downtime 569
Total • 698
TOTAL ANNUALIZED COST 754
6-55
-------
ports. Hydrated lime sorbent will be fed at 480 Ib/hr to each combustor (at
full operating rate) for a calcium-to-acid gas molar ratio of 2:1. Addi-
tional equipment for sorbent injection will include a storage silo, a
pneumatic sorbent transfer system, 4 sorbent feed bins (2 for each
combustor) and pneumatic injection nozzles. Duct sorbent injection is not
practical because of the limited space between the economizer and the ESP,
To cool the flue gas from 450°F to 350°F, a spray humidification chamber
will be installed on the roof of the building approximately above each
economizer. Water spray at 9 gpm will be required for the gas cooling for
each combustor. Thirty feet of duct between the preheater and the ESP on
each combustor will be removed and replaced with 120 feet of new duct that
carries flue gas from the preheater through the spray chamber and then to
the ESP.
An additional 4,000 square feet of ESP plate area will be required to
collect the injected sorbent. Each new ESP will be erected outside the
building next to the stack and will be connected to the existing ESP and the
stack with 75 feet of new duct. The proposed equipment arrangement is shown
in Figure 6.2-3,
The new ESP's and humidification chambers with associated ducting will
add sufficient pressure drop to require replacement of the ID fans. New
monitoring equipment for SO., HC1, Og, and C0» is also included. Downtime
is expected to be 3 months per combustor.
6.2.5.2 Environmental Performance. COD/CDF emissions are expected to
be reduced 88 percent from baseline levels. Acid gas emission reductions
are estimated at 50 percent for HC1 and 10 percent for SOg. Particulate
matter emissions will remain at 0.01 gr/dscf» but the collected sorbent will
add 4,920 tons per year of solid waste to the baseline disposal requirements
for the plant.
6.2.5.3 Costs. Capital cost requirements for dry sorbent injection
are presented in Table 6.2-5. Total capital cost is $5,660,000. Downtime
cost is $2,390,000. Most of the capital cost is associated with the new
equipment for particulate and temperature control. The cost estimates
assume a high access/congestion level for new equipment and duct demolition.
6-56
-------
Additional
ID Fans
/\
Additional
\J
1
1
a«v«
Chi
k^
J
f
(
b
?
i
•MWI
=t,
<
-^
) C
i
i
S
2
)
^
\
s
•i Plata Araa
J
I
t
> k > k
edSer*
•^
ESP
1
\
f
X
>
r
i
^
jt
r
^
H
fj
• i
L.J
1
/
Prehaata
y' ^
^
!
S
Cocnbuatof
^
r
ESP
\
ra
\
« •
t
1
%
r
r/
i-i
L.J
i
/
\
"H/
Lima Storage
and
Soioarii
Preparation
Figure 6.2-3. Plot Plan of Sorbent Injection Equipment Arrangement
6-57
-------
TABLE 6,2-5. PUNT CAPITAL COST FOR DRY SORBENT INJECTION WITH ADDITION
OF ESP PLATE AREA (Two units of 300 tpd each)
Item Cost ($1,000)
DIRECT COSTS:
Acid Gas Control3
Equipment 672
Access/Congestion Cost 67
Particulate and Temperature Control
Equipment 1,540
Access/Congestion Cost 645
New Flue Gas Ducting3
Ducting Cost 183
Access/Congestion Cost 77
Other Equipment
Fans 450
Stacks 0
Demolition/relocation ^ 18
Total 3,650
Indirect Costs i Contingencies 1,490
Monitoring Equipment 514
TOTAL CAPITAL COST 5,660
DOWNTIME COST 2,930
ANNUAL1ZED CAPITAL RECOVERY AND DOWNTIME 1,130
aBased on moderate access/congestion.
Based on high access/congestion.
cTurnkey.
6-58
-------
Annual costs are presented in Table 6,2-6. The major direct operating
and maintenance costs are sorbent purchase and monitoring instrument
maintenance. Tota-1 annualized cost of dry sorbent injection, including
capital recovery and downtime, is $2,270,000,
6-2.6 Best Acid Gas Control
6.2.6.1 Description of Modifications. To achieve greater reductions
in CDO/CDF, HC1, and SQ2» a spray dryer/fabric filter system will be
installed on each combustor. The new equipment will be located outside the
building, near the stacks. The existing ESP's will not be demolished, but
the flue gas will be bypassed around each ESP from the preheater to the
spray dryer. Approximately 50 feet of duct will be demolished (25 feet at
each end of the ESP) to make room for each new ESP bypass duct. A total of
250 feet of new duct per combustor will be required to connect each spray
dryer and fabric filter between the priheater and the stack. The proposed
equipment configuration is shown in Figure 6.2-4.
Lime slurry will be introduced into each spray dryer at a calcium-to-
acid gas molar ratio of 2.5:1. Water in the lime slurry equivalent to 13
gpm is needed to cool the gas stream from 450°F to 300°F.
The lime receiving, storage, and slurry area which will serve the spray
dryers is also shown in Figure 6.2-4. The fabric filters will each have
24,200 effective square feet of cloth (net air-to-cloth ratio of 4:1). The
increased pressure drop of fabric filters over ESP's will require a new,
larger 10 fan for each unit. New monitoring equipment for HC1, SO., CO-, 02
and opacity will be installed as well. Downtime is expected to be 6 months.
6.2.6.2 Environmental Performance. CDO/CDF emission reductions of
99 percent from inlet level or to 10 ng/Nm are expected. Emissions of PM
will be maintained at 0.01 gr/dscf. Acid gas emissions will be reduced
90 percent for S0» and 97 percent for HC1.
6.2.6.3 Costs. Capital cost requirements for installing spray
dryer/fabric filter systems are presented in Table 6.2-7. Total capital
costs are estimated at $15,900,000. This figure includes purchased
equipment, installation, ductwork demolition, and indirect costs such as
engineering and contingencies. Estimates assume high access and congestion,
6-59
-------
TABLE 6.2-6. PLANT ANNUAL COST FOR DRY SORBENT INJECTION WITH ADDITION
OF ESP PLATE AREA (Two units of 300 tpd each)
Item Cost ($1,000)
DIRECT COSTS:
Operating Labor 60
Supervision 16
Maintenance Labor 26
Maintenance Materials 69
Electricity 28
Water 4
Lime 309
Waste Disposal 123
Monitors 206
Total 841
INDIRECT COSTS:
Overhead 100
Taxes, Insurance, and Administration 197
Capital Recovery and Downtime 1.130
Total 1,430
TOTAL ANNUAUZED COST 2,270
6-60
-------
[ [ Economizers { [
Combuator
L~L
Cofntouatof
New
Spray Dryers,
• Fabric Filters
and
ID Fan
Lime Storage
and
Sorbent
Preparation
Figure 6.2-4. Plot Plan of Spray Dryer/Fabric Filter Retrofit Equipment
Arrangement
6-61
-------
TABLE i.2-7. PLANT CAPITAL COST FOR SPRAY DRYER WITH FABRIC FILTER
(Two units of 300 tpd each)
Item Cost ($1,000)
DIRECT COSTS:
Acid Gas Control3
Equipment 6,300
Access/Congestion Cost 2,650
New Flue Gas Ductinga
Ducting Cost 223
Access/Congestion Cost 94
Other Equipment
Fans ' 347
Stacks 0
Demolition/Relocation 23
Total 9,640
Indirect Costs " 3,170
Contingency 2,160
Monitoring Equipment 573
TOTAL CAPITAL COSTS 15,900
DOWNTIME COST 5,870
ANNUALIZED CAPITAL RECOVERY AND DOWNTIME 2,870
aBased on high access/congestion.
Turnkey.
6-62
-------
500 feet of new ductwork and new ID fans. Downtime cost is estimated at
$5,870,000.
Annual cost are presented in Table 6.2-8. Significant operating cost
are for maintenance materials including bag replacement, electricity for the
ID fans and slurry atomizers and monitoring instrument maintenance. Total
annual cost, including capital recovery and downtime is $4,960,000.
6.2.7 Summary of Control Options
6-2.7.1 Description of Control Costs. The control technologies
described in the previous sections have been combined into the 7 retrofit
emission control options discussed in Section 3.0. Table 6.2-9 summarizes
the combustion, particulate control, temperature control, and acid gas
control technologies described in Sections 6.2.3 through 6.2.6 that were
combined for each of the control options. It should be noted that since the
model plant already achieves best PM control at baseline, Options 1 through
3 are Identical. ' -
6.2.7.2 Environmental Performance. The performance of each control
option is summarized in Table 6.2-10. For each pollutant, the table
presents both the pollutant concentrations and annual emissions. The
greatest reduction in total CDD/CDF emissions and in acid gas emissions is
achieved with the spray dryer/fabric filter retrofit. Control of CDD/CDF
with combustion improvements or dry sorbent injection are approximately
equally effective. Greatest overall emission control is achieved when
combustion improvements are combined with acid gas control technology.
Emissions of CO are affected only by combustion improvement; PM emissions
are unchanged for any option, since best control is achieved at baseline.
Both dry sorbent injection and spray drying have significant negative waste
disposal impacts, increasing plant solid waste by 25 and 22 percent
respectively.
6.2.7.3 Costs. The total annualized cost of each option is presented
in Table 6.2-11. The cost of each control option increases with increased
level of control. The most costly Option 7, at $5,460,000 per year
annualized cost, provides 99.8 percent reduction of CDD/CDF, 97 percent
reduction of HC1, and 90 percent reduction of S02. Less costly options
provide lower levels of emission reduction.
6-63
-------
TABLE 6.2-8. PLANT ANNUAL COST FOR SPRAY DRYER WITH FABRIC FILTER
(Two units of 300 tpd each)
Item Cost ($1,000)
DIRECT COSTS:
Operating Labor 96
Supervision 14
Maintenance Labor 53
Maintenance Materials 23i
Electricity 191
Compressed Air 27
Water . 6
Lime 256
Waste Disposal 164
Monitors 215
Total 1,260
INDIRECT COSTS
Overhead 213
Taxes, Insurance, and Administration 614
Capital Recovery and Downtime 2.870
Total 3,700
TOTAL ANNUALIZED COSTS 4,960
Includes bag replacement costs of $47,000.
6-64
-------
TABLE 6,2-9. StMiARY OF CONTROL OPTIONS FOR SHALL RDF-FIRED HWC MODEL PLANT
Partlcutate conerot
Control Option Description
Combustion Teaiparatuce Existing ESP
Mod If leal Ions Control Rebuilt
Additional
Plat* Area
Acid Gas Corn rot
Hew
Fabric Filter
So r bent
Injection
Spray
Dryer
•on
en
1, Good Combust ion and
Temperature Control
2. Good PM Control with
Corabujtlon and Temperature
Control
). Bast PM Control and
Combustion and Temperature
Control
*. Good Acid Gas Control,
Best PM Control and
cure Control
5.
Good Acid Gas Control
and Best PMJCombust Ion/
e Control
Bast Acid Gas Control,
Best PM Control, and
Teiqperature Control
Best Acid Gas Control
Best PM/Combultlon/
cure Control
and
-------
TABLE 6.2-10. ENVIRONMENTAL PERFORMANCE SUMMARY FOR SHALL RDF-FIRED KWC HOOEL PLAKT
R£T«DHT COHfROL OPTIONS* (Tvo unit* of 300 tpd RUE «*ch)
Baseline Option 1 Option 2 Option 3
Total CDD/CDF Enlstion*
(n»/d»cni>
Hi/yr 1-
t Reduction v>. Baaaliiu
CO Ealiiloni
(ppenv)
Hg/yr
X Reduction v». Bate HIM
PM EnUitons
(8r/d.cf)
Hgfyr
1 Reduction vs. BaieLlo*
SO Emission*
(ppmv)
Mg/yr
I Reduction vs. Bateltn*
BC1 Ealitloni
(ppov)
M»/rr
X Reduction vs. Bate I In*
Total Solid Waste
(con»;d»y)
M*/yr 18,
1 Increase vs. Baseline
All Clue 8»> concent cations
both 1 atmosphere and 70 F.
2000
9E-3
—
200
239
—
0.01
22
—
300
BIS
--
500
778
—
60
200
ace
1000
9.5E-*
50
150
119
71
0.01
22
0
300
819
0
500
778
0
60
18,200
0
reported on *
1000
9.5E-*
50
150
119
71
0.01
22
0
300
S19
0
500
778
0
60
18,200
0
7 percent
1000
9.5E-4
50
ISO
119
71
0.01
22
0
300
819
0
SOO
778
0
60
18,200
0
Option 4 Option 5
500
4.81-4
75
200
410
0
0.01
22
0
150
410
50
250
390
SO
75
22,700
25
250
2.4E-4
68
ISO
119
71
0.01
22
0
150
4.10
50
250
390
50
75
22,700
25
Option 6
20
1.91-5
99
200
418
0
0.01
22
0
29
78
90.5
15
22
97
80
24,100
33
Option 7
10
9.6E-6
99.5
150
119
71
0.01
22
0
29
78
90.5
15
22
97
80
24,100
33
O dry baslft> Standard and normal conditions are
-------
Ov
"Nl
TABLE 6,2-11. COST SUHMARY FOR SHALL RDF-FIRED MHC MODEL PLANT RETROFIT CONTROL OPTIONS*
(Two unit* of 300 tp4 RDF «»ch)
Option 1 Option 2 Option 3 Option 4 Option 5 Option 6 Option 7
Total Capital Cott
DovntLm* Coat
Annual l>*4 Capital and
Dtnmtlma Colt
Dlr«ct OU< Case
Total Annual Cott
Cojt Eff*ctlv*n*«s
($/ton RDF)
Facility Dovmtlm*
(Month*)
Total Coop 1 lane* Tiaa
(Month.)
2,370 2,370 2,370 3,660 8,030 15,900 18,300
1,960 1,960 1,960 2,930 2,930 5,670 5,870
. 369 569 S69 1,130 1,4*0 2,870 3,180
56 56 56 841 09? 1,260 1,320
734 7S4 754 2,270 2,770 4,960 5,460
3.77 3.77 3.77 11.40 13.90 24.80 27.30
2223366
7 77 19 It 25 25
All coata «»c«pt coat «f£«ctlv«a«»» given .in $1000. All co*t» in Daccnbar 1987 dollar*.
-------
6.2.7.4 Energy ..Impact^. Table 6.2-12 presents a summary of the
energy Impacts associated with the control options. The electrical use
figures take Into account the cost savings of not operating Incremental
auxiliary fuel use because auxiliary burners are in place on the model plant
and are used under baseline operation.
6-68
-------
TABLE 6.2-12. ENERGY IMPACTS FOR SMALL RDF-FIRED COMBUSTOR
MODEL PLANTCQNTRQL OPTIONS3
Option
1
2
3
4
. 5
6
7
Electrical Use
(MWh/yr)
0
0
0
615
615
4»150b
4,150b
Gas Use
(Btu/yr)
0
0
0
0
0
0
0
alncremental use from baseline.
Excludes electrical credit of not operating the ESP's.
6-69
-------
6,3 REFERENCES
1, Hasselriis, F. Thermal Systems for Conversion of Municipal Solid Waste,
Volume 4. Burning Refuse-Derived Fuels In Boilers: A Technology Status
Report. Argonne National Laboratory. ANL/CNSV-TM-120, Vol. 4, March
1983.
2. Heap, M.P., Lanier, W.S. and Seeker, W.R., Energy and Environmental
Research Corporation, Municipal Waste Combustion Study: Combustion
Control of MSW Combustors to Minimize Emissions of Trace Organics.
EPA/530-SW-87-Q21C. June 1987.
3. Epner, E., Radian Corporation, and Schindler. P., Energy and
Environmental Research Corporation. Trip Report - Retrofit Control Site
Evaluation at Occidental Energy from Waste Facility, April 5, 1988.
4. Epner, E., Radian Corporation, and Schindler, P., Energy and
Environmental Research Corporation. Trip Report - Retrofit Control Site
Evaluation at the Albany Sheridan Avenue RDF Facility. June 1» 1988.
5. H.J. Hall Associates, Inc. Summary Analyses on Precipitator Tests and
Performance Factors. 13-15Mav at Incinerator Units 1.2-Occidental
ChemicglCompany. Technical Report HAR86-431. Prepared for Occidental
Chemical Company. June 25, 1985.
6-70
-------
7.0 MODULAR STARVED-AIR COMBUSTORS
In terms of the number of existing facilities, starved-air modular
combustors comprise the largest segment of the HWC population. There are
approximately 41 of these facilities in operation, A list of operating
facilities 1s provided 1n Table 7.0-1. Approximately 75 percent of these
facilities were manufactured by Consumat Systems. Other suppliers include
Ecolaire, Clear A1r, and Kelly Systems.
The population of modular starved-air MWC's can be divided into basic
groups: those with unit capacities of greater than or equal to 50 tpd, and
smaller units. There ire 14 facilities with corabustors having a unit capacity
of greater than or equal to 50 tpd. These facilities typically employ heat
recovery (13 out of 14), have a PM control device (11 out of 14), and are
typically newer than the smaller units. The smaller units are less likely to
have heat recovery (1§ out of 28), typically do not have PM control (4 out ot
28), and are generally older.
Based on these differences, two model plants were developed. The first
represents a larger facility with heat recovery and PM control (Section 7.1),
and the second represents a smaller facility with no heat recovery and no PM
control (Section 7.2). Although the larger model is equipped with transfer
rams for moving waste through the system, and the smaller model uses
reciprocating grates, this distinction is not as important as that of unit
size.
A typical modular starved-air MWC is shown in Figure 7.0-1. The basic
design includes two separate combustion chambers (referred to as the "primary"
and "secondary" chambers). Waste is batch fed to the primary chamber by a
hydraulically activated ram. The charging bin is filled by a front-end
loader. Waste feeding takes place automatically on a set frequency (generally
6 to 10 minutes between charges).
Waste is moved through the primary combustion chamber by either hydraulic
transfer rams or reciprocating grates. Clear Air designs are equipped with
grates, and the Consumat, Ecolaire, and Kelly Systems use transfer rams.
Systems using transfer rams have individual hearths upon which combustion
takes place. Grate systems generally include two separate grate sections. In
7-1
-------
TABLE 7,0-1. EXISTING MODULAR SIARVED-AIR COKBUSIORS
Mo, of Unit Sice
Plant /Location
Hampton, SC
Hartford County, MD
Red Wing, Mil
Tuscaloos*, AL
Perhara, UN
Portsmouth, NH
Cooi Bay, OR (11)
Auburn, HE
Oyetiburj, ™
Johnsonvllle, SC
One Id » County, NY
Belllnghaia, HA
Oiuego, HY
Bactjville, AR
Plttsfleld, NH
Fergus Falls, NN
Bar ran County, UI
Polk County, Hi
Cattaraugus County, HY
Livingston, NT
Durham, NH
Blyth«vlll«, *»
Center, IX
Carthage , TX
Wlndham, CT
Miami, OK
Newport Hews, VA
Wilton, HH
Fort Leonard Uood, MO
U Indium , ME
North Little Rock, AR
Salem, VA
HuntsvllLe, TX (DOC)
fyp«
transfer
transfer
Transfer
Transfer
Hans
Raffis
Raffis
Rams
Reciprocating Grata
Trans fe. t
Transfer
Transfer
Transfer
transfer
transfer
Transfer
Transfer
Transfer
Transfer
Transfer
Transfer
Transfer
Raflis
Raf&s
Rams
RAIDS
Haas
Rams
Rant*
Ram*
Rams
Raws
Hans
Rams
itajus
Reciprocating Crate
Transfer
Transfer
Transfer.
transfer
Transfer
Transfer
Transfer
Transfer
transfer
Transfer
Transfer
Transfer
Transfer
Transfer
Ram
Rams
Ran*
Rajas
RUBS
Rao*
Rams
Ram
flams
Riflu
Raaa
Ran*
Rams
Rams
Manufacturer-
Consunat
Conjuuut
Consucnat
Consuinat
Clear Air
Consumat
Consuoac
Consunat
Consuraat
Com Lima t
Consumat
Consunat
Consumat
Consumat
Kelly
John Zlnk
Consuraat
John Zlnk
Clear Air
Consumat
Cbnsumat
Consum»t
Consuinat
Consumat
Consumat
Consumat
.• Consumat
Consumat
EC? Systems
Consuinat
Consuraat
Com um,it
Indujt ronlci
Units
3
*
1 .
4
Z
4
1
4
I
1
4
2
4
2
1
2
2
2
3
2
3
2
1
1
3
3
1
1
i
2
4
4
1
(tpd)
90
90
90
TS
57
SO
SO
SO
50
SO
SO
SO
SO
SO
48
4?
40
40
38
38
36
16
36
36
36
35
35
30
26
25
25
15
25
Year of
Stare-Up
1985
1987
1982
1984
1986
1982
1980
1981
1986
HA
1985
1986
1986
1981
HA
1988
1986
1988
1983
1902
1980
1983
1985
1985
1981
1982
1980
1978
1982
1973
1977
1977
1984
Beat
Recovery
¥«*
Yes
Yes
Yes
Yes
Yes
.Yea
Yes
Ho
Yes
Yes
Yes
Yes
Yes
No
Yes
No
Yes
Ho
Yes
Yes
Do
Ye 5
Yes
Yes
Yea
Yes
No
Yes
No
Yes
Yes
Ha
Air Pollution
Electrostatic
Electrostatic
Electrostatic
Electrostatic
Electrostatic
Fabric Filter
None
Fabric Filter
None
Electrostatic
Electrostatic
Hone
Electrostatic
None
Hone
Control Device
Praclpltator
Pfeclpl tator
Precipltator
Precipitates
.Precipltator
Precipltator
Preelpttator
PtecipUator
Verturl Wet Scrubber
Electrostatic
Electrostatic
None
None
Cyclone
Hone
None
Hone
Fabric Filter
None
None
Hone
None
None
None
None
Hone
Precipltator
Preclpltator
HA
Information not available.
-------
TABLE 7.0-1. EXISTING HODULAR STARVED-AIR COKBUSTORS
(Continued)
Ho. of Unit Site
Plant /Location
Anderson County, TX (DOC)
Grimes County, TX (DOC)
B razor la County, IX (DOC)
Urlghtsvllle Beach, DC
Osceola, AR
Westmoreland County, PA
Cassia County, ID
Uaxahachle, TX
Lincoln, NH
Grove ton, NH
Brook Ings, OR
Stuttgart, Aft
Lltchfleld, m
Fort Dljt. NJ
Plymouth, NH
Candla, NH
Coos tay, OR (I)
Catesvllle, TX (DOC)
Canterbury, NH
Wolfboro. HH
Auburn, MB
Type
Transfer Rams
Transfer Rams
Transfer Runs
Transfer Rams
Transfer Rams
Transfer Rams
Transfer Rams
Reciprocating Grate
Transfer Rams
Transfer Rams
Transfer Rams
Transfer Rams
Transfer Rams
Reciprocating Crate
Transfer Rams
Transfer Rams
Transfer Rams
Transfer Ram*
Transfer Rams
Transfer Rams
Transfer Rams
Manufacturer
Constsnat
Indust tonics
Induitxonics
Consuaat
Consuaat
John Zlnk
Consuaat
Clear Air
Kelly
ECP Systems
Consumat
Consumat
Consuraat
Clear Air
NA
Kelly
Consumat
Consueat
Kelly
Consumat
Consumat
Units
1
1
1
2
2
2
2
2
1
1
2
3
1
4
1
1
2
1
I
2
1
(tpd)
25
25
25
25
25
25
25
25
2*
2*
2*
21
22
20
16
IS
12.5
12.5
10
8
5
Year of
, „ a
Start-up
1980
1981
1983
1981
1980
1986
1982
1982
1980
1975
1979
1971
NA
1986
1975
1979
1978
1979
NA
197S
1981
Heat-
Re cove ry
No
No
No
Ho
Yes
¥es
Yes
Yes
Ho
Yes
Mo
Ho
No
Yes
No
Ho
No
No
Ho
No
No
Air
None
None
None
Hone
Hone
Pollution Control Device
Electrostatic Precipltator
Hone
Hone
None
None
Rone
None
None
Uet
None
None
None
Hone
Hone
Hone
Hone
Scrubber/ Fabric Filter
*HA - Information not available.
-------
Tipping Floor
To Dump Stack or
Waste Heat Boiler
Primary
Gas Burner
Feed
Chute
Secondary
Air
Secondary
Chamber
Ram ^* *J
Feeder
Charge
Hopper
Fire
Door
Primary Chamber
Transfer Rams
J
Primary Air
Secondary
'Gas Burner
Ash
Quench
EC
O>
I-
Figure 7.0-1. Typical Modular Starved-Air Combustor with Transfer Rams
-------
either case, waste retention times in the primary chamber are long—up to
12 hours. Bottom ash is usually discharged to a wet quench pit.
The quantity o'f air introduced in the primary chamber defines the rate at
which waste burns. The primary chamber essentially functions as a gasifier,
producing a hot fuel gas which is burned out in the secondary chamber. The
combustion air flow rate to the primary chamber is controlled to maintain an
exhaust gas temperature set point (generally 1200 to 1400°F), which normally
corresponds to about 40 percent theoretical air. Other system designs operate
with a primary chamber temperature between 1600 and 1800°F, which requires
SO to 60 percent theoretical air.
As the hot, fuel-rich flue gases flow to the secondary chamber, they are
mixed with excess air to complete the burning process. The temperature of the
exhaust gases from the primary chamber is above the autoignition point. Thus,
completing combustion is simply a matter of getting air to the fuel-rich
gases. The amount of air added to the secondary chamber is modulated to
maintain a desired flue gas exit temperature, typically 1800 to 2200°F.
Approximately 80 percent of the total combustion air is introduced as
secondary air, so that excess air levels for the system are about 100 percent.
Typical operating ranges vary from 80 to 150 percent excess air.
The walls of both combustion chambers are refractory-lined. Early
starved-air modular combustors did not include heat recovery, but a waste heat
boiler is common in newer installations, with two or more combustion modules
manifolded .to a boiler. Combustors with heat recovery capabilities also
maintain dump stacks for use in emergency, or when the boiler is not in
operation.
Most modular starved-air MWC's are equipped with auxiliary fuel burners
which are located in both the primary and secondary combustion chambers.
Auxiliary fuel can be used during start-up or when problems are experienced in
maintaining desired combustion temperatures. In general, the combustion
process is self-sustaining through control of air flows and feed rate, so
continuous co-firing of auxiliary fuel is normally not necessary.
As mentioned above, temperature controllers are used to maintain desired
combustion air flows. Some of the newer modular MWC's preheat the secondary
combustion air by drawing it through a shroud surrounding the primary chamber,
using the radiant heat from the primary chamber to heat the flue gases.
. 7-5
-------
The current guideline elements for good combustion practices in modular
starved-air MWC's are presented in Table 7.0-2. Under normal operating
conditions, a starv'ed-air combustor will have no trouble maintaining 1800°F in
the secondary combustion chamber. However, due to some State requirements for
retention time of several seconds at 1800°F, some designs are including a
larger secondary combustion chamber.
With the increase in heat recovery, downstream flue gas temperature
control may become an important issue for modular starved-air MWC's. More
systems are using heat recovery boilers and adding ESP's for particulate
control, and in some cases the ESP temperatures may be in the range that will
promote formation of COD/CDF. One facility (Tuscaloosa, AL) has installed
an economizer in the ducting just upstream of the existing ESP. In addition
to lowering the flue gas temperature prior to the ESP, the plant also has
increased steam production by 5 to 10 percent, so that the economizer will pay
for itself after 5 years of operation.
Although the operation/control components listed in Table 7.0-2 are
generally attainable by all operating facilities, there are some verification
measures which are lacking in most starved-air modular,MWC's. For example,
air flows are not directly measured, and oxygen monitors are typically
installed only when a boiler is used. Continuous CO monitors are also not
very common.
In general, emissions of air pollutants from modular starved-air MWC's are
relatively low. Low gas velocities in the primary combustion chamber prevent
carryover of excessive participate, so that uncontrolled emissions are lower
than mass burn or RDF systems. The high combustion temperatures and
sufficient mixing of flue gases with air in the secondary combustion chamber
provide good combustion, resulting in relatively low CO and trace organic
emissions. However, the high temperatures and lack of air pollution controls
are a concern with regard to emission of trace elements.
