&EPA
United States
Environmental Protection
Agency
Industrial Environmental Research
Laboratory
Research Triangle Park NC 27711
EPA-600/7-79-178e
November 1979
Technology Assessment
Report for Industrial
Boiler Applications:
Fluidized-bed Combustion
Interagency
Energy/Environment
R&D Program Report
-------
RESEARCH REPORTING SERIES
Research reports of the Office of Research and Development, U.S. Environmental
Protection Agency, have been grouped into nine series These nine broad cate-
gories were established to facilitate further development and application of en-
vironmental technology. Elimination of traditional grouping was consciously
planned to foster technology transfer and a maximum interface in related fields.
The nine series are:
1. Environmental Health Effects Research
2. Environmental Protection Technology
3. Ecological Research
4. Environmental Monitoring
5. Socioeconomic Environmental Studies
6. Scientific and Technical Assessment Reports (STAR)
7. Interagency Energy-Environment Research and Development
8. "Special" Reports
9. Miscellaneous Reports
This report has been assigned to the INTERAGENCY ENERGY-ENVIRONMENT
RESEARCH AND DEVELOPMENT series. Reports m this series result from the
effort funded under the 17-agency Federal Energy/Environment Research and
Development Program. These studies relate to EPA's mission to protect the public
health and welfare from adverse effects of pollutants associated with energy sys-
tems. The goal of the Program is to assure the rapid development of domestic
energy supplies in an environmentally-compatible manner by providing the nec-
essary environmental data and control technology. Investigations include analy-
ses of the transport of energy-related pollutants and their health and ecological
effects; assessments of, and development of, control technologies for energy
systems; and integrated assessments of a wide'range of energy-related environ-
mental issues.
EPA REVIEW NOTICE
This report has been reviewed by the participating Federal Agencies, and approved
for publication. Approval does not signify that the contents necessarily reflect
the views and policies of the Government, nor does mention of trade names or
commercial products constitute endorsement or recommendation for use.
This document is available to the public through the National Technical Informa-
tion Service, Springfield, Virginia 22161.
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EPA-600/7-79-178e
November 1979
Technology Assessment Report
for Industrial Boiler Applications
Fluid! zed-bed Combustion
by
C.W. Young, J.M. Robinson, C.B. Thunem,
and P.P. Fennelly
GCA/Technology Division
Burlington Road
Bedford, Massachusetts 01730
Contract No. 68-02-2693
Program Element No. INE825
EPA Project Officer: D. Bruce Henschel
Industrial Environmental Research Laboratory
Office of Environmental Engineering and Technology
Research Triangle Park, NC 27711
Prepared for
U.S. ENVIRONMENTAL PROTECTION AGENCY
Office of Research and Development
Washington, DC 20460
-------
ABSTRACT
This technology assessment report discusses the use of fluidized-bed
combustion (FBC) in industrial boilers <73 MWt (250 * 106 Btu/hr) thermal
capacity. The information is being provided to support the industrial boiler
control technology assessment study being conducted by the Environmental
Protection Agency. The emphasis of the study is on coal combustion. The
principles of FBC operation and emission control are identified along with
the best systems to meet optional levels of control for S02, NOX, and par-
ticulate emissions. The best systems are evaluated based on status of
development, performance, cost impact, energy impact, and environmental
impact.
Comparison is made with conventional boiler systems, to provide perspec-
tive relative to the advantages and disadvantages of FBC. Although AFBC cost
and performance remain to be fully demonstrated in commercial application,
available data indicate that AFBC should be a candidate for any new coal-fired
industrial boiler installation where S02 contol is required.
ii
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PREFACE
The 1977 Amendments to the Clean Air Act required that emission standards
be developed for fossil-fuel-fired steam generators. Accordingly, the U.S.
Environmental Protection Agency (EPA) recently promulgated revisions to the
1971 New Source Performance Standard (NSPS) for electric utility steam genera-
ting units. Further, EPA has undertaken a study of industrial boilers with the
intent of proposing a NSPS for this category of sources. The study is being
directed by EPA's Office of Air Quality Planning and Standards, and technical
support is being provided by EPA's Office of Research and Development. As part
of this support, the Industrial Environmental Research Laboratory at Research
Triangle Park, North Carolina, prepared a series of technology assessment re-
ports to aid in determining the technological basis for the NSPS for industrial
boilers. This report is part of that series. The complete report series is
listed below:
Title
The Population and Characteristics of Industrial/
Commercial Boilers
Technology Assessment Report for Industrial Boiler
Applications: Oil Cleaning
Technology Assessment Report for Industrial Boiler
Applications: Coal Cleaning and Low Sulfur Coal
Technology Assessment Report for Industrial Boiler
Applications: Synthetic Fuels
Technology Assessment Report for Industrial Boiler
Applications: Fluidized-Bed Combustion
Technology Assessment Report for Industrial Boiler
Applications: NOx Combustion Modification
Technology Assessment Report for Industrial Boiler
Applications: NOX Flue Gas Treatment
Technology Assessment Report for Industrial Boiler
Applications: Particulate Collection
Technology Assessment Report for Industrial Boiler
Applications: Flue Gas Desulfurization
Report number
EPA-600/7-79-178a
EPA-600/7-79-178b
EPA-600/7-79-178c
EPA-600/7-79-178d
EPA-600/7-79-178e
EPA-600/7-79-178f
EPA-600/7-79-178g
EPA-600/7-79-178h
EPA-600/7-79-178i
ill
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These reports will be integrated along with other information in the
document, "industrial Boilers — Background Information for Proposed Standards,"
which will be issued by the Office of Air Quality Planning and Standards.
Therefore, for regulatory purposes, the assessment in this report — and in the
companion series of reports — must be viewed as preliminary, pending the re-
sults of the more extensive examination of impacts to be conducted by the
Office of Air Quality Planning and Standards under Section 111 of the Clean
Air Act.
iv
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CONTENTS
Abstract ............................... ii
Figures ................................ Xi
Tables ................................
Acknowledgement ............................
1.0 Executive Summary ..................... 1
1.1 Introduction ....................... 1
1.1.1 Purpose of the report ................ 1
1.1.2 Scope of the study ................. 1
1.2 Systems of emission reduction .............. 4
1.2.1 Principles of control ................ 4
1.2.2 Control techniques considered ............ 4
1.2.3 Degrees of control considered ............ 6
1.2.4 Best control techniques ............... 6
1.3 Cost impact of best control techniques .......... 14
1.3.1 Comparison with uncontrolled conventional
systems ...................... 14
1.3.2 Cost of S02 control ................. 15
1.3.3 Cost of particulate control ............. 18
1.3.4 Cost of NOX control ................. 19
1.4 Energy impact of best control techniques ......... 20
1.4.1 Basis of energy impact analysis ........... 20
1.4.2 Energy penalty of air pollution control
by AFBC ...................... 21
1.4.3 SC>2 control energy impact .............. 21
1.4.4 NOx control energy impact .............. 22
1.4.5 Particulate control energy impact .......... 22
1.5 Environmental impact of implementing best systems
of control ....................... 23
1.5.1 Impact of control techniques ............ 23
1.5.2 Solid waste disposal ................ 25
1.6 Commercial availability of AFBC ............. 26
1.7 References ........................ 29
2.0 Emission Control Techniques for Fluidized-Bed
Combustion ........................ 30
2.1 Introduction ....................... 30
2.1.1 System description — Coal-fired
f luidized-bed boiler ............... 31
2.1.2 Mechanisms for 862 control ............. 34
2.1.3 Mechanisms for NOX control ............. 35
2.1.4 Mechanisms for particulate control ......... 36
2.1.5 Differences in possible AFBC industrial
boiler designs .................. 39
v
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CONTENTS (continued)
2.1.6 Superficial velocity 43
2.2 Status of development 44
2.2.1 U.S. Department of Energy development
programs 45
2.2.2 State of Ohio's development program 48
2.2.3 Commercial availability of fluidized-bed
boilers 49
2.2.4 Summary of existing f luidized-bed units 51
2.2.5 Applicability of fluidized-bed combustion to
industrial uses 51
2.2.6 Projections of potential market for
fluidized-bed combustion 57
2.2.7 Recent improvements and ongoing research
and development 59
2.3 System performance — S02 control 64
2.3.1 Primary design/operating factors affecting
S02 emission reduction 65
2.3.2 Secondary factors affecting S02 reduction 77
2.3.3 Other factors 82
2.3.4 Factors affecting boiler performance 82
2.4 System performance — NOx control 84
2.4.1 Factors affecting NOX formation and emission
reduction 84
2.4.2 Temperature 85
2.4.3 Excess air 88
2.4.4 Gas phase residence time 88
2.4.5 Fuel nitrogen 89
2.4.6 Factors affecting local reducing conditions. ... 89
2.4.7 Coal particle size 92
2.4.8 NOX emission data summary 93
2.4.9 Potential methods of enhancing NOx control
in AFBC boilers 95
2.5 System performance — Particulate control. 99
2.5.1 FBC boiler design parameters affecting
particulate emissions 99
2.5.2 FBC boiler operating factors affecting
particulate control device performance 103
2.5.3 Particulate emission data from AFBC units 110
2.5.4 Summary of particulate emission data 123
2.5.5 Impacts of particle control on boiler
operation 124
2.5.6 Documentation 124
2.6 Pressurized FBC 125
2.7 References 126
3.0 Candidates for Best System of Emission Reduction 136
3.1 Criteria for selection 136
3.1.1 Selection of optional emission control
levels 138
3.1.2 Selection of S02 emission levels 139
vi
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CONTENTS (continued)
3.1.3 Selection of NOx emission levels 144
3.1.4 Selection of particulate emission levels 146
3.1.5 Impact of averaging time 149
3.2 Best control system for coal-fired boilers 150
3.2.1 S02 emissions 150
3.2.2 NOx emissions 173
3.2.3 Particulate emissions 181
3.3 Other fuels 190
3.4 Summary 190
3.4.1 S02 .- 194
3.4.2 NOX 195
3.4.3 Particulate 195
3.5 References 197
4.0 Cost Impact of Implementing Best Systems of
Emission Control 201
4.1 Introduction 201
4.1.1 Background 201
4.1.2 Data sources 203
4.1.3 Data uncertainties 203
4.1.4 Major contributors to emission control
costs for S02 205
4.1.5 Cost related with final particulate
removal 209
4.1.6 Most important cost items 210
4.2 Groundrules for defining cost basis 211
4.2.1 Capital costs 212
4.2.2 Operating and annualized costs 212
4.2.3 Specific vendor quotes ..... 215
4.2.4 Other FBC boiler cost estimates 220
4.3 Cost analysis for implementing best system
of S02 control 220
4.3.1 Capital costs 221
4.3.2 Operating costs 224
4.3.3 Cost of best systems of S02 control 224
4.3.4 "Commercially-offered" AFBC industrial
boilers versus "best systems" of S02
control 232
4.3.5 Cost comparison: AFBC "best system" designs
versus conventional boilers without S0£
emission control 239
4.3.6 Cost effectiveness of AFBC S02 control — Unit
cost basis 248
4.3.7 Comparison of GCA data with other independent
estimates of AFBC costs 251
4.3.8 Sensitivity analysis — Cost 259
4.4 Cost of best system particulate control cost from
S02 control costs 271
4.4.1 Attempt to isolate particulate control costs
from S02 control costs 271
vii
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CONTENTS (continued)
A.4.2 Cost of particulate control for AFBC boilers —
Excluding influence of S02 277
4.4.3 Cost of particulate control for AFBC boilers —
Including influence of S02 control 280
4.5 Cost of NOx control 284
4.6 Summary — Cost of best systems emission control in
coal-fired AFBC industrial boilers 284
4.6.1 S02 control 284
4.6.2 Comparison with FGD 287
4.6.3 Particulate control 287
4.6.4 NOX control 289
4.7 References 290
5.0 Energy Impact — Fluidized-Bed Combustion Versus
Conventional Boilers 294
5.1 Introduction 294
5.2.1 Coal handling 298
5.2.2 Boiler feedwater treatment and auxiliary
pumping requirements 300
5.2.3 Forced draft and induced draft fan power 300
5.2.4 Limestone and spent solids handling 304
5.2.5 Total auxiliary power requirements 307
5.3 Inherent energy losses in the FBC system 310
5.3.1 Flue gas heat loss 310
5.3.2 Solids heat loss 311
5.3.3 Combustion losses 313
5.3.4 Radiative and unaccounted-for losses 315
5.3.5 Total inherent energy penalties 316
5.4 Energy impact of S02 control by AFBC 318
5.4.1 Efficiency 319
5.4.2 Energy penalty as kW/kg 502 removed 321
5.4.3 Efficiency of AFBC as a percentage of
thermal input 323
5.5 Sensitivity analysis 326
5.5.1 Calcium to sulfur ratio 328
5.5.2 Sorbent reactivity 329
5.5.3 Spent solids heat recovery 330
5.5.4 Coal drying requirement 330
5.5,5 Excess air effect 331
5.5.6 Combustion efficiency 333
5.6 Energy impact of NOX control 334
5.7 Energy impact of particulate control 334
5.7.1 Comparison of fabric filters and
electrostatic precipitators 337
5.7.2 Impact of multitube cyclone use 337
5.8 Summary 338
5.8.1 S02 control 338
5.8.2 Particulate control 342
5.8.3 NOX control 342
5.9 References 343
Vlli
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CONTENTS (continued)
6.0 Fluidized-Bed Combustion Environmental Impact 345
6.1 Introduction 345
6.1.1 Emission streams 345
6.1.2 Major issues 347
6.2 Environmental impact of coal-fired AFBC 350
6.2.1 Air pollution 350
6.2.2 Solid waste 360
6.2.3 Water pollution 382
6.3 Oil-fired AFBC 383
6.4 Summary 383
6.4.1 Impact of emission control technique 383
6.4.2 Solid waste disposal 384
6.5 References 385
7.0 Emission Source Test Data 387
7.1 Introduction 387
7.2 Emission source test data for coal-fired
atmospheric FBC boilers 390
7.3 Test methods 422
7.3.1 Babcock and Wilcox (B&W) 6 ft * 6 ft unit 422
7.3.2 Babcock and Wilcox (B&W) 3 ft * 3 ft unit 426
7.3.3 National Coal Board - 3 ft * 1.5 ft unit 430
7.3.4 Pope, Evans, and Robbins 431
7.3.5 FluiDyne 433
7.3.6 National Coal Board — 6 in. diameter unit 433
7.3.7 Argonne National Laboratory (ANL) 434
7.3.8 Babcock and Wilcox, Ltd 435
7.4 Description of test facilities 435
7.4.1 Babcock and Wilcox (B&W) - 6 ft * 6 ft unit 435
7.4.2 Babcock and Wilcox 3 ft * 3 ft unit 439
7.4.3 National Coal Board 3 ft x 1.5 ft unit 441
7.4.4 Pope, Evans, and Robbins FBM unit 441
7.4.5 Babcock and Wilcox, Ltd. Renfrew unit 444
7.4.6 FluiDyne 1.5 ft x 1.5 ft unit 446
7.4.7 FluiDyne 3.3 ft x 5.3 ft unit 446
7.4.8 National Coal Board 6 in. diameter unit 449
7.4.9 Argonne National Laboratories 6 in. unit 451
7.5 Summary of emission source test data 453
7.5.1 Babcock and Wilcox Company 6 ft x 6 ft unit 474
7.5.2 Babcock and Wilcox 3 ft x 3 ft unit 476
7.5.3 National Coal Board 3 ft x 1.5 ft test unit 478
7.5.4 Pope, Evans, and Robbins 481
7.5.5 Babcock and Wilcox, Ltd ,. 484
7.5.6 FluiDyne 1.5 ft x 1.5 ft unit 485
7.5.7 FluiDyne 3.3 ft x 5.3 ft vertical slice
combustor. . 486
7.5.8 National Coal Board 6 in. diameter unit 487
7.5.9 Argonne National Laboratory (ANL) 488
ix
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CONTENTS (continued)
7.6 Derivation of Ca/S ratios presented in Section 3.0
for "best system" of SC>2 emission reduction ...... 489
7.7 Comparison of experimental data with Westinghouse
SC-2 removal kinetic model 490
7.7.1 Westinghouse studies 490
7.7.2 GCA calculations based on the Westinghouse
model 503
7.7.3 Influence of fluidization parameters assumed in
the Westinghouse model 505
7.8 Emission source test data for oil-fired AFBC boilers. . . 511
7.9 Emission source test data for gas-fired AFBC boilers. . . 512
7.10 References 513
Appendices
A. First tier of AFBC cost estimates 517
B. Cost basis used in other industrial FBC boiler
cost estimates 554
C. Detailed energy and cost tabulations 560
D. Westinghouse estimates of AFBC industrial
boiler cost 591
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FIGURES
Number Page
1 Typical industrial FBC boiler ............... 32
2 Johnston Boiler Company's combination watertube/firetube
FBC boiler ........................ 42
3 Atmospheric FBC industrial boilers — occurrence of
various boiler parameters by capacity range ....... 58
4 Projected desulfurization performance of atmospheric
fluidized-bed coal combustor, based upon model
developed by Westinghouse ................ 67
5 Sulfur dioxide reduction using limestone 1359 in a bed
of sintered ash, Pope, Evans, and Robbins ........ 70
6 Sulfur removal performance for typical sorbents (projected
using Westinghouse kinetic model) ............ 72
7 Ca/S molar feed required to maintain 90 percent sulfur
removal in AFBC, as projected by the Westinghouse
model ........ .................. 73
8 Ca/S molar feed required to maintain 90 percent sulfur
removal in AFBC with Carbon limestone, as projected
by the Westinghouse model ................ 75
9 Ca/S molar feed required to maintain 90 percent sulfur
removal in AFBC with limestone 1359, as projected
by the Westinghouse model .......... . ..... 76
10 Summary of experimental 862 reduction data for AFBC
test units .................... .... 78
11 S02 reduction as a function of bed temperature (ANL) . ... 81
12 NOx versus bed temperature, equivalence ratio 0.847
(18 percent excess air) ................. 86
13 NOx emission rate as a function of bed temperature based
on testing in the PER Fluidized-Bed Module (FBM) ..... 87
XI
-------
FIGURES (continued)
Number Page
14 NO concentrations at different levels above distributor
plate of 30 x 30 cm combustor reported by Massachusetts
Institute of Technology 91
15 Reduction in NO versus Ca/S (ANL) 91
16 Summary of NOX emission data from experimentation in
AFBC test units 94
17 Staged bed technique for NO control recommended by
investigators at MIT 98
18 Control of particulate emissions from an atmospheric
pressure FBC boiler 104
19 Resistivity of fluidized-bed particulate emissions 106
20 Typical overall collection efficiency of axial-entry
cyclones 109
21 Particle size distribution before final control device. . . 112
22 Typical particle size distribution of elutriated
material measured at Argonne National Laboratory 114
23 Particulate emissions as a function of temperature as
determined by PER in simulated CBC operation 118
24 Fractional efficiency of the primary and secondary
cyclones during experimentation in the NCB-CRE 36 in. x
18 in. test unit 120
25 Uncontrolled particulate emission rate versus superficial
velocity - Stone 7 121
26 Summary of S0£ reduction data measured in AFBC
experimentation 158
27 Summary of NOX data from experimental AFBC units 174
28 NOx emissions from experimental FBC units as a function
of capacity 179
29 Cost of final particulate control for AFBC industrial
boilers 184
Xll
-------
FIGURES (continued)
Number Page
30 Annual fixed charge of AFBC with S02 control 228
31 Total operating cost of AFBC with S02 control 229
32 Total annual cost of AFBC with S02 control 230
33 FBC cost variation as a function of superficial velocity,
estimated by Babcock and Wilcox 234
34 AFBC cost as a function of Ca/S molar feed ratio (All
other design/operating parameters constant) 237
35 Cost comparison: AFBC boilers with 862 control versus
uncontrolled conventional boilers; Eastern high
sulfur coal 244
36 Cost comparison: AFBC boilers with S02 control versus
uncontrolled conventional boilers; Eastern low
245
37
38
39
40
41
42
43
44
45
46
47
Cost comparison: AFBC boilers with S02 control versus
uncontrolled conventional boilers; subbituminous coal . .
Unit cost of S02 control in AFBC boilers with capacity
of 8 8 to 58.6 MWt (30 to 200 x 106 Btu/hr)
Cost of S02 control in AFBC ($/kg S02 removed) versus
Cost of AFBC with S02 control versus combustion
Cost of AFBC with S02 control versus excess air
Cost of AFBC at a capacity of 22 MWt with S02 control
versus plant load factor
246
250
252
253
254
257
258
265
266
267
269
Xlll
-------
FIGURES (continued)
Number Page
48 Cost of SOa control in AFBC ($/kg S02 removed) versus
plant load factor 270
49 Cost of final particulate control for AFBC industrial
boilers 283
50 Schematic of AFBC industrial boiler including auxiliary
equipment (assumes carbon burnup cell will not be
necessary) 297
51 Station efficiency for AFBC and uncontrolled conventional
boilers 320
52 Boiler efficiency as a function of Ca/S molar feed ratio. . 328a
53 Boiler efficiency as a function of excess air rate 332
54 FBC flow diagram 346
55 Land requirements for FBC burning high sulfur coal using
medium reactivity limestone 367
56 Land use requirements for disposal of solid waste 368a
57 Results of SC-2 emission testing at Renfrew, Scotland
FBC boiler reported by B&W, Ltd 420
58 Results of NOX emission testing at Renfrew, Scotland
FBC boiler reported by B&W, Ltd 420
59 Sulfur retention data in FluiDyne's 0.46 m x 0.46 m
(1.5 ft x 1.5 ft) FBC unit 421
60 Furnace outlet gas sampling for EPRI/B&W 6 ft x 6 ft
unit 423
61 Arrangement of cyclone inlet and outlet dust sampling
equipment for EPRI/B&W 6 ft x 6 ft unit 424
62 Cyclone inlet and outlet dust sampling probe for
EPRI/B&W 6 ft x 6 ft unit 425
63 Gas sampling system employed by B&W at wet scrubber
inlet 428
64 Overview of gas sampling and analysis system employed
by B&W at wet scrubber inlet 428
xiv
-------
FIGURES (continued)
Number Page
65 Particulate sampling probe used in B&W
investigations 429
66 Schematic diagram of gas sampling system used by PER
during FBM experiments 432
67 ANL gas sampling an;1 analysis system 434
68 Fluidized-bed combustion development facility 436
69 Schematic diagram of B&W 3 ft x 3 ft test unit 440
70 Schematic diagram of CRE 18 in. x 72 in. FBC facility
tested by NCB 442
71 Schematic diagram of PER-FBM test facility 443
72 Schematic of the B&W, Ltd. designed Renfrew unit 445
73 FluiDyne 1.5 ft x 1.5 ft pilot-scale FBC combustor 447
74 FluiDyne 3.3 ft x 5.3 ft vertical slice FBC combustor . . . 448
75 National Coal Board 6 in. diameter FBC unit 450
76 ANL 6 in. diameter bench-scale fluidized-bed combustion
test unit 452
77 Overall diagram of ANL bench-scale equipment 452
78 Argonne National Laboratory, 6 in. diameter test unit
using limestone 1359, 25 ym average particle size .... 491
79 Argonne National Laboratory, 6 in. diameter test unit
using limestone 1359, 177 ym x Q particle size
distribution 492
80 National Coal Board, 36 in. x 18 in. diameter combustor
using limestone 18, 1,680 ym x 0 particle size
distribution 493
81 Argonne National Laboratory, 6 in. diameter test unit
using calcined limestone 1359, 25 ym average particle
size 494
82 Argonne National Laboratory, 6 in. diameter test unit
using limestone 1359, 490 to 630 ym average particle
size 495
xv
-------
FIGURES (continued)
Number Page
83 National Coal Board, 36 in. x 18 in. combustor using
dolomite 1337, 1,680 x 0 ym particle size
distribution 496
84 National Coal Board, 36 in. x 18 in. combustor using
limestone 18, 1,680 x 0 urn particle size
distribution 497
85 National Coal Board, 6 in. diameter test unit using
U.K. limestone, 125 ym x 0 particle size
distribution 498
86 National Coal Board, 6 in. diameter test unit using
limestone 1359, 1,680 ym x 0 and 125 ym x 0 particle
size distribution 499
87 National Coal Board, 6 in. diameter and 36 in. * 18 in.
combustor using limestone 18, 1,680 ym particle size
distribution 500
88 Argonne National Laboratory and National Coal Board,
6 in. diameter test units using U.K. limestone 501
89 Argonne National Laboratory and National Coal Board,
6 in. diameter test units using limestone 1359 502
90 Comparison of experimental SC-2 data with projections
based on Westinghouse model 504
xvi
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TABLES
Number Page
1 Summary of Boiler Design/Operating Conditions 3
2 Optional Levels of Control to be Supported —
Atmospheric Fluidized-Bed Combustion of Coal 7
3 Range of Experimental Ca/S Ratios Necessary to
Meet Optional S02 Control Levels as Observed in
Testing at or near "Best System" Conditions 9
4 Optional NOx Control Levels 11
5 Optional Particulate Control Levels 12
6 Control Efficiencies Required to Meet Optional
Particulate Control Levels 13
7 Summary of AFBC Boiler Cost with S02 Control,
$/106 Btu Output 16
8 Summary of Annual Costs for Final Particulate
Control Devices for AFBC Industrial Boilers 18
9 Vendors Currently Offering AFBC Boilers Commercially 27
10 Projection of National FBC Boiler Use 28
11 Summary of Potential Alternative AFBC Industrial
Boiler Subsystem Designs 40
12 Design/Operating Conditions of "Commercially-Offered"
AFBC Industrial Boilers 41
13 AFBC Coal-Fired Demonstration and Test Units 52
14 AFBC — Ca/S Molar Feed Ratios Observed to Meet
Stringent, Intermediate, and Moderate S02 Emission
Control Levels. » 69
15 Distribution by Particle Size of Average Collection
Efficiencies for Various Particulate Control
Equipment 109
xvii
-------
TABLES (continued)
Number
Page
16 Summary of Particulate Emission Data, Primary and
Secondary Collection — Atmospheric FBC Units 115
17 Optional Levels of Control to be Supported —
Atmospheric Fluidized-Bed Combustion of Coal 139
18 SC-2 Control Levels for Fuels of Varying Sulfur
Content 144
19 Required Particulate Control Efficiencies Following
the Primary Cyclone in Coal-Fired Atmospheric
FBC Systems 147
20 Required Ca/S Molar Feed Ratios for Best S02 Control
Based on Experimental Data 156
21 Commercially-Offered AFBC Industrial Boilers - Key
Features Affecting Emission Control 160
22 Projected Ca/S Ratios Required for "Commercially-Offered"
FBC Boiler Systems Based on the Westinghouse Model 161
23 Differential Changes in Boiler Efficiency Versus Range
of FBC Design/Operating Parameters 170
24 Summary of Experimental NOX data from Atmospheric FBC
Test Units 176
25 Applicability of Final Particulate Control Devices to
Achieve Moderate Control at 107.5 ng/J (0.25 lb/106 Btu)
for Coal-Fired FBC Industrial Boilers 182
26 Applicability of Final Particulate Control Devices to
Achieve Stringent Control at 12.9 ng/J (0.03 lb/105 Btu)
for Coal-Fired Industrial Boilers 189
27 Optional S02 Control Levels and Required Efficiencies .... 191
28 Optional NOX Control Levels 192
29 Optional Particulate Control Levels and Required
Efficiencies (After Primary Cyclone) 193
30 Major Cost Contributors to FBC Boiler Capital and
Operating Cost 210
xviii
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TABLES (continued)
Number Page
31 Values Selected for Estimating Indirect FBC Capital
Costs for New Facilities 212
32 Unit Cost Values Used to Estimate Annual Operation
and Maintenance Costs for FBC Industrial Boilers 213
33 Annual Cost of Industrial FBC Boilers with S02
Control, Dollars 226
34 Annual Cost ($/106 Btu Output) of Industrial FBC
Boilers with S02 Control 227
35 Costs of "Best" S02 Control Techniques for Coal-Fired
AFBC Boilers of 8.8 MWt (30 x 10^ Btu/hr) Capacity 240
36 Costs of "Best" S02 Control Techniques for Coal-Fired
AFBC Boilers of 22 MWC (75 x 106 Btu/hr) Capacity 241
37 Costs of "Best" S02 Control Techniques for Coal-Fired
AFBC Boilers of 44 MWt (150 x 106 Btu/hr) Capacity 242
38 Costs of "Best" S02 Control Techniques for Coal-Fired
AFBC Boilers of 58.6 MWt (200 x 106 Btu/hr) Capacity. ... 243
39 Cost of S02 Control in AFBC Dollars/kg Sulfur Dioxide
Removed 249
40 Features of Westinghouse Cost Estimate for Industrial
FBC Boilers 252
41 AFBC Boiler Cost with 85 Percent S02 Removal 257
42 General Equations Relating Coal Cost, Limestone Cost,
Residue Disposal Cost, Capital Cost, Ca/S Ratio,
Drying, and Coal Sulfur to $/106 Btu
43 Cost Sensitivity Analysis — AFBC 272
44 Estimated Cost of Final Particulate Control for AFBC
Boilers — Excluding S02 Control . 278
45 Cost of Final Particulate Control for Coal-Fired AFBC
Industrial Boilers with S02 Control 281
46 Cost Summary — AFBC and Uncontrolled Conventional
Boilers: Cost = $/106 Btu Output 286
xix
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TABLES (continued)
Number Page
47 Relative Comparison of the Cost of AFBC Versus
Conventional Boilers with FGD 288
48 Qualitative Comparison of Energy Impact Associated with
AFBC and Conventional Coal-Fired Industrial Boilers .... 295
49 Auxiliary Energy Required for Coal Handling 301
50 Auxiliary Power Required for Boiler Feedwater Circulation,
Treatment and all Associated Pumping in Conventional
and AFBC 301
51 Auxiliary Power for Forced Draft, Induced Draft, and
Ancillary Air 302
52 Power Used for Materials Handling in AFBC Coal-Fired
Boilers 305
53 Auxiliary Power Required for Conventional and AFBC
Solids Handling 308
54 Total Auxiliary Power Requirements for AFBC and
Uncontrolled Conventional Boilers - kW 309
55 Flue Gas Heat Losses 312
56 Energy Impact of Solids Heat Loss (includes
Calcination and Sulfation Reactions for FBC 312
57 Combustion Loss 314
58 Radiative, Convective, and Other Unaccounted Losses 315
59 Inherent Losses as Percent of Thermal Input 316
60 Inherent Energy Losses of Uncontrolled Conventional
Boilers and AFBC by Coal Sulfur Content, Control
Level, and Sorbent Reactivity - kW 317
61 Range cf kW/kg SC>2 Removed by Coal Type and Boiler Size . . . 322
62 Energy Consumption for SC>2 Control for AFBC Coal-Fired
Boilers, 8.8 MWC (30 x 106 Btu/hour) Capacity 324
63 Energy Consumption for S02 Control for AFBC Coal-Fired
Boilers, 58.6 MWt (200 * io6 Btu/hr) Capacity 325
xx
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TABLES (continued)
Number Page
64 FBC Parametric Considerations (Eastern High
Sulfur Coal) 327
65 General Equations Relating Boiler Efficiency to Ca/S
for Eastern High Sulfur Coal 328
66 Relation Between Boiler Efficiency and Coal Drying
Requirements 330
67 General Equation Relating Boiler Efficiency to
Combustion Efficiency 333
68 Energy Consumption for Best Particulate Control
Coal-Fired AFBC Boilers 335
69 Differential Changes in Boiler Efficiency Versus
Range of FBC Design/Operating Parameters 339
70 Total System Losses Resulting from Each Energy
Component Considered 340
71 Range of FGD and FBC Process Energy Requirements 341
72a Air Pollution Impacts from "Best" and "Commercially-
Offered" S02 Control Systems for Coal-Fired FBC
Boilers (8.8 MWt or 30 x 106 Btu/hr heat input) 351
72b Air Pollution Impacts from "Best" and "Commercially-
Offered" S02 Control Systems for Coal-Fired FBC
Boilers (22 MWt or 75 x 106 Btu/hr heat input) 352
72c Air Pollution Impacts from "Best" and "Commercially-
Offered" S02 Control Systems for Coal-Fired FBC
Boilers (44 MWt or 150 x 106 Btu/hr heat input) 353
72d Air Pollution Impacts from "Best" and "Commercially-
Offered" S02 Control Systems for Coal-Fired FBC
Boilers (58.6 MWt or 200 x 106 Btu/hr heat input) 354
73 Air Pollution Impacts from "Best" NOX Control
Techniques for Coal-Fired, Atmospheric Fluidized
Bed Combustion Boilers 357
74 Air Pollution Impact from "Best" Particulate Control
Techniques for Coal-Fired, Atmospheric FBC Boilers 358
xxi
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TABLES (continued)
Number Page
75a Solid Waste Generated by a Once-Through, Limestone-
Fed, Coal-Fired, "Best System" Atmospheric FBC
Boiler (8.8 MW or 30 x 106 Btu/hr heat input) 362
75b Solid Waste Generated by a Once-Through, Limestone-
Fed, Coal-Fired, "Best System" Atmospheric FBC
Boiler (22 MW or 75 x 10^ Btu/hr heat input) 363
75c Solid Waste Generated by a Once-Through, Limestone-
Fed, Coal-Fired, "Best System" Atmospheric FBC
Boiler (44 MW or 150 x 1Q6 Btu/hr heat input) 364
75d Solid Waste Generated by a Once-Through, Limestone-
Fed, Coal-Fired, "Best System" Atmospheric FBC
Boiler (58.6 MW or 200 x 106 Btu/hr heat input) 365
76 Comparison of Leachate Characteristics from the FBC
and FGD Residues 373
77 Babcock and Wilcox Company's Comparison of Solid
Waste Mass from FBC and FGD 377
78 Comparison of AFBC and Scrubber Solid Wastes for
a 200 MW Plant Estimated by TVA 379
79 General Description of Atmospheric FBC Test Facilities. . . . 389
80 Index of AFBC Emission Test Data 390
81 Emission Test Data Measured from B&W 6 ft x 6 ft AFBC
Unit Firing Ohio No. 6 Coal with Lowellville Limestone,
Sized £9,510 urn (3/8 in. x 0) 391
82 Emission Test Data Measured During Operation of B&W
3 ft x 3 ft FBC Unit Firing Pittsburgh No. 8 Coal 395
83 Emission Source Test Data: NCB-CRE 3 ft x 1.5 ft
Atmospheric FBC 398
84 PER-FBM Emission Source Test Data Recorded in Tests
Conducted from Late 1967 Through 1969 401
85 PER-FBM Emission Source Test Data Recorded in Tests
Conducted Through 1975 with Sewickley Coal 406
86 Operating Conditions and Results of FluiDyne 500-Hour
Test in 3.3 ft * 5.3 ft Vertical Slice Combustor 407
xxii
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TABLES (continued)
Number Page
87 Operating Conditions and Results of FluiDyne Run 35
in 3.3 ft x 5.3 ft Vertical Slice Combustor 408
88 Emission Source Test Data: NCB 6 in. Diameter FBC
Unit Firing Welbeck, Park Hill, Illinois, and
Pittsburgh Coals with U.K. Limestone at a Temperature
of 7990C (14700F) 409
89 Emission Source Test Data: NCB 6 in. Diameter FBC
Unit Firing Illinois Coal with Limestone 1359 at a
Fluidizing Velocity of 0.9 m/sec (3 ft/sec) 410
90 Emission Source Test Data: NCB 6 in. Diameter FBC
Unit Firing Pittsburgh and Welbeck Coals with
Limestone 18 at a Temperature of 799°C (1470°F),
Bed Depth of 0.6 m (2 ft) and Fluidizing Velocity
of 0.9 m/sec (3 ft/sec) 411
91 Emission Test Data Measured from ANL's 6 in. AFBC Unit. . . . 412
92 AFBC Emission Source Test Data — SC-2 454
93 AFBC Emission Source Test Data — NOX 465
94 AFBC Emission Source Test Data — Particulate Loading
to Final Control Device 469
95 Average Ca/S Requirements to Meet Three Levels of
Control. Extrapolated from Tables 81 Through 91 473
96 Sorbents Used Experimentally and for Projections Using
Westinghouse Model 506
97 Comparison of Experimental and Projected Sorbent Require-
ments for the B&W 6 ft x 6 ft Unit 507
98 Comparison of Experimental and Projected Sorbent Require-
ments for the B&W 3 ft x 3 ft Unit 508
99 Comparison of Experimental and Projected Sorbent Require-
ments for the PER-FBM 1.5 ft x 6 ft Unit 508
100 Comparison of Experimental and Projected Sorbent Require-
ments for the NCB-CRE 6 in. Unit 509
xxiii
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ACKNOWLEDGEMENTS
The authors extend their appreciation to Mr. D. Bruce Henschel, the EPA
Project Officer, for his overall guidance and support throughout this study.
His advice and technical contributions where essential to the completion of
the study. We also express our appreciation to Dr. Richard Newby and Dr. Dale
Keairns of the Westinghouse Research and Development Center for their technical
assistance. Several other research and engineering organizations, and manu-
facturers contributed to this report by providing supportive information.
They include Foster-Wheeler Equipment Corporation, Johnston Boiler Company,
Combustion Engineering, Energy Resources Company, Babcock and Wilcox, FluiDyne,
and others.
We also wish to acknowledge the efforts of those at Acurex Corporation,
EPA's Office of Air Quality Planning and Standards, and the U.S. Department
of Energy who were responsible for reviewing the preliminary draft sections.
Gilbert/Commonwealth also provided valuable review comments during preparation
of draft versions of this document.
We extend our thanks to Mr. Raymond K. Yu of our technical staff, who
also aided in the preparation of this report.
Finally, we express our appreciation to Susan M. Spinney, Teresa D. Maloney,
Deborah Stott, Dotty Sheahan, and all the members of the Technical Publications
Department of GCA/Technology Division.
XXIV
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1.0 EXECUTIVE SUMMARY
1.1 INTRODUCTION
1.1.1 Purpose of the Report
This Technology Assessment Report on Fluidized-Bed Combustion (FBC) has
been prepared under contract to the U.S. Environmental Protection Agency
(EPA) — Industrial Environmental Research Laboratory (IERL). The information
in this report serves as background data for a comprehensive industrial boiler
emission control study being conducted by the EPA — Office of Air Quality
Planning and Standards (OAQPS). This report, along with several others on
emission control technologies will be used by OAQPS to assess the performance
of alternative control techniques for industrial boilers.
1.1.2 Scope of the Study
The FBC technology assessment report is a compilation of information
gathered from published and unpublished sources and personal communications
with FBC manufacturers and researchers, consulting engineers and pollution
control vendors. The state-of-the-art regarding the degree of pollution
control achievable by fluidized-bed combustion for S02, NOx and particulate
emissions is reported. The study analyzes the economic, energy and environ-
mental penalties associated with achieving these emission reductions.
The emphasis of the analysis is on coal-fired units. Despite the fact
that fluidized-bed combustion offers multifuel capabilities, the prime inter-
est in the technology is associated with its capability to burn coal efficiently
-------
with reduced environmental impact. In addition, the bulk of available opera-
ting and experimental data is for coal-firing.
Standard industrial FBC boilers in the size range of 8.8 MWt to 58.6 MWt
were considered. Commercial FBC units are currently being offered by several
vendors across this entire capacity range; in fact, commercial units as small
as 2.0 MWt are now available. AFBC boilers were compared to uncontrolled
conventional boilers of the same capacity. This basis of comparison was used
in each Technology Assessment Report so that combinations of different boilers
and control techniques could be used at a later stage by OAQPS to develop
model boiler systems. Three coal types were also considered. Table 1 is
a summary of important boiler parameters assessed in this report.
Although fluidized-bed combustion units are offered commercially by
several vendors, FBC is still an emerging technology. Most of the currently
available data and operating practices are based on bench and pilot scale
units. Actual data from commercially operating units are not yet available;
hence, it was necessary in some cases to assume a representative range of
variables and consider the variables parametrically.
The ranges used in making these assumptions and extrapolations were con-
servative and the basic conclusions in this report should not change substan-
tially as better data become available.
Fluidized-bed combustion has been deemed by the U.S. Department of Energy
(DOE) as one of eight new energy technologies whose commercialization will
*
Other technologies included in the DOE program are: low Btu-gasification,
enhanced oil recovery, unconventional gas recovery, low head hydroelectric
power, passive solar energy, energy conserving oil equipment and high
efficiency electric motors.
-------
TABLE 1. SUMMARY OF BOILER DESIGN/OPERATING CONDITIONS
Coal tjpe and associated operatint conditions
Eastern high aulEur
Eastern low sulfur
Technology
mVaec (ac fm) °C
kg/sec (ton/hr) mVsec (acfm) °C
kg'sec (toa/hr) »3/ *ec (acfrn)
AFBC Package wat«rtube/ 20
firetube, overbed
feed*
Uncontrolled Package, watertube, 50
Conventional underfeed atoker
0.32 (1.27) 4.87 (10,300) 177 (350) 0.27 (1.09) 4.6l (9,800) 177 (350:
(1.56) 4.72 (10,000) 177 (350)
60 0.32 <1.27> 6.09 (12,WO) 204 (400) 0.27 (1.09) 5.76 (12,200) 177 (350) 0.39 (1.56) 5.90 <12,500) 177 (350)
AFBC Partial field erection 20
of •hop fabricated
•oduLei, wattrtube,
overfeed feed
Uncontrolled Field erected watertube SO
Conventional chain (rate itoker
60 0.80 (3.18) 12.20 (25.800) 177 (350) 0,69 (2.72) It. 37 (24.100) 177 (350) 0.99 U.91) LI.8* (25,1001 137 (350)
60 0.80 (3.18) 15.24 O2.3QQ) 204 (400) 0.69 (2,72) 14.21 UQ.IOQ) 17? (350) 0.99 (3.91) Ifc.BZ (11,400) V77 <350)
Field erected
over-bed feed
Uncontrolled Field erected watertube 50
60 1.60 (6.36) 24.1.7 (51,800) 177 (350)
60 1.60 (6.36) 30,58 (64,800) 204 UOO)
1.37 (5.43) 22.96 (48.600) 177 (350)
1.37 (5.43) 2B.69 (60,800) 177 (350)
1.37 (5.43) 23.71 (50,200) 177 (350)
1.97 (7.81) 29. 64 (62,800) 177 (350)
overbed feed
Conventional pulverised coat
60 2.13 (8.47) 32.59 (69,000) 177 (350)
60 2.13 (8.47) 35.30 (74.800) 204 1400)
1.83 (7.25) 30.76 165.200) 173 (350)
1.83 <7.25) 33,32 (70,600) 177 (350)
2.63 (10.42) 31.89 (67,600) 177 (350)
2.63 (10.42) 34.55 (73,200) L77 (35O)
Overbed feed deiign it considered becaute available experimental data indicate equivalent
desulFurization performance between id-bed and over-bad feed arrant«Bcati «• long at pri-
mary recycle is practiced (»ee Section 3.0 and 7.0). Alto, the available FBC coat eati-
mates were baaed on over-bed feed. If in-bed feed is neceacary in commercial application
to attain high efficiency SO; control, Che retultant economci arc expected to Call with-
in the high error band of the fBC co*t «*tiMtett presented in Section 4.0.
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be accelerated through DOE programs. The data base is expected to expand
considerably as more demonstration units come online in the next 2 years.
1.2 SYSTEMS OF EMISSION REDUCTION
1.2.1 Principles of Control
Fluidized-bed S02 control technology is based on the reaction of calcium
oxide with the sulfur released from coal combustion. A calcium based sorbent,
limestone or dolomite, is fed into the bed along with the coal. 862 is formed
in the bed; the limestone is calcined forming calcium oxide, and the following
reaction takes place.
CaO + S02 + 1/202 •* CaSOi+
N0x emi8Sions from FBC units resulting from oxidation of organic nitrogen
compounds in the coal and thermal fixation of atmospheric nitrogen tend to be
low. The mechanisms causing the reduced emissions are not well understood,
but are inherent to the fluidized-bed process based on experimental data and
observations.
Industrial FBC boilers will generally use a primary particulate control
device (a cyclone or multitube cyclone) to recycle 80 to 90 percent (a level
achieved in experimentation to date) of elutriated particulate back to the bed,
It is expected that flue gas particles downstream of the primary device can be
collected at high efficiency by a final control device. Fabric filters, ESPs
and multitube cyclones are most applicable.
1.2.2 Control Techniques Considered
A wide cross-section of control techniques was considered for S02, NOx,
and particulates. Each of these techniques was assessed in terms of perfor-
mance (e.g., efficiency, reliability, and versatility); applicability (i.e.,
compatibility with the full range of FBC industrial boiler capacity); and,
-------
status of development (i.e., when the technique would be considered a proven
and available technology). The techniques considered are itemized below:
• S02 Control
Adjustment of Ca/S molar feed ratio
Increased gas phase residence times
- Reduced sorbent particle size
Variability of sorbent reactivity
Adjustment of bed temperature
Variability in feed mechanisms
- Variability in excess air levels
- Pressurized fluidized-bed combustion
Synthetic sorbents
Regeneration of sorbent
Enhancement of S02 capture with catalysts
• NOX Control
Inherent fluidized-bed combustion chemistry
Reduced excess air
Increased gas residence time
- Decreased bed temperature
- Staged combustion
Pressurized fluidized-bed combustion
Staged coal feed points
- Ammonia/urea injection
- Flue gas recirculation
Injection of recycle char
• Particulate Control
Fabric filtration
Electrostatic precipitation (hot- and cold-side)
Multitube cyclones
Wet scrubbers
- Modified design parameters
Sorbent treatment to reduce attrition
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1.2.3 Degrees of Control Considered
In the ensuing discussion of emission control technologies, candidate tech-
nologies are compared using three emission control levels labelled "moderate,
intermediate, and stringent." These control levels were chosen only to encom-
pass all candidate technologies and form bases for comparison of technologies
for control of specific pollutants considering performance, costs, energy, and
nonair environmental effects.
From these comparisons, candidate "best" technologies for control of indi-
vidual pollutants are recommended for consideration in subsequent industrial
boiler studies. These "best technology" recommendations do not consider com-
binations of technologies to remove more than one pollutant and have not under-
gone the detailed environmental, cost, and energy impact assessments necessary
for regulatory action. Therefore, the levels of "moderate, intermediate, and
stringent" and the recommendation of "best technology" for individual pollutants
are not to be construed as indicative of the regulations that will be developed
for industrial boilers. EPA will perform rigorous examination of several com-
prehensive regulatory options before any decisions are made regarding the stand-
ards for emissions from industrial boilers.
The degrees of control which were considered for current fluidized-bed
combustion technology in this assessment are summarized in Table 2.
1.2.4 Best Control Techniques
1.2.4.1 S02 Control—
The best system of SC>2 emission reduction is the one which minimizes sor-
bent feed rates, and still attains high levels of control. The Ca/S molar feed
ratio can be reduced with careful control of other operating conditions - most
significantly, sorbent particle size and gas phase residence time. Experimental
-------
results and theoretical considerations indicate that small particle sizes (in
the range of 500 ym) and sufficiently long gas phase residence times (0.67 sec)
are representative conditions for effective SC>2 control, although most FBC
facilities currently are designed or operated with shorter residence times and
coarser sorbent particles. The conditions used in this report for the best
system of SC>2 control are:
• Gas phase residence time = 0.67 sec
• Surface average limestone particle size in bed = 500 ym
• Bed temperature = 843°C (1550°F)
• Excess air rate = 20 percent
• Primary recycle of bed carryover
TABLE 2. OPTIONAL LEVELS OF CONTROL TO BE SUPPORTED -
ATMOSPHERIC FLUIDIZED-BED COMBUSTION OF COAL
SOa NOX Particulate
Level of
control % ng/J ng/J
reduction (lb/106 Btu) (lb/106 Btu)
Stringent 90* 215 12.9
(0.5) (0.03)
Intermediate 85* 258 43
(0.6) (0.1)
Moderate 75* 301 107.5
(0.7) (0.25)
*
In addition to the % reduction, an upper limit of
516 ng/J (1.2 lb/106 Btu) applies in all cases.
Furthermore, in no case are controls required to
reduce emissions below 86 ng/J (0.2 lb/106 Btu).
Increased gas residence times and reduced sorbent particle sizes will
necessitate reduced gas velocities through the bed, thus increasing boiler size
somewhat. It is estimated that especially at elevated S02 removal requirements,
-------
the possible capital cost penalty associated with the larger boiler will be
more than offset by the reduced sorbent and spent solids disposal costs at
the recommended conditions.
An important goal in the development of fluidized-bed combustion boilers
has been to maximize capacity in a combustion chamber smaller than traditionally
possible to allow package fabrication of larger capacity boilers and achieve
savings in capital cost. Recommendations in this report concerning "best
system" conditions address SOg control capability by minimizing sorbent require-
ments and, thus, enhancing boiler and plant efficiency and minimizing costs
associated with sorbent use. The conditions specified above are not much
different than those being used in current and envisioned FBC designs. For
instance, the design of Combustion Engineering's demonstration boiler (22,700
kg/hr-steam) at the Great Lakes Naval Training Center specifies a nominal super-
ficial velocity of 2.1 m/sec (7 ft/sec), expanded bed height of 0.9 m (3 ft),
and in-bed mass mean particle size of 800 ym (which is probably close to a sur-
face average particle size of 500 pm). Considering that early FBC designs
called for superficial velocities of 3 to 4.3 m/sec (10 to 14 ft/sec) and in
some cases expanded bed depths of less than 0.9 m (3 ft), the conditions recom-
mended do not seem to represent a significant change from currently envisioned
nominal design/operating conditions. All of the conditions specified have been
used in various experimental programs. FBC technology is still in the develop-
ment stage so the recommended conditions should be adaptable in future designs.
Some commercially-offered AFBC designs (including over-bed coal feeding
and inherent shallow-bed operation) may not be readily adaptable to the
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increased gas residence time/500 ym particle size conditions recommended here
for the best S02 control system. Further data on these designs are required
to establish their SC>2 control performance.
The selection of increased gas residence time (0.67 sec) and reduced sor-
bent particle size (500 ym) was made with the use of a mathematical model which
can be utilized to project Ca/S requirements based upon laboratory thermogravi-
metric analysis data. Actual AFBC operating data at conditions near these con-
ditions are limited, but some are available from smaller pilot- and bench-scale
units. Therefore, additional data, especially from large AFBC units operating
at conditions near the best system conditions are required in order to confirm
AFBC SC-2 removal performance at these conditions.
The results of experimentation conducted to data at close to the selected
best system conditions were reviewed to assess the correlation between SC>2
removal efficiency and Ca/S ratio. A range of sorbent feed requirements was
noted because of differences in the reactivity and capacity of sorbents inves-
tigated. The observed ranges in Ca/S ratios are shown in Table 3 for SC>2 re-
moval efficiencies ranging between 75 to 90 percent.
TABLE 3. RANGE OF EXPERIMENTAL Ca/S RATIOS
NECESSARY TO MEET OPTIONAL S02
CONTROL LEVELS AS OBSERVED IN
TESTING AT OR NEAR "BEST SYSTEM"
CONDITIONS
Control level %
Stringent
Intermediate
Moderate
, _ . Range of
reduction , *
Ca/S ratio
90
85
75
2
2
1
.3
.1
.6
- 4
- 3
- 3
.2
.8
.2
Average
Ca/S ratio
3
2
2
.3
.9
.2
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The range shown reflects the fact that the impact of the variance in sor-
bent reactivity on total sorbent needs may override the impact of the optional
control levels considered. Other operating conditions (e.g., sorbent particle
size, and gas phase residence time) varied slightly in the experimentation used
as a basis, but results were screened to maintain such variation to a minimum.
Therefore, the sorbent requirements noted in Table 3 represent best 862 control,
with variation due to sorbent reactivity. This variation is highly probable in
the industrial sector because high quality sorbents may not always be available
to an individual industry.
Ca/S ratios used by experimenters to achieve 75 to 90 percent S(>2 reduc-
tion have been noted as high as 5 or 6. These high sorbent requirements are
due primarily to operating factors which were not near best system conditions
in combination with a low reactivity sorbent. ANL (the 6 in. diameter unit)
B&W (the 3 ft x 3 ft unit) and B&W, Ltd. (the Renfrew unit) all ran tests in
which a Ca/S ratio greater than 5 was used. Gas residence times as low as
0.2 sec were used during these tests. Some SC>2 emission data, which are re-
ported for experimentation not conducted at best system conditions are also
within the range shown in Table 3. A combination of higher sorbent reactivity
and less than optimal operating conditions may produce adequate results. How-
ever, performance can be further improved by taking advantage of best system
conditions, although slight modifications to current designs would be required.
1.2.4.2 NOx Control—
The best system of NOx control capitalizes on the inherent combustion chem-
istry of the fluidized-bed system. Low temperatures and chemical kinetics com-
bine to produce NOx emissions which typically are lower than most conventional
systems. The levels of control that were considered are shown in Table 4.
10
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TABLE 4. OPTIONAL NOX CONTROL LEVELS
Emission rate
Control level
ng/J (lb/106 Btu)
Stringent 215 0.5
Intermediate 258 0.6
Moderate 301 0.7
Almost all of the data from experimental AFBC units operating at primary
cell bed temperature (<900°C), including units as small as 6 in. diameter, are
below the moderate level of 301 ng/J. Essentially all of the data from large
AFBC (>500 Ib coal/hr), and most of the data from smaller units, are below the
intermediate level. The limited data available from the largest AFBC units are
consistently below the stringent level of .215 ng/J, although about one-half of
the data from smaller units are above that level. Accordingly, it is felt that
the stringent level of NOX control can be achieved in commercial-scale indus-
trial AFBCs, at the values of design/operating variables typically used by
process developers today. If the gas residence time is increased for 862
control purposes, this may aid in reducing NOx emissions.
The variables which control NOx emissions from FBC are not completely
understood; thus, it is not possible to define "best" NOX control options with
the same degree of detail that is possible in the case of SO2- A detailed re-
view of experimental data from AFBC has shown that unit size, bed temperature,
excess air, gas residence time, and possibly fuel nitrogen content can influence
NOx emissions, although not with strong, well-defined correlation. The data are
sufficiently scattered that it is possible that some minor adjustments to AFBC
design/operating parameters may be necessary to ensure that commercial AFBC
boilers would achieve the stringent NOx control level reliably on a 24 hr average
11
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basis. Additional data from large AFBC units are necessary to confirm the
ability of AFBC to reliably achieve the stringent level without such adjustments,
More substantial NOX control measures (e.g., combustion modifications, such as
two-stage combustion) are not felt to be necessary for AFBC to achieve the
stringent level of control. Testing of combustion modifications in FBC for
improved NOx control is just beginning in some experimental programs.
1.2.4.3 Particulate Control—
The levels of particulate control considered for a fluidized-bed combus-
tion system are shown in Table 5.
TABLE 5. OPTIONAL PARTICULATE
CONTROL LEVELS
Emission rate
Control level
ng/J (lb/106 Btu)
Stringent 12.9 0.03
Intermediate 43 0.10
Moderate 108 0.25
Particulate reduction under all three control options should be possible
in FBC systems by using conventional add-on particulate control devices. Par-
ticle control, adequate to meet these emission levels, has not yet been demon-
strated on FBC units, since units of sufficient size have not been operated for
sufficiently long periods; however, barring some unexpected unique property of
FBC fly ash, it is anticipated that effective control could be achieved by suit-
able design of conventional particle control devices. The most important factors
in selecting a device are reliability and cost. (Other factors are similar for
all devices, except environmental impact, where water pollution problems may
12
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arise in using wet scrubbers for moderate or intermediate control. Since one
of the implicit purposes of FBC is to avoid liquid waste production, use of wet
scrubbers is not recommended.)
The control efficiencies required to meet these levels are shown in
Table 6.
TABLE 6. CONTROL EFFICIENCIES REQUIRED TO MEET OPTIONAL
PARTICULATE CONTROL LEVELS
Level of emission control and
efficiency of final particulate control
_ . . Particulate . , . device required to achieve that level
Fuel and . , ,, partible size • ^ ,, ,,..,„<: _.. •,
... . emission following ng/J (lb/10 Btu;
boiler capacity . . s average MMD _ '
MWt (106
Coal
8.8 -
(30 -
Btu/hr)
58.6
200)
ng/J (lb/106 Btu) '•""
215 - 2150
(0.5 - 5.0) 5 - 20
Stringent
12.9
(0.03)
94 - 99.4
Intermediate
43
(0.10)
80 - 98
Moderate
107.5
(0.25)
50 - 95
The loadings and particulate size characteristics following the primary
cyclone are based on a compilation of experimental results.
Based primarily on the results of the cost analysis, the best devices for
stringent and intermediate particulate control should be fabric filters or elec-
trostatic precipitators (ESPs). The best device for moderate control (at collec-
tion efficiencies -80 percent) should be a multitube cyclone.
The reliability of these systems must be documented in full-scale testing.
Experimental data indicate that ESPs will have to be operated as hot-side
installations to effectively collect the high resistivity particles elutriated
from FBC units. In addition, ESPs may be unreliable for smaller facilities
because of possible variations in fuel and sorbent characteristics and the
anticipated dependence of ESP performance on these variations.
13
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Fabric filters could possibly have operating problems. Lime hydration at
the fabric surface could cause bag blinding. Excessive carbon carryover or
temperature excursions could lead to bag fires, even though combustion effi-
ciency in AFBC should be equivalent to well designed conventional stokers.
In any event, potential problems with ESPs and fabric filters must be
explored in future commercial scale testing.
1.3 COST IMPACT OF BEST CONTROL TECHNIQUES
Cost estimates for atmospheric fluidized-bed combustion (AFBC) with S02,
N0x> and particulate control were developed based on cost quotations from FBC
vendors. Costing procedures used by PEDCo for uncontrolled conventional boiler
systems1 were adopted to maintain comparability with those estimates prepared
by other TAR contractors for other industrial boiler control technologies.
Capital, operating, and total annualized cost were estimated for "grass roots"
facilities and the variations based on different levels of emission control
were determined. Industrial AFBC boiler cost estimates were also prepared
independently by Westinghouse Research and Development and their results are
f\
reported for comparison,z
1.3.1 Comparison with Uncontrolled Conventional Systems
The cost of AFBC with control was compared with uncontrolled conventional
boilers to indicate the cost of control associated with FBC. The accuracy of
the results (estimated to be ±30 percent) and validity of conclusions is depen~
dent upon the vendor quotes used as a basis. In certain instances, previous
FBC cost estimates were reviewed and reported to lend perspective to the vendor-
based estimates.
14
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1.3.2 Cost of S02 Control
Costs in terms of $/106 Btu output, for industrial AFBC boilers with
control (excluding final particulate control) are summarized in Table 7.
The AFBC costs were developed based on vendor quotations and by employing esti-
mating guidelines recommended by PEDCo early in the program. Uncontrolled con-
ventional boiler costs are shown for comparison and are based on the results of
PEDCo's cost analysis.3 AFBC cos^s are shown for moderate and stringent SC>2
control with average reactivity sorbent. The worst case FBC cost is also shown;
i.e., stringent SC>2 control with low reactivity sorbent.
Considering high sulfur coal, the differential cost between AFBC and un-
controlled conventional systems widens as boiler capacity increases. For strin-
gent control and average sorbent reactivity, the incremental co ' for FBC ranges
from 4 up to 24 percent of the uncontrolled conventional boiler cost. The worst
case incremental costs (low sorbent reactivity) range from 8 up to 30 percent
of the uncontrolled conventional boiler cost. The small boiler (8.8 MWt) costs
are roughly comparable due to the simple package design of the FBC unit.
When low sulfur coals are considered, the gap in cost between AFBC and
uncontrolled conventional technology narrows due to the significant reduction
in sorbent needs and spent solids disposal cost. The 8.8 MWt AFBC boiler has
a slightly lower cost than the comparable uncontrolled conventional boiler.
For subbituminous coal, the cost of the two technologies are roughly equivalent
at 44 and 58.6 MW^, even though the conventional boilers are uncontrolled. For
other sizes and both low sulfur coals, AFBC technology is roughly 5 to 10 per-
cent more costly than uncontrolled conventional technology.
15
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TABLE 7. SUMMARY OF AFBC BOILER COST WITH S02 CONTROL,
$/106 Btu OUTPUT*t
Coal type
Eastern
high sulfur
Eastern
low sulfur
Subbituminous
Boiler type
AFBC
Uncontrolled
Conventional
AFBC
Uncontrolled
Conventional
AFBC
Uncontrolled
Conventional
SC-2 control
level and
% reduction
Stringent 90
Moderate 78.7
-
Stringent or ~^ 9
Intermediate
Moderate 75
-
Stringent or „., .
Intermediate
Moderate 75
~~
Sorbent
reactivity
Average
Low
Average
—
Average
Low
Average
—
Average
Low
Average
"
Boiler
8
7
8
7
7
6
6
6
7
6
6
6
7
.8
.75
.04
.48
.39
.87
.93
.83
.12
.73
.79
.70
.41
capacity,
22
6
7
6
5
6
6
6
5
5
5
5
5
.96
.28
.72
.76
.21
.27
.17
.62
.88
.93
.84
.54
44
5
6
5
4
5
5
5
4
4
4
4
4
.91
.19
.65
.77
.13
.19
.10
.70
.75
.80
.71
.73
MW
58
5.
5.
5.
4.
4.
4.
4.
4.
4.
4.
4.
4.
t
.6
69
97
43
56
93
99
90
55
51
56
48
57
The coses of FBC units with SO2 control are compared with the costs of uncontrolled
conventional boilers in order to provide the incremental cost of using FBC as an S02
control system. As indicated in the Preface, similar Technology Assessment Reports
have been prepared providing the incremental cost of other SOa control options, such
as flue gas desulfurization, coal cleaning, and synthetic fuels. A future study by
EPA's Office of Air Quality and Planning and Standards will compare the cost of S02
removal using FBC and the other control technologies, based upon the Technology
Assessment Reports. An initial comparison of controlled FBC with a conventional
boiler employing flue gas desulfurization, is included in Section 4.6.2 of this
report.
The conclusion suggested by this table — that controlled FBC may be less expensive
than uncontrolled conventional boilers in the cases of low sulfur coal — is not
supported by some other estimators (Exxon, Reference 4, page i). However, this
conclusion is considered to be warranted within the accuracy of the estimates
presented in this report.
16
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The costs reported for the 8.8 MWt (30 * 106 Btu/hr) AFBC are based on a
single basic boiler quote. The manufacturer* is currently selling package
boilers in this size range. The boiler design is simple, but operates effi-
ciently based on demonstration plant operation over the last several months.
Therefore, the costs presented are considered realistic.
The costs for the three larger AFBC boilers are based on quotes from
another FBC vendor. This manufacturer* is in an earlier stage of actual commer-
cialization but has been involved in research and development of FBC technology
for several years. They are also a major conventional boiler manufacturer.
The cost relationship shown in this analysis indicates AFBC with S0£ con-
trol is generally a higher cost option than uncontrolled conventional technology
when field erection is required or when high sulfur coal is burned. Considering
all cost estimates (the PEDCo estimates, the independent estimates by Westing-
house, and previous studies by Exxon4 and A.G. McKee5), the values presented
for conventional and AFBC boilers are considered to be accurate within 30 per-
cent. Westinghouse estimates of total annual AFBC boiler cost were about 5
percent higher than GCA's for the 8.8 MWt unit, and about 10 to 15 percent
lower for the larger boilers. The difference is in capital cost (direct opera-
ting cost estimates were equivalent) but is within the accuracy limits specified,
Considering all of these factors it is concluded that, after AFBC costs and per-
formance have been demonstrated, AFBC should be a candidate for any new coal-
fired industrial boiler installation where S02 control is required.
*
FBC manufacturers are discussed anonymously to maintain confidentiality.
17
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1.3.3 Cost of Particulate Control
The cost of final particulate control in AFBC was assumed to be equal to
the cost of final control in conventional boilers burning low sulfur coal. The
costs presented in Table 8 are based on vendor quotations and results reported
in the TAR on particulate control.6
TABLE 8. SUMMARY OF ANNUAL COSTS FOR FINAL PARTICULATE CONTROL
DEVICES FOR AFBC INDUSTRIAL BOILERS
Annual cost of device, 10 3 $
Control device
Hot-side ESP
Fabric filter
Multitube cyclone
Control level
Stringent or
Intermediate
All optional levels
Moderate
Boiler
8.8
51
10
capacity, MWt
22 44 58.6
147 208 211 - 228
86 147 181
NA 26 NA
NA = Not available.
The results indicate that fabric filters are the low cost device for
stringent or intermediate particulate control, but the estimates assume that
there will be no unanticipated baghouse operating difficulties (e.g., bag
blinding, bag fires, etc.) that will unduly influence the costs of fabric
filter operation on FBC units. The ESP costs are based on hot-side installa-
tion to account for noted high particle resistivity in FBC units.
Multitube cyclones appear to be the low cost device for moderate particu-
late control. Costs were available for ESP use at average SIP levels,* but
*
SIP indicates the average emission control level set in State Implementation
Plans throughout the United States. For coal, the level is 258 ng/J (0.6
lb/106 Btu), a factor of 2.4 more lenient than the optional moderate level
under consideration.
18
-------
were all significantly higher than the multitube cyclone costs at a moderate
particulate control level. The fabric filters costs shown in Table 8 would not
decrease for moderate control because a constant pressure drop has been assumed,
regardless of control level.
The costs presented need to be confirmed in actual application. It is
important to emphasize that final particulate control technology has not been
demonstrated on AFBC boilers to dat..
1.3.4 Cost of NOX Control
In the large scale AFBC (i.e., B&W 6 ft x 6 ft unit, and Renfrew) NOX emis-
sion testing performed to date, emission levels have not exceeded the optional
stringent level of control of 215 ng/J (0.5 lb/106 Btu). Additionally, in all
testing of smaller bench- and pilot-scale units at temperatures characteristic
of envisioned normal AFBC operating temperatures, NOx emissions have averaged
about 215 ng/J (0.5 lb/105 Btu). Therefore, it is likely that no special ad-
justments of FBC conditions will be necessary to achieve the optional levels
of NOx control considered in this report.
If variation of any of the standard design/operating variables (excess air,
bed depth, gas phase residence time) were necessary to guarantee reliable (24
hr average) achievement of the stringent NOx level, there is insufficient corre-
lation in the data to enable rigorous quantification of the cost and effective-
ness of parametric variations.
If any adjustments were necessary for NOx control, it is probable that
costs could decrease as well as increase, if such modifications reduce flue gas
heat loss or increase combustion efficiency. In fact, any such modifications
would be consistent with changes to attain the "best system" of S02 control
(i.e., increasing gas residence time to 0.67 sec). Further experimentation is
19
-------
required to resolve this effect. For the purpose of this analysis, the costs
presented for AFBC boiler operation and SC>2 control are considered to include
the cost of NOx control. No specific costs for NOx control have been added.
Likewise, the costs of combustion modification techniques to control NOx
(e.g., two-stage combustion) cannot be included because of inadequate data.
However, the need for such techniques in FBC, to achieve the NOX levels under
consideration here, is very unlikely.
1.4 ENERGY IMPACT OF BEST CONTROL TECHNIQUES
1.4.1 Basis of Energy Impact Analysis
Energy impact of AFBC commercial application is analyzed with three objec-
tives in mind. These objectives are: (1) quantify the losses in industrial
AFBC and conventional coal-fired steam raising equipment sufficiently to permit
rectification of energy impact of pollution control; (2) determine total elec-
,:al usage for cost estimating purposes; and (3) determine overall boiler
.:::iciency of AFBC and conventional technology for development of cost in terms
-.•I $/106 Btu output.
To fulfill these objectives each energy loss component was identified.
The loss variability was then quantified where possible and the energy loss
matrix developed for each component. These components are:
• Coal handling
• Limestone and spent solids handling
• Forced draft, induced draft and other fans
• Boiler water feed and treatment
• Sorbent calcination, sulfation, and spent solids sensible heat
• Flue gas sensible and latent heat losses
• Unburned carbon
• Radiation, convection, and other unaccounted-for losses
20
-------
1.4.2 Energy Penalty of Air Pollution Control by AFBC
The summation of all energy losses associated with AFBC compared with the
losses from uncontrolled conventional boilers are used as the basis for assess-
ing the energy impact of commercialization of AFBC as a control technology.
The difference between energy losses in AFBC and conventional technology is
defined as the energy impact of control.
1.4.3 SC-2 Control Energy Impact
Because the total of the losses identified in FBC is less than for uncon-
trolled conventional technology for a capacity of 44 MWt and below, the energy
impact of SC-2 control by AFBC is negative. The energy savings realized by
implementation of AFBC over this size range is as high as 3 percent of thermal
input based on estimates by GCA; i.e., AFBC boiler efficiency is greater than
conventional by as much as 3 percent. The variation is a result of boiler
capacity, coal sulfur content, control level and sorbent reactivity. Coal
sulfur content has the largest impact, and SC>2 control level appears to have
the smallest effect of the parameters considered. If the average SIP SC-2 con-
trol level is considered, then the range of SC>2 control is as significant as
coal sulfur content in determining energy impact.
When the 58.6 MWt unit is considered, the uncontrolled conventional unit
has lower energy losses than the AFBC boiler with SOz control. This is due to
greater combustion efficiency in the conventional pulverized coal unit (99
versus 97 percent) and lower flue gas heat losses in the pulverized coal unit
than the conventional stokers (30 percent versus 50 percent excess air,
respectively). AFBC boiler efficiency at this capacity is 1 to 3 percent lower
than that of the uncontrolled pulverized coal boiler. Again, the range results
21
-------
from variation in coal sulfur content, control level, and sorbent reactivity.
The range of S02 control has a significant effect if the full range of optional
levels from SIP to stringent is considered.
Implementation of best system design/operating conditions for SC>2 removal
may enhance combustion efficiency by allowing longer carbon residence time in
the bed. Also, use of primary recycle allows for combustion of recirculated
char.
1.4.4 NOx Control Energy Impact
No energy impact has been calculated for NOX control in AFBC boilers.
First of all, it is likely that no special FBC system changes will be required
to achieve the levels of control being considered; NOx control would be inherent
in the process, and no separate energy impact exists. Second, if some adjust-
ment of FBC design/operating conditions were necessary to achieve the stringent
level of control reliably on a 24 hr basis, there is insufficient correlation
in the available data to permit quantification of the effect of parametric
variations on NOX emissions. Variables which are known to affect NOX emissions,
but which are not well correlated, are gas phase residence time, excess air,
and bed temperature. Other methods of NOx reduction proposed are two-stage
combustion or chemical injection (such as ammonia). When good correlations
linking specific parametric variations with NOx emissions and the effect of
these variations on energy loss are developed, energy impact of NOx control
can be properly evaluated, if, indeed, any such parametric variations are
necessary to achieve the desired control levels.
1.4.5 Particulate Control Energy Impact
The control methods proposed for FBC particulate control are already
commercialized for conventional technology. For the expected dust loadings in
22
-------
AFBC flue gases, energy use for control will amount to roughly 1 percent of
the energy input to the boiler, based upon previous experience with these con-
ventional particle control devices on conventional boilers, burning low sulfur
coal.
1.5 ENVIRONMENTAL IMPACT OF IMPLEMENTING BEST SYSTEMS OF CONTROL
1.5.1 Impact of Control Techniques
The major environmental concern in implementing the best candidates for
emission control in fluidized-bed combustion is the impact of S02 control on
the amount of solid waste generated. The amount of spent residue increases as
Ca/S ratio is increased to attain higher S02 control levels. The major environ-
mental problems with FBC solid waste are high leachate pH, heat release upon
initial exposure to water as a result of hydration of the CaO, and total dis-
solved solids (TDS) above drinking water standards in the leachate.
For perspective, B&W7 and TVA8 have compared the amount of waste generated
in FBC and conventional boilers using wet, lime/limestone flue gas desulfuriza-
tion (FGD). Considering plant sizes of 600 and 200 MWe, respectively, these
investigators showed that dry waste amounts were greater for FBC by 10 to 50
percent, but that on a total mass basis (i.e., including the water content of
FGD slurry), FGD waste could range as much as 30 percent greater than FBC waste.
Lime/limestone FGD and FBC waste have some similar characteristics in terms
of pH, TDS content, and Ca and S0i+ content. However, the following difference
has a significant impact. FGD sludge contains sulfite ion (S03=) which will
be a source of chemical oxygen demand since it is readily oxidized to S0it=.
Whereas FBC waste is dry, and almost fully oxidized, lime/limestone FGD waste
is a thixotropic, partially oxidized slurry. Since it liquefies easily it is
23
-------
difficult to handle. Dewatering techniques such as centrifuges and vacuum
filters do not reliably yield the 70 to 75 percent solids needed prior to
landfilling.
Several other FGD processes appear to be applicable for conventional boiler
installations, including sodium scrubbing, double alkali, and Wellman-Lord. All
have associated liquid/solid waste streams. In general, solid sludge wastes
include calcium and sodium sulfites or sulfates. Liquid wastes from the Wellman-
Lord process have low pH and high chlorides. Sodium scrubbing liquid wastes
contain about 5 percent solids and sodium sulfates/sulfites or sodium carbonate.
Considering FBC particulate emissions, attainment of high S02 control
efficiency using high Ca/S ratios and small limestone particle sizes could
increase particulate emissions, but it is doubtful that this increase would be
to such a degree that available particulate control systems would be inadequate.
Except for the small amount of sorbent which might appear in the fly ash,
the quantity of solids resulting from flue gas particle control should be sim-
ilar to that from a conventional coal-fired boiler.
Implementing the specified levels of NOx control should require little, if
any, change in operating variables and little, if any, environmental impact is
foreseen.
It is considered unlikely that combustion modifications (e.g., low excess
air, staged combustion) would be necessary for stringent NOx control. If it
were necessary, there could be possible increases in hydrocarbon, CO and par-
ticulate emissions, but definitive data are not yet available. Any problems
would not be expected to be different than those encountered with combustion
modification in conventional systems.
24
-------
The major environmental impact associated with implementing moderate, in-
termediate or stringent particulate control is the incremental waste solids/ash
to be disposed of.
1.5.2 Solid Waste Disposal
FBC residue does not currently appear to be "hazardous" under RCRA9 Section
3001, according to the draft procedures currently proposed under Section 3001.
Four criteria have been proposed to date for determining whether a material is
"hazardous": toxicity (as determined by a proposed leaching test referred to
as the Extraction Procedure); corrosivity; reactivity; and ignitability. Sev-
eral FBC residues have been tested to date under the Extraction Procedure; none
were found to be "hazardous" due to toxicity. Also, it is the current judgment
that the residue would not be considered corrosive, reactive or ignitable.
Therefore, the current conclusion is that FBC residue would generally not be
considered hazardous, under the RCRA procedures as currently proposed. Any
FBC residue that is found to be hazardous (e.g., due to the use of a particular
coal or sorbent having a high trace metal leaching tendency) would be expected
to be considered under the "special high-volume waste" category proposed for
electric utility residues. Activities are underway by EPA's Office of Solid
Waste to expand the RCRA test procedures; biological testing for toxicity is
being considered, and a fifth criteria for determining whether a residue is
"hazardous" (radioactivity) is under consideration. In addition, changes in
the test procedures are possible. These future efforts under RCRA must be
followed in order to further assess the status of FBC residue under the Act
(and, consequently, any specific disposal requirements that may be imposed).
25
-------
Potential problems associated with the residue, which have been identified
are: the high pH, high IDS, and high Ca and SO^ in the leachate, the heat re-
lease potential upon initial contact with water, and the total solid volume and
handling problems.
Solid waste characterization studies indicate that with a judicious choice
and design of disposal site, no insurmountable problem should be found. Engi-
neering review of disposal/utilization options, costs, and trace constituents
is continuing. Further testing is also needed to assess the biological effects
of the leachate from FBC.
1.6 COMMERCIAL AVAILABILITY OF AFBC
AFBC is an emerging technology and commercial sales have just begun.
Manufacturers which offer FBC boilers commercially are shown in Table 9.
Commercialization is being accelerated by programs sponsored by federal (U.S.
Department of Energy) and state (Ohio) agencies to demonstrate the reliability
of the systems. Generally the design limestone particle size normally utilized
by the companies is higher than that recommended for best S02 control systems
in this report, and gas residence times are shorter. Thus, S02 capture per-
formance may not be as effective for the current designs as projected for best
systems. However, FBC systems are flexible, and as more stringent control
standards are adopted, it is felt that these variables can be adjusted to come
closer to the recommended particle size and gas residence time, without major
impact on the FBC process. Only slight modifications in current design/
operating specifications would be required. Although increased gas residence
time and reduced particle size (reduced gas velocity) will increase boiler
capital cost, it is estimated that the reduced operating cost (resulting from
reduced sorbent requirements and spent solids disposal) will more than offset
26
-------
TABLE 9. VENDORS CURRENTLY OFFERING AFBC BOILERS COMMERCIALLY
Company
Location
Fluidized Combustion Company
(joint venture of Foster-Wheeler
Energy Corporation and Pope,
Evans, and Robbins)
Johnston Boiler Company
(under license to Combustion
Systems Ltd.)
Mustad & Sons
Riley Stoker (with B&W, Ltd.)
Stone-Platt, Ltd.
International Boiler Works
(currently planning to fabricate
FBC boilers incorporating designs
developed by Energy Resources
Company (ERGO), Wormser Engineer-
ing, and FluiDyne)
Livingston, New Jersey
Ferrysburg, Michigan
Oslo, Norway
Worcester, Massachusetts
Netherton, England
East Stroudsburg, Pennsylvania
27
-------
the increased capital costs, resulting in reduced steam cost. There is also
a possibility of reduced capital costs in other areas, such as particulate con-
trol and recirculation pumps (deeper beds may allow for natural coolant circu-
lation). The savings become more substantial as the required degree of SC>2
control is increased. Studies by Westinghouse also support this contention.10
Prediction of the nationwide potential for the use of FBC is shown in
Table 10,u as estimated by EXXON in 1976. Considering that the general in-
dustrial boiler market is currently depressed, these estimates may be high.
GCA's own investigation indicates that the FBC vendors have the production
capacity to build the number of boilers projected for 1985 and 1990, but the
demand for this number of installations is uncertain. Implementation of the
Fuels Use Act of 197812 may have a positive effect on the installation of
coal-fired industrial FBC boilers; the law calls for use of coal in new boiler
installations (less than 29.3 MWt) unless technical or economic constraints
are prohibitive.
TABLE 10. PROJECTION OF NATIONAL FBC BOILER USE
Year Cumulative number 1015 Btu 1,000 B/D of
of industrial FBC boilers per year oil equivalent
1980
1985
1990
1995
2000
7
200
685
1,170
2,050
0.01
0.29
0.99
1.69
2.97
5
136
462
793
1,400
28
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1.7 REFERENCES
1. Devitt, T. , et al. The Population and Characteristics of Industrial/
Commercial Boilers. Prepared by PEDCo Environmental, Inc. for the U.S.
Environmental Protection Agency. May 1979, pp. 112-126.
2. Letter correspondence from Dr. R.A. Newby of Westinghouse Research and
Development to Mr. C.W. Young of GCA/Technology Division. April 30, 1979.
3. Devitt, T. , et al. op. cit. Appendix G.
4. Farmer, M.H., et al. Application of Fluidized-Bed Technology to Industrial
Boilers. Prepared by EXXON Research and Engineering Company for the U.S.
Environmental Protection Agency, the Energy Research and Development Ad-
ministration, and the Federal Energy Administration. EPA Report No.
600/7-77-011. January 1977, pp. 17-33, and Appendix 1.
5. Arthur G. McKee and Company. 100,000 Pound Per Hour Boiler Cost Study.
Prepared for the U.S. Department of Energy under Contract No. EX-7-C-
01-2418. July 27, 1978.
6. Roeck, D.R. , and R. Dennis. Technology Assessment Report for Industrial
Boiler Applications: Particulate Control. Draft Report. Prepared by
GCA/Technology Division for the U.S. Environmental Protection Agency,
pp. 118-197.
7. Walker, D.J., R.A. Mcllroy, H.B. Lange. Fluidized-Bed Combustion Tech-
nology for Industrial Boilers of the Future: A Progress Report. Prepared
by Babcock and Wilcox Company and presented to American Power Conference,
April 24 through 26, 1978, p. 7.
8. Reese, John T. Utility Boiler Design/Cost Comparison: Fluidized-Bed
Combustion Versus Flue Gas Desulfurization. Prepared by Tennessee Valley
Authority (TVA) for the U.S. Environmental Protection Agency (EPA),
November 1977, EPA-600/ 7-7 7-126, p. 310a.
9. The Resource Conservation and Recovery Act of 1976 Public Law 94-580.
90 Stat. 2795. October 21, 1976.
10. Newby, R.A. , et al. Effect of SOa Emission Requirements on Fluidized-Bed
Combustion Systems: Preliminary Technical/Economic Assessment. Prepared
for the U.S. Environmental Protection Agency by Westinghouse Research
and Development Center. EPA-600/ 7-78-163. August 1978.
11. Farmer, M.H., et al. op. cit.. p. ii.
12. The Fuels Use Act of 1978. Public Law No. 95-620, 92 Stat. 3290.
29
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2.0 EMISSION CONTROL TECHNIQUES FOR
FLUIDIZED-BED COMBUSTION
2.1 INTRODUCTION
The main source of air emissions from fluidized-bed combustion (FBC) is
the combustion unit itself, and the optional carbon burnup cell, if used.
The most important pollutants identified to date are S02, NOX, particulates,
and solid residue.
Fluidized-bed combustion provides in situ retention-of fuel sulfur and,
consequently, lowers the concentration of S02 in the flue gas exhausted from
the boiler. A suitable bed material such as limestone or dolomite is used to
absorb S0£ formed during combustion. An appropriate Ca/S molar feed ratio (Ca
in sorbent versus S in fuel) is selected to meet specific levels of S02 removal,
S02 reduction of 85 percent and higher has been demonstrated in atmospheric
fluidized-bed combustion (AFBC), and investigations are continuing to assess
the influence of gas phase residence time and sorbent particle size to optimize
removal efficiency at low Ca/S molar feed ratios.
Water tubes are submerged directly in the fluidized bed to enhance heat
transfer and maintain operating temperatures at 760° to 870°C (1400° to 1600°F)
There is experimental evidence that S02 removal is optimal in this temperature
range. In addition, at this temperature, bed conditions promote the chemical
reduction of NOx formed by oxidation of fuel nitrogen or atmospheric nitrogen.
30
-------
Uncontrolled NOx emissions from AFBC are typically in the range of 129 to
258 ng/J (0.3 to 0.6 lb/106 Btu) at temperatures characteristic of envisioned
typical AFBC operation.2 Current investigations are considering methods of
further reduction such as staged combustion, flue gas recirculation, or ammonia
injection.
Particulate emissions consist of fuel ash and sorbent elutriated from the
bed. Dust loading to the final particulate control device is expected to be
similar in quantity to that generated by a conventional system, and will vary
depending on fuel ash content, superficial air velocity, sorbent characteristics,
the efficiency of primary and sc ondary cyclones (used for carbon reinjection
and preliminary fly ash removal), and whether or not a carbon burnup cell (CBC)
is used.
Particulate control in FBC is not thoroughly demonstrated since an FBC
unit of sufficiently large size has not yet been operated for a sufficiently
sustained period of time. However, the necessary particle control technology
for FBC applications should be similar to conventional control applications at
conventional boilers burning low sulfur coal. Final particulate capture for an
FBC system can be a hot-side or cold-side application (upstream or downstream
of final heat recovery) using control devices such as electrostatic precipita-
tors, fabric filters, scrubbers, or cyclones.
2.1.1 System Description — Coal-Fired Fluidized-Bed Boiler
A schematic diagram of an atmospheric pressure fluidized-bed combustion
(FBC) boiler is presented in Figure 1, based on a diagram presented by Farmer,
et al.,^ with some modifications by GCA. The unit is comprised of a bed of
sorbent (or inert material) which is suspended or "fluidized" by a stream of
air at 0.3 to 4.6 m/sec (1 to 15 ft/sec)1* depending on the density and particle
size of the bed materials. Coal, or some other fuel is injected into this
31
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CONVECTION
SECTION
HEAT
TRANSFER -*
BAFFLE TUBES
PRIMARY
CYCLONE
SECONDARY
CYCLONE
FUEL
FEED
SORBENT
FEED
AIR
TO HOT SIDE
OR COLD SIDE PARTICLE
CONTROL DEVICE
IN-BED HEAT
TRANSFER TUBES
BED WITHDRAWAL
AIR DISTRIBUTION GRID
Figure 1. Typical industrial FBC boiler.
-------
bed and burned. Sorbent (usually limestone or dolomite) is also injected to
react with the S02 formed upon combustion. The gas velocity is set so that
the bed particles are suspended and move about in random motion. Under these
conditions, a gas/solid mixture behaves much like a liquid (e.g., seeks its own
level, can be readily moved through channels). The boiler tubes submerged
in the bed remove heat at a high rate to maintain bed temperatures in the range
of 760° to 870°C (1400° to 1600°F).
Bed material consists of particles with a maximum size of about 0.6 cm
(1/4 in.), and is comprised of reacted and unreacted sorbent (limestone, dolo-
mite), ash and other inert material, and small quantities (less than 3 percent)
of unburned carbon.5 The air and combustion gases passing through the bed
entrain particles into the freeboard section of the boiler, or carry some of
the smaller particles completely out of the boiler. Boiler tubes can be placed
within the freeboard for convective heat transfer and also to act as baffles
to contain some of the entrained particulate.
Particulate matter completely elutriated from the boiler passes to a
primary cyclone where 80 to 90 percent of the larger carbon containing particles
are removed.6 This collected material can be recirculated back to the FBC unit,
fed to a carbon burnup cell (CBC) to maximize combustion efficiency, or disposed
of. A carbon burnup cell is a separate FBC reactor which is operated at higher
temperatures (1093°C (2000°F)) than the main FBC to achieve maximum carbon
utilization. A secondary particle collector can be installed to collect fly
ash for disposal.
Final heat recovery can be achieved in an economizer and/or air preheater.
Final particulate collection (i.e., after primary and/or secondary cyclones) can
be achieved either upstream (hot-side) or downstream (cold-side) of final heat
recovery.
33
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2.1.2 Mechanisms for S02 Control
Sulfur dioxide emissions are a major problem in conventional coal-fired
industrial boilers. However, by using FBC technology, S02 emissions can be
reduced by up to 90 percent or more depending upon the rate of sorbent addition
to the bed and the FBC design and operating conditions. The coal is burned in
the bed in the presence of lime (CaO). The S02 reacts with the calcium oxide
and excess oxygen forming calcium sulfate (CaSOi^).7
SC>2 + CaO + 1/2 02 •+• CaSOit (anhydrous)
The CaO in the reaction is produced by rapid calcining of calcium carbonate.
The sorbent is most commonly limestone or dolomite. The degree of S02 capture
possible in FBC industrial boilers is strongly dependent on the calcium to
sulfur molar feed ratio (Ca/S). Other factors which affect the sulfur capture
efficiency of the system are the reactivity of the sorbent, the particle size
of both sorbent and coal, gas residence time in the bed (determined by super-
ficial gas velocity and bed height), the feed mechanism and material distribu-
tion in the bed, and temperature. These parameters can be adjusted to obtain
the maximum S02 removal for the system at a particular Ca/S molar feed ratio.
S02 control will be achieved typically on a once-through basis. In a
once-through system, spent sorbent is removed from the combustor and disposed
of as sulfated stone. Although sorbent regeneration will not likely be used
in the near future in industrial FBC boilers, a typical regeneration technique
would process the spent stone in a separate reaction vessel by reductively
decomposing the spent sorbent to form CaO and S02- The S02 would be sent to a
sulfur recovery system to generate elemental sulfur or sulfuric acid. The
regenerated stone as CaO could then be recycled to the combustor as makeup
sorbent.
34
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2.1.3 Mechanisms for N0y Control
Nitrogen oxide (NOX) emissions from FBC are inherently lower than uncon-
trolled emissions from conventional combustion. The primary reason for this
seems to be the unique combustion chemistry which occurs in the fluidized bed.
The fact that the combustor temperature is considerably lower in FBC (815° to
930°C (1500° to 1700°F)) than conventional combustion (1500°C (2700°F)) also
aids in lowering NOX emissions due to reduced fixation of atmospheric nitrogen,
but does not seem to be the predominant factor. Formation of NOx at the lower
temperatures is primarily due to the oxidation of fuel nitrogen.
2N (fuel) + 02 -*• 2NO
The NO is formed rapidly as the coal burns and is thought to be reduced in the
presence of carbon monoxide and other products of incomplete combustion3 by a
reaction such as the following:9
2CO + 2ND + 2C02 + N2
At higher conventional combustion temperatures a larger proportion of NOX is
derived from the oxidation of atmospheric nitrogen:10
Na (atmospheric) + QZ •*" 2ND
The reaction rate is relatively slow and temperature dependent. The temperature
and the NOX residence time are not conducive to the NO reduction reaction, so
that the final NOX emissions from conventional boilers are higher than those
from FBC.
Some combustor design and operating conditions tend to increase NOX emis-
sions; e.g., increasing bed temperature, increasing excess air, decreasing gas
residence time, and possibly increasing fuel nitrogen content. However, the
influence of these variables on NO emissions cannot be quantitated or correlated;
X
the mechanisms of NOX formation and decomposition in FBC are not well understood.
35
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Experimental NOX emissions data are scattered. Hence, it is not possible to
design FBC's for low NOX emissions with the same reliability possible for S0?.
Combustion modification methods which are used to reduce NOX emissions in
conventional boilers can also be applied to fluidized-bed combustion. Prelim-
inary experimentation indicates that staged combustion may be successfully
applied to FBC.11 The bed would be operated at low excess air, which inhibits
the formation of NOX. Secondary air would then be injected above the bed to
complete the combustion process. Further investigation on large-scale FBC units
is necessary to confirm the benefit of implementing combustion modifications on
industrial FBC boilers.
2.1.4 Mechanisms for Particulate Control
Particulate matter emitted from the combustion section of an FBC coal-fired
boiler consists of fly ash from the coal, unburned carbon, and elutriated sor-
bent material. (Most of the spent sorbent will be withdrawn from the bed as a
solid residue, and, thus will not appear in the flue gas, except in the case of
advanced FBC concepts involving high-sorbent-recirculation techniques.) The
superficial gas velocity is an important factor in determining particulate
escape from the combustor. A high percentage of small-sized particles with
terminal settling velocities less than the superficial air velocity will be
blown out of the bed. Due to turbulence in the system, geometry, and freeboard
height, some larger particles will also be elutriated, and some small particles
will remain.12 The amount of sorbent particulate matter passing out of the bed
will depend coon particle size reduction brought about by attrition and decrepi-
tation, which refer to particle grinding and roasting, respectively.
A primary cyclone is used to collect larger particles containing the most
significant carbon concentration for circulation back to the FBC or to a separate
36
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carbon burn >ip cell (CBC). A secondary cyclone of higher efficiency can also
be used to collect smaller particles for disposal as ash. Design of combustors
with high freeboard or baffle heat exchange tubes in the freeboard can help to
reduce the amount of particulate elutriated to the primary cyclone.
Final particulate control (after primary and/or secondary cyclones) will
be provided by use of conventional systems such as electrostatic precipitators,
fabric filters, scrubbers, or cyclones. These systems can be operated as hot-
side or cold-side units (upstream or downstream of final heat recovery), except
for fabric filters which must be installed cold-side to prevent fabric burning.
Although no final stage particulate control device has yet been demonstrated
on an FBC unit, it is expected that, by suitable control device design and
operation, conventional particle control devices should be adequate to meet
the optional emission levels considered in this study.
ESPs are a demonstrated control device on large conventional combustion
units, and are capable of removing small particles (<5 um) at high efficiency.
However, resistivity of the particulate from FBC units is expected to be high,
due to lime, limestone, and calcium sulfate in the flue gas and low concen-
trations of S02. If current problems with high particle resistivity can be
overcome, ESPs may be used on FBC industrial boilers.
Fabric filters have been demonstrated for utility boiler applications,
and may be especially applicable for industrial FBC particulate control because
of high collection efficiency and insensitivity to particle resistivity. Due
to low S02 concentrations and a low acid dew point in FBC flue gas, a fabric
filter could bt- operated at low temperatures without fabric detr-.r iurat ion.
Potential pro'.: loins with fabric filter application in FBC include blinding and
bag fires. Blinding could occur depending on flue gas moisturt ,tnd the
37
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possibility of calcium oxide hydration in the baghouse. The potential also
exists for bag fires if unburned carbon loadings become excessive and tempera-
ture excursions occur in the baghouse during transient conditions such as
startup or shutdown.
Scrubbers could be used, but pressure drops required for high efficiency
small particle removal may be excessive. In addition, the potential for a
water pollution control problem exits.
Cyclones may not be capable of providing satisfactory retention of small
particles <5 \im. However, they may be used in the smaller boiler size categories
depending on control level required because of potential overall system cost
advantages. Application of more sophisticated devices on small capacity FBC
boilers may result in an unwarranted economic penalty to the industry. The
effectiveness of multitube cyclones, cyclones which operate at high differential
pressure, or advanced cyclone designs, needs to be explored. In general, further
study is required to determine the most appropriate final particulate collection
method for FBC systems of different size firing different fuels.
Fly ash handling requirements will be similar to conventional combustion
system needs. The major additional equipment needed for FBC system operation
is sorbent feed and spent sorbent handling facilities. An advantage of FBC
systems is that spent stone can be handled in dry form. Coal feeding may also
be different in FBC, especially if underbed feeding is used. This technique
would use air injectors to spread the coal throughout the volume of the bed.
In bed feeding may be needed to provide suitably long sorbent residence time
for highly efficient SC>2 control. To date, experimental results indicate that
primary recycle should be capable of providing the necessary residence time,
but further work is necessary to confirm this.
38
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Another major equipment need is the forced draft fan which has to overcome
approximately three times the pressure drop encountered in a conventional
boiler. The additional pressure is needed for air passage through the dis-
tribution plate and for bed fluidization.
2.1.5 Differences in Possible AFBC Industrial Boiler Designs
Several alternative AFBC industrial boiler designs are possible. Table 11
summarizes potential alternative generic boiler arrangements. Table 12 lists
specific design differences among vendors that are developing FBC boilers for
commercial offering. The design conditions which impact emission control are
noted. Most industrial AFBC boilers currently offered are designed with water
tube heat exchangers in the bed. Additional heat transfer surface in the free-
board can also be used. The Johnston Boiler Company is offering a combined
water tube/fire tube unit as shown in Figure 2.13 The Battelle Multisolids
Fluidized Bed uses a separate ancillary dense bed for heat exchange and an
entrained bed for combustion.14> A fluidized-bed air heater is offered by the
FluiDyne Company.15
2.1.5.1 Coal Feed Systems—
l
Different coal feed mechanisms are being used by different manufacturers.
Stone-Platt is manufacturing systems in which the coal is screw fed just below
the top surface of the bed at the center of the unit.16 The demonstration unit
under construction at Georgetown University (designed by Foster-Wheeler and
Pope, Evans and Robbins) will utilize an overbed spreader coal feed system.17
AFBC boilers using staged combustion are offered by 0. Mustad and Sons of
Gjovik, Norway.18
39
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TABLE 11. SUMMARY OF POTENTIAL ALTERNATIVE AFBC INDUSTRIAL
BOILER SUBSYSTEM DESIGNS
Subsystem
Possible alternatives
Comments
Fuel and sorLent
feed mechanism
Heat transfer
Bed type
In bed or above bed (by vibra-
tional, pneumatic, or stoker
feeding)
Single point versus multiple
point injection
Water, steam, air and other
media
In bed or above bed or both;
or in separate ancillary bed
Deep or shallow
Dense, lean, or entrained
Elutriated solids
Spent bed material
Disposed of as ash or recircu-
lated to main bed or carbon
burnup cell
Direct disposal or regeneration
with recycle to main bed
The air pollution impact of overbed feed AFBC sys-
tems is unkown. It is anticipated that S02 and NOX
emissions may be increased with overbed feed systems,
Multiple point injection generally results in
better bed mixing.
To date, only water, steam, and air have received
much consideration.
Heat transfer surface in the AFBC freeboard can be
water tubes or fire tubes. Battelle Multisolids
Unit is using separate ancillary bed for heat
exchange.
Deep bed is usually in the range of 1 meter (3 to
4 feet). Shallow beds of about 0.3 meters (6 to
12 inches) are proposed for use in staged
combustion.
Dense bed operated at low gas velocity provides
best emission control. Lean bed operated at high
gas velocity to provide good mixing and high heat
transfer.
Recirculation is being considered to improve com-
bustion efficiency and S02 capture.
Regeneration of sulfated stone is being investi-
gated to minimize sorbent makeup and disposal rates
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TABLE 12. DESIGN/OPERATING CONDITIONS OF "COMMERCIALLY-OFFERED" AFBC INDUSTRIAL BOILERS
Pesign/apetaclag
conditions
Bed p4ra«eE?r
Temperature, °F
Expanded bed depth, ft
Gaa velocity, ft/sec
&a« resldenc* time, sec
Freeboard height, ft
Number of cells
Bel area. ft:
Rate, lb/hr
Pressure. 16/in.^
Temperature. °r
Feedw*ter, °F
F*ed Conditions
Coal
HI IV, Bcu/lb
Sjlfur, r
Size
Feeder type
Scrbent
ceed rate, lb/hr
Ca/S
Site
S capture, *
Air
Excess air
Boiler efficiency
t'Lue gas temperature, °F
Inpact of design conditions
^n emission control
- " lf> Mesh,
1001 < 8 *»•»
-
25
81
305
Ov
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Limestone Bunker
Coal Bunker
J
ooo
Control Panel
ooooo
QQQd
f—\ \Variable Speed)
Variable\ \ Coal Feed
Speed
Limestone
Feed
Mechanical
Oust
Collector
Figure 2. Johnston Boiler Company's combination watertube/firetube FBC boiler.13
(Reproduced with permission.)
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2.1.5.2 Solids Handling and Disposal—
Most experimental, demonstration, and commercially available systems
incorporate recycling of elutriated bed solids to maximize combustion efficiency.
Small boilers (less than 15 MWt) will generally recycle elutriated solids to
the main bed while larger systems may recirculate to a separate carbon burnup
cell. The Rivesville plant constructed by Foster-Wheeler is a multicell unit
which includes a carbon burnup cell.19 The boiler at Georgetown University
is designed with two cells, one of which can be used as a duplicate main cell
or for burning recycled material.
In first generation AFBC boilers spent bed material will be withdrawn
for direct disposal or byproduct recovery. Regeneration is a long-term develop-
ment which will find greatest application in utility boilers or in industrial
parks as a means of reducing sorbent feed and disposal requirements.
2.1.6 Impact of Key Design Features
Key features which could impact emission control performance in these
commercial designs are method of solids feed (overbed feed or underbed feed),
bed depth, superficial gas velocity, and sorbent particle size.
2.1.6.1 Superficial Velocity—
Most of the existing designs employ some combination of superficial
velocity and bed depth which allows for gas residence times of 0.5 sec or
less. The notable exception is the FluiDyne design, which for the conditions
listed in Table 12, attains gas residence times between 0.6 and 2 sec. Gas
residence times of 0.5 sec and below may require unnecessarily high Ca/S ratios
to attain high desulfurization levels. This impacts energy efficiency, overall
system cost, and waste disposal. NOX control may also be slightly limited at
lower gas residence times. Estimated best conditions for bed depth, super-
ficial velocity and gas residence time are discussed in Section 3.0.
43
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2.1.6.2 Coal and Sorbent Feed Mechanisms—
Solids feed orientation can also affect emission control. Overbed feeding
is technically simpler than underbed feeding, but solid and gas residence time
may be less than desirable. 862 released above the bed would be captured with
reduced efficiency and sorbent may be elutriated before it has a chance to
react. There is early indication from FluiDyne testing that feed method may
be of minor importance in S(>2 control as long as primary recycle is practiced.
However, this needs to be confirmed in more extended large-scale testing.
2.1.6.3 Particle Size—
Another design parameter of major concern with respect to SC>2 control is
sorbent particle size. The feed particle size distributions noted by the
vendors suggest inbed average sizes in the range of 1,000 to 2,000 ym. This
cannot be estimated with certainty because only the top and bottom size limits
of the feed sorbent are noted, and the extent of particle attrition in the
bed is unknown. However, experimental data and theoretical considerations
suggest that inbed particle sizes of about 500 ym surface average are appro-
priate for good S02 control. Overall sorbent requirements can be reduced by
using smaller particles with primary recycle.
The Mustad system is worthy of note since it is designed with a shallow
bed and two-stage combustion. Although this may provide significant reduction
of N0x» the impact on S02 control must be verified.
2.2 STATUS OF DEVELOPMENT
Fluidized-bed combustion is an emerging technology for the clean combus-
tion of fuels. First experimentation with FBC for steam generation was con-
ducted by Combustion Engineering, Inc., in the early 1950s, the British in
the early 1960s, and PER in the mid-1960s under sponsorship of the Office of
Coal Research.
44
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2.2.1 U.S. Department of Energy Development Programs
The U.S. Department of Energy (DOE) Office of Fossil Energy is conducting
an extensive program for development of coal-fired industrial AFBC boilers as
part of the National Energy Research, Development, and Demonstration Program,
to fulfill the following objectives:
• Identify and conduct evaluations of industrial
boiler or process heater requirements to deter-
mine the applications in which FBC is technically,
economically, and environmentally feasible.
• Obtain sufficient data from prototype operations
to design and construct a commercial-size unit.
Four FBC demonstration units are currently in the design or construction
phase as a result of ongoing DOE Programs.
The four units are being developed by:
• Combustion Engineering
• Fluidized Combustion Company (joint venture
of Pope, Evans, and Robbins, and Foster-Wheeler)
• Battelle Memorial Institute
• EXXON Research and Engineering Company
2.2.1.1 Combustion Engineering - Great Lakes Naval Training Center—20
Combustion Engineering will develop a package fabricated coal-fired indus-
trial steam generation boiler. Their work is divided into two phases. The
first is design and construction of a subscale test unit with a bed area of
0.3 m2 (3.0 ft2) capable of generating 1,044 kg/hr (2,300 Ib/hr) steam. This
unit is currently operating. The second phase is design and construction of
a commercial-scale FBC package boiler capable of generating 22,700 kg/hr
(50,000 Ib/hr) steam with a coal feed rate of 2,270 kg/hr (5,000 Ib/hr). This
unit will be located at the Great Lakes Naval Training Center in Illinois and
is scheduled for startup in 1981.
45
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2.2.1.2 Foster-Wheeler/Pope, Evans, and Robbins - Georgetown University—21
Foster-Wheeler and Pope, Evans, and Robbins are jointly completing instal-
lation of a 45,400 kg/hr (100,000 Ib/hr) steam generating FBC on the campus
of Georgetown University in Washington, D.C., which will supply steam for space
heating at the University. Startup began during the summer of 1979.
2.2.1.3 Battelle - Multisolid Fluidized-Bed Combustion (MSFBC)—22
The Multisolid Fluidized-Bed Combustion process was developed under the
Battelle Energy Program over a 3-year period. The feasibility of this concept
has been successfully demonstrated in a 6 in. diameter coal-combustion unit.
The U.S. DOE contract with Battelle calls for a two-phase scale-up of this
process over 6 years (including 3 years of operating the demonstration plant).
The Sub-Scale Experimental Unit System (SSEUS), which represents a 10-fold
scaleup of the 6 in. bench-scale unit, is now in operation. This pilot-scale
unit is designed to produce about 1,820 kg/hr (4,000 Ib/hr) steam from 182 kg/
hr (400 Ib/hr) coal. The full-scale demonstration plant, which will be built
adjacent to Battelle*s present steam plant, will represent a further scale-up
of about six times and will produce 11,350 kg/hr (25,000 Ib/hr) steam while
burning 1,135 kg/hr (2,500 Ib/hr) coal. Data obtained from this demonstration
unit will be used to design and build commercial boilers. The MSFBC consists
of a combined dense and entrained fluidized bed to accomplish combustion and
desulfurization. Entrained bed material can be recirculated to the dense
bed.
2.2.1.4 EXXON - Crude Oil Heating System—23
Some proportion of crude oil (~4 to 12 percent) processed in an oil re-
finery is consumed to maintain refinery operations. Under DOE contract, the
EXXON Research and Engineering Company is exploring the feasibility of using
46
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coal combustion processes to satisfy this energy requirement. The objectives
of the program are first to extend the state-of-the-art of fluidized-bed crude
oil heating for refinery applications. Second, an FBC indirect-fired process
heater will be designed and constructed as an integral part of a petroleum
refinery. Phase 1 of the program includes the following three laboratory
experiments:
• Two dimensional flow visualization units
• Process stream coking unit
• High temperature heat flux unit
Phase II incorporates installation and demonstration of a coal-fired FBC
process heater at an EXXON refinery with a capacity between 2.9 to 4.4 MWt
(10 to 15 x 106 Btu/hr).
• 9 li
2.2.1.5 Anthracite Culm Combustion Program—
The anthracite culm combustion program was developed by DOE based on
successful results at the Morgantown Energy Research Center. Three demonstra-
tion units are planned in the State of Pennsylvania as follows:
• City of Wilkes-Barre
Foster-Wheeler and Pope, Evans, and Robbins will build
a 45,400 kg/hr (100,000 Ib/hr) FBC boiler burning an
anthracite coal/culm mixture to produce steam for district
heating and air conditioning within the city. Fuel will
be obtained from the Pine Ridge Anthracite bank located
in the city. The City of Wilkes-Barre is the prime
contractor and program administrator. Foster-Wheeler
is responsible for hot model testing and boiler design
and erection. Pope, Evans, and Robbins will provide
overall system layout, detail design, and program
management.
• Shamokin Area Industrial Corporation (SAIC)
A 9,080 kg/hr (20,000 ]b/hr) FBC boiler burning anthracite
culm will be installed at the Cellu Products paper reproces-
sing plant in Shamokin. Fuel will come from the nearby
Swift Colliery. SAIC is the prime contractor responsible
for site selection, feedstock supply, and steam user
47
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coordination. Other contractors involved are Curtiss-
Wright, Dorr-Oliver, and Stone and Webster. Curtiss-
Wright will provide overall program management.
Dorr-Oliver will conduct subscale testing, process
selection, and assess prototype performance. Stone
and Webster will provide architectural/engineering
services, including equipment design and selection,
specification and bid package preparation, and assess-
ment of environmental control.
• FluiDyne Engineering Company
FluiDyne, together with Deltrak and Nebraska Boiler
Company will install a boiler at the GTE Sylvania
plant in Towanda, as a replacement for an existing
oil-fired boiler. The unit will generate 9,080 to
13,600 kg/hr (20,000 to 30,000 Ib/hr) steam. FluiDyne
is the prime contractor responsible for all subscale
testing, engineering, procurement, and construction.
The boiler package will be subcontracted through the
other two firms mentioned above.
2.2.1.6 Recent Drive for Accelerated Commercialization—
As of April 1979, DOE continued its commercialization drive for industrial-
sized AFBC boilers by requesting submittals of cost-sharing proposals for the
following industrial categories:
Industry SIC Code
Petroleum 29
Chemical 28
Primary metals 33
Paper and pulp 26
Food 20
If the potential for significant oil and gas savings is shown, the Program
Opportunity Notice (PON) will invite industry proposals for four plants pro-
ducing 90,800 kg/hr (200,000 Ib/hr) steam.
2.2.2 State of Ohio's Development Program25
On other fronts, the State of Ohio is active in the commercialization of
fluidized-bed combustion. During the natural gas shortage of the winter of
1976, it became clear to the state that coal must be used more widely than it
48
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had been. At the same time, the federal government was considering implemen-
tation of more stringent S02 emission standards. Since Ohio mines yield
high sulfur coal, there was concern from the coal industry and the governor
about possible loss of jobs and fulfillment of energy needs in the state.
Therefore, a committee was established to investigate FBC as a possible answer
to the problem. The committee's investigation led to plans for installation
of three FBC boilers to demonstrate the feasibility of the technology as applied
to Ohio's needs.
The Governor's Coal Use Committee selected Babcock Contractors, Inc.
(a joint venture with Riley Stoker Corporation) to install a 27,000 kg/hr
(60,000 Ib/hr) steam retrofit FBC boiler at the Central Ohio Psychiatric
Hospital. The unit will be used for space heating and will startup during
1980. The other two boilers are planned as new installations, one for space
heating and process steam production, and the other for electricity generation.
The former is a 45,000 kg/hr (100,000 Ib/hr) steam unit planned for the Ohio
State Penitentiary in Columbus. Design is progressing on the latter boiler
which will be of utility size; 160,000 kg/hr (350,000 Ib/hr) steam capacity
to be installed at the Columbus and Southern Ohio Electric Company at Piqua,
Ohio. Construction and start-up schedules for these two units are uncertain
at this time.
2.2.3 Commercial Availability of Fluidized-Bed Boilers
Commercial orders for FBC boilers are progressing, and it appears that
foreign boiler manufacturers have received a significant share of initial
orders. This includes Babcock Contractors, Inc. with one boiler contracted
in Ohio,26 and Stone Platt of Netherton, England, having sold FBC boilers to
Virginia Polytechnic Institute (an experimental unit) and General Motors.27
These two boilers are currently scheduled for startup.
49
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Johnston Boiler Company of Ferrysburg, Michigan claims four sales to date.
These include an 18,160 kg/hr (40,000 Ib/hr) steam coal-fired unit at the
Central Soya Company in Ohio. Two wood-fired units have been sold, one of
9,080 kg/hr (20,000 Ib/hr) steam capacity to the Herman Miller Company, a furni-
ture manufacturer in Zeeland, Michigan, and a second of 4,540 kg/hr (10,000
Ib/hr) steam capacity to the Pike Lumber Company in Atkron, Indiana. IBM, in
Charlotte, North Carolina, purchased a 9,080 kg/hr (20,000 Ib/hr) steam boiler
capable of firing gas/oil with the potential to switch to coal. All of these
units are scheduled for startup in late 1979 and 1980. 28
FBC development is occurring internationally as shown in Section 2.2.5.1,
Table 13, in the United Kingdom, West Germany, Canada, India, and other countries
2.2.3.1 Users Satisfaction/Acceptance of First Generation FBC Boilers —
The demand for FBC industrial boilers will increase as:
• The reliability of FBC technology is commercially
demonstrated through continuous boiler operation
with effective emission control.
• The economics of FBC use are shown to be competitive
with conventional systems controlled at similar
efficiency for 862, NOx, and particulate matter.
• Government regulations concerning energy policy
evolve which emphasize coal use in new facilities.
• Environmental control requirements are more firmly
defined .
The results of the ongoing DOE program, the Ohio program, and initial
operating results with boilers sold by Johnston Boiler Company, Foster-Wheeler
Babcock Contractors, Inc., Stone Platt, and others will be of major importance
in establishing demand for industrial FBC boilers in the future. Although
50
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bench-scale and pilot facilities have been operated, until actual commercial
use for a year or more of continuous operation is demonstrated, widespread
demand will not develop.
2.2.4 Summary of Existing Fluidized-Bed Units
Table 13 is a listing of industrial AFBC demonstration facilities and
pilot-scale test facilities.
2.2.5 Applicability of Fluidized-Bed Combustion to Industrial Uses
2.2.5.1 Limitations by Boiler Type—
Fluidized-bed combustion can be used in place of practically any type
of boiler (stoker, pulverized coal, gas/oil) in any application such as
saturated/unsaturated steam, process heating (water, air, crude oil), and
direct/indirect heating. FBC may also be used to advantage in instances
where conventional technology is limited because of FBC's proven multifuel
capability.
In the industrial boiler capacity size range of less than 73 MWt (250 x
106 Btu/hr), it is expected that most, if not all FBC units, will operate at
atmospheric pressure with a once-through sorbent processing scheme. Most
industrial FBC boiler users probably will not have sufficient need for onsite
electric power generation to justify the additional capital and operating costs
and operational complexity associated with pressurized FBC systems. In addi-
tion, atmospheric systems are now commercially offered for industrial use. A
similar argument of economics, operational complexity, and technological demon-
stration holds true for sorbent regeneration systems. It is expected that the
normal industrial user will select a once-through sorbent operating scheme,
due to its demonstrated simplicity and lower cost, at least in first generation
FBC installations.
51
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TABLE 13. AFBC COAL-FIRED DEMONSTRATION AND TEST UNITS
Ul
to
Developer
Industrial Demonstration Units
Combustion Engin jring
Foster-Wheeler; Pope, Evans, and
Robbins; and Georgetown
University
Exxon Research and
Engineering Co.
Battelle-Columbus
Laboratories
Foster-Wheeler; Pope, Evans,
and Robbins
Shamokin Area Industrial
Corporation (SAIC) ; Curtiss-
Wright, Dorr-Oliver; Stone
and Webster
Fluidyne Engineering Co.;
Deltrak; Nebraska Boiler
Company
Foster-Wheeler; Pope, Evans,
and Robbins
Babcock and Wllcox, Ltd.
(England)
Babcock and Wilcox Company
(U.S.)
Morgan town Energy Research
Center
Capacity
22,700 kg/hr
(50,000 Ib/hr)
steam
45,400 kg/hr
(100,000 Ib/hr)
steam
3 - 4 MJt
(10-15 x 106 Btu/hr)
11,350 kg/hr
(25,000 Ib/hr)
steam
45,400 kg/hr
(100,000 Ib/hr)
steam
9,080 kg/hr
20,000 Ib/hr)
steam
9,080 - 13,600 kg/hr
(20,000 - 90,000 Ib/hr)
steam
88 MHt
(220 x 1Q6 Btu/hr)
12 MWt
(40 x 106 Btu/hr)
6 MHt
(20 x 106 Btu/hr)
18 tVt
(60 x 106 Btu/hr)
Location
Great Lakes Naval
Training Base,
Illinois
Georgetown University
Washington, D.C.
Linden, New Jersey
or Bay town, Texas
Columbus, Ohio
Wllkes-Barre,
Pennsylvania
Cellu Products
(Paper Company)
Shamokin,
Pennsylvania
GTE Sylvania,
Towanda ,
Pennsylvania
Rivesville, West
Virginia
Renfrew, Scotland
Alliance, Ohio
Morgan town, West
Virginia
Sponsor
U.S. Department of
Energy (Cosponsor)
U.S. Department of
Energy (Cosponsor) .•
U.S. Department of
Energy (Cosponsor)
U.S. Department of
Energy (Cosponsor)
U.S. Department of
Energy
U.S. Department of
Energy
U.S. Department of
Energy
U.S. Department of
Energy
-
Electric Power
Research Institute
U.S. Department of
Energy
Status and comments
Construction to begin during
winter, 1978
Startup scheduled for summer,
1979
This unit is a process crude
oil heater and is currently
in the pretesting and design
evaluation phase
Under design based on SSEUS
test unit, see below
To be constructed under DOE
anthracite culm program
To be constructed under DOE
anthracite culm program
Replacement for existing
oil-fired boiler, to be con-
structed under DOE anthracite
culm program
Currently operating
Retrofit unit currently
operating
Currently operating
Under design
(continued)
-------
TABLE 13 (continued).
Developer
Babcock and Wllcox, Ltd.
(England)
To be negotiated
To be negotiated
Johnston Boiler Co.
Johnston Boiler Co.
Johnston Boiler Co.
Wormser Engineering,
Inc.
Must ad and Son
(Gjovik, Norway)
Coal Processing
Consultants (B&tf, Ltd.)
Energy Equipment
Ruhrkohle
Wesertal GMBH
Mitchel Engineering
Capacity
27,250 kg/hr
(60,000 Ib/hr)
steam
45,400 kg/hr
(100,000 Ib/hr)
steam
160,000 kg/hr
(353,000 Ib/hr)
steam
3 MWt
(10 x 106 Btu/hr)
18,200 kg/hr
(40,000 Ib/hr)
steam
9,080 kg/hr
(20,000 Ib/hr)
steam
6 MWt
(20 x 106 Btu/hr)
25 MWt
(85 x 106 Btu/hr)
36,300 kg/hr
(80,000 Ib/hr)
steam
13,600 kg/hr
(30,000 Ib/hr)
steam
35 MWt
(105 x 106 Btu/hr)
125 KW
(375 x 106 Btu/hr)
36,300 kg/hr
(80,000 Ib/hr)
steam
Location
Central Ohio
Psychiatric Hospital
Columbus, Ohio
Ohio State
Penitentary
Columbus, Ohio
Columbus and Southern
Ohio Electric Company
Piqua, Ohio
Johnston Boiler Co.
Ferrysburg, Michigan
Central Soya
IBM, Charlotte,
North Carolina
Lowell, Massachusetts
Vanneverk (Heating
Works) EnkOping,
Sweden
Prince Edward Island
Cadbury SCHWPS
Boarnville
United Kingdom
Dusseldorf-Flingern
West Germany
Hameln,
West Germany
Don River,
United Kingdom
Sponsor
Ohio Department of
Energy
Ohio Department of
Energy
Ohio Department of
Energy
Private
Private
Private
Private
*~
Private
Private
Private
Private
British Steel
Status and comments
Startup scheduled for late
1979
Retrofit Installation
currently In planning
stage
Utility boiler currently
in planning stage
Demonstration boiler
currently operating.
Recently sold
Recently sold; designed as
oil/gas unit capable of
burning coal
Currently operating
Startup currently
scheduled
Startup scheculed for
1982
Currently operational
Startup scheduled for early
1979
Currently operational
Currently operational
(continued)
-------
TABLE 13 (continued).
ui
Developer
Pilot Scale Test Units
Combustion Engineering
Energy Resources Company
Pope, Evans, and Robbins
Stone Platt Fluidfire, Ltd.
Stal-Laval Turbine
Company (Finspaug, Sweden)
Fluidyne Engineering
EPA Sampling and Analysis
Test Rig (SATR)
Babcock and Wilcox Company
(U.S.)
Battelle-Columbus
Laboratories (SSEUS)
Capacity
1 MHt
(3 x 106 Btu/hr)
1.8 MWt
(6 x 106 Btu/hr)
1.5 MWt
(5 x 106 Btu/hr)
0.3 MWt
(1 x 106 Btu/hr)
1.5 MWt
(4.5 x 106 Btu/hr)
<5,700 kg/hr
(12,600 Ib/hr)
hot air output
<»0.3 MWt
(1 x 106 Btu/hr)
1.5 MWt
(5 x 106 Btu/hr)
1.5 MWt
(5 x 10s Btu/hr)
Location
Windsor, Connecticut
Cambridge,
Massachusetts
Alexandria,
Virginia
Virginia Polytechnic
Institute; Blackburg,
Virginia
District Heating Plant
Orebro, Sweden
Minneapolis ,
Minnesota
Research Triangle Park,
North Carolina
Alliance, Ohio
Columbus , Ohio
Sponsor
U.S. Department of
Energy
Private
U.S. Department of
Energy
••
-
U.S. Environmental
Protection Agency
Electric Power
Research Institute
U.S. Department of
Energy
Status and comments
Currently operating
Currently operating
Currently operating
Startup currently scheduled
Currently operating
Currently operating
Currently operating
Currently operating
-------
Heat exchange media used in fluidized-bed boilers will include steam, air,
and other fluids (e.g., process streams such as crude oil). In most units, heat
transfer surface in the form of water or air tubes will be immersed directly
in the fluidized bed to maximize heat transfer rate and efficiency. Convective
transfer surfaces (water tube, fire tube, air tube) could be applied to act
as superheater, preheater, or economizer.
2.2.5.2 Limitations by Fuel Characteristics—
Fuel flexibility is an important advantage of FBC use in the industrial
sector due to the incentive to burn industrial byproducts and low-grade, high
sulfur fuels not easily burned in conventional boilers. FBC boilers have
multifuel capability and can burn all ranges of coal, oil, and gas and some
industrial wastes.
Johnston Boiler is currently offering multifuel FBC boilers, having sold
one coal-fired unit, one gas/oil unit (with coal-firing capability), and two
wood-fired units. Other tests have been conducted with all types of coal
including anthracite/anthracite culm at the Morgantown Energy Research Center
and lignite at the Grand Forks Energy Research Center. Industrial byproduct
waste combustion has also been demonstrated.
2.2.5.3 Limitations by Boiler Size—
The concensus of opinion indicates that widespread application of coal-
fired FBC industrial boilers will be limited to systems greater than 15 to
30 MWt (50 to 100 x IQ6 Btu/hr)29"32 due primarily to the disporportionately
high cost of related coal and ash handling equipment for smaller units. However,
Johnston Boiler Company33 is marketing coal-fired units as small as 1,140 kg/hr
(2,400 Ib/hr) steam which is roughly equal to 0.9 MWt (3.1 x 106 Btu/hr). To
date, the smallest unit they have sold expressly for coal-firing has a capacity
55
-------
of 18,160 kg/hr (40,000 Ib/hr) steam or about 15 MWt (50 x IQ* Btu/hr). Johnston
has also sold a gas/oil unit capable of coal-firing with a capacity of 4,540
kg/hr (10,000 Ib/hr) steam or about 4 MWfc (13 x 1Q6 Btu/hr). In general, if
FBC industrial boilers are used in the size range <30 MWt (<100 x lo6 Btu/hr)
they may be employed to burn oil or possibly gas with future conversion to
coal based on trends in fuel availability and environmental standards.
The important feature of FBC with respect to boiler size is that it may
extend to lower limits, the boiler size in which coal can be used due to lower
system cost and the avoidance of 802 scrubbing. There does not appear to be
any technical lower capacity limit to coal-firing with FBC technology.
FBC boilers have achieved heat release rates of >1 MWt/m3 (>100,000
Btu/hr/ft3) of expanded bed volume or 0.5 to 0.6 MWt/m3 (50 to 60,000 Btu/hr/
ft ) of firebox. This compares to a heat release rate of 0.2 MWt/m3 (20,000
Btu/hr/ft3) of firebox in a conventional pulverized coal boiler.3** Therefore
it is anticipated that package FBC units will be available in larger thermal
capacities than conventional boilers.
First generation fluidized-bed combustion boilers will most likely be in
the energy capacity range of less than 73 MWt (250 x io6 Btu/hr) thermal input.
Industrial, commercial and institutional facilities with new, additional or
replacement energy needs will be the potential buyers for the FBC boilers in
that category. Presently, there are over 3,000 United States boilers in this
size category.35
The Fuels Use Act of 197836 may provide an incentive for use of coal-fired
FBC boilers in capacities greater than 29 MWt (100 x IO6 Btu/hr). The legis-
lation calls for use of coal-firing in all new boiler systems greater than this
capacity unless the effectiveness of coal use can be proven unsuitable for
technical or economic reasons.
56
-------
A summary of expected FBC boiler configurations by size range is provided
in Figure 3.
2.2.5.4 Retrofits—
A study by EXXON concluded in 1976 that retrofitting FBC to an existing
conventional industrial boiler would be economically unattractive.37 However,
one retrofit FBC boiler is operating and another is planned for conmercial
installation. Babcock and Uilcox, Ltd. constructed a 18,000 kg/hr (40,000
Ib/hr steam) FBC retrofit on a stoker-fired boiler in Renfrew, Scotland. They
are planning installation of a 27,000 kg/hr (60,000 Ib/hr) retrofit unit at
the Central Ohio Psychiatric Hospital for space heating purposes. These retro-
fits are on stoker-fired boilers, where the existing grate is replaced with a
fluidized bed incorporating heat exchange tubes. The existing convective heat
transfer surfaces can be retained, thus minimizing the extent of conversion
required. If retrofitting is considered, the stoker-fired boiler is the most
appropriate system because actual conversion requirements are minimized and
capacity downrating may not result.
The actual economic and technical feasibility of FBC retrofitting is not
known, but will be extremely site-specific. However, based on these early
ventures by B&W, Ltd., it is apparent that FBC technology can be considered in
instances where system retrofitting might be appropriate.
2.2.6 Projections of Potential Market for Fluidized-Bed Combustion
Farmer, et al., have estimated potential national industrial FBC boiler
application through the year 2000.38 Most of the potential is expected to be
in the chemicals, petrochemicals, petroleum refining, paper, primary metals,
and food industries which are the industrial categories with the heaviest
steam demand. These projections were made in 1976. Since the current
57
-------
Capacity range, MW (106 Btu/hr) thermal Input
Parameter 0.1 0.3 2.9 7.3 29.2 U6 438
(0.4) (1.0) (10) (25) (100) (500) (1.500)
Fuel
Coal
Industrial byproduct*
Residual oil
Distillate oil
Gaa
Heat transfer
configuration
Water tube
Fire tube
Combined water
tube/fire tube
Air heater
Heat transfer medium
Steam
(supercritical)
Steam
(high preature)
Steam
( lov preaaure)
Hot water
Heat tranifer fluid
Hot air
Usage
Utility
Industrial (proceaa)
Induatrial
(ipaceheat)
Comnercial-
Inntitutional
Domestic
_ _ ~ ~ ~ - • —
May include low grade low cont faolf «uch a* lignite, bark and vood waste, process tars,
and sludges.
Figure 3. Atmospheric FBC industrial boilers — occurrence
of various boiler parameters by capacity range.
58
-------
industrial boiler market is depressed in general, the forecast may be high.
GCA's independent investigation indicates that current FBC vendors have the
capability to fabricate the number of boilers indicated. However, the demand
is uncertain. The nationwide potential was projected as follows:
Year
Cumulative number of 1015 Btu 1,000 B/D of
industrial FBC boilers per year oil equivalent
1980 7 0.01 5
1985 200 0.29 136
1990 685 0.99 462
1995 1170 1.69 793
2000 2050 2.97 1400
2.2.7 Recent Improvements and Ongoing Research and Development
2.2.7.1 Sulfur Dioxide Control—
Careful design of gas phase residence time and sorbent particle size can
result in efficient S02 removal according to current projections by Westing-
house.39 Model development by Westinghouse and others is continuing in order
to model sulfur retention as influenced by these design and operating parameters.
The emphasis of future research will be confirmation of S02 control esti-
mates in large-scale units. Documentation of the influence of gas phase resi-
dence time and sorbent particle size in large demonstration units is of prom-
inent importance. The trade-offs associated with maximizing or minimizing
these parameters must be defined.
Other investigations are required to assess limestone characteristics
and availability as well as alternative sorbents. Energy Resources Company
(ERCO) has recently begun investigation of interquarry limestone characteristics.1*0
This study should give a good perspective of the effects of limestone variations.
Westinghouse will be conducting a detailed investigation of intraquarry
variations. ** *
59
-------
The Illinois State Geological Survey has extensively studied several
varieties of carbonate rock (mainly limestone and dolomite) for desulfurization
in fossil fuel combustion processes.1*2 Samples were investigated for petro-
graphy, mineralogy, chemistry, pore structure, and surface area. A wide ranee
of petrographic and SC>2 sorptive properties were revealed. Relatively high
S02 reactivity was found for chalks, calcareous marls, and oolitic aragonite
sand samples, probably due to high pore volumes and fine grain size.
General Electric is conducting experimentation to develop an automatic
process controller to maintain a constant percentage of SC>2 removal by the bed **3
This capability is necessary to adjust for changing bed conditions without
allowing excessive S02 emissions for intermittent periods. Expanded research
and development in the area is expected.
Experimentation with additives for improved desulfurization has been
conducted. Argonne National Laboratories has studied the effect of adding
NaCl to the bed.1*1* Although the pore surface area and calcium utilization are
increased by salt addition, salt has a great potential for producing boiler
corrosion. Other catalysts under consideration are iron oxide and coal ash.
Westinghouse1*5 has done some preliminary investigations of NaaCOa,
NaAlOa, NaCOa, Fe203, and CaAlaO^ as alternative sorbents. Investigators at
Argonne National Laboratories are experimenting with virgin and spent oil
shale.1*6 Virgin shale is attractive because of its inherent heating value
of about 3,000 Btu/lb.
Sorbent regeneration techniques also require further exploration and
development to minimize feed requirements, spent stone disposal, and associated
sensible heat loss. EXXON is attempting to develop regenerable synthetic
sorbents that have good attrition resistance, high reactivity, and good
60
-------
regeneration characteristics.l+7 Calcium aluminate cement and calcium or barium
titanate both appear to have characteristics which may make these materials
cost competitive with limestone. Methods of enhancing limestone reactivity
by precalcining (currently under investigation at EXXON1*8) and catalyst
addition must also be studied.
In essence, the thrust of current and future work is the minimization
of sorbent requirements and spent stone disposal to optimize S02 retention
and minimize cost, energy, and environmental impact.
2.2.7.2 Nitrogen Oxides Control—
The emphasis of past research has been to document emissions from experi-
mental AFBC units being operated for some experimental purpose other than
deliberate NOX control. Little has been done to reduce NO emissions (generally
between 129 to 258 ng/J (0.3 to 0.6 lb/106 Btu)49) measured during normal
operation at FBC test units, other than to generally observe the impact on
emissions as experimental conditions were being varied for some other purpose.
Experimental and modeling work is continuing in an effort to gain a better
understanding of NOX formation/reduction mechanisms in FBC, and of the cor-
relation between emissions and the key FBC design/operating conditions which
can influence emissions. The goal of these studies is to provide the capability
to better predict and control NO* emissions through simple adjustment of
standard design/operating conditions. Also, several investigators are begin-
ning to address combustion modifications, deliberately aimed at reducing NOX
emissions from FBC, such as staged combustion, flue gas recirculation, ammonia/
urea injection, and stacked beds. It is necessary to define the effects of
such combustion modification techniques, not only on NOx emissions, but on
other system parameters, such as combustion efficiency and materials corrosion
and the potential increase of S02 or particulate emissions.
61
-------
2.2.7.3 Particulate Control—r
The major requirement in this area is to test conventional particulate
control devices applied to AFBC boilers. Although performance is not docu-
mented, it should be similar to conventional systems burning low sulfur coal
Testing is currently being performed at the Sampling and Analytic Test Rig
(SATR) operated by the U.S. Environmental Protection Agency.50 Testing is also
planned at the 30 MWe (300,000 Ib/hr steam) demonstration facility in
Rivesville, West Virginia, the 10 MWt (100,000 Ib/hr steam output) unit under
construction at Georgetown University, and other FBC units as they become
available.
2.2.7.4 Solid Residue Disposal/Utilization
The disposal and utilization character of FBC solid waste should be the
focus of considerable investigation in the near future. It is imperative
that optional disposal and handling methods are assessed and ways to minimize
the environmental, cost and energy impact of disposal are found, due to the
large volume of material which will be produced as commercial units are brou»ht-
online.
The waste may be usable for commercial purposes. Presently two main are
are under investigation, use as a structural material like concrete or use as
an agricultural soil conditioner.
Several studies have demonstrated that FBC solid residue are cementitioua
This characteristic can be exploited to form a very durable concrete-like mass
One DOE study is under way to investigate the potential of using FBC solid
waste for road construction.51 The results indicated that compressive strength
of cemented waste exceeded the value reconmended for heavy traffic highway
construction over a wide range of compositions. Further, this compressive
62
-------
strength, which is indicative of the material durability and resistance to
erosion, improved with time even after the cemented samples were subjected to
freeze/thaw cycles. The study concluded that the exceptional high strength
of cemented FBC residue makes it suitable for applications which require
materials with low water permeability, such as in embankment, structural fill,
and liners to control leaching from waste disposal landfills and lagoons.
Another DOE study being performed simultaneously in several states in the
eastern United States is an agricultural application study for FBC solid waste.52
The program covers almost all the varieties of crops grown in the eastern United
States. It includes both short- and long-term laboratory and field-based
evaluations. The waste is used as a replacement for lime to neutralize soil,
as a source for trace and certain nutrient elements, and as a source for sulfur.
The study evaluates both the quality and quantity of crops produced from soil
treated by waste material, as well as the crops' nutrient value as food for
domestic animals.
A study to evaluate the physiological effects of food that is ultimately
obtained from FBC waste-treated soils on people and animals has been proposed
to DOE and EPA. The study will monitor mineral balance and amino acids in
human tissues, primarily human hairs, which tend to accumulate toxic materials.
Some small animals will be evaluated over several reproductive cycles to
determine long-term effects on offspring. The first stage of tests will
start in October 1979 and the second stage is scheduled for 1980.
Further investigation of uses for solid waste from FBC are necessary.
By finding viable commercial uses for the residue, the environmental and
cost impact of FBC would be greatly reduced.
63
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2.2.7.5 Other Investigations—
The performance capability and cost of inbed versus overbed solids
feeding is an important issue under study. Although several developer/vendors
are engineering systems using either of these techniques, the most current
study of the effect of feed orientation on S02 control is being conducted by
FluiDyne (in their 3.3 ft x 5.3 ft unit) for EPA.53 This study will assess
performance as a function of feed orientation, gas residence time, limestone
particle size, and use of primary recycle. Earlier experiments by FluiDyne
in their 18 in. x 18 in. unit indicated that equivalent desulfurization could
be achieved regardless of feed orientation as long as primary recycle was
practiced (see Section 7.0).51f
2.3 SYSTEM PERFORMANCE - S02 CONTROL
This and the following two sections describe the key variables affecting
the performance of FBC units in terms of emissions of S02, NO and particulatea
In the absence of data from large FBC facilities, much of this discussion is
based upon data from experimental units, and the results from modeling activi-
ties. Data from large facilities are necessary to confirm the absolute per-
formance that will be observed in commercial FBC installations.
One of the major advantages of FBC over conventional combustion of coal
is that S02 is removed within the bed using a calcium-based sorbent. Design
operating factors which influence the control of S0£ emissions for an atmos-
pheric fluidized-bed combustor (AFBC) follow:
-------
• Primary factors - Ca/S molar feed ratio
- sorbent particle size
- gas phase residence time
(expanded i superficial \
bed height ' gas velocity;
• Secondary factors - sorbent reactivity
- bed temperature
- feed mechanisms
- excess air
2.3.1 Primary Design/Operating Factors Affecting S02 Emission Reduction
SC>2 produced during the combustion of coal is reduced in FBC by burning
the fuel in the presence of calcium oxide. The S(>2 reacts with the calcium
oxide and excess oxygen forming calcium sulfate.
S02 + CaO + 1/202 ->• CaSOit (anhydrous)
Calcium-based sorbents such as lime, limestone and dolomite are the most
commonly used sorbents for FBC. The calcium content is the constituent which
determines the amount of sorbent required to reduce the SC-2 emissions to a
given level. (Availability of the calcium for reaction depends on sorbent
type, particle size, gas phase residence time, and the extent of sulfation.)
Thus the ratio of the calcium content of the sorbent to the sulfur content
of the coal is used to determine sorbent needs to control S02-
2.3.1.1 Ca/S Ratio—
Of the factors which affect SC-2 emission control, the calcium to sulfur
molar feed ratio (Ca/S) has the greatest impact. As the calcium content of
the bed is increased, greater S02 removal is achieved. Westinghouse Research
and Development Center has developed a model which projects sorbent requirements
65
-------
to attain certain levels of S02 removal efficiency. Figure 4 illustrates the
rapid increase in sulfur retention with increasing Ca/S based on the model.55
For sorbents with a particle size of approximately 500 pm, the relationship is
nearly linear below about 75 percent 862 removal. Above this level, sulfur re-
tention approaches 100 percent asymptomatically. Experimental test data, where
available, concur with the projections (see Section 7.0). However, further
data from larger systems and for high levels of S02 removal are required to
support the model projections. The Westinghouse desulfurization model assumes
uniform sulfur generation throughout the bed. In underbed feed systems where
S02 may be preferentially formed near the bottom of the bed, the Westinghouse
model may underpredict the S(>2 reduction capability of the FBC system.
The curves shown in Figure 4 for Greer, Grove, and Carbon Limestone are
taken from a recent Westinghouse report.56 Westinghouse is currently investi-
gating industrial FBC boilers in their study "Effect of S02 Emission Require-
ments on Fluidized-Bed Boilers for Industrial Applications: Preliminary
Technical/Economic Assessment."57 The Western, Bussen, and Menlo quarry lime-
stones shown in Figure 4 are the basic sorbents used in their industrial boiler
study as examples of high, medium, and low reactivity sorbents, respectively.
The least reactive sorbent (Menlo) or one with similarily low reactivity would
probably be avoided in practice because a Ca/S ratio close to six is required
to achieve 90 percent S02 removal (under "best system" conditions, as discussed
in Section 3.0). Better sorbent should be routinely available to industrial
customers.
The data shown are based on an average inbed surface particle diameter of
500 pm, and the assumption that primary particle recirculation will be used.
Primary recycle should prove cost effective from the standpoint of improved
SC-2 control and combustion efficiency. If primary recycle were not used a
66
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3
5
100
9O
80
TO
60
so
N
£
5 40
•:
u
a.
3O
20
10
CARBON
BUSSEN
MENLO
WESTERN
OPERATIMa CONDITIONS
PRESSURE. 101.5 KPo(lQtm)
TEMPERATURE "MI'C U646*Fl
AVERAfiE SCMtENT -500Mm
PARTICLE SIZE
BED DEPTH* t.2m U ft)
SUPCRFICIAL »l.*m/»»c (61t/»»ei
OAS VELOCITY
PRIMARY SORMNT/ FLY ASH RECYCLE
3 4
Co/S MOLAR RATIO
Figure 4. Projected desulfurization performance of atmospheric
fluidized-bed coal combustor, based upon model
developed by Westinghouse.^5
67
-------
coarser sorbent might be required (inbed average of 1,000 ym or greater) to
avoid unacceptable sorbent losses, and Ca/S molar feed requirements would in-
crease substantially. (As discussed in Section 3.0, primary recycle is con-
sidered an important feature of "best system" design for S(>2 control.)
Table 14 summarizes some of the available data on sulfur retention versus
Ca/S molar feed ratio and sorbent particle size for several limestones. Again
the Ca/S ratio must be increased to achieve higher sulfur removal efficiency.
Although total sorbent quantities will be different the same sulfur removal
efficiency can be achieved burning coals of different sulfur concentration by
maintaining the same Ca/S molar feed ratio, if all of the other key operating/
design conditions (such as gas residence time) are maintained the same, and as
long as the first order sorbent/S02 reaction kinetics do not change. For low
sulfur coals, the reaction mechanism could conceivably change at very low SO?
partial pressures. Under these conditions, if the coal sulfur concentration
increases, the same level of control can be maintained by increasing the calcium
feed proportionally. Figure 5 illustrates this using limestone 1359 to reduce
emissions from the combustion of coals with 2.6 and 4.5 percent sulfur.58
These tests were run under the same conditions with the exception of the dif-
ference in the coal sulfur content. Notice that the sulfur retention versus
Ca/S ratio is better in this experimental case than in the Westinghouse projec-
tion in Figure 4. This may be due to the finer particle size of the sorbent
in the experimental case. As Table 14 clearly indicates, the particle size of
the sorbent is a major factor in SC-2 capture.
2.3.1.2 Limestone Particle Size—
As the particle size of a given sorbent is decreased, the calcium utiliza-
tion is increased. Thus, with the same Ca/S molar feed ratio, the SC>2 reduction
68
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TABLE 14. AFBC - Ca/S MOLAR FEED RATIOS OBSERVED TO MEET STRINGENT, INTERMEDIATE,
AND MODERATE S02 EMISSION CONTROL LEVELS
Sorbent
Type
j
Limestone 1359
Greer Limestone
Carbon Limestone
Limestone 1360
Limes tone 1 8
Lowe llvi lie Limestone
Tymochtee Dolomite
Hydrated Lime
Western 90% CaL
Bussen Quarry
Menlo Quarry
Particle size
(urn)
420 - 500
490 - 630
630
930
1,000 - 2,380
420 - 500
1,000 - 2,380
420 - 500
500
1,000
630
1,000 - 1,400
<1,680
453
median
<3,175
1,000 - 2,380
630
<44
500
500
500
Ca/S molar feed ratios required to
meet optional control levels
Stringent
90%
3.9
3.5
3.5
5.5
6.0
2.8
4.5
2.6
2.9
7.0
-
4.0
5.2
5.5
2.6
3.0
2.8
3.4
5.3
Intermediate
85%
3.5
3.0
5.7
2.6
4.2
2.4
4.2
3.6
4.8
5.0
-
2.8
2.5
2.9
4.7
Moderate
75%
2.8
2.2
4.6
2.2
3.5
2.0
2.3
2.6
3.1
4.1
4.0
-
2.1
1.9
2.3
3.9
References
Organization
Westinghouse
Argonne
Argonne
Exxon
Babcock & Wilcox
Westinghouse
Babcock & Wilcox
Westinghouse
Westinghouse
Westinghouse
Argonne
Argonne
National Coal Board
of England
National Coal Board
of England
Babcock & Wilcox
Argonne
Babcock & Wilcox
Westinghouse
Westinghouse
Westinghouse
Unit
ID
*
6" diam.
6" diam.
3" diam.
3' x 3'
*
3' x 3'
*
*
*
6" diam.
6" diam.
CRE
CRE
3' x 3'
6" diam.
3' x 31
*
*
*
Number
45
46
47
48
49
45
49
45
50
50
51
52
53
53
49
47
49
54
54
54
These data points are based on the Westinghouse model; all others are
experimental data.
Note: Temp - 540° to 980°C (1,000° to 1,800°F);
Excess air - 18 to 20 percent.
-------
10
2°
30
40
3
U.
-I
(O
50
o
lit
oc
u
o
X
2 60
o
70
80
90
100
O COAL SULFUR CONTENT =2.6%
& COAL SULFUR CONTENT *
TEST CONDITIONS
TEMPERATURE, 8l5°-870e C (I500»-I600° F)
EXCESS OXYGEN, 3%
SUPERFICIAL VELOCITY, 3.7 to 4.3m/s«c (12-14 ft/s«c)
SORBENT PARTICLE SIZE , -44/iw (-325 mtsh)
2.0
CO/S STOICHIOMETRIC RATIO
3.0
Figure 5.
Sulfur dioxide reduction using limestone 1359 in a bed of sintered ash,
Pope, Evans, and Robbins.'*''
-------
efficiency can be increased significantly by decreasing the sorbent particle
size. The increased reactivity of smaller sorbent particles is due to the
greater surface area exposed. Argonne National Laboratory (ANL), in controlled
sorbent studies, has shown that increased sorbent porosity results in increased
calcium utilization. Figure 6 shows the significant effect of reducing the
average particle size diameter from 1,000 pm to 500 pm as projected for Greer
limestone using the Westinghouse SC>2 kinetic model.59 Experimental test data
by several investigators indicate that these projections are valid (see
Section 7.0).
2.3.1.3 Gas Phase Residence Time—
The third major factor which affects the sulfur removal efficiency of the
system is gas phase residence time. This is the average time period that a unit
volume of gas remains in the bed and is defined as the ratio of the expanded bed
height to the superficial gas velocity. Figure 7 illustrates the calculated re-
lationship between gas phase residence time and Ca/S molar feed ratio required
to achieve 90 percent control, at various particle sizes for Carbon limestone
and Grove limestone.60 As gas phase residence time is increased, the calcium
to sulfur molar feed ratio required decreases. The graph also indicates that
there is a critical gas residence time (0.6 to 0.7 sec) below which sulfur
retention efficiency is significantly reduced.
2.3.1.4 Interrelationship of Key Control Variables—
These three control factors are interrelated and can be varied to obtain
the optimum SC>2 removal efficiency. A trade-off must be made among the factors
to ensure the optimum system considering system economics. The Ca/S molar feed
ratio required for a given level of control can be reduced by decreasing parti-
cle size or increasing gas residence time. However, if the particle size is
71
-------
90
80
70
Operating Conditions
AFBC
SorbentType GREER LIMESTONE
a b
Average Diameter. Mm 500 1000
Pressure. kPa 101 101
Bed Temperature. °C 840 840
Excess Air, % 20 20
Velocity, m/s 1.83 i.ss
Bed Depth, m 1.22 1.22
I | I I I I
I i i
3456 789
Calcium-to-Sulfur Ratio (Molar)
10
Figure 6. Sulfur removal performance for typical sorbents
(projected using Westinghouse kinetic model).
72
-------
-J
U>
y>\
151-
at
s
CARBON LIMESTONE
GROVE LIMESTONE
\
112 MI"
O2 0.4 0.6 0.8 I.O 1.2
GAS RESIDENCE TIME, MC
1.4 1.6 1.8 H.O
Figure 7. Ca/S molar feed required to maintain 90 percent sulfur removal in
AFBC, as projected by the Westinghouse Model.60
-------
decreased the gas velocity must be decreased so that the particles will not
elutriate from the bed. This in turn increases the gas phase residence time.
The optimum system is a balance of the minimum gas phase residence time which
gives sufficient reaction time (around 0.7 sec) and the minimum particle size
which can be used in the system. Westinghouse results indicate that an appro-
priate particle size is around 500 urn.61 Figures 8 and 9 show the relationship
of the three factors as predicted by the Westinghouse Model for 90 percent sul-
fur removal considering one of the more reactive (carbon) and less reactive
(limestone 1359) sorbents tested to date, respectively.62 Both figures show
that the required Ca/S molar feed ratio increases rapidly with gas phase resi-
dence time less than 0.8 sec and sorbent particle size greater than 700 IT H
these conditions Westinghouse predicts that 90 percent SC>2 removal can b
achieved using Carbon limestone at a Ca/S ratio of 3 or limestone 1359
Ca/S ratio of 5.
In summary, it is apparent that the calcium to sulfur molar feed
the sorbent particle size and the gas phase residence time provide the
the best S02 emission reduction performance in f luidized-bed combustion
To increase gas residence times to 0.67 sec or greater (most "^«~.
C coranercialiy.
offered" designs operate at gas residence time in the range of 0 4 to o
u-5
boiler cross section or height would have to be expanded. The cost imua
pact
this modification is discussed in Section 4.3.4. Although boiler expansion
requires higher capital investment for added steel and potentially greater
feeding equipment, there may be resultant savings in other capital equipment
costs such as particulate control equipment (due to lower elutriation) or re-
circulation pumps (if natural circulation can be achieved using deeper beds),
sec),
74
-------
Solids Density - 2.70 * 10 mole Ca/cc
Bed Voidage = 0.5
Volume Fraction of Active Emulsion
Phase in Bed = 0.5
Bed Temperature-815°C
% Excess Air-=20%
r Expanded Bed Height
Superficial Gas Velocity
Figure 8. Ca/S molar feed required to maintain 90 percent sulfur
removal in AFBC with Carbon limestone, as projected by
the Westinghouse Model.62
75
-------
T25
ro
}20
Solids Density 2.70 * 10 mole Ca/cc
Bed Voidage 0.5
Volume Fraction of Active Emulsion
Phase in Bed -=0.5
Bed Temperature = 815°C
Excess Air =20%
y_ Expanded Bed Height
buperricial Velocity
Figure 9. Ca/S molar feed required to maintain 90 percent sulfur
removal in AFBC with limestone 1359, as projected by
the Westinghouse Model.62
76
-------
It is expected that these capital savings and more importantly operating
savings in sorbent use, electricity, and improved combustion efficiency may
offset the added capital cost associated with lengthening gas residence time.
2.3.1-5 SOa Emission Data Summary—
Figure 10 is a summary of S02 data obtained at eight AFBC test facilities
under a wide variety of test conditions. The bounded area is an indication of
the range of performance expected from FBC systems at high gas phase residence
times and small sorbent particle size. Much of the experimental data falls
wxthin these boundries. The major excursions from the band are noted in the
data from the B&W 3 ft * 3 ft unit and the PER-FBM unit. If the units and test
conditions are considered closely (see Section 7.0) these deviations from the
band are expected. The B&W 3 ft x 3 ft unit has a shallow bed which allows less
than optimum sorbent/gas contact. Gas phase residence times are approximately
one-third of 0.67 sec which is suggested for good reaction time. The PER-FBM
data were also obtained using low gas phase residence times, in the range of
0.13 to 0.26 sec.
2.3.2 Secondary Factors Affecting SOg Reduction
The other factors which affect the performance of the S02 removal system
are secondary, but can be used to obtain the maximum efficiency. Sorbent
characteristics directly affect the Ca/S molar feed ratio. The temperature,
solids feed mechanism, and excess air affect the rate and efficiency of the
reaction between available CaO and S02-
2.3.2.1 Sorbent Characteristics—
The chemical and physical properties of a sorbent (i.e., sorbent reactivity)
provide a basis for determination of sorbent requirements for a given combustion
system. The volume of sorbent which will provide the desired sulfur retention
77
-------
100
HIGH SORBENT
REACTIVITY
**
V
90
ao
TO
I eo
IM
O
50
STRINGENT
LOW SORBENT
REACTIVITY
INTERMEDIATE
MODERATE
SIP LIMIT
40
30
20
KEY
m *
B a w V * s1
ANL-6"
PER-FBM
NCB-6"
NCB-CRE
B a W 6'i 6'
B ft W LTD.-RENFREW
FLUIOYNE
10
_L
J.
» 4
Co/S RATIO
Figure 10. Summary of experimental SOa reduction data
for AFBC test units.
78
-------
will vary according to the calcium availability of the sorbent as well as its
calcium content. Sorbent characterization and development studies by several
investigators have identified the following factors which affect the sorbent
reactivity:
• Sorbent porosity is the key to calcium utilization. Greater
porosity increases the amount of surface area available for
the gas/solid reaction.
• Sorbents which contain Mg(X>3 have a slightly different grain
structure than CaCO^ alone. This grain structure provides
greater pore surface area and thus greater calcium utiliza-
tion potential.
• Dolomite, due to its MgCOs content, usually will have a better
calcium utilization rate than limestone. However, a greater
volume of dolomite is needed to obtain the same Ca/S ratio and
thus equal or more solid waste may be generated.
Argonne National Laboratories performed thermogravimetric testing on 61
limestones for reactivity with SC>2 at 900°C using a gas mixture containing 0.3
CO
percent S02- There is large variability in the SC>2 reactivity of limestones
and in the extent of conversion of the calcium carbonate to calcium sulfate.
For the high calcium (>90 percent CaCC^) limestones tested, the conversion of
to CaSOit ranged from 19 to 66 percent; for the dolomites (40 to 60 percent
, the range was 21 to 100 percent.
Limestone availability is also an important factor in the development of
FBC. The U.S. Environmental Protection Agency is initiating a broad sorbent
screening study covering interquarry and intraquarry characterization. Although
there appears to be no forseeable problem in sorbent availability, the quality
of the material may have an impact on the FBC sorbent market. Limestone for
fluidized-bed combustion must not only have good chemical reactivity but must
meet physical standards for specific gravity, bulk density, crushing strength,
loss of abrasion, porosity and toughness. The major requirement for the
79
-------
commercial use of limestone is the particle size of the rock. In the mining
and preparation of the stone, a considerable amount of off-size material is
produced. This material is stockpiled for use in other commercial uses; not
all the limestone mined can be used for FBC.6"*
2.3.2.2 Temperature—
The temperature within the bed may have a direct effect on the efficiency
of the reaction between sulfur dioxide and calcium oxide. Several investiga-
tors have shown that the optimum temperature for calcium use is between 760°
and 870°C (1400° to 1600°F), depending upon the coal and sorbent in use.65
Figure 11 shows the results of a study by Argonne National Laboratory on a
6-inch diameter AFBC system.66 The temperature lower limit is determined by
the temperature at which calcination occurs; that is, CaCOs releases C02,
forming CaO, the reactive form of the sorbent. Below 760°C (1400°F) calcina-
tion is not complete. The lower sulfur retention above the optimum temperature
may be caused by the release of S02 after capture due to local reducing condi-
tions in the bed,67 or by slight changes in other operating variables.
Experimental data have shown that within the bed there are oxidizing and
reducing zones which affect the reactivity of the sorbent. Sorbent particles
which migrate between the zones will produce greater sulfur capture than parti-
cles which are exposed only to a reducing environment.
2.3.2.3 Feed Mechanisms—
The sorbent and coal feed points can also affect the calcium utilization
rate. The boiler can be fed either from over the bed or under the bed. Gen-
erally underbed feed produces greater turbulence, allowing the sorbent particles
to travel freely between oxidizing and reducing zones. However, overbed feed
systems have also been shown to achieve good calcium utilization as long as the
elutriated fines are recycled.
80
-------
704
100
90 -
80
5 70
g 60
H
j5 50
UJ
oe
oc
3
40
3 30
10
TEMPERATURE,°C
760 816 871
927
GAS VELOCITY, 3ft/t«c
EXCESS OXYGEN, 3%
LIMESTONE NO. 1359
0 ILLINOIS COAL,Co/S 2.5
• PITTSBURGH COAL.Co/S 4.0
1300 1400 I5OO I6OO
TEMPERATURE,°F
I7OO
Figure 11. 862 reduction as a function of
bed temperature (ANL).66
81
-------
2.3.2.4 Excess Air—
The excess oxygen level has a lesser, but real effect on SC>2 capture. In-
vestigators have found that S02 reduction is slightly enhanced by the increased
excess oxygen.68
2.3.3 Other Factors
Variations from the mode of operation discussed in this section will not
be significant for first generation boilers. However, in future FBC applica-
tions, new developing techniques may be used. Development is anticipated in new
sorbent technologies in the form of sorbent utilization enhancement, regenera-
tion and alternative sorbents, as well as technologies such as "fast" and
"turbulent" fluidization to improve the combustion system.
Development is needed to reduce the limestone requirements so that the
impact on limestone requirements and solid waste disposal can be minimized.
In addition, the establishment of suitable modes of transportation, storage,
and dust control must be considered.
2.3.4 Factors Affecting Boiler Performance
2.3.4.1 Corrosion/Erosion—
In fluidized-bed combustion boilers the corrosion problems are likely to
be less than in conventional combustion boilers due to the lower bed tempera-
ture. However, the wear by erosion is likely to be greater due to the impact
of the particles against boiler tubes and walls.
The erosion of heat transfer tubes within the bed is affected by the
following factors:
• Coal particle size
• Sorbent particle size
• Chemical catalysts
• Bed temperature
82
-------
• Particle velocity
• Oxidizing/reducing atmosphere
Larger coal and sorbent particle sizes produce greater potential tube
erosion.69 Smaller particles tend to follow the air stream around the tubes
so that particles either fail to impact or do so at a lesser angle. The amount
of erosion which a particle can produce is directly proportional to the angle
of impingement of the particle.70 The velocity, hardness, and sharpness of the
particle can also be directly correlated with the degree of wear. Vertical
tubes would eliminate some of these effects, but the elbows or turns would still
be highly susceptible to erosion. In addition, if chemical or thermal corrosion
or degradation of material occurs, it will increase the affect of the erosion
and abrasion. Temperatures within the range of FBC operating conditions seem
to have little affect on the wear characteristics of the boiler.
The addition of NaCl, as proposed by some early researchers, to enhance
calcium utilization may cause chemical corrosion in the form of pitting due to
the reaction of the salt with the protective metal oxide coating on the tubes.72
Generally pitting problems are not unique to FBC and can be controlled. However,
whether salts are added to enhance Ca utilization or not, the migration of oxi-
dizing and reducing zones within a turbulent bed (e.g., as a bubble moves up
through the bed and around the immersed tubes) may have a detrimental effect on
superheater tubes immersed in the bed at temperatures greater than 370°C
(700°F).73 Most tests have been conducted with metal temperatures less than
230°C (450°F). Further study of this phenomenon at higher metal temperatures
is needed.
ju
The use of CaCl2 may be better than NaCl and studies of this sort are also
underway.
83
-------
Generally it can be stated that if the proper materials are chosen for
boiler walls and tubes, there should be little problem with erosion. The ero-
sion properties of the construction material are inversely proportional to the
surface hardness of an annealed material.74
2.3.4.2 Reliability and Turndown Capability—
The reliability of FBC has not yet been proven. Demonstration units are
presently in the early phases of operation at best. The reliability of the
systems will be better assessed within the next year.
Turndown in AFBC can be achieved in two ways: (1) by slumping one or more
of several modules of the boiler; or (2) by reducing the bed depth of all the
modules. The former is preferred because it is easier to maintain high sulfur
capture. If the bed depth of all the modules is lowered the gas phase residence
time will be reduced, and thus sulfur capture efficiency will decrease. With
this in mind the turndown rate capability of AFBC could be dependent upon the
number of cells which make up the boiler system.
2.3.4.3 Monitoring Needs—
The only additional monitoring need unique to FBC systems as opposed to
conventional boilers applies to the potential corrosion and erosion of inbed
boiler tubes. It will be important to follow a schedule of cleaning and in-
spection to assure long boiler tube life.
2.4 SYSTEM PERFORMANCE - NOx CONTROL
2.4.1 Factors Affecting NOX Formation and Emission Reduction
NOX emitted during AFBC coal combustion is virtually all in the form of
NO. Argonne National Laboratory has found that NO accounts for 98 percent or
more of the total NOX emission.75 In tests by Pope, Evans, and Robbins (PER)
84
-------
oxides of nitrogen other than NO were found to average between 10 to 30 ppm. 76
The high proportion of NO has also been verified in experimentation at MIT.77
Design and operating factors which influence the formation and control
of NOX in atmospheric fluidized-bed combustors include:
• Temperature
• Excess air
• Gas residence time
• Fuel nitrogen
• Factors affecting local reducing conditions
• Coal particle size
The kinetics of NOx reduction are not well defined at this point and
actual reductions cannot be predicted based on variation of different operating
parameters. In some cases, different investigators report conflicting results
relative to the influence of parametric variations.
2.4.2 Temperature
In the range of FBC operating temperatures (800° to 900°C), there is little
correlation between temperature and NOX emission. Westinghouse has compiled
existing NOx data as part of a comprehensive statistical study to determine
the behavior of FBC with regard to NOX and to develop a predictive mathematical
model. A five-term nonlinear regression equation was developed based on
equivalence ratio, and temperature. Comparison of the model and actual data
at an excess air rate of 18 percent is shown in Figure 12. A peak is seen
between 800° and 900°C and emission rate falls off at temperatures below and
above this range.
*Actual fuel-to-air ratio * stoichiometric fuel-to-air ratio.
85
-------
E
a.
H
o
z
9OO
4OO
300
« 200
in
w 100
1292
BCD TEMPERATURE, *F
1472 1632
1832
700
800 900
BED TEMPERATURE,*C
1000
Figure 12. NOx versus bed temperature, equivalence
ratio 0.847 (18 percent excess air).
A temperature maximum for NOx emissions was found by Pereira, Beer, and
Gibbs at 750° to 800°C.78 They concluded that NOX emissions increased with
temperature up to about 750°C because of a decrease in NO reduction by CO
hydrogen, and unburned hydrocarbons. At temperatures greater than 800°C, NO,,
reduction by char is accelerated and emissions again decrease. Above 900° to
1000°C, thermal NOX formation becomes significant and the emission rate of NO»
begins to increase.
PER has performed several tests at elevated temperature in their fluidiz H
bed module (FBM).79 The results shown in Figure 13 are scattered but a defi
upward trend exists. In the probable AFBC operating temperature range shown
the maximum NOX emission rate is about 230 ng/J (0.53 lb/106 Btu) but the
average is about 200 ng/J (0.47 lb/106 Btu).
86
-------
700
600
1500
1600
BCD TEMPERATURE,*F
(TOO 1600 1900
20OO
1100
o
_i
j
Ul
a.
<
CL
•1
<
soo
40O -
00
*• soo
Ul
o
o zoo
Ul
o
o
K
100 -
0
no
KEY
\, THEORETICAL NO,
AT 20.»% OXY6EN
PROBABLE OPERATING TEMPERATURE
•RANGE FOR FLUIDIZED-BED
COMBUSTION UNITS
O-DATA FROM OTHER
PER TESTS
• TEST 520
• TEST 925
A TEST 526
! CONDUCTED
5% EXCESS 02
'
1
421
361
30)
IB)
s
Ul
ox
z
X
o
12. £
60
t27 t*2 IOM
•CO TEMPERATURE, *C
I0t5
114*
1204
Figure 13. NOx emission rate as a function of bed temperature based on testing
in the PER Pluidized-Bed Module (FBM),79
-------
Several other investigators have reported similar results8" »81 >82 with
regard to increased NOX emissions at elevated operating temperature.
2.4.3 Excess Air
The amount of NOx which is formed is also dependent upon the amount of
oxygen available to react with the nitrogen. Excess oxygen will attack nitrogen
compounds and convert the nitrogen to NOX. Thus, nitrogen may be liberated which
might normally remain fuel-bound, in addition to NOX liberated by thermal fixa-
tion. Several studies support this concept.83'81* Substoichiometric oxygen
results in lower NOx emissions.
Pope, Evans and Robbins measured NOx emissions during pilot plant (FBC)
and full-scale (FBM) testing.85 Pilot plant (FBC) NOX emissions increased
from 320 ppm at 1 percent oxygen up to 440 ppm at 5 percent oxygen. NOjc
emissions from the FBM unit ranged between 280 and 340 ppm as oxygen was in-
creased from 1 to 4 percent.
During testing at Argonne, in the 6 in. diameter unit, NChc concentration
was found to increase from 400 to 500 ppm as flue gas oxygen increased from
2.6 to 11.8 percent.86
During testing of the CBC, PER found NOx levels to be independent of excess
air. However, at normal FBC temperatures, the bulk of testing results support
the fact that NC^ emissions increase with excess air.
2.4.4 Gas Phase Residence Time
Gas phase residence time is determined by the ratio of bed depth and
zation veloci'y. For constant bed depth, gas residence time is inversely pro-
portional to fluidization velocity. Jonke, et al., found an inverse relation-
ship between NOX emission reduction and fluidization velocity.87 The results
88
-------
suggest that NOX control is improved at longer gas phase residence times,
probably because more time is available for the reduction of NO to elemental
nitrogen.
2.4.5 Fuel Nitrogen
Testing which has been performed to date indicates that most of the NO
emitted from AFBC evolves from conversion of fuel nitrogen. In fluidized-bed
combustion, total NO emissions are greater than the equilibrium concentration
expected based on thermal fixation of atmospheric nitrogen, represented by
the following reaction:
N2 (atmospheric) + 02 •*• 2NO (1)
This additional NO is attributed to conversion of fuel nitrogen, or:
2N (fuel) + 02 -v 2ND (2)
Studies at ANL predicted thermal NOx (reaction 1) formation of only 100
ppm,88 however, measured emissions average about 350 ppm at normal FBC tempera-
tures.89 In other experimentation at Argonne, air nitrogen was replaced with
argon, and no significant difference was found in NOx emission rates. These
experiments indicate the significance of reaction 2 (fixation of fuel nitrogen)
in NOx formation in AFBC boilers. In atmospheric FBC, as much as 90 percent of
the NOX is formed from the nitrogenous compounds in the coal, and 10 percent is
due to the fixation of nitrogen from the combustion air.90
2.4.6 Factors Affecting Local Reducing Conditions
Although most of the NO emitted is derived from fuel nitrogen, there is
very little correlation between fuel nitrogen content and total NOX emission
rate, apparently because of other interactions in the bed. The most important
point is that NOX is formed near the bottom of the bed and is reduced to
elemental nitrogen as it rises through the bed.91 If all the nitrogen
89
-------
in a coal of 1.4 percent N content were converted to NO, 2,500 ppm would be
emitted.92 Since average NO emissions are generally much lower than this (300
to 600 ppm)93 it appears that the chemical NO reduction mechanism overrides any
variation that would result in NOX emissions during fluidized-bed combustion of
coals with varying nitrogen concentrations.
Evidence of this NO formation and reduction mechanism has been found in
several studies. ESSO Research found that by adding 250 ppm NO to the combus-
tion air, NOx emissions only increased by a few ppm.91* Pope, Evans, and Robbins
noted a decrease in NOX concentration between samples at increased heights abov
the fluid bed, also possibly indicating that a reduction reaction was taking
place after the formation of NOX. They report that the reduction of NO between
the bed and the stack is as great as 45 percent. Dilution from air leakage
accounted for only 15 percent of the reduction.95 Results of studies at MIT
also show a correlation between NO concentration and height above the air dis-
tributor plate.96 Figure 14 illustrates NO concentrations measured at the wall
and center line of a 30 * 30 cm combustor at two different operating temperatur
A likely NOX reduction mechanism in FBC is:
2CO + 2NO -»• 2C02 + N2 (3)
Carbon monoxide in the bed reduces NO to elemental nitrogen, with reduc-
tion dependent on gas phase residence time, temperature and other bed charac-
teristics.97 At higher temperatures, lower quantities of CO are available to
reduce NO, so that final NO emissions are greater.
Another reduction reaction which may be taking place in FBC is a bit more
complex. Investigators at Argonne National Laboratory observed that NO and SO
react over a partially sulfated lime bed, but that no reaction between the two
occurs over pure CaSOi^ or pure CaO.98 Figure 15 illustrates the relationship
between sorbent feed rate and NOx emission rate determined by investigators at
ANL.
-------
0 OS 1-0 1-5 N JO
Level above distribution plate ( m)
Figure 14. NO concentrations at different levels above
distributor plate of 30 x 30 cm combustor
reported by Massachusetts Institute of
Technology.96
*
»
0
Ul
u.
U-
O
I-
LU
8
o
z
u.
O
Z
o
B
3
O
UJ
60
50
40
30
20
10
I 1 1 1 1
COMBUSTION TEMPERATURE: 1600°F
SUPERFICIAL GAS VELOCITY: 3 FT/SEC
FLUIDIZED BED: HEIGHT 2 FT
— . —
O^
>x
— x -
xx
XCX
—
— —
1 1 1 1 1
1 2
Ca/S MOLE RATIO IN FEED
Figure 15. Reduction in NO versus Ca/S (ANL).
98
91
-------
The reactions are assumed to be the following according to ESSO Research
and Engineering:99
CaO + S02 -»• CaS03 (4)
2CaS03 + 2 NO -»• 2CaS04 + N2 (5)
These reactions were found to increase in rate with temperature decreases.
Temperatures below FBC operating temperatures are more conducive to the reaction
This indicates that the rate of reaction 3 is probably greater than that of
reaction 5 under normal FBC operating conditions. ESSO Research and Engineering
reported that NO was reduced 20 to 40 percent over a partially sulfated bed as
compared to an inert bed.100 Battelle Columbus Laboratories also reported a
27 percent decrease in NO emissions over a partially sulfated bed versus an
inert bed.101
NO may also be reduced to elemental nitrogen by reaction with coal volatile-
especially ammonia.102 Fuel nitrogen, exemplified by ammonia in this case,
takes part in two parallel reactions:
+02
+NO
where NO is an intermediate in the two consecutive reactions:
NH3 NH3
02 - >• NO - » N2
2.4.7 Coal Particle Size
The effect of coal particle size on NOX emissions is unclear. The Nation
Coal Board compared NOX emissions between systems using -3175 micron coal and
-1680 micron coal. The results show NOx reduction of 100 ppm as the coal size
92
-------
was reduced.103 Investigators at Westinghouse have concluded, however, that
smaller coal feed particles cause an increase in NOX emissions.101* Further
testing is required to determine which conclusion is valid. Pereira and Bee"r105
found that reduction of NO to elemental nitrogen significantly increased as char
particle size decreased.
2.4.8 NOx Emission Data Summary
A composite diagram of NOX emission data measured over the range of normal
FBC operating conditions is shown in Figure 16. In the temperature range of
interest (800° to 900°C), most of the data points are below 260 ng/J (0.6 lb/106
Btu) and about half are below 215 ng/J (0.5 lb/106 Btu). However, about 10
percent of the test results in the temperature range of interest show NOX emis-
sions above 300 ng/J (0.7 lb/106 Btu). All of these higher values (>0.7 lb/106
Btu) are from the Argonne 6 in. diameter bench-scale unit. It is significant
to note that all of the data from the larger units measured during operation
at envisioned typical AFBC temperatures are well below the optional intermediate
and stringent levels of control.
PER has made several measurements of NOx emissions from the FBM experimental
unit. Although much of the data are above 215 ng/J (0.5 lb/106 Btu) and about
one-quarter of the data are above 301 ng/J (0.7 lb/106 Btu), the measurements
were made at temperatures (1000° to 1200°C) significantly above that range ex-
pected in operation of typical AFBC industrial boilers (815° to 870°C). There-
fore, they were not considered as supporting data in selecting optional NOx
control levels for AFBC.
These data are reported from experimentation where there was generally no
intentional variation of design or operating conditions to reduce NOx emission.
This indicates that larger industrial AFBC boilers should be capable of meeting
93
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vo
MTO
BED TEMPERATURE. *F
ItSO 1830 HMO
tl*0
400
(0.93)
s
(OJO)
w *00
3 (0.47)
x
i too
V
V
301 (O.T)
— MODERATE
a$t(ot)
t^ 3^
INTERMEDIATE
_T-^_ *_«W *-i5(^)STR,N«I.T
KEY'
• aaw 3* xs' UNIT
• 8ftW LTD RENFREW
A eaw «' x«' UNIT
^ ANL •" UNIT
V NCB-CRE
4¥ PEM-FBM
-RANGE OF OPERATINC TEMPER-
ATURES ENVISIONED FOR TYPICAL
AFBC OPERATION.
700 BOO 9OO KXX)
BED TEMPERATURE,*C
1100
I20O
•TNEK POINT* AM ESTIMATED FROM DATA REPORTED IN ,,m, THUS TNE ACCURACY OF THESE POINTS
IS ASSUMED TO K i )0%
Figure 16. Summary of NOX emission data from experimentation in AFBC test units,
-------
levels as low as 215 ng/J (0.5 lb/10 Btu). If gas residence times are
increased to enhance S02 control, this should aid in lowering NOX emissions
even further.
2.4.9 Potential Methods of Enhancing NOX Control in AFBC Boilers
An alternative operating mode that can be used to reduce NOx emissions
further is two-stage combustion. This method can be applied to conventional
boilers, and some preliminary testing has been conducted on FBC units. The
combustion air is fed into the boiler in two stages. In the initial stage,
near stoichiometric air is fed into the fluidized bed. Secondary air is fired
into the boiler above the bed. In this stage, the burner must be carefully con-
trolled in order to give minimal NOx formation. In conventional combustion,
two-stage combustion provides an effective reduction of about 30 to 50 percent
thermal NO and up to 50 percent fuel derived NOX.106 Further testing is re-
quired in order to define the NOX control potential of two-stage combustion in
FBC systems.
Some of the most recent work at the SATR, EXXON, the Battelle MS-FBC, and
the EnkSping district heating plant are of interest because of the diversity
in design, size, and results. The SATR is a small AFBC pilot plant, mainly de-
signed for investigating particulate control. The EXXON miniplant is a small
pressurized unit. The MS-FBC is a small recirculating bed FBC. The Enkoping
FBC is a two-stage combustor located in Sweden which generates 38,600 kg/hr
(85,000 Ib/hr) steam. Only the Enkoping unit is designed as a staged combustor.
Staged combustion at the SATR reduced NOx emissions to the 100 to 200 ppm
range.107 During initial trials S02 emissions increased somewhat. Subsequent
testing with altered conditions reduced S02 emissions to below 200 ppm at a
Ca/S ratio between 3.5 to 4, while maintaining low NOx levels. No estimates
of combustion efficiency are available.
95
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The testing at EXXON resulted in substantial reductions of NO.108 In one
test, emissions of 0.05 lb/106 Btu were attained.* Unfortunately, both sulfur
retention and combustion efficiency suffered. Sulfur emission reduction dropped
from 74 percent down to 47 percent removal. Combustion efficiency dropped from
95 down to 90 percent.
Preliminary testing in the MS-FBC resulted in NOX emissions dropping from
400 pptn to 150 ppm.109 No change in sulfur capture or combustion efficiency
was noted. One possible explanation for the good results obtained is the pre-
sence of an entrained bed throughout the freeboard. The freeboard is maintained
at 1550°F to maximize sulfur capture. Thus, staged combustion helps maintain
freeboard temperature for sulfur capture while reducing NOX emissions.
No data on coal combustion in the Enkoping unit are available, although
results of a preliminary coal test in spring 1978 were made available to the
U.S. EPA.110 Sulfur capture of 75 percent at a Ca/S of 1.5, virtually 100
percent combustion, and very low NOX are claimed for the unit while operating
on high sulfur oil with 5 percent excess air. Staged combustion is employed
to improve combustion efficiency at low excess air levels.
Studies at Argonne and ESSO showed that significant reduction of NOx could
be achieved in fluidized-bed combustion by the application of two-stage combus~
tion. Argonne1s test showed 70 to 100 ppm NO using two-stage combustion, where
under similar single-stage conditions they measured 180 to 500 ppm NO.111 ESSO1
data show a reduction of NO from 620 ppm at 110 percent air in single-stage com-
bustion to 200 ppm NO when the same amount of air was fed in stages (43 percent
primary, 67 percent secondary).112
>%
This is a pressurized FBC reactor and the chemical kinetics may be different
The trend of the data, however, supports the phenomena hypothesized for
atmospheric systems.
96
-------
Reduction of NOx by staged combustion may be due to several reasons. In
the primary stage there is insufficient oxygen to react with the nitrogen, and
under substoichiometric reducing conditions, there is a greater amount of un-
burned fuel present, primarily in the form of CO, which reduces NO to N2.
MIT has made several recommendations for combustion modifications for NOX
control based on small laboratory fixed and fluid bed experimentation.113
Among the optional operating techniques postulated are:
• Inject 10 percent or more of the stoichiometric combustion
air as secondary air into the freeboard for NO reduction
by char in the bed and complete combustion of CO in the
freeboard.
• Inject recycled char close to the top of the bed to pro-
mote the decomposition of NO rising through the bed.
• Inject recycled char together with coal and sorbent into
a shallow uncooled bed situated above the main bed (see
Figure 17) to reduce NO and produce favorable conditions
for volatile combustion and sulfur retention in the "top
fed" fluidized combustor.
The performance and economics of such options must be further assessed.
Further investigation of two-stage combustion in large scale FBC units is
required to ensure that suitable S02 control and combustion efficiency can be
attained simultaneously with low NOx emissions. Another item to investigate
is tube corrosion brought on by possibly shifting oxidizing/reducing zones in
the unit.
Other techniques which could be considered for further NO control in AFBC
include flue gas recirculation and ammonia/urea injection. Further testing is
required to determine the incremental NO reduction which can be expected under
these optional operating conditions.
If further reduction of NOx is necessary, catalytic reduction is a possible
approach. Studies have been done using various metal oxides and metal powders.
97
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EXHAUST
COAL + RECYCLED ^ CHAR
COOLANT<
OUT
COOLANT
IN
SECONDARY AIR
•SHALLOW, UNCOOLED BED
•^ SORBENT 4 COAL
FLUIDIZING
AIR
Figure 17. Staged bed technique for NO control recommended
by investigators at MIT.113
98
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A1.203 an<* Zr02 seemed to have no effect on NOX formation, and cobalt oxide
seemed to increase NOX- However, the addition of nickel powder to the reac-
tion chamber showed a significant decrease in NOX formation.115 This particular
catalyst is extremely expensive and economically unrealistic for use in FBC, yet
the study does demonstrate the feasibility of using a catalyst for NOX control.
2,5 SYSTEM PERFORMANCE - PARTICULATE CONTROL
2.5.1 FBC Boiler Design Parameters Affecting Particulate Emissions
The most important design factors influencing the quantity of particulate
emissions from an atmospheric FBC can be grouped as follows:
• Coal - ash content
- sulfur content
- agglomeration characteristics
• Sorbent - particle size
- attrition and decrepitation characteristics
• Operation - superficial velocity
- primary recycle
- use of carbon burnup cell
- additives
• Bed Geometry - cross sectional area
- bed depth
- orientation of boiler tubes
- grid design
- freeboard
2.5.1.1 Coal Type—
The type of coal used in an FBC boiler will influence the quantity and size
distribution of stack gas particulate emissions. The most important factors are
coal ash content, coal sulfur content and ash agglomeration characteristics.
Fly ash emissions will increase with increasing ash content since it is reported
that virtually 100 percent of all coal ash is elutriated from the fluidized
99
-------
bed.116 Particulate emission data analyzed by Babcock & Wilcox showed very
little correlation between emission rate and coal or additive particle size.117
Particulate emissions will increase with increasing sulfur content because
of greater sorbent requirements for 862 control. Although most of the spent
sorbent is likely to be withdrawn from the bed, increasing sorbent feed rate
may be expected to increase the amount of sorbent elutriated.
Collection of elutriated ash by primary recycle cyclones will be influenced
by ash agglomeration. The temperature in the fluidized bed is lower than that
associated with ash agglomeration in conventional systems, but if this does
occur in a fluidized system, the internal cyclones will provide highly effi-
cient capture of large-sized agglomerated material elutriated from the bed.
2.5.1.2 Sorbent Type--
In fluidized-bed combustion, sorbent material can represent a significant
portion of the particulate material reaching the final control device. The
amount of sorbent elutriated depends upon sorbent size distribution and the
relationship between the terminal particle settling velocity and superficial
fluidization velocity. Any change in sorbent particle size which results in
terminal particle settling velocities less than superficial velocity will tend
to cause elutriation of that size fraction. There is also a possibility of
emitting particles with higher terminal velocities due to the complex nature
of a fluidized system,118 however, higher freeboard designs will help reduce
carryover of "splashed" coarse particles. In addition to immediate sorbent
fines elutriation upon sorbent feeding, two mechanisms are responsible for
in situ reduction of sorbent particle size, including:
• Decrepitation
• Attrition
100
-------
Fines are formed as a result of sorbent decrepitation during calcination and/or
sulfation. Sorbent particles are roasted and cracked into finer size fractions,
the extent of which depends on sorbent type.
Attrition refers to mechanical grinding of sorbent particles as a result
of turbulent particle interactions in the bed. This phenomenon occurs most
rapidly during calcination and can cause a significant increase in total parti-
culate emissions if proper sorbents are not used.
2.5.1-3 Operating Conditions—
The role of superficial velocity in particulate elutriation is pointed out
above in the discussion of sorbent characteristics. In general, particulate
emissions from the FBC will increase directly with increasing superficial gas
velocity.
The use of primary recycle to enhance combustion efficiency and SC>2 control
efficiency (by allowing for longer carbon and sorbent residence times) provides
significant reduction of particle loading to the final particulate control device.
Another significant operating factor affecting particulate emissions from
an FBC system is use of a separate carbon burnup cell (CBC) to burn recycled
carbon elutriated from the main combustor. The CBC differs from the FBC in
many respects, including the following:119
• Characteristics of combustion material (i.e., finer than
FBC feed, higher proportion of ash, lower proportion of carbon
• Higher temperature operation, ~1100°C (2000°F)
• Higher excess air, ~50 percent
• Lower fluidizing velocity
Particulate emissions from the CBC will decrease with increasing tempera-
ture, as discussed in Section 2.5.3.2. Although this is the case, we do not
expect widespread use of carbon burnup cells in industrial boilers.
101
-------
Salt additives can be used to increase sulfur retention in the bed.
Studies by PER indicated that particulate emissions increased during salt
addition.120 Their investigation also noted that attrition loss was more
• • 191
severe during startup and salt addition.
2.5.1.4 Bed Geometry—
The quality of fluidization is directly related to bed depth, with gas
bypassing, slugging, and bubbling decreasing as bed depth increases. As a
result, particle elutriation is also minimized at increased bed depths.122
Bed diameter and boiler tube configuration also influence fluidization
characteristics. The quality of fluidization increases with increasing bed
diameter, and indicates that full-scale units will have better fluidization
characteristics than bench- and pilot-^cale units currently in operation.l2^
Boiler tubes in the bed can serve Lj break up gas bubbles and provide
smoother fluidization. Tubes should be oriented to allow for good mixing.
Definitive guidelines for boiler tube orientation have not been developed
but many operating pilot plant units incorporate horizontally-mounted tubes
Planned units are considering inclined tubes to allow for natural coolant cir-
culation. Tube packing also has an effect, causing large temperature gradient-
if packed too closely. This is a sign of poor mixing.
Boilev tubes also act as baffles, both water tubes submerged below the
surface of the bed, and convective tubes in the freeboard above the bed. gu h
a baffling effect could reduce the amount of particles elutriated.
Grid design is another important factor in assuring proper mixing and
fluidization. Uneven gas distribution may cause channeling and possible dea
yation in portions of the bed. Designing grid pressure drop at approximate!
40 percent of total bed pressure drop should provide for uniform gas distrih
102
-------
and mixing. This will minimize particle elutriation due to gas bypassing
and slugging or bubbling. Air distributor grid jets also contribute to attrition
and emission of sorbent particles.
It is expected that future FBC designs will incorporate deeper beds, and
smaller sorbent particles to improve S02 control (see Section 3.0). If so,
expansion of the freeboard dimension will be important to avoid excessive par-
ticle elutriation. Some designers, most notably Babcock and Wilcox, have
already worked higher freeboards into their designs.
2.5.2 FBC Boiler Operating Factors Affecting Particulate Control
Device Performance
Selection and performance of a final particulate control device will depend
on flue gas characteristics and particle characteristics as determined by basic
boiler operating parameters. Control devices which could be used include ESPs,
fabric filters, scrubbers, and cyclones. The use of each of these techiques
is discussed below to the extent that the application differs from a conventional
boiler/particulate control system.
2.5.2.1 Electrostatic Precipitators—
A hot-side or cold-side electrostatic precipitator (ESP) could be used as
a final particulate control device in an FBC system. These options are illus-
trated in Figure 18. 125 The decision is based largely on particle resistivity,
which is influenced by:
0 Flue gas temperature
* Particulate carbon and alkali concentration,
and SO3 concentration in the flue gas
• Use of separate carbon burnup cell
• Use of additive
• Trace element concentration
103
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OPTION I
FINAL FLUE
GAS CONTROL
DEVICE
PRIMARY AND SECONDARY
PARTICULATE REMOVAL
STACK
ATMOSPHERIC
PRESSURE
FLUIDIZEO KO
• OILER
OPTION 2
CYCLONES
PRIMARY AND SECONDARY
PARTICULATE REMOVAL
HEAT RECOVERY-
FLUC CAS COOLER
ATMOSPHERIC
PRESSURE
FLUIDIZEO ico
•OILER
STACK
Figure 18. Control of particulate emissions from an
atmospheric pressure FBC boiler.125
104
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The resistance of particulate material should be in the range of 1 * 107 to
2 * 1010 ohm-cm for high efficiency performance.126
Analysis of particulates emitted from fluidized-bed combustion systems
indicates that resistivity may be above the range required for acceptable ESP
performance, especially at temperatures of 95° to 150°C (200° to 300°F) charac-
teristic of cold-side control operation. Figure 19 illustrates a compilation
of resistivity measurements made by TVA and Pope, Evans, and Robbins.127 None
of the data indicate that a cold-side ESP would function well, unless the TVA
in situ measurements with limestone are extrapolated to temperatures of 120°C
(250°F) or less, which is below the normal cold-side temperature range. Five
data points at 315°C (600°F) are below 1 * 1010 ohm-cm indicating possible
hot-side ESP control. Extrapolation to higher temperatures between 315° to
370°C (600° to 700°F) shows potentially lower resistivities.
There are several reasons why particle resistivity is a problem in
fluidized-bed combustion. Very low concentrations of 803 have been recorded
in FBC flue gas, and 863 appears to be of major importance in lowering the
resistivity of fly ash collected by cold-side precipitators. All sorbent
materials (CaCC-3, CaO, MgO, CaSOi+) have high resistivities. (Carbon content of
the fly ash, on the other hand, could tend to lower resistivity.) Trace element
distribution on fly ash particles from FBC could alter the volume conduction
effect, an important factor in hot-side ESP operation.128 The test data shown
in Figure 19 are for emissions from the primary combustor with combustion effi-
ciency in the range of 85 to 90 percent. In actual operation, combustion effi-
ciencies as high as 95 to 97 percent may be approached, so that carbon concen-
trations in the flue gas will be reduced in comparison to this data.
105
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10
14
38
93
AIR TEMPERATURE, °C
149 204 260
315
10
13
10
12
10
11
2
I
»-
>
V)
o
o
10
10
10' -
1
1
370
^ IN SITU TEST
\
-------
Carbon has high conductivity and, therefore, reduces resistivity. Thus,
in full-scale industrial units, actual resistivities may be higher than reported
in this testing.
2.5.2.2 Fabric Filters—
It is anticipated that fabric filtration technology will be readily adaptable
and successful in controlling particulate emissions from coal-fired FBC boilers.
Depending on the gas moisture (which should be low) slight problems could develop
with pH of material captured in the filter, or lime hydration could cause tem-
perature excursions or blinding at the fabric surface. The potential for bag-
fires must also be considered due to uncertainty regarding the extent of carry-
over of unburned carbon.
Water vapor in flue gases from combustion is primarily a result of the
fuel hydrogen content and it produces a dew point of 50° to 60°C (122° to 140°F)
at normal excess air. However, the 803 concentration (usually 1 to 2 percent
of the S(>2 concentration) in a conventional coal-fired boiler raises the flue
gas dew point. Equipment designed to collect dry particulate (fabric filters
and dry electrostatic precipitators) must operate above the acid dew point.
Most conventional coal-fired plants maintain flue gas temperatures between
150°C (300°F) and 180°C (356°F) to avoid corrosion problems. Robinson, et al.,129
found that the Pope, Evans, and Robbins - fluidized-bed pilot plant produced
an S(>3 concentration of 39 ppm when sorbent was not used, and no measurable
SOa when sorbent was used. (Note: These early 803 results represent limited
data and must be confirmed by further 803 analyses on other fluidized-bed
combustors.) This low 803 concentration in the presence of sorbent, if confirmed,
means that flue gases might be cooled to 95°C (200°F) or below for dry particu-
late collection and increased heat recovery.130 The major problem in using
107
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fabric filters on conventional coal-fired boilers has been 803 and H2S04 induced
deterioration of the fabric. Therefore, fabric filter technology may be readily
applicable to fluidized-bed combustion systems if the low 803 concentrations
are confirmed.
2.5.2.3 Wet Scrubbers-
Wet scrubbers for final particle control application in FBC have not been
seriously considered in this report because of the wet sludge/wastewater handling
and disposal problem which would result. 'Since other particle control systems
are anticipated to perform adequately on FBC and because an inherent attraction
of FBC is dry waste production, wet scrubber use would probably not be considered
by the industrial customer. In the event that scrubbers were used, they would
have to be operated at high pressure drop with attendantly high power consump-
tion and operating cost to provide high efficiency removal of fine particles,
2.5.2.4 Multitube Cyclones—
Multitube cyclones, which represented the most common type of inertial
collector used for fly ash collection before stricter emission regulations
were enacted, depend upon centrifugal forces (i.e., inertial impaction) for
particle removal. They consist of a number of small-diameter cyclones (~5 to
30.5 cm diameter) (~2 to 12 in. diameter) operating in parallel and having a
common gas inlet and outlet.
Fly ash collection by multitube cyclones is a well-established technology
that has been applied for many years on all types of conventional coal-fired
industrial and utility boilers. However, because of efficiency limitations
they are now used mainly as precleaning devices.
A cyclone or multiple cyclones would be required to operate at high velocit
to provide significant removal of fine particles. Table 15 shows typical
ciencies of three different cyclone collectors.
108
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TABLE 15. DISTRIBUTION BY PARTICLE SIZE OF AVERAGE COLLECTION
EFFICIENCIES FOR VARIOUS PARTICULATE CONTROL
EQUIPMENT
131
Collection efficiency, %
Type of collector
Particle size range, pm
<5 5 to 10 10 to 20 20 to 44 >44
Simple cyclone 7.5 22
Multitube cyclone
(12 in. diameter) 25 54
Multitube cyclone
(6 in. diameter) 63 95
43
74
98
80
95
90
98
99.5 100
Removal of fines <5 to 10 ym probably would not be adequate with use of
any of these cyclone arrangements, and if so, only at very high cost. Figure
20 illustrates comparative collection efficiencies for two axial-entry cyclones
applied to conventional boilers with diameters of 15.2 and 30.5 cm (6 to 12
in.), respectively, as a function of percent of dust under 10 um.
IOO
c
•
V
o
Z
2 83
o
u*
O
o
80
75
70
65
(15.2 cm)
6 in. OIA.
(30.3cm)
12 in. OIA.
tp gr. OF DUST:2to3
PRESSURE DROP JS 3 in WATE
GAUGE
10 2O 30 40 5O 60 70 90
ptrctnt OF OUST UNDER lO/im
Figure 20. Typical overall collection efficiency
of axial-entry cyclones.
109
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The average inlet particle size to the final device in FBC is expected
to range between 5 to 20 ym. If it is actually 10 ym or below, the maximum
efficiency which could be expected based on this data (for conventional firing)
is 73 and 85 percent for 30.5 cm (12 in.) and 15.2 cm (6 in.) diameter cyclones
respectively.
Although a great deal more testing is required in large-scale FBC systems
to assess multitube cyclone performance capability, it is apparent that multi-
tube cyclones would probably only be adequate for moderate particulate control
levels.
2.5.3 Particulate Emission Data from AFBC Units
Actual test data demonstrating the efficiency of final particulate control
devices applied to coal-fired atmospheric FBC boilers are not available. Par-
ticulate emission data which do exist generally represent loadings in the flue
gas to, and the exhaust from, primary cyclones applied to the FBC or CBC. To
date, large FBC units have not operated long enough to demonstrate final
particulate control technology. Thus, the data on the following pages represent
data from units which are essentially uncontrolled.
The factors affecting final particulate control performance, as they differ
from conventional systems, have been pointed out. Although certain problems
require further research, and actual particle control device performance on
FBC must be demonstrated, the current prospect is that hot-side ESP or fabric
filter use should provide control performance equivalent to applications on
conventionally-fired boilers.
To support the probable adequate performance of final particulate control
devices, available emissions data pertaining to exhaust from the primary cyclo
is discussed below.
110
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2.5.3.1 Particle Size Data—
Figure 21 illustrates particle size distributions measured for emissions
from conventional and FBC boilers. The FBC particle size distribution was
measured by PER in their 1.5 ft x 6 ft fluidized-bed module.132 Isokinetic sam-
pling was used along with an MSA particle analyzer for subsieve size particles
and the data represent emissions at the inlet to the final control device.
A 12-element multicone dust collector was used for primary particulate removal.
In addition, large particle fallout occurred in the air preheater. Exact
operating conditions during this FBM run are not known, but at this time the
FBM was being operated at relatively high superficial velocities (3 to 4 m/sec).
Bed depth was variable with a maximum slumped depth of about 0.25 m (30 in.).
The distribution reported by Midwest Research Institute (MRI) represents emis-
sions after a cyclone or similar mechanical collection device applied to a
conventional pulverized coal boiler.133 Particle sizing by MRI was performed
using a Bahco classifier. Although this is limited data comparing a full-scale
conventional system with a small FBC test system, it can be tentatively con-
cluded that the size distributions of particulate emissions passing to final
control devices in conventional and FBC systems are not radically different.
It is possible, however, that particulate emissions from FBC may include a
slightly higher concentration of fines.
Argonne has determined the particle size distribution of fines (by
Coulter counter analysis) collected by their control equipment during two
atmospheric FBC bench scale experiments in a 6 in. combustor. The operating
conditions were as follows:134
• Temperature : 871OC (1600°F)
• Coal : -14 mesh Illinois, 4 percent S
111
-------
30
M
K
O
e
o
N
M
-I
O
10
9
8
7
6
I
MRI
PULVERIZED COAL
FIRED BOILERS
(BY BANCO
CLASSIFIER)
PER- FBC
(ATMOSPHERIC)
(BY MSA
ANALYZER)
PER - POPE , EVANS, ROBBINS
MRI-MIDWEST RESEARCH INSTITUTE
I I I I I I I
I
10 20 30 40 50 60 70 80 90 95
WEIGHT PERCENT SMALLER THAN STATED SIZE
Figure 21. Particle size distribution before
final control device.132'133
112
-------
• Additive : BCR - 1359 calcined limestone
t Starting bed : 30 mesh alumina
• Bed height : static - 0.4 m (15 in.)
fluidized - 0.6 m (24 in.)
0 Superficial velocity: 0.9 in/sec (3 ft/sec)
* No recycle
• Ca/S : 2.4 to 2.9
* Excess air : 10 to 30 percent
The distributions are shown in Figure 22, and illustrate that the average
size of particles collected in the primary cyclone is 70 ym. Particles exiting
the secondary cyclone have an average size of 15 ym with about 3 percent <2 ym.
Total collection efficiencies for the two devices were reported as 86 to 90
percent and 97 to 99 percent, respectively.
2.5.3.2 Emission Data
Table 16 presents a summary of particulate emissions data from PER, ANL,
NCB and B&W. PER conducted particulate emission testing during operation of
the FBC and FBM test units in 1970.135 (The FBC was a pilot-scale unit with a
rectangular bed of 30 cm * 41 cm (1 ft * 1.3 ft) and the FBM was envisioned as
a "full-scale" module with a rectangular bed of 46 cm * 183 cm (1.5 ft * 6 ft).)136
Testing downstream of the FBC cyclone indicated that about 10 percent of
the fly ash escaped uncaptured. A summary of the results is shown in Table 16.
During this test, a sintered ash bed 25 cm (10 in.) deep was operated at 843°C
(1550°F) with 3 percent oxygen in the flue gas. Superficial velocity was not
reported for this specific testing but it is known to have been varied between
1.8 to 4.3 m/sec (6 to 14 ft/sec) for all testing during this period. Fine
sorbent (-325 mesh) was injected. PER concluded that the bulk of the sorbent
113
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ui
N
u —
tC. H
uj
-------
TABLE 16. SUMMARY OF PARTICULATE EMISSION DATA, PRIMARY AND SECONDARY
COLLECTION - ATMOSPHERIC FBC UNITS
Investigator
AM.'1-0
6 in. bench
scale FBC
ANL1"1
6 In, bench
scale FBC
NCB1*2
BCURA and
CRE pilot
scale
combustors
PER"7
FBC
30 x 41 cm
<12 * 16 in.)
PER13'
FUN
0.46 x 1.8 n
(18 x 72 in.)
Coal parameters
4Z sulfur Illinois coal.
Coal ash feed rate
-0.23 kg/hr (0.5 Ib/hr)
Coal
1.8-3.3 kg/hr
(4.0-7.3 Ib/hr)
Several varieties of low
and high sulfur coal:
9-227 kg/hr (20-500 Ib/hr)
Coal ash input
kg/hr (Ib/hr)
5.8 (12.8)
5.9 (12.9)
5.7 (12.6)
5.9 (12.9)
Coal feed rate
kg/hr (Ib/hr)
364-373 (800-820)t
34S (765)t
400-420 (880-925)*
345-364 (760-800)*
327-339 (720-745)t
336-345 (740-760)t
Sorbent parameters
BCR 1359
calcined limestone
Limestone input
0.5-1.1 kg/hr
(1.1-2.3 Ib/hr)
Limestone (1359) input
kg/hr (Ib/hr)
0 (0)
0 (0)
9.7 (21.4)
12.7 (28.0)
Limestone feed rate
kg/hr (Ib/hr)
164 (360)
100 (220)
6f> (132)
128 (282)
44 (97)
30 (66)
Other operating
conditions
Gas velocity of
0.9 n/s (3 ft/s);
no recycle
Fluidizing velocity
0.61-3.35 m/sec
(2-11 ft/sec)
Sintered ash bed, 25 en
(10 in.) depth.
3% 02 in flue gas
Temp. - 843°C (1550°F)
Limestone type
(all sized at -44 un)
Dolomite 1337 raw
Limestone 1359 raw
Limestone 1337 hydrate
Limestone 1337 raw
Limestone 1359 raw
Limestone 1359 hydrate
Particulate loadings Primary and secondary
s collection efficiency
Downstream of secondary cyclone: 86-90* primary cyclone
0.45 g/m (0.198 gr/cf)
or approximately:
215 ng/J (0.5 lb/106 BTU) 97-992 combined cyclones
At combustor exit: Approximately 90Z for
0.37-4.07 g/m (0.16-1.78 gr/cf) combined primary and
average-0.14 g/m (0.06 gr/cf)
maxtaum-O.5 g/m (0.22 gr/cf)
Downstream of necondary cyclone: 95-982 for combined
0.23-1.37 g/m (0.1-0.6 gr/cf) primary and secondary
or approximately:* cyclones
108-645 ng/J (0.25-1.5 lb/106 BTU)
Fly ash captured ggh Approximately 90*
kfi/hr (Ib/hr) k*/hr
10.0 (22.0) »'J «•»
10.5 (23.2) l'1 "•*'
18.6 (41.0) !•! ?•'
19.7 (43.4) 2'2 U'9)
Particulate emission rate after
primary cyclone
LowS High 5
ng/J* (lb/106 BTU)* ng/J* (lb/10* BTU)*
318 (0.74) 696 (L.62) 90-95Z
456 (1.06) 718 (1.67)
396 (0.92) 494 (1.15)
383 (0.89) 602 (1.4)
374 (0.87) 598 (1.39)
327 (0.76) 473 (1.1)
(continued)
-------
TABLE 16 (continued).
Investigator Coal parameters
Babcock and Coal input
0.91 . 0.91 . k«/hr (lb/hr)
(3 " 3 ft) 112-758 (248-758)
200-218 (440-480)
209-222 (460-490)
154-245 (340-540)
134-240 (295-530)
220-227 (485-500)
222-230 (490-507)
Babcock and
Wilcox'1'1'
1.8 x 1.8 m T«"
(6 x 6 ft) 8«les
3-2
4-1
4-2
4-3
5-1
5-2
5-3
6-1
6-2
6-3
Sorbent parameters
Limestone Input
kg/hr
23-77
21-68
20-66
45-64
19-49
116-127
104-113
Coal
kg/hr
892
818-890
805-809
847-903
800-810
823-894
923-956
799-895
727-898
883-914
(Ib/hr)
(52-170)
(47-150)
(45-145)
(100-140)
(41-107)
(256-279)
(230-250)
input
Ib/hr
(1965)
(1801-1961)
(1773-1783)
(1866-1990)
(1762-1785)
(1813-1970)
(2033-2105)
(1759-1971)
(1601-1977)
(1944-2014)
Other operating
conditions
Type and limestone size
(urn)
6350 x 0 (Lowellville)
2380 x 0 (Lowellville)
1000 x 0
Pulverized (Lowellville)
44 x 0 (CaOH2)
2380, 1000, pulverized
Greer
2380, 1000, pulverized
Grove
Limestone input
kg/hr Ig/hr
261-277 (575-610)
245-291 (540-640)
281 (620)
300 (660)
341 (750)
295-409 (650-900)
281-302 (620-665)
217-423 (478-931)
160-267 (353-589)
198-215 (437-473)
Partlculate loadings
Particulate at US Inlet
ng/J* (lb/106 BTU)*
2253-3375 (5.24-7.85)
2878-3689 (6.74-8.58)
3078-4170 (7.16-9.70)
5434-7825 (12.64-18.20)
4970-7145 (11.56-16.62)
3637-10,623 (8.46-24.71)
3457-15,215 (8.04-35.39)
Particle loading
primary cyclone outlet
ng/J (lb/10 BTU)
3224 (7.5)
3323-6453 (7.73-12.01)
3130-3147 (7.28-7.32)
3203-3431 (7.45-7.98)
2042-2068 (4.75-4.81)
770-1367 (1.79-3.18)
2128-2205 (4.98-5.13)
1638-2184 (3.81-5.08)
1961-3276 (4.56-7.62)
3603-3770 (8.38-8.77)
Primary and secondary
collection efficiency
Primary collection
efficiency raged be-
tween 50-802. This
is low in comparison
to efficiencies
achieved when cyclones
are used for primary
fly ash removal.
Primary
collection efficiency
83
50-65
70
65
80
87-91
76
75
61-72
60
*Estlmated by GCA
tohio No. 8, unwashed coal - 4.51 S, 10.7t ash.
lohio No. 8, washed coal - 2.6Z S, 7.21 ash.
'High value measured during fine sorbent addition; low value measured with no sorbent addition.
NOTE: Limestone Type and Size - Lowellville limestone led at top size of 9510 urn for all testing.
-------
was retained in the collector despite the -325 mesh particle size. About 10
percent of the input energy was lost as carbon in the fly ash. No attempt was
made to recover this loss by fly ash recirculation.
Particulate testing was also conducted during several runs of the PER
FBM unit.137 Feed coal was Ohio No. 8. Sulfur concentration was 4.5 percent
for unwashed coal and 2.6 percent for washed coal. The ash concentrations
were 10.7 percent and 7.2 percent, respectively. Superficial velocity was
approximately 3.4 m/sec (11 ft/sec) and sorbent feed particle size was -44 vim.
particulate emission measurements downstream of the primary cyclone are sum*
marized in Table 6. PER reports that 52 percent by weight (90 percent by
number) of particles exiting the cyclone were smaller than 5 ym. In all cases,
cyclone collection efficiency exceeded 90 percent.
Use of carbon burnup cell in industrial FBC systems is not anticipated,
however, measurements made by PER on their modified fluidized-bed column indi-
cate the effect of operating temperature on particulate emissions. As shown
in Figure 23,138 particulate emissions decrease with increasing temperature,
probably due to Improved carbon combustion and ash agglomeration.139 Over the
temperature range tested, particulate emissions varied from 430 up to 3,440 ng/J
(1 to 8 lb/106 Btu).
During the ANL studies of particle size distribution, a grain loading of
0.198 gr/cf (approximately 215 ng/J) was measured in the exhaust from the
secondary cyclone.140 ANL ran tests to determine cyclone efficiency (primary
cyclone, 6-5/8 in. diameter; secondary cyclone, 4-1/2 in. diameter),lkl Flue
gas volumes ranged from 3.8 to 6.6 Ips (8 to 14 cfm), coal feed from 1.8 to 3.3
fcg/hr (1.1 to 2.3 Ib/hr). The dust loading in the combustor exhaust prior to
both cyclones ranged from 0.16 to 1.78 gr/cf, (approximately 170 to 1,920 ng/J)
117
-------
PARTICULATE EMISSION, Ib/I068to
0.4S
« 0.44
§
- 0.43
IMPERATURE.
o
A
K>
IU
£ <
£ 041<
.J
cc
0 0-*0
Ul
IT
0.39
43
1 2 3 4 5 C 7 |
\ \ 1 1 1 1
O
00
_
o o oo
0
>° o
603 0 CD 0 0
o oo o o
0 0
- o
-00
o
1 1 1 1 1 1
0 860 1290 1790 2150 2580 3010 344
PARTICULATE EMISSION. ng/J
Figure 23. Particulate emissions as a function of temperature as
determined by PER in simulated CBC operation.
118
-------
and the average measured loading after the secondary cyclone was 0.06 gr/cf
(approximately 65 ng/J) ranging to a maximum of 0.22 gr/cf (approximately 240
ng/J). Combined overall cyclone efficiency was approximately 90 percent.
Data obtained by the National Coal Board142 (from the 1.5 ft x 3 ft CRE
reactor) using primary and secondary cyclones with collection efficiencies of
90 percent for 10 ym particles, showed exhaust particulate loadings between
0.1 and 0.6 gr/scf (approximately 110 to 650 ng/J). This indicated a combined
collection efficiency for the two cyclones of 95 to 98 percent. Fractional
efficiencies for the two cyclones are shown in Figure 24, and show how drasti-
cally cyclone efficiency drops for particles smaller than 10 urn. During testing,
superficial gas velocity ranged between 1.2 to 2.4 m/sec (4 to 8 ft/sec). The
primary cyclone had a 0.6 m (24 in.) diameter with a height of 2.7 m (8 ft,
10 in.). The secondary cyclone had a diameter of 0.43 m (17.25 in.) and height
of 2 m (6 ft, 7 in.).
The primary fines were sampled using an incremental sampler designed to
take a full cross sectional sample of the entire fines flow. Samples of ex-
haust dust were obtained from a probe 1.2 m (4 ft) after the secondary cyclone
by extracting isokinetically a known volume of exhaust gas and passing it
through a weighed filter.
Babcock and Wilcox has compiled particulate emission data reported by
several investigators and has found that the best correlation of particulate
emission rate is based on superficial air velocity. Figure 25 illustrates the
relationship between uncontrolled particulate emission rate and superficial air
velocity, as reported for one specific sorbent type.11*3 This particular graph
is based on data from NCB (the 1.5 ft x 3 ft, 27 in. diameter, and the 6 in.
diameter units) and ANL (the 6 in. diameter unit).
119
-------
ro
o
SECONDARY CYCLONE
INLET VELOCITY«23-46m/wc (75-i50ft/Mc)
PRIMARY CYCLONE
INLET VELOCITY* II-23m/Me ( 37-75ft/we)
SUPERFICIAL GAS VELOCITY « 1.2-2.4
(4-8 ft/we)
10
20
PARTICLE SIZE,
Figure 24. Fractional efficiency of the primary and secondary cyclones during
experimentation in the NCB-CRE 36 in. * 18 in. test unit.
-------
SUPERFICIAL VELOCITY, fl/stc
0 I 2 3 4 5 6 7 8 9 10 II 12 13 14
80
60
40
rx
t
i
5
3 20
K
oc
1 10
tu
tu 6
J
P. «
<
a.
0
**1 2
O
a
^
z
O 1
. 1 1 1 1 1 1 I 1 1 1 I 1 1 .
-
i • i
* • •
^B ^&
w
•
«p
•
*
_
: ••' :
I
-
_
i i 1 i i i i i i i i i i
8«o"
645
43°
UJ
H
4
^
3
21 y
K
°- -»
ii 2 ?
141 C
;f2
^m
O
5 1
UJ
<
2 -
X
o
ae
a.
a.
4
.6 \2. 1.8 2.4 3.0 3.7
SUPERFICIAL VELOCITY. ffl/StC
4.3
Figure 25. Uncontrolled particulate emission rate versus
superficial velocity — Stone 7.11*3 (Reproduced
with permission of EPRI.)
In actual application, this relationship may not be so extreme (with
rcspect to required removal efficiency in the final particulate collection
device), because the primary and/or secondary cyclones will perform more
efficiently in collecting particles of larger size elutriated at higher super-
fical velocities.
Babcock and Wilcox has reported results of particulate emission testing m
their 6 ft * 6 ft unit. ^ Gas residence times were in the range of 0.4 to 0.6
sec with superficial velocities between 2.1 to 3.0 m/sec (7 to 10 ft/sec).
Lowellville limestone was fed with a top size of 9,525 ym (3/8 in. x 0). Par-
ticle loadings were measured at the inlet and outlet of the primary cyclone
using automatic duct traversing and isokinetic sampling (see Section 7.0).
121
-------
The results are summarized in Table 16. The outlet loadings are fairly
high, mainly due to the apparently low efficiency of the primary cyclone. In
those instances where cyclone efficiency was greater than 80 or 85 percent,
cyclone outlet loadings were below 2,150 ng/J (5.0 lb/106 Btu). One outlet
loading was measured at 3,224 ng/J (7.5 lb/106 Btu) at a cyclone efficiency of
83 percent. However, the highest inlet loading (by a factor of 2) was measured
during this test (18,900 ng/J). The reason for this high inlet loading is
unclear.
Babcock and Wilcox also reported emission testing results from operation
of their 0.91 m x 0.91 m (3 ft * 3 ft) experimental unit.145 Particulate mea-
surements were made in the combustor freeboard and in the flue prior to the wet
scrubber inlet. An internal cyclonic cavity is included in the flue for primary
particulate removal. Comparison of emissions in the freeboard (prior to the
internal cyclonic cavity) and at the wet scrubber inlet illustrated a total
collection efficiency ranging between 50 to 80 percent for the cyclone with an
average capture of about 70 percent. This is below the capture efficiency of
85 to 90 percent normally cited as appropriate for primary particulate removal.
Therefore, the particulate emission rates noted in Table 16 are higher than
expected from an industrial FBC boiler utilizing a primary particulate removal
device with efficiency of 85 to 90 percent. Other factors contributing to the
high particle emissions are the low freeboard of the unit and the relatively
high superficial velocities used during the testing, between 2.4 to 3.7 m/sec
(8 to 12 ft/sec).
However, the data show how particle elutriation varies as a function of
sorbent particle size and feed rate. During addition of Lowellville limestone
with a top size of 6,350 ym, measured particulate rate after the cyclone was
between 2,253 to 3,375 ng/J (5.24 to 7.85 lb/106 Btu). As limestone top size
122
-------
was decreased to 2,380 pm, the range in particulate rates measured at the wet
scrubber inlet increased to 2,878 to 3,689 ng/J (6.74 to 8.58 lb/106 Btu).
Dropping limestone size further to 1,000 pm top size, the range in particulate
rate increased to 3,078 to 4,170 ng/J (7.16 to 9.70 lb/106 Btu). With pulverized
limestone, the particulate rate was measured in the range of 5,434 to 7,825 ng/J
(12.64 to 18.20 lb/106 Btu). Using pulverized Greer and Grove limestones and
Ca(OH)2 with a top size of 44 ym produced particulate rates of approximately
6,450 ng/J (15 lb/106 Btu) with a maximum of 15,215 ng/J (35.39 lb/106 Btu).
Again, the low freeboard of the B&W 3 ft * 3 ft unit, combined with the
high gas velocity, undoubtedly contributed significantly to the high particu-
late emissions. The trend in envisioned commercial FBC units is to design with
higher freeboard and lower superficial gas velocities.
2.5.4 Summary of Particulate Emission Data
The particulate summary table (Table 16 in Section 2.5.3.2) summarizes the
particulate data presented in this subsection for atmospheric FBC systems. Emis-
sions measured downstream of primary and secondary cyclones are specified along
with associated removal efficiencies.
The cyclone outlet emissions measured from the B&W 6 ft * 6 ft test unit
are slightly higher than would be expected in a commercial unit operating with
a high primary cyclone efficiency. In most of these tests, primary cyclone
efficiency was below 75 percent. When efficiency approached 85 percent, emis-
sions generally fell below 2,150 ng/J (5.0 lb/106 Btu).
The Babcock and Wilcox emission data recorded at the inlet to the wet
scrubber of the 3 ft x 3 ft unit are significantly higher than any of the data
from other units due to the low freeboard on the 3 ft x 3 ft unit. However,
good primary particulate control conditions were not noted during this experi-
mentation. Considering the high fluidizing velocity, shallow bed, and primary
123
-------
collector design, the emissions measured in the Babcock and Wilcox 3 ft * 3 ft
unit are essentially uncontrolled in comparison to other FBC units with deeper
beds and better primary cyclone designs.
Particulate control requirements for AFBC should be similar to require-
ments for conventional boilers burning low sulfur coal. Use of a cyclone alone
is not adequate to attain emission levels as stringent as 43 ng/J (0.1 lb/106
Btu) or lower. Demonstration of control equipment is necessary because very
little data exist to support the capability of final particulate control devices
applied to atmospheric FBC boilers.
Based on PER, NCB, and ANL data, it appears that dust loadings entering
final control systems are in a range (0.5 to 5.0 lb/106 Btu) similar to emissions
generated in conventional systems. Mass mean particle sizes entering the final
control systems may be about 5 to 20 urn, depending upon the design of the cy-
clones. Therefore, with application of add-on equipment, any standard for
conventional sources should also be supported by FBC. Future test programs
to be conducted at Rivesville, West Virginia, Georgetown University, EXXON,
the EPA-SATR test unit, and other sites will indicate performance capabilities
of ESPs, fabric filters, and wet scrubbers used as final particulate control
devices.
2.5.5 Impacts of Particle Control on Boiler Operation
It is not expected that use of add-on final particulate control systems
will have any adverse impact on industrial FBC boiler operation.
2.5.6 Documentation
As summarized in Section 2.2.1.4, available source test data demonstrating
the efficiency of final particulate control is very limited. Data presented
here are based on studies conducted at ANL, PER, NCB, and Babcock and Wilcox.
124
-------
2.6 PRESSURIZED FBC
Pressurized FBC boilers would only be used in industrial applications if
the user had large electricity requirements and the system adequately fulfilled
the specific cogeneration needs. Based on the stage of PFBC development, it is
not anticipated that the typical industrial user would have sufficient need for
electrical power (from a gas turbine) to warrant the increased capital cost and
system complexity involved. Therefore, we have not considered pressurized
fluidized-bed boilers in this report. Although specific larger industries
might use pressurized technology we do not anticipate widespread application
in the near future.
125
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2.7 REFERENCES
1. Vogel, G.J., et al. Bench Scale Development of Combustion and Additive
Regeneration in Fluidized Beds. Proceedings of The Third International
Conference on Fluidized Bed Combustion. Prepared for the U.S. Environ-
mental Protection Agency by Argonne National Laboratories. December
1973. (PB 231-977), p. 1-1-24.
2. Dowdy, T.E., et al. Summary Evaluation of Atmospheric Pressure Fluidized
Bed Combustion Applied to Electric Utility Large Steam Generators. Pre-
pared by the Babcock & Wilcox Company for the Electric Power Research
Institute. EPRI FP 308. Volume II: Appendix. October 1976. Data
compilation presented on pp. 6K-55 to 6K-61.
3. Farmer, M.H., et al. Application of Fluidized Bed Technology to
Industrial Boilers. Prepared by EXXON Research and Engineering Company
for the U.S. Environmental Protection Agency. EPA Report No. 600/7-77-011,
January 1977, p. 10.
4. Dowdy, T.E., et al. Summary Evaluation of Atmospheric Pressure Fluidized
Bed Combustion Applied to Electric Utility Large Steam Generators. Pre-
pared by the Babcock & Wilcox Company for the Electric Power Research
Institute. EPRI FP-308. Volume I: Final Report. October 1976, p. 3-3.
5. Ibid.
6. Dowdy, T.E., et al. op. cit. Volume I, p. 6-40.
7. Archer, D.H., et al. Evaluation of the Fluidized Bed Combustion Process.
Performed for the U.S. Environmental Protection Agency by Westinghouse
Research Laboratories under Contract No. CPA 70-9. Volume I, Summary
Report. APTD-1165. November 15, 1971, p. 7.
8. Skopp, A., et al. Studies of the Fluidized Lime Bed Combustion Desul-
furization System: Final Report. Prepared by ESSO Research and Engin-
eering Co. for the U.S. Environmental Protection Agency, January 1 —
December 31, 1971 (PB 210-246) p. 66.
9. Hoke, R.C., et al. A Regenerative Limestone Process for Fluidized Bed
Coal Combustion and Desulfurization. Prepared by ESSO Research and
Engineering Company for the U.S. Environmental Protection Agency.
EPA 650/2-74-001. 1974, p. 64.
10. Dowdy, T.E., et al. Volume II, p. 6D-1.
11. Hammons, G.S., M.S. Nutkis, and A. Skopp. Studies of NOX and S02 Control
Techniques in a Regenerative Limestone Fluidized-Bed Coal Combustion
Process. ESSO Research and Engineering Co. Prepared under Contract
CPA 70-19 for the U.S. Environmental Protection Agency. January 1 to
June 1, 1971, p. 27.
126
-------
12. Fennelly, P.F. , et al. Preliminary Environmental Assessment of Coal-Fired
Fluidized-Bed Combustion Systems. Prepared by GCA Corporation, GCA/
Technology Division for the U.S. Environmental Protection Agency.
EPA-600/7-77-054. May 1977, p. 115.
13. Johnston Boiler Company. Johnston Multi-Fuel Fluidized Bed Combustion
Packaged Boilers. Advertising Brochure. February 1978.
14. Vaughan, D.A., et al. Fluidized Bed Combustion Industrial Application
Demonstration Projects. Special Technical Report on Battelle's Multi-
Solids Fluidized Bed Combustion Process. Prepared for the Energy Research
and Development Administration by Battelle Columbus Laboratories.
February 7, 1977, p. 1.
15. DeCoursin, D. A Description of an Industrial Fluidized-Bed Combustion
Heating System. Prepared by FluiDyne Engineering Co., presented at the
Conference on Engineering Fluidized-Bed Combustion Systems for Industrial
Use. Columbus, Ohio. September 1977.
16. Stone-Platt Fluidfire, Limited. Advertising Brochure on Fluidized-Bed
Boilers and Incinerators.
17. Buck, V., et al. Industrial Application Fluidized Bed Combustion
Georgetown University. The Proceedings of the Fifth International Con-
ference on Fluidized Bed Combustion. Volume II. December 12-14, 1977.
p. 73.
18. Murthy, K.S., and H. Nack. Trip Report on European Fluidized-Bed
Combustion Technology Developments. Battelle Columbus Laboratories.
June 1978, p. 17-21.
19. Gamble, R.L. Design of the Rivesville Multicell Fluidized Bed Steam
Generator. Foster-Wheeler Energy Corporation. Proceedings of the
Fourth International Conference on Fluidized Bed Combustion. Sponsored
by the U.S. Energy Research and Development Administration.
December 9-11, 1975, p. 133-151.
20. Anderson, J.B., and W.R. Norcross. Fluidized Bed Industrial Boiler, pre-
pared by Combustion Engineering, presented in Combustion Magazine
February 1979, p. 9-14.
21. Buck, V., F. Wachtler, and R. Tracey. Industrial Application Fluidized
Bed Combustion Georgetown University. Prepared by Pope, Evans & Robbins
Inc., Foster-Wheeler Energy Corp., and Fluidized Combustion Company,
presented at the Fifth International Conference on Fluidized Bed
Combustion, December 1977. Volume II, p. 61-91.
22. Nack, H., K.T. Liu, and G.W. Felton. Battelle's Multisolid Fluidized-
Bed Combustion Process, prepared by Battelle Columbus Laboratories, pre-
sented at the Fifth International Conference on Fluidized Bed Combustion.
December 1977. Volume III, p. 223-239.
127
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23. EXXON Research and Engineering Company. Industrial Application Fluidized
Bed Combustion Category III Indirect Fired Heaters. Quarterly Technical
Report No. 10. October 1 - December 31, 1978. Prepared by EXXON Re-
search and Engineering Company for the U.S. Department of Energy.
24. Letter correspondence from Mr. G.S. Kapp of Arthur G. McKee and Company
to Mr. Raymond Yu of GCA/Technology Division, April 10, 1978.
25. Tostenson, N.S. Legislative Response to Fluidized Bed Program in Ohio.
Presented at the Conference on Engineering Fluidized Bed Combustion for
Industrial Use. Battelle Columbus Laboratories. September 1977
p. 155-157.
26. Telephone correspondence between Mr. Robin Turner of North American Coal
Corporation, Cleveland, Ohio, and Ms. J.M. Robinson of GCA/Technology
Division. July 24, 1978.
27. Telephone correspondence between Dr. Arthur Squires of Virginia Polytechnic
Institute, and Mr. C.W. Young of GCA/Technology Division. July 31, 1978.
28. Telephone correspondence between Mr. Mike Michaels of Johnston Boiler
Company and Mr. Charles Young of GCA/Technology Division. April 25 1979
29. Telephone correspondence between Mr. David Walker of Babcock and Wilcox
Co., Industrial Marine Division and Mr. C.W. Young of GCA/Technology
Division. July 27, 1978.
30. Telephone correspondence between Dr. James Porter of Energy Resources
Company and Ms. J.M. Robinson of GCA/Technology Division. July 11, 1978.
31. Telephone correspondence between Mr. R.R. Whitehouse of Johnston Boiler
Company and Mr. C.W. Young of GCA/Technology Division. July 5, 1978.
32. Farmer, M.H. op. cit., p. 20.
33. Telephone correspondence between Mr. R.R. Whitehouse of Johnston Boiler
Company and Mr. C.W. Young of GCA/Technology Division. July 5, 1978.
34. Farmer, M.H. op. cit., p. 11.
35. Ibid, p. 4-5.
36. The Fuel Use Act of 1978, Public Law 95-620. 92 Stat. 3290.
37. Farmer, M.H. op. cit. , p. 38.
38. Farmer, M.H., et al. op. cit., p. ii.
39. Newby, R.A., et al. Effect of S02 Emission Requirements on Fluidized-
Bed Combustion Systems: Preliminary Technical/Economic Assessment.
Prepared for the U.S. Environmental Protection Agency by Westinghouse
Research and Development Center. EPA-600/7-78-163. August 1978, p. 174
128
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40. Letter correspondence from Mr. D. Bruce Henschel of the U.S. EPA, IERL
to Dr. Paul F. Fennelly of GCA/Technology Division. June 28, 1978.
41. Keairns, D.L., et al. Experimental and Engineering Support of the
Fluidized-Bed Combustion Program. Prepared by Westinghouse Research and
Development for the U.S. Environmental Protection Agency. Third Monthly
Progress Report. Contract No. 68-02-3110. January 1-31, 1979, p. 17. '
42. Harvey, R.D., R.R. Frost, and J. Thomas. Petrographic Characteristics
and Physical Properties of Marls, Chalks, Shells, and Calcines related to
Desulfurization of Flue Gases. Final Report. Prepared by the Illinois
State Geological Survey for the U.S. Environmental Protection Agency.
EPA 650/2-73-044.
43. Thoennes, C.M. Automatic Constant SO2 Removal Concept Assessment.
Monthly Progress Report, March 1979. Prepared by General Electric Company
Energy Systems & Technology Division for the U.S. Environmental Protec-
tion Agency, p. 1.
44. Jonke, A.A., et al. Supportive Studies in Fluidized Bed Combustion.
Prepared by Argonne National Laboratory for the U.S. Environmental
Protection Agency EPA-600/7-77-138. December 1977, p. 30-38.
45. Newby, R.A., and D.L. Keairns. Alternatives to Calcium-Based S02 Sorbents
for Fluidized-Bed Combustion: Conceptual Evaluation. Prepared by
Westinghouse Research and Development Center for the U.S. Environmental
Protection Agency, EPA-600/7-78-005. January 1978.
46. Johnson, I. Support Studies in Fluidized-Bed Combustion. Quarterly
Report. Prepared by Argonne National Laboratory for the U.S. Department
of Energy and the U.S. Environmental Protection Agency. ANL/CEN/FE 78-3.
January to March 1978.
47. Ruth, L.A., and G.M. Varga, Jr. Regenerable Sorbents for Fluidized-Bed
Combustion. Final Report. Prepared by EXXON Research and Engineering
Co. for National Science Foundation RANN Program. June 1978.
48. Hoke, R.C., et al. Miniplant Studies of Pressurized Fluidized-Bed
Combustion. Third Annual Report. Prepared by EXXON Research and
Engineering Company for the U.S. Environmental Protection Agency.
EPA-600/7-78-069. April 1978, p. 48-51.
49. Dowdy, T.E. op. cit. Volume II. Data Compilation Presented on p. 6K-55
to 6K-61.
50. Manfred, R.K., and K.J. Clark. Design and Construction of a Fluidized
Bed Coal Combustion Sampling and Analytical Test Rig. Monthly Reports.
Prepared by Acurex/Aerotherm for the U.S. Environmental Protection
Agency.
129
-------
51. Telephone correspondence between Dr. H. Bennett, coordinator for DOE's
Agricultural Program for FBC Solid Wastes, and Dr. T. Goldschmid of GCA/
Technology Division. February 28, 1979.
52. Minnick, L.J. Development of Potential Uses for the Residue from
Fluidized-Bed Combustion Processes, Quarterly Technical Progress Reports.
Prepared for the U.S. Department of Energy, by L. John Minnick, Prime
Contractor. December 1978-February 1979.
53. FluiDyne Engineering Corporation. Industrial Applications Fluidized Bed
Combustion Process, Quarterly Report, April-June 1977. Prepared by
FluiDyne Engineering Corporation for the U.S. Energy Research and Develop-
ment Administration. FE 2463-12, November 1977,
54. Hanson, H.A., D.C. DeCoursin, and D.D. Kinzler. Fluidized-Bed Combustor
for Small Industrial Applications. Prepared by FluiDyne Engineering Corr-
poration, presented at the Fifth International Conference on Fluidized-
Bed Combustion, December 1977. Volume II, pp. 91-105.
55. Newby, R.A., et al. Effects of SOa Emission Requirements on Fluidized
Bed Combustion Systems: Preliminary Technical/Economic Assessment.
Prepared by Westinghouse Research and Development Center for the U.S.
Environmental Protection Agency. EPA-600/7-78-163. August 1978, p. 60.
56. Letter correspondence from Dr. Richard Newby of Westinghouse Research
and Development Center to Mr. C.W. Young of GCA/Technology Division.
April 3, 1979.
57. Ahmed, M.M., D.L. Keairns, and R.A. Newby. Effect of S02 Requirements
on Fluidized Bed Boilers for Industrial Applications: Preliminary
Technical/Economic Assessment. Prepared by Westinghouse Research and
Development Center for the U.S. Environmental Protection Agency.
58. Robison, E.B., et al. Interim Report on Characterization and Control of
Emissions from Coal-Fired Fluidized-Bed Boilers. Prepared by Pope, Evans
and Robbins for National Air Pollution Control Administration and U.S.
Department of Health, Education and Welfare. PB 198^-413, October 1970.
pp. 60 and 63.
59. Newby, R.A., et al. op. cit., p. 14.
60. Letter correspondence from Ms. Nancy Ulerich, Westinghouse Research and
Development Center to Mr. D.B. Henschel, U.S. EPA IERL. June 5, 1978.
61. Newby, R.A., et al. op. cit., pp. 73 and 76.
62. Ibid.
63. Jonke, A.A., et al. Supportive Studies in Fluidized-Bed Combustion.
Prepared by Argonne National Laboratory for the U.S. Environmental
Protection Agency. EPA-600/7-77-138. December 1977, pp. 98 and 99.
130
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64. Minnick, L.J. Supply Factors and Characteristics of Limestone for
Fluidized-Bed Combustion Systems. Presented at the Conference on Engi-
neering Fluidized-Bed Combustion Systems for Industrial Use Sponsored
by the Ohio Energy Research and Development Administration and Battelle
Columbus Laboratory. September 26-27, 1977, p. 87-95.
65. Murthy, K.S., et al. Engineering Analysis of the Fluidized-Bed Combustion
of Coal. Prepared by Battelle Columbus Laboratories for the U.S. Environ-
mental Protection Agency, May 1975, p. A-18.
66. Vogel, G.J., et al. op. cit.. p. 1-1 to 1-24.
67. Murthy, K.S., et al. op. cit. 1974, p. A-18.
68. Vogel, G.J., et al. op. cit., p. 1-1-5.
69. Dowdy, T.E. op cit., p. 7-3.
70. Dowdy, T.E. op. cit. Volume II, p. 7A-11.
71. Ibid. 7A-19.
72. Dowdy, T.E. op. cit.. p. 7-6.
73. Ibid. 8-6.
74. Finnie, I. Erosion by Solid Particles, Journal of Materials. 19(1):
September 1967.
75. Jonke, A.A. Reduction of Atmospheric Pollution by the Application of
Fluidized-Bed Combustion. Argonne National Laboratories. Annual Report,
July 1969 to June 1970. ANL/ES-CEN-1002. p. 40.
76. Robison, E.B., et al. Interim Report on Characterization and Control
of Gaseous Emission from Coal-Fired Fluidized-Bed Boilers. Pope, Evans,
and Robbins. October 1970, p. 79.
77. Sarofim, A.F., and J.M. Bee"r. Modeling of Fluidized-Bed Combustion. Pre-
pared by the Department of Chemical Engineering, Massachusetts Institute
of Technology. Presented at the Seventeenth Symposium (International)
on Combustion, August 1978.
78. Pereira, F.J., et al. NOX Emissions from Fluidized-Bed Coal Combustors.
Prepared by University of Sheffield, England. Presented at the Fifteenth
Symposium (International) on Combustion, August 1974, p. 1,149-1,156.
79. Pope, Evans and Robbins, Inc. Multicell Fluidized-Bed Boiler Progress
Report 16. January 1974. Prepared by PER Inc. for the Office of Coal
Research, Department of the Interior, p. 41.
131
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80. Beacham, B. , and A.R. Marshall. Experience and Results of Fluidized-Bed
Combustion Plant at Renfrew. Prepared by Babcock Contractors Ltd., and
Combustion System Ltd. Presented at a Conference in Diisseldorf,
W. Germany. November 6 and 7, 1978.
81. Jonke, A.A., et al. Reduction of Atmospheric Pollution by the Application
of Fluidized-Bed Combustion, Annual Reports 1968, 1969, & 1970.
ANL/ES-CEN 1001, 1002, & 1004.
82. Hansen, W.S., et al. Fluidized-Bed Combustion Development Facility and
Commercial Utility AFBC Design Assessment Quarterly Technical Progress
Report, April to June 1978. Prepared by Babcock and Wilcox Company for
the Electric Power Research Institute, July 1978.
83. Pereira, F.J., et al. NO Emissions from Fluidized-Bed Coal Combustors.
Prepared for the Fifteenth Symposium on Combustion. August 25 through
31, 1974, p. 1,149-1,156.
84. Skopp, A., op. cit.
85. Robison, E.F., et al. op. cit. October 1970, p. 76-69 and 100-105.
86. Jonke, A.A., op. cit. July 1968 to June 1969. p. 35.
87. Jonke, A.A., op. cit. July 1969 to June 1970. p. 39.
88. Jonke, A.A. Reduction of Atmospheric Pollution by the Application of
Fluidized-Bed Combustion. Argonne National Laboratories. Annual
Report, July 1968 to June 1969. ANL/EX-CEN-1001. pp. 33-34.
89. Dowdy, T.E., op. cit. Volume II. Data compilation presented on p. 6K-55
to 6K-61.
90. Pereira, F.J., and J.M. Beer. A Mathematical Model of NO Formation and
Destruction in Fluidized Combustion of Coal. Massachusetts Institute
of Technology, Department of Chemical Engineering. Presented at the
Engineering Foundation Conference on Fluidization. Cambridge, Massa-
chusetts, April 1 to 6, 1978, p. 6.
91. Bee"r, J.M., et al. NO Reduction by Char in Fluidized Combustion.
Massachusetts Institute of Technology, Department of Chemical Engineer-
ing and Energy Laboratory, Cambridge, Massachusetts. Undated, p. 1.
92. Dowdy, T.E., op. cit. Volume I, p. 6-30.
93. Dowdy, .n.E., op. cit. Volume II. Data compilation presented on p. 6K-55
to 6K-61.
94. Skopp, A. Studies of the Fluidized Lime-Bed Coal Combustion Desulfuri-
zation System. Final Report. Prepared by ESSO Research and Engineering
for the U.S. Environmental Protection Agency. January 1 to December 31
1971. (PB 210-246). '
132
-------
95. Pope, Evans, and Robbins, Inc., Interim Report No. 1 on Multicell
Fluidized-Bed Boiler Design, Construction and Test Program. Prepared
by Pope, Evans, and Robbins, Inc. for the U.S. Department of the Interior.
PB 236-254, August 1974. p. 145.
96. Beer, J.M., et al. op. cit. p. 2.
97. Skopp, A., op. cit.
98. Jonke, A.A., op. cit. Annual Report. July 1969 to June 1970. p. 38.
99. Skopp, A., op. cit.
100. Ibid.
101. Murthy, K.S., op. cit. 1974. p. A-41.
102. Beer, J.M., et al. op. cit. Undated, p. 1.
103. National Coal Board. Reduction of Atmospheric Pollution. Main Report.
Prepared by the Fluidized Combustion Control Group for the U.S. Environ-
mental Protection Agency. PB 210 673. September 1971. p. 137.
104. Archer, D.H. Evaluation of Fluidized-Bed Combustion Process. Volume II.
Technical Evaluation. U.S. Environmental Protection Agency, Office of
Air Programs. Contract No. CPA 70-9. November 15, 1969 to November 15,
1971. p. 73.
105. Pereira, F.J. and J.M. Beer. NOX Formation from Coal Combustion in a
Small Experimental Fluidized Bed. Deuxieme Symposium sur la Combustion,
Orleans, France. September 5, 1975.
106. Ando, J., et al. NOX Abatement for Stationary Sources in Japan. Pre-
pared by PEDCo for the U.S. Environmental Protection Agency. EPA-600/
7-77-103b. September 1977. p. 24.
107. Personal correspondence between Mr. Walter Steen of the U.S. Environ-
mental Protection Agency and Mr. Cabot B. Thunem of GCA/Technology
Division. March 20, 1979.
108. Hoke, R.C. A Regenerative Limestone Process for Fluidized-Bed Coal
Combustion and Desulfurization. Monthly Progress Report No. 105. Pre-
pared by EXXON Research and Engineering Company for the U.S. Environ-
mental Protection Agency. November 1978. pp. 26-28.
109. Telephone correspondence between Mr. C,J. Lyons of Battelle Columbus
Laboratories and Mr. Cabot B. Thunem of GCA/Technology Division.
April 4, 1979.
110. Arthursson, D.A.A. Fluidized Bed Furnace in Enkoping, Sweden. Report
No. 1. Description of Multi-Fuel Fluidized Bed Furnace. Prepared by
Svenska, VarmeVerks-foreningen.
133
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111. Jonke, A.A. Reduction of Atmospheric Pollution by the Application of
Fluidized Bed Combustion. Argonne National Laboratories. Annual Report
July 1970 to June 1971. ANL/CEN/ES 1004. pp. 50-53.
112. Skopp, A., op. cit.
113. Bee"r, J.M., et al., op. cit. Undated, p. 14-15.
114. Jonke, A.A., op. cit. July 1969 to June 1970. p. 39.
115. Parks, D.J. Formation of Nitric Oxide in Fluidized Bed Combustion.
Ph.D. Thesis. University of Minnesota, Department of Mechanical
Engineering. 1973. p. 85.
116. Robison, E.F., op. cit. Interim Report, p. 79. October 1970.
117. Dowdy, I.E., op. cit. Volume II, p. 6E-1.
118. Fennelly, P.F., op. cit., p. 115.
119. Dowdy, T.E., op. cit. Volume I, p. 6-52.
120. Gordon, J.S., et al. Study of the Characterization and Control of Air
Pollutants from a Fluidized Bed Boiler - The S02 Acceptor Process. Pre-
pared for the U.S. Environmental Protection Agency by Pope, Evans, and
Robbins, Inc. EPA-R2-72-021. July 1972. p. 1-5.
121. Ibid, p. 6-6.
122. Fennelly, P.F., op cit., p. 111.
123. Ibid., p. 112.
124. Ibid., p. 113.
125. Ibid.. p. 93.
126. Dowdy, I.E., op. cit. Volume 1, p. 6-48.
127. Pope, Evans, and Robbins, Inc., op. cit. Interim Report No. 1, p. 153^
128. Dowdy, T.E., op. cit. Volume I, p. 6-48.
129. Robison, E.F., op. cit. Interim Report. October 1970. p. 7.
130. Fennelly, P.F., op. cit., p. 98.
131. Ibid., p. 95.
T32. Pope, Evans, and Robbins, Inc. op. cit. Interim Report No. 1, p. 15 j
August 1974.
134
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133. Shannon, L.J., and P.G. Gorman. Particulate Pollutant System Study.
Volume II - Fine Particulate F^.issions. Prepared by Midwest Research
Institute for the U.S. Environmental Protection Agency. Publication No.
APTD-0744. August 1971. pp. 67-69.
134. Jonke, A.A. op. cit. Annual Report, July 1968 to June 1969. ANL/ES-
CEN-1001. pp. 16 and 17.
135. Robison, E.F., et al. op. cit. PB 198 413. October 1970. pp. 2-4.
136. Ibid, p. 1
137. Ibid. Appendix B.
138. Robison, E.F., et al. Study of Characterization and Control of Air
Pollutants from a Fluidized-Bed Combustion Unit. The Carbon-Burnup Cell.
Prepared by Pope, Evans, and Robbins for the U.S. Department of Health
Education and Welfare. PB 210 828. February 1972. p. 171.
139. Ibid, p. 170.
140. Jonke, A.A., op. cit. Annual Report July 1968 to June 1969. ANL/ES-
CEN-1001. pp. 29-32.
141. Argonne National Laboratories. Annual Report. Report No. ANL/ES-CEN-
1005. June 1973. p. 32.
142. National Coal Board. Reduction of Atmospheric Pollution, Main Report.
Prepared for the U.S. Environmental Protection Agency. Reference No.
DHB 060971. September 1971. p. xix.
143. Dowdy, T.E., op. cit. Volume II. p. 6E-4.
144. Babcock and Wilcox Company. Fluidized Bed Combustion Development
Facility and Commercial Utility AFBC Design Assessment. Technical
Quarterly Progress Report No. 8, January through March 1979. Prepared
for the Electric Power Research Institute. April 13, 1979. pp. 2-5 to
2-90.
145. Lange, H.B., et al. SOz Absorption in Fluidized-Bed Combustion of Coal,
Effect of Limestone Particle Size. Prepared for Electrical Power
Research Institute by Babcock and Wilcox Company. FP-667, Research
Project 719-1. January 1978. p. A-6.
135
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3.0 CANDIDATES FOR BEST SYSTEM OF EMISSION REDUCTION
3.1 CRITERIA FOR SELECTION
The criteria used in selecting best systems of emission reduction are
as follows:
• System Performance - Ideally, the technique chosen for any
one pollutant should have the least possible impact on com-
bustion or boiler efficiency, the least possible impact on
system operability, and result in the least possible increase
in the emissions of other pollutants from the system.
• Applicability - The best system of emission reduction should
have a relatively wide applicability across the spectrum of
boilers to be encountered in the industrial sector. It should
not be especially sensitive to factors such as size, fuel
type, load cycle, plant configuration, etc.
• Status of Development - The emission control technique
should be forecasted as being available when emission control
levels are set and incorporated into AFBC units as they find
widespread commercial acceptance. It would be better if
the techniques were available now, or at least in a
prototype status. The best situation would be for the
tecniques to be already available and successfully
demonstrated.
• Cost - The system should be capable of meeting optional
emission control levels without inordinate increases in
capital or operating cost. Ideally, the "best system"
.would have the lowest cost of the options available.
For S02, the best system of emission reduction is the one which minimizes
sorbent feed rates, and still attains high levels of control. The Ca/S molar
feed ratio can be reduced with careful control of other operating conditions'
most significantly, sorbent particle size and gas phase residence time.
Reduction of sorbent requirements reduces not only the operating cost associated
with purchase of fresh sorbent, but also reduces the cost and environmental
136
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impact of spent solids disposal. Electricity requirements are reduced and
boiler efficiency is slightly increased.
Emission control techniques for S02 which were rejected either because of
limited applicability or still tenuous technical development included pressurized
fluidized-bed combustion, sorbent precalcination, sorbent regeneration, syn-
thetic sorbents and sorbent catalysts. The use of SC>2 scrubbers on FBC flue
gas was also not considered, due to concerns regarding performance and
applicability.
For NOX emissions, the best system of emission reduction appears to be
capitalizing on the inherent combustion chemistry which occurs in fluidized-
bed systems. The low temperature and the chemical kinetics of the system
combine to provide relatively low NOx emissions. For stringent NOx control
some care in the selection of design/operating conditions may be required.
Control techniques which were not considered, due primarily to status of
development, include substantive combustion modifications (such as two-stage
combustion, flue gas recirculation, and ammonia/urea injection), and NOX
scrubbing.
It is expected that particulate emissions can be controlled using con-
ventional particulate control technology which is currently available, with
the best systems appearing to be fabric filtration or electrostatic precipita-
tion for stringent or intermediate control, and multitube cyclones for moderate
control. Neither fabric filtration nor electrostatic precipitators have yet
been tested on commercial-sized FBC facilities, but pilot plant data have not
suggested any unusual problems beyond those that would be encountered in a
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conventional boiler burning low sulfur coal. By suitable design and operation
of the particle control devices, it is anticipated that satisfactory performance
can be achieved.
3.1.1 Selection of Optional Emission Control Levels
The optional emission control levels which will be addressed in selecting
best systems are shown in Table 17. These ranges of optional emission control
levels have been chosen because they are felt to represent attainable control
levels using FBC boilers. The rationale for selection of these optional levels
is discussed further in the following subsections. All conclusions are based
on initial test results from prototype units, and from more extensive data
compiled during operation of small FBC test units. In some cases, conclusions
have been supplemented by current theory concerning the FBC process. They are
subject to change when larger units come online and better data are available
In the ensuing discussion of emission control technologies, candidate
technologies are compared using three emission control levels labelled "moderate
intermediate, and stringent." These control levels were chosen only to encom-
pass all candidate technologies and form bases for comparison of technologies
for control of specific pollutants considering performance, costs, energy, and
nonair environmental effects.
From these comparisons, candidate "best" technologies for control of
individual pollutants are recommended for consideration in subsequent industrial
boiler studies. These "best technology" recommendations do not consider com-
binations of technologies to remove more than one pollutant and have not under-
gone the detailed environmental, cost, and energy impact assessments necessarv
Several performance tests are scheduled at Georgetown University in earlv
1980. y
138
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for regulatory action. Therefore, the levels of "moderate, intermediate, and
stringent" and the recommendation of "best technology" for individual pollutants
are not to be construed as indicative of the regulations that will be developed
for industrial boilers. EPA will perform rigorous examination of several com-
prehensive regulatory options before any decisions are made regarding the
standards for emissions from industrial boilers.
TABLE 17. OPTIONAL LEVELS OF CONTROL TO BE
SUPPORTED - ATMOSPHERIC FLUIDIZED-
BED COMBUSTION OF COAL
S02 NOX Particulate
Level of —•
control % ng/J ng/J
reduction (lb/106 Btu) (lb/106 Btu)
Stringent
90*
215
(0.5)
12.9
(0.03)
Intermediate 85* 258 43
(0.6) (0.1)
Moderate 75* 301 107.5
(0.7) (0.25)
*
In addition to the % reduction, an upper limit of
516 ng/J (1.2 lb/106 Btu) applies in all cases.
Furthermore, in no case are controls required to
reduce emissions below 86 ng/J (0.2 lb/106 Btu).
3.1-2 Selection of S02 Emission Levels
3.1.2.1 Moderate Level of Control: 75 percent removal, 516 ng/J
(1.2 lb/106 Btu) ceiling, 86 ng/J (0.2 lb/106 Btu) floor—
The moderate level of control can be supported by normal engineering
application and operation of fluidized-bed combustion boilers. This degree of
control has been consistently demonstrated by all investigators who have ex-
perimented with sorbent addition for S02 removal. Babcock and Wilcox Company
compiled and reviewed available data on the operation of atmospheric fluidized-
bed combustion (AFBC).1 Considering 368 data points, the average Ca/S molar
139
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feed ratio was 2.2 with an attendant SC>2 reduction of 76 percent, demonstrating
that the moderate level of control should be attainable on a routine basis.
3.1.2.2 Stringent Level of Control: 90 percent removal, 516 ng/J
(1.2 lb/106 Btu) ceiling, 86 ng/J (0.2 lb/106 Btu) floor—
This high level of S(>2 reduction has not been widely demonstrated in AFBC
experimentation to date, but theoretical projections by Westinghouse2 and some
experimental results indicate that 90 percent control is technically and econom-
ically achievable. The B&W 6 ft x 6 ft unit3 and the B&W, Ltd., Renfrew4 boiler
have demonstrated greater than 90 percent S02 reduction at Ca/S ratios of 4 or
less. Several other test units have achieved reductions as great as 90 percent
but only intermittently. These test data are shown in Section 7.0.
Westinghouse Research and Development has formulated an S02 removal model
for FBC.5 The model predicts S02 removal efficiencies based on sulfation rate
constants measured in laboratory thermogravimetric analysis apparatus, and
considers sorbent parameters and FBC operating conditions. The important
factors considered in the model are Ca/S molar feed ratio, gas phase residence
time and sorbent particle size. The FBC conditions suggested by the Westing-
house model for effective S02 control (i.e., our definition of the "best system")
are a gas phase residence time of 0.67 sec (superficial gas velocity of 1.8
m/sec and expanded bed depth of 1.2 m) and average inbed sorbent particle size
of 500 pm. Most current FBC designs incorporate shorter gas residence times
and larger particle size;* however, these conditions are well within the range
that has been considered in previous studies by others (notably NCB, FluiDyne
^
Refer to Table 20. Although differences in design/operating conditions exist
between current designs and those conditions recommended here for the "best
system" of S02 control, the differences are not great and could be adopted
with only minor modifications in current boiler designs.
140
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B&W) and are felt to be useable in many existing designs without major redesign
difficulty. At these conditions, 90 percent S(>2 control should be achieved at
Ca/S ratios between 2.5 and 4.0, based on the model, and some experimental
results. No higher control level was considered because extrapolation of the'
existing data base is too uncertain. It is important to emphasize that possible
capital cost increases associated with going to "best system" conditions should
be offset by reduced operating costs and possible capital savings in other areas
of the system (see Section 4.3.4).
One technical uncertainty which exists regarding SC>2 control is whether
overbed solids feeding allows for "best system" gas residence time. In appli-
cable experimentation by FluiDyne in their 1.5 ft x 1.5 ft unit,6 they found
equivalent high levels of 862 reduction (>90 percent) with underbed or overbed
feed as long as primary recycle of bed carryover was practiced. This is dis-
cussed further in Sections 3.2.1.2 and 7.5.6.
The Westinghouse model has been reasonably well confirmed at lower levels
of S02 control (85 percent and less) by comparison with experimental results
which are available in the literature, as shown in Section 7.0, Subsection 7.7.
Since experimental data at 90 percent 862 reduction are limited, the model can-
not yet be reliably confirmed at this degree of control. However, based on the
apparent validity of the model at lower desulfurization levels (85 percent and
less) and the actual data which do not exist, we conclude that 90 percent re-
duction will be achievable in industrial AFBC boilers at Ca/S ratios between
2.5 to 4.O.*
The Westinghouse model assumes uniform SC>2 generation throughout the depth
of the bed. In underbed feed systems, where S(>2 may be preferentially formed
near the bottom of the bed, the Westinghouse model may predict less efficient
SC>2 removal than actually achievable.
141
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Based on the results of the cost analysis presented in Section 4.0 90
percent S0£ control can be achieved with little additional economic impact com-
pared to 75 or 85 percent control. In fact, for high sulfur coal, the maximum
incremental cost of going from 75 to 90 percent desulfurization, is about $0.30/
106 Btu output. This is about 5 percent of total AFBC system cost. The cost
penalty is insignificant when low sulfur coals are considered. These results
are confirmed by independent estimates which Westinghouse has made for industrial
AFBC boilers (see Section 4.0, and Appendix D).7 The cost of S02 control is
more sensitive to sorbent reactivity than to the degree of control required
when levels greater than 75 percent reduction are considered.
Energy and environmental impacts are also only slightly increased if 90
percent S02 reduction is employed, compared to moderate control levels. The
energy analysis in Section 5.0 indicates that AFBC boiler efficiency is com-
parable to and potentially greater than conventional stoker technology, even
when the S02 controlled AFBC case is compared to the conventional boiler with
no S02 control. With use of "best system" design/operating conditions, energy
efficiency is not significantly impacted by adding sorbent to the bed. The
major energy impact of either FBC or conventional technology is flue gas heat
loss which overshadows the impact of S0£ control. Conventional pulverized coal
(PC) technology has generally higher boiler efficiency than AFBC due to better
combustion efficiency. However, if coal drying is necessary in the PC case
and not necessary for AFBC (assuming overbed feeding with primary recycle), then
AFBC boiler efficiency can be comparable to PC technology.
The only environmental impact which is increased by going to 90 percent
S02 control, is solid waste disposal. Particulate control capability should
not suffer; i.e., the optional levels considered in this study can still be
142
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met. NOX emissions are unaffected and may even be reduced using the "best
system" of S02 control because longer gas phase residence time allows for
further chemical reduction of NO. Solid waste quantities are greater at 90
percent control than at lower levels, but again, if sorbent reactivity is
reasonable, it should not be an overwhelming problem.
3.1.2.3 Intermediate Level of Control: 85 percent removal—
An intermediate S02 control level of 85 percent has been chosen because
it represents about the most stringent level of control which has been con-
sistently demonstrated by most investigators (those who have used sufficient
sorbent quantities and appropriate operating conditions). Moreover, modeling
studies project that, with suitable FBC design (appropriate gas residence times
and sorbent particle sizes), this degree of control can be achieved at moderate
sorbent feed rates (Ca/S = 2 to 3.5, with sorbents of reasonable reactivity).8
3.1.2.4 Upper and Lower Limits of Control Levels: 516 ng/J
(1.2 lb/106 Btu) upper, 86 ng/J (0.2 lb/106 Btu) lower—
These levels of emissions are being specified to allow flexibility in
burning a variety of fuels with a wide range of sulfur contents. The lower
limit of 86 ng/J (0.2 lb/106 Btu) is proposed to allow for burning of low sulfur
fuels without requiring excessive percentage reductions of S02. The upper limit
of 516 ng/J (1.2 lb/106 Btu) assures that the optional levels considered are not
more lenient than standards previously established for electric utility boilers.
Table 18 shows the various levels of control for several fuels with sulfur con-
tents ranging from 0.5 to 3.5 percent. The table indicates the limiting factor
for each level of control. Notice that for a fuel containing 1.0 percent sulfur
or less, the floor of 86 ng/J can be met by less than 90 percent reduction of
anc* that f°r fuels containing 3.5 percent sulfur or greater, S02 reduction
143
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must be greater than 75 percent, the proposed moderate level of control, to
insure that emissions do not exceed the ceiling of 516 ng/J (1.2 lb/106 Btu).
TABLE 18. S02 CONTROL LEVELS FOR FUELS OF VARYING SULFUR CONTENT
% Sulfur
0.5
1.5
3.5
0.5
1.5
3.5
0.5
1.5
3.5
Uncontrolled S02 _ , Required
* Control 2
emissions . . A S02
ng/J (lb/106 Btu) reduction
344 (0.8)
1,032 (2.4)
2,365 (5.5)
344 (0.8)
1,032 (2.4)
2,365 (5.5)
344 (0.8)
1,032 (2.4)
2,365 (5.5)
Stringent 75
90+
90+
Moderate 75+
75+
78
Intermediate 75
85+
85+
Controlled S02
emissions
ng/J (lb/106 Btu)
86 (0.20)+
103 (0.24)
236 (0.55)
86 (0.20)+
258 (0.60)
516 (1.20)f
86 (0.20)+
155 (0.36)
357 (0.83)
"Coal HHV = 28,000 kj/kg.
Limiting level of control.
3.1.3 Selection of NOx Emission Levels
The mechanisms by which NOx is formed in FBC, and by which NOX can be
controlled, are not understood as well as in the case of S02. NOX emissions
tend to be low in FBC because of the prevailing chemistry within the bed.
Past work has involved primarily just the monitoring of NOx emissions from
FBC units, with some effort to explore the impact on emission of some key
variables. Concentrated efforts to model and reduce emissions of NOx from
FBC are just beginning.
3.1.3.1 Moderate Level of Control: 301 ng/J (0.7 lb/106 Btu)—
All data from the larger FBC test units have been consistently below 301
ng/J (see Figure 27 in Subsection 3.2.2), except at temperatures which are
higher than envisioned for typical AFBC operation (>1000°C). Despite its
144
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small size, most data from the ANL 6 in. bench-scale unit are below this level.
Therefore, this level should be supported by FBC boilers under normal operating
conditions.
3.1.3.2 Stringent Level of Control: 215 ng/J (0.5 lb/106 Btu)—
The average NOX emission rate observed in past experimentation at typical
AFBC operating temperatures is in the range of 375 ppm NOx, which corresponds
to 215 ng/J NOx (see Figure 27). In addition, data from the large units which
have come on stream recently (Renfrew, and the EPRI/B&W 6 ft * 6 ft unit) are
consistently less than 215 ng/J (generally between 165 and 215 ng/J, or 0.4 to
0.5 lb/106 Btu). This level (215 ng/J) has thus been designated as achievable
for a stringent level of control; it is considered to be the lowest level that
a manufacturer can guarantee at this time. Although emissions of less than
215 ng/J (0.50 lb/106 Btu) have been observed fairly frequently, the role of
the factors which control NOX formation and decomposition in the bed (such as
fuel nitrogen, gas residence time, excess air, and temperature) is not suffi-
ciently well understood; the correlation between NOx emissions and the variables
which have been studied to date, does not appear to be significant based on
existing data.9"11 Therefore, control of these parameters cannot at this time
be relied upon to ensure NOx emissions below 215 ng/J and, in fact, further
data from the large FBC units would be desirable to ensure that 215 ng/J itself
would be reliably achievable on a 24-hour average.
Experimental studies are in progress at MIT specifically for characteri-
zation of NOx formation and control in FBC.12'13 The stringent level con-
sidered here has been consistently attained in their pilot-scale unit.
145
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Some conventional boiler controls may be applicable for maintenance of
reduced NOx emissions from FBC systems. The use of low excess air levels and
two-stage combustion may aid in reducing NOx emissions reliably. However, com-
bustion modifications for FBC have not yet been extensively studied. Such
modifications could impact materials corrosion, combustion efficiency and
emissions of other pollutants. Further research and development is required
on FBC combustion modifications, although such modifications are not considered
available control technology for the purpose of this document.
3.1.3.3 Intermediate Level of Control—
In the temperature range of interest (815° to 870°C) for primary FBC com-
bustion cells, virtually all of the available data from large AFBC units (500
Ib coal/hr and larger) are below 260 ng/J. Even most of the data from smaller
experimental units are below this level. Therefore, 260 ng/J has been selected
as the intermediate level of control.
3.1.4 Selection of Particulate Emission Levels
It is expected that a primary cyclone will be used as an integral part of
first generation atmospheric fluidized-bed combustion industrial boilers. The
purpose of the primary cyclone is to recycle elutriated sorbent to increase
sorbent/S02 contact time, recycle unburned carbon to the combustor, prevent
fire hazards in the downstream flue gas ducting, and decrease the particulate
loading to the final particulate control device. Primary cyclone efficiency
should be in the range of 80 to 90 percent, depending on FBC operating param-
eters and cyclone design.
Particulate emissions following the primary cyclone in coal-fired atmos-
pheric FBC systems and final particulate reduction necessary to meet stringent
intermediate, or moderate standards are shown in Table 19.
146
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TABLE 19. REQUIRED PARTICULATE CONTROL EFFICIENCIES FOLLOWING THE
PRIMARY CYCLONE IN COAL-FIRED ATMOSPHERIC FBC SYSTEMS
Fuel and
boiler capacity
Particulate
emission following
Particle size
average MMD
Level of emission control and
efficiency of final particulate control
device required to achieve that level
ng/J (lb/106 Btu)
MWt (106 Btu/hr)
Coal
8.8 - 58.6
(30 - 200)
primary eye tone
ng/J (lb/106 Btu) ym
215 - 2150
(0.5 - 5.0) 5-20
Stringent
12.9
(0.03)
94 - 99.4
Intermediate
43
(0.10)
80 - 98
Moderate
107.5
(0.25)
50 - 95
-------
The emission range of 215 to 2,150 ng/J (0.5 to 5.0 lb/106 Btu) is based
on particulate data shown in Sections 7.0 and 2.0. Pope, Evans, and Robbins 1!
Argonne,15 and NCB16 have measured emissions after the primary cyclone between
215 to 960 ng/J (0.5 to 2.0 lb/106 Btu). Babcock and Wilcox17'18 has measured
higher emissions from their 6 ft x 6 ft and 3 ft x 3 ft units, but in cases
where outlet loadings were greater than 2,150 ng/J (5.0 lb/106 Btu), primary
collection efficiencies were poor. The 3 ft x 3 ft unit is not representative
because a low efficiency cyclonic cavity was used for primary control. In
addition, freeboard height was low and a shallow bed was used. The B&W 6 ft x
6 ft unit indicated higher outlet loadings than 2,150 ng/J (5.0 lb/106 Btu)
mainly when primary cyclone efficiency fell below 75 percent. Therefore the
upper limit on uncontrolled particle emissions (i.e., the outlet from the pri-
mary cyclone) is reported here as 2,150 ng/J (5.0 lb/106 Btu). The mass mean
particle size in the primary cyclone outlet, based on available data, appears
to be in the range of 5 to 20 ym.
Although final particulate control has not been thoroughly demonstrated
in AFBC systems to date, it is expected that final particulate control in
industrial AFBC boilers will be as effective as and similar to, conventional
systems burning low sulfur coal. Conventional particle control technology,
suitably designed and operated for FBC applications, should provide the
necessary control.
3.1.4.1 Moderate Level of Control: 107.5 ng/J (0.25 lb/106 Btu)--
Due to the wide range in expected particulate loadings to the final con-
trol device, the control efficiency required to meet a moderate particulate
level of 107.5 ng/J (0.25 lb/106 Btu) ranges from 50 to 95 percent. The
moderate level was selected because this range is well within the capabilities
148
-------
of conventional particle control technology. With a mass median particle
diameter of 10 ym or greater, conventional multitube cyclones should be capable
of providing 50 to 80 percent removal efficiency. If either lower mass median
diameters exist (5 to 10 pm) or greater control efficiencies (80 to 95 percent)
are required, use of other control devices such as ESPs, or fabric filters, will
be necessary.*
3.1.4.2 Stringent Level of Control: 12.9 ng/J (0.03 lb/106 Btu)--
Stringent control requires final collection efficiencies ranging between
94 to 99.4 percent. Although this level of control has not been demonstrated
in AFBC systems, it was selected because it is anticipated that it can be
supported using fabric filters or possibly ESPs, based on performance demon-
strated in conventional boilers.19
3.1.4.3 Intermediate Level of Control: 43 ng/J (0.10 lb/106 Btu)—
This level has been established to demonstrate the various impacts asso-
ciated at midrange control level. At least in conventional boiler installations,
it has been demonstrated as a critical value above which significant costs and
energy penalties may occur.
Final particle removal efficiencies between 80 and 98 percent are required
to attain an intermediate particulate control level. This range of control
should be achievable using fabric filters or ESPs. Multitube cyclones may also
be applicable depending on actual particle sizes and efficiency requirements.
3,1.5 Impact of Averaging Time
The time period over which emissions are averaged may influence FBC oper-
ating requirements to meet optional control levels. In the case of S02, Ca/S
If a sliding scale based on boiler size is used for particulate control such
that smaller boilers have less stringent control demands, multiclones may be
the most cost-effective technique for smaller units.
149
-------
may vary with time due to changes in coal sulfur, sorbent reactivity, boiler
loading or other conditions. These effects have not been rigorously explored
in experimentation to date. More testing is required for longer time periods
to determine whether a safety factor in Ca/S requirements is necessary if
averaging times of 24 hours or longer are considered. Potential impacts on
NOx and particulate emission levels must also be characterized.
3.2 BEST CONTROL SYSTEM FOR COAL-FIRED BOILERS
The following discussion specifies the data on which the choices of best
control techniques were made. The discussion follows each of the specific
pollutants, namely S0£> N0x> and particulates. In many cases, supporting data
from other sections of the report are referenced and not reproduced here. Con-
trols for coal-fired boilers are emphasized in this report.
Since data from commercially-operating AFBC units are not available the
selection of "best systems" is necessarily made based upon laboratory and pilot
plant data, and upon projections prepared using these data and engineering
principles.
3.2.1 SO? Emissions
3.2.1.1 Factors Affecting S02 Control—
The primary factors influencing S02 control are the following:
• Calcium to sulfur molar feed ratio
• Type of limestone
• Particle size
• Gas phase residence time
The Ca/S molar feed ratio is usually varied to control the level of SO?
emissions from fluidized-bed combustion. In order to maximize the overall effi-
ciency and performance of an FBC system, at a specific level of S02 control the
Ca/S ratio must be minimized to reduce sorbent feed quantities and to minimize
150
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waste disposal problems. Among the calcium-based sorbents which have been used
in FBC systems, there are a wide range of reactivities. However, it is not
likely that a sorbent will be chosen solely on the basis of its reactivity, but
rather, will be selected primarily on the basis of the proximity of the quarry
to the FBC facility. Thus, the particle size and gas phase residence time
become the important factors in obtaining the best results. Reducing particle
size and increasing gas phase residence time can increase calcium utilization
and allow for significantly lower Ca/S ratios to support a specific level of
S02 reduction.20 In some instances, these modifications would require some
redesign of current FBC systems.
Particle size and residence time have historically been set by FBC de-
signers based on considerations other than S02 control. The effort has been
to make the boiler as small as possible to allow for shop fabrication of boilers
of larger capacity than traditionally possible by increasing velocity (decreas-
ing the residence time) and hence, also increasing the required sorbent parti-
cle size. Much of the experimental work to date has not been conducted at
residence times felt to approach the optimum for SC>2 control (0.67 sec or
greater). In addition, some designs (especially overbed coal feed designs and
inherently shallow-bed designs) may not readily lend themselves to adjustment
of gas residence time. However, our estimates indicate that, although increased
gas residence time will result in somewhat larger boilers and possibly higher
boiler cost, this higher cost will be more than offset by the reduced sorbent
requirements. Thus, reasonable increases in gas phase residence time and
correspondent decreases in particle size are presented in this report as the
best system of S02 control for AFBC.
151
-------
The optimal values for sorbent particle size and gas phase residence time
cannot be specifically defined based on currently available information; how-
ever, an estimate of close to optimal values can be made.21 It is not clear
whether technical or economic factors will limit the degree to which sorbent
particle size can be lowered or gas phase residence time can be increased.