7-6
-------
TABLE 7.0-2 COMPONENTS OF GUIDELINES - GOOD COMBUSTION PRACTICES FOR
MINIMIZING TRACE ORGANIC EMISSIONS FROM MODULAR
STARVED-AIR MWC'S
Element
Component
Design
Operation/Control
Verification
Temperature at fully mixed location
Secondary air capacity
Secondary air injector design
Auxiliary fuel capacity
Downstream flue gas temperature
Excess Air
Turndown restrictions
Start-up procedures
Use of auxiliary fuel
Oxygen in flue gas
CO in flue gas
Furnace temperature
Temperature at APCD inlet
Adequate air distribution
7-7
-------
7.1 URGE MODULAR STARVEO-AIR COHBUSTOR WITH TRANSFER RAMS
This section presents the case study results for a model large (unit
size > 50 tpd) modular starved-air MWC equipped with transfer rams. As
shown in Table 7.0-1, there are 41 known plants in this sub-category. This
subpopulation is dominated by the Consumat system (31 plants). Section
7.1.1 presents a description of the Tuscaloosa Energy Recovery Facility, a
Consumat plant which was visited in order to gather information for model
development. Section 7.1.2 presents a description of the model plant.
Sections 7.1.3 through 7.1.6 detail the retrofit modifications, estimated
performance, and costs associated with various control options. Section
7.1.7 presents a summary of the control options which are discussed in more
detail in Section 3.0 of this report.
7.1.1 Description of the Tuscaloosa. AL Plant
The Tuscaloosa Energy Recovery Facility (TERF) consists of four
Consumat model ICS3Q0Q combustors, each with a design rating of 75 tons of
municipal solid waste (MSW) per day. Figure 7.1-1 presents a cutaway view
of the standard Consumat incinerator, and Table 7.1-1 presents Tuscaloosa
plant design data. The facility and has a contract to deliver steam to the .
B.F. Goodrich plant located adjacent to the facility. The B.F. Goodrich
land where the TERF is sited, is leased to the TSWA for 20 years. The term
of the steam delivery contract is for 10 years beginning from facility
start-up in March 1984.
The TERF until recently operated on a 5-day/week schedule. However,
because the B.F. Goodrich plant now operates 7-days/week, the TERF operates
on Saturdays approximately 50 percent of the time. The current contract
requires that the TERF provide B.F. Goodrich with 50,000 Ib/hr of steam
(26.65 x 10 Ib/month). B.F. Goodrich pays a fixed price for up to 26.65 x
106 Ib/month of steam and a reduced price for any additional. The feedwater
is supplied by Goodrich. The first four modules in the boilers were
replaced one year ago due to erosion and corrosion, after three years
operation. Each of the boilers is designed to produce 32,500 Ib/hr of
steam, all of which 1s delivered to B.F. Goodrich. The plant currently
employs 21 people on a 5-day/week, 24-hr/day operating schedule.
7-8
-------
©
Hie above cutaway view of the stand-
aid CONSUMAT' energy-from-waste
module shews how material and hot
gas flows are controlled to provide
steam from solid waste A skid steer
tractor (1) pushes the waste to the
automatic loader (2). The loader then
automatically injects the waste into
the gas production chamber (3)
where transfer rams (4) move the
material slowly through the system.
The high temperature environment
in the gaa* production chamber is
pxxmded with a controlled quantity
erf air so that gases from the process
sum nf* hi irrwH in »hi« <~hamt-^r' h»tt
fed to the upper or pollution control
chamber(5). Here the gases are mixed
with air and controlled to maintain a
proper air fuel ratio and tempeidiure
for entrance into the heat exchanger
(6) where steam is produced, Asteam
is provided to ensure
high quality steam. In normal opera-
tion gases are discharged through
the energy stack (8). When steam is
not required or in the event of apower
failure, hot gases are vented through
the chimp stack (9). Th« inert mate-
rial from the combustion process is
ejected from the machine in the form
of ash into the wet sump (10) and
conveyed (11) into a closed bottom
container (12) which can then be
hauled to the landfill for final
disposal.
Figure 7.1-1. Typical Consumat Module
7-9
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TABLE 7.1-1. TUSCAtOOSA, ALABAMA DESIGN DATA
Cornbustor:
Type
Number of Combustors
Combustor Unit Capacity
Total Plant Capacity
Number of Boilers
Boiler Design Rate
Emission Controls:
Type
Number of Precipltators
Number of Fields
Inlet design particulate loading
Operating Temperature
Design Collection Efficiency
Particulate Emission Limit
Gas Flow
Modular Starved air
4 Consumat #CS«3000
75 tpd (each)
300 tpd
2 Richmond Engineering
Waste Heat Boilers
32,000 Ib/hr steam (each)
Electrostatic Precipitator
1
2
0.10 gr/dscf at 12% CO,
45Q°F z
50 percent
0.08 gr/dscf at 12% CO.,
90,000 acfm
7-10
-------
Goodrich also supplies 12 to 15 tons per day of waste in the form of
automobile tire rejects from their adjacent production plant. When the TERF
does not generate steam, the Goodrich plant increases their plant steam
generation. Currently, due to the low cost of natural gas, the Goodrich
plant generates steam at a lower cost than the TERF,
7.1.1.1 Combustor Design andOperation. Waste is delivered to the
plant and dumped on a tipping floor where mixing and fuel feeding is
executed by front-end loaders. The front-end loaders deliver a charge to
the furnaces by dumping the wa.ste into one of four waste loaders (Consumat
IMU40QMS). Each of the furnaces operates on a 5-minute charging cycle
(12 charges/hr). The furnace operator,responds to a green light signal on a
panel which indicates that the loader is ready to receive a charge. The
panel also indicates whether the charge of waste to the loader should be
heavy, normal, or light. After the waste has been placed in the loader, the
operator presses a button which closes the loader top door and activates an
automatic charging sequence. When the door closes, the fire door opens and
the ram extends, charging the waste into the primary combustion chamber.
When the feed stroke is complete, the ram retracts and the fire door closes.
The loader door opens and is then ready for an additional waste load. To
prevent ignition of the waste in the loader, a water mist curtain is
activated when the furnace is opened for charging. The loader is not
completely air tight, but observations of the charging cycle indicated that
a fairly good seal is maintained by the waste itself during the periodic
intervals when the fire door is open.
Waste is moved through the primary combustion chamber by three transfer
rams which are located on the floor of the primary combustion chamber. In
addition, an ash ram discharges the bottom ash from the primary chamber into
a water filled quench pit. The floor of the primary chamber is stepped so
that waste moves down from one hearth to another as the transfer rams
operate. Waste retention times in the primary chamber are 6 to 8 hours, and
waste volumes are reduced by approximately 90 percent. The bottom ash is
removed from the quench pit by a drag chain conveyor which dumps the wet ash
into a bin for the landfill.
-------
The primary combustion chamber operates at sub-stoichiometric conditions
with sufficient combustion air added to maintain an exit temperature of
1200 to 1400°F, To prevent slagging conditions that occur with temperatures
greater than 1400 F, the State permit requires that primary chamber
temperatures not exceed 1400°F. In order to maintain this temperature
requirement, combustion airflows to the primary chamber are limited to about
40 percent of theoretical air. Primary chamber air enters the combustion
chamber through water cooled air tubes integrated with the transfer rams.
The primary chamber is constructed with a double shell. Secondary chamber
air is preheated by drawing it through the shell and contacting it with the
wall of the primary chamber,, resulting in less heat loss from the primary
chamber and enhancing burnout in the secondary. The secondary air is
introduced into the chamber of orifices along the circumference of the
chamber (excluding the floor). Burnout of volatiles is accomplished in the.
chamber by adding sufficient excess air to provide good mixing with the flue
gases. Secondary chamber temperatures are generally in the range of
1800-2000°F. Air flows are not measured directly. Pressures are recorded
in the supply headers downstream of the control dampers for both the primary
and secondary air supplies, and these readings are displayed in the control
room for each unit. There is no continuous 02 monitor so excess air levels
are not directly measured. However, typical overall excess air levels are
100 percent. Temperatures are monitored continuously in both the primary
and secondary chambers, and are the primary variables for monitoring
operation of the units. Temperatures are maintained by varying air flows
and fuel feeding rates.
Combustion products exit the secondary chamber and are directed to one
of two waste heat boilers. The first bonier is paired with the #1 and #2
furnaces and the second boiler with #3 and #4.
Each of the waste heat boilers consists of nine steam generating
modules and one module in an economizer section. Pressure components for
the boilers were fabricated by Richmond Engineering. These were assembled
and cabinets were manufactured by Consumat. The two boilers manifold into a
common duct which originally ran the length of the building to an
electrostatic precipitator. Last year a small economizer was installed in
7-12
-------
this ducting upstream of the ESP. This modification has increased feedwater
temperature to the boilers by about 100°F and increased boiler efficiency
for a given waste feed rate. In addition, the flue gas temperatures
entering the ESP have been reduced approximately 100 to 150°F. The
economizer outlet temperatures are currently in the 450 to 500°F range.
Gas burners are located in both the primary and secondary combustion
chambers, and in the ducting between the economizer and the ESP. Gas is
fired to bring the secondary chamber up to 600°F during process start-up.
Normally the primary chamber burners are not used even during system
start-up.
7.1.1.2 Emission Control System Design and Operation. The flue gas
from all four incinerators at the TERF exits the economizer in a single
duct. This duct passes through tha facility building wall to a 2-field
electrostatic precipitator (ESP). (Table 7.1-1 also shows ESP design
information). The ESP was designed to achieve 50 percent control. The ESP
typically reduces emissions by over SO to 60 percent, achieving an emission
rate of 0.05 to 0.07 gr/dscf adjusted to 12 percent CO*.
The ESP outlet flue gas is continuously monitored by an opacity meter,
as required by the facility permit. A weekly report is submitted to the
State Department of Environmental Management detailing repairs made to the
ESP, ESP electrical readings and the opacity strip charts. Plant upset.
conditions resulting in increased emissions must be reported within
24 hours. If three 1-hour average opacity readings exceed 15 percent in a
24-hour period, a stack test must be performed within 10 days of the
occurrence. This test is used to determine if the facility meets the permit
emission limit of 0,08 gr/dscf adjusted to 12 percent C02< Two recent
compliance sampling episodes showed particulate emissions of 0.07 gr/dscf
corrected to 12 percent COj.
The facility has experienced corrosion problems with the ESP due to the
condensation of acid gases that occurs with facility shutdown and start-up.
This corrosion problem resulted in the replacement of the ESP internals
after three years of operation. The facility now maintains a higher ESP
flue gas temperature (>250°F) during shutdown/start-up using a gas fired
7-13
-------
burner located in the ducting before the ESP. If the facility goes to a
7-day/week operation, the potential for corrosion problems will also be
reduced.
Currently, the ESP ash is being handled and disposed of as a hazardous
waste. However, it is anticipated that in the future the bottom and fly ash
handling equipment will be modified so that both wastes can be disposed of
in a conventional landfill. Current landfill waste disposal costs are
approximately $13 to $18/ton.
7.1.2 Description of Model Plant
7,1.2.1 Combustor Design and Operation. Due to the prevalence of the
Consumat design in'the existing population of modular starved air MWC's, it
is assumed that the model plant is designed to incorporate the features
found in most Consumat or similar designs. Model plant design data are
shown in Table 7.1-2. The model plant consists of three 50 tpd modules,
each with a primary and secondary combustion chamber. The individual flues
manifold to a single waste heat boiler where the gas temperature is reduced
to 315°C (600°F) (see Figure 7.1-2). It is assumed that only two of the
three combustors operate simultaneously. The normal operating schedule is
24-hours/day, 7-days/week, The larger operating schedule typically
incorporate waste heat recovery capabilities, so it is assumed that heat
recovery is in place at the model.
Waste feeding is accomplished automatically by a hydraulic ram. Waste
is delivered to the feeding bin in batches by a front-end loader. The ram
feeding frequency is controlled automatically. The waste is moved through
the primary chamber by five water-cooled transfer rams that periodically
extend and retract, pushing the waste along a series of burning hearths.
The frequency of the transfer ram stroke is controlled automatically. The
waste retention time in the primary chamber is approximately 10 to 12 hours.
Holes in the transfer rams provide the flow of primary air to waste.
It is assumed that 40 percent of theoretical air is used in the primary
chamber, and primary chamber exit temperatures are maintained in the range
of 1200 to 1400°F. At 40 percent of theoretical air, approximately
-7-14
-------
TABLE 7.1-2, MODEL PLANT BASELINE DATA FOR LARGE
MODULAR STARVED-AIR COMBU.STOR
Combustor:
Type
Number of Combustors
Combustor Unit Capacity
Total Plant Capacity
Emission Controls
Type
Number
Number of Fields
Inlet Temperature
Collection Efficiency
Gas Flow
Total Plate Area
SCA at 29,000 acfm and 600°F
Emissions:
CDD/CDF (tetra-octa) (stack)
PM (stack)
CO
HC1
so2
Stack Parameters:
Height
Diameter
Operating Data:
Remaining Plant Life
Annual Operating Hours
Annual Operating Cost
Modular Starved-air
3 (Z units operate with
1 on standby)
50 tpd
150 tpd
Electrostatic Precipitator
2 n
600°F
67 percent
29,000 acfm
2200 ft2
75
SOO ng/dscm
O.Oi gr/dscfc
100 ppmv
500 ppmv
200 ppmv
60 feet
5.5 feet
> 20 years
8,000 hours
$976,000/year
aOne ESP controls emissions from entire plant. Three units are ducted to
the single ESP and stack. The ESP is sized for two units operating
simultaneously.
All emissions are dry, corrected to 7 percent 02. Standard and normal
conditions are both 1 atmosphere and 70 F. All values except PM and
CDD/CDF are at the boiler exit.
clnlet PM emissions to the ESP are 0.1 gr/dscf at 7 percent O.
7-15
-------
1,200 scfm of air is supplied in the primary chamber. The fuel-rich
combustion gases exit the primary chamber through a vertical breeching and
flow into the secondary chamber.
Additional air is added in the secondary chamber through rows of wall
jets which are located at two axial locations in the chamber. Secondary air
is preheated by drawing it through a shroud which surrounds the primary
chamber, and the secondary air flow rate is controlled automatically to
maintain a minimum chamber exit temperature of 1800°F. With the secondary
chamber operating at approximately 80 percent excess air, the total system
operates at 100 percent excess air, and total flow rates leaving the
secondary combustion chamber are approximately 6,400 dscfm for each unit.
With two units operating simultaneously, total gas flow exiting the waste
heat boiler is 12,800 dscfm.
The combustors are equipped with auxiliary fuel burners in both the
primary and secondary chambers. Temperatures are monitored continuously in
both chambers, and temperature control is accomplished by automatic
modulation of combustion air flows. Air How pressures are recorded in the
supply ducting for both primary and secondary air flows. There are no
continuous CL or CO monitors in place.
7.1.2.2 Emission Control System Design and Operation. As shown in
Table 7.0-1, the larger Consumat units that employ heat recovery are
typically equipped with an ESP for particulate control. The Tuscaloosa
plant has a single 2-field ESP with PM emissions ranging from 0.04 to
0.08 gr/dscf at 12 percent CCL. Most existing plants are equipped with a
2-field ESP; therefore, the model plant is equipped with a single 2-field
ESP controlling emissions to 0.05 gr/dscf corrected to 7 percent 0^. Since
all three modules are ducted to a single boiler and ESP, there is also a
single stack. Table 7.1-2 gives ESP operating data and stack parameters. A
plot plan of the model plant is shown in Figure 7.1-2.
7.1.2.3 Environmental Basel lire. Table 7.1-2 also presents baseline
emissions data for the model plant. Baseline emissions data are assumed for
the model based on a review of existing emissions data for plants similar in
design. All emissions are reported at the boiler outlet, corrected to
7 percent (L. Uncontrolled CDD/COF emission levels are 400 ng/dscm
measured at the boiler exit. Research indicates that ESP's operating in
.7-16
-------
Building
Walt
ioitar
(actually on
top of
combustort)
Combuators
Tipping floor
Figure 7.1-2. Plot Plan of Model Plant
7-17
-------
the 500 to 600°F temperature range promote formation of CDD/CDF and can
increase exit concentrations by 50 percent over combustor exit levels.
Therefore, the model plant is assumed to have CDD/CDF emissions of
600 ng/dscm at 7 percent CL at the stack under baseline conditions.
Particulate emissions are 0.15 gr/dscf uncontrolled and 0.05 yr/dscf at
the stack. Uncontrolled CO, HC1 and SCk emissions are 100 ppmv, 500 ppmv
and 200 ppmv, respectively. Waste volume reductions are assumed to be
90 percent, and weight reductions are assumed to be 70 percent.
7.1.3 Good Combustion Control. The model plant is judged to have good
combustion practices in place. This is reflected by the relatively low
baseline emission levels at the boiler exit. However, some additional
verification elements (monitoring) are required to provide the operators
with a means of maintaining desired emission performance levels, and there
is also'a potential for downstream form"*ion of trace organics to occur.
Discussion is provided below regarding corrective actions needed to minimize
these problems,
7.1.3.1 Description of Modifications
Verificatjon Measures. Continuous monitoring of CO and 0« is necessary to
verify good combustion and operation at prescribed excess oxygen levels.
These monitors should be installed in ducting prior to the boiler in order
to monitor conditions in each unit. The monitors will include integrators
and readouts in the control room.
Downstream Temperature Control. The flue gas temperatures entering the ESP
wi-11 be reduced from 600°F to 4IO°F. The recommended modification involves
installation of a separate economizer with adequate heat transfer surface to
achieve the required temperature reduction. It is assumed that space
between the boiler and the ESP is adequate to allow installation. Figure
7.1-3 shows the location of the proposed economizer." A bypass duct will be
included so that when repairs to the economizer are needed, a damper can
direct flue gases around the economizer into the ESP. The result of this
modification is that the flue gases are rapidly cooled to temperatures below
which CDD/CDF may form, and the ESP, where residence times and particulate
concentrations are higher, does not experience the temperature which
promotes format 1 on.
7-18
-------
ISP
Building
Wail
Economizer
Boiler
(actually on
too of
combustors)
Combustom
Tipping Roof
Figure 7.1-3. Combustion modification equipment location.
7-19
-------
Retrofit Considerations. It Is estimated that the modifications can be
completed during a scheduled outage with no unscheduled downtime.
7.1-3.2 Environmental Performance. The modifications required for the
model plant will reduce CDD/CDF emission to 400 ng/dscm at the stack,
corrected to 7 percent (L. These reductions are a result of dropping the
flue gas temperatures below the range where downstream formation of
CDD/COF has been observed. At a flue gas temperature of 450°F» CDD/CDF
emissions at the stack are assumed to be the same as at the combustor exit.
The monitors will provide the operators with a means of preventing
excess air emissions by alerting them to the need for corrective action in
the event of poor operating conditions. The modifications do not affect PM
or acid gas emissions.
7.1.3.3 Costs. The capital costs of the modifications are presented
in Table 7.1-3. Total capital costs for the retrofit are $270,000.
Annualized capital costs are $36,000 per year, based on a 15-year plant life
and a 10 percent Interest rate. Annual costs are presented in Table 7.1-4.
Total annualized costs, including O&M and annualizsd capital, are $182,000
per year.
7.1.4 Best Particulate Control
The ESP in place on the model plant reduces PM by 62 percent, from
0.15 gr/dscf to 0.05 gr/dscf {corrected to 7 percent 0*}. Since good
combustion practices are judged to already be in place, no change in inlet
grain loading will be produced by combustor modifications. Therefore, the
baseline PM emission rate is equal to the rate identified with moderate
control (0.05 gr/dscf), and no plant modifications will be required for this
control level.
7.1.4.1 Description of Hodifications. To achieve good particulate
matter control (0,01 gr/dscf emission rate) with good combustion practices
and temperature control to 4IO°F will require an ESP with 5,400 square feet
of collection area. Since the required area is two and a half times the
area of the existing ESP, adding collection plates to the existing ESP is
not a practical way to achieve the desired performance. Instead, the
existing ESP will be demolished and replaced with a new ESP of adequate
size.
7-20
-------
TABLE 7.1-3. PLANT CAPITAL COST FOR COMBUSTION MODIFICATIONS
(Three units of 50 tpd each)
Item Cost (SI,000}
DIRECT COSTS:
Economizer with Feedwater System
ind Duct Modifications 45
Oxygen and CO Monitors
with Readouts and Integrators 135
Total 180
INDIRECT COSTS AND CONTINGENCIES: 90
TOTAL CAPITAL COSTS 270
DOWNTIME COST 0
ANNUALIZED CAPITAL RECOVERY AND DOWNTIME 36
aA11 costs are in December 1987 dollars.
7.91
-------
TABLE 7.1-4. PLANT ANNUAL COST FOR COMBUSTION MODIFICATIONS
(Three units of 50 tpd each)
Item Cost ($1,000)
DIRECT COSTS:
Operating Labor 0
Maintenance Labor 42
Maintenance Materials 42
Total 84
INDIRECT COSTS;
Overhead 51
Taxes, Insurance, and Administration 11
Capital Recovery and Downtime 36
Total 98
TOTAL ANNUALIZED COST 182
7-22
-------
Fifty feet of new duct and a new ID fan will also be required. The new
ESP will be erected In the same general area as the existing ESP; a plot
plan is shown in Figure 7.1-4. No new monitoring equipment will be
installed. Downtime will affect all three units at once and is estimated to
be one month.
7.1.4.2 Environmental Performance. Particulate matter emissions will
be reduced from 0.05 gr/dscf to 0.01 gr/dscf. The increased fly ash recovery
will add 12 tons per year to the baseline solid waste disposal requirements
for the plant.
7.1.4.3 Costs. Capital cost requirements for particulate control
upgrade are shown in Table 7.1-5. Demolition of the existing ESP will cost
$400,000. The other major capital item is the PM control equipment. Total
capital cost is $1,480,000. Downtime cost will be $162,000. Annual costs
are dominated by capital recovery and annualized downtime cost and are
expected to be $298,000 per year. Annual costs are presented in
Table 7.1-6.
7-1-5 Good Acid Gas Control.
7.1.5.1 Description of Modifications. For good acid gas control,
hydrated lime will be injected into the flue gas duct before the ESP, The
lime sorbent will be fed at a molar ratio of 2:1 (calcium to acid gas) for a
total rate of 113 Ib/hr with two units operating. Additional plant
equipment will include a sorbent storage silo, a pneumatic sorbent transfer
system, a sorbent feed bin, and pneumatic injection nozzles. To cool the
flue gas from 450°F to 350°F, spray nozzles also located in the duct before
the ESP will introduce 2 to 3 gpm of water. If an economizer is not present
as the result of Installing good combustion modifications, 6 to 7 gpm of
cooling water will be required to cool the flue gas from 600°F to 350°F.
Fifty feet of new duct will be fabricated to contain the new water and
sorbent nozzles.
A total of 10,800 square feet of ESP collection area will be required
to collect the sorbent and fly ash with the economizer in place.
Approximately 11,400 total square feet will be needed if combustor
modifications have not been made. Again, the existing 2200 square foot ESP
1s not salvageable and will be demolished to make'room for a new ESP.
7-23
-------
New ESP
and ID Fan
s
Economizer
Boiler
(actually an
top of
combustora)
Building
Wall
Combustors
Tipping ROOT
Figure 7.1-4. Particulats control equipment arrangement.
. 7-24
-------
TABLE 7.1-5. PLANT CAPITAL COST FOR PARTICIPATE MATTER CONTROLS
{Three units of 50 tpd each)
Item Cost ($1000)
DIRECT COSTS:
PM Control3
Upgrade Costs 594
Access/Congestion Cost 198
New flue Gas Ducting3
Ducting Costs 12
.Access/Congestion Cost 3
Other Equipment
Fan 49
Stacks 0
Demo!i t i on/Re!ocat i on 400
Total 1,210
Indirect Costs and Contingencies 275
Monitoring Equipment . 0
TOTAL CAPITAL COST 1,480
DOWNTIME COST 154
ANNUALIZED CAPITAL RECOVERY 215
aBased on moderate access/congestion.
7-25
-------
TABLE 7.1-6. PLANT ANNUAL COST FOR PARTICULATE MATTER CONTROLS
(Three units of 50 tpd each)
Item Costs ($1000)
DIRECT COSTS:
Operating Labor 0
Supervision 0
Maintenance Labor 0
Maintenance Materials 1
Electricity 2
Water 0
Waste Disposal 0
Monitors Q_
Total 3
IKDIRECT COSTS:
Overhead 19
Taxes, Insurance, and
Administration 60
Capital Recovery and Downtime . 115
' Total 294
TOTAL ANNUALIZED COST 297
7r26
-------
Installation of a new ESP will also require 50 feet of new duct and a new ID
fan. The proposed equipment arrangement is shown In Figure 7.1-5. New
monitoring equipment for SO-, HCH, 0* and CO- is also included. Downtime is
expected to be approximately one month.
7.1.5.2 Environmental Performance. Total COD/CDF emissions are
expected to be reduced 7i percent from boiler outlet levels. Reduced ESP
operating temperatures will prevent additional formation in the ESP, so
expected total COD/CDF emissions of 100 ng/dscm are expected. Acid gas
emissions will be reduced 80 percent for HC1 and 40 percent for S(L,
Particulate matter emissions will be reduced from O.Oi gr/dscf to
0.01 gr/dscf. Additional collected fly ash and sorbent will add 595 tons per
year of solid waste to the plant baseline disposal requirements.
7.1.5.3 Costs. Capital cost requirements for dry sorbent injection
are presented in Table 7.1-7 for baseline and good combustion practices.
Total capital cost is $2,480,000 with baseline combustion and $2,450,000
with good combustion. Most of the cost is associated with new equipment for
particulate and temperature control, though $400,000 is included for
demolition of the existing ESP. A moderate access/congestion level is
assumed for all new equipment installation.
Annual costs are presented in Table 7.1-8. The major operating costs
are associated with lime purchase and with operation and maintenance of the
process monitors. Total annual cost of dry sorbent injection, including
annualized capital and downtime is $726,000 with baseline combustion and
$719,000 with good combustion.
7.1.6 Best Acid Gas Control.
7.1.6.1 Description of Modifications. To achieve greater reductions
in COO/CDF, HC1 and SO-, a spray dryer/fabric filter system will be
installed in place of the existing ESP. A total of 100 feet of new duct
will be used to connect the new equipment to the existing stack. The
proposed equipment configuration is shown in Figure 7.1-6.
Lime slurry will be introduced into the spray dryer at a calcium-to-
acid gas ratio of 2.5:1. Water in the lime slurry equivalent to 8 gpm is
needed to cool the gas stream from 600 to 300°F. The spray dryer installed
with good combustion would introduce only 4 gpm, since the economizer exit
gas is already cooled to 450°F.
7-27
-------
New ESP,
Duct Sprays,
and ID Fan
Economizer
Boiler
(actually on
top of
combustora)
Building
Wai!
Combustors
Tipping Floor
Figure 7.1-S. Dry sorbent injection tquipment arrangement,
7-28
-------
TABLE 7.1-7. PLANT CAPITAL COST FOR DRY SORBENT INJECTION WITH NEW ESP
(Three units of 50 tpd each)
Cost ($1000)
Item Baseline Combustion Good Combustion
Practices Practices
DIRECT COSTS:
Acid Gas Control3
Equipment
Access/Congestion Cost
Part icul ate and Temperature Control
Equipment
Access/Congestion Cost
New Flue Gas Ducting3
Ducting Cost
Access/Congestion Costs
Other Equipment
Fans
Stacks
Demolition/Relocation
Total
Indirect Costs and Contingencies
Monitoring Equipment
TOTAL CAPITAL COST
DOWNTIME COST
ANNUALIZED CAPITAL RECOVERY
169
17
835
174
27
9
47
0
400
1,680
538
257
2,480
154
346
169
17
824
172
25
9
45
0
400
1,660
532
257
2,450
154
342
aBased on moderate access/congestion.