Increased gas residence time and decreased sorbent particle size may increase
boiler costs at the same time they decrease sorbent requirements and cost. For
any specific site and sorbent, there may be an economically-determined optimum
combination of residence time and particle size which minimize cost of steam
from the boiler. On the other hand, if the economics continue to look attrac-
tive as the terminal particle velocity falls below the minimum fluidization
velocity, technical factors, rather than economic, could become the limiting
concern. Specifically, using very fine particle sizes of 100 pm or less could
alter fluidization needs, requiring high recycle or "fast" fluidization. A
design for such a fast bed currently exists22 but it is still under develop-
ment. Additionally, there may be a point of diminishing returns in S02 con-
trol with extremely small particle sizes or long gas residence times.
The Westinghouse calculations suggest that gas phase residence times in
the neighborhood of 0.67 sec, and sorbent particle sizes in the neighborhood
of 500 um should be suitable for effective S02 removal at reduced sorbent feed
rates. (The 0.67 sec residence time results using a 1.2 m deep bed and a 1.8
m/sec gas velocity.) These are the conditions which will be considered for the
"best system" of SOa control in this report. However, this particular combina-
tion of conditions will not necessarily be the economic optimum for all AFBC
systems; the true optimum will vary from one specific case to another, depending
upon the specific site and sorbent characteristics. (For example, in one case
a reduced gas residence time may be desirable in order to result in a boiler
152
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small enough for shop fabrication.) It is felt, however, that this combination
of conditions will be sufficiently representative of the optimum for all cases,
BO that it is used in this report to indicate the performance and cost of "best"
SOa control systems. The smaller particle size (500 ym) is suggested assuming
chat the primary cyclone catch will be recycled. If packaged FBC units (with
low freeboard) did not employ recycle, coarser (1,000 ym) sorbent might be needed
Co maintain the bed, thus increasing the Ca/S requirement. The residence time
and particle size chosen represent a breakpoint in the relationship of gas resi-
dence time and Ca/S requirements and particle size and Ca/S requirements,
according to Westinghouse data.23
3.2.1.2 Selected Design/Operating Conditions for the "Best System"
of S02 Control—
Based on the preceding discussion and other considerations mentioned below,
"best system" design/operating conditions for 862 control in FBC are represented
by the following values:
• Bed depth - 1.2 m (4 ft)
• Superficial gas velocity — 1.8 m/sec (6 ft/sec)
• Gas phase residence time* — 0.67 sec
• Sorbent particle size - 500 ym (32 mesh) inbed surface average'''
• Coal and sorbent feed — Inbed or abovebed
• Primary recycle - Yes, for either feed orientation
» Bed temperature — 843°C (1550°F)
• Excess air — 20 percent
*Estimated by dividing bed depth by superficial gas velocity.
^A 500 ym surface average is roughly equal to a mass average particle size be-
tween 600 to 700 ym, depending on the actual particle size distribution.
Theoretically, at 1.8 m/sec (6.0 ft/sec) fluidizing velocity, surface average
particle sizes between 350 to 1500 ym are suitable for operation, allowing for
fluldization without significant sorbent loss through entrainment (assuming
use of primary recycle). Actual particle distribution and combustor design
would affect this range to some extent.
153
-------
To date, the majority of experimental FBC units have operated with inbed
coal and limestone feed during testing. This allows for S(>2 formation near
the bottom of the bed and provides the maximum residence time for SO? to react
with CaO, within the designated design/operating conditions of the unit.
One set of experiments has been conducted by FluiDyne in their 1.5 ft x
1.5 ft unit to assess the effect of solids feed orientation on desulfurization
efficiency. The results of this testing are detailed in Section 7.0 of this
report. The data indicate that equivalent desulfurization levels can be ob-
tained with inbed or abovebed feed as long as primary recycle is practiced
At a Ca/S molar feed ratio of 3.0 (using limestone), 94 percent S02 reduction
efficiency was obtained regardless of feed orientation, using primary recycle
in both cases (see Figure 59). Although the supporting data are limited in
number, and the unit tested was small, it is concluded for the purpose of this
study that abovebed solids feed is applicable for "best system" 862 control
in FBC. If in actuality, higher Ca/S ratios are required with overbed feed
systems in comparison to the average values shown in the next subsection (see
Table 20), it is believed that the added operating cost of additional sorbent
purchase is within the accuracy band of total annual FBC system cost estimated
in this report. In the event that an FBC customer were to purchase an FBC sys-
tem using underbed feed to minimize sorbent requirements (if higher Ca/S ratios
were deemed necessary with overbed feed) the resultant economics should also
fall within the specified accuracy bands in Section 4.0.
A temperature of 843°C (1550°F) was selected because in experimentation
performed to date, peak S02 removal has been found in the temperature range
of 816° to 871°C (1500° to 1600°F). The excess air rate of 20 percent has been
commonly used in past experimentation. A higher rate might aid S02 reduction
but could increase NOX formation and decrease boiler efficiency.
154
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3.2.1.3 Ca/S Requirements for the "Best System" of S02 Control
Based on Experimental Test Data—
Table 20 shows the required Ca/S molar feed ratios found by investigators
using sorbent particle sizes and gas phase residence times close to those
suggested here for "best systems." These Ca/S ratios were interpolated from
curves fitting the actual data points (see Section 7.0). The ranges noted at
the bottom of Table 20 are used throughout this report as the required Ca/S
ratios when "best system" design/operating conditions are considered.
Judging from the data in Table 20, the Westinghouse model projections are
good estimates of performance which can be expected from AFBC units operating
at or near "best system" conditions (see Section 7.0 for further comparisons).
Figure 26 is a summary of experimental SC>2 reduction measurements made in
bench- and pilot-scale units operating at a wide range of condit* ns, including
some conditions different from the noted "best system" conditions. The range
of Ca/S ratios used to determine "best system" performance and cost at the op-
tional control levels (from Table 20) are shown by the straight lines between
56 and 90 percent S02 reduction. These limits represent high and low sorbent
reactivity. Limestone 1359 (Grove limestone) was used as the index of low
sorbent reactivity, and limestone 18, and U.K. limestone, were used as the
index of high reactivity. The figure illustrates that the majority of experi-
mental data, including data from experimentation conducted at other than "best
system" conditions, fall within the brackets of performance for the range of
reactivity considered here. Most of the data below the line of low sorbent
reactivity were obtained from two units, the B&W 3 ft * 3 ft unit and the
PER-FBM unit. The B&W 3 ft x 3 ft1*3 has a shallow bed and low freeboard which
reduce the time available for the gas/solid reaction of the S02 and CaO. thus
reducing the S02 capture efficiency. The PER-FBM data1*4 were generated using
155
-------
TABLE 20. REQUIRED Ca/S MOLAR FEED RATIOS FOR BEST S02 CONTROL
BASED ON EXPERIMENTAL DATA
Ln
Temperature Gas phase
,or\ residence
Source \ ^> .
(0F) time
sec
840 - 870
ANL (1550 - 1600) 0.67
SAO - 870
ANL (1550 - 1600) 0.67 - 0.70
870
ANL (1600) 0.67
870
ANL (1600) 0.5 - 0.7
850
NCB (1560) 0.58
800 - 850
NCB (1470 -1560) 0.5
750 - 850
NCB (1380 - 1560) 1.86
800 - 850
NCB (1470 - 1560) 0.5
Sorbent-
reactivity
H, M, L
Limestone
1359
L
Limestone
1359
L
Limestone
1359
calcined
H
Limestone
1359
L
Limestone
18
H
Dolomite
1337
H
Dolomite
1337
H
Limestone
18
H
Size
pro
AVE
25
177 x 0
AVE
25
AVE
490 - 630
AVE
210
AVE
100-125
AVE
100-125
AVE
210
Ca/S needed to maintain
control level Reference and
75% 78.7% 83. 2% 83.9% 85% 90%
2.4 2.7 3.1 3.2 3.4 4.2 ANL-CEN-ES-100121*
ANL-CEN-ES-100225
TESTS SA-1, SACC-5,
SACC-6, SACC-9, SA-2
2.5 2.7 2.9 3.0 3.1 3.6 ANL-CEN-ES- 100126
ANL-CEN-ES-100227
TESTS SA-3, SA-4,
BC-1, BC-6
2.0 2.0 2.1 2.1 2.2 2.3 ANL-CEN-ES-100128
SACC-1, SACC-4
2.1 2.5 2.7 2.8 3.0 3.5 Paper by Vogel at
Third International29
Conference on FBC
1.9 2.0 2.3 2.4 2.5 3.1 PB-210-67330
NCB September 1971
2.6 3.0 3.3 3.3 3.4 3.8 PB-210-67331
NCB September 1971
p. 23, Task I, Test 4
1.8 1.9 2.2 2.3 2.3 2.6 PB-210-67332
NCB September 1971
p. 23, Task I, Test 4
2.1 2.3 2.7 2.7 2.8 3.2 PB-210-67333
NCB September 1971
p. 20, Task I, Test
1.2, 1.3, 2, 5
(continued)
-------
TABLE 20 (continued).
Ui
Source
NCB
NCB
NCB
NCB
ANL
ANL
NCB
Temperature
<°C)
(°F)
800 - 850
(1470 - 1560)
800
(1470)
800
(1470)
800
(1470)
800
(1470)
800
(1470)
800
(1470)
800
(1470)
800
(1470)
Gas phase c ,
.j Sorbent -
residence . .
time «««vtty
sec
0.67 L ime s t one
18
H
0.67 U.K.
Limestone
H
0.67 Limestone
1359
1.00 Limestone
1359
0.67 Limestone
1359
0.67 Limestone
18
0.67 U.K.
Limestone
0.67 Limestone
1359
0.67 Limestone
1359
Ca/S needed to maintain
Size control level
75% 78.7% 83.2% 83.9% 85% 90%
AVE 1.8 1.9 2.2 2.3 2.3 2.6
210
AVE 1.6 1.8 2.0 2.0 2.1 2.4
300-400
AVE 2.8 3.0 3.4 3.5 3.5 3.8
210
AVE 2.3 2.4 2.7 2.7 2.8 3.3
210
125 x 0 2.0 2.3 2.7 2.7 2.8 3.5
AVE 1.8 1.9 2.1 2.2 2.2 2.6
210
NR 3.2 3.4 3.6 3.7 3.8 4.2
NR 2.7 3.0 3.2 3.3 3.4 3.8
NR 2.7 3.0 3.2 3.3 3.4 3.8
Reference and
test ID
PB-210-673 31*
NCB September
p. 20, Task I,
1.2, 1.3, 2, 5
PB-210-67335
NCB September
p. 57, Task V
PB-210-67336
p. 58, Test V
PB-210-67337
p. 58, Test V
PB-210-67338
p. 58, Test V
PB-210-67339
p. 88
PB-210-6731*0
p. 90
PB-210-673"1
p. 90
PB-210-6731*2
p. 90
1971
Test
1971
Range of Data
High
Low
Average
870
750
1.86 Low
0.5 High
25 1.6 1.8 2.0 2.0 2.1 2.3
650 3.2 3.4 3.6 3.7 3.8 4.2
2.2 2.5 2.7 2.8 2.9 3.3
-------
100
HIGH SORBENT
REACTIVITY
9O
80
70
60
50
^ _ _SIRJN_GENJ
INTERMEDIATE
MODERATE
u
K
«M
O
V)
LOW SORBENT
REACTIVITY
• SIP LIMIT
• •
\ •
A •
40
30
20
• A
• _T
KEY
B a W 3' x 3'
ANL-6"
PER-FBM
NCB-6"
NCB-CRE
B a W 6'iS'
B a W LTD.-RENFREW
FLUIDYNE
10
JL
_L
3 4
Co/S RATIO
Figure 26. Summary of SC>2 reduction data measured
in AFBC experimentation.
158
-------
gas phase residence times as low as 0.2 sec, which, as in the case of the B&W
3 ft x 3 ft unit, does not give sufficient time for an efficient S02/CaO reac-
tion. The graph also illustrates that all of the control levels under considera-
tion in this study have been demonstrated in past testing using Ca/S ratios which
are within a practical range. Further testing in larger units is required to
confirm Ca/S needs at high levels (-90 percent) of desulfurization.
3.2.1.4 Capability of Available FBC Systems Versus "Best Systems"—
Currently, there are several manufacturers offering FBC boilers on a
commercial basis (see Table 9), but only limited sales have been documented.
Other vendors will respond to a request for an FBC boiler but are not actively
marketing units yet.
The design/operating conditions of "commercially-offered" FBC units are
listed in Table 21 and are based on the larger experimental and demonstration
units currently operating or in design (all but the CE/Great Lakes unit are
currently in operation). All of the designs listed are representative of
operating conditions that would be specified in commercial units. However,
these conditions would vary on a site-specific basis.
The Westinghouse S02 removal model was used to project Ca/S ratios re-
quired for the "commercially-offered" boilers to meet the optional control
levels under consideration. The resulting values are shown in Table 22. The
sorbent requirements shown for the commercially-offered systems assume an
average inbed sorbent particle size of 1,000 ym (surface mean) although the
actual dimension may be different from this. This assumption was made for two
reasons: (1) no documentation of actual inbed average sorbent size is provided
by the vendors; and (2) most of the available sulfation rate data from Westing-
house are for particle sizes between 1,000 to 1,200 ym. The relationship
159
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TABLE 21. COMMERCIALLY-OFFERED AFBC-INDUSTRIAL BOILERS -
KEY FEATURES AFFECTING EMISSION CONTROL
Key Design/Operating
Conditions
Reference Boiler Size
Feeder type
Expanded bed depth, m (ft)
Gas velocity, m/sec (ft/sec)
Approx. gas residence time,
(sec)
Primary recycle
Sorbent type
Ca/S ratio and % removal?
Sorbent size, um (in. or mesh)
Bed temperature, °C(°F)
Excess air, %
Foster- Wheeler
Georgetown
Design
45,400
kg/hr steam
Overbed
1.37 (4.5)
2.44 (8)
0.56
Yes
Greer, Grove
3; 90
<4760 (4 mesh)
868 (1594)
20
Babcock
4 Wilcox, U.S.
Alliance,
Ohio 6'x6'
Design
Underbed
1.22 (4.0)
2.44 (8)
0.50
Yes
_
4; 90
<9510 (3/8")
843 (1550)
21
Combustion
Engineering
Great Lakes
Design
22,700
kg/hr steam
Underbed
0.91 (3.0)
2.13 (7)
0.43
Yes
_
3; 85
(VxD)
843 (1550)
20
Johnston
Boiler
Demonstration
Plant Design
Overbed
0.83 (2.7)
1.83 (6)
0.44
Yes
_
2; 75-95
100% <2380 um
(8 mesh)
85% >1190 um
(16 mesh)
843 (1550)
25
FlulDyne 0. Mustad
40"x64" B&W, Ltd. and Sons
Vertical Slice t Renfrew Design Enkoping
Combustor Design Design
Underbed
1.07-1.19
(3.5-3.9)
0.61-1.83
(2-6.0)
0.58-2.0
Yes
Dolomite
-
<6350 um
or
<2380 um
718-796 5
(1325-1465)
30-130
12 MW_
t
Underbed
0.8-0.91
(2.6-3)
2.44 (8)
0.35
Yes
_
3.0-5.5; 90
"
849 (1560)
20
25 MW
t
Overbed
Slumped
0.25 (0.8)
2.5 (8.2)
-
No
Sala
dolomite
1.5;75
500-3000
849 (1560)
/•*
10
Foster-Wheeler
Rivesville
Design
88 MW_
t
Underbed
1.2 (4)
3.6 (12)
0.33
Yes
Carbon
limestone
-
1/8" x 16 mesh
816-843
(1500-1550)
15-20
Although this unit is smaller than the others listed, the design/operating conditions are
to an air heating rate equivalent to 18,000 kg/hr steam.
j.
Sorbent type may vary significantly based on the geographic location of the installation.
xAs claimed by vendor.
Higher temperature may be used in commercial units.
**
representative of FluiDyne's commercially-offered design, up
Two-stage combustion.
-------
TABLE 22. PROJECTED Ca/S RATIOS REQUIRED FOR "COMMERCIALLY-OFFERED"
FBC BOILER SYSTEMS BASED ON THE WESTINGHOUSE MODEL
and S0:
control leve!
high sulfur
M r ingi-nt
lm<.r.vd late
'•'oil i rate
Eastern
low sulfur
Sirirvt-nl or
SUI, bituminous
Stringent or
Intt-nned late
Moderate
Best system ref
Creer limestone -
high reactivity
removal FW FU
Georgetown Rivesville
design design
90 5.29 5.63
85 4.25 5.00
78.7 3.42 4.37
83.9 4.00 4.93
75 3.13 3.75
83.2 3.70 4.62
75 3.13 i.75
ers to design/operating conditions
Grove limestone -
low react ivity hi
B,M* r ™ Be,,*
system r''°W°>"> syste.
y design 5)""e»
2.85 >10 4.20
2.51 >10 3'.60
2.30 >10 3.08
2.49 >10 3.50
2.20 >IO 2.92
2.47 >10 3.41
2.20 >10 2.92
recommended in this report as
doTo^it"- Western 90Z Cal limestone - Bussen Quarry liiaestone -
h° °10 >10 >10 5.26
2.94 8.56 9.60 9.88 6.68
2.47 7.18 7.85 8.02 4.07
2.84 8.26 9.21 9.48 4.56
2.33 6.57 7.11 7.26 3.87
2.80 8.08 8.98 9.24 4.51
2.33 6.57 7.11 7.26 3.87
-------
between the feed sorbent size, and the actual sorbent particle size in the bed
is not rigorously known; it is possible that, although the feed sorbent size
typically quoted by vendors is 1,000 to 1,500 ym mass mean, the actual size in
the bed may not be that much larger than the 500 ym surface mean selected for
the "best system" conditions.
In addition to Greer and Grove limestones (for the Foster-Wheeler boilers)
and Tymochtee dolomite (for the FluiDyne boiler), Western 90 percent CaL (high
reactivity), Bussen limestone (medium reactivity), and Menlo limestone (low
reactivity) were used to estimate Ca/S requirements for systems specified by
B&W (U.S.), Combustion Engineering, Johnston Boiler, B&W, Ltd. (England), and
for "best system" conditions. Stones such as Grove and Menlo are included only
to shown that sorbents with extremely low reactivity characteristics should not
be considered due to the large quantity needed to achieve a reasonable level of
S02 control. Western 90 percent CaL, Bussen Quarry and Menlo Quarry limestones
are the sorbents used by Westinghouse in their independent assessment of indus-
trial FBC boiler cost indicating a high, medium, and low reactivity limestone.**5
Inspection of Table 22 reveals the savings in limestone use which can be attained
if "commercially-offered" design/operating conditions are modified to correspond
with those recommended for "best systems." The sorbent quantities for "best
system" conditions are calculated from the Westinghouse model. Each "commer-
cially-offered" design is discussed individually in the following subsections
relative to the modifications which would be necessary to operate at recommended
"best system" conditions. In some cases, the substitution of recommended design/
operating conditions would require redesign of the boiler to maintain capacity
and/or to prevent increased particle elutriation. It is understood that the
recommended conditions are different than those considered by many manufacturers
162
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because the goal of FBC development has been to maximize system throughput.
However, it is believed that modification to "best system" design/operating
conditions in the future will prove cost effective. The cost impacts are
discussed in Subsection 4.3.4.
3.2.1.4.1 Foster-Wheeler (Georgetown Design)—tf6The differences between this
design and the envisioned "best system" conditions considered in this report
are in the bed depth of 1.36 m (4.5 ft), gas velocity of 2.44 m/sec (8 ft/sec),
resultant gas residence time (0.56 sec), and limestone particle size (average
£1,000 pm). As discussed earlier and in Section 7.0, overbed feed with primary
recycle is capable of efficient S02 control and, therefore, cannot be ruled out
as the best method of SC>2 control. The most significant difference is probably
the average inbed particle size of 1,000 um (or greater) as opposed to the
recommended best condition of 500 um. If particle size were reduced and gas
phase residence time were increased slightly from 0.56 to 0.67 sec (by in-
creasing bed depth to 1.65 m (5.4 ft) or decreasing superficial velocity to
2.06 m/sec (6.75 ft/sec)), a significant reduction in sorbent requirements
could be achieved based on projections employing the Westinghouse model; as
shown in column 3 of Table 22 where Ca/S ratios are cut in half by going to
best system conditions using Greer limestone. Increasing bed depth would re-
quire a concomitant increase in freeboard and slightly greater capital cost,
the magnitude of which would depend on boiler capacity. Reducing the super-
ficial velocity would cause boiler derating unless the combustor cross section
were enlarged, so either alternative could add to system capital cost. In
this particular system, the greatest benefit could be achieved by reducing
163
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sorbent particle size. This could be done by purchasing the same or another
limestone with a different particle size distribution, or the material could
be crushed and/or sized onsite.
The projections of sorbent requirements for the Georgetown design using
Grove limestone are high enough to eliminate use of such a low reactivity sor-
bent in this system. If it were to be used, particle size reduction would be
recommended, in addition to increasing gas phase residence time. It is impor-
tant to note that these high projections are completely independent of the
abovebed feed used in the Georgetown boiler; the Ca/S ratios depend on sorbent
type, particle size, and gas residence time (calculated from the expanded bed
depth and superficial velocity). The overwhelming factor is the low sorbent
reactivity.
3.2.1.4.2 Foster-Wheeler (Rivesville Design)—'t7This unit utilizes inbed feed
with primary recycle to a carbon burnup cell. Superficial velocity ranges be-
tween 2.1 to 3.7 m/sec (7 to 12 ft/sec) with an expanded bed depth of 1.2 m
(4 ft), resulting in a gas phase residence time between 0.3 to 0.57 sec.
(Testing indicates that gas velocities as low as 1.1 m/sec (3.5 ft/sec) are
adequate.) The Ca/S ratios shown in Table 22 are similar to but slightly
higher than those noted for the Foster-Wheeler Georgetown design, which can
be attributed to the lower gas phase residence time. Reduction of superficial
gas velocity would enhance SOz removal at the expense of added boiler capital
cost. Particle size reduction would also be of benefit since the sorbent in
use is double-screened with a minimum size of 1,000 ym (16 mesh). Average
inbed particle size may be in the range of 1,200 to 1,500 ym.
164
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3.2.1.4.3 FluiDyne 40 in. * 64 in. Test Unit—48The FluiDyne unit uses inbed
coal and sorbent feed with a fairly deep bed of 1.1 m (3,6 ft) and rather low
superficial velocity of 0.6 to 1.8 m/sec (2 to 6.0 ft/sec) accounting for gas
phase residence times greater than 0.6 sec. FluiDyne is anticipating using
dolomite as a sorbent. Table 22 shows projections of sorbent needs based on
Westinghouse TGA data for Tymochtee dolomite (a highly reactive sorbent), and
Bussen limestone (a medium reactivity sorbent). Dolomite Ca/S molar feed ratios
are characteristically lower than limestone requirements for similar operating
conditions due to dolomite's higher reactivity (generally attributed to its
different pore structure resulting from its magnesium content). As a result,
the Ca/S ratios noted for Tymochtee dolomite are low, even lower than those
listed for "best system" conditions using Western limestone at an average inbed
particle size of 500 urn. However, the calcium carbonate content of Tymochtee
dolomite is 60 percent or less so that total sorbent loadings would be equiva-
lent to the case of Western limestone. Although a high reactivity dolomite may
be available on a site-specific basis, the general discussion in this report
emphasizes limestone use since most testing has been performed with limestone
and it has wider availability. Although this tract has been taken, Tymochtee
dolomite would certainly qualify as an appropriate sorbent, because of its high
reactivity.
Projections of sorbent requirements were made for Bussen limestone at
1,000 urn. The resulting values are 25 to 50 percent higher than those noted
for "best system" conditions using Bussen limestone. To reduce sorbent needs
using limestone, particle size reduction would be effective, since other condi-
tions are in conformance with best system conditions.
165
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3.2.1.4.4 Babcock and Wilcox (U.S.)—49This design uses inbed solids feed with
recycle and a gas phase residence time of 0.5 sec. The limestone top size is
9,150 ym (3/8 in.) so that average inbed particle size is probably in the range
of 1,500 ym. Table 22 shows the performance which could be expected with this
unit at the conditions noted, using Western, Bussen, and Menlo limestones.
"Best system" performance is also listed. Sorbent requirements for the vendor
specified conditions are roughly 30 to 100 percent greater than required for
the "best system" conditions, regardless of limestone type or control level
The most important parameter in this case is the inbed sorbent particle size
which is larger than the recommended value of 500 ym.
3.2.1.4.5 Combustion Engineering50 or Johnston Boiler51—These two units are
discussed together because the specified gas phase residence times and opera-
ting temperatures are the same. Sorbent use projections for each unit are
based on an inbed particle size average of 1,000 pm.* Thus, sorbent needs are
the same. Both units use primary recycle although the CE unit is underbed
feed and the Johnston unit is abovebed feed. (See previous discussion and
FluiDyne results in Section 7.0.) To modify these two systems to best condi-
tions, gas phase residence time would have to be increased from 0.43 sec and
inbed sorbent particle size would have to be reduced. Increasing gas residence
time could require some boiler redesign in both instances.
The actual inbed mass mean particle diameter for the CE/Great Lakes unit may
be about 800 ym. This is not much different from the recommended best system
condition since a surface average of 500 ym is roughly equal to a mass mean
of between 600 to 700 ym.
166
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3.2.1.4.6 B&W, Ltd.—52The design conditions for this unit reflect the shortest
gas residence time cited by any vendor. Gas velocity is fairly high at 2.4 m/
sec (8 ft/sec) with a relatively shallow bed of 0.8 to 0.9 m (2.6 to 3 ft),
accounting for a gas residence time of 0.35 sec. As a result, the Ca/S ratios
shown for the medium (Bussen) and low (Menlo) reactivity limestones are unaccept-
able, only the Western limestone indicates performance characteristics in a
reasonable range (although 90 percent S02 reduction is projected to require a
Ca/S ratio of 5.7 using the high reactivity sorbent). The modifications cited
earlier for the other vendor systems would be required to attain "best system"
operating conditions for S02 control.
3.2.1.4.7 0. Mustad and Sons—5^Although this system appears to be run under
conditions which are quite different from "best system" conditions, Mustad still
predicts good 862 reduction at a low Ca/S ratio (75 percent at 1.5). The sys-
tem has overbed feed, no recycle and an apparently low gas residence time, as
well as a relatively high sorbent particle size. According to Mustad's projec-
tions, a system with these design/operating variables can meet our "best system"
projections, however, further study and demonstration is required to fully assess
the impact of these operating variables. Virtually no comparable data are
available which have been generated under these conditions.
3.2.1.5 Other Impacts—
3.2.1.5.1 Applicability/Reliability—Industrial-sized FBC boilers are as yet
unproven in extended commercial operation because fluidized-bed combustion is
an emerging technology. The commercial-scale coal-fired AFBC units which are
in operation (e.g., Renfrew, Johnston Boiler Company) are not being operated
in typical commercial "around-the-clock" service. The AFBC units that will be
used in typical service (e.g., Mustad/Enkbping, B&W, Ltd. unit at the Central
167
-------
Ohio Psychiatric Hospital, the Foster-Wheeler unit at Georgetown University,
the crude oil heater at EXXON, the Combustion Engineering/Great Lakes unit) are
not yet in operation. Such extended operation in typical service is required
in order to prove AFBC reliability and to demonstrate industrial AFBC cost
energy and environmental impact. Therefore, at the present time the impacts of
AFBC in comparison to conventional boilers may be somewhat underestimated or
overestimated. As further information becomes available more definitive con-
clusions can be drawn about AFBC and its impacts.
3.2.1.5.2 Cost—The analysis of "best system" costs indicates that AFBC with
S02 control is generally more costly than an uncontrolled conventional boiler
of equal capacity by as much as 20 to 30 percent. This increment varies con-
siderably depending on boiler capacity, coal type, S02 control level, and sor-
bent reactivity. In certain instances, controlled AFBC may be used at equal
or less cost than uncontrolled conventional systems. This was found to be
the case for the 8.8 MWt unit burning low sulfur coal at any S02 control level
or high sulfur coal at an SIP S02 control level. It was also found for the
58.6 MWt AFBC burning subbituminous coal, and is due to the equal or higher
cost of pulverized coal technology at this capacity.
Another conclusion is that use of "best system" conditions can reduce the
cost of FBC compared to "commercially-offered" design/operating conditions.
This is due mainly to reduced operating costs due to lower limestone purchase
and preparation cost and spent solids disposal costs. Adaptation of these
conditions may require minor boiler redesign in some instances.
The cost trade-offs associated with decreasing total sorbent requirements
by increasing gas phase residence time, decreasing sorbent particle size, or by
other methods must be considered to determine the most cost-effective boiler
168
-------
system. For example, gas residence time can be increased by using deeper beds
or lower superficial gas velocities. If deeper beds are employed, larger
capacity fans and more power will be required to fluidize the bed as a result
of increased pressure loss through the bed. Lowering superficial gas velocity
(while maintaining constant excess air) would require beds of greater cross
sectional area to maintain boiler capacity. Much more data is required to
conduct a sophisticated optimization study.
Although sorbent reactivity and utilization will increase as sorbent
particle size is reduced, sorbent elutriation may become severe at very fine
sizes (below 500 ym) unless gas velocity is reduced correspondingly. At some
point, sorbent requirements could increase unless sorbent effectiveness could
be maintained by increasing primary collection efficiency and recycling large
quantities of fines.
The cost of sorbent crushing and sizing must also be considered. Onsite
crushing and sizing could add 15 to 40 percent to the raw limestone cost due
to rejection of off-size material. However, if for example, the required Ca/S
ratios are reduced from 6.0 to 3.5, a potential overall cost savings of about
$0.90/106 Btu could result (see cost sensitivity analysis in Section 4.0).
Sorbent reactivity will have a major effect on the operating cost on a
site-specific basis. If a highly reactive sorbent is available in close prox-
imity to the AFBC facility this could mean substantial cost benefit. However,
if (as will likely be the case) the boiler site is not in close proximity
with a highly reactivity sorbent, trade-offs must be made between the high Ca/S
ratio necessary using a nearby limestone of low reactivity, or a higher reac-
tivity limestone with a greater transportation cost. Currently, there is no
surcharge for purchasing high reactivity limestones other than the incremental
169
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cost of shipment if the only available supply is remote. For an individual
industry, it may be more cost-effective to use sorbent of low or average reac-
tivity rather than pay freight costs for hauling limestone of higher reactivity
from long distances.
The cost analysis in this report also indicates that the level of SO?
control (in the range of 75 to 90 percent) does not have a large impact on FBC
system cost when Eastern high sulfur coal is burned. The effect of S02 control
level is insignificant when low sulfur coals are burned.
3.2.1.5.3 Energy Impact—The level of SC>2 control in AFBC has a minor effect
on the energy impact of the total system. This is illustrated in Table 23
which shows the differential changes in boiler efficiency as FBC design/operating
parameters are varied through the full range considered in this report.
TABLE 23. DIFFERENTIAL CHANGES IN BOILER EFFICIENCY VERSUS
RANGE OF FBC DESIGN/OPERATING PARAMETERS
„„ , • , • . Differential change
FBC design/operating parameter and range . ... ... . &c
^ in boiler efficiency
Sorbent reactivity — low to high* 1.83
Coal sulfur content - 0.6 to 3.5^ 2.17
Boiler capacity - 8.8 to 58.6 MWtf 1.47
S0£ control level — moderate to stringent^ 0.58
Stringent control, Eastern high sulfur coal.
Stringent control, average sorbent reactivity.
'Eastern high sulfur coal, average sorbent reactivity.
With Eastern high sulfur coal, boiler efficiency decreases by about 0.6
percent when control level is increased from moderate to stringent. This is
the minimum differential change of the parameters considered. The coal sulfur
content proved to have the most significant effect on boiler efficiency.
170
-------
If "best system" design/operating conditions (see Subsection 3.2.1.2) for
S02 control were implemented, this could have a favorable impact on combustion
efficiency, by allowing longer residence time for carbon combustion and by
recirculating char for combustion.
It is important to note AFBC energy impact relative to that of uncontrolled
conventional boilers. The comparison of AFBC and uncontrolled conventional
boilers showed that for any of the three smaller boilers (8.8, 22, and 44 MWt),
AFBC boiler efficiency was 1 to 3 percent higher than conventional boiler effi-
ciency considering all optional control levels and coal types. For the larger
boiler (58.6 MWt), AFBC boiler efficiency was 1 to 3 percent lower than the
conventional pulverized coal unit.
3.2.1.5.4 Environmental—In fluidized-bed combustion, the most prominent
environmental impact is solid waste disposal. The "best system" design for FBC
is based on minimizing the Ca/S ratio, and thus the amount of sorbent and solid
waste which is necessary to achieve a given level of S02 reduction. Therefore,
as "commercially-offered" design/operating conditions approach "best system"
conditions, the environmental impact will be reduced. The amount of solid
waste which is produced by a system of specific capacity is directly related
to the Ca/S ratio used to achieve the necessary level of S02 control. The range
of solid waste produced by systems discussed in this report is 123 kg/hr (270
Ib/hr) to 3,873 kg/hr (8,533 Ib/hr), representing the 8.8 MWt boiler using low
sulfur coal achieving a moderate control level and the 58.6 MWt boiler using
high sulfur coal achieving stringent control, respectively.
The data presented previously in Table 22 illustrate that sorbent require-
ments can vary significantly depending on system design/operating conditions
and sorbent reactivity. Considering a sorbent of reasonable reactivity, Ca/S
171
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requirements can be reduced significantly if "best system" design/operating
conditions are substituted for "commercially-offered" conditions. For instance
if Greer limestone is considered, the Ca/S ratio can be reduced to 3 or slightly
less using "best system" design/operating conditions as opposed to values between
4 and 5 for "commercially-offered" conditions and stringent or intermediate S02
reduction (based on projections from the Westinghouse model). If the Ca/S ratio
is reduced from 5 to 3, spent solids waste quantities will fall by approximately
30 percent.
The environmental concerns associated with the disposal of the waste are
due to the leachate which is generated and the heat release properties of the
waste upon initial contact with water. The pH of the leachate is high, and
the total dissolved solids content is above drinking water standards. Calcium
and sulfate are also present in the leachate at concentrations above drinking
water standards. 5tt
These facts do not present an insurmountable problem, but do suggest that
appropriate care must be taken in disposing of the residue. It is not expected
at this time that trace elements will typically be present in the leachate at
levels greater than 10 times the drinking water standards, the level at which
the residue would be considered "hazardous" (toxic) under the Resource Conser-
vation and Recovery Act (RCRA). This conclusion, however, must be confirmed
with further testing.
Air emissions are also affected by applying "best system" conditions.
The SC-2 control system in FBC affects NOx emission reduction and add-on parti-
culate control devices. Some evidence indicates that NOx emissions are lower
over a partially sulfated bed than over an inert bed. 5>56 To this extent
the S02 removal system may enhance NOX reduction. Generally, particulate
172
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control is compatible with the S02 removal system. However, finer particles
of high resistivity (sorbent derived) will be elutriated as sorbent particle
size is reduced to minimize sorbent feed requirements. It is not anticipated
chat this will impact the ability of final control devices in meeting the
optional particulate control levels considered in this report.
3.2.2 NOx Emissions
Based on existing experimental FBC NOx emission data, the "best system"
of NOx control requires no special modifications from "best system" design/
operating conditions for S02 control. An AFBC designed for effective S02
control should be capable of simultaneously achieving the optional levels of
NOx control.
3.2.2.1 Moderate Reduction Controls—
The moderate level of control for NOX emissions to be supported using
fluidized-bed combustion is 301 ng/J (0.7 lb/106 Btu). This level has typically
been met in most runs in virtually all experimental FBC units (including units
as small as 0.15 m (6 in.) diameter) under normal operating conditions burning
coal (bed temperatures less than 1000°C, excess air levels from 10 to 100 per-
cent, stable operation, and gas residence times of 0.2 sec or longer). In
larger AFBC units (3 MWt and larger), NOX emissions have rarely exceeded 301
ng/J (°-7 lb/106 Btu), except at high temperatures (above 1100°C) which are
representative of carbon burnup cell temperatures but not of typical industrial
FBC operation.
Figure 27 illustrates the predominance of NOx emission measurements that
fall below 301 ng/J (0.7 lb/106 Btu). Some ANL measurements are above this
level at operating temperatures less than 900°C (1650°F) but the results are
not representative because the AFBC unit was small (6 in. in diameter) and an
173
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BED TEMPERATURE, °F
9
s
fc
A
e
§
b.
Z
X
o
l«
300
(1.16)
400
(0.93)
v r\r\
3UU
(070)
200
10.47)
100
(O.23)
n
°7
K) I4TO (650 1630 2010 2190
T i i i i r • i ' i i i
V
V 4V
V *
V v * *
V* V &•* 301 (0.7)
•*£ *** *^^* ^ «««>«>, HTERMEO(ATE
ffyf ^%* ^^^ ^^^ "T^^y 215 \O«5 1
*V ^1^^ ^* ^ " Baw 3'X3' UNIT
^ %^S»^* •«%• • Baw LTD RENFREW
~P ^ Saw 6* X 6' UNIT
• a* V A W ANL 6" UNIT
y RANGE OF OPERATING TEMPER-
m • L / j ATURES ENVISIONED FOR TYPICAL -W- NC8-CRE
h ^ AFBC OPERATION. ^ PER_FBM
i i 1 i J i i i i i i i
DO 80O 9OO lOOO 1100 1200
BED TEMPERATURE,°C
*THE« POIHTS AJtE ESTIMATED FROM DATA REPORTED IN pp» , THUS THE ACCURACY Of THESE POINTS
IS ASSUMED TO BE ± 30%
Figure 27. Summary of NOx data from experimental AFBC units.
-------
inert bed was used.57 Several other measurements from Pope, Evans, and Robbins
are above the moderate level but operating temperatures were greater than 1100°C
(2010°F), a value characteristic of CBC operation.
Table 24 summarizes the range of NOX emission values reported by several
investigators, along with key operating conditions in existence during the
testing. It is noted that gas residence times were generally below 0.67 sec,
which should be appropriate for effective S02 and NOX control. Excess air rates
are generally around 20 percent which is considered the nominal rate for current
and future AFBC designs. The range in operating conditions noted (temperature,
gas residence time, and excess air) encompasses the design/operating conditions
previously tabulated for "commercially-offered" systems in Table 21 (see Sub-
section 3.2.1.4). In general, commercially-offered designs are planned to
operate at bed temperatures between 800° to 900°C (1472° to 1652°F), will use
gas residence times between 0.4 to 0.5 sec, and will operate with excess air
rates between 15 to 25 percent. Possible exceptions are units being developed
by FluiDyne and 0. Mustad and Sons. FluiDyne may use gas residence times up
to 2.0 sec, and bed temperatures as low as 700°C (1292°F) although these may
just be experimental extremes. Mustad is building systems with staged combus-
tion. Either system should be capable of effective NOx control, possibly
better than the other systems noted.
Comparing the experimental conditions with the "commercially-offered"
conditions, it is apparent that commercially-offered systems should be capable
of controlling NOX to levels within those shown experimentally. If gas resi-
dence times are increased to correspond with that noted for "best systems"
(0.67 sec), then improved NOX control should be possible. Regardless, the
moderate NOx level should be achievable without design or operating modifications
175
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TABLE 24. SUMMARY OF EXPERIMENTAL NOX DATA FROM ATMOSPHERIC FBC TEST UNITS*
Investigator
B&W, Ltd.
Renfrew, Scotland
B&W
Alliance, Ohio
B&W
Alliance, Ohio
Pope, Evans, and
Robblns
National Coal Board
Unit size
10 x 10 ft
-12 MWt
(40 x 106 Btu/hr)
6 x 6 ft
-7 MWt
(24 x 106 Btu/hr)
3 x 3 ft
-1.9 MWt
(6.5 x 10s Btu/hr)
1.5 x 6 ft
3.2 MWt
(11 x 106 Btu/hr)
3 x 1.5 ft
-1.3 MWt
(4.5 x 106 Btu/hr)
Temperature
°C
(°F)
690 - 900
(1274 - 1652)
835 - 899
(1535 - 1650)
770 - 894
(1418 - 1642)
804 - 1021
(1480 - 1870)
1021-1176
(1870-2147)
749 - 849
(1380 - 1560)
Range of operating conditions Range of NOX
Gas phase _ observed
Excess air Z residence . . ng/J
time (see) nltr°8en * (lb/10* Btu)
-0.3 - 0.7 1.1 70 - 198
(0.17 - 0.46)
9.9 - 44.4 0.30 - 0.57 1.03 - 1.34 77 - 185
(0.18 - 0.43)
nominal excess 0.13 - 0.21 0.76 - 1.23 47 - 262
02 - 31 (0.11 - 0.61)
5-25 0.13 - 0.29 87 - 228
(0.20 - 0.53)
0.13-0.29 190-405
(0.44-0.94)
i29 0.26 - 1.76 1.3 - 1.5 120 - 323
(0.28 - 0.75)
Comments
This Is one of the largest FBC units for
which NOx data exists. The reported data
(approximately 11 tests for NOX) are all
below the stringent control level of
215 ng/J (0.5 lb/106 Btu).
This range of NOx emissions was reported
for 56 Individual tests (see Table in
Section 7), each of 100 to 1,000 hours
duration. Most testing was performed with
excess air rates between 16 to 20 percent.
The maximum of 262 ng/J was noted once out
of 30 tests. The next highest reading was
236 ng/J (0.55 lb/106 Btu) so that 29 of
30 tests met the intermediate level of NOX
control. 20 of 30 tests met the optional
stringent level, even though gas residence
times were generally below 0.2 seconds.
64 of 65 reported NOX test results fell
below the optional stringent control level
although gas residence time was low, gener-
ally about 0.20 seconds.
The experimental temperature range is
significantly above that envisioned
for typical AFBC operation. Neverthe-
less, 75 percent of the recorded data
are below 301 ng/J (0.7 lb/106 Btu).
The maximum level was noted to drop to
191 ng/J (0.44 lb/106 Btu) during the same
individual test run. The average emission
Argonne National
Laboratory
6 in. diameter
bench scale
-0.3 MWt
718 - 900
(1325 - 1650)
6-25
based on 17 reported values calculates to
215 ng/J (0.5 lb/106 3tu). 9 of 17 re-
corded NOX values were below the optional
stringent control level. The maximum gas
residence time of 1.76 sec is atypical;
most were in the range of 0.5 seconds.
0.22 - 1.0 1.11 - 1.31 70 - 435 Although this unit is a small bench scale
(0.16 - 1.01) test unit, over 2/3 of reported NOX data
(115 Individual tests) were below the op-
tional moderate level of NOX control.
*Based on NOX emission data shown in Section 7.
-------
NOx control at this level should be routine and should not contribute any
•j£tional cost, energy, or environmental impact above that associated with
jaorio*1 AFBC boiler operation.
- 2-2.2 Stringent Reduction Controls—
"Best systems" should require no special design or operation beyond that
- t "best system" SC>2 control. However, this needs to be confirmed in future
ion and actual commercial operation.
The stringent level of control targeted for FBC is 215 ng/J (0.5 lb/106
• A review of existing emissions data indicates some individual small
-loe-scale experimental systems have been able to meet these requirements with-
O0t a^y deliberate efforts to control NOX (see Figure 27 and Table 24). For
. gtance, PER has reported NOX emissions ranging between 86 to 172 ng/J (0.2
0 0.4 lb/106 Btu) during operation of their FBC and FBM test units.58 The
.esigti of these units is similar to that expected in first generation industrial
fBC boilers although gas residence times were shorter than used in current
.cgigns.* Testing of the B&W 3 ft * 3 ft unit has consistently demonstrated
HO* emissions less than or equal to 236 ng/J (0.55 lb/106 Btu) and a minimum
£Beion of 47 ng/J (0.11 lb/106 Btu).59 This minimal value was measured at a
&B residence time of 0.62 sec, the longest reported during this test series.
_ general, the stringent level of NOx control has been met in over half of the
os on smaller facilities.
*As shown in Figure 27, PER has conducted extensive experimentation in the FBM
utlit at temperatures higher than envisioned for typical AFBC operation, and
as a result, NOx emissions higher than the optional stringent level of 215
(0.5 lb/106 Btu) have been recorded.
177
-------
The stringent level has been met consistently on the larger AFBC units
which have been operated to date (Renfrew, B&W 6 ft * 6 ft unit).* The effect
of AFBC boiler capacity on NOX emission rate is illustrated in Figure 28. The
full range of NOx test results is included in the vertical bar shown for each
test unit. Not only do emissions decrease as the size of the facility increases
but also, the two larger units had no reported NOx values above the stringent
level of 215 ng/J (0.5 lb/106 Btu). These two units operate at typical condi-
tions seen for commercial systems (see Table 20), and indicate that the strin-
gent level should be achieved without system modifications, or added cost,
energy, or environmental impact.
Increasing gas residence times to 0.67 sec (from the average value of
about 0.5 sec noted for these two larger units) could result in even lower
NOx emissions.
There are probably technical and economic upper limits to extending gas
residence time since deeper beds would be required. In addition, incremental
reductions in NOx emission rate might diminish as residence time increases.
Excess air rates between 10 and 20 percent, as normally cited for FBC operation
are probably the minimal or best levels for NOx control. Operating at lower
excess air levels might reduce combustion efficiency.
Some experimentation has been performed to assess the benefit of applying
NOX combustion modification techniques to FBC. Research at ANL showed NO
emissions between 43 to 129 ng/J (0.1 to 0.3 lb/106 Btu) when combustion air
was fed in stages to FBC.60 Although early results support the capability of
two-stage combustion in lowering NOX emissions, combustion modification should
Preliminary results from Rivesville (30 MWe unit by Foster-Wheeler and PER)
indicate NOx emissions as low as 86 ng/J (0.2 lb/106 Btu).
178
-------
5OO -
400
300
CO
to
III
x
o
200
100
Minimum Capacity Coal fired
Industrial FBC Boiler under
Consideration
-i 1.1
B8W.LTD
RENFREW
6 8 IO
BOILER CAPACITY, MWt
12
14
Figure 28. NOx emissions from experimental FBC units as a function of capacity.
-------
not be necessary to meet 215 ng/J (0.5 lb/106 Btu). Also, it is not considered
an available control technology for FBC at this time. The level of S02 reduc-
tion in FBC may establish a minimum limit to the primary air rate in two-stage
combustion to prevent excessive CaS and H2S formation in the bed and subsequent
S02 formation in the freeboard. The SC>2 formed above the bed would be ineffec-
tively removed because of the absence of high concentrations of sorbent and
the minimal sorbent S(>2 reaction time available.
Further analysis is required to determine whether staged combustion and
flue gas recirculation or other modifications could significantly improve NOX
control in FBC boilers without causing operational problems or increasing other
emissions.
The reliability of controlling NOx .emissions at the stringent level on
a 24-hour average basis during long-term operation is not certain, since data
from large AFBC units are currently very limited. The actual mechanisms which
strongly influence NOx control in FBC are not fully identified and understood
at this time.
3.2.2.3 Intermediate Reduction Controls—
The intermediate level of NOX control which is being considered is 258
ng/J (0.6 lb/106 Btu). A large percentage of NOX emission data recorded at all
existing AFBC test units (including units as small as 6 in. in diameter) have
been below this level. As discussed above, data from the larger AFBC facilities
(operating at normal primary cell bed temperatures) have been consistently below
the intermediate level of 258 ng/J (0.6 lb/106 Btu). In addition, during testing
The PER FBM data above this level were recorded in experimentation conducted
at bed temperatures much higher than envisioned for typical AFBC operation.
180
-------
of the somewhat smaller 36 in. x 18 in. CRE unit by the British National Coal
Board, all but four of the measured NOX values were below this level.^^ Based
on existing data, it is expected that industrial FBC boilers will be capable
of supporting an intermediate NOx control level without incorporation of special
design/operating features.
3.2.3 Particulate Emissions
Necessary particle control efficiencies to meet the optional control levels
under consideration are shown in Table 19, Subsection 3.1.4. Uncontrolled emis-
sions refer to the loading downstream of the FBC primary cyclone, which is con-
sidered an integral part of the FBC system. The ranges in particle loading and
mass median diameter at the outlet of the primary cyclone are also shown in
Table 19.
It is essential to note that final particulate control technology has not
been demonstrated in FBC to date. In the near future, testing is planned at
EPA's Sampling and Analysis Test Rig, Georgetown University, and Rivesville,
West Virginia. There are some data available for primary cyclone inlet and
outlet loadings (as shown in Sections 7.0 and 2.0), but it is important to
expand the data base.
3.2.3.1 Moderate Reduction Controls—
The moderate particulate control level to be supported using fluidized-bed
combustion and add-on controls is 107.5 ng/J (0.25 lb/106 Btu). Emission con-
trol techniques which could be used to reduce particulate emissions to this
level include multitube cyclones (MC), electrostatic precipitators (ESP), and
fabric filters (FF). A comparison of these controls is presented in Table 25
illustrating relative differences in cost, energy impact, environmental impact,
reliability, applicability, and other factors, by boiler capacity. Wet scrubbers
181
-------
TABLE 25. APPLICABILITY OF FINAL PARTICULATE CONTROL DEVICES TO
ACHIEVE MODERATE CONTROL AT 107.5 ng/J (0.25 lb/106 Btu)
FOR COAL-FIRED FBC INDUSTRIAL BOILERS
00
NJ
. , . , Applicability*
Boiler capacity Final Technological . . ' _
.. _ in meeting energy
MWt control ability to meet Cost control impact
(106 Btu/hr) device control level level
58.6
(200)
44
(150)
22
(75)
8.6
(30)
MC
FF
ESP
WS
MC
FF
ESP
WS
MC
FF
ESP
WS
MC
FF
ESP
WS
B
B
B
B
B
B
B
B
B
B
B
B
B
B
B
B
B
D
D
B
D
D
B
D
D
A
D
E
A
D
D
D
A
D
D
D
A
D
D
D
A
D
D
D
B
B
A
B
B
A
B
B
A
B
B
A
Environ-
mental
impact
A
A
A
A
A
A
A
A
A
A
A
A
Boiler
operation
or
safety
A
B
A
A
B
A
A
B
A
A
B
A
Reliability
B
B
B
B
B
B
B
B
B
B
B
B
Status of
development
with respect
to controlling
FBC emissions
C
C
D
C
C
D
C
C
0
c
c
D
Multi-
pollutant
control
capability
A
A
B
A
A
B
A
A
B
A
A
B
Adaptability
to new FBC
boiler
A
A
A
A
A
A
A
A
A
A
A
A
Compatibility
with
FBC
A
B
C
A
B
C
A
B
C
A
E
C
Overall
ranking
A
C '
C
D
A
C
f
D
A
C
C
D
A ,
C /
C
D
For moderate control, ESP's or FF's would be inapplicable because they represent overdesign.
Notes: Rating System - Each control device is rated by a letter code (A • best; B * good; C « acceptable; D " poor;
E - inappropriate) relating to each factor listed in the table. The overall ranking applies to all factors listed
in the text.
MC - Multitude Cyclone
FF - Fabric Filter
ESP - Electrostatic Preclpitator
WS - Wet Scrubber
-------
itemized, but are not considered as an appropriate option for particulate
control in FBC. Therefore, not all of the items have been rated for wet
scrubbers.
Considering the tenfold range of emissions downstream of the FBC primary
cyclone (215 to 2,150 ng/J) and resulting overlap in efficiency requirements
CO meet stringent, intermediate, and moderate levels, the comparison given in
Table 25 is for efficiency requirements between 50 and 80 percent. If greater
than 80 percent efficiency is required to meet a moderate level of 107.5 ng/J
(0.25 lb/106 Btu), then the comparison in Table 25 does not apply. The dis-
cussion of intermediate and stringent levels indicates the trade-offs associated
with using different particulate removal devices at control efficiencies greater
than 80 percent.
A rating system from A to E is assigned to compare control devices capable
of meeting a moderate standard, as explained in the footnotes to Table 25. The
overall ranking indicates that the best system for moderate control is the multi-
cube cyclone. In general, fabric filters and ESPs are inappropriate because they
represent overdesign and unnecessary cost for moderate particulate reduction.
The relative cost of add-on control devices is shown in Figure 29 based on the
analysis in Section 4.0. ESP costs for SIP control were estimated in Section
4.0 to be significantly higher than multitube cyclone cost for moderate control.
This fact, and the results shown in the figure indicate that a multitube cyclone
is the low cost device.
Several of the categories are interrelated, such as technological ability,
reliability, and compatibility with FBC. Since final control devices have not
been demonstrated on FBC units, none of these factors can be explicitly defined.
183
-------
BOILER CAPACITY, 10 ktu/kr INPUT
75 ISO 200
22 44
iOlLEM CAPACITY, MWt
88.6
Figure 29. Cost of final particulate control
for AFBC industrial boilers.
184
-------
All devices should have the technical capability to meet the moderate level
so they have each been assigned a B rating. An A rating was not assigned be-
cause demonstration of these devices on FBC boilers has not occurred. There
could be problems with fine particulate removal in multitube cyclones, blinding
fyc bag fires in fabric filters, and unsuitably high particle resistivity for
ESP use. Therefore, compatibility with FBC is questionable, mainly for ESPs or
fabric filters. Reliability must be proven for all systems in extended testing.
, all devices were assigned a B rating in this category.
The energy impact of fabric filters or multitube cyclones is slightly
than ESPs because of higher pressure drop. The environmental impact of
of the three systems should be similar because an equivalent amount of solid
is removed at a specific efficiency and material is handled in dry form.
No major problems with boiler operation and safety are foreseen, other than
with fabric filter use where the potential for bag fires must be assessed. Also,
since fabric filters do not have natural bypass capabilities, inadequate fabric
cleaning procedures could result in sudden pressure drop increases that might
affect the operation of the boiler.
Considering multipollutant control capability, use of any add-on final
particle control device should not have any detrimental effect on S02 or NOx
control capability in FBC. ESPs were assigned a B rating in this category be-
cattse FBC particle resistivity data indicate that ESPs must be operated as hot-
aide installations for suitable performance. Consequently, there may be other-
wise condensable trace elements which would escape a hot-side ESP. However,
associated environmental impact should be negligible.
185
-------
Adaptability of add-on final particulate devices to new FBC boilers should
not be a general problem for any specific device. Therefore, all systems have
been rated equivalently. Adaptability will be most significantly influenced
by site-specific conditions.
3.2.3.2 Stringent Reduction Controls—
The stringent control level for particulate reduction is 12.9 ng/J (0.03
lb/106 Btu). Based on particulate emissions ranging from 215 to 2,150 ng/J
(0.5 to 5 lb/106 Btu) with mass mean size of 5 to 20 ym after the primary
cyclone, the final collection efficiency requirements range between 94 to 99.4
percent. The most applicable devices for control at this level are fabric
filters and ESPs.
Multitube cyclones are not capable of routinely achieving this level of
control, and wet scrubbers have not received serious consideration because of
the generation and handling of liquid wastes. In addition, wet scrubbers would
have to operate a high pressure drops to attain high efficiency particle
collection.
Although fabric filters and ESPs should be capable of stringent particu-
late control, there are uncertainties which preclude a clear cut selection of
either device as the best system for application to FBC boilers due to the
early stage of development. These factors have been mentioned in the previous
subsection, but they deserve reemphasis here. Primarily, final control device
performance on FBC boilers has not been demonstrated to date. This assessment
is based upon the performance of these devices on conventional system particu-
late emissions. Their performance on FBC should not be grossly different from
that on conventional boilers burning low sulfur coal. However, in the case
of ESPs, particle resistivity may cause performance problems. PER and TVA
186
-------
measurements shown in Section 2.0 indicate that hot-side installation is re-
quired for ESP use. ESP reliability may be poor depending on variability in
coal. Much more experimentation is necessary to confirm that hot-side ESPs
would function well. In the case of fabric filters, there is a potential for
bag blinding due to lime hydration or bag fires. The influence of factors such
as caking, bag cleaning, and bag durability have not been explored. Until these
uncertainties and possible problems are confirmed or refuted in actual testing,
a clear-cut decision between the two devices is not possible.
There are some specific advantages or disadvantages that could influence
the choice of a fabric filter or ESP. Primarily, fabric filters are a lower
cost system than hot-side ESPs (see Figure 29), based on costs quoted for con-
ventional boilers burning low sulfur coal. The total annual cosr of the fabric
filter is 15 to 30 percent less than the hot-side ESP. When the total FBC sys-
tem costs are added, the cost difference becomes insignificant, because, at
worst, add-on device cost approaches 10 percent of total boiler system cost.
This is shown in detail in Section 4.0.
ESPs should have slightly lower energy impact due to negligible pressure
drop. However, as efficiency requirements become more stringent, the advantage
disappears. An ESP may be preferred from the standpoint of boiler operation
and safety since sudden back pressure increases with improperly cleaned fabric
filters could cause operating problems.
Neither fabric filters or ESPs have significant multipollutant control
capability, but fabric filters would have an advantage over hot-side ESPs
because they would capture condensable trace elements and organics in the
range of 100° to 150°C which would pass through a hot-side ESP uncontrolled.
187
-------
Fabric filters may be more adaptable than ESPs to small capacity boilers
because of lower capital cost and less operational variability and complexity.
Operating a hot-side ESP to overcome resistivity problems requires handling
significantly larger gas volumes than would be necessary with use of a fabric
filter. Coal and sorbent type could vary appreciably, especially at smaller
boiler installations, resulting in differences in particle resistivity which
would affect ESP collection efficiency. Assuming that hot-side ESP operation
is essential, fabric filters should be more compatible with small capacity
FBC boilers.
All of the important factors influencing the choice of the best system
of particulate control at the stringent level are summarized in Table 26.
Complete ratings are provided only for ESPs and fabric filters, since these
devices alone are considered technically capable of stringent control. The
remaining factors of concern are environmental impact and adaptability to
new FBC boilers. There should be no significant difference in ESP or fabric
filter use for either of these considerations.
3.2.3.3 Intermediate Reduction Levels—
The intermediate standard under consideration for particulate removal
is 43 ng/J (0.1 lb/106 Btu). The required final efficiency to meet this level
ranges between 80 to 98 percent. Best system selection in the range of 94 to
98 percent follows the discussion presented for stringent control. In the
range of 80 to 94 percent, fabric filters, ESPs, or multitube cyclones could
be applicable depending on site-specific conditions.
System comparisons and applicability are similar to the previous discussions
for moderate and stringent control, depending on the proximity of required con-
trol efficiency to 80 percent or 94 percent, respectively. Multitube cyclones
188
-------
TABLE 26. APPLICABILITY OF FINAL PARTICULATE CONTROL DEVICES TO
ACHIEVE STRINGENT CONTROL AT 12.9 ng/J (0.03 lb/106 Btu)
FOR COAL-FIRED INDUSTRIAL BOILERS
oo
Boiler capacity Final Technological
MJ control ability to meet
(10s Btu/hr) device control level
58.6
(200)
44
(150)
22
(75)
8.8
(30)
Motes: Rating
FF
ESP
MC
WS
FF
ESP
MC
WS
FF
ESP
we
WS
FF
ESP
MC
WS
Systen - Each
A
B
E
D
A
B
E
D
A
B
E
D
A
B
E
r
control device
Applicability _ .
Cost . mental
control impact 7=nl-<"
level lmfact
A
B
E
E
A
B
E
E
A
C
E
E
A
D
E
E
is rated
A B A
A A A
E
E
A B A
A A A
E
E
A B A
A A A
E
E
A B A
A A A
E
E
by a letter code (A " best;
Boiler
operation . . . , .
"^ Reliability
safety
B
A
B
A
B
A
B
A
B « good;
C
C
C
C
C
D
C
D
C • acceptable;
Status of
development UutMt Adaptability CMpatibility „„„„
with respect \ , to new FBC with ,..L;n.
to controlling con"?' boilers FBC r""Llng
FBC emissions ctv* l l r
D
D
D
D
D
D
D
D
D • poor; 1
A
B
A
B
A
B
A
B
E • inappropriate)
A B
A C
A B
A C
A B
A D
A B
A D
relating to
B
B
E
E
B
B
E
E
B
B
E
E
B
B
E
E
each factor listed in the table. The overall ranking applies to all factors listed and discussed in the text.
FF - Fabric Filter
ESP - Electrostatic Preclpltator
MC - Multitube Cyclone
WS - Wet Scrubber
-------
might be applicable for the low end of this range if mass median particle size
is greater than 10 um. Under this condition, multitube cyclones would be the
low cost device. Otherwise, fabric filters would be the low cost alternative
(see Figure 29). Again, it is important to consider the uncertainties due to
the lack of demonstration on FBC boilers.
3.3 OTHER FUELS
Data on emissions from fluidized-bed combustion of residual and distillate
oil or natural gas are limited. Therefore, it is premature to discuss the
rationale or ability to support optional standards for oil or gas combustion
in FBC. Also, the extent of oil or natural gas use in FBC is uncertain, but
is not expected to be widespread.
The summary (Section 3.4) presents emission reduction requirements neces-
sary for 862, NOX» and particulate, under the three optional standards. Re-
quirements for S02 control are listed for residual and distillate oil and NO
emission reduction requirements are shown for coal and oil together. It is
projected that fluidized-bed combustion of oil should be capable at least of
meeting the optional standards for SOa and NOX applicable for coal combustion.
It is possible that more stringent NOx levels could be achieved due to lower
fuel oil nitrogen content. S02 and NOX emissions from combustion of natural
gas are expected to be low, due to low sulfur and nitrogen content of natural
gas, and low combustion temperature.
3.4 SUMMARY
The candidate best systems of emission reduction associated with FBC are
summarized in Tables 27 through 29 for S02, NOX, and particulate emissions.
190
-------
TABLE 27. OPTIONAL S02 CONTROL LEVELS AND REQUIRED EFFICIENCIES
Level of emission control
Fuel and
boiler capacity
MWt
(106 Btu/hr)
Coal
8.8 to 58.6
,_. (30 to 200)
VO
t-^
Residual oil
44
(150)
Distillate oil
4.4
(15)
Sulfur Uncontrolled S°2
emission
ir\ ng'J
1 ' (lb/106 Btu)
3.5 2425
(5.64)
0.9 533
(1.24)
0.6 512
(1.19)
3.0 1350
(3.14)
0.5 219
(0.51)
efficiency
Stringent
90X removal or
required to achieve
86 ng/J
(0.2 lb/106 Btu)
90
83.9
83.2
90
60.8
and
required to achieve that level
ng/J (lb/10s Btu)
Intermediate
85Z removal or
required to achieve
86 ng/J
(0.2 lb/106 Btu)
85
83.9
83.2
85
60.8
Moderate
75Z removal or
required to achieve
516 ng/J
(0.2 lb/106 Btu)
78.7
75
75
75
60.8
Best system of SO 2 control - Ca/S ratio requirements
Stringent Control Intermediate Control Moderate Control
Sorbent reactivity
High Average Low High Average Low High Average Low
2.3 3.3 4.2 2.1 2.9 3.8 1.8 2.5 3.4
"
2.0 2.8 3.7 2.0 2.8 3.7 1.6 2.2 3.2
2.0 2.7 3.6 2.0 2.7 3.6 1.6 2.2 3.2
3.3* 2.9* 2.5*
1.2* 1.2* 1.2*
Estimated - not based on actual data from oil-fired units.
-------
TABLE 28. OPTIONAL NOx CONTROL LEVELS
VO
to
Fuel and
boiler capacity
Uncontrolled
emission
Level of emission control and NOx reduction
efficiency required to achieve that level
ng/J (lb/106 Btu)
Control device
do6
raw
Btu/hr)
"B/ v.
(lb/106
i
Btu)
Stringent
215
(0.5)
Intermediate
258
(0.6)
Moderate
301
(0.7)
required
Coal and oil
4.4 -
(15 -
58.6
200)
430*
(1.0)
50
40
30
AFBC1"
Highest reported value for FBC using calcium-based sorbent.
Ability of AFBC to achieve the stringent level of control without some adjustment of design/
operating conditions Cto excess air values as low as 15%, and to gas residence times as high
as 0.67 sec) must be confirmed by further data on large AFBC units.
-------
TABLE 29. OPTIONAL PARTICULATE CONTROL LEVELS AND REQUIRED EFFICIENCIES
(AFTER PRIMARY CYCLONE)
Level of emission control and
_ , , Uncontrolled efficiency required to achieve that level _ , . • , ,*
Fuel and «.•••.. „ • 1 • /- /ii_/-.ne „ \ Control device recommended
boiler capacity Partlculate Particle size ng/J (lb/106 Btu)
v } emission average MMD
/in6 -a*, /u A ng/J (ym) Stringent Intermediate Moderate Stringent Intermediate Moderate
(10 Btu/hr) (lb/106 Btu) 12>9 43 107>5
(0.03) (0.10) (0.25)
Coal
8.8 - 58.6
(30 - 200)
215
(0.5
- 215.0 _
- 5.0) 5 20
94 - 99.4 80 - 98 50 - 95 ESP or FF ESP'J7
or MC
MC
*
Selection of device will depend upon efficiency requirements, particle size, boiler capacity, and tradeoffs in the economic
and energy requirements of each device. (See Tables 3-5 and 3-6.)
FF - Fabric Filter
ESP - Electrostatic Precipitator
MC - Multitube Cyclone
-------
3.4.1 S02
The best S02 control system in AFBC is the one which minimizes sorbent
requirements, energy impact, and cost impact, and simultaneously maintains the
control level of concern. Based on review of experimental results, estimates
of Ca/S ratio requirements for best SC>2 control are given in the last columns
of Table 27, for SC>2 removal efficiencies ranging between 75 to 90 percent.
The values selected are average values calculated from several experiments
which were conducted using average sorbent particle sizes close to 500 vim and
gas phase residence times close to 0.67 sec. The average Ca/S ratio from the
experimental results shown in Table 27 is considered representative because SOo
reduction results were reported for sorbents of low and high reactivity. The
Ca/S ratios shown are used in the remainder of this report to assess cost, energy
and environmental impact. These values were chosen instead of model projections
for specific sorbents (i.e., Western 90 percent CaL, Bussen, and Menlo) because
the experimental Ca/S ratios are taken from a wide data base and should be more
representative of the sorbent requirements of a typical user. Also, the Menlo
sorbent reactivity is probably too low for practical use.
As S02 removal requirements become more stringent, air pollution impact
will be minimized, but the impact of disposing of large volumes of sulfated
bed material will increase. However, the spent stone is in dry form, which
should simplify handling.
Reliability of performing within the optional S02 standards has been proven
in a wide variety of pilot-scale FBC boilers. The most critical factors are
selection of a suitable sorbent, use of appropriately small particle sizes
and operation with sufficiently long gas phase residence times. Sorbent charac-
teristics have been studied thoroughly and are documented in a number of
194
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references. The FBC SC>2 control model developed by Westinghouse illustrates
the dependence of Ca/S molar feed ratios on FBC design and operating conditions.
3.4.2 NOx
Experimentation has illustrated the potential of FBC to support any of
the three optional levels. The major concern is that additional data from
.large AFBC units are necessary to confirm the ability of AFBC to reliably achieve
the stringent level of control. Data from large units are currently limited,
but the data which do exist (B&W 6 ft * 6 ft, Renfrew) support the ability of
AFBC to meet the stringent level.
3.4.3 Particulate
Particulate reduction under all three control options should be possible
in FBC systems by using suitably designed and operated conventional add-on
particulate control devices. This has not yet been demonstrated, because
suitably large AFBC units with final particle control have not been operated
for sufficiently long periods. However, control of particulates from AFBC
should be similar to control in conventional boilers burning low sulfur coal.
The most important factors in selecting a device are cost and reliability.
for stringent or intermediate control, fabric filters are the low cost device
(unless mass median particle size is large enough to allow the use of multi-
tube cyclones for lower efficiency requirements under intermediate control).
yor moderate control, multitube cyclones are the low cost device.
When total system cost is considered (i.e., the AFBC boiler with all
auxiliaries plus final particulate control) cost differences as a function of
the final particulate control device employed are small because the cost of the
add-on device is at most 5 to 10 percent of the total annual boiler cost.
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Reliability of final particulace control for FBC must be proven in large-
scale testing. Existing data indicate that ESPs will have to be operated as
hot-side installations because of high particle resisitivity. ESP performance
could be impacted by variability in coal and sorbent characteristics, a factor
which could be especially important in smaller capacity boilers. Fabric filter
performance and reliability is also uncertain due to potential problems with
bag blinding, and bag fires.
These uncertainties must be explored in full-scale testing. In the near
future, testing is planned at the EPA's Sampling and Analysis Test Rig,
Rivesville, and Georgetown University.
Since one of the implicit purposes of FBC is to avoid liquid waste produc-
tion, use of wet scrubbers has not been given serious consideration.
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3.5 REFERENCES
1. Dowdy, I.E., et al. Summary Evaluation of Atmospheric Pressure Fluidized-
Bed Combustion Applied to Electric Utility Large Steam Generators. Pre-
pared by the Babcock & Wilcox Company for the Electric Power Research
Institute. EPRI FP 308. Volume II: Appendix. October 1976. pp. 6K-r20
to 6K-68.
2. Newby, R.A., et al. Effect of S02 Emission Requirements on Fluidized-
Bed Combustion Systems: Preliminary Technical/Economic Assessment.
Prepared by Westinghouse Research and Development Center for the U.S.
Environmental Protection Agency. EPA-600/7-78-163. August 1978.
p. 24.
3. Hansen, W.A. , et al. Fluidized-Bed Combustion Development Facility
and Commercial Utility AFBC Design Assessment Quarterly Technical Progress
Reports. Prepared by Babcock and Wilcox Company for the Electric Power
Research Institute. April to June 1978. July to September 1978.
January to March 1979.
4. Beacham, B., and A.R. Marshall. Experiences and Results of Fluidized-Bed
Combustion Plant at Renfrew. Prepared by Babcock Contractors Ltd., and
Combustion Systems, Ltd. Presented at a Conference in Dusseldorf, W.
Germany. November 6 and 7, 1978.
5. Newby, R.A., op. cit. pp. 39-79.
6. Hanson, H.A., et al. Fluidized-Bed Combustor for Small Industrial
Applications. Prepared by FluiDyne Engineering Corporation. Proceedings
of the Fifth International Conference on Fluidized-Bed Combustion.
December 1977. pp. 91 to 105.
7. Letter correspondence from Dr. R.A. Newby of Westinghouse Research and
Development Center to Mr. C.W. Young at GCA/Technology Division. April
30, 1979.
8. Newby, op. cit. EPA-600/7-78-163. p. 24.
9. Ibid, p. 34
10. Dowdy, op. cit. pp. 6K-20 to 6K-68.
11. Letter correspondence from Mr. D.B. Henschel of the U.S. Environmental
Protection Agency to Mr. C.W. Young of GCA/Technology Division. April 9,
1979.
12.
Sarofim, A.F., J.M. BeeV. Modeling of Fluidized-Bed Combustion. Prepared
by Massachusetts Institute of Technology. Presented at the Seventeenth
Symposium (international) on Combustion, Leeds, England. August 1978.
197
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13. Bee'r, J.M., et al. NO Reduction by Char in Fluidized Combustion. Prepared
by Massachusetts Institute of Technology. p. 2.
14. Robison, E.G., ec al. Characterization and Control of Gaseous Emissions
from Coal-Fired Fluidized-Bed Boilers. Prepared by Pope, Evans, and
Robbins for the Division of Process Control Engineering, National. Air
Pollution Control Administration, Environmental Health Service Public
Health Service, Department of Health, Education, and Welfare. October
1970. Appendix B.
15. Jonke, A.A., et al. Reduction of Atmospheric Pollution by Application
of Fluidized-Bed Combustion. Annual Report. Prepared by Argonne National
Laboratory. ANL/ES-CEN-1001. July 1968 through June 1969. p. 29.
16. National Coal Board. Reduction of Atmospheric Pollution (Volume 1 of 3).
Main Report. Prepared by the National Coal Board for the U.S. Environ-
mental Protection Agency. PB-210 673. September 1971. pp. 141-142.
17. Babcock and Wilcox Company. Fluidized-Bed Combustion Development Facility
and Commercial Utility AFBC Design Assessment. Technical Progress Report
No. 8 (Quarterly). January through March 1979. Prepared for the Electric
Power Research Institute. April 1979. pp. 2-5 through 2-90.
18. Lange, H.B., T.M. Sommer, C.L. Chen. S02 Absorption in Fluidized-Bed
Combustion of Coal Effect of Limestone Particle Size. Prepared by the
Babcock and Wilcox Co. for the Electric Power Research Institute. FP-667.
Final Report. January 1978. pp. A1-A10.
19. Roeck, D.R., R. Dennis. Technology Assessment Report for Industrial
Boiler Applications: Particulate Control. Draft Report. Prepared by
GCA/Technology Division for the U.S. Environmental Protection Agency.
June 1979. p. 105.
20. Newby, op. cit.
21. Ibid.
22. Vaughan, D.A., et al^ Fluidized-Bed Combustion: Industrial Application
Demonstration Projects. Special Technical Report on Battelle's Multi-
Solids Fluidized-Bed Combustion Process. Prepared by Battelle Columbus
Laboratories for the U.S. Energy Research and Development Administration.
FE-2472-8. February 1977.
23. Newby, op. cit. pp. 73 and 76.
24. Jonke, op. cit. pp. 22 through 23.
25. Jonke, A.A., et al. Reduction of Atmospheric Pollution by the Application
of Fluidized-Bed Combustion. Prepared by Argonne National Laboratory.
'ANL/ES-CEN-1002. 1970. pp. 23-37.
26. Jonke, op. cit. ANL/ES-CEN-1001. pp. 21-35.
198
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27. Jonke, op. cit. ANL/ES-CEN-1002. pp. 23-37.
28. Jonke, op. cit. ANL/ES-CEN-1001. pp. 21-35.
29. Vogel, G.J., et al. Bench-Scale Development of Combustion and Additive
Regeneration in Fluidized Beds. Prepared by Argonne National Laboratory
for the U.S. Environmental Protection Agency. PB 231-977. December 1973.
p. I - 1-24.
30. National Coal Board. Reduction of Atmospheric Pollution. Main Report.
Prepared by the Fluidized Combustion Control Group for the U.S. Environ-
mental Protection Agency. September 1971. PB 210-673. pp. 17-21.
31. Ibid, pp. 21-25.
32. Ibid.
33. Ibid, pp. 17-21.
34. Ibid.
35. Ibid, pp. 55-56.
36. Ibid, p. 58.
37. Ibid.
38. Ibid.
39. Ibid, p. 88.
40. Ibid, p. 90.
41. Ibid.
42. Ibid.
43. Lange, op. cit. pp. 2-1 through 2-9.
44. Robison, op. cit. Appendix B.
45. Ahmed, M.M., D.L. Keairns, and R.A. Newby. Effect of S02 Requirements
on Fluidized-Bed Boilers for Industrial Applications: Preliminary
Technical/Economic Assessment. Prepared by Westinghouse Research and
Development Center for the U.S. Environmental Protection Agency.
November 20, 1979.
46. Buck, V., F. Wachtler, R. Tracy. Industrial Applications, Fluidized-Bed
Combustion, Georgetown University. Prepared by PER, Foster-Wheeler, and
Fluidized Combustion Company. Presented at the Fifth International Con-
ference on Fluidized-Bed Combustion. December 1977. Volume II.
pp. 61-90.
199
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47. Mesko, J.E., R.L. Gamble. Atmospheric Fluidized-Bed Steam Generators for
Electric Power Generation. Prepared by Pope, Evans, and Robbins, and
Foster-Wheeler. Presented at the Thirty-sixth Annual Meeting of the
American Power Conference. 1974.
48. Hanson, H.A., op. cit.
49. Babcock and Wilcox Company, op. cit^ April 1979.
50. Anderson, J.B., W.R. Norcross. Fluidized-Bed Industrial Boiler. Prepared
by Combustion Engineering, Inc. Published in Combustion Magazine.
February 1979. pp. 9-14.
51. Johnston Boiler Company. Multifuel Fluidized-Bed Combustion Packaged
Boilers. Advertising package received by GCA at a meeting with Johnston
Boiler on December 7, 1978.
52. Brachman, op. cit.
53. Arthursson, D.A.A. Fluidized-Bed Furance in Enk<5ping, Sweden. Report
No. 1. Description of a Multifuel Fluidized-Bed Furnace. Prepared by
Svenska Varmeverksfb'reningen.
54. Sun, C.C., C.H. Peterson, R.A. Newby, W.G. Vauz, and D.L. Keairns. Disposal
of Solid Residue from Fluidized-Bed Combustion: Engineering and Laboratory
Studies. Prepared by Westinghouse Research and Development Center for the
U.S. Environmental Protection Agency. EPA-600/7-78-049. March 1978. p. 5,
55. Dowdy, op. cit. pp. 6-27.
56. Pope, Evans, and Robbins, Inc. Interim Report No. 1 on Multicell Fluidized-
Bed Boiler Design, Construction and Test Program. Prepared by Pope, Evans,
and Robbins, Inc. for the U.S. Department of the Interior. August 1974.
p. 145.
57. Jonke, op. cit. ANL/ES-CEN-1001. pp. 32-36.
58. Robison, E.G., et al., op. cit. Appendix B.
59. Lange, op. cit. Appendix A.
60. Jonke, op. cit. ANL/ES-CEN-1001. pp. 32-36.
61. National Coal Board, op. cit.
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4.0 COST IMPACT OF IMPLEMENTING BEST SYSTEMS OF
EMISSION CONTROL
4.1 INTRODUCTION
4.1.1 Background
Industrial-sized FBC boilers are as yet unproven in extended commercial
operation because fluidized-bed combustion is an emerging technology. The
commercial scale coal-fired AFBC units which are in operation (e.g., Renfrew,
Johnston Boiler Company) are not being operated in typical commercial "around-
the-clock" service. The AFBC units that will be used in typical service
(e.g., Mustad/Enkoping, the B&W Ltd. unit at Columbus State Hospital in Ohio,
the Foster Wheeler unit at Georgetown University, the crude oil heater at
Exxon, the Combustion Engineering/Great Lakes unit) are not yet in operation.
Such extended operation in typical service is required in order to prove
AFBC reliability and to demonstrate industrial AFBC costs. Therefore, at the
present time the cost of AFBC in comparison to conventional boilers may be
under- or overestimated. As cost data from first generation commercially-
operated FBC boilers become available, more accurate cost estimates can be
developed. Second generation systems may be more cost-effective because of
design and operating improvements.
Most of the discussion in this section centers on S02 control to assess
the influence of meeting optional levels of desulfurization on FBC cost. NOx
control is considered intrinsic to the system and no specific costs are readily
identified. Particulate control will be attained with add-on devices similar
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to those used for conventional combustion with low sulfur coal; hence, cost of
particulate control should not be very sensitive to FBC design variations -
although operating data are needed to substantiate this assumption.
Costs are presented for "best system" designs and potential savings compared
to "commercially-offered" AFBC designs are estimated (see Section 3.2.1.5). Since
"commercially-offered" boiler designs do not typically incorporate the conditions
(0.67 second g,as residence time, 500 ym average in-bed sorbent particle size)
that are felt to represent the "best" S02 control system, and since data for
S02 control efficiency at these conditions are limited, the need for confirma-
tion of the "best" S02 control system costs by large scale AFBC operation is
especially important.
The cost values presented in this section are budget estimates for a new
technology operating under hypothetical conditions and are probably accurate
to within ±30 percent. Even wider variation could exist depending on site
specific conditions, and, therefore, these results are presented only as an
indication of the benefits or penalties of using FBC in place of conventional
technology on a broad basis. The results are not intended to provide a
basis for selecting one technology over another for a specific industrial
application; they are meant to reflect trends which are valid only for a
preliminary comparison of two different technologies. Therefore, the
thrust of the analysis is not the generation of absolute cost values, but a
comparison of the cost of FBC with S(>2 control under various operating conditions
against cost of conventional boilers without S02 control.
The sensitivity analysis presented later takes a prominent role in the
overall discussion as an analysis of the effect on cost of several possible
operational modes. Again, it is recommended that the absolute costs presented
later be treated cautiously.
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A more plausible comparison could be made if the conventional boilers also
included some form of 802 control (e.g., flue gas desulfurization). Because
this report is one part of an overall system analysis of pollution control for
industrial boilers being done by EPA, all pollution control options (FBC was
one of eight options) were separately compared with uncontrolled conventional
reference boilers. The results of this study are interesting in that even
without considering the added cost of S02 control for conventional systems,
there may be some cost advantage to FBC over conventional boilers in certain
size ranges or if low sulfur coals are burned.
4.1.2 Data Sources
The FBC cost estimates developed in this section are based on vendor
quotes and are mid-1978 dollars. These vendor quotes were supplemented by
reference to cost data developed by PEDCo for conventionally-fired boilers
of the same capacity,1 Other recent cost estimates for industrial fluidized-bed
combustion were reviewed and two estimates, one by Exxon Research and Engineering,
the other by A.G. McKee,3 are included for comparative purposes. In addition,
the results of an independent AFBC industrial boiler cost assessment prepared
by Westinghouse Research and Development under EPA sponsorship are also included.1*
The Westinghouse costs were partly derived using information supplied by GCA,
but in-house Westinghouse FBC cost data were used to determine total capital,
operating, and annual costs. Westinghouse did not solicit vendor quotes for
boiler cost.
4.1.3 Data Uncertainties
The cost variation among these estimates is at least partially a function
of the wide variation in atmospheric FBC designs among different vendors.
Certain differences which are important include:
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• methods of coal and limestone handling and feeding;
• freeboard height;
• bed depth;
• heat transfer tube placement and orientation;
• use of fly ash recirculation or carbon burnup cell
(use of the latter will probably be very limited
in industrial boilers);
• coal and limestone particle size; and
• normal fluidization rates.
Several methods of coal and limestone feeding are being advocated and these
methods require further investigation to determine which feed technologies
will provide adequate dispersion at minimal cost. Load variation (turndown)
is another area where several techniques are being developed and the feasibility
of these must also be studied.
There is some debate relative to maintenance requirements in fluidized-bed
boilers. Equipment of particular concern includes in-bed boiler tubes and coal
feeders. Boiler tubes in the bed may be items of high maintenance due to the
possibility of fluctuating oxidation/reduction zones near coal feed points.
However, maintenance of in-bed tubes may be reduced due to the relatively low
and constant temperatures in the bed compared to conventional boilers and
corrosion/erosion may be reduced by suitable design (e.g., by not placing tubes
in the immediate vicinity of coal injection points). In-bed coal feeders may
be a high maintenance item due to potential clogging and erosion; overbed
coal feeders :an avoid the plugging and erosion problems, but could
necessitate double screening of the coal to avoid increased emissions.
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Because the impact on maintenance cost of these system components cannot
be assessed from the current data base, neither a penalty or advantage can
be assigned to FBC maintenance requirements relative to conventional systems.
As operating experience is gained from industrial scale plants, detailed
estimates of maintenance costs can be developed. For this analysis it is
assumed that maintenance requirements and boiler life expectancy are similar
for FBC and conventional systems.
The costs presented here assume that all three levels of NOX control can
be achieved with no impact upon FBC cost. This assumption is based upon the
fact that most NOX data from all experimental AFBC units are below the inter-
mediate level of 258 ng/J (0.6 lb/106 Btu).* Data from the larger (>250 kg/hr
coal) AFBC units are consistently below 215 ng/J (0.5 lb/106 Btu) at typical
primary cell bed temperatures. Therefore, the stringent level can be expected
to be reliably attained with little or no adjustment to standard design and
operating conditions. In practice, any such adjustments may have some impact
on capital and operating costs, but it is not possible to quantify at this
time. Finally, it is not expected that SC>2 control variations will have a
significant influence on NOx control capability or cost. In practice, the
increased gas residence times desired for good SC>2 control should tend to
reduce NO,, emissions.
A
4.1.4 Major Contributors to Emission Control Costs for SO?
4.1.4.1 General Comments—
An AFBC industrial boiler is an integrated energy production/S02 control
technology. Consequently, certain equipment items and operating costs can
not be discretely isolated as part of the steam raising system on the S02
control system.
See Sections 2 and 3.
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The forced draft fan and associated fan power fall into this category.
Also included are the primary cyclone (for recycle of unreacted fine sorbent
and unburned carbon), the induced draft fan and associated power use, and
ancillary equipment for feeding and discharge of bed material. The subsequent
discussion of contributors to the capital and operating cost of S02 control
should be considered in the context of these factors.
4.1.4.2 Capital Costs Related with SC>2 Removal—
The major capital costs associated with use of AFBC as an emission control
technique are the boiler, the limestone handling and feeding system, and spent
solids handling and disposal. Ancillary equipment items normally required
for AFBC and conventional systems and of similar cost are coal handling, induced
draft fan, water treatment equipment, instrumentation, stack, etc. Common items
which are of higher cost in FBC systems are the coal feeders and the forced
draft fan.
The boiler cost will depend on several design variables. Influential
factors are: shop versus field erection, freeboard height, bed configuration,
heat transfer design, carbon recirculation design, and load following technique.
Several designs are available which incorporate different combinations of
these variables. At this stage of development, no single design is expected
to dominate the market.
Limestone handling capital cost depends on sorbent storage and feed rate
requirements, which in turn depend on 862 control level, sorbent reactivity
coal sulfur content, and boiler size. The amount of limestone storage at a
specific site will Depend upon available delivery frequency and possibly
haulage rates. Limestone feeding capital cost will depend on design (i.e.
separate or combined with coal feeding), and will vary primarily as a function
of boiler capacity.
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Spent solids handling capital cost is a direct function of limestone
feed rate. The most significant cost contributors are onsite storage and
disposal site capital cost. The letter will vary depending on the disposal
site requirements.
Coal feeders represent a possible capital cost increase for AFBC as
compared to conventional firing. This cost differential results from the
critical need for even fuel distribution throughout the cross-section of a
fluidized-bed combustor. The major design classifications are overbed screw
feeders, overbed spreader stokers, and underbed pneumatic injectors.
The forced draft fan in AFBC handles slightly lower air volumes than
the conventional coal-fired boilers under consideration (due to lower excess
air) but must overcome about 3 times the pressure drop encounte. ^d in a
conventional coal-fired boiler.* Most of the additional pressure drop in the
AFBC is across the grid plate and the bed.
4.1.4.3 Operating Costs Related with S02 Removal—
Limestone purchase and solid waste disposal costs are the most important
direct operating cost variations associated with supporting optional SC>2
control levels with FBC boilers. These costs can be reduced by reducing
sorbent feed requirements through careful boiler design and operation. The
power required to run the forced-draft fan is also a contributor.
Although limestone reactivity has a potentially important impact on
sorbent feed requirements for a given S02 control level, an industrial FBC
user may not always have the flexibility to choose a highly reactive sorbent
because it may be located at such a distance that haulage costs are excessive.
Each individual FBC user will have to balance the tradeoff between purchasing
*
See analysis of energy requirements in Section 5.0, Subsection 5.2.3,
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high grade limestone versus operating with lower reactivity stones at higher
sorbent feed rates. (The resulting sorbent feed and spent solids rates will
have a moderate impact on the capital cost of materials storage.) This means
that the cost of best SC>2 control can vary from site to site. Generally, an
AFBC user at a typical site should have available to him at least one source
of sorbent of reasonable reactivity. The cost estimates presented in this
chapter consider a range of sorbent feed rates, based upon a range of reasonable
sorbent reactivities. If, indeed at a given site, the only quarries within an
economically transportable distance have extremely nonreactive sorbents, then
AFBC might not be the SC>2 control option of choice for that particular site.
Site specific factors also influence the operating cost of spent solids
disposal. The most important are disposal site location, and applicable
waste disposal regulations.
Research is currently being performed to determine methods to: (1) minimize
solid waste from FBC boilers; (2) identify and abate the potential environmental
impact; or (3) find suitable byproduct uses. FBC residue characteristics which
are of most concern are leachate pH, Ca++, SOiJ, total dissolved solids and
heat release during hydration. 5»6 If FBC spent solids require special
handling/disposal (e.g., fixation at the plant, or imperviously-lined con-
tainment), handling costs could increase significantly. These factors might
influence plant siting or could add to the cost of an in-city plant that pays
to have its wastes hauled to disposal.
Special handling/disposal problems are not anticipated under the Resource
Conservation and Recovery Act.7 Trace elements are not typically present in
the leachate at levels greater than 10 times the drinking water standards.
This is the level at which the residue would be considered "hazardous" (toxic)
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under the Resource and Conservation and Recovery Act. Leachate concentrations
must be confirmed through further testing on waste from commercial size units.
Byproduct uses for FBC solid waste are being investigated by
L. John Minnick,8 the U.S. Department of Agriculture,9 Westinghouse,10
Ralph Stone and Co., Inc.,11 and TVA,12 and several universities and private
concerns. Cost or siting limitations might be reduced if the waste can be
utilized.
Electricity is required for operation of coal and limestone handling and
feeding, spent solid withdrawal and cooling, FD and ID fans, and boiler water
circulation and treatment. The FD fan is the major user, and consumes about
half of the total auxiliary power requirement.* Operation of the primary
particulate recycle device (normally a cyclone) will require minimal fan energy
because the pressure drop is low (<15 cm (6 in.) w.g.).
4.1.5 Cost Related with Final Particulate Removal
The cost of particulate control for FBC boilers is significant but
should be similar to particulate control on conventional boilers burning low
sulfur coal. Uncontrolled emissions (downstream of the primary cyclone)
are similar to conventional systemsJ Flue gas volumes are slightly less for
FBC boilers in comparison to conventional boilers of the same capacity because
excess air rates are lower and efficiencies are somewhat higher. Moderate
control (50 to 80 percent reduction) may be achieved with use of multitube
cyclones.1' Stringent control (94 to 99.4 percent reduction) requires installation
See Section 5.0.
See Section 3.0.
Section 2.0 and 7.0.
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of a fabric filter or ESP.* Intermediate control (80 to 94 percent reduction)
will require any one of these three devices depending on actual efficiency
necessary and other site specific conditions.''
Particulate removal cost will be influenced by SOz control because of
limestone elutriation. Particulate control needs may increase with sorbent
addition, but incremental loadings are uncertain, so that the significance
of cost variation is questionable.
4.1.6 Most Important Cost jit ems
A summary of important capital and operating cost items associated with
FBC boiler operation and emission control is shown in Table 30. The most
significant cost impact which varies as a function of S02 control level is the
direct operating cost of limestone purchase and solid waste disposal. Total
FBC system cost will also be influenced by particulate control requirements.
TABLE 30. MAJOR COST CONTRIBUTORS TO FBC BOILER
CAPITAL AND OPERATING COST
Capital FBC boiler (replaces conventional boiler)
Forced draft and induced draft fan
Coal feeding
Primary and final particulate collection
Limestone storage and handling
Spent solids storage, handling, and disposal
Operation Coal purchase
Limestone purchase
Spent solids disposal
Forced draft fan power
Final particulate collection
See Section 3.0.
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The analysis of "best system" costs indicates that AFBC with S02 control
is generally more costly than an uncontrolled conventional boiler of equal
capacity by as much as 30 percent. This increment varies considerably depending
on boiler capacity, coal type, 862 control level, and sorbent reactivity. In
certain instances, controlled AFBC may be used at equal or less cost than
uncontrolled conventional systems. This was found to be the case for the
8.8 MWt unit burning low sulfur coal at any S02 control level, or high sulfur
coal at an SIP S02 control level. It was also found for the 58.6 MWt AFBC
burning subbituminous coal, and is due to the equal or higher cost of pulverized
coal technology at this capacity.
Another conclusion is that "best system" designs can reduce the cost of FBC
compared to "commercially-offered" design/operating conditions 'see Section 4.3.4)
This is mainly due to reduced operating costs. Capital costs may be higher or
lower depending on the alterations necessary and the specific design of interest
The analysis also indicates that the level of S02 control (in the range
of 75 to 90 percent) does not have a large impact on FBC system cost when
Eastern high sulfur coal is burned. The effect of SC>2 control level" is
insignificant when low sulfur coals are burned. A more important consideration
in determining the cost impact of S02 control is sorbent reactivity. This
results because sorbent quantities vary through a greater range as a function
of the extremes of sorbent reactivity considered in this study.
4.2 GROUNDRULES FOR DEFINING COST BASIS
The AFBC costs presented are for a grass roots boiler installation in
the midwest. The facility battery limits are from, but not including, the
coal receiving equipment to, and including, the stack and onsite spent solids
storage. The cost of land for offsite spent solids/ash disposal is included
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in the annualized disposal cost. The water treatment facility is included
but piping for the steam to and from the process area is not.
4.2.1 Capital Costs
New facilities have been costed in conformance with guidelines presented
by PEDCo.13 Direct costs include all equipment, installation, and land.
Indirect costs include engineering costs, construction and field expenses,
contractor's fees, startup, performance testing, contingencies, and working
capital. Indirect costs are estimated as a percentage of direct costs with
the factors used for FBC estimates summarized in Table 31.
TABLE 31. VALUES SELECTED FOR ESTIMATING INDIRECT FBC CAPITAL COSTS
FOR NEW FACILITIES
Cost item Value selected
Engineering 10% of installed costs
Construction and field expenses 10% -of installed costs
Contractor's fee 10% of installed costs
Startup 2% of installed costs
Contingencies 20% of total direct and indirect costs
Working capital 25% of the total annual operation and
maintenance costs
4.2.2 Operating and Annualized Costs
The annual cost of owning and operating an FBC industrial boiler consists
of operation and maintenance, overhead, and capital charges. Operation and
maintenance covers all costs incurred to operate the FBC system on a daily
basis, and includes utilities, raw materials, operating labor, routine
maintenance and repairs, fuel purchase, and spent solids disposal cost.
Table 32 summarizes the unit cost values used to estimate FBC operation and
maintenance costs.
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TABLE 32. UNIT COST VALUES USED TO ESTIMATE
ANNUAL OPERATION AND MAINTENANCE
COSTS FOR FBC INDUSTRIAL BOILERS
Cost factors Unit cost*
Direct labor, $/man-hour 12.02
Supervision, $/man-hour 15.63'
Maintenance labor, $/man-hour 14.63
Electricity, mills/kwh 25.8S
Untreated water, $/l,000 gal 0.12
Process water, $/l,000 gal 0.15
Cooling water, $/l,000 gal 0.18
Boiler feed water, $/l,000 gal 1.00
Coal, High S, $/106 Btu ($/ton)(Eastern) 0.74 (17.00)*
Low S, $/106 Btu ($/ton)(Eastern) 1.16 (29.00)*
Low S, $/106 Btu ($/ton)(Wyoming) 0.42 (6.75)*
No. 2 fuel oil, $/106 Btu 3.00
No. 6 fuel oil, $/106 Btu 2.21
Natural gas, $/106 Btu 1.95
Lime, $/ton (bulk, FOB works) 32.00**
Limestone, $/ton (bulk, FOB quarry) 6.00**
Limestone, $/ton (bulk, FOB plant) 8.00
Spent solids disposal, $/ton offsite 40.00
*
All costs are in June 1978 dollars.
Engineering News-Record, June 29, 1978, pp 52-53, Average
for Chicago, Cincinnati, Cleveland, Detroit and St. Louis.
'Estimated at 30 percent over direct labor rate.
§
EEI members publication for June 1978, Average for Boston,
Chicago, Indianapolis, Houston, San Francisco, and
Los Angeles.
£
Coal Outlook, 7/18/78 issue, Spot market prices.
**
Chemical Marketing Reporter, June 19, 1978.
See subsection 4.3.2 for discussion of limestone purchase
and spent solids disposal costs.
213
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The cost of offsite spent solids disposal is based on a common unit cost
factor recommended for use in all current technology assessment reports being
done as part of EPA's industrial boiler systems study. Consequently, no credit
has been allowed for possible cost savings associated with dry material handling
and disposal. Possible income from sale for byproduct uses has not been
considered. The unit cost value is used to determine total annual disposal
cost and includes amortized capital associated with land purchase, disposal
site preparation, and necessary offsite equipment. Transportation and necessary
labor are also included.
Coal costs do not include transportation to be consistent with other
/ '
technology assessment reports. Transportation cost was included in the lime-
stone purchase cost since this is a cost specific to AFBC technology.
V
Since all of these costs can vary considerably from site to site depending
on transport distance, coal and sorbent type, and waste disposal requirements;
the impact of that variation is estimated in the cost sensitivity analysis
in Subsection 4.3.8.
Overhead costs (payroll overhead and plant overhead) have been included
and cover services such as administration, safety, engineering, legal, medical,
payroll, benefits, recreation, and public relations. The values are:
Payroll overhead = 30 percent of operating labor
Plant overhead = 26 percent of labor and materials
Equipment and installation costs, expressed as annualized capital charges,
are calculated by applying an appropriate capital recovery factor. To
facilitate comparison with the estimates made by PEDCo for conventional
boilers, an expected rate of return of 10 percent and life expectancy of 30
years were selected.
214
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Modified and reconstructed facilities are not considered in this cost
analysis. The economics of such installations are not certain and could be
misleading if presented on a generalized basis. The cost of retrofit is
highly dependent on site-specific conditions.
4.2.3 Specific Vendor Quotes
Several vendors were contacted to request capital and operating cost
information for FBC industrial boilers. Vendors contacted included
Foster-Wheeler,11* Babcock & Wilcox,15 Babcock & Wilcox, Ltd (England),16
Johnston Boiler,17 Energy Resources Company,18 and Combustion Engineering.19
Cost information for the four standard AFBC boilers has been received from
three vendors, referred to here as Companies A, B, and C.* The information
from Companies A and B was used by GCA to develop cost estimates for AFBC
boiler plants according to the format recommended by PEDCo. The latter vendor
quote was received late in the study and was used only as an internal check of
the values presented later. Subsection 4.2.3.4 discusses the results of this
comparison.
4.2.3.1 Company A— Basis of FBC Boiler Costs —
Capital and operating cost data were provided for AFBC boilers of the
following capacity:
8.8 MWt (30 x 106 Btu/hr) - full shop fabrication
2 MWt (75 x IQ6 Btu/hr) - field erection of shop fabricated modules
44 MWt (150 x 106 Btu/hr) - full field erection
58.6 MWt (200 x io6 Btu/hr) - full field erection
*
The vendor quotations are treated anonymously due to the major additions and
alterations which were necessary to adjust the costs to comply with the costing
format recommended for this study. In the final analysis, the basic boiler cost
is only a small part of the total annual system cost.
215
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Company A noted that the smallest capacity boiler was below the range that they
intend to build so that this cost will not be presented here. Capital costs
were quoted to include the following equipment (the limits represent that
equipment a boiler manufacturer would normally provide):
1. FBC cells
2. Steam generation pressure system parts
3. Flue duct dampers
4. Underbed plenum
5. Air heater and/or economizer
6. Refractory insulation and lagging
7. Structural steel
8. Platform stairways, rails, etc.
9. Ignition system
10. Valves and trim
11. Forced draft fan and motor drive
12. Induced draft fan and motor drive
13. Overbed fuel feed system
14. Limestone injection system
15. Bed material extraction and cooling system
*
Experimentation by FluiDyne (see Section 7.0) has shown comparable high
efficiency SC>2 removal for both in-bed and above-bed fuel/sorbent feeding
systems (in their 18 in. x 18 in. unit) when primary recycle is practiced.
This result is observed despite the fact that, in an overhead feed system,
some SC>2 may be released above the bed and, thus, not have a full residence
time within the sorbent bed. Therefore, the cost of the overhead type of
feed system should be consistent with achieving "best system" SC-2 control,
using the same Ca/S ratios that would be projected assuming that all of the
S(>2 is released near the bottom of the bed. The cost sensitivity analysis in
Subsection 4.3.8 indicates an added total system cost of $0.40/106 Btu output
if capital cost is underestimated by 20 percent. This should encompass the
added cost of an in-bed fuel/sorbent feed system. However, it is not anti-
cipated that in-bed feed is necessary, as long as primary recycle of elutriated
sorbent/char is practiced.
216
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16. Control and safety system
17. Mechanical collection system
18. Fly ash reinjection system
19. Steam coil air heater
20. Instrumentation
The quote does not include the following equipment:
1. Foundation
2. Motor control center
3. Instrument control panel
4. Intermediate wiring and tubing
5. Building
6. Bulk material plant receiving (coal, oil, limestone)
7. Storage bunkers, (coal, limestone, residue)
8. Auxiliary fuel storage
9. Boiler feed water treatment
10. Boiler feed water pumps
11. Spent material (residue) transfer
12. Stack
13. Intermediate piping and valves (including feed water
control valve)
Representative operating conditions associated with the FBC boilers
provided by Company A are:
• Steam Pressure: 100 to 1,000 psi, increasing with
boiler capacity
• Fluidization Velocity: 6 to 8 ft/sec
• Approximate Expanded Bed Depth: 3 ft to 4 ft
• Approximate Gas Phase Residence Time: 0.4 to 0.67 sec
• Excess Air: 20 percent
217
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This vendor noted that Ca/S molar feed ratio would have negligible impact
on cost of equipment provided for each boiler.
4.2.3.2 Company B - Basis of FBC Boiler Costs—
Company B quoted capital equipment costs for a shop fabricated AFBC
boiler of 8.8 MW (30 x 106 Btu/hr) capacity. A complete boiler unit
includes;
1. FBC cell
2. Under bed plenum
3. Ignition system
4. Coal feed hoppers
5. Limestone feed hoppers
6. Coal and limestone variable speed above-bed screw feeders
7. Flue duct dampers
8. Steam trim
9. Feedwater regulator
10. Forced draft fans and drives
11. Induced draft fan and drives
12. Instrument and control panel
13. Primary particulate control equipment with
reinjection
14. Stack and transition
15. Materials feed bins
Coal-fired boilers provided by Company B typically operate with a fuel to
steam efficiency between 81 to 83 percent. Design steam pressure for the
unit quoted is 150 psi. Steam is produced at a rate of approximately 11 350
kg/hr (25,000 Ib/hr). Excess air is typically in the range of 20 percent.
218
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This company is planning to use limestone with a particle size distribution
of 85 percent >1190 ym (16 mesh) and a top size of 2380 ym (8 mesh). Expanded
bed depth is approximately 0.84 m (32 to 34 in.). Gas phase residence time
is about 0.45 sec based on a superficial velocity of 1.8 m/sec (6 ft/sec).
The items included in these two listings are different, reflecting the
fact that Company B is providing completely shop fabricated systems. Company
A's systems are larger and require partial or complete field erection so
that certain items such as the stack and instrument control panel are
considered as extra equipment.
4.2.3.3 Other Capital Costs—
To supplement and complete the cost estimates provided by Company A
and B, the following equipment costs were based on data supplie' to PEDCo
for conventional boilers:
• Stack (Company A only);
• Boiler feedwater treatment and circulation equipment; and,
• Coal handling.
Costs for materials handling equipment (limestone, spent solids, and
ash) were estimated based on correspondence with other vendors.20"23
4.2.3.4 Company C - Cost Estimates
Capital cost estimates for the two larger AFBC boilers (44 and 58.6 MWt)
were received from a third vendor, but at a late juncture in the preparation
of this report. The costs were adjusted to include all necessary auxiliary
equipment, direct and indirect installation, and contingencies, for consistency
with the procedures used in this report. Total capital charges were between
10 and 25 percent lower than those reported in the following analysis. Capital
costs were annualized and added to direct operating costs and overhead. The
resultant total annual charges for vendor C were 5 to 7 percent lower than the
219
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AFBC costs estimated based on Company A information. We elected to consider
this third estimate only as a check on the data developed in the detailed cost
analysis which follows.
4.2.4 Other FBC Boiler Cost Estimates
Westinghouse Research and Development is currently preparing a study
entitled "Effect of SC>2 Emission Requirements on Fluidized-Bed Boilers for
Industrial Applications: Preliminary Technical/Economic Assessment." The pre-
liminary results of their cost analyses are included in Subsection 4.3.7.1.21*
Westinghouse used the cost basis defined in this study but based costs on in-
house information and sources other than boiler vendor quotes.
Other reports on industrial FBC boiler costs have been reviewed
for comparative purposes. These include reports by EXXON,25 and A.G. McKee.26
The detailed cost assumptions used in these reports are noted in Appendix B.
Some adjustments were made to the estimates to attain comparability with the
basic assumptions used in this report. A description of these adjustments
also appears in Appendix B. These costs, as adjusted are shown in terms of
$/106 Btu in subsection 4.3.7.2. They are compared with our estimates based
on quotes by Companies A and B.
4.3 COST ANALYSIS FOR IMPLEMENTING BEST SYSTEM OF SOz CONTROL
Derivation of the cost of AFBC purchase and operation with S02 control
required use of a two-tiered approach. The costs which are independent of
(but not necessarily divorced from) the three optional control levels (stringent
intermediate, moderate) on which the study is based represent the first
tier. These basic costs which are assumed to vary only with boiler capacity
and coal type are presented in Appendix A, Tables A-l through A-12. The
second tier is composed of those costs which vary as a function of S02 control
220
-------
level, and sorbent reactivity, in addition to coal sulfur level and boiler
capacity. The costs which are dependent on the degree of sulfur dioxide
retained are presented in Appendix C, Tables C-20 through C-24. While the
summation of these costs represents total cost of operation of an AFBC with
S02 control, the first tier of costs is not intended to represent the cost of
an uncontrolled AFBC boiler. This procedure was followed solely for ease of
computation in estimating the cost of AFBC operation under the several options
considered in this report.
The second tier of costs Includes the following components:
• Capital costs
- Limestone storage, conveying, and
screening
Spent solids/ash conveying, and
storage
• Operating costs
Limestone purchase
- Spent solids/ash disposal
Electricity for operation of all auxiliary equipment
(excluding building utilities such as lighting, heating,
ventilating, and air conditioning)
4.3.1 Capital Costs
Limestone handling capital cost assumes a storage bin capacity for 14 days
at full load. Double screening and pneumatic conveying equipment is also
necessary. Limestone crushing is performed at the quarry. Limestone feeding
capital cost was included in the basic AFBC boiler costs (Appendix A, Tables
A-l through A-12) because no significant cost variation with respect to
control level or sorbent reactivity is anticipated.
221
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The major equipment items necessary for spent solids handling are a
storage bin (10 days capacity at full load) and pneumatic conveying. Capital
cost of spent solids withdrawal and cooling should only vary significantly as
a function of boiler capacity and coal feed rate, and is included in the
boiler costs developed in Appendix A. The spent solids handling costs presented
as part of the SC-2 control cost do not include capacity for particulate matter
collected in the final particulate control device. (The incremental cost for
elutriated fines handling is presented in the discussion of particulate control
costs.) Equipment was sized for SC>2 control by assuming 90 percent of all
sorbent and ash which enter the^FBC combustor are removed at the spent solids
withdrawal point. The particulate matter downstream of the primary cyclone then
ranges between 365 and 1850 ng/J (0.85 to 4.3 lb/106 Btu) which is within the
envelope of experimental results discussed in Sections 2.0 and 3.0 of this
report.
Volumetric limestone and spent solids storage requirements were estimated
using hourly processing rates derived from material balance considerations.
As discussed above, a factor of 0.9 was applied to the spent solids rates to
determine storage requirements for S02 control. Capital cost estimates were
prepared based on correspondence with several equipment vendors. Storage bins
account for about 80 percent of total materials handling capital cost. They
include ancillary equipment such as dust control equipment, feed and exit ports,
access ladders, etc. They are assumed to be fabricated of 0.64 to 0.95 cm
(1/4 to 3/8 in.) carbon steel.27 Below 283 m3 (10,000 ft3) capacity, units are
shop fabricated and delivered to the site.28 Above this capacity, field erection
is required. For shop fabricated limestone storage bins, a variable unit cost
ranging from $353/m3 ($10/ft3) down to $282/m3 ($8/ft3) was applied as storage
222
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capacity increased.29 Above 283 m3 (10,000 ft3), the estimated cost for field
erection is $383/ra3 ($ll/ft3) to provide a limestone bin, equivalent to a shop
fabricated bin in stage of completion.30 (This accounts for added field labor
costs and contingencies.)
Slightly higher unit costs were used for spent solids storage to account
for any incremental cost incurred due to the higher temperature of the waste
material (such as: added wall thickness, wall linings, etc.). For shop
fabrication, unit costs of $392/m3 ($11.10/ft3) ranging down to $304/m3
($8.60/ft3) were used. For field erection of units above 283 m3 (10,000 ft3),
a unit cost of $431/m3 ($12.20/ft3) was applied.
The cost of remaining capital equipment items for sorbent and spent solids
handling was generally estimated in proportion to storage costs. A factor of
$4.40/kg/hr ($2.00/lb/hr) of limestone feed capacity was added to account for
screening equipment (i.e., $6,600 for screening if estimated limestone require-
ments are 1500 kg/hr (3300 lb/hr)). A factor of 10 percent was added to this
subtotal to account for pneumatic limestone handling equipment. A factor of
15 percent was added to spent solids storage cost to account for pneumatic
spent solids handling equipment. To determine total installed capital cost of
materials handling facilities, 35 percent was added for direct installation cost,
30 percent was added to total direct cost to estimate indirect installation
requirements, and 20 percent was added to total installed costs for contin-
gencies (see Table 31; engineering, construction and field expenses, contractor's
fee, and contingencies).
223
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4.3.2 Operating Costs
Annual operating costs are based on a load factor of O.6.* Limestone
purchase and spent solids disposal are based on the following unit costs:31
• Limestone purchase - $8.82/106 g ($8.00/ton) FOB plant
• Spent solids disposal - $44.10/106 g ($40.00/ton) offsite
The limestone purchase unit cost includes delivery to the FBC plant site. The
spent solids disposal unit cost is based on a transport distance of 20 miles
to the disposal site. The cost includes all necessary operating costs and the
amortized capital cost of land and equipment.
Electricity required for operation of all auxiliary equipment is shown
in Table C-24 as a function of boiler capacity, coal type, S02 control level,
and sorbent reactivity. Annual electricity costs are included in the total FBC
cost estimate by assuming a unit cost of 2.58c/kWh.
The costs presented subsequently in terms of $/106 Btu output are based
on the boiler efficiency ratings estimated in Section 5.0.
4.3.3 Cost^ of Best Systems of SOg Control
The incremental costs discussed in Subsections 4.3.1 and 4.3.2 are itemized
in Appendix C in Tables C-20 (Total Turnkey Cost of Limestone Handling and
Storage), C-21 (Total Turnkey Cost of Spent Solids Handling and Storage), C-22
(Annual Cost of Limestone Purchase), C-23 (Annual Cost of Spent Solids Disposal),
and C-24 (Annual Cost of Electricity). The corresponding cost associated with
uncontrolled conventional boilers is also shown.'''
*
The relationship between AFBC system cost and plant load factor is shown in
Figure 47 in Subsection 4.3.8.4.
Throughout this chapter, the cost of uncontrolled conventional boiler systems
or components is based on the results of the PEDCo cost study.32
224
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Table 33 presents the total annual cost of AFBC industrial boilers using
the "best system" of S(>2 control as identified in Section 3.0, (i.e., gas phase
residence time of 0.67 sec, bed depth of 1.2 m (4 ft), superficial gas velocity
of 1.8 m/sec (6 ft/sec), and inbed average sorbent particle size of 500 ym) in
comparison to the cost of uncontrolled conventional boilers. Annual cost is
shown as a function of boiler capacity, coal type, SC>2 control level, and sor-
bent reactivity. The range of Ca/S ratios listed are from Table 22, developed
as shown in Section 7.0.
Table 34 lists the annual cost of AFBC and conventional boilers in terms of
$/106 Btu output, accounting for the effect of boiler efficiency on system cost.
The AFBC costs are summarized in Figures 30 through 32.*
The figures show fixed annual costs, annual operating costs, and total
annual costs (the sum of the initial two costs) and represent use of a sorbent
with average reactivity. Error bands are included for fixed and total annual
costs to illustrate the effect of the estimated accuracy in capital cost esti-
mates of ±30 percent, which is generally the limit for budget equipment estimates.
This range is conservative considering that some of the FBC equipment and instal-
lation components were estimated based on PEDCo cost data. Therefore, an in-
accuracy would be duplicated for certain pieces of equipment in conventional
and FBC systems, and the relative comparison of the two technologies would not
be affected by these inaccuracies.
Since many of the direct operating costs have been estimated equal for the
two technologies (e.g., coal purchase, the unit cost of solid waste disposal,
labor, maintenance overhead, chemicals, and process water), no error bands have
been assigned to annual operating cost. The conservative estimate of accuracy
Although continuous curves are shown, interpolation to other capacities is
not recommended. This graphical method was selected to illustrate the economy
of scale possible in going to larger boiler capacities.
225
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TABLE 33. ANNUAL COST OF INDUSTRIAL FBC BOILERS WITH S02 CONTROL, DOLLARS
HOlLfc> C«^AL I ? V-Mtft
SoL^ IJW LI IN t KUL
r*t *(.»• "il Abfc KKttl. 11 VI T * Hfl 1 10 CONVtwI IHNAL Af-MC C UN VENT IUNAL Af bC Cl'NVt'^T iJfMAL A* K LU
wf-UUCI ION
f Ah 1 1 K'* H I I,M ,S **UX A vl- KAI.e S.S ^ J HIGH r*.i ^«?/uM. ybai'iy. IH^hO'i^.^ibSOfai. io«« i / /. ih^^h^a.
1 nSi AVt kalit ^.^ 9<» /o7 1 . £>Hl^tt'J. !He?bOa9. ^^^/li4*. iUU«l / /. i/HSO'ir'.
MlbM £?.! V^/u/1. 9bb4|(j. 18|?t>UU9. «?|rth4'»i. iiJia 1 7 / . ihS^cV.
i
?-' /rt.7"4 M«tW*i(jf c*.S *^ ^ / 0 M « ^bT^^rt. IH^tjtJUQ, ^14.4blc). 5 0 <4 M 1 / / . A / 1 1 ? ' > ^ .
ILIA S,M ^^7vi/1. 9l)bU S9 . lH^bU**9, r'^hOS 1 e* . ^UU«177. i^S^r'.Su .
!^? Li."1 l.i? ^^/O/l. ^^IbOi, lb?bOU9. <*OtUJh.ii, .SOu*4l/7. iab^/'jft*
QV Hlt,n u. M *>/^ / 0 7 1 . ^Ort /*>/?. lH^hl)a9./i. inaUl/7. ^SM^'J'iH.
^ 7S* /\vt«Aot f*./1 **r* 1 1 1-^. 401lhrt. lftifa <'>r / .
ao SS7 lr-. MS 7 1 -^ ! .
iKi'j^lr1. .m.vi'MS.
'"i'X i, . Uh J IS',.
'411 SS7 i r1 . •* In / ,'\S .
'11' iS7 1,-. J1". s»". , .
a.'5',7i^. 'ju in •,,>(.
-oSSMr. -4 4S -,--;•,.
>l 1 ^r.luS. .|.,-1 i a" .
<• 1 ut-'.uS. .1 i / /i-VS.
•11 «h'i'4S. 1 S- SI-.'-.
,i ! ani-'.s. -iv-'-.
'
Note: Conventional Boilers shown here contain no provisions for S02 control. This comparison was
made according to the groundrules of the industrial boiler system study. If costs of S02
control are included AFBC becomes more competitive.
-------
TABLE 34. ANKUAL COST ($/106 Btu OUTPUT) OF INDUSTRIAL FBC BOILERS WITH S02 CONTROL
N)
NJ
COAt lYPt
tASIEHn HIGH
SULKJi*
li.b* S)
SULHJ*
(0.9* S;
SO a L".:;( Ih--M ,-.!-.,(
Mt DUE MUM
3 90* AVlHAGt 3.1 / . S'» /./S S./t. o.So it , 7 / S.''l u.'it. j.'.V
LU« «.2 /.i'( h.i/y S./o /.^« n,n n.\i i.',. 'j.'-y
HIGH ^.J /. *'• I. --tit S./h ^.h6 u. // •,.,,.. I'.T: '>.(*•
1 BSX AVfHAGt rf.1* '.4'' /.f>!• '>.'>••
LO* 3.8 /.*" '.^1 S.7t, f.lb «.7/ r,..,f, ^.',n ', . r«,
HIGH /?.J /.•><' '/ . »•> S.^fa o.Blf 4.77 S.'j.i .i.Sr, S,SI
•* /8.7I AVLWAtf ^.S '.4'' 7.urt S./o B./r1 -J./7 S.f>S -i.Si S.u»
LUft i.O /.J1' '.71 S.^ft 6.VV 'i./7 S.i<> u.Si- 'j.7i
HIGH 1. 8 / . V* /.r'o S.76 h.St •"' •>.«•!» 1./7 S.iS u.s-. u.ys
LUA l.i? '.V 7.U« S./o t!..i| .i.;/ s.c1! u.Sr, S.'il
HIGH 0.8 '.4y U-4i ''.7l> ^J.IV n.ll ',.J,, .4.Sr. 11.'.;.
S/I Bi.<»* AveKAGt i.« '.!«• ''•"' ">.»<' «.«;l «./u S.l> n.'.S «.-Ji
LUA 1.7 ' . 1 •' n.-^i s..6£> «,.,)/ 11. /n S.I" i.S^ ..-•<
HIGH ^.0 '.!£ O.Ht1 '>.»»• n.lh u.7'i S.HP u . v> ••./•"
M 7^>X AVkUAGt ^.i 7 . l / h.Mi *>.to«' r» . 1 7 u,7n s . 1 1, u.Sl> •..'-<-.
10* i.i /.it' o.'(U ^.bi> f>.i?n j.7n b.ln u. ss ••.'•f
HIGH l.b /.lr> b.f't S.b? h.li rt./O ^..le- >i.V> 'I.H^,
S/I Si..'* AVtKAGl i.7 7. '11 e.7J 'j.i'i b.Bh 'i . 7 i «./s 14 . S / u.Si
LU* l.b '.Jl o./l S.'jU b.^3 'i.7* u.r: M.sf . 7u S.^M S.hi u./t u./l n . ', / <..,,>•
LU* S.i /.ui ft. 77 b»'.>*l S.^l «.7^ ".II a.S' -4.S-.
HJGH 1.6 /.ul b.ob •>.•>« S.ru u.7» u.ft- '..'./ •« . u .
Note: Conventional Boilers shown here contain no provisions for S02 control. This comparison was made
according to the groundrules of the industrial boiler system study. If costs of S02 control are
included AFBC becomes more competitive.
-------
Q.
H
O
3
*-
CD
0
O
-------
BOILER CAPACITY, I06 Btu/hr INPUT
30 75 ISO 2OO
o.
i
u
ui
2
UJ
% 3
EASTERN HIGH SULFUR COAL
STRINGENT S02 CONTROL
EASTERN LOW SULFUR COAL
STRINGENT OR INTERMEDIATE
S02 CONTROL
- EMS
SUBBITUMINOUS COAL
MODERATE S02 CONTRO
B.B
22 44
BOILER CAPAClTY.MWt
sae
Figure 31. Total operating cost of AFBC with S02 control.
229
-------
BOILER CAPACITY, I06 Btu/hr INPUT
30 75 ISO
200
I
o
8
EASTERN HI«H SULFUR COAL
STRINOENT S02 CONTROL
EASTERN LOW SULFUR COAL
STRINSENT OR INTERMEDIATE
S02 CONTROL
~ 7
en
O
o
u
h-
V)
V)
COST FOR
UNCONTROLLED
CONVENTIONAL
h iOILERS
\
SUBBITUMINOUS COAL
MODERATE, S02 CONTROL
ERROR LIMITS
FOR TOTAL
ANNUAL COST,
ALL LEVELS OF
»02 CONTROL
EXCLUDINtt SIP
8.8
22 44
BOILER CAPACITY, MWt
58.6
Figure 32. Total annual cost of FBC with S02 control,
230
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assumed for the capital costs should account for the possible errors in lime-
stone purchase or electricity requirements. Therefore, the error bands shown
on the graph of fixed annual cost (capital charges) have been translated
directly to the graph of total annual cost. The error band heights are 0.70
to 0.80 $/l06 Btu, both positive and negative for total annual FBC cost. This
is about 9 percent of total cost for the 8.8 MWt AFBC boiler burning Eastern
high sulfur coal at a stringent S02 control level, and increases to a maximum
of 15 percent for the 58.6 MWt AFBC boiler burning subbituminous coal.
System operating costs drop off significantly as boiler capacity increases
due partially to increasing boiler efficiency. A second reason is the underlying
cost of labor and overhead. These costs do not increase directly with boiler
capacity since there is some minimum staffing and overhead requirement for the
small boiler capacity which increases slowly in proportion to boiler capacity.
Two conclusions are drawn from the graph of total annual cost. First,
FBC with stringent SC-2 control firing high sulfur coal is about 20 percent more
expensive that use of uncontrolled conventional boilers. The only exception
is in the cost of the 8.8 MWt boiler where system costs are very similar, the
AFBC is only about 7 percent more costly than the uncontrolled conventional
boiler. The small AFBC boiler has a relatively low capital cost because of its
simple, space saving, package design. It is based on a cost quote from one
vendor that is starting to penetrate the commercial market. However, it can
be argued that the cost is slightly underestimated for the purpose of marketing.
If the 30 percent capital error band is factored in and the conventional costs
are assumed to be accurate, the maximum added total cost of the controlled
8.8 MWt FBC over the uncontrolled conventional system is 15 percent. The
actual cost differential probably falls within the range of 5 to 15 percent.
231
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The second conclusion is that the difference in cost between stringent
S(>2 control with high sulfur coal and moderate S02 control with subbituminous
coal is roughly 1.10 to 1.40 $/106 Btu output. If the error bands are considered,
this margin widens to a maximum of 2.70 $/106 Btu.
4.3.4 "Commercially-Offered" AFBC Industrial Boilers Versus
"Best Systems" of S02 Control
Atmospheric fluidized-bed combustion is am emerging technology, and design/
operating parameters currently specified by FBC vendors are generally different
than those specified in this report for "best system" design. The principal
differences relating to SC-2 control performance include gas phase residence
time and sorbent particle size in the bed.
It is important to note that the phrase "best system" as used in this
report, refers to design/operating conditions selected by GCA to minimize sor-
bent use, spent solids generation, and provide the low cost approach to con-
trolling S0£ in FBC. It is not intended to denote that one vendor's design is
superior to another or that current technology is far removed from the recom-
mended conditions.
The increase to "best system" gas phase residence time of 0.67 sec
(commercial systems operate at roughly 0.5 sec and below) can be achieved by
using either deeper beds or lower gas velocities. Deeper beds require increased
furnace height while lower gas velocities require larger furnace cross section.
Either modification is achieved at the expense of increased capital investment.
Although these capital cost increases would result, the additional expend-
iture may be recovered by reduced capital requirements elsewhere. For instance
increasing the bed depth sufficiently will allow design of natural circulation
boilers instead of forced convection boilers, thus eliminating recirculation
pumps. Shallow beds do not allow enough slope in the steam tubes for natural
232
-------
convection. In addition, lower superficial velocities may result in a capital
cost savings in primary particulate control through reduced bed elutriation.
It is expected that lower operating costs should recover any added capital
expenditure associated with increased gas residence time. Reduced sorbent and
coal requirements, lower maintenance through elimination of convection pumps,
and less abrasion of internals such as steam tubes and cyclones are all areas
where savings could occur. Except for reduced sorbent cost, these savings
cannot be quantified until AFBC is demonstrated in commercial operation.
As mentioned, Wescinghouse Research and Development is conducting an
engineering evaluation of industrial fluidized-bed technology. The study
will assess the net cost and performance impact of implementing "best system"
design/operating conditions.
The Babcock & Wilcox Company has estimated the effect of three different
superficial velocities on cost in terms of $/kW.33 As illustrated by Figure
33, the lowest velocity results in the lowest capital cost, coal cost, and
limestone cost. Although these estimates were developed for utility applica-
tions, the relative proportions should hold true for industrial applications.
Reduction of limestone particle size to the recommended in-bed average
of 500 ym can provide similar, and possibly greater, operating cost savings
than noted for the lengthening of gas residence time. The data presented in
Sections 2.0 and 3.0 illustrate that limestone consumption can be reduced by
at least 20 percent if average in-bed sorbent particle size is reduced from
1,000 ym to 500 ym. The difference is even greater for sorbents of low reac-
tivity. In several cases, vendors are specifying limestone feed particle sizes
of greater than 1,000 ym, possibly as high as 1,500 ym. One uncertainty is
that the relationship between feed sorbent size, and the actual size that exists
233
-------
i CAPITALIZED DIFFERENTIAL COST OF LIMESTONE
CAPITALIZED DIFFERENTIAL COST OF COAL
CAPITAL EQUIPMENT COSTS
tn
O
o
<
o
1.2 (4) 2.4(8)
SUPERFICIAL VELOCITY, m/sec (ft/s«c)
3.7(12)
Figure 33. FBC cost variation as a function of superficial
velocity, after Babcock and Wilcox.
234
-------
in the bed, is not rigorously predictable. Therefore, although vendors may be
quoting mass mean particle sizes of 1,000 to 1,500 pm for the sorbent feed, the
actual size which might exist in the bed could be much closer to the 500 jam
surface mean which is considered for the "best" system.
Incremental costs which could result from using smaller sorbent particles
include the added unit cost of sorbent (in the form of increased purchase cost
or onsite screening facilities), any added cost of primary particle control,
and any added maintenance requirements.
If particle size is reduced, there may be savings in the cost of primary
and final particulate control equipment since the amount of sorbent is decreasing
at the same time that the proportion of elutriated bed material is rising.
Westinghouse has formulated projections of elutriated solids loadings from
atmospheric FBC as a function of Ca/S ratio based on Greer limestone.31* in the
atmospheric case, lowering the Ca/S ratio from 5 to 2 resulted in a 45 percent
reduction in solids elutriated from the bed. This implies that fine particle
elutriation can increase (as a result of particle size reduction to reduce
sorbent needs) some measurable amount before the cost of primary particulate
control increases significantly. Further experimentation is required to deter-
mine where this breakpoint exists.
Any significantly increased maintenance costs resulting from sorbent size
reduction would be in the form of replacement part costs for abraded internal
equipment. The magnitude of this added cost, however, is anticipated to be
small in comparison to overall plant cost, but must be confirmed in commercial
operation.
Again, it is emphasized that, in order to maintain a surface mean sorbent
size of 500 jam in the bed, it may not always be necessary to reduce feed sorbent
235
-------
particle size significantly from the 1,000 to 1,500 urn mass mean feed size
specified by many vendors.
Based on the foregoing discussion, the most readily quantifiable difference
in cost between "commercially offered" and "best system" is sorbent purchase.
The cost of "commercially-offered" systems is estimated here using the results
of the cost sensitivity analysis and estimates of sorbent requirements based
on the Westinghouse 862 kinetic model. Changes in Ca/S ratio, as projected
using the Westinghouse model, are reported in Section 3.0 considering the
"commercially-offered" systems and several different sorbents. As shown in
Table 21, significant reductions in required Ca/S ratio may be possible by
increasing gas residence time and reducing sorbent particle size, according to
the model projections.
Depending on limestone type and reactivity and S02 control level, Ca/S
ratios are noted to rise to above 10 in Table 21, a value which would not be
used in practice. A Ca/S ratio over 6 or 7 may be economically uncompetitive
due to added operating cost (see Figure 34) and losses in boiler efficiency.*
The effect of increasing Ca/S ratio on annual operating cost is shown in
Figure 34. A detailed discussion of the method of calculation is given in
the sensitivity analysis (Subsection 4.3.8). Briefly, cost estimates were pre-
pared for "best systems" using the cost basis described previously. Then,
baseline design/operating conditions were selected (see Table C-3) and single
parameters, such as Ca/S ratio, were varied individually to assess their impact
on FBC system cost. The sensitivity cost curves for Ca/S ratio are linear as
shown in Figure 34, and show an added cost between 35 to 37 C/106 Btu output for
fc
The energy sensitivity analysis presented in Section 5.5 of this report indicates
that as Ca/S ratio exceeds a value in the range of 5.5 to 6.0, the efficiency of
an AFBC boiler drops below that of an uncontrolled stoker (see Figure 52).
236
-------
II
10
a.
O 9 -
to
o
CO
o
u
8
u
CD
6
BASELINE ANNUAL FBC COSTS (a) Co/S = 3.5
8.8 MWt - 7.79
ZZ MW» " 7.O5
44
I
468
Ca/S MOLAR FEED RATIO
8.8 MWt
22 MWt
10
Figure 34. AFBC cost as a function of Ca/S molar feed ratio.
(All other design/operating parameters constant).
237
-------
incremental increases of one in Ca/S ratio. If Ca/S ratios as high as 6 or 7
are used for stringent control, then a loss of $1.00/10° Btu output or more is
incurred for any capacity, in comparison to "best system" design. It is empha-
sized that the curves in Figure 34 do not include any cost penalties for in-
creases in boiler size, or increases in particle control requirements, etc.,
that might be incurred when FBC design operating conditions are adjusted to
obtain the reduced Ca/S levels, since other design/operating conditions have
been held constant at "best system" conditions. The figure shows only the cost
savings that could be expected if sorbent feed rate could be reduced without
such penalties. Changes which are accounted for include changes in boiler
efficiency, yearly sorbent purchase cost, annualized sorbent and spent solids
storage costs, spent solids disposal cost, and power cost for limestone and
spent solids handling.
As an example, consider the Georgetown AFBC boiler. Table 21 in Section
3.0 illustrates that the Ca/S ratio might fall from 5.29 to 2.85 (Greer lime-
stone, stringent S02 control) if "best system" design/operating conditions are
used, as projected using the Westinghouse model. Based on the sensitivity
analysis shown in Figure 34 this could result in a cost reduction of $0.90/106
Btu. However, considering the uncertainty of other operating and capital cost
changes that could result in adjusting the Georgetown design to achieve "best"
conditions, it is fair only to conclude that these other costs could increase
by $0.90/106 Btu before modification to "best system" conditions would not be
cost effective for the Georgetown design. A similar conclusion could be drawn
for other specific designs and limestone types.
As an added point, consider the 8.8 MWt FBC boiler burning high sulfur
coal. A 20 percent reduction in limestone use would reduce annual purchase
238
-------
cost by roughly $4,000 for any control level other than the average SIP level
of 56 percent. This operating savings can be translated to an increased capital
cost allowance. The present worth of this annual cost over 30 years (to be con-
sistent with boiler life expectancy) at an interest rate of 10 percent is
$38,000. This value is 15 percent of the cost of boiler equipment for the 8.8
MWt boiler and indicates the approximate capital equipment cost increase which
can be accommodated with no concomitant increase in the annual cost of steam
production because of operating cost savings.
4.3.5 Cost Comparison; AFBC "Best System" Designs Versus Conventional
Boilers Without SOg Emission Control
The goal of this cost study is to compare the total cost of controlled
FBC with uncontrolled conventional boilers so that the incremental cost of
using FBC as a boiler system controlling S02 emissions can be isolated. Similar
documents are being prepared by other contractors to estimate the cost of other
S02 control technologies with the same conventional boiler costs as a basis.
These technologies include flue gas desulfurization, coal cleaning, oil cleaning,
and synthetic fuels. A future study by EPA will compare the cost of S02 removal
using FBC and the other technologies based on these documents.
The preceding subsection introduced the comparison of uncontrolled conven-
tional and controlled FBC industrial boiler cost. The intent of this subsection
is to present a more detailed analysis indicating cost differences which exist
as a function of sorbent reactivity, S02 control level, and coal type. These
data are itemized in Tables 35 through 38 and are depicted graphically in Figures
35 through 37. Tabulated costs are shown in terms of $/106 Btu output, $/J/sec
thermal input, and $/106 Btu/hr thermal input. The latter two cost parameters
are shown for consistency with guidelines established for all of the technology
assessment reports. The costs reported graphically are in terms of $/106 Btu
239
-------
TABLE 35, COSTS OF "BEST" S02 CONTROL TECHNIQUES FOR COAL-FIRED
AFBC BOILERS OF 8,8 MWt (30 x 1Q6 Btu/hr) CAPACITY
AFBC with
Standard boiler capacity
MWt (106 Btu/hr)
and coal characteristics
8.8 (30)
Eastern high
sulfur coal
(3.5% S)
8.8 (30)
Eastern low
sulfur coal
(0.9% S )
8.8 (30)
Subbituminous
coal
(0.6% S)
SOz control
SO 2
control
level and
percentage
reduction
S 90%
I 85%
M 78.7%
SIP 56%
S or I 83.9%
M 75%
S or I 83.2%
M 75%
Sorbent
reactivity
Average
Low
High
Average
Low
High
Average
Low
High
Average
Low
High
Average
Low
High
Average
Low
High
Average
Low
High
Average
Low
High
Ca/S
ratio
3.3
4.2
2.3
2.9
3.8
2.1
2.5
3.4
1.8
1.0
1.2
0.8
2.8
3.7
2.0
2.2
3.2
1.6
2.7
3.6
2.0
2.2
3.2
1.6
Tr\t~ A 1
local
S/106 Btu
output
7.75
8.04
7.42
7.62
7.91
7.36
7.48
7.78
7.26
7.00
7.06
6.93
6.87
6.93
6.82
6.83
6.90
6.79
6.73
6.79
6.69
6.70
6.77
6.66
a.nnu£tll.z6Q costs
$/J/sec
thermal
input
0.113
0.116
0.110
0.112
0.115
0.109
0.110
0.113
0.107
0.104
0.105
0.103
0.103
0.104
0.102
0.102
0.103
0.102
0.098
0.099
0.098
0.098
0.099
0.097
$/106 Btu/hr
thermal
input
33,200
34,100
32,100
32,700
33,700
31,900
32,300
33,200
31,500
30,500
30,700
30,300
30,200
30,400
30,000
30,000
30,300
29,900
28,800
29,000
28,700
28,700
28,900
28,600
Impacts
Percent increase
in costs over
uncontrolled
conventional
boilers*
7.4
10.4
4.0
5.9
8.9
3.2
4.4
7.4
2.0
-1.3
-0.6
-2.0
-1.7
-1.0
-2.3
-2.2
-1.4
-2.6
-7.4
-6.8
-7.9
-7.8
-7.1
-8.2
Percent increase
in costs over
SIP controlled
AFBC boilers
8.8
11.1
6.1
7.3
9.6
5.3
5.8
8.1
4.1
-
-
—
-
-
-
-
-
-
-
-
-
-
-
-
*Based on costs in terms of $/J/sec (S/106 Btu/hr) thermal input.
-------
TABLE 36. COSTS OF "BEST" S02 CONTROL TECHNIQUES FOR COAL-FIRED AFBC
BOILERS OF 22 MWt (75 * 10 6 Btu/hr) CAPACITY
AFBC with
Standard boiler capacity
MWt (106 Btu/hr)
and coal characteristics
22 (75)
Eastern high
sulfur coal
(3.5% S)
22 (75)
Eastern low
sulfur coal
(0.9% S)
22 (75)
Subbi.tumi.nous
coal
(0.6% S)
SOz control
SO 2
control
level and
percentage
reduction
S 90%
I 85%
M 78.7%
SIP 56%
S or I 83.9%
M 752
S or I 83.2%
M 75%
Sorbent
reactivity
Average
Low
High
Average
Low
High
Average
Low
High
Average
Low
High
Average
Low
High
Average
Low
High
Average
Low
High
Average
Low
High
Ca/S
ratio
3.3
4.2
2.3
2.9
3.8
2.1
2.5
3.4
1.8
1.0
1.2
0.8
2.8
3.7
2.0
2.2
3.2
1.6
2.7
3.6
2.0
2.2
3.2
1.6
$/106 Btu
output
6.96
7.28
6.66
6. 84
7.15
6.60
6.72
6.99
6.51
6.25
6.31
6.19
6.21
6.27
6.16
6.17
6.24
6.13
5.88
5.93
5.83
5.84
5.91
5.80
$/J/sec
thermal
input
0.103
0.106
0.099
0.101
0.105
0.099
0.100
0.103
0.097
0.094
0.095
0.093
0.094
0.095
0.093
0.093
0.094
0.093
0.087
0.087
0.086
0.086
0.087
0.086
S/106 Btu/hr
thermal
input
30,100
31.200
29,100
29,700
30,800
28,900
29,200
30,100
28,500
27,500
27,700
27,300
27,600
27,800
27,400
27,400
27,600
27,300
25,400
25,600
25,300
25,300
25,500
25,200
Impacts
Percent increase
in costs over
uncontrolled
conventional
boilers*
23.7
28.2
19.7
22.0
26.3
18.7
20.1
23,8
17.2
13.1
14.0
12.2
12,6
13.4
11.8
12.0
12.9
11.4
8.1
8.9
7.4
7.6
8.5
7.0
Percent increase
in costs over
SIP controlled
AFBC boilers
9.4
12.5
6.6
7.8
10.8
5.7
6.2
8.6
4.4
_
-
-
—
-
-
—
-
-
_
-
-
-
-
"
*Based on costs in terms of $/J/sec ($/106 Btu/hr) thermal input.
-------
TABLE 37. COSTS OF "BEST" S02 CONTROL TECHNIQUES FOR COAL-FIRED AFBC
BOILERS OF 44 MWt (150 x 106 Btu/hr) CAPACITY
ho
*-
NJ
AFBC with
Standard boi'er capacity
MWt (106 Btu/hr)
and coal characteristics
44 (150)
Eastern high
sulfur coal
(3.5% S)
44 (150)
Eastern low
sulfur coal
(0.9% S)
44 (150)
Subbituminous
coal
(0.6% S)
S02 control
S02
control
level and
percentage
reduction
S
I
M
SIP
S or I
M
S or I
M
90%
85%
78.7%
56%
83.9%
75%
83.2%
75%
Sorbent
reactivity
Average
Low
High
Average
Low
High
Average
Low
High
Average
Low
High
Average
Low
High
Average
Low
High
Average
Low
High
Average
Low
High
Ca/S
ratio
3.3
4.2
2.3
2.9
3.8
2.1
2.5
3.4
1.8
1.0
1.2
0.8
2.8
3.7
2.0
2.2
3.2
1.6
2.7
3.6
2.0
2.2
3.2
1.6
5/106 Btu
output
5.91
6.19
5.60
5.78
6.06
5.53
5.65
5.93
5.44
5.15
5.21
5.10
5.13
5.19
5.08
5.10
5.16
5.06
4.75
4.80
4.70
4.71
4.77
4.68
S/J/sec
thermal
input
0.088
0.091
0.084
0.086
0.089
0.083
0.084
0.088
0.082
0.078
0.079
0.077
0.078
0.079
0.078
0.078
0.078
0.077
0.070
0.071
0.070
0.070
0.071
0.070
$/106 Btu/hr
thermal
input
25,700
26,700
24,600
25,200
26,200
24,400
24,700
25,700
24,000
22,800
23,000
22,600
22,900
23,100
22,700
22,800
23,000
22,600
20,600
20,800
20,500
20,500
20,700
20,400
Impacts
Percent increase
in costs over
uncontrolled
conventional
boilers*
26.7
31.5
21.3
24.3
29.2
20.0
21.9
26.8
18.2
12.4
13.4
11.4
11.2
12.2
10.4
10.5
11.6
9.8
2.2
3.2
1.5
1.6
2.7
1.0
Percent increase
in costs over
SIP controlled
AFBC boilers
12.7
16.0
8.9
10.6
13.9
7.7
8.4
11.8
6.0
-
-
-
-
-
-
-
-
-
-
-
-
-
-
"
•*Dased on costs in terms of $J/sec ($/106 Btu/hr) thermal input.
-------
TABLE 38. COSTS OF "BEST" S02 CONTROL TECHNIQUES FOR COAL-FIRED AFBC
BOILERS OF 58.6 MWt (200 * 106 Btu/hr) CAPACITY
to
js
OJ
AFBC with
Standard boiler capacity
MWt (106 Btu/hr)
and coal characteristics
58.6 (200)
Eastern high
sulfur coal
(3.5% S)
58.6 (200)
Eastern low
sulfur coal
(0.92 S)
58.6 (200)
Subbituminous
coal
(0.6% S)
S(>2 control
S02
control
level and
percentage
reduction
S 90%
I 855!
M 78.7%
SIP 56%
S or I 83. 9%
M 75%
S or I 83.2%
M 75%
. , —
Sotbent
reactivity
Average
Low
High
Average
Low
High
Average
Low
High
Average
Low
High
Average
Low
High
Average
Low
High
Average
Low
High
Average
Low
High
Ca/S
ratio
3.3
4.2
2.3
2.9
3.8
2.1
3.4
3.4
1.8
1.0
1.2
0.8
2.8
3.7
2.0
2.2
3.2
1.6
2.7
3.6
2.0
2.2
3,2
1.6
.*. \j bo. 4. aiuiuo J. J, AiCU CUS L S
$/106 Btu
output
5.69
5.97
5.38
5.56
5.8A
5.31
5.43
5.71
5.22
4.95
5.01
4.90
4.93
4.99
4.89
4.90
4.96
4.86
4.51
4.56
4.47
4.48
4.54
4.44
S/J/sec
thermal
input
0.085
0.088
0.081
0.083
0.086
0.080
0.081
0.085
0.079
0.075
0.076
0.074
0.075
0.076
0.075
0.075
0.076
0.074
0.067
o.068
0.067
0.067
0.067
0.066
$/106 Btu/hr
thermal
input
24,800
25,800
23,700
24,300
25,300
23,500
23,800
24,800
23,100
22,000
22,200
21,800
22,100
22,300
21,900
21,900
22,100
21,800
19,600
19,800
19,500
19,500
19, 700
19,400
Impacts
Percent increase
in costs over
uncontrolled
conventional
boilers*
22.9
27.8
17.5
20.5
25.4
16.2
18.1
23.0
14.3
8.9
9.9
7.9
6.4
7.4
5.6
5.7
6.8
5-1
-1.8
-0.8
-2.5
-2.4
-1.3
-3.0
Percent increase
in costs over
SIP controlled
AFBC boilers
12 9
\. 4. , J
16.2
8Q
. 7
10.7
14.1
7.7
8.5
11.9
6.0
-
__
_ .
-
_
_
_
_
-
*Based on costs In terms of S/J/sec ($/106 Btu/hr) thermal Input.
-------
8
3
O
2 6
to
to
O
V)
O
O
O
00
4
BOILER CAPACITY, 10** Btu/hr INPUT
30 75 »50
200
UNCONTROLLED
CONVENTIONAL
BOILERS
STRINGENT
INTERMEDIATE
MODERATE
SIP
EASTERN HIGH SULFUR COAL
AFBC WITH S02 CONTROL
(AVERAGE SORBENT REACTIVITY)
EXTREMES IN COST CONSIDERING
FULL RANGE OF SORBENT
REACTIVITY
CONVENTIONAL BOILERS
WITHOUT CONTROL
8.8
22 44
BOILER CAPACITY, MWf
58.6
Figure 35. Cost comparison: AFBC boilers with S02 control versus
uncontrolled conventional boilers; Eastern high sul-
fur coal.
244
-------
8
O.
t-
3
O
00
u>
O
O
o
UJ
_J
O
to
30
BOILER CAPACITY, I06 Btu/hr INPUT
75 130
200
—I—
STRINGENT OR INTERMEDIATE
SOg CONTROL
UNCONTROLLED
CONVENTIONAL
•OILERS
MODERATE SOZ CONTROL
EASTERN LOW SULFUR COAL
AFBC WITH S02 CONTROL
(AVERAGE SORBENT REACTIVITY
EXTREMES IN COST CONSIDERING
FULL RANGE OF SORBENT
REACTIVITY
CONVENTIONAL BOILERS
WITHOUT CONTROL
8.8
22 44
BOILER CAPACITY, MWt
56.6
Figure 36. Cost comparison: AFBC boilers with S02 control versus
uncontrolled conventional boilers; Eastern low sulfur
coal.
245
-------
30
BOILER CAPACITY, IO°Btu/hr INPUT
75 150
200
8
O.
K
3
O
CD
-------
output because it is a more readily interpreted parameter. The cost curves
shown for the AFBC boilers represent average sorbent reactivity. Crosshatching
is included to indicate extremes in cost based on variation in sorbent reac-
tivity. Depending on the range considered, sorbent reactivity can have more
impact on cost than 862 control level.
Each figure represents one of the three different coals and illustrates
the expected result that FBC industrial boiler technology with S(>2 control is
generally more expensive than conventional uncontrolled industrial boiler
systems. The greatest difference is noted with high sulfur coal where the most
sulfur must be removed in the FBC system. The cost differential becomes smaller
with lower sulfur coals. In fact, the controlled 8.8 MWt FBC boiler has a com-
parable or even slightly lower total cost than the uncontrolled conventional
8.8 MWt boiler. This low cost results principally because of the small addi-
tional capital and operating cost associated with limestone use and spent solids
handling when low sulfur coals are burned in FBC boilers. The difference also
may be a function of the use of cost quotes from separate sources. The effect
of inaccuracy in boiler cost estimates on total annual system cost is discussed
in more detail in the cost sensitivity analysis in Subsection 4.3.8. The in-
fluence of estimating error associated with present cost estimates is also seen
in Figure 32, shown previously.
Another crossover in cost is demonstrated where the subbituminous coal-
fired AFBC boiler is compared with the uncontrolled pulverized coal boiler.
The cost similarity is attributed to the technical complexity of the conven-
tional unit and the minimal sulfur removal requirements in the AFBC boiler
system.
247
-------
The results of the analysis also show the cost effect of controlling S02
to different emission levels using FBC technology. The difference in total
annual cost is small for the Eastern high sulfur coal and insignificant for
the two low sulfur coals. With FBC technology, once a decision is made to
control SC>2 emissions to 75 percent or greater, there is fairly small impact
in proceeding to more stringent levels, up to 90 percent reduction.
4.3.6 Cost Effectiveness of AFBC S02 Control - Unit Cost Basis
The cost of S02 control in AFBC is shown in comparison to uncontrolled
conventional boiler cost in Table 39 and Figure 38 in terms of $/kg of S02
removed. This parameter accounts for the total annual cost of uncontrolled
conventional boilers by subtracting it from the total annual cost of AFBC
boilers with S02 control (but excluding final particulate control). The
balance is divided by the amount of SO? removed annually for the set of con-
ditions of concern. As a result, positive values indicate FBC costs are greater,
and negative values indicate FBC costs are lower than uncontrolled conventional
boilers of the same capacity.
The data illustrate the same trends presented earlier, but give some idea
of cost effectiveness. With low sulfur coals, the impact of going to more
stringent SC>2 control levels is less than for the case of high sulfur coal.
The absolute values are lower, as are the slopes of the curves for low sulfur
coal. The linear relationships suggest that even greater levels of SC>2 control
(>90 percent) could be achieved without a sharply accelerated cost impact.
It is important to note the impact of sorbent reactivity on control cost
(see Table 39). For stringent control using high sulfur coal, the unit costs
are shown to vary by about ±$1.00/kg S(>2 removed for sorbent of high or low
reactivity; the variation decreases slightly as boiler capacity decreases,
248
-------
TABLE 39. COST OF S02 CONTROL IN AFBC DOLLARS/KG SULFUR DIOXIDE REMOVED
CUAL IVPL Lfc.tfhL AND StJKBEM CA/S
HtKCtMAGfc HtACllVlTV WATIU C.B
rtiOUt FIUN
bASIbWiY HIGH S 902 AvtKAGt 5.3 «?.OU
SUL^ UK I U«v 4.«» «?.H /
( i.St b) HjfiH c».S 1.11
I HbX Avf-WAbt «?.V 1.63
1. U* 3.H H 2.0 -.!<> 4.64 u.li
"•ti S.?^ b.j)
«.«?» i.rth 4. IS
«. /» «.U1 J. / ;
*>. /^ 'i.(?9 y ,Sn
".Ob S.63 r'.1'^
"•J7 4.V/ 4.^/
"3.17 q.ri-, <,.]„
3.7<* i.^9 r-.SM
2.f»b ^.<"3 ].„.•,
3.0i ^.-tj !.?
«?. /S ^.o f 1.19
^.**3
-------
6.00
5.00
4.00
g 3.00
O
M
8 2.00
1.00
-1.00
-2.00
EMS'EASTERN HIGH SULFUR COAL
ELS • EASTERN LOW SULFUR COAL
SUB'SUBBITUMINOUS COAL
22MWt,SUB—w
44 MWt,SUB
58.6 MWt.SUB*
•8.6 MWt, SUB
SO 60 70 80 90 100
PERCENTAGE S02 REDUCTION
Figure 38. Unit cost of S02 control in AFBC
boilers with capacity of 8.8 to
58.6 MWt (30 to 200 x 1Q6 Btu/hr)
250
-------
and decreases greatly as control level decreases. The impact of sorbent reac-
tivity at one particular control level is equivalent to the incremental cost
of attaining stringent S02 control in comparison to moderate 862 control using
an average reactivity sorbent. Sorbent reactivity is of somewhat less importance
when low sulfur coals are burned.
4.3.7 Comparison of GCA Data with Other Independent
Estimates of AFBC Costs
4.3.7.1 Westinghouse Study—
Westinghouse Research and Development is preparing an independent assess-
ment of industrial FBC boiler cost as part of their study, "Effect of 862
Emission Requirements on Fluidized-Bed Boilers for Industrial Applications:
Preliminary Technical/Economic Assessment."35 The basis of the cost estimate
is intentionally similar to GCA's, as shown in Table 40.
The Westinghouse cost data are presented in Appendix D, Tables D-l through
D-12. Total annual cost in terms of $/106 Btu output was estimated by GCA (as
shown at the bottom of each table) based on boiler capacity, total annual cost,
and boiler efficiency. Annual fixed charge is shown in the same terms, as
estimated by GCA from the Westinghouse data. Total turnkey cost was annualized
using the same factors used by GCA for capital recovery (0.106) and G&A, taxes,
and insurance (0.04).
FBC costs (fixed annual, operating, and total annual) estimated by GCA
and Westinghouse (for average sorbent reactivity) are shown comparatively in
Figures 39 through 41. The graphs illustrate that Westinghouse estimates a
slightly higher total annual cost than GCA for the 8.8 MWt boiler and signifi-
cantly lower annual costs for all other boiler capacities. The major difference
is in the fixed annual charge for each boiler, since total annual operating costs
251
-------
TABLE 40. FEATURES OF WESTINGHOUSE COST ESTIMATE FOR
INDUSTRIAL FBC BOILERS
Boiler capacities 8.8, 22, 44, 58.6 MWt
Coal types
Eastern high sulfur, Eastern low sulfur,
Subbituminous, as specified in the GCA
study.
S02 control levels Same as GCA analysis
considered
Cost Basis
Sorbent types
(500 vim average
in bed particle
size)
Same as GCA analysis, except that costs were
based on in-house Westinghouse data and other
accessible sources. Boiler vendor quotes were
not solicited. Some other differences are:
- Limestone purchase cost 25 $/ton
- Spent solids disposal cost 8 $/ton
I (High Reactivity) - Western 90% CaL
II (Medium Reactivity) - Bussen Quarry
III (Low Reactivity) - Menlo Quarry
a.
H
a
0>
in
O
2
UJ
in
u
ID
U
Z
z
O
Ul
X
BOILER CAPACITY, l06Btu/hr INPUT
3O 73 ISO
200
WCSTINOHOUSE ESTIMATE OF ANNUAL
FIXED CHARGE
RANGE OF ANNUAL FIXED CHARGE ESTIMATED BY GCA
INCLUDING ALL COAL TYPES
8.8
22 44
BOILER CAPACITY, MWt
38.6
Figure 39. Total fixed annual cost of AFBC with S02 control,
252
-------
30
BOILER CAPACITY, !06Btu/hr INPUT
75 ISO
200
T
I I
6CA ESTIMATE
WESTINGHOUSE
ESTIMATE
6
2 control,
253
-------
a.
O
9
m
8
2
w
I- 6
< 5
_J
<
BOILER CAPACITY, I06 Btu/hr INPUT
30 75 150
200
EASTERN HIOH SULFUR COAL
STRINGENT 302 CONTROL
SUBBITUMINOUS COAL
MODERATE S02 CONTROL
4 -
8.8
OCA ESTIMATE
WESTINGHOUSE
ESTIMATE
22 44
BOILER CAPACITY, MWt
ERROR LIMITS
'OR TOTAL
ANNUAL COST
ESTIMATES
BY OCA
98.6
Figure 41. Total annual cost of AFBC with S02 control.
254
-------
(the difference between total annual cost and annual fixed cost) are close to
the same for both estimates. It is noted that the capital cost difference is
just within the capital charge error band associated with the GCA estimate.
These results poignantly illustrate the possible disparity of two indepen-
dent cost estimates where the goal of each effort is to maintain a similar cost
basis.
It is clear that the absolute values determined in this cost analysis must
be used with caution. The differences in the two FBC cost estimates exist
because they are budget estimates. They illustrate the accuracy of budget
costing procedures and show that the validity of an FBC/conventional boiler
cost comparison is very much a function of the source of cost information.
Whereas GCA relied on two vendors for AFBC boiler equipment costs (one design
for 8.8 MWt, and one design for the other capacities), Westinghouse utilized
a similar design for all capacities and based costs on in-house information
which they have developed for their continuing studies of fluidized-bed
combustion.
When dealing with an emerging technology such as fluidized-bed combustion,
the validity of absolute values determined in a budget cost estimate are subject
to question. They should not be used for site-specific decisions and should be
used cautiosly in any other more general comparison. The merit of this costing
procedure lies in the estimation of relative cost differences; i.e., the impact
of going to more stringent SC>2 control levels or of using less reactive sorbents,
4.3.7.2 EXXON, and A.G. McKee Studies—
The A.G. McKee36 estimates are based on the DOE Georgetown University unit
in Washington, B.C., the EXXON37 estimates are for the Gulf Coast, and the GCA
255
-------
estimates are for the midwest. No attempt was made to adjust costs for
location. Some items were adjusted, however, to achieve compatability with
the assumptions in this study, but care was taken to maintain the integrity
of the other estimates. Appendix B presents the basis of other cost studies
and describes the adjustments made by GCA.
Table 41 presents a summary of annual costs in terms of $/106 Btu output
for AFBC burning Eastern high sulfur coal. The estimates represent an S02
removal efficiency of 85 percent to be comparable with a limit of 516 ng/J
(1.2 lb/106 Btu) specified by EXXON and a Ca/S ratio of 3 specified by
A.G. McKee. Figures 42 and 43 graphically illustrate the cost data.
The EXXON values (updated from 1975) are in agreement with the GCA
estimates for total annual cost and annual fixed charges assuming that inter-
polation of GCA data is valid. The A.G. McKee estimates are significantly
lower than GCA or EXXON, probably for two reasons. First, the Georgetown
unit is being installed (startup began July, 1979) as an additional boiler
at an existing facility so that several equipment items normally required
at a "grass roots" location are not necessary. This would include the steam
circulation system, and boiler feedwater treatment. Coal and solid waste handling
are necessary, however, because the two existing boilers are natural gas/oil-
fired units. Second, since the unit is currently being erected, contingencies
that must be added to budget estimates may not be applicable for the Georgetown
unit. It is not possible to conclude whether the McKee cost data validate the
*
Based on the assigned groundrules of the overall EPA Industrial Boiler
Study.
256
-------
TABLE 41. AFBC BOILER COST WITH 85 PERCENT S02 REMOVAL
Annual cost, $/106 Btu output
Source
Plant size -
8.8
22
37
44 58.6
GCA (controlled AFBC) 7.62 6.84 5.78 5.56
EXXON (controlled AFBC) - - 6.14
A.G. McKee (conventional with no S02 control) - - 4.34
A.G. McKee (controlled AFBC) - - 4.71
*
Annual fixed charge for this estimate is $2.30/106 Btu output.
a,
t-
»4
BOILER CAPACITY, 10° Btu/hr INPUT
73 ISO
200
M
O
0
a
w
»-
M
M
O
I
I
I
OCA ESTIMATE
EASTERN HIGH SULFUR
COAL
ERROR
• AND ON
CAPITAL CHARM
ESTIMATES §Y
OCA
OP FIXED ANNUAL CHAROE
I
I
S.8
22 44
BOILER CAPACITY, MW,
58.«
Figure 42. Comparison of fixed annual cost estimates.
257
-------
BOILER CAPACITY, 10* Btu/hr INPUT
JO 78 160 200
H"~iT" "" f""^~"^^^^^^^ --L.-JJ-
V»
o
u
OCA ESTIMATE
'EAITEHN HIOH SULFUft COAL
INTERMEDIATE S02 CONTHOL
<••% KfOUCTION)
A.O. MeKEE i
CONTMOLLEO
EXXON
CONTROLLED AFtC
EHMON
• AND
A.O. M«KMi
CONVENTIONAL WITH
NO 10, CONTROL
9.9
66.6
BOILER CAPACITY, MWt
Figure 43. Comparison of total annual cost estimates,
258
-------
GCA estimates since the impact of the two factors mentioned above can not
be quantified. However, the EXXON estimates do support the GCA cost values.
The difference in cost between the AFBC boiler with SC>2 control and conven-
tional boiler without SC>2 control, as estimated by A.G. McKee is small,
amounting to 8 percent. This difference is slightly less than that noted in
the earlier comparison of GCA and PEDCo derived costs for controlled AFBC and
uncontrolled conventional systems, respectively.
4.3.8 Sensitivity Analysis - Cost
An analysis of the cost sensitivity of AFBC (incorporating "best system"
design/operating conditions) to variations in operating parameters, raw mate-
rial costs, and capital costs was performed. The results are reported as
dollars per million Btu output ($/10^ Btu) and, where appropriat , as dollars
per kilogram sulfur dioxide removed ($/kg SC>2 removed). This analysis required
definition of a baseline set of conditions which is presented in Appendix C,
Table C-3. These conditions are representative of high sulfur coal combustion,
with an average sorbent and stringent 862 control. The various operating
conditions investigated were: effect of heat recovery, plant load factor,
excess air, combustion efficiency, calcium-to-sulfur ratio, moisture removal
requirements, sulfur capture, and coal sulfur content. Materials and capital
cost effects which were investigated were coal cost, limestone cost, residue
disposal cost, and variation in capital expenditure due to design changes.
The ranges investigated are also listed in Table C-3.
Of the parameters investigated, seven exhibited linear relationships,
three exhibited nonlinear relationships, and two had an insignificant effect
on cost. The seven linear variables are:
259
-------
• coal cost
• limestone cost
• residue disposal cost
• capital cost
• Ca/S ratio
• coal drying
• coal sulfur
The predictive equations are presented in Table 42.
The linear variables are discussed in three groups. Coal cost, limestone
cost and residue disposal cost are presented together as purchase or disposal
costs. Capital cost is discussed separately. Ca/S ratio, drying requirements
and coal sulfur content are discussed as operating variables.
The nonlinear variables are:
• combustion efficiency
• excess air
• plant load factor
Combustion efficiency and excess air are discussed together because their
effects are interactive (changing one forces variation in the other). Plant
load factor is discussed separately because this is a function only of steam
demand from the industrial user.
Neither of the other two variables investigated (heat recovery and
sulfur capture) had a significant effect on cost. Spent solids heat recovery,
a feature incorporated in some designs, decreased costs by 0.07 $/106 Btu as
heat recovery varied from 0 to 100 percent. Sulfur capture is calculated un-
der the assumption that the Ca/S ratio remains constant, and the only variation
is sorbent reactivity. When sulfur capture changes from 70 to 90 percent, cost
is reduced by only lc/106 Btu. Neither variable is significant for industrial
considerations.
260
-------
TABLE 42. GENERAL EQUATIONS RELATING COAL COST, LIMESTONE COST, RESIDUE
DISPOSAL COST, CAPITAL COST, Ca/S RATIO, DRYING, AND COAL
SULFUR TO $/106 BTU
Coal Cost
Limestone Cost
Method of
firing
Uncontrolled
Conventional
AFBC
Uncontrolled
Convent ional
S/10" BTU for plant size of
8.8 «ft't 22 MWt 44 MHt 58.6 MWt
0.fiJ62C + 6.49 0.0538C + 4.68 0.0554C + 3.88 0.0532C + 3.7i
0.0548C + 6.90 0.0542C + 6.16 0.0540C + 5.08 0.0538C + 4.36
— — — —
AFBC
Residue Disposal Cost Uncontrolled
0.023L + 7.60
0.023L + 6.65
0.023L + 5.77
0.023L
Capital Cost
Ca/S Ratio
Drying Requireaent
Coal Sulfur
Conventional
AFBC
Uncontrolled
Conventional
AFBC
Uncontrolled
Convent ional
AFBC
Uncontrolled
Convent ional
AFBC
Uncontrolled
Conventional
AFBC
0.0046R +
0.022R +
—
0.0186W +
0.379Ca/S -f
0.0203M +
0.0263M +
0.0044S +
C.368S +
7.22
6.94
6.02
6.98
7.35
7.75
7.38
6.50
0.0043R
0.0022R
0.0258W
0.373Ca/S
0.018M
0.0247M
0.0033S
0.368S
+ 5
+ 6
_.
.60
.19
+ 4.68
_
+ 6,
+ 5.
+ 6
+ 5
+ 5
,22
,72
.99
.75
.77
0.0020K -f
0.022R +
-
0.0228W +
_
0.355Ca/S +
0.0163M +
0.0220M +
0.0033S +
0.359S +
4
5
3
5,
4
5
4
4
.69
.11
.79
.11
.73
.91
.76
.69
0.011R +
0.022R •»•
_
0.0212U +
—
0.351Ca/S +
0.0190M +
0.0215N +
0.0022S +
0.356S +•
4.51
4.89
3.73
4.84
4.49
5.70
4.56
4.48
M = Percent Moisture Removed
C » Coal Cost
W = Percent of Original Estimate
Ca/S » Calcium-to-Sulfur Ratio
L = Limestone Cost
R = Residue Disposal Coast
S - Coil Sulfur Content
-------
4.3.8.1 Material Cost Variation--
Coal cost, limestone cost, and residue disposal cost are all site-specific
costs. No adjustment for waste reuse (such as road bed filler or agricultural
applications) was attempted because these uses are not only site-specific, but
also seasonal.
The linear equations shown in Table 47 can be used to determine the cost
of steam for any hypothetical site under investigation. Consider a site with
coal costing $22/ton, limestone at $14.90/ton and residue disposal at $31/ton.
The base costs (see Tables C-3 and C-4) are respectively: coal - $17/ton,
limestone - $8/ton, and residue disposal - $40/ton. Using coal cost as the
standard equation from Table 47, the cost in dollars per million Btu output
is approximated as follows:
• Conventional Spreader Stoker
$/106 Btu = 0.0554C + 3.88 + 0.0020 (R-40)
= 0.0554 (22) + 3.88 + 0.0020 (31-40)
= 5.08
• AFBC
$/106 Btu = 0.0540C + 5.08 + 0.023 (L-8) + 0.022 (R-40)
= 0.054 (22) + 5.08 + 0.023 (14.9-8) + 0.022 (31-40)
= 6.23
where C = coal cost
L = limestone cost
R = residue disposal cost
The calculated differential of $1.15 indicates that a controlled AFBC
boiler produces steam at a cost 23 percent higher than an uncontrolled con-
ventional boiler under these hypothetical conditions. The significance of
this difference is questionable when one considers that cost estimate accuracy
limits are specified as ±30 percent.
262
-------
4.3.8.2 Capital Investment Variation—
The linear relationship for capital cost variation in Table 47 predicts
the cost of design variations specifically affecting the AFBC cost estimates.
The capital cost variation analysis should not be confused with the aforementioned
estimated accuracy limits of ±30 percent.
Cost estimate accuracy limits pertain to errors in overall cost estimates.
The capital cost variation analysis is designed to determine the effect on output
cost when design changes (such as in-bed fuel feeding or deeper beds) increase
the anticipated capital cost. Because the focus of this report is comparison
of AFBC steam costs with conventional steam costs, only the capital cost of
those items unique to FBC were varied. Items common to both systems (such as
coal handling equipment) and items unique to conventional firing 'such as
the conventional firebox) are held constant.
An example of the use for which this analysis is intended is the cost
effect of replacing stoker feed AFBC with underbed feed AFBC. If preliminary
cost analysis indicates in-bed feed adds 20 percent to the system capital
investment, the cost of steam increases by $0.40/106 Btu for the large boiler
(58.6 MWt).
4.3.8.3 Operating Variations—
Sorbent requirements at a specific control level are a function of system
design, sorbent reactivity, coal sulfur, and sorbent particle size. The coal
sulfur effect in terms of $/106 Btu output is linear and the equations are
presented in Table 47, Rigid relationships linking the other three parameters
(system design, sorbent reactivity, and sorbent particle size) to cost are not
well defined.
263
-------
Figure 44 illustrates the effect of coal sulfur content on cost in terms
of $/kg S02 removed. The nonlinear curves result because the cost of conven-
tional boilers is subtracted from the total AFBC cost and the balance is divided
by the annual amount of SC-2 removed. For low sulfur coal, the cost per unit
sulfur dioxide removed is quite dependent on coal sulfur content. Above
4 percent sulfur, the relationship is nearly linear.
Changes in system design to alter "commercially offered" systems to "best
systems" as defined in this study are increased gas phase residence time and
reductions in sorbent particle size. These changes reduce sorbent requirements
by enhancing the gas/solid reaction.
The linear equations in Table 47 can predict cost effects of reduced Ca/S
requirements. For instance, if a commercial design requires a Ca/S ratio of
3.5 and the "best system" would require a Ca/S ratio of only 2.5, the cost re-
duction is $0.35 to $0.37/106 Btu depending upon boiler size (assuming no
capital cost changes). Coal drying (removal of surface moisture) is a require-
ment for AFBC only if an underbed feed design is necessary for maintenance of
low emissions. From the equations in Table 47, every incremental reduction
of 5 percent moisture increases cost by $0.10/106 Btu output.
4.3.8.4 Nonlinear Effects in Cost Estimates—
Three of the variables investigated are nonlinear in cost of heat produced.
These are combustion efficiency, excess air, and plant load factor.
Figures 45, and 46 depict the interrelationship between cost and: (l) com-
bustion efficiency; or (2) excess air. The cost of conventional firing under
the standard design assumptions is included at the reference conditions noted
in Table C-2. Although the relationship in both cases is nonlinear, the
deviation from linearity is minor. Assuming combustion efficiency drops from
264
-------
1.75
1.50
1.25
1.00
0.75
o
UJ
O
V)
x 0.25
-0.25
-0.50
22 MWt
44 MW;
58.6 MWj
8.8MW.
I
I
I
2468
COAL SULFUR CONTENT, %
10
Figure 44. Cost of S02 control in AFBC
($/kg S02 removed) versus
coal sulfur content.
265
-------
IO.OO
9.0O
=> 8.00
§
i
r.oo
1
I
£.00
3.00
4.0O
AFBC BOILERS
UNCONTROLLED CONVENTIONAL BOILERS
• - 8.8 MWt
• - 22 MW,
• - 44 MWt
A - 38.8 MWt
8.8 MW,
22 MW,
44 MW
t
38.6 MW.
I
80 85 9O 95, IOO
COMBUSTION EFFICIENCY.%
Figure 45. Cost of AFBC with S02 control versus combustion
efficiency.
266
-------
8
S
at
AFBC BOILERS
UNCONTROLLED CONVENTIONAL BOILERS
• - 8.8 MWt
* -22 MWt
• - 44 MWt
A - 58 MWt
8.8 MW.
VI C
8 6
-J
I
I
20 40 60
EXCESS AIR,%
80
100
Figure 46. Cost of AFBC with S02 control
versus excess air.
267
-------
95 percent down to 90 percent, the projected cost increases from 5.86 $/106
Btu to 6.19 $/106 Btu for the 58.6 MWt unit. Based on linear regression
analysis, the projected cost increases from 5.87 $/106 Btu to 6.24 $/106 Btu.
The effect of load factor on cost is presented in Figure 47 and 48 in
terms of $/106 Btu output (22 MWt case only) and $/kg SOa removed. The ordinate
of Figure 47, $/106 Btu, illustrates the difference in cost between controlled
AFBC and an uncontrolled conventional boiler of 22 MWt capacity. In Figure 48,
the ordinate, $/kg SOj removed, is obtained by dividing the cost difference
in $/106 Btu between the AFBC and conventional boiler by emissions in terms of
kg S02/106 Btu.
^
From Figure 55, the effect of both the capital and operating cost components
is evident. At low load factor; e.g., 0.40, annualized capital comprises 27
percent of the conventionally-fired cost and 30 percent of the AFBC cost. At
100 percent load, conventional-firing annualized capital cost is 23 percent.
Similar analysis of the other three capacities, 8.8 MWt, 44 MWt, and 58.6 MWt,
produces similar trends; i.e., as load factor increases the capital component
to cost decreases. Additionally, as the fraction of the total cost attributed
to capital decreases, the dependence of $/kg S02 on load factor decreases
(Figure 48).
The inverse slope of the 8.8 MWt unit as compared to the larger units in
Figure 48 is a result of the AFBC capital cost comprising a significantly
smaller proportion of the total annual AFBC cost than does the capital cost
of the conventional unit (see Figure 47). As a result, when load factor
increases, AFBC costs increase more rapidly than conventional costs because
incremental operating costs are higher for AFBC than for conventional uncontrolled
systems.
268
-------
"
10
3
co
<
z
I
0.2
\
A7BC AND UNCONTROLLED
CONVENTIONAL MMLCR CAPACITY
EQUAL*
CONVENTIONAL
BOILEM OPERATING
COST
AMC
OMUATIM
COST
CONVENTIONAL BOILER
CAPITAL COST
Af»C CAPITAL CO«T
I
1.0
Figure 47.
0.4 0.6 at
PLANT LOAD FACTO*
Cost of AFBC at a Capacity of 22 MWt with S02 control
versus plant load factor.
269
-------
1.40
O
O
m
1.20
1.00
0.60
98.6 MWi
0.60
0.40
0.20
8.8 MW
t
I
0.2
0.4 0.6 0.8
PLANT LOAD FACTOR
1.0
Figure 48. Cost of S02 control in AFBC ($/kg S02 removed)
versus plant load factor.
270
-------
The parameters investigated, the range investigated, and the resultant
cost ranges are presented in Table 43. This table may be used to assign
qualitative rankings to the variables with regard to their effect on cost.
However, even though the range investigated is within the limits one could
expect to encounter, the entire range would not be expected to occur at one
site. For example, coal cost can easily range from $10/ton up to $60/ton,
but the limits for a specific site or specific coal would not ordinarily be
this wide.
Considering this qualification, the major variables are load factor, coal
cost, combustion efficiency, Ca/S ratio, and coal sulfur. Intermediate variables
are drying requirement, capital cost, excess air, limestone cost, and residue
disposal cost. Relatively insignificant variables are heat recovery and sulfur
capture. (Sulfur capture is insignificant in this analysis because Ca/S ratio
was held constatn at 3.5). This prioritization of variables provides an insight
into the significance of each variable investigated. However, the significance
of each factor for a specific site depends on the price range for the locale.
4.4 COST OF BEST SYSTEM PARTICULATE CONTROL FOR COAL-FIRED AFBC
INDUSTRIAL BOILERS
4.4.1 Attempt to Isolate Particulate Control Costs from S07 Control Costs
Final particulate control cost is reported in this section for AFBC
boilers with and without S02 control. Although we do not anticipate that
coal-fired AFBC industrial boilers without S02 control will be used to a
significant extent, the analysis of cost of particulate control applied to
such systems is presented for the sake of completeness.
Definition of the cost of AFBC without S02 control but with particulate
control is difficult since AFBC is inherently a combined energy production/S02
control technology (see Subsection 4.1.4.1). It was roughly estimated for the
271
-------
TABLE 43. COST SENSITIVITY ANALYSIS - AFBC
N5
>J
K3
Parameter
Drying requirement
Heat recovery
Load factor
Coal cost
Capital ccst
Excess air
Combustion efficiency
Ca/S ratio
Sulfur capture
Limestone cost
Residue disposal cost
Coal sulfur content
Range studied
0
250
0.30
10.00
0.60
0
80
1
70
5
5
1
30
percent
- 1480°F
1.
60.
1.
- 100
- 99
10
- 100
- 35
40
10
00
00 $/ton
40
percent
percent
percent
$/ton
$/ton
percent
Cost range, $/106
8.8 MWt
7.75
7.69
13.49
7.42
7.08
7.68
9.56
6.96
7.78
7.71
7.04
6.85
- 8.50
- 7.79
- 5.50
- 10.00
- 8.49
- 8.27
- 7.62
- 10.15
- 7.79
- 8.38
- 7.78
- 9.98
22
6.99
6.95
12.01
6.67
6.06
6.95
8.61
6.24
7.02
6.96
6.29
6.12
MWt
-7.69
- 7.03
- 5.04
- 9.24
- 8.01
- 7.47
- 6.88
- 9.38
- 7.03
- 7.63
- 7.03
- 9.25
Btu output
44
5.91
5.88
9.85
5.59
5.08
5.88
7.28
5.17
5.93
5.89
5.21
5.03
MWt
- 5.86
- 5.95
-4.38
- 8.15
- 6.80
- 6.31
-5.82
- 8.16
- 5.95
• 6.54
- 5.94
- 8.09
58.6
5.70 -
5.66 -
9.42 -
5.37 -
4.93 -
5.66 -
7.00 -
4.95 -
5.72 -
5.66 -
5.00 -
4.84 -
MWt
6.31
5.74
4.25
7.92
6.53
6.08
5.61
7.91
5.73
6.32
5.72
7.86
-------
purpose of this section by omitting limestone handling and purchase costs.
Spent solids handling and disposal costs were modified to allow only for
withdrawal of bed bottom ash. Total auxiliary power was reduced by 15 percent
to estimate electricity requirements when SOg control is not practiced.
Available data on particulate emissions and control efficiency for AFBC
are limited relative to data for conventional systems; therefore, differences
between FBC and conventional control system costs cannot be quantified. Factors
that could cause differences in equipment design, applicability, or cost are
discussed in Sections 2.0 and 3.0.
Particulate control device costs developed in the Particulate Control ITAR3^
are considered to be representative for application to FBC boilers, accounting
for the error bounds of the cost estimates used in this study, which are estima-
ted to be ±40 percent for the combined AFBC boiler and particulate control devices
To determine the cost of particulate control for AFBC boilers employing
S02 control with limestone, it was assumed that particulate control device costs
for FBC are the same as for conventional boilers burning low sulfur coal. For
particulate control cost in AFBC boilers not controlling S02, costs were assumed
to vary depending on specific coal type.
4.4.1.1 Inlet Particle Loadings—
The discussion in Sections 2.0 and 3.0 pointed out that data are limited
on particulate loadings from atmospheric fluid-bed units. Considering the
existing data base, it is estimated that uncontrolled particulate emissions
(i.e., loadings downstream of the primary cyclone) will range between 215 to
2150 ng/J (0.5 to 5.0 lb/106 Btu) in systems operating under "best" conditions
for SC-2 control. Variation within the range will depend on primary cyclone
*
Expanded bed depth = 1.2 m (4 ft); superficial gas velocity =1.8 m/sec
(6 ft/sec); average in-bed sorbent size = 500 ym.
273
-------
efficiency, the level of S02 control, in-bed particle size distribution, coal
ash, freeboard height, the effect of baffling by the convection pass of heat
transfer tubes, the extent of recycling, and other considerations. Whether
uncontrolled particle loadings fall below this range if SC>2 control is not
practiced is unclear because of the number of influential factors in addition
to sorbent loading and sorbent particle size. In PER testing of the FBM39
(see Section 7.0, Table 84), uncontrolled particulate emissions were measured
in the range of 430 to 730 ng/J (1.0 to 1.7 lb/106 Btu) when sorbent was added
for 862 control. Burning the same coal without sorbent addition, particle
emissions were measured to range between 301 to 559 ng/J (0.7 to 1.3 lb/106 Btu),
This reduction is significant but is still above the minimum specified earlier.
The fact that grain loading was not reduced even further is of interest because
the sorbent used for SOj reduction was fed at a top size of 44 \m. This implies
that other factors are influential in determining uncontrolled particulate
emissions, and that estimation of particle loadings on a general basis when
S02 control is not practiced, cannot be done without more thorough data. Other
comparative data for a single unit are not available.
Therefore, to estimate the cost of particulate control for AFBC systems
with and without S(>2 control, we have assumed a common uncontrolled particle
emission range between 215 to 2150 ng/J (0.5 to 5.0 lb/106 Btu). This assump-
tion could be a source of error for the estimates of ESP cost since ESP design
is a strong function of particle loading and particle chemistry. It should
not be a source of error for fabric filters or multitube cyclones since the
cost of these devices is more strongly related to flue gas volume.
274
-------
4.4.1.2 Handling, Storage and Disposal of Collected Particulate Matter—
To develop the total cost of final particulate control applied to AFBC
industrial boilers, it is necessary to add the cost of waste solids handling,
storage, and disposal which results due to the added particulate captured by
the final device. The following discussion explains how these costs were
estimated for each case; i.e., AFBC without and with SC>2 control.
An inlet particle loading between 215 and 2150 ng/J (0.5 to 5.0 lb/106
Btu) was used to estimate the range of solids collected by the final device
for each boiler capacity, regardless of coal type when SC>2 control is not
practiced. For this analysis, 100 percent collection of inlet particulate
was assumed. Although actual capture can range as low as 50 percent depending
on inlet loading and control level, this assumption does not in:roduce any
significant error because the cost of additional spent solids handling is
generally less than 2 percent of the total cost of AFBC with particulate
control.
A factor of $40/ton was applied to estimate the cost of additional spent
solids disposal. A unit cost factor ranging between $8.60 to $12.20 ft3 of
storage capacity was used to estimate the cost of added handling and storage
(see Subsection 4.3.1). Appropriate factors were applied to account for direct
and indirect installation of handling and storage equipment (see Subsection
4.2.1).
To estimate approximate inlet loadings when S02 control is practiced,
the system was modeled as follows:
275
-------
COAL
•> INLET TO FINAL
DEVICE, 0.1 W
PRIMARY
CYCLONE
MAKE-UP 31
BED V
MATERIAL N.
1
W = WASTE SOLIDS
AT STEADY STATE
RECYCLE
SPENT BED WITHDRAWAL,
0.9 W
where W is the sum of:
Coal ash
Unburned carbon
Limestone inerts
Uncalcined limestone
Unused calcium oxide
CaSOi+ produced
The rate, W, for each combination of boiler capacity, coal type, and
S02 control level is shown in Section 6, Table 80. The ratio of 0.1 W was
selected to calculate the inlet final particle loading because the resultant
loadings fall vithin the range of 365 to 1850 ng/J (0.85 to 4.3 lb/106 Btu)
which approximates the experimentally documented range.
The cost of incremental needs for spent solids handling, storage, and
disposal were then calculated by assuming that the final device operated at
276
-------
100 percent efficiency. For the case of combined particulate and S02 control,
the low incremental cost is based on the minimum waste production rate, W, for
each boiler capacity, which occurs under a moderate S02 control level, burning
Eastern low sulfur coal with a high reactivity sorbent. The high point occurs
under stringent S02 control, burning Eastern high sulfur coal with a low
reactivity sorbent. These assumptions allowed for ease of computation, since
the applicable costs could be directly proportioned from the cost tables which
appear in Appendix C for spent solids handling and storage and spent solids
disposal cost when S02 control is practiced.
4.4.2 Cost of Particulate Control for AFBC Boilers - Excluding Influence
of S02
The estimated cost of particulate control for AFBC boilers operating
without S02 control is shown in Table 44, based on vendor quotes for application
of the devices to conventional boilers.^ One exception is the multitube
cyclone cost for the 40 MWt boiler, which resulted from a study conducted by
IGCI for the Environmental Protection Agency.1*1
Only those control device/control level combinations are shown which
were considered as potential "best systems" in Section 3.0. Total costs
are presented in comparison to the cost of uncontrolled conventional boilers
as a percentage. This value was calculated as:
_ -._,.„„ ["Total annual cost of AFBC vithoutl ["Total annual coat "j
Percentage I e/» ^^....-.^i v.... „,•«.!. I _ I „* ....«......-._i i«j I
percentage ^ c
-------
N)
»J
co
TABLE 44. ESTIMATED COST OF FINAL PARTICULATE CONTROL FOR AFBC BOILERS -
EXCLUDING S02 CONTROL
Boiler
capacity
(MWt)
8.8
22
44
58.6
8.8
40
44
8.8
8.8
8.8
8.8
8.8
8.8
22
22
22
44
44
44
44
44
44
58.6
58.6
58.6
58.6
58.6
58.6
Control
device
Ft'
FF
FF
FF
MC
MC
MC
ESP
ESP
ESP
ESP & MC
ESP & MC
ESP & MC
ESP
ESP
ESP
ESP
ESP
ESP
ESP & MC
ESP & MC
ESP & MC
ESP
ESP
ESP
ESP
ESP
ESP
Particulate
control
level
S, I, M. SIP
S, I, M, SIP
S, I, M, SIP
S, I, M. SIP
M, SIP
M, SIP
M, SIP
S
S
S
I
I
I
S
S
S
S
S
S
I
I
I
S
S
S
I
I
I
Annual cost
Coal °f ?infl
part icu late
type control
device
All
All
All
All
All
All
All
EHS
ELS
SUB
EHS
ELS
SUB
EHS
ELS
SUB
EHS
ELS
SUB
EHS
ELS
SUB
EHS
ELS
SUB
EHS
ELS
SUB
51,000
86,000
147,000
181,000
10,000
48,000
26,000
25,000
62,000
75,000
30,000
56,000
63,000
55,000
127,000
147,000
114,000
204,000
208,000
121,000
213,000
226,000
128,000
218,000
228,000
114,000
206,000
211,000
Annual cost of
incremental spent Approximate
solids handling an""^ c?8' of
storage and A">C »lthout
disposal S°2 contro1
1,800 -
4,400 -
8,900 -
11,900 -
1,800 -
8,100 -
8,900 -
1,800 -
1,800 -
1,800 -
1,800 -
1,800 -
1,800 -
4,400 -
4,400 -
4,400 -
8,900 -
8,900 -
8,900 -
8,900 -
8,900 -
8,900 -
11,900 -
11,900 -
11,900 -
11,900 -
11,900 -
11,900 -
17,700
43,800
89,100
118,500
17,700
81,000
89,100
17,700
17,700
17,700
17,700
17,700
17,700
43,800
43,800
43,800
89,100
89,100
89,100
89,100
89,100
89,100
118,500
118,500
118,500
118,500
118,500
118,500
847,000 -
1,860,000 -
3,001,000 -
3,804,000 -
847,000 -
2,756,000 -
3,001,000 -
874
887
847
874
887
847
1,962
2,018
1,860
3,222
3,333
3,001
3,222
3,333
3,001
4,113
4,276
3,804
4,113
4,276
3,804
887,000
2,018,000
3,333,000
4,276,000
887,000
3,055,000
3,333,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
.000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
Approximate total
cost of AFBC with
particulate control
but no SO 2 control
899,800
1,950,400
3,156,900
3,996,900
858,800
2,812,100
3,035,900
900,800
950,800
923,800
905,800
944,800
911,800
2,021,400
2,149,400
2,011,400
3,344,900
3.545,900
3,217,900
3,351,900
3,554,900
3,235,900
4,252,900
4,505,900
4,043,900
4,238,900
4,493,900
4,026,900
955,700
- 2,148,000
- 3,569,100
- 4,575,600
914.700
- 3,184,000
- 3,448,100
916,700
966,700
939,700
921,700
960,700
927,700
- 2,060,800
- 2,188,800
- 2,050,800
- 3,425,100
- 3,626,100
- 3,298,100
- 3,432,100
- 3,635,100
- 3,316,100
- 4,359,500
- 4,612,500
- 4,150,500
- 4,345,500
- 4,600,500
- 4,133,500
Percentage
increase
in cost over
uncontrolled
conventional
boilers
(-3.7) -
6.2 -
2.2 -
(-3,6) -
(-8.0) -
(-1.8) -
(-2.8) -
3.2 -
(-1.1) -
(-2.3) -
2.6 -
(-2.4) -
10.7 -
17.1 -
14.1 -
9.9 -
14.7 -
6.3 -
10.1 -
15.0 -
6.9 -
5.4 -
8.7 -
1.1 -
5.0 -
8.4 -
0.7 -
3.8
21.8
17.9
14.4
(-0.7)
13.9
(-1.1)
5.0
0.6
(-0.6)
4.3
(-0.7)
12.9
19.2
16.3
12.5
17.3
8.9
12.7
17.6
9.5
8.0
11.2
3.8
7.7
11.0
3.4
?/kg
particulate
removed
(-1.0)
1.3
0.4
(-0.6)
(-2.1)
-0.3
(-0.7)
0.8
(-0.3)
(-0.6)
0.7
(-0.6)
2.2
3.4
2.7
1.7
2.6
1.1
1.7
2.6
1.2
0.9
1.5
0.2
0.9
1.5
0.1
- 0.1
- 0.4
- 0.3
- 0.2
- 0
- 0.2
- 0
- 0.1
- 0
- 0
- 0.1
- 0
- 0.3
- 0.4
- 0.3
- 0.2
- 0.3
- 0.2
- 0.2
- 0.3
- 0.2
- 0.1
- 0.2
- 0.1
- 0.1
- 0.2
- O.I
Note: FF = Fabric Filter
MC - Hultltube Cyclone
ESP - Electrostatic Precipitator
EHS - Eastern High Sulfur Coal
ELS - Eastern Low Sulfur Coal
SUB - Subblcioiinous Coal
-------
Cost is also shown in terms of $/kg particulate removed and is estimated
as:
$/kg Renewed *
[Total annual cost of AFBC without"
SO2 control but with
particulate control
T Total annual coat 1
- I of uncontrolled I
•conventional boilers!
kg of particulate removed per year
The underlying accuracy (±40 percent) of the cost estimating procedure
must be considered in evaluating the tabulated results. For instance, differences
in cost between AFBC with particulate control and uncontrolled conventional
boilers as a function of coal type may be as much a function of basic differences
in boiler cost as particulate control device cost. Therefore, tb impact of
coal type on control device cost can only be determined from the first column
of the table. ESP cost increases as coal sulfur decreases, but this trend
would not be concluded from the last columns in the table.
Cost in terms of $/kg particulate removed decreases as inlet loading
increases from 215 to 2150 ng/J (0.5 to 5.0 lb/106 Btu). The range for ESP's
may not be as wide as shown considering that, in reality, total ESP cost would
increase with particle loading, but this analysis only accounts for the added
cost of additional waste solids handling.
Fabric filters are cost-effective for stringent or intermediate control
when low sulfur coals are burned. However, ESP's appear to have a cost
advantage over fabric filters when high sulfur coal is burned. (There is
still some question as to the performance of ESP's with FBC fly ash.) Considering
equivalent boiler capacities, cost In terms of percentage increase and $/kg
particulate removed are not significantly different for either control device.
279
-------
The percentage increase in cost over uncontrolled conventional boilers ranges
as high as 20 percent for a boiler capacity of 22 MWt. It decreases slightly
with larger boiler sizes and is much lower for the 8.8 MWt boiler simply
because of the basic cost advantage of an AFBC boiler at this capacity. Cost
in terms of $/kg particulate removed follows the same trend.
In several cases, negative values are shown in the last two columns of
the table. This indicates that the cost of AFBC with the particulate control
device noted and no SC>2 control is less expensive than an uncontrolled conven-
tional boiler of the same capacity firing the same coal.
Based on final device cost alone, multitube cyclones are the cost-effective
choice for moderate particulate control. However, the data do not show an
overwhelming advantage when the cost of AFBC and final particulate control are
considered together because variation in basic boiler cost tends to dampen the
cost impact of particulate control application.
4.4.3 Cost of Particulate Control for AFBC Boilers - Including Influence
ofSO? Control
The combined cost of AFBC systems with S(>2 control and particulate control
is shown in Table 45. Again, the costs are based on vendor quotes presented in
the ITAR on particulate control.1*2 The table assumes that within the accuracy
of this study, control device performance on AFBC boilers with SQ2 control
will be similar to conventional boilers burning low sulfur coal. Therefore,
costs are presented based on estimates for conventional boilers burning
subbituminous coal, the worst case cost. Consequently, all ESP costs represent
hot side application.
280
-------
TABLE 45. COST OF FINAL PARTICULATE CONTROL FOR COAL-FIRED AFBC
INDUSTRIAL BOILERS WITH S02 CONTROL
•stf
8.8
22
44
58.6
6.6
40
44
8.8
8.8
8.8
10 a
CO 22
*~* 44
44
44
58.6
58.6
58.6
FF
FF
FF
FF
HC
HC
HC
ESP
ESP & HC
ESP
ESP
ESP
ESP
ESP b HC
ESP
ESP
ESP
ESP
level
S, I, H, SIP
s. 1, H, SIP
S, 1, ». SIP
S, I, H. SIP
K, SIP
K, SIP
K, SIP
S
I
SIP
s
SIP
s
I
SIP
s
I
SIP
Final particular
control davict coat
Capital*
238,000
436,000
766,000
943.000
51.000
185,000
98,000
414,000
336,000
105,000
825,000
260,000
1,143,000
1,214,000
865,000
1,249,000
1,162,000
1,008,000
Operating Annual*
13,000
18.0OO
27,000
33,000
2,000
16,000
11,000
10,000
10,000
5,000
17,000
8,000
26,000
35,000
17,000
31,000
28,000
20,000
51,000
86,000
147,000
181.000
10,000
48,000
26,000
75,000
63,000
22,000
167,000
49,000
208,000
226,000
153.000
228.000
211.000
179,000
Annual1
incremental
spent lolida
diapoaal coat*
2,700
6,700
13,400
17,900
2,700
12,200
13,400
2,700
2,700
2,700
6,700
6,700
13,400
13,400
13,400
17,900
17,900
17,900
- 13.6OO*
- 34,000
- 68,000
- 90,700
- 13,600
- 61,800
- 68,000
- 13,600
- 13,600
- 13,600
- 34,000
- 34,000
- 68,000
- 68,000
- 68.DOO
- 90.700
- 90,700
- 90,700
Incremental .pant .olid* handUnft
ana •toraie coete*
Capital*
2,100 -
5,700 -
10,800 -
11,900 -
2.300 -
9.900 -
10,800 -
2,300 -
2.300 -
2,300 -
5,700 -
5,700 -
10,800 -
10.800 -
10,800 -
13.900 -
13.900 -
13.900 -
10.900*
23,100
65,500
87,400
10,900
57,800
65,500
10,900
10,900
10,900
23,100
23,100
65,500
65,500
65,500
87,400
87,400
87,400
Annualiled
capital
300 -
800 -
1,600 -
2,000 -
300 -
1,400 -
1,600 -
300 -
300 -
300 -
800 -
800 -
1,600 -
1,600 -
1,600 -
2.000 -
2,000 -
2,000 -
1,600*
3,400
9,600
12.800
1,600
8,400
9,600
] ,600
1,600
1,600
3,400
3,400
9,600
4.600
9,600
12,800
12,800
12,800
Total coat o]
Capital*
248,000
460,000
814,000
1,006,000
60,700
218,000
145,000
424,000
346,000
115,000
849,000
284,000
1,191,000
1,262,000
913,000
1,312,000
1,225,000
1,701,000
- 286,000*
552,000
- 1,018,000
- 1,279,000
99,200
- 412,000
- 349,800
462 , 000
- 384,000
153,000
941,000
- 376,000
- 1,395,000
- 1,666,000
- 1,117,000
- 1,585,000
- 1,498,000
- 1,344,000
final particular
Operating
14,600 -
22,000 -
35,000 -
43,700 -
3,600 -
23,300 -
19,000 -
11,600 -
11,600 -
6,600 -
21,000 -
12,000 -
36,000 -
43,000 -
25,000 -
41,700 -
38,700 -
30,700 -
21 , 200*
38,400
67,800
87,400
10,200
53,100
51,800
18,100
18,100
13,100
37,400
28,400
68,800
75,800
57,800
85,400
82,400
74,400
control
Annual*
54,000 -
93,500 -
162,000 -
200,900 -
13,000 -
61,600 -
41,000 -
78,000 -
66,000 -
25,000 -
154,500 -
56,500 -
223,000 -
241,000 -
168,000 -
247,900 -
230,900 -
198,900 -
66,200*
123,400
224,600
284,500
25,200
118,200
103,600
90,200
78,200
37,200
184,400
86.400
285.600
303,600
230,600
331.500
314.500
282.500
Total annual cote
of FBC vits
paniculate control
and S02 control
911,000
1,980,000
3 , 2 20 , 000
4.080,000
870,000
2,907,000
3.0"9,000
935,000
923,000
882 , 000
2.041,000
1,943,000
3,281,000
3,299,000
3,226.000
4,127,000
4. 110, 000
4,078,000
- 1,090,000
- 2.4M.OOO
- 4, 229,000
- 5,442,000
- 1,049,000
- 3,820,000
- 4,108,000
- 1,114,000
- 1.102.000
- 1.061,000
- 2,525,000
- 2.427,000
- 4,290,000
- 4,308,000
- 4,235,000
- 5,489,000
- 5.472,000
- 5,440,000
Percent ncrci.c
in coa over
uncont oiled
conven ional
boil r.
(-2.4)
12.3
6.1
2.0
(-6.8)
3.9
2.3
0.1
(-1.2)
(-5.6)
15.7
10.2
i.3
8.9
6.5
3.2
2.8
2.0
- 17.6
- 34.9
- 18.9
- 34. B
- 13.2
- 35.3
- 34.9
- 20.2
- 18.9
- 14.4
- 38.3
- 32.9
-40.9
-41.5
- 39.1
- 36.0
- 35.6
- 34.8
All capital co*t* are turnkey co*ta.
Annual coat include a oper*ting c«j«t and MMuali.ted capital coat.
Diipoael cost (b*aed oo $40/toa) of fly aah/aorbent captured in final control device. 4»ount captured in baaed on total ayate-a •pent aolid*/ aah
quantitiea ..it.ua that .mount n-ithdrairt from coabuater, vfcich ia included in the coat of 80; control.
The »aa.« coating procedure* and unit capital coata diacuaaed ia tha euhaection for S0j control are uacd hare.
tang* rcpreaenta the extreaea in coat; the low being Cattera low aulfur coal with nodertea SOj control and the particulata control level noted;
the high being Eaatem high aulfur coal with atringent SOj control end the particulate control level noted.
-------
Control device/control level combinations are shown which were considered
as "best system" candidates in Section 3.0. ESP costs at an SIP level are also
shown for comparison, but the multitube cyclone is considered to be appropriate
for SIP control. Percentage cost increases of implementing more stringent
control than SIP is not shown because ESP use is not recommended at this low
control level. Cost in terms of $/kg particulate removed should be similar to
the values noted earlier in Table 49 for low sulfur coal.
In general, the total cost of an AFBC system with 862 and particulate
control can range as high as 40 percent greater than a conventional boiler
without any emission control. Fabric filters may be more cost-effective than
ESP's in all cases for stringent or intermediate particulate control, since
ESP's have been considered as hot side installations when SC-2 control is
practiced.
This cost advantage is illustrated in Figure 49 which shows the cost of
add-on particulate control devices. Depending on performance capability, cold
side ESP's could be cost-effective compared to fabric filters. However, ESP's
will probably not be capable of operating as cold side installations when S02
control is practiced in AFBC. Figure 49 also illustrates that multitube
cyclones are the device of choice for moderate particulate control.
If inlet particle loadings are minimal (215 ng/J) and low sulfur coal
is burned, the analysis indicates that the 8.8 MWt AFBC boiler can be used at
equal or less cost than an uncontrolled conventional boiler. This continues
the trend shown in the S0£ control cost analysis and is probably a result of
the fairly low basic AFBC boiler cost at this capacity. This possible advantage
must be confirmed in actual practice.
282
-------
CAPACITY,
75
225
(00
175
< 150
o
< 125
C
2 100
O
u
75
< 30
o
I
8.8
Figure 49.
Btu/hr INPUT
ISO ZOO
T
T
MULTI-TUBE
^CYCLONE FROM
IOC I DATA
I
22 44
BOILER CAPACITY, MW,
58.8
Cost of final particulate control
for AFBC industrial boilers.
283
-------
4.5 COST OF NOX CONTROL
No cost has been added for NOX control. AFBC should be capable of in-
herently achieving the three levels of NOX control considered in this study.
4.6 SUMMARY - COST OF BEST SYSTEMS EMISSION CONTROL IN COAL FIRED
AFBC INDUSTRIAL BOILERS
4.6.1 S02 Control
The annualized cost of AFBC boiler purchase, installation, and operation
with S02 control has been computed along with comparable costs of uncontrolled
conventional boilers (as estimated by PEDCo). This summary discusses the
validity of the cost basis used and its impact on the accuracy of the final
estimates.
Based on the cost quotations supplied by vendors, small AFBC boiler use
(8.8 MWfc) can be of equal or less cost than an uncontrolled conventional stoker.
AFBC cost becomes less as coal sulfur content decreases. In the larger capa-
cities (22 to 58.6 MWt), AFBC costs (with SOz control) are higher than uncon-
trolled conventional boiler costs. An exception is the 58.6 MWt AFBC boiler
burning subbituminous coal with a sorbent of average or high reactivity. In
this instance, the cost of an uncontrolled pulverized coal-fired boiler is
equal to or higher than the AFBC boiler.
The basis of the small (8.8 MWt) AFBC boiler cost must be discussed
because of its apparently low cost relative to the uncontrolled conventional
boiler. First, the costs reported are based on a single basic boiler quote.
The manufacturer (Company B) is currently offering package boilers in this
size range. .'he boiler design is simple, but operates effectively based on
demonstration plant operation over the last several months. Therefore, the
costs presented are considered realistic.
284
-------
One aspect of this AFBC boiler which is open to question with regard to
"best" S02 control is the use of overbed screw feeding of coal and sorbent.
To date, the S02 control capabilities of this technique in commercial opera-
tion are unknown, although tests indicate SC>2 can be effectively controlled.
It is assumed for the purpose of this analysis that overbed feed can provide
suitable S02 removal performance and that its cost is representative of "best
system" cost. (See discussion of FluiDyne testing in Section 2.0 and 7.0).
In this report, we have attempted to indicate the full range of AFBC cost
based on differences in sorbent reactivity, S02 control level, coal type, sorbent
cost, and spent solids disposal costs. Because no large units have operated, the
possible trade-offs between capital cost for optional feed systems and operating
costs for reduced sorbent requirements cannot be quantified with total reliability,
but rather, must be projected based upon small-scale experimental results and
modeling efforts. In all probability, the added capital cost of in-bed materials
feeding is within the worst case cost presented for AFBC with S02 control.
Unless overbed screw feeding is proven inferior with respect to AFBC S02 control,
there is no reason to modify the costs presented here.
The costs presented for the three larger boilers are also based on overbed
coal feeders. The design in the larger boilers is somewhat different than that
incorporated in the small system, but similar considerations apply with regard
to SC-2 removal capabilities. The overbed feeding technique is under evaluation
at Georgetown University.
The coat analysis indicates that AFBC with SC-2 control can cost up to
30 percent more than an uncontrolled conventional boiler. The maximum cost
differential occurs at a stringent 862 control level during high sulfur coal
combustion with a low reactivity sorbent. As coal sulfur content decreases,
285
-------
and S(>2 control level becomes more moderate, and as sorbent reactivity increases
the difference in cost between the technologies narrows significantly. AFBC
was found to have equal or less cost at a capacity of 8.8 MWt for either low
sulfur coal and for Eastern high sulfur coal at an SIP control level. Also, the
cost of AFBC was comparable or lower for the 58.6 MWt AFBC burning subbituminous
coal. These similarities must be verified after more thorough marketing and
system use. Table 46 summarizes the cost of AFBC and uncontrolled conventional
systems estimated in this study,
TABLE 46. COST SUMMARY - AFBC AND UNCONTROLLED CONVENTIONAL
BOILERS: COST - $/106 Btu OUTPUT
Boiler capacity,
Coal type Boiler type
8.8 22 44 58.6
Eastern AFBC 6.93 - 8.04 6.19 - 7.28 5.10 - 6.19 4.90 - 5.97
High Sulfur Conventional 7.39 5.76 4.77 4.56
Eastern AFBC 6.79 - 6.93 6.13 - 6.27 5.06 - 5.19 4.86 - 4.99
Low Sulfur Conventional 7.12 5.62 4.70 4.55
Subbituminous AFBC 6.66 - 6.79 5.80 - 5.93 4.68 - 4.80 4.44 - 4.56
Conventional 7.41 5.54 4.73 4.57
An important conclusion of this study is the apparently small cost difference
between removing 75 or 90 percent S02 using AFBC. The greatest difference occurs
for high sulfur coal combustion (~$0.30/106 Btu for average sorbent reactivity)
but the difference becomes insignificant for low sulfur coals. Sorbent reacti-
vity can have a larger cost effect than control level depending on the extremes
in reactivity considered.
Implementation of "best system" conditions for S0£ control can reduce the
cost of FBC compared to "commercially offered" design/operating conditions.
This is mainly due to reduced operating costs. Capital costs may be higher or
lower depending on the alterations necessary and the specific design of interest
286
-------
4.6.2 Comparison with FGD
Considering the accuracy of both conventional and AFBC boiler costs pre-
sented in this report, it is difficult to draw clear cut conclusions concerning
the cost-effectiveness of S02 control employing AFBC technology. Comparison
with preliminary flue gas desulfurization (FGD) costs prepared by Radian1*3
for coal-fired industrial boilers can lend some perspective to the results of
the AFBC cost analysis. Table 47 lists the costs of FGD and AFBC in terms of
percentage increase over the cost of uncontrolled conventional boilers. For
the FGD case, the reported ranges cover low and high sulfur coals and optional
levels of S02 control. The AFBC ranges include, in addition, extremes in
sorbent reactivity. The data indicate that AFBC has a cost advantage at a
boiler capacity of 8.8 MWt, but that the maximum cost of both technologies
becomes comparable as boiler capacity increases from 22 up to 58.6 MWfc. On
this basis, it is concluded that AFBC is a cost-effective S02 control tech-
nology and that it should be considered in any instance where S02 control
is required for coal-fired industrial boilers.
4.6.3 Particulate Control
The results of the particulate control cost analysis (estimated accuracy =
±40 percent) indicate that fabric filters or ESP's may be selected for strin-
gent or intermediate control depending on coal type and implementation of SO2
control. Without S02 control, the estimated ESP costs are based on cold side
installation when high sulfur coal is burned. Under this condition ESP's are
less expensive than fabric filters. For any other condition; i.e., low sulfur
coal or inclusion of S02 control, fabric filters appear to be cost-effective.
*
Lack of full scale operating data is still the major bottleneck in the
technology's development.
287
-------
TABLE 47. RELATIVE COMPARISON OF THE COST OF AFBC
VERSUS CONVENTIONAL BOILERS WITH FGD
___
FGD process
Boiler capacity
% Increase in cost over
uncontrolled conventional
boilers*
FGDf
Limestone
Sodium
Double Alkali
Wellman-Lord
8.8
22
58.6
8.8
22
58.6
8.8
22
58.6
8.8
22
58.6
35
25
17
32
23
16
35
24
17
36
25
18
-W46
- 37
- 26
- 44
- 38
- 32
- 46
- 37
- 27
- 51
- 41
- 29
AFBC
<10
1 - 29
<28
<10
7-29
<28
<10
7-29
<28
<10
7-29
<28
Range includes low and high sulfur coals and optional
control levels. For AFBC, extremes in sorbent reactivity
are also included.
"•"Based on Radian TAR on FGD; see Reference No. 45.
288
-------
Under the more realistic condition where S(>2 control is assumed, fabric filters
seem to be the control device of choice, considering potential problems with
particle resistivity in ESP's and the loss of normally condensable trace
elements during hot side control. However, potential problems with fabric
filter use, such as blinding or bag fires, must be assessed in commercial
operation before one technique can be recommended over the other with total
confidence.
For moderate particulate control, multitube cyclones are the cost-
effective choice based on this analysis. It is important to reiterate that
the accuracy of the estimating technique is limited and that results must
be verified in actual applications.
4.6.4 N0y Control
NOX control to the three levels considered in this report of 215, 258,
301 ng/J (0.5, 0.6, 0.7 lb/106 Btu) is assumed to be inherently achievable
in AFBC. Therefore, no costs have to be added for NOX control.
289
-------
4.7 REFERENCES
1. Devitt, T., et al. The Population and Characteristics of Industrial/
Commercial Boilers. Prepared by PEDCo Environmental, Inc. for the U.S.
Environmental Protection Agency. Appendix G. EPA Report No. 600/7-79-
178a. August 1979.
2. Farmer, M.H., et al. Application of Fluidized-Bed Technology to In-
dustrial Boilers. Prepared by EXXON Research and Engineering Company
for the U.S. Environmental Protection Agency. EPA Report No. 600/7-77-011,
January 1977, pp. 17-33, and Appendix 1.
3. Arthur G. McKee and Company. 100,000 Pound Per Hour Boiler Cost Study.
Prepared for the U.S. Department of Energy under Contract No. EX-76-C-
01-2418. July 27, 1978.
4. Letter correspondence from Dr. R.A. Newby of Westinghouse Research and
Development to Mr. C.W. Young of GCA/Technology Division. Preliminary
data from draft report. Effect of 862 Emission Requirements on Fluidized—
Bed Boilers for Industrial Applications: Preliminary Technical/Economic
Assessment. April 30, 1979.
5. Sun, C.C., C.H. Peterson, R.A. Newby, W.G. Vaux, and D.L. Keairns.
Disposal of Solid Residue from Fluidized-Bed Combustion: Engineering
and Laboratory Studies. Prepared by Westinghouse Research and Develop-
ment Center for the U.S. Environmental Protection Agency. EPA-600/7-78-
049, pp. 4-5. March 1978.
6. Keairns, D.L., et al. Fluidized-Bed Combustion Process Evaluation; Phase
II - Pressurized Fluidized-Bed Coal Combustion Development. Westinghouse
Research Laboratories. Prepared for U.S. Environmental Protection Agency
EPA Report No. EPA-650/2-75-027c. September 1975. pp.273-286.
7. The Resource Conservation and Recovery Act of 1976. Public Law 94-580
October 21, 1976.
8. Minnick, L.J. Development of Potential Uses for the Residue from
Fluidized-Bed Combustion Processes, Quarterly Technical Progress
Report. Prepared for the U.S. Department of Energy, by L. John
Minnick. December 1978 - February, 1979.
9. Telephone conversation between Dr. H. Bennett, Coordinator for DOE's
Agricultural Program for FBC Solid Wastes, and Dr. T. Goldshmid of
GCA/Technology Division, February 28, 1979.
10. Sun, C.C., et al. op cit., pp. 3-7.
11. Stone, R., and R.L. Kahle. Environmental Assessment of Solid Residues
from Fluidized-Bed Fuel Processing: Final Report. Prepared by Ralph
Stone and Company, Inc., for the U.S. Environmental Protection Agency.
EPA-600/7-78-107, p. 9. June 1978.
290
-------
12. Crowe, J.L., and S.K. Seale. Characterization of Solid Residues from
Fluidized-Bed Combustion Units. Prepared by the Tennessee Valley
Authority for the U.S. Environmental Protection Agency. EPA-600/7-78-
135, p. 14. July 1978.
13. Devitt, T., et al. op cit., pp. 112-126.
14. Telephone conversation between Mr. Alan Downhatn, Foster-Wheeler Energy
Corporation, Livingston, New Jersey, and Ms. J.M. Robinson, GCA/Technology
Division, November 9, 1978.
15. Telephone conversation between Mr. Jerry Kennedy, Babcock and Wilcox,
Industrial Marine Division, Alliance, Ohio, and Mr. C.W. Young, GCA/
Technology Division, November 6, 1978.
16. Telephone conversation between Mr. Andrew Grant, Babcock Contractors,
Inc., Pittsburgh, Pennsylvania, and Mr. C.W. Young, GCA/Technology
Division, November 3, 1978.
17. Telephone conversation between Mr. Kent Pilz, Johnston Boiler Company,
Ferrysburg, Michigan, and Mr. C.W. Young, GCA/Technology Division,
Bedford, Massachusetts, November 20, 1978.
18. Telephone conversation between Dr. Porter, Energy Resources Company,
Cambridge, Massachusetts, and Ms. J.M. Robinson, GCA/Technology Division,
Bedford, Massachusetts, November 2, 1978.
19. Telephone conversation between Mr. V. Loiselle, Combustion Engineering,
Inc., Windsor, Connecticut, and Ms. J.M. Robinson, GCA/Technology Division,
Bedford, Massachusetts, November 3, 1978.
20. Telephone conversation between Mr. D. Vines, Mass Engineering Company,
Avon, Massachusetts, and Mr. C.W. Young, GCA/Technology Division,
Bedford, Massachusetts, January 16, 1979.
21. Telephone conversation between Mr. C. Kraven, Control Engineering and
Technology, Boston, Massachusetts, and Mr. C.W. Young, GCA/Technology
Division, Bedford, Massachusetts, January 19, 1979.
22. Telephone conversation between Mr. David Bennett, Simplicity Engineering
Company, Durand, Michigan, and Ms. J.M. Robinson, GCA/Technology Division,
Bedford, Massachusetts, January 29, 1979.
23. Telephone conversation between Mr. K. Herron, C.E. Tyler Elevator Products,
Menton, Ohio, and Mr. C.W. Young, GCA/Technology Division, Bedford,
Massachusetts, January 22, 1979.
24. Letter correspondence from Dr. R.A. Newby of Westinghouse Research and
Development to Mr. C.W. Young of GCA/Technology Division. Preliminary
data from draft report. Effect of S0£ Emission Requirements on Fluidized-
Bed Boilers for Industrial Applications: Preliminary Technical/Economic
Assessment. April 30, 1979.
291
-------
25. Farmer, op cit., pp. 17-33, and Appendix 1.
26. Arthur G. McKee and Company, op cit.
27. Telephone conversation between Mr. D. Vines, Mass Engineering Company,
Avon, Massachusetts, and Mr. C.W. Young, GCA/Technology Division, Bedford,
Massachusetts, January 16, 1979.
28. Ibid.
29. Ibid.
30. Ibid.
31. Memoranda from Mr. J. David Mobley of the U.S. Environmental Protection
Agency to the Industrial Boiler Distribution List. April 26, 1979,
and May 9, 1979.
32. Devitt, T., et al.. op cit., pp. 112-126.
33. Technical Notes for the Conceptual Design for an Atmospheric Fluidized-
Bed Direct Combustion Power Generating Plant. Prepared for the U.S.
Department of Energy by Stone & Webster Engineering Corporation in
conjunction with Pope, Evans, and Bobbins, Inc. , Babcock & Wilcox
Company, and Foster-Wheeler Energy Corporation. Volume 3A. March 1979,
p. 12-6.
34. Newby, R.A., et al. Effect of S02 Emission Requirements on Fluidized-
Bed Combustion Systems: Preliminary Technical/Economic Assessment.
Prepared by Westinghouse Research and Development Center for the U.S.
Environmental Protection Agency. EPA-600/7-78-163. August 1978,
Appendix D.
35. Letter correspondence from Dr. R.A. Newby of Westinghouse Research and
Development to Mr. C.W. Young of GCA/Technology Division. Preliminary
data from draft report. Effect of S02 Emission Requirements on Fluidized-
Bed Boilers for Industrial Applications: Preliminary Technical/Economic
Assessment. April 30, 1979.
36. Arthur G. McKee and Company, op cit..
37. Farmer, op cit., pp. 17-33, and Appendix 1.
38. Roeck, D.R., and R. Dennis. Technology Assessment Report for Industrial
Boiler Applications: Particulate Control. Draft Report. Prepared by
GCA/Teci.nology Division for the U.S. Environmental Protection Agency.
June 1979, pp. 118-197.
39. Robinson, E.B., et al. Interim Report on Characterization and Control
of Gaseous Emissions from Coal-Fired Fluidized-Bed Boilers. Prepared by
Pope, Evans, and Robbins for the U.S. Department of Health, Education
and Welfare. October 1970, Appendix B.
292
-------
40. Roeck, D.R., op cit.
41. Industrial Gas Cleaning Institute (IGCI). Particulate Emission Control
Cost for Intermediate-Sized Boilers. EPA Contract No. 68-02-1473, Task
No. 18, pp. 3-1 to 3-10. February 1977.
42. Roeck, D.R., op cit.
43. Dickerman, J.C. Flue Gas Desulfurization Technology Assessment Report.
Prepared by Radian Corporation for the U.S. Environmental Protection
Agency. January 26, 1979. Chapter 4.
293
-------
5.0 ENERGY IMPACT - FLUIDIZED-BED COMBUSTION
VERSUS CONVENTIONAL BOILERS
5.1 INTRODUCTION
The objective of this section is to quantify the energy impact of pollu-
tion control in an atmospheric fluidized-bed combustor when compared with the
power requirements of standard uncontrolled conventional boilers.
The pollutants controlled are S02, NOX» and particulatea. The inherent
chemistry of fluidized-bed combustion results in sufficiently low NOx emission-
that no energy penalty for NOx control is expected. Because particulate emis-
sions from the two technologies should be similar, (see Section 2.0) energy
requirements for AFBC particulate control are estimated based on conventional
firing control technology.1 Most of this discussion addresses the energy
impact of S02 control in fluidized-bed combustion.
A qualitative comparison of uncontrolled conventional firing, AFBC, and
conventional firing with wet scrubbing is presented in Table 48. Several
items of energy use common to all systems and of similar impact are noted.
Important energy impacts associated with flue gas desulfurization which are
not a factor in FBC are liquid pumping through the scrubber loop, absorption
tower pressure drop, and flue gas reheat.
Performance of a mass and energy balance around both an AFBC and a conve
tionally-fired design permits quantification of the energy requirements for
294
-------
TABLE 48. QUALITATIVE COMPARISON OF ENERGY IMPACT ASSOCIATED WITH
AFBC AND CONVENTIONAL COAL-FIRED INDUSTRIAL BOILERS
Subsystem
Coal handling
Limestone handling
Spent solids/
ash handling
Forced draft
fan
.
control
Wet scrubber
plant
Sensible heat
losi
Unburned carbon
other unaccounted
losses
Components of
energy use
Drying
Conveying
Calcinat ion
Sulf at ion
Conveying
Cooling
Air heater
coil heatt-'r
Plenum
Burners
Distributor plate
Fluid bed
Furnace
heater
Primary cyclone
Economizer
Air heater
Flues
Chemical feed
Heating
Slowdown
Operating power
Pumping
Absorber tower
Flue gas reheat
Spent solids/ash
Flue gas
Elutriation
Bottom ash
Fly aah
piping
AFBC with control Conventional Conventional Othef conments
without control with FGD
g '•• *• * AFBC has advantage of lower
Depending on sorbent reactivity, °f lower '°rbent Io*d-
energy added by sulfation can in*' du« *° lower re~
Lowest
* * The largest auxiliary power re-
fan operation. Assuming, 202 ex-
loss of 140 cm C>5 in.) w.g.
furnace ftp generally higher for AFBC opera-
* * device.
A A *
* * *
ble that hot side application will
AFBC than conventional boilers.
High auxi liary power
NA NA requirements in the
range of 2.02 of total
liary power requirement.
High energy loss com- lowest because only Intermediate due to
pared to conventional component is coal scrubber sludge loss
with and without s cubbing ash along with bottom
limestone.
Lowest because of low ex- intermediate because Highest losses due to
wet scrubbing.
* * * Pulverized coal firing has demon-
strated 99*1 carbon utilization.
Less of a percentage of the
total input as boiler size in-
to-volume ratios.
Indicates similar energy requirements or losses for different systema.
NA - Not applicable.
295
-------
both designs.* Each unit operation within the system was evaluated and the
loss component assessed. The detailed tables derived are presented in
Appendix C. The losses associated with each operation were grouped in terms
of auxiliary or inherent losses. Auxiliary losses are those deriving from
electric power requirements for process operations. Inherent losses are the
sensible heat losses, heat of reaction losses, and phase change losses.
Important energy losses in AFBC boilers are: air pressure drop across
the combustion air distribution plate, fluid bed, and primary cyclone; lime-
stone calcination; flue gas sensible heat loss; unburned carbon loss; solids
conveying; and spent solids sensible heat loss. A schematic diagram of a
standard AFBC industrial boiler system is shown in Figure 50, and illustrates
the auxiliary equipment necessary for SC>2 and particulate control.
In the following subsections, the energy impacts of AFBC operation are
itemized. The total energy impact of SC>2 reduction via AFBC is derived as a
function of SC>2 control level, standard boiler capacity, sorbent reactivity,
and coal characteristics. Ultimately, the increase in energy use over the
uncontrolled standard conventional boilers is presented along with a parametric
sensitivity analysis.
The results of these energy analyses indicate that energy penalty for
SC>2 control is mainly a function of boiler size. Large boilers firing
*
For this study, fluidized-bed combustion and conventional coal-fired boilers
having no 862 control are compared. For perspective, a comparison of a
fluidized-bed combustion and a conventional boiler system incorporating
flue gas desulfurization is made later in this section.
296
-------
V0
Figure 50. Schematic of AFBC industrial boiler including auxiliary equipment
(assumes carbon burnup cell will not be necessary).
-------
pulverized coal are more efficient than the AFBC furnaces; while the stoker-
fired furnaces are less efficient. Other variables which affect efficiency are
coal type and sorbent reactivity.
5.2 AUXILIARY EQUIPMENT ENERGY DEMAND FOR S02 CONTROL IN AFBC
Auxiliary power is used by the following components in AFBC boilers with
S02 control:
1. Coal handling (crushing, drying, conveying).
2. Boiler feedwater treatment, all pumping associated with
feedwater, condensate and cooling circulation, and other
miscellaneous systems.
3. Forced draft fan, induced draft fan (excluding power
needs for pressure drop through final particulate
control device), pneumatic feeding, etc.
4. Limestone handling, spent solids handling.
5.2.1 Coal Handling
Power requirements associated with coal handling include crushing, sizing
drying, and conveying. In this study, crushing and sizing are assumed to be
performed in the same process module, while conveying and drying require addi-
tional modules. Estimated power requirements are based on relationships
discussed in Perry's Handbook of Chemical Engineering, Sections 7, 8, and 20.2
In the crushing and sizing operation, coal is assumed supplied run-of-mine
(-6 in.). Required feed to the AFBC boiler is specified as 2.5 cm (-1 in.)
and under. The pulverized coal furnace requires -74 ym (-200 mesh) and the
stokers require -2.5 cm (-1 in.). Power requirement estimates are based on
the assumption that horsepower is directly proportional to reduction ratio
q
and capacity.
Coal drying to a moisture content of 5 percent is required for any
system using pneumatic coal feeding. The stokers and the AFBC designs
298
-------
do not require drying. The pulverized coal-fired boiler is the only unit
where coal drying is required. To meet a 5 percent moisture limit, 3.79 per-
cent moisture must be removed from the Eastern high sulfur coal and 15.8 per-
cent moisture must be removed from the subbituminous coal. No drying is
required for the Eastern low sulfur coal since the as-received moisture con-
tent is below 5 percent.
A fluidized-bed dryer was chosen for this study.* One of the major advan-
tages of this type of dryer in coal drying is the close control of conditions
ao that a predetermined amount of free moisture may be left with the solids
to prevent dusting during subsequent operations. Fuel requirements are from
1500 to 1900 Btu/lb of water removed and total power for blowers, feeders,
and related equipment is about 0.037 kW-hr/lb of water removed.11 For this
study an average requirement of 1700 Btu/lb of water removed was assumed.
Heat for drying is supplied by the boiler.
A point worth noting is that moisture not removed during the drying
operation results in a flue gas latent heat loss of 1040 Btu/lb of water plus
the sensible heat loss. Thus, while the drying requirement results in signifi-
cant increases in coal handling energy penalties, this loss is balanced by
somewhat reduced flue gas losses.
Energy requirements for conveying, include power to move coal from storage,
between process modules, and to the primary fuel hopper. Conveying is done
using belt, bucket, and flight conveyors and pneumatic equipment. Conveying
power requirements are based on correlations presented in Perry's coupled with
*Although a ball mill would be used for crushing and drying in the pulverized
case, the assumption of use of a fluidized bed dryer does not affect the
accuracy of the estimating procedure used here. The important factor in the
analysis is that some type of component is used do remove the level of
moisture noted.
299
-------
the total tonnage of material involved. Conveying power requirements include
a 50 percent contingency factor to cover intermittant loads. This adds 2 kW
to the small boiler energy loss and 10 kW to the largest boiler loss.
Table 49 summarizes auxiliary power required for coal handling in AFBC as
a function of boiler capacity, and coal. A comparison is provided with the
auxiliary requirements of the most likely competitive conventional system in
each of the respective size ranges.
5.2.2 Boiler Feedwater Treatment and Auxiliary Pumping Requirements
Power required for boiler feedwater treatment and all necessary pumping
is considered to be a function of boiler capacity only. Energy requirements
listed in Table 50 are based on forced circulation boiler pumping requirements
plus a 15 percent contingency to cover small and intermittent loads. These
power requirements are extrapolated from estimates for a forced circulation
boiler by Babcock and Wilcox Company.5 A forced circulation design was esti-
mated because many designs for FBC require forced circulation. If natural
convection proves feasible, pumping energy requirements can be reduced.
5.2.3 Forced Draft and Induced Draft Fan Power
Forced draft (FD) and induced draft (ID) power represents the largest
electrical consumption in AFBC operation. The FD fan must be of sufficient
capacity to move air through the air heater, ducting, plenum, distributor
plate, and fluid bed. The ID fan must transport flue gas from the freeboard,
through the primary cyclone, economizer, air heater, and flue. (Power required
for flue gas movement through the final particulate control device is discussed
later.) Table 51 shows total AFBC fan power requirements for combustion and
SC-2 removal as a function of boiler capacity. Fan power in conventional systems
is also shown for comparison. For a detailed breakdown of the components con-
sidered, see Appendix C, Table C-5.
300
-------
TABLE 49. AUXILIARY ENERGY REQUIRED FOR COAL HANDLING
Boiler capacity
MWt (106 Btu/hr)
8.8 (30)
22 (75)
44 (150)
58.6 (200)
Burner type
Stoker1"
AFBC
Stoker"1"
AFBC
Stoker
AFBC
Pulverized^
AFBC
Eastern
sulfur
6
6
12
12
22
22
373
29
Auxiliary energy
high Eastern low
coal sulfur coal
5
5
11
11
19
19
25
25
- KW
Subbituminous
coal
7
7
14
14
27
27
1796
35
GCA estimates.
Uncontrolled.
TABLE 50. AUXILIARY POWER* REQUIRED
FOR BOILER FEEDWATER
CIRCULATION, TREATMENT
AND ALL ASSOCIATED
PUMPING IN CONVENTIONAL
AND AFBC
Boiler capacity Auxiliary power
MWt (106 Btu/hr) KW (HP)
8.8 (30)
22 (75)
44 (150)
58.6 (200)
18 (25)
47 (63)
94 (125)
125 (167)
GCA estimates.
301
-------
TABLE 51. AUXILIARY POWER* FOR FORCED DRAFT,
INDUCED DRAFT, AND ANCILLARY AIR
Boiler capacity „ . Auxiliary power
M»t (106 5tu/hJ) Burner type ^
8.8 (30)
22 (75)
44 (150)
58.6 (200)
Stoker"1"
AFBC
Stoker"1"
AFBC
Stoker
AFBC
Pulverized
AFBC
42
115
91
287
172
574
277
766
Flue gas rates
(acfm)
12,500
10,000
31,400
25,120
62,800
50,240
73,200
67,570
GCA estimates.
Uncontrolled.
302
-------
Pressure losses through the economizer and other common equipment compon-
ents were estimated by reference to Steam/Its Generation and Use, by Babcock
and Wilcox. Pressure loss through the FBC distribution plate and fluid bed
was estimated by reference to experimental data reported by Pope, Evans, and
Robbins. For plate designs tested, the average pressure loss equaled twice
the velocity head. Assuming a range of superficial gas velocities in industrial
AFBC boilers between 1.8 to 2.4 m/sec (6 to 8 ft/sec), a representative loss
through the distribution plate is 38.1 cm (15 in.). Pressure loss (w.g.) in
the bed during PER testing was found to be approximately equal to the expanded
bed height.8 In this analysis, a bed depth of 122 cm (48 in.) is assumed for
estimating FBC FD fan power, in conformance with the bed depth recommended for
"best system" design.
The selection of this bed height represents a compromise between two
factors. First, increased bed depth results in increased pressure drop, which
puts more load on the forced draft fan. Conversely, decreasing the bed height
will result in lower sorbent and gas residence times with concomitant increases
in either sulfur emissions or sorbent requirements.
This interrelation between bed depth and sorbent requirement may severely
limit the application of bed height variation as a method of load following
(see Section 2.0). If bed height variation is attempted as a load following
technique, bed depths lower than 30 in. are possible. The lower value will
depend upon tube surface area which must be exposed to achieve the desired
boiler turndown. An important point to note is that this shallow bed will
have severely impaired sulfur capture capability and could not be maintained
without penalties in S(>2 emissions or sorbent requirements.9 It seems likely
that bed slumping, variation in superficial velocity, and bed temperature control
will be more acceptable methods of load following.
303
-------
While no one bed height will serve in all designs, an estimate of 122 cm
(48 in.) should be representative for conventional AFBC designs. In cases
where sorbent is expensive, or of low reactivity, the additional fan loss as-
sociated with increased bed depth (to obtain higher sorbent sulfation and
higher combustion efficiency) may be acceptable.
Flue gas rates required for calculating fan power requirements for con-
ventional boilers are average figures (i.e., subbituminous coal-firing) taken
from PEDCo reference data.10 Flue gas rates for AFBC were proportioned from
the conventional boiler estimates, assuming 20 percent excess air in all four
standard AFBC boilers. Combustion air rates for both systems were estimated
assuming a temperature of 22°C (80°F) for forced draft fan design. Fan power
was estimated using standard design practice and a fan efficiency of 65
percent.^
Total fan power requirements for AFBC with S02 control are about three
times that necessary for conventional boiler operation. AFBC fan power ranges
from 115 to 766 kW for boilers ranging in capacity from 8.8 to 58.6 MWt (30 to
200 x io6 Btu/hr). These figures represent the calculated power requirements
plus a 10 percent contingency to cover ancillary air requirements.
5.2.4 Limestone and Spent Solids Handling
Limestone and spent solids handling auxiliary power requirements were
estimated from the materials quantities coupled with the estimated unit power
requirements (in kW/100 kg of solids) presented in Table 52. Power requirements
for limestone and spent solids handling in Table 52 were determined by reference
to a system (approximate coal-fired capacity equals 34 MWt) under construction
by Foster-Wheeler.12
304
-------
TABLE 52. POWER USED FOR MATERIALS HANDLING IN AFBC COAL-FIRED BOILERS
OJ
0
Cn
1.
2.
3.
4.
5.
6.
7.
8.
9.
Feed
Fresh limestone air blower
Rotary feeders
Limestone feed air blower
Limestone screening (with dust control)
Solids cooler
Solids cooler fan
Spent solids air blower
Bin activators
Total
Unit power requirements kw/100 kg/hr
(HP/100 Ib/hr)
Power use - KW (HP)
Limestone handling Spent
Rate = 1,634 kg/hr (3,600 Ib/hr) Withdrawal Rate =
7.5
1.1
2.2
1.9
3.0
15.7
0.96
(10)
(1.
(3.
(2.
(4.
(21.
(0.
5)
0)
5)
0)
0)
58)
0
3
7
18
1
31
2
solids handling
1,362 kg/hr (3,000 Ib/hr)
.4
.0
.5
.6
.5
.0
.28
(0.
(4)
(10)
(25)
(2.
(41.
(1.
5)
0)
5)
38)
Based on correspondence with C.E. Tyler Elevator Products. (See discussion in text.)
-------
Materials quantities are a function of boiler size, coal type,
control level, and sorbent reactivity. The Ca/S molar feed ratios used in
Table C-6, Appendix C, are based on the test data presented in Section 3.0.
A range of Ca/S ratios is considered for each coal and each control level,
assuming a range of sorbent reactivities. Limestone is assumed to be 90
percent CaCOs, with 95 percent calcination to CaO. Spent bed material quantities
include limestone inerts, uncalcined limestone, unreacted CaO, CaSO^ generated
and coal bottom ash. (The exact method of calculating spent solids quantities
is shown in Section 6.0, Table 20).
The screening power requirements noted in Table 52 are based on correspon-
dence with C.E. Tyler Elevator Products of Mentor, Ohio.13 Although limestone
conveying and spent solids handling needs can be represented readily, limestone
crushing and screening requirements are difficult to characterize on a general
basis for two reasons. First, the particle size distribution of limestone
received from the quarry is variable from quarry to quarry. Second, because
the physical characteristics of different limestones are variable, the ultimate
limestone particle size distribution in the bed will be affected by attrition
and elutriation. In some instances, an appropriate particle size distribution
(average size of -500 ym) may be attained in the bed with no intermediate
processing required at the quarry or industrial site. In the extreme case,
crushing and screening may be necessary. In any event, limestone crushing and
screening requirements will be determined on a case-by-case basis.
To estimate auxiliary energy requirements for limestone processing at the
FBC site, using the input from C.E. Tyler Elevator Products, double screening
is assumed at the FBC site, but all crushing is performed at the quarry. Powe
is utilized in screening for mechanical vibration and for fan operation to
306
-------
convey entrained dust through a hood and cyclone or fabric collector. For
processing of 1,634 kg/hr (3,600 Ib/hr) limestone, total power for screening
and dust control is estimated at 1.9 kW (2.5 hp).14
Unit power requirements for materials handling, as shown in Table 52,
were applied to the full range of limestone and spent solids rates. Table 53
indicates the range of total materials handling power use as a function of
boiler capacity and firing method. Table 53 is a summary of Table C-6 which
details the complete range. Materials handling power requirements are
maximum at the highest sorbent feed rate; i.e., burning high sulfur coal
at a stringent S02 control level using a sorbent of low reactivity. For a
particular coal, variation in materials handling power is most dependent on
sorfaent reactivity.
5.2.5 Total Auxiliary Power Requirements
The various electrical loads identified in the previous subsections are
summed and presented in Table 54 as a function of coal grade, control level
and sorbent reactivity for the firing methods and boiler sizes considered.
Because this represents the purchased electric power requirements in an
industrial boiler, the heat supplied by the boiler for coal drying was sub-
tracted from the total in Table 54 and added to the inherent losses in
Section 5.3. Auxiliary power requirements for AFBC are higher than the
auxiliary power requirements for uncontrolled conventionally-fired boilers.
(Auxiliary power estimates for conventional units with S02 control would be
somewhat higher than the uncontrolled units.) The chief component of this loss
differential is the fan power requirements which represent roughly 60 percent
of the total auxiliary power purchased in a conventional system and 70 percent
for AFBC.
307
-------
TABLE 53. AUXILIARY POWER* REQUIRED FOR CONVENTIONAL
AND AFBC SOLIDS HANDLING
Boiler type
Stoker
AFBC
Stoker
AFBC
Stoker
AFBC
Pulverized coal
AFBC
Boiler capacity
MWt (106 Btu/hr)
8.8 (30)
22 (75)
44 (150)
58.6 (200)
Auxiliary power - KW
All coal
types
2 - 3t
3-19
4 - 7
8-48
9-14
16 - 96
12 - 19
22 - 128
t,
GCA estimates.
The range presented represents variability to expect
when going from Moderate control with a high reactivity
sorbent to Stringent control with a low reactivity
sorbent.
308
-------
TABLE 54. TOTAL AUXILIARY POWER REQUIREMENTS FOR AFBC AND
UNCONTROLLED CONVENTIONAL BOILERS - kW
BlHLtk CAHACIIir-Mw
SULFUrt (.UMtHOL
LlliL TYPf ItVtL »M> SUNHtNl
t'EHCt-ilAGE WtACTIVjr*
KtDUCI IUM
tflSltX'X HU,M S yiH AVtHAC.t
S(.ILfU>» LUft
( S,St h) MIUM
1 «Si AVLHAU
Hi".
Hl(,H
/H.7i AvLWAOt
LUK
HIC.H
U>
O
vO
Mll.n
KASltW" Ltlrt S/I 8i.9X AVtKAl.t
suojw I.UK
(i).4 . J 4S .
''.O *>4. 144.
i.e 1,9. i4«.
4.«? b<*. |(|«,
l.b b'l. 1. .Sdj", /Si>.
5/9. «^. 7S»,.
5Mo, 5i. /ft 7.
5Sb. <^<>i. /I 1 .
5S5. ^fi. 7dS.
5S3. ,"M. ?(,S.
5bb! ^9*1 7U'. . /1H.
5b7. 51V. 7li.
557. 5«2. 71 i.
559. J0<>. /!/.
356. 50*>. /ll.
( iji. vf '1 1 (" AL Af f(
>'•'). )0^/
*'*'!. H!U/.
V^- """'•
VC'. Mil/.
S'-1*. 1'iS^.
3VV.
Vl. W].
5 "» "* . 470.
5V1*. '>/u.
4V4. c!h'i.
?«/ «JJ<
4« / . >Jii ,' .
5ti/. 4J<(.
*«/. 9'in
iM / . 4au.
5«/. 'M/.
i-<<*. '»-i5
54<<. ''S/.
54<>. 4SO.
!•»•). 4SO.
^qcj_ <
-------
5.3 INHERENT ENERGY LOSSES IN THE FBC SYSTEM
Energy losses (other than auxiliary power) associated with AFBC coal
combustion are the heat losses in flue gas and spent solids, limestone calcina-
tion, unburned carbon, and radiative and convective losses. (The total inherent
energy loss also includes the coal drying losses estimated in the previous
subsection.) Each loss is quantified and the effects of design and operating
variations are discussed.
5.3.1 Flue Gas Heat Loss
Flue gas heat loss represents the single largest loss associated with
coal-fired steam production. The components of this loss are latent heat,
sensible heat, and humidity. The magnitude of each component is a function of
coal composition and moisture content, excess air, and temperature differential
between ambient air and flue gas. The temperatures assumed in the analysis
are: ambient - 27°C (80°F); conventionally-fired high sulfur flue gas - 200°C
(400°F); conventionally-fired low sulfur and subbituminous flue gas - 175°c
(350°F). Flue gas temperatures are assumed at 175°C (350°F) in all AFBC cases.
Excess air rates o£ 50 percent for stoker-fired boilers, 30 percent for
pulverized coal furnaces, and 20 percent for AFBC were used in this study.
The conventional boiler excess air rates are taken from the PEDCo study.15
The AFBC air rate is the mid-range commonly reported by vendors. Reduction of
the excess air to 10 percent may be possible through improved design and two-
stage combustion. (Two-stage operation is being investigated in Sweden by
0. Mustad and Son.)
Coal composition and moisture content affect the sensible and the latent
heat content of the flue gas. Coal analyses and moisture content are taken
from the PEDCo study of conventionally-fired boilers16 (see Table C-l) , in
310
-------
Appendix C). In the cases where coal drying is required, the flue gas sensible
heat loss is reduced by the amount of moisture removed during drying. The
results of the flue gas heat loss calculations are shown in Table 55.
5.3.2 Solids Heat Loss
The heat loss accompanying spent solids withdrawal is calculated using a
standard heat balance of the form:
0 = W • C • (T - T. )
x out p out in
*out
where the heat capacity (C ) of spent bed material plus ash is 947 J/kg-°K.
The weight of the material out is represented by W, the temperature by T, and
the heat loss by Q. A value of 947 J/kg-°K is also assumed for the ash in
conventional boilers. The AFBC bed solids temperature differential is 1480°F
and the conventional bottom ash temperature differential is 1700°F.
For AFBC, 90 percent of the input ash is retained as bed residue. The
8.8 MWt, and 22 MWt stokers retain 75 percent of the ash as bottoms, the
44 MWt stoker retains 35 percent as bottoms, and the pulverized coal-fired
58.6 MWt unit retains 20 percent. Even though some solids exit the system as
bottom residue and other material exits with the flue gas, both stream solids
losses (bottoms and elutriated) are reported in Table 56 as solids heat losses.
The differentiation between retained solids and elutriated solids is necessary
because of the temperature differences between solids in the bed and solids in
the flue gas. Systems with higher entrainment rates have lower solids heat
losses because of cooling and subsequent heat recovery from the solids and
flue gases in the economizer.
In addition to the sensible heat loss in the FBC, both the endothermic
limestone calcination reaction and the exothermic sulfation reaction must be
accounted for. Calcination requires 3,178 kJ/kg per kg CaO produced and
311
-------
TABLE 55. FLUE GAS HEAT LOSSES
Heat losses - KW
Boiler capacity
MWt (106 Btu/hr) urner vPe Eastern high Eastern low Subbituminous
sulfur sulfur coal coal
8.8 (30)
22 (75)
44 (150)
58.6 (200)
Stoker
AFBC
Stoker
AFBC
Stoker
AFBC
Pulverized
AFBC
1277
955
3192
2388
6384
4777
7381
6369
1065
883
2664
2207
5327
4415
6317
5886
1270
1074
3176
2685
6351
5370
6506
7160
— • _^ _ _ — . _ — .
"See Appendix C, Table C-l for coal analyses on which heat loss
calculations are based.
TABLE 56 ENERGY IMPACT OF SOLIDS HEAT LOSS
(INCLUDES CALCINATION AND SULFATION
REACTIONS FOR FBC)
Energy impact - kW*
Boiler type
Stoker
AFBC
Stoker
AFBC
Stoker
A1BC
MWt (106 Btu/hr)
8.8 (30)
22 (75)
44 (150)
Pulverized coal 5g>6 (2Q(J)
All coal
types
13 - 24
1 - 213
33 - 61
3 - 533
39 - 72
6 - 1066
37 - 72
8 - 1421
Assumes no heat recovery from the withdrawn spent
bed material.
312
-------
sulfation of CaO releases 8,668 kj/kg per kg CaO consumed.18 This consideration
provides further impetus for using highly reactive sorbents and low Ca/S ratios.
In cases where the sorbent stone is highly sulfated, a net heat release for
the two reactions can be achieved.
The solids heat balance is summarized in Table 56. (The complete table
presenting all values is in Appendix C, Table C-10.) This table presents the
range of values calculated when one considers moderate control with high
reactivity sorbent through stringent control with low reactivity sorbent.
When sensible heat, calcination, and sulfation are accounted for, energy losses
range from 1 to 213 kW for the small boiler (8.8 MW ) and 8 to 1421 kW for the
larger boiler (58.6 MWt).
Variables which will affect the total solids loss are: the quantity of
ash and limestone input, the retention/elutriation split, flue gas and spent
solids exit temperature, and the degree of calcination and sulfation achieved.
The quantity of limestone required is a function of coal sulfur, 862 control
level, and limestone reactivity. Selection of a reactive limestone and pre-
cise control of the Ca/S molar feed ratio will both serve to minimize these
losses.
5.3.3 Combustion Losses
A wide range of combustion efficiencies has been reported for AFBC units:
85 to 90 percent for units operating without recycle of solids from the primary
cyclone and 95 to 97 percent for units operating with recycle.19,20,21
Convention-firing combustion efficiencies range from 95 to 97 percent for
spreader stokers with recycle. Pulverized coal units (the 58.6 MW conven-
tional case) have demonstrated the capability of routinely achieving 99+ per-
cent combustion efficiency.
313
-------
For this study the upper end of the reported range, 97 percent, was
assumed achievable for both spreader stoker and AFBC boilers. A combustion
efficiency of 99 percent was assumed for the pulverized coal-fired unit.
Table 57 presents the combustion loss estimates based on the efficiencies noted,
TABLE 57. COMBUSTION LOSS
„ . , . Energy loss - kW
Boiler capacity
MWt (106 Btu/hr)
8.8 (30) 264 264
22 (75) 659 659
44 (150) 1,318 1,318
58.6 (200) 586 1,757
The combustion efficiencies assumed can be achieved through both g0od
design practice and good operating procedures. Recent AFBC designs, for
have higher freeboards than earlier systems. This higher freeboard improv
combustion efficiency, probably by reducing char elutriation. Increasin
residence time with deeper beds and lower superficial velocities at *-Q
t ecommended
for improved sulfur retention also serves to improve combustion efficie
Operator-controlled variables which affect combustion efficiency ar th
ratio of char recycle to char rejection, coal sizing, and the superficial vel
city. Recycle of a large percentage of the elutriated material will increase
carbon burnout while increasing the load on the particulate control device.
Rejection of coal fines will reduce the char elutriation problem while increasing.
coal costs. Low superficial velocities will reduce solids carryover while
requiring a larger boiler size for a given steam output. Thus, each option
for improved carbon burnout is accompanied by an attendant cost or operability
penalty.
314
-------
5.3.4 Radiative and Unaccounted-For Losses
Radiative losses are a direct function of the surface emissivity, the
fourth power of the absolute temperature, and the surface area. These radiative
losses, as well as convective losses, occur from the boiler walls, steam pipes
and other equipment where a temperature differential exists.
In estimating these losses, AFBC surface area plus piping was assumed
equal to an equally rated conventionally-fired furnace plus piping. While
early units had smaller total surface areas, increased freeboard in later
designs has resulted in AFBC units with total volumes roughly equal to those
of conventional units.22
A combined radiative and convective heat transfer coefficient of 15,560
J/m2 - °C (2.5 Btu/ft2 - °F) was determined from reference to Pe-ry's Handbook
of Chemical Engineering.23 An average surface temperature of 200°C (400°F)
was assumed. Dimensional proportions of equal height and depth, and width
equal to one-half the height were used for heat loss calculations. The calcula-
ted losses include contingency losses such as piping, blowdown, and other small,
intermittent losses. The resultant losses decrease from 3 percent down to 1.5
percent of the total heat input when the size is increased from 8.8 MWt up to
58.6 MWt. Table 58 shows the losses in kW.
TABLE 58. RADIATIVE, CONVECTIVE,
AND OTHER UNACCOUNTED
LOSSES
Loss by boiler
Boiler capacity type - KW
MWt (106 Btu/hr)
Convent ional/AFBC
8.8 (30) 265
22 (75) 479
44 (150) 750
58.6 (200) 903
315
-------
These estimates reflect the economy-of-scale savings which result due to
continuously decreasing surface-to-volume ratios with increasing boiler size.
5.3.5 Total Inherent Energy Penalties
All inherent losses associated with AFBC and uncontrolled conventional
coal-fired industrial boilers (from Tables 55, 56, 57, and 58) are summed
in Table 60 for each case - low, medium, and high reactivity sorbents; SIP,
moderate, intermediate, and stringent control levels; and subbituminous, Eastern
low sulfur, and Eastern high sulfur coals. There is no variability for the
conventionally-fired boilers except by coal type and boiler capacity. Fuel-
to-steam thermal efficiencies are estimated based on these inherent losses.
The FluiDyne unit reported in Table 59 is the 1 m * 1.62 m air heater with
primary cyclone recycle. The B&W unit is a 3 ft x 3 ft test bed with no reCycie
capability. The Enkoping unit is a 10 ft x 10 ft commercial steam generator
capable of firing coal, oil, and gas.
TABLE 59. INHERENT LOSSES AS PERCENT OF THERMAL INPUT
Unit
Flue gas loss
(Flue gas losses - adjusted)
Solids loss
Radiative loss
Combustion loss
GCA Estimate
10.5
-
1.6
3.0
3.0
FluiDyne
22.7
(7.0)
1.9
3.0
1.7
it B&W25
3 ft x 3 ft
22.7
(13.8)
0.6
6.8
17.4
5.6
(6.9)
1.5
0.5
0
Losses in flue gas are adjusted to ITAR Design Conditions.
Combustion air
Loss
design
Teurn
actual
'design
x Loss
Combustion air
actual
Temp
design
actual
316
-------
TABLE 60. INHERENT ENERGY LOSSES OF UNCONTROLLED CONVENTIONAL BOILERS AND AFBC BY
COAL SULFUR CONTENT, CONTROL LEVEL, AND SORBENT REACTIVITY - kW
BOILER CAPACm-«M
SULUJR CONTHOL
CUAL 'm LEVtL AND
PEKCtNTAGt
REDUCTION
EASTtKtt "1UH S <»OX
SULt-UK
C4.5X S)
1 .U
* IH.I*.
SIP SbX
fc*ST£H« LOh S/I 84. 9X
SULI-UM
(0.9X b)
M 75X
SUHHl luMINOUS S/l 83. it
LOW SULUJK
(0.6* S)
M 75*
SURBENT
REACTIVITY
AVtNAGl
LOW
HIGH
AVtNAGt
LOW
HIGH
AVtRAUt
LUw
HIGH
AVEMAGt
LUn
HIGH
AvtKAbt
LU«
HIGH
AVtRAGt
LOW
HIGH
AVERAGE
LOW
HIGH
AVtHAGE
LOH
HIGH
CA/S
HAtia
4.2
2.9
3.8
I.' 8
1.0
1.2
U.8
I'.l
lib
)!b
2.0
3!2
l.b
8.8
CUNVtN'IONAL
1830.
18)0.
U10.
1830.
1830.
imo!
JB30.
1830.
IdJO.
1830.
1608.
1608.
16UH.
1606.
1608.
ielS:
1814.
1814.
1814.
AFBC
170*1
1601.
1678.
1577.
1518!
1485.
1502.
1468.
l«6l!
1137.
|42b.
1635.
1651.
1629.
1647.
1618.
22
CONVENTIONAL
4)9] '.
439J.
4)91.'
4391.
4391.
4391.
4391.
4391.
4391.
38)5.
38)5.
3835.
38)5.
3835.
3835.
4351,
435l!
4351.
4351.
4)51.
AFUC
3885.
4076.
3674.
3820.
4010.
3651.
3759.
3950.
3611.
3529.
3572.
3487.
3.42S.
3470.
3391.
3408.
3454.
3)80.
3904.
394M.
3874.
3889.
3933.
3862.
44
CONVENTIONAL
8524.
8524.
8524.
6524.
85?4.
8524.
B524.
8524.
8524.
8524.
8524.
6524.
7434.
7434.
7434.
74)4.
7434.
74)4.
8463.
84b3.
84b3.
8461.
84bl.
8463.
AFHC
7562.
79
-------
Table 59- lists the relative inherent loss attributable to each identified
component for AFBC and three operating units. The range in the flue gas
for the operating units presented in Table 59 are a function of excess air
flue gas exhaust temperatures, and fuel analyses which differ from the ITAR
design assumptions. The row titled (Flue Gas Losses - Adjusted) represents
estimated losses at the three units after compensating for the differences in
excess air and temperature. Any remaining differences are a function
of fuel analysis and water content.
The rather high combustion loss of over 17 percent reported for the B&W
3 ft x 3 ft is not considered representative for fluidized beds. The 6 ft x
6 ft unit at B&W (which is an improved design) routinely achieves 91 to 96
percent combustion efficiency. The combustion efficiency reported for the
FluiDyne unit is for coal combustion with primary cyclone recycle.
5.4 ENERGY IMPACT OF S02 CONTROL BY AFBC
The energy impact of S02 control is defined as the increase (or decrease)
in energy requirements for the controlled FBC case, as compared to the convert
tionally-fired uncontrolled boiler. Comparisons are made on the basis of
total energy requirements; i.e., auxiliary losses plus inherent losses. For
conventional S02 control methods, where some energy consuming device is added
onto the conventional boiler, a net energy penalty must ensue. In the case of
AFBC, the conventional boiler is eliminated and replaced by an integrated
This reporting mode was developed to facilitate quantification of the enerev
penalty associated with implementing a specific technology as an SC^
r-nnt-rn] nntTOn.
control option
318
-------
system of steam raising and S02 control within the same vessel. The net
result is, in many instances, a net reduction in energy requirements, which
in turn is reported as a negative energy penalty.
5.4.1 Efficiency
The efficiency is calculated on the basis of boiler input minus total
losses.* Calculated efficiencies for AFBC are presented in Table C-17 and
Figure 51. The conventionally-fired system efficiencies are included for
comparative purposes.
Boiler efficiency improves with increasing boiler size, decreasing coal
sulfur content, decreasing S02 control level, and increasing sorbent reactivity.
The relative importance of these variables with respect to efficiency, in
order of decreasing effect, is:
1. Coal sulfur;
2. Sorbent reactivity;
3. Boiler capacity; and
4. Control level.
While the ranking of these variables is somewhat a function of the assump-
tions incorporated within the analysis, the range considered is sufficiently
broad that the results should be applicable to most commercial situations.
Efficiency estimates for the small boiler (8.8 MWt) range from a low of
78.8 percent for Eastern high sulfur coal, stringent control, and low reactivity
stone up to 82.2 percent for Eastern low sulfur coal, moderate control, and
high reactivity sorbent. For the large (58.6 MWt) boiler, efficiencies range
Total losses are auxiliary plus inherent losses.
319
-------
EASTERN HWH SULFUR
u 83
S 82
80
8.6 22 44 H.6
BOLER INPUT, MWt
AFBC EFFICIENCY ENVELOPE
EASTERN LOW SULFUR
89r
84-
80 •
*8 22 44 586
BOILER INPUT, MW,
SUBBITUUINOOS
89
o
80
8.8 22 44 98 «
BOILER INPUT, MWt
Figure 51. Station efficiency for AFBC and uncontrolled
conventional boilers.
320
-------
from a low of 80.3 percent for Eastern high sulfur coal, stringent control,
and low sorbent reactivity up to 83.6 percent for Eastern low sulfur coal,
moderate control, and high reactivity sorbent.
The efficiency of AFBC is as high or higher than the efficiency of a
comparably-sized stoker-fired boiler for all cases. The pulverized coal-fired
unit is more efficient than any AFBC option considered.
Overall fuel-to-steam* efficiencies reported in the literature for operating
units are generally within the range covered by the GCA estimates. For example,
CE27 reported an efficiency of 81.8 percent and Johnston Boiler28 reported an
efficiency of 81.4 percent for high-sulfur high-ash coal, and 83.4 percent for
low-sulfur low-ash coal. These efficiencies are all within the range of fuel-
to-steam efficiencies estimated by GCA. The minimum efficiency estimated by
GCA is 81.0 percent and the maximum is 83.8 percent for the 8.8 MWt boiler.
5.4.2 Energy Penalty as kW/kg SC>2 Removed
Calculated energy differentials are divided by kilograms of SC>2 removed.
This resultant value (kW/kg SC-2 removed) is the measure of effectiveness of
an SC-2 control device for the technology (in this case, AFBC) in question.
The kW/kg SO? removed calculated for each case under consideration is presented
in Table C-18. Table 61 is an abbreviated listing of the energy penalty range
expected for each coal type and boiler size over the range of control levels
and sorbent reactivities investigated.
Fuel-to-steam efficiency excludes auxiliary losses,
321
-------
CO
N5
TABLE 61. RANGE OF kW/kg S02 REMOVED BY COAL TYPE AND BOILER SIZE
Boiler capacity - MWt
8.8 22 44 58.6
Eastern high sulfur* -12.4 to -1.0 -12.2 to -0.8 -11.7 to -0.5 1.3 to 7.6
Eastern low sulfur"1" -16.2 to -9.5 -15.3 to -8.7 -14.2 to -7.7 27.7 to 34.9
Subbituminous1" -19.0 to -12.3 -18.1 to -11.5 -16.8 to -10.3 15.0 to 20.5
Range is from SIP up to stringent S02 control for low to high reactivity sorbent.
Range is from moderate up to stringent S02 control for low to high reactivity
sorbent.
-------
Examination of Table 61 reveals that the energy savings of AFBC over
uncontrolled conventional units is greatest for the smaller units burning low
sulfur coal. As unit size and/or coal sulfur increase, the energy savings for
AFBC decrease. Finally, for the largest unit considered (58.6 MWt), the uncon-
trolled conventionally-fired unit is more energy efficient than AFBC.
5.4.3 Efficiency of AFBC as a Percentage of Thermal Input
The energy impact of controlling SC-2 by AFBC and the increase in energy
requirements when control levels more stringent than SIP are adopted are pre-
sented in Tables 62 and 63. The values of energy consumption are presented in
terms of: energy consumed by control device; and percent change in energy use,
compared to uncontrolled conventional boilers and AFBC boilers with SC-2 control
at an average SIP level.
The impact of controlling SC>2 to an average SIP level of 1,075 ng/J
(2.5 lb/106 Btu) is germane only when burning Eastern high sulfur coal where
the required SC-2 reduction is 56 percent. The SIP control level does not apply
to the Eastern low sulfur and subbituminous coals. The SIP energy requirements,
as well as energy requirements for all other options considered, are presented
in Table C-16.
These values were used as a basis to calculate entries in the last column
of Tables 62 and 63. The incremental energy requirements between SIP control
and the more stringent control levels ranges from 0.61 to 2.41 percent. The
percent increase over uncontrolled conventional-firing ranges from -2.6 up to
3.2 for all cases considered. The reported percentage increase is calculated
as follows:
323
-------
TABLE 62. ENERGY CONSUMPTION FOR S02 CONTROL FOR AFBC COAL-FIRED BOILERS, 8.8 MWt
(30 x 106 Btu/hour) CAPACITY
to
System
Standard boiler
Heat input Level ?f reduction
Fuel tvoc control j
MWt (MBtu/hr)
8.8 (30) Eastern Stringent 90
high sulfur
(3.5Z S)
Intermediate 85
Moderate 78.7
SIP 58.6
Eastern Stringent 83.9
low sulfur or
(0.9Z S) Intermediate
Moderate 75
Subbituminous Stringent 83.2
(0.6Z S) or
Intermediate
Moderate 75
Sorbent
reactivity
Average
Low
High
Average
Low
• High
Average
Low
High
Average
Low
High
Average
Low
High
Average
Low
High
Average
Low
High
Average
Low
High
Energy consumption
Percent increase
Ca/S Energy consumed in en?F«[ U8e ove! ,
... mi uncontrolled conventional
ratio KH . . ,
boiler as percent
of boiler input
3.3
4.2
2.3
2.9
3.8
2.1
2.5
3.4
1.8
1.0
1.2
0.8
2.8
3.7
2.0
2.2
3.2
1.6
2.7
3.6
2.0
2.2
3.2
1.6
-117
- 37
-205
-144
- 65
-215
-170
- 91
-231
-267
-250
-285
- 88
- 71
-103
- 97
- 77
-108
-104
- 88
-177
-111
- 92
-122
-1.33
-0.42
-2.33
-1.64
-0.74
-2.44
-1.93
-1.03
-2.63
-3.03
-2.84
-3.24
-1.00
-0.81
-1.17
-1.10
-0.88
-1.23
-1.18
-1.00
-2.01
-1.26
-1.05
-1.39
Percent change in
energy use over SIP
controlled AFBC
boiler
1.70
2.42
0.91
1.40
2.10
0.80
1.10
1.81
0.61
-------
TABLE 63. ENERGY CONSUMPTION FOR S02 CONTROL FOR AFBC COAL-FIRED BOILERS,
58.6 MWt (200 x 106 Btu/hr) CAPACITY
CO
to
Ui
System
Standard boiler
Level of
Heat input „ _ _ control
MHt (MBtu/hr)
58.6 (200) Eastern Stringent
high sulfur
(3.5Z S)
Intermediate
Moderate
SIP
Eastern Stringent
low sulfur or
(0.9Z S) Intermediate
Moderate
Subbituminous Stringent
(0.6X S) or
Intermediate
Moderate
CA~
.S°2 Sorbent
reduction reaceivity
90 Average
Low
High
85 Average
Low
High
78.7 Average
Low
High
56 Average
Low
High
83.9 Average
Low
High
75 Average
Low
High
83 . 2 Average
Low
High
7 5 Average
Low
High
Ca/S
ratio
3.3
4.2
2.3
2.9
3.8
2.1
2.5
3.4
1.8
1.0
1.2
0.8
2.8
3.7
2.0
2.2
3.2
1.6
2.7
3.6
2.0
2.2
3.2
1.6
Energy consumed
KW
1,327
1,855
741
1,143
1,671
674
972
1,500
561
321
438
204
1,479
1,594
1,377
1,422
1,550
1,345
794
904
708
749
872
676
Energy consumption
Percent increase
in energy use over
uncontrolled conventional
boiler
2.26
3.17
1.26
1.95
2.85
1.15
1.66
2.56
0.96
0.54
0.75
0.35
2.52
2.72
2.35
2.43
2.65
2.30
1.35
1.54
1.21
1.28
1.49
1.15
Percent change in
energy use over SIP
controlled AFBC
boiler
1.72
2.42
0.92
1.40
2.42
0.80
1.11
1.81
0.61
-------
(1°88)AFBC " (1°3S)*
% increase = x
Total thermal input
where * represents either uncontrolled conventional boiler loss or AFBC SIP-
controlled loss. Although the energy envelopes overlap, the conclusions to
be drawn are quite clear. For a given sorbent reactivity, S02 control level
variability has a significant energy impact only for Eastern high sulfur coal
When highly reactive sorbents are used in the large boiler, all coals have
nearly the same energy penalty (-1 percent). For the low reactivity sorbents
high sulfur Eastern coal usage is accompanied by an increase of 2.6 percent to
3.2 percent in the large boiler (58.6 MWt) energy requirements. This range
is a function of control level variability.
5.5 SENSITIVITY ANALYSIS
Several parameters which could be expected to affect the energy consump-
tion of an AFBC system were varied through the extremes of a plausible range.
The variables examined were excess air, calcium-to-sulfur ratio, combustion
efficiency, sorbent reactivity, and spent solids heat recovery. A baseline
around which these parameters were varied was also defined. The base condition
as well as the range of each parameter investigated are tabulated in Table 64
Boiler efficiency was selected to measure the effect of parametric variation
on energy requirements. Boiler efficiency is defined as:
efficiency - (tthermal input - inherent losses]/thermal input) x 100
The conventional boiler parameters were held constant throughout this analyst
The results presented for each parameter are generated with a computeriz H
mass and energy balance. For each set of conditions, all necessary parameter
are fed into the program. A mass balance is then performed for the specified
326
-------
TABLE 64. FBC PARAMETRIC CONSIDERATIONS
(EASTERN HIGH SULFUR COAL)
Parameter
Excess air, %
Combustion efficiency, %
Ca/S ratio, m/m
S02 control efficiency
(sorbent reactivity, %)
Coal Sulfur, %
Coal HHV, Btu/lb
Spent solids heat recovery, %
(Spent solids temp., °F)
Flue gas temperature, °F
Bottom Ash, %
Std. Condition
20
97
3.5
90
3.5
11,800
0
1,500
350
90
Range
0 -
80 -
1 -
70 -
1 -
—
0 -
1,550 -
—
—
100
100
10
95
10
100
300
327
-------
conditions. The results of this mass balance are used to determine heat losses
around the furnace. These losses are summed to arrive at a calculated boiler
efficiency.
5.5.1 Calcium to Sulfur Ratio
The calculated effect of calcium-to-sulfur ratio on boiler efficiency
is linear based on the results obtained when the Ca/S ratio is varied from
0 to 10. Because the effect is linear, an equation of the form
Efficiency = a (Ca/S) + b
was determined by linear least squares regression analysis for each boiler.
The general equation, the conventional boiler efficiency, and the breakeven
Ca/S ratio are presented in Table 65 and Figure 52.
TABLE 65 GENERAL EQUATIONS RELATING BOILER EFFICIENCY TO Ca/S
FOR EASTERN HIGH SULFUR COAL
Conventional
Boiler - MWt
8.8
22
44
58.6
E* =
E =
E =
E •
-0
-0
-0
-0
Equation
.963
.963
.963
.963
x (Ca/S)"1" +
x (Ca/S) +
x (Ca/S) +
x (Ca/S) +
85
85
86
86
.0
.9
.3
.5
Boiler
Efficiency
79.
80.
81.
84.
5
4
0
2
— — — _
Breakeven
Ca/S
5
5
5
2
.73
.66
.53
.38
*
Boiler efficiency.
Calcium-to-sulfur ratio.
This breakeven Ca/S is determined by substitution of the conventional
boiler efficiency into the generalized equation. Any Ca/S requirement less
than the brea. even point results in AFBC operation with a higher efficiency
than the uncontrolled unit. The breakeven Ca/S ratio of 2.38 for the 58.6 MWt
unit indicates that, under the assumptions upon which this study is based, any
lower Ca/S is sufficient for AFBC technology to exceed the efficiency of pul-
verized coal-fired technology.
328
-------
CONVENTIONAL UNITS
• 8.8 MWt STOKER
• 22 MWt STOKER
• 44 MWt STOKER
A 98.6 MWt PULVERIZED COAL
58.6 MWt AFBC
'•*- 44 MWt AFBC
>«*- 22 MWt AFBC
74
Figure 52. Boiler efficiency as a function of
Ca/S molar feed ratio.
328a
-------
If AFBC Ca/S is maintained below 5.5 for the 8.8 - 44 MW units, AFBC
is more efficient than conventional firing.
Calcium-to-sulfur ratio for a given system is a function of system design,
sorbent reactivity, and sorbent particle size. System designs, incorporating
increased bed depth or lower superficial velocity, such as proposed for best
systems as opposed to commercially offered systems, can decrease sorbent
requirements. Sorbent reactivity, which varies significantly among the sorbents
tested, also affects sorbent requirements.
Implementation of any or all of these options (deeper beds, lower gas
velocities, smaller sorbent particles, and more reactive sorbent) can increase
boiler efficiency considerably. Each reduction of 1 in the Ca/S ratio improves
boiler efficiency by 0.96 percent, as illustrated by Figure 52.