Based on high access/congestion for temperature control ductwork.
cTurnkey.
. 7-29
-------
TABLE 7.1-8. PLANT ANNUAL COST FOR DRY SORBENT INJECTION WITH NEW ESP
(Three units of 50 tpd each)
Cost ($10001
Item Baseline Combustion Good Combustion
Practices Practices
DIRECT COSTS:
Operating Labor 30
Supervision 5
Maintenance Labor 14
Maintenance Materials 13
Electricity 17
Water 2
Lime 36
Waste Disposal 16
Monitors 103
Total 236
INDIRECT COSTS:
Overhead , 55 55
Taxes, Insurance, and
Administration 89 88
Capital Recovery and Downtime 346 342
Total 490 485
TOTAL ANNUALIZED COST 726 719
7-30
-------
New Spray Dryer,
Fabric Filter,
and ID Fan
Economizer | |
[ I
Boiler
(actually on
top of
combustora)
Building
Wall
Combustora
Tipping ROOT
Figure 7.1-6. Spray dryer/fabric filter equipment arrangement,
7-31
-------
The lime receiving, storage and slurry area is also shown in
Figure 7.1-6. The fabric filter will have 7,300 square feet of effective
cloth area with good combustion or 7,600 square feet with baseline
combustion. Both filters have a net air-to-cloth ratio of 4:1. The
increased pressure drop of fabric filter over ESP will require a new ID fan.
New monitoring equipment for HC1, S02> C02> 0, and opacity will be
installed. Downtime is expected to be one month.
7.1.6.2 Environmental Performance. CDD/CDF emission reductions of
99 percent or to 5 ng/dscm (whichever is higher) are expected. Emissions of
particulate matter will be reduced to 0.01 gr/dscf. Acid gas emissions will
be reduced 90 percent for S02 and 97 percent for HC1.
7.1.6.3 Costs. Capital costs for installing a spray dryer/fabric
filter system are shown in Table 7.1-9. Total capital costs are $4,490,000
with baseline combustion and $4,200,000 with good combustion. These figures
include purchased equipment, installation, ESP demolition, and indirect
costs such as engineering and contingencies. A moderate level of access/
congestion was assumed.
Annual costs are presented in Table 7.1-10. Significant operating
costs are for maintenance materials including bag replacement, and for
maintenance of the process monitors. Total annual cost including capital
recovery and annualized downtime is $1,180,000 with baseline combustion, and
$1,120,000 with good combustion.
7.1.7 Summary of Control Options
7.1.7.1 Description of Control Costs. The control technologies
described in the previous sections have been combined into seven retrofit
emission control options. Table 7.1-11 summarizes the combustion,
particulate control, and acid gas control technologies described in Sections
7.1.3 through 7.1.6 that were combined for each of the control options
described in Section 3.0. It should be noted that since the model, plant
already achieves good PH control at baseline, Options 1 and 2 are identical.
7.1.7.2 Environmental Performance. The performance of each control
option is summarized in Table 7.1-12. For each pollutant, the table
presents both the pollutant concentrations and emissions. The greatest
reductions in acid gases, particulate matter, and total CDD/CDF are all
7-32
-------
TABLE 7.1-9,
PLANT CAPITAL COST FOR SPRAY DRYER WITH FABRIC FILTER
(Three units of 50 tpd each)
Costs ($1000)
Item
Baseline Combustion
Practices
Good Combustion
Practices
DIRECT COSTS:
Acid Gas Control
Equipment
Access/Congestion Cost
New Flue Gas Ducting
Ducting Cost
Access/Congestion Cost
Other Equipment
Fans
Stacks
Demolition/Relocation
Total
Indirect Costs
Contingency .
Monitoring Equipment
TOTAL CAPITAL COST
DOWNTIME COST
ANNUAL I ZED CAPITAL
RECOVERY AND DOWNTIME
1,840
459
26
7
56
0
400
2,780
787
634
286
4,490
154
610
1,700
424
25
6
48
0
400
2,600
726
585
286
4,200
154
573
Turnkey.
7-33
-------
TABLE 7.1-10. PLANT ANNUAL COST FOR SPRAY DRYER WITH FABRIC FILTER
(Three units of 50 tpd each)
Cost (SlOOtn
Item Baseline Combustion Good Combustion
Practices Practices
DIRECT COSTS;
Operating Labor 48 48
Supervision 7 7
Maintenance Labor 26 26
Maintenance Materials 55 51
Electricity 40 32
Compressed Air 5 4
Water . 2 1
Lime 30 30
Waste Disposal 20 20
Monitors 107 107
Total 341 328
INDIRECT COSTS:
Overhead 78 75
Taxes, Insurance, and
Administration 152 140
Capital Recovery and Downtime 610 573
Total 840 788
TOTAL ANNUALIZED COST 1,180 1,120
3Includes bag replacement costs of $7,000.
7-34
-------
TABLE 7.1-11. SUMMARY OF CONTROL OPTIONS FOR LA85E MODULAR STARVED-AIR COHBUSTOR
-a
i
Participate Contro 1
Acid Gas Control
Combustion Temperature Existing ESP Additional Meu Sorbent Spray
Control Option Baseription Modifications Control Rebuilt SCA -fabric Fitter Injection Dryer
1. Good Combustion and
Temperature Control
2. Good PN Control with
Combustion Control
3. Best PM Control and
Combustion and Temperature
Control
4. Good Acid Gas Control,
Best PH Control and
Temperature Control
5. Good Acid Gas Control
and Best PM/Combust ion/
Temperature Control
6. Best Acid Gas Control,
Best PM Control, and
Temperature Control
7. Best Acid Gas Control and
Best PM/Combustion/
Temperature Control
-------
TABLE 7.1*12, ENVIRONMENTAL PERFORHAHCE SUMMARY FOR LARGE HODULAR STARVE)-AIR KWC
MODEL PLANT' RETROFIT CONTROL OPTIONS* (Three unit* of 50 tpd esch)
•xl
I
CO
Baseline Option 1 Option 2 Option J Option 4 Option 5 Option 6 Option 7
Total CDD/CDP Emission*
(of/dgca)
X Reduction vs. Baseline
00 Emissions
(pponr)
H»/yr
X Reduction vs. Baseline
PM Emissions
(gr/dicf)
Hifyr
X Reduction vs. Baseline
SO Emissions
Cppuw)
H»fyi
X Reduction vs. Baseline
HC1 Emissions
(ppav)
Kg/ye
X Reduction vs. Baseline
Total Solid Maste
(tons /day)
Nt/yc
X Increase vs. Baseline
600
7.8E-5
—
100
16.2
—
0.05
14.8
—
200
74
•-
500
105
—
30
9,090
~~
400
5.1E-5
33
100
16.2
0
0.05
14.8
0
200
T4
0
500
105
80
30
9,090
0
400
5.1E-S
33
100
16.2
0
0,05
14. a
0
a oo
14
0
500
105
0
30
9,090
0
400
5.1E-5
31
100
16.2
0
0.01
3.0
80
200
74
0
SOO
105
0
30
9,100
0
100
1.3E-6
83
100
16.2
0
0.01
3.0
80
120
44
40
100
21
90
31. a
9,630
6
100
1 . 31-6
83
100
16.2
0
0.01
3.0
80
120
44
40
100
21
80
31.8
9,630
6
5
6.5E-7
99
100
16.2
0
0.01
J.O
80
19
7
90.5
15
3
97
32.3
9,800
8
5
6.5E-7
99
100
16,2
0
0.01
3,0
BO
19
7
90.5
15
3
97
32.3
9,800
8
All flue (** concentr»tlon» ace reported on • dcy 1 peccent O best!. Standard and normal conditions are
both 1 atmosphere and 70 F
-------
achieved with the spray dryer/fabric filter system. The next most effective
control for all these pollutants is the dry sorbent injection. Both sorbent
addition technologies increase solid waste slightly (less than 10 percent
above baseline). The CO emissions remain unchanged, at 100 ppm, for all
control options.
7.1.7.3 Costs. The total annualized cost of each option is presented
in Table 7.1-13. The most costly control option is Option 7, the spray
dryer/fabric filter installation with the economizer for temperature
control. Total annual cost for Option 7 is $1,300,000 per year. Overall,
the costs of each option are higher for successively higher levels of
control.
7.1.7.4 £nargy_Impacts. Table 7.1-14 presents a summary of the energy
impacts associated with the control options. The energy use figures shown
are incremental use relative to baseline. The energy savings from not
operating the existing ESP are taken into account. There is no increase in"
auxiliary fuel use because auxiliary burners are already in place on the
model plant and are used under baseline operation. Note that there is a
considerable electrical penalty for the spray dryer/fabric filter option
(Option 6 vs. 7) for temperature control with humidification instead of the
economizer installation. The fan cost is increased because of increased gas
volume, from the injected water, which must be pulled through the fabric
filter.
7-37
-------
TABLE 7.1-13. COST SUMMARY FOR LARGE MODULAR STARVED-AIR KUC MODEL PLANT RETROFIT CONTROL OPTIONS*
(Three unLLi of 50 tp4 each)
Ope Ion 1
total Capital Coit
Downtime Cost
Annual lead Capital and Downtime
Can
Direct O&H Colt
total Annual Coit
Coat Eff ectlvenejt
270
0
36
8*
182
3.64
Option 2
270
0
36
84
182
3.64
Option 3
1,750
15*
251
87
479
9. 58
Option 4
2,480
154
346
236
726
14. SO
Option 5
2,720
154
378
318
901
18.00
Option 6
4,490
1S4
610
341
1,180
23.6
Option 7
4,470
154
609
412
1,300
26.0
(«/ton MSH)
Facility Downtime 0011111
(Months)
-4
jV, Total Conpllince Tim* 4 4 19 19 19 2S 25
00 (Months)
All co«t» (except coat effectiveness) glvan In £1000. All ccutm in 1997 dollars.
-------
TABLE 7.1-14. ENERGY IMPACTS FOR LARGE MODULAR
STARVED-AIR COMBUSTOR CONTROL OPTIONS3
Option
1
2
3
4
5
6
7
Electrical Use
(MWh/yr)
0
0
35.1
345
336
885b
709b
Gas Use
(Btu/yr)
0
0
0
0
0
0
0
Increase from baseline consumption.
Excludes the electrical credit for not operating the ESP'2.
7-39
-------
7.2 SMALL MODULAR STARVED-AIR COMBUSTOR WITH RECIPROCATING GRATES
This section presents the retrofit case study results for a small (unit
size < 50 tpd) modular starved-air MWC with reciprocating grates. As shown
in Table 7.0-1, four existing facilities are represented by this model with
unit sizes varying from 25 to 38 tpd. Section 7.2.1 describes of the
Waxahachie, TX, facility, which was visited to gather information for model
development. Section 7.2.2 describes of the model plant. Sections 7.2.3
through 7.2.8 detail the retrofit modifications, estimated performance, and
costs associated with each control option. Section 7.2.9 summarizes the
control options, which are discussed in more detail in Section 2.0 of this
report.
2
7.2.1 Description of the Waxahachlg Facility
The Waxahachie waste-to-energy plant consists of two modular MWC's, each
with capacity to burn 25 tons.of municipal solid waste (MSW) per day. The
units are two-chamber designs with starved-air conditions in the primary
chamber and burnout of gases in the secondary. The units manifold to a
single-pass firetube boiler and exhaust gases exit the system with no further
treatment. The plant operates both units at full capacity from 11:00 p.m.
Sunday until noon the following Saturday, with routine maintenance taking
place during downtime. The plant accepts residential and some commercial (no
industrial) waste. Due to limitations on storage and burning capacities, MSW
is regularly routed to the landfill.
The plant was constructed and began operations in 1982 using a Synergy
grate system supplied by Clear Air. When the waste plant was in the
planning/construction phase, a steam delivery contract was established with
International Extrusion, a subsidiary of International Aluminum. Extrusion
agreed to purchase 15,000 Ib/hr (or its total requirement, if less) of
100 psi steam. The price of steam was based on the cost of the least
expensive fossil fuel available to Extrusion, which was natural gas. Process
modifications at Extrusion have continually reduced the steam demands from
the waste facility over the last five years. It was uneconomical for the
plant to continue to produce so little steam for Extrusion, and the City
finally dissolved the contract in August 1987. The boiler is currently idle
and flue gases are being vented to the dump stacks until an alternate steam
7-40
-------
contract is secured. The plant is in negotiating with an adjacent production
plant to establish a new contract for steam sales. If this contract is
secured it may resu-lt in 7-day/week operation for the waste-fired
plant.
7.2.1.1 Combustor Design and Operating Procedures. Trucks deliver
waste and dump it on the tipping floor where large bulky items are separated.
A front end loader mixes the waste and charges each furnace. Each unit is
equipped with an automatic loader which holds approximately 2.5 bucket loads
from the front end loader. When waste is charged and the top door of the
loader closes an automatic charging sequence begins. The fire door opens and
a ram extends, pushing the fuel into the primary combustion chamber. The ram
then retracts and the fire door closes. When the loader top door opens, it
is then ready to receive another charge. The timing cycle is set manually
.and usually operates every four minutes. The seal on the loader is not
tight, and the inside of the furnace can be seen through a 1-inch gap
during charging. However, based on a visual inspection, it appeared that
there are few other points of air inleakage to the system.
The primary chamber is 22'-9" long by 7'-4" wide. It contains two
separate grate sections separated by a vertical drop of about one foot. The
sections are sloped 15° from horizontal, and each is equipped with an
individual air plenum and reciprocating grates which work by way of a rack
and pinion. Grate speeds are set manually to achieve good waste burnout.
The reciprocating action is controlled by a Texas Instruments controller
(Model TI5). Grate siftings are conveyed to the quench pit by drag
conveyers. Bottom ash is discharged from the lower grate section to the
water-quenched pit which is also equipped with a drag conveyer. Bottom ash
is buried in the local landfill. Burnout appears to be fairly good based on
visual observation of the bottom ash, and ash disposal quantities are
reported to be about four tons of ash per 50 tons of garbage (92 percent
weight reduction).
The original Synergy grates were wedge-shaped cast iron with a 2-inch
nose on the lower portion. This nose (combined with the 15° slope) resulted
in waste being pushed through the system too rapidly, and burnout became a
7-41
-------
problem. This has been resolved by replacing the Synergy grates with the
flat 1/2-inch steel- plates which are cut and drilled on site.
Separate forced draft fans supply combustion air to the primary and
secondary chambers. Air flows are not measured directly for either the
primary or the secondary supplies. Thermocouples located at the exit of each
chamber provide a signal to the computer controller that results in an
automatic adjustment to each air system supply damper, thus maintaining a
temperature set point. Primary air is supplied at low velocity through the
grates and the estimated retention time of gases in the primary chamber is
1.2 seconds.
Typical operating temperatures in the primary chamber vary from 1600 to
1800°F, The primary chamber contains a gas burner which is fired for about
2 to 3 hours during process start-up. Constant pressure is maintained in the
primary chamber by the induced draft fan, which automatically adjusts a
damper setting based on a pressure reading from the primary chamber. A
negative draft (approximately -0,2" H-0) is maintained to avoid fugitive
emission episodes.
The secondary combustion chamber has a volume of 265 cubic feet and
a gas residence time of 0.8 seconds. High-velocity air is injected into the
chamber through 16 holes, each 0.75 inches in diameter, located on a ring
around the circumference at the entrance to the chamber, A second nozzle,
four inches in diameter, injects additional air from the same header at a
side wall location approximately three feet downstream of the radial ring.
At the exit of the secondary chamber there are two nozzles, each six inches
in diameter, which supply cooling air before the flue gases exit the chamber.
A single forced-draft fan supplies all of the secondary air for one furnace.
Neither of the secondary air fans were operating during the visit. Plant
personnel indicated that the induced-draft fan usually created enough draft
to pull secondary air into the chamber at the required flow rate. A
secondary chamber gas burner fires automatically as needed to maintain a
temperature setting in the secondary chamber. The set point temperature 1s
usually near 1800°F. Thi flue gases exiting each secondary chamber may
either be discharged through individual dump stacks, or manifolded and ducted
to the firetube boiler and discharged through a single stack.
7-42
-------
When the boiler is operating, 60 percent of delivered steam is returned
as condensate. Water treatment is performed on site. Discussions with plant
personnel concerning maintenance indicated that the firetube boiler has
performed adequately when operated. Tubes are cleaned once per week with a
wire brush.
7.2.1.2 Emission Control System Design and Operation. No air pollution
control device (APCD) is currently in place. The Plant Manager stated that
the unit is stack tested for participate matter emissions yearly by the State
Air Control Board, but the results have not been forwarded to the plant.
Smoke emissions were less than 5 percent opacity during the 4 hours of the
visit.
7-2.2 Description of Model Plant
7.2.2.1 Combustor Design and Operation. The model facility consists of
two 25-tpd modular combustors that operate 5 days per week, 24 hours per day..
Typical of most smaller modular starved-air MWC's, there is no heat recovery
in place at the model facility. Rather than transfer rams, grates are used
to move the waste through the primary combustion chamber. A plot plan of the
model plant is shown in Figure 7.2-1.
Each unit consists of refractory-lined primary and secondary combustion
chambers connected by a vertical breeching. Haste is fed to the primary
chamber by a hydraulic ram. The ram frequency is adjusted manually and
controlled automatically. The primary chamber contains two reciprocating
grate sections that move the waste through the system. The grates have
separate sets of underfire air plenums which provide primary air at
substoichiometric conditions. Primary air flows are adjusted automatically
to maintain the primary chamber temperature at 1600°F. The distribution of
air to each of the plenums can be manually adjusted. Grate speeds are
manually set and adjusted.
The fuel-rich gases from the primary chamber flow through the refractory
breeching into the secondary chamber, where they are mixed with high pressure
secondary air to complete the combustion process. Excess air quantities are
supplied in the secondary chamber so that the combined air supply system
provides 100 percent excess air. At 100 percent excess air, total air flow
exiting the secondary chamber is approximately 3400 scfm (3200 dscfm) per
unit. The primary and secondary air flow rates are controlled automatically
7-43
-------
Incinerator
Loader
Stack
Located on
R00'
LD-fin
, Water Quench Chamber
Incinerator
Loader
Building
Figure 7.2-1 Plot Plan of Hodel Plant
00
§
7-44
-------
in response to temperature readings in each combustion chamber. The desired
temperature set points are 1600°F at the exit of the primary chamber and
1800°F at the exit tjf the secondary chamber. Auxiliary fuel burners are
located in each chamber and are used during start-up. There are no
continuous flue gas monitors in place at the model plant. The combustor
exhaust gases are manifold from the exit of the secondary combustion chamber
to a water quench chamber, where they are cooled to 450°F before being
discharged to the atmosphere through a single stack.
7.2.2.2 ^mission Control System and Operation. The model plant is not
equipped with an APCD. As shown in Table 7.0-1, small modular starved-air
plants typically are not equipped with any air pollution control devices
(APCD's). For retrofitting new APCD's, a moderate access and congestion
level is assumed. It is assumed that this level is typical for plants in
this subcateg'ory. For this case study, one APCD will be costed based on the
combined flue gas flow rate of both combustors.
7.2.2.3 Environmental Baseline. Table 7.2-1 presents baseline emission
data for the model plant. The model plant is assumed to have COO/COF
emission 400 ng/dscm, corrected to 7 percent Qj. Both uncontrolled PM and
CO emissions are assumed to be relatively lew (0.15 gr/dscf and 100 ppmv, at
7 percent 0*, respectively) which indicate good combustion practices are
essentially in place. Uncontrolled HC1 and SO- emissions are estimated to be
500 and 200 ppmv at 7 percent Q-, respectively. It is assumed that the
combustion process reduces waste volume by 90 percent and weight by 70
percent.
7-2.3 Good Combustion Control
7.2.3.1 Description of Modifications. With the exception of some
verification measures, the model plant is judged to have good combustion
practices in place. This is reflected by the relatively low baseline
emissions. Operating practices are assumed to be kept within the limits of
the combustor design specifications. The recommended modifications are
limited to the installation of continuous CO and 0- monitors in the stack to
provide verification of good combustion and proper excess air levels. The
monitors should be installed with integrators and readout in the control
7-45
-------
TABLE 7.2-1. MODEL PLANT BASELINE DATA FOR SHALL MODULAR
STARVED-AIR MWC WITH RECIPROCATING GRATES
Combustor:
Type - Modular Starved-Air,
Reciprocating Grate
Number of Combustors - 2
Combustor Unit Capacity - 25 tpd
Emission Controls - None
Flue Gas Flow Ratea - 15,500 acfm at 1800°F
Emissions:
COD/CDF (tetra-octa) - 400 ng/dscm
PM (stack) - 0.11 gr/dscf
CO - 100 ppmv
HC1 - 500 ppmv
S02 - 200 ppmv
Operating Data:
Remaining Plant Life - 15 years
Annual Operating Hours - 6,500 hours
Annual Operating Cost - $557,000/year
aper combustor.
All emissions are dry, corrected to 7 percent
7-46
-------
room. It is estimated that installations of the monitors can be completed
during a schedule outage with no unscheduled downtime.
7.2.3.2 Environmental Performance. The modifications will provide
verification of proper combustion operation. No changes in emissions from
baseline are expected.
7.2.3.3 Good Combustion Control Costs. The capital costs of the
modification" are presented in Table 7.2-2. Total capital costs are estimated
to be $117,000. Annual costs are presented in Table 7.2-3. Annualized
capital is $15,000 based on a 15-year facility life and a 10 percent interest
rate. Total annual ized costs are $84,000 per year, including annualized
capital and O&M.
7.2.4 Moderate Particulate Control
7.2.4.1 Description of Modifications. To achieve moderate PM control
(0.08 gr/dscf) will require the additional of a new ESP with 2,050 square
feet of plate area. This ESP is sized to handle the flue gas from both
combustors. It is assumed that there is sufficient space beyond the existing
stack to locate the ESP, and that access/congestion constraints are moderate.
Forty-five feet of flue gas ducting would be required to connect the water
quench to the ESP and connect the ESP outlet to a new stack. Besides a new
stack, a new 1.0. fan is included to handle the additional pressure drop of
the new ESP and ductwork. In addition, cost for an opacity monitor and data
reduction system is included. The opacity monitor is to be located at the
outlet of the ESP. Figure 7.2-2 also shows the location of the ESP,
ductwork, new I.D. fan, and new stack.
Downtime will affect both combustors at once and is estimated at one
month for ductwork tie-ins.
7.2.4.2 Env1ronmental Performance. Particulate matter emissions will
be reduced from baseline levels of 0.15 gr/dscf to 0.08 gr/dscf. This
additional fly ash recovery will add 9 tons/year (dry) to the solid waste
disposal requirements. COO/CDF and acid gas emissions are not affected by
this modification.
7.2.4.3 Costs. Capital cost requirements for moderate particulate
control are presented in Table 7.2-4. The major cost item is the particulate
control equipment. Total capital cost is estimated to be $580,000. This
7-47
-------
TABLE 7.2-2. PLANT CAPITAL COST FOR COMBUSTION MODIFICATIONS
(Two units at 25 tpd each)
Item Costs ($1,000)
DIRECT COSTS:
Oxygen and CO Monitors
with Readouts and Integrators 90
Total 90
Indirect Costs and Contingency , 27
TOTAL CAPITAL COSTS 117
DOWNTIME COST 0
ANNUALIZED CAPITAL COSTS 15
7-48
-------
TABLE 7.2-3, PLANT ANNUAL COST OF COMBUSTION MODIFICATIONS
(Two units at 25 tpd each)
Item Costs ($1,000)
DIRECT COSTS;
Maintenance labor 20
Maintenance Materials 20
Operating Labor 0
Total 40
INDIRECT COSTS:
Overhead 24
Taxes, Insurance, and S
Administration
Capital Recovery and Downtime 15
44
Total
84
TOTAL ANNUALIZED COST
7-49
-------
Incinerator
Loader
New Stack
LD. Fan
ESP
Water Quench
Chamber
Incinerator
Loader
Building
Flgyre 7.2-2. Plot Plan of Temperature and Participate Control Equipment °
7-50
-------
TABLE 7,2-4 PLANT CAPITAL COST FOR PARTICULATE HATTER CONTROLS
(Two units of 25 tpd each)
Item
DIRECT COSTS:
Parti cul ate Control4
Equipment
Access/Congestion Cost
Temperature Control
Equipment
Access/Congestion Costs
New Flue Gas Ducting3
Ducting Costs
Access/Congestion Cost
Other Equipment
Fan
Stack
Demo! 1 1 i on/Re! ocat 1 on
Total
Indirect Costs and Contingencies
Monitoring Equipment
TOTAL CAPITAL COST
DOWNTIME COSTS
ANNUALIZED CAPITAL RECOVERY AND •
DOWNTIME
Costs
Moderateh
PM Control0
226
56
0
0
9
3
31
100
0
429
90
60
580
19
79
(SI. 000)
Good PM
Control
302
75
0
0
9
3
35
100
0
524~
90
60
675
19
92
Best PM
Control
562
141
0
0
9
3
35
100
0
850
90
60
1,000
19
135
aTurnkey
Moderate PM control is 0.08 gr/dscf at 7 percent
7-51
-------
cost includes purchase equipment, installation, and indirect costs such as
engineering and contingencies. Estimates assume moderate APCO congestion
level.
Annual costs are presented in Table 7,2-5 and are dominated by capital
recovery and downtime. Indirect annual costs including capital recovery and
downtime are estimated to be $112,000 per year. Direct operating and
maintenance costs are estimated at $31,000 per year. Thus, total annualized
cost for moderate PM control is estimated at $144,000 per year.
7.2.5 Good Particulate Control
7.2.5.1 Description of Modifications. To achieve good PM control
(0.05 gr/dscf) will require the addition of a new ESP with 5,590 square feet
of plate area. This ESP is sized to handle the flue gas from both
combustors. It is assumed that there is sufficient space beyond the existing
stack to locate the ESP, and that access/congestion constraints are moderate..
Approximately 45 feet of flue gas ducting would be required to connect the
water quench chamber to the ESP and connect the ESP outlet to a new stack.
Besides a new stack, a new 1.0. fan is included to handle the additional
pressure drop of the new ESP and ductwork. In addition, cost for an opacity
monitor and data reduction system is included. The opacity monitor is to be
located at the outlet of the ESP. Figure 7.2-2 also shows the location of
the ESP, ductwork, new I.D. fan, and new stack.
Downtime will affect both combustors at once and is estimated at one
month for ductwork tie-ins.
7.2.5.2 Environmental Performance. Particulate matter emissions will
be reduced from baseline levels of 0.15 gr/dscf to 0.05 gr/dscf. This
additional fly ash recovery will add 13 tons/year (dry) to the solid waste
disposal requirements.. CDD/CDF and acid gas emissions are not affected by
this modification.
7.2.4.3 Costs. Capital cost requirements for good particulate control
are presented in Table 7.2-4. The major cost item is the particulate control
equipment. Total capital cost is estimated to be $524,000. This figure
includes purchased equipment, installation, and indirect costs such as
engineering and contingencies. Estimates assume a moderate APCD congestion
level.
7-52
-------
TABLE 7.2-5 PLANT ANNUAL COST FOR NEW PARTICULATE MATTER CONTROLS
(Two units of 2S tpd each)
Item
DIRECT COSTS;
Operating Labor
Supervision
Maintenance Labor
Maintenance Materials
Electricity
Water
Waste Disposal
Monitors
Total
IM01RECT COSTS:
Overhead
Taxes, Insurance, and
Administration
Capital Recovery and Downtime
Total
TOTAL ANNUAL1ZED COST
Moderate
PM Control*
10
1
5
4
1
0
0
8
29
12
21
79
112
141.
Costs
Good PM
Control
10
1
5
5
2
0
0
3
31
13
25
92
129
160
Best PM
Control
10
1
5
8
3
0
0
8
34 -
15
38
135
188
221
oderate PM control is 0,08 gr/dscf at 7 percent
7-13
-------
Annual costs are presented in Table 7.2-5 and are dominated by
annualized capital recovery and downtime. Indirect annual costs
including capital recovery and downtime are estimated to be $129,000 per
year. Direct operating and maintenance costs are estimated at $31,000 per
year. Thus, total annualized cost for good PH control is estimated at
$160,000 per year.
7.2.6 Best Particulate Control
7.2.6.1 Description of Modifications. To achieve best PM control
(0.01 gr/dscf), a single new ESP with approximately 15,900 square feet of
collection area will be installed to serve both combustors. The new
ESP, ductwork, l.D. fan, and new stack are located as shown in Figure 7.2-2.
An opacity monitor is located at the outlet of the new ESP. Approximately
45 feet of new ducting will be required. Downtime will affect both
combustors at once and ;s estimated at 1 month for ductwork tie-ins.
7-2.6.2 Environmental Performance. Particulate matter emissions will "
be reduced from 0.15 gr/dscf to 0.01 gr/dscf. The additional recovered fly
ash will add 19 tons/yr to the site total solid waste disposal requirements.
CDD/CDF and acid gas emissions are not affected by this modification.
7.2.6.3 Costs. Capital cost requirements for the best particulate
control are presented in Table 7.2-4. Total capital cost is estimated to be
$1,000,000. This includes purchased equipment, installation, and indirect
costs such as engineering and contingencies. Estimates assume a moderate
APCD congestion level.
Annual costs are presented in Table 7.2-5 and are dominated by
annualized capital recovery and downtime. Indirect annual costs
are $188,000 per year. Direct operating and maintenance costs are estimated
at $34,000 per year. Thus, total annualized cost for best PM control is
estimated at $221,000 per year.
7.2.7 Good Acid Acid Gas Control
7.2.7.1 Description of Modifications. For good acid gas control, dry
sorbent will be injected into the new ductwork between the water quench
chamber and a new fabric filter. Tht flue gas flow rate at the water quench
chamber outlet is 15,500 acfm at 300°F. This temperature reduction is
achieved by adding an additional 5 gpm of water in the water quench chamber.
New equipment for dry sorbent injection includes one sorbent storage silo, a
7-54
-------
pneumatic sorbent transport system, one sorbent feed bin, and a pneumatic
sorbent injection system. Hydrated lime sorbent will be fed at a
calcium-to-acid gas molar ratio of 2:1. At full load, this requires a
sorbent injection rate of 57 Ib/hr. Approximately 6,460 square feet of
fabric filter cloth will be required based on a gross air-to-cloth ratio of
3:1. A new 1.0. fan and 70 feet of new ductwork will also be required.
Figure 7.2-3 shows the location of the equipment. Moderate
access/congestion levels were assumed for the ductwork and fabric filter.
Moderate access/congestion levels were also assumed for the lime receiving,
storage, and conveying equipment. New monitoring equipment for S0?, HC1, and
0» is also included and is located upstream of the sorbent injection area and
also at the outlet of the fabric filter. In addition, an opacity monitor
will be located at the outlet of the fabric filter. Downtime is estimated at
1 month for ductwork tie-ins.
7.2.7.2 Envi ronmental Performance. CDD/COF emissions are expected to
be reduced by 75 percent from inlet levels. Acid gas emission reductions are
80 percent for HC1 and 40 percent for S02, respectively. Emissions of PM are
0.01 gr/dscf. This technology will add 255 tons/year of sorbent and fly ash
to the baseline solid waste disposal requirements,
7.2.7.3 Costs. Capital cost requirements for dry sorbent injection are
presented in Table 7.2-6. Total capital cost is estimated at 11,430,000.
Most of the cost Is associated with new particulate control. This estimate
assumes moderate APCD access/congestion level.
Annual O&M and indirect costs are presented in Table 7.2-7. The major
operating cost is monitoring equipment maintenance. The largest annualized
cost Is annual 1 zed capital recovery and downtime. The total annual 1 zed costs
for the modification are $534,000 per year. Capital and O&M costs are the
same for baseline and good combustion conditions since flue gas flow rate and
acid gas content are the same for each case.
7.2.8 Best Acid Gas Control
7.2.8.1 Description of Modifications. For best acid gas control, a new
spray dryer/fabric filter system will be installed. Lime slurry will be fed
to a single spray dryer at a 2.5:1 molar calcium-to-add gas ratio. Lime
will be slurried in sufficient water to cool the flue gas from 450°F to
7-55
-------
Incinerator
-Loader
New Stack
I.D. Fan
Fabric
Filter
Sorbent
Storage and
Preparation
Area
•Sorbent Injection
L
Water Quench
Chamber
Incinerator
"Header
Building
Figure 7.2-3. Plot Plan of Dry Sorbent Injection/Fabric Filter Retrofit
Equipment Arrangement
aa
§
7-S6
-------
TABLE 7.2-6. PLANT CAPITAL COST FOR DRY SORBENT INJECTION WITH FABRIC FILTER
(Two units of 25 tpd each)
Item
Costs ($1,000)
DIRECT COSTS:
Acid Gas Control
Equipment
Access/Congestion Cost
Particulate and Temperature Control
Equipment
Access/Congestion Cost
New Flue Gas Ducting
Ducting cost
Access/Congestion Cost
Other Equipment
Fan
Stacks
Demolition/relocation
Total
Indirect Costs and Contingencies
Monitoring Equipment3
TOTAL CAPITAL COST
DOWNTIME COST
ANNUALIZED CAPITAL RECOVERY
1S8
16
267
167
14
4
33
59
618
527
286
1,430
19
191
Turnkey.
7-57
-------
TABLE 7,2-7. PLANT ANNUAL COST FOR DRY SORBENT INJECTION
WITH FABRIC FILTER (Two units at 25 tpd each)
Item Costs ($1,000)
DIRECT COSTS:
Operating Labor 39
Supervision 6
Maintenance Labor 16
Maintenance materials 33
Electricity 20
Compressed Air 2
Water 0
Lime . .15
Waste Disposal 6
Monitors 107
Total 244
INDIRECT COSTS:
Overhead 53
Taxes, Insurance, and Administration 46
Capital Recovery and Downtime 191
Total 290
TOTAL ANNUALIZED COST 534
Includes $1,000 for bag replacement.
7-58
-------
300°F. Flue gas flow rate at 300°F is 7,750 acfn. A fabric filter with
6,460 square feet of cloth (gross air-to-cloth ratio of 3:1) will be
installed following- the spray dryer.
This arrangement will require about 100 total feet of new duct, which
will connect the water quench chamber and spray dryer/fabric filter to the
combustor exit and to a new stack. The proposed equipment layout is
illustrated in Figure 7.2-4. This sketch also shows the location of the lime
receiving, storage, and slurry area and the location of the waste storage
silo. Access and congestion levels are assumed to be moderate for the flue
gas ducting, spray dryer/fabric filter and the sorbent preparation and waste
silo. New monitoring equipment for HC1, SO-, 0, will be installed at both
the inlet to the spray dryer and the outlet of the fabric filter. Also, an
opacity monitor will be installed at the outlet of the fabric filter.
Downtime is expected to be 1 month for ductwork tie-ins.
7.2.8.2 Environmental Performance. COD/CDF emissions are expected to-
decrease to 5 ng/dscm. Emissions of particulate matter will be reduced to
0.01 gr/dscf. Acid gases will be reduced 90 percent for S02 and 97 percent
for HC1.
7.2.8.3 Costs. Capital cost requirements for installing a spray
dryer/fabric filter system are presented in Table 7.2-8, Total capital cost
is estimated at $3,320,000 for both baseline and good combustion conditions
and includes purchased equipment, installation, and indirect costs such as
engineering and contingencies. Estimates assume moderate access and
congestion.
Annual O&M and indirect costs are presented in Table 7.2-9. The most
significant annual costs are maintenance materials including bag replacement
and annualized capital recovery and downtime. Total annualized cost of good
acid gas control would be $880,000 per year.
7.2.9 Summary of Control Options
7.2.9.1 Description of Control OptTODS. The control technologies
described in the previous sections have been combined into seven retrofit
emission control options. Table 7.2-10 summarizes the combustion,
particulate, and acid gas control technologies described in Sections 7.2.3
through 7.2.8 that were combined for each of the control options described in
7-59
-------
Incinerator
^" Loader
New Stack
I.D. Fan
Sorbent
Storage and
Preparation
Area
Water Quench
Chamber
Incinerator
• Loader
Building
Figure 7.2-4.
Plot Plan of Spray Dryer/Fabric Filter Retrofit Equipment
Arrangement
*
•3
7-60
-------
TABLE 7.2-8. PLANT CAPITAL COST FOR SPRAY DRYER WITH
FABRIC FILTER (Two units at 25 tpd each)
Item Costs ($1,000)
DIRECT COSTS:
Acid Gas and Participate Control
Equipment 1,430
Access/Congestion Cost 358
New Flue Gas Ducting
Ducting cost 21
Access/Congestion Cost 5
Other Equipment
Fan 35
Stacks 59
Demolition/relocation 0
Total 1,910
Indirect Costs and Contingencies 1,120
Monitoring Equipment3 286
TOTAL CAPITAL COST 2,320
DOWNTIME COST 19
ANNUALIZED CAPITAL RECOVERY 439
aTurnkey.
7-61
-------
TABLE 7.2-9. PLANT ANNUAL COST FOR SPRAY DRYER WITH
FABRIC FILTER (Two units at 25 tpd each)
Item Costs ($1,000)
DIRECT COSTS:
Operating Labor 39
Supervision 6
Maintenance Labor 21
Maintenance materials 42
Electricity 19
Compressed Air -2
Water 0
Lime • 12
Waste Disposal 8
Monitors 107
Total 258
INDIRECT COSTS;
Overhead 62
Taxes, Insurance, and Administration 121
Capital Recovery and Downtime 439
Total . 622
TOTAL ANNUALIZED COST 880
alncludes $5,000 for bag replacement.
7-62
-------
TABLE 7.2-10. SUMURY Of CONTROL OPTIONS FOR SHALL MODULAR STARVED-AIR RECIPROCATING GHATS KWC MODEL PLANT
Combustion Tein»*r»tiir«
Control Option Description Modlf lotloni Control
PtrtlcuUtB Control.
New
Mm ESP F»brlc Filter
Acid 0»» Control
Sorbent
Injection
Spr»jr
Dryer
1. Good Combiutlon Control
2. Good PM Control «nd
Combustion Control
-•I
O»
3. Beat PM Control »nd
Corabuitlon utd
Tcnp>r*tura Control
*. Good Acid G»* Control,
and Beat PM Control und
Tcnp*rature Control
5. Good Acid G«i Control
*nd B»«t PM/Canbmtion/
tur« Control
6. Bait Acid C*a Control,
B«»t PM Control, «nd
tur* Control
7, B«»t Acid C*« Control Uld
B*»t PM/Combuitlon/
loq>«r*tur* Control
-------
Section 3.0. It should be noted that since the model plant achieves good
combustion at baseline, Options 4 and 5 are identical, and Options 6 and 7
are identical.
7.2.9.2 Environmenta] Performance. The performance of each control
option is summarized in Table 7.2-11. For each pollutant the table presents
both the pollutant concentrations and annual emissions. The greatest
reductions in acid gases, particulate matter, and COD/CDF all are achieved
with the spray dryer/fabric filter system. The next most effective control
for all these pollutants is dry sorbent injection. Both sorbent addition
technologies increase the baseline solid waste disposal by about six percent.
Mo combustion modifications-were appropriate. Therefore, CO emissions remain
unchanged, at 100 ppm, for all control options.
7.2.9.3 Costs. The total annualized cost of each option is presented
in Table 7.2-12. The most expensive control option (Option 7) on an
annual ized basis is the spray dryer/fabric filter installation at $1,000,000".
This cost 1s roughly a factor of 8 higher than the cost for Option 1.
Overall, both capital and annualized costs are higher for higher levels of
control.
7.2.9.4 Energy Impacts. Table 7.2-13 summarizes the energy impacts
associated with the control options. The energy use figures are incremental
use. Both the dry sorbent injection with fabric filter and spray dryer with
fabric filter consume the most electricity. There is no increase in
auxiliary fuel use because auxiliary burners are already in place on the
model plant and burn the same amount of fuel under baseline and the other
control options.
7-64
-------
TABLE 7.2*11. ENVIRONMENTAL PERFORHAHCE SIMURY FOR SMALL MODULAR STARVED-AIR
RECIPROCATING GRATE HJC MODEL PLANT RETROFIT COSTRQL OPTIONS*
(Two unit* of 25 tpd each)
Total CDO /CO? Emtnlonj
(na/d»m)
Mg/Tf
I lUduction ir«. BaMlln*
CO Ealsilont
(ppmv)
Mgfjrr
1 Reduction v» . SaMlln*
PH Eol*«Lon*
(«r/d»c£)
Kc/yt
1 Reduction v» . &aa*iln*
SO, Eolation*
2
H»/jr
1 Reduction ft, B*f*lln*
HC1 Eol«»lon»
(ppmv)
Mt/yc
I lUduction v*. BaMlln*
Total Solid Ua*t*
/d*]r)
M»/Yr
X Increa** vs. B»«*lln*
«a*«lU>*
400
2.11-3
—
100
6.2
—
0.15
ia.o
200
29.4
--
500
to. 5
—
15.0
3,690
~~
Option 1
too
2.11-5
0
100
6.2
0
0.15
18.0
0
200
29.4
0
500
40. S
0
15.0
3,690
0
Mod*cat«
too
2.1E-5
0
100
6.2
0
0.08
9.6
47
200
29.4
0
500
40.5
0
15.0
3,690
0.2
Option 2 Option 3 Option 4 Opt loo S Option 6 Option 7
400
2.1E-5
0
100
6.2
0
0.05
6.0
67
200
29.4
0
500
40.5
0
15.1
3,700
0.3
40fl
2.1E-5
0
100
6.2
0
0.01
1.2
93
200
29.4
0
500
tO. 5
0
15.1
3,700
0.5
100
5.3E-6
75
100
6.2
0
0.01
1.2
93
120
17.6
40
100
8.1
80
15.9
3,920
6
100
5.3E-6
75
100
6.2
0
0.01
1.2
93
120
17.6
40
100
B.I
80
15.9
3,920
6
5
2.6E-7
98.6
100
6.2
0
0.01
1.2
93
1»
2.8
90.5
15
1.2
97
16.2
3,990
8
5
2.6E-7
98.6
100
6.2
0
0.01
1.2
9)
19
2. 8
90.5
15
1.2
97
16.2
3.990
a
All f lu> ••* conc«ntr»tlon» mis reported on '»' dry 7 percent O_ bails.
Hsi* •million t»t«» m« for total plant {both coobiutor*).
-------
(Two unlta of 25 cpd «*ch)
Ot
Option 1 Moderate Option 2 Option 3 Option 4 Option 5 Option 6 Option 7
Total Capital Cast
Downtlma Coat
Annual lead Capital and
Down t Ua* Coit
Dlract OW Colt
Total Annual Cent
Facility Dovntlaw
(Hontha)
Co*t Eff«cttv«n«»i
(S/ton HUS)
Total Cofl^plianc4 TISM
(Month*)
'117 697 792 1,120 1,430 1,550 3,320 3,440
0 19 19 19 19 19 19 19
15 94 107 150 191 206 439 454
58 87 89 92 244 302 258 316
124 265 28* 345 534 658 880 1,000
01 111111
9.16 19.60 21.00 25,50 39.40 48.60 65.00 73.90
3 19 19 19 19 19 25 25
All coat* C«c*s»t colt «ff«ct lv«n»«§ ) tlv«n In $1000. All coat* la 0*e>nb*r 1987 doll»r».
coat* lor combustion isodlf Lcttloni .
-------
TABLE 7.2-13. ENERGY IMPACTS FOR SMALL MODULAR STARVED-AIR
COMBUSTOR CONTROL OPTIONS3
Option
1
2
3
4
5
6
7
Electrical Use
(MWh/yr)
0
20.4
27.0
437 ,
437
424
424
Gis Use
(Btu/yr)
0
0
0
0
0
0
0
* Increase from baseline consumption.
7-67
-------
7.3 REFERENCES
Schindler, P., Energy and Environmental Research Corporation, and
Eiranel, T., Radian Corporation. Trip Report - Retrofit Control Sites
Evaluation at the Tuscaloosa Energy Recovery Facility. February 9, 1988.
Epner, E.» Radian Corporation; Landrum, V., and Schindler, P., Energy and
Environmental Research Corporation. Trip Report: Retrofit Control Site
Evaluation at the Waxahachie Solid Waste Recovery Plant. March 8, 1988.
.7-68
-------
8.0 MODULAR EXCESS-AIR COMBUSTORS
The population of modular excess-air municipal waste combustors (MWC's)
consists of 10 facilities. These plants have individual combustor
capacities ranging in size from 8 to 120 tpd. Several manufacturers supply
modular excess-air designs, including Vicon/lnercon, Cadoux, Sigoure Freres,
and 01ivine. The Vicon/Enercon facilities comprise the largest share of the
population in terms of overall capacity (1200 tpd). A complete description
of the Vicon/Enercon design is given in the case study in Section 8.1.
The Cadoux design includes hydraulic forks which load the waste into a
refractory-lined primary chamber where burning takes place on oscillating
grates. Underfire air is supplied beneath the grates. Combustion gases are
burned out in a refractory-lined secondary chamber and then flow to a waste
heat boiler. Temperatures in the secondary chamber reportedly approach
2000°F. Approximately 33 percent of the total air is added beneath the
grate and the remainder is supplied in the secondary post-combustion
chamber. They system reportedly operates at IS percent excess 0-
(approximately 250 percent excess-air) at the boiler outlet. Typical boiler
exit gas temperatures range from 450 to iOO°F.
The Sigoure Freres system is also a two-chamber design. Waste is
burned in the primary chamber on a revolving angular hearth which is covered
by a grate. Ten automatic pokers stoke the burning waste bed on the hearth
as it revolves. Approximately 80 percent of total combustion air is
supplied in the primary chamber as undergrate air and through sidewall
overfire air nozzles. Combustion gases flow to a cyclonic post-combustion
chamber where burnout is completed, and then to a waste heat boiler. The
system reportedly operates at 12 to ,14 percent excess 02 (150 to 200 percent
excess-air).
-------
TABLE 8.0 1. EXISTINC MODULAR EXCESS-AIR COMBUSTORS
tl ant /Location
Sick*. AE
ULlmln«t«. 01
fUyport HAS, FL
Pltt»U«ld. HA
Arooitook, KB
Alexandria, Mi
Paaeagoule, Kt
Clabugrna, IX
Rutland, VT
NottlA»h»ffl, HH
Manufacturer
SL|our« Pr«r«j
V 1 con/ En« rcon
HA"
Vicon/ Enarcon
Oltvlna
Gadou*
Slcour* Fr«r*«
Cadoux
Vlcoa/Entrcon
KA
No. of
Unit!
2
5
1
3
1
1
2
3
2
1
Unit Slca
Ctpd)
12. S
120
*8
120
SO
100
75
38
110
8
V.»r of
Statt-iv
1985
19B7
1978
1981
1982
86
i-itas
1986
1987
1872
Air Pollution
Control Davle*
8«M
El«ctro»tatlc Pnclpltator
Cjclonm
El«ctrl£l«d Ccavvl Bad
Hon«
Elect ro>t*ttc Praclpltator
Elactcoatatlc Pr«clplt«tor
Elaeccoitatle Pr«clpit»tor
El*ctroitatle Pr«clptt»tor
Nona
HA » Information not *vatl*bL«.
09
-------
8.1 INTRODUCTION
This section presents the case study results for a mass burn modular
excess-air MWC. Section 8.1.1 presents a description of the plant located in
Pittsfield, MA, which was visited to gather information for model development.
Section 8.1.2 presents a description of the model plant. Sections 8.1.3
through 8.1.6 detail the retrofit modifications, estimated performance, and
costs associated with each control option. Section 8.1.7 presents a summary
of the control options, which are discussed in more detail in Section 3.0 of
this report.
8.1.1 Description of the Pittsfield. MA Plant1
The Pittsfield waste-to-energy plant began commercial operation in 1981.
The plant handles all the waste generated in the Pittsfield community and
accepts waste from an additional six towns in the surrounding area. The
facility occupies a 5-acre site and has three modular excess air refractory-
wall combustors. Each combustor has a rated capacity of 120 tons of municipal
solid waste (MSW) per day. The combustion system is an Enercon raulti-chamber
design with flue gas recirculation (FGR). Vicon is the licence of Enercon
technology. Figure 8.1-1 illustrates the Pittsfield plant layout, including
the three combustor trains which are integrated with two waste heat boilers.
Two waste heat recovery boilers are used to generate steam for sale to a
nearby paper manufacturer (Crane Company). Cross-connected breechings and
dampers allow operation of any two of the three combustors with the two waste
heat boilers. Air pollutant emissions are controlled by the unique combustion
process and by an electrified granular bed (EGB), supplied by Combustion
Power Company, Inc. Table 8.1-1 presents Pittsfield plant design data.
Waste is delivered to the plant where it can be dumped into a storage
pit or onto a tipping floor. The plant has three days waste storage capacity.
Transfer stations are located at the side of the plant where individuals are
permitted to dump waste. The transfer point allows large haulers to have
priority in accessing the pit and the tipping floor. A crane transfers MSW
from the pit to the tipping floor where a front-end loader charges the
combustors.
8-3
-------
Secondary
Chambers
00
Ash
Removal
Recirculated
UF Air
Primary
Combustion Chambers
Tertiary
Duct
Stacks
EGB's
00
01
Figure 8.1-1. Equipment Train at Pittsfield
-------
TABLE 8.1-1. PITTSFIEIO, MASSACHUSETTS DESIGN DATA
Combustor:
Type
Manufacturer
Number of Combustors
Combustor Unit Capacity
Emission Controls:
Type
Manufacturer
Number of EGB's
Operating Temperature
Particulate Emissions
Gas Flow (each E6B) at
Ga<: Velocity
475°F
Modular Excess-air
Enercon/Vicon
3
120 tpd each
Electrified Granular Bed (EGB)
Combustion Power Co., Inc.
475°F
0.04 gr/dscf at 12% CO-
25,000 acfm c
1.5 to 2,5 ft/s
-------
In addition to burning MSW and commercial waste, the plant also fires 12 tpd
of sludge from the steam customer's pulping operation. The sludge dewatering
press is located in the same building as the waste-fired combustors. The
dtwatered sludge is normally 40 percent moisture by weight (5 dry tpd).
The Pittsfield plant operates two of the waste-fired units on a
24-hour/day, 7-day/week schedule. The third unit is kept on standby.
Complete plant shutdown is scheduled for two weeks every July to coincide
with a scheduled shutdown of the steam customer. The waste-fired plant
reports an average availability of 90 percent (based on two units), with only
8 percent scheduled down time. Most of the scheduled down time occurs during
the summer outage. Each of the boilers is brought off line every 5 months
for a 24-hour scheduled cleaning. A gas/oil-fired boiler is located on site
to handle load swings during normal operation.
8.1.1.1 Combustor Design and Operation. Figure 8.1-2 shows a schematic
of a typical Enercon/Vicon design. A front-end loader delivers waste from
the tipping floor to individual combustor charging hoppers (dimensions 8' by
6' by 5') at a 10-minute charging interval. The waste is charged to the
primary combustion chamber by a hydraulic ram which extends after the top
hopper door closes and the fire door opens. The two operating combustors
(240 tpd combined capacity) normally process a total of 220 to 230 tpd.
Reduced capacities are reported to be due in part to a desire to achieve good
waste burnout. Waste retention time in the primary chamber is approximately
three hours.
The primary combustion chamber is refractory-lined and contains five
hearths. Each hearth is ten feet in length. Figure 8.1-2 shows six hearths,
which is typical of other Enercon/V1con designs. Haste is moved through the
chamber on the stepped hearths by the action of water-cooled transfer rams.
The stroke of the transfer rams is five feet.
The primary chamber contains a number of points of combustion air
injection (discussed below). The temperature in the primary chamber is
nominally maintained at 1800 to 1900°F. There is no additional air injected
into the secondary chamber. The temperature is verified by a thermocouple
located in the secondary chamber. A Thermox continuous 02 analyzer is
located at the exit of the secondary chamber. A signal from the O analyzer
8-6
-------
Flue Gas Recirculaiion Manifold
Overttre FOR Undertwa FOR
Figure 8.1-2. Typical Vicon/Enercon Module.
DC
O
00
00
-------
automatically adjusts the rate of one of the four sources of air in the
primary chamber. Excess 02 levels are maintained at approximately 7 percent
during normal operation by this control loop.
The secondary chamber flue gases from each combustor manifold into a
common tertiary duct where combustion is completed. Recirculated flue gas is
injected into the tertiary chamber as tempering air to control the
temperature of the gases entering the waste heat boilers to 1400°F.
The waste-heat boilers were manufactured by Bigelow. Design steam
production rates per boiler are 33,000 pounds per hour of 180 psig steam at
480°F. No condensate is returned from the steam customer, so water treatment
is necessary for 100 percent make-up water. The flue gases exit the boiler
and enter the flue gas cleaning equipment. The induced draft fan is located
upstream of the flue gas treatment equipment (downstream of the boiler) and
is designed to handle a dirty gas stream.
Combustion Air F1owsandControls. The Enercon design operates in an
excess air mode and employs FGR to maintain desired temperatures and flow
rates. Air flow is controlled in response to signals from temperature and
oxygen readings in various portions of the combustor.
There are four air supplies to the primary combustion chamber:
(1) scavenger air, (2) recirculated underfire (UF) air, (3) clean overfire
(OF) air, and (4) recirculated OF air. Scavenger air is drawn from the pit
and tipping floor and enters the combustion chamber through gaps in the
transfer rams. It provides odor control in the pit area and cooling air for
the transfer rams. The scavenger air is not significantly pressurized.
Recirculated UF air is the main source of UF air on a volume basis. It is
drawn from a point in the stack and supplied through individual ducts beneath
the five hearths. Each of these points of air supply can be individually
controlled by manually-operated dampers.
Clean OF air is supplied through a number of ports at the head of the
primary chamber above the charging hearth. This air is preheated to a
temperature of 150 to 180°F by drawing it through a shroud surrounding the
primary chamber. This type of air preheat system provides control of heat
loss from the primary chamber. The flow rate of the clem OF air is
automatically adjusted in response to a signal from the 02 sensor located at
8-8
-------
the exit of the secondary chamber. This is the only point of oxygen
monitoring in the system. The set point for excess oxygen level is normally
seven percent.
Recirculated flue gas is routed from the ducting at the boiler exit
{prior to flue gas cleaning) and injected through five 8-inch diameter ports
in the roof of the primary chamber. The FGR temperature is typically 400 to
450°F, and the flow rate is automatically adjusted in response to the
temperature in the secondary chamber. This flow rate is modulated to
maintain the desired secondary chamber temperature (1800 to 190Q°F).
Although control of furnace temperature is achieved by varying air and FGR
flow rates, these gas streams are not directly measured. However, under
normal operating conditions the following air flows were reported as measured
during testing:
Recirculated UF air - 1600 scfm
Clean OF air - 8700 scfm
Recircylated OF air - 3000 scfm
Scavenger air was not measured.
As stated above, no additional oxidizer is added in the secondary
combustion chamber. However, an additional supply of FGR (termed "tempering
air") is injected in the tertiary chamber to maintain the desired boiler
inlet temperature (1400°F). The rate of tempering air is controlled based on
the temperature set point at the boiler inlet.
Start-up/Shutdown Procedures. Each combustor has a fuel oil burner
located in the primary combustion chamber which can be used for preheat
during start-up. Under normal operation, MSW is not fired until a
temperature of 1400°F is attained in the secondary combustion chamber.
Generally, wood pallets are charged to the combustor until the required
combustion temperature is achieved, whereupon the operator begins charging
MSW. During a scheduled shutdown, wood is fed to the combustors until MSW is
cleared from the primary chamber. The continuous operation of the combustors
results in few scheduled start-ups and shutdowns.