Considering the Foster-Wheeler Georgetown design with Greer limestone as
an example (see Section 3, Table 21 where commercial and best systems are
compared), Ca/S estimates are ~5.0 for a commercial system and 2.8 for best
system conditions. This assumes stringent control and high sulfur coal as
in the sensitivity assumptions (Appendix C, Table C-3). The estimated
efficiency improvement in this example of using best system conditions is
2.1 percent.
5.5.2 Sorbent Reactivity
Recognizing that all sorbents are not equally capable of capturing S0_
under identical conditions, the percent sulfur retained was varied while
maintaining the Ca/S ratio constant. This analysis, as expected, indicates
little overall effect on efficiency. As sorbent sulfur capture capability
ranged from 70 percent up to 100 percent, boiler efficiency varied by roughly
0.5 percent.
329
-------
5.5.3 Spent Solids Heat Recovery
When spent solids are withdrawn from an FBC, sensible heat is lost with
the solids. Some designs recover this sensible heat while others simply reject
this heat as waste. To determine the effect on boiler efficiency of waste
heat recovery, sensible heat recovery was varied from 0 up to 100 percent.
Boiler efficiency increases by roughly 1 percent over the entire range from
zero heat recovery to total heat recovery.
5.5.4 Coal Drying Requirement
Even though no coal drying is required for overbed coal feed AFBC systems
some commercially offered systems are designed for underbed feeding where coal
drying is required. Because many commercial systems may require drying, an
analysis of the effect on efficiency of coal moisture removal requirements was
performed. As coal moisture varied, the coal analysis (and heating value)
were normalized to compensate for the increased surface moisture.
Table 66 presents the linear equations relating boiler efficiency to coal
drying requirements. In this analysis, spreader stoker-firing exhibits the
least dependency on moisture content because no drying is required.
TABLE 66. RELATION BETWEEN BOILER EFFICIENCY AND COAL
DRYING REQUIREMENTS
Boiler capacity
MWt
8.8
22
44
58.6
-0.
-0.
-0.
-0.
AFBC
efficiency
11 5P* +
155P +
155P +
155P +
8.
82
82
83
164
.48
.96
.12
Conventional Breakeven
efficiency moisture content
-0
-0
-0
-0
.102P +
.102P +
.102P +
.155P +
79.
80.
80.
84.
56
40
98
73
39.2
39.2
37.4
-
P = percent moisture removed from coal.
330
-------
The fluidized bed and pulverized coal-fired units exhibit identical dependency
on coal moisture.
The breakeven moisture content is also listed in Table 66. At this mois-
ture content the stoker and AFBC boiler efficiencies for a given boiler size
are identical. The rather high breakeven points indicate that even should
drying be required for AFBC, stokers will still be less energy efficient.
The absence of a breakeven point for AFBC versus pulverized-firing results
because both technologies are assumed to require the same percentage moisture
removal.
No moisture content, under these design assumptions, is sufficiently low
for AFBC-fired units to achieve higher efficiency than pulverized-fired units.
For the smaller units (8.8 MWt to 44 MWt), any coal moisture removal requirement
less than the breakeven point is sufficiently low for AFBC units to operate
more efficiently than conventionally-fired stoker units.
5.5.5 Excess Air Effect
Excess air was calculated on the basis of Eastern high sulfur coal use
with 97 percent combustion efficiency. Excess air is the percentage air intro-
duced in excess of that required for stoichiometric combustion. The range
examined is from 0 to 100 percent.
The effect of excess air variation is presented in Figure 53. As excess
air increases, boiler efficiency decreases. The rate of decrease is slightly
nonlinear. Each 10 percent increase in excess air is accompanied by roughly
a 0.5 percent decrease in boiler efficiency.
The efficiencies of the conventional units are included for comparative
purposes. To obtain efficiency equivalence between AFBC units and stokers,
331
-------
8.6 MWt STOKER
22 MWt STOKER
44 MWt STOKER
58.« MW( PULVERIZED COAL
76
56.• MWt AFBC
44 MW* AFBC
MWt AFBC
60 80
EXCESS AIR.%
100
Figure 53. Boiler efficiency as a function of
excess air rate.
332
-------
AFBC units could run at excess air rates as high as 55 percent. An AFBC unit
would need to operate with zero excess air to achieve the efficiency of a
pulverized coal-fired unit.
5.5.6 Combustion Efficiency
The effect of combustion efficiency on boiler efficiency is linear. As
in the case of Ca/S ratio, linear equations relating combustion efficiency to
boiler efficiency were determined by regression analysis. These equations,
along with the conventional technology boiler efficiencies, were then used to
determine the combustion efficiency necessary for equivalent boiler efficiencies
for the two technologies. The general equations, the conventional system
efficiencies, and the breakeven combustion efficiencies are presented in
Table 67.
TABLE 67. GENERAL EQUATION RELATING BOILER EFFICIENCY TO
COMBUSTION EFFICIENCY
Boiler - MWt
8.8
22
44
58.6
E*
E
E
E
Equation
= 0.891 x
= 0.891 x
= 0.891 x
= 0.891 x
(CE)f
(CE)
(CE)
(CE)
Conventional
boiler
efficiency
- 4.837
-3.95
- 3.56
- 3.314
79.5
80.4
81.0
84.2
Breakeven
combus t ion
efficiency
94.6
94.7
94.8
98.2
Boiler efficiency.
Combustion efficiency.
In all cases, sufficiently high combustion efficiency will result in
AFBC boiler efficiency as good as or better than conventional boiler technology.
The ability of AFBC technology to achieve these combustion efficiencies has
not yet been demonstrated.
333
-------
5.6 ENERGY IMPACT OF NOX CONTROL
As discussed in Chapter 3, commercial-scale AFBC units should generally
be able to achieve all three levels of NOX control without major adjustments
to design/operating conditions. Thus, the desired levels of NOX control should
be achievable with no additional energy impact on the AFBC system.
5.7 ENERGY IMPACT OF PARTICULATE CONTROL
Energy required for final particulate control in AFBC industrial boilers
is expected to be similar to that resulting from application of conventional
particle control devices on conventional boilers. Particulate emissions from
a conventional boiler are ash and char. The emissions from an AFBC are lime-
stone, spent bed material, ash, and char. At 177°C (350°F), AFBC flue gas
rates are less than the values noted for the four conventional coal-fired
boilers. The difference is due to the difference in excess air values. The
conventional coal-fired boilers operate at excess air rates between 30 and 50
percent, while the AFBC boilers operate at 20 percent excess air. On this
basis, it may be projected that the requirements for particulate control in
conventional systems provide a conservative indication of energy impact associ-
ated with final particulate control operation in AFBC industrial boilers.
Table 68 presents a summary of energy requirements for final particulate
control for coal-fired AFBC industrial boilers. For each level of control,
energy use is shown for the systems discussed in Section 3.0. Estimates of
energy losses/auxiliary requirements in an uncontrolled conventional boiler
were obtained from "Technology Assessment Report for Industrial Boilers:
Particulate Control."29
334
-------
TABLE 68. ENERGY CONSUMPTION FOR BEST PARTICULATE
CONTROL COAL-FIRED AFBC BOILERS
System
Standard boiler
Type • level
MW (MBtu/hr)
8.8 (30) Stringent
FF
ESP
Intermediate
FF
ESP
MC
Moderate
.FT
ESP
MC
SIP
FF
ESP
MC
22 (75) Stringent
FF
ESP
Intermediete
FF
esp
MC
Moderate
FF
ESP
HC
SIP
FF
ESP
MC
44 (150) ttrinient
rr
CSP
Intermediate
FF
E1P
HC
Moderate
FF
ESP
MC
Energy consumption
Control
efficient
94.
97.
80.
92.
80
50
80
SO
52
94
97,
80
92
80
50
80
50
52
94
99
80
Z
0-98.
6-97.
0-98
0-92.
- 82.
- 95
- 82.
- 82.
lU
- 57.
<82
- 98.
,6 - 97.
- 98
- 92.
- 82.
- 95
- 82.
energy consumed
KU
7
9
9
1
1
1
1
15.
13.
15.
9.
15.
15.
6.
15.
15.
4.
6 -
0 -
6 -
3 -
6 -
6 -
5 -
6 -
6 -
0 -
15.6 -
7
,9
9
,3
.3
- «2.3
£88
- 57
£82
- 99
.1-99
- 98
96.9 - 97
80
50
92
50
- (2
- 95
.3-93
- 80
.5
.5
.2
.3
.2
38,
32,
31.
23.
38
38
16
38
38
10
38
77
82
77
63
77
77
48
77
,4 -
.8 -
.4 -
,5 -
.4 -
.4 -
.6 -
.4 -
.4 -
.1 -
.4 -
.6 -
.4 -
.6 -
.2 -
.6 -
.6 -
.8 -
.6 -
16.4
16.0
16.4
11.4
16.0
16.4
8.2
16.0
16.4
5.0
16.0
41.2
40.9
41.2
29.5
40.0
4.12
20.9
40.0
41.2
12.7
40.0
82.6
102.1
82.6
78.6
80
82.6
60.6
80
in energy use over
boiler
0.
0.
0.
0.
0.
0.
89
74
89
53
89
89
0.37
0.89
0.
0.
89
23
0.89
0.
0
0,
0,
0
0
0
0
0
0
0
0
.93
.80
,93
.57
.93
.93
.40
.93
.93
.25
.93
.98
1.04
0
0
0
0
0
0
.98
.80
.98
.98
.61
.98
-0.96
- 0.91
- 0.93
- 0.65
- 0.91
- 0.93
- 0.47
- 0.91
- 0.93
- 0.29
- 0.91
- 1.00
- 0.99
- 1. 00
- 0.72
- 0.97
- 1.00
- 0.51
- 0.97
- 1.00
- 0.31
- 0.97
- 1.04
- 1.29
- 1.04
- 0.99
- 1.01
- 1.04
- 0.76
- 1.01
energy use over SIP
boiler
0
0.59 -
0
0.35 -
0
0
0.16 -
0
_
-
-
0
0.65 -
0
0.38 -
0
0
0.19 -
0
_
_
-
0
0.70 -
0
0.41 -
0
0
0.20 -
0
0.72
0.42
0.21
0.81
0.48
0.23
0.86
O.S1
0.25
FT
ESP
MC
58.6 (200) Striment
n
ESP
Intermediate
FF
ESP
MC
Moderate
FT
esp
HC
SIP
FF
ESP
HC
81.
94
99.
80
97.
80
50
93
50
85
iW
5 - 83.6
382
- 99.4
2-99.3
- 98
5 - 97.8
- 82
- 95
.8 - 94.4
- 80
588
- 16.7
i»2
77.6
35.3
77.6
90.2
99.3
90.2
77.2
90.2
90.2
60.5
90.2
90.2
44.4
90.2
- 82.
- 43.
- 80
- 95.
- 124.
- 95.
- 96.
- 92,
- 95,
6
9
4
0
,4
.5
,5
,4
- 75.5
- 92.5
- 95
- 55
- 92
.4
.8
.5
0.98
0.44
0.98
1.
1.
1.
0.
1,
1.
0.
i
i
0
i
07
18
07
,91
,07
,07
.72
.07
.07
.53
.07
- 1.
- 0.
- 1.
- 1.
- 1.
- 1.
- 1,
- 1,
- I
- 0
- 1
- 1
- 0
- 1
04
55
01
13
,47
.13
.14
.10
.13
.89
.10
.13
.66
.10
-
0
0.63 - 0.
0
0.37 - 0,
0
0
0.18 - 0
0
_
_
-
77
.46
.22
The energy conauwed by th« particle control device on an AFBC %**• aesuaied to be eh* lav* *• its energy
coiuiMption on conventional boiler*, taken tram Reference 23.
Energy refer* to auxiliary plua inherent energy requirement!.
335
-------
Electrostatic precipitation energy use estimates for low sulfur coal
combustion in conventional units were considered comparable to anticipated APBc
requirements where effective ESP operation would probably require hot side
installation.
As in the case of AFBC SC>2 control, the energy impact of particulate
control devices applied to AFBC is expressed in terms of the percentage increa
in energy usage over that in an uncontrolled conventional boiler. Of course
a similar increase in energy usage would be experienced in a conventional
unit.
The percent increase in energy use presented in Table 68 is calculated
as follows:
Uncontrolled Conventional Boilers
„. . Energy consumed by control device
% increase = " l — x IQO
Total system energy requirements for uncon-
trolled conventional boiler
SIP-controlled AFBC boiler
(Energy consumed by control device)-
(Energy consumed by control device
.. . for SIP control)
-4 increase = x iQO
(Total system energy requirements
for AFBC) +
(Energy consumed by control device
for SIP control)
Energy use calculated on this basis associated with the full range of
anticipated efficiency requirements; i.e., from 50 to 99.4 percent, is shown
for fabric filters and multitube cyclones. This range is also covered for ESto*
but in discrete steps. Interpolation of the data is necessary in cases whe
the specific control level of interest was not considered in the particular
336
-------
control ITAR. Enough information is shown to indicate the relative differences
in energy requirements using different control devices to support stringent,
intermediate, and moderate particulate reduction levels.
5.7.1 Comparison of Fabric Filters and Electrostatic Precipitators
Fabric filters and ESP's were recommended for stringent control in
Section 3.0, Table 26. Energy requirements at the stringent control level are
similar for these two control methods. Fabric filters appear to have a slight
advantage for the two larger boilers where removal requirements exceed 98
percent, whereas, ESP's have a slight advantage at intermediate and moderate
control levels. (This effect may be a result of an assumption of constant
pressure drop for fabric filters, regardless of control level.)
For control with fabric filters, the energy penalty ranges "rom between
0.89 to 0.96 percent for the 8.8 MWt boiler up to 1.07 percent to 1.13 percent
for the largest boiler. Because of the constant pressure drop assumption, there
is no variation in energy penalty with control level for fabric filters. For
stringent control with ESP technology, the 8.8 MWt boiler penalty range is
0.74 to 0.91 percent and for the large boiler the range is 1.18 to 1.47 percent.
For less stringent control this energy penalty is lower.
5.7.2 Impact of Multitube Cyclone Use
The energy penalty accompanying particulate control by multitube cyclone
is only slightly less than for fabric filters. The range for cyclones is 0.89
to 0.93 percent for the 8.8 MWt boiler and 1.07 to 1.10 percent for the 58.6
MWt boiler.
When comparing SIP control level with the moderate, intermediate, and
stringent levels under consideration, there is no associated energy penalty
for the fabric filters or for the multitube cyclones (as a result of the
337
-------
constant pressure drop assumption). The SIP control energy difference is only
a factor for ESP technology. When the moderate, intermediate, and stringent
levels are compared to SIP control (see Table 68), the energy penalties are
roughly as follows:
• moderate - 0.20 percent
• intermediate - 0.4 percent
• stringent - 0.65 percent
The effect of boiler size on energy penalty is miniscule.
It is thus projected that the optional particulate control levels can be
supported by AFBC with conventional add-on particulate controls, with an atten-
dant energy penalty of from 0.4 up to 1.15 percent, compared to a conventional
uncontrolled boiler. The exact energy penalty is a function of control level
control device, and boiler size. Sinee particulate emissions (downstream of
the primary cyclone) are a function of S02 control level, sorbent particle
size, and primary cyclone efficiency, final particle control energy use is
also a function of these factors, especially in the case of ESP control. ESP
performance must be confirmed on the basis of sorbent resistivity and total
sorbent loadings to determine above 95 percent are routinely achievable.
Because of these unknowns, the energy estimates for FF and MC control have a
higher confidence level than those noted for ESP operation. In conclusion,
the energy impact of ESP control is a function of the 862 removal system but
FF and MC energy use is not expected to be as sensitive to S02 control metho-
dology, provided the constant pressure drop assumption is valid.
5.8 SUMMARY
5.8.1 SOg Control
The estimated energy requirements for SOz control when AFBC is compared
to uncontrolled conventional systems ranges from -2.6 percent of thermal input
338
-------
to the boiler (which represents an energy savings) up to 3.2 percent (which
represents an energy penalty). The wide range is principally a function of
boiler size. Other variables which affect energy requirements are coal type
and sorbent reactivity.
The level of S02 control in AFBC has a minor effect on the energy impact
of the total system. This is illustrated in Table 69 which shows the
differential changes in boiler efficiency as FBC design/operating parameters
are varied through the full range considered in this report.
With Eastern high sulfur coal, boiler efficiency decreases by about 0.6
percent when control level is increased from moderate to stringent. This is
the minimum differential for the parameters considered. The coal sulfur
content proved to have the most significant effect on boiler efficiency.
TABLE 69. DIFFERENTIAL CHANGES IN BOILER EFFICIENCY
VERSUS RANGE OF FBC DESIGN/OPERATING
PARAMETERS
FBC design/operating Differential change
parameter and range in boiler efficiency
Sorbent reactivity - low to high* 1.83
Coal sulfur content - 0.6 to 3.5* 2.17
Boiler capacity - 8.8 to 58.6 MWtf 1.47
S02 control level - moderate to stringent* 0.58
*Stringent control, Eastern high sulfur coal.
^Stringent control, average sorbent reactivity.
^Eastern high sulfur coal, average sorbent reactivity.
The comparison of AFBC and uncontrolled conventional boilers showed that
for any of the three smaller boilers (8.8, 22, and 44 MWt), AFBC boiler effi-
339
-------
ciency was 1 to 3 percent higher than conventional boiler efficiency consign**
all optional control levels and coal types. For the large boiler (58.6
AFBC boiler efficiency was 1 to 3 percent lower than the conventional
coal unit.
Of the total system losses, roughly 10 percent are auxiliary losses
90 percent are inherent losses for the options investigated (see Table 70V
The major component of the auxiliary losses is fan power. Fan power
ments comprise approximately two-thirds of the auxiliary power required -ifr
FBC system. The principal inherent loss component, flue gas sensible heat
loss accounts for roughly two-thirds of the inherent losses. Even the
auxiliary component (fan power) is not particularly significant when total
system losses are considered.
TABLE 70. TOTAL SYSTEM LOSSES RESULTING FROM EACH
ENERGY COMPONENT CONSIDERED
Component
Auxiliary
Coal Handling
Fan Power
Solids Handling
Pumping
Inherent
Flue Gas
Solids
Combustion
Radiative
Uncontrolled
Conventional
KW Percent
6-35
42-227
3-19
18-125
1065-7381
13-72
264-1318
265-903
0.3
2.3
0.2
1.2
71.8
0.7
13.4
9.9
AFBC
KW
6-35
115-766
3-128
18-125
881-7170
1-142
264-1757
265-903
Percent
0.3
6,4
0.9
1.0
59.1
10.3
14.6
8.4
340
-------
Because flue gas desulfurization is the only widely commercialized sulfur
emission control method for coal-fired steam raising, percentage energy require-
ments for the four most widely accepted systems are presented in Table 71, along
with estimates of AFBC energy requirements. Flue gas desulfurization energy
requirements vary as a function of coal sulfur level, S02 control level, and
to a smaller extent, plant size.^O Industrial fluidized-bed combustion energy
requirements vary with coal sulfur level, sorbent reactivity, sulfur emission
control level, and plant size.
TABLE 71. RANGE OF FGD31 AND FBC PROCESS
ENERGY REQUIREMENTS
Energy requirement (percent)
S02 control method increase over uncontrolled
conventional boiler)
Lime/Limestone 2.6 to 3.7
Double Alkali 2.0 to 2.4
Sodium Scrubbing 2.0 to 2.6
Wellman-Lord 3.2 to 8.0
AFBC -2.6 to 3.2
While the range presented for AFBC encompasses both double alkali and
sodium scrubbing, the actual energy requirements would probably be lower than
those estimated because the upper and lower limits of the range are mainly a
function of sorbent reactivity. If only average sorbent reactivity is consid*
ered, the range is from -1.9 percent up to 2.5 percent. The negative value
(-1.9 percent) indicates that AFBC system losses are less than uncontrolled
conventionally-fired systems.
341
-------
5.8.2 Particulate Control
Particulate control energy requirements range from 0.4 to 1.45 percent of
total operating energy requirement if ESP's are used, and from 0.90 to 1.15
percent if fabric filters or multitube cyclones are used. ESP energy is a
strong function of control efficiency, but FF and MC energy use is fairly
independent of control efficiency.
5.8.3 NCsr Control
NOx reduction to stringent, intermediate, or moderate levels can be
achieved at standard FBC operating conditions, so that no auxiliary energy
requirements are expected.
342
-------
5.9 REFERENCES
1. Roeck, D.R. & R. Dennis. Technology Assessment Report for Industrial
Boiler Applications: Particulate Control. Prepared by GCA/Technology
Division, Bedford, Massachusetts, for the U.S. EPA, June 1979. pp. 198-229.
2. Perry, J.H., et al. Perry's Chemical Engineer's Handbook. Fourth Edition.
McGraw-Hill Publishing Co., New York, New York. 1963. pp. 7-1 to 7-44,
8-1 to 8-64 and 20-1 to 20-96.
3. Ibid, pp. 8-18.
4. Ibid, pp. 20-52.
5. Hansen, W.A. (Project Manager). Conceptual Studies and Preliminary De-r
sign of a Fluid Bed Fired Boiler for Service in an Electric Utility.
Prepared by the Babcock and Wilcox Co., Alliance, Ohio, for the TVA/U.S.
DOE. Report No. TID-28442. April 28, 1978. p. 11-3.
6. Steam — Its Generation and Use. 38th Edition. Babcock and Wilcox,
161 East 42nd Street, New York, New York. 1975. p. 17-11.
7. Multicell Fluidized-Bed Boiler Design, Construction and Test Program.
Quarterly Report No. 3. January-March 1975. Prepared by Pope, Evans
& Robbins, Inc., for the U.S. DOE. Report No. FE-1237-T3. April 1975.
8. Ibid.
9. Newby, R.A., et al. Effect of S02 Emission Requirements on Fluidized-
Bed Combustion Systems: Preliminary Technical/Economic Assessment.
Prepared for the U.S. Environmental Protection Agency by Westinghouse
Research and Development Center. EPA-600/7-78-163. August 1978. p. 40.
10. Devitt, T., et al. The Population and Characteristics of Industrial/
Commercial Boilers. Prepared by PEDCo Environmental, Inc., for the
U.S. Environmental Protection Agency. May 1979. pp. 88-111.
11. American Conference of Industrial Hygienists, Industrial Ventilation.
10th Edition. Edwards Brothers, Inc., Ann Arbor, Michigan. 1976.
12. Letter Correspondence from Mr. R. McMillan of Foster-Wheeler Energy
Corporation to Mr. C.W. Young, GCA/Technology Division, Bedford,
Massachusetts. October 6, 1978.
13. Telephone conversation between Mr. K. Herron, C.E. Tyler Elevator
Products, Mentor, Ohio, and Mr. C.W. Young, GCA/Technology Division,
Bedford, Massachusetts. Januray 22, 1979.
14. Ibid.
15. Devitt, op. cit. pp. 88-111.
343
-------
16. Devitt, op. cit. p. 104.
17. Perry, op. cit. p. 3-133.
18. Perry, op. cit^ p. 3-135.
19. Lange, H.B., et al. S02 Adsorption in Fluidized-Bed Combustion of Coal
Effect of Limestone Particle Size. Prepared for Electric Power Research
Institute by Babcock and Wilcox Company, FP-667, Research Project 719-1
January 1978. p. 8-2.
20. Aulisio, C., R. Divilio, and R.R. Reed. Results of Recent Test Program
Related to AFB Combustion Efficiency. Pope, Evans, and Robbins, Pro-
ceedings of the Fifth International Conference on Fluidized-Bed Combus-
tion. Volume III. p. 91.
21. Industrial Application — Fluidized-Bed Combustion Process. Quarterly
Report for the Period April-June 1977. FluiDyne Engineering Corporation
Prepared for the U.S. ERDA, Report No. FE-2463-12. June 1977. p. 10.
22. Meeting attended by GCA and Gilbert/Commonwealth personnel. May 27, 1979
23. Perry, op. cit. p. 10-13.
24. Industrial Application — Fluidized-Bed Combustion Process. Quarterly
Report for the Period April-June 1977. FluiDyne Engineering Corporation
Prepared for the U.S. ERDA, Report No. FE-2463-12. June 1977. p. 10.
25. Lange, op. cit.
26. Fluidized-Bed Furnace in Enkoping, Sweden. Report 1: Description of a
Multi-Fuel Fluidized-Bed Furnace. Enkb'ping, Sweden.
27. Anderson, J.B. and Norcross, W.R. Fluidized-Bed Industrial Boiler.
Combustion Engineering, Inc. Combustion. February 1979. p. 14.
28. Boiler Efficiency: An Overview. Johnston Boiler Co. Report No. 103.
August 28, 1979. p. 2.
29. Roeck, D. and R. Dennis, op. cit. pp. 198-229.
30. Dickerman, J.C. Flue Gas Desulfurization Technology Assessment Report
Prepared by Radian Corp., Austin, Texas, for the U.S. EPA. January 26*
1979. p. 5-1.
31. Ibid, p. 5-1.
344
-------
6.0 FLUIDIZED-BED COMBUSTION ENVIRONMENTAL IMPACT
6.1 INTRODUCTION
This section provides an assessment of the environmental impact of adopting
the "best systems" for emission control in atmospheric fluidized-bed combustion
as applied to industrial-sized boilers.
In fluidized-bed combustion, the most prominent environmental impact is
solid waste disposal. The "best system" design for FBC is based on minimizing
the Ca/S ratio, and thus the amount of sorbent and solid waste wMch is neces-
sary to achieve a given level of S02 reduction. Therefore, as "commercially
offered" design/operating conditions approach "best system" conditions, the
environmental impact will be reduced. The impact of S02 emissions will remain
the same because specific S02 control levels are the frame of reference. The
effect on NOX and particulate emissions is uncertain, although NOx may be
reduced due to extended gas phase residence times.
6.1.1 Emission Streams
Figure 54 is a diagram showing the waste streams from a simplified FBC
system. The pollutants from the system can be divided into the following
categories:
• Stack gas - S02, NOX and particulate emissions are the
primary pollutants emitted in the stack gas. CO, hydro-
carbons, and volatile trace element emissions may also be
of concern. These latter mentioned pollutants are emitted
at the same low level from FBC as from conventional coal-
fired combustors. The environmental impact of these
emissions is under continued investigation.
345
-------
u>
4S
0\
Pi*
FEED WATER STEAM
LIQUID TREATMENT
l^LUtNl - \J WJ-E(,
AIR EMISSIONS
| X"" COAL
STORA6F
& LIMESTONE
HANDLING
1
5§
s^^BSssssa
>:¥:¥:*: :¥:¥:¥:¥:¥:¥S
il^lUlil
1
(PRIMARY V
1 CONTROL
T
^ CARBON
^^
BED MATERIAL
AIR
STACK GAS * ^MISSIONS
PARTICULATE
"T CONTROL
FLY ASH
EMISSIONS
r- . . — T
TOTAL STORAGE.
WASTE DISPOSAL
i
LEACHATE
AIR
LEACHATE
Figure 54. FBC flow diagram.
-------
• Solid residue - Spent bed material and fly ash are the two
types of solid residue produced by FBC systems. This residue
creates the major environmental impact of FBC. CAO, CaSO^,
ash and impurities make up the solid residue. Handling and
disposal problems arise from the potential heat release of
the material upon contact with water, the high pH and high
total dissolved solids attributed primarily to the high CaO
content of the solid. The waste may also contain toxic trace
elements, from the coal ash and limestone impurities which
may be leachable. Care must be taken in designing handling
and disposal systems, but based on current information, there
is no reason to assume that waste disposal cannot be accom-
plished in an environmentally acceptable manner.
• Fugitive emissions - Coal, limestone and solid waste storage,
handling, and onsite transportation may produce fugitive dust
emissions and possibly even some low level radiation. These
emissions are expected to be equivalent to those produced at
the site of a conventional coal-fired facility with lime/lime-
stone flue gas desulfurizatlon.
• Water - Most effluents from an FBC plant are expected to be
the same as those from conventional systems. The steam cycle
discharges result from feed water treatment and boiler blow-
down. These discharges should be equivalent to those pro-
duced in conventional boilers because FBC boiler designs are
expected to follow existing boiler codes. Wastes from fire-
side boiler cleaning could differ from conventional systems,
but such cleanings occur infrequently and should pose a minor
impact. Water pollution also results from rainwater percola-
tion through storage piles forming a leachate. Leachate from
coal storage piles will be the same as that encountered in
conventional systems.
6.1.2 Major Issues
Based on the data which are presently available, conclusions have been
drawn by several investigators1-l4 that fluidized-bed combustion is an environ-
mentally sound technology and no insurmountable pollution problems are fore-
seen. Further investigation, however, is recommended and is presently being
undertaken on larger scale tests for air emissions, as well as solid waste
disposal, including analysis of a wide range of possible pollutants not pre-
viously considered. The major issue of concern with respect to the environ-
mental impact of FBC is the amount of the solid waste and disposal requirements,
347
-------
The amount of spent solids produced at an industrial FBC boiler facility Is
primarily dependent upon: the unit capacity, the coal sulfur content and the
level of S02 control desired. The approximate range of solid waste predicted
under the size, fuel and control level guidelines of this study is 100 kg/hr
(220 Ib/hr) to nearly 4,000 kg/hr (8,800 Ib/hr) . Handling and disposal options
need to be identified and studied because of the heat release properties of the
material and the high pH and total dissolved solids.
6.1.2.1 Influence of RCRA--
The disposal options must take into account the states of FBC waste under
the Resource Conservation and Recovery Act (RCRA, PL 94-580) as well as leachat
characteristics affected by the National Pollution Discharge Elimination Syat^
(NPDES) and any other legislation governing the quality of the nation's waters
According to recent tests sponsored by EPA and carried out by Westinghouse
search Laboratories, FBC residues do not appear to be "hazardous" according
the procedures currently proposed under Section 3001 of RCRA. Using the
tion Procedure proposed in the Federal Register,5 tests showed that none of
eight species called out in the Federal Register exceeded the threshold of \ri
times the national interim primary drinking water standards. The other crlt» *
in Section 3001 are "ignitable," "reactive," and "corrosive" and they do not
seem to apply to FBC waste, although no formal ruling has been made. The lat- ^
criteria could conceivably apply to FBC waste, but for the time being,
interpretations are that this applies to liquid wastes and not solids or
ates from solids. ..••-
The designs tion of FBC waste under the RCRA waste categories will contl
to be an active research and regulatory issue for the near future. Solid v« •*
from electric utilities have been placed in a special high volume category- «."-*
seems a likely interim category for FBC waste until more data become
348
-------
The process variables which have the greatest effect on the environmental
impact of FBC solid waste (both quantity and composition) are those which
determine the amount of sorbent used. They include the level of SC>2 emission
control desired, the Ca/S molar feed ratio necessary to meet that level and
the operating variables and conditions which are used to minimize the Ca/S
ratio; i.e., sorbent particle size, gas phase residence time, sorbent reactivity,
and bed temperature. The quantity of sorbent used affects most of the pollution
emissions in some manner.
6.1.2.2 Multimedia Impact—
When analyzing the environmental impact of a given system and the control
regulations applying to it, it is of the utmost importance to consider cross
pollutant and multimedia effects; i.e., what is the impact of reducing one
pollutant on the emission of the others. The other pollutants can be affected
in two ways: (1) directly, producing a new or increased amount of byproduct,
such as collected fly ash resulting from flue gas particulate removal; and
(2) changing the conditions of the system such that they affect other pollutants
from .the system, such as increasing gas residence time to increase 862 capture,
with the result of decreased NO emissions as an additional benefit. In this
assessment of the environmental impact of S02> NO and particulate control on
FBC, a multipollutant approach has been taken.
Other issues of environmental and commercial concern also need to be
further investigated. S02 control performance of AFBC must be more fully
demonstrated at the 0.67 second gas phase residence time and 500 um average
bed particle size which have been chosen to represent the "best" system.
Particle control devices must be adequately demonstrated as applied to AFBC
349
-------
in order to prove applicability and reliability of these systems. Another
issue that must be further .investigated is the emission of trace elements
from FBC industrial boilers.
Section 6.2 also includes a brief discussion of FBC versus conventional
combustion with flue gas desulfurization as reported by several investigators.
Although this is not in the scope of the project, it is felt that this com-
parison will give the reader a better perspective on the environmental impact
of FBC compared to other coal-based combustion systems.
6.2 ENVIRONMENTAL IMPACT OF COAL-FIRED AFBC
The air pollution impact of AFBC industrial boilers will most likely be
the same for "commercially offered" units as for the proposed "best system"
of emission control, if the same levels of emission reduction are considered
for each system. The discussion which follows, therefore, applies to both
systems.
The solid waste impact, however, will vary between the systems, due to
the variations in operating parameters between "commercially offered" systems
and the "best" system, and the resultant differences in sorbent requirements
to achieve equivalent levels of S02 reduction.
6.2.1 Air Pollution
6.2.1.1 S02 Emissions—
Tables 72a through 72d illustrate the S02 emissions from coal-fired atmo-
spheric fluidized bed combustion boilers under varying conditions, which in-
clude four boiler capacities, three different coals, and three S02 control
levels. The Ca/S ratios indicated in Table 72 are projected for AFBC design
and operating conditions representing the "best" system for S02 control in AFBC
with a sorbent of average reactivity (see Section 3.0).
350
-------
OJ
TABLE 72. AIR POLLUTION IMPACTS FROM "BEST" AND "COMMERCIALLY OFFERED" S02 CONTROL
SYSTEMS FOR COAL-FIRED FBC BOILERS C8.8 MWt or 30 * 106 Btu/hr heat input)
%s
3.5
0.9
0.6
3.5
3.5
3.5
0.9
0.9
0.8
0.6
0.6
0.6
Heat
«/*
27,450
32,100
22,330
27,450
27,450
27,450
32,100
32,100
32, 100
22,330
22,330
22,330
value
(Btu/lb)
(11,800)
(13,800)
(9,600)
(11,800)
(11,800)
(11,900)
(13,800)
(13,800)
(13,800)
(9,600)
(9,600)
(9,600)
Syete
Control1"
level
none
none
none
M
1
S
M
I & S
S+
M
I & S
s+
a Air Emissions
Percent*
reduction
0
0
0
78.7
85
90
75
83.9
90
75
83.2
90
Type of
System
AFBC
AFBC
AFBC
AFBC
AFBC
AFBC
AFBC
AFBC
AFBC
AFBC
AFBC
AFBC
control
Ca/S
0
0
0
2.5
2.9
3.3
2.2
2.8
3.3
2.2
2.7
3.3
./.
21
4.7
4.5
4.5
3.3
2.1
1.2
0.76
0.45
l.l
0.76
0.45
(Ib/h)
(169)
(37)
(36)
(36)
(26)
(17)
(9.3)
(6.0)
(3.6)
(9.0)
(6.0)
(3.6)
S02
ng/J
2,424
533
512
516
364
242
133
86
52
128
86
52
(lb/106 Btu)
(5.64)
(1.24)
(1.19)
(1.20)
(0.85)
(0.56)
(0.31)
(0.20)
(0.12)
(0.30)
(0.20)
(0.12)
Other pollutants
Pollutant Effect5
NA NA
NA NA
NA NA
particulate +
particulate +
particulate +
particulate +
particulate +
particulate +
particulate +
particulate +
particulate +
Secondary pollutants
Solid waste
"Best'
kg/h
420
461
502
128
142
152
133
144
157
' system
(Ib/h)
NA
NA
NA
(925)
(1,016)
(1,105)
(281)
(310)
(335)
(293)
(318)
(345)
Commercial
system
kg/h (Ib/h)
NA
NA
NA
-------
TABLE 72b. AIR POLLUTION IMPACTS FROM
SYSTEMS FOR COAL-FIRED FBC
"BEST" AND "COMMERCIALLY OFFERED" S02 CONTROL
BOILERS (22 MWt or 75 x io6 Btu/hr heat input)
System
ZS
3.5
0.9
0.6
3.5
3.5
3.5
0.9
0.9
0.9
0.6
0.6
0.6
Heat
kJ/kg
27,450
32,100
22,330
27,450
27,450
27,450
32 , 100
32 , 100
32,100
22,330
22,330
22,330
value
(Btu/lb)
(11,800)
(13,800)
(9,600)
(11,800)
(11,800)
(11,800)
(13,800)
(13,800)
(13,800)
(9,600)
(9,600)
(9,600)
Control
level
none
none
none
M
I
S
M
I & S
s+
M
1 & S
s+
Percent*
reduction
0
0
0
78.7
85
90
75
83.9
90
75
83.2
90
Type of control
System
AFBC
AFBC
AFBC
AFBC
AFBC
AFBC
AFBC
AFBC
AFBC
AFBC
AFBC
AFBC
Ca/S
0
0
0
2.5
2.9
3.3
2.2
2.8
3.3
2.2
2.7
3.3
g/s
53
12
11
11
8.0
5.3
2.9
1.9
1.1
2.8
1.9
1.1
(Ib/h)
(423)
(93)
(89)
(90)
(64)
(42)
(23)
(15)
(9)
(22)
(15)
(9)
S02
ng/J
2,425
533
512
516
364
242
133
86
52
128
86
52
Air emissions
(lb/106 Btu)
(5.64)
(1.24)
(1.19)
(1.20)
(0.85)
(0.56)
(0.31)
(0.20)
(0.12)
(0.30)
(0.20)
(0.12)
Secondary pollutants
Other poll
Pollutant
NA
NA
NA
particulate
particulate
particulate
particulate
particulate
particulate
particulate
particulate
particulate
Effect5 "Best" system
Ef£eCt kg/h (Ib/h)
NA NA
NA NA
NA NA
+ 1,052 (2,318)
+ 1,155 (2,545)
+ 1,255 (2,766)
+ 314 (699)
+ 352 (775)
•f 379 (835)
+ 332 (734)
+ 360 (794)
+ 392 (864)
aste
Commercial
system
kg/h (Ib/h)
NA
NA
NA
-------
TABLE 72c. AIR POLLUTION IMPACTS FROM "BEST" AND "COMMERCIALLY OFFERED" S02 CONTROL
SYSTEMS FOR COAL-FIRED FBC BOILERS (.44 MWt or 150 * 106 Btu/hr heat input)
Heat value
2S
3.5
0.9
0.6
3.5
OJ 3.5
Ln
W 3.5
0.9
0.9
0.9
0.6
0.6
0.6
kJ/kg
27,450
32,100
22,330
27,450
27,450
27,450
32,100
32,100
32,100
22,330
22,330
22,330
(Btu/lb)
(11,800)
(13,800)
(9,600)
(11,800)
(11,800)
(11,800)
(13,800)
(13,800)
(13,800)
(9,600)
(9,600)
(9,600)
level
none
none
none
M
I
S
M
I & S
S+
M
I & S
S+
+
reduction
0
0
3
78.7
85
90
75
83.9
90
75
83.2
90
Type of
System
AFBC
AFBC
AFBC
AFBC
AFBC
AFBC
AFBC
AFBC
AFBC
AFBC
AFBC
AFBC
control
Ca/S
0
0
0
2.5
2.9
3.3
2.2
2.8
3.3
2.2
2.7
3.3
g/s
107
23
23
23
16
11
5.6
3.8
2.3
5.7
3.8
2.3
(Ib/h)
(846)
(186)
(179)
(180)
(128)
(84)
(47)
(30)
(18)
(45)
(30)
(18)
S02
ng/J
2,425
533
512
516
364
242
133
86
52
12o
86
52
(lb/106 Btu)
(5.64)
(1.24)
(1.19)
(1.20)
(0.85)
(0.56)
(0.31)
(0.20)
(0.12)
(0.30)
(0.20)
(0.12)
Secondary pollutants
Other poll
Pollutant
NA
NA
NA
particulate
particulate
particulate
particulate
particulate
particulate
particulate
particulate
particulate
E«-5 TK
NA
NA
NA
+ 2,102
+ 2,309
+ 2,509
+ 634
+ 704
+ 758
+ 667
<• 722
+ 785
. *
Solid waste*
sy^iem
(Ib'h)
NA
NA
NA
(4,635)
(5,089)
(5,532)
(1,400)
(1,550)
(1,670)
(1,467)
(1.588)
(1,727)
« . ,
system
kg/h (Ib/h)
NA
NA
NA
-------
TABLE 72d. AIR POLLUTION IMPACTS FROM "BEST" AND "COMMERCIALLY OFFERED" S02 CONTROL
SYSTEMS FOR COAL-FIRED FBC BOILERS (58.6 MWt or 200 x 106 Btu/hr heat input)
Ul
System
Xs
3.5
0.9
0.6
3.5
3.5
3.5
0.9
0.9
0.9
0.6
0.6
0.6
Heat
W/kg
27,450
32,100
22,330
27,450
27,450
27,450
32,100
32,100
32,100
22,330
22,330
22,330
value
(Btu/lh)
(11,800)
(13,800)
(9,600)
(11,800)
(11,800)
(11,800)
(13,800)
(13,800)
(13,800)
(9,600)
(9,600)
(9,600)
Control
level
none
none
none
M
I
S
M
I & S
S+
M
I & S
S+
Percent^
reduction
0
0
0
78.7
85
90
75
83.9
90
75
83.2
90
Type of control
i System Ca/S** g/s
AFBC
AFBC
AFBC
AFBC
AFBC
AFBC
AFBC
AFBC
AFBC
AFBC
AFBC
AFBC
0
0
0
2.5
2.9
3.3
2.2
2.8
3.3
2.2
2.7
3.3
142
31
30
30
21
14
7.8
5.0
3.0
7.6
5.0
3.0
Ub/h)
(1,128)
(248)
(238)
(240)
(170)
(112)
(62)
(40)
(24)
(60)
(40)
(24)
Air emissions
SO2
ng/J (lb/106 Btu)
2,245
533
512
516
364
242
133
86
52
128
86
52
(5.64)
(1.24)
(1.19)
(1.20)
(0.85)
(0.56)
(0.31)
(0.20)
(0.12)
(0.30)
(0.20)
(0.12)
Other pollutants
Pollutant Effect;
NA NA
NA NA
NA NA
particulate +
particulate +
particulate +
particulate +
particulate +
particulate *
particulate +
particulate +
particulate +
Secondary pollutants
Solid waste*
F "Best" system C°^^^'1
NA
NA
NA
2,805 (6,181)
3,080 (6,786)
3.347 (7,376)
846 (1,866)
938 (2,066)
1,012 (2,227)
887 (1,956)
960 (2,117)
1,043 (2,303)
NA
NA
NA
*
*
*
*
*
*
*
*
*
These solid waste quantities are dependent upon the Ca/S molar feed ratio required for a given "commercially offered"
system. Table in Section 3 gives a range of Ca/S ratios projected, and Table in Appendix gives the relative
land use requirement for varying Ca/S ratios.
M = moderate level
I • intermediate level
S = stringent level
S+ = greater than recommended stringent level
TVariance from the 75 percent - moderate; 85 percent - intermediate; and 90 percent - stringent levels are due to the upper and
lower limits of ^16 ng/J (1.2 Ib/MMBtu) and 86 ng/J (0.2 Ib/MMBtu), respectively.
+ = an increase in emissions of the pollutant identified attributed to the S02 control method.
- = a decrease in emissions of the pollutant identified attributed to the S0£ control method.
These solid waste quantities were calculated as shown In Table of this section. The quantities of waste indicated
in Table are based on the assumption that the sorbent fed is of average reactivity.
**
Ca/S ratios based on a sorbent of average reactivity.
NA - Not Applicable.
-------
The SC>2 emitted to the atmosphere is dependent upon the level of control
which is exercised and the heat input rate of the boiler. For an 8.8 MWt
(30 x 103 Btu/hr) boiler using high sulfur coal (3.5 percent), the SC>2 emissions
range from approximately 2.1 to 4.5 g/s (16 to 36 Ib/hr) over the stringent
to moderate control range. This compares to uncontrolled emissions of about
21 g/s (169 Ib/hr) S02.
Table 72 also indicates that there is a slight increase in particulate
emissions due to the control of SC>2 by limestone addition. To date, these
results are not quantifiable; only trends in the data can be verified.
The effect of S02 control on NOx emissions differs in that there is no
predictable trend which can be identified. Depending on which operating
variables are used to enhance S02 capture, NOX emissions may increase or
decrease. Generally, in a given system, once the design and operating
conditions are established, increasing S02 capture will have little effect
on NOx emissions.
The largest potential impact of S02 control techniques in fluidized-bed
combustion is the solid waste which is generated (spent bed material and
carryover/fly ash) by the system. As S02 control levels are increased the
amount of solid waste is increased. Table 72 shows the total quantity of
solid waste generated for the three coals at three levels of control for the
"best" system. Quantities of waste for the 8.8 MWt (30 x 103 Btu/hr) boiler,
assuming a sorbent of average reactivity, range from 128 kg/hr (281 Ib/hr)
for the lowest sulfur coal and S(>2 control level, to 502 kg/hr (1,105 Ib/hr)
for the highest sulfur coal and SO2 control level.
As more research is done, S02 control via fluidized-bed combustion may
be found to have beneficial effects beyond the S02 control itself. It is
355
-------
quite possible that as a better understanding of the chemical, physical and
mechanical properties of the solid waste is developed, the material could have
widespread use as a commercial byproduct (i.e., structural, road construction
agricultural, and soil conditioning materials). There are several research
programs underway in this area whose initial results are very encouraging
(see Section 6.2.2.5). If such uses of the solid waste find wide commercial
application, a large degree of the adverse impact could translate into
beneficial impact.
The environmental impact of AFBC solid waste is discussed in further
detail in Section 6.2.2.
6.2.1.2 NOX Emissions—
Table 73 illustrates NOx emissions from coal-fired AFBC boilers under
varying levels of NOx control. NOx emissions range from 1.9 to 2.6 g/s
(15 to 21 Ib/h) for the 8.8 MWt (30 x io3 Btu/h) boiler, and 13 to 18 g/8
(100 to 140 Ib/h) for the 58.6 MWt (200 x IO3 Btu/h) boiler. It is assumed
based upon available data, that commercial-scale AFBC units will inherently
be able to achieve all three levels of NOX control, including the most string
without major adjustments to design and operating conditions.
6.2.1.3 Particulate Emissions—
Table 74 illustrates the air pollution impact of particulate control as
applied to atmospheric fluidized-bed combustion. Uncontrolled particulate
emissions from AFBC boilers range from 1.9 to 126 g/s (15 to 1,000 Ib/h) in
the boiler size range of 8.8 to 58.6 MWt (30 to 200 x io3 Btu/hr). Moderate
control levels of 107 ng/J (0.25 lb/106 Btu) and stringent control levels of
12.9 ng/J (0.03 lb/106 Btu), are expected to be achievable by AFBC with
conventional add-on particulate control devices. The particulate material
356
-------
TABLE 73. AIR POLLUTION IMPACTS FROM "BEST" NOX CONTROL
TECHNIQUES FOR COAL-FIRED, ATMOSPHERIC FLUIDIZED-
BED COMBUSTION BOILERS
Syste
NOX emissions
Other emissions
Secondary pollutants.
Heat rate
(106 Btu/h)
Fuel* control C°"r^1 g/s (Ib/h) ng/J (lb/106 Btu) Pollutant ^l"* Beneficial Adverse
level
ethod
of change
8.8
8.8
8.8
8.8
22
22
22
22
44
44
44
44
58.6
58.6
58.6
58.6
(30)
(30)
(30)
(30)
(75)
(75)
(75)
(75)
(150)
(150)
(150)
(150)
(200)
(200)
(200)
(200)
Coal none
A, B & C
Coal M
A, B & C
Coal I
A, B * C
Coal S
A, B 4 C
Coal none
A, B & C
Coal H
A, B & C
Coal I
A, B & C
Coal S
A, B & C
Coal none
A, B & C
Coal M
A, B & C
Coal I
A, B & C
Coal S
A, B i C
Coal none
A, B & C
Coal M
A, B & C
Coal I
A, B & C
Coal S
A, B & C
none
AFBC
AFBC
AFBC
none
AFBC
AFBC
AFBC
none
AFBC
AFBC
AFBC
none
AFBC
AFBC
AFBC
2.6
2.6
2.3
1.9
6.7
6.7
5.7
4.8
13
13
11
9.4
18
18
15
13
(21)
(21)
(18)
(15)
(53)
(53)
(45)
(38)
(105)
(105)
(90)
(75)
(140)
(140)
(120)
(100)
301
301
258
215
301
301
254
251
301
301
258
251
301
301
258
251
(0.7)
(0.7)
(0.6)
(0.5)
(0.7)
(0.7)
(0.6)
(0.5)
(0.7)
(0.7)
(0.6)
(0.5)
(0.7)
(0.7)
(0.6)
(0.5)
NA
NA
MA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
J»
*Co»l A - High sulfur Eastern coal, 3.S percent S; 10.6 percent Ash; 27,450 kj/kg (11,800 Btu/lb).
Coal B • Low sulfur Eastern coal, 0.9 percent S; 6.9 percent Ash; 30,100 kj/kg (13,800 Btu/lb).
Coal C - Subbituminous coal, 0.6 percent S; 5.4 percent Ash; 22,330 kj/kg (9,600 Btu/lb).
NA - not applicable.
357
-------
TABLE 74. AIR POLLUTION IMPACT FROM "BEST" PARTICULATE CONTROL TECHNIQUES
FOR COAL-FIRED, ATMOSPHERIC FBC BOILERS
Ln
00
H.-JC Rali Pal
Tutl*
MW (MMBtu/h>
ft. B (30) Coat
A, S & C
«. S (30) Coal
A, B & C
N. 8 ( 30) Coal
A, B c. C
H.« ( 30) Coal
A, B i C
21! (75) Coal
A, B & C
22 (75) Coal
A, H i C
22 (75) Coal
A, 8 (, C
22 (75) Caal
A, B & (
44 (150) Coal
A, B i C
44 (150) Coal
A, B & C
4i (150) Coal
A, B i C
44 (iSu) coal
A, B & C
5(4.6 (200) Coal
A, B 6 C
58.6 (200) Coal
A, B i C
W.tS (2001 coal
A. B 4 C
58.6 (200) Coal
A, B & C
System
:ontrol
level
H
I
S
none
H
I
S
i one
M
I
S
none
M
I
S
Percent
particulate
reduction
0
50.0 - 95.3
80.0 - 98.0
93.3 - 99.3
0
50.0 - 94.9
81.6 - 98.1
94.7 - 99.5
0
50.0 - 94.9
80. 0 - 98.0
94.7 - 99.5
0
50.0 - 95.0
80.0 - 98.0
94.0 - 99.4
Particul.te e.Ution. Other «•""<><>•
^r£ir' •/• «^> -* <»"<» -> "»««< .rxi. •
none 1.9 - 18.9 (15 - 150) 213 - 2150 (0.5 - 5.0) NA NA
MC. US, ESP or FF 0.9 (7.5) 107 (0.25) NA NA
MC, WS, ESP or FF 0.4 (i.O) 43 (0.10) NA NA
ESP or FF 0.1 (0.9) 12.9 (0.03) NA NA
none 4.7 - 47.2 (38 - 375) 215 - 2150 (0.5 - 5.0) NA NA
MC, WS, ESP or FF 2.4 (H) 107 (0.25) NA NA
MC, WS, ESP or FF 0.9 (".5) 43 (0.10) NA NA
ESP or FF 0.3 (J.3) 12.9 (0.03) NA NA
none 9.4 - 94.5 (75 - 750) 21! - 2150 (0.5 - 5.0) NA NA
MC, WS, ESP or FF 4.8 (33) 107 (0.25) NA NA
MC, WS, ESP or FF 1.9 (15) 43 (0.10) NA NA
ESP or FF 5.7 (4.5) 12.9 (0.03) NA NA
none 12.6 - 126.0 (100 - 1000) 215 - 2150 (0.5 - 4.0) NA NA
MC, WS, ESP or FF 6.3 (i.0) 107 (0.25) NA NA
MC, WS, ESP or FF 2.5 (-0) 43 (0.10) HA HA
ESP or FF 0.8 '6.0) 12.9 (0.03) HA HA
1 P
Adverse
teneficial solid waste
g/s (Ib/h)
HA NA
NA 1.5 - 18.5 (12 - 147)
NA 1.8 - 18.8 (14 - 149)
NA NA
NA 2.4 - 45 (19 - 356)
NA 3.9 - 46 (31 - 368)
MA 4.5 - 47 (36 - 373)
NA HA
NA 4.7 - 90 (37 - 712)
NA 7.6 - 93 (60 - 735)
NA 8.9 - 94 (71 - 746)
HA NA
NA 6.3 - 120 (50 - 950)
NA 10 - 123 (80 - 980)
NA 12 - 125 (94 - 994)
*Coal A - High sulfur Eastern coal, 27,450 kj/kg (11,800 Btu/lb); 3.5 percent S; 10.6 percent A
Coal B « Low sulfur Eastern coal. 32,100 kJ/kg (13,800 Btu/lb); 0.9 percent S; 6.9 percent A
Coal C - SubbituMlnous coal, 22,230 kj/kg (9,600 Btu/lb); 0.6 percent S; 5.4 percent A
WS - Wet scrubber
MC - Hultitube cyclone
Then* levels of paniculate
eaisBioni
Hodersite - 107 ng/J (0.25 lb/106
Interned. at« - 43 ng/J (0.10 lb/106
Stringent - 12 9 ng/J (0.03 lb/10e
•re bated on
the following proposed standarda :
Btu)
Btu)
Btu)
upon Ca/S ratio, gas resider.ee tiaw and velocity, particle sin and particle site distribotica.
-------
which is collected ranges from 0.9 to 125 g/s (7.5 to 994 Ib/hr) depending
upon the boiler size and level of S02 and particulate control. The 125 g/s
(994 Ib/hr) of collected particulates compares to 113 g/s (900 Ib/hr) from
a conventional system of equivalent coal usage. A larger quantity of
participates is expected from FBC than from conventional systems as a result
of the attrited bed material in the carryover. The particulates collected
comprise from 5 to 15 percent of the total solid waste from AFBC. The
environmental impact of the combined solid waste is covered separately in
Section 6.2.2 of this report.
6.2.1.4 Trace Element Emissions—
The emissions of trace elements from coal-fired fluidized-bed combustion
systems on an industrial scale have not been documented. To date, there is
no reason to suspect that trace element emissions from fluidized-bed combustion
should be worse than that encountered in any coal-fired system. In fact,
the lower temperatures of FBC combustion may reduce the tendency of some of
the more volatile elements to be enriched on the finer fly ash particulates,
a phenomenon which is sometimes encountered in conventional coal-fired systems.
In bench scale experiments on a 6-in. pressurized combustor, Argonne reported
trace element emissions which were lower than what one would expect from
conventional systems.6 A preliminary environmental assessment by GCA Corporation
concluded that coal-fired FBC should present no problems for airborne trace
element emissions.7 However, it is important to note that any conclusions
to date on FBC trace element emissions are based on limited laboratory scale
data. Further experimental verification of the characteristics of trace
metals in air emissions (and solid waste) is necessary on industrial-scale
FBC systems.
359
-------
6.2.2 Solid Waste
The major adverse environmental impact of fluidized-bed combustion is
expected to be the solid waste which it produces. Solid residue from the
fluidized-bed process consists of spent bed material (largely calcined
and sulfated sorbent), and a mixture of fly ash collected in the participate
control devices.
6.2.2.1 Quantity of Solid Waste Generated—
The amount of solid waste material produced is a function of the fuel
and sorbent characteristics. The following major variables are considered
in estimating the amount of solid waste which will be generated.
• Ca/S molar feed ratio required
reactivity of the sorbent type (categorized
by chemical and physical properties)
design/operating conditions which affect
sorbent performance (sorbent particle size
and gas phase residence time, etc.)
percent 862 reduction required
• fuel sulfur
• fuel ash
• fuel heating value
Different sorbents have varying calcium contents and calcium utilization
rates. Once a sorbent is chosen for a specific application, the calcium
utilization rate can generally be increased by reducing the particle size.
The design gas velocity and bed height can then be adjusted to give the
optimum gas-solids contact time for a given particle size. The greater the
gas phase residence time is, the greater the calcium utilization. Once thes
parameters are established, the fuel feed and the level of control to be met
determine the sorbent mass feed rate and amount of solid waste generated in
the fluidized bed.
360
-------
To indicate the environmental iim-.-ct of the waste, Tables 75a through 75d
demonstrate the waste produced at varying control levels using different coals.
The methods used to calculate the mass and composition of the total waste are
indicated in the footnotes under Table 75d. For each boiler size, coal type
and control level, a range of waste production rates is given, representing
the expected range of sorbent reactivities. Solid waste for an 8.8 MW^
(30 * 103 Btu/hr) thermal input coal-fired boiler ranges from 115 to 580 kg/h
(255 to 1,278 Ib/h). At 58.6 MWt (200 x 1Q3 Btu/hr), the estimated maximum
waste is 3,873 kg/h (8,533 Ib/h). These solid waste loadings constitute the
total waste produced by the system; about 85 to 95 percent of the waste will
be withdrawn as spent bed material, assuming that the material collected in
the primary cyclone is recycled to the bed. The remaining 5 tc "5 percent
elutriates from the bed, passes through the primary cyclone, and is collected
by a final particulate control device.
At levels of control specified earlier in Table 74 for particulate emissions,
nearly all the particulate matter is collected, and it is assumed to be mixed
with the spent bed material for disposal.
The land use for disposal of the solid waste has been projected using the
sensitivity analysis program discussed in Appendix C. Table C-29 in the Appendix
shows the variation of disposal area needed for wastes from AFBC and conven-
tional-fired boilers with NOx and 862 control. The table shows the impact
for the four boiler sizes, using the three coals which have been represented
throughout the report, and the optional S0£ control levels. Figure 55 illustrates
the effect of these variables upon the land requirements for an FBC site where
high sulfur (3.5 percent S) coal is burned. For each boiler capacity the
361
-------
u>
TABLE 75a. SOLID WASTE GENERATED BY A ONCE-THROUGH, LIMESTONE-FED,
COAL-FIRED, "BEST SYSTEM" ATMOSPHERIC FBC BOILER
(8.8 MW or 30 x io6 Btu/hr heat input)
% Sulfur J Ash * S°=, Level °f* Ca/!f
• .atrol control ratio
3.5 10.6 78.7 M 2.5
3.4
1.8
3.5 10.6 85 I 2.9
3.8
2.1
3.5 10.6 90 S 3.3
4.2
2.3
0.9 6.9 75 M 2.2
3.2
1.6
0.9 6.9 83.9 I i S 2.8
3.7
2.0
0.9 6.9 90 S + 3.3
4.2
2.3
0.6 5.4 75 M 2.2
3.2
1.6
0.6 5.4 83.2 I & S 2.7
3.6
2.0
0.6 5.4 90 s +• 3.3
4.2
2.3
Limestone feed* . Ine"s f* °™ Uncalcined CaCO3S
i /L /iv/i.\ limestone (101) , ,t ,,t .. ^ J
kg/h (Ib/h) ^ (lb/h) kg/h
-------
TABLE 75b. SOLID WASTE GENERATED BY A ONCE-THROUGH, LIMESTONE-PED,
COAL-FIRED, "BEST SYSTEM" ATMOSPHERIC FBC BOILER
(22 MW or 75 x io6 Btu/hr beat itiput)
I Sulfur : A.h * "Z LeV*1 °f Ca/S+
control control ratio
3.5 10.6 78.7 H 2.5
3.4
1.8
3.5 10.6 85 I 2.9
3.8
2.1
3.5 10.6 90 S 3.3
4.2
2.3
0.9 6.9 75 M 2.2
3,2
1.6
0.9 6.9 83.9 Its 2,8
1.7
2,0
0.9 6.9 90 S + 3.3
4.2
2.3
0.6 5.4 75 H 2.2
3.2
1.6
0.6 S.4 83.2 I 4 S 2,7
3.6
2.0
0.6 5.4 90 S •»• 3.3
4.2
2.3
. * it Incrtt frov s
Lutestone feedT . /ioi} uncmlcined CaCOs
kg/h (Ib/h) k /hUb/h) kg'b (lb'll)
877
1,193
632
1,017
1,333
737
1,158
1,474
807
170
247
123
216
165
154
255
324
178
163
237
vie
200
266
148
244
311
170
(1,932)
(2,623)
(1.391)
(2,241)
(2,937)
(1,623)
(2,551)
(3, 246}
(1,178)
(374)
(544)
(272)
(476)
(629)
(340)
(561)
(714)
(391)
(358)
(521)
mn
(440)
(5S7)
(326)
(538)
(6S4)
(375)
86
119
63
102
133
74
lib
147
Bl
17
25
12
22
29
15
26
32
IS
16
24
12
20
27
15
24
31
17
(193)
(263)
(139)
(224)
(2»4)
(161)
(255)
(325)
(178)
(37)
(54)
(27)
(48)
(63)
(34)
(56)
m>
(39)
(36)
(52)
(16)
(44)
(59)
(33)
(54)
(68)
(38)
39
54
28
46
60
33
52
6fi
36
4.8
H
5.5
9.7
13
6.9
11
15
8.0
7.3
11
5.3
9.0
12
6.7
11
14
T.7
(87)
(118)
(62)
(101)
(132)
(71)
(115)
(146)
C80)
(17)
(24(
(12)
(21)
(28)
(IS)
(25)
O2)
(18)
(16)
(23)
cm
(20)
(26)
(15)
(24)
(31)
(17)
Unreacted C«0*
kg/b (Ib/h)
281
432
163
337
488
10J
395
547
227
52
89
30
71
104
41
87
120
50
SO
85
29
65
97
40
83
114
48
(618)
(951)
(359)
(742)
(1,075)
(446)
(870)
(1,203)
C500)
(115)
(196)
(66)
(156)
(229)
(91)
(192)
(255)
(110)
(109)
(187)
(63)
(143)
(213)
(88)
(184)
(253)
(106)
CaSOi, generated*
kg/h Ub/h)
338
338
338
364
364
364
386
386
386
70
70
70
80
BO
80
85
85
85
*e
68
66
75
75
75
83
83
83
(746)
(746)
(746)
(804)
(804)
(804)
(852)
(852)
(852)
(155)
(155)
(155)
(175)
(175)
(175)
(187)
(187)
(1«7)
usn
(151)
mi)
(165)
(165)
(165)
(180)
(180)
(ISO)
kg/h Clb/h)
305 (674)
306 (674)
306 (674)
306 (674)
306 (674)
306 (674)
306 (674)
306 (674)
306 (674)
170 (375)
170 (375)
170 (375)
170 (375)
170 (375)
170 (375)
170 (375)
170 (375)
170 (375)
191 (til)
191 (422)
191 («2)
191 (422)
191 (422)
191 (422)
191 (*22)
191 (422)
191 (422)
ktg/h (Ib/h)
1,052 <2,316)
1,249 (2,752)
898 (1,980)
1,155 (2,545)
1,351 (2,979)
980 (2,159)
1,255 (2,766)
1,452 (3,200)
1,036 (2,284)
314 (699)
365 (804)
288 (635)
352 (775)
396 (870)
313 (690)
379 (835)
422 (930)
331 (729)
332 (734)
379 (835)
3OS (674)
360 (794)
402 (885)
328 (723)
392 (864)
433 (954)
347 (763)
-------
U)
IABLE 75c- sps: tS5^'zs£K»s5£**»'
(44 MW or 150 x 106 Btu/hr heat input)
. „ ,. , . . Z S02 Level of* Ca/Sf
Z Sulfur Z Ash control control r.tio
3.5 10.6 78.7 M 2.5
3.4
1.8
3.5 10.6 85 I 2.9
3.8
2.1
3.5 10.6 90 S 3.3
4.2
2.3
0.9 6.9 75 M 2.2
3.2
1.6
0.9 6.9 83.9 IkS 2.8
3.7
2.0
0.9 6.9 90 S + 3.3
4.2
2.3
0.6 5.4 75 M 2.2
3.2
1.6
0.6 5.4 83.2 I & S 2.7
3.6
2.0
0.6 5.4 90 S + 3.3
4.2
2.3
Limestone feed*
1,754 (3.865)
2,386 (5,255)
1,264 (2,782)
2,034 (4,482)
2,666 (5,874)
1,474 (3,246)
2,316 (5,102)
2,948 (6,492)
1,614 (3,556)
340 (748)
494 (1,086)
246 (544)
432 (952)
570 (1,258)
308 (680)
510 (1,122)
648 (1,428)
356 (782)
326 (716)
474 (1,042)
236 (522)
400 (880)
532 (1,174)
296 (652)
488 (1,076)
622 (1,368)
340 (750)
Inertt frov c
\ Unc&lcxncd C&CO^
Limestone (10X) , ,. /,. *. \
kg/h db/h) kg/h (lb/h)
175
239
126
203
267
147
232
295
161
34
49
25
43
57
31
51
65
36
33
47
24
40
53
30
49
62
34
(387)
(526)
(278)
(448)
(587)
(325)
(510)
(649)
(356)
(75)
(109)
(54)
(95)
(126)
(68)
(112)
(143)
(78)
(72)
(104)
(52)
(88)
(117)
(6»
(108)
(137)
(75)
79
107
56
92
120
66
104
133
73
15
22
11
19
26
14
23
29
16
15
21
11
18
24
13
22
28
15
(174)
(236)
(125)
(202)
(264)
(146)
(230)
(292)
(160)
(34)
(49)
(24)
(43)
(57)
(31)
(50)
(64)
(35)
(32)
(47)
(23)
(40)
(53)
(29)
(48)
(62)
(34)
Unreacted CaO*
kg/h (Ib/h)
562
864
326
674
976
406
790
1,094
454
104
178
60
142
208
82
174
240
100
100
170
58
130
194
80
166
228
96
(1.236)
(1.902)
(718)
(1.484)
(2,150)
(892)
(1,740)
(2,406)
(1,000)
(230)
(392)
(132)
(312)
(458)
(182)
(384)
(530)
(220)
(218)
(374)
(126)
(286)
(426)
(176)
(368)
(506)
(212)
CaSOii generated*
kg/h (Ib/h)
675 (1,491)
675 (1.491)
675 (1,491)
729 (1,608)
729 (1,608)
729 (1,608)
772 (1.705)
772 (1,705)
772 (1,705)
141 (311)
141 (311)
141 (311)
160 (350)
160 (350)
160 (350)
170 (374)
170 (374)
170 (374)
136 (301)
136 (301)
136 (301)
151 (330)
151 (330)
151 (330)
165 (359)
165 (359)
165 (359)
* Coal ash*t
kg/h (Ib/h)
611 (1,347)
611 (1,347)
611 (1,347)
611 (1,347)
611 (1,347)
611 (1,347)
611 (1,347)
611 (1,347)
611 (1,347)
340 (750)
340 (750)
340 (750)
340 (750)
340 (750)
340 (750)
340 (750)
340 (750)
340 (750)
383 (844)
383 (844)
383 (844)
383 (844)
383 (844)
383 (844)
383 (844)
383 (844)
383 (844)
Total solid waste
kg/h (Ib/h)
2,102
2,496
1,794
2,309
2,703
1,959
2,509
2,905
2,071
634
730
577
704
791
627
758
844
662
667
757
612
722
805
657
785
866
693
(4,635)
(5,502)
(3,959)
(5,089)
(5,956)
(4,318)
(5,532)
(6,399)
(4,568)
(1,400)
(1.611)
(1,271)
(1,550)
(1,741)
(1,381)
(1,670)
(1,861)
(1,457)
(1,467)
(1,670)
(1,346)
(1,588)
(1,770)
(1,444)
(1,727)
(1,908)
(1,524)
-------
TABLE 75d. SOLID WASTE GENERATED BY A ONCE-THROUGH, LIMESTONE-FED,
COAL-FIRED, "BEST SYSTEM" ATMOSPHERIC FBC BOILER
(58.6 MW or 200 x io6 Btu/hr heat input)
» o ,<: » . u. * SO, Level of* C»/Sf
% Sulfur I Ash ^^ control rat.o
3.5 10.6 78.7 M 2.5
3.4
1.8
3.5 10.6 85 I 2.9
3.8
2.1
3.5 10.6 90 S 3.3
4.2
2.3
0.9 6.9 75 M 2.2
3.2
1.6
0.9 6.9 83.9 I & S 2.8
3.7
2.0
0.9 6.9 90 S + 3.3
4.2
2.3
0.6 5.4 75 M 2.2
3.2
1.6
0.6 5.4 83.2 I & S 2.7
3.6
2.0
0.6 5.4 90 S + 3.3
4.2
2.3
Linestone feed*
kg/h (Ib/h)
2,339 (5,153)
3,181 (7,007)
1,684 (3,709)
2,713 (5,976)
3,555 (7,832)
1,965 (4,328)
3,089 (6,803)
3,930 (8,656)
2,152 (4,741)
453 (997)
657 (1,448)
329 (725)
576 (1,269)
761 (1,677)
412 (907)
679 (1,496)
864 (1,904)
474 (1,043)
434 (955)
631 (1,389)
316 (696)
533 (1,173)
711 (1,565)
395 (869)
651 (1,435)
828 (1,824)
454 (1.000)
inert, fro. Uncilcined CaC035
liaeatone (101) . . nh/h'V
kg/h (Ib/h) kg/h Ub/h)
234
318
168
271
356
196
308
393
215
45
66
33
58
76
41
68
86
47
43
63
32
53
71
40
65
83
45
(515)
(701)
(371)
(598)
(783)
(433)
(680)
(865)
(474)
(100)
(145)
(73)
(127)
(168)
(91)
(150)
(190)
(104)
(96)
(139)
(70)
(117)
(157)
(87)
(144)
(182)
(100)
105
143
76
122
160
88
139
177
97
20
29
15
26
34
19
31
39
21
20
28
14
24
32
18
29
37
20
(232)
(315)
(167)
(269)
(352)
(195)
(306)
(390)
(213)
(45)
(65)
(33)
(57)
(75)
(41)
(67)
(86)
(47)
(43)
(63)
(31)
(53)
(70)
(39)
(65)
(82)
(45)
Unreacted CaO*
kg/h (Ib/h)
748
1,151
434
898
1,301
540
1,053
1,456
605
139
237
80
189
278
110
233
321
134
132
226
76
174
258
107
223
307
129
(1,648)
(2,536)
(957)
(1,978)
(2,866)
(1,189)
(2,320)
(3,208)
(1,333)
(306)
(522)
(176)
(416)
(611)
(243)
(512)
(707)
(294)
(291)
(499)
(168)
(382)
(568)
(235)
(491)
(675)
(283)
CaSOi, generated*
kg/h (Ib/h)
903
903
903
974
974
974
1,032
1,032
1,032
188
188
188
211
211
211
226
226
226
182
182
182
199
199
199
216
216
216
(1.989)
(1,989)
(1,989)
(2,144)
(2,144)
(2,144)
(2,273)
(2,273)
(2,273)
(415)
(415)
(415)
(466)
(466)
(466)
(498)
(498)
(498)
(401)
(401)
(401)
(440)
(440)
(440)
(478)
(478)
(478)
'* Coal ash**
kg/h (Ib/h)
815 (1,797)
815 (1,797)
815 (1,797)
815 (1,797)
815 (1,797)
815 (1,797)
815 (1,797)
915 (1,797)
815 (1,797)
454 (1,000)
454 (1,000)
454 (1,000)
454 (1,000)
454 (1,000)
454 (1,000)
454 (1,000)
454 (1,000)
454 (1,000)
510 (1,125)
510 (1,125)
510 (1,125)
510 (1,125)
510 (1,125)
510 (1,125)
510 (1,125)
510 (1,125)
510 (1,125)
Total solid waste
kg/h (Ib/h)
2,805 (6,181)
3,330 (7,338)
2,396 (5,281)
3,080 (6,786)
3,606 (7,942)
2,613 (5,758)
3,347 (7,376)
3,873 (8,533)
2,764 (6,090)
846 (1,866)
974 (2,147)
770 (1,697)
938 (2,066)
1,053 (2,320)
835 (1,841)
1,012 (2,227)
1,126 (2,481)
882 (1,943)
887 (1,956)
1,009 (2,227)
814 (1,795)
960 (2,117)
1,070 (2,360)
874 (1,926)
1,043 (2,303)
1,153 (2,542)
920 (2.031)
-------
TABLE 75 (continued)
M * moderate level
I • intermediate level
S » stringent level
S+ • greater than recooaended stringent level
Each level of control is shown to have three Ca/S ratios assocated with it. This range of ratios represents the projected range of sorbent feed
rates (for the "best system" design for SO2 control) resulting from the expected range of aorbent reactivities.
^Limestone - assumed 90 percent CaC03; 10 percent inerts.
95 percent of the CaC03 is assumed to be calcined.
Unreacted CaO • CaO produced - CaO used;
U>
O\ Rate CaO produced - percent CaCOs in feed x percent CaCOi calcined x aolecul>r weight of CaO— x limestone feed rate;
molecular weight of CaCOs
.90 x 0.95 x — x limestone feed I
100
(i.e., O.S
Rate CaO used - fractional S02 control level x rate SO, released by coal combustion (kg/h or Ib/h) x •oscular weight of CaO L f |5\
molecular weight of SQ2 \ **/
**C.SO, generated x C.O used x molecular weight of C.SO ( m\
molecular weight of CaO \ 36 /
Total solid waste quantities include 100 percent of the coal ash, regardless of whether the ash is withdrawn from the bed or captured in primary
and final fly ash control devices. Similarity, the total waste includes all of the spent sorbent regardless whether the spent sorbent is
withdrawn from the bed.
-------
1.3
I
E
u
a
u
1.0
0.9
0.8
0.7
O.i.
0.5
0.4
0.5
0.2
O.I
/ /CONTROL
/ /
SiP CONTROL
6.8
22
44
* I HECTARE - m«t«r/y«or:
CAPACITY, MW
8 oc/e f«ot/>«or
Figure 55. Land requirements for FBC burning high
sulfur coal using medium reactivity
limestone.
367
-------
land use requirements of the stringent level of SC>2 control are nearly twice
the requirements of that which would result if S02 control were equal to
current SIP requirements. This impact is slight for the small boilers, but
can be significant for the larger boilers. The range of land needed for solid
waste disposal for the boiler systems in Figure 55 is 0.11 to 1.43 hectare
meter/yr (0.92 to 11.56 acre ft/yr).
Figure 56 indicates the sensitivity of the land needed for disposal of
the waste with respect to the Ca/S ratio, as it is increased from 1 to 9.9.
(Ca/S ratios above 6 are considered unrealistic but are provided simply for
the reader's perspective.) Figure 56 can be used to project the impact of
"commercially offered" systems by comparing the Ca/S ratios used for the com-
mercial systems as discussed in Section 3.0 of this report with the Ca/S
ratios and associated land use requirements projected in the figure. For
example, taking the case of the Babcock and Wilcox (U.S.) commercially offered
design burning an Eastern high sulfur coal and Western 90 percent Ca/Limestone
with stringent (90 percent) S02 control, the Ca/S ratio is projected at 4.58,
as opposed to 2.83 for the "best system" design/operating conditions. The
following land use comparisons can be mader
Boiler B&w "best" system
capacity hectare meter/yr hectare meter/yr
8.8
22
44
58.6
0.26
0.66
1.31
1.74
0.20
0.49
0.78
1.30
368
-------
IU
>
(C
u>
I-
UJ
o
Ul
4.00
5.80
3.60
3-40
3.20
3.00
2.80
2.60
2.40
2.20
2.00
1.60
I 60
1.40
1.20
t.OO
0.80
060
0.40
0.20
_L
_L
_L
_L
_L
I 2
* I HECTARE - m«ttr/y«or
34567
Co/S MOLAR FEED RATIO
X
6 oer« f««t
8.8 MW«
10
Figure 56. Land use requirements for disposal of
solid waste.
368a
-------
6.2.2.2 Environmental Properties of FBC Solid Waste—
Disposal of solid waste from FBC systems is expected to occur by landfil-
ling the material. The environmental impact of this method of disposal is
under investigation. The primary sources of environmental degradation are the
leachate formed by rainwater runoff and percolation after landfilling, and the
heat release from the material upon initial contact with water, due to hydra-
tion of the CaO in the waste.
The disposal of solid waste is governed by laws promulgated under the
auspices of the 1976 Resource Conservation and Recovery Act (RCRA, PL 94-580).
In response to RCRA, the EPA has proposed a regulatory program to manage and
control the nation's hazardous wastes from generation to disposal. The pro-
gram includes criteria for identification of hazardous wastes (toxic, corro-
sive, ignitable and reactive), and rules and regulations for their management
and control. When the EPA proposed the hazardous waste regulations, it set
aside, a unique category of special wastes - certain large volume wastes of
which portions would be hazardous. The EPA plans to propose regulations gov-
erning special wastes in the early part of 1982. Until that time, the EPA has
prepared special standards for each type of special waste. Although solid
residues from coal-fired fluidized-bed combustion systems have not been regu-
lated by the proposed program, they are a potential candidate for inclusion
in the special wastes category which will include cement kiln dust, utility
wastes (fly ash, bottom ash, scrubber sludge), phosphate mining and proces-
sing wastes, uranium mining wastes, other mining wastes, and oil and gas
drilling muds and oil production brines.
369
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FBC residue seems to be a potential candidate for the special waste
category because it will be generated in large quantities once the FBC
technology is commercialized. Also, it contains similar chemical constituents
to those found in utility wastes and cement kiln dust.
The EPA recommends that only the hazardous portions of special wastes
comply with the proposed special standards. Section 3001 of the regulation
provides the means for determining whether a waste is hazardous for the
purpose of the Act. The hazardous portions of solid residues of FBC systems
will be determined by testing by toxicity - one of the characteristics exhibited
by hazardous wastes when improperly disposed of. A waste is considered toxic
for the purpose of the Act if a chemical analysis of its water extract obtained
in accordance with the Extraction Procedure (EP) reveals the presence of one
of certain chemicals in concentrations which exceed ten times the drinking
water standards. The contaminants and their maximum allowable concentration*
are listed below:
Contaminant
Arsenic
Barium
Cadmium
Chromium
Lead
Mercury
Selenium
Silver
Endrin
Lindane
Methoxychlor
Toxaphene
2,4-P
2,4,5-TP
Maximum allowable
extract level (mg/1)
0.50
10.0
0.10
0.50
0.50
0.02
0.10
0.50
0.002
0.040
1.0
0.050
l.Q
0.10
370
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This list is not final and may be it vised by EPA through the rulemaking
process as information develops. Since the last six contaminants are synthe-
tic organic compounds, it is very likely that they will be present in leachates
from FBC wastes. The analysis, thete£or2, can be limited to the metal ions por-
tions of the list. Wastes from several small scale fluidized-bed combustion
units have recently been tested by Westinghouse for EPA. None of the eight
metals listed above exceeded the maximum allowable extract level.®
If these pollutants are measured in concentrations above the maximum
allowable extract level, then the solid waste must be disposed of in compli-
ance with the rules and regulations set forth in RCRA for toxic wastes. FBC
residue will probably not be considered a candidate for corrosive, ignitable
or reactive categories under RCRA.
Current interpretations of RCRA indicate that "corrosive" applies to
liquid wastes and not leachate from solid waste; hence, despite its high pH,
FBC waste would probably not be considered "corrosive." Furthermore, even
though it does release heat upon exposure to water, the reaction does not
seem sufficient to meet current EPA criteria for "reactive" waste.
The British Coal Utilization Research Administration (BCURA),9 Pope,
Evans, and Robbins,10 Westinghouse,11'12 and Ralph Stone and Company,13 have
conducted laboratory tests to investigate the properties of the leachate
obtained from the coal ash/limestone waste using distilled water. Their
test results generally showed the following common factors:
• high calcium content;
• high sulfate content;
• high total dissolved solids, due to CaSO^ going into
solution; and,
• high pH (10 to 12) due to CaO content.
371
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One of the most definitive evaluations of the potential contamination
from FBC waste was done by Westinghouse Research Laboratories.14'15 Leachates
were generated using distilled, deionized water in laboratory shake tests for
a variety of FBC wastes; the resulting leachate concentrations were then
compared with drinking water standards (National Interim Primary Drinking
Water Regulations (NIPDWR-1975), U.S. Public Health Service (USPHS) Drinking
Standards). The data are summarized in Table 76. This is a very conservative
approach and would tend to overestimate the impact since: (1) the laboratory
shake tests are designed to maximize the water extraction forces; and (2) direct-
comparison with drinking water standards does not allow for any dilution of
a leachate plume in the ground water. It is also important to note that
drinking water standards are more stringent than leachate standards presently
being proposed under Section 3001 of the Resource Conservation and Recovery
Act (RCRA) by a factor of 10, underscoring the conservative approach taken
by Westinghouse.
The only components of FBC leachate which consistently exceeded the
drinking water standards were the following:
• Ca;
• S(V,
• pH; and
• total dissolved solids.
Note, this set of experiments did not use the EP procedure (acetic acid) as
described in the RCRA Guidelines published in the December 18, 1979 Federal
Register. As mentioned earlier, tests done subsequent to these experiments
using the acetic acid EPA procedure still showed no problems with FBC leach-
ates when compared with the RCRA Guidelines.
372
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TABLE 76. COMPARISON OF LEACHATE CHARACTERISTICS
FROM THE FBC AND FGD RESIDUES14
Substance
Al
<^g
As
B
Ba
. Be
Bi
Ca
Cd
Co
Cr
Cu
Fe
Hg
Mg
Hn
Mo
Na
Hi
Pb
Sb
Se
Si
Sn
Sr
Ti
V
Zn
Zr
SO 3
SO.,
Cl
F
NO 3 (as N)
TOC
pH
IDS
Specific
Conductance
millimhos/cm
Liquor (mg/1)
FGD
0 to 20
<0.05
<0.05
>5
<1
<0.02
<0.04
>5001:
0 to 0.2$
<0.1
<0.05
<1
<0.3
<0.002
0 to >1,000$
0 to 20$
0.1 to 7.0
0 to >100
<1
<0.05
<0.2
0.001 to 0.5$
0 to 30
<1.0
0 to 40
<2
<2
<2
<2
<10 to 40
1,000 to 7, 000$
300 to 6,000$
10 to 50$
0 to 100*
<30
6 to 9
5,000 to 14,000$
5.0 to 17.0
Leachate (mg/1) Dri
FBC
0 to >2
<0.05
<0.05
0 to >5
<2+$
<0.02
<0.04
>500$
<0.01
<0.1
<1.0*$
<0.1
<0.3
<0.002
0 - 250**
<0.05
<5
0 to >100
<0.1
<0.05
<0.1
<0.01
0 to 30
<1.0
0 to >10
<2
<1
<1
<1
<10
1,000 - 2,000*
0 to 350f$
<2.4
<10
<30
9 to 12$
2,000 to 4,0001
0.5 to 10.0
FGD
<1
<0.05
0 to 0.1-f
>1
<1
<0.02
<0.04
>500*
<0.01
<0.1
<0.05
<0.1
<0.3
<0.002
0 to 500*
0 to O.lt
<1
<10
<0.1
<0.05
<0.1
0 to 0.1*
0 to 5
<1.0
0 to 5
<2
<1
<1
<1
<10
1,000 - 2,000*
30 to 300$
1 to 10*
<10
<30
6 to 9
2,000 to 3,000'f
2.0 to 3.0
Inking Water*
Standards
(mg/1)
0.05
0.05
1.0
75
0.01
0.05
1.0
0.3
0.002
50
0.05
2.0
0.05
0.01
1.0
5.0
250
250
2.4
10
5 to 9.
500
National Interim Primary Drinking Water Regulations (NIPDWR) (1975) and
U.S. Public Health Service (USPHS) (1962) Drinking Water Standards, and
World Health Organization (WHO) Potable Water Standards.
Concentrations higher than the Drinking Water Standards resulted from
leachates of <2 Batches of carry-over fines among the >30 spent FBC materials
investigated.
^Exceed Drinking Water Standards.
373
-------
In addition, the following species exceeded the drinking water
in less than two of the more than 30 FBC samples tested:
• Ba;
• Cr;
• Mg; and,
• Cl.
Westinghouse16 has concluded from their study that:
• No water pollution is expected from the leaching of
those trace-metal ions for which drinking water standards
exist, since the leachate itself meets drinking water
standards.
• An insignificant amount of magnesium is leached out,
even for dolomite sorbent.
• Sulfide may not be a problem for the once-through
sorbent, since the sulfide concentration in the leachate
is below detection limits.
• The total dissolved organics are below detection limits.
• Residual activity, reflected by heat release upon initial
exposure to water, has been observed for once-through
atmospheric pressure FBC systems, and is judged as an
environmental concern for direct disposal. The heat
release is attributed to the large amount of calcium
oxide present in the spent sorbent.
• Potential problems with the leachates are the high
concentrations of calcium (Ca), sulfate (SO^), pH,
and total dissolved solids (TDS), which are above
drinking water standards.
• The addition of 20 wt percent ash to the spent sorbent
improves leachate quality. Thus, codisposal of spent
sorbent and ash can reduce the adverse environmental
impact.
• The environmental impact is reduced by room-temperature
processing.
According to Westinghouse, FBC residue will not be a hazardous pollutant.
however, it is still a candidate for the RCRA special waste category by vlrt-
of the volume of material which will be produced.
374
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Further engineering and experimental studies are required in order to
further define the environmental impact of the FBC residue in the actual dis-
posal environment, and to systematically assess the design, performance and
costs of alternative handling and disposal options. The following areas need
investigation:
1. Define environmental impact of disposal.
A more comprehensive view of the environmental impact of
FBC residue can be approached through development of a
methodology to project the environmental impact of commer-
cial-scale disposal sites based upon laboratory data.
Specifically, soil attenuation and deattenuation studies;
field cell work (to assess the tendency of the material
to set up, and the leaching properties that result); and
further confirmation of the major environmental problems
(pH, IDS, Ca, SOij) on a wider variety of FBC residues
should be pursued.
2. Assess handling options.
Handling options for the solids prior to disposal must be
identified and evaluated. Two options are hydration of
the solid waste piles at the FBC plant site, or transpor-
ting the waste to a disposal site prior to hydration in
covered trucks to avoid fugitive emissions during trans-
port. These and other options and their environmental
impacts must be assessed.
3. Assess disposal options.
Disposal options must be identified and evaluated more
fully. Options such as solid waste neutralization to
control pH, clay-lined basins to prevent leaching to
ground water, and pretreatment as a cement-like material
at the site to prevent heat release and leaching, should
be considered. Tests which are needed to evaluate these
methods must also be identified. For example, liners
must be tested to see whether the waste will react with
the material or not, and what the consequences of any
such reaction might be. The effectiveness of the liners
must be assessed as well as any pretreatment options.
Furthermore, it would be advantageous to the commercial-
ization of FBC systems to follow the development of RCRA
requirements as well as any other regulatory activities
which may affect the disposal requirements for FBC, such
as effluent guidelines or ground water regulations which
may be developed in the future. The assessment of the cost
of meeting these kinds of requirements is also essential.
375
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It appears at this time that FBC solid waste disposal should not be an
insurmountable problem. However, attention to suitable handling and disposal
options should be given in the FBC plant design and cost studies.
6.2.2.3 Means of Reducing the Quantity of Solid Waste Generated—
Due to the large amount of solid waste generated, it is to the FBC devel-
oper and operator's best interest to reduce the quantity generated by whatever
means are available. Methods of lowering the volume of material that are pre-
sently feasible are:
• using low sulfur coal;
• using a sorbent with high reactivity;
• increasing gas residence time; and,
• decreasing sorbent particle size.
Methods which are presently under investigation and development are:
• other methods of improving calcium utilization, such
as injection of sodium chloride or calcium chloride;
• spent stone regeneration;
• alternate synthetic sorbents which require less volume
and have better regeneration qualities; and,
• reactivation of spent stone by exposure to water.
6.2.2.4 Comparison of FBC Solid Waste with FGD Sludge—-
The solid waste produced at an industrial-sized AFBC plant may range from
110 to 3,900 kg/hr (250 to 8,500 Ib/hr). Babcock and Wilcox Company compared
the solid waste from a fluidized-bed boiler with particulate control and from
a flue gas desulfurization (FGD) system plus a precipitator on a conventional
pulverized fuel boiler, using a 3 percent sulfur, 10 percent ash coal. Table
77 indicates the relative amount of material to be disposed of from the two
17
systems.
376
-------
TABLE 77. BABCOCK AND WILCOX COMPANY'S
COMPARISON OF SOLID WASTE
MASS FROM FBC AND FGD17
Quantity/ton of coal,
kg (Ibs)
Ca/S Ratio required
CaCOs Supplied
Spent Sorbent
Limestone inert
Moisture in filter
cake at 50
percent
Fly ash and carbon
Solid waste to haul
away
Form of Waste
FBC
4.0
349 (750)
243 (536)
18 (39)
-0-
105 (232)
366 (807)
Dry granular
solid
FGD and
precipitator
1.1
94 (206)
107 (235)
5 (11)
112 (246)
105 (232)
329 (724)*
Wet sludge
Wet basis.
377
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Based on the Babcock and Wilcox results, the mass of waste which must be
hauled away to a landfill from an FBC boiler (dry basis) is only 11 percent
more than the waste from a wet scrubber system (wet basis) when a separate
(dry) particulate removal system is used with the scrubber. However, if the
fly ash is also collected in the wet scrubber, then the amount of wet sludge
will be greater than the amount of dry waste from the FBC boiler, due to the
moisture content that would be associated with the fly ash in such a case.
The Tennessee Valley Authority has also compiled information on the
relative mass of the two wastes produced. Table 78 indicates that although
the actual amount of dry sorbent used is less for FGD than FBC, the solid
waste mass is actually greater by as much as 40 percent due to the water
content of the slurry.18
There are a few major differences between the waste from FBC and lime/
limestone FGD. Listed below are the major environmental concerns associated
with the waste from the two technologies.
FBC
PH
IDS
-
SOit
Ca
_
FGD19
PH
TDS
S03
SC-1+
Ca
Cl
dry granular thixotropic
solid sludge
heat release
378
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TABLE 78. COMPARISON OF AFBC AND
SCRUBBER SOLID WASTES
FOR A 200 MW PLANT
ESTIMATED BY TVA18
AFBC
Conventional
with scrubber
Coal
Ash
Sulfur
Percent removal
Ca/S
10%
3.5%
85%
2.5
10%
3.5%
85%
1.5
Annual coal use 450,000 ton/yr 450,000 ton/yr
Spent Sorbent
Dry
Wet
Spent Ash
Total waste
120,000 ton/yr
168,000 ton/yr
45,000 ton/yr 45,000 ton/yr
165,000 ton/yr 213,000 ton/yr
84,000 ton/yr
379
-------
The presence of sulfite ion (SOs") in the scrubber sludge is the major
chemical difference between the wastes produced by the two systems . From an
environmental viewpoint this makes scrubber sludge a detriment, as this SOj*
will be a source of chemical oxygen demand, since it is readily oxidized to
FGD sludge is a thixotropic, partially oxidized slurry. Since thixo-
tropic slurry tends to liquefy easily, it is difficult to handle, and dewater-
ing techniques such as centrifuges and vacuum filters do not reliably yield
the 70 to 75 percent solids needed prior to landfilling.
FBC waste in contrast is a dry, almost fully oxidized solid, although In
some cases it may be necessary to wet it down for handling purposes. It would
not, however, contain as much water as scrubber sludge. The preliminary en-
vironmental concern with FBC waste is the leachate quality and heat release pro-
perties. Although the disposal of waste from the FBC system may be less of an
environmental detriment than that from FGD, there is still a great volume of
material which must be disposed of. Methods of lowering the volume of material
that are presently feasible are using a low sulfur coal or a sorbent with high
reactivity. Methods which are presently under investigation and development
are:
• methods for improved calcium utilization;
• methods of regenerating spent stone; and,
• alternate synthetic sorbents which require less volume
and better regeneration qualities.
Both residues may need some sort of treatment prior to disposal: FBC to
control the heat release potential and FGD to dewater and oxidize the waste.
It is difficult at this time to project exactly what degree of treatment will
380
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be necessary for either waste. According to the TVA and B&W studies, FBC waste
has a slight disposal cost advantage over FGD sludge. Further study of this
issue is warranted.
6.2.2.5 Byproduct Uses for Solid Waste—
The potential of this waste material as a byproduct should not be ignored.
Because of the high amount of unused lime (CaO), uses as a cement supplement,
agricultural additive, building material and road aggregate have all been
explored and results are promising. As larger quantities of waste become
available from the operation of a demonstration plant, a better assessment
of the resource recovery possibilities can be made.
The Department of Energy (DOE) is funding a 5-year research program to
identify and evaluate potential agricultural applications for FBC solid
wastes.2" The study is being performed simultaneously in several states,
all located in the Eastern half of the United States. The program covers almost
the entire crops grown in Eastern United States. It includes both short- and
long-term laboratory and field based evaluations. The waste is used as a
replacement for lime to neutralize soil, as a source for trace and certain
nutrient elements, and as a source for sulfur. The study evaluates both the
quality and quantity of crops produced from soil treated by waste material,
as well as the crops' nutrient value as food for domestic animals.
A study to evaluate the physiological effects of food that was ultimately
obtained from FBC waste-treated soils on people and animals has been proposed
to DOE and EPA. The study will monitor mineral balance and amino acids in
human tissues, primarily human hairs, which tend to accumulate toxic materials.
Some small animals will be evaluated over several reproductive cycles to deter-
mine long term effects on offspring. People will be fed in two stages. The
first test will start in October 1979 and the second is scheduled for 1980.
381
-------
Several other studies have demonstrated that FBC solid residues, because
of their unique chemical composition, possess cementitious characteristics
which, if exploited, can turn the waste into a very durable concrete-like
mass. One such study investigated the potential for using FBC solid waste
for road constructions.21 The result indicated that comprehensive strength
of cemented waste exceeded the value recommended for heavy traffic highway
construction over a wide range of compositions. Further, this compressive
strength, which is indicative of the material durability and resistance to
erosion, improved with time even after the cemented samples were subjected
to the effect of freeze/thaw cycles. The study concluded that the excep-
tionally high strength of cemented FBC residue makes it suitable for applica-
tions requiring materials with low water permeability, such as in embankments'
structural fills, and liners to control leaching from waste disposal dumps
and lagoons. The latter application is particularly important, since some
clay-type liners which are being used in sanitary landfill have developed
cracks after several years of use, which allow leachates to further perco-
late into ground water aquifers.
6.2.3 Water Pollution
Most aqueous emissions from AFBC such as boiler feed water treatment
effluents, thermal discharge, and runoff from coal and limestone piles will
be similar to conventional boilers' effluents.
Water pollution from solid waste disposal is discussed in Section 6.2.2
The preliminary water impact concerns are the pH, TDS, Ca, and SO^ contents
of the leachate.
New FBC sites will be required to obtain a National Pollution Discharge
Elimination System (NPDES) permit under the Water Pollution Control Act
382
-------
requiring zero discharge (not increasing the pollution level of waters) of
certain pollutants such as IDS, pH, BOD (biochemical oxygen demand) and COD
(chemical oxygen demand), and certain other pollutants which are character-
istic of the particular process (i.e., possibly SO^ and Ca for FBC).
6.3 OIL-FIRED AFBC
The air, water, and solid waste pollution from oil-fired AFBC units is
expected to be similar to coal-fired pollutants. It is expected that air
emissions will be lower due to lower fuel sulfur content, lower nitrogen
content, and lower fuel ash. The solid waste impact, therefore, will also
be lower because less sorbent feed would be required to remove the S02-
6.4 SUMMARY
6.4.1 Impact of Emission Control Technique
In terms of implementing the best candidates for emission control in
fluidized-bed combustion, the major environmental concern is the impact of
increased Ca/S mole ratios for S02 control on the amount of solid waste gen-
erated. Enhanced S02 control using high Ca/S ratios along with very small
limestone particle sizes could also increase particulate emissions, but it
is doubtful that this increase would be to such a degree that available par-
ticle control systems could not handle it.
Implementing the three levels of NOX control requires little change in
operating variables and little if any environmental impact is foreseen.
The only major environmental impact foreseen in implementing moderate,
intermediate or stringent particulate control is the concomitant 5 to 10
percent increase in solid waste disposal associated with the increased con-
trol. Characterization of the nature of these collected fines is an area
where further research is needed.
383
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6.4.2 Solid Waste Disposal
FBC residue does not currently appear to be "hazardous" under RCRA Section
3001 (i.e., it is not considered toxic, reactive, corrosive, or ignitable).
However, future RCRA developments do need to be followed.
Potential problems associated with the residue which have been identified
are: the pH, IDS, Ca and S0i+ in the leachate and initial heat release upon
contact with water and total solid mass, and handling problems.
Thus, the residue will require some care in handling and disposal such
as pretreatment with water, neutralization, clay-lined basins for disposal,
or a combination of these options. Generally, the disposal of AFBC residue
does not pose any insurmountable problems.
384
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6.5 REFERENCES
1. Swift, W.M., G.J. Vogel, and A.F. Panek. Potential of Fluidized-Bed Com-
bustion for Reducing Trace-Element Emissions. Prepared by Argonne Nation-
al Laboratory. Presented at the 68th Annual Meeting of the Air Pollution
Control Association. Paper No. 75-46.3. June 1975. p. 15.
2. Fennelly, P.F., et al. Preliminary Environmental Assessment of Coal-
Fired Fluidized-Bed Combustion Systems. Prepared by GCA Corporation,
GCA/Technology Division for the U.S. Environmental Protection Agency.
EPA-600/7-77-054. May 1977. p. 39.
3. Dowdy, I.E., et al. Summary Evaluation of Atmospheric Pressure Fluidized-
Bed Combustion Applied to Electric Utility Large Steam Generators. Pre-
pared by the Babcock and Wilcox Company for the Electric Power Research
Institute. EPRI FP-308. October 1976. p. 6J-9.
4. Henschel, D.B. Environmental Emissions from Coal-Fired Industrial
Fluidized-Bed Boilers. Proceedings of the Conference on Engineering
Fluidized-Bed Combustion Systems for Industrial Use. Sponsored by the
Ohio Department of Energy and Battelle-Columbus Laboratories.
September 26-27, 1977. p. 17.
5. Environmental Protection Agency. Hazardous Waste — Proposed Guidelines
and Regulations and Proposal on Identification and Listing. Federal
Register. December 18, 1978. Part IV, pp. 58946-59028.
6. Swift, W.M., op. cit. p. 1.
7. Fennelly, P.F., op. cit. pp. 28-34.
8. Henschel, D.B. The EPA R&D Program to Assess the Solid Residue from the
Fluidized-Bed Combustion Process. Presented at EPRI/ASCE Workshop on
Solid Waste, San Diego, California. April 23-25, 1979.
9. Pressurized Fluidized-Bed Combustion. British Coal Utilization Research
Agency (BCURA). National Research Development Corporation, London.
Prepared for Office of Coal Research. R&D Report No. 85.
10. Pope, Evans, and Robbins. Multicell Fluidized-Bed Boiler Design, Con-
struction and Test Program. Pope, Evans, and Robbins, Inc. Publication
No. PB 236 245/AS. Office of Coal Research, Washington, D.C. R&D Report
No. 90. Interim Report No. 1. August 1974. pp. 211-214.
11. Keairns, D.L., et al. Fluidized-Bed Combustion Process Evaluation;
Phase II — Pressurized Fluidized-Bed Coal Combustion Development.
Westinghouse Research Laboratories. Prepared for U.S. Environmental
Protection Agency. EPA Report No. EPA-650/2-75-027c. September 1975.
pp. 273-286.
385
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12. Sun, C.C., C.H. Peterson, R.A. Newby, W.G. Vaux, D.L. Keairns. Disposal
of Solid Residue from Fluidized-Bed Combustion: Engineering and Labora-
tory Studies. Prepared by Westinghouse Research and Development Center
for the U.S. Environmental Protection Agency. EPA-600/7-78-049.
March 1978. pp. 4-5.
13. Stone, R., R.L. Kahle. Environmental Assessment of Solid Residues from
Fluidized-Bed Fuel Processing. Final Report. Prepared by Ralph Stone
and Company, Inc., for the U.S. Environmental Protection Agency. EPA-600/
7-78-107. June 1978. pp. 88-97.
14. Sun, C.C., C.H. Peterson, D.L. Keairns. Environmental Impact of the
Disoosal of Processed and Unprocessed FBC Bed Material and Carry-over.
Prepared by Westinghouse Research and Development Center for the Fifth
International Conference on Fluidized-Bed Combustion. December 12-14 1977
p. 5.
15. Sun, C.C., EPA-600/7-78-049, op. cit.
16. Ibid.
17. Walker, D.J., R.A. Mcllroy, H.B. Lange. Fluidi?ed-Bed Combustion Tech-
nology for Industrial Boilers of the Future: A Progress Report.
Prepared by Babcock and Wilcox Company. Presented to American Power
Conference. April 24-26, 1978. p. 7.
18. Reese, John T. Utility Boiler Design/Cost Comparison: Fluidized-Bed
Combustion Versus Flue Gas Desulfurization. Prepared by Tennessee
Valley Authority (TVA) for the U.S. Environmental Protection Agency
(EPA). November 1977. EPA-600/7-77-126. p. 310a.
19. Dickerman, J.C. Flue Gas Desulfurization Technology Assessment Report.
Draft Report. January 1979. Prepared by Radian Corp. for U.S. Environ-
mental Protection Agency, pp. 6-17 through 6-30.
20. Telephone conversation between Dr. H. Bennett, coordinator of DOE's
Agricultural Program for FBC Solid Wastes, and Dr. T. Goldschmid of
GCA/Technology Division. February 28, 1979.
21. Minnick, L.J. Development of Potential Uses for the Residue from
Fluidized-Bed Combustion Processes. Quarterly Technical Progress
Report. December 1978-February 1979. Prepared for the U.S. Depart-
ment of Energy, by L. John Minnick, Prime Contractor. April 1979.
pp. 6-12.
386
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7.0 EMISSION SOURCE TEST DATA
7.1 INTRODUCTION
Most of the emission test data from coal-fired atmospheric FBC boilers
has been obtained using sampling and analytical techniques other than EPA
reference methods. A variety of circumstances have contributed to this fact.
Primarily, emission data have been collected on experimental units, mostly to
characterize the FBC process and to investigate emission variability as a
function of boiler operating conditions. Because of the experimental nature
of many of the early units, and because the emissions from such small units may
not be completely characteristic of emissions from full-scale commercial units,
rigorous testing to determine compliance with specific emission standards had
not been an issue. In addition, due to the fact that previously available
FBC units were generally not amenable to continuous (24 hr/day) long-term
operation for extended periods, no long-term averaging (e.g., 30 day periods)
data have been generated. Most test periods have been short, some only hours,
others a few days. Although various investigators have expressed emission
results in terms of emission standards, EPA reference methods were not always
rigorously followed; in fact, a significant portion of the available emissions
data from atmospheric FBC units was obtained before the EPA reference methods
were officially accepted.
Sampling and analysis techniques have varied widely depending on the needs
and equipment limitations of individual experimental programs. The nature of
some of the FBC pilot facilities made certain aspects of compliance testing
387
-------
impractical; i.e., traversing across very small ducts and locating sampling
ports at stipulated distances from upstream and downstream disturbances. In
addition, there has been no impetus for monitoring according to EPA reference
methods in FBC testing performed in foreign countries, such as England, where
a significant portion of the early work was done.
A high priority in current testing plans is to monitor large scale FBC
boiler facilities for 30 day periods using EPA reference methods. Planning
is underway now to conduct such testing as soon as appropriate large AFBC
units begin operating for extended periods.
This section emphasizes the results of test programs conducted at the
largest atmospheric FBC units. Much of these data were obtained several years
ago, and in many cases, important design conditions, such as gas phase residence
time, freeboard height, and limestone particle size were not necessarily optimal *
The larger FBC units discussed here include those operated by Babcock and Wil-
cox (B&W); the National Coal Board (NCB); Pope, Evans and Robbins (PER); and
Babcock and Wilcox, Ltd. (Great Britain).
This section also reports raw test data which was referred to or
summarized in Section 2.0 of this report. A large portion of the discussion
and results presented in Section 2.0 is based on testing results reported by
NCB, PER, and B&W.
A general description of the FBC test facilities noted in this section
is presented in Table 79. A more detailed description of each test facility
As discussed elsewhere in this report, recent theoretical and bench scale
experimental work indicate substantial increases in SO? removal efficiency
can result 'using longer residence times and smaller limestone particles.
388
-------
TABLE 79. GENERAL DESCRIPTION OF ATMOSPHERIC FBC TEST FACILITIES
OJ
00
VO
Investigator
Babcock and Wllcox
(BtW)
Babcock and Wilcox
(B&W)
National Coal
Board (NCB)
Pope , Evans , and
Bobbins
Babcock and Wilcox,
Ltd.
FluiDyne
FluiDyne
National Coal
Board (NCB)
Argonne National
Laboratories (AND
_r ... Boiler
A T ^L classification and
designation cao.ctty (ag te8ted)
6 ft x 6 ft Pilot scale
7 M»t (25 x 10s Btu/hr)
3 ft x 3 ft Pilot scale
1.9 MHt (6.5 x 106 Btu/hr)
3 ft x 1.5 ft Pilot scale
0.3 - 1.3 J*»t
(1 - 4.5 x 106 Btu/hr)
1.5 x 6 ft Full scale boiler module
3.2 Wt (11 x 106 Btu/hr)
10 ft x 10 ft Industrial scale
12 tUt (40 x 106 Btu/hr)
3 ft x 5.3 ft Pilot scale
68 - 227 kg/hr coal
1.5 ft x 1.5 pilot scale
ft
6 in. Bench scale
diameter
6-in. diameter Bench scale
Bed Fluldizing
depth-meters velocity
fft> m/sec
Ut) (ft/sec)
0.80 - 1.4* 3
(2.83 - 4.73) (8)
0.3 - 0.6 1.2 - 3.7
(1.0 - 2.1) (4 - 12)
0.6 - 2.1 0.6 - 2.4
(2.0 - 7.0) (2.0 - 8.0)
0.3 - 0.6 3.0 - 4.6
(1.0 - 2.0)+ (10 - 15)
-
1.1 - 1.2 0.6 - 1.3
(3.5 - 4.0) (2.0 - 4.2)
- -
0.6 - 0.9 0.6 - 0.9
(2.0 - 3.0) (2.0 - 3.0)
0.38 - 0.61 0.73-2.36
(1.25 - 2.0) (2.40-7.73)
Other design
features
System Includes
primary cyclone
Integral water
jacketed fly
ash removal
device
System Includes
primary and
secondary
cyclones
Integral multi-
clone collector
for primary fly
ash removal
FBC retrofit to
stoker-fired
boiler
Underbed or
overbed feed
with recycle
Underbed or
overbed feed
with recycle
Underbed feed
with recycle
Underbed feed
with recycle
Emission data
reported*
S02. HO,
partlculate
S02, NCL
paniculate
S02. NO,
S02, NO,
partlculate
S02, NO,
S02
S02
S02
S02, NO,
Remarks «ef.r«ne.
number
Demonstrates greater than 1 and 2, 3
90 percent S02 control.
Limited recycle possible
(only 25 percent of carryover)
Shallow bed design not optimal 4
for S02 reduction. Low free-
board, no recycle
Underbed bed feed with 5, 6
recycle. High freeboard.
Short gas phase residence time 7, 8
and shallow bed depth not
optimal for S02 removal^"
Details of boiler design and 9
test procedures are not cur-
rently available
Effective S02 control due to 10, 11
long gas phase residence time
Demonstrated equivalent desul- 10
furlzation with inbed or over-
bed feed and primary recycle
Effective SO2 control consistent 12
with operating conditions close
to those recommended for "best
system" design
Effective SOa control consistent 13. 1*. 15
with operating conditions close and 16
to those recommended for "best
system" design. NO, higher than
expected due to small unit size.
*In some cases, more data was originally reported, but only emissions pertinent to this investigation are tabulated in this section.
fStatlc bed depth.
-------
is presented in Subsection 7.4. Emissions measured that are of concern in this
effort are also presented in Table 79.
7.2 EMISSION SOURCE TEST DATA FOR COAL-FIRED ATMOSPHERIC FBC BOILERS
This subsection presents detailed raw test data for experimental AFBC
test units. Table 80 is an index of the investigators and test units for which
data is reported.
TABLE 80. INDEX OF AFBC EMISSION TEST DATA
Table
No.
. FBC unit
Investigator , . . .
6 designation
Year of
testing
81
82
83
84
85
86
B&W
B&W
NCB
PER
PER
FluiDyne
6 ft
3 ft
CRE 3 ft
FBM 1.5
FBM 1.5
Vertical
x 6 ft
x 3 ft
x 1.5 ft
ft x 6 ft
ft x 6 ft
slice FBC
1978-1979
1976
1970-1971
Late 1967
through 1969
Through 1975
1977
87 FluiDyne
(3.3 ft x 5.3 ft)
Vertical slice FBC
(3.3 ft x 5.3 ft)
1977
88
89
90
91
NCB
NCB
NCB
Argonne
6 in.
6 in.
6 in.
6 in.
diameter
diameter
diameter
diameter
1970-1971
1970-1971
1970-1971
1968-1971
In addition, graphical emissions data reported by B&W, Ltd. at the
Renfrew, Scotland boiler are included in Figures 57 and 58. Figure 59 is
graph of data recorded by FluiDyne during operation of their 1.5 ft x 1.5
unit.
390
-------
TABLE 81. EMISSION TEST DATA MEASURED FROM B&W 6 FT x 6 FT AFBC UNIT FIRING OHIO
NO. 6 COAL WITH LOWELLVILLE LIMESTONE, SIZED <9510 ym (3/8 in. x Q)1'2'3
No.
l-l
1-1
1-2
1-2
1-2
1-2
1-1
1-1
l-l
1-4
(j) 1-4
VO
|_4 1-4
1-4
1-5
2-1
2-2
2-2
2-2
2-2
2-2
2-2
2-2
2-2
2-1
2-1
Dale
4-10-78
5-1-78
5-2-78
5-2-78
5-2-78
5-2-78
5-4-78
5-4-78
5-4-78
5-6-78
5-6-78
5-6-78
5-6-78
5-7-78
6-8-76
6-10-78
6-10-78
6-10-78
6-10-78
6-10-78
6-10-78
6-10-78
6-10-78
6-15-78
6-15-78
Bed
lesjpersture
°C (Of)
876
(1,609)
878
(1.612)
865
11,586)
869
(1.597)
871
(1,600)
874
(1,605)
872
(1,601)
867
(1,592)
867
(1.592)
849
(1.559)
852
(1.565)
866.3
(1.591)
855.6
(1.572)
872
(1.601)
869
(1,596)
839
(1,542)
845
(1,553)
844
(1,551)
845
(1,553)
842
(1,548)
846
(1,556)
845
(1,554)
845
(1,553)
841
(1,546)
841
(1,546)
Superficial
gas velocity
i/a (f/a)
2.42
(7.95)
2.50
(8.21)
2.33
(7.66)
2.55
(8.36)
2.18
(7.30)
2.50
(8.19)
2.56
18.19)
2.51
(8.29)
2.48
(1.14)
2.06
(6.75)
2.08
(6.87)
2.13
(6.98)
2.06
(6.74)
2.49
(8.15)
2.56
(8.19)
2.45
(8.02)
2.32
(7.61)
2.12
(7.61)
2.40
(7.88)
2.46
(8.06)
2.40
(7.86)
2.12
(7.60)
2.41
(7.98)
2.17
(7.11)
2.17
(7.11)
Bed Fu'1
'':>,?•. * tlL *"" Heating value
aec «-)/«* (»tu/lb)
1.13
(46.4)
1.21
(47.6)
1.42
(55.9)
1.42
(55.88)
1.44
(56.76)
1.42
(56.07)
1.24
(48.96)
1.21
(48.26)
1.27
(49.86)
0.85
(31.13)
0.85
(33.31)
0.80
(31.67)
0.82
(12.43)
.19
( 7.01)
.19
( 7.0)
.26
(49.53)
1.25
(49.07)
1.26
(49.5)
.26
( 9.6)
.21
( 7.75)
.20
( 7.19)
.23
(48.57)
1.23
(48.25)
1.22
(48.22)
1.22
(48.22)
0.47
0.48
0.61
0.56
0.61
0.57
0.48
0.49
0.51
0.41
0.41
0.18
0.40
0.48
0.46
0.51
0.54
0.54
0.53
0.49
0.50
0.51
0.51
0.56
0.56
28,907
(12,416)
28,907
(12,416)
J1.217
(11,430)
31.217
(1 ,430)
3 .242
(1 ,440)
3 ,242
(1 ,440)
2 ,970
(1 ,464)
1 ,464
(1 ,106)
1 ,46*
(1 ,106)
1 ,589
(13,590)
31.589
(13,590)
11,589
(11,590)
11.589
(13,590)
31,426
(11,520)
29,506
(12,694)
29,209
(12,566)
29,426
(12,660)
29,426
(12,660)
29,426
(12.660)
29.492
(12,690)
29,186
(12,556)
29,188
(12,556)
29,186
(12,556)
29,784
(12,818)
29,7(4
(12,138)
characterlstlca
t S
3.46
1.46
1.27
1.27
1.28
3.28
3.20
3.20
3.47
3.19
1.19
3.29
3.28
3.14
1.48
4.05
3.96
3.96
3.96
3.88
3.75
3.75
3.75
3.21
1.21
t Ash
7.29
7.29
6.83
6.83
6.84
6.84
8.18
8.18
8.82
5.93
5.91
6.83
6. SI
6.28
6.68
8.10
7.25
7.25
7.25
7.01
6.64
6.84
6.84
6.12
6.12
Feed rate
B/a (Ib/hr)
270.8
(2,149)
270.8
(2,149)
259.4
(2.059)
259.4
(2,059)
270.1
(2.144)
270.1
(2,144)
258.6
(2.052)
258.6
(2.052)
258.6
<2,052)
191.5
(1,536)
193.5
(1.516)
192.8
(1,5)0)
192.8
(1,5)0)
246.7
(1,958)
263.1
(2,090)
254.5
(2.020)
245.7
(1,950)
245.7
(1,950)
245.7
(1.950)
253.3
(2,010)
252.0
(2,000)
252.0
(2,000)
252.0
(2,000)
244.4
(1.940)
244.4
(1,940)
Sorbent
characterlatlcs
Feed t»te
g/» (Ib/hr)
136.1
(1,080)
116.1
(1,080)
117.5
(1,091)
117.5
(1,091)
117.5
(1,091)
117.5
(1,091)
125.5
(996)
125.5
(996)
125.5
(996)
102.1
(810)
102.1
(810)
96.4
(765)
96.4
(765)
117.8
(915)
81.9
(650)
84.4
(670)
89.5
(710)
89.5
(710)
89.5
(710)
101.1
(820)
91.24
(740)
91.24
(740)
93.24
(740)
0
(0)
0
(0)
c«Vs
ratio
4.22
4.22
4.80
4.80
4.51
4.51
4.59
4.06
4.59
4.50
4.50
4.46
4.46
4.20
2.69
2.44
2.78
2.78
2.78
3.20
2.95
2.95
2.95
0
0
pp«
167
174
90
90
111
126
118
115
115
156
161
140
110
181
700
891
588
564
604
774
676
6fll
627
1,495
1.495
ng/J < lb/10' Blu)
113.3
(0.31)
111.1
(0.11)
64.5
(0. 15
68.
(0.16
94.
(0.22
94.
(0.22
111.
(0.26
107.
(0.25
133.
(0.31
116.
(0.27
120.
(0.28
107.
(0.25
98.
(0.21
111.
(0.31
541.8
(1.26)
688
(1.60)
464
(1.08)
441
(1.01)
471
(1.10)
602
(1.40)
529
(1.21)
511.1
(1.24)
494.5
(1.15)
1,152.4
(2.68)
1,152.4
(2.68)
t SO;
reiention
94.4
94.3
96.fi
96.8
95.5
95.7
95.1
95.2
95.2
94.2
94.0
94.6
94.9
93.3
78.8
77.3
85.4
86.0
84.4
79.8
81.9
82.1
82.8
55.0'
55.0*
Esuationa
6/s
(Ib/hr)
70,8
(562)
70.8
(562)
81.1
(661)
83.1
(661)
81.3
(661)
83.1
(661)
49.0
(189)
49.0
(389)
49.0
(369)
49.2
(190)
49.2
(190)
49.2
(390)
49.2
(390)
54.8
(415)
69.9
(555)
64.4
(511)
68.4
(543)
(541)
(543)
77.1
(612)
(537)
67 7
(537)
67.7
(537)
(271)
34.1
(271)
characteriitica
ng/J (lb/106 Blu)
9,028
(21.0)
9,028
(21.0)
11.092
(25.8)
10,275
(23.9)
9,888
(23.0)
9.888
(23.0)
6,635
(15.2)
6.635
(15.2)
5,976
(13.9)
8,040
(18.7)
8,040
(18.7)
8,169
(19.0)
8.169
(19.0)
7,057
(16.4)
6.965
(20.9)
8,641
(20.1)
(22.0)
(22.0)
(22.0)
10,318
(24.0)
(21.4)
(21.4)
92200
(21.4)
(10.9)
4,686
(10.9)
S's
(Ib/hr) *
TO
(TO)
NR
(TO)
TO
(HR)
TO
(TO)
HR
(TO)
NR
(HR)
TO
(HR)
TO
(TO)
TO
(HR)
HR
(TO)
HR
(HR)
NR
(HR)
HR
(HR)
TO
(HR)
25.7
(170)
24.0
(159)
(163)
24.6
(163)
24.6
(161)
18.1
(252)
2A. a.
(162)
24.4
(162)
24.4
(162)
16. 3
(108)
16.3
(108)
!„ . .1 ,>'
eye lone out In )
g/J (lb/106 Blu)
NR
(HI)
NR
(NR)
NR
(HR)
TO
(TO)
HR
(HR)
NR
(HR)
NR
(NR)
NR
(NR)
NR
(HR)
HR
(m>
HR
(NR)
NR
(NR)
KR
(NR)
NR
(HR)
2,750
(6.4)
2,710
(6.1)
(6.6)
(6.6)
(6.6)
4,260
(9.9)
2 ,790
(«.5)
2.790
(6.5)
2,790
(6.5)
1,850
(4.1)
1,850
(4.1)
-------
TABLE 81 (continued)
u>
vO
NJ
Ifn I- Kan r
l-JA
<-JB
4-U
i-lB
t-K:
4- IK
,
i-K
--1H
4-11
--1 1
--1K
--1M
V 1".
,- ](>
--IP
J-JA
--JK
-- 1,\
4- If
Bed
°C <°F)
838
(1.541)
841
(1.545)
847
(1,556)
847
(1.556)
849
(1,560)
487
(1.557)
H47
(1.554)
(1.558)
H46
U.555)
8*6
(1.554)
851
(1,561)
850
• 1. 563)
84 B
I 1 .351)
* 17
( ! ,11*0
83i
1 ] , 3 | - )
HI 3
ll.il-.)
S )*.
1 1 , > r
H 1,
1 1 , '. M i
-^^
i ) ,^-i )
tt*-
M ,6- "1
S<*fi
! 1 .*>-.-!
f'-',
I 1 , V) .' )
( 1 . 5SM
8*7
( 1 , iSM
Superficial
m/s (f/s)
2.69
(8.8)
2.61
(8.62)
2.5
( a . 3 )
2.5
(8.2)
2.7
(8.8)
2. 5
(8. 3)
2.6
(8.6)
(8.5)
2.6
(8.5)
2.6
(8.5)
2.6
(8.6)
2.6
(8.6)
2. S
(8.1)
2.6
{S.5I
J.5
(8.3)
2.^
18. i)
2. '
• rt. 'M
J.t-
( 8 . : )
( *.*)
: . h
'«.->)
.'.ft
i*. i)
:. -
' -.*!
-^1
i - . . )
Bed Ga> residence Fuel ch*™cter
• (In.)
1.21
(47.7)
1.22
(48.2)
1.2
(47.7)
1.2
(47.6)
1. 1
(45.2)
1 . 2
(47. h)
1.2
(47.9)
(47.;)
1.2
(46.8)
1.2
(48.0)
1.2
(46.2)
1.2
(46,6)
1.2
(47. J)
1.2
(49.0)
1 . t
(49. 5>
i.:
(-8.0)
! . J
(49. 2
O.i6
0.48
0.-6
J. JO
0. 10
0.30
0.44
0.4fl
- . ..
Heating value
kJ/kg (Biu/'b)
29,508
(12,686)
29.508
(12.6R6)
29,894
(12,852)
29,894
(12,852)
29,894
(12.852)
29 722
(12,778)
29,722
(12.778)
(12,786)
29.740
(12,786)
29.740
(12,786)
29,663
(12,753)
29,663
(12,753)
29.663
(12,753)
29,117
(12,518)
29,117
(12,518)
29, 1 1 7
(12,5181
29,117
(12, SIS)
2 ,117
(1 ,518)
2 ,194
(1 ,551)
2 ,194
(1 .551
2 ,194
(1 ,551)
2 ,324
(1 ,607)
(12,607)
29,324
(12.607)
Z S
4.54
4,54
3.69
3.69
3.69
3 77
3.77
3.69
3.69
3.87
3.87
3.87
3.65
1.65
3.65
1.65
3.65
4.24
4.24
4.24
4.22
4.22
X N
1.23
1.23
1.13
1.13
1.13
1.13
1.13
1.13
1.13
1.23
! .23
1.23
1.22
1.22
1.22
1.22
1.22
1.13
1.13
1.13
1.22
1.22
Is tics
X Aah
6.62
6.62
6.05
6.05
6.05
6.13
6.24
6.24
6.32
6.32
6.32
7.50
7.50
7.50
7.50
7.50
7.64
7.64
7.64
6.57
6.57
characteristics
Teed rate
R/B (lb/hr)
248
(1,965)
248
(1,965)
243
(1,928)
242
(1,921)
241
(1,932)
(1,918)
246
(1.956)
(1,910)
245
(1.947)
243
(1,926)
238
(1,886)
240
(l.Mi)
247
(1,961)
227
(1.801)
229
(1,818)
233
(1.851)
233
(1,850)
234
(1.860)
223
(1,773)
225
(1.783)
225
(1,782)
251
(1,990)
(1.891)
235
(1,866)
Feed rate
g/a (lb/hr)
72
(575)
77
(610)
81
(640)
81
(640)
81
(640)
(640)
81
(640)
81
(640)
81
(640)
81
(640)
81
(640)
81
(640)
81
(640)
68
(540)
68
(540)
68
(540)
68
(540)
68
(540)
78
(620)
78
(620)
78
(620)
83
(660)
(660)
83
(660)
Ca/S
ratio
1.87
1.98
2.64
2.65
2.63
2.58
2.65
2.63
2.66
2.61
2.58
J.51
2.47
2.15
2.40
2.40
2.39
2.43
2.U
2.42
2.31
2.46
PPW
962
1,0*1
785
785
751
749
806
826
713
706
748
767
917
982
1,070
1.115
1,067
1.454
1.457
1,502
938
857
SO;
(16/10* Btu)
770
(1.79)
838
(1.95)
580
(1.35)
572
(1.33)
589
(1.37)
(1-34)
592
(1.33)
615
(1.43)
623
(1.45)
5^.2
(1-26)
559
(1.30)
585
(1.36)
563
(1.31)
770
(1-79)
791
(1.84)
877
(2.04)
950
(2.21)
860
(2.00)
1.178
(2.74)
1.152
(2.68)
1,169
(2.72)
772
(1.68)
(1.39)
636
(1.48)
Emission characteristics
SO, Partlculate
S02
retention
76.30
75.03
76.40
76.79
76.17
77 . 35
77.38
75.17
74.83
78.07
78.54
77.60
78.37
69.36
68.36
65.06
62.09
65.68
59.47
60.30
59.65
74.90
"
77.8*
pp" (lb/106 Btu)
-
-
-
-
-
-
-
-
-
-
-
-
202 116
(0.27)
214 120
(0. 8)
198 1 2
(0. 6)
20" 1 2
(0. 6)
20* 107
(0,25)
208 112
(0,26)
Cyclone itilet
ng/J (lb/106 Btu)
18,904
(43.97)
18,904
(43.97)
12,451
(28.86)
12.451
(28.96)
12,382
(28.80)
12 541
(29.17)
12,300
(28.61)
(28!97)
12.347
(28.72)
12,481
(29.03)
12,782
(29.73)
12.653
(29.43)
12,291
(28.59)
9,709
(22.58)
9.617
(22.37)
9,445
(21.97)
9.450
(21.98)
9.398
(21.86)
10,374
(24.13)
10.318
(24.00)
10,322
(24.01)
9,136
(21.25)
9611
9,742
(22.66)
Cyclone outlet
ng/J (lb/106 Btu)
3,224
(7.50)
3,224
(7.50)
6,21*
(14. 5?)
6,285
(14.62)
6.2*3
(141S4)
6, 333
(14.73)
6,208
(14.44)
(14.63)
6,234
(14.50)
6,303
(14.66)
6,453
(15. 01)
6.389
(14.86)
6,210
(K.44)
3,341
(7.98)
3,401
(7.91)
3,340
(7.77)
3,340
(7.77)
3,323
(7.73)
3.1*7
(7. 2)
3, 30
(7. fl)
3, 34
( • ">)
,203
( -45)
. 371
( .84)
3.418
(7.95)
-------
VO
TABLE 81 (continued)
Ho.
4- JO
4-3E
5-1A
5-18
5-l.C
5-lt
5-lt
5-2«
5-!>
5-2C
5-20
5-2E
5-2F
5-3*
5-38
5-3C
6-IA
6-38
6-1 C
6-3 D
6-1E
6-1F
«-IG
Bed SuMrflcial ted C*m retldaac*
teaperiture
«c (*r>
847
(1.558)
849
(1.560)
847
(1.356)
851
(1.564)
852
(1.565)
848
(1.558)-
832
(1.565)
843
(1,550)
845
11.554)
861
(1.583)
847
(1.557)
•36
(1.537)
635
(1.534)
aw
(1,648)
(1,646)
899
(1,650)
845
(1,532)
83O
(1.562)
849
(1,5*0)
849
(1,560)
853
(1.567)
633
(1.567)
851
(1.563)
8** velocity Q*pcn
«/« (fit) m (In.)
2.5
(8.1)
2.5
(8.2)
2.5
(8.2)
7.6
(8.4)
2.6
(8.51
2.6
(6.5)
2.5
(8.3)
2.6
<8.«)
2.6
(8.6)
2.6
(8.6)
2.6
(•.6)
2.6
(6.4)
2.6
(8.4)
!.9
(9.6)
3.1
(10.0)
3.0
(9.9)
2.5
(8.1)
2.5
(8.2)
2.5
(8.1)
2.3
(8.1)
2.6
(8.6)
2.6
(8.4)
2.6
(8.4)
1.2
us.n
1.2
(46.5)
1.2
(47.7)
1.2
(48.9
1.2
(46.5)
1.2
(47.2)
1.2
(47. D)
1.2
(47.7)
1.2
(47.1)
1.2
(46.5)
1.3
(49.8)
1.3
(49.3)
l.J
(47.3)
l.J
(47.2)
1.2
(46. 81
1.2
(46.1)
1.2
(48.8)
1.2
(47.8)
1.3
(50.1)
1.2
(48.3)
l.J
(47.3)
I.I
(47.7
1.2
(47.9)
tlmt
*ec
0.48
-
0.48
0.48
0.46
0.46
0.46
d.tt
0. 46
0.46
0.46
0.50
0.46
D.46
0.41
0.40
0.40
0.48
0.48
0.52
0.48
0.46
0.46
0.46
>uel the
Heating valve _ _
u/ka. (in/lb) *
29, 1*8
(12.540)
29.1*8
(11,540)
29. 368
(12.626)
29,368
(12.626)
29,368
(12,626)
29,368
(12,626)
29,368
(12.626)
28,967
(12,4«2>
28,987
(12,462)
28.987
(12,462)
29,013
(12,474)
29,013
(12,474)
29,015
(12,474)
18.791
(12.378)
28,791
(12,378)
28.791
(12,378)
2S.76*
(12.368)
28,76*
(12,368)
28. 7M
(12,368)
28,768
(12,368)
29,112
(11,516)
29,112
(12,516)
29,112
(12.516)
4.14
4.14
3.89
3.89
3.89
3.69
3.69
3.94
3.94
3.94
3.83
3.83
3.85
4.U
4.12
«.12
4.22
4.12
4.22
4.22
4.02
4.02
4.02
raeterittlc*
I 1C
1.22
1.22
1.14
1.14
1.14
1.14
1.14
1.22
1.22
1.22
1.03
1.03
1.03
1.11
1.12
I.It
1.22
1.21
1.22
1.22
1.31
1.31
1.31
I Art
7.14
7.14
7.51
7.51
7.51
7.51
1.51
7.31
7.31
7.31
7.24
7.24
7.24
7.66
7.68
7.68
8.15
8.13
t.Ii
8.15
6.82
«.82
6.82
F*«d rat*
I/e (Ib/hr)
2)5
(1.868)
236
(l.»76)
225
(1.784)
223
(1.768)
J15
(1,765)
222
(1.762)
IZ2
C1.765)
229
(1,814)
232
(1,»42>
234
(1,860)
248
(1,970)
233
(1,848)
228
(1.813)
256
(2.033)
259
(2.058)
245
(2.105)
244
(1.940)
246
(1.934)
248
(1.971)
243
(1.944)
237
(1,679)
240
(1.906)
238
(1.889)
Sorbent
«h*racterl*tlc*
reed rate CeVS
lit (Ib'hr) ratio
»3
(660)
83
(660)
94
(750)
94
(750)
94
(750)
94
(750)
94
(750)
101
(800)
101
(8
63.61
49.25
86.87
87.73
87.94
67.72
63.42
86.90
84.54
PP«
200
218
-
-
241
154
266
306
-
-
-
-
258
-
-
-
275
275
290
290
190
290
300
•».