Residue. The bottom ash drops from the last hearth into a water quench
pit which also serves as a combustor seal. Ash 1s conveyed to a holding bin
by a drag chain conveyer, then hauled to the landfill. Dry weight reduction
8-9
-------
is reported to be 75 percent. Volume reduction 1s reported to be 88 to
90 percent. A limited amount of metal separation takes place prior to
combustion (amounting to approximately 1.5 percent of the waste stream),
8.1.1.2 Emission Control System Design and Operation. Participate
emissions are controlled by two EGB's. According to literature supplied by
the manufacturer to the plant, this is the only MSW facility in the U.S.
using this type of control device. Test results from 1986 show that the EGB
is reducing PH emission rates to about 0.039 gr/dscf corrected to 12 percent
COg. No inlet PH data are available.
The EGB's at Pittsfield are mounted on the roof. Figure 8.1-3 shows a
schematic of an EGB. The EGB consists of a vessel containing two concentric,
louvered cylindrical tubes. The annular space between the tubes is filled
with pea-sized gravel media. Dirty gas enters the EGB through the
side-mounted breeching, is distributed tot he inner cylinder and passes to
the filter media by the plenum section. Flow rates are 25,000 acfm (per EGB)
at 475°F, The gas passes through the filter at velocities of 100 to 150 feet
per minute. Particulate matter is removed from the gas stream by impact with
the gravel media. Clean gas exits to the atmosphere through the stack, which
is mounted on top of the filter unit. Fly ash and gravel are separated in
the de-entrainment zone. Cleaned gravel is readmitted to the main vessel.,
and the fly ash is collected in a bag filter.
Tht filttr media is continuously moved downward at * rate of 6 to
10 feet per hour. This rate is regulated by a media lift blower. This
moving bed of gravel filter media provides the EGB with the capability for
self cleaning, continuous operation. Also, the tumbling action of the filter
media, in contact with the louvers, prevents any bridging or buildup of PM on
the louvers.
The primary collection phenomenon is impaction - both classical
inertia! impaction and electrostatically-assisted impaction. An
electrostatic grid, configures in the form of a cage, is positioned within
the filter media cavity. High voltages applied to the grid produce an
electric field between the grid and the louvers. During normal operation,
voltage is maintained at 32 KV.
8-10
-------
Figure 8.1-3, Electrified Gravel Bed
HIGH VOITM1 MirtCUUTE COLLECTION C8*CSPt
"" f**tfi.«tf Jet
Oy utiliitftQ tfl* -*dfyrdtf v^Jfffle -7"
.finean,
SO to JO irtpu &
-------
The electrostatic field induced between the grid and the louvers raises
the PM collection efficiency due to the fact that small fly ash particles
have a slight positive or negative charge. As the particles migrate through
the filter media, the electrical field either attracts or repels them,
depending on charge. In either case, the particle is propelled towards
pieces of the gravel media for capture by impact ion.
The facility provided a report which assessed the EGB, along with the
possibility of retrofitting the facility with an electrostatic precipitator
(ESP) or fabric filter. This report was prepared by an independent
contractor in response to problems the facility had 1n maintaining EGB
voltages. The report lists two possible reasons for EGB voltage drops.
These are:
• interference in feedback signals caused by variable-speed drives on
the induced draft fans, and
* insufficient size of transformer/rectifier sets to accommodate
larger current flows caused by varying resistivity and
concentrations of fly ash in the bed.
8.1.2 Description of the Model PI ant
8.1-2.1 Combustor Design and Operation. There are several distinct
modular MWC system designs that operate.in an excess-air mode (Enercon/Vicon,
Cadoux, Sigoure Freres). Due to the variance in these designs, no single
model plant can adequately represent all existing facilities. The largest
and most prevalent of the excess?air modular systems is the Enercon/Vicon
design. There are currently three facilities operating in the U.S. using
Enercon/Vicon technology. The model plant represents a typical facility of
this design; model plant data are shown in Table 8.1-2.
The model plant consists of two units, each with a rated capacity of
100 tpd. Both units burn 100 percent municipal solid waste, 24-hours/day,
7-days/week. Each module has both primary and secondary combustion chambers
which manifold into a single tertiary duct where burning is completed prior
to the flue gases entering a waste heat boiler. The boiler reduces the flue
gas temperatures from 1400°F to 450°F before entering the air pollution
control equipment.
8-12
-------
TABLE 8,1-2. MODEL PLANT BASELINE DATA FOR MODULAR EXCESS-AIR COMBUSTOR
Combustor:
Type
Number of Combustors
Combustor Unit Capacity
Plant Capacity
Emission Controls:
Type
Number of ESP's
Number of Fields
Inlet Temperature
Collection Efficiency
Gas Flow
Total Plate Area
SCA at 39,000 acfm and 450°F
Emissions:3
CDO/CDF (tetra-octa)
PM (stack)
CO
HC1
so2
Stack Parameters:
Height
Diameter
Operating Data:
Remaining Plant Life
Annual Operating Hours
Annual Operating Cost
Modular Excess-air
2
100 tpd each
200 tpd
Electrostatic Precipitator
1
450°F
97.5 percent
39,000 acfm
11,500 ft*
295
200 ng/dscm h
0.05 gr/dscf°
50 ppmv
500 ppmv
200 ppmv
70 ft
5.5 ft
> 20-years
8,000 hours
$I,3QO,QOQ/year
§A11 emissions are dry, corrected to 7 percent 02. Standard and Normal
conditions are both 70 F and 1 atmosphere.
'inlet PM emissions to the ESP are 2.0 gr/dscf at 7 percent
-------
Fuel feeding and combustion air supplies are assumed to be identical to
those at Pittsfield, as described above. Excess air levels at the boiler
outlet are assumed to be 50 percent. Flue gas flow rates are approximately
19,100 dscfm at the boiler exit. It is assumed that a CO monitor is in place
along with the 0» monitor at the secondary chamber exit. Temperatures are
measured at the exit of the primary and secondary chambers, and at the boiler
inlet and outlet. An auxiliary fuel burner is located in the primary
combustion chamber for use during process start-up and during episodes of low
temperature.
8.1.2.2 Emission Control SystemDesign and Operation. As previously
mentioned 1n the description of the Pittsfield plant, the EGB control system
is unique amount MSW facilities. As shown in Table 8.0-1, most excess-air
combustors have electrostatic precipitators for particulate matter control.
Therefore, the model plant is equipped with a single 2-field ESP controlling
emissions to 0.05 gr/dscf at 7 percent Og. Since both combustors are ducted
to a single boiler and ESP, a single stack is also assumed. The model plant
ID fan is located downstream of the ESP, since this is more common than the
upstream location used at Pittsfield. A plot plan of the model plant is
shown in Figure 8.1-4.
8.1.2.3 Environmental Baseline. Table 8.1-2 also presents baseline
emissions data for the model plant. Baseline uncontrolled emissions are
established for the model plant using the measured data from a parametric
testing program carried out at Pittsfield. Based on these measured
emissions, baseline uncontrolled CDD/CDF emissions are assumed to be
200 ng/dscm. Uncontrolled emissions of CO are 50 ppmv.
No uncontrolled PM data are available for a facility of this design.
Therefore, a value of 2.0 gr/dscf is assumed for the model by analogy with
other excess-air systems. Uncontrolled HC1 and SO* emissions are assumed to
be 500 ppmv and 200 ppmv, respectively. All emissions are corrected to
7 percent 0*. The combustion process is assumed to reduce incoming waste
90 percent by volume and 70 percent by weight.
It is important to note that this model plant configuration represents
the Enercon/Vicon design, and that other modular excess-air designs are
8-14
-------
Stack
ESP
Tipping Floor
Building
Wall
Combustors
Figure 8.1-4. Plot Plan of Model Plant
§
-------
considerably different in configuration. Thus, baseline emission values
established for the model may not be appropriate for other model excess-air
HWC's.
8-1.3 Good CombustionControl
The model plant has good combustion practices in place. This is
verified by the low uncontrolled levels of CDD/CDF and CO emissions. Under
normal operating conditions the combustor achieves 1800°F, and good mixing is
in place. Honitoring of temperature, oxygen, and CO is also in place. Due
to adequate heat removal through the boiler, the exhaust gas temperature is
4SO°F. As a result, there is no need for further flue gas temperature
reduction prior to the air pollution control equipment, and the potential for
formation of CDD/CDF in the ESP is minimized. Based on this assessment there
are no combustion retrofits required for the model plant.
8.1.4 Best Particulate Control
The ESP in place on the model plant reduces PM by 97.5 percent, from
2.0 gr/dscf to 0.05 gr/dscf corrected to 7 percent Og. Therefore, the
baseline PM emission rate is equal to the rate identified with good control
(0.05 gr/dscf}, and no plant modifications will be required for this control
level.
8.1.4.1 Description of Modifications. To achieve best particulate
matter control (0.01 gr/dscf emission rate) will require an ESP with
16,500 square feet of collection area. Therefore, an additional 5,000 square
feet will be added to the model plant ESP. The additional area will be
installed as a separate single-field ESP in series with the existing ESP.
Fifty feet of new duct and a new ID fan will be required. The existing stack
will continue to be used. A plot plan of the proposed equipment arrangement
is shown in Figure 8.1-5. No new monitoring equipment will be required.
Downtime will affect both combustors at once and is estimated at one month
for ductwork tie-in.
8.1.4.2 Environmental Performance. Particulate matter emissions will be
reduced from 0.05 gr/dscf to 0.01 gr/dscf. The increased fly ash recovery
will add 26 tons per year to the baseline solid waste disposal requirements
for the plant.
8-16
-------
Stack
ESP
Tipping Root
New ESP
^ and ID Fan
Building
Wall
Combustors
Figure 8.1-5. Plot Plan of Particulite Control Equipment
ac
(Zi
91
*
0
15
-------
8'1-4.3 Costs. Capital cost requirements for best participate control
are shown in Table 8.1-3. The major cost item is the participate control
equipment. Total capital requirement is $1,090,000. Annual costs are
presented in Table 8.1-4, and are dominated by annualized capital recovery
and downtime. Total annual costs are expected to be $235,000 per year.
8-1.5 Good Acid Gas Control
8.1.5,1 Description of Modifications. For good acid gas and CDO/CDF
control, hydrated lime sorbent will be injected into the flue gas duct before
the ESP. The lime sorbent will be fed at a molar ratio 2:1 (calcium to acid
gas) for a rate of 227 Ib/hr with both combustors operating. Additional
equipment for sorbent injection will include a sorbent storage silo, a
pneumatic sorbent transfer system, a sorbent feed bin, and pneumatic
injection nozzles. To cool the flue gas from 45Q°F to 350°F, spray nozzles,
also located in : se duct before the ESP, nil introduce 4 gpm of water.
Fifty feet of new duct will be fabricated containing the water and sorbent
nozzles.
A total of 19,000 square feet of ESP collection area will be required to
collect the sorbent and fly ash to an emission level of 0.01 gr/dscf.
Therefore, an additional 7,500 square feet of collection area will be added
to the model plant ESP. The additional area will be.installed as a separate
single-field ESP in series with the existing ESP. Installation of the new
ESP will also require 50 feet of new duct and a new ID fan. The proposed
equipment arrangement is shown in Figure 8.1-6. New monitoring equipment for
SOg, HC1, 02 and CQj is also included. Downtime is estimated at one month.
8.1.5.2 Environmental Performance. COD/CDF emissions are expected to
be reduced to 25 percent of inlet levels or to 50 ng/dscm, whichever is
greater. Add gas emission reductions are expected to be 80 percent for HC1
and 40 percent for SO-. Particulate matter emissions will be reduced to
0.01 gr/dscf. Additional collected fly ash and sorbent will add 1190 tons per
year of solid waste to the baseline disposal requirements for the plant.
8.1.5.3 Costs. Capital cost requirements for dry sorbent injection are
presented In Table 8.1-5. Total capital cost is $2,070,000. Most of the
cost is associated with new equipment for particulate and temperature
control. A moderate access and congestion level 1s assumed for all equipment
except the duct containing the spray nozzles. Since this duct passes through
8-18
-------
TABLE 8.1-3. PLANT CAPITAL COST FOR PARTICULATE MATTER CONTROLS
(Two units of 100 tpd each)
Item Cost ($1000)
DIRECT COSTS;
PM Control3
Upgrade Costs 587
Access/Congestion Cost 147
New Flue Gas Ducting1
Ducting Costs 15
Access/Congestion Cost 4
Other Equipment
Fan 74
Stack 0
Demolition/Relocation 0
Total 827
Indirect Costs and Contingencies 267
Monitoring Equipment 0
TOTAL CAPITAL COST 1,090
DOWNTIME COST 205
ANNUALIZED CAPITAL RECOVERY AND DOWNTIME 171
aBased on moderate access/congestion.
8-19
-------
TABLE 8.1-4. PLANT ANNUAL COST FOR PARTICULATE HATTER CONTROLS
(Two units of 100 tpd each)
Item Cost ($1000)
DIRECT COSTS:
Operating Labor 0
Supervision 0
Maintenance Labor 0
Maintenance Materials 10
Electricity 3
Waste Disposal 1
Monitors 0
Total 14
INDIRECT COSTS:
Overhead 6
Taxes, Insurance, and
Administration 44
Capital Recovery and Downtime 171
Total 221
TOTAL ANNUAL1ZED COST 235
8-20
-------
Stack
ESP
New ESP
^ and ID Fan
Sorbent
.Storage
r New Duct
with Nozzsls
Tipping Floor
Building
Wall
Combustors
Figure 8.1-6. Plot Plan of Dry Sorbent Injection Equipment Arrangement
x
•si
71
a-2i
-------
TABLE 8.1-5. PLANT CAPITAL COST FOR DRY SQRBENT INJECTION
WITH ADDITIONAL ESP COLLECTION AREA
(Two units of 100 tpd each)
Item Cost ($1000)
DIRECT COSTS:
Acid Gas Control3
Equipment 189
Access/Congestion Cost 19
Particulate and Temperature Control
Equipment 785
Access/Congestion Cost 160
New Flue Gas Ducting3
Ducting Cost 31
Access/Congestion Costs 11
Other Equipment
Fans 68
Stacks 0
Demolition/Relocation 0
Total 1,260
Indirect Costs and Contingencies 545
Monitoring Equipment0 257
TOTAL CAPITAL COST 2,070
DOWNTIME COST 205
ANNUALIZED CAPITAL RECOVERY AND DOWNTIME 299
aBased on moderate access/congestion.
Based on high access/congestion for temperature control ductwork.
cTurnkey.
8-22
-------
the building wall, a high access/congestion factor was applied to the direct
cost.
Annual costs are presented in Table 8.1-6. The major operating costs
are for lime purchase and monitoring equipment maintenance. The largest
annual cost is annualized capital recovery and downtime. Total annual cost
is estimated to be $705,000.
8-1.6 Best Acid Gas Control
8.1.6.1 Descript1on of Hodif i cations. To achieve greater reductions in
COO/CDF, HC1, and S02, a spray dryer/fabric filter system will be installed.
The existing ESP will not be demolished, but will be bypassed and left in
place. A total of 100 feet of new duct will be used to connect the new
equipment between the boiler outlet and the existing stack. The proposed
equipment arrangement is shown in Figure 8.1-7.
Lime slurry will be.introduced into the spray dryer at a calcium-to-acid
gas molar ratio of 2.5:1. Water in the lime slurry equivalent to 6 gpm is
needed to cool the gas stream from 450°F to 3QO°F.
The lime receiving, storage and slurry preparation area is also shown in
Figure 8.1-7. The fabric filter will have 11,300 square feet of cloth arsa
(net air-to-cloth ratio of 4:1). The increased pressure drop of the fabric
filter relative to the existing ESP will require replacement of the ID fan,
New monitoring equipment for HC1, SCL, CO^, 0, and opacity will be installed,
Downtime is expected to be one month for ductwork tie-ins.
8-1-6,2 Environmental Performance. CDD/CDF emission reduction of
99 percent or to 5 ng/dscm (whichever gives higher emissions) is expected.
Emissions of particulate matter will be reduced to 0.01 gr/dscf. Acid gas
emissions will be reduced 90 percent for SO, and 97 percent for HC1.
8.1.6.3 Costs. Capital costs for installing a spray dryer/fabric
filter system are shown in Table 8.1-7. Total capital cost is 54,720,000.
The major capital cost is for the purchased equipment. A moderate
access/congestion factor was applied to all direct equipment costs. Annual
costs are shown in Table 8.1-8. The largest annual costs are for
maintenance materials, including bag replacement, and annualized capital
recovery and downtime. Maintenance cost for process monitors is also
significant. Total annual cost is estimated at $1,320,000 per year.
fi-23
-------
TABLE 8.1-6. PLANT ANNUAL COST FOR DRY SORBENT INJECTION WITH
ADDITIONAL ESP COLLECTION AREA
(Two units of 100 tpd each)
Item Cost ($1000)
DIRECT COSTS:
Operating Labor 30
Supervision 5
Maintenance Labor 20
Maintenance Materials 14
Electricity 15
Water • 1
Lime 72
Waste Disposal 30
Monitors 103
Total 290
INDIRECT COSTS:
Overhead 44
Taxes, Insurance, and
Administration
Capital Recovery and Downtime
Total
TOTAL ANNUAUZED COST 705
8-24
-------
Sorbent
Preparation
and Storage
> New Spray Dryer,
Fabric Filter and ID Fan
Building
Wall
Combustors
Tipping Roor
Figure 8.1-7. Plot Plan of Spray Dryer/Fabric Filter Retrofit Equipment
Arrangement
-------
TABLE 8.1-7. PLANT CAPITAL COST FOR SPRAY DRYER WITH FABRIC FILTER
(Two units of 100 tpd each)
Item Cost ($1000)
DIRECT COSTS:
Acid Gas Control
Equipment 2,130
Access/Congestion Cost 533
New Flue Gas Ducting
Ducting Cost 30
Access/Congestion Cost 8
Other Equipment
Fans 74
Stacks 0
Demolition/Relocation 0
Total 2,780
Indirect Costs 917
Contingency 739
Monitoring Equipment3 • 286
TOTAL CAPITAL COST 4,720
OOHNTIHI COST 205
ANNUALIZED CAPITAL RECOVERY AND DOWNTIME 648
aTurnkey.
8-26
-------
TABLE 8.1-8. PLANT ANNUAL COST FOR SPRAY DRYER WITH FABRIC FILTER
(Two units of 100 tpd each)
Item Cost ($1000)
DIRECT COSTS:
Operating Labor
Supervision
Maintenance Labor
Maintenance Materials
Electricity
Compressed Air
Water
Lime
Waste Disposal
Monitors
Total
INDIRECT COSTS:
Overhead 82
Taxes, Insurance, and
Administration
Capital Recovery and Downtime
Total
TOTAL ANNUALIZEO COST 1,320
'includes bag replacement costs of $11,000.
8-27
-------
8.1.7 Summary of Control Options
8.1.7.1 Description of Control^Costs. The control technologies
described in the previous sections have been combined into seven retrofit
emission control options. Table 8.1-9 summarizes the combustion,
particulate, temperature, and acid gas control technologies described in
Sections 8.1.3 through 8.1.6 that were combined for each of the control
options described in Section 3.0.
It should be noted that since the model plant already achieves moderate
PH control at baseline, Options 1 and 2 are identical. Also, since the model
plant achieves good combustion at baseline, Options 1 and 2 are equivalent to
baseline, Options 4' and 5 are identical, and Options 6 and 7 are identical.
8.1.7.2 Environmental Performance. The performance of each control
option is summarized in Table 8.1-10. For each pollutant, the table presents
both the pollutant concentrations and emissions. The greatest emission
reductions of acid gases, particulate matter, and CDO/CDF all are achieved
with the spray dryer/fabric filter system. The next most effective control
for all these pollutants is dry sorbent injection. Both sorbent addition
technologies increase solid waste slightly (less than 10 percent over
baseline). No combustion modifications were made, so CO emissions remain
unchanged at SO ppm for all options.
8.1.7.3 Costs. The total annualized cost of each option is presented
in Table 8.1-11. The most costly control option is the spray dryer/fabric
filter installation, at a capital cost of $4,720,000. Overall, costs are
higher for higher levels of control, and are roughly double the cost of the
previous control option.
8.1.7.4 Energy Impacts. Table 8.1-12 presents a summary of the energy
impacts associated with the control options. The energy use figures are
incremental use; savings realized by not operating the existing ESP are taken
into account. There is no increase in auxiliary fuel use because auxiliary
burners are already in place on-the model plant and are used under baseline
operation.
8-28
-------
TABLE 8.1-9. StXMARY OF OOHTROL OPTIONS K» MDDCljW EXCESS-AIR COMBUSTOR
Control Option D«*crlptlon
Acid CM Control
Combuatlon Teicp«tatur« Enticing ESP
Modification* Control Kcbullt
Additional
Plant Ax«a
Hew Soctwnt Spr«y
Fabric Filter Injectlou Dryer
1. Good Combuiclon »nd
T«itfi>ratur> Control
2. Good PM Control with
Combuitlon Control
Beat PM Control Mid
Combiutlon mat
Control
VI
O
*. Good Acid C»» Control,
B««t PM Control and
T«tn>«r«tur« Control
5. Good Acid C*s Control
•nd Bast PM/Combu»tlon/
T«(n>er»cure Control
6. B«it Acid C»i Control,
B«»c PM Control, »nd
T«af>«r*cur« Control
7. B*it Acid G»« Control *nd
B«*t PM/Cocnbuitlon/
Control
-------
CO
I
TABLE 8.1-10. EKVIROHMEHTAL PERFORMANCE SUMUOT FOR MODULAR EXCESS-AIR
HWC HOOEL PUNT RETROFIT OOHTRDL OPTIONS*
(Two unit* of 100 tpd
Total CDD/CDF Emliilotu
(ng/dicm)
Hi/rr
X Reduction vl. B»*elLn*
CO Emission*
(pprav)
H8/»r
X Reduction v» . Baaelln*
PM Emissions
(»r), Baseline
SO. Emissions
d»y)
Hs/jrr
X Increase vs. Baaellne
Baseline
200
5.21-5
-*
50
16.2
~-
0.05
29. 8
—
200
1*8
-—
500
212
—
60
18,200
"
Option 1
200
5.2E-J
0
50
16.2
0
O.05
29,8
0
200
1*8
0
500
212
0
60
18,200
0
Ope loo 2
200
5.2E-5
0
50
16.2
0
O.05
29.8
0
200
1*8
0
500
212
0
60
18,200
0
Option 1
200
5.2E-S
0
50
16.2
0
ft. 01
6.0
BO
200
1*8
0
500
212
0
60
18,200
0
Option * Option 5 Option 6 Option ?
50
1.3E-5
75
SO
16.2
0
O.O1
6.0
80
12D
89
40
100
'42
•0
6*
19,300
6
SO
1.3E-S
75
50
16.2
0
O.O1
6.O
80
120
89
40"
100
42
80
64
19,300
6
5
1.3E-6
98
50
16.2
0
0.01
6.0
80
J9
1*
90.5
IS
6
97
6S
19,600
8
5
1.3E-6
98
50
16.2
0
0.01
6.0
80
19
i*
90.5
15
6
97
65
19,600
a
All flu* 1*1 concentrmtlonj *r« repotted on * drjr 7 percent 0 bull. Standard and normal condition*
are both 1 atMsphar* and 70 F.
-------
TABLE 8.1-11. COST SUMMARY FOR MODULAR EXCESS-AIR MUG MODEL. PLANT RETROFIT CONTROL OPTIONS
(Two unit* of 100 tp4 each)
U»
Option 1 Option 2 Option 1 Option » Option S Option £ Option 7
local Capital Coit
Downtime Coat
Annual lied Capital and
Downtime Colt
Dlr«ct OIK Coit
Total Annual Coat
Cose Ef fecliveneii
-------
TABLE 8.1-12. ENERGY IMPACTS FOR MODULAR EXCESS-AIR COMBUSTOR
MODEL PLANT CONTROL OPTIONS3
Option
1
2
3
4
5
6
7
Electrical Use
(MWh/yr)
0
0
60
334
334
h
1,030°
l,030b
Gas Use
(Btu/yr)
0
0
0
0
0
0
0
alncrease from baseline consumption.
Excludes the electrical credit of not operating the ESP's.
8-32
-------
8.2 REFERENCES
1. Epner, E.» Radian Corporation, and Schindler, P., Energy and
Environmental Research Corporation. Trip report - Retrofit Control Site
Evaluation at the Pittsfield Waste to Energy Facility. March 31, 1988.
8-33
-------
9.0 ROTARY WATERWALL COMBUSTORS
The O'Connor rotary water-wall combustion system is one of the more
unique designs in the existing population of MWC's. There are currently
three operating plants using the O'Connor design. Table 9,0-1 lists these
plants along with number of combustors, unit size, start-up date, and air
pollution control device. Individual plants are comprised of two combustors
ranging in unit capacity from 100 to 255 tpd. Additional O'Connor-design
plants are in planning, permitting, or construction stages in York County,
PA; Delaware County, PA; Lubbock, TX; and Hercer County, NJ.
9.1 INTRODUCTION
This section presents the retrofit case study results for a mass burn
rotary waterwall municipal waste combustor (MWC). Table 9.0-1 lists the
three existing plants in this subcategory. Section 9.1..1 presents a
description of the Bay County MWC plant, which was visited in order to
gather information for model development. Section 9.1.2 presents a
description of the model plant. Sections 9.1.3 through 9.1.7 detail the
retrofit modifications, estimated performance, and costs associated with
various control options, which are discussed in more detail in Section 3.0
of this report.
9.1.1 Descriptionof the Bav County. FL Plant
The Bay County Resource Management Facility consists of two
Westinghouse - O'Connor rotary waterwall combustors designed to mass burn up
to 255 tpd of MSU (total plant capacity 510 tpd). The combustors can also
burn wood waste or a mixture of NSW and wood waste. Heat generated by
combustion produces steam to drive a turbine generator. Design data are
presented in Table 9.1-1, and a process flow diagram of the Bay County
facility is shown in Figure 9.1-1. The facility is owned by New England
Trust Company, leased by Bay County and operated (under a 25-year contract)
by Westinghouse, Generated electricity is sold to Gulf Power at an average
of 2.074 cents per kwh. The facility charges a tipping fee of $22 per ton
and disposes of ash at the county-owned landfill at no direct charge. Waste
disposal costs $3.72 per ton for contract hauling by truck to the landfill.
9-1
-------
TABLE 9.0-1. EXISTING ROTARY WATERWALL COHBUSTORS
No. of Unit Size Year of A1r Pollution
Plant/Location Units (tpd) Start-up Control Device
Bay County, FL 2 255 1987 ESP
Poughkeipsie, NY 2 253 1987 Fabric Filter
Gallatin, TN 2 100 1981 ESP
9-2
-------
TABLE 9.1-1. BAY COUNTY, FLORIDA DESIGN DATA
Furnaces:
Number
Capacity
Furnace Dimensions
Emission Controls:
Numbers
Type
Gas Flow
Collection Area
SCA
Dimensions
Length
Width
Height
Gas Velocity
Inlet Concentration
Exit Concentration
- 2
255 tpd
Each combustor consists of a
tapered barrel 10 feet in
diameter and 40 feet long.
- 2 (one for each furnace)
- 3-field ESP
- 56,000 acftn at 400°F each
- 18J10,ftz each
- 350 fr/1000 acfm
- 30 ft
- 18 ft
- 24 ft
- 4 ft/sec
-2.0 gr/dscf at 12% CO-
-0.02 gr/dscf at 12% C0
Generating Capacity:
Steam (each boiler)
Electricity (site total)
68,800 Ib/hr at 600 psi,
750°F
11.5 m
9-3
-------
31=..
^ &• M
*|y J p
r t
5J i;
JL>i *
^*
i
u
o
M V
« I
U 01
o ei
u i*
O)
52
II
9-4
-------
Construction of the facility began in November 1985, and waste was
first burned in February 1987. Start-up testing in May 1987, demonstrated
contractual commitments of burning 510 tpd, generating 11.5 MM gross
electric power output, and leaving less than 11 percent combustibles in the
ash. The facility employs 35 people and has operated on a 24-hour/day,
7-day/week schedule since commercial start-up in May 1987. To maintain this
schedule, the facility frequently burns wood waste (bark or sawdust) in one
combustor, and MSW or a mixture of MSW and wood in the other combustor. The
average heating value of MSW is 4,500 to 5,000 Btu/lb. However, the
estimated heating value of the mixed fuel is 3,800 to 4,000 Btu/lb due to
the high moisture content of the wood, which has an average heating value of
3,000 to 3,500 Btu/lb. Wood is purchased for an average of $10 per ton.
The MSW supply is seasonal in Bay County, which is a resort area, but even
in the peak summer season the MSW supply has not yet met plant capacity. In
the winter, the plant typically burns 250 tpd MSW, 50 tpd commercial waste
and trash, and 210 tpd wood waste. In the summer, the feed is 380 tpd MSW,
50 tpd commercial waste and trash, and 80 tpd wood waste. Westinghouse is
currently seeking out-of-county waste to replace some of the wood fuel.
9.1.1.1 Combustor Design andOperation. Waste is delivered to the
plant and dumped on the tipping floor, which accommodates about 1,500 tons
of waste. The waste is then sorted to remove large objects, mixed
thoroughly, and pushed onto one of two horizontal apron conveyors by a
front-end loader. A shear shredder is available for shredding large
combustible items, but is not often used. About 3 percent of the waste is
rejected as non-combustible and delivered intact to the landfill.
Each horizontal apron conveyor transfers waste feed onto separate
parallel inclined conveyors which contain weigh scales to continuously
measure the weight of waste being delivered to the charging hopper. One
additional horizontal conveyor is located at the charging hopper level to
allow waste from one conveyor line to be sent to an adjacent combustor.
Therefore, both combustors can be supplied from one conveyor line in the
event that the parallel line is down for maintenance. From the charge
chute, MSW is pushed into the combustor by dual hydraulic ram feeders. The
ram speed is adjusted by the computerized combustion control system, but the
9-5
-------
time to complete a stroke is usually 3.5 minutes. The Bay County rotary
drum (barrel) sits at a 6° angle from the horizontal and is tapered over the
final 4 feet. The Bay County units are the only O'Connor facilities that
use a tapered barrel. The combustor barrel rotates slowly {3 to 7 rph)
causing the waste to tumble and advance as it burns. At the typical rotation
speed of 5 rph, the waste remains in the combustor for approximately
30 minutes. The ram speed and the rotation speed are automatically adjusted
to maintain constant bed profile. This practice is designed to maximize
waste burnout at the barrel exit. The combustor barrel is 10 feet in
diameter, 40 feet long, and is constructed of steel tubes and perforated
webs (see Figure 9.1-2). The tubes direct cooling water through the outside
wall of the combustor barrel and to the boiler, and thus, the rotary portion
is considered an integral part of the boiler radiant section. The combustor
barrel protrudes approximately 5 feet into the boiler. Bottom ash is
discharged from the rotary combustor onto a stationary after-burning grate
and then into the wet quench pit.
A forced-draft fan draws combustion air from the tipping area. This
air is preheated to 450°F and then enters a multiple-zone windbox beneath
the combustor barrel. Westinghouse defines underfire air and overfire air
differently from the classic mass-fired system. The three plenums are
separated laterally into two sections each (3x2 arrangement). The rotation
of the drum dictates the location of the fuel bed. Air supplied through the
three windboxes beneath the fuel bed is designated underfire air, and the
air directed through the adjacent three windboxes is overfire air.
Figure 9.1-2 shows the cross-section of the rotary combustor and the flow of
overfire and underfire air. The air supplied to the rotary combustor is
distributed to the three wi/idboxes as 40, 40 and 20 percent, front to rear.
In the first and second windbox section the overfire/under ft re air ratio is
40/60. In the third section the ratio is 50/50. These splits are reported
as estimated normal operating conditions, and they are adjustable. Under
normal operating conditions, 80 percent of the total air is delivered to the
rotary combustor. Five percent of the total air is supplied below the
afterburning grate. The remaining 15 percent of the total air is drawn from
9-6
-------
SHROUD
WEBS
SUPPORT
DETAIL »A'
STRIP
SEAL
WATtR-
COOLED
TUBES
WATER
FLOW
WEB
Figure 9.1-2. Cross-Stctlon of the itestlnghousi O'Connor Mitsr-Coolfid
Rotary Combustor
9-7
-------
the duct supplying the rotary combustor and delivered as tertiary air
through overfire air. nozzles. Two rows of opposed 2-1/2 Inch diameter
overfire air nozzles are located on the front and rear walls of the boiler
approximately 10 feet above the rotary combustor. There are 34 nozzles on
each wall.
The waste feed rate is maintained by the Westinghouse computer
controller, but the setpoint can be adjusted by the operator based on fuel
characteristics. The combustion air flow is also controlled automatically
to maintain desired steam flows. The air flow rate to the drying zone is
based on the combustor inlet temperatures. Air flows to the combustion and
burnout zones control firing rates and are based on the exit gas oxygen
content. Ram speed and combustor rotation are adjusted to maintain the exit
gas conditions at 1400°F and 5.0 to 5.7 percent Q* (wet).
The Bay County facility is equipped with a recuperative tubular air
heater. To protect against corrosion in the air heater, a steam preheater
is located at the air inlet to increase the temperature from ambient to
150°F. The steam drums of each boiler are connected by piping so that steam
generated in one unit can be distributed to the adjacent boiler to aid in
preheating the heat recovery equipment during process start up. Therefore,
if outages are scheduled independently, the boiler that is down can be
preheated to 300°F by steam from the operating unit, shortening the time
required to come up to full operating load.
The flue gases exit the air heater and are pulled through the
electrostatic precipitator (ESP) by an induced-draft fan before exiting the
stack. The stack is precast concrete with two 4-ft, 6-in. diameter flues
constructed of 4-inch acid brick. The stack is 125 feet tall and has
monitoring ports 60 feet above the base. In addition to continuous oxygen
monitors located at the boiler exits, the plant also operates opacity and CO
monitors downstream of the ESP's.
Each boiler is designed to produce 68,800 Ib/hr of 600 psi, 750°F
super-heated steam. The steam flows to a multiple extraction condensing
turbine generator which produces about 11.5 HW of 3-phase, Hz electrical
power for distribution to the utility grid. Transformers provide power at
reduced voltage for plant use. Turbine exhaust steam is condensed in a
9-8
-------
shell and tube heat exchanger that is cooled by an external cooling tower
using 200,000 gpd well water. Steam condensate is pumped back to the boiler
through feedwater heaters and a deaerator.
As stated previously, bottom ash leaves the combustor barrel via a
steeply inclined burnout grate, and drops into a wet quench pit. The bottom
ash is removed from the quench pit by dual drag chain conveyors which dump
the wet ash into waiting trucks for transportation to the landfill.
Discharge chutes are adjustable to allow all the ash from both combustors to
be delivered to one of the removal systems. Fly ash collected in the boiler
and ESP is pneumatically conveyed to the quench pit for disposal. Siftings
collected on a conveyor beneath the combustor are also added to the quench
pit. Total ash combustibles are normally 11 percent by weight. An average
of 150 tpd wet ash (11 truckloads) is hauled to the county landfill. The
county-owned landfill is a lined mono-cell facility with leachate collection
located on a 155-acre site approximately 39 miles from the incinerator site.
Auxiliary fuel oil burners are available to preheat the combustor to
400 F, but are only used if both combustors have been down. Normally, steam
from an operating boiler is used to preheat the adjacent cold boiler. One
fuel oil burner is located in the combustor and used to ignite the waste.
Two others are located in the walls of the boiler radiant section.
During the visit it was noted that boiler operating temperatures were
higher than design, and particulate carryover from the discharge of the
rotary combustor seemed relatively high. The units were operating on wood
waste during the visit.
Bay County is the second facility in the U.S. to burn MSW in the
O'Connor combustor, and the first to be constructed by Westinghouse. The
first plant to use the O'Connor technology is located in Gal latin, TN.
Performance tests executed at Gall atin have provided information leading to
some design changes in subsequent O'Connor systems. As an example, CO
profiling tests performed at Gallatfn demonstrated the need for overfire air
above the rotary combustor exit, as well as the need for some air to be
supplied to the burnout grate below the barrel. These air sources, which
were once eliminated at Gallatin, were shown to be necessary and were
reinstituted in the design. However, the design configuration at Bay County
9-9
-------
was established prior to completion of all the performance evaluations at
Gal latin. For example, the Gallatin tests were instrumental 1n changing the
design of the barrel such that the rotary section will not protrude as far
into the radiant section of the boiler in the future designs, thus
eliminating the increased potential for unmixed pockets of combustion gases
below the extended rotary sections.
9.1.1.2 Emission Control System Design and Operation. Flue gases
from each combustor exit the gas heater and enter a 3-field ESP. Each field
has an electrical set and ash hopper. The ESP's are the rigid frame type
with plate dimensions of 24 feet high by 9 feet long, with 1/2 inch diameter
•j
pipe electrodes. Total collection area for each ESP is 19,710 ft and the
design gas flow rate for each is 56,000 acfm at 400°F (SCA - 350 ft2/1000
acfm). Actual ESP inlet temperature is approximately 450°F at full rate.
The ESP's were designed to meet the Florida Department of Environmental
Regulation emission limit of 0.03 gr/dscf at 12 percent ML. Compliance
tests for the facility have shown actual emissions of 0.02 gr/dscf and inlet
loadings of approximately 2.0 gr/dscf. Opacity is in compliance as well, at
less than 10 percent. Table 9.1-2 summarizes recent compliance test results
and gaseous emission tests used to support the plant's PSD permit
application.
9.1.2 Description of Model Plant
9.1.2.1 Combustor Design and Operation. There are three existing
MWC's which use the O'Connor rotary waterwall technology (Gallatin, Bay
County, and Dutchess County, NY). Gallatin began operating in 1981, using
two 100-tpd cojjibustors. Bay County began operating in 1987, using two
25S-tpd units. Dutchess County started operating in 1988, using two 253-tpd
combustion units. In an attempt to configure the model plant to represent
the existing population, two 250-tpd units were selected for the model.
(Model plant design data are summarized in Table 9.1-3.) with the exception
of Gallatin, the facilities have state-of-the-art automatic combustion
control systems and auxiliary fuel firing capacity. In addition, the newer
facilities use rows of high pressure tertiary air nozzles to complete the
mixing process in the radiation section of the boiler. As described in the
preceding section, the Gallatin plant has added a similar set of nozzles
9-10
-------
TABLE 9.1-2. BAY COUNTY, FLORIDA EMISSIONS SUMMARY*
Part icul ate Matter
(gr/dscf)
(dry pprnv)
NO
(dry ppmv)
HC1
(dry ppmv)
CO
(dry ppmv)
COO/CDF
Permitted Values
0.03
(10% opacity)
NA
NA
NA
NA
NA
Unit 1
0.019
133
NA
428
NA
NA
Unit 2
0.024
84
169
508
68
NA
All values corrected to 12% CO, basis except CO, which is on 7% 0* basis,
COD/CDF data were measured, but have not yet been reported.
9-11
-------
TABLE 9.1-3. MODEL PLANT BASELINE DATA FOR ROTARY WATERWALL COMBUSTOR
Combustors:
Type
Manufacturer
Number of Combustors
Combustor Unit Capacity
Plant Capacity
Emission Controls:
Type
Number
Number of Fields
Inlet Temperature
Collection Efficiency
Gas Flow
Total Plate Area
SCA at 47,000 acfm and 450°F
Emissions:3
COO/CDF (tetra-octa)
PM (stack)
CO
HC1
S02
Stack Parameters:
Height
Diameter
Operating Data:
Remaining Plant Life
Annual Operating Hours
Annual Operating Cost
Rotary Waterwall
Westinghouse/0'Connor
2
250 tpd each
500 tpd
Electrostatic Precipitator
2 (one per combustor)
3 each
4508F
98.5 percent
49,000 acfm each
16,300 ft* each
335
2000 ng/dscmh
0.03 gr/dscfD
100 pprnv
500 ppmv
200 ppmv
125 feet
4 feet (per flue)
> 20 years
8,000 hours
$5,720,000/year
aAll emissions are dry, corrected to 7 percent 0-. Standard and normal
conditions are both 70 F and 1 atmosphere,
blnlet PH emissions to the ESP are 2.0 gr/dscf at 7 percent 0.
9-12
-------
which are an essential component of good combustion practice. Because the
majority of existing, plants have these design features, is is appropriate to
include them in the model. It is assumed that tht distribution of
combustion air in the model plant is the same as that reported for the Bay
County facility, with 80 percent of the total air delivered to the rotary
combustor, 15 percent injected through the tertiary nozzles, and 5 percent
supplied to the burnout grate,
"he model plant is assumed to operate on a 24-hr/day, 7-day/week
schedule, burning 100 percent MSU. The basic plant configuration is assumed
to be similar to Bay County, including ram feeders, three underfire air
plenum sections along the length of the rotary combustor, and one row of
tertiary air nozzles on each of the front and rear walls in the radiation
section of the boiler above the discharge of the rotary combustor. A
burnout grate is located at the exit of the rotary combustor, and the bottom.
ash is discharged into a water quench pit.
The O'Connor combustion system typically operates in the range of
25 to 75 percent excess air. An average value of 50 percent excess air is
assumed for the model plant. At SO percent excess air, total flue gas flow
rate exiting the heat recovery equipment is approximately 23,900 dscfm per
unit. Based on the available information for Gall atin and Bay County, the
flue gas temperatures at the economizer outlet typically range from
350 to 450°F. A value of 450°F is selected for the model plant.
Continuous monitors are in place to verify combustor flue gas oxygen
levels and temperatures. It is assumed that CO monitors are in place at the
model plant.
As discussed in Section 9.1.1.1, the Bay County facility is the only
operating plant that uses a tapered barrel. In addition, at Bay County the
rotary combustor protrudes into the radiation section of the boiler. This
has been shown to result in dead zones where mixing 1s prevented and higher
CO measurements are observed. Bay County is also the only existing facility
to use an extended barrel. Therefore, the assumed configuration of the
model plant does not include the tapered, extended barrel.
9-13
-------
9.1.2.2 Emission Control jystem Desjgn and Operation. The Bay
County plant has 3-fjeld ESP's that reduce PM emissions to 0.02 gr/dscf from
2.0 gr/dscf, but measured emissions at Gallatin and expected emissions from
plants currently under construction are higher. Therefore, the model plant
is assumed to have two 3-f!eld ESP's that reduce PM emission to 0.03 gr/dscf
(corrected to 7 percent O-.) The Bay County single stack with two flues
will be retained for the model plant. Stack parameters are presented in
Table 9,1-3, and a plot plan of the model plant is shown in Figure 9.1-3.
9.1.2.3 Environmental Baseline. Table 9.1-3 also presents baseline
emissions data for the plant. All baseline emissions are presented
corrected to 7 percent 0.. Bay County and Gallatin both have reported data
for all the pollutants of concern, with the exception of CDD/CDF. Baseline
particulate emissions ire estimated to be 2 gr/dscf) at the inlet to the
ESP. This is typical of a conventional mass burn water-wall facility. The
measured CO values at Bay County are reported to vary from 50 to 100 pprnv.
A baseline value of 100 ppmv is assumed for the model plant. Based on
calculations of jet penetration, it is determined that the existing tertiary
air system is not adequate to provide the required coverage and penetration
of the furnace cross section. As a result, relatively large quantities of
fuel-rich gases escape the combustor without being mixed. When combined
with an uncontrolled particulate emission rate of 2 gr/dscf, there is
potential for extensive catalytic reaction of the organics to form COO/CDF.
As such, baseline uncontrolled tetra through octa COO/CDF emissions are
.established at 2,000 ng/dson. As with the other mass burn models, uncon-
trolled HC1 and SO. emissions are assumed to be 500 ppmv and 200 ppmv
respectively. The combustors are assumed to achieve 90 percent waste volume
reduction and 70 percent weight reduction.
9.1.3 Good Combustion
9.1.3.1 Description of Modifications. Modification to the existing
overfire (tertiary) air nozzles is required in order to achieve the proper
mixing through penetration and coverage of the furnace cross section. A
properly designed and operated tertiary air supply will ensure that the
combustion gases are thoroughly mixed and that COO/CDF emissions art
minimized. In order to establish an effective design, flow modeling studies
are required to determine the proper nozzle size, number, velocity, and
9-14
-------
Stack
ESP
ESP
Cooling
Tower
Boiler Building
Generator
Building
Figure 9.1-3. Model Plant Plot Plan
9-15
-------
and spacing. In addition, the nozzles should be designed with the ability
to supply at least 40 percent of the total combustion air to the system.
Because the waterwalls in this section of the boiler are a welded wall
construction, it is assumed that new waterwall panels will be required with
tube bends around the overfire air nozzles.
Following a successful redesign of the tertiary air nozzles, the model
plant will have the design, operation/control, and verification measures in
place which constitute good combustion practices. The 1800°F temperature is
attained and auxiliary fuel is in place to use during start up and low
temperature/high CO conditions. The necessary flue gas monitors are in
place to briefly operation conditions. The flue gas temperatures at the
economizer outlet are low enough to prevent CDD/CDF formation from
occurring. The new nozzles will ensure that mixing of the exhiust gases is
achieved and CDD/CDF concentrations are minimized,
9.1.3.2 Environmental Performance. Following redesign of the
overfire air nozzles the effect on pollutant emission levels will be a
reduction in CDD/CDF emissions from the baseline values to 400 ng/dscm. No
additional pollutant reductions can be anticipated. Downtime is estimated
to be three weeks for each combustor.
9.1.3.3 Costs. Capital costs for combustion modifications are
presented in Table 9.1-4, Total capital costs are $295,000. Annual costs
are presented in Table 9.1-5. Annual cost is $109,000 per year.
9.1.4 Best Particulate Control
The ESP's in place on the model plant reduce PH emissions by
98.5 percent from 2.0 gr/dscf to 0.03 gr/dscf (corrected to 7 percent 02).
Therefore, the baseline PM emission rate is lower than the rate identified
with good control (0.05 gr/dscf), and no plant modifications will be required
for good control.
9.1.4.1 Description of Modifications. To achieve best particulate
control (0.01 gr/dscf) will require an ESP with 20,600 square feet of
collection area for each combustor. To obtain this performance, each
existing ESP will be upgraded with 4300 square feet of additional plate
area. Fifty feet of ductwork will be replaced between each ESP and the
9-16
-------
TABLE 9.1-4. PLANT CAPITAL COST FOR COHBUSTION MODIFICATIONSa
(Two units of 250 tpd each)
Item Cost ($1,000)
DIRECT COSTS:
Flow Hodeling 75
Qverfire Air Nozzles 122
Total 197
INDIRECT COSTS AND CONTINGENCIES: 98
TOTAL CAPITAL COSTS 295
DOWNTIME COST 441
ANNUALIZED CAPITAL AND DOWNTIME 97
aAll costs are in December 1987 dollars.
-------
TABLE 9.1-5 PLANT ANNUAL COST FOR COMBUSTION MODIFICATIONS
{Two units of 250 tpd each)
Item Cost ($1,000)
DIRECT COSTS;
Operating Labor 0
Maintenance Labor 0
Maintenance Materials 0
Total 0
INDIRECT COSTS:
Overhead - 0
Taxes, Insurance, and Administration 12
Capital Recovery and Downtime 97
Total 109
TOTAL ANNUALIZED COST 109
9-18
-------
stack. A a plot plan of the equipment arrangement Is shown In Figure 9.1-4.
The existing ID fans will be retained. No new monitoring equipment will be
installed. Downtime is estimated to be one month for each combustor.
9.1.4.2 Environmental Performance. Particulate matter emissions will
be reduced from 0.03 gr/dscf to 0.01 gr/dscf. No other pollutant of interest
will be affected. The increased fly ash recovery will add 33 tons per year
to the baseline solid waste disposal requirements for the plant.
9,1.4.3 Costs. Capital costs for particulate control upgrade are
presented in Table 9.1-6. The major capital cost is purchased particulate
control equipment. A moderate access and congestion factor was used to
estimate the total capital cost. Total capital required is $1,990,000.
Downtime costs are $588,000 and are primarily lost revenues from electrical
generation. Annual costs are shown in Table 9.1-7. The largest annual cost
is annualized capital recovery and downtime. Total annual cost is $456,000
per year.
9.1.5 Good Acid Gas Control
9.1.5.1 Description of Modifications. For good CDD/CDF and acid gas
control, hydrated lime will be injected into the flue gas duct before the
ESP. The lime sorbent will be fed at a molar ratio of 2:1 (calcium-to-
total acid gas) for a rate of 283 Ib/hr per combustor. Site equipment for
sorbent injection will include a sorbent storage silo, a pneumatic sorbent
transfer system, pneumatic nozzles, and a sorbent feed bin for each
combustor. To cool the flue gas from 450°F to 350°F, water spray nozzles,
also located in the duct before the ESP inlet, will introduce 5 gpm of
water. Fifty feet of new duct for each combustor will be fabricated
containing the water and sorbent nozzles.
A total of 23,750 square feet of ESP collection area will be required
to collect the sorbent and fly ash from each combustor at an emission rate
of 0.01 gr/dscf. The additional 7,450 square feet of required collection
area will be added as a new single-field ESP in series behind the existing
ESP. Installation of the two new ESP's will also require 100 total feet of
new ductwork and two new ID fans. The proposed equipment arrangement is
shown in Figure 9.1-5. New monitoring equipment for SOg, HC1, Og, and CCL,
for each cqmbustor is also included. Downtime is expected to be
approximately one month for each combustor.
9-19
-------
Stack
x—\_~ sr—s.
ffmdo
ESP
New ESP Plate Area
ESP
Boiler Building
Cooling
Tower
Generator
Building
Figure 9.1-4. Partfculite Control Equlpntnt Arrangtment
i
9-20
-------
TABLE 9.1-6. PLANT CAPITAL COST FOR PARTICULATE HATTER CONTROLS
(Two units of 250 tpd each)
Item
Cost ($1000)
DIRECT COSTS:
PH Controla
Upgrade Costs
Access/Congestion Cost
Mew Flue Gas Ducting8
Ducting Costs
Access/Congestion Cost
Other Equipment
Fan
Stacks
Demo!ition/Relocation
Total
Indirect Costs and Contingencies
Monitoring Equipment
TOTAL CAPITAL COST
DOWNTIME COST
ANNUALIZED CAPITAL RECOVERY AND DOHNTIHE
1,150
288
34
9
0
0
g
1,480
506
0
1,990
588
, 338
aBased on moderate access/congestion.
9-21
-------
TABLE 9.1-7. PLANT ANNUAL COST FOR PARTICIPATE MATTER CONTROLS
. (Two units of 250 tpd each)
Hew Cost ($1000)
DIRECT COSTS:
Operating Labor 0
Supervision 0
Maintenance Labor • 0
Maintenance Materials 20
Electricity - 5
Waste Disposal 1
Monitors 0.
Total 26
INDIRECT COSTS:
Overhead 12
Taxes, Insurance, and
Administration 80
Capital Recovery and Downtime J3j
Total 430
TOTAL ANNUALIZEO COST 456
9-22
-------
Stack
:.:x5C
u
\
_ i i
/
\J
ESP
^
ESP
Boiler Building
Cooling
Tower
Generator
Building
New ESP's
* and ID Fans
Flfurt f.l-S. Dry Sorbent Injection Equipment Arrangeiient
9-E3
-------
9.1.5.2 Environmental Performance. Total COO/CDF emissions are
expected to be reduced 75 percent from baseline levels or to 50 dscm,
whichever is higher." Acid gas emission reductions are expected to be
80 percent for HC1 and 40 percent for SO-. Participate matter emissions
will be reduced from 0.03 gr/dscf to 0.01 gr/dscf. Additional collected fly
ash and sorbent will add 2,950 tons per year of solid waste to the baseline
disposal requirements for the plant.
9.1.5.3 Costs. The capital cost requirements for dry sorbent
injection are presented in Table 9,1-8. Total capital cost is $4,140,000.
Host of the cost is associated with equipment for particulate and temperature
control. A moderate access and congestion level was assumed for
all new equipment except the ducts containing the spray nozzles. Since
these ducts pass through the boiler building wall, a high access/congest!on
factor was applied to their direct cost.
Annual costs are presented In Table 9.1-9. The major operating costs
are for sorbent purchase and maintenance of monitoring instruments. The
largest annual cost is annualized capital recovery and downtime. Total
annual cost is estimated to be 31,560,000.
9-1.6 Best Acid Gas Control
9.1.6.1 Description of Modifications. To achieve greatest reductions
in CDD/CDF, HC1, and SCL, a spray dryer with fabric filter will be installed
on each combustor. The existing ESP's will not be demolished, but will be
by-passed and left in place. A total of 300 feet of new duct will be used
to connect the new equipment between the boilers' outlets and the existing
stack. The proposed equipment arrangement is shown in Figure 9.1-6.
Lime slurry will be introduced into the spray dryers at a calcium-to-
acid gas molar ratio of 2.5:1. Water in the lime slurry equivalent to 7 gpm
is needed to cool the gas stream from 450°F to 300°F.
The plant lime receiving, storage, and slurry preparation area is also
shown 1n Figure 9.1-6. Each fabric filter will have an effective cloth area
of 10,600 square feet (net air-to-cloth ratio of 4:1). The increased
pressure drop of the fabric filters relative to the existing ESP's will
require replacement of the ID fans. New monitoring instruments for HC1,
9-24
-------
TABLE 9.1-8. PLANT CAPITAL COST FOR DRY SORBENT INJECTION WITH ADDITIONAL
ESP COLLECTION AREA (Two units of 250 tpd each)
Item Cost ($1000)
DIRECT COSTS:
Acid Gas Control3
Equipment 349
Access/Congestion Cost 35
Particulate and Temperature Control
Equipment 1,580
Access/Congestion Cost 320
New Flue Gas Ducting3
Ducting Cost 71
Access/Congestion Costs 24
Other Equipment
Fans 170
Stacks 0
Demolition/Relocation „ 0
Total 2,550
Indirect Costs and Contingencies 1,080
C*
Monitoring Equipment 514
TOTAL CAPITAL COST 4,140
oowrriHE COST see
ANNUALIZED CAPITAL RECOVERY AND DOWNTIME 622
aBased on moderate access/congestion.
Based on high access/congestion for temperature control ductwork.
cTurnkey.
9-25
-------
TABLE 9.1-9, PLANT ANNUAL COST FOR DRY SORBENT INJECTION WITH ADDITIONAL
ESP COLLECTION AREA (Two units for 250 tpd each)
Item Costs" ($1000)
DIRECT COSTS:
Operating Labor 60
Supervision 16
Maintenance Labor 26
Maintenance Materials 47
Electricity 30
Water 2
Lime 181
Waste Disposal 74
Monitors 206
Total 642
INDIRECT COSTSs
Overhead 89
Taxes, Insurance, and
Administration 145
Capital Recovery and Downtime 622
Total 856
TOTAL ANNUALIZED COST 1,500
9-26
-------
New Spray Dryers,
Fabric Filters and
ID Fans
Stack
Tl
Fabric
Filter
ESP
\
ESP
Boiler Building
Fabric
RIter
Cooling
Tower
Sorbent
Preparation
Generator
Building
Figure 9.1-6. Spny Dryer/Fabric Filter Equipment Arrangement
9-27
-------
SCL, COg, Qg, and opacity will also be installed. Downtime is expected to
be one month for each combustor for ductwork and tie-ins.
9.1.6,2 Environmental Performance. Reductions in CDD/CDF emissions
of 99 percent or to 5 dscm (whichever is higher) are expected. Emissions of
particulate matter will be reduced to 0.01 gr/dscf. Acid gas emissions will
be reduced 90 percent for SO- and 97 percent for HC1. Solid waste in the
form of recovered sorbent and additional recovered fly ash will add
2,590 tons per year to the plant disposal requirements.