0./J
(IV 10> Sta)
112
(0.26)
77
(0.18)
-
-
150
(0.35)
159
<0.)7)
163
<0.38)
165
<0.43)
-
-
-
-
150
(0.35)
_
-
-
95
(0.22)
99
(0.23)
99
(0.23)
101
(0.24)
111
(0.24)
107
07.25)
116
W.27)
r«rt
Cyclone inlet
n,/J db/10' Itu)
9,781
(22.75)
9,742
(2!. 6*)
10.135
(23.62)
10,245
(23.63)
10.150
(23.61)
10,275
(23.91)
10,262
(23.87)
10,060
(23.40)
9,910
(23.05)
9.611
(22.82)
8,134
(18.92)
6,672
(20.17)
8,839
(20.56)
9,129
(21.70)
9,213
(21.43)
9,011
(J0.96)
8.422
(19.59)
8.362
(19. »5)
8,829
(19.18)
8,405
(19.55)
7,807
(18.16)
7,696
(17. «0)
8.057
(M.W)
culat*
Cyclone outlet
n«/J Ub/10' 9tu)
3.431
(7.9«)
3,418
(7.95)
2,042
(4.75)
,059
( .79)
,042
( .75)
.068
< .81)
.064
( .SO)
,367
(3. 16)
1,350
(3.14)
1,337
(3.10)
770
(1.79)
821
(1.91)
838
(1.95)
2,205
(5.13)
2.17S
(5.06)
2.128
(4.95)
2,184
(5.08)
2.171
(5.05)
2,150
(5.00)
2,180
(5.07)
1,664
(3.87)
1,638
(J.M)
1,948
(4.53)
-------
TABLE 81 (continued)
vO
oed
£" te.per.tur.
6-1H
6-11
6-U
6-1K
6-11
6- IK
6-1S
6-1O
6-1P
6-2*
6-2 B
6-2C
b-2D
6-2E
6-2F
6-K
6-2M
6-21
6-211
6-JL
6-2M
6-2K
'.9
(1.561)
84-
< l.V>!)
R45
< 1 .552)
P4fc
(1,554)
8.1
(1 ,547)
942
(1,548)
84?
(1,5481
641
(1.545)
638
(1,540)
848
(1,559)
846
(1,558)
848
(1.559)
849
(1,558)
845
(1.5S3>
844
(1.551)
84}
(l,5iP)
84k
(1.555)
S46
U.5S5)
(1.5S5)
847
(1.556)
845
(1.552)
(1.5S6)
847
(1.556)
2.0
[S.5>
2.4
(B.O)
2.5
(8.0)
2. 5
(S.I!
2.3
(7.5)
2. 1
(7.4)
2. 3
( .6)
.3
( .6)
.3
( - )
2.
7. )
2.
(7. )
2.
(7. )
2.
(7. )
J.I
(7.4)
2.1
(7.5)
2.2
(7.2)
2.3
(7.4)
2.2
7.1)
(7.2)
2.3
(7.5)
.1
< .11
( .11
.5
(8.2)
X
1.2
(47 .<»
1.2
(48. n
1 .1
(4S.1)
1 .2
<4S.fc)
1.2
(47.6)
1.2
(4H.9)
1.2
(47.81
1.2
(47.5)
1.2
(48.9)
1,2
(48.4)
1.3
(49,2)
1.3
(49.3)
1.2
(47.5)
1.2
(47.8)
1.2
(47.6)
1.2
(47.4)
1.2
<48.2)
1.2
(47.5)
(47.2)
1.2
(46.9)
1.2
(47.2)
1.2
1.2
(47.6)
0.46
il.4*.
I). -.H
0.4«
0.52
0.52
0.52
0.52
0.52
0.52
0.57
0.54
0.55
0.52
0. 52
0. 55
0.52
0.55
"
0.52
0.52
0.1*
29,112
(12,516)
29,324
(U.607)
29.124
(12.607)
29.324
(12.607)
29. BIO
(17 ,!«M)
29.' 5M
(12.698)
4.22
4.22
4.22
3.25
3.25
3. i5
3.25
3.25
1.70
1.70
1.70
2.53
2.51
2.5]
2.53
2.53
2.27
2.27
2.27
2. 5B
2.58
1.2!
1.22
1.2!
1.24
1.24
1.24
1.24
1.24
1.32
1.32
1.32
1.31
1.31
1 .31
1. )1
1.31
1.32
'
1.32
l.M
1.34
7.12
7.32
7. 32
8.02
8.02
8.02
8.02
8.02
9.16
9.36
9.36
B.«2
8.82
8.82
8.82
8.B2
8.14
'
1.11
1.11
9. 15
9.35
238
(1,886)
239
(1.894)
210
(1,908)
242
(1.929)
224
(1,774)
222
(1.759)
221
(1,77*>
224
(1.778)
22}
( 1,769)
213
(1,152)
234
(1,857)
231
(1.858)
202
(1.601)
231
(1,834)
2)8
(1.890
210
(1.825)
210
(1.123)
211
11.851)
(1,173)
215
(1,166)
215
(1,8631
218
249
(1,974)
Sorbent
Feed rate Ca/S
a/a {Ib'hr) ratio
101
(Mil)
117
(931)
11)
(926)
115
(915)
64
(508)
61
(486)
61
(483)
66
(5J4)
60
(478)
66
(521)
66
(527)
66
(520)
51
(405)
46
(366)
74
(589)
51
(429)
51
(410)
50
(393)
(191)
44
(353)
50
(4V»
57
<1M>
3.20
3.37
3.33
).2S
2.68
2.58
2.55
2.75
2.53
1.70
1.74
4.67
7..W
2.34
3.67
2.77
2.72
2.73
I. 70
2.44
i.72
2.62
""2
pp* (lb/106 Bti»)
511
689
649
749
608
552
574
600
606
200
204
194
101
123
111
163
320
198
"
179
367
546
426
(0.99)
537
(1,25)
507
(1.18)
580
(1.15)
469
(J.09(
421
(0.98)
447
(1.01)
46S
(1.09)
477
(1.11)
150
(0.3S)
155
(0.16)
112
(0.33)
25»
(0.39)
241
(0.56)
241
(0.54)
267
10.62)
216
(0.5SI
284
(0.66)
281
275
(0.64)
154
(O.S9)
10. U)
401
(0.95)
EMlealon Characterlatlca
^ Paniculate
SO,
retention
84.59
81.24
82.35
79.77
78.57
80.59
79.56
78.52
78.00
86.97
86.61
67.81
65.47
86.15
86. 18
84.7!
86.24
81.45
11.0
81.96
11.12
71 79
76.70
«-
300
270
270
270
285
285
215
285
285
430
430
410
150
150
350
350
350
320
320
120
290
290
nvx
»8/J
Ub/101 >tu)
116
(0.27)
99
(0.21)
99
(0.23)
99
(0.23)
103
(0.24)
103
(0.24)
103
(0.21)
103
(0.24)
107
(0.25)
150
(0.35)
155
(0.161
155
(0.16)
118
(0.32)
120
(0.28)
120
(0.28)
120
10.28)
120
(0.28)
107
(0.25)
303
(0.21)
107
(0.25)
103
(0.24)
(0.23)
10]
(0.24)
Cyclone Inlet
ng/J (lb'106 Btu)
8.070
(It. 77)
7.906
(18.39)
7,846
(18.25)
7,825
(18.20)
h.561
(15.26)
*,616
(15.39)
6.561
(15.26)
6.548
(15.23)
6.582
(15.11)
8,131
(18.92)
8,113
(18.87)
8.108
(18.86)
8,392
(19.52)
7,326
(17.04)
7,111
(16.54)
7.365
(17.13)
7.373
(17.15)
7.831
(18.22)
(18-04)
7,702
(11.10)
7,794
(11.11)
1 398
119.51)
1,1(1
(19.31)
Cyclone outlet
tuj/J (lb'106 Btu)
1.941
(4.53)
(
(
(
f
(
1
(
i
(
(
C
(
.943
.52)
.930
.49)
,926
.48)
,702
.96)
.715
.99)
,702
.96)
,698
.95)
,707
97)
.515
85>
5O6
831
50<
81)
313
38)
021
70)
9frl
(4.56)
2.029
(4 72)
2.029
(1.72)
2.198
(5.81)
(5.'75)
1 .181
(5.77)
2,185
(5.78)
3,216
(7.55)
3,212
(7.51)
-------
TABLE 81 (continued)
vo
Teat
No.
6-20
6-2r
6-2Q
6-3*
fr-X
6-30
6-3E
6-3F
6-3C
6-3H
6-3t
6-1J
Bed Superficial
•c (°r> ,/,
844
(1,552)
848
(1,549)
849
(1.5*0)
848
(1.558)
(1,564)
850
(1.562)
850
(1.5(2)
852
(1,565
853
(1.567
845
(1,552)
844
844
(1.551)
843
(1,550)
"lr teck»an «utoauMe
2.5
(8.1)
2-1
(7.6)
2.3
(7.4)
2.9
(9.5)
(9.4)
2.8
(9.3)
2.9
(9.6)
2.8
(9.2)
2.9
(9.4)
2.8
(9.0)
2.8
2.7
(8.9)
2.8
(9.0)
lafrared *
Bed Gas residence
depth ttmf
1.2
(47.6)
1.2
(47.5)
1.2
(48.4)
1.2
(47.4)
(4«.2)
1.3
(50.1)
1.2
(48.5)
1.2
(48.9)
1.2
(48.1)
1.2
(47. B)
1. 2
(47.8)
1.2
(48.9)
1.2
(47.4)
ntalrcer.
Fuel characteristics
0.48
0.52
0.52
0.41
'
0.46
0.41
0.43
0.41
0.43
0.43
0.44
0.43
29.536
(12.698)
29.516
(12.699)
29.536
(12,698)
29,743
(12,787)
(12|7B7)
29,743
(12,787)
29.743
(12.787)
29.743
(12.787)
29,743
(12,787)
29, 770
(12.799)
29,770
(12,799)
29,770
(12,799)
29.770
(12,799)
2.58
2.58
2.58
2.37
2.87
2.87
2.87
2.87
2.18
2.L8
2.18
2.18
1.34 9.35
1 . 14 9.15
1.34 9.35
1.24 S.50
1.24 8.50
1.24 8.50
1.24 8.50
1.24 8.50
1.23 8.04
1.23 8.04
1.23 8.04
1.23 8.04
248
(1.966)
246
(1,954)
249
(1,977)
248
(1,966)
(1,967)
246
(1,956)
248
(1,969)
248
(1,967)
245
(1,944)
253
(2,006)
254
(2.014)
252
(2.000)
252
(2,003)
char.ct.rl.t1c. ^
g/s Ub/hr) ratio ppv,
s?
(451)
58
(463)
57
(450)
56
(442)
(455)
55
(437)
58
(461)
58
(462)
58
(461)
60
(478)
58
(464)
59
59
(470)
2.61
2.69
2.59
2.28
2. 35
2.27
2.38
2.38
2.40
3.03
2.96
3.01
3.01
509
583
603
551
498
»0
675
671
282
309
299
305
db/10' Btu)
378
(0.88)
404
(0.94)
400
(0.93)
470
(1.09)
516
(1.20)
417
(0.97)
426
(0.99)
546
(1.27)
563
(1.31)
224
(0.52)
(0.57)
236
(0.55)
245
(0.57)
,.,S<0,
78.29
76.11
77.10
75.72
73.21
78.35
77. «J
71.58
70.73
84.75
83.92
83.19
PP"
290
290
290
370
370
370
370
370
375
375
375
HO,
(lb/10* Btu)
103
(0.24)
95
(0.22)
90
(0.21)
146
(0.34)
(0.34)
146
(0.34)
146
(O.M)
142
(0.33)
146
(0.34)
1J8
(0.32)
(0.33)
138
(0.32)
142
(0.33)
Partlcul.te
Cyclone Inlet
ng/J Ub/106 Btu)
8.422
(19.59)
8.474
(19.71)
8,175
(19.48)
9,162
(21.32)
(21.31)
9,213
(21.43)
9,153
(21.29)
9,162
( 1.31)
.121
( 1.56)
,377
( 1.81)
( 1.72)
,407
(21.88)
9.389
(21.84)
Cyclone outlet
n«/J (lb/106 Btu)
3.255
(7.57)
1.276
(7.62)
3,237
(7.53)
3.727
(8.67)
(a!67)
3,749
(8.72)
3.721
(0.66)
3,727
(8.67)
3.770
(8.71)
3.614
(8.41)
3,603
(8.38)
3.629
(8.44)
3.624
(8.43)
-------
vO
TABLE 82. EMISSION TEST DATA MEASURED DURING OPERATION OF B&W 3 FT * 3 FT FBC
UNIT FIRING PITTSBURGH NO, 8 COAL4
19
20
21
22
it
25
26
27
28
19
1O
31
32
Jt
17
Tc*t
(hr)
10/16/76 10.0
lO/K/76 9.0
10/21/76 6.0
10/21/76 8.0
10/24/76
10/26/T6 7.0
ll/OI/7b 7.0
11/09/74 10.0
lt/IO/76 8.0
11/11/76 7. i
11/1I/T6 B.O
11/11/7* i. 5
11/16/76 8.5
12/09/76 4.5
12/10/'6 4.5
**d
(1559)
850
(1562)
894
(1642)
8)9
(1542)
(1426)
ft)B
(1541)
TJQ
(1418)
829
(1S2S)
842
(1548)
85B
l\516>
845
(1553)
• 50
(1562)
819
(ISO*)
(1518)
(1551)
(1553)
819
(1507)
851
(1563)
Superficial
!•• velocity
•/• (f/.)
2.56
1.57
(8.41)
2.56
(8.39)
3.57
(8.42)
(8.05)
3.6)
(11.91)
l,*0
(4.60)
2.49
(8.16)
2.52
(8.28)
2.58
(8.45)
2.5*
(•-34)
Z.5*
(8.34)
2.48
(8.13)
(•:»>
(•.22)
'8.501
1-55
(5.M)
2.57
(•.44)
***
• (in.)
0.47
U8.4)
0.50
(19.7)
0.4)
(17.1)
0.51
(20.2)
(23.1)
O.frl
(24.6)
0.87
(34,4)
0.42
(16.5)
0.42
(16.5)
0.42
lib. 5)
0.43
(17.1)
0.*)
(16.9)
0.40
(15.8)
(16.4)
(16.4)
(16.2)
0.29
(11.4)
O.J*
(13.1)
c*»
residence
(£>
0.20
0.17
0.20
0.17
Q-W
0.17
0-17
0.16
0-17
0.17
0.16
0. V6
0.19
0. u
•**t v«lu«
U/k*
(•tu/lk)
(U.M4)
19,275
(12,5*4)
29,175
(12. 5*6)
29,275
(12,5*6)
(12,629)
29,175
(12,629)
29.115
(12^629)
29,4*4
(12.676)
29.4*4
(12,674)
29.484
(12.676)
29,4*4
(11,676)
29.4*4
(12,676)
29,4*4
(12.676)
(12^676)
(12.676)
19,48*
(12,676)
19,48*
(11,674)
29.484
(11,476)
X 6 I A»h
3.04 9.32
3.04 9.31
3.04 9.32
2.86 9.43
2.«6 9.4)
2.84 9.4)
2.*6 9.41
2.86 9.43
2.86 9.43
2.86 9.41
2.*4 9.41
2.84 9.4i
1.86 9.4)
2.86 9.41
1
t •
0.86
0.86
0.86
0.86
0.84
0.76
0.76
0.76
0.76
0.76
0.76
0.7*
0.76
0. 76
.
(Ik/k)
(500)
227
(500)
193
(421)
209
(440)
(490)
344
(758)
113
(247)
111
(464)
209
(**0)
218
(4*0)
200
(4*0)
20*
(*50)
222
(490)
(4*0)
(440)
1W
(460>
1(4
(140)
245
(5*0)
(it
ill* 23*0
(1
LoMllvill* 23*0
(•
LMMlUilU 23*0
(8
Lowellvill* 1000
(16
(16
(16
L~.1U.IU **'
L0wll*ilU P«l
Lava 11* ill* Ml
>. or M)
it. » 0)
Mm " 0
im. « 0)
urn » 0
i*. - 0)
M » 0
in. > 0)
10. • 0)
urn * 0
IB • 0)
M * 0
ia. • 0)
\M * 0
•Mb . 0)
MB « 0
•Mh • 0)
M * 0
•Mb • 0)
m * 0
•M* • 0)
urn > 0
«* • 0)
M t 0
•MM • 0)
M*b M Q)
•Mb • 0)
L"""-
mii+4
v«riB*d
(Ib/k) r-lio
(110)
25 0.5*
(54)
43 1.5)
(9*. I)
44 1.49
(102)
(102)
72 l.*l
(159)
1) 1,7)
(51.5)
44 1.16
(94.4)
43 1.11
(95)
U 3.51
uw»
21 1.11
(47)
21 1.11
(47)
** 1.4*
(9*)
(145)
(45)
(1*0)
*5 1.25
(100)
49 1.38
(107)
Flu* •••
•t H8 inUt
k(/k
(U/h)
1,8*4
<*.m)
l.M)
(6,144)
2,137
(4,154)
2,893
(6.377)
(4.542)
4,043
(8.95*;
1.4*7
(3,741)
1,*44
(6,269)
2,*4*
(6.331)
1. 192
it.y)*)
2,876
(4,341)
2.8*1
(4.30*)
2,849
(4,313)
(6,H7)
(6! 261)
1,90*
(6,411)
1,*02
(1,972)
2,«74
(6,341)
•-• ,
•39
1.473
1,114
1.107
1.403
1.165
• 79
•49
5*9
1,143
1,501
1.01!
***
930
•9S
•Oz « US !•
!«#'«-•
400
(0.93)
494
(1.62)
62*
(1.46)
5*0
(1.35)
1,4*5
(3.92)
1.251
(2.91)
1.445
(3.36)
•90
(2.07)
877
(2.0*)
585
(1.34)
1,13*
(l.M)
1,5*1
(3.6*)
1.004
(2.34)
(1.S5)
1,522
(1.48)
1,0*0
(2.42)
• 16
(1.90)
791
(l.M)
il*t
1
40.*
24-5
37.9
41.9
11.4
41.1
37. »
58.7
40.8
74.6
39.2
12.)
58.1
*5.9
61.0
59. J
iona eh*r«ct*ri«tici
*>.
283
211
334
215
)OO
213
54
21)
2»
322
2'3
303
!>•
263
144
196
(9*
•t WS inl«t1
(IWIO* Uwl
99
(0.23.)
7)
(O.U)
1)3
(0.31)
82
(0.19)
219
(0.51)
138
(0.32)
4T
(O.U)
155
(0.)6>
211
(0.49)
221
(0.51)
181
(0.42)
221
(0.53)
148
(0.39)
(0)
(0.45)
1*5
(0.43)
1*5
(0.43)
12)
(0.29)
Part'
« «
) ((T/ftCf)
7.4
(3.3)
7.4
(3,1)
7.4
(3.3)
(.0
(3.5)
8.9
(3.9)
7.8
(1.4)
S.i
(2.1)
8.9
(1.9)
*.9
(3.9)
9.8
(k.3)
7.8
().*}
7.3
(1.2)
1O.5
(4.4)
(*.**)
O.J)
(*'*)
14.5
(7.J)
14.7
(7.))
culat*
l.l«*
(lh/W* lt»)*
1,494
2.6*3
(6.24)
1,057
(7.11)
1,154
(7.34)
3,175
(7.13)
1,405
(6.04)
1,15)
(5.24)
3,315
(7.71)
3.461
(8.05)
3.489
(8-58)
3.14*
(7.34)
2,8T*
(6.14)
4.0*4
(9.50)
(8.44)
(7.14)
m 4i)
5,414
(11.44)
5.JJ7
(12 H)
-------
TABLE 82 (continued)
w
c*-
]£** tot* Aunt i«a t«.»»*»t«r« M* wlvcitT .top* "^J^*"
M
40
41
42
A3
^4
44
47
4*
50
51
12/1J/7*
12/14/74
12/17/74
01/11/77
Ojy 12/77
OL/U/I7
Ol/H/77
Oj/lO/11
01/Z1/77
01/14/77
02/07/77
%T Outamt H04.il
4
•Oa
t«MOV>jl «ff
7.0 MS
(IHfl
».i 13*
(1S2S1
U.J K5
(1551)
l.« 042
(1547)
»-0 Ml
(1544)
5.1 Ml
C1&44)
1 . J (41
(1UI)
1 .0 HI
(15M)
4.0 *M
(1540)
(1541)
4.0 MO
(1544)
(1SS4)
4.0 117
(15»)
411, W lifht •bftorttie*
cU-clM.
2.4*
1.40
(8.54)
2,42
2.5S
(•.44)
(1.40)
2.44
(1.44)
(M<>
0.4) «.14
(17.1)
0.11 0.21
(U.I)
0.17 0.14
(14.9)
0.4S 0.17
(17.4)
O. 44 0.17
(17.2)
0.44 0,17
(17. 5>
0.4if 0.1*
(U.l>
0.45 0.11
(17.9)
0.43 0.14
(l«.»)
°'W
0.41 0.17
(17,1)
<14.»
O.M 0.13
U4.0)
PI
* tooU •*!•*
7t)
»,4M
(Il,i7|)
19. 15
(1>, 17)
(1>! 11>
21, 13
(13, 17)
1*, 1)
(13. 17)
(Si 517)
2*. 115
(U.M7)
(1X.S17)
2* lit
(lOW
• •! pri«*C7
.1 d-r«,«
1.04 9.43
1.04 9.43
I.M 9.41
1.01 9.41
2.04 9.43
3.12 9.74
3.12 9.74
3.12 9.74
3.12 9.74
3.12 9.74
LMlc* 9aifc4«t etenewriitic* riM ^^
{ g
0.71
0.74
0.74
0.74
0.74
1.1)
1.13
1.13
1.23
1.13
>«4* r.l. llM Wnt r«. ** * tal"
(l»/k)
24*
<31O)
114
<293)
n;
(500)
134
2)4
(319)
244
(9)9)
211
(490)
214
(494)
2»
(419)
(900)
113
(494)
(3«7>
111
(490)
(i«. ~ M (ttrt) *""• "**'
C4(01>s 44
(313
C.(01)1 44
(32!
C*(0»i 44
(J13
LMMllwill* 1300
(I
LMMllvillB 1000
(14
tOlMllTJUl I>«
' (329
(t
Cc«r 1000
M « 0
•••fe « D)
1- • 0
•4rt • »
NB - 0
•Mt ' 0)
M » 0
..*• 0)
M • 0
•4* • 0)
tr«ris«4
»Mi < 0)
wk • 0)
W « 0
<14 .U4 . 0)
cr^« 2)00
(•
Oror* 1000
(14
Grvrc rwl
«. • 0
M>k > 0)
m « 0
MB4. - 0>
VVTJM41
49
(107>
19
<41)
31
<497
79
(17))
79
(17))
91
(103)
(40)
, (179)
114
(1M)
(»')
104
(110)
113
(Z90>
11)
(290)
2. It
l.H
1.4*
3.34
3.33
2.74
3.M
4.43
4.9)
).99
1,919
(4t4J*)
1,711
(3,793)
1,903
(4,401)
3,011
(1,444)
3,01)
(4,4U)
3.014
(1.443)
(4.319)
(1,943)
1,99!
(4,)I4)
2 99)
2,937
(1,473)
2,944
),003
(4,413)
9W*
»7
)U
404
790
0»
079
401
MO
934
447
749
OOl « « ii
(1W10* tt,}
333
(0.02)
307
(1.10)
444
(1.0t>
735
(1.71)
134
(1.94)
013
(1.91)
(1.99)
(0.94)
191
1 140
533
(1.14)
440
(1.07)
745
U.tll
.,,..
ue
>
70.1
73.1
73.4
40.3
44.1
94.9
11.)
•3.0
77.4
tl.l
19.1
,-.«.
r«»ri., .CM i4i.t» ;r«"i.i«'
t »9»
199
11]
M9
11*
340
224
340
191
307
309
2M
<1»/10» 11.
129
(0.30)
119
(0.51)
109
(0.43)
114
(0.32)
134
(0.5)1
150
(0.13)
(0.44)
(0.41)
219
(0.51)
(0 41)
119
(0.51)
219
150
(0.33)
, <«!£„
11.0
(9.1)
19.7
(0.4)
11.3
(1.1)
10.1
(4.4)
11.4
(3.0)
11.1
(9.7)
":?)
(4!))
9.4
(4.1)
I™!))
9.2
(4.0)
9.4
39.4
(17.2)
(U/10* •(•)*
4,433
(19.01)
7,145
(14.11)
4,490
(15.50)
)P447
<0.53)
1,170
<9.70)
7,129
IK. 20)
(11.54)
(t-4»>
3,437
(0.44)
(24.71)
3.300
(0.14)
),457
(0.04)
19,219
()9.)9)
r~r«l« lto«U
-------
TABLE 83. EMISSION SOURCE TEST DATA: NCB-CRE 3 FT x 1,5 FT ATMOSPHERIC FBC5'6
Test
no .
1.1
1.2
Datum
Datum
1.3
1.4
1.5
1.6
CO 1.7
VO
00
1.8
1.9
1.10
1.11
3.1
3.2
3.3
3.4
3.5
3.6
Da tun
Bed
temperature
°C (°F)
799
(1470)
799
(1470)
849
(1560)
799
(1470)
799
(1470)
749
(1380)
849
(1560)
849
(1560)
849
(1560)
849
(1560)
849
(1560)
799
(1470)
799
(1470)
849
(1560)
849
(1560)
849
(1560)
849
(1560)
849
(1560)
849
(1560)
849
(1560)
Gas
velocity
Ws
(ft/s)
1.2
(4.0)
1.2
(4.0)
1.2
(4.0)
0.91
(3.0)
1.2
(4.0)
1.2
(4.0)
1.2
(4.0)
1.2
(4.0)
1.2
(4.0)
1.2
(4.0)
1.2
(4.0)
0.91
(3.0)
0.94
(3.1)
2.4
(7.9)
2.4
(8.0)
2.4
(8.0)
2.4
(7.9)
2.4
(8.0)
1.2
(4.1)
2.5
(8.1)
Bed
depth
(ft)
0.70
(2.3)
0.70
(2.3)
0.67
(2.2)
0.70
(2.3)
0.67
(2.2)
0.67
(2.2)
0.67
(2.2)
0.67
(2.2)
0.64
(2.1)
0.67
(2.2)
0.64
(2.1)
0.70
(2.3)
0.64
(2.1)
0.64
(2.1)
0.64
(2.1)
0.64
(2.1)
0.67
(2.2)
1.16
(3.8)
0.7
(2.3)
0.64
(2.1)
Gas phase Fuel ch««cteris
residence Heat value*
Hae kJ/kg X S
"C (Btu/lb)
0.58
0.58
0.58
0.77
0.58
0.58
0.58
0.58
0.53
0.58
0.53
0.77
0.68
0.27
0.26
0.26
0.28
0.48
0.58
0.26
35,062
(15,074)
35,062
(15,074)
35,062
(15.074)
35,062
(15,074)
35,062
(15,074)
35,062
(15,074)
35,062
(15,074)
35.062
(15.074)
35,062
(15,074)
35,062
(15,074)
35,062
(15.074)
35,062
(15,074)
35,062
(15,074)
33,437
(14,375)
33,437
(14,375)
33,437
(14,375)
33,437
(14,375)
33,437
(14,375)
33,437
(14.375)
35.062
(15.074)
2.8
2.8
2.8
2.8
2.8
2.8
2.8
2.8
2.8
2.8
2.8
2.8
2.8
1.3
1.3
1.3
1.3
1.3
1.3
2.8
itics
X Ash
13.5
13.5
13.5
13.5
13.5
13.5
13.5
13.5
13.5
13.5
13.5
13.5
13.5
18.2
18.2
18.2
18.2
18.2
18.2
13.5
Sorbent characteristics
SUe+
Type median
Urn
-
-
-
-
Limestone 18 210
Limestone 18 210
Limestone 18 210
Limestone 18 210
Limestone 18 210
Limestone 18 210
Limestone 18 210
Limestone 18 210
Limestone 18 210
-
U.K. Limestone 300 - 400
U.K. Limestone 300 - 400
U.K. Limestone 300-400
U.K. Limestone 300 - 400
U.K. Limestone 300 - 400
-
Ca/S
0
0
0
0
2.2
2.2
2.2
1.3
2.2
3.3
1.2
2.2
3.3
0
1.8
2.1
2.8
2.8
3.0
0
Emissions characteristics
SO2 ™ / .
' ng/J
pp^ (lb/106 Btu)'
1.750
2,050
2,100
2,020
400
1,020
360
880
510
180
840
330
42
1,480
910
740
540
540
420
1,830
1,596
(3.7)
1,596
(3.7)
1,596
(3.7)
1.596
(3.7)
301
(0.70)
796
(1.9)
271
(0.63)
671
(1.6)
353
(0.82)
142
(0.33)
637
(1.5)
254
(0.59)
30
(0.07)
777
(1.8)
482
(1.1)
389
(0.90)
280
(0.65)
280
(0.65)
218
(0.51)
1.596
0.7)
X
control
0
0
0
0
81
50
83
58
76
91
60
84
98
0
38
49
64
64
72
0
NOX#
ppm
NR
NR
NR
NR
NR
NR
NR
NR
NR
NR
NR
NR
NR
NR
NR
NR
NR
NR
NR
424
ng/J
(lb/10E Btu)1
NR
(NR)
NR
(NR)
NR
(NR)
NR
(NR)
NR
(NR)
NR
(NR)
NR
(NR)
NR
(NR)
NR
(NR)
NR
(NR)
NR
(NR)
NR
(NR)
NR
(NR)
NR
(NR)
NR
(NR)
NR
(NR)
NR
(NR)
NR
(NR)
NR
(NR)
266
(0.62)
-------
TABLE 83 (continued)
u>
Teat
no.
Da tun
Datum
2.1
2.2
2.3
5.1
5.2
5.3
5.4
5.5
2.4
2.5
Da tun
Datum
4.1
4.2
4.3
1 4.4
4.5
Bed
temperature
°C (°F)
849
(1560)
849
(1560)
849
(1560)
849
(1560)
849
(1560)
849
(1560)
849
(1560)
849
(1560)
849
(1560)
849
(1560)
849
(1560)
849
(1560)
799
(1470)
849
(1560)
799
(1470)
749
(1380)
849
(1560)
799
(1470) .
799
(1470)
Gaa
velocity
m/a
(ft/a)
1.2
(4.0)
1.2
(4.0)
2.5
(8.1)
2.5
(8.1)
2.4
(8.0)
1.2
(4.0)
2.4
(8.0)
2.4
(7.8)
2.4
(8.0)
2.4
(8.0)
1.2
(4.0)
0.91
(3.0)
1.2
(4.0)
2.4
(8.0)
1.2
(4.0)
1.2
(4.1)
1.2
(3.8)
1.2
(4.0)
0.64
(2.1)
Bed
depth
(ft)
0.64
(2.1)
0.64
(2.1)
0.64
(2.1)
0.64
(2.1)
0.64
(2.1)
0.64
(2.1)
0.67
(2.2)
1.07
(3.5)
1.10
(3.6)
1.10
(3.6)
0.64
(2.1)
0.61
(2.0)
0.64
(2.1)
0.82
(2.7)
0.64
(2.1)
0.64
(2.1)
0.64
(2.1)
0.64
(2.1)
1.13
(3.7)
_ . Fuel characteriatica
Ca* phase
residence .4
*" (Btu/lb)
0.53
0.53
0.26
0.26
0.26
0.53
0.28
0.45
0.45
0.45
0.53
0.67
0.53
0.34
0.53
0,51
0,55
0.53
1.76
36,062
(15.074)
35,062
(15,074)
35,062
(15,074)
35,062
(15,074)
35,062
(15.074)
35,062
(15.074)
35,062
(15,074)
35,062
(15,074)
35.062
(15,074)
35,062
(15,074)
35,062
(15,074)
35,062
(15,074)
35,062
(15,074)
35,062
(15.074)
35,062
(15,074>
35,062
(15,074)
35,062
(15,074)
35,062
(15,074)
35,062
(15,074)
Z S
2.8
2.8
2.8
2.8
2.8
2.8
2.8
2.8
2.8
2.8
2.8
2.8
2.8
2.8
2.8
2.8
2.8
2.8
2.8
Z Ash
13.5
13.5
13.5
13.5
13.5
13.5
13.5
13.5
13.5
13.5
13.5
13.5
13.5
13.5
13.5
13.5
13.5
13.5
13.5
Sorbent characteristics
Type
-
-
Limeatone 18
Limestone 18
Limeatone 18
Limeatone 18
Limeatone 18
Limestone 18
Limeatone 18
Limestone 18
Limestone 18
Limestone 18
-
-
Dolomite 1337
Dolomite 1337
Dolomite 1337
Dolomite 1337
Dolomite 1337
median Ca/S
urn
0
0
350 - 450 1.1
350 - 450 2.3
350 - 450 2.9
350 - 450 1.7
350 - 450 1.6
350 - 450 1.9
350 - 450 5.7
350 - 450 6.0
-125 1.0
-125 1.0
0
0
100 - 125 3.1
100 - 125 2.6
100 - 125 2.7
100 - 125 2.7
100 - 125 2.2
Emissions characteristic!
«"" (lb/106 Btu)5
2,100
2,400
1,200
900
650
850
1,180
1,040
80
11
1,050
1,050
2,240
2,190
380
620
600
580
380
1,596
(3.7)
1,596
(3.7)
1,054
(2.5)
703
(1.6)
511
(1.2)
559
(1.3)
783
(1.8)
687
(1.6)
48
(0.11)
9
(0.02)
814
(1.9)
814
(1.9J
1,596
(3.7)
1,596
(3.7)
271
(0.63)
447
(1.0)
431
(1.0)
415
(0.97)
271
(0.63)
Z
control
0
0
34
56
68
65
51
57
97
100
49
49
0
0
83
72
73
74
83
NOX*
pom
NR
305
470
515
NR
NR
445
NR
560
550, 325
NR
MR
NR
390
234
NR
244
NR
360
ng/J
(lb/10s Btu)s
NR
(NR)
146
(0.35)
297
(0.69)
289
(0.67)
NR
(NR)
NR
(NR)
212
(0.49)
NR
(NR)
242
(0.56)
323, 191
(0.75), (0.44)
NR
(NR)
KR
(NR)
NR
(NR)
204
(0.47)
120
(0.28)
NR
(NR)
126
(0.29)
NR
(NR?
185
(0.43)
-------
TABLE 83 (.continued)
*»
0
o
es temperature
no. oc (OF)
4.6 799
(1470)
6.1 849
(1560)
6.2 849
(1560)
6.3 849
(1560)
6.4 849
(1560)
6.5 849
(1560)
*
Gas
velocity
m/s
(ft/8)
0.67
(2.2)
2.4
(8.0)
2.4
(8.0)
2.5
(8.1)
2.4
(8.0)
2.4
(8.0)
Bed Gas phase
depth residence
m tune
(ft) sec
1.16 1.73
(3.8)
0.82 0.34
(2.7)
0.82 0.34
(2.7)
1.22 0.49
(4.0)
2.13 0.88
(7.0)
1.68 0.69
(5.5)
Heat value* Size*
kJ/kg Z S Z Ash Type median Ca/S
(Btu/lb) urn
35,062 2.8 13.5 Dolomite 1337 100 - 125 1.6**
(15,074)
35,062 2.8 13.5 Dolomite 1337 875 - 1000 2.5
(15,074)
35,062 2.8 13.5 Dolomite 1337 875 - 1000 5.4
(15,074)
35,062 2.8 13.5 Dolomite 1337 875 - 1000 5.3
(15,074)
35,062 2.8 13.5 Dolomite 1337 875 - 1000 5.2
(15,074)
35,062 2.8 13.5 Dolomite 1337 875 - 1000 5.0
(15,074)
Emissions characteristics
««' n$
PP" Ub/106 Btu)5
20 16
(0.04)
840 575
(1.3)
280 208
(0.48)
260 192
(0.45)
155 112
(0.26)
280 208
(4S>
Z NOX* ng/J
control ppm (lb/106 8tu)S
99 392 225
(0.52)
64 NR NR
(NR)
87 390 208
(0.48)
88 360 191
(0.44)
93 400 207
(0.48)
87 425 226
(0.53)
Size range for all limestone is -1680 urn * 0
By continuous online Hartman-Braun infrared analyzer, the iodine method,'0 and the hydrogen peroxide method."
Estimated by CCA.
*By a modified Saltzman's method,12 and the BCURA NO, box.13
**
With fines recycle.
NR - Not reported.
-------
TABLE 84. PER-FBM MISSION SOURCE TEST DATA RECORDED IN TESTS CONDUCTED FROM
LATE 1967 THROUGH 19697
TME T,.t st.uc "£^ „;«
rubber condition b»d d«pth ^ fc
nu-b" c" (ln-) « (U.) (tb/hr)
ji L ^
(20
I 5C.
< JO
1 SO.
<20
4 50,
UO
2J - 1 10.
(I!
2 SO.
CO
) 50.
(20
4 SO.
(20
3 l" JO
(10
2 50.
CO
4 t 18.
(IS
(15
t 3B.
(IS
*" 18.
(15
76 J,:73
(30) 1
rt>
(30) (
76
(30) I
76
(30) (
46
(IB) (
76
(30) (
76
(30) (
76
(30) C
(30) (
If,
(10) (
58
(33) (
(23) (
58
(23) (
58
(23) (
200)
2t3
200)
271
200)
27)
200)
164
400)
364
400)
)6b
400)
164
400)
600)
455
600)
455
600)
600)
455
600)
,4S5
,600)
Calculated"
mj* (ft/.)
3.1
(10.21
J. 1
(10.1)
3.1
(10.1)
3. 1
(10.2)
3.6
(It. 9)
3.4
(11.1)
3.3
(10.8)
3. 1
(10.3)
(11.2)
1. J
(10. a)
3. J
(12.0)
(11.9)
(11. 1)
3.6
{11. l>
tiac
0.25
C.IS
0.15
0.2S
O.13
0.23
0.2)
0.24
0.23
0.21
O.16
0.16
tt»rerjtur
81*
(540)
SM
(540?
m»
(5*0)
838
(540)
981
(l.BOO)
899
871
( 1.600)
816
(1,500)
(1.620}
838
(1,5*0>
960
(1.760)
( 1.740)
938
(1.720)
938
( 1.710)
Fe*d
- Si «•
(Ib/br)
Cut )64 1.0
Ktntucky (BOO)
JM I.O
[800)
364 1.0
(BOO)
364 1.0
(BOO)
Ohio *» 1T7 4.5
S,— (BM)
UmiMbcd 364 4.5
(BOO)
364 4.5
(BOO)
364 4.5
(BOO)
StM (8)0)
UawMhcd 39S 4.S
(870>
Ohio #8 377 4.5
Seaa (830)
MMU* «d
377 4.S
{8 JO)
377 4.S
(830)
HHV
I A«h kj;h» Typ«
(Btu/U) M
ft.O
8.0
B.O
10.7 30.0*4
(12,934)
10.7 30,084
(11,934)
10.7 30,084 1137B*'1 -2.B30
a:. 934) -ii.no
10.7 30,08*
(11,934)
U2.934)
10.7 30,084 1337K -2.B30
(12.934) -il.fclO
10.7 30,084
(12.934)
(12,934) +1,410
10.7 3OP084
(12,934)
10.7 30.0*4
(12.934)
Feed
r«ce C*/S
(Lb/hr)
168 1 . 75
(370)
143 1.4
(320)
( 54)
61 1.60
( 53)
IB 2.10
(480)
SO; K*«-**I so^
P^ PP"
680
600
500
61D
700 .909
7.0)
3.400 .009
7.0)
l.SOO .169
3.2)
800 ,009
7.0)
7.0)
2,050 ,715
4.0)
3 . 800 ] , 340 009
7.0)
6.8)
3.300 ,612
(6.1)
2.700 2.13*
(5.0)
SOj
r*ductiai
t
0
0
0
0
0
0
54.5
0
43.0
0
2.*
L3.2
29.0
MO NOX NO,
' IllAe T>BSI n«/Jh
pp» pp. Clb/10* BtuJ
20O
220
260
24O
250 M
( .37)
300 9C
300 90
( .44)
140 1
( . )
( . 1)
360 1
( . )
360 1)4 205
(0.48)
(0.45)
340 194
(0.4S)
300 170
(0.40)
-------
TABLE 84 (continued)
o
10
-- -si!:;- ££r
5 I 50.8
2 50-8
3 50.8
CO)
i SO.fl
7 I 50.41
12C)
3 50.8
) "M.8
CO)
{.P 50. B
17 I SO. 8
(JO)
i M.*
120)
1 SO. 8
4P 50. 6
IB1 L 31. D
(11)
111)
1 13.0
on
i 11,0
(13)
rxpindfd T
bed depth kg
,. l.o I Clb
76 3
EJO) I
7t
130) I
J6
OOI (
H
00) t
?4
00) <
76
(30)
t3fl)
7t
no)
76
< JO) (
7k
t JO) i
74
( JO) I
'4
5,
(201 t
51
1 201 (
*,l
(2«1 I
SI
12C) I
:** *i*/ (10.4)
.5*5 3.9 O.li
BOO) (11.4)
.5*5 S-S O.U
004) ( 12.1 )
!**5 J.« 0.13
,BOO) tlJ.iJ
,54i J.I 0.13
.BOO) UJ,*>
Bed
eM
854
B^4
Lt.MO)
ss<-
(l.>^>
ft* 2
(1. 620)
804
(1 ,UO)
80*
(1.1.SO)
804
(!>»>
BU
(I .MO)
860
ll.SM)
BbO
( 1 , 1*0 »
eio
(1.4W)
1.011
(1.B70)
1.004
( I , 4*0 1
M2
*W
(l.!W
Coal
Peed
r«te ,
Clb/hr)
«io *g 327 4.S
S(«M ( I 20 )
Uniovhed 327 4,i
327 4.5
(7ZO)
327 4.1
(720)
Ohio #B 155 4.S
S*M ( 80)
Unw*»hed 55 4.5
< 80)
55 4.1
t BO)
55 4.5
( K}
Ohio H 1*1 45
LhH»»tirt 173 4.5
(820!
164 4. 5>
(890)
182 4.5
(8*0)
Ohio H 37? 1,6
S*M
»«w«rt»W 2. t
2.6
164 2.6
1BOC>
t Mh
10.'
10.7
10,7
10.1
10.)
10.7
10.7
10. T
10.7
10.7
10.7
10.7
7.2
7.1
7.2
7.2
«s» -
JO, 0*4
(ll',934)
30,084 1117|t
30 ! 084
(12,934)
30,064
(12.914)
30.0*4
(12,934)
30.0*4 ML
10,0*4
(12,934)
30.0*4
<12.»>*>
>O.D*4
10,094 1159B*
( 11,934)
)O^D*4
( 1 1,934)
30. DU
(11. 9M)
Jl.BIO
( 3.t*d>
i. tic
( l.l>*OI
1.130
( 3, *»)
l.HO
Sorbent
Teed
Si» r4t« C*/S
(Lb/hr)
-I. a Jo oo 1.13
*!,*!» ! 20)
4* 1.65
t in
09 2.40
(*M)
-2.830 *0 1.11
120 1.70
1165)
BO 1.11
(IJi)
-4* 29 0.7J
(tl>
36 0.9ft
(94 >
3« 0.9]
(**>
fl2l chiiH^
PP"
3,400 J.SOC
3,000
2.400
2,000 1 ,8M
3,»00 1,640
2.BDO
2.15C
2 , 400 1 . 1 50
3,WO J.870
2. BOO 2.69*
2 , 100 J . 180
1 , BOO 1 , 820
2,800
•2.6W
2.500
1.100
rim
Ub/YO- Uu)
3.O09
(7.0
li.;
(i-*
1.S48
3,009
<7.0t
.150
b.0>
.634
S.fl)
.BO6
*.2>
3.3O9
< ; .01
2,150
ISO)
1 bt2
( 3.*)
1.376
( 3 li
1.63*
j 554
{} (1
1,634
(J.l)
1.614
11.1)
>'•
SO; MO NO*
reduction' IRAC PDSS
* PP" PI"
0 ZSO 162
21.0 28Q
17.0 2BO
b8.0 280
0 280 1J9
28 2 260
45.0 22Q
)9.0 160
0 280
28.2 '240 285
41.0 200
54.0 200
o :so
D 300
0 J20 32S
0 140
,,^>
159
159
(0,37)
(0 3) >
159
(0.3!)
15S
(0. 31)
143
tD.JJ)
(0.26)
87
(0.20J
ii9
(0.37)
132
10. 31 1
(021^
110
1 17
(0. 27]
133
(C.il)
15.0
174
(0.0)
-------
TABLE 84 (.continued)
o
OJ
T«*C T*" *«•*'«:
""*"
20 1 31.0
(131
I 33-0
(13J
i 3i. a
(1)1
U3)
21 1 44.3
(191
2 48.3
(19)
(19)
22 1 50.0
(20)
3 50.*
(10)
11 1 48.3
<19)
2 48.1
24 ) 55. t
(22)
I 55.9
(12)
(22J
V 55.9
(23)
bed depth h|
cm (in.) (1
il 5
lit. ) (
CM! ) <
*t.
ci». ) <
t».
tii. ) (
7J.
C14. 1 (
7J.
(28. ) (
TI.
(2*. ) 1
7*
(30) (
7k
4)0) f
72.4
ue!i) (
<28.5) (
<33) (
(3J) (
(31) (
83.8
(33.) (
«; ,""££ -"si*"
rtr) • « ' (i«c)
,5*5 D.13
800) (1 >
.5*4 013
,800) (I )
.1*5 O.U
.400) ( 1 >
,5*5 0.14
,8000 (1 )
,545 0,20
,4001 ( I )
,5*5 0-20
,»00) (1 )
,545 G.Il
.800) (1 )
V45 (1 )
,}M 0.22
.400) (1 )
1*00) (I )
,36A 0.25
,400) (1 , )
.400) (1 . )
.344 0.25
.400) (10. )
. .-,.„««.
(*r>
966
<1 770)
'w*
(1,810)
M*
(1.710)
932
(1.710)
916
(I. MO)
(1,680)
an
(1.600)
*rt
<1,9»)
u.JS)
*»«
1 1.6)0)
U,5H»
(l.fcOO)
(t.600)
(1.600)
8U
(1,600)
^
*"* tSSo
Ohio ft 364 2.6
S«j. (8001
Wa>b*d 400 1,6
(MO)
404 2 . *
1900)
401 2. ft
(900)
Ohio rt 400 2.6
|«M (8M>
WMJied M» 2.6
(8M>
MM 2.4
(800)
Ohio M 420 J-*
»M» )925>
(91Sf
Ohio M )M ;.*
««•• (too)
tfMhcd 3M i-t
(800)
VMftcrf JM 2.4
(BOO;
(800>
36* 2.6
(too)
™ , »«
7.2 31.120
< 1.480)
7.2 1,420 13)'H -4*
< l.UO)
7.2 1^*20
< 3.480)
7.2 1,«20
( 1,480)
7.2 3 ^20
O .480}
7.2 3 ,«2D 13171 -V*
<1 ,4*0}
7.2 3 .820
(I ,480J
J.2 J .120
(1 .480)
U .480]
7.2 Jl,«fl
7.2 3),»20 133TH -M
U3.480)
(13. MO)
7.2 Jl,«!0 1JJJ* -4*
(1J.4M)
j 2 31(020
(1J.*«)
7.1 31.120
(13, MO)
'£ «/«
0
51 1.17
(111)
63 l.+ft
(144)
6) 1.*$
(144)
ff
M 1,17
(132)
60 L. 17
C112)
0
(l*5»
0
128 2,*
(182)
127 J.4
(3*0)
118 23
118 2.1
(0. 2)
6.5 4(6
(14.2) (I. 1)
6.3 54
( 11. ») (L.I)
7 . 0 602
(15.3) (1.40)
(»-3) (0.8S)
6.2 533
(13.6) (1.24}
-------
TABLE 84 Ccontinued)
JS
O
.p-
nu"b" nu-ber c. (In.)
25 1 61.0
(24)
(24)
) 61.0
(24)
(20)
2 50.8
1 70)
J Vi. *
110)
n \ 5o.a
(20
: 50.
(20
28 1 50.
(20
00
J 50.
(20
29 I 50. B
(20)
2 5U.B
(20)
1 SO. 8
(20)
4° 50. K
cot
e«p.nd«d
bed depth
CM ( in . )
91
(16)
(36)
91
(16)
(10)
76
(10)
7b
(10)
76
(10)
76
(10)
76
(30)
(30)
76
(30)
76
(10)
76
(10)
76
(30)
76
(30)
Air !**
Fly ••hr
k|/hr
(Ib/hr)
3.5
(7.8)
6.5
( 14.3)
5.6
(12.4)
7.6
(16.8)
4.8
(10.5)
7.5
(16.5)
4.0
(8.9)
t!2>)
5.5
(12.1)
6.7
(14. 7)
fly Mb'
(lb/10* Btu)
318
(0.74)
567
(1.32)
516
(1.20)
696
(1.62)
456
(1.06)
718
(1.67)
374
(O.B7>
(1 .32)
559
(1.10)
679
(1.58)
-------
TABLE 84 (continued)
^
30
31
11
niM*«r cm (I
I V)
U
2 SO
(2
] 50
<2
1 So
IA
2 50
(2
J 50
(2
1 50
(2
1 50
(2
3 50
{.'
(Z
rr •=»•» ,?
76
( 10) I
76
410) (
76
(JO) (
76
(30) (
76
(30) (
T6
(JO) 4
76
(30) (
76
(30) (
76
(JO) I
T*>
(10) <
/hr
/hr )
.364
,400)
,164
.4001
,164
,400>
,*-3S
,WO>
.4*5
.600)
,WO)
.164
.400)
.164
,400)
,364
,400)
>WI
^!±]
0.3J ««2 uhiu vl J* .'.fc
C 1 . > I I ,fcI(J) S*M | 40)
"-J ' **- WiMi.-d 45
f 1 , I 11 .410! ( 60)
O.)l M2 *}
Ct . ) ( I. MO) < M»
0.22 Ml Ohio *B 7J 3 6
(1 . ) (1>2D) £,«• ( 10)
0.32 a'Z tfiihed 10
(1 . ) (1.6 0) ( 70)
0.12 M *4
II . ) (1,6 0} ( 00)
O.J) •' Ohio. *• IS 3.6
(1 . ) f 1.* 0! $*«, ( 00)
Q.23 «' ««i**i 27
(1 . ) (1,6 Ok ( 20)
0.23 BT 21
M . ) U,6 fit ( 20)
O.JJ f 327
(1 . ) (1,610) (720)
Km
«*v
' A»h kJ/k« Tvjw
M 31.810
<13,6«0)
11.120 1HM -44
(ll.WOI
U.B2O
7 2 ]i no
(13^640)
U.BIO I35M -44
< 13, 6*0)
(iiiwo)
7.1 11.120
1L.BIO U1»* -44
(13. *M)
JI.B20
(ll.MOJ
31.120
b^t
rat*
1,6 l.OOQ [.0*0
0 2.6SO 2. WO
1.6 1,020 l.OiO
1.1 970 910
I.I 7*0
ri«* (••
10, M,
1.414 0
(1.B)
*lf M.O
( 1 .*)
447 60.6
l.«34 0
(J.I)
ns si. •
(I.76J
«* 41 . 1
(I.5>
1,634 0
411 61.9
(1.44)
574 64. f
(1.33))
412 70,1
(1.1)
240
2*0
jro
270
no
290
290
290
Jii 1U
(O.IT)
114
(0.3T)
114
(0.27)
JOJ Ii2
(0.21)
lit
(O.II)
(0.2«)
J10 12*
(0.10)
11*
(O.JO)
11*
(O, lo)
(O.JO)
3.5 327
n.l> (O.TfcJ
5.2 473
tll.4) tww - 71 f«rc*«C C*CO3.
Mt » Rot t*p«Tt«4
-------
TABLE 85. PER-FBM EMISSION SOURCE TEST DATA RECORDED IN TESTS CONDUCTED
THROUGH 1975 WITH SEWICKLEY COAL8
•e-
o
Test
number
636
637-1
637-2
639
621
630
Operating
bed
depth
cm
(in.)
86.1
(33.9)
102.9
(40.5)
101.3
(39.9)
96.8
(38.1)
94.0
(37)
96.5
(38)
Superficial Bed
gas
velocity
m/sec
(ft/sec)
4.3
(14)
3.8
(12.4)
3.8
(12.5)
4.7
(15.5)
4.5
(14.6)
3.8
(12.7)
temper-
ature
°C
815
(1500)
815
(1500)
827
(1520)
857
(1575)
815
(1500)
815
(1500)
Coal
residence Feed
time rate
(sec) Type kg/hr
(Ib/hr)
0.202 Sewickley 336
(740)
0.272 Sewickley 320
(705)
0.266 Sewickley 320
(705)
0.205 Sewickley 350
(770)
0.211 Sewickley 334
(735)
0.249 Sewickley 306
(674)
Limestone
_ Type Sis
4.1 - 4.5 Germany
Valley
4.1 - 4.5 Greer
4.1 - 4.5 Greer
4.1 - 4.5 Greer
4.1 - 4.5 Greer
4.1 - 4.5 Germany
Valley
Feed
* rate Ca/S t
EG 1/1 j Ppf t
kg/hr ratio rr^ (
(Ib/hr)
216 4.4 650
(475)
170 2.9 500
(374)
189 3.2 370
(416)
202 3.5 490
(445)
133 2.9 1,200
(292)
114 2.76 1,120
(251)
S02
„#'**
679
(1.58)
598
(1.39)
512
(1.19)
473
(1.10)
1,071
(2.49)
967
(2.25)
*Size ranged from 370 to 4,760 urn.
By IR analyzer.
-------
TABLE 86. OPERATING CONDITIONS AND RESULTS OF FLUIDYNE 500-HR
TEST IN 3.3 FT x 5.3 FT VERTICLE SLICE COMBUSTOR10
OPERATING CONDITIONS
• Fuel Characteristics
1. Type
2. Surface Moisture (Z)
3. Feed rate
4. Z Sulfur
5. Feed location
• Sorbcnt Characteristics
1. Type
2. Surface Moisture (Z)
3. Ca/S
4. Feed rate
5. Feed location
• Bed Temperature
• Bed Depth
• Superficial Velocity
• Flue Gas Excess Air Level
• Process Air Flow Rate
• Total Heat Output
• Recycle of Elutriated Particulates
• Combustion Efficiency (Z)
Illinois Mo. 6
2-11
68 - 227 kg/hr (150 - 500 Ib/hr)
3.6
In-bed
Owatonna Dolomite - 1/4 in.
3-7
1.1 - 2.2
23 - 82 kg/hr (50 - 180 Ib/hr)
In-bed
718° to 796°C (1325° to 1465°F)
1.1 - 1.2 m (42 - 47 in.)
0.6 - 1.3 m/sec (2.0 - 4.2 ft/sec)
30 - 130 percent
454 - 5675 kg/hr (1,000 - 12,500 Ib/hr)
0.5 - 1.6 MWt (1.65 - 5.5 x 106 Btu/hr)
Yes
93.5 to 96.3
RESULTS OF TESTING
Load
Bed Temperature, °C (°F)
Superficial Velocity, m/sec (ft/sec)
Kg Dolomite /Kg Coal
Ca/S Ratio*
SO 2 Control Efficiency (%)
NOx emission ng/J (lb/106 Btu)
Excess Air (%)
Low
718 (1325)
0.76 (2.5)
0.46
2.4
80
236 (0.55)
130
High
796 (1465)
1.1 (3.6)
0.31
1.7
80
159 (0.37)
30
Estimated by GCA from kg dolomite/kg coal.
Estimated by GCA from coal heating value and sulfur content and SO2 outlet
level of 516 ng/J (1.2 lb/106 Btu).
407
-------
TABLE 87. OPERATING CONDITIONS AND RESULTS OF FLUIDYNE RUN 35
IN 3.3 FT x 5.3 FT VERTICAL SLICE COMBUSTOR11
OPERATING CONDITIONS
• Fuel Characteristics
1. Type
2. Feed rate
3. % Sulfur
4. Feed location
• Sorbent Characteristics
1. Type
2. Ca/S ratio
3. Feed rate
4. Feed location
• Bed Temperature
• Bed Depth
• Superficial velocity
• Excess air
• Recycle of Elutriated Particulate
• Gas Phase Residence Time
Illinois No. 6
173 kg/hr (380 Ib/hr)
3.6
Above-bed
Owatonna Dolomite
2.38
77 kg/hr (170 Ib/hr)
Above-bed
772°C (1421°F)
1.1 tn (45 in.)
1 m/sec (3.21 ft/sec)
50 percent
Yes
0.86 sec
RESULTS OF TESTING
Ca/S ratio
S02 Control Efficiency (%)
2.38
87.2
Estimated by GCA.
408
-------
TABLE 88. EMISSION SOURCE TEST DATA: NCB 6-IN. DIAMETER FBC UNIT
FIRING WELBECK, PARK HILL, ILLINOIS, AND PITTSBURGH COALS
WITH U.K. LIMESTONE AT A TEMPERATURE OF 799°C (1470°F)12
Test "lo"ty?8 °*"
-------
TABLE 89. EMISSION SOURCE TEST DATA: NCB 6 INCH DIAMETER FBC UNIT
FIRING ILLINOIS COAL WITH LIMESTONE 1359 AT A FLUIDIZING
VELOCITY OF 0.9 m/sec (3 ft/sec)12
Bed
Test temperature
No. oc
1.1
1.2
1.3
1.4
3.1
3.2
3.3
3.4
3.5*
3.6*
799
(1470)
799
(1470)
799
(1470)
799
(1470)
699
(1290)
699
(1290)
799
(1470)
799
(1470)
799
(1470)
799
(1470)
Bed ^ Ca/S
depth, <*?*% molar S02, S
ln°" feed ppm retefi°n>
(ft) 8SS' ratio 7°
0.6 2.9 0 4023 0
(2)
0.6 2.8 1.5 2118 47
(2)
0.6 2.6 2.2 1450 64
(2)
0.6 2.9 3.3 680 78
(2)
0.6 2.7 1.1 3376 24
(2)
0.6 2.4 2.2 3245 26
(2)
0.9 2.7 1.1 1930 49
(3)
0.9 2.6 2.1 1136 70
(3)
0.6 2.4 1.1 1523 61
(2)
0.6 2.5 3.6 278 92
(2)
S02
reduction,
&
0
47
63
78
15
18
51
72
61
93
*Tests with -125 ym limestone particles.
410
-------
TABLE 90. EMISSION SOURCE TEST DATA: NCB 6 INCH DIAMETER FBC
UNIT FIRING PITTSBURGH AND WELBECK COALS WITH LIME-
STONE 18 AT A TEMPERATURE OF 799°C (1470°F) , BED
DEPTH OF 0.6 m (2 feet) AND FLUIDIZING VELOCITY OF
0.9 m/sec (3 ft/sec)12
Test
No.
4.1
4.5
4.6
4.7
4.8*
4.9f
5.2
Oxygen
Coal type In off
gas, %
Pittsburgh
Pittsburgh
Pittsburgh
Pittsburgh
Pittsburgh
Pittsburgh
Welbeck
2.3
2.5
2.2
2.3
2.1
2.5
2.6
Ca/S g
molar SO?, . .
feed pp£ "tention,
ratio
0 1980
0.9 1137
1.7 581
2.6 185
0.9 1238
0.9 1115
1.9 236
5
50
75
92
55
60
85
S02
reduction,
%
0
43
71
91
38
43
80
*Test with lime rich bed.
i"Test with shale bed.
411
-------
TABLE 91. EMISSION TEST DATA MEASURED FROM ANL'S 6-IN. AFBC UNIT13"16
Test conditions
-Test No.
CC-1-1
CC-1-2
CC-1-3
CC-2-1
CC-2-2
CC-2-3
*: cc-3-i
ro
CC-3-2
CC-3-3
CC-3-4
CC-4-1
CC-4-2
CC-4-3
CC-4-4
CC-7-1
CC-7-2
CC-9
SACC-1
Bed
temp.
°C
870
(1600)
870
(1600)
870
(1600)
870
(1600)
870
(1600)
870
(1600)
870
(1600)
870
(1600)
870
(1600)
870
(1600)
870
(1600)
870
(1600)
870
(1600)
870
(1600)
870
(1600,
870
(1600)
870
(1600)
870
(1600)
Super-
ficial
gas
Velocity
0/8
(ft/s)
1.14
(3.75)
1.14
(3.75)
1.14
(3.75)
1.14
(3.75)
1.14
(3.75)
1.14
(3.75)
1.14
(3.75)
1.14
(3.75)
1.14
(3.75)
1.14
(3.75)
1.14
(3.75)
1.14
(3.75)
1.14
(3.75)
1.14
(3.75)
1.14
(3.75)
1.14
(3.75)
1.14
(3.75)
0.91
(3.0)
Bed
depth
(in.)
0.38
(15)
0.38
(15)
0.38
(15)
0.38
(15)
0.38
(15)
0.38
(15)
0.38
(15)
0.38
(15)
0.38
(15)
0.38
(15)
0.38
(15)
0.38
(15)
0.38
(15)
0.38
(15)
0.38
(15)
0.38
(15)
0.38
(15)
0.61
(24)
Gas
resi-
dence
tine
sec
0.33
0.33
0.33
0.33
0.33
0.33
0.33
0.33
0.33
0.33
0.33
0.33
0.33
0.33
0.33
0.33
0.33
0.67
Heating
value
kJ/kg
(Btu/lb)
28,126
(12,092)
28,126
(12,092)
28,126
(12,092)
-8,126
(12,092)
28,126
(12,092)
28,126
(12,092)
28,126
(12,092)
28,126
(12,092)
28,126
(12,092)
28,126
(12,092)
28,126
(12,092)
28,126
(12,092)
28,126
(12,092)
28,126
(12,092)
28,126
(12,092)
28,126
(12,092)
28,126
(12,092)
28.126
(12,092)
Fuel characteristics
Sulfur
Z
4.63
4.63
4.63
4.63
4.63
4.63
4.63
4.63
4.63
4.63
4.63
4.63
4.63
4.63
4.63
4.63
4.63
4.63
Nitrogen
Z
1.31
1.31
1.31
1.31
1.31
1.31
1.31
1.31
1.31
1.31
1.31
1.31
1.31
1.31
1.31
1.31
1.31
1.31
Ash
%
12.39
12.39
12.39
12.39
12.39
12.39
12.39
12.39
12.39
12.39
12.39
12.39
12.39
12.39
12.39
12.39
12.39
12.39
Sorbent characteristics
Feed
IK T"<
(Ib/h)
dolomite
1337
- 1337
1337
1337
1337
1337
1337
1337
1337
1337
1337
1337
1337
1337
1337
3.7 lines tone
(29.7) 1360
- 1360
3.7 limestone
(29.1) 1359
Mean
size
un
(in.)
-
300
300
-
100
100
300
300
300
-
100
100
100
-
1200
1200
25
Feed
rate
8/8
(Ib/h)
0.0
(0.0)
-
-
0.0
(0.0)
-
-
0.0
(0.0)
-
-
0.0
(0.0)
-
-
-
0.0
(0.0)
0.2
(1.5)
-
1.2
(9.69)
Ca/S
ratio
0.0
3.5
5.1
0.0
1.4
2.8
0.0
2.0
2.9
4.0
0.0
1.5
2.1
2.6
0.0
2.5
4.2
1.9
PP»
1350
450
350
2000
1150
500
1550
600
400
200
2250
1600
1100
900
2850
800
400
1300
Emission characteristics
SO,
ng/J
(lb/106
Btu)
3295
(7.66)
1090
(2.53)
855
(1.99)
3295
(7.66)
1910
(4.44)
825
(1.92)
3295
(7.66)
1290
(3.00)
855
(1.99)
430
(1.00)
3295
(7.66)
2340
(5.44)
1610
(3.75)
1315
(3.06)
3295
(7.66)
920
(2.14)
460
(1-07)
1055
(2.45)
S02
reten-
tion
0.0
67.0
74.0
0.0
42.0
75.0
0.0
61.0
74.0
87.0
0.0
29.0
51.0
60.0
0.0
72.0
86.0
68.0
NOX
ng/J
ppm (lb/106
Btu)
-
-
-
-
-
-
—
-
-
-
-
-
-
-
-
-
440 "3
**° (0.59)
-------
TABLE 91 Ccontinued)
Test conditions
Test No.
SACC-2
SACC-3
SACC-4
SA1A
SA1B
SA1C
SAID
SA1E
SACC-5
SACC-5R
SACC9-1
SACC9-2
SACC9-3
SACC9-5
SACC6-1
SACC6-2
SACC-7
SACC8-1
Bed
temp.
°C
870
(1600)
870
(1600
870
(1600)
843
(1550)
843
(1550)
843
(1500)
843
(1550)
843
(1500)
870
(1600)
870
(1600)
870
(1600)
870
(1600)
870
(1600)
870
(1600)
870
(1600)
870
(1600)
870
(1600)
870
(1600)
Super-
ficial
gas
velocity
m/s
(ft/s)
0.91
(3.0)
0.91
(3.0)
0.91
(3.0)
0.91
(3.0)
0.91
(3.0)
0.91
(3.0)
0.91
(3.0)
0.91
(3.0)
0.91
(3.0)
0.91
(3.0)
0.91
(3.0)
0.91
(3.0)
0.91
(3.0)
0.91
(3.0)
2.7
(9.0)
2.. 7
(9.0)
2.7
(9.0)
2.7
(9.0)
Bed
depth
(in.)
0.61
(24)
0.61
(24)
0.61
(24)
0.61
(24)
0.61
(24)
0.61
(24)
0.61
(24)
0.61
(24)
0.61
(24)
0.61
(24)
0.61
(24)
0.61
(24)
0.61
(24)
0.61
(24)
0.61
(24)
0.61
(24)
0.61
(24)
0.61
(24)
Gas
resi-
dence
time
sec
0.67
0.67
0.67
0.67
0.67
0.67
0.67
0.67
0.67
0.67
0.67
0.67
0.67
0.67
0.22
0.22
0.22
0.22
Heating
value
kJ/kg
(Btu/lb)
28,482
(12,245)
28,482
(12,245)
28,482
(12,245)
28,482
(12,245)
28.482
(12,245)
28,482
(12,245)
28,482
(12,245)
28.482
(12,245)
28,482
(12,245)
28,475
(12.242)
28,475
(12.242)
28,475
(12.242)
28.475
(12,242)
28,475
(12.242)
28,475
(12,242)
28,475
(12.242)
28,475
(12,242)
28,475
(12.242)
Fuel characteristics
Sulfur
Z
4.84
4.84
4.84
4.84
4.84
4.84
4.84
4.84
4.84
4.84
4.84
4.84
4.84
4.84
4.84
4.84
4.84
4.84
Nitrogen
Z
1.11
1.11
1.11
1.11
1.11
1.11
1.11
1.11
1.11
1.11
1.11
1.11
1.11
1.11
1.11
1.11
1.11
1.11
Feed
Ash rate
Z g/S
(Ib/h)
13.13
13'13 (30'.2)
13'13 (29%
13.13
13.13
13.13
13.13 -
13.13
13.13 -
13.13 -
13.13 -
13.13
13.13
13.13 -
13.13 -
13.13
13.13
13.13
Sorbent characteristics
Type
1359
1359
1359
1359
1359
1359
1359
1359
1359
1359
1359
1359
1359
1359
1359
1359
1359
1359
Mean
alee
UB
(in.)
600
25
25
25
25
25
25
25
25
25
25
25
25
25
25
25
1400
25
Feed
rate Ca/S
g/S ratio
(Ib/h)
2.4
1.2
(9.82) Z-ft
1-2
(9.79) 2'Z
- 0.0
1.5
2.0
2.6
4.2
2.2
- 2.2
1.7
- 1.2
1.7
3.0
1.3
1.7
1.6
1.0
PP"
1600
1700
360
3780
1600
1250
650
400
300
800
1400
2290
1380
800
2000
1650
3350
2400
Emission characteristics
S02
ng/J
(lb/106
Btu)
1600
(3.72)
1630
(3.79)
445
(1.03)
3400
(7.91)
1425
(3.32)
1120
(2.61)
574
(1.34)
375
(0.87)
715
(1.66)
715
(1.66)
1225
(2.85)
2005
(4.66)
1190
(2.77)
715
(1.66)
1665
(3.87)
1395
(3.24)
2785
(6.48)
2070
(4.82)
S02
reten-
tion
Z
53.0
52.0
87.0
0.0
58.0
67.0
83.0
89.0
79.0
79.0
64.0
41.0
65.0
79.0
51.0
59.0
18.0
39.0
ppm
400
400
360
720
600
600
600
650
420
420
500
400
460
500
420
400
550
520
NO
ng/J t
(lb/106
Btu
230
(0.53)
230
(0.53)
205
(0.48)
415
(0.96)
345
(0.80)
345
(0.40)
345
(0.80)
375
(0.87)
240
(0.56)
240
(0.56)
290
(0.67)
230
(0.53)
260
(0.61)
290
(0.67)
240
(0.56)
230
(0.53)
315
(0.73)
295
(0.69)
-------
TABLE 91 (continued)
Test conditions
Fuel characteristics
Sorbent characteristics
Emission characteristics
Test No.
SACC8R-2
SACC8R-3
SACC8-4
SACC8R-5
SA2A
SA2B
SA2C
SA2D
SA2E
SA3A
SA3B
SA3C
SA3D
SA3E
SA4A
SA-3
SA4C
SA4D
Bed
temp.
°C
870
(1600)
870
(1600)
870
(1600)
870
(1600)
870
(1600)
870
(1600)
900
(1650)
900
(1650)
900
(1650)
900
(1650)
900
(1650)
900
(1650)
900
(1650)
900
(1650)
843
(1550)
843
(1550)
843
(1550)
843
(1550)
Super-
ficial
gas
velocity
m/s
(.ft/a)
2.7
(9.0)
2.7
(9.0)
2.7
(9.0)
2.7
(9.0)
2.7
(9.0)
2.7
(9.0)
0.91
(3.0)
0.91
(3.0)
0.91
(3.0)
0.91
(3.0)
0.91
(3.0)
0.91
(3.0)
0.91
(3.0)
0.91
(3.0)
0.91
(3.0)
0.91
(3.0)
0.91
(3.0)
0.91
(3.0)
Bed
depth
(in.)
0.61
(24)
0.61
(24)
0.61
(24)
0.61
(24)
0.61
(24)
0.61
(24)
0.61
(24)
0.61
(24)
0.61
(24)
0.61
(3.0)
0.61
(24)
0.61
(24)
0.61
(24)
0.61
(24)
0.61
(24)
0.61
(24)
0.61
(24)
0.61
(24)
Gas
resi-
dence
time
sec
0.22
0.22
0.22
0.22
0.22
0.22
0.67
0.67
0.67
0.67
0.67
0.67
0.67
0.67
0.67
0.67
0.67
0.67
Heating
value
kJ/kg
(Btu/lb)
28,475
(12,242)
28,475
(12,242)
28,475
(12,242)
28,475
(12,242)
28,475
(12,242)
28,475
(12,242)
28,475)
(12,242)
28,475)
(12,242)
28,475
(12,242)
28,475
(12,242)
28,475
(12,242)
28,475
(12,242)
28,475)
(12,242)
28,475
(12,242)
28,475
(12,242)
28,475
(12,242)
28,475
(12,242)
28,475
(12,242)
Sulfur
Z
4.84
4.84
4.84
4.84
4.84
4.84
4.84
4.84
4.84
4.84
4.84
4.84'
4.84
4.84
4.84
4.84
4.84
4.84
Nitrogen
Z
1.11
1.11
1.11
1.11
1.11
1.11
1.31
1.31
1.31
1.31
1.31
1.31
1.31
1.31
1.31
1.31
1.31
1.31
Feed
Ash rate
* g/S
(Ib/h)
13.13
13.13
13.13
13.13
13.13
13.13
13.13
13.13
13.13 -
13.13
13.13
13.13 -
13.13
13.13
13.13
13.13
13.13
13.13 - .
Type
1359
1359
1359
1359
1359
1359
1359
1359
1359
1359
1359
1359
1359
1359
1359
1359
1359
1359
Mean
size
urn
(in.)
25
25
25
25
25
25
25
25
25
103
103
103
103
103
103
103
103
103
Feed
rate Ca/S
g/S ratio
(Ib/h)
1.0
2.4
2.4
2.4
0.0
1.5
2.6
3.0
3.7
0.0
2.4
0.8
0.6
0.8
0.0
4.0
1.7
0.6
ppm
2650
1150
1350
1550
4400
2050
1150
850
620
4000
1600
1800
2300
2300
3400
160
1300
2400
S02
ng/J
(lb/106
Btu)
2280
(5.30)
985
(2.29)
1055
(2.45)
1225
(2.85)
3400
(7.91)
1565
(3.64)
885
(2.06)
645
(1.50)
475
(1.11)
3400
(7.91).
1360
(3.16)
1530
(3.56)
1975
(4.59)
1975
(4.59)
3400
(7.91)
170
(0.40)
1395
(3.24)
2315
(5.38)
S02
reten-
tion
33.0
71.0
69.0
64.0
0.0
54.0
74.0
81.0
86.0
0.0
60.0
55.0
42.0
42.0
0.0
95.0
59.0
32.0
ppm
510
510
470
420
800
560
600
600
600
-
-
-
-
-
760
550
570
600
NO
X
ng/J
(lb/106
Btu)
290
(0.68)
290
(0.68)
270
(0.63)
240
(0.56)
460
(1.07)
320
(0.75)
345
(0.80)
345
(0.80)
345
(0.80)
-
-
-
-
-
435
(1.01)
315
(0.73)
325
(0.76)
345
(0.80)
-------
TABLE 91 (continued)
Ui
Test conditions
Test No.
SA4E
BC-1-1
BC-1-2
BC-2
BC-3
BC-4
BC-4-1
BC-5-1
BC-5-2
BC-6-1
BC-6-2
BC-6-3
BC-7-1
BC-7-2
BC-8-1
BC-8-2
BC-9
BC-10-A
Bed
temp.
°C
843
(1550)
870
(1600)
870
(1600)
870
(1600)
870
(1600)
870
(1600)
870
(1600)
870
(1600)
870
(1600)
816
(1500)
870
(1600)
870
(1600)
870
(1600)
870
(1600)
870
(1600)
870
(1600)
870
(1600)
870
(1600)
Super-
ficial
gas
velocity
m/s
(ft/s)
0.91
(3.0)
0.91
(3.0)
0.87
(2.85)
0.87
(2.85)
0.87
(2.85)
0.87
(2.85)
0.87
(2.85)
0.87
(2.85)
0.85
(2.8)
0.85
(2.8)
0.85
(2.8)
0.85
(2.8)
0.85
(2.8)
0.85
(2.8)
0.85
(2.8)
0.85
(2.8)
0.85
(2.8)
0.85
(2.8)
Bed
depth
(in.)
0.61
(24)
0.61
(24)
0.61
(24)
0.61
(24)
0.61
(24)
0.61
(24)
0.61
(24)
0.61
(24)
0.61
(24)
0.61
(24)
0.61
(24)
0.61
(24)
0.61
(24)
0.61
(24)
0.61
(24)
0.61
(24)
0.61
(24)
0.61
(24)
Gas
resi-
dence
tine
see
0.67
0.67
0.70
0.70
0.70
0.70
0.70
0.70
0.71
0.71
0.71
0.71
0.71
0.71
0.71
0.71
0.71
0.71
Heating
value
kJ/kg
(Btu/lb)
28,475
(12,242)
28,475)
(12,242)
28,475
(12,242)
28.475
(12,242)
28,475
(12,242)
28,475
(12,242)
28,475
(12,242)
28,475
(12,242)
28,475
(12,242)
28,475
(12,242)
28,475
(12.242)
28.475
(12.242)
28,475
(12,242)
28,475
(12,242)
28,475
(12,242)
28,475
(12,242)
28,475
(12,242)
28,475
(12,242)
Fuel characteristics
Sulfur
Z
4.84
4.84
4.84
4.84
4.84
4.84
4.84
4.84
4.84
4.84
4.84
4.84
4.84
4.84
4.84
4.84
4.84
4.84
Nitrogen
Z
1.31
1.31
1.31
1.31
1.31
1.31
1.31
1.31
1.31
1.31
1.31
1.31
1.31
1.31
1.31
1.31
1.31
1.31
Ash
I
13.13
13.13
13.13
13.13
13.13
13.13
13.13
13.13
13.13
13.13
13.13
13.13
13.13
13.13
13.13
13.13
13.13
13.13
Feed
rate
g/S
(Ib/h)
-
-
-
-
-
-
-
-
-
0.6
(4.4)
0.6
(4.4)
0.6
(4.4)
0.6
(4.9)
0.7
(5.2)
0.6
(4.5)
0.5
(4.3)
0.5
(4.1)
0.5
(4.3)
Sorbent characteristics
Type
1359
1359
1359
Tymoch-
tee
Tymoch-
tee
Tymoch-
tee
Tymoch-
tee
Tymoch-
tee
Tyinoch-
tee
1359
1359
1359
1359
1359
1359
1359
1359
1337
Mean
size
(In.)
103
25
25
575
575
44
44
44
44
615
615
615
615
615
615
615
630
540
Feed
rate
g/S
(Ib/h)
-
-
-
-
-
-
-
-
-
-
-
0.2
(1.6)
0.0
(0.0)
0.2
(1-8)
0.0
(0.0)
0.2
(1.6)
0.2
(1.7)
0.3
(2.6)
Ca/S
ratio
2.4
1.2
2.0
1.6
1.5
0.6
1.2
1.5
2.1
-
-
2.6
0.0
2.3
0.0
2.5
2.3
2.2
PPn
920
-
-
530
850
1850
1050
1250
620
130
250
960
2250
930
3350
940
1100
910
Emission
S02
ng/J
(lb/106
Btu)
915
(2.13)
1600
(3.72)
1190
(2.77)
445
(1.03)
750
(1.74)
1870
(4.35)
1055
(2.45)
1155
(2.69)
575
(1.34)
140
(0.32)
1800
(4.19)
715-
(1.66)
1530
(3.56)
575
(1-34)
2480
(5.77)
715
(1.66)
885
(2.06)
645
(1.50)
characteristics
S02
reten-
tion
Z
73.0
53.0
65.0
87.0
73.0
45.0
69.0
66.0
83.0
96.0
47.0
79.0
55.0
83.0
27.0
79.0
74.0
81.0
ppn
530
-
-
500
550
350
395
365
400
600
400
380
340
220
310
320 '
400
440
NO
ng/J
(lb/106
Btu)
305
(0.71)
-
-
290
(0.67)
315
(0.73)
200
(0.47)
230
(0.53)
210
(0.49)
230
(0.53)
345
(0.80)
230
(0.53)
220
(0.51)
195
(0.45)
125
(0.29)
175
(0.41)
185
(0.43)
230
(0.53)
255
(0.59)
-------
TABLE 91 (.continued)
Test conditions
Fuel characteristics
Sorbent characteristics
Emission characteristics
S02
NO
'Test No.
BC-10-B
BC-10-C
AR-l-A
AR-l-B
AR-l-C
AR-l-D
AR-l-E
AR-l-F
BRIT-1
BRIT-2
BRIT-3
AMER-1
AMER-2
AMER-3
AMER-33
AM- BRIT
BRIT-AM
AR2A
Bed
temp.
°C
(°F>
788
(1450)
982
(1800)
760
(1400)
788
(1450)
816
(1500)
843
(1550)
870
(1600)
760
(1400)
800
(1470)
800
(1470)
800
(1470)
800
(1470)
800
(1470)
800
(1470)
800
(14,^
800
(1470)
800
(1470)
843
(1550)
super-
ficial
gas
velocity
m/s
(ft/s)
0.85
(2.8)
0.85
(2.8)
0.85
(2.8)
0.85
(2.8)
0.85
(2.8)
0.85
(2.8)
0.85
(2.8)
0.85
(2.8)
0.76
(2.5)
0.79
(2.6)
0.79
(2.6)
0.79
(2.6)
0.79
(2.6)
0.79
(2.6)
0.79
(2.6)
0.79
(2.6)
0.79
(2.6)
0.85
(2.8)
Bed
depth
m
(in.)
0.61
(24)
0.61
(24)
0.61
(24)
0.61
(24)
0.61
(24)
0.61
(24)
0.61
(24)
0.61
(24)
0.61
(24)
0.61
(24)
0.61
(24)
0.61
(24)
0.61
(24)
0.61
(24)
0.61
(24)
0.61
(24)
0.61
(24)
0.61
(24)
Gas
resi-
dence
tine
sec
0.71
0.71
0.71
0.71
0.71
0.71
0.71
0.71
0.71
0.77
0.77
0.77
0.77
0.77
0.77
0.77
0.77
0.71
Heating
value
kJ/kg
(Btu/lb)
28,475
(12,242)
28,475
(12,242)
28,475
(12,242)
28,475
(12,242)
28,475
(12,242)
28,475
(12,242)
28,475
(12,242)
28,475
(12,242)
27,463
(11,807)
27,463
(11,807)
27,463
(11,807)
28,290
(12,163)
28,290
(12,163)
28,290
(12,163)
28,290
(12,163)
28,290
(12,163)
27,463
(11,807)
28,290
(12,163)
Sulfur
Z
4.84
4.84
4.84
4.84
4.84
4.84
4.84
4.84
1.28
1.28
1.28
4.14
4.14
4.14
4.14
4.14
1.28
3.7
Nitrogen
Z
1.31
1.31
1.31
1.31
1.31
1.31
1.31
1.31
1.21
1.21
1.21
1.18
1.18
1.18
1.18
1.18
1.21
1.18
Ash
7.
13.13
13.13
13.13
13.13
13.13
13.13
13.13
13.13
18.07
18.07
18.07
12.08
12.08
12.08
12.08
.12.08
18.07
10.85
Feed
rate
g/s
(Ib/h)
0.5
(4.3)
0.5
(4.3)
0.6
(4.6)
0.6
(4.6)
0.6
(4.6)
0.6
(4.6)
0.6
(4.6)
0.6
(4.6)
0.6
(5.0)
0.6
(4.9)
0.7
(5.2)
0.6
(4.5)
0.6
(4.6)
0.6
(4.6)
0.6
(4.6)
0.6
(4.6)
0.7
(5.2)
0.5
(4.3)
Type
1337
1337
1359
1359
1359
1359
1359
1359
B-SONK
B-SONK
B-SONK
1359
1359
1359
1359
B-SONK
1359
1359
Mean
size
urn
(in.)
540
540
490
490
490
490
490
490
440
440
440
555
555
555
550
440
555
490
Feed
rate
g/s
(Ib/h)
0.3
(2.6)
0.3
(2.6)
0.2
(1.7)
0.2
(1.7)
0.2
(1.7)
0.2
(1.7)
0.2
(1.7)
0.2
(1-7)
0.1
(0.42)
0.1
(0.69)
0.1
(0.23)
0.1
(0.53)
0.2
(1.6)
0.1
(1.05)
0.2
(1.5)
0.1
(1.0)
0.1
(0.38)
0.2
(1.6)
Ca/S
ratio
2.2
2.2
2.5
2.5
2.5
2.5
2.5
2.5
2.2
3.65
1.2
1.05
2.9
1.95
2.75
1.9
1.9
2.6
ppm
470
3650
2400
1460
420
420
900
2450
320
250
660
2480
870
1460
840
1300
500
470
ng/J
(lb/106
Btu)
305
(0.71)
2820
(6.56)
1905
(4.43)
1190
(2.77)
305
(0.71)
305
(0.71)
475
(1.11)
1680
(3-72)
205
(0.48)
170
(0.39)
430
(1.00)
1815
(4.22)
645
(1.50)
1085
(2.52)
615
(1.43)
940
(2.18)
320
(0.74)
-
S02
reten-
tion
Z
91.0
17.0
44.0
65.0
91.0
91.0
86.0
53.0
78.0
82.0
55.0
38.0
78.0
63.0
79.0
68.0
66.0
. -
ppm
340
460
250
280
360
430
430
270
350
310
265
240
260
215
240
250
265
390
ng/J
(lb/106
Btu)
195
(0.45)
260
(0.61)
140
(0.33)
160
(0.37)
205
(0.48)
245
(0.57)
245
(0.57)
155
(0.36)
200
(0.47)
175
(0.41)
150
(0.35)
140
(0.32)
150
(0.35)
125
(0.29)
140
(0.32)
140
(0.33)
150
(0.35)
225
(0.52)
o\
-------
TABLE 91 (continued)
Test conditions
Test No.
AR2B
AR2C
AR2D
AR4
AR5A
AR5B
AR3C
AK5D
AR6C
AMER6D
AHER6E
AHER8A
AMER8B
AMER8C
HUMP1A
HUMP1B
HUMP1C
HUMP1D
Bed
temp.
°C
843
(1550)
843
(1550)
843
(1550)
843
(1550)
843
(1550)
843
(1550)
843
(1550)
843
(1550)
843
(1550)
844
(1552)
840
(1544)
841
(1545)
849
(1560)
845
(1553)
783
(1441)
842
(1548)
900
(1650)
791
(1455)
Super-
ficial
.gas
velocity
«/s
(ft/s)
0.76
(2.5)
0.73
(2.4)
0.94
(3.1)
0.85
(2.8)
0.85
(2.8)
0.85
(2.8)
0.85
(2.8)
0.85
(2.8)
2.26
(7.4)
0.80
(2.64)
0.80
(2.64)
0.87
(2.85)
0.91
(2.98)
0.91
D.15)
0.79
(2.60)
0.84
(2.77)
0.86
(2.83)
0.80
(2.62)
Bed
depth
m
(in.)
0.61
(24)
0.61
(24)
0.61
(24)
0.61
(24)
0.61
(24)
0.51
(24)
0.61
(24)
0.61
(24)
0.61
(24)
0.61
(24)
0.61
(24)
0.36
(14)
0.61
(24)
1.17
(46)
0.61
(24)
0.61
(24)
0.61
(24)
0.61
(24)
Gas
resi-
dence
tine
sec
0.80
0.83
0.65
0.71
0.71
0.71
0.71
0.71
0.27
0.76
0.76
0.41
0.67
1.22
0.77
0.72
0.71
0.76
Heating
value
kJ/kg
(Btu/lb)
28,290
(12,163)
28,290
(12,163)
28,290
(12.163)
28,290
(12.163)
28,290
(12,163)
28,290
(12,163)
28,290
(12.163)
28,290
(12,163)
28,290
(12,163)
28,290
(12,163)
28,290
(12.163)
28,290
(12.163)
28,290
(12,163)
28,290
(12,163)
-
-
-
-
Fuel characteristics
Feed
Sulfur Nitrogen Ash rate
I X S g/S
(Ib/h)
3.7 1.18 10.85 °'£
3.7 1.18 10.85 °'|.
3.7 1.18 10.85 £*,
3.7 1.18 10.85 "•*
3.7 1.18 10.85 £*,
3.7 1.18 10.85 (°'*
3.7 1.18 10.85 (°'*
3.7 1.18 10.85 (°'*
3.7 1.18 10.85 (°5'56)
3.7 1.18 10.85 ^^j
3.7 1.18 10.85 (°'^j
3.7 1.18 10.85 (°5'/0)
3.7 1.18 10.85 (°'68)
0.6
3.7 1.18 10.85 (5 Q)
2'4 ~ ~ (4.1)
2'4 - - (°4'.2)
2'4 - - W.I)
'•* - - (°3.58)
Sorbent characteristics
Type
1359
1359
1359
1359
1359
1359
1359
1359
1359
1359
1359
1359
1359
1359
1359
1359
1359
1359
Mean
size
(in.)
490
490
490
490
490
490
490
490
1640
609
609
-
-
-
-
-
-
-
Feed
rate
g/S
(Ib/h)
0.2
(1-7)
0.2
(1.7)
0.2
(1-8)
0.2
(1.6)
0.2
(1.6)
0.4
(3.1)
0.3
(2.4)
0.2
(1.3)
0.4
(3.5)
0.2
(1.8)
0.2
(1.8)
0.3
(2.3)
0.3
(2.4)
0.2
(2.3)
0.2
(1.3)
0.2
(1.4)
0.2
(1.4)
0.2
(1.3)
Ca/S
ratio
2.6
2.6
2.6
2.8
3.0
5.5
4.6
2.5
4.2
2.99
2.94
3.99
4.28
3.98
4.18
4.30
4.45
4.58
ppa
730
1250
850
750
1100
200
160
720
1500
1516
1195
891
751
570
25
380
980
64
Emission characteristics
S02
ng/J S02
(lb/106 reten- ppn
Btu) tlon
X
350
- 300
- - 430
310
- 370
350
- - 440
330
- - 470
(2801) 67 214
J*j 71 264
348
- - 299
352
- 464
- 529
- 610
529
NO
X
ng/J
(lb/106
Btu)
200
(0.47)
170
(0.40)
245
(0.57)
175
(0.41)
210
(0.49)
200
(0.47)
255
(0.59)
190
(0.44)
270
(0.63)
125
(0.29)
150
(0.35)
200
(0.46)
160
(0.37)
200
(0.47)
265
(0.62)
305
(0.71)
350
(0.81)
305
(0.71)
-------
TABLE 91 (.continued)
Test conditions
Test No-
HUMP- IE
HUMP2A2
HUMP2B3
HUMP 3
HUMP3-2
HUMP 4-1
*• HUMP4-2
K-*
oo
HUMP 4- 3
HUMP4-4
HP- 5- A
HP-5-B
HP-5-C
HP-5-D
KP-5-E
HP6A
HP6B
HP6C
HP6D
Bed
temp.
°C
757
UJ',3)
791
(1456)
784
(1443)
789
(1452)
786
(1446)
796
(1464)
783
(1441)
784
(1443)
787
(1448)
718
(1325)
788
(1450)
837
(1538)
784
(1605)
718
(1325)
720
(1328)
782
(1439)
840
(1544)
894
(1642)
Super-
ficial
gas
velocity
m/s
(ft/s)
0.74
(2.42)
0.80
(2.61)
0.78
(2.57)
0.77
(2.53)
0.77
(2.52)
0.78
(2.55)
0.77
(2.51)
0.76
(2.50)
0.77
(2.52)
0.73
(2.40)
0.85
(2,79)
0.88
(2.90)
0.91
(2.99)
0.82
(2.70)
0.79
(2.59)
2.36
(7.73)
0.87
(2.87)
0.93
(3.04)
Bed
depth
m
(in.)
0.61
(24)
0.61
(24)
0.61
(24)
0.61
(24)
0.61
(24)
0.61
(24)
0.61
(24)
0.61
(24)
0.61
(24)
0.61
(24)
0.61
(24)
0.61
(24)
0.61
(24)
0.61
(24)
0.61
(24)
0.61
(24)
0.61
(24)
0.61
(24)
p_ a
re i- Heatln«
, a value
uence . , ,.
tine kJ/kg
sec
0.83 -
0.77
0.78
0.79
0.79
0.78
0.80
0.80
0.79
0.83
0.72
0.69
0.67
0.74
0.77
0.26
0.70 -
0.66
Fuel characteristics
Sulfur Nitrogen
I X
2.4
2.4 -
2.4
2.4 -
2.4
2.4
2.4
2.4
2.4 -
2.4 -
2.4
2.4
2.4
2.4
2.4
2.4
2.4
2.4
Feed
Ash rate
X g/S
(Ib/h)
0.5
(4.0)
0.5
(4.0)
0.5
(4.1)
0.5
(4.0)
0.5
(4.0)
0.5
(4.0)
0.5
(4.0)
0.5
(4.1)
0.5
(4-0)
0.5
(4.0)
0.5
(3.9)
0.5
(3.6)
0.5
(4.2)
0.5
(4.3)
0.6
(4.4)
0.5
(4.0)
0.6
(«•*>
0.6
(5.0) .
Sorbent characteristics
Mean Feed
(in.) (Ib/h)
1359 - (?:23)
»» - (SIS,
1359 - <2:«
1359 ~~ (03)
1359 - ,°'*
0.1
1359 ~~ (03)
1359 - (°''
"» - ("oil)
0.0
(0-0)
0.0
(0.0)
0.0
(0.0)
0.0
(0.0)
0.0
(0.0)
0.0
(0.0)
0.0
(0.0)
0.0
(0.0)
0.0
(0.0)
Ca/S
ratio
4.44
2.67
1.00
1.10
1.28
0.94
0.94
1.00
1.46
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
ppm
276
564
1310
1500
1526
1571
1480
1413
1306
1910
1911
2051
2231
1987
2282
2119
2289
2452
Emission characteristics
S02
ng/J S02
(lb/106 reten- ppm
Btu) tion
- — 447
336
461
- - 486
534
47 531
- 44 506
42 433
- 39 396
- 0 462
- 0 609
0 626
0 601
0 585
0 600
0 684
0 664
0 M2
N0x
ng/J
(lb/106
Btu)
250
(0.50)
195
(0.45)
260
(0.61)
280
(0.65)
305
(0.71)
305
(0.71)
290
(0.67)
250
(0.58)
230
(0.53)
265
(0.62)
350
(0.81)
355
(0.83)
345
(0.80)
335
(0.78)
345
(0.80)
390
(0.91)
390
(0.91)
370
(0.86)
-------
TABLE 91 (continued)
Teat conditions
Fuel characteristics
Sorbent characteristics
Emission characteristics
S02
NO
Test No.
PBY2A
PBY2B
PBY2C
PBY2D
PBY2E
PEABY4
PEABY5
PBY5R
FEABY-6
PBY6K
AMER-333
AHER-333-3
AMER-333-4
Bed
temp.
°C
719
(1326)
788
(1450)
844
(1551)
896
(1644)
788
(1450)
804
(1479)
842
(1547)
843
(1550)
844
(1551)
843
(1550)
799
(1471)
798
(1468)
803
(1477)
super-
ficial
gas
velocity
m/s
(ft/s)
0.73
(2.40)
0.79
(2.60)
0.82
(2.70)
0.85
(2.80)
0.79
(2.60)
0.80
(2.61)
0.82
(2.70)
0.82
(2.69)
0.82
(2.68)
0.92
(3.01)
0.85
(2.79)
0.79
(2.59)
0.78
(2.56)
Bed
depth
(in.)
0.61
(24)
0.61
(24)
0.61
(24)
0.61
(24)
0.61
(24)
0.61
(24)
0.61
(24)
0.61
(24)
0.61
(24)
0.61
(24)
0.61
(24)
0.31
(12)
0.31
(12)
Gag
resi-
dence
time
aec
0.83
0.77
0.74
0.71
0.77
0.77
0.74
0.74
0.75
0.66
0.72
0.39
0.39
Heating
value
kJ/kg
(Btu/lb)
28,290
(12,163)
28,290
(12,163)
28,290
(12,163)
28,290
(12,163)
28,290
(12,163)
28,290
(12,163)
28,290
(12.163)
28.290
(12.163)
28,290
(12.163)
28,290
(12.163)
28,290
(12,163)
28,290
(12.163)
28,290
(12,163)
Sulfur
Z
3.7
3.7
3.7
3.7
3.7
3.7
3.7
3.7
3.7
3.7
3.7
3.7
3.7
Nitrogen
X
1.18
1.18
1.18
1.18
1.18
1.18
1.18
1.18
1.18
1.18
1.18
1.18
1.18
Ash
I
10.85
10.85
10.85
10.85
10.85
10.85
10.85
10.85
10.85
10.85
10.85
10.85
10.85
Feed
rate
g/S
(Ib/h)
0.6
(4.4)
0.5
(4.1)
0.5
(4.2)
0.5
(4.3)
0.5
(4.2)
0.5
(4.0)
0.5
(3.9)
0.5
(3.9)
0.5
(4.0)
0,5
(3.9)
0.5
(4.3)
0.6
(4.7)
0.6
(5.0)
Mean Feed
_ size rate
Type m g/S
(in.) (Ib/h)
0.0
(0-0)
0.0
(0.0)
0.0
(0.0)
0.0
(0.0)
0.0
(0.0)
0.3
(2.1)
1359 - (°'_2)
1359 - u.i)
1359 - °'2
0.1
1JS9 (1.1)
1359 - (l'.7)
1359 - U.5)
1359 - (l'.6)
Ca/S
ratio
0.0
0.0
0.0
0.0
0.0
2.58
2.43
2.89
2.43
3.50
2.75
3.25
ppm
3903
3677
3759
4095
3733
452
649
1169
845
660
1459
1172
ng/J
(lb/106
Btu)
2615
(6.08)
2615
(6.08)
2615
(6.08)
2615
(6.08)
2615
(6.08)
-
-
-
-
-
-
-
-
S02
ret en—
ppn
tion r
0 534
0 649
0 654
0 649
0 672
5
318
294
388
236
121
- 494
203
ng/J
(lb/105
Btu)
305
(0.71)
375
(0.87)
375
(0.87)
375
(0.87)
385
(0.90)
5
(0.007)
180
(0.42)
170
(0.39)
225
(0.52)
135
(0.31)
70
(0.16)
285
'(0.66)
115
(0.27)
vO
-------
100
ro
o
Prsdicmd pant! from
'laboratory Ktto tt»M\
8160 kg/hr (40.000 tb/hr)
Fluidiad-btd Boikr
Sulfur content of cool, 9.5%
Bed temperot«re,850°C
234
Calcium: sulfur mol ratio
0.2 0.4 0.6 0.8 1.0
Ratio of limestone to coal by weight
1.2
Figure 57. Results of SC>2 emission testing at
Renfrew, Scotland FBC boiler re-
ported by B&W, Ltd. (Courtesy of
Babcock Contractors, Inc.)
Bed Temperature, *F
11*2 147* ICS2
It.O* 1 IS«£ | 1562 j
1742
400
^215(0.5)
Firing Coot with I.I % Nitrofl«n
18160 Kg/h (40,000 Ib/h) Boiler
650 700 750 800 850 900 950
Bed ttmp«r»ture, *C
'ESTIMATED
Figure 58. Results of NOX emission testing
at Renfrew, Scotland FBC boiler
reported by B&W, Ltd. (Courtesy of
Babcock Contractors, Lie.)
-------
1400
100
BED TEMPERATURE, °F
1500 1600
1700
90
80
70
z 60
O
P
? 50
Ul
oe
40
to
30
20
10
(RECYCLE)
(NO RECYCLE)
RECYCLE)
- 1.4 m/sec (4.5 ft/sec)
- 0.9 m (36 in.)
- 3.0
- 0.5 kg/kg
- Iowa (4.8 percent sulfur)
Sorbent (uncirclccl pts.) - Illinois limestone Ca/S -3 to 3.7
(8 to 30 mesh)
Sorbent (circled pts.) - Owatonna Dolomite (8 to 3 mcsli)
Superficial velocity
Bed depth (expanded)
Ca/S ratio (limestone)
Sorbent/(.'oal
Coal
RECYCLE NO RECYCLE
ABOVE-BED FEED A o
IN-BED FEED A •
STRINGENT CONTROL
INTERMEDIATE CONTROL
MODERATE CONTROL
3IF- CONTROL
760
816 871
BED TEMPERATURE, *C
927
Figure 59. Sulfur retention data in FluiDyne's 0.46
(1.5 ft * 1.5 ft) FBC unit.11
0.46 m
•421
-------
7.3 TEST METHODS
This subsection delineates the sampling technology and analytical procedures
followed by the individual investigators.
7.3.1 Babcock and Wilcox (B&W) 6 ft x 6 ft Unit17>18»19
Babcock and Wilcox Company of Alliance, Ohio conducted a series of tests
in a 6 ft * 6 ft fluidized-bed combustion boiler in 1978 and 1979. The proie
was established as a cooperative B&W and Electric Power Research Institute (EPRT)
effort to develop sufficient design data and accumulate convincing operating
experience in a pilot scale FBC boiler to justify demonstration and commercia-
lization of atmospheric fluidized-bed combustion (AFBC) boilers. The data
collected in the tests include S02 emissions and particulate loadings at the
cyclone inlet and outlet.
The Furnace Outlet Gas Sampling Probe (Figure 60), through which the SO
data reported in Table 81 were collected, consists of a sheath (cooling jacket:')
around a single-center tube with a quartz liner. The liner extends beyond th
rear of the metal sheath where it connects to a cyclone oven. The cyclone ov
is a heated box containing a glass cyclone, catch bottle, and filter assembly
The probe is operational any time combustion occurs in the 6 ft x 6 ft unit
Gas samples from the probe are drawn through heated sample lines to the
Beckmarr analyzer system in the control room. An NOX analyzer was added to
the gas sampling system for more comprehensive testing during 1979. Details f "
the analyzing systems were not reported. The Cyclone Inlet and Cyclone Outlet
Particulate (Dust) Sampling System consists of a probe, electropneumatic cont
valve, transducer, condenser, vacuum gauge, gas meter, mounting flange, Bug-r^
drive, and vacuum pump (Figure 61). Traversing was performed automatically
®
using the Bug-0 drive unit. Figure 62 illustrates the probe and its inter
422
-------
CYCLONE
OVEN
K9
Co
20" DIA.
FURNACE
OUTLET
DUCT
Figure 60. Furnace outlet gas sampling system for EPRI/B&W
6 ft x 6 ft unit. (Reproduced with permission of EPRI.)
-------
JN
NJ
JS
VACUUM
GAUGE IN
CONTROL
ROOM
ELECTRO-PNEUMATIC
CONTROLLER IN
CONTROL ROOM
BLAST
GATE
VALVE
20" DIA
FURNACE
OUCT
TC TO
DATA ACQ
ISOKINETtC
SENSING LINE
GAS
METER
CONTROL
VALVE CONDENSATE
TRAP
Figure 61. Arrangement of cyclone inlet and outlet dust sampling equipment
for EPRI/B&W 6 ft x 6 ft unit. (Reproduced with permission of EPRI.)
-------
SAMPLE IN
COPPER CLAD
ASBESTOS
GASKETS
N)
en
ISOKINEHC PRESSURE SENOCH
PROBE HEAD
(FILTER CHAMBER)
UNCOOLED
SHEATH
FILTER
Figure 62. Cyclone inlet and outlet dust sampling probe
for EPRI/B&W 6 ft x 6 ft unit. (Reproduced with permission
of EPRI.)
-------
fiberglass filter. It is not clear from available information whether
the probe orientation of this unit or any of the units discussed meets the
requirements of the EPA Reference Methods. The main body of this probe is an
uncooled sheath containing two tubes. The large tube connects the probe to
the condenser while the other connects it to the transducer. This probe is an
isokinetic type, based on null balance techniques. During null balance isokine-
tic sampling, an attempt is made to equalize the static pressure in the sampling
duct and in the probe tip. Maintaining this balance during sampling insures
that a representative (isokinetic) dust sample is taken during testing.
7.3.2 Babcock and Wilcox (B&W) 3 ft * 3 ft Unit20
Babcock and Wilcox has reported results of testing on their 3 ft x 3 ft
fluidized-bed combustion facility during late 1976. The purpose of the B&W
testing was to assess the effect of sorbent particle size on SC>2 absorption.
The data acquired in the tests covers the three major pollutants - SC>2, NO
and particulates.
Emissions were sampled at the inlet of a wet scrubber attached to the unit
Test duration was normally between 6 and 8 hours, and emissions data were ac-
quired after the unit had been equilibrated at the desired operating condition
The following sampling and measurement procedures were normally carried
out:
• Coal feed, sorbent feed, bed material and hopper ash
were each sampled at the start and end of each test;
• Flue gas at the scrubber inlet was sampled and analyzed
for S02> C>2» CO and NOX throughout each test;
Spot measurements of CC>2 and l^S were made at the
scrubber inlet; and
Dust loadings were measured over a five-point traverse
at the scrubber inlet.
426
-------
The following methods of gas analysis for SC>2 and NOX were used:
• S(>2 ~ DuPont Model 411 (light absorption in uv range)
- Barton Model 256 (continuous titration of
S02/H2S with bromine)
- Reich wet chemical spot check (titration of
S02 with potassium iodate)21
• NOX - Teco Model 10A (chemiluminescence from reaction
with ozone).
Sampling of flue gas at the scrubber inlet employed the sampling probe
shown schematically in Figure 63. The probe was lined, with a 7-ram I.D. quartz
tube. The suction rate through the probe was normally 6 to 7 1/min. Water
cooling was not used in all tests. The oven temperature was maintained near
250°F, and the impinger-exit temperature was maintained below room temperature.
Figure 72 shows the overall gas analysis system applied at the scrubber inlet.
The DuPont S02 measurement was supplemented during part of each test by
measurements in the Barton instrument. Comparisons of the different methods
of measurement of S02 at the scrubber inlet were also made. The two methods
of S02 measurement generally agreed within ±12 percent. The scrubber-inlet
S02 measurements in Table 82 are from the DuPont instrument.
Dust loading was measured during each test at the scrubber inlet for
1 hour. A five-point equal-area traverse was made at the scrubber inlet duct.
The probe used to measure dust loading at the scrubber inlet is shown in
Figure 65. The sample gas rate was adjusted to give an isokinetic inlet
velocity.
427
-------
PROBE
---
WATER-COOLED
SECTION
CYCLONE
SEPARA-
SET
FIBERGLASS '
FILTER ! I
I I
DUST COLLECTIO^ j
FLASK . - SURROUNDED BVi
-J LiCEZfeO_aAYfl!
1
•TO GAS
ANALYZERS
ELECTRICALLY HEATED
ENCLOSURE
Figure 63. Gas sampling system employed by B&W
at wet scrubber inlet. (Reproduced with
permission of EPRI.)
(g> 2 - WAY VALVE
© VACUUM CAGE
0 THERMOMETER
[F] HOTAMETER
GAS CONDITIONING
SAMPlf
PHOBt
UMBILICAL
CORD
| CXH-
I lioo% o2
1800 cc/m,n}
NO«
ANALYZtR
CO
ANALYZER
PLANT AIR
«f
I
-f^-,
PRESSURE REGULATOR
PLOW CONTROL VALVE
•Y.PASS LINI
Figure 64. Overview of gas sampling and analysis system employed by
B&W at wet scrubber inlet. (Reproduced with permission
of EPRI.)
428
-------
TO I LOW
Ml ASOMtMtNT
WATtH JACKET PROBt
STAINLESS SIEEl
I 1/,2" OD. 60" LENGTH
9/16" ID 62" LENGTH
L.AS INLtT LINt 3/8" O.D. SS TUBING - 68" LONG
INLH NO.VLI 3/4" OD SS TUBING 1/2" LENGTH - 0.652" I.D
PROBt H/J OUTLET 1/8" SS TUBING
PROBt H2O INLET 1/8" SS TUBING TO WITHIN 1/4" OF END
CONNECTOR LINt b/16" ID TYGON TUBING
CO
HtAI tU FHTtH BOX
(260"H
H 4" UIA FILTEH HOLDEH
I 112 mm GLASS ULTER
103 MICRONI
I 51 tOGfc PIPt ORIFICt
K VACUUM PUMP
SCIENTIFIC GLASS * INST
«8000 2BG4
SCIENTIFIC GLASS & INST. CO.
• 1010-4- 4
S.G I CO *100? -FG4
1/8" ORIFICE IN 1/2" SCH. 40 PIPE
Figure 65. Particulate sampling probe used in B&W investigations.
(Reproduced with permission of EPRI.)
429
-------
7.3.3 National Coal Board - 3 ft x 1.5 ft Unit22'23
Flue gas samples were taken in the stack downstream of the secondary cy-
clone. Three methods for sulfur dioxide and two methods for nitrogen oxides
analysis provided information concerning pollutant concentrations in the flue
gas from the CRE unit. The methods were as follows:
• SOa - Continuous online Hartman-Braun
infrared analyzer.
- The iodine method.24
- The hydrogen peroxide method.
• NOX - A modified Saltzman's method.26
- The BCURA NOX box.27
The iodine method was the standard method used to determine S02 concen-
tration. Flue gas was bubbled through an iodine solution and S02 concentration
was determined colorimetrically. Using the hydrogen peroxide method, flue gas
was bubbled through a solution of hydrogen peroxide and the sulfate produced
was determined gravimetrically by precipitation as barium sulfate. The Hartman-
Braun analyzer was run continuously and all results were compared periodicallv
To determine NOx, a modified Saltzman's method was used by drawing a
sample of S02 free gas into an evacuated 500 ml sample bottle containing 40 nil
of Saltzman's reagent. At 30-min intervals, solution was withdrawn and fresh
reagent was added. This was repeated until the color developed by the solution
was negligible. All of the solution was bulked and the intensity of the color
was measured using a spectrophotometer.
In the BCURA NOX box the S02 free gas is first passed through an oxidizer
in which any NO present is converted to N02- The gas is then passed through
a cell containing a platinum gauze electrode moistened by a wick dipping i
an electrolyte solution in which an active carbon electrode was immersed.
430
-------
A microammeter was used to measure the current through the external circuit
through the electrodes, which varied as a function of N02 concentration.
The data reported are the result of testing Pittsburgh and-Welbeck coals
with limestone 18, dolomite 1337, and U.K. limestone as sorbents. Since the
main test objectives were correlation of parametric effects on emissions with
data obtained in a smaller unit rather than demonstration of operating relia-
bility, no long-term testing was attempted. Typical test duration at steady-
state at a specific set of operating conditions ranged from 2 to 4 hours.
This did not include startup or condition changes.
7.3.A Pope, Evans, and Robbing28 29
The emission test data reported by PER and presented in Tables 84 and 85
were compiled from experiments conducted between 1967 and 1975. Gas samples
were withdrawn from the FBM at the gas passage around the steam drum through
a 7.6 cm (3 in.) diameter welded pipe. A schematic diagram of the sampling
system is shown in Figure 66.
Emissions of 862 and NOX were monitored continuously by infrared (Beckman
Model 215) analysis and periodically checked using methods similar to EPA
Reference Methods 6 and 7.
Particulate emissions were monitored using an isokinetic probe system
at one point. The sampling location was downstream of the multicone collector
and prior to the ID fan (see Figure 71).
The test procedures for the FBM investigations involved igniting the
bed and stabilizing the combustion at the desired bed temperature until steady-
state conditions prevailed. Steady-state was assumed when the Bailey Meter
used for 02 measurement and the S(>2 IR analyzer indicated constant values of
oxygen and sulfur dioxide in the flue gas. At steady-state the sorbent feed
431
-------
NJ
FILTERS
TO
ATMO-
SPHERE
WELDED
CONNECTIONS
LOOP OVER
ROOM
INS
TO IK (S02&NO)
! f. KC
j ANALYZERS
r~Z~ I.D. FAN
INFILTRA-
AIR
ANALYSIS
(WET TESTS)
LDUST
COLLECTOR
WELDED
SEAXS
FLUE GAS FROM
FLUIDIZED BED
FBM
Figure 66. Schematic diagram of gas sampling system used by PER during
FBM experiments.
-------
was initiated or some other operating condition varied and the effect on emission
observed. A period of 30 min, at least, was allowed for a new steady-state
condition after an operating condition change. Each run lasted from 2 to 6
hours.
7.3.5 FluiDyne30>31
Emissions testing equipment used to monitor the 1.5 ft x 1.5 ft unit and
the 3.3 ft x 5.3 ft vertical slice combustor, included the following:
• Gas Composition Measurement Instrumentation
Beckman Model 864 NDIR CC>2 Analyzer
Beckman Model 865 NDIR S02 Analyzer
- Beckman Model 742 02 Analyzer
Fisher Orsat (CO measurement)
DuPont Model 411 S02/NOX Analyzer
• Flue gas Particulate Measurement Instrumentation
Water cooled sampling probe with alumina thimble holder
- Blue M Globar (15 kw) furnace and analytical balance
During sampling of the vertical slice combustor, S02 measurements using the
Beckman Model 865 were checked by including the DuPont Model 411 in the flue
gas sampling system. It is noted that the Beckman unit consistently indicated
flue gas S02 concentrations higher than actual (based on wet chemical tests
and readings from the DuPont instrument), so that reported sulfur retention
levels should be conservative.
7.3.6 National Coal Board - 6-in. Diameter Unit32
Gas samples were withdrawn at a point about 2 ft after each secondary cy-
clone, as appropriate, (see Figure 85), and bubbled through iodine or H202
solution for determination of S02. Samples were also taken for analysis of
02, CO, C02 and CHi+ by gas chromatograph.
433
-------
Each test was carried out as a 1-day (16-hr) run comprising plant startun
approach to equilibrium, a 6-hr mass balance and shutdown.
7.3.7 Argonne National Laboratory (ANL) 33i 3t*. 3S
The data presented in Table 91 was obtained from the ANL 6-in. diameter
atmospheric pressure fluidized-bed combustion unit.
The sampling methods used for the system follow. A continuous stream of
approximately one-twentieth of the total flue gas (0.24 I/sec) was withdrawn
through a 1.3 cm (0.5 in.) diameter stainless steel sample probe from the
upper portion of the bench-scale unit. The gas was dried by passage through
a water condenser and refrigerator. Continuous analysis of NO and SQ2 was
carried out using Beckman 315A infrared analyzers. Figure 67 is a general
schematic of the system.
..THERMOCOUPLES
13-in.
SINTEHEO- NICKEL
BAYONET FILTER
HOTAMETEH
,-\ WATER CONDENSER
PUMP
n OlA BENCH SCALE
COMBUS101
INSTRUMENT
STANDARDS
CAS SUPPL .' V4NIFOLO
PRESSURE CONTROL
AND SOLENOID
CMKOMATOGRAPM
SAMPLE. CH. AMO CO
HEWLETT PACKARD 0«YGf N
GAS CMMOMATOGRAPM
(C0 analyi'i )
Figure 67. ANL gas sampling and analysis system.
434
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7.3.8 Babcock and Wilcox, Ltd.36
Limited information is available on testing procedures at the B&W, Ltd.
unit located in Renfrew, Scotland. The currently available publication indicates
only that NOX was measured using a chemiluminescence monitor.
7.4 DESCRIPTION OF TEST FACILITIES
7.4.1 Babcock and Wilcox (B&W) - 6 ft * 6 ft Unit37 38 39
The B&W 6 ft x 6 ft AFBC unit has four feed points at the spacing of one
feedpoint per 9 ft2 of bed area with allowance for operating with fewer feed
points. The unit was designed to produce steam for heating the Alliance
Research Center (ARC) B&W's research facility. Condensing the steam and re-
cycling treated water back to the unit provides operational cost savings.
Once the overall bed size and steam producing capabilities ^re defined,
the other basic design parameters listed below were established.
6 ft x 6 ft Design Parameters (Nominal)
Bed Area 6 ft x 6 ft
Superfical Velocity 8 fps
Coal Feed Rate 1880 Ib/hr
Heat Rate -7 MWt
Saturated Steam Production 10,000 Ib/hr at 150 psig
Superheated Steam Production 2,000 Ib/hr at 1000°F
Bed Operating Temperature ^1600°F
Figure 68 identifies the major components of the facility. Coal and
limestone are conveyed to the top of the Boiler Room where they are crushed,
then transported either directly to two separate bunkers or through an inter-
mediate screening operation. Coal and limestone from the bunkers are fed
through separate weigh feeders into a common transport line. The feed solids
This unit may be modified to use fewer feedpoints, during 1979.
435
-------
WATER JACKET VENTS
GAS DISCHARGE
STtAM DRUM
SAMPLE POUTS
AIR HEATER '
ASH CONVEYOR
RECIRCULATI3N PUMPS
Figure 68. Fluidized-bed combustion development facility (B&W)
(Reproduced with permission of EPRI.)
436
-------
are picked up by transport air and carried to a splitter where they are separated
into four equal feed streams. These pass up through the windbox and the distri-
butor plate into the combustion zone of the fluidized-bed boiler.
Forced draft air to the fluidized-bed is supplied by a Spencer turbine
centrifugal blower capable of delivering 6,000 cfm at a 60-in. water gauge
head. The combustion air supplied by this fan first passes through a steam
preheater and then through a direct-fired preheater before it diverges into
the four separate ducts entering the windbox. Each of these ducts has a
separate damper and venturi flowmeter for control and measurement.
The initial distributor plate was made of woven Ni-Chrome wire that had
been calendered to obtain a specified pressure drop at a design flow rate per
square foot of bed area (10 in. water pressure drop at 8 ft/sec). Because of
warpage and pluggage problems, the woven wire was replaced with a perforated
distributor plate. This plate is type 316 stainless steel having 0.0938 in.
holes on 0.587 in. square pitch. The distributor plate and windbox are designed
as a unit that can be lowered from 20 in. below (initial position) to 40 in.
below the immersed tube bank.
The main furnace structure of the fluidized-bed test facility consists
of an atmospheric pressure water wall with fireside refractory lining.
The immersed tube bank consists of a serpentine arrangement of 11, 1-1/2
in. O.D- tubes on a 5 in. triangular pitch.
One tube is used as a superheater. The balance of the tube bank consists
Of steam generating tubes which will produce 150 psig saturated steam.
A freeboard of 18 ft is located between the immersed tube bank and the
convective tube bank at the top of the furnace. This height was chosen so
437
-------
that the larger particles thrown out of the bed would return to the bed-
i.e, particles with a terminal settling velocity greater than the fluidizing
velocity would fall back.
The convective tube bank at the top of the furnace serves two purposes.
First, it cools the flue gas before it exits the furnace and enters the cyclone
dust collectors. Second, it produces additional saturated steam for heating
the Alliance Research Center. Space in the center of this tube bank has been
allotted for a sootblower, if one is found necessary.
Four cyclone separators are mounted at the furnace exit to collect par-
ticulates escaping the furnace. Dampers on each of the cyclones can be closed
to maintain reasonable entering velocities and, by so doing, improve collection
efficiencies. Material collected by the cyclones can be recycled to the bed
or removed from the unit by the ash-handling system. Material to be recycled
is fed from the cyclone hoppers through a water-cooled conveyor. After passine
over an inline impact flowmeter, the material passes through a downcomer to
the transport air line in the coal and limestone feed system. The recycle
system as initially designed is capable of recycling only about one-qaar_er of
the carryover back to the combustor. Testing reported in this section was co -
ducted with this recycle capability. The system is currently being modified
to enable full recycle.
The flue gas exiting the cyclones passes through a large venturi flowmete
and then is cooled before entering the induced draft fan which carries it out
the stack.
The boiling water circuit consists of a split steam drum and two recir-
culation pumps which feed the immersed and convective*tube banks. Separat
makeup and blowdown systems are also provided.
438
-------
The spent bed removal system consists of five drain pipes which extend
from the bed through the windbox and the distributor plate to the basement.
Each pipe has a separate shutoff valve controlled by an air cylinder. Initially,
only the center pipe will be used to remove material from the bed. During an
upset condition all of the pipes can be opened to rapidly drain the bed of
solids. The rate of bed removal is controlled by the pressure drop across the
bed. This system can be easily modified so that the control of solids removal
is set either by bed temperature, the input limestone and coal feed rates,
and/or a time sequence.
7.4.2 Babcock and Wilcox 3 ft x 3 ft Unit1*0
The 3 ft x 3 ft unit is a vertical furnace enclosed by an atmospheric
pressure water-jacket. Fluidizing air is supplied to the furnace by a 3,500
rpm fan rated for 4.25 m3/sec (9,000 cfm) at a pressure of 13.7 kPa (55 in.
of water). Coal and limestone are generally crushed, screened, and sized
prior to charging. Coal feed rate can be varied from 90.9 to 1,818 kg/hr
(200 to 4,000 Ib/hr), and limestone feed rate can be varied from 45.4 to 909
kg/hr (100 to 2,000 Ib/hr). Coal and limestone are added to the boiler as a
mixture. A boiler tube bank is positioned in the bed consisting of 8.9 square
meters (96 ft2) of cooling surface. The tubes are cooled by recirculating
cooled water at approximately 1,172 kPa (170 psig). Primary flue gas particu-
i
late removal was provided by a larger water-jacketed cavity in the flue.
During testing, fly ash recirculation was not practiced. The freeboard in this
unit is low and primary collection efficiency is poor so that particulate carry-
over is high. A schematic diagram of the Babcock and Wilcox 3 ft x 3 ft FBC
appears in Figure 69.
439
-------
STEAM
FLUE GAS TO
WET SCRUBBER
///////////////////////////////// / S / /
Figure 69. Schematic diagram of B&W 3 ft x 3 ft test unit.
(Reproduced with permission of EPRI.)
440
-------
7.4.3 National Coal Board 3 ft x 1.5 ft Unit1*1'**2
The Coal Research Establishment (CRE) unit has an internal cross-section
of 0.9 x 0.46 meters (3 ft * 1.5 ft). The height from the air distributor to
the gas off-take was 4.6 meters (15 ft). Coal and limestone were pneumatically
fed in adjacent lines to the center of the bed. Off-gases pass through primary
and secondary cyclones and then to the stack. The primary recycle capability
of the unit was not utilized during the tests for which data is reported.
Fourteen water-cooled tubes of 5 cm (2 in.) inside diameter are included in
the bed. Coal feed rate is variable between 34 to 136 kg/hr (75 to 300 Ib/hr).
A schematic diagram of the boiler is shown in Figure 70.
7.4.4 Pope, Evans, and Robbins FBM Unit1*3
The PER-FBM was intended to represent one-half of a multicell FBC
package boiler. The 1.5 ft x 6 ft rectangular bed was surrounded by vertical
water tubes and an overhead drum. There were no boiler tubes located through
the bed. Flue gas passed around the steam drum. Freeboard in the boiler was
short, the total distance from grid to bottom of steam drum was only 1.6
meters (5 ft, 4 in.). The combustion space was 1.5 m3 (53 ft3) with a pro-
jected heating surface of 7.4 m2 (80 ft2). Boiler capacity is 2,270 kg/hr
(5,000 Ib/hr) steam excluding convection heat transfer and 3,180 kg/hr (7,000
Ib/hr) including convection heat transfer. Pressure rating is 3,070 kPa (300
psi) design and 1,380 kPa (200 psi) normal operation. Coal feed varies between
300 to 400 kg/hr (700 to 900 Ib/hr). A multicone dust collector and hopper
is included which contains 12, 25 cm (10 in.) diameter centrifugal collector
units, a rotary feeder for fly ash reinjection and valve for fly ash removal.
Fly a8^ reinjection was possible as an option, and was employed in a few, but
not the bulk of the tests summarized in Table 84. A schematic diagram of the
FBM appears in Figure 71.
441
-------
Stack
Coal
N3
Condenser
Primary
Cyclone
To Cooling
Tower
>9
eptor
\
\
CL1
CII
D
:)
-•>
k_
tt
0
1
i
2-2
«/>
o
"a.
£
•fl
«
a:
«/i
XI
o
CJ
V
-Steam
Air
Hot Gas Generator
Gas
Incremental ^ incremental
Feed Samples p-Ash Samples-
Ash
Offtake
D
IRAnalyztrs
Gas and Dust Samples
Ash
Sample
Fines Reinjection
Figure 70. Schematic diagram of CRE 18 in. x 72 in. FBC facility
tested by NCB.
-------
STUB STACK
: —-INDUCED DRAFT FAN
ROOF
DRAFT
BALANCE
DAMPER
Co
OUST COLL
HOPPER -
PARTICULATE
SAMPUNO POMT
SAMPLE GAS TO ANALYZERS
J COOLING AIR INLETS
PRESSURIZED
COAL HOPPER'
PREHEATER
BYPASS
ADDITIVE HOPPER.
SCREW FEEDER
OPEN COAL
HOPPER
DUCT
FROM
FORCED-1
OUAFT FAN
TAR FEEDER
ASH RECMCULATION LINE
LMHTOFF
BURNER
INCLMEO SCREW,
PRESSURE SEAL
COAL FEED PORT
COLO AM LINE
SH/ADDITIVE
INJECTION PORT
INLET AM
FROM PRENKATCR
SCREW
DRfVE
Figure 71. Schematic diagram of PER-FBM test facility.
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7.4.5 Babcock and Wilcox, Ltd. Renfrew Unit'1'4
The data reported here was measured at the full-scale unit constructed
by B&W, Ltd., in Renfrew, Scotland. This FBC units was constructed as a retro-
fit of an existing stoker-fired boiler. A schematic diagram of the unit is
shown in Figure 72. The capacity is approximately 12 MWt (40 x 1Q6 Btu/hr) .
Dried coal is conveyed to a storage bunker, from where it falls by gravity
to a service hopper which supplies nine rotary feeders. Coal from these feeders
is pneumatically conveyed into the bed via nine T-shaped feed points. Limestone
and limited recycled fines added similarly.
The uncompartmented bed is 3.1m x 3.1 m (10 ft x 10 ft) and operated
with a fluidized depth of about 0.8 m to 0.9 m (2.6 ft to 3 ft). The distri-
butor plate is made up of short stand pipes which admit air to the bed from the
windbox below. The windbox is compartmented, thus allowing air to be shut off
to sections of the bed independently, causing slumping and allowing turndown.
There are three stand pipes for ash removal from the bed, although only one is
generally used. The ash from this pipe falls into a cooler from where it is
discharged via a rotary valve. Horizontal hairpin tubes are installed within
the bed and provision is made for forced circulation of water from the boiler
drum. For the first test series at a nominal 1.25 m/sec fluidizing velocity
two groups of boiler surface were provided, with an area of uncooled bed
between. In total there were 10 tube loops. The boiler output was up to
10,500 kg/hr of steam. For the later tests at 2.5 m/sec, the number of tube
loops was increased to 24. This increased the boiler output up to 21,000
kg/hr. About 50 percent of the heat absorption is accomplished in the sub-
merged tubes.
444
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COARSE
GRIT ARRESTER
ECONOMISER
^•?ci;r-":i:'-$-':'-'-^-' . i''.
-—^ «"-».*- _ - ~ • i-- • - • r '
PRAT - DANIEL
DUST
0= GRIT REFIRING
COAL
INJECTION
.ASH REMOVAL
CIRCULATING
PUMPS
Figure 72. Schematic of the B&W, Ltd. designed Renfrew unit.
-------
7.A. 6 FluiDyne 1.5 ft x 1.5 ft Unit1*5
This unit was designed and constructed after cold flow testing in a 0.6 m x
0.6 m (24 in. x 24 in.) plexiglass unit and is located at the Fluidyne Medicine
Lake Test Facility. A schematic diagram of the pilot scale combustor is
shown in Figure 73. Either inbed or abovebed feed is possible in this
unit so that the effect of feed orientation on pollutant emissions can be ob-
served. A primary cyclone is included and recycling is possible. Process air
is raised from ambient temperature to 482°C (900°F) in a horizontal tube bundle
heat exchanger located within the bed. It can be operated with or without
preheated combustion air and uses a limestone or dolomite bed for S02 control
Other design operating parameters are:
• Superficial velocity, m/sec (ft/sec): 0.76 to 1.5 (2.5 to 5.0)
• Bed temperature, °C (°F): 788° to 898°C (1450° to 1650°F)
7.4.7 FluiDyne 3.3 ft * 5.3 ft Unit1*6*1*7
This unit was designed based on experience with the 1.5 ft * 1.5 ft unit
It is a vertical slice approximately one-third the size of a full-scale FBC
module, as defined by FluiDyne. A schematic process diagram is shown in
Figure 74. Design/operating conditions are listed below:
Test Combustor and Operating Conditions
Bed size 1.0 m x 1.62 m (40 in. x 64 in.)
Combustor pressure Atmospheric
In-bed heat exchanger Horizontal tube bundle for
heating process air from ambient
to 900°F (482°C) (full-scale tube
length, diameter, packing density,
and flow rate per tube).
Ignition burner fuel Propane
Ignition burner location Inlet to air distribution grid
446
-------
DRAFT
BLOWER
ATOMIZED SPRAY
02 SENSOR
COAL FEEDER
"T^r p-"Jfl f^CONTROLLER
LIMESTONE FEEDER
»
BLOWER
CY-
CLONE
COMBUSTOR
FLYASH
RECYCLE
iiiitiiiiiiiiiiiiniiiiiii
IGNITION BURNER
FLAME SAFETY
SYSTEM
FLOW
CONTROLLED
ASH AND SPEN1
LIMESTONE
PREHEAT
COMBUSTION
AIR
DISCARD
PROPANE
»- SUPPLY
Figure 73. FluiDyne 1.5 ft x 1.5 ft pilot scale FBC combustor.
447
-------
BAG-
HOUSE
OR
PRECIPITATOR
-p-
OO
COMBUSTION AIR BLOWER
CONVEYING AIR
COAL FEEDER
PROCESS AIR BLOWER
FLAME SAFETY SYSTEM
•H>-,
KJ
INDUCED DRAFTi
BLOWER <
PROPANE SUPPLY
ASH AND
LIMESTONE
LEGEND KEY
PC - Pressure Controller
PE - Pressure Element
PS - Pressure Switch
FE - Flow Element
FF - Flow Ratio (Fraction)
FC - Flow Controller
FIC - Flow Indicator Controller
TIC - Temperature Indicating Controller
AE - Analyzing Element
TE - Temperature Element
Figure 74. FlulDyne 3.3 ft x 5.3 ft vertical slice FBC combustor.
-------
Superficial velocity
0.76 ra/sec to 1.5 m/sec
(2.5 ft/sec to 5.0 ft/sec)
Bed temperature
Cyclone for recycling fines
Limestone, dolomite, or inert bed
Multipoint feed
Flue gas 02 level
788° to 898°C (1450° to 1650°F)
(0.83 m2 bed area/feed point)
2 to 3 percent
System Flow Rates and Capacity
Combustion air
Process air
Fuel feed rate
Limestone feed rate
Total heat input
Ash and spent limestone
removal rate
1180 to 2361 kg/hr (2600 to
5200 Ib/hr)
0 to 5766 kg/hr (0 to 12,700
Ib/hr)
57 to 286 kg/hr (126 to 630
Ib/hr)
Varies with fuel sulfur
0.37 to 1.85 MWt (1.25 to 6.3 x
106 Btu/hr)
Varies with fuel ash and sulfur
7,4.8 National Coal Board 6-in. Diameter Unit**8
A schematic diagram of this unit is shown in Figure 75, with approximate
dimensions. The unit was of circular cross-section, constructed of stainless
steel. The whole combustor could be heated electrically by external wall
heaters. These were used for startup and then to maintain a uniform tempera-
ture throughout the freeboard. Air was supplied from a plenum chamber, and
passed through a distributor plate made from a drilled flat plate convered with
three layers of 1 cm (3/8 in.) diameter alumina balls. The premixed coal/additive
449
-------
SO, 0,
Sampling Analyser
0, SO,
Analyser Somphnq
Fines
Catchpots
\
Condenser
Fluidised Bed
Cooling /
Wa»cr Cooling
Reservoir Coil
Vibrator
| Fines
Catchpot
0.43m(l7")
• Fines Return Line
-. Combustor
O.I5m(6
Cool
Hopper
FVeheater
Air
Ash
1.2m (4')
0.3m{|')
l-83m(6')
Figure 75. National Coal Poard 6-in. diameter FBC unit.
450
-------
feed was pneumatically conveyed to the bed, which it entered tangentially,
approximately 1.9 cm (3/4 in.) above the alumina balls. Excess heat was re-
moved by a water-cooled metal coil immersed in the fluidized bed. . The bed
height was maintained constant by emptying surplus ash through a tube in the
center of the distributor.
The gases leaving the combustor could be directed through two alternative
cyclone systems, both comprising primary and secondary cyclones, for operation
with or without fines recycle. With recycle, the primary cyclone was vertically
above the bed and the fines were recycled via a dip-leg.