9.1.6.3 Costs. Capital costs for installing the spray dryer/fabric
filter systems are shown in Table 9.1-10. Total capital cost is $10,600,000;
the major capital item is purchased equipment. A moderate access and
congestion factor was used for all new equipment. Annual costs are shown in
Table 9.1-11. The largest annual costs are for maintenance materials
including bag replacement, and for annualized capital recovery and downtime.
Maintenance cost for process monitors is also significant. Total annual
cost is estimated at $2,960,000 per year.
9.1.7 Summary of Control Options
9.1.7.1 Description of Control Options. "The control technologies
described in Sections 9,1.2 through 9.1.6 have been combined into the seven
retrofit emission control options previously described in Section 3.0.
Table 9.1-12 presents the combination of combustion, temperature,
particulate, and acid gas control technology used for each of the control
options. It should be noted that since the model plant already achieves
good PM control at baseline, Options 1 and .2 are identical.
9.1.7.2 Environmental Performance. The performance of each control
option is summarized in Table 9.1-13. For each pollutant, the table presents
both the pollutant concentrations and emissions. The greatest reduction in
COO/CDF emissions is achieved by addition of the spray dryer/fabric filter
systems; the next most effective measure for control of COO/CDF is combustor
modification. The lowest overall emissions of COD/CDF result from-the
implementation of both of these technologies together. Dry sorbent injection
is almost as effective for COO/CDF control as combustor modifications. Both
sorbent addition technologies negatively impact solid waste disposal
requirements slightly.
9-28
-------
TABLE 9.1-10. PLANT CAPITAL COST FOR SPRAY DRYER WITH FABRIC FILTER
(Two units of 250 tpd each)
Item
Cost {$1000}
DIRECT COSTS:
Acid Gas Control
Equipment
Acciss/Congestion Cost
New Flue Gas Ducting
Ducting Cost
Access/Congestion Cost
Other Equipment
Fans
Stacks
Demolition/Relocation
Total
Indirect Costs
Contingency
Monitoring Equipment2
TOTAL CAPITAL COST
DOWNTIME COST
ANNUALIZED CAPITAL RECOVERY AND CONTINGENCIES
5,040
950
102
26
183
0
0
6,300
2,080
1,670
. 573
10,600
588
1,470
Turnkey.
9-29
-------
TABLE 9.1-11. PLANT ANNUAL COST FOR SPRAY DRYER WITH FABRIC FILTER
(Two units of 250 tpd each)
Item Cost ($1000)
DIRECT COSTS:
Operating Labor 96
Supervision 14
Maintenance Labor 53
Maintenance Materials 154
Electricity 116
Compressed Air 16
Water 4
Lime 150
Waste Disposal 97
Monitors 215
Total 913
INDIRECT COSTS:
Overhead 173
Taxes, Insurance, and
Administration 402
Capital Recovery and Downtime 1,470
Total 2,050
TOTAL ANNUALIZED COST 2,960
Includes bag replacement costs of $28,000.
9-30
-------
TABLE 9,1-12, SUMMARY OF CONTROL OPTIONS FOR ROTARY WATERWALL COK8USTOR
Control Option Deicri.pt Ion
Paniculate Control
Acid Gaj Control
Combujtlon Temperature E*litln* ISP
Modifications Control Rebuilt
Additional.
Plata Are»
H«w Socbent Spray
Fabric filter Injection Dryer
1. Good Combtutlan and
Tefflpereture Control
2. Good PM Control with
Coobuatlon Control and
Tftia|>«rftt.ur« Control
3. Best PM Control and
Combustion and Temperatun
Control
IO
i
5.
Good Acid Cat Control,
Bait PM Control and
Temperature Control
Good Acid Gat Control
and B«nt PM/C«nhuitlon/
Teiqp*ratur* Control
6. Beit Acid Cai Control,
Beit PM Control, and
Teaparatur* Control
7. Best Acid Cai Control and
Beit PH/CombuatLon/
Teofiaratur* Control
-------
TABLE 9.1-13. ENVIRONMENTAL PERfORMAHCE SIMMARY FOR ROTARY UATERHALL
ROTARY MUG MODEL PLANT RETROFIT CONTROL OPTIONS*
(Two unlit of 250 tpd each)
Total CDD/CDF Enlstlooa
(nc/djcm)
M«/yr
I Reduction v*. Baaelta*
CO Emission*
(ppow)
M«/yt
Z Reduction va. Baseline
PM Emissions
(gr/d»cf)
Mji/yr
Z Reduction vs. Baseline
SO Emli ilons
(ppnw)
Mg/yr
1 Reduction vs. Basal Ine
HC1 Emissions
Cpptnv)
H«/yr
Z Reduction vs. Baseline
Total Solid Haste.
(tons /day)
Mg/yr
X Increase Vs. Baseline
Ba**lln*
2000
1.3E-3
--
100
81
--
0.03
49
--
200
370
—
500
528
--
150
45,500
"
Option 1
400
2.6E-4
BO
100
81
0
0.03
49
0
200
370
0
500
528
0
150
45,500
0
Option 2
400
2.6E-4
80
100
81
0
0.03
49
0
. 200
370
0
500
528
0
ISO
45,500
0
Opt loo 3
400
2.6E-4
80
100
81
0
0.01
16
67
200
370
0
500
528
0
150
45,500
0
Option 4 Option S
500
3 2E-4
75
100
81
0
O.ui
16
67
120
222
40
100
106
80
159
48 , 500
7
100
6.5E-5
95
100
81
0
0.01
16
67
120
222
40
100
106
80
159
48,500
7
Option 6
20
1.3E-5
99
100
ai
0
0,01
16
67
19
35
90.5
15
15
97
162
48,970
8
Option 7
5
3.2E-6
99
100
81
0
0,01
16
67
19
35
90.5
15
15
97
162
48,970
8
All flue t»» concentration* are reported on * dry 7 percent 0. bail*. Manual and Standard conditions ace 1
•toosplwr* and 70 F.
-------
9.1.7.3 Costs. The total annualized cost of each option is presented
in Table 9.1-14. The cost of control options increases as the level of
control increases. Combustion control combined with acid gas control
technologies increases CDD/CDF control substantially (about 80 percent) with
very little additional cost. This is because the major cost of combustion
retrofit is downtime, and the downtime for the acid gas APCD retrofit is
longer than for the combustion modifications.
9.1.7.4 Energy Impacts. Table 9.1-15 presents a summary of the
energy impacts associated with the control options. The electrical use
figures take into account the savings realized by not operating the existing
ESP. There is no increase in auxiliary fuel use because auxiliary burners
are already in place on the model plant and are used under baseline
operation.
9-33
-------
I
Oi
¥*BU 9.1-1*. COSI SUNMRir FOR ROTARY UATERUALL MWC HQDHL PULBT RETROFIT COKTROL OFTIOHS*
(Two unita of 2SO tpd «»ch>
Option 1 Option 2 Option 3 Option 4 Option S Option < Option 7
Tot»L Capital Coat
Downtown Coat
Annuitized Capital and
Downtime Coat
Blcact OlM Co.t
total Annual Coat
Cojt Effaetlvanaai
(S/ton HSU1
Facility DowntiiM
(Honth.)
total Cooyllanca ftm*
(Hontha)
19S 29S 2.290 4,1*0 *,«40 10.600 10,900
441 441 SB* 588 588 588 SM
97 91 377 £22 661 1,470 1,510
0.0 26 £42 642 913 911
109 1S2 SOT 1,300 1,550 2,960 3,010
0.6S 0.91 3,04 8, 98 9. 28 17,80 18.10
0.75 0.75 1 1 1 I i
55 19 19 19 25 25
All coati (»capt coil. *ff»ctlven«n) given In $1000. All cottm In Dacambar 1987 dollara.
-------
TABLE 9.1-15. ENERGY IMPACTS FOR ROTARY WATERWALL
COHBUSTOR MODEL PLANT CONTROL OPTIO
(Two units of 250 tpd each)
Option
1
2
3
4
5
6
7
Electrical Use
(MWh/yr)
0
0
102
672
672
2,520b
2,520b
Gas Use
(Btu/yr)
0
0
0
0
.0
0
0
Increase from baseline consumption.
Excludes the electrical credit of not operating the ESP's.
9-35
-------
9.2 REFERENCES
1. Schindler, P., Energy and Environmental Research Corporation, and
Lamb, L., Radian Corporation, Trip Report - Retrofit Control Site
Evaluation at the Bay County, Florida Waste-to-Energy Facility.
March 30, 1988.
9-36
-------
10.0 HODEL PLANTS REPRESENTING PROJECTED lll(d) FACILITIES
In addition to the estimated 160 HWC's currently operating, there are
at least another 110" that will commence construction by 1989 and therefore
be subject to the lll(d) regulations. This population was examined and each
facility was assigned to one of the 12 model plants presented in Section 4.0
through 9.0 when appropriate. Where differences between the population of
planned facilities and the existing lll(d) model plants were identified, new
model plants were developed. A list of these facilities and the model
plants they have been assigned to is presented in a separate memorandum.
Sections 10.1 through 10.5 present the case study summaries for the
additional five model plants developed to represent planned lll(d)
facilities.
10.1. LARGE MODULAR EXCESS AIR COHBUSTOR
10.1.1 Description of the Model Plant
10.1.1.1 Combustor Design and Operation. The model plant presented in
this section was selected as representative of six planned lll(d) plants
that would commence construction by November 1989 and be subject to the
Section lll(d) guidelines currently being developed. Although this model
plant is similar in design to the modular excess-air plant presented in
Section 8.1, this model is somewhat larger. This reflects the relative
Increase in capacity represented by the projected excess-air MWC's. The
model plant data are shown in Table 10.1-1.
The model plant consists of three units, each with a rated capacity of
140 tpd and based on the Enercon/Vicon design. The units burn 100 percent
municipal solid waste, 24-hours/day, 7-days/week. Each unit has both
primary and secondary combustion chambers which manifold Into a single
tertiary duct where burning is completed prior to the flue gases entering a
waste heat boiler. The boiler reduces the flue gas temperature from 1400°F
to 450°F before entering the air pollution control equipment.
Fuel feeding and combustion air supplies are identical to those of the
modular excess-air plant described in section 8.1. Excess air levels at the
boiler outlet are assumed to be SO percent. Flue gas flowrates ire
approximately 40,100 dscfm at the boiler exit. CO and Og monitors are
located at the secondary chamber exit. Temperatures are measured at the
10-1
-------
TABLE 10.1-1 MODEL PLANT BASELINE DATA FOR LARGE MODULAR
EXCESS-AIR COMBUSTOR
Combustor:
type
Number of Combustors
Combustor Unit Capacity
Plant Capacity
Emission Controls:
Type
Number of ESP's
Number of Fields
Inlet Temperature
Collection Efficiency
Gas Flow
Total Plate Area
SCA at 82,000 acfm and 450°F
Emissions:3
CDD/CDF (tetra-octa)
PM (stack)
CO
HC1
so2
Stack Parameters:
Height
Diameter
Operating Data:
Remaining Plant Life
Annual Operating Hours
Annual Operating Cost
Modular Excess-air
3
140 tpd each
420 tpd
Electrostatic Precipitator
1
450°F
97.5 percent
82,000 acfm
24,200 fr
295
200 ng/dscm h
0.05 gr/dscf°
50 ppmv
500 ppmv
200 ppmv
70 ft
8.0 ft
> 20 years
8,000 hours
$3,810,000
emissions are dry, corrected to 7 percent Q-, Standard and Normal
conditions are both 70 F and 1 atmosphere,
blnlet PM emissions to the ESP are 2.0 gr/dscf at 7 percent 09.
10-2
-------
exit of the primary and secondary chambers, and at the boiler inlet and
outlet. An auxiliary fuel burner 1s located in the primary combustion
chamber for use during process start-up and during episodes of low
temperatures.
10.1.1.2 Emission Control System Design and Operation. As with the
model plant described in Section 8.1, the model plant here is equipped with
a single 2-field ESP controlling particulate matter emissions to
0.05 gr/dscf at 7 percent 02- Since all three combustors are ducted to a
single boiler and ESP, a single stack is also assumed. The model plant ID
fan is located downstream of the ESP. A plot plan of the model plant is
shown in Figure 10.1-1.
10.1.1.3 Environmental Baseline. Table 10.1-1 also presents baseline
emissions data for the model plant. Baseline emissions are the same as
presented for the modular excess air model plant presented in Section 8.1.
The combustion process is assumed to reduce incoming waste 90 percent by
volume and 70 percent by weight.
10.1.2 Good Combustion Control
The model plant has good combustion practices in place. This is
verified by the low uncontrolled levels of COD/CDF and CO emissions. Under
normal operating conditions the combustor achieves 1800°F» and good mixing is
in place. Monitoring of temperature, oxygen, and CO is also in place. Due
to adequate heat removal through the boiler, the exhaust gas temperature is
450°F. As a result, there is no need for further flue gas temperature
reduction prior to the air pollution control equipment, and the potential for
formation of COD/CDF in the ESP is minimized. Based on this assessment there
are no combustion retrofits required for the model plant.
10.1.3 Best Particulate Control
The ESP in place on the model plant reduces PM by 97..5 percent, from
2.0 gr/dscf to 0.05 gr/dscf corrected to 7 percent 0-. Therefore, the
baseline PM emission rate is equal to the rate identified with good control
(0.05 gr/dscf), and no plant modifications will be required for this control
1evel.
10.1.3.1 Descrlption of Modif1 cations. To achieve best particulate
matter control (0.01 gr/dscf emission rate) will require an ESP with
34,500 square feet of collection area. Therefore, an additional
10-3
-------
Stack
ESP
Tipping Floor
Building
Wall
Combustors
Figure 10.1-1. Plot Plan of Hodel Plant
10-4
-------
10,300 square feet will be added to the model plant ESP. The additional area
will be installed as a separate single-field ESP 1n series with the existing
ESP, A hundred feet of new duct and a new ID fan will be required. The
existing stack will continue to be used. A plot plan of the proposed
equipment arrangement is shown in Figure 10.1-2. No new monitoring
equipment will be required. Downtime will affect both combustors at once
and 1s estimated at one month for ductwork tie-in.
10.1.3.2 Environmental Performance. Particulate matter emissions will
be reduced from 0.05 gr/dscf to 0.01 gr/dscf. The increased fly ash
recovery will add 55 tons per year to the baseline solid waste disposal
requirements for the plant.
10.1.3.3 Costs. Capital cost requirements for best particulate
control are shown in Table 10.1-2. The major cost item is the particulate
control equipment. Total capital requirement is $1,400,000. Annual costs
are presented in Table 10.1*3, and are dominated by annualized capital
recovery and downtime. Total annual costs are expected to be $327,000 per
year.
10.1.4 Good Acid Gas Control
10.1.4.1 Description of ModifiC|tlQns. For good acid gas and CDD/CDF
control, hydrated lime sorbent will be injected into the flue gas duct
before the ESP. The lime sorbent will be fed at a molar ratio 2:1 (calcium
to acid gas) for a rate of 47S Ib/hr With both combustors operating.
Additional equipment for sorbent injection will include a sorbent storage
silo, a pneumatic sorbent transfer system, a sorbent feed bin, and pneumatic
injection nozzles. To cool the flue gas from 450°F to 3SO°F, spray nozzles,
also located in the duct before the ESP, will introduce 8 gpm of water.
Fifty feet of new duct will be fabricated containing the water and sorbent
nozzles.
A total of 39,900 square feet of ESP collection area will be required
to collect the sorbent and fly ash to an emission level of 0.01 gr/dscf,
Therefore, an additional 15,700 square feet of collection area will be added
to the model plant ESP. The additional area will be installed as a separate
single-field ESP in series with the existing ESP. Installation of the new
ESP will also require 100 feet of new duct and a new ID fan. The proposed
10-5
-------
Stack
ESP
Tipping Roof
New ESP
* and ID Fan
Building
Wail
Combustors
Figure 10.1-2. Plot Plan of Particulate Control Equipment
5
3
10-6
-------
TABLE 10.1-2 PLANT CAPITAL COST FOR PARTICIPATE MATTER CONTROLS
(Three units of 140 tpd each)
Item
Cost ($1000)
DIRECT COSTS:
PM Control*
Upgrade Costs
Access/Congestion Cost
New Flue Gas Ducting3
Ducting Costs
Access/Congestion Cost
Other Equipment
Fan
Stack
Demolition/Relocation
Total
Indirect Costs and Contingencies
Monitoring Equipment
TOTAL CAPITAL COST
DOWNTIME COST
ANNUALIZED CAPITAL RECOVERY AND DOWNTIME
671
168
4S
11
152
0
0
1,010
3S7
0
1,400
432
242
Based on moderate access/congestion.
10-7
-------
TABLE 10.1-3 PLANT ANNUAL COST FOR PARTICULATE MATTER CONTROLS
(Three units of 140 tpd each)
Item Cost ($1000)
DIRECT COSTS:
Operating Labor 0
Supervision 0
Maintenance Labor 0
Maintenance Materials 14
Electricity 6
Waste Disposal 1
Monitors 0
Total 21
INDIRECT COSTS;
Overhead 8
Taxes, Insurance, and
Administration SB
Capital Recovery and Downtime g42
Total 30S
TOTAL ANNUALIZED COST 327
10-8
-------
equipment arrangement is shown in Figure 10.1-3. New monitoring equipment
for S02» HC1» Og and C02 is also included. Downtime is estimated at one
month,
10.1,4.2 Environmental Performance. CDD/CDF emissions are expected to
be reduced to 25 percent of inlet levels or to 50 ng/dscm, whichever is
greater. Acid gas emission reductions are expected to be 80 percent for HC1
and 40 percent for SO-. Particulate matter emissions will be reduced to
0.01 gr/dscf. Additional collected fly ash and sorbent will add 2,510 tons
per year of solid waste to the baseline disposal requirements for the plant.
10.1.4.3 Costs. Capital cost requirements for dry sorbent injection
are presented in Table 10.1-4. Total capital cost is $2,790,000. Most of
the cost is associated with new equipment for particulate and temperature
control. A moderate access and congestion level is assumed for all
equipment except the duct containing the spray nozzles. Since this duct
passes through the building wall, a high access/congestion factor was
applied to the direct cost.
Annual costs are presented in Table 10.1-5. The major operating costs
are for lime purchase and monitoring equipment maintenance. The largest
annual cost is annualized capital recovery and downtime. Total annual cost
is estimated to be $999,000.
10-1-5 Best Acid Gas Control
10.1.5.1 Description of Modifications. To achieve greater reductions
in CDD/CDF, HC1, and SO-, a spray dryer/fabric filter system will be
installed. The existing ESP will not be demolished, but will be bypassed
and left in place. A total of 200 feet of new duct will be used to connect
the new equipment between the boiler outlet and the existing stack. The
proposed equipment arrangement is shown in Figure 10,1-4.
Lime slurry will be introduced into the spray dryer at a calcium-to-acid
gas molar ratio of 2.5:1. Water in the lime slurry equivalent to 12 gpm is
needed to cool the gas stream from 450°F to 300°F.
The lime receiving, storage and slurry preparation area is also shown in
Figure 10.1-4. The fabric filter will have 17,800 square feet of effective
cloth area (net air-to-cloth ratio of 4:1). The increased pressure drop of
10-9
-------
Stack
ESP
New ESP
and 10 Fan
Sorbenr
Storage,
Building
Wall
New Duct
with Injection Nozzles
Tipping Floor
Combustors
Figure 10.1-3, Plot Plan of Dry Sorbent Injection Equipment Arrangement
10-10
-------
TABLE 10.1-4 PLANT CAPITAL COST FOR DRY SORBENT INJECTION
WITH ADDITIONAL ESP COLLECTION AREA
(Three units of 140 tpd iach)
Item Cost ($1000)
DIRECT COSTS:
Acid Gas Control3
Equipment 331
Access/Congestion Cost 33
Particulate and Temperature Control
Equipment 974
Access/Congestion Cost 203
New Flue Gas Ducting3
Ducting Cost 43
Access/Congestion Costs 10
Other Equipment
Fans 140
Stacks 0
Demolition/Relocation 0
Total 1,730
Indirect Costs and Contingencies 801
Monitoring Equipmentc 257
TOTAL CAPITAL COST 2,7,90
DOWNTIME COST 432
ANNUALIZED CAPITAL RECOVERY AND DOWNTIME 423
aBased on moderate access/congestion.
Based on high access/congestion for temperature control ductwork.
cTurnkey.
10-11
-------
TABLE 10.1-5. PLANT ANNUAL COST FOR DRY SORBENT INJECTION WITH
ADDITIONAL ESP COLLECTION AREA
(Three units of 140 tpd each)
Item Cost ($1000)
DIRECT COSTS:
Operating Labor 30
Supervision 5
Maintenance Labor 14
Maintenance Materials 36
Electricity 21
Water 2
Lime 152
Waste Disposal 63
Monitors 103
Total 425
INDIRECT -COSTS:
Overhead 50
Taxes, Insurance, and
Administration
Capital Recovery and Downtime
Total
TOTAL ANNUALIZED COST 999
10-12
-------
Sorbent
Preparation
and Storage
Tipping Floor
t New Spray Dryer,
Fabric Filter and ID Fan
Building
Wall
Combustors
Figure 10.1-4
Plot Plan of Spray Dryer/Fabric Filter Retofit Equipment
Arrangement
10-13
-------
the fabric filter relative to the existing ESP will require replacement of
the ID fan. New monitoring equipment for HC1, SOg, CO-, 0- and opacity will
be installed. Downtime is expected to be one month for ductwork tie-ins.
10.1,5.2 Environmental p_erfOjrmancj• COD/CDF emission reduction of
99 percent or to S ng/dscm (whichever gives higher emissions) is expected.
Emissions of particulate matter will be reduced to 0.01 gr/dscf. Acid gas
emissions will be reduced 70 percent for SO- and 90 percent for HC1. Solid
waste in the form of additional fly ash and recovered sorbent will add
2,210 tons per year to the plant solid waste disposal requirements.
10.1.5.3 Costs. Capital costs for installing a spray dryer/fabric
filter system are shown in Table 10.1-6. Total capital cost is $6,950,000.
The major capital cost is for the purchased equipment. A moderate
access/congestion factor was applied to all direct equipment costs. Annual
costs are shown in Table 10.1-7. The largest annual costs are *or
maintenance materials, including bag replacement, and annualized capital
recovery and downtime. Naintenance cost for monitors is also significant.
Total annual cost is estimated at $1,950,000 per year.
10.1.6 Summary of ControlOptions
10.1.6.1 Description of Control Costs. The control technologies
described in the previous sections have been combined into seven retrofit
emission control options. Table 10.1-8 summarizes the combustion,
particulate, temperature, and acid gas control technologies described in
Sections 10.1.2 through 10.1.5 that were combined for each of the control
options described in Section 3.0.
It should be noted that since the model plant already achieves moderate
PM control at baseline, Options 1 and 2 are identical^ Also, since the model
plant achieves good combustion at baseline, Options 1 and 2 are equivalent to
baseline, Options 4 and 5 are identical, and Options 6 and 7 are identical.
10.1.6.2 Environmental Performance. The performance of each control
option is summarized in Table 10.1-9. For each pollutant, the table
presents both the pollutant concentrations and emissions. The greatest
emission reductions of acid gases, particulate matter, and CDD/CDF all are
achieved with the spray dryer/fabric filter system. The next most effective
control for all these pollutants 1s dry sorbent injection. Both sorbint
10-14
-------
TABLE 10.1-6. PLANT CAPITAL COST FOR SPRAY DRYER WITH FABRIC FILTER
(Three units of 140 tpd each)
Item
Cost ($1000)
DIRECT COSTS:
Acid Gas Control
Equipment
Access/Congestion Cost
New Flue Gas Ducting
Ducting Cost
Access/Congestion Cost
Other Equipment
Fans
Stacks
Dewoli t i on/Relocat i on
Total
Indirect Costs
Contingency
Monitoring Equipment3
TOTAL CAPITAL COST
DOWNTIME COST
ANNUALIZED CAPITAL RECOVERY AND DOWNTIME
3,130
781
89
22
151
0
. ft
4,170
1,380
1,110
286
6,950
432
970
Turnkey.
10-15
-------
TABLE 10.1-7 PLANT ANNUAL COST FOR SPRAY DRYER WITH FABRIC FILTER
(Two units of 100 tpd each)
Item Cost ($1000)
DIRECT COSTS:
Operating Labor 48
Supervision 7
Maintenance Labor 26
Maintenance Materials 106
Electricity 93
Compressed Air 13
Water 3
Lime 126
Waste Disposal 82
Monitors 107
Total 613
INDIRECT COSTS:
Overhead 99
Taxes, Insurance, and
Administration 266
Capital Recovery and Downtime ,rr970
Total 1,340
TOTAL ANNUALIZED COST 1,950
alncludis bag replacement costs of $23,000,
10-16
-------
TABLE 10.1-8 SUHURY OF COHmOL OPTIONS FOR LARGE MODULAR EXCESS-AIR OOMBUSTOR
Control Opt Ian Description
Particular Control
Acid Gas Control
Combustion Temperature Existing ESP
Modification* Control Rebuilt
Additional
Plant Area
Hew Sorbent Spray
Fabric Filter Injection Dryer
1. Good Combustion and
Temperature Control
2. Good PM Control with
Combustion Control
3, Beat PM Control and
Combustion and
Control
4. Good Acid Gas Control,
Bast PM Control and
Teofierature Control
O
i
5. Good Acid Gas Control
and Beat PH/Cexnbujtlon/
Temperature Control
6. Best Acid Gaa Control,
Beat PM Control, and
Temperature Control
7. Best Acid Gas Control and
Best PH/ Combust ion/
Tmcnrature Control
-------
TABLE 10.1-9 ENVIRONMENTAL PERFORMANCE SUWARY FOR LARGE NODULAR
EXCESS-AIR HUC HQOEL PLAHT RETROFIT CONTROL OPTIONS*
(Thza* units of 140 tpd each)
Baseline Option 1
CCD/CDF Emission*
(na/dsca)
M|Jfr
I Reduction vs. Baseline
CO Emission*
Cppow)
H§fy*
X Reduction vs. HsselLne
PM Emissions
(gr/d»cf )
M§/yr
I Seduction vs. Baseline
£0. Enlsalona
(pponr)
Mg/yr
X Reduction vs. Baseline
HC1 Emissions
(PEKDV)
Mgjyr
X Reduction vs. Baseline
Total Solid Haste
(tons /day)
H«/yr
S Increase vs. Baseline
200
1.09E-4 1
SO
31. S
—
o.os
62.1
—
200
305
—
500
417
—
126
38,100
™""~
200
-09E-4
0
50
31.5
0
0.05
62,1
0
200
30S
0
500
417
0
126
38,100
0
Option 2
200
1.09E-4
0
SO
31.5
0
0.05
£2.1
0
200
SOS
0
500
41?
0
126
38,100
0
Option }
200
1.09E-4
0
SO
31.5
0
0.01
12.4
80
200
305
0
SOO
417
0
126
38,150
0.1
Option 4
SO
2.7E-S
75
SO
31
0
0.01
12.4
80
120
183
40
100
84
80
134
40,400
6
Option 5 Option 6 Option 7
50
2. 7E-S
75
50
31.5
0
0.01
12.4
80
120
183
40
100
64
80
134
40,400
6
S
1.3E-6
98
SO
31.3
0
0.01
12.4
80
19
29
90.5
15
13
97
13&
41,100
8
5
2.71-6
98
SO
31.5
0
0.01
12.4
80
19
29
90.5
15
13
9?
136
41,100
8
All flu* gai concentr*tloria ac« reported on a dry 1 percent 0. b*»l*. Standard And Normal conditions
*r* both 1 «tff>a*pher* «n4 70 ¥•
-------
addition technologies increase solid waste slightly (less than 10 percent
over baseline). No combustion modifications were made, so CO emissions
remain unchanged at SO ppm for all options.
10.1.6.3 Costs. The total annualized cost of each option is presented
in Table 10.1-10. The most costly control option is the spray dryer/fabric
filter installation, at a capital cost of $2,270,000. Overall, costs are
higher for higher levels of control.