7.4.9 Argonne National Laboratories 6 in. Unit 33»3tf»35
The Argonne 6-in. diameter atmospheric fluidized-bed combustor (shown
in Figure 76) consisted of two vertical sections of stainless steel pipe. Four
annular chambers (each 6.4 cm high) surround the lower section through which
a mixture of water dispersed in air can be circulated to control heat removal
in each zone. Figure 77 is a simplified piping diagram of the bench-scale
equipment. Fluidizing air, after passing through a preheater at 538°C (1000°F)
enters the reactor through a bubble-cap-type gas distributor mounted on the
bottom flange of the reactor. Auxiliary heaters increase the inert-bed tem-
perature to the coal ignition point. The coal, additive and recycled elutriated
fines are entrained in transport air streams. Variable-drive volumetric screw
feeders on scales are used to meter the solids into the transport air streams.
The entrained solids are introduced into the fluidized-bed at a feed point just
above the gas distributor. The off-gas from the reactor is passed through two
high-efficiency cyclone separators in series and a cloth filter bag to effect
separation of the solids from the gas stream. Provision was made for recycle
of solids separated in the cyclone.
451
-------
-VIEWING PORT
LN-
FLUE GAS
10 CY;:LONt
StPARATORS
AIR-WATER
COOLANT INLET -
FECO POINT FOR COAL.
ADDITIVE, AND
RECYCLED FINES
COMBUSTION
AIM
INLET
-COOLING JACKET
'COOLING JACKET
OPENINGS FOR
THERMOCOUPLE,
PRESSURE TAPS,
AND SOLID
SAMPLING
•OTTOM SOLIDS
TAKE-OFF
Figure 76. ANL 6-in. diameter bench-scale fluidized-
bed combustion test unit.
TO CLOTH
FILTER SAC
-fc AND
VENTILATION
EXHAUST
[ TRANSPORT
"**" AIR
Figure 77. Overall diagram of ANL bench-scale equipment.
452
-------
7.5 SUMMARY OF EMISSION SOURCE TEST DATA
The raw test data presented in Subsection 7.2 is summarized here in tabular
form by pollutant emission; i.e., Table 92 presents S02 data, Table 93 presents
UOx data, and Table 94 presents particulate data. In most cases, emissions in
terms of ng/J (lb/106 Btu) have been estimated by GCA from available data on
flue gas concentrations and FBC operating conditions.
Test series have been grouped by coal type, sorbent type, or sorbent par-
ticle size. Throughout most test series, Ca/S molar feed ratios varied so that
reporting average S02 emission reductions is meaningless. Therefore, only low
and high S0£ emissions recorded during each test series are reported, noting
the applicable Ca/S ratios. This provides a more realistic basis for assessing
those operating conditions which approached or supported the optional control
levels being considered as part of this overall study. On this same basis,
overage emission values are not reported for NOx or particulate emissions.
Table 95 shows the approximate average Ca/S ratios required to meet 75,
85 and 90 percent SOa reduction for the various sets of data in Section 7.0.
These values were estimated by plotting the available data and interpolating
for the optional S02 control levels. Extrapolation to 90 percent S02 control
was necessary for the PER and the B&W 3 ft * 3 ft data. Variance within each
get of data was usually dependent upon the type of limestone and the gas resi-
dence time used. In most cases, the units were operated at other than "best
system" conditions. (See Subsection 7.6 for estimates of Ca/S requirements
using "best system" conditions.) The points in the table represent an average
trend in the data. Listed below are the maximum and minimum values extrapolated
from the data.
453
-------
TABLE 92. AFBC EMISSION SOURCE TEST DATA - S02
Ul
Ac tu
boil
1.9 » • 1.
(6 ft • 6
3 Wt
(J5 * 106
• • toted
l.S m - 1.
(6 ft x b
7 MU, ^
•* tetced
1.9 « - 1.
7 NU
US i 10s
a« testtd
1.9 * - 1.
(6 ft » 6
7 HHt
(J5 * 10*-
tt te»ted
1.9 • x 1.
(6 ft < 6
(25 - 10*
•» teated
1.9 n x 1.
(4 tt * 6
1 )**(
(25 « 10«
•» t cited
1,9 • x 1 .
(6 ft x *
7 HWt
(25 » 10s
aa tetted
I. 9 • • I.
<6 tt « 6
7 MHt
US - I06
«s leiled
al
9 n
U)
Btu)
9 .
ft)
Btu)
9 •
E
Itul
9 .
ft )
Btu)
» •
ft)
Btu)
9 •
ft)
Btu)
9 •
Ft)
Btu)
9 at
fU
Btu)
Control
method
AfBC
Line* ton*
Addition
AFBC
Xiarcacone
Addition
AFBC
Addition
AFBC
Addition
ATBC
Line « Cone
Addition
AFBC
Limtttane
Addition
Liaiaatcxie
Addition
AFBC
Li»«»ttm*
Addition
Heat
(Btu/lb)
28,407
(12,436)
11,242
(11,440)
28,970 ft 30,464
1 .
31 , 589
( i] 590)
31.4J6
(13,570)
29,506
Cli.6*4)
(1^600)
29,7»4
(11,818)
, „ . h a*tb«xt of CecC* duraciaa ti— ! l "u ^l)"1
(hr.) (a«) j^ Hi (0.21)
Sy.ta.
(coRCiauotia)
107,5 133.3
3.2 - 3.47 B.18 - ft 8J BccbMo 3 - 0.48 - 0.51 (0.23) (0.31) t f J 1 - 95.2
Syjtaai
(continuowi)
3.Z9 - 3.39 5.93 - *-8J Bcckatan 4 * O.38 - 0.41 99.9 116.1 t 94.0 - 94,4
Sy^t!*11*
Uontinuoua)
3 . 14 6 . 28 BackaMB 1 - 0 .48 1>3 . 3 133 . } t 93 . 3
Analytii* (0.31) <0.3l>
(cant tnuoui >
1 ** 6.6B BCCRMH 1 • 0.46 Ml. 8 341.8 t 78.8
Aiulytiiv (1.26) (1.26)
Syatn
(coaciauou*)
3.75-3.96 6.M-7.H «.|-^ . - O.W - 0.54 443^ MJ^
3.21 6.12 Mcteaa 2 - 0.56 1,152.4 1,132.4 t 55
An* 1* cine (1.86) (2.86)
Sjr>I«
(co.tinoaii)
M*L|a } Mtcrence
.f<«°"£, °«»»- -IL:-'-
9f d«*ic* ,u *t.d Location
HJt S BtW
Alliance,
Ohio
Ref. 1
Teat l-l
MA S B&H
Alliance,
Ohio
He I I
Tejt 1-2
MA 5 BW
All iance,
Ohio
Ref. 1
T*at 1-3
MA S UW
Ohio
tef. 1
Teat 1-4
NA S BW
Alliance,
Ohio
lef J
Teat 1-5
HA H BiH
Alliance,
Ohio
Ref. 2
Teat 2-1
Alliance,
Ohio
K«f. 2
T«.t 7-2
MA »4H
Alliance,
Ohio
<*f. 2
T*at 2-1
Raurka
Sorbent • <9,525 w (3/8 in.
Lovellville LiMattn*
C./S - 4.22
Sorbcnt • <9,525 IM <3/8 in.
LtMrtUvi.il* Luwttone
4.51 - 4. SO
Sorbent • <9,525 \m O/B in.
LoiMllville LuMiConc
C*/£ * 4.06 - 4.S9
Sorb.M.<9,S25W.(3rt in.
Ca/S • 4.46 - 4.50
Sorbcnt • <9,525 t« tl/* in.
Lowellvill* Liawatone
Ca/& - 4.2
Sorbant • <9,S2S tan (3/6 in.
Lovcllvill* Liawatoei*
C«/S * Z.«9
Lowcllville LiaM»tooe
C«/5 - 2.4 - 3.2
Ct/S - 0
. 0)
* 0)
X 0)
x 0)
« E»
« 0)
-------
TABLE 92 (continued)
Actuel
bollet
• lie
1.9 m * 1.9 •
(6 ft « « tt)
(25 • 10' Btu)
1.9 • - 1.9 •
(6 ft • «. ft)
7 mt
(25 • 10' Itu)
•• tested
1.9 . < 1.9 •
(6 ft * 6 ft)
(25 - 1C* »tu)
(« ft • « ft)
(25 * 10' ttv)
•» tested
1.9 • • 1.9 »
P" (• ft « t ft)
U» 7»t
(j, (25 « 10» It.)
•• tested
1.9 • ' 1.9 •
(6 It • 6 ft)
7 Wt
(25 « 10« leu)
M tested
1.9 e " 1,9 •
(* ft " • ft)
7 H/t
(25 • 10* itu)
•• w«««d
1.9 • " 1.9 •
(« ft " t 11}
7 PW,
(2J • I01 itu)
» tested
Control
•ethod
ATK
llMstone
AFK
Addition
AFIC
Addition
id«"»r
ATK
LlBMtoM
AeVleloe
UK
llrtirtmt
•MitlM
ATK
LIMeteM
Addition
AFK
LlMecom
Addltlfl*
Fuel
Meet
v«lue
(Itu/lb)
29,501
in.ttel
29.WS
(12.S57.)
29.122
(12. ns)
»,M3
(121753)
29.117
I12.il»
29.191
(12.551)
29,321
(U.*07)
ch.rtt.rUtl,. fcl..lo«' „. . IU.1U
te.t »-b.r cett. r»U»c. (»/S«Jlu>> "tott.ol .f!*;™' °™'™' "'" '•"•
( e*tkod ftf te.t. dur.tlon tlM (Ij .fflclency J>;r j end
(br,) (^) ^ ^ Mr^t of ,e,,c. -wore- ,«.tta,
4,54 (,,62 UdaWH 3 - 0.43 - 0.46 41.79) H.9S) - 75. 0 - 76.1 HA H UU
Aa*lycln« AlllMM*.
5y.ltc» Onie.
(coocinuou*) fc*f • 3
Te.it 3-2
3.« 6.05 ercckateui 3 - 0.*J - 0.*» (1,3J> O.37) - 76.17 - 76. 7» NA H 14U
AIM lye lot A- ' f *"c«.
Sy.t* 01, U
(coaclnuoui) Ref • 3
Teat 4-1 ABC
3.77 j.u eWckMU I - 0.4* - &•*« <1-3W <1.W - "-35 - 71. M SA H UW
An* lyxlnc A11 l*>»e« •
SyiCit B«lf . 3
TMI *-l FCH
3. (7 6.12 BMteM 1 - 0.4* - Q.t* »» StS 77.60 - 7ft. 54 NA. H UU
AMlydjet (1.30) (l.H) ~ All! •!.€«,
Sr*t«.» Ohio
(CMitl...MNI.i) Ketf. 3
7«t 4-1 JJK
3.65 T.30 1M1.M.. S - 0.46 - 0.92 770 *M> «2.09 - 69.34 HA *4W
1-MlT*^ (1.7?) (2.21) AlliMC*.
ty*t~ Ohio
(continueuc) *•'• 3
T«>t 4-1 LP
4.24 7.64 UckMn 3 - O.W i,152 1,17* _ M.47 - 60.30 RA MH
^j1»l/*- in,
C./S - 2.58 - j.63
Sorbeflt • <9,S2S u« (3/1 In,
Lowellvlllt Liiiet tone
C«/S * 2.63 - 2.66
$orb*t>C - <9.*25 u> (3/8 In.
LoM*ll*lllc LlMiton*
C./S -
Sorbent * <9,S?) LM (3/4 In.
LwclJvllle LI ...ton*
Ca/S - l.» - 1.41
Sorbent • <»,525 M (3/8 In.
Low«llvllle Limeccoac
C*/S *
Sorbenc • <9,S2S .,• (3/B lr.
Lovetllvlllc Lim*,tM,'
Cc/S * 2.31 - 7.46
-
. • 0)
. . o,
. • 0)
. • 01
. o>
• 0)
» 0>
' 0)
-------
TABLE 92 (continued)
Actual
boiler
siie
1.9 •
(6 ft
7 MUt
(25 •
as te
1.9 m
(6 ft
7!*t
as t«
1.9 m
(6 ft
(25 *
as te
1.9 n
(b ft
7 MUt
(25 -
as te
(t> ft
•P- (25 •
Ln .. t.
(6 ft
7 HUt
(25 •
• 1.
' 6
10*
sted
• 1.
« 6
10*-
• ted
- 1.
• 6
L0«
sted
• 1,
• 6
106
sted
- 6
10*
sted
• 6
106
as tested
(6 ft • 6
7 HHt
(25 -
106
9 *
ft)
Btu)
9 •
ft)
Btu)
9 m
ft)
Btu)
,9 M
ft)
Btu)
ft)
Btu)
ft)
Btu)
ft)
Btu)
Control
•ethod
AFBC
Limestone
Addition
AFBC
Limestone
Addition
AFBC
Limestone
Addition
AFBC
Limestone
Addition
Limestone
Addition
Limestone
Addition
Limestone
Addition
Fuel
Heat
value
(Btu/lb)
29.168
(12.540)
29.368
(12,626)
28,987
(12,462)
29,015
(12,474)
28,791
(12,378)
( 12*. 368)
29 , 11 2
(12,516)
(12)607)
characteristics
Test Niaiber
X S * Ash ""hod of *"»
4.14 7.14 Beckman 2
Analyzing
System
(continuous)
3.89 7.51 Beckman 5
Analyzing
System
( cont inuous)
3.94 7.31 Beckman 5
Analysing
3.85 7.24 (continuous)
4.12 7.68 Beckman 3
Analysing
System
(continuous)
4.22 8.15 Beckman 4
System
(continuous)
4. 02 6.82 ftecbman 4
Analyzing.
System
(continuous)
Analyzing
System
(continuous)
Lonitet Ces t-laelooe* ^ „,,,.„
...raTlon '"IT" C../.-...0 control .,™«°n>y
(hr.) (eec) u>/
0.1,8 615
(l.»3>
0.46 - 0.48 357
(0.13)
0.46 - 0.50 34*
(0.80)
0.40 - 0.41 808
(l.M)
(0.82)
(0.84)
(1.1»
"•* *••"•«' """""
Ml 76.67 - 78.32 NA
(l.M)
477 81.0 - 86.56 NA
(1.17)
610 72.01 - 87.34 HA
(1.42)
1,040 63.61 - 71.78 M
(2.42)
(O.M)
426 64.54 - 86.90 NA
(O.M)
(1.35)
as tested
""""I Uf.r.n««
£:~! -""j-0-
1-»1_ loc-tt™,
supported
IW
Alliance.
Ohio
H.f. 3
T«»t 4-3 DE
BiU
Alliance.
Ohio
Rtf. 3
Teet 5-1
BtH
Alliance,
Ohio
Ref. 3
Teat 5-2
- B6H
Alliance,
Ohio
Kef. 3
Teat 5-3
Alliance,
Ohio
Ref. 3
Teet 6-1 AD
1 BiU
Alliance.
Ohio
Ref. 3
Teet 6-1 EH
Alliance,
Ohio
Ref. 3
Teet 6-1 IK
Sorbent
Lowellv
Ce/S •
Sorbent
Lovellv
Ca/S -
Sorbent
Lowellv
Ca/S -
Sorbent
Lowellv
C«/S •
Lowellv
Ca/S -
Reeiarka
- <9,525 »• (3/8 In.
•llle LlAeatone
2.56 - 2.57
• <9.525 »• (3/8 in.
llle LlfMfttone
3.21 - 3.25
• <9,525 UB (3/8 in.
llle Llawetone
2.47 - 3.61
• <9,525 Mi (3/8 in.
llle Llaeatone
2.38 - 3.64
llle LljeeetoM
1.97 - 3.38
'
Sorbanc • *»,}« urn \jro in.
Lowellvllle Llawatone
Ca/S -
Lowellv
Ca/S -
3.17 - 3.26
llle Llaeetone
3.25 - 3.37
> 0)
" 0)
" 0)
" 0)
"
*
-------
TABLE 92 Ccontinued)
Actual
boiler
• Lie
1.4 • • 1.9 •
(* ft • t> ft)
7 HWt
(25 • 10* Btu)
» te«t«J
) .9 • K 1, 9 »
(6 ft - 6 ft)
(H - 10* Btu)
«• tetted
L.* • - 1 .9 •
(6 ft - 6 ft)
7 Wt
(25 - 10* Btu)
aa teatad
1.9 a • 1.9 m
(6 ft • 6 ft)
7 HUt
US • 10' itu)
aa tcated
(25 - 10s Btu)
aa tasted
1.9 • - 1.9 •
<* ft " 6 ft)
7 MH.
(25 • 106 Btu)
aa ta*t*d
(6 ft - 6 ft)
(25 < 10b Btu)
•a tastad
IWl
Control H«t
HI hod valu*
AF«C }9,«10
llMitone (11,816)
Addition
AflC 29,212
Ll»«.tooc <12!s5»>
Addition
AFBC 29,110
U—.mn. (IJ.Sil)
Addition
ATVC 29,8(5
Ll«««tc* af/J ** °, control
duration tlaw (lb/10* Btu) afficlaney
Lou HUh Av (0.95)
0.41 - 0.46 417 543 70.73 - 78.35 HA
(0.97) (1.31)
<0.52) (0.57)
tUxlM Mf,rwKift
control ""'anj'"'
support**) ^"'io"
H BlU
Alliance,
Ohio
Kmf . J
Teat b-1 LP
Ohio
Kef. »
Teat 4-2 ABC
I MM
Alliance ,
Ohio
Hef. 3
Tast fc-2 DM
N Bttf
Alliance.
Ohio
Kef. 3
Tast 6-2 H.
M UH
Alliance,
Ohio
Kaf. 1
TMC 6-2 HQ
H WV
Alliance,
Ohio
Uf. 3
Teat 6-3 AT
Alliance .
Ohio
l*f. 3
T»t 6-3 GJ
«— -
Sorbcnt - <9.525 urn ()/8 in.
lovcUvllle Liawetonc
Ca/S - 2.53 - J-7S
C*/S - 4.67 - 4.H
Sorbenc - '9,525 um (3/8 in.
IxwcUvilLe Llmeitone
Ca/S -2.36 - 3.67
Sorbmt • <9,525 am (3/B In.
Lovcllvll.a LlMJtone
Ca/S - 2,4* - 2.73
Sorbent • <9.525 in (3/8 In.
Ca/S • 2.59 - 2.69
Sorbent • <9.525 u» (3/8 in.
LovcllvlUe Llatutoae
Ca/S - 2.27 - 2.40
Lowcllvllla Liawatonc
Ca/S - 2.96 - 3.03
- 0>
- 0)
- 0)
- 0)
- 0>
-------
TABLE 92 (continued)
00
*ctfl Control
• la" "*th»d
0.9 - - 0.9 m AFBC
(3 ft • 3 ft) Liweatone
1.75 Ml Addition
(6 . 10* Btu/hr)
as tested
Heat
value
U/k|
(Bcu/lb)
29,375
(12.586)
29,375
(12,5*6)
29,484
(12,676)
29.484
(12.676)
29.484
(12.676)
29,464
(12 676)
29,115
(12,517)
29.115
(12,517)
29.115
(12,517)
29,115
(12.517)
j;;* Jis. !E;i» ";£"• ««$'«*> ""'»"'
""" <"«> u- «i.h ...,.,.t
1.04 9.32 Dupont 4 10 0. 17 - 0.20 400 696 t 66-91
Model 411 (0.93) (1.62)
UV light
absorption
2.86 9.43 1 7 0.17 - 0.62 1,251 1,685 t 13-16
(2.91) O.92)
2.86 9.41 6 10 0.16 - 0.17 585 1,582 t 18-70
(1.36) (1.6ft)
2.86 9.43 4 8.1 0.16 - 0.17 666 1,582 t 18-66
(1.56) (3.68)
2.86 9.41 1 8.) 0.11 - 0,19 791 1,040 * 46-59
(1.84) (2.42)
2.86 9.41 3 12.5 0.14 - 0.21 353 507 t 74-82
(0.82) ( 1 18)
1.12 9.74 1 5.5 0.17 825 t 61
(1.92)
1.12 9.74 1 1.5 0.18 1.543 t 28
(3.59)
J.12 ».74 3 7 0.14 - 0.18 391 1,1*8 • *6 - 82
(0.91) (2.67)
1.12 9,74 3 9 0.13 - 0.17 460 765 t 64 - 79
(1.07) (1.78)
-u,i_-
»«»! °«'°~1 ™'uT"
II j • control Remark*
of device location
supported
MA M BfcW Sorbent • 6,350 vm (1/4 in. « 0)
Alliance, Lowellville L IMS tone
Ohio Ca/S - 0.58 - 2.71
Kef. 4
Sorbent • 6.350 MI (1/4 in. - 0)
Loweltville LUestone
Ca/S - 1.57 - 1.81
Ca/S • 1.11 - 3.51
Sorbent - 1,000 \m (16 M>h) - 0
Lowellville Liuatone
Ca/5 - 0.87 - 1.49
Sorbent • pulverized
Lowellville Li«*»tone
C./S - 2.05 - 2.38
N Sorbent - 44 y, (325 »t«h) - 0
C*/S - 1.68 - 2.18
Sorbent - pulverised
Lowellville Limestone
Ca/S "2.76
Sorbent • 4 M (125 *esh)
Hydra ted Li*e
C*/S -0.99
M Sorfrent • Creer liaeitone
3 size* (8H, 16H, pulv)
Ca/S • 2.70 - 3.94
M Sorbent Grove LiMatone
3 sites
-------
TABLE 92 (continued)
boilvr Control
tize Method
0.91 • 0.48 AFBC
(3 M 1.5) Litmctcone
Addition
AF5C
Liweitone
Addition
AFftC
Live* tone
Addition
AF»C
»OlOMUtC
Addition
AFBC
DolDMiti
Addition
1.5 fc » 6 ft AFK
Dolomte
Addition
^>
*£ "K
^5 ' , . ,too<
Arec
Doloiite
Addition
Heat
T,)U * S S A«h
35,062 2.8 11.5
(15,074)
33,437 1.3 18.2
£I4,375»
15,062 2.8 1J.5
( 15,074)
35.06Z 2.6 13.5
35.062 2,8 13.5
Cli.074)
Ohio Hn. S ufiwa»aed
30.084 4,5 10.7
(12.934)
Ohio No. 4 uflvaihttd
30,084 4.5 10, J
(12,9)4}
Ohio Mo. 8 .invaihad
(•«> .^^ Hijh Av€r.iK.jt
It ^ 4 0.53 - 0-JT 30 79fe •*• 50-98
(0.07) (L.B5)
18 it 0.26 - 0.58 218 t.ft2 * 3« - 72
(.51) (1.12)
ID 8 * 0.26-0.76 9 1 , 054 - H - 100
(0.02) (2.45)
II) 6 J 0.53 - 1.16 .6 4*T t 72 - 99
(0.04) (I. 04)
[ft 5t 0.14 * 9.88 112 575 t 64 - 9J
T (0.26) (1.33)
tl 8 f 0.13 - 0.26 1.369 2,911 •* 2,6 - 54.4
(3.2) (6.8)
IB 3 t 0.13 - 0.26 1,634 2,150 t 211.2 - «
(3.8) (5.0)
1R 3 1 0 13 - 0 26 1 376 2 130 t 28.2 - 54
<1.2t (S.flJ
(1,8) (2.5)
Dciicn HiaiaMBi m9t
coatrol °JaJ°"1 "nil I.B.
ftfdeVi" 'U^"" l&C*ti0n
MA Stiin|.m HC-i-CtE
Teat 1
K«f. 5(6
"A - HC*-C«E
Te«t 3
K*f. 146
NA Sttinjpni NCft-CKE
Teat 1 i 5
Ref. 566
•A StTingent KCt-CU
Teat 4
£«C. S i 6
HA 5triti|tat HC8-CU
T«»t fr
kef. J t 6
** - TEK FBH
VirtLr...
Kf. J
M - rat rw
ff. 7
AlU.TO.lE It,
Tlrglniai
»«(. 7
AluMdrU.
VlriUU
Kef * 7
Roarfct
Li-e.tonc t«
210 MI McdUn
Ca/S - 1.2 - 3.J
U.K. ti*c«toM
300 - 400 M BCdian
Ca/S • I.B - 3.0
Lix«*ton« IS
350 - MO »» Median
CaVS • 1.0 - 6.0
VolMic* 13J1
100 - 130 urn Median
Ca/S - 1.6 - 3.1
Dolomite 133?
875 - 1025 M awdiMi
Ca/S - 2.5 - 5.4
Ca/S ratio: 1. 15 ~ t.75
Natural mine li.Mc»tt>«c
- 2,830 * 1,410 ua
-44 M '
C«/S ratio: 0.72 - 0.98
-44 M
Ca/S ratio: 1.7 for low and
Ca/S • 1.9 reported •idrjng* SO;
-------
TABLE 92 (continued)
Actual
mi- 1 hod
Lift • 6 ft AFBC
Umcvtone
Addition
AFBC
Addition
1 .5 ft • 6 ft AFBC
Dolomite
Addition
AFBC
Dolomite
Addition
JS AFBC
31 Dolomite
W^ Addition
0
1.5 ft « 6 ft AFBC
Line* tone
Addition
AFBC
Limestone
Addition
Lon
H«?al Te«t Number co
value method of teat» dur
kJ/kg * S * A"h (h
(Btu/lb)
Ohio No. 8 unuaahed
10,084 it.*> 10. 7 IR 4
(12,934)
Ohio No. 8 vaihed
11,820 2. ft 7.2 I ft 6
(12,934)
Ohio No. 8 waihed
11,820 2.6 J.2 IR 4
(11,680)
Ohio No. 8 waahed
31,820 2.6 7.1 IR 5
Ohio No. 8 waihed
31,820 2.6 7.2 IR 4
(11,680)
Sewickley coal
Sewlckley coal 4.1-4.5 - IR 2
* 1-4 5 IR *
«••* C" "I/!™ Range of
ml. reaidence (lb/106 Btu) control
ation time ,., <
(!.«>
0.13 - 0.26 521
(1.3)
0.13 - 0.26 267
(0.61)
0.13 - 0.26 464
(1.1)
0.13 - 0.26 629
(1.5)
0.13 - 0.26 679
(1.58)
0.13 - 0.26 473
(1.1)
High Average*
-------
TABLE 92 (continued)
ss
10 ft « 10 it
in ft - 10 ft
1.5 «t " 1,5 ft
1.5 ft - 1.5 ft
1.5 ft « 1.5 ft
1.5 ft « 1.5 f<
3.) ft « 5.3 ft
3.3 ft « 5.3 ft
F»lc
~'~ 3s,
uric
LiMttatt*
Addition
AFK
LiMatona
W>f. 10
».» - B.cloun 3 - 0.*; - - -•*-» U S rlulOyn. H" .
ltedlcl.< Uk.
Tut F.clllty
K«f. 10
4.1 - luksn * - O.k? - - -90-55 U S FlulByni 1«" «
HodEl H; at Flull>p»
HadlelM Lak«
T«at Facility
Kaf . 10 t 12
*.« - kctun 2 - O.t; - - - » - 95 w S rjulDyn. 19" «
Hotlcl H5 at FLuiDyna
TMt Facility
bf. 10 t 12
3.* - kftean 1 - 0.« - tl.l M I FlulOrna U" >
Hotel MS at riulDyu.
Dupogt Itodtclu UV«
Modal all Taat Facility
Hal. 10 1 12
J.» - aactan 1 5OO O.SS-2.0 K> U * Fl«lJ)yM M™ »
Hodal US Vartlcla Slice
Hoall all MI. U > 12
,..rt.
LLwatcwe A
Ca/S - O.B - J.2
Llaeetone B
C*/S - 1.8 - 6.0
IB" Above-bed feed
Ho recycle
IlllnoU LlMBton*
Ca/S Ratio - 3
Ho recycle
tUlnoi* Llaitatoae
Ca/S Ratio • 3
IB" Above-bed f*ed
With recycle
tlllooia LlBMatone
Ca/S Ratio - 3
It" In-bcd f«d
Vltfe recycle
tlllnoia LlaMitoi.*
Ca/S Katlo - 3
IB" Kun Ho. 35
Above-bad feed
With r«cTcl«
44" KO Bour tm»t
In-bad few!
With recycle
Ca/S - 1.7 - 2.4
-------
TABLE 92 (continued)
NJ
A
b<
6 in.
6 in.
t> In.
t. In.
6 In.
6 In.
6 In.
Fuel characteristic*
""J Control Heat
.JIT -«- S-
(Btu/lb)
Dla»«t«r AFBC Illinois Coal 4.4 11. B
Limestone
Addition
Diamter AFBC Welbcck Coal 1.3 IB. 2
Llacaton*
Addition
LlBcaton*
Addition
Staneter AFBC Pittsburgh 2.8 13. S
LlMSton*
Addition
Diaswter AFBC Pittsburgh 2.8 13.5
Limestone
Addition
Di«jtet*r AFBC Uelbeek 1.3 18.2
LiMttont
Addition
Diameter AFBC Illinois Coal 4.4 11.8
LlMiton«
Addition
i . .r n« Emissions*
Test Hu.*.r cont. residence (Jb/lga, , ,
(hrs> (sec) ^ H1|h Aw.rM,t
Iodine Method 4 - 0.67 -
H* ff «ann -
Braua> I.R. and
H20;
Iodine awchod 9 - 0.67 - 1.00 -
Haffskann-
Braua I.R. and
H30?
Kaffmann-
Brausi I.R. and
H;02
Iodine Mthftd 4 - 0.67 ...
U»ff**nn-
Braua I.R. and
HjOj
Iodine Mthod 6 - 0.67 -
iUffMnn-
Braum I.R. and
M2
Iodine Method 1 - 0.67 -
BaffBann-
Braim I.R. and
»2°3
Iodine aethod 10 - 0.67 ...
tUffa*nn-
BrauB I.R. and
"l02
Design M*!'J"i*1 Reference
R.Dg, of contfol "P"0"1 unit 1.0.
control efficiency ?"", *"d
<« <"d«ic' ..PIK,r;.d iw*tion
0-94 HA S NCB 6 In.
DlasMter FBC
Ref. 12
0-97 NA S NCB 6 In.
Dlaaeter FBC
Ref. 12
0-B4 HA S KB « In.
Diavster FBC
Ref. 12
0-88 KA S HCB 6 In.
Diameter FBC
Ref. 12
0-91 HA S NCB b in.
Diameter FBC
Ref. 12
80 NA H NCB 6 In.
Dla»tcer FBC
Ref. 12
0-93 NA S HCB 6 In.
OlaMtar FBC
let, 12
Remarks
U.K. LlMStone
Ca/S - 0-3.2
U.K. LlBittone
Ca/S • 0-2.9
U.K. LlaestOM
Ca/S - 0-2.6
U.K. LiBestone
Ca/S • 0-3.1
Lines ton* 18
Ca/S - 0-2.6
Lie** tout 18
Ca/S -1.9
LlMStone 1359
Ca/S - 0-3.6
-------
TABLE 92 (continued)
Fuel char *ct«r Is tics
1
6 In.
6 In.
6 In.
6 in.
6 In.
6 In.
6 In.
=£ =?
DlM*t*r AFBC
LlsttBtone
Addition
Diuttter AFtC
LisMstone
Addition
Di*BMt«r AFBC
LiMsCone
Addition
OlsMter AFBC
LlMStOM
Addition
DicBeter AFBC
UsMstoae
Addition
IHMMtcr ATK
LiMSCOM
Addition
Di«*eter AFBC
LlBMBtOM
Addition
HMt
value
kJ/k«
(Btu/lb)
28.126
(12.092)
28.482
(12.245)
28.482
(12.245)
28.482
(12,245)
28 475
(12J242)
28.290
(12.16))
27.46J
(11.W7)
T«.c
IS X W -""^
4.63 12.39 tockMfl
t.R. Hodcl
315A
4.M 13.13 hctao
l.>. KxMl
31JA
t.M 13.13 kckiu
I.«. Mntel
315A
t.M 11.13 bcknn
I.R. Itodtl
31SA
*. •* 13.13 Itekau
I.R. Model
31 JA
3.7 10.8 B«ckBK
and ud I.R. ltod«l
4.1 12.01 31JA
1.21 11.07 taclnu
I.R. Nedcl
313A
Looi.it Cu
MuHbcr cont. t.ildmcc
of tt.ta duration !!••
(hrs) (.«) ^
17 - 0.33 430
(1.00)
18 - 0.22 375
«nd (0.87)
0.67
20 - 0.22 170
*nd (0.40)
0.67
19 - 0.67-0.71 140
(0.32)
6 - 0.71 305
(0.71)
12 - 0.41-0.77 615
(1.43)
3 - 0.77-0.80 170
(0.34)
7T* —•• ss,
Ib/lO'.,.) control ..Hci..:,
•ill. A..r.,.' ""•"""
3.29S - 0-87 NA
(7.66)
2.785 - 18-89 HA
(6.98)
3.400 - 0-95 NA
(7.91)
2,820 - 17-96 NA
(6.56)
1,905 - 44-91 NA
(4.43)
1,815 - 38-79 NA
(4.22)
430 - 55-82 NA
(1.00)
~ S:TT
control ^
1*v«1 loc.tlon
•upported
I AML 6 In. Unit
CC T«Bt Scries
Rcf. 13-16
1 AML 6 in. Unit
SACC T«it S«rle«
Rcf. 13-16
S AML 6 in. Unit
SA Test Series
Ref. 13-16
S AML 6 in. Unit
BC T»t Serlec
Ref. 13-16
S ANL 6 in. Unit
IUf. 13-16
H AML 6 la. Unit
AHER Te»t Series
R«f. 13-16
H ANL 6 in. Unit
BRIT Test Scries
IUf. 13-16
1
Rensrks \
LlBttBtone 1337
100 - 1200 u-
Ca/S • 0-5.1
LlMBtone 1359
25» 6OO, 1200. 1400 urn
C*/S - 1.0-3.0
Lis*Bton« 1359
25 and 103 v*
Cs/S - 0-4.2
Tyvochtse Dolonlte
LlMBtonc 1359
LlMBtone 1360
Listtfttone 1337
25 - 615 »•
Cs/S - 0-2.6
490 urn
U/S - 2.5
Lines tone 1359
555 - 609 \im
Ca/S • 1.05-2.99
B-Sonk
Llaestone
440 M*
Ca/S - 1.2-3.65
-------
TABLE 92 Ccontlnued)
6 In.
6 In.
6 In.
*Vari
+T
Sot*;
Actual
boiler
Dlavcter
Dlaaeter
Dta»«ter
•tlon for
d
NA - Hoi
Control Heat
""hod value ^ $ Z Aah
(Btu/lb)
APBC 28.290 *.U 12.08
Llswaton* (12,163)
Addition
AFBC Hutphrcy 2.4
LlMeatone Coal
Addition
AF1C - 2.4
LlMitoa*
Addition
LlMatone (12,163)
Addition
each teat group correlata* with the Ca/S ratio uaad.
P
" *
E Applicable.
Teat V«b*r coat. rwioavc'- /.tTTn • . , control opuonai unlt 1>n_ Re«ark«
•ethod of teat! duratlor. tla» (lb/1° Btu) ""J™ efficient, control -n<|
(hr.) <•«) Low 11(jb A¥er-i/ ' ' of device ^—^ loc.Uo*
BechBan 2 - 0.77 120 9*0 - M - 68 M - AKL 6 In. Unit Liawatonc 1359
IR Model (0.74) (2.18) AH-BBIT Serlaa and B-Sonk
115 A Kef. 13-16 550 • 4 440 •
Ca/S - l.OS - 2.9
BectoM 13 1.71 - 0.83 - - - 39 - 47 NA - ANL ft In. Unit LlMatooe 1339
lit Model HUMP S«rlt* Ca/S - 0.94 - 4.58
315 A ftef. 13-16
Bcetaan 9 - 0.26 - 0.83 --- o HA -AKLila. (tale No SorbenC
IR Model H* S*rl*-« Addition
315 A R*(. 13-16 Ca/S " 0
IR Modal (6.08) ' Paabody Sarlea C«/S - 0 - 4.54
315 A Raf. 13-16
*
e»y» • aachad
-------
TABLE 93.. AFBC EMISSION SOURCE TEST DATA - NOX
Fuel characteristics
kii Control Heat Test
* method value Z Z method
8ize kJ/kg S Ash
(Btu/lb)
1.9 m x 1.9 m AFBC 29,194 4.24 7.64 Becknan
(6 ft * 6 ft) (12,551) I.g.
7 MH,
(24 x 106 Btu/hr)
29,324 4.22 6.57
(12,607)
29,168 4.14 7.14
(12,540)
29,368 3.89 7.51
(12,626)
28,987 3.94 7.31
(12,462)
29,015 3.85 7.24
(12,474)
28,768 4.22 8.15
(12,368)
29,810 3.25 8.02
(12,816)
29,112 4.02 6.82
(12,516)
Longest Missions
^" duration dWlO^Btu)
tests /i,_-\ 7
lnrs' Low High Average*
3 - 112 120 *
(0.26) (0.28)
5-77 112 *
(0.18) (0.26)
5 - 150 163 *
(0.35) (0.38)
2 - 185 *
(0.43)
4 - 150 *
(0.35)
16 - 95 116 *
(0.22) (0.27)
_ . Range of _ ,
Range Deslgn optional Referen«
. , control , unit I.D.
of control ... control .
fl. efficiency . and
1 ' of device . location
supported
NA NA S B&W
Alliance,
Ohio
Ref. 4
Test 4-2
NA NA S E&H
Alliance,
Ohio
Ref. 4
Test 4-3
NA NA S B&W
Alliance,
Ohio
, Ref. 4
Test 5-1
NA NA S B&W
Alliance.
Ohio
Ref. 4
Test 5-2
A-B
NA NA S B&W
Alliance,
Ohio
Ref. 4
Test 5-2
C-F
NA NA S B&W
Alliance,
Ohio
Ref. 4
Test 6-1
Remarks
Fuel N •
1.131
Fuel N =
1.221
Fuel N -
1.14%
Fuel N «
1.22Z
Fuel S -
1.03*
Fuel N -
1.22Z,
1.24Z
1.31Z
(continued)
-------
TABLE 93 (continued)
Fuel characteristics
,c.?a Control Heat
method value
kJ/kg
(Btu/lb)
1.9 m x 1.9 m
(6 ft x 6 ft)
(24 x 106 Btu/hr)
0.9 m « 0.9 m
(3 ft x 3 ft)
1.75 MW
(6 x 106 Btu/hr)
as tested
AFBC 29
(12
29
(12
29
(12
29
(12
29
(12
29
(12
29
(12
29
(12
29
(12
29
(12
29
(12
29
(12
29
,212
,559)
,170
,541)
,815
,818)
,536
,698)
,743
,787)
,770
,799)
,375
,629)
,375
,629)
,484
,676)
,484
,676)
,484
,676)
,484
,676)
,115
J
S
1
2
2
2
2
2
3
2
2
2
2
2
3
.70
.53
.27
.58
.87
.18
.04
.86
.86
.86
.86
.86
.12
Test Kunber
X method °!
Ash te"s
9.
8.
8.
9.
8.
8.
9.
9.
9.
9.
9.
9.
9.
36 Beclunan 17
l.R.
82
14
35
,50 10
,04
32 Teco Model 4
10A
Chemilumin-
escence
43 3
43 6
43 4
43 3
43 3
74 1
(12,517)
29,115
3.12
9.
74 1
(12,517)
T_ .. Emissions
U>"8"t ng/J Range
duration (lb/1°6 Btu) of «?tro1
Low
90
(0.21)
138
(0.32)
10 73
(0.17)
7 47
(0.11)
10 155
(0.36)
8.5 0
(0)
8.5 125
(0.29)
12 5 129
(0.30)
* v '
High Average*
155 * NA
(0.36)
146 * NA
(0.34)
133 * NA
(0.31)
291 *
(0.51)
228 *
(0.53)
236 *
(0.52)
185 *
(0.43)
219 *
(0.51)
5.5 150
(0
.35)
1.5 189
(0
.44)
Design n*e °. Reference
control _ unit l.D.
efficiency c°n r° and
of device eve . location
supported
NA S B&W
Alliance
Ohio
Ref. 4
Test 6-2
NA S B&W
Alliance
Ohio
Ref. 4
Test 6-3
NA S B&W
Alliance,
Ohio
Ref. 5
I-S
I-S
I-S
S
I-S
S
S
Remarks
Fuel N
1.31%
=
1.32%,
1.34%
Fuel N
1.23%
1.24%
Fuel N
0.86%
Fuel N
0.86%
Fuel N
0.76%
Fuel N
0.76%
Fuel N '
0.76%
Fuel N •
0.76%
Fuel N •
1.23S
Fuel N •
1.23%
-
=
=
=
a
(continued)
-------
TABLE 93 (continued)
Fuel characteristics
*c.t"al Control Heat Test Hu"*er
bo"et method value X * method °*
Sl" kJ/kg S Ash "8tS
(Btu/lb)
0.9 • » 0.9 n AFBC 29,115 3.12 9.74 Teco Model 3
(3 ft « 3 ft) (12,517) 10A
1.75 (W Chemllunin-
(6 x io6 Btu/hr) escence
as "Sted 29,115 3.12 9.74 3
(12.517)
0.91 n x Q.46 n AFBC Pittsburgh coal BCURA 6
(36, in. x 18 in.) 35,062 2.8 13.5 NOX box
(15,073)
Pittsburgh coal BCURA 5
35,062 2.8 13.5 NOX box
Pittsburgh coal BCURA 8
35,062 2.8 13.5 NOX box
1.5 ft x 6 ft AFBC Ohio No. 8 unwashed
30,084 4.5 10.7 IR 11
(12,934)
Ohio No. 8 unwashed
30,084 4.5 10.7 11
(12,934)
Ohio No. 8 washed
31,820 2.6 7.2 19
(13,680)
Washed and unwashed 25
Ohio No. 8
tonr ™«* Low
7 176
(0.41)
9 150
(0.35)
t 126
(0.29)
t 191
(0.44)
t 191
(0.44)
87
(0.2)
91
(0.21)
107
(0.25)
107
(0.25)
High Average (I)
262 * NA
(0.61)
219 *
(0.51)
225 * HA
(0.52)
226 *
(0.53)
323 *
(0.75)
216 * HA
(0.50)
187 *
(0.44)
228 *
(0.53)
228 *
(0.53)
Rantte of
Design .7 . Reference
optional
control , unit l.D. _
.... . control . Remarks
efficiency and
of device "="<=* location
supported
MA M-S B4W
Alliance
Ohio
Ref. 5
1-S
NA 1-S HCB-CRE
36 in.
x 18 in.
Ref. 4
I-S NCB-CRE
36 in.
x 18 in.
None-S NCB-CRE
36 in.
x 18 in.
PER FBM
HA S Alexan-
dria,
Virginia
Ref. 8,9
S
I-S
1-S
Fuel N -
1.23X
Fuel N =
1.23*
Coal size
< 1,680 pm
Dolomite 1337
< 1,680 urn
Coal size
< 3,175 vn>
Dolomite 1337
< 3,175 pra
Coal size
< 3,175 um
Limestone 18
< 3,175 nm
Coarse (-2,830
•*• 1,410 urn)
limestone
addition
Fine (-44 urn)
limestone
addition
'
Fine (-44 ym)
limestone
addition
All tests
without sor-
benc addition
(continued)
-------
TABLE 93 (continued)
Fuel characteristics
boiler Control Heat Test *"•*•* cont . (
TOPfhnd vfllye I Z method duration
kJ/kg S Ash cescs (hrs) L,,,,
(Btu/lb)
1.5 ft x 6 ft AFBC Washed and unwashed IR 41 8?
Ohio No. 8 (0-20)
10 ft x 10 ft AFBC - 5.5 - t 11 65
(0.15)
3.3 ft x 5.3 ft AFBC Illinois No. 6 Becknan 1 500 159
3.6 IR (0.37)
Model 865
6 in. diameter AFBC 28,482 4.84 13.13 Beckman 57 - I15
(12,245) IR (0-29)
28,290 3.7 10.85 Becknan 33-5
(12,163) IR (0.07)
Humphrey Beckman 22 - 195
2.4 - IR (0.45)
Emissions
ng/J
lb/106 Btu)
High Average
216 *
(0.50)
200 *
(0.45)
236 *
(0.55)
460 *
(1.07)
585 *
(0.90)
390 *
(0.91)
""I*8 Design ""f' °f Reference
c°n_ control "£££ unitl.D. Renarks
efficiency . . and
"« °f devlce supported lo"tion
S PER FBM All tests
Alexan- with sorbent
dria, addition
Virginia
Ref. 8,9
NA NA S Renfrew, Estimated
Scotland from ppm
Ref. 10 reported
NA NA I-S Fluidyne Express air
Ref. 11, from 30X to
12 130Z
NA NA None-S ANL Fuel N -
Ref. 14-17 1.11Z
SA Series,
SACC Se-
ries and
BC Series
NA NA None-S ANL Fuel N -
Ref. 14-17 1.18Z
AR
Peabody
Series
NA NA None-S ANL
Ref .14-17
HUMP & HP
Series
Averages are inappropriate for these tests due to the variation in test conditions within each series.
Test duration varied from 2 to 4 hours for each set of test conditions.
^Chemiluininescence.
Note: NA - Not applicable.
-------
TABLE 94. AFBC EMISSION SOURCE TEST DATA - PARTICULATE LOADING TO FINAL CONTROL DEVICE
atethod
size
1.9 m . 1.9 m Primary
(6 ft « 6 ft) cyclone
7 m
(25 * 10* Btu/hr)
as tested
Fuel characteristic!
Heat Teal w^mwr
value X X awthod °
kj/kg S A»h t««a
(Btu/lb)
29,506 3.48 6.68 Aa de- 1
(12,694) scribed in
Section
7.3.1
29,500 3.75 6.84 8
(12,600) 2.96 7.25
29,784 3.21 6.32 2
(12,838)
29.508 4.54 6.62 2
(12.686)
29,500 3.76 6.75 11
(12,680)
29,194 4.24 7.64 3
(15,551)
29,200 4.15 6.86 5
(12,560)
29,368 3.94 7.51 5
(12,626)
28,987 3.9* 7.25 6
(12.462)
28,791 4.12 7.68 3
(12,17*)
Longest ag/S"*
duration
(hrs) Low* High* Average
2,750 t
(6.4)
2,710 4,260 t
(6.3) (9.9)
1,850 t
(4.3)
3,224 t
(7.5)
3,323 6,453 t
(7.73)-(15.01>
3,130 3,147 +
(7.28)-(7.32>
3,203 3,431 t
(7.45)-(7.98)
2,042 2,068 f
(4. 75) -(4. 81)
770 1,367 t
2.129 2,206 t
<4.98)-(5.13)
Rang* of
control
nee (alary
to Beet S
control^
(X)
99.5
99.5-99.7
99.3
99.6
99.6-99.8
99.6
99.6
99.4
98.3-99.1
99.4
Range of
control
neceaaary
to meet I
control^
«>
98.4
98.4-99.0
97.7
98.7
98.7-99.3
98.6
98.7
97.9
94.4-96.9
98.0-98.1
Range of
control Opac-
neceaaary ity
to meet H (X)
control!
(X)
96.1 MR
96.1-97.5
94.2
96.7
96.8-98.3 MR
96.6
96.6-96.9
94.7-94.8
86.0-92.1
94.9-95.1
Reference
location
B&W these emission rates represent
Alliance, loadings to a final particulate
Ohio control device
Ref.1,2,3
Test 2-1
Cyclone outlet loadings greater
than 2150 ng/J (5.0 lb/106 Btu)
usually occurred vhen primary
collection efficiency was re-
ported below 75 percent
(continued)
-------
TABLE 94 (continued)
*>
^j
o
~£ <=
size
1.9 m * 1.9 m Primary
(6 ft « 6 ft) cyclone
7 MU
(25 » 106 Btu/hr)
as tested
0.9 m « 0.9 m Integral
(3 ft " 3 ft) low effi-
1.75 HH ciency
(6 x 106 Btu/hr) collector
Fuel characteristics
Heat T«.t *"*"
value X X method °
U/kg S Ash «'"
(Btu/lb)
29,324 3.74 7.50 As de- 16
(12,607) scribed in
Section
7.3.1
29.536 2.27 8.82 12
(12,698)
29,743 2.87 8.50 10
(12,787)
29,375 3.04 9.32 As de- 4
(12,629) scribed in
Section
7.3.2
29,375 2.86 9.43 3
(12,629)
29,484 2.86 9.43 6
(12,676)
29,484 2.86 9. A3 4
(12,676)
29,484 2.86 9.43 3
(12,676)
29,484 2.86 9.43 3
(12,676)
29,115 3.12 9.74 1
(12,517)
29,115 3.12 9.74 1
(12,517)
29,115 3.12 9.74 3
(12,517)
29,115 3.12 9.74 3
(12,517
. Emissions
Long*" »e/J
duration <1W1°6 *»>
^"> Low* High* Av«age
1,638 2,184 t
(3.81) (5.08)
1,961 3,276 t
(4.56)-(7.62)
3,603 3,770 t
(8.38)-(8.77)
10 2,683 3,156 t
(6.24) (7.34)
7 2,253 3,375 t
(5.24) (7.85)
10 2,878 3,689 t
(6.74) (8.58)
8.5 3,078 4.170 -t
(7.16) (9.70)
8.5 5,434 5,765 t
(12.64X13.41)
12.5 6.4S3 7,145 t
(15.01X16.62)
5.5 7,825 t
(18.20)
1.5 4,970 t
(11.56)
7 3,637 10,623 t
(S.«6)(24.71)
9 3,457 15,215 t
(8.04) (35. 39)
Range of
necessary
to Beet S
controlt
(I)
99.2-99.4
99.3-99.6
99.6-99.7
99.5-99.6
99.4-99.6
99.6-99.7
99.6-99.8
99.8
99.8
99.8
99.7
99.6-99,9
99.6-99.9
Bange of
necessary
controlf
97.4-98.0
97.8-98.7
98.8-98.9
98.4-98.6
98.1-98.7
98.5-98.8
98.6-99.0
99.2-99.3
99.3-99.4
99.5
99.1
98.8-99.6
98.8-».7
Range of
control Opac—
necessary ity
control f
93.4-95.1 NB
94.5-96.7
97.0-97.1
96.0-96.6 MR
95.2-96.8
96.3-97.0
96.5-97.4
98.0-98.1
98.3-98.5
98.6
97. B
97.0-99.0
96.9-99.3
Reference
unit l.D. », ,
and Sa-arts
location
'*
Ohio control device. Loadings are
Ref- 4 high because Halted freeboard
ciency permitted substantial
carryover.
(continued)
-------
TABLE 94 (continued)
Fuel characteristics
^J"1 Control Heat Test Vamb"
lill 'echod value * * "ethod teats
slie kj/kg S Ash ""'
(Btu/lb)
18 in. » 72 In. Integral Ohio No. 8 unwashed Isokinetlc
primary stapling
•ultlcone 30 084 4 5 10.7 at one 2
collector (12.934) point down-
primary
multlcone
collector
Ohio No. 8 unwashed
30,084 4.5 10.7 2
(12,934)
Ohio No. 8 washed
31,820 2.6 7.2 2
(13,680)
Ohio No. 8 Hashed
31,820 2.6 7.2 2
(13,680)
Ohio Ho. 8 washed
31,820 2.6 7.2 2
(13,680)
Emissions """*' of *"•* cf """*' °f
Longest na/J control control control Opac- Reference
"nt- (1W106 Stu) necessary necessary necessary ity unit I.D. R— arks
duration UD'1U Btu) to meet S to meet I to meet M (I) and Remarks
(hrs) Lo * Hi h* A control^ control^ control^ location
PER FBM Dolonite 1337 raw
ft . Alexandria, -44 urn
(0.74) (1.62) Ref. 7,8 final fly ash control is
t P y
374* 679* t 96.6-98.1 86.5-93.7 71.3-84.2 NR PER FBM Limestone 1359 raw
(0.8?) (1.58) Alexandria, -44 urn
Virginia
Ref. 7,8
396* 4.94* t 96.7-97.4 89.1-91.3 72.8-78.3 HR PER FBM Llwestone 1337 hydrate
(0.92) (1.15) Alexandria, -44 um
Virginia
Ref. 7,8
383* 602* t 96.6-97.9 88.8-92.9 71.9-82.1 NX PER FBM Limestone 1337 raw
(0.89) (1.4) Alexandria, -44 u«
Virginia
Ref. 7.8
374* 598* t 96.6-97.8 88.5-92.8 71.3-82.0 NX PER FBM Limestone 1359 raw
(0.87) (1.39) Alexandria. -44 vm ,
Virginia
Ref. 7,8
(continued)
-------
TABLE 94 (continued)
^J
N3
Actual
boiler
size
18 in.
x 72 in.
*
+A» ave,
Fuel characteristic;
Control Heat
method value X I
kJ/kg S Ash
(Btu/lb)
Ohio No. 8 washed
31,820 2.6 7.2
(13,680)
B EBlsslo
T"ed **" dc°°r Low* High*
2 327* 473*
(0.76) (1.1)
»stu due to the variation in test conaitions
Range of Range of
. necessary necessary
' to meet S to meet I
Aver...* controlJ control}
Average (x) (x)
96.1-97.3 86.8-90.9
for each test series.
Range of
necessary ity
to Beet M (Z)
control!
(Z)
67.1-77.3 NR
unit I.D.
and
location
PER FBM
Alexan- i,
dria,
Virginia
Ref. 7,8
Remarks
Ume&tone 1359 hydrate
-44 UB
fs - 0.03 ID/106 Btu (12.9 ng/J)
I - 0.10 lb/106 Btu (*3 ng/Jj
M • 0.25 ib/106 Btu (107.5 ng/J)
Note: NA - Not applicable; NR - Not reported.
-------
TABLE 95. AVERAGE Ca/S REQUIREMENTS TO MEET THREE LEVELS OF CONTROL.
EXTRAPOLATED FROM TABLES 81 THROUGH 91*
No.
Unit ID
range of gas
residence time
(sec)
Range of
sorbent particle
size, pm and
limestone type
Ca/S required to meet
75 85 90
percent reduction
Table B&W 6 ft * 6 ft 0.30 - 0.61
< 9,525
Lowellville
Limestone
2.1 3.3 3.8
Table B&W 3 ft * 3 ft 0.13 - 0.24
6,350 x 0 to
pulverized
Lowellville,
Ca(OH)2, Greer
and Grove lime-
stones
3.5 4.0 4.3
Table NCB-CRE
36 in. x 18 in.
0.26 - 1.76
100 - 1,000
Limestone 18,
U.K. limestone
and dolomite
1337
2.6 3.1 3.3
Table Per FBM*
0.13 - 0.26
2,830 - 44
raw and hydrated
dolomite 1337;
raw and hydrated
limestone 1359
2.1
Figure B&W Ltd
Renfrew
Limestone B
Limestone A
1.6 2.0 2.3
4.2 4.9 5.3
Tables NCB 6 in.
diameter
U.K. limestone
Limestone 1359
Limestone 18
2.2 2.7 2.9
Table ANL 6 in.
diameter
0.22 - 0.83
100 - 1,200
Dolomite 1337,
Limestone 1360,
Limestone 1359,
Tymochtee
Dolomite, B-Sonk
2.8 3.3 3.6
*FluiDyne results are not reported. A single Ca/S ratio of 3.0 was used in the
1.5 ft x 1.5 ft data reviewed, and all levels of S02 control were supported
depending on operating conditions. In the FluiDyne vertical slice testing
reviewed, 80 percent S02 removal was obtained at a Ca/S ratio of 2.4 and 1.7,
the lower value corresponding to a longer gas residence time. In one other
3.3 ft x 5.3 ft test run (No. 35), 87 percent S02 reduction was achieved at a
Ca/S ratio of 2.4.
''"Insufficient data to extrapolate to emission levels of 85 and 90 percent reduction
473
-------
** , Minimum Ca/S Maximum Ca/S
removal
75 1.5 5.1
85 1.6 5.2
90 2.2 5.6
In general, the objective of experimental programs to date has been to
characterize emissions as a function of FBC operating conditions. The research
has been primarily exploratory in nature; the FBC units were small, and much of
the testing preceeded the proposal of the EPA Reference Sampling Methods. As
a result, the EPA Reference Methods have not been employed extensively on FBC
units in the past. In addition, previous testing has not generally been con-
ducted at FBC operating conditions designed exclusively for the most cost-
effective means of environmental control. In the very near future, most FBC
testing programs will define, in more detail, performance of FBC at more optimal
conditions for pollution control and will include the use of the EPA Reference
Methods.
The emissions data summarized in the tables are discussed belc.^. No attempt
is made to compare the results of one experimental program to another: i.e.
PER versus B&W, because test conditions and unit designs vary widely. Therefore
the discussion is limited to the results determined by each investigator, And
methods by which the efficiency of pollution abatement could have been enhanced
7.5.1 Babcock and Wilcox Company 6 ft * 6 ft Unit
B&W ran a series of tests during 1978 and 1979 to demonstrate the SOo
control capability of f luidized-bed combustion in their 6 ft x 6 ft unit. The
test series shov that 75, 85, and 90 percent SC-2 reduction is achievable.
Greater than 90 percent S02 removal was also achieved using Ca/S ratios greater
than 4. The results were impressive considering the apparently large limestone
particle size and relatively short gas phase residence time which averaged about
0.5 sec.
474
-------
The NOX data reported in Table 93 all meet 215 ng/J (0.5 lb/106 Btu) the
optional stringent emission guideline. In fact, of 56 data points all but
1 are under 172 ng/J (0.4 lb/106 Btu) and two-thirds are under 129- ng/J (0.3
lb/106 Btu). The data is promising as the B&W unit is one of the larger units
for which data is available and, thus, best represents industrial boiler
capacity. The gas residence times are also slightly lower than those recommended
for best systems, thus, there is a potential for decreasing the NOX emissions
even further.
Other variables during testing were: temperature, from 834°C (1533°F)
to 899°C (1650°F); gas residence time from 0.30 sec to 0.61 sec (as compared
to -0.7 sec, which is currently thought to be appropriate for effective S02
control); fuel ranging in heating value from 28,768 kJ/kg (12,368 Btu/lb) to
31,589 kJ/kg (13,590 Btu/lb); sulfur content from 1.70 percent to 4.54 percent;
and ash content from 5.93 percent to 9.36 percent.
The B&W test series also included two tests during which there was no
sorbent addition. Comparing the dust loading at the cyclone inlet of these
two tests, 4,686 ng/J (10.9 lb/106 Btu), to those tests which did have sorbent
addition, between 6,535 ng/J (15,2 lb/106 Btu) and 11,092 ng/J (25.8 lb/106
Btu) shows the relative amount of particulate elutriation which can be attri-
buted to sorbent addition. If fines recycling were greater, this impact could
perhaps be lessened.
Complete recycling was not possible during this testing because the current
system is designed to recycle only about one-fourth of the carryover. If more
efficient recycling were possible, higher SOa removals could be anticipated at
the Ca/S ratios used, due to higher utilization of calcium.
475
-------
7.5.2 Babcock and Wilcox 3 ft * 3 ft Unit
The 31 tests which B&W reported have been summarized into 10 categories
although no two tests in any one category were actually run under exactly the
same conditions. The type of fuel, type of limestone, and particle size were
used to distinguish the categories. Within these categories the variation in
SC>2 emissions is dependent primarily on the Ca/S molar feed ratio and the lime-
stone particle size. For example, using Lowellville limestone at 6,350 pm x o
(1/4 in. * o), B&W found that S02 reduction increased from 66 to 81 percent as
Ca/S molar feed ratio was increased from 0.58 to 2.71. (increasing the Ca/S
ratio further would produce even greater sulfur capture according to the trend
in the test data.) The data also show that as the particle size is decreased
from 2,380 urn (8 mesh) to 1,000 ym (16 mesh) (for the Grove and Greer limestones)
the sulfur retention increases slightly. Further decrease in particle size
should also increase sulfur retention. However, B&W data shows that the actual
sulfur removal rate is lower for the case of the pulverized limestones. This
decrease is accounted for by particle elutriation which was reported to be
extremely high compared to that noted during addition of larger particles. The
small particles probably elutriated from the bed before reaction with S(>2 could
occur. If the captured carryover had been recycled, better S02 capture may
have occurred. By reducing gas velocity, thus reducing particle elutriation
and increasing gas residence time, a marked improvement in sulfur retention
may have been possible.
The main objective of the testing was to assess the effect of operating
variations on boiler performance and emissions reductions. B&W was also
attempting to reduce required boiler size by increasing gas velocity to 8 ft/
sec with a bed height limit of about 1-1/2 ft. Although the reported S02
476
-------
emissions from this test series generally meet only a moderate S02 control
level at best with the Ca/S ratios used by B&W, this is not surprising since
the gas residence time was fairly low (generally 0.2 sec or less) and the
sorbent particle size was either fairly large (1000 to 6350 vro) or else was
so small ( ~44 vm) that the sorbent elutriated from the bed before it could
completely react. As mentioned in several previous sections, current theory
suggests that improved performance could be achieved if the gas residence time
were increased by a factor of 3 or 4 (e.g., 0.6 to 0.8 sec) and limestone par-
ticles on the order of 500 wn in the bed were used.
Another major contributor to the lower S02 removal efficiencies in the
3 ft x 3 ft unit is the unit's low freeboard (allowing carryover of sorbent
particles before they had adequate time to react with 802), combined with the
lack of recycle of the carryover back to the bed (so that once elutriated,
the sorbent particles did not have any further opportunity to react).
The tradeoffs between designing larger boilers with lower fluidizing
velocities but enhanced S02 capture and staying with current FBC designs are
currently being studied.*
All of the NOX data reported supports an optional intermediate standard
(258 ng/J, 0.6 lb/106 Btu). Seventy percent of the results support the
optional stringent level of control (215 ng/J, 0.5 * 10 Btu). There is no
apparent experimental variable which had a predominant influence on NOX emis-
sion levels in this test program.
*Current designs in fluidized-bed combustion tend to stress crushed stone and
high fluidizing velocity. The impact on overall FBC design features of swit-
ching to pulverized stone and lower fluidizing velocity is currently being
studied by GCA, Gilbert/Commonwealth, and Westinghouse under EPA Contract.
477
-------
The particulate data reported represents the loading at the inlet of a
wet scrubber; hence it is uncontrolled. The 3 ft * 3 ft unit at Babcock and
Wilcox did not include a primary cyclone which is a part of most FBC systems
and used to recycle bed carryover. In addition, the freeboard of this unit
is very limited, resulting in carryover of relatively large particles which are
"splashed" out of the bed, and would not normally be entrained. The low
freeboard, together with the high gas velocities used, contribute to the high
dust loadings prior to the scrubber. Therefore, it is impractical to use the
data to project the control efficiency required of an additional final parti-
culate control device. However, this data is discussed in Section 2.0 because
available particulate data for FBC systems is limited.
7.5.3 National Coal Board 3 ft x 1.5 ft Test Unit
As shown in Table 83 and 84, the test series with Pittsburgh coal and
limestone 18 at a median particle size of 210 ym consisted of nine runs with
Ca/S ratios ranging from 1.2 to 3.3. Sulfur control ranged from 50 percent
with a Ca/S ratio of 2.2 up to 98 percent with a Ca/S ratio of 3.3. The lowest
control level of 50 percent appears out of line because four other runs at a
Ca/S ratio of 2.2 showed retention of sulfur at 76, 81, 83, and 84 percent.
In looking more closely at the data, two factors could have contributed to the
low removal in the one test; a low bed temperature of 749°C; and a large
percentage of very fine particles in the bed material.26 The relatively small
sorbent particle size (about 210 vim mass mean) used in this entire test series
combined with the general absence of recycle, could have resulted in elutria-
tion of much of the sorbent before it had a chance to fully react (at the
velocities of 0.9 to 1.2 m/sec (3 to 4 ft/sec) being used) with no opportunity
(through recycle) for additional reaction time in the bed. This test series
478
-------
was operated, however, with gas residence times (0.53 to 0.77 sec) in the range
being suggested in this report for effective S02 removal.
For the series with Welbeck coal and U.K. limestone at 300 to 400 urn median
particle feed size, sulfur control was not high at the Ca/S ratios used. Re-
tention ranged from 38 percent up to 72 percent with Ca/S ratio at 1.8 and 3.0,
respectively. The trend of the data indicates that if a sufficiently high
Ca/S ratio had been used, support oi optional SC-2 emissions levels may have
been achieved. The gas phase residence time for this test series was quite
low, around 0.3 sec. A residence time of 0.6 sec or greater would have in-
creased S02 retention. In this test series, recycle of the primary cyclone
catch would probably have improved S02 capture.
A series of eight runs with Pittsburgh coal and limestone 18 at 350 to
450 vm average particle size resulted in sulfur retention ranging from 34 up
to 99+ percent. Ca/S ratios ranged from 1.1 to 6.0. Two additional tests
were run at similar conditions with a significantly reduced limestone size
(<125 ym). These tests indicate control of 49 percent at a Ca/S ratio of 1
with the 125 ym sorbent as compared with 34 percent control at similar condi-
tions with the larger particle size. Variations in the series also show that
the best capture efficiency was achieved with the highest gas residence times.
For example, the one run with a residence time of >0.5 sec gave 65 percent
S(>2 removal at a Ca/S ratio of 1.7. The other data points are at conditions
reflecting lower residence times (0.26 to 0.45 sec) and thus do not portray
the calcium utilization that might be possible with residence times of 0.6 to
0.7 sec. Again, recycle of the cyclone catch may be expected to have improved
the S02 capture, especially in the 125 urn cases.
479
-------
Pittsburgh coal and dolomite 1337 at median feed size of 100 to 125 ym
achieved S02 control levels from 72 to 99 percent. In most of these tests,
gas residence time was about 0.5 sec and recycle was not employed. In this
series Ca/S ratios of 2.6 to 3.4 supported control levels of 75 to 85 percent.
In the final run, the Ca/S ratio was set at 1.6 and fines were recycled to the
bed (the only test conducted with recycle). In addition, in the last test a
gas residence time of 1.76 sec was used, which is much greater than in the
other tests and which is possibly greater than would be cost-effective in
commercial practice. An SO2 emission reduction of 99 percent was achieved at
the very attractive Ca/S ratio of 1.6, showing the acute impact of long gas
residence time, and the use of fine sorbent with recycle, on the amount of
sorbent needed to meet high SC>2 capture constraints. The "best system" of SOs
control in AFBC considered in this report envisions a shorter gas residence
time (-0.67 sec) than considered in this last test (and hence a smaller boiler).
Sorbent particle size envisioned is also more coarse (500 pm surface mean)
resulting in less grinding cost for commercial applications. Recycle of
primary cyclone catch is also envisioned in the "best system." A commercial
AFBC system that employed fine sorbent (125 vtm) and high recycle rates, as
suggested by this last test, could be attractive in commercial practice, but
has not been considered explicitly in this report due to the limited data
available on this method of operation.
Another series was run with Pittsburgh coal and dolomite 1337 at a median
size of 875 to 1000 wn. In one run at a Ca/S ratio of 2.6, sulfur retention
was 64 percent. For the rest of the series, retention was in the intermediate
to stringent control range (87 to 93 percent) with Ca/S ratios between 5.0 and
5.4. However, only one measurement showed greater than 90 percent S02 reduction.
480
-------
Once again, the gas residence time is an obvious factor in the calcium utili-
zation. Using approximately the same Ca/S (5.3 and 5.2) at gas residence times
of 0.49 and 0.88 sec, sulfur capture was 88 and 93 percent, respectively.
In reviewing the NCB S02 removal data, it appears that the relatively
low percentage of SC>2 removal in many cases is a combined effect resulting
from the low residence times, small limestone particle sizes combined with
relatively high velocities, and the absence of primary bed recycle. For
example, the median limestone sizes generally range from 200 to 500 ym at an
8 ft/sec gas velocity and 100 ym at 4 ft/sec; the sorbent is probably being
blown out of the bed before it can react completely. Without recycle, there
is no chance for further reaction.
The data that exist are not inconsistent with achieving S02 removal at
levels between 85 to 90 percent. Extrapolating the trends in the data indicate
that under suitable operating conditions, these removal levels could be achieved
(see Figure 88).
As shown in Tables 83 and 84, emissions of NO were reported for three
X
test series: (1) Pittsburgh coal with limestone 18 at <3,175 ym; (2) Pitts-
burgh coal with dolomite 1337 at <3,175 ym; and (3) Pittsburgh coal with dolo-
mite 1337 at <1,680 ym. The low and high emissions in ng/J for these tests
are, respectively, 191 to 323; 191 to 226; and 126 to 225. None of the para-
meters investigated have a strong influence on NOX emissions.
7.5.4 Pope, Evans, and Robbins
The S02 emission test data measured at the FBM is grouped in Table 92 by
coal type, limestone type, and sorbent particle size. Addition of coarse sor-
bents provided a maximum S02 reduction of 54.5 percent at a Ca/S ratio of 1.75
when unwashed high sulfur coal was burned. S02 reduction was increased to 74
481
-------
percent at a Ca/S ratio of 1.7 when raw dolomite 1337 was fed at -44 urn. The
same reduction was attained using raw limestone 1359 at -44 vim and a Ca/S
ratio of 2.0.
Burning washed medium sulfur coal indicates similar SC>2 reductions as a
function of limestone type, Ca/S ratio, and limestone particle size, although
coarse sorbents were not tested with washed coal. The maximum S02 reduction
measured was 82 percent at a Ca/S ratio of 2.2 using raw dolomite 1337. This
was the only case in which an optional S02 control level was supported. Gas
residence times were generally very low (about 0.15 sec) and could account for
results which do not appear optimum. It must be stressed, however, that when
these tests were conducted, support of specific 862 control levels was not the
objective. By extrapolating the data exhibited in the table, one can speculate
that increased Ca/S ratios and increased gas residence time would support inter-
mediate and stringent S02 control levels. The summary table also shows that
the hydrated sorbents did not exhibit greater SC-2 removal capability than the
raw forms.
In interpreting the PER data, it is critical to note that: (1) ga^ resi-
dence times were normally quite low, typically 0.15 to 0.25 sec; (2) sorbent
particle size was either very coarse (-2800, +1400 urn) limiting available reac-
tion surface area, or so fine (-44 ym) that it elutriated very rapidly at the
high gas velocities being employed (3 m/sec (10 ft/sec) or higher); (3) the
freeboard above the fluidized bed was very limited, allowing significant
carryover; and (4) in general, the carryover captured by the cyclone was not
recycled, except in a few cases. All of the factors together contributed to
the relatively low S02 removals observed in the FBM.
482
-------
Referring back to Table 84, it is possible to assess SC>2 test results
based on continuous IR analysis as compared to wet chemical analysis according
to EPA Reference Method 6. In all cases, S(>2 emissions in terms of'ppm are
very close for the two techniques. Differences in reported emissions are
within the range expected based on the precision of either of the two analysis
techniques.
Later testing results burning ewickley coal using Greer and Germany
Valley limestone (see Tables 85 and 92) showed fairly high 862 emissions in
terms of ng/J (lb/106 Btu) although fairly high Ca/S ratios were used. Gas
residence times of about 0.2 sec were used which are not as high as would be
desirable for effective SC>2 removal. It is not possible to calculate reliable
values of percentage reduction due to lack of data, but the maximum reduction
using Greer limestone at a Ca/S ratio of 3.5 is probably in the range of 80
to 85 percent. PER has noted that Germany Valley limestone has a higher calcium
content, but Greer limestone has a more favorable internal structure and more
favorable overall kinetics.
The average NOX emission measured during all the Pope, Evans, and Robbins
FBM testing reported in 1970 was approximately 275 ppm or 175 ng/J (0.4 lb/106
Btu). NOX data was not included in the presentation of results during com-
bustion of Sewickley coal in the FBM. Table 93 shows low and high NOx values
recorded during combustion of unwashed and washed Ohio coals with coarse and
fine sorbent addition. The range of NOx measured is also shown for the overall
testing with and without sorbent feed.
Comparison of NOX measurements based on IR analysis and methods similar
to EPA Reference Method 7 (see Table 84 and emissions reported in ppm) illus-
trates good agreement between the two techniques. Only three of the 16 compari-
sons differ by as much as a factor of 2. Most values are within a range of
483
-------
±10 percent. The larger differences were noted in the first test runs, and
then good agreement was demonstrated as experimentation continued.
Table 94 shows particulate emissions downstream of the multiclone collec-
tor based on the washed and unwashed coal and the different sorbents. Each
test series includes a dust loading measurement with sorbent feed and without
sorbent feed. In all cases, the higher emissions level was associated with
addition of finely divided sorbent. With sorbent addition, the data suggests
that final fly ash control of greater than 90 percent efficiency is required
to achieve an intermediate optional control level of 43 ng/J (0.1 lb/106 Btu).
7.5.5 Babcock and Wilcox, Ltd.
Because limited data were available, a summary tabulation of emissions
data from the Renfrew unit is not included. However, some useful information
can be extracted from the graphical results presented earlier in Subsection
722
/ • *• • fc •
Figure 57 illustrates S02 reduction as a function of Ca/S molar feed
ratio, using two different limestones. It is important to note that S02 emis-
sions reductions greater than 90 percent were achieved burning high sulfur
(5.5 percent) coal using a Ca/S ratio of about 2.5 with a more reactive sor-
bent, but a Ca/S ratio of about 5 would be necessary if the less reactive
sorbent were used.* The curves also illustrate that laboratory scale tests
accurately predict SC-2 reduction in a full-scale industrial boiler.
No details were provided on the specific differences between the two types
nf cn-rhpnf .
of sorbent. .
484
-------
In Figure 58, NOx emissions during combustion of a coal containing 1.1
percent nitrogen are shown as a function of bed temperature. The analyses were
done by the chemiluminescence method. The maximum emission level of 325 ppm
(corrected to stoichiometric conditions) is equivalent to approximately 195
ng/J (0.45 lb/10^ Btu), which supports the optional stringent NOX control level
under consideration.
7.5.6 FluiDyne 1.5 ft x 1.5 ft Unit
FluiDyne reported the results of SC>2 emission testing in this unit at the
Fifth International Conference on Fluidized-Bed Combustion. The data is
important because it demonstrates the effect of feed orientation and primary
recycle. Without primary recycle, S02 removal efficiency with abovebed feed
is inferior to removal efficiency attained with inbed feed at the same Ca/S
ratio (approximately 3). This is caused by the lower sorbent/S02 reaction time
available due to rapid elutriation of small sorbent particles without subsequent
reinjection to the combustor. With recycle and abovebed feed, S02 removal
efficiency improved from less than 70 percent up to 94 percent, at 843°C (1500°F)
and illustrates the impact that recycle has over the range of SC>2 control effi-
ciencies under consideration in this report. With inbed feed and no recycle,
S02 removal dropped from 90 to 83 percent over the temperature range of 793° to
871°C (1460° to 1600°F). SC-2 removal efficiency improved with recycle up to
level of about 94 percent, the same as measured with above-bed feed and
recycle.
These results illustrate that above-bed feed of coal and limestone is
appropriate for efficient S02 control as long as primary recycle is used.
Since abovebed feeding may be simpler and less expensive than inbed feeding,
these results set a favorable precedent in lowering FBC system cost. (This
485
-------
provides support to our contention in Section 4.0 that the cost of "best systems"
of S02 control using FBC can be estimated by assuming abovebed feed with pri-
mary recycle (see Section 4.0)).
7.5.7 FluiDyne 3.3 ft * 5.3 ft Vertical Slice Combustor
The results of two runs are presented here, Run 35, and the 500-hr test
run. The testing was done with Owatonna dolomite in both cases, and high gas
phase residence times (>0.85 sec).
In the 500-hr test (begun September 20, 1977), the objective was to reduce
S02 emissions to below 516 ng/J (1.2 lb/106 Btu), or a control efficiency of
about 80 percent. Therefore, the results should not be interpreted as the
most efficient control possible. Required Ca/S ratios ranged from 1.7 at 796°c
(1465°F) to 2.4 at 718°C (1325°F), both with primary recycle. Although the
gas residence time was longer for the testing at 718°C (1325°F), 1.5 versus
1.0 sec, and the excess air was much higher, 130 percent versus 30 percent, the
Ca/S requirement was probably greater because of the low temperature and inef-
ficient calcining of the available CaCOs- The effect of excess air at 130 per-
cent is uncertain, but it may have allowed for better SC>2 capture thrn vould
have been attained at 718°C (1325°F) if a lower excess air rate were used.
The dolomite particle size was the same at both temperatures, 6350 um x
0 (1/4 in. x 0). Although the average size is not known, it is likely that it
was greater than 500 ym. If so, one could speculate that even better perform
could have been attained at smaller particles sizes.
Run 35 was performed with above-bed feed and recycle using dolomite (6350
ym x 0) and a gas phase residence time of 0.86 sec. An S02 removal efficienc
of 87.2 percent was attained at a Ca/S ratio of 2.38. This lends further sju
port to the ability of FBC to perform efficiently with above-bed feed and
primary recycle.
486
-------
7.5.8 National Coal Board 6-in. Diameter Uni,t
The results of this testing are itemized in Tables 88 through 90, and
summarized in Table 92. Of the three criteria pollutants, only S02 data were
reported. In one series of runs, U.''. limestore was used during combustion
of Welbeck, Park Hill, Illinois, and Pittsburgh coals. Fluidizing velocity
varied between 0.6 to 0.9 m/sec (2 to 3 ft/sec) but in most cases the unit was
operated at 0.9 m/sec (3 ft/sec), s<; that gas phase residence time was generally
0.67 sec, based on an expanded bed depth of 0.6 m (2 ft). NCB forwarded two
possible explanations to account for the better results obtained during Welbeck
coal combustion. First, NCB found that the total rate of sulfur release from
Welbeck coal was more rapid than for Pittsburgh coal (the other two coals were
not tested). This may have minimized the quantity of sulfur released from
elutriated fines in the freeboard, where reaction with sorbent is inefficient
A second explanation was that because of the low feed rate of sorbent with
low sulfur Welbeck coal, the bed residence time of coarse sorbent particles
may have been longer. S02 emission control performance was excellent regard-
less of coal type in this set of experiments. Except for one experimental case,
90 percent S(>2 removal was achieved at a Ca/S molar feed ratio of 3 or less.
This is not surprising since the actual operating conditions corresponded closely
with "best system" operating conditions. U.K. limestone was prepared to a
median particle diameter of 537 Mm so that average in-bed particle size was
probably close to 500 \m or slightly less.
Another set of experiments was run with limestone 1359 and Illinois coal.
S02 reduction was improved when bed depth was expanded to 0.9 m (3 ft) from
0.6 m (2 ft), as would be expected. Use of finely crushed (-125 ym) limestone
also improved performance, although primary recycle is absolutely essential in
487
-------
this operating mode to control the high sorbent elutriation rate. The overall
results indicate that limestone 1359 was less effective than U.K. limestone in
controlling SC>2 emissions. This result is expected since the reactivity of
limestone 1359 is less than average.
A final set of experiments was reported for the NCB 6-in. test unit using
limestone 18 with Pittsburgh (five tests) and Welbeck (one test) coals. Lime-
stone 18 proved more effective with Pittsburgh coal than did U.K. limestone.
The one test with Welbeck coal indicated performance similar to testing with
U.K. limestone. The major difference in this series of tests was that limestone
was finely crushed to a median size of 207 urn.
SC>2 removal performance was generally good in all three sets of experiments.
This results from the proximity of operating conditions to recommended "best"
operating conditions.
7.5.9 Argonne National Laboratory (ANL)
The results of testing on the ANL 6-in. unit are tabulated in Table 96 and
summarized in Tables 92 and 93. S02 and NOX data are reported.
Although the unit is small and the data was generated between 1970 and
1973, it is quite comprehensive and still useful.
The data demonstrates the ability of FBC to operate at the "best system"
conditions and achieve very good 862 reduction results with reasonably low
Ca/S ratios. The information also illustrates that for the same unit using the
same Ca/S ratios, the reduction efficiency can vary widely with relation to
the gas phase residence time.
488
-------
The NOV data on the other hand is not as representative of the actual
X
values expected from larger units. The values appear considerably higher than
data from the B&W 6 ft x 6 ft unit and the Renfrew unit (the two largest units
for which data is reported). Even so, more than two-thirds of the data listed
is below 301 ng/J (0.7 lb/106 Btu) , the moderate level of control.
The majority of the tests were run with gas residence times between 0.66
and 1.00 sec. Two of the test series were run'at 0.22 and 0.33 sec. Tempera-
tures ranged from 718° to 900°C (1325° to 1650°F). Most tests were run using
limestone 1359 with relatively small average particle sizes. Variations in
sorbent included, dolomite 1337, limestone 1360, Tymochtee dolomite and a
British sorbent referred to as B-Sonk. Ca/S ratios varied from 0 to 5.1 with
the majority between 1.5 and 3.0. The figures in Subsection 7.6 show some of
the ANL data used to extrapolate necessary Ca/S ratios for the 75, 85, and 90
percent control levels at close to "best system" conditions.
7.6 DERIVATION OF Ca/S RATIOS PRESENTED IN SECTION 3.0 FOR "BEST SYSTEM"
OF S02 EMISSION REDUCTION
The Ca/S ratios presented in Table 22 in Section 3.0 were estimated by
GCA from summary graphs of S02 reduction data which has been presented in
tabulated form. The graphs are shown in this subsection, and are based on
experimental results obtained from test units operated at or near "best system"
conditions. A tabulation of important operating parameters is inset into each
graph along with the interpolated Ca/S ratios at the optional 862 control
levels. An index of graphs is listed below:
A. Figure 78 - Argonne National Laboratory, 6-in. diameter
test unit using limestone 1359, 25 pm average
particle size.
B. Figure 79 - Argonne National Laboratory, 6-in. diameter
test unit using limestone 1359, 177 ym x 0
particle size distribution.
489
-------
C. Figure 80 - National Coal Board, 36 in. x 18 in. diameter
combustor using limestone 18, 1680 \m x 0
particle size distribution.
D. Figure 81 - Argonne National Laboratory, 6-in. diameter
test unit using calcined limestone 1359, 25 \m
average particle size.
E. Figure 82 - Argonne National Laboratory, 6-in. diameter
test unit using limestone 1359, 490 to 630 ym
average particle size.
F. Figure 83 - National Coal Board, 36 in. x 18 in. combustor
using dolomite 1337, 1680 x 0 ym particle size
distribution.
G. Figure 84 - National Coal Board, 36 in. x 18 in. combustor
using limestone 18, 1680 x 0 ym particle size
distribution.
H. Figure 85 - National Coal Board, 6-in. diameter test unit
using U.K. limestone, 125 ym x 0 particle size
distribution.
I. Figure 86 - National Coal Board, 6-in. diameter test unit
using limestone 1359, 1680 ym x 0 and 125 ym x 0
particle size distribution.
J. Figure 87 - National Coal Board, 6-in. diameter and 36 in.
18 in. combustor using limestone 18, 1680 ym
particle size distribution.
K. Figure 88 - Argonne National Laboratory and National Coal
Board, 6-in. diameter test units using U.K.
limestone.
L. Figure 89 - Argonne National Laboratory and National Coal
Board, 6-in. diameter test units using limestone
1359.
7.7 COMPARISON OF EXPERIMENTAL DATA WITH WESTINGHOUSE S02 REMOVAL
KINETIC MODEL
7.7.1 Westinghouse Studies
Westinghouse has compared experimental FBC S02 removal measurements with
their projections of Ca/S requirements to confirm the S02 removal model. They
concluded from their computerized file of FBC data that thennogravimetric
projections are representative for the limited bench scale and pilot plant
490
-------
100
90
80
70
60
2 so
40
(Nl
O
<0 30
20
10
1.0
2.0 3.0
C«/S ratio
4.0
INVESTIGATOR'
ARGONNE NATIONAL
LABORATORY
F8C UNIT DESIGNATION' 6" DIAMETER BENCH SCALE
SORBENT: LIMESTONE 1359
APPROXIMATE REACTIVITY- LOW
PARTICLE SIZE > 25^m AVERAGE
TEMPERATURE, *C (»F) ' 843-871 (1550-1600)
GAS PHASE
RESIDENCE TIME, ««condt' 0.67
SORBENT REQUIREMENTS FOR OPTIONAL SO? CONTROL
LEVELS BASED ON THIS DATA*
% REMOVAL 75 78.7 83.2 83.9 83 90
Co/S ratio, 2.4 2.7 3.1 3.2 3.4 4.2
Figure 78. Argonne National Laboratory, 6-in. diameter test
unit using limestone 1359, 25 urn average particle
size.
491
-------
100
90
BO
60
2 ,o
O
O
(VI
O
40
30
20
10 •
JL
1.0
2.0
Co/S
3.0
4.0
rotio
INVESTIGATOR*
AR60NNE NATIONAL
LABORATORY
FBC UNIT DESIGNATION' 6" DIAMETER BENCH SCALE
SORBENT' LIMESTONE 1359
APPROXIMATE REACTIVITY' LOW
PARTICLE SIZE' 177 ^m xO
TEMPERATURE,»C (*F)' 843-871 (1350-1600)
GAS PHASE
RESIDENCE TIME, Mcondi' 0.67-0.7
SORBENT REQUIREMENTS FOR OPTIONAL SO? CONTROL
LEVELS BASED ON THIS DATA:
% REMOVAL
Co/S ratio,
73
2.5
78.7
2.7
83.2
2.9
83.9 85
3.0 3.1
90
3.6
Figure 79. Argonne National Laboratory, 6-in. diameter test unit
using limestone 1359, 177 urn x 0 particle size distribution.
492
-------
100
9O
ao
70
60
2 so
CM
40
30
20
10
J_
1.0
2.0
Co/S
3.0
4.0
rotio
INVESTIGATOR'
NATIONAL COAL
BOARD
FBC UNIT DESIGNATION' 36" x 18" COMBUSTOR
SORBENT: LIMESTONE IB
APPROXIMATE REACTIVITY' HIGH
PARTICLE SIZE' 1680/im xO
TEMPERATURE, •€(*?)' 849(1560)
GAS PHASE
RESIDENCE TIME, »«cond«' 0.58
SORBENT REQUIREMENTS FOR OPTIONAL S02 CONTROL
LEVELS BASED ON THIS DATA:
% REMOVAL
Co/S rotio,
75
1.9
78.7
2.0
83.2
2.3
83.9
2.4
85
2.5
90
3.1
Figure 80. National Coal Board, 36 in. x 18 in. diameter
combustor using limestone 18, 1680 ym x 0
particle size distribution.
493
-------
100
V
w
a.
60
TO
60
2 50
o
o
bJ
X.
CJ
O
40
30
20
10
1.0
? 0
Co/'
3.0
4.0
ratio
INVESTIGATOR'
ARGONNE NATIONAL
LABORATORY
FBC UNIT DESIGNATION' 6' DIAMETER BENCH SCALE
SORBENT' CALCINED LIMESTONE 1359
APPROXIMATE REACTIVITY: HIGH
PARTICLE SIZE' 23^m AVERAGE
TEMPERATURE, 'C CF) ' 871 (1600)
GAS PHASE
RESIDENCE TIME, stcondi' 0.67
SORBENT REQUIREMENTS FOR OPTIONAL S02 CONTROL
LEVELS BASED ON THIS DATA:
*/• REMOVAL
Co/S ratio,
75
Z.O
78
2.
.7
0
83
2.
.2
1
83
2.
.9
1
85
2.2
90
2.3
Figure 81. Argonne National Laboratory, 6-in. diameter test
unit using calcined limestone 1359, 25 ym average
particle size.
494
-------
100
PITTSBURGH COAL
ILLINOIS COAL
INVESTIGATOR'
ARGONNE NATIONAL
LABORATORY
FBC UNIT DESIGNATION' 6" DIAMETER BENCH SCALE
SORBENT' LIMESTONE 1399
APPROXIMATE REACTIVITY' LOW
PARTICLE SIZE ' 490 -630 p.m AVERAGE
TEMPERATURE,*C(*F)' 871 (1600)
GAS PHASE
RESIDENCE TIME, seconds: 0.5-0.7
SORBENT REQUIREMENTS FOR OPTIONAL SO? CONTROL
LEVELS BASED ON THIS DATA
% REMOVAL
Co/S ratio,
75
2.1
78.7
2.5
83.2
2.7
83.9
2.8
89
3.0
90
3.9
Figure 82. Argonne National Laboratory,, 6-in, diameter test
unit using limestone 1359, 490 to 630 urn average
particle size.
495
-------
100
90
80
70
60
40
CNJ
O
CO 30
20
10 •
TEST
234
Co/S ratio
INVESTIGATOR' NATIONAL COAL BOARD
TEST' A
FBC UN.T DES.GNAT.ON. cWiUSTO
SORBENT' DOLOMITE 1337
APPROXIMATE REACTIVITY' HIGH
PARTICLE SIZE' 1680/imxO
TEMPERATURE, «C CF) ' ""-^o-.seo)
GAS PHASE
RESIDENCE TIME, tccondi: 0.9
SORBENT REQUIREMENTS FOR OPTIONAL SO?
LEVELS BASED ON THIS DATA
% REMOVAL 75 78.7 83.2 83.9 65 90
Ca/S ratio,
TEST A 2.6 3.0 3.3 3.3 3.4 3.8
TEST B 16 1.9 2.2 2.3 2.3 2.6
B
36" x 16"
COMBUSTOR
DOLOMITE 1337
HIGH
1680am iO
749-849
(1380-1560)
1.86
CONTROL
Figure 83. National Coal Board, 36 in. * 18 in. combustor
using dolomite 1337, 1680 x 0 ym particle size
distribution.
496
-------
i
100
90
80
7O
60
1 50
o
a
UJ
ac
(VI
O
40
30
20
10
TEST
234
Co/S ratio
INVESTIGATOR' NATIONAL
TEST'
PBC UNIT DESIGNATION'
SOR8ENT'
APPROXIMATE REACTIVITY
PARTICLE SIZE'
TEMPERATURE, •C(*F)<
GAS PHASE
RESIDENCE TIME, •»cond«<
COAL BOARD
A
3«" DIAMETER
COMBUSTOR
LIMESTONE IB
! HIGH
16 80 urn x 0
799-849
(1470-1560)
0.3
SORBENT REQUIREMENTS FOR OPTIONAL SO*
LEVELS BASED ON THIS DATA
% REMOVAL 75 78.7 83.2 83.9 85 90
Co/S ratio,
TEST A 2.1 2.3 2.7 2.7 2.8 3.2
TEST B 1.8 1.9 2.2 2J 2.3 2.6
B
36" DIAMETER
COMBUSTOR
LIMESTONE IB
HIGH
1680 urn xO
799-849
(1470-1560)
0.67
CONTROL
Figure 84. National Coal Board, 36 in. x 18 in. combustor using
limestone 18, 1680 x 0 ym particle size distribution,
497
-------
100
90
SO
70
•>
ex
60
50
O
UJ
(E 40
CM
O
V)
30
20
10
0
WELBECK COAL
J_
1.0 2.0 3.0
Ca/S mol ratio
4.0
INVESTIGATOR'
NATIONAL COAL
BOARD
F8C UNIT DESIGNATION' 6" COMBUSTOR
SORBENT> U.K. LIMESTONE
APPROXIMATE REACTIVITY: HIGH
PARTICLE SIZE > 129 pm * 0
TEMPERATURE,'C('F)' 799-(1470)
GAS PHASE
RESIDENCE TIME, second*: 0.67
SORBENT REQUIREMENTS FOR OPTIONAL S02 CONTROL
LEVELS BASED ON THIS DATA
% REMOVAL
Ca/S ratio,
75
1.6
78.7
1.8
83.2
2.0
89.9
2.0
85
2.1
90
2.4
Figure 85. National Coal Board, 6-in. diameter test unit using
U.K. limestone, 125 ym x o particle size distribution,
498
-------
100
90
ao
70
60
40
CJ
O
V) 30
20
10
TEST C
TEST B
1.0
2.0
Co/S
3.0
4.0
ratio
INVESTIGATOR ' NATIONAL COAL BOARD
TEST' A
FBC UNIT DESIGNATION: 6" DIAMETER
COMBUSTOR
SORBENT' LIMESTONE 1339
APPROXIMATE REACTIVITY' LOW
PARTICLE SIZE' 1680 /im x 0
TEMPERATURE, »C HO ' 799(1470)
GAS PHASE
RESIDENCE TIME, t«eond«= 0.67
SORBENT REQUIREMENTS FOR OPTIONAL SO*
LEVELS BASED ON THIS DATA
% REMOVAL 75 78.7 83.2 83.9 83 90
Co/S ratio,
TEST A 2.8 3.0 3.4 3.5 3.5 3.8
TEST B 2.3 2.4 2.7 ^7 2.8 3.3
TEST C 2.0 2.3 2.7 2.7 2.8 3.5
B
6" DIAMETER
COMBUSTOR
LIMESTONE 1339
LOW
1680 /im xO
799 (1470)
1.00
CONTROL
C
6" DIAMETER
COMBUSTOR
LIMESTONE 1359
LOW
125 /im xO
799(1470)
0.67
Figure 86. National Coal Board, 6-in. diameter test unit using
limestone 1359, 1680 um x 0 and 125 ym x Q particle
size distribution.
499
-------
100
90
70
60
2 50
cw
40
30
20
10
1.0
20
Co/S
3.0
4.0
ratio
INVESTIGATOR'
NATIONAL COAL
BOARD
FBC UNIT DESIGNATION' 6 AND 36" COMBUSTORS
SOftBENT' LIMESTONE 18
APPROXIMATE REACTIVITY' HIGH
PARTICLE SIZE > 1680 >tm x 0
TEMPERATURE, *C(*F)' 799(1470)
GAS PHASE
RESIDENCE TIME, itcond»< 0.67
SORBENT REQUIREMENTS FOR OPTIONAL S02 CONTROL
LEVELS BASED ON THIS DATA
% REMOVAL
CO/S rotio,
75
1.8
78.7
1.9
83.2
2.1
83.9
2.2
85
2.2
90
2.6
Figure 87. National Coal Board, 6-in. diameter and 36 in. * is in.
combustor using limestone 18, 1680 ym particle size
distribution.
500
-------
too
o
o
CM
o
v>
WELBECK COAL
BED DEPTH 2ft.
FLUIDISINC VELOCITY 3ft/«
NO RECYCLE
ANL DATA A
CME DATA •
I 2 3
Co/S molerotio
INVESTIGATOR'
AR60NNE NATIONAL
LABORATORY
FBC UNIT DESIGNATION' 6 UNITS
SORBENTi U.K. LIMESTONE
APPROXIMATE REACTIVITY'
PARTICLE SIZE ' NOT REPORTED
TEMPERATURE,9C Cf)' 799(1470)
GAS PHASE
RESIDENCE TIME, Mcondt' 0.67
SORBENT REQUIREMENTS FOR OPTIONAL S02 CONTROL
LEVELS BASED ON THIS DATA
*/• REMOVAL
Co/S ratio,
75
3.2
78.7
3.4
83.2
3.6
83.9
3.7
85 90
3.8 4.2
Figure 88. Argonne National Laboratory and National Coal Board,
6-in. diameter test units using U.K. limestone.
501
-------
100
80
to
o
H
Z
Ul
40
K
OT 20
I
I 2 3
Co/S molf ratio
ILLINOIS COAL
BED DEPTH 2ft.
FLUIOISIN6 VtLOClTY Jft/t
NO RECYCLE
ANL DATA A
CRE DATA o
INVESTIGATOR'
AR60NNE NATIONAL
LABORATORY
FBC UNIT DESIGNATION' 6" COMBUSTORS
SORBENT' LIMESTONE 1359
APPROXIMATE REACTIVITY' LOW
PARTICLE SIZE' NOT REPORTED
TEMPERATURE,'C (*F)' 799(1470)
GAS PHASE
RESIDENCE TIME, second*' 0.67
SORBENT REQUIREMENTS FOR OPTIONAL SO? CONTROL
LEVELS BASED ON THIS DATA
% REMOVAL 79 78.7 83.2 83.9 65 90
Co/S ratio, 2.7 3.0 3.2 3.3 3.4 3.8
Figure 89. Argonne National Laboratory and National Coal Board
6-in. diameter test units using limestone 1359.
502
-------
data available at comparable operating conditions. Model projections of the
Ca/S molar feed ratios required for various levels of S02 removal in AFBC, as
a function of limestone type, are compared to the data collected from the ANL
and British Coal Research fluidized-bed units for limestone 1359 in Figure 90.
Conditions for the fluidized bed experimental runs were:
• Pressure - kPa (1 atm)
• Sorbent type - liuestone 1359
• Sorbent particle size - 490 to 630 ym in feed
• Superficial velocity - 0.8 to 0.85 m/sec (2.6 to 2.8 ft/sec)
• Temperature - 788° to 798°C (1450° to 1468°F)
• Bed height - 0.6 m (2 ft)
• Flue gas conditions - 3 percent 02, 15 percent CC-2
The Westinghouse projections are based on thermogravimetric rate data from
sulfation at 815°C (1500°F) in 0.5 percent S02, 4 percent 02, and N2. The
stilfations were carried out with 420 to 500 jam particles of limestone, calcine:
at 815°C (1500°F) in 15 percent C02 and nitrogen. The gas residence time (base:
on input bed height and velocity) was 0.66 sec, as opposed to an experimental
value of 0.74 sec used by ANL. This longer residence time may account for the
slightly lower Ca/S molar feed ratio requirements in the ANL limestone 1359 data.
7.7.2 GCA Calculations Based on the Westinghouse Model
Projections of Ca/S molar feed ratio requirements for several levels of
desulfurization have been calculated by GCA for comparison with experimental
results from the following test units.
• B&W 6 ft x 6 ft (1978)
• B&W 3 ft x 3 ft (1976)
• NCB-CRE 6 in. (1969)
• PER-FBM 1.5 ft x 6 ft (1971)
503
-------
100
90
S »o
e
5 *»
N
w 60
.2 SO -
Fluid-Bed
Operotino Conditions:
lotm, 101.3 fcPa
42O-5OO//fn Limestone Port ides
Bed Height I-2m
Velocity 1.8 m/sec
8I5°C
~20% excess air
Carbon Limectone
• Greer Limestone
> Limestone 1359
ANL best fit of Data
Collected for Limestone 1359
(1971)
345
Co/S Motor Ratio
Figure 90. Comparison of experimental S02 data with
projections based on Westinghouse Model.
504
-------
Table 101 shows the sorbents used in the comparisons and the Westinghouse identi-
fication number for applicable thermogravimetric data. Iti general, the Westing-
house prediction of Ca/S requirements for various levels of sulfur removal
arc close to the experimental data measured. The comparisons are shown in
Table8 97 through 100.
7^7.3 Influence of Fluidization Parameters Assumed in the Westinghouse Model
Important parametric values assumed for the projections are:
• e - bed voidage = 0.5
0 5 - volume fraction of bed bubbles =0.5
0 PS ~ density of Ca in sorbent = 0.0271 mole Ca/cc
« ?k - fraction of bed volume occupied by heat transfer tubes = 0
The impact of the assumptions made for each of these parameters as used
in the calculations are discussed below.
7^7.3.1 Particle Size Distribution—
The size of sorbent particles in the bed has a large effect on desulfuri-
zation efficiency. This is illustrated in the following example based on the
B&W 3 ft x 3 ft operating conditions.
• Data Source: B&W 3 ft x 3 ft test no, 31 (see Table 82)
Operating conditions: Temperature - 819°C (1506°F)
Bed height - 0.4 m (16 in.)
Superficial velocity - 2.5 m/sec (8.1 ft/sec)
S02 reduction - 58 percent
Ca/S ratio - 2.46
Sorbent type - Lowellville
Sorbent particle size - 1000 ym x Q
Projections of sorbent needs using Westinghouse model based on car-
bon limestone (TG run number 231) are:
505
-------
TABLE 96. SORBENTS USED EXPERIMENTALLY AND FOR PROJECTIONS USING WESTINGHOUSE MODEL
AFBC test
unit
B&W
6 ft x 6 ft
B&W
3 ft x 3 ft
NCB-CRE
6 in.
PER-FBM
1.5 ft x
6 ft
o v Westinghouse
Experimental , f */ ,„ Identification
sorbent ,, . .. No. for
Projection ,„„ ,
J TG data
Lowellville Carbon1" 231
Limestone Limestone
Lowellvile, Ohio
Greer Greer 86
Morgantown,
W. Va.
Grove Grove 381
(Limestone 1359)
Frederick, Md.
Grove Grove 296
(Limestone 1359)
Bed particle size Sorbent particle
used for Ca/S size specified
calculation* in experimental
(ym) results, ym (feed size)
1,000 9,525 x 0
(average bed size -
1,600 ym)f
1,000 2,380 x o
(average bed size -
1,200 um)f
500 1,680 x 0
(average bed size -
400 ym)§
75-150 44 x 0
This assumed particle size was limited by the extent to which data was available from Westinghouse
thermogravimetric experiments - 1,000 ym was the largest size reported in the Westinghouse experiments
and 75 ym was the smaller size.
^Carbon limestone had the most similar sulfation characteristics based on the TG data available.
tfiased on size analysis of spent bed material.
5Assuming that average bed size is roug'ily one-half average feed size.
-------
TABLE 97. COMPARISON OF EXPERIMENTAL AND PROJECTED SORBENT
REQUIREMENTS FOR THE B&W 6 FT x 6 FT UNIT
Test No.
1-1
1-1
1-2
1-2
1-2
1-2
1-3
1-3
1-3
1-4
1-4
1-4
1-4
1-5
Bed
temperature (°C)
876
878
864
869
871
874
869
872
867
848
852
866
856
872
Gas residence
time
0.49
0.48
0.61
0.56
0.65
0.57
0.49
0.49
0.51
0.41
0.41
0.38
0.40
0.48
Percent
S02
removal
94.37
94.29
97.04
96.79
95.48
95.66
95.22
95.08
94.33
94.24
94.01
94.59
94.98
93.27
Required Ca/S
Experimental
4.22
4.22
4.80
4.80
4.51
4.51
4.59
4.59
4.06
4.50
4.50
4.46
4.46
4.20
ratios
Proj ected
4.69
4.58
4.71
4.70
4.63
4.64
4.62
4.62
4.58
4.58
4.57
4.59
4.61
4.53
507
-------
TABLE 98. COMPARISON OF EXPERIMENTAL AND PROJECTED SORBENT
REQUIREMENTS FOR THE B&W 3 FT x 3 FT UNIT
Test No.
46
47
48
Bed
temperature
837
838
843
TABLE 99.
Gas residence
f c* "\
(seconds)
0.18
0.16
0.14
Percent
S02
removal
81.7
85.0
48.3
COMPARISON OF EXPERIMENTAL AND
REQUIREMENTS FOR THE PER FBM 1.
Required Ca/S ratios
Experimental Projected
3.62 3.14
3.94 3.27
2.70 2.20
PROJECTED SORBENT
5 FT x 6 FT UNIT
Test No.
27
28
29
30
31
32
Bed
temperature
854
871
871
871
871
882
882
882
882
877
877
877
Gas residence
(°C) time
0.21
0.21
0.21
0.21
0.21
0.20
0.20
0.20
0.20
0.20
0.20
0.20
Percent
S02
removal
74.0
71.6
64.7
73.5
73.5
50.0
60.4
53.8
61.5
61.9
64.9
70.5
Required Ca/S ratios
Experimental Projected
2.0 2.15
2.4 2.06
2.2 1.82
1.7 2.12
2.0 2.12
1.4 1.37
1.8 1.69
1.4 1.49
1.8 1.72
1.6 1.73
1.8 1.82
1.8 2.02
508
-------
TABLE 100. COMPARISON OF EXPERIMENTAL AND PROJECTED SORBENT
REQUIREMENTS FOR THE NCB-CRE 6 IN. UNIT
Test No.
1-2
1-3
1-4
3-1
3-2
3-3
3-4
3-5
3-6
Bed
temperature (°C)
799
799
799
699
699
799
799
799
799
Gas residence
time
0.67
0.67
0.67
0.67
0.67
1.0
1.0
0.67
0.67
Percent
S02
removal
46.5
63.4
83.0
15.0
18.0
51.0
72.0
61.0
93.0
Required Ca/S
Experimental
1.5
2.2
3.3
1.1
2.2
1.1
2.1
1.1
3.6
ratios
Projected
1.8
2.4
3.1
0.6
0.7
1.9
2.6
2.3
3.4
509
-------
Average
.. • , • Projected
particle size J
considered
1000 ym 3.87
500 ym 1.70
40 percent 500 ym _ .,
60 percent 1000 ym
The correlation between particle size and sorbent utilization exists because of
the dependence of the sulfation reaction on mass transfer and inter- or intra-
granular diffusion. Mass transfer dominates only for about the first 10 per-
cent of sulfation, but then diffusion becomes the rate limiting process. Diffu-
sional resistance within the porous structure of the sorbent increases with
particle size since sulfated outer regions limit diffusion into the interior
of the particle.
7.7.3.2 Bed Voidage—
The gas residence time is an important consideration in achieving high
efficiency S02 removal. Throughout this effort, it has been reported as the
expanded bed height divided by the superficial velocity. However, for rigorous
modeling purposes, correction factors are applied to determine interstitial velo-
city, which corrects for voidage, bed bubbles, and heat transfer tubes, as
follows:
t = H/y
y,.
(1 - 6) e + 5 (1 - fh)
where t = gas residence time, sec
H = expanded bed depth
y = interstitial gas velocity
ys = superficial gas velocity
& = volume fraction of bed bubbles
e = volume fraction of voids in a bed of particles
fh = fraction of bed volume occupied by heat transfer surface
510
-------
The following expression can be used to calculate the bed voidage if
experimental data on static pressure as a function of elevation is given, as
in the case of the B&W 3 ft x 3 ft unit.
e = 1 - AP/L
PS ~ P
where e = volume fraction of voids in a bed of particles
AP/L = pressure gradient
ps = true particle density
p = fluid density
7.7.3.3 Bed Temperature—
A change in bed temperature has a strong effect on the sulfation rate
constant of the sorbent because of the basic exponential dependence of the
Arrhenius kinetics involved.
7.7.3.4 Solid Particle Density—
Uniform particle density throughout the particle distribution is imports
to provide a uniform fluidized system. This is assumed in applying the
Westinghouse model.
7.8 EMISSION SOURCE TEST DATA FOR OIL-FIRED AFBC BOILERS
The only emission test data available in this category are results from
the Argonne National Laboratory (ANL) 0.15 m (6-in.) bench scale experimental
unit.52 The size of the unit is small and nonrepresentative of expected
commercial units. It is not warranted to present this data alone in support
of emission standards development without other emissions data available from
larger pilot and industrial scale units.
511
-------
7.9 EMISSION SOURCE TEST DATA FOR GAS-FIRED AFBC BOILERS
There are no published emission source test data for gas-fired PBC boilers
currently available.
512
-------
7.10 REFERENCES
1. Hansen, W.A., et al. Fluidized-Bed Combustion Development Facility and
Commercial Utility AFBC Design Assessment. Quarterly Technical Progress
Report. April to June 1978. Prepared by Babcock and Wilcox Company
for the Electric Power Research Institute. July 1978. pp. 5-1 through
5-24.
2. Hansen, W.A., et al. Fluidized-Bed Combustion Development Facility and
Commercial Utility AFBC Design Assessment. Quarterly Technical Progress
Report. July to September 1978. Prepared by Babcock and Wilcox Company
for the Electric Power Research Institute. October 1978. pp. 5-1 through
5-33.
3. Babcock and Wilcox Co. Fluidized-Bed Combustion Development Facility and
Commercial Utility AFBC Design Assessment. Quarterly Technical Progress
Report. Prepared for the Electric Power Research Institute. RP-718-2-1.
Prepared by Babcock and Wilcox Company. January to March 1979. pp. 2-5
through 2-90.
4. Lange, H.B., T.M. Sommer, C.L. Chen. S02 Absorption in Fluidized-Bed
Combustion of Coal; Effect of Limestone Particle Size. Prepared by the
Babcock and Wilcox Company for the Electric Power Research Institute.
Report No. FP 667. January 1978. Sections 2-7 and Appendix A.
5. National Coal Board. Reduction of Atmospheric Pollution: Main Report.
Prepared by the Fluidized Combustion Control Group. NTIS-PB 210-673.
September 1971.
6. National Coal Board. Reduction of Atmospheric Pollution, Appendices 1
through 3. Prepared by the Fluidized Combustion Control Group. NTIS-PB
210-674. September 1971.
7. Robison, E.B., A.H. Bagnulo, J.W. Bishop, S. Ehrlich. Characterization
and Control of Gaseous Emissions from Coal-Fired Fluidized-Bed Boilers.
Prepared by Pope, Evans, and Robbins, Inc. Prepared for the U.S. Depart-
ment of Health, Education, and Welfare. October 1970. pp. 18-45 and
Appendices B and C.
g. Mesko, J.E. Multicell Fluidized-Bed Boiler Design Construction and Test
Program. Quarterly Progress Report for October to December 1975. Pre-
pared by Pope, Evans, and Robbins, Inc. Prepared for the U.S. Energy
Research and Development Administration. January 1976.
9. Beacham, B., and A.R. Marshall. Experiences and Results of Fluidized-Bed
Combustion Plant at Renfrew. Prepared by Babcock Contractors Ltd., and
Combustion System Ltd. Presented at a conference in Dusseldorf, W. Germany,
November 6 and 7, 1978.
lO. Hanson, H.A., D.G. DeCoursin, D.D. Kinzler. Fluidized-Bed Combustor for
Small Industrial Applications. Prepared by FluiDyne Engineering Corpora-
tion for the Fifth International Conference on Fluidized-Bed Combustion.
December 1977. pp. 91 to 105.
513
-------
11. FluiDyne Engineering Corporation. Industrial Application Fluidized-Bed
Combustion Process. Quarterly Report. April to June 1977. Prepared by
FluiDyne Engineering Corporation for the U.S. Energy Research and Develop-
ment Administration (ERDA). FE 2463-12. November 1977. p. 10.
12. National Coal Board. Reduction of Atmospheric Pollution: Main Report.
Prepared by NCB for the U.S. Environmental Protection Agency. September
1971. pp. 59 to 61.
13. Jonke, A.A., E.L. Carls, R.L. Jarry, M. Haas, W.A. Murphy, and C.B.
Schoffstoll. Reduction of Atmospheric Pollution by the Application of
Fluidized-Bed Combustion. Annual Report. July 1968 through June 1969.
Prepared by Argonne National Laboratory. ANL-ES-CEN-1001.
14. Jonke, A.A., E.L. Carls, R.L. Jarry, L.J. Anastasia, M. Haas, J.R. Pavlik,
W.A. Murphy, C.B. Schoffstoll, and G.N. Vargo. Reduction of Atmospheric
Pollution by the Application of Fluidized-Bed Combustion. Annual Report.
July 1969 through June 1970. Prepared by Argonne National Laboratory.
ANL-ES-CEN-1002.
15. Jonke, A.A., G.J. Vogel, L.J. Anastasia, R.L. Jarry, D. Ramaswami, M. Haas
C.B. Schoffstoll, J.R. Pavlik, G.N. Vargo, and R. Green. Reduction of
Atmospheric Pollution by the Application of Fluidized-Bed Combustion.
Annual Report. July 1970-June 1971. ANL-ES-CEN-1004.
16. Dowdy, I.E., et al. Summary Evaluation of Atmospheric Pressure Fluidized-
Bed Combustion Applied to Electric Utility Large Steam Generators. Pre-
pared by the Babcock and Wilcox Company for the Electric Power Research
Institute. EPRI-FP-308. Volume II Appendix. October 1976. pp. 6K-55
through 6K-61.
17. Hansen, op. cit. July 1978.
18. Hansen, op. cit. October 1978.
19. Babcock and Wilcox Co., op. cit. March 1979.
20. Lange, op. cit. FP 667.
21. Telephone conversation between Mr. James Vick, Babcock and Wilcox,
Chemical Engineering Department, Alliance, Ohio, and Ms. J.M. Robinson,
GCA/Technology Division, Bedford, Massachusetts. December 1, 1978.
22. National Coal Board, op. cit. PB 210-673.
23. National Coal Board, op. cit. PB 210-674.
24. British Standards Institution. Methods for the Sampling and Analysis
of Flue Gases: Part 4. "British Standards ^Institution." Report B5 1756:
Part 4. London. 1963. p. 68.
514
-------
25. ASTM-D-3449. 1978 Annual Book of ASTM Standards. Part 26. Gaseous
Fuels. Coal and Coke. Atmospheric Analysis, pp. 784 to 787.
26. National Coal Board. Reduction of Atmospheric Pollution. Volume 3
Appendices 4 to 9. Prepared by the Fluidized-Bed Combustion Control
Group. APTD-1084. September 1971. p. A9.4.
27. Ibid, p. A9.7.
28. Robison, op. cit. October 1970.
29. Mesko, op. cit. January 1976.
30. Hanson, op. cit. December 1977.
31. FluiDyne Engineering Corporation, op. cit^. November 1977.
32. National Coal Board, op. cit. Main Report. September 1971.
33. Jonke, op. cit. ANL-ES-CEN-1001.
34. Jonke, op. cit. ANL/ES-CEN-1002.
35. Jonke, op. cit. ANL-ES-CEN-1004.
36. Beachman, op. cit.
37. Hansen, op. cit. July 1978.
38. Hansen, op. cit. October 1978.
39. Babcock and Wilcox Co., op. cit. March 1979.
40. Lange, op. cit. FP 667.
41. National Coal Board, op. cit. PB 210-673.
42. National Coal Board, op. cit. PB 210-674.
43. Robison, op. cit. October 1970.
44. Beachman, op. cit.
45. FluiDyne Engineering Corporation. Industrial Application Fluidized-Bed
Combustion Process. Quarterly Report. January to March 1977. Prepared
by FluiDyne Engineering Corporation for the U.S. Energy Research and
Development Administration (ERDA). FE-2463-9. April 1977.
46. Hanson, op. cit. December 1977.
47. FluiDyne Engineering Corporation, op. cit. November 1977.
515
-------
48. National Coal Board, op. cit. Main Report. September 1971.
49. Jonke, op. cit. ANL/ES/CEN-1001.
50. Jonke, op. cit. ANL/ES/CEN-1002.
51. Jonke, op. cit. ANL/ES/CEN-1004.
52. Jonke, A.A., et al. Reduction of Atmospheric Pollution by the Application
of Fluidized-Bed Combustion and Regeneration of Sulfur-Containing Additives
Annual Report. July 1971 to June 1972. ANL/ES/CEN-1005. June 1973.
p. 200.
516
-------
APPENDIX A
FIRST TIER OF AFBC COST ESTIMATES
The first tier (see Subsection 4.3) of AFBC Industrial Boiler Costs
are included in this Appendix. The tabulated costs vary as a function of
boiler capacity and coal type. The following costs are not included in the
data in this Appendix.
• Capital costs
Limestone storage, conveying, and screening
Spent solids/ash conveying, and storage
• Operating costs
Limestone purchase
Spent solids/ash disposal
Electricity for operation of all auxiliary equipment
517
-------
TABLE A-l. (CONT'd)
EQUIPMENT INSTALLATION COSTS, DIRECT
Boiler (@ .35% x capital)
Stack
Instrumentation
Pulverizers
Feeders
Crushers
Deaerator*
Boiler feed pumps*
Condensate system*
Water treatment system*
Chemical feed*
Coal handling system (@ 60% x equipment)
Spent solids withdrawal and cooling
Limestone handling and,storage system
i . i , rnondlinoond ° J
Spent solids and ashvstorage system
Foundation and Supports (@ 90% PEDCo estimate)
Piping*
Insulation
Painting
Electrical
Buildings
TOTAL INSTALLATION COST
TOTAL DIRECT COST (EQUIPMENT & INSTALLATION)(DC)
.
incl w/
incl. w/ boiler
NA
incl. w/ boiler
incl « w/cocil
\ 100
X? .000
~IO .GOO
incl. w/ boile.r
See Table C-2Q.
See Table C-21
OOP
incl. w/ boiler
,800
EQUIPMENT INSTALLATION COST
Engineering @ 10% DC
Construction & field expenses @ 10% DC
Construction fee @ 10% DC
Start-up and performance tests'
TOTAL INDIRECT COSTS (1C)
Contingencies @ 20% DC & 1C
TOTAL TURNKEY COST (DC + 1C + CONTINGENCIES)
Land
Working capital @ 25% of total direct
operating costs
GRAND TOTAL CAPITAL COST (TURNKEY + LAND +
WORKING CAPITAL)
81 430
I
i O oon
354.360
36 ,
.404
*From PEDCo estimates for conventional systems.
tBased on FBC vendor quotes.
519
-------
TABLE A-2. ESTIMATED CAPITAL, OPERATING AND ANNUALIZED COSTS FOR AFBC
INDUSTRIAL BOILERS - 8.8 MW (30 x 106 Btu/h) EASTERN LOW
SULFUR COAL
Based on quote from
Date of estimate
Com pan t/ ~P>
tT
MID- I SIR
Capacity
Coal Type Easte
rn
-CAPITAL EQUIPMENT COST
Boiler (with fans & ducts)
Primary particulate control device
Final particulate control device
Stack
Instrumentation
Pulverizers
Coal
Limestone
Feeders
Coal
Limestone
Crushers
Coal
Limestone
Deaerator*
Boiler feed pumps*
Condensate systems*
Water treatment system*
Chemical feed*
Compressed air system (FD fan)
Coal handling system (pEDCo -
Limestone handling & storage system
Spent solids withdrawal & cooling system
Spent solids and ash/\storage system
hcxodlioQcxnci
TOTAL EQUIPMENT COST
OOP
incl. w/ boiler
IrviJ
not included
JI Ivailer
incl. w/ boiler
NA
NA
incl. w/ boiler
incl. w/ boiler
incl. w/ coal handling
screening is included in
limestone handling &
storage. See Table C-20
| .^ 4 p n
~7QO
) A CO
incl. w/ boiler
5?QQ
See Table C-20
incl. w/ boiler
See Table C-21
3~l~l
*From PEDCo estimates for conventional systems.
tA cost of $20,000 for coal feeding equipment is included in the
boiler cost.
521
-------
TABLE A-2. (CONT'd)
EQUIPMENT INSTALLATION COSTS, DIRECT
Boiler (@ 35% x capital)
Stack
Instrumentation
Pulverizers
Feeders
Crushers
Deaerator*
Boiler feed pumps*
Condensate system*
Water treatment system*
Chemical feed*
Coal handling system (@ 60% x equipment)
Spent solids withdrawal and cooling
Limestone handling and^storage system
Spent solids and ashvstorage system
Foundation and Supports (@ 90% PEDCo estimate)
Piping*
Insulation
Painting
Electrical
Buildings
TOTAL INSTALLATION COST
TOTAL DIRECT COST (EQUIPMENT & INSTALLATION)(DC)
incl
incl
xA//fc>oi
. w/ bo
boiler
NA
incl. w/ boiler
incl.
3 -.000
; 100
w
See Table C-20
See Table C-21
, 000
incl. w/ boiler
30 .
OOP
147
EQUIPMENT INSTALLATION COST
Engineering @ 10% DC
Construction & field expenses @ 10% DC
Construction fee @ 10% DC
Start-up and performance tests '
TOTAL INDIRECT COSTS (1C)
Contingencies @ 20% DC & 1C
TOTAL TURNKEY COST (DC + 1C + CONTINGENCIES)
Land
Working capital @ 25% of total direct
operating costs
GRAND TOTAL CAPITAL COST (TURNKEY + LAND +
WORKING CAPITAL)
74,
oo
» 96 .4
. QO
77n
*From PEDCo estimates for conventional systems.
tBased on FBC vendor quotes.
522
-------
TABLE A-2. (CONT'd)
DIRECT OPERATING COST
Direct labor*
Supervision*
Maintenance labor*
Replacement parts*
Electricity
Steam
Cooling water
Process water*
Fuel (§$3^./ton
Limestone
Waste disposal
Chemicals*
TOTAL DIRECT COST
OVERHEAD
Payroll (30% of direct labor)
Plant (26% of labor parts and maintenance)
TOTAL OVERHEAD COST
By-product credits
CAPITAL CHARGES
G&A, taxes & insurance @ 4% Total turnkey cost
Capital recovery factor @10.6% Total turnkey cost_
Interest on working capital @ 10% working capital_
TOTAL CAPITAL CHARGES
TOTAL ANNUAL COSTS
SCO
1QO
. OOP
See Table C-24
NA
NA
_4/700
See Table C-22
See Table C-23
300
5.33,640
47.370
13^,490
*From PEDCo estimates for conventional systems.
523
-------
TABLE A-3. ESTIMATED CAPITAL, OPERATING AND ANNUALIZED COSTS FOR AFBC
INDUSTRIAL BOILERS - 8.8 MW (30 x 10b Btu/h) SUBBITUMINOUS
COAL
Based on quote from
Date of estimate
"B
Capacity
Coal Type
CAPITAL EQUIPMENT COST
Boiler (with fans & ducts)
Primary particulate control device
Final particulate control device
Stack
Instrumentation
Pulverizers
Coal
Limestone
Feeders
Coal
Limestone
Crushers
Coal
Limestone
Deaerator*
Boiler feed pumps*
Condensate systems*
Water treatment system*
Chemical feed*
Compressed air system (FD fan) . \
Coal handling system (PEECo - 3C,CCCT)
Limestone handling & storage system
Spent solids withdrawal & cooling system
Spent solids and ashAstorage system
handling and
TOTAL EQUIPMENT COST
£45.OOP
incl .'
not
w/ boiler
included
i_- -1 . / i - J
3T1C.L- W/ hoilej*
incl.
w/ boiler
NA
NA
incl.
incl.
w/ boiler
w/ boiler
incl. w/ coal handling
screening is included in
limestone handling &
storage. See Table C-20
5_
4OO
•7 ,-700
incl. w/ boiler
See Table C-20
incl. w/ boiler
See Table C-21
*From PEDCo estimates for conventional systems.
tA cost of $20,000 for coal feeding equipment is included in the
boiler cost.
524
-------
TABLE A-3. (CONT'd)
EQUIPMENT INSTALLATION COSTS, DIRECT
Boiler (@ 35% x capital) £4? OOP
Stack xncl. W/ boiler"
Instrumentation incl. w/ boiler
Pulverizers NA
Feeders incl. w/ boiler
Crushers tncl. w/ fiocd.
Deaerator* ^_
Boiler feed pumps* ^
Condensate system* I > I OO
Water treatment system* ;j OOP
Chemical feed* ROO
Coal handling system (@ 60% x equipment) % % 0| QQ
Spent solids withdrawal and cooling I31C.I. w./ foOL
Limestone handling and storage system See Table C-20
Spent solids and asn^sto'rage system See Table C-21
Foundation and Supports (@ 90% PEDCo estimate)
Piping* 5OJ 4QO
Insulation incl. w/ boiler
Painting -7
Electrical .3D . Poo
Buildings | 73
TOTAL INSTALLATION COST
TOTAL DIRECT COST (EQUIPMENT & INSTALLATION) (DC) 9_l3
EQUIPMENT INSTALLATION COST
Engineering @ 10% DC q t ^5^,
Construction & field expenses @ 10% DC
Construction fee @ 10% DC
Start-up and performance tests ' |^^ ^QQQ
Ll"^^B-^^^^-^fc»»^»—
TOTAL INDIRECT COSTS (1C) 3*%^ "7SO
Contingencies @ 20% DC & 1C £3^ .^5"O
TOTAL TURNKEY COST (DC + 1C + CONTINGENCIES) j.
Land
Working capital @ 25% of total direct
operating costs
GRAND TOTAL CAPITAL COST (TURNKEY + LAND +
WORKING CAPITAL) i
*From PEDCo estimates for conventional systems.
•i-Based on FBC vendor quotes.
525
-------
TABLE A-3. (CONT'd)
DIRECT OPERATING COST
Direct labor* _ 15700
Supervision* _ 4%
Maintenance labor* _ 64
Replacement parts* _ g
_ _
Electricity _ See Table C-24
Steam _ NA __
Cooling water _ NA _ __
Process water* _ 4 TOO _
Fuel @&>.15/ton
Limestone __ See Table C-22
Waste disposal _ See Table C-23
Chemicals* _ c^
TOTAL DIRECT COST _ 4 39
}
OVERHEAD
Payroll (30% of direct labor) _ 4l.37Q
Plant (26% of labor parts and maintenance)
TOTAL OVERHEAD COST _ 145. * 5"Q
By-product credits _ N A.
CAPITAL CHARGES
G&A, taxes & insurance @ 4% Total turnkey cost _ 51^4^0
Capital recovery factor @10.6% Total turnkey cost _ I ^.3. J ~7Q
Interest on working capital @ 10% working capital _ )O
TOTAL CAPITAL CHARGES _
-------
TABLE A-4. ESTIMATED CAPITAL, OPERATING AND ANNUALIZED COSTS FOR AFBC
INDUSTRIAL BOILERS - 22 MW (75 x 106 Btu/h) EASTERN HIGH
SULFUR COAL
Based on quote from
Date of estimate
MID-
Capacity <33MWf75Tx
Coal Type EaSigrr
T
CAPITAL EQUIPMENT COST
Boiler (with fans & ducts)
Primary particulate control device
Final particulate control device
Stack
Instrumentation
Pulverizers
Coal
Limestone
Feeders
Coal
Limestone
Crushers
Coal
Limestone
Deaerator*
Boiler feed pumps*
Condensate systems*
Water treatment system*
Chemical feed*
Compressed air system (FD fan)
Coal handling system*
Limestone handling & storage system
Spent solids withdrawal & cooling system
Spent solids and ash^storage system
handling cxncl
TOTAL EQUIPMENT COST
^5,30^000
incl. w/ boiler
not included
OOP
incl. w/ boiler
NA
NA
incl. w/ boiler
incl. w/ boiler
incl. w/ coal handling
screening is included in
limestone handling &
storage. See Table C-20
15 9OO
15 OOO
K400
incl. w/ boiler
g
See Table C-2Q
incl. w/ boiler
See Table C-21
*From PEDCo estimates for conventional systems.
527
-------
TABLE A-4. (CONT'd)
EQUIPMENT INSTALLATION COSTS, DIRECT
Boiler (@ 35% x capital)
Stack
Instrumentation
Pulverizers
Feeders
Crushers
Deaerator*
Boiler feed pumps*
Condensate system*
Water treatment system*
Chemical feed*
Coal handling system*
Spent solids withdrawal and cooling
Limestone handling and .storage system
ViaodTioaarJ0 J
Spent solids and ash » storage system
Foundation and Supports (@ 90% PEDCo estimate)
Piping*
Insulation
Painting
Electrical
Buildings
TOTAL INSTALLATION COST
TOTAL DIRECT COST (EQUIPMENT & INSTALLATION) (DC)
-30,000
incl. w/ boiler
NA
incl. w/ boiler
See Table C-20
See Table C-21
incl. w/x boiler
8
; 301
EQUIPMENT INSTALLATION COST
Engineering @ 10% DC
Construction & field expenses @ 10% DC
Construction fee @ 10% DC
Start-up and performance tests
TOTAL INDIRECT COSTS (1C)
Contingencies @ 20% DC & 1C
TOTAL TURNKEY COST (DC + 1C + CONTINGENCIES)
Land
Working capital @ 25% of total direct
operating costs
GRAND TOTAL CAPITAL COST (TURNKEY + LAND +
WORKING CAPITAL)
*From PEDCo estimates for conventional systems.
528
-------
•CABLE A-4. (CONT'd)
DIRECT OPERATING COST
Direct labor* _
Supervision* _
Maintenance labor* _
Replacement parts* _
Electricity _
Steam _
Cooling water _
Process water* _
Fuel @ ^11-/ton
Limestone _
Waste disposal _
Chemicals* _
TOTAL DIRECT COST
OVERHEAD
Payroll (30% of direct labor)
Plant (26% of labor parts and maintenance) _
TOTAL OVERHEAD COST
By-product credits
CAPITAL CHARGES
G&A, taxes & insurance @ 4% Total turnkey cost
Capital recovery factor @10.6% Total turnkey cost
Interest on working capital @ 10% working capital_
TOTAL CAPITAL CHARGES
TOTAL ANNUAL COSTS
~7
See Table C-24
NA
NA
.
Tab
See Table C-22
See Table C-23
A, 300
3SO
, aoo
IOO
M.A.
51 o a oo
*From PEDCo estimates for conventional systems.
529
-------
TABLE A-5. ESTIMATED CAPITAL, OPERATING AND ANNUALIZED COSTS FOR AFBC
INDUSTRIAL BOILERS - 22 MW (75 x 106 Btu/h) EASTERN LOW
SULFUR COAL
Based on quote from Cjjrnprtny A
Date of estimate i^) I D -
Capacity 33 MW (l5
Coal Type FQSJFTD JOtO
CAPITAL EQUIPMENT COST
Boiler (with fans & ducts)
Primary particulate control device
Final particulate control device
Stack
Instrumentation
Pulverizers
Coal
Limestone
Feeders
Coal
Limestone
Crushers
Coal
Limestone
Deaerator*
Boiler feed pumps*
Condensate systems*
Water treatment system*
Chemical feed*
Compressed air system (FD fan)
Coal handling system*
Limestone handling & storage system
Spent solids withdrawal & cooling system
Spent solids and ashAstorage system
Handling ani
TOTAL EQUIPMENT COST
520,000
incl. w/ boiler
not included
UlyJ . V ^t]J^_f_^
incl. w/ boiler
NA
NA
incl. w/ boiler
incl. w/ boiler
incl. w/ coal handling
screening is included in
limestone handling &
storage. See Table C-20
300
ft ."70Q
7T4QO
incl. w/ boiler
/4
See Table C-2Q
incl. w/ boiler
Table C-21
*From PEDCo estimates for conventional systems.
530
-------
TABLE A-5. (CONT'd)
EQUIPMENT INSTALLATION COSTS, DIRECT
Boiler (@ 35% x capital)
Stack
Instrumentation
Pulverizers
Feeders
Crushers
Deaerator*
Boiler feed pumps*
Condensate system*
Water treatment system*
Chemical feed*
Coal handling system*
Spent solids withdrawal and cooling
Limestone handling and storage system
r. *. i _, j j .Handling <\n3°
Spent solids and ashvstorage system
Foundation and Supports (@ 90% PEDCo estimate)
Piping*
Insulation
Painting
Electrical
Buildings
TOTAL INSTALLATION COST
TOTAL DIRECT COST (EQUIPMENT & INSTALLATION) (DC)
533.000
incl. w/ boiler
NA
incl. w/ boiler
inc.
500
lra.ncl.lLng
5 S
3L 500
I .SCO
'50.000
See Table C-20
See Table C-21
"13000
incl. w7 boiler
.300 .000
.30.
EQUIPMENT INSTALLATION COST (IMD1RE.CT3
Engineering @ 10% DC
Construction & field expenses @ 10% DC
Construction fee @ 10% DC
Start-up and performance tests
TOTAL INDIRECT COSTS (1C)
Contingencies @ 20% DC & 1C
TOTAL TURNKEY COST (DC + 1C + CONTINGENCIES)
Land
Working capital @ 25% of total direct
operating costs
GRAND TOTAL CAPITAL COST (TURNKEY + LAND +
WORKING CAPITAL)
goo
'
'Roo
*From PEDCo estimates for conventional systems.
531
-------
TABLE A-5. (CONT1d)
DIRECT OPERATING COST
Direct labor*
Supervision*
Maintenance labor*
Replacement parts* )
-------
TABLE A-6. ESTIMATED CAPITAL, OPERATING AND ANNUALIZED COSTS FOR AFBC
INDUSTRIAL BOILERS - 22 MW (30 x 106 Btu/h) SUBBITUMINOUS
COAL
Based on quote from
Date of estimate
A
Mlfi-
Capacity ,30 MU/fex
Coal Type
CAPITAL EQUIPMENT COST
Boiler (with fans & ducts)
Primary particulate control device
Final particulate control device
Stack
Instrumentation
Pulverizers
Coal
Limestone
Feeders
Coal
Limestone
Crushers
Coal
Limestone
Deaerator*
Boiler feed pumps*
Condensate systems*
Water treatment system*
Chemical feed*
Compressed air system (FD fan)
Coal handling system"*
Limestone handling & storage system
Spent solids withdrawal & cooling system
Spent solids and ashAstorage system
Ha.nd.lLng-
TOTAL EQUIPMENT COST
1 520.OOP
incl. w/ boiler
not included
OOP
incl. w/ boiler
NA
NA
incl. w/ boiler
incl. w/ boiler
incl. w/ coal handling^
screening is included in
limestone handling &
storage. See Table C-20
15
S .
ft Oft
T4QQ
incl. w/ boiler
QQ?>
See Table C-20
incl. w/ boiler
See Table C-21
*From PEDCo estimates for conventional systems.
533
-------
TABLE A-6. (CONT'd)
EQUIPMENT INSTALLATION COSTS, DIRECT
Boiler (@ 357o x capital)
Stack
Instrumentation incl. w/ boiler
Pulverizers NA
Feeders incl. w/ boiler
Crushers rncZ. ^
Deaerator* -^
Boiler feed pumps* 5:
Condensate system* , ..
Water treatment system*
Chemical feed*
Coal handling system* £ ) £, QOQ
Spent solids withdrawal and cooling
Limestone handling an^^tora|e system See Table C-20
Spent solids and ash«storage system See Table C-21
Foundation and Supports (@ 90% PEDCo estimate) |Q^ "7 op "
Piping* "7 j / Oor>
Insulation incl. w/ boiler
Painting
Electrical
Buildings
TOTAL INSTALLATION COST | _. w^.
TOTAL DIRECT COST (EQUIPMENT & INSTALLATION)(DC) ^
EQUIPMENT INSTALLATION COST (INDIRECT)
Engineering <§ 10% DC __T___
Construction & field expenses @ 10% DC ^3r>' IQD
Construction fee @ 10% DC
Start-up and performance tests ~l I J.
TOTAL INDIRECT COSTS (1C) I
Contingencies @ 20% DC & 1C
TOTAL TURNKEY COST (DC + 1C + CONTINGENCIES) §
Land
Working capital @ 25% of total direct
operating costs
GRAND TOTAL CAPITAL COST (TURNKEY + LAND +
WORKING CAPITAL) 5
*From PEDCo estimates for conventional systems.
534
-------
TABLE A-6. (CONT'd)
DIRECT OPERATING COST
Direct labor*
Supervision*
Maintenance labor*
Replacement parts*
Electricity
Steam
Cooling water
Process water*
Fuel @&>n5/ton
Limestone
Waste disposal
Chemicals*
TOTAL DIRECT COST
OVERHEAD
Payroll (30% of direct labor)
Plant (26% of labor parts and maintenance)
TOTAL OVERHEAD COST
By-product credits
CAPITAL CHARGES
G&A, taxes & insurance @ 4% Total turnkey cost
Capital recovery factor @10.6% Total turnkey cost_
Interest on working capital @ 10% working capital_
.310
I 44.noo
See Table C-24
NA
See Table C-22
See Table C-23
30Q
IPO
334,300
^ *
M.A.
8.400
TOTAL CAPITAL CHARGES
TOTAL ANNUAL COSTS
"760
*From PEDCo estimates for conventional systems,
535
-------
TABLE A-7. ESTIMATED CAPITAL, OPERATING AND ANNUALIZED COSTS FOR AFBC
INDUSTRIAL BOILERS - 44 MW (150 x 106 Btu/h) EASTERN HIGH
SULFUR COAL
Based on quote from
Date of estimate
CjQmp?Wl\ A. _ Capacity 4A W\J(\5O*.
Mlft- l^TS?
Coal Type Eastern l>ign
CAPITAL EQUIPMENT COST
Boiler (with fans & ducts)
Primary particulate control device
Final particulate control device
Stack
Instrumentation
Pulverizers
Coal
Limestone
Feeders
Coal
Limestone
Crushers
Coal
Limestone
Deaerator*
Boiler feed pumps*
Condensate systems*
Water treatment system*
Chemical feed*
Compressed air system (FD fan)
Coal handling system*
Limestone handling & storage system
Spent solids withdrawal & cooling system
Spent solids and ashAstorage system
handling
TOTAL EQUIPMENT COST
.3. 4 37, OOP
incl. w/ toiler
not included
300 OOP
incl. w/ boiler
NA
incl. w/ boiler
incl. w/ boiler
incl. w/ coal handling
screening is included in
limestone handling &
storage. See Table C-20
'j OQ -
44
i fi OOP
'
incl. w/ boiler
See Table C-20
incl. w/ boiler
See Table C-21
IQ4 IQQ
from PEDCo estimates for conventional systems
536
-------
TABLE A-7. (CONT'd)
EQUIPMENT INSTALLATION COSTS, DIRECT
Boiler (@ 4O% x capital)
Stack
Instrumentation
Pulverizers
Feeders
Crushers
Deaerator*
Boiler feed pumps*
Condensate system*
Water treatment system*
Chemical feed*
Coal handling system*
Spent solids withdrawal and cooling
Limestone handling and storage system
_ , . , , kancllinA fLrtJr
Spent solids and ashvstorage system
Foundation and Supports (@ 90% PEDCo estimate)
Piping*
Insulation
Painting
Electrical
Buildings
TOTAL INSTALLATION COST
TOTAL DIRECT COST (EQUIPMENT & INSTALLATION)(DC)
970,000
incl. w/ boiler
NA
incl. w/ boiler
i.ryl wCoa!
SlDO
See Table C-20
See Table C-21
incl. w/ boiler
1 SO. COO
' soo
35*0
45O
EQUIPMENT INSTALLATION COST
Engineering @ 10% DC
Construction & field expenses @ 10% DC
Construction fee @ 10% DC
Start-up and performance tests
TOTAL INDIRECT COSTS (1C)
Contingencies @ 20% DC & 1C
TOTAL TURNKEY COST (DC + 1C + CONTINGENCIES)
Land
Working capital @ 25% of total direct
operating costs
GRAND TOTAL CAPITAL COST (TURNKEY + LAND +
WORKING CAPITAL)
53.4 S
I 14 Jc\ IP
•**
*From PEDCo estimates for conventional systems.
537
-------
TABLE A-7. (CONT'd)
DIRECT OPERATING COST
Direct labor*
Supervision*
Maintenance labor*
Replacement parts* 3 34 f OOP
Electricity See Table C-24
Steam NA
Cooling water NA
Process water* 18^ 8OO
Fuel @$n /ton '
Limestone See Table C-22
Waste disposal See Table C-23~
Chemicals* fe*"~
TOTAL DIRECT COST I.4O%. IOO
X
OVERHEAD
Payroll (30% of direct labor) 9 4^70
Plant (26% of labor parts and maintenance) £ ] | QQr^
TOTAL OVERHEAD COST BOfcj
By-product credits M . A.
CAPITAL CHARGES
G&A, taxes & insurance @ 4% Total turnkey cost
Capital recovery factor @10.6% Total turnkey cost_
Interest on working capital @ 10% working capital_
TOTAL CAPITAL CHARGES
TOTAL ANNUAL COSTS
from PEDCo estimates for conventional systems
538
-------
TABLE A-8. ESTIMATED CAPITAL, OPERATING AND ANNUALIZED COSTS FOR AFBC
INDUSTRIAL BOILERS - 44 MW (150 x 106 Btu/h) EASTERN LOW
SULFUR COAL
Based on quote from
Date of estimate
., A
HlD-
Capacity 44 hW f ISOx iQfo R+i JU)
Coal Type C —1_ I vr
i r-
CAPITAL EQUIPMENT COST
Boiler (with fans & ducts)
Primary particulate control device
Final particulate control device
Stack
Instrumentation
Pulverizers
Coal
Limestone
Feeders
Coal
Limestone
Crushers
Coal
Limestone
Deaerator*
Boiler feed pumps*
Condensate systems*
Water treatment system*
Chemical feed*
Compressed air system (FD fan)
Coal handling system*
Limestone handling & storage system
Spent solids withdrawal & cooling system
Spent solids and ashAstorage system
Hand lino cvndl
TOTAL EQUIPMENT COST
.431 .OOP
incl. w/ boiler
not included
ooo
incl. w/ boiler
NA
NA
incl. w/ boiler
incl. w/ boiler
incl. w/ coal handling
screening is included in
limestone handling &
storage. See Table C-20
44;
incl. w/ boiler
j30Q
See Table C-20
incl. w/ boiler
See Table C-21
from PEDCo estimates for conventional systems
539
-------
TABLE A-8. (CONT'd)
EQUIPMENT INSTALLATION COSTS, DIRECT
Boiler (@ ^O^o x capital)
Stack SOj Oon
Instrumentation incl. w/ boiler
Pulverizers NA
Feeders incl. w/ boiler
Crushers -Lnci. \*
Deaerator*
Boiler feed pumps* 7} OOP
Condensate system*
Water treatment system*
Chemical feed*
Coal handling system*
Spent solids withdrawal and cooling Tr?cl. to/
Limestone handling ajid storage system See Table C-20
Spent solids and ash^sto'r'age system See Table C-21
Foundation and Supports (@ 90% PEDCo estimate) [^
Piping* ~7O . ooo
Insulation incl. w/ boiler
Painting
Electrical
Buildings
TOTAL INSTALLATION COST £
TOTAL DIRECT COST (EQUIPMENT & INSTALLATION)(DC) ^
EQUIPMENT INSTALLATION COST
Engineering @ 10% DC
Construction & field expenses @ 10% DC
Construction fee @ 10% DC
Start-up and performance tests
TOTAL INDIRECT COSTS (1C)
Contingencies @ 20% DC & 1C
TOTAL TURNKEY COST (DC + 1C + CONTINGENCIES) g.
Land 5jflon
Working capital @ 25% of total direct
operating costs
GRAND TOTAL CAPITAL COST (TURNKEY + LAND +
WORKING CAPITAL) %
*From PEDCo estimates for conventional systems.
540
-------
A-8. (CONT'd)
*From PEDCo estimates for conventional systems.
541
OPERATING COST
Direct labor*
Supervision*
Maintenance labor* I a% t 3oo>
Replacement parts* ^oo^ooo
Electricity See Table C-24
Steam NA "
Cooling water NA
Process water* ia
Fuel @$ 2S-/ton S37^-?oo
Limestone See Table C-22
Waste disposal See Table C-23
Chemicals*
TOTAL DIRECT COST
OVERHEAD
Payroll (30% of direct labor)
Plant (26% of labor parts and maintenance) 2o4'
'o-ia
i^^^^_^«^»^—
OVERHEAD COST
By-product credits
CHARGES
G&A, taxes & insurance @ 4% Total turnkey cost 331
Capital recovery factor @10.6% Total turnkey cost g 51
Interest on working capital @ 10% working capital 4O.
* n r J
TOTAL CAPITAL CHARGES )_
ANNUAL COSTS 3 ...
-------
TABLE A-9. ESTIMATED CAPITAL, OPERATING AND ANNUALIZED COSTS FOR AFBC
INDUSTRIAL BOILERS - 44 MW (150 x 106 Btu/h) SUBBITUMINOUS
COAL
Based on quote from
Date of estimate
mu
A
Capacity
Coal Type S
CAPITAL EQUIPMENT COST
Boiler (with fans & ducts)
Primary particulate control device
Final particulate control device
Stack
Instrumentation
Pulverizers
Coal
Limestone
Feeders
Coal
Limestone
Crushers
Coal
Limestone
Deaerator*
Boiler feed pumps*
Condensate systems*
Water treatment system*
Chemical feed*
Compressed air system (FD fan)
Coal handling system*"
Limestone handling & storage system
Spent solids withdrawal & cooling system
Spent solids and ash^storage system
ViOncllinn eunrl
TOTAL EQUIPMENT COST
431
incl. w/ boiler
not included
3OQ.OOO
incl. w/ boiler
NA
NA
incl. w/ boiler
incl. w/ boiler
incl. w/ coal handling
screening is included in
limestone handling &
storage. See Table C-20
incl. w/ boiler
See Table C-2Q
incl. w/ boiler
See Table C-21
*From PEDCo estimates for conventional systems.
542
-------
TABLE A-9. (CONT'd)
EQUIPMENT INSTALLATION COSTS, DIRECT
Boiler (@ 4Oc7o x capital) 9?c
Stack • 'JO coo
Instrumentation incl. w/ boiler
Pulverizers NA
Feeders incl. w/ boiler
Crushers
Deaerator*
Boiler feed pumps*
Condensate system* I , SToo
Water treatment system* ^ ooo^
Chemical feed*
Coal handling system*
Spent solids withdrawal and cooling i.nc.1.
Limestone handling and storage system See Table C-20
Spent solids and ash* stora'ge system See Table C-21
Foundation and Supports (@ 90% PEDCo estimate) ) 94, 400
Piping* loo %OQ
Insulation incl. w/ boiler
Painting 14. 400
Electrical
Buildings
TOTAL INSTALLATION COST
TOTAL DIRECT COST (EQUIPMENT & INSTALLATION) (DC) £ g'SO_t"7QO
EQUIPMENT INSTALLATION COST CXMDIR.&C.T)
Engineering @ 10% DC 5S"3 O'7O
Construction & field expenses @ 10% DC fTS "3 o~7Q
Construction fee @ 10% DC *T5^ O7O
Start-up and performance tests | 3 Q (o I O
TOTAL INDIRECT COSTS (1C)
Contingencies @ 20% DC & 1C ) 463 /Qp
TOTAL TURNKEY COST (DC + 1C + CONTINGENCIES)
Land
Working capital @ 25% of total direct
operating costs
GRAND TOTAL CAPITAL COST (TURNKEY + LAND +
WORKING CAPITAL)
*From PEDCo estimates for conventional systems.
543
-------
TABLE A-9. (CONT1d)
TOTAL ANNUAL COSTS
3)5
See Table C-24
NA
NA
/ft, 800
See Table C-22
See Table C-23
DIRECT OPERATING COST
Direct labor*
Supervision*
Maintenance labor*
Replacement parts*
Electricity
Steam
Cooling water
Process water*
Fuel @&>.7S/ton ~
Limestone
Waste disposal
Chemicals*
S»FVi.
TOTAL DIRECT COST
OVERHEAD
Payroll (30% of direct labor)
Plant (26% of labor parts and maintenance)
TOTAL OVERHEAD COST
By-product credits
CAPITAL CHARGES
G&A, taxes & insurance @ 4% Total turnkey cost
Capital recovery factor @10.6% Total turnkey cost_
Interest on working capital @ 10% working capital^
TOTAL CAPITAL CHARGES
./j /7Q; 900
A 3/0,070
*From PEDCo estimates for conventional systems.
544
-------
TABLE A-10.
ESTIMATED CAPITAL, OPERATING AND ANNUALIZED COSTS FOR AFBC
INDUSTRIAL BOILERS - 58.6 MW (200 x 106 Btu/h) EASTERN
HIGH SULFUR COAL
on quote from
Date of estimate
C.
om
po
n
r\
Capacity .gft.
M/D -
Coal Type Eastern kink -
-------
TABLE A-10. (CONT'd)
EQUIPMENT INSTALLATION COSTS, DIRECT
Boiler (@ /\Q% x capital)
Stack
Instrumentation
Pulverizers
Feeders
Crushers
Deaerator*
Boiler feed pumps*
Condensate system*
Water treatment system*
Chemical feed*
Coal handling system*
Spent solids withdrawal and cooling
Limestone handling and storage system
_ , . , , , loa«JMi->g and
Spent solids and ash"Storage system
Foundation and Supports (@ 90% PEDCo estimate)
Piping*
Insulation
Painting
Electrical
Buildings
TOTAL INSTALLATION COST
TOTAL DIRECT COST (EQUIPMENT & INSTALLATION)(DC)
. OOP
incl. w/ boiler
NA
incl. w/ boiler
•uric L • w/Coal n
". OOP
oon
.3. 5~<
.. u;/
See Table C-20
See Table C-21
9 ^
incl. w/ boiler
I J
444 ,
6.4ST.S
EQUIPMENT INSTALLATION COST C IN*"DIRECT)
Engineering @ 10% DC
Construction & field expenses @ 10% DC
Construction fee @ 10% DC
Start-up and performance tests
TOTAL INDIRECT COSTS (1C)
Contingencies @ 20% DC & 1C
TOTAL TURNKEY COST (DC 4- 1C + CONTINGENCIES)
Land
Working capital @ 25% of total direct
operating costs
GRAND TOTAL CAPITAL COST (TURNKEY + LAND +
WORKING CAPITAL)
*From PEDCo estimates for conventional systems.
546
-------
TABLE A-10. (CONT'd)
DIRECT OPERATING COST
Direct labor*
Supervision*
Maintenance labor*
Replacement parts*
Electricity
Steam
Cooling water
Process water*
Fuel @$ 17- /ton
Limestone
Waste disposal
Chemicals*
TOTAL DIRECT COST
OVERHEAD
Payroll (30% of direct labor)
Plant (26% of labor parts and maintenance)
TOTAL OVERHEAD COST
By-product credits
CAPITAL CHARGES
G&A, taxes & insurance @ 4% Total turnkey cost
Capital recovery factor @10.6% Total turnkey cost_
Interest on working capital @ 10% working capital_
TOTAL CAPITAL CHARGES
TOTAL ANNUAL COSTS
See table C-24
NA
NA
See Table C-22
See Table C-23
N.A.
409 .530
45.
*From PEDCo estimates for conventional systems.
547
-------
TABLE A-ll. ESTIMATED CAPITAL, OPERATING AND ANNUALIZED COSTS FOR AFBC
INDUSTRIAL BOILERS - 58.6 MW (200 x 106 Btu/h) EASTERN LOW
SULFUR COAL
Based on quote from
Date of estimate
Co
mpany
Mm-
Capacity s ft . £ MWfa QO A
Coal Type Eastern loco su )£xr
CAPITAL EQUIPMENT COST
Boiler (with fans & ducts)
Primary particulate control device
Final particulate control device
Stack
Instrumentation
Pulverizers
Coal
Limestone
Feeders
Coal
Limestone
Crushers
Coal
Limestone
Deaerator*
Boiler feed pumps*
Condensate systems*
Water treatment system*
Chemical feed*
Compressed air system (FD fan)
Coal handling system *
Limestone handling & storage system
Spent solids withdrawal & cooling system
Spent solids and ashAstorage system
hancUz-ng and
TOTAL EQUIPMENT COST
3.ML5QO
incl. w/ boiler
not included
incl. w/ boiler
NA
NA
incl. w/ boiler
incl. w/ boiler
incl. w/ coal handling
screening is included in
limestone handling &
storage. See Table C-20
OOP
<£.;
incl. w/ boiler
See Table C-20
incl. w/ boiler
See Table C-21
*From PEDCo estimates for conventional systems.
548
-------
TABLE A-ll. (CONT'd)
EQUIPMENT INSTALLATION COSTS, DIRECT
Boiler (@ 40% x capital)
Stack
Instrumentation incl. w/ boiler
Pulverizers NA
Feeders incl. w/ boiler
Crushers isid. Lo/Coeii
Jing
Deaerator*
Boiler feed pumps*
Condensate system*
Water treatment system*
Chemical feed*
Coal handling system* ~~3L~7S, OOP
Spent solids withdrawal and cooling
Limestone handling and storage system See Table C-2Q
Spent solids and ash«storage system See Table C-21
Foundation and Supports (@ 90% PEDCo estimate)
Piping*
Insulation incl. w/ boiler
Painting yn . o ^
Electrical )£>C~) GOC^
Buildings :T pi'i'^ii*- *—
TOTAL INSTALLATION COST O
TOTAL DIRECT COST (EQUIPMENT & INSTALLATION)(DC) £,
EQUIPMENT INSTALLATION COST
Engineering @ 10% DC
Construction & field expenses @ 10% DC
Construction fee (§ 10% DC
Start-up and performance tests
TOTAL INDIRECT COSTS (1C)
Contingencies @ 20% DC & 1C
TOTAL TURNKEY COST (DC + 1C + CONTINGENCIES)
Land
Working capital @ 25% of total direct
operating costs
GRAND TOTAL CAPITAL COST (TURNKEY + LAND +
WORKING CAPITAL) < O , A ^
*From PEDCo estimates for conventional systems.
549
-------
TABLE A-ll. (CONT'd)
DIRECT OPERATING COST
Direct labor*
Supervision*
Maintenance labor*
Replacement parts*
Electricity See Table C-24
Steam NA
Cooling water NA
Process water*
Fuel @$09 /ton |.
Limestone 'See Ta'ble C-22
Waste disposal See Table C-23
Chemicals*
TOTAL DIRECT COST £
OVERHEAD
Payroll (30% of direct labor)
Plant (26% of labor parts and maintenance)
TOTAL OVERHEAD COST 3 gfo , 44Q
By-product credits N* • A •
CAPITAL CHARGES
G&A, taxes & insurance @ 4% Total turnkey cost
Capital recovery factor @10.6% Total turnkey cost
Interest on working capital @ 10% working capital
TOTAL CAPITAL CHARGES
TOTAL ANNUAL COSTS
*Prom PEDCo estimates for conventional systems.
550
-------
TABLE A-12. ESTIMATED CAPITAL, OPERATING AND ANNUALIZED COSTS FOR AFBC
INDUSTRIAL BOILERS - 58.6 MW (200 x 10 Btu/h) SUBBITUMINOUS
COAL
Based on quote from
Date of estimate
A
Capacity 6B.feMU/6o04flOfcBJc.A)
HlD-
Coal Type Si-L^fc)i l
minous.
CAPITAL EQUIPMENT COST
Boiler (with fans & ducts)
Primary particulate control device
Final particulate control device
Stack
Instrumentation
Pulverizers
Coal
Limestone
Feeders
Coal
Limestone
Crushers
Coal
Limestone
Deaerator*
Boiler feed pumps*
Condensate systems*
Water treatment system*
Chemical feed*
Compressed air system (FD fan)
Coal handling system*
Limestone handling & storage system
Spent solids withdrawal & cooling system
Spent solids and ashAstorage system
HarujliTtg ancj[
TOTAL EQUIPMENT COST
HI
incl. w/ boiler
not included
GOO
incl. w/ boiler
NA
NA
incl. w/ boiler
incl. w/ boiler
incl. w/ coal handling
screening is included in
limestone handling &
storage. See Table C-20
incl. w/ boiler
OOP
See Table C-20
incl. w/ boiler
See Table C-21
*From PEDCo estimates for conventional systems.
551
-------
TABLE A-12. (CONT'd)
EQUIPMENT INSTALLATION COSTS, DIRECT
Boiler (@ 407o x capital)
Ol-"Llv .^.j^- . | jv ^^^'
Instrumentation incl. wf boiler
Pulverizers NA
Feeders incl. w/ boiler
Crushers _
Deaerator* _
Boiler feed pumps* _
Condensate system* _
Water treatment system* 3^
Chemical feed*
Coal handling system*
Spent solids withdrawal and cooling tocj.
Limestone handling agd^storage system See Table C-20
Spent solids and ashvstorage' system See Table C-21
Foundation and Supports (@ 90% PEDCo estimate)
Piping*
*From PEDCo estimates for conventional systems.
552
Insulation incl. w/ boiler
Painting / / ~7OO
Electrical '
Buildings ,
TOTAL INSTALLATION COST 3
TOTAL DIRECT COST (EQUIPMENT & INSTALLATION) (DC) £> ~?9S 3OO
EQUIPMENT INSTALLATION COST
Engineering @ 10% DC £19. Sc3O
Construction & field expenses @ 10% DC
Construction fee @ 10% DC ^ , , ^
Start-up and performance tests
TOTAL INDIRECT COSTS (1C)
Contingencies @ 20% DC & 1C
TOTAL TURNKEY COST (DC + 1C + CONTINGENCIES) j £>
Land cP t QQ ^
Working capital @ 25% of total direct
operating costs
GRAND TOTAL CAPITAL COST (TURNKEY + LAND +
WORKING CAPITAL) / j .
-------
TABLE A-12. (CONT'd)
DIRECT OPERATING COST
Direct labor*
Supervision*
Maintenance labor*
Replacement parts*
Electricity
Steam
Cooling water
Process water*
Fuel @4>t>-7S/ton
Limestone
Waste disposal
Chemicals*
TOTAL DIRECT COST
OVERHEAD
Payroll (30% of direct labor)
Plant (26% of labor parts and maintenance)
TOTAL OVERHEAD COST
By-product credits
CAPITAL CHARGES
G&A, taxes & insurance @ 4% Total turnkey cost
Capital recovery factor @10.6% Total turnkey cost
Interest on working capital @ 10% working capital
TOTAL CAPITAL CHARGES
TOTAL ANNUAL COSTS
431
,COO
See Table C-24
NA
NA
See Table C-22
See Table C-23
415; 040
A/./A.
5JO
).
^. ST3S.790
*From PEDCo estimates for conventional systems.
553
-------
APPENDIX B
COST BASIS USED IN OTHER INDUSTRIAL FBC BOILER COST ESTIMATES
EXXON - APPLICATION OF FLUIDIZED-BED TECHNOLOGY TO INDUSTRIAL BQJLERfi
This report estimated costs for "grass roots" FBC and conventional indus-
trial boilers producing 100,000 Ib/hr steam at 125 psig. The important
assumptions used for FBC costs are shown below. A complete listing is
included in Appendix Al of the origina,! Exxon report.
v
Capital Costs
• Two boilers for each case, each rated at 100,000 Ib/hr
steam and 82 percent efficiency.
• U.S. Gulf Coast Location, First Quarter, 1975
• Process development allowance of 15 percent added to
FBC cost
• Environmental standards for coal firing:
S02 - 516 ng/J (1.2 lb/106 Btu)
NOX - 301 ng/J (0.7 lb/106 Btu)
Particulate - 43 ng/J (0.1 lb/106 Btu)
• Coal: Illinois No. 6; 3.6 percent S, 8.0 percent ash,
HHV = 10,600 Btu/lb
• Coal and limestone handling:
Coal - 10 day storage, ready for charging as delivered
Limestone - 10 day storage, 1/8 in. particle size
• Solid waste handling: stored and hauled to disposal by truck.
554
-------
Items excluded from the capital estimate are:
• Land;
• Unusual site preparation;
• Boiler feedwater treatment facilities (included
as operating costs);
• Slowdown system; and
• Steam distribution system
Operating costs were derived using the following basis:
• Load factor = 0.9
• Manpower = 20,000 $/yr/man
• Electricity = 4c/kwh
• Limestone = 12$/ton.
• Waste solids disposal = 8$/ton
• Annual repair materials =1.5 percent of investment
• Annual cost for supplies,'local taxes, administrative
expense, and general expense =3.0 percent of investment
• Annual capital charges = 20 percent of investment
• Boiler feedwater and blowdown cost = 60c/l,000 Ib of
produced steam
Adjustments made to Exxon estimates to achieve comparability with cost
estimates derived here, are shown in Table B-l. Only the high sulfur coal
case was considered.
These adjustments result in an annualized capital charge of $2.30/106 Btu
output and a total annual cost of $6.14/106 Btu output.
A.G.McKEE - 100.000 LB/HR BOILER COST STUDY
The McKee study considers three boiler systems rated at 100,000 Ib/hr
steam, including:
555
-------
TABLE B-l. ADJUSTMENTS MADE TO EXXON COST BASIS
1. The cost of one boiler and total ESP cost were subtracted.
2. The process development allowance of 20 percent was subtracted.
3. A load factor of 0.6 (as opposed to 0.9) was used to determine annualized
capital cost.
4. The Marshall Stevens equipment index for steam power was used to update
capital costs from First Quarter, 1975 to Third Quarter, 1978.
5. A cost of $0.88/106 Btu output was used for Eastern high sulfur coal
based on 82 percent boiler efficiency and $17/ton of coal.
6. Operating costs were updated by a factor of 7 percent/yr.
556
-------
• AFBC burning noncompliance coal;
4 Conventional spreader stoker burning noncompliance
coal with a mechanical collector and double alkali
FGD; and
• Conventional spreader stoker-burning compliance
coal with dry ESP.
The AFBC costs are based on the current 1978 contract costs associated
with installation of a boiler at Georgetown University in Washington, D.C.
•Therefore, a minimum amount of cost estimating was required for the AFBC
case. The costs for the comparable conventional boilers were based on McKee's
0vn inhouse data. The equipment included in the AFBC system includes:
• One, 100,000 Ib/hr-steam AFBC boiler top supported operating
at 625 psig saturated steam consisting of several shop-assembled.
components including lagging, insulation, and setting.
• Coal receiving, conveying system, crushing, screening, storage,
weighing and spreader feeder system.
• Solid waste material cooling, conveying, storage and disposal
system. (Two waste materials - bottom ash and top ash.)
• Combustion air supply system.
• Flue gas exhaust system.
• Mechanical collector and reinjection system.
• Economizer.
• Bag filter and disposal system.
• Fuel oil startup system with flame safety.
Comparable equipment was included in the estimates of conventional boiler
cost. The following equipment was not included in any of the systems:
In this particular FBC system bottom ash or spent bed material is drained from
the fluid bed continuously to maintain a constant bed level. The bottom ash is
cooled, crushed, stored and hauled separately because of its potential value as
a. chemical. Top ash consists primarily of coal ash and is removed from the
baghouse, conveyed, stored and hauled separately since its potential use is
different.
557
-------
• Feedwater treatment;
• Deaeration;
• Pumping; and
• Water or steam piping.
These items were not included because the AFBC boiler is being installed
in addition to two existing gas- and oil-fired boilers. A booster feed pump
and steam pressure reducing valve were included to accommodate the existing
header pressures.
Operating costs include all raw materials, labor, utilities, consumable
materials, repair, maintenance, and waste materials handling. They are based
on the District of Columbia area. Unit costs and other considerations are
listed below:
• Boiler efficiency - FBC = 82.5 percent with 4.1 percent
carbon loss
- Conventional - 84 percent with 2.2
percent carbon loss
• Coal - noncompliance high sulfur, $40/ton (Eastern, 3.5
percent S, 8 percent ash, HHV = 12,500 Btu/lb)
- compliance low sulfur, $53/ton (Eastern, 0.7
percent S, 8 percent ash, HHV = 12,250 Btu/lb)
• Limestone (Ca/S = 3), $15/ton
• Electricity, $0.035/kwh
• Labor (average), $8.00/man-hour
• Annual fixed charges = 18 percent of total capital cost
(to include depreciation, interest, local taxes, and
insurance).
The costs developed for the FBC burning high sulfur coal and the conven-
tional system burning low sulfur compliance coal were considered in this
analysis. Adjustments made to these costs to provide comparability are shown
in Table B-2.
558
-------
TABLE B-2. ADJUSTMENTS MADE TO A.G. McKEE COST BASIS
1. Total annual costs were developed based on use of the Eastern high sulfur
coal noted for this study; i.e., 11,800 Btu/lb and $17/ton. For FBC
(82.5 percent efficiency) this converts to $0.87/106 Btu output.
2. Eastern high sulfur coal was substituted for the compliance coal burned
by the conventional boiler with ESP. This equates to a coal cost of
$0.86/106 Btu output based on 84 percent boiler efficiency.
3. A load factor of 0.6 was used to determine annualized capital costs.
These adjustments resulted in the following total annual costs:
•»
• FBC boiler burning high sulfur coal - $4.71/106 Btu output
• Conventional boiler burning high sulfur coal with ESP -
$4.34/106 Btu output
The ESP cost was not itemized, so that it was not subtracted from the
conventional boiler cost.
559
-------
APPENDIX C
DETAILED ENERGY AND COST TABULATIONS
The values presented in Tables C-6 through C-30 are calculated based on
information from Appendix A; Tables C-l through C-5, and from the PEDCo study
of conventional boiler costs. Derivation of this background information is
discussed in Chapters 3.0 and 4.0.
The background information is collated by computer to insure internal
consistency under all options considered. The input to the program includes
standard boiler costs, load factor, the coal analysis, drying requirements,
and sulfur control information such as Ca/S and control level. This infor-
mation is manipulated through mass and energy balances to determine input and
output streams. These balances are then input to a costing subroutine to derive
estimates of the effect on capital and operating cost for each boiler size.
The mass, energy and costing subroutines are the source of all final
energy and cost estimates presented in Chapters 4.0 and 5.0. Additional infor-
mation, such as S02 emitted, flue gas rates, and land use impact estimates,
are printed out as needed for other chapters. Complete listings of all output
are not included, for the sake of brevity. Sufficient information is included
in Tables C-l through C-30 to permit independent derivation of information
presented.
560
-------
TABLE C-l. COAL ANALYSES*
Coal Moisture Carbon Hydrogen Sulfur Oxygen Nitrogen Ash Btu/lb
Eastern
high sulfur 8.79 64.80 4.43 3.50 6.56 1.30 10.58 11,800
Eastern
low sulfur 2.83 78.75 4.71 0.90 4.91 1.50 6.90 13,800
Western
low sulfur 20.80 57.60 3.20 0.60 11.20 1.20 5.40 9,600
*
These values are averages developed from coals listed in Babcock & Wilcox
"Useful Tables for Engineers and Steam Users," 12 ed., 1972.
-------
TABLE C-2. PHYSICAL CONSTANTS
SENSIBLE HEAT
Spent Residue
N2
02
CO 2
S02
H20
LATENT HEAT
H20
HEAT OF REACTION
0.217
7
7
9
9
8
1040
Btu/lb - °F
Btu/lb-mole-°F
Btu/lb-mole-°F
Btu/lb-mole-°F
Btu/lb-mole-°F
Btu/lb-mole-°F
Btu/lb - °F
CaC03 »> CaO + C02 1367 Btu/lb
CaO + S02 + 1/2 02 —*> CaSOi+ 3729 Btu/lb
562
-------
TABLE C-3. BASE CONDITIONS AND RANGE FOR SENSITIVITY ANALYSIS
Conventional combustion parametric considerations
Parameter Boiler capacity - MWt
8.8 22 44 58.6
Excess air, % 50 50 50 30
Combustion efficiency, 1 97 97 97 99
Ca/S ratio, m/ra -
SOa control efficiency, % -
Oi Coal sulfur, % 0.6 - 3.5 0.6 - 3.5 0.6 - 3.5 0.6 - 3.5
ON
OJ Coal HHV, Btu/lb 9,600 - 13,800 9,600 - 13,800 9,600 - 13,800 9,600 - 13,800
Coal cost, S/ton 6.75 - 29 6.75 - 29 6.75 - 29 6.75 - 29
Limestone cost, $/ton -
Spent solids disposal, $/ton -
Spent solids heat recovery, 0000
X
Spent solids temperature, °F 1,700 1,700 1,700 1,700
Flue gaa temperature, °F 350 - 400 350 - 400 350 - 400 350 - 400
Ambient Air at FD fan, °F 80 80 80 80
Bottom ash, % 75 75 35 20
Load factor, % 60 60 60 60
FBC parametric considerations
Std Condition
20
97
3.5
90
3.5
11,800
17
8.00
40
0
1,500
350
80
90
60
ITAR
20
97
0.6 - 3.5
56 - 90
0.6 - 3.5
9,600 - 13,800
6.75 - 29
8.00
40
0
1.500
350
80
90
60
Sensitivity
0 - 100
80 - 100
1 - 10
70 - 95
3.5
11,800
8-60
5-30
5-40
0 - 100
1,550 - 300
350
80
90
30 - IOC
-------
TABLE C-4. INPUT PARAMETERS
HV, CAS, SC, ASH, DELT, C, H, S, 0, AN, H20
SHL1, SHL, CCOST, HLP, HPC
LOWWl, LOSS2, LOSS3, XS, XA, XSP, AV
HV
CAS
SC
ASH
DELT
C, H, S, 0, AN
H20
SHLl, SHL
CCOST, HLP, HPC
LOSS1, LOSS2, LOSS3
XSS, XSA, XSP
AV
- HEATING VALUE 11800 Btu/lb ^ 0.0118
- CALCIUM TO SULFUR RATIO m/ra
- SULFUR CONTROL, %
- COAL ASH CONTENT, %/100
- TEMPERATURE DIFFERENTIAL OF FLUE GAS, °F
- CARBON, HYDROGEN, SULFUR, OXYGEN, NITROGEN IN COAL, %/100
- SURFACE MOISTURE REMOVAL REQUIREMENT, %/100
- TEMPERATURE DIFFERENTIAL FOR SOLIDS HEAT LOSS
IN CONVENTIONAL
- COAL COST, LIMESTONE COST, DISPOSAL COST, $/TON
- CARBON LOSS FROM AFB, P.C., STOKERS, %
- EXCESS AIR IN STOKERS, AFBC, P.C., %/100
- PLANT AVAILABILITY, %/100
564
-------
TABLE C-5. POWER REQUIREMENTS FOR GAS MOVEMENT IN UNCONTROLLED AFBC AND CONVENTIONAL
INDUSTRIAL BOILERS
System components
flue gas
AFBC
Forced Air heater
Plenum
Distribution plate
Fluid bed
Subtotal
Induced Freeboar-J
draft
Primary cyclone
Economizer
Air heater
Flues
t-t Subtotal
(-n Total
Value* for conventional boiler* W1
for lover operating excel* air ral
through which air (FD) or
(ID) is conveyed
CC
Air heater
Plenum
Burner*
Subtotal
Furnace
Economizer
Air heater
Flue.
Subtotal
Total
ere taken from reference no. 6 In
Section 5. Other loaaea for AFBC
tio of 20 percent. Flue |a> ii at
.- -k.r.: H(, 0.000157 Q . t? .
fan efficiency
Typical
lo.a - cm
AFBC
8.9 (3.5)
5.1 (2.0)
7.6 (3.0)
38.1 (15)t
121.9 <48)t
181.6 (71.5)
0.3 (0.1)
15.2 (6.0)t
4.8 (1.9)
11.2 (4.4)
2.3 (0.9)
33.8 (13.3)
Section 5.
were aaauwd t
177»C (350°P).
pre..ure Standard boiler Air and flue gal rate. Fan power requirement. I°"1 FD "" ID !'°
un.Jv.g. capacity • power requirements1"
CC Ml
8.9 (3.5) 8.8
5.1 (2.0) 22
7.6 (3.0) 44
5.1 (2.0)*« 58.6
26.7 (10.5)
0.3 (0.1) 8.8
3.3 (1.3) 22
44
4.8 (1.9) 58.6
11.2 (4.4)
2.3 (0.9)
21.8 (8.6)
8.8
22.
44
58.6
AFBC CC AFBC CC
nn6 .„..,,._, •""• "• ArBC
cm. acf. cm. acfm Ol (HP) KW (HP)
(30) 2.86 6,060 3.58 7,575 78.1 104.7 14.3 19 2
<75> 7.19 15,225 8.98 19,030 196 262.9 36 0 48 3
(150) 14.37 30,450 17.96 38,060 392.2 525.9 72 0 96 5
(200) 19.33 40,950 20.94 44,365 527.4 707.2 138 185
(30) 4.72 10,000 5.90 12,500 23.9 32.1 19.4 26 0
(75) 11.86 25,120 14.82 31,400 60.2 80.7 48 6 65 2
(150) 23.71 50,240 29.64 62,800 120 161 97 13l'
(200) 31.89 67,570 34.55 73,200 162 217 113 152
<3?J 115 155 42
" 287 386 91
{!"' 574 772 172
(200) 766 1030 277
CC
HP
56
122
231
373
tqulvelent to conventional bollera.
•e. estimated by PEDCo. Volumetric rata. are lower for AFBC to account
Combuation air ia
Q • acfm
SP • atatic pre.aure
at 2?oc (80»F) for FD fan deaign.
, in. w.g.
fan efficiency • 65 percent
kw - HP " 0.7457
**Pre..ure lo.i of 15.2 cm (6 In.) w«« added for 58.6 l*t *C boiler to account for primary air conveying coal to burner..
"include. 10 percent contingency for ancillary «lr requirement..
-------
TABLE C-6. POWER REQUIRED FOR LIMESTONE AND SPENT SOLIDS HANDLING, kW
SULUJH CONIKOL
IDAl IrPt LtVtL AND
PtHCtNlAGt
MF.OUCHGN
tASltHN MlliM S 90X
SULFUH
t3.I5i S)
I 8SX
M 7M.7X
SIP ShX
tASttKu HI* S/I 84.9X
SULl-UH
10. 9X b)
M 7SX
SUrtrtltU" INDUS 5/1 83. 2X
LU* SULUJH
(0.0* S)
-* 7SX
SDKHtNT
Kt AtTlVl f T
AVtKAGl
LU*
HIGH
AVtHAGt
LUA
HIGH
AVtKAGf
l-Uft
HIGH
Avf.HAGt
LO*.
H 1 I.H
AVtWAGt
LOIN
HIGH
AVtHAGt
LlJn
HIGH
AVt-KAGL
LU*
Ml(,H
AVFHAGfc
tOo
HIGH
CA/S
MATIU
3.3
4.2
2.3
2.9
3.H
2.1
2.«>
3.4
1 .8
1 .0
1 .2
0.8
2.8
l!7
2.0
2.2
3i2
l.h
2.V
3.6
2.0
2.2
3.2
1.6
H.B
CONVtNl 1UNAL
3.
3.
3.
3.
3.
3.
3.
3.
3.
3.
3.
3.
€,_
<>.
^*
2.
2.
2.
2.
2.
2.
2.
2.
2.
H01LEH CAHACITV-Mft
22 44
AFBC
16.
19.
13.
IS.
18.
12.
13.
16.
1 1 .
7.
8.
'•
4.
•l.
3.
„_
4.
3.
q>
•)'.
4.
a>
4.
3.
CUNVEMIUNAL
7.
7.
7.
7.
7.
7.
7.
7.
7.
7.
/.
7.
4.
4.
4.
4.
4.
4.
4.
4.
4.
a>
4.
4.
AF-BC
40.
4H.
32.
37.
44.
30.
33.
40.
27.
19.
20.
17.
H>.
12.
9.
9.
11.
8.
10.
12.
9.
9.
11.
8.
CONVt NTIUNAI.
14.
14.
14.
14.
14.
14.
14.
14.
14.
14.
14.
14.
8.
8.
8.
8.
8.
8.
9.
9.
9.
9.
9.
9.
Af hC
an.
9fa.
63.
/4.
hH.
V*.
66.
M.
54.
37.
41 .
34.
20.
24.
17.
18.
21.
It).
20.
23.
18.
1H.
22.
16.
Stl.h
CUNVU'TIUI.AL
19.
1 9.
19.
19.
19.
19.
19.
19.
19.
19.
I".
19.
1 1).
1 0.
1 II.
lu.
1".
10.
12.
12.
12.
12.
12.
12.
Ah hi
107.
12H.
KS.
97.
1 1 f .
/9.
H7.
lOh.
72.
"51- .
S" .
4S.
27.
41 .
24.
24.
29.
21 .
cl .
31 .
24.
24.
29.
22.
-------
TABLE O7. POWER REQUIRED POR COAL HANDLING, kW
HOlLt» CW.CIIY
SUUHJH CIIN1HUL
— "» ^^ulk "«'m" ":"n ""
HtOuCTlUN ^^.^ ^^ ^_^
,, „ r,,,, AvtHAbt 3.3
tAbltK* «II." !> 1|1X tu- U.«>
SuLt-i'" M|i,M 2.5
( 4.Si !>)
A ufr k uUt 2 . V
1 rt-jX AVtK«Ut r.
Ltl* i«8
MlOM -!'1
M 7M./X AVtKAGt 2.b
LOA 3 .
tllbM l'B
J1P SbX ivtKAbt •
in.. '•'
M1I.M «-H
. ' '
, , . . L J K
• •yIR*VjT Atat^*»t»C c • '
^^SI^K'«L<;
HlliM l.°
8.B
|VtMION»L
b .
b.
b.
b.
b.
b.
b.
b.
b.
b.
b.
b.
•3.
S.
S.
S.
•>.
"i.
7.
/.
7.
/.
/.
/.
Af-HC
b .
b.
b.
b.
b.
b.
b.
b.
b.
b.
b.
b.
b.
S.
S.
b.
. iS.
-------
TABLE C-8. POWER REQUIRED FOR BOILER FEEDWATER PUMPING, kW
00
BUlLtH CAPAC1TY-MK
SULFUH CONTROL
CUflL TYPt LtVfcL AND
Pf-' CLNFAGt
HfcUUtriON
fcASIt«'» HIGH S 901
SULFUK
(i.b* S)
I MbX
" 78. 7X
SIP bt>X
tASItK"- LU« S/I 84. 9X
SULFU*
(0.9t b)
M 7bX
SUbbHuMIMJUS S/I 83. 2X
Lit* SULKJW
(O.bX S)
M /bX
SDRBtNl
Wt ACTIVITY
AvtRAGt
LU«
HIGH
AVtkAGt
LOW
HIGH
AVfcHAGE
LUn
HIGH
AVtHM*
LUft
HIGH
AVI WAGt
LUr.
HIGH
AvtHAGt
LUft
HIGH
AvfcKAGl
LOW
HIGH
AvtHAGt
Ltlft
HIGH
CA/S
HAIIO
3.4
1.2
2.1
2.9
sle
2.1
2.S
3.1
1.8
1 .0
1 .2
0.8
2.8
3. /
2.0
2.2
J.2
l.a
2.7
3.0
2.0
2.2
3.2
1.6
H.B
CONVtNllONAL
18.
11*.
18.
18.
18.
18.
16.
18.
18.
18.
18.
18.
18.
18.
18.
18.
18.
18.
18.
18.
18.
18.
18.
22
AFHC CONVENTIONAL
18. 47.
18. 47.
18. 17.
18. 17.
18. 17.
18. 17.
18. 17.
18. «7.
18. 17.
18. 17.
18. 17.
18. 1?.
18. 17.
18. I/.
18. I/.
18. 17.
18. 17.
18. 17.
IB. 17.
18. 17.
18. 17.
18. «7.
18. 17.
18. 17.
Af-BC
17.
17.
17.
17.
17.
17.
17.
17.
17.
17.
1?!
17.
I/.
(I I
U f
17.
17.
I/.
17.
17.
17.
17.
17.
17.
11
CONVENTIONAL
91.
91.
91.
91.
91.
91.
91.
91.
91.
91.
91.
91.
91.
91.
91.
91.
91.
91.
91.
91.
91.
91.
91.
91.
bH.fi
AFHC CUNVHiTIUNAL
91. l<>b.
91. 12S.
91. 12b.
91. 1/b.
91. If'b,
9«. l^b.
91. lb.
91, It'b.
9u, 1 t"i.
9-4 1/S
91. 12b.
91. 12b.
91. 12b.
91. l«>b.
91. l«!b.
91. l.
"""
12S.
12b.
12S.
l^b.
1 fi.
""'•
^s
1 ^b.
12S.
12b.
12b.
12S.
If").
l^b.
\^.
125.
12s!
I2S.
-------
TABLE C-9. POWER REQUIRED TOR FANS, kW
•OILER CAPACITY-MM
0.6
a
at
56.6
SULFUR CONTROL r»/s ~ ~ ••
COAL TYPt pE2cENTAGE REACTIVITY RATIO CONVENTIONAL AFBC CONVENTIONAL AFBC CONVENTIONAL AfBC CONVENTIONAL
SEDUCTION
t ASIfcHN HIGH S 90X
SuLF JH
(5.5X S)
I 85X
''• 7 8 . 7 X
SIP 56*
EASTtHN ID* S/I 8J.9X
SULf-'U**
CO.** S)
n 75X
SUUHITul-INOUS 3/1 8J.2X
L0» SULUJH
CO.bX S)
M 75X
AVtHAGE. i.i
LOl* «•*
HIGH 2.3
AvtHAGE 2.^
LU* ^'^
A Vfck AbE 2.5
LO* i-1'
HIGH 1.8
AVE.HAGE 1.0
LO* >.2
HIGH O'8
AVERAGE 2.8
LU* J'7
HIGH 2.0
AvthAGt 2.2
LUn 3.2
HIGH l.t>
AVERAGE 2.7
LO" *•<>
HIGH 2.0
AVERAGE 2.2
LQ» 3.2
H 1 {.H 1.0
02. 115.
«2. 115.
«2. 115.
42. !!•>.
<42. 115.
«2. 115.
«2. 115.
<42. 1!5.
«2. 115.
42. 115.
42. 115.
«2. 115.
42. 115.
"2. 115.
42. 115.
42. 115.
42. 115.
"2. M5.
42. 115.
42. 115.
"2. 115.
«2. 115.
"2. 115.
42. 115.
91.
91.
91 .
91.
91.
91 .
91.
91.
91.
91.
91.
91.
91.
91.
91.
91.
91.
91.
91.
91.
91.
91 .
91.
91 .
267.
287.
2h'.
2»7.
267.
2«7.
267.
2H7.
2t>7.
287.
287.
2«7.
2*7.
28/.
287.
287.
287.
2H7.
2C7.
2»/.
2b7.
267.
267.
26/.
172. 57«.
172. b7a.
1/2. S7«.
m. 57<4.
172. 57«.
1 72. 57«
172. 57«.
172. b?u.
172. 57«.
1/2. 574.
172. 57U.
1/2. 57u.
172. 57a.
172. 57tt.
172. 57U.
172. 57.4.
172. >e .
7bf-.
7hr.
7fib .
760.
7rt>
'oc .
7bn.
7nt~ .
7b6.
7(-h.
760.
7bb.
7b6.
7b»^.
7bf>.
7^o.
76ft.
7ftr.
7 ht> .
7bn.
7bo.
7ot.
760.
-------
TABLE C-10. SOLIDS HEAT LOSS, kW
BOILER CAPACITY-UK
SULFUR CUNTRIIL
tUAl TrHE LEVEL AND SUHBENT
PERCENTAGE REACTIVITY
REDUCTION
EASIE*'* HIGH S 90* AVERAGE
SULFUK LOW
(i.S* 5) HIGH
I 85* AVERAGE
Hi*
HIGH
M 78. /X AVERAGE
LUW
HIGH
Cn
~J SIP 56* AVERAGE
0 LU«
HIGH
EASTERN LUn 3/1 8i. 9X AVERAGE
SULFUR LOW
(0.9* S) HIGH
M 7b* AVERAGE
LOn
HIGH
SUBB1 luMJNUUS S/l 81.2* AVERAGE
LUW SULFUR LOW
co.h* S) HIGH
M 7SX AVERAGE
LOn
HIGH
CA/S
RATIO
3.3
4.2
2.3
2.9
3.8
2.1
2.b
3.4
1.8
1.0
1.2
0.8
2.«
s!?
2.0
2.2
3^2
1 .6
2.7
3.6
2.0
2.2
3.2
1.6
R.8
CONVENTIONAL
24.
24.
24.
24.
-------
TABLE C-ll. FLUE GAS HEAT LOSSES, kW
U1
BOILEK CAPACITV-Mft
SULFUH CUNTHOL
LUAL TYHE LEVEL AND *?!!?^lin
PEKCENFAGE RfcACUVin
REDUCTION
EAStt«« HIGH S 90X
SULfUrt
(4.SX S)
1 8SX
M 16.11
SIP 5bX
EASTERN LOW S/I 83. 9X
SULUJW
(0.9X S)
M 75X
SUbBITUMlNOUS 3/1 83. 2X
LOW SULFOH
(0.6X S)
M 75X
AVERAGE
LOW
HIGH
AVERAGE
LOW
HIGH
AVERAGE
LOW
HIGH
AVERAGE
LO*
HIGH
AVtHAGE
LOW
HIGH
AVERAGE
LOU
HIGH
AVEHAGE
LOW
HIGH
AVERAGE
LOW
HIGH
a. a
CA/S
r HATIU
i.i
«.i;
2.3
Z."
3.8
2.1
2.i
J.u
1.8
1.0
!.<>
0.8
2.8
J.7
2.0
i.i
3.2
1.6
?.7
3.6
2.0
2.2
3.2
1.6
22
44
5H.6
CONVENTIONAL AMC CUNVENTIUNAL AFBC CONVEMIUNAL AFBC CONVt Nl 1IINAL AF bC
12//.
1277.
1277.
1277.
1277.
U/7.
12/7.
127/.
1277.
12/7.
12/7.
1277.
10»5.
106S.
1065.
1065.
I06b.
106S.
1270.
1270.
1270.
12/0.
1270.
12/0.
•»S5.
962.
948.
953.
959.
9.
6321.
bJSO.
b}94.
6il2.
63i<>.
bi75.
bj"*1).
bi>t>U.
*>2/U.
h?S5.
SHB6.
SHYb.
S878.
S6«0.
S«91.
bH/«.
/IbO.
71^9.
/ISi.
71S5.
/lb").
not.
-------
TABLE C-12. COMBUSTION LOSSES, kW
Ln
~j
to
BOlLtR CAPACITY-**
SULFUR CONIKOL
COAL TYPt LEVEL AND SORBEN1
PERCEN1AGE REACTIVITY
REDUCTION
EASFtK"" HIGH S 90X
SULFUR
.
b«b.
5Hh.
S86.
SH6.
S«e>.
586.
5Bb.
586.
506.
586.
5Bb.
586.
58b.
56h.
5B6.
58h.
S86.
586.
5Hb.
US/.
1 75/.
1757.
1757.
US/.
!/•>/.
US7.
1 757.
US/.
1757.
. 1757.
1757.
1757.
17S/.
I7W.
1757.
1757.
1757.
1757.
1/S/.
1 7b7.
1757.
US/.
1757.
-------
TABLE O13. RADIATIVE AND OTHER ENERGY LOSSES, kW
u>
HU1UK CA^ACIlY-Mh
LiML IVPt
tAilt** HtbM
SUl> OK
( 4.SX i)
tASItK" LI.IA
HULf UW
(0.9* SJ
Suttnl IUMIMIUS
UU* SULUJK
CO.oX S>)
SOLHiK CONTHOL
LtVfL AND SUMHtM CA/S
HtWCt'MlAGt KtACTlVllY KATIO
*f one r HIM
S VOX AvtKAUt i.*
IU« «•*
M 1 lj H *? « 5
| HSX »vth«(,fc <^.<»
I ijft 4.H
Hi l<» <*• '
v, /h.7X AVLKA(,t t'.')
* ' • ' * 4/1
Li If. •*•"
HlOH 1 "W
aiP st,* A«tkAM i.u
I (It- * • ^
Ml Ml °'H
S/l «4.9X AvtHACiL >>'*
10 1'. •*•'
HJI.H c'.O
M 7SX AvI-WAlit *•*
L u ^. 4 . *?
HIGH !.«»
S/I HJ.r>X AVKKA(,e <*.'
LUrt *-h
^ I f M £* . "
n i w^ *• •
M 7SX Avfc^AUt ^ * ^
L 1 ) ft 3 . ^
Hlbh !.«>
6.8 H
CUNVkNflONAl A^aC CUNVI-NTIUNAL
«!bS. ^bS. g?9.
.
^bS. ^bS. u/9.
t<>'.>. S. 6',. «/9.
«?bS. ibS. <479.
«^bS. i»»)S. «79.
.
9i.4. 'Ju-,.
9i'.S. «..,.
9i. S. '• • S.
9l'.S. '<•• s.
''04. •( , S.
'K)>. '!•}•,.
'" i. '<"•,.
9f'4. ".!S.
"04. '...j.
904. i/,M.
9«. 4. <<.I3.
9(M.
-------
TABLE C-14. AUXILIARY POWER REQUIREMENTS, kW
Ui
^j
4S
SOILED CAPACITY*!**
SULFUR CONTROL
COAL TYPE LtVEL AND SORHENT
PERCENTAGE REACTIVITY
REDUCTION
EASTERN HIGH S 90S AVERAGE.
SULFUR LOU
( 1.5X S) HIGH
I B5X AvEKAGe
LUft
HIGH
» 7H.7X AVERAGE
(.0*
HIGH
S1H 5bX AVtRAGt
LOrt
HIGH
t'ASTtR* LOW S/I 83. 9X AVERAGE
jjuUFUH LU«
(0.9X S) "1GH
- 75X AVERAGE
LU*
HIGH
SuHbl'uwiNOuS S/l B3.2X AvtMAGE
L0« SOLTUR LUrt
(O.bt bj HIGH
« 7SX AVERAGE
L(i«
PlJGH
CA/S
RATIO
3.3
a. ?
^. J
?.9
s.e
^.i
^."i
i.«
1.8
1.0
1.2
0.8
^.H
J.7
^.0
^.a
i.a
l.b
f.7
i.b
^.0
2.2
3.2
l.b
8.8
CONVENTIONAL
70.
70.
70.
70.
70.
7J.
70.
70.
70.
'0.
70.
70.
b«.
h8.
08.
08.
08.
bf».
b9.
o<».
o1*.
o"? .
&<*.
OQ.
AF8C
IS^.
1S9.
1*5^.
Iba.
1S7.
1S1.
tb2.
1SS.
ISO.
1«7.
ia7.
lib.
1").
111.
112.
142.
115.
1«2.
111.
US.
114.
111.
H«.
115.
22
CONVENTIONAL
1S7.
1S7.
157.
157.
157.
157.
157.
157.
157.
157.
157.
157.
152.
152.
152.
152.
152.
152.
15/.
15/.
157,
157.
157.
157.
AFHC
4Hb.
J^l.
376.
3«2.
5>.
Jfib.
i'J.
165.
366.
363.
351.
35b.
353.
353.
355.
352.
35».
3fcU.
J57.
157.
35<».
356.
14
CUNVtNTlONAL
302.
302.
3d2.
302.
3 :. 2 .
3C'2.
302.
302.
302.
302.
302.
302.
291.
291.
293.
29}.
293.
291.
lur-.
3'V.
3«'2.
302.
102.
302.
AFHC
7/1.
7fib.
75".
763.
7/fc.
75K
756.
771.
7au.
728.
731.
721.
707.
711.
705.
705.
709.
703.
715.
718.
711.
71 1.
71 /.
/It.
58.6
CONVFNT1UNAL
399.
399.
399.
39 .
uou .
'*!/.
9S3.
•V5/.
95'.' .
950 .
955.
9af.
-------
TABLE C-15. TOTAL INHERENT ENERGY LOSSES, kW
BOILER CMACITY-MW
COAL TYPE
EASTERN HIGH
SULFU«
(3.5X S)
EASTERN LOn
SULK UK
(0.9X S)
_^—^— ^— — — —
Surirt 11 w« INDUS
UOK SULFUR
(0.6* S)
SULFUR CONTROL
LEVEL AND SOHBENT
PERCENTAGE REACTIVITY
HtOUCUON
S 90S AVERAGE
LOn
HIGH
j hbX AVERAGE
LOn
HIGH
M /M./X AVERAGE
LOn
HIGH
SIP 56X AVEWAGE
LOn
HIGH
S/I 63. 9X AVERAGE
LOn
HIGH
M 75X AVERAGE
LOn
HIGH
S/l 83. 2X AVERAGE
LOn
HIGH
M 75X AVERAGE
L0»
HltM
8.8
CA/S
RATIO CONVENTIONAL
3.J !»«•
,,.2 1»JO-
2.3 I"0'
2.9 Irt30.
i.8 184°-
2., 1830.
p 5 1830.
j I 1830.
lie i»30-
i.o 18JO-
2 1830.
o.'a 18JO-
_
2.B 'b08'
j'" 1608.
t'.O 1008.
p , 1608.
,'> 16l>8.
l.*6 lb°«'
^ , lft!«.
ill >•"•
J.O >81"'
2.2 »81a-
3.2 le>"-
1.6 »°»u'
AFBC
1628.
1704.
1543.
1601.
1678.
1534.
1577.
1653.
1518.
1485.
1502.
1468.
1445.
1461.
1430.
1437.
1455.
1«?6.
1655.
1651.
1625.
1629.
1647.
1618.
22
CONVENTIONAL
1391.
«391,
"391.
4391,
439|.
-»39t.
4391.
4391.
439).
«391.
4MI.
4391.
3835,
3835.
3835.
3835.
3835.
3835.
4351.
4551.
4351.
4351.
4351.
4351.
AF8C
!885.
"076.
367«.
5820.
"1016.
4651.
3759.
3950.
3611.
5529.
3572.
3487.
3428.
3470.
3391.
3400.
3454.
5580.
i904.
5944.
5874.
3889.
3933.
3«62.
44 58.6
CONVENTIONAL AFBC CONVENTIONAL Af-bC
8524. 7562. 9,fijb. 9986.
85i>U. /943. 9?Hb. 10493.
8524. 7139. «26t>. ''421.
8524. /a31. Vet. "Ml,
4524. 7812. S2S6, |i!5l<$,
8524. 709,;. 9<"Ko. "Jinr.
h52<*. 7310. 9286, »6Sf.
8S24. 7691. <>?86, 1C1SP.
8S24. 701U. rV8h. !«2S^.
8524. 6650. 9286, V036.
852«. 6934. 9286. 9149.
8524. 6765. 9286. «<>2S.
7434. 664H. 7845. H/b7,
7434. 6731. 7843. H87M.
7434. 6S74. 7845. 866H.
7454. 6607. 7fju3, "Mi.
7oju. 6/Oo. /hu5, «H3fr.
7434. 6552. 7h«5. 0651*.
6«e3. 7600. V7<)Mi l'^5/.
8465. 7oeO. <•/««. IC'.at.
846i. 753*-. uT>n. ^^Su.
84b5. 7569. <*7<>H. 9=»<
-------
TABLE C-16. TOTAL ENERGY LOSSES (AUXILIARY PLUS INHERENT), kW
•OKI*. .CM»*CITY-N(|
>i" FUR CONTROL
COAL TYPE LEVEL AND
PERCENTAGE
REDUCTION
EASFtHN HIGH S 90S
SULf UH
< 5.5X S)
I «SX
«( 7b.7X
SIP 56X
EASTERN L0« S/I 83. 9X
(0.9X S)
M 7bX
SUHBITUMIwuS S/I 83. 2X
(O.el S)
M 75X
SORBENT
REACUVITY
AVERAGE
HIUH
AVERAGE
L0»
AVtHAOt
LOW
HIGH
AVERAGE
LUM
HIGH
AVERAGE
LOn
HIGH
AVERAGE
LUn
HIGH
AVERAGE
LUn
HIGH
AVERAGE
LON
HIGH
CA/S
RATIO
3.3
4.2
2.3
2.9
3.6
2.1
2.5
3.4
1.8
1.0
1.2
0.8
2.8
3.7
2.0
2.2
3.2
1.6
2.7
3.6
2.0
l!b
e.a
CONVENTIONAL
1699.
1899.
1899.
1899.
1B99.
1B99.
1899.
1899.
189V.
1699.
1899.
1899.
1675!
1675.
1675.
1675.
1675.
1884.
1B64.
186it.
1664.
1864.
1804.
AFBC
1783.
1862.
1695.
1755.
1634.
1685.
1750.
1609.
1668.
1632.
1649.
1614.
1587.
1605.
1572.
1579.
1598.
1567.
1779.
1796.
1767.
1773.
1791.
1762.
22
CONVENTIONAL
4548.
4548.
4548.
4548.
4548.
4548.
4548.
4548.
4546.
«5<»e.
4548.
454R.
3988.
J988.
3988.
3968.
3986.
3988.
450*.
4508.
450f).
4508.
4508.
4508.
AF8C
4271.
4469.
1051.
4202.
uUUO.
4136.
4336.
3984.
389«.
3930.
3850.
3783.
3826.
3744.
3761.
ifl09.
3732.
u^6 5 •
•t io^ •
*42<*ft,
a £-19.
a,
CONVENTIONAL
8826.
6626.
86?6.
6626.
8826.
8826.
H826.
8626.
8826.
H826.
7727.
7727.
7727.
mi.
7727.
7727.
H7»4.
8/64.
."•7b«.
8764.
AFBC
8332.
872h.
7892.
H59D.
8066.
6462.
/75B.
7577.
7665.
7484.
7355.
7442.
7278.
7412.
7408.
7255.
6<>5I .
8282.
B37u.
58.6
CONVENTIONAL AFBC
9h«5. ll"12.
<*b85. 11541.
"b»5. 10628.
''BhS. 1 1 3S6.
9o«5. l(lo5V.
9o«5. 11185.
^bBb. ! 0246.
9fc65t 10006.
9b65t 10123.
9h85. 9689.
8230» 9710.
6230, 9n<>5.
6230. 960?.
6230. <)780.
6230. ^57b.
1 019h. 11100.
10196. 1&9UU.
K'196. 1094b.
If 196. 110»>«<.
-------
TABLE C-17. STATION EFFICIENCY, PERCENT
Ln
eillLEh CAHACITr-Mn
SULUJW CONTHQL
CJAL TYPE Lt*tL AMD
KEOuCTIU'"
£ASTt«« "IC* S 90X
SOkF J*
(3.5X S)
I 85X
M 78. 7X
SIP 56X
fcASUSN LOU S/J 83. 9X
SULFUK
(0.9X S)
M 75X
SUBBITUMINOU3 S/I 83. 2X
L0« SULFUH
(O.bX S)
M 75X
SO*** '•'
h> ACMvI I
AVt>.AGt
A.tfrAtfc
LO*
A.tKAGf
LO*
HIGH
t Oft
nlGH
AVtRAGt
LOh
HIGH
AVERAGE
LOM
HIGH
AVERAGE
LOW
HIGH
AvEKAGt
LU»
HIGH
r «»ua
3.3
2.9
3.8
2.1
2.5
J.4
1.8
1.0
1.2
0.6
3^7
2.0
2,2
3.2
1.6
2.7
3.6
2.0
2.2
3.2
1.6
8.6 fi
44
CONVE.UOMAL »F-tC CONVtNTIONAL AfbC CON»tMJ(J(>A
74. 38
7d. ifl
7B.3B
7B.3B
7o. J«
70.38
76.38
78.38
78.38
7«, 38
78.38
78.38
80.93
R0.93
80.93
60.93
80.93
60,93
76.56
76.56
78.56
/e.Sb
7o.bh
79. /I
16,61
80.71
60.02
79. 1?
80.42
60.32
79.41
81.02
81.1}
61.23
81. (,J
81.93
81.74
62.11
62.03
81.81
62.16
79.75
79.56
79.89
79.8,>
79.61
79. OS
79. JO
79. Ju
79. JO
79. JO
79. JO
79. JO
79.30
79. JO
79. JO
79.JO
79. JO
79. JO
81.85
81.65
81.85
81.65
61.65
61.85
79.48
79.48
79.48
79.48
79.46
79. 4H
00. -16
61.56
so. e/
79,97
61 .67
HI. 16
80.<>6
81.66
Silo?
82.47
82.78
82.58
62. 9b
82.86
62.66
63.01
60.59
60.41
80.74
80.67
80. at,
80.79
79.91
79.9]
79.91
79.-J1
79.91
79.91
79.91
7V. 91
79.91
79.91
79.91
79.91
82.41
82.41
62.41
62.41
62.41
62.41
80. OS
80.05
HO. 05
60.05
60.05
HO. OS
«...
L AfeC. Cl''»vf M ILAAI
81. 1,3
BO. 1 J
82.03
81. J5
hi-. IS
61.64
80.74
82. J«
«2.,5
82.95
8j!(>fe
83.43
63.36
63.14
63.49
81.07
60. 86
«1.22
61. 15
80. 9u
81 .2/
65. -7
83. u?
81. -7
83.<47
83. "7
83.17
6J.4?
8J.47
85. 9S
85.95
65. 9S
85.95
85.95
85.95
62.59
82.59
82.59
82.59
82.5)
b^.5"
ii-tiC
* v . i ;
82.PC
ftl .^l
i» "i », '
^.32
Sl.rtl
80.90
8?.9,
8J.12
83. U?
83.23
63.60
83.52
83.30
63.65
81 .24
61.05
81.38
«1 . 11
f 1 . !<•
01 .«"
-------
TABLE C-18. KW/KG S02 REMOVED
SULFUR CONTROL
COAL TYPE LEVEL AND SORBENT
PERCENTAGE REACTIVITY
REDUCTION
EASTERN HIGH S 90X AVERAGE
SULFUR 10*
(3.SX S) *IGn
1 85X AVERAGE
10*
HIGH
v 78. /i AVERAGE
nIGH
SIP S6X AVERAGE
Ui LO"
W HIGH
EASItRN LO* S/I HJ.9X AVERAGE
SuLKUR LO*
(0.9X S) HIGH
M 7sx AVERAGE
uo*
HIGH
SUH6ITUMINOUS S/I H3.2J AVERAGE
L0«i SULFUR LUA
(O.bX S) HIGH
M 75X AVERAGE
LO*
HIGH
BOILER CAPACITY-**
CA/S
RATIO
3.J
i!»
3. a
1 .8
1.0
0.8
3!?
2.0
1 .6
2.7
3.6
2.0
l!2
1.6
8.8
•3.16
-1.01
•5.56
-t.15
-1.B7
-S.27
-11.68
-10.91
-11 .79
-1-4. "7
-11.50
-lb.20
-It.b8
-12. 3«
-17.32
-19. 04
22
-s.oo
-0.85
-5.39
-l./O
-o.OO
-5.09
-2. hi
-7.00
-1 1 .«2
-10. bS
-12.19
-10.99
-8.b8
-13. 5h
-10.70
-15.31
-13. 110
-1 1 .50
-15. hS
-10.39
-13. SI
-18.1 1
« a
-2.68
-U.53
-5.07
-1.3h
-5.bb
-2.26
-o.fa«
-10.90
'I0.lt
-11.67
-7.65
-12.05
-l«.l 7
-12.0?
- 1 0 . 3 i
- 1 u.uf
-15.06
-12.21
-Ib.tfl
58.6
7!so
a .9 5
a. Si
2.10
2.S7
1.J3
4?!oS
41 .«P
In. /9
19.12
la.")?
17.59
20.46
-------
TABLE C-19. BOILER EFFICIENCY PERCENT
COAL TTPt
SULFUW CONTROL
LE*El AND
PEMCEtTAGE
REDUCTION
80JLER CAPAClir-M*
8.8 22 44 SB.O
SOHBtM CA/S
HEACTJVITr RATIO CO*.VtM10NAL AFHC CU*vEN T lO'VAL »* t»C COiNVENT JGNAU AfbC LUNVtM 1 L'.I7
79.17
7V. a 7
79.17
79. J7
79.1 1
79.1 /
79.17
81. 10
81.70
81.70
81.70
81.70
81.70
/<».iS
79. 35
79. 3b
7V. Jb
79. 3S
79. W
B1.4H
80.61
81?. 14
81.77
80.91
82. S«
B?.3S
B1.1H
82.7i>
83.10
8.B9
82.04
83. So
83.93
83.71
84.13
81.39
64.20
84.56
84.49
04.27
84.61
82.22
82.04
82.37
82.30
•2.09
•2.42
80.60
80.60
60.60
6U.60
80.60
80.60
80.60
60.60
80.60
60.60
80.60
80.60
83.06
83.08
83.08
63.08
63.06
63.08
• 0.74
80.74
•0.74
• 0.7<4
•0.74
•0.74
82.79
81.9?
83.75
B3.09
82.22
63.86
ej.ic
62.«9
8U.03
64. Ml
84.22
64.60
64.67
64.66
65.04
• 4.96
•4.75
•5.09
•2.70
82.52
62.84
82.77
•2.47
•2.«9
8U.1S
«a. ib
84. IS
BU.1S
8U. Ib
84. IS
8U.1S
8«. IS
8«.IS
84. IS
H4. 15
64. IS
86.61
86.61
86.61
86.61
• 6.61
86.61
• 3.27
63.27
•3.27 '
63.27
• 3.27
• 3.27
h<>.9S
o£.0"
Bi.92
Si.^S
B2.3S
*«.02
PJ.SJ
r>f.hb
«u.<>0
8-4.57
rt^.ift
HM. 77
85. Oi
84. BU
8S.5
B2.H6
B2.66
Hi. 01
H2.9«
82.71
fii.Ob
VO
-------
TABLE C-20. TOTAL TURNKEY COST FOR LIMESTONE STORAGE AND HANDLING - DOLLARS
Ui
00
o
HU1LFH CAPACITY-MI*
JULFUW CONTHOL
CUAL TYPE LEVEL AND
PERCENTAGE
REDUCTION
tASTkHN HIGH S 90X
SULUJK
( 4.5* b)
I 85X
M 7S.7X
SIP 56X
tAbltKN LOK S/l 85. 9X
SOLt-UK
(0.9X S)
"1 75X
SUHUl lUMIMOUS S/l 81. 2X
LOW 3ULHJW
10. 01 b)
M 75X
SONBENT
REACTIVITY
AVERAGE
LOW
HIGH
AVERAGE
LU«
HIGH
AVERAfct
LOW
HIGH
AVERAGE
LOW
HIGH
AVEHAGE
LOW
HIGH
AVEHAGE
LOn
HIGH
AVEHAGE
LOn
HIGH
AVERAGE
LOft
HIGH
CA/S
RATIO
3.3
4.2
2.5
2.9
3.H
2.1
2.5
3.4
1 .8
1 .0
1 .2
0.8
2.8
3.7
2.0
2.2
3.2
1.6
2./
s!&
2.0
2.2
3.2
1.6
8.8
CONVkM IUNAL
0.
0.
0.
0.
0.
0.
0.
0.
0.
0.
0.
0.
0.
0.
0.
o.
0.
0.
0.
o.
0.
0.
0.
0.
Af-BC
88455.
109899!
63278.
78553.
100509.
580/3.
68427.
90894.
50160.
28434.
33950,
22860.
17476.
22982.
12536.
137/5.
19929.
10050.
16168.
21458.
12019.
14208.
19113.
9655.
«
CONVENTIONAL
0.
0.
0.
0.
0.
0.
0.
0.
0.
0.
0.
0.
0.
0.
0.
0.
0.
0.
0.
0.
0.
0.
0.
0.
AfbC
192208
334076
144145
1/4045
301555
133469
154465
1 9652 /
116/9J
68426
81049
55449
42705
55735
30839
53830
48538
24805
495/9
52150
29587
32461
46601
24795
44
CONVENTIONAL
0.
0.
0.
0.
0.
"•
0.
0.
0.
0.
0.
0.
0.
o.
0.
0.
0.
0.
0.
0.
0.
0.
0.
0.
AFbC CUMVt
525405.
666152.
364796.
459962.
60270V.
4430/6.
3Vb519.
539266!
2HS49-4.
12/99<<.
149449.
105242.
82140.
105744.
60004.
65646.
92792.
4H5JH.
/6457.
99J20.
57637.
630*2.
89268!
46601 .
*,.*
i-il IUNAL
0.
0.
I'.
0.
0.
0 .
1).
0.
0.
u.
u.
0.
0.
0.
0.
0.
u.
0.
0.
(1.
0.
0.
0.
0.
^^ MC
h«*/«7u.
MMH204.
..M.VW.
»IWBJ.
»>04til 5.
'4<(4t 02.
52*642.
719022.
4h(l65"».
1*2/96.
I 87 MOO.
] 55275.
106591 .
1 45h"H.
/H51 I .
HS/M.
1 19914.
h 57hh.
9^32(1.
1 2/949.
754B4.
H2440.
1 I552h.
to\?t>\ .
-------
TABLE C-21. TOTAL TURNKEY COST FOR SPENT SOLIDS STORAGE AND HANDLING - DOLLARS
oo
•OlUft CM>«CHV*N«
SULFUR COKTROt
rnti T.PF LEVEL AND SORBENt CA/S
COAL T,PE ^CEN?AGE REACTIVITY HA, 10
REDUCTION
fASTEHN HIGH S 90X
SULFUR
( 5.5X S)
I 85X
"1 78. 7X
SIP 56X
CAS1EHN LU» S/I 83.91
SuLFUN
(0.9* S)
M 75X
SUB8ITUMINOUS S/I 83. 21
(.On SULFUR
10.61 S)
M 75X
AVERAGE 3.3
LU* «.2
HIGH 2.3
AVERAGE 2.9
LOft i-8
HIGH 2.1
AVERAGE 2.5
I.QW 3.4
HIGH 1.8
AVERAGE I'D
1 flM 1.2
\f W * *
HIGH 0.8
AVERAGE 2.8
1,0» i.'
H 1 GH 2.0
AVERAGE 2.2
LOi 3*2
HIGH 1.6
AVERAGE 2.7
LO i-6
HIGH 2.0
AVERAGE 2.2
LO* 1.2
HIGH 1.6
8.8 22
CONVENTIONAL AKBC CONVENTIONAL
18544. 86224. 45213,
18544. 98425. 45213.
18544. 72225. 45213.
18544. 79877. 45213.
1S5«4. 92270. 45213.
105(14. 6H5U5. 45213.
18544. 73220. 45213.
1»52bu.
"5t)0i6.'.
b?tl«7l .
Mll-Hu.
bf'y/u'*.
56M69U.
b/5/0/.
4M5ubl .
359294.
383075.
135513.
14759U.
162?13.
1 53035.
1 3Sf45.
I525I6.
125039.
15(/5"9.
16u-4bi.
139?
-------
TABLE C-22. ANNUAL COST OF LIMESTONE PURCHASE - DOLLARS
VI
oo
to
BOILER CAPACITY-UN
SULFUR CONTROL
COAL TYPE LEVEL AND
PERCENTAGE
REDUCTION
EASTERN HIGH S 90X
SULFUH
(4. Si S)
1 85X
* 78. 1\
SIP bbX
EASttKN LOW S/I 83. 9X
SULFOH
(O.'iX S)
M 75X
SJHBI ruMiMous s/i 83. 2x
IU« SULFUR
(0.6X S)
* 75X
SOHBENT
SEACTIVI t»
AVtRAGE
LU*
HIGH
AVCHAGE
tUft
HIGH
AVfcRAGt
LU*
HIGH
AVERAGE
I UK
HIGH
AVERAGE
IUI»
HIGH
AVERAGE
UO*
HIGH
AvtRAGt
(.Of
HIGH
AVERAGE
L0»
HIGH
CA/S
RATIO
3.4
u.a
?.3
.= .9
i.B
a.i
2.b
i.u
i .a
1.0
1.2
o.a
2.8
3.?
2.0
2.2
3.2
) .b
2.7
3.6
2.0
2.2
3.2
1.6
8.8
CONVENTIONAL
o t
0.
0.
0 .
0.
0.
0.
0.
0.
0.
0.
0.
0.
0.
0.
0.
0.
0.
0.
0.
0.
0.
0.
0.
AFBC
21681.
27b9U,
I Mil.
190SJ.
24966.
13797.
1042S.
22138.
1 1826.
6S70.
rasa.
b2S6.
3999.
528S.
2857.
3142.
4S70.
2285.
3b<»6.
4927.
2737.
3011.
4380.
2190.
22
CONVENTIONAL
0.
0.
0.
0.
0.
0.
0.
0.
0.
0.
0.
0.
0.
0.
0.
0.
0.
0.
0.
0.
0.
0.
0.
0.
AFBC
b«202.
68985.
37777.
47632.
t.2415.
34492.
•41062.
5584«0.
'il^HO.
109500 .
1<4(?V?0.
?e«4o.
j seoo.
525bO.
350«0.
P>i6bl .
35230.
l^OUS.
PG^HP.
3 '' -J ' 0 .
r->235.
2uo \7 .
V-<50.
lb 2 5 0 .
20075.
r?92(vO.
1 u b 0 0 .
-------
TABLE C-23. ANNUAL COST OF SPENT SOLIDS DISPOSAL - DOLLARS
00
CUAL tret
tASItKrt HIGH
suouw
(J.b* a)
tASttWi\. LUM
Suit an
(«.«** a)
Surtbl TUMINOUS
Ld* SULI-UK
(0.6X ill
BUILth tAHAClTY-Mll
H.H 3d nil S&.O
Sill FllW 1 ilWTWlll
LLVtL AND SUbtttUT CA/S
PtWCLNTAGt HMtllVlTV WAT10 CUNVM1 lUNAL AFHC CUNVtM 1MNAL AfBL LtlNVEM IONAL AfHL tni.vt.M lui'Al »v hi
rtlOUC 1 ll-IN
S <»lHObUhllH. 19b7h. '4122/S. I?//-'. S'i9/i)|.
« 7H./X AvtKAGt t'.b «J1. «9b7b. 11^'iHu. Milt. bvoil*.
lUir. 1.1 i\tnl. 10S171. bll!7. 2b2911. «Vb7b. S«-Snt-/. •./IIS.. /"llSo.
HIGH 1.8 i^ltJ'47. 7bSb2. Sill'. 1H8901. «9b7b. 17YBIW. l//r<;. Vii/ib.
SIP bbX AVtkAGt 1.0 i\4»l. bS9^1. bll!7. llVBtf). 19S7b. >l*btv. <<1 1 1 S. . S7r'n^n.
L01 l.i <>2. bl!17. liObbb. «9b/6. <>blll^. S77/,>. SUIMSP.
S/I HI, 9* AVtkAGt i.B ll«2b. .'9119. 29SbS. 71117. 27b9«. llbbVb. ('M'c'U. I^SSIJ.
10ft 1.7 Jl»«?b. J29bO. i?9Sbb. H?«00. lu«"<. l/"Mn.
* 7SX AvfcHAC.t f,2 U«2o. 2bbli. 29Sbb. bbi>»i. ?7b97b9u. Ib^hPf-. r-l !'«•••. /"''1W/.
HIGH i.6 ll»^b. 21099. 29bbb. bOi'lH. 27b9«. 120i4<bl. 7blbl. 11011. IbfiVh, i> \»'it . 2oi.«4Q.
LU* i.6 liifU. llSlb. 112bl. 81H1H. ilOuS. Ift/ti/h. dlt-bf1. ^^ib'i".
HIGH 2.0 llSOu. £75bb. i.l.'bl. bSllb. lloal. llbHil. r'ihS,'. l*-2u-1.
M 7bX AVtMAGt 2.2 11<01. 27771. U2bl. b9111. 11011. IlWHbH. 2iftb^. I'-Slb".
LU* 1.2 J1401. 11629. 11261. /90/1. 11011. lbHl«7. ^ihS^. ^l')^».«>.
HIGH i.fc I44UU. ab<460. 11261. ftlbbl. 11011. 1(*/40|. c'ir>b>J. |n-)/4i.
-------
TABLE C-24. ANNUAL COST OF ELECTRICITY - DOLLARS
oo
MHK* C*MCnY*N»
SULfO» CONTROL
Ctj*L TYPE U-*€L AND SOR8ENT
f'EUCfcNTAGE REACTIVITY
HEOUCUUN
tlST£Hr« HIGH 3 90X AVERAGE
( 5.5X S) *IGM
HIGH
"1 7(J. 7X A VEKAUE
LUn
HIGH
SIP 56X AvEKAtt
HIGH
EASIER LO* S/I 83. 9X AVERAGE
SyLFUH LUA
(0.9X S) HIGH
« 75X AvtRAGE
LU«
*IGh
SbdbiTuMlNOUS S/I 83. 2X AVERAGE
L0« SuLUJR LUO
(O.oX 5) HIGH
«• 75x AVERAGE
( DM
HIGH
8.8
CA/3
WATIO CONVENTIONAL AfBC
4.2 9434. 21470.
?. i 94J«. 2059&.
1:1 X": 'L8'':
2.5 9«lu, 20653.
3.4 94J4. 21066.
1.8 9434. 20331.
1.0 ">434. 19891.
l.
-------
TABLE C-25. ANNUAL COAL PURCHASE COST - DOLLARS
GO
•otic* CAPACITY***
SULFUR CONTROL
COAX TYPC LEVEL AND
PERCENTAGE
REDUCTION
£J3TEHN HIGH S 90X
SULFUR
( ».5X 3)
M 78. ?X
SIP 56X
EASTERN LO" S/I 83.9X
SULFUW
(0.91 S)
M 75X
SudBITuMIIMOUS S/I 83. 2X
LO* SULFUR
(0.6* S)
M 75»
SOR8ENT
REACTIVITY
AVERAGE
L0«
HIGH
AvtRAGE
HIGH
AVERAGE
HIGH
AVERAGE
UO*
HIGH
AVERAGE
LUM
HIGH
AVERAGE
AVERAGE
LU*
Hi CM
AVERAGE
HIGH
8.8
RATIO CONVENTIONAL
3.3 113583.
4.2 113583.
2.3 113583.
2.9 113583.
3.S 113583.
2.1 113583.
2.5 113583.
3.4 113583.
1.8 113583.
1.0 113583.
1.2 113583.
0.8 113583.
2.8 165678.
3.7 165678.
^.0 165678.
2.2 165678.
3.2 165678.
!•» 165678.
2.7 55434.
3.6 554 34 .
2.0 iS43l|
*•* 55431.
3.2 55434.
1.6 55434.
AF8C
113583.
113583.
113583.
11358J.
113583.
113581.
113583.
113583.
113583.
113583.
113583.
113583.
165678.
165678.
165678.
165678.
165678.
165678.
55434.
55434.
55434.
55431.
55434.
55434.
22
CONVENTIONAL
2839S7.
283957.
283957.
263957.
283957.
283957.
283957.
283957.
283957.
283957.
283957.
283957.
41H95.
41 1195.
4I419S.
414195.
414195.
41419^.
138586.
138586.
138586.
138586.
138586.
1 38586.
AF6C
2B3957.
283957.
283957.
283957.
263957.
2H3957.
283957.
283957.
263957.
283957.
263957.
283957.
114195.
114195.
414195.
414195.
414)95.
414195.
138586.
1385B6.
138586.
138586.
li«58e.
138586.
14
CONVENTIONAL
567915.
56791S.
567915.
567915.
567915.
56/915.
567915.
5679)5.
567915.
567915.
828391.
H2639).
828391.
828391.
828391.
2771 /2.
2/71 72.
27/172.
277172.
2/7172.
AFBC
567915.
567915.
56/915.
567915.
50/9J5.
567915.
56/915.
5679)5.
567915.
56/915.
567915.
567915.
828391.
B28391.
S28S91.
828391.
b2b!91.
828391.
2VM72.
27/1/2.
27/172.
27/172.
58.6
CONVENTIONAL
757220.
757220.
757220.
757220.
/57220.
757220.
757220.
75/220.
757220.
757220.
757220.
1104520.
1 104520.
1 104520.
1 104520.
1 10<45«!U.
1 104520.
Sn^Soi.
569563.
369563.
369563.
3o9565.
AFBC
'57/^0.
/S/220.
/5722C .
757220.
75/220.
7S7220.
757220.
757220.
757220.
1 104520.
1 104520.
1104520.
1 1 U4520.
1 104S2C.
1 104520.
36S563.
Jn15e5.
-------
TABLE C-26. TOTAL ANNUAL COST, AFBC WITH S02 CONTROL AND UNCONTROLLED
CONVENTIONAL BOILERS - DOLLARS
SULt-UW UIMKOL
I.IIAL l»Pl LtVtL AMU SUKhfNT IA/S
r>tHL> '< 1 At,t WKALIIVIlr HA1KJ
WfcUUCT ION
t-ASUH.« Mll,M S 9ui AktkAUt 4.4
SuLt-iJ* Lilf U. . 4
L MSA A V t (« A(,t «> . 9
in'. 4.8
MlbM
OS LH». 1.^
Mll.H II. 0
tASItW.^ LI I*. S/I HS.9X AvH.0
M 7bX Avfr^AbL (*./*
Lu^. 4>(;
Mll.K 1.6
Simttl lu^I'MiL'S S/l tti.i'i AvlHAl.e ^.7
Lllft SULfllK LOW 4.b
(O.r>* SI HlbM «>.0
M /sx A»tKA(,t ^.^
LU« 4.^
f'K.M 1 .h
HOILE.W CAHALI tY-M«
8.8 2.? 44 SC.n
CDNvtNl 1IINAL Af-MC CONVENTIONAL Ahht CONVtNTlUNAL AH'C CtHi vf '. I 1 1 1 .«L
9«!/U/l. 99Sbbl. 18?hOy9. flW/Ul. iO<4«|/7. 4HSn/<4->. «UV,71^.
945'4/. lH<'bOil9, 1. uu.lS/1/1.
9^7U71. 9b<4i9l4. lH^bO'49. ^18^064. 40««177. 4h9/l^.
9«"7o71. 100998/4. 40UU1/7. 449^4'IM. ^JtliS/Jc'.
Wlvv. 90S8^7. I81b2b9. *0«,/iOh. 4090S^. 4«S/c^: «1-l,,«aS.
*^dllu^, ''li.*U7y. IHibf'b*'. i?yH<*/Sit. i090Sbb» 4uh/^4(», 'iiuhuyS.
9dllO«l. 900,?bb. 184b^S9. iOSlblO. 4090-,Sb. 1-Jl.^a. «lu,,,,').
9^1104, 9011H8. Ifl4b£b9, ^Ubbtti?^. 4090SSS. 4M1SOM«'. '4]qbauS.
90<4S4/1. 4o9uSbS. 449ar>7u. -.MnauS.
944«be', Mb<471if. 17b4«79. l90SHr'l4. 40^H^b7. 4'i4bl7. V.i 7 YftfO . 4<'l'''4»-4.
<448br>. 8b7b^b. 17feiu79> l^liOi'U, 40^81S/ 1 nl .
1 ^ .
<4y(,SMa.| .
-( h 1 - ^ / !4 .
'4 l'*St S'l.
yuSriSr1/.
' J -4 1 4 1 13 t) .
'inS Snu'J.
44/7h<"i.
•1 S'' 4S-4I1. .
'4 .4 ^ - - l.i f. .
44V-,.V.
Jl,^..,.,.^
s'
-------
TABLE C-27. TOTAL ANNUAL COST OF AFBC AND UNCONTROLLED CONVENTIONAL
BOILERS, $/106 Btu OUTPUT
bUUtK CAPACltfMft
SULFUR CONTROL
COAL T»P£ LEVEL AND SOR6ENT CA/3
PERCENTAGE REACTIVITY RATIO
REDUCTION
8.8
AfdC CJNv£iiTlL)f«AL *fbC COhVENl Ki^AL ifbl UJN«£f« t II^
A'rC
oo
EASTERN HIGH S 90S
(J.5X S)
I ftSS
« 78.7*
SIP S6t
EAS7ERM 10m S/I »J.«
. SULFUR
N 7SX
8USBJTUH1NOUS S/I 83,2»
LO* SULFUR
(0.6X SI
- ,«
AVERAGE
HIGH
AVERAGE
LOH
HIGH
AVERAGE
LOH
HIGH
AVERAGE
LOU
HIGH
AVERAGE
LOH
MICH
AVERAGE
LOH
HIGH
AVERAGE
LOH
HIGH
AVERAGE
LM
HIGH
3.3
3J8
2.1
2.%
US
1.0
o.'s
3^7
3*2
1.6
2.7
3.6
2.0
2.2
».*
l.»
/.39 S.04
/.i9 7.6?
7.i9 7.91
7.49 7.46
7. 59 7.4d
7.J9 /.7rt
7.J9 7.?6
7.i9 7.00
7.39 7.06
7.39 6.93
7.1? 6.»/
7.1? 6.9i
7.1? 6.61
7,l
-------
TABLE C-28. LAND VOLUME REQUIRED FOR SPENT SOLIDS/ASH DISPOSAL, ACRE-FT/YR
Ul
oo
oo
80XLC* CMUCJTT-WI
SUlr-« CONTROL
8.8
COAL TYPE LEVEL AND SOHBENT CA/S
PERCENTAGE REACTIVITY RATIO CONVENTIONAL
REDUCTION
i ASTERN HIGH S 90X
SULFUR
( S.bX S)
I »5X
H 78. 7X
SIP 56X
kASTEWN LO" S/I 83. 9X
SULKUR
(o.
-------
TABLE C-29. LAND VOLUME REQUIRED FOR SPENT SOLIDS/ASH DISPOSAL, HECTARE -m/yr
00
NILE* CAPACITT»H«
SUiruft CONTROL
COAU TYPE LEWtt AND SORBtNT CA/S
0.0
22
* AVtHAGt J.S
SULFU« LU« «.2
( 5.5t S) "I<>H ^.J
I 05* iyfrRAGt 2.V
LO* 3.8
HlGrl 2.1
* /B.7X AVLKAGS 2,5
L0« 5.»
HIGH 1.8
SIP 56* AVEHAGt 1 .0
{.Llf, 1.2
HIGH 0.6
tiSTEMN LOn S/I 83.9* AVtHAGE 2.0
SULKUtf LU» J.7
(0.9J SJ «)GH 2.0
M 75* AVtHAGt 2.2
ldn 3.2
r(Gh 1.6
SuBblluWlNOUS S/I 85. 2t 4Vt««GE 2.7
LUi SULFUR LUn 3.6
10.6* S) HI&M 2.0
M 75X *vEHA<;fc 2.?
L0» 3.i
MlGc 1.6
O.OK
U.OU
u.0«
O.Ofc
0,01
U.OU
O.oa
O.OU
0.01
O.OU
0.0«
0.0«
0.02
0.02
0.02
0.02
o.oa
0.02
U.OJ
0.03
0.05
0.03
0,05
0.03
0,21
0.25
0. 18
iJ.20
0.23
0.17
0.16
0.21
0,15
0.11
0.12
0.11
0.06
0.07
0.05
0,05
0.06
0.05
0.0ft
0.07
0.06
0.06
0.06
O.d5
0.11
0.11
0.11
0.11
3.11
0.11
0.11
9.11
0.11
0.11
0.11
0.11
0.06
0.06
0.06
0.06
0.06
0.06
O.Of
0.07
O.U'
0.07
0,07
0.0'
0.55
0.62
o.aa
(itif
0.58
a. 2
'J.06 .1.?t>
O.U8
o . o fc
ti.U«
o.ce
0.08
O.Ofl
0.0»
O.iib
'I.OU
«,06
0.08
"S
0.(5
. AfHC
1 .««
1 .fr"7
1 .1C
1 . 5 1
1 .Si
1.11
1.19
! ."2
1 .02
0.75
o.c.o
•J. 70
0.10
<).uu
0.35
ft.i6
0.42
0. i/
0 i /
r:.l^
-------
TABLE C-30. DOLLARS/kg S02 REMOVED
Ui
v£>
o
SJLH,K C.,M«UL
^t-Ct'. '•'i't KtACMVl'Y
-.tout II j-«
tASU** "Ib" !• 4U* avlRAM
SUL*«Jw LO'.
C4.SX b) iIC,n
1 »V. AVtftbt
LU*
t'K.H
7B. /X AvEK/U.t
LO*
HIGH
SI" Sh* A^Wi&t
LuA
HI I,"
tASltKN LU* S/J 84. 9X AVtHAl>l
SULFUR LOft
(0.9X S) Hll,"
M 7SX *VE«A(,E
CO"
HIGH
SUHB1 tUMINOUS S/I B3.2X AVERAGE
LO* SULFUR LO*
(O.bl b) M1C.M
« ;•)» avtwiuL
Ll)r
H j OM
C4/3
- » 1 I 0 8 . f
4.1 2, Oil
« . 2 2 . « .'
2.4 1.11
2.9 l.bj
3,8 2.^7
? . ! u , pv ^
2.S 1.22
i.tt 2, OS
1.8 O.Se
1.0 -0.4S
1.2 -0.17
y.U -O.S-i
2.8 -O.ub
3.7 -0.27
2.0 -0.62
2.2 -0.59
3.2 -O.i1*
1.6 -0.72
2.7 -£.06
J.b -i.66
2..1 -2.20
2.2 -2.17
4 . f •!."•/
'.o -2.2S
bl-RFK CA«
22
S.16
n. 1 4
•1.27
u.7f
S. 72
*.^
^ . 3 '
-3.17
-'•'"
2.bb
3.04
2.hb
2.7S
2.93
2.59
2.61
2. 82
2.19
1.69
1.87
I.S6
i.se
1.78
1.-7
^CITY-MW
Mil
—
«.8«
"3.7?
J.«h
tl.U t
S.29
j.&i
3.97
4. as
5.29
2.2S
2.U1
2.07
2.0?
2.2b
1.91
1.93
2.13
1.81
C.«0
J .bi. t.
ft.i ;
b . •. !
5. !r-
4. '7
^ .S-1
c" . '• ':
3.2,
~" . 1 M
2 . S C
i . 5'
j . 7 4
1 * •* r
1.1"
1. 4/
1.03
1 .On
1 . 2 1
U.'JU
•C. 4!
-I.-. 1 'i
-C.u'-
- v . U ?
-i- . ' i
- .. . S b
-------
APPENDIX D
WESTINGHOUSE ESTIMATES OF AFBC INDUSTRIAL BOILER COST
Independent estimates of industrial AFBC boiler cost prepared by
Westinghouse Research and Development Center are included in this Appendix.
Values presented in terms of $/106 Btu output were estimated by GCA based on
total costs and boiler efficiencies presented by Westinghouse.
591
-------
TABLE D-l. ESTIMATED CAPITAL, OPERATING COSTS AND PERFORMANCE OF AFBC INDUSTRIAL BOILER
(30 x 106 Btu/hr) - 150 psig SATURATED STEAM (S02 CONTROL LEVEL - STRINGENT)
U1
COAL TYPE
CC»L SULFUR CONTENT, KH
COA.L HHV, PTO/LB
» REMOVAL CF iOi RELEAStC
SO? EMISSIONS, LPS/Kf BTU
SCPfcFST TrFt
CA/S fCLAfi RATIO
CAPITAL COSTS
TOTAL TUKNKFY
WORKING CAPITAL
TCT/L CAPITAL COSTS
F/xeP MiMiML. u?STS, ^/lO^BfU
OPERATING COSTS S iC» LCAL
TOTAL C1RECT CFERATIKG COST
OVER HE'D
TOTAL ANNl/ALIZEC CCST
PERFORMANCE
BOILER EFFICIENCY, *
AUXILIARY FCWER, KU
STEAK GENERATEC » ICC*
OPERATING LCAC, LPS/KR
STEAH CCST, S/IOOD LB
(i eOX LOAD)
y//O*8+u outpt-f
COSTS IN Kit 1978 COLLARS
-SOBBEKT TYPE -I CHI6I- REACTIVITY)-
EASTERN HI6H S EASTERN LOk/ S WESTERN SUBBITUMlNCUS
3.5C .90 .6C
118CO. 138CO. <:6CO.
9D.OO -tJl.63 -. . - . 81. CC
•5V ,2C ,2C
I II HI I II III I II III
^•P3 3.11 5.26- 2.12 2.85 1.57 2.12 2.85 1.57
2i7i?1?. 2296855. 2313603. 2193810. 2205117. 2215856. 219293?. 22C1377. 2211613.
151291. 159112." 164126'. 118659T TSOO^ei ISTSSOT T2113K 122171. 123908.
212371C. 2156297. 2179929. 2J«L219«. . 23555CE ^_ 23671111^ 23_1_1C6?. 2326819. 2338552.
A. 02. P.4b 2. S3
£05563. 637767. 66E3CT.~ 59~163T; 6~61iF3T;; 6lJ¥2Tn *t
-------
TABLE D-2. ESTIMATED CAPITAL, OPERATING COSTS AND PERFORMANCE OF AFBC INDUSTRIAL BOILER
(30 x 106 Btu/hr) - 150 psig SATURATED STEAM (S02 CONTROL LEVEL - INTERMEDIATE)
Ui
CLAL TKFE
CC»L SULFUP CCHTENT, WT»
CC«L HHV, E1U/L8
» REMOVAL OF S02 RELEAUD
St2 EflSSiCNS, LBS/MM 9TL
SCRbEM TYPt
CA/S KCLAR RATIO
CAPITAL CCSTS
10T/L TLhNKEY
I/CRKIKE CAPITAL
TOTAL CAPITAL COSTS
p/xep AhWc,'Ai- COSTS, liiG^fttv
OPERATIKC CCSTS S 6C> LCAt
"1CTAL DIRECT CFERA1IKG COST
OVER HEAD
TOTAL ANNUALI2EC CCST
PERFORMANCE
PPIU.R EFFJCIEfcCY, *
AUXILIARY FCkER, Kb
$TCAf< GEKERATEC • ICC*
OPERATU6 LCAC, LCS/t-R
STEAf COST, S/1CCC It
18 tCI LCAC)
COSTS^^r^PfcLlARScTTviT¥f
tASTtPN HICK S
3.FC
iiecc.
b«.CC
.89
I 11 III
2.?G ?.9~4 4.168-
?i651t?. 2Z8655P. 2304558.
149?i,7. 155837. 162673.
241446*. 2442395. 2467231.
2, fee
597226. 623349.' 65C69"1.
_ 12792C. 127920. 127920.
1C7C79C. 11CC69C. 1131344.
64. 1C . 83.72 _ .«j.5» ...
203. 213. 224.
'24554. 24444. 24C99.
8.3C 8.57 8.93
8.07 8.34 2-69
urttrofc or* r«i
EASTERN LCW S WESTERK ?UPB I TUMINCUS
.90 .6C
138CO. S6CC.
8JL.67 84. CC
.2C .^C
I II III I II III
2.42 T.~8"5 4.57 2.42 2.85 1.57
219384C. 220S447. 2215856. 21
-------
TABLE D-3. ESTIMATED CAPITAL, OPERATING COSTS AND PERFORMANCE OF AFBC INDUSTRIAL BOILER
(30 x 106 Btu/hr) - 150 psig SATURATED STEAM (S02 CONTROL LEVEL - MODERATE)
COAL TYPE
CCAL SULFUP CONTENT, hi*
CCAL HHV , BTU/L6
* RfCVAL CF SCi. RELEASED
SO? EMISSIONS, LBS/Mn BTL'
SOPBENT TfFL I
CA/b MCL'R RATIO ?.C9
CAPITAL COSTS
TOTAL TURNKEY 2 i 5 £ 1 S 9
WORKING CAPITAL 14(655
TOTAL CAPITAL COSTS 24C1J54
FiXtp AWKUJnt. F$+u Oittpfi- 7.<56
COSTS IN PIC If76 COLLARS
iCHBENT TYPE -I (HIGH REACTIVITY)- yESTERK
-11 IfECILf REACTIVITY) - BLSS
-III ILOb REACTIVITY) - KENLC
SORPENT PARTICLE SI?E - 5CC. HCRONS
EASTt°N hIC»- S
3.5C
11PLO.
7<: .77
1.2C
11 III
2.51 4.13.
. 2i7fc3fc7. 2ZSE29C.
152560. 159169.
. 2426927. 2454458.
61C24D." 636£"75.
127920. 12792C.
U85766. 1115624.
83.93 82.63 _
206. 219.
24506. 24164.
8.43 8.78
Sao S.S4
9Ct CAL
EN CLARRY
(LARRY
EASTEPN LOh S bESTERN SUE6 I TUMlNOOS
.90 .6C
13PCP. 96CO.
75. CC - 75. CC
.n .31
I II III I II III
1.92 2.33 "3.87""' 1.92 2.33 3.87
21866C4. 2108391. 22C938C. ?1?5P01. 2197423. 2208?64.
' T4794~6T l"4"9175"r" 15057"5. 120447. 121624. 122966.
2134E19.. 2347565. 2359955. 23C624G. 2319046. 233123C.
2,45 2-^i
"59T784.~ £966"99; ~6T32"299".' 4"8^lT8"7. 486498. " 491865.
1M92D«._ 12792C. 127520. 12792C, 127920. 12792D.
1053742. 1C6C502. 1C67R46. 940679. 9474C4. 954468.
A5_^3H E.5..2.7 AS-^.03 B3. 1ft B3. 11 B_2_*A9 .
162. 184. 186. 164. 186. 188.
24917. 24695. 24827. 24267. 24265. 24201.
?.05 6.10 6.18 7.37 7.43 7.50
7.S3 7-W 796 7J7 7-33 7-3o
-------
TABLE D-4. ESTIMATED CAPITAL, OPERATING COSTS AND PERFORMANCE BY AFBC INDUSTRIAL BOILER
(75 * 106 Btu/hr) - 150 psig SATURATED STEAM (S02 CONTROL LEVEL - STRINGENT)
CO»L T>FF LASTEPN hIG»- S CAStERN LCW
CCAL SULFUR CONTENT, bT» 3. ft .90
CCAL HHV, STU/Lfc 118GC. 138CO.
» RtKCVAL OF SOi fifLFAStr SC.CC 84.67_
SC2 EMISSIONS, LPS/MM ?TU .55 .2C
SCREENT TVFL I II ]JI I II
CA/S HOLAR RMIC 2.83 3.41 5.2t- 2.42 2.85 ~
CAPITAL CCSTS
TOTAL TURNKEY ?S7tl5?. 4CI62G?. 4C44345. 3657191. 3873529.
FORKING CAPITAL 296764. 31689?. 334103. 2«9936~ 2*3433.
TOTAL CAPITAL CCSTS 4i74917. 4335094. 4378448. 4J47127, 4J6fe962*
Fixep AHKCHL ccrsT$; j/o*ft»» I'tt /.73
OPERATING CCSTS o 6Ct LCAb
"TCTAL DIRECT CFCRATIhG COST I187C5C. 126756T. 1 236Tii 1 . ~ Il"5974^ . — 1I73T32";
OVER HEAC 18933C. 189330. 169330. 1893_30.. 18933J,
TOTAL ANNUALI7EC CCS1 198687?. 2C7S243. 2149626. 1941217. 1957941.
PERFORMANCE
BOILEB EFFICIENCY, « «3.94 _ 83,45. _... 82..2JL 85»2? ._15t2i
AUXILIARY FCUER, Kh !1(. 546. 574. 458. 464.
STEAM GENERATED • 1CCS
OPERATING LCAC, LfS/l-P 61273. 6C912. 6CCC3. 62258. 62199.
f|E*C»CLCAC) 6»17 t»1« 6.82 5.93 5.99
SflBBCKiT^Tfrt -J7?^IGhLn?lcTIVTT»>- Hf?TFBk ?Ct c*|r
-lil<(LciLfiEACTIVlTYr; J-ENLC CtAUfir
SORGENT PARTICLE SI2E - 5CC. MICRONS
S lIEST5R^ 5U§b I TUMI fvc!(J5
.fcC
cfaCC.
84. uC
.iC
III I II III
4.57 2.42 2.85 4.57
3867879. 3656456. 7872517. 3866636.
2~9718"2. "221114. "224465. 228056.
418506J. 4077S72. 4096962. 4114697.
1.77
TII872I." 88«5l. 897861. 9I22T2".
J8933JJ.._ .18933C.. 189330. 189330.
1975406. 165694C. 1675025. 1691817.
_8JL«96 83.14 AJ_»JJ6. 82.8L_
470. 464. 469. 474.
62011. 60683. 6C627. 60447.
6.06 5.20 5.26 5.33
5.9o 5,06 5. /a f,tt
-------
TABLE D-5. ESTIMATED CAPITAL, OPERATING COSTS AND
(75 x io6 Btu/hr) - 150 psig SATURATED
PERFORMANCE BY AFBC INDUSTRIAL BOILER
STEAM (SOa CONTROL LEVEL - INTERMEDIATE)
Co»L TYFF
CCAL SULFUC CCNTFNT, wTi
CC*L H- V , B7u/tb
» PtfCVAL CF SCi RELEASLC
SC2 FPISSICN5, LcS/ff PTU
SCPbENT TYPE.
CA/S POLAR RM1C
CAPITAL COSTS
TOTAL TLftNKFY
WORKING CAPITAL
TOTAL CAFITH COSTS
Fix£i> AfcNuAu COSTS, ^/lO^Sfv
OPERATING CCSTS S tC» LC«L
TCfAL' DIRECT CFEKMING COST
CVtR HEAD
TOTAL ANNUALIZEC CCST
PERFORMANCE
BOILER EFFICIENCY. *
AUXILIARY PCWER, Kk
STEAK GENERATED i ICCt
OPERATING LCAL, LBS/KR
STEAM CCST , 1/1CCC LB
(9 6C» LCAC)
$7/0^ B/K OU/fX/f
COSTS Ik PIC 1978 COLLARS
SOJJBCta TYPE -I (HGti REACTIVITV)-
-11 (PECUP REACTIVITY)
-III n 6-48
UE5TFRN 9CS CAL
- ELSSEN OtARRY
PENLC CLARRY
ONS
EASTERN LCk S WESTERN SuBBITUMlNCuS
.9C .6C
138CO. 9&CO.
84.67 fi4.C,C
.20 .it
T II III I II
2.12 " 2.85" 1.57 2.12 2.85
. 3857191. 3873529. 7687879. 3856458. 3872517.
289936". 293133. 2971827 221114. 224465.
. 4147127. 28" . 88 44 5"67~ 897 Obi .
, . 169330^ 18?33.C._ _Lft9_31Cj_ JJ923C* 18?3iflt
. 1941217. 1957941. 1975406. 165894C. 1675025.
85.29 85.21 81.96 83. 14 81,06
458. 161. 170. 161. 169.
62258. 62199. 62011. 60683. 60627.
5.93 5.99 6.06 5.2C 5.26
5,77 S-*3 5^o 5,06 5.12
in
1.57
7886638.
228C58.
1111697.
"912232.
18934J3,
1691817.
171.
60117.
5.33
s,/g
-------
TABLE D-6. ESTIMATED CAPITAL, OPERATING COSTS AND PERFORMANCE BY AFBC INDUSTRIAL BOILER
(75 x 1Q6 Btu/hr) - 150 psig SATURATED STEAM (S02 CONTROL LEVEL - MODERATE)
COAL TYPE
CC*L SULFUP CONTFM, KU
COAL HH«, 6TU/Lb
» PEMCVAL CF id RFLFAS.LCI
S02 EMISSIONS , LFS/hP "TU
SOPBfNT TYFt
CA/S PCLAfi RATIO
LASTtPN HICI- S
3.SC
11FLC.
7<=.77
1.2L
I II III
?.C« 2.51 4.13-
EASTERN LCli S UESTFRN SuPB I TUMIKCUS
• *c .tc
I3*cr. ?6rc.
75. CC 7S.LC
•33 .31
1 II III I II III
1.92 2.33 3.87 1.92 2.33 3.87
CAPITAL COSTS
TOTAL TURNKEY
WOfiHlM. CAPITAL
TOTAL CAPITAL COSTS
Ft*SO t+DW*. tCOT^ ^/l«?
CFERATIKC CCSTS o 6C» LCAC
TOTAL CIRECT CFEfiATING COST
OVER «t«C
TOTAL ANNUALI2LC CCST
I9PSC13. 4C14C19. 3847244. 36636C1. 3678645. 384666P. 3662759. 3877569.
299687. 3U2C9. 288152". 2«l224. 2<4724." 219405. 222349. 225703.
423fc4SC. 42847C1. 423C229. 4135397. 4154026. 4173369, 4Q66C73. 4085107. 4103272.
'•§' /.73. 1.77
1139698. 119875C. 1264838. 1I52609T" URIfflTi IT7¥898. fl77tl«". 889395. 902812.
18S33C. 189330. 189330. 189330.. .189330. . 189330. 18933C. 189330. 189330.
1S7441S. 1999861. ?C71«35. 1932452. 1947436. 1963982. 16505C3. 1664922. 1680837.
BOILER EFFICIENCY, *
AUXILIARY FChEfi, f •
.30 83.93
498. 520.
.. 85,34
547. 456.
46f
166.
461
466.
471
STE»M
CPERATUC LCAD, LPS/I-R
STEAM CCST, J/1CCC Le
(S CCt LCAC)
61529. 61265. 6C461. 62293.
5.96 6.21 6.52 5.9C
62237. 62068. 60717. 6G663. 60501.
6.C2 5.17 5.22 5.29
5.95
6.04 6,35 "" "5.74 "" " 5:79 5.86 5.03
S-oy
- VESTERN 9C» CAL
) - etSSEN CLAfiRY
-JJ I r t L 1L r nt.Mi.ij.il'. •.«.-... . _ „
-III (LOW REACTIVITY) - KEKLO CLARKY
SORBENT PARTICLE S17E - SOL. HICRONS
-------
TABLE D-7. ESTIMATED CAPITAL, OPERATING COSTS AND PERFORMANCE OF AFBC INDUSTRIAL BOILER
(150 x 106 Btu) - 450 psig, 600 F STEAM (S02 CONTROL LEVEL - STRINGENT)
COAL TYFF
CCAL SULFUR CCMENT, UTi
CCAL HHtf, PTU/IB
» REMOVAL OF SC2 RELFASE.C
SC2 FH1S51CHS, LPS/ff BTU
SOREENT TYPE
CA/IS KCLAfi RATIO
CAPITAL CCSTS
TOTAL TLRNKEY
'kCRKIKt CAPITAL
TOTAL CAPITAL CCSTi
Fl )C€T> AXiKk-flL CC'Vr.i, ?>/<
OFERATINC CCSTS a frCt LCAC
TC1AL LIRECT CFERATING COST
. CVEK HtAC
TCTAL ANNUALI7EC COST
PEPFORKAKCE
BilLER EFFICIENCY, <
AUXILIARY FCbER, Kk
STCAP GENERATED a 1CCS
CPERATIKC LCAC, LBS/hR
EASTERN HItK S
3.BC
1 IfiCP.
sr.cc
ii in
3.41 5.26.
i. 7551400. 7S9C633.
57<»T81.~
7988817. PC9155P. 8165214.
I.TZ
13. 2160633.
286290.
7603444. 375C3C?.
EASTERN LOh S
.9C
138CC.
64.67
.2C
I II III
"2.42"" 2.«<5~ 4.57
73C9500. 7331652. 735C662.
~493"24lT~ 5CC7391
779574JL. .7J2489!. _
l.tA
8T1 r
WESTFRK ?UEBITUMINOOS
.6C
84. CC
.2C
II
? 2.85
III
4.57
3347089. 3378999. 3412516.
73C9296. 7331C06. 7349668.
'348(03. 355306. 362491.
7657E95. 76863L2._ 7712159.
!. i4212"23i' "1449965.
2J6290j _2B_6290,
2782719. 2813370. 2845556.
CCST , 5/1CCC LE
(3 tC> LCACI
63.94 83.A5. .. £2jJLL .
1C33. 1093. 1148,
lllCee. 11C131. 1CC784,
5.F7 6.21 6.56
927
_8J ^QA 6_2_. ftJ
937. 949.
112872. 11276S. 112425.
110C17. 109914.
5.64
5.7C
5.78
i.ei
4.87
4.94
&01
4-30
COSTS n fit 1978 COLLARS
^ORBtNT TYPE -1 tHEh REACTIVITY)- KESlEfifc.
-II IKECIlf REACTIVITY) - bUSSEk OtARRY
-III (LCfc REACTIVITY) - »-ENLC CLAfifiY
SORBENT PARTICLE SIZE - bCO. HICRCKS
-------
Ln
TABLE D-8. ESTIMATED CAPITAL, OPERATING COSTS AND PERFORMANCE OF AFBC INDUSTRIAL BOILER
(150 x 106 Btu) _ 450 psig> 600 F STEAM (S02 CONTROL LEVEL - INTERMEDIATE)
COAL TYPE
CCAL SULFUP COMEM, kTj
CCAL HHV, FTL/Lfc
X PEMCVAL CF iC2 RFLFAStT
SC2 EHISS1CHS, Lȣ/>> PTL
SCREENT TYPE
CA/S POL*R fiMIC
CAPITAL CCSTS
TOTAL TURNKEY
kCRKIKC CAPITAL
TOTAL CAPITAL COSTS
OPERATING CCSTS S 6C» LCAC
TOTAL CTRECT CFTRATTNG COST
OVER HE'C
TOTAL ANNUALI2EG CCST
PERFORMANCE
_ BOILER .EFFICIENCY, t
AUXILIARY FCkEfi, «k
EE^ERATEL • ICCt
LCAC, LES/HR
STE'f CCST, W1CCC LE
ca ec» LCAC)
I
2.EC
3.5C
ueor.
e5.CC
.89
II
7525265.
522137.
hIC>- S EASTERN LCk S
.SO
138CO.
84.67
.2C
I" I II in
1.68. ~ 2.42 ' f.85 4.57
7566516. 73C95CO. 7231652. 73EC662.
7461191.
\n\
81231J9. 7795717, 782N893., 785H01,
1C17.
11129C.
5.75
286290.
2525712.
83.72
1C65.
11C791.
6.05
T22E254.
286290.
3671531.
e2.54_
1120.
"1541(9-8^"" T^72T5r: 2TJTTr95*.
286290... .28629C.,.. 286290.
3347089. 3278999. 3112516.
WESTERN SUEeiTUHlNCUS
.tc
SbCC.
ei.cc
.^c
I II III
2.12 2.85 1.57
7309296. 7331C06. 7J19668.
31860*2. 355306. 362191.
7657695. 7666312. 7712159.
T391J4-1TT 142122J". 144"9965.
J6629C. 286290_,_ 28629C.
2782715. 2813370. 2845556.
__91, ??____15_»21 «JLt-?6
917. 927. 939.
JJtlA Jl.Ofe _ 62,81_
527. 937. 919.
109229
6. 1C
112872. 112765. 112*25.
5.61
5.7C
5.78
110C17.
4.81
1C9914,
4.87
109588.
4.94
5. Id
I- WESTER* 5C» _
:ih'cLCrRCACfivif-;V^E^^AS^RfiY
SORPENT PARTICLf SIZE - 500. PICROKS
S-64 4.98
5.01 S.cft 4.25- 4.3o 4W
-------
o
o
TABLE D-9. ESTIMATED CAPITAL, OPERATING COSTS AND PERFORMANCE OF AFBC INDUSTRIAL BOILER
(150 x 106 Btu) - 450 psig, 600 F STEAM (S02 CONTROL LEVEL - MODERATE)
TYFF
CCtL SULFUR roNTFM, k T »
C1.1L rilj V , B1U/LS-
* PEMCVAL CF SC* RFLFASLT
S02 EMSSKNS, LFS/ff "111
StRbENT TTCL
CA/S *C\.tK RMIC
CAPITAL CCS1S
1CT«L TURNKEY
C*FIT»L
TOTAL CAPITAL CCSTi
OFERATUC CCSTS S tC* LC«C
fffH DIRECT CFrRJIlNC COST
OVER Ht»C
CCS1
PERFORHANCE
... __ B.Q1LEP EFFICIENCY,
AUXILIARY FCuFR, K h
STE»K GENERATED i lOCt
CPERAT1KG Lt. C, LES/J-P
STEAf CCST, S/1CCC LE
-------
TABLE D-10. ESTIMATED CAPITAL, OPERATING COSTS AND PERFORMANCE OF AFBC INDUSTRIAL BOILER
(200 x 106 Btu) - 750 psig, 750 F STEAM (S02 CONTROL LEVEL - STRINGENT)
COAL TYPE
CCAL SULFUR CCNTFNT, »T»
CCAL HHV, BTU/LE
t PEIfCVAL OF SC2 RFLEAStC
SC2 EMISSIONS, LPS/C^ °1L ,-•
SOPEENT TYPE
CA/S HOLAfi RA1IC
CAPITAL CCSTS
TOTAL TURNKEY
•OfiKING CAPITAL
TOTAL CAPITAL COSTS
r=/xep ANNUAL <^>TS >/*?»&
OPERATING CCSTS 5 tCt LC»L
64STLPN hlC-h S EASTERN LCb S bESTERN SUflB ITUMINOOS
7.5C .90, ,6C
11PLO. 138CO. 96CC.
9C.OC . 8.1^67 f1.CC
,S9 .2C ,2C
I II III I II III T II III
2.63 3.11 5.26- " 2.12 ~ 2.8S" " 1.57 2.12 2.85 1.57
lCC23?if. 1C1C0137. 101171S9. 98C8231. 9833715. 9855388. 98C8M1M. "833112. 9B51632.
6512S4. 707^28." 75J821. 6360^67' SC51TT"."" ~6YS36"97" 1"52S21.~" 161158. 171C38.
1C677E1C. 1C806065. 109C 1 283. . lfl.111280. 10179J 17 ._!C51J)7i7 . 1C260961 . K291870.. J0325671 .
^ n* i.b<>- i.st
" "TCTIC CTRTCT CFfRITING COST 2617C17.' 2831711. 3C1S297. ~?5111S3. 2~57HfiS. 26Z1175. 18TOGB2. 1B1S~83~0. ffffTilSS.
OVER HEAD
TOTAL ANNUALIZEC COST
PERFORMANCE
BOILER EFFICIENCY, t
AUXILIARY PCUERt KU
STE»M 6ENER»TEC • 1CC«
OPERATING LCAC, LES/^R
STEAf COST, »/lCCC Lfc
LCAU
^/"IO&BTXI ocfr'^
saa.iS5H.jn(BK«lHH
-III (LOk REACTIV
SORBENT PARTICLE SIZE - SCO
38C36C.. 380360. 38C360. _ _380360._ J8.C36flj>_. - 38036D._ .. .3I.01A.O.* 38C360. 38J3iO.
1^2(211. 1757161. 1952568. 1120150. 1162109. 1SC6258. 3667727. 3708011. 3750393.
83.91 63.15. _ .*2.2L .-9J.»11 8.L.11 8A»9J 11*1* BJ^Qi B.2J1
1377. 1157. 1531. 1222. 1236. 1252. 1237. 1250. 1265.
139562. 138739. 136669. 1118C5. H1671. H1241. 138218. 138C89. 137680.
6.17 6.52 6.89 5.93 5.99 6.07 5.C5 5.11 5.18
'^"" 5.13 5-42 £73 4*3 4fTB 5.0? 4ao 4.^ 4-3/
rvitri - etSJEN OLARRY
ITY) - rENLC tLARfiV
. PICRONS
-------
t^
o
N>
TABLE D-ll. ESTIMATED CAPITAL, OPERATING COSTS AND PERFORMANCE OF AFBC INDUSTRIAL BOILER
(200 x 106 Btu) - 750 psig, 750 F STEAM (S02 CONTROL LEVEL - INTERMEDIATE)
CI.AL TYPE
CCAL SULFUP CCMFNT, ,T<
CCAL HHtt P II /LB
* REMOVAL OF S02 RELEASED
SC2 EK1SS1CN5, LPi/C* PTU
SCPbENT TYPE
CA/S KCLAR RATIC
CAPITAL CCS1S
TOTAL TURNKEY
hCRKING CAPITAL
TC1/L CAPITAL COSTS
OPERATING CCSTS 5 «C> LC»u
TCTAL DIRECT OPERATING COST
CVER HEA£
TCTAL ANNUALI7EC CCST
PERFORMANCE
BOILER EFFICIENCY, t
AUXILIARY PCWEft, Kk
STEAf GEKERATEC i lOCt
OPERATIKG LCAC, LBS/hR
STEAK CCST, J/1DCC LE
O 6C« LCAC 1
HICI- S
2.5C
3.50
116CD.
tE.CC
.87 " 452521. 461458. 471038.
10MH«L28C^_ lC«79117^_ltSlD75I^ 1C26QSM. 1C29487Q. 10325671.
['iff£ l.K>"~i
T l6~2T4f5T 18loT82~. f8458lO~i 1884153.
_JJD.36J)« 3802i£.«._ 38ii360_j 3E036Q_>
4420150. 4*62109. 45C6258. 3667727. J7C8014. 3750393.
1,10 _. . 83«72_
1356. 1421.
11911.
.as_*z9 fis_ajz.i a.4^56 LI^UL
1222. 1236. 1252.
83.06 82.81
1237. 1250. 1265.
139817. 139191. 137228. 1418C5. 1*1671. 1*121*. 138211. 138089. 1376*0,
6.C4)
6.36
£.72
5.93
5.99
6.07
s.cs
5.11
S.1B
COSTS IK MC 1976 COLLARS
_iORAOa TYPE -1 CH16I- RE ACT I«IT Y J-_lt£SJ£Rk-_aj:r C1L .
-II mCILf REACTII/ITYJ - BLSSEN OLARRY
-III
-------
TABLE D-12. ESTIMATED CAPITAL, OPERATING COSTS AND PERFORMANCE OF AFBC INDUSTRIAL BOILER
(200 x 1Q6 Btu) - 750 psig, 750 F STEAM (S02 CONTROL LEVEL - MODERATE)
o
U)
COAL TYPE
CCAL SULFUR CCMENT, * T *
CCAL HHV, STL/Lb
» REMOVAL CF iC2 ^FLFASED
SC2 EMSSJCMS, LPS/Kf ?TU
SLR&ENT TYPE i
CA/S MOLAR RATIC 2.C9
CAPITAL COSTS
TOTAL TURNKEY 957bf>ie.
UCRKING CAPITAL t2Z662.
TOTAL CAPITAL CCSTS 1H59653C.
MX£D AWUUJll. Ct>'5rSx i)>Ok9tV
OPERATING COSTS S 6C» LcAC
TCTAL CIKF.CT OPERATING COST 2M9C72?".
OVER HEAD 38C36C.
TOTAL ANNUALI7EC COST 13PSP3C.
PERFORMANCE
BOILER EFFICIENCY, t ... £*_.3.C ..
AUXILIARY FChER, Kk 1329.
STEAK GENERATED i ICCt _,.„,,.,
OPERATING LCAC. LPS/^R »*C1*«.
STEAK CCST, J/10CC LS
O 6C» LCAC» 5'96
ffjo^Biuoyfrot 4-v^
itilM'Mt \r^l^tmim- wip f?
t ASTE.PN
3.Et
iiecc.
79.77
1.2C
ii
2.51
10C37312.
662050.
1C699362.
1.71
7616200.
38C360.
1E6C213.
83.93 _.._
1388.
1395**.
6.22
s.ri
CJ^I,
HIGI" S EASTERN LOW S kESTERN SuPE ITUHINOUS
•90 .6C
138C0' «!oro.
"-" 75. CC
•?2 .31
iIJ T » "I I II ill
1.13. i.92 2.33 3.87 1.92 2.33 3.87
10C866C1. 9793307. 9818255. 98*C670. 9793*05. 9618251. 98*0212.
7C61CIV -63i2«07 U^62. -&teis. MMn62. ,,5-5,^. 46(|758f
107917JO. ltL*2.15?7_, 1W77J7. 10*89185. 102*1767. 1C271C6*. !0305000.
l-b4 l.ty^t
7621*3*7- 757515r.— 2557927- -2S9TT>6T;n91Rr.- 1823253. mSOSTY
.38C360.. . 380360, . . J8C36C, 38036JL. 380760. 38Q3&D «n^tn
171*310. 1398170. 1*35700. *1772*0. 3616902. 3682659. 3722512.
_ 62.8J _8_S_.3* iS^il 85, p} flj,^ .,,,, B7i,
1*58. 1215. 1227. 12«. ,23C. ,2,u ^^ ^
137712. 1*1885. 1*1757. H1373. 13*29*. 13817.2. 13700*.
6-56 S.9C 5.95 6.C3 5.C2 5.C7 5.^
S4S 440 f
-------
1. REPORT NO
EPA-600/7-79-178e
TECHNICAL REPORT DATA
(Please read Instructions on the reverse before completing)
|3. RECIPIENT'S ACCESSION NO.
4. TITLE AND SUBTITLE
Technology Assessment Report for Industrial Boiler
Applications: Fluidized-bed Combustion
5. REPORT DATE
November 1979
5. PERFORMING ORGANIZATION CODt
|7. AUTHORIS)
C.W. Young, J.M.Robinson, C.B.Thunem, and
P. F.Fennellv
8. PERFORMING
9. PERFORMING ORGANIZATION NAME AND ADDRESS
GCA/Technology Division
Burlington Road
Bedford, Massachusetts 01730
10. PROGRAM ELEMENT NU
INE825
11. CONTRACT/GRAN I NU
68-02-2693
12. SPONSORING AGENCY NAME AND ADDRESS
EPA, Office of Research and Development
Industrial Environmental Research Laboratory
Research Triangle Park, NC 27711
13 TYPE OF REPORT A^
Task
14. SPONSORING AGENCY tOOE
EPA/600/13
15. SUPPLEMENTARY NOTES IERL-RTP project officer is D. Bruce Henschel, Mail Dr°P 61'
919/541-2825.
16. ABSTRACT
The report gives results of an assessment of the applicability of atmos-
pheric fluidized-bed combustion (AFBC) to industrial boilers. It is one of a serie
of reports to aid in determining the technological basis for a New Source Perfor-
mance Standard for air pollutant emissions from the boilers. It reviews the deve -
opment status and performance of SO2, NOx, and partic\ilate control options for
AFBC; selects the most promising systems for control; and estimates the cost,
energy, and environmental impacts of the most promising systems. It concludes
that the most promising approach for economically achieving the range of SOZ
control levels considered (75 - 90%) involves increased residence time (at»out_;.r,
sec) and decreased sorbent particle size (about 500 micrometers surface mea
the bed. NOx emissions in the range considered (0. 5 to 0.7 lb/10 million Btu)
be achieved in AFBC units without any further control technology. Fabric filw
ESPs appear to be the best options for particle control, although both must yet D
demonstrated on AFBC. Cost estimates indicate that AFBC should be able to
achieve the levels of control considered, at a cost only moderately above those
an uncontrolled conventional boiler, and at a cost competitive with conventional
boilers using flue gas scrubbers.
17.
KEY WORDS AND DOCUMENT ANALYSIS
DESCRIPTORS
Pollution
Industrial Processes
Boilers
Combustion
Sulfur Dioxide
Nitrogen Oxides
Dust
Aerosols
Fluidized Bed Processing
Assessments
. DISTRIBUTION STATEMENT
Release to Public
EPA Form 2220-1 (9-73)
.IDENTIFIERS/OPEN ENDEDTEPMS
Pollution Control
Stationary Sources
Industrial Boilers
Particulate
19. SECURITY CLASS (This Report)
Unclassified
20. SECURITY CLASS (Thispage)
Unclassified
604
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