10,1.6.4 Energy Impacts. Table 10.1-11 presents a summary of the
energy impacts associated with the control options. The energy use figures
are incremental use; savings realized by not operating the existing ESP are
taken into account. There is no increase in auxiliary fuel use because
auxiliary burners are already .in place on the model plant and are used under
baseline operation.
10-19
-------
TABLE 10.1-10 COST SUItURY FOX THE LARGE NODULAR EXCESS-AIR MMC HOOEL PUNT RETROFIT COKTROL OFTIOHS
(Three unite of 140 tpd each)
Total Capital Cost
DovntiiB* Cojt
Annual iB*d Capital and
Downtime Cost
Annual OIK Coit
Total Annual Cost
Co«t Ef£ectlvent»i
Option 1
0
0
0
0
0
0
Option 2
0
0
0
0
0
0
Option 3 Option 4 Option 5
1,400 2,790 2,790
432 432 412
242 423 421
21 425 425
327 999 999
2.34 7.14 7.14
Option 6
6,950
432
970
613
1,950
13.90
Option 7
6,950
432
970
613
1,950
13.90
^ (Slton MSH)
O
^ F»clllty Dom Time
O (Honth.)
Total Coafllinct TlIM 11 19 19 19 23 25
(Honth.)
All co»t» (except: co»t *f(ectlv*na») §lv*n In $1000. All co«t» In December 1987 dollar*.
-------
TABLE 10.1-11. ENERGY IMPACTS FOR THE LARGE MODULAR EXCESS-AIR
COMBUSTOR MODEL PLANT CONTROL OPTIONS3
Option
1
2
3
4
5
i *
• 6
7
Electrical Use
(MWh/yr)
0
0
125
448
448
h
2,040°
h
2,040°
Gas Use
(Btu/yr)
0
0
0
0
0
0
0
Increase from baseline consumption.
Excludes the electrical credit of not operating the ESP's.
10-21
-------
10.2 SMALL MASS BURN WATERWALL COMBUSTOR
This model plant described in this section represents projected small
mass burn plants which will commence construction by November 1989 and will
be subject to the Section lll(d) guidelines rather than to the proposed
NSPS. This model plant is the same as the one described in Section 5.3
except that baseline for the model includes good combustion practices and
temperature control to 450°F whereas the model plant discussed in
Section 5.3 does not. Table 10.2-1 summaries the combustion, temperature,
particulate, and acid gas control technologies that were combined for each
of the control options described in Section 3.0. As with the model plant
described in Section i.3, the model plant already achieves good PM control
at baseline; Option 1 is identical to Option 2.
The environmental performances, costs, and energy impacts for baseline
and the control options were adjusted from those presented in Section 5.3 to
reflect the change in baseline. A summary of these impacts and costs are
presented in the following three sections,
10.2.1 Ejwironmental Performance
Table 10.2-2 summarizes the environmental performances of baseline and
each control option. Because of the change in baseline, baseline emissions
are equivalent to those presented under Control Option 1 and 2.
Furthermore, CDD/CDF emissions for Options 4 and 5 are 75 percent lower than
baseline and CDD/CDF emissions for Option 6 and 7 are 98 percent lower than
baseline. CO emissions for the control-options are equivalent to those of
baseline. . The respective emission rates and the emission reductions from
baseline of other pollutants (PM, SO-, and HC1) for each control options
remain unchanged from those presented in Section 5.3. Similarly, total
solid waste disposal rates of the control options also remain.unchanged.
Because this model plant uses good combustion practices in the baseline
whereas the model plant described in Section 5.3 does not, baseline
emissions of CDD/CDF and CO in Table 10.2-2 are 93 and 88 percent lower,
respectively, than those presented at baseline for the small mass burn
waterwall model plant in Section 5.3.
10-22
-------
TABLE 10.2-1.
SUMMAR* OF CONTROL OPTIONS FOR SMALL MASS BUBM UATERWALL CQMBUSTOR
Partictilete control
Combustion Temperature Existing ESP Additional
Control Option Description Modification* Control Rebuilt SCA
Acid Gai Control
Mew Sorbent Spray
Fabric Filter Injection Dryer
1. Good Combustion and
Taofjereture Control
2. Good PM Control ulth
Combustion Control
ro
to
I, Beat PM Control and
Combustion and Temperature
Control
», Good Acid Gaa Control,
Beat PM Control and
Tainperature Control
5. Good Acid Gaa Control
and Beat PM/Combust Lou/
Teopecature Control
6. Bait Acid G*i Control,
Beat PM Control, and
Temperature Control
7, Beat Acid Caa Control and
Beat PHICoobustton/
Temperature Control
-------
TABLE 10.2-2. ENVIRONMENTAL PERFORMANCE SUMMARY FOR SMALL MASS BURN
WATERWAU, HWC MODEL PLANT RETROFIT COHTROL OPTIONS
(Two units of 100 tpd «»ch)
Total CDD/CDP Emlulon*
-------
10.2.2 Costs
The total capital and annualized costs of each option are presented in
Table 10.2-3 for the model plant described in this Section. The costs for
the control options that include good combustion practices (Options 2, 3, 5,
and 7) were estimated as the difference between the costs presented in Table
.5.3-13 and the costs of both the combustor control presented in Tables 5.3-3
and 5.3-4 and of temperature control presented in Tables 5.3-5 and 5.3-6.
Overall, both capital and annualized costs in Table 10,2-3 are higher
for higher levels of control. Since good PM control is achieved at
baseline, no costs are presented for Options 1 and 2. Costs of Options 4
and 5 are the same as are the costs of Options 6 and 7. Total capital and
annualized costs for the most expensive option (Options 6 or 7) are
$8,190,000 and $2,570,000, respectively.
10.2.3 Energy Impacts
Table 10.2-4 presents a summary of the energy impacts associated with
.the control options for the model plant described in this section. The
electricity consumed for Options 1 to 7 were estimated from those presented
in Table 5.3-14 by subtracting the electricity consumed for temperature
control to 450°F (Option 1 in Table 5.3-14). The spray dryer with fabric
filter control options consume the most electricity (1,240 MWh/yr).
Auxiliary fuel is assumed to be fired during baseline. Thus, no increase in
auxiliary fuel use beyond baseline is expected for the control options.
10-25
-------
f\>
TABLE 10.2-3. COST StMMRf FOR SHALL MASS BURN HA TERM ALL HUG MODEL PLANT
RETROFIT CONTROL OPTIONS* (Two unite at 100 tpd)
total Capital Colt
Downtime Coat
Annual Izfld Capital and
Downtime Coit
Direct OOt Cost
fetal Annual Coat
Co»t Effective*!***
(S/ton HSU)
Facility Downtime
(Month*)
Option 1 Option 2 Option 3 Option 4 Option 5
0 0 2,050 3, BIO 3,810
0 0 235 235 235
0 0 300 531 531
0 0 72 498 498
0 . 0 1.83 1,250 1,250
0 0 7.24 IB. 80 ' 18.80
0 0 1 11
Option 6 Option 7
B. 190 8,190
235 235
1,110 1,110
654 654
2,190 2,190
32.90 32.90
1 1
All caata (except coat eff«ctlv«iuu») given In $1000. All cost* In December 1987 dollari.
-------
TABLE 10.2-4 ENERGY IMPACTS FOR SMALL MASS BURN ,
»ATERWALL COMBUSTOR CONTROL OPTIONS*
Option
1
2
3
4
5
6
7
Electrical Use
(MWh/yr)
0
0
92
600
600
1,420°
1,420°
Gas Use
(Btu/yr)
0
0
0
0
'0
0
0
aIncrease from baseline consumption.
Total electrical use excludes the electrical savings of not operating the
existing ESP's.
10-27
-------
10.3 LARGE RDF-FIRED COMBUSTOR
The model plant described in this section represents projected large
RDF-fired plants which will commence construction by November 1989 and will
be subject to the Section lll(d) guidelines rather than to the proposed
NSPS. The .model plant is the same as the one described in Section 6,1
except that baseline for the model includes good combustion practices and
temperature control to 450°F whereas the model plant discussed in
Section 6.1 does not. It is assumed that the downtime associated with
retrofitting APCD's for control options will take only 1 month per
combustor. This downtime period for this model plant is shorter than those
assumed for the model plant described in Section 6.1. In addition, access
and congestion for retrofitting APCD's are assumed to be moderate for this
model plant. A high access and congestion factor was assumed for the model
plant in Section 6.1. Table 10.3-1 summarizes the combustion, temperature,
particulate, and acid gas control technologies that were combined for each
of the control options described in Section 3.0. As with the model plant
described in Section 6.1, the model plant already achieves best PM control
at baseline; Option 1 to 3 are identical.
The environmental performances, costs, and energy impacts for baseline
and the control options were adjusted for those presented in Section 6.1 to
reflect the changes in baseline, downtime, and access/congestion. A summary
of these impacts and costs are presented in the following three sections.
10-3-1 Environmental Performance
Table 10.3-2 summarizes the environmental performances of baseline and
each control option. Because of the changes in baseline, baseline emissions
are equivalent to those presented under Control Options 1 to 3.
Furthermore, CDD/CDF emissions for Options 4 and 5 are 75 percent lower than
those of baseline, and CDD/CDF emissions for Option 6 and 7 are 99 percent
lower than baseline. CO emissions for the control options are equivalent
to those of baseline. The respective emission rates and-emission reductions
from baseline of the other pollutants (PM, SO-, and HC1) remains unchanged
from those presented in Section 6.1. Similarly, total solid waste disposal
rates of the control options also remain unchanged. Because the model plant
10-28
-------
TABLE 10.3-1 SUMMARY OP CONTROL OPTIOHS FOR LARGE RDF-FIRED MWC MODEL PLANT
Control Option Description
Particular* control
Acid Gai Control
Combustion
Modification*
Control
Existing ESP
Rebuilt
Additional
SCA
New Sorbent Spray
Fabric filter Injection Dryer
ro
to
1. Good Coobuttlon and
Temperature Control
2. Good PM Control with
Combustion Control
3. Beat PM Control and
Combustion and Temperature
Control
*, Good Acid Ga* Control,
Best PM Control and
Temperature Control
S. Good Acid Ga* Control
and Beat PK/Combust Ion/
Temperature Control
6. Beit Acid Ga* Control,
Best PM Control, and
Temperature Control
7. Best Acid Ca» Control and
Beit PM/Combustion^
Temperature Control
-------
TABLE 10.3-2 ENVIRONMENTAL PERFORMANCE SUMMARY FOR LARGE RUF-FIRED HUC MODEL PLANT
RETROFIT CONTROL OPTIONS*' (Two unit* of 1,000 tpd RDF each)
Baseline
total CDD/CDF Eral»»lon«
(ng/djcaj) 1000
Mg/yr 3.2E-3
£ Reduction v». i**ellne
CO Emiaaioos
(ppw) 150
H»/Tt 554
X Reduction vi. Baiellne
PH Enlisloni
(gr/dscf) 0.01
Kg/j-r 73
2 Reduction vs. Baieline.
i_> SO Eraisaloni
*p
-------
uses good combustion practices whereas the model plant described in Section
6.1 does not, baseline emissions of COD/CDF and CO in Table 10.3-2 are 87
and 25 percent lower, respectively, than those presented at baseline for the
large RDF-fired model plant in Section 6.1.
10.3.2 Costs
The total capital and annualized costs for each options are presented
in Table 10.3-3 for the model plant described in this section. The costs
for the control options that include good combustion practices (Options 2,
3, 5 and 7) were estimated as the difference between the costs presented in
Table 6.1-11 and the costs of the combustor control presented in Tables
6.1-3 and 6.1-4. Total capital costs presented in Table 10.3-3 for moderate
access and congestion were estimated from those presented in Section 6.1 for
high access and congestion. Direct capital costs for the model plant were
estimated by multiplying the direct capital costs presented in Section 6.1
an the ratio of the access and congestion factors. Indirect and contingency
costs were calculated from the direct capital costs using appropriate
multipliers. Similarly, downtime costs presented in Table 10.3-3 for one
month were prorated from those presented in Table 6.1-11 based on facility
downtimes.
Overall,-both capital and annualized costs in Table 10.3-3 are higher
for higher levels for control. Since best PM control is achieved at
baseline, no costs are presented for Options 1 to 3. Costs of Options 4 and
5 are the same as well as the costs of Options 6 and 7. Total capital and
annualized costs for the most expensive option (Options 6 or 7) are
$26,200,000 and $9,170,000, respectively.
10.3.3 Energy Impacts
Table 10.3-4 presents a summary of the energy impacts associated with
the control options for the model plant described in this section. The
spray dryer with fabric filter control options consume the most electricity
(7,710 MWh/yr). No increase in auxiliary fuel use beyond baseline is
expected for the control options.
10-31
-------
TABLE 10.}-} COST SUfMARY FOR LARGE RDF-FIRZD MIC H9DEL PLANT RETROFIT
CONTROL OPTIONS* (Two unit! ot 1,000 cpd RDF ««ch)
CO
Option 1 Option 2 Option 3 Option 4 Option 5 Option 6 Option 7
Total Capital Cote
Downtime Colt
Annu»Ur«d Capital and
Downtime Cost
Direct OtM Coat
Total Annual Coat
Co«t Effectiveness
($/ton RFD)
Facility Downtime
(Montha)
Total Compliance Time
(rtontk.)
000 2,240 2,240 26,200 26,200
0 0 0 3,260 3,260 3,260 3,260
000 724 724 3,670 3,870
0 0 0 1,790 1,790 2,980 2,960
000 2,640 2,640 8,170 8,170
0 0 0 4.00 4.00 12.26 12.26
000 1111
1 1.1 19 ' 19 25 25
All coit» («Kcepc coit »ff«ctIvetwii) given in $1000. All co»ti in December 1987 dollars and bated on
moderate acc«i*/con(«ation.
-------
TABLE 10.3-4. PLANT TOTAL ENERGY IMPACTS FOR CONTROL OPTIONS4
Option
1
2
3
4
5
6
7
Electrical Use
(MWh/yr)
0
0
0
615
615
13»300b
13,300b
Gas Use
(Btu/yr)
0
0
0
0
0
0
0
Increase from baseline consumption.
Total electrical use excludes the electrical savings of not operating the
existing ESP's.
10-33
-------
10.4 SHALL RDF-FIRED COMBUSTOR
The modi! plant described in this section represents projected small
RDF-fired plants whi'ch will commence construction by November 1989 and will
be subject to the Section lll(d) guidelines rather than to the proposed
NSPS. The model plant is the same as the one described in Section 6.2
except that baseline for the model includes good combustion practices
whereas the model plant discussed in Section 6.2 does not. It is assumed
that the downtime associated with retrofitting APCO's for control options
will taken only 1 month per combustor. This downtime period for this model
plant is shorter than those assumed for the model plant described in
Section 6.2. In addition, access and congestion for retrofitting APCD's are
assumed to be moderate for this model plant. A high access and congestion
factor was assumed for the model plant in Section 6.2. Table 10.4-1
summarizes the combustion, temperature, particulate, and acid gas control
technologies that were combined for each of the control options described in"
Section 3.0. As with the model plant described in Section 6.2, the model
plant already achieves best PM control at baseline; Options 1 to 3 are
identical.
The environmental performances, costs, and energy impacts for baseline
and the control options were adjusted for those presented in Section 6.2 to
reflect the changes in baseline, downtime, and access/congestion. A summary
of these impacts and costs are presented in the following three sections.
10.4.1 Environmental Performance
Table 10.4-2 summarizes the environmental performances of baseline and
each control option. Because of the change in baseline, baseline emissions
are equivalent to those presented under Control Options 1 to 3.
Furthermore, CDD/CDF emissions for Options 4 and 5 are 75 percent lower than
those of baseline, and CDD/CDF emissions for Options 6 and 7 are 99 percent
lower than baseline. CO emissions for the control options are equivalent to
those of baseline. The respective emission rates and emission reductions
from baseline of the other pollutants (PM, SO*, and HC1) remains unchanged
from those presented in Section 6.2. Similarly, total solid waste disposal
rates of the control options also remain unchanged. Because the model plant
uses good combustion practices whereas the model plant described in
10-34
-------
TABLE 10.4-1 SUHMARX OP CONTROL OPTIONS FOR SMALL RDF-FIRED MUG HOC EX PLANT
Control Option Description
inarticulate control
Combustion Temperature EMlstlng ESP Additional
Notification* Control Rebuilt Plate Are*
Acid GJJ Control
Hew
fabric Filter
Sorbent
Injection
Spray
Dryer
1 . Good Combust Ion and
tuc* Control
2. Good PM Control with
Conibmtlon and Temp«ratur«
Control
3. Beat PH Control and
CombuiClon end Temperature
Control
O
I
u>
01
i. Good Acid Gas Control,
Best PM Control and
Temperature Control
5. Good Acid Caj Control
and Be*t PH/Corabusclon/
T«a|)«rature Control
6. Best Acid Ga« Control,
Beat PM Control, and
tur* Control
J. Best AcId Gat Control
Beit PH/CocobuJtlon/
Tenpecature Control
and
-------
TABLE 10,*-2 ENVIRONMENTAL PERFORMANCE SUMURY FOR SMALL RDF-FIRED KHC ICDEL PLANT RETROFIT CONTROL OPTIONS
Total CDD/CD7 Emission*
(nf/dgco)
Hf Syr
I Reduction v*. Baseline
CO Ealsslons
(ppcnv)
Mt/yr
I Reduction vf • Baiellne
I'M Emissions
(f r/dacf )
H«/yr
X Reduction v*. Baseline
SO Emissions
-------
Section 6.1 does not, baseline emissions of CDO/CDF and CO in Table 10.4-2
are 80 and 71 percent lower, respectively, than those presented at baseline
for the small ROF-fired model plant in Section 6.2.
10.4.2 Costs.
The total capital and annualized costs of each options are presented in
Table 10.4-3 for the model plant described in this section. The costs for
the control options that include good combustion practices (Options 2, 3, 5,
and 7} were estimated as the difference between the costs presented in Table
6.2-11 and the costs of the combustor control presented in Tables 6.2-3 and
6.2-4. Total capital costs presented in Table 10.4-3 for moderate access
and congestion were estimated from those presented in Section 6.2 for high
access and congestion. Direct capital costs for the model plant were
estimated by multiplying the direct capital costs presented in Section 6.2
and the ratio of the access and congestion factors. Indirect and
contingency costs were estimated from the direct capital costs appropriate
multipliers. Similarly, downtime costs presented in Table 10.3-3 for one
month were prorated from those presented in Table 6.2-11 based on facility
downtimes.
Overall, both capital and annualized costs in Table 10.4-3 are higher
for higher levels of control. Since best PM control is achieved at
baseline, no costs are presented for Options 1 to 3. Costs of Options 4 and
5 are the same as well as the costs of Options 6 and 7. Total capital and
annualized costs for the most expensive option (Options 6 or 7} are
$14,100,000 and $4,700,000, respectively.
10.4.3 Energy Impacts
Table 10.4-4 presents a summary of the energy impacts associated with
the control options for the model plant described in this section. The
spray dryer with fabric filter control options consume the most electricity
(3,060 MWh/yr). No increase in auxiliary fuel use beyond baseline is
expected for the control options. The incremental electrical and auxiliary
fuel consumptions from baseline in Table 10.4-4 are the same as those for
the model plant in Section 6.2.
1.0-37
-------
TABLE 10.4-3 COST SUMMARY FOR SMALL RDF-FIRED HUC MODEL PLANT RETROFIT CONTROL OPTIONS
(Two unit* of 300 tpd each)
Total Capital Co»t
DovntUo* Cost
Annual Ized Capital and
Downtime Colt
Direct OW Cost
Total Annual Cost
Colt Effectlvene**
Option 1
0
0
0
0
0
0
Option 2
0
0
0
0
0
O
Ope Ion 3
0
0
0
0
0
0
Option 4 Option 5
5,060 5,110
978 978
801 801
8*0 840
1,930 1,930
9.6% 9.65
Option 6
H.100
978
1,990
1.240
3,950
19.80
Option 7
14,100
978
1,990
1,2*0
3.950
19.80
(Sfton RDF)
O
' Facility Dovnt iae
O> (Honth.)
Total Confilianc* Tina 1 1 1 19 19 25 25
(Month*)
All cost* (except colt effecclv«»i*) given In $1000. All coita ace In December 1987 dollar* and ace baled
on moderate accet* and con*e*tlon.
-------
TABLE 10.4-4. PLANT TOTAL ENERGY IMPACTS FOR CONTROL OPTIONS*
Option
1
2
3
4
5
6
7
Electrical Use
(MWh/yr)
0
0
0
61S
615
4,150b
4,l50b
Gas Use
(Btu/yr)
0
0
0
0
0
0
0
alncremenatal use from baseline.
Excludes the electrical credit of not operating the ESP's.
10-39
-------
10.5 ROTARY WATERWALL COMBUSTOR
The model plant described In this section represents projected rotary
waterwall plants which will commence construction by November 1989 and will
be subject to the Section lll(d) guidelines rather than to the proposed
NSPS. The model plant is the same as the one described'in Section 9.1
except that baseline for the model includes good combustion practices
whereas the model plant discussed in Section 9.1 does not. Table 10.5-1
summarizes the combustion, temperature, particulate, and acid gas control
technologies that were combined for each of the control options described in
Section 3.0. As with the model plant described in Section 9.1, the model
plant already achieves good PM control at baseline; Option 1 and 2 are
identical.
The environmental performances, costs, and energy impacts for baseline
and the control options were adjusted for those presented in Section 9.1 to
reflect the changes in baseline. A summary of these impacts and costs are
presented in the following three sections.
10.5.1 Environmental Performance
Table 10.5-2 summarizes the environmental performances of baseline and
each control option. Because of the changes in baseline, baseline emissions
are equivalent to those presented under Control Options 1 to 2.
Furthermore, CDO/CDF emissions for Options 4 and 5 are 75 present lower than
those of baseline, and CDD/CDF emissions for Option 6 and 7 are 99 percent
lower than baseline. CO emissions for the control options are equivalent
to those of baseline. The respective emission rates and emission reductions
from baseline of the other pollutants (PM, SQ», and KC1) remains unchanged
from those presented in Section 9.1. Similarly, total solid waste disposal
rates of the control options also remain unchanged. Because the model plant
uses good combustion practices whereas the model plant described in Section
6.1 does not, baseline emissions of CDD/CDF in Table 10.5-2 are 80 percent
lower than those presented at baseline for the rotary waterwall model plant
in Section 9.1.
10.5.2 Costs
The total capital and annualized costs for each options are presented
in Table 10.5-3 for the model plant described in this section. The costs
for the control options that include good combustion practices (Options 2,
10-40
-------
TABLE 10.5-1 SUMUitX OF CONTROL OPTIONS FOR ROTARY UATERMAU. OOM8USIOR
PartlculatB Control
Acid Gas Control
Combustion Temperature Existing ESP
Control Option Description HodlfIcatloni Control 'Rebuilt
Additional
Plate Ar«4
Hen Sorb«nt Spray
t-'mbrlc Filter Injection Dryer
1. Good Combustion and
ature Control
2. Good PH Control with
Co^uscion Control and
Tca(i«r*tuc« Control
3. B«*t PH Central *nd
Coobujtlon «nd Tanp«ratura
Control
4. Good Acid Gas Control,
Beit PH Control and
Temperature Control
S. Good Acid Cms Control
and "Beit PM/ Combustion/
feofieratura Control
6. Best Acid Gas Control,
Bast PH Control, and
leaptrttutt Control
7. Rest Acid C»» Control and
Bait PH/Conbujtlon/
tuco Control
-------
o
1
ISi
TABLE 10.5-2 ENVIRONMENTAL PERFORMANCE SUMMARY FOR ROTARY WATERWALL
HUC MODEL PLAKT RETROFIT COWTROt OPTIONS.
(Two unit* of 250 tpd «»ch)
Total COO/ CDF Em In lota
(n«/nd*rd conditions are
1 ataoiphcce and JO t.
-------
o
I
«•
to
TABLE 10.5-3 COST SUMMARY FOR ROTARY UATERUAiL KWC MODEL PLAKT RETROFIT CONTROL OPTIONS
(Two unit* of 2SO tpd each)
Option 1
Total Capital Coat 0
Downtown Coat 0
Annual laid Capital and
Downtime Coat 0
Dlract OtM Co«t 0
total Annual Cost 0
Co«t Eff «ctLv*nait 0
(S/ton HSU)
Facility Dovxitbm 0
< Month. >
Total Coopllanca Time 1
(Hanth»)
Option 2 Optltui 3 Option 4 'Option 5 Option 6 Option ?
0 1,990 4,1*0 4.UO 10,600 10,600
0 ia8 588 588 SBfl 588
0 339 622 622 1,470 1,470
0 2<> 6*2 6*2 913 913
0 45? l.iOO 1.550 2,860 2.960
0 2.7* 9.00 9.30 17,80 17.80
0 11111
1 19 19 19 25 23
*A11 co«ti («Jtc«pt coit affactlvcnaaa) (Ivan In $1000, All coat* In Oaecfflbac 1997 dollar.
-------
3, 5 and 7) were estimated as the difference between the costs presented in
Tables 9.1-14 and the costs of the combustor presented in Table 9.1-4 and
9.1-5,
Overall, both capital and annualized costs in Table 10.5-3 are higher
for higher levels for control. Since good PM control is achieved at
baseline, no costs are presented for Options 1 and 2. Costs of Options 4
and 5 are the same as well as the costs of Options 6 and 7. Total capital
and annualized costs for the most expensive option (Options 6 or 7) are
$10,600,000 and $3,490,000, respectively.
10.5.3 Energy Impjcts
Table 10.5-4 presents a summary of the energy impacts associated with
the control options for the model plant described in this section. The
spray dryer with fabric filter control options consume the most electricity
(2,050 MWh/yr). No increase in auxiliary fuel use beyond baseline is
expected for the control options. The incremental electrical and auxiliary
fuel consumptions from baseline in table 10.5-4 are the same as those for
the model plant in Section 9.1.
10-44
-------
TABLE 10.5-4. PLANT TOTAL ENERGY IMPACTS FOR CONTROL OPTIONS3
Option
1
2
3
4
5
6
7
Electrical Use
(HWh/yr)
0
0
102
672
672
2,520b
2,52Qb
Gas Use
(Btu/yr)
0
• o
0
0
0
4
0
0
alncrease from baseline consumption.
Excludes the electrical credit of not operating the ESP's.
10-45
-------
TECHNICAL REPORT DATA
(ftetae read Instructions on the reverse before compigtingf
1, REPORT NO.
EPA-45Q/3-89-27e
2.
3, RECIPIENT'S ACCESSION NO.
4. TITLE AND SUBTITLE
Municipal Waste Combustors - Background Information for
Proposed Guidelines for Existing Facilities
S. SIPORTOATS
August 1989
6. PERFORMING ORGANIZATION CODE
?. AUTHOR(S»
8, PERFORMING ORGANIZATION REPORT NO.
9. PERFORMING ORGANIZATION NAME AND ADDRESS
Office of Air Quality Planning and Standards
U.S. Environmental Protection Agency
Research Triangle Park, North Carolina 27711
10. PROGRAM ELEMENT NO,
11. CONTRACT/GRANT NO.
68-02-4378
12. SPONSORING AGENCY NAME AND A.DDRESS . _
DAA for Air Quality Planning and Standards
Office of Air and Radiation
U.S. Environmental Protection Agency
Research Triangle Park, North Carolina 27711
13. TYPE OF REPORT AND PERIOD COVERED
Final
14. SPONSORING AGENCY CODE
200/04
IS. SUPPLEMENTARY NOTES
16. ABSTRACT
Major categories of existing municipal waste combustor facilities are
identified. Representative model plants are identified and serve as the basis of
the evaluations presented. The technical feasibility, environmental benefits, and
cost impacts of various retrofit options are presented for each of the model plants.
17.
KEY WORDS AND DOCUMENT ANALYSIS
DESCRIPTORS
fiNOED Tf RMS
c. COSATI Field/Group
Air Pollution
Municipal Waste Combustors
Incineration
Pollution Control
Costs
Air Pollution Control
13B
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